ML103350442

NUREG-1437 Supplement 38 Vol 3 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Regarding Indian Point Nuclear Generating Unit Nos. 2 and 3, Public Comments Continued, Appendices

ML103350442
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Site:	Indian Point
Issue date:	12/31/2010
From:	Stuyvenberg A Office of Nuclear Reactor Regulation
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Beltz G
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NUREG-1437 S38 V3
Download: ML103350442 (665)

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NUREG-1437, Supplement 38, Vol. 3 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 38 Regarding Indian Point Nuclear Generating Unit Nos. 2 and 3 Final Report Public Comments Continued, Appendices Office of Nuclear Reactor Regulation

AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS NRC Reference Material Non-NRC Reference Material As of November 1999, you may electronically access Documents available from public and special technical NUREG-series publications and other NRC records at libraries include all open literature items, such as NRC=s Public Electronic Reading Room at books, journal articles, and transactions, Federal http://www.nrc.gov/reading-rm.html. Register notices, Federal and State legislation, and Publicly released records include, to name a few, congressional reports. Such documents as theses, NUREG-series publications; Federal Register notices; dissertations, foreign reports and translations, and applicant, licensee, and vendor documents and non-NRC conference proceedings may be purchased correspondence; NRC correspondence and internal from their sponsoring organization.

memoranda; bulletins and information notices; inspection and investigative reports; licensee event reports; and Commission papers and their Copies of industry codes and standards used in a attachments. substantive manner in the NRC regulatory process are maintained atC NRC publications in the NUREG series, NRC The NRC Technical Library regulations, and Title 10, Energy, in the Code of Two White Flint North Federal Regulations may also be purchased from one 11545 Rockville Pike of these two sources. Rockville, MD 20852B2738

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2. The National Technical Information Service American National Standards Institute nd Springfield, VA 22161B0002 11 West 42 Street www.ntis.gov New York, NY 10036B8002 1B800B553B6847 or, locally, 703B605B6000 www.ansi.org 212B642B4900 A single copy of each NRC draft report for comment is available free, to the extent of supply, upon written request as follows: Legally binding regulatory requirements are stated only Address: U.S. Nuclear Regulatory Commission in laws; NRC regulations; licenses, including technical Office of Administration specifications; or orders, not in Mail, Distribution and Messenger Team NUREG-series publications. The views expressed in Washington, DC 20555-0001 contractor-prepared publications in this series are not E-mail: DISTRIBUTION@nrc.gov necessarily those of the NRC.

Facsimile: 301B415B2289 The NUREG series comprises (1) technical and Some publications in the NUREG series that are administrative reports and books prepared by the staff posted at NRC=s Web site address (NUREGBXXXX) or agency contractors http://www.nrc.gov/reading-rm/doc-collections/nuregs (NUREG/CRBXXXX), (2) proceedings of conferences are updated periodically and may differ from the last (NUREG/CPBXXXX), (3) reports resulting from printed version. Although references to material found international agreements (NUREG/IABXXXX), (4) on a Web site bear the date the material was brochures (NUREG/BRBXXXX), and (5) compilations accessed, the material available on the date cited may of legal decisions and orders of the Commission and subsequently be removed from the site. Atomic and Safety Licensing Boards and of Directors=

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NUREG-1437, Supplement 38, Vol. 3 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 38 Regarding Indian Point Nuclear Generating Unit Nos. 2 and 3 Final Report Public Comments Continued, Appendices Manuscript Completed: November 2010 Date Published: December 2010 Office of Nuclear Reactor Regulation

1 ABSTRACT 2 The U.S. Nuclear Regulatory Commission (NRC) considered the environmental impacts of 3 renewing nuclear power plant operating licenses for a 20-year period in NUREG-1437, 4 Volumes 1 and 2, Generic Environmental Impact Statement for License Renewal of Nuclear 5 Plants (hereafter referred to as the GEIS),(1) and codified the results in Title 10, Part 51, 6 Environmental Protection Regulations for Domestic Licensing and Related Regulatory 7 Functions, of the Code of Federal Regulations (10 CFR Part 51). In the GEIS (and its 8 Addendum 1), the NRC staff identified 92 environmental issues and reached generic 9 conclusions related to environmental impacts for 69 of these issues that apply to all plants or to 10 plants with specific design or site characteristics. Additional plant-specific review is required for 11 the remaining 23 issues. These plant-specific reviews are to be included in a supplement to the 12 GEIS.

13 This supplemental environmental impact statement (SEIS) has been prepared in response to an 14 application submitted to the NRC by Entergy Nuclear Operations, Inc. (Entergy), Entergy 15 Nuclear Indian Point 2, LLC, and Entergy Nuclear Indian Point 3, LLC (all applicants will be 16 jointly referred to as Entergy) to renew the operating licenses for Indian Point Nuclear 17 Generating Unit Nos. 2 and 3 (IP2 and IP3) for an additional 20 years under 10 CFR Part 54, 18 Requirements for Renewal of Operating Licenses for Nuclear Power Plants. This SEIS 19 includes the NRC staffs analysis which considers and weighs the environmental impacts of the 20 proposed action, the environmental impacts of alternatives to the proposed action, and 21 mitigation measures available for reducing or avoiding adverse impacts. It also includes the 22 NRC staffs recommendation regarding the proposed action.

23 Regarding the 69 issues for which the GEIS reached generic conclusions, neither Entergy nor 24 the NRC staff has identified information that is both new and significant for any issues that apply 25 to IP2 and/or IP3. In addition, the NRC staff determined that information provided during the 26 scoping process was not new and significant with respect to the conclusions in the GEIS.

27 Therefore, the NRC staff concludes that the impacts of renewing the operating licenses for IP2 28 and IP3 will not be greater than the impacts identified for these issues in the GEIS. For each of 29 these issues, the NRC staffs conclusion in the GEIS is that the impact is of SMALL(2) 30 significance (except for the collective offsite radiological impacts from the fuel cycle and high-31 level waste and spent fuel, which were not assigned a single significance level).

32 Regarding the remaining 23 issues, those that apply to IP2 and IP3 are addressed in this SEIS.

33 The NRC staff determined that several of these issues were not applicable because of the type 34 of facility cooling system or other reasons detailed within this SEIS. For the remaining 35 applicable issues, the NRC staff concludes that the significance of potential environmental 36 impacts related to operating license renewal is SMALL, with three exceptionsentrainment, 37 impingement, and heat shock from the facilitys heated discharge. Overall effects from 38 entrainment and impingement are likely to be MODERATE. Impacts from heat shock potentially (1)

The GEIS was originally issued in 1996. Addendum 1 to the GEIS was issued in 1999. Hereafter, all references to the GEIS include the GEIS and its Addendum 1.

(2)

Environmental effects are not detectable or are so minor that they will neither destabilize nor noticeably alter any important attribute of the resource.

December 2010 iii NUREG-1437, Supplement 38

Abstract 1 range from SMALL to LARGE depending on the conclusions of thermal studies proposed by the 2 New York State Department of Environmental Conservation (NYSDEC). Based on corrected 3 data received since completing the draft SEIS, NRC staff concludes that impacts to the 4 endangered shortnose sturgeon - which ranged from SMALL to LARGE in the draft SEIS - are 5 likely to be SMALL.

6 The NRC staffs recommendation is that the Commission determine that the adverse 7 environmental impacts of license renewals for IP2 and IP3 are not so great that preserving the 8 option of license renewal for energy planning decision makers would be unreasonable. This 9 recommendation is based on (1) the analysis and findings in the GEIS, (2) the environmental 10 report and other information submitted by Entergy, (3) consultation with other Federal, State, 11 Tribal, and local agencies, (4) the NRC staffs own independent review, and (5) the NRC staffs 12 consideration of public comments received during the scoping process and in response to the 13 draft SEIS.

14 Paperwork Reduction Act Statement 15 This NUREG does not contain information collection requirements and, therefore, is not subject 16 to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). These 17 information collections were approved by the Office of Management and Budget (OMB),

18 approval numbers 3150-0004, 3150-0155, 3150-0014, 3150-0011, 3150-0021, 3150-0132, and 19 3150-0151.

20 Public Protection Notification 21 The NRC may not conduct or sponsor, and a person is not required to respond to, a request for 22 information or an information collection requirement unless the requesting document displays a 23 currently valid OMB control number.

NUREG-1437, Supplement 38 iv December 2010

Table of Contents ABSTRACT ...................................................................................................................................iii EXECUTIVE

SUMMARY

............................................................................................................ xv ABBREVIATIONS/ACRONYMS .................................................................................................xxi 1.0 Introduction .................................................................................................................... 1-1 1.1 Report Contents ................................................................................................. 1-2 1.2 Background ........................................................................................................ 1-3 1.2.1 Generic Environmental Impact Statement .............................................. 1-3 1.2.2 License Renewal Evaluation Process..................................................... 1-4 1.3 The Proposed Federal Action ............................................................................. 1-6 1.4 The Purpose and Need for the Proposed Action ................................................ 1-7 1.5 Compliance and Consultations ........................................................................... 1-7 1.6 References ......................................................................................................... 1-8 2.0 Description of Nuclear Power Plant and Site and Plant Interaction with the Environment ...................................................................................................................2-1 2.1 Plant and Site Description and Proposed Plant Operation During the Renewal Term .................................................................................................... 2-1 2.1.1 External Appearance and Setting ........................................................... 2-2 2.1.2 Reactor Systems .................................................................................... 2-5 2.1.3 Cooling and Auxiliary Water Systems..................................................... 2-8 2.1.4 Radioactive Waste Management Systems and Effluent Control Systems ................................................................................................ 2-14 2.1.4.1 Liquid Waste Processing Systems and Effluent Controls .......2-15 2.1.4.2 Gaseous Waste Processing Systems and Effluent Controls ..2-17 2.1.4.3 Solid Waste Processing..........................................................2-20 2.1.5 Nonradioactive Waste Systems ............................................................ 2-21 2.1.5.1 Nonradioactive Waste Streams ..............................................2-22 2.1.5.2 Pollution Prevention and Waste Minimization ........................2-23 2.1.6 Facility Operation and Maintenance ..................................................... 2-23 2.1.7 Power Transmission System ................................................................ 2-23 2.2 Plant Interaction with the Environment ............................................................. 2-24 2.2.1 Land Use .............................................................................................. 2-24 2.2.2 Water Use ............................................................................................. 2-24 2.2.3 Water Quality ........................................................................................ 2-24 2.2.4 Meteorology and Air Quality ................................................................. 2-27 2.2.4.1 Climate ...................................................................................2-27 2.2.4.2 Meteorological System ...........................................................2-28 2.2.4.3 Air Quality ...............................................................................2-29 2.2.5 Aquatic Resources................................................................................ 2-31 2.2.5.1 The Hudson River Estuary .....................................................2-31 December 2010 v NUREG-1437, Supplement 38

Table of Contents 2.2.5.2 Significant Environmental Issues Associated with the Hudson River Estuary .............................................................2-39 2.2.5.3 Regulatory Framework and Monitoring Programs ..................2-48 2.2.5.4 Potentially Affected Fish and Shellfish Resources .................2-52 2.2.5.5 Special Status Species and Habitats......................................2-77 2.2.5.6 Other Potentially Affected Aquatic Resources ........................2-80 2.2.5.7 Nuisance Species ...................................................................2-82 2.2.6 Terrestrial Resources ........................................................................... 2-84 2.2.6.1 Description of Site Terrestrial Environment ............................2-85 2.2.6.2 Threatened and Endangered Terrestrial Species ...................2-86 2.2.7 Radiological Impacts........................................................................... 2-104 2.2.8 Socioeconomic Factors ...................................................................... 2-114 2.2.8.1 Housing ................................................................................2-115 2.2.8.2 Public Services .....................................................................2-116 2.2.8.3 Offsite Land Use ...................................................................2-121 2.2.8.4 Visual Aesthetics and Noise .................................................2-123 2.2.8.5 Demography .........................................................................2-124 2.2.8.6 Economy...............................................................................2-131 2.2.9 Historic and Archeological Resources ................................................ 2-134 2.2.9.1 Cultural Background .............................................................2-134 2.2.9.2 Historic and Archeological Resources at the IP2 & IP3 Site .......................................................................................2-138 2.2.10 Related Federal Project Activities and Consultations ......................... 2-139 2.3 References ..................................................................................................... 2-142 3.0 Environmental Impacts of Refurbishment ...................................................................... 3-1 3.1 Potential Refurbishment Activities ...................................................................... 3-1 3.2 Refurbishment Impacts ...................................................................................... 3-4 3.2.1 Terrestrial EcologyRefurbishment Impacts ......................................... 3-7 3.2.2 Threatened or Endangered SpeciesRefurbishment Impacts .............. 3-8 3.2.3 Air Quality During Refurbishment (Nonattainment and Maintenance Areas) ..................................................................................................... 3-9 3.2.4 Housing ImpactsRefurbishment ........................................................ 3-10 3.2.5 Public Services: Public UtilitiesRefurbishment ................................. 3-10 3.2.6 Public Services: EducationRefurbishment ....................................... 3-11 3.2.7 Offsite Land UseRefurbishment ........................................................ 3-11 3.2.8 Public Services: TransportationRefurbishment ................................ 3-11 3.2.9 Historic and Archeological ResourcesRefurbishment ....................... 3-12 3.2.10 Environmental JusticeRefurbishment................................................ 3-13 3.3 Evaluation of New and Potentially Significant Information on Impacts of Refurbishment .................................................................................................. 3-13 3.4 Summary of Refurbishment Impacts ................................................................ 3-13 3.5 References ....................................................................................................... 3-13 4.0 Environmental Impacts of Operation .............................................................................. 4-1 4.1 Cooling System .................................................................................................. 4-2 4.1.1 Impingement of Fish and Shellfish........................................................ 4-10 NUREG-1437, Supplement 38 vi December 2010

Table of Contents 4.1.2 Entrainment of Fish and Shellfish in Early Lifestages........................... 4-14 4.1.3 Combined Effects of Impingement and Entrainment ............................ 4-15 4.1.3.1 Assessment of Population TrendsThe First Line of Evidence .................................................................................4-19 4.1.3.2 Assessment of Strength of ConnectionThe Second Line of Evidence .............................................................................4-20 4.1.3.3 Impingement and Entrainment Impact Summary ...................4-20 4.1.3.4 Discussion of Uncertainty .......................................................4-24 4.1.3.5 Overall Impingement and Entrainment Impact .......................4-25 4.1.4 Heat Shock ........................................................................................... 4-26 4.1.4.1 Potential Effects of Heated Water Discharges on Aquatic Biota .......................................................................................4-27 4.1.4.2 Historical Context ...................................................................4-27 4.1.4.3 Thermal Studies and Conclusions ..........................................4-28 4.1.4.4 Assessments of Thermal Impacts ..........................................4-30 4.1.4.5 NRC Staff Assessment of Thermal Impacts ...........................4-32 4.1.5 Potential Mitigation Options .................................................................. 4-32 4.2 Transmission Lines .......................................................................................... 4-36 4.2.1 Electromagnetic FieldsAcute Effects................................................. 4-38 4.2.2 Electromagnetic FieldsChronic Effects ............................................. 4-40 4.3 Radiological Impacts of Normal Operations ..................................................... 4-40 4.4 Socioeconomic Impacts of Plant Operations during the License Renewal Term ................................................................................................................. 4-42 4.4.1 Housing Impacts ................................................................................... 4-43 4.4.2 Public ServicesPublic Utility Impacts ................................................ 4-44 4.4.3 Offsite Land UseLicense Renewal Period......................................... 4-45 4.4.3.1 Population-Related Impacts ...................................................4-46 4.4.3.2 Tax-Revenue-Related Impacts ...............................................4-46 4.4.4 Public Services: Transportation Impacts during Operations ................ 4-47 4.4.5 Historic and Archeological Resources .................................................. 4-47 4.4.5.1 Site-Specific Cultural Resources Information .........................4-48 4.4.5.2 Conclusions ............................................................................4-48 4.4.6 Environmental Justice........................................................................... 4-49 4.5 Ground Water Use and Quality ........................................................................ 4-56 4.6 Threatened or Endangered Species ................................................................ 4-56 4.6.1 Aquatic Special Status Species ............................................................ 4-57 4.6.2 Terrestrial Threatened or Endangered Species.................................... 4-60 4.7 Evaluation of New and Potentially Significant Information on Impacts of Operations during the Renewal Term .............................................................. 4-61 4.8 Cumulative Impacts .......................................................................................... 4-61 4.8.1 Cumulative Impacts on Aquatic Resources .......................................... 4-62 4.8.2 Cumulative Impacts on Terrestrial Resources ...................................... 4-66 4.8.3 Cumulative Radiological Impacts.......................................................... 4-67 4.8.4 Cumulative Socioeconomic Impacts ..................................................... 4-68 4.8.5 Cumulative Impacts on Ground Water Use and Quality ....................... 4-69 4.8.6 Conclusions Regarding Cumulative Impacts ........................................ 4-69 4.9 Summary of Impacts of Operations during the Renewal Term......................... 4-69 December 2010 vii NUREG-1437, Supplement 38

Table of Contents 4.10 References ....................................................................................................... 4-70 5.0 Environmental Impacts of Postulated Accidents ............................................................ 5-1 5.1 Postulated Plant Accidents ................................................................................. 5-1 5.1.1 Design-Basis Accidents .......................................................................... 5-1 5.1.2 Severe Accidents .................................................................................... 5-3 5.2 Severe Accident Mitigation Alternatives ............................................................. 5-4 5.2.1 Introduction ............................................................................................. 5-4 5.2.2 Estimate of Risk ...................................................................................... 5-5 5.2.3 Potential Plant Improvements ................................................................. 5-7 5.2.4 Evaluation of Risk Reduction and Costs of Improvements ..................... 5-8 5.2.5 Cost-Benefit Comparison........................................................................ 5-8 5.2.6 Conclusions .......................................................................................... 5-11 5.3 References ....................................................................................................... 5-12 6.0 Environmental Impacts of the Uranium Fuel Cycle, Solid Waste Management, and Greenhouse Gas Emissions .......................................................................................... 6-1 6.1 The Uranium Fuel Cycle ..................................................................................... 6-1 6.2 Greenhouse Gas Emissions ............................................................................... 6-8 6.2.1 Introduction ............................................................................................. 6-8 6.2.2 IP2 and IP3 ............................................................................................. 6-9 6.2.3 GEIS ....................................................................................................... 6-9 6.2.4 Other Studies .......................................................................................... 6-9 6.2.4.1 Qualitative Studies....................................................................6-9 6.2.4.2 Quantitative Studies ...............................................................6-10 6.2.5 Summary of Nuclear Greenhouse Gas Emissions Compared to Coal ...................................................................................................... 6-12 6.2.6 Summary of Nuclear Greenhouse Gas Emissions Compared to Natural Gas........................................................................................... 6-13 6.2.7 Summary of Nuclear Greenhouse Gas Emissions Compared to Renewable Energy Sources ................................................................. 6-14 6.2.8 Conclusions .......................................................................................... 6-15 6.3 References ....................................................................................................... 6-17 7.0 Environmental Impacts of Decommissioning ................................................................. 7-1 7.1 Decommissioning ............................................................................................... 7-1 7.2 References ......................................................................................................... 7-4 8.0 Environmental Impacts of Alternatives to License Renewal .......................................... 8-1 8.1 Alternatives to the Existing IP2 and IP3 Cooling-Water System ........................ 8-2 8.1.1 Closed-Cycle Cooling Alternative ........................................................... 8-5 8.1.1.1 Description of the Closed-Cycle Cooling Alternative ................8-6 8.1.1.2 Environmental Impacts of the Closed-Cycle Cooling Alternative.................................................................................8-6 8.2 No-Action Alternative ........................................................................................ 8-20 8.3 Alternative Energy Sources .............................................................................. 8-26 8.3.1 Natural Gas-Fired Combined-Cycle (NGCC) Generation ..................... 8-28 NUREG-1437, Supplement 38 viii December 2010

Table of Contents 8.3.2 Purchased Electric Power..................................................................... 8-39 8.3.3 Conservation......................................................................................... 8-41 8.3.4 Alternatives Dismissed From Individual Consideration......................... 8-43 8.3.4.1 Wind Power ............................................................................8-43 8.3.4.2 Wood and Wood Waste..........................................................8-44 8.3.4.3 Hydropower ............................................................................8-45 8.3.4.4 Oil-Fired Generation ...............................................................8-45 8.3.4.5 Solar Power ............................................................................8-45 8.3.4.6 New Nuclear Generation ........................................................8-46 8.3.4.7 Geothermal Energy ................................................................8-46 8.3.4.8 Municipal Solid Waste ............................................................8-47 8.3.4.9 Other Biomass Derived Fuels .................................................8-47 8.3.4.10 Fuel Cells................................................................................8-48 8.3.4.11 Delayed Retirement ................................................................8-48 8.3.4.12 Combined Heat and Power ....................................................8-48 8.3.4.13 Supercritical Coal-Fired Generation .......................................8-49 8.3.5 Combination of Alternatives .................................................................. 8-59 8.3.5.1 Impacts of Combination Alternative 1 .....................................8-61 8.3.5.2 Impacts of Combined Alternative 2.........................................8-67 8.4 Summary of Alternatives Considered ............................................................... 8-72 8.5 References ....................................................................................................... 8-73 9.0 Summary and Conclusions ............................................................................................ 9-1 9.1 Environmental Impacts of the Proposed ActionLicense Renewal................... 9-4 9.1.1 Unavoidable Adverse Impacts ................................................................ 9-6 9.1.2 Irreversible or Irretrievable Resource Commitments .............................. 9-6 9.1.3 Short-Term Use Versus Long-Term Productivity .................................... 9-7 9.2 Relative Significance of the Environmental Impacts of License Renewal and Alternatives ......................................................................................................... 9-7 9.3 Conclusions and Recommendations .................................................................. 9-8 9.4 References ....................................................................................................... 9-11 Appendices Appendix A: Comments Received on the Environmental Review ............................................ A-1 Appendix B: Contributers to the Supplement ............................................................................ B-1 Appendix C: Chronology of NRC Staff Environmental Review Correspondence Related to the Entergy Nuclear Operations, Inc. Application for License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 .......................................................................... C-1 Appendix D: Organizations Contacted ...................................................................................... D-1 Appendix E: Indian Point Nuclear Generating Unit Numbers 2 and 3 Compliance Status and Consultation Correspondence....................................................................................... E-1 Appendix F: GEIS Environmental Issues Not Applicable to Indian Point Nuclear Generating Station Unit Nos. 2 and 3 ...............................................................................................F-1 December 2010 ix NUREG-1437, Supplement 38

Table of Contents Appendix G: U.S. Nuclear Regulatory Commission Staff Evaluation of Severe Accident Mitigation Alternatives for Indian Point Nuclear Generating Unit Nos. 2 and 3 in Support of License Renewal Application Review ....................................................................... G-1 Appendix H: U.S. Nuclear Regulatory Commission Staff Evaluation of Environmental Impacts of Cooling System ............................................................................................................. H-1 Appendix I: Statistical Analyses Conducted for Chapter 4 Aquatic Resources and Appendix H

........................................................................................................................................ I-1 NUREG-1437, Supplement 38 x December 2010

Figures Figure 2-1. Location of IP2 and IP3, 50-mi (80-km) radius ........................................................2-3 Figure 2-2. Location of IP2 and IP3, 6-mi (10-km) radius ..........................................................2-4 Figure 2-3. IP2 and IP3 property boundaries and environs .......................................................2-6 Figure 2-4. IP2 and IP3 site layout .............................................................................................2-7 Figure 2-5. IP2 intake structure ................................................................................................2-10 Figure 2-6. IP3 intake structure ................................................................................................2-11 Figure 2-7. IP2 intake system ..................................................................................................2-12 Figure 2-8. IP3 intake system ..................................................................................................2-12 Figure 2-9. Topographic features surrounding IP2 and IP3 .....................................................2-26 Figure 2-10. Hudson study area and river segments ...............................................................2-32 Figure 2-11. Hudson River area and national estuarine research sites ...................................2-33 Figure 4-1. Percentage of impingement composed of RIS fish and RIS fish plus blue crab relative to the estimated total impingement at IP2 .......................................................4-12 Figure 4-2. Percentage of impingement composed of RIS fish and RIS fish plus blue crab relative to the estimated total impingement at IP3 .......................................................4-12 Figure 4-3. Percentage of entrainment composed of RIS fish and total identified fish relative to the estimated total entrainment at IP2 and IP3 combined............................................4-15 Figure 4-4. General weight-of-evidence approach employed to assess the level of impact to population trends attributable to IP cooling system operation ......................................4-16 Figure 4-5. Minority block groups in 2000 within a 50-mi radius of IP2 and IP3 ......................4-52 Figure 4-6. Low-income block groups in 2000 within a 50-mi radius of IP2 and IP3 ...............4-55 December 2010 xi NUREG-1437, Supplement 38

Tables Table 2-1. Historical Impacts on the Hudson River Watershed ............................................... 2-42 Table 2-2. Facilities Discharging at Least 50 mgd (190,000 m3/day) into the Lower Hudson River ............................................................................................................................. 2-44 Table 2-3. Hudson River Environmental Studies Table ........................................................... 2-52 Table 2-4. Representative Important Aquatic Species............................................................. 2-53 Table 2-5. Locations in the Hudson River Estuary (see Figure 2-10) Where the Presence of RIS Life Stages Represented at Least 10 Percent of the Total Number Collected in Referenced Surveys or Studies ................................................................ 2-55 Table 2-6. Federally and State-Listed Terrestrial Species Potentially Occurring in Westchester County ..................................................................................................... 2-90 Table 2-7. IP2 and IP3 Employee Residence by County in 2006 .......................................... 2-115 Table 2-8. Housing in Dutchess, Orange, Putnam and Westchester Counties, New York .... 2-116 Table 2-9. Major Public Water Supply Systems in 2005 (mgd) ............................................. 2-119 Table 2-10. Average Annual Daily Traffic Counts on US 9 Near IP2 and IP3, 2004 ............. 2-121 Table 2-11. Population and Percent Growth in Dutchess, Orange, Putnam, and Westchester Counties, New York, from 1970 to 2000 and Projected for 2010 and 2050 .................................................................................................................... 2-125 Table 2-12. Demographic Profile of the Population in the IP2 and IP3 Four-County ROI in 2000 ....................................................................................................................... 2-126 Table 2-13. Demographic Profile of the Population in the IP2 and IP3 Four-County ROI in 2006 (Estimate) ...................................................................................................... 2-127 Table 2-14. Seasonal Housing within 50 mi (80 km) of the IP2 and IP3 ................................ 2-128 Table 2-15. Migrant Farm Worker and Temporary Farm Labor within 50 mi (80 km) of IP2 and IP3 ................................................................................................................ 2-130 Table 2-16. Major Employers in Westchester County in 2006 ............................................... 2-132 Table 2-17. Income Information for the IP2 and IP3 ROI....................................................... 2-132 Table 2-18. IP2 and IP3 PILOT and Property Tax Paid and Percentage of the Total Revenue of the Town of Cortlandt, Hendrick Hudson Central School District, and Village of Buchanan, 2003 to 2006 ..................................................................... 2-134 Table 2-19. Cultural Sequence and Chronology .................................................................... 2-135 Table 3-1. Category 1 Issues for Refurbishment Evaluation ..................................................... 3-4 Table 3-2. Category 2 Issues for Refurbishment Evaluation ..................................................... 3-7 Table 4-1. Generic (Category 1) Issues Applicable to the Operation of the IP2 and IP3 Cooling System during the Renewal Term..................................................................... 4-2 December 2010 xii NUREG-1437, Supplement 38

Tables Table 4-2. Site-Specific (Category 2) Issues Applicable to the Operation of the IP2 and IP3 Cooling System during the Renewal Term..................................................................... 4-6 Table 4-3. Cumulative Mortality and Injury of Selected Fish Species after Impingement on Ristroph Screens.......................................................................................................... 4-13 Table 4-4. Impingement and Entrainment Impact Summary for Hudson River RIS ................ 4-23 Table 4-5. Category 1 Issues Applicable to the IP2 and IP3 Transmission Lines during the Renewal Term .............................................................................................................. 4-37 Table 4-6. Category 2 and Uncategorized Issues Applicable to the IP2 and IP3 Transmission Lines during the Renewal Term ............................................................. 4-38 Table 4-7. Category 1 Issues Applicable to Radiological Impacts of Normal Operations during the Renewal Term ............................................................................................. 4-41 Table 4-8. Category 1 Issues Applicable to Socioeconomics during the Renewal Term ......... 4-42 Table 4-9. Category 2 Issues Applicable to Socioeconomics and Environmental Justice during the Renewal Term ............................................................................................. 4-43 Table 4-10. Category 2 Issues Applicable to Threatened or Endangered Species during the Renewal Term .............................................................................................................. 4-57 Table 4-11. Impingement Data for Shortnose and Atlantic Sturgeon at IP2 and IP3, 1975-1990 ................................................................................................................... 4-59 Table 5-1. Category 1 Issues Applicable to Postulated Accidents during the Renewal Term ... 5-2 Table 5-2. Category 2 Issues Applicable to Postulated Accidents during the Renewal Term .. 5-3 Table 5-3. IP2 and IP3 Core Damage Frequency...................................................................... 5-6 Table 5-4. Breakdown of Population Dose by Containment Failure Mode ................................ 5-7 Table 6-1. Category 1 Issues Applicable to the Uranium Fuel Cycle and Solid Waste Management during the Renewal Term ......................................................................... 6-2 Table 6-2. Nuclear GHG Emissions Compared to Coal........................................................... 6-12 Table 6-3. Nuclear GHG Emissions Compared to Natural Gas ............................................... 6-13 Table 6-4. Nuclear GHG Emissions Compared to Renewable Energy Sources ..................... 6-14 Table 7-1. Category 1 Issues Applicable to the Decommissioning of IP2 and IP3 Following the Renewal Term .......................................................................................................... 7-2 Table 8-1. Summary of Environmental Impacts of a Closed-Cycle Cooling Alternative at IP2 and IP3 ................................................................................................................................ 8-19 Table 8-2. Summary of Environmental Impacts of the No-Action Alternative .......................... 8-21 Table 8-3. Summary of Environmental Impacts of the NGCC Alternative Located at IP2 and IP3 and an Alternate Site ................................................................................................... 8-37 Table 8-4. Summary of Environmental Impacts of Combination Alternatives .......................... 8-71 December 2010 xiii NUREG-1437, Supplement 38

Tables Table 9-1. Summary of Environmental Significance of License Renewal, the No-Action Alternative, and Alternative Methods of Generation ....................................................... 9-9 NUREG-1437, Supplement 38 xiv December 2010

1 EXECUTIVE

SUMMARY

2 By letter dated April 30, 2007, Entergy Nuclear Operations, Inc. (Entergy) submitted an 3 application to the U.S. Nuclear Regulatory Commission (NRC) to renew the operating licenses 4 for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) for an additional 20-year 5 period. If the operating licenses are renewed, State regulatory agencies and Entergy will 6 ultimately decide whether the plant will continue to operate based on factors such as the need 7 for power, issues falling under the purview of the owners, or other matters within the States 8 jurisdiction, including acceptability of water withdrawal. Two state-level issues (consistency with 9 State water quality standards, and consistency with State coastal zone management plans) 10 need to be resolved. On April 2, 2010, the New York State Department of Environmental 11 Conservation (NYSDEC) issued a Notice of Denial regarding the Clean Water Act Section 401 12 Water Quality Certification. Entergy has since requested a hearing on the issue, and the matter 13 will be decided through NYSDECs hearing process. If the operating licenses are not renewed, 14 then IP2 and IP3 must be shut down at or before the expiration date of their current operating 15 licenses which expire September 28, 2013, and December 12, 2015, respectively.

16 The NRC has implemented Section 102 of the National Environmental Policy Act of 1969, as 17 amended (42 U.S.C. 4321), in Title 10, Part 51, Environmental Protection Regulations for 18 Domestic Licensing and Related Regulatory Functions, of the Code of Federal Regulations 19 (10 CFR Part 51). In 10 CFR 51.20(b)(2), the Commission requires preparation of an 20 environmental impact statement (EIS) or a supplement to an EIS for renewal of a reactor 21 operating license. In addition, 10 CFR 51.95(c) states that the EIS prepared at the operating 22 license renewal stage will be a supplement to NUREG-1437, Volumes 1 and 2, Generic 23 Environmental Impact Statement for License Renewal of Nuclear Plants (hereafter referred to 24 as the GEIS).(1) 25 Upon acceptance of the IP2 and IP3 application, the NRC began the environmental review 26 process described in 10 CFR Part 51 by publishing a notice of intent to prepare an EIS and 27 conduct scoping. The NRC staff visited the IP2 and IP3 site in September 2007, held two public 28 scoping meetings on September 19, 2007, and conducted two site audits on September 10-14, 29 2007, and September 24-27, 2007. In the preparation of this supplemental environmental 30 impact statement (SEIS) for IP2 and IP3, the NRC staff reviewed the IP2 and IP3 environmental 31 report (ER) and compared it to the GEIS; consulted with other agencies; conducted an 32 independent review of the issues following the guidance in NUREG-1555, Standard Review 33 Plans for Environmental Reviews for Nuclear Power Plants, Supplement 1: Operating License 34 Renewal, issued October 1999; and considered the public comments received during the 35 scoping process and in response to the draft SEIS. The public comments received during the 36 scoping process that were considered to be within the scope of the environmental review are 37 contained in the Scoping Summary Report for Indian Point Nuclear Generating Unit Nos. 2 and 38 3, issued by NRC staff in December 2008. In Appendix A of this SEIS, the NRC staff adopts, by 39 reference, the comments and responses in the Scoping Summary Report and provides 40 information on how to electronically access the scoping summary or view a hard copy.

(1)

The GEIS was originally issued in 1996. Addendum 1 to the GEIS was issued in 1999. Hereafter, all references to the GEIS include the GEIS and its Addendum 1.

December 2010 xv NUREG-1437, Supplement 38

Executive Summary 1 The NRC staff held public meetings in Cortlandt Manor, New York, on February 12, 2009 and 2 described the preliminary results of the NRC environmental review, answered questions, and 3 provided members of the public with information to assist them in formulating comments on the 4 draft SEIS. The NRC staff considered and addressed all of the comments received. These 5 comments are reflected in the SEIS or addressed in Appendix A, Part 2, to this SEIS.

6 This SEIS includes the NRC staffs analysis that considers and weighs the environmental 7 effects of the proposed action, the environmental impacts of alternatives to the proposed action, 8 and mitigation measures for reducing or avoiding adverse effects. It also includes the NRC 9 staffs recommendation regarding the proposed action.

10 The Commission has adopted the following statement of purpose and need for license renewal 11 from the GEIS:

12 The purpose and need for the proposed action (renewal of an operating license) 13 is to provide an option that allows for power generation capability beyond the 14 term of a current nuclear power plant operating license to meet future system 15 generating needs, as such needs may be determined by State, utility, and, where 16 authorized, Federal (other than NRC) decision makers.

17 The purpose of the NRC staffs environmental review, as defined in 10 CFR 51.95(c)(4) and the 18 GEIS, is to determine the following:

19 whether or not the adverse environmental impacts of license renewal are so 20 great that preserving the option of license renewal for energy planning decision 21 makers would be unreasonable.

22 Both the statement of purpose and need and the evaluation criterion implicitly acknowledge that 23 there are factors, in addition to license renewal, that will ultimately determine whether an 24 existing nuclear power plant continues to operate beyond the period of the current operating 25 license (or licenses).

26 NRC regulations (10 CFR 51.95(c)(2)) contain the following statement regarding the content of 27 SEISs prepared at the license renewal stage:

28 The supplemental environmental impact statement for license renewal is not 29 required to include discussion of need for power or the economic costs and 30 economic benefits of the proposed action or of alternatives to the proposed 31 action except insofar as such benefits and costs are either essential for a 32 determination regarding the inclusion of an alternative in the range of alternatives 33 considered or relevant to mitigation. In addition, the supplemental environmental 34 impact statement prepared at the license renewal stage need not discuss other 35 issues not related to the environmental effects of the proposed action and the 36 alternatives, or any aspect of the storage of spent fuel for the facility within the 37 scope of the generic determination in 10 CFR 51.23(a) [Temporary storage of 38 spent fuel after cessation of reactor operation-generic determination of no 39 significant environmental impact] and in accordance with 10 CFR 51.23(b).

40 The GEIS contains the results of a systematic evaluation of the consequences of renewing an 41 operating license and operating a nuclear power plant for an additional 20 years. It evaluates 42 92 environmental issues using the NRCs three-level standard of significanceSMALL, 43 MODERATE, or LARGEdeveloped using the Council on Environmental Quality (CEQ)

NUREG-1437, Supplement 38 xvi December 2010

Executive Summary 1 guidelines.

2 The following definitions of the three significance levels are set forth in footnotes to Table B-1 of 3 Appendix B, Environmental Effect of Renewing the Operating License of a Nuclear Power 4 Plant, to 10 CFR Part 51, Subpart A, National Environmental Policy ActRegulations 5 Implementing Section 102(2):

6 SMALLEnvironmental effects are not detectable or are so minor that they will 7 neither destabilize nor noticeably alter any important attribute of the resource.

8 MODERATEEnvironmental effects are sufficient to alter noticeably, but not to 9 destabilize, important attributes of the resource.

10 LARGEEnvironmental effects are clearly noticeable and are sufficient to 11 destabilize important attributes of the resource.

12 For 69 of the 92 issues considered in the GEIS, the analysis in the GEIS reached the following 13 conclusions:

14 (1) The environmental impacts associated with the issue have been determined to apply 15 either to all plants or, for some issues, to plants having a specific type of cooling system 16 or other specified plant or site characteristics.

17 (2) A single significance level (that is, SMALL, MODERATE, or LARGE) has been assigned 18 to the impacts (except for collective offsite radiological impacts from the fuel cycle and 19 from high-level waste and spent fuel disposal).

20 (3) Mitigation of adverse impacts associated with the issue has been considered in the 21 analysis, and it has been determined that additional plant-specific mitigation measures 22 are not likely to be sufficiently beneficial to warrant implementation.

23 These 69 issues were identified in the GEIS as Category 1 issues. In the absence of new and 24 significant information, the staff relied on conclusions in the GEIS for issues designated as 25 Category 1 in Table B-1 of Appendix B to 10 CFR Part 51, Subpart A.

26 Of the 23 issues that do not meet the criteria set forth above, 21 are classified as Category 2 27 issues requiring analysis in a plant-specific supplement to the GEIS. The remaining two issues, 28 environmental justice and chronic effects of electromagnetic fields, were not categorized.

29 Environmental justice was not evaluated on a generic basis and must be addressed in a plant-30 specific supplement to the GEIS. Information on the chronic effects of electromagnetic fields 31 was not conclusive at the time the GEIS was prepared.

32 This SEIS documents the NRC staffs consideration of all 92 environmental issues identified in 33 the GEIS. The NRC staff considered the environmental impacts associated with alternatives to 34 license renewal and compared the environmental impacts of license renewal and the 35 alternatives. The alternatives to license renewal that were considered include the no-action 36 alternative (not renewing the operating licenses for IP2 and IP3), alternative methods of power 37 generation, and conservation. The NRC staff also considered an alternative that included 38 continued operation of IP2 and IP3 with a closed-cycle cooling system. This alternative is 39 considered for several reasons. First, the New York State Department of Environmental 40 Conservation (NYSDEC) issued a preliminary determination in its 2003 draft and 2004 revised 41 draft State Pollutant Discharge Elimination System (SPDES) permits that closed cycle cooling is 42 the site-specific best technology available (BTA) to reduce impacts on fish and shellfish; December 2010 xvii NUREG-1437, Supplement 38

Executive Summary 1 currently the revised draft SPDES permit is the subject of NYSDEC proceedings, and the 2 existing SPDES permit continues in effect at this time. Second, NYSDEC affirmed this view in 3 its April 2, 2010, Notice of Denial of Entergys Clean Water Act Section 401 Water Quality 4 Certification, indicating that closed cycle cooling would minimize aquatic impacts; that 5 determination is currently subject to further State-level adjudication. Third, NYSDEC has 6 published a draft policy on BTA indicating that Wet closed-cycle cooling or its equivalent is the 7 minimum performance goal for existing industrial facilities that operate a CWIS [cooling water 8 intake system] in connection with a point source thermal discharge. Public comments on that 9 draft policy were submitted through July 9, 2010.

10 Entergy and the NRC staff have established independent processes for identifying and 11 evaluating the significance of any new information on the environmental impacts of license 12 renewal. Neither Entergy nor the staff has identified information that is both new and significant 13 related to Category 1 issues that would call into question the conclusions in the GEIS. Similarly, 14 neither the scoping process nor the NRC staff has identified any new issue applicable to IP2 15 and IP3 that has a significant environmental impact. Therefore, the NRC staff relies on the 16 conclusions of the GEIS for all of the Category 1 issues that are applicable to IP2 and IP3.

17 Entergys license renewal application presents an analysis of the 21 Category 2 issues that are 18 applicable to IP2 and IP3, plus environmental justice and chronic effects from electromagnetic 19 fields, for a total of 23 issues. The NRC staff has reviewed the Entergy analysis and has 20 conducted an independent assessment of each issue. Six of the Category 2 issues are not 21 applicable because they are related to a type of existing cooling system, water use conflicts, 22 and ground water use not found at IP2 and IP3. Entergy has stated that its evaluation of 23 structures and components, as required by 10 CFR 54.21, Contents of ApplicationTechnical 24 Information, did not identify any major plant refurbishment activities or modifications as 25 necessary to support the continued operation of IP2 and IP3 for the license renewal period.

26 Entergy did, however, indicate that it plans to replace reactor vessel heads and control rod drive 27 mechanisms at IP2 and IP3. The NRC staff has evaluated the potential impacts of these 28 activities using the framework provided by the GEIS for addressing refurbishment issues.

29 Seventeen environmental issues related to operational impacts and postulated accidents during 30 the renewal term are discussed in detail in this SEIS. These include 15 Category 2 issues and 31 2 uncategorized issues, environmental justice and chronic effects of electromagnetic fields. The 32 NRC staff also discusses in detail the potential impacts related to the 10 Category 2 issues that 33 apply to refurbishment activities. The NRC staff concludes that the potential environmental 34 effects for most of these issues are of SMALL significance in the context of the standards set 35 forth in the GEIS with three exceptionsentrainment, impingement, and heat shock from the 36 facilitys heated discharge. The NRC staff jointly assessed the impacts of entrainment and 37 impingement to be MODERATE based on NRCs analysis of representative important species.

38 Impacts from heat shock potentially range from SMALL to LARGE depending on the 39 conclusions of thermal studies proposed by the NYSDEC. Based on corrected data received 40 since completing the draft SEIS, the NRC staff concludes that impacts to the endangered 41 shortnose sturgeon - which ranged from SMALL to LARGE in the draft SEIS - are likely to be 42 SMALL.

43 The NRC staff also determined that appropriate Federal health agencies have not reached a 44 consensus on the existence of chronic adverse effects from electromagnetic fields. Therefore, 45 no further evaluation of this issue is required.

NUREG-1437, Supplement 38 xviii December 2010

Executive Summary 1 For severe accident mitigation alternatives (SAMAs), the staff concludes that a reasonable, 2 comprehensive effort was made to identify and evaluate SAMAs. Based on its review of the 3 SAMAs for IP2 and IP3 and the plant improvements already made, the NRC staff concludes that 4 several SAMAs may be cost-beneficial. However, these SAMAs do not relate to adequate 5 management of the effects of aging during the period of extended operation. Therefore, they do 6 not need to be implemented as part of license renewal pursuant to 10 CFR Part 54, 7 Requirements for Renewal of Operating Licenses for Nuclear Power Plants.

8 Cumulative impacts of past, present, and reasonably foreseeable future actions were 9 considered, regardless of what agency (Federal or non-Federal) or person undertakes such 10 other actions. For purposes of this analysis, the NRC staff determined that the cumulative 11 impacts to terrestrial and aquatic resources in the IP2 and IP3 environs would be LARGE, due 12 primarily to past development and pollution, much of which preceded IP2 and IP3 or occurred 13 as a result of other actions (for example, suburban development and hardening of the Hudson 14 River shoreline).

15 The NRC staffs analysis indicates that the adverse impacts of potential alternatives will differ 16 from those of the proposed action. Most alternatives result in smaller impacts to aquatic life, 17 while creating greater impacts in other resource areas. Often, the most significant 18 environmental impacts of alternatives result from constructing new facilities or infrastructure.

19 The recommendation of the NRC staff is that the Commission determine that the adverse 20 environmental impacts of license renewals for IP2 and IP3 are not so great that not preserving 21 the option of license renewal for energy planning decision makers would be unreasonable. This 22 recommendation is based on (1) the analysis and findings in the GEIS, (2) the ER and other 23 information submitted by Entergy, (3) consultation with other Federal, State, Tribal, and local 24 agencies, (4) the staffs own independent review, and (5) the staffs consideration of public 25 comments received during the scoping process and in response to the draft SEIS.

December 2010 xix NUREG-1437, Supplement 38

1 December 2010 xx NUREG-1437, Supplement 38

Abbreviations/Acronyms 1 Abbreviations/Acronyms 2 E degree(s) 3 m micron(s) 4 3D three dimensional 5 ACAA American Coal Ash Association 6 ac acre(s) 7 AC alternating current 8 ACC averted cleanup and decontamination 9 ADAMS Agencywide Documents Access and Management System 10 ADAPT Atmospheric Data Assimilation and Parameterization Technique 11 ACEEE American Council for an Energy Efficient Economy 12 AEC Atomic Energy Commission 13 AFW auxiliary feed water 14 AGTC Algonquin Gas Transmission Company 15 ALARA as low as reasonably achievable 16 ANOVA analysis of variance 17 AOC averted off-site property damage costs 18 AOE averted occupational exposure costs 19 AOSC averted on-site costs 20 APE averted public exposure 21 ASA Applied Science Associates 22 ASME American Society of Mechanical Engineers 23 ASMFC Atlantic States Marine Fisheries Commission 24 ASSS alternate safe shutdown system 25 ATWS anticipated transient without scram 26 AUTOSAM Automated Abundance Sampler 27 BA biological assessment 28 BO Biological Opinion 29 Board Atomic Safety and Licensing Board 30 Bq/L becquerel per liter 31 Bq/kg becquerel per kilogram 32 BSS Beach Seine Survey 33 BTA best technology available 34 BTU British thermal unit(s) 35 C Celsius 36 CAA Clean Air Act 37 CAFTA computer aided fault-tree analysis code 38 CAIR Clean Air Interstate Rule 39 CAMR Clean Air Mercury Rule 40 CCF common cause failure 41 CCMP Comprehensive Conservation and Management Plan 42 CCW component cooling water December 2010 xxi NUREG-1437, Supplement 38

Abbreviations and Acronyms 1 CCWD Cortlandt Consolidated Water District 2 CDF core damage frequency 3 CDM Clean Development Mechanism 4 CET Containment Event Tree 5 CEQ Council on Environmental Quality 6 CFR Code of Federal Regulations 7 cfs cubic foot (feet) per second 8 CHGEC Central Hudson Gas & Electric Corporation 9 Ci curie(s) 10 CI confidence interval 11 cm centimeter(s) 12 CMP Coastal Management Plan 13 CMR conditional mortality rate 14 CNP Cook Nuclear Plant 15 CO carbon monoxide 16 CO2 carbon dioxide 17 COE cost of enhancement 18 COL Combined License 19 Con Edison Consolidated Edison Company of New York 20 CORMIX Cornell University Mixing Zone Model 21 CPUE catch-per-unit-effort 22 CRDM control rod drive mechanism 23 CST condensate storage tank 24 CV coefficient of variation 25 CWA Clean Water Act 26 CWIS Circulating Water Intake System 27 CZMA Coastal Zone Management Act 28 dB(A) decibel(s) 29 DBA Design-basis accident 30 DC direct current 31 DDT dichloro-diphenyl-trichloroethane 32 DEIS Draft Environmental Impact Statement 33 DF Decontamination Factor 34 DNA deoxyribonucleic acid 35 DNR Department of Natural Resources 36 DO dissolved oxygen 37 DOC dissolved organic carbon 38 DOE U.S. Department of Energy 39 DOS Department of State 40 DOT U.S. Department of Transportation 41 DPS Distinct Population Segment 42 DSEIS Draft Supplemental Environmental Impact Statement 43 EA Environmental Assessment 44 ECL Environmental Conservation Law 45 EDG emergency diesel generator NUREG-1437, Supplement 38 xxii December 2010

Abbreviations/Acronyms 1 EIA Energy Information Administration 2 EIS environmental impact statement 3 EFH Essential Fish Habitat 4 ELF-EMF extremely low frequency-electromagnetic field 5 EMR entrainment mortality rate 6 Entergy Entergy Nuclear Operations, Inc.

7 EOP emergency operating procedure 8 EPA U.S. Environmental Protection Agency 9 EPRI Electric Power Research Institute 10 ER Environmental Report 11 ER-M effects-range-median 12 ESA Endangered Species Act 13 F Fahrenheit 14 F&O Facts and Observations 15 FAA Federal Aviation Administration 16 FDA Food and Drug Administration 17 FEIS Final Environmental Impact Statement 18 FERC Federal Energy Regulatory Commission 19 FES Final Environmental Statement 20 FJS Fall Juvenile Survey 21 FPC Federal Power Commission 22 fps feet per second 23 FPS fire protection system 24 FR Federal Register 25 FSAR Final Safety Analysis Report 26 FSS Fall Shoals Survey 27 ft foot (feet) 28 ft2 square feet 29 ft3 cubic feet 30 FWS U.S. Fish and Wildlife Service 31 g gram(s) 32 gal gallon(s) 33 gCeq/kWh gram(s) of carbon dioxide equivalents per kilowatt-hour 34 GEIS Generic Environmental Impact Statement for License Renewal of Nuclear 35 Plants, NUREG-1437 36 GHG greenhouse gas 37 GL Generic Letter 38 gpm gallon(s) per minute 39 GW gigawatt 40 ha hectare(s) 41 HAP hazardous air pollutant 42 HLW high-level waste 43 hr hour(s) 44 HRA Human Reliability Analysis December 2010 xxiii NUREG-1437, Supplement 38

Abbreviations and Acronyms 1 HRERF Hudson River Estuary Restoration Fund 2 HRFI Hudson River Fisheries Investigation 3 HRPC Hudson River Policy Committee 4 HRSA Hudson River Settlement Agreement 5 IAEA International Atomic Energy Agency 6 IMR impingement mortality rate 7 in. inch(es) 8 INEEL Idaho National Energy and Environmental Laboratory 9 IP1 Indian Point Nuclear Generating Unit No. 1 10 IP2 Indian Point Nuclear Generating Unit No. 2 11 IP3 Indian Point Nuclear Generating Unit No. 3 12 IPE individual plant examination 13 IPEEE individual plant examination of external events 14 ISFSI Independent Fuel Storage Installation 15 ISLOCA Interfacing Systems Loss of Coolant Accidents 16 IWSA Integrated Waste Services Association 17 kg kilogram(s) 18 km kilometer(s) 19 km2 square kilometer(s) 20 kV kilovolt(s) 21 kWh kilowatt hour(s) 22 lb pound(s) 23 L liter(s) 24 LERF Large Early Release Frequency 25 LLMW low-level mixed waste 26 LLNL Lawrence Livermore National Library 27 LOCA loss of coolant accident 28 LODI Lagrangian Operational Dispersion Integrator 29 LOE Line(s) of Evidence 30 lpm liters per minute 31 LRA license renewal application 32 LR linear regression 33 LRS Long River Survey 34 LSE load serving entities 35 m meter(s) 36 mm millimeter(s) 37 m2 square meter(s) 38 m3 cubic meter(s) 39 m3/sec cubic meter(s) per second 40 MAAP Modular Accident Analysis Program 41 MACCS2 MELCOR Accident Consequence Code System 2 42 MBq megabecquerel 43 mg milligram(s)

NUREG-1437, Supplement 38 xxiv December 2010

Abbreviations/Acronyms 1 mgd million gallons per day 2 mg/L milligram(s) per liter 3 mGy milligray 4 mi mile(s) 5 min minute(s) 6 MIT Massachusetts Institute of Technology 7 mL milliliter(s) 8 MLES Marine Life Exclusion System 9 MMBtu million British thermal unit(s) 10 mps meter(s) per second 11 mrad millirad(s) 12 mrem millirem(s) 13 mRNA messenger ribonucleic acid 14 MSE mean squared error 15 MSL mean sea level 16 MSPI Mitigating Systems Performance Indicator 17 mSv millisievert 18 MT metric ton(s) 19 MTU metric ton of uranium 20 MW megawatt 21 MWd megawatt-days 22 MW(e) megawatt(s) electric 23 MW(h) megawatt hour(s) 24 MW(t) megawatt(s) thermal 25 MWSF Mixed Waste Storage Facility 26 NAAQS National Ambient Air Quality Standards 27 NARAC National Atmospheric Release Advisory Center 28 NAS National Academy of Sciences 29 NEA Nuclear Energy Agency 30 NEPA National Environmental Policy Act of 1969, as amended 31 NESC National Electric Safety Code 32 NGO Nongovernmental Organization 33 NHPA National Historic Preservation Act 34 NIEHS National Institute of Environmental Health Sciences 35 NIRS Nuclear Information and Resource Service 36 NMFS National Marine Fisheries Service 37 NJDEP New Jersey Department of Environmental Protection 38 NO2 nitrogen dioxide 39 NOx nitrogen oxide(s) 40 NOAA National Oceanic and Atmospheric Administration 41 NPDES National Pollutant Discharge Elimination System 42 NRC U.S. Nuclear Regulatory Commission 43 NRHP National Register of Historic Places 44 NSSS nuclear steam supply system 45 NWJWW Northern Westchester Joint Water Works 46 NY/NJ/PHL New York/New Jersey/Philadelphia December 2010 xxv NUREG-1437, Supplement 38

Abbreviations and Acronyms 1 NYCA New York Control Area 2 NYCDEP New York City Department of Environmental Protection 3 NYCRR New York Code of Rules and Regulations 4 NYISO New York Independent System Operator 5 NYPA New York Power Authority 6 NYPSC New York Public Service Commission 7 NYRI New York Regional Interconnect, Inc.

8 NYSDEC New York State Department of Environmental Conservation 9 NYSDOH New York State Department of Health 10 NYSERDA New York State Energy Research and Development Authority 11 NYSHPO New York State Historic Preservation Office 12 O3 ozone 8-hour standard 13 OCNGS Oyster Creek Nuclear Generating Station 14 ODCM Offsite Dose Calculation Manual 15 OMB Office of Management and Budget 16 OPR Office of Protected Resources 17 PAB primary auxiliary building 18 PAH polycyclic aromatic hydrocarbon 19 PCB polychlorinated biphenyls 20 pCi/L picoCuries per liter 21 pCi/kg picoCuries per kilogram 22 PDS plant damage state 23 PILOT payment-in-lieu-of-taxes 24 PM particulate matter 25 PM2.5 particulate matter, 2.5 microns or less in diameter 26 PM10 particulate matter, 10 microns or less in diameter 27 POC particulate organic carbon 28 PORV power operated relief valve 29 POST Parliamentary Office of Science and Technology 30 ppm parts per million 31 ppt parts per thousand 32 PRA probabilistic risk assessment 33 PSA probabilistic safety assessment 34 PV photovoltaic 35 PWR pressurized water reactor 36 PWW Poughkeepsie Water Works 37 PYSL post yolk-sac larvae 38 REMP Radiological Environmental Monitoring Program 39 R-EMAP regional environmental monitoring and assessment program 40 RAI request for additional information 41 RCP reactor coolant pump 42 RCRA Resource Conservation and Recovery Act 43 RCS reactor cooling system 44 REMP radiological environmental monitoring program NUREG-1437, Supplement 38 xxvi December 2010

Abbreviations/Acronyms 1 RHR residual heat removal 2 Riverkeeper Hudson River Fishermens Association 3 RIS Representative Important Species 4 RKM river kilometer(s) 5 RM river mile(s) 6 RMP Risk Management Plan 7 ROD Record of Decision 8 ROI region of influence 9 ROW right-of-way 10 RPC long-term replacement power costs 11 rpm revolutions per minute 12 RRW risk reduction worth 13 RWST refueling water storage tank 14 s second(s) 15 SAFSTOR safe storage condition 16 SAMA severe accident mitigation alternative 17 SAR Safety Analysis Report 18 SAV submerged aquatic vegetation 19 SBO station blackout 20 Scenic Hudson Scenic Hudson Preservation Conference 21 SCR selective catalytic reduction 22 SECPOP sector population, land fraction and economic estimation program 23 SEIS Supplemental Environmental Impact Statement 24 SFP Spent Fuel Pool 25 SGTR Steam Generator Tube Ruptures 26 SI Safety Injection 27 SO2 sulfur dioxide 28 SOx sulfur oxide(s) 29 SPDES State Pollutant Discharge Elimination System 30 SPU stretch power uprate 31 sq mi square mile(s) 32 SR segmented regression 33 SRP Standard Review Plan 34 SRT Status Review Team 35 SSBR spawning stock biomass per-recruit 36 SSE safe shutdown earthquake 37 Sv person-sievert 38 SWS service water system 39 t ton(s) 40 TDEC Tennessee Department of Environment and Conservation 41 TI-SGTR thermally-induced Steam Generator Tube Ruptures 42 TLD Thermoluminescent dosimeter 43 TOC total organic carbon 44 TRC TRC Environmental Corporation December 2010 xxvii NUREG-1437, Supplement 38

Abbreviations and Acronyms 1 U.S. United States 2 U.S.C. United States Code 3 USACE U.S. Army Corps of Engineers 4 USAEC U.S. Atomic Energy Commission 5 USCB U.S. Census Bureau 6 USDA U.S. Department of Agriculture 7 USGS U.S. Geological Survey 8 UWNY United Water New York 9 V volt(s) 10 VALWNF value of non-farm wealth 11 VOC volatile organic compound 12 WCDOH Westchester County Department of Health 13 WISE World Information Service on Energy 14 WJWW Westchester Joint Water Works 15 WOE weight of evidence 16 WOG Westinghouse Owners Group 17 YSL yolk-sac larvae 18 YOY young of year 19 yr year(s)

NUREG-1437, Supplement 38 xxviii December 2010

1 Appendix A 2

3 4 Comments Received on the Environmental Review 5 Continued from Volume 2

Appendix A 1 MR.OROS: Mines easy. It's Soros without the `S` or the 2 billions. My name is George Oros. I'm a member of the 3 Westchester County Board of Legislators. I represent the people 4 that live in the shadow of Indian Point. The people of 5 Buchanan, Cortland, Northern Yorktown and Peekskill. And it's 6 ironic to me, as I often argue at my colleagues down-county how 7 those of us who live closest to the plant have the least amount 8 of alarm and concern. And that's probably because those of us 9 that live closest, know the most about the plant and how it 10 operates. One of the things I think has to be brought into 11 mind, in addition to how this plant curbs the carbon emissions, 12 how it's clean energy, how it provides the energy for about 21%

13 of the region's needs. Beyond all of that there's another 130-a-AQ/

SR 14 factor. This plant is a major employer of the people that live 15 in my legislative district. In addition, it is the largest 16 taxpayer to the school district, to the village of Buchanan, and 17 believe it or not, this plant pays 1% of Westchester Counties 18 property taxes. At a time when the economy is hurting, when the 19 people I represent are hurting, we cannot afford to overlook 20 that. You know, a few years ago there was a resolution passed 21 by our Board of Legislators about Indian Point and the 22 relicensing. But I would hope that those that want to use that 23 as some sort of hammer to try to what prevent the relicensing 24 read it carefully. Because that resolution is conditioned, very NUREG-1437, Supplement 38 A-1044 December 2010

Appendix A 130-a-AQ/

1 specifically, upon three things happening. SR contd.

2 One of them is someone's going to have to replace the 3 amount of tax dollars that this plant pays before it could close 4 or not be relicensed. Secondly, hire the 900 people. Find them 5 good meaningful jobs that are going to support their families 6 and third replace all of the energy that this plant produces. I 7 don't believe any of those three criteria can be met in the next 8 decade and therefore I don't see how, if you just consider those 9 factors and all the other factors, this plant cannot be 10 relicensed. I'm sure the NRC, I'm sure the operators of this 11 plant, I'm sure the State of New York, the local officials here 130-b-OP/

SO/SR 12 in the county will do all they can to make sure that this plant 13 is safe. That it is operated properly. I think that with all 14 of those safeguards in place, the relicensing is something that 15 we would all support here locally. So with that, I want to 16 thank you for the opportunity to address you. I've never done 17 this before, by the way, but I get a little tired of hearing the 18 people out there who don't live in our community and they come 19 to this community. We are in a community here, where we live 20 very peacefully with Indian Point and appreciate what it does 21 for our community. Thank you.

22 23 December 2010 A-1045 NUREG-1437, Supplement 38

Appendix A 1 MR. OTIS: Hi. My name is Mike Otis. I'm an 2 electrical and computer engineering professor at a local 3 university in New York State. I teach a variety of engineering 4 courses as well as a non-engineering course entitled "Renewable 5 Energy". This course looks at several of energy providing 6 solutions for the future by exploring different technologies and 7 uses a scientific approach in doing so. Nuclear energy plays a 8 very important role in this course is an excellent topic to 9 study when discussing viable solutions as well as public policy.

10 It really makes for a great debate. I am pleasantly surprised 11 by the open-mindedness of my students when they explore such 12 controversial and interesting topic using research and math and 131-a-OS 13 science as their tools. At the beginning of this course, many 14 of them had already drawn conclusions about nuclear energy that 15 were based on fear rather than fact. For most, the fear is gone 16 and their conclusions have changed. Now shifting gears to my 17 engineering department. Our primary goal of the engineering 18 department is to engage our engineering students in the learning 19 process through hands-on experiences. So the intertwined roles 20 of both conducting student research and acquiring scholarship 21 funds are both seen as critical components in educating this 22 nations next generation of scientists, mathematicians and 23 engineers. This investment is exactly why I hear today.

24 I want to make sure that you understand the important 131-b-SE NUREG-1437, Supplement 38 A-1046 December 2010

Appendix A 1 partnership my university has forged with Entergy and the Indian 2 Point Energy Center in seeding the development of our students.

3 Together with Entergy, we have created an excellent internship 4 program at Indian Point for both electrical and computer 5 engineering students. This site serves as one of the key 6 locations for students. For the past three summers, young men 7 and women have gained invaluable experiences in their focus of 8 study. This has far exceeded all my expectations. Entergy is 131-b-SE contd.

9 an investor in our students futures, as well as the nation's 10 future. We are developing the next generation of engineers that 11 this country so desperately needs. Yet we have come to the 12 realization that their education cannot be confined within the 13 four walls of the classroom. So field experience, working side-14 by-side with experienced engineers and technicians has enhanced 15 our students chances for success and invaluable for those 16 entering the workforce. The re-licensing of Indian Point is 17 critical to the future of our students, the future of the state 18 economy and the future of nuclear power in the United States.

19 Entergy exemplifies the best of corporate philanthropy and 20 they're providing the leadership and investment in education 131-c-SE/

SR 21 while others are cutting and slashing their commitments to 22 educate today's and tomorrow's youth. That is why I strongly 23 support the re-licensing of Indian Point for an additional 20 24 years. Thank you.

December 2010 A-1047 NUREG-1437, Supplement 38

Appendix A 131-d-SE 1

2 NUREG-1437, Supplement 38 A-1048 December 2010

Appendix A 131-d-SE contd.

131-e-AQ/EC/SR 1

2 December 2010 A-1049 NUREG-1437, Supplement 38

Appendix A 131-e-AQ/EC/SR contd.

1 2

NUREG-1437, Supplement 38 A-1050 December 2010

Appendix A 1 MR. PARKER: Thank you, Lance. Good afternoon everyone. My name 2 is John Parker and I am the regional attorney for the Department 3 of Environmental Conservation Region 3. I'm here today in my 4 official capacity representing the executive agencies of the 5 State of New York. I wanted to welcome the NRC, NRC staff, the 6 applicant, local residents and others to our wonderful lower 7 Hudson Valley region. We appreciate the opportunity to present 8 to the NRC our comments on Supplement-38 to the Generic 9 Environmental Impact Statement. We will submit more detailed 10 written comments by the close of the comment period on March 11 18th.

12 There has never been a complete and thorough 13 environmental review of Indian Point, even though environmental 14 reviews are routinely done on applications like this one. The 15 State of New York has and will continue to participate in this 16 process, but the draft is inadequate, incomplete and reaches the 132-a-AL 17 wrong conclusion preliminarily. There's a commitment by New 18 York to bring renewable energy and energy conservation measures 19 to the forefront of a sustainable energy future. These efforts 20 are part of the states action to reduce climate change impacts.

21 Yet this review today remains in many ways isolated from all of 22 the change going on around it.

23 We call upon NRC to do a full and thorough 132-b-NE 24 environmental review required by law as this process moves from December 2010 A-1051 NUREG-1437, Supplement 38

Appendix A 1 a draft to a final stage. On balance, the state is convinced 2 that a full and complete record will lead to only one conclusion 3 about the environmental impacts of this facility. The Draft 4 Supplemental EIS, which has been issued by NRC ostensibly to 5 fulfill its obligations underneath NEPA, which is the National 132-b-NE contd.

6 Environmental Policy Act, that requires the government to look 7 at the environmental impact of the decisions before it makes 8 them. Now, Indian Point is a nuclear generating facility, as we 9 all know. The license is for an additional 20 years. But let's 10 look at the environmental impacts.

11 In the process of generating electricity, Indian Point 12 consumes 2.5 billion gallons of Hudson River water each day.

13 This process has significant impacts and kills billions of fish 132-c-AE 14 and other aquatic organisms each year in addition to numerous 15 other impacts. The Draft Supplemental EIS, as we've learned, 16 concludes preliminarily that the environmental impacts would not 17 preclude a 20-year extension. This Supplemental EIS accepts 18 significant environmental impacts as quote unavoidable. We do 132-d-GI/

LR 19 not accept this premise nor that they are inevitable.

20 The Department of Environmental Conservation, or DEC, 21 commented on the scope in the fall of 2007, and we submitted 22 detailed written comments in October of 2007 as well. These 132-e-AE 23 comments raised several environmental issues that are not 24 addressed in a December 2008 draft that we are to talk about NUREG-1437, Supplement 38 A-1052 December 2010

Appendix A 1 today. Turning to some of those issues. New York raised the 2 category of aquatic ecology. As you've heard: entrainment, 3 impingement and thermal impacts to the Hudson River. The NRC's 4 analyses of these impacts undermines its conclusions. We have 5 many questions regarding these analyses, including whether the 132-f-AE 6 data reviewed were analyzed correctly. Whether the data support 7 the conclusions reached. Whether the conclusions that the NRC 8 reached our consistent with state and federal standards for the 9 Hudson. And importantly, whether these conclusions are 10 consistent with parallel proceedings before our agency, DEC.

11 MR. RAKOVAN: Mr. Parker, if you can summarize, please.

12 I'm sorry.

13 MR. PARKER: Okay. I do show -- it's difficult for 14 multiple agencies.

15 MR. RAKOVAN: I understand, but I've got a lot of 16 people who want to speak.

17 MR. PARKER: I have about -- OK. Additional issues 18 which we have a concern with are endangered species, the 19 socioeconomic impacts, historical impacts, impacts of the 20 coastal zone, which we feel are not adequately addressed. We 132-g-GI/

21 also have concerns about the generic nature of the review and LR 22 the failure to address site specific issues such as the 23 evacuation planning, seismic earthquake hazards, possibility of 24 terrorist attacks and long-term storage of spent nuclear fuel.

December 2010 A-1053 NUREG-1437, Supplement 38

Appendix A 1 In conclusion, there is nothing inevitable or unavoidable about 2 the environmental impacts of the operation of Indian Point.

3 The Draft SEIS review inadequately addresses many of 4 the environmental issues that the NRC is obligated to analyze 5 and assess. Yet despite these shortcomings, or perhaps because 132-g-GI/

6 of them, the Supplement concludes that the current level of LR contd.

7 environmental impacts do not need to be altered or changed and 8 that these impacts should not serve as impediment to license 9 renewal. We disagree and note that the NRC's conclusions do not 10 address issues raised by the State of New York in its scoping 11 process. Thank you.

12 13 NUREG-1437, Supplement 38 A-1054 December 2010

Appendix A 1

2 3 MS. PERRY: Okay, I just want to make a correction.

4 Good afternoon, my name is Sharonee Perry. I am a community 5 activist and consultant. As a former chairperson of community 6 Board 3 in Brooklyn, I would like to take this time to discuss 7 the many reasons I believe that Indian Point Energy Center 8 should receive a new license valid for 20 years. In this time 9 of financial crisis, we much carefully examine any proposal that 133-a-EC/

SO/SR 10 would cause costs to rise for New York City families. Currently 11 Indian Point helps to stabilize energy costs in Brooklyn. While 12 the cost of oil and gas energy can change dramatically based on 13 factors beyond our control, nuclear energy costs are relatively 14 consistent. Many of the lower income communities of Brooklyn, 15 rising costs are making it increasingly difficult for families 16 to survive in order to heat their homes.

17 Independent studies show that closing Indian Point can 18 raise energy costs for families by thousands of dollars per 133-b-EC 19 year. Stabilizing energy costs isn't the only reason to keep 20 Indian Point open for our communities. The quality of air that 21 we breathe decreases as more and more people move into Brooklyn, 22 increasing the number of cars that are being used. New York 23 City's air is already harmful. It violates federal safety 133-c-AQ 24 standards. Because of the poor air quality, our children suffer 25 from asthma. I am a witness to that who has a grandson who is a December 2010 A-1055 NUREG-1437, Supplement 38

Appendix A 1 chronic asthmatic, who I almost lost twice. The poor air 2 quality in our community is particularly caused by the same 133-c-AQ contd.

3 dirty power plants that would replace Indian Point if it closed.

4 Brooklyn cannot afford to have more of these dirty 5 plants pumping toxic fumes into the air, putting our families in 6 more danger. Unlike dirty plants, Indian Point provides clean 7 and affordable energy to New York City. Re-licensing Indian 8 Point would keep Brooklyn's air-quality from becoming more 133-d-AL/

9 harmful and pave the way for New York to develop clean energy AQ/SR 10 sources throughout the city. As Chair of Community Board 3, 11 I've worked with many people, businesses and institutions that 12 keeps Brooklyn strong. Indian Point is part of the larger 13 community affecting Brooklyn that we cannot afford to lose.

14 Thank you.

15 16 NUREG-1437, Supplement 38 A-1056 December 2010

Appendix A 1

2 MS. PERRY: Good evening. I'm Donzella Perry. I am a 3 Brooklyn resident in support of re-licensing Indian Point. New 4 York City's air quality is so dangerous that it falls far below 5 already lax federal standards. Yet, opponents to Indian Point 6 want to close the Center forcing the construction of dirty power 7 plants that will cause our air quality to plummet even further. 134-a-AL/

AQ/GI 8 Indian Point offers clean, affordable energy to New York City 9 and reduces the overall carbon footprint of the city. I along 10 with the members of my community support relicensing Indian 11 Point because it reduces the amount of greenhouse gas emissions 12 and pollution and sets a precedent for the rest of the city to 13 offer clean energy sources throughout New York. The dangers 14 air-quality in Brooklyn is particularly to the most vulnerable 15 of our society, children in low-income families. Our children 16 have breathed dirty city air for their entire lives and have 17 asthma rates that are four times the national average.

18 Parents in low income families cannot afford to pay 19 for proper care and medication to keep their childrens asthma 134-b-AL/

AQ/EJ 20 under control. As a result, low income children miss school 21 days and must depend on emergency care to respond to preventable 22 asthma attacks. The cause for the high incidence of asthma, 23 poor air-quality, is man-made and preventable. Closing Indian 24 Point will only make matters worse. New York should be moving December 2010 A-1057 NUREG-1437, Supplement 38

Appendix A 1 towards making all of its power plants cleaner, more efficient 2 and more affordable for our communities. Closing Indian Point 3 and relying on dirty power plants to pick up the slack is not 134-b-AL/

4 only dangerous for our families, it is irresponsible for the AQ/EJ contd.

5 future of our city. Our children that are severely asthmatic 6 are our endangered species.

7 8

NUREG-1437, Supplement 38 A-1058 December 2010

Appendix A 1

2 135-a-LE/OR 135-b-LE 135-c-RW/ST December 2010 A-1059 NUREG-1437, Supplement 38

Appendix A 1 MR. POCKRISS: Good afternoon. I'm Peter Pockriss, Director 2 of Development for Historic Hudson Valley. And I appreciate 3 the opportunity to say a few words to you today. Were a 4 non-profit organization that operates six historic sites 5 along the Hudson River, including Van Cortlandt Manor, which 6 is not too far from here and is the site of the great Jack-o-7 lantern Blaze which many of you may be familiar with. Our 8 museum properties are treasured community resources. Theyre 9 tourist destinations that attract thousands of visitors from 136-a-CR/

SO/SR 10 across the world. They are learning laboratories that serves 11 some 35,000 school children a year. Many from disadvantaged 12 backgrounds. Entergy has been a longtime philanthropic 13 investor in our mission. The companies partnership has 14 enabled us to launch the great Jack-o-lantern Blaze and 15 Winter Wonderlights. These family events have become 16 cherished holiday traditions for the people of our 17 communities. These heritage tourism events are also 18 important engines of the local economy.

19 Many of the 85,000 people who attended last year 20 stayed in area hotels, dined in restaurants and shopped on 21 our main streets. Blaze and Wonderlights have also had a 136-b-SO/

SR 22 tremendous impact on Historic Hudson Valley's own work, 23 boosting revenue, our membership base and awareness about our 24 NUREG-1437, Supplement 38 A-1060 December 2010

Appendix A 1 sites and educational programs. Entergy truly represents the 2 gold standard for corporate philanthropy here in Westchester 136-b-SO/

3 County. Historic Hudson Valley and other non-profits across SR contd.

4 the county and across the nation have benefited from millions 5 of dollars in philanthropic support from Entergy.

6 But beyond contributed dollars, we also benefit in 7 a variety of other meaningful ways. From the guidance and 8 expertise of the leadership team at Entergy's regional 9 headquarters. From the volunteer hours donated by Indian 10 Point employees. From Entergy sponsored workshops and 11 seminars, which empower our staffs. From networking 12 opportunities, which foster greater cooperation among those 136-c-SE 13 of us in the non-profit sector. And from promotional 14 initiatives that drive people to our programs and our events.

15 All of us at Historic Hudson Valley are proud to call Entergy 16 a friend, a committed neighbor and a partner in our efforts 17 to enrich the quality of life along the Hudson. It's our 18 great hope to continue to work side-by-side with Entergy for 19 many years to come. Thank you.

20 21 December 2010 A-1061 NUREG-1437, Supplement 38

Appendix A 1 MS. PUGLISI: Hi everybody, welcome to the Town of 2 Cortlandt. As he said, my name is Linda Puglisi. I've been 3 supervisor of our lovely town for a several years now.

4 Entergy/Indian Point is in our great village of Buchanan, in our 5 town of Cortlandt. Our role over the years has been to monitor 6 the safety, security of the facility prior to Entergy owning it.

7 And of course now that Entergy owns it, and if I say so myself, 8 Entergy has done a better job. I was here for many years 137-a-SA/

SR 9 before, so I can tell you other stories, but that's not the 10 point for this evening. Our town board and I have not said 11 close the plant. We have said consistently, keep it safe.

12 Please keep it safe for our residents.

13 As I said before, this has been our role. To go all 14 the meetings. We've gone to many meetings, public hearings.

15 Raised our questions. Asked the pertinent questions, which we 16 have the right to know to disseminate the information to our 17 citizens. We realize this forum tonight is not to address the 18 safety and security of the facility, but to address the 137-b-GW/

RW/PA/SF 19 environmental issues, so if I just may raise some things that I 20 would like the NRC to please consider as they proceed in this 21 process. Please address the storage of the spent nuclear waste 22 on-site in the DSEIS. Consider all feasible alternatives 23 regarding severe accident mitigation alternatives are important.

24 Thank you. Take a hard look at releases of radiological NUREG-1437, Supplement 38 A-1062 December 2010

Appendix A 1 contaminants into groundwater and into the atmosphere of course.

2 In the year 2000, I think it was, there was a release that we 137-b-GW/

RW/PA/SF 3 had to monitor and be on concerned about as you all recall. And contd.

4 address the storage of the spent nuclear waste on the site.

5 Under NEPA, an agency must take a hard look at the consequences 6 of its proposed actions and provide important information to the 7 public. Under an EIS, an EIS cannot rely solely on 8 unsubstantiated assertions. We have a whole list, which I've 137-c-NE 9 submitted to the NRC. I won't go through all the list, I 10 promise you, but there are many points that we would like the 11 NRC to consider as they review the environmental aspects of this 12 secret process.

13 One thing that was really upsetting to us on the town 14 board, as I said in my opening remarks that it's in the town of 15 Cortlandt, we had passed a resolution sent it onto the NRC 16 wanting to be an intervener. Which means that we wanted to have 17 a chair at the table, a seat at the table, to raise our 18 questions and be there as the process goes on. But we were 137-d-LR/

19 denied and so I just have a little point to make about that that ST 20 I think that the host community should've been seated at the 21 table. Then the gentleman brought up before about, bring back 22 the National Guard. We wrote a letter to the governor saying, 23 please return the National Guard, Coast Guard cutters, no-fly 24 zone. I've been saying for a decade, let's keep them. Let's December 2010 A-1063 NUREG-1437, Supplement 38

Appendix A 1 bring them back. These are things that we need. Safety and 137-d-LR/

2 security is what I monitor. That's what our town board ST 3 monitors. I thank you very much for listening to me tonight.

4 5

6 7

8 9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 NUREG-1437, Supplement 38 A-1064 December 2010

Appendix A 1

2 3

December 2010 A-1065 NUREG-1437, Supplement 38

Appendix A 137-e-LR 1

NUREG-1437, Supplement 38 A-1066 December 2010

Appendix A 137-f-AL/LE/

PA/RF/SF 137-g-NE/RW 1

December 2010 A-1067 NUREG-1437, Supplement 38

Appendix A 137-h-AL 137-i-PA 137-j-RI 1

NUREG-1437, Supplement 38 A-1068 December 2010

Appendix A 1

137-j-RI contd.

137-k-RF 137-l-DC/RW 2

December 2010 A-1069 NUREG-1437, Supplement 38

Appendix A 1

2 NUREG-1437, Supplement 38 A-1070 December 2010

Appendix A 137-m-LR 137-n-LR 1

2 3

4 5

December 2010 A-1071 NUREG-1437, Supplement 38

Appendix A 137-n-LR contd.

137-o-SO 137-p-ST 137-q-EP 1

2 NUREG-1437, Supplement 38 A-1072 December 2010

Appendix A 137-r-LR 1

December 2010 A-1073 NUREG-1437, Supplement 38

Appendix A 1

2 138-a-EJ/HH/LE NUREG-1437, Supplement 38 A-1074 December 2010

Appendix A 1

December 2010 A-1075 NUREG-1437, Supplement 38

Appendix A 1

NUREG-1437, Supplement 38 A-1076 December 2010

Appendix A 139-a-TS 139-b-TS 1

December 2010 A-1077 NUREG-1437, Supplement 38

Appendix A 139-b-RS contd.

139-c-AE 139-d-AE 1

NUREG-1437, Supplement 38 A-1078 December 2010

Appendix A 139-d-AE contd.

139-e-AE 139-f-AL/LR 1

December 2010 A-1079 NUREG-1437, Supplement 38

Appendix A 139-f-AL/LR contd.

139-g-LR 1

2 3

4 5

NUREG-1437, Supplement 38 A-1080 December 2010

Appendix A 1

December 2010 A-1081 NUREG-1437, Supplement 38

Appendix A 140-a-AE 1

NUREG-1437, Supplement 38 A-1082 December 2010

Appendix A 140-a-AE C ontd.

140-b-EP 1

December 2010 A-1083 NUREG-1437, Supplement 38

Appendix A 140-b-EP contd.

1 NUREG-1437, Supplement 38 A-1084 December 2010

Appendix A 140-b-EP contd.

140-c-AE 1

December 2010 A-1085 NUREG-1437, Supplement 38

Appendix A 1

140-c-AE contd.

2 NUREG-1437, Supplement 38 A-1086 December 2010

Appendix A 140-c-AE contd.

140-d-AE 1

December 2010 A-1087 NUREG-1437, Supplement 38

Appendix A 140-d-AE contd.

140-e-AE 1

NUREG-1437, Supplement 38 A-1088 December 2010

Appendix A 140-e-AE contd.

140-f-AE 140-g-AE 1

December 2010 A-1089 NUREG-1437, Supplement 38

Appendix A 140-g-AE contd.

140-h-AE 1

NUREG-1437, Supplement 38 A-1090 December 2010

Appendix A 140-h-AE contd.

140-i-AE 140-j-AE 1

December 2010 A-1091 NUREG-1437, Supplement 38

Appendix A 140-j-AE contd.

140-k-AE 140-l-AE 140-m-TS 1

NUREG-1437, Supplement 38 A-1092 December 2010

Appendix A 140-m-TS contd.

140-n-TS 1

December 2010 A-1093 NUREG-1437, Supplement 38

Appendix A 140-o-TS 140-p-TS 140-q-TS 1

NUREG-1437, Supplement 38 A-1094 December 2010

Appendix A 1

140-q-TS contd.

2 December 2010 A-1095 NUREG-1437, Supplement 38

Appendix A 140-q-TS contd.

140-r-TS 140-s-TS 1

NUREG-1437, Supplement 38 A-1096 December 2010

Appendix A 140-s-TS contd.

140-t-TS 140-u-GW/SA 1

December 2010 A-1097 NUREG-1437, Supplement 38

Appendix A 140-u-GW/SA contd.

1 NUREG-1437, Supplement 38 A-1098 December 2010

Appendix A 140-u-GW/SA contd.

140-v-GW/HH/RI 1

December 2010 A-1099 NUREG-1437, Supplement 38

Appendix A 140-v-GW/HH/RI contd.

140-w-GW/HH/RI 1

NUREG-1437, Supplement 38 A-1100 December 2010

Appendix A 140-w-GW/HH/RI contd.

1 December 2010 A-1101 NUREG-1437, Supplement 38

Appendix A 140-w-GW/HH/RI contd.

140-x-HH 1

NUREG-1437, Supplement 38 A-1102 December 2010

Appendix A 140-x-HH contd.

1 December 2010 A-1103 NUREG-1437, Supplement 38

Appendix A 140-x-HH contd.

1 2

NUREG-1437, Supplement 38 A-1104 December 2010

Appendix A 1

140-x-HH contd.

140-y-AE/CL 140-z-AE/CI 2

December 2010 A-1105 NUREG-1437, Supplement 38

Appendix A 140-z-AE/CI contd.

140-aa-SM 140-bb-SM 1

NUREG-1437, Supplement 38 A-1106 December 2010

Appendix A 140-bb-SM contd.

1 December 2010 A-1107 NUREG-1437, Supplement 38

Appendix A 140-bb-SM contd.

1 NUREG-1437, Supplement 38 A-1108 December 2010

Appendix A 140-bb-SM contd.

1 December 2010 A-1109 NUREG-1437, Supplement 38

Appendix A 140-bb-SM contd.

140-cc-SM 1

NUREG-1437, Supplement 38 A-1110 December 2010

Appendix A 140-cc-SM contd.

1 December 2010 A-1111 NUREG-1437, Supplement 38

Appendix A 140-cc-SM contd.

1 NUREG-1437, Supplement 38 A-1112 December 2010

Appendix A 140-cc-SM contd.

1 December 2010 A-1113 NUREG-1437, Supplement 38

Appendix A 140-dd-SM 1

NUREG-1437, Supplement 38 A-1114 December 2010

Appendix A 140-ee-SM 140-ff-SM 1

December 2010 A-1115 NUREG-1437, Supplement 38

Appendix A 140-ff-SM contd.

1 NUREG-1437, Supplement 38 A-1116 December 2010

Appendix A 140-ff-SM contd.

140-gg-UF 1

December 2010 A-1117 NUREG-1437, Supplement 38

Appendix A 140-gg-UF contd.

1 NUREG-1437, Supplement 38 A-1118 December 2010

Appendix A 140-gg-UF contd.

140-hh-SM 140-ii-SM/UF 1

December 2010 A-1119 NUREG-1437, Supplement 38

Appendix A 140-ii-SM/UF contd.

140-jj-SM 1

NUREG-1437, Supplement 38 A-1120 December 2010

Appendix A 140-jj-SM contd.

1 December 2010 A-1121 NUREG-1437, Supplement 38

Appendix A 140-kk-AL 140-ll-AL 1

NUREG-1437, Supplement 38 A-1122 December 2010

Appendix A 140-mm-AL 1

December 2010 A-1123 NUREG-1437, Supplement 38

Appendix A 140-nn-AL 140-oo-AL 1

NUREG-1437, Supplement 38 A-1124 December 2010

Appendix A 140-oo-AL contd.

140-pp-AL contd.

1 December 2010 A-1125 NUREG-1437, Supplement 38

Appendix A 140-pp-AL contd.

140-qq-AL 140-rr-AL 1

NUREG-1437, Supplement 38 A-1126 December 2010

Appendix A 140-rr-AL contd.

140-ss-LR 1

December 2010 A-1127 NUREG-1437, Supplement 38

Appendix A 1

NUREG-1437, Supplement 38 A-1128 December 2010

Appendix A 1

December 2010 A-1129 NUREG-1437, Supplement 38

Appendix A 1

NUREG-1437, Supplement 38 A-1130 December 2010

Appendix A 1

December 2010 A-1131 NUREG-1437, Supplement 38

Appendix A 1

NUREG-1437, Supplement 38 A-1132 December 2010

Appendix A 140-tt-AE 1

December 2010 A-1133 NUREG-1437, Supplement 38

Appendix A 140-tt-AE contd.

1 NUREG-1437, Supplement 38 A-1134 December 2010

Appendix A 140-tt-AE contd.

1 December 2010 A-1135 NUREG-1437, Supplement 38

Appendix A 140-tt-AE contd.

1 NUREG-1437, Supplement 38 A-1136 December 2010

Appendix A 140-tt-AE contd.

1 December 2010 A-1137 NUREG-1437, Supplement 38

Appendix A 140-tt-AE contd.

1 NUREG-1437, Supplement 38 A-1138 December 2010

Appendix A 140-tt-AE contd.

1 December 2010 A-1139 NUREG-1437, Supplement 38

Appendix A 140-tt-AE contd.

1 NUREG-1437, Supplement 38 A-1140 December 2010

Appendix A 140-tt-AE contd.

1 December 2010 A-1141 NUREG-1437, Supplement 38

Appendix A 140-uu-TS 140-vv-AE 140-ww-AE/CI 140-xx-AE 1

NUREG-1437, Supplement 38 A-1142 December 2010

Appendix A 140-xx-AE contd.

140-yy-AE 1

December 2010 A-1143 NUREG-1437, Supplement 38

Appendix A 1

NUREG-1437, Supplement 38 A-1144 December 2010

Appendix A 1

December 2010 A-1145 NUREG-1437, Supplement 38

Appendix A 1

NUREG-1437, Supplement 38 A-1146 December 2010

Appendix A 1

December 2010 A-1147 NUREG-1437, Supplement 38

Appendix A 1

NUREG-1437, Supplement 38 A-1148 December 2010

Appendix A 1

December 2010 A-1149 NUREG-1437, Supplement 38

Appendix A 1

NUREG-1437, Supplement 38 A-1150 December 2010

Appendix A 1

2 3

4 141-a-OR 141-b-AM/DE/PA/RW 141-c-AE/LE/RI 141-d-AL/OR December 2010 A-1151 NUREG-1437, Supplement 38

Appendix A 1

2 3

4 5

142-a-LE/OR 6

7 8

9 NUREG-1437, Supplement 38 A-1152 December 2010

Appendix A 1

2 143-a-GI/OR/RW December 2010 A-1153 NUREG-1437, Supplement 38

Appendix A 1 MR. RYAN: Good evening neighbors. My name is Tom Ryan. I'm a 2 field construction boilermaker for Local 5, but I assure you I 3 have not been compensated by either them or Entergy to come 4 speak in support of re-licensing. I also say neighbors because 5 I live in the so-called 10-mile kill zone over in Yorktown. My 6 four small children live there with me and go to school there.

7 My wife lives with me and also works there. I've worked in 8 power plants, Long Island, New York City and the lower Hudson 9 Valley. I've been at Indian Point when we unloaded the cask 10 systems for the spent-fuel. I've been actually in the reactors 144-a-EC/

SC/SR 11 while supporting Entergy and their maintenance department. I 12 don't say this to impress you, but to impress upon you, I speak 13 from experience. Of all the power plants that I have worked in 14 the last nine years, Indian Point is undoubtedly, hands down, 15 the cleanest, safest, most secure and most efficient. Indian 16 Point produces 2000 Mw of clean, low-cost electricity. It's 17 extremely important considering Tomkin's Cove is now closed, 18 hydropower has been closed-down in Sullivan County at the dams 19 and Bowline rumor has it may soon be dormant.

20 Renewable resource research and development is 21 applaudable, but it's not keeping the lights on. Southeast New 22 York will need another 2000 Mw by 2012. That's a conservative 144-b-EC/

SO 23 estimate by the Independent System Operator. Lack of a Article-24 10 Power Plant Siting Law is stifling the growth of our power NUREG-1437, Supplement 38 A-1154 December 2010

Appendix A 1 needs in New York State. Especially downstate. As for labor, 2 Indian Point Energy Center is a friend of labor and the middle 3 class. It provides inexpensive power as well as very good 4 paying jobs, benefits and health care to hundreds upon hundreds 144-b-EC/

5 of qualified employees and contractors. We hear about SO contd.

6 endangered species. The middle class is the most endangered 7 species economically today and most in need of the economic 8 stimulant called Indian Point. As for environment and security, 9 New York City is the target. I'm not a member of the Central 10 Intelligence Agency, but I don't need to remind you that New 11 York City is the target. Not all the way up here. New York 12 City power plants are shockingly unsecure. The IPEC security 13 is more than adequate in-house. However, you can't have too 144-c-ST 14 much. I would definitely urge the NRC, when looking at the re-15 licensing, to urge Governor Patterson to returning the National 16 Guard to the site as well as increasing the United States Coast 17 Guard patrols both sea and air. And strictly enforcing the no-18 fly zone.

19 As for foreign oil, most tools in a nuclear power 20 plant because they have the money and such stringent rules and 21 regulations and safety laws, most of the tools are made here in 144-d-OS 22 America. You go to other construction sites and theyre not.

23 Theyre made abroad. They're made in China, a communist 24 country. I won't get into politics. The uranium is mined in December 2010 A-1155 NUREG-1437, Supplement 38

Appendix A 1 the U.S.. Foreign oil obviously isn't. I'm going to think the 2 NRC for hearing my thoughts and I'll just leave you with this.

3 Talking about the environment. I've got quite a few friends, 4 close friends, and family that served in the front lines, both 144-d-OS contd.

5 Afghanistan and the Middle East. There is no reason why 6 American blood should be spilled for foreign oil. Indian Point 7 helps prevent that. Thank you.

8 9

NUREG-1437, Supplement 38 A-1156 December 2010

Appendix A 1

2 145-a-AM/PA 145-b-RW/ST 145-c-HH/LE 145-d-LE/OM/WA 145-e-AE 145-f-DE/OR December 2010 A-1157 NUREG-1437, Supplement 38

Appendix A 1 MR. RYAN: My name is Martin Ryan. I'm a resident of Rockland 2 County. And I live beside the Hudson River just downstream of 3 Indian point. I'm here tonight representing myself. I'm a 4 chemical engineer by profession. I believe that the impact 5 assessment as presented to this board has many inadequacies.

6 Therere too many to really mention all of them here tonight.

7 The process needs to ensure that all of the impacts of Indian 8 Point are catalogued and analyzed. The current assessment fails 9 on the following fronts.

10 The storage of spent fuel at the Indian Point cite 11 within a densely populated area. The effect of the outdated 12 cooling system on the Hudson River ecosystem and many endangered 145-g-OE 13 species. The effect of current groundwater contamination 14 present at the site and the status of underground piping, which 15 has not been addressed at all. The effect of current 16 groundwater contamination and air contamination on our children 17 and families. The effect of accidental and uncontrolled release 18 of materials into our water or air. The NRC has ultimate 19 responsibility to ensure that these issues are adequately 20 addressed. We cannot turn a blind eye to these impacts.

21 Whatever decision is made, it must be made with all the 22 relevant information. The outdated impact assessment that has 23 been presented does not do that and it needs to be updated with 24 accurate and researched information. Thank you.

NUREG-1437, Supplement 38 A-1158 December 2010

Appendix A 1 MR. SAFIAN: Thank you. My name is Keith Safian. I'm 2 a president and CEO of Phelps Memorial Hospital, right here in 3 Westchester, where I've worked for 19 years. There seems to be 4 a strong Brooklyn contingent, that is my personal homeland, but 5 I really been focused in Westchester, as I said, for almost two 6 decades. I speak tonight as Westchester's 10th largest 7 employer. Phelps Memorial Hospital has over 1500 employees.

8 About 140 more than we had two years ago. We continue to grow.

9 We have over 450 medical staff, 300 volunteers and that adds up 10 to over 2200 people who work at Phelps every week. We serve as 11 a backup hospital for Indian Point and have done that for over 12 20 years. They train with our staff every year on disaster 146-a-EP/

SE 13 preparedness. Although we've never received a nuclear related 14 injury from Indian Point since Phelps been there and since 15 Indian Point has been there.

16 This training, however, really serves a very important 17 purpose of preparing us for chemical and biological disasters.

18 It was very helpful on September 11, 2001 when seven victims 19 from the World Trade Center drove to Phelps Hospital for care 20 for their injuries. It was very helpful when anthrax was 21 discovered in Manhattan and about 200 people reached out to 22 Phelps to ask for help because they were exposed. And thanks to 23 Indian Point, our hospital was prepared for these kinds of 24 disasters, not the things you would think of. Phelps is a very, December 2010 A-1159 NUREG-1437, Supplement 38

Appendix A 1 very busy and growing hospital. We served over 268,000 patient 146-a-EP/

2 registrations last year, which was another record as was the SE contd.

3 year before. But we also spent a million dollars buying 4 heating oil. That cost us 30% more than the year before. All I 5 can say is thank goodness our electricity is not based on 6 foreign oil because otherwise that bill would have gone up. Our 7 hospital expanded in the last two years by physically 100%. We 8 doubled our square footage. We added a new medical office 9 building, a new emergency department, which has all private 10 rooms. We put in a new gigantic outpatient physical therapy 11 and occupational therapy service with an aqua-therapy swimming 146-b-EC 12 pool and a parking garage with 750 additional free parking 13 spaces. But despite all of that much increased square footage 14 our electricity bill only went up 12%. 100% more square 15 footage, only a 12% increase in electricity because Entergy and 16 the Indian Point plants were there to give us literally 17 unlimited additional electricity whenever we needed it. There 18 was never a question in our expansion plans that electricity 19 would be a limiting factor.

20 So, as a very large employer and a major health-care 21 provider, Indian Point is critical to our continued growth. But 146-c-AQ/

22 where I wear my health-care provider hat, were also very SR 23 concerned about the serious effects of air pollution on our 24 community. We've seen the incidence of lung cancer particularly NUREG-1437, Supplement 38 A-1160 December 2010

Appendix A 1 in women grow dramatically in the last few years. It has really 2 become the most a frequent killer of women, far more than youd 146-c-AQ/

SR 3 think. So, clean, pollution free nuclear power is the best contd.

4 source of power for the health of our community. Absent 5 adequate electricity, my hospital could not continue to grow.

6 We could not continue to hire more employees. We could not 7 continue to accommodate another 20,000 additional patient visits 8 each year. And given the terrible economic crisis that's facing 9 our state government and Washington, it's unthinkable that we 146-d-EC/

SO 10 could lose the safe, economically viable and irreplaceable 11 source of critically important electrical power. My last 12 comment is, the last thing you want as our community is for my 13 hospital to divert money from patient care to pay for more 14 higher cost electricity that's fired by imported oil rather than 15 safe and inexpensive nuclear power. Thank you.

16 17 December 2010 A-1161 NUREG-1437, Supplement 38

Appendix A 1

2 147-a-GE/LE 147-b-NE/PA 147-c-AM 147-d-OR NUREG-1437, Supplement 38 A-1162 December 2010

Appendix A 1 MR. SAMUELS: Good afternoon. My name is Al Samuels. I am 2 President and CEO of the Rockland Business Association. Our 3 organization represents over a thousand businesses in the 4 region. 24% of our members are from outside of Rockland. 7%

5 from Westchester. 7% from Orange County. We represent a very 6 diverse group. We have a very diverse membership base. We 7 speak on their behalf on many issues concerning rebuilding an 8 expansion of infrastructure, affordable health care and of 9 course the reliability and availability of electricity, which is 10 why I come before you today.

11 Historically, Rocklands residents have rarely viewed 12 Indian Point as being beneficial to the county. While they have 13 participated in the emergency planning process as part of 14 Rocklands officials responsibilities to the E-Plan without 15 either apparent tax or power benefits from the site, some 16 residents and elected officials took the viewpoint there was no 17 viable connection between the site and the county. If recent 148-a-AL/

SO 18 events have taught us anything, it's that seemingly disconnected 19 pieces of our economy, whether here or thousands of miles away 20 are delicately interconnected and when those pieces break, we 21 all suffer consequences and equally feel the financial impact.

22 The time for Rocklands agnostic feelings towards the future of 23 Indian Point is over.

24 Indian Points power now flows through our lines to December 2010 A-1163 NUREG-1437, Supplement 38

Appendix A 1 our businesses and our homes. Indian Point employees live in 2 Rockland County. When they spend their hard-earned money, those 3 dollars flow to our shops, to our gas stations, to our 4 restaurants. When they pay their school taxes that money flows 5 to our classrooms and goes towards paying our teacher salaries.

6 We agree with our colleagues in labor. This is not the time to 7 put union workers on the unemployment line.

8 Now in the face of the mounting budget cuts, the 9 threat of economic collapse, we need Indian Points, green low-10 cost electric power more than ever. The lower Hudson Valley 11 receives 18-36% of its electricity from Indian Point. A large 12 amount of power and by any reasonable measure, an amount we 148-a-AL/

SO 13 cannot easily afford to lose or to replace. contd.

14 Our association is very proud of something we call our 15 green counsel. This group addresses many issues and seeks many 16 green solutions, but business owners cannot rely on empty or 17 fanciful promises of alternative sources of energy. We have 18 businesses to run. Employees to pay. Taxes to make do. We 19 must submit this and pay these things every day. We must have 20 reliable and affordable electricity that runs 24/7 that 21 parallels the demands of our businesses. We need this in order 22 to be competitive in today's economy to survive. The Rockland 23 Business Association fully supports both our counties and our 24 state's energy efficiency reports and there were efforts. We NUREG-1437, Supplement 38 A-1164 December 2010

Appendix A 1 believe in the investing and the development of new sources of 2 green power. But let's first prove that we can both save enough 3 electricity through new efficiency programs and build enough 4 additional transmission and power producing infrastructure 5 before we casually dismiss 2000 Mw of efficient base-load power 6 right here in the Hudson Valley.

7 Rockland is no stranger to seeing energy providers 148-a-AL/

8 close up shop. Plant closures such as the Lovett Plant in SO contd.

9 Stonypoint have significantly impacted the budgets of our North 10 Rockland communities, of which I am a resident, and our school 11 district. We cannot allow other communities to suffer the same 12 consequences. That is why I am here today to support the 13 continued operation of the Indian Point Energy Center and to 14 urge the Nuclear Regulatory Commission to extend the site 15 license for another 20 years. And I thank you very much for 16 your time.

December 2010 A-1165 NUREG-1437, Supplement 38

Appendix A 1

148-b-AL/SO NUREG-1437, Supplement 38 A-1166 December 2010

Appendix A 148-c-AL/SO 1

December 2010 A-1167 NUREG-1437, Supplement 38

Appendix A 148-c-AL/SO contd.

1 2

NUREG-1437, Supplement 38 A-1168 December 2010

Appendix A 148-c-AL/SO contd.

1 December 2010 A-1169 NUREG-1437, Supplement 38

Appendix A 148-c-AL/SO contd.

1 NUREG-1437, Supplement 38 A-1170 December 2010

Appendix A 148-c-AL/SO contd.

1 December 2010 A-1171 NUREG-1437, Supplement 38

Appendix A 1

2 3

149-a-AE 149-b-EJ/HH 149-c-HH/LE NUREG-1437, Supplement 38 A-1172 December 2010

Appendix A 1

2 149-c-HH/LE contd.

149-d-EP/HH/RI 149-e-TS December 2010 A-1173 NUREG-1437, Supplement 38

Appendix A 1 MR. SEGER: Good evening. My name is Bob Seger. I'm the 2 business manager of Millwright Local-740. For those of you who 3 don't know what a millwright does, we pretty much do the 4 turbines and the generators inside, not only Indian Point but 5 every other powerhouse in the area. I'd like to thank the NRC 6 for the opportunity to speak. I have worked in those plants 7 since 1972, and I can tell you from first-hand knowledge that 150-a-SA/

SE 8 out of the three owners that I've worked for in those plants, 9 Entergy is by far the best one yet. They've invested millions 10 of dollars in the plant for safety and I can tell you that based 11 on work that I've had to do in there and that my members have to 12 do. I can't tell you how frustrating it is to know the job that 13 you want to do and have somebody come along and stop you because 14 they tell you that youre not doing it safe enough. Entergy's 15 been that way since they took over the plants. From an 16 economical standpoint, I can just tell you that a lot of the 17 people that I think will get up here tonight and have gotten up 18 here prior to this, are probably not people that have or are 150-b-SA/

19 going to be directly impacted by the plant closing. When some SO 20 of the gas stations and the delicatessen's start closing because 21 there's no money around here, those are the people that are 22 going to be affected, not the people that live in another area.

23 Over the last 10-years I've had the opportunity to meet with 24 some of the management of Indian Point. And all I keep getting NUREG-1437, Supplement 38 A-1174 December 2010

Appendix A 1 told is safety, safety, safety. I guess theres 2 things I really can't mention that they've told me as far as the 3 things that have been done for safety and security because from 150-b-SA/

SO 4 what I'm told, they won't let me back in the plant if I do. contd.

5 But, I just can't stress the difference that Entergy has made in 6 these plants. I had to write some things down, which I don't 7 think I've ever done before.

8 Entergy is probably under more scrutiny than any 9 nuclear facility that I've ever worked in. I've worked in For 10 Creek, I've worked in Three-Mile Island. Very rarely do you 11 hear anything about either. I think out of all the scrutiny 12 that they've gone through, they have always come out with 13 excellent ratings as to the improvements that they make and the 14 response time to the problems that they've had. I would only 15 suggest to some of people here that if you had trouble with a 16 car or if you had trouble with your house, you wouldn't throw 150-c-SA/

SE 17 the car in the junkyard or burn it down to the ground. You'd 18 fix it. I believe that that's what Entergy's intentions are and 19 have been and I believe that they'll continue to do it. Id 20 just like to say on behalf of my members and the rest of the 21 tradesmen that are in this room, thanks for the opportunity to 22 speak. I'll get it out away now. Yes, I'm interested in the 23 jobs that they provide for all of my members and the rest of the 24 organized labor as well as their own employees. But I've said December 2010 A-1175 NUREG-1437, Supplement 38

Appendix A 1 it here before, I would not send anybody from my Local into a 150-c-SA/

SE 2 place that I did not believe safe. I have no problems sending contd.

3 all of them into that facility. Thank you.

4 NUREG-1437, Supplement 38 A-1176 December 2010

Appendix A 1

150-d-EC/SR 150-e-AQ/OP/SO 150-f-SO/SR December 2010 A-1177 NUREG-1437, Supplement 38

Appendix A 1 MS. SEEMAN: Hello, my name is Laurie Seeman. Thank you for this 2 opportunity to speak. I am a resident that lives within 10 3 miles of the Indian Point Power Plant. I am also a mother of 4 two children. I am an environmental educator that works with 5 children, outdoor education and I teach them about 6 sustainability. I ask you that you do not re-license Indian 151-a-OR 7 Point Power Plant. I asked that and the same time I ask that 8 you do that, I'm doing something on my end. I'm teaching 9 children about conservation of energy. When I talk to the 10 children about the power plant, there's absolutely no way I can 11 explain to them why that power plant exists in this Hudson 12 Valley region. Theres absolutely not one explanation that 13 makes sense to the heart of a child.

14 I also would like address you and tell you that three 15 years after the Three-Mile Island nuclear incident I was there 16 in that vicinity for 11 days making a short independent film.

17 We were in the farmland within view of the towers and when 18 people saw us filming, the residents pulled over and spoke with 151-b-OS 19 us. I could not believe the stories that I heard. I was 20 hearing that there is sickness as a result of that power plant.

21 I was aware that there was a complete devastation of community.

22 Spiritual devastation. Financial devastation. I wish the 23 people here that work in these facilities could hear me speak 24 right now because the people in that town were abandoned by NUREG-1437, Supplement 38 A-1178 December 2010

Appendix A 1 their government. These people that work in these facilities 2 now do need to know that if there is an incident, the people 3 that are supporting them now will be gone. It's very 4 interesting to know that if that was a mishap at Three-Mile 5 Island those years ago, which was conveniently a term that our 6 media used, then why are those people still 30-plus years later 151-b-OS 7 having open mic night once a year for people to stand up and contd.

8 speak about what happened to them at that incident. It's a 9 very significant parallel situation, the people in that town, if 10 they were to hear about the savings that they benefited from 11 would hardly disagree and say they would give up every penny 12 that they have ever made in their lifetime to go back to the day 13 before that that incident occurred.

14 I have been to many town hearings about Indian Point.

15 It is my one passionate issue that I have stayed with since the 16 1980s. I've heard Entergy speak before our Rockland County 17 legislature and explain the benefit of the savings that we enjoy 18 from this power plant. I can't believe that we are gambling on 19 this type of a concept of safety. We are talking about numbers 151-c-SA 20 that nobody can agree upon. As a matter of fact, we can't agree 21 on the numbers because so many of them are not factual. I have 22 been to these hearings. I heard very informed people speak 23 about how reports are made on the wrong dates, so that incidents 24 are not pulled in under a certain timeframe which would make December 2010 A-1179 NUREG-1437, Supplement 38

Appendix A 1 them red-flagged. So many of these things that were gambling 151-c-SA 2 our future on are based on non-truths. I've been following it contd.

3 along and I'm old enough now to see the longer picture and it's 4 very frightening.

5 I would like to address the comment that the doctor 6 made from the hospital. I also heard Dr. Eric Larson speak 7 before our Rockland County Legislature. He has been for twenty-8 some years head of the emergency department at Westchester 9 Medical. Dr. Larson was also trained in triage for Indian Point 10 Power Plant. He has had an incident there. It's one of the 11 most striking stories I've heard in all of the testimony. They 12 had one member calm there who had his leg caught in a doorway 13 and his protection suit was gashed. Nuclear contamination got 14 into his wound. He was brought to Westchester Medical. OK, now 151-d-EP 15 I'm talking one person. They had to close down the emergency 16 room, triage all of the 40 other people to other locations.

17 Their entire medical staff that was available, I think he said 18 30 people were brought to work on this one person. Eric, Dr.

19 Larson kept saying this was one person. The only treatment they 20 had was to flush him down with water. And where did that water 21 go? It went into the drain and it's a fact. That is a fact.

22 If you want to base your decisions on facts, I would really 23 hardly like you to focus on that particular fact because that 24 one really speaks to my heart and tells me whats true. Thank NUREG-1437, Supplement 38 A-1180 December 2010

Appendix A 151-d-EP 1 you for this opportunity to speak. contd.

2 Oh, one more thing. I'm so sorry. I have this 3 newspaper that I have had in my office since 2006. The headline 4 is RADIOACTIVE WATER MAY BE FOLLOWING CRACKS TO THE HUDSON. I 5 went to the hearing on this. This nuclear power plant is based 6 on water technology. If there's one thing I know as an 7 environmentalist, water is the most ungovernable of all of the 8 elements. This nuclear power plant is not safe simply for the 9 fact that it's run on water. When I heard your panel of people 151-e-OR 10 address this issue, you had two different hydrologists that 11 spoke that night, they were in such contrary opinion about what 12 water does and where this was going and whos safe and who's not 13 safe. One of them said those of us on the other side of the 14 river don't have to worry about it. It's out of control. I 15 really hope that this power plant will be closed down and we can 16 begin a future of conservation and living in a very healthy way 17 where we all can get together and have a future. Thank you.

18 19 20 21 December 2010 A-1181 NUREG-1437, Supplement 38

Appendix A 1 MS. SHAPIRO: Yes, hi. I represent the Sierra Club and 2 before I get into my comments on the draft EIS, which I believe 3 this meeting was for, I want to congratulate Entergy on there 4 really great PR campaign for giving lots of money to not-for-5 profits that came here today to call for their support, which is 6 not what this meeting was really about and I think there was a 7 lot of misinformation that was told to these groups and I think 8 thats a sad comment on Entergy though. I hope the NRC 9 understands that, you know, if you use money to pay for people 10 to come and support you that doesn't mean that is a public 11 safety evaluation. I also wanted to say I'm sorry these people 12 left from the City, but the reality is no one who is calling for 152-a-GE/

PA 13 the closure of Indian Point for safety reasons believes that we 14 should be putting coal- fired plants that would increase asthma 15 in their communities or any community. That's never been a 16 replacement factor. Going to the GEIS, which I believe is an 17 incomplete and inadequate document because, there are a few 18 reasons, which I'll go through.

19 The first one is that it doesn't consider the long-20 term impacts of this new superseding license that Entergy is 21 planning to grant with regard to seismology evacuation 22 possibility and the increased population density in this area.

23 Because it is a new license as acknowledged by Entergy, these 24 factors must be considered. The EIS and the re-licensing NUREG-1437, Supplement 38 A-1182 December 2010

Appendix A 1 document does not consider those and therefore its fully 152-a-GE/

PA 2 inadequate and incomplete. This environmental report also does contd.

3 not include the fact that Entergy nor the NRC actually knows 4 the current licensing basis of the plant at the moment. They 5 don't actually have that knowledge because over of the time, the 6 last 40 years the plant has been operating, theyve been 7 granting exemption on top of exemption on top of exemption on 8 top of exemption on safety standards at the plant. So, it's 9 running not at design basis. Those issues will be carried over 10 into the new superseding license period. That must be included 11 in the EIS because those are large impacts when you have a 152-b-AM/

SA 12 degraded system.

13 For example, currently, the fire safety standards at 14 Indian Point are highly degraded. They exempted, NRC granted an 15 exemption from a one-hour fire rating because the rack that was 16 used was inadequate and they allow them now to operate with a 17 24-minute fire rating. Which means, if there's a fire in this 18 crucial part of the planet that's needed for safe shutdown, you 19 have to detect and put out the fire within 24-minutes or 20 there'll be a melt down. That's what we in this area and all of 21 the New York City people are living under that danger. The 22 other things that have been recently exempted in the last year 152-c-LE/

23 are that the spent-fuel pool, which we know is leaking, which OP 24 has been acknowledged to be leaking, they cannot inspect 60% of December 2010 A-1183 NUREG-1437, Supplement 38

Appendix A 1 it. They could inspect it, but the cost to Entergy, the cost 2 analysis to Entergy is too much. So the NRC has granted an 3 exemption. That makes this report highly incomplete and 4 inaccurate. Without a full inspection of the spent-fuel pool 5 that is known to be leaking, this report is not complete.

6 Further, they called it a relaxation of the 7 standards, to inspect a design basis required inspection, which 8 is the rust in the dome. They know there's rust in the dome.

9 Five years ago they got an extension for this inspection. Now, 10 they decided this year it's too difficult, it's too expensive, 11 to actually inspect this. So, they've given them a permanent, 12 permanent, which means they will never inspect this part of the 152-d-AM/

OP 13 plant, which is known to have rust in the dome. Which is truly 14 an aging management problem. They've granted that as an 15 exemption. These have great, large environmental impacts which 16 are not included in this. Additionally, 60% of the underground 17 piping at Indian Point and the cables are not being inspected.

18 Further, the last two things I'd to mention is that recently at 19 Indian Point a small camera, a digital camera, actually shut 20 down the plant because when Indian Point was built there were 21 no RF signals. Therefore, in the aging management of Indian 22 Point, it is required, its new information, that they must 23 include how they're going to deal with new technologies. Like 24 cell phones and cameras and various RF signals that are going NUREG-1437, Supplement 38 A-1184 December 2010

Appendix A 152-d-AM/

1 to be used by outside contractors and visitors to the plant. OP contd.

2 Finally, the overall problem with this report is that it is done 3 on a cost-benefit analysis basis, which is a violation of NEPA.

4 They actually evaluate how much the cost to the benefit to the 5 public, to the safety of the public. That's not the way you do 6 an environmental impact statement. So, this reliance on the 152-e-NE 7 cost to the industry versus the safety to the public makes this 8 report incomplete and inadequate. So, basically, I would 9 request that -- there'll be one more pass at this report? I 10 don't think youre ready to do the final pass. I think you need 11 another step. I think there's got to be another draft because 12 you're far from there. Thank you.

13 14 December 2010 A-1185 NUREG-1437, Supplement 38

Appendix A 1 MR. SHAW: My name is Gary Shaw. I live about 5 1/2 2 miles from the plant. I've lived in this area for 16 years. My 3 understanding of the charge of the NRC Relicensing Board is too 4 ensure that the operators of these nuclear plants have a 5 sufficient set of safety and maintenance systems in place to 6 prevent environmental contamination from radioactive materials 7 for the next 25 years. 20 years beyond the expiration of the 8 current licenses. As we all know, Indian Point is the first 9 nuclear plant in the country known to have leached Strontium-90 153-a-LE 10 into groundwater and one of several known to be leaking Tritium.

11 Just today, a study of lactating mothers showed that the closer 12 to Indian Point the nursing mother resides, the higher the 13 Strontium-90 levels in their milk. On the face of this, these 14 results are consistent with the Radiation and Public Health 15 Projects Tooth Fairy Project, which found Strontium-90 in the 16 baby teeth of children residing in proximity to nuclear plants 17 that showed higher levels when residing in closer proximity. I 18 would hope that these findings factor into NRC deliberations.

19 The issue here is whether the primary responsibility 20 of the NRC is to safeguard the public health to the best of its 21 ability or if their job is to try and figure out how much public 153-b-LE 22 contamination is allowable, so a for-profit publicly traded 23 multibillion-dollar company can maximize profits. I will remind 24 this panel that the NRC's office of Inspector General has NUREG-1437, Supplement 38 A-1186 December 2010

Appendix A 1 previously criticized the agency for giving undue consideration 2 to operator profits that resulted in the near breach of 3 containment at the Davis Bessie Plant in Ohio in 2002. From 4 newspaper reports, we know that the severe corrosion of the 5 Davis Bessie reactor head was discovered when a worker leaned on 6 a control rod and it was lose. The corrosion was not discovered 7 by design, just by luck. We also know that the entire issue of 153-b-LE contd.

8 radioactive leaks at Indian Point came to light not because of 9 any effort of the NRC inspectors or plant management oversight.

10 The leaks were discovered during excavation in preparation for 11 moving the overflowing nuclear waste from the spent-fuel pools 12 so they could be placed in casks and stacked like nuclear 13 bowling pins on a concrete slab near the banks of the Hudson 14 River. The NRC has seemed very willing to waive regulations 15 when the operators have asked for it. A noteworthy recent 16 example is the waiver of the one-hour fire protection 17 requirements for HEMC insulation. Lowering the requirement to 153-c-OM 18 24 minutes. To me, there is a real credibility issue about your 19 responsibilities and your standards. Toward that end, I would 20 like to bring up an issue I have raised at a range of NRC 21 meetings.

22 Indian Point has extensive underground piping that is 23 more than three decades old. With the pipes sheathing tables 153-d-AM/

LE/OM 24 circulating billions of gallons of Hudson River salt water December 2010 A-1187 NUREG-1437, Supplement 38

Appendix A 1 daily. We have had a tritiated steam leak from pipes that were 2 supposed to be carry only non-radioactive water. I have asked 3 the NRC multiple times to make public how the operators will 4 judge the viability of buried piping now and for the life of the 5 new license being considered. The important issue is to prevent 6 leaks, not to find ways to fix leaks once they have happened.

7 For credibility sake, this panel should make public the specific 153-d-AM/

LE/OM 8 metrics being used to evaluate the effectiveness of monitoring.

contd.

9 Specifically, I would like to know the number of linear feet 10 there are of buried pipes with no aboveground visual access. I 11 would like to know by what methods and what percentage of 12 underground piping would be accessible and inspected on an 13 ongoing basis. I would also like to know to what degree welds 14 will be tested for integrity. If your standards are valid, they 15 should be offered for public and peer review. I will finish by 16 reminding the panel that Indian Point could not get siting 17 approval today because of population density around the plant.

18 What you are considering is a new license, not a an extension.

19 I will also remind everyone that in 1979, Robert Ryan, the 153-e-AM/

DE 20 former NRC director of the Office of State Programs labeled 21 Indian Point one of the most inappropriate locations in 22 existence for a nuclear plant. 30 years of population growth 23 and aging infrastructure has not made this location any more 24 suitable.

NUREG-1437, Supplement 38 A-1188 December 2010

Appendix A 1

2 3

4 MS. SHEPARD: I'm with Westchester Citizens Awareness 5 Network. I've been involved in some of the health studies that 6 have been conducted in our area to measure radionuclides in baby 7 teeth and also in milk. There are studies going on all over the 8 world that show a correlation between occurrences of various 9 cancers and proximity to nuclear plants. The human health 10 studies that have been conducted in our area have been scorned 11 and marginalize and deemed invalid by the NRC and Entergy 12 because the samples are small. Because that's what happens when 13 there's not enough money to collect larger samples because when 14 grassroots organizations do testing. They don't have the money 15 to collect samples on a widespread basis the way the government 154-a-HH/

LE/MP 16 does. The way the government has in the past. The way the 17 government collected baby teeth in the 60s and the early 70s.

18 However, you heard today that mothers milk and goats milk has 19 been tested and with a very small sample, preliminary results 20 are showing the presence of Strontium-90 in many of the samples.

21 The really significant thing is, two of the samples contained 22 detectable levels of Strontium-89, which means since Strontium-23 89 has a short half-life that this is not attributable to 24 background radiation from aboveground testing from the 60s.

25 It's not attributable to anything left over from Chernobyl.

December 2010 A-1189 NUREG-1437, Supplement 38

Appendix A 1 It's recent and it cannot be discounted.

2 I obviously do not share the love of nuclear power 3 that the NRC and Entergy feel. The NRC and Entergy have an 4 unconditional love for nuclear power. I don't have that. But 5 if they do not agree with the laboratory measurements that have 6 been taken by our grassroots studies that show the presence of 7 man-made nuclides, radionuclides in the teeth and milk of area 8 residents. And I'm talking about the wives and mothers of the 9 children of the man who spoke tonight. The wives and the 10 mothers of the children of the men who spoke tonight, who talked 11 about their wives, their healthy children, living right here 12 within this proximity probably had or currently have or will 154-a-HH/

13 have man-made radionuclieds in their breast no. It's not nice LE/MP contd.

14 to think about, but it's something we need to know about. If 15 the NRC and Entergy don't like the results of the studies and 16 have poured a lot of money into their PR machine to generate 17 literature that refutes the studies that have been done by our 18 hungry for money volunteer people, who are doing these studies, 19 then please throw some money towards some studies and let's make 20 it mandatory that human milk testing is part of any kind of 21 environmental impact statement having to do with a nuclear 22 plant. This is something that the government used to do support 23 in the past and needs to be supported now. So, this is not 24 going to go away. Any kind of man-made radionuclides that are NUREG-1437, Supplement 38 A-1190 December 2010

Appendix A 1 in teeth and milk are going to stay there until those regular 2 and routine emissions are no longer going into the air in our 3 area. Please, every single person here in this room whos 4 concerned about air quality and asthma and your children's 5 health, when you go home, look around your house and see how 154-b-AL 6 much energy youre wasting. Unplug your phantom electricity.

7 Pull out your transformers. Look and see what is using up 8 energy in your house that doesn't need to be. Turn off your 9 computers at night and be aware and be mindful because it's 10 everybody's responsibility to conserve energy. Thank you.

11 12 December 2010 A-1191 NUREG-1437, Supplement 38

Appendix A 1

2 MS. SHERMAN: Good afternoon. My name is Andrea Sherman 3 and I'm a resident of the city of White Plains, Westchester 4 County, New York. Since moving to the county in 2001, I have 5 kept a watchful eye on news stories of the Indian Point nuclear 6 power plant and I'm here today to lend my comments as a citizen 7 to the discussion of its re-licensing. To be brief, the issue 8 at hand seems to be one of risks, benefits and alternatives.

9 Undeniably, Indian Point brings benefits of the region. It 155-a-EC/

10 provides a source of energy to fuel our consumption, which is a SO 11 precious commodity, as we know. It also brings economic 12 benefits to its parent company Entergy. To the employees who 13 depend on it for their livelihood and to the surrounding local 14 towns and other communities who enjoy lower taxes and other 15 economic benefits from having the plant in their midst. These 16 benefits are all positive and no one is disputing that.

17 However, when one looks at the risk column, suddenly 18 these economic benefits begin to pale in comparison to the 19 overwhelming risks to health and safety imposed on an entire 20 region of millions by the close proximity of such a potentially 155-b-PA 21 toxic entity as the Indian Point nuclear plant. Whether through 22 unfortunate technical accident, all too common human error, 23 unforeseeable natural disaster, terrifying attack or the 24 aftermath of the parent company's decision someday to divest NUREG-1437, Supplement 38 A-1192 December 2010

Appendix A 1 itself of this asset, the devastation to both life and habitat 155-b-PA 2 in our region would be catastrophic and largely irreversible, contd.

3 certainly for this generation and possibly for generations to 4 come.

5 Since the long-term risks to health and safety 6 outweigh the shorter-term and mutable economic considerations, I 7 urge, no, I plead with Entergy and our government officials to 155-c-AL/

8 seek similar economic benefits by means of reasonable SA 9 alternatives to the operation of a hazardous nuclear power plant 10 in New York. Speaking as a citizen, my vote will follow those 11 who recognize and act on this imperative. To address the 12 concerns raised by so many of today's speakers, there are other 13 ways to keep energy affordable and to improve air quality 14 without exposing our region to the dangers of nuclear 15 production. It would be morally bankrupt for our government to 155-d-OR 16 permit primarily economic interests to co-opt those of public 17 health, safety and environmental integrity. Safer alternatives 18 can be sought if there is the public and political will to do 19 so. Thank you for allowing me to speak today.

20 21 December 2010 A-1193 NUREG-1437, Supplement 38

Appendix A 1

2 MR. SKANES: Good afternoon. I'm not going to sing to 3 you although I did notice the grannies got about seven or eight 4 minutes. I guess that's the trick, if you sing, you get a 5 longer time. I'm Brian Skanes and like John Yanofsky, I wear a 6 number of hats. Number one, I'm a 10 year resident of Mount 7 Kisco. I'm the executive director to the Boys and Girls Club of 8 Northern Westchester. I'm also a member of the local Rotary 9 Club, the Business Council, the Westchester Community 10 Association, member of the President's Council of Northern 11 Westchester Hospital Center, but more importantly, I'm a really 12 concerned citizen.

13 I have to say, I'm very encouraged about what I've 14 heard today on the positive side. I think it's been mentioned 15 many times and all the reasons why I too believe that we have 16 re-license Indian Point. Especially because of, in my role as 17 executive director of the Boys and Girls Club's, 3500 kids who 18 come from better than the best circumstances, they really need 156-a-SE/

SR 19 the corporate partner that Entergy really offers our 20 organization. It's been mentioned before, not only the Boys 21 and Girls Club, but non-profit after non-profit after non-22 profit benefit from the employees who help us on our boards and 23 come to our events. The financial support we get, and by the 24 way, in 35 years of working in Boys and Girls Club's and NUREG-1437, Supplement 38 A-1194 December 2010

Appendix A 1 working with all kinds of corporations, I can say without 2 hesitation, that Entergy is the best corporation working with 3 non-profits that I have ever seen. The non-profit summit they 4 run every year. The opportunity to go to Yankee Stadium and be 156-a-SE/

5 part of some marketing and public relations training and also SR contd.

6 the opportunity to receive some pro bono advertising. All 7 these things add into a lot of good things for kids in this 8 community and that's why I stand for and support re-licensing 9 Indian Point. Again. Thank you.

10 11 December 2010 A-1195 NUREG-1437, Supplement 38

Appendix A 1

2 MR. SLEVIN: Good afternoon. My name is Jimmy Slevin.

3 I'm a senior business agent for the Utility Workers Local 1-2.

4 Thank you for letting me appear before you today. Local 1-2 of 5 the UWA, which the union represents most of the workers at 6 Indian Point, is therefore on the frontline of the debate before 7 you today.

8 We are in the best position to contribute the 9 information on the subject of most relevance to the commission.

10 Indian Point is safe. If we had any reason to believe not, we 11 would not let our members work there. Our members cannot only 157-a-OP 12 attest to the fact that the commitment to safety operations, but 13 are an intricate part of the team that makes the facility safe.

14 The unparalleled record of plant safety is something we are 15 proud of.

16 As residents of this area and as involved citizens, we 17 are very much concerned with the physical and economic health of 18 the community. Indian Point produces 2000 Mw of electricity, 19 and that represents about 20 to 40% of the needs of this region.

20 Cutting off this substantial and vital supply of power would be 157-b-AL/

EC/SO 21 a body-blow to the economic health and personal well-being of 22 every citizen. This amount of energy could not be replaced.

23 New construction of fossil power is not feasible in the views of 24 the prevailing environmental concerns and other time-consuming NUREG-1437, Supplement 38 A-1196 December 2010

Appendix A 1 obstacles in their construction. Green energy sources have not 2 reached the levels of viability that allows us to rely on them 157-b-AL/

EC/SO contd.

3 in immediate or foreseeable future. Nuclear power is here and 4 it is environmentally clean. Unlike fossil power, it does not 5 contribute to the greenhouse effects or global warming. It does 6 not release harmful carbon emissions into the atmosphere as 7 fossil plants do. What it does is provide us with an 157-c-AL/

8 inexpensive and safe electrical power. We were told in the EC 9 recent past that with one of these onsets of deregulation and 10 the unleashing of market forces in the power generation 11 industry, there would be a glut of low-cost energy capacity for 12 all classes of consumers. Deregulation has passed, but the 13 promise results never followed.

14 How could anyone with the best interest of the 15 community in mind, now demand the elimination of 2000 Mw of 16 vital need power without the remote practical expectation that 17 it will be replaced in our lifetime. Even if it could be, the 18 cost would be unimaginable. We refuse to play either the blame 19 game or engage in scare tactics, but let's be realistic, Indian 157-d-EC/

SR 20 Point has been a mass of this community and region. Those who 21 would not merely tamper with its function should think long and 22 hard about what it would do to them because it would be 23 extremely unwisely counterproductive and blatant destruction to 24 deny the re-licensing of Indian Point. I thank you again for December 2010 A-1197 NUREG-1437, Supplement 38

Appendix A 1 the opportunity to share my views. Indian Point is a good 157-d-EC/

2 neighbor. Indian Point is good for the environment and Indian SR contd.

3 Point deserves to be re-licensed.

4 NUREG-1437, Supplement 38 A-1198 December 2010

Appendix A 1

2 157-e-OP 157-f-AL/EC/SO December 2010 A-1199 NUREG-1437, Supplement 38

Appendix A 157-f-AL/EC/SO contd.

1 2

3 4

5 6

7 8

9 10 11 12 NUREG-1437, Supplement 38 A-1200 December 2010

Appendix A 1 DR. SMITH: Good afternoon. My name is Dr. Gregory 2 Robeson Smith and I am the senior pastor of the Mother AME Mount 3 Zion Church in Harlem. New York State's oldest church.

4 Organized in 1796, we will celebrate our 213th year. Mother 5 Zion, also known as the freedom church throughout its long 6 history. Mother Zion has many of its illustrious members who 7 were leaders in our historic fight for freedom. They included 8 Harriet Tubman, Frederick Douglass, Sternon Tooth [sp], Paul 9 Robeson, Madame C.J. Walker and many others who fought so 10 valiantly to free African-Americans socially, politically and 11 spiritually.

12 Today, Mother Zion is the Mother Church of the AME 13 Zion denomination, which is located on five continents and has a 14 membership of 1.5 million members. Public forums like this have 15 historically granted citizens a unique opportunity to have their 16 concerns heard by decision-makers and power brokers. From 17 ancient Rome to Birmingham, Alabama, the people who rise to 18 address these forums have helped shape public opinion and 19 policy. One such policy I would like to speak to this afternoon 20 is the re-licensing of Indian Point Energy Center and how it 21 continues operation in the best interests of the children and 158-a-EJ/

SR 22 the families of Harlem, who make up my congregation.

23 Regrettably, the debate over re-licensing has taken place 24 without input from communities like Harlem which are under siege December 2010 A-1201 NUREG-1437, Supplement 38

Appendix A 1 by the dirty air, not to mention the health aspects that come 2 along with poor air quality. The debate over re-licensing has 3 raged on without input from those who can ill afford to pay 4 electricity bills. This debate over re-licensing has taken 5 place without the reassurance that the dirty air power plants 158-a-EJ/

6 built to replace Indian Point will not once again end up in our SR contd.

7 neighborhoods. It's only through conversations in communities 8 most benefited by Indian Point like Harlem, Bronx, and Brooklyn, 9 we can begin to fully appreciate the need for clean and reliable 10 energy Indian Point provides.

11 Last year we sponsored such a dialogue with my fellow 12 members of the Harlem clergy. It is through this dialogue that 13 we learned the full scope of the crisis situation facing Harlem 14 families if Indian Point is closed. We learned that the closing 15 of Indian Point comes with additional threats to our air quality 16 and drastic increases in electricity bills. There are too many 17 cases of seniors in our neighborhoods and to many families 158-b-AL/

AQ/EC 18 forced to choose between heating their home and buying groceries 19 just to justify closing Indian Point. An open Indian Point 20 means continued clean emissions-free energy that will help 21 improve air quality. An open Indian Point means continued 22 affordable energy that helps keep electricity bills stable. An 23 open Indian Point means continued reliable energy which would 24 provide for our homes, schools, mass transit, hospitals and NUREG-1437, Supplement 38 A-1202 December 2010

Appendix A 1 religious 2

3 4 institutions. I am not only here to support Indian 5 Point Energy Center, but I'm also here today in the spirit of 6 corporation and unity. Thank you for allowing the to add my 158-b-AL/

7 concerns and that of my congregation to this debate and were AQ/EC contd.

8 hopeful that any decision reached will be one that ensures 9 continued supply of reliable, clean and affordable electricity 10 for all New Yorkers.

11 12 December 2010 A-1203 NUREG-1437, Supplement 38

Appendix A 1

2 MS. SMITH: Good afternoon. I'm Carol Smith and I'm 3 vice-president for the Orange County Chamber of Commerce. Our 4 chamber represents more than 2000 businesses in Orange County 5 and the surrounding areas. It is an indisputable fact that 6 Indian Point generates more than 2000 Mw of electricity, 7 which has been said is enough to provide between 18 and 38%

8 of the lower Hudson Valley's and New York City's electricity 159-a-EC/

GL 9 needs on any given day. More important though, is that this 10 is clean and affordable power whose generation produces none 11 of the greenhouse gases or other pollutants that contaminate 12 our environment and contribute to global warming.

13 Of course, alternative sources of energy such as 14 wind and solar power should be actively pursued, but in the 15 meantime, it would be economically and environmentally 16 irresponsible to close Indian Point. The Orange County 17 Chamber of Commerce believes that Entergy should be granted 18 the renewal of its license to operate Indian Point. Assuming 159-b-AL/

SA/SR 19 that safety of our residents and security of this facility 20 are always its paramount concerns. Since purchasing Indian 21 Point in 2001, Entergy has invested hundreds of millions of 22 dollars in enhanced security and safety features for the 23 facility. We are sure they will continue to do so.

24 25 NUREG-1437, Supplement 38 A-1204 December 2010

Appendix A 1 The Indian Point Energy Center is vitally important 2 to the economic and environmental health of the entire 3 region. Electricity demands are rapidly increasing and no 159-c-EC/

SR 4 new power plants are being built or even planned. These are 5 two additional reasons why the re-licensing of Indian Point 6 is so important. To answer those who call for Indian Point 7 to be shutdown, a recent national Academy of Science study 8 said that although a shutdown would be technically feasible, 159-d-EC 9 it would lead to significantly higher electricity bills and 10 would worsen the volatile price swings within the natural gas 11 market. For an environmental point of view, loss of Indian 12 Points 2000 Mw of energy would result in higher levels of 13 environmentally harmful greenhouse gas emissions because of 14 the bulk of the replacement power would require burning the 15 dirtier fossil fuels. We know the Nuclear Regulatory 16 Commission will be carefully evaluating Entergy's request for 159-e-AL/

17 the license renewal of Indian Point and this process will AQ/SR 18 include a comprehensive review and evaluation of the 19 facility. We support this license renewal and we know that 20 Entergy will continue to operate Indian Point with impeccable 21 high standards of quality and excellence. Thank you for the 22 opportunity to speak.

23 24 December 2010 A-1205 NUREG-1437, Supplement 38

Appendix A 1

2 3

4 160-a-AL/OR/SA NUREG-1437, Supplement 38 A-1206 December 2010

Appendix A 1 MS. STARKE: Good evening and thank you to the NRC. My name is 2 Alexis Starke and I am a resident of the Hudson Valley. I am 3 here tonight to represent myself. There is no conflict of 4 interest in my being here tonight. I understand that people 161-a-GI 5 have spoken out in favor of Entergy tonight because they are 6 scared for their jobs. I understand and I respect that. But we 7 have a moral obligation here tonight to look at the bigger 8 picture. I grew up in New York state and I care deeply about 9 our environment and our majestic river, the Hudson.

10 I am here tonight to ask the NRC not to re-license 11 Indian Point and to begin the process of closing it. Indian 12 Point has carelessly and incompetently damaged our environment 13 and our river for long enough. There is nothing clean or green 14 about Entergy or about Indian Point. I am outraged about the 15 continual leak of radioactive water from Indian Point into our 161-b-GI/

16 groundwater, i.e. our drinking water. And into the Hudson LE/WA 17 River, which is also our drinking water. United Water New York 18 Suez is planning on building a Hudson River water desalination 19 filtration plant directly across the river from Indian Point. I 20 am outraged about residual contamination caused by plumes of 21 contaminated groundwater that slowly leach toxic Strontium-90 22 and Cesium-137 into the river. I am greatly concerned about 23 the inefficient and shamefully shoddy storage of thousands of 161-c-RW/

ST 24 tons of highly toxic nuclear waste on the banks of the Hudson December 2010 A-1207 NUREG-1437, Supplement 38

Appendix A 1 River. This is unacceptable. Indian Points dry casks are 2 vulnerable to terrorist attacks. Again, this is unacceptable.

3 Indian Point is and always has been an environmental disaster 4 for the Hudson Valley. It is a constant source of fear of 5 unspeakable destruction should it be the target of terrorist 6 attacks. Our tax dollars should not be spent in providing 161-c-RW/

ST 7 military protection for Indian Point, so that Entergy can contd.

8 continue to make huge profits. This is ridiculous. NRC, I 9 trust you will close down Indian Point. It has been a source of 10 fear and shame for our region for long enough. The law has been 11 flagrantly violated by Entergy for long enough. It is time for 12 us to start conserving energy.

13 14 NUREG-1437, Supplement 38 A-1208 December 2010

Appendix A 1

2 161-d-GI/OR 161-e-AE 161-f-LE/WA 161-g-ST/UF 161-h-DE/ST 161-i-AL/OR December 2010 A-1209 NUREG-1437, Supplement 38

Appendix A 1

2 NUREG-1437, Supplement 38 A-1210 December 2010

Appendix A 1

2 MR. SULLIVAN: Hi, I'm John Sullivan. I live probably 3 about 2 miles from the plant. I have been here before. I've 4 been on the list serve for IPSEC, but I'm really here for my 5 own self. I just want to add my voice to the fact that I 162-a-OR/

6 believe that the license should not be extended. I think the RW 7 most egregious error of the report is that it does not look 8 into the future. The reality is we are going to have nuclear 9 waste on this site for the next hundred years and unless that 10 is addressed in the report, its incomplete.

11 I'd also like to extend the challenge to the folks 12 that do get money from IPSEC, that are supported, that feel 13 that -- I'm sorry, not IPSEC, from Entergy, that feel that 14 Entergy is a good corporate citizen. People in the 15 environmental movement, IPSEC, Riverkeeper, have proposed many 16 things that would make the plants safer. God forbid from my 162-b-AL/

SF/ST 17 point of view, if in fact the plant is re-licensed, these 18 things should be put into place. A closed-water cooling tower.

19 Hardened onsite storage of nuclear waste and with deterrents 20 for terrorist attacks. Please speak to your corporate sponsor 21 and urge them to do the right thing and not just buy good 22 publicity. Thank you.

23 24 December 2010 A-1211 NUREG-1437, Supplement 38

Appendix A 1

2 3

4 162-c-OR 162-d-GW/

LE/PA 162-e-AM/RW 162-f-OR NUREG-1437, Supplement 38 A-1212 December 2010

Appendix A 1

2 3

163-a-SE/SO/SR December 2010 A-1213 NUREG-1437, Supplement 38

Appendix A 1

2 163-a-SE/SO/SR contd.

NUREG-1437, Supplement 38 A-1214 December 2010

Appendix A 1

2 3

4 5

6 7

8 9

10 163-a-SE/SO/SR contd.

11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 December 2010 A-1215 NUREG-1437, Supplement 38

Appendix A 1

2 MS. TAORMINO: Good evening. My name is Michelle 3 Taormino and I'm part of an environmental assessment class at 4 Ramapo College in Mahwah, New Jersey. I'm also a citizen within 5 a 30 mile radius of Indian Point and I would be affected by any 6 major incident that would occur at the power plant. Which when 7 reading the EIS, I found that the EIS does not include certain 164-a-PA/

ST 8 information. These points I'm going to go over. There's no 9 protocol if there's a meltdown. There's no, how they would deal 10 with a fire if a fire breaks out. There's no security included 11 about the plant, if there's a terrorist attack or if there's a 12 natural disaster, the fault line near the plant is not addressed 13 either.

14 After reading the EIS, I was startled at how little 15 information was given and what little weight the evacuation plan 16 at Indian Point carried. Regardless of new updates, the sirens 17 give no regard to the hearing-impaired or to those in the area 18 who don't know what the sirens are, what they mean or know about 164-b-EP 19 the plan. The plan is also loosely put together with inadequate 20 evacuation roads to handle the evacuating population. Also, 21 certain people can opt out of the evacuation plan like EMTs and 22 police and there's no substitution for those that will help in 23 the evacuation plan. In addition, the EIS mentioned that the 164-c-LE/

24 leaks occurring at the plant have minimal impact on the soil in TE NUREG-1437, Supplement 38 A-1216 December 2010

Appendix A 1 the area. However, studies on turtles who live in that soil 2 were found to have Strontium-90. This suggests that more 164-c-LE/

TE 3 thorough studies about the soil contamination need to be contd.

4 conducted. Also, certain aspects of Indian Point have been not 5 inspected and these areas like plumbing underground have not 6 been included in the EIS regardless of why or why not, it has 7 not been inspected. It has not been listed in the EIS. Issues 164-d-LR/

OM 8 like the evacuation plan are not considered in the renewal 9 license process nor is the leakage that occurs. Certain studies 10 prove that more analysis needs to be done before any decisions 11 can be made.

12 An EIS was developed to accurately review the plant 13 and determine whether or not re-licensing should be granted.

14 The lack of the information given in the EIS, as well as the NRC 15 allowing the re-licensing without holding the Indian Point power 16 plant to fix its faults prior to re-licensing and not including 17 that theyre doing this in the EIS, makes the EIS, in turn, 18 inadequate. Making a decision to re-license Indian Point should 164-e-EP 19 not be considered unless studies are thorough and are followed 20 through with and a solid evacuation plan and incident plan is 21 determined. You can't make a decision about the next 20 years 22 without seriously looking at all the information and accurate 23 information now in the present. It's not a time to overlook or 24 look away from any present issues. You need to make a concise, December 2010 A-1217 NUREG-1437, Supplement 38

Appendix A 1 clear and confident decision. More information needs to be 164-e-EP contd.

2 looked at and considered. Thank you.

3 4

NUREG-1437, Supplement 38 A-1218 December 2010

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2 3

4 164-f-EJ/EP 164-g-LE/MP December 2010 A-1219 NUREG-1437, Supplement 38

Appendix A 1

2 164-g-LE/MP contd.

164-h-UF 164-i-GL NUREG-1437, Supplement 38 A-1220 December 2010

Appendix A 1

2 165-a-OR/PA December 2010 A-1221 NUREG-1437, Supplement 38

Appendix A 1

2 3

166-a-LR/SR 166-b-AL/EC/SO 166-c-AL/HH 166-d-SO/SR NUREG-1437, Supplement 38 A-1222 December 2010

Appendix A 166-e-SO/SR 166-f-AL/EC 1

2 December 2010 A-1223 NUREG-1437, Supplement 38

Appendix A 166-f-AL/EC contd.

166-g-AE/SO 1

2 3

4 5

6 7

8 9

10 11 12 NUREG-1437, Supplement 38 A-1224 December 2010

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2 167-b-OR/

RW/SF 167-a-AE December 2010 A-1225 NUREG-1437, Supplement 38

Appendix A 1

2 3

4 5

6 7

8 9

10 11 12 The following pages contain the written comments 13 submitted by Various Authors during the scoping period 14 for the Indian Point Nuclear Generating Unit 15 Numbers 2 and 3 license renewal 16 17 18 19 Comment ID 20 168-a-OS 21 NUREG-1437, Supplement 38 A-1226 December 2010

Appendix A 1

December 2010 A-1227 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1228 December 2010

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December 2010 A-1229 NUREG-1437, Supplement 38

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December 2010 A-1231 NUREG-1437, Supplement 38

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December 2010 A-1233 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1234 December 2010

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December 2010 A-1235 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1236 December 2010

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December 2010 A-1237 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1238 December 2010

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December 2010 A-1239 NUREG-1437, Supplement 38

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December 2010 A-1241 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1242 December 2010

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December 2010 A-1243 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1244 December 2010

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December 2010 A-1245 NUREG-1437, Supplement 38

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2 3

NUREG-1437, Supplement 38 A-1246 December 2010

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December 2010 A-1247 NUREG-1437, Supplement 38

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December 2010 A-1249 NUREG-1437, Supplement 38

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December 2010 A-1251 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1252 December 2010

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December 2010 A-1253 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1254 December 2010

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December 2010 A-1255 NUREG-1437, Supplement 38

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December 2010 A-1257 NUREG-1437, Supplement 38

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December 2010 A-1259 NUREG-1437, Supplement 38

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December 2010 A-1261 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1262 December 2010

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2 December 2010 A-1263 NUREG-1437, Supplement 38

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December 2010 A-1265 NUREG-1437, Supplement 38

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December 2010 A-1267 NUREG-1437, Supplement 38

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December 2010 A-1269 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1270 December 2010

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December 2010 A-1271 NUREG-1437, Supplement 38

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2 NUREG-1437, Supplement 38 A-1272 December 2010

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December 2010 A-1273 NUREG-1437, Supplement 38

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December 2010 A-1275 NUREG-1437, Supplement 38

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December 2010 A-1277 NUREG-1437, Supplement 38

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December 2010 A-1279 NUREG-1437, Supplement 38

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December 2010 A-1281 NUREG-1437, Supplement 38

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December 2010 A-1283 NUREG-1437, Supplement 38

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December 2010 A-1285 NUREG-1437, Supplement 38

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December 2010 A-1287 NUREG-1437, Supplement 38

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NUREG-1437, Supplement 38 A-1288 December 2010

Appendix A 1

2 MR. VITALE: Good afternoon, my name is Paul Vitale.

3 I'm vice president of the government relations for the Business 4 Council of Westchester. Business Council of Westchester is 5 Westchesters largest business organization, representing over 6 1200 members ranging in size from large multinational 7 corporations and mid-size businesses to professional firms not 8 for profit organizations and small-business owners in every 9 sector of the county's diverse economy. The economic 10 situation in Westchester is increasingly distressing. As 11 such, the closure of Indian Point, which is the backbone of 12 Westchester County and the lower Hudson Valley's electricity 13 network, would be economically devastating. It should be 14 emphasized that Indian Point provides more than 75% of the 169-a-AL/

15 electricity consumed within the lower Hudson Valley. Indian EC/SO 16 Point contributes over $50 million paid in local taxes, 17 including sales taxes, payroll taxes, property taxes and 18 state and local income taxes. Losing Indian Point could 19 potentially cause major power disruptions, the loss of up to 20 11,000 jobs and $2.1 billion in cumulative lost wages, while 21 Westchester's unemployment rate continues to increase.

22 The closure of Indian Point could result in the 23 doubling of the electricity rates of the second highest rates 169-b-AL/

AQ/EC 24 that New York homeowners and businesses currently pay. Many 25 December 2010 A-1289 NUREG-1437, Supplement 38

Appendix A 1 businesses in Westchester County already having trouble 2 managing their increasing costs, including the cost of 3 reliable electricity. The alternatives laid out to 4 replace Indian Point do not make sense economically or 5 environmentally for this region. Replacing Indian Point 6 with any fossil fuel equivalent would greatly increase the 169-b-AL/

AQ/EC contd.

7 carbon emissions of the region at a time when we can ill 8 afford to do so. Indian Point has been very important to 9 this region and our communities. The renewal of the 10 operating license for Indian Point is crucial more than 11 ever before. Thank you for the chance to address this 12 audience.

13 14 NUREG-1437, Supplement 38 A-1290 December 2010

Appendix A 1

2 170-a-OR 170-b-HH 170-c-PA/SM 170-d-SM December 2010 A-1291 NUREG-1437, Supplement 38

Appendix A 1

2 170-d-PA/SM contd.

NUREG-1437, Supplement 38 A-1292 December 2010

Appendix A 1

2 170-d-PA/SM contd.

170-e-LE/WA 170-f-HH/PA/

UF 170-g-AL 170-h-HH/OR December 2010 A-1293 NUREG-1437, Supplement 38

Appendix A 1

170-h-HH/OR contd.

2 NUREG-1437, Supplement 38 A-1294 December 2010

Appendix A 1 MS. WALTZER: Hi. In considering whether Indian Point 2 should remain open or not, I'd like us to look to the past 3 and to the future. From sitting here tonight, I realize 4 how very important job issue is to so many people. And 5 it's a valid issue. But I want to remind you that when we 171-a-SO 6 had sailboats and we went into steam boats, those sailors 7 didnt lose their jobs. When we had horses and went to 8 cars, people still kept their jobs. They might have 9 changed to something more for the future. But we still 10 keep our jobs. They just change. The other thing I would 11 like to remind you is that this is a human issue. These 12 are human beings that are running Indian Point as any 13 nuclear power plant. I'd like you to think of any realm of 14 human endeavor. Whether its business, government, 15 financial institutions, religious organizations, sports, 16 politics, the arts, the space program, even in families. 171-b-PA/

ST 17 Were human beings. And we are subject to making mistakes.

18 To corruption. To sabotage. To blackmail. Were 19 vulnerable to terrorism. We make errors and so on. So I'd 20 like to ask you, what makes you think that this aging, 21 leaking power plant would be immune to all of these human 22 frailties? Thank you.

23 December 2010 A-1295 NUREG-1437, Supplement 38

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2 3

172-a-HH/RI 172-b-DE/EP 172-c-ST 172-d-LR NUREG-1437, Supplement 38 A-1296 December 2010

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2 3

4 173-a-AE/EP/

ST 173-b-AL/OR December 2010 A-1297 NUREG-1437, Supplement 38

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2 174-a-HH/RI 174-b-RI 174-c-HH 174-d-PA 174-e-NE/PA 174-f-GI/OM 174-g-AM 174-h-SA 174-i-AL 174-j-OR NUREG-1437, Supplement 38 A-1298 December 2010

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2 175-a-OP/OR/

PA December 2010 A-1299 NUREG-1437, Supplement 38

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2 3

176-a-OR 176-b-AE 176-c-AE 176-d-LE 176-e-RW/

SF/ST 176-f-OR NUREG-1437, Supplement 38 A-1300 December 2010

Appendix A 1 MR. WILSON: Thank you. Good evening. My name is Craig Wilson.

2 I am the Executive Director of SHARE. SHARE is a non-profit 3 coalition of organizations that are committed to ensuring the 4 continued supply of reliable clean and affordable electricity 5 for all New Yorkers. Were especially pleased today that we 6 have members of SHARE that made the trip from various parts of 7 the city: Brooklyn, many of our folks are from. May you all 8 have a round. And some great signs too that you can show. For 9 too long high electricity prices have placed an undue economic 177-a-AQ/

10 burden on New York's families and businesses. While poor air EC/SO 11 quality has led to high asthma rates which place our most 12 vulnerable at risk. Right now, as we all are too well aware, we 13 are in the midst of a most severe economic crisis since the 14 Great Depression. Community residents, small businesses and 15 working men and women from communities across the region are 16 struggling. And yet there is a light at the end of the tunnel 17 that we can see right now. Recognizing the turmoil within our 18 economy, now is not the time to shut our source of clean, safe 19 and affordable power for the region.

20 As much as 40% of our power, used for everything from 21 our schools, hospitals and businesses comes from the Indian 177-b-EC 22 .Energy Center. If it were to be closed, it is estimated that 23 electricity costs for small, excuse me, electricity costs for 24 small businesses could rise as much as $10,000 annually, while December 2010 A-1301 NUREG-1437, Supplement 38

Appendix A 1 individual residences would pay an additional $1500 a year. Our 177-b-EC 2 members simply are not able to pay these dramatically higher contd.

3 electricity bills particularly in these economic times. Beyond 4 the financial benefits, the Indian Point Energy Center greatly 5 reduces the amount of pollution emitted into our air. Unlike 6 all other power plants within the region, Indian Point does not 7 release asthma causing pollutants or greenhouse gases into the 177-c-AQ 8 atmosphere. This is of great benefit to our air quality as 9 nearly all the counties served by Indian Point consistently have 10 their air-quality rated an `F` by the American Lung Association.

11 Clearly, we need more clean energy facilities like Indian Point, 12 not fewer. Moreover, many of the members of our members live in 13 low-income communities where asthma rates are four times the 14 national average. And one in four children suffer from this 15 serious life altering disease. Nearly one third of New York 16 City children with asthma reside in the Bronx with neighborhoods 17 like Hunts Point and Mont Haven having among the highest asthma 18 rates in the country. For these reasons, SHARE and its member 177-d-AQ/

EJ/SR 19 organizations, firmly support the continued operation of the 20 clean, safe and secure Indian Point Energy Center.

21 Additionally, we are committed to working with local 22 stakeholders in the New York metropolitan area to provide to 23 provide all New Yorkers with the clean and affordable power they 24 deserve. Thank you.

NUREG-1437, Supplement 38 A-1302 December 2010

Appendix A 177-a-AQ/EC/

SO 177-b-EC 177-c-AQ 177-d-AQ/EJ/

SR 1

December 2010 A-1303 NUREG-1437, Supplement 38

Appendix A 1

2 178-a-LE/OR/

RW NUREG-1437, Supplement 38 A-1304 December 2010

Appendix A 1

2 MR. WOLF: Good afternoon. While I am certainly 3 sympathetic to the comments that have been made about the 4 environment, I believe this meeting is about the environment 5 and specifically the environmental statement. Rather than 6 going through the thousand of pages of material, I'd like to 7 get back to basics. Because sometimes were so inundated by 8 the information that is contained in these documents that we 9 lose sight of what we really need to consider and what the 10 NRC needs to consider. The NRC's 2008 citizens report 11 states that the NRC's vision is quote excellence in 12 regulating the safe and secure use and management of 13 radioactive materials for public good unquote. They also say 14 that their number one strategic goal is safety, as evidenced 179-a-SA/

SF/RW 15 by the first strategic outcome, which is to quote prevent the 16 occurrence of any releases of any radioactive materials that 17 would result in significant radiation exposures unquote 18 and/or quote adverse environmental impacts unquote. Which is 19 on page 8. Their factors, which singley or certainly in 20 combination, create an untenable environmental risk regarding 21 the releases of radioactive material regarding Indian Point.

22 Including but not limited to number one: the type of above 23 ground storage of spent fuel.

24 December 2010 A-1305 NUREG-1437, Supplement 38

Appendix A 1 Again this report on page 7 says, typically the spent fuel 2 from nuclear power plants is stored either in water filled 3 pools at each reactor site or as a storage facility in 4 Illinois unquote. And that quote several nuclear power 5 plants have also begun not using dry-cask to store spent 6 fuel and that the heavy metal in concrete casks rests on 179-a-SA/

SF/RW 7 concrete pads adjacent to the reactor facility. My contd.

8 understanding is that this type of storage is not as safe as 9 underground in water. Now, we know that a lot of this has 10 come because Yucca Mountain cannot accept the nuclear waste 11 that was envisioned when the plant was created. But 12 nonetheless, we have to deal with the reality of what this 13 means in storing these casks above ground.

14 Two: the unusual high number of leaks or shutdowns 15 and other indications of mismanagement of the facility has 16 compromised the safety for the community around it and the 179-b-LE/

OP/SA 17 apparent continuation of its radioactive leaks is indicated 18 that Indian Point is not responsibly dealing with the 19 environmental and safety aspect of this plant.

20 Three: the plant falls on a fault-line creating an 21 earthquake risk, which means that if there is an earthquake 179-c-PA 22 and storage facilities are not adequate that radiation will 23 go throughout the community.

24 NUREG-1437, Supplement 38 A-1306 December 2010

Appendix A 1 Four: again, it's not Indian Points initial 179-d-DE 2 problem because they didn't build the plant, but the fact is 3 that it is perilously close to high population areas.

4 Five: there is the possibility of the continuation 179-e-LE/

5 of radioactive leaks and further contamination into the WA 6 Hudson River.

7 Six: even though we're now in the year 2009, the 8 threats that were created in 2001, still exist and are still 179-f-RW/

SF/ST 9 a problem, especially when youre talking about aboveground 10 storage of spent nuclear waste.

11 And seven: we don't know and I don't think from 12 what I've seen that the report adequately deals with the fact 13 that you're now going to have a plant that's 40 to 60 years 179-g-AM 14 old. And we don't have a very good safety record dealing 15 with the first 40 years, and I think that the NRC needs to 16 look at this as well.

17 We all take risks every day. Even driving here to 18 make this statement involved risk. But we must evaluate the 19 risk/reward ratio and make a determination. The NRC also 20 must make a determination as to the continued safety and 179-h-OR/

SA 21 viability of having Indian Point operate for another 20 22 years. Based on the risks outlined above as well as other 23 risks that have been discussed in these reports, it would December 2010 A-1307 NUREG-1437, Supplement 38

Appendix A 1 seem incumbent upon the Nuclear Regulatory Commission in its 2 primary goal of excellence in regulating safe and secure 179-h-OR/

3 management of radioactive materials for the public good to SA contd.

4 turn down the application for the re-licensing of Indian 5 Point. Thank you.

6 7

NUREG-1437, Supplement 38 A-1308 December 2010

Appendix A 1

2 179-i-OE December 2010 A-1309 NUREG-1437, Supplement 38

Appendix A 1

2 180-a-HH/LE/

RI 180-b-AL 180-c-AE 180-d-AM/GL 180-e-PA 180-f-RW 180-g-NE/PA NUREG-1437, Supplement 38 A-1310 December 2010

Appendix A 1

2 180-h-GI/OM 180-i-AM 180-j-OM December 2010 A-1311 NUREG-1437, Supplement 38

Appendix A 1

2 MR. YANOFSKY: Boy, that's a tough act to follow and 3 I'm in the performing arts. I'm violating the cardinal rule 4 which is never follow a great act. But my name is John Yanofsky 5 and I'm here under three auspices.

6 The first is I'm the executive director of the 7 Paramount Center for the Arts, which is a non-profit 8 organization housed in an historic theater built in 1930 located 9 in downtown Peekskill. I'm also a board member of the 10 Westchester Arts Council, which now goes by the name of Arts 11 Westchester, which is a countywide organization that not only 12 re-grants to non-profits throughout the county, but also does an 13 extensive amount of direct services and programs out of their 14 headquarters in downtown White Plains. And thirdly, I'm a 15 homeowner and resident here in Peekskill.

16 I am here to strongly urge the renewal of the 17 Indian Point license. The parent company of Indian Point, 18 Entergy has been a model corporate citizen to the Paramount, 19 to Arts Westchester, to dozens of arts organizations through 20 out the region as well as non-profits. There are few 181-a-SE/

SR 21 corporations in the county who do more for the non-profit 22 sector than Entergy. Their commitment to the quality-of-life 23 issues that we all face is reflected in their demonstrative 24 commitment to supporting essential programs and services that NUREG-1437, Supplement 38 A-1312 December 2010

Appendix A 1 non-profits like the Paramount provide and serve in the 2 community and to our residents. Specifically with respect to 3 the Paramount, Entergy was there for our organization during 4 a very critical period when we began our revitalization and 5 restoration of our historic theater and they were the lead 6 supporter of our ability to renovate a historic theater, 7 which now draws tens of thousands of people to downtown 8 Peekskill to support local businesses and restaurants and 9 have become, our theater has become a major anchor to the 10 downtown revitalization in Peekskill. We could not have 11 accomplished that without the support of Entergy.

12 I've also had the personal honor and privilege to 13 serve with several Entergy employees in my role as a board 181-a-SE/

SR 14 member of Arts Westchester, as well as on the Board of contd.

15 Trustees at the Paramount Center. In addition to volunteers 16 and colleagues that I've come into contact with, not only 17 through my work at the Paramount, but in other organizations 18 who donate their time and services to the quality-of-life and 19 improving the quality of life in our county. Entergy's 20 support is also instrumental to the vitality of other arts 21 organizations, as I alluded to. And certainly, given our 22 current financial situations becomes even more desperate and 23 dire situation. For some organization's, Entergys support December 2010 A-1313 NUREG-1437, Supplement 38

Appendix A 1 really means and make the difference between staying open and 2 closing its doors. As a business professional, as a 3 resident of this county, someone who lives and works here 4 and has dedicated his professional life to the ongoing 181-a-SE/

5 improvement through culture and artistic expression, I SR contd.

6 strongly urge the NRC to re-license Indian Point for another 7 20 years and to keep Entergy a vital force in our communities 8 and in the lives of our county. Thank you.

9 10 NUREG-1437, Supplement 38 A-1314 December 2010

Appendix A 1

2 182-a-LE/OR 182-b-AE/HH/

RW/SF 182-c-EP/ST 182-d-AL/EJ/

OR December 2010 A-1315 NUREG-1437, Supplement 38

Appendix A 1

2 3

4 5

6 7

8 9 183-a-EP/HH/

PA 10 11 183-b-AM/OM 12 13 14 183-c-EP/HH/

PA 15 16 17 18 19 183-d-ST NUREG-1437, Supplement 38 A-1316 December 2010

Appendix B Contributors to the Supplement

1 Appendix B 2 Contributors to the Supplement 3 The Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, had overall 4 responsibility for the preparation of this supplement, assisted by staff from other NRC 5 organizations, AECOM, and Pacific Northwest National Laboratory.

Name Function or Expertise U.S. Nuclear Regulatory Commission Andrew Stuyvenberg Environmental Project Manager/Alternatives Rani Franovich Branch Chief David Wrona Branch Chief Bo Pham Branch Chief Andy Imboden Branch Chief Dennis Beissel Hydrology/Water Use Elizabeth Wexler Ecology Dennis Logan Ecology Briana Balsam Ecology Jeffrey Rikhoff Socioeconomics/Land Use/Env. Justice Jennifer Davis Historical/Archeological Resources Steve Klementowicz Radiation Protection/Human Health Andrew Carrera Radiation Protection/Human Health Ekaterina Lenning Air Quality Robert Palla Severe Accident Mitigation Alternatives Tina Ghosh Severe Accident Mitigation Alternatives Paula Cooper Comment Resolution April Bebault Comment Resolution AECOM Roberta Hurley Project Manager Kevin Taylor Alternatives Stephen Duda Ecology Stephen Dillard Terrestrial Ecology December 2010 B-1 NUREG-1437, Supplement 38

Appendix B Name Function or Expertise Ed Kaczmarczyk Air Quality Matthew Goodwin Historical/Archeological Resources Robert Dover Alternatives/Nuclear Fuel Cycle Nicole Spangler Project Coordinator Katie Broom Project Support Bonnie Freeman Administrative Support Pacific Northwest National Laboratory Jeffrey A. Ward Aquatic Ecology Valerie Cullinan Aquatic Ecology Lance W. Vail Hydrology/Water Use Sandia National Laboratory Joseph Jones Severe Accident Mitigation Alternatives Nathan Bixler Severe Accident Mitigation Alternatives Fotini Watson Severe Accident Mitigation Alternatives 1

NUREG-1437, Supplement 38 B-2 December 2010

Appendix C Chronology of NRC Staff Environmental Review Correspondence Related to the Entergy Nuclear Operations, Inc.

Application for License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3

1 Appendix C 2 Chronology of NRC Staff Environmental Review Correspondence 3 Related to the Entergy Nuclear Operations, Inc.,

4 Application for License Renewal of Indian Point Nuclear Generating 5 Unit Nos. 2 and 3 6 This appendix contains a chronological listing of correspondence between the U.S. Nuclear 7 Regulatory Commission (NRC) and Entergy Nuclear Operations, Inc. (Entergy), and other 8 correspondence related to the NRC staffs environmental review under Title 10, Part 51, 9 Environmental Protection Regulations for Domestic Licensing and Related Regulatory 10 Functions of the Code of Federal Regulations (10 CFR Part 51), of Entergys application for 11 renewal of the operating licenses for Indian Point Nuclear Generating Unit Nos. 2 and 3. All 12 documents, with the exception of those containing proprietary information, have been placed in 13 the NRCs Public Document Room at One White Flint North, 11555 Rockville Pike (first floor),

14 Rockville, Maryland. These documents are also available electronically from the Public 15 Electronic Reading Room found on the Internet at http://www.nrc.gov/reading-rm.html. From 16 this site, the public can gain access to the NRCs Agencywide Documents Access and 17 Management System (ADAMS), which provides text and image files of NRCs public documents 18 in the Publicly Available Records component of ADAMS. The ADAMS accession numbers for 19 each document are included below.

20 April 23, 2007 Letter to NRC from Entergy forwarding the application for renewal of 21 operating licenses for Indian Point Nuclear Generating Units 2 and 3, 22 requesting extension of operating licenses for an additional 20 years.

23 (Accession No. ML071207512) 24 April 23, 2007 Letter to NRC from Entergy forwarding a copy of reference documents 25 used in preparing the Environmental Report (Appendix E) for the 26 Indian Point Nuclear Generating Units 2 and 3 license renewal 27 application. (Accession No. ML071210108) 28 May 7, 2007 Letter to Entergy from NRC, Receipt and Availability of the License 29 Renewal Application for Indian Point Nuclear Generating Unit Nos. 2 30 and 3. (Accession No. ML071080133) 31 May 7, 2007 Letter to Ms. Patricia Thorsen, White Plains Public Library, from NRC, 32 Maintenance of Reference Materials at the White Plains Public 33 Library Related to the Review of the Entergy Nuclear Operations, Inc.,

34 License Renewal Application. (Accession No. ML071070518) 35 May 7, 2007 Letter to Ms. Resa Getman, Hendrick Hudson Free Library, from 36 NRC, Maintenance of Reference Materials at the Hendrick Hudson December 2010 C-1 NUREG-1437, Supplement 38

Appendix C 1 Free Library Related to the Review of the Entergy Nuclear 2 Operations, Inc., License Renewal Application. (Accession 3 No. ML071080080) 4 May 7, 2007 Letter to Ms. Susan Thaler, The Field Library, from NRC, 5 Maintenance of Reference Materials at The Field Library Related to 6 the Review of the Entergy Nuclear Operations, Inc., License Renewal 7 Application. (Accession No. ML071080122) 8 July 25, 2007 Letter to Entergy from NRC transmitting Determination of 9 Acceptability and Sufficiency for Docketing, Proposed Review 10 Schedule, and Opportunity for a Hearing Regarding the Application 11 from Entergy Nuclear Operations, Inc. for Renewal of Operating 12 Licenses for Indian Point Nuclear Generating Unit Nos. 2 and 3."

13 (Accession No. ML071900365) 14 August 6, 2007 Letter to Entergy from NRC, Notice of Intent to Prepare an 15 Environmental Impact Statement and Conduct Scoping Process for 16 License Renewal for Indian Pont Nuclear Generating Unit Nos. 2 and 17 3, and forwarding Federal Register notice. (Accession 18 No. ML071840939) 19 August 9, 2007 Memorandum on Forthcoming Meeting to Discuss Environmental 20 Scoping Process for Indian Point Nuclear Generating Unit Nos. 2 and 21 3 License Renewal Application. (Accession No. ML072180296) 22 August 9, 2007 Letter to New York State Office of Parks, Recreation, and Historic 23 Preservation from NRC, Indian Point Nuclear Generating Unit Nos. 2 24 and 3 (Indian Point) License Renewal Application Review (SHPO 25 No. 06PR06720). (Accession No. ML072130333) 26 August 9, 2007 Letter to Advisory Council on Historic Preservation from NRC, Indian 27 Point Nuclear Generating Unit Nos. 2 and 3 License Renewal 28 Application Review. (Accession No. ML072130367) 29 August 16, 2007 Letter to Mr. David Stillwell, U.S. Fish and Wildlife Service (USFWS),

30 Request for List of Protected Species Within the Area Under 31 Evaluation for the Indian Point Nuclear Generating Unit Nos. 2 and 3 32 License Renewal Application Review. (Accession 33 No. ML072130211) 34 August 16, 2007 Letter to Mr. Peter Colosi, National Marine Fisheries Service (NMFS),

35 Request for List of Protected Species and Essential Fish Habitat 36 Within the Area Under Evaluation for the Indian Point Nuclear 37 Generating Unit Nos. 2 and 3 License Renewal Application Review.

38 (Accession No. ML072130388) 39 August 24, 2007 Letter to Mr. Andy Warrior, Absentee Shawnee Tribe of Oklahoma, NUREG-1437, Supplement 38 C-2 December 2010

Appendix C 1 Request for Comments Concerning the Indian Point Nuclear 2 Generating Unit Nos. 2 and 3 License Renewal Application Review.

3 (Accession No. ML072250103) 4 August 24, 2007 Letter to The Honorable Maurice John, Cattaraugus Reservation, 5 Seneca Nation, Request for Comments Concerning the Indian Point 6 Nuclear Generating Unit Nos. 2 and 3 License Renewal Application 7 Review. (Accession No. ML072250171) 8 August 24, 2007 Letter to Mr. Clint Halftown, Cayuga Nation, Request for Comments 9 Concerning the Indian Point Nuclear Generating Unit Nos. 2 and 3 10 License Renewal Application Review. (Accession 11 No. ML072250394) 12 August 24, 2007 Letter to Ms. Nikki Owings-Crumm, Delaware Nation, Request for 13 Comments Concerning the Indian Point Nuclear Generating Unit 14 Nos. 2 and 3 License Renewal Application Review. (Accession 15 No. ML072250459) 16 August 24, 2007 Letter to The Honorable Jerry Douglas, Delaware Tribe of Indians, 17 Request for Comments Concerning the Indian Point Nuclear 18 Generating Unit Nos. 2 and 3 License Renewal Application Review.

19 (Accession No. ML072250488) 20 August 24, 2007 Letter to The Honorable C.W. Longlow, Echota Chickamauga 21 Cherokee Tribe of New Jersey, Request for Comments Concerning 22 the Indian Point Nuclear Generating Unit Nos. 2 and 3 License 23 Renewal Application Review. (Accession No. ML072250534) 24 August 24, 2007 Letter to The Honorable Michael Thomas, Mashantucket Pequot 25 Tribe, Request for Comments Concerning the Indian Point Nuclear 26 Generating Unit Nos. 2 and 3 License Renewal Application Review.

27 (Accession No. ML072260033) 28 August 24, 2007 Letter to Ms. Jeanne Schbotte, Mohegan Tribe, Request for 29 Comments Concerning the Indian Point Nuclear Generating Unit 30 Nos. 2 and 3 License Renewal Application Review. (Accession 31 No. ML072260047) 32 August 24, 2007 Letter to Mr. Ray Halbritter, Oneida Indian Nation of New York, 33 Request for Comments Concerning the Indian Point Nuclear 34 Generating Unit Nos. 2 and 3 License Renewal Application Review.

35 (Accession No. ML072260201) 36 August 24, 2007 Letter to Council of Chiefs, Onondaga Nation, Request for Comments 37 Concerning the Indian Point Nuclear Generating Unit Nos. 2 and 3 38 License Renewal Application Review. (Accession 39 No. ML072260245)

December 2010 C-3 NUREG-1437, Supplement 38

Appendix C 1 August 24, 2007 Letter to The Honorable Dwaine Perry, Ramapough Lenape, Request 2 for Comments Concerning the Indian Point Nuclear Generating Unit 3 Nos. 2 and 3 License Renewal Application Review. (Accession 4 No. ML072260491) 5 August 24, 2007 Letter to Mr. Mike John, Seneca Nation of Indians, Request for 6 Comments Concerning the Indian Point Nuclear Generating Unit 7 Nos. 2 and 3 License Renewal Application Review. (Accession 8 No. ML072260519) 9 August 24, 2007 Letter to Mr. Randy Kind, Shinnecock Tribe, Request for Comments 10 Concerning the Indian Point Nuclear Generating Unit Nos. 2 and 3 11 License Renewal Application Review. (Accession 12 No. ML072270070) 13 August 24, 2007 Letter to The Honorable Harry B. Wallace, Unkechaug Nation, 14 Request for Comments Concerning the Indian Point Nuclear 15 Generating Unit Nos. 2 and 3 License Renewal Application Review.

16 (Accession No. ML072270113) 17 August 24, 2007 Letter to The Honorable Leo Henry, Tuscarora Nation, Request for 18 Comments Concerning the Indian Point Nuclear Generating Unit 19 Nos. 2 and 3 License Renewal Application Review. (Accession 20 No. ML072270548) 21 August 24, 2007 Letter to The Honorable Roger Hill, Tonawanda Band of Senecas, 22 Request for Comments Concerning the Indian Point Nuclear 23 Generating Unit Nos. 2 and 3 License Renewal Application Review.

24 (Accession No. ML072270590) 25 August 24, 2007 Letter to Ms. Sherry White, Stockbridge-Munsee Community Band of 26 Mohican Indians, Request for Comments Concerning the Indian Point 27 Nuclear Generating Unit Nos. 2 and 3 License Renewal Application 28 Review (Accession No. ML072270615) 29 August 24, 2007 Letter to Mr. Ken Jock, St. Regis Mohawk Tribal Council, Request for 30 Comments Concerning the Indian Point Nuclear Generating Unit 31 Nos. 2 and 3 License Renewal Application Review. (Accession 32 No. ML072280045) 33 August 29, 2007 Letter to NRC from USFWS, Indian Point Nuclear Generating Unit 34 Nos. 2 and 3 Protected Species Response. (Accession 35 No. ML0732307840) 36 October 4, 2007 Letter to NRC from NMFS regarding endangered species near Indian 37 Point Nuclear Generating Unit Nos. 2 and 3. (Accession No.

38 ML073340068)

NUREG-1437, Supplement 38 C-4 December 2010

Appendix C 1 October 5, 2007 Letter to NRC from New York State Department of Environmental 2 Conservation (NYSDEC), Indian Point Units 2 and 3 Relicensing 3 Extension Request for Scoping Comments on SEIS. (Accession 4 No. ML072820746) 5 October 10, 2007 Letter to NRC from NYSDEC, Indian Point Units 2 and 3 Relicensing 6 Extension Request for Scoping Comments on SEIS. (Accession 7 No. ML072900470) 8 October 11, 2007 Letter to NYSDEC from NRC regarding extension request for scoping 9 comments. (Accession No. ML072840275) 10 October 24, 2007 Meeting Summary of Public Environmental Scoping Meetings 11 Related to the Review of the Indian Point Nuclear Generating Unit 12 Nos. 2 and 3, License Renewal Application (TAC nos. MD5411 and 13 MD5412). (Accession No. ML072851079) 14 November 8, 2007 Summary of Site Audit Related to the Review of the License Renewal 15 Application for Indian Point Nuclear Generating Unit Nos. 2 and 3.

16 (Accession No. ML073050267) 17 November 14, 2007 Letter to NRC from Entergy, Supplement to License Renewal 18 Application (LRA) Environmental Report References. (Accession 19 No. ML073330590) 20 November 27, 2007 Letter to NYSDEC from NRC, Request for List of State Protected 21 Species Within the Area Under Evaluation for the Indian Point Nuclear 22 Generating Unit Nos. 2 and 3 License Renewal Application Review.

23 (Accession No. ML073190161) 24 December 5, 2007 Letter to Entergy from NRC, Request for Additional Information 25 Regarding Environmental Review for Indian Point Nuclear Generating 26 Unit Nos. 2 and 3 License Renewal (TAC nos. MD5411 and 27 MD5412). (Accession No. ML073330931) 28 December 7, 2007 Letter to Entergy from NRC, Request for Additional Information 29 Regarding Severe Accident Mitigation Alternatives for Indian Point 30 Nuclear Generating Unit Nos. 2 and 3 License Renewal (TAC 31 nos. MD5411 and MD5412). (Accession No. ML073110447) 32 December 20, 2007 Letter to NRC from Entergy, Supplement to License Renewal 33 Application (LRA)Environmental Report References. (Accession 34 No. ML080080205) 35 December 28, 2007 Letter to NRC from NYSDEC regarding rare or State-listed animals 36 and plants, significant natural communities, and other habitats on or in 37 the vicinity of the Indian Point site. (Accession No. ML080070085, 38 withheld from public disclosure per request by NYSDEC)

December 2010 C-5 NUREG-1437, Supplement 38

Appendix C 1 January 4, 2008 Letter to NRC from Entergy, Reply to Request for Additional 2 Information Regarding Environmental Review for License Renewal 3 Application. (Accession No. ML080110372) 4 January 10, 2008 Letter to NRC from Entergy, Supplemental Response to Request for 5 Additional Information Regarding Environmental Review for License 6 Renewal Application. (Accession No. ML080220165) 7 January 30, 2008 Letter to NRC from Entergy, Supplemental Response to Request for 8 Additional Information Regarding Environmental Review for License 9 Renewal Application. (Accession No. ML080380096) 10 February 20, 2008 Letter to NRC from Entergy, Document Request for Additional 11 Information Regarding Environmental Review for License Renewal 12 ApplicationElectronic Copy of Impingement DataTables 4-1 and 13 4-2 of the 1990 Annual Report (EA 1991). (Accession 14 No. ML080580408) 15 February 28, 2008 Letter to NRC from NMFS, Essential Fish Habitat Information 16 Request for Docket Nos. 50-247 and 50-286; Indian Point Nuclear 17 Generating Unit Nos. 2 and 3 License Renewal; at the Village of 18 Buchanan, Town of Cortlandt, Westchester County, NY. (Accession 19 No. ML080990403) 20 March 7, 2008 Letter to NRC from Entergy, Document Request for Additional 21 Information Regarding Environmental Review for License Renewal 22 ApplicationHudson River Fisheries Program Data (Year Class 23 Report). (Accession No. ML080770457) 24 April 9, 2008 Letter to Entergy from NRC, Request for Additional Information 25 Regarding the Review of the License Renewal Application for Indian 26 Point Nuclear Generating Unit Nos. 2 and 3 (TAC nos. MD5411 and 27 MD5412). (Accession No. ML080880104) 28 April 14, 2008 Letter to Entergy from NRC, Request for Additional Information 29 Regarding the Review of the License Renewal Application for Indian 30 Point Nuclear Generating Unit Nos. 2 and 3 (TAC nos. MD5411 and 31 MD5412). (Accession No. ML080940408) 32 April 23, 2008 Letter to Entergy from NRC, Revision of Schedule for the Review of 33 the Indian Point Nuclear Generating Unit Nos. 2 and 3 License 34 Renewal Application (TAC nos. MD5411 and MD5412). (Accession 35 No. ML081000441) 36 April 23, 2008 Letter to NRC from Entergy, Reply to Document Request for 37 Additional Information Regarding Site Audit Review of License 38 Renewal Application for Indian Point Nuclear Generating Unit Nos. 2 39 and 3. (Accession No. ML081230243)

NUREG-1437, Supplement 38 C-6 December 2010

Appendix C 1 May 14, 2008 Letter to NRC from Entergy, Reply to Request for Additional 2 Information Regarding License Renewal ApplicationRefurbishment.

3 (Accession No. ML081440052) 4 May 22, 2008 Letter to NRC from Entergy, Supplemental Reply to Request for 5 Additional Information Regarding License Renewal Application 6 Severe Accident Mitigation Alternatives Analysis. (Accession 7 No. ML081490336) 8 December 19, 2008 Letter to Entergy from NRC, Issuance of Environmental Scoping 9 Summary Report Associated with the Staffs Review of the Application 10 for Renewal of the Operating Licenses for Indian Point Nuclear 11 Generating Unit Nos. 2 and 3 (TAC Nos. MD5411 and MD5412).

12 (Accession No. ML083360062) 13 December 22, 2008 Letter to Entergy from NRC, Notice of Availability of the Draft Plant-14 Specific Supplement 38 to the Generic Environmental Impact 15 Statement for License Renewal of Nuclear Plants Regarding Indian 16 Point Nuclear Generating Unit Nos. 2 and 3 (TAC Nos. MD5411 and 17 MD5412). (Accession No. ML083390523) 18 December 22, 2008 Letter to U.S. Environmental Protection Agency from NRC, Notice of 19 Availability of the Draft Plant-Specific Supplement 38 to the Generic 20 Environmental Impact Statement for License Renewal of Nuclear 21 Plants Regarding Indian Point Nuclear Generating Unit Nos. 2 and 3.

22 (Accession No. ML083400180) 23 December 22, 2008 Letter to New York State Historic Preservation Officer (Ms. Carol Ash) 24 from NRC, Indian Point Nuclear Generating Unit Nos. 2 and 3 25 License Renewal Application Review. (Accession No.

26 ML083400192) 27 December 22, 2008 Letter to National Marine Fisheries Service (Ms. Mary Colligan) from 28 NRC, Biological Assessment for License Renewal of the Indian Point 29 Nuclear Generating Unit Nos. 2 and 3. (Accession No.

30 ML083450723) 31 January 12, 2009 Letter to Delaware Nation of Oklahoma (Ms. Danieala Nieto) from 32 NRC, Request for Comments Concerning the Indian Point Nuclear 33 Generating Unit Nos. 2 and 3, Draft Supplemental Environmental 34 Impact Statement. (Accession No. ML083500409) 35 February 24, 2009 Letter from National Marine Fisheries Service (Ms. Mary Colligan) to 36 NRC, RE: Biological Assessment for License Renewal of Indian Point 37 Nuclear Generating Unit Nos. 2 and 3. (Accession No.

38 ML090820316) 39 March 11, 2009 Letter to NRC from U.S. Environmental Protection Agency (John December 2010 C-7 NUREG-1437, Supplement 38

Appendix C 1 Filippelli). (Accession No. ML090860878) 2 April 30, 2009 Letter to National Marine Fisheries Service (Mr. Peter Colosi) from 3 NRC, Essential Fish Habitat Assessment for License Renewal of 4 Indian Point Nuclear Generating Unit Nos. 2 and 3 (TAC Nos.

5 MD5411 and MD5412). (Accession No. ML090790176) 6 July 1, 2009 Letter to NRC from Entergy, Transmission of Additional Requested 7 Information Regarding Sturgeon Impingement Data. (Accession No.

8 ML091950345) 9 November 24, 1009 Letter from Entergy to NRC, Request for Additional Information 10 Related to License Renewal Indian Point Nuclear Application 11 Environmental Report - Impingement Data. (Accession No.

12 ML093420528) 13 December 11, 2009 Letter from Entergy to NRC, License Renewal Application - SAMA 14 Reanalysis Using Alternate Meteorological Tower Data. (Accession 15 No. ML093580089.)

16 December 17, 2009 Letter from Entergy to NRC, Documents Related to License Renewal 17 Application - Environmental Report. (Accession No ML100290495) 18 January 14, 2010 Letter to NRC from Entergy, License Renewal Application -

19 Supplement to SAMA Reanalysis Using Alternate Meteorological 20 Tower Data. (Accession No. ML100260750) 21 February 2, 2010 Letter to Entergy from NRC, Revision of Schedule for Review of the 22 Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal 23 Application. (Accession No. ML100110063) 24 May 25, 2010 Letter to Entergy from NRC, Revision of Schedule for Review of the 25 Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal 26 Application. (Accession No. ML101260536) 27 May 27, 2010 Letter to NRC from Entergy, Correction to License Renewal 28 Application (TAC Nos. MD5407 and MD5408) Indian Point Unit 29 Numbers 2 and 3. (Accession No. ML101590515) 30 August 31, 2010 Letter to Entergy from NRC, Revision of Schedule for Review of the 31 Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal 32 Application. (Accession No. ML101260536) 33 September 21, 2010 Letter to National Marine Fisheries Service (Mr. Peter D. Colosi) from 34 NRC, Essential Fish Habitat Consultation for License Renewal of 35 Indian Point Nuclear Generating Unit Nos. 2 and 3 (TAC Nos.

36 MD5411 and MD5412). (Accession No. ML092860253) 37 September 27, 2010 Letter to New York State Office of Parks, Recreation and Historic NUREG-1437, Supplement 38 C-8 December 2010

Appendix C 1 Preservation (Ms. Ruth L. Pierpont) from NRC, Indian Point Nuclear 2 Generating Unit Nos. 2 and 3 License Renewal Application Review 3 (SHPO No. 06PR06720). (Accession No. ML092860228) 4 October 12, 2010 Letter to NRC from National Marine Fisheries Service (Mr. Peter D.

5 Colosi), Re: Indian Point Nuclear Generating Unit Nos. 2 and 3 6 License Renewal; Docket Nos. 50-247 and 50-268 [sic]; Essential 7 Fish Habitat Consultation. (Accession No. ML102930012) 8 October 26, 2010 Letter to NRC from New York State Office of Parks, Recreation and 9 Historic Preservation (Mr. Thomas B. Lyons), Re: NRC, Indian Point 10 License Renewal, Buchanan, Westchester County. (Accession No.

11 ML103060210) 12 13 14 December 2010 C-9 NUREG-1437, Supplement 38

Appendix D Organizations Contacted

1 Appendix D 2 Organizations Contacted 3 The U.S. Nuclear Regulatory Commission contacted the following Federal, State, regional, and 4 local agencies, and Native American Tribes, during its independent review of the environmental 5 impacts related to the application by Entergy Nuclear Operations, Inc., for renewal of the 6 operating licenses for Indian Point Nuclear Generating Units Nos. 2 and 3:

7 Absentee Shawnee Tribe of Oklahoma 8 Cattaraugus Reservation, Seneca Nation 9 Cayuga Nation 10 Delaware Nation 11 Delaware Tribe of Indians 12 Echota Chickamauga Cherokee Tribe of New Jersey 13 National Marine Fisheries Service 14 New York State Department of Environmental Conservation 15 New York State Office of Parks, Recreation and Historic Preservation, Historic Preservation 16 Field Services Bureau 17 Oneida Indian Nation of New York 18 Onondaga Nation 19 Ramapough Lenape, Ramapough Tribal Office 20 Seneca Nation of Indians 21 Seneca Nation Tribal Historic Preservation 22 Shinnecock Tribe 23 St. Regis Mohawk Tribal Council 24 Stockbridge-Munsee Community Band of Mohican Indians, Tribal Historic Preservation Office 25 The Mashantucket Pequot Tribe (CT) 26 The Mohegan Tribe (CT) 27 Tonawanda Band of Senecas 28 Tuscarora Nation 29 Unkechaug Nation 30 U.S. Environmental Protection Agency, Region 2 31 U.S. Fish and Wildlife Service December 2010 D-1 NUREG-1437, Supplement 38

Appendix E Compliance Status and Consultation Correspondence 1

Appendix E Indian Point Nuclear Generating Unit Nos. 2 and 3 Compliance Status and Consultation Correspondence Consultation correspondence related to the evaluation of the application for renewal of the operating licenses for Indian Point Nuclear Generating Units 2 and 3 (IP2 and IP3, respectively) is identified in Table E-1. Copies of the correspondence are included in this appendix.

The licenses, permits, consultations, and other approvals obtained from Federal, State, regional, and local authorities for SSES are listed in Table E-2.

Table E-1. Consultation Correspondence Source Recipient Date of Letter U.S. Nuclear Regulatory State Historical Preservation Office August 9, 2007 Commission (R. Franovich) (Office of Parks, Recreation, and Historic Preservation, R. L. Pierpont)

U.S. Nuclear Regulatory Advisory Council on Historic Preservation August 9, 2007 Commission (R. Franovich) (D. Klima)

U.S. Nuclear Regulatory U.S. Fish and Wildlife Service (D. August 16, 2007 Commission (R. Franovich) Stillwell)

U.S. Nuclear Regulatory National Marine Fisheries Service (P. August 16, 2007 Commission (R. Franovich) Colosi)

U.S. Nuclear Regulatory Absentee Shawnee Tribe of Oklahoma August 24, 2007 Commission (R. Franovich) (A. Warrior)

U.S. Nuclear Regulatory Cattaraugus Reservation, Seneca Nation August 24, 2007 Commission (R. Franovich) (The Hon. M. John)

U.S. Nuclear Regulatory Cayuga Nation August 24, 2007 Commission (R. Franovich) (C. Halftown)

U.S. Nuclear Regulatory Delaware Nation (N. Owings-Crumm) August 24, 2007 Commission (R. Franovich)

December 2010 E-1 NUREG-1437, Supplement 38

Appendix E U.S. Nuclear Regulatory Delaware Tribe of Indians (The Hon. J. August 24, 2007 Commission (R. Franovich) Douglas)

U.S. Nuclear Regulatory Echota Chickamauga Cherokee Tribe of August 24, 2007 Commission (R. Franovich) New Jersey (The Hon. C.W. Longlow)

U.S. Nuclear Regulatory Mashantucket Pequot Tribe (The Hon. M. August 24, 2007 Commission (R. Franovich) Thomas)

U.S. Nuclear Regulatory Mohegan Tribe (J. Schbotte) August 24, 2007 Commission (R. Franovich)

U.S. Nuclear Regulatory Oneida Indian Nation of New York (R. August 24, 2007 Commission (R. Franovich) Halbritter)

U.S. Nuclear Regulatory Onondaga Nation (Council of Chiefs) August 24, 2007 Commission (R. Franovich)

U.S. Nuclear Regulatory Ramapough Lenape (The Hon. D. Perry) August 24, 2007 Commission (R. Franovich)

U.S. Nuclear Regulatory Seneca Nation of Indians (M. John) August 24, 2007 Commission (R. Franovich)

U.S. Nuclear Regulatory Shinnecock Tribe (R. Kind) August 24, 2007 Commission (R. Franovich)

U.S. Nuclear Regulatory Unkechaug Nation (The Hon. H. B. August 24, 2007 Commission (R. Franovich) Wallace)

U.S. Nuclear Regulatory Tuscarora Nation (The Hon. L. Henry) August 24, 2007 Commission (R. Franovich)

U.S. Nuclear Regulatory Tonawanda Band of Senecas (The Hon. August 24, 2007 Commission (R. Franovich) R. Hill)

U.S. Nuclear Regulatory Stockbridge-Munsee Community Band of August 24, 2007 Commission (R. Franovich) Mohican Indians (S. White)

U.S. Nuclear Regulatory St. Regis Mohawk Tribal Council (K. August 24, 2007 Commission (R. Franovich) Jock)

U.S. Fish and Wildlife Service (M. U.S. Nuclear Regulatory Commission (R. August 29, 2007 VanDonsell and R. Niver) Franovich)

Delaware Nation (D. Nieto) U.S. Nuclear Regulatory Commission September 5, 2007 National Marine Fisheries Service U.S. Nuclear Regulatory Commission (R. October 4, 2007 (M. A. Colligan) Franovich)

NUREG-1437, Supplement 38 E-2 December 2010

Appendix E U.S. Nuclear Regulatory New York State Dept. of Environmental November 11, 2007 Commission (R. Franovich) Conservation (J. Pietrusiak)

New York State Department of U.S. Nuclear Regulatory Commission (R. December 28, 2007 Environmental Conservation (T. Franovich)

Seoane)

National Marine Fisheries Service U.S. Nuclear Regulatory Commission (R. February 28, 2008 (P. Colosi) Franovich)

U.S. Nuclear Regulatory New York State Historic Preservation December 22, 2008 Commission (D. Wrona) Office (Carol Ash)

U.S. Nuclear Regulatory National Marine Fisheries Service (M.A. December 22, 2008 Commission (D. Wrona) Colligan)

U.S. Nuclear Regulatory Delaware Nation (D. Nieto) January 12, 2009 Commission (D. Wrona)

National Marine Fisheries Service U.S. Nuclear Regulatory Commission (D. February 24, 2009 (M.A. Colligan) Wrona)

U.S. Nuclear Regulatory National Marine Fisheries Service (P. April 30, 2009 Commission (D. Wrona) Colosi)

U.S. Nuclear Regulatory National Marine Fisheries Service (P. September 21, 2010 Commission (D. Wrona) Colosi)

U.S. Nuclear Regulatory New York State Office of Parks, September 27, 2010 Commission (D. Wrona) Recreation and Historic Preservation (R.

Pierpont)

National Marine Fisheries Service U.S. Nuclear Regulatory Commission (D. October 12, 2010 (P. Colosi) Wrona)

New York State Office of Parks, U.S. Nuclear Regulatory Commission (D. October 26, 2010 Recreation and Historic Wrona)

Preservation (T. Lyons)

December 2010 E-3 NUREG-1437, Supplement 38

Appendix E Table E-2. Federal, State, Local, and Regional Licenses, Permits, Consultations, and Other Approvals for the Indian Point site Expiration Agency Authority Description Number Date Remarks NRC 10 CFR Part 50 Possession License, DPR-5 09/28/13 Authorizes Indian Point Unit 1 SAFSTOR for Unit 1 NRC 10 CFR Part 50 Operating license, IP2 DPR-26 09/28/13 Authorizes operation of IP2 NRC 10 CFR Part 50 Operating license, IP3 DPR-64 12/10/15 Authorizes operation of IP3 DOT 49 CFR Part 107 IP2 Hazardous Materials 051909552037 06/30/12 Radioactive Certificate of RT and hazardous Registration materials shipments DOT 49 CFR Part 107 IP3 Hazardous Materials 05919552032R 06/30/12 Radioactive Certificate of T and hazardous Registration materials shipments EPA 40 CFR Part 264 IP2 Hazardous Solid NYD991304411 10/14/02 Accumulation Waste Amendment and temporary Permit (1) onsite storage of mixed waste for >90 days EPA 40 CFR Part 264 IP3 Hazardous Solid NYD085503746 10/17/01 Accumulation Waste Amendment and temporary (2)

Permit onsite storage of mixed waste for >90 days NYSDEC 6 NYCRR Part 325 IP2 Pesticide Application 12696 04/30/12 Pesticide Business Registration application NYSDEC 6 NYCRR Part 325 IP3 Pesticide Application 13163 04/30/12 Pesticide Business Registration application NYSDEC 6 NYCRR Parts 704 IP1, 2, and 3 SPDES NY 000 4472 10/01/923 Discharge of (3) and 750 Permit wastewaters and stormwaters to waters of the State NYSDEC 6 NYCRR Part 704 Simulator Transformer NY 025 0414 02/28/13 Discharge of Vault SPDES Permit wastewaters to waters of the State NUREG-1437, Supplement 38 E-4 December 2010

Appendix E Expiration Agency Authority Description Number Date Remarks NYSDEC 6 NYCRR Part 704 Buchanan Gas Turbine NY 022 4826 02/28/13 Discharge of SPDES Permit wastewaters to waters of the State NYSDEC 6 NYCRR Part 750 ISFSI Project SPDES NYR 00E 125 NA Stormwater Multi-Sector General discharge Permit during construction of dry cask spent fuel storage NYSDEC 6 NYCRR Parts 200 IP2 Air Permit 3-5522- NA Operation of and 201 00011/00026 air emission sources (boilers, turbines and generators)

NYSDEC 6 NYCRR Parts 200 IP3 Air Permit 3-5522- NA Operation of and 201 00105/00009 air emission sources (boilers, turbines and generators)

NYSDEC 6 NYCRR Part 596 IP2 Hazardous 3-000107 09/04/11 Onsite bulk Substance Bulk Storage storage of Registration Certificate hazardous substances NYSDEC 6 NYCRR Part 596 IP3 Hazardous 3-000071 08/16/12 Onsite bulk Substance Bulk Storage storage of Registration Certificate hazardous substances NYSDEC 6 NYCRR Part 610 IP2 Major Oil Storage 3-2140 -- Onsite bulk (4)

Facility storage of

>400,000 gallons of petroleum products NYSDEC 6 NYCRR Part 372 IP2 Hazardous Waste NYD991304411 NA Hazardous Generator Identification waste generation NYSDEC 6 NYCRR Part 372 IP3 Hazardous Waste NYD085503746 NA Hazardous Generator Identification waste generation NYSDEC 6 NYCRR Part 373 IP2 Hazardous Waste NYD991304411 02/28/07 Accumulation (5)

Part 373 Permit and temporary onsite storage of mixed waste for >90 days December 2010 E-5 NUREG-1437, Supplement 38

Appendix E Expiration Agency Authority Description Number Date Remarks WCDOH Chapter 873, Article IP2 Gas Turbine 1 Air #00021 12/31/12 Operation of XIII, Section Permit an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Chapter 873, Article IP2 Gas Turbine 2 Air #00022 12/31/12 Operation of XIII, Section Permit an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Chapter 873, Article IP2 Gas Turbine 3 Air #00023 12/31/12 Operation of XIII, Section Permit an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Chapter 873, Article IP2 Boiler Permit 52-4493 NA Operation of XIII, Section an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Chapter 873, Article IP2 Vapor Extractor Air VE0001 12/31/12 Operation of XIII, Section Permit an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Chapter 873, Article IP3 Vapor Extractor Air NA NA Operation of (6)

XIII, Section Permit an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Chapter 873, Article IP3 Boiler Permit 52-6497 NA Operation of XIII, Section an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Chapter 873, Article IP3 Training Center 52-6498 NA Operation of XIII, Section Boiler Permit an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Chapter 873, Article IP3 Vapor Extractor Air -- -- Operation of XIII, Section Permit an air 873.1306.1 of the contamination Laws of Westchester source County WCDOH Westchester County IP3 Petroleum Bulk 3-166367 09/07/10 Onsite Bulk Sanitary Code, Article Storage Registration Storage of XXV Certificate Petroleum Products NUREG-1437, Supplement 38 E-6 December 2010

Appendix E Expiration Agency Authority Description Number Date Remarks TDEC Tennessee IP2 Tennessee T-NY-010-L09 12/31/10 Shipment of Department of Radioactive Waste- radioactive Environment and License-for-Delivery material into Conservation Tennessee to Regulations a disposal/

processing facility.

TDEC Tennessee IP3 Tennessee T-NY-005-L09 12/31/10 Shipment of Department of Radioactive Waste- radioactive Environment and License-for-Delivery material into Conservation Tennessee to Regulations a disposal/

processing facility.

Notes:

(1) IP2 Hazardous Solid Waste Amendment Permit = Permit has been administratively continued based on conditional mixed waste exemption.

(2) IP3 Hazardous Solid Waste Amendment Permit = Permit has been administratively continued based on conditional mixed waste exemption.

(3) IP1, 2, and 3 SPDES Permit = Timely Renewal application was submitted; therefore, permit is administratively continued under New York Administrative Procedures Act.

(4) IP2 Major Oil Storage Facility = Timely renewal application was submitted; therefore, permit is administratively continued under New York Administrative Procedures Act.

(5) IPs Hazardous Waste Part 373 Permit = Timely renewal application was submitted; therefore, permit is administratively continued under New York Administrative Procedures Act.

(6) IP3 Vapor Extractor Air Permit = Application has been submitted to WCDOH, but permit has not yet been issued.

CFR = Code of Federal Regulations DOT = U.S. Department of Transportation EPA = U.S. Environmental Protection Agency IP 2 = Indian Point, Unit 2 IP 3 = Indian Point, Unit 3 NRC = U.S. Nuclear Regulatory Commission NYCRR = New York Codes, Rules, and Regulations NYSDEC = New York State Department of Environmental Conservation SAFSTOR = Safe Storage SPDES = State Pollutant Discharge Elimination System TDEC = Tennessee Department of Environment and Conservation WCDOH = Westchester County Department of Health December 2010 E-7 NUREG-1437, Supplement 38

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Appendix E Enclosure (report containing a list of rare or State-listed plants and animals) withheld by NRC as sensitive information per New York Natural Heritage Program request.

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Appendix F GEIS Environmental Issues Not Applicable to Indian Point Nuclear Generating Station Unit Nos. 2 and 3

Appendix F GEIS Environmental Issues Not Applicable to Indian Point Nuclear Generating Unit Nos. 2 and 3 Table F-1 lists those environmental issues identified in NUREG-1437, Volumes 1 and 2, Generic Environmental Impact Statement for License Renewal of Nuclear Plants (hereafter referred to as the GEIS), issued 1996 and 1999,(1) and in Table B-1 of Appendix B to Subpart A of Title 10, Part 51, Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions, of the Code of Federal Regulations (10 CFR Part 51), that are not applicable to Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) because of plant or site characteristics.

Table F-1. GEIS Environmental Issues Not Applicable to IP2 and IP3 ISSUE10 CFR Part 51, Subpart A, Category GEIS Appendix B, Table B-1 Sections Comment SURFACE WATER QUALITY, HYDROLOGY, AND USE (FOR ALL PLANTS)

Altered thermal stratification of lakes 1 4.2.1.2.3, IP2 and IP3 do not 4.4.2.2 discharge into a lake.

Water use conflicts (plants with 1 4.3.2.1, IP2 and IP3 have a once-cooling pond or cooling towers using 4.4.2.1 through cooling system.

makeup water from a small river with low flow)

Water use conflicts (plants with 2 4.3.2.1 This issue is related to cooling towers and cooling ponds 4.4.2.1 heat-dissipation systems using make-up water from a small that are not installed at IP2 river with low flow) and IP3.

(1) The GEIS was originally issued in 1996. Addendum 1 to the GEIS was issued in 1999. Hereafter, all references to the GEIS include both the GEIS and its Addendum 1.

December 2010 F-1 NUREG-1437, Supplement 38

Appendix F AQUATIC ECOLOGY (FOR ALL PLANTS)

AQUATIC ECOLOGY (FOR PLANTS WITH COOLING TOWER-BASED HEAT DISSIPATION SYSTEMS)

Entrainment of fish and shellfish in 1 4.2.2.1.2, This issue is related to early life stages 4.4.3 heat-dissipation systems that are not installed at IP2 and IP3.

Impingement of fish and shellfish 1 4.2.2.1.3, This issue is related to 4.4.3 heat-dissipation systems that are not installed at IP2 and IP3.

Heat shock 1 4.2.2.1.4, This issue is related to 4.4.4 heat-dissipation systems that are not installed at IP2 and IP3.

GROUND WATER USE AND QUALITY Ground water use conflicts (potable 1 4.8.1.1, IP2 and IP3 do not use and service water, and dewatering; 4.8.1.2 ground water for any plants that use <100 gpm) purpose.

Ground water use conflicts (potable 2 4.8.1.1, IP2 and IP3 do not use and service water, and dewatering; 4.8.1.2 ground water for any plants that use >100 gpm) purpose.

Ground water use conflicts (plants 2 4.8.1.3 This issue is related to using cooling towers withdrawing heat-dissipation systems makeup water from a small river) that are not installed at IP2 and IP3.

Ground water use conflicts (Ranney 2 4.8.1.4 IP2 and IP3 do not have or wells) use Ranney wells.

Ground water quality degradation 1 4.8.2.2 IP2 and IP3 do not have or (Ranney wells) use Ranney wells.

Ground water quality degradation 1 4.8.2.1 IP2 and IP3 do not use (saltwater intrusion) groundwater for any purpose.

NUREG-1437, Supplement 38 F-2 December 2010

Appendix F Ground water quality degradation 1 4.8.3 IP2 and IP3 do not use (cooling ponds in salt marshes) cooling ponds.

Ground water quality degradation 2 4.8.3 IP2 and IP3 do not use (cooling ponds at inland sites) cooling ponds.

HUMAN HEALTH Microbial organisms (occupational 1 4.3.6 This issue is related to a health) heat-dissipation system that is not installed at IP2 and IP3.

Microbiological organisms (public 2 4.3.6 This issue is related to a health; plants lakes or canals, cooling heat-dissipation system towers, or cooling ponds that that is not installed at IP2 discharge to a small river) and IP3.

TERRESTRIAL RESOURCES Cooling tower impacts on crops and 1 4.3.4 This issue is related to a ornamental vegetation heat-dissipation system that is not installed at IP2 and IP3.

Cooling tower impacts on native 1 4.3.5.1 This issue is related to a plants heat-dissipation system that is not installed at IP2 and IP3.

Bird collisions with cooling towers 1 4.3.5.2 This issue is related to a heat-dissipation system that is not installed at IP2 and IP3.

Cooling pond impacts on terrestrial 1 4.4.4 This issue is related to a resources heat-dissipation system that is not installed at IP2 and IP3.

December 2010 F-3 NUREG-1437, Supplement 38

Appendix F References Code of Federal Regulations, Title 10, Energy, Part 51, Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions.

U.S. Nuclear Regulatory Commission, NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants, Volumes 1 and 2, May 1996.

U.S. Nuclear Regulatory Commission, NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants: Main Report, Section 6.3, Transportation, Table 9.1, Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants, Final Report, Volume 1, Addendum 1, August 1999.

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Appendix G U.S. Nuclear Regulatory Commission Staff Evaluation of Severe Accident Mitigation Alternatives for Indian Point Nuclear Generating Unit Nos. 2 and 3 in Support of License Renewal Application Review

1 Appendix G 2 U.S. Nuclear Regulatory Commission Staff Evaluation of 3 Severe Accident Mitigation Alternatives for 4 Indian Point Nuclear Generating Unit Nos. 2 and 3 in 5 Support of License Renewal Application Review 6 G.1 Introduction 7 Entergy Nuclear Operations, Inc. (Entergy) submitted an assessment of severe accident 8 mitigation alternatives (SAMAs) for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and 9 IP3) as part of the environmental report (ER) (Entergy 2007). Entergy based its assessment on 10 the most recent probabilistic safety assessment (PSA) for IP2 and IP3 (a site-specific offsite 11 consequence analysis performed using the MELCOR Accident Consequence Code System 2 12 (MACCS2) computer code), and on insights from the Individual Plant Examination (IPE) (Con 13 Ed 1992 and NYPA 1994) and the Individual Plant Examination of External Events (IPEEE) 14 (Con Ed 1995 and NYPA 1997) for each unit. In identifying and evaluating potential SAMAs, 15 Entergy considered SAMAs that addressed the major contributors to core damage frequency 16 (CDF) and large early release frequency (LERF) at IP2 and IP3, as well as SAMA candidates 17 for other operating plants that have submitted license renewal applications. Entergy identified 18 231 candidate SAMAs for IP2 and 237 SAMAs for IP3. This list was reduced to 68 (IP2) and 62 19 (IP3) unique SAMAs by eliminating SAMAs that are not applicable at IP2 and IP3 because they 20 have design differences, they have already been implemented at IP2 and IP3, or they are 21 similar in nature and could be combined with another SAMA candidate. Entergy assessed the 22 costs and benefits associated with each of the potential SAMAs and concluded in the ER that 23 several of these were potentially cost beneficial.

24 Based on a review of the SAMA assessment, the U.S. Nuclear Regulatory Commission (NRC) 25 issued requests for additional information (RAIs) to Entergy in letters dated December 7, 2007 26 (NRC 2007), and April 9, 2008 (NRC 2008). Key questions concerned major changes to the 27 internal flood model in each of the PSA updates; PSA peer review comments and their 28 resolution; MACCS2 input data and assumptions (including core inventory, evacuation 29 modeling, and offsite economic costs); assumptions used to quantify the benefits for certain 30 SAMAs; reasons for unit-to-unit differences for certain risk contributors and estimated SAMA 31 benefits; and further information on several specific candidate SAMAs and low-cost alternatives, 32 including SAMAs related to steam generator tube rupture (SGTR) events. Entergy submitted 33 additional information by letters dated February 5, 2008 (Entergy 2008a), and May 22, 2008 34 (Entergy 2008b). In response to the RAIs, Entergy provided clarification of the internal flooding 35 analysis changes in each PSA model version; additional information regarding the peer review 36 process and comment resolution; details regarding the MACCS2 input data, including results of 37 a sensitivity analysis addressing loss of tourism and business; additional explanation and 38 justification for the assumptions in each analysis case; descriptions of plant-specific features 39 that account for differences in risk and SAMA benefits between units; and additional information 40 regarding several specific SAMAs, including SGTR-related SAMAs. Entergys responses 41 addressed the NRC staffs concerns and resulted in the identification of several additional December 2010 G-1 NUREG-1437, Supplement 38

Appendix G 1 potentially cost-beneficial SAMAs and the elimination of one previously identified cost-beneficial 2 SAMA. Subsequent to issuance of the Draft Supplemental Environmental Impact Statement 3 (DSEIS), Entergy identified an error in the Indian Point site meteorology file used to calculate 4 offsite consequences of severe accidents, and submitted a SAMA re-analysis based on the 5 corrected meteorological data (Entergy 2009). The SAMA re-analysis resulted in the 6 identification of several additional potentially cost-beneficial SAMAs beyond those identified in 7 the ER and the DSEIS.

8 An assessment of SAMAs for IP2 and IP3 is presented below.

9 G.2 Estimate of Risk for IP2 and IP3 10 Entergys estimates of offsite risk at IP2 and IP3 are summarized in Section G.2.1. The 11 summary is followed by the NRC staffs review of Entergys risk estimates in Section G.2.2.

12 G.2.1. Entergys Risk Estimates 13 The two distinct analyses that are combined to form the basis for the risk estimates used in the 14 SAMA analysis are (1) the IP2 and IP3 Level 1 and Level 2 PSA models, which are updated 15 versions of the IPE (Con Ed 1992 and NYPA 1994) and IPEEE (Con Ed 1995 and NYPA 1997) 16 for each unit, and (2) supplemental analyses of offsite consequences and economic impacts 17 (essentially a Level 3 PSA model) developed specifically for the SAMA analysis. The SAMA 18 analysis is based on the most recent IP2 and IP3 Level 1 and Level 2 PSA models available at 19 the time of the ER, referred to as the IP2 Revision 1 PSA model (April 2007) for IP2 and the IP3 20 Revision 2 PSA model (April 2007) for IP3. The scope of the PSA models does not include 21 external events.

22 The baseline CDF for the purpose of the SAMA evaluation is approximately 1.79x10-5 per year 23 for IP2 and 1.15x10-5 per year for IP3. The CDF is based on the risk assessment for internally 24 initiated events, including internal flooding. Entergy did not include the contributions from 25 external events within the IP2 and IP3 risk estimates; however, it did perform separate 26 assessments of the CDF from external events and did account for the potential risk reduction 27 benefits associated with external events by multiplying the estimated benefits for internal events 28 by a factor of approximately 3.8 for IP2 and 5.5 for IP3. This is discussed further in Sections 29 G.2.2 and G.6.2.

30 The breakdown of CDF by initiating event is provided in Table G-1 for IP2 and IP3. For IP2, 31 loss of offsite power sequences, including station blackout (SBO) events and internal flooding 32 initiators are the dominant contributors to CDF. For IP3, internal flooding initiators, loss-of-33 coolant accidents (LOCAs), SGTR events, and anticipated transient without scram (ATWS) 34 events are the dominant contributors to CDF.

35 There are several significant differences between the two Indian Point units that account for 36 differences in the risk contributions shown in Table G-1. These differences include:

37 The pressurizer PORV block valves are normally closed in Unit 2, and normally open in Unit 3.

38 Thus, the ability to use the PORVs for feed and bleed cooling in LOOP and partial power loss 39 events is greater at Unit 3, resulting in a lower CDF for LOOP events in Unit 3.

NUREG-1437, Supplement 38 G-2 December 2010

Appendix G 1 There are differences in the internal flooding sources and building configurations (e.g., ingress 2 and egress paths). These physical differences together with differences in the method for 3 calculating failure frequencies result in higher flood CDF frequencies in Unit 2.

4 In Unit 2, DC control power for EDGs and other loads on emergency 480 VAC busses is 5 supplied from either normal or emergency backup supplies, with automatic switching between 6 supplies. Unit 3 does not have this backup capability. This results in a lower CDF contribution 7 from loss of DC power events in Unit 2.

8 Table G-1. IP2 and IP3 Core Damage Frequency (Entergy, 2007)

Initiating Event IP2 IP3

%  %

CDF Contribution CDF Contribution (Per Year) to CDF (Per Year) to CDF Loss of offsite power 1 6.7x10-6 38 1.2x10-7 1 Internal flooding 4.7x10-6 26 2.2x10-6 20 LOCA 1.5x10-6 8 2.2x10-6 19 Transients 1 1.2x10-6 7 8.5x10-7 7 ATWS 9.9x10-7 6 1.5x10-6 13 SBO 8.5x10-7 5 7.2x10-7 6 SGTR 7.2x10-7 4 1.6x10-6 14 Loss of component cooling water 5.8x10-7 3 1.1x10-7 <1 (CCW)

Loss of nonessential service water 3.0x10-7 2 2.8x10-7 2 Interfacing systems LOCA (ISLOCA) 1.5x10-7 <1 1.5x10-7 1 Reactor vessel rupture 1.0x10-7 <1 1.0x10-7 <1 Loss of 125 volts (V) direct current 5.8x10-8 <1 1.0x10-6 9 (dc) power Total loss of service water system 4.4x10-8 <1 5.4x10-7 5 Loss of essential service water 1.9x10-10 <1 1.8x10-8 <1 Total CDF (internal events) 1.79x10-5 100 1.15x10-5 100 1

Contributions from SBO and ATWS events are noted separately and are not included in the reported values for loss of offsite power or transients.

9 The current Level 2 PSA models are based on the IPE models, with updates to reflect changes 10 to the plant and modeling techniques, including a 3.3 percent and 4.8 percent power uprate for 11 IP2 and IP3, respectively; inclusion of additional plant damage states (PDSs) to improve the 12 Level 1-Level 2 PSA interface; and updated accident progression and source term analyses 13 using a later version of the Modular Accident Analysis Program (MAAP) computer code. The 14 Level 1 core damage sequences are placed into one of 57 PDS bins that provide the interface 15 between the Level 1 and Level 2 analyses. The Level 2 models use a single containment event 16 tree (CET) with functional nodes representing both systemic and phenomenological events.

17 CET nodes are evaluated using supporting fault trees and logic rules.

18 The result of the Level 2 PSA is a set of nine release categories with their respective frequency 19 and release characteristics. The results of this analysis for IP2 and IP3 are provided in Tables December 2010 G-3 NUREG-1437, Supplement 38

Appendix G 1 E.1-9 (IP2) and E.3-9 (IP3) of the ER. The frequency of each release category was obtained by 2 summing the frequency of the individual accident progression CET endpoints binned into the 3 release category. Source terms were developed for each of the nine release categories using 4 the results of MAAP 4.04 computer code calculations. The release characteristics for each 5 release category were obtained by frequency-weighting the release characteristics for each 6 CET endpoint contributing to the release category (Entergy 2007).

7 The offsite consequences and economic impact analyses use the MACCS2 code to determine 8 the offsite risk impacts on the surrounding environment and public. Inputs for these analyses 9 include plant-specific and site-specific input values for core radionuclide inventory, source term 10 and release characteristics, site meteorological data, projected population distribution (within an 11 80-kilometer [50-mile] radius) for the year 2035, emergency response evacuation modeling, and 12 economic data. The magnitude of the onsite impacts (in terms of cleanup and decontamination 13 costs and occupational dose) is based on information provided in NUREG/BR-0184 (NRC 14 1997a).

15 In its SAMA analysis, as revised, Entergy estimated the dose to the population within 80 16 kilometers (50 miles) of the IP2 and IP3 site to be approximately 0.87 person-sievert (Sv; 87 17 person-rem) per year for IP2, and 0.95 Sv (95 person-rem) per year for IP3. The breakdown of 18 the total population dose by containment failure mode is summarized in Table G-2, based on 19 information provided in Entergys SAMA re-analysis submitted subsequent to issuance of the 20 DSEIS (Entergy 2009). SGTR events and late containment failures caused by gradual 21 overpressurization by steam and noncondensable gases dominate the population dose risk at 22 both units.

23 Table G-2. Breakdown of Population Dose by Containment Failure Mode (Entergy 2009)

IP2 IP3 Population Population Containment Failure Dose (Person- Percent Dose (Person Percent Mode Rem1 Per Year) Contribution Rem1 Per Contribution Year)

Intact containment <0.1 <1 <0.1 <1 Basemat meltthrough 4.1 5 2.4 3 Gradual overpressure 28.3 32 16.8 18 Late hydrogen burns 3.6 4 2.1 2 Early hydrogen burns 8.6 10 3.2 3 Invessel steam explosion 0.6 <1 0.2 <1 Reactor vessel rupture 4.1 5 1.5 2 ISLOCA 6.6 8 4.2 4 SGTR 31.5 36 64.4 68 Total 87.4 100 94.8 100 1

A rem (Roentgen equivalent man) is a standard unit used to measure the dose equivalent (or effective dose) of radiation, which combines the amount of energy from ionizing radiation that is deposited in human tissue, along with the medical effects of the particular type of radiation (alpha, beta, gamma or neutron) involved . As defined in 10 CFR 20.1004, a rem is a dose-equivalent quantity of radiation equal to the absorbed dose in rads (radiation absorbed dose).

A person-rem is the total dose (in rems) received by a population. One person-rem = 0.01 Sv.

24 25 G.2.2 Review of Entergys Risk Estimates NUREG-1437, Supplement 38 G-4 December 2010

Appendix G 1

2 Entergys determination of offsite risk at IP2 and IP3 is based on the following four major 3 elements of analysis:

4 (1) The Level 1 and Level 2 risk models that form the bases for the IPE submittals (Con Ed 5 1992, NYPA 1994) and the IPEEE submittals (Con Ed 1995,NYPA 1997);

6 (2) The major modifications to the IPE models that have been incorporated in the IP2 and 7 IP3 2007 PSA updates; 8 (3) Adjustments to the IPEEE seismic and fire risk results to represent recent plant changes, 9 updated failure probabilities, and more realistic assumptions; 10 (4) The MACCS2 analyses performed to translate fission product source terms and release 11 frequencies from the Level 2 PSA model into offsite consequence measures.

12 Each of these analyses was reviewed to determine the acceptability of Entergys risk estimates 13 for the SAMA analysis, as summarized below.

14 The NRC staffs reviews of the IP2 and IP3 IPE submittals are described in the NRC reports 15 dated August 14, 1996 (NRC 1996) and October 20, 1995 (NRC 1995), for IP2 and IP3, 16 respectively. Based on its review of the IPE submittals and responses to RAIs, the NRC staff 17 concluded that the IPE submittals met the intent of Generic Letter (GL) 88-20; that is, the 18 licensees IPE process is capable of identifying the most likely severe accidents and severe 19 accident vulnerabilities. Although no vulnerabilities were identified in the IPE, several plant 20 improvements were identified. These improvements have either been implemented at the site 21 or addressed by a SAMA (Entergy 2007). These improvements are discussed in Section G.3.2.

22 There have been three revisions to the IP2 PSA model and two revisions to the IP3 PSA model 23 since the respective IPE submittals. A comparison of the internal events CDF between the IPE 24 submittals and the current PSA models indicates a decrease of approximately 45 and 75 25 percent for IP2 and IP3, respectively (from 3.13x10-5 per year to 1.79x10-5 per year for IP2 and 26 from 4.40x10-5 per year to 1.15x10-5 per year for IP3). A description of those changes that 27 resulted in the greatest impact on the internal-event CDF is provided in Sections E.1.4 and 28 E.3.4 of the ER (Entergy 2007) and in response to a staff RAI (Entergy 2008a) and is 29 summarized in Tables G-3a and G-3b for IP2 and IP3, respectively.

30 December 2010 G-5 NUREG-1437, Supplement 38

Appendix G 1 Table G-3a. IP2 PSA Historical Summary PSA Summary of Changes from Prior Model CDF Version (per year) 1992 IPE submittal (excluding internal flooding) (RISKMAN) 3.13x10-5 2.19x10-5 Update 5/2003 PSA Update (RISKMAN)

- credited recovery of feedwater and condensate

- added treatment of cross-header common-cause failure (CCF) for essential and nonessential service water headers

- updated equipment performance and unavailability data

- revised human error probabilities based on thermal-hydraulic calculations

- updated reactor coolant pump (RCP) seal LOCA model

- added treatment of internal flooding events Rev. 0 1.71x10-5 3/2005 PSA update (Computer-Aided Fault-Tree Analysis code [CAFTA])

- updated initiating event, component failure, and unavailability databases

- updated offsite power recovery data per EPRI 1009889

- revised internal flooding analysis, including pipe-break frequencies and human error probabilities

- changed CCF model from multiple Greek letter to Alpha method

- updated human reliability analysis (HRA) method to the EPRI HRA method

- updated RCP seal LOCA model to WCAP-16141 (WOG2000)

- updated ISLOCA model to address ISLOCAs inside containment, to credit mitigation only for small LOCAs outside containment, and to remove credit for makeup to the refueling water storage tank (RWST)

NUREG-1437, Supplement 38 G-6 December 2010

Appendix G PSA Summary of Changes from Prior Model CDF Version (per year) 1.79x10-5 Rev. 1 2/2007 PSA update

- updated selected initiating event frequencies

- updated offsite power recovery model per NUREG/CR-6890

- included CCF for plugging service water pump strainers

- revised model to reflect that normal offsite power feeds to the 480-V ac safeguards buses do not trip on a safety injection (SI) signal without a concurrent loss of offsite power

- added credit for Indian Point Unit 1 (IP1) station air compressors for scenarios that do not involve loss of offsite power

- revised auxiliary feedwater (AFW) success criterion to require flow to two (rather than one) steam generators for normal (non-ATWS) response 1 Table G-3b. IP3 PSA Historical Summary PSA Summary of Changes from Prior Model CDF Version (per year) 1994 IPE submittal (including internal flooding CDF of 6.5x10-6) 4.40x10-5 Rev. 1 1.35x10-5 6/2001 PSA Update

- updated initiating event, component failure, and unavailability databases

- updated offsite power recovery model per NUREG/CR-5496

- revised and added CCF component groups consistent with the most recent probabilistic risk assessment (PRA) practices, and updated CCF data

- revised HRA to reflect EOP changes

- updated RCP seal LOCA model per Brookhaven model, including credit for qualified high-temperature RCP seals December 2010 G-7 NUREG-1437, Supplement 38

Appendix G

- incorporated major plant design changes, including:

• replacement of power-operated relief valves (PORVs) to eliminate leakage and allow operation with the block valve open

• reassignment of power supplies to emergency diesel generator (EDG) room exhaust fans to eliminate dependencies

• modification of backup battery charger 35 to be able to be powered from 480-V MCC 36C, 36D, or 36E

• installation of a diesel-driven station air compressor

• installation of temperature detectors to provide control room alarm if high temperature on the 15 and 33 feet (ft) elevation of the control building

• installation of a waterproof door to the deluge valve station Rev. 2 1.15x10-5 2/2007 PSA Update

- added a total loss of service water initiating event

- updated offsite power recovery model per NUREG/CR-6890

- changed CCF model from modified Beta method to Alpha method

- updated RCP seal LOCA model to WCAP-16141 (WOG2000)

- revised AFW success criterion to require flow to two (rather than one) steam generators for normal (non-ATWS) response

- modified success criteria for cooling of internal recirculation pumps to remove credit for cooling by redundant systems

- removed the credit for an offsite gas turbine (which is no longer maintained) 1 NUREG-1437, Supplement 38 G-8 December 2010

Appendix G 1 The CDF values from the IP2 and IP3 IPE submittals (3.13x10 per year and 4.40x10-5 per

-5 2 year, respectively) are near the average of the CDF values reported in the IPEs for pressurized-3 water reactors (PWRs) with dry containments. Figure 11.2 of NUREG-1560 shows that the IPE-4 based total internal events for these plants range from 9x10-8 to 8x10-5 per year, with an 5 average CDF for the group of 2x10-5 per year (NRC 1997b). The NRC staff recognizes that 6 other plants have updated the values for CDF subsequent to the IPE submittals to reflect 7 modeling and hardware changes. The current internal event CDF results for IP2 and IP3 8 (1.79x10-5 per year and 1.15x10-5 per year, respectively) are comparable to those for other 9 plants of similar vintage and characteristics.

10 The NRC staff considered the peer reviews performed for the IP2 and IP3 PSAs and the 11 potential impact of the review findings on the SAMA evaluation in order to reach a conclusion 12 regarding adequacy of the PRA to support SAMA evaluation. In the ER, Entergy described the 13 peer review by the (former) Westinghouse Owners Group (WOG) of the IP2 PSA model, 14 conducted in May 2002, and of the IP3 PSA model, conducted in January 2001. The IP2 model 15 reviewed was an updated version of the IPE that predated the May 2003 version described in 16 Table G-3a. Similarly, the IP3 model reviewed was an updated version of the IPE that predated 17 the June 2001 version described in Table G-3b.

18 For both IP2 and IP3, the ER states that all of the technical elements were graded as sufficient 19 to support applications requiring the capabilities defined for grade 2 (e.g., risk-ranking 20 applications). In addition, most of the elements were further graded as sufficient to support 21 applications requiring the capabilities defined for grade 3 (e.g., risk-informed applications 22 supported by deterministic insights).

23 For IP2, the ER states that there were no Level A findings (for which immediate model changes 24 would have been appropriate) from the peer review. Although a number of minor model 25 corrections were made following the peer review, no significant changes were made to the 26 model structure or underlying assumptions in the May 2003 PSA update. The IP2 model was 27 subsequently converted from the support-state RISKMAN model to a linked-fault-tree CAFTA 28 model. Entergy indicates that the conversion effort included a number of modeling changes for 29 consistency with other Entergy models and addressed the remaining findings and observations 30 (F&Os) from the IP2 Peer Review (i.e., Level B, C, and D F&Os), where appropriate. In 31 addition, the issues raised during the peer review of the IP3 model were also examined for 32 applicability to IP2; all applicable issues were addressed consistent with the treatment used for 33 IP3. For IP3, the ER states that all Level A and B F&Os from the IP3 peer review were 34 addressed in the final version of the Revision 1 PSA model for IP3, which was issued in 35 June 2001, and that less significant (Level C & D) F&Os were addressed, where appropriate.

36 Entergy indicates that the model changes incorporated in the IP2 Revision 1 and the IP3 37 Revision 2 PSA models also underwent an internal independent review by Entergy PSA staff 38 and plant personnel and were subjected to a focused self-assessment to demonstrate technical 39 quality in preparation for the NRC Mitigating Systems Performance Indicator (MSPI) program in 40 2006. In addition, the IP2 model was also subjected to a weeklong review by a team of industry 41 peers from outside the Entergy staff in July 2005. Finally, the ER indicates that the model 42 changes in the IP2 Revision 1 and the IP3 Revision 2 PSA models were peer reviewed for 43 accuracy and consistency by members of the Entergy Nuclear Systems Analysis Group not 44 directly involved in their implementation (Entergy 2007).

December 2010 G-9 NUREG-1437, Supplement 38

Appendix G 1 Given that the IP2 and IP3 internal events PSA models have been peer reviewed and the peer 2 review findings were either addressed or judged to have no adverse impact on the SAMA 3 evaluation, and that Entergy has satisfactorily addressed the NRC questions regarding the PSA 4 (NRC 2007, NRC 2008, Entergy 2008a, Entergy 2008b). The NRC staff concludes that the 5 internal events Level 1 PSA model for the plants is of sufficient quality to support the SAMA 6 evaluation.

7 Section E.1.4 of the ER states that, for IP2, internal flooding was examined as part of the 8 IPEEE, while Section E.3.4 indicates that internal flooding was included in the IP3 IPE. Internal 9 flooding was later incorporated into the IP2 May 2003 PSA update, resulting in the consistent 10 treatment of internal flooding for the two units.

11 The IP2 IPEEE analysis of internal flooding yielded a CDF of 6.6x10-6 per year while the IP3 IPE 12 internal flooding analysis yielded a CDF of 6.5x10-6 per year. For each plant, three scenarios 13 accounted for more than 80 percent of the flood CDF. All these scenarios result in a reactor trip 14 and the nonrecoverable loss of safety-related switchgear from flooding sources located in or 15 adjacent to each units 480-V switchgear room.

16 The internal flooding analysis was included in the WOG peer review. In response to an RAI, 17 Entergy provided a detailed discussion on the incorporation of peer review comments for IP2 18 and IP3. For IP2, the licensee indicated that there were only two WOG peer review findings 19 associated with the internal flooding analysis.

20 The first finding related to use of a flooding event screening criterion of 1x10-6 per year in the 21 analysis. That criterion, however, was only applied to a scenario involving the potential for 22 intercompartmental flooding from the EDG building to the electrical tunnel and involved leakage 23 that could be accommodated by existing plant drains rather than catastrophic failure. Therefore, 24 it was determined that screening of this scenario was appropriate and a model change was not 25 needed.

26 The second finding was a general concern that the flooding study had not been updated since 27 1993. The IP2 internal flooding analysis was subsequently updated in 2005 (Entergy 2008a).

28 For IP3, the licensee indicated that the IP3 WOG peer review concluded that the internal 29 flooding analysis demonstrated a superior combination of industry data and models to obtain 30 plant-specific piping rupture frequencies. The peer review identified four F&Os related to the 31 internal flooding analysis. One F&O was a strength that warranted no change to the model.

32 The other findings related to incorporation of historical data, assembly of walkdown records, and 33 consideration of applicable draft American Society of Mechanical Engineers (ASME) standards 34 to enhance the flooding analysis. The findings related to the incorporation of historical data and 35 to the assembly of walkdown records were resolved during preparation of the final version of 36 Revision 1 of the IP3 PSA model. The draft ASME standards identified by the review team were 37 reviewed, and no modeling changes were warranted. Therefore, all internal flooding review 38 comments that affect the model were addressed in the model used for the SAMA analysis 39 (Entergy 2008a).

40 As indicated above, the current IP2 and IP3 PSA models do not include external events. In the 41 absence of such an analysis, Entergy used the IP2 and IP3 IPEEEs, in conjunction with minor 42 adjustments in fire and seismic scenarios, to identify the highest risk accident sequences and 43 the potential means of reducing the risk posed by those sequences, as discussed below.

NUREG-1437, Supplement 38 G-10 December 2010

Appendix G 1 The IP2 and IP3 IPEEEs were submitted in December 1995 (Con Ed 1995) and September 2 1997 (NYPA 1997), in response to Supplement 4 of GL 88-20 (NRC 1991). These submittals 3 included a seismic PRA analysis, a fire PRA, a high-wind risk model, and a screening analysis 4 for other external events. While no fundamental weaknesses or vulnerabilities to severe 5 accident risk in regard to the external events were identified, several opportunities for risk 6 reduction were identified and implemented, as discussed below. In letters dated August 13, 7 1999, and February 15, 2001, the NRC staff concluded that the submittals for IP2 and IP3 8 generally met the intent of Supplement 4 to GL 88-20, and that the licensees IPEEE process is 9 capable of identifying the most likely severe accidents and severe accident vulnerabilities (NRC 10 1999, NRC 2001). For IP3, the NRC staff identified an issue related to misdirection of manual 11 fire suppression, which can fail equipment, but decided to resolve that issue separately from the 12 IPEEE.

13 The IPEEE seismic analyses employed a seismic PSA following the guidance of NUREG-1407.

14 The IPEEE estimated a seismic CDF of 1.46x10-5 and 4.4x10-5 per year for IP2 and IP3, 15 respectively. Components related to decay heat removal were modeled in the seismic PSA for 16 both units. No unique decay-heat removal vulnerabilities were found for either unit based on the 17 quantitative risk results. Seismic-induced flooding and fires were examined as part of the 18 IPEEE process for both units. Specific seismic-fire interactions were identified by Entergy, as 19 listed in Table 2.12 of NUREG-1742 (NRC 2002). However, upon further consideration, the 20 NRC staff concluded that the contribution to the CDF is small because the conditional 21 probability of a fire, given an earthquake, is small (NRC 2001). For IP2 and IP3, the IPEEEs 22 also addressed the issue of relay chattering through a detailed examination of the relays used in 23 IP2 and IP3 against the low-capacity relay list found in Appendix D of Electric Power Research 24 Institute (EPRI) NP-7148-SL. A list of the dominant contributors to the seismic CDF for IP2 and 25 IP3 is provided in Tables G-4a and G-4b, based on the information provided in response to an 26 RAI (Entergy 2008a).

27 In Section 4.21.5.4 of the ER, Entergy noted that conservative assumptions were used in the 28 seismic analyses, including the use of a single, conservative surrogate element to model the 29 most seismically rugged components, the assumption that redundant components are 30 completely correlated in determining the probability of seismic-induced failure, and the 31 assumption that seismic-induced ATWS events are not recoverable. For purposes of the SAMA 32 evaluation, Entergy performed a reevaluation of the seismic CDF, as discussed below. For IP2, 33 as a result of an IPEEE recommendation, the CCW surge tank hold-down bolts were upgraded.

34 This effectively eliminated the contribution from the failure of the CCW surge tank, reducing the 35 seismic CDF for IP2 from 1.46x10-5 per year to approximately 1.06x10-5 per year. For IP3, no 36 seismic improvements were recommended. However, Entergy reevaluated the seismic PSA to 37 reflect updated random component failure probabilities and to model recovery of onsite power 38 and local operation of the turbine-driven AFW pump. This reduced the seismic CDF for IP3 39 from 4.4x10-5 per year to 2.65x10-5 per year. These reduced CDF values were used in 40 developing the external events multipliers in the SAMA benefit analysis, as discussed later.

December 2010 G-11 NUREG-1437, Supplement 38

Appendix G 1 Table G-4a. IP2 Seismic Scenarios and Their Contribution to Seismic CDF CDF (per year)

Seismic Scenario Description Percent Frequency Contribution Failure of CCW, primarily caused by failure of surge tank hold- 4.2x10-6 29 down bolts Failure of the turbine building frame and consequential failure of 3.5x10-6 24 control building Collapse of IP1 super heater stack onto control building 3.0x10-6 21

-6 Loss of 480 V emergency power 1.3x10 9 Loss of service water (seismic failure of service water pumps) 1.3x10-6 9

-7 Seismic-induced loss of offsite power 4.4x10 3

-7 Other 7.4x10 5 Total Seismic CDF from Dominant Scenarios 1.46x10-5 100 2 Table G-4b. IP3 Seismic Scenarios and Their Contribution to Seismic CDF CDF (per year)

Seismic Scenario Description Percent Frequency Contribution Loss of 480-V ac electric power with consequential RCP seal 1.9x10-5 43 LOCA Loss of CCW with consequential RCP seal LOCA 1.0x10-5 23 Loss of offsite power with seismic failures of the RHR heat 9.2x10-6 21 exchangers, the condensate stage tank, containment instrument racks, and AFW Surrogate element (represents screened out, rugged 3.5x10-6 8 components and structures, where failure leads to core damage)

Seismic-induced ATWS 2.2x10-6 5

-5 Total Seismic CDF from Dominant Scenarios 4.4x10 100 3

NUREG-1437, Supplement 38 G-12 December 2010

Appendix G 1 The IPEEE fire analyses employed a combination of PRA with the EPRIs fire-induced 2 vulnerability evaluation methodology. The evaluation was performed in four phases:

3 (1) Qualitative screening; 4 (2) Quantitative screening; 5 (3) Fire damage evaluation screening; 6 (4) Fire scenario evaluation and quantification.

7 Each phase focused on those fire areas that did not screen out in the prior phases. The final 8 phase involved using the IPE model for internal events to quantify the CDF resulting from a fire-9 initiating event. Each fire area that remained after screening was then treated as a separate 10 initiating event and was propagated through the model with the appropriate model modifications.

11 The CDF for each area was obtained by accounting for the frequency of a fire in a given fire 12 area; the conditional core damage probability associated with that fire scenario in the fire area, 13 including, where appropriate, the impact of fire suppression; and fire propagation. The potential 14 impact on containment performance and isolation was evaluated following the core damage 15 evaluation. The total fire CDF from the IPEEE was estimated to be 1.8x10-5 per year for IP2 16 (Con Ed 1995) and 5.6x10-5 per year for IP3 (NYPA 1997).

17 In Section 4.21.5.4 of the ER, Entergy noted that conservative assumptions were used in the 18 IPEEE fire analyses, including overestimation of the frequency and severity of fires; 19 conservative treatment of open, hot short, and short-to-ground circuits; and assumption of a 20 plant trip for all fires. For purposes of the SAMA evaluation, Entergy performed a reevaluation 21 of the fire CDF, as discussed below.

22 For IP2, Section E.1.3.2 of the ER notes that the IP2 IPEEE fire model had the following known 23 conservatisms:

24 The main feedwater and condensate systems were assumed to be unavailable in all 25 scenarios, even when their power source was not affected by the fire scenario.

26 The pressurizer PORV block valves were assumed to be in the limiting position (open or 27 closed) to maximize the impact of the fire.

28 All sequences involving RCP seal LOCAs were assumed to lead to complete seal 29 failure.

30 For the purpose of the SAMA evaluation, Entergy reevaluated the dominant IPEEE fire 31 sequences (sequences with CDF contributions greater than 1x10-7 per year) to reduce the 32 conservatisms associated with main feedwater and condensate unavailability and PORV block 33 valve assumptions and to reflect updated modeling associated with RCP-seal LOCAs. In 34 response to a RAI, Entergy explained that other portions of the fire analysis methodology and 35 modeling were not revised as part of the SAMA update. Entergy also noted that preliminary fire 36 analysis results were inadvertently included in the ER and provided a corrected, revised IP2 fire 37 CDF value of 8.4x10-6 per reactor year (Entergy 2008a). These revised results are included in 38 Table G-5a and were used in developing the external events multiplier in the SAMA benefit 39 analysis.

40 Similarly, for IP3, Section E.3.3.2 of the ER notes that the IP3 IPEEE fire model had known 41 conservatisms in estimating the fire ignition frequency (e.g., an air compressor ignition December 2010 G-13 NUREG-1437, Supplement 38

Appendix G 1 frequency did not take into account that the compressor would operate only for a total of about 2 5 days per year). Also, at the time of IPEEE, the automatic suppression systems in some plant 3 areas were placed in manual mode because of concerns with seismic interactions.

4 Subsequently, some fire suppression systems were extensively modified so that the 5 suppression mode could have been returned to automatic. As part of the update for the 6 purpose of SAMA evaluations, Entergy performed a reanalysis of the fire CDF and provided a 7 revised IP3 fire CDF value of 2.55x10-5 per year (Entergy 2007). These revised results are 8 included in Table G-5b and were used to develop the external events multiplier in the SAMA 9 benefit analysis.

10 Table G-5a. IP2 Fire Areas and Their Contribution to Fire CDF CDF (per year)

Fire Area Area Description IPEEE Fire Reanalysis 1A Electrical tunnel/pipe penetration area 9.2x10-7 6.6x10-7 2A Primary water makeup area 1.1x10-6 5.1x10-7 11 Cable spreading room 4.3x10-6 2.0x10-6 14 Switchgear room 3.8x10-6 1.4x10-6 15 Control room 7.1x10-6 3.0x10-6 74A Electrical penetration area 1.1x10-6 7.3x10-7 6A Drumming and storage station 1.5x10-9 1.5x10-9 32A Cable tunnel 9.6x10-8 9.6x10-8 1 CCW pump room 2.2x10-9 2.2x10-9 22/63A Service water intake 7.5x10-9 7.5x10-9 23 AFW pump room 6.2x10-9 6.2x10-9 Total Fire CDF from Major Fire Areas 1.8x10-5 8.4x10-6 11 Table G-5b. IP3 Fire Areas and Their Contribution to Fire CDF CDF (per year)

Fire Area Area Description IPEEE Fire Reanalysis 14 480-V switchgear room 3.5x10-5 1.3x10-5 11 Cable spreading room 6.8x10-6 5.3x10-6 15 Control room 3.7x10-6 3.7x10-6 480-V switchgear room/south turbine 14/37A 4.5x10-6 1.8x10-7 building 10 Diesel generator 31 2.1x10-6 2.0x10-6 102A Diesel generator 33 1.9x10-6 4.7x10-9 NUREG-1437, Supplement 38 G-14 December 2010

Appendix G CDF (per year)

Fire Area Area Description IPEEE Fire Reanalysis 60A Upper electrical tunnel 7.1x10-7 7.1x10-7 101A Diesel generator 32 3.4x10-7 5.2x10-9 7A Lower electrical tunnel 2.8x10-7 2.8x10-7 1

December 2010 G-15 NUREG-1437, Supplement 38

Appendix G 1 Table G-5b (continued)

CDF (per year)

Fire Area Area Description IPEEE Fire Reanalysis 23 AFW pump room 2.3x10-7 2.3x10-7 37A south turbine building elevation 15 ft 3.8x10-8 3.8x10-8 17A primary auxiliary building (PAB) corridor 3.2x10-8 3.2x10-8 Total Fire CDF from Major Fire Areas 5.6x10-5 2.6x10-5 2 For high-wind and tornado events, the ER noted that IP2 structures and systems predate the 3 1975 Standard Review Plan (SRP) criteria. Therefore, a detailed PRA was developed as part of 4 the IPEEE analysis to address the impact of high-wind events at IP2. The equipment of 5 concern includes that located within sheet metal clad structures (e.g., the gas turbine and EDG 6 components) and equipment in the yard, including the condensate storage tank (CST) and 7 service water pumps. The CDF for high-wind events was estimated in the IPEEE to be 8 3.03x10-5 per year. In Section E.1.3.3.1 and E.1.4.3 of the ER, Entergy noted that its planned 9 removal of the gas turbines from service would reduce the probability of recovering power from 10 the offsite gas turbine location (as modeled in the PRA), but as shown by a sensitivity analysis 11 this impact would be offset by the increased reliability and ruggedness of the new IP2 12 SBO/Appendix R diesel generator relative to that of the gas turbines. Accordingly, Entergy used 13 the IPEEE high-wind CDF of 3.03x10-5 per year in determining the external event multiplier for 14 IP2, as discussed later.

15 The IP3 structures and systems also predate the SRP criteria, but the IPEEE found the 16 estimated CDF for high-wind events to be below the 1x10-6 per year screening criterion (from 17 NUREG-1407). This conclusion is based in part on the assumption that high water levels are 18 maintained in the condensate storage and city water storage tank, thus preventing significant 19 wind load and pressure differential damage to the tanks that provide water to the AFW system 20 (NYPA 1997). Because of the low CDF value, the IP3 external-event multiplier does not 21 explicitly account for risks associated with high-wind and tornado events.

22 The IP2 and IP3 IPEEE submittals examined a number of other external hazards, including 23 external flooding, ice formation, and accidents involving hazardous chemicals, transportation 24 (e.g., accidental aircraft impacts), or nearby industrial facilities. These evaluations followed the 25 screening and evaluation approaches specified in Supplement 4 to GL 88-20 (NRC 1991). No 26 risks to the plant from external floods, ice formation, or accidents involving hazardous 27 chemicals, transportation, or nearby facilities, were identified that might lead to core damage 28 with a predicted frequency in excess of 1x10-6 per year (Con Ed 1995, NYPA 1997). For IP3, 29 scenarios involving hydrogen explosions within the turbine building, the pipe trench between the 30 PAB and containment, the hydrogen shed area in the containment access facility, and the pipe 31 chase on the 73-ft elevation of the northeast corner of the PAB were identified that, in total, 32 could result in core damage with an estimated frequency slightly above 1x10-6 per year. As a 33 result, Phase II SAMA 53 was identified to evaluate the change in plant risk from plant 34 modifications to install an excess flow valve to reduce the risk associated with hydrogen 35 explosions inside the turbine building or PAB. Entergy noted that the risks from deliberate NUREG-1437, Supplement 38 G-16 December 2010

Appendix G 1 aircraft impacts were explicitly excluded, since this was being considered in other forums, along 2 with other sources of sabotage.

3 Based on the aforementioned results, Entergy estimated that the external event CDF is 4 approximately 2.8 and 4.52 times that of the internal-event CDF for IP2 and IP3, respectively.

5 For IP2, this factor was based on an internal event CDF of 1.79x10-5 per year, a seismic CDF of 6 1.06x10-5 per year, a fire CDF of 8.4x10-6 per year, and a high-wind CDF contribution of 7 3.03x10-5 per year. For IP3, this factor was based on an internal-event CDF of 1.15x10-5 per 8 year, a seismic CDF of 2.65x10-5 per year, and a fire CDF of 2.55x10-5 per year. Accordingly, 9 the total CDF from internal and external events would be approximately 3.8 times the internal-10 event CDF for IP2 and 5.5 times the internal event CDF for IP3.

11 In the SAMA analysis submitted in the ER, Entergy increased the benefit that was derived from 12 the internal-event model by a factor 3.8 and 5.5 to account for the combined contribution from 13 internal and external events for IP2 and IP3, respectively. For SAMA candidates that address 14 only a specific external event and have no bearing on internal-event risk (e.g., IP2 SAMA 66 15 Harden EDG Building Against High Winds), Entergy derived the benefit directly from the 16 external-event risk model and then increased the benefit by the multipliers identified earlier.

17 This resulted in a bounding benefit for the SAMA candidates addressing a specific external 18 event. The NRC staff agrees with the licensees overall conclusion concerning the impact of 19 external events and concludes that the licensees use of a multiplier of 3.8 and 5.5 for IP2 and 20 IP3, respectively, to account for external events is reasonable for the purposes of the SAMA 21 evaluation. This is discussed further in Section G.6.2.

22 The NRC staff reviewed both the general process used by Entergy to translate the results of the 23 Level 1 PSA into containment releases and the results of the Level 2 analysis, as described in 24 the ER and in response to the NRC staffs RAIs (Entergy 2007, Entergy 2008a). The 25 containment designs and the Level 2 analyses are similar for IP2 and IP3. The NRC staff notes 26 that, after reviewing information provided by Entergy, the current Level 2 PSA models are based 27 on the IPE models, with updates to reflect changes to the plant and modeling techniques, 28 including a 3.3 percent and 4.8 percent power uprate for IP2 and IP3, respectively; inclusion of 29 additional PDSs to improve the Level 1-Level 2 PSA interface; and updated accident 30 progression and source term analyses using a later version of the MAAP computer code.

31 The Level 1 core damage sequences are placed into one of 57 PDS bins that provide the 32 interface between the Level 1 and Level 2 analyses. The PDSs are defined by a set of 33 functional characteristics for system operation that are important to accident progression, 34 containment failure, and source-term definition. The Level 2 models use a single CET with 35 functional nodes representing both systemic and phenomenological events. The CET is used to 36 determine the appropriate release category for each Level 2 sequence. CET nodes are 37 evaluated using supporting fault trees and logic rules.

38 Entergy characterized the releases for the spectrum of possible radionuclide release scenarios 39 using a set of nine release categories, defined based on the timing and magnitude of the 40 release and whether the containment remains intact, fails, or is bypassed. The frequency of 41 each release category was obtained by summing the frequency of the individual accident 42 progression CET endpoints binned into the release category. The release characteristics for 43 each category were obtained by frequency weighting the release characteristics for each CET 44 endstate contributing to the release category. The source-term release fractions for the CET December 2010 G-17 NUREG-1437, Supplement 38

Appendix G 1 endstates were estimated based on the results of plant-specific analyses of the dominant CET 2 scenarios using the MAAP (Version 4.04) computer program. The release categories and their 3 frequencies and release characteristics are presented in Tables E.1-10 and E.3-10 of the ER.

4 During the review of the Level 2 analysis, the NRC staff could not determine the modeling 5 approach used to assess the likelihood of a thermally induced SGTR (TI-SGTR) following core 6 damage in the current IP2 and IP3 PSAs. Entergy explained that TI-SGTR events are 7 considered in the Level 2 analyses for two conditions:

8 (1) High reactor cooling system (RCS) pressure and steam generators dry (no secondary-9 side cooling);

10 (2) High RCS pressure and steam generators initially dry, with recovery of secondary-side 11 cooling before challenging the steam generator tubes.

12 The first condition applies to transient event sequences in which RCS pressure is at the 13 pressurizer PORV setpoint at the time of core damage. No credit is taken for recovery of 14 secondary-side cooling in these sequences. Entergy states that a TI-SGTR probability of 0.01 15 is used for this case, based on Table 2-1 of NUREG/CR-4551, Volume 2, Revision 1, Part 1, 16 which shows a distribution that ranges from 1x10-5 to 0.1208 and a mean value of 0.018. The 17 second condition applies to SBO sequences in which RCS pressure is at the pressurizer PORV 18 setpoint at the time of core damage. Entergy states that a TI-SGTR probability of 5x10-4 is used 19 for this SBO case, based on the expectation that the steam generators will not dry out until after 20 battery depletion and that secondary-side cooling and other mitigating system functions could 21 be recovered before that time. The value is stated as being derived from the transient case 22 value of 0.01 combined with the human error probability of 5.2x10-2 for failure to align AFW 23 following ac power recovery. Entergy explained that a stuck-open main steam safety valve or 24 other secondary-side depressurization event is required to create the large differential pressure 25 needed for the conditional TI-SGTR probabilities assumed above and that the Level 2 analyses 26 conservatively did not account for the probability that these additional failures do not occur 27 (Entergy 2008b). A sensitivity analysis that increases the probability of the TI-SGTR was 28 developed at the staffs request and is described in Section G.6.2.

29 The NRC staffs reviews of the Level 2 IPEs for IP2 and IP3 concluded that the analyses 30 addressed the most important severe accident phenomena normally associated with large dry 31 containments and identified no significant problems or errors (NRC 1995, NRC 1996). It should 32 be noted, however, that the current Level 2 models are revisions to those of the IPE. The Level 33 2 PSA models were included in the WOG peer reviews mentioned previously. The changes to 34 the Level 2 models to update the methodology and to address the peer review 35 recommendations are described in Sections E.1.4 and E.3.4 of the ER (Entergy 2007) and in 36 response to an RAI concerning peer review findings related to the Level 2 PSA model (Entergy 37 2008a).

38 In the RAI response, Entergy provided a detailed discussion of all the changes that resulted 39 from the incorporation of the WOG peer review of the Level 2 PRA. For IP2, the licensee 40 indicated that there were two Level C F&Os related to the Level 2 analysis. One issue dealt 41 with treatment of containment failure from energetic events (e.g., direct containment heating, 42 hydrogen combustion, in-vessel steam explosions, and ex-vessel steam explosions). The other 43 issue related to treatment of a stuck-open main steam safety valve following an SGTR core NUREG-1437, Supplement 38 G-18 December 2010

Appendix G 1 damage event. Entergy indicated that all peer review recommendations associated with the 2 WOG review were incorporated in Revision 0 of the IP2 PSA (3/2005).

3 For IP3, Entergy indicated that there were six F&Os from the WOG peer review team related to 4 the Level 2 analysis:

5

• One F&O was related to the containment strength that was considered for a plant-6 specific containment structural analysis.

7

• One Level A F&O recommended that the LERF definition include the release of iodine 8 as well as cesium and tellurium.

9

• Two Level B F&Os were related to justification for the value used for ex-vessel 10 explosions, and an overestimation of the Alpha mode-induced containment failure 11 probability.

12

• One Level C F&O recommended crediting repair and recovery of systems that affect 13 containment performance.

14

• One Level D F&O was related to documentation.

15 Entergy indicated that all Level A and B F&Os were resolved and that changes were 16 incorporated as necessary in Revision 1 of the IP3 PSA (6/2001). Entergy also stated that the 17 Level C and D F&Os were addressed, as appropriate, in the next revision of the model 18 (Revision 2, 2/2007).

19 Based on the NRC staffs review of the Level 2 methodology, the fact that the Level 2 model 20 was reviewed in more detail as part of the WOG peer review and updated to address peer 21 review findings, and Entergys responses to the RAIs, the NRC staff concludes that the Level 2 22 PSAs for IP2 and IP3 are technically sound and provide an acceptable basis for evaluating the 23 benefits associated with various SAMAs.

24 As indicated in the ER, the estimated IP2 and IP3 reactor core radionuclide inventories used in 25 the MACCS2 input are based on the current core configuration and a power level of 3216 26 megawatt thermal (MWt). The information was derived from Westinghouse Electric Company, 27 Core Radiation Sources to Support IP2 Power Uprate Project, CN-REA-03-4 (3/7/2005), and 28 Westinghouse Electric Company, Core Radiation Sources to Support IP3 Stretch Power Uprate 29 (SPU) Project, CN-REA-03-40 (5/19/2005). In response to an RAI, Entergy confirmed that the 30 current core design and operational practice are consistent with this analysis and that there are 31 no planned future changes to reactor power level or fuel management strategies that would 32 affect the reactor core radionuclide inventory used in the MACCS2 analysis (Entergy 2008a).

33 The NRC staff reviewed the process used by Entergy to extend the containment performance 34 (Level 2) portion of the PSA to an assessment of offsite consequences (essentially a Level 3 35 PSA). This included consideration of the source terms used to characterize fission product 36 releases for the applicable containment release categories and the major input assumptions 37 used in the offsite consequence analyses. The MACCS2 code was used to estimate offsite 38 consequences. Plant-specific input to the code includes the source terms for each release 39 category and the reactor core radionuclide inventory (both discussed above), site-specific 40 meteorological data, projected population distribution within an 80-kilometer (50-mile) radius for 41 the year 2035, emergency evacuation modeling, and economic data. This information is 42 provided in Sections E.1.5 and E.3.5 of the ER for IP2 and IP3, respectively (Entergy 2007).

December 2010 G-19 NUREG-1437, Supplement 38

Appendix G 1 As described in Sections E.1.5.2.6 and E.3.5.2.6 of the ER, meteorological data for a 5-year 2 period from January 2000 to December 2004 were obtained from the Indian Point onsite 3 meteorological monitoring system. The 5-year data included 43,848 consecutive hourly values 4 of wind speed, wind direction, precipitation, and temperature. Missing data were estimated 5 using data substitution methods. These methods include substitution of missing data with valid 6 data from the previous hour and with data collected from other elevations on the meteorological 7 tower. The data for the 5-year period were averaged to provide a data file consisting of one 8 year of hourly readings representative of site meteorology. This data file was used as input to 9 the MACCS2 code for the SAMA analysis reported in the ER.

10 Subsequent to issuance of the DSEIS, a problem with the process used to numerically average 11 the site-specific meteorological data was identified. Entergy determined that the method used 12 to average the wind direction data was faulty and resulted in a lower frequency of winds blowing 13 toward the south than actually observed. Since a majority of the population near Indian Point is 14 in the southern semicircle of the 50-mile radius, this error resulted in a smaller population dose 15 and a smaller offsite economic cost than would be expected using the corrected method.

16 Accordingly, the dose and economic impacts of a severe accident and the estimated benefits of 17 candidate SAMAs would be larger than was reported in the ER (Entergy 2009).

18 To address the meteorological data errors impact on the SAMA evaluation, Entergy performed 19 a separate MACCS2 analysis for each of the five single years of meteorological data. Entergy 20 compared the results and selected the year that resulted in the largest population dose (year 21 2000) as the representative year for use in the SAMA analysis. This approach circumvents the 22 problem associated with averaging wind directions, and is consistent with the intent of the ER to 23 provide results for representative site meteorology. Entergy updated the population dose and 24 offsite economic cost values for each containment release mode, and the estimated benefits for 25 each SAMA based on the meteorological data for year 2000. The correction in meteorological 26 data resulted in approximately a factor of 4 increase in population dose and offsite economic 27 cost values, and resulted in several additional SAMAs becoming potentially cost-beneficial 28 (Entergy 2009). This is discussed further in Section G.6.1. The NRC staff concludes that the 29 updated approach taken for collecting and applying the meteorological data in the SAMA 30 analysis is reasonable and acceptable. This is discussed further in section G.2.3.

31 The population distribution which the licensee used as input to the MACCS2 analysis was 32 estimated for the year 2035 based on information from the New York Statistical Information 33 System from 2000 to 2030, the New Jersey Department of Labor and Workforce Development 34 from 2000 to 2025, the Connecticut State Data Center from 2000 to 2020, and the Pennsylvania 35 State Data Center from 2000 to 2020. These data were used to project county-level resident 36 populations to the year 2035 using regression analysis. The 2035 transient population was 37 assumed to be the 2004 transient-to-permanent population ratio multiplied by the extrapolated 38 permanent population. The 2004 transient data were obtained from State tourism agencies.

39 The NRC staff notes that Entergys projected 2035 population within a 50-mile radius of IP2 and 40 IP3 reported in Tables E.1-12 and E.3-12 of the Entergy ER (19.2 million people) is 41 approximately 15 percent greater than the 50-mile population obtained from NRC SECPOP2000 42 code (16.8 million) for the year 2003 (NRC 2003). This represents an average annual growth 43 rate of 0.4 percent, which comports with Entergys estimated growth rates reported in Section 44 2.6.1 of the ER. The NRC staff considers the methods and assumptions for estimating 45 population reasonable and acceptable for the purposes of the SAMA evaluation.

NUREG-1437, Supplement 38 G-20 December 2010

Appendix G 1 Entergy did not credit evacuation either as part of the base-case analysis or for estimating the 2 benefit from SAMA cases. Entergy assumed a no evacuation scenario to conservatively 3 estimate the population dose. In response to an NRC staff RAI, Entergy clarified that the no 4 evacuation scenario assumes that individuals within the 10-mile evacuation zone continue 5 normal activity following a postulated accident without taking emergency response actions such 6 as evacuation or sheltering. Relocation actions within a 50-mile radius of the plant are still 7 modeled in the no evacuation scenario. As such, individuals within hot spots or high-radiation 8 areas anywhere within the 50-mile zone are assumed to be relocated outside the 50-mile zone 9 until long-term protective actions reduce radiation levels (Entergy 2008a). As used in the 10 MACCS2 code, evacuation refers to the prompt movement of the population out of an affected 11 region (e.g., certain sectors of the EPZ) during the emergency-phase time period immediately 12 following an accident, in accordance with the emergency evacuation plan. Relocation refers to 13 the movement of the population out of an affected region (e.g., within hot spots or high radiation 14 areas) during the intermediate phase or long term phase based on longer-term dose 15 considerations. The NRC staff concludes that the evacuation and relocation assumptions and 16 analysis are generally conservative and acceptable for the purposes of the SAMA evaluation.

17 Much of the site-specific economic data was obtained from the 2002 Census of Agriculture 18 (USDA 2002). These include the value of farm and nonfarm wealth. Other data, such as 19 population relocation cost, daily cost for a person who is relocated, and cost of farm and 20 nonfarm decontamination were obtained from the Code Manual for MACCS2 (NRC 1997c).

21 The data from the MACCS2 Code Manual were inflation-adjusted using the consumer price 22 index corresponding to the year 2005. Information on regional crops was obtained from the 23 2002 Census of Agriculture. Crops for each county were mapped into the seven MACCS2 crop 24 categories.

25 MACCS2 requires an average value of nonfarm wealth (identified as VALWNF in MACCS2).

26 The county-level nonfarm property value was used as a basis for deriving VALWNF and 27 resulted in a value of $163,631 per person. This does not explicitly account for the economic 28 value associated with tourism and business. In the ER, Entergy assessed the impact of 29 including tourism and business losses using a sensitivity case. This sensitivity case assumed a 30 loss of $208,838 per person in the affected region, as opposed to $163,631 per person in the 31 base case. The NRC staff questioned the basis for the modified VALWNF value ($208,838 per 32 person) and the rationale for treating the loss of tourism and business in a sensitivity case rather 33 than in the baseline analysis (NRC 2007). In response, Entergy described the basis for the 34 modified VALWNF value and explained that the impact of lost tourism and business was not 35 modeled in the baseline analysis because the level of tourism and business activity can be re-36 established in time. Nevertheless, Entergy provided the results of a revised uncertainty analysis 37 using the modified VALWNF value (Entergy 2008a). As a result, three additional potentially 38 cost-beneficial SAMAs were identified (SAMAs 9 and 53 for IP2 and SAMA 53 for IP3). In 39 response to an RAI, Entergy indicated that these SAMAs have been submitted for engineering 40 project cost-benefit analysis to obtain a more detailed examination of their viability and 41 implementation costs (Entergy 2008b). As described in Section G.6.2, the NRC staff has 42 adopted the case incorporating lost tourism and business as its base case, given that it may 43 take years to re-establish the level of tourism and business activity following a severe accident.

44 In the draft SEIS, the NRC staff reached a preliminary conclusion that the methodology used by 45 Entergy to estimate the offsite consequences for IP2 and IP3 provides an acceptable basis from December 2010 G-21 NUREG-1437, Supplement 38

Appendix G 1 which to proceed with an assessment of candidate SAMAs. A further assessment of the 2 methodology was subsequently performed by the NRC staff of issues raised in a petition by 3 New York State (NYS) to intervene in the license renewal proceeding. As described below in 4 Section G.2.3, the NRC staff reaffirms its original conclusion that the methodology used by 5 Entergy to estimate the offsite consequences for Indian Point, as amended in Entergy=s SAMA 6 re-analysis (Entergy 2009), provides an acceptable basis from which to proceed with an 7 assessment of candidate SAMAs.

8 G.2.3 Review of Issues Related to NYS Contentions 12 and 16 9 On November 30, 2007, New York State (NYS) filed a petition to intervene in the Indian Point 10 license renewal proceeding, in which it filed various contentions, including two contentions 11 challenging Entergy=s SAMA analysis, asserting that the analysis was flawed based, in part, on 12 its use of certain input data for the MACCS2 code and the ATMOS air dispersion module. The 13 Atomic Safety Licensing Board (Board) admitted NYS Contentions 12 and 16 related to the 14 SAMA analysis on July 31, 2008.

15 On February 27, 2009, NYS filed Amended Contentions 12A and 16A, challenging the NRC 16 staffs evaluation and preliminary conclusions regarding Entergys SAMA analysis as set forth in 17 the DSEIS. On June 16, 2009, the Board admitted amended contentions NYS 12A and 16A, 18 and consolidated them with original contentions NYS 12 and 16. As admitted by the Board, 19 NYS Contention 12/12A challenges whether specific inputs and assumptions related to clean-up 20 and decontamination costs are correct for the area surrounding Indian Point, and NYS 21 Contention 16/16A challenges: (1) whether the population projections used by Entergy are 22 underestimated, (2) whether the ATMOS module in MACCS2 is being used beyond its range of 23 validity (beyond thirty-one miles), and (3) whether use of MACCS2 with the ATMOS module 24 leads to non-conservative geographical distribution of radioactive dose within a fifty-mile radius 25 of Indian Point.

26 On March 11, 2010, NYS filed Amended Contentions 12B and 16B, challenging various aspects 27 of Entergys December 2009 SAMA Reanalysis - which, using revised meteorological data, had 28 produced revised estimates of offsite population doses and economic costs, and revised SAMA 29 analysis results (including six additional potentially cost-beneficial SAMAs). On June 30, 2010, 30 the Board admitted NYS Contentions 12B and 16B (in part), and consolidated them with NYS 31 Contentions 12/12A and 16/16A. Entergy Nuclear Operations, Inc. (Indian Point Nuclear 32 Generating Units 2 and 3), LBP-10-13, 71 NRC (2010), slip op. at 10, 14-15.

33 In reviewing the issues raised in these contentions, the NRC staff obtained the technical 34 assistance of Sandia National Laboratory (Sandia). The NRC staff and Sandia performed a 35 comprehensive review of relevant documents and references, including the ER, the draft SEIS, 36 the MACCS2 input decks for Indian Point and associated documentation, the NYS contentions 37 and supporting documents and references, the Boards rulings on the contentions, and other 38 relevant filings in the adjudicatory proceeding. A summary of the staff=s assessment of the 39 issues raised in the admitted contentions is provided below.

40 Clean-up and Decontamination Costs (NYS Contention 12/12A/12B) 41 NYS Contention 12/12A/12B argues that the size of the particles dispersed from a severe 42 reactor accident would be comparable to those released in nuclear weapons tests, smaller than 43 the particle size considered in MACCS2, and that it will be more expensive to decontaminate NUREG-1437, Supplement 38 G-22 December 2010

Appendix G 1 and clean-up a suburban/urban area in which small-sized radionuclide particles have been 2 dispersed. NYS defines large-sized particles as ranging in size from tens to hundreds of 3 microns and defines small particles as ranging in size from a fraction of a micron to a few 4 microns.

5 The staff and Sandia reviewed the inputs and assumptions regarding particle size distribution 6 and decontamination costs used in the SAMA analysis, and determined that the particle size 7 utilized in the analysis was reasonable and acceptable. In this regard, in the MACCS2 input 8 files (atmbi2NS.inp and atmbi3NS.inp), Entergy used a dry deposition velocity value of 0.01 9 meters per second (m/s) for all aerosol particles. A deposition velocity of 0.01 m/s corresponds 10 to approximately a 5 to 10 micron radius particle, based on gravitational settling of small 11 spheres in dilute laminar flow fields. Thus, the MACCS2 dispersion does not assume that the 12 dispersion will consist of large-sized radionuclide particles as NYS contends. While smaller (or 13 larger) particle sizes could have been used in the analysis, the particle size utilized in the 14 analysis was relatively small, is consistent with the accepted SAMA analyses performed for 15 other nuclear power plants, and is acceptable. With respect to the estimated decontamination 16 costs used in Entergys MACCS2 SAMA analysis, the staff found that Entergys estimated 17 decontamination costs were reasonable and acceptable, as described below.

18 In the MACCS2 input files, Entergy used decontamination cost parameters that were typically 19 higher than the MACCS2 Sample Problem A values by a factor of 1.7. (Sample Problem A 20 values were primarily developed for the Surry plant analysis in NUREG-1150 and represent best 21 estimate information for that site and time.) As described in the ER, the values were obtained 22 by adjusting the generic Sample Problem A economic data with the consumer price index of 23 195.3, which accounts for inflation between 1986 and 2005. Farm and nonfarm values for 24 Indian Point were based on site-specific data and were not extrapolated from Sample Problem 25 A. NYS suggests that in place of the outdated decontamination cost figures used by Entergy, 26 the methodology described in a Sandia document, SAND96-0957, Site Restoration: Estimation 27 of Attributable Costs from Plutonium-Dispersal Accident should be used in establishing 28 decontamination values for input to MACCS2. The NRC staff does not consider the 29 methodology for clean-up of a nuclear weapons accident relevant to clean-up following a 30 nuclear power plant (NPP) accident. Nonetheless, at the staffs request, Sandia performed a 31 comparison of the decontamination cost factors derived from the Site Restoration study to those 32 used in the SAMA analysis. The approach to the cost comparison included identifying basic 33 considerations of each type of accident (e.g., contaminants, half life of contaminants, and health 34 and safety considerations), identifying the decontamination methods required, and comparing 35 the Site Restoration study cost values (as applied to the urban area of New York City) to those 36 used in Entergys analysis.

37 Sandia noted that the primary constituent in weapons grade plutonium, Pu239, is an alpha 38 emitter, whereas the primary contaminant from an NPP accident, Cs137, is a gamma emitter.

39 As such, Pu239 is more difficult and expensive to characterize and verify in the field than 40 gamma emitters like Cs137. Furthermore, Pu239 is primarily an inhalation hazard with half-life 41 of 24,000 years, whereas Cs137 is primarily an external health hazard with half-life of about 30 42 years. The need for evacuating the public is much greater with plutonium because if inhaled, 43 the health consequences can be severe.

44 Both the Site Restoration study and the MACCS2 model consider the extent of decontamination 45 required in determining decontamination costs. This is typically expressed as a December 2010 G-23 NUREG-1437, Supplement 38

Appendix G 1 decontamination factor (DF) which represents the ratio of the contamination level before and 2 after clean-up. The Site Restoration study provides cost estimates for remediation of light 3 contamination (DF=2 to 5), moderate contamination (DF=5 to 10), and heavy contamination 4 (DF>10). Appendix F of the Site Restoration study describes the decontamination methods for 5 light, moderate, and heavy contamination by plutonium. For the Indian Point MACCS2 model, 6 Entergy provided decontamination cost input values for two levels of remediation, specifically, a 7 DF of 3 and a DF of 15. Sandia considered the decontamination activities described in the Site 8 Restoration study together with the differences in health hazards posed by Pu239 versus 9 Cs137, and concluded that the activities required to support clean-up of moderate plutonium 10 contamination align more closely with clean-up activities for heavy cesium contamination.

11 Sandia performed the comparison of decontamination cost values on this basis.

12 Sandia conservatively limited its cost comparison to urban areas (non-farmland) because urban 13 areas are more costly to decontaminate than farmland, and because farmland makes up a very 14 small percentage of land area within the Indian Point area, with most counties having less than 15 1 percent farmland. To further simplify the cost analysis and provide a comparison of the 16 highest cost areas, the cost comparison was performed only for New York City, which includes 17 five counties (the Bronx, Kings, New York, Queens, and Richmond). The population density of 18 New York City is about 12,000 persons/km2.

19 As described above, the decontamination activities for moderate plutonium contamination are 20 most directly comparable to the decontamination activities for heavy cesium contamination. The 21 Site Restoration study (Table 6-2) provides an estimated cost of $178.4 million/km2 for clean-up 22 of moderate plutonium contamination in urban areas, or $14,900 per person when expressed on 23 a per capita basis for New York City. In contrast, a cost of $13,824 per person was used in 24 Entergys MACCS2 analysis for decontamination of heavy cesium contamination. Thus, the 25 decontamination cost from the Site Restoration study ($14,900 per person) is not significantly 26 different than the value used by Entergy in the SAMA analysis ($13,824 per person). If the Site 27 Restoration study values were escalated to 2005 dollars, as were the values used in the SAMA 28 analysis, the difference would be greater, but would still be within a factor of about 2, The 29 differential dollar cost attributable to this difference would vary depending upon the size of the 30 area (i.e., the number of people) that would need to be evacuated. Thus, using the Site 31 Restoration study values, decontamination could cost more than was estimated in Entergys 32 analysis; however, it could also cost less than Entergy estimated, inasmuch as the SAMA 33 analysis assumed the dispersal of heavy contamination. Considering the uncertainties 34 inherent in such predictions, Entergys decontamination cost estimates appear reasonable and 35 acceptable. Further, Entergys decontamination cost estimates are consistent with those used 36 in accepted SAMA analyses performed for other nuclear power plants.

37 Population Projections (NYS Contention 16/16A/16B) 38 NYS Contention 16/16A/16B argues that Entergys projections of the 2035 population living 39 within the 50-mile radius of Indian Point underestimate the potential exposed population. The 40 staff and Sandia reviewed Entergys baseline and projected population values and its population 41 projection methodology, and developed independent estimates of the baseline and projected 42 population. Entergy obtained population estimates directly from State agency reports for 43 periods ranging from 2000 to 2020 and 2000 to 2030, depending on the State data available.

44 Entergy projected total permanent populations to the year 2035 for 25 of the 28 counties that 45 are within or encroach upon the limit of 50 miles from Indian Point using linear extrapolation.

NUREG-1437, Supplement 38 G-24 December 2010

Appendix G 1 Entergy used areal weighting, which assumes a constant population distribution over the area 2 assessed (i.e., in each of the 160 cells within the 16 sectors and radial rings representing the 3 50-mile radius surrounding the IP site), to establish fractional population within 50 miles of 4 Indian Point. Entergy then adjusted this permanent population projection upward to account for 5 the presence of the transient (tourist) population as estimated from available tourist information.

6 For the remaining three counties, including New York (Manhattan), Rockland, and Westchester 7 counties, Entergy used polynomial regression for projecting the population. A polynomial 8 regression appears to have been used for these counties because State data shows a decrease 9 in the population of these counties. The population for these counties was projected by the 10 State to increase from 2000 to 2020 and then decrease from 2020 to 2030 resulting in a peak 11 population in 2020. Because there is a peak within the projection period, Sandia agreed that 12 use of a polynomial projection to the year 2035 is a more appropriate approach than a linear 13 projection for these counties. Entergy estimated the year 2000 permanent population within the 14 50-mile radius of Indian Point to be 16,914,178. Entergy projected the permanent population 15 out to 2035 to be 18,879,657, an increase of 12.43 percent. The population Entergy used in its 16 SAMA analysis was 19,228,714, which accounts for the transient population, as described 17 above.

18 Sandia performed an independent assessment of the population data within a 50-mile radius of 19 Indian Point using the SECPOP2000 computer program. The population data in SECPOP2000 20 is based on 2000 U.S. Census Bureau data. The population for the year 2000 estimated by 21 SECPOP2000 is 16,800,272; this compares very closely with Entergys year 2000 estimate of 22 the permanent population within the 50-mile radius (16,914,178).

23 Sandia also performed two analyses of projected population growth to the year 2035, and 24 determined that Entergys projected population growth was reasonable. The first evaluation 25 was based on the US Census Bureaus projected growth from 2000 to 2008 for the Northeast 26 region of the US. During these 8 years, the projected growth is 2.344 percent; based on this 27 number, the annualized growth rate for the Northeast region of the country is 0.2900 percent.

28 Assuming a constant growth rate between the years 2000 and 2035 results in an estimated 29 growth of 10.67 percent. This estimate is lower than the Entergy value of 12.43 percent. The 30 second evaluation used the same year 2000 population for the 28 counties surrounding Indian 31 Point as used by Entergy, but used a simpler method than Entergy for extrapolating out to 2035.

32 The annualized growth rate was calculated starting from the 2000 census values to the final 33 (latest) year projected by each of the states. Assuming this growth rate to continue through 34 2035, the estimated growth for the 28 counties is 15.98 percent. This value is larger than 35 Entergys projected growth of 12.43 percent, but the difference is small. Thus, the two 36 evaluations performed by Sandia bound the Entergy projection for population growth.

37 38 Finally, Sandia performed a separate population projection for the five counties comprising New 39 York City. For New York, Queens, and Richmond Counties, Sandia projected slightly higher 40 populations than Entergy. For Bronx and Kings Counties, Entergy projected higher populations.

41 The difference between the Sandia and Entergy population projections for all 5 counties is only 42 0.39 percent. The NRC staff concludes that Entergys population data and projected population 43 growth analysis provide reasonable (and slightly conservative) population values for its SAMA 44 analysis.

December 2010 G-25 NUREG-1437, Supplement 38

Appendix G 1 Validity of ATMOS Model (NYS Contention 16/16A/16B) 2 NYS Contention 16/16A/16B argues that the ATMOS air dispersion module utilized in the 3 MACCS2 code is being used beyond its range of validity (beyond thirty-one miles), which could 4 affect the validity of decontamination cost estimates for areas beyond that range. The NRC 5 staff and Sandia National Laboratory addressed this issue in detail, in the NRC staffs October 6 13, 2009 response to a NYS motion for partial summary disposition. In brief, the NRC staff and 7 Sandia considered the States concern, and concluded that ATMOS air dispersion module 8 provides an acceptable means for estimating potential plume travel and dispersion in a 9 probabilistic statistical analysis, and is acceptable for use with the MACCS2 code, in which a 10 probabilistic analysis is performed for a large number of meteorological trials, which are subject 11 to hourly variation. Further, this conclusion is supported by a comparison of the results 12 produced by MACCS2 analyses using the ATMOS module with the results of analyses 13 performed with other codes.

14 ATMOS is a Gaussian plume model within MACCS2 that treats plume segments under different 15 weather conditions based on hourly changes from the site meteorological data. The 16 meteorological data considered for each segment include wind speed, direction, stability class, 17 and precipitation. Once a plume is formed, the direction does not change; however, the wind 18 speed, stability class, and precipitation rate can change hour-by-hour based on the 19 meteorological data.

20 The MACCS2 code considers, among other things, phenomena related to atmospheric transport 21 and deposition under time-variant meteorology, short- and long-term mitigative actions, potential 22 exposure pathways, deterministic and stochastic health effects, and economic costs. The 23 MACCS2 code samples the meteorological data from an entire year and uses wind rose data to 24 account for the plume traveling through all 16 compass sectors to ensure that all the potential 25 plume paths are accounted for in the calculations. This ensures that likely impacts for the entire 26 area within a 50-mile radius have an accurate statistical model for likelihood of a plume reaching 27 that area and its expected concentration. The MACCS2 model generates average or expected 28 values of metrics of interest considering all of the relevant dose pathways, including the food 29 and water pathway, and covering essentially a lifetime of exposure to a contaminated 30 environment.

31 Questions regarding the adequacy of averaging metrics of interest over numerous weather 32 sequences have been studied in detail. This included a detailed code comparison completed in 33 2004 with the objective of determining if the average atmospheric transport and dispersion 34 results from codes such as MACCS2 are sufficiently accurate that more complex models are not 35 required. In that study, results from the MACCS2 code were directly compared to those from 36 the LODI (Lagrangian Operational Dispersion Integrator) code and the RASCAL 3.0 37 (Radiological Assessment System for Consequence Analysis, Version 3.0) code.

38 LODI is a state-of-the-art, three-dimensional (3D) advection dispersion code that uses a 39 Lagrangian stochastic Monte Carlo method. LODI is coupled to ADAPT (Atmospheric Data 40 Assimilation and Parameterization Technique), which provides time-varying, 3D fields of mean 41 winds, turbulence, pressure, temperature, and precipitation based on observed meteorology.

42 LODI is an element of the National Atmospheric Release Advisory Center (NARAC) emergency 43 response modeling system at Lawrence Livermore National Laboratory (LLNL) which is a 44 national support and resource center for planning, real-time assessment, emergency response, NUREG-1437, Supplement 38 G-26 December 2010

Appendix G 1 and detailed studies of incidents involving the spread of hazardous material accidentally or 2 intentionally released into the atmosphere.

3 RASCAL 3.0 is used by the NRC for emergency response applications where a rapid response 4 is required. The NRC evaluates accident conditions using RASCAL and compares results to 5 those produced by NARAC during an accident. RASCAL 3.0 contains atmospheric transport 6 and dispersion components that are intermediate in complexity between MACCS2 and ADAPT/

7 LODI. RASCAL employs time-varying, two-dimensional meteorological fields of wind, stability, 8 and precipitation based on surface-level meteorological observations as input to a Lagrangian 9 trajectory transport model and a Gaussian puff dispersion model. While the dispersion portions 10 of RASCAL 3.0 are similar to those of MACCS2, the transport portions are significantly different.

11 The capabilities of RASCAL 3.0 are similar to those of the dispersion models CALPUFF and 12 AERMOD, which were recommended by NYS.

13 As documented in NUREG/CR-6853, Comparison of Average Transport and Dispersion Among 14 a Gaussian, a Two-Dimensional, and a Three-Dimensional Model, this comparison shows that 15 MACCS2 provides results consistent with those from the more complex plume models at 16 distances up to 100 miles. This is well beyond the 50-mile radius considered in the SAMA 17 analysis. The MACCS2 predictions for average, time-integrated, ground-level air concentrations 18 (which directly relates to inhalation and cloudshine doses), and for average deposition (which 19 directly relates to groundshine and ingestion pathway doses) were very comparable to 20 predictions made by the state-of-the-art NARAC codes, ADAPT/LODI, at all distances. The 21 direct comparison to state-of-the-art codes demonstrates that MACCS2 is well within its range 22 of validity when used to perform SAMA analyses.

23 Geographical Distribution of Radioactive Contamination and Dose (NYS Contention 24 16/16A/16B) 25 NYS Contention 16/16A/16B also argues that use of MACCS2 with the ATMOS module leads to 26 a non-conservative geographical distribution of radioactive dose and radionuclide contamination 27 within a 50-mile radius of Indian Point, which could affect the validity of dose and contamination 28 cost estimates within that area. The staff and Sandia considered the States concerns regarding 29 ATMOS, and concluded that ATMOS provides an acceptable plume model for the calculation of 30 doses and radioactive contamination in a SAMA analysis. In response to this concern, Sandia 31 assessed the impact of using a Gaussian plume model on accident consequences, and 32 evaluated the population distribution and meteorological data used in Entergys SAMA analysis.

33 The Gaussian plume model used in ATMOS assumes that the plume travels in a straight line.

34 For Indian Point, this would minimize the distance the plume would travel in reaching the 35 highest population areas, which are near the periphery of the 50-mile radius. The Gaussian 36 plume model provides further conservatism under variable terrain conditions. Specifically, when 37 variable terrain features such as river embankments or mountains intervene between a source 38 and an observation point, these features would tend to disperse and dilute the plume as it is 39 forced to move around obstacles. The plume model conservatively estimates that the plume 40 travels in a straight line over or through the obstacle, thereby resulting in larger accumulated 41 radiological doses and higher estimates of economic consequences in areas farther from the 42 plant.

43 Although there are large geographic variations of population density within 50 miles of Indian 44 Point, the evaluation of population distribution shows that the largest populations are located at December 2010 G-27 NUREG-1437, Supplement 38

Appendix G 1 the furthest distances within the 50-mile radius surrounding the site (i.e., in the New York City 2 metropolitan area located about 30 to 50 miles south [SSE to SSW] of the Indian Point site).

3 The shorter path of travel associated with the Gaussian plume model, together with the 4 dominant wind direction being toward New York City (discussed below), ensures that a 5 conservatively large amount of contaminant reaches the areas with higher population density in 6 the MACCS2 analysis. Accordingly, use of the ATMOS module would result in a conservative 7 geographical distribution of radioactive dose within a 50-mile radius of Indian Point relative to 8 other atmospheric transport models.

9 Sandia reviewed the MACCS2 input files used in the Entergy baseline analysis to determine 10 whether input parameter selection might contribute to non-conservative geographical 11 distribution of radioactive dose within the 50-mile radius of Indian Point. Most of the input 12 parameters used by Entergy in the MACCS2 analyses were standard choices consistent with 13 Sample Problem A that is distributed with the MACCS2 code. The following input choices were 14 specifically reviewed by Sandia:

15

• Meteorology - In the SAMA analysis described in the ER, Entergy averaged 16 meteorological data for a 5-year period to provide a data file consisting of one year of 17 hourly readings representative of site meteorology. After the staff raised questions 18 concerning the weather data used in the analysis, Entergy submitted an updated 19 MACCS2 input file which uses a single weather year with conservative data and corrects 20 the wind rose data. The use of a single years data is consistent with regulatory 21 guidance; further, the wind direction in the updated file is predominantly to the south 22 (toward New York City), consistent with information reported elsewhere for Indian Point 23 (e.g., in annual effluent reports between 1999 through 2002). Thus, the staffs concern 24 regarding wind direction has been resolved in the updated analysis.

25

• Population - The population values in the MACCS2 input files are consistent with the 26 values reported in the ER. The population values were also found to be consistent with 27 the US Census data as discussed above. The 2035 projected population value of 28 19,228,712 used by Entergy was reviewed and found to be reasonable. Sandia 29 confirmed that Entergys population projections for New York City, which is in the 30 dominant downwind plume direction, are reasonable. Further, Entergys use of 31 populations accounting for tourists was found to be reasonable and to provide a slightly 32 higher estimated cost.

33

• Dry Deposition Velocity - The dry deposition velocity of 0.01 m/s corresponds to a 34 relatively small particle size. Within the plume model, small particle sizes will travel 35 greater distances than large particle sizes. Therefore, smaller particle sizes would favor 36 deposition at the higher population locations farther from the site, and would likely result 37 in greater population dose and greater decontamination costs because the areas farther 38 away from the plant are more densely populated urban areas which have higher 39 decontamination costs. While smaller or larger particle sizes could have been used in 40 the analysis, the particle size that Entergy used is reasonable and acceptable.

41

• Plume representation - Releases to the environment were modeled as a single 42 Gaussian plume in the SAMA analysis. While Entergys analysis utilized a single plume, 43 MACCS2 has the ability to divide the plume into a number of plume segments. Use of 44 additional plume segments would likely result in some variation in wind direction, NUREG-1437, Supplement 38 G-28 December 2010

Appendix G 1 dispersing the radiation and resulting in lower peak doses to the public. For purposes of 2 a SAMA analysis, however, the results of a single isolated meteorological data trial is not 3 at issue; rather, the analysis should model the results of numerous meteorological trials 4 that provide a mean dispersion over the entire 50-mile radius. Such modeling 5 necessarily includes variations in wind direction. The end result of conducting multiple 6 meteorological trials is the calculation of a mean atmospheric transport, which describes 7 the expected amount and timing of the contaminant release reaching any area within a 8 50-mile radius. This calculation allows for the determination of the mean effect on dose 9 and economic costs for each modeled event that could occur at some time in the future 10 under unknown weather conditions. The NRC staff notes that a SAMA analysis is not 11 meant to provide a prediction of the contamination for any specific weather event; rather, 12 it provides a mean result for a type of event under the mean potential circumstances.

13 The use of a single Gaussian plume in each trial in the SAMA analysis provides a 14 reasonable and acceptable approach for this purpose.

15

• Spatial grid - The MACCS2 analysis considered consequences with a 50-mile radius of 16 the Indian Point site. This is consistent with NRC guidance for regulatory analysis as 17 provided in NUREG/BR-0184.

18

• Decontamination costs - Decontamination costs were based on Sample Problem A and 19 adjusted for inflation using the consumer price index factor. A comparison of Entergys 20 input values with those derived from the Site Restoration study shows the values are in 21 reasonable agreement.

22

• Emergency evacuation - The emergency phase evacuation was not modeled in the 23 Entergy analysis. Entergy claims that this is more conservative than using the radial 24 evacuation approach applied in Sample Problem A. The emergency evacuation 25 treatment is not expected to significantly affect the SAMA results (e.g., total population 26 dose and offsite economic cost risk) because these metrics are typically driven by 27 doses/deposition well beyond the 10-mile emergency planning zone.

28 Based on the NRC staffs and Sandias review, the ATMOS module and MACCS2 input 29 parameters used by Entergy are reasonable and acceptable, and do not result in a non-30 conservative geographical distribution of radioactive dose and contamination within a 50-mile 31 radius of Indian Point.

32 Summary 33 The NRC staff, with the assistance of Sandia National Laboratory, evaluated the concerns 34 raised in NYS Contentions 12/12A/12B and 16/16A/16B. Based on this review, the staff 35 concludes that the issues raised in these contentions do not alter the staffs conclusions, set 36 forth in the DSEIS, regarding the acceptability of Entergys SAMA analysis. Accordingly, the 37 NRC concludes that Entergys use of the MACCS2 code, including the inputs and ATMOS 38 module used to estimate offsite consequences for Indian Point, as amended in Entergys SAMA 39 re-analysis, provides an acceptable methodology for use in the assessment of candidate 40 SAMAs.

41 G.3 Potential Plant Improvements December 2010 G-29 NUREG-1437, Supplement 38

Appendix G 1 This section discusses the process for identifying potential plant improvements, an evaluation of 2 that process, and the improvements evaluated in detail by Entergy.

3 G.3.1. Process for Identifying Potential Plant Improvements 4 Entergys process for identifying potential plant improvements (SAMAs) consisted of the 5 following elements:

6

• The review of the most significant basic events from the current, plant-specific PSA; 7

• The review of potential plant improvements identified in the IP2 and IP3 IPE and IPEEE; 8

• The review of Phase II SAMAs from license renewal applications for nine other 9 pressurized water reactors; 10

• The review of dominant contributors to seismic and fire events in the current seismic and 11 fire analyses; 12

• The review of other NRC and industry documentation discussing potential plant 13 improvements.

14 Based on this process, an initial set of 231 candidate SAMAs for IP2 and 237 candidate SAMAs 15 for IP3, referred to as Phase I SAMAs, was identified. In Phase I of the evaluation, Entergy 16 performed a qualitative screening of the initial list of SAMAs and eliminated SAMAs from further 17 consideration using one of the following criteria:

18

• The SAMA is not applicable at IP2 and IP3 because of design differences.

19

• The SAMA has already been implemented at IP2 and IP3.

20

• The SAMA is similar in nature and could be combined with another SAMA candidate.

21 Based on this screening, 163 IP2 SAMAs and 175 IP3 SAMAs were eliminated, leaving 68 22 unique SAMAs for IP2 and 62 unique SAMAs for IP3. The remaining SAMAs, referred to as 23 Phase II SAMAs, are listed in Tables E.2-2 and E.4-2 of the ER (Entergy 2007). In Phase II, a 24 detailed evaluation was performed for each of the remaining SAMA candidates, as discussed in 25 Sections G.4 and G.6 below. To account for the potential impact of external events, the 26 estimated benefits based on internal events were multiplied by a factor of 3.8 for IP2 and 5.5 for 27 IP3, as previously discussed.

28 G.3.2. Review of Entergys Process 29 Entergys efforts to identify potential SAMAs focused primarily on areas associated with internal 30 initiating events but also included explicit consideration of potential SAMAs for seismic and fire.

31 The initial list of SAMAs generally addressed the accident sequences considered to be 32 important to CDF from functional, initiating event, and risk-reduction worth (RRW) perspectives 33 at IP2 and IP3 and included selected SAMAs from prior SAMA analyses for other plants.

34 Entergy provided a tabular listing of the PSA basic events, sorted according to their RRW for 35 CDF (Entergy 2007). SAMAs affecting these basic events would have the greatest potential for 36 reducing risk. Entergy used an RRW cutoff of 1.005, which corresponds to about a 0.5-percent 37 change in CDF, given the 100 -percent reliability of the SAMA. This equates to a benefit of 38 approximately $7,000 for IP2 and IP3 (based on a total benefit of about $1.3 million for each unit NUREG-1437, Supplement 38 G-30 December 2010

Appendix G 1 for eliminating all severe accidents caused by internal events). Entergy also provided and 2 reviewed the LERF-based RRW events down to an RRW of 1.005. Entergy correlated the top 3 CDF and LERF events with the SAMAs evaluated in Phase I or Phase II and showed that, with 4 a few exceptions, all of the significant basic events are addressed by one or more SAMAs 5 (Entergy 2007). Of the basic events of high-risk importance that are not addressed by SAMAs, 6 each is closely tied to other basic events that had been addressed by one or more SAMAs.

7 Entergy considered the potential plant improvements described in the IPE and IPEEE in the 8 identification of plant-specific candidate SAMAs for internal and external events. As a result of 9 the IPE, four major procedural/hardware improvements were identified for each unit. The IP2 10 enhancements are to (1) upgrade IP2 gas turbine black-start capability, (2) install an additional 11 EDG building fan, (3) monitor changes in the operating position of PORV block valves, and (4) 12 implement periodic testing of all the EDG building fans. The IP3 enhancements are to (1) revise 13 emergency operating procedures (EOPs) to instruct operators to align the backup city water 14 supply to the AFW pumps, should the CST outlet valve fail as indicated by a low-suction-flow 15 alarm, (2) revise the alarm response procedure for a high AFW pump room temperature, to 16 direct operators to open the rollup door to the AFW pump room for ventilation, (3) install a 17 switchgear room high-temperature alarm and implement an associated procedure to direct 18 operators to block open doors to the 480-V ac switchgear room, and (4) revise EOPs to 19 emphasize the need to align the safe-shutdown equipment to MCC 312A during events 20 involving the loss of all 480-V ac safeguard buses while offsite power is available, as well as 21 during fire-related events. These improvements have all been implemented and therefore were 22 not considered further in the SAMA analysis.

23 As a result of the IPEEEs, several improvements were identified for external events. The IP2 24 enhancements are to (1) replace the hold-down bolts for the CCW surge tank with higher tensile 25 strength bolts, (2) add surveillance of the control building drain flapper valve flow, (3) add 26 weather stripping to doors between the transformer area and the switchgear room, and (4) add 27 screens on the 480-V switchgear room equipment. The IP3 enhancements are to (1) restore 28 the carbon dioxide (CO2) suppression system to automatic mode within the switchgear room, 29 (2) reroute the EDG exhaust fans and the auxiliary cables so that a fire in a single EDG cell 30 would not affect multiple EDGs, and (3) install an excess flow valve to reduce the risk 31 associated with hydrogen explosions inside the turbine building or PAB. With the exception of 32 the last item, all of these improvements have been implemented and therefore were not 33 considered further in the SAMA analysis. As noted in Section E.3.3.3 of the ER, IP3 SAMA 53 34 (install an excess flow valve to reduce the risk associated with hydrogen explosions) was 35 proposed as a result of the IPEEE analysis and retained for the Phase II evaluation.

36 Several concerns were raised in the IPEEE regarding the seismic-induced failures of fire 37 protection equipment (primarily for IP3). As mentioned above, these seismic-fire interactions 38 were judged to be of little risk significance (NRC 2001). One plant improvement identified in 39 Table 2.4 of NUREG-1742 (NRC 2002) addressed the potential spurious operation of the EDG 40 rooms CO2 system and subsequent shutdown of the EDG ventilation system during a seismic 41 event. Entergy subsequently installed a quality assurance Category I, seismic class I actuation 42 permission auxiliary control panel for CO2 discharge into the EDG building. Since shutdown of 43 EDG ventilation caused by spurious operation of the CO2 system during a seismic event is not 44 considered in the seismic PSA model, the seismic CDF was not affected by this modification.

December 2010 G-31 NUREG-1437, Supplement 38

Appendix G 1 As noted in Section E.1.3.3.1 of the ER, the IP2 CDF for SBO events with gas turbines 2 unavailable could be reduced by (1) aligning the IP3 Appendix R diesel to IP2, (2) installing an 3 IP2 Appendix R diesel, (3) upgrading the EDG building for high winds, and (4) protecting the 4 alternate power source from tornadoes and high winds. However, with the exception of the third 5 item, these modifications were not evaluated as candidate SAMAs because a modification to 6 replace the existing gas turbines with an IP2 SBO/Appendix R diesel generator capable of being 7 used to recover power to the vital buses following an SBO was planned for the near future. The 8 planned modification included provisions for aligning the IP3 Appendix R generator to IP2 and 9 for protecting the new alternate power source from tornadoes and high winds.1 10 For a number of the Phase II SAMAs listed in the ER, the NRC staff found that information 11 provided did not sufficiently describe the proposed modifications or other considerations that 12 might have been taken into account in estimating the benefit and implementation cost.

13 Therefore, the NRC staff requested, and the licensee provided, more information on certain 14 proposed modifications listed for the Phase II SAMA candidates (NRC 2007, Entergy 2008a).

15 For several SAMA candidates, the NRC staff questioned if lower cost alternatives could have 16 been considered, including:

17

• The implementation of improved instrumentation and procedures to help cool down and 18 depressurize the RCS before RWST depletion.

19

• The implementation of a procedure for recovery of the steam dump to condenser from 20 the unaffected steam generator.

21

• The implementation of a procedure for recovery of the main feedwater valve/condensate 22 post-SI actuation.

23

• The purchase or manufacture of a gagging device that could be used to close a stuck-24 open steam generator safety valve on an SGTR before core damage occurred.

25

• The reactivation of the IP3 postaccident containment venting system (a system that is 26 still active on IP2 but was deactivated on IP3).

27 In response, Entergy indicated that most of the low-cost alternatives to aid in the mitigation of an 28 SGTR (four out of the five alternatives dismissed above) have been already implemented and 29 provided specific reasons why the cost of these alternative SAMA candidates would be high 30 enough that the decision on the final SAMA selection would not have been affected. However, 31 the alternative associated with the gagging device was found to be potentially cost beneficial 32 (Entergy 2008a, Entergy 2008b). The evaluation of these SAMAs is discussed further in 33 Section G.6.2.

34 The NRC staff notes that the set of SAMAs submitted is not all inclusive, since additional, 35 possibly even less expensive, design alternatives can always be postulated. However, the NRC 36 staff concludes that the benefits of any additional modifications are unlikely to exceed the 37 benefits of the modifications evaluated and that the alternative improvements would not likely 38 cost less than the least expensive alternatives evaluated, when the subsidiary costs associated 39 with maintenance, procedures, and training are considered.

1 Installation of this diesel was made a condition of acceptance of the License Renewal Application (LRA) for review.

The diesel was installed and operated prior to 4/30/2008. See Entergy letter NL-08-074, Indian Point, Units 2 and 3, Amendment 4 to LRA April 30, 2008 (ML081280491).

NUREG-1437, Supplement 38 G-32 December 2010

Appendix G 1 The NRC staff concludes that Entergy used a systematic and comprehensive process for 2 identifying potential plant improvements for IP2 and IP3 and that the set of SAMAs evaluated in 3 the ER, together with those identified in response to the NRC staff inquiries, is reasonably 4 comprehensive and therefore acceptable. The search included reviewing insights from the 5 plant-specific risk studies and reviewing plant improvements considered in previous SAMA 6 analyses. While explicit treatment of external events in the SAMA identification process was 7 limited, the NRC staff recognizes that the prior implementation of plant modifications for seismic 8 and fire events, and the absence of external-event vulnerabilities, reasonably justifies examining 9 primarily the internal-event risk results for this purpose.

10 G.4 Risk-Reduction Potential of Plant Improvements 11 Entergy evaluated the risk-reduction potential of the remaining 68 IP2 and 62 IP3 SAMAs. The 12 SAMA evaluations were performed using realistic assumptions with some conservatism. On 13 balance, such calculations overestimate the benefits and are conservative.

14 For all of the SAMAs, Entergy used model requantification to determine the potential benefits.

15 The CDF and population-dose reductions were estimated using the latest version of the IP2 and 16 IP3 PSA models. The changes made to the models to quantify the impact of the SAMAs are 17 detailed in Tables E.2-2 and E.4-2 of the ER (Entergy 2007). Table G-6 lists the assumptions 18 considered to estimate the risk reduction for each of the evaluated SAMAs, the estimated risk 19 reduction in terms of the percentage of reduction in CDF and population dose, and the 20 estimated total benefit (present value) of the averted risk. The estimated benefits reported in 21 Table G-6 reflect the combined benefit for both internal and external events and the correction 22 of the meteorological data error discussed previously. The determination of the benefits for the 23 various SAMAs is further discussed in Section G.6.

24 The NRC staff questioned the assumptions used in evaluating the benefits or risk-reduction 25 estimates of a number of SAMAs provided in the ER (NRC 2007). For example, the NRC staff 26 requested information regarding the plant features or modeling assumptions that result in the 27 CCW pumps having limited risk importance. In response, Entergy stated that both units are 28 unique in that the capability exists to initiate backup cooling to key components in the event the 29 primary CCW cooling function is lost. The use of backup city water cooling to the charging 30 pumps enables continued seal injection and therefore reduces the likelihood of an RCP seal 31 LOCA. In IP2, city water backup or primary water can be used to cool the safety injection and 32 residual heat removal (RHR) pumps. In IP3, city water backup is available to cool RHR 33 Pump 31. Also, CCW is not required in either plant during the injection phase of the response 34 to a LOCA. The NRC staff considers the explanation of the plant features, as clarified, to be 35 reasonable and therefore acceptable for the purposes of the SAMA evaluation.

36 For a number of the Phase II SAMAs listed in the ER, the description of the improvement and 37 the associated analyses appeared either inconsistent between the two units or were unclear.

38 Therefore, the NRC staff asked the applicant to provide more detailed descriptions of the 39 modifications for several of the Phase II SAMA candidates (NRC 2007). In response, Entergy 40 provided additional information on those SAMA candidates that further explained the SAMA 41 modifications and the differences between units that account for the different analysis 42 assumptions for each unit (Entergy 2008a). Entergy also provided further clarifications and 43 discussion regarding the analysis assumptions and their bases. As an example, the licensee December 2010 G-33 NUREG-1437, Supplement 38

Appendix G 1 clarified a major difference in operation of a turbine-driven AFW pump between the two units 2 that affects the disposition of several SAMA candidates. In its response, Entergy indicated that 3 the units respond differently upon depletion of the station batteries. IP2 has pneumatic level 4 and pressure instruments that allow operators to monitor key parameters and effectively control 5 AFW flow after the batteries are depleted, whereas IP3 does not have this instrumentation.

6 Although it is still possible for the operators to manipulate AFW flow, the current IP3 model does 7 not credit this manual operation.

8 In the SAMA analysis submitted in the ER, Entergy increased the benefit that was derived from 9 the internal-event model by factors of 3.8 and 5.5 to account for the combined contribution from 10 internal and external events for IP2 and IP3, respectively. The NRC staff agrees with the 11 licensees overall conclusion concerning the impact of external events and concludes that the 12 licensees use of a multiplier of 3.8 and 5.5 for IP2 and IP3, respectively, to account for external 13 events is reasonable for the purposes of the SAMA evaluation. This is discussed further in 14 Section G.6.2.

15 For SAMA candidates that only address a specific external event and have no bearing on 16 internal-event risk (e.g., IP2 SAMA 66Harden EDG Building Against High Winds), Entergy 17 derived the benefit directly from the external-event risk model and then increased the benefit by 18 the multipliers identified earlier. The NRC staff notes that the use of multipliers for these 19 SAMAs (conceptually, to account for additional benefits in internal events) is unnecessary, since 20 these SAMAs have no bearing on internal events. However, use of the multipliers adds 21 conservatism to the benefit estimate for these SAMA candidates.

22 IP3 SAMA 53 (install an excess-flow valve to reduce the risk associated with hydrogen 23 explosions) was identified to reduce the risk associated with hydrogen explosions inside the 24 turbine building or PAB. The proposed plant modification involves the installation of a 25 nonelectric excess-flow valve. The benefit of this SAMA is also calculated in a bounding 26 manner. As discussed in Section G.6.2, this SAMA was found to be potentially cost beneficial, 27 based on revised analyses submitted in response to an NRC request.

28 The NRC staff has reviewed Entergys bases for calculating the risk reduction for the various 29 plant improvements and concludes that the rationale and assumptions for estimating risk 30 reduction are reasonable and generally conservative (i.e., the estimated risk reduction is higher 31 than what would actually be realized). Accordingly, the NRC staff based its estimates of averted 32 risk for the various SAMAs on Entergys risk reduction estimates.

33 G.5 Cost Impacts of Candidate Plant Improvements 34 Entergy estimated the costs of implementing the candidate SAMAs through the application of 35 engineering judgment and use of other licensees estimates for similar improvements. The ER 36 stated that the cost estimates conservatively did not include the cost of replacement power 37 during extended outages required to implement the modifications, nor did they include 38 contingency costs associated with unforeseen implementation obstacles. The cost estimates 39 provided in the ER also did not account for inflation, which is considered another conservatism.

40 The NRC staff reviewed the bases for the licensees cost estimates. For certain improvements, 41 the NRC staff also compared the cost estimates to estimates developed elsewhere for similar 42 improvements, including estimates developed as part of other licensees analyses of SAMAs for NUREG-1437, Supplement 38 G-34 December 2010

Appendix G 1 operating reactors and advanced light-water reactors. The NRC staff reviewed the costs and 2 found them to be reasonable and generally consistent with estimates provided in support of 3 other licensees analyses.

December 2010 G-35 NUREG-1437, Supplement 38

1 Table G-6. Final Potentially Cost-Beneficial SAMAs for IP2 and IP3 1

% Risk Total Benefit

($)

Appendix G Reduction Cost SAMA Assumptions 2 ($)

Population Baseline (Int Baseline With CDF Dose + Ext Events) Uncertainty IP2 SAMAs 9 - Create a reactor cavity flooding Eliminate containment failure 0 47 6.3M 13M 4.1M3 system. caused by concrete-core interaction.

NUREG-1437, Supplement 38 21 - Install additional pressure or leak Eliminate ISLOCA events. 0.8 11 2.1M 4.4M 3.2M3 monitoring instrumentation for ISLOCA.

22 - Add redundant and diverse limit Reduce ISLOCA frequency by 50 0.4 6 1.1M 2.3M 2.2M3 switches to each containment percent.

isolation valve.

28 - Provide a portable diesel-driven Eliminate failure of local operation 5 9 1.4M 2.9M 938K3 G-36 battery charger. of the turbine-driven AFW pump during SBO scenarios.

44 - Use fire water system as backup Eliminate failure of the turbine- 33 14 2.4M 4.9M 1.7M for steam generator inventory. driven AFW pump and local operation of AFW during SBO.

53 - Keep both pressurizer PORV Eliminate failure of PORV block 18 3 660K 1.4M 800K block valves open. valves to open.

54 - Install flood alarm in the 480-V ac Reduce control building flooding 20 39 5.6M 12M 200K switchgear room. initiator frequencies by a factor of 3.

56 - Keep RHR heat exchanger Eliminate failure of RHR heat 2 0.2 49K 100K 82K discharge MOVs normally open. exchanger discharge MOVs to open.

60 - Provide added protection against Eliminate flood initiated by a break 5 9 1.3M 2.7M 216K flood propagation from stairwell 4 in fire protection piping in into the 480-V ac switchgear room. stairwell 4.

61 - Provide added protection against Eliminate flood initiated by a break 10 19 2.8M 5.8M 192K flood propagation from the deluge in the 10-inch fire protection piping room into the 480-V ac switchgear in the deluge room at elevation 15 room. feet.

2 December 2010

1 Table G-6 (continued)

% Risk Total Benefit Reduction ($) Cost Assumptions 2 ($)

December 2010 SAMA Population Baseline (Int Baseline With CDF Dose + Ext Events) Uncertainty 62 - Provide a hard-wired connection Eliminate failure to align ASSS 3 6 850K 1.8M 1.5M3 to an SI pump from ASSS power power to SI and charging pumps supply. following loss of power from 480V buses.

65 - Upgrade the ASSS to allow timely Eliminate control building flooding 20 39 5.6M 12M 560K restoration of seal injection and initiators.

cooling.

IP3 SAMAs4 7 - Create a reactor cavity flooding Eliminate containment failures due 0 24 5.0M 7.3M 4.1M3 system. to core-concrete interactions G-37 18 - Route the discharge from the Reduce SGTR accident source 0 11 4.8M5 15M5 12M3 MSSVs through a structure where terms by a factor of 2.

spray water would condense the stream and remove fission products.

19 - Install additional pressure or leak Eliminate ISLOCA events 1 7 2.1M 3.1M 2.8M3 monitoring instrumentation for ISLOCAs.

52 - Open city water supply valve for Eliminate loss of the normal suction 1 1 250K 360K 50K alternative AFW pump suction. path to the AFW system.

53 - Install an excess flow valve to Eliminate hydrogen ruptures inside 2 2 500K 720K 228K reduce the risk associated with the turbine building.

hydrogen explosions.

55 - Provide the capability of powering Eliminate operator failure to align 16 18 4.1M 5.9M 1.3M one SI pump or RHR pump using MCC 312A.

the Appendix R bus (MCC 312A).

61 - Upgrade the ASSS to allow timely Eliminate control building flooding 17 20 4.4M 6.3M 560K restoration of seal injection and initiators.

cooling.

NUREG-1437, Supplement 38 Appendix G

% Risk Total Benefit Reduction ($) Cost Assumptions 2 ($) Appendix G SAMA Population Baseline (Int Baseline With CDF Dose + Ext Events) Uncertainty 62 - Install flood alarm in the 480-V ac Eliminate control building flooding 17 20 4.4M 6.3M 197K switchgear room. initiators.

1 1

2 The information was reproduced by combining the information from ER Tables E.2-2 and E.4-2 and Entergys SAMA re-analysis (Entergy 2009).

2 3 Reported benefit values account for risk reduction in both internal and external events and include the economic impact of lost tourism and business following a NUREG-1437, Supplement 38 4 severe accident. The values do not account for analysis uncertainties.

3 5 The cost estimate is based on a revised value provided in Entergys SAMA re-analysis (Entergy 2009) 4 6 SAMA 30 was identified as cost beneficial in the ER. However, an error in the original benefit calculation was discovered subsequent to submittal of the ER, as 7 described in Entergys response to RAI 5g (Entergy 2008a). Reported values in Table G-6 reflect correction of the calculational error. SAMA 30 is no longer cost 8 beneficial after corrections.

5 9 The benefit estimate is based on revised TI-SGTR sensitivity study results provided in Entergys SAMA re-analysis (Entergy 2009).

10 G-38 December 2010

Appendix G 1 The NRC staff questioned the high cost estimate ($800,000) for changing the pressurizer PORV 2 block valves from normally closed to normally open in conjunction with IP2 SAMA 53 (NRC 3 2008a). In response, Entergy clarified that a modification had been previously implemented 4 allowing closure of the block valves when operating pressure is less than 2235 pounds per 5 square inch gauge (psig). If the reactor coolant pressure increases to 2300 psig, the current 6 circuitry alarms and sends a signal to open the block valves. The SAMA would reverse this 7 operating approach and may require adding or changing the auto-open feature to a lower value.

8 Entergy provided a breakdown of the estimated cost, which included a $236,000 contingency 9 cost. As Section 4.21 of the ER states that contingency costs are excluded, the staff requested 10 clarification of this apparent inconsistency. In response, Entergy stated that the site-specific 11 implementation cost estimates include some contingency costs to account for the high degree of 12 uncertainty associated with the preliminary cost estimates and that, given the bounding nature 13 of the benefit analysis, it is reasonable to include contingency costs in these estimates. To 14 eliminate the confusion between Section 4.21 of the ER and the stated practice above, Entergy 15 revised Section 4.21, eliminating the contingency exclusion clause (Entergy 2008b).

16 Considering that this SAMA has been added to the list of potentially cost-beneficial SAMAs (see 17 Section G.6), the staff finds the cost estimate for SAMA 53 to be acceptable. In addition, no 18 other improvement cost estimates were identified as outliers. Therefore, the impact of including 19 contingency costs does not appear to be consequential.

20 As part of Entergys SAMA re-analysis (using corrected meteorological data), Entergy subjected 21 a subset of the SAMAs to more comprehensive and precise cost estimating techniques -

22 specifically, those SAMAs that appeared to be cost-beneficial based on the new benefit 23 estimate and the original implementation cost estimate. For two IP2 SAMAs (IP SAMAs 17 and 24 40) and four IP3 SAMAs (IP3 SAMAs 17, 20, 40, and 50), the updated (increased) cost estimate 25 resulted in the SAMA becoming non-cost-beneficial (i.e., the SAMA would be cost-beneficial 26 based on the cost estimate reported in the ER, but not cost-beneficial based on the revised cost 27 estimate). For each of these SAMAs, the NRC Staff requested that Entergy provide the basis 28 for the revised cost estimate and a breakdown of the cost estimate in terms of the major cost 29 factors. Entergy provided this additional information by letter dated January 14, 2010 (Entergy 30 2010). As stated in the response, the revised cost estimates were developed using Entergys 31 standard process for developing conceptual-level project cost estimates utilizing spreadsheets 32 containing 2009 rates for material, labor, insurance, fees, etc. Also, Entergy determined that 33 one SAMA that was previously identified as potentially cost beneficial was no longer cost 34 beneficial based on correction of an error in the ER (IP3 SAMA 30) (Entergy 2008b, Entergy 35 2009).

36 The NRC staff reviewed this additional cost information to determine the degree to which the 37 revised cost estimates and their constituent costs comport with the nature, magnitude and 38 complexity of each change. The NRC staff notes that the associated modifications all involve 39 either major plant modifications (e.g., erecting a barrier to protect the containment liner, 40 installing secondary side guard pipes) or changes to safety-related systems, structures, or 41 components (e.g., increasing secondary side pressure capacity, enhancing the RCS 42 depressurization capabilities). In addition to hardware costs, the modifications would require 43 extensive design work and safety analysis calculations, including seismic analyses, thermal 44 analyses, and analyses for piping or penetration interferences. The cost estimates reported in 45 previous SAMA analyses for similar modifications are typically on the order of $1M or more.

46 Entergys cost estimates are consistent with these values. The NRC staff also notes that for December 2010 G-39 NUREG-1437, Supplement 38

Appendix G 1 each of these SAMAs the revised cost estimates are at least 50 percent greater than the revised 2 benefit estimates even when the benefit estimates are increased to account for uncertainties.

3 Accordingly, Entergys revised cost estimates appear reasonable, and result in an appropriate 4 determination that these candidate SAMAs are not cost-beneficial.

5 The NRC staff concludes that the cost estimates provided by Entergy are sufficient and 6 appropriate for use in the SAMA evaluation.

7 G.6 Cost-Benefit Comparison 8 Entergys cost-benefit analysis and the NRC staffs review are described in the following 9 sections.

10 G.6.1. Entergys Evaluation 11 The methodology used by Entergy was based primarily on the NRCs guidance for performing a 12 cost-benefit analysis (i.e., NUREG/BR-0184, Regulatory Analysis Technical Evaluation 13 Handbook (NRC 1997a). The guidance involves determining the net present value for each 14 SAMA according to the following formula:

15 Net Value = (APE + AOC + AOE + AOSC) - COE, where 16 APE = present value of averted public exposure ($)

17 AOC = present value of averted offsite property damage costs ($)

18 AOE = present value of averted occupational exposure costs ($)

19 AOSC = present value of averted onsite costs ($)

20 COE = cost of enhancement ($)

21 If the net value of a SAMA is negative, the cost of implementing the SAMA is larger than the 22 benefit associated with the SAMA, and it is not considered cost beneficial. Entergys derivation 23 of each of the associated costs is summarized below.

24 NUREG/BR-0058 has recently been revised to reflect the agencys policy on discount rates.

25 Revision 4 of NUREG/BR-0058 states that two sets of estimates should be developedone at 26 3 percent and one at 7 percent (NRC 2004). Entergy performed the SAMA analysis using 27 7 percent and provided a sensitivity analysis using the 3 percent discount rate in order to 28 capture SAMAs that may be cost-effective using the lower discount rate, as well as the higher, 29 baseline rate (Entergy 2007). This analysis is sufficient to satisfy NRC policy in Revision 4 of 30 NUREG/BR-0058.

31 Averted Public Exposure (APE) Costs 32 The APE costs were calculated using the following formula:

33 APE = Annual reduction in public exposure (person-rem/year) 34 x monetary equivalent of unit dose ($2000 per person-rem) 35 x present value conversion factor (10.76 based on a 20-year period with 36 a 7 percent discount rate)

NUREG-1437, Supplement 38 G-40 December 2010

Appendix G 1 As stated in NUREG/BR-0184 (NRC 1997a), the monetary value of the public health risk after 2 discounting does not represent the expected reduction in public health risk caused by a single 3 accident. Rather, it is the present value of a stream of potential losses extending over the 4 remaining lifetime (in this case, the renewal period) of the facility. Thus, it reflects the expected 5 annual loss caused by a single accident, the possibility that such an accident could occur at any 6 time over the renewal period, and the effect of discounting these potential future losses to 7 present value. For the purposes of initial screening, which assumes elimination of all severe 8 accidents caused by internal events, Entergy calculated an APE of approximately $474,000 for 9 IP2 and $527,000 for IP3 for the 20-year license renewal period. Based on Entergys SAMA re-10 analysis (using corrected meteorological data), these values increase to $1.88M for IP2 and 11 $2.04M for IP3.

12 Averted Offsite Property Damage Costs (AOC) 13 The AOCs were calculated using the following formula:

14 AOC = Annual CDF reduction 15 x offsite economic costs associated with a severe accident (on a per-16 event basis) 17 x present value conversion factor 18 For the purposes of initial screening, which assumes all severe accidents caused by internal 19 events are eliminated, Entergy calculated an annual offsite economic cost of about $45,000 for 20 IP2 and $53,000 for IP3 based on the Level 3 risk analysis. This results in a discounted value 21 of approximately $483,000 for IP2 and $568,000 for IP3 for the 20-year license renewal period.

22 Based on Entergys SAMA re-analysis (using corrected meteorological data), these values 23 increase to $2.28 million for IP2 and $2.81 million for IP3.

24 Averted Occupational Exposure (AOE) Costs 25 The AOE costs were calculated using the following formula:

26 AOE = Annual CDF reduction 27 x occupational exposure per core damage event 28 x monetary equivalent of unit dose 29 x present value conversion factor 30 Entergy derived the values for AOE from information provided in Section 5.7.3 of the regulatory 31 analysis handbook (NRC 1997a). Best estimate values that provided for immediate 32 occupational dose (3300 person-rem) and long-term occupational dose (20,000 person-rem 33 over a 10-year cleanup period) were used. The present value of these doses was calculated 34 using the equations provided in the handbook, in conjunction with a monetary equivalent of unit 35 dose of $2000 per person-rem, a real discount rate of 7 percent, and a time period of 20 years 36 to represent the license renewal period. For the purposes of initial screening, which assumes 37 all severe accidents caused by internal events are eliminated, Entergy calculated an AOE of 38 approximately $7,000 for IP2 and $4,000 for IP3 for the 20-year license renewal period.

December 2010 G-41 NUREG-1437, Supplement 38

Appendix G 1 Averted Onsite Costs 2 Averted onsite costs (AOSC) include averted cleanup and decontamination costs and averted 3 power replacement costs. Repair and refurbishment costs are considered for recoverable 4 accidents only and not for severe accidents. Entergy derived the values for AOSC based on 5 information provided in Section 5.7.6 of NUREG/BR-0184, the regulatory analysis handbook 6 (NRC 1997a).

7 Entergy divided this cost element into two partsthe onsite cleanup and decontamination cost, 8 also commonly referred to as averted cleanup and decontamination costs (ACC), and the 9 replacement power cost (RPC).

10 ACCs were calculated using the following formula:

11 ACC = Annual CDF reduction 12 x present value of cleanup costs per core damage event 13 x present value conversion factor 14 The total cost of cleanup and decontamination subsequent to a severe accident is estimated in 15 NUREG/BR-0184 to be $1.5x109 (undiscounted). This value was converted to present costs 16 over a 10-year cleanup period and integrated over the term of the proposed license extension.

17 For the purposes of initial screening, which assumes all severe accidents caused by internal 18 events are eliminated, Entergy calculated an ACC of approximately $208,000 for IP2 and 19 $133,000 for IP3 for the 20-year license renewal period.

20 Long-term RPCs were calculated using the following formula:

21 RPC = Annual CDF reduction 22 x present value of replacement power for a single event 23 x factor to account for remaining service years for which replacement 24 power is required 25 x reactor power scaling factor 26 Entergy based its calculations on the value of 1071 megawatt electric (MWe) and scaled up 27 from the 910 MWe reference plant in NUREG/BR-0184 (NRC 1997b). Therefore, Entergy 28 applied a power-scaling factor of 1071/910 to determine the RPCs. For the purposes of initial 29 screening, which assumes all severe accidents caused by internal events are eliminated, 30 Entergy calculated an RPC of approximately $166,000 for IP2 and $107,000 for IP3, and an 31 AOSC of approximately $374,000 for IP2 and $240,000 for IP3 for the 20-year license renewal 32 period.

33 Using the above equations and corrected meteorological data, Entergy determined that the total 34 present dollar-value equivalent associated with completely eliminating severe accidents caused 35 by internal events is approximately $4.5 million at IP2 and $5.1 million at IP3. Use of a 36 multiplier of 3.8 for IP2 and 5.5 for IP3 to account for external events increases the present 37 dollar value to $17 million for IP2 and $28 million for IP3 and represents the present dollar value 38 associated with completely eliminating the risk of severe accidents caused by all internal and 39 external events at IP2 and IP3, respectively.

40 Entergys Results NUREG-1437, Supplement 38 G-42 December 2010

Appendix G 1 If the implementation costs for a candidate SAMA exceeded the calculated benefit, the SAMA 2 was considered by Entergy not to be cost beneficial. In the baseline analysis (using a 7 percent 3 discount rate) and the sensitivity analysis (using a 3 percent discount rate) contained in the ER, 4 Entergy identified 10 potentially cost-beneficial SAMAs (five for IP2 and five for IP3). Based on 5 consideration of analysis uncertainties, Entergy identified two additional potentially cost-6 beneficial SAMAs for IP2 in the ER (IP2 SAMAs 44 and 56).

7 In response to an NRC staff request, Entergy provided the results of a revised uncertainty 8 analysis in which the impact of lost tourism and business was accounted for in the baseline 9 analysis (rather than as a separate sensitivity case). The revised uncertainty analysis resulted 10 in the identification of two additional potentially cost-beneficial SAMAs for IP2 (IP2 SAMAs 9 11 and 53) and one additional potentially cost-beneficial SAMA for IP3 (IP3 SAMA 53), as reported 12 in the DSEIS.

13 Based on the SAMA re-analysis (using corrected meteorological data), Entergy identified three 14 additional potentially cost-beneficial SAMAs for IP2 (IP2 SAMAs 21,22, and 62) and three 15 additional potentially cost-beneficial SAMAs for IP3 (IP3 SAMAs 7, 18, and 19).

16 In sum, the potentially cost-beneficial SAMAs for IP2 are the following:

17

• SAMA 9 - Create a reactor cavity flooding system to reduce the impact of core-concrete 18 interaction from molten core debris following core damage and vessel failure.

19

• SAMA 21 - Install additional pressure or leak monitoring instrumentation to reduce the 20 frequency of interfacing system loss of coolant accidents.

21

• SAMA 22 - Add redundant and diverse limit switches to each containment isolation 22 valve. This modification would reduce the frequency of an interfacing system loss of 23 coolant accident.

24

• SAMA 28 - Provide a portable diesel-driven battery charger to improve dc power 25 reliability. A safety-related disconnect would be used to charge a selected battery. This 26 modification would enhance the long-term operation of the turbine-driven AFW pump on 27 battery depletion.

28

• SAMA 44 - Use fire water as a backup for steam generator inventory to increase the 29 availability of the steam generator water supply to ensure adequate inventory for the 30 operation of the turbine-driven AFW pump during SBO events.

31

• SAMA 53 - Keep both pressurizer PORV block valves open. This modification would 32 reduce the CDF contribution from loss of secondary heat sink by improving the 33 availability of feed and bleed.

34

• SAMA 54 - Install a flood alarm in the 480-V ac switchgear room to mitigate the 35 occurrence of internal floods inside the 480-V ac switchgear room.

36

• SAMA 56 - Keep RHR heat exchanger discharge valves, motor-operated valves 746 37 and 747, normally open. This procedure change would reduce the CDF contribution from 38 transients and LOCAs.

39

• SAMA 60 - Provide added protection against flood propagation from stairwell 4 into the 40 480-V ac switchgear room to reduce the CDF contribution from flood sources within 41 stairwell 4 adjacent to the 480-V ac switchgear room.

December 2010 G-43 NUREG-1437, Supplement 38

Appendix G 1

• SAMA 61 - Provide added protection against flood propagation from the deluge room 2 into the 480-V ac switchgear room to reduce the CDF contribution from flood sources 3 within the deluge room adjacent to the 480-V ac switchgear room.

4

• SAMA 62 - Provide a hard-wired connection to a safety injection (SI) pump from the 5 alternate safe shutdown system (ASSS) power supply. This modification would reduce 6 the CDF from events that involve loss of power from the 480V vital buses.

7

• SAMA 65 - Upgrade the alternate safe shutdown system (ASSS) to allow timely 8 restoration of RCP-seal injection and cooling from events that cause a loss of power 9 from the 480-V ac vital buses.

10 The potentially cost-beneficial SAMAs for IP3 are the following:

11

• SAMA 7 - Create a reactor cavity flooding system. This modification would enhance 12 core debris cooling and reduce the frequency of containment failure due to core-13 concrete interaction.

14

• SAMA 18 - Route the discharge from the main steam safety valves through a structure 15 where a water spray would condense the steam and remove fission products.

16

• SAMA 19 - Install additional pressure or leak monitoring instrumentation to reduce the 17 frequency of interfacing system loss of coolant accidents.

18

• SAMA 52 - Institute a procedure for opening the city water supply valve for alternative 19 AFW system pump suction to enhance the availability of the AFW system.

20

• SAMA 53 - Install an excess flow valve to reduce the risk associated with hydrogen 21 explosions inside the turbine building or PAB.

22

• SAMA 55 - Provide the capability of powering one safety injection pump or RHR pump 23 using the Appendix R diesel (MCC 312A) to enhance RCS injection capability during 24 events that cause a loss of power from the 480-V ac vital buses.

25

• SAMA 61 - Upgrade the ASSS to allow timely restoration of RCP-seal injection and 26 cooling from events that cause a loss of power from the 480-V ac vital buses.

27

• SAMA 62 - Install a flood alarm in the 480-V ac switchgear room to mitigate the 28 occurrence of internal floods inside the 480-V ac switchgear room.

29 In response to an NRC staff inquiry regarding estimated benefits for certain SAMAs and lower 30 cost alternatives, one additional potentially cost-beneficial SAMA was identified (regarding a 31 dedicated main stream safety valve gagging device for SGTR events in both units) (Entergy 32 2008b), and one SAMA that was previously identified as potentially cost beneficial was found no 33 longer cost beneficial based on correction of an error in the ER (IP3 SAMA 30) (Entergy 2008a, 34 Entergy 2009). The potentially cost-beneficial SAMAs and Entergys plans for further evaluation 35 of these SAMAs are discussed in more detail in Section G.6.2.

36 G.1.2 Review of Entergys Cost-Benefit Evaluation 37 The cost-benefit analysis performed by Entergy was based primarily on NUREG/BR-0184 (NRC 38 1997a) and was implemented consistent with that guidance.

NUREG-1437, Supplement 38 G-44 December 2010

Appendix G 1 SAMAs identified primarily on the basis of the internal events analysis could provide benefits in 2 certain external events, in addition to their benefits in internal events. To account for the 3 additional benefits in external events, Entergy multiplied the internal event benefits for each 4 internal event SAMA by an amount equal to the ratio of the sum of the internal and external 5 event CDF to the internal event CDF. This ratio is approximately 3.8 for IP2 and 5.5 for IP3.

6 Potential benefits in external events were estimated in this manner, since the external-event 7 models are generally less detailed than the internal-event models and do not lend themselves to 8 quantifying the benefits of the specific plant changes associated with internal-event SAMAs.

9 For example, the benefits of a procedural change associated with an important internal event 10 sequence cannot be readily assessed using the seismic-risk model if that operator action or 11 system is not represented in the seismic-risk model. The use of a multiplier on the benefits 12 obtained from the internal events PSA to incorporate the impact of external events implicitly 13 assumes that each SAMA would offer the same percentage reduction in external-event CDF 14 and population dose as it offers in internal events. While this provides only a rough 15 approximation of the potential benefits, such an adjustment was considered appropriate, given 16 the large risk contribution from external events relative to internal events and the lack of 17 information on which to base a more precise risk reduction estimate for external events. In view 18 of the remaining conservatism in the external events CDF, and the licensees further evaluation 19 of the impacts of the use of a multiplier on the SAMA screening (as part of the uncertainty 20 assessment discussed below), the NRC staff agrees that the use of these multipliers for 21 external events is reasonable.

22 For SAMA candidates that only address a specific external event and have no bearing on 23 internal-event risk, Entergy derived the benefit directly from the external-event risk model and 24 then increased the benefit by the multipliers identified earlier. The NRC staff notes that the use 25 of multipliers for these SAMAs (conceptually, to account for additional benefits in internal 26 events) is unnecessary, since these SAMAs have no bearing on internal events. However, use 27 of the multipliers adds conservatism to the benefit estimate for these SAMA candidates.

28 Entergy considered the impact that possible increases in benefits from analysis uncertainties 29 would have on the results of the SAMA assessment. In the ER, Entergy presents the results of 30 an uncertainty analysis of the internal-event CDF for IP2 and IP3, which indicates that the 95th 31 percentile value is a factor of 2.1 times the mean CDF for IP2 and 1.4 times the mean CDF for 32 IP3. Entergy assessed the impact on the SAMA screening if the estimated benefits for each 33 SAMA were further increased by these uncertainty factors. For purposes of this assessment, 34 Entergy applied a multiplier of 8 to the internal-event benefits for each unit to account for both 35 internal and external events, with analysis uncertainty. The multiplier of 8 slightly exceeds the 36 product of the external-event multiplier and the uncertainty factor for each unit (i.e.,

37 3.80x2.10=7.98 for IP2, and 5.53x1.40=7.73 for IP3) and adds a small amount of additional 38 conservatism. Although not cost beneficial in the baseline analysis, Entergy included any 39 additional SAMAs identified as potentially cost beneficial in the uncertainty analysis within the 40 set of potentially cost-beneficial SAMAs that it intends to examine further for implementation.

41 Entergy also provided the results of additional sensitivity analyses in the ER, including use of a 42 3 percent discount rate, use of a longer plant life, and the consideration of economic losses by 43 tourism and business (which were not included in the baseline analysis). These analyses did 44 not identify any additional potentially cost-beneficial SAMAs beyond those already identified 45 through the uncertainty analysis.

December 2010 G-45 NUREG-1437, Supplement 38

Appendix G 1 The NRC staff questioned the rationale for treating the loss of tourism and business in a 2 sensitivity case rather than in the baseline analysis (NRC 2007). Incorporation of tourism and 3 business losses within the baseline analysis could result in identification of additional cost-4 beneficial SAMAs, particularly when the baseline benefits are multiplied to account for 5 uncertainties. In response, Entergy explained that the impact of lost tourism and business was 6 not modeled in the baseline analysis because the level of tourism and business activity can be 7 reestablished in time. Nevertheless, Entergy provided the results of an additional uncertainty 8 case showing the impact of lost tourism and business combined with analysis uncertainty. This 9 uncertainty case resulted in the identification of two additional potentially cost-beneficial SAMAs 10 for IP2 (IP2 SAMAs 9 and 53) and one additional potentially cost-beneficial SAMA for IP3 (IP3 11 SAMA 53). Given that it may take years to reestablish the level of tourism and business activity 12 following a severe accident, the NRC staff has conservatively adopted the case incorporating 13 lost tourism and business as its base case and has reflected the results of that case in 14 Table G-6.

15 In responding to an NRC RAI, Entergy identified and corrected an error in the benefit analysis 16 for IP3 SAMA 30 (provide a portable battery charger for monitoring instrumentation necessary to 17 allow manual operation of the turbine-driven AFW pump), which results in this SAMA no longer 18 being potentially cost beneficial. As indicated in ER Section E.4.3, the benefit of this SAMA was 19 estimated based on the assumption that the SAMA would increase the time available to recover 20 offsite power before local operation of AFW is required from 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />, and would also 21 reduce internal switchgear room floods by 5 percent (which bounds the benefit of using a 22 portable diesel-driven battery charger in switchgear flood events). According to Entergy, the 23 original analysis inadvertently reduced the contribution from internal switchgear room floods by 24 more than 5 percent (Entergy 2008a). Entergys reevaluation of the benefits for this SAMA, 25 consistent with the intended bounding case, resulted in a reduction in the baseline benefit to 26 about $146,000, including the impacts of lost tourism and business and analysis uncertainties 27 (Entergy 2008a), and $309,000 using the same assumptions and corrected site meteorological 28 data (Entergy 2009). The revised benefit estimate using corrected site meteorology is reflected 29 in Table G-6. The NRC staff notes that the benefit associated with several other SAMA 30 candidates that could increase the time available to recover offsite power before local operation 31 of AFW is required from 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> (e.g., IP3 SAMA 24 (provide additional dc battery 32 capacity) was estimated at about $51,000, including the impacts of lost tourism and business 33 and analysis uncertainties. Therefore, a revised benefit estimate of $146,000 (before correcting 34 site meteorological data) for IP3 SAMA 30, which also includes the additional benefit from 35 reducing the contribution of internal switchgear room floods by 5 percent, appears reasonable.

36 In the ER, Entergy indicated that the implementation cost associated with IP3 SAMA 30 (i.e.,

37 $494,000) was specifically estimated for IP3. The proposed plant modification involves 38 purchasing, installing, and maintaining a diesel-driven generator to charge the 125-V dc 39 batteries. Safety-related quick-disconnects would be used to charge the selected battery. The 40 diesel generator would be installed in a weather enclosure outside the turbine or control 41 building, requiring fire barrier penetration sealing. Calculation of cable size, as well as 42 procedure development and training, would be required (Entergy 2007). In view of the scope of 43 these modifications and the fact that the modifications involve a safety-related dc system, the 44 estimated costs appear reasonable. As part of Entergys SAMA re-analysis (using corrected 45 meteorological data) Entergy provided an updated site-specific cost estimate of $938,000 for 46 SAMA 30 based on more comprehensive and precise cost estimating techniques (Entergy NUREG-1437, Supplement 38 G-46 December 2010

Appendix G 1 2009). However, the NRC staff notes that SAMA 30 would not be cost-beneficial regardless of 2 which cost estimate is used. Accordingly, the NRC staff agrees that this SAMA would not be 3 cost beneficial for IP3.

4 The NRC-sponsored severe accident analyses performed subsequent to the time of the IPE 5 suggest that the probability of a TI-SGTR, given a core-damage event with high primary-side 6 pressure and a depressurized, dry secondary side, may be higher than the value used in the 7 IP2 and IP3 PSAs. In response to an NRC request, Entergy provided the results of a sensitivity 8 study in which it increased the conditional TI-SGTR probability from 0.01 (used in the baseline 9 analysis) to 0.25, which is comparable to the values reported in NUREG-1570 (NRC 1998).

10 Entergy identified the candidate SAMAs potentially affected by the TI-SGTR assumption and 11 reassessed the benefits for these SAMAs, subject to the increased conditional failure probability 12 and the impact of analysis uncertainties. Entergy identified no additional cost-beneficial SAMAs 13 as a result of this reassessment. Entergy also noted that the IP2 and IP3 steam generators 14 have only 0.19 percent and 0.12 percent of the tubes plugged for IP2 and IP3, respectively, and 15 would be classified as pristine, in accordance with the Westinghouse criteria for categorizing 16 steam generator tube integrity. With no observed corrosion, Entergy concludesand the NRC 17 staff concursthat this sensitivity study is conservative relative to the application of the 18 NUREG-1570 results for pristine generators (Entergy 2008b).

19 As part of Entergys SAMA re-analysis, Entergy revisited this sensitivity study using corrected 20 site meteorological data. Due to the higher offsite consequences in the re-analysis, additional 21 SAMAs were identified as potentially impacted by the TI-SGTR assumption (relative to the 22 original study) and were re-evaluated. Based on the re-evaluation, one additional SAMA was 23 found to be potentially cost-beneficial for IP3 (IP3 SAMA 18) (Entergy 2009).

24 The NRC staff noted that for certain SAMAs considered in the ER, there may be alternatives 25 that could achieve much of the risk reduction at a lower cost. The NRC staff asked the licensee 26 to evaluate several lower cost alternatives to the SAMAs considered in the ER, including 27 SAMAs that had been found to be potentially cost beneficial at other PWR plants. These 28 alternatives were (1) implementation of improved instrumentation and/or procedures to aid in 29 the mitigation of a SGTR, (2) implementation of a procedure for recovery of steam dump to 30 condenser from the unaffected steam generator to aid the mitigation of a SGTR, 31 (3) implementation of a procedure for recovery of the main feedwater/condensate after safety 32 injection actuation to aid in the mitigation of a SGTR, (4) reactivation of the IP3 postaccident 33 containment venting system, and (5) purchase or manufacture of a gagging device that could 34 be used to close a stuck-open steam generator safety valve on a faulted steam generator 35 before core damage occurs (NRC 2007a, NRC 2007b). Entergy provided a further evaluation of 36 these alternatives, as summarized below.

37

• Improve SGTR instrumentation and/or valve procedures. Operator actions to cool and 38 depressurize the RCS to cold shutdown conditions following a SGTR before depleting 39 RWST inventory are already contained in EOPs. EOPs also direct plant personnel to 40 initiate RWST makeup, given a low RWST level without a corresponding increase in the 41 containment recirculation sump water level, or if the ruptured steam generator narrow-42 range level indication is high.

December 2010 G-47 NUREG-1437, Supplement 38

Appendix G 1

• Institute a procedure for recovery of steam dump to condenser. Procedures for recovery 2 of steam dump to condenser from the unaffected steam generator are currently available 3 at both units.

4

• Recover main feedwater/condensate. For IP2, the operators are currently directed to 5 attempt to establish a secondary heat sink with AFW, main feedwater, or condensate, 6 should the AFW system initially not function or subsequently fail during implementation 7 of the EOPs. For IP3, procedural guidance currently exists for re-establishing 8 condensate flow, but there is no guidance to use main feedwater following a loss of the 9 secondary heat sink. Thus, the development of guidance on aligning main feedwater for 10 secondary heat removal was evaluated as a potential SAMA for IP3.

11

• Reactivate the IP3 containment venting system. IP3 has three alternate methods of 12 containment depressurization and combustible gas control. These methods are 13 backflow to the steam ejector line, containment pressure relief line, and the containment 14 purge system. All of the venting functions require similar operator actions. Given these 15 various alternatives, failure to vent would be dominated by human error and would not 16 be substantially reduced by providing an additional means of venting.

17 With regard to the steam generator safety gagging device, which was found to be potentially 18 cost beneficial at another pressurized-water reactor seeking license renewal, Entergy provided 19 a separate assessment of the benefits and implementation costs. Entergy estimated the benefit 20 associated with successfully gagging a stuck-open main steam safety valve following an SGTR 21 by assuming all early steam generator isolation failures and all TI-SGTRs would be eliminated.

22 The total benefits were estimated to be about $2.9 million for IP2 and $4.4 million for IP3 23 (Entergy 2008b). Based on Entergys SAMA re-analysis (using corrected meteorological data),

24 these values would increase to about $13 million for IP2 and $19 million for IP3 (Entergy 2009).

25 The implementation cost, including purchasing and storing a dedicated gagging devise, revising 26 procedures, and providing training, was estimated to be about $50,000 for each unit. As such, 27 the results indicate that this SAMA is potentially cost beneficial for both units. Entergy indicates 28 that this additional SAMA has been submitted for an engineering project cost-benefit analysis 29 for a more detailed examination of its viability and implementation cost (Entergy 2008b). The 30 NRC staff concurs with Entergys findings regarding these alternative SAMAs because the NRC 31 staff finds the additional information provided by Entergy for the aforementioned alternative 32 SAMAs to be technically sound.

33 The NRC staff notes that all of the 12 potentially cost-beneficial SAMAs for IP2 (IP2 SAMAs 9, 34 21, 22, 28, 44, 53, 54, 56, 60, 61, 62 and 65) and eight potentially cost-beneficial SAMAs for 35 IP3 (IP3 SAMAs 7, 18, 19, 52, 53, 55, 61, and 62), identified in either Entergys baseline 36 analysis or supplemental analyses provided in response to the NRC requests, as well as the 37 additional SAMA regarding a dedicated gagging device for SGTR events (applicable to both 38 units), are included within the set of SAMAs that Entergy will consider further for 39 implementation. The NRC staff concludes that, with the exception of the potentially cost-40 beneficial SAMAs discussed above, the costs of the other SAMAs would be higher than the 41 associated benefits (i.e., no additional SAMAs appear to be cost-beneficial).

42 G.7 Conclusions NUREG-1437, Supplement 38 G-48 December 2010

Appendix G 1 Entergy compiled a list of 231 candidate SAMAs for IP2 and 237 SAMAs for IP3, based on a 2 review of the most significant basic events from the current plant-specific PSA, insights from the 3 plant-specific IPE and IPEEE, and a review of other industry documentation. An initial 4 screening removed SAMA candidates that (1) were not applicable at IP2 and IP3, (2) were 5 already implemented or their intent had been met, or (3) were similar in nature and could be 6 combined with another SAMA candidate. Based on this screening, 163 IP2 and 175 IP3 7 SAMAs were eliminated, leaving 68 IP2 and 62 IP3 candidate SAMAs for evaluation.

8 For the remaining SAMA candidates, more detailed evaluation was performed as shown in 9 Table G-6. The cost-benefit analyses in the ER showed that five IP2 and five IP3 SAMA 10 candidates were potentially cost beneficial in either the baseline analysis or sensitivity analysis 11 using a 3 percent discount rate. Entergy performed additional analyses to evaluate the impact 12 of parameter choices and uncertainties on the results of the SAMA assessment. As a result, 13 four additional IP2 SAMAs and one additional IP3 SAMA were identified as potentially cost 14 beneficial. In addition, a SAMA regarding a dedicated gagging device for SGTR events was 15 identified as potentially cost beneficial for both units. Correction of an error in the benefit 16 analysis for IP2 SAMA 30 resulted in it no longer being considered cost beneficial. Subsequent 17 to issuance of the DSEIS, in response to NRC Staff questions, Entergy identified an error in the 18 Indian Point site meteorology file used to calculate offsite consequences of severe accidents, 19 and submitted a SAMA re-analysis based on corrected meteorological data (Entergy 2009).

20 The SAMA re-analysis resulted in identification of three additional potentially cost beneficial 21 SAMAs for IP2 (IP2 SAMAs 21, 22, and 62) and three potentially cost beneficial SAMAs for IP3 22 (IP3 SAMAs 7, 18, and 19). Entergy has indicated that all 12 potentially cost-beneficial SAMAs 23 for IP2 (IP2 SAMAs 9, 21, 22, 28, 44, 53, 54, 56, 60, 61, 62, and 65) and eight potentially cost-24 beneficial SAMAs for IP3 (IP3 SAMAs 7, 18, 19, 52, 53, 55, 61, and 62), as well as the 25 additional SAMA regarding a dedicated gagging device for SGTR events, will be considered 26 further for implementation at IP2 and IP3.

27 The NRC staff reviewed the Entergy analysis and concludes that the methods used and the 28 implementation of those methods were sound. The treatment of SAMA benefits and costs 29 support the general conclusion that the SAMA evaluations performed by Entergy are reasonable 30 and sufficient for the license renewal submittal. Although the treatment of SAMAs for external 31 events was somewhat limited, the likelihood of there being cost-beneficial enhancements in this 32 area was minimized by improvements that have been realized as a result of the IPEEE process 33 and inclusion of a multiplier to account for external events.

34 The NRC staff concurs with Entergys identification of areas in which risk can be further reduced 35 in a cost-beneficial manner through the implementation of the identified, potentially cost-36 beneficial SAMAs. Given the potential for cost-beneficial risk reduction, the NRC staff agrees 37 that further evaluation of these SAMAs by Entergy is warranted. However, these SAMAs do not 38 relate to adequately managing the effects of aging during the period of extended operation.

39 Therefore, they need not be implemented as part of license renewal pursuant to Title 10 of the 40 Code of Federal Regulations, Part 54, Requirements for Renewal of Operating Licenses for 41 Nuclear Power Plants (10 CFR Part 54).

42 G.8 References December 2010 G-49 NUREG-1437, Supplement 38

Appendix G 1 Consolidated Edison (Con Ed). 1992. Letter from Stephen B. Bram to U.S. NRC,

Subject:

2 Generic Letter 88-20, Supplement 1: Individual Plant Examination (IPE) for Severe Accident 3 Vulnerabilities10 CFR 50.54, IP2 and IP3 Unit No. 2, August 12, 1992.

4 Consolidated Edison (Con Ed). 1995. Letter from Stephen E. Quinn to U.S. NRC,

Subject:

5 Final Response to Generic Letter 88-20, Supplement 4: Submittal of Individual Plant 6 Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, IP2 and IP3 Unit 7 No. 2, December 6, 1995.

8 Entergy Nuclear Operations, Inc. (Entergy). 2007. Letter from Fred Dacimo to U.S. NRC, 9

Subject:

IP2 and IP3 Energy Center Licensee Renewal Application, NL-07-039, April 23, 2007.

10 ADAMS Accession No. ML071220512.

11 Entergy Nuclear Operations, Inc. (Entergy). 2008a. Letter from Fred R. Dacimo to U.S. NRC, 12

Subject:

Reply to Request for Additional Information Regarding License Renewal Application 13 Severe Accident Mitigation Alternatives Analysis, NL-08-028, February 5, 2008. ADAMS 14 Accession No. ML080420264.

15 Entergy Nuclear Operations, Inc. (Entergy). 2008b. Letter from Fred R. Dacimo to U.S. NRC, 16

Subject:

Supplemental Reply to Request for Additional Information Regarding License Renewal 17 ApplicationSevere Accident Mitigation Alternatives Analysis, NL-08-086, May 22, 2008.

18 ADAMS Accession No. ML081490336.

19 Entergy Nuclear Operations, Inc. (Entergy). 2009. Letter from Fred Dacimo to U.S. NRC, 20

Subject:

License Renewal Application - SAMA Re-analysis Using Alternate Meteorological 21 Tower Data, NL-09-165, December 11, 2009. ADAMS Accession No. ML093580089.

22 Entergy Nuclear Operations, Inc. (Entergy). 2010. Letter from Fred Dacimo to U.S. NRC, 23

Subject:

License Renewal Application - Supplement To SAMA Re-Analysis Using Alternate 24 Meteorological Tower Data, NL-10-013, January 14, 2010. ADAMS Accession No.

25 ML100260750.

26 New York Power Authority (NYPA). 1994. Letter from William A. Josiger to U.S. NRC,

Subject:

27 IP2 and IP3 3 Nuclear Power Plant Individual Plant Examination for Internal Events, June 30, 28 1994.

29 New York Power Authority (NYPA). 1997. Letter from James Knubel to U.S. NRC,

Subject:

30 IP2 and IP3 3 Nuclear Power Plant Individual Plant Examination of External Events (IPEEE),

31 September 26, 1997.

32 Nuclear Regulatory Commission (NRC). 1990. Severe Accident Risks: An Assessment for 33 Five U.S. Nuclear Power Plants. NUREG-1150, Washington, DC, December 1990. ADAMS 34 Accession No. ML040140729.

35 Nuclear Regulatory Commission (NRC). 1991. Generic Letter 88-20, Supplement 4, Individual 36 Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, June 28, 37 1991.

38 Nuclear Regulatory Commission (NRC). 1995. Letter from Jefferey F. Harold to William J.

39 Cahill, Jr.,

Subject:

Staff Evaluation of IP2 and IP3 Nuclear Generating Unit No. 3Individual 40 Plant Examination (TAC No. M74423), December 11, 1995.

NUREG-1437, Supplement 38 G-50 December 2010

Appendix G 1 Nuclear Regulatory Commission (NRC). 1996. Letter from Barry Westreich to Stephen E.

2 Quinn,

Subject:

Staff Evaluation of IP2 and IP3 Nuclear Generating Unit No. 2Individual Plant 3 Examination (TAC No. M74422), August 14, 1996.

4 Nuclear Regulatory Commission (NRC). 1997a. Regulatory Analysis Technical Evaluation 5 Handbook. NUREG/BR-0184, Washington, DC, January 1997.

6 Nuclear Regulatory Commission (NRC). 1997b. Individual Plant Examination Program:

7 Perspectives on Reactor Safety and Plant Performance. NUREG-1560, Washington, DC, 8 December 1997.

9 Nuclear Regulatory Commission (NRC). 1997c. Code Manual for MACCS2: Volume 1, User's 10 Guide. NUREG/CR-6613, Washington, DC, May 1998.

11 Nuclear Regulatory Commission (NRC). 1998. Risk Assessment of Severe Accident-Induced 12 Steam Generator Tube Rupture. NUREG-1570, Washington, DC, March 1998.

13 Nuclear Regulatory Commission (NRC). 1999. Letter from Jefferey F. Harold to A. Alan Blind, 14

Subject:

Review of IP2 and IP3 Nuclear Generating Unit No. 2Individual Plant Examination of 15 External Events (IPEEE) Submittal (TAC No. M83631), August 13, 1999.

16 Nuclear Regulatory Commission (NRC). 2001. Letter from George F. Wunder to Michael 17 Kansler,

Subject:

Review of Individual Plant Examination of External EventsIP2 and IP3 18 Nuclear Generating Unit No. 3 (TAC No. M83632), February 15, 2001. ADAMS Accession No.

19 ML010080273.

20 Nuclear Regulatory Commission (NRC). 2002. Perspectives Gained From the Individual Plant 21 Examination of External Events (IPEEE) Program," Volume 1 & 2, Final Report. NUREG-1742, 22 Washington, DC, April 2002.

23 Nuclear Regulatory Commission (NRC). 2004. Regulatory Analysis Guidelines of the U.S.

24 Nuclear Regulatory Commission. NUREG/BR-0058, Washington, DC, September 2004.

25 ADAMS Accession No. ML042820192.

26 Nuclear Regulatory Commission (NRC). 2007. Letter from Jill Caverly to Entergy,

Subject:

27 Request for Additional Information Regarding Severe Accident Mitigation Alternatives for IP2 28 and IP3 Nuclear Generating Unit Nos. 2 and 3 Licensee Renewal (TAC Nos. MD5411 and 29 MD5412), December 7, 2007. ADAMS Accession No. ML073110447.

30 Nuclear Regulatory Commission (NRC). 2008. Letter from Bo M. Pham to Entergy,

Subject:

31 Request for Additional Information Regarding the Review of the License Renewal Application for 32 IP2 and IP3 Nuclear Generating Unit Nos. 2 and 3 (TAC Nos. MD5411 and MD5412), April 9, 33 2008. ADAMS Accession No. ML080880104.

34 Nuclear Regulatory Commission (NRC). 2010. Atomic Safety and Licensing Board. LBP 35 13. 71 NRC (2010). slip op. at 10, 14-15.

36 U.S. Department of Agriculture (USDA). 2002. Census of Agriculture. Accessed at:

37 http://www.nass.usda.gov/census/ on April 26, 2005.us/ on April 26, 2009.

December 2010 G-51 NUREG-1437, Supplement 38

Appendix H U.S. Nuclear Regulatory Commission Staff Evaluation of Environmental Impacts of Cooling System

1 Appendix H 2 U.S. Nuclear Regulatory Commission 3 Staff Evaluation of 4 Environmental Impacts of Cooling System 5 H.1 Environmental Impacts of Cooling System 6 Environmental issues associated with the operation of a nuclear power plant during the renewal 7 term are discussed in the U.S. Nuclear Regulatory Commission (NRC) document, 8 NUREG-1437, Volumes 1 and 2, Generic Environmental Impact Statement for License 9 Renewal of Nuclear Plants (hereafter referred to as the GEIS) (NRC 1996, 1999).(a) The GEIS 10 includes a determination of whether the analysis of the environmental issues could be applied to 11 all plants and whether additional mitigation measures would be warranted. Issues are then 12 assigned a generic (Category 1) or site-specific (Category 2) designation. As set forth in the 13 GEIS, generic issues are those that have the following characteristics:

14 (1) The environmental impacts associated with the issue have been determined to apply 15 either to all plants or, for some issues, to plants having a specific type of cooling system 16 or other specified plant or site characteristics.

17 (2) A single significance level (i.e., SMALL, MODERATE, OR LARGE) has been assigned to 18 the impacts (except for collective offsite radiological impacts from the fuel cycle and from 19 high-level waste and spent fuel disposal).

20 (3) Mitigation of adverse impacts associated with the issue has been considered in the 21 analysis, and it has been determined that additional plant-specific mitigation measures 22 are likely not to be sufficiently beneficial to warrant implementation.

23 No additional plant-specific analysis is required for generic issues unless new and significant 24 information is identified. Site-specific issues do not have all the above characteristics, and a 25 plant-specific review is required.

26 This appendix addresses the issues that are listed in Table B-1, Appendix B, Subpart A, of 27 Title 10 of the Code of Federal Regulations (CFR), Part 51, Environmental Protection 28 Regulations for Domestic Licensing and Related Regulatory Functions, and that are related to 29 the operation of the cooling systems of Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 30 and IP3) during their renewal term. Section H.1 addresses the impingement of fish and shellfish 31 applicable to the IP2 and IP3 cooling systems. Section H.2 addresses the entrainment of fish 32 and shellfish applicable to the IP2 and IP3 cooling systems. Section H.3 addresses the 33 combined effects of impingement and entrainment, and Section H.4 discusses cumulative 34 impacts. Finally, Section H.5 lists the references for Appendix H. Category 1 and Category 2 35 issues that are not applicable to IP2 and IP3, because they are related to plant design features December 2010 H-1 NUREG-1437, Supplement 38

Appendix H 1 orsite characteristics not found at IP2 and IP3, are listed in Appendix F. As stated in Section 2 4.1 of this SEIS, the applicant submitted corrected impingement and entrainment data following 3 publication of the draft SEIS. The NRC staff considered those data as well as comments NRC 4 received regarding the draft SEIS in preparing this appendix.

5 H.1.1. Impingement of Fish and Shellfish 6 Impingement occurs when organisms are trapped against cooling water intake screens or racks 7 by the force of moving water. Impingement can kill organisms immediately or gradually, by 8 exhaustion, suffocation, injury, or exposure to air when screens are rotated for cleaning. The 9 potential for injury or death is generally related to the amount of time an organism is impinged, 10 its susceptibility to injury, and the physical characteristics of the screenwash and fish return 11 system that is employed. Studies of impingement losses associated with the operation of IP2 12 and IP3 cooling systems were conducted annually from 1975 to 1990. Before the installation of 13 modified Ristroph screen systems in 1991, impingement mortality was assumed to be 14 100 percent. Beginning in 1985, studies were conducted to evaluate whether the addition of 15 Ristroph screens would decrease impingement mortality for representative species. The final 16 design (Version 2), as reported in Fletcher (1990), appeared to reduce impingement mortality, 17 based on a pilot study, in comparison to the existing (original) system in place at IP2 and IP3 18 (Table H-1). The impingement survival estimates reported in Fletcher (1990) were not 19 validated, however, after the new Ristroph screens were installed at IP2 and IP3 in 1991.

20 Table H-1 Assumed Cumulative Mortality and Injury of Selected Fish Species after 21 Impingement on Ristroph Screens Percent Species Dead and Injured Alewife 62 American Shad 35 Atlantic Tomcod 17 Bay Anchovy 23 Blueback Herring 26 Hogchoker 13 Striped Bass 9 Weakfish 12 White Catfish 40 White Perch 14 Source: Fletcher 1990.

22 H.1.1.1. Summary of Impingement Monitoring Studies NUREG-1437, Supplement 38 H-2 December 2010

Appendix H 1 The former owners of IP2 and IP3 conducted impingement monitoring between 1975 and 1990 2 using a variety of techniques. Between January 1975 and June 1981, fish were collected and 3 sorted during a daily intake screen washing between 0800 and 1200 hours50 days <br />7.143 weeks <br />1.644 months <br /> (hr). In July 1981 4 and continuing through October 1990, fish were collected during intake screen washings 5 between 0800 and 1200 hr on selected days determined from a stratified random design 6 intended to reduce the overall sampling effort without affecting data use and utility. Between 7 October and December 1990, IP2 was sampled every Tuesday, and IP3 was not sampled 8 because of a plant outage. During all collections, the wash water was circulated to draw a 9 portion of the fish and debris into the forebay, where it was drained through a sluice containing a 10 1-millimeter (mm) (0.375-inch [in.]) square mesh screen. Collection efficiency was estimated in 11 1974, 1975, and 1977 at IP2. The results of these studies suggested that the collection 12 efficiency was highly variable (ranging from 2 percent to 45 percent based on the recovery of 13 dyed fish) and averaged 29 percent (Con Edison 1976, Con Edison 1979). Collection efficiency 14 at IP3 in 1976 and 1977 ranged from 58 percent to 86 percent recovery of dyed fish with an 15 average of 71 percent (Con Edison 1977, Con Edison 1979). The difference in the collection 16 efficiency at the two units was associated with the differences in the type of screens (fixed 17 versus traveling screens) and the method used for screen washing. To estimate the total 18 number of fish impinged, the total number of fish collected was multiplied by an adjustment 19 factor representing the inverse of the collection efficiency. From 1975 to 1978, adjustment 20 factors of 3.5 and 1.4 were used for IP2 and IP3, respectively (Con Edison 1980).

21 Analysis of variance and the correlation of environmental and IP2 and IP3 operation variables 22 were employed to explain the variation in collection efficiency. Early studies suggested that 23 collection efficiency increased during periods of low water temperature. In 1979, the adjustment 24 factor became a function of the time of year, based on the increase in collection efficiency when 25 water temperatures were less than 15EC (59F). Thus, cool water adjustment factors of 2.1 and 26 1.2 were adopted to estimate the number of fish impinged at IP2 and IP3, respectively, during 27 January through April, November, and December. For May to October, the adjustment factor 28 was 3.8 for IP2 and 1.5 for IP3. In 1981, the collection efficiency was estimated with a 29 regression relationship with temperature:

30 IP2 efficiency= E2 = -0.00945 (Temperature C) + 0.54708 31 IP3 efficiency= E3 = -0.00792 (Temperature C) + 0.71640 (Con Edison 1984).

32 These regression relationships were updated in 1982, and screen-specific adjustments were 33 devised from studies conducted in 1985 and 1986 (Table H-2).

34 Impingement monitoring designs changed through time (Con Edison 1980, Con Edison 1984, 35 Con Edison and NYPA 1986, Con Edison and NYPA 1987, Con Edison and NYPA 1988, Con 36 Edison and NYPA 1991) as follows. In 1979, the daily variation in impingement counts was 37 analyzed to determine its effect on the precision and accuracy of reduced sampling plans.

38 Starting in July 1981, a sampling plan employing a seasonally stratified random sample 39 developed from these results was used for all further impingement studies except the last 40 quarter of 1990. Instead of sampling daily, IP2 and IP3 were sampled a total of 110 days per 41 year (a 30-percent sampling fraction with approximately 92-percent accuracy) (Con Edison 42 1984). Days were selected at random within four calendar strata defined by similar water 43 temperatures and variance in the number of fish impinged (January-March, April-June, July-44 September, and October-December). The number of days sampled per stratum was December 2010 H-3 NUREG-1437, Supplement 38

Appendix H 1 proportional to the number of days available and the variance in impingement for all taxa 2 combined (Table H-3) (Con Edison 1984). The number of days allocated to strata was updated 3 in 1985 to take advantage of current data trends and again in 1990 because of known plant 4 outages. Even though IP2 and IP3 had different numbers of samples allocated to each stratum, 5 sampling was conducted on the same day at both units to the extent possible.

6 During 1981, the New York State Department of Environmental Conservation (NYSDEC) 7 required daily sampling when total impingement counts were greater than 10,000 fish. Daily 8 sampling was required to continue until the total was below 10,000 fish. Because these 9 sampling dates were not part of the stratified design, they were used in place of random dates 10 that were associated with unplanned unit outages. Outages were defined as circulating pump 11 outages and were not necessarily associated with cessation of power generation. In 1981, 12 randomly selected days that fell on planned outages were not replaced. From 1982 to 13 October 1990, to minimize the effect of planned and unplanned outages on the selected days 14 for collection, a randomly selected replacement day within the given stratum was sampled. In 15 October 1990, a systematic sampling design was employed that required sampling at IP2 each 16 Tuesday. No sampling was conducted at IP3 from October 1990 to December 1990 because of 17 an extended outage.

18 Sampling for blue crabs began in April 1983 and continued though December 1990. Sampling 19 was conducted on all days of plant operation. The total number of impinged crab and their total 20 weight were obtained for each sampling. In addition, the carapace width, total weight, and 21 observed condition were recorded for each collected individual.

22 Table H-2 Estimates of Collection Efficiency Based on Temporal Averages, Regressions 23 as a Function of Temperature, and Specific Screens Ristroph Screen Year IP2 Conventional Screen IP3 Conventional Screen Version1 1975-1978 29 percent 71 to 73 percent None installed Jan.-April = 48 percent Jan.-April = 83 percent 1979-1980 May-Oct. = 26 percent May-Oct. = 66 percent None installed Nov.-Dec. = 48 percent Nov.-Dec. = 83 percent 1981 E2 = -0.00945 T + 0.54708 E3 = -0.00792 T + 0.71640 None installed 1982-1985 E2 = -0.00871 T + 0.51858 E3 = -0.00792 T + 0.71640 None installed 24 NUREG-1437, Supplement 38 H-4 December 2010

Appendix H 1 Table H-2 (continued)

IP2 Conventional Ristroph Screen Year IP3 Conventional Screen Screen Version1 Jan.-Mar. = 70.8 percent Apr.-June = E2 or E3 E2 = -0.00871 T +

1986 E3 = -0.00792 T + 0.71640 July-Aug. = 18.7 percent 0.51858 Sept. = 29.6 percent Oct.-Dec. = E2 or E3 Jan.-Mar. = 74.4 percent Apr.-June = E2 or E3 E2 = -0.00871 T +

1987-1990 E3= -0.00792 T + 0.71640 July-Aug. = 18.7 percent 0.51858 Sept. = 29.6 percent Oct.-Dec. = E2 or E3 1

Number of Ristroph Screens at IP2. In 1986, a Ristroph Screen E2 - Collection Efficiency at IP2. was installed on Intake Bay 26.

E3 = Collection Efficiency at IP3.

T = Temperature in degrees C.

Sources: Con Edison 1980, Con Edison 1984, Con Edison and NYPA 1986, Con Edison and NYPA 1987, Con Edison and NYPA 1988, Con Edison and NYPA 1991.

2 Table H-3 Number of Days Allocated to Each Quarter Based on the Stratified Random 3 Sampling Design Allocation to IP2 Allocation to IP3 Total Stratum Dates in 1981; 1982-84; in 1981; 1982-84; Days 1985-89; and 1990 1985-89; and 1990 Winter Jan. 1-Mar. 31 90 N/Aa; 30; 23; 23 N/A; 27; 35; 35 Spring Apr. 1-June 30 91 N/A; 10; 8; 8 N/A; 18; 20; 20 Summer July 1-Sept. 30 92 11; 11; 11; 11 31; 31; 31; 31 Fall Oct. 1-Dec. 31 92 59; 59; 68; 13 34; 34; 24; 0 4 a N/A = Not Applicable, the reduced sampling began July 1, 1981 (Con Edison 1984).

5 Sources: Con Edison 1984, Con Edison and NYPA 1986, Con Edison and NYPA 1987, Con Edison and NYPA 1988, 6 Con Edison and NYPA 1991.

7 For all impingement studies, fish were sorted and counted completely if either the identified 8 species was white perch, striped bass, or tomcod, or the total number collected for a given 9 species was less than 100 individuals (with heads). All other sorted samples were enumerated 10 by subsampling and weighing to four general length classes. This information was used to 11 determine the total sample size. To estimate the number of fish impinged, the estimated daily 12 counts (taken before July 1981) were multiplied by the collection efficiency adjustment factor 13 (Con Edison 1984). During the period of stratified random sampling (July 1981-1990), the December 2010 H-5 NUREG-1437, Supplement 38

Appendix H 1 mean of the estimated number of fish counted within a stratum was multiplied by the collection 2 efficiency adjustment factor and the number of days of plant operation (Con Edison 1984).

3 H.1.1.2. Historic Assessment of Impingement Impacts 4 As discussed in the previous section, numerous studies have been conducted to evaluate the 5 effects of impingement associated with the Indian Point cooling systems. Studies have also 6 been conducted to evaluate the trends of fish populations in the Hudson River. Entergy Nuclear 7 Operations, Inc. (Entergy, or the applicant) and NYSDEC have used the results of these studies 8 to evaluate the potential for adverse effects associated with the operation of the Indian Point 9 cooling systems. The results of these assessments are described below. Nongovernmental 10 groups and members of the public have also evaluated publicly available information and data 11 associated with the Hudson River and have expressed the opinion that many species of fish in 12 the river are in decline and that the entrainment of juvenile and adult fish at Indian Point is 13 contributing to the decline, destabilization, and ultimate loss of these important aquatic 14 resources.

15 Applicant Assessment 16 In the draft environmental impact statement (DEIS) (CHGEC 1999) and environmental report 17 (ER) for license renewal (Entergy 2007), the applicant acknowledged that some impinged fish 18 survive and others die. Mortality can be immediate or occur at a later time (latent or long-term 19 mortality), and mortality rates depend on the species, the size of the fish, the waters 20 temperature and salinity, the design of the screens, the water velocity through the screen, the 21 length of time the fish was impinged, and the design and operation of the fish return system.

22 Impingement effects were examined by evaluating conditional mortality rates (CMRs) and 23 trends associated with population abundance for eight selected taxa representing 90 percent of 24 those fish species collected from screens at IP2 and IP3, including striped bass, white perch, 25 Atlantic tomcod, American shad, bay anchovy, alewife, blueback herring, and spottail shiner.

26 Estimates of the CMR, defined as the fractional reduction in the river population abundance of 27 the vulnerable age group caused by one source of mortality only, were assumed to be the same 28 as or lower than that which occurred in past years, caused by the installation of Ristroph 29 screens and fish return systems at IP2 and IP3. For species exhibiting low impingement 30 mortality (e.g., striped bass, white perch, and Atlantic tomcod), future impingement effects were 31 expected to be substantially lower than they were before the installation and use of the present 32 protective measures.

33 Central Hudson Gas and Electric Corporation (CHGEC) (1999) concluded that the maximum 34 expected total impingement CMR was 0.004 for white perch and less for all other taxa. The ER 35 (Entergy 2007) stated that the results of in-river population studies performed from 1974 to 1997 36 had not shown any negative trend in overall aquatic river species populations attributable to 37 plant operations:

38 NUREG-1437, Supplement 38 H-6 December 2010

Appendix H 1 More than 30 years of extensive fisheries studies of the Hudson River in the 2 vicinity of IP2 and IP3 support current operations. The results of the studies 3 performed from 1974 to 1997, the period of time covered in the DEIS, are 4 referenced and summarized in the DEIS, and have not shown any negative 5 trend in overall aquatic river species populations attributable to plant 6 operations...

7 The ER also stated that ongoing studies continue to support these conclusions. Thus, the 8 applicant determined impingement impacts to be small, suggesting that the withdrawal of water 9 from the Hudson River for the purposes of once-through cooling for IP2 and IP3 did not have 10 any demonstrable negative effect on representative Hudson River fish populations, nor did it 11 warrant further mitigation measures.

12 To support this assessment, the applicant provided two reviews, Barnthouse et al. (2002) and 13 Barnthouse et al. (2008). These reviews addressed the status and trends of fish populations 14 and communities of the Hudson River estuary in relation to the operation of Bowline Point, IP2 15 and IP3, and Roseton generating stations, which currently share a State Pollutant Discharge 16 Elimination System (SPDES) permit. Barnthouse et al. (2002) was based on a review of the 17 DEIS, comments on the DEIS abundance indices though 2000 (CHGEC 1999), and the annual 18 Year Class Report (ASA 2000). Barnthouse et al. (2008) was based on abundance indices 19 through 2005, the spawning stock biomass-per-recruit model (SSBR), and CMR estimates.

20 Although both reviews recognized that the long-term population trends reflected the combined 21 effects of entrainment and impingement, the 2008 report focused on entrainment and suggested 22 that the existing retrofits (Ristroph screens and fish returns) have resolved the concerns 23 regarding impingement. Additional discussions concerning the results of the Barnthouse et al.

24 (2008) analyses are provided in Section H.2.

25 NYSDEC Assessment 26 With respect to the operation of the IP2 and IP3 cooling systems, the NYSDEC regulatory role 27 includes protecting aquatic resources from impacts associated with impingement, entrainment, 28 and thermal and chemical discharges. Based on activities conducted under the Hudson River 29 Settlement Agreement (HRSA), subsequent Consent Orders, and existing agreements with the 30 operators of IP2 and IP3, Roseton, and Bowline Point power generation stations, NYSDEC 31 concluded that IP2 and IP3 have achieved some reductions in intake volumes through the use 32 of dual-speed and variable-flow pumps and have improved impingement survival through the 33 installation of modified Ristroph traveling screens (NYSDEC 2003a). However, NYSDEC stated 34 that while these represent some level of improvement compared to operations with no 35 mitigation or protection, there are still significant unmitigated mortalities from entrainment and 36 impingement at all three of the HRSA facilities. In a petition submitted to the NRC to intervene 37 in the IP2 and IP3 license renewal proceeding dated November 30, 2007, the NYSDEC stated 38 the following:

39 December 2010 H-7 NUREG-1437, Supplement 38

Appendix H 1 The plants outdated design and operation have caused significant adverse 2 environmental impacts to the Hudson River. These impacts include 3 impingement, entrainment, and heat shock to numerous fish species in the 4 Hudson, including the endangered sturgeon. In the alternative, even if the NRC 5 were to grant the license renewal application, it could only do that by 6 conditioning the renewal on the construction and use of closed-cycle cooling 7 water intake systems at IP2 and IP3. As was stated in the above contention on 8 impingement and entrainment, the perpetuation of once-through cooling here, 9 with its long history of massive injury and destruction of tens of millions of 10 Hudson River fish, is simply no longer tenable, either in fact or in law.

11 NYSDEC stated further that the applicant would need a Clean Water Act Section 316(b) 12 determination, a demonstration that the current cooling water intake structure reflects the best 13 technology available for minimizing adverse environmental impacts (NYSDEC 2007). However, 14 the NYSDEC states the following:

15 Entergy has not and could not demonstrate that its once-through cooling water 16 intake structures at IP2 and IP3 reflects the best technology available for 17 minimizing adverse environmental impacts. Indeed, the New York State 18 Department of Environmental Conservation has determined in the pending 19 SPDES permit renewal proceeding that closed-cycle cooling, and not once-20 through cooling, represents the best technology available for minimizing adverse 21 environmental impacts.

22 H.1.1.3. NRC Staff Assessment of Impingement Impacts 23 To assess impingement impacts, the NRC staff evaluated weekly estimated impingement 24 numbers at IP2 and IP3 from January 1975 to November 1980, and seasonally estimated 25 impingement numbers from January 1981 and December 1990. The combined numbers of 26 young of year (YOY), yearling, and older fish were used for analysis since these data were 27 available for all years of sampling.

28 29 The applicants monitoring data showed that a total of 141 fish taxa and blue crab were 30 collected and identified at IP2 and IP3 during this 16-year period. At IP2, the estimated number 31 of representative important species (RIS; as defined in Table 2-4 in the main text) fish impinged 32 made up greater than 85 percent of the total impinged (fish and blue crab; Figure H-1, solid 33 lines). Until 1984, the RIS fish made up at least 95 percent of the total impinged. When blue 34 crab are included with the RIS fish, the estimated number impinged made up greater than 90 35 percent of the total impinged for all but one year. The total number of fish and blue crab 36 impinged at IP2 has significantly decreased at a rate of 0.15 million per year (linear regression; 37 n = 16; p = 0.025) from 1975 to 1990. Total impingement approached or exceeded 4 million in 38 1977 and 1981 (Figure H-1, dashed line). Impingement of all fish and blue crab was lowest in 39 1984 (about 0.5 million).

40 NUREG-1437, Supplement 38 H-8 December 2010

Appendix H 100% 5.0 95% 4.5 90% 4.0 85% 3.5 3.0 80%

2.5 75%

2.0 70% 1.5 65% 1.0 Total Impinged at Unit 2 Percentage of Total Impinged 60% 0.5 (millions of Fish and Blue Crab) 55% 0.0 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 RIS Fish RIS Fish+Blue Crab Total Impinged Unit 2 1

2 Figure H-1 Percentage of impingement composed of RIS fish and RIS fish plus blue crab 3 relative to the estimated total impingement at IP2 (data from Entergy 2007b and 2009 [NL-4 09-131]).

5 At IP3, the estimated number of RIS fish impinged made up greater than or equal to 95 percent 6 of the total impinged except for the last three years (Figure H-2, solid lines). When blue crab 7 were included with the RIS fish, the estimated number impinged was greater than 85 percent for 8 all but one year. The total number of fish and blue crab impinged at IP3 significantly decreased 9 from 1976 to 1990 at a rate of 0.08 million per year (linear regression; n = 15; p = 0.002).

10 Except for 1983, for which IP3 had extensive outages, the numbers of fish and crab impinged 11 annually at IP2 are 2.6 times greater than those at IP3. The highest total impingement at IP3 12 occurred in 1977 at just over 1.8 million fish and blue crab; the lowest occurred in 1983 at about 13 0.03 million (Figure H-2, dashed line).

14 Total impingement trends at IP2 and IP3 suggest that the total number of fish and blue crab 15 impinged tended to decrease between 1977 and 1982, then leveled off between 1982 and 1990.

16 From 1975 to 1990, the number of days of operation at IP2 and IP3 has shown a general 17 increase of eight days per year for IP2 and five days per year for IP3 (linear regression, 18 p = 0.004 and p = 0.286 for IP2 and IP3, respectively). The total volume circulated at IP2 and 19 IP3 combined has also shown a general increase of 26.2 x 106 cubic meters (m3) (linear 20 regression, p = 0.164). If the IP2 and IP3 cooling systems are considered a relatively constant 21 sampler of Hudson River aquatic biota (recognizing the slight increase in frequency and volume 22 of water circulated), then the decrease in the percent of RIS impinged and total impingement 23 would suggest that RIS and all other taxa within the vicinity of IP2 and IP3 have decreased from 24 a high in 1977 to a relatively constant lower level of impingement between 1984 and 1990. This 25 will be explored further in Section H.3.

26 To determine trends in RIS impingement, the NRC staff examined quarterly data from IP2 and 27 IP3 from 1975 to 1990 (Table H-4). The two major time periods (1975-1980) and (1981-1990) 28 December 2010 H-9 NUREG-1437, Supplement 38

Appendix H 100% 5.0 Total Impinged at Unit 3 4.5 Percentage of Total Impinged 95%

90% 4.0 85% 3.5 3.0 80%

2.5 75%

(millions of Fish and Blue Crab) 2.0 70% 1.5 65% 1.0 60% 0.5 55% 0.0 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 RIS Fish RIS Fish+Blue Crab Total Impinged Unit 3 1

2 Figure H-2 Percentage of impingement composed of RIS fish and RIS fish plus blue crab 3 relative to the estimated total impingement at IP3 (data from Entergy 2007b and 2009 [NL-4 09-131]).

5 were analyzed separately to account for the differences in impingement sampling strategies 6 discussed above. Eight RIS taxa, including blue crab, accounted for 96 percent (IP2) and 93 7 percent (IP3) of the total number of RIS impinged over all years. During January to March 8 sampling events for both units and all years, white perch was the most commonly impinged 9 species, accounting for 78 to 98 percent of the RIS impinged. Impingement of RIS was more 10 variable during other sampling periods but was dominated by white perch, Atlantic tomcod, bay 11 anchovy, and blueback herring. The notable exception to this pattern occurred between 1981 12 and 1990, when the percentage of hogchoker and weakfish impinged increased at both units 13 during the spring and summer sampling periods compared to estimates obtained from 1975 to 14 1980 (Table H-4). Greenwood (2008) stated that power station cooling-water intake screens 15 are effective estuarine fish sampling devices. Therefore, if we regard the cooling systems 16 associated with IP2 and IP3 as an efficient environmental sampler, then the patterns observed 17 in the impingement data could indicate a change in species composition in the vicinity of IP2 18 and IP3 occurred in the 1980s.

19 20 As a result of the HRSA, operational measures were implemented to reduce the loss of aquatic 21 resources to impingement. These measures included the installation of dual-speed intake 22 pumps at IP2 in 1984, installation of variable-speed pumps at IP3 in 1985, and the installation of 23 modified Ristroph screens and fish-return systems at both units in 1991. The plant operators 24 also developed programs to employ flow-reduction measures and scheduled outages to reduce 25 impingement and entrainment impacts. Flow rates are dependent on intake water temperature, 26 with increased flow required when water temperatures rise above 15 C. For example, the 27 average monthly water temperatures taken near Poughkeepsie, New York from 1992 to 2006 28 (Figure H-3) suggests to NRC staff that greater flow would be required during the months of NUREG-1437, Supplement 38 H-10 December 2010

Appendix H 1 May through October. This roughly corresponds to the second and third quarters of 2 impingement sampling (April-September timeframes in Table H-4). The seasonal percentage 3 of RIS fish impinged as a function of the annual number of RIS fish impinged at IP2 was 4 significantly different between seasons with January to March greater than April to June 5 (Kruskal-Wallis, p = 0.04). Thus, a greater percentage of impingement occurred at IP2 when 6 the average intake water flow was relatively low compared to the rest of the year. The median 7 seasonal percentage impinged over years was 14 to 32 percent.

8 9 Percentage of RIS taxa impinged as a function of the annual number of RIS taxa impinged at 10 IP3 was not significantly different among seasons (Kruskal-Wallis, p = 0.25; Figure H-4). Thus, 11 even though the plants withdrew a greater volume of water between May and October (analysis 12 of variance (ANOVA), p = 0.02 with a CV = 41 percent and p = 0.53 with a CV = 61 percent for 13 IP2 and IP3, respectively), impingement did not increase during these periods. Instead, the 14 seasonal pattern of impingement may reflect times when susceptible fish are present near the 15 facility.

16 17 Table H-4 Average Percentage Impingement of RIS Compared to Total Impingement per 18 Season for 1975-1980 and 1981-1990 for Selected Taxa (data from Entergy 2007b)

IP2 COOLING SYSTEM 1975-1980 1981-1990 Percent RIS Species Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- of Mar Jun Sep Dec Mar Jun Sep Dec RISTaxa1 White Perch 96 35 17 38 93 44 13 62 50 Atlantic 1 55 27 1 1 35 24 3 14 Tomcod Bay Anchovy 0 2 32 7 0 5 23 8 11 Blueback 0 0 10 45 0 0 2 11 14 Herring Hogchoker 0 3 4 3 0 10 12 4 2 Weakfish 0 0 3 0 0 0 9 2 2 Striped Bass 2 0 2 1 4 1 2 4 2 Blue Crab NA NA NA NA 0 0 14 2 1 Percent of 100 99 99 96 99 98 99 98 982 RIS Fish 19 December 2010 H-11 NUREG-1437, Supplement 38

Appendix H 1 Table H-4 (continued)

IP3 COOLING SYSTEM 1975-1980 1981-1990 Percent RIS Species Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- of Mar Jun Sep Dec Mar Jun Sep Dec RISTaxa1 White Perch 95 55 10 43 91 62 16 56 51 Atlantic 0 23 40 2 0 14 16 2 17 Tomcod Bay Anchovy 0 3 23 2 0 6 17 3 8 Blueback 0 3 6 38 0 3 2 27 10 Herring Hogchoker 0 5 8 1 0 8 15 2 3 Weakfish 0 0 3 0 0 0 5 1 1 Striped Bass 2 1 1 6 5 1 1 2 2 Weak Fish NA NA NA NA 0 1 20 6 2 Percent of 99 98 98 98 99 98 99 99 97 2

RIS Fish 1

RIS Taxa include Blue Crab.

2 Percent of RIS Taxa out of all impinged taxa.

NA = Not included in data collection.

2 30 Monthly Average Water Temperature (°C) 25 20 15 below Poughkeepsie, NY 10 5

0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 3

4 Source: U.S. Geological Survey Surface Water Data, http://waterdata.usgs.gov/usa/nwis/uv?site_no=01372058.

5 6 Figure H-3 Average monthly water temperature taken from below Poughkeepsie, NY, 7 from 1992 to 2006.

NUREG-1437, Supplement 38 H-12 December 2010

Appendix H 45%

40%

Percent of Annual Total 35%

30%

25%

20%

15%

10%

5%

0%

Jan-Mar Apr-Jun Jul-Sep Oct-Dec Unit 2 Impingement Unit 3 Impingement Unit 2 Flow Unit 3 Flow 1

2 Figure H-4 Seasonal percentage of RIS fish impinged out of the annual total taxa 3 impinged and the seasonal percentage of the volume circulated out of the annual total 4 volume circulated from 1975-1990 (data from Entergy 2007b and 2009).

5 Based on the above NRC staff analyses, the species with the highest percentage of 6 impingement at IP2 and IP3 from 1975 to 1990 were white perch, Atlantic tomcod, blueback 7 herring, bay anchovy, and hogchoker. Impingement trends for both units show that each of 8 these species was impinged during at least one sampling season in quantities representing at 9 least 10 percent of the total impingement counts for that period. During some sampling 10 seasons, a single species represented over 90 percent of the total impingement (e.g., white 11 perch during January to March). Impingement magnitude does not appear to be directly related 12 to flow; rather, the available information suggests that the frequency of impingement is 13 associated with seasonal patterns of fish and their proximity to IP2 and IP3. The environmental 14 significance of impingement is explored further in Section H-3.

15 H.1.2. Entrainment of Fish and Shellfish in Early Life Stages 16 Entrainment occurs when small aquatic life forms are carried into and through the cooling 17 system as water is withdrawn for use in the plants cooling system. Entrainment can affect 18 organisms smaller than the screen mesh (0.25 to 0.5 in.) that are carried into the plant with the 19 pumped water mass and have limited swimming ability to escape. This includes phytoplankton, 20 microzooplankton, and macrozooplankton. Entrained organisms also include the young life 21 stages of fish (eggs, larvae, post-yolk-sac larvae [YSL], and juveniles) and shellfish.

22 Entrained organisms pass through the circulating pumps and are carried with the flow through 23 the intake conduits toward the condenser units. They are then drawn through one of the many 24 condenser tubes used to cool the turbine exhaust steam and enter the discharge canal for December 2010 H-13 NUREG-1437, Supplement 38

Appendix H 1 return to the water. As entrained organisms pass through the intake, they may be injured from 2 abrasion or compression. Within the cooling system, they encounter physical impacts in the 3 pumps and condenser tubing, pressure changes, sheer stress, thermal shock, and chemical 4 exposure to chlorine and residual industrial chemicals discharged at the diffuser ports (Mayhew 5 et al. 2000). Death can occur immediately (direct effect) or after being discharged (indirect 6 effect) from an inability to escape predators, a reduced ability to forage, or other factors.

7 The former owners of IP2 and IP3 conducted studies of entrainment loss associated with IP2 8 and IP3 in 1981 and then annually from 1983 to 1987. Entrainment survival is a disputed 9 subject. The U.S. Environmental Protection Agency (EPA) assumes that the mortality 10 associated with entrainment is 100 percent (NYSDEC 2003a). Consolidated Edison Company 11 of New York (Con Edison) and New York Power Authority (NYPA 1984) assume that, for the 12 more delicate species (bay anchovy, American shad, clupeids), mortality was 100 percent.

13 However, for other species, mortality could be separated into thermal and mechanical 14 components and overall was less than 100 percent. By 1987, Con Edison estimated the 15 survival of entrained bay anchovy could be up to 52 percent (EA 1989). This assessment 16 recognizes that 96-hr survival of fish following entrainment is not a measure of the potential 17 reduction in ability to forage and avoid predation within hours or days of being discharged at the 18 diffuser ports. Thus, indirect losses for a given species from entrainment for the purpose of this 19 assessment are unknown.

20 H.1.2.1. Summary of Entrainment Survival Monitoring Studies 21 Entrainment studies to evaluate the survival of entrainable aquatic organisms (eggs, larvae, 22 YSL, small juveniles) have been conducted at IP2 and IP3 since the early 1970s. A variety of 23 sampling gear has been employed. Study endpoints included estimates of immediate and latent 24 mortality by monitoring collected organisms for up to 96 hr. Initial monitoring efforts were based 25 on the assumption that survival of organisms collected by nets was the same from intake canal 26 samples as it was from discharge canal samples. It was discovered, however, that differences 27 in water velocity at intake and discharge sampling stations may have affected ichthyoplankton 28 survival, and subsequent studies demonstrated that the survival of striped bass eggs and larvae 29 collected using fixed nets were velocity dependent. Based on these results, entrainment 30 survival sampling at IP2 and IP3 in 1977 and 1978 was expanded to include new sampling gear 31 designed to reduce or eliminate the effects of intake and discharge water velocity on apparent 32 postcollection survival. The primary change involved the use of centrifugal pumps to transport 33 water into a flume and larval collection table, where water quality conditions could be optimized 34 and samples concentrated for survival and latent mortality analyses. In spite of these 35 refinements, entrainment survival estimates derived from the pump/larval table collection 36 system were again compromised by poor ichthyoplankton survival in control samples collected 37 in front of intakes representing initial larval conditions before passage through the IP2 and IP3 38 cooling systems.

39 Subsequent revisions to sampling gear were employed in 1979, 1980, and 1989, and are 40 discussed below. Because the survival estimates conducted before 1979 were significantly 41 compromised by sampling gear design and choice, the NRC staff focused on the later studies to 42 evaluate entrainment mortality at IP2 and IP3. Sampling was also conducted in 1985 to 43 determine the effects of entrainment mortality resulting from an upgrade to the pumping system NUREG-1437, Supplement 38 H-14 December 2010

Appendix H 1 associated with IP2. The results of this study are not directly comparable to the 1979 and 1980 2 studies, because a different sampling design was employed.

3 Details of the 1979 entrainment survival and related studies are presented in EA (1981a).

4 Entrainment survival studies were conducted during two separate sampling periods, the late 5 winter season from March 12 to 22, 1979, to evaluate the larvae of Atlantic tomcod (M. tomcod),

6 and in the spring-summer season from April 30 to August 14, 1979, to evaluate early life-stages 7 of striped bass (M. saxatilis), white perch (M. americana), herring (Clupeidae), and anchovies 8 (Engraulidae). During the winter season, sampling with a pump/larval table collection system 9 was conducted at the intakes associated with IP2 and IP3, in the IP3 effluent before it enters the 10 discharge canal, and in portions of the discharge canal containing effluent water from both units.

11 The shutdown of IP3 from March 20 to 22, 1979 provided an opportunity to evaluate Atlantic 12 tomcod larval survival under one- and two-unit operation. During the spring-summer season, a 13 raft-mounted flume collection was used for the first time at IP2 and IP3. This system was 14 designed to reduce sampling stress on target organisms by taking advantage of head pressure 15 created by a difference between water levels on either side of the flume apparatus. The 16 shutdown of IP2 after June 16, 1979, provided an opportunity to assess the survival of other 17 species during both one- and two-unit operation.

18 For the Atlantic tomcod study during the winter of 1979, sampling was initiated upon notification 19 of the first occurrence of tomcod larvae and conducted on four consecutive nights per week 20 over the two-week sampling period from March 12 to 22, for a total of eight sampling days.

21 Sampling occurred between 1700 and 0200 hr to coincide with the diel period of peak larval 22 abundance. At the beginning of the study, both IP2 and IP3 units were operating, but an 23 unscheduled shutdown of IP3 occurred on March 20 and continued through the remainder of 24 the study. Although the unit did not generate power, two circulating water pumps continued to 25 operate. Thus, for the tomcod study, a total of 11 circulating pumps were operating from 26 March 12 to 19 (6 at IP2, 5 at IP3), and a total of eight pumps were operating from March 20 to 27 22 (6 at IP2, 2 at IP3). The pump/larval table collection system used for the tomcod study 28 consisted of a modular two-screen collection flume that allowed collection of larval samples with 29 minimal sampling stress associated with turbulent flow or temperature changes. Sample water 30 was delivered to the table by two centrifugal pumps equipped with flowmeters. Collected 31 entrainment samples were transferred to an onsite laboratory for sorting, where icthyoplankton 32 were sorted and classified as live (fish, eggs), stunned (fish only), or dead (fish and eggs).

33 Dead eggs and larvae were preserved; live or stunned fish or eggs were transferred to holding 34 facilities to determine latent effects on survival at 3, 6, 12, 24, 48, 72, and 96 hr. Specific 35 sampling procedures are discussed in the EA (1981a).

36 The spring-summer sampling to evaluate entrainment survival of striped bass, white perch, 37 herrings, and anchovies was conducted from April 30 to August 14, 1979, coincident with the 38 primary spawning and nursery seasons of these species. Samples were collected on 39 two consecutive nights each week for a total of 32 sampling days from 1800 to 0200 hr that 40 coincided with maximum abundance. As described above, a pumpless, rear-draw plankton 41 sampling flume mounted on rafts was employed during this study to minimize stress associated 42 with the use of centrifugal pumps. The volume of water samples collected from all samplers 43 was measured with integrated flowmeters, and vertical 505-micron (m) mesh screens were 44 employed to divert entrained organisms into collection boxes, where they were concentrated 45 and processed to determine latent survival as described for the tomcod study.

December 2010 H-15 NUREG-1437, Supplement 38

Appendix H 1 EA (1982) presents details of the 1980 entrainment survival and related studies. In 1980, 2 entrainment survival sampling at IP2 and IP3 was conducted from April 30 to July 10. Sampling 3 was focused on entrainable life stages of striped bass (M. saxatilis), white perch (M.

4 americana), herrings (Clupeidae), and anchovies (Engraulidae). Juvenile Atlantic tomcod (M.

5 tomcod) were also collected. To correct possible sources of gear-related effects on study 6 results, the rear-draw and pumpless plankton flumes used in 1979 were modified with flow 7 diffusion panels and slotted standpipes installed behind the angled diversion screens. These 8 refinements were intended to more evenly distribute the water across the surface of the screens 9 and eliminate localized areas of high-velocity flow that may have caused impingement. This, 10 along with other improvements to the sampling system, was expected to decrease the gear-11 related mortality observed in control samples from the intakes at IP2 and IP3.

12 Entrainment survival sampling for striped bass, white perch, herring and anchovies was 13 conducted from April 30 to July 10, 1980, coinciding with the primary spawning and nursery 14 seasons of these taxa. Samples were collected on 4 consecutive nights each week for a total of 15 44 sampling days between the hours of 1600 and 0200. Sampling was conducted at discharge 16 canal station DP and at the IP3 intake using the modified rear-draw plankton sampling flumes.

17 Live and dead icthyoplankton collected during the study were sorted at the onsite laboratory 18 immediately after sample collection and classified as live (fish and eggs), stunned (fish only), or 19 dead (fish and eggs). Dead eggs and larvae were preserved; live or stunned fish or eggs were 20 transferred to holding facilities to determine latent effects with checks at 3, 6, 12, 24, 48, 72, and 21 96 hr.

22 During the summer and early fall of 1984, dual-speed cooling water pumps were installed at 23 IP2. In 1985, variable-speed pumps were installed at IP3. The specific objectives of the 1988 24 entrainment studies were to (1) estimate the initial and extended survival of ichthyoplankton 25 entrained at IP2 and IP3 and compare the results to those from previous years, (2) determine 26 whether live and dead ichthyoplankton are randomly dispersed in the IP2 and IP3 discharge 27 canal at sampling station D2, and (3) assess whether the thermal and mechanical components 28 of entrainment stress are independent. The study description that follows was obtained from 29 the EA (1989).

30 The 1988 study EA (1989) was designed to sample 180 m3 per day with each flume system.

31 One flume was deployed at intake Station IP3; two flumes were deployed at discharge station 32 D2. The original design required that flumes be operated 3 days per week from May 23 to 33 June 30, 1989, resulting in 18 total sampling days. Specific daily volume requirements and 34 numbers of sampling days were developed to ensure sufficient numbers of organics were 35 collected. Because of a number of logistical challenges, the actual number of sampling days 36 was 13, from June 8 to 30. The flume design and collection procedures employed in 1988 were 37 consistent with previous studies described above. Average daily sample volumes collected at 38 the intake were 143.3 m3, and the daily combined volume sampled by both flumes in the 39 discharge canal was 271.2 m3. The sampling program was conducted during afternoon and 40 evening hours (1300-2300). Live and dead icthyoplankton collected during the study were 41 sorted at the onsite laboratory immediately after sample collection and classified as described 42 above. Other studies conducted in 1988 included sampling stress evaluations to provide a 43 better understanding of mortality caused by sampling stress at intake versus discharge 44 sampling locations, direct release studies to augment entrainment studies based on wild fish NUREG-1437, Supplement 38 H-16 December 2010

Appendix H 1 captures, and net studies in the discharge canal to provide additional information on 2 icthyoplankton distribution.

3 The results of entrainment survival from the 1977-80, 1985, and 1988 studies are presented in 4 EA (1989) for initial intake survival (EA 1989, Figure 4-8), initial discharge survival (EA 1989, 5 Figure 4-9), and overall entrainment survival (EA 1989, Figure 4-10). Summary information for 6 the 1979, 1980, and 1988 study years are summarized in Table H-5 below:

7 Table H-5 Entrainment Survival Estimates for Study Years 1979, 1980, and 1988 Estimated Initial Intake Initial Discharge Entrainment Species Proportion Proportion Proportion Survival Survival Survival Bay Anchovy PYSL ~0.09-0.32 ~0.01-0.05 ~0.12-0.52 Striped Bass YSL ~0.52-0.95 ~0.61 ~0.62-0.72 Striped Bass PYSL ~0.50-0.95 ~0.70-0.78 ~0.68-0.80 White Perch PYSL ~0.15-0.95 ~0.19-0.85 ~0.30-0.92 Alosa spp. PYSL ~0.25-0.90 ~0.30-0.60 ~0.30-0.65 Adapted from Figures 4-8-4-10 in EA (1989).

8 H.1.2.2. Summary of Entrainment Abundance Monitoring Studies 9 During 1981, EA employed an Automated Abundance Sampler (AUTOSAM) to collect 10 icthyoplankton samples from IP2 and IP3. Mid-depth water samples were collected 11 twice a week during May-August from discharge station D2. Each sampling effort 12 consisted of collecting 90-minute (min) composite samples within eight 3-hr sampling 13 intervals extending over a 24-hr period. Ichthyoplankton samples were sorted, 14 identified to species and life stage, and counted (EA 1981b). In 1983, entrainment 15 abundance samples were again collected at discharge canal station D2 from May 3 to 16 August 13, 1983, using the AUTOSAM collector. From May 3 to 18, each sample 17 consisted of a 90- min composite sample within eight 3-hr sampling periods. From May 18 19 to August 13, the 90-min composites reflect a shorter collection time to reduce 19 clogging caused by the presence of detritus. Ichthyoplankton samples were sorted, 20 identified to species and life stage, and counted (EA 1984). In 1984, icthyoplankton 21 samples were collected from discharge canal station D2 from May 3 to August 11, 1984.

22 Sampling equipment, collection procedures, and sample processing were consistent 23 with past sampling efforts described above (EA 1985).

24 In 1985, ichthyoplankton samples were taken continuously (24 hr per day) from May 1 to 25 August 11. Each sample consisted of one 3-hr period, resulting in eight samples per day. Total 26 sample volumes were 150 m3. Replicate sampling to determine variance estimates was 27 conducted on Wednesdays and Thursdays of each week. Samples were collected by pumping 28 water through a 10-centimeter (cm) (4-in.) diameter pipe submerged to a depth of 3 m at 29 discharge canal Station D2 and passing the collected water into a plankton net with a codend 30 cup. The collected sample was transferred to a sample jar, preserved, and transferred to a December 2010 H-17 NUREG-1437, Supplement 38

Appendix H 1 laboratory for sorting, identification to species and life stage, and enumeration (Normandeu 2 1987a). Pump samples to quantify ichthyoplankton entrained at IP2 and IP3 were collected 3 from May 1 to August 10, 1986, at discharge canal station D2. Sampling duration was 3 hr 4 without replication from May 1 to May 14, and 2 hr from May 15 to August 10 to increase the 5 number of collected samples. Replicate sampling to provide variance estimates were collected 6 five days per week from May 16 through August 10. Sampling equipment and processing were 7 consistent with the 1985 sampling study (Normandeu 1987b). In 1987, pump samples to 8 determine ichthyoplankton entrainment abundance were collected 24 hr per day from May 6 to 9 August 10 from discharge canal station D2. Sample duration was 2 hr, which allowed a large 10 number of samples to be collected. Replicate sampling to provide variance estimates was 11 collected five days per week from May 6 to August 7 (Normandeu 1988).

12 H.1.2.3. Historic Assessment of Entrainment Impacts 13 As discussed in Sections 4.1.2.1 and 4.1.2.2 of the SEIS, numerous studies have been 14 conducted to estimate the quantity of RIS that are entrained by the Indian Point cooling systems 15 and evaluate the survival of these species after entrainment occurs. Studies have also been 16 conducted to evaluate the trends of fish populations in the Hudson River. The applicant and 17 NYSDEC have used the results of these studies to evaluate the potential for adverse effects 18 associated with the operation of the Indian Point cooling systems. The results of these 19 assessments are described below. As described in Section 4.1.1.2 of the SEIS, 20 nongovernmental groups and members of the public have also evaluated publicly available 21 information and data associated with the Hudson River and have expressed the opinion that 22 many species of fish in the river are in decline and that entrainment of eggs, larval, and juvenile 23 fish at Indian Point is contributing to the decline, destabilization, and ultimate loss of these 24 important aquatic resources.

25 Applicant Assessment 26 In the environmental report for IP2 and IP3 (Entergy 2007), the applicant presents estimates of 27 CMR for American shad, Atlantic tomcod, bay anchovy, river herring, striped bass, and white 28 perch and discusses the results of the assessment conducted by Barnthouse et al. (2002). The 29 conclusions of the ER are as follows:

30 More than 30 years of extensive fisheries studies of the Hudson River in the 31 vicinity of IP2 and IP3 support current operations. The results of the studies 32 performed from 1974 to 1997, the period of time covered in the DEIS, are 33 referenced and summarized in the DEIS, and have not shown any negative 34 trend in overall aquatic river species populations attributable to plant operations.

35 Ongoing studies continue to support these conclusions [ASA]. In addition, 36 current mitigation measures implemented through the HRSA and retained in the 37 four Consent Orders, the current agreements with NYSDEC, and the outcome of 38 the draft SPDES Permit proceeding, will ensure that entrainment impacts remain 39 SMALL during the license renewal term. Therefore, withdrawal of water from 40 the Hudson River for the purposes of once-through cooling at the site does not 41 have any demonstrable negative effect on representative Hudson River fish 42 populations, nor does it warrant further mitigation measures.

NUREG-1437, Supplement 38 H-18 December 2010

Appendix H 1 Additional impact assessment information was also provided to the NRC staff in Barnthouse 2 et al. (2008) that used environmental risk-assessment techniques to evaluate the potential for 3 adverse impacts to Hudson River RIS from a variety of natural and anthropogenic stressors, 4 including the operation of the IP2 and IP3 cooling water intake system (CWIS), fish pressure, 5 the presence of zebra mussels, predation by striped bass, and water temperature. Summary 6 results available in Barnthouse et al. (2008) are presented in Table H-6. Using this information, 7 the authors concluded the following:

8 Considered together, the evidence evaluated in this report shows that the 9 operation of IP2 and IP3 has not caused effects on early life stages of fish that 10 reasonably would be considered adverse by fisheries scientists and/or 11 managers. The operation of IP2 and IP3 has not destabilized or noticeably 12 altered any important attribute of the resource.

13 Table H-6 Summary of Impact Assessment for IP2 and IP3 Species Suspected Cause of Apparent Hudson River Decline CWIS and zebra mussel hypothesis rejected.

American Shad Most likely cause: fishing, with striped bass predation a potential contributing factor (Barnthouse et al. 2008, Table 5).

CWIS hypothesis rejected.

Atlantic Tomcod Temperature is a significant influence, but cannot explain post-1990 decline. Most likely cause of decline: striped bass predation (Barnthouse et al. 2008, Table 6).

CWIS hypothesis rejected.

Bay Anchovy Striped bass predation most likely cause of change (Barnthouse et al. 2008, Table 8).

CWIS and zebra mussel hypothesis rejected.

River Herring Most likely cause: striped bass predation (Barnthouse et al.

2008, Table 7).

CWIS and zebra mussel hypothesis rejected. Most likely Striped Bass cause: fishing (Barnthouse et al. 2008, Table 3).

CWIS hypothesis rejected.

Zebra mussel and striped bass predation may have White Perch contributed to declines occurring in later years, but other unknown causes were responsible for declines occurring between 1975 and 1985 (Barnthouse et al. 2008, Table 4).

Source: Entergy 2008, adapted from Barnthouse et al. 2008.

14 NYSDEC Assessment 15 In 2003, NYSDEC developed a Final Environmental Impact Statement (FEIS) for the draft 16 SPDES permit (NYSDEC 2003a) in response to the DEIS submitted by the operators of IP2 and December 2010 H-19 NUREG-1437, Supplement 38

Appendix H 1 IP3, Roseton, and Bowline Point (CHGEC 1999). In the FEIS, NYSDEC noted that while the 2 DEIS was acceptable as an initial evaluation and assessment, it was not sufficient to stand as 3 the final document, and additional information as to alternatives and evaluation of impacts must 4 be considered. The Public Comment Summary portion of the NYSDEC FEIS presents a 5 summary of comments received on the 1999 DEIS (CHGEC 1999); a subsequent section, 6 Responses to Comments, provides the NYSDEC reply. In response to comments associated 7 with the cropping of fish populations by power plants, NYSDEC provided a detailed response.

8 The following excerpt from pages 53 and 54 of the document presented by NYSDEC at the time 9 of the FEIS publication:

10 Rather than selective cropping, the impacts associated with power plants are 11 more comparable to habitat degradation; the entire natural community is 12 impacted. These once-through cooling power plants do not selectively harvest 13 individual species. Rather, impingement and entrainment and warming of the 14 water impact the entire community of organisms that inhabit the water column.

15 For example, these impacts diminish a portion of the forage base for each 16 species that consumes plankton (drifting organisms in the water column) or 17 nekton (mobile organisms swimming through the water column) so there is less 18 food available for the survivors. In an intact ecosystem, these organisms serve 19 as compact packets of nutrients and energy, with each trophic (food chain) level 20 serving to capture a diffuse resource and make it more concentrated.

21 Ichthyoplankton (fish eggs, larvae and very small fish which drift in the water 22 column) and small fish feed on a base of zooplankton (drifting animal life) and 23 phytoplankton (drifting plant life). The loss of these small organisms in the 24 natural community may be a factor that leads to harmful algal blooms. The 25 small fish themselves serve as forage for the young of larger species, which 26 serve as forage for larger individuals, and so on up the food chain, more 27 correctly understood as a trophic pyramid. Once-through cooling mortality 28 short-circuits the trophic pyramid and compromises the health of the natural 29 community. For example, while an individual bay anchovy might ordinarily serve 30 as food for a juvenile striped bass or even for a common tern, entrainment and 31 passage through a power plants cooling system would render it useful only as 32 food to lower trophic level organisms. It could no longer provide its other 33 ecosystem functions of consuming phytoplankton, digesting and concentrating it 34 into its tissues, and ranging over a wide area, distributing other nutrients as 35 manure. This is just a single example from a very complex natural system, 36 where the same basic impact is multiplied millions of times over more than one 37 hundred fish species.

38 NYSDEC also expressed concern about entrainment in the 2003 Fact Sheet pertaining to 39 SPDES license renewal at IP2 and IP3 (NYSDEC 2003b, Attachment B, 1. Biological Effects):

40 1. Biological Effects 41 Each year Indian Point Units 2 and 3 (collectively Indian Point) cause the 42 mortality of more than a billion fish from entrainment of various life stages of 43 fishes through the plant and impingement of fishes on intake screens.

44 Entrainment occurs when small fish larvae and eggs (with other aquatic 45 organisms) are carried into and through the plant with cooling water, causing NUREG-1437, Supplement 38 H-20 December 2010

Appendix H 1 mortality from physical contact with structures and thermal stresses.

2 Impingement occurs when larger fish are caught against racks and screens at 3 the cooling water intakes, where these organisms may be trapped by the force 4 of the water, suffocate, or otherwise be injured. Losses at Indian Point are 5 distributed primarily among seven species of fish, including bay anchovy, striped 6 bass, white perch, blueback herring, Atlantic tomcod, alewife, and American 7 shad. Of these, Atlantic tomcod, American shad, and white perch numbers are 8 known to be declining in the Hudson River (ASA Analysis and Communications 9 2002). Thus, current losses of various life stages of fishes are substantial.

10 Finally, in the petition to intervene submitted to the NRC on November 30, 2007, regarding the 11 relicensing of IP2 and IP3 (NYSDEC 2007), the NYSDEC commented on impingement and 12 entrainment impacts:

13 Impingement and Entrainment Contention 14 The operation of Indian Point consumes and returns approximately 2.5 billion 15 gallons of Hudson River water each day. The river is an important estuarine 16 ecosystem, and this operation has significant adverse impacts to the fish that 17 call the Hudson home. Large fish are impinged on screens at the water intake 18 where they are severely stressed and then suffocated. Smaller fish are 19 entrained in the water intake, pulled through the operating plant and killed. This 20 relentless process has continued relatively unabated for almost 40 years, and 21 the applicant now seeks 20 more years. This must not continue because the 22 environmental costs are too high. The NRC must fully consider the alternative of 23 closed cycle cooling to mitigate these significant adverse impacts in this license 24 renewal proceeding.

25 H.1.2.4. NRC Staff Assessment of Entrainment Impacts 26 Entergy (2007b) provided data to the NRC staff. Entrainment data included weekly average 27 densities of entrained taxa for a given life stage for IP2 and IP3 for analysis. Entrainment data 28 were collected from May to August in 1981 and 1983 through 1985, from January to August in 29 1986, and from May to August in 1987. NRC staff estimated the number entrained per week by 30 life stage and taxon as the product of the mean weekly density entrained and the sum of the 31 weekly volume of circulated water (m3) at IP2 and IP3. The NRC staff used the sum of the 32 weekly numbers entrained of all life stages for a given taxon and season (January-March, 33 April-June, July-September, and October-December) to estimate the seasonal number 34 entrained per taxon.

35 The NRC staff found that the entrainment monitoring data provided by the applicant comprised 36 66 identified taxa. There were no blue crab, shortnose or Atlantic sturgeon, or gizzard shad 37 identified in the 1981-1987 entrainment data. Because of the difficulty in identification of early 38 life stages, RIS included those taxa identified only to family or genus (Alosa spp., anchovy 39 family, and Morone spp.). NRC compared the percent RIS fish entrained and total identified fish 40 entrained to the total number entrained (Figure H-5). Except for two weeks in 1984 and 1985 41 (one week in May and June) for which amphipods (Gammarus sp.) were recorded, the 42 percentage RIS fish entrained was greater than 70 percent of entrained taxa. The number of 43 amphipods collected in two weeks in 1984 was more than 2.5 times greater than the number of December 2010 H-21 NUREG-1437, Supplement 38

Appendix H 1 identified fish collected over 15 weeks within the same year. Linear regression (n = 6; p < 0.01) 2 indicated that the number of identified fish entrained decreased at a rate of 187 billion fish per 3 year, a result consistent with the decrease observed in the number of fish impinged.

4 NUREG-1437, Supplement 38 H-22 December 2010

Appendix H 100% 35 90%

30 80%

Percentage Entrained out of Total 70% 25 Total Entrained (x 1011) 60%

20 50%

15 40%

30% 10 20%

5 10%

0% 0 1980 1981 1982 1983 1984 1985 1986 1987 1988

% RIS Fish  % Total Identified Fish Total Number Entrained 1

2 3 Figure H-5 Percentage of entrainment composed of RIS fish and total identified fish 4 relative to the estimated total entrainment at IP2 and IP3 combined (data from Entergy 5 2007b) 6 NRC staff evaluated the seasonal pattern in the percentage entrainment of each RIS relative to 7 the total RIS fish entrained (Table H-7). Entrainment of American shad, Alosa spp. (i.e., not 8 identified to species), white perch, and striped bass occurred mainly in the second quarter 9 (April-June). Entrainment of weakfish and hogchoker occurred mainly in the third quarter 10 (July-September). The greatest percentage of rainbow smelt and Atlantic tomcod occurred in 11 the first quarter (January-March) of 1986. The taxa (lowest level identified) representing 10 12 percent or greater of total RIS entrained for at least one sampling period were Alosa spp.,

13 anchovy family, Atlantic tomcod, bay anchovy, Morone spp., rainbow smelt, striped bass, and 14 white perch (Table H-7). Entrainment losses may affect populations directly by reducing the 15 number of individuals available for recruitment and indirectly through the removal of potential 16 food for predators. The environmental significance of entrainment is explored further in Section 17 H.1.3.

18 H.1.3. Combined Effects of Impingement and Entrainment 19 The combined effects of impingement and entrainment were evaluated by the applicant in the 20 DEIS (CHGEC 1999) by estimating CMR, which is intended to represent the fractional reduction 21 in abundance of the vulnerable age groups (primarily those fish hatched during the current year) 22 from a single source.

December 2010 H-23 NUREG-1437, Supplement 38

1 Table H-7 Percentage Entrainment of RIS by Year and Season (data from Entergy 2007b) Appendix H Year/ 1981 1983 1984 1985 1986 1987 Season 2 3 2 3 2 3 2 3 1 2 3 2 3 Alewife - - - <0.05 <0.05 - - - - 0.1 - <0.05 -

Alosa Species 5.7 <0.05 52.9 <0.05 55.1 <0.05 0.7 - 0.4 <0.05 - <0.05 -

American Shad 0.1 <0.05 0.2 <0.05 5.5 <0.05 <0.05 - - 0.1 - <0.05 <0.05 Anchovy Family 3.5 7.7 <0.05 43.3 1.2 8.5 - - - - - - -

Atlantic NUREG-1437, Supplement 38 Menhaden - - - - - - 0.1 - - 0.2 - - -

Atlantic Tomcod 0.4 - 0.1 <0.05 1.7 0.1 7.9 <0.05 30.6 1.3 - 1.1 <0.05 Bay Anchovy 51.7 91.5 0.1 53.1 16.9 85.3 66.1 98.9 - 8.1 98.5 48.5 99.1 Blueback Herring - <0.05 <0.05 0.1 <0.05 <0.05 - <0.05 - <0.05 <0.05 - -

Bluefish - - - - - <0.05 - <0.05 - - - - -

<0.0 Hogchoker 5 0.3 <0.05 0.6 <0.05 0.2 <0.05 0.3 - <0.05 0.3 <0.05 0.1 Morone Species - - 10.9 0.2 1.4 0.1 3.7 <0.05 - 4.2 <0.05 2.9 <0.05 Rainbow Smelt - - <0.05 - 0.3 <0.05 <0.05 <0.05 66.7 2.7 0.2 0.8 0.1 Spottail Shiner - - - <0.05 - <0.05 - - - - - - -

H-24 Striped Bass 24.8 <0.05 13.4 0.9 10.0 3.1 14.0 <0.05 - 43.8 0.2 38.0 0.3 Weakfish - 0.3 - 1.1 - 2.2 0.1 0.7 - - 0.4 <0.05 <0.05 White Catfish - - - - - <0.05 - - 0.1 <0.05 - - -

White Perch 13.8 0.1 22.4 0.6 7.8 0.5 7.3 0.1 2.1 39.5 0.4 8.6 0.3 2 (a) Season 1 is January-March; 3 Season 2 is April-June; 4 Season 3 is July-September.

5 (b) - indicates no identified observation.

6 Units = percent.

December 2010

Appendix H 1 Here the NRC staff analysis relied primarily on the extensive fishery data sets collected under 2 the direction and oversight of the NYSDEC.

3 The purpose of this analysis is to determine the potential for adverse impacts to the aquatic 4 resources of the Hudson River Estuary associated with the operation of IP2 and IP3 once-5 through cooling systems during the relicensing period. The National Environmental Policy Act, 6 as amended (NEPA), requires an ecologically relevant analysis of potential impacts that is more 7 holistic than a general fisheries biology approach. Fisheries biology tends to focus on single 8 species issues, such as sustaining a harvest rate, no matter what the effect may be on other 9 species within the system. In contrast, the NRC staff analysis considers potential impacts 10 across trophic levels and life history strategies by assessing the population responses over time 11 for important predator and prey species in the lower Hudson River.

12 The operation of the IP2 and IP3 cooling systems can directly affect the aquatic communities of 13 the Hudson River through impingement, entrainment, or thermal releases. Loss of YOY, 14 yearling and older fish, blue crabs (Callinectes sapidus), and other aquatic species can occur 15 from impingement against intake screens. Eggs, YSL, post-yolk-sac larvae (PYSL), and 16 juvenile fish and invertebrates small enough to pass through the intake screens (9.5-mm or 17 0.375-in. square mesh) may become entrained within the intake units of the once-through 18 cooling system and experience adverse effects associated with mechanical, chemical, and 19 thermal stressors. Releases of heated noncontact cooling water through subsurface diffuser 20 ports into the Hudson River can result in heat- or cold-shock effects. Cooling system operation 21 can also result in indirect effects to aquatic resources. Impingement may injure, stun, or 22 debilitate an organism, reducing its ability to avoid predation, capture prey, or grow and 23 reproduce in a normal manner. Entrainment of larval or small juvenile forms not resulting in 24 death may reduce viability or survival success. Entrainment can also create an indirect adverse 25 impact to estuarine food webs by removing potential prey items from predators, or altering and 26 redistributing the aquatic organic carbon represented by entrained organisms. In addition, the 27 release of heated water can result in sublethal effects, including changes in reproduction or 28 development, increased susceptibility to other environmental stressors, or behavioral changes 29 associated with avoiding thermal plumes.

30 Evaluating the potential for adverse impacts of the IP2 and IP3 cooling systems to the aquatic 31 resources of the Hudson River Estuary presents a significant challenge for a variety of reasons.

32 First, the potential stressor of interest (the IP2 and IP3 cooling systems) occupies a fixed 33 position on the Hudson River, while RIS associated with the Hudson River generally have large 34 spatial and temporal distributions that can change for each life stage. Thus, evaluation of 35 causal relationships between potential stressors and receptors is difficult and requires a 36 systems-level understanding that may not be possible with existing environmental information.

37 Second, the Hudson River estuary represents a dynamic, open-ended system containing a 38 complex food web that is hydrologically connected from freshwater locations near the Troy Dam 39 to the Atlantic Ocean. Detectable trends at population levels that suggest adverse effects may 40 be attributable to a variety of anthropogenic and natural stressors, including the activities at IP2 41 and IP3. Finally, because the Hudson River estuary represents a complex system with 42 hundreds of aquatic species, it is necessary to focus primarily on a subset of RIS. While this 43 simplifies the assessment of impact, it also introduces additional uncertainties that must be 44 acknowledged and addressed.

December 2010 H-25 NUREG-1437, Supplement 38

Appendix H 1 The GEIS defines impingement, entrainment, and heat shock from cooling system operation as 2 Category 2 issues requiring site-specific review. Levels of impact associated with these issues 3 are defined as potentially SMALL, MODERATE, or LARGE, consistent with the criteria that the 4 NRC established in Footnote 3 to Table B-1, Appendix B, 10 CFR Part 51, as follows:

5

• SMALLEnvironmental effects are not detectable or are so minor that they will neither 6 destabilize nor noticeably alter any important attribute of the resource.

7

• MODERATEEnvironmental effects are sufficient to alter noticeably, but not to 8 destabilize, any important attributes of the resource.

9

• LARGEEnvironmental effects are clearly noticeable and are sufficient to destabilize 10 any important attributes of the resource.

11 To evaluate whether the operation of the IP2 and IP3 cooling systems adversely affects RIS, the 12 NRC staff employed a modified weight-of-evidence (WOE) approach as represented in Figure 13 H-6. The approach used impingement and entrainment monitoring data obtained from the IP2 14 and IP3 facilities, data from the lower Hudson River collected during the Long River Survey 15 (LRS), Fall Juvenile/Fall Shoals Survey (FJS/FSS), and Beach Seine Survey (BSS), as 16 described in Table 2-3 in the main text of this SEIS, and coastal fishery trend data, when 17 available, as ancillary information. Lines of evidence (LOE) associated with the population 18 trends and strength of connection were developed. The WOE is a technique used to integrate 19 multiple LOE, or types of variables, to make a single decision concerning the magnitude of 20 impact and its association with a potential stressor (IP2 and IP3 cooling systems). The WOE 21 approach employed was based on Menzie et al. (1996) and consisted of the following steps 22 depicted in Figure H-7:

23 (1) Identify the environmental component or value to be protected.

24 (2) Develop LOE and quantifiable measurements to assess the potential for adverse 25 environmental effects and evaluate whether the IP2 and IP3 cooling systems are 26 contributing to the effect.

27 (3) Quantify the use and utility of each measurement for supporting the impact assessment.

28 (4) Develop quantifiable decision rules for interpreting the results of each measurement.

29 (5) Use the WOE to integrate the results, assign a level of potential impact, and determine if 30 adverse effects in RIS populations, if present, are related to the operation of the IP2 and 31 IP3 cooling systems.

NUREG-1437, Supplement 38 H-26 December 2010

Appendix H 18 Representative Important Species River Data for Each Species In-Plant Data for Each Species

1) Monitoring Surveys (LRS, FJS, BSS) 1) Impingement of RIS

-River Segment Measurements 2) Entrainment of RIS

-River-wide Measurements Line of Evidence: Line of Evidence:

Population Trend Strength of Connection of for Each Species Indian Point to Each Species Evaluate Data Evaluate Data To Determine WOE Score To Determine WOE Score Decision for Level of Impact to Population of Each Species Attributable to IP Cooling System Operation 1

2 Figure H-6 General weight-of-evidence approach employed to assess the level of impact 3 to population trends attributable to IP cooling system operation 4 These steps are discussed below in more detail. Supporting information for the statistical 5 analyses used in this determination is presented in Appendix I. A WOE approach was not used 6 to evaluate thermal effects, because recent monitoring or modeling data were not available.

Step 1: Identify Value to Be Protected:

Aquatic Resources as Represented by 18 RIS Step 2: Develop Lines of Evidence and Associated Measurements Step 3: Assess Use and Utility of measurement Assign Score Use and Utility type Define 7 Attributes Take Average Score Weight of Evidence Integrate Score Step 4: Determine Decisions Rules Evaluate data Result Score for each measurement Per rules Step 5: Assign Impact Category for Both Line of Evidence Integrate Impact Categories Impact of Indian Point For Each Population of for Both Lines of Evidence Cooling System on Representative Important Species Each RIS Species 7

8 Figure H-7 Steps used to conduct the weight-of-evidence assessment December 2010 H-27 NUREG-1437, Supplement 38

Appendix H 1 Step 1: Identify the Environmental Component or Value to be Protected 2 For this assessment, the environmental component to be protected is the Hudson River aquatic 3 resources as represented by the 18 RIS identified in Table 2-4 in the main text of this SEIS.

4 These species represent a variety of feeding strategies and food web classifications and are 5 considered ecologically, commercially, or recreationally important. The WOE approach focuses 6 primarily on the potential impacts to YOY and yearling fish and their food sources. Although 7 eggs, larvae, and PYSL are important components to the food web, the natural mortality to 8 these life stages is high, as noted by Barnthouse et al. (2008) and Secor and Houde (1995). In 9 contrast, fish surviving to YOY and older are more likely to add to the adult breeding population 10 and are at greater risk from the cooling system operation. Any factor that increases (or 11 decreases) the survival of those fish during juvenile and yearling stages can affect the 12 sustainability of the population.

13 The conceptual model considers that the dynamics of the system are subject to large changes 14 based on a wide variety of controlling factors. Phytoplankton and zooplankton communities 15 form the basis of the food web and are used by a variety of fish and invertebrates during their 16 development from larvae to adults. Plankton abundances generally increase during the spring 17 and summer, coinciding with the emergence of larval and juvenile forms of fish and 18 invertebrates after spawning. For some species, such as striped bass, PYSL and juvenile forms 19 initially eat small, planktonic prey, then switch to larger prey as they grow. For other species, 20 such as herring and alosids, adults remain planktivores. Predator-prey relationships within the 21 estuary are complex and are influenced by a variety of physical, chemical, spatial, and temporal 22 factors. Within this system, predation may be inter- or intraspecific, and operate at a variety of 23 levels simultaneously. There are also a variety of controlling factors that may exert influence on 24 the estuarine food web and inhabitants of the estuary. Physical and chemical fluctuations can 25 serve as cues for reproduction and promote or inhibit growth, the nature and extent of predation 26 can result in shifts in food web dynamics, and the influence of invasive or exotic species and 27 anthropogenic activities can affect year-classes or result in long-term changes to populations.

28 After reviewing available information, the NRC staff could not determine if the operation of the 29 IP2 and IP3 cooling systems is adversely affecting the RIS through the phytoplankton and 30 zooplankton populations present near the facilities. It is possible, however, that the entrainment 31 of these food web constituents can alter or influence the food web by removing potential prey 32 items from the water column and reintroducing and redistributing them in the river in an altered 33 state. As a result, the form and distribution of organic carbon can be fundamentally changed, 34 even though the overall mass-balance remains the same. A similar effect may exist for larval 35 forms that experience entrainment and are thus unavailable in their natural state for predation.

36 Impingement losses may also alter the food web by removing potential predator or prey items 37 from the system or by changing the dynamics of the relationships at critical periods. At the 38 higher levels of the food web, large predators such as bluefish, weakfish, and striped bass may 39 be affected by alterations to the food web in ways that are not always obvious. For instance, 40 work by Baird and Ulanowicz (1989) suggested that, even though striped bass and bluefish in 41 the Chesapeake Bay ecosystem were both piscivorous predators, 63 percent of the bluefish 42 intake depended indirectly on benthic organisms, whereas striped bass depended mainly on 43 planktonic organisms.

44 Within this food web context, the IP2 and IP3 cooling systems can be viewed as hybrid 45 predators. Although the operation of the cooling water systems exerts a predatory effect at NUREG-1437, Supplement 38 H-28 December 2010

Appendix H 1 multiple levels within the estuarine food web, the fixed position of the plants in the environment, 2 their relatively continuous operation, and their lack of sensitivity to traditional environmental 3 stressors that affect predators place them in a unique position within the estuarine system. The 4 cooling system also functions as an environmental sampling device through impingement and 5 entrainment. To fully explore the potential adverse impacts of cooling system operation to the 6 aquatic resources of the Hudson River estuary, it is necessary to examine both the direct 7 impacts associated with losses caused by impingement, entrainment, and heat, and the indirect 8 impacts of these potential stressors that may work through the food web and contribute to 9 detectable long-term changes to RIS populations.

10 Step 2: Develop Lines of Evidence and Quantifiable Measurements 11 The LOE and measurements used by the NRC Staff to assess the impacts of the IP2 and IP3 12 cooling systems on RIS in the Hudson River estuary are presented in Table H-8. The first LOE 13 (LOE-1) was a population-trend analysis using data from the three surveys conducted for the 14 Hudson River utilities. Population trends over time are often used to assess long-term changes 15 in population abundance or species composition and to provide information on sustainability.

16 For Measure 1-1, the NRC staff based river-segment trends on the fish caught within River 17 Segment 4 (IP2 and IP3) or, if this sampling area had a consistently low catch, an adjoining 18 segment (River Segments 2 through 6), whichever had a greater catch (Figure 2-10 in the main 19 text). The river-segment data were the weekly catch-per-unit-effort (CPUE) and catch density 20 from the FSS, BSS, and LRS. The annual estimate of the population response was the 75th 21 percentile of the weekly data for a given year, because it was not as sensitive as the mean to 22 the few large observations collected each year. Using a percentile provided a better measure of 23 central tendency given the highly skewed data. The NRC staff chose the 75th percentile rather 24 than the median because on average 52 percent and 65 percent of the weekly FSS and BSS 25 catches were 0 for the chosen RIS.

26 For Measure 1-2, riverwide population trends were based on the annual CPUE and the annual 27 abundance index derived by the applicant. Population trends also formed the basis of the WOE 28 analysis used by the NRC staff to assess the cumulative impacts of IP2 and IP3 activities, as 29 well as other anthropogenic and natural environmental stressors, including the potential effects 30 of zebra mussels in the freshwater portion of the Hudson River. The draft SEIS used 31 commercial harvest data in addition to Hudson River sampling program data to assess 32 population trends of RIS. The NRC staff removed this measure in this final SEIS based on 33 comments on the SEIS and a reassessment by the NRC staff. Coast-wide fish populations are 34 not the young-of-the-year populations measured by the Hudson River sampling programs and 35 so respond different factors and can change on different time scales. These are differences that 36 can introduce unwanted noise into the analysis.

37 Table H-8 Lines of Evidence and Measurements Used To Assess Cooling System Impacts LOE-1: ASSESSMENT OF POPULATION TRENDS OF RIS River-segment RIS population trends from FSS and BSS Measurement 1-1 (and LRS for tomcod)

December 2010 H-29 NUREG-1437, Supplement 38

Appendix H Riverwide RIS population trends from FSS and BSS (and Measurement 1-2 LRS for tomcod) 1 Table H-8 (continued)

LOE-2: ASSESSMENT OF STRENGTH OF CONNECTION Measurement 2-1 Impingement of RIS Measurement 2-2 Entrainment of RIS 2 The second LOE (LOE-2) is a semi-quantitative measure of the strength of the connection 3 between the operation of the IP2 and IP3 cooling systems and the aquatic resources in the 4 Hudson River. NRC staff determined the strength of connection from monitoring data at IP2 5 and IP3 from 1975 to 1990 that provide information on impingement and entrainment rates for 6 RIS. As discussed above, the operation of the cooling system can result in direct mortality of 7 RIS or may debilitate or damage organisms in a manner that causes latent mortality.

8 Impingement and/or entrainment can also remove and reintroduce RIS prey into the aquatic 9 system in a manner that alters food web dynamics and produces indirect effects that may result 10 in decreased recruitment, changes in predator-prey relationships, changes in population feeding 11 strategies, or movements of populations closer to or farther away from the cooling system 12 intakes or discharges. NRC staff based the analysis of the strength of connection on an 13 estimate of uncertainty derived from a Monte Carlo simulation that examined the differences in 14 population trends with and without losses of YOY fish by entrainment and impingement.

15 Uncertainty analysis is an important component of risk characterization required in the U.S.

16 Environmental Protection Agency ecological risk assessment guidelines (USEPA 1998) before 17 interpreting the ecological significance of a decision.

18 Step 3: Quantify the Use and Utility of Each Measurement 19 The following attributes of each measurement within each LOE were adapted from Menzie et al.

20 (1996) and were assigned an ordinal score corresponding to a ranking of its use and utility as 21 low (1), medium (2), or high (3):

22 (1) Strength of Association Between the Measured Parameter and the Aquatic 23 Communitythe extent to which the measurement parameter is representative of, 24 correlated with, or applicable to the assessment of the target fish community; 25 (2) Stressor-specificitythe extent to which the measurement parameter is associated with 26 the specific stressor (e.g., impingement mortality);

27 (3) Site-specificitythe extent to which data, media, species, environmental conditions, and 28 other factors relate to the site of interest; 29 (4) Sensitivity of the Measurement Parameter for Detecting Changesthe ability to detect a 30 response in the measurement parameter; NUREG-1437, Supplement 38 H-30 December 2010

Appendix H 1 (5) Spatial Representativenessthe degree of compatibility between the study area, 2 location of measurements or samples, locations of stressors, and locations of biological 3 receptors and their points of exposure; 4 (6) Temporal Representativenessthe temporal compatibility between the measurement 5 parameter and the period during which effects of concern would occur; 6 (7) Correlation of Stressor to Responsethe degree to which a correlation is observed 7 between levels of response, and the strength of that correlation.

8 The NRC staff then calculated overall use and utility scores for each measurement within each 9 LOE as the average of the individual attribute scores. For a given LOE, the average score for 10 all attributes was used to characterize the overall use and utility of the measurement as low, 11 medium, or high, using the following definitions:

12

• Low use and utilityoverall score of <1.5 (questionable for decision-making) 13

• Medium use and utilityoverall score of 1.5 and 2 (adequate for decision-making) 14

• High use and utilityoverall score of >2 (very useful for decision-making) 15 The results of these evaluations are presented for each LOE and supporting measurements in 16 Tables 4-2 and 4-3. For LOE-1, RIS population trends, measurements with the highest use and 17 utility are those that provide information on long-term trends in RIS populations at river-segment 18 and riverwide scales (Table H-9). Comprehensive data sets extending over 30 years yield high 19 use and utility for assessing impacts. As measurements of populations become more spatially 20 distributed, the ability to use the measurement to assess impacts associated with IP2 and IP3 21 decreases.

22 The NRC staff used the strength of the connection between the IP2 and IP3 cooling systems 23 and the aquatic environment (i.e., the ability of the IP2 and IP3 cooling system operation to 24 affect RIS populations in the Hudson River estuary) as a semi-quantitative line of evidence.

25 Thus, the staff did not apply the use and utility analysis to this LOE.

26 Table H-9 Use and Utility of Each Measurement Type to Evaluate RIS Population Trends 27 Potentially Associated with IP2 and IP3 Cooling System Operation River-Segment Riverwide RIS Use and Utility Attribute RIS Community Community Trends Trends Strength of Association between Measurement and 3 2 Community Response Stressor-specificity 2 1 Site-Specificity of Measurement in Relation to the 2 1 Stressor Sensitivity (Variability) of Measurement 2 2 Spatial Representativeness 3 2 Temporal Representativeness 3 3 Correlation of Stressor to Response 2 1 Overall Utility Score 2.4 1.7 December 2010 H-31 NUREG-1437, Supplement 38

Appendix H Overall Assessment(a) High Medium (a) Overall Assessment: scores <1.5: low utility (questionable use for decision-making); 1.5 scores 2.0: medium utility (adequate for decision-making); scores >2.0: high utility (very useful for decision-making).

1 NUREG-1437, Supplement 38 H-32 December 2010

Appendix H 1

2 3 Step 4: Develop Quantifiable Decision Rules for Interpreting the Results of Each Measurement 4 For all population trend assessments in the first LOE, NRC Staff used a two-step process to 5 assign the level of potential for an adverse impact suggested by a given measurement. The first 6 step was to determine the shape of the best-fit model for the abundance data; the second step 7 was to evaluate determine if a statistically significant decline in population occurred. The shape 8 of the trend data was determined using simple linear regression and segmented regression as a 9 function of time with a single join point (see the statistical approach below and Appendix I for 10 specific details). The segmented regression analysis allowed a delayed response and two time 11 periods to evaluate trends. The model with the smallest error mean square was chosen as the 12 better fit and was used to assess the level of potential adverse impact. In the second step, staff 13 used the significance of the estimated slope(s) to determine whether a detectable population 14 decline was present.

15 For the population trend LOE, the number of data sets available for each RIS and measurement 16 scale (river segment and riverwide) varied. Based on two possible outcomes, the NRC staff 17 used the following decision rules to evaluate RIS population trend data:

18

• RIS populations were not declining if population trends had slopes that were not 19 significantly less than zero (i.e., undetected population decline or a detectable population 20 increase). This indicated the RIS populations had not changed appreciably over time, or 21 were increasing. The NRC staff assigned trends satisfying this description a score of 1.

22

• RIS populations were declining if population trends had slopes that were significantly 23 less than zero (i.e., detectable population decline). NRC staff assigned trends satisfying 24 this description a score of 4.

25 The staff chose a value of 4 to represent large because it allowed for scaled intermediate scores 26 to occur when combining the results of multiple datasets for a given measurement scale (river 27 segment and riverwide). Staff considered each data set within a measurement scale to be 28 equal and the population trend scores were then averaged (Table H-10). The staff evaluated December 2010 H-33 NUREG-1437, Supplement 38

Appendix H 1 multiple data sets from the same measurement scale to garner consistency for a determination 2 of either a small or large potential adverse impact. The NRC staff determined that an 3 intermediate potential of an adverse impact was warranted when equal numbers of 1s and 4s 4 occurred for a given measurement scale.

5 Table H-10 Possible outcomes and the resulting average for single or multiple data sets 6 for a measurement scale in the population trend line of evidence Number of Measurement Possible Outcomes Data Sets Scale Average 1 1 1

4 4 1 1 1 2 1 4 2.5 4 4 4 1 1 1 1 1 1 4 2 3

1 4 4 3 4 4 4 4 1 1 1 1 1 1 1 1 4 1.75 4 1 1 4 4 2.5 1 4 4 4 3.25 4 4 4 4 4 7

8 To evaluate the strength of connection between the operation of the IP2 and IP3 cooling 9 systems and the observed RIS population declines, the NRC staff developed decision rules for 10 assessing the influence of impingement and entrainment directly on. All of the RIS appeared in 11 either the impingement or the entrainment samples. Thus, the NRC staff considers that the 12 connection relative to risk to the population abundance from the operation of the cooling 13 systems has been established. However, staff can only determine the proportion of the 14 population decline caused either directly or indirectly by the operation of IP2 and IP3 15 qualitatively. This qualification depends on the ability of a simple exponential model to 16 approximate RIS population trends through time and estimate a biologically relevant measure of 17 uncertainty associated with the cause of decline in RIS populations in the Hudson River. The 18 NRC staff conducted simulation runs with different model parameter values to provide a greater 19 sense of the separation between conclusions on the strength of connection and specific model 20 assumptions. The staff discusses the details of the development of the uncertainty analysis of 21 population abundance with and without losses of YOY fish by entrainment, impingement, and 22 food web dependencies in the statistical approach below and in Appendix I.

23

• The RIS had a Low strength of connection if the interval between the first and third 24 quartiles of the difference in modeled cumulative abundance for a given YOY RIS with 25 and without mortality from entrainment, impingement, and loss of prey included zero 26 for at least one of the simulation runs. That is, the variability in the species population 27 trend was too large to enable the detection of losses from entrainment and 28 impingement. Thus, there is high level of uncertainty associated with the link between NUREG-1437, Supplement 38 H-34 December 2010

Appendix H 1 the population trend and the direct and indirect effects of the operation of IP2 and IP3 2 cooling systems.

3

• The RIS had a High strength of connection if the interval between the first and third 4 quartiles of the difference in modeled cumulative abundance for a given YOY RIS with 5 and without mortality from entrainment, impingement, and loss of prey did not include 6 zero for any of the simulation runs. That is, the effects of entrainment and impingement 7 were greater than the variability in the population trend, and the direct and indirect 8 effects of the operation of IP2 and IP3 cooling systems affected species population 9 trends.

10 Step 5: Integrate the Results and Assess Impact 11 The NRC Staff derived WOE scores for only the population trend LOE. The staff used the 12 strength of connection LOE to evaluate uncertainty in the evidence as to whether the IP2 and 13 IP3 cooling systems were affecting the RIS population trends. The above decision rules 14 enabled the NRC to assign levels of impact to individual measurement scales of RIS 15 populations. Staff used a weighted mean equation to assign a level of impact across 16 measurement scales as follows:

(overall utility score )(decision rule result score )

i i 17 WOE Score = i

,

overall utility score i

i 18 where i = 1 to the number of measurements; the overall utility score i is defined in Table H-9; 19 and the result score i equals the average of 1s and 4s defined in Table H-11 and on the above 20 decision rules for individual data sets on population trends.

21 22 The NRC Staff defined the WOE population trend impact categories as follows:

23

• Small impact: WOE score < 2.2 24

• Moderate impact: WOE score 2.2 but 2.8 25

• Large: WOE score > 2.8 26 The staff defined boundary values between impact categories based on the possible outcomes 27 for a given measurement scale (Table H-10). WOE scores less than 2.2 occurred when 28 population trend data produced more result scores that were 1s than were 4s. WOE scores 29 greater than 2.8 occurred when population trend data produced more result scores that were 4s 30 than were 1s.

31 The resulting impact categories for the population trend and strength of connection LOE were 32 then integrated by applying the logic developed by EPA for evaluating the ecological effects of 33 environmental stressors (EPA 1998). In accordance with EPA (1998) risk assessment 34 guidelines, a connection between the stressor and the response must be established to assign 35 any level of impact using. For the purpose of this assessment, the stressor is the IP2 and IP3 December 2010 H-35 NUREG-1437, Supplement 38

Appendix H 1 cooling systems, while the receptor is the aquatic community, as represented by the RIS 2 populations, and the degree of exposure is qualified by the strength of connection.

3 Statistical Approach for Each Line of Evidence 4 The decision rules developed above to determine the level of adverse impact to the aquatic 5 resources of the Hudson River estuary associated with the operation of the IP2 and IP3 once-6 through cooling systems use (1) population trend data to provide a measure of potential impacts 7 to the aquatic resources, and (2) impingement and entrainment data to provide a measure of 8 the strength of connection between IP2 and IP3 operations and the aquatic environment. The 9 statistical approach used to evaluate each measurement is described below. Results were 10 compared to the decision rules to assign a result score that was then integrated using the 11 weighted mean presented above. WOE was then used to integrate the measures of potential 12 impact with the measures of strength of connection to assign a level of impact attributable to the 13 operation of the IP2 and 3 cooling systems.

14 Statistical Approach to Assessing Long-Term RIS Population Trends: Simple linear regression 15 and segmented regression with a single join point were statistically fit to an annual measure of 16 abundance (y) for each RIS using GraphPad Prism Version 4.0, 2003. The form of the 17 segmented regression model is 18 a + S1 x for x < J p 19 y=

a + J p ( S1 S 2 ) + S 2 x for x J p 20 where x was the year, a was the intercept, S1 and S2 were early (associated with years < Jp) and 21 recent slopes of the line, and Jp was the estimated point in time when the slope changed 22 (i.e., the join point). The model with the smallest mean squared error (MSE) was chosen as the 23 better fit to the data. If the best-fit model was the simple linear regression and the slope was 24 statistically significant (negative or positive, = 0.05), a population trend was detected. If the 25 slope was not significantly different from zero, then a population trend was not detected. If the 26 best-fit model was the segmented regression and either slope, S1 or S2, was statistically 27 significant ( = 0.05), then a population trend was considered detected. If both slopes S1 and 28 S2 were not significantly different from zero ( = 0.05), then the trend was not considered 29 detected. Note that an NRC impact level of small (value = 1) was defined as the lowest level of 30 potential adverse impact.

31 To evaluate whether abundance data were indicative of potential aquatic impacts, NRC staff 32 standardized all data by subtracting the mean of the first five years of data and then dividing by 33 the standard deviation based on all years of data. The first five years (1979-1983) were chosen 34 as the standard because the coefficient of variation (CV) of abundance either leveled out at n =

35 5, or it was preceded by a rapid change in direction (Figure H-8). For density and CPUE data, 36 the staff compared population trends between the BSS and FJS to determine if the shift from 37 the epibenthic sled to the beam trawl in 1985 was influencing the shape of the response. The 38 NRC staff split FJS data into pre- and post-1985 for analysis if a visual and statistical 39 assessment (see Appendix I for details) showed that the FJS data had standardized 40 observations that were consistently less than the standardized BSS data after 1985.

41 NUREG-1437, Supplement 38 H-36 December 2010

Appendix H 160%

140%

120%

100%

CV 80%

60%

40%

20%

0%

n=3 n=4 n=5 n=6 n=7 n=8 n=9 n=10 Number of Years of Data Alewife Bay Anchovy American Shad Bluefish Hogchoker Blueback Herring Rainbow Smelt Spottail Shiner Stripped Bass Atlantic Tomcod White Catfish White Perch Weakfish 1

2 Figure H-8 Coefficient of variation of the abundance index for an increasing number of 3 data points (data from Entergy 2007b).

4 The NRC staff considered an assessment of adverse impact supported if at least one of the 5 slopes from the best fit model or models (if pre- and post-1985 data were modeled separately) 6 was significantly less than zero. There were six possible outcomes for the assessment (Table 7 H-11).

8 Table H-11 Comparison of Possible Outcomes When Assessing Population Trends of 9 RIS in the Hudson River Studies Statistical Outcome Potential for Impact Best-fit Model and Result Score Significant Slope(s)

Simple Linear No 1 Regression Yes 4 (All data)

Segmented Neither 1 Regression Either or Both 4 (All data)

Simple Linear Regression (1979-1984) None 1 Segmented At least One 4 Regression (1985-2005) 10 Statistical Approach to Assessing Strength of Connection: To determine the strength of 11 connection between the operation of the IP2 and IP3 cooling systems and the RIS that exist in 12 the Hudson River near the facility, the NRC staff used the information from two types of December 2010 H-37 NUREG-1437, Supplement 38

Appendix H 1 environmental samplers: (1) impingement and entrainment data obtained from the operators of 2 IP2 and IP3 (a stationary environmental sampler along the shore of the Hudson) and (2) long-3 term aquatic resource studies conducted in the river by power plant operators under the 4 supervision of State agencies (e.g. LRS, FJS, BSS). Rose (2000) suggested that the high 5 interannual variation in YOY fish populations greatly reduces the statistical power of correlation-6 based analyses to isolate the effects of anthropogenic impacts to fish populations. Rose also 7 contended that model-based approaches have been more successful in increasing the 8 detectability of anthropogenic impacts. Newbold and Iovanna (2007) supported this approach 9 by suggesting that models that assess density-independent mortality associated with cooling-10 water withdrawals can help put raw data on entrainment and impingement losses into a 11 broader ecological context. Newbold and Iovanna recognized, however, that the model should 12 reflect the differential losses based on life stage (eggs, larvae, and juveniles).

13 The NRC staff acknowledges that River Segment 4 at Indian Point is not a closed biological 14 system for which loses and gains to a population can be easily studied. Many of the RIS 15 reproduce 100 river miles upriver, and the eggs and larvae then float downstream where some 16 are entrained at IP2 or IP3. The resulting YOY population densities near Indian Point are 17 inherently noisy (highly variable) and even a detected decline can easily be related to several 18 environmental, ecological, and anthropogenic effects that occur upstream and downstream of 19 River Segment 4. Thus, if the loss of YOY RIS is to be linked to mortality from entrainment and 20 impingement at IP2 and IP3, the effect of the cooling system operation on a given population 21 must be greater than the noise or variability in the abundance of the population over time near 22 the Indian Point plant.

23 For this analysis, the NRC staff determined the strength of connection from the uncertainty in 24 estimating the difference in the RIS YOY population abundance with and without losses from 25 impingement and entrainment by IP2 and IP3 cooling systems. The staff conducted a series of 26 Monte Carlo simulations (n = 1000 for each series) to estimate the first and third quartiles of the 27 modeled relative cumulative difference in the population abundance achieved over a specified 28 number of years (t = 1 to 27, for example) with and without removal of eggs, larvae, and 29 juveniles by entrainment and impingement. Staff used a simple exponential model to estimate 30 the annual juvenile population abundance (Nt) assuming losses from entrainment and 31 impingement (Figure H-9; see Appendix I for a complete model description);

32 33 where N0 is the initial population abundance, r is the linear growth rate estimated from the River 34 Segment 4 population trend, t is the standard deviation of abundance at time t, and t is a 35 Normal (0,1) random variate. NRC staff estimated YOY annual abundance without losses from 36 entrainment and impingement by increasing the initial population abundance (N0) by the number 37 of eggs, larvae, and juveniles entrained and amending the growth rate (r) by multiplying it by 38 one minus the conditional impingement mortality rate (Figure H-10). The conditional 39 impingement mortality rate assumes partial survival associated with the installation of Ristroph 40 screens at IP2 and IP3.

41 The cumulative annual difference in the YOY abundance from the two models provided an 42 estimate of the proportion of YOY lost from entrainment and impingement. The staff used the 43 Monte Carlo simulation to estimate a distribution of the proportion lost based on the variability in 44 population abundance. The null hypothesis was that the interval between the quartiles of the NUREG-1437, Supplement 38 H-38 December 2010

Appendix H 1 modeled differences in the YOY cumulative abundance over time in the fish community near IP2 2 and IP3 with and without the effects of entrainment and impingement would contain zero (i.e.,

3 there was a Low strength of connection between population trend and the effects of entrainment 4 and impingement).

5 NRC staff conducted four simulations (n = 1000) with different input variables for N0 and t. Each 6 simulation produced a sample with the same variability as that observed in the abundance data 7 for the given RIS. Multiple simulations allowed NRC staff to qualify the strength of connection 8 with less dependency on specific model parameters. There were two possible outcomes, each 9 with an associated conclusion of the strength of connection (Table H-12).

2500 2000 Abundance (Nt) 1500 1000 500 0

0 2 4 6 8 10 12 14 16 18 20 Years (t) 10 11 Figure H-9 Range in Expected YOY Population Abundance Over Time Based on an 12 Exponential Model for Each of the RIS Assuming Losses From Entrainment and 13 Impingement. The curves represent growth rates (ranging from -0.08 to 0.04) for modeled 14 RIS as presented in Appendix I, Table I-31.

December 2010 H-39 NUREG-1437, Supplement 38

Appendix H 1200 1000 Abundance (Nt) 800 With Losses from 600 Entrainment and Impingement 400 Without Losses from Entrainment and 200 Impingement 0

0 10 20 30 Years (t) 1 2 Figure H-10 Expected YOY Population Abundance Over Time Based on an Exponential 3 Model With and Without Losses From Entrainment and Impingement.

4 5 Table H-12 Possible Outcomes When Assessing Simulation Results of RIS YOY 6 Abundance With and Without the Effects of IP2 and IP3 Cooling System Outcome Strength of Connection Conclusion At least one out of four simulation results Low strength of connection suggesting the RIS contain zero within the interval between population trend is not associated with the effects the first and third quartiles of the sample of the cooling system.

distribution.

None of the simulation results contains High strength of connection suggesting the RIS zero within the interval between the first population trend is highly likely to be associated and third quartiles of the sample with the effects of the cooling system.

distribution.

7 H.1.3.1. Assessment of Population Trends 8 Studies Used To Evaluate Population Trends 9 The Hudson River utilities conducted the LRS from 1974 to 2005 and targeted fish eggs, YSL, 10 and PYSL from the George Washington Bridge (river mile (RM) 12) to the Federal Dam at Troy 11 (RM 152), a total of 140 miles (CHGEC 1999). Sampling was conducted during the spring, 12 summer, and early fall, using a stratified random design based on 13 regions and three strata 13 within each region (channel, shoal, and bottom). A 1-m2 Tucker trawl was used to sample the 14 channel strata; an epibenthic sled-mounted 1-m2 net similar in design to the Tucker trawl was 15 used to sample the bottom strata, and both gear types were used to sample the shoal strata.

NUREG-1437, Supplement 38 H-40 December 2010

Appendix H 1 Because this survey targeted younger life stages, staff did not use the LRS in this analysis 2 except for YOY Atlantic tomcod data.

3 The utilities FJS, also known as the FSS, was conducted from 1974 to 2005 and targeted 4 juveniles, yearlings, and older fish (CHGEC 1999). Samples were collected on alternate weeks 5 from the BSS between Manhattan (RM 0) and the Troy Dam (RM 152) using a stratified random 6 design. Data were used to estimate the abundance of YOY and older fish in offshore habitats.

7 Approximately 200 samples were collected each week from July to December. Between 1974 8 and 1984, a 1- m2 Tucker trawl with a 3-mm mesh was used to sample the channel and a 1-m2 9 epibenthic sled with a 3-mm mesh was used to sample the bottom and shoal strata. From 1985 10 to 2005, a 3-m beam trawl with a 38-mm mesh on all but the cod-end replaced the epibenthic 11 sled. Bay anchovy, American shad, and weakfish were sampled with less efficiency using the 12 beam trawl (NYPA 1986). Further, the number and volume of samples in the bottom and shoal 13 strata were generally greater than 2.5 times those in the channel. Thus, all data were evaluated 14 to determine if a shift in the gear type was affecting the observed trend. When the standardized 15 FJS data were consistently less than the standardized BSS data after 1985, staff analyzed the 16 pre- and post-1985 data separately.

17 The utilities BSS was conducted from 1974 to 2005 and targeted YOY and older fish in the 18 shore-zone (extending from the shore to a depth of 10 ft) (CHGEC 1999). Samples were 19 collected from April to December but generally every other week from mid-June through early 20 October between the George Washington Bridge (RM 12) and the Troy Dam (RM 152). A 21 100-ft bag beach seine was used to collect 100 samples during each sampling period from 22 beaches selected according to a stratified random design. A completed tow covers an area of 23 approximately 450 m2.

24 For ancillary information, the NRC Staff obtained coastal population trends for striped bass, 25 American shad, Atlantic sturgeon, river herring, bluefish, Atlantic menhaden, and weakfish from 26 commercial and recreational harvest statistics gathered by the Atlantic States Marine Fisheries 27 Commission (ASMFC). Currently, the ASMFC Interstate Fisheries Management Program 28 coordinates the conservation and management of 22 Atlantic coastal fish species or species 29 groups. For species that have significant fisheries in both State and Federal waters, the 30 ASMFC works cooperatively with the relevant East Coast Regional Fishery Management 31 Councils to develop fishery management plans. The ASMFC also works with the National 32 Marine Fisheries Service to develop compatible regulations for Federal waters. For each of the 33 managed species, the ASMFC conducts periodic stock assessments. Information on each of 34 the managed species can be found at http://www.asmfc.org/.

35 Data from all three field surveys from the Hudson River Estuary Monitoring Program (LRS, FJS, 36 and BSS) were provided for this analysis. The three data sets included the annual abundance 37 index per taxon and life stage from 1974 through 2005, the annual total catch and volume 38 sampled per taxon from 1974 through 2005, and the weekly total volume sampled, catch 39 density, and total catch for each river segment and life stage for the 17 RIS fish from 1979 40 through 2005. The weekly volume, total catch, and catch density were the combined results of 41 each gear type. Analysis of the river-segment and riverwide trends provided a measure of 42 potential injury. The NRC staff used the ASMFC assessment of coastal harvest data as 43 ancillary information to evaluate Hudson River population trends.

44 December 2010 H-41 NUREG-1437, Supplement 38

Appendix H 1 Metrics Used by NRC Staff to Evaluate Population Trends 2 Abundance Index 3 The abundance index for YOY for each species was based on the catch from a selected 4 sampling program and used by the applicant and its contractors to estimate riverwide mean RIS 5 abundances. The selection process considered the expected location of each species in the 6 river, based on life-history characteristics and the observed catch rates from previous sampling.

7 The abundance index was constructed to account for the stratified random sampling design 8 used by each of the surveys. For the LRS and the FSS, sampling within a river segment was 9 further stratified by river depth and sampled with a separate gear type. For blueback herring, 10 alewife, bay anchovy, hogchoker, weakfish, and rainbow smelt, the YOY abundance index was 11 based on the catch from a single gear type.

12 The LRS (LA) and the FJS abundance index (FA) were similarly constructed and provided 13 unbiased estimates of the total and mean riverwide population abundance for selected species, 14 respectively (Cochran 1997). For Atlantic tomcod, weeks 19 through 22 of the LRS samples 15 were used to calculate the abundance index. The LA is strictly a sum of the weighted average 16 species densities over sampling weeks (w) instead of an average over weeks as for the FA.

17 For the FJS and each gear type, FA is constructed as a weighted mean of the average species 18 density ( d rsw ) for a given river segment (r = 0 to 12), sampling stratum (s = 1 to 3), and week v rs d rsw 1 r s 19 (w = 33 to 40), i.e., FA = I(0,1) for n equal to the number of weeks n w v rs r s 20 sampled, vrs equal to the volume of the given river segment and strata sampled, and the 21 indicator function I(0,1) equaling 1 if a given week was sampled and 0 otherwise (CHGEC 22 1999). For the FJS, strata sampled were the channel, bottom, and shoal for a given river 23 segment. Poughkeepsie and West Point river segments had the greatest channel volume, 24 Poughkeepsie and Tappan Zee had the greatest bottom volume, and Tappan Zee had the 25 greatest shoal volume. Because the river segment associated with IP2 and IP3 did not have 26 large bottom or shoal volumes, the abundance index would not be sensitive to changes in 27 population trends within the vicinity of IP2 and IP3.

28 The construction of the BSS abundance index (BA) provided an unbiased estimate of the mean 29 riverwide population abundance for striped bass, white perch, American shad, bluefish, spottail 30 shiner, and white catfish. A single gear type was used for all years; thus, BA was constructed as 31 a weighted average density or catch per haul ( c rw ) for a given river segment (r = 0 to 12) and Wr c rw 1

32 week (w = 33 to 40), i.e., B A = r I(0,1) for n equal to the number of weeks n w Wr r

33 sampled, Wr equaled the number of beach segments in the sampling design for a given river 34 segment, and the indicator function I(0,1) equaled 1 if a given week was sampled and 0 35 otherwise (CHGEC 1999).

36 NUREG-1437, Supplement 38 H-42 December 2010

Appendix H 1 Catch-Per-Unit-Effort 2 NRC Staff used the CPUE to evaluate riverwide and river-segment population trends and was 3 defined for a given species as the sum of the fish caught within a given year divided by the total 4 volume sampled. The CPUE for a given region is a biased (by the ratio of vs/V) estimate of the 5 population abundance, i.e.,

ys vs 6 E(CPUE) = E s = s vs s V s

7 where ys is the number of fish caught in a given stratum (s = 1 to 3),

8 s is the mean density of fish in a given stratum, 9 vs is the volume sampled in the given stratum, and 10 V is the total volume sampled).

11 For the LRS and FJS, a greater fraction of the volume sampled was from the bottom and shoal 12 strata; therefore, the CPUE from each river segment is not sensitive to changes in abundance 13 associated with fish sampled in the channel. For the BSS, there was only one gear type (beach 14 seine); thus, the CPUE from each river segment was equivalent to the density ( d rsw ) from the 15 BSS. The river-segment CPUE from the BSS was not used in the analysis.

16 The staff assumed that the river-segment densities for each of the surveys provided by the 17 applicant were the same average species densities, d rsw and c rw , used to derive the 18 abundance indices. Because multiple gear types were used in the LRS and FJS, the NRC staff 19 assumed that the densities for each gear type probably represented a weighted average.

20 Analysis of Population Impacts 21 To assess potential impacts to RIS populations near the IP2 and IP3 facility and within the lower 22 Hudson River, the NRC staff evaluated environmental data from FSS, BSS, and LRS studies, 23 and coastal trends, when available. Detailed information is presented in Appendix I.

24 River Segment 4 25 To assess potential impacts to RIS populations near the IP2 and IP3 facilities, the NRC staff 26 evaluated environmental data from FSS, BSS, and LRS studies for River Segment 4, which is 27 located at river kilometers (RKM) 63-76 (RM 39-46) (Figure 2-10 in the main text). The two 28 measurement metrics evaluated using the environmental data were density (estimated number 29 of RIS per given volume of water provided by the applicant) and CPUE (number of RIS captured 30 by the sampler for a given volume of water, derived by the NRC staff). Using these two metrics, 31 the staff detected population declines (assessment values 2.2) for alewife, American shad, 32 Atlantic tomcod, blueback herring, bluefish, hogchoker, rainbow smelt, spottail shiner, weakfish, 33 and white perch (Table H-13). The NRC staff was unable to detect population declines 34 (assessment values < 2.2) for bay anchovy, striped bass, and white catfish. In addition, the 35 staff could not determine if there was a decline for populations of Atlantic menhaden, Atlantic 36 and shortnose sturgeon, gizzard shad, and blue crab because the river studies did not routinely December 2010 H-43 NUREG-1437, Supplement 38

Appendix H 1 catch these species. As described above, the NRC staff defined a detected decline for this river 2 segment and a given RIS as a statistically significant negative slope in population abundance.

3 The decision rules for this analysis are found in Section H.1.3; the complete analysis is 4 presented in Appendix I.

5 Table H-13 Assessment of Population Trends for River Segment 4 Density Catch-per-Unit Effort River Species Segment FSS BSS LRS FSS LRS Assessment a

Alewife 4 4 N/A 4 N/A 4.0 American Shad 4 4 N/A 4 N/A 4.0 Atlantic Menhaden N/A N/A N/A N/A N/A Unknown Atlantic Sturgeon N/A N/A N/A N/A N/A Unknown Atlantic Tomcod 4 N/A 4 1 4 3.3 Bay Anchovy 4 1 N/A 1 N/A 2.0 Blueback Herring 4 4 N/A 1 N/A 3.0 Bluefish 1 4 N/A 4 N/A 3.0 Gizzard Shad N/A N/A N/A N/A N/A Unknown Hogchoker 4 4 N/A 4 N/A 4.0 Rainbow Smelt 1 N/A N/A 4 N/A 2.5 Shortnose Sturgeon N/A N/A N/A N/A N/A Unknown Spottail Shiner N/A 4 N/A N/A N/A 4.0 Striped Bass 1 1 N/A 1 N/A 1.0 Weakfish 4 N/A N/A 1 N/A 2.5 White Catfish 1 N/A N/A N/A N/A 1.0 White Perch 1 4 N/A 4 N/A 3.0 Blue Crab N/A N/A N/A N/A N/A Unknown (a) N/A: not applicable; YOY not present in samples.

Note: tabled values for density and catch-per-unit effort data are either a 1 (undetected decline) or a 4 (detected decline). The river segment assessment is an average of the scores for the given row.

6 Lower Hudson River 7 The NRC staff evaluated abundance index data provided by the applicant and CPUE data 8 obtained from the FJS, BSS, and LRS studies to assess RIS population trends for the lower 9 Hudson River (RKM 0-245, RM 0-152) (Figure 2-10 in the main text). Analysis of riverwide 10 data showed detectable population declines (assessment values 2.2) for American shad, 11 Atlantic tomcod, blueback herring, bluefish, hogchoker, rainbow smelt, weakfish, white catfish, 12 and white perch. The analysis failed to detect a decline (assessment values < 2.2) for alewife, 13 bay anchovy, spottail shiner, and striped bass (Table H-14). Staff could not assess population 14 trends for Atlantic menhaden, Atlantic and shortnose sturgeon, gizzard shad, and blue crab, 15 because too few were caught during the monitoring studies.

16 NUREG-1437, Supplement 38 H-44 December 2010

Appendix H 1 Table H-14 Assessment of Population Trends for the Lower Hudson River Abundance CPUE Riverwide Species Index FJS BSS LRS Assessment Alewife 1 1 1 N/Aa 1.0 American Shad 4 4 1 N/A 3.0 Atlantic Menhaden N/A N/A N/A N/A Unknown Atlantic Sturgeon N/A N/A N/A N/A Unknown Atlantic Tomcod 4 4 4 1 3.3 Bay Anchovy 4 1 1 N/A 2.0 Blueback Herring 4 4 4 N/A 4.0 Bluefish 1 4 4 N/A 3.0 Gizzard Shad N/A N/A N/A N/A Unknown Hogchoker 1 4 4 N/A 3.0 Rainbow Smelt 1 N/A 4 N/A 2.5 Shortnose Sturgeon N/A N/A N/A N/A Unknown Spottail Shiner 1 4 1 N/A 2.0 Striped Bass 1 1 1 N/A 1.0 Weakfish 4 N/A 1 N/A 2.5 White Catfish 4 N/A 4 N/A 4.0 White Perch 4 4 4 N/A 4.0 Blue Crab N/A N/A N/A N/A Unknown (a) N/A: not applicable; YOY not present in samples.

Note: tabled values for the abundance index and CPUE data are either a 1 (undetected decline) or a 4 (detected decline). The riverwide assessment is an average of the scores for the given row.

2 WOE Summary of Population Trends 3 The NRC staff used a WOE analysis to integrate all of the available RIS population data for IP2 4 and IP3 and the lower Hudson River. An overview of this analysis is presented at the beginning 5 of Section H.1.3; detailed information is presented in Appendix I. The results for this analysis 6 and impact conclusions are presented in Table H-15. The staffs analysis detected population 7 declines for eight YOY RIS: American shad, Atlantic tomcod, blueback herring, bluefish, 8 hogchoker, spottail shiner, and white perch. This analysis did not detect population declines for 9 bay anchovy and striped bass. Four species (alewife, rainbow smelt, weakfish, and white 10 catfish) exhibited variable population trend responses, meaning some data showed a 11 detectable population decline for a species, whereas others did not. Staff could not resolve 12 population trends for Atlantic menhaden, Atlantic sturgeon, gizzard shad, shortnose sturgeon, 13 and blue crab because Hudson River monitoring programs did not collect enough of them to 14 support a trend analysis. The decision rules for these analyses are found at the beginning of 15 Section H-3; the complete analysis is presented in Appendix I.

December 2010 H-45 NUREG-1437, Supplement 38

Appendix H Table H-15 Weight of Evidence Results for the Population Trend Line of Evidence River Segment Riverwide Assessment WOE Impact Measurement Assessment Score Score(b) Conclusion Score Utility Score(a) 2.4 1.7 Alewife 4.0 1.0 2.8 Variable American Shad 4.0 3.0 3.6 Detected Decline Atlantic Unknown Unknown Unknown Unresolved(c)

Menhaden Atlantic Sturgeon Unknown Unknown Unknown Unresolved(c)

Atlantic Tomcod 3.3 3.3 3.3 Detected Decline Undetected Bay Anchovy 2.0 2.0 2.0 Decline Blueback Herring 3.0 4.0 3.4 Detected Decline Bluefish 3.0 3.0 3.0 Detected Decline Gizzard Shad Unknown Unknown Unknown Unresolved(c)

Hogchoker 4.0 3.0 3.6 Detected Decline Rainbow Smelt 2.5 2.5 2.5 Variable Shortnose Unknown Unknown Unknown Unresolved(c)

Sturgeon Spottail Shiner 4.0 2.0 3.2 Detected Decline Undetected Striped Bass 1.0 1.0 1.0 Decline Weakfish 2.5 2.5 2.5 Variable White Catfish 1.0 4.0 2.2 Variable White Perch 3.0 4.0 3.4 Detected Decline Blue Crab Unknown Unknown Unknown Unresolved(c)

(a) Overall Use and Utility Score: Low = < 1.5, Medium 1.5 but 2.0, High > 2.0.

(b) WOE Score: Undetected Decline <2.2; Variable 2.2 but 2.8; Detected Decline >2.8.

(c) Unable to make a WOE conclusion because of a lack of data for trend assessment.

1 NUREG-1437, Supplement 38 H-46 December 2010

Appendix H 1 H.1.3.2. Analysis of Strength of Connection 2 The NRC staff conducted a strength-of-connection analysis to determine whether the operation 3 of the IP2 and IP3 cooling systems had the potential to influence RIS populations near the 4 facility or within the lower Hudson River. A summary of this analysis is in Section H.1.3; 5 detailed information on the analysis is presented in Appendix I. The strength-of-connection 6 analysis assumed that the IP2 and IP3 cooling systems can affect aquatic resources directly 7 through impingement or entrainment and indirectly by impinging and entraining potential food 8 (prey). By examining the distribution of the simulated differences in the cumulative annual 9 abundance of YOY RIS with and without losses from impingement and entrainment, staff could 10 assess the effect of the IP2 and IP3 cooling systems on the river segment population trend 11 (e.g., how strongly are the affects of the cooling system connected to the RIS of interest). The 12 results of this analysis indicated a High strength of connection for nine species (Table H-16).

13 For those species, the IP2 and IP3 cooling systems were removing the species at levels that 14 were proportionally higher than expected from of the observed abundance in the river. This is 15 strong evidence that the operation of the cooling systems can affects these species. For four 16 RIS, the strength of connection was Low (minimal evidence of connection). NRC staff could 17 not model the strength of connection for Atlantic menhaden, Atlantic and shortnose sturgeon, 18 gizzard shad, and blue crab, but concluded that the connection was Low because of the low 19 rate of entrainment and impingement observed at IP2 and IP3 (Table H-16).

20 21 Atlantic menhaden did not occur in entrainment samples (1981, 1983-1987) and occurred in low 22 numbers (approximately 630 annually) in impingement samples. The number impinged 23 represented 0.05 percent of all fish and blue crab impinged (1975-1990). For this reason, the 24 NRC staff concludes that the strength of connection for Atlantic menhaden is Low.

25 26 Atlantic and shortnose sturgeon did not occur in entrainment samples (1981, 1983-1987) and 27 occurred in low numbers (approximately 15 and 2 annually) in impingement samples. The 28 number impinged represented less than 0.005 percent of all fish and blue crab impinged (1975-29 1990). For this reason, the NRC staff concludes that the strength of connection for Atlantic and 30 shortnose sturgeon is Low.

31 32 Gizzard shad did not occur in entrainment samples (1981, 1983-1987). Gizzard shad appeared 33 regularly in impingement samples and increased from about 2400 annually from 1975 to 1984 to 34 about 7700 annually from 1985 to 1990. Sampling for blue crab in impingement samples began 35 in 1983. The numbers of impinged blue crab increased from approximately 2000 annually from 36 1983 to1987 to 56,600 annually from 1988 to 1990. Despite the increase in impingement, 37 gizzard shad and blue crab represented only one percent of all RIS impinged. For this reason, 38 the NRC staff concludes that the strength of connection for gizzard shad and blue crab is Low.

39 40 41 42 December 2010 H-47 NUREG-1437, Supplement 38

Appendix H 1 Table H-16 Weight of Evidence for the Strength-of-Connection Line of Evidence for YOY 2 RIS Based on the Monte Carlo Simulation RIS Strength of Connection RIS Strength of Connection Alewife High Hogchoker High American Shad Low Rainbow Smelt High Atlantic Shortnose Cannot be Modeled(a) Cannot be Modeled(a)

Menhaden Sturgeon Atlantic Cannot be Modeled(a) Spottail Shiner High Sturgeon Atlantic Low Striped Bass High Tomcod Bay Anchovy High Weakfish High Blueback High White Catfish Low Herring Bluefish Low White Perch High Gizzard Shad Cannot be Modeled(a) Blue Crab Cannot be Modeled(a)

(a)

Estimates for model parameters were unavailable or information was lacking. Strength of connection assumed to be Low based on review of impingement and entrainment data.

3 H.1.3.3. Impingement and Entrainment Impact Summary 4 The final integration of population-level and strength-of-connection LOE is presented in 5 Table H-17. This table shows the final conclusions for both LOEpopulation trends and 6 strength of connection. Assignment of an NRC level of impact (small, moderate, or large) 7 requires information on both a measurable response in the RIS population and clear evidence 8 that the RIS is influenced by the operation of the IP2 and IP3 cooling systems. Thus, when the 9 strength of connection is low, it is not possible to assign an impact level greater than small, 10 because of little evidence that a relationship between the cooling system and RIS exists.

11 Conversely, for an RIS with a high strength of connection to the IP2 and IP3 cooling system 12 operation but evidence of no population decline, the final determination must be small.

13 As discussed previously, the NRC staff believes that long-term population trends for RIS in the 14 lower Hudson River provide the best evidence of whether adverse effects are present. Synoptic 15 sampling of the river for almost four decades has produced a long-term data set that provides a 16 useful way to evaluate status of individual species commonly found in the river, and the complex 17 food web that sustains them. In addition to synoptic sampling from the mouth of the Hudson to 18 the Troy Dam, the environmental sampler that is the IP2 and IP3 cooling system provides 19 important information on the species composition near the plant. By using reported 20 entrainment and impingement losses for YOY fish as input to population models and using 21 Monte Carlo simulations, staff can evaluate how population trajectories might change with and 22 without the presence of Indian Point, thus providing a way to assess the relationship between 23 the cooling system and the aquatic resources. Taken together, the NRC staff used these two 24 lines of evidence to determine whether the once-through cooling systems associated with IP2 25 and IP3 had the potential to adversely affect important aquatic resources. To conclude the NUREG-1437, Supplement 38 H-48 December 2010

Appendix H 1 occurrence of an adverse effect for a particular RIS that was attributable to Indian Point, the 2 staff required that there must be evidence of a detectable, long-term RIS population decline, 3 and evidence that the operation of the Indian Point cooling system influenced the RIS.

4 5 Based on the WOE assessment (Table H-17), the NRC staff concludes that the impact levels s 6 are Small for eleven species: American shad, Atlantic menhaden, Atlantic sturgeon, Atlantic 7 tomcod, bay anchovy, bluefish, gizzard shad, shortnose sturgeon, striped bass, white catfish, 8 and blue crab. Further, the staff concludes that the impacts are Moderate for three species:

9 alewife, rainbow smelt, and weakfish. Finally, the staff concludes that the impacts are Large for 10 four species: blueback herring, hogchoker, spottail shiner, and white perch. A brief discussion 11 of the WOE results for species with Large or moderate impact levels is presented below.

12 Environmental data sets used by the NRC staff to support population trend analysis include 13 river-wide abundance and CPUE data, river segment 4 (Indian Point) density, and CPUE 14 information from the FSS, BSS, and LRC studies for each RIS.

15 Table H-17 Impingement and Entrainment Impact Summary for Hudson River YOY RIS Impacts of IP2 and IP3 Population Trend Strength of Connection Species Cooling Systems on Line of Evidence Line of Evidence YOY RIS Alewife Variable High Moderate American Shad Detected Decline Low Small Atlantic Menhaden Unresolved(a) Low(b) Small Atlantic Sturgeon Unresolved(a) Low(b) Small Atlantic Tomcod Detected Decline Low Small Bay Anchovy Undetected Decline High Small Blueback Herring Detected Decline High Large Bluefish Detected Decline Low Small Gizzard Shad Unresolved(a) Low(b) Small Hogchoker Detected Decline High Large Rainbow Smelt Variable High Moderate-Large(c)

Shortnose Sturgeon Unresolved(a) Low(b) Small Spottail Shiner Detected Decline High Large Striped Bass Undetected Decline High Small Weakfish Variable High Moderate White Catfish Variable Low Small White Perch Detected Decline High Large Blue Crab Unresolved(a) Low(b) Small (a) Population LOE could not be established using WOE; therefore, population LOE could range from small to large.

(b) Strength of connection could not be established using Monte Carlo simulation; therefore, strength of connection was based on the rate of entrainment and impingement.

(c) Section 4.1.3.3 provides supplemental information.

December 2010 H-49 NUREG-1437, Supplement 38

Appendix H 1 Blueback Herring 2

3 The NRC staff concludes that a Large impact is present for YOY blueback herring because a 4 detectable population decline occurred in most of the river-wide (3 of 3) and river segment (2 of 5 3) data sets used in the analysis, and there was a high strength of connection with the IP2 and 6 IP3 cooling system. Blueback herring, which along with alewife are known as river herring, 7 share life history and distribution characteristics with alewife. An anadromous species, 8 blueback herring migrate upriver to spawn during the spring and live about seven to eight 9 years. This species feeds primarily on insect larvae and copepods and is prey for bluefish, 10 weakfish, and striped bass (Hass-Castro 2006). Hass-Castro (2006) also reports that river 11 herring populations are well below historic levels of the mid 20th century, possibly because of 12 overfishing, habitat destruction, and states that a population assessment has been listed as a 13 high priority by the ASMFC, given the blueback herring listing as a species of concern by the 14 NMFS.

15 16 Hogchoker 17 18 The NRC staff concludes that a Large impact is present for YOY hogchoker because a 19 detectable population decline occurred in most of the river-wide (2 of 3) and river segment (3 of 20 3) data sets, and strength of connection with the IP2 and IP3 cooling system was high. This 21 species is a right-eyed flatfish that occurs in the Hudson River estuary and surrounding bays 22 and coastal waters. Adults are generalists, and eat annelids, arthropods, and siphons of clams; 23 adults and juveniles are prey of striped bass. Coastal population trend data were not available 24 for this species.

25 26 Spottail Shiner 27 28 The NRC staff concludes that a Large impact is present for YOY spottail shiner because a 29 detectable population decline occurred in the river-wide (1 of 3) and river segment (1 of 1) 30 datasets, and there was a high strength of connection with the IP2 and IP3 cooling system. The 31 habitat for the spottail shiner includes small streams, lakes, and large rivers, including the 32 Hudson. This species feeds primarily on aquatic insect larvae, zooplankton, benthic 33 invertebrates, and fish eggs and larvae, and is the prey of striped bass. Spottail shiners spawn 34 from May to June or July (typically later for the northern populations) over sandy bottoms and 35 stream mouths (Smith 1985; Marcy et al. 2005); water chestnut (Trapa natans) beds provide 36 important spawning habitat (CHGEC 1999). Individuals older than three years are rare, but 37 there is evidence of individuals living four or five years (Marcy et al. 2005). Coastal population 38 trend data were not available for this species.

39 40 White Perch 41 42 The NRC staff concludes that a Large impact is present for YOY white perch because a 43 detectable population decline occurred in the majority of the river-wide (3 of 3) and river 44 segment (2 of 3) datasets, and there was a high strength of connection with the IP2 and IP3 45 cooling system. White perch are an estuarine species that is a year-round resident in the 46 Hudson River, and is commonly entrained by IP2 and IP3. An opportunistic feeder, this 47 species is prey to large piscivorous fish and terrestrial vertebrates. White perch have never NUREG-1437, Supplement 38 H-50 December 2010

Appendix H 1 been a recreationally or commercially important resource for the Hudson River, and commercial 2 fishing was closed in 1976 because of polychlorinated biphenyl (PCB) contamination. White 3 perch populations appear to be relatively stable in the Maryland portion of Chesapeake Bay, 4 and commercial harvest has generally increased since 1980 in that area (Maryland DNR 2005).

5 6 Alewife 7

8 The NRC staff concludes that a Moderate impact is present for YOY alewife because a 9 detectable population decline occurred in river segment 4 (3 out of 3 datasets) and there was a 10 high strength of connection with the IP2 and IP3 cooling system. The NRC staff determined 11 that the population trend results were variable because the declines observed in river segment 12 4 were not confirmed by river-wide population trends. YOY alewife (river herring) are present in 13 the lower and upper reaches of the Hudson River, and feed as juveniles primarily on 14 amphipods, zooplankton, and fish eggs and larvae, and as an adult on small fish. This species 15 is also prey for bluefish, weakfish, and striped bass. ASMFC implemented a combined 16 fisheries management plan for American shad and river herring in 1985. Although the herring 17 fishery is one of the oldest fisheries in the United States, no commercial fishery for river herring 18 currently exists in the Hudson River. River herring population declines have been reported in 19 Connecticut, Rhode Island, and Massachusetts, and NMFS has listed river herring as a species 20 of concern throughout its range Hass-Castro (2006).

21 22 Rainbow Smelt 23 24 The NRC staff concludes that a Moderate to Large impact level is present for rainbow smelt 25 because detectable population declines occurred in river-wide (1 of 2) and river segment (1 of 26 2) data sets, and there was a high strength of connection with the IP2 and IP3 cooling system.

27 Although detectable population declines occurred in two of four river data sets, indicating 28 population trend results were variable, the staff concluded that a Moderate-Large impact was 29 present based on the dramatic population declines observed for this species over the past three 30 decades. Rainbow smelt is an anadromous species once commonly found along the Atlantic 31 Coast. Larval and juvenile smelt feed primarily on planktonic crustaceans; adults eat 32 crustaceans, polychaetes, and small fish. Bluefish and striped bass are primary predators of 33 rainbow smelt. Once a prevalent fish in the Hudson River, the rainbow smelt has undergone an 34 abrupt population decline in the Hudson River since 1994, and the species may no longer have 35 a viable population within the Hudson River. The last tributary run of rainbow smelt was 36 recorded in 1988, and the Hudson River Utilities Long River Ichthyoplankton Survey showed 37 that PYSL essentially disappeared from the river after 1995 (Daniels et al. 2005). The NRC 38 staffs regression analysis of rainbow smelt population trends was affected by the lack of 39 rainbow smelt caught by the Hudson River field surveys after 1995. Detectable population 40 declines were present for CPUE data set but not for density or abundance index data, given the 41 disappearance of this species from the river. Thus, the WOE conclusion of moderate impact 42 may, in fact, be an underestimate of the true impact; the staff concluded that a Moderate-Large 43 impact assessment was appropriate.

44 45 December 2010 H-51 NUREG-1437, Supplement 38

Appendix H 1 Weakfish 2

3 The NRC staff concludes that a Moderate impact is present for weakfish because detectable 4 population declines occurred in river-wide (1 of 2) and river segment (1 of 2) data sets, and 5 there was a high strength of connection with the IP2 and IP3 cooling system. Because 6 detectable declines occurred in two of four river data sets, staff determined that the population 7 trend results were variable. The weakfish is historically one of the most abundant fish species 8 along the Atlantic coast and is fished recreationally and commercially. Small weakfish prey 9 primarily on crustacean, whereas larger individuals eat small fish. Bluefish, striped bass, and 10 larger weakfish are primary predators of smaller weakfish. Weakfish are thought to be in decline 11 based on decreased commercial landings in recent years. The weakfish stock declined 12 suddenly in 1999 and approached even lower levels by 2003, which ASMFC determined to be 13 because of higher natural mortality rates rather than fishing mortality (ASMFC 2007). A leading 14 hypothesis suggests reduced prey availability and increased predation by striped bass may 15 contribute significantly to rising natural mortality rates in the weakfish population (ASMFC 2007).

16 Integrated Assessment 17 The NRC staff developed a calculation for the overall impact of the IP2 and IP3 cooling system 18 by integrating the numerical results for the WOE assessment (Table H-17). Staff used a scoring 19 criteria (e.g. small potential for adverse impacts = 1, moderate impacts = 2, large impacts = 4) to 20 obtain an average over all RIS that reflects an equally spaced interval on a logarithmic scale for 21 which the magnitude of harm doubles at each step. From Table H-17, NRC staff concludes that 22 there are eleven RIS showing a Small impact (scored as a 1), three RIS showing a Moderate 23 impact (scored as a 2), and four RIS showing a Large impact (scored as a 4). The average of 24 the 18 RIS scores rounded to the nearest whole number is 2.0 which equates to a Moderate 25 impact. Thus, NRC staff concludes that the level of impact from the operation of IP2 and IP3 26 cooling water systems to the aquatic resources of the lower Hudson River during the 27 relicensing period would be Moderate.

28 H.2 Cumulative Impacts on Aquatic Resources 29 In addition to the potential impacts associated with the IP2 and IP3 cooling water intake system 30 described in Section H.1, it is possible that other natural or anthropogenic factors unrelated to 31 the relicensing of Indian Point could influence the aquatic resources of the lower Hudson River.

32 In this section, the NRC staff discusses and evaluates potential stressors that could contribute 33 to the total impacts to the aquatic resources during the license renewal period. Potential 34 stressors include other Hudson River facilities that withdraw water, the presence of zebra 35 mussels in the freshwater portions of the river, fishing pressure associated with commercially 36 and recreationally important species, habitat loss, interactions with other invasive species, and 37 impacts associated with changes to water and sediment quality caused by short-term 38 anthropogenic activities or long-term influences associated with global climate change.

39 Population trends should, in theory, reflect cumulative effects of all impacts on the population.

40 Impacts attributable to the Indian Point cooling systems have already been analyzed. This 41 section of the appendix concentrates on effects associated with the invasion of zebra mussels, NUREG-1437, Supplement 38 H-52 December 2010

Appendix H 1 using a WOE approach, as discussed in Section H.3. A qualitative assessment of effects 2 associated with fishing pressure was also explored.

3 The NRC staff evaluated potential population-level impacts to RIS for the lower Hudson River 4 (RKM 0-245, RM 0-152) (Figure 2-10 in the main text) in Section H.3.1. Riverwide data used in 5 the analysis included the abundance index provided by the applicant and CPUE data obtained 6 from FJS, BSS, and LRS studies. The results of this analysis were presented in Table H-14 and 7 showed a large potential for adverse impacts for 7 of the 18 RIS caused by the CWIS.

8 An analysis conducted on behalf of Entergy (Barnthouse et al. 2008) used environmental risk-9 assessment techniques to evaluate the potential for adverse impacts to Hudson River RIS from 10 a variety of natural and anthropogenic stressors, including the operation of the IP2 and IP3 11 CWIS, fishing pressure, the presence of zebra mussels, predation by striped bass, and water 12 temperature. Barnthouse et al. (2008) concluded that the Indian Point CWIS had no effect on 13 all seven of the RIS included in their study. Instead, the authors concluded that observed 14 population declines in selected RIS were influenced by striped bass predation, mortality 15 imposed by fishing, water temperature, and zebra mussel invasion.

16 Strayer et al. (2004) concluded that the abundance of juvenile American shad and white perch 17 declined following the zebra mussel invasion. Further, the authors found that juvenile alewife 18 abundance increased following the zebra mussel invasion. The NRC staffs analysis follows.

19 Zebra Mussels 20 To evaluate the effects of zebra mussels, the NRC staff applied a WOE approach. It is 21 important to note, however, that the Hudson River monitoring surveys used in these analyses 22 were designed to evaluate the population abundance of selected species. They were not 23 designed to evaluate competing and confounded factors affecting population abundance.

24 Coincident measures of zebra mussel abundance through time, water quality, changes to 25 thermal discharges, changes in fishing pressure, and predator-prey interactions would be a 26 minimal requirement to begin to rank stressor effects on each population. These measures are 27 not available, and so the remaining analyses should be viewed as the development of 28 hypotheses of potential impacts associated with zebra mussels.

29 The NRC staff analyzed the impact of zebra mussels on RIS populations that were caught in 30 River Segment 12 (Albany). The NRC staff analyzed the 75th percentile of the weekly FJS and 31 BSS density and CPUE data from this river segment and used this information to evaluate the 32 population trend LOE for these species. Data for white perch, blueback herring, alewife, 33 American shad, white catfish, spottail shiner, and striped bass were used in the analysis 34 because all have high densities of YOY within this region. Only weeks 27 to 43 were used in 35 the analysis for the FJS and weeks 22 to 43 for the BSS survey so that most years contained 36 observations from the months July through October and June through October for each survey, 37 respectively. Effects associated with changes in gear type for the FJS (1985) were also 38 considered. Details of the analysis are presented in Appendix I.

39 Simple linear regression and segmented regression with a single join point were fit to the annual 40 measure of abundance for each RIS, as described in Section H.1.3. If the estimated slope from 41 the linear regression or either slope from the segmented regression, whichever was determined 42 to be the better fitting model, was significantly less than zero, then an adverse population impact 43 was considered detected.

December 2010 H-53 NUREG-1437, Supplement 38

Appendix H 1 The strength of connection to a potential impact associated with a zebra mussel invasion was 2 determined by the temporality of the observed change in population trends and the year 3 associated with invasion of the zebra mussels in the Hudson River (1991) based on work by 4 Strayer et al. (2004). For any stressor to be considered a potential cause of an impact, the 5 stress must occur before the response (Adams 2003). For the assessment of the observed 6 response, the year associated with a change in population trend was estimated by the join point 7 from the segmented regression or was considered pre-1991, if the linear model was the better 8 fit to the density and CPUE data collected from Region 12 (Albany area). If the join point was 9 before 1991, then the strength of connection was defined as low. If the segmented regression 10 did not converge or was not the better fitting model, the linear regression was used to suggest 11 that there was no change in slope following invasion; thus, the strength of connection was low.

12 If the join point from the segmented regression was after 1991, then the strength of connection 13 was defined as high.

14 Based on the WOE analysis (see Appendix I for details) and the decision rules presented in 15 Section H.1.3, the NRC staff determined potential moderate-to-large population impacts within 16 River Segment 12 (Albany) were possible for many RIS, including American shad, blueback 17 herring, spottail shiner, white catfish, and white perch (Table H-18). NRC staff concluded a 18 small potential for adverse population impacts was present for alewife and striped bass. The 19 data tables for which the results of the strength of connection between adverse population 20 impacts and the zebra mussel invasion are drawn are presented in Appendix I. None of the RIS 21 evaluated had a statistically significant increase in population abundance in River Segment 12.

22 The strength-of-connection analysis assumes that zebra mussels can affect aquatic resources 23 indirectly by reducing potential food resources (prey) or by altering habitat (e.g. shelter). The 24 results of the strength-of-connection analysis are presented in Table H-19 and show that a Low 25 strength of connection was observed for all fish. For each RIS, two of the data sets out of a 26 possible three suggested a Low strength of connection.

27 Table H-18 Population Trends after the invasion of Zebra Mussels in 1991 for Density 28 and CPUE of YOY Collected from River Segment 12 (Albany)

Hypothesized Level Species FSS Density BSS Density FJS CPUE WOE of Impact to Population Trend Alewife 1 1 1 1.0 Undetected Decline American Shad 4 4 1 3.0 Detected Decline Blueback Herring 4 4 4 4.0 Detected Decline Spottail Shiner 4 1 4 3.0 Detected Decline Striped Bass 1 1 1 1.0 Undetected Decline White Catfish 1 N/A 4 2.5 Variable White Perch 4 4 4 4.0 Detected Decline N/A is not applicable; YOY are not present in samples.

29 30 NUREG-1437, Supplement 38 H-54 December 2010

Appendix H 1 Table H-19 Strength of Connection between Population Trends and Zebra Mussel 2 Invasion Hypothesized Strength Species FJS Density BSS Density FJS CPUE WOE of Connection Alewife 1 1 4 2.0 Low American Shad 4 1 1 2.0 Low Blueback Herring 1 4 1 2.0 Low Spottail Shiner 4 1 1 2.0 Low Striped Bass 1 1 4 2.0 Low White Catfish 1 N/A 1 1.0 Low White Perch 1 4 1 2.0 Low N/A is not applicable; YOY are not present in samples.

3 4 The final integration of population-level and strength-of-connection LOE is presented in 5 Table H-20. This table shows the final NRC staff conclusions for both LOEpopulation trends 6 and strength of connection. The conclusion of adverse impact requires both a measurable 7 response in the RIS population and clear evidence that the RIS is influenced by the zebra 8 mussel invasion. When the strength of connection is low, it is not possible to arrive at an impact 9 level greater than small, because of little evidence that a relationship between the mussel 10 invasion and population trends exists. Conversely, for an RIS with a High strength of 11 connection to the zebra mussel invasion but evidence of no population decline, the final 12 determination must be small.

13 Based on the final WOE assessment, the NRC staff concludes that there is a small potential for 14 adverse impacts from the zebra mussel invasion for all seven of the RIS. Alewife and striped 15 bass showed no evidence of population declines, and white catfish displayed a population 16 decline but had a Low strength of connection. The Staff detected a potential large population 17 impact for American shad, blueback herring, spottail shiner, and white perch, however there 18 was an inconsistent assessment of strength of connection among the three data sets (Figures 19 H-11, H-12, and H-13).

20 Table H-20 Weight of Evidence Associated with Potential Negative Impacts on 21 Population Trends from Zebra Mussel Invasion Hypothesized Level of Hypothesized Hypothesized Species Impact to Strength of Impact to Population Population Trends Connection Trends from Zebra Mussel Alewife Undetected Decline Low Small American Shad Detected Decline Low Small Blueback Herring Detected Decline Low Small Spottail Shiner Detected Decline Low Small Striped Bass Undetected Decline Low Small White Catfish Variable Low Small White Perch Detected Decline Low Small December 2010 H-55 NUREG-1437, Supplement 38

Appendix H 1 The NRC staff analysis concluded that a large potential adverse population impact was present 2 for American shad in River Segment 12 (Albany) (Table H-20). For the WOE analysis, NRC 3 staff used the post-1985 FSS River Segment 12 density data, since the catch efficiency of the 4 beam trawl for YOY American shad was less than the epibenthic sled. The Staff also used the 5 1979 to 2005 BSS density data and the FSS CPUE data from River Segment 12. The relative 6 population response and the timing of the effect of the zebra mussel invasion for each data set 7 are presented in Figures H-11, H-12, and H-13. Strayer et al. (2004) used the riverwide 8 abundance index to conclude that the abundance of American shad was affected by zebra 9 mussels. The NRC staff found, however, that only the FSS River Segment 12 density data 10 showed a decline for American shad following the mussel invasion (Figure H-11). The BSS 11 density data suggested a continuous decline from 1979-2005 (Figure H-12), and the FSS 12 CPUE showed a decline before the invasion (Figure H-13). Therefore, the NRC staff and 13 Barnthouse et al. (2008) disagreed with Strayer et al. (2004) that zebra mussels were a 14 potential cause of the American shad decline.

NUREG-1437, Supplement 38 H-56 December 2010

Appendix H FSS 3rd Q Standardized Density FSS 3rd Q Standardized Density Zebra Mussel Invasion Zebra Mussel Invasion 3 2 2 1 1

0 0

-1

-1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey American Shad 85-05 Blueback Herring Zebra Mussel Invasion FSS 3rd Q Standardized Density FSS 3rd Q Standardized Density Zebra Mussel Invasion 4 3 3 2 1

2 0

1

-1 0 -2

-1 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Spottail Shiner Outlier White Perch 1 Source: Normandeau 2008 2 Figure H-9 Standardized population density data for River Segment 12 (RS12) Fall 3 Juvenile Surveys (Normandeau 2008). Shaded plots indicate potential effects from zebra 4 mussel invasion.

5 The NRC staff analysis concluded that a large potential population impact was present for 6 juvenile blueback herring in River Segment 12 (Albany). However, the NRC staff and 7 Barnthouse et al. (2008) disagreed with Strayer et al. (2004) that zebra mussels were a 8 potential cause in the decline of blueback herring. Only the BSS data suggested a possible 9 blueback herring response to the zebra mussel invasion (Figure H-12).

December 2010 H-57 NUREG-1437, Supplement 38

Appendix H Zebra Mussel Invasion Zebra Mussel Invasion 2 2 1

BSS 3rd Q Density BSS 3rd Q Density 1

0 0

-1

-1

-2

-2 -3

-3 -4 0 10 20 30 0 10 20 30 Years of Survey Years of Survey American Shad Outlier Blueback Herring Zebra Mussel Invasion Zebra Mussel Invasion 4 2 3

BSS 3rd Q Density BSS 3rd Q Density 1

2 0

1

-1 0

-1 -2

-2 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Spottail Shiner Outlier White Perch 1 Source: Normandeau 2008 2 Figure H-12 Standardized population density data for River Segment 12 (RS12) Beach 3 Seine Surveys. Shaded plots indicate potential effects from zebra mussel invasion.

4 The NRC staff analysis concluded that a large potential population impact was present for 5 juvenile spottail shiner in River Segment 12 (Albany). Strayer et al. (2004) concluded that 6 there was no change in spottail shiner abundance, and Barnthouse et al. (2008) did not 7 evaluate spottail shiner population trends. The FSS density data was the only data set to NUREG-1437, Supplement 38 H-58 December 2010

Appendix H 1 suggest a possible effect of the zebra mussel invasion (Figure H-11). The BSS and FSS CPUE 2 showed a continuous decline from 1974 to 2005 (Figure H-12 and Figure H-13).

3 The NRC staff analysis concluded that a large potential population impact was present for 4 juvenile white perch in River Segment 12 (Albany). White perch population trends obtained 5 from the FSS were not affected by gear changes (year 6 of the survey). All three data sets 6 indicated an early decline in fish density and CPUE in River Segment 12 (Figures H-11, H-102 7 and H-13). Thus, the NRC Staff concluded that a combination of stressors acting on the 8 riverwide population is associated with a relatively greater adverse impact than the impact from 9 the zebra mussel invasion.

Zebra Mussel Invasion Zebra Mussel Invasion 2 1.5 1.0 1

FSS 3rd Q CPUE FSS 3rd Q CPUE 0.5 0.0 0

-0.5

-1.0

-1

-1.5

-2 -2.0

-2.5

-3 -3.0 0 10 20 30 0 10 20 30 Years of Survey Years of Survey American Shad Blueback Herring Zebra Mussel Invasion Zebra Mussel Invasion 4 2 3 1 FSS 3rd Q CPUE FSS 3rd Q CPUE 2 0 1 -1 0 -2

-1 -3

-2 -4 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Spottail shiner Outlier White Perch 10 Source: Normandeau 2008 11 Figure H-13 Standardized CPUE trend data for River Segment 12 (RS12) Fall Juvenile 12 Surveys.

December 2010 H-59 NUREG-1437, Supplement 38

Appendix H 1 Water Quality and Climate Change 2 Sewage Treatment System Upgrades As discussed in Section 2.2.5, the increasing populations along the river and within the watershed resulted in an increased discharge of sewage into the Hudson River and an overall degradation of water quality. Beginning in 1906 with the creation of the Metropolitan Sewerage Commission of New York, a series of studies were conducted to formulate plans to improve water quality within the region (Brosnan and OShea 1996). In the freshwater portion of the lower Hudson River, the most dramatic improvements in wastewater treatment were made between 1974 and 1985, resulting in a decrease in the discharge of suspended solids by 56 percent. Improvements in the brackish portion of the river were even greater. In the New York City area, the construction and upgrading of water treatment plants reduced the discharge of untreated wastewater from 450 million gallons per day (mgd) in 1970 to less than 5 mgd in 1988 (CHGEC 1999). The discharge of raw sewage was further reduced between 1989 and 1993 due to the implementation of additional treatment programs (Brosnan and OShea 1996).

During the 1990s, three municipal treatment plants located in the lower Hudson River converted to full secondary treatmentNorth River (1991), North Bergen MUA-Woodcliff (1991), and North Hudson Sewerage Authority West New York (1992). In addition, the North Hudson Sewerage Authority-Hoboken plant, located on the western bank of the Hudson River opposite Manhattan Island, went to full secondary treatment in 1994 (CHGEC 1999). Upgrades to the Yonkers Joint Treatment Plant in 1988 and the Rockland County Sewer District #1 in 1989 also resulted in improvements in water quality in the brackish portion of the Hudson River. In the mid-1990s, the Rockland County Sewer District #1 and Orangetown Sewer District plants were also upgraded. (CHGEC 1999) 3 Trends in Dissolved Oxygen 4 A review of long-term trends in dissolved oxygen (DO) and total coliform bacteria concentrations 5 by Brosnan and OShea (1996) has shown that improvements to water treatment facilities have 6 improved water quality. The authors noted that, between the 1970s and 1990s, DO 7 concentrations in the Hudson River generally increased. The increases coincided with the 8 upgrading of the 170 million mgd North River plant to secondary treatment in the spring of 1991.

9 DO, expressed as the average percent saturation, exceeded 80 percent in surface waters and 10 60 percent in bottom waters during summer in the early 1990s. DO minimums also increased 11 from less than 1.5 milligrams per liter (mg/L) in the early 1970s to more than 3.0 mg/L in the 12 1990s, and the duration of low DO (hypoxia) events was also reduced (Brosnan and OShea 13 1996). Similar trends showing improvements in DO were noted by Abood et al. (2006) from an 14 examination of two long-term data sets collected by NYCDEP in the lower reaches of the river.

15 Brosnan and OShea (1996) also noted a strong decline in total coliform bacteria concentrations 16 that began in the 1970s and continued into the 1990s, coinciding with sewage treatment plant 17 upgrades.

18 Chemical Contaminants 19 As discussed in Section 2.2.5, the lower Hudson River currently appears on the EPA 303-d list 20 as an impaired waterway, because of the presence of PCBs and the need for fishing restrictions 21 (EPA 2004). Contamination of the sediment, water, and biota of the Hudson River estuary 22 resulted from the manufacture of capacitors and other electronic equipment in the towns of Fort NUREG-1437, Supplement 38 H-60 December 2010

Appendix H 1 Edward and Hudson Falls, New York, from the 1940s to the 1970s. Investigations conducted by 2 the EPA and others over the past 25 years have delineated the extent and magnitude of 3 contamination, and numerous cleanup plans have been devised and implemented. Recently, 4 EPA Region 2 released a Fact Sheet describing a remedial dredging program designed to 5 remove over 1.5 million cubic yards of contaminated sediment covering 400 acres, extending 6 from the Fort Edwards Dam to the Federal Dam at Troy (EPA 2008). Concentrations of PCBs in 7 river sediments below the Troy Dam are much lower. Work summarized by Steinberg et al.

8 (2004) suggests the sediment-bound concentrations of PCBs and dioxins have generally 9 declined in the lower Hudson River since the 1970s and are now at or below ER-M limits.

10 Chemical contaminants present in the tissues of fish in the Hudson River estuary have been 11 extensively studied for many years and resulted in the posting of consumption advisories by the 12 States of New York and New Jersey. Current information summarized in Steinberg et al. (2004) 13 suggests that many recreationally and important fish and shellfish still contain levels of metals, 14 pesticides, PCBs, and dioxins above the Food and Drug Administration (FDA) guidance values 15 for commercial sales. Tissue concentrations of mercury were of concern only for striped bass; 16 other fish, and shellfish, including flounder, perch, eels, blue crab, and lobster, contained 17 concentrations of mercury in their tissues well below the FDA limit of 2 parts per million (ppm) 18 for commercial sale. Concentrations of chlordane in white perch, American eels, and the 19 hepatopancreas (green gland) of blue crabs were also above FDA guidelines. DDT 20 concentrations in the tissues of most recreationally and commercially valuable fish and shellfish 21 in the estuary were below the 2 ppm FDA limit with the exception of American eel.

22 Unfortunately, the concentrations of 2,3,7,8-TCDD (a dioxin compound) and total PCBs in fish 23 and shellfish tissues were often above FDA guidance limits, suggesting fish and shellfish 24 obtained from some locations within the estuary should be eaten in moderation or not at all.

25 The results described above suggest that, although a wide variety of contaminants still exist in 26 sediment, water, and biota in the lower Hudson River, the overall levels appear to be decreasing 27 because of the imposition of strict discharge controls by Federal and State regulatory agencies 28 and improvements in wastewater treatment. These trends appear to be confirmed, based on 29 the results of a NOAA-sponsored toxicological evaluation of the estuary in 1991, as described in 30 Wolfe et al. (1996). There is continuing concern, however, that legacy PCB waste may still 31 pose a threat to invertebrate, fish, and human populations. A study by Achman et al. (1996) 32 suggested that PCB concentrations in sediment measured at several locations in the lower 33 Hudson River from the mouth to Haverstraw Bay are above equilibrium with overlying water and 34 may be available for transfer within the food web. The implications of this study are that, in 35 some locations within the lower river, the sediments could act as a source of PCBs and pose a 36 long-term chronic threat. The authors concluded, however, that fate and transport modeling 37 would be required to fully understand the implications of this potential contaminant source.

38 Based on the above information, it appears that the overall water quality in the lower Hudson 39 River is generally improving, although the presence of legacy contaminants still presents a 40 concern to regulatory agencies. Based on the information reviewed, the NRC staff concludes 41 that the cumulative impact of water quality on RIS should decline if efforts continue to address 42 point- and non-point pollution and legacy waste removal and treatment.

43 December 2010 H-61 NUREG-1437, Supplement 38

Appendix H 1 Climate Change 2 The potential cumulative effects of climate change on Hudson River RIS could result in a variety 3 of fundamental changes to watersheds that would affect aquatic resources. The environmental 4 factors of significance identified by Kennedy (1990) that would affect estuarine systems included 5 sea level rise, temperature increase, salinity changes, and wind and water circulation changes.

6 Changes in sea level could result in dramatic effects on nearshore communities, including the 7 reduction or redistribution of submerged aquatic vegetation, changes to marsh communities, 8 and influences to wetland areas adjacent to nearshore systems. Water temperature increases 9 could affect spawning patterns or success, or influence the distribution of key RIS when cold-10 water species move poleward while warm-water species become established in new habitats.

11 Changes to river salinity and the presence of the salt front could influence the spawning and 12 distribution of RIS, and the range of exotic or nuisance species. Fundamental changes in 13 precipitation could profoundly influence water circulation and change the nature of 14 allochothonous and autochothonous inputs to the system. This could result in fundamental 15 changes to primary production and influence the estuarine food web on many levels. Kennedy 16 (1990) also concluded that some fisheries and aquaculture enterprises and communities might 17 benefit from the results of climate change, while others would suffer extensive economic losses 18 that could lead to population shifts.

19 The extent and magnitude of climate change impacts to the aquatic resources of the lower 20 Hudson River are an important component of the cumulative assessment analyses. This 21 assessment is beyond the scope of this review and will need to be explored and evaluated by 22 others. A minimal evaluation of shifts in the distribution of RIS standardized mean density for 23 1979 to 1983 and for 2001 to 2005 was explored in Appendix H. Several RIS (striped bass, 24 alewife, spottail shiner, hogchoker, and white perch) may be shifting their distribution slightly 25 upriver while bay anchovies may be shifting their distribution seaward. This analysis attempts 26 only to explore hypotheses about potential redistribution of fish; definitive statements cannot be 27 made because of data limitations. Thus, the NRC staff has concluded that the cumulative 28 effects of climate change cannot be determined.

29 H.3 References 30 10 CFR Part 51. U.S. Code of Federal Regulations, Environmental Protection Regulations for 31 Domestic Licensing and Related Regulatory Functions, Part 51, Chapter 1, Title 10, Energy.

32 Abood, K.A., T.L. Englert, S.G. Metzger, C.V. Beckers, Jr., T.J. Groninger, and S. Mallavaram.

33 2006. Current and Evolving Physical and Chemical Conditions in the Hudson River Estuary.

34 American Fisheries Society Symposium 51, pp. 39-61.

35 Achman, D.R., B.J. Brownawell, and L. Zhang. 1996. Exchange of Polychlorinated Biphenyls 36 Between Sediment and Water in the Hudson River Estuary. Estuaries 19:4, pp. 950-965.

37 Adams, S.M. 2003. Establishing Causality Between Environmental Stressors and Effects on 38 Aquatic Ecosystems. Human and Ecological Risk Assessment, Vol. 9, No.1, pp. 17-35.

39 Atlantic States Marine Fisheries Commission (ASMFC). 2006. Species profile: Atlantic striped 40 bass, the challenges of managing a restored stock. Accessed at:

NUREG-1437, Supplement 38 H-62 December 2010

Appendix H 1 http://www.asmfc.org/speciesDocuments/stripedBass/speciesprofile.pdf. on December 10, 2 2007.

3 Atlantic Striped Bass Conservation Act of 1984. 16 USC 5151-5158, et seq.

4 Baird, D., and R.E. Ulanowicz. 1989. The Seasonal Dynamics of the Chesapeake Bay 5 Ecosystem. Ecological Monographs 59(4), pp. 329-364.

6 Barnthouse, L.W., C.C. Coutant, and W. Van Winkle. 2002. Status and Trends of Hudson 7 River Fish Populations and Communities Since the 1970s: Evaluation of Evidence Concerning 8 Impacts of Cooling Water Withdrawals. January 2002. ADAMS Accession No.

9 ML083360704.

10 Barnthouse, L.W., D.G. Heimbuch, W. Van Winkle, and J. Young. 2008. Entrainment and 11 Impingement at Indian Point: A Biological Impact Assessment. January 2008. ADAMS 12 Accession No. ML080390059.

13 Brosnan, T.M. and M.L. OShea. 1996. Long-term Improvements in Water Quality Due to 14 Sewage Abatement in the Lower Hudson River. Estuaries 19:4, pp. 890-900.

15 Central Hudson Gas and Electric Corporation (CHGEC). 1999. Draft Environmental Impact 16 Statement for State Pollutant Discharge Elimination System Permits for Bowline Point, Indian 17 Point 2 and 3, and Roseton Steam Electric Generating Stations. Consolidated Edison Company 18 New York, Inc. New York Power Authority and Southern Energy New York. December 1999.

19 ADAMS Accession No. ML083400128.

20 Clean Water Act of 1977 (CWA). 33 USC 1326 et seq. (common name of the Federal Water 21 Pollution Control Act of 1977).

22 Cochran, W.G. 1997. Sampling Techniques, John Wiley and Sons, New York.

23 Consolidated Edison Company of New York (Con Edison). 1976. Indian Point Impingement 24 Study Report for the Period 1 January 1975-31 December 1975. Prepared by Texas 25 Instruments, Inc. ADAMS Accession No. ML083360750.

26 Consolidated Edison Company of New York (Con Edison). 1977. Hudson River Ecological 27 Study in the Area of Indian Point 1976 Annual Report. Prepared by Texas Instruments, Inc.

28 ADAMS Accession No. ML08309161.

29 Consolidated Edison Company of New York (Con Edison). 1979. Hudson River Ecological 30 Study in the Area of Indian Point 1977 Annual Report. Prepared by Texas Instruments, Inc.

31 ADAMS Accession No. ML083091068.

32 Consolidated Edison Company of New York (Con Edison). 1980. Hudson River Ecological 33 Study in the Area of Indian Point 1979 Annual Report. Prepared by Texas Instruments, Inc.

34 ADAMS Accession No. ML083360740.

35 Consolidated Edison Company of New York (Con Edison). 1984a. Hudson River Ecological 36 Study in the Area of Indian Point 1981 Annual Report. ADAMS Accession No. ML083091069.

37 Consolidated Edison Company of New York (Con Edison). 1984b. Precision and Accuracy of 38 Stratified Sampling to Estimate Fish Impingement at Indian Point Unit No. 2 and Unit No. 3.

39 Prepared by Normandeau Associates, Inc. ADAMS Accession No. ML083360792.

December 2010 H-63 NUREG-1437, Supplement 38

Appendix H 1 Consolidated Edison Company of New York (Con Edison) and New York Power Authority 2 (NYPA). 1986. Hudson River Ecological Study in the Area of Indian Point 1985 Annual 3 Report. Prepared by Normandeau Associates, Inc. ADAMS Accession No. ML083091074.

4 Consolidated Edison Company of New York (Con Edison) and New York Power Authority 5 (NYPA). 1987. Hudson River Ecological Study in the Area of Indian Point 1986 Annual 6 Report. Prepared by Normandeau Associates, Inc. ADAMS Accession No. ML083091087.

7 Consolidated Edison Company of New York (Con Edison) and New York Power Authority 8 (NYPA). 1988. Hudson River Ecological Study in the Area of Indian Point 1987 Annual 9 Report. Prepared by EA Science and Technology. ADAMS Accession No. ML083091084.

10 Consolidated Edison Company of New York (Con Edison) and New York Power Authority 11 (NYPA). 1991. Hudson River Ecological Study in the Area of Indian Point 1990 Annual 12 Report. Prepared by EA Science and Technology. ADAMS Accession No. ML083091086.

13 Daniels, R.A., K.E. Limburg, R.E. Schmidt, D.L. Strayer, and R.C. Chambers. 2005. Changes 14 in Fish Assemblages in the Tidal Hudson River, New York. American Fisheries Society 15 Symposium 45: pp. 471-503. Accessed at 16 http://www.ecostudies.org/reprints/daniels_et_al_2005.pdf on March 13, 2008 17 Ecological Analyses, Inc. (EA). 1981a. Indian Point Generating Station Entrainment Survival 18 and Related Studies. 1979 Annual Report. Prepared for Consolidated Edison Company of New 19 York, Inc., and Power Authority of the State of New York. Ecological Analysts, Inc.

20 January 1982. ADAMS Accession No. ML073330733.

21 Ecological Analyses, Inc. (EA). 1981b. 1981 Con Edison Automated Abundance Sampling 22 (AUTOSAM) and Laboratory Processing Standard Operating Procedures. Prepared for 23 Consolidated Edison Company of New York, Inc. Ecological Analysts, Inc. May 1981.

24 ADAMS Accession No. ML083100602.

25 Ecological Analyses, Inc. (EA). 1982. Indian Point Generating Station Entrainment Survival 26 and Related Studies. 1980 Annual Report. Prepared for Consolidated Edison Company of New 27 York, Inc., and Power Authority of the State of New York. Ecological Analysts, Inc. April 1981.

28 ADAMS Accession No. ML073330737.

29 Ecological Analyses, Inc. (EA). 1984. Indian Point Generating Station Entrainment Abundance 30 and Outage Evaluation, 1983 Annual Report. Prepared for Consolidated Edison Company of 31 New York, Inc., and Power Authority of the State of New York. EA Engineering, Science and 32 Technology, Inc. September 1984. ADAMS Accession No. ML083101084.

33 Ecological Analyses, Inc. (EA). 1985. Indian Point Generating Station Entrainment Abundance 34 and Outage Evaluation, 1983 Annual Report. Prepared for Consolidated Edison Company of 35 New York, Inc., and Power Authority of the State of New York. EA Engineering, Science and 36 Technology. July 1985. ADAMS Accession No. ML083101091.

37 Ecological Analyses, Inc. (EA). 1989. Indian Point Generating Station 1988 Entrainment 38 Survival Study. Prepared for Consolidated Edison Company of New York, Inc., and Power 39 Authority of the State of New York. EA Engineering, Science and Technology, Northeast 40 Regional Operations, Report No. 10648.03. August 1989. ADAMS Accession no.

41 ML083101103.

NUREG-1437, Supplement 38 H-64 December 2010

Appendix H 1 Entergy Nuclear Operations Inc. (Entergy). 2003. Indian Point Nuclear Power Plant, Units No.

2 1, 2, and 3Annual Radiological Environmental Operating Report [for 2002]. Docket Numbers 3 50-03, 50-247, and 50-286, Buchanan, New York. Agencywide Documents Access and 4 Management System (ADAMS) Accession No. ML031220085.

5 Entergy Nuclear Operations Inc. (Entergy). 2004. Indian Point Nuclear Power Plants, Units 1, 6 2, and 3Indian Points Annual Radiological Environmental Operating Report for 2003. Docket 7 Numbers50-003, 50-247, and 50-286, Buchanan, New York. Adams Accession 8 No. ML041340492.

9 Entergy Nuclear Operations Inc. (Entergy). 2005. Indian Point Units 1, 2, and 32004 Annual 10 Radiological Environmental Operating Report. Docket Numbers 50-3, 50-247, and 50-286, 11 Buchanan, New York. ADAMS Accession No. ML051220210.

12 Entergy Nuclear Operations Inc. (Entergy). 2006. Indian Point Nuclear Power Plants, Units 1, 2 13 and 3Annual Radiological Environmental Operating Report for 2005. Docket Numbers 50-3, 14 50-247, and 50-286, Buchanan, New York. ADAMS Accession No. ML061290085.

15 Entergy Nuclear Operations, Inc. (Entergy). 2007. Applicants Environmental Report, 16 Operating License Renewal Stage. (Appendix E of Indian Point Units 2 and 3, License 17 Renewal Application.) April 23, 2007. ADAMS Accession No. ML071210530.

18 Entergy Nuclear Operations, Inc. (Entergy). 2008. Letter from F. Dacimo, Vice President, 19 Entergy Nuclear Operations, to U.S. Nuclear Regulatory Commission Document Control Desk.

20

Subject:

Reply to Document Request for Additional Information Regarding Site Audit Review of 21 License Renewal Application for Indian Point Nuclear Generating Unit Nos. 2 and 3. April 23, 22 2008. ADAMS Accession No. ML081230243.

23 Entergy Nuclear Operations, Inc. (Entergy). 2009. Letter from F. Dacimo, Vice President, 24 Entergy Nuclear Operations, to U.S. Nuclear Regulatory Commission Document Control Desk.

25

Subject:

Request for Additional Information Related to License Renewal, Indian Point Nuclear 26 Application Environmental Report - Impingement Data, Indian Point Nuclear Generating Unit 27 Nos. 2 & 3 Docket Nos. 50-247 and 50-286, License Nos. DPR-26 and DPR-64. November 24, 28 2009. ADAMS Accession No. ML093420528.Environmental Protection Agency (EPA). 1992.

29 Framework for Ecological Risk Assessment. EPA/630/R-92-001. Risk Assessment forum, 30 Washington, D.C. 41 pp. Accessed at http://rais.ornl.gov/homepage/FRMWRK_ERA.PDF 31 Environmental Protection Agency (EPA). 2004. Total Maximum Daily Loads, Listed Water 32 Information, Cycle: 2004. Hudson River, Lower Hudson River. Accessed at:

33 http://oaspub.epa.gov/tmdl/enviro.control?p_list_id=NY-1301-0002andp_cycle=2004 on 34 February 23, 2008.

35 Environmental Protection Agency (EPA). 2008. Hudson River PCB Superfund Site, Dredge 36 Area 2 Delineation Fact Sheet, 2008. Accessed at:

37 http://www.epa.gov/hudson/factsheet_2nd_phaselow.pdf on February 4, 2008.

38 Fish and Wildlife Service (FWS). 2007. Letter from R. A. Niver, Endangered Species Biologist, 39 to Rani Franovich, Branch Chief, Projects Branch 2, Division of License Renewal, Office of 40 Nuclear Reactor Regulation, NRC, Washington, DC. Response to letter from NRC requesting 41 information on federally listed, proposed, and candidate species and critical habitat in the 42 vicinity of Indian Point Nuclear Generating Station Unit Nos. 2 and 3. August 29.

December 2010 H-65 NUREG-1437, Supplement 38

Appendix H 1 Fletcher, R.I. 1990. Flow dynamics and fish recovery experiments: Water intake systems.

2 Transactions of the American Fisheries Society, 119:393-415.

3 Frank, K.T., B. Petrie, and N.L. Shackell. 2007. The Ups and Downs of Trophic Control in 4 Continental Shelf Ecosystems. Trends in Ecology and Evolution 22:5, pp. 236-242.

5 Greenwood, M.F.D. 2008. Trawls and Cooling-water Intakes as Estuarine Fish Sampling 6 Tools: Comparisons of Catch Composition, Trends in Relative Abundance, and Length 7 Selectivity, Estuarine, Coastal and Shelf Science 76:121-130.

8 Haas-Castro, R. 2006. Status of Fishery Resources off the Northeastern U.S.: River Herring.

9 Northeast Fisheries Science Center Resource Evaluation and Assessment Division, National 10 Oceanic and Atmospheric Administration. Accessed at:

11 http://www.nefsc.noaa.gov/sos/spsyn/af/herring/archives/38_RiverHerring_2006.pdf on 12 December 17, 2007. ADAMS No. ML083390029.

13 Marcy, B.C., D.E. Fletcher, F.D. Martin, M.H. Paller, and M.J.M. Reichert. 2005. Spottail 14 Shiner. In: Fishes of the Middle Savannah River Basin. Athens, GA: University of Georgia 15 Press, pp. 153-156.

16 Maryland Department of Natural Resources, Fisheries Service, Chesapeake Finfish Program 17 (MDNR). February 2005. 2004 Stock Assessment of Selected Resident and Migratory 18 Recreational Finfish Species within Marylands Chesapeake Bay. Accessed at 19 http://dnr.maryland.gov/fisheries/management/FMP/FMPWhitePerch04.pdf on February 4, 20 2010.

21 Mayhew, D.A., L.D. Jensen, D.F. Hanson, and P.H. Muessig, 2000. A Comparative Review of 22 Entrainment Survival Studies at Power Plants in Estuarine Environments, Environmental 23 Science and Policy 3, pp. 295-301.

24 Menzie, C., M. H. Henning, J. Cura, K. Finkelstein, J. Gentile, J. Maughan, D. Mitchell, S.

25 Petron, B. Potocki, S. Svirsky, and P. Tyler. 1996. Report of the Massachusetts Weight-of-26 Evidence Workgroup: A Weight-of-Evidence Approach for Evaluating Ecological Risks.

27 Human and Ecological Risk Assessment 2:277-304.

28 Newbold, Steven C. and Rich Iovanna. 2007. Ecological effects of density-independent 29 mortality: application to cooling-water withdrawals. Ecological Applications, 17:390-406.

30 New York Power Authority (NYPA). 1986. Size selectivity and relative catch efficiency of a 3-31 m beam trawl and a 1-m2 epibenthic sled for sampling young of the year striped bass and other 32 fishes in the Hudson River estuary. Prepared by Normandeau Associates, Inc. January 1986.

33 (HR Library #7180). ADAMS Accession No. ML083360641.

34 New York State Department of Environmental Conservation (NYSDEC). 2003a. Final 35 Environmental Impact Statement Concerning the Applications to Renew New York State 36 Pollutant Discharge Elimination System (SPDES) Permits for the Roseton 1and2 Bowline 1and2 37 and IP2 and IP3 2and3 Steam Electric Generating Stations, Orange, Rockland and Westchester 38 Counties. Hudson River Power Plants FEIS. June 25, 2003. ADAMS Accession No.

39 ML083360752.

40 New York State Department of Environmental Conservation (NYSDEC). 2003b. Fact Sheet.

41 New York State Pollutant Discharge Elimination System (SPDES) Draft Permit Renewal with 42 Modification, IP2 and IP3 Electric Generating Station, Buchanan, NY November 2003.

NUREG-1437, Supplement 38 H-66 December 2010

Appendix H 1 Accessed at http://www.dec.ny.gov/docs/permits_ej_operations_pdf/IndianPointFS.pdf on 2 July 12, 2007. ADAMS Accession No. ML083360743.

3 New York State Department of Environmental Conservation (NYSDEC). 2007. State of New 4 York Petition submitted to the U.S. Nuclear Regulatory Commission, November 30, 2007, on 5 the Application of Entergy Nuclear Operations, Inc., for the 20-year Relicensing of Indian Point 6 Nuclear Power Plants 1 and 2, Buchanan, New York. Summary of Some of the Key 7 Contentions. Accessed at http://www.dec.ny.gov/permits/40237.html on March 18, 2008.

8 ADAMS Accession No. ML083360757.

9 Normandeu Associates (Normandeu). 1987a. IP2 and IP3 Generating Station Entrainment 10 Abundance Program, 1985 Annual Report. Prepared for Consolidated Edison Company of New 11 York, Inc., and New York Power Authority. Prepared by Normandeu Associates, Inc.

12 Report R-332-1062. April 1987. ADAMS Accession No. ML0803091074.

13 Normandeu Associates (Normandeu). 1987b. IP2 and IP3 Generating Station Entrainment 14 Abundance Program, 1986 Annual Report. Prepared for Consolidated Edison Company of New 15 York, Inc., and New York Power Authority. Prepared by Normandeu Associates, Inc.

16 Report R-220. June 1987. ADAMS Accession No. ML083091087.

17 Normandeu Associates (Normandeu). 1988. IP2 and IP3 Generating Station Entrainment 18 Abundance Program, 1987 Annual Report. Prepared for Consolidated Edison Company of New 19 York, Inc., and New York Power Authority. Prepared by Normandeu Associates, Inc.

20 Report R-1110. May 1988. ADAMS Accession No. ML083360798.

21 Nuclear Regulatory Commission (NRC). 1996. Generic Environmental Impact Statement for 22 License Renewal of Nuclear Power Plants. NUREG-1437, Volumes 1 and 2, Washington, DC.

23 Nuclear Regulatory Commission (NRC). 1999. Generic Environmental Impact Statement for 24 License Renewal of Nuclear Plants Main Report, Section 6.3Transportation, Table 9.1, 25 Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants.

26 NUREG-1437, Volume 1, Addendum 1, Washington, DC.

27 Rose, Kenneth A. 2000. Why are quantitative relationships between environmental quality and 28 fish populations so elusive? Ecological Applications, 10:367-385.

29 Secor, D.H. and E D. Houde. 1995. Temperature Effects on the Timing of Striped Bass Egg 30 Production, Larval Viability, and Recruitment Potential in the Patuxent River (Chesapeake 31 Bay). Estuaries 18, pp. 527-533.

32 Shepherd G. 2006a. Atlantic Striped Bass. Accessed at 33 http://www.nefsc.noaa.gov/sos/spsyn/af/sbass/archives/40_StripedBass_2006.pdf on 34 December 10, 2007.

35 Shepherd G. 2006b. Bluefish. Accessed at 36 http://www.nefsc.noaa.gov/sos/spsyn/op/bluefish/archives/25_Bluefish_2006.pdf.

37 Smith, C.L. 1985. Spottail Shiner. The Inland Fishes of New York State, pp. 194-195. New 38 York State Department of Environmental Conservation, Albany, NY.

39 Snedecor G.W. and W.G. Cochran. 1980. Statistical Methods. The Iowa State University 40 Press, Ames, Iowa.

December 2010 H-67 NUREG-1437, Supplement 38

Appendix H 1 Steinberg, N., D.J. Suszkowski, L. Clark, and J. Way. 2004. Health of the Harbor: The First 2 Comprehensive Look at the State of the NY, NY Harbor Estuary. A Report to the New 3 York/New Jersey Harbor Estuary Program. Hudson River Foundation, New York.

4 Strayer, D.L., K.A. Hattala, and A.W. Kahnle. 2004. Effects of an Invasive Bivalve (Dreissena 5 polymorpha) on Fish in the Hudson River Estuary. Canadian Journal of Fisheries and Aquatic 6 Sciences 61, pp. 924-941.

7 Ulanowicz, R.E. 1995. Trophic Flow Networks as Indicators of Ecosystem Stress. In: G.A.

8 Polis and K.O. Winemiller (eds). Food Webs: Integration of Patterns and Dynamics, Chapman 9 and Hall, NY, pp. 358-368.

10 U.S. EPA. 1998. Guidelines for Ecological Risk Assessment. U.S. Environmental Protection 11 Agency, Risk Assessment Forum, Washington, DC, EPA/630/R095/002F. Accessed at:

12 http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=12460 13 Wolfe, D.A., E.R. Long, and G.B. Thursby. 1996. Sediment Toxicity in the Hudson-Raritan 14 Estuary: Distribution and Correlations with Chemical Contamination. Estuaries 19:4, pp. 901-15 912.

NUREG-1437, Supplement 38 H-68 December 2010

Appendix I Statistical Analyses Conducted for Chapter 4 Aquatic Resources and Appendix H

1 Appendix I 2 Statistical Analyses Conducted for Chapter 4 Aquatic Resources and 3 Appendix H 4 Supporting analyses and data tables are presented by section as referenced in the Aquatic 5 Resources sections of Appendix H. Major section headings are maintained to allow mapping 6 between appendices. This appendix includes supporting information for the U.S. Nuclear 7 Regulatory Commission (NRC) staff assessment of impingement impacts (Appendix H, 8 Section 1.3), the assessment of population trends (Appendix H, Section 3.1), the analysis of 9 strength of connection (Appendix H, Section 3.2), and the cumulative impacts on aquatic 10 resources (Appendix H, Section 4).

11 I.1 Impingement of Fish and Shellfish 12 I.1.1. NRC Staff Assessment of Impingement Impacts 13 NRC staff conducted simple linear regression over years on the number of days of operation 14 and the combined volume of water discharged for Indian Point Nuclear Generating Station Unit 15 Nos. 2 and 3 (IP2 and IP3) between 1975 and 1990 (Table I-1). Days of operation from 1975 to 16 1981 were obtained from impingement data provided by Entergy Nuclear Operations, Inc. (the 17 applicant) (Entergy 2007b). Days of operation for the remaining years and the combined 18 volume discharged were compiled from the annual reports for the Hudson River Ecological 19 Study in the area of IP2 and IP3 (Con Edison 1980; Con Edison 1984, 1986-1991). The 20 number of days of operation at IP2 and IP3 had a general increase of eight days per year for 21 IP2 and five days per year for IP3 (linear regression, p = 0.004 and p = 0.286 for IP2 and IP3, 22 respectively). The total volume circulated at IP2 and IP3 combined also had a general increase 23 of 26.2 x 106 cubic meters (m3; linear regression, p = 0.164).

24 December 2010 I-1 NUREG-1437, Supplement 38

Appendix I 1 Table I-1 Number of Days of Operation at IP2 and IP3 and Combined Discharge Combined Volume Year Days of Operation (millions m3)

IP2 IP3 1975 307 1119 1976 176 239 1329 1977 265 259 2159 1978 234 270 2030 1979 246 227 1935 1980 263 261 1822 1981 276 297 1617 1982 304 135 1273 1983 340 48 1286 1984 238 306 1710 1985 365 266 1977 1986 285 357 1892 1987 346 265 1815 1988 357 352 2322 1989 302 301 1748 1990 365 272 1902 2 Source: Days of Operation: Entergy 2007b; Con Edison 1984, 1986-1991 3 Volume Discharged: Con Edison 1980, 1991.

4 I.2 Combined Effects of Impingement and Entrainment 5 I.2.1. Assessment of Population Trends 6 Studies Used To Evaluate Population Trends 7 The Hudson River utilities conducted the Fall Juvenile Shoals Survey (FSS) from 1974 to 2005 8 and targeted juveniles, yearlings, and older fish. Between 1974 and 1984, a 1-square meter 9 (m2) Tucker trawl with a 3-millimeter (mm) mesh was used to sample the channel and a 1-m2 10 epibenthic sled with a 3-mm mesh was used to sample the bottom and shoal strata. From 1985 11 to 2005, a 3-meter (m) beam trawl with a 38-mm mesh on all but the cod-end replaced the 12 epibenthic sled. Size selectivity and relative catch efficiency between gear types was tested 13 during nocturnal samplings between August and September 1984. Bay anchovy, American 14 shad, and weakfish were sampled with less efficiency with the beam trawl (Table I-2) (NYPA 15 1986). Further, the number and volume of samples in the bottom and shoal strata were 16 generally greater than 2.5 times those in the channel (Table I-3).

17 The Beach Seine Survey (BSS) was conducted from 1974 to 2005 and targeted young of the 18 year (YOY) and older fish in the shore-zone (extending from the shore to a depth of 10 feet [ft]).

19 Samples were collected from April to December but generally every other week from mid-June 20 through early October (Table I-4). For all years, a 100-ft bag beach seine was used to collect 21 100 samples during each sampling period from beaches selected according to a stratified NUREG-1437, Supplement 38 I-2 December 2010

Appendix I 1 random design. Even though the catch-per-unit-effort (CPUE) for representative important 2 species (RIS) differed in magnitude between the BSS and FSS (Table I-5), standardizing the 3 data (observed CPUE minus the mean CPUE and divided by the standard deviation across 4 years) allowed a comparison of the shape of the data over time. Thus, NRC staff conducted a 5 visual and statistical comparison of the standardized BSS and FSS data to determine if a shift in 6 gear types was affecting the observed FSS trend. The standardized FSS data were considered 7 consistently less than the standardized BSS data after 1985 if greater than 90 percent of the 8 standardized FSS observations were less than the BSS and the median absolute difference 9 between the standardized FSS and BSS was greater than 0.5 based on a sign test ( = 0.1). If 10 these two metrics were met, a gear effect was assumed, and the pre- and post-1985 data were 11 evaluated separately. If less than 25 percent of the standardized FSS observations were less 12 than the BSS and either (1) the median absolute difference between the standardized FSS and 13 BSS was greater than 0.5 based on a sign test ( = 0.1) or (2) the absolute difference of the 14 percentage of FSS observations less than BSS observations before and after the gear change 15 was greater than 0.3, then the magnitude of FSS data was considered greater than the 16 magnitude of BSS data. If 25 percent to 90 percent of the standardized FSS observations were 17 less than the BSS, then the FSS and BSS data were considered not biologically different.

18 Table I-2 Catch by Gear or Gear Efficiency (catch per 1000 m2) 19 from August to September 1984 Young of the Year Yearling and Older 1-m2 Epibenthic 3-m Beam Trawl Sled 3-m Beam Trawl 1-m2 Epibenthic (n = 257) (n = 322) (n = 257) Sled (n = 322)

Mean Standard Mean Standard Mean Standard Mean Standard Species Density Error Density Error Density Error Density Error Bay Anchovy 29.0 3.0 1261 61.9 0.6 0.1 11.2 1.2 American Shad 0.4 0.1 4.4 3.0 0.0 0.0 0.0 0.0 Bluefish 0.1 <0.1 0.3 0.1 0.0 0.0 0.0 0.0 Hogchoker 0.1 <0.1 0.1 <0.1 5.4 0.4 1.5 0.2 Striped Bass 13.3 0.8 3.4 0.4 0.2 <0.1 0.1 <0.1 White Catfish 0.0 0.0 0.0 0.0 1.6 0.2 1.0 0.1 White Perch 1.3 0.2 0.1 <0.1 22.1 1.6 6.4 1.3 Weakfish 0.7 0.1 1.9 0.3 0.0 0.0 0.0 0.0 20 Source: NYPA 1986.

21 December 2010 I-3 NUREG-1437, Supplement 38

Appendix I 1 Table I-3 Changes to the Design and Gear Used During the Fall Juvenile Survey Number Samples per Gear of Epibenthic Tucker Beam Sample Collection 3

Year Volume (m ) Samples Sled Trawl Trawl Dates 1974 728083 1690 100/wk Weekly, Aug-Dec 1975 317749 901 100/wk Biweekly, Aug-Dec 1976 365903 881 100/wk Biweekly, Aug-Dec 1977 368134 826 100/wk Biweekly, Aug-Dec 1978 352420 900 100/wk Biweekly, Aug-Dec 1979 1,006,411 2387 150/wk 50/wk Biweekly, July-Dec 1980 771291 2103 150/wk 50/wk Biweekly, July-Dec 1981 479591 1199 150/wk 50/wk Biweekly, Aug-Oct 1982 400969 1000 150/wk 50/wk Biweekly, Aug-Oct 1983 477057 1199 150/wk 50/wk Biweekly, Aug-Oct 1984 601459 1601 150/wk 50/wk Biweekly, July-Oct 1985 1886754 1802 ~500 ~1,500 Biweekly, July-Nov 1986 2,298,395 2098 549 1,549 Biweekly, July-Dec 1987 2035472 1891 495 1,396 Biweekly, July-Nov 1988 1826692 1680 440 1,240 Biweekly, July-Oct 1989 1590118 1679 439 1,240 Biweekly, July-Oct 1990 1252994 1680 439 1,241 Biweekly, July-Oct 1991 1707319 1678 440 1,238 Biweekly, July-Oct 1992 1865451 1680 440 1,240 Biweekly, July-Oct 1993 2010222 1680 440 1,240 Biweekly, July-Oct 1994 2018494 1681 440 1,241 Biweekly, July-Oct 1995 1782199 1680 440 1,240 Biweekly, July-Oct 1996 1824802 1669 484 1,185 Biweekly, July-Oct 1997 1995519 2015 826 1,189 Biweekly, July-Nov 1998 2214707 2130 825 1,305 Biweekly, July-Dec 1999 2160009 2085 823 1,262 Biweekly, July-Dec 2000 2174896 2113 816 1,297 Biweekly, July-Nov 2001 2097877 2084 818 1,266 Biweekly, July-Oct 2002 2105272 2128 821 1,307 Biweekly, July-Dec 2003 1891135 2131 825 1,306 Biweekly, July-Dec 2004 2106874 2128 823 1,305 Biweekly, July-Dec 2005 2063654 2128 824 1,304 Biweekly, July-Dec 2 Note: Compiled from the annual Year Class Reports for the Hudson River Estuary Monitoring Program; ASA 1999, 3 2001a, 2001b, 2003, 2004a, 2004b, 2005-2007; Battelle 1983; ConEd undated a, undated b, 1996; EA 1990, 1995, 4 1991; LMS 1989, 1991, 1996; MMES 1983; Versar 1987; TI 1977-1981; NAI 1985a, 1985b, 2007.

5 NUREG-1437, Supplement 38 I-4 December 2010

Appendix I 1 There were four basic combinations of sampling intensities, duration, and gear types used 2 during the FSS (Table I-3). Likewise, there were roughly three levels of sampling intensity used 3 during the BSS (Table I-4). Thus, for data provided on a weekly basis, only weeks 27 to 43 4 were used in the analysis for the FSS and weeks 22 to 43 for the BSS survey, so that most 5 years contained observations from the months of July through October and June through 6 October for each survey, respectively.

7 Table I-4 Number of Weeks Sampled Each Month During the BSS Year April May June July August September October November December 1974 4 4 4 5 4 5 4 4 3 1975 5 4 4 5 4 5 4 4 3 1976 5 4 4 5 4 5 4 4 2 1977 4 4 4 5 4 5 4 4 3 1978 4 4 4 5 4 5 4 4 4 1979 5 4 4 5 4 5 4 4 2 1980 5 4 4 5 4 2 2 2 1 1981 0 0 0 0 2 3 2 0 0 1982 0 0 0 0 1 3 1 0 0 1983 0 0 0 0 2 3 1 0 0 1984 0 0 0 1 2 2 2 1 0 1985 0 0 0 2 2 2 2 2 0 1986 0 0 0 2 2 2 2 2 0 1987 0 0 1 2 2 3 2 1 0 1988 0 0 1 3 2 2 2 1 0 1989 0 0 1 3 2 2 2 1 0 1990 0 0 1 3 2 2 2 0 0 1991 0 0 1 2 2 3 2 0 0 1992 0 0 1 2 2 3 2 0 0 1993 0 0 0 3 2 2 2 1 0 1994 0 0 0 3 2 2 2 1 0 1995 0 0 1 2 2 3 2 0 0 1996 0 0 1 3 2 2 2 0 0 1997 0 0 1 3 2 2 2 0 0 1998 0 0 1 3 2 2 2 0 0 1999 0 0 1 3 2 2 2 0 0 2000 0 0 1 3 2 2 2 0 0 2001 0 0 1 3 2 2 2 0 0 2002 0 0 1 3 2 2 2 0 0 2003 0 0 1 3 2 2 2 0 0 2004 0 0 1 3 2 2 2 0 0 2005 0 0 1 3 2 2 2 0 0 8 Source: NRC Request for Sampling Effort and Abundance Data from Three Hudson River Sampling Programs for 16 9 Selected Fish Species from 1974 through 2005, Normandeau Associates Inc., February 25, 2008.

December 2010 I-5 NUREG-1437, Supplement 38

Appendix I 1 Metrics Used To Evaluate Population Trends 2 Abundance Index 3 The abundance index for YOY for each species was based on the catch from a selected 4 sampling program and was used by the applicant and its contractors to estimate riverwide mean 5 RIS abundances. The selection process considered the expected location of each species in 6 the river, based on life-history characteristics and the observed catch rates from previous 7 sampling. The abundance index was constructed to account for the stratified random sampling 8 design used by each of the surveys. For the Long River Survey (LRS) and the FSS, sampling 9 within a river segment was further stratified by river depth and sampled with separate gear 10 types. For blueback herring, alewife, bay anchovy, hogchoker, weakfish, and rainbow smelt, the 11 YOY abundance index was based on the catch from a single gear type (Table I-5).

12 The construction of the LRS (LA) and the FSS abundance index (FA) were similar and provided 13 an unbiased estimate of the total and mean riverwide population abundance for selected 14 species, respectively (Cochran 1997). For the FSS and each gear type, FA was constructed as 15 a weighted mean of the average species density with weight given by the volume of each 16 stratum for a given river segment. For the FSS, strata sampled were the channel, bottom, and 17 shoal for a given river segment. Poughkeepsie and West Point river segments had the greatest 18 channel volume, Poughkeepsie and Tappan Zee had the greatest bottom volume, and Tappan 19 Zee had the greatest shoal volume (Table I-6). Because the river segment associated with IP2 20 and IP3 did not have large bottom or shoal volumes, the abundance index was not sensitive to 21 changes in population trends within the vicinity of IP2 and IP3.

22 Table I-5 Sampling Program Used To Calculate the Abundance Index for YOY and 23 Yearling Fish and the Median Catch-per-Unit-Effort Over Time Riverwide FSS Median Riverwide BSS YOY Catch-per- Median YOY Catch-Species Sampling Program Unit-Effort per-Unit-Effort Alewife FSS-Channel 4.35E-04 1.05 Bay Anchovy FSS-Channel 2.61E-02 6.70 American Shad BSS 8.12E-04 9.17 Bluefish BSS 3.18E-05 3.36E-01 Hogchoker FSS-Bottom 1.03E-02 2.30E-01 Blueback Herring FSS-Channel 1.12E-02 2.86E+01 Rainbow Smelt FSS-Channel N/Aa < 0.0001 Spottail Shiner FSS-Channel 1.10E-04 7.25 Stripped Bass BSS 2.47E-03 6.47 Atlantic Tomcod LRS 2.69E-03 6.70E-02 White Catfish BSS N/A 2.50E-02 White Perch BSS 5.89E-03 10.4 Weakfish FSS-Channel N/A 5.00E-03 a

24 N/A = not applicable; YOY not present in samples.

25 Source: CHGE 1999.

26 NUREG-1437, Supplement 38 I-6 December 2010

Appendix I 1 Table I-6 Volume of Sampling Strata by River Segment River Volume (m3) Area (m2)

Region Segment Channel Bottom Shoal Region Shore Zone Battery 0 141,809,822 48,455,129 18,747,833 209,012,784 N/A Yonkers 1 143,452,543 59,312,978 26,654,767 229,420,288 3,389,000 Tappan Zee 2 138,000,768 62,125,705 121,684,992 321,811,465 20,446,000 Croton-Haverstraw 3 61,309,016 32,517,633 53,910,105 147,736,754 12,101,000 Indian Point 4 162,269,471 33,418,632 12,648,163 208,336,266 4,147,000 West Point 5 178,830,022 25,977,862 2,647,885 207,455,769 1,186,000 Cornwall 6 94,882,267 36,768,629 8,140,123 139,791,019 4,793,000 Poughkeepsie 7 228,975,052 63,168,132 5,990,260 298,133,444 3,193,000 Hyde Park 8 131,165,041 32,012,000 2,307,625 165,484,666 558,000 Kingston 9 93,657,021 35,479,990 12,332,868 141,469,879 3,874,000 Saugerties 10 113,143,296 42,845,077 20,307,338 176,295,711 7,900,000 Catskill 11 83,924,081 42,281,206 34,526,456 160,731,743 8,854,000 Albany 12 32,025,080 13,517,183 25,606,842 71,149,105 6,114,000 2 N/A - not applicable. Data from Entergy 2007b.

3 Analysis of Population Impacts 4 As discussed in Section H.1.3, the analysis was based on YOY fish to assess the population 5 trends. For the river-segment analysis, the median and the 75th percentile of the densities of 6 YOY caught within a given year in the vicinity of IP2 and IP3 (River Segment 4) were used to 7 bound population trends for a visual representation. The median and 75th percentile are less 8 sensitive to extreme values than the mean. Fish population sizes and the chance of catching 9 fish were highly variable, and a few large catches can influence the mean and potentially distort 10 a trend analysis. For example, the mean density for alewives caught during the FSS in the 11 vicinity of IP2 and IP3 tended to be equal to or greater than the 75th percentile of the density for 12 most years because of the relatively fewer large observations (Figure I-1). Further, seasonal 13 and interannual differences in the salt front position may influence the pattern of trends in total 14 or mean abundance between river segments. Evaluating the 75th percentile of the weekly data 15 removed the influence from any given week associated with potentially extreme environmental 16 characteristics.

17 River-segment data collected from 1979 to 2005 (n = 27 for each RIS) was standardized by 18 subtracting the first 5-year mean and dividing by the standard deviation based on all years.

19 Because of the large variability between years (coefficients of variation [CVs] ranging from 67 to 20 247 percent), a 3-year moving average was used to smooth the river-segment data before the 21 trend analysis. Two competing models, simple linear regression and segmented regression 22 with a single join point, were statistically fit to the smoothed and standardized 75th percentile of 23 the annual observed densities for each taxon. The model with the smallest mean square error 24 (MSE) was chosen as the better fitting model and used to determine the level of potential injury.

25 Extreme outliers (values greater than 2 standard deviations from the mean) were removed from 26 the analysis if the segmented regression was unable to converge; results with and without 27 outliers were recorded. All data (1979-2005) from the FSS were compared to the BSS to 28 determine if changes in the gear type affected the observed trend. When the standardized FSS 29 data were consistently less than the standardized BSS data after 1985 (based on the December 2010 I-7 NUREG-1437, Supplement 38

Appendix I 1 percentage of FSS observations less than the BSS and the median absolute difference between 2 the FSS and BSS standardized observations), the pre- and post-1985 data were evaluated 3 separately.

4 5

6 Note: The value 0.001 was added to all numbers so that the log scale could be used for plotting.

7 Figure I-1 Relationship among the mean, the median, and the 75th percentile of the fish 8 density for alewives caught during the FSS in River Segment 4 9 For the riverwide data collected from 1979 to 2005 (n = 27 for each RIS), the FSS CPUE, the 10 BSS CPUE, and the abundance index for the YOY were used to assess the population trends.

11 Riverwide data consisted of a single number per year for a given taxon and life stage. CVs 12 ranged from 60 percent to 154 percent for the FSS, 41 percent to 302 percent for the BSS, and 13 49 percent to 319 percent for the abundance index. Simple linear regression and segmented 14 regression with a single join point were fit to the standardized data (using the first 5-year mean 15 and the standard deviation based on all years). Extreme outliers were removed from the 16 analysis if the segmented regression was unable to converge; results with and without outliers 17 were recorded. The model with the smallest MSE was chosen as the best-fit model and used to 18 determine the level of potential injury. All data (1979-2005) from the FSS were compared to the 19 BSS to determine if changes in the gear type affected the observed trend. When the NUREG-1437, Supplement 38 I-8 December 2010

Appendix I 1 standardized FSS data were consistently less than the standardized BSS data after 1985, NRC 2 staff evaluated the pre- and post-1985 data separately. Consistency of a gear effect was 3 defined as (1) greater than 90 percent of the standardized FSS observations less than the 4 associated BSS observations, and (2) the rejection of the one-sample, one-sided, sign test of 5 the null hypothesis, H0: the median of the absolute difference (FSS-BSS standardized density) 6 is less than or equal to 0.5 ( = 0.1).

7 The FSS density and CPUE for a given RIS can be highly correlated when nearly all of the fish 8 are caught from a single habitat (channel, shoal, or bottom) for the majority of sampling events.

9 For these RIS, the weight-of-evidence (WOE) analysis was conducted both with and without the 10 FSS CPUE results. Because of the slight variation in response between the two measures of 11 population trend, different result scores can occur. However, for all RIS, the final determination 12 of the level of impact associated with the IP2 and IP3 cooling systems was the same by either 13 method. Thus, the correlation between measures was ignored.

14 For each data set, the results of the linear and segmented regression were presented in a 15 series of three tables and a figure if a conclusion of potential large impact to any RIS population 16 was made. The first table contained the initial values used in the fitting of the segmented 17 regression which was conducted with Prism Version 4 (GraphPad Software, Inc. 2003). The 18 nonlinear fitting Levenberg-Marquardt (or Marquardt) method was used to estimate the 19 intercept, the join point, and the two slopes in the segmented regression model. The Marquardt 20 method uses the iterative method of steepest descent in the early iterations and then gradually 21 switches to the Gauss-Newton approach until the difference in the error sum of squares is less 22 than 1x10-7. The statistics displayed in the second table included the mean squared error 23 (MSE) for each model; the estimate of the linear slope and associated 95 percent confidence 24 interval; the p-value associated with the significance test of the null hypothesis that the slope (S) 25 associated with the simple linear model equals zero; the estimated 95 percent confidence 26 interval (CI) of the two slopes from the segmented regression (Slope 1=S1 and Slope 2=S2);

27 and the estimated join point. For the segmented regression, slopes were defined as significant 28 if the CI did not include zero.

29 30 The best-fit model (defined as the model with the smaller MSE) was then characterized in a 31 third table, based on the general trend depicted by the direction of the estimated slopes. If the 32 slope was significantly different from 0, the trend was represented by either the statement S > 0 33 for a positive slope or S < 0 for a negative slope. If the slope was not significant, the statement 34 depicting the lack of a trend was S = 0. A level of potential negative impact was then 35 determined, based on the decision rules presented in Section 4.1 of the Supplemental 36 Environmental Impact Statement (SEIS). If a large potential for a negative impact was 37 concluded for any RIS, a figure of the data and the best-fit model was presented.

38 IP2 and IP3 River Segment 4 39 As stated above, there were two different gear types used during the FSS to sample the bottom 40 and shoal habitats. From 1979 to 1984, an epibenthic sled was used, and from 1985 to 2005, a 41 beam trawl was used. Because there were not enough annual observations from the 1979 to 42 1984 time period to conduct a segmented regression, a simple linear regression was conducted 43 to assess the slope of the density of fish near IP2 and IP3. These data were standardized to 44 the average of the first 2 years and divided by the standard deviation of all six observations.

45 Only white perch had a significant negative slope (n = 6, p = 0.01; Figure I-2). Hogchoker and December 2010 I-9 NUREG-1437, Supplement 38

Appendix I 1 rainbow smelt appeared to have negative trends, but they were not significant (p= 0.33 and 0.15 2 respectively).

3 1.5 1

Standardized FSS Density 0.5 0

-0.5 White Perch

-1 Hogchoker Rainbow Smelt

-1.5

-2

-2.5 0 1 2 3 4 5 6 Years of Survey 4

5 Figure I-2 River Segment 4 population trends based on the first 6 years (1979-1984) of 6 FSS standardized density data for selected RIS 7 Data collected between 1985 and 2005 were temporally disconnected from the mid-1970s, 8 when operation began at IP2 and IP3. There was a potential that fish populations responded 9 earlier and stabilized to a lower abundance level. For this analysis, data were standardized with 10 the average of 1985 to 1989 and the standard deviation of all data between 1985 and 2005; the 11 data were not smoothed. This analysis was used only when the observed response from all 12 data was biologically different from the BSS population density trend and had a decline 13 potentially associated with the gear change.

14 15 A visual and statistical comparison (Table I-7) of the river-segment FSS standardized density 16 with the BSS standardized density based on the proportion of the FSS observations less than 17 the BSS following the gear change and the sign test of H0: the median absolute difference 0.5 18 suggested that the trends were not biologically different for American shad (proportion FSS <

19 BSS = 0.47; p = 0.99), Atlantic tomcod (proportion FSS < BSS = 0.26; p = 0.08), blueback 20 herring (proportion FSS < BSS = 0.95; p = 0.68), striped bass (proportion FSS < BSS = 0.32; p 21 = 0.50), and weakfish (proportion FSS < BSS = 0.58; p = 0.97; Figure I-3). Observations from 22 the two surveys overlap and cross over each other. The post-1985 FSS observations for alewife 23 (proportion FSS < BSS = 0.21; p = 0.32), bluefish (proportion FSS < BSS = 0.00; p = 0.01),

24 hogchoker (proportion FSS < BSS = 0.00; p < 0.01), and white perch (proportion FSS < BSS =

NUREG-1437, Supplement 38 I-10 December 2010

Appendix I 1 0.00; p < 0.01) were greater than the BSS observations and did not show a decline associated 2 with the gear change relative to the BSS (Figure I-4). Thus, for these eight RIS, all of the FSS 3 data (1979-2005) were used in the regression analysis. The FSS density data for bay anchovy, 4 however, did show a potential gear effect (proportion FSS < BSS = 1.00; p < 0.01; Figure I-5),

5 and a pre- and post-1985 analysis was conducted.

6 7 Table I-7 Evaluation of Gear Effect on FSS Population Trends in River Segment 4 Proportion FSS < BSS Absolute Medan Absolute Difference Significance Difference Taxa of Conclusion 1979-1984 1985-2005 in 1979-1984 1985-2005 Sign Test Proportions Alewife 0.60 0.21 0.39 0.41 0.65 0.324 FSS > BSS American Not Biol.

0.40 0.47 0.07 0.61 0.26 0.990 Shad Different Atlantic Not Biol.

0.20 0.26 0.06 0.31 0.71 0.084 Tomcod Different Separate Bay Anchovy 0.40 1.00 0.60 0.43 1.32 0.002 Analysis Blueback Not Biol.

0.60 0.95 0.35 0.06 0.48 0.676 Herring Different Bluefish 0.40 0.00 0.40 0.25 1.36 0.010 FSS > BSS Hogchoker 0.60 0.00 0.60 0.88 0.92 < 0.001 FSS > BSS Not Biol.

Striped Bass 0.60 0.32 0.28 0.46 0.52 0.500 Different Not Biol.

Weakfish 0.40 0.58 0.18 0.29 0.20 0.968 Different White Perch 0.40 0.00 0.40 0.20 1.24 < 0.001 FSS > BSS December 2010 I-11 NUREG-1437, Supplement 38

Appendix I FSS gear change FSS gear change 2 2 Standardized Density Standardized Density 1 1 0 0

-1 -1

-2 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Atlantic Tomcod R2-D-BSS American Shad-D-BSS Atlantic Tomcod-D-FSS American Shad-D-FSS FSS gear change FSS gear change 2 2 Standardized Density Standardized Density 1 1 0 0

-1 -1

-2 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Blueback Herring-D-BSS Striped Bass-D-BSS Blueback Herring-D-FSS Striped Bass-D-FSS 2 FSS gear change Standardized Density 1

0

-1

-2 0 10 20 30 Years of Survey W eakfish R1-6-D-BSS W eakfish-D-FSS 1 Note: All data were used in WOE analysis; R2 = River Segment 2, Yonkers; 1 - R6 = River Segments 1 - 6.

2 Figure I-3 River Segment 4 population trends based on the BSS and FSS standardized 3 density (D) not considered biologically different NUREG-1437, Supplement 38 I-12 December 2010

Appendix I 2 FSS gear change 2 FSS gear change Standardized Density Standardized Density 1

1 0

0

-1

-1

-2

-2 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Alewife-D-BSS Bluefish-D-BSS Alewife-D-FSS Bluefish-D-FSS 2 FSS gear change 2 FSS gear change Standardized Density Standardized Density 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Hogchoker-D-BSS White Perch-D-BSS Hogchoker-D-FSS White Perch-D-FSS 1 Note: All data were used in WOE analysis.

2 Figure I-4 River Segment 4 population trends based on the BSS and FSS standardized 3 density (D) for which the FSS density is greater December 2010 I-13 NUREG-1437, Supplement 38

Appendix I 2 FSS gear change Standardized Density 1

0

-1

-2

-3 0 10 20 30 Years of Survey Bay Anchovy-D-BSS Bay Anchovy-D-FSS 1 Note: All years were analyzed separately for WOE analysis; R2 = River Segment 2, Yonkers.

2 Figure I-5 River Segment 4 population trends based on the BSS and FSS standardized 3 density (D) for which the FSS may indicate a gear difference 4

NUREG-1437, Supplement 38 I-14 December 2010

Appendix I 1 The following tables are the intermediate analyses for the assessment of population trends 2 associated with fish density sampled from River Segment 4. Results of these river-segment 3 trend analyses are compiled in Table H-14 in Section H.1.3 of the SEIS Appendices. The data 4 used in this analysis, in order of appearance, were the standardized 75th percentile of the 5 weekly fish density for a given year collected from the FSS (Table I-8, Table I-9, Table I-10, 6 and Figure I-6), BSS (Table I-11, Table I-12, Table I-13, and Figure I-7), and LRS for Atlantic 7 tomcod only (Table I-14, Table I-15, Table I-16, and Figure 8).

8 Two FSS alewife density observations, not extreme outliers, were removed from the regression 9 analysis to allow the segmented regression to converge (Tables I-9 and I-10). These 10 observations corresponded to the peaks in two sporadic increases. Three FSS white catfish 11 density observations, also not extreme outliers, were removed from the regression analysis to 12 allow the segmented regression to converge. The results of both regression models with the 13 observations removed were considered more conservative and were used for the trend 14 analysis.

15 Table I-8. Initial Values for the Nonlinear Fit of the Segmented Regression Models 16 Used on FSS Population Trends of YOY Fish Density from River Segment 4 17 Taxa Intercept Slope 1 Join Point Slope 2 Alewife (2 values removed) -0.04 -0.20 1990 0.02 American Shad (All data) 0.20 -0.06 1997 -0.10 Atlantic Tomcod (All data) 0.40 -0.01 1990 -0.08 Bay Anchovy (1985-2005) -1.00 0.10 1990 -0.10 Blueback Herring (All data) 0.50 -0.08 1990 -0.02 Bluefish (All data) 0.30 -0.09 1996 -0.01 Hogchoker (All data) 0.03 0.05 1989 -0.10 Rainbow Smelt (1979-1997) 0.00 0.30 1991 -0.30 Striped Bass (All data) -0.08 0.07 1990 0.00 Weakfish (All data) 0.40 -0.08 1990 -0.02 White Catfish (3 values removed) -0.20 0.08 1986 0.10 White Perch (All data) 1.00 -0.07 1982 0.00 18 December 2010 I-15 NUREG-1437, Supplement 38

Appendix I 1 Table I-9. Competing Models Used To Characterize the Standardized River Segment 4 2 FSS Population Trends of YOY Fish Density Using a 3-Year Moving Average Linear Regression Segmented Regression 95 percent CI Join 95 percent CI Species MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife (All data) 0.58 -0.035 +/- 0.016 0.040 Did Not Converge Alewife (2 values -3.93e+008 to removed) 0.47 -0.041 +/- 0.014 0.007 0.50 -0.070 to -0.007 2004 3.93e+008 American Shad (All data) 0.35 -0.079 +/- 0.010 < 0.001 0.36 -0.106 to -0.031 1997 -0.226 to 0.008 Atlantic Tomcod (All data) 0.49 -0.040 +/- 0.014 0.007 0.49 -0.510 to 0.691 1983 -0.085 to -0.012 Bay Anchovy 1979-1984 1.10 -0.102 +/- 0.262 0.716 Not Fit Bay Anchovy 1985-2005 0.96 -0.058 +/- 0.035 0.113 0.91 -0.170 to 0.481 1992 -0.287 to -0.004 Blueback Herring (All data) 0.49 -0.055 +/- 0.014 0.001 0.51 -0.154 to 0.002 1992 -0.120 to 0.056 Bluefish (All data) 0.52 -0.019 +/- 0.014 0.194 0.54 -0.081 to 0.039 1996 -0.178 to 0.153 Hogchoker (All data) 0.58 -0.034 +/- 0.016 0.047 0.43 0.038 to 0.268 1988 -0.150 to -0.053 Rainbow Smelt (All data) 0.58 0.012 +/- 0.029 0.67 0.51 -0.018 to 0.142 1993 -1.05 to 0.260 Striped Bass (All data) 0.46 0.034 +/- 0.013 0.013 0.44 -0.014 to 0.241 1988 -0.045 to 0.053 Weakfish (All data) 0.56 -0.047 +/- 0.016 0.006 0.52 -0.243 to -0.038 1990 -0.062 to 0.081 White Catfish (All data) 0.57 0.014 +/- 0.016 0.37 Did Not Converge White Catfish (3 values removed) 0.10 0.007 +/- 0.003 0.030 0.10 -0.025 to 0.070 1986 -0.006 to 0.013 White Perch (All data) 0.62 -0.014 +/- 0.017 0.413 0.63 -2.43 to 1.27 1981 -0.047 to 0.035 3 CI = confidence interval.

4 NUREG-1437, Supplement 38 I-16 December 2010

Appendix I 1 Table I-10 River Segment 4 Assessment of the Level of Potential Negative Impact Based 2 on the Standardized FSS Density Using a 3-Year Moving Average Level of Best General Potential Species Fit Trend Negative Impact Alewife LR S<0 4 (All data)

Alewife (2 values LR S<0 4 removed)

American Shad LR S<0 4 Atlantic Tomcod LR S<0 4 Bay Anchovy LR S=0 1979-1984 4

Bay Anchovy S1 = 0 SR 1985-2005 S2 < 0 Blueback Herring LR S<0 4 Bluefish LR S=0 1 S1 > 0 Hogchoker SR 4 S2 < 0 S1 = 0 Rainbow Smelt SR 1 S2 = 0 S1 = 0 Striped Bass SR 1 S2 = 0 S1 < 0 Weakfish SR 4 S2 = 0 White Catfish LR S=0 1 (All data)

White Catfish (3 values LR S>0 1 removed)

White Perch LR S=0 1 3 LR = Linear Regression; SR = Segmented Regression.

December 2010 I-17 NUREG-1437, Supplement 38

Appendix I 1 1 2 FSS 3rd Q Density FSS 3rd Q Density FSS 3rd Q Density 0 1 0

-1 0

-1

-2 -1

-2 -3 -2 0 10 20 30 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Years of Survey Alewife Outlier American Shad Atlantic Tomcod 3 2 2 2

FSS 3rd Q Density FSS 3rd Q Density FSS 3rd Q Density 1 1 1

0 0 0

-1

-1 -1

-2

-3 -2 -2 0 10 20 30 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Years of Survey Bay Anchovy 79-84 Bay Anchovy 89-05 Blueback Herring Hogchoker 2

Weakfish FSS 3rd Q Density 1

0

-1

-2 0 10 20 30 Years of Survey 1 Figure I-6 River Segment 4 population trends based on the FSS standardized density 2 assigned a large level of potential negative impact 3

NUREG-1437, Supplement 38 I-18 December 2010

Appendix I 1 Table I-11. Initial Values for the Nonlinear Fit of the Segmented Regression Models Used 2 on BSS Population Trends of YOY Fish Density from River Segment 4 3

Taxa Intercept Slope 1 Join Point Slope 2 Alewife -0.04 -0.20 1990 0.02 American Shad 0.20 -0.04 1992 -0.07 Bay Anchovy 0.04 -0.06 1997 -0.11 Blueback Herring 0.50 0.07 1990 -0.08 Bluefish 0.30 -0.09 1996 -0.01 Hogchoker 0.03 0.05 1989 -0.10 Spottail shiner 1.30 -0.80 1982 0.00 Striped Bass 0.18 -0.04 1984 0.04 White Perch 0.30 -0.12 1991 -0.05 4 Table I-12 Competing Models Used To Characterize the Standardized River Segment 4 5 BSS Population Trends of YOY Fish Density Using a 3-Year Moving Average Linear Regression Segmented Regression 95 percent CI Join 95 percent CI Species MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife 0.57 -0.030 +/- 0.016 0.065 0.39 -0.459 to -0.156 1986 -0.010 to 0.063 American Shad 0.35 -0.069 +/- 0.010 < 0.001 0.34 -0.724 to 0.270 1983 -0.083 to -0.036 Bay Anchovy 0.44 0.056 +/- 0.012 0.000 0.39 -0.095 to 0.058 1991 0.055 to 0.161 Blueback Herring 0.53 -0.024 +/- 0.015 0.120 0.42 -0.005 to 0.100 1994 -0.235 to -0.042 Bluefish 0.58 -0.038 +/- 0.016 0.027 0.48 -0.146 to -0.047 1996 -0.021 to 0.287 Hogchoker 0.52 -0.059 +/- 0.014 < 0.001 0.40 -0.250 to -0.092 1991 -0.034 to 0.076 Spottail Shiner 0.43 -0.017 +/- 0.012 0.176 0.35 -0.469 to -0.004 1985 -0.014 to 0.043 Striped Bass 0.42 0.040 +/- 0.012 0.002 0.43 -0.287 to 0.221 1985 0.013 to 0.087 White Perch 0.61 -0.062 +/- 0.017 0.001 0.40 -0.247 to -0.122 1992 -0.007 to 0.133 December 2010 I-19 NUREG-1437, Supplement 38

Appendix I 1 Table I-13 River Segment 4 Assessment of the Level of Potential Negative Impact Based 2 on the Standardized BSS Density Using a 3-Year Moving Average Species Best Fit General Trend Final Decision S1 < 0 Alewife SR S2 = 0 4 S1 = 0 American Shad SR S2 < 0 4 S1 = 0 Bay Anchovy SR S2 > 0 1 S1 = 0 Blueback Herring SR S2 < 0 4 S1 < 0 Bluefish SR S2 = 0 4 S1 < 0 Hogchoker SR S2 = 0 4 S1 < 0 Spottail Shiner SR S2 = 0 4 Striped Bass LR S>0 1 S1 < 0 White Perch SR S2 = 0 4 3 LR = Linear Regression; SR = Segmented Regression.

NUREG-1437, Supplement 38 I-20 December 2010

Appendix I 2 1 BSS 3rd Q Density BSS 3rd Q Density 1

0 0

-1

-1

-2 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Alewife American Shad 2 1 BSS 3rd Q Density BSS 3rd Q Density 1 0 0 -1

-1 -2

-2 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Blueback Herring Bluefish 1 1 BSS 3rd Q Density BSS 3rd Q Density 0 0

-1 -1

-2 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Hogchoker Spottail Shiner 1

BSS 3rd Q Density 0

-1

-2

-3 0 10 20 30 Years of Survey W hite Perch 1 Figure I-7 River Segment 4 population trends based on the BSS standardized density 2 assigned a large level of potential negative impact December 2010 I-21 NUREG-1437, Supplement 38

Appendix I 1 Table I-14. Initial Values for the Nonlinear Fit of the Segmented Regression Models 2 Used on LRS Population Trends of YOY Fish Density from River Segment 4 3

Taxa Intercept Slope 1 Join Point Slope 2 Atlantic Tomcod 0.20 -0.50 1989 0.50 4 Table I-15 Competing Models Used To Characterize the Standardized River Segment 4 5 LRS Population Trends of YOY Atlantic Tomcod Density Using a 3-Year Moving Average Linear Regression Segmented Regression 95 percent CI Join 95 percent CI Species MSE Slope p-value MSE Slope 1 Point Slope 2 Atlantic Tomcod 0.53 -0.074 +/- 0.015 < 0.001 0.49 -0.187 to -0.067 1982 -0.098 to 0.124 6 Table I-16 River Segment 4 Assessment of the Level of Potential Negative Impact Based 7 on the Standardized LRS Atlantic Tomcod YOY Density Using a 3-Year Moving Average Level of Potential General Negative Species Best Fit Trend Impact S1 < 0 Atlantic Tomcod SR S2 = 0 4 8 SR = Segmented Regression.

9 NUREG-1437, Supplement 38 I-22 December 2010

Appendix I 1

2 Standardized LRS Atlantic tomcod 1

0 3rd Quartile Density

-1

-2 0 10 20 30 Years of Survey 2

3 Figure I-8. River Segment 4 population trends based on the LRS standardized density 4 assigned a large level of potential negative impact 5 A visual and statistical comparison of the river-segment FSS standardized CPUE with the BSS 6 standardized density (Table I-17) suggested that the trends for alewife, American shad, 7 Atlantic tomcod, bluefish, striped bass, and weakfish were not biologically different (Figure I-9).

8 Observations from both surveys overlap and cross over each other. The post-1985 FSS CPUE 9 observations for hogchoker and white perch were greater than the BSS observations and did 10 not show a decline associated with the gear change (Figure I-10). Thus, for these RIS, all of the 11 FSS CPUE data (1979-2005) were used in the regression analysis. The FSS density data for 12 bay anchovy and blueback herring, however, did show a potential gear effect (Figure I-11), and 13 a pre- and post-1985 analysis was conducted.

14 15 Table I-17. Evaluation of Gear Effect on FSS CPUE Population Trends in River Segment 4 Proportion FSS < BSS Absolute Medan Absolute Difference Significance Difference Taxa of Conclusion 1979-1984 1985-2005 in 1979-1984 1985-2005 Sign Test Proportions Alewife 0.50 0.90 0.40 0.69 0.46 0.808 Not Biol. Different American Shad 0.33 0.86 0.52 0.32 0.82 0.013 Not Biol. Different Atlantic Tomcod 0.33 0.24 0.10 1.02 0.64 0.332 Not Biol. Different Bay Anchovy 0.50 1.00 0.50 1.07 2.21 < 0.001 Separate Analysis Blueback Herring 0.67 0.95 0.29 0.61 1.25 < 0.001 Separate Analysis Bluefish 0.67 0.71 0.05 0.81 0.53 0.332 Not Biol. Different Hogchoker 0.33 0.00 0.33 1.22 1.11 < 0.001 FSS > BSS Striped Bass 0.50 0.52 0.02 1.23 1.28 0.004 Not Biol. Different Weakfish 0.50 0.62 0.12 0.66 0.36 0.668 Not Biol. Different White Perch 0.33 0.10 0.24 0.52 0.94 0.013 FSS > BSS 16 December 2010 I-23 NUREG-1437, Supplement 38

Appendix I Standardized Density or CPUE Standardized Density or CPUE 2 FSS gear change 2 FSS gear change 1 1 0 0

-1 -1

-2 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Alewife-D-BSS American Shad-D-BSS Alewife-C-FSS American Shad-C-FSS Standardized Density or CPUE Standardized Density or CPUE FSS gear change FSS gear change 2 2 1

1 0

0

-1

-1

-2

-2 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Atlantic tomcod R2-D-BSS Bluefish-D-BSS Atlantic Tomcod-C-FSS Bluefish-C-FSS Standardized Density or CPUE Standardized Density or CPUE FSS gear change 2 FSS gear change 2

1 1 0 0

-1 -1

-2 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Striped Bass-D-BSS Weakfish R1-6-D-BSS Striped Bass-C-FSS Weakfish-C-FSS 1 Note: All data were used in WOE analysis; R2 = River Segment 2 and R1-6 = River Segments 1-6.

2 Figure I-9. River Segment 4 population trends based on the FSS standardized CPUE (C) 3 and BSS density (D) not considered biologically different NUREG-1437, Supplement 38 I-24 December 2010

Appendix I Standardized Density or CPUE FSS gear change 2

1 0

-1

-2

-3 0 10 20 30 Years of Survey Hogchoker-D-BSS Hogchoker-C-FSS FSS gear change Standardized Density or CPUE 3

2 1

0

-1

-2

-3 0 10 20 30 Years of Survey White Perch-D-BSS White Perch-C-FSS 1 Note: All data were used in WOE analysis.

2 Figure I-10. River Segment 4 population trends based on the FSS standardized CPUE (C) 3 and BSS density (D) for which the FSS density is greater.

December 2010 I-25 NUREG-1437, Supplement 38

Appendix I Standardized Density or CPUE FSS gear change 2

1 0

-1

-2

-3 0 10 20 30 Years of Survey Bay Anchovy-D-BSS Bay Anchovy-C-FSS Standardized Density or CPUE FSS gear change 2

1 0

-1

-2 0 10 20 30 Years of Survey Blueback Herring-D-BSS Blueback Herring-C-FSS 1 Note: Years were analyzed separately for WOE analysis.

2 Figure I-11. River Segment 4 population trends based on the FSS standardized CPUE (C) 3 and BSS density (D) for which the FSS may indicate a gear difference NUREG-1437, Supplement 38 I-26 December 2010

Appendix I 1 The following tables were the intermediate analyses for the assessment of population trends 2 associated with fish CPUE sampled from River Segment 4 (Indian Point). Results of these 3 river-segment trend analyses were compiled in Table H-13 in Section H.1.3 of the SEIS. The 4 data used in this analysis (from Entergy 2007), in order of appearance, were the standardized 5 75th percentile of the weekly fish CPUE for a given year collected from the FSS (Table I-18, 6 Table I-19, Table I-20, and Figure I-12) and LRS for Atlantic tomcod only (Table I-21, Table I-22 7 and Table I-23). The Atlantic tomcod population trend observed with the LRS CPUE data was 8 analyzed both before and after the gear change using a 3-year moving average. The data 9 were standardized first and then smoothed.

10 Table I-18 Initial Values for the Nonlinear Fit of the Segmented Regression Models 11 Used in FSS Population Trends of YOY Fish CPUE from River Segment 4 12 Taxa Intercept Slope 1 Join Point Slope 2 Alewife -0.04 -0.20 1990 0.02 American Shad 0.20 -0.50 1986 0.00 Atlantic Tomcod 0.40 0.06 1988 0.00 (All data)

Bay Anchovy 0.04 -0.50 1990 0.00 (1985-2005)

Bluefish 0.30 -0.09 1996 -0.01 Hogchoker

-0.17 0.08 1987 -0.05 (All data)

Hogchoker 0.03 0.05 1989 -0.10 (2 values removed)

Rainbow Smelt 1.00 -0.80 1982 0.00 Striped Bass -0.08 0.07 1990 0.00 Weakfish 0.40 -0.08 1990 -0.02 (All data)

Weakfish 0.40 -0.08 1990 -0.02 (2 values removed)

White Perch 2.00 -1.00 1981 -0.01 (All data)

White Perch 1.00 0.00 1982 0.00 (1 value removed) 13 December 2010 I-27 NUREG-1437, Supplement 38

Appendix I 1 Table I-19 Competing Models Used To Characterize the Standardized River Segment 4, 2 FSS Population Trends of YOY Fish CPUE Linear Regression Segmented Regression Species 95 percent CI Join 95 percent CI MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife 0.92 -0.055 +/- 0.023 0.022 0.79 -0.839 to -0.058 1984 -0.058 to 0.060 American Shad 0.76 -0.085 +/- 0.019 < 0.001 0.57 -0.717 to -0.159 1985 -0.067 to 0.018 Atlantic Tomcod 0.95 -0.046 +/- 0.024 0.063 0.99 -6.78 to 6.63 1980 -0.102 to 0.012 (All data)

Atlantic Tomcod 0.66 -0.028 +/- 0.017 0.106 Did Not Converge (1 value removed)

Bay Anchovy 0.80 -0.373 +/- 0.191 0.123 Not Fit 1979-1984 Bay Anchovy 1.00 0.034 +/- 0.036 0.360 0.96 -0.022 to 0.248 1999 -0.596 to 0.172 1985-2005 Blueback Herring 1.11 -0.059 +/- 0.266 0.835 Not Fit 1979-1984 Blueback Herring 0.38 -0.022 +/- 0.015 0.152 Did Not Converge 1985-2005 Bluefish 0.84 -0.072 +/- 0.021 0.002 0.82 -0.374 to -0.002 1988 -0.106 to 0.061 Hogchoker 1.00 -0.025 +/- 0.025 0.332 0.92 -0.101 to 0.368 1988 -0.184 to 0.000 (All data)

Hogchoker 0.47 -0.021 +/- 0.012 0.087 0.44 -0.049 to 0.211 1987 -0.097 to -0.008 (2 values removed)

Rainbow Smelt 0.89 -0.062 +/- 0.022 0.009 0.45 -4.95 to -2.33 1980 -0.049 to 0.002 Striped Bass 1.01 -0.013 +/- 0.025 0.599 1.00 -0.089 to 0.178 1993 -0.259 to 0.076 White Perch 0.95 -0.047 +/- 0.023 0.055 0.87 -3.97 to 1.12 1981 -0.071 to 0.029 (All data)

White Perch 0.72 -0.039 +/- 0.018 0.038 0.51 -2.02 to -0.538 1981 -0.037 to 0.026 (1 value removed)

Weakfish 0.98 -0.036 +/- 0.024 0.152 0.97 -0.282 to 0.045 1991 -0.098 to 0.159 (All data)

Weakfish 0.52 -0.003 +/- 0.014 0.842 0.50 -0.162 to 0.033 1990 -0.026 to 0.095 (2 values removed) 3 Two extreme outliers (both values greater than 3 standard deviations from the mean) were 4 removed from the FSS hogchoker CPUE regression analysis because of their influence on the 5 regression (Tables I-19 and I-20). One extreme outlier (value greater than 3 standard 6 deviations from the mean) was removed from the FSS Atlantic tomcod CPUE regression 7 analysis, and one extreme outlier (value greater than 2 standard deviations from the mean) was 8 removed from the FSS white perch CPUE regression analysis. These extreme outliers had a 9 great influence on the regression results. One value (not an extreme outlier) and one extreme 10 outlier (greater than 3 standard deviations from the mean) were removed from the FSS weakfish 11 CPUE regression analysis because of the influence these data had on the regression results.

12 The results of the regression models with the observations removed were more conservative 13 and were used for the trend analysis.

14 NUREG-1437, Supplement 38 I-28 December 2010

Appendix I 1 Table I-20 River Segment 4 Assessment of the Level of Potential Negative Impact 2 Based on the Standardized FSS CPUE Level of Gener Best Potential Species al Fit Negative Trend Impact S1 < 0 Alewife SR 4 S2 = 0 S1 < 0 American Shad SR 4 S2 = 0 Atlantic Tomcod LR S=0 1 (All data)

Atlantic Tomcod LR S=0 1 (1 value removed)

Bay Anchovy LR S=0 1979-1984 1

Bay Anchovy S1 = 0 SR 1985-2005 S2 = 0 Blueback Herring LR S=0 1979-1984 1

Blueback Herring LR S=0 1985-2005 S1 < 0 Bluefish SR 4 S2 = 0 S1 = 0 Hogchoker (All data) SR 1 S2 = 0 Hogchoker S1 = 0 SR 4 (2 values removed) S2 < 0 S1 < 0 Rainbow Smelt SR 4 S2 = 0 S1 = 0 Striped Bass SR 1 S2 = 0 S1 = 0 Weakfish (All data) SR 1 S2 = 0 Weakfish S1 = 0 SR 1 (2 values removed) S2 = 0 S1 = 0 White Perch (All data) SR 1 S2 = 0 White Perch S1 < 0 SR 4 (1 value removed) S2 = 0 3 LR = Linear Regression; SR = Segmented Regression.

December 2010 I-29 NUREG-1437, Supplement 38

Appendix I 3 2 2 1 FSS 3rd Q CPUE FSS 3rd Q CPUE 1

0 0

-1

-1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Alewife American Shad 3 4 2 3 FSS 3rd Q CPUE FSS 3rd Q CPUE 1 2 0 1

-1 0

-2 -1

-3 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Bluefish Hogchoker Outlier 3

5.0 2

FSS 3rd Q CPUE FSS 3rd Q CPUE 2.5 1 0

0.0

-1

-2

-2.5 10 20 30 0 10 20 30 Years of Survey Years of Survey Rainbow Smelt W hite Perch Outlier 1 Figure I-12 River Segment 4 population trends based on the FSS standardized CPUE 2 assigned a large level of potential negative impact NUREG-1437, Supplement 38 I-30 December 2010

Appendix I 1 Table I-21. Initial Values for the Nonlinear Fit of the Segmented Regression Models 2 Used on LRS Population Trends of YOY Fish CPUE from River Segment 4 3

Taxa Intercept Slope 1 Join Point Slope 2 Atlantic Tomcod 0.30 -0.02 1999 0.10 (1985-2005) 4 Table I-22. Competing Models Used To Characterize the Standardized River Segment 4 5 LRS Population Trends of YOY Atlantic Tomcod CPUE Using a 3-Year Moving Average Linear Regression Segmented Regression Species 95 percent CI Join 95 percent CI MSE Slope p-value MSE Slope 1 Point Slope 2 Atlantic Tomcod 0.31 0.494 +/- 0.074 0.003 Not Fit (1979-1984)

Atlantic Tomcod 0.57 -0.069 +/- 0.022 0.006 0.28 -0.873 to -0.338 1989 -0.031 to 0.034 (1985-2005) 6 Table I-23. River Segment 4 Assessment of the Level of Potential Negative Impact Based 7 on the Standardized LRS Atlantic Tomcod YOY CPUE Using a 3-Year Moving Average Best General Level of Potential Species Fit Trend Negative Impact Atlantic Tomcod LR S>0 (1979-1984) 4 Atlantic Tomcod S1 < 0 SR (1985-2005) S2 = 0 8 LR = Linear Regression; SR = Segmented Regression.

9 The results of the two measurement metricsdensity (estimated number of RIS per given 10 volume of water provided by the applicant) and CPUE (number of RIS captured by the sampler 11 for a given volume of water derived by the NRC staff) were combined for the assessment of 12 population impacts potentially associated with the IP2 and IP3 cooling systems. Table I-25 13 presents the numeric results compiled from Tables I-8, I-10, I-12, I-14, and I-16 above and used 14 to derive Table H-14 in Section H.3 in the SEIS Appendices.

December 2010 I-31 NUREG-1437, Supplement 38

Appendix I 4 Gear Change Standardized 3

2 3rd Quartile LRS CPUE 1

0

-1 0 10 20 30 Years of Survey Atlantic tomcod 79-84 Atlantic tomcod 85-05 1

2 Figure I-13. River Segment 4 population trends based on the LRS standardized CPUE 3 assigned a large level of potential negative impact 4

5 Table I-24. Assessment of Population Impacts for IP2 and IP3 River Segment 4 Density CPUE River-Species Segment FSS BSS LRS FSS LRS Assessment a

Alewife 4 4 N/A 4 N/A 4.0 American Shad 4 4 N/A 4 N/A 4.0 Atlantic N/A N/A N/A N/A N/A Unknown Menhaden Atlantic Sturgeon N/A N/A N/A N/A N/A Unknown Atlantic Tomcod 4 N/A 4 1 4 3.3 Bay Anchovy 4 1 N/A 1 N/A 2.0 Blueback Herring 4 4 N/A 1 N/A 3.0 Bluefish 1 4 N/A 4 N/A 3.0 Gizzard Shad N/A N/A N/A N/A N/A Unknown Hogchoker 4 4 N/A 4 N/A 4.0 Rainbow Smelt 1 N/A N/A 4 N/A 2.5 Shortnose N/A N/A N/A N/A N/A Unknown Sturgeon Spottail Shiner N/A 4 N/A N/A N/A 4.0 Striped Bass 1 1 N/A 1 N/A 1.0 Weakfish 4 N/A N/A 1 N/A 2.5 White Catfish 1 N/A N/A N/A N/A 1.0 White Perch 1 4 N/A 4 N/A 3.0 Blue Crab N/A N/A N/A N/A N/A Unknown NUREG-1437, Supplement 38 I-32 December 2010

Appendix I 1 (a) N/A: not applicable; YOY not present in samples 2

December 2010 I-33 NUREG-1437, Supplement 38

Appendix I 1 Lower Hudson River 2 A visual and statistical comparison of the riverwide FSS standardized CPUE with the BSS 3 standardized CPUE (Table I-25) suggested that the trends were not biologically different for 4 hogchoker, spottail shiner, and striped bass (Figure I-14). Observations from both surveys 5 overlap and cross over each other. The post-1985 FSS observations for Atlantic tomcod and 6 white perch were greater than the BSS observations and did not show a decline associated with 7 the gear change (Figure I-15). For these RIS, all of the FSS data (1979-2005) were used in the 8 regression analysis. The FSS density data for alewife, American shad, bay anchovy, blueback 9 herring, and bluefish, however, did show a potential gear effect (Figure I-16), and a pre- and 10 post-1985 analysis was conducted.

11 12 Table I-25. Evaluation of Gear Effect on FSS CPUE Riverwide Population Trends Proportion FSS < BSS Absolute Medan Absolute Difference Significance Difference Taxa of Conclusion 1979-1984 1985-2005 in 1979-1984 1985-2005 Sign Test Proportions Alewife 0.67 1.00 0.33 0.68 1.47 < 0.001 Separate Analysis American Shad 0.33 1.00 0.67 1.17 1.60 < 0.001 Separate Analysis Atlantic Tomcod 0.33 0.00 0.33 1.18 1.36 < 0.001 FSS > BSS Bay Anchovy 0.50 1.00 0.50 1.04 0.78 < 0.001 Separate Analysis Blueback Herring 0.50 1.00 0.50 0.86 0.66 < 0.001 Separate Analysis Bluefish 0.33 1.00 0.67 0.89 1.28 < 0.001 Separate Analysis Hogchoker 0.50 0.29 0.21 0.61 0.78 < 0.001 Not Biol. Different Spottail Shiner 0.50 0.38 0.12 0.28 0.85 0.013 Not Biol. Different Striped Bass 0.50 0.43 0.07 0.91 0.79 0.039 Not Biol. Different White Perch 0.33 0.19 0.14 1.33 0.81 0.039 FSS > BSS 13 NUREG-1437, Supplement 38 I-34 December 2010

Appendix I FSS gear change FSS gear change 4 4 Standardized CPUE Standardized CPUE 3 3 2 2 1 1 0 0

-1 -1

-2 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Hogchoker-BSS Spottail Shiner-BSS Hogchoker-FSS Spottail Shiner-FSS FSS gear change 5

4 Standardized CPUE 3

2 1

0

-1

-2 0 10 20 30 Years of Survey Striped Bass-BSS Striped Bass-FSS 1 Note: All data were used in WOE analysis.

2 Figure I-14. Riverwide population trends based on the FSS and BSS standardized CPUE 3 not considered biologically different December 2010 I-35 NUREG-1437, Supplement 38

Appendix I FSS gear change 5

4 Standardized CPUE 3

2 1

0

-1

-2 0 10 20 30 Years of Survey Atlantic Tomcod-BSS Atlantic Tomcod-FSS FSS gear change 2

Standardized CPUE 1

0

-1

-2

-3

-4 0 10 20 30 Years of Survey White Perch-BSS White Perch-FSS 1 Note: All data were used in WOE analysis.

2 Figure I-15. Riverwide population trends based on the FSS and BSS standardized CPUE 3 for which the FSS density is greater NUREG-1437, Supplement 38 I-36 December 2010

Appendix I 3 FSS gear change 3 FSS gear change Standardized CPUE Standardized CPUE 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Alewife-BSS American Shad-BSS Alewife-FSS American Shad-FSS FSS gear change FSS gear change 2 3 Standardized CPUE Standardized CPUE 1 2 1

0 0

-1

-1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Bay Anchovy-BSS Blueback Herring-BSS Bay Anchovy-FSS Blueback Herring-FSS FSS gear change 5

4 Standardized CPUE 3

2 1

0

-1

-2

-3 0 10 20 30 Years of Survey Bluefish-BSS Bluefish-FSS 1 Note: Years were analyzed separately for WOE analysis.

2 Figure I-16. Riverwide population trends based on the FSS and BSS standardized CPUE 3 for which the FSS may indicate a gear difference December 2010 I-37 NUREG-1437, Supplement 38

Appendix I 1 The following tables are the intermediate analyses for the riverwide assessment of population 2 trends associated with annual fish CPUE and the abundance index. Results of these riverwide 3 trend analyses are compiled in Table H-15 in Section H.1.3 of the SEIS Appendices. The data 4 used in this analysis, in order of appearance, were the standardized annual fish CPUE for a 5 given year collected from the FSS (Table I-26, Table I-2718, Table I-28, and Figure I-17), BSS 6 (Table I-29, Table I-30, Table I-31, and Figure I-18), LRS for Atlantic tomcod only (Table I-32, 7 Table I-33 and Table I-34), and the annual fish abundance index (Table I-35, Table I-36, Table 8 I-37, and Figure I-19).

9 One extreme outlier (value greater than 4 standard deviation away from the mean) was 10 removed from the Atlantic tomcod FSS CPUE regression analysis (Tables I-26, I-27, and I-28) 11 and one from the bluefish BSS CPUE regression analysis (Tables I-29, I-30, and I-31). One 12 extreme outlier (value greater than 4 standard deviations away from the mean) was removed 13 from the abundance index for the bluefish regression analysis (Table I-35, Tables I-36, and I-14 27). One extreme outlier was also removed from the abundance index for both the rainbow 15 smelt (value greater than 5 standard deviations away from the mean) regression analysis and 16 the white catfish (value greater than 2 standard deviations away from the mean) regression 17 analysis, because of the influence these data had on the regression results. The results of the 18 regression models with the observations removed were more conservative and were used for 19 the trend analysis.

20 Table I-26. Initial Values for the Nonlinear Fit of the Segmented Regression Models 21 Used in FSS CPUE Riverwide Population Trends of YOY Fish 22 Taxa Intercept Slope 1 Join Point Slope 2 Alewife (1985-2005) -0.50 0.30 1989 -0.03 American Shad (1985-2005) -0.50 0.30 1989 -0.03 Atlantic Tomcod (All data) 0.10 0.00 1991 -0.10 Atlantic Tomcod (1 value removed) 0.10 0.01 1991 -0.01 Bay Anchovy (1985-2005) -0.50 0.30 1989 -0.03 Blueback Herring (1985-2005) -0.50 0.30 1989 -0.03 Bluefish (1985-2005) -0.50 0.30 1989 -0.03 Hogchoker -0.50 0.30 1987 -0.10 Spottail Shiner 0.00 0.00 1984 0.00 Striped Bass -0.10 0.10 1989 -0.06 23 24 NUREG-1437, Supplement 38 I-38 December 2010

Appendix I 1 Table I-27 Competing Models Used To Characterize the Standardized Riverwide FSS 2 Population Trends of YOY Fish CPUE Linear Regression Segmented Regression Species 95 percent CI Join 95 percent CI MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife 0.83 -0.357 +/- 0.199 0.148 Not Fit 1979-1984 Alewife -2.44e-006 to 0.99 0.043 +/- 0.036 0.238 1.00 1986 -0.028 to 0.139 1985-2005 2.44e+006 American Shad 0.98 -0.254 +/- 0.235 0.340 Not Fit 1979-1984 American Shad 0.87 -0.085 +/- 0.032 0.015 0.82 -0.293 to 0.805 1989 -0.226 to -0.038 1985-2005 Atlantic Tomcod 0.95 -0.046 +/- 0.023 0.059 0.93 -0.335 to 0.774 1984 -0.146 to -0.009 (All data)

Atlantic Tomcod 0.61 -0.028 +/- 0.015 0.083 0.60 -0.089 to 0.183 1989 -0.124 to -0.002 (1 value removed)

Bay Anchovy 1.08 0.135 +/- 0.259 0.629 Not Fit 1979-1984 Bay Anchovy 1.03 -0.002 +/- 0.037 0.962 0.99 -0.520 to 1.74 1988 -0.152 to 0.053 1985-2005 Blueback Herring 1.12 0.004 +/- 0.267 0.990 Not Fit 1979-1984 Blueback Herring 0.84 -0.092 +/- 0.030 0.007 0.83 -0.272 to 0.382 1991 -0.256 to -0.023 1985-2005 Bluefish 0.92 0.305 +/- 0.219 0.236 Not Fit 1979-1984 Bluefish 0.92 -0.073 +/- 0.033 0.039 0.90 -0.874 to 1.44 1988 -0.195 to -0.010 1985-2005 Hogchoker 0.92 -0.055 +/- 0.023 0.022 0.65 0.114 to 0.526 1986 -0.198 to -0.086 Spottail Shiner 0.96 -0.043 +/- 0.024 0.083 0.91 -0.186 to 0.719 1984 -0.152 to -0.015 Striped Bass 1.02 -0.003 +/- 0.025 0.902 0.93 -0.084 to 0.389 1988 -0.164 to 0.023 White Perch 0.65 -0.097 +/- 0.016 < 0.001 Did Not Converge December 2010 I-39 NUREG-1437, Supplement 38

Appendix I 1 Table I-28 Riverwide Assessment of the Level of Potential Negative Impact Based on the 2 Standardized FSS CPUE General Species Best Fit Final Decision Trend Alewife 1979-1984 LR S=0 1

Alewife 1985-2005 LR S=0 American Shad 1979-1984 LR S=0 S1 = 0 4 American Shad 1985-2005 SR S2 < 0 S1 = 0 Atlantic Tomcod (All data) SR S2 < 0 4

S1 = 0 Atlantic Tomcod (1 value removed) SR S2 < 0 4

Bay Anchovy 1979-1984 LR S=0 S1 = 0 1 Bay Anchovy 1985-2005 SR S2 = 0 Blueback Herring 1979-1984 LR S=0 S1 = 0 4 Blueback Herring 1985-2005 SR S2 < 0 Bluefish 1979-1984 LR S=0 S1 = 0 4 Bluefish 1985-2005 SR S2 < 0 S1 > 0 Hogchoker SR S2 < 0 4

S1 = 0 Spottail Shiner SR S2 < 0 4

S1 = 0 Striped Bass SR S2 = 0 1

White Perch LR S<0 4 3 LR = Linear Regression; SR = Segmented Regression.

NUREG-1437, Supplement 38 I-40 December 2010

Appendix I 3 5 Standardized FSS CPUE Standardized FSS CPUE 2 4 1 3 0 2

-1 1

-2 0

-3 -1

-4 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey American Shad 79-84 American Shad 85-05 Atlantic Tomcod Outlier 3 3 Standardized FSS CPUE Standardized FSS CPUE 2 2 1

1 0

0

-1

-1

-2

-3 -2

-4 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Blueback Herring 79-84 Blueback Herring 85-05 Bluefish 79-84 Bluefish 85-05 3 3 Standardized FSS CPUE Standardized FSS CPUE 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Hogchoker Spottail Shiner 2

Standardized FSS CPUE 1

0

-1

-2

-3 0 10 20 30 Years of Survey W hite Perch 1

2 Figure I-17. Riverwide population trend based on the FSS standardized CPUE assigned a 3 large level of potential negative impact 4

December 2010 I-41 NUREG-1437, Supplement 38

Appendix I 1 Table I-29. Initial Values for the Nonlinear Fit of the Segmented Regression Models 2 Used in BSS CPUE Riverwide Population Trends of YOY Fish 3

Taxa Intercept Slope 1 Join Point Slope 2 Alewife 0.50 -0.02 1991 0.00 American Shad 14.00 0.02 1990 -0.05 Atlantic Tomcod 0.05 -0.03 1993 0.00 Bay Anchovy 4.00 -2.00 1986 0.10 Blueback Herring 11.00 0.37 1992 -1.30 Bluefish (All data) 0.30 -0.02 1989 0.03 Bluefish (1 value removed) 0.30 -0.02 1989 0.03 Hogchoker 1.50 0.23 1990 -0.24 Rainbow Smelt 0.16 -0.03 1984 0.00 Spottail Shiner 9.20 -0.50 1988 0.36 Striped Bass 5.20 0.10 1988 0.32 Weakfish 0.00 0.01 1983 0.00 White Catfish 0.10 -0.01 1984 0.00 White Perch 16.90 -0.60 1990 -0.04 4 Table I-30 Competing Models Used To Characterize the Standardized Riverwide BSS 5 Population Trends of YOY Fish CPUE Linear Regression Segmented Regression 95 percent CI Join 95 percent CI Species MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife 0.996 0.027 +/- 0.025 0.281 0.944 -0.417 to 0.087 1987 -0.001 to 0.177 American Shad 0.991 -0.030 +/- 0.025 0.235 0.981 -0.103 to 0.198 1992 -0.240 to 0.029 Atlantic Tomcod 0.802 -0.078 +/- 0.020 0.001 0.787 -0.232 to -0.038 1993 -0.135 to 0.137 Bay Anchovy 0.971 -0.038 +/- 0.024 0.123 0.927 -0.631 to 0.094 1986 -0.063 to 0.085 Blueback Herring 0.937 -0.050 +/- 0.023 0.042 0.940 -0.429 to 0.091 1987 -0.101 to 0.075 Bluefish (All data) 1.02 0.001 +/- 0.025 0.976 1.04 -0.189 to 0.097 1993 -0.101 to 0.218 Bluefish (1 value removed) 0.478 -0.019 +/- 0.012 0.121 0.439 -0.103 to -0.013 1995 -0.038 to 0.165 Hogchoker 0.969 -0.039 +/- 0.024 0.113 0.913 -0.212 to 0.983 1983 -0.141 to -0.014 Rainbow Smelt 0.875 -0.065 +/- 0.022 0.006 0.327 -1.54 to -0.939 1982 -0.022 to 0.021 Spottail Shiner 0.965 0.041 +/- 0.024 0.101 0.928 -0.448 to 0.145 1987 0.012 to 0.172 Striped Bass 0.908 0.057 +/- 0.022 0.017 0.941 -0.347 to 0.373 1986 -0.010 to 0.147 Weakfish 1.01 -0.021 +/- 0.025 0.407 0.996 -0.514 to 1.33 1982 -0.111 to 0.018 White Catfish 0.642 -0.098 +/- 0.016 < 0.001 0.668 -2.02 to 1.89 1980 -0.138 to -0.061 White Perch 0.859 -0.068 +/- 0.021 0.004 0.737 -0.208 to -0.070 1997 -0.036 to 0.358 NUREG-1437, Supplement 38 I-42 December 2010

Appendix I 1 Table I-31 Riverwide Assessment of the Level of Potential Negative Impact 2 Based on the BSS CPUE General Species Best Fit Trend Final Decision S1 = 0 Alewife SR S2 = 0 1 S1 = 0 American Shad SR S2 = 0 1 S1 < 0 Atlantic Tomcod SR S2 = 0 4 S1 = 0 Bay Anchovy SR S2 = 0 1 Blueback Herring LR S<0 4 Bluefish (All data) LR S=0 1 S1 < 0 Bluefish (1 value removed) SR S2 = 0 4 S1 = 0 Hogchoker SR S2 < 0 4 S1 < 0 Rainbow Smelt SR S2 = 0 4 S1 = 0 Spottail Shiner SR S2 > 0 1 Striped Bass LR S>0 1 S1 = 0 Weakfish SR S2 = 0 1 White Catfish LR S<0 4 S1 < 0 White Perch SR S2 = 0 4 3 LR = Linear Regression; SR = Segmented Regression.

December 2010 I-43 NUREG-1437, Supplement 38

Appendix I 3 3 Standardized BSS CPUE Standardized BSS CPUE 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Atlantic Tomcod Blueback Herring 5 4 Standardized BSS CPUE Standardized BSS CPUE 4 3 3 2 2 1 1 0 0 -1

-1 -2

-2 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Bluefish Outlier Hogc hoker 4 2 Standardized BSS CPUE Standardized BSS CPUE 3 1 2

0 1

-1 0

-2

-1

-2 -3

-3 -4 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Rainbow Smelt W hite Catfish 2

Standardized BSS CPUE 1

0

-1

-2

-3

-4 0 10 20 30 Years of Survey W hite Perch 1 Figure I-18. Riverwide population trends based on the BSS standardized CPUE assigned 2 a large level of potential negative impact NUREG-1437, Supplement 38 I-44 December 2010

Appendix I 1 Table I-32. Initial Values for the Nonlinear Fit of the Segmented Regression Model 2 Used on Riverwide LRS Population Trend of YOY Atlantic Tomcod CPUE 3

Taxa Intercept Slope 1 Join Point Slope 2 Atlantic Tomcod 1.00 -0.20 1989 0.30 4

5 Table I-33 Competing Models Used To Characterize the Standardized Riverwide LRS 6 Population Trend of YOY Atlantic Tomcod CPUE Linear Regression Segmented Regression 95 percent CI Join 95 percent CI Species MSE Slope p-value MSE Slope 1 Point Slope 2 Atlantic Tomcod 1.02 -0.006 +/- 0.025 0.826 0.96 -2.38 to 0.439 1980 -0.037 to 0.081 7

8 Table I-34 Riverwide Assessment of the Level of Potential Negative Impact Based on the 9 Standardized LRS CPUE of Atlantic Tomcod General Species Best Fit Trend Final Decision S1 = 0 Atlantic Tomcod SR S2 = 0 1 10 SR = Segmented Regression.

11 December 2010 I-45 NUREG-1437, Supplement 38

Appendix I 1 Table I-35. Initial Values for the Nonlinear Fit of the Segmented Regression Models 2 Used in Riverwide YOY Abundance Index Trends 3

Taxa Intercept Slope 1 Join Point Slope 2 Alewife 0.1 -0.1 14 0.01 American Shad -0.3 0.02 11 -0.5 Atlantic Tomcod 0.1 0.01 12 -0.01 Bay Anchovy -0.1 0.1 14 -0.1 Blueback Herring -0.3 0.4 13 -0.1 Bluefish (All data) 0.3 -0.02 10 0.03 Bluefish (1 value removed) 0.3 -0.02 10 0.03 Hogchoker -0.4 0.2 11 -0.1 Rainbow Smelt (1 value removed) 0.3 0.1 11 -0.1 Spottail Shiner -0.1 -0.03 14 0.5 Striped Bass -0.1 0.08 15 0.25 Weakfish -0.1 -0.02 15 -0.04 White Catfish -1.00 0.00 20 0.00 White Perch 0.2 -0.06 12 0.18 4

NUREG-1437, Supplement 38 I-46 December 2010

Appendix I 1 Table I-36 Competing Models Used To Characterize the Standardized Riverwide YOY 2 Abundance Index Trends Linear Regression Segmented Regression Species 95 percent CI Join 95 percent CI MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife 1.00 -0.024 +/- 0.025 0.334 1.03 -0.199 to 0.075 1993 -0.150 to 0.195 American Shad 0.92 -0.053 +/- 0.023 0.028 0.93 -0.151 to 0.209 1989 -0.199 to 0.010 Atlantic Tomcod 0.97 -0.039 +/- 0.024 0.112 0.85 -0.051 to 0.323 1989 -0.223 to -0.036 Bay Anchovy 0.95 -0.045 +/- 0.024 0.067 0.89 -0.128 to 0.323 1988 -0.195 to -0.016 Blueback Herring 0.98 -0.036 +/- 0.024 0.152 0.90 -0.077 to 0.380 1988 -0.200 to -0.020 Bluefish 1.00 0.023 +/- 0.025 0.355 1.03 -0.274 to 0.195 1989 -0.053 to 0.158 (All data)

Bluefish 0.38 0.003 +/- 0.009 0.775 0.36 -0.074 to 0.015 1994 -0.014 to 0.111 (1 value removed)

Hogchoker 0.99 -0.029 +/- 0.025 0.244 0.96 -0.143 to 0.349 1988 -0.179 to 0.015 Rainbow Smelt 1.02 -0.008 +/- 0.025 0.759 Did Not Converge (All data)

Rainbow Smelt 0.27 -0.008 +/- 0.007 0.253 0.26 -0.022 to 0.059 1992 -0.072 to 0.008 (1 value removed)

Spottail Shiner 0.97 0.038 +/- 0.024 0.125 0.96 -0.164 to 0.100 1993 -0.025 to 0.270 Striped Bass 0.95 0.045 +/- 0.024 0.067 0.97 -0.081 to 0.114 1996 -0.126 to 0.369 Weakfish 0.90 -0.059 +/- 0.022 0.013 0.85 -0.312 to 0.701 1984 -0.154 to -0.029 White Catfish 0.85 -0.069 +/- 0.021 0.003 Did Not Converge (All data)

White Catfish 0.50 -0.062 +/- 0.012 < 0.001 0.49 -0.169 to -0.030 1992 -0.100 to 0.051 (1 value removed)

White Perch 0.96 -0.041 +/- 0.024 0.096 0.80 -0.286 to -0.068 1993 -0.007 to 0.237 December 2010 I-47 NUREG-1437, Supplement 38

Appendix I 1 Table I-37 Riverwide Assessment of the Level of Potential Negative Impact 2 Based in the Abundance Index General Species Best Fit Trend Final Decision Alewife LR S=0 1 American Shad LR S<0 4 S1 = 0 Atlantic Tomcod SR S2 < 0 4 S1 = 0 Bay Anchovy SR S2 < 0 4 S1 = 0 Blueback Herring SR S2 < 0 4 Bluefish (All data) LR S=0 1 S1 = 0 Bluefish (1 value removed) SR S2 = 0 1 S1 = 0 Hogchoker SR S2 = 0 1 Rainbow Smelt (All data) LR S=0 1 S1 = 0 Rainbow Smelt (1 value removed) SR S2 = 0 1 S1 = 0 Spottail Shiner SR S2 = 0 1 Striped Bass LR S=0 1 S1 = 0 Weakfish SR S2 < 0 4 White Catfish (All data) LR S<0 4 S1 < 0 White Catfish (1 value removed) SR S2 = 0 4 S1 < 0 White Perch SR S2 = 0 4 3 LR = Linear Regression; SR = Segmented Regression.

NUREG-1437, Supplement 38 I-48 December 2010

Appendix I 2 3 1 2 Standardized 0 Standardized 1 Abundance Index Abundance Index

-1 0

-2 -1

-3 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey American Shad Atlantic Tomc od 3 4 3

Standardized 2

Standardized 2

1 1

Abundance Index Abundance Index 0

0

-1 -1

-2 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Bay Anc hovy Blueback Herring 4 3 3 2 Standardized Standardized 2 1 1 0 Abundance Index Abundance Index 0 -1

-1 -2

-2 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey W eakfish W hite Catfish Outlier 2

1 Standardized 0

-1 Abundance Index

-2

-3

-4 0 10 20 30 Years of Survey W hite Perc h 1 Figure I-19. Riverwide population trends based on the abundance index assigned a large 2 level of potential negative impact December 2010 I-49 NUREG-1437, Supplement 38

Appendix I 1 The results of the two measurement metricsCPUE (number of RIS captured by the sampler 2 for a given volume of water derived by the NRC staff) and the abundance index provided by the 3 applicantwere combined for the assessment of riverwide population impacts. Table I-38 4 presents the numeric results compiled from Tables I-28, I-31, I-34, and I-37 above and used to 5 derive Table H-14 in Section H.3 in the SEIS Appendices.

6 Table I-38 Assessment of Riverwide Population Impacts CPUE Abundance Riverwide Species FSS BSS LRS Index Assessment Alewife 1 1 N/A 1 1.0 American Shad 4 1 N/A 4 3.0 Atlantic N/A N/A N/A N/A Unknown Menhaden Atlantic Sturgeon N/A N/A N/A N/A Unknown Atlantic Tomcod 4 4 1 4 3.3 Bay Anchovy 1 1 N/A 4 2.0 Blueback Herring 4 4 N/A 4 4.0 Bluefish 4 4 N/A 1 3.0 Gizzard Shad N/A N/A N/A N/A Unknown Hogchoker 4 4 N/A 1 3.0 Rainbow Smelt N/A 4 N/A 1 2.5 Shortnose N/A N/A N/A N/A Unknown Sturgeon Spottail Shiner 4 1 N/A 1 2.0 Striped Bass 1 1 N/A 1 1.0 Weakfish N/A 1 N/A 4 2.5 White Catfish N/A 4 N/A 4 4.0 White Perch 4 4 N/A 4 4.0 Blue Crab N/A N/A N/A N/A Unknown 7 I.2.2. Analysis of Strength of Connection 8 To determine whether the operation of the IP2 and IP3 cooling systems has the potential to 9 influence RIS populations near the facilities or within the lower Hudson River, the NRC staff 10 conducted a strength-of-connection analysis. Measurements used for this analysis include 11 monitoring data at IP2 and IP3 from 1975 to 1990 that provide information on impingement and 12 entrainment rates for RIS and River Segment 4 (Indian Point) population-density data from the 13 LRS, FSS and BSS.

14 For this analysis, the strength of connection was determined from the uncertainty associated 15 with estimating the difference in the RIS YOY population abundance with and without losses 16 from impingement and entrainment associated with IP2 and IP3 cooling systems. A Monte 17 Carlo simulation (n = 1000) was conducted to estimate the first and third quartiles of the 18 modeled relative cumulative difference in the population abundance achieved over a specified NUREG-1437, Supplement 38 I-50 December 2010

Appendix I 1 number of years with and without removal of eggs, larvae, and juveniles from entrainment and 2 impingement. A simple exponential model was used to estimate the annual juvenile population 3 abundance (Nt) as follows:

4 (1) 5 where t = 1 to 20 or 27 years; 6 N0 = the initial juvenile population abundance set to either 1000 or 1x108; 7 r = the population growth rate estimated from the slope from the linear model of 8 standardized YOY River Segment 4 (Indian Point) FSS or BSS density data (1979-2005);

9 = the level of variability in the density data which was estimated as the sum of the CV of 10 the annual 75th percentiles from the weekly catch density and the error mean square from the 11 linear regression; and 12 t = an independent Normal (0,1) random variable.

13 Two different values for the starting population parameter N0 and the extent of the number of 14 years simulated (20 or 27) were used to assess their impact on the simulation results. The 15 number of simulation runs (1000) should be large enough such that these two parameters will 16 not affect the results.

17 Equation (1) was used to model annual abundance of YOY RIS with the removal of eggs, 18 larvae, and juveniles from entrainment and impingement implicit in the parameters N0 and r.

19 Annual abundance of YOY RIS without losses of eggs, larvae, and juveniles from entrainment 20 and impingement was estimated using the same model form but with N0 and r replaced with 21 and (2) 22 where EMR and IMR are conditional mortality rates for entrainment and impingement; rUCL is the 23 upper 95 percent confidence limit of the linear slope; and CV is the coefficient of variation of the 24 annual 75th percentiles from the weekly catch density. The growth rate is divided by the CV in 25 the density data to provide an alternative growth rate closer to zero for negative values of r and 26 a slightly larger growth rate for positive values of r with the amount of increase dependent on 27 the magnitude of the variability. The divisor is set to 1 (allowing a maximum increase in growth 28 rate) when the CV is less than 1. The parameter EMR for each RIS was estimated from 29 entrainment and River Segment 4 field data supplied by the applicant (Entergy 2007b). The 30 parameter IMR for each RIS was estimated from published conditional impingement mortality 31 rates (CIMR; CHGEC 1999). Estimates for EMR assume 100 percent mortality while the IMR 32 assumes partial survival.

33 The parameter EMR was estimated as the ratio of the number entrained to the sum of the 34 standing crop of eggs, larvae, and juveniles in River Segment 4 (Indian Point) estimated from 35 the LRS, FSS, and BSS 1981 and 1983-1987 data. All three surveys were used because 36 entrainment of juveniles was proportionally greater during July and August than during May and 37 June which was when the majority of the sampling for the LRS took place (Table I-39 and 38 Figure 17a). Estimation of the number entrained and the river segment standing crop were 39 based on the calculations presented in Table I-40.

December 2010 I-51 NUREG-1437, Supplement 38

Appendix I 1 The number of RIS by life stage (i = eggs, yolk sac larvae, post-yolk sac larvae, juvenile, and 2 undetermined) entrained (Eijk) was calculated weekly (k = 2-35) for each year (j = 1981, 1983-3 1987) as 4 (3) 5 where 3 is the input mean weekly density entrained (pounds/m ) for a given RIS (Table I-40) 6 along with the associated volume of water withdrawn (1000 m3/min) at IP2 and IP3 (VIP2 and 7 VIP3, respectively). Seasonal numbers of RIS entrained were calculated by summing over life 8 stages and weeks. Season 1 (January - March) was only sampled in 1986, thus, the number of 9 fish entrained during that season was added to the totals for all other years.

10 11 The estimate of the River Segment 4 standing crop of each life stage was based on the 12 combined standing crop estimates from the LRS, FSS, and BSS (Tables I-40). The LRS and 13 FSS weekly standing crop was estimated as the weekly density of fish caught times the Indian 14 Point region river volume (208,336,266 m3). The BSS weekly standing crop was estimated as 15 the weekly density of fish caught times the Indian Point region shore zone surface area 16 (4,147,000 m2) divided by the area of a seine sample (450 m2). The total number of RIS at risk 17 from entrainment or impingement was calculated as the sum of those RIS entrained (or 18 impinged) and the RIS caught in the river. The annual standing crop of eggs, larvae, and 19 juveniles estimated in the vicinity of IP2 and IP3 based on the LRS, FSS, and BSS is presented 20 in Table I-41. The estimated number of each RIS entrained for the SOC analysis was 21 calculated from the mean density entrained (1981 and 1983-1987) at IP2 and IP3 (Table I-42).

22 The estimated EMR values can be compared to the riverwide CMRs (CHGEC 1999; Table I-43).

23 Impingement mortality for YOY RIS is greatest in July through December (Table I-44), however, 24 impingement data from 1981 through 1990 was not available by life stage. Thus, the parameter 25 IMR was estimated as the maximum plant specific cumulative CIMR (1984-1990; CHGEC 1999) 26 for an annual cohort from the juvenile life stage through the last age of impingement 27 vulnerability (Table I-45). The minimum value of IMR was set at 0.0005. The CIMR values are 28 based on the estimated number impinged and the Ristroph screen 8-hr mortality rate reported 29 by Fletcher (1990).

30 The relative cumulative difference in the population abundance achieved over a specified 31 number of years between models with and without the effects of entrainment and impingement 32 was estimated as the sum of the annual differences divided by N0 (1000 or 108) and the number 33 of years evaluated (20 or 27). One realization of the simulation using t = 27, N0 = 1000, and the 34 white perch parameters (Table I-46) highlights the annual difference achieved in the YOY 35 population abundance with and without entrainment and impingement effects (Figure I-121).

36 The distribution of the relative cumulative difference in the population abundance achieved from 37 all 1000 simulations using the white perch parameters is presented in Figure I-22. Negative 38 values occur when a single simulation has greater negative annual differences (i.e., greater 39 abundance with the model incorporating entrainment and impingement mortality, shown in black 40 in Figure I-21). If there was no variation in the model ( = 0), then all differences would be 41 positive. Allowing to be greater than 0 incorporates the variation observed in the YOY 42 population and the error in the linear model used to estimate population growth. If the range of 43 the first and third quartiles of the resulting distribution includes zero, then the effect of 44 entrainment and impingement was not large enough to be detected over the variation observed 45 in the population.

NUREG-1437, Supplement 38 I-52 December 2010

Appendix I 1 Four simulation series were conducted for each RIS using all possible pairs of the parameters t 2 and N0 (n = 1000 for each). All other model parameter values for a give RIS stayed the same 3 for each simulation series and are presented in Table I-46. The strength of connection was 4 determined to be low if the range of the first and third quartiles of the distribution of the relative 5 cumulative difference in YOY population abundance included zero for any of the simulation 6 series. The strength of connection was determined to be high if both quartiles were positive for 7 all parameter t and N0 pairs. The latter result occurs when the effect of entrainment and 8 impingement was consistently greater than the variation in the model.

9 The results and strength of connection conclusions of the Monte Carlo simulations (n = 1000) 10 for each pair of N0 (1000 and 108) and number of years modeled (20 and 27) are presented in 11 Table H-17 in Section H.1.3 of Appendix H and in Table I-47. In general, for a given RIS the 12 difference in the median simulation results for 20 verses 27 years modeled (t) decreased with 13 increasing initial abundance (N0). For N0 = 1000 and 1 x 108, the median difference between 14 the simulation results with a different number of years modeled was 3 percent across all RIS.

15 For t = 20 and 27 years, the median difference between the results of the simulations with 16 different initial abundance was 2 percent and 1 percent respectively across all RIS. Thus, the 17 number of simulations (n = 1000) was sufficient to conclude a strength of connection.

18 December 2010 I-53 NUREG-1437, Supplement 38

Appendix I 1 Table I-39. Percentage of Each Life Stage Entrained by Season and the Contribution of 2 Major Taxa Represented in the Samples. Calculations are based on the 75th percentile over 3 years (1981 and 1983-1987) of each seasons number of fish entrained. There was no 4 entrainment sampling in October - December.

Season 1 Season 2 Season 3 Life Stage 75th Percentile over Years Jan-Mar Apr-Jun Jul-Sep EGG 3% 20% 78% 210,801 x 106 Rainbow Smelt 99% 2% 0%

Bay Anchovy 0% 92% 100%

White Perch 0% 4% < 1%

Alosa species 1% 2% 0%

YOLK-SAC LARVA 8% 89% 3% 23,140 x 106 Atlantic Tomcod 100% 0% 0%

Herring Family 0% 91% < 1%

Bay Anchovy 0% 2% 94%

Striped Bass 0% 5% 1%

Hogchoker 0% 0% 3%

POST YOLK-SAC LARVA < 1% 52% 48% 618,393 x 106 Atlantic Tomcod 100% < 1% 0%

Alosa species 0% 37% < 1%

Bay Anchovy 0% 11% 58%

Anchovy Family 0% 2% 39%

White Perch 0% 12% 1%

Striped Bass 0% 17% 1%

Herring Family 0% 20% < 1%

JUVENILE 2% 44% 54% 10,989 x 106 White Perch 96% 10% 10%

Atlantic Tomcod 0% 67% 2%

Weakfish 0% 1% 50%

Bay Anchovy 0% 1% 17%

Rainbow Smelt 0% 9% 3%

Striped Bass 0% 6% 5%

Anchovy Family 0% 1% 4%

Alosa species 0% 2% 2%

White Catfish 4% < 1% 0%

Blueback Herring 0% < 1% 3%

UNDETERMINED STAGE 10% 77% 13% 4,469 x 106 Atlantic Tomcod 100% < 1% 0%

Morone species 0% 88% 2%

Bay Anchovy 0% 9% 83%

Anchovy Family 0% 0% 10%

Alosa species 0% 0% 4%

NUREG-1437, Supplement 38 I-54 December 2010

Appendix I Survey Week Jan-Mar 1 2 3 4 5 6 7 8 9 10 11 12 13 Apr-Jun 14 15 16 17 18 19 20 21 22 23 24 25 26 LRS-1981 LRS-1983 LRS-1984 LRS-1985 and 1986 LRS-1987 BSS-1987 Jul-Sep 27 28 29 30 31 32 33 34 35 36 37 38 39 LRS-1981 LRS-1983 LRS-1984 LRS-1985 -1987 BSS-1981 BSS-1983 BSS-1984 BSS-1985 and 1986 BSS-1987 FSS-1981 FSS-1983 FSS-1984-1986 FSS-1987 Oct-Dec 40 41 42 43 44 45 46 47 48 49 50 51 52 BSS-1981 BSS-1983 BSS-1984 BSS-1985 and 1986 BSS-1987 FSS-1981 FSS-1983 FSS-1984 FSS-1985 FSS-1986 FSS-1987 1

2 Figure I-20. Time Line of River Segment 4 Sampling Programs Used to Estimate EMR 3 (1981 and 1983-1987 Surveys). Shaded cells indicate a sampling event occurs within the 4 given week.

5 6

December 2010 I-55 NUREG-1437, Supplement 38

Appendix I 1 Table I-40. Method for Estimating Taxon-Specific Entrainment Mortality Rate (EMR) 2 Based on River Segment 4 Standing Crop for the Strength of Connection Analysis Property of Method Number Entrained River Segment 4 Standing Crop LRS density (by life stage) mean density organisms FSS density of YOY entrained by IP2 and IP3 BSS density of YOY Variables Input Volume of cooling water River Segment 4 volume (m3)

Data withdrawn by IP2 and IP3 River Segment 4 shorezone 3 2 (1000 m /min) surface area (m )

Frequency Per week of sampling Per week of sampling Sum of weekly estimates of Seasonal (Year Sum of weekly standing crop number of organisms entrained specific) estimates by IP2 and IP3 Sum of Season 1, 1986 with Sum of seasonal standing crop Annual each years totals from Season 2 Summary estimates for River Segment 4 and Season 3 Statistics 75th Percentile Annual Number Entrained EMR 75th Percentile (Annual Number Entrained + Annual Standing Crop)

Units of numerator and denominator of # of organisms EMR Years of Data 1981 and 1983-1987 1981 and 1983-1987 Eggs, Larvae, and Juveniles Life Stages Eggs, Larvae, and Juveniles (YOY)

Alewife, Blueback Herring, and unidentified Alosids treated collectively as River Herring Taxonomic Substitutions Unidentified Anchovy spp allocated to Bay Anchovy Unidentified Morone spp allocated proportionally to Striped Bass and White Perch 3

4 NUREG-1437, Supplement 38 I-56 December 2010

Appendix I 1 Table I-41. Estimated Annual Standing Crop of Eggs, Larvae, and Juvenile RIS Within 2 River Segment 4 (millions of fish) 3 Taxon 1981 1983 1984 1985 1986 1987 Alewife and Blueback Herring 239,387 1,357,568 1,038,155 78,176 353,533 21,619 American Shad 9,731 2,374 95,443 2,100 3,222 926 Atlantic Menhaden Unknown Unknown Unknown Unknown Unknown Unknown Atlantic Sturgeon Unknown Unknown Unknown Unknown Unknown Unknown Atlantic Tomcod 200,776 25,139 135,160 401,962 151,134 207,723 Bay Anchovy 2,075,519 1,139,353 1,190,819 1,545,273 497,132 1,885,743 Bluefish 465 1,158 851 200 513 1,348 Gizzard Shad Unknown Unknown Unknown Unknown Unknown 3.83 Hogchoker 1,882 587 1,057 1,116 3,521 6,384 Rainbow Smelt 1,341 841 16,111 992 46,771 21,926 Shortnose Sturgeon Unknown Unknown Unknown Unknown Unknown Unknown Spottail Shiner 5.81 0.103 0.0161 215 0.0387 0.0166 Striped Bass 1,336,073 625,737 627,731 79,755 405,668 291,361 Weakfish 1,473 3,547 15,306 3,495 1,245 985 White Catfish Unknown 0.0018 27.3 215 Unknown 31.9 White Perch 794,963 913,526 437,750 91,594 757,411 68,591 December 2010 I-57 NUREG-1437, Supplement 38

Appendix I 1 Table I-42. Annual Estimated Number of RIS Entrained at IP2 and IP3 (millions of fish)

Taxa 1981 1983 1984 1985 1986 1987 Alewife and Blueback Herring 20,159 119,801 181,006 954 186 44.6 American Shad 350 359 18,175 26.0 242 9.27 Atlantic Menhaden 0 0 0 0 0 0 Atlantic Sturgeon 0 0 0 0 0 0 Atlantic Tomcod 4,231 2,951 8,557 12,737 4,925 3,714 Bay Anchovy 1,241,061 352,177 467,558 344,483 182,493 236,713 Bluefish 0 0 3.88 19.7 0 0 Gizzard Shad 0 0 0 0 0 0 Hogchoker 3,188 2,168 961 745 585 185 Rainbow Smelt 6,089 6,090 7,146 6,126 10,952 6,857 Shortnose Sturgeon 0 0 0 0 0 0 Spottail Shiner 0 9.13 3.93 0 0 0 Striped Bass 85,626 43,256 49,716 20,495 78,666 33,076 Weakfish 3,130 4,154 9,485 2,062 631 102 White Catfish 7.23 7.23 10.8 7.23 10.5 7.23 White Perch 48,743 68,418 29,734 11,137 71,501 8,297 All fish taxa 1,446,376 795,342 888,363 403,092 463,644 288,208 2

3 NUREG-1437, Supplement 38 I-58 December 2010

Appendix I 1 Table I-43. Estimate of the River Segment 4 Entrainment Mortality Rate (EMR) and the 95 2 Percent Confidence Limits for the Riverwide Entrainment CMR (1974-1997)

Riverwide CMR 75th Percentile for Entrainment 75th Percentile at IP2 and IP3 Annual Number Taxa of Number at Risk EMR Lower 95 Upper 95 Entrained 9 9 (number x 10 ) percent percent (number x 10 ) Confidence Confidence Limit Limit Alewife and Blueback Herring 94.9 1003 0.095 0.00747 0.0324 American Shad 0.357 8.43 0.042 0 0.016696 Atlantic Menhaden 0 NA NA Not Modeled Atlantic Sturgeon 0 NA NA Not Modeled Atlantic Tomcod 7.65 210 0.036 0.152 0.234 Bay Anchovy 439 2064 0.213 0.0925 0.140 Bluefish 0.00291 1.08 0.003 Not Modeled Gizzard Shad 0 NA NA Not Modeled Hogchoker 1.87 4.83 0.386 Not Modeled Rainbow Smelt 7.07 27.4 0.258 Not Modeled Shortnose Sturgeon 0 NA NA Not Modeled Spottail Shiner 0.00295 0.00838 0.352 0.0802 0.104 Striped Bass 71.4 675 0.106 0.181 0.276 Weakfish 3.90 7.17 0.544 Not Modeled White Catfish 0.00965 0.0848 0.114 Not Modeled White Perch 63.5 840 0.076 0.0568 0.108 3

4 December 2010 I-59 NUREG-1437, Supplement 38

Appendix I 1 Table I-44. Percentage of Each Life Stage Impinged by Season and the Contribution of 2 Major Taxa Represented in the Samples. Note, because only two years had life stage 3 information available (1979 and 1980), calculation of the 75th percentile was based on the 4 weighted average of the ranked observations, (i.e., y = 0.25*X(1) + 0.75*X(2) where X(i) is the 5 ranked observation in increasing order).

Season 1 Season 2 Season 3 Season 4 th 75 Percentile Life Stage Jan-Mar Apr-Jun Jul-Sep Oct-Dec over Years Young-of-Year 0% 9% 43% 48% 3,214 x 103 Atlantic Tomcod 0% 98% 60% 1%

White Perch 0% 0% 16% 72%

American Shad 0% 0% 6% 1%

Blueback Herring 0% 0% 3% 24%

Weakfish 0% 0% 5% < 1%

Yearling 82% 17% 1% 1% 3,747 x 103 White Perch 95% 94% 60% 93%

Striped Bass 4% 1% 5% 1%

Atlantic Tomcod 1% < 1% 14% 1%

Alewife < 1% < 1% 12% 1%

Blueback Herring < 1% 1% 9% 3%

Older 19% 19% 53% 9% 1,320 x 103 White Perch 83% 41% 3% 5%

Bay Anchovy < 1% 15% 85% 40%

Rainbow Smelt 10% 18% 1% 12%

Hogchoker < 1% 20% 6% 16%

Alosa species < 1% < 1% < 1% 16%

6 7

NUREG-1437, Supplement 38 I-60 December 2010

Appendix I 1 Table I-45. Cumulative Conditional Impingement Mortality Rate Estimated by Year Class 2 for Indian Point1 Used to Estimate the Taxon-Specific Impingement Mortality Rate (IMR) 3 for the Strength of Connection Analysis. Note, these estimates include a correction for 4 partial survival.

Maximum RIS 1984 1985 1986 1987 1988 1989 1990

= IMR Alewife NA 0.002 0.002 0.001 0.001 0.001 NA 0.002 American Shad NA < 0.0005 < 0.0005 < 0.0005 < 0.0005 < 0.0005 < 0.0005 0.0005 Atlantic Tomcod NA NA 0.008 0.030 0.005 0.003 0.004 0.030 Bay Anchovy NA 0.002 0.004 < 0.0005 < 0.0005 < 0.0005 < 0.0005 0.004 Blueback Herring NA 0.003 0.004 0.002 0.001 0.001 NA 0.004 Bluefish NA NA NA NA NA NA NA 0.0005 Hogchoker NA NA NA NA NA NA NA 0.0005 Rainbow Smelt NA NA NA NA NA NA NA 0.0005 Spottail Shiner NA 0.002 0.001 0.007 < 0.0005 0.001 < 0.0005 0.007 Striped Bass 0.008 0.003 0.005 0.005 < 0.0005 < 0.0005 0.001 0.008 Weakfish NA NA NA NA NA NA NA 0.0005 White Catfish NA NA NA NA NA NA NA 0.0005 White Perch NA 0.026 0.032 0.012 0.011 0.014 0.007 0.032 1

5 CHGEC (1999) Appendix VI.

6 NA = Not available.

7 Table I-46. Parameter Values Used in the Monte Carlo Simulation Linear Upper 95% Error Mean CV of Survey RIS Slope Confidence Limit Square from Density Data EMR IMR Used (r) of the Slope Regression (19 79-1990)

Alewife BSS -0.030 -0.014 0.570 1.245 0.095 0.0020 American Shad BSS -0.069 -0.059 0.350 0.744 0.042 0.0005 Atlantic Tomcod FSS -0.040 -0.026 0.490 1.035 0.036 0.0300 Bay Anchovy FSS -0.075 -0.061 0.505 0.598 0.213 0.0040 Blueback Herring BSS -0.024 -0.009 0.530 1.488 0.095 0.0040 Bluefish BSS -0.038 -0.022 0.580 0.692 0.003 0.0005 Hogchoker FSS -0.034 -0.018 0.580 1.679 0.386 0.0005 Rainbow Smelt FSS 0.012 0.041 0.576 1.452 0.258 0.0005 Spottail Shiner BSS -0.017 -0.005 0.430 1.293 0.352 0.0070 Striped Bass BSS 0.040 0.052 0.420 0.528 0.106 0.0080 Weakfish FSS -0.047 -0.031 0.560 1.085 0.544 0.0005 White Catfish FSS 0.007 0.010 0.100 3.520 0.114 0.0005 White Perch BSS -0.062 -0.045 0.610 0.848 0.076 0.0320 8

December 2010 I-61 NUREG-1437, Supplement 38

Appendix I 1

2 Figure I-21. One Realization of the Monte Carlo Simulation using Parameter Estimates 3 for White Perch. Gray and black shading represents positive and negative annual differences 4 in abundance between the two models.

Q1 Q3 350 Frequency of Occurrence 300 250 200 150 Frequency 100 50 0

-0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 Relative Difference in Cumulative Abundance 5

6 Figure I-22. Distribution of the Relative Difference in Cumulative Abundance from the 7 Monte Carlo Simulation (n = 1000) using Parameter Estimates for White Perch. The first 8 and third quartiles (Q1 and Q3) of the distribution are indicated with dashed lines.

9 NUREG-1437, Supplement 38 I-62 December 2010

Appendix I 1 Table I-47. Quartiles of the Relative Difference in Cumulative Abundance and 2 Conclusions for the Strength-of-Connection From the Monte Carlo Simulation Number N0 = 1000 N0 = 1 x 108 Strength Taxa of of Connection Years Median Q1 Q3 Median Q1 Q3 Conclusion 20 0.33 0.11 0.59 0.32 0.06 0.55 Alewife High 27 0.36 0.15 0.56 0.33 0.14 0.53 American 20 0.07 -0.04 0.18 0.09 -0.02 0.20 Low Shad 27 0.08 -0.01 0.16 0.08 0.00 0.16 Atlantic 20 0.14 -0.04 0.32 0.17 -0.01 0.38 Low Tomcod 27 0.18 0.04 0.32 0.18 0.02 0.33 20 0.21 0.09 0.32 0.20 0.08 0.31 Bay Anchovy High 27 0.18 0.10 0.26 0.18 0.10 0.27 Blueback 20 0.30 0.02 0.60 0.28 0.02 0.60 High Herring 27 0.43 0.16 0.67 0.40 0.14 0.64 20 0.13 -0.04 0.29 0.14 -0.03 0.30 Bluefish Low 27 0.14 0.02 0.29 0.16 0.01 0.30 20 0.71 0.39 1.05 0.74 0.41 1.10 Hogchoker High 27 0.81 0.53 1.10 0.77 0.46 1.06 Rainbow 20 0.77 0.33 1.25 0.81 0.35 1.34 High Smelt 27 0.93 0.52 1.38 1.03 0.63 1.46 Spottail 20 0.59 0.33 0.88 0.58 0.23 0.90 High Shiner 27 0.61 0.36 0.88 0.62 0.35 0.87 20 0.45 0.09 0.76 0.45 0.12 0.78 Striped Bass High 27 0.62 0.27 1.02 0.66 0.31 1.01 20 0.62 0.39 0.87 0.66 0.42 0.90 Weakfish High 27 0.63 0.43 0.84 0.64 0.43 0.83 20 0.19 -0.36 0.76 0.05 -0.46 0.66 White Catfish Low 27 0.09 -0.41 0.58 0.09 -0.43 0.58 20 0.16 0.01 0.32 0.20 0.04 0.35 White Perch High 27 0.18 0.06 0.31 0.20 0.07 0.31 3 I.3 Cumulative Impacts on Aquatic Resources 4 Zebra Mussels 5 For this analysis, the 75th percentile of the weekly FSS and BSS density and CPUE data from 6 Region 12 (Albany) were used to evaluate the population trend LOE for impacts associated with 7 a zebra mussel invasion. Data for white perch, blueback herring, alewife, American shad, white 8 catfish, spottail shiner, and striped bass were used in the analysis because all have high 9 densities of YOY within this region. The data were standardized based on the first 5-year mean 10 and the standard deviation of all annual results (1979 - 2005). Only weeks 27 to 43 were used 11 in the analysis for the FSS and weeks 22 to 43 for the BSS survey, so that most years 12 contained observations from the months of July through October and June through October for December 2010 I-63 NUREG-1437, Supplement 38

Appendix I 1 each survey, respectively. Effects associated with changes in gear types for the FSS (1985) 2 were also considered.

3 Simple linear regression and segmented regression with a single join point were fit to the annual 4 measure of abundance for each RIS, as described in Section H.3. The model with the smallest 5 MSE was chosen as the better fit to the data. If the best-fit model was the simple linear 6 regression and the slope was statistically significantly less than 0 ( = 0.05), a negative 7 population trend was considered detected. If the slope was not significantly different from 0, 8 then a population trend was not considered detected. If the best-fit model was the segmented 9 regression and either slope, S1 or S2, was statistically significantly less than 0 ( = 0.05), then a 10 negative population trend was considered detected. If both slopes S1 and S2 were not 11 significantly different from 0 ( = 0.05), then the trend was not considered detected.

12 Data collected between 1985 and 2005 are not temporally disconnected from the 1991 invasion 13 of zebra mussels. However, because of earlier impacts, there is a potential that fish populations 14 stabilized pre-1985 to a lower abundance level. If changes in gear types have affected the 15 observed population response, only data post-1985 were used. For this analysis, data were 16 standardized with the average of 1985 to 1989 and the standard deviation of all data between 17 1985 and 2005. This analysis was used only when the observed response from all data was 18 biologically different from the BSS population density trend and had a decline associated with 19 the gear change.

20 A visual and statistical comparison of the river-segment FSS standardized density with the BSS 21 standardized density (Table I-48) suggested that the trends for blueback herring, striped bass, 22 and white perch were not biologically different (Figure I-23). Observations from both surveys 23 overlap and cross over each other. The post-1985 FSS observations for spottail shiner 24 (proportion FSS < BSS = 0.14; p = 0.013) were generally greater than the BSS observations 25 and did not show a decline associated with the gear change relative to the BSS (Figure I-23).

26 Thus, for these RIS, all of the FSS data (1979-2005) were used in the regression analysis. The 27 FSS density data for alewife and American shad, however, did show a potential gear effect 28 (Figure I-24), and a post-1985 analysis was conducted.

29 30 Table I-48. Evaluation of Gear Effect on FSS River Segment 12 Population Density 31 Trends Proportion FSS < BSS Absolute Medan Absolute Difference Significance Difference Taxa of Conclusion 1979-1984 1985-2005 in 1979-1984 1985-2005 Sign Test Proportions Alewife 0.40 1.00 0.60 1.11 1.19 < 0.001 Separate Analysis American Shad 0.60 0.90 0.30 0.89 0.94 0.095 Separate Analysis Blueback Herring 0.40 0.71 0.31 1.36 0.57 0.192 Not Biol. Different Spottail Shiner 0.40 0.14 0.26 0.67 0.78 0.013 FSS > BSS Striped Bass 0.40 0.29 0.11 0.56 0.57 0.332 Not Biol. Different White Perch 0.40 0.95 0.55 0.86 0.44 < 0.001 Not Biol. Different NUREG-1437, Supplement 38 I-64 December 2010

Appendix I FSS gear change FSS gear change 3 3 Standardized Density Standardized Density 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Blueback Herring BSS-D Spottail Shiner BSS-D Blueback Herring FSS-D Spottail Shiner FSS-D FSS gear change FSS gear change 3 3 Standardized Density Standardized Density 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Striped Bass BSS-D White Perch BSS-D Striped Bass FSS-D White Perch FSS-D 1 Figure I-23. River Segment 12 population trends based on the BSS and FSS 2 standardized density (D) not considered to be affected by the gear change December 2010 I-65 NUREG-1437, Supplement 38

Appendix I FSS gear change FSS gear change 3 3 Standardized Density Standardized Density 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Alewife BSS-D American Shad BSS-D Alewife FSS-D American Shad FSS-D 1 Figure I-24. River Segment 12 population trends based on the BSS and FSS standardized 2 density (D) for which the FSS may indicate a gear difference 3 The following tables are the intermediate analyses for the assessment of population trends 4 associated with fish density sampled from River Segment 12 (Albany). Results of these river-5 segment trend analyses are compiled in Table H-19 in Section H.2 of the Appendix H. The data 6 used in this analysis, in order of appearance, were the standardized 75th percentile of the 7 weekly fish density for a given year collected from the FSS (Table I-49, Table I-50, Table I-51, 8 and Figure I-25) and BSS (Table I-52, Table I-53, Table I-54, and Figure I-26).

9 Two extreme outliers (values greater than 2 standard deviations away from the mean) were 10 removed from the FSS spottail shiner density regression analysis (Tables I-50 and I-51). Three 11 extreme outliers were also removed from the FSS striped bass density (values greater than 12 2 standard deviations away from the mean) regression analysis and one extreme outlier from 13 the FSS white catfish density (value greater than 2 standard deviations away from the mean) 14 regression analysis because of the influence these data had on the regression results. The 15 results of the regression models with the observations removed were more conservative and 16 were used for the trend analysis.

17 One extreme outlier (value greater than 2 standard deviations away from the mean) was 18 removed from the BSS alewife density regression analysis (Tables I-53 and I-54). One value 19 was also removed from the BSS American shad density (value greater than 1.6 standard 20 deviations away from the mean) regression analysis, as well as one extreme outlier from the 21 BSS spottail shiner density (value greater than 3 standard deviations away from the mean) 22 regression analysis and two extreme outliers from the BSS striped bass density (values greater 23 than 2 standard deviations away from the mean) regression analysis because of the influence 24 these data had on the regression results. The results of the regression models with the 25 observations removed were more conservative and were used for the trend analysis.

NUREG-1437, Supplement 38 I-66 December 2010

Appendix I 1 Table I-49. Initial Values for the Nonlinear Fit of the Segmented Regression Models 2 Used in FSS Population Trends of YOY Fish Density from River Segment 12 3

Taxa Intercept Slope 1 Join Point Slope 2 Alewife (1985-2005) 0.0 0.0 1994 -0.1 American Shad (1985-2005) 0.0 0.0 1994 -0.1 Blueback Herring (All data) 0.5 -0.08 1990 -0.02 Spottail Shiner (2 values removed) 0.0 0.3 1991 -0.3 Striped Bass (3 values removed) -0.08 0.07 1990 0.0 White Catfish (1 value removed) -0.2 0.08 1986 0.1 White Perch (All data) 0.4 0.0 1982 0.0 4

5 Table I-50. Competing Models Used To Characterize the Standardized River Segment 12 6 (Albany) Fall Juvenile Survey Population Trends of YOY Fish Density Linear Regression Segmented Regression 95 percent CI Join 95 percent CI Species MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife (1985-2005) 1.01 0.031 +/- 0.036 0.409 0.95 -5.66 to 2.00 1986 -0.028 to 0.139 American Shad (1985-2005) 0.95 -0.059 +/- 0.034 0.102 0.90 -0.216 to 0.475 1992 -0.271 to -0.0001 Blueback Herring 0.73 -0.088 +/- 0.018 < 0.001 0.44 -0.520 to -0.238 1987 -0.042 to 0.034 Spottail Shiner (All data) 1.02 -0.007 +/- 0.025 0.777 1.05 -0.553 to 0.695 1984 -0.095 to 0.059 Spottail Shiner (2 outliers removed) 0.65 -0.025 +/- 0.017 0.158 0.59 -0.041 to 0.160 1991 -0.188 to -0.010 Striped Bass (All data) 0.975 0.037 +/- 0.024 0.139 0.94 0.004 to 0.155 1999 -0.568 to 0.171 Striped Bass (3 outliers removed) 0.40 0.012 +/- 0.010 0.253 0.42 -1.20 to 1.30 1980 -0.014 to 0.037 White Catfish (All data) 0.982 -0.034 +/- 0.024 0.171 1.00 -0.118 to 0.123 1994 -0.283 to 0.096 White Catfish (1 outlier -1.15e+006 to removed) 0.88 -0.022 +/- 0.022 0.327 0.92 1.15e+006 1979 -0.070 to 0.026 White Perch 0.84 -0.071 +/- 0.021 0.002 0.58 -0.972 to -0.212 1984 -0.049 to 0.031 7

December 2010 I-67 NUREG-1437, Supplement 38

Appendix I 1 Table I-51. River Segment 12 (Albany) Assessment of the Level of Potential Negative 2 Impact Based on the Standardized FSS Density Level of Potential Best General Negative Species Fit Trend Impact S1 = 0 Alewife SR S2 = 0 1 S1 = 0 American Shad SR S2 < 0 4 S1 < 0 Blueback Herring SR S2 = 0 4 Spottail Shiner (All data) LR S=0 1 Spottail Shiner S1 = 0 (2 outliers removed) SR S2 < 0 4 Striped Bass S1 > 0 (All data) SR S2 = 0 1 Striped Bass (3 outliers removed) LR S=0 1 White Catfish (All data) LR S=0 1 White Catfish (1 outlier removed) LR S=0 1 S1 < 0 White Perch SR S2 = 0 4 3 LR = Linear Regression; SR = Segmented Regression.

NUREG-1437, Supplement 38 I-68 December 2010

Appendix I 1

FSS 3rd Q Standardized Density FSS 3rd Q Standardized Density Gear Change 3 2 2 1 1

0 0

-1

-1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey American Shad 85-05 Blueback Herring FSS 3rd Q Standardized Density FSS 3rd Q Standardized Density 4 3 3 2 1

2 0

1

-1 0 -2

-1 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Spottail Shiner Outlier White Perch 2

3 Figure I-25. River Segment 12 (Albany) population trends based on the FSS standardized 4 density assigned a large level of potential negative impact 5 Table I-52. Initial Values for the Nonlinear Fit of the Segmented Regression Models 6 Used in BSS Population Trends of YOY Fish Density from River Segment 12 7

Taxa Intercept Slope 1 Join Point Slope 2 Alewife (1 value removed) -0.04 -0.20 1990 0.020 Blueback Herring (All data) 0.50 0.07 1990 -0.080 Spottail Shiner (1 value removed) 1.25 -0.80 1982 0.000 Striped Bass (2 values removed) 0.18 -0.04 1984 0.040 White Perch (All data) 0.30 -0.12 1991 -0.050 December 2010 I-69 NUREG-1437, Supplement 38

Appendix I 1 Table I-53. Competing Models Used To Characterize the Standardized River Segment 12 2 (Albany) Beach Seine Survey Population Trends of YOY Fish Density Linear Regression Segmented Regression 95 percent CI Join 95 percent CI Species MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife (All data) 1.01 -0.020 +/- 0.025 0.440 1.03 -0.877 to 0.472 1984 -0.073 to 0.071 Alewife (1 outlier removed) 0.78 -0.018 +/- 0.019 0.373 0.74 -0.310 to 0.027 1989 -0.039 to 0.120 American Shad (All data) 0.91 -0.056 +/- 0.023 0.020 Did Not Converge American Shad (1 value removed) 0.81 -0.055 +/- 0.020 0.012 Did Not Converge Blueback Herring 0.87 -0.066 +/- 0.022 0.005 0.78 -0.221 to -0.060 1996 -0.078 to 0.279 Spottail Shiner (All data) 1.02 0.007 +/- 0.025 0.769 1.05 -1.23 to 0.765 1982 -0.050 to 0.087 Spottail Shiner (1 outlier removed) 0.66 -0.021 +/- 0.017 0.232 0.68 -1.06 to 0.704 1982 -0.059 to 0.032 Striped Bass (All data) 0.99 0.030 +/- 0.025 0.226 1.02 -0.787 to 0.544 1984 -0.024 to 0.117 Striped Bass (2 outliers removed) 0.61 0.020 +/- 0.015 0.211 0.59 -0.483 to 0.148 1984 -0.003 to 0.088 White Perch 0.94 -0.048 +/- 0.023 0.048 0.92 -0.229 to -0.003 1994 -0.100 to 0.216 NUREG-1437, Supplement 38 I-70 December 2010

Appendix I 1 Table I-54. River Segment 12 (Albany) Assessment of the Level of Potential Negative 2 Impact Based on the Standardized BSS Density Level of Potential Species Best General Negative Fit Trend Impact Alewife (All data) LR S=0 1 S1 = 0 Alewife (1 value removed)

SR S2 = 0 1 American Shad (All data) LR S<0 4 American Shad (1 value removed) LR S<0 4 S1 < 0 Blueback Herring SR S2 = 0 4 Spottail Shiner (All data) LR S=0 1 Spottail Shiner (1 value removed) LR S=0 1 Striped Bass (All data) LR S=0 1 S1 = 0 Striped Bass (2 value removed)

SR S2 = 0 1 S1 < 0 White Perch SR S2 = 0 4 3 LR = Linear Regression; SR = Segmented Regression.

December 2010 I-71 NUREG-1437, Supplement 38

Appendix I 2 2 1

BSS 3rd Q Density BSS 3rd Q Density 1

0 0

-1

-1

-2

-2 -3

-3 -4 0 10 20 30 0 10 20 30 Years of Survey Years of Survey American Shad Outlier Blueback Herring 2

BSS 3rd Q Density 1

0

-1

-2

-3 0 10 20 30 Years of Survey White Perch 1 Note: Design Restricted 2 Figure I-26. River Segment 12 (Albany) population trends based on the BSS standardized 3 density assigned a large level of potential negative impact 4 A visual and statistical comparison of the river-segment FSS standardized CPUE with the BSS 5 standardized density (Table I-55) suggested that the trends were not biologically different for 6 blueback herring, spottail shiner, striped bass, and white perch (Figure I-27). Observations from 7 both surveys overlap and cross over each other. Thus, for these RIS, all of the FSS data 8 (1979-2005) were used in the regression analysis. The FSS CPUE data for alewife and 9 American shad, however, did show a potential gear effect (Figure I-28), and a post-1985 10 analysis was conducted.

11 NUREG-1437, Supplement 38 I-72 December 2010

Appendix I 1 Table I-55. Evaluation of Gear Effect on FSS CPUE Trends for River Segment 12 Proportion FSS < BSS Absolute Medan Absolute Difference Significance Difference Taxa of Conclusion 1979-1984 1985-2005 in 1979-1984 1985-2005 Sign Test Proportions Alewife 0.50 1.00 0.50 1.08 1.22 < 0.001 Separate Analysis American Shad 0.67 0.90 0.24 0.74 1.11 0.01 Separate Analysis Blueback Herring 0.33 0.67 0.33 1.44 0.62 0.33 Not Biol. Different Spottail Shiner 0.33 0.33 0.00 1.09 0.49 0.67 Not Biol. Different Striped Bass 0.33 0.24 0.10 0.45 0.53 0.33 Not Biol. Different White Perch 0.50 0.76 0.26 0.83 0.87 0.09 Not Biol. Different FSS gear change FSS gear change Standardized Density or CPUE Standardized Density or CPUE 3 3 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Blueback Herring BSS-D Spottail Shiner BSS-D Blueback Herring FSS-C Spottail shiner FSS-C FSS gear change FSS gear change Standardized Density or CPUE Standardized Density or CPUE 3 3 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Striped Bass BSS-D W hite Perch BSS-D Stripped Bass FSS-C W hite Perch FSS-C 2 Note: All data were used in WOE analysis.

December 2010 I-73 NUREG-1437, Supplement 38

Appendix I 1 Figure I-27. River Segment 12 population trends based on the FSS standardized CPUE 2 (C) and BSS density (D) not considered biologically different FSS gear change FSS gear change Standardized Density or CPUE Standardized Density or CPUE 3 3 2 2 1 1 0 0

-1 -1

-2 -2

-3 -3 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Alewife BSS-D American Shad BSS-D Alewife FSS-C American Shad FSS-C 3

4 Note: Post-1985 data were analyzed for WOE analysis.

5 Figure I-28. River Segment 12 population trends based on the FSS standardized CPUE 6 (C) and BSS density (D) for which the FSS may indicate a gear difference 7 The following tables are the intermediate analyses for the assessment of population trends 8 associated with fish CPUE sampled from River Segment 12 (Albany). Results of these river-9 segment trend analyses are compiled in Table H-19 in Section H.2 of Appendix H. The data 10 used in this analysis were the standardized 75th percentile of the weekly fish CPUE for a given 11 year collected from the FSS (Table I-56, Table I-57, Table I-58, and Figure I-27.).

12 13 One extreme outlier (value greater than 3 standard deviations away from the mean) was 14 removed from the FSS spottail shiner CPUE regression analysis (Tables I-56 and I-57), and one 15 extreme outlier was removed from the FSS white catfish CPUE (value greater than 2 standard 16 deviations away from the mean) regression analysis because of the influence these data had on 17 the regression results. The results of the regression models with the observations removed 18 were more conservative and were used for the trend analysis.

19 NUREG-1437, Supplement 38 I-74 December 2010

Appendix I 1 Table I-56. Initial Values for the Nonlinear Fit of the Segmented Regression Models 2 Used on FSS CPUE Trends for YOY Fish from River Segment 12 3

Taxa Intercept Slope 1 Join Point Slope 2 Alewife (1985-2005) 0.00 0.00 1994 -0.10 American Shad (1985-2005) 0.00 0.00 1994 -0.09 Blueback Herring (All data) 0.50 -0.08 1990 -0.02 Spottail Shiner (1 value removed) 1.25 -0.08 1982 0.00 Striped Bass (All data) -0.08 0.07 1990 0.00 White Catfish (1 value removed) 0.40 0.06 1988 0.00 White Perch (All data) 0.30 0.00 1982 0.00 4

5 Table I-57 Competing Models Used To Characterize the Standardized River Segment 12 6 (Albany) Fall Juvenile Survey Population Trends of YOY Fish CPUE Linear Regression Segmented Regression 95 percent CI Join 95 percent CI Species MSE Slope p-value MSE Slope 1 Point Slope 2 Alewife (1985-2005) 1.00 0.033 +/- 0.036 0.371 0.96 -0.185 to 0.083 1999 -0.108 to 0.656 American Shad (1985-2005) 0.94 -0.066 +/- 0.034 0.064 0.96 -0.342 to 0.385 1992 -0.247 to 0.046 Blueback Herring 0.72 -0.089 +/- 0.018 < 0.001 0.38 -0.484 to -0.282 1987 -0.035 to 0.037 Spottail Shiner (All data) 0.91 -0.057 +/- 0.023 0.018 Did Not Converge Spottail Shiner (1 outlier removed) 0.52 -0.038 +/- 0.013 0.008 0.53 -2.89 to 2.14 1980 -0.066 to -0.002 Striped Bass 0.98 0.034 +/- 0.024 0.168 0.95 -0.010 to 0.162 1997 -0.415 to 0.180 White Catfish (All data) 0.91 -0.056 +/- 0.023 0.020 Did Not Converge White Catfish (1 outlier removed) 0.72 -0.042 +/- 0.018 0.031 0.68 -0.325 to 1.14 1982 -0.111 to -0.018 White Perch 0.67 -0.095 +/- 0.017 < 0.001 0.64 -0.391 to -0.052 1987 -0.116 to 0.003 December 2010 I-75 NUREG-1437, Supplement 38

Appendix I Table I-58. River Segment 12 (Albany) Assessment of the Level of Potential Negative Impact Based on the Standardized FSS CPUE Level of Potential Best General Negative Species Fit Trend Impact S1 = 0 Alewife SR S2 = 0 1 American Shad LR S=0 1 S1 < 0 Blueback Herring SR S2 = 0 4 Spottail Shiner (All data) LR S<0 4 Spottail Shiner (1 outlier removed) LR S<0 4 S1 = 0 Striped Bass SR S2 = 0 1 White Catfish (All data) LR S<0 4 S1 = 0 White Catfish (1 outlier removed) SR S2 < 0 4 S1 < 0 White Perch SR S2 = 0 4 1 LR = Linear Regression; SR = Segmented Regression.

NUREG-1437, Supplement 38 I-76 December 2010

Appendix I 1.5 4 1.0 3

FSS 3rd Q CPUE FSS 3rd Q CPUE 0.5 0.0 2

-0.5 1

-1.0

-1.5 0

-2.0

-1

-2.5

-3.0 -2 0 10 20 30 0 10 20 30 Years of Survey Years of Survey Blueback Herring Spottail shiner Outlier 3 2 2 1 FSS 3rd Q CPUE FSS 3rd Q CPUE 0

1

-1 0

-2

-1 -3

-2 -4 0 10 20 30 0 10 20 30 Years of Survey Years of Survey White Catfish Outlier White Perch 1

2 Note: Design Restricted.

3 Figure I-29. River Segment 12 (Albany) population trends based on the FSS standardized 4 CPUE assigned a large level of potential negative impact 5 The WOE analysis for River Segment 12, Albany, for all population trend data post-1991 is 6 presented in Table I-59. This table is a compilation of Tables I-51, I-54, and I-58 and was used 7 to derive Table H-21 in Section H.2 in the Appendix H of this SEIS.

8 December 2010 I-77 NUREG-1437, Supplement 38

Appendix I 1 Table I-59. River Segment 12 (Albany) Assessment of the Level of Potential Negative 2 Impact Following Zebra Mussel Invasion in 1991 Based on the Standardized FSS and 3 BSS Density and FSS CPUE Level of Potential Species Trend Post-1991 Negative Impact Post- 1991 FSS Density Alewife S2 = 0 1 American Shad S2 < 0 4 Blueback Herring S2 = 0 1 Spottail Shiner S2 < 0 4 Striped Bass S=0 1 White Catfish S=0 1 White Perch S2 = 0 1 BSS Density Alewife S2 = 0 1 American Shad S<0 4 Blueback Herring S2 = 0 1 Spottail Shiner S=0 1 Striped Bass S2 = 0 1 White Perch S2 = 0 1 FSS CPUE Alewife S2 = 0 1 American Shad S=0 1 Blueback Herring S2 = 0 1 Spottail Shiner S<0 4 Striped Bass S2 = 0 1 White Catfish S2 < 0 4 White Perch S2 = 0 1 4 Water Quality and Temperature 5 Both water quality and water temperature can act to shift RIS densities into adjacent river 6 segments based on specific life stage needs. Water quality changes have been occurring over 7 the past decade (Section 2.2.5 of the SEIS), and water temperatures have been increasing over 8 the last 100 years (Figure I-31). An analysis of RIS distributional change within the Hudson 9 River was conducted by comparing the first and last 5-year mean densities from the survey that 10 was most efficient at catching a given RIS. Striped bass (Figure I-32), alewife (Figure I-33),

11 spottail shiner (Figure I-34), hogchoker (Figure I-35), and white perch (Figure I-36) all appear to 12 have shifted slightly upriver, while the bay anchovy has shifted slightly downriver (Figure I-37).

13 All other RIS that could be evaluated (American shad, Atlantic tomcod, blueback herring, 14 bluefish, and weakfish) did not show a change in their distributions. It is not possible from these 15 data to determine what might have influenced these shifts.

NUREG-1437, Supplement 38 I-78 December 2010

Appendix I 1

2 Source: Hansen et al. 2006.

3 Figure I-31. Historical trend in global land and ocean temperature Striped bass 3

2 Standardized Mean Density 1

0

-1

-2

-3 0 1 2 3 4 5 6 7 8 9 10 11 12 River Segment 1st 5-yr mean Last 5-yr Mean 4

5 Figure I-32. Relative density of YOY striped bass from the BSS 1979-1983 and 2001-6 2005; data within each river segment of the Hudson River December 2010 I-79 NUREG-1437, Supplement 38

Appendix I Alewife 3

2 Standardized Mean Density 1

0

-1

-2

-3 0 1 2 3 4 5 6 7 8 9 10 11 12 River Segment 1st 5-yr mean Last 5-yr Mean 1

2 Figure I-33. Relative density of YOY alewife from the BSS 1979-1983 and 2001-2005; 3 data within each river segment of the Hudson River Spottail shiner 3

2 Standardized Mean Density 1

0

-1

-2

-3 0 1 2 3 4 5 6 7 8 9 10 11 12 River Segment 1st 5-yr mean Last 5-yr Mean 4

5 Figure I-34. Relative density of YOY spottail shiner from the BSS 1979-1983 and 2001-6 2005; data within each river segment of the Hudson River NUREG-1437, Supplement 38 I-80 December 2010

Appendix I Hogchoker 3

2 Standardized Mean Density 1

0

-1

-2

-3 0 1 2 3 4 5 6 7 8 9 10 11 12 River Segment 1st 5-yr mean Last 5-yr Mean 1

2 Figure I-35. Relative density of YOY hogchoker from the FSS 1979-1983 and 2001-2005; 3 data within each river segment of the Hudson River W hite perch 3

2 Standardized Mean Density 1

0

-1

-2

-3 0 1 2 3 4 5 6 7 8 9 10 11 12 River Segment 1st 5-yr mean Last 5-yr Mean 4

5 Figure I-36. Relative density of YOY white perch from the BSS 1979-1983 and 2001-2005; 6 data within each river segment of the Hudson River December 2010 I-81 NUREG-1437, Supplement 38

Appendix I Bay anchovy 3

2 Standardized Mean Density 1

0

-1

-2

-3 0 1 2 3 4 5 6 7 8 9 10 11 12 River Segment 1st 5-yr mean Last 5-yr Mean 1

2 Figure I-37. Relative density of YOY bay anchovy from the FSS 1979-1983 and 2001-3 2005; data within each river segment of the Hudson River 4

NUREG-1437, Supplement 38 I-82 December 2010

Appendix I 1 I.4 References 2 Applied Science Associates (ASA). 1999. 1996 Year Class Report for the Hudson River 3 Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, Inc.;

4 Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New York 5 Power Authority; and Niagara Mohawk Power Corporation. December 1999. ADAMS 6 Accession No. ML083420045.

7 Applied Science Associates (ASA). 2001a. 1997 Year Class Report for the Hudson River 8 Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, Inc.;

9 Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New York 10 Power Authority; Niagara Mohawk Power Corporation; and Southern Energy New York.

11 January 2001. ADAMS Accession No. ML083420045.

12 ASA Analysis and Communication (ASA). 2001b. 1998 Year Class Report for the Hudson 13 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 14 Inc.; Central Hudson Gas and Electric Corporation; Dynegy Roseton LLC; Entergy Indian Point 15 3 LLC; Mirant Bowline LLC; New York Power Authority; and Niagara Mohawk Power 16 Corporation. July 2001.

17 ASA Analysis and Communication (ASA). 2002. 1999 Year Class Report for the Hudson River 18 Estuary Monitoring Program. Prepared for Dynegy Roseton L.L.C.; Entergy Nuclear Indian 19 Point 2 L.L.C.; Entergy Nuclear Indian Point 3 L.L.C.; and Mirant Bowline L.L.C. August 2002.

20 ADAMS Accession No. ML083420076.

21 ASA Analysis and Communication (ASA). 2003. 2000 Year Class Report for the Hudson River 22 Estuary Monitoring Program. Prepared for Dynegy Roseton L.L.C.; Entergy Nuclear Indian 23 Point 2 L.L.C.; Entergy Nuclear Indian Point 3 L.L.C.; and Mirant Bowline L.L.C. June 2003.

24 ADAMS Accession No. ML083420089.

25 ASA Analysis and Communication (ASA). 2004a. 2001 Year Class Report for the Hudson 26 River Estuary Monitoring Program. Prepared for Dynegy Roseton L.L.C.; Entergy Nuclear 27 Indian Point 2 L.L.C.; Entergy Nuclear Indian Point 3 L.L.C.; and Mirant Bowline L.L.C.

28 April 2004.

29 ASA Analysis and Communication (ASA). 2004b. 2002 Year Class Report for the Hudson 30 River Estuary Monitoring Program. Prepared for Dynegy Roseton L.L.C.; Entergy Nuclear 31 Indian Point 2 L.L.C.; Entergy Nuclear Indian Point 3 L.L.C.; and Mirant Bowline L.L.C.

32 October 2004.

33 ASA Analysis and Communication (ASA). 2005. 2003 Year Class Report for the Hudson River 34 Estuary Monitoring Program. Prepared for Dynegy Roseton L.L.C.; Entergy Nuclear Indian 35 Point 2 L.L.C.; Entergy Nuclear Indian Point 3 L.L.C.; and Mirant Bowline L.L.C. February 2005.

36 ASA Analysis and Communication (ASA). 2006. 2004 Year Class Report for the Hudson River 37 Estuary Monitoring Program. Prepared for Dynegy Roseton L.L.C.; Entergy Nuclear Indian 38 Point 2 L.L.C.; Entergy Nuclear Indian Point 3 L.L.C.; and Mirant Bowline L.L.C. January 2006.

39 ADAMS Accession No. ML083420103.

December 2010 I-83 NUREG-1437, Supplement 38

Appendix I 1 ASA Analysis and Communication (ASA). 2007. 2005 Year Class Report for the Hudson River 2 Estuary Monitoring Program. Prepared for Dynegy Roseton L.L.C.; Entergy Nuclear Indian 3 Point 2 L.L.C.; Entergy Nuclear Indian Point 3 L.L.C.; and Mirant Bowline L.L.C. January 2007.

4 ADAMS Accession No. ML073331067.

5 Battelle. 1983. 1980 and 1981 Year Class Report for the Hudson River Estuary Monitoring 6 Program. Prepared for Consolidated Edison Company of New York, Inc.; Orange and Rockland 7 Utilities, Inc.; Central Hudson Gas and Electric Corporation; New York Power Authority; and 8 Niagara Mohawk Power Corporation. December 15, 1983. ADAMS Accession No.

9 ML083420045.

10 Cochran, W.G. 1997. Sampling Techniques, John Wiley & Sons, New York, New York.

11 Consolidated Edison Company of New York, Inc. (Con Edison). Undated a. 1993 Year Class 12 Report for the Hudson River Estuary Monitoring Program. Prepared for Consolidated Edison 13 Company of New York, Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and 14 Electric Corporation; New York Power Authority; and Niagara Mohawk Power Corporation.

15 ADAMS Accession No. ML083420045.

16 Consolidated Edison Company of New York, Inc. (Con Edison). Undated b. 1994 Year Class 17 Report for the Hudson River Estuary Monitoring Program. Prepared for Consolidated Edison 18 Company of New York, Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and 19 Electric Corporation; New York Power Authority; and Niagara Mohawk Power Corporation.

20 ADAMS Accession No. ML083420045.

21 Consolidated Edison Company of New York, Inc. (Con Edison). Undated c. 1995 Year Class 22 Report for the Hudson River Estuary Monitoring Program. Prepared for Consolidated Edison 23 Company of New York, Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and 24 Electric Corporation; New York Power Authority; and Niagara Mohawk Power Corporation.

25 ADAMS Accession No. ML083420045.

26 Consolidated Edison Company of New York, Inc. (Con Edison). 1980. Hudson River Ecological 27 Study in the Area of Indian Point 1979 Annual Report. ADAMS Accession No. ML083420045.

28 Consolidated Edison Company of New York, Inc. (Con Edison). 1983. Hudson River 29 Ecological Study in the Area of Indian Point 1982 Annual Report. ADAMS Accession No.

30 ML083420045.

31 Consolidated Edison Company of New York, Inc. (Con Edison). 1984. Hudson River 32 Ecological Study in the Area of Indian Point 1981 Annual Report. ADAMS Accession No.

33 ML083420045.

34 Consolidated Edison Company of New York, Inc. (Con Edison) and New York Power Authority.

35 1984. Hudson River Ecological Study in the Area of Indian Point 1983 Annual Report. Prepared 36 by Normandeau Associates, Inc. ADAMS Accession No. ML083420045.

37 Consolidated Edison Company of New York, Inc. (Con Edison) and New York Power Authority.

38 1986. Hudson River Ecological Study in the Area of Indian Point 1985 Annual Report. Prepared 39 by Normandeau Associates, Inc. ADAMS Accession No. ML083420045.

40 Consolidated Edison Company of New York, Inc. (Con Edison) and New York Power Authority.

41 1987. Hudson River Ecological Study in the Area of Indian Point 1986 Annual Report. Prepared 42 by Normandeau Associates, Inc. ADAMS Accession No. ML083420045.

NUREG-1437, Supplement 38 I-84 December 2010

Appendix I 1 Consolidated Edison Company of New York, Inc. (Con Edison) and New York Power Authority.

2 1988. Hudson River Ecological Study in the Area of Indian Point 1987 Annual Report. Prepared 3 by EA Science and Technology. ADAMS Accession No. ML083420045.

4 Consolidated Edison Company of New York, Inc. (Con Edison) and New York Power Authority.

5 1991. Hudson River Ecological Study in the Area of Indian Point 1990 Annual Report. Prepared 6 by EA Science and Technology. ADAMS Accession No. ML083420045.

7 Consolidated Edison Company of New York, Inc. (Con Edison). 1996. 1992 Year Class Report 8 for the Hudson River Estuary Monitoring Program. Prepared for Consolidated Edison Company 9 of New York, Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric 10 Corporation; New York Power Authority; and Niagara Mohawk Power Corporation. April 1996.

11 ADAMS Accession No. ML083420045.

12 EA Engineering, Science, and Technology (EA). 1988. 1987 Year Class Report for the Hudson 13 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 14 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 15 York Power Authority; and Niagara Mohawk Power Corporation. July 1988. ADAMS Accession 16 No. ML083420045.

17 EA Engineering, Science, and Technology (EA). 1990. 1988 Year Class Report for the Hudson 18 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 19 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 20 York Power Authority; and Niagara Mohawk Power Corporation. August 1990. ADAMS 21 Accession No. ML083420045.

22 EA Engineering, Science, and Technology (EA). 1991. 1989 Year Class Report for the Hudson 23 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 24 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 25 York Power Authority; and Niagara Mohawk Power Corporation. March 1991. ADAMS 26 Accession No. ML083420045.

27 EA Engineering, Science, and Technology (EA). 1991. 1990 Year Class Report for the Hudson 28 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 29 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 30 York Power Authority; and Niagara Mohawk Power Corporation. October 1991. ADAMS 31 Accession No. ML083420045.

32 EA Engineering, Science, and Technology (EA). 1995. 1995 Year Class Report for the Hudson 33 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 34 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 35 York Power Authority; and Niagara Mohawk Power Corporation. ADAMS Accession No.

36 ML083420045.

37 Entergy Nuclear Operations, Inc. (Entergy). 2007. Applicant's Environment Report, Operating 38 License Renewal Stage. (Appendix E of Indian Point, Units 2 and 3, License Renewal 39 Application). April 23, 2007. (Agencywide Documents Access and Management System) 40 ADAMS Accession No. ML071210530.

41 Entergy Nuclear Operations, Inc. (Entergy). 2007b. Letter from F.R. Dacimo, Vide President, 42 Entergy Nuclear Operations, Inc. to Document Control Desk, U.S. Nuclear Regulatory 43 Commission.

Subject:

Entergy Nuclear Operations, Inc., Indian Point Nuclear Generating Unit December 2010 I-85 NUREG-1437, Supplement 38

Appendix I 1 Nos. 2 & 3; Docket Nos. 50-247 and 50-286; Supplement to License Renewal Application (LRA) 2 - Environmental Report References. ADAMS Nos. ML080080205, ML0800080209, 3 ML080080214, ML0800802161, ML0800080291, ML080080298, ML080080306, and 4 ML080080313.

5 Hansen J., M. Sato, R. Ruedy, K. Lo, D.W. Lea, and M. Medina-Elizade. 2006. Global 6 Temperature Change. PNAS 103: 14288-14293. Accessed at 7 http://pubs.giss.nasa.gov/docs/2006/2006_Hansen_etal_1.pdf on April 21, 2008.

8 Lawler, Matusky & Skelly Engineers (LMS). 1989. 1986 and 1987 Year Class Report for the 9 Hudson River Estuary Monitoring Program. Prepared for Consolidated Edison Company of 10 New York, Inc.; Orange and Rockland Utilities, Inc.; and Central Hudson Gas and Electric 11 Corporation. June 1989. ADAMS Accession No. ML083420045.

12 Lawler, Matusky & Skelly Engineers (LMS). 1991. 1990 Year Class Report for the Hudson 13 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 14 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 15 York Power Authority; and Niagara Mohawk Power Corporation. January 1991. ADAMS 16 Accession No. ML083420045.

17 Lawler, Matusky & Skelly Engineers (LMS). 1996. 1991 Year Class Report for the Hudson 18 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 19 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 20 York Power Authority; and Niagara Mohawk Power Corporation. January 1996. ADAMS 21 Accession No. ML083420045.

22 Martin Marietta Environmental Systems (MMES). 1986. 1984 Year Class Report for the 23 Hudson River Estuary Monitoring Program. Prepared for Consolidated Edison Company of 24 New York, Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric 25 Corporation; New York Power Authority; and Niagara Mohawk Power Corporation. May 1986.

26 ADAMS Accession No. ML083420045.

27 New York Power Authority (NYPA). 1986. Size Selectivity and Relative Catch Efficiency of a 28 3-m Beam Trawl and a 1-m2 Epibenthic Sled for Sampling Young of the Year Striped Bass and 29 Other Fishes in the Hudson River Estuary. Prepared by Normandeau Associates, Inc. January 30 1986. (HR Library #7180). ADAMS Accession No. ML083360641.

31 Normandeau Associates, Inc. (Normandeau). 1985a. 1982 Year Class Report for the Hudson 32 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 33 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 34 York Power Authority; and Niagara Mohawk Power Corporation. February 1985. ADAMS 35 Accession No. ML083420045.

36 Normandeau Associates, Inc. (Normandeau). 1985b. 1983 Year Class Report for the Hudson 37 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 38 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 39 York Power Authority; and Niagara Mohawk Power Corporation. April 1985. ADAMS 40 Accession No. ML083420045.

41 Normandeau Associates, Inc. (Normandeau). 1986. 1985 Year Class Report for the Hudson 42 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 43 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New NUREG-1437, Supplement 38 I-86 December 2010

Appendix I 1 York Power Authority; and Niagara Mohawk Power Corporation. September 1986. ADAMS 2 Accession No. ML083420045.

3 Normandeau Associates, Inc. (Normandeau). 1987. 1986 Year Class Report for the Hudson 4 River Estuary Monitoring Program. Prepared for Consolidated Edison Company of New York, 5 Inc.; Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; New 6 York Power Authority; and Niagara Mohawk Power Corporation. August 1987. ADAMS 7 Accession No. ML083420045.

8 Texas Instruments Inc. (TI). 1977. 1974 Year Class Report for the Multiplant Impact Study of 9 the Hudson River Estuary. Prepared for Consolidated Edison Company of New York, Inc.;

10 Orange and Rockland Utilities, Inc.; and Central Hudson Gas and Electric Corporation.

11 May 1977. ADAMS Accession No. ML083420045.

12 Texas Instruments Inc. (TI). 1978. 1975 Year Class Report for the Multiplant Impact Study of 13 the Hudson River Estuary. Prepared for Consolidated Edison Company of New York, Inc.;

14 Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; and Power 15 Authority of the State of New York. June 1978. ADAMS Accession No. ML083420045.

16 Texas Instruments Inc. (TI). 1979. 1976 Year Class Report for the Multiplant Impact Study of 17 the Hudson River Estuary. Prepared for Consolidated Edison Company of New York, Inc.;

18 Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; and Power 19 Authority of the State of New York. May 1979. ADAMS Accession No. ML083420045.

20 Texas Instruments Inc. (TI). 1980. 1977 Year Class Report for the Multiplant Impact Study of 21 the Hudson River Estuary. Prepared for Consolidated Edison Company of New York, Inc.;

22 Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; and Power 23 Authority of the State of New York. July 1980. ADAMS Accession No. ML083420045.

24 Texas Instruments Inc. (TI). 1980. 1978 Year Class Report for the Multiplant Impact Study of 25 the Hudson River Estuary. Prepared for Consolidated Edison Company of New York, Inc.;

26 Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; and Power 27 Authority of the State of New York. September 1980. ADAMS Accession No. ML083420045.

28 Texas Instruments Inc. (TI). 1981. 1979 Year Class Report for the Multiplant Impact Study of 29 the Hudson River Estuary. Prepared for Consolidated Edison Company of New York, Inc.;

30 Orange and Rockland Utilities, Inc.; Central Hudson Gas and Electric Corporation; and Power 31 Authority of the State of New York. March 1981. ADAMS Accession No. ML083420045.

32 Versar, Inc. (Versar). 1987. 1985 Year Class Report for the Hudson River Estuary Monitoring 33 Program. Prepared for Consolidated Edison Company of New York, Inc.; Orange and Rockland 34 Utilities, Inc.; Central Hudson Gas and Electric Corporation; New York Power Authority; and 35 Niagara Mohawk Power Corporation. October 1987. ADAMS Accession No. ML083420045.

December 2010 I-87 NUREG-1437, Supplement 38

NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER (9-2004) (Assigned by NRC, Add Vol., Supp., Rev.,

NRCMD 3.7 and Addendum Numbers, if any.)

BIBLIOGRAPHIC DATA SHEET NUREG-1437, Suplement 38, (See instructions on the reverse)

Vol. 3

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED Generic Environmental Impact Statement for License Renewal of Nuclear Plants MONTH YEAR Supplement 38 Regarding Indian Point Nuclear Generating Unit Nos. 2 and 3 December 2010 Final Report 4. FIN OR GRANT NUMBER Public Comments, Continued; Appendices

5. AUTHOR(S) 6. TYPE OF REPORT See Appendix B of this Report Technical

7. PERIOD COVERED (Inclusive Dates)

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor, provide name and mailing address.)

Division of License Renewal Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above"; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address.)

Same as 8 above

10. SUPPLEMENTARY NOTES Docket Nos. 05000247 and 05000286, TAC Nos. MD5411 and MD5412

11. ABSTRACT (200 words or less)

This supplemental environmental impact statement (SEIS) has been prepared in response to an application submitted to the NRC by Entergy Nuclear Operations, Inc. (Entergy), Entergy Nuclear Indian Point 2, LLC, and Entergy Nuclear Indian Point 3, LLC (all applicants will be jointly referred to as Entergy) to renew the operating licenses for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) for an additional 20 years under 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." This SEIS includes the NRC staff's analysis which considers and weighs the environmental impacts of the proposed action, the environmental impacts of alternatives to the proposed action, and mitigation measures available for reducing or avoiding adverse impacts. It also includes the NRC staff's recommendation regarding the proposed action.

The NRC staff's recommendation is that the Commission determine that the adverse environmental impacts of license renewals for IP2 and IP3 are not so great that preserving the option of license renewal for energy planning decision makers would be unreasonable. This recommendation is based on (1) the analysis and findings in the GEIS, (2) the environmental report and other information submitted by Entergy, (3) consultation with other Federal, State, Tribal, and local agencies, (4) the NRC staff's own independent review, and (5) the NRC staff's consideration of public comments received during the scoping process and in response to the draft SEIS.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABILITY STATEMENT Indian Point Nuclear Generating Unit Numbers 2 and 3 unlimited

14. SECURITY CLASSIFICATION IP2 IP3 (This Page)

IPEC unclassified Supplement to the Generic Environmental Impact Statement (This Report)

FSEIS unclassified National Environmental Policy Act NEPA 15. NUMBER OF PAGES License Renewal GEIS 16. PRICE NUREG-1437, Supplement 38 NRC FORM 335 (9-2004) PRINTED ON RECYCLED PAPER

UNITED STATES NUCLEAR REGULATORY COMMISSION MEDIA MAIL WASHINGTON, DC 20555-0001

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OFFICIAL BUSINESS

NUREG-1437, Supplement 38, Generic Environmental Impact Statement for License Renewal of December 2010 Vol. 3 Nuclear Plants: Regarding Indian Point Nuclear Generating Unit Nos. 2 and 3 Final