Text

Updated Final Safety Analysis Report, Rev. 26,
	ML23103A325
Person / Time
Site:	Salem, Hope Creek
Issue date:	04/13/2023
From:	; Public Service Enterprise Group
To:	; Office of Nuclear Reactor Regulation
Shared Package
ML23103A322	List: LR-N23-0027, Updated Final Safety Analysis Report, Rev. 26,; ML23103A323;
References
	LR-N23-0027, NEI 99-04
	Download: ML23103A325 (1)
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{{#Wiki_filter:* MASTER TABLE OF CONTENTS Section 1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT

1.1 INTRODUCTION

1.2 GENERAL PLANT DESCRIPTION 1.3 COMPARISON TABLES 1.4 IDENTIFICATION OF AGENTS AND CONTRACTORS 1.5 REQUIREMENTS FOR FURTHER TECHNICAL INFORMATION 1.6 MATERIAL INCORPORATED BY REFERENCE 1.7 DRAWINGS AND OTHER DETAILED INFORMATION 1.8 CONFORMANCE TO NRC REGULATORY GUIDES 1.9 STANDARD DESIGNS 1.10 TMI-2 RELATED REQUIREMENTS FOR NEW OPERATING LICENSES 1.11 DIFFERENCES FROM THE STANDARD REVIEW PLAN 1.12 UNRESOLVED GENERIC SAFETY ISSUES 1.13 SYMBOLS AND TERMS 1.14 GENERIC LICENSING ISSUES 1.15 CONFORMANCE TO RULES ISSUED AFTER PLANT LICENSING 2 SITE CHARACTERISTICS 2.1 GEOGRAPHY AND DEMOGRAPHY 2.2 NEARBY INDUSTRIAL, TRANSPORTAION, AND MILITARY FACILITIES 2.3 METEOROLOGY 2.4 HYDROLOGIC ENGINEERING 2.5 GEOLOGY, SEISMOLOGY, AND GEOTECHNICAL ENGINEERING

HCGS-UFSAR i

Revision 7 December 29, 1995

MASTER TABLE OF CONTENTS (Cont) section 3 DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS 3.1 CONFORMANCE WITH NRC GENERAL DESIGN CRITERIA 3.2 CLASSIFICATION OF STRUCTURES, COMPONENTS, AND SYSTEMS 3.3 WIND AND TORNADO LOADINGS 3.4 WATER LEVEL (FLOOD) DESIGN 3.5 MISSILE PROTECTION 3.6 PROTECTION AGAINST DYNAMIC EFFECTS ASSOCIATED WITH THE POSTULATED RUPTURE OF PIPING 3.7 SEISMIC DESIGN 3.8 DESIGN OF CATEGORY I STRUCTURES 3.9 MECHANICAL SYSTEMS AND COMPONENTS 3.10 SEISMIC QUALIFICATION OF SEISMIC CATEGORY I INSTRUMENTATION AND ELECTRICAL EQUIPMENT 3.11 ENVIRONMENTAL DESIGN OF MECHANICAL AND ELECTRICAL EQUIPMENT 3A COMPUTER PROGRAMS USED IN STRUCTURAL ANALYSIS AND DESIGN 38 MARK I LONG-TERM PROGRAM PLANT UNIQUE ANALYSIS FSAR

SUMMARY

REPORT 3C REACTOR ASYMMETRIC LOADS ANALYSIS 3D FOUNDATION MAT DESIGN 3E BUCKLING ANALYSIS OF THE DRYWELL VESSEL 3F ANALYSIS AND DESIGN OF FUEL POOL LINER AND SLAB 3G INTAKE STRUCTURE STABILITY ANALYSIS 3H POWER BLOCK STABILITY ANALYSIS 3I ULTIMATE CAPACITY OF CONTAINMENT

HCGS-UFSAR ii Revision 0 April 11, 1988

MASTER TABLE OF CONTENTS (Cont) Section Title 4 REACTOR 4.1

SUMMARY

DESCRIPTION 4.2 FUEL SYSTEM DESIGN 4.3 NUCLEAR DESIGN 4.4 THERMAL AND HYDRAULIC DESIGN 4.5 REACTOR MATERIALS 4.6 FUNCTIONAL DESIGN OF REACTIVITY CONTROL SYSTEMS 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.1

SUMMARY

DESCRIPTION 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY 5.3 REACTOR VESSEL 5.4 COMPONENT AND SUBSYSTEM DESIGN SA COMPLIANCE WITH 10CFR50, APPENDIX G AND APPENDIX H 6 ENGINEERED SAFETY FEATURES 6.0 GENERAL 6.1 ENGINEERED SAFETY FEATURE MATERIALS 6.2 CONTAINMENT SYSTEMS 6.3 EMERGENCY CORE COOLING SYSTEM 6.4 HABITABILITY SYSTEMS 6.5 FISSION PRODUCT REMOVAL AND CONTROL SYSTEMS 6.6 INSERVICE INSPECTION OF ASME B&PV CODE CLASS 2 AND 3 COMPONENTS

6. 7 6.8 "DELETED" FILTRATION, RECIRCULATION, AND VENTILATION I

SYSTEM iii HCGS-UFSAR Revision 12 May 3, 2002

MASTER TABLE OF CONTENTS (Cont) Section 6A NEGATIVE PRESSURE DESIGN EVALUATION 68 SUBCOMPARTMENT DIFFERENTIAL PRESSURE CONSIDERATIONS 6C STRUCTURAL DESIGN CRITERIA FOR SEISMIC CATEGORY I HVAC DUCTS AND DUCT SUPPORTS 7 INSTRUMENTATION AND CONTROLS

7.1 INTRODUCTION

7.2 REACTOR PROTECTION (TRIP) SYSTEM (RPS) 7.3 ENGINEERED SAFETY FEATURE SYSTEMS 7.4 SYSTEMS REQUIRED FOR SAFE SHUTDOWN 7.5 SAFETY-RELATED DISPLAY INSTRUMENTATION (INFORMATION SYSTEMS IMPORTANT TO SAFETY) 7.6 ALL OTHER INSTRUMENTATION SYSTEMS REQUIRED FOR SAFETY (INTERLOCK SYSTEMS IMPORTANT TO SAFETY) 7.7 CONTROL SYSTEMS NOT REQUIRED FOR SAFETY 8 ELECTRIC POWER

8.1 INTRODUCTION

8.2 OFFSITE POWER SYSTEMS 8.3 ONSITE POWER SYSTEMS 9 AUXILIARY SYSTEMS 9.1 FUEL STORAGE AND HANDLING 9.2 WATER SYSTEMS 9.3 PROCESS AUXILIARIES

HCGS-UFSAR iv Revision 7 December 29, 1995

MASTER TABLE OF CONTENTS (Cent) Section 9.4 AIR CONDITIONING, HEATING, COOLING, AND VENTILATING SYSTEMS 9.5 OTHER AUXILIARY SYSTEMS 9A APPENDIX R COMPARISON 9B DESIGN, ANALYSIS, AND CONSTRUCTION OF SPENT FUEL STORAGE RACKS 10 STEAM AND POWER CONVERSION SYSTEM 10.1

SUMMARY

DESCRIPTION 10.2 TURBINE GENERATOR 10.3 MAIN STEAM SUPPLY SYSTEM 10.4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM 11 RADIOACTIVE WASTE MANAGEMENT 11.1 SOURCE TERMS 11.2 LIQUID WASTE MANAGEMENT SYSTEMS 11.3 GASEOUS WASTE MANAGEMENT SYSTEMS 11.4 SOLID WASTE MANAGEMENT SYSTEM 11.5 PROCESS AND EFFLUENT RADIOLOGICAL MONITORING AND SAMPLING SYSTEMS 12 RADIATION PROTECTION 12.1 ENSURING THAT OCCUPATIONAL RADIATION EXPOSURES ARE AS LOW AS REASONABLY ACHIEVABLE (ALARA) 12.2 RADIATION SOURCES

HCGS-UFSAR v

Revision 0 April 11, 1988

MASTER TABLE OF CONTENTS (Cont) Section Title 12.3 RADIATION PROTECTION DESIGN FEATURES 12.4 DOSE ASSESSMENT 12.5 RADIATION PROTECTION PROGRAM 13 CONDUCT OF OPERATIONS 13.1 ORGANIZATIONAL STRUCTURE 13.2 TRAINING 13.3 EMERGENCY PLANNING 13.4 REVIEW AND AUDIT 13.5 PLANT PROCEDURES 13.6 PLANT RECORDS 13.7 SECURITY 13A INTENTIONALLY DELETED 13B INTENTIONALLY DELETED 13C INTENTIONALLY DELETED 13D INTENTIONALLY DELETED 13E INTENTIONALLY DELETED 13F INTENTIONALLY DELETED 13G INTENTIONALLY DELETED 13H INTENTIONALLY DELETED 13I INTENTIONALLY DELETED 13J INTENTIONALLY DELETED 13K INTENTIONALLY DELETED 13L PROCEDURES GENERATION PACKAGE 14 INITIAL TEST PROGRAM 14.1 SPECIFIC INFORMATION INCLUDED IS THE PRELIMINARY SAFETY ANALYSIS REPORT 14.2 CONSTRUCTION VERIFICATION, PREOPERATIONAL, AND POWER TEST PROGRAM vi HCGS-UFSAR Revision 22 May 9, 2017

MASTER TABLE OF CONTENTS (Cont) Section Title 15 ACCIDENT ANALYSES 15.0 GENERAL 15.1 DECREASE IN REACTOR COOLANT TEMPERATURE 15.2 INCREASE IN REACTOR PRESSURE 15.3 DECREASE IN REACTOR COOLANT SYSTEM FLOW RATE 15.4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES 15.5 INCREASE IN REACTOR COOLANT INVENTORY 15.6 DECREASE IN REACTOR COOLANT INVENTORY 15.7 RADIOACTIVE RELEASE FROM SUBSYSTEMS AND COMPONENTS 15.8 ANTICIPATED TRANSIENTS WITHOUT SCRAM (ATWS) 15.9 PLANT NUCLEAR SAFETY OPERATIONAL ANALYSIS (A SYSTEM LEVEL/ QUALITATIVE PLANT FAILURE MODES AND EFFECTS ANALYSIS) 15A APPENDIX 15A 15B SPECIAL ANALYSIS 15C HOPE CREEK SINGLE LOOP OPERATION ANALYSIS 15D CYCLE 25 RELOAD ANALYSIS RESULTS 16 TECHNICAL SPECIFICATIONS 16.1 PRELIMINARY TECHNICAL SPECIFICATIONS 16.2 PROPOSED FINAL TECHNICAL SPECIFICATIONS 17 QUALITY ASSURANCE 17.1 QUALITY ASSURANCE DURING DESIGN AND CONSTRUCTION 17.2 QUALITY ASSURANCE DURING THE OPERATIONS PHASE 17.3 QUALITY ASSURANCE OF THE INDEPENDENT SPENT FUEL STORAGE INSTALLATION vii HCGS-UFSAR Revision 26 April 13, 2023

MASTER TABLE OF CONTENTS (Cont) Section Title 18 HUMAN FACTORS ENGINEERING 18.1 DETAILED CONTROL ROOM DESIGN REVIEW 18.2 SAFETY PARAMETER DISPLAY SYSTEM 18.3 TASK ANALYSIS 18.4 THE MAIN CONTROL ROOM 18.5 CONTROL CENTERS OUTSIDE OF THE MAIN CONTROL ROOM I APPENDIX A LICENSE RENEWAL FINAL SAFETY ANALYSIS REPORT SUPPLEMENT viii HCGS-UFSAR Revision 19 November 5, 2012

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HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T1.8-1 Sh7 0 1.10-40 0 1.10-90 0 T1.11-1 Sh14 17 T1.8-1 Sh8 8 1.10-41 0 1.10-91 0 T1.11-1 Sh15 0 T1.8-1 Sh9 0 1.10-42 0 1.10-92 0 T1.11-1 Sh16 0 T1.8-1 Sh10 0 1.10-43 0 1.10-93 0 T1.11-1 Sh17 0 T1.8-1 Sh11 0 1.10-44 8 1.10-94 0 T1.11-1 Sh18 0 T1.8-2 0 1.10-45 13 1.10-95 20 T1.11-1 Sh19 0 T1.8-3 14 1.10-46 0 1.10-96 0 T1.11-1 Sh20 0 T1.8-4 Sh1 0 1.10-47 4 1.10-97 9 T1.11-1 Sh21 0 T1.8-4 Sh2 0 1.10-48 17 1.10-98 0 T1.11-1 Sh22 0 T1.8-4 Sh3 0 1.10-49 0 1.10-99 0 T1.11-1 Sh23 0 1.9-1 0 1.10-50 0 1.10-100 0 T1.11-1 Sh24 0 1.10-1 0 1.10-51 0 1.10-101 0 T1.11-1 Sh25 0 1.10-2 0 1.10-52 17 1.10-102 0 T1.11-1 Sh26 0 1.10-3 15 1.10-53 15 1.10-103 0 T1.11-1 Sh27 0 1.10-4 15 1.10-54 15 1.10-104 0 T1.11-1 Sh28 8 1.10-5 0 1.10-55 17 1.10-105 0 T1.11-1 Sh29 14 1.10-6 9 1.10-56 0 1.10-106 17 T1.11-1 Sh30 0 1.10-7 8 1.10-57 8 1.10-107 17 T1.11-1 Sh31 0 1.10-8 8 1.10-58 1 1.10-108 0 1.12-1 0 1.10-9 8 1.10-59 7 1.10-109 8 1.12-2 0 1.10-10 13 1.10-60 0 1.10-110 15 1.12-3 0 1.10-11 8 1.10-61 17 1.10-111 0 1.12-4 0 1.10-12 13 1.10-62 17 1.10-112 17 1.12-5 0 1.10-13 0 1.10-63 0 1.10-113 0 1.12-6 0 1.10-14 6 1.10-64 0 1.10-114 0 1.12-7 0 1.10-15 4 1.10-65 8 1.10-115 9 1.12-8 0 1.10-16 0 1.10-66 0 1.10-116 12 1.12-9 0 1.10-17 4 1.10-67 0 1.10-117 0 1.12-10 0 1.10-18 4 1.10-68 0 1.10-118 0 1.12-11 0 1.10-19 22 1.10-69 17 1.10-119 15 1.12-12 0 1.10-20 9 1.10-70 17 1.10-120 0 1.12-13 0 1.10-21 14 1.10-71 0 1.10-121 8 1.12-14 0 1.10-22 9 1.10-72 20 1.10-122 0 1.12-15 0 1.10-23 14 1.10-73 8 1.10-123 0 1.12-16 0 1.10-24 8 1.10-74 8 1.10-124 0 1.12-17 7 1.10-25 8 1.10-75 8 1.10-125 0 1.12-18 7 1.10-26 9 1.10-76 0 1.11-1 0 1.12-19 7 1.10-27 8 1.10-77 0 T1.11-1 Sh1 0 1.12-20 7 1.10-28 0 1.10-78 0 T1.11-1 Sh2 0 1.12-21 0 1.10-29 0 1.10-79 20 T1.11-1 Sh3 0 1.12-22 0 1.10-30 0 1.10-80 17 T1.11-1 Sh4 0 1.12-23 0 1.10-31 4 1.10-81 8 T1.11-1 Sh5 0 1.12-24 0 1.10-32 0 1.10-82 0 T1.11-1 Sh6 0 1.12-25 0 1.10-33 17 1.10-83 0 T1.11-1 Sh7 16 1.12-26 0 1.10-34 8 1.10-84 0 T1.11-1 Sh8 0 1.12-27 15 1.10-35 0 1.10-85 8 T1.11-1 Sh9 0 1.13-1 0 1.10-36 17 1.10-86 8 T1.11-1 Sh10 0 1.13-2 20 1.10-37 17 1.10-87 0 T1.11-1 Sh11 0 1.13-3 0 1.10-38 0 1.10-88 20 T1.11-1 Sh12 0 1.13-4 22 1.10-39 0 1.10-89 0 T1.11-1 Sh13 0 1.13-5 10 3

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 1.13-6 0 1.14-32 0 1.14-78 0 2-xi 0 1.13-7 0 1.14-33 17 1.14-79 0 2-xii 0 1.13-8 0 1.14-34 0 1.14-80 0 2-xiii 0 1.13-9 0 1.14-35 0 1.14-81 0 2-xiv 0 T1.13-1 Sh1 23 1.14-36 0 1.14-82 0 2-xv 0 T1.13-1 Sh2 23 1.14-37 0 1.14-83 0 2-xvi 0 T1.13-1 Sh3 23 1.14-38 0 1.14-84 12 2-xvii 0 T1.13-1 Sh4 14 1.14-39 0 1.14-85 0 2-xviii 21 T1.13-1 Sh5 12 1.14-40 0 1.14-86 0 2-xix 0 T1.13-1 Sh6 23 1.14-41 0 1.14-87 0 2-xx 20 T1.13-1 Sh7 0 1.14-42 0 1.14-88 0 2-xxi 0 T1.13-1 Sh8 23 1.14-43 0 1.14-89 23 2-xxii 0 T1.13-1 Sh9 0 1.14-44 0 1.14-90 0 2-xxiii 0 T1.13-2 Sh1 0 1.14-45 0 1.14-91 0 2-xxiv 0 T1.13-2 Sh2 0 1.14-46 8 1.14-92 0 2-xxv 0 T1.13-2 Sh3 0 1.14-47 8 1.14-93 0 2-xxvi 0 F1.13-1 Sh1 20 1.14-48 0 1.14-94 0 2-xxvii 0 F1.13-1 Sh2 R 1.14-49 0 1.14-95 0 2-xxviii 0 F1.13-2 0 1.14-50 7 1.14-96 0 2.1-1 0 1.14-1 0 1.14-50a 7 1.14-97 20 2.1-2 0 1.14-2 0 1.14-50b 7 1.14-98 0 2.1-3 0 1.14-3 0 1.14-51 0 1.14-99 18 2.1-4 0 1.14-4 0 1.14-52 0 1.14-100 0 2.1-5 0 1.14-5 12 1.14-53 0 1.14-101 14 2.1-6 0 1.14-6 0 1.14-54 0 1.14-102 14 2.1-7 0 1.14-7 0 1.14-55 8 1.14-103 17 2.1-8 0 1.14-8 0 1.14-56 9 1.14-104 17 2.1-9 0 1.14-9 20 1.14-57 11 1.14-105 22 2.1-10 0 1.14-10 0 1.14-58 23 1.14-106 17 2.1-11 0 1.14-11 23 1.14-59 12 1.14-107 17 2.1-12 0 1.14-12 0 1.14-60 23 1.14-107a R 2.1-13 0 1.14-13 0 1.14-61 23 1.14-107b R 2.1-14 0 1.14-14 0 1.14-62 20 1.14-108 14 T2.1-1 0 1.14-15 0 1.14-63 1 1.14-108a R T2.1-2 Sh1 0 1.14-16 0 1.14-64 1 1.14-108b R T2.1-2 Sh2 0 1.14-17 0 1.14-65 1 1.14-109 0 T2.1-2 Sh3 0 1.14-18 0 1.14-66 20 1.14-110 0 T2.1-3 Sh1 0 1.14-19 15 1.14-67 12 1.14-111 0 T2.1-3 Sh2 0 1.14-20 0 1.14-67a 3 1.15-1 8 T2.1-4 0 1.14-21 0 1.14-67b 1 1.15-2 22 T2.1-5 0 1.14-22 0 1.14-68 9 2-i 0 T2.1-6 Sh1 0 1.14-23 0 1.14-69 0 2-ii 0 T2.1-6 Sh2 0 1.14-24 0 1.14-70 0 2-iii 0 T2.1-7 0 1.14-25 0 1.14-71 0 2-iv 21 F2.1-1 0 1.14-26 0 1.14-72 0 2-v 0 F2.1-2 0 1.14-27 9 1.14-73 20 2-vi 0 F2.1-3 0 1.14-28 0 1.14-74 0 2-vii 0 F2.1-4 0 1.14-29 0 1.14-75 0 2-viii 0 F2.1-5 0 1.14-30 0 1.14-76 0 2-ix 0 F2.1-6 0 1.14-31 0 1.14-77 20 2-x 11 F2.1-7 0 4

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F2.1-8 0 2.3-2 0 2.3-52 8 T2.3-29c Sh1 13 F2.1-9 0 2.3-3 0 2.3-53 0 T2.3-29c Sh2 R F2.1-10 0 2.3-4 0 2.3-54 0 T2.3-30 0 F2.1-11 0 2.3-5 0 2.3-55 0 T2.3-30a 0 F2.1-12 0 2.3-6 0 2.3-56 0 T2.3-31 Sh1 13 F2.1-13 0 2.3-7 0 2.3-57 0 T2.3-31 Sh2 13 F2.1-14 0 2.3-8 0 2.3-58 0 T2.3-32 Sh1 13 F2.1-15 0 2.3-9 0 2.3-59 0 T2.3-32 Sh2 13 F2.1-16 0 2.3-10 0 2.3-60 0 T2.3-33 Sh1 13 F2.1-17 0 2.3-11 0 T2.3-1 0 T2.3-33 Sh2 13 F2.1-18 0 2.3-12 0 T2.3-2 0 T2.3-34 0 F2.1-19 0 2.3-13 0 T2.3-3 0 T2.3-35 0 F2.1-20 0 2.3-14 0 T2.3-4 0 T2.3-36 0 F2.1-21 0 2.3-15 0 T2.3-5 0 T2.3-37 0 F2.1-22 0 2.3-16 0 T2.3-6 0 T2.3-38 0 F2.1-23 0 2.3-17 0 T2.3-7 0 T2.3-39 0 2.2-1 5 2.3-18 0 T2.3-8 17 T2.3-40 0 2.2-2 0 2.3-19 0 T2.3-9 0 F2.3-1 0 2.2-3 0 2.3-20 0 T2.3-10 Sh1 0 F2.3-2 0 2.2-4 0 2.3-21 0 T2.3-10 Sh2 0 F2.3-3 Sh1 0 2.2-5 0 2.3-22 3 T2.3-11 0 F2.3-3 Sh2 0 2.2-6 8 2.3-23 0 T2.3-12 0 F2.3-3 Sh3 0 2.2-7 0 2.3-24 11 T2.3-13 0 F2.3-3 Sh4 0 2.2-8 0 2.3-25 0 T2.3-14 0 F2.3-4 0 2.2-9 8 2.3-26 0 T2.3-15 Sh1 0 F2.3-5 26 2.2-10 0 2.3-27 0 T2.3-15 Sh2 0 F2.3-6 26 2.2-11 0 2.3-28 8 T2.3-16 0 F2.3-7 0 2.2-12 17 2.3-29 0 T2.3-17 0 2.4-1 20 2.2-13 13 2.3-30 0 T2.3-18 Sh1 0 2.4-2 21 2.2-14 25 2.3-31 0 T2.3-18 Sh2 0 2.4-3 0 2.2-14a 5 2.3-32 8 T2.3-19 0 2.4-4 0 2.2-14b 5 2.3-33 0 T2.3-20 0 2.4-5 21 2.2-15 0 2.3-34 0 T2.3-21 0 2.4-6 17 2.2-16 0 2.3-35 13 T2.3-22 Sh1 0 2.4-7 0 2.2-17 9 2.3-36 26 T2.3-22 Sh2 0 2.4-8 0 2.2-18 0 2.3-37 26 T2.3-23 0 2.4-9 0 2.2-19 0 2.3-38 26 T2.3-24 0 2.4-10 0 2.2-20 8 2.3-39 15 T2.3-25 0 2.4-11 0 T2.2-1 0 2.3-40 3 T2.3-26 0 2.4-12 0 T2.2-2 0 2.3-41 0 T2.3-27 Sh1 0 2.4-13 8 T2.2-3 0 2.3-42 0 T2.3-27 Sh2 0 2.4-14 0 T2.2-4 13 2.3-43 0 T2.3-27a 0 2.4-15 0 T2.2-5 Sh1 8 2.3-44 13 T2.3-27b Sh1 0 2.4-16 8 T2.2-5 Sh2 25 2.3-45 0 T2.3-27b Sh2 0 2.4-17 21 T2.2-6 25 2.3-46 0 T2.3-28 1 2.4-18 21 F2.2-1 0 2.3-47 0 T2.3-29 Sh1 26 2.4-19 0 F2.2-2 0 2.3-48 8 T2.3-29 Sh2 R 2.4-20 0 F2.2-3 0 2.3-49 0 T2.3-29 Sh3 R 2.4-21 0 F2.2-4 0 2.3-50 0 T2.3-29a 13 2.4-22 0 2.3-1 0 2.3-51 0 T2.3-29b 13 2.4-23 0 5

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 2.4-24 0 2.4-74 0 T2.4-16 Sh1 0 F2.4-35 0 2.4-25 0 2.4-75 8 T2.4-16 Sh2 0 F2.4-36 0 2.4-26 0 2.4-76 20 T2.4-16 Sh3 0 F2.4-37 0 2.4-27 17 2.4-77 9 T2.4-17 Sh1 0 F2.4-38 0 2.4-28 8 2.4-78 0 T2.4-17 Sh2 0 F2.4-39 0 2.4-29 0 2.4-79 0 T2.4-17 Sh3 0 F2.4-40 0 2.4-30 8 2.4-80 20 T2.4-18 Sh1 0 F2.4-41 0 2.4-31 0 2.4-81 0 T2.4-18 Sh2 0 F2.4-42 0 2.4-32 0 2.4-82 4 T2.4-19 0 F2.4-43 0 2.4-33 0 2.4-83 20 T2.4-20 Sh1 8 F2.4-44 0 2.4-34 17 2.4-84 0 T2.4-20 Sh2 8 2.5-1 0 2.4-35 8 2.4-85 0 T2.4-21 Sh1 8 2.5-2 0 2.4-36 17 2.4-86 0 T2.4-21 Sh2 8 2.5-3 0 2.4-37 8 2.4-87 0 T2.4-22 Sh1 8 2.5-4 0 2.4-38 9 2.4-88 17 T2.4-22 Sh2 8 2.5-5 17 2.4-39 19 2.4-89 0 T2.4-23 8 2.5-6 8 2.4-40 0 2.4-90 21 F2.4-1 0 2.5-7 0 2.4-41 0 2.4-91 8 F2.4-2 20 2.5-8 0 2.4-42 0 2.4-92 24 F2.4-3 0 2.5-9 0 2.4-43 0 2.4-93 0 F2.4-4 0 2.5-10 0 2.4-44 9 2.4-94 8 F2.4-5 0 2.5-11 0 2.4-45 0 2.4-95 0 F2.4-6 0 2.5-12 0 2.4-46 9 2.4-96 0 F2.4-7 0 2.5-13 0 2.4-47 0 2.4-97 8 F2.4-8 0 2.5-14 8 2.4-48 0 2.4-98 0 F2.4-9 0 2.5-15 0 2.4-49 8 T2.4-1 8 F2.4-10 0 2.5-16 17 2.4-50 17 T2.4-2 Sh1 0 F2.4-11 0 2.5-17 0 2.4-51 0 T2.4-2 Sh2 0 F2.4-12 0 2.5-18 17 2.4-52 0 T2.4-3 Sh1 0 F2.4-13 0 2.5-19 0 2.4-53 0 T2.4-3 Sh2 0 F2.4-14 0 2.5-20 0 2.4-54 0 T2.4-4 Sh1 0 F2.4-15 0 2.5-21 0 2.4-55 0 T2.4-4 Sh2 0 F2.4-16 0 2.5-22 0 2.4-56 0 T2.4-5 0 F2.4-17 0 2.5-23 0 2.4-57 0 T2.4-6 Sh1 0 F2.4-18 0 2.5-24 0 2.4-58 0 T2.4-6 Sh2 0 F2.4-19 0 2.5-25 0 2.4-59 8 T2.4-7 0 F2.4-20 0 2.5-26 0 2.4-60 0 T2.4-8 0 F2.4-21 0 2.5-27 0 2.4-61 0 T2.4-9 0 F2.4-22 0 2.5-28 0 2.4-62 0 T2.4-10 Sh1 8 F2.4-23 0 2.5-29 0 2.4-63 8 T2.4-10 Sh2 19 F2.4-24 0 2.5-30 0 2.4-64 0 T2.4-10a 0 F2.4-25 20 2.5-31 0 2.4-65 0 T2.4-11 0 F2.4-26 0 2.5-32 17 2.4-66 0 T2.4-11a 0 F2.4-27 0 2.5-33 0 2.4-67 0 T2.4-12 0 F2.4-28 0 2.5-34 0 2.4-68 8 T2.4-13 0 F2.4-29 0 2.5-35 0 2.4-69 8 T2.4-14 Sh1 8 F2.4-30 0 2.5-36 0 2.4-70 8 T2.4-14 Sh2 8 F2.4-31 0 2.5-37 0 2.4-71 0 T2.4-14 Sh3 8 F2.4-32 0 2.5-38 0 2.4-72 0 T2.4-14 Sh4 17 F2.4-33 0 2.5-39 17 2.4-73 0 T2.4-15 0 F2.4-34 0 2.5-40 0 6

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 2.5-41 0 2.5-91 0 2.5-139 1 T2.5-2 Sh1 0 2.5-42 0 2.5-92 0 2.5-139a 1 T2.5-2 Sh2 0 2.5-43 0 2.5-93 0 2.5-139b 1 T2.5-3 0 2.5-44 0 2.5-94 0 2.5-140 0 T2.5-4 0 2.5-45 0 2.5-95 0 2.5-141 0 T2.5-5 0 2.5-46 0 2.5-96 0 2.5-142 0 T2.5-6 Sh1 0 2.5-47 0 2.5-97 0 2.5-143 0 T2.5-6 Sh2 0 2.5-48 0 2.5-98 0 2.5-144 0 T2.5-7 0 2.5-49 0 2.5-99 0 2.5-145 0 T2.5-8 Sh1 0 2.5-50 0 2.5-100 0 2.5-146 0 T2.5-8 Sh2 0 2.5-51 0 2.5-101 1 2.5-147 0 T2.5-9 0 2.5-52 0 2.5-101a 1 2.5-148 17 T2.5-10 0 2.5-53 0 2.5-101b 1 2.5-149 17 T2.5-11 Sh1 0 2.5-54 0 2.5-102 0 2.5-150 0 T2.5-11 Sh2 0 2.5-55 0 2.5-103 0 2.5-151 0 T2.5-11 Sh3 0 2.5-56 0 2.5-104 17 2.5-152 0 T2.5-11 Sh4 0 2.5-57 0 2.5-105 0 2.5-153 0 T2.5-12 Sh1 0 2.5-58 0 2.5-106 0 2.5-154 0 T2.5-12 Sh2 0 2.5-59 0 2.5-107 0 2.5-155 0 T2.5-13 Sh1 0 2.5-60 0 2.5-108 0 2.5-156 0 T2.5-13 Sh2 0 2.5-61 0 2.5-109 0 2.5-157 0 T2.5-14 0 2.5-62 0 2.5-110 0 2.5-158 0 T2.5-15 0 2.5-63 0 2.5-111 0 2.5-159 0 T2.5-16 0 2.5-64 0 2.5-112 0 2.5-160 0 T2.5-17 0 2.5-65 0 2.5-113 0 2.5-161 0 T2.5-18 0 2.5-66 0 2.5-114 0 2.5-162 17 T2.5-19 0 2.5-67 0 2.5-115 0 2.5-163 0 T2.5-20 0 2.5-68 0 2.5-116 0 2.5-164 0 T2.5-21 0 2.5-69 0 2.5-117 0 2.5-165 0 T2.5-22 0 2.5-70 0 2.5-118 17 2.5-166 0 T2.5-23 0 2.5-71 8 2.5-119 0 2.5-167 0 T2.5-24 0 2.5-72 0 2.5-120 0 2.5-168 0 F2.5-1 0 2.5-73 17 2.5-121 17 2.5-169 0 F2.5-2 0 2.5-74 0 2.5-122 0 2.5-170 0 F2.5-3 0 2.5-75 17 2.5-123 0 2.5-171 0 F2.5-4 0 2.5-76 0 2.5-124 0 2.5-172 0 F2.5-5 0 2.5-77 0 2.5-125 0 2.5-173 0 F2.5-6 0 2.5-78 0 2.5-126 0 2.5-174 0 F2.5-7 0 2.5-79 0 2.5-127 0 2.5-175 0 F2.5-8 0 2.5-80 0 2.5-128 17 2.5-176 0 F2.5-9 0 2.5-81 0 2.5-129 0 2.5-177 0 F2.5-10 0 2.5-82 0 2.5-130 17 2.5-178 0 F2.5-10a 0 2.5-83 0 2.5-131 0 2.5-179 0 F2.5-11 0 2.5-84 0 2.5-132 1 2.5-180 0 F2.5-11a 0 2.5-85 0 2.5-133 0 2.5-181 0 F2.5-12 0 2.5-86 0 2.5-134 0 2.5-182 0 F2.5-13 0 2.5-87 0 2.5-135 0 T2.5-1 Sh1 0 F2.5-14 0 2.5-88 0 2.5-136 0 T2.5-1 Sh2 0 F2.5-15 0 2.5-89 0 2.5-137 0 T2.5-1 Sh3 0 F2.5-16 0 2.5-90 0 2.5-138 0 T2.5-1 Sh4 17 F2.5-17 0 7

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F2.5-18 0 F2.5-50 Sh10 0 F2.5-50 Sh60 0 F2.5-50 Sh110 0 F2.5-19 0 F2.5-50 Sh11 0 F2.5-50 Sh61 0 F2.5-50 Sh111 0 F2.5-20 0 F2.5-50 Sh12 0 F2.5-50 Sh62 0 F2.5-50 Sh112 0 F2.5-21 0 F2.5-50 Sh13 0 F2.5-50 Sh63 0 F2.5-50 Sh113 0 F2.5-22 0 F2.5-50 Sh14 0 F2.5-50 Sh64 0 F2.5-50 Sh114 0 F2.5-23 0 F2.5-50 Sh15 0 F2.5-50 Sh65 0 F2.5-50 Sh115 0 F2.5-24 0 F2.5-50 Sh16 0 F2.5-50 Sh66 0 F2.5-50 Sh116 0 F2.5-25 0 F2.5-50 Sh17 0 F2.5-50 Sh67 0 F2.5-50 Sh117 0 F2.5-26 0 F2.5-50 Sh18 0 F2.5-50 Sh68 0 F2.5-50 Sh118 0 F2.5-26a 0 F2.5-50 Sh19 0 F2.5-50 Sh69 0 F2.5-50 Sh119 0 F2.5-27 0 F2.5-50 Sh20 0 F2.5-50 Sh70 0 F2.5-50 Sh120 0 F2.5-28 0 F2.5-50 Sh21 0 F2.5-50 Sh71 0 F2.5-50 Sh121 0 F2.5-28a 0 F2.5-50 Sh22 0 F2.5-50 Sh72 0 F2.5-50 Sh122 0 F2.5-28b 0 F2.5-50 Sh23 0 F2.5-50 Sh73 0 F2.5-50 Sh123 0 F2.5-29 0 F2.5-50 Sh24 0 F2.5-50 Sh74 0 F2.5-50 Sh124 0 F2.5-30 0 F2.5-50 Sh25 0 F2.5-50 Sh75 0 F2.5-50 Sh125 0 F2.5-31 0 F2.5-50 Sh26 0 F2.5-50 Sh76 0 F2.5-50 Sh126 0 F2.5-32 0 F2.5-50 Sh27 0 F2.5-50 Sh77 0 F2.5-50 Sh127 0 F2.5-33 0 F2.5-50 Sh28 0 F2.5-50 Sh78 0 F2.5-50 Sh128 0 F2.5-34 0 F2.5-50 Sh29 0 F2.5-50 Sh79 0 F2.5-50 Sh129 0 F2.5-35 0 F2.5-50 Sh30 0 F2.5-50 Sh80 0 F2.5-50 Sh130 0 F2.5-36 0 F2.5-50 Sh31 0 F2.5-50 Sh81 0 F2.5-50 Sh131 0 F2.5-37 0 F2.5-50 Sh32 0 F2.5-50 Sh82 0 F2.5-50 Sh132 0 F2.5-38 0 F2.5-50 Sh33 0 F2.5-50 Sh83 0 F2.5-50 Sh133 0 F2.5-39 0 F2.5-50 Sh34 0 F2.5-50 Sh84 0 F2.5-50 Sh134 0 F2.5-40 0 F2.5-50 Sh35 0 F2.5-50 Sh85 0 F2.5-50 Sh135 0 F2.5-41 Sh1 0 F2.5-50 Sh36 0 F2.5-50 Sh86 0 F2.5-50 Sh136 0 F2.5-41 Sh2 0 F2.5-50 Sh37 0 F2.5-50 Sh87 0 F2.5-50 Sh137 0 F2.5-41 Sh3 0 F2.5-50 Sh38 0 F2.5-50 Sh88 0 F2.5-50 Sh138 0 F2.5-41 Sh4 0 F2.5-50 Sh39 0 F2.5-50 Sh89 0 F2.5-50 Sh139 0 F2.5-42 Sh1 0 F2.5-50 Sh40 0 F2.5-50 Sh90 0 F2.5-50 Sh140 0 F2.5-42 Sh2 0 F2.5-50 Sh41 0 F2.5-50 Sh91 0 F2.5-50 Sh141 0 F2.5-42 Sh3 0 F2.5-50 Sh42 0 F2.5-50 Sh92 0 F2.5-50 Sh142 0 F2.5-42 Sh4 0 F2.5-50 Sh43 0 F2.5-50 Sh93 0 F2.5-50 Sh143 0 F2.5-43 0 F2.5-50 Sh44 0 F2.5-50 Sh94 0 F2.5-50 Sh144 0 F2.5-44 0 F2.5-50 Sh45 0 F2.5-50 Sh95 0 F2.5-50 Sh145 0 F2.5-45 0 F2.5-50 Sh46 0 F2.5-50 Sh96 0 F2.5-50 Sh146 0 F2.5-46 0 F2.5-50 Sh47 0 F2.5-50 Sh97 0 F2.5-50 Sh147 0 F2.5-47 0 F2.5-50 Sh48 0 F2.5-50 Sh98 0 F2.5-50 Sh148 0 F2.5-48 0 F2.5-50 Sh49 0 F2.5-50 Sh99 0 F2.5-50 Sh149 0 F2.5-49 0 F2.5-50 Sh50 0 F2.5-50 Sh100 0 F2.5-50 Sh150 0 F2.5-50 Sh1 0 F2.5-50 Sh51 0 F2.5-50 Sh101 0 F2.5-50 Sh151 0 F2.5-50 Sh2 0 F2.5-50 Sh52 0 F2.5-50 Sh102 0 F2.5-50 Sh152 0 F2.5-50 Sh3 0 F2.5-50 Sh53 0 F2.5-50 Sh103 0 F2.5-50 Sh153 0 F2.5-50 Sh4 0 F2.5-50 Sh54 0 F2.5-50 Sh104 0 F2.5-50 Sh154 0 F2.5-50 Sh5 0 F2.5-50 Sh55 0 F2.5-50 Sh105 0 F2.5-50 Sh155 0 F2.5-50 Sh6 0 F2.5-50 Sh56 0 F2.5-50 Sh106 0 F2.5-50 Sh156 0 F2.5-50 Sh7 0 F2.5-50 Sh57 0 F2.5-50 Sh107 0 F2.5-50 Sh157 0 F2.5-50 Sh8 0 F2.5-50 Sh58 0 F2.5-50 Sh108 0 F2.5-50 Sh158 0 F2.5-50 Sh9 0 F2.5-50 Sh59 0 F2.5-50 Sh109 0 F2.5-50 Sh159 0 8

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F2.5-50 Sh160 0 F2.5-67 Sh1 0 F2.5-92 Sh1 0 3-xLi 0 F2.5-50 Sh161 0 F2.5-67 Sh2 0 F2.5-92 Sh2 0 3-xLii 0 F2.5-50 Sh162 0 F2.5-68 Sh1 0 F2.5-93 Sh1 0 3-xliii 0 F2.5-50 Sh163 0 F2.5-68 Sh2 0 F2.5-93 Sh2 0 3-xLiv 0 F2.5-50 Sh164 0 F2.5-69 Sh1 0 F2.5-94 Sh1 0 3-xLv 0 F2.5-50 Sh165 0 F2.5-69 Sh2 0 F2.5-94 Sh2 0 3-xLvi 0 F2.5-50 Sh166 0 F2.5-70 Sh1 0 F2.5-95 Sh1 0 3-xLvii 0 F2.5-50 Sh167 0 F2.5-70 Sh2 0 F2.5-95 Sh2 0 3-xLviii 0 F2.5-50 Sh168 0 F2.5-71 Sh1 0 F2.5-96 Sh1 0 3-xLix 0 F2.5-50 Sh169 0 F2.5-71 Sh2 0 F2.5-96 Sh2 0 3-L 0 F2.5-50 Sh170 0 F2.5-72 Sh1 0 3-i 0 3-Li 0 F2.5-50 Sh171 0 F2.5-72 Sh2 0 3-ii 0 3-Lii 0 F2.5-50 Sh172 0 F2.5-73 Sh1 0 3-iii 0 3.1-1 0 F2.5-50 Sh173 0 F2.5-73 Sh2 0 3-iv 0 3.1-2 0 F2.5-50 Sh174 0 F2.5-74 Sh1 0 3-v 0 3.1-3 0 F2.5-50 Sh175 0 F2.5-74 Sh2 0 3-vi 0 3.1-4 0 F2.5-50 Sh176 0 F2.5-75 Sh1 0 3-vii 16 3.1-5 0 F2.5-50 Sh177 0 F2.5-75 Sh2 0 3-viii 0 3.1-6 0 F2.5-50 Sh178 0 F2.5-76 Sh1 0 3-ix 17 3.1-7 0 F2.5-50 Sh179 0 F2.5-76 Sh2 0 3-x 0 3.1-8 0 F2.5-50 Sh180 0 F2.5-77 Sh1 0 3-xi 16 3.1-9 14 F2.5-50 Sh181 0 F2.5-77 Sh2 0 3-xii 0 3.1-10 0 F2.5-50 Sh182 0 F2.5-78 Sh1 0 3-xiii 14 3.1-11 0 F2.5-50 Sh183 0 F2.5-78 Sh2 0 3-xiv 0 3.1-12 0 F2.5-50 Sh184 0 F2.5-79 Sh1 0 3-xv 6 3.1-13 14 F2.5-50 Sh185 0 F2.5-79 Sh2 0 3-xvi 14 3.1-14 0 F2.5-50 Sh186 0 F2.5-80 Sh1 0 3-xvii 0 3.1-15 0 F2.5-50 Sh187 0 F2.5-80 Sh2 0 3-xviii 0 3.1-16 0 F2.5-50 Sh188 0 F2.5-81 Sh1 0 3-xix 14 3.1-17 0 F2.5-50 Sh189 0 F2.5-81 Sh2 0 3-xx 0 3.1-18 0 F2.5-51 0 F2.5-82 Sh1 0 3-xxi 0 3.1-19 0 F2.5-52 0 F2.5-82 Sh2 0 3-xxii 0 3.1-20 12 F2.5-53 0 F2.5-83 Sh1 0 3-xxiii 0 3.1-21 0 F2.5-54 0 F2.5-83 Sh2 0 3-xxiv 0 3.1-22 0 F2.5-55 0 F2.5-84 Sh1 0 3-xxv 0 3.1-23 0 F2.5-56 0 F2.5-84 Sh2 0 3-xxvi 0 3.1-24 12 F2.5-57 0 F2.5-85 Sh1 0 3-xxvii 20 3.1-25 0 F2.5-58 0 F2.5-85 Sh2 0 3-xxviii 14 3.1-26 0 F2.5-59 0 F2.5-86 Sh1 0 3-xxix 20 3.1-27 7 F2.5-60 0 F2.5-86 Sh2 0 3-xxx 0 3.1-28 0 F2.5-61 0 F2.5-87 Sh1 0 3-xxxi 0 3.1-29 0 F2.5-62 0 F2.5-87 Sh2 0 3-xxxii 14 3.1-30 0 F2.5-63 0 F2.5-88 Sh1 0 3-xxxiii 0 3.1-31 0 F2.5-64 Sh1 0 F2.5-88 Sh2 0 3-xxxiv 0 3.1-32 0 F2.5-64 Sh2 0 F2.5-89 Sh1 0 3-xxxv 0 3.1-33 0 F2.5-64 Sh3 0 F2.5-89 Sh2 0 3-xxxvi 0 3.1-34 0 F2.5-65 Sh1 0 F2.5-90 Sh1 0 3-xxxvii 0 3.1-35 0 F2.5-65 Sh2 0 F2.5-90 Sh2 0 3-xxxviii 0 3.1-36 0 F2.5-65 Sh3 0 F2.5-91 Sh1 0 3-xxxix 0 3.1-37 9 F2.5-66 0 F2.5-91 Sh2 0 3-xL 0 3.1-38 0 9

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 3.1-39 0 3.2-4 0 T3.3-2 Sh1 0 3.5-19 14 3.1-40 11 T3.2-1 Sh1 12 T3.3-2 Sh2 7 3.5-20 14 3.1-41 0 T3.2-1 Sh2 12 3.4-1 14 3.5-21 14 3.1-42 9 T3.2-1 Sh3 14 3.4-2 0 3.5-22 14 3.1-43 0 T3.2-1 Sh4 14 3.4-3 0 3.5-23 14 3.1-44 8 T3.2-1 Sh5 8 3.4-4 0 3.5-24 14 3.1-45 17 T3.2-1 Sh6 15 3.4-5 0 3.5-25 14 3.1-46 0 T3.2-1 Sh7 12 3.4-6 0 3.5-26 14 3.1-47 0 T3.2-1 Sh8 21 3.4-7 20 3.5-27 14 3.1-48 0 T3.2-1 Sh9 18 3.4-8 0 3.5-28 14 3.1-49 0 T3.2-1 Sh10 8 3.4-9 0 3.5-29 14 3.1-50 0 T3.2-1 Sh11 11 3.4-10 0 3.5-30 14 3.1-51 0 T3.2-1 Sh12 8 3.4-11 14 3.5-31 14 3.1-52 0 T3.2-1 Sh13 17 3.4-12 20 3.5-32 14 3.1-53 0 T3.2-1 Sh14 19 3.4-13 0 3.5-33 14 3.1-54 0 T3.2-1 Sh15 8 3.4-14 0 3.5-34 14 3.1-55 0 T3.2-1 Sh16 8 T3.4-1 0 3.5-35 14 3.1-56 0 T3.2-1 Sh17 8 T3.4-2 Sh1 14 3.5-36 14 3.1-57 0 T3.2-1 Sh18 8 T3.4-2 Sh2 R 3.5-37 14 3.1-58 0 T3.2-1 Sh19 8 T3.4-2 Sh3 R 3.5-38 14 3.1-59 0 T3.2-1 Sh20 8 T3.4-2 Sh4 R 3.5-39 14 3.1-60 0 T3.2-1 Sh21 8 T3.4-2 Sh5 R 3.5-40 14 3.1-61 0 T3.2-1 Sh22 8 T3.4-2 Sh6 R 3.5-41 14 3.1-62 0 T3.2-1 Sh23 8 T3.4-3 0 3.5-42 14 3.1-63 15 T3.2-1 Sh24 12 T3.4-4 25 3.5-43 14 3.1-64 0 T3.2-1 Sh25 8 F3.4-1 0 3.5-44 14 3.1-65 0 T3.2-1 Sh26 14 F3.4-2 0 3.5-45 14 3.1-66 11 T3.2-1 Sh27 23 F3.4-3 Sh1 20 3.5-46 8 3.1-67 0 T3.2-1 Sh28 8 F3.4-3 Sh2 R 3.5-47 0 3.1-68 0 T3.2-1 Sh29 8 F3.4-3 Sh3 R 3.5-48 17 3.1-69 0 T3.2-1 Sh30 13 F3.4-3 Sh4 R 3.5-49 0 3.1-70 0 T3.2-1 Sh31 17 F3.4-4 0 3.5-50 8 3.1-71 9 T3.2-1 Sh32 8 3.5-1 20 3.5-51 0 3.1-72 9 T3.2-1 Sh33 8 3.5-2 21 3.5-52 0 3.1-73 0 T3.2-1 Sh34 12 3.5-3 0 3.5-53 8 3.1-74 0 T3.2-1 Sh35 8 3.5-4 8 3.5-54 0 3.1-75 0 T3.2-1 Sh36 23 3.5-5 0 3.5-55 0 3.1-76 0 T3.2-1 Sh37 8 3.5-6 9 3.5-56 17 3.1-77 17 T3.2-1 Sh38 8 3.5-7 11 3.5-57 21 3.1-78 11 T3.2-1 Sh39 8 3.5-8 26 3.5-58 0 3.1-79 11 T3.2-1 Sh40 8 3.5-9 17 3.5-59 14 3.1-80 0 T3.2-1 Sh41 8 3.5-10 20 3.5-60 14 3.1-81 0 T3.2-1 Sh42 16 3.5-11 14 3.5-61 26 3.1-82 14 T3.2-2 Sh1 0 3.5-12 14 T3.5-1 Sh1 0 3.1-83 0 T3.2-2 Sh2 17 3.5-13 14 T3.5-1 Sh2 0 3.1-84 0 T3.2-3 7 3.5-14 14 T3.5-2 Sh1 14 3.1-85 0 3.3-1 0 3.5-15 14 T3.5-2 Sh2 14 3.2-1 17 3.3-2 0 3.5-16 14 T3.5-3 14 3.2-2 0 3.3-3 0 3.5-17 14 T3.5-4 14 3.2-3 0 T3.3-1 0 3.5-18 14 T3.5-5 0 10

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T3.5-6 0 3.6-4 0 3.6-54 0 T3.6-5 Sh2 R T3.5-7 0 3.6-5 0 3.6-55 0 T3.6-6 12 T3.5-8 0 3.6-6 0 3.6-56 0 T3.6-6a 12 T3.5-9 0 3.6-7 17 3.6-57 0 T3.6-7 0 T3.5-10 0 3.6-8 17 3.6-58 0 T3.6-8 16 T3.5-11 Sh1 0 3.6-9 0 3.6-59 0 T3.6-8a 16 T3.5-11 Sh2 0 3.6-10 0 3.6-60 0 T3.6-9 16 T3.5-12 0 3.6-11 0 3.6-61 0 T3.6-10 Sh1 25 T3.5-13 Sh1 0 3.6-12 0 3.6-62 0 T3.6-10 Sh2 7 T3.5-13 Sh2 0 3.6-13 0 3.6-63 0 T3.6-11 25 T3.5-13 Sh3 0 3.6-14 19 3.6-64 0 T3.6-12 16 T3.5-13 Sh4 0 3.6-15 0 3.6-65 0 T3.6-13 24 T3.5-13 Sh5 0 3.6-16 0 3.6-66 0 T3.6-14 16 T3.5-13 Sh6 0 3.6-17 8 3.6-67 0 T3.6-15 0 T3.5-13 Sh7 21 3.6-18 0 3.6-68 0 T3.6-16 0 T3.5-13 Sh8 17 3.6-19 19 3.6-69 0 T3.6-17 Sh1 12 T3.5-13 Sh9 0 3.6-20 26 3.6-70 0 T3.6-17 Sh2 0 F3.5-1 0 3.6-21 14 3.6-71 8 T3.6-18 0 F3.5-2 20 3.6-22 17 3.6-72 0 T3.6-19 0 F3.5-3 20 3.6-23 0 3.6-73 0 T3.6-20 7 F3.5-4 20 3.6-24 14 3.6-74 0 T3.6-21 7 F3.5-5 20 3.6-25 0 3.6-75 0 T3.6-22 Sh1 7 F3.5-6 14 3.6-26 20 3.6-76 0 T3.6-22 Sh2 0 F3.5-7 20 3.6-27 0 3.6-77 0 T3.6-23 7 F3.5-8 20 3.6-28 0 3.6-78 0 T3.6-24 0 F3.5-9 20 3.6-29 20 3.6-79 0 T3.6-25 14 F3.5-10 10 3.6-30 0 3.6-80 0 T3.6-26 0 F3.5-11 14 3.6-31 0 3.6-81 0 T3.6-27 7 F3.5-12 14 3.6-32 0 3.6-82 0 T3.6-28 11 F3.5-13 14 3.6-33 0 3.6-83 0 T3.6-29 0 F3.5-14 14 3.6-34 0 3.6-84 0 F3.6-1 Sh1 0 F3.5-15 14 3.6-35 0 3.6-85 0 F3.6-1 Sh2 0 F3.5-16 14 3.6-36 0 3.6-86 0 F3.6-1 Sh3 0 F3.5-17 0 3.6-37 0 3.6-87 0 F3.6-1 Sh4 0 F3.5-18 0 3.6-38 0 3.6-88 0 F3.6-1 Sh5 0 F3.5-19 0 3.6-39 0 3.6-89 0 F3.6-1 Sh6 0 F3.5-20 0 3.6-40 0 3.6-90 0 F3.6-1 Sh7 0 F3.5-21 0 3.6-41 0 3.6-91 0 F3.6-2 Sh1 0 F3.5-22 0 3.6-42 0 3.6-92 0 F3.6-2 Sh2 0 F3.5-23 0 3.6-43 8 3.6-93 17 F3.6-3 12 F3.5-24 0 3.6-44 14 T3.6-1 Sh1 0 F3.6-4 0 F3.5-25 0 3.6-45 14 T3.6-1 Sh2 0 F3.6-5 0 F3.5-26 0 3.6-46 20 T3.6-1 Sh3 14 F3.6-6 0 F3.5-27 0 3.6-47 0 T3.6-2 Sh1 16 F3.6-7 0 F3.5-28 0 3.6-48 0 T3.6-2 Sh2 16 F3.6-8 0 F3.5-29 Sh1 20 3.6-49 0 T3.6-3 16 F3.6-9 0 F3.5-29 Sh2 R 3.6-50 0 T3.6-4 Sh1 17 F3.6-10 Sh1 0 3.6-1 0 3.6-51 0 T3.6-4 Sh2 17 F3.6-10 Sh2 7 3.6-2 0 3.6-52 0 T3.6-4 Sh3 17 F3.6-11 0 3.6-3 0 3.6-53 0 T3.6-5 Sh1 17 F3.6-12 0 11

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F3.6-13 0 3.7-6 0 3.7-56 10 F3.7-41 0 F3.6-14 8 3.7-7 0 3.7-57 0 F3.7-42 0 F3.6-15 7 3.7-8 0 T3.7-1 Sh1 0 F3.7-43 0 F3.6-16 Sh1 21 3.7-9 0 T3.7-1 Sh2 0 F3.7-44 0 F3.6-16 Sh2 0 3.7-10 8 T3.7-2 0 F3.7-45 0 F3.6-16 Sh3 2 3.7-11 0 T3.7-3 0 F3.7-46 0 F3.6-17 2 3.7-12 0 T3.7-4 0 F3.7-47 0 F3.6-18 0 3.7-13 0 T3.7-5 0 F3.7-48 0 F3.6-19 1 3.7-14 8 T3.7-6 0 F3.7-49 0 F3.6-20 1 3.7-15 0 T3.7-7 17 F3.7-50 0 F3.6-21 1 3.7-16 0 F3.7-1 0 F3.7-51 0 F3.6-22 0 3.7-17 17 F3.7-2 0 F3.7-52 0 F3.6-23 0 3.7-18 0 F3.7-3 0 F3.7-53 0 F3.6-24 1 3.7-19 0 F3.7-4 0 F3.7-54 0 F3.6-25 1 3.7-20 0 F3.7-5 0 F3.7-55 0 F3.6-26 0 3.7-21 0 F3.7-6 0 F3.7-56 0 F3.6-27 Sh1 7 3.7-22 0 F3.7-7 0 F3.7-57 0 F3.6-27 Sh2 12 3.7-23 0 F3.7-8 0 F3.7-58 0 F3.6-28 0 3.7-24 0 F3.7-9 0 F3.7-59 0 F3.6-29 0 3.7-25 0 F3.7-10 0 F3.7-60 0 F3.6-30 7 3.7-26 0 F3.7-11 0 F3.7-61 0 F3.6-31 Sh1 7 3.7-27 0 F3.7-12 0 F3.7-62 0 F3.6-31 Sh2 7 3.7-28 0 F3.7-13 0 F3.7-63 0 F3.6-32 0 3.7-29 0 F3.7-14 0 F3.7-64 0 F3.6-33 0 3.7-30 0 F3.7-15 0 F3.7-65 0 F3.6-34 0 3.7-31 0 F3.7-16 0 F3.7-66 0 F3.6-35 14 3.7-32 8 F3.7-17 0 F3.7-67 0 F3.6-36 0 3.7-33 0 F3.7-18 0 F3.7-68 0 F3.6-37 7 3.7-34 0 F3.7-19 0 F3.7-69 0 F3.6-38 0 3.7-35 17 F3.7-20 0 F3.7-70 0 F3.6-39 0 3.7-36 8 F3.7-21 0 F3.7-71 0 F3.6-40 0 3.7-37 0 F3.7-22 0 F3.7-72 0 F3.6-41 0 3.7-38 0 F3.7-23 0 F3.7-73 0 F3.6-42 0 3.7-39 0 F3.7-24 0 F3.7-74 0 F3.6-43 0 3.7-40 0 F3.7-25 0 F3.7-75 0 F3.6-44 0 3.7-41 0 F3.7-26 0 F3.7-76 0 F3.6-45 0 3.7-42 17 F3.7-27 0 F3.7-77 0 F3.6-46 1 3.7-43 0 F3.7-28 0 F3.7-78 0 F3.6-47 1 3.7-44 0 F3.7-29 0 F3.7-79 0 F3.6-48 Sh1 0 3.7-45 0 F3.7-30 0 F3.7-80 0 F3.6-48 Sh2 0 3.7-46 0 F3.7-31 0 F3.7-81 0 F3.6-48 Sh3 0 3.7-47 0 F3.7-32 0 F3.7-82 0 F3.6-48 Sh4 0 3.7-48 0 F3.7-33 0 F3.7-83 0 F3.6-48 Sh5 0 3.7-49 0 F3.7-34 0 F3.7-84 0 F3.6-48 Sh6 0 3.7-50 0 F3.7-35 0 F3.7-85 0 3.7-1 17 3.7-51 0 F3.7-36 0 F3.7-86 0 3.7-2 0 3.7-52 0 F3.7-37 0 F3.7-87 0 3.7-3 0 3.7-53 17 F3.7-38 0 F3.7-88 0 3.7-4 0 3.7-54 0 F3.7-39 0 F3.7-89 0 3.7-5 0 3.7-55 0 F3.7-40 0 F3.7-90 0 12

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F3.7-91 0 F3.7-141 0 3.8-27 0 3.8-77 0 F3.7-92 0 F3.7-142 0 3.8-28 0 3.8-78 0 F3.7-93 0 F3.7-143 0 3.8-29 0 3.8-79 0 F3.7-94 0 F3.7-144 0 3.8-30 0 3.8-80 0 F3.7-95 0 F3.7-145 0 3.8-31 0 3.8-81 0 F3.7-96 0 F3.7-146 0 3.8-32 0 3.8-82 0 F3.7-97 0 F3.7-147 0 3.8-33 0 3.8-83 0 F3.7-98 0 F3.7-148 0 3.8-34 0 3.8-84 0 F3.7-99 0 F3.7-149 0 3.8-35 0 3.8-85 0 F3.7-100 0 F3.7-150 0 3.8-36 0 3.8-86 17 F3.7-101 0 F3.7-151 0 3.8-37 0 3.8-87 0 F3.7-102 0 F3.7-152 0 3.8-38 20 3.8-88 8 F3.7-103 0 F3.7-153 0 3.8-39 16 3.8-89 0 F3.7-104 0 F3.7-154 0 3.8-40 20 T3.8-1 Sh1 0 F3.7-105 0 F3.7-155 0 3.8-41 20 T3.8-1 Sh2 0 F3.7-106 0 F3.7-156 0 3.8-42 20 T3.8-2 Sh1 0 F3.7-107 0 F3.7-156a 0 3.8-43 20 T3.8-2 Sh2 0 F3.7-108 0 F3.7-157 0 3.8-44 0 T3.8-2 Sh3 0 F3.7-109 0 F3.7-157a 0 3.8-45 20 T3.8-3 Sh1 0 F3.7-110 0 F3.7-158 0 3.8-46 0 T3.8-3 Sh2 0 F3.7-111 0 F3.7-159 0 3.8-47 17 T3.8-3 Sh3 0 F3.7-112 0 F3.7-160 0 3.8-48 0 T3.8-4 Sh1 0 F3.7-113 0 F3.7-161 0 3.8-49 0 T3.8-4 Sh2 0 F3.7-114 0 F3.7-162 0 3.8-50 0 T3.8-5 Sh1 17 F3.7-115 0 3.8-1 0 3.8-51 0 T3.8-5 Sh2 0 F3.7-116 0 3.8-2 0 3.8-52 0 T3.8-6 0 F3.7-117 0 3.8-3 0 3.8-53 0 T3.8-7 Sh1 0 F3.7-118 0 3.8-4 0 3.8-54 0 T3.8-7 Sh2 0 F3.7-119 0 3.8-5 0 3.8-55 0 T3.8-8 0 F3.7-120 0 3.8-6 17 3.8-56 0 T3.8-9 0 F3.7-121 0 3.8-7 0 3.8-57 0 T3.8-10 0 F3.7-122 0 3.8-8 0 3.8-58 0 T3.8-11 0 F3.7-123 0 3.8-9 0 3.8-59 0 T3.8-12 Sh1 0 F3.7-124 0 3.8-10 0 3.8-60 0 T3.8-12 Sh2 0 F3.7-125 0 3.8-11 0 3.8-61 0 T3.8-13 Sh1 0 F3.7-126 0 3.8-12 0 3.8-62 0 T3.8-13 Sh2 0 F3.7-127 0 3.8-13 0 3.8-63 0 T3.8-14 0 F3.7-128 0 3.8-14 0 3.8-64 0 T3.8-15 Sh1 0 F3.7-129 0 3.8-15 0 3.8-65 0 T3.8-15 Sh2 0 F3.7-130 0 3.8-16 0 3.8-66 0 T3.8-15 Sh3 0 F3.7-131 0 3.8-17 0 3.8-67 0 T3.8-15 Sh4 0 F3.7-132 0 3.8-18 0 3.8-68 0 T3.8-15 Sh5 0 F3.7-133 0 3.8-19 0 3.8-69 0 T3.8-15 Sh6 0 F3.7-134 0 3.8-20 0 3.8-70 0 T3.8-16 Sh1 0 F3.7-135 0 3.8-21 0 3.8-71 0 T3.8-16 Sh2 0 F3.7-136 0 3.8-22 0 3.8-72 0 T3.8-17 0 F3.7-137 0 3.8-23 9 3.8-73 0 T3.8-18 Sh1 0 F3.7-138 0 3.8-24 0 3.8-74 0 T3.8-18 Sh2 17 F3.7-139 0 3.8-25 0 3.8-75 0 T3.8-19 0 F3.7-140 0 3.8-26 0 3.8-76 0 T3.8-20 14 13

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F3.8-1 0 3.9-4 0 3.9-52 23 3.9-102 0 F3.8-2 0 3.9-5 14 3.9-53 0 3.9-103 0 F3.8-3 0 3.9-6 0 3.9-54 0 3.9-104 0 F3.8-4 0 3.9-7 0 3.9-55 0 3.9-105 16 F3.8-5 0 3.9-8 0 3.9-56 0 3.9-106 0 F3.8-6 0 3.9-9 0 3.9-57 0 3.9-107 0 F3.8-7 0 3.9-10 14 3.9-58 0 3.9-108 0 F3.8-8 0 3.9-11 18 3.9-59 0 3.9-109 8 F3.8-9 0 3.9-12 18 3.9-60 0 3.9-110 0 F3.8-10 0 3.9-13 18 3.9-61 0 3.9-111 25 F3.8-11 0 3.9-14 18 3.9-62 0 3.9-112 25 F3.8-12 0 3.9-15 18 3.9-63 0 3.9-113 0 F3.8-13 0 3.9-16 14 3.9-64 0 3.9-114 16 F3.8-14 0 3.9-17 0 3.9-65 0 3.9-115 0 F3.8-15 0 3.9-18 0 3.9-66 0 3.9-116 0 F3.8-16 0 3.9-19 8 3.9-67 0 3.9-117 0 F3.8-17 0 3.9-20 0 3.9-68 0 3.9-118 0 F3.8-18 0 3.9-21 0 3.9-69 0 3.9-119 0 F3.8-19 0 3.9-22 0 3.9-70 0 3.9-120 23 F3.8-20 0 3.9-23 0 3.9-71 0 3.9-121 25 F3.8-21 0 3.9-24 0 3.9-72 1 3.9-122 8 F3.8-22 0 3.9-25 0 3.9-73 0 3.9-123 25 F3.8-23 0 3.9-26 0 3.9-74 0 3.9-124 0 F3.8-24 0 3.9-27 8 3.9-75 0 3.9-125 12 F3.8-25 0 3.9-28 8 3.9-76 25 3.9-126 0 F3.8-26 0 3.9-29 0 3.9-77 1 3.9-127 1 F3.8-27 0 3.9-30 0 3.9-78 0 3.9-128 0 F3.8-28 0 3.9-31 0 3.9-79 0 3.9-129 1 F3.8-29 0 3.9-32 0 3.9-80 0 3.9-130 0 F3.8-30 0 3.9-33 0 3.9-81 0 3.9-131 1 F3.8-31 0 3.9-34 0 3.9-82 0 3.9-132 0 F3.8-32 0 3.9-35 0 3.9-83 0 3.9-133 0 F3.8-33 0 3.9-36 0 3.9-84 0 3.9-134 1 F3.8-34 0 3.9-37 0 3.9-85 9 3.9-134a 1 F3.8-35 0 3.9-38 0 3.9-86 0 3.9-134b 1 F3.8-36 0 3.9-39 0 3.9-87 0 3.9-135 1 F3.8-37 0 3.9-40 16 3.9-88 0 3.9-136 18 F3.8-38 0 3.9-40a 16 3.9-89 0 3.9-137 18 F3.8-39 0 3.9-40b 16 3.9-90 0 3.9-138 8 F3.8-40 0 3.9-41 0 3.9-91 0 3.9-139 0 F3.8-41 0 3.9-42 0 3.9-92 0 3.9-140 0 F3.8-42 0 3.9-43 0 3.9-93 0 3.9-141 0 F3.8-43 Sh1 0 3.9-44 0 3.9-94 15 3.9-142 14 F3.8-43 Sh2 0 3.9-45 0 3.9-95 0 3.9-143 0 F3.8-44 0 3.9-46 11 3.9-96 0 3.9-144 0 F3.8-45 0 3.9-47 0 3.9-97 19 3.9-145 0 F3.8-46 0 3.9-48 0 3.9-98 0 3.9-146 17 3.9-1 0 3.9-49 0 3.9-99 0 3.9-147 16 3.9-2 0 3.9-50 0 3.9-100 16 3.9-148 14 3.9-3 17 3.9-51 0 3.9-101 0 3.9-149 0 14

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 3.9-150 0 T3.9-4j Sh2 16 T3.9-4ee 11 T3.9-24 0 3.9-151 0 T3.9-4j Sh3 16 T3.9-5 Sh1 0 T3.9-25 17 3.9-152 0 T3.9-4j Sh4 16 T3.9-5 Sh2 12 T3.9-26 0 3.9-153 0 T3.9-4j Sh5 16 T3.9-5 Sh3 0 T3.9-27 Sh1 0 3.9-154 0 T3.9-4j Sh6 16 T3.9-5 Sh4 0 T3.9-27 Sh2 0 3.9-155 0 T3.9-4j Sh7 16 T3.9-5 Sh5 0 T3.9-27 Sh3 0 3.9-156 0 T3.9-4k Sh1 0 T3.9-6 Sh1 0 T3.9-28 0 3.9-157 0 T3.9-4k Sh2 0 T3.9-6 Sh2 0 T3.9-29 0 3.9-158 17 T3.9-4k Sh3 17 T3.9-6 Sh3 0 F3.9-1 0 3.9-159 17 T3.9-4k Sh4 7 T3.9-6 Sh4 0 F3.9-2 0 3.9-160 17 T3.9-4L Sh1 7 T3.9-6 Sh5 0 F3.9-3 0 3.9-160a 17 T3.9-4L Sh2 7 T3.9-6 Sh6 0 F3.9-4 0 3.9-160b 21 T3.9-4L Sh3 7 T3.9-6 Sh7 0 F3.9-5 9 3.9-161 4 T3.9-4L Sh4 7 T3.9-6 Sh8 0 F3.9-6 0 3.9-162 0 T3.9-4L Sh5 7 T3.9-7 Sh1 0 F3.9-7 0 3.9-163 14 T3.9-4L Sh6 7 T3.9-7 Sh2 0 F3.9-8 0 3.9-164 18 T3.9-4L Sh7 7 T3.9-8 0 F3.9-9 0 T3.9-1 Sh1 14 T3.9-4m 0 T3.9-9 Sh1 0 F3.9-10 0 T3.9-1 Sh2 0 T3.9-4n Sh1 0 T3.9-9 Sh2 0 F3.9-11 0 T3.9-1 Sh3 0 T3.9-4n Sh2 0 T3.9-10 0 F3.9-12 0 T3.9-1a 14 T3.9-4n Sh3 0 T3.9-11 Sh1 0 F3.9-13 0 T3.9-2 0 T3.9-4o 0 T3.9-11 Sh2 0 F3.9-14 0 T3.9-3 0 T3.9-4p 0 T3.9-12 0 F3.9-15 0 T3.9-4 Sh1 0 T3.9-4q Sh1 0 T3.9-13 0 F3.9-16 0 T3.9-4 Sh2 0 T3.9-4q Sh2 0 T3.9-14 Sh1 0 3.10-1 0 T3.9-4a Sh1 0 T3.9-4q Sh3 0 T3.9-14 Sh2 0 3.10-2 0 T3.9-4a Sh2 0 T3.9-4r Sh1 21 T3.9-15 0 3.10-3 0 T3.9-4b Sh1 14 T3.9-4r Sh2 R T3.9-16 0 3.10-4 0 T3.9-4b Sh2 17 T3.9-4s Sh1 0 T3.9-17 Sh1 0 3.10-5 0 T3.9-4b Sh3 18 T3.9-4s Sh2 0 T3.9-17 Sh2 0 3.10-6 0 T3.9-4b Sh4 0 T3.9-4s Sh3 0 T3.9-17 Sh3 0 3.10-7 0 T3.9-4c Sh1 18 T3.9-4t Sh1 0 T3.9-17 Sh4 0 3.10-8 0 T3.9-4c Sh2 18 T3.9-4t Sh2 0 T3.9-18 Sh1 14 3.10-9 0 T3.9-4c Sh3 18 T3.9-4t Sh3 0 T3.9-18 Sh2 0 3.10-10 0 T3.9-4d Sh1 2 T3.9-4u 0 T3.9-18 Sh3 19 3.10-11 0 T3.9-4d Sh2 2 T3.9-4v Sh1 21 T3.9-18 Sh4 12 3.10-12 0 T3.9-4d Sh3 0 T3.9-4v Sh2 21 T3.9-18 Sh5 12 3.10-13 0 T3.9-4e Sh1 16 T3.9-4v Sh3 21 T3.9-18 Sh6 9 3.10-14 0 T3.9-4e Sh2 16 T3.9-4v Sh4 0 T3.9-19 Sh1 0 3.10-15 0 T3.9-4f 16 T3.9-4w Sh1 0 T3.9-19 Sh2 0 3.10-16 0 T3.9-4g 12 T3.9-4w Sh2 0 T3.9-20 Sh1 0 T3.10-1 Sh1 0 T3.9-4h 12 T3.9-4x 18 T3.9-20 Sh2 0 T3.10-1 Sh2 0 T3.9-4i Sh1 16 T3.9-4y 18 T3.9-21 Sh1 0 T3.10-2 Sh1 0 T3.9-4i Sh1a 16 T3.9-4z 18 T3.9-21 Sh2 0 T3.10-2 Sh2 0 T3.9-4i Sh2 16 T3.9-4aa 18 T3.9-22 Sh1 0 T3.10-2 Sh3 0 T3.9-4i Sh3 16 T3.9-4bb 18 T3.9-22 Sh2 0 T3.10-2 Sh4 0 T3.9-4i Sh4 16 T3.9-4cc Sh1 17 T3.9-22 Sh3 0 T3.10-2 Sh5 0 T3.9-4i Sh5 16 T3.9-4cc Sh2 0 T3.9-22 Sh4 0 T3.10-2 Sh6 0 T3.9-4i Sh6 16 T3.9-4cc Sh3 0 T3.9-23 Sh1 0 T3.10-3 Sh1 0 T3.9-4j Sh1 16 T3.9-4dd 0 T3.9-23 Sh2 0 T3.10-3 Sh2 17 15

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T3.10-3 Sh3 0 3A-6 0 TIV-1 Sh1 21 F3H-1 0 T3.10-3 Sh4 0 3A-7 0 TIV-1 Sh2 21 3I-1 0 T3.10-3 Sh5 7 3A-8 0 TIV-2 Sh1 21 3I-2 0 T3.10-4 Sh1 17 3A-9 0 TIV-2 Sh2 21 3I-3 0 T3.10-4 Sh2 23 3A-10 0 TV-1 Sh1 21 T3I-1 0 T3.10-4 Sh3 0 3A-11 0 TV-1 Sh2 21 4-i 0 T3.10-4 Sh4 0 3A-12 0 TV-1 Sh3 21 4-ii 23 F3.10-1 0 3A-13 0 FII-1 0 4-iii 1 F3.10-2 0 3A-14 0 FII-2 0 4-iv 0 F3.10-3 0 3A-15 16 FII-3 0 4-v 23 F3.10-4 0 3A-16 16 FVI-1 0 4-vi 23 3.11-1 16 3A-17 16 FVI-2 0 4-vii 20 3.11-2 14 3A-18 16 FVII-1 0 4.1-1 11 3.11-3 20 T3A-1 Sh1 0 3C-1 15 4.1-2 7 3.11-3a R T3A-1 Sh2 0 3C-2 15 4.1-3 11 3.11-3b R T3A-1 Sh3 0 3C-3 15 4.1-4 0 3.11-4 20 T3A-1 Sh4 0 3C-4 15 4.1-5 0 3.11-5 5 T3A-1 Sh5 0 3C-5 15 4.1-6 0 3.11-6 0 T3A-1 Sh6 0 F3C-1 0 4.1-7 0 3.11-7 0 App 3B 11 3D-1 0 4.1-8 0 3.11-8 0 3B-i 0 3D-2 0 4.1-9 0 3.11-9 16 3B-ii 0 T3D-1 0 4.1-10 0 3.11-10 16 3B-1 9 T3D-2 0 4.1-11 0 3.11-11 0 3B-2 23 T3D-3 0 4.1-12 0 3.11-12 20 3B-3 23 T3D-4 0 4.1-13 0 3.11-13 14 3B-4 0 T3D-5 0 4.1-14 0 3.11-14 14 3B-5 0 F3D-1 0 4.1-15 0 3.11-15 0 3B-6 0 F3D-2 0 4.1-16 0 3.11-16 15 3B-7 0 3E-1 0 4.1-17 0 3.11-17 15 3B-8 0 3E-2 0 4.1-18 11 3.11-18 16 3B-9 0 3E-3 8 4.1-19 14 3.11-19 16 3B-10 0 3E-4 0 4.1-20 7 T3.11-1 5 3B-11 0 T3E-1 0 4.1-21 14 T3.11-2 5 3B-12 0 T3E-2 0 4.2-1 22 T3.11-3 Sh1 0 3B-13 0 T3E-3 0 4.2-2 17 T3.11-3 Sh2 14 3B-14 0 3F-1 0 4.2-3 23 T3.11-3 Sh3 5 3B-15 0 3F-2 20 4.3-1 22 T3.11-3 Sh4 0 3B-16 0 3F-3 0 4.3-2 23 T3.11-3 Sh5 5 3B-17 0 T3F-1 0 4.3-3 23 F3.11-1 5 3B-18 0 3G-1 0 4.3-4 R F3.11-2 5 3B-19 0 3G-2 0 T4.3-1 23 F3.11-3 5 3B-20 0 F3G-1 0 T4.3-2 12 F3.11-4 5 3B-21 0 F3G-2 0 T4.3-3 0 F3.11-5 5 3B-22 0 3H-1 8 F4.3-1 0 3A-i 16 3B-23 0 3H-2 0 F4.3-2 12 3A-1 0 3B-24 8 3H-3 0 F4.3-3 12 3A-2 0 3B-25 0 3H-4 0 4.4-1 22 3A-3 0 3B-26 0 3H-5 0 4.4-2 14 3A-4 0 3B-27 0 T3H-1 Sh1 0 4.4-3 0 3A-5 0 3B-28 0 T3H-1 Sh2 0 4.4-4 23 16

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 4.4-5 23 4.6-10 0 F4.6-7 Sh1 20 5.2-16 0 4.4-6 23 4.6-11 20 F4.6-7 Sh2 R 5.2-17 25 4.4-6a 17 4.6-12 20 F4.6-7 Sh3 R 5.2-17a 25 4.4-6b 1 4.6-13 11 F4.6-7 Sh4 R 5.2-17b 23 4.4-7 17 4.6-14 0 F4.6-8 0 5.2-17c 23 4.4-8 17 4.6-15 20 F4.6-9 0 5.2-17d 25 4.4-9 11 4.6-16 20 F4.6-10 20 5.2-18 25 4.4-10 14 4.6-17 20 5-i 0 5.2-19 25 4.4-11 23 4.6-18 0 5-ii 8 5.2-20 23 T4.4-1 Sh1 11 4.6-19 0 5-iii 0 5.2-21 23 T4.4-1 Sh2 11 4.6-20 14 5-iv 0 5.2-22 25 T4.4-1 Sh3 0 4.6-21 14 5-v 0 5.2-23 25 T4.4-2 11 4.6-22 20 5-vi 0 5.2-24 25 T4.4-3 11 4.6-23 0 5-vii 12 5.2-25 23 T4.4-4 11 4.6-24 0 5-viii 0 5.2-26 25 T4.4-5 0 4.6-25 0 5-ix 8 5.2-27 25 T4.4-6 Sh1 0 4.6-26 8 5-x 0 5.2-28 0 T4.4-6 Sh2 0 4.6-27 0 5-xi 20 5.2-29 0 T4.4-6 Sh3 0 4.6-28 0 5-xii 23 5.2-30 12 T4.4-7 0 4.6-29 0 5-xiii 20 5.2-31 12 F4.4-1 23 4.6-30 17 5-xiv 20 5.2-32 12 F4.4-1a 23 4.6-31 0 5.1-1 0 5.2-33 12 F4.4-2 0 4.6-32 0 5.1-2 20 5.2-34 12 F4.4-3 0 4.6-33 0 5.1-3 20 5.2-35 11 F4.4-4 0 4.6-34 0 5.1-4 0 5.2-36 13 F4.4-5 0 4.6-35 0 5.1-5 12 5.2-36a 13 4.5-1 0 4.6-36 0 5.1-6 0 5.2-36b 13 4.5-2 0 4.6-37 0 5.1-7 0 5.2-37 16 4.5-3 0 4.6-38 0 F5.1-1 17 5.2-38 0 4.5-4 0 4.6-39 0 F5.1-2 0 5.2-39 0 4.5-5 0 4.6-40 0 F5.1-3 Sh1 20 5.2-40 0 4.5-6 0 4.6-41 8 F5.1-3 Sh2 R 5.2-41 0 4.5-7 0 4.6-42 8 F5.1-4 Sh1 20 5.2-42 8 4.5-8 0 4.6-43 0 F5.1-4 Sh2 R 5.2-43 14 4.5-9 8 4.6-44 0 F5.1-5 20 5.2-44 0 4.5-10 9 4.6-45 7 5.2-1 9 5.2-45 8 4.5-11 8 4.6-46 0 5.2-2 0 5.2-46 8 4.5-12 8 4.6-47 0 5.2-3 0 5.2-47 0 4.5-13 8 4.6-48 24 5.2-4 0 5.2-48 4 4.5-14 0 4.6-49 0 5.2-5 11 5.2-49 8 4.5-15 8 4.6-50 0 5.2-6 14 5.2-50 0 4.6-1 0 4.6-51 0 5.2-7 0 5.2-51 0 4.6-2 0 4.6-52 14 5.2-8 0 5.2-52 9 4.6-3 8 F4.6-1 0 5.2-9 17 5.2-53 16 4.6-4 0 F4.6-2 0 5.2-10 17 5.2-54 21 4.6-5 0 F4.6-3 15 5.2-11 14 5.2-55 20 4.6-6 0 F4.6-4 15 5.2-12 20 5.2-56 0 4.6-7 0 F4.6-5 20 5.2-13 0 5.2-57 8 4.6-8 15 F4.6-6 Sh1 20 5.2-14 0 5.2-58 0 4.6-9 11 F4.6-6 Sh2 R 5.2-15 0 5.2-59 0 17

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 5.2-60 0 T5.2-8 13 5.3-30 0 5.4-39 0 5.2-61 0 T5.2-9 11 5.3-31 8 5.4-40 0 5.2-62 12 T5.2-10 0 5.3-32 0 5.4-41 8 5.2-63 20 T5.2-11 0 5.3-33 0 5.4-42 20 5.2-64 0 F5.2-1 0 5.3-34 23 5.4-43 20 5.2-65 0 F5.2-2 0 F5.3-1A 23 5.4-44 20 5.2-66 0 F5.2-3 0 F5.3-1B 23 5.4-45 8 5.2-67 0 F5.2-4 0 F5.3-1C 23 5.4-46 20 5.2-68 0 F5.2-5 0 F5.3-2 8 5.4-47 17 5.2-69 0 F5.2-6 0 F5.3-3 0 5.4-48 9 5.2-70 0 F5.2-7 0 F5.3-4 0 5.4-49 14 5.2-71 0 F5.2-8 25 F5.3-5 0 5.4-50 10 5.2-72 0 F5.2-8A R 5.4-1 0 5.4-51 20 5.2-73 0 F5.2-9 12 5.4-2 20 5.4-52 8 5.2-74 0 F5.2-10 0 5.4-3 23 5.4-53 11 5.2-75 0 F5.2-11 0 5.4-4 0 5.4-54 11 5.2-76 6 F5.2-12 0 5.4-5 23 5.4-55 11 5.2-77 17 F5.2-13 0 5.4-6 0 5.4-56 0 T5.2-1 sh1 25 F5.2-14 0 5.4-7 0 5.4-57 8 T5.2-2 Sh1 9 5.3-1 0 5.4-8 0 5.4-58 0 T5.2-2 Sh2 0 5.3-2 0 5.4-9 20 5.4-59 13 T5.2-2 Sh3 0 5.3-3 0 5.4-10 17 5.4-60 26 T5.2-2 Sh4 1 5.3-4 0 5.4-11 17 5.4-61 26 T5.2-2 Sh5 0 5.3-5 8 5.4-12 0 5.4-61a 4 T5.2-2 Sh6 0 5.3-6 23 5.4-13 17 5.4-61b 2 T5.2-2 Sh7 0 5.3-7 8 5.4-14 23 5.4-62 20 T5.2-2 Sh7a 23 5.3-8 23 5.4-15 17 5.4-63 13 T5.2-2 Sh8 0 5.3-9 12 5.4-16 17 5.4-64 20 T5.2-2 Sh9 0 5.3-10 0 5.4-17 0 5.4-65 17 T5.2-2 Sh10 9 5.3-11 23 5.4-18 17 5.4-66 20 T5.2-2 Sh11 0 5.3-11a R 5.4-19 0 5.4-67 12 T5.2-2 Sh12 0 5.3-11b R 5.4-20 17 5.4-68 0 T5.2-2 Sh13 16 5.3-12 5 5.4-21 12 5.4-69 0 T5.2-3 26 5.3-13 0 5.4-22 0 5.4-70 0 T5.2-4 0 5.3-14 0 5.4-23 0 5.4-71 0 T5.2-5 0 5.3-15 0 5.4-24 0 5.4-72 0 T5.2-6 0 5.3-16 12 5.4-25 17 5.4-73 0 T5.2-7 Sh1 18 5.3-17 23 5.4-26 0 5.4-74 0 T5.2-7 Sh2 0 5.3-18 23 5.4-27 0 5.4-75 0 T5.2-7 Sh3 17 5.3-19 0 5.4-28 20 T5.4-1 Sh1 12 T5.2-7 Sh4 16 5.3-20 12 5.4-29 17 T5.4-1 Sh2 17 T5.2-7 Sh5 0 5.3-21 0 5.4-30 17 T5.4-1 Sh3 17 T5.2-7 Sh6 0 5.3-22 0 5.4-31 20 T5.4-2 14 T5.2-7 Sh7 25 5.3-23 12 5.4-32 16 T5.4-3 21 T5.2-7 Sh7a R 5.3-24 12 5.4-33 0 F5.4-1 0 T5.2-7 Sh8 16 5.3-25 0 5.4-34 15 F5.4-2 Sh1 20 T5.2-7 Sh9 16 5.3-26 0 5.4-35 1 F5.4-2 Sh2 R T5.2-7 Sh10 17 5.3-27 18 5.4-36 15 F5.4-3 20 T5.2-7 Sh11 0 5.3-28 0 5.4-37 13 F5.4-4 0 T5.2-7 Sh12 0 5.3-29 0 5.4-38 14 F5.4-5 0 18

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F5.4-6 0 T5A-13 0 6-xxvii 20 6.2-7 17 F5.4-7 15 T5A-14 0 6-xxviii 0 6.2-8 17 F5.4-8 20 T5A-15 0 6-xxix 13 6.2-9 17 F5.4-9 20 T5A-16 0 6.0-1 0 6.2-10 17 F5.4-10 Sh1 20 T5A-17 0 6.0-2 12 6.2-11 17 F5.4-10 Sh2 R T5A-18 0 T6.0-1 Sh1 0 6.2-12 17 F5.4-11 0 T5A-19 17 T6.0-1 Sh2 0 6.2-13 23 F5.4-12 17 T5A-20 0 6.1-1 0 6.2-14 17 F5.4-13 Sh1 20 T5A-21 5 6.1-2 0 6.2-15 17 F5.4-13 Sh2 R T5A-22 0 6.1-3 0 6.2-16 23 F5.4-14 11 T5A-23 0 6.1-4 0 6.2-17 0 F5.4-15 11 T5A-24 5 6.1-5 0 6.2-18 23 F5.4-15D 11 T5A-25 0 6.1-6 0 6.2-19 0 F5.4-16 11 T5A-26 Sh1 0 6.1-7 0 6.2-20 17 F5.4-16A 11 T5A-26 Sh2 0 6.1-8 0 6.2-21 0 F5.4-16B 11 F5A-1 5 6.1-9 0 6.2-22 17 F5.4-17 20 F5A-2 5 6.1-10 0 6.2-23 0 F5.4-18 Sh1 20 F5A-3 5 T6.1-1 Sh1 0 6.2-24 0 F5.4-18 Sh2 R F5A-4 5 T6.1-1 Sh2 0 6.2-25 20 F5.4-19 20 F5A-5 5 T6.1-1 Sh3 0 6.2-26 0 F5.4-20 7 F5A-6 5 T6.1-1 Sh4 0 6.2-27 0 F5.4-21 0 F5A-7 0 T6.1-2 Sh1 0 6.2-28 0 5A-1 0 6-i 0 T6.1-2 Sh2 0 6.2-29 17 5A-2 5 6-ii 15 T6.1-2 Sh3 0 6.2-30 0 5A-3 8 6-iii 0 T6.1-2 Sh4 0 6.2-31 17 5A-4 14 6-iv 0 T6.1-2 Sh5 0 6.2-32 0 5A-5 14 6-v 19 T6.1-2 Sh6 0 6.2-33 17 5A-6 0 6-vi 12 T6.1-2 Sh7 0 6.2-34 17 5A-7 0 6-vii 0 T6.1-2 Sh8 0 6.2-35 17 5A-8 14 6-viii 0 T6.1-2 Sh9 0 6.2-36 0 5A-9 23 6-ix 17 T6.1-2 Sh10 0 6.2-37 0 5A-10 14 6-x 15 T6.1-2 Sh11 0 6.2-38 0 5A-10a 5 6-xi 24 T6.1-2 Sh12 0 6.2-39 12 5A-10b 5 6-xii 12 T6.1-2 Sh13 0 6.2-40 11 5A-11 14 6-xiii 14 T6.1-2 Sh14 0 6.2-41 11 T5A-1 Sh1 8 6-xiv 0 T6.1-2 Sh15 12 6.2-41a R T5A-1 Sh2 8 6-xv 17 T6.1-2 Sh16 12 6.2-41b R T5A-2 Sh1 8 6-xvi 20 T6.1-2 Sh17 0 6.2-42 17 T5A-2 Sh2 8 6-xvii 20 T6.1-3 Sh1 14 6.2-43 17 T5A-3 0 6-xviia R T6.1-3 Sh2 17 6.2-44 12 T5A-4 Sh1 14 6-xviib R T6.1-3 Sh3 R 6.2-45 20 T5A-4 Sh2 14 6-xviii 20 T6.1-4 Sh1 0 6.2-46 0 T5A-5 14 6-xix 20 T6.1-4 Sh2 0 6.2-47 9 T5A-6 0 6-xx 20 T6.1-4 Sh3 14 6.2-48 20 T5A-7 0 6-xxi 22 6.2-1 12 6.2-49 0 T5A-8 0 6-xxii 20 6.2-2 0 6.2-50 7 T5A-9 0 6-xxiii 22 6.2-3 0 6.2-51 12 T5A-10 0 6-xxiv 14 6.2-4 17 6.2-52 12 T5A-11 0 6-xxv 14 6.2-5 23 6.2-53 13 T5A-12 0 6-xxvi 14 6.2-6 17 6.2-53a R 19

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 6.2-53b R 6.2-97 20 T6.2-4 Sh1 17 T6.2-16 Sh13a 21 6.2-54 12 6.2-97a 2 T6.2-4 Sh2 R T6.2-16 Sh14 8 6.2-55 0 6.2-97b 2 T6.2-5 Sh1 17 T6.2-16 Sh14a 21 6.2-56 15 6.2-98 1 T6.2-5 Sh2 17 T6.2-16 Sh15 8 6.2-57 15 6.2-98a 1 T6.2-6 17 T6.2-16 Sh15a 21 6.2-58 0 6.2-98b 1 T6.2-7 Sh1 17 T6.2-16 Sh16 21 6.2-59 3 6.2-99 1 T6.2-7 Sh2 17 T6.2-16 Sh16a 21 6.2-60 0 6.2-100 20 T6.2-8 17 T6.2-16 Sh17 21 6.2-61 12 6.2-101 0 T6.2-9 17 T6.2-16 Sh17a 21 6.2-62 12 6.2-102 15 T6.2-9a 17 T6.2-16 Sh18 21 6.2-63 15 6.2-103 20 T6.2-10 17 T6.2-16 Sh18a 21 6.2-64 15 6.2-104 15 T6.2-11 Sh1 17 T6.2-16 Sh19 8 6.2-65 14 6.2-104a 15 T6.2-11 Sh2 R T6.2-16 Sh19a 21 6.2-66 0 6.2-104b 2 T6.2-12 Sh1 13 T6.2-16 Sh20 8 6.2-67 0 6.2-105 0 T6.2-12 Sh2 0 T6.2-16 Sh20a 21 6.2-68 0 6.2-106 15 T6.2-13 Sh1 15 T6.2-16 Sh21 21 6.2-69 12 6.2-107 15 T6.2-13 Sh2 12 T6.2-16 Sh21a 21 6.2-70 0 6.2-108 15 T6.2-13a 9 T6.2-16 Sh22 21 6.2-71 3 6.2-109 15 T6.2-14 0 T6.2-16 Sh22a 21 6.2-72 8 6.2-110 15 T6.2-14a Sh1 0 T6.2-16 Sh23 21 6.2-73 0 6.2-111 15 T6.2-14a Sh2 0 T6.2-16 Sh23a 21 6.2-74 0 6.2-112 15 T6.2-15 Sh1 12 T6.2-16 Sh24 21 6.2-75 0 6.2-113 15 T6.2-15 Sh2 10 T6.2-16 Sh24a 21 6.2-76 0 6.2-114 15 T6.2-15 Sh3 12 T6.2-16 Sh25 8 6.2-77 12 6.2-115 15 T6.2-15 Sh4 10 T6.2-16 Sh25a 21 6.2-77a R 6.2-116 15 T6.2-16 Sh1 21 T6.2-16 Sh26 8 6.2-77b R 6.2-117 15 T6.2-16 Sh1a 21 T6.2-16 Sh26a 21 6.2-78 12 6.2-118 12 T6.2-16 Sh2 21 T6.2-16 Sh27 8 6.2-78a R 6.2-119 20 T6.2-16 Sh2a 21 T6.2-16 Sh27a 21 6.2-78b R 6.2-120 9 T6.2-16 Sh3 21 T6.2-16 Sh28 8 6.2-79 12 6.2-121 17 T6.2-16 Sh3a 21 T6.2-16 Sh28a 8 6.2-79a R 6.2-122 17 T6.2-16 Sh4 21 T6.2-16 Sh28b 21 6.2-79b R 6.2-123 17 T6.2-16 Sh4a 21 T6.2-16 Sh28c 21 6.2-80 0 6.2-124 9 T6.2-16 Sh5 8 T6.2-16 Sh29 8 6.2-81 0 6.2-125 9 T6.2-16 Sh5a 21 T6.2-16 Sh30 0 6.2-82 0 6.2-126 21 T6.2-16 Sh6 21 T6.2-16 Sh31 17 6.2-83 15 6.2-127 9 T6.2-16 Sh6a 21 T6.2-16 Sh32 0 6.2-84 12 6.2-128 9 T6.2-16 Sh7 21 T6.2-16 Sh33 17 6.2-85 21 6.2-129 8 T6.2-16 Sh7a 21 T6.2-16 Sh33a 1 6.2-86 24 6.2-130 0 T6.2-16 Sh8 21 T6.2-17 Sh1 0 6.2-87 9 6.2-131 17 T6.2-16 Sh8a 21 T6.2-17 Sh2 17 6.2-88 9 6.2-132 15 T6.2-16 Sh9 8 T6.2-17 Sh3 2 6.2-89 21 6.2-133 17 T6.2-16 Sh9a 21 T6.2-17 Sh3a 2 6.2-90 12 T6.2-1 Sh1 9 T6.2-16 Sh10 8 T6.2-18 Sh1 15 6.2-91 1 T6.2-1 Sh2 17 T6.2-16 Sh10a 21 T6.2-18 Sh2 15 6.2-92 15 T6.2-2 Sh1 0 T6.2-16 Sh11 21 T6.2-19 Sh1 0 6.2-93 15 T6.2-2 Sh2 11 T6.2-16 Sh11a 21 T6.2-19 Sh2 0 6.2-94 15 T6.2-2 Sh3 0 T6.2-16 Sh12 8 T6.2-20 Sh1 15 6.2-95 0 T6.2-3 Sh1 17 T6.2-16 Sh12a 21 T6.2-20 Sh2 R 6.2-96 20 T6.2-3 Sh2 17 T6.2-16 Sh13 21 T6.2-21 Sh1 15 20

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T6.2-21 Sh2 R F6.2-9 17 F6.2-27 Sh27 0 F6.2-47 Sh3 12 T6.2-21a 15 F6.2-9a 17 F6.2-27 Sh28 0 F6.2-48 Sh1 0 T6.2-22 Sh1 7 F6.2-10 17 F6.2-27 Sh29 0 F6.2-48 Sh2 9 T6.2-22 Sh2 17 F6.2-10a 17 F6.2-27 Sh30 7 F6.2-49 0 T6.2-22 Sh3 0 F6.2-11 17 F6.2-27 Sh31 22 F6.2-50 0 T6.2-23 17 F6.2-12 17 F6.2-27 Sh32 9 6.3-1 9 T6.2-24 Sh1 21 F6.2-13 17 F6.2-27 Sh33 0 6.3-2 0 T6.2-24 Sh2 21 F6.2-14 17 F6.2-27 Sh34 0 6.3-3 11 T6.2-24 Sh3 21 F6.2-15 17 F6.2-27 Sh35 9 6.3-4 0 T6.2-24 Sh4 21 F6.2-16 17 F6.2-27 Sh36 0 6.3-5 0 T6.2-24 Sh5 21 F6.2-17 17 F6.2-27 Sh37 0 6.3-6 10 T6.2-24 Sh6 21 F6.2-18 17 F6.2-27 Sh38 7 6.3-7 10 T6.2-24 Sh7 21 F6.2-18a 17 F6.2-27 Sh39 0 6.3-8 0 T6.2-24 Sh8 21 F6.2-19 17 F6.2-27 Sh40 0 6.3-9 20 T6.2-24 Sh9 4 F6.2-20 20 F6.2-27 Sh41 0 6.3-10 12 T6.2-24 Sh10 4 F6.2-21 20 F6.2-27 Sh42 0 6.3-11 24 T6.2-24 Sh11 4 F6.2-22 20 F6.2-27 Sh43 0 6.3-12 13 T6.2-24 Sh12 4 F6.2-23 20 F6.2-27 Sh44 0 6.3-13 13 T6.2-24 Sh13 4 F6.2-24 20 F6.2-27 Sh45 0 6.3-14 9 T6.2-24 Sh14 21 F6.2-25 20 F6.2-27 Sh46 0 6.3-15 2 T6.2-24 Sh15 4 F6.2-26 12 F6.2-27 Sh47 0 6.3-16 20 T6.2-24 Sh16 4 F6.2-26a 12 F6.2-27 Sh48 9 6.3-17 0 T6.2-24 Sh17 21 F6.2-26b 12 F6.2-27 Sh49 0 6.3-18 0 T6.2-25 Sh1 14 F6.2-26c 12 F6.2-28 Sh1 0 6.3-19 10 T6.2-25 Sh2 8 F6.2-27 Sh1 12 F6.2-28 Sh2 8 6.3-20 20 T6.2-26 Sh1 22 F6.2-27 Sh2 8 F6.2-29 20 6.3-21 20 T6.2-26 Sh2 12 F6.2-27 Sh3 8 F6.2-30 20 6.3-22 0 T6.2-26 Sh3 22 F6.2-27 Sh4 8 F6.2-31 0 6.3-23 0 T6.2-27 17 F6.2-27 Sh5 9 F6.2-32 17 6.3-24 20 T6.2-28 0 F6.2-27 Sh6 7 F6.2-33 17 6.3-25 16 T6.2-29 17 F6.2-27 Sh7 0 F6.2-34 17 6.3-26 14 T6.2-30 Sh1 0 F6.2-27 Sh8 14 F6.2-35 17 6.3-27 0 T6.2-30 Sh2 14 F6.2-27 Sh9 0 F6.2-36 17 6.3-28 20 T6.2-30 Sh3 0 F6.2-27 Sh10 2 F6.2-37 17 6.3-29 11 T6.2-30 Sh4 0 F6.2-27 Sh11 0 F6.2-38 17 6.3-30 11 T6.2-30 Sh5 0 F6.2-27 Sh12 0 F6.2-39 17 6.3-31 11 T6.2-30 Sh6 17 F6.2-27 Sh13 7 F6.2-40 17 6.3-32 20 T6.2-30 Sh7 7 F6.2-27 Sh14 0 F6.2-41 20 6.3-33 8 T6.2-30 Sh8 22 F6.2-27 Sh15 8 F6.2-42 Sh1 0 6.3-34 0 T6.2-30 Sh9 0 F6.2-27 Sh16 9 F6.2-42 Sh2 0 6.3-35 11 F6.2-1 0 F6.2-27 Sh17 0 F6.2-42 Sh3 0 6.3-36 20 F6.2-2 17 F6.2-27 Sh18 0 F6.2-43 Sh1 0 6.3-37 14 F6.2-3 17 F6.2-27 Sh19 0 F6.2-43 Sh2 0 6.3-38 14 F6.2-4 17 F6.2-27 Sh20 9 F6.2-44 0 6.3-39 0 F6.2-5 17 F6.2-27 Sh21 9 F6.2-45 Sh1 12 6.3-40 14 F6.2-6 17 F6.2-27 Sh22 9 F6.2-45 Sh2 0 6.3-41 20 F6.2-7 17 F6.2-27 Sh23 0 F6.2-46 Sh1 12 6.3-42 22 F6.2-7a 17 F6.2-27 Sh24 0 F6.2-46 Sh2 0 6.3-43 22 F6.2-8 17 F6.2-27 Sh25 0 F6.2-47 Sh1 24 6.3-44 22 F6.2-8a 17 F6.2-27 Sh26 0 F6.2-47 Sh2 24 6.3-45 20 21

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 6.3-46 7 F6.3-22a 20 6.4-3b 5 T6.5-1 Sh2 0 6.3-47 0 F6.3-23 22 6.4-4 20 T6.5-1 Sh3 0 6.3-48 20 F6.3-23a 20 6.4-5 20 T6.5-2 0 6.3-49 0 F6.3-24 14 6.4-6 20 T6.5-3 Sh1 0 6.3-50 20 F6.3-25 14 6.4-7 0 T6.5-3 Sh2 0 6.3-51 22 F6.3-26 14 6.4-8 12 T6.5-4 Sh1 8 T6.3-1 Sh1 14 F6.3-27 14 6.4-9 19 T6.5-4 Sh2 8 T6.3-1 Sh2 2 F6.3-28 14 6.4-10 18 T6.5-4 Sh3 0 T6.3-2 Sh1 17 F6.3-29 14 6.4-11 16 6.6-1 9 T6.3-2 Sh2 17 F6.3-30 17 6.4-12 0 6.6-2 9 T6.3-2 Sh3 17 F6.3-31 17 6.4-13 0 6.6-3 15 T6.3-2 Sh4 22 F6.3-32 17 6.4-14 0 6.6-4 15 T6.3-2 Sh5 0 F6.3-32a 20 6.4-15 22 6.7-1 12 T6.3-2 Sh6 22 F6.3-33 17 6.4-16 19 6.7-2 R T6.3-3 22 F6.3-33a 20 6.4-17 19 6.7-3 R T6.3-3a 22 F6.3-34 14 6.4-18 R 6.7-4 R T6.3-4 14 F6.3-35 14 6.4-19 R 6.7-5 R T6.3-5 Sh1 14 F6.3-36 14 6.4-20 R 6.7-6 R T6.3-5 Sh2 R F6.3-37 14 6.4-21 R 6.7-7 R T6.3-5 Sh3 R F6.3-38 22 6.4-22 R 6.7-8 R T6.3-5 Sh4 R F6.3-39 22 6.4-23 R 6.7-9 R T6.3-6 14 F6.3-40 22 6.4-24 R 6.7-10 R T6.3-7 Sh1 24 F6.3-40a 20 6.4-25 R 6.7-11 R T6.3-7 Sh2 23 F6.3-41 22 6.4-26 R 6.7-12 R T6.3-7 Sh3 24 F6.3-41a 20 6.4-27 R T6.7-1 Sh1 12 F6.3-1 20 F6.3-42 14 6.4-28 R T6.7-1 Sh2 R F6.3-2 20 F6.3-43 14 6.4-29 R T6.7-1 Sh3 R F6.3-3 20 F6.3-44 14 6.4-30 R T6.7-1 Sh4 R F6.3-4 0 F6.3-45 14 6.4-31 R T6.7-1 Sh5 R F6.3-5 0 F6.3-46 14 T6.4-1 Sh1 2 F6.7-1 12 F6.3-6 6 F6.3-47 14 T6.4-1 Sh2 0 6.8-1 17 F6.3-7 20 F6.3-48 14 T6.4-2 18 6.8-2 20 F6.3-8 20 F6.3-49 14 T6.4-3 12 6.8-3 0 F6.3-9 12 F6.3-50 14 T6.4-4 22 6.8-4 20 F6.3-10 0 F6.3-51 14 T6.4-5 12 6.8-5 0 F6.3-11 0 F6.3-52 14 T6.4-6 0 6.8-6 0 F6.3-12 Sh1 11 F6.3-53 14 F6.4-1 20 6.8-7 13 F6.3-12 Sh2 12 F6.3-54 14 F6.4-2 0 6.8-8 13 F6.3-12 Sh3 9 F6.3-55 14 6.5-1 0 6.8-9 17 F6.3-13 0 F6.3-56 14 6.5-2 0 6.8-10 6 F6.3-14 22 F6.3-57 14 6.5-3 12 6.8-11 13 F6.3-14a 20 F6.3-58 14 6.5-4 0 6.8-12 20 F6.3-15 14 F6.3-59 14 6.5-5 0 6.8-13 0 F6.3-16 14 F6.3-60 14 6.5-6 0 6.8-14 13 F6.3-17 14 F6.3-61 14 6.5-7 0 6.8-15 13 F6.3-18 14 F6.3-62 14 6.5-8 0 6.8-16 13 F6.3-19 14 6.4-1 19 6.5-9 0 T6.8-1 Sh1 0 F6.3-20 22 6.4-2 16 6.5-10 20 T6.8-1 Sh2 0 F6.3-21 22 6.4-3 5 6.5-11 0 T6.8-1 Sh3 0 F6.3-22 22 6.4-3a 5 T6.5-1 Sh1 0 T6.8-2 Sh1 0 22

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T6.8-2 Sh2 13 6B-4 0 F6B-6 Sh7 0 7.1-17 1 T6.8-2 Sh3 10 6B-5 0 F6B-6 Sh8 0 7.1-18 0 T6.8-3 Sh1 17 6B-6 14 F6B-7 Sh1 0 7.1-19 20 T6.8-3 Sh2 17 6B-7 13 F6B-7 Sh2 0 7.1-20 0 T6.8-4 0 T6B-1 0 F6B-7 Sh3 0 7.1-21 0 T6.8-5 Sh1 13 T6B-2 Sh1 0 F6B-7 Sh4 0 7.1-22 0 T6.8-5 Sh2 13 T6B-2 Sh2 0 F6B-7 Sh5 0 7.1-23 7 T6.8-5 Sh3 0 T6B-2 Sh3 0 F6B-7 Sh6 0 7.1-24 0 T6.8-6 Sh1 0 T6B-3 0 F6B-7 Sh7 0 7.1-25 0 T6.8-6 Sh2 0 T6B-4 0 F6B-7 Sh8 0 7.1-26 0 T6.8-6 Sh3 0 T6B-5 14 F6B-8 0 7.1-27 0 T6.8-6 Sh4 0 T6B-6 Sh1 0 F6B-9 0 7.1-28 0 T6.8-6 Sh5 0 T6B-6 Sh2 0 F6B-10 0 7.1-29 0 T6.8-6 Sh6 0 T6B-6 Sh3 0 F6B-11 0 7.1-30 0 T6.8-6 Sh7 0 T6B-7 Sh1 0 F6B-12 0 7.1-31 0 T6.8-6 Sh8 17 T6B-7 Sh2 0 F6B-13 13 7.1-32 0 T6.8-6 Sh9 0 T6B-7 Sh3 0 F6B-14 13 7.1-33 0 6A-1 7 T6B-7 Sh4 0 6C-1 0 7.1-34 8 6A-2 7 T6B-7 Sh5 0 6C-2 0 7.1-35 8 6A-3 7 T6B-7 Sh6 0 T6C-1 0 7.1-36 18 6A-4 7 T6B-7 Sh7 0 T6C-2 0 7.1-37 18 6A-5 7 T6B-7 Sh8 0 7-i 0 7.1-38 8 6A-6 7 T6B-7 Sh9 0 7-ii 23 7.1-39 13 6A-7 7 T6B-7 Sh10 0 7-iii 0 7.1-40 8 6A-8 7 T6B-7 Sh11 0 7-iv 0 7.1-41 8 6A-9 7 T6B-7 Sh12 0 7-v 16 7.1-42 0 6A-10 7 T6B-7 Sh13 0 7-vi 8 7.1-43 0 6A-11 7 T6B-8 0 7-vii 12 7.1-44 18 6A-12 7 F6B-1 0 7-viii 23 7.1-45 0 6A-13 7 F6B-2 0 7-ix 20 7.1-46 0 6A-14 7 F6B-3a 0 7-x 20 7.1-47 0 6A-15 7 F6B-3b 0 7-xi 20 7.1-48 0 6A-16 7 F6B-4 Sh1 0 7-xii 20 7.1-49 0 6A-17 7 F6B-4 Sh2 0 7-xiii 20 7.1-50 0 6A-18 7 F6B-4 Sh3 0 7.1-1 0 7.1-51 0 6A-19 7 F6B-4 Sh4 0 7.1-2 0 7.1-52 0 6A-20 7 F6B-4 Sh5 0 7.1-3 15 7.1-53 0 T6A-1 Sh1 7 F6B-4 Sh6 0 7.1-4 0 7.1-54 0 T6A-1 Sh2 7 F6B-5 Sh1 0 7.1-5 14 7.1-55 0 T6A-2 7 F6B-5 Sh2 0 7.1-6 0 7.1-56 0 T6A-3 0 F6B-5 Sh3 0 7.1-7 0 7.1-57 0 F6A-1 7 F6B-5 Sh4 0 7.1-8 7 7.1-58 0 F6A-2 7 F6B-5 Sh5 0 7.1-9 7 7.1-59 0 F6A-3 7 F6B-5 Sh6 0 7.1-10 7 7.1-60 0 F6A-4 7 F6B-6 Sh1 0 7.1-11 0 7.1-61 0 F6A-5 7 F6B-6 Sh2 0 7.1-12 0 7.1-62 20 F6A-6 7 F6B-6 Sh3 0 7.1-13 0 7.1-63 20 6B-1 15 F6B-6 Sh4 0 7.1-14 0 7.1-64 0 6B-2 0 F6B-6 Sh5 0 7.1-15 0 7.1-65 15 6B-3 14 F6B-6 Sh6 0 7.1-16 12 7.1-66 17 23

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 7.1-67 15 7.2-18 19 7.3-15 0 7.3-63 0 7.1-68 15 7.2-19 7 7.3-16 20 7.3-64 20 7.1-69 15 7.2-20 23 7.3-17 17 7.3-65 20 7.1-70 0 7.2-21 8 7.3-18 8 7.3-66 20 T7.1-1 Sh1 12 7.2-22 0 7.3-19 20 7.3-67 20 T7.1-1 Sh2 19 7.2-23 0 7.3-20 20 7.3-68 12 T7.1-1 Sh3 23 7.2-24 8 7.3-21 20 7.3-69 12 T7.1-2 Sh1 8 7.2-25 0 7.3-22 12 7.3-70 0 T7.1-2 Sh2 23 7.2-26 0 7.3-23 0 7.3-71 20 T7.1-2 Sh3 8 7.2-27 0 7.3-24 7 7.3-72 12 T7.1-2 Sh4 23 7.2-28 0 7.3-25 4 7.3-73 20 T7.1-2 Sh5 8 7.2-29 23 7.3-26 17 7.3-74 16 T7.1-2 Sh6 23 7.2-30 20 7.3-27 4 7.3-75 16 T7.1-3 Sh1 12 7.2-31 0 7.3-27a 4 7.3-76 0 T7.1-3 Sh2 14 7.2-32 0 7.3-27b 4 7.3-77 0 T7.1-3 Sh3 12 7.2-33 23 7.3-28 17 7.3-78 20 T7.1-3 Sh4 14 7.2-34 12 7.3-29 0 7.3-79 0 T7.1-3 Sh5 8 7.2-35 0 7.3-30 0 7.3-80 0 T7.1-4 Sh1 0 7.2-36 23 7.3-31 12 7.3-81 20 T7.1-4 Sh2 0 7.2-37 23 7.3-32 12 7.3-82 20 T7.1-4 Sh3 0 7.2-38 19 7.3-33 12 7.3-83 19 T7.1-4 Sh4 0 7.2-39 0 7.3-34 20 7.3-84 20 T7.1-4 Sh5 0 7.2-40 0 7.3-35 12 7.3-85 12 F7.1-1 24 7.2-41 0 7.3-36 20 7.3-86 12 F7.1-2 0 7.2-42 0 7.3-37 13 7.3-87 12 F7.1-3 0 7.2-43 0 7.3-38 20 7.3-88 8 F7.1-4 0 T7.2-1 Sh1 7 7.3-39 20 7.3-89 12 F7.1-5 0 T7.2-1 Sh2 0 7.3-40 15 7.3-90 20 F7.1-6 0 T7.2-2 Sh1 23 7.3-41 15 7.3-91 20 F7.1-7 0 T7.2-3 Sh1 23 7.3-42 0 7.3-92 0 F7.1-8 0 F7.2-1 Sh1 20 7.3-43 20 7.3-93 20 F7.1-9 0 F7.2-1 Sh2 R 7.3-44 0 7.3-94 0 F7.1-10 0 F7.2-1 Sh3 R 7.3-45 20 7.3-95 0 7.2-1 20 F7.2-1 Sh4 R 7.3-46 8 7.3-96 20 7.2-2 0 F7.2-1 Sh5 R 7.3-47 20 7.3-97 0 7.2-3 0 F7.2-2 1 7.3-48 15 7.3-98 0 7.2-4 0 7.3-1 12 7.3-49 0 7.3-99 20 7.2-5 8 7.3-2 0 7.3-50 15 7.3-100 0 7.2-6 8 7.3-3 20 7.3-51 20 7.3-101 20 7.2-7 24 7.3-4 9 7.3-52 13 7.3-102 0 7.2-8 24 7.3-5 10 7.3-53 13 7.3-103 12 7.2-9 23 7.3-6 20 7.3-54 20 7.3-104 8 7.2-10 23 7.3-7 0 7.3-55 0 7.3-105 0 7.2-11 23 7.3-8 0 7.3-56 22 7.3-106 0 7.2-12 23 7.3-9 20 7.3-57 12 7.3-107 0 7.2-13 23 7.3-10 0 7.3-58 12 7.3-108 0 7.2-14 12 7.3-11 0 7.3-59 12 7.3-109 0 7.2-15 12 7.3-12 0 7.3-60 12 7.3-110 12 7.2-16 12 7.3-13 20 7.3-61 12 7.3-111 19 7.2-17 0 7.3-14 20 7.3-62 20 7.3-112 0 24

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 7.3-113 0 F7.3-1 Sh3 R F7.3-15 Sh2 R F7.3-21 Sh10 R 7.3-114 10 F7.3-1 Sh4 R F7.3-16 Sh1 20 F7.3-21 Sh11 R 7.3-115 0 F7.3-1 Sh5 R F7.3-16 Sh2 R F7.3-21 Sh12 R 7.3-116 12 F7.3-1 Sh6 R F7.3-16 Sh3 R F7.3-22 Sh1 20 7.3-117 20 F7.3-2 Sh1 20 F7.3-16 Sh4 R F7.3-22 Sh2 R 7.3-118 20 F7.3-2 Sh2 R F7.3-16 Sh5 R F7.3-22 Sh3 R 7.3-118a 5 F7.3-2 Sh3 R F7.3-16 Sh6 R F7.3-23 Sh1 20 7.3-118b 5 F7.3-2 Sh4 R F7.3-16 Sh7 R F7.3-23 Sh2 R 7.3-119 12 F7.3-2 Sh5 R F7.3-16 Sh8 R F7.3-23 Sh3 R 7.3-120 0 F7.3-2 Sh6 R F7.3-16 Sh9 R F7.3-23 Sh4 R 7.3-121 0 F7.3-3 Sh1 20 F7.3-16 Sh10 R F7.3-23 Sh5 R 7.3-122 0 F7.3-3 Sh2 R F7.3-17 Sh1 12 F7.3-23 Sh6 R 7.3-123 0 F7.3-3 Sh3 R F7.3-17 Sh2 R F7.3-24 Sh1 20 7.3-124 0 F7.3-3 Sh4 R F7.3-17 Sh3 R F7.3-24 Sh2 R 7.3-125 0 F7.3-4 Sh1 20 F7.3-18 Sh1 20 F7.3-24 Sh3 R 7.3-126 0 F7.3-4 Sh2 R F7.3-18 Sh2 R F7.3-24 Sh4 R 7.3-127 0 F7.3-4 Sh3 R F7.3-18 Sh3 R F7.3-24 Sh5 R 7.3-128 0 F7.3-5 Sh1 20 F7.3-18 Sh4 R F7.3-25 Sh1 20 7.3-129 0 F7.3-5 Sh2 R F7.3-18 Sh5 R F7.3-25 Sh2 R 7.3-130 0 F7.3-6 Sh1 20 F7.3-18 Sh6 R F7.3-25 Sh3 R T7.3-1 0 F7.3-6 Sh2 R F7.3-18 Sh7 R F7.3-26 Sh1 20 T7.3-2 13 F7.3-6 Sh3 R F7.3-19 Sh1 20 F7.3-26 Sh2 R T7.3-3 0 F7.3-7 Sh1 20 F7.3-19 Sh2 R F7.3-26 Sh3 R T7.3-4 13 F7.3-7 Sh2 R F7.3-19 Sh3 R F7.3-26 Sh4 R T7.3-5 Sh1 13 F7.3-7 Sh3 R F7.3-20 Sh1 20 F7.3-26 Sh5 R T7.3-5 Sh2 13 F7.3-7 Sh4 R F7.3-20 Sh2 R F7.3-26 Sh6 R T7.3-6 Sh1 14 F7.3-8 Sh1 20 F7.3-20 Sh3 R F7.3-26 Sh7 R T7.3-6 Sh2 0 F7.3-8 Sh2 R F7.3-20 Sh4 R F7.3-26 Sh8 R T7.3-7 0 F7.3-8 Sh3 R F7.3-20 Sh5 R F7.3-27 Sh1 20 T7.3-8 13 F7.3-8 Sh4 R F7.3-20 Sh6 R F7.3-27 Sh2 R T7.3-9 Sh1 13 F7.3-8 Sh5 R F7.3-20 Sh7 R F7.3-27 Sh3 R T7.3-9 Sh2 13 F7.3-8 Sh6 R F7.3-20 Sh8 R F7.3-27 Sh4 R T7.3-9 Sh3 13 F7.3-8 Sh7 R F7.3-20 Sh9 R F7.3-27 Sh5 R T7.3-10 Sh1 13 F7.3-8 Sh8 R F7.3-20 Sh10 R F7.3-27 Sh6 R T7.3-10 Sh2 13 F7.3-8 Sh9 R F7.3-20 Sh11 R F7.3-27 Sh7 R T7.3-10 Sh3 13 F7.3-8 Sh10 R F7.3-20 Sh12 R F7.3-27 Sh8 R T7.3-11 12 F7.3-8 Sh11 R F7.3-20 Sh13 R F7.3-27 Sh9 R T7.3-12 13 F7.3-8 Sh12 R F7.3-20 Sh14 R F7.3-27 Sh10 R T7.3-13 13 F7.3-8 Sh13 R F7.3-20 Sh15 R F7.3-28 Sh1 20 T7.3-14 Sh1 13 F7.3-9 20 F7.3-20 Sh16 R F7.3-28 Sh2 R T7.3-14 Sh2 13 F7.3-10 20 F7.3-20 Sh17 R F7.3-28 Sh3 R T7.3-15 Sh1 8 F7.3-11 0 F7.3-21 Sh1 20 7.4-1 0 T7.3-15 Sh1a 12 F7.3-12 0 F7.3-21 Sh2 R 7.4-2 20 T7.3-15 Sh2 17 F7.3-13 0 F7.3-21 Sh3 R 7.4-3 16 T7.3-15 Sh2a 17 F7.3-14 Sh1 20 F7.3-21 Sh4 R 7.4-4 20 T7.3-16 Sh1 8 F7.3-14 Sh2 R F7.3-21 Sh5 R 7.4-5 20 T7.3-16 Sh2 22 F7.3-14 Sh3 R F7.3-21 Sh6 R 7.4-6 0 T7.3-17 8 F7.3-14 Sh4 R F7.3-21 Sh7 R 7.4-7 0 F7.3-1 Sh1 20 F7.3-14 Sh5 R F7.3-21 Sh8 R 7.4-8 20 F7.3-1 Sh2 R F7.3-15 Sh1 20 F7.3-21 Sh9 R 7.4-9 9 25

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 7.4-10 14 T7.4-3 Sh5 17 7.5-26 0 F7.5-2 Sh2 20 7.4-11 20 T7.4-3 Sh6 0 7.5-27 20 F7.5-3 14 7.4-12 20 T7.4-3 Sh7 17 7.5-28 0 7.6-1 0 7.4-13 14 T7.4-3 Sh8 0 7.5-29 0 7.6-2 20 7.4-14 20 T7.4-3 Sh9 0 T7.5-1 Sh1 22 7.6-3 14 7.4-15 17 F7.4-1 Sh1 20 T7.5-1 Sh1a 8 7.6-4 7 7.4-16 17 F7.4-1 Sh2 R T7.5-1 Sh2 22 7.6-5 0 7.4-17 0 F7.4-1 Sh3 R T7.5-1 Sh2a 22 7.6-6 20 7.4-18 20 F7.4-1 Sh4 R T7.5-1 Sh3 22 7.6-7 0 7.4-19 18 F7.4-1 Sh5 R T7.5-1 Sh3a 22 7.6-8 0 7.4-20 16 F7.4-2 Sh1 20 T7.5-1 Sh4 8 7.6-9 0 7.4-21 8 F7.4-2 Sh2 R T7.5-1 Sh4a 8 7.6-10 0 7.4-22 11 F7.4-2 Sh3 R T7.5-1 Sh5 12 7.6-11 23 7.4-23 8 F7.4-2 Sh4 R T7.5-1 Sh5a 12 7.6-12 23 7.4-24 0 F7.4-2 Sh5 R T7.5-1 Sh6 14 7.6-13 23 7.4-25 0 F7.4-2 Sh6 R T7.5-1 Sh6a 14 7.6-14 24 7.4-26 0 F7.4-2 Sh7 R T7.5-1 Sh7 8 7.6-15 23 7.4-27 0 F7.4-2 Sh8 R T7.5-1 Sh7a 8 7.6-16 23 7.4-28 0 F7.4-2 Sh9 R T7.5-1 Sh8 8 7.6-17 23 7.4-29 0 F7.4-3 Sh1 20 T7.5-1 Sh8a 8 7.6-18 23 7.4-30 0 F7.4-3 Sh2 R T7.5-1 Sh9 12 7.6-18a R 7.4-31 0 F7.4-4 Sh1 20 T7.5-1 Sh9a 12 7.6-18b R 7.4-32 0 F7.4-4 Sh2 R T7.5-1 Sh10 17 7.6-19 20 7.4-33 19 F7.4-4 Sh3 R T7.5-1 Sh10a 8 7.6-20 17 7.4-34 0 F7.4-4 Sh4 R T7.5-1 Sh11 12 7.6-21 20 7.4-35 0 7.5-1 20 T7.5-1 Sh11a 12 7.6-22 15 7.4-36 0 7.5-2 14 T7.5-1 Sh12 11 7.6-22a 15 7.4-37 0 7.5-3 0 T7.5-1 Sh12a 8 7.6-22b 6 7.4-38 0 7.5-4 0 T7.5-1 Sh13 8 7.6-23 3 7.4-39 0 7.5-5 15 T7.5-1 Sh13a 8 7.6-24 20 7.4-40 0 7.5-6 20 T7.5-1 Sh14 8 7.6-25 0 7.4-41 0 7.5-7 11 T7.5-1 Sh14a 8 7.6-26 0 7.4-42 0 7.5-8 23 T7.5-1 Sh15 8 7.6-27 0 7.4-43 0 7.5-9 11 T7.5-1 Sh15a 8 7.6-28 0 7.4-44 0 7.5-10 18 T7.5-1 Sh16 14 7.6-29 20 7.4-45 0 7.5-11 18 T7.5-1 Sh16a 8 7.6-30 0 7.4-46 0 7.5-12 18 T7.5-1 Sh17 8 7.6-31 0 7.4-47 0 7.5-13 18 T7.5-1 Sh17a 8 7.6-32 0 7.4-48 6 7.5-14 18 T7.5-1 Sh18 8 7.6-33 14 7.4-49 0 7.5-15 18 T7.5-1 Sh18a 8 7.6-34 22 T7.4-1 0 7.5-16 8 T7.5-1 Sh19 8 7.6-35 22 T7.4-2 Sh1 0 7.5-17 10 T7.5-1 Sh19a 8 7.6-36 1 T7.4-2 Sh2 17 7.5-18 14 T7.5-1 Sh20 8 7.6-37 7 T7.4-2 Sh3 0 7.5-19 14 T7.5-1 Sh20a 8 7.6-38 0 T7.4-2 Sh4 0 7.5-20 14 T7.5-1 Sh21 8 7.6-39 0 T7.4-2 Sh5 17 7.5-21 14 T7.5-1 Sh21a 8 7.6-40 0 T7.4-3 Sh1 0 7.5-22 14 T7.5-1 Sh22 0 7.6-41 6 T7.4-3 Sh2 0 7.5-23 14 T7.5-1 Sh23 22 7.6-42 6 T7.4-3 Sh3 14 7.5-24 14 F7.5-1 20 7.6-43 23 T7.4-3 Sh4 0 7.5-25 0 F7.5-2 Sh1 12 7.6-44 23 26

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 7.6-45 3 F7.6-7 Sh3 R 7.7-32 23 F7.7-1 Sh7 R 7.6-46 0 F7.6-7 Sh4 R 7.7-33 23 F7.7-2 20 7.6-47 23 F7.6-7 Sh5 R 7.7-34 7 F7.7-3 0 7.6-48 23 F7.6-7 Sh6 R 7.7-35 7 F7.7-4 0 7.6-49 24 F7.6-7 Sh7 R 7.7-36 7 F7.7-5 0 7.6-50 24 F7.6-8 Sh1 20 7.7-37 17 F7.7-6 23 7.6-50a R F7.6-8 Sh2 R 7.7-38 7 F7.7-7 7 7.6-50b R F7.6-8 Sh3 R 7.7-39 7 F7.7-8 14 7.6-51 24 F7.6-8 Sh4 R 7.7-40 7 8-i 0 7.6-52 0 F7.6-8 Sh5 R 7.7-41 2 8-ii 0 7.6-53 0 F7.6-8 Sh6 R 7.7-42 2 8-iii 0 7.6-54 0 F7.6-8 Sh7 R 7.7-43 13 8-iv 0 7.6-55 8 F7.6-8 Sh8 R 7.7-44 13 8-v 0 7.6-56 0 F7.6-8 Sh9 R 7.7-45 14 8-vi 13 7.6-57 0 F7.6-9 0 7.7-46 14 8-vii 13 7.6-58 23 F7.6-10 16 7.7-47 14 8-viii 20 7.6-59 0 F7.6-11 7 7.7-48 14 8-ix 20 7.6-60 0 F7.6-12 1 7.7-49 23 8.1-1 0 7.6-61 0 F7.6-13 9 7.7-50 14 8.1-2 20 7.6-62 0 7.7-1 0 7.7-51 23 8.1-3 20 7.6-63 0 7.7-2 20 7.7-52 0 8.1-4 20 7.6-64 0 7.7-3 0 7.7-53 14 8.1-5 0 7.6-65 0 7.7-4 0 7.7-54 14 8.1-6 0 7.6-66 0 7.7-5 11 7.7-55 8 8.1-7 0 7.6-67 0 7.7-6 11 7.7-55a 16 8.1-8 0 7.6-68 0 7.7-7 0 7.7-55b 18 8.1-9 20 7.6-69 0 7.7-8 23 7.7-56 0 8.1-10 0 7.6-70 0 7.7-9 23 7.7-57 23 8.1-11 12 7.6-71 0 7.7-10 11 7.7-58 11 8.1-12 0 7.6-72 0 7.7-11 0 7.7-59 11 8.1-13 0 7.6-73 0 7.7-12 23 7.7-60 9 8.1-14 0 T7.6-1 0 7.7-13 0 7.7-61 0 8.1-15 0 T7.6-2 Sh1 23 7.7-14 23 7.7-62 0 8.1-16 0 T7.6-2 Sh2 23 7.7-15 17 7.7-63 0 8.1-17 23 T7.6-3 Sh1 23 7.7-16 0 7.7-64 9 8.1-18 23 T7.6-4 Sh1 0 7.7-17 19 7.7-65 9 8.1-19 0 T7.6-5 Sh1 0 7.7-18 0 7.7-66 0 8.1-20 0 T7.6-5 Sh2 0 7.7-19 19 T7.7-1 0 8.1-21 0 T7.6-5 Sh3 0 7.7-20 0 T7.7-2 Sh1 14 8.1-22 0 T7.6-6 Sh1 3 7.7-21 11 T7.7-2 Sh2 0 8.1-23 23 T7.6-7 Sh1 23 7.7-22 11 T7.7-3 Sh1 16 8.1-24 0 F7.6-1 0 7.7-23 9 T7.7-3 Sh2 13 8.1-25 0 F7.6-2 Sh1 20 7.7-24 23 T7.7-4 25 8.1-26 0 F7.6-2 Sh2 R 7.7-25 23 T7.7-5 8 8.1-27 23 F7.6-3 0 7.7-26 23 F7.7-1 Sh1 20 8.1-28 0 F7.6-4 0 7.7-27 23 F7.7-1 Sh2 R 8.1-29 15 F7.6-5 23 7.7-28 23 F7.7-1 Sh3 R 8.1-30 20 F7.6-6 0 7.7-29 23 F7.7-1 Sh4 R 8.1-31 8 F7.6-7 Sh1 20 7.7-30 26 F7.7-1 Sh5 R 8.1-32 15 F7.6-7 Sh2 R 7.7-31 23 F7.7-1 Sh6 R 8.1-33 8 27

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 8.1-34 0 8.3-12 0 8.3-60 9 T8.3-3 Sh12 R 8.1-35 0 8.3-13 0 8.3-61 18 T8.3-3 Sh13 R 8.1-36 0 8.3-14 22 8.3-62 23 T8.3-3 Sh14 R 8.1-37 0 8.3-15 1 8.3-63 0 T8.3-3 Sh15 R 8.1-38 8 8.3-16 0 8.3-64 0 T8.3-3 Sh16 R 8.1-39 0 8.3-17 8 8.3-65 10 T8.3-3 Sh17 R 8.1-40 0 8.3-18 25 8.3-66 0 T8.3-4 Sh1 12 8.1-41 0 8.3-19 25 8.3-67 24 T8.3-4 Sh2 R 8.1-42 8 8.3-20 9 8.3-68 0 T8.3-4 Sh3 R 8.1-43 0 8.3-21 0 8.3-69 11 T8.3-4 Sh4 R 8.1-44 0 8.3-22 20 8.3-70 0 T8.3-4 Sh5 R 8.1-45 0 8.3-23 0 8.3-71 0 T8.3-4 Sh6 R 8.1-46 1 8.3-24 11 8.3-72 0 T8.3-4 Sh7 R 8.1-47 0 8.3-25 11 T8.3-1 Sh1 12 T8.3-4 Sh8 R 8.1-48 0 8.3-26 11 T8.3-1 Sh2 12 T8.3-4 Sh9 R 8.1-49 0 8.3-27 0 T8.3-1 Sh3 13 T8.3-4 Sh10 R 8.1-50 0 8.3-28 0 T8.3-1 Sh4 12 T8.3-4 Sh11 R T8.1-1 0 8.3-29 0 T8.3-1 Sh5 12 T8.3-4 Sh12 R T8.1-2 Sh1 0 8.3-30 0 T8.3-1 Sh6 12 T8.3-4 Sh13 R T8.1-2 Sh2 0 8.3-31 0 T8.3-1 Sh7 12 T8.3-4 Sh14 R T8.1-2 Sh3 11 8.3-32 0 T8.3-1 Sh8 12 T8.3-4 Sh15 R F8.1-1 0 8.3-33 0 T8.3-1 Sh9 12 T8.3-4 Sh16 R F8.1-2 0 8.3-34 22 T8.3-1 Sh10 13 T8.3-4 Sh17 R 8.2-1 26 8.3-35 20 T8.3-2 Sh1 12 T8.3-5 Sh1 12 8.2-2 26 8.3-36 1 T8.3-2 Sh2 R T8.3-5 Sh2 R 8.2-3 26 8.3-36a 1 T8.3-2 Sh3 R T8.3-5 Sh3 R 8.2-4 26 8.3-36b 1 T8.3-2 Sh4 R T8.3-5 Sh4 R 8.2-5 0 8.3-37 16 T8.3-2 Sh5 R T8.3-5 Sh5 R 8.2-6 26 8.3-38 0 T8.3-2 Sh6 R T8.3-5 Sh6 R 8.2-7 25 8.3-39 8 T8.3-2 Sh7 R T8.3-5 Sh7 R 8.2-8 26 8.3-40 9 T8.3-2 Sh8 R T8.3-5 Sh8 R 8.2-9 26 8.3-41 0 T8.3-2 Sh9 R T8.3-5 Sh9 R 8.2-10 20 8.3-42 0 T8.3-2 Sh10 R T8.3-5 Sh10 R 8.2-11 7 8.3-43 20 T8.3-2 Sh11 R T8.3-5 Sh11 R 8.2-12 0 8.3-44 0 T8.3-2 Sh12 R T8.3-5 Sh12 R 8.2-13 0 8.3-45 20 T8.3-2 Sh13 R T8.3-5 Sh13 R T8.2-1 15 8.3-46 0 T8.3-2 Sh14 R T8.3-5 Sh14 R F8.2-1 20 8.3-47 0 T8.3-2 Sh15 R T8.3-5 Sh15 R F8.2-2 26 8.3-48 0 T8.3-2 Sh16 R T8.3-5 Sh16 R 8.3-1 20 8.3-49 20 T8.3-3 Sh1 12 T8.3-6 Sh1 12 8.3-2 7 8.3-50 6 T8.3-3 Sh2 R T8.3-6 Sh2 R 8.3-3 19 8.3-51 6 T8.3-3 Sh3 R T8.3-6 Sh3 R 8.3-4 11 8.3-52 8 T8.3-3 Sh4 R T8.3-6 Sh4 R 8.3-5 20 8.3-53 0 T8.3-3 Sh5 R T8.3-6 Sh5 R 8.3-6 0 8.3-54 0 T8.3-3 Sh6 R T8.3-6 Sh6 R 8.3-7 20 8.3-55 20 T8.3-3 Sh7 R T8.3-6 Sh7 R 8.3-8 0 8.3-56 13 T8.3-3 Sh8 R T8.3-6 Sh8 R 8.3-9 14 8.3-57 13 T8.3-3 Sh9 R T8.3-6 Sh9 R 8.3-10 22 8.3-58 20 T8.3-3 Sh10 R T8.3-6 Sh10 R 8.3-11 17 8.3-59 11 T8.3-3 Sh11 R T8.3-6 Sh11 R 28

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T8.3-6 Sh12 R F8.3-15 7 9-xvii 6 9.1-23b R T8.3-6 Sh13 R F8.3-16 Sh1 9 9-xviii 6 9.1-24 11 T8.3-6 Sh14 R F8.3-16 Sh2 11 9-xix 6 9.1-25 11 T8.3-6 Sh15 R F8.3-16 Sh3 9 9-xx 6 9.1-26 11 T8.3-6 Sh16 R F8.3-16 Sh4 13 9-xxi 6 9.1-27 11 T8.3-7a 13 F8.3-16 Sh5 8 9-xxii 6 9.1-28 11 T8.3-7b 13 F8.3-16 Sh6 8 9-xxiia 25 9.1-29 18 T8.3-7c 13 F8.3-16 Sh7 23 9-xxiii 20 9.1-30 18 T8.3-7d 13 F8.3-16 Sh8 8 9-xxiv 20 9.1-31 16 T8.3-8 Sh1 13 F8.3-17 Sh1 0 9-xxv 16 9.1-32 20 T8.3-8 Sh2 R F8.3-17 Sh1a 19 9-xxvi 25 9.1-33 17 T8.3-8 Sh3 R F8.3-17 Sh2 0 9-xxvii 20 9.1-33a 17 T8.3-9 Sh1 13 F8.3-17 Sh3 0 9-xxviii 20 9.1-33b 9 T8.3-9 Sh2 R F8.3-17 Sh3a 19 9-xxix 20 9.1-34 16 T8.3-9 Sh3 R F8.3-17 Sh4 0 9-xxx 20 9.1-35 20 T8.3-10a 13 F8.3-17 Sh5 0 9-xxxi 20 9.1-36 26 T8.3-10b 13 F8.3-17 Sh6 0 9-xxxii 20 9.1-37 0 T8.3-11 Sh1 15 F8.3-17 Sh7 0 9-xxxiii 20 9.1-38 11 T8.3-11 Sh2 9 F8.3-17 Sh8 0 9-xxxiv 19 9.1-39 14 T8.3-11 Sh3 9 F8.3-17 Sh9 0 9-xxxv 15 9.1-40 16 T8.3-11 Sh4 17 F8.3-17 Sh10 0 9-xxxvi 20 9.1-41 0 T8.3-11 Sh5 9 F8.3-17 Sh11 0 9-xxxvii 20 9.1-42 20 T8.3-11 Sh6 12 F8.3-17 Sh12 0 9.1-1 17 9.1-42a 16 F8.3-1 20 F8.3-17 Sh13 0 9.1-2 15 9.1-42b 9 F8.3-2 Sh1 20 F8.3-17 Sh14 0 9.1-3 15 9.1-43 17 F8.3-2 Sh2 R F8.3-17 Sh15 0 9.1-4 25 9.1-44 17 F8.3-3 20 F8.3-17 Sh16 0 9.1-4a 25 9.1-45 0 F8.3-4 20 F8.3-17 Sh17 0 9.1-4b 25 9.1-46 16 F8.3-5 Sh1 20 F8.3-17 Sh18 0 9.1-5 15 9.1-47 8 F8.3-5 Sh2 R F8.3-17 Sh19 0 9.1-6 14 9.1-48 26 F8.3-6 20 F8.3-17 Sh20 0 9.1-7 16 9.1-49 11 F8.3-7 20 F8.3-17 Sh21 0 9.1-8 17 9.1-50 17 F8.3-8 Sh1 20 F8.3-18 0 9.1-9 16 9.1-51 17 F8.3-8 Sh2 R F8.3-19 20 9.1-10 16 9.1-52 17 F8.3-8 Sh3 R 9-i 18 9.1-11 20 9.1-53 14 F8.3-8 Sh4 R 9-ii 0 9.1-12 20 9.1-54 16 F8.3-8 Sh5 R 9-iii 0 9.1-13 14 9.1-55 16 F8.3-9 20 9-iv 0 9.1-14 12 9.1-56 14 F8.3-10 Sh1 20 9-v 0 9.1-14a R 9.1-57 11 F8.3-10 Sh2 R 9-vi 18 9.1-14b R 9.1-58 17 F8.3-11 Sh1 20 9-vii 4 9.1-15 16 9.1-59 17 F8.3-11 Sh2 R 9-viii 4 9.1-16 25 9.1-60 10 F8.3-11 Sh3 R 9-ix 0 9.1-17 0 9.1-61 10 F8.3-11 Sh4 R 9-x 12 9.1-18 12 9.1-62 10 F8.3-11 Sh5 R 9-xi 11 9.1-19 11 9.1-63 11 F8.3-12 Sh1 20 9-xii 7 9.1-20 11 9.1-63a 7 F8.3-12 Sh2 R 9-xiii 0 9.1-21 11 9.1-63b 7 F8.3-12 Sh3 R 9-xiv 0 9.1-22 11 9.1-64 10 F8.3-13 20 9-xv 16 9.1-23 11 9.1-65 7 F8.3-14 1 9-xvi 8 9.1-23a R 9.1-65a 15 29

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 9.1-65b 15 9.1-103 0 9.1-147 0 T9.1-12 Sh6 17 9.1-66 10 9.1-104 15 9.1-148 16 T9.1-12 Sh7 16 9.1-67 0 9.1-105 15 9.1-149 16 T9.1-12 Sh8 16 9.1-68 10 9.1-106 15 9.1-149a 16 T9.1-12 Sh9 16 9.1-69 10 9.1-107 17 9.1-149b 3 T9.1-13 Sh1 0 9.1-70 15 9.1-108 17 9.1-150 0 T9.1-13 Sh2 0 9.1-70a 16 9.1-109 17 9.1-151 0 T9.1-13 Sh3 0 9.1-70b 1 9.1-110 0 9.1-152 0 T9.1-13 Sh4 0 9.1-71 11 9.1-111 0 9.1-153 0 T9.1-13 Sh5 0 9.1-72 13 9.1-112 0 9.1-154 0 T9.1-13 Sh6 15 9.1-73 11 9.1-113 0 9.1-155 15 T9.1-13 Sh7 15 9.1-74 10 9.1-114 0 9.1-156 13 T9.1-13 Sh8 0 9.1-75 17 9.1-115 0 9.1-157 0 T9.1-13 Sh9 14 9.1-76 20 9.1-116 16 9.1-158 11 T9.1-13 Sh10 15 9.1-77 17 9.1-117 11 9.1-159 11 T9.1-13 Sh11 0 9.1-78 20 9.1-117a 15 T9.1-1 Sh1 12 T9.1-14 Sh1 17 9.1-79 16 9.1-117b 2 T9.1-1 Sh2 12 T9.1-14 Sh2 17 9.1-80 20 9.1-118 16 T9.1-1 Sh3 12 T9.1-15 Sh1 15 9.1-81 18 9.1-119 16 T9.1-1 Sh4 12 T9.1-15 Sh2 0 9.1-81a R 9.1-120 16 T9.1-2 Sh1 12 T9.1-15 Sh3 14 9.1-81b R 9.1-121 16 T9.1-2 Sh2 R T9.1-15 Sh4 14 9.1-82 11 9.1-122 16 T9.1-3 Sh1 26 T9.1-15 Sh5 15 9.1-82a R 9.1-123 0 T9.1-3 Sh2 0 T9.1-16 0 9.1-82b R 9.1-124 16 T9.1-3 Sh3 0 T9.1-17 Sh1 17 9.1-83 11 9.1-125 7 T9.1-4 Sh1 18 T9.1-17 Sh2 17 9.1-84 10 9.1-126 13 T9.1-4 Sh2 R T9.1-18 Sh1 11 9.1-85 16 9.1-127 13 T9.1-4 Sh3 R T9.1-18 Sh2 R 9.1-86 16 9.1-128 16 T9.1-5 14 T9.1-19 Sh1 11 9.1-87 12 9.1-129 10 T9.1-6 Sh1 15 T9.1-19 Sh2 R 9.1-87a 12 9.1-130 17 T9.1-6 Sh2 0 T9.1-20 Sh1 11 9.1-87b 12 9.1-131 17 T9.1-7 Sh1 10 T9.1-20 Sh2 R 9.1-88 16 9.1-132 15 T9.1-7 Sh2 0 T9.1-21 Sh1 16 9.1-89 10 9.1-133 17 T9.1-8 Sh1 1 T9.1-21 Sh2 16 9.1-90 13 9.1-133a 16 T9.1-8 Sh2 1 T9.1-21 Sh3 16 9.1-90a R 9.1-133b 17 T9.1-9 10 T9.1-21 Sh4 16 9.1-90b R 9.1-133c 16 T9.1-10 Sh1 17 T9.1-22 Sh1 17 9.1-91 13 9.1-133d 16 T9.1-10 Sh1a 17 T9.1-22 Sh2 18 9.1-91a R 9.1-134 16 T9.1-10 Sh2 8 T9.1-22 Sh3 16 9.1-91b R 9.1-135 16 T9.1-10 Sh2a 18 F9.1-1 0 9.1-92 11 9.1-136 22 T9.1-10 Sh3 15 F9.1-2 0 9.1-93 7 9.1-137 16 T9.1-10 Sh3a 18 F9.1-3 Sh1 0 9.1-94 7 9.1-138 16 T9.1-10 Sh4 8 F9.1-3 Sh2 4 9.1-95 0 9.1-139 0 T9.1-11 Sh1 0 F9.1-3 Sh3 4 9.1-96 11 9.1-140 0 T9.1-11 Sh2 0 F9.1-3 Sh4 4 9.1-97 17 9.1-141 0 T9.1-11 Sh3 0 F9.1-4 5 9.1-98 0 9.1-142 0 T9.1-12 Sh1 16 F9.1-5 Sh1 20 9.1-99 0 9.1-143 16 T9.1-12 Sh2 17 F9.1-5 Sh2 R 9.1-100 16 9.1-144 16 T9.1-12 Sh3 17 F9.1-6 20 9.1-101 0 9.1-145 16 T9.1-12 Sh4 16 F9.1-7 0 9.1-102 0 9.1-146 16 T9.1-12 Sh5 16 F9.1-8 10 30

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F9.1-9 10 F9.1-41 1 9.2-45 20 F9.2-14 Sh2 R F9.1-10 10 F9.1-42 16 9.2-46 24 F9.2-14 Sh3 R F9.1-11 10 9.2-1 0 9.2-47 24 F9.2-14 Sh4 R F9.1-12 10 9.2-2 0 9.2-48 0 F9.2-15 Sh1 20 F9.1-13 0 9.2-3 20 9.2-49 20 F9.2-15 Sh2 R F9.1-14 0 9.2-4 16 9.2-50 21 F9.2-15 Sh3 R F9.1-15 10 9.2-5 26 9.2-51 17 F9.2-16 20 F9.1-16 Sh1 11 9.2-6 0 9.2-52 21 F9.2-17 20 F9.1-16 Sh2 11 9.2-7 26 9.2-52a 1 9.3-1 20 F9.1-17 20 9.2-8 16 9.2-52b 1 9.3-2 22 F9.1-18 0 9.2-9 0 9.2-53 20 9.3-3 22 F9.1-19 1 9.2-10 20 9.2-54 0 9.3-4 22 F9.1-20 16 9.2-11 20 T9.2-1 5 9.3-5 4 F9.1-21 14 9.2-12 9 T9.2-2 9 9.3-5a 3 F9.1-22 0 9.2-13 0 T9.2-3 Sh1 11 9.3-5b 3 F9.1-23 0 9.2-14 20 T9.2-3 Sh2 19 9.3-6 22 F9.1-24 0 9.2-15 25 T9.2-4 Sh1 23 9.3-7 14 F9.1-25 0 9.2-16 17 T9.2-4 Sh1a 23 9.3-8 14 F9.1-26 0 9.2-17 20 T9.2-4 Sh1b 23 9.3-9 20 F9.1-27 0 9.2-18 19 T9.2-4 Sh2 17 9.3-10 14 F9.1-28 0 9.2-18a 19 T9.2-4 Sh2a 17 9.3-10a R F9.1-29 0 9.2-18b 1 T9.2-4 Sh2b 17 9.3-10b R F9.1-30 0 9.2-19 13 T9.2-4 Sh2c 23 9.3-11 10 F9.1-31 0 9.2-20 8 T9.2-5 Sh1 0 9.3-12 20 F9.1-32 Sh1 16 9.2-21 19 T9.2-5 Sh2 0 9.3-13 0 F9.1-32 Sh1a R 9.2-22 18 T9.2-6 Sh1 13 9.3-14 0 F9.1-32 Sh2 R 9.2-23 20 T9.2-6 Sh2 17 9.3-15 0 F9.1-32 Sh3 R 9.2-24 8 T9.2-7 24 9.3-16 0 F9.1-32 Sh4 R 9.2-25 18 T9.2-8 24 9.3-17 0 F9.1-32 Sh5 R 9.2-26 20 T9.2-9 Sh1 11 9.3-18 2 F9.1-32 Sh6 R 9.2-27 16 T9.2-9 Sh2 11 9.3-19 0 F9.1-32 Sh7 R 9.2-28 17 F9.2-1 0 9.3-20 0 F9.1-32 Sh8 R 9.2-29 20 F9.2-2 20 9.3-21 2 F9.1-32 Sh9 R 9.2-30 25 F9.2-3 20 9.3-22 10 F9.1-32 Sh10 R 9.2-31 17 F9.2-4 Sh1 20 9.3-23 2 F9.1-32 Sh11 R 9.2-32 0 F9.2-4 Sh2 R 9.3-24 0 F9.1-32 Sh12 R 9.2-33 0 F9.2-4 Sh3 R 9.3-25 20 F9.1-32 Sh13 R 9.2-34 17 F9.2-5 20 9.3-26 0 F9.1-32 Sh13a R 9.2-35 17 F9.2-6 Sh1 20 9.3-27 0 F9.1-32 Sh13b R 9.2-36 20 F9.2-6 Sh2 R 9.3-28 2 F9.1-33 16 9.2-37 16 F9.2-7 8 9.3-29 0 F9.1-34 16 9.2-38 18 F9.2-8 20 9.3-30 0 F9.1-35 16 9.2-39 0 F9.2-9 20 9.3-31 0 F9.1-36 16 9.2-40 20 F9.2-10 20 9.3-32 22 F9.1-37 16 9.2-41 20 F9.2-11 Sh1 20 9.3-33 7 F9.1-38 0 9.2-42 7 F9.2-11 Sh2 R 9.3-34 9 F9.1-39 Sh1 11 9.2-42a 6 F9.2-12 25 9.3-35 20 F9.1-39 Sh2 R 9.2-42b 4 F9.2-13 Sh1 20 9.3-36 11 F9.1-40 Sh1 11 9.2-43 20 F9.2-13 Sh2 R 9.3-37 20 F9.1-40 Sh2 R 9.2-44 0 F9.2-14 Sh1 20 9.3-38 15 31

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 9.3-39 7 T9.3-6 Sh2 11 9.4-17 0 9.4-65 0 9.3-40 0 T9.3-6 Sh3 11 9.4-18 0 9.4-66 21 9.3-41 11 T9.3-6 Sh4 11 9.4-19 0 9.4-67 20 9.3-42 8 T9.3-7 9 9.4-20 0 9.4-68 21 9.3-43 11 T9.3-8 Sh1 17 9.4-21 0 9.4-69 23 9.3-44 11 T9.3-8 Sh2 7 9.4-22 20 9.4-70 17 9.3-45 0 F9.3-1 20 9.4-23 17 9.4-71 0 9.3-46 17 F9.3-2 20 9.4-24 20 9.4-72 0 9.3-46a 2 F9.3-3 20 9.4-25 0 9.4-73 0 9.3-46b 2 F9.3-4 Sh1 20 9.4-26 1 9.4-74 23 9.3-47 8 F9.3-4 Sh2 R 9.4-27 14 9.4-75 20 9.3-48 0 F9.3-4 Sh3 R 9.4-28 19 9.4-76 0 9.3-49 20 F9.3-5 Sh1 20 9.4-28a 1 9.4-77 21 9.3-50 0 F9.3-5 Sh2 R 9.4-28b 1 9.4-78 17 9.3-51 13 F9.3-6 Sh1 20 9.4-29 19 9.4-79 20 9.3-52 0 F9.3-6 Sh2 R 9.4-30 20 9.4-80 0 9.3-53 12 F9.3-7 Sh1 20 9.4-31 13 9.4-81 1 9.3-54 1 F9.3-7 Sh2 R 9.4-32 0 9.4-82 20 9.3-55 0 F9.3-7 Sh3 R 9.4-33 0 9.4-83 1 9.3-56 0 F9.3-8 20 9.4-34 0 9.4-83a 1 9.3-57 0 F9.3-9 1 9.4-35 0 9.4-83b 1 9.3-58 20 F9.3-10 0 9.4-36 0 9.4-84 0 9.3-59 20 F9.3-11 Sh1 20 9.4-37 17 9.4-85 0 9.3-59a R F9.3-11 Sh2 R 9.4-38 0 9.4-86 11 9.3-59b R F9.3-12 Sh1 20 9.4-39 0 9.4-87 11 9.3-60 12 F9.3-12 Sh2 R 9.4-40 0 9.4-88 11 9.3-61 20 F9.3-12 Sh3 R 9.4-41 0 9.4-89 11 9.3-62 12 F9.3-12 Sh4 R 9.4-42 21 9.4-90 0 9.3-62a R F9.3-13 20 9.4-43 17 9.4-91 0 9.3-62b R F9.3-14 Sh1 20 9.4-44 17 9.4-92 0 9.3-63 13 F9.3-14 Sh2 R 9.4-45 14 9.4-93 20 9.3-64 16 F9.3-14 Sh3 R 9.4-46 20 9.4-94 0 9.3-65 12 F9.3-14 Sh4 R 9.4-47 0 9.4-95 0 9.3-65a R F9.3-15 20 9.4-48 0 9.4-96 18 9.3-65b R 9.4-1 18 9.4-49 0 9.4-97 18 9.3-66 R 9.4-2 8 9.4-50 20 9.4-98 0 T9.3-1 Sh1 3 9.4-3 0 9.4-51 0 9.4-99 8 T9.3-1 Sh2 22 9.4-4 0 9.4-52 0 9.4-100 8 T9.3-1 Sh3 22 9.4-5 14 9.4-53 0 9.4-101 20 T9.3-1 Sh4 22 9.4-6 0 9.4-54 20 9.4-102 18 T9.3-1 Sh5 17 9.4-7 0 9.4-55 20 T9.4-1 Sh1 2 T9.3-2 9 9.4-8 20 9.4-56 20 T9.4-1 Sh2 0 T9.3-3 Sh1 11 9.4-9 0 9.4-57 0 T9.4-1 Sh3 0 T9.3-3 Sh2 9 9.4-10 20 9.4-58 0 T9.4-2 Sh1 0 T9.3-3 Sh3 9 9.4-11 20 9.4-59 0 T9.4-2 Sh2 0 T9.3-4 Sh1 8 9.4-12 14 9.4-60 0 T9.4-2 Sh3 0 T9.3-4 Sh2 8 9.4-13 0 9.4-61 0 T9.4-3 Sh1 12 T9.3-5 Sh1 19 9.4-14 0 9.4-62 0 T9.4-3 Sh2 0 T9.3-5 Sh2 0 9.4-15 0 9.4-63 0 T9.4-4 0 T9.3-6 Sh1 11 9.4-16 0 9.4-64 9 T9.4-5 0 32

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T9.4-6 Sh1 0 T9.4-22 Sh2 17 9.5-22 0 9.5-64 14 T9.4-6 Sh2 0 T9.4-22 Sh3 0 9.5-23 0 9.5-65 2 T9.4-6 Sh3 0 T9.4-22 Sh4 0 9.5-24 20 9.5-66 20 T9.4-6 Sh4 0 T9.4-22 Sh5 0 9.5-25 20 9.5-67 15 T9.4-6 Sh5 0 F9.4-1 20 9.5-26 0 9.5-68 0 T9.4-6 Sh6 0 F9.4-2 20 9.5-27 25 9.5-69 0 T9.4-6 Sh7 0 F9.4-3 20 9.5-28 6 9.5-70 0 T9.4-6 Sh8 0 F9.4-4 20 9.5-29 7 9.5-71 0 T9.4-6 Sh9 0 F9.4-5 20 9.5-30 0 9.5-72 24 T9.4-6 Sh10 0 F9.4-6 Sh1 20 9.5-31 23 9.5-73 12 T9.4-7 Sh1 1 F9.4-6 Sh2 R 9.5-32 23 9.5-73a R T9.4-7 Sh2 0 F9.4-6 Sh3 R 9.5-33 23 9.5-73b R T9.4-8 10 F9.4-7 20 9.5-34 23 9.5-74 0 T9.4-9 Sh1 8 F9.4-8 Sh1 20 9.5-35 0 9.5-75 6 T9.4-9 Sh1a 8 F9.4-8 Sh2 R 9.5-36 0 9.5-76 0 T9.4-10 Sh1 9 F9.4-9 Sh1 20 9.5-37 18 9.5-77 8 T9.4-10 Sh1a 8 F9.4-9 Sh2 R 9.5-38 2 9.5-78 23 T9.4-10 Sh2 8 F9.4-10 20 9.5-39 23 9.5-78a 23 T9.4-10 Sh2a 10 F9.4-11 20 9.5-40 23 9.5-78b 9 T9.4-11 Sh1 0 F9.4-12 20 9.5-40a R 9.5-79 20 T9.4-11 Sh2 0 F9.4-13 20 9.5-40b R 9.5-80 9 T9.4-12 Sh1 0 F9.4-14 20 9.5-41 23 9.5-81 0 T9.4-12 Sh2 0 F9.4-15 Sh1 20 9.5-42 8 9.5-82 20 T9.4-12 Sh3 0 F9.4-15 Sh2 R 9.5-43 23 9.5-83 0 T9.4-12 Sh4 0 F9.4-16 Sh1 20 9.5-44 23 9.5-84 23 T9.4-12 Sh5 13 F9.4-16 Sh2 R 9.5-45 23 9.5-85 20 T9.4-12 Sh6 13 F9.4-17 20 9.5-46 5 9.5-86 20 T9.4-12 Sh7 0 F9.4-18 20 9.5-47 7 9.5-87 11 T9.4-12 Sh8 21 F9.4-19 20 9.5-48 12 9.5-88 8 T9.4-12 Sh9 13 9.5-1 0 9.5-48a 5 9.5-89 25 T9.4-13 0 9.5-2 0 9.5-48b 5 9.5-90 18 T9.4-14 Sh1 0 9.5-3 20 9.5-49 0 9.5-90a 1 T9.4-14 Sh2 0 9.5-4 23 9.5-50 14 9.5-90b 1 T9.4-15 8 9.5-5 16 9.5-51 11 9.5-91 0 T9.4-16 Sh1 0 9.5-6 24 9.5-52 20 9.5-92 20 T9.4-16 Sh2 11 9.5-7 15 9.5-53 14 9.5-93 9 T9.4-16 Sh3 0 9.5-8 15 9.5-54 23 9.5-94 0 T9.4-17 Sh1 0 9.5-9 0 9.5-55 0 9.5-95 20 T9.4-17 Sh2 0 9.5-10 14 9.5-56 0 9.5-96 0 T9.4-18 0 9.5-11 14 9.5-57 14 9.5-97 0 T9.4-19 0 9.5-12 0 9.5-58 20 9.5-98 20 T9.4-20 Sh1 0 9.5-13 9 9.5-59 0 9.5-99 0 T9.4-20 Sh2 0 9.5-14 14 9.5-60 14 9.5-100 0 T9.4-20 Sh3 8 9.5-15 14 9.5-61 22 9.5-101 16 T9.4-20 Sh4 8 9.5-16 0 9.5-61a R 9.5-102 20 T9.4-20 Sh5 18 9.5-17 0 9.5-61b R 9.5-102a R T9.4-21 Sh1 0 9.5-18 0 9.5-62 22 9.5-102b R T9.4-21 Sh2 17 9.5-19 0 9.5-63 17 9.5-103 20 T9.4-21 Sh3 0 9.5-20 14 9.5-63a 12 9.5-104 16 T9.4-22 Sh1 0 9.5-21 0 9.5-63b 12 9.5-105 0 33

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 9.5-106 20 9.5-156 20 T9.5-5 Sh2 0 T9.5-24 5 9.5-107 23 9.5-157 20 T9.5-6 Sh1 0 T9.5-25 Sh1 9 9.5-108 0 9.5-158 0 T9.5-6 Sh2 0 T9.5-25 Sh2 0 9.5-109 0 9.5-159 23 T9.5-7 16 T9.5-25 Sh3 0 9.5-110 22 9.5-160 20 T9.5-8 Sh1 0 T9.5-26 5 9.5-111 22 9.5-161 20 T9.5-8 Sh2 16 T9.5-27 Sh1 11 9.5-112 22 9.5-162 3 T9.5-9 Sh1 0 T9.5-27 Sh2 11 9.5-113 22 9.5-163 3 T9.5-9 Sh2 0 T9.5-27 Sh3 11 9.5-114 22 9.5-164 0 T9.5-10 0 T9.5-27 Sh4 11 9.5-115 0 9.5-165 0 T9.5-11 Sh1 0 T9.5-27 Sh5 11 9.5-116 22 9.5-166 0 T9.5-11 Sh2 0 T9.5-27 Sh6 11 9.5-117 22 9.5-167 0 T9.5-11 Sh3 0 T9.5-28 5 9.5-118 16 9.5-168 0 T9.5-11 Sh4 0 T9.5-29 0 9.5-119 20 9.5-169 0 T9.5-12 Sh1 0 T9.5-30 9 9.5-120 16 9.5-170 11 T9.5-12 Sh2 0 F9.5-1 20 9.5-121 20 9.5-171 11 T9.5-12 Sh3 17 F9.5-2 20 9.5-122 8 9.5-172 0 T9.5-13 Sh1 0 F9.5-3 20 9.5-123 20 9.5-173 20 T9.5-13 Sh2 0 F9.5-4 20 9.5-124 0 9.5-173a 1 T9.5-14 0 F9.5-5 20 9.5-125 7 9.5-173b 1 T9.5-15 8 F9.5-6 20 9.5-126 20 9.5-174 0 T9.5-16 4 F9.5-7 20 9.5-127 20 9.5-175 20 T9.5-17 Sh1 17 F9.5-8 20 9.5-128 20 9.5-176 17 T9.5-17 Sh2 0 F9.5-9 20 9.5-129 20 9.5-177 0 T9.5-17 Sh3 0 F9.5-10 20 9.5-130 0 9.5-178 0 T9.5-17 Sh4 0 F9.5-11 20 9.5-131 0 9.5-179 17 T9.5-17 Sh5 16 F9.5-12 20 9.5-132 16 9.5-180 17 T9.5-17 Sh6 0 F9.5-12a 20 9.5-133 0 9.5-181 15 T9.5-17 Sh7 0 F9.5-13 20 9.5-134 0 9.5-182 0 T9.5-17 Sh8 0 F9.5-14 20 9.5-135 0 9.5-183 4 T9.5-17 Sh9 0 F9.5-15 20 9.5-136 0 T9.5-1 Sh1 0 T9.5-17 Sh10 11 F9.5-16 20 9.5-137 20 T9.5-1 Sh2 9 T9.5-17 Sh11 8 F9.5-17 20 9.5-138 16 T9.5-2 Sh1 14 T9.5-17 Sh12 3 F9.5-18 20 9.5-139 16 T9.5-2 Sh2 2 T9.5-18 Sh1 0 F9.5-19 20 9.5-140 0 T9.5-2 Sh3 0 T9.5-18 Sh2 0 F9.5-20 20 9.5-141 20 T9.5-2 Sh4 7 T9.5-19 Sh1 23 F9.5-21 Sh1 20 9.5-142 0 T9.5-2 Sh5 0 T9.5-19 Sh2 23 F9.5-21 Sh2 R 9.5-143 16 T9.5-2 Sh6 2 T9.5-19 Sh3 0 F9.5-21 Sh3 R 9.5-144 20 T9.5-2 Sh7 0 T9.5-19 Sh4 0 F9.5-21a Sh1 20 9.5-145 0 T9.5-2 Sh8 2 T9.5-19 Sh5 25 F9.5-21a Sh2 R 9.5-146 0 T9.5-3 Sh1 17 T9.5-20 5 F9.5-22 20 9.5-147 0 T9.5-3 Sh1a 7 T9.5-21 Sh1 9 F9.5-23 Sh1 20 9.5-148 0 T9.5-3 Sh2 8 T9.5-21 Sh2 9 F9.5-23 Sh2 R 9.5-149 20 T9.5-3 Sh3 25 T9.5-21 Sh3 8 F9.5-24 Sh1 20 9.5-150 20 T9.5-3 Sh4 25 T9.5-21 Sh4 0 F9.5-24 Sh2 R 9.5-151 0 T9.5-3 Sh5 25 T9.5-22 5 F9.5-25 20 9.5-152 20 T9.5-4 Sh1 10 T9.5-23 Sh1 0 F9.5-26 Sh1 20 9.5-153 0 T9.5-4 Sh2 0 T9.5-23 Sh2 0 F9.5-26 Sh2 R 9.5-154 12 T9.5-4 Sh3 0 T9.5-23 Sh3 11 F9.5-27 Sh1 20 9.5-155 0 T9.5-5 Sh1 0 T9.5-23 Sh4 0 F9.5-27 Sh2 R 34

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F9.5-28 20 9A-25 26 9A-71 26 T9A-1 Sh11 26 F9.5-29 Sh1 20 9A-26 26 9A-72 26 T9A-1 Sh12 26 F9.5-29 Sh2 R 9A-27 26 9A-73 26 T9A-1 Sh13 26 F9.5-30 8 9A-28 26 9A-74 26 T9A-1 Sh14 26 F9.5-31 8 9A-29 26 9A-75 26 T9A-1 Sh15 26 F9.5-32 20 9A-30 26 9A-76 26 T9A-1 Sh16 26 F9.5-33 20 9A-31 26 9A-77 26 T9A-1 Sh17 26 F9.5-34 20 9A-32 26 9A-78 26 T9A-1 Sh18 26 F9.5-35 20 9A-32a R 9A-79 26 T9A-1 Sh19 26 F9.5-36 20 9A-32b R 9A-80 26 T9A-1 Sh20 26 F9.5-37 20 9A-33 26 9A-81 26 T9A-1 Sh21 26 F9.5-38 20 9A-34 26 9A-82 26 T9A-1 Sh22 26 F9.5-39 20 9A-35 26 9A-83 26 T9A-1 Sh22a R F9.5-40 20 9A-36 26 9A-84 26 T9A-1 Sh23 26 F9.5-41 20 9A-37 26 9A-84a R T9A-1 Sh23a R F9.5-42 20 9A-38 26 9A-84b R T9A-1 Sh24 26 F9.5-43 20 9A-39 26 9A-85 26 T9A-1 Sh25 26 F9.5-44 20 9A-40 26 9A-86 26 T9A-1 Sh26 26 F9.5-45 20 9A-41 26 9A-87 26 T9A-1 Sh27 26 F9.5-46 0 9A-42 26 9A-88 26 T9A-1 Sh28 26 F9.5-47 0 9A-43 26 9A-89 26 T9A-1 Sh29 26 F9.5-48 0 9A-44 26 9A-90 26 T9A-1 Sh30 26 9A-i 6 9A-45 26 9A-91 26 T9A-1 Sh31 26 9A-ii 0 9A-46 26 9A-92 26 T9A-1 Sh32 26 9A-iii 26 9A-47 26 9A-93 26 T9A-1 Sh33 26 9A-iv 26 9A-48 26 9A-94 R T9A-1 Sh34 26 9A-1 0 9A-49 26 9A-95 R T9A-1 Sh35 26 9A-2 0 9A-50 26 9A-96 R T9A-1 Sh36 R 9A-3 0 9A-51 26 9A-97 R T9A-1 Sh37 R 9A-4 0 9A-52 26 9A-98 R T9A-1 Sh38 R 9A-5 14 9A-53 26 9A-99 R T9A-1 Sh39 R 9A-6 14 9A-54 26 9A-100 R T9A-1 Sh40 R 9A-7 20 9A-55 26 9A-101 R T9A-1 Sh41 R 9A-8 14 9A-56 26 9A-102 R T9A-1 Sh42 R 9A-9 0 9A-57 26 9A-103 R T9A-1 Sh43 R 9A-10 14 9A-58 26 9A-104 R T9A-1 Sh44 R 9A-11 0 9A-59 26 9A-105 R T9A-1 Sh45 R 9A-12 14 9A-60 26 9A-106 R T9A-1 Sh46 R 9A-13 24 9A-61 26 9A-107 R T9A-1 Sh47 R 9A-14 24 9A-61a R 9A-108 R T9A-1 Sh48 R 9A-15 14 9A-61b R T9A-1 Sh1 26 T9A-1 Sh49 R 9A-16 14 9A-62 26 T9A-1 Sh2 26 T9A-1 Sh50 R 9A-17 26 9A-63 26 T9A-1 Sh3 26 T9A-1 Sh51 R 9A-18 26 9A-64 26 T9A-1 Sh4 26 T9A-1 Sh52 R 9A-19 26 9A-65 26 T9A-1 Sh5 26 T9A-1 Sh53 R 9A-20 26 9A-66 26 T9A-1 Sh6 26 T9A-1 Sh54 R 9A-21 26 9A-67 26 T9A-1 Sh7 26 T9A-1 Sh55 R 9A-22 26 9A-68 26 T9A-1 Sh8 26 T9A-2 Sh1 0 9A-23 26 9A-69 26 T9A-1 Sh9 26 T9A-2 Sh2 6 9A-24 26 9A-70 26 T9A-1 Sh10 26 T9A-2 Sh3 0 35

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T9A-2 Sh4 0 T9A-8 Sh6 26 T9A-9 Sh26 26 T9A-12 Sh35 26 T9A-2 Sh5 0 T9A-8 Sh7 26 T9A-9 Sh27 26 T9A-12 Sh36 26 T9A-2 Sh6 20 T9A-8 Sh8 26 T9A-10 Sh1 26 T9A-12 Sh37 26 T9A-2 Sh7 22 T9A-8 Sh9 26 T9A-10 Sh2 26 T9A-12 Sh38 26 T9A-2 Sh8 22 T9A-8 Sh10 26 T9A-10 Sh2a R T9A-12 Sh39 26 T9A-2 Sh9 0 T9A-8 Sh11 26 T9A-10 Sh3 26 T9A-12 Sh40 26 T9A-2 Sh10 0 T9A-8 Sh12 26 T9A-10 Sh4 26 T9A-12 Sh41 26 T9A-2 Sh11 15 T9A-8 Sh13 26 T9A-10 Sh5 26 T9A-12 Sh42 26 T9A-2 Sh12 24 T9A-8 Sh14 26 T9A-10 Sh6 26 T9A-12 Sh43 26 T9A-2 Sh13 24 T9A-8 Sh15 26 T9A-10 Sh7 26 T9A-12 Sh44 26 T9A-2 Sh14 18 T9A-8 Sh16 26 T9A-10 Sh8 26 T9A-12 Sh45 26 T9A-2 Sh15 0 T9A-8 Sh17 26 T9A-10 Sh9 26 T9A-12 Sh46 26 T9A-2 Sh16 0 T9A-8 Sh18 26 T9A-10 Sh10 26 T9A-12 Sh47 26 T9A-3 Sh1 0 T9A-8 Sh19 26 T9A-10 Sh11 26 T9A-12 Sh48 26 T9A-3 Sh2 20 T9A-8 Sh20 26 T9A-11 26 T9A-12 Sh49 26 T9A-3 Sh3 16 T9A-8 Sh21 26 T9A-12 Sh1 26 T9A-12 Sh50 26 T9A-3 Sh4 10 T9A-8 Sh22 26 T9A-12 Sh2 26 T9A-12 Sh51 26 T9A-3 Sh5 15 T9A-8 Sh23 26 T9A-12 Sh3 26 T9A-12 Sh52 26 T9A-3 Sh6 24 T9A-8 Sh24 26 T9A-12 Sh4 26 T9A-12 Sh53 26 T9A-3 Sh7 18 T9A-8 Sh25 26 T9A-12 Sh5 26 T9A-12 Sh54 26 T9A-3 Sh8 18 T9A-8 Sh26 26 T9A-12 Sh6 26 T9A-12 Sh55 26 T9A-3 Sh9 24 T9A-8 Sh27 26 T9A-12 Sh7 26 T9A-12 Sh56 26 T9A-3 Sh10 18 T9A-8 Sh28 26 T9A-12 Sh8 26 T9A-12 Sh57 26 T9A-3 Sh11 0 T9A-8 Sh29 26 T9A-12 Sh9 26 T9A-12 Sh58 26 T9A-3 Sh12 15 T9A-8 Sh30 26 T9A-12 Sh9a R T9A-12 Sh59 26 T9A-3 Sh13 0 T9A-9 Sh1 26 T9A-12 Sh10 26 T9A-12 Sh60 26 T9A-3 Sh14 22 T9A-9 Sh2 26 T9A-12 Sh11 26 T9A-13 Sh1 26 T9A-3 Sh15 15 T9A-9 Sh3 26 T9A-12 Sh12 26 T9A-13 Sh2 26 T9A-3 Sh16 6 T9A-9 Sh4 26 T9A-12 Sh13 26 T9A-13 Sh3 26 T9A-3 Sh17 0 T9A-9 Sh5 26 T9A-12 Sh14 26 T9A-13 Sh4 26 T9A-4 Sh1 8 T9A-9 Sh6 26 T9A-12 Sh15 26 T9A-13 Sh5 26 T9A-4 Sh2 24 T9A-9 Sh7 26 T9A-12 Sh16 26 T9A-13 Sh6 26 T9A-5 Sh1 9 T9A-9 Sh8 26 T9A-12 Sh17 26 T9A-13 Sh7 26 T9A-5 Sh2 9 T9A-9 Sh9 26 T9A-12 Sh18 26 T9A-13 Sh8 26 T9A-5 Sh3 0 T9A-9 Sh10 26 T9A-12 Sh19 26 T9A-13 Sh9 26 T9A-5 Sh4 0 T9A-9 Sh11 26 T9A-12 Sh20 26 T9A-13 Sh10 26 T9A-6 Sh1 26 T9A-9 Sh12 26 T9A-12 Sh21 26 T9A-13 Sh11 26 T9A-6 Sh2 26 T9A-9 Sh13 26 T9A-12 Sh22 26 T9A-14 Sh1 26 T9A-6 Sh3 26 T9A-9 Sh14 26 T9A-12 Sh23 26 T9A-14 Sh2 26 T9A-6 Sh4 26 T9A-9 Sh15 26 T9A-12 Sh24 26 T9A-14 Sh3 26 T9A-6 Sh4a R T9A-9 Sh16 26 T9A-12 Sh25 26 T9A-14 Sh4 26 T9A-6 Sh5 26 T9A-9 Sh17 26 T9A-12 Sh26 26 T9A-14 Sh5 R T9A-6 Sh6 26 T9A-9 Sh18 26 T9A-12 Sh27 26 T9A-15 Sh1 26 T9A-6 Sh7 R T9A-9 Sh19 26 T9A-12 Sh28 26 T9A-15 Sh2 26 T9A-7 26 T9A-9 Sh20 26 T9A-12 Sh29 26 T9A-15 Sh3 26 T9A-8 Sh1 26 T9A-9 Sh21 26 T9A-12 Sh30 26 T9A-15 Sh4 26 T9A-8 Sh2 26 T9A-9 Sh22 26 T9A-12 Sh31 26 T9A-15 Sh5 26 T9A-8 Sh3 26 T9A-9 Sh23 26 T9A-12 Sh32 26 T9A-15 Sh6 26 T9A-8 Sh4 26 T9A-9 Sh24 26 T9A-12 Sh33 26 T9A-15 Sh7 26 T9A-8 Sh5 26 T9A-9 Sh25 26 T9A-12 Sh34 26 T9A-15 Sh8 26 36

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T9A-15 Sh9 26 T9A-34 Sh3 26 T9A-60 Sh9 26 T9A-94 26 T9A-15 Sh10 26 T9A-34 Sh4 26 T9A-60 Sh10 26 T9A-95 26 T9A-15 Sh11 26 T9A-34 Sh5 26 T9A-60 Sh11 26 T9A-96 26 T9A-15 Sh12 26 T9A-34 Sh6 26 T9A-60 Sh12 R T9A-97 Sh1 26 T9A-15 Sh13 26 T9A-34 Sh7 R T9A-60 Sh13 R T9A-97 Sh2 26 T9A-15 Sh14 26 T9A-35 Sh1 26 T9A-61 Sh1 26 T9A-97 Sh3 26 T9A-15 Sh15 26 T9A-35 Sh2 26 T9A-61 Sh2 26 T9A-97 Sh4 26 T9A-15 Sh16 26 T9A-35 Sh3 26 T9A-61 Sh3 26 T9A-97 Sh5 26 T9A-16 26 T9A-35 Sh4 26 T9A-61 Sh4 R T9A-98 26 T9A-17 26 T9A-35 Sh5 26 T9A-62 26 T9A-99 Sh1 26 T9A-18 26 T9A-35 Sh6 26 T9A-63 26 T9A-99 Sh2 26 T9A-19 26 T9A-35 Sh7 R T9A-64 26 T9A-99 Sh3 26 T9A-20 0 T9A-36 9 T9A-65 26 T9A-99 Sh4 26 T9A-21 26 T9A-37 9 T9A-66 26 T9A-99 Sh5 R T9A-22 26 T9A-38 9 T9A-67 26 T9A-100 Sh1 26 T9A-23 26 T9A-39 9 T9A-68 26 T9A-100 Sh2 26 T9A-24 26 T9A-40 26 T9A-69 26 T9A-100 Sh3 26 T9A-25 Sh1 26 T9A-41 26 T9A-70 26 T9A-100 Sh4 26 T9A-25 Sh2 26 T9A-42 sh1 26 T9A-71 26 T9A-100 Sh5 26 T9A-25 Sh3 26 T9A-42 sh2 26 T9A-72 26 T9A-100 Sh6 26 T9A-25 Sh4 26 T9A-43 sh1 26 T9A-73 26 T9A-100 Sh7 26 T9A-25 Sh5 26 T9A-43 sh2 26 T9A-74 26 T9A-100 Sh8 26 T9A-25 Sh6 26 T9A-44 sh1 26 T9A-75 Sh1 26 T9A-100 Sh9 26 T9A-25 Sh7 26 T9A-44 sh2 26 T9A-75 Sh2 26 T9A-100 Sh10 26 T9A-25 Sh8 26 T9A-45 sh1 26 T9A-75 Sh3 26 T9A-100 Sh11 26 T9A-25 Sh9 26 T9A-45 sh2 26 T9A-75 Sh4 26 T9A-100 Sh12 26 T9A-25 Sh10 26 T9A-46 sh1 26 T9A-75 Sh5 26 T9A-100 Sh13 26 T9A-25 Sh11 26 T9A-46 sh2 26 T9A-76 sh1 26 T9A-100 Sh14 26 T9A-26 26 T9A-47 26 T9A-76 sh2 26 T9A-100 Sh15 26 T9A-27 26 T9A-48 26 T9A-77 Sh1 26 T9A-100 Sh16 26 T9A-28 26 T9A-49 26 T9A-77 Sh2 26 T9A-100 Sh17 26 T9A-29 26 T9A-50 sh1 26 T9A-77 Sh3 26 T9A-100 Sh18 26 T9A-30 26 T9A-50 sh2 26 T9A-77 Sh4 26 T9A-100 Sh19 26 T9A-31 26 T9A-51 26 T9A-77 Sh5 26 T9A-100 Sh20 26 T9A-32 Sh1 26 T9A-52 0 T9A-78 26 T9A-101 Sh1 26 T9A-32 Sh2 26 T9A-53 0 T9A-79 0 T9A-101 Sh2 26 T9A-32 Sh3 26 T9A-54 0 T9A-80 26 T9A-101 Sh3 26 T9A-32 Sh4 26 T9A-55 0 T9A-81 26 T9A-101 Sh4 26 T9A-32 Sh5 26 T9A-56 26 T9A-82 26 T9A-101 Sh5 26 T9A-32 Sh6 26 T9A-57 26 T9A-83 26 T9A-101 Sh6 26 T9A-32 Sh7 R T9A-58 26 T9A-84 26 T9A-101 Sh7 26 T9A-33 Sh1 26 T9A-59 26 T9A-85 26 T9A-101 Sh8 26 T9A-33 Sh2 26 T9A-60 Sh1 26 T9A-86 26 T9A-101 Sh9 26 T9A-33 Sh3 26 T9A-60 Sh2 26 T9A-87 0 T9A-102 sh1 26 T9A-33 Sh4 26 T9A-60 Sh3 26 T9A-88 26 T9A-102 sh2 26 T9A-33 Sh5 26 T9A-60 Sh4 26 T9A-89 26 T9A-103 Sh 1 26 T9A-33 Sh6 26 T9A-60 Sh5 26 T9A-90 26 T9A-103 Sh 2 26 T9A-33 Sh7 R T9A-60 Sh6 26 T9A-91 26 T9A-104 7 T9A-34 Sh1 26 T9A-60 Sh7 26 T9A-92 26 F9A-1 20 T9A-34 Sh2 26 T9A-60 Sh8 26 T9A-93 26 F9A-2 20 37

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F9A-3 20 9B-1 20 F10.2-11 14 10.4-35 10 F9A-4 Sh1 20 9B-2 0 F10.2-12 14 10.4-36 20 F9A-4 Sh2 R 9B-3 0 10.3-1 12 10.4-37 22 F9A-5 20 9B-4 0 10.3-2 20 10.4-38 22 F9A-6 20 F9B-1 0 10.3-3 17 10.4-39 20 F9A-7 20 F9B-2 0 10.3-4 0 10.4-40 20 F9A-8 0 10-i 18 10.3-5 0 10.4-41 0 F9A-9 0 10-ii 0 10.3-6 0 10.4-42 0 F9A-10 0 10-iii 0 T10.3-1 17 10.4-43 17 F9A-11 Sh1 0 10-iv 17 F10.3-1 20 10.4-44 0 F9A-11 Sh2 0 10-v 20 10.4-1 0 T10.4-1 Sh1 17 F9A-12 0 10-vi 20 10.4-2 20 T10.4-1 Sh2 17 F9A-13 0 10.1-1 0 10.4-3 21 T10.4-2 Sh1 17 F9A-14 26 10.1-2 0 10.4-4 0 T10.4-2 Sh2 17 F9A-15 19 10.1-3 23 10.4-5 0 T10.4-2 Sh3 17 F9A-15a 26 10.1-4 12 10.4-6 20 T10.4-3 0 F9A-16 19 T10.1-1 17 10.4-7 16 T10.4-4 17 F9A-16a 26 F10.1-1 12 10.4-8 20 T10.4-5 0 F9A-17 19 F10.1-2 17 10.4-9 20 T10.4-6 25 F9A-17a 26 10.2-1 23 10.4-10 13 T10.4-7 Sh1 17 F9A-18 26 10.2-2 17 10.4-11 0 T10.4-7 Sh2 0 F9A-19 26 10.2-3 20 10.4-12 0 T10.4-7 Sh3 0 F9A-19 Sh2 R 10.2-4 17 10.4-13 20 T10.4-7 Sh4 0 F9A-19 Sh3 R 10.2-5 20 10.4-14 0 T10.4-7 Sh5 0 F9A-20 26 10.2-6 17 10.4-15 0 T10.4-7 Sh6 16 F9A-21 Sh1 26 10.2-6a R 10.4-16 0 T10.4-8 17 F9A-21 Sh2 R 10.2-6b R 10.4-17 20 F10.4-1 20 F9A-22 26 10.2-7 17 10.4-18 17 F10.4-2 20 F9A-23 26 10.2-8 17 10.4-19 24 F10.4-3 Sh1 20 F9A-24 26 10.2-9 17 10.4-20 17 F10.4-3 Sh2 R F9A-25 26 10.2-10 17 10.4-21 0 F10.4-4 Sh1 20 F9A-26 26 10.2-11 17 10.4-22 24 F10.4-4 Sh2 R F9A-27 26 10.2-12 26 10.4-22a 1 F10.4-5 Sh1 20 F9A-28 26 10.2-13 24 10.4-22b 1 F10.4-5 Sh2 R F9A-29 26 10.2-14 26 10.4-23 20 F10.4-5 Sh3 R F9A-30 26 10.2-15 R 10.4-24 25 F10.4-6 20 F9A-31 26 10.2-16 R 10.4-25 11 F10.4-7 Sh1 20 F9A-32 20 10.2-17 R 10.4-26 0 F10.4-7 Sh2 R F9A-33 20 T10.2-1 16 10.4-27 10 F10.4-8 20 F9A-34 20 T10.2-2 14 10.4-28 20 11-i 7 F9A-35 20 F10.2-1 0 10.4-29 17 11-ii 16 F9A-36 20 F10.2-2 0 10.4-30 17 11-iii 0 F9A-37 20 F10.2-3 20 10.4-31 20 11-iv 0 F9A-38 20 F10.2-4 20 10.4-32 6 11-v 0 F9A-39 20 F10.2-5 14 10.4-33 9 11-vi 0 F9A-40 20 F10.2-6 14 10.4-34 22 11-vii 20 F9A-41 20 F10.2-7 14 10.4-34a 20 11-viii 20 F9A-42 20 F10.2-8 14 10.4-34b 17 11.1-1 0 F9A-43 20 F10.2-9 14 10.4-34c 16 11.1-2 0 F9A-44 20 F10.2-10 14 10.4-34d 10 11.1-3 0 38

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 11.1-4 0 T11.2-3 Sh4 16 11.3-8 16 11.4-4b R 11.1-5 8 T11.2-4 Sh1 16 11.3-9 16 11.4-5 16 11.1-6 8 T11.2-4 Sh2 16 11.3-10 16 11.4-6 16 11.1-7 0 T11.2-5 Sh1 16 11.3-11 16 11.4-7 16 11.1-8 0 T11.2-5 Sh2 16 11.3-12 20 11.4-8 20 11.1-9 0 T11.2-6 Sh1 16 11.3-13 16 11.4-9 R 11.1-10 0 T11.2-6 Sh2 16 11.3-14 16 11.4-10 R 11.1-11 0 T11.2-7 Sh1 16 11.3-15 16 11.4-11 R 11.1-12 0 T11.2-7 Sh2 16 11.3-16 16 11.4-11a R 11.1-13 0 T11.2-8 Sh1 16 11.3-17 16 11.4-11b R 11.1-14 0 T11.2-8 Sh2 16 11.3-18 16 11.4-12 R 11.1-15 0 T11.2-9 Sh1 16 11.3-19 16 11.4-13 R 11.1-16 0 T11.2-9 Sh2 16 11.3-20 16 11.4-14 R 11.1-17 0 T11.2-10 Sh1 16 11.3-21 16 11.4-15 R 11.1-18 0 T11.2-10 Sh2 16 11.3-22 20 11.4-16 R T11.1-1 Sh1 12 T11.2-10 Sh3 16 11.3-23 16 T11.4-1 Sh1 16 T11.1-1 Sh2 12 T11.2-10 Sh4 19 11.3-24 16 T11.4-1 Sh2 16 T11.1-2 0 T11.2-10 Sh5 16 T11.3-1 16 T11.4-1 Sh3 16 T11.1-3 12 T11.2-11 Sh1 16 T11.3-2 Sh1 16 T11.4-1 Sh4 16 T11.1-4 Sh1 12 T11.2-11 Sh2 16 T11.3-2 Sh2 16 T11.4-1 Sh5 16 T11.1-4 Sh2 12 T11.2-11 Sh3 16 T11.3-3 Sh1 16 T11.4-1 Sh6 16 T11.1-5 12 T11.2-12 Sh1 16 T11.3-3 Sh2 16 T11.4-1 Sh7 16 T11.1-6 12 T11.2-12 Sh2 16 T11.3-4 Sh1 17 T11.4-2 16 F11.1-1 0 T11.2-12 Sh3 16 T11.3-4 Sh2 16 T11.4-3 Sh1 17 F11.1-2 0 T11.2-12 Sh4 16 T11.3-5 Sh1 16 T11.4-3 Sh2 16 F11.1-3 0 T11.2-13 Sh1 16 T11.3-5 Sh2 16 T11.4-4 16 11.2-1 20 T11.2-13 Sh2 16 T11.3-6 Sh1 16 T11.4-5 Sh1 16 11.2-2 16 T11.2-13 Sh3 16 T11.3-6 Sh2 16 T11.4-5 Sh2 16 11.2-3 16 T11.2-13 Sh4 16 T11.3-6 Sh3 16 T11.4-5 Sh3 16 11.2-4 16 T11.2-13 Sh5 16 T11.3-6 Sh4 16 T11.4-6 Sh1 16 11.2-5 16 T11.2-14 Sh1 16 T11.3-6 Sh5 16 T11.4-6 Sh2 16 11.2-6 16 T11.2-14 Sh2 16 T11.3-6 Sh6 16 T11.4-6 Sh3 16 11.2-7 16 F11.2-1 Sh1 20 T11.3-6 Sh7 16 T11.4-7 Sh1 16 11.2-8 16 F11.2-1 Sh2 R T11.3-6 Sh8 16 T11.4-7 Sh2 16 11.2-9 16 F11.2-2 Sh1 20 T11.3-6 Sh9 16 T11.4-8 16 11.2-10 16 F11.2-2 Sh2 R T11.3-7 16 T11.4-9 Sh1 16 11.2-11 19 F11.2-3 20 T11.3-8 Sh1 16 T11.4-9 Sh2 16 11.2-12 16 F11.2-4 Sh1 20 T11.3-8 Sh2 16 F11.4-1 20 11.2-13 16 F11.2-4 Sh2 R F11.3-1 0 F11.4-2 20 11.2-14 16 F11.2-4 Sh3 R F11.3-2 20 F11.4-3 20 11.2-15 16 F11.2-5 Sh1 11 F11.3-3 20 F11.4-4 20 T11.2-1 Sh1 16 F11.2-5 Sh2 11 F11.3-4 20 F11.4-5 20 T11.2-1 Sh2 16 F11.2-6 0 F11.3-5 20 F11.4-6 20 T11.2-1 Sh3 16 11.3-1 8 F11.3-6 20 F11.4-7 20 T11.2-1 Sh4 16 11.3-2 8 F11.3-7 20 F11.4-8 20 T11.2-2 Sh1 16 11.3-3 17 11.4-1 16 F11.4-9 20 T11.2-2 Sh2 16 11.3-4 20 11.4-2 16 F11.4-10 11 T11.2-3 Sh1 16 11.3-5 0 11.4-3 20 11.5-1 0 T11.2-3 Sh2 16 11.3-6 15 11.4-4 20 11.5-2 0 T11.2-3 Sh3 16 11.3-7 15 11.4-4a R 11.5-3 0 39

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 11.5-4 11 12-iv 16 12.2-6 16 T12.2-21 Sh1 16 11.5-5 21 12-v 0 12.2-6a 16 T12.2-21 Sh2 16 11.5-6 0 12-vi 0 12.2-6b 5 T12.2-22 Sh1 16 11.5-7 0 12-vii 0 12.2-7 16 T12.2-22 Sh2 16 11.5-8 18 12-viii 0 12.2-8 16 T12.2-23 Sh1 16 11.5-9 14 12-ix 0 12.2-9 16 T12.2-23 Sh2 16 11.5-10 18 12-x 0 12.2-10 16 T12.2-24 Sh1 16 11.5-11 20 12-xi 0 12.2-11 16 T12.2-24 Sh2 16 11.5-12 7 12-xii 0 12.2-12 16 T12.2-25 Sh1 16 11.5-13 0 12-xiii 0 12.2-13 16 T12.2-25 Sh2 16 11.5-14 7 12-xiv 0 12.2-14 16 T12.2-26 Sh1 16 11.5-15 20 12-xv 0 12.2-15 16 T12.2-26 Sh2 16 11.5-16 18 12-xvi 7 12.2-16 16 T12.2-27 Sh1 16 11.5-17 18 12-xvii 12 12.2-17 16 T12.2-27 Sh2 16 11.5-18 20 12-xviii 0 12.2-18 16 T12.2-28 16 11.5-19 20 12-xix 22 12.2-19 16 T12.2-29 Sh1 16 11.5-20 23 12-xx 20 12.2-20 16 T12.2-29 Sh2 16 11.5-21 22 12-xxi 20 T12.2-1 Sh1 16 T12.2-30 Sh1 16 11.5-22 22 12-xxii 12 T12.2-1 Sh2 16 T12.2-30 Sh2 16 11.5-23 20 12-xxiii 12 T12.2-2 Sh1 16 T12.2-31 16 11.5-23a 20 12-xxiv 12 T12.2-2 Sh2 16 T12.2-32 16 11.5-23b 2 12-xxv 12 T12.2-3 16 T12.2-33 16 11.5-24 20 12-xxvi 20 T12.2-4 16 T12.2-34 16 11.5-25 20 12.1-1 22 T12.2-5 16 T12.2-35 Sh1 16 11.5-25a 20 12.1-2 16 T12.2-6 16 T12.2-35 Sh2 16 11.5-25b 2 12.1-3 16 T12.2-7 Sh1 16 T12.2-36 Sh1 16 11.5-26 21 12.1-4 16 T12.2-7 Sh2 16 T12.2-36 Sh2 16 11.5-27 22 12.1-5 16 T12.2-8 16 T12.2-37 16 11.5-27a 5 12.1-6 16 T12.2-9 Sh1 16 T12.2-38 Sh1 16 11.5-27b 5 12.1-7 16 T12.2-9 Sh2 16 T12.2-38 Sh2 16 11.5-28 11 12.1-8 16 T12.2-10 10 T12.2-39 Sh1 16 11.5-29 20 12.1-9 16 T12.2-11 16 T12.2-39 Sh2 16 T11.5-1 Sh1 10 12.1-10 16 T12.2-12 Sh1 16 T12.2-40 16 T11.5-1 Sh2 18 12.1-11 16 T12.2-12 Sh2 16 T12.2-41 16 T11.5-1 Sh3 22 12.1-12 16 T12.2-13 Sh1 16 T12.2-42 Sh1 16 T11.5-1 Sh4 22 12.1-13 16 T12.2-13 Sh2 16 T12.2-42 Sh2 16 T11.5-1 Sh5 22 12.1-14 16 T12.2-14 Sh1 16 T12.2-42 Sh3 16 T11.5-1 Sh6 22 12.1-15 16 T12.2-14 Sh2 16 T12.2-43 Sh1 16 T11.5-2 21 12.1-16 16 T12.2-15 Sh1 16 T12.2-43 Sh2 16 T11.5-3 Sh1 11 12.1-17 16 T12.2-15 Sh2 16 T12.2-44 Sh1 16 T11.5-3 Sh2 11 12.1-18 16 T12.2-16 Sh1 16 T12.2-44 Sh2 16 F11.5-1 Sh1 20 12.1-19 16 T12.2-16 Sh2 16 T12.2-45 Sh1 16 F11.5-1 Sh2 R 12.1-20 16 T12.2-17 Sh1 16 T12.2-45 Sh2 16 F11.5-2 8 T12.1-1 16 T12.2-17 Sh2 16 T12.2-46 Sh1 16 F11.5-3 Sh1 20 T12.1-2 16 T12.2-18 Sh1 16 T12.2-46 Sh2 16 F11.5-3 Sh2 R 12.2-1 16 T12.2-18 Sh2 16 T12.2-47 Sh1 16 F11.5-3 Sh3 R 12.2-2 20 T12.2-19 Sh1 16 T12.2-47 Sh2 16 12-i 0 12.2-3 16 T12.2-19 Sh2 16 T12.2-48 Sh1 16 12-ii 16 12.2-4 16 T12.2-20 Sh1 16 T12.2-48 Sh2 16 12-iii 16 12.2-5 16 T12.2-20 Sh2 16 T12.2-49 Sh1 16 40

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T12.2-49 Sh2 16 T12.2-75 Sh2 16 T12.2-106 16 T12.2-131 Sh1 16 T12.2-50 Sh1 16 T12.2-76 16 T12.2-107 Sh1 16 T12.2-131 Sh2 16 T12.2-50 Sh2 16 T12.2-77 Sh1 16 T12.2-107 Sh2 16 T12.2-132 Sh1 16 T12.2-51 Sh1 16 T12.2-77 Sh2 16 T12.2-107 Sh3 16 T12.2-132 Sh2 16 T12.2-51 Sh2 16 T12.2-78 Sh1 16 T12.2-107 Sh4 16 T12.2-133 Sh1 16 T12.2-52 Sh1 16 T12.2-78 Sh2 16 T12.2-107 Sh5 16 T12.2-133 Sh2 16 T12.2-52 Sh2 16 T12.2-79 Sh1 16 T12.2-108 16 T12.2-133 Sh3 16 T12.2-53 Sh1 16 T12.2-79 Sh2 16 T12.2-109 Sh1 16 T12.2-133 Sh4 16 T12.2-53 Sh2 16 T12.2-80 Sh1 16 T12.2-109 Sh2 16 T12.2-133 Sh5 16 T12.2-54 Sh1 16 T12.2-80 Sh2 16 T12.2-110 Sh1 16 T12.2-133 Sh6 16 T12.2-54 Sh2 16 T12.2-81 16 T12.2-110 Sh2 16 T12.2-134 16 T12.2-55 Sh1 16 T12.2-82 Sh1 16 T12.2-111 Sh1 16 T12.2-135 Sh1 16 T12.2-55 Sh2 16 T12.2-82 Sh2 16 T12.2-111 Sh2 16 T12.2-135 Sh2 16 T12.2-56 Sh1 16 T12.2-83 Sh1 16 T12.2-112 Sh1 16 T12.2-135 Sh3 16 T12.2-56 Sh2 16 T12.2-83 Sh2 16 T12.2-112 Sh2 16 T12.2-136 Sh1 16 T12.2-57 Sh1 16 T12.2-84 16 T12.2-113 Sh1 16 T12.2-136 Sh2 16 T12.2-57 Sh2 16 T12.2-85 Sh1 16 T12.2-113 Sh2 16 T12.2-136 Sh3 16 T12.2-58 Sh1 16 T12.2-85 Sh2 16 T12.2-114 Sh1 16 T12.2-137 16 T12.2-58 Sh2 16 T12.2-86 Sh1 16 T12.2-114 Sh2 16 T12.2-138 Sh1 16 T12.2-59 Sh1 16 T12.2-86 Sh2 16 T12.2-115 Sh1 16 T12.2-138 Sh2 16 T12.2-59 Sh2 16 T12.2-87 Sh1 16 T12.2-115 Sh2 16 T12.2-139 Sh1 16 T12.2-60 16 T12.2-87 Sh2 16 T12.2-116 Sh1 16 T12.2-139 Sh2 16 T12.2-61 Sh1 16 T12.2-88 16 T12.2-116 Sh2 16 T12.2-140 Sh1 16 T12.2-61 Sh2 16 T12.2-89 16 T12.2-117 Sh1 16 T12.2-140 Sh2 16 T12.2-62 Sh1 16 T12.2-90 16 T12.2-117 Sh2 16 T12.2-140 Sh3 16 T12.2-62 Sh2 16 T12.2-91 Sh1 16 T12.2-118 Sh1 16 T12.2-141 16 T12.2-63 Sh1 16 T12.2-91 Sh2 16 T12.2-118 Sh2 16 T12.2-142 16 T12.2-63 Sh2 16 T12.2-92 Sh1 16 T12.2-119 Sh1 16 T12.2-143 Sh1 16 T12.2-64 Sh1 16 T12.2-92 Sh2 16 T12.2-119 Sh2 16 T12.2-143 Sh2 16 T12.2-64 Sh2 16 T12.2-93 16 T12.2-119 Sh3 16 T12.2-144 Sh1 16 T12.2-65 Sh1 16 T12.2-94 16 T12.2-120 Sh1 16 T12.2-144 Sh2 16 T12.2-65 Sh2 16 T12.2-95 16 T12.2-120 Sh2 16 T12.2-145 7 T12.2-66 Sh1 16 T12.2-96 16 T12.2-121 16 12.3-1 16 T12.2-66 Sh2 16 T12.2-97 16 T12.2-122 Sh1 16 12.3-2 20 T12.2-67 Sh1 16 T12.2-98 Sh1 0 T12.2-122 Sh2 16 12.3-3 20 T12.2-67 Sh2 16 T12.2-98 Sh2 0 T12.2-123 Sh1 16 12.3-4 16 T12.2-68 Sh1 16 T12.2-99 Sh1 16 T12.2-123 Sh2 16 12.3-5 16 T12.2-68 Sh2 16 T12.2-99 Sh2 16 T12.2-124 Sh1 16 12.3-6 16 T12.2-69 Sh1 16 T12.2-100 Sh1 16 T12.2-124 Sh2 16 12.3-7 16 T12.2-69 Sh2 16 T12.2-100 Sh2 16 T12.2-125 Sh1 16 12.3-8 20 T12.2-70 Sh1 16 T12.2-101 Sh1 16 T12.2-125 Sh2 16 12.3-9 16 T12.2-70 Sh2 16 T12.2-101 Sh2 16 T12.2-126 Sh1 16 12.3-10 16 T12.2-71 Sh1 16 T12.2-102 Sh1 16 T12.2-126 Sh2 16 12.3-11 16 T12.2-71 Sh2 16 T12.2-102 Sh2 16 T12.2-127 Sh1 16 12.3-12 16 T12.2-72 Sh1 16 T12.2-103 Sh1 16 T12.2-127 Sh2 16 12.3-13 20 T12.2-72 Sh2 16 T12.2-103 Sh2 16 T12.2-128 Sh1 16 12.3-14 16 T12.2-73 Sh1 16 T12.2-104 Sh1 16 T12.2-128 Sh2 16 12.3-15 22 T12.2-73 Sh2 16 T12.2-104 Sh2 16 T12.2-129 16 12.3-16 21 T12.2-74 16 T12.2-105 Sh1 16 T12.2-130 Sh1 16 12.3-17 16 T12.2-75 Sh1 16 T12.2-105 Sh2 16 T12.2-130 Sh2 16 12.3-18 16 41

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 12.3-19 20 T12.3-6 16 F12.3-37 12 12.4-13 16 12.3-20 16 T12.3-7 Sh1 0 F12.3-38 12 T12.4-1 16 12.3-21 20 T12.3-7 Sh2 0 F12.3-39 12 T12.4-2 16 12.3-22 16 T12.3-7 Sh3 0 F12.3-40 12 T12.4-3 16 12.3-23 16 T12.3-8 Sh1 16 F12.3-41 12 T12.4-4 Sh1 16 12.3-23a R T12.3-8 Sh2 16 F12.3-42 12 T12.4-4 Sh2 16 12.3-23b R T12.3-9 Sh1 6 F12.3-43 12 T12.4-5 16 12.3-24 20 T12.3-9 Sh2 6 F12.3-44 12 T12.4-6 Sh1 16 12.3-25 20 T12.3-9 Sh3 6 F12.3-45 12 T12.4-6 Sh2 16 12.3-26 20 T12.3-9 Sh4 6 F12.3-46 12 T12.4-7 Sh1 16 12.3-27 20 T12.3-10 Sh1 12 F12.3-47 12 T12.4-7 Sh2 16 12.3-28 16 T12.3-10 Sh2 18 F12.3-48 12 T12.4-8 Sh1 16 12.3-29 18 T12.3-10 Sh3 18 F12.3-49 12 T12.4-8 Sh2 16 12.3-30 12 T12.3-10 Sh4 12 F12.3-50 12 T12.4-8 Sh3 16 12.3-31 12 F12.3-1 20 F12.3-51 12 T12.4-9 16 12.3-32 22 F12.3-2 20 F12.3-52 12 T12.4-10 Sh1 16 12.3-33 16 F12.3-3 20 F12.3-53 12 T12.4-10 Sh2 16 12.3-34 16 F12.3-4 20 F12.3-54 12 T12.4-11 Sh1 16 12.3-35 16 F12.3-5 20 F12.3-55 12 T12.4-11 Sh2 16 12.3-36 16 F12.3-6 20 F12.3-56 12 T12.4-12 Sh1 16 12.3-37 16 F12.3-7 20 F12.3-57 12 T12.4-12 Sh2 16 12.3-38 16 F12.3-8 20 F12.3-57a 12 T12.4-12 Sh3 16 12.3-39 16 F12.3-9 20 F12.3-58 0 T12.4-13 16 12.3-40 16 F12.3-10 20 F12.3-59 0 T12.4-14 16 12.3-41 16 F12.3-11 20 F12.3-60 13 T12.4-15 16 12.3-42 0 F12.3-12 20 F12.3-61 13 T12.4-16 16 12.3-43 0 F12.3-13 20 F12.3-62 13 T12.4-17 16 12.3-44 10 F12.3-14 20 F12.3-63 13 F12.4-1 11 12.3-45 10 F12.3-15 20 F12.3-64 Sh1 20 12.5-1 22 12.3-46 15 F12.3-16 20 F12.3-64 Sh2 R 12.5-2 16 12.3-47 6 F12.3-17 20 F12.3-65 13 12.5-3 20 12.3-48 0 F12.3-18 20 F12.3-66 Sh1 20 12.5-4 16 12.3-49 12 F12.3-19 20 F12.3-66 Sh2 R 12.5-5 20 12.3-50 0 F12.3-20 20 F12.3-67 13 12.5-6 22 12.3-51 22 F12.3-21 20 F12.3-68 13 12.5-7 22 12.3-52 23 F12.3-22 0 F12.3-69 13 12.5-8 22 12.3-53 0 F12.3-23 0 F12.3-70 13 12.5-9 16 12.3-54 0 F12.3-24 0 F12.3-71 13 12.5-10 22 12.3-55 0 F12.3-25 0 12.4-1 16 12.5-11 22 T12.3-1 0 F12.3-26 0 12.4-2 16 12.5-12 16 T12.3-2 Sh1 12 F12.3-27 0 12.4-3 16 12.5-13 17 T12.3-2 Sh2 R F12.3-28 0 12.4-4 16 12.5-13a 17 T12.3-3 Sh1 18 F12.3-29 10 12.4-5 16 12.5-13b 17 T12.3-3 Sh2 R F12.3-30 12 12.4-6 16 12.5-14 16 T12.3-3a Sh1 12 F12.3-31 12 12.4-7 16 12.5-15 22 T12.3-3a Sh2 R F12.3-32 12 12.4-8 16 12.5-16 16 T12.3-3a Sh3 R F12.3-33 12 12.4-9 16 12.5-17 16 T12.3-4 Sh1 16 F12.3-34 12 12.4-10 22 12.5-18 16 T12.3-4 Sh2 16 F12.3-35 12 12.4-11 16 12.5-19 16 T12.3-5 16 F12.3-36 12 12.4-12 16 12.5-20 22 42

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 12.5-21 16 13.1-28 R 13.5-16 R 14.2-15 0 12.5-22 23 13.1-29 R 13.5-17 R 14.2-16 0 12.5-23 22 13.1-30 R 13.5-18 R 14.2-17 0 12.5-24 16 13.1-31 R 13.5-19 R 14.2-18 0 12.5-25 R 13.1-32 R 13.5-20 R 14.2-19 0 12.5-26 R 13.1-33 R 13.5-21 R 14.2-20 0 12.5-27 R 13.1-34 R 13.5-22 R 14.2-21 0 12.5-28 R T13.1-1 Sh1 24 13.5-23 R 14.2-22 0 12.5-29 R T13.1-1 Sh2 R 13.5-24 R 14.2-23 0 12.5-30 R F13.1-1 24 13.5-25 R 14.2-24 0 12.5-31 R F13.1-2 24 T13.5-1 Sh1 18 14.2-25 0 T12.5-1 22 F13.1-3 24 T13.5-1 Sh2 18 14.2-26 0 T12.5-2 22 F13.1-4 24 T13.5-1 Sh3 18 14.2-27 0 F12.5-1 8 F13.1-5 R T13.5-2 Sh1 15 14.2-28 0 F12.5-2 20 F13.1-6 R T13.5-2 Sh2 15 14.2-29 17 F12.5-3 0 F13.1-6a R F13.5-1 R 14.2-30 0 F12.5-4 20 F13.1-6b R 13.6-1 12 14.2-31 0 F12.5-5 20 F13.1-6c R 13.6-2 12 14.2-32 0 13-i 24 F13.1-6d R 13.7-1 12 14.2-33 0 13-ii 24 F13.1-6e R 13A-1 4 14.2-34 0 13-iii 24 F13.1-7 R 13B-1 4 14.2-35 0 13-iv R F13.1-8 R 13C-1 4 14.2-36 0 13-v R F13.1-9 R 13D-1 4 14.2-37 0 13.1-1 24 F13.1-10 R 13E-1 4 14.2-38 0 13.1-2 24 13.2-1 22 13F-1 4 14.2-39 0 13.1-3 R 13.2-2 22 13G-1 4 14.2-40 0 13.1-4 R 13.2-3 R 13H-1 4 14.2-41 0 13.1-5 R 13.2-4 R 13I-1 4 14.2-42 0 13.1-6 R 13.2-5 R 13J-1 4 14.2-43 0 13.1-7 R 13.2-6 R 13K-1 4 14.2-44 0 13.1-8 R 13.2-7 R 13L-1 9 14.2-45 0 13.1-9 R 13.2-8 R 14-i 0 14.2-46 0 13.1-10 R F13.2-1 R 14-ii 0 14.2-47 0 13.1-11 R 13.3-1 12 14-iii 0 14.2-48 0 13.1-12 R 13.4-1 16 14-iv 0 14.2-49 0 13.1-13 R 13.5-1 22 14.1-1 0 14.2-50 0 13.1-14 R 13.5-2 18 14.2-1 0 14.2-51 17 13.1-15 R 13.5-3 18 14.2-2 0 14.2-52 0 13.1-16 R 13.5-4 13 14.2-3 0 14.2-53 0 13.1-17 R 13.5-5 16 14.2-4 0 14.2-54 0 13.1-18 R 13.5-6 16 14.2-5 0 14.2-55 0 13.1-19 R 13.5-7 16 14.2-6 0 14.2-56 0 13.1-20 R 13.5-8 R 14.2-7 0 14.2-57 0 13.1-21 R 13.5-9 R 14.2-8 0 14.2-58 0 13.1-22 R 13.5-10 R 14.2-9 0 14.2-59 0 13.1-23 R 13.5-11 R 14.2-10 0 14.2-60 0 13.1-24 R 13.5-12 R 14.2-11 0 14.2-61 0 13.1-25 R 13.5-13 R 14.2-12 0 14.2-62 0 13.1-26 R 13.5-14 R 14.2-13 0 14.2-63 0 13.1-27 R 13.5-15 R 14.2-14 0 14.2-64 0 43

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 14.2-65 0 14.2-115 0 14.2-165 0 14.2-215 0 14.2-66 0 14.2-116 0 14.2-166 0 14.2-216 0 14.2-67 0 14.2-117 0 14.2-167 0 14.2-217 23 14.2-68 0 14.2-118 17 14.2-168 0 14.2-218 0 14.2-69 0 14.2-119 0 14.2-169 0 14.2-219 0 14.2-70 0 14.2-120 0 14.2-170 0 14.2-220 0 14.2-71 0 14.2-121 0 14.2-171 0 14.2-221 0 14.2-72 0 14.2-122 0 14.2-172 0 14.2-222 0 14.2-73 0 14.2-123 0 14.2-173 0 14.2-223 14 14.2-74 0 14.2-124 0 14.2-174 0 14.2-224 0 14.2-75 0 14.2-125 0 14.2-175 0 14.2-225 0 14.2-76 17 14.2-126 0 14.2-176 0 14.2-226 17 14.2-77 0 14.2-127 0 14.2-177 0 14.2-227 0 14.2-78 0 14.2-128 0 14.2-178 11 F14.2-1 0 14.2-79 0 14.2-129 14 14.2-179 11 F14.2-2 0 14.2-80 0 14.2-130 14 14.2-180 0 F14.2-3 0 14.2-81 0 14.2-131 0 14.2-181 0 F14.2-4 0 14.2-82 0 14.2-132 0 14.2-182 0 F14.2-5 0 14.2-83 0 14.2-133 11 14.2-183 0 15-i 0 14.2-84 0 14.2-134 0 14.2-184 0 15-ii 7 14.2-85 0 14.2-135 0 14.2-185 0 15-iii 0 14.2-86 0 14.2-136 9 14.2-186 0 15-iv 0 14.2-87 0 14.2-137 0 14.2-187 0 15-v 0 14.2-88 0 14.2-138 0 14.2-188 0 15-vi 17 14.2-89 0 14.2-139 0 14.2-189 0 15-vii 0 14.2-90 0 14.2-140 0 14.2-190 0 15-viii 0 14.2-91 12 14.2-141 0 14.2-191 0 15-ix 16 14.2-92 12 14.2-142 11 14.2-192 0 15-x 0 14.2-93 12 14.2-143 0 14.2-193 0 15-xi 0 14.2-94 0 14.2-144 0 14.2-194 0 15-xii 0 14.2-95 0 14.2-145 12 14.2-195 0 15-xiii 17 14.2-96 0 14.2-146 12 14.2-196 0 15-xiv 13 14.2-97 0 14.2-147 0 14.2-197 0 15-xv 11 14.2-98 0 14.2-148 0 14.2-198 0 15-xvi 18 14.2-99 0 14.2-149 0 14.2-199 0 15-xvii 17 14.2-100 0 14.2-150 0 14.2-200 0 15-xviii 12 14.2-101 0 14.2-151 0 14.2-201 0 15-xix 12 14.2-102 0 14.2-152 0 14.2-202 0 15-xx 0 14.2-103 0 14.2-153 0 14.2-203 0 15-xxi 17 14.2-104 0 14.2-154 0 14.2-204 0 15-xxii 11 14.2-105 0 14.2-155 0 14.2-205 0 15-xxiii 13 14.2-106 0 14.2-156 0 14.2-206 0 15-xxiv 0 14.2-107 0 14.2-157 0 14.2-207 23 15-xxv 0 14.2-108 0 14.2-158 0 14.2-208 7 15-xxvi 0 14.2-109 0 14.2-159 0 14.2-209 0 15-xxvii 0 14.2-110 0 14.2-160 0 14.2-210 0 15-xxviii 0 14.2-111 0 14.2-161 0 14.2-211 0 15-xxix 0 14.2-112 0 14.2-162 0 14.2-212 0 15.0-1 17 14.2-113 0 14.2-163 0 14.2-213 21 T15.0-1 Sh1 17 14.2-114 0 14.2-164 0 14.2-214 0 T15.0-1 Sh2 17 44

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev T15.0-1 Sh3 17 15.2-8a R T15.2-11 13 15.4-16 11 T15.0-2 14 15.2-8b R F15.2-1 17 15.4-17 11 T15.0-3 Sh1 17 15.2-9 11 F15.2-2 11 15.4-18 15 T15.0-3 Sh2 17 15.2-10 14 F15.2-3 17 15.4-19 16 T15.0-3 Sh3 17 15.2-11 17 F15.2-4 11 15.4-20 23 T15.0-3 Sh4 17 15.2-12 0 F15.2-5 17 T15.4-1 0 T15.0-4 11 15.2-13 17 F15.2-6 0 T15.4-2 17 T15.0-5 Sh1 9 15.2-14 17 F15.2-7 0 T15.4-3 11 T15.0-5 Sh2 0 15.2-15 17 F15.2-8 0 T15.4-4 11 F15.0-1 0 15.2-16 17 F15.2-9 13 T15.4-5 11 F15.0-2 11 15.2-17 17 F15.2-10 0 T15.4-6 16 15.1-1 17 15.2-18 17 F15.2-11 0 T15.4-7 7 15.1-2 17 15.2-19 15 15.3-1 14 T15.4-8 7 15.1-3 17 15.2-20 17 15.3-2 12 T15.4-9 7 15.1-4 25 15.2-21 17 15.3-3 0 T15.4-10 22 15.1-5 17 15.2-22 17 15.3-4 14 T15.4-11 7 15.1-6 17 15.2-23 17 15.3-5 12 T15.4-12 7 15.1-7 11 15.2-24 14 15.3-6 23 T15.4-13 7 15.1-8 14 15.2-25 0 15.3-7 23 T15.4-14 7 15.1-9 11 15.2-26 14 15.3-8 23 T15.4-15 7 15.1-10 11 15.2-27 17 15.3-9 23 T15.4-16 7 15.1-11 14 15.2-28 0 15.3-10 14 T15.4-17 11 15.1-12 14 15.2-29 14 15.3-11 22 F15.4-1 11 15.1-13 11 15.2-30 14 15.3-12 12 F15.4-2 0 15.1-14 14 15.2-31 10 15.3-13 14 F15.4-3 14 15.1-15 11 15.2-32 14 15.3-14 0 F15.4-4 7 15.1-16 23 15.2-33 26 15.3-15 0 15.5-1 14 15.1-17 11 15.2-34 17 15.3-16 0 15.5-2 14 15.1-18 0 15.2-35 0 15.3-17 14 15.5-3 12 15.1-19 14 15.2-36 14 T15.3-1 0 15.5-4 14 15.1-20 11 15.2-37 17 T15.3-2 0 T15.5-1 0 15.1-21 14 15.2-38 17 T15.3-3 0 F15.5-1 0 T15.1-1 17 15.2-39 13 F15.3-1 0 15.6-1 16 T15.1-2 11 15.2-40 13 F15.3-2 0 15.6-2 0 T15.1-3 11 15.2-41 10 F15.3-3 0 15.6-3 0 T15.1-4 0 15.2-42 13 15.4-1 14 15.6-4 16 T15.1-5 0 15.2-43 14 15.4-2 14 15.6-5 16 T15.1-6 0 15.2-44 10 15.4-3 13 15.6-6 19 F15.1-1 17 15.2-45 0 15.4-4 17 15.6-7 16 F15.1-2 11 15.2-46 14 15.4-5 23 15.6-8 14 F15.1-3 11 T15.2-1 17 15.4-6 14 15.6-9 14 F15.1-4 0 T15.2-2 11 15.4-7 23 15.6-10 0 15.2-1 14 T15.2-3 17 15.4-8 17 15.6-11 17 15.2-2 14 T15.2-4 11 15.4-9 23 15.6-12 17 15.2-3 14 T15.2-5 17 15.4-10 23 15.6-13 19 15.2-4 14 T15.2-6 0 15.4-11 23 15.6-14 12 15.2-5 26 T15.2-7 14 15.4-12 17 15.6-15 0 15.2-6 17 T15.2-8 0 15.4-13 17 15.6-16 0 15.2-7 17 T15.2-9 0 15.4-14 11 15.6-17 0 15.2-8 17 T15.2-10 2 15.4-15 14 15.6-18 12 45

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev 15.6-19 18 F15.6-4 12 15.9-2 0 15.9-52 10 15.6-20 19 F15.6-5 12 15.9-3 0 15.9-53 10 15.6-21 18 F15.6-6 12 15.9-4 0 15.9-54 0 15.6-22 19 F15.6-7 12 15.9-5 17 15.9-55 14 15.6-23 12 F15.6-8 12 15.9-6 0 15.9-56 14 15.6-24 12 F15.6-9 12 15.9-7 17 15.9-57 0 15.6-25 13 F15.6-10 12 15.9-8 0 15.9-58 0 15.6-26 14 F15.6-11 12 15.9-9 0 15.9-59 0 15.6-27 0 F15.6-12 12 15.9-10 0 15.9-60 0 15.6-28 14 F15.6-13 12 15.9-11 0 15.9-61 0 15.6-29 16 15.7-1 14 15.9-12 0 15.9-62 0 15.6-30 19 15.7-2 0 15.9-13 0 15.9-63 0 15.6-31 19 15.7-3 14 15.9-14 0 15.9-64 0 T15.6-1 0 15.7-4 14 15.9-15 0 15.9-65 17 T15.6-2 Sh1 16 15.7-5 14 15.9-16 0 15.9-66 7 T15.6-2 Sh2 16 15.7-6 1 15.9-17 0 15.9-67 0 T15.6-2 Sh3 16 15.7-7 1 15.9-18 0 15.9-68 13 T15.6-3 12 15.7-7a 1 15.9-19 0 15.9-69 13 T15.6-4 12 15.7-7b 1 15.9-20 0 15.9-70 0 T15.6-5 19 15.7-8 1 15.9-21 0 15.9-71 0 T15.6-6 Sh1 2 15.7-9 1 15.9-22 0 15.9-72 15 T15.6-6 Sh2 0 15.7-10 16 15.9-23 0 15.9-73 0 T15.6-7 Sh1 17 15.7-11 19 15.9-24 0 15.9-74 15 T15.6-7 Sh2 17 15.7-12 19 15.9-25 0 15.9-75 0 T15.6-7 Sh3 R 15.7-13 R 15.9-26 0 T15.9-1 0 T15.6-8 12 15.7-14 R 15.9-27 0 T15.9-2 Sh1 0 T15.6-9 17 T15.7-1 0 15.9-28 0 T15.9-2 Sh2 0 T15.6-10 12 T15.7-2 0 15.9-29 0 T15.9-3 0 T15.6-11 12 T15.7-3 0 15.9-30 0 T15.9-4 0 T15.6-12 Sh1 19 T15.7-4 14 15.9-31 3 T15.9-5 15 T15.6-12 Sh2 19 T15.7-5 Sh1 16 15.9-32 3 T15.9-6 0 T15.6-12 Sh3 12 T15.7-5 Sh2 16 15.9-33 0 T15.9-7 0 T15.6-12 Sh4 R T15.7-5 Sh3 16 15.9-34 0 T15.9-8 17 T15.6-13 12 T15.7-5 Sh4 16 15.9-35 0 T15.9-9 17 T15.6-14 12 T15.7-6 12 15.9-36 0 T15.9-10 0 T15.6-15 12 T15.7-7 12 15.9-37 0 T15.9-11 0 T15.6-16 22 T15.7-8 22 15.9-38 0 F15.9-1 0 T15.6-17 12 T15.7-9 12 15.9-39 0 F15.9-2 0 T15.6-18 12 T15.7-10 12 15.9-40 0 F15.9-3 0 T15.6-19 12 T15.7-11 12 15.9-41 0 F15.9-4 0 T15.6-20 12 T15.7-12 12 15.9-42 0 F15.9-5 0 T15.6-21 2 F15.7-1 13 15.9-43 0 F15.9-6 0 T15.6-22 Sh1 16 15.8-1 22 15.9-44 0 F15.9-7 0 T15.6-22 Sh2 0 15.8-2 11 15.9-45 0 F15.9-8 0 T15.6-22 Sh3 16 15.8-3 0 15.9-46 0 F15.9-9 0 T15.6-23 12 15.8-4 0 15.9-47 14 F15.9-10 0 T15.6-24 19 15.8-5 0 15.9-48 23 F15.9-11 0 F15.6-1 0 15.8-6 0 15.9-49 0 F15.9-12 0 F15.6-2 0 15.8-7 23 15.9-50 0 F15.9-13 0 F15.6-3 12 15.9-1 0 15.9-51 0 F15.9-14 0 46

HOPE CREEK LIST OF CURRENT PAGES REVISION 26 PAGE Rev PAGE Rev PAGE Rev PAGE Rev F15.9-15 0 15A-8 R 15C.3-5 11 T15D-3 26 F15.9-16 0 15A-9 R 15C.3-6 15 T15D-4 26 F15.9-17 0 15A-10 R 15C.3-7 11 T15D-5 26 F15.9-18 23 15A-11 R 15C.3-8 11 T15D-6 14 F15.9-19 0 15A-12 R 15C.3-9 8 T15D-7 14 F15.9-20 0 15A-13 R 15C.3-10 18 T15D-8 26 F15.9-21 0 15A-13a R 15C.3-11 0 T15D-9 26 F15.9-22 0 15A-13b R 15C.3-12 0 F15D-1 26 F15.9-23 0 15A-14 R 15C.3-13 0 F15D-2 26 F15.9-24 9 15A-15 R 15C.3-14 0 F15D-3 26 F15.9-25 0 15A-16 R 15C.3-15 0 F15D-4 26 F15.9-26 0 15A-17 R 15C.3-16 0 F15D-5 14 F15.9-27 0 15A-18 R 15C.3-17 0 F15D-6 14 F15.9-28 0 15A-19 R 15C.3-18 0 F15D-7 14 F15.9-29 0 15A-20 R 15C.3-19 0 F15D-8 14 F15.9-30 0 15A-21 R 15C.3-20 0 F15D-9 14 F15.9-31 14 15A-22 R 15C.3-21 0 F15D-10 14 F15.9-32 0 15A-23 R 15C.4-1 18 F15D-11 14 F15.9-33 0 15A-24 R 15C.4-2 18 F15D-12 14 F15.9-34 0 T15A-1 0 15C.4-3 11 F15D-13 14 F15.9-35 0 T15A-2 Sh1 0 15C.5-1 11 F15D-14 14 F15.9-36 0 T15A-2 Sh2 0 15C.5-2 11 F15D-15 14 F15.9-37 0 15B-1 15 15C.5-3 R F15D-16 14 F15.9-38 0 15B-2 15 15C.5-4 R F15D-17 14 F15.9-39 0 15B-3 0 15C.6-1 0 F15D-18 14 F15.9-40 0 15B-4 15 15C.7-1 11 F15D-19 14 F15.9-41 7 15B-5 15 15C.7-2 14 F15D-20 R F15.9-42 0 15B-6 15 15C.8-1 14 F15D-21 R F15.9-43 0 T15B-1 9 15C.8-2 17 F15D-22 R F15.9-44 0 T15B-2 0 15D-i 26 F15D-23 R F15.9-45 0 F15B-1 0 15D-ii 24 F15D-24 R F15.9-46 0 F15B-2 0 15D-iii 24 F15D-25 R F15.9-47 0 F15B-3 0 15D-iv 26 16-i 0 F15.9-48 0 F15B-4 0 15D-v 18 16.1-1 0 F15.9-49 15 AShShx 15C 0 15D-1 26 16.2-1 0 F15.9-50 0 15C-i 25 15D-2 26 17-i 15 F15.9-51 15 15C-ii 0 15D-3 25 17-ii 15 F15.9-52 0 15C-iii 0 15D-4 25 17-iii 15 F15.9-53 0 15C-iv 25 15D-5 24 17-iv R F15.9-54 0 15C.1-1 17 15D-6 26 17.1-1 0 F15.9-55 0 15C.1-2 18 15D-7 24 17.2-1 15 F15.9-56 0 15C.2-1 11 15D-8 26 17.2-2 R F15.9-57 0 15C.2-2 18 15D-9 26 17.2-3 R 15A-1 16 15C.2-3 18 15D-10 26 17.2-4 R 15A-2 16 15C.2-4 18 T15D-1 Sh1 26 17.2-5 R 15A-3 16 15C.2-5 0 T15D-1 Sh2 26 17.2-6 R 15A-4 16 15C.3-1 11 T15D-1 Sh3 26 17.2-7 R 15A-5 R 15C.3-2 12 T15D-1 Sh4 R 17.2-7a R 15A-6 R 15C.3-3 18 T15D-1 Sh5 R 17.2-7b R 15A-7 R 15C.3-4 18 T15D-2 26 17.2-7c R 47

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SECTION 1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT TABLE OF CONTENTS Section Title Page

1.1 INTRODUCTION

1.1-1 1.2 GENERAL PLANT DESCRIPTION 1.2-1 1.2.1 Site Characteristics 1.2-1 1.2.1.1 Location 1.2-1 1.2.1.2 Meteorology 1.2-1 1.2.1.3 Site Environs and Access 1.2-2 1.2.1.4 Geology and Soil 1.2-2 1.2.1.5 Seismology 1.2-3 1.2.1.6 Hydrology 1.2-3 1.2.1.7 Groundwater 1.2-4 1.2.2 Principal Design Criteria 1.2-5 1.2.2.1 General Design Criteria 1.2-5 1.2.2.2 System Criteria 1.2-11 1.2.3 General Arrangement of Structures and 1.2-17 Equipment 1.2.4 System Description 1.2-18 1.2.4.1 Nuclear System 1.2-18 1.2.4.2 Nuclear Safety Systems and Engineered 1.2-21 Safety Features 1.2.4.3 Power Conversion System 1.2-31 1.2.4.4 Electrical Systems and Instrumentation 1.2-35 and Control 1.2.4.5 Fuel Handling and Storage Systems 1.2-39 1.2.4.6 Cooling Water and Auxiliary Systems 1.2-40 1.2.4.7 Radioactive Waste Systems 1.2-44 1.2.4.8 Radiation Monitoring and Control 1.2-46 1.2.4.9 Shielding 1.2-46 1.2.5 References 1.2-47 1-i HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.3 COMPARISON TABLES 1.3-1 1.3.1 Comparisons with Similar Facility Designs 1.3-1 1.3.2 Comparison of Final and Preliminary 1.3-1 Information (FSAR) 1.3.3 References 1.3-2 1.4 IDENTIFICATION OF AGENTS AND CONTRACTORS 1.4-1 1.4.1 Applicant 1.4-1 1.4.2 Architect Engineer and Constructor 1.4-2 1.4.3 Nuclear Steam Supply System Supplier 1.4-3 1.4.4 Turbine Generator Supplier 1.4-3 1.4.5 Consultants 1.4-4 1.5 REQUIREMENTS FOR FURTHER TECHNICAL 1.5-1 INFORMATION 1.5.1 Current Development Programs 1.5-1 1.5.1.1 Instrumentation for Vibration 1.5-1 1.5.1.2 Core Spray Distribution 1.5-1 1.5.1.3 Core Spray and Core Flooding 1.5-2 Heat Transfer Effectiveness 1.5.1.4 Verification of Pressure Suppression 1.5-2 Design 1.5.1.5 Critical Heat Flux Testing 1.5-3 1.5.2 References 1.5-3 1.6 MATERIAL INCORPORATED BY REFERENCE 1.6-1 1.7 DRAWINGS AND OTHER DETAILED INFORMATION 1.7-1 1.8 CONFORMANCE TO NRC REGULATORY GUIDES 1.8-1 1.8.1 Non-NSSS Assessment of Conformance 1.8-1 1.8.2 NSSS Assessment of Conformance 1.8-157 1.8.2.1 Purpose 1.8-157 1-ii HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.8.2.2 Compliance Assessment Method-NSSS 1.8-157 1.8.3 References 1.8-158 1.9 STANDARD DESIGNS 1.9-1 1.10 TMI-2 RELATED REQUIREMENTS FOR NEW 1.10-1 OPERATING LICENSES 1.10.1 NUREG-0737, Clarification of the 1.10-1 TMI Action Plan Requirements 1.10.2 TMI Action Plan Requirements for 1.10-2 Applicants for an Operating License (Enclosure 2 to NUREG-0737) 1.11 DIFFERENCES FROM THE STANDARD REVIEW 1.11-1 PLAN 1.11.1 Differences from SRP Acceptance Criteria 1.11-1 1.12 UNRESOLVED GENERIC SAFETY ISSUES 1.12-1 1.12.1 Introduction 1.12-1 1.12.2 New Unresolved Safety Issues 1.12-6 1.12.3 Discussion of Tasks as They Relate 1.12-7 to HCGS 1.12.3.1 Task A-1, Waterhammer 1.12-7 1.12.3.2 Task A-7, Mark I Containment Long-Term 1.12-9 Program 1.12.3.3 Task A-11, Reactor Vessel Materials 1.12-11 Toughness 1.12.3.4 Task A-17, Systems Interaction In Nuclear 1.12-13 Power Plants 1.12.3.5 Task A-40, Seismic Design Criteria/ 1.12-15 Short-Term Program 1.12.3.6 Task A-43, Containment Emergency Sump 1.12-16 Reliability 1-iii HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.12.3.7 Task A-44, Station Blackout 1.12-17 1.12.3.8 Task A-45, Shutdown Decay Heat Removal 1.12-21 Requirements 1.12.3.9 Task A-46, Seismic Qualification of 1.12-23 Equipment in Operating Plants 1.12.3.10 Task A-47, Safety Implications of 1.12-24 Control Systems 1.12.3.11 Task A-48, Hydrogen Control Measures 1.12-25 and Effects of Hydrogen Burns on Safety Equipment 1.13 SYMBOLS AND TERMS 1.13-1 1.13.1 Text Acronyms 1.13-1 1.13.2 Logic Symbols 1.13-1 1.13.3 Piping Identification 1.13-1 1.13.4 Valve Identification 1.13-2 1.13.5 Equipment Numbering and Location 1.13-3 1.13.6 Electrical Component Identification 1.13-6 1.13.6.1 Equipment Location Numbers 1.13-6 1.13.6.2 Scheme Cable Numbers 1.13-7 1.13.6.3 Raceway Numbers 1.13-7 1.13.6.4 Conduit Numbers 1.13-9 1.14 GENERIC LICENSING ISSUES 1.14-1 1.14.1 Licensing Issues 1.14-1 1.14.1.1 Internally Generated Missiles, 1.14-9 LRG I/RSB-1 1.14.1.2 CRD Return Line Removal, LRG I/RSB-2 1.14-9 1.14.1.3 SRV Surveillance Program, LRG II/3-RSB -3 1.14-10 1.14.1.4 SRV Performance Testing, LRG I/RSB-3 1.14-10 1-iv HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.14.1.5 Applicability of The Liquid Flow 1.14-11 Through SRV Tests Performed in Response to TMI Action Plan Item II.D.1, LRG II/6-RSB 1.14.1.6 Trip of Recirculation Pumps to Mitigate 1.14-11 ATWS, LRG I/RSB-4 1.14.1.7 Detection of Intersystem Leakage, 1.14-11 LRG I/RSB-5 1.14.1.8 RCIC Pump Suction Switchover, 1.14-13 LRG I/RSB-6 and LRG II/6-RSB 1.14.1.9 Unintentional Shutdown of the RCIC 1.14-13 System, LRG I/RSB-7 1.14.1.10 Design Adequacy of the RCIC System- 1.14-14 Providing Automatic Restart Capability, LRG II/2-RSB(a), LRG II/2-RSB(b), LRG II/2-RSB(d) 1.14.1.11 Adequate SRV Fluid Flow, LRG I/RSB-8 1.14-15 1.14.1.12 Provisions to Preclude Vortex Formation, 1.14-15 LRG II/7-RSB 1.14.1.13 Categorization of Valve Which Isolates 1.14-16 RHR From Reactor Coolant System, LRG I/RSB-9 1.14.1.14 Available Net Positive Suction Head, 1.14-16 LRG I/RSB-10 1.14.1.15 Assurance of Filled ECCS Lines, 1.14-16 LRG I/RSB-II 1.14.1.16 Operability of ADS, LRG I/RSB-12 1.14-17 1.14.1.17 Assurance for Long Term Operability of 1.14-17 the Automatic Depressurization System (ADS), LRG II/8-RSB 1.14.1.18 Leakage Testing of Reactor Coolant 1.14-18 System Isolation Valves, LRG I/RSB-13 1-v HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.14.1.19 Assurance for Long-Term Operability of 1.14-18 Deep Draft Pumps, LRG II/9-RSB and LRG I/RSB-14 1.14.1.20 Control of Post-LOCA Leakage to 1.14-20 Protect ECCS and Preserve Suppression Pool Level LRG II/5-RSB 1.14.1.21 Operator Action Required/Assumed in 1.14-20 LOCA Analysis in the 10-to-20 Minute Time Frame, LRG II/4-RSB 1.14.1.22 Replace High Drywell Pressure Interlock 1.14-21 on HPCS Trip Circuitry with Level-8 Trip to Prevent Main Steam Line Flooding, LRG II/13-RSB 1.14.1.23 Additional LOCA Break Spectrum, 1.14-21 LRG I/RSB-15 1.14.1.24 LOCA Analyses with Closure of the 1.14-22 Recirculation Flow Control Valve, LRG I/RSB-16 and LRG II/10-RSB 1.14.1.25 Adequate Time Available for Operator 1.14-22 Action Required LRG I/RSB-17 1.14.1.26 Requirement for Automatic Restart of 1.14-23 HPCS after Manual Termination, LRG II/1-RSB 1.14.1.27 Adequate Core Cooling Maintained with 1.14-23 LPCI Diversion, LRG I/RSB-18 1.14.1.28 Temperature Drop with Feedwater 1.14-24 Heater Failure, LRG I/RSB-19 1.14.1.29 Use of Nonreliable Equipment in 1.14-24 Anticipated Operational Transients, LRG I/RSB-20 1-vi HCGS-UFSAR Revision 8 September 25, 1996

TABLE OF CONTENTS (Cont) Section Title Page 1.14.1.30 Reliance on Nonsafety-Grade Equipment 1.14-25 in the Analysis of Recirculation-Pump Shaft Seizure, LRG I/RSB-21 and LRG II/11-RSB 1.14.1.31 ATWS, LRG I/RSB-22 1.14-26 1.14.1.32 ODYN Transient Analysis Code, 1.14-28 LRG I/RSB-23 1.14.1.33 Classification of Load Rejection Without 1.14-28 Bypass and Turbine Trip Without Bypass and Recalculation of MCPR, LRG I/RSB-24 and LRG II/12-RSB 1.14.1.34 Proper Classification of Transients, 1.14:29 LRG II/12-RSB 1.14.1.35 Adequacy of the GEXL Correlation, 1.14-29 LRG I/RSB-25 1.14.1.36 Core Thermal Hydraulic Stability 1.14-29 Analyses, LRG I/RSB-26 and LRG II/11-CPB 1.14.1.37 Low or Degraded Grid Voltage, LRG I/PSB-1 1.14-31 1.14.1.38 Test Results for Diesel Generators, 1.14-31 LRG I/PSB-2 1.14.1.39 Containment Electrical Penetrations, 1.14-32 LRG I/PSB-3 1.14.1.40 Adequacy of the 120 V ac RPS Power 1.14-33 Supply, LRG I/PSB-4 1.14.1.41 Thermal Overload Protection Bypass, 1.14-34 LRG I/PSB-5 1.14.1.42 Reliability of Diesel Generator, 1.14-34 LRG I/PSB-6 1.14.1.43 Diesel Generator Reliability, 1.14-35 LRG II/1-PSB 1.14.1.44 Shared DG Conformance R.G. 1.81, 1.14-46 LRG I/PSB-7 1-vii HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.14.1.45 Periodic Diesel Generator Testing, 1.14-46 LRG I/PSB-8 1.14.1.46 Special Low Power Testing Program, 1.14-46 LRG II/L-HFS 1.14.1.47 Emergency Procedures Reactivity Control 1.14-47 Guidelines, LRG II/2-HFS 1.14.1.48 Common Reference for Reactor Level 1.14-47 Measurements, LRG II/3-HFS 1.14.1.49 Reactor Coolant Sampling, LRG II/1-CHEB 1.14-48 1.14.1.50 Suppression Pool Sampling LRG II/2-CHEB 1.14-49 1.14.1.51 Estimation of Fuel Damage from Post 1.14-50 Accident Samples, LRG II/3-CHEB 1.14.1.52 Failures in Vessel Level Sensing Lines 1.14-50 Common to Control and Protective Systems, LRG II/1-ICSB 1.14.1.53 Physical Separation and Electrical 1.14-51 Isolation, LRG I/ICSB-2 1.14.1.54 Redundancy and Diversity of High/Low 1.14-51 Pressure System Interlocks, LRG II/2-ICSB 1.14.1.55 ATWS, LRG I/ICSB-3 1.14-52 1.14.1.56 Test Techniques, LRG I/ICSB-4 1.14-52 1.14.1.57 Potential for Both Low-Low Setpoint 1.14-53 Valves to Open Due To Single Failures, LRG II/3-ICSB 1.14.1.58 Safety System Setpoints, Instrument 1.14-53 Range, LRG I/ICSB-5 1.14.1.59 IE Bulletin 80-06: Engineered Safety 1.14-54 Feature Reset Control, LRG II/4-ICSB 1.14.1.60 Drawings, LRG I/ICSB-6 1.14-54 1.14.1.61 Control Systems Failure, LRG II/5-ICSB 1.14-55 1.14.1.62 RCIC Classification, LRG I/ICSB-7 1.14-55 1-viii HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.14.1.63 Safety-Related Display, LRG I/ICSB-9 1.14-56 1.14.1.64 Rod Block Monitor, LRG I/ICSB-10 1.14-56 1.14.1.65 MSIV Leakage Control System, 1.14-58 LRG I/ICSB-11 (Historical Information) 1.14.1.66 Procedures Following Bus Failure (IE 1.14-59 Bulletin 79-27), LRG II/6-ICSB 1.14.1.67 Harsh Environment for Electrical 1.14-59 Equipment Following High Energy Line Breaks LRG II/7-ISCB 1.14.1.68 Steam Bypass of the Suppression Pool, 1.14-60 LRG I/CSB-1 1.14.1.69 Pool Dynamic LOCA and SRV Loads, 1.14-60 LRG I/CSB-2 1.14.1.70 Containment Dynamic Loads, LRG II/1-CSB 1.14-61 1.14.1.71 Containment Purge System, LRG I/CSB-3 1.14-61 1.14.1.72 Combustible Gas Control LRG I/CSB-4 1.14-69 1.14.1.73 Hydrogen Control Capability, LRG II/2-CSB 1.14-70 1.14.1.74 Containment Leakage Testing, LRG I/CSB-5 1.14-71 1.14.1.75 BWR Scram Discharge Volume Modifications, 1.14-72 LRG II/1-ASB 1.14.1.76 Safe Shutdown for Fires and Remote 1.14-82 Shutdown System, LRG II/2-ASD 1.14.1.77 Protection of Equipment in Main Steam 1.14-82 Pipe Tunnel LRG II/3-ASB 1.14.1.78 Design Adequacy of the RCIC System Pump 1.14-83 Room Cooling System, LRG II/4-ASB 1.14.1.79 Reassessment of Accident Assumptions as 1.14-84 Related to Main Steam Line Isolation Valve Leakage Rate, LRG II/1-AEB 1.14.1.80 Asymmetrical LOCA and SSE and Annulus 1.14-84 Pressurization Loads on Reactor, Vessel, Internals and Supports, LRG I/MEB-1 1-ix HCGS-UFSAR Revision 12 May 3, 2002

TABLE OF CONTENTS (Cont) Section Title Page 1.14.1.81 Pre-Operational Vibration Assurance 1.14-85 Program, LRG I/MEB-2 1.14.1.82 RPV Internals Vibration Test Program for 1.14-85 BWR/6, LRG II/2-MEB 1.14.1.83 Dynamic Response Combination Using SRSS 1.14-86 Technique, LRG I/MEB-3 1.14.1.84 Input Criteria for Use of SRSS for 1.14-86 Mechanical Equipment (NUREG-0484, Rev. 1), LRG II/1-MEB 1.14.1.85 Loading Combinations, Design Transients, 1.14-87 and Stress Limits, LRG I/MEB-4 1.14.1.86 Stress Corrosion Cracking of Stainless 1.14-87 Steel, LRG I/MEB-5 1.14.1.87 Pump and Valve Operability Assurance 1.14-88 Program, LRG I/MEB-6 1.14.1.88 Bolted Connections for Supports, 1.14-88 LRG I/MEB-7 1.14.1.89 Pump and Valve Inservice Testing Program, 1.14-89 LRG I/MEB-8 1.14.1.90 SRV In-Situ Test Program, LRG I/MEB-9 1.14-89 1.14.1.91 CRD System Return Line Removal, 1.14-90 LRG I/MEB-11 1.14.1.92 Test Program Documentation for High and 1.14-90 Moderate-Energy Piping Systems, LRG I/MEB-12 1.14.1.93 OBE Stress Cycles for the Mechanical 1.14-90 Design of NSSS Equipment and Components, LRG II/3-MEB 1.14.1.94 Kuosheng Incore Instrument Tube Break, 1.14-91 LRG II/4-MEB 1-x HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.14.1.95 Preservice and Inservice Inspection of 1.14-92 Class 1, 2, and 3 Components, LRG I/MTEB-1 1.14.1.96 Inspectability of Welded Flued Head 1.14-92 Design on Main Steam Line Containment Penetration, LRG II/L-MTEB 1.14.1.97 Clarification and Justification of the 1.14-94 Methods Used to Construct the Operating Pressure/Temperature Limits, LRG I/MTEB-2 and MTEB-4 1.14.1.98 Exemptions from Appendix H to 10CFR50, 1.14-95 LRG I/MTEB-3 1.14.1.99 Reactor Testing and Cooldown Limits, 1.14-96 LRG I/MTEB-4 1.14.1.100 Exposure Resulting from Actuation of 1.14-96 Safety/Relief Valves (SRVs), LRG II/1-RAB 1.14.1.101 Routing Exposures Inside Containment, 1.14-97 LRG II/2-RAB 1.14.1.102 Controlling Radioactivity During Steam 1.14-98 Dryer and Steam Separator Refueling Transfer, LRG II/3-RAB 1.14.1.103 Shielding of Spent Fuel Transfer Tube 1.14-98 and Canal During Refueling, LRG II/4-RAB 1.14.1.104 Combination of Loads, LRG II/1-SEB 1.14-99 1.14.1.105 Fluid/Structure Interaction, LRG II/2-SEB 1.14-100 1.14.1.106 Loads Assessment of Fuel Assembly 1.14-101 Components, LRG I/CPB-1 1.14.1.107 Combined Seismic and LOCA Loads 1.14-101 Analysis on Fuel, LRG II/2-CPB 1.14.1.108 Nonconservatism in the Models for 1.14-102 Fuel Cladding Swelling and Rupture, LRG I/CPB-2 and LRG II/1-CPB 1-xi HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 1.14.1.109 Fuel Rod Cladding Ballooning and Rupture 1.14-102 1.14.1.110 High Burnup Fission Gas Release, 1.14-103 LRG II/4-CPB 1.14.1.111 Channel Box Deflection, LRG II/3-CPB 1.14-103 and LRG I/CPB-3 1.14.1.112 Water Side Corrosion of Fuel Cladding 1.14-106 Due to Copper in the Feedwater, LRG I/CPB-4 and LRG II/5-CPB 1.14.1.113 Cladding Water-Side Corrosion, 1.14-106 LRG II/5-CPB 1.14.1.114 Instrumentation to Detect Inadequate 1.14-107 Core Cooling, LRG II/6-CPB 1.14.1.115 Rod Withdrawal Transient Analysis, 1.14-107 LRG II/7-CPB 1.14.1.116 Fuel Analysis for Mislocated or 1.14-108 Misoriented Bundles, LRG II/8-CPB 1.14.1.117 Discrepancy in Void Coefficient 1.14-108 Calculation, LRG II/9-CPB 1.14.1.118 Bounding Rod Worth Analysis, 1.14-109 LRG II/10-CPB 1.14.1.119 Core Thermal Hydraulic Stability 1.14-110 Analysis, LRG II/11-CPB 1.14.1.120 Seismic Qualification of Equipment, LRG I 1.14-110 1.14.1.121 Environmental Qualification of Equipment, 1.14-111 LRG I 1.15 CONFORMANCE TO RULES ISSUED AFTER PLANT 1.15-1 LICENSING 1.15.1 NRC Rule on Station Blackout 1.15-1 1.15.1.1 Conformance to NRC Rule on Station Blackout 1.15-1 1.15.2 References 1.15-2 1-xii HCGS-UFSAR Revision 7 December 29, 1995

LIST OF TABLES Table Title 1.3-1 Comparison of Nuclear Steam Supply System Design Characteristics 1.3-2 Comparison of Power Conversion System Design Characteristics 1.3-3 Comparison of Engineered Safety Features and Auxiliary Systems Design Characteristics 1.3-4 Comparison of Containment Design Characteristics 1.3-5 Radioactive Waste Management Systems Design Characteristics 1.3-6 Comparison of Structural Design Characteristics 1.3-7 Comparison of Instrumentation and Electrical Systems Design Characteristics 1.3-8 Significant Design Changes from PSAR to FSAR 1.7-1 Electrical Drawings 1.7-2 Figure Index for Plant Systems 1.7-3 Control and Instrumentation Drawings 1.8-1 Regulatory Guide Assessment - NSSS 1-xiii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES (Cont) Table Title 1.8-2 Relative Neutron Flux Versus Time 1.8-3 Use of Code Case N-242 on RCPB Piping and Components 1.8-4 Design Criteria Comparison 1.11-1 Summary of Differences from SRP 1.13-1 Acronyms Used in FSAR 1.13-2 Piping and Valve Class Identification 1-xiv HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES Figure Title 1.1-1 Heat Balance at Rated Power 1.2-1 Deleted: Refer to Plant Drawing C-0001-0 1.2-2 Deleted: Refer to Plant Drawing P-0001-0 1.2-3 Deleted: Refer to Plant Drawing P-0002-0 1.2-4 Deleted: Refer to Plant Drawing P-0003-0 1.2-5 Deleted: Refer to Plant Drawing P-0004-0 1.2-6 Deleted: Refer to Plant Drawing P-0005-0 1.2-7 Deleted: Refer to Plant Drawing P-0006-0 1.2-8 Deleted: Refer to Plant Drawing P-0007-0 1.2-9 Deleted: Refer to Plant Drawing P-0010-0 1.2-10 Deleted: Refer to Plant Drawing P-0011-0 1.2-11 Deleted: Refer to Plant Drawing P-0012-0 1.2-12 Deleted: Refer to Plant Drawing N-1011 1.2-13 Deleted: Refer to Plant Drawing P-0012-1 1.2-14 Deleted: Refer to Plant Drawing P-0013-1 1-xv HCGS-UFSAR Revision 20 May 9, 2014

LIST OF FIGURES (Cont) Figure Title 1.2-15 Deleted: Refer to Plant Drawing P-0014-1 1.2-16 Deleted: Refer to Plant Drawing P-0015-1 1.2-17 Deleted: Refer to Plant Drawing P-0016-1 1.2-18 Deleted: Refer to Plant Drawing P-0031-0 1.2-19 Deleted: Refer to Plant Drawing P-0032-0 1.2-20 Deleted: Refer to Plant Drawing P-0033-0 1.2-21 Deleted: Refer to Plant Drawing P-0034-0 1.2-22 Deleted: Refer to Plant Drawing P-0035-0 1.2-23 Deleted: Refer to Plant Drawing P-0036-0 1.2-24 Deleted: Refer to Plant Drawing P-0037-0 1.2-25 Deleted: Refer to Plant Drawing P-0038-0 1-xvi HCGS-UFSAR Revision 20 May 9, 2014

LIST OF FIGURES (Cont) Figure Title 1.2-26 Deleted: Refer to Plant Drawing P-0014-1 1.2-27 Deleted: Refer to Plant Drawing P-0042-1 1.2-28 Deleted: Refer to Plant Drawing P-0043-1 1.2-29 Deleted: Refer to Plant Drawing P-0044-1 1.2-30 Deleted: Refer to Plant Drawing P-0045-1 1.2-31 Deleted: Refer to Plant Drawing P-0046-1 1.2-32 Deleted: Refer to Plant Drawing P-0047-1 1.2-33 Deleted: Refer to Plant Drawing P-0051-0 1.2-34 Deleted: Refer to Plant Drawing P-0052-0 1.2-35 Deleted: Refer to Plant Drawing P-0053-0 1.2-36 Deleted: Refer to Plant Drawing P-0054-0 1-xvii HCGS-UFSAR Revision 20 May 9, 2014

LIST OF FIGURES (Cont) Figure Title 1.2-37 Deleted: Refer to Plant Drawing P-0055-0 1.2-38 Deleted: Refer to Plant Drawing P-0056-0 1.2-39 Deleted: Refer to Plant Drawing P-0057-0 1.2-40 Deleted: Refer to Plant Drawing P-0071-0 1.2-41 Deleted: Refer to Plant Drawing P-0072-0 1.2-42 Deleted: Refer to Plant Drawing P-0073-0 1.2-43 Deleted: Refer to Plant Drawing P-0076-0 1.2-44 Plant Area Designations 1.13-1 Deleted: Refer to Plant Drawing M-00-0 1.13-2 Logic Symbols 1-xviii HCGS-UFSAR Revision 20 May 9, 2014

SECTION 1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT

1.1 INTRODUCTION

This Final Safety Analysis Report (FSAR) is submitted in support of the application of the Public Service Electric and Gas Company (PSE&G) for a utilization facility (Class 103) license for a nuclear power station designated as Hope Creek Generating Station (HCGS). This station is a one unit nuclear power plant. On August 21, 2000, the operating license for the Hope Creek station was transferred from PSE&G to PSEG Nuclear LLC. HCGS is located on the southern part of Artificial Island on the east bank of the Delaware River in Lower Alloways Creek Township, Salem County, New Jersey. The site is 15 miles south of the Delaware Memorial Bridge, 18 miles south of Wilmington, Delaware, 30 miles southwest of Philadelphia, Pennsylvania, and 7-1/2 miles southwest of Salem, New Jersey. The unit employs a General Electric boiling water reactor (BWR) licensed to operate at a rated core thermal power of 3902 MWt (100 percent steam flow) with a turbine generator nameplate rating of approximately 1287 MWe. The heat balance for rated power is shown on Figure 1.1-1. The reactor design power level of 3917 MWt is used in various analyses discussed in Section 6.3 and Section 15. In some analyses, a conservative power level of 4031 MWt is applied. The Dual Barrier Containment System designed by Bechtel Power Corporation consists of the following:

1. The Reactor and the Pressure Suppression Primary Containment System 1.1-1 HCGS-UFSAR Revision 23 November 12, 2018

2. The Reactor Building.

The primary containment is a steel shell, shaped like a light bulb, enclosed in reinforced concrete, and interconnected to a torus type steel suppression chamber. The design employs the drywall/pressure suppression features of the BWR/Mark I containment concept. The Reactor Building completely houses the reactor, the primary containment, and fuel handling and storage areas. To the extent that it limits the release of radioactive materials to the environs, the Reactor Building is capable of containing any radioactive materials that might I be released to it, subsequent to the occurrence of a postulated loss-of-coolant accident (LOCA) , so that the offsi te doses are below the guideline values stated in 10CFR50.67. Condenser cooling is provided by water circulated through a natural draft cooling tower. Fuel loading of the HCGS is scheduled for January, 1986. Therefore, receipt of the operating license is required by that date. Based on such receipt, commercial operation of the HCGS is scheduled for June 1986. 1.1-2 HCGS-UFSAR Revision 12 May 3, 2002

Revision 23, NOV 12,2018 Hope Creek Nucl ear Generati ng Stati on PSEG Nucl ear,LLC HEAT BALANCE AT RATED POW ER HOPE CREEK NUCLEAR GENERATING STATI ON Updated FSAR Figure 1.1-1 C 2000 PSEG Nuclear, LLC. All Rights Reserved.

THISFIGUREHASBEENDELETED PSEG NUCLEARL..L.C.. HOPE CREEKGENERATING STATION HOPECREEKUFSAR -REV 14 SHEET1 OF 1 July26, 2005 F1.1-1a

1.2 GENERAL PLANT DESCRIPTION 1.2.1 Site Characteristics A summary of the site characteristics for Hope Creek Generating Station (HCGS) is provided below. Detailed discussions on the site characteristics are provided in Section 2. 1.2.1.1 Location HCGS is located on the southern part of Artificial Island on the east bank of the Delaware River in Lower Alloways Creek Township, Salem County, New Jersey. While called Artificial Island, the site is actually connected to the mainland of New Jersey by a strip of tideland formed by hydraulic fill from dredging operations on the Delaware River by the U.S. Army Corps of Engineers. The site is 15 miles south of the Delaware Memorial Bridge, 18 miles south of Wilmington, Delaware, 30 miles southwest of Philadelphia, Pennsylvania, and 7-1/2 miles southwest of Salem, New Jersey. 1.2.1.2 Meteorology The area surrounding the Hope Creek site intersects two climatic regions: humid continental and humid subtropical. Both climates are characterized by warm summers and mild winters. Summer maximum temperatures average 80F, and the coldest month is January with an average daily temperature of approximately 32F. The maximum temperature reaches 100F on the average of 1 out of 6 years, and a temperature of 0F is observed 1 out of 4 years. The area is frequented by Polar Canadian air masses in the fall and winter and occasionally invaded by Arctic Canadian air late in winter. During the spring and summer, the dominant air mass is Maritime Tropical. The relative humidity averages 70 to 75 percent because of the proximity of the large water bodies to the south and west of the 1.2-1 HCGS-UFSAR Revision 0 April 11, 1988

site and the occurrence of southerly winds. Fog is frequent for the same reason. Southeasterly winds moving along the Delaware Bay at low wind speeds favor this formation of fog. Rainfall amounts are highest in the summer. Snowfall can be as little as 1 inch or as much as the 50 inches observed one year. Snow is generally mixed with rain and sleet. 1.2.1.3 Site Environs and Access The site is located in the southern region of the Delaware River Valley, which is defined as the area immediately adjacent to the Delaware River and extending from Trenton to Cape May Point, New Jersey on the eastern side, and from Morrisville, Pennsylvania, to Lewes, Delaware, on the western side. This region is characterized by extensive tidal marshlands and low-lying meadowlands. The major portion of the land in this area is undeveloped. A great deal of land adjacent to the Delaware River near the site is public land (federal- and state-owned), or land planned for future open space projects. In addition, industrial, commercial, or residential growth is limited by recent wetlands and New Jersey CAFRA legislation. The main access to the plant is from a road constructed by Public Service Electric and Gas Company (PSE&G). This road connects with Alloways Creek Neck Road about 2-1/2 miles east of the site. Access to the plant site and all activities thereon is under the control of PSE&G. 1.2.1.4 Geology and Soil The site is located within the Atlantic Coastal Plain Physiographic Province and is situated approximately 18 miles southeast of the Fall Line, which separates the Coastal Plain from the Piedmont Physiographic Province. The pre-Cretaceous basement rock is approximately 1500 to 2000 feet below grade. The sediments of Cretaceous age consist of Raritan 1.2-2 HCGS-UFSAR Revision 0 April 11, 1988

Formation, Magothy Formation, Matawan Group, and Monmouth Group. The sediments of Tertiary age consist of Hornerstown Formation, Vincentown Formation, and Kirkwood Formation. A thin layer of river bed sand and gravel is on top of the Kirkwood clays; approximately 30 feet of hydraulic fill was subsequently placed over this river bed deposit and now forms the surface of the Artificial Island. All Seismic Category I structures are firmly founded on compacted engineering backfill or concrete down to the Vincentown Formation. 1.2.1.5 Seismology The site is located in the region that has experienced infrequent minor earthquake activities. No known faults exist in the basement rock or sedimentary deposits in the immediate vicinity of the site. Significant earthquake motion is not expected at the site during the life of the facility. The seismicity of the site was evaluated on the basis of historical earthquake, local and regional geological structures, and associated tectonic provinces. The safe shutdown earthquake (SSE) for the Hope Creek site is conservatively specified as a modified Mercalli Intensity VII plus, with a ground acceleration of 20 percent of gravity. The operating basis earthquake (OBE) is specified with a ground acceleration of 10 percent gravity. 1.2.1.6 Hydrology The Delaware River Estuary System consists of Delaware Bay, Delaware Estuary, and Delaware River. HCGS is located on the Artificial Island in the Delaware Estuary, approximately 50 river miles upstream of the mouth of Delaware Bay. Tidal flows dominate over fresh water discharge in this area. The plant grade is generally at Elevation 12.5 feet above mean sea level (MSL), and is subject to maximum design flooding under the effects of probable maximum hurricane surge. All Seismic Category I structures are flood protected and structurally designed to 1.2-3 HCGS-UFSAR Revision 0 April 11, 1988

withstand the static and dynamic effects of the flood and coincident waves up to Elevation 31.4 feet MSL. The southeast face of the Reactor Building and a small corner face of the Auxiliary Building, which have exposures to slightly higher waves, are appropriately protected to Elevation 37.2 feet MSL. The site area is generally flat with natural drainage flowing toward the Delaware River and into the marsh areas toward the north and east. The site drainage system consists of below grade piping and drainage ditches that intercept and convey the runoff to the Delaware River. 1.2.1.7 Groundwater There are four major aquifers of interest in this region. The confining layers that separate the aquifers are not completely impermeable. The shallow aquifer is a 5 to 10 foot thick layer of riverbed sand and gravel at 30 feet below grade. The recharge to this aquifer occurs from infiltration of precipitation on the outcrop area within the site, and the discharge is in the southwest direction towards Delaware River. The deep aquifer is located in the basal sand of lower part of Kirkwood Formation, the Vincentown Formation, and the upper part of Hornerstown Formation. It is 80 feet thick, with its surface at approximately 70 feet below grade. Recharge to this aquifer occurs primarily by leakage from the overlying aquifers, and the discharge is in the southwest direction towards Delaware River. At 170 feet below grade is the Mount Laurel-Wenonah aquifer, which crops out and intercepts the Delaware River at 5 miles north of the site. Recharge to this aquifer occurs by leakage from overlying aquifers, and the discharge is in the north direction towards Delaware River. 1.2-4 HCGS-UFSAR Revision 0 April 11, 1988

The combined Raritan and Magothy aquifer has a maximum thickness of about 475 feet in their outcrop area, which extends from northeast to southwest from Long Island across New Jersey and Delaware into Maryland. Recharge to this aquifer occurs from precipitation in the outcrop area by infiltration from the surface water and by leakage through the overlying or underlying aquicludes from the aquifers above or below. The discharge is in the direction toward the rivers in the outcrop area. Groundwater is used for industrial, sanitary, potable, and fire protection purposes at the site. Three production wells were drilled into the Mount Laurel-Wenonah aquifer for Salem Generating Station. Because of salinity concerns, four additional production wells were drilled into the Raritan-Magothy aquifer, two each for Hope Creek and Salem Generating Stations. Most private wells in this region draw water from Mount Laurel-Wenonah aquifer. 1.2.2 Principal Design Criteria The principal design criteria for the design, construction, and testing of HCGS are presented in two ways. First, they are classified as either a power generation function or a safety function. Second, they are grouped according to system. Although the distinctions between power generation and safety functions are not always clear cut, and sometimes overlap, the functional classification facilitates safety analyses, while the system classification facilitates the understanding of both the system function and design. 1.2.2.1 General Design Criteria 1.2.2.1.1 Power Generation Design Criteria

1. The plant is designed, fabricated, erected, and operated to produce electrical power in a safe and reliable manner. Steam is produced within the nuclear reactor for direct use in the turbine generator unit.

1.2-5 HCGS-UFSAR Revision 0 April 11, 1988

2. Heat removal systems are provided with sufficient capacity and operational adequacy to remove heat generated in the reactor core for the full range of normal operational conditions and abnormal operational transients.

3. Backup heat removal systems are provided to remove decay heat generated in the core under circumstances wherein the normal operational heat removal systems become inoperative. The capacity of such systems is adequate to prevent fuel cladding damage.

4. The fuel cladding, in conjunction with other plant systems, is designed to retain integrity such that any failures shall be within acceptable limits throughout the range of normal operational conditions and abnormal operational transients for the design life of the fuel.

5. Control equipment allows the reactor to respond automatically to load changes and abnormal operational transients.

6. Reactor power level is manually controllable.

7. Control of the reactor is possible from a single location.

8. Reactor controls, including alarms, are arranged to allow the operator to rapidly assess the condition of the reactor system and locate system malfunctions.

9. Interlocks or other automatic equipment are provided as backup to procedural controls to avoid conditions requiring the functioning of nuclear safeguard systems or engineered safety features (ESFs).

10. The station is designed for routine continuous operation whereby steam activation products, fission products, 1.2-6 HCGS-UFSAR Revision 0 April 11, 1988

corrosion products, and coolant dissociation products are processed within acceptable limits. 1.2.2.1.2 Safety Design Criteria

1. The station is designed, fabricated, erected, and operated in such a way that the release of radioactive materials to the environment does not exceed the limits and guideline values of applicable government regulations pertaining to the release of radioactive materials for normal operations and for abnormal transients and accidents.

2. The reactor core is designed so that its nuclear characteristics do not contribute to a divergent power transient.

3. The reactor is designed to preclude divergent oscillation of any operating characteristic, to facilitate normal interaction of the reactor with other appropriate plant systems.

4. Gaseous, liquid, and solid waste disposal facilities are designed so that the discharge of radioactive effluents and offsite shipment of radioactive materials can be made in accordance with applicable regulations.

5. The design provides means by which plant operators are alerted when limits on the release of radioactive material are approached.

6. Sufficient indications are provided to determine whether the reactor is operating within the envelope of conditions considered by plant safety analysis.

7. Radiation shielding is provided and access control patterns are established to allow a properly trained operating staff to control radiation doses within the 1.2-7 HCGS-UFSAR Revision 0 April 11, 1988

limits of applicable regulations in any mode of normal plant operations.

8. Those portions of the nuclear system that form part of the reactor coolant pressure boundary (RCPB) are designed to retain integrity as a radioactive material containment barrier following abnormal operational transients and accidents.

9. Nuclear safety systems and ESFs function to ensure that no damage to the RCPB results from internal pressures caused by abnormal operational transients and accidents.

10. Where positive, precise action is immediately required in response to abnormal operational transients and accidents, such action is automatic and requires no decision or manipulation of controls by plant operations personnel.

11. Essential safety actions are provided by systems of sufficient redundance and independence such that no single failure of active components, or of passive components in certain cases, results in the complete failure of a system. For systems or components to which IEEE 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations and/or IEEE 308-1978, Criteria for Class 1E Electrical Systems for Nuclear Power Generating Stations, applies, single failures of either active or passive electrical components are considered in recognition of the higher anticipated failure rates of passive electrical components relative to passive mechanical components.

12. Provisions are made for control of active components of nuclear safety systems and ESFs from the main control room.

1.2-8 HCGS-UFSAR Revision 0 April 11, 1988

13. Nuclear safety systems and ESFs are designed to permit demonstration of their functional performance requirements.

14. The design of nuclear safety systems and ESFs includes allowances for natural environmental disturbances such as earthquakes, floods, and storms at the station site.

15. Standby electrical power sources have sufficient capacity to power all nuclear safety systems and ESFs requiring electrical power concurrently.

16. Standby electrical power sources are provided to allow prompt reactor shutdown and removal of decay heat under circumstances where normal auxiliary power is not available.

17. The primary containment completely encloses the reactor system, employing the pressure suppression concept.

18. Provisions are made to test the leaktight status and integrity of the primary containment at periodic intervals.

19. A Reactor Building enclosure is provided that completely encloses the primary containment. This building enclosure contains a system for controlling the radioactive materials that may be released from the primary containment.

20. The primary containment and Reactor Building enclosure, in conjunction with other ESFs, limit radiological effects of accidents resulting in the release of radioactive material to the containment volumes to less than the prescribed acceptable limits.

1.2-9 HCGS-UFSAR Revision 0 April 11, 1988

21. Provisions are made for removing energy from the primary containment, as necessary, to maintain the integrity of the containment system following accidents that release energy to the containment.

22. Piping that penetrates the primary containment and could serve as a path for the uncontrolled release of radioactive material to the environs is automatically isolated whenever such uncontrolled radioactive material release is imminent. Such isolation is performed in time to limit radiological effects to less than the specified acceptable limits.

23. Emergency Core Cooling Systems (ECCSs) are provided to limit fuel cladding temperature to less than the limits of 10CFR50.46 in the event of a loss-of-coolant accident (LOCA).

24. The ECCSs provide for continuity of core cooling over the complete range of postulated break sizes in the RCPB.

25. Operation of the ECCSs is initiated automatically when required, regardless of the availability of offsite power supplies and the normal generating system of the station.

26. The main control room and the technical support center are shielded against radiation to allow continued occupancy under accident conditions.

27. In the event that the main control room becomes uninhabitable, it is possible to bring the reactor from power range operation to cold shutdown conditions by using the equipment and local controls that are available outside the main control room.

28. Backup reactor shutdown capability is provided independent of normal reactivity control provisions. This backup 1.2-10 HCGS-UFSAR Revision 0 April 11, 1988

system has the capability to shut down the reactor from any normal operating condition and subsequently to maintain the cold shutdown condition.

29. Fuel handling and storage facilities are designed to prevent inadvertent criticality and to maintain shielding and cooling of spent fuel.

30. Systems that have redundant or backup safety functions are physically separated and arranged such that any credible event causing damage to any one region of the reactor island complex has minimum prospect for compromising the functional capability of the designated counterpart system.

1.2.2.2 System Criteria The principal design criteria for particular systems are listed in the following sections. 1.2.2.2.1 Nuclear System Criteria

1. The fuel cladding is designed to retain integrity as a radioactive material barrier, such that any failures are within acceptable limits throughout the design power range.

2. The fuel cladding, in conjunction with other plant systems, is designed to retain integrity such that any failures are within acceptable limits throughout any abnormal operational transient.

3. Those portions of the nuclear system that form part of the RCPB are designed to retain integrity as a radioactive material barrier during normal operation and following abnormal operational transients and accidents.

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4. Heat removal systems are provided in sufficient capacity and operational adequacy to remove heat generated in the reactor core for the full range of normal operational transients as well as for abnormal operation transients. The capacity of such systems is adequate to prevent fuel cladding damage.

5. Heat removal systems are provided to remove decay heat generated in the core under circumstances wherein the normal operational heat removal systems become inoperative. The capacity of such systems is adequate to prevent fuel cladding damage. The reactor is capable of being shut down automatically in sufficient time to permit decay heat removal systems to become effective following loss of operation of normal heat removal systems.

6. The reactor core and reactivity control systems are designed so that control rod action is capable of bringing the core subcritical and maintaining it in that condition, even with the rod of highest reactivity worth fully withdrawn and unavailable for insertion.

7. The reactor core is designed so that its nuclear characteristics do not contribute to a divergent power transient.

8. The nuclear system is designed to preclude divergent oscillation of any operating characteristic, to facilitate normal interaction of the nuclear system with other appropriate plant systems.

1.2.2.2.2 Power Conversion Systems Criteria The power conversion systems criteria are discussed below. 1.2-12 HCGS-UFSAR Revision 0 April 11, 1988

1.2.2.2.3 Electrical Power Systems Criteria Sufficient normal auxiliary and standby sources of electrical power are provided to attain prompt shutdown and continued maintenance of the station in a safe condition. The power sources are adequate to accomplish all required essential safety actions under postulated design basis accident (DBA) conditions. 1.2.2.2.4 Radwaste System Criteria

1. The gaseous and liquid radwaste systems are designed to limit the release of radioactive effluents from the station to the environs to the lowest practical values. Such releases as may be necessary during normal operations are limited to values that meet the requirements of applicable regulations, including 10CFR20 and 10CFR50.

2. The solid radwaste disposal systems are designed so that in-plant processing and offsite shipments are in accordance with all applicable regulations, including 10 CFR 20, 10CFR71, and 49CFR171 through 179 and Department of Transportation Regulations.

3. The systems' designs provide means by which station operations personnel are alerted whenever specified limits on the release of radioactive material may be approached.

1.2.2.2.5 Auxiliary Systems Criteria

1. Fuel handling and storage facilities are designed to prevent criticality and to maintain adequate shielding and cooling for spent fuel. Provisions are made for maintaining the proper chemistry of spent fuel cooling and shielding water.

2. Other auxiliary systems, such as service water, cooling water, fire protection, heating and ventilating, 1.2-13 HCGS-UFSAR Revision 0 April 11, 1988

communications, and lighting, are designed to function during normal and/or accident conditions.

3. Auxiliary systems that are not required to effect safe shutdown of the reactor, or maintain it in a safe condition, are designed such that a failure of these systems shall not prevent the essential auxiliary systems from performing their design functions.

1.2.2.2.6 Radiation Shielding and Access Control Criteria Where necessary, radiation shielding is provided, and personnel access control patterns are established to allow the plant operating staff to limit radiation exposures to the guideline values of applicable regulations for any mode of normal power operation. Adequate radiation shielding and access control is also provided for abnormal operating conditions such as the release of fission products from failed fuel elements or the contamination of plant areas from system leakage. Certain vital plant areas, such as the main control room and the technical support center, are shielded and provided with suitable environmental controls. 1.2.2.2.7 Nuclear Safety Systems and Engineered Safety Features Criteria Principal design criteria for nuclear safety systems and engineered safety features (ESFs) are as follows:

1. These criteria correspond to criteria 10. through 17.,

24. through 26., 29., and 30. in Section 1.2.2.1.2.

2. In the event that the main control room is uninhabitable, it is possible to bring the reactor from power range operation to a hot shutdown condition by use of equipment and local controls that are available outside the main 1.2-14 HCGS-UFSAR Revision 0 April 11, 1988

control room. Furthermore, station design allows the operator in these circumstances to bring the reactor to a cold shutdown condition from a hot shutdown condition from outside the main control room.

3. Backup reactor shutdown capability is provided by the Standby Liquid Control System (SLCS). The system is independent of normal reactivity control provisions. This backup system has the capability to shutdown the reactor from any operating condition and subsequently to maintain the shutdown condition.

1.2.2.2.8 Process Control Systems Criteria The principal design criteria for the process control systems follows. 1.2.2.2.8.1 Nuclear System Process Control Criteria

1. Control equipment is provided to allow the reactor to respond automatically to main load changes within design limits.

2. Provisions are made for manual control of the reactor power level.

3. Control of the nuclear system is possible from a central location.

4. Nuclear system process controls and alarms are arranged to allow the operator to rapidly assess the condition of the nuclear system and to locate process system malfunctions.

5. Interlocks or other automatic equipment are provided as a backup to procedural controls to avoid conditions requiring the actuation of ESFs.

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1.2.2.2.8.2 Power Conversion Systems Process Control Criteria

1. Control equipment is provided to automatically control the reactor pressure throughout its operating range.

2. The turbine is able to respond automatically to minor changes in load.

3. Control equipment in the feedwater system automatically maintains the water level in the reactor vessel at the optimum level required by steam separators.

4. Control of the power conversion equipment is possible from a central location.

5. Interlocks or other automatic components are provided in addition to procedural controls to avoid conditions requiring the actuation of ESFs.

1.2.2.2.8.3 Electrical Power System Process Control Criteria

1. The Class 1E power systems are designed as an "n" channel system, with any "n-1" channels being adequate to safely shut down the unit.

2. In the event of equipment failure, protective relaying is used to detect and isolate the faulty equipment from the system with a minimum of disturbance.

3. Voltage relays are used on the Class 1E and balance of plant equipment buses to isolate these buses from the normal electrical system, in the event of loss of offsite power (LOP), and to initiate the standby emergency power system diesel generators.

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4. The standby emergency power diesel generators are started and loaded automatically to meet the existing emergency condition.

5. Electrically operated breakers are controllable from the main control room.

6. Monitoring of essential generators, transformers, and circuits is provided in the main control room.

7. Controls are provided to ensure that sufficient electrical power is provided for startup, normal operation, prompt shutdown, and continued maintenance of the plant in a safe condition.

1.2.3 General Arrangement of Structures and Equipment The principal structures at the plant site are as follows:

1. Main power block

a. Reactor Building with refueling floor

b. Main control room area of the auxiliary building

c. Turbine building with turbine generator sets

d. Radwaste area of the Auxiliary Building

e. Service area of the Auxiliary Building

f. Diesel generator area of the Auxiliary Building

2. Circulating water pump structure

3. Cooling tower and water treatment building 1.2-17 HCGS-UFSAR Revision 0 April 11, 1988

4. Sewage treatment plant

5. Service water intake structure

6. Switchyard

7. Administration Building

8. Guardhouse

9. Warehouse area

10. Low-Level Radwaste Storage Facility

11. Independent Spent Fuel Storage Installation (ISFSI)

The arrangement of structures on the site is shown on Plant Drawing C-0001-0. The general arrangement for the major power block structures is shown on Plant Drawings P-0001-0 through P-0007-0 and P-0010-0 through P-0012-0. The equipment arrangement for these structures is shown on the following Plant Drawings: N-1011, P-0012-1 through P-0016-1, P-0031-0 through P-0038-0, P-0042-1 through P-0047-1, P-0051-0 through P-0057-0, P-0072-0, P-0073-0 and P-0076-0. 1.2.4 System Description A summary of the system description for Hope Creek Generating Station (HCGS) is provided below. 1.2.4.1 Nuclear System The nuclear system includes a direct cycle, forced circulation, General Electric (GE) boiling water reactor (BWR) that produces steam for direct use in the steam turbine. A heat balance showing the major parameters of the nuclear system for the rated power conditions is shown on Figures 10.1-1 and 10.1-2. 1.2.4.1.1 Reactor Core and Control Rods The reactor core and control rods are described in Section 1 and Appendix A, Subsection A.1.2.2.3.1 of Reference 1.2-1. 1.2-18 HCGS-UFSAR Revision 20 May 9, 2014

1.2.4.1.2 Reactor Vessel and Internals The reactor vessel contains the core and supporting structures, steam separators and dryers, jet pumps, control rod guide tubes, distribution lines for the feedwater, core sprays, core differential pressure and liquid control lines, in-core instrumentation, and other components. The main connections to the vessel include steam lines, coolant recirculation lines, feedwater lines, control rod drive (CRD) and in-core nuclear instrument housings, core spray lines, core differential pressure line, jet pump pressure sensing lines, water level instrumentation, and CRD system return lines (capped). The reactor vessel is designed and fabricated in accordance with applicable codes for a pressure of 1250 psig. The nominal operating pressure in the steam space above the separators is 1020 psia. The vessel is fabricated of low alloy steel and is clad internally with stainless steel (except for the top head, which is not clad). The reactor core is cooled by demineralized water that enters the lower portion of the core and boils as it flows upward around the fuel rods. The steam leaving the core is dried by steam separators and dryers located in the upper portion of the reactor vessel. The steam is then directed to the turbine through the main steam lines. Each steam line is provided with two automatic containment isolation valves in series; one on each side of the primary containment barrier. 1.2.4.1.3 Reactor Recirculation System The Reactor Recirculation System consists of two recirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reactor vessel jet pumps. Each loop has one motor driven recirculation pump powered and controlled by a dedicated motor generator set located outside the primary containment. Recirculation pump speed can be varied, to 1.2-19 HCGS-UFSAR Revision 0 April 11, 1988

allow some control of reactor power level through the effects of coolant flow rate on the moderator void content. The jet pumps are reactor vessel internals. The jet pumps provide a continuous internal circulation path for the major portion of the core coolant flow. The jet pumps are located in the annular region between the core shroud and the vessel inner wall. Any recirculation line break would still allow core flooding to approximately two-thirds of the core height, the level of the jet pumps' inlet. 1.2.4.1.4 Residual Heat Removal System The Residual Heat Removal (RHR) System is a system of pumps, heat exchangers, and piping that fulfills the following functions:

1. Removes decay and sensible heat during and after plant shutdown

2. Injects water into the reactor system, following a LOCA, to reflood the core independent of other core cooling systems as discussed in Section 1.2.4.2.8.

3. Removes heat from the primary containment, following a LOCA, to limit the increase in primary containment pressure. This is accomplished by cooling and recirculating the suppression pool water (containment cooling) and, if desired, by spraying the drywell and suppression pool air spaces (containment spray) with suppression pool water.

1.2.4.1.5 Reactor Water Cleanup System The Reactor Water Cleanup System (RWCU) recirculates a portion of reactor coolant through a filter demineralizer to remove particulate and dissolved impurities from the reactor coolant. It also removes excess coolant from the reactor system under controlled conditions. 1.2-20 HCGS-UFSAR Revision 0 April 11, 1988

1.2.4.1.6 Nuclear Leak Detection System The nuclear leak detection and monitoring system consists of temperature, pressure, flow, and fission product sensors with associated instrumentation and alarms. This system detects and annunciates leakage in the following systems:

1. Main steam lines

2. RWCU system

3. RHR system

4. Reactor Core Isolation Cooling (RCIC) System

5. Feedwater system

6. Emergency Core Cooling Systems (ECCS)

7. Other miscellaneous systems, such as Safety Auxiliaries Cooling System (SACS) heat exchanger room, reactor building equipment drain sump, etc.

Small leaks generally are detected by monitoring the air coolers' condensate flow inside the drywell, airborne radiation levels, and drain sump fillup and pumpout rates. Large leaks are also detected by changes in reactor water level and changes in flow rates in process lines. 1.2.4.2 Nuclear Safety Systems and Engineered Safety Features 1.2.4.2.1 Reactor Protection System The Reactor Protection System (RPS) initiates a rapid, automatic shutdown (scram) of the reactor. It acts in time to prevent fuel cladding damage and any nuclear system process barrier damage following abnormal operational transients. The RPS overrides all 1.2-21 HCGS-UFSAR Revision 0 April 11, 1988

operator actions and process controls and is based on a fail-safe design that allows appropriate protective action even if a single failure occurs. 1.2.4.2.2 Neutron Monitoring System Those portions of the neutron monitoring system that form part of the RPS qualify as a nuclear safety system. The intermediate range monitors (IRM) and the average power range monitors (APRM), which monitor neutron flux via in-core detectors, provide scram logic inputs to the RPS. Thus, a scram is initiated in time to prevent excessive fuel clad damage as a result of over power transients. The APRM system also generates a simulated thermal power signal. Both Neutron Flux - Upscale and upscale simulated thermal power are conditions that provide scram logic signals. 1.2.4.2.3 Control Rod Drive System When a scram is initiated by the RPS, the CRD system inserts the negative reactivity necessary to shut down the reactor. Each control rod is controlled individually by a hydraulic control unit (HCU). When a scram signal is received, either the high pressure water stored in an accumulator in the HCU or the reactor pressure forces its control rod into the core. 1.2.4.2.4 Control Rod Drive Housing Supports CRD housing supports are located underneath the reactor vessel near the control rod housings. The supports limit the travel of a control rod in the event that a control rod housing is ruptured. 1.2.4.2.5 Control Rod Velocity Limiter A control rod velocity limiter is attached to each control rod to limit the velocity at which a control rod can fall out of the core, in the unlikely event of it becoming detached from its CRD. This 1.2-22 HCGS-UFSAR Revision 23 November 12, 2018

action limits the rate of reactivity insertion resulting from a rod drop accident. The limiters contain no moving parts. 1.2.4.2.6 Nuclear System Pressure Relief System A Pressure Relief System consisting of 14 safety/relief valves mounted on the main steam lines is provided to prevent excessive pressure inside the nuclear system for operational transients or accidents. 1.2.4.2.7 Reactor Core Isolation Cooling System The RCIC system provides makeup water to the reactor vessel when the vessel is isolated. The RCIC system uses a steam driven turbine pump unit and operates automatically, with sufficient coolant flow to maintain adequate water level in the reactor vessel for events defined in Section 5.4.6. 1.2.4.2.8 Emergency Core Cooling Systems In the event of a breach in the RCPB that results in a loss of reactor coolant, four ECCSs are provided to maintain fuel cladding below the temperature limit of 10CFR50.46. The systems are:

1. High pressure coolant injection (HPCI) - The HPCI system provides and maintains an adequate coolant inventory inside the reactor vessel to limit fuel clad temperature that may result from postulated small breaks in the nuclear system process barrier. A high pressure system is needed for small breaks because the reactor vessel depressurizes slowly, preventing low pressure systems from injecting coolant. The HPCI system includes a turbine driven pump powered by reactor steam. The system is designed to accomplish its function on a short term basis without reliance on plant auxiliary power supplies other than the dc power supply.

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2. Automatic Depressurization System (ADS) - The ADS rapidly reduces reactor vessel pressure during a LOCA in which the HPCI system fails to maintain the reactor vessel water level. The depressurization provided by the system enables the low pressure ECCSs to deliver cooling water to the reactor vessel. The ADS uses some of the relief valves that are part of the Nuclear System Pressure Relief System. The automatic relief valves are arranged to open on conditions indicating both a break in the reactor coolant pressure boundary (RCPB) and a failure of the HPCI system to deliver sufficient cooling water to the reactor vessel to maintain the water level above a preselected value. The ADS will not be actuated unless either the core spray or RHR pumps (in the LPCI mode) are operating. This ensures that adequate coolant will be available to maintain reactor water level after depressurization.

3. Core spray - The Core Spray System consists of two independent pump loops that deliver cooling water to spray spargers over the core.

The system is actuated by conditions indicating that a breach exists in the nuclear system process barrier, but water is delivered to the core only after reactor vessel pressure is reduced to below the pump shutoff head. This system provides the capability of cooling the fuel by spraying water onto the core. Either core spray loop, in conjunction with the ADS, or HPCI system by itself, can provide sufficient fuel cladding cooling following a LOCA.

4. Low pressure coolant injection (LPCI) - LPCI is an operating mode of the RHR system, but is discussed here because the LPCI mode acts as an ESF in conjunction with the other ECCSs. LPCI uses the pump loops of the RHR to inject cooling water into the reactor system.

LPCI is actuated by conditions indicating a breach in the RCPB, but water is delivered to the core only after reactor vessel pressure is reduced to below the pump shutoff head. 1.2-24 HCGS-UFSAR Revision 0 April 11, 1988

LPCI operation provides the capability of core reflooding, following a LOCA, in time to maintain the fuel cladding below the prescribed temperature limit. 1.2.4.2.9 Containment 1.2.4.2.9.1 Functional Design The containment system offsets the consequences of a breach of the reactor pressure vessel (RPV) and fuel by limiting the discharge of radioactive products, as prescribed by federal regulations. Primary containment and Reactor Building enclosure barriers have been provided. The former employs the pressure suppression concept. The latter includes a low leakage Reactor Building and a Filtration, Recirculation, and Ventilation System (FRVS). The primary containment is designed to remain intact before, during, and after a design basis accident (DBA). The design employs a pressure suppression primary containment that houses the reactor vessel, the coolant recirculation loops, and other branch connections of the primary system. The pressure suppression chamber (torus) stores a large volume of water and consists of a connecting vent system between the drywell and the pressure suppression pool, and isolation valves. In the event of a process system piping failure within the drywell, reactor water and steam are released into the drywell air space. The resulting increased drywell pressure forces a mixture of air, steam, and water through the vents into the pool of water stored in the suppression chamber. The steam condenses in the suppression pool, resulting in a rapid pressure reduction in the drywell. Air transferred to the suppression pool is subsequently vented through the vacuum breakers to the drywell to equalize the pressure between the two areas. Heat from the reactor core, the drywell, and the torus is removed by the containment cooling systems. Containment 1.2-25 HCGS-UFSAR Revision 0 April 11, 1988

isolation valves ensure that the released radioactive materials are confined to the primary containment. 1.2.4.2.9.2 Heat Removal The Containment Heat Removal System is summarized in Section 1.2.4.2.14. 1.2.4.2.9.3 Containment Spray The Containment Spray System consists of two redundant subsystems, each with its own full capacity spray header. Each subsystem is supplied from a separate redundant RHR subsystem. This system is provided as a means of reducing the containment pressure following a LOCA. 1.2.4.2.9.4 Combustible Gas Control The level of combustible gas in the containment environment during a beyond design basis accident is controlled by two redundant thermal hydrogen recombiners. The recombiner trains are separated into mechanical and electrical divisions. During reactor normal operations, containment purging capability is provided through the Reactor Building Ventilation System (RBVS). 1.2.4.2.10 Containment and Reactor Vessel Isolation Control System The containment and reactor vessel isolation control system automatically initiates closure of isolation valves to close off all process lines that are potential leakage paths for radioactive material to the environs. This action is taken upon indication of a breach in the RCPB. 1.2.4.2.11 Main Steam Isolation Valves Although all pipelines that both penetrate the containment and offer a potential release path for radioactive material are provided with 1.2-26 HCGS-UFSAR Revision 15 October 27, 2006

redundant isolation capabilities, the main steam lines, because of their large size and large mass flow rates, are given special isolation consideration. Automatic isolation valves are provided in each main steam line. Each is powered by both air pressure and spring force. These valves accomplish the following objectives:

1. Prevent excessive damage to the fuel barrier by limiting the loss of reactor coolant from the reactor vessel (as such a loss could derive either from a major leak in the steam piping outside the containment or from a malfunction of the pressure control system, resulting in excessive steam flow from the reactor vessel).

2. Limit the release of radioactive materials from the fuel to the reactor cooling water and steam by isolating the RCPB

3. Limit the release of radioactive materials by closing the containment barrier, in the event of a major leak from the nuclear system inside the containment.

1.2.4.2.12 Main Steam Line Flow Restrictors A venturi type flow restrictor is installed in each steam line. These devices limit the loss of coolant from the reactor vessel before the main steam isolation valves (MSIVs) are closed, in the event of a main steam line break outside the containment. 1.2.4.2.13 Main Steam Line Radiation Monitoring System The main steam line radiation monitoring system consists of four gamma radiation monitors located externally to the main steam lines just outside the containment. The monitors are designed to detect a gross release of fission products from the fuel. 1.2-27 HCGS-UFSAR Revision 7 December 29, 1995

1.2.4.2.14 Residual Heat Removal System (Containment Cooling) The containment cooling subsystem is placed in operation to limit the temperature of water in the suppression pool and of the atmospheres in the drywell and suppression chamber following a design basis LOCA; to control the pool temperature during normal operation of the main steam safety/relief valves (SRVs) and the RCIC system, and to reduce the pool temperature following an isolation transient. In the containment cooling mode of operation, the RHR main system pumps take suction from the suppression pool and pump the water through the RHR heat exchangers where cooling takes place by transferring heat to the SACS, which in turn transfers the heat to the service water system. The fluid is then discharged back to the suppression pool, to the drywell spray header, or to the suppression chamber spray header. 1.2.4.2.15 Ventilation Exhaust Radiation Monitoring System The Process Ventilation Radiation Monitoring System consists of a number of radiation monitors arranged to monitor the activity level of the air exhaust from the Containment and Reactor Building, Auxiliary Building, radwaste area Auxiliary Building laboratories, fuel handling pool, and Turbine Building. 1.2.4.2.16 Filtration, Recirculation, and Ventilation System (FRVS) The FRVS confines, controls, and collects the airborne contamination released to the Reactor Building as a result of any abnormal incident. By mixing and filtering the Reactor Building atmosphere, and by maintaining the Reactor Building under negative pressure with respect to outdoors, the system limits the release of radioactivity. Redundant trains of fans, filters, controls, etc, have been provided along with emergency power to ensure system operation and reliability. 1.2-28 HCGS-UFSAR Revision 0 April 11, 1988

1.2.4.2.17 Power Supply 1.2.4.2.17.1 Standby AC Power Supply The standby ac power supply system consists of four independent diesel generators. Each of the four Class 1E load groups is fed from its own dedicated standby diesel generator (SDG). Each SDG starts automatically upon LOP or LOCA. SDGs are designed to start and be ready to accept load within 10 seconds after receipt of a start signal. Three out of the four SDGs provide adequate capacity to operate all the equipment necessary to prevent undue risk to public health and safety in the event of total LOP or DBAs. No provision is made to parallel any two Class 1E SDGs under any operating conditions. 1.2.4.2.17.2 Non-Class 1E AC Power Supply The non-Class 1E ac systems consist of 7.2 kV and 4.16 kV switchgear, 480 V unit substation switchgear, motor control centers (MCCs), and 120 V panels. These systems supply power to balance of plant equipment. 1.2.4.2.18 DC Power Supply 1.2.4.2.18.1 Class 1E DC Power Supply Systems HCGS is provided with four independent 125 V and two 250 V dc Class 1E channels. Each dc system is supplied from an independent battery and battery chargers. Each 125 V dc bus supplies control power for Class 1E equipment in its own load group. Both 250 V dc systems, one of which is dedicated to the HPCI system and the other to the RCIC system, operate the valves and vacuum pumps in their respective systems. The Class 1E 125 V and 250 V dc systems are designed to supply sufficient power to satisfy the ESF load requirements of a postulated LOP and any concurrent single failure in the dc system. 1.2-29 HCGS-UFSAR Revision 0 April 11, 1988

1.2.4.2.18.2 Non-Class 1E DC Power Supply Systems The station is provided with two +/-24 V, five 125 V, and one 250 V dc power systems. Each dc system is supplied by an independent battery and battery chargers. The 24 V dc systems supply power for the Neutron Monitoring System (NMS). The 125 V dc systems supply control power for non-Class 1E systems and power for some of the equipment important for plant operation. A 250 V dc bus supplies power for auxiliary equipment important for the reactor recirculation motor generator set, the reactor feed pump turbine (RFPT), and the main turbine generator unit. 1.2.4.2.19 Standby Liquid Control System Although not intended to provide prompt reactor shutdown, as are the control rods, the SLC system provides a redundant, independent, and alternate way to bring the nuclear fission reaction to subcriticality and to maintain subcriticality as the reactor cools. The system makes possible an orderly and safe shutdown in the event that the number of control rods inserted into the reactor core is insufficient to accomplish shutdown in the normal manner. The system is sized to counteract the positive reactivity effect from rated power to the cold shutdown condition. 1.2.4.2.20 Safe Shutdown from Outside the Main Control Room In the event that the main control room becomes inaccessible, the reactor can be brought from power range operation to cold shutdown conditions by means of the local controls and components that are available outside the main control room. 1.2.4.2.21 DELETED 1.2-30 HCGS-UFSAR Revision 12 May 3, 2002

1.2.4.3 Power Conversion System 1.2.4.3.1 Turbine Generator The turbine generator consists of the turbine, generator, exciter, controls, and required subsystems designed for a nameplate 1287 MWe plant rating. The turbine is an 1800 rpm, tandem compound, six flow, nonreheat unit with 43-inch last stage buckets and a digital electrohydraulic control system. The main turbine include one double flow high pressure turbine and three double flow low pressure turbines. Exhaust steam from the high pressure turbine passes through moisture separators before entering the three low pressure turbines. The generator is a direct drive, three phase, 60 hertz, 25,000 V, 1800 rpm, with the rotor hydrogen cooled and the stator conductors water cooled, synchronous generator rated on the basis of guaranteed best turbine efficiency megawatt rating at 0.94 power factor and 75 psig hydrogen pressure. The generator exciter system is shaft driven, complete with a static type voltage regulator and associated switchgear. The turbine generator auxiliary systems are as follows:

1. Generator Gas Control System

2. Generator Seal Oil System

3. Turbine Lube Oil System

4. Steam Seal System 1.2-31 HCGS-UFSAR Revision 17 June 23, 2009

5. Generator Stator Cooling System.

1.2.4.3.2 Main Steam System The Main Steam System delivers steam from the Nuclear Boiler System through four 28-inch steam lines to the turbine generator. This system also supplies steam to the steam jet air ejectors (SJAEs), the reactor feed pump turbines (RFPTs), the main condenser hotwell, and the steam seal evaporator. 1.2.4.3.3 Main Condenser The main condenser is a two pass, single pressure, deaerating type. The condenser consists of three shells, each with two tube bundles, two inlet/outlet waterboxes, and two reversing end waterboxes. Each shell is located below one of three low pressure turbines. Rubber expansion joints are provided between each turbine exhaust opening and the steam inlet connections in the condenser shells. During normal operation, steam from the low pressure turbine is exhausted directly downward into the condenser shells through exhaust openings in the bottom of the turbine casings and is condensed. The condenser also serves as a heat sink for several other flows, i.e., exhaust steam from the RFPTs, feedwater heater shell operating vents, and other components in the heat cycle. During abnormal conditions, the condenser is designed to receive one or more streams from turbine bypass steam, feedwater heater high level dump(s), and relief valve discharge from moisture separators, feedwater heater shells, and various steam supply lines. Other flows occur periodically. They originate from condensate pump and reactor feed pump startup vents, reactor feed pump and condensate pump minimum recirculation flows, and feedwater line startup vents; turbine equipment clean drains and low point drains; deaerating steam, makeup, condensate, etc. 1.2-32 HCGS-UFSAR Revision 0 April 11, 1988

1.2.4.3.4 Main Condenser Air Removal The main condenser air removal system removes the noncondensable gases from the main condenser and exhausts them to the off-gas system. Two, 100 percent capacity SJAEs are provided for air removal during normal operation. Two 100 percent capacity motor-driven vacuum pumps are provided for air removal during startup. 1.2.4.3.5 Turbine Gland Seal System The Steam Seal System provides steam to the seals of the turbine valve packings and the turbine shaft packings. The sealing steam is supplied by the seal steam evaporator. An auxiliary boiler provides an auxiliary steam supply for startup and when the seal steam evaporator is not operating. 1.2.4.3.6 Turbine Bypass System and Pressure Control System A Turbine Bypass System is provided that passes steam controlled by a pressure regulator directly to the main condenser. Steam is bypassed to the condenser whenever the reactor steaming rate exceeds the load permitted to pass to the turbine generator. The capacity of the Turbine Bypass System is 21.75 percent of the reactor rated steam flow. The pressure regulation system provides main turbine control valve and bypass valve flow demands so as to maintain a nearly constant reactor pressure during normal plant operation. 1.2.4.3.7 Circulating Water System The Circulating Water System (CWS) is designed to circulate the flow of water required to remove the heat load from the main condenser and other auxiliary equipment and to discharge it to the atmosphere through a natural draft cooling tower. 1.2-33 HCGS-UFSAR Revision 23 November 12, 2018

1.2.4.3.8 Condensate Demineralizer System The function of the condensate demineralizer system is to maintain the required purity of the feedwater flowing to the reactor. The system consists of full flow, deep bed demineralizers using ion exchange resins that remove dissolved and suspended solids from the feedwater to maintain the feedwater purity necessary for the reactor. The demineralizers also remove some of the radioactive material produced by corrosion and fission product carryover from the reactor. The radioactivity from these sources does not have a significant effect on the resins. The condensate pre-filter system is located upstream of the existing deep bed demineralizers to improve iron removal and reduce radwaste. The condensate pre-filter system is described in 1.2.4.3.11. 1.2.4.3.9 Condensate and Feedwater System The condensate and feedwater system is designed to deliver the required feedwater flow to the reactor vessels during stable and transient operating conditions, throughout all modes of operation, including startup to full load to shutdown. The system uses three primary condensate pumps to pump deaerated condensate from the hotwell of the main condenser through the air ejector condenser, the gland steam condenser, and in turn to the condensate demineralizer. The three secondary condensate pumps then pump demineralized feedwater through three parallel strings of feedwater heaters, each string consisting of five heaters, to the suction of three reactor feed pumps that deliver feedwater to the reactor through the sixth feedwater heater. 1.2.4.3.10 Condensate and Refueling Water Storage and Transfer System The function of the Condensate and Refueling Water Storage and Transfer System is to store condensate and employ it to accomplish the following objectives:

1. Supply water for the RCIC and HPCI systems

2. Maintain the required condensate level in the hotwell by supplying condensate to the main condensate system to make up for a deficiency and receive excess condensate rejected from the main condensate system at the secondary condensate pump suction side

3. Fill the reactor well during refueling and receive this water back for storage after it has been cleaned by the demineralizer 1.2-34 HCGS-UFSAR Revision 10 September 30, 1999

4. Provide condensate where required for miscellaneous equipment in the radwaste and Reactor Buildings.

Makeup water to the condensate storage tanks (CSTs) is provided by the demineralized water storage tank. 1.2.4.3.11 Condensate Pre-filter System The function of the Condensate Pre-filter system is to remove insoluble impurities, primarily iron, from the condensate upstream of the deep bed demineralizers. The Condensate Pre-filter System consists of four vessels operated in parallel with a 33% bypass valve. The filter system is designed to operate at 100% condensate flow with a filter flux flow of approximately 0.32 gpm/ft2 with all four filter vessels in service. The Condensate Pre-filter System is designed to remove iron to less than 1ppb. Automatic valves operated by the Condensate Pre-filter control system remove the individual filter vessels from the process stream and backwash the filter media. Backwash water is collected in a header and directed to the Backwash Receiving Tank (BWRT). The BWRT is pumped to the radwaste system. 1.2.4.4 Electrical Systems and Instrumentation and Control Four independent Class 1E 208/120 V ac power systems are provided. Each is dedicated to its own instrumentation channel. Control power supply for Class 1E 4.16-kV and 480 V switchgear is supplied from the corresponding channel 125 V dc system. Starters in the MCCs derive their control power from the control power transformers located in the starter cubicle. 1.2.4.4.1 Electrical Power Systems 1.2.4.4.1.1 Generation and Transmission Systems The main generator is a 1373.1 MVA, 1800 rpm, 0.94 power factor, 25,000 V, three phase, 60 hertz, 0.50 scr, 75 psig hydrogen cooled synchronous machine. The stator is water cooled. The generator is connected directly to the turbine shaft. Excitation is from a shaft driven alternator and stationary rectifier banks. The generator neutral is grounded through a 75-kVA, single phase, 14,400 120/240 V distribution transformer. The main generator unit is connected to the PSE&G 500-kV switchyard through three 1.2-35 HCGS-UFSAR Revision 17 June 23, 2009

single phase 24 500-kV main stepup transformers. The Hope Creek 500-kV switchyard is tied to the Pennsylvania New Jersey Maryland interconnected power network by three physically independent aerial transmission lines. 1.2.4.4.1.2 Electric Power Distribution Offsite AC Systems Power Supply Arrangement of the switchyard provides a reliable and redundant offsite auxiliary power supply. Power from the 500 kV switchyard to a 13.8-kV ring bus is fed through two physically independent paths. The 13.8-kV ring bus feeds both Class 1E and non Class 1E ac and dc power systems. The Class 1E power system supplies all safety related equipment and some non Class 1E loads that are important for plant operation. The non Class 1E power system applies to the balance of plant equipment. The Class 1E ac system consists of four independent load groups. Each load group includes 4.16 kV switchgear, 480 V unit substations, 480 V MCCs, and 120 V control and instrument power panels. The vital ac instrumentation and control power supply systems include dc battery systems and static inverters. 1.2.4.4.2 Nuclear System Process Control and Instrumentation 1.2.4.4.2.1 Reactor Manual Control System The Reactor Manual Control System provides the means by which control rods are positioned from the main control room for power control. The system operates valves in each hydraulic control unit to change control rod position. Only one control rod can be manipulated at a time. The Reactor Manual Control System includes logic that restricts control rod movement (rod block) under certain conditions as a backup to procedural controls. 1.2-36 HCGS-UFSAR Revision 11 November 24, 2000

1.2.4.4.2.2 Recirculation Flow Control System The Recirculation Flow Control System controls the speed of the reactor recirculation pumps. Adjusting the pump speed changes the coolant flow rate through the core. This effects changes in core power level. 1.2.4.4.2.3 Neutron Monitoring System The Neutron Monitoring System (NMS) is a system of in-core neutron detectors and out-of-core electronic monitoring equipment. The system provides indication of neutron flux, which can be correlated to thermal power level for the entire range of flux conditions that can exist in the core. The source range monitors (SRMs) and the intermediate range monitors (IRMs) provide flux level indications during reactor startup and low power operation. The local power range monitors (LPRMs) and average power range monitors (APRMs) allow assessment of local and overall flux conditions during power range operation. The traversing in core probe system (TIP) provides a means to calibrate the individual LPRM sensors. The NMS provides inputs to the reactor manual control system to initiate rod blocks if preset flux limits are exceeded, and inputs to the RPS to initiate a scram if other limits are exceeded. 1.2.4.4.2.4 Refueling Interlocks A system of interlocks that restricts movement of refueling equipment and control rods when the reactor is in the refueling and startup modes is provided to prevent an inadvertent criticality during refueling operations. The interlocks back up procedural controls that have the same objective. The interlocks affect the refueling platform, refueling platform main hoist, fuel grapple, and control rods. 1.2-37 HCGS-UFSAR Revision 13 November 14, 2003

1.2.4.4.2.5 Reactor Vessel Instrumentation In addition to instrumentation for the nuclear safety systems and engineered safety features (ESFs), instrumentation is provided to monitor and transmit information that can be used to assess conditions existing inside the reactor vessel and the physical condition of the vessel itself. This instrumentation monitors reactor vessel pressure, water level, coolant temperature, reactor core differential pressure, coolant flow rates, and reactor vessel head inner seal ring leakage. 1.2.4.4.2.6 Process Computer System An online process computer is provided to monitor and log process variables and to make certain analytical computations. This system is part of the CRIDS System. An off-line computer program, which duplicates the process computer core evaluation functions, may be used in the event the online system is unavailable. 1.2.4.4.3 Power Conversion Systems Process Control and Instrumentation 1.2.4.4.3.1 Pressure Regulator and Turbine Generator Control The digital pressure regulator maintains control of the turbine control and turbine bypass valves to allow proper generator and reactor response to system load demand changes while maintaining the nuclear system pressure essentially constant. The turbine generator speed load control algorithms act to maintain the turbine speed (generator frequency) at a constant rate. 1.2-38 HCGS-UFSAR Revision 19 November 5, 2012

The turbine generator speed load controls can initiate rapid closure of the turbine control valves and rapid opening of the turbine bypass valves to prevent turbine overspeed on loss of the generator electric load or a power/load unbalance event. 1.2.4.4.3.2 Feedwater Control System The Feedwater Control System automatically controls the flow of feedwater into the RPV to maintain the water within the vessel at predetermined levels. A conventional three element flow control system is used to accomplish this function. 1.2.4.5 Fuel Handling and Storage Systems 1.2.4.5.1 New and Spent Fuel Storage New and spent fuel storage racks are designed to prevent inadvertent criticality and load buckling. Sufficient coolant and shielding are maintained to prevent overheating and excessive personnel exposure, respectively. The design of the fuel pool provides for corrosion resistance, adherence to Seismic Category I requirements, and prevention of k from reaching 0.95 under dry or eff flooded conditions. 1.2.4.5.2 Fuel Handling System The fuel handling equipment includes a fuel inspection stand, fuel preparation machine, a bridge crane, a refueling platform, a new fuel transfer basket, a 360 Degree Scorpion II service platform, jib cranes, and other related tools for fuel and reactor servicing. All equipment conforms to applicable codes and standards. 1.2.4.5.3 Independent Spent Fuel Storage Installation (ISFSI) Interim storage of spent fuel is available at the on-site ISFSI, pursuant to satisfying the general license requirements of 10 CFR 72, Subpart K. Details pertaining to the design and operation of the ISFSI, including the design and safety analyses for the spent fuel storage casks, may be found in the site 10 CFR 72.212 evaluation report and the dry spent fuel storage system Certificate of Compliance (CoC) and FSAR. 1.2-39 HCGS-UFSAR Revision 16 May 15, 2008

1.2.4.6 Cooling Water and Auxiliary Systems 1.2.4.6.1 Safety and Turbine Auxiliaries Cooling System The SACS, a portion of the Safety and Turbine Auxiliaries Cooling System (STACS), supplies cooling water to essential reactor components during normal and accident modes of operation. During normal operation, the Turbine Auxiliary Cooling System (TACS), a portion of the STACS, also cools the turbine auxiliary equipment. Heat is transferred from the SACS to the service water system. The system consists of two 100 percent capacity loops with two pumps and two heat exchangers per loop. During normal operation, one loop is in service, and the other loop in automatic standby. Each loop is isolated from the other loop to eliminate the possibility of a single event causing loss of the entire system. 1.2.4.6.2 Reactor Auxiliary Cooling System The Reactor Auxiliary Cooling System (RACS) cools the nonsafety related reactor and radwaste equipment during normal, LOP, and shutdown conditions. The RACS transfers its heat to the service water system. The system consists of two pumps and two heat exchangers. One pump and one heat exchanger are required for plant loads, except for the cooling of the radwaste systems, which requires two pumps and two heat exchangers to operate. 1.2.4.6.3 Fuel Pool Cooling and Cleanup System The Fuel Pool Cooling and Cleanup (FPCC) System is provided to remove decay heat from spent fuel stored in the fuel pool and to maintain specified water temperature, purity, clarity, and level. 1.2-40 HCGS-UFSAR Revision 0 April 11, 1988

The fuel pool filter demineralizer subsystem is also used by the Torus Water Cleanup (TWC) System. 1.2.4.6.4 Station Service Water System The Station Service Water System (SSWS) consists of two redundant trains that provide river water to cool the SACS heat exchangers and the Reactor Auxiliaries Cooling System (RACS) heat exchangers. 1.2.4.6.5 Ultimate Heat Sink (UHS) The ultimate heat sink (UHS) for HCGS engineered safety equipment is the Delaware River. The UHS provides the required cooling water for the startup, normal operation, accident, or shutdown conditions of the reactor. During normal operation, the UHS is designed to dissipate heat by discharging heated water into the circulating water system. This system dissipates this heat and the heat rejected in the main condenser to the atmosphere by a natural draft cooling tower by evaporation, with the overflow going to the Delaware River. During LOCA or LOP conditions, the UHS provides the necessary reliable heat sink for the safeguard equipment. The cooling tower is not essential for the safe shutdown of the plant. 1.2.4.6.6 Raw Water Treatment Plant and Makeup Water Treatment System A Makeup Water Treatment System is provided to furnish a supply of treated water suitable for plant use. 1.2.4.6.7 Potable and Sanitary Wastewater System The Potable and Sanitary Wastewater System provides water for drinking, makeup, and sanitary services. 1.2-41 HCGS-UFSAR Revision 0 April 11, 1988

1.2.4.6.8 Plant Chilled Water System The plant CWS is designed to provide a means of cooling both the fresh air supply and air recirculation to building HVAC systems. 1.2.4.6.9 Process Sampling System The Process Sampling System furnishes process information that is required to monitor plant and equipment performance and changes in operating parameters. Representative liquid and gas samples are taken automatically and/or manually during normal plant operation and under accident conditions for laboratory or online analyses. 1.2.4.6.10 Plant Equipment and Floor Drainage The Plant Equipment and Floor Drainage Systems include both radioactive and nonradioactive drains. Radioactive drains contain potentially radioactive materials and are pumped to the radwaste system for cleanup, reuse, or disposal. Nonradioactive drain materials are treated to remove oil prior to discharge to the Delaware River. The Turbine Building Circulating Water Dewatering Sump may be contaminated with low levels of tritium from certain supply ventilation HVAC drains. 1.2.4.6.11 Service and Instrument Air Systems The Service Air System supplies filtered, oil free, compressed air for plant operation and services. The Instrument Air System supplies filtered, dried, and oil free compressed air for air operated instruments. 1.2-42 HCGS-UFSAR Revision 14 July 26, 2005

The breathing air system supplies filtered, dried, oil free, and purified compressed air for operating and maintenance personnel working in hazardous areas. 1.2.4.6.12 Diesel Generator Fuel Oil Storage and Transfer System The diesel generators are located inside the Auxiliary Building. The fuel oil storage tanks, two per diesel generator, are located below the engines, and each tank has a capacity of 26,500 gallons of oil. It takes 53,000 gallons of oil to run one diesel generator at 4340 kW continuously for 7 days. Each diesel generator unit has its own fuel oil day tank. The tank is mounted above the unit for gravity feed of diesel fuel at startup. This tank's capacity is about 550 gallons. The diesel generator is a self sustaining unit with its own lube oil and fuel oil system. 1.2.4.6.13 Auxiliary Steam System The Auxiliary Steam System consists of three water tube boilers, a deaerator, three boiler feedwater pumps, and associated piping and instrumentation. The system is designed to accommodate varying steam demands during all operating modes. 1.2.4.6.14 Heating, Ventilating, and Air Conditioning (HVAC)/ Environmental Systems The HVAC systems supply and circulate filtered fresh air for personnel comfort and equipment cooling. 1.2.4.6.15 Lighting Systems The Plant Lighting System is designed to provide adequate lighting during all plant operating and maintenance conditions. Illumination levels provided in various areas either conform to or exceed those required in the IES handbook. The Plant Lighting System consists of normal, essential, standby, and standby self contained 8 hour battery pack units. The integrated design of the lighting systems 1.2-43 HCGS-UFSAR Revision 0 April 11, 1988

provides adequate station lighting in all areas required for maintenance of safety related equipment, firefighting, and access routes to and from these areas. 1.2.4.6.16 Fire Protection System A Fire Protection System (FPS) supplies firefighting water to automatic fire suppression systems and hose stations located throughout the plant. A carbon dioxide protection system is provided in addition to portable fire extinguishers in some areas of the plant, such as the diesel generator rooms, diesel fuel tank rooms, and at turbine generators in the Turbine Building, etc. 1.2.4.6.17 Communications Systems The Plant Communication System provides for personnel communication between various locations in buildings and also between various buildings. 1.2.4.7 Radioactive Waste Systems 1.2.4.7.1 Gaseous Radwaste System The purpose of the Gaseous Radwaste System is to process and control the release of gaseous radioactive wastes to the site environs so that the total radiation exposure to persons outside the controlled area does not exceed the maximum limits of the applicable 10CFR regulations, even in the case of defective fuel rods. The off-gases from the main condenser are the major source of gaseous radioactive waste. The treatment of these gases includes volume reduction through a catalytic hydrogen oxygen recombiner; water vapor removal through a condenser; decay of short lived radioisotopes through a holdup line; further condensation and cooling, filtration, adsorption of isotopes on activated charcoal beds; further filtration through high efficiency filters; and final releases. 1.2-44 HCGS-UFSAR Revision 0 April 11, 1988

Continuous radiation monitors are provided that indicate radioactive release from the reactor and from the charcoal adsorbers. The radiation monitors are used to isolate the off-gas system on high radioactivity in order to prevent gas releases of unacceptably high activity. 1.2.4.7.2 Liquid Radwaste System The Liquid Radwaste System collects, treats, stores, and disposes of all radioactive liquid wastes. These wastes are collected in sumps and drain tanks at various locations throughout the plant and then transferred to the appropriate collection tanks in the radwaste building for processing. Processed liquid wastes are returned to the condensate system, transferred to the solid radwaste system for dewatering and packaging for offsite shipment, or discharged from the plant. Equipment is selected, arranged, and shielded to permit operation, inspection, and maintenance within radiation allowances for personnel exposure. Valving redundancy, instrumentation for detection, alarms of abnormal conditions, and procedural controls protect against the accidental discharge of liquid radioactive waste. 1.2.4.7.3 Solid Radwaste System Solid radioactive wastes originating from the Nuclear Steam Supply System (NSSS) equipment are stored for radioactive decay in the fuel storage pool and prepared for reprocessing or offsite storage in approved shipping containers. Examples of these wastes include spent control rods and in core ion chambers. Process solid wastes are collected, dewatered, concentrated, solidified, packaged, and stored in a shielded compartment prior to offsite shipment in approved shipping containers. Examples of these wastes include: filter residue, spent resins, evaporator bottoms, and dry waste. 1.2-45 HCGS-UFSAR Revision 0 April 11, 1988

1.2.4.8 Radiation Monitoring and Control 1.2.4.8.1 Process Radiation Monitoring Process Radiation Monitoring Systems are provided to monitor and control radioactivity in process and effluent streams and to activate appropriate alarms and controls. A Process Radiation Monitoring System is provided to indicate and record radiation levels associated with selected plant process streams and effluent paths leading to the environment. All effluents from the plant that are potentially radioactive are monitored. 1.2.4.8.2 Area Radiation Monitors Area radiation monitoring systems alert plant and main control room personnel of excessive gamma radiation levels at various locations within the plant. 1.2.4.8.3 Site Environs Radiation Monitors Radiation monitors are provided outside the plant structures to monitor radiation levels. The data obtained from these monitors are used to compute the onsite and offsite radiation levels due to the plant operations. 1.2.4.9 Shielding Shielding is provided throughout the plant, as required, to reduce radiation levels to operating personnel and the general public within the applicable limits set forth in 10CFR20 and 10CFR50.67. It is also designed to protect certain plant components from radiation exposures that could result in unacceptable alterations of material properties or activation. 1.2-46 HCGS-UFSAR Revision 17 June 23, 2009

1.2.5 References 1.2.5.1 "General Electric Standard Application for Reactor Fuel", including the "United States Supplement," NEDE 24011-P-A and NEDE 24011-P-A-US (latest approved versions). 1.2-47 HCGS-UFSAR Revision 17 June 23, 2009

Figure F1.2-1 intentionally deleted. Refer to Plant Drawing C-0001-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-2 intentionally deleted. Refer to Plant Drawing P-0001-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-3 intentionally deleted. Refer to Plant Drawing P-0002-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-4 intentionally deleted. Refer to Plant Drawing P-0003-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-5 intentionally deleted. Refer to Plant Drawing P-0004-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-6 intentionally deleted. Refer to Plant Drawing P-0005-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-7 intentionally deleted. Refer to Plant Drawing P-0006-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-8 intentionally deleted. Refer to Plant Drawing P-0007-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-9 intentionally deleted. Refer to Plant Drawing P-0010-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-10 intentionally deleted. Refer to Plant Drawing P-0011-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-11 intentionally deleted. Refer to Plant Drawing P-0012-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-12 intentionally deleted. Refer to Plant Drawing N-1011 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-13 intentionally deleted. Refer to Plant Drawing P-0012-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-14 intentionally deleted. Refer to Plant Drawing P-0013-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-15 intentionally deleted. Refer to Plant Drawing P-0014-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-16 intentionally deleted. Refer to Plant Drawing P-0015-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-17 intentionally deleted. Refer to Plant Drawing P-0016-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-18 intentionally deleted. Refer to Plant Drawing P-0031-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-19 intentionally deleted. Refer to Plant Drawing P-0032-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-20 intentionally deleted. Refer to Plant Drawing P-0033-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-21 intentionally deleted. Refer to Plant Drawing P-0034-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-22 intentionally deleted. Refer to Plant Drawing P-0035-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-23 intentionally deleted. Refer to Plant Drawing P-0036-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-24 intentionally deleted. Refer to Plant Drawing P-0037-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-25 intentionally deleted. Refer to Plant Drawing P-0038-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-26 intentionally deleted. Refer to Plant Drawing P-0014-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-27 intentionally deleted. Refer to Plant Drawing P-0042-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-28 intentionally deleted. Refer to Plant Drawing P-0043-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-29 intentionally deleted. Refer to Plant Drawing P-0044-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-30 intentionally deleted. Refer to Plant Drawing P-0045-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-31 intentionally deleted. Refer to Plant Drawing P-0046-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-32, intentionally deleted. Refer to Plant Drawing P-0047-1 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-33 intentionally deleted. Refer to Plant Drawing P-0051-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-34 intentionally deleted. Refer to Plant Drawing P-0052-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-35 intentionally deleted. Refer to Plant Drawing P-0053-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-36 intentionally deleted. Refer to Plant Drawing P-0054-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-37 intentionally deleted. Refer to Plant Drawing P-0055-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-38 intentionally deleted. Refer to Plant Drawing P-0056-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-39 intentionally deleted. Refer to Plant Drawing P-0057-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-40 intentionally deleted. Refer to Plant Drawing P-0071-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-41 intentionally deleted. Refer to Plant Drawing P-0072-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-42 intentionally deleted. Refer to Plant Drawing P-0073-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

Figure F1.2-43 intentionally deleted. Refer to Plant Drawing P-0076-0 in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

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PLANT UNITNO.1 KEY PLAN REVISION 0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION PLANTAREADESIGNATIONS UPDATEDFSAR FIGURE1.244

1.3 COMPARISON TABLES

1.3.1 Comparisons with Similar Facility Designs This section highlights the principal design features of the plant and compares its major features with those of other boiling water reactor (BWR) facilities. The design of this facility is based on proven technology obtained during the development, design, construction, and operation of BWR.s of similar types. The data, performance characteristics, and other information presented here represent a current, firm design.

The following tables summarize the plant design characteristics of the Hope Creek Generating Station (HCGS), the Hatch Nuclear Plant, the Limerick Generating Station, and the Susquehanna Steam Electric Station: Table No. System

1.3-1 1.3-2 Comparison of Nuclear Steam Supply System Design Characteristics Comparison of Power Conversion System Design Characteristics 1.3-3 Comparison of Engineered Safety Features and Auxiliary Systems Design Characteristics 1.3-4 Comparison of Containment Design Characteristics 1.3-5 Radioactive Waste Managerment Systems Design Characteristics 1.3-6 Comparison of Structural Design Characteristics 1.3-7 Comparison of Instrumentation and Electrical Systems Design Classifications 1.3.2 Comparison of Final and Preliminary Information (FSAR)

All of the significant changes that have been made in the facility design since submission of the PSAR are listed in Table 1.3-8. Each item in Table 1.3-8 is cross-referenced to the appropriate portion 1.3-1 HCGS-UFSAR Revision 0 April 11, 1988

of the FSAR that describes the changes. and the bases for them. 1.3.3 References 1.3-1 "General Electric Standard Application for Reactor Fuel," including I the "United States Supplement," NEDE-24011-P-A and NEDE-24011-P-A-US, current revisions. 1.3-2 HCGS-UFSAR Revision 17 June 23, 2009

I TABLE 1. 3-1 (Historical Infor.mation) (1) COMPARISON OF NUCLEAR STEAM SUPPLY SYSTEM DESIGN CHARACTERISTICS Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 Thermal and Hydraulic Design (Section 4.4) Rated power, MWt 3293 2436 3293 3293 Design power, MWt (ECCS design basis) 3430 2550 3435 3439 Steam flow rate, lb/h 14.159 E6 10.03 E6 14.156 E6 13.48 E6 Core coolant flow rate, lb/h 100.0 E6 78.5 E6 100.0 E6 100.0 E6 Feedwater flow rate, lb/h 14.127 E6 10.445 E6 14.117 E6 13.574 E6 System pressure, nominal in steam dome, psia 1020 1020 1020 1020 Average power density, kW/liter 48.7 51.2 48.7 48.7 Minimum critical power ratio 1.20 (4) 1.24 1.23 Coolant enthalpy at core inlet, Btu/lb 526.1 526.2 526.1 521.8 Core maximum exit voids within assemblies 77.1 79 77.1 76.00 Core average exit quality, % steam 14.1 12.7 14.1 13.2 Feedwater temperature, °F 419.9 387.4 420 383 Design Power Peaking Factor (Section 4. 4 J Maximum relative assembly power 1.40 1.40 1.40 1.40 Local peaking factor 1.15 1.24 14} 1.15 Axial peaking factor 1.4 1.5 1.4 1.40 Total peaking factor 2.51 2.6 (4) 2.51 1 of 5 HCGS-UFSAR Revision 12 May 3, 2002

I TABLE 1.3-1 {Cant) (Historical Infor.mation) Hope Creek Hatch 1 Limerick: Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 Nuclear Design (First Corel {Section 4.3} Reactivity with strongest control <0.99 <0.99 <0.99 <0.99 rod out, k eff Initial cycle exposure, MWD/short ton 8100 9413 9600 9600 Core Mechanical Design (Sections 4.2 and 4.6) Fuel Assembly (Table A.1.3-1 of Reference 1.3-lJ Reactor Control System Method of variation of reactor power Movable control Movable control Movable control Movable control rods and variable rods and variable rods and variable rods and variable forced coolant forced coolant forced coolant forced coolant flow flow flow flow Number of movable control rods 185 137 185 185 Shape of movable control rods Cruciform Cruciform Cruciform Cruciform Pitch of movable control rods 12.0 12.0 12.0 12.0 Control material in movable rods Boron carbide B C granules B C granules B C granules 4 4 4 {8 C) granules compacted in ss compacted in ss compacted in ss 4 compacted in tubes tubes tubes stainless steel {ss} tubes Type of CRDs Bottom entry Bottom entry Bottom entry Bottom entry locking piston locking piston locking piston locking piston Type of temporary reactivity Burnable poison; Burnable poison; Burnable poison; Burnable poison; control for initial core gadolinia-urania gadolinia-urania gadolinia-urania gadolinia-urania fuel rods fuel rods fuel rods fuel rods 2 of 5 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 1.3-1 (Conti (Historical Infor.mation) Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 In-core Neutron Instrumentation Total number of (LPRM) detectors 172 124 112 172 Number of in-core LPRM penetrations 43 31 43 43 Number of LPRM detectors per penetration 4 4 Number of SRM penetrations 4 4 4 4 Number of IRM penetrations a 8 8 8 Total nuclear instrument penetrations 55 43 55 55 SRMs Range - shutdown through criticality {3) {31 13) (3) 4 4 4 4 IRMs Range - prior to criticality to low power (3) {3} (3) 8 8 8 8 Power range monitors Range approximately 1\ power 125% power LPRMs 172 124 172 (3) (3) (3) APRMs 6 6 6 6 Number and type of in-core neutron 7 Sb-Be 5 Sb-Be 1 Sb-Be 7 Sb-Be sources Material Low-alloy steel/ Carbon steel/ Carbon steel/ Carbon steel/ stainless clad stainless clad stainless clad stainless clad Design pressure, psig 1250 1250 1250 1250 Design temperature, °F 575 575 575 575 Inside diameter, ft-in. 20-11 18-2 20-11 20-11 Inside height, ft-in. 72-6.5 69-4 72-1 72-11 3 of 5 Revision 12 May 3, 2002

I TABLE 1.3-1 {Cont) (Historical Xnfor.mation) Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 Minimum base metal thickness (cylindrical 6.102 5.53 6.187 6.19 section), in. Minimum cladding thickness, in. 13/64 l/8 1/8 1/8 Number of recirculation loops 2 2 2 Design pressure Inlet leg, psig 1250 1148 1250 1250 Outlet leg, psig 1500 1274 1500 1500 Design temperature, °F 575 562 575 575 Pipe diameter, in. 28 28 28 28 Pipe material, ANSI 304 304/316 316 304/316 Recirculation pump flow rate, gpm 45,200 42,200 45, 45, Number of jet pumps in reactor 20

5. 4)

Number of steamlines 4 4 Design pressure, psig 1250 1146 1250 1250 Design temperature, °F 575 563 575 575 Pipe diameter, in. 26 24 26 26 Pipe material Carbon steel Carbon steel Carbon steel Carbon steel 4 of HCGS-Uf'SAR Revision 12 May 3, 2002

TABLE 1.3-1 (Cant} (Historical Infor.mation) (1) Parameters are related to rated power output for a single plant unless otherwise noted. (2) Free-standing loaded tubes. {3) Channels of monitors from detectors. (4) Information not available. 5 of 5 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 1.3-2 (Historical Infor.mation) COMPARISON OF POWER CONVERSION SYSTEM DESIGN CHARACTERISTICS Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 Turbine-Generator (Section 10.2) Rated power, MWe (gross) 1117.5 813.5 1136 1085 Generator speed, rpm 1800 1800 1800 1800 Rated steam flow, lb/h 14.159 E6 10.46 E6 14.85 E6 13.4 E6 Inlet pressure, psig 965 950 950 965 Steam Bypass System (Section 10.4.41 Capacity, percent design steam flow 25 25 25 25 Main Condenser (Section 10.4 .1) Heat removal capacity, Btu/h 7726 E6 5720 E6 7800 E6 7890 E6 Circulating Water System (Section 10.4.7) Number of pumps 4 2 4 Flow rate, gpm/pump 138,000 185,000 113,000 112,000 Condensate and Feedwater System (Section 10.4.7) Design flow rate, lb/h 14.82 E6 10.096 E6 14.885 E6 13.44 E6 Number of condensate pumps 3 3 3 Number of condensate booster pumps 3 3 None None Number of feedwater pumps 3 2 3 3 Number of feedwater booster pumps None None None None Condensate pump drive ac power ac power ac power ac power 1 of 2 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 1.3-2 (Cont) (Historical Information) Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 216-560 251-764 251-764 Condensate booster pump drive ac power ac power NA NA Feedwater pump drive Turbine Turbine Turbine Turbine 2 of 2 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 1.3-3 COMPARISON OF ENGINEERED SAFETY FEATURES AND AUXILIARY SYSTEMS DESIGN CHARACTERISTICS Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 Emergency Core Cooling Systems (Systems sized on design power! (Section 6.3} LPCS Systems Number of loops 2 2 2 2 Flow rate, gpm (per loop) HPCI System Number of loops 6150 at 105 psid 1 4725 at 113 psid 1 6350 at 105 psid 1 6350 at 105 psid 1 I Flow rate, gpm 5600 4250 5600 min 5000 at 1172-165 psia ADS Number of relief valves 5 1 5 6 (1) LPCI Number of loops 4 2 2 Number of pumps 4 Flow rate, gpm/pump 10,000 at 20 psid 9200 at 20 psid 10,000 at 20 psid 10,650 at 20 psid Auxiliary Systems (Sections 5.4 and 9.1) RHR System Reactor Shutdown Cooling Mode: Number of loops 2 2 2 2 Number of pumps 2 2 2 {2) Flow rate, gpm/pump 10,000 7,700 10,000 10,000 1 of 2 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 1.3-3 (Cont) Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 Duty, Btu/h/heat exchanger ( 3 ) 41.6 E6 32. E6 41.6 K6 44 B6 Ntnber of heat exchangers 2 2 2 2 Primarycontainment cooling mcxle: Flow rate, gpa/beat exchanger 10,000 11,550 10,000 10,000 Standby Service Water System Flow rate, I}D/heat exchanger 16,500 8000 12,000 9000 Nunber of JUIIPB 4 4 3 2 RCIC System Flow rate, gpa 600 at 150-1120 400 at 150-1120 625 at 1120 600 at 1172-165 peid psid psid psia ~System Capacity, Btu/h 12 K6 8.5 B6 11.25 B6 13.2 B6 (1) A mode of the RHR systea. (2) Capacity during reactor flO<Xling mode wit:.b more than one ptup n.uming. (3) Heat exchanger duty at 20 hours following reactor shutdown. 2 of Z Revision 0 April 11, 1988

TABLE 1.3-4 CXMPARIBrn OF m:I'AINMBNT DESIGN CHARACrBRISTICS Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 PrimarYContainment ( 1 ) (Section 6.2.1) MKI t£1 t<< II MK II Pressure sup- Pressure sup- pressure Over and under pression pression suppression pressure sup-pression Constl'l.¥Jtion Concrete with Concrete with Concrete with ~tewith free standing free standing steel liner steel liner steel vessel steel vessel Drywell Light bulb/ Light bulb/ Frust\ID of cone, Frust\ID of cone, steel vessel steel vessel upper portion upper portion Pressure-suppression chamber Torus/ Torus/steel vessel Cylirdrical Cylirdrical steel vessel lower portion lower portion Pressure-suppression chamber internal 62 56 55 53 design pressure, psig Pressure-suppression chamber external 3 2 5 5 design pressure, psi Drywell internal design pressure, psig 62 56 55 53 Drywell external design pressure, psi 3 2 5 5 3 Drywell free voltllle, ft 169,000 146,010 243,580 239,600 3 Pressure-suppression chamber free volliDe, ft 133,500 112,900 147,670 148,590 (high water level) (high water level) (high Water level) (high water level) 159,540 (lor.r 159, 130 (low level) water level) 3 Pressure-suppression pool water vol\.IDe, ft 122,000 85,112 (min) 134,600 (max) 131,550 (max) (high water level) 122,120 (llin) 122,410 (min) Sul:mergence of vent pipe below pressure 3.33 3.67 12-1/4 11 pool surface, ft (high water level) (high water level) (high water level) (normal water level) 10 (low water level) 1 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 1. 3-4 ( Cont) Hope Creek Batch 1 Limerick SUsquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 Design temperature of drywell, °F 340 281 340 340 Design ~rature of pressure-suppression 310 281 220 220 chamber, F Downcomer vent pressure loss factor 5.51 6.18 2.18 2.5 Break area/total vent area 0.0173 0.0194 0.0159 0.016 Calculated maxi..mun pressure after blowdown 48.1 46.5 44 44 to drywell, psig Calculated maximlm pressure-suppression 27.5 28 30.6 29 chamber pressureafter 1..CCA blosd.own, psig Initial pressure-suppression pool temperature 41 50 43 40 rise during u:x::A bl~, °F Leakage rate, percent free vol\llle/day 0.5 at 62 psig 1.2 at 59 psig 0.5 0.5 Secondary Containment (Section 6.2.3) Type Controlled leak- Controlled leak- Controlled leak- Controlled leak-age, elevated age, elevated age, roof age, elevated release release level release release Construction Lower levels Reinforced Reinforced Reinforced Reinforced concrete concrete concrete concrete Upper levels Reinforced Steel super- Reinforced Steel super-concrete structure and concrete super- structure and precast concrete structure and siding panels siding Roof Reinforced Steel sheeting Reinforced Steel decking concrete dane and reinforced concrete with steel liner concrete slabs Internal design pressure, psig 1.00 0.25 0.25 0.25 2 of 3 HOOS-UFSAR Revision 0 April 11, 1988

TABLE 1.3-4 {Cont) Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 I 251-764 218-560 251-764 251-764 Design inleakage rate, percent free 100 100 50/100 100 volume/day at 0.25 inwc (nom.) {l) Where applicable, containment parameters are based on design power. 3 of 3 HCGS-UFSAR Revision 13 November 14, 2003

TABLE 1.3-5 RADIOACI'IVE WASTH MA.NAGFMFm'SYSTEH3 DF.SIGN CHARACI'ERISTICS Hope Creek Limerick Susquehanna Hatch1 BWR 4/5 BWR 4/5 BWR 4 BWR 4 251-764 251-764 251-764 218-560 Gaseous Radwaste (Section 11.3) Design bases noble gases 500,000 100,000 100,000 100,000 annual average annual average Ci/s at 30 min at 30 min at 30 min at 30 min Process treatment Recombiner ambient Recombiner and Ambient charcoal Reccobiner ambient charcoal ambient charcoal charcoal delay Ntmber of beds 10 5 12 Design condenser inleakage, 75 75 30 40 cfm Release point-height above 217 197 201 394 ground,ft Liquid Radwaste (Section 11. 2) Treatment of:

1. Floor drains(!) F,D,R,OC F,D,R F,D,R F,D,R

2. Equipnent drains(!) F,D,R F,D,R F,D,R F,D,R 1

3. Chemical drains { ) Regenerative wastes E,D, concentrates B, concentrates to F, DC, E, solid to neutralized E, to solid radwaste, solid radwaste, radwaste distillate R, and distillater R distillate R concentrates to solid radwaste to solid radwa.ste Mise chemical decon wastes - neutralized B and vapor discharged.

Concentrates to solid radwaste 1 of 4 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 1.3-5 (Cont) Limerick Susquehanna Hatch 1 BWR 4/5 BWR 4 BWR 4 251-764 251-764 218-560

4. Laundry drains F, DC F, D Diluted and sent to Diluted and sent to circulating water circulating water discharge discharge

5. Expected annual avg 1900 (3) [3) 2000 release, pCi (excluding tritium)

Other Design Information (Section 11.4) Wet solid waste processing and decay Storage and decay Storage and decay Storage and separators. in phase separators. in phase separators. in phase in cen- Dewatered in cen- Dewatered in dewatering Dewatering cen-trifuge. then filters then solidified Dewatering solids to E/E. with cement with cement in materials with asphalt or UF in 55-gallon 55-gallon drums with cement drums drums or UF in 55-gallon solidified with I drums Concentrated liquid waste Crystallizer bottoms Solidified with UF Solidified with cement Solidified with cement processing to EE. Solidify with in 55-gallon drums in 55-gallon drums or UF in 55-gallon asphalt in 55-gallon drums drums Dry solid waste processing Packaged with hydrau- Packaged with hydrau- Packaged with hydrau- Packaged with hydrau-lie press in wooden, lie press in drums lie press in boxes or lie press in drums steel-lined boxes drums Off-gas systems (Section 11.3) (3) Noble gas release rate 100,000 100, 000 100,000 after 30 min. delay, ~tCi/s (max. expected) 500,000 {design basis) Air flow r'lte (scfm) (3) Normal 25 75 30 (2) (2) (3) Maximum 75 300 300 (3) Diluting gas Steam Steam Steam (3) Recoooiner catalyst base Ceramic bas*e Metal base Ceramic base Abandoned In Place 2 of 4 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 1.3-5 (Cont) Hope Creek Limerick SUsquehanna Hatch1 BWR 4/5 BWR 4/5 BWR 4 BWR 4 251-764 251-764 251-764 218-560 (3) Minimtan holdup time prior 10 6.3 9.6 to the charcoal delay, min. (3) Mass *of charcoal in guard 200 687 1280 bed, lbs (3) Delay system Ambient charcoal Ambient charcoal Ambient charcoal (3) Number of charcoal 10 7(Unit 1) 5 beds/lDlit 9{Unit 2) (3) r-hss of charcoal, 322,000 321,000 152,000 lb/unit (3) Xe adsorption 733 733 420 coefficient, cc/g (3) Temperature/dew 65/40 65/40 65/40 point, °F (3) Xe delay time, days 35 35 23 Collection (Section 11.2) 4 subsystems 3 subsystems (3) 5 subsystems 2-32,000 gal. 25,000 gal. (3) Equipnent drain Combine w/floor 2-182 gpn 280 gpo (3) Floor drain 2-17,000 gal. 21,000 gal. 3-22,200 gaL 2-176 gpn 280 gpo 280 gpu (3) Chemical waste 4500 gal. 7500 gal. 11,850 gaL 176 gpu 200 gpu 20 pgiD Detergent drain collect 2000 gal. (3) 2-1000 gal. 2-820 gal. 2-25 gpo 2-25 gpn 25 pgiD Radwaste demineralizer 3 3 3 (3) Agent 1-190 ft mixed bed 2-85 rt Podex 140 ft mixed bed resin regenerable nonregenerable resin nonregenerable 3 of 4 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 1.3-5 (Cant) Hope Creek Limerick Susquehanna Hatch 1 BWR 4/5 BWR 4/5 BWR 4 BWR 4 251-764 251-764 251-764 218-560 (3) Flow rate 180 gpm 280 gpm 200 gpm (3) Filter 2-precoat type 2-precoat type 2-centrifugal 180 gpm 280 gpm 200 gpm (3) Laundry filters 25 pairs-cartridge- 1-cartridge-type 2-cartridge-type type 25 gpm - can be 25 gpm - can be 25 gpm - can be concentrated by concentrated by concentrated by decon evaporator waste evaporator waste evaporator via directly feed tank chemical waste tank I (3) Evaporator waste ** 2-forced circulation 2-forced circulation 2-forced circulation 40 gpm - Distillate 20 gpm - Distillate 15-30 gpm - Distillate 40 gpm - Distillate 20 gpm - Distillate 15-30 gpm - Distillate returned to waste returned to waste returned to waste collection tank collection tank collection tank (3} Decon evaporator Natural circulation Uses waste evaporator Uses waste evaporator 3 gpm - distillate to H&V vent stack (1) Legend D - demineralized F

filtered E
evaporator/concentrator R
recycled, i.e., returned to condensate storage DC
discharged E/B
extruder-evaporator UF
urea formaldehyde (2) Based on startup condition.

(3) Not available. Abandoned In Place I 4 of 4 HCGS-UFSAR Revision 11 November 24, 2000

TABLE 1.3-6 ro1PARISCIN OF S"1'mJCruRAL DESIGN CIIARACIHUSTICS Rope Creek Hatch1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 Seismic Desim (Section 3.7) OBB Horizontal, g 0.10 0.08 0.075 0.05 Vertical, g 0.10 0.05 0.05 0.033 SSE Horizontal, g 0.20 0.15 0.15 0.10 Vertical, g 0.20 0.10 0.10 0.067 Wind DesiJln (Section 3.3) Maximum sustained, wird speed, mph 108 105 90 80 Tol1l8dos (Section 3.3) Translational speed, aq:il 70 60 60 60 Tangential speed, og:tt 290 300 300 300 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 1.3-7

                                   <X11PARI~ OF INSTRlMBNTATION AND ELECTRICAL SYSTEMS DESIGN CHARACI'BRISTIC:S Hope Creek           Hatch1            Limerick         SUsqueharma BWR 4/5             BWR 4            BWR 4/5             BWR 4 251-764            218-560           251-764             251-764 Transmission Sygtem (Section 8.2)

Outgoing lines, m.lllber - rating 2 - 500-kV 5- 230-kV 3-500-kV 1-230-kV 2-23Q-kV {Unit 1) 1-500-kV {Unit 2) Normal Auxili~ AC Power (Section 8.2 and 8.3) Incoming lines, mmber - rating 2- 500-kV and 5 - 230-kV 3-500-kV 2-230-kV 500-kV connection 2-230-kV (Connon to both to Salem switch- tmits) yard Station power transformer 4 2 2 1 (Unit 1) 1 (Unit 2) Station service transformer 8 NA NA NA Startup transformer No separate 2 2 2 startup trans- ( Counon to both formers tmits) Stand~ AC Power S!!l!(!l;t: (Section 8.3) Nunber of standby diesel generators 4 3 8 4 ( Coomon to both tmits) Nunber of 4160 V shutdown buses 4 3 8 4 per tmit NUDberof 480 V shutdown buses 8 load centers 4 600 v 8 4 load centers and (ClasslE) 8 rt:X.:sper \Dli t; 16 ~ (Class 1E} 8 foiXs COIIIDOD to both \Dlits 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 1.3-7 (Cont) Hope Creek Hatch 1 Limerick Susquehanna BWR 4/5 BWR 4 BWR 4/5 BWR 4 251-764 218-560 251-764 251-764 DC Power Supply (Section 8.3) Nunber of 125 V batteries 16 2 4 4 per tmit (6 are Class lE) 6 125/250 v (10 are non-Class lE) Nunber of 250 V batteries 3 2 2 2 per mit (2 are Class lE) (1 is non-class lE) Number of 125 V buses 12 2 24 4 per tmit ( 6 are Class lE) (6 are non-Class lE) Number of 250 V buses 3 2 12 2 load centers and ( 2 are Class lE) 3 foiXs per mit (1 is non-Class lE) 2 of 2 HCGS-UFSAR Revision 0 April 11, 1988

(

( ( TABLE 1.3-8 SIGNIFICANT DESIGN CHANGHS FlD'I PSAR TO FSAR{ 1 ) FSAR Section in Which Item Change Reason for auuwe Subiect is Discussed General building layout Core standby cooling systems 'ftlis change was ll8deto achieve 1.2 changes were relocated outside the necessary separation and space previously eylirdrical walls for CJa3 equipaent. in the lower Reactor Building elevations. 'Ibis has resulted in a rect.anaular base for the lower portion of the Reactor Building. Unit2 Unit2 has beendeleted, 'ftlis change was made because 1 .. 2.3, 3.8 .. 4.1.4 causing the following chanaes of the decreasing proJected in the plantlayout: load growth .. a) 'lbeUnit2 Turbine Building area is now used as a laydownarea for Urit 1 during maintenance b) 'lbe Unit2 Reactor Building has been abmdoned c) 'ftle Unit2 cooling tower has not been hrl.l t d) The Unit2 portion of the service 1-eter intake structure has been built but the Unit2 bay equipaent has been deleted e) Changesto the 5()()-kV swi tchyardi.ool\de reducing the nl.IDber of breakers to five. Mark I containment program 'lbe containment is designed 'ftlis pro&ram is in accordance 3.8.2 for hydrodynamic loads for a with current criteria. Mark I containment. A plant tvri.queanalysis report has been sul:Ditted under separate cover (letter fraa R.L. Mittl, PSBIG, to A.. Schwencer, NRC, dated February 10, 1984. 1 of 8 HOOS-UFSAR Revision 0 April 11, 1988

f

( ( TABLE 1.3-8 (Cont) FSAR Section in Which I tea <llange Reason for OJanle Sub.iect is Discussed Design of Reactor Replaced roof, wioo, and tornado This new list of design loadings 3.8.4 Building loadings witha ccmplete list conforms to ~ SRP 3. 8. 4. of design loadings to be used. CRD system The return line on the control 'Ibis change was made in order 3. 9. 4 rod drive systemhas been to prevent intenrranular stress capped. corrosion cracking on the return line vessel nozzle. Environmental 'lbe Hope Creek environaental 'Ibis programis in agreement with 3 .11 qualification qualification ~ for current ~ guidelines. safety-related equipaent is in accordance witb NURBG-0588 guidelines. Post-LCCAresponse of Max:ia.apost-l.Cn\ temperature Greater Reactor Buil.ding heat 3 .11 .. 1 and 6. 8.1 Reactor Building at:a:>s- was obanged frml 120 to 148'7. loads, plus the use of closed P.ere loop water for cooling, result in higher est!.ated post-I.O:A building te.peratures. A t.e.perature of 148~ does not exceedthe qualification li.mits for safet7-related equi~t in theReactor Building. Nuclear fuel 'lbe arrangement of fuel rods in This change increases 4. 3 each fuel hurdle was changed safety ma.rgins and enhances fraa 7 by 7 to 8 by 8. fuel performance. Vibration and loose parts Insti'\IIIelltation for IIIOili. toring 'lhis provides early detection 4. 4.6 monitoring for vibration or for the of equipaent anomalies. presenceof loose partsin the Reactor Coolant System has been added. Reactor recirculation Delete the 4-inch bypassline Several operating BWRs have 5. 4. 1 system description aroundeach recirculation pap experienced cracks in this line. discharge gate valve. Add a Its removal llli.nimizes throttling circuit to the the p:>tential for cracking recirculation p.np discharge and improvesplant availability. gate valve' a motor control. 2 of 8 HCGS-UF'SAR Revision 0 April 11, 1988

TABLE 1.3-8 (Cant) FSAR Section in Which Item Change Reason for Change Subject is Discussed Main steam line header The s~z~ng of the header between This change facilitates testing 10.3 the main steam lines has not of the MSIVs. been reduced to provide reduction in the blowdown mass loss following a main steam line break. RHR system PSAR Section 15.9.4 gives three Only alternatives 2 & 3 listed in 5.4.7 alternatives for maintaining the PSAR section are used. high quality water in the torus. Suppression pool water and the RHR system are not treated with corrosion inhibitor. Reactor isolation PSAR Section 4.8.8 describes the The possibility of discharging RHR steam condensing mode. This steam to the suppression pool mode of operation has been could have resulted in additional removed from the HCGS design. hydrodynamic loading on the suppression chamber. Main steam line tunnel Pressure relief of the main Plant vents have been incor- 3.6.1 steam tunnel is also provided porated in the main steam through plant vents. tunnel design to augment the pressure relief of the tunnel. Post-LOCA response of The estimate of post-LOCA heat This reflects present estimates 6.2.3 Reactor Building atmos- load changed from 1.8 million of building heat loads. phere to 5 million Btu/h. Reactor Building Pressure relief was changed from This permits direct venting of 3.6, 6.2.3, and 15.6 pressure relief 2 psig to 1 psig. This includes steam from a pipe break pressure relief from the main outside primary containment, which steam line tunnel. limits the exposure of safety-related equipment to a steam environment. Dose consequences I of direct steam venting are within 10CFR50.67 guidelines. Containment inerting The primary containment is This change is in compliance with 6.2.5 inerted during plant operation. current NRC requirements. 3 of 8 Revision 12 May 3, 2002

TABLE 1.3-8 (Cont} FSAR Section in Which Item Change Reason for Change Subject is Discussed HPCI system Instead of injecting 5600 gpm This change deletes the require- 6.3 through the core spray sparger, ments for a selective ATWS runback 2600 gpm is diverted to the circuit. feedwater sparger. Nuclear system pressure The PSAR states that there are This is a more efficient design. 6.3 relief system eleven relief valves and four safety valves mounted on the main steam lines. The pressure relief system has fourteen safety/relief valves instead. Preoperational test A full flow functional test is The only HPCI return line to 6.3.2 program - HPCI system performed to and from the con- the suppression pool is the densate storage tank only and minimum bypass line. This is not alternated with the does not provide sufficient suppression pool. capacity for a full flow functional test. REVS The Reactor Building ventilation Results of calculations of 6.4 exhaust is set to establish the reactor building post-a negative building pressure LOCA response show this to during normal operation by be an acceptable design. modulating exhaust fan damper position. I Reactor Building Changed the number of FRVS This change was made to meet the 6.8 FRVS recirculation units from three requirements of Regulatory Guide 50 percent to six 25 percent 1.52, i.e., the volumetric air flow units. rate of a single cleanup train should be limited to approxi-mately 30,000 cfm. Since the total recirculation flow is 120,000 cfm, having three 50 percent units (60,000 cfm each) would exceed this limitation. Post-accident monitoring Extensive additions }lave been Additional instrumentation is 7.5 made to post-accident instru- in agreement with Regulatory mentation. Guide 1.97, Revision 2. 4 of 8 HCGS-UFSAR Revision 13 November 14, 2003

( ( ( TABLE 1.3-8 (Cant) FSAR Section in Which Item Qmnse Reason for Q!anle Sub iect is Discussed Emergency responsefacilities Rmergency response facilities now provide p>st-aooident were added in &greement with display information. Nl1RI!XJ-0696 requirements. A post-aooident S811p].ing static:m A post--at:X)ident 88111p].in8 system 9.3.2 that provides grab samples MIS added in &greement with has been added. NlJRBJ-0737 requirements. 125 V and 250 V de power Vital loads have been isolated This change was ladeto cc:.ply 8.3 systems frcm ncmvi tal loads. with Regulatory Guide 1. 32 125 V and 250 V de power 'Ihe vital ac source to the Higher voltage and ~tic 8.3 systems charger for the vital 250 V circuit breakers were selected to batteries freD 230 V to 480 V illprove systeaefficiency have been changed. The and to increase S)'Btemprotecti<m. associated circuit breakers have also been changed fnw nonautaaatic to autcaatic. Standby diesel generators The diesel generators have The higher continuous rating is 8.3 been purchased with a ccntinuous conservative and is adequate for rating of 4430 kW each. the design loads. Standby diesel generators The station standby diesel 'Ibis change reflects &greeaatt 8.3 generator system consists of with Regulatory Guide 1. 32. four automatically starting diesel generators that are dedicated to supply ~r to the four vi tal bJaesin the one t.mi t if offsite power is unavailable. Fuel pools and fuel access Deleteddesign that the truck It is not feasible to design the 9.1.2 recei v:ing bay floor is tru::k/railroad receiving bay floor designed to wi thstard a spent to withstand the impact of a spent fuel caskdropfrom the opera- fuel cask dropped f:n:a the refuel-tingdeck. ing floor (design features based on a 125-ton cask). 1berefore, special design features basedon Nt.JRm--0612 are incorporated in the design of the crane to exclude consideration of cask drop fraa stnlctural design. 5 of 8 RXJS-UFSAR Revision 0 April 11, 1988

( ( ( TABLB 1.3-8 (Coot) FSAR Section in Which Ite. Reason for Change SUb.iect is Discussed High density fuel racks A high density fuel rack This reflects state-of-the-art 9.1.2 design is nowused. design allowing DBXiaafuel storage. Reactor Building polar The PSAR states that the polar With the present arrangement of 9.1.5 crane crane rails are re~mved in the refueling floor, removal of vicinity of the fuel pool to the crane rails in the vicinity prevent a:>vement of the crane of the fuel pool ~d also over the pool. Instead, the crane prevent crane access to the rail is not removed, and dryer and separator storage mechanical stopsand. Iiili t pool. switches are used to prevent the 150-ton hookfrc:a traveling abovethe fuel pool. A 10-ton hook is allowed to travel above the fuel pool. SSWS, SACS, and RAGS ~fied cooling water This increases the plant reli- 9.2.1, 9.2.2, and systemsto place all plant ability and safet7 by using fresh 9.2.8 cooling loads on intelWdi.ate waterto cool all plant equip-loops. The SSWS consists of Jielltpreviously cooled directly two essential supply trains with service water (Delaware that supply water to the River water). '1he inte:naediate associated SACS, ard. a single loops also provide an additional nonessential train that barrier for cont.ainaalt of supplies water to the RACS. radioactive contaminated water. Breathing Air System The Hope Creek plant nowhas This provides workers with a 9.5.10 provisions for a breathing filtered air supply while working air supply. in areas of potential airborne contaodnation and. thus minimizes ()(X)U(Btional exposures. Standby liquid control 1he system is nowcapable of Mitigation of An¥8 events 9.3.5 supplying a 86 gpm flow. RBVS Station service water piping lbe drywell cooling units are 9.4.2 no longer penetrates the now cooled by either chilled primary containment. water or RACS water, both of which are closed loop systems. Service Area, Heating, ~ tizone fans are deleted and ~tizone fans are not required 9.4.3 Cooling and Ventilating pre-filters and after-filters in the control area and. pre-filters systemg are added to the control roca and after-filters provide higher air cordi tioning system. efficiency cleanup. 6 of 8 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.3-8 {COnt) FSAR Section in Which I tell Change Reason for <lvmge Subject is Discussed Radwaste Area Heating, An addi tiona! FSAR section, not Since the Auxiliary Building 9. 4. 3 Cooling, and Ventilating inclWed in the PSAR, describes service area HVAC is to be a System the heating, ventilating, and air distinct system serving certain cooditioning for the Auxiliary areas that are separate fran the Building service area. radwaste area and other Auxiliary Building areas, a new FSAR section describing the service area HVAC system is necessary. FPS A motor driven fire pap was 1be original diesel-engine- 9. 5. 1 added to the system. driven fire pap now serves as a st..amby-f ireJUIIP*

                          'lbe water source has been changed fra.Del.a.ware  River        DelmereRiver water quality water to two 300,000-gallon          in the vicinity- of Hope water storage tanks to be            Creekis not suitable for filled from the site well.           fire protection.

cws 1be 144-inch turbine h.rlldi.ng The)rwere an operational feature 10.4.5 isolation valves were deleted. later deemedundesirable and uniBportant to safetY". cws Condenserbypassline was Not required for syst.e. operation 10.4.5 eliminated. reliability- or safety. Cooling towers 1be nl.IDber of cooling towers 'lhis change was madebecause 10.4.5 has been changed to one instead of the new facility layout when of two. the original site was changed to Artificial Island. Power conversion systell Changed ntaber of feedwater 1bis change pei'IIi. ts a higher 10.4.7 puDpB fran t~<<> to three. plant generating capaci t7 uplll loss of a single feedwater pap. GRS 1be type of off-gas syste. has the cbarcoal system is a sillpler 11.3 been changed froma cryogenic system. It improvesthe reliabi-to an ambient charcoal system. lity of the system and the plant availability. In addition, it requires less maintenrmce and is able to better 11eet the goals of Regulatory Guide 8. 9. 7 of 8 Revision 0 April 11, 1988

( ( TABLE 1.3-8 (Cont) FSAR Section in Which Item Change Reason for Chanle Subiect is Discussed Station shielding design 'lhe FSAR states that the Regular area radiation surveys 12.3.2 surveillance ard testing purpose of the initial would not detect cracks or voids, shield test is to detect any and ~tethods to do so are very shielding inadequacies lengthy aol expensive aol require (calculational and/or radia- specialized instnaentation aol tion stresmi.ng or shine) rather sources. than to detect cracks or voids as indicated in the PSAR. Station shielding design 'lhe ~misture separators are 'Ibe disadvantages of pltting 12.3.2 turbine building located above the turbine .,isture separators below the deck, not below it. operating floor:

a. Longerarlo steamrunsare required

b. Congestion is increased below the operating floor

c. '1be .oisture separators would no longer be self-draining to beater no. 5

d. 1be aoisture separators 1<<Nl.d be .wedifficult to install and support.

Adequate shielding can be provided above the operating floor to ~uce offsi te dosesfrca N to acceptable levels. ( 1) Changes listed are only those that have occurred since the last PSAR amendllent.

           'Ibe NRC has been notified of all other major design changes through amerdaeuts to the PSAR.

8 of 8 HCXJS-UFSAR Revision 0 April 11 J 1988

1.4 IDENTIFICATION OF AGENTS AND CONTRACTORS 1.4.1 Applicant Public Service Electric and Gas Company (PSE&G) is the applicant for the utilization facility license and will operate the plant upon completion. Prime contractors and principal consultants are identified in Sections 1.4.2 through 1.4.5. The applicant has been responsible for the design and currently operates seven multiunit fossil fuel power plants and one two unit nuclear power plant. Additionally, several combustion turbine driven generator installations have also been designed, constructed, and are currently being operated by the applicant. The applicant also has an ownership interest in one pumped storage plant, two operating fossil fuel plants, and a two unit operating nuclear power plant. These plants provide capacity and energy to the applicant's system, but are not operated by the applicant . These facilities, which had a net capacity of 8995 ~e at the end of 1982, constitute the applicant's electric generating system. The applicant has been active in the development of atomic energy for generation of electricity for over 30 years. In 1952, it becam~ a charter member of the Dow Chemical*Detroit Edison Nuclear Power Development Project, which subsequently became Atomic Power Development Associates, Inc. (APDA). This organization designed and developed a fast breeder power reactor for the Atomic Energy Commission's Power Demonstration Program. In 1957, the applicant began consultant services for the Princeton University Plasma Physics Laboratory, and it continues to work closely with the laboratory in the research and development of fusion technology. In 1972, the applicant pioneered plans for the world's first offshore floating nuclear generating station. The applicant has contributed manpower and financial support to numerous other research and development projects including the High Temperature Reactor 1.4*1 HCGS*UFSAR Revision 0 April 11, 1988

Development Associates, Inc, Fast Breeder Reactor Research, the Liquid Metal Fast Breeder Reactor (LMFBR) Breeder Reactor Corp, the Direct Cycle High Temperature Gas Cooled Reactor, the Westinghouse Fusion-Fission Hybrid Study, and Nuclear Reactor and Plant Engineering Research. The applicant's engineers have participated in nuclear assignments ranging from the classroom to the nation's leading nuclear laboratories and most advanced reactor projects. The applicant sponsored engineers in nuclear training programs such as the Oak Ridge School of Reactor Technology, and in extended assignments at facilities such as the Oak Ridge National Laboratory, the Argonne National Laboratory, the National Reactor Testing Station, the Knolls Atomic Power Laboratory, the General Atomic Division of General Dynamics Corporation, and the Atomic Power Development Associates. Its engineers have participated in such nuclear projects as the Experimental Boiling Water Reactor, the Materials Testing Reactor, the Engineering Test Reactor, the Seawolf, the Peach Bottom Atomic Power Station, the Empire State Atomic Development Associates High-Temperature Gas-Cooled Reactor Program, and the Enrico Fermi Atomic Power Station. The applicant's engineers were extensively involved in the design, construction, startup, operation, and maintenance of the Salem Generating I Station Units 1 and 2, each unit consisting of a pressurized water reactor (PWR). 1.4.2 Architect/Engineer and Constructor The applicant has retained Bechtel Power Corporation and Bechtel Construction, Inc. to provide architectural, engineering, construction, and startup assistance services for Hope Creek Generating Station (HCGS}. The change in corporate entity from 1.4-2 HCGS-UFSAR Revision 12 May 3, 2002

Bechtel Power Corporation to Bechtel Construction Inc. for construction activities, was implemented on May 21, 1984. In addition, Bechtel Power Corporation is responsible for procurement of equipment other than the Nuclear Steam Supply System (NSSS) , turbine generator, and certain other major components that have been purchased by the applicant. Bechtel Power Corporation has been continuously engaged in engineering and construction activities since 1898. A review of recent tabulations of nuclear units in the continental United States that are planned, under construction, or in operation, indicates that Bechtel is responsible for the engineering design of approximately 60 of these units and for the construction of about 40 units. Bechtel Power Corporation and Bechtel Construction Inc., are, therefo~e, eminently qualified to provide the required services for station design, equipment procurement, construction, and startup assistance. 1.4.3 Nuclear Steam Supply System Supplier General Electric Company (GE) has the contract to design, fabricate, and deliver the boiling water type NSSS and nuclear fuel fo~ HCGS, as well as to provide technical direction for installation and startup of this system. GE has been engaged in the development, design, construction, and operation of BWRs since 1955. A review of recent tabulations of nuclear units in the United States that are planned, under construction, or in operation reveals that approximately 65 of these units employ General Electric BWRs. Thus, General Electric has substantial experience, knowledge, and capability to design, manufacture, and furnish technical assistance for the installation and startup of the HCGS NSSS. 1.4.4 Turbine Generator Supplier GE has the contract to design, fabricate, and deliver the turbine generator for HCGS, as well as to provide technical assistance for installation and startup of this equipment. GE has a long history in the application of turbine generators to nuclear power stations dating back to 1955. Over 100 of the nuclear units 1.4-3 HCGS-UFSAR Revision 0 April 11, 1988

planned, under construction, or in operation in the United States employ General Electric turbine generators. General Electric is, therefore, well qualified to design, fabricate, and deliver the turbine generator for HCGS, and to provide technical assistance for the installation and startup of this equipment. 1.4.5 Consultants PSE&G has engaged consultants to provide information and recommendations in a number of specialized fields. Principal consultants include: Consultant Area of Contribution Dames & Moore Geology, seismology, ground water, hydrology EDS Nuclear Seismic analysis Kibbe & Associates Nuclear fuel supply Meteorological Evaluation Meteorology Services, Inc Nuclear Exchange Corp Nuclear fuel supply Nutech Mark I containment plant unique analysis Pickard, Lowe, & Garrick Cooling tower studies S.M. Stoller Corp Nuclear fuel supply Separative Work Unit Corp Nuclear fuel supply Southwest Research Institute Inservice inspection 1.4-4 HCGS*UFSAR Revision 0 April 11, 1988

A.D. Little River traffic studies NUS Corporation Safety and risk assessment

HCGS-UFSAR. Revision 0 April 11:-, 1988

1. 5 REQUIREMENTS FOR FURTHER TECHNICAL INFORMATION 1.5.1 Current Development Programs 1.5.1.1 InstrumentatiQn for Vibration Vibration testing for reactor internals is*perfor.med on all General Electric (GE) boiling water reactor (BWR) plants. At the time of issue of Regulatory Guide 1. 20, test programs for compliance were instituted. The first BWR 4 plant, Browns Ferry 1, is considered a prototype design and is instrumented and subjected to both cold and hot two-phase flow testing to demonstrate that flow induced vibrations, similar to those expected during operation, do not cause damage. Subsequent plants that have internals similar to those of the prototype are tested in compliance to the requirements of Regulatory Guide 1. 20 to confirm the adequacy of the design with respect to vibration. Further discussion is presented in Section 3.9.2 and in NED0-24057A, Assessment of Reactor Internals Vibration in BWR/4 and BWR/5 Plants, Reference 1.5-1 .

1.5.1.2 Core Spray Distribution The design basis for core spray distribution for BWR 4 plants has been described in References 1.5-2 and 1.5-3. Other loss-of-coolant accident (LOCA) programs, jointly sponsored by GE/NRC/EPRI have shown that the core spray systems' introduction of core spray water into the upper plenum results in a pool of water in the upper plenum. This provides a water downflow into all of the fuel bundles. When this water inventory in the upper plenum subcools, the countercurrent flow limiting at the upper tieplate breaks down; thus, the water flows through the core and refloods the core at an earlier time than currently calculated. Fuel bundle heat transfer, consistent with system performance during the time from rated core spray to core reflood, has been shown to exceed the values allowed by Reference 1. 5-3. This behavior has been verified by overseas testing and reported at the "Ninth Water Reactor Safety Research Information Meeting," October 26 through 30, 1981 . 1.5-1 HCGS-UFSAR Revision 0

                                                     ' April 11, 1988

and Core Flooding Heat Transfer Effectiveness 1.5.1.3 Core Spray Due to the incorporation of an 8x8 fuel rod array with unheated water rods, tests have been conducted to demonstrate the effectiveness of the Emergency Core Cooling System (ECCS) in the new geometry. These tests are regarded as confirmatory only, since the geometry change is very slight, and the water rods provide an additional heat sink on the inside of the bundle, improving heat transfer effectiveness. There are two distinct programs involving the core spray. One program is discussed in Section 1.5.1.2. The other program.concerns the testing of core spray and core flooding heat transfer effectiveness. The results of testing with stainless steel cladding were reported in Reference 1.5-4. The results of testing using Zircaloy cladding were reported in Reference 1.5-5. 1.5.1.4 Verification of Pressure Suppression Desicn The initial Mark I pressure suppression tests were perfomed from 1958 through 1962 to demonstrate the viability of the pressure*suppression concept for reactor containment design. The tests were designed to stmul~te LOCAs with breaks in piping sized up to approximately twice the cross-sectional break area of the design-basis LOCA. In 1977, testing was initiated at the quarter scale test facility (QSTF). The QSTF was designed so that the suppression-chamber section width, drywell volume, downcomer system configuration, vent system resistance, vent header deflector, and other test conditions could be varied on a plant specific basis. The data obtained from the QSTF plant unique tests serve as the principal source for the pool swell load specifications. The scaling relationships for the pool swell tests were developed based on the method of similitude. Independent research studies, performed for the NRC by the 1.5-2 HCGS-UFSAR Revision 0 April 11, 1988

Massachusetts Institute* of Technology, the Lawrence Livermore Labor a tory, and the University of California at Los Angeles, have confirmed these pool swell staling relationships . In 1~78, tests were initiated at the full scale test facility (FSTF). The FSTF was a full scale, 22.5° sector of a typical Mark I suppression chamber connected to simulated drywell and pressure vessel volumes. The tests simulated blowdowns over a range from small breaks to the design basis accident (DBA) . The principal des,'ign parameters, e.g. , vent area to pool area ratio, and distance of the downcomer exit to the suppression chamber shell, were selected to produce conservative data from which the loads could be derived. The 6ondensatlon oscillation and chugging design loads are based on the results of the FSTF tests. 1.5.1.5 Critical Heat Flu~ Testing A pfogram for critical heat flux testing was established similar to that described in Reference 1. 5-6. Since that time, however, a new analysis has been performed and the GE BWR Thermal Analysis Basis {GETAB) program, Reference 1.5-7 1 initiated . The results of that analysis and related testing are described in Reference; 1.5-7. 1.5.2 References 1.5-1 General Electric, "Assessment of Reactor Internals Vibration in BWR/4 and BWR/5.PlantS 1 11 NED0-24057A, November 1977. 1.5-2 General Electric, "BWR Core Spray Distribution, 11 NEDO 10846, April 1973. 1.5-3 General Electric, 11 General Electric Company Analytical Model for Loss-of-Coolant.Analysis in Accordance with 10 CFR 50, Appendix K - Effect of Steam Environment on BWR Core Spray Distribution, 11 NEDE 20566-P-A 1 Volume 3, September 1986 .

HCGS..;.UFSAR Revision 14 July 26, 2005

1.5-4 General Electric, "Modeling the BWR/6 Loss-of-Coolant Accident: Core Spray and Bottom Flooding Heat Transfer Effectiveness," Licensing Topical Report, NED0-10801, March 1973. 1.5-5 General Electric, "Emergency Core Cooling Tests of an Internally Pressurized, Zircaloy-Clad, 8X8 Simulated BWR Fuel Bundle," Licensing Topical Report, NED0*20231, December 1973. 1.5-6 "Design Basis for Critical Heat Flux Condition in Boiling Water Reactors," APED-5286, September 1966. 1.5-7 General Electric, "General Electric BWR Thermal Analysis Basis (GETAB): Data, Correlation and Design Application," Licensing Topical Report, NED0-10958-A, January 1977. 1.5-4 HCGS-UFSAR Revision 0 April 11, 1988

1.6 MATERIAL INCORPORATED BY REFERENCE The following is a tabulation of topical reports and other documents referenced in this FSAR. Report Referenced in Number FSAR Section GENERAL ELECTRIC COMPANY REPORTS: APED~4827 Maximum Two~Phase Blowdown from 6.2 Pipes, April 1965. APED~5286 Design Basis for Critical Heat Flux 1.5 Condition in BWRs, September 1966. APED~5458 Effectiveness of Core Standby Cooling 5.4 Systems for General Electric Boiling Water Reactors, March 1968 . APED*5460 Design and Performance of General 3.9 Electric BWR Jet Pumps, July 1968. APED-5555 Impact Testing on Collet Assembly for 4.6 Control Rod Drive Mechanism 7RDB144A, November 1967. APED-5750 Design and Performance of General 5.4 Electric Boiling Water Reactor Main Steam Line Isolation Valves, March 1969. APED-5756 Analytical Methods for Evaluating the 15.4, Radiological Aspects of the General 15.7 Electric Boiling Yater Reactor, March 1969 . 1.6-1 HCGS-UFSAR Revision 0 April 11, 1988

Report Referenced in Number Title FSAR Section GEAP-5620 Failure Behavior in ASTM A1063 Pipes 5.2 Containing Axial Through-Wall Flows, April 1968 NEDC-32410P-A Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Plus Option III Stability Trip - Licensing Topical Report NEDC-33075P-A Licensing Topical Report GE Hitachi 7.6 Boiling Water Reactor Detect and Suppress Solution - Confirmation Density NEDC-33153P SAFER/GESTR-LOCA Loss-of-Coolant 6.3 Accident Analysis for Hope Creek Generating Station NEDE-10313 PDA - Pipe Dynamic Analysis Program 3.6 for Pipe Rupture Movement (Proprietary Filing). NEDE-10958A General Electric Thermal Analysis 4.4 Basis (GETAB): Data, Correlation, and Design Application, January 1977 NEDE-20566-P-A General Electric Company Model for 1.5, 3.9, Loss-of-Coolant Accident Analysis in 6.3 Accordance with 10CFR50 Appendix K, September 1986. NEDE-20944-P BWR/4 and BWR/5 Fuel Design, Proprietary Versions, October 1976. NEDE-20944-P-1 BWR/4 and BWR/5 Fuel Design, 4.2 Amendment 1, (only BWR/4&5,) 4.3 January 1977. NEDE-21354-P BWR Fuel Channel Mechanical Design 3.9 and Deflection, September 1976. NEDE-23014 HEX O1 User's Manual, July 1976. 15.2 NEDE-24011-P-A General Electric Standard Application 1.2, 1.3, for Reactor Fuel, latest revision 4.1, 4.2, 4,3, 4,4, 6.3, 15.0, 15.3, 15.4 1.6-2 HCGS-UFSAR Revision 23 November 12, 2018

Report Referenced in General Electric Standard 1. 2, 1.3 Application for Reactor Fuel, 4. 1, 4. 2t United Supplement, 4. 3, 4. 4' Latest revision 6. 3, 15.0 15.. 3, 15.4 NEDE-+24222 Asses~ment of BWR Mitigation of ATWS 15.8 (NUREG-0460 Alternate No. 3), Volume 1, May 1979; Volume 2, December 1979. NEDE~24834 Hanfo:rd 2 Crimped CRD Hydraulic 3.6

              *withdrawal Lines,  (Proprietary).

NED0-:-10029 An Analytical Study on Brittle 5.3 Fracture.of GE-BWR Vessel Subjected to the Design Basis Accident, July 1969 . NE00,..10173 Current State of Knowledge, High 11.1 Performance BWR Zircaloy-clad 003[16]2 Fuel, May 1970. NED0-10320 The General Electric Pressure 6.2 Suppression Containment Analytical Model, April 1971; Supplement l1 May 1971. NEDQ~10.34 9 Analysis of Anticipated Transients 15.8 Without Scram, March 1971. NEDQ-10505 Experience .with BWR Fuel Through 11.1 September 1971, May 1972 .

HCGS-UFSAR 1.

Revision 14 July 26, 2005

Report Referenced in NED0!10585 Behavior of Iodine in Reactor Water During Plant Shutdown and Startup, August 1972. 15.6 NED0....;10602 Testing of Improved Jet Pumps for the 3.9 BWR/6 Nuclear System, June 1972. NED0~10739 Methods for Calculating Safe Test 6. 3, Intervals And Allowable Repair Times 15.9 for Engineered Safeguard Systems, January 1973. NEDO;.;..l0801 Modeling the BWR/6 Loss-of-Coolant 1.5 Accident: Core Spray and Bottom Flooding Heat Transfer Effectiveness, Marcn 1973. I

                  . Analytical Methods of Plant Transient       4.1, 15.1 I

Evaluations for General Electric Boiling Water Reactor, December 1986. NEDOL-10846 BWR Core Spray Distribution, April 1.5 1973. NED0..;..10871 Technical Derivation of BWR 1971 11.1 Design Basis Radioactive Material Source Terms~ March 1975. NED0-10899 Chlo.ride Control in BWR Coolants, June 5.2 197 NED0....;10958-A General Electric BWR Thermal Analysis 1.5, 4.4 Basis (GETABJ : Data, Correlation, and Design Application, January 1977. HCGS-UFSAR

1. 6-4 Revision 14 July 26, 2005

Referenced in NEDO-tll209-0A Energy Business 1.8 Boiling Water Reactor Quality Assurance Program Description, Latsst NRC-Accepted Revision NED0-12037 Summary of X-Ray and Gamma-Ray Energy 12.3 and ~ntensity Dataj January 1970.

NED0~20231 Emergency Core Cooling Tests of an 1.5 Internally Pressuri:zed, Zircaloy Clad, 8X8 Simulated BWR Fuel Bundle, December 1973. NED0-20626 Studies of BWR Designs for Mitigation 15.8 I of Anticipated Transients Without Scrams, October 1974 . NED0;-20651 BWR Radiation Effects Design Curve, 5.3 March 1975. NED0~20922 Experience. With BWR Fuel Through 11.1 September 1974, June 1975. NED0-21142 Realistic Accident Analysis for 15.4; General Electric Boiling Water Reactor; 15. 6, The RELAC Code and User's Guide, .7 January 1978. 1.6 ... 5 HCGS-UFSAR Revision 14 July 26, 2005

Report Referenced in Number FSAR Section NED0-:-'21143 Radiological Accident 15.4, Evaluation The CONACOl Code, March 15. 6, 1976. 15.7 NED0-21159 Airborne Release from BWRs for 11.1, 12.3 Environmental Impact Evaluations, March 1976. NED0~21159-2 Airborne Releases from BWRs for 12.3 Environmental Impact Evaluations, 1977. NED0.;..21506 Stability and Dynamic Performance of 4.1 the General Electric Boiling Water Reactor, January 1977. NED0-21660 Experience with BWR Fuel through 11.1 DScember 1976, July 1977. NED0-21778-A Transient Pressure Rises Affecting 5.3 Fracture Toughness Requirements for BWRs, December 1978. NED0:-21821-2 Boiling Water Reactor Feedwater 5,3 No;z:zle/Sparger Final Report (Nonproprietary}, August 1979. NED0.:..24057-A Assessment of Reactor Internals 1.5, 3.9 Vibration in BWR/4 and BWR/5 Plants, November 1977. NED0.:...24154-A Qualification of the 4 .1, 5. 2, One-Dimensional Core Transient 15.1 Model For BWR, August 1986. HCGS-UFSAR

1. 6-6 Revision 14 July 26, 2005

Report Referenced in Number FSAR Section NED0-24988 Analysis of Generic BWR Safety/ 5.2 Relief Valve Operability Test Results, October 1981.

NED0-31960 BWR Owners' Group 7.6 Long Term Stability Solutions Licensing Methodology, June 1991 NED0-31960 BWR Owners' Group 7.6 Supplement 1 Long Term Stability Solutions Licensing Methodology, March 1992 OTHER REFERENCED REPORTS AEEW-R-705 An Investigation Into the Effects 4.4 of Crud Deposits on Surface Temperature, Dry-Out, and Pressure Drop, with Forced Convection Boiling of Water at 69 Bar in an Annular Test Section, 1971. AI-75-2 (H~storical ~nformation) Thermal Hydrogen Recombiner System 6.2 I for Water-Cooled Reactors, Revision 2, July 1975. AI-77-55 Thermal Hydrogen Recombiner System 6.2 for Mark I and I I Boiling Water Reactors, September 1977. ANL-6948. Condensation of Metal Vapors: Mercury 6.2 and the Kinetic Theory of Condensation, october 1964. BHR/DER 70-1 Radiological Surveillance Studies 11.1 at a Boiling Water Nuclear Power Reactor, March 1970. 1.6-7 HCGS-UFSAR Revision 15 October 27, 2006

Report Referenced in Number Title FSAR Section CF 59-6-47 Removal of Fission Product Gases from 11.3 (ORNL) Reactor Offgas Streams by Adsorption, 1959. EPRI NP-495 Sources of Radioiodine at Boiling 12.2 Water Reactors, February 1978. ORNL-3041 SDC, A Shielding-Design Calculation 12.3 for Fuel-Handling Facilities, March 1966. ORNL-4585 Morse - A Multigroup Neutron and 12.3 Gamma-Ray Monte Carlo Transport Code, September 1973. ORNL-4628 Origen - The ORNL Generation and 12.3 Depletion Code, May 1973. ORNL-4932 Radioactive Atoms Supplement 1, 12.3 August 1973. ORNC-NSIC-23 Potential Metal Water Reaction in 6.2 Light Water Cooled Power Reactors, August 1968. ORNL-RSIC-10 A Survey of Empirical Functions Used 12.3 to Fit Gamma Ray Buildup Factor, February 1966. ORNL-RSIC-21 Neutron and Gamma Ray Albedos, 12.3 February 1968. ORNL-TM-4280 The DOT 3 Two Dimensional Discrete 12.3 Ordinates Transport Code, September 1973. 1.6-8 HCGS-UFSAR Revision 23 November 12, 2018

Report Referenced in Number FSAR Section (Historical Information) FC-4290 Hydrogen Evolution from Zinc Corrosion 6.2 under Simulated Loss-of-Coolant Accident Conditions, August 1976. WASH-1258 Numerical Guides for Design Objectives 11.3 and Limiting Conditions for Operation to Meet the Criterion as Low as Practicable for Radioactive Material in Light-Water-Cooled Nuclear Power Reactor Effluents. WCAP-8776 Corrosion Study for Determining 6.2 Hydrogen Generation from Aluminum and Zinc During Post-Accident Conditions, 1976. WAPD-TM-918 Thermal and Hydraulic Effects of Crud 4.4 Deposited on Electrically Heated Rod Bundles, September 1970. BECHTEL POWER CORPORATION REPORTS BC-TOP-4A Seismic Analyses of Structures and 3.7 Equipment for Nuclear Power Plants, Revision 3, November 1974. BC-TOP-3A Tornado and Extreme Wind Design 3.3 Criteria for Nuclear Power Plants, Revision 3, August 1974. BC-TOP-9A Desigp of Structures for Missile 3.5 Impact, Revision 2, September 1974.

1. 6-9 HCGS-UFSAR Revision 15 October 27, 2006

Report Referenced in Number FSAR Section BN-TOP-1 Testing Criteria for Integrated 6.2 Leakage Rate Testing of Primary Containment Structures for Nuclear Power Plants, November 1972. BN-TOP-2 Design for Pipe Break Effects, 3.6, 3.8 Revision 2, May 1974. BN-TOP-4 Subcompartment Pressure Analyses 3.6 Revision 0, July 1976. BP-TOP-1 Seismic Analysis Piping System, 3.7 Revision 3, January 1976. ABB COMBUSTION ENGINEERING REPORTS: CENPD-300-P-A Reference Safety Report for Boiling 4.1, 4.2, 4.3, Water Reactor Reload Fuel, July 1996 4.4 CENPD-287-P-A Fuel Assembly Mechanical Design 3.9, 4.2 Methodology for Boiling Water Reactors CENPD-288-P-A ABB Seismic/LOCA Evaluation Methodology 3.9 for Boiling Water Reactor Fuel I WCAP-15942-P-A Fuel Assembly Mechanical Design 4.2 Methodology for Boiling Water Reactors, Supplement 1 to CENP-287

1. 6-10 HCGS-UFSAR Revision 17 June 23, 2009

1.7 DRAWINGS AND OTHER DETAILED INFORMATION Table 1.7-1 provides a listing of electrical drawings used in the plant design. Table 1.7-2 provides a listing of piping and instrumentation diagrams (P&IDs) used in the plant design. Table 1.7-3 provides a listing of control and instrumentation drawings used in the plant design. It should be noted that the information presented in these tables is considered current through FSAR Amendment 15. However, the Figures contained in the UFSAR have been deleted and replaced with references to the appropriate Plant Drawings or Vendor Technical Document. 1.7-1 HCGS-UFSAR Revision 20 May 9, 2014

TABLE 1.7-1 ELECTRICAL DRAWINGS (B1stor~cal Information) *I FSAR Figure Drawing Number Title Number Rev Date E-0001-0 Single line Diagram, Station 8. 3-1 6 02/11/85 E-0002-1, Sh 1 Single line Meter & Relay Diagram, Power System 8.3-2 Sh 1 7 12/17/85 E-0002-1, Sh 2 Single line Meter & Relay Diagram, Power System 8.3-2 Sh 2 4 12/17/85 E-0003-1 Single line Meter & Relay Diagram Generator, Main Transformer 8.3-3 5 09/30/85 E-0004-1 Single line Meter and Relay Diagram, 7.2 kV Station Power System 8.3-4 5 01/24./85 E-0005-0 Single line Meter & Relay Diagram, 4.16 kV Station Power System 4 10/06/83 E-0005-1, Sh 1 Single line Meter & Relay Diagram, 4.16 kV Station Power System 5 03/13/85 E-0005-1, Sh 2 Single line Meter & Relay Diagram, 4.16 kV Station Power System 3 03/13/85 E>0006-l, Sh 1 Single line Meter & Relay Diagram, 4.16 kV Class lE Power System 8.3-5 Sh 1 4 03/1.3/85 E-0006-1, Sh 2 Single line Meter & Relay Diagram, 4.16 kV Class lE Power System 8.3-s Sh 2 4 03/13/85 E-0007*1 Single line Diagram Synchronizing 8.3-6 5 08/02/85 E-0008-1 Single line Meter & Relay Diagram, Diesel Generators 8.3-7 2 08/02/85 E-0009-1, Sh 1 Single line Meter & Relay Diagram, 125 V de System 8.3-8 Sh 1 7 ll/22/85 E-0009-1, Sh 2 Single line Meter & Relay Diagram, 125 V de System 8.3-8 Sh 2 8 11/22/85 E-0009-1, Sh 3 Single line Meter & Relay Diagram, 125 V de System 8.3-8 Sh 3 8 l.l/22/85 E-0009-1, Sh 4 Single line Meter & Relay Diagram, 125 v de System 8.3-8 Sh 4 4 ll/22/85 E-0009-1, Sh 5 Single line Meter & Relay Diagram, 125 v de System 8.3-8 Sh 5 4 11/22/85 E-0010-0 Single line Meter & Relay Diagram, +24 V de System a 3-9 3 01/31/83 E-0011-1, Sh Single line Meter & Relay Diagram, 250 V de System 8.3-lo sh 1 7 12/02/85 E-0011-1, Sh 2 E-0012-1, Sh 1 Single line Meter & Relay Diagram, 250 Single line Meter v de System

                                & Relay Diagram, 120 v ac Instrumentation &
                                                                                  .- 8.3-10 Sh 2 8.3-11 Sh l 6

7 12/02/85 11/03/86 Miscellaneous Sys l of 35 HCGS-UFSAR Revision 1.4 July 26, 2005

TABLE 1. 7-1 (Historica~ Znformation) *I FSAR Figure Drawing Number Title Number ~ Date E-0012-1, Sh 2 Single line Meter & Relay Diagram, 120 V ac Instrumentation 8.3-11 Sh 2 9 01/03/86 Miscellaneous Sys E-0012-1, Sh 3 Single line Meter & Relay Diagram, 120 v ac Instrumentation & a. 3-11 sh 3 g 07/25/85 Miscellaneous Sys E-0012-1, Sh 4 Single line Meter & Relay Diagram, 120 V ac Instrumentation & 8-3-11 Sh 4 4 01/03/86 Miscellaneous Sys E-0012-1, Sh 5 Single line Meter & Relay Diagram. 120 V ac Instrumentation & a. 3-11 Sh s 8 10/21/85 Miscellaneous Sys E-0018-1, Sh 1 Single line Meter & Relay Diagram, 480 V, Class lE Unit Substation 8-3-12 Sh 1 9 09/19/85 10B410, 420, 430, 440, 450, 460, 470, 480 E-0018-1, Sh 2 Single line Meter & Relay Diagram, 480 v Class lE Unit Substation 8.3-12 Sh 2 9 09/19/85 108410. 420, 430, 440. 450, 460, 470, 480 E-0018-1, Sh 3 Single line Meter & Relay Diagram, 480 v Auxiliary Breaker Centers 8.3-12 Sh 3 5 06/11/85 10B415, 426, 437, 448 E-0019-1, sh 1 480 v Motor control Center (MCC) Tabulation, Class lE, Auxiliary Building, 6 08/21/85 Diesel Generator (DG) Area 10B411, 10B421, 10B431, & 10B441 E-0019-1, Sh 2 480 v MCC Tabulation Class lE, Auxiliary Building, DG Areas 108411, 5 08/21/85 421, 431, 441 E-0020-1, Sh 1 480 V MCC Tabulation Class 1E Auxiliary Building DG Area 10B451, 461, 7 02/25/85 471, 481 E-0020-1, Sh 2 480 v MCC Tabulation Class 1E Auxiliary Building DG Area 10B451, 461, 8 11/12/85 471, 481 E-0021-1, Sh 1 480 V MCC Tabulation Class lE !-iCC-Reactor Area 10B212. 222, 232, 242 9 08/21/85 E-0021-1, Sh 2 580 V MCC Tabulation Class lE MCC-Reactor Area lOB212, 222, 232, 242 9 08/21/85 E-0021-1, Sh 480 v MCC Tabulation Class lE MCC-Reactor Area 10B212. 222, 232, 242 9 06/27/85 E-0021-1, Sh 4 480 v MCC Tabulation Class lE MCC-Reactor Area 10B212, 222, 232, 242 9 10/ll/85 E-0021-1, Sh 5 480 v MCC Tabulation Class lE MCC-Reactor Area 10B212, 222, 232, 242 9 05/31/95 E-0021-1, Sh 6 480 v MCC Tabulation Class lE MCC-Reactor Area lOB212, 222, 232, 242 9 OB/16/85 2 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1. 7-1 (Cant)* FSAR Figure (Historical Information) *I Drawing Number Title Number ~ nate E-0022-1, Sh 1 480 V MCC Tabulation Class lE MCC-Reactor Area 10BS53, 563, 573, 583 6 06/28/85 E-0022-1, Sh 2 480 V MCC Tabulation Class lE MCC-Reactor Area 10B553, 563, 5/3, 583 4 06/28/85 E-0023-1, Sh 3 480 V MCC Tabulation 10B252, 10B262. 10B2?2, 10B2B2, 10B313, lOB323, 10 11/12/85 and OOB474 - Reac, R/W & Control Area E-0036-l Schematic Phasing Diagram, 4.16 kV & 480 v Class 1E System 1 11/04/84 E-0040-l Schematic Meter & Relay Diagram, Synchronizing 6 08/23/85 E-0046-1 Schematic Meter & Relay Diagram, 4.16 kV Class lE Station Power System 6 09/06/84 Switchgears 10A401 & 10A403 E-0047-1 Schematic Meter & Relay Diagram, 4.:16 kV Class 1E Station Power System 6 09/06/84 Switchgears 10A402, 10A404 E-0048-l Schematic Meter & Relay Diagram, Diesel Generators 10 07/26/85 E-0068-0 Electrical Schematic Diagram (ESD), Class 1E-4.16 kV Station 9 05/07/85 System Switchgear, Main Circuit Breaker (1)52-40108 E-0069-0 ESD, Class lE 4.16 kV Station Power Switchgear, Main Circuit Breaker 7 05/07/85 (:1)52-40108 E-0070-0 ESD, Class lE 4.16 kV Station Power Switchgear 7 05/07/85 Main Circuit Breaker (1)52-40201 E-oon-o ESD, Class 1E 4.16 kV Station Power Switchgear 7 05/07/85 Main Circuit Breaker (1)52-40208 E-0072-0 ESD, Class 1E 4.16 kV Station Power 7 OS/07/85 Main Circuit Breaker (1)52-40308 E-0073-0 ESD, Class 1E 4.16 kV Station Power System Switchgear, 7 05/07/85 Main Circuit Breaker (1)52-40301 E-0074-0 ESD, Class 1E 4.16 kV Station Power Switchgear 7 05/07/85 Main Circuit Breaker (1)52-40401 E-0075-0 ESD, Class lE 4.16 kV Station Power Switchgear 7 05/07/85 Main Circuit Breaker (1)52-40408 E-0076-0 ESD, Class lE 4.16 kV Unit Substation Transformer 6 08/06/85 Feeder Circuit Breaker (1)52-40110 3 of 35 BCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Historical Information}

                                                                                                                          *I FSAR Figure Drawing Number                                                                        Number   Rev       Date E-0077-0       ESD, Class lE 4.16 kV Unit Substation Transformer                               s       08/06/85 Feeder Circuit Breaker (1)52-40210 E>0078-0       ESD, Class 1£ 4.16 kV Unit Substation Transformer                               5       08/06/85 Feeder Circuit Breaker (1)52-40310 E-0079-0       ESD, Class lE 4.16 kV Unit Substation Transformer                               5       08/06/85 Feeder Circuit Breaker (1)52-40410 ESD, Class lE 4.16 kV Unit Substation Transformer                               5       08/06/85 Feeder Circuit Breaker (1)52-40103 E-0081-0       ESD, Class lE 4.16 kV Unit Substation Transformer                               5       08/06/65 Feeder Circuit Breaker (1)52-40203 E-0092 -0      ESD, Class lE 4.16 kV Unit Substation Transformer                               5       08/06/85 Feeder Circuit Breaker (1}52-40303 E-0083-0       ESD, Class 1E 4.16 kV Unit Substation Transformer                               5       08/06/85 Feeder Circuit Breaker (1)52-40403 E-0084-0       ESD, Class 1E 4.16 kV Station Power System Switchgear                           8       10/03/85 Diesel Generator Circuit Breaker (1)52-40107 E-0085-0       ESD, Class lE 4.16 kV Station Power System Switchgear                           B       10/03/SS Diesel Generator Circuit Breaker (1)52-40207 E-0086-0       ESD, Class 1E 4.16 kV Station Power System Switchgear                           8       10/03/85 Diesel Generator Circuit Breaker (1)52-40307 E-0087-0       ESD, Class lE 4.16 kV Station Power System Switchgear                           8       10/03/85 Diesel Generator Circuit Breaker (1)52-40407 E-0096-0, Sh 1 ESD, Unit Substation 480 V Feeder Circuit Breaker                               5       03/19/85 for Non-Class lE Loads E-0096-0, Sh 2 ESD, Unit Substation 480 V System Feeder Circuit Breaker                        5       06/14/85 for Non-Class IE Loads E-0097-0, Sh 1 ESD, Unit Substat.ion 480 V System MCC & Panel Feeder Circuit                   6       11/25/84 Breakers E-0097-0, Sh 2 ESD, unit Substation 480  v System MCC & Panel Feeder Circuit                   5       07/15/85 Breakers 4 of 35 HCGS-UFSAR                                                                                                   Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Historica1 Info~tion} *I PSAR Figure Drawing Number Title Number Rev Date E-0106-0, Sh A ESD, Class lE 4 kV Station Fower System Bus A401 & 11 07/03/85 A402 Diff and Overcurrent Protection (5 sheets) E-0107-0, Sh A ESD, DG Regular and Backup Lockout Relaying (4 sheets) 9 08/21/85 E-0108-0 ESD, Class lE Station Power Switchgears, Circuit 2 CHl/10/84 Breaker Failure Protection E-0112-0, Sh 1 ESD. Station Service Transformer Protection, 5 05/10/84 Group A Transformers Regular Protection E-0112-0, Sh 2 ESD, Station Service Transformer Protection, 7 12/21/84 Group A Backup Protection E-0112-0, Sh 3 ESD, Station Service Transformer Group A Protection 4 05/01/85 E-0113-0, Sh 1 ESD, Station Service Transformer Protection, 5 05/10/84 Group B Regular Protection E-0113-0, Sh 2 ESD, Station Service Transformer Protection. 6 08/10/84 Group B Backup Protection E-0113-0, Sh 3 ESD, Station Service Transformer Group A Protection 6 08/12/85 E-0114-0, Sh 1 ESD, Station Service Transformer Protection, 5 07/09/84 Group A & B Transformer Overcurrent Protection E-0114-0, Sh 2 ESD, Sta,tion Service Transformer Protection, 4 05/10/84 Group A & B Transformer OVercurrent Protection E-0118-0, Sh 1 Schematic Meter and Relay Diagram, 250 V de System 7 03/14/85 E-0118-0, Sh 2 Schematic Meter & Relay Diagram, 250 v de System 4 02/17/84 E-0119-0, Sh l Schematic Meter & Relay Diagram, 125 V de System 7 01/27/84 E-0119-0, Sh 2 Schematic Meter & Relay Diagram 125 V de System 10 11/19/84 E-0119-0, Sh 3 Schematic.Meter & Relay Diagram 125 V de System 5 10/0l/84 E-0146-0, Sh 1 Electrical schematic Diagram Main Steam Pipe Drains 3 06/14/85 E-0160-0, Sh 1 ESD, Feedwater Heater 1, 2 and Drain Cooler to Vent Valves 4 05/24/85 E-0207-0, Sh A ESD, Vacuum Breaker Solenoid Valves (4 sheets) 11 12/13/85 5 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 {Cent) (Historical Information) *I FSAR Figure Drawing Number Title Number Rev Date E-020B-o, Sh A ESD, 4.16 kV Circuit Breaker Control, Station service Water Pump 7 01/10/85 {5 sheets) E-0209-0, Sh A ESD, Station Service Water System (SSWS) (5 sheets! 5 04/23/84 E-0211-0, Sh A ESD, SSWS Reactor Auxiliaries Cooling System Heat Exchanger Valves 9 02/08/85 (7 sheets) E-0212-0, Sh A ESD, SSWS Strainer and Backwash Valve HV-2197 A,B,C&D (4 sheets} 9 09/18/85 E-0216-0, Sh 1 ESD, SSWS Fuel Pool & Safety Auxiliaries Cooling System (SACS) Isolation 3 09/24/84 Drain Valve E-0216-0, Sh 2 ESD, ssw Fuel Pool & SACS Makeup Isolation Valve 3 09/24/84 E- 02l'7 -0, Sh A ESD, 4.16 kV Circuit Breaker Control Safety Auxiliary Cooling Pump 5 08/21/85 (9 sheets) E-0218-0, Sh A ESD, SACS/Turbine Auxiliaries Cooling System (TACSJ Supply & Return Valve 12 08/19/85 2522, 2496 (7 sheets) E-0219-0, Sh l ESD, RHR Pump seal & Motor Searing cooling Water Supply Solenoid Valves 03/23/84 E-0219-0, Sh 2 ESD, RHR Pump Seal & Motor Bearing Cooling water Supply Solenoid Valves 6 03/23/84 E-0220-0, Sh A ESD, SACS Expansion Tank & Hydraulic Accumulator Valves (4 sheets) 7 08/22/84 E-0221-0, Sh 1 ESD SACS Loop A Heat Exchanger (HX) Inlet Valves 2 04/15/85 E-0221-0, Sh 2 ESD, SACS, Loop B HX Inlet Valves 4 04/15/85 E-0223-0, Sh 1 ESD, Residual Heat Removal (RHR) HX Outlet Motor Operated Valve 5 04/lB/85 (MOV) 2512A E-0223-0, Sh 2 ESD, RHR HX Outlet MOV 2512B 4 03/23/84 E-0224-0 ESD, Process Sampling Shutoff Valve 5 05/04/83 E-0225-0 ESD, SACS Fuel Pool HX Inlet Valves 6 09/25/85 E-0226-0 ESD, SACS Fuel Pool HX Cross Connection Valves 4 03/23/84 E-0227-0 ESD, Hydrogen Recombiner HX Cleaning Water Valves 2313 A/B 2 08/23/82 E-0228-0 ESD, Safety Auxiliary Cleaning SACS HX Bypass Shutoff Valves 6 12/23/85 6 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 {COnt) {Historical Infor.mation) *I FSAR Figure Drawing Number Title Number Rev Date E-0229~0 ESD SACS Cleaning Water to Instrument Gas Compressor Valves 2 04/23/84 E-0238-0 ESD, Reactor Building Isolation Valves 2 04/30/84 E-0240-0, Sh 1 ESD, Reactor Recirculation Pump Color Isolation Valves 2 04/25/84 E-0240-0, Sh 2 ESD Reactor Recirculation Pump Isolation Valves 2 04/25/84 E-0276-0, Sh 1 ESD, Main Steam Isolation Valve {MSIV) Sealing Line Isolation 4 OS/13/85 Valves E-0276-0, Sh 2 ESD, Schematic Diagram MS!V Sealing Line Isol. Val. 0 11/11/83 E-0277-0 ESD, MSIV Sealing System Instrument Gas Isolation Valves 2 04/15/85 E- 0278-0 ESD MSIV Sealing System Instrument Gas Supply Valves 3 10/10/84 E-0279-0 ESD, MSIV System Test Isolation Valves 3 08/01/85 E-0297-0 ESD, Plant Leak Detection Containment Isolation Valves 3 10/23/SS E-0298-0 ESD Containment Atmosphere Control Prepurge, Cleanup Isolation 2 03/14/85 Valves E-0299-0 ESD, Containment Atmosphere Control Hydrogen/Oxygen Analyzer 2 04/23/84 Isolation Valves E-0300-0, Sh ESD, Containment Atmosphere Control Bleed Valves 2 04/19/84 E-0300-0, Sh 2 ESD, Containment Atmosphere control Bleed Valves 2 04/19/84 E-0303-0 ESD, Containment Atmosphere control Reactor Building To Torus 3 09/06/85 Vacuum Relief Valves E-0304-0 ESD, Containment Hydrogen Recombination System Gas Recombiner 3 01/10/85 Isolation Valves E-0306-0, Sh 1 ESD, Primary Containment Instrument Gas Supply Header Isolation 5 09/06/85

              & Emergency Pneumatic Supply Valve E-0306-0, Sh 2 ESD, Primary Containment Instrument Gas supply Header Isolation                 3       08/05/85
              & Emergency Pneumatic Supply Valve E-0307-0       ESD, Primary Containment Instrument Gas Isolation Valves                        2       05/01/85 7 of 35 HCGS-UFSAR                                                                                                   Revision 14 July 26, 2005

TABLE 1.7-l (Contl (Historical. J:nfo:r:ID.lltion) *I FSAR Figure Drawing Number Title Number Rev Date E-0308-0, Sh l ESD, Primary Containment Instrument Gas Motor-Operated Isolation Valves 4 02/13/85 E-0308-0, Sh 2 ESD, Primary Containment Instrument Gas Motor-Operated Isolation 3 08/05/85 Valves E-0310-0 ESD, Primary Containment Instrument Gas Post-Accident Compressor 2 02/13/85 Suction Valves E-0313-0 ESD, Containment Atmosphere Control Hydrogen/Oxygen Analyzer Supply Valves 4 07/22/85 E>0324-0 ESD, Fuel Pool Cooling Water Pumps 7 06/:24/85 E-0326-0 ESD, Fuel Pool Filter Demineralizer System Isolation Valves 5 09/06/85 E-0329-0 ESD, Reactor Building Isolation valves SV-4656 & 4663 4 01/09/84 E-0330-0 ESD, Torus Water Cleanup Suppression Pool Isolation Valves 3 09/06/85 E-0331-0, Sh 1 ESD, Fuel Pool Filter Demineralizer Bypass Valve 4 04/10/84 E-0331-0, Sh 2 ESD, Fuel Pool Filter Dernineralizer Bypass Valve & Fuel 4 04/10/84 Pool Makeup Valves E-0436-0, Sh A ESD, 4.16-kV Class lE Circuit Breaker Control Chiller Compressor 10 12/10/85 Index Sheet (11 sheets) E-0350-0, Sh A ESD, Liquid Radwaste Collection Motor Operated Valves Index Sheet 5 09/06/85 (4 sheets) E-0385-0 ESD, Solid Radwaste Collection Reactor Bldg Isolation Valve IHV-5551 4 10/11/BS E-0426-0, Sh 1 ESD, Compressed Air System Reciprocating Emergency Instrument 5 06/27/85 Air Compressors E-0426-0, Sh 2 ESD, Compressed Air System Reciprocating Emergency 6 09/25/85 Instrument Air Compressors E-0428-0 ESD, Compressed Air System Reactor Building Isolation Valves l 01/31/83 E-0435-0, Sh A ESD, Chilled Water Circulation Pump 1AP400 & Head Tank Makeup 7 09/11/85 water Valves (5 sheets) E-0436-0, Sh A ESD 4.16 kV Class lE Circuit Breaker Control Chiller Compressor 10 12/20/85 Index Sheet, (11 sheets) B of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cant) {Historical Information). *I FSAR Figure Drawing Number Title Number Rev Date E-0465-0, Sh 1 ESD, Sch Diagram RBVS Supp Fans A/B/C VH300 6 02/25/85 E-0465-0, Sh 2 ESD, Reactor Building ventilation System {RBVS) Supply Fans 5 08/13/85 E-0467-0, Sh A ESD, Reactor Bldg Supply Filtration, Recirculation, & Ventilation 11 :l.0/18/SS System (9 sheets) E-0468-0, Sh A ESP, Reactor Bldg & SACS Pump Room Unit Coolers (5 sheets) 16 10/0l/85 E-0468-0, Sh 1 ESD, NSSS Pump Room Unit Coolers {5 sheets) 8 05/24/85 E-0469-0, Sh 1 ESD, Reactor Bldg Supply Refueling Dampers Indication 5 11/26/84 E-0469-0, Sh 2 ESD, Reactor Bldg Supply Refueling Damper Indication 9 12/17/85 E-O*H0-0, Sh 1 ESD, Drywell Purge Damper controls 4 09/05/86 E-0472-0, Sh A ESD, Reactor Building Exhaust FRVS vent Fans & Dampers (4 sheets) l.O 09/02/85 E-0473-0, Sh 1 ESD, Reactor Building Exhaust Isolation Dampers 4 11/26/84 E-0473-0, Sh 2 ESD, Airlock Isolation Damper 9451F 4 10/18/84 E-0474-0, Sh A ESD, Reactor Building Exhaust Room & Pipe Chase Isolation Dampers 7 10/24/85 E-0479-0, Sh A ESD, Chilled Water System Containment & Reactor Building Isolation 2 04/30/84 Valves (4 sheets) E-0485-0, Sh A ESD, Auxiliary Building Diesel Area Switchgear Room Coolers 13 10/04/85 (5 sheets) E-0486-0 ESD, Diesel Generator Room Recirculation System Fans 9 10/30/85 E-0487-0, Sh A ESD, Auxiliary Building- Diesel Area Battery Room Exhaust Fans (6 sheets) 7 12/23/85 E-0490-0, Sh A ESD, Auxiliary Building & Control Area, Control Room Supply Fans 4 07/22/85 (5 sheets) E-0491-0 ESD, Auxiliary Building Control Area Electro Hydraulic Air Dampers l ll/11/82 E-0492-0, Sh A ESD, Auxiliary Building Control Room H&V (5 sheets) 10 08/23/85 E- 0492-0, Sh 3 ESD, Auxiliary Building Control Room H&V Outside Air Dampers {4 sheets) 5 09/23/85 E-0493*0, Sh A ESD, Auxiliary Building Control Area Battery Room Exhaust Fans (4 sheets) 11 08/05/85 9 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 {Cont) {Historical Information)

                                                                                                                                *I FSAR Figure Drawing Number                        Title                                                 Number   Rev       Date E-0495-0       ESD, Auxiliary Building Control Area Control Room Isolation Dangers                   5       10/23/85 E-0496-0, Sh A ESD, Intake Structure & Yard Building Intake Structure Supply Fans                    12      07/22/85 (5 sheets)

E-0497-0 ESD, Miscellaneous Structure & Yard Buildings, Intake Structure 6 11/26/84 Exhaust Fans E~l403-0, Sh A Lighting Notes, Symbols, and Details 42 09/25/85 E-1405-1, Sh A Class 1£ Panel Schedule (34 sheets) a 03/14./85 E-1408-0, Sh A Wire and Cable Notes, Details (12 sheets) 19 08/26/85 E-1412-0, Sh A Electrical Numbering System (34 sheets) 11 01/14/85 E-1417-0, Sh A Fuse Panel Schedule (10 sheets) 3 03/14/85 E-1421-0 Single Line Lighting Distribution 9.5-20 12 05/28/85 E-1435-0 Lighting and Telephone Plan, Control &: D/G Area, Plan El. 155-3 & 163-6 20 12/05/85 E-1450-1 Lighting and Telephone Plan, Turbine Building Unit 1, Plan El. 54-0 9 12/09/85 E-1451-1 Lighting and Telephone Plan, Reactor Building Unit 1, Plan .El. 54-0 14 12/09/85 E-1456-1 Lighting and Telephone Plan, Turbine Building Unit 1, Plan El. 120-0 7 12/09/85 E-1456-2 Lighting and Telephone Plan, Turbine Building Unit 2, Plan El. 120-0 6 12/09/85 E-1462-1 Lighting and Telephone Plan, Turbine Building Unit 1, Plan El. 171-0 6 12/09/85 E-1467-0 Plant Area Telephone System Riser Diagram 7 12/06/85 E-1468-0, Sh 1 Riser Diagram P. A. System 14 09/05/85 E-1468-0, Sh 2 Not used E-1468-0, Sh 3 Not used E-1469-1, Sh 1 Riser Diagram-F. A. System Guardhouse 10 09/13/84 E-1469-1, Sh 2 Riser Diagram-F. A. System Guardhouse 16 10/31/85 E-1469-1, Sh Riser Diagram-F. A. System Guardhouse 13 10/31/85 10 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1. 7.:1 (Cont) (Historical ~nformation}

                                                                                                                             *I FSAR Figure Drawin2 Number                         Title                                             Number   Rev       Date E-1469-1, Sh 4 Riser Diagram-P. A. System Guardhouse                                              5       09/09/BS E-1469-1, Sh 5 Riser Diagram-P. A. System Guardhouse                                              8       09/05/85 E-1472-1       Riser Diagram Fire Detection System, Reactor and Turbine Building                  9       10/31/85 E-1475-l, Sh 1 UHF Radio System Riser Diagram                                         9.5-33      3       08-30-85 E-1475-1, Sh 2 UHF Radio System Equipment Location                                    9.5-34      3       08-30-85 E-1504-0, Sh l Raceway :Plan, Intake Structure                                                    16      12/31/BS E-1504-0, Sh 2 Raceway Plan, Intake Structure                                                     6       10/19/84 E-1504-0, Sh 3 Raceway Plan, Intake Structure                                                     7       04/10/85 E-l504-0, Sh 4 Raceway Plan, Intake Structure                                                     10      08/07/85 E-1504-0, Sh 5 Raceway Plan, Intake Structure                                                     6       12/17/84 E-1504-0, Sh 6 Raceway Plan, Intake Structure                                                     9       03/18/BS E-1504-0, Sh 7 Raceway Plan, Intake Structure                                                     15      09/30/85 E-1504-0, Sh 8 Raceway Plan. Intake Structure                                                     2       03/08/85 E-1511-1. Sh 1 Raceway Plan, Reactor Building, El 54, Area 15                                     5       07/17/84 E-1511-1, Sh 2 Raceway Plan, Reactor Building, El 54, Area 15                                     28      12/09/85 E-1512-1       Raceway Plan, Reactor Building, El 77, Area 15 (2 sheets)                          20      12/21/85 E-1513-1, Sh 1 Raceway Plan, Reactor Building. El 102, Area 15                                    20      11/04/85 E-l513-1, Sh 2 Raceway Plan, Reactor Building, El 102, Area 15                                    5       10/13/83 E-1514-1, Sh 1 Raceway Plan, Reactor Building, E1 132, Area 15                                    14      11/21/85 E-1514-1, Sh 2 Raceway Plan, Reactor Building, El 132, Jl.rea 15                                  4       11/19/85 E-1515-1, Sh 1 Raceway Plan, Reactor Building, El 145, Area 15                                    11      11/27/85 E-1515-1, Sh 2 Raceway Plan, Reactor Building, El 145, Area 15                                            08/15/85 E-1516-1       Raceway Plan, Reactor Building, El 162, Area 15                                    11      11/04/85 11 of 35 HCGS-UFSAR                                                                                                      Revision 14 July 26, 2005

TABLE 1.7-1 (Contl (Historical Information) *I FSAR Figure Drawing Number Title Number Rev Date E-1521-l, Sh 1 Raceway Plan, Reactor Building, El 54, Area 14 1 12/15/76 E-1521-1, Sh 2 Raceway Plan, Reactor Building, El 54, Area 14 19 05/28/85 E-1522-1, Sh 1 Raceway Plan, Reactor Building, El 77, Area 14 20 12/13/85 E-1522-1, Sh 2 Raceway Plan, Reactor Building, El 77, Area 14 3 12/06/B3 E-1523 -1, Sh 1 Raceway Plan, Reactor Building, El 102, Area 14 21 ll/11/85 E-1523-1, Sh 2 Raceway Plan, Reactor Building, El 102, Area 14 9 09/23/84 E-1524-1 Raceway Plan, Reactor Building, El 124 & 132, Area 14 18 12/1.9/85 E-1525-l Raceway Plan, Reactor Building, El 137 & 145, Area 14 15 11/11/85 E-1526-1, Sh 1 Raceway Plan, Reactor Building, El 162 & 178-6, Area 14 13 11/1.4/85 E-1526-1, Sh 2 Raceway Plan, Reactor Building, El 162 & 178-6, Area 14 11 11/11/85 E-1531-1, Sh 1 Raceway Layout, Reactor Building, El 54, Area 13 3 12/12/77 E-1531-1, Sh 2 Raceway Layout, Reactor Building, El 54, Area 13 24 12/24/85 E-1532-1, Sh 1 Raceway Plan, Reactor Building, El 77, Area 13 21 11/27/85 E-1532-1, Sh 2 Raceway Plan, Reactor Building, El 77, Area 13 5 08/11/82 E-1533-1, Sh Raceway Plan, Reactor Building, El 102, Area 13 18 12/06/85 E-1533-l, Sh 2 Raceway Plan, Reactor Building. El 102, Area 13 4 04/01/83 E-1534-1 Raceway Plan, Reactor Building, El 120 & 132, Area 13 13 12/05/85 E-1535-l Raceway Plan. Reactor Building, El 137 & 145, Area 13 15 11/21/BS E-1536-l Raceway Plan, Reactor Building, El 162 & 178-6, Area 13 10 ll/14/85 Raceway Plan, Reactor Building, El 171 & 201, Area 13 8 08/16/85 E-1541-1, Sh 1 Raceway Plan, Reactor Building, El 54, Area 18 1 12/15/76 E-1541-1, Sh 2 Raceway Plan, Reactor Building, El 54, Area 18 20 ll/27/85 E-1542-1 Raceway Plan, Reactor Building, El 77, Area 18 14 11/04/85 12 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 {Cont) {Historical Information) *I FSAR Figure Drawing Nuniber Title Number Rev Date E-1543-1, Sh 1 Raceway Plan, Reactor Building, El 102, Area 18 22 12/30/85 E-1543-1, Sh 2 Raceway Plan, Reactor Building, El 102, Area 18 4 04/24/84 E-1544-1 Raceway Plan, Reactor Building, El 132, Area 18 15 11/14/85 E-1545-1 Raceway Plan, Reactor Building, El 145, Area 18 8 11/11/85 E-1547-l Raceway Plan, Reactor Building, El 201, Area 18 8 10/31/BS E-1551-1 Raceway Plan, Reactor Building, El 54, Area 17 1 12/15/76 E-1552-1, Sh Raceway Plan, Reactor Building, El 77, Area 17 24 12/24/85 E-1552-1, Sh 2 Raceway Plan, Reactor Building, El 77, Area 17 lO 09/09/85 E-1552-1, Sh 3 Raceway Plan, Reactor Building, El 77; Area 17 3 02/13/85 E-1552-1, Sh 4 Raceway Plan, Reactor Building, El 77, Area 17 4 Ol/28/85 E-1552-1, Sh 5 Raceway Plan, Reactor Building, El 77, Area 17 2 10/05/82 E-1552-1, Sh 6 Raceway Plan, Reactor Building, El 77, Area 17 2 10/05/82 E-1552-1, Sh 7 Raceway Plan, Reactor Building, El 77, Area 17 5 10/12/84 E-1552-1, Sh 8 Raceway Plan, Reactor Building, El 77, Area 17 06/19/84 E-1552-1, Sh 9 Raceway Plan, Reactor Building, El 77, Area 17 5 04/08/85 E-1552-1, Sh 10 Raceway Plan, Reactor Building, El 77, Area 17 5 03/28/85 E-1552-1, Sh 11 Raceway Plan, Reactor Building, El 77, Area 17 2 04/15/85 E-1552-1, Sh 12 Raceway Plan, Reactor Building, El 77, Area 17 1 02/07/83 E-1552-1, Sh 13 Raceway Plan, Reactor Building, El 77, Area 17 3 06/29/85 E-1552-1, Sh 14 Raceway Plan, Reactor Building, El 77, Area 17 3 04/15/65 E-1552-1, Sh 15 Raceway Plan, Reactor Building, El 77, Area 17 02/13/85 E-1552-1, Sh 16 Raceway Plan, Reactor Building, El 77, Area 17 02/22/83 E-1552-1, Sh 17 Raceway Plan, Reactor Building, E1 77, Area 17 2 O:l/23/SS 13 of 35 HCGS-UFSJ\R Revision 14 July 26, 2005

TABLE 1.7-l {Cont) (Historica1 Information} *I FSAR Figure Drawing Number Title Number Date E-1552-1, Sh 16 Raceway Plan, Reactor Building, El 77, Area 17 2 02/23/83 E-1552-1, Sh 19 Raceway Plan, Reactor Building, El 77, Area 17 4 03/26/85 E-1552-1, Sh 20 Raceway Plan, Reactor Building, El 77, Area 17 4 10/12/84 E-1552-1, Sh :n Raceway Plan, Reactor Building, El 77, Area 17 3 12/09/83 E-1552-1, Sh 22 Raceway Plan, Reactor Building, El 77, Area 17 3 12/09/83 E-1552-1, Sh 23 Raceway Plan, Reactor Building, El 77, Area 17 1 03/30/83 E-1552-1, Sh 24 Raceway Plan, Reactor Building, El 77, Area 17 5 05/28/85 E-1552-1, Sh 25 Raceway Plan, Reactor Building, E1 77, Area 17 2 02/07/83 E-1552-1, Sh 26 Raceway Plan, Reactor Building, El 77, Area 17 4 09/13/85 E-1552-1, Sh 27 Raceway Plan, Reactor Building,.El 77, Area 17 1 02/07/83 E-1552-1, Sh 29 Raceway Plan, Reactor Building, El 77, Area 17 1 02/07/83 E-1552-1, Sh 29 Raceway Plan, Reactor Building, El 77, Area 17 1 06/06/83 E-1552-1, Sh 30 Raceway Plan, Reactor BUilding, El 77, Area 17 4 09/30/85 E-1552-1, Sh 3l Raceway Plan, Reactor Building, El 77, Area 17 3 03/27/85 E-1552-l, Sh 32 Raceway Plan, Reactor Building, El 77, Area 17 4 02/13/85 E-1552-1, Sh 33 Raceway Plan, Reactor Building, El 77, Area 17 3 08/29/BS E-1552-1, Sh 34 Raceway Plan, Reactor Building, El 77, Area 17 3 07/20/64 E-1552-1, Sh 35 Raceway Plan, Reactor Building, El 77, Area 17 08/29/84 E-1552-1, Sh 36 Raceway Plan, Reactor Building, El 77, Area 17 0 10/05/84 E-1552-1, Sh 37 Raceway Plan, Reactor Building, El 77, Area 17 0 11/21/84 E-1552-1, Sh 38 Raceway Plan, Reactor Building, El 77, Area 17 0 12/07/84 E-1552-1, Sh 39 Raceway Plan, Reactor Building, El 77, Area 17 0 12/07/84 E-1552-l, Sh 40 Raceway Plan, Reactor Building, El 77, ~ea 17 0 12/07/84 14 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (H~storie~1 Information) *I FSAR Figure Drawing Number Title Number Date E-1552-1, Sh 41 Raceway Plan, Reactor Building, El 77, Area 17 0 12/07/84 E-1553-1, Sh Raceway Plan, Reactor Building, El 102, Area 17 18 12/09/BS E-1553-1, Sh 2 Raceway Plan, Reactor Building, El 102, Area 17 1.2 03/12/85 E-1553-1, Sh 3 Raceway Plan, Reactor Building, El 102, Area 17 12 08/19/85 E-1553-1, Sh 4 Raceway Plan, Reactor Building, El 102, Area 17 7 08/1.2/85 E:-1553-1, Sh 5 Raceway Plan, Reactor Building, El 102, Area 17 7 12/07/84 E-1553-1, Sh 6 Raceway Plan, Reactor Building, El 102, Area 17 3 10/26/84 E-1553-1, Sh 7 Raceway Plan, Reactor Building, El 102, Area 17 3 12/19/84 E-1553-l, Sh 8 Raceway Plan, Reactor Building,,El 102, Area 17 5 08/29/85 E-1553-1, Sh 9 Raceway Plan, Reactor Building, El 102, Area 17 8 12/03/84 E-1553-1, Sh 10 Raceway Plan, Reactor Building, El 102, Area 17 6 12/03/84 E-1553-1, Sh 11 Raceway Plan, Reactor Building, El 102, Area 17 4 08/26/83 E-1553-1, Sh 1.2 Raceway Plan, Reactor Building, El 102, Area 17 3 05/28/85 E-1553-l, Sh l3 Raceway Plan, Reactor Building, El 102, Area 17 3 08/12/85 E-1553-1, Sh 14 Raceway Plan, Reactor Building, El 102, Area 17 5 08/12/85 E-1553-1, Sh 15 Raceway Plan, Reactor Building, El 102, Area 17 4 04/17/85 E-1553-1, Sh 16 Raceway Plan, Reactor Building, El 10.2, Area 17 5 11/28/84 E-1553-1, Sh 17 Raceway Plan, Reactor Building, El 102, Area 17 2 12/02/82 E-1553-1, Sh 18 Raceway Plan, Reactor Building, El 102, Area 17 4 08/16/85 E-1553-1, Sh 19 Raceway Plan, Reactor Building, El 102, Area 17 2 10/05/82 E-1553-1, Sh 20 Raceway Plan, Reactor Building, El 102, Area 17 3 02/23/84 E-1553-1, Sh 21 Raceway Plan, Reactor Building, El 102, Area 17 6 04/25/85 E-1553-1, Sh 22 Raceway Plan, Reactor Building, El 102, Area 17 7 08/16/85 15 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Historica1 Information}

                                                                                                                           *I FSAR Figure Drawing Number                         Title                                          Number   Rev       Date E-1553-1, Sh 23 Raceway Plan, Reactor Building, El 102, Area 17                                6       03/26/85 E-1553-1, Sh 24 Raceway Plan, Reactor Building, El 102, Area 17                                6       03/26/85 E-1553-1, Sh 25 Raceway Plan, Reactor Building, El 102, Area 17                                6       03/21/85 E-1553-1, Sh 26 Raceway Plan, Reactor Building, El 102, Area 17                                6       04/17/85 E-1553-1, Sh 27 Raceway Plan, Reactor Building, El 102, Area 17                                9       04/25/85 E-1553-1, Sh 28 Raceway Plan, Reactor Building, El 102, Area 17                                3       02/23/84 E-1553-1, Sh 29 Raceway Plan, Reactor Building, El 102, Area 17                                4       01/H/85 E-1553-1, Sh 30 Raceway Plan, Reactor Building, El 102, Area 17                                2       04/13/83 E-1553-1, Sh 31 Raceway Plan, Reactor Building,'El 102, Area 17                                4       01/23/85 E-1553-1, Sh 32 Raceway Plan, Reactor Building, El 102, Area 17                                2       12/19/84 E-1553-1, Sh 33 Raceway Plan, Reactor Building, El 102, Area 17                                4       06/29/85 E-1553-1, Sh 34 Raceway Plan, Reactor Building, El 102, Area 17                                4       10/18/84 E-1553-1, Sh 35 Raceway Plan, Reactor Building, El 102, Area 17                                3       04/13/84 E-1553-1, Sh 36 Raceway Plan, Reactor Building, El 102, Area 17                                6       09/13/85 E-1553-1, Sh 37 Raceway Plan, Reactor Building, El 102, Area 17                                4       11/16/84 E-1553-1, Sh 38 Raceway Plan, Reactor Building, El 102, Area 17                                5       10/18/84 E-1553-l, Sh 39 Raceway Plan, Reactor Building, EI 102, Area 17                                7       09/30/85 E-1553-1, Sh 40 Raceway Plan, Reactor Building, El 102, Area 17                                3       08/.26/83 E-1553-1, Sh 41 Raceway Plan, Reactor Building, El 102, Area 17                                1       10/01/82 E-1553-1, Sh 42 Raceway Plan, Reactor Building, El 102, Area 17                                1       10/01/82 E-1553-1, Sh 43 Raceway Plan, Reactor Building, E1 102, Area 17                                17      11/19/85 E-1553-1, Sh 44 Raceway Plan, Reactor Building, El 102, ~rea 17                                2       09/07/84 E-1553-1, Sh 45 Raceway Plan, Reactor Building, El 102, Area 17                                7       09/13/85 16 of 35 HCGS-UFSA.~                                                                                                  Revision 14
                                                                                                            .July 26, 2005

TABLE 1.7-1 (Cont) (Historical infor.mation) *I FSAR Figure Drawing Number Title Number Rev nate E-1553-1, Sh 46 Raceway Plan, Reactor Building, El 102, Area 17 12/05/84 E-1553-l, Sh 47 Raceway Plan, Reactor Building, El 102, Area 17 4 12/03/84 E-1553-1, Sh 48 Raceway Plan, Reactor Building, El 102, Area 17 5 03/11/85 E-1553-1, Sh 49 Raceway Plan, Reactor Building, El 102, Area 17 4 06/07/84 E-1553-1, Sh 50 Raceway Plan, Reactor Building, El 102, Area 17 4 05/16/85 E-1553-1, Sh 51 Raceway Plan, Reactor Building, El 102, Area 17 4. 08/24/84. E-1553-1, Sh 52 Raceway Plan, Reactor Building, El 102, Area 17 5 10/08/84 E-1553-1, Sh 53 Raceway Plan, Reactor Building, El 102, Area 17 1 04/24/84 E-1553-l, Sh 54 Raceway Plan, Reactor Building, El 102, Area 17 4 09/30/85 E-1553-1, Sh 55 Raceway Plan, Reactor Building, El 102, Area 17 1 05/09/85 E-1553-1, Sh 56 Raceway Plan, Reactor Building, El 102, Area 17 1 02/22/83 E-1553-1, Sh 57 Raceway Plan, Reactor Building, El 102, Area 17 3 10/05/84 E-1553-1, Sh 58 Raceway Plan, Reactor Building, El 102, Area 17 2 01/23/85 E-1553-1, Sh 59 Raceway Plan, Reactor Building, El 102, Area 17 1 02/07/83 E-1553-1, Sh 60 Raceway Plan, Reactor Building, El 102, Area 17 5 05/28/85 E-1553-1, Sh 61 Raceway Plan, Reactor Building, El 102, Area 17 4 06/07/84 E-1553-1, Sh 62 Raceway Plan, Reactor Building, El 102, Area 17 1 02/07/83 E-1553-1, Sh 63 Raceway Plan, Reactor Building, El 102, Area 17 5 04/15/85 E-1553-1, Sh 64 Raceway Plan, Reactor Building, El 102, Area 17 2 02/24/83 E-1553-1, Sh 65 Raceway Plan, Reactor Building, El 102, Area 17 2 Ol/23/85 E-1553-1, Sh 66 Raceway Plan, Reactor Building, El 102, Area 17 2 02/13/85 E-1553-1, Sh 67 Raceway Plan, Reactor Building, £1 102, Area 17 1 02/07/83 E-1553-1, Sh 68 Raceway Plan, Reactor Building, El 102, Area 17 4 08/12/85 17 of 35 HCGS-UFSAR Revision J.4 July 26, 2005

TABLE 1.7-1 (Cent) (Historical Information) *I FSAR Figure Drawing Number Title Number Date E-1553-1, Sh 69 Raceway Plan, Reactor Building, El 102, Area 17 0 11/12/82 E-1553-1, Sh 70 Raceway Plan, Reactor Building, El 102, Area 17 08/29/85 E-1553-1, Sh 71 Raceway Plan, Reactor Building, El 102, Area 17 5 08/29/85 E-1553-1, Sh 72 Raceway Plan, Reactor Building, El 102, Area 17 5 04/01/85 E-1553-1, Sh 73 Raceway Plan, Reactor Building, El 102, Area 17 2 04/03/84 E-1553-1, Sh 74 Raceway Plan, Reactor Building, El 102, Area 17 09/09/85 E-1553-1, Sh 75 Raceway Plan, Reactor Building, El 102, Area 17 6 03/20/85 E-1553-1, Sh 76 Raceway Plan, Reactor Building, El 102, Area 17 3 02/22/85 E-1553-1, Sh 77 Raceway Plan, Reactor Building, El 102, Area 17 2 03/21/34 E-1553-1, Sh 78 Raceway Plan, Reactor Building, El 102, Area 17 2 1.2/19/84 E-1553-l, Sh 79 Raceway Plan, Reactor Building, El 102, Area 17 1 09/13/85 E-1553-1, Sh 80 Raceway Plan, Reactor Building, El 102, Area 17 4 09/13/85 E-1553-1, Sh 81 Raceway Plan, Reactor Building, El 102, Area 17 1.2/07/84 E-1553-1, Sh 82 Raceway Plan, Reactor Building, El 102, Area 17 08/29/84 E-1553-1, Sh 83 Raceway Plan, Reactor Building, El 102, Area 17 5 12/19/84 E-1553-1, Sh 84 Raceway Plan, Reactor Building, El 102, Area 17 2 03/26/84 E-1553-1, Sh 85 Raceway Plan, Reactor Building, El 102, Area 17 3 09/09/85 E-1553-1, Sh 86 Raceway Plan, Reactor Building, El 102, Area 17 7 09/13/85 E-1553-1, Sh 97 Raceway Plan, Reactor Building, El 102, Area 17 07/18/85 E-1553 l, Sh 88 Raceway Plan, Reactor Building, El 102, Area 17 04/27/84 E-1553-1, Sh 89 Raceway Plan, Reactor Building. E1 102, 17 6 08/12/BS E-1553-1, Sh 90 Raceway Plan, Reactor Building, El 102, Area 17 5 07/18/85 E-1553-1, Sh 91 Raceway Plan, Reactor Building, El 102, Area 17 2 07/22/85 18 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Sistor~cal Informat~on)

                                                                                                                            *I FSAR Figure Draw~ng Number                         Title                                          Number               Date E-1553-1, Sh 92 Raceway Plan, Reactor Building, El 102, Area 17                                2        09/13/85 E-1553-1, Sh 93 Raceway Plan, Reactor Building, El 102, Area 17                                1        04/08/85 E-1553-1, Sh 94 Raceway Plan, Reactor Building, El 102, Area 17                                1        04/08/85 E-1553-1, Sh 95 Raceway Plan, Reactor Building, El 102, Area 17                                1        l.l/26/84 E-1553-1, Sh 96 Raceway Plan, Reactor Building, El 102, Area 17                                2        04/08/85 E-1553-1, Sh 97 Raceway Plan, Reactor Building, El 102, Area 17                                2        07/18/85 E-1553-1, Sh 98 Raceway Plan, Reactor Building, El 102, Area 17                                3        08/19/BS E-1553-1, Sh 99 Raceway Plan, Reactor Building, El 102, Area 17                                0        03/14/85 E-1554-1, Sh 1  Raceway Plan, Reactor Building, El 132, Area 17                                14       11/22/85 E-1554-1, Sh 2  Raceway Plan, Reactor Building, El 132, Area 17                                12       08/19/85 E-1554-1, Sh 3  Raceway Plan, Reactor Building, El 132, Area 17                                2        12/02/82 E-1554-l, Sh 4  Raceway Plan, Reactor Building, El 132, Area 17                                5        05/07/85 E-1554-1, Sh 5  Raceway Plan, Reactor Building, El 132, Area 17                                3        OB/H/84 E-1554-1, Sh 6  Raceway Plan, Reactor Building, El 132, Area 17                                2        03/28/82 E-1554-1, Sh 7  Raceway Plan, Reactor Building, El 132, Area 17                                2        03/28/82 E-1554-1, Sh 8  Raceway Plan, Reactor Building, El 132, Area 17                                2        03/28/82 E-1554-1, Sh 9  Raceway Plan, Reactor Building, El 132, Area 17                                2        03/28/82 E-1554-1, Sh 10 Raceway Plan, Reactor Building, El 132, Area 17                                2        03/28/83 E-1554-1, Sh 11 Raceway Plan, Reactor Building. El 132, Area 17                                         02/23/84 E-1554-1, Sh 12 Raceway Plan, Reactor Building, El 132, area 17                                         12/09/83 E-1554-1, Sh 13 Raceway Plan, Reactor Building, El 132, Area 17                                5        08/21/84 E-1554-1, Sh 14 Raceway Plan, Reactor Building, El 132, Area 17                                5        05/09/85 E-1554-1, Sh 15 Raceway Plan, Reactor Building, El 132, Area 17                                         10/01/84 19 of 35 HCGS-Uf'SAR                                                                                                    Revision 14 July 26, 2005

TABLE 1.7-1 (Cont} (Histo~ieal Information) *I FSAR Figure Drawing Number Title Number Rev Date E-1554-1, Sh 16 Raceway Plan, Reactor Building, El 132, Area 17 2 04/25/85 E-1554-l, Sh 17 Raceway Plan, Reactor Building, El 132, Area 17 2 05/16/85 E-1554-1, Sh 18 Raceway Plan, Reactor Building, El 132, Area 17 3 08/29/85 E-1554-1, Sh 19 Raceway Plan, Reactor Building, El 132, Area 17 2 12/19/84 E-1554-l., Sh 20 Raceway Plan, Reactor Building, El 132, Area 17 7 OB/29/85 E-1554-1, Sh 21 Raceway Plan, Reactor Building, El 132, Area 17 5 08/29/85 E-1554-1, Sh 22 Raceway Plan, Reactor Building, El 132, Area 17 6 08/29/85 E-1554-1, Sh 23 Raceway Plan, Reactor Building, El 132, Area 17 6 06/29/85 E-1554-1, Sh 24 Raceway Plan, Reactor Building, El 132, Area 17 4 08/29/85 E-1554-1, Sh 25 Raceway Plan, Reactor Building, El 132, Area 17 5 01/23/85 E-1554-1, Sh 26 Raceway Plan, Reactor Building, El 132, Area 17 4 05/15/84 E-1554-1, Sh 27 Raceway Plan, Reactor Building, El 132, Area 17 4 08/29/85 E-1554-1, Sh 28 Raceway Plan, Reactor Building, El 132, Area 17 4 08/29/85 E-1554-1, Sh 29 Raceway Plan, Reactor Building, El 132, Area 17 3 05/09/85 E-1554-l, Sh 30 Raceway Plan, Reactor Building, El 132, Area 17 4 08/29/85 E-1554-l, Sh 31 Raceway Plan, Reactor Building, El 132, Area 17 4 02/13/85 E-1554-l, Sh 32 Raceway Plan, Reactor Building, El 132, Area 17 5 08/29/85 E-1554-1, Sh 33 Raceway Plan, Reactor Building, El 132, Area 17 5 08/12/85 E-1554-1, Sh 34 Raceway Plan, Reactor Building, El 132, Area 17 2 08/24/84 E-1554-l, Sh 35 Raceway Plan, Reactor Building, El 132, Area 17 6 08/29/85 E-1554-1, Sh 36 Raceway Plan, Reactor Building, El 132, Area 17 4 08/16/84 E-1554-l, Sh 37 Raceway Plan, Reactor Building, El 132, Area 17 4 09/30/85 E-1554-1, Sh 38 Raceway Plan, Reactor Building. El 132, Area 17 2 04/15/85 20 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cent) (Historica~ Information) *I FSAR Figure Drawing Number Title Number Date E~1554~1, Sh 39 Raceway Plan, Reactor Building, El 132, Area 17 5 11/26/84 E-1554~1, Sh 40 Raceway Plan, Reactor Building, El 132, Area 17 7 02/19/85 E-1554~1, Sh 41 Raceway Plan, Reactor Building, El 132, Area 17 2 06/07/84 E-1554-1, Sh 42 Raceway Plan, Reactor Building, El 132, Area 17 3 08/29/85 E-1554-1, Sh 43 Raceway Plan, Reactor Building, El 132, Area 17 3 08/29/85 E-1554-1, Sh 44 Raceway Plan, Reactor Building, El 132, Area 17 3 06/04/84. E-1554-1, Sh 45 Raceway Plan, Reactor Building, El 132, Area 17 7 OB/29/85 E-1554-1, Sh 46 Raceway Plan, Reactor Building, El 132, Area 17 3 01/23/85 E~1554-l, Sh 47 Raceway Plan, Reactor Building, El 132, Area 17 2 12/03/84 E-1554-1, Sh 48 Raceway Plan, Reactor Building, El 132, Area 17 3 06/19/84 E-1554-1, Sh 49 Raceway Plan, Reactor Building, El 132, Area 17 1 04/27/84 E-1554-1, Sh 50 Raceway Plan, Reactor Building, El 132, Area 17 3 08/29/85 E-1554-1, Sh 51 Raceway Plan, Reactor Building, El 132, Area 17 2 08/01/84 E-1554-1, Sh 52 Raceway Plan, Reactor Building, £1 132, Area 17 03/ll/85 E-1554-1, Sh 53 Raceway Plan, Reactor Building, El 132, Area 17 3 06/19/84 E-1554-1, Sh 54 Raceway Plan, Reactor Building, El 132, Area 17 3 12/20/84 E-1554-1, Sh 55 Raceway Plan, Reactor Building, El 132, Area 17 l 05/23/84 E-1554 -1., Sh 56 Raceway Plan, Reactor Building, El 132, Area 17 5 07/05/85 E-1554-1, Sh 57 Raceway Plan, Reactor Building, El 132, 17 2 06/19/84 E-1554*1, Sh 58 Raceway Plan, Reactor Building, El 132, Area 17 5 08/19/85 E-1554-1, Sh 59 Raceway Plan, Reactor Building, El 132, Area 17 08/29/85 E-1554-1, Sh 60 Raceway Plan, Reactor Building, El 132, Area 17 09/09/95 E-1554-1, Sh 61 Raceway Plan, Reactor Building, El 132, Area 17 3 09/09/85 21 of 35 HCGS*UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Historica1 Information)

                                                                                                                           *I FSAR Figure Drawing Number                         Title                                           Number   Rev       Date E-1554-1, Sh 62 Raceway Plan, Reactor Building, El 132, Area 17                                 4       09/09/85 E-1554-1, Sh 63 Raceway Plan, Reactor Building, El 132, Area 17                                 2       12/03/84 E-1554-1, Sh 64 Raceway Plan, Reactor Building, El 132, Area 17                                 4       09/09/85 E-1554-1, Sh 65 Raceway Plan, Reactor Building, El 132, Area 17                                 2       03/28/85 E-1554-1, Sh 66 Raceway Plan, Reactor Building, ,El 132, Area 17                                2       12/H/84 E-1554-1, Sh 67 Raceway Plan, Reactor Building, El 132, Area 17                                         05/16/85 E-1554-1, Sh 68 Raceway Plan, Reactor Building, El 132, Area 17                                 2       05/09/85 E-1554-1, Sh 69 Raceway Plan, Reactor Building, El 132, Area 17                                 0       06/21/84

£-1554-1, Sh 70 Raceway Plan, Reactor Building, El 132, Area 17 2 06/12/85 E-1554-1, Sh 71 Raceway Plan, Reactor Building, El 132, Area 17 1 09/21/84 E-1554-1, Sh 72 Raceway Plan, Reactor Building, El 132, Area 17 0 12/19/84 E-1555-1, Sh 1 Raceway Plan, Reactor Building, El 145, Area 17 15 11/14/85 E-1555-1, Sh 2 Raceway Plan, Reactor Building, El 145, Area 17 6 04/04/85 E-1555-1, Sh 3 Raceway Plan, Reactor Building, El 145, Area 17 2 05/26/83 E-1555-1, Sh 4 Raceway Plan, Reactor Building, El 145, Area 17 3 04/17/84 E-1555-1, Sh 5 Raceway Plan, Reactor Building, El 145, Area 17 4 04/17/84 E-1555-1, Sh 6 Raceway Plan, Reactor Building, El 145, Area 17 12/09/83 E-1555-1, Sh 7 Raceway Plan, Reactor Building, El 145, Area 17 6 04/17/85 E-1555-l, Sh 8 Raceway Plan, Reactor Building, El 145, Area 17 8 04/17/85 E-1555-1, Sh 9 Raceway Plan, Reactor Building, El 145, Area 17 2 06/11/84 E-1555-1, Sh 10 Raceway Plan, Reactor Building, El 145, Area 17 4 04/15/BS E-1555-1, Sh 11 Raceway Plan, Reactor Building, El 145, Area 17 3 06/19/84 E-1555-1, Sh 12 Raceway Plan, Reactor Building, El 145, Area 17 04/15/85 22 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Historical Information} *I FSAR Figure Title Number Rev Date E-1555-1, Sh 13 Raceway Plan, Reactor Building, El 145, Area 17 1 06/07/84 E-1555-l, Sh 14 Raceway Plan, Reactor Building, El 145, Area 17 4 04/17/85 E-1556-1, Sh 1 Raceway Plan, Reactor Building, El 162, Area 17 16 11/15/85 E-1556-1, Sh 2 Raceway Plan, Reactor Building,*El 162, Area 17 ] 03/19/84 E-1556-1, Sh 3 Raceway Plan, Reactor Building, El 162, Area 17 13 06/28/85 E-1556-1, Sh 4 Raceway Plan, Reactor Building, El 162, Area 17 3 07/30/84 E-1556-1, Sh 5 Raceway Plan, Reactor Building, El 162, Area 17 4 04/05/85 E-1556-1, Sh 6 Raceway Plan, Reactor Building, El 162, Area 17 11 09/30/85 E-1556-1, Sh 7 Raceway Plan, Reactor Building, El 162, Area 17 11 04/16/85 E-1556-1, Sh 8 Raceway Plan, Reactor Building, El 162, Area 17 5 07/18/85 E-1556-1, Sh 9 Raceway Plan, Reactor Building, El 162, Area 17 10 10/24/85 E-1556-1, Sh 10 Raceway Plan, Reactor Building, El 162, Area 17 8 11/l9/85 E-1556-1, Sh 11 Raceway Plan, Reactor Building, El 162, Area 17 5 10/02/85 E-1556-1, Sh 12 Raceway Plan, Reactor Building, El 162, Area 17 3 03/12/85 E-1556-1, Sh 13 Raceway Plan, Reactor Building, El 162, Area 17 3 03/20/85 E-1556-1, Sh 14. Raceway Plan, Reactor Building, El 162, Area 17 2 Ol/3l/85 E-1556-l, Sh 15 Raceway Plan, Reactor Building, El 162, l'i 5 04/16/85 E-1556-l, Sh 16 Raceway Plan. Reactor El 162, Area 17 4 04/25/85 E-1556-l, Sh 17 Raceway Plan, Reactor Building, El 162, Area 17 9 08/19/85 E-1556-1, Sh 18 Raceway Plan, Reactor Building, El 162, Area 17 5 07/23/85 E-1556-1, Sh 19 Raceway Plan, Reactor Building, El 162, Area 17 3 04/01/BS E-1556-1, Sh 20 Raceway Plan, Reactor Building, El 162, Area 17 3 04/04/85 E-1556-1, Sh 21 Raceway Plan, Reactor Building, El 162, Area 17 4 06/07/85 23 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cant) (Historica1 Information)

                                                                                                                          *I FSAR Figure Drawing Number                         Title                                          Number   Rev       Date E-1556-1, Sh 24 Raceway Sections & Details, Reactor Building Area                              6       11/19/85 E-1561-1, Sh 1  Raceway Plan, Reactor Building, El 54, Area 16                                 1       12/15/76 E-1561-1, Sh 2  Raceway Plan, Reactor Building,,El 54, Area 16                                 15      12/09/85 E-1562-1        Raceway Plan, Reactor Building, El 77, Area 16                                 18      12/06/85 E-1563-1, Sh 1  Raceway Plan, Reactor Building, El 102, Area 16                                20      12/06/85 E-1563-1, Sh 2  Raceway Plan, Reactor Building, El 102, Area 16                                4       03/12/85 E-1564-1        Raceway Plan, Reactor Building, El 132, Area 16                                14      11/27/85 E-1565-1        Raceway Plan, Reactor Building, El 145, Area 16                                16      11/04/85 E-1566-1, Sh 1  Raceway Plan, Reactor Building, El 162, Area 16                                14      12/19/85 E-1566-1, Sh 2  Raceway Plan, Reactor Building, El 162, Area 16                                        12/H/85 E-1566-1, Sh    Raceway Plan, Reactor Building, El 162, Area 16                                3       04/04/85 E-1567-1        Raceway Plan, Reactor Building, El 201, Area 16                                9       12/19/85 E-1571-1, Sh 1  Raceway Plan, Reactor Building, El 54, Area 21                                 4       02/07/84 E-1571-1, Sh 2  Raceway Plan, Reactor Building, El 54, Area 21                                 26      12/07/85 Raceway Plan, Reactor Building, El 77, Area 21                                 20      12/06/85 E-1573-1, Sh 1  Raceway Plan, Reactor Building, El 102, Area 21                                19      12/24/85 E-1573-1, Sh 2  Raceway Plan, Reactor Building, El 102, Area 21                                6       07/07/83 E-1574-1        Raceway Plan, Reactor Building, El 132, Area 21                                10      12/19/85 E-1575-1        Raceway Plan, Reactor Building, El 145, Area 21                                8       11/27/85 E-1576-1        Raceway Plan, Reactor Building, El 162, Area 21                                11      12/19/85 E-1577-1        Raceway Plan, Reactor Building, El 201, Area 21                                8       12/12/85 E-1581-1, Sh 1  Raceway Plan, Reactor Building, El 54, Area 20                                 2       06/07/82 E-lSBl-1, Sh 2  Raceway Plan, Reactor Building, El 54, Area 20                                 17      10/31/85 24 of 35 HC:GS-UFSAR                                                                                                  Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Historica1 Information)

                                                                                                                          *I FSAR Figure Drawing Number                        Title                                           Number             Date E-1582-l       Raceway Plan, Reactor Building, El 77, Area 20                                  12      12/06/85 E-1583-l, Sh l Raceway Plan, Reactor Building, El 102, Area 20                                 17      12/24/85 E-1583-1, Sh 2 Raceway Plan, Reactor Building, El 102, Area 20                                         01/31/85 E-1584-1       Raceway Plan, Reactor Building, El 132, Area 20                                 13      11/27/85 E-1585-1       Raceway Plan, Reactor Building, El 145, Area 20                                 12      11/27/85

.E:-1586-1 Raceway Plan, Reactor Building, El 162, Area 20 12 08/29/85 E-1587-1 Raceway Plan, Reactor Building, El 201, Area 20 7 11/21/85 E-1591-1, Sh 1 Raceway Plan, Reactor Building, El 54, Area 19 1 12/15/76 E-1591-1, Sh 2 Raceway Plan, Reactor Building, El 54, Area 19 26 10/31/85 E-1592-1 Raceway Plan, Reactor Building, El 77, Area 19 21 12/06/BS E-1593-1, Sh 1 Raceway Plan, Reactor Building, El 102, Area 19 19 12/24/85 E-1593-1, Sh 2 Raceway Plan, Reactor Building, El 102, Area 19 12/10/82 E-1594-1 Raceway Plan, Reactor Building, El 132, Area 19 10 11/27/85 E-1595-1 Raceway Plan, Reactor Building, El 145, Area 19 14 12/19/85 E-1596-1 Raceway Plan, Reactor Building, El 162, Area 19 17 12/19/85 E-1597*1 Raceway Plan, Reactor Building, El 201, Area 19 6 12/19/85 E-1611-1, Sh 1 Raceway Plan, Reactor Building, El 54, Area 24 4 06/07/82 E-1611-1, Sh 2 Raceway Layout, Reactor Building, El 54, Area 24 24 12/24/85 E-1612-1 Raceway Plan, Reactor Building, El 77, Area 24 17 11/04/85 E-1613-1, Sh 1 Raceway Plan, Reactor Building, El 102, Area 24 14 12/24/85 E-1613-1, Sh 2 Raceway Plan, Reactor Building, El 102, Area 24 4 03/24/83 E-1621-1, Sh 1 Raceway Plan, Reactor Building, El 54, Area 23 06/07/82 E-1621-1, Sh 2 Raceway Plan, Reactor Building, El 54. Area 23 28 01/02/86 25 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Historical Information) *I FSAR Figure Drawing Number Title Number Date E-1622-1 Raceway Plan, Reactor Building, El 77, Area 23 13 11/04/85 E-1623-1 Raceway Plan, Reactor Building, El 102, Area 23 13 03/14/85 E-1631-1, Sh 1 Raceway Plan, Reactor Building, El 54, Area 22 4 02/16/84 E-1631-1, Sh 2 Raceway Plan, Reactor Building, El 54, Area 22 24 01/02/86 E-1632-1 Raceway Plan, Reactor Building, El 77, Area 22 22 12/30/85 E-1633-1 Raceway Plan, Reactor Building, El 102, Area 22 18 12/24/85 E-1651-1, Sh 1 Raceway Plan, Auxiliary Building Control Area, El 54, Area 25 6 03/18/85 E-1651-l., Sh 2 Raceway Plan, Auxiliary Building, Control Area, El 54, Area 25 32 11/20/85 E-1651-1, Sh 3 Raceway Plan, Auxiliary Building, Control Area, El 54, Area 25 4 OB/19/85 E-1651-1, Sh 4 Raceway Plan, Auxiliary Building, Control Area, El 54, Area 25 2 08/19/85 E-1652-1, Sh 1 Raceway Pl.an, Auxiliary Building, Control Area, El 77, Area 25 28 12/12/85 E-1652-1, Sh 2 Raceway Plan, Auxiliary Building, Control Area, El 77, Area 25 18 12/12/85 E-1653-1 Raceway Plan, Auxiliary Building, Control Area, El 102, Area 25 29 01/02/86 E-1654-1, Sh Raceway Plan, Auxiliary Building, Control Area, El 117-6, Area 25 12 11/13/85 E-1654-1, Sh 2 Raceway Plan, Auxiliary Building, Control Area, El 124, Area 25 15 01/02/86 E-1654-1, Sh 3 Raceway Plan, Auxiliary Building, El 124; Area 25 10 12/23/85 E-1654-1, Sh 4 Raceway Plan, Auxiliary Building Control Area 26 Plan at El 124-0 20 11/20/85 E-1655-1 Raceway Plan, Auxiliary Building, Control Area, El 137, Area 25 24 11/n/85 E-1656-1, Sh 1 Raceway Plan, Auxiliary Building, Control Area, El 155-3, Area 25 4 10/01/84 E-1656-1, Sh 2 Raceway Plan, Auxiliary Building, Control Plan at El 155-3, Area 25 17 12/23/85 E-1661-1, Sh 1 Raceway Plan, Auxiliary Building Control Area, El 54, Area 26 3 06/07/78 E-1661-1, Sh 2 Raceway Plan, Auxiliary Building, Control Area, El 54, Area 26 26 09/13/85 E-1662-1, Sh 1 Raceway Layout, Auxiliary Building, Control Area, El 77, Area 26 32 11/27/85 26 of 35 HCGS- UFSAR Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Historical Info~tion)

                                                                                                                                 *I FSAR Figure Drawing Number                        Title                                                 Number              Date E-1662-1, Sh 2 Raceway Plan, Auxiliary Building, Control Area, El 77, Area 26                        18      11/27/85 E-1663-1       Raceway Plan, Auxiliary Building, Control Area, El 102, Area 26                       28      12/31/85 E-1664-1, Sh   Raceway Plan, Auxiliary Building, Control Area, El 117-6, Area 26                     13      12/23/85 E-1664*1, Sh 2 Raceway Plan, Auxiliary Building, Control Area, El 124, Area 26                       19      01/02/86 E-1664-1, Sh 3 Raceway Plan, Auxiliary Building, Control Area, El 124, Area 26                       12      11/21/85 E-1664-1, Sh 4 Raceway Plan, Auxiliary Building, Control Area, El 124, Area 26                       17      11/21/85 E-1664-1, Sh 6 Raceway Plan, Auxiliary Building, control Area, El 124, Area 26                       18      11/04/85 E-1665-1       Raceway Plan, Auxiliary Building, control Area, El 137, Area 26                       23      11/21/85 E-1666-1, Sh 1 Raceway Plan, Auxiliary Building, Control Area, El 155-3, Area 26                     2       07/08/81 Raceway Plan, Auxiliary Building, Control Area, El 155-3, Area 26                             ll/13/85 E-1671-1, Sh 1 Raceway Plan, Auxiliary Building, Diesel Area, El 54, Area 27                         3       05/20/82 E-1671-1, Sh 2 Raceway Plan, Auxiliary Building, Diesel Area, El 54, Area 27                         22      12/07/84 E-1672-1       Raceway Plan, Auxiliary Building, Diesel Area, El 77, Area 27                         18      11/27/85 E-1673-1       Raceway Plan, Auxiliary Building, Diesel Area, El 102, Area 27 (2 sheets)             24      12/12/85 E-1675-1       Raceway Plan, Auxiliary Building, Diesel Area, El 130, Area 27                        22      11/13/BS E-1676*1       Raceway Plan, Auxiliary Building, Diesel 'Area, El 150, Area 27                       20      11/27/85 E-1677-1       Raceway Plan, Auxiliary Building, Diesel Area, El 163-6, Area 27                      18      11/21/85 E-1680-1, Sh 1 Raceway Plan Auxiliary Building, Diesel Generator Area, El 178-0, Area 27             2       05/11/84 E-1680-1, Sh 2 Raceway Plan Auxiliary Building, Diesel Generator Area, El 178-0, Area 27             14      11/21/8 5 E-1681-1, Sh 1 Raceway Plan, Auxiliary Building, Diesel Generator Area, El 54, Area 28               2       05/21/82 E-1681-1, Sh 2 Raceway Plan, Auxiliary Building, Diesel Generator Area, El 54, Area 28               22      11/21/85 Raceway Plan, Auxiliary Building, Diesel Generator Area, El 77, Area 28               21      11/21/85 E-1683-1       Raceway Plan, Auxiliary Building. Diesel Area, El 102, Area 28                        25      11/27/85 27 of 35 HCGS-UFSAR                                                                                                          Revision 14 July 26, 2005

TABLE 1.7*1 (Cant) (Historical Information)

                                                                                                                                   *I FSAR Figure Drawing Number                         T'tle                                                 Number   Rev        Date E 1685-1        Raceway Plan, Auxiliary Building, Diesel Area, El 130, Area 28                        22       1.2/23/85 E-1686-1        Raceway Plan, Auxiliary Building, Diesel Area, El 150, Area 28                        21.      12/23/85 E-1687-1, Sh 1  Raceway Plan, Auxiliary Building, Diesel Area, El 160, Area 28                        15       ll/21/85 E-1687-1, Sh 2  Raceway Plan, Auxiliary Building, Diesel Area, El 160, Area 28                        l        08/09/82 E-1687-2        Raceway Plan, Auxiliary Building, Control Area, El 163-6, Area 68                     13       11/21/BS E-1690-1, Sh 1  Raceway Plan, Auxiliary Building Diesel Generator Area, El 178, Area 28               13       11/21/85 E-1690-l, Sh 2  Raceway Plan, Auxiliary Building Diesel Generator Area, El 178-0, Area 28 E-1695-0        Embedded Conduits, Auxiliary Building, El 102, Areas 27, 28,  67 & 68                 14       09/09/BS E-1700-0        Raceway Plan, Auxiliary Building, Radwaste Area, El 54, Area 38                       14       11/27/85 E-1701-0, Sh 1  Raceway Plan, Auxiliary Building, Radwaste Area, El 54, Area 78                       2        01/18/83 E-1701-0, Sh 2  Raceway Plan, Auxiliary Building, Radwaste Area, El 54, Area 78                       13       11/27/85 E-1712-0, Sh 1  Raceway Plan, Auxiliary Building, Radwaste Area, El 54, Area 73                                06/14/83 E-1712-0, Sh 2  Raceway Plan, Auxiliary Building, Radwaste Area, El 54, Area 73                       17       11/15/85 E-1714-0        Raceway Plan, Auxiliary Building, Radwaste Area, El 54, Area 72                       18       12/12/85 E-1716-0, Sh 1  Raceway Plan, Auxiliary Building, Radwas~e Area, El 54, Area 71                       1        11/19/76 E-1716-0. Sh 2 Raceway Plan. Auxiliary Building, Radwaste Area, El 54, Area 71                       10       01/18/85 E-1721-0        Raceway Plan, Auxiliary Building, Radwaste Area, El 87, Area 78                       17       10/10/85 E-1723-0        Raceway Plan, Auxiliary Building, Radwaste Area, El 87, Area 77                       10       10/10/85 E-1725-0        Raceway Plan, Auxiliary Building, Radwaste Area, El 87, Area 76                       13       10/10/85 E-1726-0        Raceway Plan, Auxiliary Building, Radwaste Area, El 67, Area 35                       21       10/28/85 E-1729-0        Auxiliary Building & Radwaste Area, Raceway Partial Plans, El 75                      8        11/04/85 E-1730-0        Raceway Plan, Auxiliary Building, Radwaste Area, El 87, Area 34                       26       12/31/85 E-1732-0        Raceway Plan, Auxiliary Builaing, Radwaste Area, El 87, Area 73                       26       1.1/27/85 28 of 35 HCGS-UFSAR                                                                                                            Revision 14 July 26, 2005

TABLE 1 7-J. (Cent}

                                                                                                                       *I FSAR Figure Drawing Number                        Title                                            Number         Date E-1734-0       Raceway Plan, Auxiliary           Radwaste Area, El 87, Area 72                  17 08/07/85 E-1736-0       Raceway Plan, Auxiliary Building, Radwaste Area, El 87, Area 71                  19 11/04/B5 E-1741-0       Raceway Plan, Auxiliary Building, Service Area, El 102, Area 78                  17 09/24/85 E-1743-0, Sh 1 Raceway Plan, Auxiliary Building, Service Area, El 102, Area 77                  16 10/10/BS E-1743-0, Sh 2 Raceway Plan, Auxiliary Building, Service Area, El 102, Area 77 E-1750-0, Sh 1 Raceway Plan, Auxiliary Building, Service Area, El 102, Area 34                  25 12/12/85 E-1750-0, Sh 2 Raceway Plan, Auxiliary Building, Service Area, El 102, Area 34                  10 10/24/85 E-1750-0, Sh 3 Raceway Plan, Auxiliary Building, Service Area, El 102, Area 34                  5  05/23/84 E-1750-0, Sh 4 Raceway Plan, Auxiliary Building, Service Area, El 102, Area 34                  4  06/07/84 E-1750-0, Sh 5 Raceway Plan, Auxiliary Building, Service Area, El 102, Area 34                  9  05/H/84 E-1752-0       Raceway Plan, Auxiliary Building, Radwaste Area, El 102, Area 73                 25 12/31/85 E-1754-0, Sh 1 Raceway Plan, Auxiliary Building, Radwaste Area, El 102, Area 72                 22 12/31/85 E-1754-0, Sh 2 Raceway Plan, Auxiliary Building Service Area, El 102, Area 72                   10 11/11/84 E-1756-0       Raceway Plan, Auxiliary Building, Radwaste Area, El 102, Area 71                 21 11/21/85 E-1761-0       Raceway Plan, Auxiliary Building, Service Area, El 124, Area 77                  6  01/25/85 E-1763 -0      Raceway Plan, Auxiliary Building, Service Area, El 124, Area 76                  6  :!.2/20/84 E-1764-0, Sh 1 Raceway Plan, Auxiliary Building, Service Area, El 124, Area 35                  14 08/20/84 E-1764-0, Sh 2 Raceway Plan, Auxiliary Building, Service Area, El 124, Area 35                  4  10/13/83 E-1764-0, Sh 3 Raceway Plan, Auxiliary Building, Service Area, El 124, Area 35                  4  06/16/83 E-1767-0       Raceway Plan, Auxiliary Building, Service Area, El 124, Area 73                  20 10/10/85 E-1769-0       Raceway Plan, Auxiliary Building, Service Area, El 124, Area 72                  a  12/31/85 E-1773-0       Raceway Plan, Auxiliary Building, Service Area, El 137, Area 76                  7  Ol/23/S4 E-1777-0       Raceway Plan, Auxiliary Building, Service Area, El 137, Area 73                  19 12/31/85 29 of 35 HCGS-UFSAR                                                                                                Revision 14 July 26, 2005

TABLE 1.7-1 {Cont) (Historiea1 Info~tion)

                                                                                                                            *I FSAR Figure Drawing Number                         Title                                           Number   Rev        Date Raceway Plan, Turbine Building, El 54, Area 04                                  18      12/09/85 E~1804-0,  Sh 1 Raceway Plan, TUrbine Building, El 102, Area 41                                 20      02/13/85 E-1804-0, Sh 2  Raceway Plan, Turbine Building, El 102, Area 41                                 5       06/20/84 E-1815-1        Raceway Plan, Turbine Building, El 137, Area 03                                 13      12/22/85 E-1825-1        Raceway Plan, Turbine Building, El 137, Area 02                                 10      11/22/85 E:-1833-1, Sh 1 Raceway Plan, Turbine Building, El 102 & 120, Area 01                           20      11/22/85 E-1833-1, Sh 2  Raceway Sections & Details, Turbine Building, Bl 102 & 120, Area 01             4       11/22/85 E-1853-1, Sh    Raceway Plan, Turbine Building, El 102, Area 08                                 20      11/13/85 E-1853-1, Sh 2  Raceway Plan, Turbine Building, El 102, Area 08                                 6       08/26/83 E-1854-1        Raceway Plan, Turbine Building, El 120, Area 08                                 17      03/28/85 E-1863-1, Sh 1  Raceway Plan, Turbine Building, El 102 & 120, Area 07                           14      12/24/85 E-1863-1, Sh 2  Raceway Plan, Turbine Building, El 102 & 120, Area 07                           1       09/28/83 E-1865-l        Raceway Plan, Turbine Building, El 137 & 145, Area 07                           13      12/07/84 E-1875-l        Raceway Plan, Turbine Building, El 137, Area 06                                 13      ll./22/85 E-1903-1, Sh 1  Raceway Plan, Turbine Building, El 102, Area 12                                 1.9     11/13/85 E-1903-l, Sh 2  Raceway Plan, Turbine Building, El 102, Area 12                                 4       05/21./84 E-1925-1        Raceway Plan, Turbine Building, El 137, Area 10                                         11/22/85 E-1926-1, Sh 1  Raceway Plan, Turbine Building, El 171, Area 10                                 a       11/22/85 E-3020-0, Sh A  Logic Diagram, Station service Transformer Protection {4 sheets)                1       09/27/82 E-3030-0, Sh 1  Logic Diagram, Unit Protection                                                  2       06/10/85 E-3030-0, Sh 2  Logic Diagram, Unit Protection                                                  3       09/24/85 E-3031-0        Logic Diagram, Main Turbine Generator Excitation Control                        3       04/02/85 Logic Diagram, 13.8 kV Ring Bus Protection                                      0       09/16/82 30 of 35 HCGS-UFSAR                                                                                                     Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (H~stor~cal ~nformation)

                                                                                                                                    *I FSAR Figure Drawing Number                        Title                                                   Number   Rev        Date E-3040-0       Logic Diagram, 7.2 kV Station Power System, Switchgear Main                             10      ll/01/BS Circuit Breaker E-3041-0       Logic Diagram, 7.2 kV Station Power System Bus Differential Overcurrent                 3       10/19/83 and Under Voltage Protection E-3042-0       Logic Diagram, 7~2 kV Reactor Recirculation Motor-Generator Set                         9       10/11/85 Circuit Breaker E-3043-0       Logic Diagram, Recirculation Pump Motor Circuit Breaker Control                         3       10/25/84 E-3044-0       Logic Diagram, Station Power Switchgear Breaker Fail Relaying                           1       02/17/84 E-3050-0, Sh 1 Logic Diagram, 4.16 kV Station Power System Switchgear Main Circuit Breaker             13      ll/Ol./85 E-3050-0, Sh 2 Logic Diagram, 4.16 kV Station Power Switchgear Main Circuit Breaker                    5       11/01/85 Circuit Breaker E-3051-0, Sh 1 Logic Diagram, 4.16 kV Station Power System Switchgear Unit Sub                         10      1.1/01/85 Transformer Feeder Circuit Breaker E-3051-0, Sh 2 Logic Diagram 4.16 kV Station Power System Switchgear Unit Substation                   5       :l.l/01/85 E-3052-0, Sh 1 Logic Diagram 4.16 kV Station Power System Bus Differential                             2       11/23/82 Overcurrent and Undervoltage Protection.,

E-3052-0, Sh 2 Logic Diagram, 4.16 kV Station Power System Bus Differential 2 ll/23/82 Overcurrent and Undervoltage Protection E-3060-0 Logic Diagram, Class lE Station Power Switchgear, 4.16 kV System 13 11/01/85 Main Circuit Breaker E-3061-0 Logic Diagram, Class 1E Switchgear 4.16 kV Unit SUb Transformer Feeder 6 11/01/85 Circuit Breaker E-3062-0, Sh 1 Logic Diagram 4.16 kV Class lE BUS Differential Overcurrent and 3 11/14/83 Undervoltage Protection E-3062-0, Sh 2 Logic Diagram, 4.16 kV Class lE BUS Differential Overcurrent and 1 11/14/83 Undervoltage Protection E-3065-0, Sh 1 Logic Diagram, Diesel Generator Regular & Backup Relaying 5 J.l/14/84 E-3065-0, Sh 2 Logic Diagram, Diesel Genera~or Regulatory & Backup Relaying 5 08/20/85 31 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-l (Cont) (Historica1 Information) *I FSAR Figure Drawing Number Title Number Rev Date E-3080-0, Sh 1 Logic Diagram, Class lE Switchgear, 4.16 kv System Diesel General 9 11/01/BS Circuit Breaker E-3080-0, Sh 2 Logic Diagram, Class IE Switchgear, 4.16 kV System Diesel General 7 02/03/84 Circuit Breaker E-3081-0, Sh 1 Logic Diagram, Diesel Generator Control s 03/17/84 E-3081-0, Sh 2 Logic Diagram, Diesel Generator Control 7 09/13/85 E-3090-0, Sh 1 Logic Diagram, 125 v de system 6 05/15/85 E-3090-0, Sh 2 Logic Diagram, 125 v de System 3 11/14./84 E-3110-0 Logic Diagram, 250 v Diesel Generator System 4 03/01/BS E-3120-0 Logic Diagram, 120 V ac Uninterruptible Power System Alarms 5 06/27/85 E-3l.32-0 Logic Diagram, Unit Substation 480 V System Motor Control Center and 5 09/17/84 Feeder Circuit Breaker E-3133-0, Sh 1 Logic Diagram, Unit Substation 480 V System Feeder Circuit Breaker, 5 10/25/84 Non-lE Loads E-3133-0, Sh 2 Logic Diagram, Unit Substation 480 v Feeder Circuit Breaker 4 06/14/85 Non -lE: Loads E-3134-0 Logic Diagram, Unit Substation 480 V Feeder Circuit Breaker Alarm Input 7 10/25/84 E-3400-0, Sh 1 Logic Diagram, Electrical Distribution Alarm Input 4 11/18/83 E-3400-0, Sh 2 Logic Diagram, Electrical Distribution Alarm Input 2 11/lB/83 E-3999-0, Sh A Elec Loop Diagram, Transducers (12 sheets) 13 04/08/85 E-3999-0, Sh 11 Elec Loop Diagram, Circ Water Pump Motor Circuit Transducers 4 04/08/85 E-4068-1 Cable Block Diagram, Class lE 4 kV Station Power Main Circuit Breaker 2 07/06/BS E-4069-1 CBD, Class 1E 4.16 kV Station Power Main Circuit Breaker 152-40101 2 07/16/85 E-40/0-1 CBD, Class lE 4.16 kV Station Power Main Circuit Breaker 152-40201 2 07/16/85 E-6001-0, Sh l ESD, Reactor Recirculation Motor-Generator Set Drive Motor, 5 01/10/SS 7.2 kV Circuit Breaker 32 of 35 HCGS-UFSAR Revision 14 July 26,_2005

TABLE 1.7-1 (Cant) (Historical rn£ormation) *I FSAR Figure Drawing Nulliber Title Nulliber Rev Date E-6001-0, Sh 2 ESD, Reactor Recirculator Motor-Generator Drive Motor, 7.2 kV 10/04/85 Circuit Breaker and Motor-Generator Space Heaters E-6016-0, Sh 1 ESD, Reactor Recirculation Pump, Motor Circuit Breaker Control Circuit 2 04/25/84. E-6016-0, Sh 2 ESD, Reactor Recirculacion Pump, Motor Circuit Breaker Control 2 04/25/84 E-6022-0 ESD, Core Spray system, core Spray Pump Suction Valves 3 12/19/84 E-6023-0 ESD, Core Spray System, Core Spray Isolation Valves 3 06/03/85 E-6024-0 ESD, Core Spray System. Core Spray Minimum Flow Valves 3 01/14/85 E-6025-0 ESD. Core Spray System, Core Spray Reactor Isolation Valves 3 07/24/84 E-6026-0 ESD, Core Spray System Core Spray Test Return Valves 4 12/19/84 E-6067-0, Sh A ESD, Solenoid Pilot Valves "An For Safety/Relief Valves 3 04/30/84 DSV-F0135, F & K E-6067-0, Sh 2 E:SD, Solenoid Pilot Valves "A" for Safety/Relief Valves PSV-F013L & P 4. 11/14/85 E-6067-0, Sh 4 ESD, Solenoid Pilot Valves "A" for Safety/Relief valves PSV-F013H, F &: M 4 11/14/85 E-6074-0 ESD, High Pressure Coolant Injection, Turbine Auxiliary Oil Pump (HPCI) 4 05/10/85 E-6074-l, Sh l ESD, HPCI Condensate & Vacuum Pump Motors 4 Ol/17/85 E-6074-1, Sh 2 ESD, HPCI Condensate and Vacuum PUmp Motors 5 06/03/85 E-6082-1, Sh 1 ESD, RCIC System Pump Motors Vacuum & Condensate Pumps 4 01/17/85 E-6082-1, Sh 2 ESD, RCIC System Pump Motors Vacuum & Condensate Pumps 4 01/17/85 E-6086-0 ESD, RCIC Isolation Cooling System AOVs 3 05/18/84 E-6089-0 ESD, Recirculation System Turbine Monitoring Circuits in Remote 9 11/11/85 Shutdown Panel E-6107-0, Sh 1 ESD. Nuclear Steam Supply Shutoff System Reactor Water Cleanup 2 04/30/84 Isolation Valve E-6107-0, Sh 2 ESD, Nuclear Steam SUpply System Reactor Water Cleanup Valve 2 04/30/84 E-6109-0, Sh 1 ESD, Nuclear Boiler Line Drain Isolation Valves 5 10/18/85 33 of 35 HCGS-UFSAR Revision l4

                                                                                                                       .July 26, 2005

TABLE 1.7-1 (Cont) (Historical Information)

                                                                                                                                *I FSAR Figure Drawing Number                        Title                                               Number   Rev        Date E-6109-0, Sh 2 ESD, Nuclear Boiler Main Steam Line Drain Isolation Valves                          2        06/03/85 E-6231-0, Sh A ESD, RHR System MOVs w/o RSP-Remote Panel (14 sheets)                               ~2       09/26/85 E-6234-0, Sh A ESD, RHR System with RSP                                                            9        09/26/85 E-6235-0       ESD, RHR Testable Check Valve Bypass                                                6        09/28/85 E-6239-0       ESD, RHR Heat Exchanger Pressure & Level Control Solenoid Valves                    2        09/26/85 E-6253-D, Sh A ESD, Reactor Water Cleanup System MOVs                                              5        08/08/85 E-6402-0       ESD, Main Steam Stop Valves                                                         1        05/18/84 E-6404-0, Sh A ESD, RHR System BOP Valves                                                          6        09/26/85 E-6404-D, Sh 3 ESD, RHR System Reactor Building Isolation Valve                                    4        04/18/85 E-6406-D       ESD, 480 V Circuit Breaker Control, Reactor Recirculation System                    1        05/lS/84 Motor-Generator Set Lube Oil Pumps E-6416-0       ESD, Reactor Water Cleanup System MOVs                                              2        04/01/85 E-6419-0       ESD, Reactor Protector System Control Rod Drive {CRD) Scram Discharge               1        10/19/83 Volume Outboard Vent & Drain Vlvs Ind E-6422-0       ESD. CRD Rydraulic Reactor Building Isolation Valve HV-4005                         2        05/18/84 E-6431-0       ESD, HPCI Pump Turbine Emergency Core Cooling System Jockey Pump 1AP228             3        01/25/85 E-6433-0       ESD, Reactor core Isolation Cooling System Pump Turbine Emergency Core              4        07/22/85 cooling System 1BP22B E-6435-0, Sh 1 ESD, RHR System Jockey Pump DP22B                                                   3        10/12/84 E-6435-0, Sh 2 ESD, RHR Jockey Pump ICP22S                                                         2        10/12/84 E-6439-0       ESD, HPCI Suppression Pool Isolation Valves                                         2        01/10/BS E-6440-0       ESD, HPCI Pump Turbine Vacuum Pump Discharge to Cond IHV-4922                       2        04/1.9/8-4 E-6441-0, Sh 1 ESD, Class lE 4.16 kV Circuit Breaker Control, RHR Pumps 1AP202,                    5        05/10/85 lCP202, 1DP202 E-6441-0, Sh 2 ESD, 4.16 kV Circuit Breaker RHR Pump 1AP202, 1CP202, 1DP202                        5        10/03/SS 34 of 35 HCGS-UFSAR                                                                                                         Revision 14 July 26, 2005

TABLE 1.7-1 (Cont) (Histo*ical Information) *I FSAR Figure Drawing Number Title Number Rev Date E-6442*0 ESD, 4 . 16 kV Circuit Bre-aker Control, Core Spray Pumps 6 07/11/85 E-6443*0 ESD, 4.16 kV Circuit Breaker control RHR Pump 1BP202 7 10/03/85 E-6531-0 ESD, 4 kV & 6.9 kV Motor Space Heaters 2 01/23/84 E-6603-0, Sh 1 RSP-lOC399 Transfer Switch Contact UT Table 4 03/09/83 35 of 35 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-2 (Histo~ical Information) *I FIGURE INDEX FOR PLANT SYSTEMS P&lD FSAR ~ S stem Fiqure Number Revision Date M-00-0, Sh ~ P&ID Legend 1-13-1 8 08/30/85 M-00-0, Sh 2 P&ID Legend 1.13-1 9 09/09/85 M-0~-1 Main Steam 10.3-1 16 ~2/10/85 M-02-~ Extraction Steam 10.2-4 9 05/01/85 M-03*1 vents & Drains Heaters 1&2 9 06/05/85 M-04-1 Vents & Drains Heaters 3,4,5,&6 9 09/09/85 M-05-1, Sh 1 Condensate 10.4-5 8 1.2/06/84 M-05-1, Sh 2 Condensate ~0.4-5 10 11/0B/85 M-05-1, Sh 3 condensate 10.4-5 12 12/04/85 M-06-1 Feedwater 10.4-6 9 11/03/85 M-07-1 Condenser Air Removal 10.4-1 15 12/13/85 M-08-0, Sh 1 Condensate & Refueling Water Storage &'Transfer 9.2-B 15 22/04/85 M-08-0, Sh 2 Condensate & Refueling Water Storage & Transfer 9.2-13 9 10/03/85 M-09-1, Sh 1 Circulating Water 10.4-3 11 11/15/85 M-09-1, Sh 2 Circulating Water 10 .4-3 8 07/26/85 M-10-l, Sh 1 Service Water 9.2-2 11 12/04/85 M-10-1, Sh 2 Service Water 9.2-3 11 10/03/85 M-10-1. Sh 3 Service Water 8 10/11/85 M-11-1, Sh 1 Safety Auxiliaries Cooling, Reactor Building 9.2-4 11 07/25/85 M-11-1, Sh 2 Safety Auxiliaries Cooling, Reactor Building 9.2-4 12 11/15/85 M-11-1, Sh 3 Safety Auxiliaries Cooling, Reactor Building 9.2-4 5 10/03/85 M-12 -1 Safety Auxiliaries Cooling, Auxiliary Building 9.2-5 9 22/30/85 1 of 10 HCGS-UFSAR Revision'14 July 26, 2005

TABLE 1. 7-2 (Cont) (Historical Information) *I P&ID FSAR Number s stem Fi9!:!re Number Revision Date M-B-0 Reactor Auxiliaries Cooling 9.2-16 10 OS/01/85 M-13-1 Reactor Auxiliaries Cooling 9.2-17 12 H/26/85 M-14-1, Sh Turbine Auxiliaries Cooling 9.2-6 9 J.l/03/85 M-14*1, Sh 2 TUrbine Auxiliaries Cooling 9.2-6 11 ll/08/85 M-15-0, Sh l Compressed Air 9.3-1 14 11/15/85 M-15*0, Sh 2 Compressed Air 9.3-2 14 12/30/85 M-15-0, Sh 3 Compressed Air 8 09/27/BS M-15-0, Sh 4 Compressed Air 9.3-3 8 02/01/85 M-15-0, Sh 5 Compressed Air 1 12/15/82 M-15-1 Breathing Air 9.5-32 B :ll/08/85 M-16-1, Sh 1 Condensate Demineralizer 10.4-4 10 l2/D4/S5 M-16-1, Sh 2 Condensate Deminer<J.lizer 10.4-4 9 11/03/85 I M-17-0 Fresh Water Pretreatment 9.2-8 6 12/13/85 M-18-0, Sh 1 Demineralized Water Makeup Storage & Transfer 9.2-7 12 10/21/85 M-18-0, Sh 2 Demineralized Water Makeup Storage & Transfer 9.2-7 10 .ll/08/85 M-18-0, Sh Demineralized water Makeup Storage & Transfer 9.2-7 7 10/03/BS M-19-1, Sh 1 Lube Oil 10 12/04/85 M-19-1, Sh 2 Lube Oil 6 05/01/85 M-19-1, Sh 3 Lube Oil 10 11/08/85 M-19-l, Sh 4 Lube Oil 4 10/18/84 M-19-1, Sh 5 Lube Oil 5 11/03/85 M-l9-l, Sh 6 Lube Oil 5 12/10/85 M-20-0, Sh 1 Auxiliary Boiler Fuel Oil System 9.5-31 7 12/10/85 I 2 of 10 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-2 (Cont) (Historical Information)

                                                                                                                         *I P&!D                                                                               FSAR I

~ S stem Fisure Number Revision Date M-20-0, Sh 2 Auxiliary Boiler Fuel Oil System 9.5-31 5 05/01/85 M<Zl-0, Sh 1 Auxiliary Steam 9.5-30 10 11/03/85 M-21-0, Sh 2 Auxiliary Steam 9.5-30 9 H/OB/85 M-22*0, Sh 1 Fire Protection 9.5-13 18 12/30/85 M-22-0, Sh 2 Fire Protection 9.5-14 16 12/13/85 M-22-0, Sh 3 Fire Protection 9.5-15 13 12/30/85 M-22*0, Sh 4 Fire Protection 9.5-16 8 12/30/85 M-22-0, Sh 5 Fire Protection 9.5-17 11 11/26/85 M-22-0, Sh 6 Fire Prot.ection 9.5-18 10 07/25/85 M-22-0, Sh 7 Fire Protection 9.5-19 a 12/30/85 I M-23-0 Process Sampling 9.3-4 8 01/07/85 M-23-1, Sh 1 Process Sampling 9.3-4 9 11/26/85 M-23-1, Sh 2 Process Sampling 9.3-4 a 11/03/85 M-23-1, Sh 3 Process Sampling B 06/05/75 M-23-l, Sh 4 Process Sampling A 06/05/75 M-24-0, Sh 1 Circulating water Hypochlorination 7 08/26/85 M-24*0, Sh 2 Circulating Water Acid Injection 6 06/14/85 M-24-0, Sh 3 service Water Hypochlorination a ll/18/85 M-24-0, Sh 4 Circulating Water caustic and scale In.hibitor Injection 2 ll/08/85 M-25-1, Sb 1 Plant Leak Detection 11.5-3 5 11/26/85 M-25-1, Sh 2 Plant Leak Detection ll.S-3 4 11/03/85 M-25-1, Sh 3 Plant Leak Detection 11.5-3 4 ll/03/85 M-26-1, Sh 1 Radiological Monitoring System 11.5-1 4 10/16/85 3 of 10 HCGS-UFSA.~ Revision 14 July 26, 2005

TABLE 1.7-2 (Cont} (Historical In£ormation} *I P&JD FSAR ~ S stem Figure Number Revision Date M-26-l, Sh 2 Radiological Monitoring System 11.5-1 3 10/16/85 M-27 Not used M-28-1 Generator Gas Control 10.2-3 B 11/18/85 M-29-1 Turbine Sealing Steam 10.4-2 9 07/28/85 M-30-1, Sh 1 Diesel Engine Auxiliary Systems 9.5-22 14 12/04/BS M-30-1, Sh 2 Diesel Engine Auxiliary Systems 9.5-25 8 10/21/85 M-30-1, Sh 3 Diesel Engine Auxiliary Systems 9.5-28 10 11/:lB/85 M-31-1, Sh 1 Reactor Feed Pump Turbine Stearn System 10.4-7 5 03/07/85 M-31-1, Sh 2 Reactor Feed Pump Turbine Steam System 10.4-7 3 12/09/83 I M-32 Not used A 11/07/18 M-33-0 Low Volume & Oily, wastewater Treatment!: ll.S-2 3 09/20/85 M-34 Not used M-35 Guardhouse Air Flow Diagram 2 12/13/85 M-36-0 Guardhouse Air Control Diagram 3 10/25/84 M-37-0 Guardhouse Chilled Water System 4 09/28/84 M-38-0, Sh 1 Post-accident Sampling System 9.3-5 4 09/24./85 M-3B-O, Sh 2 Post-accident Sampling System 9.3-5 3 10/21/BS M-39 Not used M-40 Not used M-41-1, Sh 1 Nuclear Boile:.:- 5.1-3 12 11/04/85 M-41-1, Sh 2 Nuclear Boiler 5 ~-3 10 11/04/85 M-42-1, Sh 1 Nuclear Boiler Vessel Instrumentation 5.1-4 B 12/13/85 M-42-1, Sh 2 Nuclear Boiler vessel Instrumentation 5.1-4 7 12/13/85 4 of ~o HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-2 {Cent) (Historiea~ In£ormation) *I P&ID FSAR ~ S stem Figure Number Revision M-43-1, Sh 1 Reactor Recirculation System 5.4-2 12 12/13/85 M-43-1, Sh 2 Reactor Recirculation system 5.4-2 6 12/19/85 M-44-1 Reactor Water Cleanup 5.4-17 11 11/03/85 M-45-1 Cleanup Filter/Demineralizer 5.4-19 11 10/03/85 M-46-1 Control Rod Drive Hydraulic Part A 4.6-5 9 06/27/85 M-47-1, Sh l Control Rod Drive Hydraulic - Part B 4.6-6 11 11/26/85 M-47-1, Sh 2 Control Rod Drive Hydraulic - Part B 4.6-6 2 05/05/85 M-48-1 Standby Liquid Control 9.3-B 8 11/03/85 M-49-1 Reactor Core Isolation cooling 5.4-8 l1 11/26/85 M-50-1 RCIC Pump Turbine 5.4-9 13 11/03/85 M-51-1, Sh 1 Residual Heat Removal 5.4-13 15 12/04/85 M-51-1, Sh 2 Residual Heat Removal 5.4-13 15 12/04/BS M-52-1 core Spray 6.3-7 13 11/16/85 M-53-1, Sh 1 Fuel Pool Cooling & Torus Water Cleanup 9.1-5 15 12/10/85 M-53-1, Sh 2 Fuel Pool Cooling & Torus water Cleanup 9.1-S 12 11/08/85 M-54-0 Fuel Pool Filter Demineralizer 9 l-6 9 12/19/85 M-55-1 High Pressure Coolant Injection 6.3-1 16 12/10/85 M-56-1 HPCI Pump Turbine 6 3-2 12 09/09/85 M-57-1 Containment Atmosphere Control 6.2-29 13 11/03/85 M-58-1 containment Hydrogen Recombination System 6.2-30 5 11/03/85 M-59-1, Sh 1 Primary Containment Instrument Gas 9.3-11 10 11/04/BS M-59-1, Sh 2 Primary Containment Instrument Gas 9.3-11 5 l.l./26/85 M-60-1 Primary Containment Leakage Rate Testing 6.2-H 9 10/21/85 5 of 10 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-2 (Cont.) (Historica~ ~nfor.mation)

                                                                                                                                  *I P&ID                                                                                FSAR Number                                   S stem                                 Figure Number         Revision          Date M-61-0       Equipment and Floor Drainage                                         9.3-7 sh 2 of           5             02/14/85 M-61-1, Sh 1 Equipment and Floor Drainage                                         9.3-7 sh 3 of 3         12            07/05/85 M-61-1, Sh 2 Equipment and Floor Drainage                                         9.3-7 sh 1 of 3         8             07/05/85 M-62-0, Sh 1 Liquid Radwast.e Equipment: Drain Processing                         11.2-1                  13            11/18/85 M-62-0, Sh 2 Liquid Radwaste Equipment Drain Processing                           11.2-1                  8             06/14/85 M-63-0, Sh 1 Liquid Radwaste Flood Drain    Processing                            11.2-2                  12            11/18/85 M-63-0, Sh 2 Liquid Radwaste Flood Drain Processing                               11.2-2                  8             06/14/85 M-64-0       Liquid Radwaste Chemical Waste Processing                            11.2-3                  10            11/03/85 M-65-0, Sh 1 Liquid Radwaste Regenerant Wast:e Procej:>sing                       11.2-4                  9             08/30/85 M-65-0, Sh 2 Liquid Radwaste Regenerant waste Processing                          11.2-4                  8             07/16/85 M-65-0, Sh 3 Liquid Radwaste Regenerant waste Processing                          11.2-4                  7             ll/03/85 M-66-0       Solid Radwaste Collection                                            11.4-1                  12            12/30/85 M-67-0, Sh 1 Solid Radwaste Volume Reduction System                               11.4-2                  9             12/.19/85 M-67-0, Sh 2 Solid Radwaste Volume Reduction System                               11.4-3                  7             12/19/85 M-68-0, Sh 1 Solid Radwaste Processing Solidification                             11.4-4                  6             09/27/85 M-68-0, Sh 2 Solid Radwaste Processing Solidification                             11.4-5                  6             09/27/85 M-68-0, Sh 3 Solid Radwaste Processing Solidification                             11.4-6                  7             OB/13/85 M-68-0, Sh 4 solid Radwaste Processing Solidification                             11.4-7                  8             08/20/85 M-68-0, Sh 5 Not used M-68-0, Sh 6 Not used M-66-0, Sh 7 Solid Radwaste Processing Solidification                             11.4-8                  3             12/10/SS M-68-0, Sh a Solid Radwaste Processing Solidification                             11.4-9                  6             11/03/85 M-69-0, Sh 1 Gaseous Radwaste Recombiner                                          11.3-2                  12            ::Ll/OB/85 6 of 10 HCGS-UFSAR                                                                                                       Revision 14 July 26, 2005

TABLE 1.7-2 (Conti (Historical Information) *I P&ID FSAR Number S stem Fisure Number Revision Date M-69-0, Sh 2 Gaseous Radwaste Recombiner ll 3-3 9 12/10/BS M-69-0, Sh 3 Gaseous Radwaste Recombiner 2 11/03/85 M-70*0, Sh 1 Gaseous Radwaste Ambient Charcoal Treatment System 11.3-4 6 10/ll/85 M-70-0, Sh 2 Gaseous Radwaste Ambient Charcoal Treatment System 11.3-5 4 07/0S/85 M-70-0, Sh 3 Gaseous Radwaste Ambient Charcoal Treatment System 6 09/27/85 I M-71-0 Liquid Nitrogen for Purge and Containment Inerting 3 09/09/85 M-72*1 Main Steam Isolation Valve Sealing System 6.7-1 6 11/26/85 M-73-0 Administration Facility Chilled Water , 6 12/04/85 M-74-0 Administration Facility Control Diagram 7 12/04/85 M-75-1, Sh 1 Turbine Building Air Flow Diagram 9.4-11 12 12/04/85 M-75-1, Sh 2 Not used M-76-1 Reactor Building Air Flow Diagram 9.4*3 9 12/13/BS M-77-1 Drywell Air Flow Diagram 9.4-13 5 10/11/85 M-78-1 Auxiliary Building Control Area Air Flow Diagram 9.4*1 13 11/03/85 M-79-0, Sh l Technical Support Center Air Flow Diagram 9.4-7 12 12/30/85 M-79-0, Sh 2 Technical Support Center Air Flow Diagram 9.4-10 4 09/13/85 M*B0-0 Administration Facility Air Flow Diagram 7 07/26/83 M-81-0, Sh 1 Service Water Intake Structure Miscellaneous 9.4-17 5 03/28/83 Structures Air Flow Diagrams M-81-0, Sh 2 Miscellaneous Structures and Yard Buildings Air Flow Diagrams 9.4-19 6 11/03/SS M-81-0, Sh 3 Miscellaneous Structures and Yard Buildings Air Flow Diagrams 5 12/17/82 M-82*1, Sh 1 TUrbine Building Supply & Exhaust Control Diagram 9.4-12 13 10/21/85 M-82*1, Sh 2 Not used 7 of 10 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1. 7~2 (Cant) (Historical Information) *I P&ID FSAR Number S stem Figure Number Revision Date M-83-1 Reactor Building Supply Control Diagram 9.4-4 11 07/25/85 M-84-1 Reactor Building Exhaust Control Diagram 9.4-5 13 12/10/85 M-85-1, Sh 1 Auxiliary Building Diesel Area Air Flow Diagram 9.4-15 11 09/27/85 M-85-1, Sh 2 Auxiliary Building Diesel Area Air Flow Diagram 9.4-15 6 09/27/85 M-86-1 Drywell Control Diagram 9.4-14 4 10/21/85 M-87-1, Sh 1 Chilled Water System 9.2-14 11 H/26/85 M-87-1, Sh 2 Chilled water system 9.2-14 11 12/04/85 M-87-1, Sh 3 Chilled Water System 9.2-H 7 l.l/03/85 M-87-l, Sh 4 Chilled Water System 9.2-14 a 12/04/85 M-88-1, Sh 1 Auxiliary Building Diesel Area Control Diagram 9.4-16 10 12/10/85 M-88-1, Sh 2 Auxiliary Building Diesel Area Control Diagram 9.4-16 5 12/B/85 M-89-1 Auxiliary Building Control Area Control Diagram 9.4-2 14 12/19/85 M-90-1., Sh 1 Auxiliary Building Control Area Chilled Water System 9.2-15 11 12/10/85 M-90-1, Sh 2 Auxiliary Building Control Area Chilled Water System 9.2-15 11 12/10/85 M-90-l, Sh 3 Auxiliary Building control Area Chilled water System 9.2-15 7 12/10/85 M-91-0, Sh 1 Auxiliary Building Radwast:e Area Air Flow Diagram 9.4-6 13 11/26/85 M-91-0, Sh 2 Auxiliary Building Radwast:e Area Air Flow Diagram 9.4-6 6 12/14/84 M-91-0, Sh 3 Auxiliary Building Radwaste Area Air Flow Diagram 9.4-6 3 11/0S/85 M-92-0, Sh 1 Auxiliary Building Radwaste Area Control Diagrams 9.4-9 12 10/21/85 M-92-0, Sh 2 Auxiliary Building Radwast:e Area Control Diagrams 9-4-9 2 12/19/85 M-93-0, Sh 1 Auxiliary Building Service Area Control Diagram 9-4-8 11 12/19/85 M-93-0, Sh 2 Technical Support Center Control Diagram 9.4-8 5 10/21/85 M-94-0 Roof Drainage System 4 11/lS/85 8 of 10 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-2 (Cont) (Histo~ic~1 Information)

                                                                                                                              *I P&ID Number                                   s stem                                 Figure Number M-95-0       Miscellaneous Structures & Yard Buildings Control Diagram            9.4-18 M-96-0, Sh 1 Plant Heating M-96-0, Sh 2 Plant Heating M-96-0, Sh 3 Plant Heat:.ing M-97-0, Sh 1 Building & Equipment Drains, Aux Bldg, Radwaste Sys El 54'           9.3-12 M-97-0, Sh 2 Building & Equipment Drains, Aux Bldg Control & Diesel Areas;        9.3-12 Chemical Waste Systems M-97-0, Sh 3 Building & Equipment Drains, Aux Bldg Radwaste Sys Floor El 66'-0"   9.3-12 to 172'-3" M-97-0, Sh 4 Building & Equipment Drains, Aux Bldg Radwaste Sys Floor El 65'-0"   !L3-12 to 153'-0" M-97-0, Sh 5 Building &   Equipment Drains, Intake Structure                      9 3-13 M-97-1, Sh 1 Building &   Equipment Drains, TUrbine Bldg Floor El 54' -0" to      9.3-14, Sh 1 of 4 102'-0" M-97-1, Sh 2 Building & Equipment Drains, Reactor Bldg                            9.3-15 M-97-1, Sh 3 Building &   Equipment Drains, Turbine Bldg Floor El 120'-0" to      9.3-14, Sh 2 of 4 188. -6" M-97-2, Sh 1 Floor and Equipment Drains, Turbine Building                         9.3-14,Sh 3 of 4 M-97-2, Sh 2 Not used M-97-2, Sh 3 Building Drains, Turbine Building Fl. El. 120' -0" to 171' -0"       9.3-14, 4 of 4 M-98-0, Sh 1 Domestic Water System                                                9.2-10 M-98-0, Sh 2 Domestic Water System                                                9.2-9 M-99-0, Sh 1 Building Sewage M-99-0, Sh 2 Building Sewage                                                      9.2-11 M-5001       Fire Protection    & Detection Plan, El 54'0" 9 of 10 HCGS-UFSAR                                                                                                       Revision 14 July 26, 2005

TABLE 1.7-2 (Cont) (Historical In£ormation) *I P&ID FSAR Number s stem Figure Number Revision Date M-5002 Fire Protection & Detection Plan, El 77' -0" 8 11/05/85 M-5003 Fire Protection & Detection Plan, El 102' -0" 9 11/05/85 M-5004 Fire Protection & Detection Plan, El 120'-Qtt & 132'-0" 8 11/05/85 M-5005 Fire Protection & Detection Plan, El 137'-0" & 145'-0" 9 11/05/85 M-5006 Fire Protection & Detection Plan, El 155'-3" & 163'-6" 11/05/85 M*5007 Fire Protection & Detection Plan, El 171'-0" & 178'-0" & 201'-0" s 11/05/SS M-5008 Fire Protection .. Detection Section A-A & B-B 4 09/09/85 M-5009 Fire Protection & Detection section c-c & D-D 4 09/09/85 M-5010 Fire Protection & Detection Section E-E & F-F 4 09/09/BS M-5011 Fire Protection & Detection Intake Structure Plan, El 93',100',114', & 122' 7 11/05/85 M-5012 Fire Protection & Detection Intake Structure Plan, El 93' ,107* and 6 11/05/85 Sections M-5013 Fire Protection & Detection Auxiliary Boiler, Circulating Water 0 07/23/84 Structure & Fire Pump House 10 of 10 HCGS-UFSAR Revision 14 July 26, 2005

TABLE L 7-3 CONTROL AND INSTRUMENTATION DRAWINGS (Historical Information) *I FSAR Figure Drawin9 Number Title Number ~ Date LOGIC DIAGRAMS J-00-0 Standard Symbols 10 08/29/85 J-01-0, Sh 1 Main Steam 6 12/16/83 J-01-0, Sh 2 Main Steam 5 12/16/83 J-01-0, Sh 3 Main Steam 2 06/14/82 J-01-0, Sh 4 Main steam 2 06/14/82 J-01-0, Sh 5 Main Steam 5 12/16/83 J-01-0, Sh 6 Main Steam 5 12/16/83 J-01-0, Sh 7 Main Steam 3 06/14/82 J-01-0, Sh 8 Main Steam 5 12/16/83 J-01-0, Sh 9 Main Steam 3 06/14/82 J-01-0, Sh 10 Main Steam 5 12/16/83 J-01-0, Sh 11 Main Steam 4 06/14/82 J'-01-0, Sh 12 Main Steam 4 06/14/82 J-01-0, Sh 13 Main Steam 2 06/14/82 J-01-0, Sh 14 Main Steam 3 06/14/82 J-01-0, Sh 15 Main Steam 1 10/17/80 J-02-0, Sh 1 Extraction Steam 9 11/08/85 J-02-0, Sh 2 Extraction Steam 4 11/08/82 J-02-0, Sh 3 Extraction Steam 5 11/0B/82 J-02-0, Sh 4 Extraction Steam 3 12/06/82 J 0, Sh 5 Extraction Steam 7 11/08/85 J-02-0, Sh 6 Extraction Steam 4 11/08/82 J-02-0, Sh 7 Extraction Steam 6 09/30/85 J-02-0, Sh 8 Extraction Stearn 6 11/08/82 J-02-0, Sh 9 Extraction Steam 6 08/04/83 J'-02-0, Sh 10 Extraction Steam 3 08/04/83 J-02-0, Sh 11 Extraction Steam 1 08/04/83 J-03-0, Sh 1 vents and Drains, Heaters 1 &2 5 06/14/82 J-03-0, Sh 2 Vents and Drains , Heaters 1 & 2 4 06/14/82 J-03-0, Sh 3 Vents and Drains, Heaters 1 & 2 3 06/14/82 J-03-0, Sh 4 Vents and Drains, Heaters 1 & 2 4 06/14/82 J-03-0, Sh 5 Vents and Drains, Heaters 1 & 2 5 06/14/82 J 0' Sh 1 Vents and Drains, Heaters 3, 4, 5, 6 6 08/30/B3 J-04-0, Sh 2 Vents and Drains, Heaters 3, 4, 5, 6 4 06/14/82 J-04-0, Sh 3 Vents and Drains, Heaters 3, 4, 5, 6 5 06/14/82 J'-04-0, Sh 4 Vents and Drains, Heaters 3, 4, 5, 6 5 06/14/82 J-04-0, Sh 5 Vents and Drains, Heaters 3, 4, 5, 6 s 06/14/82 J-04-0, Sh 6 Vents and Drains, Heaters 3. 4, 5, 6 2 06/14/82 J-04-0, Sh 7 Vents and Drains, Heaters 3. 4, 5, 6 5 06/H/82 J-04-0, Sh 8 vents and Drains, Heaters 3' 4, 5, 6 6 08/30/83 J-04-0, Sh 9 vents and Drains, Heaters 3. 4, 5, 6 5 06/H/82 1 of 18 HCGS-UFSAR Revision 14 July 26, 2005

TABLE

                                                                    ~-7-3 (Cont)

FSAR Figure (Historiea~ In£ormation) *I Drawing Number Title Number Rev Date LOGIC DIAGRAMS J-05-0, Sh I Condensate System 10 10/02/85 J-05-0, Sh 2 Condensate System 7 10/02/85 J-05-0, Sh 3 Condensate System 6 10/02/85 J-05-0, Sh 4 condensate System 3 06/14/82 J-05-0, Sh 5 Condensate System 8 10/02/85 J-05-0, Sh 6 condensate System 3 06/18/82 J-05-0, Sh 7 Condensate System 5 U/05/64 J-05-0, Sh 8 Condensate System 5 04/18/83 J-05-0, Sh 9 Condensate System 4 06/14/82 J-05-0, Sh 10 Condensate System 6 11/05/84 Sh 11 Condensate System 4 06/14/82 Sh 12 Condensate System 5 11/05/84 J-05-0, Sh 1) Condensate System 4 06/14/82 J-05-0, Sh 14 Condensate System 7 ll./OS/84 J-05-0, Sh 15 Condensate System 6 11/05/84 J-05-0, Sh 16 Condensate System 1 06/14/82 J-05-0, Sh l7 Condensate System 1 06/14/82 J-05-0, Sh 18 Condensate System 2 ll/05/84 J-06-0, Sh 1 Feedwat:er System 10 06/05/SS J-06-0. Sh 2 Feedwater System 4 06/07/82 J-06-0, Sh 3 Feedwater System 6 04/11/84 J-06-0, Sh 4 Feedwater System 3 06/07/82 J-06-0, Sh 5 Feedwater System 6 06/05/85 J-06-0, Sh 6 Feedwater System 6 12/16/83 J-06-0, Sh 7 Feedwater System 5 12/16/83 J-06-0, Sh 8 Feedwater system l 06/07/82 J-07-0, Sh 1 Condenser Air Removal System 11 ll/22/85 J-07-0, Sh 2 Condenser Air Removal System 3 06/11/82 J-07-0, Sh 3 Condenser Air Removal System 3 06/ll/82 J-07-0, Sh 4 Condenser Air Removal System 3 06/11/82 J-07-0, Sh s Condenser Air Removal System 2 06/11/82 J-07-0, Sh 6 Condenser Air Removal System 3 06/11/83 J-07-0, Sh 7 Condenser Air Removal System 3 11/06/82 J~07-0, Sh 8 Condenser Air Removal System 2 06/11/82 J-07-0, Sh 9 Condenser Air Removal System 6 05/15/83 J-07-0, Sh 10 Condenser Air Removal System 9 11/22/85 J-07-0, Sh U. Condenser Air Removal System 4 05/15/83 J-07-0, sh 12 Condenser Air Removal System 7 01/12/84 J-07-0, Sh B Condenser Air Removal System 1 01/12/84 J-08-0, Sh 1 Condensate & Refueling Water Storage & Transfer 13 ll/04/85 J-08-0, Sh 2 condensate & Refueling Water Storage & Transfer 6 11/04/BS J-08-0, Sh 3 condensate & Refueling water Storage & Transfer 6 11/04/85 J-08-0, Sh 4 Condensate & Refueling Water Storage & Transfer 5 12/03/84 2 of 18 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-3 (Cant) FSAR Figure (Histo~ic~1 Information) *I Drawin51 Number Title Number Rev Date LOGIC DIAGRAMS J-08-0, Sh 5 Condensate & Refueling Water Storage & Transfer 3 06/15/82 J-08-0, Sh 6 Condensate & Refueling Water Storage & Transfer 8 12/03/84 J-08-0, Sh 7 Condensate & Refueling Water Storage & Transfer 4 06/15/82 J-08-0, Sh 8 Condensate & Refueling Water Storage & Transfer 11 12/03/84 J-08-0, Sh 9 Condensate & Refueling Water Storage & Transfer 6 11/04/85 J-08-0, Sh 10 condensate & Refueling Water Storage & Transfer 7 12/03/84 J-08-0, Sh ll Condensate & Refueling Water Storage & Transfer 2 08/27/80 .J-09-0, Sh 1 Circulating water System a l.l/04/85 J-09-0, Sh 2 Circulating water System 7 11/04/85 J-09-0, Sh 3 Circulating Water System 4 06/14/82 J-09-0, Sh 4 Circulating Water Syscem 5 02/13/84 J-09-0, Sh 5 Circulating Water System 4 12/03/84 J-09-0, Sh 6 Circulating Water System 5 02/13/84 J-09-0, Sh 7 Circulating water System 7 11/04/85 J-09-0, Sh 8 Circulating Water system 4 02/13/84 J-09-0, Sh 9 Circulating Water System 5 02/13/84 J-09-0, Sh 10 Circulating Water System 5 02/13/84 J-09-0, Sh 11 Circulating Water System 5 02/13/84 J-09-0, Sh 12 Circulating Water System 5 02/12/84 J-09-0, Sh 13 Circulating Water System 5 02/13/84 J-09-0, Sh 14 Circulating Water System 4 02/13/84 J-0.9-0, Sh 15 Circulating Water System 3 06/14/82 J-09-0, Sh 16 Circulating Water System B 11/04/85 J-09-0, Sh 17 Circulating Water System 7 12/03/84 J-09-0, Sh l8 Circulating Water Syst;ern 3 02/13/84 J-09-0, Sh 19 Circulating wacer System 1 06/14/82 J-09-0, Sh 20 Circulating Water System 2 02/13/84 J-09-0, Sh 21 Circulating Water System 2 02/13/84 J-10-0, Sh 1 St;ation Service Water System 7.3-20 13 12/10/85 J-10-0, Sh 2 Station Service Water System 9 09/16/84 J-10-0, Sh 3 Station Service Water System 7 05/02/83 J-10-0, Sh 4 Station Service Water System 9 09/16/84 J'-10-0, Sh 5 Station Service water System 8 12/10/85 J-10-0, Sh 6 Station Service Water System 9 09/16/84 J-10-0, Sh 7 Station Service water System 8 05/02/83 J-10-0, Sh S Station Service water System 7 09/16/84 J-10-0, Sh 9 Station Service Water System 7 09/16/84 J-10-0, Sh 10 Station Service Water System s 09/16/84 J-10-0, Sh 11 Station Service Water System 7 09/16/84 J-10-0, Sh 12 Station Service Water System 4 12/12/83 J-10-0, Sh 13 Station Service Water System B 09/16/84 J-10-0, Sh 14 Station Service Water System 9 12/10/85 J-10-0, Sh 15 Station Service Water System 10 09/16/84 3 of 18 HCGS-UFSAR Revision 14 July 26, 2005

Drawing Number TABLE 1.7-3 [Contl FSAR Figure Number Rev Date (Historical Inform.a tion) *I Title LOGIC DIAGRAMS J-10-0, Sh 16 Station Service Water System 8 09/1£/84 J-10-0, Sh 17 Station Service Water System B 09/16/84 J-10-0, Sh 18 Station Service Water System 8 09/16/84 J'-10-0, Sh 19 Station Service Water System 7 05/02/83 J-10-0, Sh 20 Station Service Water System 7 09/16/84 .J-10-0, Sh 21 Station Service Water System 3 12/10/85 J-10-0, Sh 22 Station Service Water System 5 12/10/85 J-10-0, Sh 23 Station service Water System 6 09/16/84 J-10-0, Sh 24 Station Service Water System 7 08/30/83 J-10-0, Sh 25 station service water System 5 09/16/84 J-10-0, Sh 26 Station service Water System 4 12/10/85 J-10-0, Sh 27 Station Service Water System 4 12/10/85 J-10-0, Sh 28 Station Service Water system 1 06/rl/82 J~lo~o. Sh 29 Station Service Water System 2 09/16/84 J-10-0, Sh 30 Station Service Water System 3 09/16/84 J-10-0, Sh 31 Station Service Water System 3 12/10/85 J-11-0, Sh 1 Safety Auxiliaries Cooling 7.3-21 11 10/07/85 J-11-0, Sh 2 Safety Auxiliaries Cooling 7 10/07/85 J'-11-0, Sh 3 Safety Auxiliaries Cooling 5 10/07/85 J-11-0, Sh 4 Safety Auxiliaries Cooling 7 10/07/85 J-11-0, Sh 5 Safety Auxiliaries Cooling 6 10/07/85 J-11-0, Sh 6 Safety Auxiliaries Cooling 6 10/18/84 J-11-0, Sh 7 Safety Auxiliaries Cooling 6 10/01/85 J'-11-0, Sh 8 Safety Auxiliaries Cooling 6 10/07/85 J-11-0, Sh 9 Safety Auxiliaries Cooling 5 10/17/84 J-11-0, Sh 10 Safety Auxiliaries Cooling 1 01/05/79 J-11-0, Sh 11 Safety Auxiliaries Cooling 1 01/05/79 J-11-0, Sh 12 Safety Auxiliaries Cooling 4 08/06/82 J-11-0, Sh 13 Safety Auxiliaries cooling 4 08/06/82 J-11-0, Sh 14 Safety Auxiliaries Cooling 3 10/17/84 J-11-0, Sh 15 Safety Auxiliaries Cooling 5 10/18/84 J-11-0, Sh 16 Safety Auxiliaries cooling 7 10/07/85 J'-11-0, Sh 17 Safety Auxiliaries cooling 4 04/lB/83 J-11-0, Sh 18 Safety Auxiliaries Cooling 5 10/l7/84 J-11-0, Sh 19 Safety Auxiliaries Cooling 6 10/07/85 J-ll-0, Sh 20 Safety Auxiliaries Cooling 4 08/06/82 J-11-0, Sh 21 Safety Auxiliaries Cooling 6 10/07/85 J-11-0, Sh 22 Safety Auxiliaries Cooling 8 10/l7/84 J-11-0, Sh 23 Safety Auxiliaries cooling 4 10/17/84 J-ll-0, Sh 24 Safety Auxiliaries Cooling 5 10/17/84 J-ll-0, Sh 25 Safety Auxiliaries Cooling 4 04/18/83 J-11-0, Sh 26 Safety Auxiliaries cooling 3 10/17/84 J-11-0, Sh 27 Safety Auxiliaries Cooling 6 07/23/84 4 of 18 HCGS-UFSAR .Revision 14 July 26, 2005

TABLE L 7-3 (Cant) FSAR Figure (Historical Information) *I Drawing Number Number Rev Date LOGIC DIAGRAMS J-ll-0, Sh 28 Safety Auxiliaries Cooling 3 08/06/82 J-11-0, Sh 29 Safety Auxiliaries Cooling 3 l.0/07/85 J-11-0, Sh 30 Safety Auxiliaries cooling 4 10/17/84. J-11-0, Sh 31 Safety Auxiliaries Cooling 2 04/18/83 J-11-0, Sh 32 Safety Auxiliaries Cooling 2 04/18/83 J-11-0, Sh 33 Safety hUA~~~~~~~'~ Cooling 3 10/17/84 J-13-0, Sh 1 Reactor '"""-J. .LJ.<<.L cooling 11 09/0S/84 J-13-0, Sh 2 Reactor Auxiliaries Cooling 6 10/29/82 J-13 -0' Sh 3 Reactor Auxiliaries Cooling 5 10/29/82 J-13-0, Sh 4 Reactor Auxiliaries Cooling 6 09/05/84 J-13-0, Sh 5 Reactor Auxiliaries Cooling 6 09/05/84 J-13-0, Sh 6 Reactor Auxiliaries Cooling 9 09/05/84 J-13-0, Sh 7 Reactor Auxiliaries Cooling 5 05/23/83 J-13-0, Sh a Reactor Auxiliaries Cooling 4. 10/29/82 J-13-0, Sh 9 Reactor Auxiliaries cooling 6 09/05/84 J-13-0, Sh 10 Reactor Auxiliaries cooling 5 l.0/29/82 J-13-0, Sh l.l Reactor Auxiliaries cooling 8 09/0S/84 J-13-0, Sh 12 Reactor Auxiliaries cooling 7 08/25/83 J-13-0, Sh 13 Reactor Auxiliaries Cooling 3 12/16/83 J-13-0, Sh 14 Reactor Auxiliaries cooling 2 12/16/83 J-13-0, Sh 15 Reactor Auxiliaries Cooling 0 10/29/82 J-14-0 Turbine Auxiliary Cooling 3 01/04/84 H-15-0 Compressed Air System 7 10/22/85 J-15-0, Sh 1 Breathing Air System 2 05/18/84 J-15-D, Sh 2 Breathing Air system 0 05/23/83 J-15-0, Sh 3 Breathing Air System 2 05/18/84 J-15-0, Sh 4 Breathing Air System 1 12/22/83 J-16-0, Sh 1 Condensate Demineralizer 5 04/18/83 J-16-0, Sh 2 Condensate Demineralizer 4 04/18/83 J-17-0, Sh 1 Fresh Water Supply 2 12/16/83 J-17-0, Sh 2 Fresh Water Supply 1 12/16/83 J-17-0, Sh 3 Fresh Water Supply 0 11/18/82 J-17-0, Sh 4 Fresh Water Supply 0 ll./18/82 J-17-0, Sh 5 Fresh Water Supply 2 12/16/83 J-18-0, Sh 1 Demineralized Water Makeup Storage & Transfer 7 10/17/84 J-18-0, Sh 2 Demineralized Water Makeup Storage & Transfer 3 05/28/82 J-18-0, Sh 3 Demineralized Water Makeup Storage & Transfer 3 05/28/82 J-18-0, Sh 4 Demineralized water Makeup Storage & Transfer 4 12/16/83 J-18-0, Sh 5 Demineralized water Makeup Storage & Transfer 5 10/17/84 J-19-0, Sh 1 Lube Oil 9 05/10/85 J-19-0, Sh 2 Lube Oil 7 05/02/83 J-19-0, Sh 3 Lube Oil 5 06/21/82 J-19-0, Sh 4 Lube Oil 8 05/10/85 5 of 18 HCGS-UFSAR Revision l4 July 26, 2~05

Drawing Number TABLE 1. 7-3 (Cont) FSAR Figure (Historical Information) *I Title Number Rev Date J-19-0, Sh 5 5 05/:10/85 J-19-0, Sh 6 Lube Oil 1 06/21/82 J-19-0, Sh 7 Lube Oil 2 06/2:1/82 J-19-0, Sh a Lube Oil 5 05/10/85 J-19-0, Sh 9 Lube Oil 5 05/02/83 J-19-0, Sh 10 Lube Oil 6 05/10/85 J-19-0, Sh 11 Lube Oil 6 05/10/85 J-19-0, Sh 12 Lube Oil 6 05/02/83 J-19-0, Sh 13 Lube Oil 6 05/10/85 J-19-0, Sh 14 Lube Oil 5 05/10/85 J-19-0, Sh 15 Lube Oil 6 05/10/85 J-20-0, Sh 1 Auxiliary Boiler Fuel Oil System 7 01/22/85 J-20-0, Sh 2 Auxiliary Boiler Fuel Oil System 6 05/11/84 J-20-0, Sh 3 Auxiliary Boiler Fuel Oil System 2 01/22/85 J-20-0, Sh 4 Auxiliary Boiler Fuel Oil System 1 06/02/83 J-21-0 Auxiliary Steam 1 06/02/83 H-22-0 Fire Protection - Fire Water 10 12/08/83 J-25-0, Sh 1 Plant Leak Detection 4 04/26/83 J-25-0, Sh 2 Plant Leak Detection 4 04/26/83 J-25-0, Sh 3 J?lant Leak Detection 3 04/26/83 J-25-0, Sh 4 Plant Leak Detection 4 04/26/83 J-25-0, Sh 5 Plant Leak Detection 3 04/26/83 J-25-0, Sh 6 Plant Leak Detection 3 04/26/83 J-25-0, Sh 7 Plant Leak Detection 1 04/26/83 J-25-0, Sh 8 Plant Leak Detection 0 04/26/83 J-25-0, Sh 9 Plant Leak Detection 0 04/26/83 J-25-0, Sh 10 Plant Leak Detection 0 04/26/83 J-25-0, Sh 11 Plant Leak Detection 0 04/26/83 J-25-0, Sh 12 Plant Leak Detection 0 04/26/83 J-26-0, Sh 1 Radiation Monitoring System 1 10/:12/84 J-26-0, Sh 2 Radiation Monitoring System 1 10/12/84 J-26-0, Sh 3 Radiation Monitoring System 1 10/12/84 J-28-0, Sh 1 Generator Gas control 6 12/16/83 J-28-0, Sh 2 Generator Gas Control 3 12/16/83 J-2.9-0, Sh 1 Turbine Sealing Steam 7 04/26/83 J-29-0, Sh 2 Turbine Sealing Steam 4 06/2:1/82 J-29-0, Sh 3 Turbine Sealing Steam 4 06/21/82 J-29-0, Sh 4 Turbine Sealing Steam 3 06/21/82 J-29-0, Sh 5 Turbine sealing Steam 5 06/21/82 J-29~0. Sh 6 Turbine Sealing Steam 2 06/21/82 J-29-0, Sh 7 Turbine Sealing Steam 5 04/26/83 J-30-0, Sh 1 Diesel Engine Auxiliary Systems 2 04/29/82 J-30-0, Sh 2 Diesel Engine Auxiliary Systems 1 04/29/83 6 of 18 BCGS-DFSAR Revision i4 July 26, 2005

TABLE 1.7-3 tCont) FSAR Figure {Historical Information)

                                                                                                                                 *I DrawinS~ Number                            Title                              Number   Rev    Date LOGIC DIAGRAMS J-30-0, Sh 3    Diesel Engine Auxiliary Systems                                        1   04/29/82 J-31-0, Sh l    Reactor Feed Pump Turbine Steam System                                 9   06/24/85 J-31-0, Sh 2    Reactor Feed Pump Turbine Steam System                                 5   12/14/83 J-31-0, Sh 3    Reactor Feed Pump Turbine Steam Syst:em                                4   09/11/84 J-31-0, Sh 4    Reactor Feed Pump Turbine Stearn System                                4   12/14/83 J-31-0,  Sh S   Reactor Feed Pump Turbine Steam System                                 8   06/24/85 J-31-0,  Sh 6   Reactor Feed Pump Turbine Stearn System                                7   06/24/85 J-3l-O,  Sh 7   Reactor Feed Pump Turbine Steam System                                 7   06/24/85 J-31-0,  Sh B   Reactor Feed Pump Turbine Steam System                                 7   09/11/84 J-31-0,  Sh 9   Reactor Feed Pump Turbine Steam System                                 6   12/14/83 J-31-0,  Sh 10  Reactor Feed Pump Turbine Steam System                                 5   OS/26/83 J-31*0,  Sh ll  Reactor Feed Pump Turbine Steam System                                 6   06/24/85 J-31-0,  Sh 12  Reactor Feed Pump Turbine Steam System                                 5   12/14/83 J-31-0,  Sh 13  Reactor Feed Pump Turbine Steam System                                 6   09/11/84 J-31-0,  Sh 14  Reactor Feed Pump Turbine Steam System                                 5   08/26/83 J-31-0,  Sh 15  Reactor Feed Pump Turbine Steam System                                 3   12/14/83 J-31-0,  Sh 16  Reactor Feed Pump Turbine Steam system                                 3   12/14/83 J-31.-0, Sh 17  Reactor Feed Pump Turbine Steam System                                 3   12/14/83 J-31-0,  Sh 18  Reactor Feed Pump Turbine Steam System                                 0   08/26/83 J-38~0, Sh 1    Post Accident Sampling System                              9.3-6       1   10/24/84 J-38-0, Sh 2    Post Accident Sampling System                                          1   10/24/84 J~41-0, Sh l    Nuclear Boiler                                             7.3-4       9   11/06/85 J-41-0, Sh 2    Nuclear Boiler                                                         5   ll/06/85 J-41-0, Sh 3    Nuclear Boiler                                                         7   08/30/84 J-41-0, Sh 4    Nuclear Boiler                                                         5   08/30/84 J-41-0, Sh 5    Nuclear Boiler                                                         5   04/04/83 J-41-0, Sh 6    Nuclear Boiler                                                         5   06/30/84 J-4l-O, Sh 7    Nuclear Boiler                                                         3   06/19/82 J-41-0, sh a    Nuclear Boiler                                                         3   06/19/82 J-41-0, Sh 9    Nuclear Boiler                                                         4   08/30/84 J-41-0, Sh 10   Nuclear Boiler                                                         2   06/B/82 J-41-0, Sh 11   Nuclear Boiler                                                         4   12/10/83 J-41-0, Sh 12   Nuclear Boiler                                                         4   12/10/83 J-41-0, Sh 13   Nuclear Boiler                                                         5   11/06/85 J-41-0, Sh 14   Nuclear Boiler                                                         3   OB/30/84 J-41-0, Sh 15   Nuclear Boiler                                                         3   11/06/85 J-41-0, Sh 16   Nuclear Boiler                                                         2   l.l./06/BS J-41-0, Sh 16A  Nuclear Boiler                                                         0   11/06/85 J-42-0, Sh 2    Nuclear Boiler Vessel Instrumentation                                  5   12/05/83 J-42-0, Sh 3    Nuclear Boiler Vessel Instrumentation                                  4   12/05/83 J-42-0, Sh 4    Nuclear Boiler Vessel Instrumentation                                  2   06/14/82 J-42-0, Sh 5    Nuclear Boiler Vessel Inst.rumentation                                 5   12/0S/83 J-43-0, Sh 1    Reactor Recirculation System                                           13  11/04/85 7 of 18 HCGS-UFSAR                                                                                                          Revision 14 July 26, 2005

TABLE 1.7-3 (cent) FSAR Figure (H1storica~ Info~tion) *I Drawing Number Title Number ~ Date J-43-0, Sh 2 System B 11/04/85 J-43-0, Sh 3 Reactor Recirculation System 7 11/04/85 J-4.3-0, Sh 4 Reactor Recirculation System 8 06/24/85 J-43-0, Sh 5 Reactor Recirculation System 3 J-43-0, Sh 6 Reactor Recirculation System 5 10/12/84 J-4.3-0, Sh 7 Reactor Recirculation System 4 06/21/83 J-4.3-0, Sh 8 Reactor Recirculation System 4 10/12/84. J-43-0, Sh 9 Reactor Recirculation System 7 11/04/85 J-43-0, Sh 10 Reactor Recirculation System 1 06/2:1/83 J-44-0, Sh 1 Reactor Water Cleanup 11 10/29/85 J-44-0, Sh 2 Reactor water Cleanup 7 10/29/85 J-44-0, Sh 3 Reactor Water Cleanup 6 08/30/84 J-44-0, Sh 4 Reactor Water Cleanup 6 08/30/84 J-44-0, Sh 5 Reactor Water Cleanup 7.3-10 s OB/30/84 J-44-0, Sh 6 Reactor Water Cleanup 3 12/14/83 J-44~0, Sh 7 Reactor Water Cleanup 4 12/14/83 J-44-0, Sh B Reactor Water Cleanup 2 12/14/83 J-45-0, Sh 1 Cleanup Filter/Demineralizer 2 12/10/83 J-45-0, Sh 2 Cleanup Filter/Demineralizer 1 OB/30/84 J-46-0, Sh 1 Control Rod Drive Hydraulic 7 02/11/85 J-46-0, Sh 2 control Rod Drive Hydraulic 6 12/10/83 J-46-0, Sh Control Rod Drive Hydraulic 5 12/10/83 J-46-0, Sh 4 Control Rod Drive Hydraulic 06/14/82 J-46-0, Sh 5 Control Rod Drive Hydraulic 3 06/14/82 J-46-0, Sh 6 Control Rod Drive Hydraulic 4 02/11/85 J-46-0, Sh 7 Control Rod Drive Hydraulic 2 02/11/85 J-46-0, Sh 8 Control Rod Drive Hydraulic 3 06/14/83 J-46-0, Sh 9 Control Rod Drive Hydraulic 3 06/14/83 J-47-0, Sh l Control Rod Drive Hydraulic - Part B 2 12/05/83 J-47-0, Sh 2 control Rod Drive Hydraulic - Part B 2 12/05/83 J-47-0, Sh 3 Control Rod Drive Hydraulic Part B 2 12/05/83 J-48-0, Sh 1. Standby Liquid Control 7.4-4 7 11/01/85 J-48-0, Sh 2 Standby Liquid Control 7.4-4 7 11/01/85 J-48-0, Sh 3 Standby Liquid Control s 11/01/BS J-48-0, Sh 4 Standby Liquid Control 3 05/24/83 J-48-0, Sh 5 Standby Liquid Control 1 12/14/83 J-49-0, Sh 1 Reactor Core Isolation Cooling System 7-4-2 13 12/10/85 J-49-0, Sh 2 Reactor Core Isolation Cooling System 8 12/10/85 J-49-0, Sh Reactor Core Isolation Cooling System 4 09/11/84 J-49-0, Sh 4 Reactor Core Isolation Cooling System 4 09/11/84 J-49-0, Sh 5 Reactor Core Isolation Cooling System 6 ~0/01/85 J~49-0, Sh SA Reactor Core Isolation Cooling System 2 10/0~/85 J-49.:.0, Sh 6 Reactor Core Isolation cooling System 6 12/10/BS 8 of 18 HCGS-tJFSAR Revision 14 July 26, 2005

TABLE 1.7-3 (Cont) FSAR Figure (Historical Xnformation) *I Title Number Rev Date LOGIC DIAGRAMS J-49-0, Sh 7 Reactor Core Isolation Cooling System 7 12/10/85 J-49-0, Sh a Reactor Core Isolation Cooling System 4 09/ll/84 J-49-0, Sh 9 Reactor Core Isolation Cooling System 6 06/24/85 J-49-0, Sh 10 React:or Core Isolation Cooling System 3 06/16/82 J-49-D, Sh 11 Reactor Core Isolation Cooling System 2 06/16/82 J-49-0, Sh 12 Reactor Core Isolation Cooling System 4 10/0l/85 J-49-0, Sh 13 Reactor Core !solation Cooling System 6 10/01/BS J-49-0, Sh 14 Reactor Core Isolation Cooling System 3 06/16/83 J-49-0, Sh 15 Reactor Core Isolation Cooling System 3 10/01/85 J-49-0, Sh 16 Reactor Core Isolation Cooling System 4 10/01/85 J-49-0, Sh 17 Reactor Core Isolation cooling System 1 06/16/83 J-49-0, Sh 18 Reactor Core Isolation Cooling System 1 09/ll/84 J-49-0, Sh 19 Reactor Core Isolation Cooling System 1 05/15/83 J-49-0, Sh 20 Reactor Core Isolation Cooling System 0 10/01/85 J-50-0, Sh 1 RCIC Pump Turbine 7.4-.2 12 12/10/BS J-50-0, Sh 2 RCIC Pump Turbine 9 12/10/85 J-50-0, Sh 3 RCIC Pump Turbine 2 10/29/85 J-50-0, Sh 4 RCIC Pump Turbine 1 10/29/85 J-50-0, Sh 5 RCIC Pump Turbine 2 09/11/84 J-50-0, Sh 6 RCIC Pump Turbine 3 10/29/85 J-50-0, Sh 7 RCIC Pump Turbine 2 10/29/85 J-50-0, Sh a RCIC Pump Turbine 2 12/16/83 J-50-0, Sh 9 RCIC Pump Turbine 3 10/29/BS J-50-0, Sh 10 RCIC Pump Turbine 1 08/30/83 J-51-0, Sh 1 Residual Heat Removal 7.3-8 10 08/29/BS J-51-0, Sh 2 Residual Heat Removal 6 09/10/84 J-51-0, Sh Residual Heat Removal 5 09/10/84 J-51-0, Sh 3A Residual Heat Removal 0 07/12/82 J-51-0, Sh 4 Residual Heat Removal 5 09/10/84 J-51-0, Sh 4A Residual Heat Removal 1 09/10/84 J-51-0, Sh 5 Residual Heat Removal 6 09/10/84 J-51-0, Sh 6 Residual Heat Removal 5 09/10/84 J-51-0, Sh 7 Residual Heat Removal 6 09/10/84 J-51-0, Sh 7A Residual Heat Removal 1 12/23/83 J-51-0, Sh s Residual Heat Removal 6 09/10/84 J-51-0, Sh SA Residual Heat Removal 0 07/12/82 J-51-0, Sh 9 Residual Heat Removal 5 09/l0/84 J-51-0, Sh 9A Residual Heat Removal 2 09/10/84 J-51-0, Sh 10 Residual Heat Removal 5 09/10/84 J-51-0, Sh lOA Residual Heat Removal 2 09/10/84 J-51'-0, Sh 11 Residual Heat Removal 5 09/10/84 J-51-0, Sh 11A Residual Heat Removal 2 09/10/84 J-51-0, Sh 12 Residual Heat Removal 5 09/10/84

                                                        .9 of 18 HCGS-UFSAR                                                                                                       Revision 14 July 26, 2005

Drawing Number Title TABLE 1. 7-3 (Cant) FSAR. Figure Number Rev Date (Historical Information)

                                                                                                                                     *I LOGIC DIAGRAMS J-Sl-0,  Sh l2A Residual Heat Removal                                                       l   09/10/84 J-51-0,  Sh 13  Residual Heat Removal                                                       4   09/10/84 J-51-0,  Sh 14  Residual Heat Removal                                                       4   09/10/84 J-51-0,  Sh 15  Residual Heat Removal                                                       5   09/10/64 J-51-0,  Sh 16  Residual Heat Removal                                                       5   08/29/83 J-51-0,  Sh 17  Residual Hea.t Removal                                                      5   08/29/83 J-51-0,  Sh 18  Residual Heat Removal                                                       6   12/22/83 J-51-0,  Sh 19  Residual Heat Removal                                                       5   08/29/83 J-51-0,  Sh 20  Residual Heat Removal                                                       2   0'7/12/82 J-51-0,  Sh 21  Residual Heat Removal                                                       5   09/10/84 J-51-0,  Sh 22  Residual Heat Removal                                                       2   07/12/82 J-51-0,  Sh 23  Residual Heat Removal                                                       3   12/22/83 J-51-0,  Sh 24  Residual Heat Removal                                                       3   12/22/83 J-51-0,  Sh 25  Residual Heat Removal                                                       2   osno/s4 J-51-0,  Sh 2SA Residual Heat Removal                                                       1   12/22/83 J-51-0,  Sh 26  Residual Heat Removal                                                       1   12/22/83 J-51-0,  Sh 2/  Residual Heat Removal                                                       2   12/22/83 J-51-0,  Sh 28  Residual Heat Removal                                                       2   12/22/83 J-51-0,  Sh 29  Residual Heat Removal                                                       2   12/22/83 J-52-0,  Sh 1   Core Spray System                                              7.3-6        11  08/29/85 J-52-0,  Sh 2   Core Spray System                                                           4   05/02/83 J-52-0,  Sh 3   Core Spray System                                                           5   08/24/84 J-52-0'  Sh 4   Core Spray System                                                           5   OB/24/84 J'-52-0, Sh 5   Core Spray System                                                           4   08/24/84 J-52-0'  Sh 6   Core Spray System                                                           3   05/02/83 J-52-0,  Sh 7   Core Spray System                                                           6   05/06/85 J-52-0,  Sh B   Core Spray System                                                           5   12/12/83 J-52-0,  Sh 9   Core Spray System                                                           4   05/06/85 J-52-0,  Sh 10  core Spray System                                                           4   08/24/84 J-52-0,  Sh 11  Core Spray System                                                           3   12/12/83 J-52-0,  Sh 12  Core Spray System                                                           4   08/24/84 J-53-0,  Sh 1   FUel Pool cooling and  Torus Water Cleanup                                  9   10/29/85 J-53-0,  Sh 2   Fuel Pool Cooling and  Torus Water Cleanup                                  8   10/29/85 J-53-0,  Sh 3   Fuel Pool Cooling and  Torus water Cleanup                                  5   04/18/83 J-53-0,  Sh 4   FUel Pool Cooling and  Torus water Cleanup                                  7   10/06/84 J-53-0,  Sh 5   Fuel Pool cooling and  Torus Water Cleanup                                  6   10/29/85 J-53-0,  Sh 6   Fuel Pool Cooling and  Torus Water Cleanup                                  s   10/06/84 J-53-0,  Sh 7   Fuel Pool Cooling and  Torus Water Cleanup                                  4. 10/06/84.

J-53-0, Sh 8 Fuel Pool Cooling and Torus water Cleanup 6 10/06/84. J-53*0, Sh 9 Fuel Pool Cooling and Torus Water Cleanup 5 10/06/84 J-53-0, Sh 10 Fuel Pool Cooling and Torus Water Cleanup 7 10/29/85 J-53-0, Sh 11 Fuel Pool Cooling and Torus Water Cleanup 4 12/05/83 J-53-0, Sh 12 Fuel Pool Cooling and Torus Water Cleanup 3 10/29/85 10 of 18 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-3 (Cont) FSAR Figure (Histor~eal Information) *I Drawin9. Number Title Number Rev Date LOGIC DIAGRAMS J-55-0, Sh 1 High pressure Coolant Injection 7.3-2 12 12/10/85 J-55-0, Sh 2 High Pressure Coolant Injection 6 08/30/84 J-55-0, Sh 3 High Pressure Coolant Injection 6 08/30/84 J-55-0, Sh 4 High Pressure Coolant Injection 7 12/10/85 J-55-0, Sh 4A High Pressure Coolant Injection 1 12/10/85 J-55-0, Sh 5 High Pressure Coolant Injection 6 12/10/85 J-55-0, Sh 6 High Pressure Coolant Injection 6 06/25/85 J-55-0, Sh 7 High pressure Coolant Injection 7 12/10/85 J-55-0, Sh B High Pressure Coolant Injection 6 06/25/85 J-55-0, Sh 9 High Pressure Coolant Injection 06/17/82 J-55-0, Sh 10 High Pressure Coolant. Injection 3 06/17/82 J-55-0, Sh 11 High pressure coolant. Injection 5 12/10/83 J-55-0, Sh 12 High Pressure Coolant:: Injection 6 12/1.0/85 J-55-0, Sh 13 High Pressure Coolant: Injection 2 06/17/82 J-55-0, Sh 14 High Pressure Coolant Injection 3 06/25/85 J-55-0, Sh 15 High Pressure Coolant Injection 2 08/30/84 J-56-0, Sh 1 HPCI pump Turbine 11 02/11/85 J-56-0, Sh 2 HPCI Pump Turbine 7 10/12/84 J-56-0, Sh 3 HPCI Pump Turbine 7 02/11/85 J-56-0, Sh 4. HPCI Pump Turbine 2 10/12/84 J-56-0, Sh 5 HPCI Pump Turbine 2 02/ll/85 J-56-0, Sh 6 HPCI Pump Turbine 1 12/05/83 J-56-o. Sh 7 HPCI Pump Turbine 1 10/12/84 J-56-0, sh a HPCI Pump Turbine 2 12/05/83 J-56-0, Sh 9 HPCI Pump Turbine 3 10/12/84 J-56-0, Sh 10 HPCI Pump Turbine 2 02/11/85 J-57-0, Sh 1 Containment Atmosphere Control 7.3-14 10 11/22/85 J-57-0, Sh 2 Containment Atmosphere Control 7 04/11/83 J-57-0, Sh 3 Containment Atmosphere Control 7 03/25/85 J-57-0, Sh 4 Containment Atmosphere Control 6 06/17/82 J-57-0, Sh 5 Containment Atmosphere Control B 11/22/85 J-57-0, Sh 6 Containment Atmosphere control 6 H/22/85 J-57-0, Sh 7 containment Atmosphere Control 8 11./22/85 J-57-0, Sh 8 Containment Atmosphere Control 7 04/l:l./83 J-57-0, Sh 9 Containment Atmosphere control 4 06/17/82 J-57-0, Sh 10 Containment Atmosphere Control 6 OB/25/83 J-57-0, Sh 11 Containment Atmosphere control 5 08/23/83 J-57-0, Sh 12 Containment Atmosphere Control 4 ll/22/85 J-57-0, Sh 13 Containment Atmosphere Control 5 04/11/83 J-57-0, Sh 14 Containment Atmosphere Control 4 06/17/82 J-57-0, Sh 15 Containment Atmosphere Control 5 04/ll/83 J-57-0, Sh 16 Containment Atmosphere control 2 06/17/82 J-57-0, Sh 17 Containment Atmosphere control 2 06/1"7/82 11 of 18 HCGS-UFSAR Revision 14 July 26, 2005

Drawing Number Title TABLE 1.7-3 (Cant) FSAR Figure (Historical Information) *I Number Rev Date LOGIC DIAGRAMS J-57-0, Sh 18 Containment Atmosphere Control 3 11/22/85 J-57-0, Sh 19 containment Atmosphere Control 1 04/1.1/83 J-57-0, Sh 20 Containment Atmosphere control l 04/ll/83 J-58-0, Sh 1 Containment Hydrogen Recombination System 7.3-15 8 03/25/85 J-58-0, Sh 2 Containment Hydrogen Recombination System 7 03/25/85 J-58-0, Sh 3 Containment Hydrogen Recombination System 6 08/23/83 J-58-0, Sh 4 Containment Hydrogen Recombination System 1 04/18/83 J-59-0, Sh l Primary Containment Instrument Gas 7.3-22 10 11/08/85 J-59-0, Sh 2 Primary containment Instrument Gas 7 03/25/85 J-59-0, Sh 3 Primary Containment Instrument Gas 5 04/18/83 J-59-0, Sh 4 Primary Containment Instrument Gas 4 04/18/83 J-59-0, Sh 5 Primary Containment rnstrument Gas 7 12/05/83 J-59-0, Sh 6 Primary Containment rnstrument Gas 9 11/08/85 J-59-0, Sh 7 Primary Containment Instrument Gas 6 03/25/85 J-59-0, Sh 8 Primary Containment Instrument Gas 6 08/25/83 J-59-0, Sh 9 Primary Containment Instrument Gas 2 03/25/85 J-59-0, Sh 10 Primary Containment Instrument Gas 1 04/18/83 J-60-1 Primary containment Leakage Rate Testing 1 12/05/83 J-61-0, Sh 1 Liquid Radwaste Collection 9 12/27/84 J-61-0, Sh 2 Liquid Radwast:e Collection 6 12/27/84 J-61-0, Sh 3 Liquid Radwaste Collection 8 12/27/84 J-61-0, Sh 4 Liquid Radwaste Collection 6 01/26/84 J-61-0, Sh 5 Liquid Radwaste Collection 2 01/25/84 J-61-0, Sh 6 Liquid Radwaste Collection 2 12/27/84 J-66-0, Sh 1 Solid Radwaste Collection 7 11/14/84 J-66-0, Sh 2 Solid Radwaste Collection 1 04/26/83 J-69-0, Sh 1 Gaseous Radwaste-Recombination 9 10/29/85 J-69-0, Sh 2 Gaseous Radwaste-Recombination 4 02/17/83 J-69-0, Sh 3 Gaseous Radwast:e-Recombination 7 10/29/85 J-69-0, Sh 4 Gaseous Radwaste-Recombination 3 07/23/82 J-.69-0, Sh s Gaseous Radwaste-Recombination 4 01/23/82 J-69-0, Sh 6 Gaseous Radwaste-Recombination 6 12/03/84 J-69-0, Sh 7 Gaseous Radwaste-Recombination 4 02/17/83 J-69-0, Sh 8 Gaseous Radwaste-Recombination 4 02/17/83 J-69-0, Sh 9 Gaseous Radwaste-Recombination 6 12/03/84 J-72-0, Sh l Main steam Isolation Valve Sealing System 7.3-17 ? 10/29/85 J-72-0, Sh 2 Main Steam Isolation Valve Sealing System 5 10/29/85 J-72-0, Sh 3 Main Steam Isolation Valve Sealing system 4 02/28/85 J-72-0, Sh 4 Main Steam Isolation Valve Sealing System 2 01/30/81 J-72-0, Sh 5 Main Steam Isolation Valve Sealing System 5 10/29/85 J-72-0, Sh 6 Main Steam Isolation Valve Sealing System 2 01/30/81 J-72-0, Sh 7 Main Steam Isolation Valve Sealing System 2 Ol/30/81 J-72-0, Sh B Main Steam Isolation Valve Sealing System 3 04./18/83 12 of lB HCGS-UFSAR Revision 14 July 26, 2005

Drawing Number Title TABLE 1.7-3 (Cont} FSAR Figure Number Rev Date (H~sto~~eel Information) *I J-72-0, Sh 9 Valve sealing System 04/18/83 J-72-0, Sh 10 Main Steam Isolation Valve Sealing System 5 12/10/83 J-72-0, Sh 11 Main Steam Isolation Valve sealing System 4 08/23/83 J-72-0, Sh 12 Main Steam Isolation Valve Sealing System 4 12/10/83 J-72-0, H-73-0 H-74-0 Sh 13 Main Steam Isolation Valve Sealing System Administration Facility Administration Facility

                                                                                                .2 2

12/10/83 07/26/83 I 2 07/26/83 H-82-0 Turbine Building Supply & Exhaust 12 10/29/85 H-83-0 Reactor Building Supply 7.3-18 14 10/29/85 H-84-0 Reactor Building Exhaust & FRVS Vent 7.3-19 11 09/20/85 H-86-0 Drywell-Control 10 07/17/85 H-87-0 Chilled Water System 9 07/31/85 H-88-0 Auxiliary Building Diesel Area 7.3-24 13 10/23/85 H-89-0 Auxiliary Building Control Area 7.3-16 14 10/22/85 H-90-0 Auxiliary Building Control Area Chilled Water System 7.3-23 11 09/20/85 H-92-0 Auxiliary Building - Radwaste Area 11 09/09/85 H-93-0 Auxiliary Building Service Area 11 08/13/85 H-95-0 Miscellaneous Structures and Yard Building 7.3-25 9 10/22/85 H-96-0 Plant Heating 12/27/82 J-98-0; Sh 1 Domestic Water System 0 06/07/82 J-98-0, Sh 2 Domestic Water System 0 06/07/82 J-98-0, Sh 3 Domestic Water System 0 06/07/82 J-100-0 Turbine Miscellaneous Auxiliaries 8 08/27/85 J-101-0 Out of Service Status Display 6 09/27/85 J-102-0 High Radiation and LOCA/Isolation Signals Fanout 7.3-26 6 10/30/85 J-103-0, Sh 1 Remote Shutdown Panel Takeover Fanout 7 11/08/85 J-103-0, Sh 2 Remote Shutdown Panel Takeover Fanout 5 11/08/85 J-103-0, Sh 3 Remote Shutdown Panel Takeover Fanout 6 ll/08/85 J-103-0, Sh 5 Remote Shutdown Panel Takeover Fanout 5 11/08/85 J-103-0, Sh 6 Remote Shutdown Panel Takeover Fanout 2 11/08/85 J-103-0, Sh 8 Remote Shutdown Panel Takeover Fanout 2 11/08/85 J-104-0 Excess Flow Check Valves 5 11/22/85 J-105-0 Sequencer Fanout 7.3-27 6 08/28/85 J-106-0 Bus Power Fail Fanout 5 07/13/83 J-107-0 Emergency Load Sequencer 7.3-28 3 ll/14/84 J-108-0 Miscellaneous Alarm Systems 4 09/30/85 J-109-0 Redundant Reactivity Control System 2 09/28/84 INSTRUMENTATION LOCATION DRAWINGS J-JOOOl-0 Instrument Location Drawing, Typical Legend and General Notes 4 03/24/83 J-JOlOl-1 Unit 1, Turbine Building Instrument: (TBI) Location Plan, el 54'-0" Area 1 4 06/23/83 J-J0l02-l Unit 1, TBI Location Plan, El 77'-0" Area 1 2 11/04/82 l3 of 18 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-3 (COnti FSAR Figure (H1storical Info~tion) *I Drawing Number Title Number Rev Date J-J0l03-l & 120' -0" Area 1 3 10/17/83 J-J0201-l Unit 1, TBI Location Plan, El 54'-0" Area 2 2 10/08/82 J-J0202-l Unit 1, TBI Location Plan, £1 77' -0" Area 2 3 11/11/82 J-J0203-l Unit l, TBI Location Plan, El 102'-0" Area 1 2 07/02/82 J-J0205-l Unit 1, TBI Location Plan, El 137'-0" Area 2 1 05/07/82 J-J030l-1 Unit 1, TB! Location Plan, El 54'-0" Area 3 3 10/08/82 J-J0302-l Unit 1, TB! Location Plan, El 77'-0" Area 3 2 11/l.l/82 J-J0303-l unic 1, TBI Location Plan, El 102' & 120'-0" Area 3 4 06/21/83 J-J0305-l Unit 1, TBI Location Plan, El 137'-0" Area 3 3 12/26/84 J-J0401-l Unit 1, TBI Location Plan, El 54'-0" Area 4 5 06/24/85 J-J0402-l Unit 1, TBI Location Plan, El 77' -0" Area 4 3 l.l/11/82 J-J0403-l Unit 1, TBI Location Plan, El 102'-0" Area 4 4 07/29/85 J-J0404-l Unit 1, TBl Location Plan, El 120'-0" Area 4 3 01/30/84 J-J0405-1 Unit 1, TBl Location Plan, El 137'-0" Area 4 0 01/18/82 J-JOSOl-1 Unit 1, TBI Location Plan, El 54"-0" Area 5 2 10/18/82 J-J0502-1 Unit 1, TBI Location Plan, El 77"-0" Area 5 2 11/04/82 J-J0503-1 Unit 1, TBI Location Plan, El 102' & 120'-0" Area 5 4 01/26/84 J-J0601-1 Unit 1, TBI Location Plan, El 54'-0" Area 6 5 01/07/84 J-J0602-l Unit 1, TBI Location Plan, El 77'-0" Area 6 2 11/15/82 J-J0603-l Unit 1, TBI Location Plan, El 102'-0" Area 6 4 12/28/84 J-J0604-1 Unit 1, TBI Location Plan, El 120'-0" Area 6 1 04/08/82 J-J0605-l Unit 1, TBI Location Plan, El 137'-0" Area 6 3 12/28/84 J-J0701-1 Unit 1, TBI Location Plan, El 54'-0" Area 7 3 05/15/83 J-J0702-l Unit 1, TBI Location Plan, El 77'-0" Area 7 4 08/26/83 J-J0703-1 Unit 1, TBI Location Plan, El 102' & 120'-0" Area 7 3 06/27/83 J-J0704-l Unit: 1, TBI Location Plan, El 120'-0" Area 7 4 01/31/84 J-J0705-l Unit 1, TBI Location Plan, El 137'-0" Area 7 4 11/03/83 J-J0801-l Unit 1, TBI Location Plan, El 54' -0" Area B 2 02/04/92 J-J0802-l Unit 1, TBI Location Plan, El 77'-0" Area B 5 1.2/28/84 J-JOS03-l Unit 1, TBI Location Plan, El 102'-o~ Area 8 2 10/15/84 J-J0804-1 Unic 1, TBI Location Plan, El 120'-0" Area 7 3 01/31/84 J-J0901-1 Unit 1, TBI Location Plan, El 54' -0" Area 9 5 01/16/84 J-J0902-1 Unit 1, TBl Location Plan, El 77' -0" Area 9 4 09/28/84 J-J0903-l Unit 1, TBI Location Plan, El 102'-0" Area 9 3 12/:20/82 J-J0904-l Unit 1, TBI Location Plan, El 120'-0" Area 9 4 12/26/84 J-J0905-l Unit 1, TBI Location Plan, El 171'-0" Area 9 1 09/28/82 J-J0906-l Unit 1, TBI Location Plan, El 171'-0" Area 9 3 01/26/84 J-JlOOl-1 Unit 1, TBI Location Plan, El 54'-0" Area 10 5 07/1'2/83 J-J1002-l Unit 1, TBI Location Plan, El 77'-0" Area 10 4 06/'27/83 J-J1003-l Unit 1, TBI Location Plan, El 102'-0" Area 10 3 12/'20/82 J-J1004 unit 1, TBI Location Plan, Bl 120'-0" Area 10 2 10/06/84 J-J1005-1 Unit 1, TBI Location Plan, El 137'-0" Area 10 3 02/21/84 J-Jl006-1 Unit l, TBI Location Plan, El 171'-0" Area 10 l 09/l3/82 14 of 18 HCGS-UFSAR Revision ~4 July 26, 2005

TABLE 1.7-3 {Cont) FSAR Figure (Historical Info~tion) *I Drawing Number Title Number Rev _.;;;D;.;;a;.;t:;.;e:;__ J-JllOl-1 ~0" Area 11 4 08/12/83 J-Jll02-l Unit 1, TBI Location Plan, El 77' -0" Area 11 5 08/12/83 J-Jll03-l Unit 1, TBI Location Plan, El 102'-0" Area 11 3 06/21/93 J-Jll04-l Unit l, TBI Location Plan, El 120'-0" Area 11 l 07/26/82 J-JllOS-1 Unit 1, TBI Location Plan, El 137'-0" Area 11 3 12/17/84 J*J1106-l Unit 1, TBI Location Plan, El 171'-0" Are"' ll 3 10/17/83 J-J120l-1 Unit 1, TBI Location Plan, El 54'-0" Area 12 s 12/26/84 J-J1202-l Unit l, TBI Location Plan, El 77 * -0." Area 12 4 12/26/84 J-Jl203-l Unit 1, TBI Location Plan, El 102'-0" Area 12 3 09/21/84 J-Jl205-l Unit 1, TBI Location Plan, El 137'-0" Area 12 2 10/17/83 J-J1206-1 Unit 1, TBI Location Plan, El 171'-0" Area 12 1 09/01/82 J-J4101-0 Unit 1, TBI Location Plan, El 54'-0" Area 41 4 10/24/83 J-J4.102-0 Unit 1, TBI Location Plan, El 77'-0" Area 41 1 11/16/82 J-J4103-2 Unit 1, TBI Location Plan, El 102'0" Area 41 0 11/20/81 J-J4501-0 Unit 1, TBI Location Plan, El 54' -0" Area 45 11/15/82 J-J4502-0 Unit 1, '!'Bl Location Plan, El 77'-0" Area 45 2 10/17/83 J-J4901-0 Unit 1, TBI Location Plan, £1 54'-0" Area 49 3 04/03/84 J-J4902-0 Unit l, TBI Location Plan, El 77'-0" Area 49 3 01/12/84 J-J1301-l Unit 1, Reactor Building Instrument Location Plan, El 54'-0" Area 13 B 04/08/BS J-J1302-1 Unit l., Reactor Building Instrument Location Plan, El 77'-0" Area 13 5 11/10/83 J-JB03-l Unit 1, Reactor Building Instrument Location Plan, El 102'-0" Area AT 3 11/ll/82 J-J1304-l Unit 1, Reactor Building Instrument Location Plan, El 132'&145"-0" A' Area 13 PL 4 09/23/83 J-J1401-1 Unit 1, Reactor Building Instrument Location Plan, El 54'-0" Area 14 4 05/22/85 J-J1402-l Unit 1, Reactor Building Instrument Location Plan, El 77'-0" Area 14 4 07/16/83 J-J1403-1 Unit 1, Reactor Building Instrument Location Plan, El 102'-0" Area 16 7 01/22/85 J-J1404-1 Unit 1., Reactor Building Instrument Location Plan, El 132'-0" Area 14 PL 4 11/08/83 J-Jl405-l Unit 1, Reactor Building Instrument Location Plan, El 145' -0" Area 14 PL 1 07/20/83 J-Jl406-l Unit 1, Reactor Building Instrument Location Plan, El 162'-0" Area 14 PL 1 03/08/63 J-JlSOl-1 Unit 1, Reactor Building Instrument Location Plan, El 54'-0" Area 15 7 04/08/85 J-Jl502-l Unit 1, Reactor Building Instrument Location Plan, El 77'-0" Area 15 3 09/14/82 J-Jl503-1 Unit 1, Reactor Building Instrument Location Plan, El 102*-o Area 15 3 12/10/83 J-Jl504-1 Unit 1, Reactor Building Instrument Location Plan, El 132'&145'-0" Area 15 4 09/23/83 J-Jl601-1 Unit 1, Reactor Building Instrument Location Plan, El 54'-0" Area 16 5 05/22/85 J-Jl602-l Unit 1, Reactor Building Instrument Location Plan, El 77'-0" Area 16 7 09/21/84 J-J1603-1 Unit 1, Reactor Building Instrument Location Plan, El 100'-2" Area 17 4 02/28/85 J-Jl604-1 Unit 1, Reactor Building Instrument Location Plan, El 132'-0" Area 16 3 07/12/83 J-J1605-1 Unit 1, Reactor Building Instrument Location Plan, E1 145'-0" Area 16 4 05/10/SS J-J1606-1 Unit 1, Reactor Building Instrument Location Plan, El 162 * -0" Area 16 3 06/15/83 J-J1702-1, Sh 1 Unit 1, Reactor Building Instrument Location Plan, El 77'-0" Area 17 5 05/06/BS J-.11702-l, Sh 2 Unit 1, Reactor Building Instrument Location Plan, El 77'-0" Area l.1 09/ll/SS J-Jl702-l, Sh 3 unit l, Reactor Building Instrument Location Plan, El 77'-0" Area 17 10/12/82 J-J1703-1 Unit l, Reactor Building Instrument Location Plan, El 100' -2" Area 17 5 03/25/85 15 of 18 Revision 14 July 26, 2005

Drawing Number Title TABLE 1.7-3 {Cant) FSAR Figure Number (Histo~ical Info~tion} *I

                                                                                                     ~  _.::D::.::a:::.:t:.:e:::__

J-J:l705-l Loc<>tion Plan, El 121'-71 1/2" Area 17 2 07/21/83 J-J1706-l Unit 1, Reactor Building Instrument Location Plan, El 132'-0" Area 17 2 07/27/83 J-Jl707-l Unit 1, Reactor Building Instrument Location Plan, El 145'-0" Area 17 1 06/23/83 J-Jl708-1 Unit 1, Reactor Building Instrument Location Plan, El 162'-0" Area 17 4 04/08/85 J-JlBOl-1 Unit 1, Reactor Building Instrument Location l?la.n, El 54'-0" Area 18 5 01/22/85 J-J1802-l Unit l, Reactor Building Instrument Location Plan, El 77'-0" Area 18 3 01/30/84 J-J1B03-1 Unit 1, Reactor Building Instrument Location Plan, El 102'-0" Area 18 5 09/ll/85 J-J1B04-l unit 1, Reactor Building Instrument Location Plan, El 132'-0" Area 18 2 l.l/16/82 J-J1S06-1 Unit 1, Reactor Building Instrument Location Plan, El 162'-0" Area 18 4 10/24/84 J-J190l-l Unit 1, Reactor Building Instrument Location Plan, El 54'-0" Area 19 7 05/20/85 J-J1902-1 Unit l, Reactor Building Instrument Location Plan, El 77'-0" Area 19 4 11/25/85 J-J1903-1 Unit 1, Reactor Building Instrument Location Plan, El 102'-0" Area 19 6 05/21/85 J-J1904-1 Unit 1, Reactor Building Instrument Location Plan, El 132'&145'-0" Area 19 1 10/14/83 J-J1905-l Unit 1, Reactor Building Instrument Location Plan, El 162'-201'-0" Area 19 08/07/85 J-J2001-1 Unit 1, Reactor Building Instrument Location Plan, El 54'-Qtt Area 20 4 05/22/85 J-J2002-1 Unit 1, Reactor Building Instrument Location Plan, El 77'-0" Area 20 5 11/0B/83 J-J2003-l Unit 1, Reactor Building Instrument Location Plan, El 102'-0" Area 20 2 10/26/92 J-J2006-l Unit 1, Reactor Building Instrument Location Plan, El 162'-0" Area 20 5 09/27/85 J-J2007-l Unit 1, React:or Building Instrument Location Plan, El 201'-0" Area 20 2 11/08/83 J-J210l-l Unit l, Reactor Building Instrument Location Plan, El 54'-0" Area 21 7 09/23/83 J-J2102-1 Unie 1, Reactor Building Instrument Location P~an, El 77'-0" Area 21 4 05/16/83 J-J2103-l Unit 1, Reactor Building Instrument Location Plan, El l.02'-0" Area 21 3 06/15/83 J-J2105-l Unit 1, Reactor Building Instrument Location Plan, El 162'-201'-0" Area 21 5 12/26/84 J-J2201-l Unit 1, Reactor Building Instrument Location Plan, El 54'-0" Area 22 a 11/10/83 J-J2202-l Unit 1, Reactor Building Instrument Location Plan, E1 77'-0" Area 22 4 02/15/84 J-J2203-l Unit 1, Reactor Building Instrument Location Plan, El 102'~0" Area 22 4 06/03/83 J-J2301-l unit 1, Reactor Building Instrument Location Plan, El 54'-0" Area 23 6 07/29/85 J-J2302-1 unit 1, Reactor Building Instrument Location Plan, El 77'-0" Area 23 6 09/27/85 J-J2303-l Ul1it 1, Reactor Building Instrument Location Plan, El 102'-0" Area 23 4 11/08/83 J-J2401-l Unit 1, Reactor Building Instrument Location Plan, El 54'-0" Area 24 7 10/24/83 J-J2402-1 Unit 1, Reactor Building Instrument Location Plan, El 77'-0" Area 24 3 12/27/83 J-J2403-1 Unit 1, Reactor Building Instrument Location Plan, El :102'-0" Area 24 5 11/10/83 J-J2501-1 Unit 1, Auxiliary Building El 54'-0" Area 25 l. 06/18/82 J-J2502-1 Unit 1, Auxiliary Building El 77'-0" Area 24 1 06/18/82 J-J2506-1 Unit 1, Auxiliary Building El 155'-0" Area 25 4 04/20/84 J-J2601-l Unit 1, Auxiliary Building El 54'-0H Area 25 2 10/25/82 J-J2606-1 Unit 1, Auxiliary Building El 155' -0" Area 26 5 09/27/85 J-J2701-1 Unit 1, Auxiliary Building El 54'-0" Area 27 8 10/15/84 J-J2702-1 Unit 1, Auxiliary Building El 77'-0" Area 27 3 02/07/84 J-J2703-l Unit 1, Auxiliary Building El 102'-0" Area 27 5 09/21/84 J-J2704-1 Unit 1, Auxiliary Building El 130'-0" Area 27 4 07/17/84 J-J2801-1 Unit 1, Auxiliary Building El 54'-0" Area 28 6 10/15/84 J-J2802-l Unit 1, Auxiliary Building El 77'-0" Area 29 3 02/07/84 16 of l.S HCGS-OFSA.R Revision 14 July 26, 2005

TABLE 1.7-3 (Cont} FSAR Figure (Historical Information) *I Drawing Number Title Number Date INSTRUMENTATION LOCATION DRAWINGS J-J2S03-l Unit 1' Auxiliary Building El 102' -0" Area 28 5 09/21/84 J-J2804-1 Unit 1, Auxiliary Building El 130' -0" Area 28 2 08/26/83 J-J3101-0, Sh 1 Unit 1, Auxiliary Building El 54'-0" Area 31 6 09/25/84 J-J3101-0, Sh 2 Unit 1, Auxiliary Building El 75'-0" Area 31 4 04/lB/83 J-J3201-0, Sh 1 Unit 1, Auxiliary Building El 54'-on Area 32 6 02/28/83 J-J3201-0, Sh 2 Unit 1, Auxiliary Building El 75'*0" Area 32 3 04/18/83 J-J3202-0 unit 1, Auxiliary Building El 87'-0" Area 32 3 09/23/83 J-J3203-0, Sh 1 Unit 1, Auxiliary Building El 102' -0" Area 32 1 09/09/81 J-J3206-0 Unit 1' Auxiliary Building El 153' -0" Area 32 2 06/15/83 J-J3301-0 Unit 1, Auxiliary Building El 54'-0" Area 33 s 11/22/63 J-J3401-0, Sh 1 Unit 1, Auxiliary Building El 54'-0" Area 34 6 07/13/83 J-J3401-0, Sh 2 Unit 1, Auxilia*ry Building El 54'-0" Area 34 J-J3403-0 Unit 1, Auxiliary Building El 102'-0" Area 34 s 02/13/84 J-J350l-0 Unit 1, Auxiliary Building El 54'-0" Area 35 11 03/01/85 J*J3502-0 unit 1' Auxiliary Building El 87'*0" Area 35 3 04/18/83 J-J3503-0 Unit 1, Auxiliary Building El 102' -0" Area 35 6 07/15/85 J-J3506-0 Unit 1, Auxiliary Building El 135'-3" Area 35 6 10/15/84 J-J7101-0 Unit ~' Auxiliary Building El 54'-0" Area 71 5 6/10/85 J-J7201-0 Unit 1, Auxiliary Building El 54'-0" Area 72 2 07/19/82 J-J7206-0 Unit 1' Auxiliary Building El 153' -0" Area 72 2 03/23/83 J-J7301-0 Unit 1, Auxiliary Building El 54'-0ft Area 73 6 06/15/83 C-163C1723 & Motor Control Center Standards 4 12/18/78 C-762E180 Reactor Recirculation Pump & Motor Generator Set BRO 07/12/83 C-791E401AC Nuclear Steam Supply Shutoff System BR1 12/06/83 C-791E402AC Nuclear Boiler Process Instrumentation System BRO 12/06/83 C-791E403AC Auto Depressurization System BRO 12/06/83 C-791E406AC Reactor Manual control System BRl 12/05/83 C-7.91E407AC Control Rod Drive Hydraulic System BRO 01/04/84 C-7!HE408AC Feedwater Control System BR1 12/05/63 C-791E409AC Standby Liquid Control System 6 12/16/83 C-791E410AC Startup Range Neutron Monitoring System BR1 05/24/84 C-791E411AC Power Range Neutron Monitoring System BRl 12/05/83 C-791E412AC Startup Range Detector Drive Control 2 02/16/82 C-791E413AC Transverse Incore Probe Calibration System BRl 05/24/84 C-791E414AC Reactor Protection System BRl 12/02/83 C-791E415AC Interconnection Schematic 2 11/11/82 C-791E418AC Residual Heat Removal System BRO 12/05/83 C-791E419AC Core Spray System BRl 12/09/83 C-791E420AC High Pressure Coolant Injection System BRl 12/09/83 C-791E421AC Reactor Core Isolation Cooling System BRl 12/09/83 17 of IS HCGS-UFSAR Revision 14 July 26, 2005

TABLE 1.7-3 (Cont) (Historical Information) *I FSAR Figure Drawing Number Title Number Date ELEMENTARY DIAGRAMS C-791E425AC Steam Leak Detection System BR1 01/04/84 C-807E16BAC Process Radiation Monitoring System BR1 01/1.2/84 C-865E346AC Jet Pump Instrumentation System BR2 01/1.2/84 C-865E366 Reactor Water Cleanup System B!U 05/09/84 C-866El42 Radwaste System BRO 12/09/83 115D6002AC RPS MG Set Control BRO 10/20/83 FUNCTIONAL CONTROL DIAGRAMS C-729E60SAC Reactor Water Cleanup System J. 11/:21/83 C-729E613AC Core Spray System GC 04/15/82 C-729E61BAD Control Rod Drive Hydraulic system 3 11/18/83 C-729E622AC Reactor Core Isolation Cooling System 1 02/15/94 C-729E625 Reactor Recirculation System 6 12/21/82 C-729E627AC High Pressure Coolant Injection system 2 03/.29/83 C- 72 9E63 OAC Residual Heat Removal System BC 06/23/83 C-729E6HAC Neutron Monitoring System 1 03/23/84 C-919D694AC Standby Liquid Control System 1 12/21/82 18 of 18 HCGS-UFSAR Revision 14 July 26, 2005

1.8 CONFORMANCE TO NRC REGULATORY GUIDES 1.8.1 Non-NSSS Assessment of Conformance The extent of Non-Nuclear Steam Supply System (NSSS) compliance with the NRC Regulatory Guides is indicated here and, where applicable, reference is made to the Final Safety Analysis Report (FSAR) section(s) that describe the appropriate design feature. Determination of conformance is based on a comparison of the Hope Creek Generating Station (HCGS) non-NSSS design and construction to the latest version of the Regulatory Guides. Variances are discussed and justified in this section where the design deviates from regulatory guidelines, or where compliance has been qualified by an interpretation of the Regulatory Guide. Positions stated with respect to Regulatory Guide compliance will apply during the operations phase unless otherwise stated. In general, the statement, "although Regulatory Guide 1.XXX does not apply to HCGS, per its implementation section..." applies only during construction and startup phase; i.e., the Regulatory Guide is applicable during the operations phase. 1.8.1.1 Conformance to Regulatory Guide 1.1 (Safety Guide 1) Revision 0, November 2, 1970: Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal System Pumps HCGS complies with Regulatory Guide 1.1, as described below. The suction piping for all pumps required for safe shutdown of the reactor, during both normal and accident conditions, including the cooling of both the core and the containment, is designed and located to ensure adequate net positive suction head (NPSH). The available NPSH for the residual heat removal (RHR) and core spray pumps is based on a torus water temperature of 212F, with the pool surface at 14.7 psia. The calculated available NPSH for the high 1.8-1 HCGS-UFSAR Revision 0 April 11, 1988

pressure coolant injection (HPCI) pump is based on a water temperature of 170F, with the pool surface at 14.7 psia. For further discussion, see Sections 5.4.7, 6.2.2, and 6.3.2. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.2 Conformance to Regulatory Guide 1.2, (Safety Guide 2) Revision 0, November 2, 1970: Thermal Shock to Reactor Pressure Vessels Although NRC Regulatory Guide 1.2 was withdrawn by the NRC on July 31, 1991, HCGS commitments, as stated below, are not affected by this withdrawal. HCGS complies with Regulatory Guide 1.2, as described below: An investigation of the structural integrity of boiling water reactor (BWR) pressure vessels during a design basis accident (DBA) determined that, based on the methods of fracture mechanics, failure of the vessel by brittle fracture does not occur as a result of a DBA. See Section 5.3 for further discussion of fracture toughness of the reactor pressure vessel (RPV) and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.3 Conformance to Regulatory Guide 1.3, Revision 2, June 1974: Assumptions Used For Evaluating The Potential Radiological Consequences of a Loss of Coolant Accident For Boiling Water Reactors HCGS complies with Regulatory Guide 1.183 instead. 1.8-2 HCGS-UFSAR Revision 13 November 14, 2003

1.8.1.4 Conformance to Regulatory Guide 1.4, Revision 2, June 1974: Assumptions Used For Evaluating The Potential Radiological Consequences of a Loss of Coolant Accident For Pressurized Water Reactors Regulatory Guide 1.4 deals with pressurized water reactors (PWRs) only and is, therefore, not applicable to HCGS. 1.8.1.5 Conformance to Regulatory Guide 1.5 (Safety Guide 5), Revision 0, February 1, 1971: Assumptions Used for Evaluating The Potential Radiological Consequences of Steam Line Break Accident For Boiling Water Reactors HCGS complies with Regulatory Guide 1.5. See Chapter 15 for discussion of accident analyses. 1.8.1.6 Conformance to Regulatory Guide 1.6 (Safety Guide 6), Revision 0, March 10, 1971: Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems HCGS complies with Regulatory Guide 1.6, as described below. The ac and dc safety-related equipment and control power loads are separated into redundant load groups, each of which is connected to independent standby power sources. No provisions are made for paralleling standby power sources or for connecting redundant load groups together. For further discussion of the Onsite Electrical System, see Sections 7.1.2, 7.2.1, 8.3.1, and 8.3.2. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-3 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.7 Conformance to Regulatory Guide 1.7, Revision 2, November 1978: Control of Combustible Gas Concentrations in Containment Following a Loss of Coolant Accident HCGS complies with Regulatory Guide 1.7, except as noted below. Position C.1 of Regulatory Guide 1.7 specifies that HCGS "should have the capability to ... mix the atmosphere in the containment." The drywell fans have not been classified as safety-related to provide post-accident mixing. Analyses indicate that adequate mixing is obtained from convection, diffusion, and turbulence and that no mechanical means of mixing is necessary. The Nuclear Regulatory Commission (NRC or the Commission) has revised Title 10 of the Code Of Federal Regulations (10 CFR) Section 50.44, Standards For Combustible Gas Control System In Light-Water Power Reactors. The amended standards eliminated the requirements for hydrogen recombiners and relaxed the requirements for hydrogen and oxygen monitoring. On August 9, 2005, the NRC issued Amendment 160 to the Hope Creek Facility Operating License to allow the plant to implement the revised rule. Amendment 160 constitutes the current licensing commitment, in lieu of the guidance specified in Regulatory Guide 1.7, with regard to the requirements for the hydrogen recombiners and for hydrogen and oxygen monitoring systems. For further discussion of the design of combustible gas control in containment, see Section 6.2.5. 1.8.1.8 Conformance to Regulatory Guide 1.8, Revision 2, April 1987: Qualification and Training of Personnel for Nuclear Power Plants HCGS complies with Regulatory Guide 1.8, except as noted below. The Operations Manager shall either hold an SRO license or have held an SRO license for a similar unit (BWR) or have been certified at an appropriate simulator for equipment senior operator knowledge. Licensed Operator qualifications and training shall be in accordance with 10CFR55. The Radiation Protection Manager shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975. The Director - Nuclear Oversight (NOS) and the engineering manager positions under the Site Engineering Director, which correspond to the Engineer in Charge, must meet or exceed the qualifications of ANSI/ANS 3.1-1981. Qualification requirements for the Nuclear Safety Review Board personnel performing the offsite independent review function and PORC members are described in their associated program documents. 1.8-4 HCGS-UFSAR Revision 22 May 9, 2017

See Section 12.5 and Section 13 for further discussion of staffing of plant personnel. 1.8.1.9 Conformance to Regulatory Guide 1.9, Revision 2, December 1979: Selection, Design, and Qualification of Diesel Generator Units Used as Standby (Onsite) Electric Power Systems at Nuclear Power Plants Although Regulatory Guide 1.9 is not applicable to HCGS, per its implementation section, HCGS complies with IEEE 387-1977, as endorsed and modified by Regulatory Guide 1.9, subject to the clarifications stated below: Paragraph C.4 requires that the frequency and voltage not decrease to less than 95 percent of nominal and 75 percent of nominal, respectively, at any time during the loading sequence. At HCGS, because the two unit substation transformers remain connected to the diesel generator bus all the time, the voltage will dip below 75% of rated voltage upon the closure of the generator breaker for a DBA or loss of offsite power (LOP). This voltage dip is due to the excitation current inrush while the transformers are energized and lasts for approximately six cycles. The first motor load applied is the RHR motor, after closure of the SDG circuit breaker. The RHR circuit breaker has a closing permissive from the bus undervoltage relays. With the current setting of these relays (set to dropout at 70 percent and to pickup at 78 percent) the RHR motor circuit breaker will close when permitted. It takes 4.5 cycles for this circuit breaker to close. During this interval the generator has recovered its voltage in excess of 90 percent. This will be verified during the preoperational tests described in Section 14.2.12.1.30. Compliance with Position C.6 of Regulatory Guide 1.9 is discussed in Section 1.8.1.108. The order of testing specified in Regulatory Position C.14 is not applicable to Hope Creek. The Hope Creek order of testing is as described in the Hope Creek Technical Specifications. For further discussion of onsite power systems, see Section 8.3. 1.8.1.10 Conformance to Regulatory Guide 1.10, Revision 1, January 2, 1973: Mechanical (Cadweld) Splices in Reinforcing Bars of Category I Concrete Structures Although Regulatory Guide 1.10 was withdrawn by the NRC on July 21, 1981, HCGS complies with it. The original Cadweld testing program in the Preliminary Safety Analysis Report (PSAR) was based on using only sister splices. The program was later revised before the start of construction to conform with the Regulatory Guide using a combination of production and sister splices. When newer technical criteria for Cadwelding developed, the architect/engineer revised the program to delete the tensile test frequency requirements for each splicing crew. The new criteria conformed to the requirements of ANSI N45.2.5, 1978, as 1.8-5 HCGS-UFSAR Revision 15 October 27, 2006

endorsed by Regulatory Guide 1.94. However, the letter dated August 5, 1981, NRC to PSE&G, from R. L. Tedesco to R. L. Mittl, requested that the sample frequency requirements of this guide be implemented. Since November 30, 1981, HCGS has been in complete compliance with this Regulatory Guide. For further discussion, see Section 3.8.6. 1.8.1.11 Conformance to Regulatory Guide 1.11 (Safety Guide 11), Revision 0, February 1, 1971: Instrument Lines Penetrating Primary Reactor Containment HCGS complies with Regulatory Guide 1.11, except as noted below. Containment pressure sensing lines are not provided with an automatic or remotely operated isolation valve as specified in Position C.1.c of Regulatory Guide 1.11. Sensing lines are not isolated automatically upon a containment isolation signal because the pressure sensors provide a Reactor Protection System (RPS) signal. The capability for remote operation is not useful to the operator because remote indication of failure of a specific line is not available. However, these lines are provided with manual isolation valves for local operation and are checked for leakage during normal instrumentation calibrations. For further discussion of containment isolation provisions, see Section 6.2.4. 1.8.1.12 Conformance to Regulatory Guide 1.12, Revision 1, April 1974: Instrumentation for Earthquakes HCGS complies with ANSI N18.5-1974, as endorsed and modified by Regulatory Guide 1.12, subject to the clarification that the response-spectrum recorders required by Paragraph C.1.c are not supplied as discrete instruments. Instead, triaxial time history accelerographs are provided, at the required locations, with a multichannel magnetic tape recorder and a response spectrum 1.8-6 HCGS-UFSAR Revision 0 April 11, 1988

analyzer. This system provides more complete information than that presented by response spectrum recorders. For further discussion, see Section 3.7.4. 1.8.1.13 Conformance to Regulatory Guide 1.13, Revision 1, December 1975: Spent Fuel Storage Facility Design Basis HCGS complies with Regulatory Guide 1.13 with the following exception: Position C.3 of Regulatory Guide 1.13 requires that interlocks be provided to prevent cranes from passing over stored fuel when fuel handling is not in progress. At HCGS, only the main hoist of the Reactor Building polar crane is physically restricted from travelling over the spent fuel pool. The 10-ton auxiliary hoist has no such travel restriction. Restricting its travel over the fuel pool is not part of the polar crane design basis. Instead, the alternate crane design basis of a single failure proof auxiliary hoist, described in FSAR Section 9.1.5.3.1, is used. No loads are required to be routinely handled over the fuel pool when fuel handling is not in progress. In the event a light load must be handled over stored fuel, a single failure proof handling system will be used. See Section 9.1 for further discussion of the fuel handling and storage facilities and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.14 Conformance to Regulatory Guide 1.14, Revision 1, August 1975: Reactor Coolant Pump Flywheel Integrity Regulatory Guide 1.14 is not applicable to HCGS. The reactor recirculation pumps at HCGS do not have inertia flywheels. 1.8-7 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.15 Conformance to Regulatory Guide 1.15, Revision 1, December 28, 1972: Testing of Reinforcing Bars for Category I Concrete Structures Although Regulatory Guide 1.15 was withdrawn by the NRC on July 21, 1981, HCGS complies with it. For further discussion, see Section 3.8.6. 1.8.1.16 Conformance to Regulatory Guide 1.16, Revision 4, August 1975: Reporting of Operating Information Appendix A Technical Specification HCGS complies with Generic Letter 97-02, Revised Contents of the Monthly Operating Report, in lieu of the guidance provided in draft Regulatory Guide 1.16, Revision 4, as allowed by Generic Letter 97-02. 1.8.1.17 Conformance to Regulatory Guide 1.17, Revision 1, June 1973: Protection of Nuclear Power Plants Against Industrial Sabotage Although NRC Regulatory Guide 1.17 was withdrawn by the NRC on July 5, 1991, HCGS commitments, as stated below, are not affected by this withdrawal. HCGS complies with 10CFR73.55, Requirement for Physical Protection of Licensed Activities in Nuclear Power Reactors Against Radiological Sabotage. 1.8.1.18 Conformance to Regulatory Guide 1.18, Revision 1, December 28, 1972: Structural Acceptance Test For Concrete Primary Reactor Containments Regulatory Guide 1.18 was withdrawn by the NRC on July 21, 1981, and is not applicable to HCGS. 1.8.1.19 Conformance to Regulatory Guide 1.19 (Safety Guide 19), Revision 1, August 11, 1972: Nondestructive Examination of Primary Containment Linear Welds 1.8-8 HCGS-UFSAR Revision 10 September 30, 1999

Regulatory Guide 1.19 was withdrawn by the NRC on July 21, 1981, and is not applicable to HCGS. 1.8.1.20 Conformance to Regulatory Guide 1.20, Revision 2, May 1976: Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing HCGS complies with Regulatory Guide 1.20, with the clarification that the HCGS reactor internals were tested in accordance with the provisions for nonprototype Seismic Category I plants. The results of the vibration assessment program are found in GE Licensing Topical Report NEDE-24057, Reference 1.8-1. For a discussion of the preoperational flow test and inspection program, see Sections 3.9.2.6 and 14.2. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.21 Conformance to Regulatory Guide 1.21, Revision 2, June 2009: Measuring, Evaluating, and Reporting Radioactive Material in Liquid and Gaseous Effluents and Solid Waste HCGS complies with Regulatory Guide 1.21, with the clarifications outlined below: Position 6 of Regulatory Guide 1.21 requires that the total curie quantity and radionuclides in the solid waste shipped offsite be determined. Curie and radionuclide determinations for solid radioactive waste shipped offsite are performed to the extent and level required by Department of Transportation Regulations and 10CFR71, Packaging of Radioactive Material. Any additional monitoring is unnecessary and will increase personnel exposures. 1.8-9 HCGS-UFSAR Revision 25 November 15, 2021

1.8.1.22 Conformance to Regulatory Guide 1.22 (Safety Guide 22), Revision 0, February 17, 1972: Periodic Testing of Protection System Actuation Functions HCGS complies with Regulatory Guide 1.22 based on the interpretations listed below. The systems classed as important to safety, as defined in IEEE 279-1971, Criteria for Protection Systems for Nuclear Power Generating Stations, are:

1. Reactor Protection System (RPS), described in Section 7.2.

2. Primary Containment Isolation System (PCIS) and nuclear steam supply system shutoff (NSSSS), described in Section 7.3.

3. Reactor Core Isolation Cooling (RCIC) System described in Section 5.4.6.

4. Filtration, Recirculation, and Ventilation System (FRVS), described in Section 6.8.

5. Station Service Water System (SSWS), described in Section 9.2.1.

6. Safety Auxiliaries Cooling System (SACS), described in Section 9.2.2.

1.8-10 HCGS-UFSAR Revision 25 November 15, 2021

Position D.3.a of Regulatory Guide 1.22 requires that "positive means" be provided to prevent expansion of the bypass condition to redundant or diverse systems. Administrative controls are considered a "positive means" of preventing expansion of the bypass condition, since interlocks between systems could lead to common mode failures. Position D.3.b in Regulatory Guide 1.22 is interpreted to require indication of bypass on a system basis, not necessarily by component. For additional discussion of the design of the HCGS electrical system, see Section 7 and Section 8.1. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.23 Conformance to Regulatory Guide 1.23, Revision 1, March 2007: Meteorological Monitoring Programs for Nuclear Power Plants HCGS complies with the intent of Regulatory Guide 1.23. 1.8.1.24 Conformance to Regulatory Guide 1.24 (Safety Guide 24), Revision 0, March 23, 1972: Assumptions Used for Evaluating the Potential Radiological Consequences of a Pressurized Water Reactor Radioactive Gas Storage Tank Failure Regulatory Guide 1.24 is not applicable to HCGS. 1.8-11 HCGS-UFSAR Revision 25 November 15, 2021

1.8.1.25 Conformance to Regulatory Guide 1.25 (Safety Guide 25), Revision 0, March 23, 1972: Assumptions Used for Evaluating the Potential Radiological Consequences of a Fuel Handling Accident in the Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors HCGS complies with Regulatory Guide 1.183, Appendix B, instead. 1.8.1.26 Conformance to Regulatory Guide 1.26, Revision 3, February 1976: Quality Group Classifications and Standards for Water, Steam, and Radioactive Waste Containing Components of Nuclear Power Plants HCGS complies with Regulatory Guide 1.26, with the clarifications outlined below. PSE&G does recognize the need for the assurance of the specified operation of certain non-safety-related structures, systems and components, such as fire protection systems, radioactive waste treatment, handling and storage systems, and Seismic Category II/I items. Such assurance is documented through the specification of limited quality assurance programs (described in Table 3.2-1, footnotes 22, 50 and 52. In addition, items designated "R" in Table 3.2-1 will be included in the QA program during operations to the extent required by Regulatory Guide 1.143. The exception to Position C.2.b is that since the reactor recirculation pumps do not perform any safety function and since failure of the reactor coolant pumps due to seal or cooling water failure does not have serious safety implications, the control rod drive (CRD) seal purge supply and Reactor Auxiliaries Cooling System (RACS) cooling water to the seal coolers are quality group D. Additionally, Position C.2.b of Regulatory Guide 1.26 requires that cooling water systems important to the safety function of the standby diesel generators be Quality Group C. HCGS's diesel generator cooling water systems are classified as Quality Group C 1.8-12 HCGS-UFSAR Revision 13 November 14, 2003

except for the engine mounted piping systems (such as the lube oil headers, water headers, cylinder heads, etc). The engine mounted piping systems are part of the diesel engine and its auxiliary support systems which, as stated in Section B of the Regulatory Guide, are not covered by this guide. These systems are manufactured to the manufacturer's proprietary design requirements which do not necessarily meet the requirements of ASME Section III or ANSI B.31. However, the components used are pressure tested and the manufacturing processes are monitored as a part of the suppliers approved QA program, which addresses the 18 criteria contained within 10 CFR 50, Appendix B. Additional quality assurance requirements invoked by the applicant include:

1. periodic documented subsupplier audits (including plant visits),

2. review and approval of subsupplier QA programs and manuals,

3. test and inspection audits,

4. calibration of test gauges before and after use, and

5. control of calibration records and acceptance devices.

With the imposition of the above design, manufacturing, and testing controls, the on-skid and off-skid piping and components have been made to be equivalent to Quality Group C. This meets the requirements in Section B of the guide to design, fabricate, erect and test the diesel engine and its auxiliary support systems to quality standards commensurate with the safety function to be performed. NUREG-0737, Item II.k.3.25 extends the requirements of Position C.2.b by requiring demonstration that the consequences 1.8-13 HCGS-UFSAR Revision 8 September 25, 1996

stemming from a loss of cooling water to the reactor recirculation pump seal coolers is acceptable following a loss of power for at least 2 hours. NEDO-24951 (Reference 5.4-4) confirms that the HCGS design meets the requirements of NUREG-0737, Item II.k.3.25. See Section 3.2.2 for further discussion and Section 1.8.2 for NSSS assessment of this Regulatory Guide. 1.8.1.27 Conformance to Regulatory Guide 1.27, Revision 2, January 1976: Ultimate Heat Sink For Nuclear Power Plants HCGS complies with Regulatory Guide 1.27. The ultimate heat sink (UHS) is the Delaware River, which is a large, single water source as defined by the Regulatory Guide. The service water equipment required for the dissipation of residual heat is all safety-related and redundant, with the exception of the service water discharge piping outside of the Reactor Building. This piping normally discharges into the Circulation Water System (CWS). However, if some natural or site-related event occurs and blocks the flow, there are rupture discs in the safety-related portion of the service water discharge piping that allow the water to be safely diverted onto and across the lower yard surface area, thus completing the cooling loop between the UHS and the plant. For further discussion of the Station Service Water System (SSWS) and the UHS, see Sections 9.2.1 and 9.2.5. 1.8.1.28 Conformance to Regulatory Guide 1.28, Revision 2, February 1979: Quality Assurance Program Requirements (Design and Construction) Although Regulatory Guide 1.28, Revision 2, is not applicable to HCGS, HCGS complies with NQA-1-1994. 1.8-14 HCGS-UFSAR Revision 15 October 27, 2006

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1.8.1.29 Conformance to Regulatory Guide 1.29, Revision 3, September 1978: Seismic Design Classification HCGS complies with Regulatory Guide 1.29, except as noted below. Position C.1.b of Regulatory Guide 1.29 requires the reactor core and reactor vessel internals be designated Seismic Category I and should be designed to withstand the effects of the SSE and remain functional. Application of this guide is limited to those reactor vessel internals that are part of engineered safety features (ESFs), such as core spray piping, core spray sparger and hardware, etc. Position C.1.e of Regulatory Guide 1.29 requires that those portions of the steam systems of boiling water reactors extending from the outermost primary containment isolation valve up to but not including the turbine stop valve and connected piping of 2-1/2 inches or larger nominal pipe size up to and including the first valve that is either normally closed or capable of automatic closure during all modes of normal reactor operation be designated as Seismic Category I and be designed to withstand the effects of a safe shutdown earthquake (SSE) and remain functional. This position also requires that the pertinent quality assurance requirements of Appendix B to 10CFR50 be applied to all activities affecting the safety-related functions of these systems and components. Additionally, the turbine stop valve should be designed to withstand the SSE and maintain its integrity. The main steam line classification and design is based on the approach discussed in Standard Review Plan 3.2.2, Revision 1, July 1981, Appendix B. The main steam lines (MSL) from the second isolation valve up to and including MS stop valve and all the branch lines 2 1/2-inches in diameter and larger between these two valves up to and including the first valve in the branch line is classified under quality group B (ASME Section III, Class 2). The main steam line piping between MS stop and the turbine main stop valve is ASME Section III, Class 3 instead of D classification as required in 1.8-16 HCGS-UFSAR Revision 0 April 11, 1988

Appendix B. This portion of MSL is not classified as safety-related, is not specifically designed to Seismic Category I standards, and is not housed in Seismic Category I structures, as discussed in Appendix B. This different approach satisfies SRP 3.2.2 acceptance criteria requirements and results in an acceptable level of safety. Position C.1.h requires that cooling water and seal water systems or portions of these systems that are required for functioning of Reactor Coolant System components important to safety, such as reactor coolant pumps, be designated and designed as Seismic Category I systems and components. The CRD seal purge and seal cooling from the RACS for the reactor recirculation pumps are not designed to withstand an SSE, as the reactor recirculation pumps do not perform any safety function, and failure does not have serious safety implications. NUREG-0737, Item II.k.3.25 extends the requirements of Position C.1.h by requiring demonstration that the consequences stemming from a loss of cooling water to the reactor recirculation pump seal coolers is acceptable following a loss of ac power for at least 2 hours. NEDO-24951 (Reference 5.5-4) confirms that the HCGS design meets the requirements of NUREG-0737, Item II.k.3.25. NEDO-24083 (Reference 1.8-2) shows that if the seal and cooling systems to the reactor recirculation pump fail to operate, the leakage past the recirculation pump seal is sufficiently small so that no safety concerns exist. Position C.2 of Regulatory Guide 1.29 requires that items that would otherwise be classified non-Seismic Category I, "but whose failure could reduce the functioning" of the items important to safety "to an unacceptable safety level," are to be "designed and constructed so that the SSE would not cause such failure." In addition, Position C.4 of Regulatory Guide 1.29 requires that the pertinent quality assurance requirement of Appendix B to 10CFR50 be applied to the safety requirements of such items. Both these requirements are 1.8-17 HCGS-UFSAR Revision 0 April 11, 1988

considered to be adequately met by establishing the following practices to such items:

1. During the construction and operations phase, design and design control for features of such items that should not fail are carried out in the same manner as for items directly important to safety.

This includes the performance of appropriate design reviews.

2. During the construction phase, field work is performed under the direction of experienced field construction superintendents and is inspected by quality control engineers stationed at the site. The quality control engineers are responsible for verifying that construction is performed in accordance with the design drawings and specifications and with applicable standard codes and specifications.

Field Engineering inspection records may be accepted in lieu of quality control for items installed prior to initiation of this program or for specific cases, such as where disassembly would be required to perform the inspection. Each exception will require approval from Bechtel Quality Assurance.

3. During the construction phase, such items are neither purchased to a code higher than normal system design dictates, nor is the quality assurance program of 10CFR50, Appendix B, applied to their procurement. However, these items are identified in the applicable documents. During the operations phase applicable procurement documents, design modifications documents, and station work orders will be reviewed for designation of appropriate quality assurance controls.

Position C.3 of Regulatory Guide 1.29 requires that Seismic Category I design requirements be extended "to the first seismic restraint beyond the defined boundaries." Since seismic analysis of 1.8-18 HCGS-UFSAR Revision 12 May 3, 2002

a piping system necessitates division of the systems into discrete segments terminated by fixed points, the seismic design cannot be terminated at a seismic restraint. However, it is extended to the first point in the system that can be treated as an anchor to the plant structure. In addition, Position C.4 of Regulatory Guide 1.29 requires that the pertinent quality assurance requirement of Appendix B to 10CFR50 be applied to the safety requirements of such items. Both these requirements are considered to be met adequately by establishing the following practices:

1. During the construction and operations phase, design and design control for such items are carried out in the same manner as for items directly important to safety. This includes the performance of appropriate design reviews.

2. During the construction and operations phase, walk-through inspections are performed by representatives of the originating design group (nuclear engineering department during the operations phase) to ensure that the final installation of such items is in accordance with documents that formed the basis for the seismic analysis of the items.

3. During the construction phase, such items are neither identified as requiring the quality assurance requirements of 10CFR50, Appendix B, nor purchased to a code higher than normal system design dictates.

During the operations phase, applicable procurement documents, design modification documents and station work orders will be reviewed by NQA for designation of appropriate quality assurance controls. See Section 3.2.1 for further discussion of seismic design classification and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-19 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.30 Conformance to Regulatory Guide 1.30 (Safety Guide 30), Revision 0, August 11, 1972: Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment HCGS complies with Regulatory Guide 1.30. See Section 17.2 for further discussion of quality assurance and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.31 Conformance to Regulatory Guide 1.31, Revision 3, April 1978: Control Ferrite Content Stainless Steel Weld Metal (Prior to 2013) Although Revision 3 of Regulatory Guide 1.31 is not applicable to HCGS, per its implementation section, HCGS complies with it, except as stated below. Architect/Engineer procured items and field welding conform to Regulatory Guide 1.31, except as follows. Contrary to Position C.1, C.2, and C.3 of Regulatory Guide 1.31, for HCGS, the procedure for determining the amount of delta ferrite in each heat or lot of austenitic stainless steel filler material is based on the chemical analysis provisions of ASME B&PV Code Section III, NE-2430, using the Schaeffler or DeLong diagrams represented by Figure NE-2433.1-1. Magnetic measurements are taken for comparative purposes only. A magnetic measurement of 3 percent delta ferrite (3 ferrite number) or less is cause to perform additional tests to determine the acceptability of the welding material. Position C.4 of Regulatory Guide 1.31 is complied with for welding material certification to the extent that austenitic stainless steel welding filler materials used in the fabrication and installation of ASME B&PV Code, Section III components are controlled to deposit from 8 to 15 percent delta ferrite (8.5 to 18 ferrite number). Exceptions are 309 and 309L welding filler materials, which are determined by chemical analysis, are in accordance with the controlled to deposit from 5 to 15 percent delta ferrite (5 to 18 ferrite number) and are used only for welding carbon or low alloy steel to austenitic stainless steel. 1.8-20 HCGS-UFSAR Revision 24 May 21, 2020

Use of 309L welding filler material is required for the overlay deposit on the carbon or low alloy steel component nozzles or connecting pipe when postweld heat treatment is required. The specified delta ferrite ranges, as acceptable ferrite number range of 5 to 20. See Section 5.2.3 for further discussion of ferrite control as it pertains to reactor coolant pressure boundary (RCPB) materials and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. Conformance to Regulatory Guide 1.31 Revision 4, October 2013: Control of Ferrite Content in Stainless Steel Weld Metal Hope Creek Generating Station complies with Revision 4 of Regulatory Guide 1.31. Per this revision of the regulatory guide, ferrite content in the weld metal as depicted by a ferrite number (FN) of weld metal used in austenitic stainless steel core support structures, reactor internals, and class 1, 2 and 3 components should be between 5 and 20. The lower limit provides sufficient ferrite to avoid microfissuring in welds, whereas the upper limit provides ferrite content adequate to offset dilution and reduce thermal aging effects. 1.8.1.32 Conformance to Regulatory Guide 1.32, Revision 2, February 1977: Criteria for Safety-Related Electric Power Systems for Nuclear Power Plants Although Regulatory Guide 1.32 is not applicable to HCGS, per its implementation section, HCGS complies with IEEE 308-1974, as endorsed and modified by Regulatory Guide 1.32, subject to the clarification of Position C.1.b, C.1.d and C.1.f. HCGS complies with Position C.1.b of Regulatory Guide 1.32 as discussed in Section 8.3.2.2. Position C.1.d of Regulatory Guide 1.32 references Regulatory Guide 1.75. HCGS compliance to this Regulatory Guide is discussed in Section 1.8.1.75. Position C.1.f of Regulatory Guide 1.32 references Regulatory Guide 1.9. HCGS compliance to this Regulatory Guide is discussed in Section 1.8.1.9. See Chapter 8 for further discussion of the electrical system and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-21 HCGS-UFSAR Revision 24 May 21, 2020

1.8.1.33 Conformance to Regulatory Guide 1.33, Revision 2, February 1978: Quality Assurance Program Requirements (Operation) HCGS complies with the Quality Assurance Program requirements of NQA-1-1994. See the Quality Assurance Topical Report, Appendix C, Section 1.3.1.5 for further discussion. 1.8.1.34 Conformance to Regulatory Guide 1.34, Revision 0, December 28, 1972: Control of Electroslag Weld Properties Regulatory Guide 1.34 is not applicable to HCGS because the process is not used. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.35 Conformance to Regulatory Guide 1.35, Revision 2, January 1976: Inservice Inspection of Ungrouted Tendons in Prestressed Concrete Containment Structures Regulatory Guide 1.35 is not applicable because HCGS does not have a prestressed concrete containment. 1.8.1.36 Conformance to Regulatory Guide 1.36, Revision 0, February 23, 1973: Nonmetallic Thermal Insulation for Austenitic Stainless Steel HCGS complies with Regulatory Guide 1.36. See Section 5.2.3 for further discussion and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-22 HCGS-UFSAR Revision 15 October 27, 2006

1.8.1.37 Conformance to Regulatory Guide 1.37, Revision 0, March 16, 1973: Quality Assurance Requirements for Cleaning of Fluid System and Associated Components of Water Cooled Nuclear Power Plants HCGS complies with NQA-1-1994 and the intent of the regulatory position set forth in the Regulatory Guide. 1.8.1.38 Conformance to Regulatory Guide 1.38, Revision 2, May 1977: Quality Assurance Requirements for Packaging, Shipping, Receiving, Storage, and Handling of Items for Water Cooled Nuclear Power Plants HCGS complies with NQA-1-1994. See the Quality Assurance Topical Report, Appendix C, Section 1.3.1.6 for further discussion. 1.8-23 HCGS-UFSAR Revision 16 May 15, 2008

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1.8.1.39 Conformance to Regulatory Guide 1.39, Revision 2, September 1977: Housekeeping Requirements for Water Cooled Nuclear Power Plants HCGS complies with the requirements of NQA-1-1994. See the Quality Assurance Topical Report, Appendix C, Section 1.3.1.7 for further discussion. 1.8-25 HCGS-UFSAR Revision 15 October 27, 2006

1.8.1.40 Conformance to Regulatory Guide 1.40, Revision 0, March 16, 1973: Qualification Tests of Continuous Duty Motors Installed Inside the Containment of Water Cooled Nuclear Power Plants Regulatory Guide 1.40 and IEEE 334-1971 are not applicable to HCGS as there are no continuous duty Class 1E motors installed inside primary containment. 1.8.1.41 Conformance to Regulatory Guide 1.41, Revision 0, March 16, 1973: Preoperational Testing of Redundant Onsite Electric Power Systems to Verify Proper Load Group Assignments HCGS complies with Regulatory Guide 1.41. For further discussion, see Sections 8.1.4 and 14.2. 1.8.1.42 Conformance to Regulatory Guide 1.42, Revision 1, March 1974: Interim Licensing Policy On As Low As Practicable For Gaseous Radioiodine Releases From Light Water Cooled Nuclear Power Reactors Regulatory Guide 1.42 was withdrawn by the NRC on March 22, 1976. HCGS is committed to Regulatory Guides 1.109, 1.111, and 1.112. 1.8.1.43 Conformance to Regulatory Guide 1.43, Revision 0, May 1973: Control of Stainless Steel Weld Cladding of Low Alloy Steel Components Regulatory Guide 1.43 is not applicable to HCGS. Cladding on low alloy steel components is not used on safety-related components in the non-NSSS scope of supply. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-26 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.44 Conformance to Regulatory Guide 1.44, Revision 0, May 1973: Control of the Use of Sensitized Stainless Steel HCGS complies with Regulatory Guide 1.44, except as noted below. Architect/engineer procured items and architect/engineer field work comply with Regulatory Guide 1.44, subject to exceptions or clarifications stated below that are applied to ASME B&PV Code, Section III equipment and piping in safety-related systems. They are not generally applied to HVAC systems or to instruments. Position C.1 of Regulatory Guide 1.44 is complied with since contamination of austenitic stainless steel (Type 300 series) by compounds that could cause stress corrosion cracking is avoided during all stages of fabrication and installation in accordance with Regulatory Guide 1.37 and ANSI N45.2.1-1973. Nonmetallic materials in contact with austenitic stainless steel are controlled so that halogen and sulfur levels agree with the various Regulatory Guides or ANSI Standards covering these materials. In addition, these materials are removed immediately following the operation in which they are used and prior to any elevated temperature treatment. Penetrant materials may conform to the higher contaminant levels specified in Article 6, Section V, of the ASME B&PV Code, provided that the materials are thoroughly removed and the surface cleaned immediately after the examination has been completed. Crevices and small openings are protected from contamination. Completed components are packaged such that they are protected from the weather, dirt, wind, water spray, and any other extraneous environmental conditions that may be encountered during shipment and subsequent site storage. In the field, austenitic stainless steel components are stored clean and dry. Components either are stored indoors, or, if outdoors, are stored off the ground and covered with tarps. 1.8-27 HCGS-UFSAR Revision 0 April 11, 1988

Contamination of austenitic stainless steels in the field during installation is avoided as described above. The system hydrostatic test and the preoperational testing and final flushing of the completed system is performed with water equivalent to reactor coolant grade. Nonmetallic insulation composed of leachable chloride and fluoride materials that come into contact with austenitic stainless steel are held to the lowest practicable level by the inclusion of the requirements of Regulatory Guide 1.36 in the insulation purchase specifications. Position C.2 of Regulatory Guide 1.44 is complied with since all grades of austenitic stainless steels (Type 300 series) are required to be furnished in the solution heat treated condition before fabrication or assembly into components or systems. The solution heat treatment varies according to the applicable ASME or ASTM material specification. Position C.3 of Regulatory Guide 1.44 covers all austenitic stainless steels furnished in the solution heat-treated condition in accordance with the material specification. During fabrication and installation, austenitic stainless steels are not permitted to be exposed to temperatures in the range of 800 to 1500F, except for welding and hot forming. Welding practices are controlled to avoid severe sensitization, and solution heat treatment in accordance with the material specification is also required following hot forming in the temperature range of 800 to 1500F. Unless otherwise required by the material specification, the maximum length of time for cooling from the solution heat treated temperature to below 800F is specified in the equipment specification. Corrosion testing in accordance with ASTM A 262-70, Practice A or E, may be required if the maximum length of time for cooling below 800F is exceeded, or the solution heat-treated condition is in doubt. No austenitic stainless steel is subjected to service temperatures in the range of 800 to 1500F, as discussed in Position C.4 of Regulatory Guide 1.44. The only exposure of austenitic stainless steels to this range of temperatures occurs on the Containment 1.8-28 HCGS-UFSAR Revision 0 April 11, 1988

Hydrogen Recombiner System (CHRS) and subsequent to solution heat treating during welding. Welding practices are controlled as discussed below. In addition, the architect/engineer supplied austenitic stainless steel piping and valves that form part of the RCPB are fabricated either from L-grade wrought products or castings with controlled ferrite content. During system testing of the recombiner system, the stainless steel does become sensitized. However, stress corrosion occurs only under the presence of condensation upon the metal surface. The formation of condensation is prevented by the use of a trickle treat system. Heat treating austenitic stainless steel in the temperature range of 800 to 1500_F is not permitted and solution heat treatment is required following hot forming as discussed in Position C.5 of Regulatory Guide 1.44. Since sensitization is avoided, testing to determine susceptibility to intergranular attack is not performed. Position C.6 of Regulatory Guide 1.44 covers welding practices that are controlled to avoid severe sensitization in the heat affected zone of unstabilized austenitic stainless steel, as described below. Unless otherwise stated, the position applies to both architect/engineer and architect/engineer suppliers and subcontractors. Intergranular corrosion testing is not performed on a routine basis. The architect/engineer controls weld heat input during field installation by using shielded metal arc welding and gas tungsten-arc welding processes only. The size of electrodes for each process is limited to 5/32-inch and 1/8-inch diameter maximum, respectively, for welding non-L grade material, except for castings with controlled ferrite content. In addition to the above two processes, architect/engineer suppliers and subcontractors are permitted to use automatic submerged arc welding and gas metal arc welding. Hardsurfacing operations are not included. When automatic submerged arc welding or gas metal arc welding is used, or shielded metal arc welding or gas tungsten arc welding is used with 1.8-29 HCGS-UFSAR Revision 0 April 11, 1988

electrodes larger than those specified above, testing in accordance with ASTM A262, Practice A or E, is required unless welding is followed by solution heat treatment. The interpass temperature is controlled so as not to exceed 350F. See Sections 5.2.3 and 6.1 for further discussion and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.45 Conformance to Regulatory Guide 1.45, Revision 0 May 1973: Reactor Coolant Pressure Boundary Leakage Detection Systems HCGS is designed to comply with Regulatory Guide 1.45, with the exceptions, clarifications, and amplifications discussed below. Paragraph C.3 of Regulatory Guide 1.45 requires that three methods of leak detection be provided. HCGS does not employ an airborne particulate radioactivity monitor due to uncertainties in detecting 1 gpm of RCPB leakage in 1 hour. The uncertainties that affect the reliability, sensitivity, and response times of radiation monitors, especially iodine and particulate monitors, are discussed below. The amount of activity becoming airborne following a 1 gpm leakage from the RCPB varies, depending upon the leak location and the coolant temperature and pressure, which affect the flashing fraction and partition factor for iodines and particulates. Thus, an airborne concentration cannot be correlated to a quantity of leakage without knowing the source of the leakage. Coolant concentrations during operation can vary by as much as several orders of magnitude within several hours. These effects are mainly due to spiking during power transients or changes in the use of the Reactor Water Cleanup (RWCU) System. An increase in the coolant concentrations can give increased containment concentrations when no increase in unidentified leakage occurs. 1.8-30 HCGS-UFSAR Revision 0 April 11, 1988

Not all activity is from unidentified leakage. Changes in other sources result in changes in the containment airborne concentrations. For example, identified leakage is piped to the drywell equipment drain sump, but all sump and collection drains are vented to the drywell atmosphere, thereby allowing particulates to escape, causing further measurement uncertainties. The amount of activity that is detected depends upon the amount of plateout on drywell surfaces prior to reaching the detector intake. The amount of plateout is dependent on uncertain quantities, such as location of the leak, distance from the detectors, and the pathway to the detector. Furthermore, under normal operating conditions a radiation-free background does not exist. There is a buildup of activity concentration due to both identified and unidentified leakage. At high equilibrium activity levels, a small change in activity level due to a small leak is hard to detect in the desired time interval. Although particulate monitors are available with sensitivities covering concentrations expected in the drywell, previously discussed uncertainties under operating conditions coupled with any calibration and setpoint uncertainties make particulate monitors a less reliable method of leak detection. HCGS does employ five separate and diverse leak detection methods. The RCPB leak detection system consists of:

1. Seismic Category I qualified drywell floor and equipment drain sump level monitors (in lieu of a Seismic Category I air particulate detection system).

2. A drywell cooler condensate flow monitor.

3. A noble gas monitor, 1.8-31 HCGS-UFSAR Revision 0 April 11, 1988

4. Seismic Category I drywell pressure monitors

5. Seismic Category I drywell temperature monitors.

Leakage flows into the drywell floor and equipment drain sumps are not measured directly due to physical configuration which makes it impractical to do so. As stated in Section 5.2.5.2, leakage flow into the sumps is calculated based on the rate of change of level in the sumps. Sump pump starts and stops and duration of pumpout are monitored by the Class 1E radiation processor. An alarm is annunciated in the main control room whenever pumpout duration exceeds a predetermined time limit. Total sump pumpout can be calculated based on the duration of pumpout and the constant known flowrate of the sump pump provided that only one pump is required to lower the sump level. The starting of the second pump is a positive indication of excessive leakage into the sump or is an indication that the first pump has failed with either event requiring operator action. The high-high level condition which initiated the operation of the second pump is annunciated in the main control room. Paragraphs C.2 and 5 require that the leakage monitors be able to detect an increase in leakage of 1 gpm in 1 hour. The noble gas monitor can detect

                                 -6 concentrations   as   low   as  10    Ci/cc,  the   minimum   activity   concentration expected in the drywell based on the primary system coolant.               However, an increase in 1 gpm leakage within an hour may be difficult to detect due to high
                                                     -6       -4 equilibrium activity levels for noble gases (10           to 10   Ci/cc) and buildup of background radiation.      The noble gas monitor is capable of detecting leaks of approximately 10 gpm and does so very quickly due to the high diffusion rates of the noble gases.

The drywell floor drain sump level monitor and the drywell cooler condensate monitor can detect fluid flows of 1 gpm in 1 hour. However, fluid flow is not always a direct indication of RCPB leakage because of free communication between the suppression 1.8-32 HCGS-UFSAR Revision 0 April 11, 1988

chamber and the drywell. The drywell atmosphere is not necessarily saturated due to the water vapor removal by the drywell coolers. Hot water can evaporate from the torus and enter the drywell. The water will condense and register on the drywell cooler condensate monitor. The condensate drains into the drywell floor drain sump and will register on the sump level monitor. Therefore, during times of suppression pool transients, such as from heat up from main steam safety/relief valve (SRV) or HPCI system testing, evaporation from the suppression chamber will obscure values of RCPB leakage. Position C.7 requires that indicators and alarms for each leakage detection system should be provided in the main control room. Procedures for converting various indications to a common leakage equivalent should be available to the operators. The calibration of the indicators should account for needed independent variables. Position C.7 is further clarified by Standard Review Plan Section 5.2.5, III.5 which requires that if monitoring is computerized, backup procedures should be available to the operator. The drywell air coolers leakage monitoring and noble gas monitoring systems signals are processed by local radiation processors which then transmit the processed data to the main control room via the central radiation processor (CRP). The CRP in turn makes this indicating and alarming information available to the control room operator via CRT displays. These signals are processed locally by local radiation processors (LRPS) which are provided with digital readout indicators. These indicators provide information to the operator in the same format (using the same engineering units) as the information provided by the CRP through the CRTs in the main control room. Since these indications are of the same format, procedures for converting the LRP indication to a common leakage equivalent (to that normally provided in the main control room) are unnecessary. 1.8-33 HCGS-UFSAR Revision 0 April 11, 1988

As described in Section 5.2.5.2, displays of drywell equipment and floor drain sump levels (which are not dependent on the non-1E plant computer systems) are provided on panel 10C604 in the main control room. Position C.8 requires that the leakage detection systems should be equipped with provisions to readily permit testing for operability and calibration during plant operation. This is interpreted to mean channel functional testing as defined in the Technical Specifications (Section 16). Calibration of the leakage detection systems is performed during plant outages per the technical specifications. Calibration of the drywell floor and equipment drain sump level monitoring systems can not be performed at power due to the fact that the sensors are located inside the drywell and are therefore inaccessible during power operation. Rosemount 1153 transmitters are used throughout the plant and are typically calibrated on an 18 month cycle (reference NUREG-0123). This model transmitter is used for the sump level transmitter. In addition, the calibration accuracy of these transmitters can be observed on an ongoing basis by comparing the level readings with known independently measured sump levels at which the sump pumps start or stop. The pumps are started and stopped using electromechanical float switches. It should also be noted that the rate of change readings (sump inflow) obtained from these transmitters will be substantially free from the effects of drift due to the sampling frequency. The sensors for the drywell cooler condensate flow monitoring systems and the drywell temperature monitoring system are also located inside the drywell (and therefore inaccessible during power operation). However, these sensors are LT's and access to them for normal instrument channel calibration is not required. The remaining leak detection monitoring systems discussed above have the capability of being calibrated during operation. For further discussion of the RCPB Leak Detection System, see Section 5.2.5. 1.8-34 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.46 Conformance to Regulatory Guide 1.46, Revision 0, May 1973: Protection Against Pipe Whip Inside Containment Although NRC Regulatory Guide 1.46 was withdrawn by the NRC on March 11, 1985, HCGS commitments, as stated below, are not affected by this withdrawal. The criteria set forth in Regulatory Guide 1.46 are design bases for HCGS. See Section 3.6.2 for further discussion of pipe break design and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.47 Conformance to Regulatory Guide 1.47, Revision 0, May 1973: Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems HCGS complies with Regulatory Guide 1.47. For further discussion of bypass and inoperable status indication, see Sections 7.2, 7.3, 7.4, 7.5 and 7.6. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.48 Conformance to Regulatory Guide 1.48, Revision 0, May 1973: Design Limits and Loading Combinations for Seismic Category I Fluid System Components The information and requirements of Regulatory Guide 1.48 have been superseded by NUREG-0800, Section 3.9.3, Appendix A, Revision 1, July 1981. For further discussion of mechanical component design, see Section 3.9. 1.8.1.49 Conformance to Regulatory Guide 1.49, Revision 1, December 1973: Power Levels of Nuclear Power Plants 1.8-35 HCGS-UFSAR Revision 6 October 22, 1994

HCGS complies with Regulatory Guide 1.49. For further discussion, see Section 15.0.4 and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.50 Conformance to Regulatory Guide 1.50, Revision 0, May 1973: Control of Preheat Temperature for Welding of Low-Alloy Steel HCGS complies with Regulatory Guide 1.50 subject to exceptions and clarifications added below. Position C.1.a of Regulatory Guide 1.50 requires minimum preheat temperatures (Appendix D of ASME B&PV Code, Section III), regardless of whether impact testing is required. When impact testing is required, the requirements of Subarticle 2300 of ASME B&PV Code, Section III, and Regulatory Guide 1.50 are met. The maximum interpass temperature is 500F unless otherwise specified. When impact testing is not required, specification of a maximum interpass temperature in the welding procedure is not necessary to ensure that the required mechanical properties are met. Position C.1.b of Regulatory Guide 1.50 is not complied with since the welding procedure qualification requirements of ASME B&PV Code, Section III and IX, are considered to be more than adequate. With respect to Position C.2 of Regulatory Guide 1.50, usage of low alloy steel in piping, pumps, and valves is minimal and primarily limited to Class 3 construction. When low alloy steel piping, pumps, and valves are used, preheat is maintained until welding is completed but not until postweld heat treatment is performed, since the conditions that cause delayed cracking in the weld or heat affected zone (HAZ) are not present. Position C.4 of Regulatory Guide 1.50 is complied with when the Positions C.1 and C.2 are not met. 1.8-36 HCGS-UFSAR Revision 6 October 22, 1994

For further discussion of RCPB and equipment safety feature (ESF) materials, see Sections 5.2.3 and 6.1.1. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.51 Conformance to Regulatory Guide 1.51, Revision 0, May 1973: Inservice Inspection of ASME Code Class 2 and 3 Nuclear Power Plant Components Regulatory Guide 1.51 was withdrawn by the NRC on July 15, 1975. For discussion of inservice inspection, see Sections 3.9.6, 5.2.4, and 6.6. 1.8.1.52 Conformance to Regulatory Guide 1.52, Revision 2, March 1978: Design, Testing, and Maintenance Criteria for Post-Accident Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light Water Cooled Nuclear Power Plants HCGS complies with Regulatory Guide 1.52, except as stated below:

1. Position C.2.a of Regulatory Guide 1.52 - This position lists the sequence of components that should make up engineered safety feature ESF atmospheric cleanup systems. In the HCGS design, the FRVS vent units do not have demisters, and there are no high efficiency particulate air (HEPA) filters ahead of the carbon adsorbers because the FRVS vent units are downstream of the demisters and HEPA filters in the recirculation units. Each of the FRVS vent trains receives all its air from the discharge of the FRVS recirculation trains.

Therefore, demisters for the FRVS vent trains are not required. The control room emergency filters are not provided with demisters because moisture impingement and water damage is not considered a potential problem. The units recirculate air from the main control room with minimal outside air. 1.8-37 HCGS-UFSAR Revision 13 November 14, 2003

Each of the CREF trains draws a mixture of 1000 cubic feet per minute (CFM) outside air (assumed 100 percent RH) and 3000 CFM room air (50 percent RH) resulting in a mixed air relative humidity at 62 percent. A heating coil is provided for humidity control. Air entering the charcoal filters is expected to be less than 70 percent relative humidity. Sources of excess moisture do not exist which could cause saturated or super saturated mixed air conditions. Therefore, demisters are not required for water droplet removal.

2. Position C.2.g of Regulatory Guide 1.52 - This position requires that the pertinent pressure drops and flow rates on ESF atmosphere cleanup systems be alarmed and recorded in the control room. On the FRVS recirculation units, the pertinent pressure drop, which is instrumented to signal an alarm and record in the main control room, is the pressure drop across the upstream HEPA filters. In addition to this, the pressure drop across the entire filter train is alarmed in the control room, and local differential pressure indication across each filter component is provided. On the CREF units the pertinent pressure drop is the pressure drop across the upstream HEPA filters. This is instrumented to indicate and activate an alarm in the control room and is available in the plant computer. In addition to this, local differential pressure indication across each filter component is provided. CREF and FRVS compliance with minimum instrumentation requirements is provided in Tables 6.5-4 and 6.8-5, respectively.

3. Position C.2.j. of Regulatory Guide 1.52 - Overall design considerations include reduction of radiation exposures during routine maintenance and testing. It is not anticipated, however, that workers will handle filter units immediately after a DBA.

Accordingly, no efforts 1.8-38 HCGS-UFSAR Revision 5 May 11, 1993

are made to provide a unitized atmosphere cleanup train design specifically to facilitate post-accident removal.

4. Position C.2.1 of Regulatory Guide 1.52 - Table 4-3 of ANSI N509-1980 Section 4.12 was used as the acceptance criteria for maximum allowable leakage in ductwork.

5. Position C.3.o of the Regulatory Guide 1.52 - Unusual air flow straightening devices are not installed. Adequate flow distribution is achieved in a low air velocity housing without special devices.

6. The guidance on spacing between components is not followed for HCGS.

Spacing between components may be less than 3 feet where anticipated maintenance does not require this clearance.

7. Regulatory Guide 1.52 references ANSI N510-1975. HCGS testing commitments will follow the ANSI N510-1980 issue.

8. Position C.4.d of Regulatory Guide 1.52 - This position requires the heaters to be on during the 10 hour adsorber and HEPA filter drying run. For Hope Creek, heaters on is considered to be equivalent of heaters dissipating heat.

1.8.1.53 Conformance to Regulatory Guide 1.53, Revision 0, June 1973: Application of the Single Failure Criterion to Nuclear Power Plant Protection Systems HCGS complies with IEEE 379-1972, as endorsed and modified by Regulatory Guide 1.53. See Section 8.1.4.10 for further discussion of compliance with Regulatory Guide 1.53 and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.54 Conformance to Regulatory Guide 1.54, Revision 0, June 1973: Quality Assurance Requirements for Protective Coatings Applied to Water Cooled Nuclear Power Plants HCGS complies with the requirements and guidelines of ANSI N101.4-1972, as endorsed and modified by Regulatory Guide 1.54, 1.8-39 HCGS-UFSAR Revision 10 September 30, 1999

for protective coating applications requiring quality assurance in accordance with 10CFR50, Appendix B. See Section 6.1.2 for further discussion of ESF materials and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.55 Conformance to Regulatory Guide 1.55, Revision 0, June 1973: Concrete Placement in Category I Structures Regulatory Guide 1.55 was withdrawn by the NRC on July 21, 1981. However, the placement of concrete in Seismic Category I structures is in accordance with this Regulatory Guide, with the exceptions discussed below. Positions C.2 and C.3 state the presumed functional responsibilities of the "designer" and the "constructor." The designer's role includes the responsibilities of checking shop drawings and locations of construction joints. For HCGS, the former is fully delegated to the qualified architect/engineer/constructor although the architect/engineer design engineering office may check significant portions and may advise construction accordingly. The responsibility for construction joint location is partially delegated to the field in the sense that the field must follow the guidelines set out in the design drawings and specifications prepared by engineering. For further discussion of the design of Seismic Category I structures, see Section 3.8. This Regulatory Guide is not applicable during the operations phase. 1.8.1.56 Conformance to Regulatory Guide 1.56, Revision 1, July 1978: Maintenance of Water Purity in Boiling Water Reactors HCGS complies with Regulatory Guide 1.56, with exception to Position C.4.c. This exception is discussed in Section 10.4.6.2.1. 1.8-40 HCGS-UFSAR Revision 0 April 11, 1988

For further discussion, see Sections 5.2.3, 5.4.8, and 10.4.6. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.57 Conformance to Regulatory Guide 1.57, Revision 0, June 1973: Design Limits and Loading Combinations for Metal Primary Reactor Containment System Components HCGS complies with Regulatory Guide 1.57, except that the loading combinations and stress limits of Position C.1.b(2) are not used. The loading combinations and stress limits that are used by HCGS in the analysis of the primary containment during a postulated post-LOCA flooded condition are recognized by Standard Review Plan Section 3.8.2, Paragraph II.3.b.iii.e. 1.8.1.58 Conformance to Regulatory Guide 1.58, Revision 1, September 1980: Qualification of Nuclear Power Plant Inspection, Examination, and Testing Personnel NRC Regulatory Guide 1.58 was withdrawn by the NRC on July 31, 1991. HCGS is committed to the requirements of NQA-1-1994. 1.8-41 HCGS-UFSAR Revision 15 October 27, 2006

1.8.1.59 Conformance to Regulatory Guide 1.59, Revision 2, August 1977 with Errata Sheet July 30, 1980: Design Basis Floods for Nuclear Power Plants Although Regulatory Guide 1.59 does not apply to HCGS, per its implementation section, HCGS complies with it. For further discussion of flood design, see Section 2.4.2. 1.8.1.60 Conformance to Regulatory Guide 1.60, Revision 1, December 1973: Design Response Spectra for Seismic Design of Nuclear Power Plants HCGS complies with Regulatory Guide 1.60. For further discussion of the seismic design, see Section 3.7.1. 1.8.1.61 Conformance to Regulatory Guide 1.61, Revision 0, October 1973: Damping Values for Seismic Design of Nuclear Power Plants HCGS complies with Regulatory Guide 1.61. See Section 3.7.1 for further discussion of seismic design and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.62 Conformance to Regulatory Guide 1.62, Revision 0, October 1973: Manual Initiation of Protective Actions HCGS complies with Regulatory Guide 1.62, except as noted below. Position C.1 states that means should be provided for manual initiation of each protective action at the system level. This position requires that the steam isolation dampers, as shown on Plant Drawing M-84-1, for the heating and ventilation systems serving areas 1.8-42 HCGS-UFSAR Revision 20 May 9, 2014

of the Reactor Building that enclose high energy lines, be capable of manual actuation from the main control room. However, there are two redundant automatic isolation dampers in series with separate and redundant power supplies. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.63 Conformance to Regulatory Guide 1.63, Revision 2, July 1978: Electric Penetration Assemblies in Containment Structures for Light Water Cooled Nuclear Power Plants Although Regulatory Guide 1.63 is not applicable to HCGS, per its implementation section, HCGS complies with the design, qualification, construction, installation, and testing requirements of IEEE 317-1976, as modified by Regulatory Guide 1.63, subject to the clarification in Section 8.1.4.12. 1.8.1.64 Conformance to Regulatory Guide 1.64, Revision 2, June 1976: Quality Assurance Requirements for the Design of Nuclear Power Plants NRC Regulatory Guide 1.64 was withdrawn by the NRC on July 31, 1991. HCGS is committed to the requirements of NQA-1-1994. 1.8.1.65 Conformance to Regulatory Guide 1.65, Revision 0, October 1973: Materials and Inspections for Reactor Vessel Closure Studs Regulatory Guide 1.65 is not applicable. 1.8-43 HCGS-UFSAR Revision 15 October 27, 2006

See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.66 Conformance to Regulatory Guide 1.66, Revision 0, October 1973: Nondestructive Examination of Tubular Products Regulatory Guide 1.66 was withdrawn by the NRC on September 28, 1977. See Section 5.2.3 for further discussion of testing on mechanical components and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.67 Conformance to Regulatory Guide 1.67, Revision 0, October 1973: Installation of Overpressure Protection Devices Regulatory Guide 1.67 is not applicable to HCGS because there are no open discharge lines where reaction forces are considered to be significant. 1.8.1.68 Conformance to Regulatory Guide 1.68, Revision 2, August 1978: Initial Test Programs for Water Cooled Nuclear Power Plants HCGS complies with Regulatory Guide 1.68, with the exceptions and clarifications discussed below. Position C.1 provides the criteria for selection plant features that are tested during the initial test program. At HCGS, testing is conducted on structures, systems, components, and design features as described in Section 14.2, based on their safety-related functions. See Section 3.9.2 for further discussion of dynamic testing and analysis. 1.8-44 HCGS-UFSAR Revision 6 October 22, 1994

The objective of Regulatory Guide 1.68 is to describe the scope and depth of a test program, as required, to ensure that plant structures, systems, and components perform satisfactorily in service. The basis for this Regulatory Guide is Appendix B to 10CFR50, which specifically applies only to testing the performance of safety-related functions. Therefore, this Regulatory Guide is applied only to plant structures, systems, and components that have safety-related functions, defined as those plant features necessary to ensure the integrity of the RCPB, the capability to shut down the reactor and maintain it in a safely shutdown condition, or the capability to prevent or mitigate the consequences of accidents that could result in offsite exposures comparable to the guideline exposure of 10CFR50.67. Safety-related structures, systems, and components are identified as such in Chapter 14 and are tested to meet the requirements of Regulatory Guide 1.68. Other systems and components within the plant that are not safety-related may or may not be tested in accordance with the Regulatory Guide. Since the plant units that are not safety-related by definition do not compromise the safety-related aspects of the plant, it is not planned to test them to the Regulatory Guide. Regulatory Position C.7 and Section 1.h of Appendix C state that one of the objectives of the initial test program is to verify by trial use that the facility operating and emergency procedures are adequate. Because preoperational test procedures are intended to demonstrate system design criteria, they are conducted under system configurations and conditions different than those required by facility operating and emergency procedures. Therefore, operating and emergency procedures are proven independent of the preoperational test procedures. 1.8-45 HCGS-UFSAR Revision 17 June 23, 2009

Section 1 of Appendix A states that system vibration, expansion, and restraints may be verified by observation as allowed during power-ascension testing by Section 5.0.0 of Appendix A. This position statement does not apply to the vibration monitoring of reactor internals. Section 1.1 of Appendix A states that spiked samples should be used where necessary to verify the operability of radioactive waste handling and storage systems. The functional testing of these systems is accomplished without the use of spiked samples of typical media, use of which is also not considered necessary to verify conformance to the design.

1. Appendix A, Paragraph 1.a(1), 1.1.(1), 1.e - General Electric BWRs have performed hot functional tests during initial heatup following fuel load. System expansion, hanger, seismic, and restraint checks not performed prior to fuel load will be performed during the initial heatup after fuel load. Prior to nuclear heatup and plant operation, there is no practical mechanism to accomplish integrated system heatup on the reactor coolant system, main steam system, feedwater system, steam extraction system, and HPCI/RCIC steam lines.

Therefore, the expansion tests are deferred to Phase III startup testing. The Section 14 test descriptions associated with expansion testing following fuel load are Sections 14.2.12.3.15 and 14.2.12.3.39. The systems subject to expansion testing are discussed in Section 3.9.2. Figures 14.2-4 and 14.2-5 describe when expansion testing will be performed.

2. Appendix A, Paragraphs 1.a(3), 4.s, 5.p - Regulatory Guide 1.20, Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing, is addressed in Section 1.8.1.20. Hope Creek is a Regulatory Guide 1.20 Non-Prototype, Category 1 1.8-46 HCGS-UFSAR Revision 0 April 11, 1988

plant. Therefore, Hope Creek will implement the inspection program as permitted by Paragraph 3.1.2 of Regulatory Guide 1.20. During the preoperational test phase, the reactor internals will be inspected following flow through the vessel as part of the standard BWR test program. No further testing is planned following fuel load. Paragraph 2.2.2.C of Regulatory Guide 1.20 states that the vibration test may be conducted without fuel assemblies (or dummy assemblies) if it can be shown by analytical or experimental means that such conditions yield conservative results. The study of prototype test data by General Electric (refer to Reference 3.9-12) has shown vibration response amplitudes are conservative in preoperational test conditions as compared to operating conditions. Therefore, HCGS will perform the preoperational phase inspection program with no fuel assemblies (rated volumetric flow for 35 hours balanced two loop operation and single loop flow for 16 hours each loop with pre and post vessel internal inspections).

3. Appendix A, Paragraph 1.b(3) - Verification of proper mixing of the solution is not performed as part of the preoperational test program.

Just prior to fuel load, the solution is mixed and sampled using the station operating procedures.

4. Appendix A, Paragraph 1.c - Compliance with Regulatory Guide 1.118, Periodic Testing of Electric Power and Protection Systems, is addressed in Section 1.8.1.118. Regulatory Guide 1.118 will be used as guidance for preoperational tests.

5. Appendix A, Paragraph 1.d - Compliance with Regulatory Guide 1.41, Preoperational Testing of Redundant Onsite Electric Power Systems to Verify Proper Load Group Assignments, is addressed in Section 1.8.1.41.

1.8-47 HCGS-UFSAR Revision 0 April 11, 1988

6. Appendix A, paragraph 1.e - Compliance with Regulatory Guide 1.68.1, Preoperational and Initial Startup Testing of Feedwater and Condensate System for BWR Plants, is addressed in Section 1.8.1.68.1.

7. Appendix A, Paragraph 1.g(2) - Emergency loads are tested with nominal voltage available at the emergency ac power distribution system buses. The power source to these buses is either from offsite (normal) or onsite (standby). When the bus is supplied from the onsite source, the available voltage is maintained within specified limits to verify proper functioning and loading of the onsite source.

Test abstracts are presented in Sections 14.2.12.1.30, 14.2.12.1.32 and 14.2.12.1.33. Testing of emergency loads with maximum and minimum design voltage available is not considered necessary because the station distribution system is designed to maintain voltages to support starting and operating of loads within their design limits. The station distribution system has been analyzed in accordance with BTP PSB-1 to establish minimum and maximum voltages under several operating conditions with only the offsite source considered available. Actual test voltage at selected points on the station distribution system will be taken and compared with the calculated voltages to validate the analysis performed.

8. Appendix A, Paragraph 1.g(3) - Compliance with Regulatory Guide 1.108, Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants, is addressed in Section 1.8.1.108.

Compliance with Regulatory Guide 1.9, Selection, Design and Qualification for Diesel Generator Units Used as Onsite Electric Power System at Nuclear Power Plants, is addressed in Section 1.8.1.9. 1.8-48 HCGS-UFSAR Revision 0 April 11, 1988

9. Appendix A, Paragraph 1.h(10) - There is no practical way to verify the maximum heat removal capability of the UHS. Flow paths are demonstrated to show the proper operation of equipment and structures used to transport the water to and from the UHS. The ultimate heat sink (UHS) is the Delaware River, which provides the source of cooling water to the SACS heat exchangers through the Station Service Water System (SSWS). The UHS has been designed in accordance with the requirements of Regulatory Guide 1.27 and is described in Sections 9.2.5 and 9.2.1. The UHS has been designed to perform during periods of adverse meteorological conditions which result in maximum water consumption and minimum cooling capability as stated in Section 9.2.5.1.2. Therefore, it is not practical to verify the maximum heat removal capability of the UHS.

A description of tests for station service water and safety auxiliaries cooling systems to deliver cooling water to their components is provided in Sections 14.2.12.1.12 and 14.2.12.1.16, respectively. Also a description of the test to demonstrate that safety auxiliaries cooling system performance margin is adequate to support engineered safety features equipment over their full range of design requirements is provided in Section 14.2.12.3.38. Performance test for each service water pump was conducted and performed in accordance with approved HTPCo procedures for the test and in accordance with the ASME Power Test Code 8.2, 1965 and the standards of the Hydraulic Institute. The pump was tested with the bell submerged 4 feet 6 inches below the design water level which is 76 feet 0 inches (In addition, Hope Creek Technical Specifications require a plant shutdown at 80 feet PSE&G datum.). Test demonstrated adequate net positive suction head and absence of vortexing at the minimum postulated river level, which is 81 feet 0 inches. Model 1.8-49 HCGS-UFSAR Revision 9 June 13, 1998

studies were conducted at Lasalle Hydraulic Lab to ensure acceptable conditions in the pump sump. The measures suggested in the test, were taken in order to avoid vortices.

10. Appendix A, Paragraph 1.h(7) - Compliance with Regulatory Guide 1.52, Design, Testing and Maintenance Criteria for Engineered Safety Feature Atmospheric Cleanup System of Light Water Cooled Nuclear Power Plants, is addressed in Section 1.8.1.52.

11. Appendix A, Paragraphs 1.k(2) & (3) - Preoperational testing of personnel radiation monitoring and survey equipment or laboratory equipment is not performed. Calibration tests are performed prior to core load in accordance with station procedures.

12. Appendix A, Paragraphs 1.m(4) & 1.0(1) - Regulatory Guide 1.104 was withdrawn by the NRC on August 22, 1979. During preoperational testing, the cranes will be verified to function in accordance with specifications. The controls, interlocks, and travel limits of the reactor building and fuel handling cranes are verified.

13. Appendix A, Paragraph 1.n(11) - Compliance with Regulatory Guide 1.80, Preoperational Testing of Instrument Air Systems, is addressed in Section 1.8.1.80.

14. Appendix A, Paragraph 2.c - The Reactor Protection System will be functionally checked in accordance with the HCGS Technical Specification prior to initial criticality using station surveillance and calibration procedures. The Reactor Protection System is shown to operate in conjunction with the control rod drive startup test, 1.8-50 HCGS-UFSAR Revision 0 April 11, 1988

described in Section 14.2.12.3.8. Also, the Reactor Protection System is verified to operate following scheduled transient tests such as MSIV isolation and turbine trip/generator load rejection.

15. Appendix A, Paragraph 5.0 - Setpoints related to leak detection high steam flow in HPCI and RCIC are determined and set as stated in Sections 14.2.12.3.12 and such as drywell equipment drain sump pump will be accomplished using station operating procedures.

16. Appendix A, Paragraph 2.e - Compliance with Regulatory Guide 1.56, Maintenance of Water Purity in Boiling Water Reactors, is addressed in Section 1.8.1.56.

17. Appendix A, Paragraph 4.m - Following fuel load, there is no planned startup test of the MSIV leak control system. The preoperational test demonstrates the operability of the system at design conditions.

Testing following fuel load does not contribute any additional meaningful data. The HCGS sealing system is a positive pressure system not a vacuum system. A vacuum system's operation could be affected by hot steam pipe because this could elevate the temperature of the vacuum system. In contrast, hot steam pipe will have no affect on the operation of a positive pressure system that "pumps" sealing gas into the steam pipe rather than "pumping" gas out of the steam pipe. Therefore, testing the HCGS system at ambient temperatures should be sufficient.

18. Appendix A, Paragraph 4.p - Main steam system relief valve testing will be performed at a power level between 10 and 20 percent of rated thermal power in order to provide adequate control of system pressure.

1.8-51 HCGS-UFSAR Revision 0 April 11, 1988

19. Appendix A, Paragraph 5.j - Rod runback and partial scram testing is not performed because the plant does not have this design feature.

20. DELETED

21. Appendix A, Paragraph 5.q - There are no startup tests of the failed fuel detection systems. Preoperational testing and periodic surveillance testing after fuel load ensure the proper operation of radiation monitoring systems used for isolation signals in case of gross fission product release. Data is recorded from these systems and used as baseline data. There will be no Phase III Startup Test entitled "Failed Fuel Detection System". Two systems at Hope Creek routinely monitor gaseous activities which result from fission product release from the fuel: the Main Steam Process Radiation Monitoring subsystem, and the Offgas Radiation Monitoring subsystem.

Startup test procedure No. 1, Chemical and Radiochemical, states that gaseous activities will be measured at each major power level plateau, as defined in Figures 14.2-4 and 14.2-5. The test method has been revised to state that baseline data will be documented (Section 14.2.12.3.1).

22. Appendix A, Paragraph 5.s - Although there will be no startup test procedure designated hotwell level control, operation of the hotwell level control system will be verified using station operating procedures and monitoring hotwell level during Phase III startup testing.

1.8-52 HCGS-UFSAR Revision 14 July 26, 2005

23. Appendix A, Paragraph 5.dd - Compliance with Regulatory Guide 1.68.2, Initial Startup Test Program to Demonstrate Remote Shutdown Capability for Water Cooled Nuclear Power Plants, is addressed in Section 1.8.1.68.2.

24. Appendix A, Paragraph 5.gg - The ATWS subsystems are thoroughly checked out logically and functionally during the preoperational test program, as described in Sections 14.2.12.1.2.c.6, 14.2.12.1.3.c.3, 14.2.12.1.4.c.4, 14.2.12.1.8.c.9, 14.2.12.1.9.c.7, and 14.2.12.1.10.c.4. The recirculation pump trip (RPT) is tested as part of the recirculation system tests and generator/turbine trips that are performed in Phase III testing.

25. Appendix A, Paragraph 5.ii - Hope Creek design does not incorporate the recirculation flow control valve.

26. Appendix A, Paragraph 4.o - For the purpose of initial turbine generator testing conducted in the Low Power Testing program the nominal 5 percent power limitation will be extended to 10 percent power. All other low power testing will be conducted within the 5 percent power limitation.

1.8.1.68.1 Conformance to Regulatory Guide 1.68.1, Revision 1, January 1977: Preoperational and Initial Startup Testing of Feedwater and Condensate Systems for Boiling Water Reactor Power Plants HCGS complies with the intent of Regulatory Guide 1.68.1. For further discussion of the initial test program, see Section 14. 1.8.1.68.2 Conformance to Regulatory Guide 1.68.2, Revision 1, July 1978: Initial Startup Test Program to Demonstrate Remote Shutdown Capability for Water-Cooled Nuclear Power Plants 1.8-53 HCGS-UFSAR Revision 8 September 25, 1996

HCGS complies with the intent of Regulatory Guide 1.68.2. For further discussion of the initial test program, see Section 14. 1.8.1.68.3 Conformance to Regulatory Guide 1.68.3, Revision 0, April 1982: Preoperational Testing of Instrument and Control Air Systems HCGS complies with Regulatory Guide 1.68.3, with the following exceptions and clarifications discussed below:

1. Deleted

2. Position C.5 - Observation of branch line pressure during maximum system service is sufficient to ensure that total air demand is in accordance with system design.

2.1 Position C.6 - The Instrument Air System afterfilter is designed to remove 0.04 micrometer particles with 98 percent efficiency. The system is designed to permit preventive or corrective maintenance on one dryer and afterfilter train without affecting system operability. Therefore, quarterly replacement of the afterfilter assures that the maximum particle size in the air stream at the instrument is 5.0 micrometers.

3. Positions C.7 and 8 - Each safety-related component is tested on an individual basis to ensure that the subject component responds safely to all failure modes.

4. Position C.10 - All safety-related air operated loads either fail to their safe position on loss of instrument air or are provided with an accumulator which ensures operation following a loss of air condition. Each safety-related component is tested on an individual basis 1.8-54 HCGS-UFSAR Revision 17 June 23, 2009

to ensure that the subject components respond safely to a failure mode. Safety-related components are verified for proper operation during loss of instrument air in accordance with Section 14.2.12.1.27.c.4.

5. Position C.11 - The instrument air system is provided with pressure relief valves which ensure that no safety-related components will be subjected to air pressure above their design value. Instrumentation has been provided to automatically trip compressors upon high air pressure in the receiver. Relief valve setpoints will be checked and instrumentation calibration completed prior to performing the preoperational test in accordance with Section 14.2.12.1.27.

1.8.1.69 Conformance to Regulatory Guide 1.69, Revision 0, December 1973: Concrete Radiation Shields for Nuclear Power Plants HCGS complies with ANSI N101.6-1972, as endorsed and modified by Regulatory Guide 1.69. For further discussion of concrete shielding, see Section 12.3.2. 1.8.1.70 Conformance to Regulatory Guide 1.70, Revision 3, November 1978: Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants, LWR Edition The HCGS FSAR conforms to the format and content requirements of Regulatory Guide 1.70 with the following clarification: The FSAR was written in accordance with the guidance of Regulatory Guide 1.70, Revision 3. Additionally, PSEG Nuclear will utilize Regulatory Guide 1.181 in conjunction with NEI 98-03, Guideline for Updating Final Safety Analysis Reports, as guidance for maintaining the UFSAR in accordance with the requirements of 10 CFR 50.71(e). 1.8-55 HCGS-UFSAR Revision 20 May 9, 2014

1.8.1.71 Conformance to Regulatory Guide 1.71, Revision 0, December 1973: Welder Qualification for Areas of Limited Accessibility HCGS complies with Regulatory Guide 1.71, subject to the exceptions and clarifications described below. Position C.1 states that the performance qualification should require testing of the welder under simulated restricted access conditions. At HCGS, performance qualifications for personnel who weld under conditions of limited access, as defined in Position C.1 of Regulatory Guide 1.71, are conducted in accordance with the applicable requirements of ASME B&PV Code, Sections III and IX. Additionally, responsible site supervisors are required to assign only the most highly skilled welders to limited access welding. Welding conducted in areas of limited access is subjected to the required nondestructive testing and no waiver or relaxation of examination methods or acceptance criteria because of the limited access is permitted. Position C.2 of Regulatory Guide 1.71 requires requalification when significantly different restricted accessibility conditions occur or when any of the essential welding variables in Section IX changes. At HCGS, requalification is required whenever any of the essential variables of ASME B&PV Code, Section IX, are changed, or when any authorized inspector questions the ability of the welder to perform the requirements of ASME B&PV Code, Sections III or IX satisfactorily. Concerning Position C.3, production welding is monitored and welding qualifications are certified in accordance with Positions C.1 and C.2. See Section 5.2.3, Chapter 17, for further discussion of welding procedures and quality assurance and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-56 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.72 Conformance to Regulatory Guide 1.72, Revision 2, November 1978: Spray Pond Piping Made From Fiberglass Reinforced Thermosetting Resin Regulatory Guide 1.72 is not applicable to HCGS because HCGS does not use a spray pond for its UHS. 1.8.1.73 Conformance to Regulatory Guide 1.73, Revision 0, January 1974: Qualification Tests of Electric Valve Operators Installed Inside the Containment of Nuclear Power Plants HCGS complies with IEEE 382-1972, as endorsed and modified by Regulatory Guide 1.73, subject to the exceptions and clarifications described below. Valve motor actuators may be qualified by either analysis and successful use under similar conditions, or by actual type tests, as permitted by Section III of Appendix B to 10CFR50. Where type tests are proposed by a manufacturer, IEEE 382-1972, together with the specified accident environment, is used as the basis for evaluating the test program. See Section 3.11 for further discussion of environmental qualification of electrical equipment and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.74 Conformance to Regulatory Guide 1.74, Revision 0, February 1974: Quality Assurance Terms and Definitions NRC Regulatory Guide 1.74 was withdrawn by the NRC on September 1, 1989. HCGS complies with the requirements of NQA-1-1994. 1.8-57 HCGS-UFSAR Revision 15 October 27, 2006

1.8.1.75 Conformance to Regulatory Guide 1.75, Revision 2, September 1978: Physical Independence of Electric Systems HCGS complies with IEEE 384-1974, as modified and endorsed by Regulatory Guide 1.75, Revision 2, with the clarifications and exceptions outlined below. Position C.1 electrical separation is accomplished at HCGS per IEEE 384-1992 which was endorsed by Regulatory Guide 1.75 Rev. 3. This revision states, The breaker or fuse that is automatically open by fault current may be used as an isolation device.... HCGS use of isolation devices are used as defined in this standard. Isolation devices that are actuated only by a fault current are coordinated such that upstream circuit protection devices are not affected by a non-Class 1E fault. Where fuses are used as isolation devices, two series Class 1E fuses are used to provide additional assurance that non-Class 1E faults do not propagate to the Class 1E bus. Position C.1 separation is accomplished in general by supplying non-Class 1E loads connected to a Class 1E bus through a single breaker with a shunt trip device tripped by a LOCA signal. In these cases, non-Class 1E loads will be tripped automatically by LOCA signal. Provisions for restoring certain of these loads from the main control room are provided. For normal (non-accident) conditions, the breakers which are Class 1E and are equipped with overcurrent protective devices, will trip on fault currents in the non-Class 1E loads such that the Class 1E buses remain functional. The breakers' LOCA trip function and overcurrent protective devices are periodically tested during plant operation to ensure operability. This method of meeting Position C.1 ensures that the ESF, RPS and NMS electrical and physical separation requirements are maintained. The cables beyond the breakers are non-Class 1E and are not run in the same raceways as the divisionalized cables of the ESF systems, 1.8-58 HCGS-UFSAR Revision 22 May 9, 2017

RPS, and NMS. Section 8.1.4.14.1 indicates that the raceways for the ESF systems, RPS, and NMS are separate and independent of each other and are separated from non-Class 1E circuits. The remaining clarifications and exceptions are associated with Regulatory Guide 1.75, Revision 2, and IEEE Std. 384-1974. Position C.6 states that all analyses to justify lesser separation distances shall be identified. The following are the HCGS exceptions to the IEEE 284 separation distances. A. There are six generic cases where analysis and/or test data are used to justify lesser separation distances. These are identified and analyzed as follows:

1. Conduit to conduit less than one (1) inch apart.

Because of space limitations in some areas of the plant, the minimum separation distance of one inch between rigid steel conduits can not be maintained. The use of the conduits is limited to instrumentation to instrumentation control to control, and instrumentation to power feeder with maximum 120 V ac or 125 V dc cables only. Wyle Test Report No. 56719, prepared for Susquehanna Steam Electric station, showed that rigid steel conduits in contact with each other are acceptable barriers. The testing demonstrated that shorting of conductors in one conduit until failure did not affect the performance of the conductors in the other conduit or damage the conduit. In addition, Franklin Institute Research Laboratories (FIRL) performed similar testing for the Toledo Edison Company in 1977 with successful results. The test configuration and cables used conservatively bound the HCGS conditions; therefore, the limited cases where the HCGS separation has not been met in the installation are justified. The two reports referenced have been submitted under separate cover, by letter from R. L. Mittl, PSE&G, to A. Schwencer, NRC, dated August 30, 1984. 1.8-59 HCGS-UFSAR Revision 22 May 9, 2017

Based on the results of this test and analysis program, separation criteria for Class 1E conduit has been established which assures that 1) any failure or occurrence in a Class 1E conduit will not degrade a redundant essential Class 1E circuit in adjacent Class 1E conduits, 2) a failure or occurrence in a non-Class 1E conduit will not degrade redundant essential Class 1E circuits in adjacent Class 1E conduits. The criteria established are as follows:

a. Circuits carrying control, instrumentation, or power cable (where the power cable is limited to 480 volt or lower and No. 12 AWG or smaller) are allowed to touch each other.

b. Conduit carrying essential Class 1E 4.15 kV power cables or 480 volt load center power cables will have a one inch minimum separation from conduits carrying Class 1E circuits of a redundant channel.

c. Conduit carrying non-essential 13.8 kV, 4.16 kV, or 480 volt load center cables that bridge conduits carrying essential Class 1E circuits of redundant channels will be separated from conduit carrying circuits of the redundant channel to give a minimum separation of one inch.

d. Conduit carrying essential Class 1E power cable of 480 volt or lower voltage with conductor size larger than number 12 AWG, and not covered by b. above, will meet the following criteria:

1. Will have a minimum of 1/8-inch separation from the surface of any conduit crossing above which contains an essential Class 1E circuit of the redundant channel.

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2. Are allowed to touch conduits containing an essential Class 1E circuit of the redundant channel when installed in horizontal, side by side configuration.

3. Will have a minimum separation of one inch from conduits containing an essential Class 1E circuit of the redundant channel mounted directly above and running parallel.

e. Conduit carrying non-essential power cable of 480 volt or lower voltage with conductor size larger than number 12 AWG, and not covered by 3. above, that bridge conduits carrying essential Class 1E circuits of redundant channels will be treated as in d.1,2 and 3 for proper separation from the redundant channel.

2. Non-Class 1E conduit separation from Class 1E tray.

In safety-related areas of the plant there are non-Class 1E rigid steel conduits within one inch of Class 1E tray. The non-Class 1E conduit contains only control, instrumentation or power cables. HCGS performed a series of tests to demonstrate the adequacy of the rigid steel conduit as an effective barrier for protection of cables in open tray from faulted cables within the rigid steel conduit. The test results are documented on Wyle Test Report No. 17730-01 which has been submitted to the NRC as discussed in Section 8.1.4.14.3.1. The tests showed that a rigid steel conduit containing a faulted cable of one 500 kcmil or three No. 2/0 AWG cables and separated by 1/2 inch from an open tray acted as an effective barrier. 1.8-61 HCGS-UFSAR Revision 0 April 11, 1988

Based on the tests, the following configurations are considered acceptable:

a. Rigid steel conduit containing non-Class 1E cables no larger than 500 kcmil with service voltage no higher than 480 V ac and separated a minimum of 1 inch from an open tray containing Class 1E control and instrumentation cables.

b. The minimum separation distance of 1 inch, measured either from the top or bottom of the tray surface to the conduit surface, may be reduced to 1/2 inch provided that the size of the cable in the conduit is no larger than No. 2/0 AWG.

c. In cases that are not within the boundary of Items a and b above, a cable tray cover will be provided.

3. Metal clad cable separation from Class 1E raceways.

Metal clad cables, type MC, are used in non-Class 1E circuits only. The minimum separation between the metal clad cable and Class 1E raceways (open top trays or conduits) is one inch. The type MC cable is a factory assembly of one or more conductors each individually insulated, covered with an overall insulating jacket and all enclosed in a metallic sheath of interlocking galvanized steel. The cable has passed the vertical flame test of IEEE 383-1974. HCGS performed tests on the separation configuration of metal clad cable to open top tray. The test results are documented on the same Wyle test report described in Paragraph 2 above. One test showed that a faulted No. 2 AWG metal-clad cable can cause a cable in the open top 1.8-62 HCGS-UFSAR Revision 0 April 11, 1988

tray to exceed its qualified temperature for approximately 2 minutes while the temperature of other cables within the tray remained within acceptable limits during the fault condition. A repeat test was performed with successful results. A minimum of 3/4-inch separation distance between the metal clad cable and tray surfaces was used in tests. Based on the tests, the following separation criteria are considered acceptable:

a. A non-Class 1E metal clad cable shall be separated by a minimum of 6 inches from Class 1E open tray surface, top or bottom. The largest metal clad cable shall be No. 2 AWG.

b. If the criterion of Paragraph a cannot be met, then a tray cover will be installed, or the metal clad cable will be wrapped with Siltemp material. The installation of the tray cover or Siltemp shall be sufficient to prevent any possible contract between the surfaces of the metal-clad cable and cables in the tray.

4. Armor clad and antenna cables' separation from Class 1E trays.

Armor clad cables are used in non-Class 1E circuits only. This type of cable is a factory assembly of insulated conductors enclosed in a metallic sheath formed from interlocking galvanized steel strip. Use of this cable is limited to lighting system applications. The antenna cables for the UHF radio system are non-Class 1E. These cables, designated by tradenames of Heliax and Radiax, are constructed of a flame retardant jacket over a 1.8-63 HCGS-UFSAR Revision 0 April 11, 1988

copper-corrugated strip which encloses the dielectric and center conductor. HCGS performed a series of tests to demonstrate the adequacy of the separation distance between these cables and an open tray. The test results are documented on the same Wyle Test Report described in Paragraph 2 above. The tests showed that a faulted armor clad or Heliax cable separated by 1 inch from an open tray did not impact the cables in the tray. Based on the tests, the following separation criteria are considered acceptable.

a. Non-Class 1E armor clad cable with maximum conductor size of No. 10 AWG shall have a minimum separation of 1 inch from an open tray containing Class 1E control and instrumentation cables.

b. Non-Class 1E UHF radio system antenna cables (Heliax and Radiax shall have the same separation as in Paragraph a above.

5. Free air cable drop separation.

Certain cable installations require that a cable enter or leave from a cable tray or enclosure without enclosing the cable in a conduit. The cable is considered as a free-air cable (unsupported) and it may be exposed to other Class 1E cables or conduits. HCGS performed a series of tests to demonstrate the adequacy of separation configurations that are representative of the free air cable installations. The test results are documented on the same Wyle Test Report 1.8-64 HCGS-UFSAR Revision 0 April 11, 1988

described in Paragraph 2. above. The tests showed that the following configurations are acceptable:

a. A free air power cable of No. 2/0 AWG and separated by 1 inch from a rigid steel conduit containing instrumentation cable of No. 16 AWG size.

b. A free air instrumentation cable of No. 16 AWG and separated by 1 inch from a rigid steel conduit containing a power cable of No. 2/0 AWG size.

c. A free air control cable of No. 14 AWG size separated by a minimum of 1 inch from a power cable of 500 kcmil size which is wrapped with Siltemp material.

d. Siltemp material is an acceptable separation barrier.

The above testing represented worst case generic configurations and established minimum separation distances. Specific configurations are reviewed for conformance with the limits established by the tests. In cases where the free air cable installation does not conform with the above, the free air cable will be wrapped with Siltemp material or enclosed in conduit until the minimum separation distance of 1 inch is met.

6. Neutron Monitoring System cables under reactor pressure vessel.

Due to spatial limitation beneath the reactor pressure vessel and the need for movement of Neutron Monitoring System (NMS) detectors and control rod drive (CRD) position indicators during plant operation, the separation requirement defined in Section 8.1.4.14 for NMS channels 1.8-65 HCGS-UFSAR Revision 0 April 11, 1988

cannot be met in this area. Specifically, the conduits for redundant NMS cables do not enclose the entire cable lengths from the pedestal wall to the cable end connectors and less than 1 inch separation between conduits is necessary to allow for proper routing, distribution, and connection of cables to the NMS detectors. The less than 1 inch separation between conduits is considered acceptable per the analysis described in Paragraph 1. above because NMS cables are for instrumentation. In addition, the NMS and CRD systems are powered from non-Class 1E sources. Therefore, failure or faults on these cables do not impact Class 1E power sources. A single failure analysis for the neutron monitoring and process radiation monitoring systems, dated August 1984, was submitted to the NRC by letter dated September 9, 1984, R. L. Mittl, PSE&G, to A. Schwencer, NRC. The above analysis identified the cases on a generic level. The installation and inspection of raceways are ongoing and the specific cases where the analysis applies are documented on nonconformance reports that are part of the Nuclear Oversight Quality Verification Inspection program. B. Position C.1, section 3.8, requires an isolation device be used to separate class 1-E and non-class 1-E equipment. Revision 2 of this regulatory guide supplements this requirement by stating, interrupting devices actuated only by a fault current are not considered to be isolation devices. Justification to attach test equipment to associated circuitry of an OPERABLE emergency diesel during periodic monthly and 24 hour run surveillance testing, is documented in evaluation H2001-003. A failure modes effect analysis of all connection points to the control circuitry provides assurance that diesel operability is not compromised. Position C.12 states that redundant cable spreading areas should be provided. HCGS has only a single cable spreading area. Position C.12 endorses IEEE 384-1974, Paragraph 5.1.3, which indicates that in cable spreading areas the minimum separation distance between redundant Class 1E cable trays should be 1 foot between trays separated horizontally and 3 feet between trays separated vertically. The separation criteria used on HCGS for cable spreading areas is a minimum of 1 foot horizontal distance and 18 inch vertical distance between redundant Class 1E cable trays. See Section 8.1.4.14.3.1 for justification of this vertical separation distance. 1.8-66 HCGS-UFSAR Revision 14 July 26, 2005

Position C.15 specifies that redundant Class 1E batteries be located in separate safety class structures and be served by independent ventilation systems. The 250 V Class 1E batteries for electrical divisions A and B, located on Elevation 163 feet of the Auxiliary Building, are served by a common ventilation exhaust system that has redundant exhaust fans but not independent ductwork. See Section 8.1.4 for further discussion of electrical separation and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.76 Conformance to Regulatory Guide 1.76, Revision 0, April 1974: Design Basis Tornado for Nuclear Power Plants HCGS complies with Regulatory Guide 1.76. For further details on protection of HCGS against tornadoes, see Sections 2.3.1.2 and 3.3.2. 1.8.1.77 Conformance to Regulatory Guide 1.77, Revision 0, May 1974: Assumptions Used for Evaluating a Control Rod Ejection Accident for Pressurized Water Reactors Regulatory Guide 1.77 is not applicable to HCGS. 1.8.1.78 Conformance to Regulatory Guide 1.78, Revision 0, June 1974: Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release The HCGS design meets the requirements of Regulatory Guide 1.78. Postulated accidents regarding hazardous chemicals stored at the HCGS and SGS, and frequently shipped past the site were evaluated. It was concluded that the HCGS control room will remain habitable during a release of any of the evaluated hazardous chemicals. From the control room habitability evaluations, the only chemical stored and/or delivered onsite that can accumulate to any appreciable concentration in the control room is ammonium hydroxide. Calculations simulating the release of ammonium hydroxide at the SGS 1.8-67 HCGS-UFSAR Revision 5 May 11, 1993

indicated that the control room operators have more than two (2) minutes from the time of detection of ammonia to the toxicity limit listed in Table C-1 of Regulatory Guide 1.78 to take corrective actions. The HCGS utilizes the detection mechanism (human detection) as allowed by Regulatory Position C.7. Instrumentation is not provided to detect hazardous chemicals entering the control room and alarm control room personnel. 1.8.1.79 Conformance to Regulatory Guide 1.79, Revision 1, September 1975: Preoperational Testing of Emergency Core Cooling Systems for Pressurized Water Reactors Regulatory Guide 1.79 is not applicable to HCGS. 1.8.1.80 Conformance to Regulatory Guide 1.80, Revision 0, June 1974: Preoperational Testing of Instrument Air Systems Regulatory Guide 1.80 was superseded by Regulatory Guide 1.68.3 on April 20, 1982. See Section 1.8.1.68.3 for discussion of conformance to Regulatory Guide 1.68.3. 1.8.1.81 Conformance to Regulatory Guide 1.81, Revision 1, January 1975: Shared Emergency and Shutdown Electric Systems for Multiunit Nuclear Power Plant Regulatory Guide 1.81 is not applicable to HCGS. 1.8.1.82 Conformance to Regulatory Guide 1.82, Revision 0, June 1974: Sumps for Emergency Core Cooling and Containment Spray Systems Regulatory Guide 1.82 is not applicable to HCGS because it is applicable only to PWRs where Reactor Building sumps are designed to be a source of water for emergency core cooling. 1.8-68 HCGS-UFSAR Revision 5 May 11, 1993

1.8.1.83 Conformance to Regulatory Guide 1.83, Revision 1, July 1975: Inservice Inspection of Pressurized Water Reactor Steam Generators Tubes Regulatory Guide 1.83 is not applicable to HCGS. 1.8.1.84 Conformance to Regulatory Guide 1.84, Revision 24, June 1986: Design and Fabrication Code Case Acceptability, ASME Section III Division 1 HCGS complies with Regulatory Guide 1.84, with the following exception. Position C.1 states that the use of ASME Code Case N-252 is acceptable provided that the PSAR and/or FSAR indicate the capacitive discharge welding application, the material, and the material thickness. This information has not been provided for all applications, because Code Case N-252 contains sufficient controls, i.e., maximum power output, welding procedure specification preparation, and minimum material thickness, to prevent surface cracking or other adverse conditions. Information on the use of Code Case N-252 on the reactor coolant pressure boundary is presented below. Code Case N-252 was invoked in the fabrication of nuclear service piping. The guidance in Code Case N-252 was applied to the attachment of thermocouples to materials for the monitoring of metal temperature during post-weld heat treatment. The material involved was carbon steel (ASME P No. 1) greater than 1-1/2-inch thick. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-69 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.85 Conformance to Regulatory Guide 1.85, Revision 18, August 1981: Materials Code Case Acceptability ASME Section III Division 1 HCGS complies with Regulatory Guide 1.85, with the following exception: Position C.1 of Revision 17 of Regulatory Guide 1.85 accepted the use of Code Case N-242. Its use was acceptable, provided that the PSAR and/or FSAR identify all components and supports requiring the use of Paragraphs 1.0 through 4.0 of the ASME Code Case. A listing of components and supports in all applications is not provided because Code Case N-242 contains sufficient controls to ensure the proper certification of materials. A list of all reactor coolant pressure boundary components that invoked Code Case N-242 in ASME Section III, Class 1 applications is provided in Table 1.8-3. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.86 Conformance to Regulatory Guide 1.86, Revision 0, June 1974: Termination of Operating Licenses for Nuclear Reactors HCGS complies with the intent of Regulatory Guide 1.86. 1.8.1.87 Conformance to Regulatory Guide 1.87, Revision 1, June 1975: Guidance for Construction of Class 1 Components in Elevated Temperature Reactors (Supplement to ASME Section III Code Cases 1592, 1593, 1594, 1595, and 1596) Regulatory Guide 1.87 is not applicable to HCGS. 1.8-70 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.88 Conformance to Regulatory Guide 1.88, Revision 2, October 1976: Collection, Storage, and Maintenance of Nuclear Power Plant Quality Assurance Records NRC Regulatory Guide 1.88 was withdrawn by the NRC on July 31, 1991. HCGS is committed to the requirements of NQA-1-1994, Supplement 175-1, Section 4, Storage, Preservation, and Safekeeping, with the following specific exceptions for the Records Storage Room No. 145 in the Nuclear Administration Building:

1. Per NUGEG-0800, Records Storage Room No. 145 was built to comply with option (3) a 2 hour rated fire resistant file room meeting NFPA 232.

Regulatory Guide 1.88 endorses NFPA 232-1975 and NQA-1-1994 endorses NFPA 232-1986; however, during construction, NFPA 232-1991 was utilized to provide an acceptable level of record protection,

2. A cable tray which passes through the room is enclosed with a three hour rated symmetrical wrap system to assure its presence will not affect the rooms content or fire protection features, and

3. The ceiling is pierced by several miscellaneous drainage lines and two ventilation ducts. A drip pan, with discharge outside the room, is provided for the miscellaneous drainage plumbing to minimize the potential for inadvertent wetting of records and fire dampers are installed in the ventilation ducts.

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1.8.1.89 Conformance to Regulatory Guide 1.89, Revision 0, November 1974: Qualification of Class 1E Equipment for Nuclear Power Plants HCGS will attempt to comply with Regulatory Guide 1.89 on a case by case basis. See Section 3.11 for further discussion of environmental qualification and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-79 HCGS-UFSAR Revision 15 October 27, 2006

1.8.1.90 Conformance to Regulatory Guide 1.90, Revision 1, August 1977: Inservice Inspection of Prestressed Concrete Containment Structures with Grouted Tendons Regulatory Guide 1.90 is not applicable to HCGS because HCGS does not have a concrete containment. 1.8.1.91 Conformance to Regulatory Guide 1.91, Revision 1, February 1978: Evaluations of Explosions Postulated to Occur on Transportation Routes Near Nuclear Power Plants Regulatory Guide 1.91 is not applicable to HCGS. 1.8.1.92 Conformance to Regulatory Guide 1.92, Revision 1, February 1976: Combining Modal Responses and Spatial Components in Seismic Response Analysis Although Regulatory Guide 1.92 is not applicable to HCGS, per its implementation section, HCGS complies with it. Some of the equipment supplied under the NSSS contract has had to be reassessed according to the provisions of Regulatory Guide 1.92. Equipment that does not qualify under these provisions has been identified in the Hope Creek Seismic Qualification Review Program and qualified by more sophisticated analyses or testing. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.93 Conformance to Regulatory Guide 1.93, Revision 0, December 1974: Availability of Electric Power Sources Although Regulatory Guide 1.93 is not applicable to HCGS, per its implementation section, HCGS complies with it. See Chapter 16 for further discussion. 1.8-80 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.94 Conformance to Regulatory Guide 1.94, Revision 1, April 1976: Quality Assurance Requirements for Installation, Inspection, and Testing of Structural Concrete and Structural Steel During the Construction Phase of Nuclear Power Plants Although Regulatory Guide 1.94 is not applicable to HCGS, HCGS complies with NQA-1-1994 and the intent of the regulatory guide, with the following exceptions and clarifications:

1. In-Process Tests on Concrete.

Sampling is as follows:

a. Sampling point - Compressive strength test cylinders are cast from representative samples taken from the discharge of the batch plant stationary mixer. Slump and temperature of the concrete are recorded when cylinders are being cast. Air content is also recorded when the mix design contains air entraining admixture.

b. Correlation - For purpose of correlation between the stationary mixer and the transport discharge, cylinders are also cast from a sample taken at the transport discharge of the same batch from which a sample was taken at the stationary mixer, until correlation is established. For pumped concrete, this sample is taken at the pump line discharge.

c. Sampling for compressive strength tests from the pump discharge - It is not practical to take compressive strength test samples at the pump discharge because it is sometimes 200-feet high or deep in the structures.

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d. Samples for correlation are not taken when water has been added to the truck at point of discharge.

2. Mechanical (Cadweld) Splice Testing - HCGS compliance is discussed in Section 1.8.1.10.

3. A list of tests to which the project has taken exceptions, is as follows:

a. Aggregate moisture content testing per ASTM C566. The project specification requires aggregate moisture content testing but with no reference to a specific test procedure.

This test is used by the concrete supplier to determine the amount of water to be added to the concrete batch weights to produce the proper slump. Other test methods for moisture are equally acceptable to determine the proper amount of water.

b. ASTM C142, friable particles, is required only initially by the project. ASTM C123, lightweight pieces, and C235, soft fragments, are not required. Project requirements are adequate since the aggregate is crushed rock, subject to very little change.

c. Aggregate - Flat and elongated particle measurement is fully described in the project specification, but without a reference to CRD-C119. The description provides an adequate method in lieu of CRD-C119.

d. Water and ice - Setting time is determined by ASTM C266, Gillmore needles, instead of ASTM C191, 1.8-82 HCGS-UFSAR Revision 16 May 15, 2008

e. Water and ice - autoclave expansion, for soundness. This test is not required by the project, but other tests required by Specification C191, Section 6.2, for chlorides and sulfates should provide an indication of any long term reduction of strength.

f. Admixtures - an infrared spectrophotometry analysis for the chemical composition on a composite of each shipment. This test is not a specification requirement. However, HCGS does require the manufacturer to furnish certifications for every shipment stating that the materials originally approved have not been changed.

See Section 3.8.6 for further discussion. 1.8.1.95 Conformance to Regulatory Guide 1.95, Revision 1, January 1977: Protection of Nuclear Power Plant Control Room Operators Against An Accidental Chlorine Release Regulatory Guide 1.95 is not applicable to HCGS, per its implementation section. Furthermore, there is no need to include special provisions for chlorine detection at the control room ventilation intakes since chlorine is not stored onsite or at the nearby SNGS. At HCGS, sodium hypochlorite is used for water chlorination purposes. At HCGS, chlorine dioxide is produced by the Purate System and is also used for chlorination purposes. Implementation of the chlorine dioxide was subsequent to NRC withdrawal of RG 1.95. Chlorine dioxide was implemented using guidance from RG 1.78. Evaluations concluded that the control room would remain habitable during a postulated chlorine dioxide release at the Purate System structure. In any case, the control room ventilation system is provided with manual isolation capability, and self-contained breathing masks are provided for the main control room operators. For further discussion of chemical releases and main control room habitability, see Section 1.8.1.78. 1.8-83 HCGS-UFSAR Revision 26 April 13, 2023

1.8.1.96 Conformance to Regulatory Guide 1.96, Revision 1, June 1976: Design of Main Steam Isolation Valve Leakage Control Systems for Boiling Water Reactor Nuclear Power Plants (Historical Information) HCGS complies with Regulatory Guide 1.96. In response to Generic Issue C-8, MSIV Leakage and Leakage Control System Failure, 10CFR50.67, and Regulatory Guide 1.183, the MSIV leakage control system was removed. 1.8.1.97 Conformance to Regulatory Guide 1.97, Revision 2, December 1980: Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident 1.8.1.97.1 General Position Statement HCGS concurs with the intent of Regulatory Guide 1.97, Revision 2. The intent of the regulatory guide is to ensure that necessary and sufficient instrumentation exists at each nuclear power station for assessing plant and environmental conditions during and following an accident, as required by 10CFR Part 50, Appendix A and General Design Criteria 13, 19, and 64. Regulatory Guide 1.97 requirements are being implemented except in those instances in which differences from the letter of the guide are justified technically and then they can be implemented without disrupting the general intent of the regulatory guide, or other applicable design criteria. In assessing Regulatory Guide 1.97, HCGS has drawn upon information contained in several applicable documents, such as ANS 4.5, NUREG/CR-2100, and the BWROG Emergency Procedures Guidelines, and on data derived from other analyses and studies. HCGS has attempted to meet the intent of, as opposed to the literal compliance with the provisions of the regulatory guide, because of their specific nature. In general, HCGS intends to follow the criteria used by the NRC for establishing Category 1, 2, and 3 instruments. Where differences between the Regulatory Guide Categories exist, 1.8-84 HCGS-UFSAR Revision 12 May 3, 2002

justification for the category chosen is provided. This approach is preferable as some Regulatory Guide 1.97 requirements call for excessive ranges or categories or both, others call for functions already available, and still others could adversely affect operator judgment under certain conditions. For example, research by S. Levy, Inc., (SLI), show that core thermocouples will provide conflicting information to BWR operators. HCGS intends to follow the criteria used by the NRC for establishing Category 1, 2, and 3 instruments. The following HCGS compliance statement is applicable to the regulatory positions defined in Regulatory Guide 1.97, Revision 2 (the paragraph numbers cited correspond to those in Regulatory Guide 1.97).

1. Accident Monitoring Instrumentation Par. 1.1: HCGS concurs with this definition.

Par. 1.2: HCGS concurs with this definition. Par. 1.3: Instruments used for accident monitoring to meet the provisions of Regulatory Guide 1.97 will have the proper sensitivity, range, transient response, and accuracy to ensure that both during and following a design basis accident the control room operator is able to perform his role in bringing the plant to, and maintaining it in, a safe shutdown condition and in assessing actual or possible releases of radioactive material. Accident monitoring instruments that are required to be environmentally qualified will be qualified as described in Section 3.11. The seismic qualification of instruments is described in Section 3.10. The HCGS quality assurance program ensures that accident monitoring instruments comply with the applicable 1.8-85 HCGS-UFSAR Revision 0 April 11, 1988

requirements of Title 10CFR50, Appendix B. Table 3.2-1 identifies where these requirements have been applied. The HCGS program for periodic checking, testing, calibrating, and calibration verification of accident-monitoring instrument channels (Regulatory Guide 1.118) is identified in Section 16, "Technical Specifications." Par. 1.3.1 A third channel of instrumentation for Category 1 instruments will be provided only if:

a. a failure of one accident monitoring channel results in information ambiguity that would lead operators to defeat or fail to accomplish a required safety function, and

b. if one of the following measures cannot provide the information:

1. Cross-checking with an independent channel that monitors a different variable bearing a known relationship to the variable being monitored.

2. Providing the operator with the capability of perturbing the measured variable to determine which channel has failed by observing the response on each instrument.

3. Using portable instrumentation for validation.

Category 1 instrument channels, which are designated as being part of a Class 1E system, will meet the more stringent design requirements of either the system or the Regulatory Guide. 1.8-86 HCGS-UFSAR Revision 0 April 11, 1988

The requirements for physical independence of electrical systems (Regulatory Guide 1.75) are identified in Section 1.8.1.75. Par. 1.3.2: HCGS concurs with the regulatory position for Category 2 instrumentation, except as modified by Par. 1.3 above. Par. 1.3.3: HCGS concurs with the regulatory position for Category 3 instrumentation. Par. 1.4: Instruments designated as Categories 1 and 2 for variable types A, B, and C should be identified in such a manner as to optimize the human factors engineering and presentation of information to the control room operator. This position is taken to clarify the intent of Regulatory Guide 1.97, which specified that these instruments be easily discerned for use during accident conditions (see Issue 1 Section 1.8.1.97.4) Par. 1.5: HCGS concurs with the regulatory position taken in this section, except as modified by Par. 1.3 above. Par. 1.6: It is the position of HCGS that in terms of accident monitoring at HCGS, Table 1 of Regulatory Guide 1.97 is not representative of the optimum SPT of variables required and does not necessarily represent correct variable ranges or instrumentation categories. HCGS accident monitoring variables are identified in Table 7.5-1. The classification of instrumentation used to measure the variables as Category 1, 2, or 3 is Regulatory Guide 1.97. However, differences between the Regulatory Guide Categories and HCGS categories for each variable described in Table 1 of Regulatory Guide 1.97 is described in Section 1.8.1.97.3. 1.8-87 HCGS-UFSAR Revision 0 April 11, 1988

The HCGS position on the implementation of each variable described in Table 1 of Regulatory Guide 1.97 is presented in Section 1.8.1.97.3.

2. Systems Operation Monitoring and Effluent Release Monitoring Instrumentation The HCGS position stated in Par. 1.3 above is applicable to the Type D and E variables described in Regulatory Guide 1.97.

Par. 2.1: HCGS concurs with these definitions. Par. 2.2: HCGS concurs with these regulatory position. Par. 2.3: HCGS concurs with these regulatory position Par. 2.4: HCGS concurs with these regulatory position. Par. 2.5: The HCGS position as stated in Par. 1.6 above is applicable to this regulatory position. 1.8.1.97.2 Proposed Type A Variables Regulatory Guide 1.97, Revision 2, designates all Type A variables as Category 1 plant specific, thereby defining none in particular. The regulatory guide defines Type A variables as: Those variables to be monitored that provide primary information required to permit the control room operator to take specific manually controlled actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for design basis accident events. Regulatory Guide 1.97 defines primary information as "information that is essential for the direct accomplishment of the specified 1.8-88 HCGS-UFSAR Revision 0 April 11, 1988

safety functions." Variables associated with contingency actions that may be identified in written procedures are excluded from this definition of primary information. HCGS has determined that the monitoring of the following noted safety functions for the listed operator actions are required to meet the intent of Regulatory Guide 1.97. The specific Type A variables are identified in Section 1.8.1.97.3.1: Variable A1. Deleted Variable A2. RPV Pressure Safety Function: 1) Core cooling; 2) maintain reactor coolant system integrity. Operator action: 1) Depressurize RPV and maintain safe cooldown rate by any of several systems, such as main turbine bypass valves, HPCI, RCIC, and RWCU: 2) manually open one SRV to reduce pressure to below SRV setpoint if an SRV is cycling. Variable A3. RPV Water Level Safety Function: Core cooling. Operator action: Restore and maintain RPV water level. 1.8-89 HCGS-UFSAR Revision 15 October 27, 2006

Variable A4. Suppression Pool Water Temperature Safety Function: 1) Maintain containment integrity and 2) maintain reactor coolant system integrity. Operator action: 1) Operate available suppression pool cooling system when pool temperature exceeds normal operating limits;

2) scram reactor if temperature reaches limit for scram; 3) if suppression pool temperature cannot be maintained below the heat capacity temperature limit, maintain RPV pressure below the corresponding limit; and 4) close any stuck open relief valve.

Variable A5. Suppression Pool Water Level Safety Function: 1) maintain containment integrity. Operator action: Maintain suppression pool water level within normal operating limits: 1) transfer RCIC suction from the condensate storage tank (CST) to the suppression pool in the event of high suppression pool level; and 2) if suppression pool water level cannot be maintained below the suppression pool load limit, maintain RPV pressure below corresponding limit. Variable A6. Drywell Pressure Safety Function: 1) maintain containment integrity and

2) maintain reactor coolant system integrity.

Operator action: Control primary containment pressure by any of several systems, such as containment atmosphere control systems, suppression pool sprays, drywell sprays, etc. 1.8-90 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.97.3 Plant Variables For Accident Monitoring In brief, the measurement of the following five variable types provides the noted required information to plant operators during and after an accident:

1) Type A-primary information, on the basis of which operators take planned specified manually controlled actions; 2) Type B-information about the accomplishment of plant safety functions; 3) Type C-information about the breaching of barriers to fission product release; 4) Type D-information about the operation of individual safety systems; and 5) Type E-information about the magnitude of the release of radioactive materials.

The three categories (1,2,3) of required variables define the design and qualification criteria for the instrumentation that is to be used for their measurement. Category 1 imposes the most stringent requirements; Categories 2 and 3 impose progressively less stringent requirements. The categories are also related (per Regulatory Guide 1.97) to "key variables." Key variables are defined differently for the different variable types. For Type B and Type C variables, the key variables are those variables that most differently indicate the accomplishment of a safety function; instrumentation for these key variables is designated Category 1. Key variables that are Type D variables are defined as those variables that most directly indicate the operation of a safety function; instrumentation for these key variables is usually Category 2. And key variables that are Type E variables are defined as those variables that most directly indicate the release of radioactive material; instrumentation for these key variables is also usually Category 2. Backup variables for Type B, C, D and E variables are generally Category 3. A complete discussion of the variable types and instrumentation design criteria is presented in Regulatory Guide 1.97. HCGS positions on the implementation of the variables listed in Table 1 of Regulatory Guide 1.97 and on the assignment of design and 1.8-91 HCGS-UFSAR Revision 0 April 11, 1988

qualification criteria for the instrumentation proposed for their measurement is summarized in the tabulation that follows. The variables are listed here in the same sequence used in Table 1, Regulatory Guide 1.97; however, for convenience in cross-referencing entries and supporting data, the variables are designated by letter and number. For example, the sixth B-type variable listed in Regulatory Guide 1.97 is denoted here as variable B6. The HCGS variable category designated ("HC") and the Regulatory Guide 1.97 category designated ("RG") are shown for each variable and for its instrumentation design criteria and category. In general, there are three positions cited by HCGS: 1) the variable and required instrumentation was implemented in accordance with the regulatory position stated in Table 1, Regulatory Guide 1.97 2) was implemented with qualifying exceptions or revisions; and 3) was not implemented. As necessary, the HCGS positions are justified or substantiated by the 11 "Issues" (identified in the tabulation of variables where applicable) noted in Section 1.8.1.97.4. 1.8.1.97.3.1 Type A variables (Reference Section 1.8.1.97.2) A1. Deleted A2. Reactor pressure (HC Category 1, RG Category 1) Position: Implemented. A3. Coolant level in reactor (HC Category 1, RG Category 1) Position: Implemented. See B4. A4. Suppression pool water temperature (HC Category 1, RG Category 1) Position: Implemented. See D6. 1.8-92 HCGS-UFSAR Revision 15 October 27, 2006

A5. Suppression pool water level (HC Category 1, RG Category 1) Position: Implemented. See C7 and D5. A6. Drywell pressure (HC Category 1, RG Category 1) Position: Implemented. See B7, B9, C8, C10, and D4. 1.8.1.97.3.2 Type B Variables

1. Reactivity Control B1. Neutron Flux (RG Category 1) Position: Not implemented. See issue 2, Section 1.8.1.97.4.2.

B2. Control Rod Position (HC Category 3, RG Category 3) Position: Implemented. B3. RCS Soluble Boron Concentration (sample) (HC Category 3, RG Category 3) Position: Implemented.

2. Core Cooling B4. Coolant Level in Reactor (HC Category 1, RG Category 1)

Position: Implemented. See A3. B5. BWR Core Thermocouples (RG Category 1) Position: Not implemented. See B4, C3, and SLI-8121 (December, 1981) (Appendix A to Reference 1.8-4).

3. Maintaining Reactor Coolant System Integrity B6. RCS Pressure (HC Category 1; RG Category 1) Position:

Implemented. See A2, C4, C9, and Issue 3, Section 1.8.1.97.4.3. 1.8-93 HCGS-UFSAR Revision 22 May 9, 2017

B7. Drywell Pressure (HC Category 1; RG Category 1) Position: Implemented. See A6, B9, C8, C10, and D4. B8. Drywell Sump Level (HC Category 3; RG Category 1) Position: Implemented as Category 3. See C6 and Issue 4, Section 1.8.1.97.4.4.

4. Maintaining Containment Integrity B9. Primary Containment Pressure (HC Category 1; RG Category 1)Position: Implemented. See A6, B7, C8, C10, and D4.

B10. Primary Containment Isolation Valve Position (excluding check valves) (HC Category 1; RG Category 1) Position: Implemented (See Section 6.2.4.2). Redundant indication is not required on each redundant isolation valve. 1.8.1.97.3.3 Type C Variables

1. Fuel Cladding C1. Radioactivity Concentration or Radiation Level in Circulating Primary Coolant (RG Category 1) Position: Not implemented.

See Issue 5, Section 1.8.1.97.4.5. C2. Analysis of Primary Coolant (gamma spectrum) (HC Category 3; RG Category 3) Position: Implemented C3. BWR Core Thermocouples (RG Category 1) Position: Not implemented. See B4, B5, and SLI-8121 (December, 1981) (Appendix A to Reference a.8-4). 1.8-94 HCGS-UFSAR Revision 0 April 11, 1988

2. Reactor Coolant Pressure Boundary C4. RCS Pressure (HC Category 1; RG Category 1)

Position: Implemented. See A2, B6, and C9. C5. Primary Containment Area Radiation (HC Category 1; RG Category 3) Position: Implemented as Category 1. See E1. C6. Drywell Drain Sumps Level (identified and unidentified leakage) (HC Category 3; RG Category 1) Position: Implemented as Category 3. See B8 and Issue 4, Section 1.8.1.97.4.4. C7. Suppression Pool Water Level (HC Category 1; RG Category 1) Position: Implemented. See A5 and D5. C8. Drywell Pressure (HC Category 1; RG Category 1) Position: Implemented. See A6, B7, and B9, C10, and D4.

3. Containment C9. RCS Pressure (HC Category 1; RG Category 1)

Position: Implemented. See A2, B6, and C4. C10. Primary Containment Pressure (HC Category 1; RG Category 1) Position: Implemented. See A6, B7, B9, C8, and D4. C11. Containment and Drywell H Concentration (HC Category 3; RG 2 Category 1) Position: Implemented as Category 3 in accordance with License Amendment 160. 1.8-95 HCGS-UFSAR Revision 15 October 27, 2006

C12. Containment and Drywell Oxygen Concentration (HC Category 2; RG Category 1) Position: Implemented as Category 2 in accordance with License Amendment 160. C13. Containment Effluent Radioactivity-Noble Gases (from identified release points including Filtration, Recirculation

                  & Ventilation System Vent) (HC Category 3; RG Category 3)

Position: Implemented. C14. Radiation Exposure Rate (inside buildings or areas, e.g., Auxiliary Building, Reactor Building, which are in direct contact with primary containment where penetrations and hatches are located) (RG Category 2) Position: Not implemented. See E2, E3, and Issue 6, Section 1.8.1.97.4.6. C15. Effluent Radioactivity-Noble Gases (from buildings as indicated above (HC Category 2; RG Category 2) Position: Implemented. 1.8.1.97.3.4 Type D Variables

1. Condensate and Feedwater System D1. Main Feedwater Flow (HC Category 3; RG Category 3)

Position: Implemented. D2. Condensate Storage Tank Level (HC Category 3; RG Category 3) Position: Implemented.

2. Primary Containment Related System D3. Suppression Chamber Spray Flow (HC Category 2; RG Category 2)

Position: Implemented. 1.8-96 HCGS-UFSAR Revision 15 October 27, 2006

D4. Drywell Pressure (HC Category 2; RG Category 2) Position: Implemented. D5. Suppression Pool Water Level (HC Category 2; RG Category 2) Position: Implemented. See A5 and C7. D6. Suppression Pool Water Temperature (HC Category 1; RG Category 2) Position: Implemented, but must be Category 1. Both local and bulk temperature. See A4. D7. Drywell Atmosphere Temperature (HC Category 2; RG Category 2) Position: Implemented. D8. Drywell Spray Flow (HC Category 2; RG Category 2) Position: Implemented.

3. Main Steam System (Historical Information)

D9. Main Steamline Isolation Valves' Leakage Control System Pressure (HC Category 2; RG Category 2) Position: Implemented. (System is identified as Main Steam Isolation Valve Sealing System at HCGS). D10. Primary System Safety Relief Valve Position, Including ADS or Flow Through or Pressure in Valve Lines (HC Category 2; RG Category 2) Position: Implemented.

4. Safety Systems D11. Isolation Condenser System Shell Side Water Level Position: Not applicable to HCGS.

1.8-97 HCGS-UFSAR Revision 12 May 3, 2002

D12. Isolation Condenser System Valve Position Position: Not applicable to HCGS. D13. RCIC Flow (HC Category 2; RG Category 2) Position: Implemented. See Issue 7, Section 1.8.1.97.4.7. D14. HPCI Flow (HC Category 2; RG Category 2) Position: Implemented. See Issue 7, Section 1.8.1.97.4.7. D15. Core Spray System Flow (HC Category 2; RG Category 2) Position: Implemented. See Issue 7, Section 1.8.1.97.4.7. D16. LPCI System Flow (HC Category 2; RG Category 2) Position: Implemented. See Issue 7, Section 1.8.1.97.4.7. D17. SLC System Flow (HC Category 3; RG Category 2) Position: Implemented as Category 3. See Issue 7, Section 1.8.1.97.4.7. D18. SLC System Storage Tank Level (HC Category 2; RG Category 2) Position: Implemented.

5. Residual Heat Removal (RHR) Systems D19. RHR System Flow (HC Category 2; RG Category 2)

Position: Implemented. D20. RHR Heat Exchange Outlet Temperature (HC Category 2; RG Category 2) Position: Implemented. 1.8-98 HCGS-UFSAR Revision 0 April 11, 1988

6. Cooling Water System D21. Cooling Water Temperature to ESF System Components (HC Category 2; RG Category 2) Position: Interpreted as Safety Auxiliaries Cooling System (SACS) temperature and implemented.

D22. Cooling Water Flow to ESF System Components (HC Category 2; RG Category 2) Position: Interpreted as SACS flow and implemented.

7. Radwaste Systems D23. High Radioactivity Liquid Tank Level (HC Category 3; RG Category 3) Position: Implemented.

8. Ventilation Systems D24. Emergency Ventilation Damper Position (HC Category 2; RG Category 3) Position: Interpreted as meaning dampers actuated under accident conditions and whose failure could result in radioactive discharge to the environment. Control room damper position is indicated. Implemented.

9. Power Supplies D25. Status of Standby Power and Other Energy Sources Important to Safety (hydraulic, pneumatic) (HC Category 2; RG Category 2)

Position: Implemented; onsite sources only. 1.8-99 HCGS-UFSAR Revision 0 April 11, 1988

(Note: HCGS has implemented the following D-type variables as recommended by the BWROG; see Issue 8, Section 1.8.1.97.4.8.) D26. Turbine Bypass Valve Position (HC Category 3) Position: Implemented. See Issue 8, Section 1.8.1.97.4.8. D27. Condenser Hotwell Level (HC Category 3) Position: Implemented. See Issue 8, Section 1.8.1.97.4.8. D28. Condenser Vacuum (HC Category 3) Position: Implemented. See Issue 8, Section 1.8.1.97.4.8. D29. Condenser Cooling Water Flow (HC Category 3) Position: Interpreted as cooling water T across the condenser and implemented. See Issue 8, Section 1.8.1.97.4.8. D30. Primary Loop Recirculation (HC Category 3) Position: Implemented. See Issue 8, Section 1.8.1.97.4.8. 1.8.1.97.3.5 Type E Variables

1. Containment Radiation E1. Primary Containment Area Radiation-High Range (HC Category 1; RG Category 1) Position: Implemented in accordance with NUREG-0737 commitment. See C5.

E2. Reactor Building or Secondary Containment Area Radiation (RC Category 2 for Mark I and II containments) 1.8-100 HCGS-UFSAR Revision 0 April 11, 1988

Position: Not implemented for HCGS (Mark I) containment. See C14, E3, and Issue 9, Section 1.8.1.97.4.9.

2. Area Radiation E3. Radiation Exposure Rate (inside buildings or areas where access is required to service equipment important to safety (HC Category 3; RG Category 2) Position: Implemented as Category 3, using existing instrumentation. See C14, E2, and Issue 10, Section 1.8.1.97.4.10.

3. Airborne Radioactive Materials Released From Plant E4. Noble Gases and Vent Flow Rate (HC Category 2; RG Category 2)

Position: Implemented. E5. Particulates and Halogens (HC Category 3; RG Category 3) Position: Implemented.

4. Environs Radiation and Radioactivity E6. Radiation Exposure Meters (continuous indication at fixed locations) Position: Deleted. See NRC errata of July 1981.

E7. Airborne Radiohalogens and Particulates (portable sampling with onsite analysis capability (HC Category 3; RG Category 3) Position: Implemented. E8. Plant Environs Radiation (portable instrumentation) (HC Category 3; RG Category 3) Position: Implemented (portable equipment). 1.8-101 HCGS-UFSAR Revision 0 April 11, 1988

E9. Plant and Environs Radioactivity (portable instrumentation) (HC Category 3; RG Category 3) Position: Implemented (portable equipment).

5. Meteorology E10. Wind Direction (HC Category 3; RG Category 3)

Position: Implemented. E11. Wind Speed (HC Category 3; RG Category 3) Position: Implemented. E12. Estimation of Atmospheric Stability (HC Category 3; RG Category 3) Position: Implemented.

6. Accident-Sampling Capability (Analysis Capability Onsite)

E13. Primary Coolant and Sump (HC Category 3-Primary Coolant only; RG Category 3) Position: Implemented Primary Coolant. (Dissolved hydrogen or Total Gas not implemented). Sump not implemented. See Issue 11, Section 1.8.1.97.4.11. E14. Containment Air (HC Category 3; RG Category 3) Position: Implemented. The instrumentation for monitoring and display of type A, B, C, D, and E variables at HCGS is identified on Table 7.5-1. 1.8.1.97.4 Supplementary Analyses These supplementary analyses support positions cited in Section 1.8.1.97.1 (Issue 1) and Section 1.8.1.97.3 (Issues 2-12). 1.8-102 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.97.4.1 Issue 1 - Instrument Identification Regulatory Guide 1.97 specifies, in paragraph 1.4.b, the following: "The instruments designated as Types A, B, and C and Categories 1 and 2 should be specifically identified on the control panels so that the operator can easily discern that they are intended for use under accident conditions." The objective of this regulatory position is the achievement of good human factors engineering in the presentation of information to the control room a operator. This objective is best achieved by evaluating current practices and procedures that provide for identifying instruments in a manner that aids the operator; redundant labels would tend to distract the operator and cause confusion. Instruments designated as Categories 1 and 2 for monitoring variable types A, B, and C should be identified in such a manner as to optimize applicable human factors engineering and presentation of information to the control room operator. This position is taken to clarify the intent of Regulatory Guide 1.97, which specifies that these instruments be easily discerned for use during accident conditions. The method of identification used at HCGS will be based on the results of a human factors analysis performed on the HCGS main control room (See Section 18). 1.8.1.97.4.2 Issue 2 - Variable B1 The measurement of neutron flux is specified as the key variable in monitoring the status of reactivity. Neutron flux is classified as a Type B variable, Category 1. Hope Creek is committed to NEDO-31558-A which was approved by the NRC by a safety evaluation dated January 13, 1993 to exempt currently designed BWRs from RG 1.97 Category 1 requirements for the Neutron Monitoring System. NEDO-31558-A provides alternate criteria for range, accuracy, response characteristics, equipment qualification, function time, seismic qualification, redundancy and separation, power sources, channel availability, quality assurance, display and recording, equipment identification, interfaces, service test and calibration, human factors, and direct measurement. NEDO-31588-A requirements are met therefore neutron monitoring is not implemented as a RG 1.97 required variable. 1.8-103 HCGS-UFSAR Revision 22 May 9, 2017

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1.8.1.97.4.3 Issue 3 - Trend Recording The purpose of addressing Issue 3 is to determine which variables set forth in Regulatory Guide 1.97 require trend recording. Regulatory Guide 1.97, paragraph 1.3.2f, states the general requirement for trend recording as follows: "Where direct and immediate trend or transient information is essential for operator information or action, the recording should be continuously available for dedicated recorders." Using the BWROG Emergency Procedures Guidelines (EPG's) as a basis, the only trended variables required for operator action are reactor water level and reactor vessel pressure. Other variables at HCGS are recorded as identified on Table 7.5-1. 1.8.1.97.4.4 Issue 4 - Variables B8 and C6 Regulatory Guide 1.97 requires Category 1 instrumentation to monitor drywell sump level (variable B8) and drywell drain sumps level (variable C6). These designations refer to the drywell equipment and floor drain tank levels. Category 1 instrumentation indicates that the variable being monitored is a key variable. In Regulatory Guide 1.97, a key variable is defined as "... that single variable (or minimum number of variables) that most directly indicates the accomplishment of a safety function..." The following discussion supports the HCGS safety position that drywell sump level and drywell drain-sumps levels should be designated as Category 3 instrumentation requirements. The HCGS drywell has two drain sumps. One drain is the equipment drain sump, which collects identified leakage; the other is the floor drain sump, which collects unidentified leakage. Although the level of the drain sumps can be a direct indication of breach of the Rector Coolant System pressure boundary, the indication is not unambiguous, because that can be water in those 1.8-108 HCGS-UFSAR Revision 0 April 11, 1988

sumps during normal operation. There is other instrumentation required by Regulatory Guide 1.97 that would indicate leakage in the drywell:

1. Drywell pressure-variable B7, Category 1

2. Drywell temperature-variable D7, Category 2

3. Primary containment area radiation-variable C5, Category 1 The drywell sump levels signal neither automatic protection control circuitry nor the operator to take safety-related actions. Both sumps have level detectors that provide only the following nonsafety indications:

1. Continuous level indication

2. Rate of rise indication

3. High level alarm (starts first sump pump)

4. High-high level alarm (starts second sump pump)

Regulatory Guide 1.97 requires instrumentation to function during and after an accident. The drywell sump systems are deliberately isolated at the primary containment penetration upon receipt of an accident signal to establish containment integrity. This fact renders the drywell sump level signal irrelevant. Therefore, by design, drywell level instrumentation serves no useful accident monitoring function. The Emergency Procedure Guidelines use the RPV level and the drywell pressure as entry conditions for the Level Control Guideline. A small line break will cause the drywell pressure to increase before a noticeable increase in the sump level. Therefore, the drywell sumps will provide a "lagging" versus "early" indication of a leak. 1.8-109 HCGS-UFSAR Revision 0 April 11, 1988

Based on the above considerations, HCGS believes that the drywell sump level and drywell drain sump level instrumentation should be designated as Category 3, "high-quality off the shelf instrumentation." 1.8.1.97.4.5 Issue 5 - Variable C1 Regulatory Guide 1.97 specifies that the status of the fuel cladding be monitored during and after an accident. The specified variable to accomplish this monitoring is variable C1-radioactivity concentration or radiation level in circulating primary coolant. The range is given as "1/2 Tech. Spec. Limit to 100 times Tech. Spec. Limit, R/hr." In Table 1 of Regulatory Guide 1.97, instrumentation for measuring variable C1 is designated as Category 1. The purpose for monitoring this variable is given as detection of breach," referring, in this case, to breach of fuel cladding. The usefulness of the information obtained by monitoring variable C1, in terms of helping the operator in his efforts to prevent and mitigate accidents, has not been substantiated. The particular planned operator action to be taken based on monitoring this variable is not specified in the current draft of the Emergency Procedure Guidelines (EPGs). The critical actions that must be taken to prevent and mitigate a gross breach of fuel cladding are 1) shut down the reactor and 2) maintain water level. Monitoring variable C1, as directed in Regulatory Guide 1.97, will have no influence on either of these actions. The purpose of this monitor falls in the category of "information that the barriers to release of radioactive material are being challenged" and "identification of degraded conditions and their magnitude, so the operator can take actions that are available to mitigation the consequences." Additional operator actions to mitigate the consequences of fuel barriers being challenged, other than those based on Type A and B variables, have not been identified. 1.8-110 HCGS-UFSAR Revision 0 April 11, 1988

Regulatory Guide 1.97 specifies measurement of the radioactivity of the circulating primary coolant as the key variable in monitoring fuel cladding status during isolation of the NSSS. The words "circulating primary coolant" are interpreted to mean coolant, or a representative sample of such coolant, that flows past the core. A basic criterion for a valid measurement of the specified variable is that the coolant being monitored is coolant that is in active contact with the fuel, that is, flowing past the failed fuel. Monitoring the active coolant (or a sample thereof) is the dominant consideration. The Process Sampling System provides a representative sample which can be monitored. The subject of concern in the Regulatory Guide 1.97 requirement is assumed to be an isolated NSSS that is shutdown. This assumption is justified as current monitors in the condenser off-gas and main steam lines provide reliable and accurate information on the status of fuel cladding when the plant is not isolated. Further, the Process Sampling System will provide an accurate status of coolant radioactivity, and hence cladding status, following an accident. In the interim between NSSS isolation and sampling, monitoring of the primary containment radiation and containment hydrogen will provide information on the status of the fuel cladding. Later in the sequence, the sample can be augmented by area radiation monitor when the RHR system is being used to remove core decay heat. The designation of instrumentation for measuring variable C1 should be Category 3, because no planned operator actions are identified and no operator actions are anticipated based on this variable serving as the key variable. Existing Category 3 instrumentation is adequate for monitoring fuel cladding status. 1.8-111 HCGS-UFSAR Revision 14 July 26, 2005

1.8.1.97.4.6 Issue 6 - Variable C14 Variable C14 is defined in Table 1 of Regulatory 1.97 as follows: "Radiation exposure rate (inside buildings or areas, e.g., Auxiliary Building, Fuel Handling Building, Secondary Containment), which are in direct contact with primary containment where penetrations and hatches are located." The reason for monitoring variable C14 is given as "Indication of breach." The use of local radiation exposure rate monitors to detect breach or leakage through primary containment penetrations is impractical and unnecessary. In general, radiation exposure rate in the Reactor Building will be largely a function of radioactivity in primary containment and in the fluids flowing in ECCS piping, which will cause direct radiation shine on the area monitors. Also, because of the amount of piping and the number of electrical penetrations and hatches and their widely scattered locations, local radiation exposure rate monitors could give ambiguous indications. The proper way to detect breach of containment is by using the plant noble gas effluent monitors. Therefore, it is the position of HCGS that this parameter not be implemented. 1.8.1.97.4.7 Issue 7 - Variables D13-D17 Regulatory Guide 1.97 specifies flow measurements of the following systems: reactor core isolation cooling (RCIC) (variable D13), high pressure coolant injection (HPCI) (variable D14, core spray (variable D15), low pressure coolant injection (LPCI) (variable D16), and standby liquid control (SLC) (variable D17). The purpose is for monitoring the operation of individual safety systems. Instrumentation for measuring these variables is designated as Category 2; the range is specified as 0 to 110 percent of design flow. These variables are related to flow into the reactor pressure vessel (RPV). 1.8-112 HCGS-UFSAR Revision 8 September 25, 1996

The RCIC, HPCI, and core spray systems each have one branch line; the test line downstream of the flow measuring element. The test line is provided with a motor operated valve that is normally closed HPCI and RCIC also share a motor operated valve that is normally open). Further, the valve in the test line automatically closes when the emergency system is actuated, thereby ensuring that indicated flow is not being diverted by the test line. Proper valve position can be verified by a direct indication of valve position on the main control board. Although the LPCI has several branch lines located downstream of each flow measuring element, upon initiation of the LPCI, the valves in the system automatically line up for proper operation and prevent flow diversion by branch lines. Proper valve position can be verified by the operator using main control board indication of valve position. For all of the above systems, there are valid primary indicators other than flow measurement to verify the performance of the emergency system; for example, reactor vessel water level. Flow measuring devices are not provided for the SLC system. The pump discharge header pressure, which is indicated in the control room, will indicated SLC pump operation. Besides the discharge header pressure observation, the operator can verify the proper functioning of the SLC system by monitoring the following:

1. The decrease in the level of the SLC storage tank,

2. The boron injection induced reactivity change in the reactor as measured by neutron flux.

3. The main control room motor status indicating lights (or motor current),

4. Squib valve continuity indicating lights.

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The use of these indications is believed to be a valid alternative to SLC system flow indication. The flow measurement schemes for the RCIC, HPCI, core spray, and LPCI meet the Category 2 requirements of Regulatory Guide 1.97. Monitoring the SLC system can be adequately done by measuring the above named Category 3 variables rather than the actual flow. 1.8.1.97.4.8 Issue 8 - Variables D26-D30 Regulatory Guide 1.97 states that "The plant designer should select variables and information display channels required by his design to enable the control room personnel to ascertain the operating status of each individual safety system and other systems important to safety to that extend necessary to determine if each system is operating or can be placed in operation..." The purpose of this analysis was to determine whether certain other D-type variables should be added to Table 1, Regulatory Guide 1.97. Regulatory Guide 1.97 addressed safety systems and systems important to safety to mitigate consequences of an accident. Another list of variables has been compiled for the BWR in NUREG/CR-2100 (Boiling Water Reactor Status Monitoring during Accident Conditions, April 1981). That report and a companion report, NUREG/CR-1440 (Light Water Reactor Status Monitoring during Accident Conditions, June 1980), address plant systems not important to safety, as well as systems that are important to safety. In particular, these reports consider the potential role of the turbine generator system in mitigating certain accidents. These two reports were reviewed in determining whether the listed variables (D26-D30) should be added to the Regulatory Guide 1.97 list. The NUREG evaluations used a systematic approach to derive a variables list. The basic approach of the analysis was to focus on those accident conditions under which the operator is most likely to be confronted with "and/or" accident conditions which result in the 1.8-114 HCGS-UFSAR Revision 0 April 11, 1988

most serious consequences should the operator fail to accomplish his required tasks. This is a probabilistic event tree type of study, and the reports used the sequences of the Reactor Safety Study (WASH 1400), and similar studies. The events in each sequence that involved operator action were identified; also, events were added to the event tree to include additional operator actions that could mitigate the accident. The event tree defines a series of key plant states that could evolve as the accident progresses and as the operator attempts to respond. Thus the operator's informational needs are linked to these plant states. NUREG/CR-2100 is a BWR evaluation undertaken to address appropriate operator actions, the information needed to take those actions, and the instrumentation necessary and sufficient to provide the required information. The sequences evaluated were:

1. Anticipated transient followed by loss of decay heat removal.

2. Anticipated transients without scram (ATWS).

3. Anticipated transient together with failure of HPCI, RCIC, and low pressure ECCS.

4. Large loss of coolant accident (LOCA) with failure of emergency core cooling systems.

5. Small LOCA with failure of emergency core cooling systems.

The Regulatory Guide 1.97 list is based on accidents that result in an isolated NSSS. The NUREG documents considered accidents that could be prevented or mitigated by using water inventory and the heat sink in the turbine plant. 1.8-115 HCGS-UFSAR Revision 0 April 11, 1988

Five of the 15 variables identified in the NUREG, but not in Regulatory Guide 1.97, are recommended as Type D, Category 3 additions to the Regulatory Guide 1.97 list. Four of these variables are in the turbine plant: the turbine bypass valve position, condenser hotwell level, condenser vacuum, and condenser cooling water flow. These variables provide a primary measure of the status of a heat sink or water inventory in the turbine plant. The turbine-plant systems are not to be classed as "safety systems" or as systems important to safety. The addition of reactor primary loop recirculation as a variable is also recommended. HCGS has implemented these four variables plus reactor primary loop recirculation (Variable D26-D30) as plant specific Category 3 items in accordance with Regulatory Guide 1.97 considerations. Note that HCGS has implemented variable D29 (condenser cooling water flow) by monitoring the circulating water temperature rise across the condenser as a positive T across the condenser coupled with no decrease in condenser vacuum is an adequate indication of condenser cooling water flow. 1.8.1.97.4.9 Issue 9 - Variable E2 Regulatory Guide 1.97 specifies that "Reactor building or secondary containment

                                                                          -1       4 area radiation" (variable E2) should be monitored over the range of 10        to 10 7

R/hr for Mark I and II containments, and over the range of 1 to 10 R/hr for Mark III containments. The classification for Hope Creek is Category 2; for Mark III, the classification is Category 1. As discussed in the variable C14 position statement (Issue 6), Reactor Building area radiation is an inappropriate parameter to use to detect or assess primary containment leakage. The Reactor Building exhaust and refueling floor area exhaust are continuously monitored by their respective Radiation Monitoring System as described in Sections 11.5.2.1.3 and 11.5.2.1.2. Any 1.8-116 HCGS-UFSAR Revision 0 April 11, 1988

concentration of airborne radioactivity in excess of preset limits as detected by either of these systems (possibly indicating a leak from the primary containment) will initiate the Filtration, Recirculation and Ventilation System vent (FRVSV) and will also provide signals to the Primary Containment Isolation System to initiate primary containment isolation to the extent described in Section 7.3.1.1.5. The Reactor Building exhaust and refueling floor area exhaust are normally routed to the south plant vent Radiation Monitoring System as described in Section 11.5.2.2.2. The south plant vent radiation monitoring system instrumentation ranges and sensitivities are listed in Table 11.5-1. If the FRVSV system is initiated (either manually or automatically by the Reactor Building exhaust or refueling floor area exhaust radiation monitoring systems) the Reactor Building exhaust and refueling floor area exhausts are automatically shifted to the FRVSV system. The FRVSV effluent air is monitored by the FRVSV radiation monitoring system as described in Section 11.5.2.2.3. The FRVSV radiation monitoring system instrumentation ranges and minimum sensitivities are listed in Table 11.5-1. It is the Hope Creek position that the monitoring functions performed by the south plant vent radiation monitoring system and the FRVSV radiation monitoring system with the ranges and sensitivities listed in Table 11.5-1 provide a much more reliable means of detection of significant releases, release assessment, and long term surveillance than could be provided by reactor building area radiation monitors. Therefore, it is the position of HCGS that the specified Reactor Building area radiation monitors are not required for HCGS. 1.8-117 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.97.4.10 Issue 10 - Variable E3 Regulatory Guide 1.97 specifies in Table 1, variable E3, that radiation exposure rate (inside buildings or areas where access is required to service

                                                                        -1       4 equipment important to safety) be monitored over the range of 10            to 10 R/hr for detection of significant releases, for release assessment, and for long-term surveillance.

In general, access is not required to any area of the Reactor Building in order to service safety-related equipment in a post-accident situation. When accessibility is reestablished in the long term, it will be done by a combination of portable radiation survey instruments and post-accident sampling of the Reactor Building atmosphere. The existing lower range (typically 3 decades lower than the Regulatory Guide 1.97 range) area radiation monitors would be used only in those instances in which anticipated radiation levels were within measurable instrument ranges. It is HCGS's position that this parameter was modified to allow credit for existing area radiation monitors. That is, this parameter should be reclassified as Category 3 with the ranges specified on Table 11.5-1. 1.8.1.97.4.11 Issue 11 - Variable E13 Regulatory Guide 1.97 requires installation of the capability for obtaining grab samples (variable E13) of the containment sumps and the reactor building sumps for the purpose of release assessment, verification, and analysis. The need for sampling a particular sump must take into account its location and the design of the plant in which it is installed. For all accidents in which radioactive material would be in the HCGS drywell sumps, these sumps will be isolated and will overflow to the suppression pool. A suppression pool sample can therefore be used as a valid alternative to a drywell sump sample. 1.8-118 HCGS-UFSAR Revision 0 April 11, 1988

The analysis of Reactor Building sumps liquid samples can be used for release assessment, as suggested in Regulatory Guide 1.97, only for those designs in which potentially radioactive water can be pumped out of a controlled area to an area such as radwaste. For designs in which sump pump out is not allowed on a high radiation or a LOCA signal, or in which the water is pumped to the suppression pool, a sump sample does not contribute to release assessment. The use of the subject sump samples for verification and analysis is of little value; a sample of the suppression pool and reactor water, as required by other portions of Regulatory Guide 1.97, provides a much better measurement for these purposes. The guidelines recommended by the BWR Owners' Group and GE shall be followed in lieu of Total Dissolved Gas Group and GE shall be followed in lieu of Total Dissolved Gas Analysis. This was agreed to in a meeting between NRC management (R. Vollmer) and GE (F. Quick) dated December 12, 1983. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.97.5 Exceptions to Regulatory Guide 1.97 1.8.1.97.5.1 Neutron Flux Regulatory Guide 1.97 recommends Category 1 instrumentation with a range of

      -6 from 10    to 100 percent of full power. HCGS has provided three redundant sets of  instrumentation   having   overlapping   ranges  which,  together,  cover  the recommended range. However, the instrumentation is Category 2.      The source-range monitors and intermediate-range monitors are driven into the core soon after shutdown and this makes it highly probable that one or more of the existing detectors will be inserted.       The operator can actuate the standby liquid control system on loss of instrumentation.      There are four source-range monitors, eight intermediate-range monitors, six average power range monitors and individual local power range monitors.

This deviation is similar to most boiling water reactors. 1.8-119 HCGS-UFSAR Revision 7 December 29, 1995

1.8.1.97.5.2 Drywell Sump Level and Drywell Drains Sump Level HCGS is supplying instrumentation for this variable that is Category 3 rather than the recommended Category 1. Justification for this deviation is as follows:

1. The sump level is not an unambiguous indication of a breach in the reactor coolant system pressure boundary

2. Other instrumentation (drywell pressure, drywell temperature and primary containment radiation) indicates leakage in the drywell

3. The sump level does not cause any automatic initiation of safety-related systems or alert the operator to take any safety-related actions

4. The sump level provides only non-safety indications

5. The sumps are deliberately isolated at the primary containment penetration upon receipt of an accident signal. This is done to establish containment integrity.

The instrumentation supplied will provide appropriate monitoring for the parameters of concern. This is based on 1) for small leaks, the instrumentation is not expected to experience harsh environments during operation, 2) for larger leaks, the sumps fill promptly and the sump drain lines isolate due to the increase in drywell pressure, thus negating the drywell sump level and drywell drain sumps level instrumentation, 3) the drywell pressure and temperature as well as the primary containment area radiation instrumentation can be used to detect leakage in the drywell, and 4) this 1.8-120 HCGS-UFSAR Revision 7 December 29, 1995

instrumentation neither automatically initiates nor alerts the operator to initiate operation of a safety-related system in a post-accident situation. 1.8.1.97.5.3 Radiation Level in Circulating Primary Coolant The process sampling system provides a means of obtaining samples of reactor coolant and determining the status of fuel cladding. The radiation monitors in the condenser off-gas and the main steamlines provide information on the status of fuel cladding when the plant is not isolated. Monitoring the primary containment radiation and containment hydrogen concentration provide this information when the plant is isolated. 1.8.1.97.5.4 Radiation Exposure Rate Regulatory Guide 1.97, Revision 2, specifies instrumentation for this Type C variable. HCGS's position is that this variable need not be implemented. Revision 3 of Regulatory Guide 1.97 (Reference 7) states that exposure rate monitors inside buildings for detecting containment breach were deleted from the guide. Regulatory Guide 1.97, Revision 2, specifies instrumentation for this Type E

                                                                         -1      4 variable. The stated range for this Category 2 instrumentation is 10       to 10 R/hr. HCGS's position is that no access to a harsh environment area to service safety-related equipment following an accident is required; and that long-term accessibility will be evaluated with portable radiation survey instruments and containment atmosphere sampling and analysis.       HCGS has provided Category 3 4

instrumentation for this variable with a range of 0.1 mR/hr to 10 R/hr, which will be used only where the anticipated radiation levels are within the instrument range. 1.8-121 HCGS-UFSAR Revision 14 July 26, 2005

Regulatory Guide 1.97, Revision 2, specifies Category 3 instrumentation for this variable. This instrumentation will be used only where they are expected to remain on scale following an accident. 1.8.1.97.5.5 Emergency Core Cooling Flow HCGS has deviated from the recommendations of Regulatory Guide 1.97 for measuring the flow of the following systems:

a. Reactor Core Isolation Cooling (RCIC)

b. High Pressure Coolant Injection (HPCI)

c. Core Spray (CS)

d. Low Pressure Coolant Injection (LPCI)

Regulatory Guide 1.97 recommends Category 2 instrumentation for these variables, each with a range of 0 to 110 percent of design flow. As a deviation, a potential for flow diversion for each of the four systems exists. This diversion could be caused by open valves in branch lines downstream of the flow measuring elements. The instrumentation for measuring the flow for these systems is adequate since it meets the intent of the Regulatory Guide and because the valve position is known and the valves close automatically on an accident signal. The flow instrumentation for the HPCI measures to 107 percent of design flow (6,000 gallons per minute). The existing range is adequate to provide the necessary accident and post-accident information. Therefore, this is an acceptable deviation from Regulatory Guide 1.97. 1.8-122 HCGS-UFSAR Revision 1 April 11, 1989

1.8.1.97.5.6 Standby Liquid Control System Flow Regulatory Guide 1.97 specifies Category 2 instrumentation with a range of 0 to 110 percent of design flow for this variable. HCGS does not measure this variable directly. The pump discharge header pressure will indicate pump operation to the operator. Other parameters that can be monitored to verify system operation include: level decrease in the boric acid storage tank, neutron flux, pump motor contactor position (or running current), and squib valve continuity indication. These parameters are sufficient to establish that there is flow in the standby liquid control system. Positive displacement pumps are used for the standby liquid control system. High pump pressure indicates flow blockage and erratic or low pressure indicates a line break. The above indications are valid for an alternate standby liquid control system flow indication. 1.8.1.97.5.7 Cooling Water Temperature to Engineered Safety Features (ESF) System Components Regulatory Guide 1.97 recommends instrumentation for this variable with a range from 40 to 200F. HCGS provides this instrumentation for the safety auxiliary cooling system, with a range from 32 to 95F (UFSAR, Table 7.5-1). Table 9.2-3 of the UFSAR lists the design water outlet temperature minimum at 32F, the maximum at 95F. This corresponds to the range of the instrumentation supplied. Therefore, the supplied range is acceptable. 1.8.1.97.5.8 Reactor Building or Secondary Containment Radiation Regulatory Guide 1.97 recommends that this variable be monitored with Category 2 instrumentation; HCGS's position is that secondary containment area radiation is not an appropriate parameter to use 1.8-123 HCGS-UFSAR Revision 8 September 25, 1996

for assessing primary containment leakage or detecting significant releases. The use of local radiation exposure rate monitors to detect breach or leakage through primary containment penetrations results in ambiguous indications. This is due to the radioactivity in the primary containment, the radioactivity in the fluids flowing in emergency core coolant system piping and the amount and location of fluid and electrical penetrations. The use of the plant noble gas effluent monitors is the proper way to accomplish the purpose of this variable. The alternate instrumentation for this variable is provided by the Category 2 filtration, recirculation and ventilation system vent radiation monitoring

                               -6                                5 system. It has a range of 10     to 10 Ci/cc beta and 5 to 10 Ci/cc gamma.

This measures the radiation levels in the exhausts from the reactor building and refueling floor area in the post-accident situation. Normal monitoring of the exhausts from these areas is done by the south plant vent radiation monitoring system. This is also a Category 2 system that includes normal and extended ranges. 1.8.1.97.5.9 Accident Sampling (Primary Coolant Containment Air and Sump) Regulatory Guide 1.97 recommends sampling and onsite analysis capability for the reactor coolant system, contaminant sump, ECCS pump room sumps and other similar auxiliary building sump liquids, the containment sump and containment air. HCGS's post-accident sampling facility provides sampling and analysis. However, there are deviations from the following recommendations.

1. The sumps are not sampled

2. Dissolved hydrogen or total gas analysis capability is not included.

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HCGS takes exception to Regulatory Guide 1.97 with respect to post accident sampling capability. This exception is discussed in Section 1.10 under NUREG-0737, Item II.B.3. 1.8.1.98 Conformance to Regulatory Guide 1.98, Revision 0, March 1976: Assumptions Used for Evaluating the Potential Radiological Consequences of a Radioactive Off-gas System Failure in a Boiling Water Reactor HCGS complies with Branch Technical Position ETSB 11-5, Revision 0, July 1981, in lieu of Regulatory Guide 1.18. For further discussion, see Section 15.7.1. 1.8.1.99 Conformance to Regulatory Guide 1.99, Revision 2, May 1988: Radiation Embrittlement of Reactor Vessel Materials Regulatory Guide 1.99 is not applicable. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.100 Conformance to Regulatory Guide 1.100, Revision 1, August 1977: Seismic Qualification of Electric Equipment For Nuclear Power Plants Although Regulatory Guide 1.100 is not applicable to HCGS, per its implementation section, HCGS complies with it. See Section 3.10 for further discussion of seismic qualification of electrical components and Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8-125 HCGS-UFSAR Revision 8 September 25, 1996

1.8.1.101 Conformance to Regulatory Guide 1.101, Revision 3, August 1992: Emergency Planning and Preparedness for Nuclear Power Reactors Hope Creek conforms to Regulatory Guide 1.101, Revision 3, August 1992, and uses as the planning basis "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants", NUREG-0654/FEMA-REP-1, Rev.1 (November 1980), and "Methodology for Development of Emergency Action Levels", NUMARC/NESP-007. The Emergency Plan Manuals, as revised, describe the total emergency program as described in Section 13.3. 1.8.1.102 Conformance to Regulatory Guide 1.102, Revision 1, September 1976: Flood Protection for Nuclear Power Plants HCGS complies with Regulatory Guide 1.102. 1.8.1.103 Conformance to Regulatory Guide 1.103, Revision 1, October 1976: Post-Tensioned Prestressing Systems for Concrete Reactor Vessels and Containments Regulatory Guide 1.103 was withdrawn on July 21, 1981. It is not applicable to HCGS. 1.8.1.104 Conformance to Regulatory Guide 1.104, Revision 0, February 1976: Overhead Crane Handling Systems for Nuclear Power Plants Regulatory Guide 1.104 was withdrawn on August 22, 1979. Nevertheless, the HCGS reactor building polar crane was designed and procured using Regulatory Guide 1.104 as a guide; except as noted below. The current criteria for evaluating single failure proof crane design is NUREG-0554. The HCGS design complies with NUREG-0554, except as noted in Section 9.1.5. For a comparison of the HCGS design to NUREG-0554, see Section 9.1.5. HCGS complies with Regulatory Guide 1.104 with the exceptions and clarifications noted below, which are keyed to the Regulatory Guide paragraph numbers. 1.8-126 HCGS-UFSAR Revision 9 June 13, 1998

Position 1 - Performance Specification and Design Criteria

a. The crane may be used for miscellaneous construction lifts, including assembly of reactor internals. Construction lifts will be within the rated crane capacity, and therefore a separate performance specification was not prepared. Otherwise, the design complies.

b.1. This paragraph is not applicable because the crane is not located inside containment. The crane girders are sealed. Venting is not required because the crane is designed for reactor building pressure differentials. b.2. Structural members essential to structural integrity that are not redundant have been impact tested. It is expected that the 60F margin will be satisfied for HCGS service conditions. However, this margin is considered excessive as a general rule. b.3. Cold proof testing is not required because impact testing in accordance with b.2. was performed. b.4. Low alloy steel is not used in the crane.

c. The design complies.

d. The design complies.

e. A fatigue analysis is not considered necessary in view of the low number of load cycles to be experienced.

f. Welding procedures comply. No low alloy steel is used.

1.8-127 HCGS-UFSAR Revision 0 April 11, 1988

Position 2 - Safety Features

a. The design complies.

b. The design complies.

c. The design complies.

d. The design complies.

Position 3 - Equipment Selection

a. The design complies.

b. Not applicable to the crane design.

c. The design complies.

d. The design complies.

e. The design complies.

f. The design complies.

g. A 200 percent static test of the hook was performed, followed by nondestructive examination. Breaking strength tests were performed on samples of the hoisting rope. The assembled crane will be statically tested at 125 percent of the rated load prior to initial use in accordance with OSHA.

h. The design complies.

i. The design complies.

1.8-128 HCGS-UFSAR Revision 0 April 11, 1988

j. Provision is made in design to prevent the occurrence of two-blocking. Redundant upper limit switches of diverse design are provided to interrupt hoisting power.

k. Provisions are made to capture the drum in the event its shaft or bearings fail. Movement of the drum in this event will be limited mechanically so that the gear trains and holding brakes will not disengage. Total failure of the drum itself is not considered credible. Stresses are low. Impact testing in accordance with Paragraph 1.b.2) was performed on the drum material.

l. The design complies.

m. The design complies. It is interpreted that installation of two holding brakes is a sufficient design provision to protect against single failure.

n. The design complies.

o. Stepless controls are provided for hoisting. Plugging protection is provided to the extent that torque and current will be limited if the operator moves the master controller in the opposite direction in order to obtain a rapid reversal.

p. The design complies.

q. The design complies.

r. The design complies.

s. The value of the maximum working load (MWL) is undefined. However, if the MWL is assumed to be a 125-ton cask lift, that is 83 percent of the design rating of 150 tons.

1.8-129 HCGS-UFSAR Revision 0 April 11, 1988

Position 4 - Mechanical Check, Testing, and Preventive Maintenance

a. Testing will comply.

b. A two-block test will not be performed other than to check that the hoisting limit switches are functional. A test for load hangup may be performed, but without the provision for one revolution of the drum before the start of hoisting.

c. The crane will be marked with the design rated load.

d. This paragraph is not applicable because impact testing was performed on materials that met the ASME criteria for materials requiring impact testing.

Position 5 - Quality Assurance The quality assurance program of 10CFR50, Appendix B is applied to the crane. Therefore, it complies. 1.8.1.105 Conformance to Regulatory Guide 1.105, Revision 1, November 1976: Instrument Setpoints Although Regulatory Guide 1.105 is not applicable to HCGS, per its implementation section, HCGS complies with it, subject to the following interpretation of Position C.5, which requires that instruments have a setpoint securing device. Position C.5 is invalid if it is demonstrated by analysis or test that such devices do not aid in maintaining the required setpoint. It is evident from the licensee event reports (LER) that the vast majority of events attributed to drift are associated with mechanically actuated devices. To circumvent this problem, the HCGS project avoids the use of direct process connected electromechanical devices in safety-related systems. For safety-related circuits, HCGS uses proportional transmitting devices to make the primary 1.8-130 HCGS-UFSAR Revision 0 April 11, 1988

measurement. The switching device or bistable is an electronic switch located in main or remote panels. Because Regulatory Guide 1.105 does not differentiate between the types of bistable actuation (mechanical or electronic), HCGS requested suppliers to demonstrate by test, preferably during the tests performed to comply with IEEE 323, that their electronic switch is not subject to unacceptable drift. Position C.5 also requires that securing devices be under administrative control. If securing devices are required, based upon test results, administrative control consists of control of access to areas within the plant where these devices are located. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.106 Conformance to Regulatory Guide 1.106, Revision 1, March 1977: Thermal Overload Protection for Electric Motors on Motor Operated Valves Although Regulatory Guide 1.106 is not applicable to HCGS, HCGS implements this Regulatory Guide as discussed in Section 8.3.1.1.2.10. See Section 1.8.2 for the NSSS assessment of this Regulatory Guide. 1.8.1.107 Conformance to Regulatory Guide 1.107, Revision 1, February 1977: Qualifications for Cement Grouting for Prestressing Tendons in Containment Structures Regulatory Guide 1.107 is not applicable to HCGS. 1.8-131 HCGS-UFSAR Revision 12 May 3, 2002

1.8.1.108 Conformance to Regulatory Guide 1.108, Revision 1, August 1977: Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants HCGS complies with Regulatory Guide 1.108, with the following exception:

1. During the preoperational test phase, following the diesel 24-hour full load test, the proper design accident loading sequence will be demonstrated by the test described in Section 14.2.12.1.47. This test will verify the ability of the SDG to start and accept the sequenced design loads as specified in Table 8.3-1. This test will provide ECCS flows to the reactor vessel.

2. The criteria regarding sustained load levels of 100 percent and 110 percent can be demonstrated when those significant parameters being measured have stabilized to acceptable values. Although the 100 percent load level should be maintained for 22 hours followed by a 110 percent load level for 2 hours, reduced run times at 110 percent load levels are not regarded as an inadequate demonstration as defined by Position C.2.c provided: Runtime is sufficient to stabilize significant parameters being measured at the 110 percent load level and additional runtime (continuous beyond 22 hours) at the 100 percent load level is available to the diesel generator's load-carrying capability on an extended basis to compensate for the reduced runtime at the 110 percent load level.

3. For periodic testing required by the Hope Creek Technical Specifications, the test per this regulatory position will be performed during shutdown, except as noted in item 4. This test will simulate, separately, a loss of offsite power, and a loss of offsite power plus a LOCA condition, to verify the SDGs' ability to start and accept the sequence design loads.

4. For periodic testing required by the Hope Creek Technical Specifications, exception to regulatory position C.2.a.(5) is taken with respect to simulating a loss of offsite power (regulatory position C.2.a.(1)) and demonstrating the proper operation for design-accident-loading-sequence to design-load requirement 1.8-132 HCGS-UFSAR Revision 11 November 24, 2000

(regulatory position C.2.a.(2). Instead, the diesel generators will be subjected to a hot restart test (no loading required) that will follow either the 24-hour endurance run or a 2-hour loaded run of the diesel generator. Additionally, both the 24-hour endurance run and the for restart test may be performed during any mode of operation.

5. Regulatory Guide 1.108 criteria for determining and reporting valid tests and failures and accelerated diesel generator testing have been superceded by implementation of the Maintenance Rule for diesel generators per 10CFR50.65. This was approved in Hope Creek License Amendment 119.

6. Tests described in regulatory position C.2.a and C.2.b will be performed at a frequency determined under the Surveillance Frequency Control Program.

1.8.1.109 Conformance to Regulatory Guide 1.109, Revision 1, October 1977: Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10CFR Part 50, Appendix I HCGS complies with Regulatory Guide 1.109. For further discussion, see Section 15. 1.8.1.110 Conformance to Regulatory Guide 1.110, Revision 0, March 1976: Cost Benefit Analysis for Radwaste Systems For Light Water Cooled Nuclear Power Reactors HCGS complies with Regulatory Guide 1.110. 1.8.1.111 Conformance to Regulatory Guide 1.111, Revision 1, July 1977: Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light Water Cooled Reactors HCGS complies with Regulatory Guide 1.111. See Chapter 15 for further discussion. 1.8.1.112 Conformance to Regulatory Guide 1.112, Revision 0-R, May 1977: Calculation of Release of Radioactive Materials in Gaseous and Liquid Effluent from Light Water Cooled Power Reactors HCGS complies with Regulatory Guide 1.112. 1.8-133 HCGS-UFSAR Revision 24 May 21, 2020

1.8.1.113 Conformance to Regulatory Guide 1.113, Revision 1, April 1977: Estimating Aquatic Dispersion of Effluents From Accidental and Routine Reactor Releases for the Purpose of Implementing Appendix I HCGS complies with Regulatory Guide 1.113. See Chapter 15 for further discussion. 1.8.1.114 Conformance to Regulatory Guide 1.114, Revision 1, November 1976: Guidance on Being Operator at the Controls of a Nuclear Power Plant HCGS is committed to Regulatory Guide 1.114. This Regulatory Guide will be incorporated in an operating department directive or the appropriate NBU administrative procedure(s). 1.8.1.115 Conformance to Regulatory Guide 1.115, Revision 1, July 1977: Protection Against Low Trajectory Turbine Missiles HCGS complies with Regulatory Guide 1.115. For further discussion of missile protection, see Section 3.5. 1.8.1.116 Conformance to Regulatory Guide 1.116, Revision 0-R, June 1976: Quality Assurance Requirements for Installation, Inspection, and Testing of Mechanical Equipment and Systems HCGS complies with NQA-1-1994, and the intent of the regulatory position set forth in the Regulatory Guide. 1.8-134 HCGS-UFSAR Revision 16 May 15, 2008

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1.8.1.117 Conformance to Regulatory Guide 1.117, Revision 1, April 1978: Tornado Design Classification Although Regulatory Guide 1.117 is not applicable to HCGS, per its implementation section, HCGS complies with it. For further discussion of tornado loadings, see Section 3.3.2. 1.8.1.118 Conformance to Regulatory Guide 1.118, Revision 2, June 1978: Period Testing of Electric Power and Protection Systems Regulatory Guide 1.118 is not applicable to HCGS per its implementation section. However, with certain exceptions related to the use of temporary alterations during the performance of required at-power surveillance tests, HCGS is in compliance with this Regulatory Guide. 1.8.1.119 Conformance to Regulatory Guide 1.119, Revision 0, June 1976: Surveillance Program for New Fuel Assembly Designs Regulatory Guide 1.119 was withdrawn by the NRC on June 23, 1977 and is not applicable. 1.8.1.120 Conformance to Regulatory Guide 1.120, Revision 1, November 1977: Fire Protection Guidelines for Nuclear Power Plants HCGS complies with Regulatory Guide 1.120 with the exceptions discussed below. Since most of the guidelines in Regulatory Guide 1.120 have been incorporated in BTP CMEB 9.5.1, Revision 2, 1.8-136 HCGS-UFSAR Revision 15 October 27, 2006

dated July 1981, the attached exceptions are only for those items that are not found in BTP CMEB 9.5.1, Revision 2. See Section 9.5.1 for an evaluation of SRP 9.5.1 and additional exceptions. Also, see Appendix 9A for an evaluation of the HCGS design against the requirements of 10CFR50, Appendix R. Position C.4.a(10) of Regulatory Guide 1.120 requires that fire rated doors be normally closed and delay-alarmed with alarm and annunciation in the control room, and also locked closed or equipped with automatic self-closing devices using magnetic hold-open devices that are activated by smoke or rate-of-rise heat detectors protecting both sides of the opening. At HCGS, all fire rated doors meet the requirements of Appendix R to 10 CFR 50 and BTP CMEB 9.5.1, Revision 2, to ensure that they will protect the door opening as required in case of fire. Fire doors are provided with mechanical closing devices. In addition, all fire doors will be kept closed and inspected daily to verify that they are in the closed position. Position C.4.c.(4) of Regulatory Guide 1.120 requires that fire stops be installed every 20 feet along horizontal cable routing in areas that are not protected by automatic water systems. Vertical cable routings should have fire stops installed at each floor/ceiling level. Between levels or in vertical cable chases, fire stops should be installed at the midheight of the vertical run, 20 feet or more, but less than 30 feet or at 15 foot intervals in vertical runs of 30 feet or more, unless such vertical cable routings are protected by automatic water systems directed on the cable trays. At HCGS, fire stops are not provided for horizontal or vertical cable routings in areas or cable chases that are not protected by automatic water systems. All cable and cable tray penetrations through fire rated barriers, e.g., walls, ceiling, or floors, are sealed to provide a fire resistance rating equal to the fire rating of the barrier. Cable chases are separated from each other by a 1.8-137 HCGS-UFSAR Revision 0 April 11, 1988

3-hour fire barrier. Only one channel is included in each chase, and access doors are provided at each floor elevation. All cable routings are accessible for manual firefighting, and the cable spreading room and control equipment mezzanine are provided with an automatic fire suppression system. In addition, an automatic fire detection system is provided in areas where redundant shutdown cable trains are located. All cable routings meet the separation criteria for redundant shutdown trains as required in Appendix R to 10CFR50, and a fire in one fire area will not prevent safe shutdown of the plant. See Appendix 9A for comparison of HCGS to Appendix R. Position C.4.d.(1) of Regulatory Guide 1.120 requires that to facilitate manual firefighting separate smoke and heat vents be provided in specific areas such as cable spreading rooms, diesel fuel oil storage areas, switchgear rooms, and other areas where potential for heavy smoke conditions exists. At HCGS, automatic fire suppression systems are provided in areas where heavy smoke conditions may exist during a fire, i.e., cable spreading room and fuel oil storage areas. The cable spreading room is provided with a separate smoke removal system that serves the control area. For other areas of the plant, the normal ventilation system and portable smoke ejectors can be used to remove smoke generated during a fire. Automatic smoke detectors are provided in all fuel oil storage areas and electrical equipment rooms. Position C.5.b.(5) of Regulatory Guide 1.120 requires that the fire water supply be calculated on the basis of the largest expected flow rate for a period of 2 hours, not less than 300,000 gallons. This flow rate should be conservatively based on 750 gpm for manual base streams plus the largest design demand of any sprinkler or deluge system as determined in accordance with NFPA 13 or NFPA 15. The fire water supply should be capable of delivering this design demand over the longest route of the water supply system. 1.8-138 HCGS-UFSAR Revision 0 April 11, 1988

At HCGS, the fire water supply meets the requirements of BTP CMEB 9.5.1, Revision 2, which specify that the fire water supply be based on a flow rate of 500 gpm for manual base streams plus the largest design demand of any sprinkler or deluge system. Position C.6.j. of Regulatory Guide 1.120 requires that the diesel fuel oil tanks with a capacity greater than 1100 gallons not be located inside buildings containing safety-related equipment. If above ground tanks are used, they should be located at least 50 feet from any building containing safety-related equipment or, if located within 50 feet, they should be housed in a separate building with construction having a minimum fire resistance rating of 3 hours. Potential oil spills should be confined or directed away from buildings containing safety-related equipment. Totally buried tanks are acceptable outside or under buildings. See NFPA 30, Flammable and Combustible Liquid Code, for additional guidance. At HCGS, the two 26,500 gallon diesel fuel oil storage tanks are located in each of the storage tank rooms at floor elevation 54 feet of the Auxiliary Building diesel generator area. There are four of these rooms containing a total of 212,000 gallons of fuel oil. Each room is enclosed by 3-hour fire barriers. The diesel area is separated from the control area by 3-hour fire walls. A manually actuated deluge sprinkler system, a fixed automatic carbon dioxide total flooding system, and an automatic fire detection system is provided for each room. The above diesel fuel oil storage meets the requirement of NFPA 30. Although the combustible loading in the diesel fuel oil storage tank rooms is 2 7,045,000 Btu/ft of floor area, oxygen depletion can restrict the fully developed period of any fire event to approximately 5 minutes in consideration of the postulated combustion of approximately 17.36 gallons of fuel oil. HCGS's fuel oil storage conforms to the requirements of Appendix R to 10CFR50 and BTP CMEB 9.5.1, Revision 2. 1.8-139 HCGS-UFSAR Revision 0 April 11, 1988

1.8.1.121 Conformance to Regulatory Guide 1.121, Revision 0, August 1976: Bases for Plugging Degraded PWR Steam Generator Tubes Regulatory Guide 1.121 is not applicable to HCGS. 1.8.1.122 Conformance to Regulatory Guide 1.122, Revision 1, February 1978: Development of Floor Design Response Spectra for Seismic Design of Floor-Supported Equipment or Components Although Regulatory Guide 1.122 is not applicable to HCGS, per its implementation section, HCGS complies with it. For further discussion of seismic design, see Sections 3.7 and 3.10. 1.8.1.123 Conformance of Regulatory Guide 1.123, Revision 1, July 1977: Quality Assurance Requirements for Control of Procurement of Items and Services for Nuclear Power Plants NRC Regulatory Guide 1.123 was withdrawn by the NRC on July 31, 1991. HCGS complies with NQA-1-1994. 1.8-140 HCGS-UFSAR Revision 15 October 27, 2006

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1.8.1.124 Conformance To Regulatory Guide 1.124, Revision 1, January 1978: Service Limits and Loading Combinations for Class 1 Linear Type Component Supports Although Regulatory Guide 1.124 is not applicable to HCGS, per its implementation section, HCGS complies with it. For further discussion, see Section 3.9. 1.8.1.125 Conformance to Regulatory Guide 1.125, Revision 1, October 1978: Physical Models for Design and Operation of Hydraulic Structures and Systems for Nuclear Power Plants Although Regulatory Guide 1.125 is not applicable to HCGS, per its implementation section, HCGS complies with it. For further discussion of the Station Service Water System design, see Section 9.2.1. 1.8-144 HCGS-UFSAR Revision 15 October 27, 2006

1.8.1.126 Conformance to Regulatory Guide 1.126, Revision 1, March 1978: An Acceptable Model and Related Statistical Methods for the Analysis of Fuel Densification Regulatory Guide 1.126 is not applicable. 1.8.1.127 Conformance to Regulatory Guide 1.127, Revision 1, March 1978: Inspection of Water Control Structures Associated with Nuclear Power Plants HCGS complies with Regulatory Guide 1.127 as applicable to the intake structure. 1.8.1.128 Conformance to Regulatory Guide 1.128, Revision 1, October 1978: Installation Design and Installation of Large Lead Storage Batteries for Nuclear Power Plants Although Regulatory Guide 1.128 is not applicable to HCGS, per its implementation section, HCGS complies with it, subject to the clarification of Position C.1 that the ventilation exhaust duct is located just below the battery room ceiling in order to limit hydrogen concentrations to less than 2 percent by volume within the battery area. For further discussion of the lead storage batteries, see Sections 8.1.4.22 and 8.3.2. 1.8.1.129 Conformance to Regulatory Guide 1.129, Revision 1, February 1978: Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Nuclear Power Plants Although Regulatory Guide 1.129 is not applicable to HCGS, per its implementation section, HCGS complies with it with the following exception. Tests described in IEEE Std. 450-1975 will be performed at a frequency determined under the Surveillance Frequency Control Program. For further discussion of the batteries see Section 8.3.2 and Section 16. 1.8-145 HCGS-UFSAR Revision 24 May 21, 2020

1.8.1.130 Conformance to Regulatory Guide 1.130, Revision 1, October 1978: Service Limits and Loading Combinations for Class 1 Plate and Shell Type Components Supports Although Regulatory Guide 1.129 is not applicable to HCGS, per its implementation section, HCGS complies with it. For further discussion of design limits and loading combination, see Section 3.9.3. 1.8.1.131 Conformance to Regulatory Guide 1.131, Revision 0, August 1977: Qualification Tests of Electric Cables, Field Splices, and Connections for Light Water Cooled Nuclear Power Plants Although Regulatory Guide 1.131 is not applicable to HCGS, per its implementation section, HCGS complies with it, with the following clarification: Position C.5 states that the radiological source term and exposure rate simulating LOCA conditions should be obtained from Regulatory Guide 1.89 rather than from IEEE 323-1974. HCGS complies with this requirement. However, cable installed outside the reactor building is qualified to the relatively mild environment conditions that exist there. 1.8.1.132 Conformance to Regulatory Guide 1.132, Revision 1, March 1979: Site Investigations for Foundations of Nuclear Power Plants Regulatory Guide 1.132 is not applicable to HCGS. 1.8.1.133 Conformance to Regulatory Guide 1.133, Revision 1, May 1981: Loose Part Detection Program for the Primary System of Light Water Cooled Reactors Regulatory Guide 1.133 is no longer applicable to HCGS. The NRC has accepted General Electric (GE) Topical Report NEDC-32975P, Regulatory Relaxation for BWR Loose Parts Monitoring Systems. 1.8-146 HCGS-UFSAR Revision 12 May 3, 2002

1.8.1.134 Conformance to Regulatory Guide 1.134, Revision 2, April 1987: Medical Evaluation of Licensed Personnel for Nuclear Power Plants. HCGS complies with Regulatory Guide 1.34. 1.8.1.135 Conformance to Regulatory Guide 1.135, Revision 0, September 1977: Normal Water Level and Discharge at Nuclear Power Plants Although Regulatory Guide 1.135 is not applicable to HCGS, per its implementation section, HCGS complies with it. For further discussion, see Section 2.4. 1.8.1.136 Conformance to Regulatory Guide 1.136, Revision 2, June 1981: Materials, Construction, and Testing of Concrete Containments (Articles CC-1000, -2000, and -4000 through -6000 of the Code for Concrete Reactor Vessels and Containments) Regulatory Guide 1.136 is not applicable to HCGS. 1.8.1.137 Conformance to Regulatory Guide 1.137, Revision 1, October 1979: Fuel-Oil Systems for Standby Diesel Generators Although Regulatory Guide 1.137 is not applicable to HCGS, per its implementation section, HCGS complies with it, subject to exception of regulatory position C.1, which endorses ANSI N195-1976 Section 8.2.d and as modified by Technical Specification Amendment Nos. 74 and 100, and C.2.f, which specifies a 10 year frequency for fuel oil storage tank inspections. HCGS has a fuel-oil storage tank low-low and low alarm. High level protection is provided by the common fill isolation valve that automatically closes at the storage tank high-high level setpoint. Frequency for the fuel oil storage tank inspections will be performed as determined by the Surveillance Frequency Control Program. Compliance with Regulatory Guide 1.137 has been amended by the NRC in a letter dated Nov. 22, 1993 to provide an acceptable alternative to the guidance and recommendations contained in ANSI N195-1976 and RG 1.137, Revision 1, and complies with the requirements of GDC 5 and 17 as well as satisfying the intent of SRP Section 9.5.4, Section I.1.d. 1.8-147 HCGS-UFSAR Revision 26 April 13, 2023

1.8.1.138 Conformance to Regulatory Guide 1.138, Revision 0, April 1978: Laboratory Investigations of Soils for Engineering Analysis and Design of Nuclear Power Plants For new investigations conducted after December 1, 1978, HCGS complies with Regulatory Guide 1.138. Position C.3 references Regulatory Guide 1.132. Compliance with Regulatory Guide 1.132 is discussed in Section 1.8.1.132. For further discussion of site investigations, see Sections 2.4 and 2.5. 1.8.1.139 Conformance to Regulatory Guide 1.139, Revision 0, May 1978: Guidance for Residual Heat Removal Although the HCGS RHR design was completed before the issuance of this Regulatory Guide, which provides guidance on shutdown cooling mode design, the HCGS design satisfies the intent of the Regulatory Guide, subject to the following clarifications:

1. Provision of shutdown cooling, assuming the most limiting single active failure, loss of the common suction line due to valve failure to open, as discussed in Position C.1 of the Regulatory Guide, can also be accomplished by an alternate flow path. In the alternate method, the RHR pump takes suction from the suppression pool and discharges to the reactor vessel via the RHR heat exchanger. Flow returns from the vessel to the suppression pool via manually opened Automatic Depressurization System (ADS) valves.

A safety-grade air supply is available for ADS valve actuation, as discussed in Section 9.3.1. A variation of this method is to pump to the vessel with a core spray pump and operate the RHR system in the suppression pool cooling mode. 1.8-148 HCGS-UFSAR Revision 0 April 11, 1988

2. Regarding Position C.2.a of the Regulatory Guide, which discusses reactor high pressure interlocks and alarms, HCGS conforms with the intent in that the two suction valves, E11-HV-F008 and E11-HV-F009, are interlocked with reactor pressure. Two out of two low reactor pressure signals must be present to permit opening. Upon a high pressure signal, the valves close, and the pump trips. A pump trip activates an "RHR system out of service" alarm that annunciates in the main control room. High pressure is displayed on CRTs and the computer. Loss of power to the valve control logic causes suction valve closure and pump trip.

3. The RHR system is a low pressure system that when aligned to the reactor coolant systems operates only when the reactor pressure has been brought down to 100 psig. The RHR system isolates if reactor vessel pressure exceeds this design setpoint.

When the RHR system is not in operation, relief valves protect the system from excess pressure due to thermal expansion or leakback from the reactor through isolation valves. These relief valves discharge to the suppression pool.

4. The RHR design is considered to conform to the pump protection discussion in Position C.4 of the Regulatory Guide in that the pump motor has thermal overload protection, and the stator and bearing temperatures are monitored on the plant computer.

Cavitation is considered in pump selection and piping layout. Calculations have been performed to verify that adequate NPSH exists at maximum suppression pool temperature (212F) and maximum pump runout flow. 1.8-149 HCGS-UFSAR Revision 0 April 11, 1988

5. On-line testing capability of isolation valve operability and interlock circuits, as discussed in Position C.5 of the Regulatory Guide, is not provided. However, the system is periodically tested as discussed in Section 16, the Hope Creek Standard Technical Specifications.

1.8.1.140 Conformance to Regulatory Guide 1.140, Revision 1, October 1979: Design, Testing, and Maintenance Criteria for Normal Ventilation Exhaust System Air Filtration and Adsorption Units of Light Water Cooled Nuclear Power Plants Although Regulatory Guide 1.140 is not applicable to HCGS, per its implementation section, HCGS complies with it, subject to exceptions and clarifications stated below: Concerning Position C.2.a, the reactor building normally uses the Reactor Building Ventilation System (RBVS) exhaust system, which includes prefilters and HEPA filters but no charcoal filters. The radwaste area, fume hoods, and chemistry lab area exhaust systems have only prefilters and HEPA filters. The turbine building equipment compartment exhaust system has been designed with a provisional filter plenum which, at the present time, does not include filters. Position C.2.b has not been strictly observed because the RBVS exhaust system exhausts 48,000 cfm per each filter plenum. The radwaste area exhaust system fans are set to provide a nominal 33,800 cfm per each exhaust filter plenum since the tank vent has only 1000 cfm per filter plenum. Position C.2.f of Regulatory Guide 1.140 - Table 4-3 of ANSI N509 - 1980 Section 4.12 was used as the acceptance criteria for maximum allowable leakage in ductwork. Concerning Section C.5.d of Revision 1, the activated carbon adsorber section should be leak tested with a gaseous halogenated hydrocarbon refrigerant on a frequency that is in accordance with the HCGS Preventive Maintenance (PM) program. Regulatory Guide 1.140 references ANSI N510-1975. HCGS will use the ANSI N510-1980 issue. 1.8-150 HCGS-UFSAR Revision 25 November 15, 2021

For further discussion of the atmosphere cleanup systems, see Section 9.4. 1.8.1.141 Conformance to Regulatory Guide 1.141, Revision 0, April 1978: Containment Isolation Provisions for Fluid Systems Although Regulatory Guide 1.141 is not applicable to HCGS, per its implementation section, HCGS complies with the requirements of ANSI N271-1976 (ANS-56.2) as modified and interpreted by Regulatory Guide 1.141, with the exceptions and clarifications discussed below. ANSI Section 3.1, General, references an American National Standard and a draft standard for guidance on the development of quality group classifications. The criteria for quality group classifications at the HCGS is based on the guidelines of Regulatory Guide 1.26. When it is not practical to provide one isolation valve inside and one outside containment, and both valves are located outside primary containment, Section 3.6.4 requires that the valve nearest primary containment be enclosed in a protective leaktight or controlled leakage housing to prevent leakage to the atmosphere. Similarly, when greater safety is achieved by the use of a single isolation valve, Section 3.6.5 requires that the isolation valve be enclosed in a protective housing. In the HCGS design, no protective housing is provided. Nonetheless, the design is adequate in that any leakage will be collected within the Reactor Building, prior to filtration, dilution, and final release to the environment. Also, extensive leakage will trip sump level alarms, which will alert the main control room operators. Appendix A depicts typical isolation valve arrangements for BWRs. The arrangements are applicable to Mark III containment designs and do not apply to HCGS. 1.8-151 HCGS-UFSAR Revision 0 April 11, 1988

For further discussion of containment isolation, see Section 6.2.4. ANSI Section 3.6.2, Instrument Lines, states that NRC Regulatory Guide 1.11 provides suitable bases for demonstrating the acceptability of instrument lines penetrating primary containment. See Section 1.8.1.11 for discussion of compliance with Regulatory Guide 1.11. 1.8.1.142 Conformance to Regulatory Guide 1.142, Revision 1, October 1981: Safety-Related Concrete Structures for Nuclear Power Plants (Other than Reactor Vessels and Containments) Regulatory Guide 1.142 is not applicable to HCGS per its implementation section. SRP Section 3.8.4, Acceptance Criteria II.2, requires that Seismic Category I structures be designed in accordance with ACI 349-1976 as augmented by Regulatory Guide 1.142. HCGS Seismic Category I structures are designed based on ACI 318-1971. A review of the design of the HCGS Seismic Category I structures indicates that there is no impact due to differences in the structural acceptance criteria between ACI 318-71 and ACI 349-76 as augmented by Regulatory Guide 1.142. See Design Criteria Comparison Table 1.8-4. The load combinations used are in conformance with the following SRP sections except that the 0.9 load factor on dead load as required by ACI 349-76 was not used: Structures SRP Section Primary Containment Internal 3.8.3.II.3.b Concrete Structures Other Seismic Category I 3.8.4.II.3.b Concrete Structures 1.8-152 HCGS-UFSAR Revision 0 April 11, 1988

Based on parametric analyses, an adequate design margin exists to compensate for the effects of the reduced dead load factor. See Section 3.8.3 for discussion of the design of concrete structures. 1.8.1.143 Conformance to Regulatory Guide 1.143, Revision 1, October 1979: Design Guidance for Radioactive Waste Management Systems, Structures, and Components Installed in Light Water Cooled Nuclear Power Plants Although Regulatory Guide 1.143 is not applicable to HCGS, per its implementation section, HCGS complies with it, with the clarifications stated below. Positions C.1.1.2, C.2.1.2, C.3.1.2, and Table 1 of Regulatory Guide 1.143 require that all material specifications for pressure-retaining components within the radioactive process boundary conform to ASME B&PV Code, Section II. In addition, they require that piping materials conform to both the ASME and the identical ASTM specification, and they permit substitution of manufacturers' standards, instead of the ASME specification, in the case of pump materials. Although Regulatory Guide 1.143 does not explicitly address in-line process components, sight flow glasses, Y-strainers, and steam traps procured by the architect/engineer, and the orifice plates and conductivity elements in the NSSS scope of supply do not have certificates of compliance for the materials specified. Also, the records of shop inspection, required by Table 1, for the Y-strainers and the steam traps are not available from the supplier. Nevertheless, the quality assurance measures taken provide the reasonable assurance needed to protect the health and safety of the public and that of plant operating personnel. Position C.1.2.1 requires that the designated high liquid level conditions should actuate alarms both locally and in the control 1.8-153 HCGS-UFSAR Revision 0 April 11, 1988

room. For all tanks, a high liquid level condition actuates an alarm in the radwaste control room only. There are no local alarms since the tank rooms are controlled areas and normally unmanned. Position C.4.3 requires that process lines should not be less than 3/4 inch (nominal). The crystallizer concentrates and slurry waste transfer lines to the extruder/evaporators are 1/2 inch nominal, in order to maintain acceptable flow velocities to prevent settling in the lines**. The fluid flowrates are on the order of one (1) gpm as shown in Table 11.4-7 and on Plant Drawing M-68-0. 1.8.1.144 Conformance to Regulatory Guide 1.144, Revision 1, September 1980: Auditing of Quality Assurance Programs for Nuclear Power Plants NRC Regulatory Guide 1.144 was withdrawn by the NRC on July 31, 1991. HCGS is committed to the requirements of NQA-1-1994.

- Note: Crystallizer and Extruder Evaporators are abandoned in place.

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For further discussion of quality assurance, see Section 17. 1.8.1.145 Conformance to Regulatory Guide 1.145, Revision 0, August 1979: Atmospheric Dispersion Models for Potential Accident Consequence Assessments at Nuclear Power Plants HCGS complies with Regulatory Guide 1.145. 1.8-155 HCGS-UFSAR Revision 9 June 13, 1998

1.8.1.146 Conformance to Regulatory Guide 1.146, Revision 0, August 1980: Qualification of Quality Assurance Program Audit Personnel for Nuclear Power Plants NRC Regulatory Guide 1.146 was withdrawn by the NRC on July 31, 1991. HCGS is committed to the requirements of NQA-1-1994. For further discussion of quality assurance, see Section 17. 1.8.1.147 Conformance to Regulatory Guide 1.147, (Latest Revision): Inservice Inspection Code Case Acceptability ASME Section XI Division 1 HCGS complies with Regulatory Guide 1.147. For further discussion of inservice inspection, see Sections 3.9.6, 5.2.4, and 6.6. 1.8.1.148 Conformance to Regulatory Guide 1.148, Revision 0, March 1981; Functional Specification for Active Valve Assemblies in Systems Important to Safety in Nuclear Power Plants In accordance with Paragraph D, Implementation, Regulatory Guide 1.148 is not currently applicable to HCGS. If, in the future, replacement valves are ordered or modifications are made to systems important to safety, the guidelines of ANSI N278.1-1975, as modified and endorsed by Regulatory Guide 1.148, will be addressed and/or implemented. For discussion of the function specification requirements of active valve assemblies, see Section 3.9.3. 1.8.1.149 Conformance to Regulatory Guide 1.149, Revision 0, April 1981; Nuclear Power Plant Simulator for Use in Operator Training NOTE: Regulatory Guide 1.149, Revision 0, has been superseded by 10CFR55.45(b) and 10CFR55.46. 1.8-156 HCGS-UFSAR Revision 19 November 5, 2012

NOTE: Regulatory Guide 1.150 was been superseded by 10CFR50.55a(g)(6)(ii)(C) (1), Inservice inspection requirements. 1.8.1.155 Conformance to Regulatory Guide 1.155, Revision 0, August 1988: Station Blackout HCGS complies with Regulatory Guide 1.155 as described in Section 1.15. 1.8.1.181 Conformance to Regulatory Guide 1.181, Revision 0, September 1999: Content Of The Updated Final Safety Analysis Report in Accordance With 10 CFR 50.71(e) The PSEG Nuclear procedures for updating the UFSAR are based on NEI 98-03, Revision 1, which is endorsed by Regulatory Guide 1.181. The purpose of NEI 98-03 is to provide licensees with guidance for updating their FSARs consistent with the requirements of 10 CFR 50.71(e). Guidance is also provided for making voluntary modifications to UFSARs (i.e., removal, reformatting and simplification of information, as appropriate) to improve their focus, clarity and maintainability. 1.8.1.183 Conformance to Regulatory Guide 1.183, Revision 0, July 2000: Alternative Radiological Source Terms For Evaluating Design Basis Accidents At Nuclear Power Plants HCGS complies with Regulatory Guide 1.183. See Sections 6 and 15 for discussions of the radiological consequences of accidents. 1.8.2 NSSS Assessment of Conformance 1.8.2.1 Purpose The purpose of this section is to outline the compliance of the Hope Creek Generating Station (HCGS) design with Regulatory Guides issued by the NRC. 1.8.2.2 Compliance Assessment Method-NSSS Table 1.8-1 presents an assessment of the GE Nuclear Steam Supply System (NSSS) compliance with NRC Regulatory Guides. The NRC (AEC) began in 1970 to issue Regulatory Guides (Safety Guides), which state in detail methods acceptable to the NRC staff of meeting applicable Federal Regulations. Since that time, new and revised Regulatory Guides have been issued on an ongoing basis. 1.8-157 HCGS-UFSAR Revision 20 May 9, 2014

During the Construction Permit stage of HCGS, GE agreed in the Preliminary Safety Analysis Report (PSAR) to comply with the appropriate Regulatory Guides issued at that time. These Regulatory Guides are treated by GE as part of the design basis for HCGS. Subsequent to the Construction Permit stage, additional Regulatory Guides applicable to BWRs were issued. The HCGS design inherently meets, with alternate position in some cases, most of these Regulatory Guides. However, the Regulatory Guides issued subsequent to Construction Permit stage are not considered a part of the formal plant design basis. Table 1.8-1 lists the applicable Regulatory Guides 1.1 through 1.120, 1.128, 1.129, and 1.131, except for those Regulatory Guides that have been withdrawn or which do not apply to BWRs. The table also differentiates between those Regulatory Guides that are part of the design basis, i.e., GE committed to meet them in the PSAR, and those Regulatory Guides against which the design has been assessed. The actual description of how the design meets a Regulatory Guide is included in the FSAR text in the location where Regulatory Guide 1.70, Revision 3, indicates that it be addressed. The table identifies the specific revision of all Regulatory Guides addressed. Using the approach and methods discussed above, Table 1.8-1 provides a concise and accurate definition of Regulatory Guide compliance for the NSSS portion of HCGS. 1.8.3 References 1.8-1 General Electric, "Assessment of Reactor Internals Vibration in BWR/4 and BWR/5 plants," NEDO-24057A, April 1981. 1.8-2 General Electric, "Recirculation Pump Shaft Seal Leakage Analysis," NEDO-24083, November 1978. 1.8-3 Arthur D. Little, Inc, "Analysis of Potential Effects of Waterborne Traffic On the Safety of The Control Room and Water Intakes at Hope Creek Generating Station, September 1974. 1.8-158 HCGS-UFSAR Revision 18 May 10, 2011

1.8-4 Deleted. 1.8-5 General Electric, "Nuclear Energy Business Operations Boiling Water Reactor Quality Assurance Program Description," NEDO-11209-0A, Latest NRC-Accepted Revision. 1.8-159 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.8-1 REGULATORY GUIDE ASSESSMENT-NSSS Compliance { 1)

Design Basis Design Regulatory Guide Reference 121 N:s( 3) Compliance Alternate Basis Capability

1. 1' Net Positive Suction Head for ECCS Section 6.3.2.2 X X 0 1.2, Thermal Shock to Reactor Pressure Section 5. 3.3.1 X X 0 Vessels l .:J. ;~sumptions Used for Radiological NA Consequences of a LOCA BW~

1.5, Assumptions Used for Evaluating NA the Potential Radiological Consequences of a Steam Line Break 1.6, Independence Between Redundant X X 0 Standby (Onsite) Power Sources 1 *7 1 Control of C.omhustible Gas NA Concentrations in Containment 1.8, Personnel Selection and Training NA 1.9, Selection of Diesel Generator Set NA Capacity for Standby Power Supplies 1.11, Instrument Lines Penetrating NA Primary Reactor Containment Supplement to Safety Guide 11, Backfitting Considerations 1.12, Instrumentation for Earthquakes NA

l. 13 Spent Fuel Storage Facility Section 9 .1. 4

3 X 0 Design Basis 1.14, Reactor Coolant Pump Fl)~~cel Integrity 1.16, RerX)rting of Operating Infonnation NA

1. 17, Protection of Nuclear f'cn.:er Plants NA

              ,\gainst Industrial Sabotage l of 11 HCGS-FFSi\R                                                                                                                Revision 0 April ll , 1988

( ( ( TABLE 1.8-1 (Cont) Compliance ( 1 ) Design GE Basis Design Regulatory Guide Reference(Zl NSSS(J) Compliance Alternate Basis Capability

1. 20, Comprehensive Vibration Assessment Section 3.9.2.6.1 X X 2 Program for Reactor Internals

l. 21, :"leasuring, Evaluating, and NA Reporting Rad.ioacti vi ty in Solid Kas tes and Releases of Radioactive Naterials in Liquid and Gaseous Effluents

l. 22, Periodic Testing of Protection Sections 7.1.2.4, X X 0 0 System Actuation Functions 7.2.2.3, 7.3.2.1, 7.4.2.1, 7.4.2.2, 7.6.2.2, 7.6.2.3, and 7.6.2.5 1 . 23 , Onsi te Meteorological Programs NA

1. 25, ,\._">Slllllptions Used for Evaluating NA the Potential Radiological Consequences of a Fuel Handling Accident

1. 26, Qua.li ty Group Classifications & Sections 3. 2 . 2 X X 0,2 Standards for Water-, Steam-, & and 9.3.5.3 Radioactive Waste-containing Components

1. 21, til timate Heat Sink for Nuclear NA PoHcr Plants 1 . 28 , qual it:-- Assurance Program Chapter 17 X X 2 2 Requirements t!tjsign and Con!'\truction) 1.29, Seismic Desiron Classification Sections 3.2.1, X X 1 5.4.8.1, 1.1.2.4, 7.4.2.1, 7.<1.2.2, 7.6.2.5, and 9.3.5.3

1. 30, Quality ,\ssurance Requirements Sections 3. 11 X X 0 for the Instailation, Inspection, 1.1.2.4, 7.4.2.1,

               & Testing of Inst~ntation and          and 7.6.2.5 Electric Equipment
                                                                      ., of 11 IICGS-L
     'FSAH                                                                                                                    Revision 0
                                                                                                                              .\pril 1l

1988

TABLE 1.8-1 (Cont) Compliance(1) Design GE Basis Design (2) (3) Regulatory Guide Reference NSSS Compliance Alternate Basis Capability 1.31, Control of Ferrite Content in Sections 4.5.1.2, X X - 1,3,4 - Stainless Steel Weld Metal 4.5.2.4, 5.2.3.4, and 5.3.1.4 1.32, Criteria for Safety-Related Section 8.3.1.5 X - - - 2 Electric Power Systems for Nuclear Power Plants 1.33, Quality Assurance Program - NA - - - - Requirements (Operation) 1.34, Control of Electroslag Weld Sections 4.5.2.4, X - - - - Properties 5.2.3.3, and 5.3.1.4 1.35, Inservice Inspection of Ungrouted - NA - - - - Tendons in Prestressed Concrete Containment 1.36, Nonmetallic Thermal Insulation Section 4.5.2.4 X - - - 0 for Austenitic Stainless Steel 1.37, Quality Assurance Requirements Sections 4.5.1.4 X X 0 0 - for Cleaning of Fluid Systems (4) (Construction) 1.38, QA Requirements for Packaging, Chapter 17 X X 2 2 - Shipping, Receiving, Storage, (4)

      & Handling 1.39,  Housekeeping Requirements for     Chapter 17          X              X           -                2     -

Water-Cooled Nuclear Power (4) Plants 1.40, Qualification Tests of Continuous - NA - - - - Duty Motors Installed Inside the Containment 1.41, Preop Tests of Redundant Onsite - NA - - - - Electric Power Systems 1.43, Control of Stainless Steel Weld Sections 5.2.3, X - - - 0 Cladding of Low-Alloy Components and 5.3.1.4 3 of 11 HCGS-UFSAR Revision 24 May 21, 2020

( ( ( TABLE 1.8-1 (Cont) ComJ2liance ( 1) Design GE Basis Design R.eference(Z) NSSS(J) Compliance Alternate Basis canabili t;y 1.44, Control of the Use of Sensitized Sections 4.5.1.2, X X 0 0 Stainless Steel 5.2.3.4, and 5.3.1.4 1.45, Reactor Coolant Pressure Boundary Leakage Detection Systems 1.46, Protection Against Pipe Whip Section 3.6.2.6 X X 0 Inside Containment 1.47' Bypassed& Inoperable Status Sections 7.1.2.4, X X 0 Indication for Nuclear Power 7.4.2.1, 7.4.2.2, Plant Safety Systems 7.6.2.4, and 7.6.2.5 1.48, Design Limits & Loading NA Combinations for Seismic Category I Fluid System Components L.49, Power Levels of Nuclear Power Section 15.0.5 X 1 Plants 1.50, Control of Preheat Temperature Sections 5.2.3.3 X 0 for Welding of Low-Alloy Steel and 5.3.1.4 1.52, Design, Testing, & Maintenance NA Criteria for Atmosphere Cleanup System Air Filtration & Absorption Units 1.53, Application of the Single-Failure Sections 7.1.2.4, X X 0 Criterion 7.2.2.3, 7.3.2.1, and 7.6.2.3 1.54, QA ~uif~~nts for Protective Section 6 .1.2 X X 0 Coatu~s 1.55, Concrete Placement in Category I NA Structures 1.56, Maintenance of Water Purity in Sections 5.2.3.2 X X B\\'Rs and 5.4.8.1 l of 11 HCGS-UFSAR Revision 0 April ll, 1988

( ( ( TABLE 1.8-1 (Cont) Cauoliance ( 1 ) Design GE Basis Design Reference ( 2 ) NSSS( 3 ) Compliance Alten:~ate Basis Capability 1.57, Design Limits & Loading NA 1 Combinations for Metal Primary Reactor Containment 1.58, Qualification of Nuclear Power Chapter 17 X X 1 1 Plant Inspection, (~nation, & Testing Personnel 1.59, Design Basis for Floods for NA Nuclear Power Plants 1.60, Design Response Spectra for X 1 Seismic Design of Nuclear Power Plants 1.61, I:lamping Values for Seismic Design Section 3. 7

1 X X 0 of Nuclear Power Plants 1.62, Manual Initiation of Protective Sections 7.1.2.4, X X 0 Actions 7.2.2.3, 7.3.2.1, 7.4.2.1, and 7.4.2.2 1.63, Electric Penetration Assemblies NA in Containment Structures 1.64, QA Requirements for Destff PSAR Chapter 17 X X 2 2 of Nuclear Power Plants 1.65, ~hterials & Inspection for Section 5.3.1. 7 X 0 Reactor Vessel Closure Studs 1.66, Nondestructive Examination of Sections 5.2.3.3 X 0 Tubular Products and 5.2.3.4 1.671 Installation of Overpressure NA Protection Devices 1.68, Initial Test Programs for Section 14.2 NA Water-cooled Reactor Power Plants 5 of 11 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1. 8-1 (Cont) Compliance t1) Design GE Basis Design Regulatory Guide Reference(Z) NSSS(J) Compliance Alternate Basis Capability 1.68.1, Preop & Initial Startup Section 14.2 Testing of FW &. Condensate Systems for BWR 1.68.2, Initial Startup Test Section 14.2 Program to Demonstrate Remote Shutdown Capability

1. 69, Concrete Radiation Shields for NA Nuclear Pal-ler Plants

1. 70, Standard Format &. Contentof X X 3 Safety Analysis Reports for Nuclear Power Plants 1.71, Welder Qualification for Areas Sections 4.5.2.4, X 0 of Limited Accessibility 5.2.3.3, 5.2.3.4, and 5.3.1.4

1. 72, Spray Pond Plastic Piping NA 1.73, Qualification Tests of Electric Sections 3. 11 and NA 0 Valve Operators Installed Inside 7.1.2.4 the Containment of Nuclear Power Plants 1

74, QA Terms &. Definitions ( 4 ) Chapter 17 X X 2 1.75, Physical Independence of Sections 7.1.2.4, X X 1 1 Electric System 7.4.2.1, 7.6.2.2, 7.6.2.4 and 7.6.2.5

1. 76, Design Basis Tornado for Nuclear NA Power Plants

1. 78, Assl.lllptions for Evaluating the NA Habitability of a Hazardous Chemical Release 1.80, Prcop Testing of Instrt.nnent Air NA S~-stems 6 of 11 HCGS-llFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.8-1 (Cont) canpliance ( 1 ) Design GE Basis Design Regulatory Guide Reference(Z) NSSS ( 3 ) Compliance Alternate Basis Capability 1.81, Shared Emergency & Shutdown NA Electric Systems for Multiunit Nuclear Power Plants l

82 , SlBilps for Ea::: & Contail11DE!nt Spray NA Systems

1. 84, Code Case Acoeptabili ty - ASHE Section 5.2.1.2 X X NA Section III Design &. Fabrication

1. 85, Code Case Acceptability - ASME Section 5. 2.1.2 :X X NA Section III Materials

1. 86 1 Termination of Operating Licenses NA for Nuclear Reactors 1.88, Collection, s~~e, &. Maintenance Chapter 17 :X X 2 2 of QA Records

1. 89, Q.Jali fication of Class lE Sections 3 .11 and :X 0 Equipnent for Nuclear Power 7 .1.2.4 Plants

1. 90, Inservice Inspection of NA Prestressed Concrete Containment Struc::tures with GroutedTendons 1 .91 , Evaluation of Explosions NA Postulated to <Xx:ruron Transportation Routes

1. 92, Combining Model Responses &. Sections 3.7.3.7 X 1 Spatial Components in Seismic and 3.9.2.3 Response Analysis

1. 93, Availability of Electric Power NA Sources 1.94, QA for Installation, Inspection, NA

              & Testing of Structural COncrete
              &. Structural Steel During Construction 7 of 11 HCGS-UFSAR                                                                                                                       Revision 0 April 11, 1988

( ( ( TABLE 1.8-1 (Cont)

                                                                                        .(    1) coop l 1ance Design (2)    GE  (3)                  Basis          Design Regulatory §uide                         Reference       !!n          C*Uance Alternate           Basis  Capabi l i ty 1.95, Protection of Control Room                             NA Operators Agafnst an Accidental Chlorine Release 1.96, Design of MSIV Leakage Control                         NA SysttiiS for BWR Power Plants 1.97, tnstrunentation for LWR                                NA Nuclear Power Plants to Assess Plant Conditions During and Following an Accident 1.99, Radiation EIIDrittlement of        Section 5.3.1.4     NA                                              2 Reactor Vessel Materials 1.100, Seismic Qualification of          Sections 3.10       X Electric Equipment for            and 7.1.2.4 Nuclear Power Plants 1.101, Emergency Plamfng for Nuclear                         NA Power Plants 1.102, Flood Protection for Nuclear                          NA Power Plants 1.105, InstrUMent Setpoints              Section 7.1.2.4     X 1.106, Thermal overload Protection for                       NA Electric Motors on Motor~Operated Valves 1.108, Periodic Testing of Diesel                            NA Generator Units Used as onsite Electric Power Systems at Nuclear Power Plants 1.109, calculation of Annual Doses to                        NA Man From Routine Releases of Reactor Effluents 8 of 11 HCGS*UFSAR                                                                                                             Revision 8 Septent:Jer 25, 1996

( ( ( TABLE 1.8-1 (Cont) Com~liance ( 1) Design GE Basis Design Reference(Z) NSSS( 3 ) Com~liance Alternate Basis Cai;!!bil i tl 1.111, ~~thods for Esttmating NA Atmosphere Transport and Dispersion of Gaseous Effluents in Routine Releases from Light Water Cooled Reactors.

1. 112, C',.alculation of Releases of NA Radioactive Materials in Gaseous and Liquid Effluents from Light Water Cooled Power Reactors 1.113, Estimating Aquatic Dispersion of NA Effluents fl'OIIl Al:x)idental and Routine Reactor Releases for the Purpose of Implementing Appendix I 1.114t Guidance on Being Operator at the NA Controls of a Nuclear Prnoer Plant 1.115, Protection Against Low Trajectory NA Trubine Missles

1. 116' Quality Assurance Requirements Chapter 17 X X 0 for Installation, Inspection, and Testing of Hechanl1J'l Equipnent and Systems

1. 117. Tornado Design Classification NA 1.118, Periodic Testing of Electric Section 7.1.2.4 NA 2 Pm.rer and Protection Systenm 1.120, Fire Protection Guidelines for NA Nuclear Power Plants 1.123, Quality Assurance Requirements Chapter 17 X X 1 1 for Control of Procurement of Items and Sefl}ces for Nuclear Power Plants 9 of 11 HCGS-tiFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.8-1 {Cant) Compliance ( 1 ) Design GE Basis Design Regulatory Guide Reference( 2 ) NSSS(a) Compliance Alternate Basis Capability 1.128, Installation, Design, and NA Installation of Large Lead Storage Batteries for Nuclear Power Plants 1.129, Maintenance, Testing, and NA Replacement of J..argeLead Storage Batteries for Nuclear Power Plants 1.131, Qualification Tests of Kleotric NA Cables, Field Splices, and Connections for Light-Water-Cooled NuclearPowerPlants (1) Compliance assessment:

a. Design basis: A nliDber is placed in this col\Bil to indicate the Regulatory Guide revision that is a NSSS design basis requirement for this plant. Where no nliDber is shown, the guide was not an NSSS design 'ba.sis (See Section 1. 8. 2 )

When two nunbers are shown, they indicate the revision n\Dbers for guides applicable to equipuent procured and systems released before and after December, 1974, respectively.

b. C<nplia;nc:,e: An "X" is placed in this colmD.l to indicate compliance if the design basis guide ~ used by GE with or without an alternate position taken.

c. Design basis alternate: An "X" is placed in this column to indicate the SUide revision mnber to which an alternate position is taken.

d. Capability: A number is placed in this column to indicate the guide revision by which the capability of the NSSS portion of the HOGS ~ assessed.

(2)

Reference:

The number in this column indicates the section in which the compliance assessment for the guide indicated can be found. 13J GE NSSS - An "X" is placed under GE NSSS to indicate that GE is res}Xlnsible for the implementation or assessment of the Regulatory Guide shown. This colunn is used to designate "NA" when the guide shown is not applicable to the NSSS scope of supply for the HCGS. 10 of 11 HCGS-FFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.8-1 (Cant) 14l Descriptions of compliance with quality assurance related Regulatory Guides are not requested by Regulatory Guide 1. 70, Revision 3, since they relate to requirements that are implemented during the design, are resolved at the PSAR, i.e., Construction Pennit, stage of the project, ard are not pertinent at the FSAR, i.e., Operating License, stage. Compliance descriptions for quality assurance related Regulatory Guides may be found in Reference 1.8.5. 11 of 11 BCGS-l'FSAR Revision 0 April 11 , 1988

TABLE 1.8-2 RELATIVE NEUTRON FLUX VERSUS TIME( 1 ) Leakage rate, gpm (ramp rate, ¢/min){ 2} Percent 1(0.03) 5{0.15) 20(0.60) of Power 5 X 10"' 8 -555 500 -111 100 -27.75 25 5 X 10"' 7 .. 55 50 *11 10 -2.75 2.5 5 X 10"' 6 -5 5 -1 1 -0.25 0.25 5 X 10"' 5 0 0 0 5 X 10"' 4 0.8 0.8 0.36 0.36 0.18 0.18 5 X 10 .. J 1.33 0.53 0.51 0.15 0.25 0.07 5 X 10"' 2 1.59 0.26 0.62 0.11 0.31 0.06 5 X 10"' 1 1.80 0.21 0.72 0.10 0.36 0.05 5 X 10° 1.89 0.09 0.80 0.08 0.40 0.04

                                     -8 (1)   Shutdown flux- 5 x 10            percent of power.

(2) E

total number of'hours; ~-hours for neutron flux to increase by one decade *
HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 1.8-3 USE OF CODE CASE N-242 ON RCPB PIPING AND COMPONENTS (1) Item Tag/Spool No. Application Piping 1-AB-050-819 Main Steam Line Drain 1-AB-050-S20 Main Steam Line Drain 1-BE-023-SOl Core Spray Injection Safety-relief Valve 1-BC-PSV-4425 RHR shutdown suction venturies 1-FD-FO-N032 HPCI Steam Supply 1-FC-FE-4155 RCIC Steam Supply (1) Code case N-242 1 Revision o is applicable to all items.

HCGS-UFSAR 1 of 1 Revision 14 July 26, 2005

TABLE 1.8-4 DESIGN CRITERIA COMPARISON ACI 349-76 and Regulatory Guide Impact of Difference on HCGS Not included 8.8.4 and 8.8.5 None. Permanent fillers are not used for HCGS Seismic Category I structures. Not included 8.10 Alternate design None. Alternate design method is not used for method HCGS Seismic Category I structures. 9.3 Required strength 9.3 Required strength None. Load combinations for HCGS Seismic Category I concrete structures comply with SRP 3.8.3.II.3.b for containment internal concrete structures and SRP 3.8.4.II.3.b for other concrete structures. 9.3.3 Reduced load factors 9.3.4'Redu~ed load factors None. As stated in Section 3.8.4.8.1, an for dead and live load for dead and live load adequate design margin exists to compensate for the effects of the reduced dead and live load factors. 9.4 Design strengths for 9.4 Design strengths for None. Design of HCGS Seismic Category I reinforcement reinforcement structures is based on rebar yield strength (fy) = 60~000 psi Yield strength (fy) Yield strength (fy) limited to 60,000 psi limited to 80,000 psi 10.2.7 Assumptions 10.2.7 Assumptions None, since max~ value of design compressive strength, t * = 5000 psi for HCGS Seismic c B1 shall not be taken less No limitation on minimum Category I structures. than 0.65 value of a1 10.17 Minimum reinforcement Not included None. A review of the design of the HCGS for massive concrete structures Seismic Category I structures indicates that ACI 349 Section 10.17 criteria is met. 11.16.6 Punching shear 11.16.6 refers to 11.10 None. A review of the design of HCGS Seismic stress where: Category I structures indicates that ACI 349-76, Section 11.16.7 criteria is met. vc =weighted average of v c =4/f:! c vcb and vcv consider membrane stresses in wall. 1 of 3 HCGS-UFSAR Revision 0 t.~-~, 1, 1 QO:Il

ACI 349-76 and TABLE 1.8-4 (Cont)

Regulatory Guide ACI 318-71 Impact of Difference on HCGS 12.10 Development of welded 12.10 Development of welded None. Welded wire fabric does not serve a wire fabric wire fabric safety related function for HCGS Seismic Category I structures. Additional requirements for development length as compared with ACI 318-71. 13.3.1.5 Direct design 13.3.1.5 Direct design None. A review of the design of slabs for the method limitations method limitations HCGS Seismic Category I structures indicates that the direct design method is not used. uAll loads shall be due to "The live load shall not gravity only and uniformly exceed three times the dead distributed over the entire load." panel. The live load shall not exceed three times the dead load." 15.10 (b) Combined footings 15.10 (b) Combined footings None. A review of the design of the foundation and mats and mats mats for the HCGS Seismic Category I structures indicates that the direct method is not used. 11 The Direct Design Method of Use of Section 13.3 is not Section 13.3 shall not be excluded. used to design combined footings and mats. 11 16.2.2 Precast Concrete 16.2 Precast Concrete Design None. Precast concrete is *not used for HCGS Design Seismic Category I structures. Dynamic loadings are not "The design shall consider addressed in this section. impact and other dynamic These loads are considered loading which may be imposed to be part of Section during transportation or 16.2.1. erection." 2 of 3 HCGS-UPSAR Revision 0

ACI 349*76 and TABLE 1.8-4 (Cont)*

Regulatory Guide ACI 318-71 Impact of Difference on HCGS 16.4.2 Precast Concrete 16.4.2 Precast Concrete None. Precast concrete is not used for HCGS Details Details Seismic Category I structures. Embedded dowels or inserts Lifting devices shall have may be placed while the the capacity to support four concrete is in a plastic times the member's weight. state provided that they are not required to be booked or tied to reinforcement within concrete. Chapter 18 - Prestressed Chapter 18 - Prestressed None. Prestressed concrete is not used for Concrete Concrete HCGS Seismic Categor~ I structures. Differences with ACI 318.71 for Sections 18.5~ 18.9, 18.12 and 18.17. Chapter 19 - Shells Chapter 19 - Shells and None. A review of the design of the HCGS Folded Plate Members Seismic Category I shell concrete structures This chapter applies to indicates that ACI 349-76, Chapter 19 criteria shell concrete structures This chapter applies to thin is met. having thicknesses equal to concrete structures only. or greater than 12 inches. Appendix A - Thermal Not included None. A review of the design of the HCGS Considerations Seismic Category I structures indicates that ACI 349-76, Appendix A criteria is met. Appendix C - Special Not included A review of the design of the HCGS Seismic Provisions for Impulsive and Category I concrete structures indjcates that Impactive Effects the criteria given in Appendix C of ACI. 349-76 as amended by Regulatory Guide 1.142 are met. 3 of 3 HCGS-UFSAR Revision 0 ln¥ll 11 lORA

1.9 STANDARD DESIGNS This section is not applicable to Hope Creek Generating Station (HCGS) as it is not a standard design plant *

HCGS-UFSAR 1.9-1 Revision 0 April 11, 1988

1.10 TMI-2 RELATED REQUIREMENTS FOR NEW OPERATING LICENSES 1.10.1 NUREG-0737, Clarification of the TMI Action Plan Requirements Following the accident at Three Mile Island (TMI) Unit 2, the Nuclear Regulatory Commission (NRC) developed the TMI Action Plan, NUREG-0660, to provide a comprehensive and integrated plan for improving the safety of power reactors. NUREG-0737 was issued with an October 31, 1980 letter from D.G. Eisenhut, NRC, to licensees of operating power reactors and applicants for operating licenses forwarding specific TMI related requirements from NUREG-0660 which have been approved by the NRC for implementation at this time. In this NRC report, these specific requirements comprise a single document which includes additional information about implementation schedules, applicability, method of implementation review by the NRC, submittal dates, and clarification of technical positions. The total set of TMI related actions have been documented in NUREG-0660, but only those items that the NRC has approved for implementation to date are included in NUREG-0737. to NUREG-0737 lists TMI Action Plan requirements for operating license applicants. FSAR Section 1.10.2 itemizes these requirements sequentially according to the NUREG-0737 number. Each item is accompanied by a response and/or reference to a section in the FSAR that further discusses how Public Service Electric and Gas Company (PSE&G) or the Hope Creek Generating Station (HCGS) design complies with the requirement. These responses will be revised periodically as ongoing efforts to address each requirement are completed. 1.10-1 HCGS-UFSAR Revision 0 April 11, 1988

1.10.2 TMI Action Plan Requirements for Applicants for an Operating License (Enclosure 2 to NUREG-0737) I.A.1.1 Shift Technical Advisor Position Each applicant shall provide an on-shift technical advisor to the shift supervisor. The Shift Technical Advisor (STA) may serve more than one unit at a multiunit site if qualified to perform the advisor function for the various units. The STA shall have a bachelor's degree or equivalent in a scientific or engineering discipline and have received specific training in the response and analysis of the plant for transients and accidents. The STA shall also receive training in plant design and layout, including the capabilities of instrumentation and controls and the control room. The applicant shall assign normal duties to the STAs that pertain to the engineering aspects of assuring safe operations of the plant, including the review and evaluation of operating experience. Clarification

1. Due to the similarity in the requirements for dedication to safety, training, and onsite location and the desire that the accident assessment function be performed by someone whose normal duties involve review of operating experiences, our preferred position is that the same people perform the accident and operating experience assessment function. The performance of these two functions may be split if it can be demonstrated the persons assigned the accident assessment role are aware, on a current basis, of the work being done by those reviewing operating experience.

2. To provide assurance that the STA will be dedicated to concern for the safety of the plant, our position has been the STAs 1.10-2 HCGS-UFSAR Revision 0 April 11, 1988

must have a clear measure of independence from duties associated with the commercial operation of the plant. This would minimize possible distractions from safety judgments by the demands of commercial operations. We have determined that, while desirable, independence from the operations staff of the plant is not necessary to provide this assurance. It is necessary, however, to clearly emphasize the dedication to safety associated with the STA position both in the STA job description and in the personnel filling this position. It is not acceptable to assign a person who is normally the immediate supervisor of the shift supervisor to STA duties as defined herein.

3. It is our position that the STA should be available within 10 minutes of being summoned and therefore should be onsite. The onsite STA may be in a duty status for periods of time longer than one shift, and therefore asleep at some times, if the 10-minute availability is assured. It is preferable to locate those doing the operating experience assessment onsite. The desired exposure to the operating plant and contact with the STA (if these functions are to be split) may be able to be accomplished by a group, normally stationed offsite, with frequent onsite presence.

We do not intend, at this time, to specify or advocate a minimum time onsite.

Response

The STA function will be provided, on shift, by an individual meeting the experience, education, and training requirements as specified in NUREG-0737 and ANS 3.1-1981 as endorsed by the NRC in Regulatory Guide 1.8, Revision 2. The proposed supervisory shift crew composition for conditions 1 through 3 consists of one Shift Manager, one Control Room Supervisor (CRS-SRO), two reactor operators/plant operators (RO/POs), and a person who is STA qualified. 1.10-3 HCGS-UFSAR Revision 15 October 27, 2006

The STA will have a Bachelors degree or equivalent in a scientific or engineering discipline with specific training in: the response and analysis of the plant for transients and accidents; plant design and layout; and the capabilities of instrumentation and control in the control room; in accordance with the requirements of NUREG-0737, Section I.A.1.1. Individuals can serve in a dual role capacity as either the SNSS/STA or NSS/STA. Any STA filling the dual role of STA/SRO (Reference 13.1.1.4.1.2) will meet the educational requirements of the Commission Policy Statement on Engineering on Shift (50 FR 43621) by having a: professional engineer's license; or bachelors degree from an accredited institution in an engineering, engineering technology, or physical sciences discipline (the engineering technology or physical sciences programs shall include courses in the physical, mathematical, or engineering sciences) as well as the specific training specified above. During normal operations, the STA may be assigned responsibilities that pertain to the engineering aspects of ensuring safe operations of the plant. See Section 13.1 for further discussion. The content of the Shift Technical Advisor Training and Certification Program is described in the Nuclear Training Procedures Manual. I.A.1.2 Shift Supervisor Responsibilities Position Review the administrative duties of the shift supervisor and delegate functions that detract from or are subordinate to the management responsibility for assuring safe operation of the plant to other personnel not on duty in the control room. 1.10-4 HCGS-UFSAR Revision 15 October 27, 2006

Clarification

1. The highest level of corporate management of each licensee shall issue and periodically reissue a management directive that emphasizes the primary management responsibility of the shift supervisor for safe operation of the plant under all conditions on his shift and that clearly establishes his command duties.

2. Plant procedures shall be reviewed to assure that the duties, responsibilities, and authority of the shift supervisor and control room operators are properly defined to effect the establishment of a definite line of command and clear delineation of the command decision authority of the shift supervisor in the control room relative to other plant management personnel. Particular emphasis shall be placed on the following:

(a) The responsibility and authority of the shift supervisor shall be to maintain the broadest perspective of operational conditions affecting the safety of the plant as a matter of highest priority at all times when on duty in the control room. The principle shall be reinforced that the shift supervisor should not become totally involved in any single operation in times of emergency when multiple operations are required in the control room. (b) The shift supervisor, until properly relieved, shall remain in the control room at all times during accident situations to direct the activities of control room operators. Persons authorized to relieve the shift supervisor shall be specified. (c) If the shift supervisor is temporarily absent from the control room during routine operations, a lead control room operator shall be designated to assume the control room command function. These temporary duties, 1.10-5 HCGS-UFSAR Revision 0 April 11, 1988

responsibilities, and authority shall be clearly specified.

3. Training programs for shift supervisors shall emphasize and reinforce the responsibility for safe operation and the management function that the shift supervisor is to provide for assuring safety.

4. The administrative duties of the shift supervisor shall be reviewed by the senior officer of each utility responsible for plant operations.

Administrative functions that detract from or are subordinate to the management responsibility for assuring the safe operation of the plant shall be delegated to other operations personnel not on duty in the control room.

Response

A written policy describing the primary management responsibilities of OS-SROs and establishing their command duties was placed in effect September 12, 1979 and reissued by the senior corporate nuclear officer as VPN-PLP-01. Subsequently, the policy will be contained in the appropriate NBU administrative procedure(s). The guidance of this policy, along with the duties, responsibilities, and authority of the OS-SRO, is promulgated in the appropriate NBU administrative procedure(s). The shift command function responsibilities are promulgated in the appropriate NBU administrative procedures(s). Shift administrative duties which detract from the OS-SRO's responsibility for safe operation of the plant will be assigned to clerks, the Operations Staff Group or "Work Control Group personnel" as appropriate. 1.10-6 HCGS-UFSAR Revision 9 June 13, 1998

See Section 13.1.2 for further discussion. I.A.1.3 Shift Staffing Position Assure that the necessary number and availability of personnel to staff the operations shifts have been designated by the licensee. Administrative procedures should be written to govern the movement of key individuals about the plant to assure that qualified individuals are readily available in the event of an abnormal or emergency situation. This should consider the recommendations on overtime in NUREG-0578. Provisions should be made for an aide to the shift supervisor to assure that, over the long term, the shift supervisor is free of routine administrative duties. Clarification At any time a licensed nuclear unit is being operated in Modes 1-4 for a pressurized water reactor (power operation, startup, hot standby, or hot shutdown, respectively) or in Modes 1-3 for a boiling water reactor (power operation, startup, or hot shutdown, respectively), the minimum shift crew shall include two licensed senior reactor operators, one of whom shall be designated as the shift supervisor, two licensed reactor operators, and two unlicensed auxiliary operators. For a multi unit station, depending upon the station configuration, shift staffing may be adjusted to allow credit for licensed senior reactor operators and licensed reactor operators to serve as relief operators on more than one unit; however, these individuals must be properly licensed on each such unit. At all other times, for a unit loaded with fuel, the minimum shift crew shall include one shift supervisor who shall be a licensed senior reactor operator, one licensed reactor operator, and one unlicensed auxiliary operator. 1.10-7 HCGS-UFSAR Revision 8 September 25, 1996

Adjunct requirements to the shift staffing criteria stated above are as follows:

1. A shift supervisor with a senior reactor operator's license, who is also a member of the station supervisory staff, shall be onsite at all times when at least one unit is loaded with fuel.

2. A licensed senior reactor operator shall, at all times, be in the control room from which a reactor is being operated. The shift supervisor may from time to time act as relief operator for the licensed senior reactor operator assigned to the control room.

3. For any station with more than one reactor containing fuel, the number of licensed senior reactor operators onsite shall, at all times, be at least one more than the number of control rooms from which the reactors are being operated.

4. In addition to the licensed senior reactor operators specified in 1, 2, and 3 above, for each reactor containing fuel, a licensed reactor operator shall be in the control room at all times.

5. In addition to the operators specified in 1, 2, 3, and 4 above, for each control room from which a reactor is being operated, an additional licensed reactor operator shall be onsite at all times and available to serve as relief operator for that control room. As noted above, this individual may serve as relief operator for each unit being operated from that control room, provided (s)he holds a current license for each unit.

6. Auxiliary (non-licensed) operators shall be properly qualified to support the unit to which assigned.

7. In addition to the staffing requirements stated above, shift crew assignments during periods of core alterations shall 1.10-8 HCGS-UFSAR Revision 8 September 25, 1996

include a licensed senior reactor operator to directly supervise the core alterations. This licensed senior reactor operator may have fuel handling duties but shall not have other concurrent operational duties. Licensees of operating plants and applicants for operating licenses shall include in their administrative procedures (required by license conditions) provisions governing required shift staffing and movement of key individuals about the plant. These provisions are required to assure that qualified plant personnel to staff the operational shifts are readily available in the event of an abnormal or emergency situation. These administrative procedures shall also set forth a policy, the objective of which is to operate the plant with the required staff and develop working schedules such that use of overtime is avoided, to the extent practicable, for the plant staff who perform safety-related functions (e.g., senior reactor operators, health physicists, auxiliary operators, instrumentation and control technicians, and key maintenance personnel). IE Circular No. 80-02, "Nuclear Power Plant Staff Work Hours," dated February 1, 1980, discusses the concern of overtime work for members of the plant staff who perform safety-related functions. We recognize that there are diverse opinions on the amount of overtime that would be considered permissible and that there is a lack of hard data on the effects of overtime beyond the generally recognized normal 8-hour working day, the effects of shift rotation, and other factors. We have initiated studies in this area. Until a firmer basis is developed on working hours, the administrative procedures shall include as an interim measure the following guidance, which generally follows that of IE Circular No. 80-02. 1.10-9 HCGS-UFSAR Revision 8 September 25, 1996

In the event that overtime must be used (excluding extended periods of shutdown for refueling, major maintenance, or major plant modifications), the following overtime restrictions should be followed.

1. An individual should not be permitted to work more than 12 hours straight (not including shift turnover time).

2. There should be a break of at least 12 hours (which can include shift turnover time) between all work periods.

3. An individual should not work more than 72 hours in any 7-day period.

4. An individual should not be required to work more than 14 consecutive days without having 2 consecutive days off.

However, recognizing that circumstances may arise requiring deviation from the above restrictions, such deviation shall be authorized by the Plant Manager or higher levels of management in accordance with published procedures and with appropriate documentation of the cause. If a reactor operator (RO) or senior reactor operator (SRO) has been working more than 12 hours during periods of extended shutdown (e.g., at duties away from the control board), such individuals shall not be assigned shift duty in the control room without at least a 12 hour break preceding such an assignment. We encourage the development of a staffing policy that would permit the licensed reactor operators and senior reactor operators to be periodically relieved of primary duties at the control board, such that periods of duty at the board do not exceed about 4 hours at a time. If a reactor operator is required to work in excess of 8 continuous hours, (s)he shall be periodically relieved of primary duties at the control board, such that periods of duty at the board do not exceed about 4 hours at a time. 1.10-10 HCGS-UFSAR Revision 13 November 14, 2003

The guidelines on overtime do not apply to the STA provided that the STA is provided sleeping accommodations and 10-minute availability is assured. Operating license applicants shall complete these administrative procedures before fuel loading. Development and implementation of the administrative procedures at operating plants will be reviewed by the Office of Inspection and Enforcement beginning 90 days after July 31, 1980.

Response

See Section 13.1.2 for discussion on shift staffing and operating shift crews. The appropriate NBU administrative procedure(s) establishes maximum work hours for licensed operators and implements current NRC policy including policy statement on nuclear power plant staff working hours dated 2/11/82 and Generic Letter 82-12. Adequate shift coverage shall be maintained without routine excessive use of overtime. The objective shall be to have operating personnel work a nominal 40-hour week while the plant is operating to meet the rotating schedule requirements of the department. However, in the event that unforeseen problems require substantial amounts of overtime to be used; or during extended periods of shutdown for refueling, major maintenance, or major plant modifications, on a temporary basis; the following guidelines shall be followed:

1. An individual should not be permitted to work more than 16 hours straight, excluding shift turnover time.

2. An individual should not be permitted to work more than 16 hours in any 24-hour period, nor more than 24 hours in any 48-hour period, nor more than 72 hours in any 7-day period, all excluding shift turnover time.

1.10-11 HCGS-UFSAR Revision 8 September 25, 1996

3. A break of at least 8 hours should be allowed between work periods, including shift turnover time.

4. Except during extended shutdown periods, the use of overtime should be considered on an individual basis and not for the entire staff on a shift.

Any deviation from the above guidelines shall be authorized by the cognizant department manager or higher levels of management, with documentation of the basis for granting the deviation. Overtime shall be reviewed monthly by the Plant Manager or designee. Shift staffing is described in Section 13.1.2 and in the appropriate NBU administrative procedure(s). I.A.2.1 Immediate Upgrading of Operator and Senior Operator Training and Qualification Position Applicants for SRO license shall have 4 years of responsible power plant experience, of which at least 2 years shall be nuclear power plant experience (including 6 months at specific plant) and no more than 2 years shall be academic or related technical training. After fuel loading, applicants shall have 1 year of experience as a licensed operator or equivalent. Certifications that operator license applicants have learned to operate the controls shall be signed by the highest level of corporate management for plant operation. Applicants must revise training programs to include training in heat transfer, fluid flow, thermodynamics, and plant transients. 1.10-12 HCGS-UFSAR Revision 13 November 14, 2003

Clarification Applicants for SRO either come through the operations chain (C operator to B operator to A operator, etc.) or are degree-holding staff engineers who obtain licenses for backup purposes. In the past, many individuals who came through the operator ranks were administered SRO examinations without first being an operator. This was clearly a poor practice and the letter of March 28, 1980 requires reactor operator experience for SRO applicants. However, NRC does not wish to discourage staff engineers from becoming licensed SROs. The effort is encouraged because it forces engineers to broaden their knowledge about the plant and its operation. In addition, in order to attract degree holding engineers to consider the shift supervisor's job as part of their career development, NRC should provide an alternate path to holding an operator's license for 1 year. The track followed by a high-school graduate (a nondegreed individual) to become an SRO would be 4 years as a control room operator, at least one of which would be as a licensed operator, and participation in an SRO training program that includes 3 months on shift as an extra person. The track followed by a degree holding engineer would be, at a minimum, 2 years of responsible nuclear power plant experience as a staff engineer, participation in an SRO training program equivalent to a cold applicant training program, and 3 months on shift as an extra person in training for an SRO position. Holding these positions assures that individuals who will direct the license activities of licensed operators have had the necessary combination of education, training, and actual operating experience prior to assuming a supervisory role at the facility. 1.10-13 HCGS-UFSAR Revision 0 April 11, 1988

The staff realizes that the necessary knowledge and experience can be gained in a variety of ways. Consequently, credit for equivalent experience should be given to applicants for SRO licenses. Applicants for SRO licenses at a facility may obtain their 1-year operating experience in a licensed capacity (operator or senior operator) at another nuclear power plant. In addition, actual operating experience in a position that is equivalent to a licensed operator or senior operator at military propulsion reactors will be acceptable on a one for one basis. Individual applicants must document this experience in their individual applications in sufficient detail so that the staff can make a finding regarding equivalency. Applicants for SRO licenses who possess a degree in engineering or applicable sciences are deemed to meet the above requirements, provided they meet the requirements set forth in Sections A.1.a and A.2 in the enclosure in the letter from H.R. Denton to all power reactor applicants and licensees, dated March 28, 1980, and have participated in a training program equivalent to that of a cold senior operator applicant. NRC has not imposed the 1-year experience requirement on cold applicants for SRO licenses. Cold applicants are to work on a facility not yet in operation; their training programs are designed to supply the equivalent of the experience not available to them.

Response

All pre-core load SRO candidates will sit for a cold license and thus are not required to have been a licensed operator. The training program is designed to supply the equivalent of the experience they may lack and to meet the requirements of NUREG-0737 and ANS 3.1-1981. Subsequent hot license candidates will meet the requirements of NUREG-0737, ANS 3.1-1981 as endorsed by the NRC in Regulatory Guide 1.8, Revision 2 and the H.R. Denton letter of 3/28/80. 1.10-14 HCGS-UFSAR Revision 6 October 22, 1994

I.A.2.3 Administration of Training Programs Position Pending accreditation of training institutions, training instructors who teach systems, integrated response, transient and simulator courses shall successfully complete a Senior Reactor Operator (SRO) examination prior to fuel loading and instructors shall attend appropriate retraining programs that address, as a minimum, current operating history, problems and changes to procedure and administrative limitations. In the event an instructor is a licensed SRO, his retraining shall be the SRO requalification program. Clarification The above position is a short term position. In the future, accreditation of training institutions will include review of the procedure for certification of instructors. The certification of instructors may, or may not, include successful completion of an SRO examination. The purpose of the examination is to provide NRC with reasonable assurance during the interim period that instructors are technically competent. The requirement is directed to permanent members of training staff who teach the subjects listed above, including members of other organizations who routinely conduct training at the facility. There is no intention to require guest lecturers who are experts in particular subjects (reactor theory, instrumentation, thermodynamics, health physics, chemistry, etc.) to successfully complete an SRO examination. Nor is it intended to require a system expert, such as the instrument and control supervisor teaching the control rod drive system, to sit for an SRO examination. 1.10-15 HCGS-UFSAR Revision 4 April 11, 1992

Response

Prior to fuel loading, all instructors who teach systems, integrated response, transient response, and simulator courses will have successfully completed an approved SRO Cold Certification Program and/or have held an SRO license on a BWR facility. In addition, they will take as a minimum an NRC SRO instructor certification exam and actively participate in the SRO requalification program as required by the NRC. Vendor personnel who teach the above courses will be approved by the principal training supervisor - Hope Creek or his designated representative. I.A.3.1 Revise Scope and Criteria for Licensing Examinations Position Applicants for operator licenses will be required to grant permission to the NRC to inform their facility management regarding the results of examinations. Contents of the licensed operator requalification program shall be modified to include instruction in heat transfer fluid flow, thermodynamics and mitigation of accidents involving a degraded core. The criteria for requiring a licensed individual to participate in accelerated requalification shall be modified to be consistent with the new passing grade for issuance of a license. Requalification programs shall be modified to require specific reactivity control manipulations. Normal control manipulations, such as plant or reactor startups, must be performed. Control manipulations during abnormal or emergency operation shall be walked through and evaluated by a member of the training staff. An 1.10-16 HCGS-UFSAR Revision 0 April 11, 1988

appropriate simulator may be used to satisfy the requirements for control manipulations. Clarification The clarification does not alter the staff's position regarding simulator examinations. The clarification does provide additional preparation time for utility companies and NRC to meet examination requirements as stated. A study is under way to consider how similar a nonidentical simulator should be for a valid examination. In addition, present simulators are fully booked months in advance. Application of this requirement was stated in June 1, 1980 to applicants where a simulator is located at the facility. Starting October 1, 1981, simulator examinations will be conducted for applicants of facilities that do not have simulators at the site. NRC simulator examinations normally require 2 to 3 hours. Normally, two applicants are examined during this time period by two examiners. Utility companies should make the necessary arrangements with an appropriate simulator training center to provide time for these examinations. Preferably these examinations should be scheduled consecutively with the balance of the examination. However, they may be scheduled no sooner than 2 weeks prior to and no later than 2 weeks after the balance of the examination.

Response

The requalification program meets the requirements of 10CFR55. The Hope Creek simulator is operational for training and has been used for the operator requalification training program. 1.10-17 HCGS-UFSAR Revision 4 April 11, 1992

I.B.1.2 Evaluation of Organization and Management Position Corporate management of the utility owner of a nuclear power plant shall be sufficiently involved in the operational phase activities, including plant modifications, to assure a continual understanding of plant conditions and safety considerations. Corporate management shall establish safety standards for the operation and maintenance of the nuclear power plant. To these ends, each utility owner shall establish an organization, parts of which shall be located onsite, to: perform independent review and audits of plant activities; provide technical support to the plant staff for maintenance, modifications, operational problems, and operational analysis; and aid in the establishment of programmatic requirements for plant activities. The licensee shall establish an integrated organizational arrangement to provide for the overall management of nuclear power plant operations. This organization shall provide for clear management control and effective lines of authority and communication between the organizational units involved in the management, technical support, and operation of the nuclear unit. The key characteristics of a typical organization arrangement are:

1. Integration of all necessary functional responsibilities under a single responsible head.

2. The assignment of responsibility for the safe operation of the nuclear power plant(s) to an upper level executive position.

Utility management shall establish a group, independent of the plant staff, but assigned onsite, to perform independent reviews of plant operational activities. The main functions of this group will be to evaluate the technical adequacy of all procedures and changes 1.10-18 HCGS-UFSAR Revision 4 April 11, 1992

important to the safe operation of the facility and to provide continuing evaluation and assessment of the plant's operating experience and performance.

Response

See Section 13.1 for discussion of the PSE&G and HCGS organizations. The Director - Nuclear Oversight reports directly to the President and Chief Nuclear Officer as discussed in Sections 13.1 and 17.2. I.C.1 Short Term Accident Analysis and Procedure Review Position In our letters of September 13 and 27, October 10 and 30, and November 9, 1979, we required licensees of operating plants, applicants for operating licenses, and licensees of plants under construction to perform analyses of transients and accidents, prepare emergency procedure guidelines, upgrade emergency procedures, and to conduct operator retraining (see also Item I.A.2.1 of this report). Emergency procedures are required to be consistent with the actions necessary to cope with the transients and accidents analyzed. Analyses of transients and accidents were to be completed in early 1980, and implementation of procedures and retraining were to be completed 3 months after emergency procedure guidelines were established; however, some difficulty in completing these requirements has been experienced. Clarification of the scope of the task and appropriate schedule revisions were included in NUREG-0737, Item I.C.1. Pending staff approval of the revised analysis and guidelines, the staff will continue the pilot monitoring of emergency procedures described in Item I.C.8 (NUREG-0660). The adequacy of the boiling water reactor vendor's guidelines will be identified to each near-term operating licensee during the emergency procedure review. 1.10-19 HCGS-UFSAR Revision 22 May 9, 2017

Response

All emergency operating procedures (EOPs) have been written following the guidelines of the BWR Owners Group-Emergency Procedures Committee, as long as the guidelines do not contradict existing NRC directives. The Procedures Generation Package (PGP) for the EOPs is provided in Appendix 13L. The procedures are available for NRC review. Corrections will be made, as necessary, based on any NRC audits of these procedures. The Emergency Operating Procedures for HCGS comply with NUREG-0737, Supplement 1, Section 7.0. The Procedure Generation Package, Appendix 13L, which applied to initial revision of the Emergency Operating Procedures, has been deleted. The Writer's Guide, Verification Plan, Validation Plan and Training Plan have been retained in appropriate department administrative procedures and training programs for use in subsequent EOP revisions. I.C.2 Shift Relief and Turnover Procedures Position The licensee shall review and revise as necessary the plant procedure for shift and relief turnover to assure the following:

1. A checklist shall be provided for the oncoming and offgoing control room operators and the oncoming shift supervisor to complete and sign. The following items, as a minimum, shall be included in the checklist:

(a) Assurance that critical plant parameters are within allowable limits (parameters and allowable limits shall be listed on the checklist). (b) Assurance of the availability and proper alignment of all systems essential to the prevention and mitigation of operational transients and accidents by a check of the control console. What to check and criteria for acceptable status shall be included on the checklist. 1.10-20 HCGS-UFSAR Revision 9 June 13, 1998

(c) Identification of systems and components that are in a degraded mode of operation permitted by the Technical Specifications. For such systems and components, the length of time in the degraded mode shall be compared with the Technical Specifications action statement. (This shall be recorded as a separate entry on the checklist.)

2. Checklists or logs shall be provided for completion by the offgoing and oncoming auxiliary operators and technicians. Such checklists or logs shall include any equipment under maintenance or test that by itself could degrade a system critical to the prevention and mitigation of operational transients and accidents or initiate an operational transient (what to check and criteria for acceptable status shall be included on the checklist); and

3. A system shall be established to evaluate the effectiveness of the shift and relief turnover procedures (for example, periodic independent verification of system alignments).

Response

The required checklists addressing shift turnover are specified in the appropriate NBU administrative procedure(s). The effectiveness of and compliance with the shift turnover procedure shall be audited in accordance with the Nuclear Oversight audit program as described in section 17.2 of the UFSAR. I.C.3 Shift Supervisor Responsibilities This item is included with Item I.A.1.2, Shift Supervisor Duties.

Response

A discussion of this item is provided in the response to Item I.A.1.2. 1.10-21 HCGS-UFSAR Revision 14 July 26, 2005

I.C.4 Control Room Access Position The licensee shall make provisions for limiting access to the control room to those individuals responsible for the direct operation of the nuclear power plant (e.g., operations supervisor, shift supervisor, and control room operators), to technical advisors who may be requested or required to support operation, and the predesignated NRC personnel. Provisions shall include the following:

1. Develop and implement an administrative procedure that establishes the authority and responsibility of the person in charge of the control room to limit access.

2. Develop and implement procedures that establish a clear line of authority and responsibility in the control room in the event of an emergency. The line of succession for the person in charge of the control room shall be established and limited to persons possessing a current senior reactor operator's license. The plan shall clearly define the lines of communication and authority for plant management personnel not in direct command of operations, including those who report to stations outside the control room.

Response

The lines of responsibility and authority of the OS-SRO, or the individual assuming the control room command function (as previously promulgated in procedure VPN-PLP-01 and subsequently contained in the appropriate NBU administrative procedure(s)) permit limited access to the control room area. This authority is delineated in the appropriate NBU administrative procedure(s). This item is also discussed in the response to Item I.A.1.2. 1.10-22 HCGS-UFSAR Revision 9 June 13, 1998

I.C.5 Feedback of Operating Experience Position Each licensee will review its administrative procedures to assure that operating experience from within and outside the organization is continually provided to operators and other operational personnel and is incorporated in training programs.

Response

The appropriate NBU administrative procedure(s) provides the mechanism for the dissemination of information to station departments. Industry operating experiences, including events occurring within the organization, are reviewed for applicability to Hope Creek by the Licensing and Regulation Department. Pertinent information is communicated to the appropriate department for their information, and any actions required are tracked until they have been satisfactorily completed. In addition, information is communicated to the Training Manager for incorporating new material into the training programs. The activities of the Licensing and Regulation Department with respect to operating experiences (i.e., INPO's SEE-IN Program) are governed by NBU administrative procedures. Vendor technical documents describing the operation and maintenance of installed equipment and components associated with Hope Creek Generating Station shall be controlled in the following manner;

1. When vendor documents are received by disciplines within the NBU, these documents will be forwarded to Engineering for 1.10-23 HCGS-UFSAR Revision 14 July 26, 2005

review and approval for inclusion into the Vendor Document Control System.

2. Once approved by the cognizant engineer they will be assigned a unique number and distributed to all user departments, and incorporated in procedures and training as necessary.

Information on operating experience provided by the NRC through the I & E Bulletins/Information Notices, generic letters and letters on the docket are processed by the Nuclear Licensing and Regulation Department. These letters are distributed to various disciplines within the NBU for feedback of information. A response action form is utilized when a response or action is required and is monitored through the commitment tracking system to completion. In addition, the Nuclear Training Center Administrative Procedures delineates the process of review and tracking of industry and station information that may have training implications. I.C.6 Verify Correct Performance of Operating Activities Position It is required (from NUREG-0660) that licensees' procedures be reviewed and revised, as necessary, to assure that an effective system of verifying the correct performance of operating activities is provided as a means of reducing human errors and improving the quality of normal operations. This will reduce the frequency of occurrence of situations that could result in or contribute to accidents. Such a verification system may include automatic system status monitoring, human verification of operations, and maintenance activities independent of the people performing the activity (see NUREG-0585, Recommendation 5), or both. 1.10-24 HCGS-UFSAR Revision 8 September 25, 1996

Response

Verification of operating activities to provide a means of reducing human errors and to improve the quality of normal operations shall be assured by the following programs:

1. The appropriate NBU administrative procedure(s) shall:

(a) Describe a program to track a system's status, i.e., operability. (b) Determine if a system's change in status results in the entering or clearing of a limiting condition for operation. (c) Describe a program to ensure that technical specification required operability of redundant safety-related equipment is verified. When like equipment is removed from service, this program shall also ensure the appropriate retest of equipment following preventive or corrective maintenance and prior to the equipment's return to an operable status. (d) Describe the independent verification program; this procedure will describe the method and technique for performing the independent verification. Individuals performing the independent verification associated with mechanical and electrical lineups shall, as a minimum, meet the requirements of 1.10-25 HCGS-UFSAR Revision 8 September 25, 1996

Section 13.2.1.1 and INPO Accredited Training Programs. Equipment operators performing the verifications will be those operators assigned to the control room supervisor on duty. In some cases the independent verifications may be performed by a reactor operator/plant operator or shift technical advisor assigned to the on-duty shift.

2. The appropriate NBU administrative procedure(s) shall describe the method of valve sealing to prevent unauthorized operation of equipment. The valves that are required to be sealed shall be identified on design P&IDs. This information shall be incorporated into system valve lineups.

3. The appropriate NBU administrative procedure(s) shall contain the requirements for independent verification of safety-related system lineup and temporary modification for testing. In addition, this procedure will require, prior to start of testing, permission from designated operations personnel holding an SRO license.

4. The appropriate NBU administrative procedure(s) shall include reference to independent verification of installation and removal of Temporary Grounding Tags used on safety-related equipment.

5. The appropriate NBU administrative procedure(s) shall include requirements to obtain prior permission to work on plant equipment from designated operations personnel holding a SRO license.

1.10-26 HCGS-UFSAR Revision 9 June 13, 1998

6. The appropriate NBU administrative procedure(s) shall include independent verification requirements for installation of temporary modification on safety-related systems.

7. The appropriate NBU administrative procedure(s) shall establish the plant systems or subsystems requiring independent verification.

The above procedures shall contain identification of activities requiring independent verification, responsible person to perform the verification, and the method of documenting the performance verification for safety-related equipment. In addition, the appropriate NBU administrative procedure(s) shall specify periodic audit requirements of operational activities included, but not limited to, the above procedures. I.C.7 NSSS Vendor Review of Procedures Position Obtain Nuclear Steam Supply System vendor review of power ascension and emergency operating procedures to further verify their adequacy.

Response

All NSSS startup test procedures from core load through power ascension will be reviewed by the NSSS vendor, General Electric Co. All non-NSSS startup test procedures will be reviewed by the appropriate system designer. This review, as well as vendor or designer review of test results, will be documented prior to completion of the Power Ascension (Phase III) Testing Program. The HCGS Emergency Operating Procedures are being developed based on the NRC-approved BWR Owners' Group Emergency Procedure Guidelines (EPGs). Due to GE's involvement in the development of the EPGs, it 1.10-27 HCGS-UFSAR Revision 8 September 25, 1996

has been determined that an additional NSSS vendor review of the plant specific Emergency Instructions is not necessary. I.C.8 Pilot Monitoring of Selected Emergency Procedures for Near Term Operating License Applicants Position Correct emergency procedures as necessary based on the NRC audit of selected plant emergency operating procedures (e.g., small break loss-of-coolant accident, loss of feedwater, restart of engineered safety features following a loss of ac power and steam line break).

Response

A Procedure Generation Package (PGP) was prepared in accordance with Supplement 1 NUREG-0737. The PGP and plant specific Emergency Operating Procedures will be based on the NRC approved BWR Owners Group Emergency Procedure Guidelines (EPGs). As a result, it has been determined that an NRC review of the plant specific Emergency Operating Procedures is not necessary. I.D.1 Control Room Design Reviews Position Licensees and applications for operating licenses are required to conduct a detailed control room design review to identify and correct design deficiencies. This detailed control room design review is expected to take about a year. Those applicants for operating licenses who are unable to complete this review prior to issuance of a license shall make preliminary assessments of their control rooms to identify significant human factors and instrumentation problems and establish a schedule approved by us for correcting deficiencies. These applicants will be required to complete the more detailed control room reviews on the same schedule as licensees with operating plants. 1.10-28 HCGS-UFSAR Revision 0 April 11, 1988

Clarification Applicants for operating license who will be unable to complete the detailed control room review prior to issuance of a license are required to perform a preliminary control room design assessment to identify significant human factors problems. Applicants will find it of value to refer to the draft document, NUREG/CR-1580, "Human Engineering Guide to Control Room Evaluation," in performing the preliminary assessment. We will evaluate the applicant's preliminary assessments including the performance by us of onsite reviews/audits. Our onsite review/audit will be on a schedule consistent with applicant licensing needs and will emphasize the following aspects of the control room:

1. The adequacy of information presented to the operator to reflect plant status for normal operation, anticipated operational occurrences, and accident conditions.

2. The groupings of displays and the layout of panels.

3. Improvements in the safety monitoring and human factors enhancement of controls and control displays.

4. The communications from the control room to points outside the control room, such as the onsite technical support center, remote shutdown panel, offsite telephone lines, and to other areas within the plant for normal and emergency operation.

5. The use of direct rather than derived signals for the presentation of process and safety information to the operator.

6. The operability of the plant from the control room with multiple failures of nonsafety-grade and nonseismic systems.

7. The adequacy of operating procedures and operator training with respect to limitations of instrumentation displays in the control room.

1.10-29 HCGS-UFSAR Revision 0 April 11, 1988

8. The categorization of alarms, with unique definition of safety alarms.

9. The physical location of the shift supervisor's office either adjacent to or within the control room complex.

Prior to the onsite review/audit, we will require a copy of the applicant's preliminary assessment and additional information which will be used in formulating the details of the onsite review/audit.

Response

Essex Corporation has performed a detailed control room review to verify human factors considerations. The schedule and criteria for the review were based on NUREG-0700, and Supplement 1 to NUREG-0737. The control room design review summary report was submitted by a letter from R.L. Mittl, PSE&G, to A. Schwencer, NRC, dated August 14, 1984. See Section 18, Human Factors Engineering, for discussion. I.D.2 Plant Safety Parameter Display Console Position Each applicant and licensee shall install a Safety Parameter Display System (SPDS) that will display to operating personnel a minimum set of parameters which define the safety status of the plant. This can be attained through continuous indication of direct and derived variables as necessary to assess plant safety status.

Response

HCGS will install an SPDS in accordance with the requirements of Item I.D.2, as amended by Supplement 1 to NUREG-0737, and based on the guidelines detailed in SECY 82-111B. The displays are based on 1.10-30 HCGS-UFSAR Revision 0 April 11, 1988

the displays developed by the BWR Owners' Group. The safety parameter display system is part of the Control Room Integrated Display System (Item XV.d of Table 3.2-1). The SPDS is discussed in Section 7.5. I.G.1 Training During Low-Power Testing Position We require applicants for a new operating license to define and commit to a special low-power testing program approved by NRC to be conducted at power levels no greater than 5 percent for the purposes of providing meaningful technical information beyond that obtained in the normal startup test program and to provide supplemental training. Clarification Chapter 14 of the Final Safety Analysis Report describes the applicant's initial test program. The objectives of the initial test program include both training and the acquisition of technical data. This program has been determined by the staff to be acceptable as reported in Section 14 of this report. However, we require the applicant to perform additional testing and training beyond the requirements of the initial test program.

Response

Operators will participate in the low-power physics test program. Important activities and information from that program will be factored into the overall training program. Any additional testing for training required by the NRC or GE will be conducted in accordance with prepared procedures and the results reviewed with operating personnel. 1.10-31 HCGS-UFSAR Revision 4 April 11, 1992

II.B.1 Reactor Coolant System Vents Position Each applicant shall install Reactor Coolant System and reactor vessel head high point vents remotely operable from the control room. The applicant must submit a description of the design, location, size, and power supply for the vent system along with results of analyses for loss-of-coolant accidents initiated by a break in the vent pipe. The results of the analyses should demonstrate compliance with the acceptance criteria of 10CFR50.46. In addition, procedures and supporting analysis for operator use of the vents that include the information available to the operator for initiating or terminating vent usage should be submitted. Documentation to meet this item is required by July 1, 1981 and implementation is required by July 1, 1982. Detailed clarification of this requirement is provided in Section II.B.1 of NUREG-0737.

Response

All the requirements are fulfilled by the HPCI and/or RCIC turbine operations or by the safety grade automatic depressurization system (ADS), described in Sections 5.2.2, 6.3.2, and 7.3.1, together with the long term safety grade air supply, described in Section 9.3.1. The point of connection of the vent lines to the vessel is such that accumulation of gases above this elevation in the vessel will not inhibit natural circulation cooling of the reactor core. The ADS valves are 5 of the 14 safety/relief valves. In addition, a reactor pressure vessel (RPV) head vent, which is operable from the control room, could be used as a backup to the ADS valve venting capability. The analysis demonstrating that the direct venting of noncondensable gases with possible high hydrogen concentrations does not result in violation of combustible gas concentration limits in containment is discussed in Section 6.2.5. Procedures for the operation of systems used to preclude the accumulation of noncondensible gases are available for review. 1.10-32 HCGS-UFSAR Revision 0 April 11, 1988

The design of the Reactor Coolant System (RCS) and RPV vent system is in agreement with the generic capabilities proposed by the BWR Owners' Group (BWROG), with the exception of isolation condensers. The BWROG position is summarized in NEDO-24782. The HPCI, RCIC, ADS, and containment instrument gas systems are Q-listed; as shown in Items V.C, VI, XV.b.1, and LXVII.b of Table 3.2-1. The RPV head vent is Q-listed but not Class 1E (Item I.c of Table 3.2-1). II.B.2 Plant Shielding Position With the assumption of a post-accident release of radioactivity equivalent to that described in Regulatory Guide 1.3, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Boiling Water Reactors," and Regulatory Guide 1.4, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Pressurized Water Reactors" (i.e., the equivalent of 50 percent of the core radioiodine, 100 percent of the core noble gas inventory, and 1 percent of the core solids are contained in the primary coolant), each licensee shall perform a radiation and shielding-design review of the spaces around systems that may, as a result of an accident, contain highly radioactive materials. The design review should identify the location of vital areas and equipment, such as the control room, radwaste control stations, emergency power supplies, motor control centers, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment may be unduly degraded by the radiation fields during post accident operations of these systems. Each licensee shall provide for adequate access to vital areas of protection of safety equipment by design changes, increased permanent or temporary shielding, or post accident procedural controls. The design review shall determine which types of 1.10-33 HCGS-UFSAR Revision 17 June 23, 2009

corrective actions are needed for vital areas throughout the facility. Clarification The purpose of this item is to ensure that licensees examine their plants to determine what actions can be taken over the short term to reduce radiation levels and increase the capability of operators to control and mitigate the consequences of an accident. The actions should be taken pending conclusions resulting in the long term degraded core rulemaking, which may result in a need to consider additional sources. Any area which will or may require occupancy to permit an operator to aid in the mitigation of or recovery from an accident is designated as a vital area. For purposes of this evaluation, vital areas and equipment are not necessarily the same vital areas or equipment defined in 10CFR Part 73.2 for security purposes. The security center is listed as an area to be considered as potentially vital, since access to this area may be necessary to take action to give access to other areas in the plant. The control room, technical support center (TSC), sampling station, and sample analysis area must be included among those areas where access is considered vital after an accident. (Refer to Section III.A.1.2 of this report for discussion of the TSC and emergency operations facility.) The evaluation to determine the necessary vital areas should also include, but not be limited to, consideration of the post loss-of-coolant accident hydrogen control system, containment isolation reset control area, manual emergency core cooling system alignment area (if any), motor control centers, instrument panels, emergency power supplies, security center, and radwaste control panels. Dose rate determinations need not be done for these areas if they are determined not to be vital. 1.10-34 HCGS-UFSAR Revision 8 September 25, 1996

As a minimum, necessary modification must be sufficient to provide for vital system operation and for occupancy of the control room, TSC, sampling station, and sample analysis area. In order to assure that personnel can perform necessary post-accident operations in the vital areas, the following guidance is to be used by licensees to evaluate the adequacy of radiation protection to the operators:

1. Source Term The minimum radioactive source term should be equivalent to the source terms recommended in Regulatory Guides 1.3, 1.4, 1.7, "Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident," and Standard Review Plan 15.6.5 with appropriate decay times based on plant design (i.e., assuming the radioactive decay that occurs before fission products can be transported to various systems).

(a) Liquid Containing Systems: 100 percent of the core equilibrium noble gas inventory, 50 percent of the core equilibrium halogen inventory, and 1 percent of all others are assumed to be mixed in the reactor coolant and liquids recirculated by residual heat removal, high pressure coolant injection, and low pressure coolant injection, or the equivalent of these systems. In determining the source term for recirculated, depressurized cooling water, assuming that the water contains no noble gases. (b) Gas Containing Systems: 100 percent of the core equilibrium noble gas inventory and 25 percent of the core equilibrium halogen activity are assumed to be mixed in the containment atmosphere. For vapor containing lines connected to the primary system (e.g., boiling water reactor steam lines), the concentration of radioactivity shall be determined assuming the activity is contained in the vapor space in the Primary Coolant System. 1.10-35 HCGS-UFSAR Revision 0 April 11, 1988

2. Systems Containing the Source Systems assumed in your analysis to contain high levels of radioactivity in a post accident situation should include, but not be limited to, containment, residual heat removal system, safety injection systems, chemical and volume control system, containment spray recirculation system, sample lines, gaseous radwaste systems, and standby gas treatment systems (or equivalent of these systems). If any of these systems or others that could contain high levels of radioactivity were excluded, you should explain why such systems were excluded. Radiation from leakage of systems located outside of containment need not be considered for this analysis. Leakage measurement and reduction is treated under Section III.D.1.1, "Integrity of Systems Outside Containment Likely to Contain Radioactive Material for PWRs and BWRs." Liquid waste systems need not be included in this analysis. Modifications to liquid waste systems will be considered after completion of Section III.D.1.4, "Radwaste System Design Features To Aid in Accident Recovery and Decontamination."

3. Dose Rate Criteria The design dose rate for personnel in a vital area should be such that the guidelines of Criterion 19 of the General Design Criteria (GDC) will not be exceeded during the course of the accident. GDC 19 requires that adequate radiation protection be provided such that the dose to personnel should not be in excess of 5 rem whole body, or its equivalent to any part of the body for the duration of the accident. When determining the dose to an operator, care must be taken to determine the necessary occupancy times in a specific area. For example, areas requiring continuous occupancy will require much lower dose rates than areas where minimal occupancy is required. Therefore, allowable dose rates will be based upon expected occupancy, as well as the radioactive source terms and shielding. However, in order to provide a general design 1.10-36 HCGS-UFSAR Revision 17 June 23, 2009

objective, we are providing the following dose rate criteria with alternatives to be documented on a case by case basis. The recommended dose rates are average rates in the area. Local hot spots may exceed the dose rate guidelines. These doses are design objectives and are not to be used to limit access in the event of an accident. (a) Areas Requiring Continuous Occupancy: <15 mrem/hr (averaged over 30 days). These areas will require full-time occupancy during the course of the accident. The control room and onsite technical support center are areas where continuous occupancy will be required. The dose rate for these areas is based on the control room occupancy factors contained in Standard Review Plan 6.4. (b) Areas Requiring Infrequent Access: GDC 19. These areas may require access on an irregular basis, not continuous occupancy. Shielding should be provided to allow access at a frequency and duration estimated by the licensee. The plant radiochemical/chemical analysis laboratory, radwaste panel, motor control center, instrumentation locations, and reactor coolant and containment gas sample stations are examples of sites where occupancy may be needed often, but not continuously.

4. Radiation Qualification of Safety-Related Equipment The review of safety-related equipment which may be unduly degraded by radiation during post accident operation of this equipment relates to equipment inside and outside of the primary containment. Radiation source terms calculated to determine environmental qualification of safety-related equipment consider the following:

(a) Loss of coolant accident (LOCA) events which completely depressurize the primary system should consider releases of the source term (100 percent noble gases, 50 percent 1.10-37 HCGS-UFSAR Revision 17 June 23, 2009

iodines, and 1 percent particulates) to the containment atmosphere. (b) LOCA events in which the primary system may not depressurize should consider the source term (100 percent noble gases, 50 percent iodines, and 1 percent particulates) to remain in the primary coolant. This method is used to determine the qualification doses for equipment in close proximity to recirculating fluid systems inside and outside of containment. Non-LOCA events both inside and outside of containment should use 10 percent noble gases, 10 percent iodines, and 0 percent particulate as a source term. The following table summarizes these considerations: Non-LOCA High Energy Line LOCA Source Term Break Source Term (Noble Gas/Iodine/ (Noble Gas/Iodine/ Containment Particulate) Particulate) Outside Percent Percent (100/50/1) (10/10/0) in Reactor in Reactor Coolant System Coolant System Inside Larger of (10/10/0) (100/50/1) In Reactor in containment Coolant System or (100/50/1) in Reactor Coolant System 1.10-38 HCGS-UFSAR Revision 0 April 11, 1988

Response

In compliance with the requirements stated in NUREG-0737, a post-accident shielding design and access review for HCGS has been completed. For details of this review, see Section 12.3.2. The post-accident shielding is Q-listed (Item XIX.m of Table 3.2-1). II.B.3 Post-Accident Sampling Position A design and operational review of the reactor coolant and containment atmosphere sampling line systems shall be performed to determine the capability of personnel to promptly obtain (less than 1 hour) a sample under accident conditions without incurring a radiation exposure to any individual in excess of 3 and 18-3/4 rem to the whole body or extremities, respectively. Accident conditions should assume a Regulatory Guide 1.3, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Boiling Water Reactors," or 1.4 "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Pressurized Water Reactor" release of fission products. If the review indicates that personnel could not promptly and safely obtain samples, additional design features or shielding should be provided to meet the criteria. A design and operational review of the radiological spectrum analysis facilities shall be performed to determine the capability to promptly quantify (in less than 2 hours) certain radionuclides that are indicators of the degree of core damage. Such radionuclides are noble gases which indicate cladding failure and isotopes which indicate fuel melting. The initial reactor coolant spectrum should correspond to a Regulatory Guide 1.3 or 1.4 release. The review should also consider the effects of direct radiation from 1.10-39 HCGS-UFSAR Revision 0 April 11, 1988

piping and components in the auxiliary building and possible contamination and direct radiation from airborne effluents. If the review indicates that the analyses required cannot be performed in a prompt manner with existing equipment, then design modifications or equipment procurement shall be undertaken to meet the criteria. In addition to the radiological analyses, certain chemical analyses are necessary for monitoring reactor conditions. Procedures shall be provided to perform boron and chloride chemical analyses assuming a highly radioactive initial sample (Regulatory Guide 1.3 or 1.4 source term). Both analyses shall be capable of being completed promptly (i.e., the boron sample analysis within an hour and the chloride sample analysis within a shift). Clarification The following items are clarifications of requirements identified in NUREG-0578, NUREG-0660, or the September 13, 1979, October 30, 1979, September 5, 1980 and October 31, 1980 clarification letters.

1. The applicant shall have the capability to promptly obtain reactor coolant samples and containment atmosphere samples. The combined time allotted for sampling and analysis should be 3 hours or less from the time a decision is made to take a sample.

2. The applicant shall establish an onsite radiological and chemical analysis capability to provide, within the 3-hour time frame established above, quantification of the following.

(a) Certain radionuclides in the reactor coolant and containment atmosphere that may be indicators of the degree of core damage (e.g., noble gases, iodines and cesiums, and nonvolatile isotopes). (b) Hydrogen levels in the containment atmosphere. 1.10-40 HCGS-UFSAR Revision 0 April 11, 1988

(c) Dissolved gases (e.g., hydrogen), chloride (time allotted for analysis subject to discussion below), and boron concentration of liquids. (d) Alternatively, have inline monitoring capabilities to perform all or part of the above analyses.

3. Reactor coolant and containment atmosphere sampling during post-accident conditions shall not require an isolated auxiliary system (e.g., the letdown system, reactor water cleanup system) to be placed in operation in order to use the sampling system.

4. Pressurized reactor coolant samples are not required if the applicant can quantify the amount of dissolved gases with unpressurized reactor coolant samples. The measurement of either total dissolved gases or hydrogen gas in reactor coolant samples is considered adequate. Measuring the oxygen concentration is recommended, but is not mandatory.

5. The time for a chloride analysis to be performed is dependent upon two factors: 1) if the plant's coolant water is seawater or brackish water, and 2) if there is only a single barrier between primary containment systems and the cooling water. Under both of the above conditions, the applicant shall provide for a chloride analysis within 24 hours of the sample being taken. For all other cases, the applicant shall provide for the analysis to be completed within 4 days. The chloride analysis does not have to be done onsite.

6. The design basis for plant equipment for reactor coolant and containment atmosphere sampling and analysis must assume that it is possible to obtain and analyze a sample without radiation exposures to any individual exceeding GDC 19 (i.e., 5 rem whole body, 75 rem extremities).

1.10-41 HCGS-UFSAR Revision 0 April 11, 1988

7. If inline monitoring is used for any sampling and analytical capability specified herein, the applicant shall provide backup sampling through grab samples, and shall demonstrate the capability of analyzing the samples. Established planning for analysis at offsite facilities is acceptable. Equipment provided for backup sampling shall be capable of providing at least one sample per day for 7 days following onset of the accident and at least one sample per week until the accident condition no longer exists.

8. The applicant's radiological and chemical sample analysis capability shall include provisions to:

(a) Identify and quantify the isotopes of the nuclide categories discussed above to levels corresponding to the source terms given in Regulatory Guides 1.3 or 1.4 and 1.7, "Control of Combustible Gas Concentration in Containment Following a Loss-of-Coolant Accident." Where necessary and practicable, the ability to dilute samples to provide capability for measurement and reduction of personnel exposure should be provided. Sensitivity of onsite liquid sample analysis capability should be such as to permit measurement of nuclide concentration in the range from approximately 1 µCi/g to 10 Ci/g. (b) Restrict background levels of radiation in the radiological and chemical analysis facility from sources such that the sample analysis will provide results with an acceptably small error (approximately a factor of 2). This can be accomplished through the use of sufficient shielding around samples and outside sources, and by the use of ventilation system design which will control the presence of airborne radioactivity.

9. Accuracy, range, and sensitivity shall be adequate to provide pertinent data to the operator in order to describe 1.10-42 HCGS-UFSAR Revision 0 April 11, 1988

radiological and chemical status of the reactor coolant systems.

10. In the design of the post-accident sampling and analysis capability, consideration should be given to the following items:

(a) Provisions for purging sample lines, for reducing plateout in sample lines, for minimizing sample loss or distortion, for preventing blockage of sample lines by loose material in the reactor coolant system or containment, for appropriate disposal of the samples, and for flow restrictions to limit reactor coolant loss from a rupture of the sample line. The post-accident reactor coolant and containment atmosphere samples should be representative of the reactor coolant in the core area and the containment atmosphere following a transient or accident. The sample lines should be as short as possible to minimize the volume of fluid to be taken from containment. The residues of sample collection should be returned to containment or to a closed system. (b) The ventilation exhaust from the sampling station should be filtered with charcoal adsorbers and high efficiency particulate air filters.

11. If gas chromatography is used for reactor coolant analysis, special provisions (e.g., pressure relief and purging) shall be provided to prevent high pressure argon from entering the reactor coolant.

12. Applicants should provide a description of the implementation of the position and clarification including pipe and instrumentation drawings, together with either 1) a summary description of procedures for sample collection, sample transfer or transport, and sample analysis, or

2) copies of procedures for sample collection, sample transfer or transport, 1.10-43 HCGS-UFSAR Revision 0 April 11, 1988

and sample analysis, in accordance with the proposed review schedule but in no case less than 4 months prior to the issuance of an operating license. A post-implementation review will be performed.

Response

Provisions for post-accident sampling of reactor coolant and containment atmosphere are described in Section 9.3.2. The Post Accident Sampling System (PASS) is not Q-listed with the exception of the primary containment isolation and reactor coolant pressure boundary piping and valves (Item XVII.h of Table 3.2-1). The HCGS design incorporates a radioactive gas and liquid sampling system designed by General Electric. Additionally, the radiological spectrum and chemical analysis capabilities will be reviewed prior to 5 percent power operation by an NRC site inspection to ensure that the appropriate analyses can be performed within the times specified in NUREG-0737. Shielding requirements and source terms used are consistent with those used for the Design Review of Plant Shielding, discussed under Item II.B.2. The review to assure compliance of the radioactive gas and liquid sampling system for shielding and source term requirements has been completed and is described in Section 9.3.2. II.B.4 Training for Mitigating Core Damage Position We require that the applicant develop a program to ensure that all operating personnel are trained in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged. They must then implement the training program. 1.10-44 HCGS-UFSAR Revision 8 September 25, 1996

Clarification STA and operating personnel from the Plant Manager through the operations chain to the licensed operators shall receive this training. The training program shall include the following topics:

1. Incore Instrumentation (a) Use of fixed or movable in-core detectors to determine extent of core damage and geometry changes.

(b) Use of thermocouples in determining peak temperatures; methods for extended range readings; methods for direct readings at terminal junctions.

2. Excore Nuclear Instrumentation (a) Use of excore nuclear instrumentation for determination of void formation; void location basis for excore nuclear instrumentation response as a function of core temperatures and density changes.

3. Vital Instrumentation (a) Instrumentation response in an accident environment; failure sequence (time to failure, method of failure); indication reliability (actual versus indicated level).

(b) Alternative methods for measuring flows, pressures, levels, and temperatures. (1) Determination of pressurizer level if all level transmitters fail. (2) Determination of letdown flow with a clogged filter (low flow). 1.10-45 HCGS-UFSAR Revision 13 November 14, 2003

(3) Determination of other Reactor Coolant System parameters if the primary method of measurement has failed.

4. Primary Chemistry (a) Expected chemistry results with severe core damage; consequences of transferring small quantities of liquid outside containment; importance of using leaktight systems.

(b) Expected isotopic breakdown for core damage; for clad damage. (c) Corrosion effects of extended immersion in primary water; time to failure.

5. Radiation Monitoring (a) Response of process and area monitors to severe damage; behavior of detectors when saturated; method for detecting radiation readings by direct measurement at detector output (overranged detector);

expected accuracy of detectors at different locations; use of detectors to determine extent of core damage. (b) Methods of determining dose rate inside containment from measurements taken outside containment.

6. Gas Generation (a) Methods of hydrogen generation during an accident; other sources of gas (Xe, Kr); techniques for venting or disposal of noncondensibles.

(b) Hydrogen flammability and explosive limit; sources of oxygen in containment or Reactor Coolant System. 1.10-46 HCGS-UFSAR Revision 0 April 11, 1988

Managers and technicians in the instrumentation and control, health physics, and chemistry departments shall receive training commensurate with their responsibilities.

Response

A program for training of all plant operations staff in mitigating core damage has been implemented. II.D.1 Relief and Safety Valve Test Requirements Position Pressurized water reactor and boiling water reactor licensees and applicants shall conduct testing to qualify the Reactor Coolant System relief and safety valves under expected operating conditions for design basis transients and accidents. Clarification Licensees and applicants shall determine the expected valve operating conditions through the use of analyses of accidents and anticipated operational occurrences referenced in Regulatory Guide 1.70, Revision 2. The single failures applied to these analyses shall be chosen so that the dynamic forces on the safety and relief valves are maximized. Test pressures shall be the highest predicted by conventional safety analysis procedures. Reactor coolant system relief and safety valve qualification shall include qualification of associated control circuitry, piping, and supports, as well as the valves themselves.

1. Performance Testing of Relief and Safety Valves - The following information must be provided in report form:

1.10-47 HCGS-UFSAR Revision 4 April 11, 1992

(a) Evidence supported by test of safety and relief valve functionality for expected operating and accident (non-ATWS) conditions must be provided to NRC. The testing should demonstrate that the valves will open and reclose under the expected flow conditions. (b) Since it is not planned to test all valves on all plants, each licensee must submit to NRC a correlation or other evidence to substantiate that the valves tested in the EPRI (Electric Power Research Institute) or other generic test program demonstrate the functionality of as-installed primary relief and safety valves. This correlation must show that the test conditions used are equivalent to expected operating and accident conditions as prescribed in the FSAR. The effect of as-built relief and safety valve discharge piping on valve operability must be accounted for, if it is different from the generic test loop piping. (c) Test data including criteria for success and failure of valves tested must be provided for NRC staff review and evaluation. These test data should include data that would permit plant-specific evaluation of discharge piping and supports that are not directly tested.

2. Qualification of PWR Block Valves-Although not specifically listed as a short term lessons learned requirement in NUREG-0578, qualification of PWR block valves is required by the NRC Task Action Plan NUREG-0660 under task Item II.D.1. It is the understanding of the NRC that testing of several commonly used block valve designs is already included in the generic EPRI PWR safety and relief valve testing program to be completed by July 1, 1981. By means of this letter, NRC is establishing July 1, 1982 as the date for verification of block valve functionality. By July 1, 1982, each PWR licensee, for plants so equipped, should provide evidence supported by test that the block or isolation valves between the pressurizer and 1.10-48 HCGS-UFSAR Revision 17 June 23, 2009

each power operated relief valve can be operated, closed, and opened for all fluid conditions expected under operating and accident conditions.

3. ATWS Testing-Although ATWS testing need not be completed by July 1, 1981, the test facility should be designed to accommodate ATWS conditions of approximately 3200 to 3500 pounds per square inch (Service Level C pressure limit) and 700 degrees Fahrenheit with sufficient capacity to enable testing of relief and safety valves of the size and type used on operating pressurized water reactors.

Response

PSE&G is participating in the BWROG program to test safety/relief valves. Wyle Laboratories in Huntsville, Alabama, was contracted to design and build a test facility. The facility is capable of high and low pressure valve tests. Documentation of the BWROG testing program was sent to the NRC on September 17, 1980, by a letter from D.B. Waters to R.N. Vollmer. A summary of this document is provided below. An engineering evaluation was made to identify the expected operating conditions for safety/relief valves (SRVs) during design basis transients and accidents. This evaluation indicates the safety/relief valves may be required to pass low pressure liquid as a result of the alternate shutdown cooling mode described in Section 15.2.9. No other significantly probable event even combined with a single active failure or single operator error that would require SRV testing was identified in this report. Therefore, a test program was developed to demonstrate the SRV capabilities as may be necessary during the alternate shutdown mode. The generic test program has been completed and the results were documented to the NRC in October, 1981. The results showed that for all the SRVs tested, the valves operated properly for the test 1.10-49 HCGS-UFSAR Revision 0 April 11, 1988

conditions. Also the loads for the water discharge were significantly less than the design basis steam loads. The NRC has accepted the generic SRV test program and has requested that individual applicants justify the applicability of the test data to their plants. An analysis of the applicability of the testing program for HCGS valves was submitted to the NRC on October 25, 1983 by a letter from R.L. Mittl to A. Schwencer. II.D.3 Relief and Safety Valve Position Indication Position Reactor Coolant System relief and safety valves shall be provided with a positive indication in the control room derived from a reliable valve position detection device or a reliable indication of flow in the discharge pipe. Clarification

1. The basic requirement is to provide the operator with unambiguous indications of valve position (open or closed) so that appropriate operator actions can be taken.

2. The valve position should be indicated in the control room. An alarm should be provided in conjunction with this indication.

3. The valve position indication may be safety grade. If the position indication is not safety grade, a reliable single channel direct indication, powered from a vital instrument bus, may be provided if backup methods of determining valve position are available and are discussed in the emergency procedures as an aid to operator diagnosis of an action.

4. The valve position indication should be seismically qualified consistent with the component or system to which it is attached.

1.10-50 HCGS-UFSAR Revision 0 April 11, 1988

5. The position indication should be qualified for its appropriate environment (any transient or accident which would cause the relief or safety valve to lift) and in accordance with Commission Order of May 23, 1980 (CLI-80-21).

6. It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human factor analysis should be performed taking into consideration:

(a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms during emergency and need for prioritization of alarms.

Response

The HCGS design includes an Acoustic Monitoring System that meets the requirements of NUREG-0737 and Regulatory Guide 1.97, Revision 2. See Section 7.5.1.3.6 for a description of the Safety/ Relief Valve Position Indication System. The SRV position indication system is not Q-listed (Item XV.d.5 of Table 3.2-1). II.E.1.1 Auxiliary Feedwater System Evaluation

Response

These requirements are not applicable to BWRs. 1.10-51 HCGS-UFSAR Revision 0 April 11, 1988

II.E 1.2 Auxiliary Feedwater System Initiation and Flow

Response

This requirement is not applicable to BWRs. II.E.3.1 Emergency Power for Pressurizer Heaters

Response

This not requirement is applicable to BWRs. II.E.4.1 Dedicated Hydrogen Control Penetrations Position Plants using external recombiners or purge systems for post accident combustible gas control of the containment atmosphere should provide containment penetration systems for external recombiner or purge systems that are dedicated to that service only, that meet the redundancy and single failure requirements of GDC 54 and 56 and that are sized to satisfy the flow requirements of the recombiner or purge system. The procedures for the use of combustible gas control systems following an accident that results in a degraded core and release of radioactivity to the containment must be reviewed and revised, if necessary. Clarification

1. An acceptable alternative to the dedicated penetration is a combined design that is single failure proof for containment isolation purposes and single failure proof for operation of the recombiner or purge system.

1.10-52 HCGS-UFSAR Revision 17 June 23, 2009

2. The dedicated penetration or the combined single failure proof alternative shall be sized such that the flow requirements for the use of the recombiner or purge system are satisfied. The design shall be based on 10CFR50.44 requirements.

3. Components furnished to satisfy this requirement shall be safety grade.

4. Licensees that rely on purge systems as the primary means for controlling combustible gases following a loss-of-coolant accident should be aware of the positions taken in SECY-80-399, "Proposed Interim Amendments to 10CFR Part 50 Related to Hydrogen Control and Certain Degraded Core Considerations." This proposed rule, published in the Federal Register on October 2, 1980, would require plants that do not now have recombiners to have the capacity to install external recombiners by January 1, 1982.

(Installed internal recombiners are an acceptable alternative to the above.)

5. Containment Atmosphere Dilution (CAD) Systems are considered to be purge systems for the purpose of implementing the requirements of this TMI Task Action item.

Response

The safety-related containment hydrogen recombiner system, described in Section 6.2.5, is used for beyond design basis accident combustible gas control. The containment penetrations associated with the hydrogen recombiner system are a combined design as described in clarification 1 above. This design is single failure proof for containment isolation purposes during system operation and single failure proof for operation of the recombiner or purge system. The piping is sized such that the flow requirements for the use of the recombiner are satisfied for the full range of possible containment pressures during the time period when the recombiner might be required to operate. 1.10-53 HCGS-UFSAR Revision 15 October 27, 2006

HCGS is provided with permanently installed recombiners that are remotely operated from the control room. Personnel access to this equipment after an accident is therefore not required. The shielding requirements associated with recombiner have been evaluated as art of the Design Review for Plant Shielding, which is discussed under Item II.B.2. The dedicated hydrogen control penetrations are Q-listed (Item V.d.5.g and h of Table 3.2-1). II.E.4.2 Containment Isolation Dependability Position

1. Containment isolation system designs shall comply with the recommendations of Standard Review Plan Section 6.2.4 (i.e., that there be diversity in the parameters sensed for the initiation of containment isolation).

2. All plant personnel shall give careful consideration of the definition of essential and nonessential systems, identify each system determined to be essential, identify each system determined to be nonessential, describe the basis for selection of each essential system, modify their containment isolation designs accordingly, and report the results of the reevaluation to the NRC.

3. All non-essential systems shall be automatically isolated by the containment isolation signal.

4. The design of control systems for automatic containment isolation valves shall be such that resetting the isolation signal will not result in the automatic reopening of containment isolation valves. Reopening of containment isolation valves shall require deliberate operator action.

1.10-54 HCGS-UFSAR Revision 15 October 27, 2006

5. The containment setpoint pressure that initiates containment isolation for nonessential penetrations must be reduced to the minimum compatible with normal operating conditions.

6. Containment purge valves that do not satisfy the operability criteria set forth in Branch Technical Position CSB 6-4 or the Staff Interim Position of October 23, 1979 must be sealed closed as defined in SRP 6.2.4, Item II.3.f during operational conditions 1, 2, 3, and 4. Furthermore, these valves must be verified to be closed at least every 31 days.

7. Containment purge and vent isolation valves must close on a high radiation signal.

Clarification

1. The reference to SRP 6.2.4 in position 1 is only to the diversity requirements set forth in that document.

2. For post accident situations, each nonessential penetration (except instrument lines) is required to have two isolation barriers in series that meet requirements of General Design Criteria 54, 55, 56, and 57, as clarified by Standard Review Plan, Section 6.2.4. Isolation must be performed automatically (i.e., no credit can be given for operator action). Manual valves must be sealed closed, as defined by Standard Review Plan, Section 6.2.4 to qualify as an isolation barrier. Each automatic isolation valve in a nonessential penetration must receive the diverse isolation signals.

3. Revision 2 to Regulatory Guide 1.141 will contain guidance on the classification of essential versus nonessential systems and is due to be issued by June 1981. Requirements for operating plants to review their list of essential and nonessential systems will be issued in conjunction with this guide including an appropriate time schedule for completion.

1.10-55 HCGS-UFSAR Revision 17 June 23, 2009

4. Administrative provisions to close all isolation valves manually before resetting the isolation signals is not an acceptable method of meeting position 4.

5. Ganged reopening of containment isolation valves is not acceptable.

Reopening of isolation valves must be performed on a valve by valve basis, or on a line by line basis, provided that electrical independence and other single failure criteria continue to be satisfied.

6. The containment pressure history during normal operation should be used as a basis for arriving at an appropriate minimum pressure setpoint for initiating containment isolation. The pressure setpoint selected should be far enough above the maximum observed (or expected) pressure inside containment during normal operation so that inadvertent containment isolation does not occur during normal operation from instrument drift or fluctuations due to the accuracy of the pressure sensor. A margin of 1 psi above the maximum expected containment pressure should be adequate to account for instrument error. Any proposed values greater than 1 psi will require detailed justification. Applicants for an operating license and operating plant licensees that have operated less than one year should use pressure history data from similar plants that have operated more than one year, if possible, to arrive at a minimum containment setpoint pressure.

7. Sealed closed purge isolation valves shall be under administrative control to assure that they cannot be inadvertently opened.

Administrative control includes mechanical devices to seal or lock the valve closed, or to prevent power from being supplied to the valve operator. Checking the valve position light in the control room is an adequate method for verifying every 24 hours that the purge valves are closed. 1.10-56 HCGS-UFSAR Revision 0 April 11, 1988

Response

Essential systems are those critical to the mitigation of the consequences of a LOCA. Also identified as essential are those systems that could be useful, although not critical, in mitigating an accident that results in containment isolation. Essential systems are not automatically isolated by accident signals, except for the containment heat removal and containment hydrogen control systems that are not required immediately for accident mitigation. Containment isolation valves are Q-listed (See Table 3.2-1 under applicable system). Nonessential systems are those that are not required or used in the mitigation of an accident that results in containment isolation. All nonessential systems are automatically isolated by the containment isolation signal, with the exception of the systems discussed below:

1. Reactor Water Cleanup (RWCU) System Return - Automatic isolation of Valve AE-V021 (AE-HV-F039) is not provided because there are two check valves on either side of the containment boundary providing primary containment isolation for the feedwater system. These valves will provide immediate isolation without actuation of the motor operated valve by an isolation signal. Valve AE-V021 is a motor operated check valve that closes on backflow and is capable of being manually closed from the main control room.

2. Bypass Lines Around the Testable Check Valves on the RHR and Core Spray System - Although the check valves perform containment isolation functions, they are not containment isolation valves in accordance with the "other defined basis" provisions of 10CFR50, Appendix J. The valves in the 1-inch bypass lines are not automatically isolated because they are normally closed, fail-closed valves that are only operated to equalize pressures to permit the testing of the check valves. The valves are opened by an operator holding a momentary pushbutton switch in the open position. Release of the switch by the operator will return the valves to the closed position.

1.10-57 HCGS-UFSAR Revision 8 September 25, 1996

3. Warmup Lines Around the Inboard HPCI and RCIC Steam Line Isolation Valves

     - Automatic isolation of these valves is not provided because they are in the essential systems and are not required to perform a containment isolation function when the RCIC and HPCI systems are in operation.

4. Post-Accident Sampling System - Automatic isolation of the post-accident sampling lines is not provided because the penetrations are designed to be a sealed closed system. Administrative procedures prevent the containment isolation valves from being inadvertently opened by ensuring that power is not supplied to the valves until the system is required to operate.

Reopening of primary containment isolation valves requires deliberate operator action on a valve by valve basis. Valves with manual override capabilities are identified in Table 6.2-16. Essential and nonessential systems are identified in Table 6.2-16. Diverse parameters are sensed for the initiation of automatic isolation of nonessential systems penetrating primary containment. See Section 6.2.4 for a discussion of containment isolation signal sensed parameter diversity. As required for post-accident situations, each nonessential penetration, except instrument lines, has two isolation barriers in series that meet the requirements of GDC 54, 55, 56, or 57, as clarified by SRP Section 6.2.4. Isolation is automatic with no credit taken for operator action. All manual valves are sealed closed so as to qualify as an isolation barrier. Each automatic isolation valve in a nonessential penetration receives independent isolation signals, derived from diverse parameters. The design of the controls for automatic containment isolation are such that the resetting of the isolation signals will not result in the automatic reopening of containment isolation valves. Reopening 1.10-58 HCGS-UFSAR Revision 1 April 11, 1989

of containment isolation valves will require deliberate operator action on a valve by valve basis. Ganged reopening of containment isolation valves is not used. An exception to this response is the HPCI Torus Suction Isolation Valve, 1BJHV-FO42. This valve will automatically reopen upon the resetting of a HPCI System Isolation signal if an automatic open signal is present. This configuration is discussed in UFSAR Section 6.2.4.3.2.9. The primary containment isolation logic setpoint pressure is 1.68 psig. This pressure is far enough above the maximum expected pressure inside containment during normal operation that inadvertent containment isolation does not occur during normal operation from instrument drift fluctuations due to the accuracy of the pressure sensor. The 6-, 24-, and 26-inch containment purge and vent butterfly valves are under administrative control. As discussed in Section 6.2.5.2, the 24- and 26-inch inboard vent valves (1-GS-HV-4952 and -4964), in conjunction with the 2-inch air operated globe valves (1-GS-HV-4951 and -4963), are opened to vent as required for thermal expansion and oxygen control. The purge supply and exhaust valves may be opened at other times as permitted by Technical Specifications. II.F.1 Accident Monitoring Instrumentation , Noble Gas Effluent Monitor Position Noble gas effluent monitors shall be installed with an extended range designed to function during accident conditions as well as during normal operating conditions. Multiple monitors are considered necessary to cover the ranges of interest. 1.10-59 HCGS-UFSAR Revision 7 December 29, 1995

5

1. Noble gas effluent monitors with an upper range capacity of 10 µ/Ci/cc (Xe-133) are considered to be practical and should be installed in all operating plants.

2. Noble gas effluent monitoring shall be provided for the total range of concentration extending from normal condition (as low as reasonably 5

achievable (ALARA)) concentrations to a maximum of 10 µ/Ci/cc (Xe-133). Multiple monitors are considered to be necessary to cover the ranges of interest. The range capacity of individual monitors should overlap by a factor of 10. It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human factor analysis should be performed taking into consideration:

1. The use of this information by an operator during both normal and abnormal plant conditions;

2. Integration into emergency procedures;

3. Integration into operator training; and

4. Other alarms during emergency and need for prioritization of alarms.

Clarification NUREG-0578, Section 2.1.8b provided the basic requirements for this item. Letters dated September 27 and November 9, 1979, provided clarification and NUREG-0660, Item II.F.1 provided the action plan for additional accident monitoring instrumentation by noble gas effluent radiological monitor requirements. Additional clarification was provided by letters dated September 5 and October 31, 1980. 1.10-60 HCGS-UFSAR Revision 0 April 11, 1988

By summary clarification, the following guidelines were established:

1. Applicants shall provide continuous monitoring of high-level post accident releases of radioactive noble gases from the plant. Gaseous effluent monitors shall meet requirements specified in the enclosed Table II.F.1-1. Typical plant effluent pathways to be monitored are also given in the table.

2. The monitors shall be capable of functioning both during and following an accident. System designs shall accommodate a design basis release and then be capable of following decreasing concentrations of noble gases.

3. Offline monitors are not required for the pressurized water reactor secondary side main steam safety valve and dump valve discharge lines.

For this application, externally mounted monitors viewing the main steam line upstream of the valves are acceptable with procedures to correct for the low energy gammas the external monitors would not detect. Isotopic identification is not required.

4. Instrumentation ranges shall overlap to cover the entire range of effluents from normal (ALARA) through accident conditions.

The design description shall include the following information: (a) System description, including: (1) instrumentation to be used, including range or sensitivity, energy dependence or response, calibration frequency and technique, and vendor's model number, if applicable. (2) monitoring locations (or points of sampling), including description of methods used to assure representative measurements and background correction. 1.10-61 HCGS-UFSAR Revision 17 June 23, 2009

(3) location of instrument readout(s) and method of recording, including description of the method or procedure for transmitting or disseminating the information or data. (4) assurance of the capability to obtain readings at least every 15 minutes during and following an accident. (5) the source of power to be used. (b) Description of procedures or calculational methods to be used for converting instrument readings to release rates per unit time, based on exhaust air flow and considering radionuclide spectrum distribution as a function of time after shutdown. (5.) Applicants should have available for review the final design description of the as-built system, including piping and instrument diagrams together with either 1) a description of procedures for system operation and calibration, or 2) copies of procedures for system operation and calibration. Changes to technical specifications will be required. Applicants will submit the above details in accordance with the proposed review schedule, but in no case less than 4 months prior to the issuance of an operating license. A post implementation review will be performed. Until final implementation on January 1, 1982, all operating reactors must provide an interim method for quantifying high level releases which meet the requirements of the enclosed Table II.F.1-2. This method is to serve only as a provisional fix until the accident monitoring instrumentation is installed, calibrated, tested and approved by January 1, 1982. Methods are to be developed to quantify release rates up to 10,000 Ci/sec for noble gases from all 1.10-62 HCGS-UFSAR Revision 17 June 23, 2009

potential release points and any other areas that communicate directly with systems which may contain primary coolant or containment gases. Measurements/analysis capabilities of the effluents at the final release point (e.g., stack) should be such that measurements of individual sources which contribute to the common release point may not be necessary. For noble gases, an acceptable method of meeting the intent of this requirement is to modify the existing monitoring system, such that portable high range survey instruments set in shielded collimators "see" small sections of the sampling lines. The applicant shall provide the following information on its method to quantify gaseous releases of radioactivity from the plant during an accident. (a) An interim system/method description for noble gas effluents, including: (1) instrumentation to be used including range or sensitivity, energy dependence, and calibration frequency and technique. (2) monitoring/sampling locations, including methods to assure representative measurements and background radiation correction. (3) a description of method to be employed to facilitate access to radiation readings. For January 1, 1981, control room readout is preferred; however, if impractical, in situ readings by an individual with verbal communication with the control room is acceptable based on 4., below. (4) capability to obtain radiation readings at least every 15 minutes during an accident. 1.10-63 HCGS-UFSAR Revision 0 April 11, 1988

(5) source of power to be used. If normal alternating current power is used, an alternate backup power supply should be provided. If direct current power is used, the source should be capable of providing continuous readout for 7 consecutive days. (b) Procedures for conducting all aspects of the measurement/analysis, including: (1) procedures for minimizing occupational exposures. (2) calculational methods for converting instrument readings to release rates based on exhaust air flow and taking into consideration radionuclide spectrum distribution as function of time after shutdown. (3) procedures for dissemination of information. (4) procedures for calibration. TABLE II.F.1-1 HIGH-RANGE NOBLE GAS EFFLUENT MONITORS REQUIREMENT - Capability to detect and measure concentrations of noble fission products in plant gaseous effluents during and following an accident. All potential accident release paths shall be monitored. PURPOSE - To provide the plant operator and emergency planning agencies with information on plant releases of noble gases during and following an accident. 1.10-64 HCGS-UFSAR Revision 0 April 11, 1988

TABLE II.F.1-1 (Cont) DESIGN BASIS MAXIMUM RANGE Design range values may be expressed in Xe-133 equivalent values for monitors employing gamma radiation detectors or in microcuries per cubic centimeter (µCi/cc) of air at standard temperature and pressure (STP) for monitors employing beta radiation detector (Note: 1R/hr @ 1 ft = 6.7 Ci Xe-133 equivalent for point source). Calibrations with a higher energy source are acceptable. The decay of radionuclide noble gases after an accident (i.e., the distribution of noble gas changes) should be taken into account. 5 10 µCi/cc - Undiluted containment exhaust gases (e.g., pressurized water reactor, reactor building purge, boiling water reactor drywell purge through the standby gas treatment system).

              -    Undiluted pressurized water reactor condenser air removal system exhaust.

4 10 µCi/cc - Boiling water reactor, Reactor Building (secondary containment) exhaust air.

              -    Pressurized water reactor secondary containment exhaust air.

3 10 µCi/cc - Buildings with systems containing primary coolant or primary coolant off-gases (e.g., pressurized water reactor Auxiliary Buildings, boiling water reactor Turbine Buildings).

              -    Pressurized  water   reactor steam   safety  valve  discharge, atmospheric steam dump valve discharge.

1.10-65 HCGS-UFSAR Revision 8 September 25, 1996

TABLE II.F.1-1 (Cont) 2 10 µCi/cc - Other release points (e.g., Radwaste Buildings, fuel handling/storage buildings). REDUNDANCY - Not required; monitoring the final release point of several discharge inputs is acceptable. SPECIFICATIONS - (None) Sampling design criteria per ANSI N13.1. POWER SUPPLY - Vital instrument bus or dependable backup power supply to normal alternating current. CALIBRATION - Calibrate monitors using gamma detectors to Xe-133 equivalent (1R/hr @ 1 ft = 6.7 Ci Xe-133 equivalent for point source). Calibrate monitors using beta detectors to Sr-90 or similar long-lived beta isotope of at least 0.2 MeV. DISPLAY - Continuous and recording as equivalent Xe-133 concentrations or µCi/cc of actual noble gases. QUALIFICATION - The instruments shall provide sufficiently accurate responses to perform the intended function in the environment to which they will be exposed during accidents. DESIGN - Offline monitoring is acceptable for all ranges CONSIDERATIONS of noble gas concentrations. 2

              - Inline (induct) sensors are acceptable for 10 µCi/cc to 5                                                    2 10 µCi/cc    noble    gases.      For   less   than  10 µCi/cc, offline monitoring is recommended.

1.10-66 HCGS-UFSAR Revision 0 April 11, 1988

TABLE II.F.1-1 (Cont)

                 -     Upstream filtration (prefiltering to remove radioactive iodines and particulates) is not required; however, design should consider all alternatives with respect to capability to monitor effluents following an accident.
                 -     For external mounted monitors (e.g., pressurized water reactor main steam line), the thickness of the pipe should be taken into account in accounting for low energy gamma radiation.

Applicants are to implement procedures for estimating noble gas and radioiodine release rates if the existing effluent instrumentation goes off scale. Examples of major elements of a highly radioactive effluent release special procedure (noble gas). - Preselected location to measure radiation from the exhaust air, e.g., exhaust duct or sample line. - Provide shielding to minimize background interference. - Use of an installed monitor (preferable) or dedicated portable monitoring (acceptable) to measure the radiation. - Predetermined calculational method to convert the radiation level to radioactive effluent release rate. 1.10-67 HCGS-UFSAR Revision 0 April 11, 1988

Response

All Reactor Building vent noble gas effluent monitors, described in Section 11.5, meet the requirements of Revision 2 of Regulatory Guide 1.97. ATTACHMENT 2, Sampling and Analysis of Plant Effluents Position The requirements associated with this recommendation should be considered as advanced implementation of certain requirements to be included in a revision to Regulatory Guide 1.97, "Instrumentation to Follow the Course of an Accident," which has already been initiated, and in other Regulatory Guides, which will be promulgated in the near term. Because iodine gaseous effluent monitors for the accident condition are not considered to be practical at this time, capability for effluent monitoring of radioiodines for the accident condition shall be provided with sampling conducted by adsorption on charcoal or other media, followed by onsite laboratory analysis. It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human-factor analysis should be performed taking into consideration:

1. The use of this information by an operator during both normal and abnormal plant conditions.

2. Integration into emergency procedures.

3. Integration into operator training.

4. Other alarms during emergency and need for prioritization of alarms.

1.10-68 HCGS-UFSAR Revision 0 April 11, 1988

Clarification NUREG-0578, Section 3.1.8b provided the basic requirements for this item. Letters dated September 27 and November 9, 1979, provided clarification, however, NUREG-0660 inadvertently omitted this requirement on the action plan for additional accident-monitoring instrumentation by sampling and analysis of plant effluents. Additional clarification was provided by letters dated September 5 and October 31, 1980. By summary clarification, the following guidelines were established:

1. Applicants shall provide continuous sampling of plant gaseous effluent for post accident releases of radioactive iodines and particulates to meet the requirements of the enclosed Table II.F.1-3. Applicants shall also provide onsite laboratory capabilities to analyze or measure these samples. This requirement should not be construed to prohibit design and development of radioiodine and particulate monitors to provide online sampling and analysis for the accident condition. If gross gamma radiation measurement techniques are used, then provisions shall be made to minimize noble gas interference.

2. The shielding design basis is given in Table II.F.1-3. The sampling system design shall be such that plant personnel could remove samples, replace sampling media and transport the samples to the onsite analysis facility with radiation exposures that are not in excess of the GDC 19 of 5 rem whole body exposure and 75 rem to the extremities during the duration of the accident.

3. The design of the systems for the sampling of particulates and iodines should provide for sample nozzle entry velocities which are approximately isokinetic (same velocity) with expected induct or instack air velocities. For accident conditions, 1.10-69 HCGS-UFSAR Revision 17 June 23, 2009

sampling may be complicated by a reduction in stack or vent effluent velocities to below design levels, making it necessary to substantially reduce sampler intake flow rates to achieve the isokinetic condition. Reductions in air flow may well be beyond the capability of available sampler flow controllers to maintain isokinetic conditions; therefore, the staff will accept flow control devices which have the capability of maintaining isokinetic conditions with variations in stack or duct design flow velocity of ~ 20 percent. Further departure from the isokinetic condition need not be considered in design. Corrections for an isokinetic sampling conditions, as provided in Appendix C of ANSI 13.1-1969 may be considered on an ad hoc basis.

4. effluent steams which may contain air with entrained water, e.g., air ejector discharge, shall have provisions to ensure that the adsorber is not degraded while providing a representative sample, e.g., heaters.

5. License applicants should have available for review the final design description of the as-built system, including piping and instrument diagrams together with either 1) a description of procedures for system operation and calibration, or 2) copies of procedures for system operation and calibration. Changes to technical specifications will be required. Applicants will submit the above details in accordance with proposed review schedule, but in no case less than 4 months prior to the issuance of an operating license. A post implementation review will be performed.

1.10-70 HCGS-UFSAR Revision 17 June 23, 2009

TABLE II.F.1-3 SAMPLING AND ANALYSIS OR MEASUREMENT OF HIGH-RANGE RADIOIODINE AND PARTICULATE EFFLUENTS IN GASEOUS EFFLUENT STREAMS EQUIPMENT - Capability to collect and analyze or measure representative samples of radioactive iodines and particulates in plant gaseous effluents during and following an accident. The capability to sample and analyze for radioiodine and particulate effluents is not required for pressurized water reactor secondary main steam safety valve and dump valve discharge lines. PURPOSE - To determine quantitative release of radioiodines and particulates for dose calculation and assessment. 2 DESIGN BASIS - 10 µCi/cc of gaseous radioiodine and par-SHIELDING ticulates, deposited on sampling media; ENVELOPE 30 minutes sampling time, average gamma energy (E) of 0.5 MeV. SAMPLING MEDIA - Iodine > 90 percent effective adsorption for all forms of gaseous iodine. - Particulates > 90 percent effective retention for 0.3 micron (µ) diameter particles. SAMPLING CONSIDERATIONS - Representative sampling per ANSI N13.1-1969. 1.10-71 HCGS-UFSAR Revision 0 April 11, 1988

TABLE II.F.1-3 (Cont) - Entrained moisture in effluent steam should not degrade adsorber. - Continuous collection required whenever exhaust flow occurs. - Provisions for limiting occupational dose to personnel incorporated in sampling systems, in sample handling and transport, and in analysis of samples. ANALYSIS - Design of analytical facilities and preparation of analytical procedures shall consider the design basis sample. - Highly radioactive samples may not be compatible with generally accepted analytical procedures; in such cases, measurement of emissive gamma radiations and the use of shielding and distance factors should be considered in design.

Response

The isokinetic effluent iodine and particulate filters and radiogas monitors for the North Plant Vent, South Plant Vent, and FRVS radiation monitoring systems on the post-accident effluent stream are described in Section 11.5. The inlet sample lines are heat-traced as indicated by Plant Drawing M-26-1. 1.10-72 HCGS-UFSAR Revision 20 May 9, 2014

ATTACHMENT 3, Containment High Range Radiation Monitor Position 8 In containment radiation level monitors with a maximum range of 10 rad/hr shall be installed. A minimum of two such monitors that are physically separated shall be provided. Monitors shall be developed and qualified to function in an accident environment. Clarification

1. Provide two radiation monitor systems in containment which are documented to meet the requirements of Table II.F.1-4.

8

2. The specification of 10 rad/hr in the above position was based on a calculation of post-accident containment radiation levels that include both particulate (beta) and photon (gamma) radiation. A radiation detector that responds to both beta and gamma radiation cannot be qualified to post-LOCA (loss-of-coolant accident) containment environments but gamma-sensitive instruments can be so qualified. In order to follow the course of an accident, a containment monitor that measures only gamma radiation is adequate. The requirement was revised in the October 30, 1979 letter to provide for a photon-only measurement 7

with an upper range of 10 R/hr.

3. The monitors shall be located in containment(s) in a manner as to provide a reasonable assessment of area radiation conditions inside containment.

The monitors shall be widely separated so as to provide independent measurements and shall "view" a large fraction of the containment volume. Monitors should not be placed in areas which are protected by massive shielding and should be reasonably accessible for replacement, maintenance, or calibration. Placement high in a Reactor Building dome is not recommended because of potential maintenance difficulties. 1.10-73 HCGS-UFSAR Revision 8 September 25, 1996

4. For BWR Mark III containments, two such monitoring systems should be inside both the primary containment (drywell) and the secondary containment.

5. The monitors are required to respond to gamma photons with energies as low as 60 keV and to provide an essentially flat response for gamma energies between 100 keV and 3 MeV, as specified in Table II.F.1-4.

Monitors that use thick shielding to increase the upper range will underestimate post-accident radiation levels in containment by several orders of magnitude because of their insensitivity to low energy gamma and are not acceptable. TABLE II.F.1-4 CONTAINMENT HIGH-RANGE RADIATION MONITOR REQUIREMENT - The capability to detect and measure the radiation level within the reactor containment during and following an accident. 7 RANGE - 1 R/hr to 10 R/hr (gamma only) RESPONSE - 60 keV to 3 MeV photons (with linear energy response

                  ~ 20 percent for photons of 0.1 MeV to 3 MeV).          Instruments must be accurate enough to provide usable information.

REDUNDANT - A minimum of two physically separated monitors (i.e., monitoring widely separated spaces within containment). 1.10-74 HCGS-UFSAR Revision 8 September 25, 1996

TABLE II.F.1-4 (Cont) DESIGN AND - Category 1 instruments as described in Appendix A QUALIFICATION except as listed below. SPECIAL - In situ calibration by electronic signal substitution CALIBRATION is acceptable for all range decades above 10 R/hr. In situ calibration for at least one decade below 10 R/hr shall be by means of calibrated radiation source. The original laboratory calibration is not an acceptable position due to the possible differences after in situ installation. For high range calibration, no adequate sources exist, so an alternate was provided. SPECIAL - Calibrate and type-test representative specimens ENVIRONMENTAL of detectors at sufficient points to demonstrate 6 QUALIFICATIONS linearity through all scales up to 10 R/hr. Prior to initial use, certify calibration of each detector for at least one point per decade of range between 1 R/hr 3 and 10 R/hr.

Response

The in-containment radiation monitors described in Section 11.5 have a maximum 8 range of 1 to 10 R/hr (gamma) and are physically separated. They are designed and qualified to function in an accident environment. , Containment Pressure Monitor 1.10-75 HCGS-UFSAR Revision 8 September 25, 1996

Position A continuous indication of containment pressure shall be provided in the control room of each operating reactor. Measurement and indication capability shall include three times the design pressure of the containment for concrete, four times the design pressure for steel, and -5 psig for all containments. Clarification

1. Design and qualification criteria are outlined in Appendix B of NUREG-0737.

2. Measurement and indication capability shall extend to 5 pounds per square inch absolute for sub-atmospheric containments.

3. Two or more instruments may be used to meet requirements. However, instruments that need to be switched from one scale to another scale to meet the range requirements are not acceptable.

4. Continuous display and recording of the containment pressure over the specified range in the control room is required.

5. The accuracy and response time specifications of the pressure monitor shall be provided and justified to be adequate for their intended function.

Response

The existing containment pressure instrumentation is identified in Section 7.5.1 and Table 7.5-1. , Containment Water Level Monitor 1.10-76 HCGS-UFSAR Revision 0 April 11, 1988

Position A continuous indication of containment water level shall be provided in the control room for all plants. A narrow range instrument shall be provided for pressurized water reactors (PWRs) and cover the range from the bottom to the top of the containment sump. A wide range instrument shall also be provided for boiling water reactors (BWRs) and shall cover the range from the bottom of the containment to the elevation equivalent to a 600,000 gallon capacity. For BWRs, a wide range instrument shall be provided and cover the range from the bottom to 5 feet above the normal water level of the suppression pool. Clarification

1. The containment wide range water level indication channels shall meet the design and qualification criteria as outlined in Appendixes B and C. The narrow range channel shall meet the requirements of Regulatory Guide 1.89.

2. The measurement capability of 600,000 gallons is based on recent plant designs. For older plants with smaller water capacities, licensees may propose deviations from this requirement based on the available water supply capability at their plant.

3. Narrow range water level monitors are required for all sizes of sumps but are not required in those plants that do not contain sumps inside the containment.

4. For BWR pressure-suppression containments, the Emergency Core Cooling System (ECCS) suction line inlets may be used as a starting reference point for the narrow range and wide range water level monitors, instead of the bottom of the suppression pool.

1.10-77 HCGS-UFSAR Revision 0 April 11, 1988

5. The accuracy requirements of the water level monitors shall be provided and justified to be adequate for their intended function.

Response

The existing water level instrumentation, described in Section 7.5.1 conforms to the BWROG position on NRC Regulatory Guide 1.97, Revision 2. , Containment Hydrogen Monitor Position A continuous indication of hydrogen concentration in the containment atmosphere shall be provided in the control room. Measurement capability shall be provided over the range of 0 to 10 percent hydrogen concentration under both positive and negative ambient pressure. Clarification

1. Design and qualification criteria are outlined in Appendix B.

2. The continuous indication of hydrogen concentration is not required during normal operation.

If an indication is not available at all times, continuous indication and recording shall be functioning within 30 minutes of the initiation of safety injection.

3. The accuracy and placement of the hydrogen monitors shall be provided and justified to be adequate for their intended function.

1.10-78 HCGS-UFSAR Revision 0 April 11, 1988

Response

The hydrogen monitoring instrumentation is identified in Section 7.3. Plant Drawing J-57-0 identifies the containment atmosphere control system's design operations. II.F.2 Instrumentation for Detection of Inadequate Core Cooling Position Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement existing instrumentation (including primary coolant saturation monitors) in order to provide an unambiguous, easy to interpret indication of inadequate core cooling (ICC). A description of the functional design requirements for the system shall also be included. A description of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment shall be provided. Clarification

1. Design of new instrumentation should provide an unambiguous indication of ICC. This may require new measurements or a synthesis of existing measurements which meet design criteria (Item 7).

2. The evaluation is to include reactor water level indication.

3. Licensees and applicants are required to provide the necessary design analysis to support the proposed final instrumentation system for inadequate core cooling and to evaluate the merits of various instruments to monitor water level and to monitor other parameters indicative of core cooling conditions.

1.10-79 HCGS-UFSAR Revision 20 May 9, 2014

4. The indication of ICC must be unambiguous in that it should have the following properties:

(a) It must indicate the existence of inadequate core cooling caused by various phenomena (i.e., high void fraction pumped flow as well as stagnant boiloff). (b) It must not erroneously indicate ICC because of the presence of an unrelated phenomenon.

5. The indication must give advanced warning of the approach of ICC.

6. The indication must cover the full range from normal operation to complete core uncover. For example, water level instrumentation may be chosen to provide advanced warning of two phase level drop to the top of the core and could be supplemented by other indicators such as incore and core-exit thermocouples provided that the indicated temperatures can be correlated to provide indication of the existence of ICC and to infer the extent of core uncover. Alternatively, full range level instrumentation to the bottom of the core may be employed in conjunction with other diverse indicators such as core exit thermocouples to preclude misinterpretation due to any inherent deficiencies or inaccuracies in the measurement system selected.

7. All instrumentation in the final ICC system must be evaluated for conformance to Appendix B of NUREG-0737, "Clarification of TMI Action Plan Requirements," as clarified or modified by the provisions of Items 8 and 9 that follow. This is a new requirement.

8. If a computer is provided to process liquid level signals for display, seismic qualification is not required for the computer and associated hardware beyond the isolator or input buffer at 1.10-80 HCGS-UFSAR Revision 17 June 23, 2009

a location accessible for maintenance following an accident. The single failure criteria of Item 2, Appendix B, need not apply to the channel beyond the isolation device if it is designed to provide 99 percent availability with respect to functional capability for liquid level display. The display and associated hardware beyond the isolation device need not be Class 1E, but should be energized from a high reliability power source which is battery backed. The quality assurance provisions cited in Appendix B, Item 5, need not apply to this portion of the instrumentation system. This is a new requirement.

9. In-core thermocouples located at the core exit or at discrete axial levels of the ICC monitoring system and which are part of the monitoring system should be evaluated for conformity with Attachment 1, "Design and Qualification Criteria for PWR Incore Thermocouples," which is a new requirement.

10. The types and locations of displays and alarms should be determined by performing a human factors analysis taking into consideration:

(a) The use of this information by an operator during both normal and abnormal plant conditions (b) Integration into emergency procedures (c) Integration into operator training (d) Other alarms during emergency and need for prioritization of alarms 1.10-81 HCGS-UFSAR Revision 8 September 25, 1996

Response

The HCGS design does not include the use of in-core thermocouples for detection of inadequate core cooling. PSE&G endorses the position of the BWR Owner's Group as outlined in the S. Levy Inc. Reports (SLI 8218 & SLI 8211) that there is no technical basis for requiring in-core thermocouples in addition to the existing water level instrumentation. HCGS incorporates the BWR Owner's Group recommendation to use analog equipment in place of mechanical level indication equipment. HCGS has also rerouted instrument lines for two channels of level monitoring instrumentation to minimize the vertical instrument line drop inside the drywell. This reduces the amount of instrument line that would be exposed to high drywell temperatures in the event of an accident or loss of drywell cooling. By doing this, the possibility of losing level indication has been significantly reduced. The following discussion describes the reasoning behind the decision to reroute these instrument lines. An evaluation of the effects of high temperatures on reference legs of water level measuring instruments subsequent to High Energy Line Breaks (HELB) is divided into two parts: 1) the effects of temperature alone, and 2) the effects of flashing/boiloff. High Temperature Effects (without flashing/boiloff) An increase in the temperature of the drywell will cause a heatup of the fluid in the instrument sensing lines, contributing to sensor error. The HCGS instrument sensing line design reduces this error by routing the variable leg and the reference leg lines with equivalent elevation drops in the drywell. The only exceptions to this design are the Upset Range transmitters reference leg sensing lines. Physical configuration prevents equivalent routing of these lines. However, these transmitters are used exclusively for indication and will not present any challenges to plant safety. 1.10-82 HCGS-UFSAR Revision 0 April 11, 1988

A high drywell temperature alarm is computer generated from isolated outputs of Class 1E temperature transmitters. Class 1E temperature recorders located in the main control room provide a continuous display of drywell temperature. Flashing/Boiloff Effects The effect of flashing/boiloff of the instrument line reference leg is to cause the level instruments to indicate erroneously high levels. The amount of error is directly related to the drop in elevation of piping physically located within the drywell and subject to flashing. HCGS has rerouted two channels of reactor pressure vessel (RPV) level instrumentation sensing lines to provide a maximum 3-ft elevation drop in the drywell (maximum 1-ft drop for the reference legs). A worst case analysis of the effects of boiloff of that portion of the sensing line inside the drywell, indicates the instruments using the rerouted lines will indicate a level that is 1.3 ft higher than actual. During and after a HELB the operator is required to maintain RPV level within the normal operating range, 18 ft above the top of active fuel. The 1.3 ft error is negligible with respect to the operating requirements. Transmitters used for post accident monitoring use the rerouted lines. Therefore, the wide, narrow, and fuel zone range recorders and indicators will provide an unambiguous display of level even after partial flashing of the reference legs. As a result of a HELB in containment, the drywell temperature may reach a maximum of 340F. Flashing/boiloff of the sensing lines may occur when the RPV pressure is less than 118 psia when the drywell temperature is 340F. At the 118 psia RPV pressure the High Pressure Coolant Injection (HPCI) system and the Automatic Depressurization System (ADS) are not required. 1.10-83 HCGS-UFSAR Revision 0 April 11, 1988

In response to a HELB of a large or intermediate sized line (see Figure 15.9-

43) Low Pressure Coolant Injection (LPCI) and core spray are initiated by low water level 1 (L1) or high drywell pressure signals. For these postulated events, HPCI and ADS are not required.

Two different response paths must be considered for a small break accident (SBA). The first response path considers a SBA with HPCI available. The Emergency Core Cooling System (ECCS) response to a SBA is outlined in FSAR Chapter 15 in response to Event 42 (Figure 15.9-43). Core spray and LPCI are initiated by high drywell pressure. HPCI is initiated on receipt of a low level 2 or high drywell pressure signal. HPCI continues to operate until the reactor vessel pressure is below the pressure at which LPCI or core spray operation can maintain core cooling. LPCI and core spray are designed to begin injecting water into the RPV when the differential pressure between the RPV and the suppression chamber is approximately 300 psid per design requirements (see FSAR Chapter 6.3). The second response path considers a HPCI line SBA that incapacitates HPCI. Accident mitigation requires the actuation of the Automatic Depressurization System (ADS), LPCI, and core spray. LPCI and core spray are initiated on high drywell pressure or a L1 signal. ADS is initiated by a L1 and high drywell pressure and a level 3 permissive signal when low pressure ECCS pumps are running. At the point flashing could occur, the RPV pressure will be low enough that ADS will not be required; before that point level signals/actuations will remain accurate. In the event of any credible HELB inside containment, the capability of the ECCS to mitigate the accident is not compromised by high drywell temperature or flashing of the RPV level instrumentation line reference legs. 1.10-84 HCGS-UFSAR Revision 0 April 11, 1988

II.G.1 Power Supplies for Pressurizer Relief Valves, Block Valves and Level Indicators

Response

This item is not applicable to BWRs. II.K.1 IE Bulletins on Measures to Mitigate Small Break LOCAs and Loss of Feedwater Accidents II.K.1.5 Assurance of Proper Engineered Safety Features Functioning Position Review all safety-related valve positions, positioning requirements, and positive controls to assure that valves remain positioned (open or closed) in a manner to ensure the proper operation of engineered safety features. Also, review related procedures, such as those for maintenance, testing, plant and system startup, and supervisory periodic (e.g., daily/shift checks) surveillance to ensure that such valves are returned to their correct positions following necessary manipulations and are maintained in their proper positions during operational modes.

Response

This requirement has been incorporated into the appropriate NBU administrative procedure(s). Refer to the response to position I.C.6 for supplementary information. 1.10-85 HCGS-UFSAR Revision 8 September 25, 1996

II.K.1.10 Position Review and modify, as required, procedures for removing safety-related systems from service (and restoring to service) to assure operability status is known.

Response

This requirement has been incorporated into the appropriate NBU administrative procedure(s). II.K.1.17 Position Trip pressurizer level bistable so that low pressure (rather than pressurizer low pressure and pressurizer low-level coincidence) will initiate safety injection.

Response

This requirement is not applicable to HCGS, which has a GE BWR. II.K.1.20 Position Provide procedures and training to operators for prompt manual reactor trip for loss of feedwater, turbine trip, main steamline isolation valve closure, loss of offsite power, loss of steam generator level, and low pressurizer level. 1.10-86 HCGS-UFSAR Revision 8 September 25, 1996

Response

This requirement is not applicable to HCGS. II.K.1.21 Position Provide automatic safety-grade anticipatory reactor trip for loss of feedwater, turbine trip, or significant decrease in steam generator level.

Response

This requirement is not applicable to HCGS. II.K.1.22 Proper Functioning of Heat Removal Systems Position Describe the actions, both automatic and manual, necessary for proper functioning of the auxiliary heat removal systems (e.g., reactor core isolation cooling) that are used when the main feedwater system is not operable. For any manual action necessary, describe in summary form the procedure by which this action is taken in a timely sense.

Response

HCGS endorses the operator action scenario described in the BWROG position. See Section 5.4.6 and 5.4.7 for discussion of the automatic and manual actions necessary for the proper functioning of heat removal systems when the Main Feedwater System is not available. 1.10-87 HCGS-UFSAR Revision 0 April 11, 1988

II.K.1.23 Reactor Vessel Water Level Indication Position Describe all uses and types of reactor vessel level indication for both automatic and manual initiation of safety systems. Describe other instrumentation that might give the operator the same information on plant status.

Response

All uses and types of reactor vessel water level indication for both automatic and manual initiation of safety systems are shown on Plant Drawing M-42-1, Nuclear Boiler Instrumentation P&ID. With all other conditions normal, other instrumentation that might give the control room operator the same information on plant status as low reactor water level are:

1. Increase in reactor water temperature at recirculation pump suction

2. Decrease in reactor pressure

3. Increase in drywell sump level.

II.K.2 Commission Orders on Babcock & Wilcox Plants

Response

These requirements are not applicable to HCGS. 1.10-88 HCGS-UFSAR Revision 20 May 9, 2014

II.K.3 Final Recommendations of B&O Task Force II.K.3.1 Installation and Testing of Automatic PORV Isolation System

Response

This requirement is not applicable to HCGS. II.K.3.2 Report on Overall Safety Effect of PORV Isolation System

Response

This requirement is not applicable to HCGS. II.K.3.3 Failure of PORV or Safety Valve to Close Position Assure that any failure of a PORV or safety valve to close will be reported to the NRC promptly. All challenges to the PORVs or safety valves should be documented in the annual report. This requirement is to be met before fuel load.

Response

HCGS will report any failure of a safety relief valve to close. A written report in the form of a Licensee Event Report will be submitted within 30 days as required by Section 50.73 of 10CFR Part 50. The PSE&G HCGS annual report to the NRC will list each safety relief valve which is challenged during the year and will include the number of times each is challenged. This reporting requirement will be included in the HCGS Technical Specifications. 1.10-89 HCGS-UFSAR Revision 0 April 11, 1988

II.K.3.5 Automatic Trip of Reactor Coolant Pumps During LOCA

Response

This requirement is not applicable to HCGS. II.K.3.7 Evaluation of PORV Opening Probability During Overpressure Transient

Response

This requirement is not applicable to HCGS. II.K.3.9 Proportional Integral Derivative (PID) Controller Modification

Response

This requirement is not applicable to HCGS. II.K.3.10 Proposed Anticipatory Trip Modification

Response

This requirement is not applicable to HCGS. II.K.3.11 Justification in the Use of Certain PORVs

Response

There are no PORVs at HCGS. The ADS system employs five safety/relief valves to depressurize the reactor so that flow from LPCI and/or the core spray systems enters the reactor in the event that RCIC and/or the HPCI system cannot maintain the reactor water level. See Sections 5.2.2 and 7.3 for further discussion. 1.10-90 HCGS-UFSAR Revision 0 April 11, 1988

II.K.3.12 Confirm Existence of Anticipatory Reactor Trip Upon Turbine Trip

Response

This requirement is not applicable to HCGS. II.K.3.13 Separation of HPCI and RCIC System Initiation Levels - Analysis and Implementation Position Currently, the Reactor Core Isolation Cooling (RCIC) System and the High Pressure Coolant Injection (HPCI) System both initiate on the same low water level signal and both isolate on the same high water level signal. The HPCI system will restart on low water level but the RCIC system will not. The RCIC system is a low flow system when compared to the HPCI system. The initiation levels of the HPCI and RCIC system should be separated so that the RCIC system initiates at a higher water level than the HPCI system. Further, the RCIC system initiation logic should be modified so that the RCIC system will restart on low water level. These changes have the potential to reduce the number of challenges to the HPCI system and could result in less stress on the vessel from cold water injection. Analyses should be performed to evaluate these changes. The analyses should be submitted to the NRC staff and changes should be implemented if justified by the analysis.

Response

PSE&G concurs with the BWROG position on the separation of the HPCI and RCIC setpoints, which was transmitted to the NRC by letter from R.H. Bucholz (GE) to D.G. Eisenhut (NRC), October 1, 1980 (MFN-169-80). This letter forwarded a GE study that showed that HPCI and RCIC initiations at the current low water level setpoints is within the 1.10-91 HCGS-UFSAR Revision 0 April 11, 1988

design basis thermal fatigue analysis of the reactor vessel and its internals. Separating HPCI and RCIC setpoints as means of reducing thermal cycles has been shown to be of negligible benefit. In addition, raising the RCIC setpoint or lowering the HPCI setpoint has undesirable consequences that outweigh the benefit of the limited reduction in thermal cycles. Therefore, when evaluated on this basis, PSE&G concludes that no change in RCIC or HPCI setpoints is required. PSE&G also concurs with the BWROG position that RCIC should restart automatically following a trip of the system at high reactor vessel water level. Instead of a RCIC turbine trip, which required operator action to allow restart of the system, the steam supply valve (E51-F045) to the turbine is closed to shut down the turbine and pump. Four separate transmitter/trip units energize individual relays, arranged in a one-out-of-two-twice logic configuration, to provide the closure signal for the valve. If the reactor water level subsequently decreases to level 2, the system initiation logic circuitry will reopen the steam supply valve, restarting the RCIC operation. This position was transmitted to the NRC by letter from D.B. Waters (BWROG) to D.G. Eisenhut (NRC), December 29, 1980. Therefore, the design of the RCIC system reflects this position. The RCIC system starts automatically when reactor water reaches a predetermined low level. The system is automatically shut off at a predetermined high level to prevent flooding of the steam lines. An automatic reset follows a high level trip. The RCIC system would then restart automatically on a subsequent low water level. I.K.3.15 Modify Break Detection Logic to Prevent Spurious Isolation of HPCI and RCIC Systems Position The HPCI and RCIC systems use differential pressure sensors on elbow taps in the steam lines to their turbine drives to detect and isolate pipe breaks in the systems. The pipe break detection circuitry has resulted in spurious isolation of the HPCI and RCIC 1.10-92 HCGS-UFSAR Revision 0 April 11, 1988

systems due to the pressure spike which accompanies startup of the systems. The pipe break detection circuitry should be modified so that pressure spikes resulting from HPCI and RCIC system initiation will not cause inadvertent system isolation. Submit sufficient documentation to support a reasonable assurance finding by the NRC that the modifications, as implemented, have resulted in satisfying the concerns expressed in the previous requirements.

Response

Each HPCI and RCIC steam supply line is provided with two normally open isolation valves. These valves close automatically upon receipt of an isolation signal. Each line contains a flow metering device. The HPCI and RCIC leak detection systems are Q-listed (Item XV.e.2 of Table 3.2-1). The flow sensing system will initiate closure of the isolation valves when the flow in that line exceeds 300 percent of rated. The issue raised by the NRC in NUREG-0737 was that the 300 percent setpoint may be momentarily exceeded during the HPCI/RCIC start sequences. The HCGS design incorporates an addition of a time delay to the break detection circuitry, which directly addresses the problem and has no impact on the currently documented accident analyses of the HPCI/RCIC steam supply line breaks. The design objectives have been met by replacing the previously installed isolation relay in each break detection circuit with a Class 1E time delay (approximately 3 seconds) relay to prevent inadvertent isolations during transient (startup) changes in steam flow. 1.10-93 HCGS-UFSAR Revision 0 April 11, 1988

II.K.3.16 Reduction of Challenges and Failures of Relief Valves - Feasibility Study and System Modifications Position Failure of the power-operated relief valve to reclose during the TMI-2 accident resulted in damage to the reactor core. As a consequence, relief valves in all plants, including boiling water reactors, are being examined with a view toward their possible role in a small break loss-of-coolant accident. The safety/relief valves are dual function pilot operated relief valves that use a spring actuated pilot for the safety function and an external air diaphragm actuated pilot for the relief function. The operating history of the safety/relief valves has been poor. A new design is used in some plants, but the operational history is too brief to evaluate the effectiveness of the new design. Another way of improving the performance of the valves is to reduce the number of challenges to the valves. This may be done by the methods described above or by other means. The feasibility and contraindications of reducing the number of challenges to the valves by the various methods should be studied. Those changes which are shown to decrease the number of challenges without compromising the performance of the valves or other systems should be implemented. Results of the evaluation shall be submitted by April 1, 1981 for staff review. Documentation of the staff approved modification will be provided by January 1, 1982. The actual modification will be accomplished during the next scheduled refueling outage after January 1, 1982 (if required). 1.10-94 HCGS-UFSAR Revision 0 April 11, 1988

Response

The NRC staff safety evaluation of the BWR Owners' Group response to NUREG-0737 Item II.K.3.16 states that the following modifications are acceptable methods of reducing SRV challenges and failures:

1. Providing a low-low set (LLS) relief logic system or developing procedures for Equivalent Manual Actions

2. Lowering the reactor pressure vessel water level isolation setpoint for main steam isolation valve (MSIV) closure from level 2 to level 1

3. Increasing the SRV simmer margin

4. Instituting a preventive maintenance program.

HCGS has provided a low-low set relief logic system based on the BWROG's generic design. The low-low set relief logic is Q-listed (Item XV.b.1 of Table 3.2-1). HCGS has implemented a MSIV closure setpoint change. The setpoint has been changed from an RPV Level 2 to Level 1 as indicated in Plant Drawing M-42-1. No changes will be made to the SRV simmer margin. The simmer margin is the difference between the SRV set pressure and the reactor pressure vessel operating pressure. The SRV set pressures are listed in Table 5.2-3. The RPV operating pressure is 1000 psig under steady state conditions. Therefore, the simmer margins, under steady state conditions, range from 108 to 130 psi. These values meet the intent of the 120 psi value recommended in General Electric Service Information Letter 196, Supplement 3. Besides the design changes, HCGS is committed to implementing an SRV preventative maintenance program. The program will be based on information on operational feedback experiences found in such publications as NRC Inspection and Enforcement Bulletins, Information Notices, and General Electric service information letters. Maintenance procedures are available. 1.10-95 HCGS-UFSAR Revision 20 May 9, 2014

II.K.3.17 Report on Outages of ECCS Systems Licensee Report and Proposed Technical Specification Changes Position Several components of the Emergency Core Cooling (ECC) Systems are permitted by technical specifications to have substantial outage times (e.g., 72 hours for one diesel generator; 14 days for the high pressure coolant injection system). In addition, there are no cumulative outage time limitations for ECC systems. Licensees should submit a report detailing outage dates and lengths of outages for all ECC systems for the last 5 years of operation. The report should also include the causes of the outages (i.e., controller failure, spurious isolation). Clarification The present technical specifications contain limits on allowable outage times for ECC systems and components. However, there are no cumulative outage time limitations on these same systems. It is possible that ECC equipment could meet present technical specification requirements but have a high unavailability because of frequent outages within the allowable technical specifications. The licensees should submit a report detailing outage dates and length of outages for all ECC systems for the last 5 years of operation, including causes of the outages. This report will provide the staff with a quantification of historical unreliability due to test and maintenance outages, which will be used to determine if a need exists for cumulative outage requirements in the technical specifications. Based on the above guidance and clarification, a detailed report should be submitted. The report should contain 1) outage dates and duration of outages;

2) causes of the outage; 3) ECC systems or components involved in the outage; and 4) corrective action taken. Tests and maintenance outages should be included in the above 1.10-96 HCGS-UFSAR Revision 0 April 11, 1988

listings which are to cover the last 5 years of operation. The licensee should propose changes to improve the availability of ECC equipment, if needed. Applicants for an operating license shall establish a plan to meet these requirements.

Response

All unplanned ECCS outages are documented as a condition adverse to quality reported in the corrective action program. These reports are used to generate licensee event reports (LERs) in accordance with 10CFR50.73, as applicable. Planned ECCS outages are documented in the OS/CRS daily log. Analysis of failure trends is accomplished by means of the LER system, corrective action program, MRule activities, etc., which requires a review of previous occurrences. Identified trends are further analyzed by Onsite Independent Review and/or the Nuclear Maintenance Programs personnel. II.K.3.18 Modification of ADS Logic - Feasibility for Increased Diversity for Some Event Sequences Position The Automatic Depressurization System (ADS) actuation logic should be modified to eliminate the need for manual actuation to assure adequate core cooling. A feasibility and risk assessment study is required to determine the optimum approach. One possible scheme that should be considered is ADS actuation on low reactor-vessel water level provided no high pressure coolant injection or high pressure core spray flow exists and a low pressure Emergency Core Cooling (ECC) System is running. This logic would complement, not replace, the existing ADS actuation logic. 1.10-97 HCGS-UFSAR Revision 9 June 13, 1998

Response

GE performed a study for the BWR Owners Group and a revised report, NEDO - 24951, which identified eight optional means for resolution of this issue and was submitted to the NRC on October 28, 1982. The NRC judged acceptable either Option 2 (Eliminate High Drywell Pressure Trip and Add Manual Inhibit Switch) or Option 4 (Bypass High Drywell Pressure Trip and Add Manual Inhibit Switch). HCGS design incorporates Option 4. This further automates the ADS by providing initiation, if required, for events that result in loss of coolant without an increase in the drywell pressure such as a pipe break outside the drywell or stuck open SRVs. The manual inhibit switch allows the operator to inhibit ADS operation without having to repeatedly press the reset switch. The use of the inhibit switch is addressed in plant operating procedures OP-EO.ZZ-101(Q), "Reactor Pressure Vessel Control," and OP-EO.ZZ-201(Q), "Level Restoration." These modifications have been incorporated in the HCGS design. The ADS logic including the modifications due to this TMI item is Q-listed (Item XV.b.1 of Table 3.2-1). II.K.3.21 Restart of Core Spray and LPCI Systems Position The core spray and LPCI system flow may be stopped by the operator. These systems will not restart automatically on loss of water level if an initiation signal is still present. The core spray and LPCI system logic should be modified so that these systems will restart if required to assure adequate core cooling. Because this design 1.10-98 HCGS-UFSAR Revision 0 April 11, 1988

modification affects several core cooling modes under accident conditions, a preliminary design should be submitted for staff review and approval prior to making the actual modification. Part a By January 1, 1981, each licensee shall submit proposed design modifications and supporting analysis which will contain sufficient information to support a reasonable assurance finding by the NRC that the above position is met. The documentation should include as a minimum:

1. A discussion of the design with respect to the above paragraphs of Institute of Electronics and Electrical Engineers Standard 279-1971.

2. Support information including system design description, logic diagrams, electrical schematics, piping and instrument diagrams, test procedures and technical specifications.

3. Sufficient documentation to demonstrate that the system, as modified, would not degrade proper system functions.

Part b Licensee to implement modifications at the next refueling outage following staff approval of the design unless this outage is scheduled within 6 months of the approval date. In this event, modifications will be completed during the following refueling outage.

Response

PSE&G concurs with the BWROG position, which is stated in NEDO-24951. The conclusion of the study is that the current BWR ECCS control logic as well as the core spray and LPCI logic is adequate, and no change is required. 1.10-99 HCGS-UFSAR Revision 0 April 11, 1988

II.K.3.22 Automatic Switchover of RCIC System Suction - Verify Procedures and Modify Design Position The Reactor Core Isolation Cooling (RCIC) System takes suction from the condensate storage tank with manual switchover to the suppression pool when the condensate storage tank level is low. The switchover should be made automatically. Until the automatic switchover is implemented, licensees should verify that clear and cogent procedures exist for the manual switchover of the RCIC system suction from the condensate storage tank to the suppression pool.

Response

The HCGS design incorporates an automatic transfer to the suppression pool when the condensate storage tank (CST) water reaches a predetermined low level. The RCIC suction transfer is Q-listed (Item XV.c.1 of Table 3.2-1). The subject valves are interlocked so that one must open before the other closes. For more details, see Sections 5.4.6.1 and 7.4.1.1.2. II.K.3.24 Confirm Adequacy of Space Cooling for HPCI and RCIC Systems Position Long term operation of the reactor core isolation cooling and high pressure coolant injection systems may require space cooling to maintain the pump room temperatures within allowable limits. Applications should verify the acceptability of the consequences of a complete loss of alternating current power. The reactor core isolation cooling and high pressure core injection systems should be designed to withstand a complete loss of offsite alternating current power to their support systems, including coolers, for at least 2 hours. 1.10-100 HCGS-UFSAR Revision 0 April 11, 1988

Confirm that HPCI and RCIC room cooling can be maintained to enable continuous operation during a loss of offsite ac power for 2 hours.

Response

The HPCI and RCIC room unit coolers and their support systems are designed to withstand the consequences of a complete loss of offsite ac power since these are powered from onsite diesel generators. Each HPCI and RCIC room is provided with a 100 percent capacity redundant unit cooler. The HPCI and RCIC room unit coolers are Q-listed (Item XIII.c.2 of Table 3.2-1). II.K.3.25 Effect of Loss of AC Power on Pump Seals Position The licensees should determine, on a plant specific basis, by analysis or experiment, the consequences of a loss of cooling water to the reactor recirculation pump seal coolers. The pump seals should be designed to withstand a complete loss of alternating current power for at least 2 hours. Adequacy of the seal design should be demonstrated. The results of the evaluation and proposed modifications are due by July 1, 1981. Modifications are to be implemented by January 1, 1982. Clarification The intent of this position is to prevent excessive loss of reactor coolant system inventory following an anticipated operational occurrence. Loss of alternating current power for this case is construed to be loss of offsite power. If seal failure is the consequence of loss of cooling water to the reactor coolant pump seal coolers for 2 hours, due to loss of offsite power, one acceptable solution would be to supply emergency power to the component cooling water pump. 1.10-101 HCGS-UFSAR Revision 0 April 11, 1988

Response

At HCGS, cooling to the reactor recirculation pump seals is provided by the Reactor Auxiliaries Cooling System (RACS). RACS is automatically energized from the Class 1E standby diesel generators during LOP. The recirculation pump sealing cooling water supply system (RAC and CRD) are not Q-listed (Item XI.c and IV of Table 3.2-1). PSE&G concurs with the BWROG study of this issue. BWROG submittals to the NRC on September 21, 1981, and September 2, 1982 provided test data showing very small seal leakage (on the order of 1 gpm) for a loss of seal cooling for longer than two hours. These results are applicable to the Byron-Jackson pumps used at HCGS. The normal or emergency controls for reactor water level could easily accommodate this small leakage rate. II.K.3.27 Provide Common Reference Level for Vessel Level Instrumentation Position Different reference points of the various reactor vessel water level instruments may cause operator confusion. Therefore, all level instruments should be referenced to the same point. Either the bottom of the vessel or the top of the active fuel are reasonable reference points. The applicant is to submit documentation by January 1, 1981 and implement action by April 1, 1981.

Response

The Hope Creek position on TMI issue II.K.3.27 was the current BWROG study, NEDO-24951, which stated that the current BWR water level indication system is fully adequate to allow plant operations to 1.10-102 HCGS-UFSAR Revision 0 April 11, 1988

respond properly under all postulated reactor conditions and that there are no required design changes based on any plant safety considerations. This evaluation was rejected by the NRC as explained in the letter from D.G. Eisenhut to D.B. Waters, dated April 6, 1981. In this letter, the NRC stated its position that "... all level instruments should be referenced to the same point. The selection of the reference point for any specific reactor has been left to the discretion of the licensee..." In light of this situation, HCGS has established the bottom of the dryer skirt as the common reference point for instruments measuring water level in the reactor vessel. See Table 3.2 for listing of existing level instrumentation. II.K.3.28 Verify Qualification of Accumulators on ADS Valves Position Safety analysis reports claim that air or nitrogen accumulators for the Automatic Depressurization System (ADS) valves are provided with sufficient capacity to cycle the valves open five times at design pressures. General Electric has also stated that the Emergency Core Cooling (ECC) Systems are designed to withstand a hostile environment and still perform their function for 100 days following an accident. Licensee and applicant should verify that the accumulators on the ADS valves meet these requirements, even considering normal leakage. If this cannot be demonstrated, the licensee and applicant must show that the accumulator design is still acceptable. Clarification The ADS valves, accumulators, and associated equipment and instrumentation must be capable of performing their functions during and following exposure to hostile environments and taking no credit 1.10-103 HCGS-UFSAR Revision 0 April 11, 1988

for nonsafety-related equipment or instrumentation. Additionally, air (or nitrogen) leakage through valves must be accounted for in order to assure that enough inventory of compressed air is available to cycle the ADS valves.

Response

See Section 6.3 for a discussion of the ADS and see Section 9.3.6 for a discussion of the Containment Instrument Gas System. The ADS valves, accumulators and associated equipment and instrumentation are Q-listed (Item II.1, II.b, II.c XV.b.1 & 11 and XVII.b of Table 3.2-1). II.K.3.30 Revised Small Break LOCA Methods to Shop Compliance with 10CFR50, Appendix K Position The analysis methods used by nuclear steam supply system vendors and/or fuel suppliers for small break loss-of-coolant accident (LOCA) analysis for compliance with Appendix K to 10CFR Part 50 should be revised, documented, and submitted for NRC approval. The revisions should account for comparisons with experimental data, including data from the LOFT Test and Semiscale Test facilities. Clarification As a result of the accident at TMI-2, the Bulletins and Orders Task Force was formed within the Office of Nuclear Reactor Regulation. This task force was charged, in part, to review the analytical predictions of feedwater transients and small break LOCAs for the purpose of assuring the continued safe operation of all operating reactors, including a determination of acceptability of emergency guidelines for operators. 1.10-104 HCGS-UFSAR Revision 0 April 11, 1988

As a result of the task force reviews, a number of concerns were identified regarding the adequacy of certain features of small break LOCA models, particularly the need to confirm specific model features (e.g., condensation heat transfer rates) against applicable experimental data. These concerns, as they applied to each light water reactor (LWR) vendor's models, were documented in the task force reports for each LWR vendor. In addition to the modeling concerns identified, the task force also concluded that, in light of the TMI-2 accident, additional systems verification of the small break LOCA model as required by II.4 of Appendix K to 10CFR Part 50 was needed. This included providing predictions of Semiscale Test S-07-10B, LOFT Test (L3-1), and providing experimental verification of the various modes of single-phase and two-phase natural circulation predicted to occur in each vendor's reactor during small break LOCAs. Based on the cumulative staff requirements for additional small break LOCA model verification, including both integral system and separate effects verification, the staff considered model revision as the appropriate method for reflecting any potential upgrading of the analysis methods. The purpose of the verification was to provide the necessary assurance that the small break LOCA models were acceptable to calculate the behavior and consequences of small primary system breaks. The staff believes that this assurance can alternatively be provided, as appropriate, by additional justification of the acceptability of present small break LOCA models with regard to specific staff concerns and recent test data. Such justification could supplement or supersede the need for model revision. The specific staff concerns regarding small break LOCA models are provided in the analysis sections of the B&O Task Force reports for each LWR vendor. These concerns should be reviewed in total by each holder of an approved emergency core cooling system model and addressed in the evaluation as appropriate. 1.10-105 HCGS-UFSAR Revision 0 April 11, 1988

The recent tests include the entire Semiscale small break test series and LOFT Test (L3-1) and (L3-2). The staff believes that the present small break LOCA models can be both qualitatively and quantitatively assessed against these tests. Other separate effects tests (e.g., Oak Ridge National Laboratory core uncover tests) and future tests, as appropriate, should also be factored into this assessment. Based on the preceding information, a detailed outline of the proposed program to address this issue should be submitted. In particular, this submittal should identify 1) which areas of the models, if any, the licensee intends to upgrade, 2) which areas the licensee intends to address by further justification of acceptability, 3) test data to be used as part of the overall verification/upgrade effort, and 4) the estimated schedule for performing the necessary work and submitted this information for staff review and approval.

Response

General Electric provided information concerning the NRC's small break model concerns in a meeting between GE and the NRC staff held on June 18, 1981 and subsequent documentation included in a letter from R.H. Bucholz (GE) to D.G. Eisenhut (NRC) dated June 26, 1981. Based on its review of this information, the NRC staff has prepared a safety evaluation report (SER) that concludes the test data comparisons and other information submitted by GE acceptably demonstrate that the existing GE small break model is in compliance with 10CFR50, Appendix K and, therefore, no model changes are required. The SAFER/GESTR-LOCA methodology, presented in reference 1, applies to the small breaks. Response Reference

1. General Electric Standard Application for Reactor Fuel (GESTAR II) (US Supplement), NEDE-24011-P-A-US (latest approved revision).

1.10-106 HCGS-UFSAR Revision 17 June 23, 2009

II.K.3.31 Plant Specific Calculations to Show Compliance with 10CFR50.46 Position Plant specific calculations using NRC approved models for small break loss of-coolant accidents as described in II.K.3 Item 30 to show compliance with 10CFR50.46 should be submitted for NRC approval by all licensees. Calculations to be submitted by January 1, 1983 or 1 year after staff approval of loss-of-coolant accident analysis models, whichever is later (required only if model changes have been made).

Response

Small break LOCA calculations are described in Section 6.3.3.7, and the results are summarized in Table 6.3-4. The references in Section 6.3.6 describe the currently approved Appendix K methodology used. Compliance with 10CFR50.46 has been previously established by the NRC. No model changes are necessary (see response to Item II.K.3.30). II.K.3.44 Evaluation of Anticipated Transients with Single Failure to Verify No Fuel Failure Position For anticipated transients combined with the worst single failure and assuming proper operator actions, licensees should demonstrate that the core remains covered or provide analysis to show that no significant fuel damage results from core uncover. Transients which result in a stuck open relief valve should be included in this category. The results of the evaluation are due January 1, 1981. 1.10-107 HCGS-UFSAR Revision 17 June 23, 2009

Response

The BWROG has prepared a generic response (NEDO-24951) to this requirement. The report was transmitted to D.G. Eisenhut by a letter from D.B. Waters on December 29, 1980. This response contains an evaluation of analyses performed to demonstrate that the core remains covered or no significant fuel damage occurs from an anticipated transient with a single failure. The report is applicable to HCGS and concludes that the core remains covered for all evaluated combinations of anticipated transients and single failures. II.K.3.45 Evaluation of Depressurization with Other Than ADS Position Analyses to support depressurization modes other than full actuation of the automatic depressurization system (e.g., early blowdown with one or two safety/relief valves) should be provided. Slower depressurization would reduce the possibility of exceeding vessel integrity limits by rapid cooldown.

Response

The BWROG submitted a generic response (NEDO-24951) to this requirement. This response was transmitted by letter to D.G. Eisenhut from D.B. Waters on December 29, 1980. This report concludes that a full ADS actuation is within the vessel integrity limits, that slower depressurization rates provide little benefit on vessel fatigue usage relative to full ADS, and slower depressurization rates can have an adverse impact on core cooling capability. The report is applicable to HCGS. 1.10-108 HCGS-UFSAR Revision 0 April 11, 1988

II.K.3.46 Responding to Michelson Concerns Position General Electric should provide a response to the Michelson concerns as they relate to boiling water reactors. Clarification General Electric provided a response to the Michelson concerns as they relate to boiling water reactors by letter dated February 21, 1980. Licensees and applicants should assess applicability and adequacy of this response to their plants.

Response

The February 21, 1980 letter to D.F. Ross of the NRC from R.H. Bucholz of G.E. addresses the Michelson concerns. This letter is applicable to HCGS. III.A.1.1 Emergency Preparedness, Short Term Position Comply with Appendix E to 10CFR Part 50 and Regulatory Guide 1.101, "Emergency Planning for Nuclear Power Plants," and meet the essential elements of NUREG-75/111, "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," or have a favorable finding from the Federal Emergency Management Agency (FEMA).

Response

Emergency planning is discussed in Section 13.3. HCGS complies with NUREG-0654, Revision 1, dated January 1981, endorsed by Regulatory Guide 1.101, Revision 2, and 10CFR50, Appendix E. 1.10-109 HCGS-UFSAR Revision 8 September 25, 1996

Activities covered by the QA program are delineated in the QATR and include emergency plans. III.A.1.2 Upgrade Emergency Support Facilities Position Establish an interim onsite Technical Support Center (TSC) separate from, but close to, the control room for engineering and management support of reactor operations during an accident. The Center shall be large enough for the necessary utility personnel and five NRC personnel, have direct display or callup of plant parameters, and dedicated communication with the control room, emergency operations facility, and the NRC. Provide a description of and a completion schedule for establishing a permanent TSC in accordance with the regulatory position of NUREG-0696, "Functional Criteria for Emergency Response" (February 1981). Establish an onsite Operations Support Center; separate from but with communications to the control room for use by operation support personnel during an accident. Designate a near site Emergency Operations Facility (EOF) with communications with the plant to provide evaluation of radiological releases and coordination of all onsite and offsite activities during an accident. These requirements shall be met before fuel loading.

Response

HCGS is designed and operated in accordance with the intent of Item III.A.1.2, as amended by Supplement 1 to NUREG-0737. 1.10-110 HCGS-UFSAR Revision 15 October 27, 2006

The display system available to the TSC and EOF is described in Section 7.5. The technical support center (TSC) is a two floor structure located in the corner of the Reactor Building. The room arrangement has been finalized. Two Control Room Integrated Display Systems (CRIDS) CRTs and a meteorological and radiation monitoring system CRT will be installed in the facility. The emergency operations facility (EOF) is located in the Training Center. The required data will be transmitted to the EOF via microwave with a computer telephone line backup. The Emergency Response Facilities Data Acquisition System (ERFDAS) is listed in Item XV.d of Table 3.2-1. III.A.2 Emergency Preparedness Position

1. Each nuclear facility shall upgrade its emergency plan to provide reasonable assurance that adequate protective measures can and will be taken in the event of a radiological emergency. Specific criteria to meet this requirement are delineated in NUREG-0654 (FEMA-REP-1),

     "Criteria   for  Preparation   and   Evaluation    of  Radiological   Emergency Response Plans and Preparation in Support of Nuclear Power Plants."

2. Perform an emergency response exercise to test the integrated capability and a major portion of the basic elements existing within emergency preparedness plans and organizations.

Response

The operation of HCGS will be in accordance with the criteria delineated in NUREG-0654. An emergency response exercise will be conducted for the HCGS prior to issuance of a full power license. Emergency planning is discussed in Section 13.3. 1.10-111 HCGS-UFSAR Revision 0 April 11, 1988

III.D.1.1 Primary Coolant Outside Containment Position Applicants shall implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as low as practical levels. This program shall include the following:

1. Immediate leak reduction (a) Implement all practical leak reduction measures for all systems that could carry radioactive fluid outside of containment.

(b) Measure actual leakage rates with system in operation and report them to the NRC.

2. Continuing Leak Reduction-Establish and implement a program of preventive maintenance to reduce leakage to as-low-as-practical levels. This program shall include periodic integrated leak tests at intervals not to exceed each refueling cycle.

Clarification Applicants shall provide a summary description, together with initial leaktest results, of their program to reduce leakage from systems outside containment that would or could contain primary coolant or other highly radioactive fluids or gases during or following a serious transient or accident.

1. Systems that should be leak tested are as follows (any other plant system which has similar functions or post accident characteristics even through not specified herein, should be included):

(a) Residual heat removal 1.10-112 HCGS-UFSAR Revision 17 June 23, 2009

(b) Containment spray recirculation (c) High-pressure injection recirculation (d) Containment and primary coolant sampling (e) Reactor core isolation cooling (f) Makeup and letdown (pressurized water reactors only) (g) Waste gas (includes headers and cover gas system outside of containment in addition to decay or storage system). Include a list of systems containing radioactive materials which are excluded from program and provide justification for exclusion.

2. Testing of gaseous systems should include helium leak detection or equivalent testing methods.

3. Should consider program to reduce leakage potential release paths due to design and operator deficiencies as discussed in our letter to all operating nuclear power plants regarding North Anna and Related incidents, dated October 17, 1979.

Response

1. The following are systems which penetrate containment and are likely to contain high radioactive fluids during or after a serious transient or accident and are included in the leakage reduction program.

(a) RCIC (b) RHR 1.10-113 HCGS-UFSAR Revision 0 April 11, 1988

(c) Core Spray (d) HPCI (e) Hydrogen/Oxygen Analyzer System (f) Post-Accident Sampling (g) Containment Hydrogen Recombination (h) Control Rod Drive Hydraulic System (SCRAM discharge portion)

2. The following design features and provisions are incorporated in these systems to minimize the leakage from the system boundary.

(a) The pumps are provided with mechanical seals (b) The piping is welded construction. (c) The boundaries of the systems are isolated by one of the following means:

1. One normally closed manual valve (low pressure piping)

2. Two normally closed manual valves

3. Two check valves

4. One remotely actuated valve and a check valve

5. Two remotely actuated valves

6. One safety/relief valve or rupture disk 1.10-114 HCGS-UFSAR Revision 0 April 11, 1988

3. The leakage reduction program is an ongoing program that includes periodic tests and visual examinations to identify leakage from the system boundary.

4. Liquid Systems Systems containing liquids will be tested by recirculation of the test water back to the source, if possible. The system pressure will reflect that expected during an accident. Systems or portions of systems outside containment which normally operate at a pressure less than accident pressure will be examined for leakage during the Containment Integrated Leakage Rate Test described in Section 6.2.6.1. Typical areas that will be inspected for leakage are valve stems, pump seals, vents, drains, pump casing joints, valve bonnet joints, and flanges. All leakage will be evaluated and corrective action taken where necessary.

5. Steam Systems Systems containing steam will be tested using steam at operating conditions, if possible. Corrective action will be taken to reduce the leakage as necessary.

6. Gas Systems Systems containing highly radioactive gases post-accident, i.e.,

connected to the containment atmosphere, will be pressurized using a gas to the accident conditions. Leakage can be identified by using a tracer gas, monitoring pressure decay metering the gas makeup or using a bubble test. Corrective action will be taken to eliminate any observed leakage.

7. Containment Isolation Valves and Piping The containment isolation valves will be tested for leakage in accordance with 10CFR50 Appendix J, Option B, as discussed in Section 6.2.4.

Therefore, these valves need not be included in the leak test program. 1.10-115 HCGS-UFSAR Revision 9 June 13, 1998

8. Test Frequency The systems will be inspected for leakage during refueling outages at intervals not to exceed 24 months.

9. The following systems are excluded from the leakage reduction program for the reasons given below:

(a) Reactor Recirculation System - The system is contained completely within the containment. (b) Reactor Water Cleanup - The RWCU is isolated at the containment boundary by the containment isolation valves. (c) Main Steam System - The Main Steam System is isolated at the containment boundary by the main steam isolation valves. (d) Feedwater System - The Feedwater System is isolated at the containment boundary by the feedwater isolation valves. (e) Process Sampling System - The Process Sampling System is isolated at the containment boundary by the containment isolation valves. Post-accident samples will be obtained by the post-accident sampling system. (f) Suppression Pool Cleanup System - The Suppression Pool Cleanup System is isolated at the containment boundary by the containment isolation valves. (g) Plant Leak Detection System - The Containment Radiation Sampling System used to detect primary leakage is isolated at the containment boundary by the containment isolation valves. 1.10-116 HCGS-UFSAR Revision 12 May 3, 2002

(h) Containment Inerting and Purging System - The Containment Inerting and Purging System is isolated at the containment boundary by the containment isolation valves. (i) Gaseous Radwaste System - The Gaseous Radwaste System (off-gas) receives its input from the Condensate Air Removal System. The main steam line isolation valves prevent highly radioactive steam from reaching the condenser and the Gaseous Radwaste System. (j) Reactor Building Ventilation System - The RBVS supply and exhaust are isolated on a high radiation signal. (k) Liquid Radwaste System - The drywell sump discharge is isolated at the containment boundary by the containment isolation valves. (l) Radwaste Tank Vents - The radwaste tanks are vented to the radwaste tank filter units as described in Section 9.4.3. This vent system will not receive highly radioactive gases post-accident because the radwaste system is isolated at the containment boundary.

10. The concerns expressed in the October 1979 letter regarding the North Anna incident are resolved in the design for the radwaste tank vents described in Section 9.4.3. The drainage, ventilation and radwaste systems are described in Sections 9.3.3, 9.3.4 and Section 11. The discussion for each system describes the tests and inspections used to verify proper system operation.

1.10-117 HCGS-UFSAR Revision 0 April 11, 1988

III.D.3.3 Improved Inplant Iodine Instrumentation Under Accident Conditions Position

1. Each licensee shall provide equipment and associated training and procedures for accurately determining the airborne iodine concentration in areas within the facility where plant personnel may be present during an accident.

2. Each applicant for a fuel loading license to be issued prior to January 1, 1981 shall provide the equipment, training, and procedure necessary to accurately determine the presence of airborne radioiodine in areas within the plant where plant personnel may be present during an accident.

Clarification Effective monitoring of increasing iodine levels in the buildings under accident conditions must include the use of portable instruments using sample media that will collect iodine selectively over xenon (e.g., silver zeolite) for the following reasons:

1. The physical size of the auxiliary and/or Fuel Handling Building precludes locating stationary monitoring instrumentation at all areas where airborne iodine concentration data might be required.

2. Unanticipated isolated "hot spots" may occur in locations where no stationary monitoring instrumentation is located.

3. Unexpectedly high background radiation levels near stationary monitoring instrumentation after an accident may interfere with filter radiation readings.

1.10-118 HCGS-UFSAR Revision 0 April 11, 1988

4. The time required to retrieve samples after an accident may result in high personnel exposures if these filters are located in high dose rate areas.

After January 1, 1981, each applicant and licensee shall have the capability to remove the sampling cartridge to a low background, low contamination area for further analysis. Normally, counting rooms in auxiliary buildings will not have sufficiently low backgrounds for such analyses following an accident. In the low background area, the sample should first be purged of any entrapped noble gases using nitrogen gas or clean air free of noble gases. The licensee shall have the capability to measure accurately the iodine concentrations present on these samples under accident conditions. There should be sufficient samplers to sample all vital areas. For applicants with fuel loading dates prior to January 1, 1981, provide by fuel loading (until January 1, 1981) the capability to accurately detect the presence of iodine in the region of interest following an accident. This can be accomplished by using a portable or cart mounted iodine sampler with attached single channel analyzer (SCA). The SCA window should be calibrated to the 365 keV of iodine-131 using the SCA. This will give an initial conservative estimate of presence of iodine and can be used to determine if respiratory protection is required. Care must be taken to assure that the counting system is not saturated as a result of too much activity collected on the sampling cartridge.

Response

A description of the equipment, training, and procedures has been provided in Section 12.5.3. Activities covered by the QA program are delineated in the QATR. 1.10-119 HCGS-UFSAR Revision 15 October 27, 2006

III.D.3.4 Control Room Habitability Position In accordance with Item III.D.3.4, "Control Room Habitability", applicants shall assure that control room operators will be adequately protected against the effects of accidental release of toxic and radioactive gases and that the nuclear power plant can be safely operated or shut down under design basis accident conditions (GDC 19). Clarification

1. All applicants must make a submittal to us regardless of whether or not they met the criteria of the referenced Standard Review Plan sections.

The new clarification specifies that applicants that meet the criteria of the Standard Review Plans should provide the basis for their conclusion that Section 6.4 of the Standard Review Plan requirements are met. Applicants may establish this basis by referencing past submittals to us and/or providing new or additional information to supplement past submittals.

2. All applicants with control rooms that meet the criteria of the following sections of the Standard Review Plan:

2.2.1,2.2.2 Identification of Potential Hazards in Site Vicinity, 2.2.3 Evaluation of Potential Accidents, and 6.4 Habitability Systems 1.10-120 HCGS-UFSAR Revision 0 April 11, 1988

shall report their findings regarding the specific Standard Review Plan sections as explained below. The following documents should be used for guidance: (a) Regulatory Guide 1.78, "Assumptions for Evaluating the Habitability of Regulatory Power Plant Control Room During a Postulated Hazardous Chemical Release". (b) Regulatory Guide 1.95, "Protection of Nuclear Power Plant Control Room Operators Against an Accident Chlorine Release". (c) K.G. Murphy and K.M. Campe, "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criterion 19", 13th AEC Air Cleaning Conference, August 1974. Applicants shall submit the results of their findings as well as the basis for those findings by January 1, 1981. In providing the basis for the habitability finding, applicants may reference their past submittals. Applicants should, however, ensure that these submittals reflect the current facility design and that the information requested in Table III.D.3.4-1 is provided.

3. All applicants with control rooms that do not meet the criteria of the above listed references, Standard Review Plans, regulatory guides, and other references shall perform the necessary evaluations and identify appropriate modifications.

Each applicant submittal shall include the results of the analyses of control room concentrations from postulated accidental release of toxic gases and control room operator radiation exposures from airborne radioactive material and direct radiation resulting from design basis accidents. The toxic gas accident analysis should be performed for all potential hazardous chemical releases occurring either on the site or within 5 miles of the plant boundary. 1.10-121 HCGS-UFSAR Revision 8 September 25, 1996

Regulatory Guide 1.78 lists the chemicals most commonly encountered in the evaluation of the control room habitability but is not all inclusive. The design basis accident radiation source term should be for the loss-of-coolant accident containment leakage and engineered safety features leakage contribution outside containment as described in Appendices A and B in Section 15.6.5 of the Standard Review Plan. In addition, boiling water reactor facility evaluations should add any leakage from the main steam isolation valves (i.e., valve steam leakage, valve seat leakage, main steam isolation valve leakage control system release) to the containment leakage and engineered safety features leakage following a loss-of-coolant accident. This should not be construed as altering our recommendations in Section D of Regulatory Guide 1.95 (Rev 2) regarding main steam isolation valve leakage control systems. Other design basis accidents should be reviewed to determine whether they might constitute a more severe control room hazard than the loss-of-coolant accident. In addition to the accident analysis results, which should either identify the possible need for control room modifications or provide assurance that the habitability systems will operate under all postulated conditions to permit the control room operators to remain in the control room to take appropriate actions required by GDC 19, the applicant should submit sufficient information needed for an independent evaluation of the adequacy of the habitability systems. Table III.D.3.4-1 lists the information that should be provided along with applicant's evaluation. 1.10-122 HCGS-UFSAR Revision 0 April 11, 1988

TABLE III.D.3.4-1 INFORMATION REQUIRED FOR CONTROL ROOM HABITABILITY EVALUATION

1. Control room mode operation, i.e., pressurization and filter recirculation for radiological accident isolation or chlorine release

2. Control room characteristics:

(a) air volume control room (b) control room emergency zone (control room, critical files, kitchen, washroom, computer room, etc.) (c) control room ventilation system schematic with normal and emergency air flow rates (d) infiltration leakage rate (e) high efficiency particulate air filter and charcoal adsorber efficiencies (f) closest distance between containment and air intake (g) layout of control room, air intakes, Containment Building, and chlorine, or other chemical storage facility with dimensions (h) control room shielding including radiation streaming from penetrations, doors, ducts, stairways, etc. (i) automatic isolation capability damper closing time, damper leakage and area (j) chlorine detectors or toxic gas (local or remote) 1.10-123 HCGS-UFSAR Revision 0 April 11, 1988

TABLE III.D.3.4-1 (Cont) (k) self-contained breathing apparatus availability (number) (l) bottled air supply (hours supply) (m) emergency food and potable water supply (how many days and how many people) (n) control-room personnel capacity (normal and emergency) (o) potassium iodide drug supply

3. Onsite storage of chlorine and other hazardous chemicals:

(a) total amount and size of container (b) closest distance from control room air intake

4. Offsite manufacturing, storage, or transportation facilities of hazardous chemicals (a) identify facilities within a 5-mile radius (b) distance from control room (c) quantity of hazardous chemicals in one container (d) frequency of hazardous chemical transportation traffic (truck, rail, and barge)

5. Technical Specifications (refer to standard Technical Specifications)

(a) chlorine detection system 1.10-124 HCGS-UFSAR Revision 0 April 11, 1988

TABLE III.D.3.4-1 (Cont) (b) control room emergency filtration system including the capability to maintain the control room pressurization at 1/8-inch water gauge, verification of isolation by test signals and damper closure times, and filter testing requirements.

Response

See Section 6.4 for a discussion of control room habitability. 1.10-125 HCGS-UFSAR Revision 0 April 11, 1988

~[1:1LIS: G()c:h~ <>f PesdE~l::al Re~gulat:i.(:*ns 5() .. 3~~ (TH:.l4e: 10) rie:quj_rE~s an c:~v*atl'LULt:ion <>f tl:u; :E:.eL*c:dJ.lt:y ug,i::~.:i.lr:t:s:t: l~nlr.REm-*0800 t:bt*E! .r:H:~:md.c:~xdl :r::**:::*;,tiEH117 ]~l<!ltlll ( SRP) , d.atc:d .July 1981. ~I1r:t*E: ce:Y.ELlllcl1::lcJn :t'*Et*~tu.j~J~E:!.S that: thE~ d:i ff,e~nmcc~ =; bE~ 1:><11*c~ c:~riL t:hE~ :f.r:Ld.l jLty .:md t:he~ SlH' bE~ j~du1:1.1~::i.f Le~ d ,. d.c:~:s.1::rfbE~d, ia.nd justl:E':it::,r:l. Sc;!c::.t:i.>r::m 1 . 11.1. Al!~cl pre~.e>E~ntc:!d .erre~ j1J.Is.t:i.f].c:at:lc::~n:s: d:l:E'f1e:remc:E~s lil t:he1 i!!.pplJ.c:abh~ SEH:tic)J:lus. ()f thE! :f'SAR 1;.;rhic:h ]pr~mdd<<~ .a bas :i.:s: fn :c* c:c>llc:: l1..:L*t:Ung t:hc:L t: tl-:t*e:y <!l.:r::*.e: ac:::.c::.;e:p tc;Lb lc~ J!llE~ 1:hcld.l; <> f c:omp ly i.ng \lllt:bt *t:hEI rE:!g;ul.sLt:l.cms. l.ll**l HGGS**UF~MR Rt:J:vi.::d.cm 0 April 11, 19'88

( ( ( TABLE 1. 11-1 SlM1ARY OF DIFFERENCES Fln1. SRP Suoola.ry FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences 2.5.1 II 2.5.1.3 (Rev 2) Site information regarding Unrelieved residual stresses unrelieved residual stresses have not been determined. in bedrock is required. (Section 2.5.1.2.4.C) 2.5.4 II 2.5.2.8 (Rev 1) For each set of conditions Information required is not describing the occurrence available for the plant site. of the maxiuua potential earthquake, the type of seis-mic waves proc:h.cing the maxillliD ground motion and the significant frequencies must be determined. (Section 2.5.2.5) II The amplitude and variation Earthquakes associated with of acceleration at the grotn'ld geological structures and surface, the effective fre- Tectonic Provinces were quency range, and the duration evaluated using the mean corresponding to each maxi.mla of the relationship between potential earthquake must be acceleration and Modified identified. The spectral Mercalli Intensity units. content for each pontential maximum earthquake should be described and l::B.sed on con-sideration of the available ground motion time histories and regional characteristics of seismic wave transmission. (Section 2.5.2.6) l of 31 HCGS-UFSAR Revision 0 April It, 1988

( ( ( TABLE 1.11-1 (Cont) Sl.llllll8.rY FSAR Section(s) SRP Specific SRP Where Section Acceptance Criteria Discussed 3.2.1 II 3.2.1 (Rev 1) Regulatory Guide 1.29, Application of this guide Position C.l.b, requires that is limited to those reactor the reactor core and reactor vessel internals that are vessel internals be designated part of engineered safety Seismic Category I features (ESFs), such as core spray piping, core spray spa.rger and hardware, etc. II 1.8.1 Regulatory Guide 1. 29, Portion of main steam line Position C.l.e, requires piping between main steam that portion of main steam shutoff valve and the turbine extending from the outermost main stop valve is not speci-containment isolation valve fically designed to Seismic to and incluiing the turbine Category I standards and is stop valve be designated not located in Seismic Seismic Category I. Category I structures. II Regulatory Guide 1.29, Seal cooling piping for the Position C.l.h, requires that reactor recirculation pump cooling water and seal water is not designed to withstand systems required for func- a safe shutdown earthquake (SSE). tioning of reactor coolant pumpsbe classified as Seismic Category I. II Regulatory Guide 1. 29 Non-Seismic Category I items Position C.2 requires that items that may impact safety-related whose continued function is not components are not specifically required but whose failure could designed to withstand an SSE. reduce the functioning of the safety-related components to an unacceptable level should be designed to withstand an SSE. 2 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) Sl.llllll8.ry FSAR Sectian(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed 3.2.2 II 1.8.1 (Rev 1) Regulatory Guide 1.26, Quality GroupD components Sections A&B, requires that are not safety-related. Quality Group D components be safety-related. II 3.2.2.1 Regulatory Guide 1.26 be used for Some components were not specifically establishing quality group standards designed and fabricated to these for Quality Groups B, C, and D. quality groupstandards. 3.5.3 Appendix A, Sect. II. 1 , Reinforced 3.8.4.8 (Rev 1) Concrete Members Permissible ductility ratios For flexural beams and slabs shall be in accordance with subjected to impBCtive loads, Regulatory Guide 1.142. the permissible ductility ratios exceed those given in Regulatory Guide 1.142. Appendix A, Sect.II.2, 3.8.4.8 Structural Steel Members Permissible ductility ratios For flexural beamssubjected are listed. to impactive loads (other than tornado missiles) the permissible ductility ratio exceeds that given in Appendix A of imP 3. 5. 3. For axial tension members subject to impulsive loads, a permissible ductility ratio of 3 is used. 3.6.2 ILl 3.6.2.7 (Rev 1} Postulated pipe rupture a) HCGS design for NSSS piping meets locations in containment the provisions of Rev 0 (November should meet MEB 3-1. 1973~ of this SRP section, and not the current SRP (Rev 1, July 1981~. 3 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) FSAR Section ( s l SRP Speci fie SRP Where Section Acceptance Criteria Discussed b) Intermediate breaks on Class 1, 2, and 3 piping are not postulated unless such locations exceed stress and usage factor threshold levels per MEB 3-1 or are located in the proximity of welded pipe attachments. II.3

        'Ibis section refers to IIJ.2.a(2) t          A pipe break initial condition which states that the initial                  of 100% power at nonnal plant condition prior to postulated                 conditions is used.

pipe rupture should be the greater of the contained energy at hot standb¥ or at 102'X.power. 3.7.1 ILL b 3.7.1.5 (Rev 1) Design time history for seis- In the chosen set of frequencies mic ground motion. Spectral for the 28 to 33 Hz range, values calculated fromdesign each frequency is generally time history should have fre- not within 10% of the pre-quency ranges in aareement vious one. with Table 3. 7.1-1 or selec-tion of a set of frequencies such that each frequency is within 10% of the previous one. II.l.b No more than five points of 'lhe spectra obtained from the spectra obtained fran the design time history have the design time history more than eight points fall should fall below the design below the design response response spectra. spectra for 1, 2, 5, and 7% damping. 4 of 31 Revision 0 April 11 , 1988

( ( ( TABLE 1.11-1 (Cant) Sl.lllllary FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed 3.7.3 II.2.b 3.7.3.16 (Rev 1) Five operating basis earth- For NSSS components and equip-quakes (OBEs) , with a minimu:n of ment, 10 equivalent peak OBE 10 cycles each, should be cycles are used. assumedduring the plant life. 3.8.2 II.4.f 3.8.2.8 (Rev 1) Design report is considered Sufficient information acceptable when it satisfies is available in forms the guidelines of Appendix C other than those outlined to SRP 3.8.4. in Appendix C. II.5 Table 3.8.2 lists allowa- Allowable stresses used for ble stress limits for steel testing and post-flooding containments. conditions are higher than indicated in SRP Table 3.8.2. 3.8.3 11.2 3.8.4.8 (Rev 1) Interior structures of con- Interior structures are tainments shall be designed designed in accordance in accordance with Specification with Specification ACI 318-71. ACI 349 as augmented by Regulatory Guide 1.142. II.4.e 3.8.2.8 Design report described in Sufficient information is Appendix C to SRP 3. 8. 4 is available in forms other reviewed. than those outlined in Appendix C. 3.8.4 11.2 3.8.4.8 (Rev 1) Category I structures shall Category I structures are de-be designed in accordance signed in accordance with with Specification ACI 349 Specification ACI 318-71. as augmented by Regulatory Guide 1.142. 5 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) Sl.llllllllry FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed IJ,2 1.8.1 Conformance to Regulatory Nonconformance, in part, Guides 1.10, 1.55 and 1.94. with Regulatory Guides 1.10,

t. 55. and 1.94.

IL4.d 3.8.2.8 Design reports are acceptable Sufficient information is if it contains the information available in forms other specified in Appendix c. thanthose outlined in Appendix c. II.4.f 3.8.4.8.1 Spent fuel rackmaterial AS1M steel procured under an ANSI should conform to Section III, N45.2 Q.A. Program, instead of steel Subsection NF, of the ASME Code. procured under an ASMB Code Q.A. Programin accordance with Subsection NF1 is used. 3.8.5 II.4.e 3.8.2.8 (Rev l) Design report is considered Sufficient information is acceptable if it satisfies the available in forms other guidelines of Appendix C to than those outlined in SRP 3.8.4. Appendix C. 3.9.3 II.l 3.9.3.5 (Rev 1) Acceptability of the oombina- Design and. service loadings tion of design and. service applicable to the design of loadings applicable to the Class 1, 2, and 3 canponents design of Class 1, 2, and 3 do not comform, in part, to caaponents should be ju::'lged Appendix A or SRP 3.9.3. by comparison with positions stated in Appendix A of SRP 3.9.3. 6 of 31 HCGS-UFSAR Revision 0 April L1, 1988

TABLE 1.11-1 (Cont) FSAR Section(s) SRP Specific SRP of Where Section Acceptance Criteria Discussed 3.9.5 II.b 3.9.5.4 (Rev 2) Design and construction of Design and construction of the core support structures the core support structures is to con£orm to the require- do not specifically conform ment of Subsection NG of to Subsection NG of Section Section III of the ASME Code. III of the ASME Code. II.c Design basis for reactor Reactor internals do not internals to conform to specifically conform to ASME III, Subsection ASME III, Subsection NG 3000. NG 3000.

Ln II 3 .11.5 (Rev 2)

Envircnmental qualification is performed by either one of the two methods: analysis or testing'. II Complete and auditable These records will be available records be available at time in time for environmental of OL application. qualification audit, prior to fuel load. II program Mechanical II IEEE-323 (augmented by Reg. The HCGS equipment qualification Guide 1.89) as acceptance program will comply with Reg. criteria is to be used for Guide 1.69 for equipment upgraded qualification program. to NUREG 0588, Category I requirements. 7 of 31 HCGS-UFSAR Revision 16 May l.S, 2008

( ( ( TABLE 1.11-1 (Cant) Sumnary FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed 4.4 ILB 4.4.7 (Rev 1) Crud effects should be account- Crui effects and process moni-ed for in the thermal-hydrau- toring to detect a 3X drop in lic design. Process moni tar- reactor coolant flow are not ing should be capa.ble of explicitly addressed in FSAR. detecting a 3% pressure drop in the reactor c<X>lant flow. 4.5.1 II.l 4.5.1.5 (Rev 2) Properties of materials for Ci'llycomp::ment.s forming pri-control drive mechanism are mary pressure boundary use to be equivalent to those code materials. given in Appendix I to Section III of the ASME code. 4.5.2 11.2 4.5.2.6.1 (Rev 2) Welds fabricated per ASME Welds are not performed in Section III, NG-4000 must accordance with ASHE III, meet examination and accep- NG-4000 and NG-5000 tance criteria shown in requirements, NG-5000. 11.3 4.5.2.6.2 NOlldestructive examination of Tubular products are not wrought seamless tul:ular pro- supplied to ASMB Code ducts and fittings shall be in Section III, NG-2500 and accordance with ASHE Code NG-5300requirements. Section III, NG-2500 and NG-5300. II.4 4.5.2.6.3 Fabrication is to be in full Fabrication is not in full compliance with Regulatory compliance with Regulatory Guides 1.31 and 1.44. Guides 1.31 and 1.44. 8 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) Sullmary FSAR Section(s} SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed 5.2.1.1 II.1,2 5.2.1.3.1, (Rev 2) 5.2.1.3.2 Minimun quality standard for Certain safety-related struc- and 1.8.1 safety-related structures, tures, systems, and components systems, and canponents a.s are purchased under different established by 10 CFR 50. 55a editions and addenda of the requires conformance with code. appropriate editions of specified published industry codes and standards. 5.2.1.2 11.1,2 5.2.1.3.1, (Rev Z) 5.2.1.3.2 ASME Section III code case Some code cases that have been and 1.8.1 acceptability for safety used are not addressed in related structures, systems in applicable Regulatory Guides. and components is based on conformance to Regulatory Guides 1.84, 1.85, and 1.147. 5.2.3 II.3.b.(3) and II.4.d 5.2.3.5.2 and (Rev 2) 1.8.1 Regulatory Guide 1. 71 states Welders are not tested under that performance qualifica- simulated access conditions tions should ~re testing and are not requalified for of welders tmd.er simulated significantly different res-access condi tiona whenPlY- tricted accessibility sica! conditions restrict conditions. welder's access. Requalifi-cation of welder is required. when significantly different restricted accessibility conditions occur. II.4.d Regulatory Guide 1. 31, Ferrite content is deter-Position e.l, requires that mined by chemical analysis. delta ferrite content veri-fication tests on austenitic steel weld filler material be made using magnetic measuring devices. 9 of 31 llCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) SUIIDB.ry FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed II.l.l 5.2.3.5.1 Material specifications for Requirements of Part B, reactor coolant pressure Section II are not met. boundary(RCPB) materials Design stresslimitsof ASME are those identified in Section III, Appendix I Appendix I of Section III are not used. or described in detail in Parts A, B, and C of Section II. II.4.b.2 5.2.3.5.1 Water quality for final Relevant sections of Regula-cleaning or flushing of tory Guide I. 37 are not finished surfaces during imposed. installation per Regulatory Guide 1.37 5.2.4 11.7 5.2.4.8 (Rev I) Exemptions from code exami- Exemptions are not listed. nations are in accordance withthe criteria in IWB-1220. 5.2.5 11.1 5.2.5.ll and (Rev 1) 1.8.1 Application of Regulatory Portions of IDS are not Guide 1.29 positions C-1 and qualified for a seismic event. and C-2 to LeakDetection System(IDS)* 5.3.1 1!.2 5.3.1.8.1 (Rev 1) Reactor pressurevessel(RPV) Components are fabricated and appurtenances are to be and installed to earlier fabricated and installed to edition of ASME, Section III, ASMB Code Section III, Code. Paragraph NB-4100. 10 of 31 HCGS-UFSAR ReYision 0 April il, 1988

( ( ( TABLE 1.11-1 (Cont) S\lllllarY FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences 1!.3 5.3.1.8.2 Nondestructive examination Caaponents are fabricated of RPV material to ASME Code, and installed to earlier Section III NB-5000 (normal) edition of ASME, Section III, or Appendix IX-6000 (special Code. method). II.4.a 5.3. 1.8.3 Welding records of RPV Welding records per NB-4300 ferritic and austenitic of Section III are not stainless steel are required specifically addressed. by NB-4300 of Section III. II.4.e 5.3.1.8.4 Regulatory Guides 1. 37 and Nonconformance to Regulatory 1

44 in avoiding sensi tiza- Guide 1. 37 as related to the tion and contamination of RPV.

RPV stainless steel. 11.5 & II.6 5.3.1.8.5 Appendices G and H of Design and procurement of 10 CFR 50 regarding material Hope Creekreactor vessel testing and acceptance stan- is not in total compliance with dards for fracture toughness. Appendices G and H. 5.3.3 II.l 5.3.3.8 (Rev 1) Conformance to ASME B&PV Reactor vessel does not code. have an ASME code "N" stamp. II.2 Acceptable materials for Additional materials for reac-reactor vessel parts are tor vessel partsare used. SA 533 Gr B Cll, SA 508 Cl2 and SA 508 Cl3. 11 of 31 HC.'OS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cant) SUlllllarY FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences 11.4 Preservice inspection and ASME Section XI , preservice flaw evaluation of RPV as required inspection and flaw criteria by ASHE Code, Section XI. is not applied. 5.4.8 II.l.a 5.4.8.4 (Rev 2) Reactor water demineraliza- Demineralization is accom-tion is to operate at It. of plished with less than 1% of main steam flow rate. main steam flow rate. 5.4.12 n.s 5.4.12.5 (Rev 0) Provisions to test for opera- Provisions for testing are bility of the reactor coolant not provided. vent system should be part of the design. 6.1.1 II.A.t.a.2 6.1.1.3 (Rev 2) Regulatory Guide 1.44 re- Corrosion tests are generally quires corrosion testing for not performed, verification of nonsensitiza-tion of austenitic stainless steel components. II.A.l.a.4 Regulatory Guide 1.31 1 re- Ferrite content is determined quires delta ferrite content by chemical analysis. verification of austeni-tic stainless steel weld filler material by tests using magnetic measuring devices. II.A.l.b.l ASME Code and Regulatory Weld procedures and practices Guide 1. 50 set requirements are in full compliance with for the control of preheat the code, but not strictly for welding of low-alloy with all aspects of Regula-steel. tory Guide 1. 50. 12 of 31 Revision 0 April 11. 1988

( ( ( TABLE 1.11-1 (Cont) S\.miJI9.l'Y FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed II.B.l Regulatory Guide 1. 7, Drywell fans are not safety-Position C .1 , requires that related. Analysis show that capability be provided to adequate mixing is obtained mix cc::mtainment atmosJitere from convection, diffusion, to control hydrogen genera- and turbulence. tion fol~owing a LOCA. 6.1.2 II 6.1.2.1 (Rev 2) Caapliance with Regulatory Noncanplience with Regulatory Guide 1

54 and the standards Guide 1. 54 as related to of ANSI N101.2 for NSSS ANSI 101.4.

coatina systems inside the contairalent. 6.2.1.2 Criteria II.B.l 6.2.1.8 (Rev 2) Initial conditions for sub- The subcompartment enalyses caapart.laent analyses should for RPV shield annulus and be: drywell head were basedon Rfi;;:;O, T;;:;Maximl.m, the following initial con-P=Hinimlm (Page 6.2.1.2.2). ditions: RH.::30, T=135~, and P=15.45 psia. 6.2.3 II.3.e 6.2.3.6 (Rev 2)

        'nle external design pressure                   The secondary containment for of the secondary containment                     tornado depressurization is structure should provide an                     not designed with any margin adequate margin above the                       above the maxi.Im.a expected
        -.x:imuDexpected external                       extenml pressure as stated pressure.                                        in Regulatory Guide 1. 76.

13 of 31 Revision 0 April 11 , 1988

TABLE 1.11-1 {Cant) Summary FSAR Section ( s) of Where Discussed 6.2.4.5 6.2.4 II.6.d (Rev 2) An enclosure or leak-tight Valve nearest the contain-ment and piping between the housing has not been designed. containment and the first valve, when both valves are located outside primary should be enclosed in a tight or controlled leakage housing. 1.10.II.E.4.2/ II.6.h 6.2.4.5 All nonessential systems penetrating There are valves in nonessential primary containment must be portions of systems where automatic automatically isolated by the isolation is not provided. containment isolation signal. 6.2.5.7 6.2.5 II.4 (Rev 2) Pressure increase due to main Following a LOCA, repressuri-zation of the containment steam isolation valve (MSIV) should be limited to less after a LOCA will than 50% of containment repressurization of design pressure. more 50% of the contain-ment design pressure. 6.5.1.2 6.5.1 II (Rev 2) Compliance with the minimum Design of instrumentation for ESF atmosphere cleanup systems instrQ~entation requirements to the guidelines of Regulatory for the CREF system are Guide 1.52 and to the recom- discussed in Table 6.5-4 and for the FRVS systems in mendations of ANSI N509 as summarized in SRP Table 6.5.1-1. Table 6.8-5 I 14 of 31 Revision 17 HCGS-UFSAR June 23, 2009

( ( ( TABLE 1.11-1 (Cont) SUDIJial"Y FSAR Seotion(s) SRP Specific SRP Description of Where Section Discussed 6.5.1 II 6.5.1.1 !Rev 21 Relevant requirements of General Compliance with the recaumendations Design Criteria 19, 41, 42, 61, of Regulatory Guide 1. 52 are discussed and 64 as they relate to the in Section 1.8.1.52. Design Testing and.Maintenance of ESF at.lsphere cleanup system air filtration and absorption units are met by using the regulatory positions contained in Regulatory Guide 1. 52. 7.1 Table 7-1 7.1.2.4(q) (Rev 2) Conformance to Regulatory Exception to Regulatory Guide Guide 1.118. 1.118. 8.1 Table 8-1 8.1.6 and (Rev 2) 8.3.4 Applies Criteria Item F Regulatory HOGS separation criteria also Guide 1.75, IEEE-384-1981, allow 18 inches vertical sepa-to: requires that vertical sepa- ration for redundant Class lE 8.3.1 ration between redundant cable trays in the cable (Rev 2) Class l.B cable trays in the spreading room. and cable spreadingroom is .to 8.3.2 be at least 3 feet. (Rev 2) Table 8.1 Regulatory Guide 1. 75, HOGS design does not have Position C.15, requires that complete independence for safety class structures each battery room. housing redundant Class lE batteries should have indepen-dent ventilation systems. 9.1.2 II. I 9.1.2.5 (Rev 21 ANS 57. 2, Paragra}Xts5. 1. 1 Spent fuel liner plates are and 6.4.1.(1) requires that non-seismic Category I. the spent fuel pool to be designed to Seismic category I. 15 of 31 HCGS-lJFSAR Revision 0 April 11 , 1988

( ( ( TABLE 1.11-1 (Cont) Sl..IIIIBr'Y FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed II.6 ANS 57.2 1 Paragra{il 5. 4. 1 No permanent radiation moni-requires that at least one tors are provided on the radiation monitor with audi- refueling machine. ble alarm shall be installed on the fuel handling machine. u.s ANS 57.2, Paragraph 5.4.2 High and low level alarms requires that high and low are provided only in the 128in level alarms shall be provi- control room. ded in the spent fuel buildirc and in the control roce to indicate if the pool water level falls below or exceeds predetermined limi ta. 9.1.3 II.t.d. (4) 9.1.3.6 (Rev 1)

          'lbe max:iaa norual spent fuel                'lbe maxiD.Jm normal spent fuel pooA  water temperature is                     pool water temperature will 140 F withsingle failure of                    exceed 1400, after the first one heat exchanger.                            refueling cycle of the plant.

9.1.4 11.3 and 4 9.1.4.6 (Rev 2) Regulatory Guide 1. 13 * 'lbe reactor building polar Position C. 3, requires that crane 10-ton auxiliary hoist interlocks be provided to is not physically restricted prevent cranes fraa passing from traveling over the spent over stored fuel when fuel fuel pool. handling is not in progress. Il.3 ANS 57.1. Paragraph 6.2.1.1(a), The polar crane auxiliary hoist, requires that the auxiliary which functions as the auxili-fuel handling crane be pro- ary fuel handling crane, is vided with an underload not provided with an underload interlock. interlock. 16 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) SUillliB.ry FSAR Section ( s) SRP Speoi fie SRP Description of Where Section Acceptance Criteria Differences Discussed II.5 The ma:ximun potential kinetic Light loads handled by the energy capable of being devel- fuel pool jib cranes and oped by any load handled the auxiliary hoist of above stored spent fuel, if the reactor building polar dropped, should not exceed crane could exceed the max-the kinetic energy of one imliDpotential energy. fuel assembly and its associa-ted handling tool when dropped from the height of wwhich it is normally ha:odled above the spent fuel pool storage racks. 9.1.5 !1.2 9.1.5.6 (Rev O>> Regulatory Guide 1.13 Position C. 3 Interlocks should be provided The auxiliary hoist of the polar to prevent cranes from passing crane has no travel restriction. over stored fuel when fuel handling is not in prol(ress.

          !1.2 NUREG 0612, para. 5.1.1(1)                    Loadpathsare not painted Load paths should be clearly                  on the floor.

marked on the floor in the areas where heavy loads are to be handled II.2 ANS 57.1, para 6.2.1.1(a) The auxiliary hoist of the Auxiliary fuel ha:odling crane polar crane, which functions to be provided with an underload as the auxiliary fuel handling interlock that is actuated upon crane, has no under load reduction in load while lowering. interlock. 17 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cant) FSAR Section(s) SRP Specific SRP Where Section Acceptance Criteria Discussed 9.3.2 II.5.a 9.3.2.6 (Rev 2) The post-accident sampling The PASS does provide a method for systemshould have the capl- measuring dissolved oxygen as bility for measuring dis- discussed in Section 9.3.2.6. solved oxygen to required concentrations in the reactor coolant. 9.4.1 II 9.4.1.6 (Rev 2) Regulatory Guide 1. 52, Demisters are used only where Position C.2a, states that moisture impingement is a engineered safety feature potential problem. ( ESF) atmosphere cleanup systems should include demisters prior to prefil ters. II Regulatory Guide 1. 52, The ESF atmosphere cleanup Position C.2.j, states that systems are not designed to ESF atmosphere cleanup units be replaced as intact units be designed and installed in or in segmented sections. a manner that permits replace-ment of one train as an intact unit or as a m.inimlDnunber of sections. 9.4.2 II.3 9.4.2.6 (Rev 2) Regulatory Guide 1. 52, Demisters are used only where Position C.2.a, states that moisture impingement is a ESF atmosphere cleanup sys- potential problem. HEPA tems should include demisters filters are not provided ahead* prior to prefil ters and HEPA of adsorbers when HEPA filters filters ahead of the adsorbers. are normally present upstream of the BSF atmospheric cleanup units. 18 of 31 Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cant) Sumlary FSAR Section ( s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed IJ.3 Regulatory Guide 1. 52, 'Ibe ESF atmosphere cleanup Position C.2.j, states that systems are not designed to

          ~F atmosphere cleanup units                   be replaced as intact units be designed and installed in                   or in segmented sections.

a manner that pe111li ts replace-ment of one train as an intact unit or as a minimlnmnber of sections. 11.3 Regulatory Guide 1.140, 'Ibe flow limit of 30,000 cfm Position c.z.a, requires that per filter is exceeded in the flow rate of a single some of the exhaust systems atmosphere cleanup train be of the nonnal ventilation limited to approxi.Jaately systems. 30.000 cfm. 9.4.3 II 9.4.3.6 (Rev 2) Regulatory Guide 1.140, 'lbe a~re cleanup units Position C.2.a, states that in the norq,l ventilation atmosphere cleanup systems exhaust systems do not in-in normal ventilation exhaust clt.d.e all the sequential systems should consist of the caoponents required by fallowing sequential ccapo- Regulatory Guide 1.140. nents: HEPA filters before adsorbers, adsorbers, fans *

        . and interspersed ducts, dampers, and related instruaentation.

19 of 31 Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) Staaary FSAR Section(s) SRP Speoific SRP Description of Where Section Aooeptance Criteria Differences Discussed 9.4.4 II.3 9.4.4.6 (Rev 2) Regulatory Guide 1.140, The atmos]:i1ere cleanup units Position C.2.a, states that in the normal ventilation atmopshere cleanup systems in exhaust systems do not in-normal ventilation exahust cluie all the sequential systems should consist of the components required by following sequential compo- Regulatory Guide 1.140. nents: HBPA filters before adsorbers, adsorbers, fans, and interspersed ducts, dampers, and related insti'UIIelltation. 9.4.5 II.5 9.4.5.6 (Rev 2) Regulatory Guide 1. 52, Demisters are usedonly where Position C.2.a, states that moisture impingement is a ESF at:Dopshere cleanup systems potential problea. HEPA fil-should inoluie d.emsters ters are not provided ahead prior to prefilters and HEPA of adsorbers "WhenIlEPA fil-filters aheadof the ters are normally present adsorbers. upstream of the ESF atmospheric cleanup l.Dlits. 11.5 Regulatory Guide 1. 52, The ESF atmos):ilere cleanup Position C.2.j, states that systems are not designed to ESF atmopshere cleanup mi ts to be replaced as intact be designed and installed in units or in segmented a manner that permitsre- sections. placement of one train as an intact unit or as a minia. ntlllber of sections. II Regulatory Guide 1.140, The flow limit of 30, 000 cfm Position C.2.b, requires per filter is exceeded in that flow rate of single sane of the exhaust systems atmosphere cleanup train of the normal ventilation be limited to approximately systems. 30,000 cfm. 20 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) S'IBDB.rY FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed 9.5.1 II.2 9.5.1.6 (Rev 3) All criteria paragraphs listed hereunder relate to BTP CMEB 9.5-1, Rev 2, 7/81. C.l.c(2) requires that single HOGS complies with this requirement active failure or crack in fire except for the auxiliary building - protection piping should not radwaste/service area, elevator shafts, im:pair both the primary and and machine I'OOIIlS for elevators 11-02 backupfire suppression oapabili ty and 51-01 in the turbine and auxiliary buildings, circulating water pump structure, and the 1 ,000,000-gallon fuel oil storage tank in the yardarea.

c. 4 requires that the quality HCGS complies with this requirement assurance programof the Con- for the fuel oil tank, the fire PJIIIP8 tractors should ensure the and associated controls, the fire guidelines for design, pro- protection water spray systems, the curement, installation, and carbon dioxide systems, and the early testing of the fire protection smokeand detection systems warnill.iC systems for safety related areas in safety related areas. However are satisfied. the qus.li ty assurance program

( 'F' program) was forma.l.ly implemen-ted effective July 1, 1978. In view of that certain fire system components purchased and installed prior to July 1, 1978, such as the fire water storage tanks, the tank heaters and associated controls, and the valve pit heaters are excluded from the 'F' program during the construction~. However, these cauponents will be under the F program after fuel is delivered to the site. C.5.a(l) requires sep:1ration of See FSAR Appendix 9A for redundant divisions or trains description of differences of safety-related systems fran this requirement. 21 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Oont) Surmary FSAR Section ( s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed C.5.a.(3) requires openings for Some openings in fire barriers are not piping, conduit ard cable trays in sealed, i.e., inside non-segregated fire barriers be sealed pmsebus dtcts and openings in turbine operating deck for turbine CIVs. Also see FSAR Appendix9A for additional differences from this requirement. C.5.a.(4) requires that penetration Some penetration openings for openings for ventilation systems ventilation systemsare not in fire barriers be provided with provided with fire dampers. fire dampers. Also see FSAR Appendix 9A for additional differences from this requirement. c.5.a(5) requires door openings HCGS caaplies with this requirement in fire barriers be protected and provides Underwriters' with equivalently rated doors, Laboratories (UL) or Factory Mutual frame and hardware (FM) labeled doors for all openings except for those openingsthat exceed the maximum available UL or FM label doors size. UL Certificate of Inspection is provided for oversize fire doors. C.5.a(8) allows only one Both safety divisions are redundant safety division in one cable spreading roaa. per cable spreadingroaa. C.5.a(13) requires outdoor The transformers are less oil-filled transforaers to than 50 feet from building be located at least 50 feet walls. All walls facing from building walls, or if transformers have fire within 50 feet, adjacent resistance rati.:ng of 2 hours building walls shall have and are not entirely free no openings and have a fire of openings. rating of at least 3 hours. C.5.b. requires one safe shutd<>lm See FSAR A:ppeOOix 9A for train be free of fire damage description of differences by separation of redundant from this requirement. shutd<>lm trains by 3-hour fire barrier or other alternates. 22 of 31 Revision 0 April 11 1 1988

( ( ( TABLE 1.11-1 (Cont) Stmuary FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed C. 5.c. requires one safe shutd.own See FSAR Appendix9A for train be free of fire damage description of difference from this requirement. C.5.e(2) requires redundant See FSAR Apperd.ix 9A safety-related cable system outside for description of differences the cable spreading room to be from this requirement. separated from each other and from potential fire exposure hazards by 3-hour fire barrier or provided automatic water systems. C.5.e(2) requires that Continuous line-type heat redundant safety-related detectors are not provided. cable trays outside the Instead. photoelectric and spreading roomsto be pro- ionization detectors are vided with continuous installed in areaswhere line-type heat detectors. safety-related cable trays are located. C.5.e(2) also requires that Not all safety-related cable safety-related cable trays trays are provided with a shall be protected frail water suppression system. potential exposure to fire by an automatic water suppression system where a fire could occur. Paragra}fl C. 5. f ( 1 ) requires lEGS generally uses normal smoke and corrosive gases to ventilation system to remove be discharged directly outside smoke and gases. A separate and separate smokeand heat smoke systemis provided vents be provided for certain for control area. areas. C.5.g.(3) states that a HCGS has no specific fixed emergency camnuni.ca- emergency COIIIIR.Blication tion system independent of system intended solely the normal plant ooaamica- for emergency situations. tion systembe installed at pre-selected stations. 23 of 31 HCXJS-UFSAR Revision 0 April 11 1 1988

( ( ( TABLE 1.11-1 (Cont) Stmna.ry FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed C.6.a(2) requires that fire Areas required for initial hot detection systems comply shutdown outside the reactor building with NFPA 72D, Class A and most areas of the reactor building, systems. except the new fuel storage area, spent fuel pool, and above the cask loading pit, are provided with a Class A fire detection system. All other Class B fire detection systems. In addition, the operation and supervision of the fire protection system is not the sole function of the plant operator. c.6.a(3) requires that Location of early warning the fire detectors be installed fire and smoke detectors was in accordance with NFPA 72E determined by the detection system vendor. under the direction of a qualified fire protection engineer. C.6.a(6) requires that Secondary power is provided secondary p:>Wer supplies for for motor operated valve, electrically operated control which is disconnected during valves be provided per NFPA 72D. a lOCA. Also the fire detection system is supplied with uninterruptible 120 V ac power. c.6.b(6) requires that Fire punp installation conforms fire pump installation conform to NFPA 20 except the diesel to NFPA 20 fire pump fuel oil day tank is located outside and is subject to freezing, and the waste water line from the diesel fire :ruup heat exchanger is not provided with a open waste cone. Also, the punp test flow meter and test manifold are installed in series in the same test line. C,6.b.(7) requires that hydrants Hydrants are provided on the be installed approximately every yard main, but in some areas 250 feet on the yard main system the distance between hydrants is greater than 250 feet. 24 of 31 JrnS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) S1.mllal'y FSAR Section(s) SRP Specific SRP Where Acceptance Criteria Discussed C.6.b.(9) requires that failure A leak in the fire pump suction in one fire water storage tank pipe and either fire water or its piping should not cause storage tankcould cause both tanksto drain loss of water fromboth tanks. C. 6. b. ( 11) requires that the fire Table 9.5-18 lists the minimum water supply should be calculated and actual hose stream flows on basis of the largest expected available for all hydraulically flow from sprinkler system plus designed sprinkler systems. 500 gpm for hose streams C.6.c.(2) requires that all Administratively controlled, locked valves in the fire protection valves are inspected monthly and water system be periodically electrically supervised valves are checked to verify position not periodically checked because they in accordance with NFPA 26. are constantly monitored. C.6.c. (3) requires that fixed NFPA deviations have been water extinguishing systems identified and evaluated. comply with the apppropriate Significant deviations are NFPA Standard identified in FSAR. C.6.c.(4) requires that interior At HCGS, certain hose stations are fire water hose installations be provided withan add.i tiona! 50 able to rea.c:h any location that feet of hose that is not connected contains or could present a fire and is stored near the fire hose exposure hazard to safety-related station, which will be used to reach equipoent with at least one certain areaswhere 100 foot hoses effective hose stream using a will not rescb. maxiliUD of 100 feet of hose. C.6.c.(4) requires individual HOGS provides 4-inch in standpipes should be at least diameter standpipes feed.ing 4-inches in diameter for multiple hoseconnection, multiple hose connections. but branches off standpipes feeding two or one hose connections are 3-inch in diameter. 25 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) SliJIIla.rY FSAR Section(s) SRP Speci fie SRP Description of Where Section Acceptance Criteria Differences Discussed C.6.C. (4) states that Firewater piping to hose provisions should be made stations and standpipes are to supply water to at least not analyzed for SSE load-standpipes and hose con- ings and no cross-connection nections for manual fire- to a normal Seismic category I fighting in areascontaining water system is provided. equipnent required for safe plant shutdown in the event of an SSE. Pipina serving such hose stations should be analyzed for SSE loadings. C.7.a.(l),(C) requires that No fire protection systems the primary containment are provided in the contain-should be provided with fire ment drywell. detection systemsinchxting backup, general &reat fire detection capability. C.7.b requires that venti- HCGS has fire dampers in the lation openings between return air ducts of the peri-control room and peripheral pheral rooms. rooms shall be provided with automatic BIDDke dampers. c.7.b also requiresperi- No automatic water suppression pheral rooms in the control is provided in peri{ileral room complex to be provided rooms of the main control with automatic water roomcomplex. suppression. C.7.b also requiresthat Smoke detectors are only smoke detectors be provided provided in control room in the control roomcabinets cabinets and consoles that and consoles. include redundant safe shut-doHn equipnent. C.7.c requires primar,y IIC'XJ.9provides an automatic fire suppression in cable carbondioxide in the spreading roombe an control equipnent mezzanine automatic water system. room (cable spreading room) at floor elevation 177 feet

                                                     -6 inches of control area.

A manual water deluge system is provided as a backup. 26 of 31 Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) SUIIIIary FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences C.7.o(2) requires aisle Main access aisles are separation between tray stacks less than 3 feet wide and in cable spreading rocm be 8 feet high in some areas at least 3 feet wide and of cable spreading roans. A 8 feet high. manual water deluge system is provided as backup. C. 7

c ( 5) requires continuous Continuous line-type heat line-type heat detectors for detectors are not provided.

cable trays inside the cable Instead, photoelectric and spreading room. ionization detectors are installed in areaswhere safety-related cable trays are located. C.7.f requires redundant safety- See Appendix 9A for description related panels remote fromthe* of differences from this requirement. control room complex be separated fromeach other by a 3-hour fire barrier. C.?.i requires automatic Inadvertent operation of one fire suppression system for the of the automatic carbon diesel generator areas be dioxide sytems provided for designed for operation when the diesel generator rooms the diesel is rurming without could affect operation rutnot affecting the diesel. affect safe shutdown of the plant. C.7.j requires diesel fuel Two 26 1 500 gallon diesel oil tanks with oapaci ty greater fuel oil tanks are located in than 1, 100 gallons not be each of the four tankl'OClBIS located inside wildings in the auxiliary building - containing safety-related diesel area. Each room is equipnent. surrounded by a 3-hour fire barrier and fire suppression and fire detection is provided for each room. 27 of 31 Revision 0 April 11, 1988

( ( ( TABLE 1.11*1 (Cont) Sl111B8ry FSAR Section(s) SRP Specific SRP Description of Yhere Section Acceptance Criteria Differences Discussed t.7.k. requfres redundant 3-hour fire barriers are safety-related pumpsbe provided to separate redundant separated from each other safety-related trains to the parts of the plant by a extent noted in FSAR Appendix 9A. 3-hour fire barrier. 3*hour fire barriers are not provided to separate safety-related pumpsfrom other parts of the plant unless the fire hazard analysis indicated it is required to meet Appendix R to 10CFR50. C.7.n requires that fire In general fire barriers. barriers. automatic fire sup* automatic fire suppression pression and detection be and detection fs provided provided for the radwaste for the radwaste and and decontamination areas. decontamination areas as indicated by the fire ha1ard analysis. 9.5.8 11.1 9.5.8.6 <Rev 2) Regulatory Gutde 1.117, Projections of the emergency Appendix Positfon 13, re* diesel engine exhaust stacks quires that emergency power above the roof are not systems, including all re* provided with tornado mis* lated auxi l fary systems, be sHe barrfers. protected from the effects of tornado missiles. 11.3 11.8.6 11.3.5 (Rev 2) All gas analyzers shall be Gas analyzers have not nonsparking (Page 11.3*6). specifically been purchased to be nonsparkfng, except devices: OHAAE, AT*5738A1, A2 OHAAE, AT*5739A1, A2 12.2 JI.6 12.2.1 (Rev 2) ANSI N237-1976; typical long GE developed source terms term concentrations of from operating experience. principal radionucl ides in fluid steams. 28 of 31 HCGS-UFSAR Revision 8 September 25, 1996

SRP Specific SRP TABLE l.ll-1 (Cont) SUmmary Description of FSAR Section(sl Where Section Acceptance criteria Differences Discussed 12.3 - 11.17 12.3.4.1.3 12.4 (Rev 2) ANSI/ANS-HPSSG-6.8.1c1981: Location of fixed continuous Criteria for location and area gamma radiation monitors and design of area radia- are not in agreement with tion monitoring systems. this ANSI/ANS standard. I!.4.b.3 Ventilation monitors are to Ventilation monitors are down-be upstream of HEPA filters stream of HEPA filters. II.4.a.3 The area radiation monitors Not all radiation monitors should provide on-scale read- have on-scale reading ranges ings for normal and anticipa- designed to account for post ted operational occurrences accident conditions. and accidents. II.4.a.8 and 4.b.7 Criteria imply that radiation Radiation monitors installed monitoring systems be on at HCGS are not on emergency emergency power. power. II.4.e Compliance to the criteria of Basedupon NRC evaluation of the 10 CPR 70.24 for accidental information presented in the Hope criticality monitor Creek Special Nuclear Material (SNM) License application dated May 23, 1985, PSE&G has been granted exemption to the requirements of 10 CFR 70.24 as documented in Hope Creek SNM License No. 1953 dated August 21, 1985. When the Special Material License expired, the exemption Conditions were incorporated into the operating License in SSER 5. These conditions are specific to GE fuel only. Alternately, 10CFR50.6B can be used to demonstrate compliance with 10CFR70.24. bath of these approaches eliminate the need for instrumentation since criticality is not credible. 29 of 31 HCGS-UFSAR Revision 14 July 26, 2005

( ( ( TABLE 1.11-1 (Cont) StDJDary FSAR Section(s) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed 13.6 II 13.6 (Rev 2) Regulatory Guide 5. 20 sets Security personnel training requirements for security program will be based on personnel training program. Appendix B to 10 em Part 73, to the extent applicable to power reactors. 14.2 II 14.2.13.1, 2, 3, (Rev 2) 4, and 5 Conformance to Regulatory Nonconformance, in part, Guides 1.68, 1.20, 1.56, with Regulatory Guides1.68, 1.68.3 and 1.10.8 {Page 1.20, 1.56, 1.68.3 and 1.108. 14.2-3, 4) 15.3.3 - II.lO 15.3.4.6 15.3.4 (Rev 1) Assunptions for coolant PlJD.PB Turbine trip with coincidental rotor seizure and coolant loss of offsite power and punp shaft break accident. coast down of undamaged p:mps is not assumed. 15.8 II. a 15.8.4 {Rev 1) Application of one 10 to the GDC 10 is not applied. ATWS event. II.b Application of GOC 15 to the GDC 15 is not applied. ATWS event. I I.e Application of GOC 26 to the one 16 is not applied. ATWS event. II.d Application of one 27 to the GDC 27 is not applied. ATWS event. 30 of 31 HCGS-UFSAR Revision 0 April 11, 1988

( ( ( TABLE 1.11-1 (Cont) Sumary FSAR Section ( s ) SRP Specific SRP Description of Where Section Acceptance Criteria Differences Discussed I I.e Application of GDC 29 to the GDC 29 is not applied. AT'WS event. II.f Criteria of NUREG-0460, Criteria j of NUREG-0460, Vol. 2, Section IV-4 apply Vol. Z, Section IV-4 is to BWR RPl'. not applied. 31 of 31 Revision 0 April 11, 1988

1.12 UNRESOLVED GENERIC SAFETY ISSUES 1.12.1 Introduction The Nuclear Regulatory Commission (NRC) continuously evaluates the safety requirements used in its reviews against new information as it becomes available. Information related to the safety of nuclear power plants comes from a variety of sources, including experience from operating reactors; research results; NRC staff and Advisory Committee on Reactor Safeguards (ACRS) safety reviews; and vendor, architect/engineer, and utility design reviews. Each time a new concern or sa:fety issue is identified from one or more of these sources, the need for immediate action to ensure safe operation is assessed. This assessment includes consideration of the generic implications of the issue. In some cases, immediate action is taken to ensure safety, e.g., the derating of boiling water reactors as a result of the channel box wear problems in 197 5. In other cases , interim measures, e.g. , modifications to operating procedures, may be sufficient to allow further study of the issue before making licensing decisions. In most cases, however, the initial assessment indicates that immediate licensing actions or changes in licensing criteria are not necessary. In any event, further study may be deemed appropriate to make judgments as to whether existing NRC requirements should be modified to address the issue for new plants or if backfi tting is appropriate for the long-term operation of plants already under construction or in operation. These issues are sometimes called generic safety issues, because they are related to a particular class or type of nuclear facility rather than to a specific plant. Certain of these issues have been designated as unresolved safety issues in NUREG-0410, NRC Program for the Resolution of Generic Issues Related to Nuclear Power Plants, dated January 1, 1978. However, as discussed above, such issues are considered on a generic basis only after the NRC staff has made an initial determination that the safety significance of 1.12-1 HCGS-UFSAR Revision 0 April 11, 1988

the issue does not prohibit continued operation, or require licensing actions while the longer-term generic review is underway. In 1978, the NRC undertook a review of over 130 generic issues addressed in the NRC program. The review is described in a report, NUREG-0510, Identification of Unresolved Safety Issues Relating to Nuclear Power Plants -A Report to Congress, dated January 1979. The report provides the following definition of an unresolved safety issued: An unresolved safety issue is a matter affecting a number of nuclear power plants that poses important questions concerning the adequacy of existing safety requirements for which a final resolution has not yet been developed and that involves conditions not likely to be acceptable over the lifetime of the plant it affects. Furthermore, the report indicates that, in applying this definition, matters that .pose "important questions concerning the adequacy of existing safety requirements" were judged to be those for which resolution is necessary either to compensate for a possible major reduction in the degree of protection of the public health and safety, or to provide a potentially significant decrease in the risk to the public health and safety. Quite simply, an unresolved safety issue is potentially significant from a public safety standpoint and its resolution is likely to result in NRC action on the affected plants. All of the issues addressed in the NRC program were systematically evaluated against this definition, as described in NUREG-0510. As a result, 17 unresolved safety issues addressed by 22 tasks in the NRC program were identified. The issues and applicable task numbers are listed below. Progress on these issues was first discussed in the 1978 NRC Annual Report. Each number of each generic task, e.g., A-1, in the NRC program addressing each of the 17 issues, is indicated in parentheses following the title: 1.12-2 HCGS-UFSAR Revision 0 April 11, 1988

1. Waterhammer (A-1)

2. Asymmetric blowdown loads on the Reactor Coolant System

{A-2)

3. Pressurized water reactor steam generator tube integrity (A-3, A-4, A-5)

4. BWR Mark I and Mark II pressure suppression containments

{A-6, A-7, A-8, A-39)

5. Anticipated transients without scram (A-9)

6. BWR nozzle cracking (A-10)

7. Reactor vessel materials toughness (A-ll)

8. Fracture toughness of steam generator and reactor coolant pump supports (A-12)

9. Systems interaction in nuclear power plants (A-17)

10. Environmental qualification of safety-related electrical equipment (A-24)

11. Reactor vessel pressure transient protection (A-26)

12. Residual heat removal requirements (A-31)

13. Control of heavy loads near spent fuel (A-36)

14. Seismic design criteria (A-40)

15. Pipe cracks at boiling water reactors (A-42)

16. Containment emergency sump reliability (A-43) 1.12-3 HCGS-UFSAR Revision 0 April 11, 1988

17. Station blackout (A-44).

Six of the 22 tasks identified with the unresolved safety issues are not applicable to Hope Creek Generating Station (HCGS), because they apply to pressurized water reactors only. These tasks are A-2, A-3, A-4, A-5, A-12, and A-26. Task A-8 only applies to Mark II boiling water reactor (BWR) containments. With regard to the remaining 15 tasks that are applicable to HCGS, the NRC staff has issued NUREG reports providing its resolution of eight of the issues. These issues are as follows: Task Number NYREG Report No. and Title A-6 NUREG-0408, Mark I Containment Short-term Program Safety Evaluation Report A-9 NUREG-0460, Vol 4, Anticipated Transients Without Scram for Light Water Reactors A-10 NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking A-24 NUREG-0588, Revision 1, Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment A-31 NUREG-0800, SRP 5.4.7 and BTP 5-l, Residual Heat Removal Systems (incorporate requirements of US! A-31) A-36 NUREG-0612, Control of Heavy Loads at Nuclear Power Plants A-39 NUREG-0661 Mark I Containment Long-Term Program Safety Evaluation Report 1.12-4 HCGS-UFSAR Revision 0 April 11, 1988

Task Number NUREG Report No. and Title A-42 NUREG-0313, Revision 1, Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping. The extent of implementation of these guidelines into the HCGS design is demonstrated by discussions in the following sections:

1. Appendix 3B - On the primary containment analysis (A-6),

(A-39)

2. Section 3.11 .. On environment design of mechanical and electrical equipment (A-24)

3. Section 4.6.1.2.4

On the control rod drive hydraulic system (A-10) General Electric, Boiling Water Reactor Feedwater Nozzle/Sparger Final Report, NEDE-21821-02, August 1979

4. Section 5.2.3 - On RCPB materials (A-42)

5. Section 5.4.7 -On residual heat removal (A-31)

6. Section 9 .1. 5 - On the handling of overhead heavy loads (A-36)

7. Section 15.8

On anticipated transient without scram (A-9).

The remaining issues applicable to HCGS are:

1. Waterhammer (A-1)

2. Mark I containment long term program (A-7)

3. Reactor vessel materials toughness (A-ll) 1.12-5 HCGS-UFSAR Revision 0 April 11, 1988

4. Systems interaction in nuclear power plants (A-17)

5. Seismic design criteria (A-40)

6. Containment emergency sump reliability (A-43)

7. Station blackout (A-44).

1.12.2 New Unresolved Safety Issues The NRC has performed an in*depth and systematic review of generic safety concerns identified since January 1979 to determine if any of these issues should be designated as new unresolved safety issues. The candidate issues originated from concerns identified in NUREG-0660, titled NRC Action Plan as a Result of the TMI-2 Accident; ACRS recommendations; abnormal occurrence reports; and other operating experience. The NRC considered the above information and approved the following four new unresolved safety issues:

1. Shutdown decay heat removal requirements (A-45)

2. Seismic qualification of equipment in operating plants (A-46)

3. Safety implication of control systems (A-47)

4. Hydrogen control measures and effects of hydrogen burns on safety equipment (A-48).

A description of the above process, together with a list of the issues considered, is presented in NUREG-0705, Identification of New Unresolved Safety Issues Relating to Nuclear Power Plants, Special Report to Congress, dated March 1981. An expanded discussion of each of the new unresolved safety issues is also contained in NUREG-0705. 1.12-6 HCGS-UFSAR Revision 0 April 11, 1988

Recently, Task A-49, Pressurized Thermal Shock, was identified as an unresolved safety issue. Although the NRC staff has not determined the extent of this issue, it is not expected to affect boiling water reactors (BWRs). 1.12.3 Discussions of Tasks as They Relate to HCGS This section provides HCGS evaluation of each applicable unresolved safety issue. 1.12.3.1 Task A-1. Waterhammer

1. Issue - Waterhammer events are intense pressure pulses in fluid systems caused by any one of a number of mechanisms and system conditions, such as rapid condensation of steam pockets, steam-driven slugs of water, pump startup with partially empty lines, and rapid valve motion. Since 1971, over 200 incidents involving waterhammer in pressurized and boiling water reactors have been reported. The waterhammers (or steam hammers) have involved steam generator feedrings and piping; the Residual Heat Removal (RHR) Systems; Emergency Cor~ Cooling Systems (ECCS); and containment spray, service water, feedwater, and steam lines.

Most of the damage reported has been relatively minor, involving pipe hangers and restraints; however, several waterhammer incidents have resulted in piping and valve damage. The most serious waterhammer events have occurred in the steam generator feedrings of pressurized water reactors. In no case has any waterhammer incident resulted in the release of radioactive material. Under generic Task A-1, the potential for waterhammer in various systems is being evaluated and appropriate requirements and systematic review procedures are being developed to ensure that waterhammer is given appropriate 1.12-7 HCGS-UFSAR Revision 0 April 11, 1988

consideration in all areas of licensing review. A technical report, NUREG-0582, Waterhammer in Nuclear Power Plants (July 1979), providing the results of an NRC staff review of waterhammer events in nuclear power plants and stating current staff licensing positions, completes a major subtask of generic Task A-1.

2. HCGS discussion - Although waterhammer can occur in any light water reactor, and approximately 118 actual and probable events have been reported in boiling water reactors (BWRs) as of September 1979, none has caused major pipe failures in a BWR such as HCGS, and none has resulted in the offsite release of radioactivity. As noted above, the most severe waterhammers observed to date have been in steam generators. The HCGS feedwater design includes the relevant design provisions that have been effective in eliminating the occurrence, and lessening the severity of, waterhammer in PWRs. The HCGS feedwater ring is designed to incorporate use of only short horizontal runs of feedwater pipe into the reactor pressure vessel and use of J-tubes.

Furthermore, any waterhammer that may occur in feedwater or main steam piping will not impair the ECCS, because ECCS water can enter the reactor vessel through six separate reactor vessel nozzles independent of the feedwater and main steam piping. To protect the HCGS ECCS from the effects of waterhammer, there is an ECCS discharge line fill network whose pumps take suction from the suppression pool or the condensate storage tank (CST), and provide water to the ECCS injection lines. This ensures that the ECCS lines remain filled with water, the ECCS pumps will not start pumping into voided lines, and steam will not collect in the ECCS piping. 1.12-8 HCGS-UFSAR Revision 0 April 11, 1988

Piping design codes require consideration of impact loads. A systematic review of all safety and nonsafety systems has been performed. Where waterhammer problems were identified, design refinements were implemented to address the specific problem. Some of the design refinements incorporated to address waterhammer are listed below:

a. Increasing valve closure times

b. Changing piping layout to preclude water slugs in steam lines and vapor formation in water lines

c. Adding snubbers and pipe hangers

d. Using vents and drains

e. The use of accumulators.

For specific discussion of the ECCS discharge line fill network, see Section 6.3.2.2.6. In the event that Task A-1 identifies potentially significant waterhammer scenarios that have not been accounted for explicitly in the design and operation of HCGS, corrective measures will be implemented at that time. The task has not identified the need for measures beyond those already implemented. Based on the foregoing, PSE&G concludes that HCGS can be operated without undue risk to the health and safety of the public. 1.12.3.2 Task A-7. Mark I Containment Lons-Term Prosram

1. Issue - During the conduct of a large scale testing program for an advanced design pressure suppression containment system (Mark III) for BYR.s, new suppression 1.12-9 HCGS-UFSAR Revision 0 April 11, 1988

pool hydrodynamic loads associated with a postulated loss-of*coolant accident (LOCA) were identified that had not been explicitly included in the original design of the Mark I containment systems. In addition, experience at operating plants has indicated that the dynamic effects of safety/relief valve (SRV) discharges to the suppression pool could be substantial and should be reconsidered. The results of the Mark I containment short-term program (STP) have ensured that for a "most probable load" the Mark I containment system of each operating BWR facility would maintain its integrity and functional capability during a postulated LOCA. The need exists both to establish design basis LOCA loads that are appropriate for the life of the facility, and either to restore the originally intended design safety margins for the containment systems or to ensure that adequate design safety margins have been provided in the design of the containment system prior to issuance of an operating license. The Mark I Owner's Group has initiated a comprehensive testing and evaluation program to define design basis loads for the Mark I containment system and to establish structural acceptance criteria that will ensure margins of safety for the containment system that are equivalent to those currently specified in the ASME B&PV Code. Also included in their program is an evaluation of the need for structural modifications and/or load mitigation devices to ensure adequate Mark I containment system structural safety margins. The NRC staff will evaluate the loadst load combinations, and associated structural acceptance criteria proposed by the Mark I Owner's Group prior to the conduct of plant-unique structural evaluations. The results of this evaluation will be documented in a generic safety 1.12-10 HCGS-UFSAR Revision 0 April 11, 1988

evaluation report. Publication of this report will constitute the resolution of this technical activity . Implementation of the results of this generic review. although not a part of this task, will be accomplished by an NRC requirement that each affected utility perform. a plant unique 4 structural evaluation of the containment

          'system    for    their   facility   using    the   loads,    loading combinations, and structural acceptance criteria approved by the NRC staff.

2. HCGS discussion - At HCGS, this unresolyed safety issue is considered complete. HCGS is proceeding according to the guidelines of NUREG-0661. For discussion of the primary containment plant unique analysis, see Appendix 3B.

Therefore, PSE&G concludes that HCGS can be operated without undue risk to the health and safety of the public . 1.12.3.3 Task A-11. Reactor Vessel Materials Toughness

1. Issue Resistance to brittle fracture is described quantitatively by a material property generally denoted as fracture toughness. Fracture toughness has different values and characteristics depending on the material being considered. For steels used in a nuclear reactor pressure vessel (RPV), three considerations are important:

a. Fracture toughness increases with increasing temperature

b. Fracture toughness decreases with increasing load rates

c. Fracture toughness decreases with neutron irradiation .

HCGS-UFSAR Revision 0 April 11, 1988

In recognition of these considerations, power reactors are operated within restrictions imposed by the Technical Specifications on the pressure during heatup and cooldown operations. These restrictions ensure that the reactor vessel will not be subject to a combination of pressure and temperature that could cause brittle fracture of the vessel if there were significant flaws in the vessel material. The effect of neutron radiation on the fracture toughness of the vessel material over the life of the plant is accounted for in Technical Specification limitations. The principal objective of Task A-ll is to develop safety criteria to allow a more precise assessment of safety margins during normal operation, transients, and accident conditions in older reactor vessels with marginal fracture toughness. When Task A-ll is completed and explicit fracture evaluation criteria for accident conditions are defined, all vessels will be reevaluated for acceptability over their design lives.

2. HCGS discussion - Based on its evaluation of the HCGS reactor vessel materials toughness, PSE&G concludes that adequate safety margins exist for brittle failure for postulated accidents throughout HCGS's design life.

A major condition necessary for full compliance to 10CFR50, Appendix G, is satisfaction of the requirements of the Summer 1972 addenda to ASME B&PV Code, Section III. As explained in Section 5. 3 .1. 5, this is not entirely possible with components that were purchased to earlier code requirements. The extent of compliance is discussed in Appendix SA. Compliance with the toughness requirements described in Appendix SA and the operating limitations on pressure and temperature based on fracture margins in Appendix G assure adequate safety margins 1.12*12 HCGS-UFSAR Revision 0 April 11, 1988

against brittle fracture. The extent of compliance to 10CFRSO, Appendix H, is also discussed in Appendix SA . Therefore, PSE&G concludes that HCGS can be operated without undue risk to the health and safety of the public. 1.12.3.4 Task A-17. Systems Interaction in Nuclear Power Plants

1. Issue The staff's systems interaction program was initiated in May 1978 with the definition of unresolved safety issue A-17, System Interaction in Nuclear Power Plants, and was intensified by TMI Action Plan (NUREG-0660) Item II.C.3, Systems Interaction. The concern arises because the design, analysis, and installation of systems are frequently the responsibility of teams of engineers with functional specialities such as civil, electrical, mechanical, or nuclear. Experience at operating plants has led to questions of whether the work of these functional specialists is sufficiently integrated to enable them to minimize adverse interactions among systems. Some adverse events that occurred in the past might have been prevented if the teams had ensured the necessary independence of safety systems under all conditions of operation.

I

2. HCGS discussion - The NRC staff's current procedures assign primary responsibility for review of various technical areas to specific organizational units and assign secondary responsibility to other units where there is a functional interface. Designers follow somewhat similar procedures and provide the analyses of systems and interface reviews. Task A-17 has been developing methods that could identify adverse systems interactions that were not considered by current review procedures. The first phase of this study began in May 1978, and was completed in February 1980, by Sandia Laboratories under contract to the NRC staff .

HCGS-UFSAR Revision 0 April 11, 1988

The phase I investigation was structured to identify areas where interactions are possible between systems that have the potential of negating or seriously degrading the performance of safety functions. The study concentrated on commonly caused failures among systems that would violate a safety function. The investigation was to then identify those areas in which NRC review procedures may not have properly accounted for these interactions. The Sandia Laboratories used fault~tree analysis on a selected light water reactor (LWR) design to identify component failure combinations, cut sets, that could result in loss of a safety function. The cut sets were further reduced by incorporating six linking systems failures into the analysis. The results of the Sandia effort indicated a few potentially adverse systems interactions within the limited scope of the study. The staff reviewed the interactions for safety significance and generic implications. The staff concluded that no corrective measures needed to be implemented immediately, except for the potential interaction between the power~operated relief valve and its block valve. This interaction had been separately identified by the evaluations of the TMI*2 accident while Sandia was studying the selected L'WR. Because corrective measures were already being implemented, no separate measures were needed under unresolved safety issue A~l7. NUREG*0660 provides for a systems interaction study in Item II.C.3, Systems Interactions. Since April 1980, the Office of Nuclear Reactor Regulation has intensified the effort both by broadening the study of methods to identify potential systems interactions and by preparing guidance for audit reviews of selected plants for systems interactions. 1.12-14 HCGS-UFSAR Revision 0 April 11, 1988

It is expected that the development of systematic ways to identify, rank, and evaluate systems interactions will go further to reduce the likelihood of intersystem failures, resulting in the loss of plant safety functions. A comprehensive program is expected to use analytical methods, visual inspections, experience feedback, and simulator dependencies experiments. The LWR industry's current experience with systems interaction reviews is fragmented. Experience like that gained by the Phase I study is an essential ingredient to the staff's considerations of a comprehensive systems interaction program. The design of HCGS is based on the principle of defense in depth. Adherence to this principle results in requirements such as physical separation and independence of redundant safety systems, and protection against hazards such as high energy line ruptures, missiles, high winds, flooding, seismic events, fires, human factors, and sabotage. These design provisions are subject to interdisciplinary reviews of safety-grade equipment and address different types of potential systems interactions. Also, the quality assurance program that is followed during the design, construction, and operational phases for HCGS contributes to the prevention of introducing adverse systems interactions. Interdisciplinary reviews and the HCGS quality assurance program provide assurance that HCGS can be operated without undue risk to the health and safety of the public. 1.12.3.5 Task A-40. Seismic Desien Criteria/Short Term Proeram

1. Issue - NRC regulations require that nuclear power plant structures, systems, and components important to safety be designed to withstand the effects of natural phenomena such as earthquakes. Detailed requirements and guidance regarding the seismic design of nuclear plants are 1.12 .. 15 HCGS-UFSAR Revision 0 April 11, 1988

provided in the NRC regulations and in regulatory guides issued by the NRC. However, there are a number of plants with construction permits and operating licenses issued before the NRC's current regulations and regulatory guidance existed. For this reason, reviews of the seismic design of various plants are being undertaken again by the NRC to ensure that these plants do not present an undue risk to the public. Task A-40 is, in effect, a compendium of short term efforts to support such reevaluation efforts of the NRC staff, especially those related to older operating plants. Should the resolution of Task A-40 indicate that a change is needed in these licensing requirements, all reactors, including HCGS, will be reevaluated on a case-by-case basis.

2. HCGS discussion - The seismic design basis and seismic design of HCGS are in accordance with current requirements and regulations as discussed in Section 3.

Accordingly, PSE&G has concluded that HCGS can be operated without undue risk to the health and safety of the public. 1.12.3.6 Task A-43. Containment Emergency Sump Reliability

1. Issue - Following a postulated LOCA, that is, a break in the Reactor Coolant System (RCS) piping, the water flowing from the break would be collected in the suppression pool.

This water would be recirculated through the reactor system by the emergency core cooling pumps to maintain core cooling. This water may also be circulated through the Containment Spray System to remove heat and fission products from the drywell and wetwell atmosphere. Loss of the ability to draw water from the suppression pool could disable the emergency cooling and containment spray systems. 1.12-16 HCGS-UFSAR Revision 0 April 11, 1988

2. HCGS discussion - The concern addressed by this task for BWRs is limited to the potential for degraded Emergency Core Cooling System (ECCS) performance as a result of thermal insulation debris that may be blown into the suppression pool during a LOCA and cause blockage of the pump suction lines.

The likelihood of any insulation being drawn into an ECCS pump suction line is very small, as discussed in section 6.2.2.2. The potential debris in the drywell could only be swept into the suppression pool through the downcomer openings, which are covered by deflector plates. Most pieces reaching the pool would tend to either float to the surface or settle on the bottom, and would not be drawn into the pump suction, because the suction centerline is above the pool bottom and below the pool surface. In addition, the HCGS design employs strainers on the suction piping, and net positive suction head calculations for the pumps are based on 50 percent blockage. A second concern, potential vortex formation, is not considered serious for Mark I containments because of the depth of the ECCS suction lines, the low approach velocities, and the strainer configuration. Accordingly, PSE&G concludes that HCGS can be operated without undue risk to the health and safety of the public. 1.12.3.7 Task A-44, Station Blackout Task A-44, Station Blackout was resolved by the NRC by issuance of an amendment to Title 10 of the Code of Federal Regulations on July 21, 1988. This amendment added Section 10 CFR so. 63, "Loss of All Alternating Current Power,** (Station Blackout} to the code of Federal Regulations. conformance to 10 CFR 50.63 is discussed in Section 1.15.1 *

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1.12.3.8 Task A-45. Shutdown Decay Heat Removal Requirements

1. Issue .. Following a reactor shutdown, the radioactive decay of fission products continues to produce heat (decay heat) that must be removed from the primary system. The principal means for removing this heat in a BWR while at high pressure is by means of the steam lines to the main condenser. The condensate is normally returned to the reactor vessel by the feedwater system; in addition, the steam turbine driven RCIC system is provided to maintain primary system inventory if ac power is not available.

           "When the system is at low pressure, the decay heat is removed by the Residual Heat Removal (RHR) System.           This unresolved safety       issue will   evaluate the benefit of providing alternate means of decay heat removal, which could substantially increase the plant's capability to handle a broader spectrum of transients and accidents.

The study will consist of a generic system evaluation and will result in recommendations regarding: 1) the desirability of and possible design requirements for improvements in existing systems, or 2) an alternative decay heat removal method if the improvement or alternative can significantly reduce the overall risk to the public. Following the TMI-2 accident, the industry performed and documented extensive analyses of feedwater transients and small break LOCAs to support acceptability of current designs. A report of these analyses for GE BWR.s was provided to the NRC in NED0-24708A, Revision 1, dated December 1980. The staff's assessment of current designs related to loss of feedwater transients and small LOCAs is contained in NUREG-0626, Generic Evaluation of Feewater Transients and Small Break Loss-of-Coolant Accidents in GE-Designed Operating Plants and Near-Term Operating License Applications . 1.12-21 HCGS-UFSAR Revision 0 April 11, 1988

2. HCGS discussion The HCGS reactor has various methods for M

removal of decay heat. As discussed above, when the reactor is at high pressure and temperature, decay heat is normally rejected to the main condenser and condensate returned to the vessel by the feedwater system. At lower temperatures and pressures, the RHR system is used in the shutdown cooling mode, which consists of two virtually redundant loops. If the main condenser is unavailable, heat can be removed by means of the main steam safety/relief valves (SRVs) to the suppression pool. The suppression pool can then be cooled by using redundant loops of the RHR system in the suppression pool cooling mode. The RCIC system, which is a safety grade Engineered Safety Feature (ESF) System, provides an alternative means of supplying makeup water to the vessel. The turbine driven pump in the RCIC system takes suction from the condensate storage tank or suppression pool and pumps to the vessel. The HPCI system is provided in the unlikely event that the RCIC system is unavailable. Another alternative for cooling and supplying makeup water is to manually open the Automatic Depressurization System (ADS) valves and to use the RHR system. Two of the four RHR loops are available for use in the suppression pool cooling mode and two of the four loops are available to pump water into the reactor vessel. Only one loop is required for pumping water into the reactor and only one for suppression pool cooling. The other two loops are redundant. In addition, any one of the four core spray pumps can be used to pump water into the vessel, allowing the. RHR system to be used exclusively in the suppression pool cooling mode. 1.12-22 HCGS-UFSAR Revision 0 April 11, 1988

See Sections 5.4. 7 and 15.9. 6. 3. 3 for further discussion of decay heat removal failure modes . On the basis of the above considerations, PSE&G has concluded that HCCS can be operated before the ultimate resolution of this generic issue without undue risk to the health and safety of the public. 1.12.3.9 Task A-46. Seismic Qualification of Equipment in Operatins Plants

1. Issue .. The design criteria and methods for the seismic qualification of mechanical and electrical equipment in nuclear power plants have undergone significant change during the course of the commercial nuclear power program.

Consequently, the margins of safety provided in existing equipment to resist seismically induced loads and perform the intended safety functions may vary considerably. Therefore, the seismic qualification of the equipment in operating plants must be reassessed to ensure the ability to bring t~e plant to safe shutdown conditions when subject to a seismic event. The objective of this unresolved safety issue is to establish an explicit set of guidelines that could be used to judge the adequacy of the seismic qualification of mechanical and electrical equipment at all operating plants instead of attempting to backfit current design criteria for new plants. This guidance will concern equipment required to safely shut down the plant, as well as equipment whose function is not required for safe shutdown but whose failure could result in adverse conditions that might impair shutdown functions.

2. HCGS discussion

HCGS is designed using current seismic design criteria, as discussed in Section 3. All HCGS systems, components, and equipment related to plant safety are designed to withstand safe shutdown and operating 1.12-23 HCGS-UFSAR Revision 0 April 11, 1988

basis seismic events. Therefore, PSE&G has concluded that HCGS can be operated without undue risk to public health and safety. 1.12.3.10 Task A*4Z. Safety Implications of Control Systems

1. Issue - This issue concerns the potential for transients or accidents being made more severe as a result of control system failures or malfunctions. These failures or malfunctions may occur independently or as a result of the accident or transient under consideration. One concern is the potential for a single failure, such as loss of a power supply, short circuit, open circuit, or sensor failure to cause simultaneous malfunction of several control features. Such an occurrence could conceivably result in a transient more severe than those transients analyzed as anticipated operational occurrences. A second concern is for a postulated accident to cause control system failures that would make the accident more severe than analyzed. Accidents could conceivably cause control system failures by creating a harsh environment in the area of the control equipment or by physically damaging the control equipment. Although it is generally believed that such control system failures would not lead to serious events or result in conditions that safety systems cannot safely handle, in-depth studies have not been rigorously performed to verify this belief. The potential for an accident that would affect a particular control system, and effects of the control system failures, may differ from plant to plant. Therefore, it is not possible to develop generic answers to all of these concerns; it is possible to develop generic criteria that can be used for future plant specific reviews. The purpose of this unresolved safety issue is to verify the adequacy of existing criteria for control systems or propose additional generic criteria, if necessary, that will be used for plant-specific review.

1.12-24 HCGS-UFSAR Revision 0 April 11, 1988

2. HCGS discussion The HCGS safety systems have been designed with the goal of ensuring that control system failures will not prevent automatic or manual initiation and operation of any safety system equipment required to trip the plant or to maintain the plant in a safe shutdown condition following any anticipated operational occurrence or accident. This has been accomplished by providing both independence between safety and nonsafety grade systems and isolating devices between safety and nonsafety grade systems. These devices preclude the propagation of nonsafety grade system equipment faults so that operation of the safety grade system equipment is not impaired.

The subtask of this issue concerning the reactor overfill transient in boiling water reactors is currently under review by the BWR Owner's Group, of which PSE&G is a member. Pending ultimate resolution of this item, PSE&G has incorporated, in the HCGS design, a high level trip (Level 8) of the RCIC, _and feedwater systems to prevent the occurrence of overfill transients. On the basis of the above considerations, PSE&G has concluded that there is reasonable assurance that HCGS can be constructed and operated without undue risk to the health and safety of the public. 1.12.3.11 Task A-48. Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equipment

1. Issue - Following a LOCA in an LWR plant, combustible gases, principally hydrogen, may accumulate inside the primary reactor containment as a result of the following:

a. Metal water reaction involving the fuel element cladding 1.12-25 HCGS-UFSAR Revision 0 April 11, 1988

b. The radiolytic decomposition of the water in the reactor core and the containment sump

c. The corrosion of certain construction materials by the spray solution

d. Any synergistic chemical, thermal, and radiolytic effects of post-accident environmental conditions on containment protective coating systems and electric cable insulation.

Because of the potential for significant hydrogen generation as the result of an accident, 10CFR50.44, Standards for Combustible Gas Control System in Light Water Cooled Power Reactors, and CDC 41, Containment Atmosphere Cleanup, in Appendix A to 10CFRSO, require that systems be provided to control hydrogen concentrations in the containment atmosphere following a postulated accident, to ensure that containment integrity is maintained. Regulation 10CFR50.44 requires that the combustible gas control system provided be capable of handling the hydrogen generated as a result of degradation of the ECCS, so that the hydrogen release is five times the amount calculated in demonstrating compliance with 10CFR50.46, or the amount corresponding to reaction of the cladding to a depth of 0.00023 in .* whichever amount is greater. The accident at TMI-2 on March 28, 1979 resulted in hydrogen generation well in excess of the amounts specified in 10CFR50.44. As a result of this, it became apparent to the NRC that specific design measures are needed for handling larger hydrogen releases, particularly for small, low pressure containments. As a result, the NRC determined that a rulemaking proceeding should be undertaken to define the manner and extent to which 1.12-26 HCGS-UFSAR Revision 0 April 11, 1988

hydrogen evolution and other effects of a degraded core need to be taken into account in plant design. An advance notice of this rulemaking proceeding on degraded core issues was published in the Federal Register on October 2, 1980. Recognizing that a number of years may be required to complete this rulemaking proceeding, a set of short term or interim actions relative to hydrogen control requirements was developed and implemented. These interim measures were described in a second October 2, 1980, Federal Register notice.

2. HCGS discussion HCGS is committed to inerting the primary containment with nitrogen gas during power operation in order to preclude hydrogen burning, as discussed in Section 6. 2. 5. To I

ensure that the hydrogen concentration in the primary containment is maintained below the lower flammability limit, a combustible gas analyzer subsystem is provided as part of the containment atmospheric control .system. The results of PSE&G's evaluation indicate that HCGS can be operated without undue risk to the public health and safety. 1.12-27 HCGS-UFSAR Revision 15 October 27, 2006

1.13 SYMBOLS AND TERMS 1.13.1 Text Acronyms Acronyms used throughout the Final Safety Analysis Report (FSAR) are listed in Table 1.13-1. 1.13.2 Logic Symbols Logic symbols used on functional control diagrams (FCD) are shown in Figure 1.13-2. 1.13.3 Piping Identification Piping is identified on the piping and instrumentation diagrams (P&IDs) by a three group identifier where the first group is the nominal pipe size in inches; the second is a three letter group for the pipe class; and the third is a three digit group sequentially assigned within a pipe class. Example: 6" HBD 116 Size ------------------------------------- Class ------------------------------------------- Sequence ---------------------------------------------- The three letter group for the pipe class is described in detail in Table 1.13-2. The three digit sequence number is assigned consecutively from 001 to 999. 1.13-1 HCGS-UFSAR Revision 0 April 11, 1988

Line identification, for lines other than those of a major system on a P&ID, is shown with the applicable system designation preceding the line identification, e.g., AF-6"-HBD-116. In some cases, this identifier is preceded by a 0 or 1 to indicate Common or Unit 1, respectively. 1.13.4 Valve Identification All manual and remotely operated valves have unique identification numbers for tracking purposes and are shown in the P&IDs. Listed below are the numbering systems used for each group of valves. Self-actuated devices and solenoid valves are identified as shown on Plant Drawing M-00-0. All other valves, including those which have a General Electric (GE) Master Parts List (MPL) number and those valves supplied by vendors as part of an equipment package and not installed by Bechtel, are identified by the prefix letter "V" followed by a three digit sequence number. In some cases, this identifier is preceded by a 1 or 0 to indicate Unit 1 or Common, respectively. Remote operated valves that do not have a GE MPL number are also identified by the two-letter prefix HV- followed by a three or four digit sequence number. Those valves in GE's MPL are identified by the two-letter prefix HV followed by the GE valve number, e.g., HV-F055. Valve identification, for valves other than those of the major system on a P&ID, is shown with the applicable system designator preceding the valve number, e.g., AP-V126. Valve types are indicated on Plant Drawing M-00-0. Valves that are not numbered are supplied as part of a vendor mounted equipment package are identified in the vendor's operation and maintenance manuals. This is done to avoid duplication in numbering these valves. 1.13-2 HCGS-UFSAR Revision 20 May 9, 2014

1.13.5 Equipment Numbering and Location Equipment is identified on the P&IDs by a four group identifier as discussed below: Example: 1 A - P 101 Unit number ------------------------------------------ 1 - Unit 1 Number of items ------------------------------------------ (lettered alphabetically if more than one item; a zero (0) is used if only one item) Equipment classification ------------------------------------- (See description below) Sequence number --------------------------------------------------- (See description below) Equipment classification is identified by type as follows: A 7.2-kV or 4.16-kV switchgear (NA=test station) B 480 V unit substation, MCC or distribution panel C Control boards D DC equipment E Heat exchangers F Filters and cleaning equipment 1.13-3 HCGS-UFSAR Revision 0 April 11, 1988

FH Fuel handling equipment G Generators (turbine, diesel) and associated equipment H Hoists, cranes HC Hose rack in cabinet (H2O) HO Hose reel (CO2) (CO2 hose reels are removed from the plant) HR Hose reel (H2O) J 120 V ac instrument power distribution panels K Air compressors, chiller compressors L Lighting panels N Local control station P Pumps R Equipment in switchyard S Miscellaneous T Tanks and pressure vessels U Hydraulic control units V Air conditioning units, ventilation fans and exhausters, process fans and blowers. VE HVAC heat exchangers, unit heaters VH HVAC ventilation housing, air handling units 1.13-4 HCGS-UFSAR Revision 22 May 9, 2017

W Electrical penetrations X Transformers Y 120 V ac power distribution panels Z Computer equipment The three digit sequence number is assigned consecutively to identify specific equipment as follows: 000-099 NSSS local panels and racks 100-199 Turbine Building 200-299 Reactor Building 300-399 Auxiliary Building, radwaste area 400-499 Auxiliary Building, control and diesel areas 500-599 Miscellaneous locations - outside power block 600-649 NSSS control room panels (except 642 & 643) 650-749 Balance of plant (BOP) control room panels (including 642 & 643) 800-899 Annunciator panels (corresponds to 600 series panels) 900-999 Miscellaneous locations inside power block 1.13-5 HCGS-UFSAR Revision 10 September 30, 1999

1.13.6 Electrical Component Identification This section describes the methods used to identify electrical equipment locations and to number electrical schemes, cables, and raceways. 1.13.6.1 Equipment Location Numbers Each piece of electrical equipment is identified by an equipment number as described in Section 1.13.4. To facilitate cable routing from one equipment location to another, a location number is also assigned to each piece of electrical equipment. Generally, the equipment number and equipment location number for a specific piece of electrical equipment are identical. For large pieces of electrical equipment, such as switchgear, load centers, and motor control centers (MCC), which are compartmentalized, the equipment location number consists of the basic equipment number plus additional suffixed information to identify a location within the equipment itself. The following two examples illustrate equipment location numbers: Example 1: 10X101 Example 2: 10B44601 In the first example, the equipment number and equipment location number for transformer 10X101 are identical. In the second example, the basic MCC equipment location number 10B446 is suffixed to establish an equipment location number, 10B44601, which identifies a specific cubicle within the MCC. Equipment location numbers are generally assigned to items listed in the circuit and raceway schedules. Accordingly, most electrical equipment related to systems such as lighting, communications, and cathodic protection is not included. Electrical equipment that is an integral part of mechanical equipment is assigned the same number as the mechanical equipment. 1.13-6 HCGS-UFSAR Revision 0 April 11, 1988

1.13.6.2 Scheme Cable Numbers Each cable in the plant is uniquely identified by a scheme cable number that is composed of nine characters of the form LLNLNNNNL. The example given below illustrates what each character of a cable symbolizes. A P 1 Q 08 01 R Cable 'R' in cable Block Diagram Scheme Number (01) System (RHR System) System Q - In This Case Nuclear Steam Supply System Plant Unit Number System Voltage Level Separation Group Except for cabling associated with the plant lighting and cathodic protection systems, each cable in the plant is identified by a cable number. 1.13.6.3 Raceway Numbers A unique alpha-numeric identification is assigned to each cable tray, conduit pull box, sleeve, or slot for cables, etc. This identification consists of 8 characters that are indicated on electrical raceway drawings. 1.13-7 HCGS-UFSAR Revision 0 April 11, 1988

The cable tray numbering system is illustrated in the following example. 1 3 A T F E 01 Tray Subsection Number Building Elevation Voltage Level Tray Separation Group Plant Building and Area Plant Unit Number 1.13-8 HCGS-UFSAR Revision 0 April 11, 1988

1.13.6.4 Conduit Numbers The conduit numbering system is illustrated in the following example. 1 4 N R P E 34 Sequential Number Elevation Service (control or power) Conduit Separation Group Building and Area Plant Unit Number 1 1.13-9 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 1.13-1 ACRONYMS USED IN FSAR ABA Amplitude Based Algorithm ABDA auxiliary Building, diesel area ABCA auxiliary Building, control area ACRS Advisory Committee on Reactor Safeguards ADS Automatic Depressurization System AISC American Institute of Steel Construction AISI American Iron and Steel Institute ALARA as low as is reasonably achievable ANI American Nuclear Insurers ANS American Nuclear Society ANSI American National Standards Institute APRM average power range monitor ARI alternate rod insertion ARMS Area Radiation Monitoring System ARW high conductivity radwaste ASCE American Society of Civil Engineers ASME American Society of Mechanical Engineers ASME B&PV Code American Society of Mechanical Engineers Boiler and Pressure Vessel Code ASTM American Society for Testing and Materials ATM analog trip module ATWS anticipated transients without scram AWS American Welding Society AWWA American Water Works Association BISIS bypassed and inoperable status indication BOC beginning of cycle BOP balance of plant BTP Branch Technical Position BWR boiling water reactor 1 of 9 HCGS-UFSAR Revision 23 November 12, 2018

TABLE 1.13-1 (Cont) CACWS Control Area Chilled Water System CAE control area exhaust CDA Confirmation Density Algorithm CERS control equipment room supply CFR Code of Federal Regulations CHRS Containment Hydrogen Recombiner System CIPS Containment Inerting and Purge System CPCS Containment Prepurge Cleanup System CPPU Constant Pressure Power Uprate CPR critical power ratio CRD control rod drive CRDA control rod drop accident CRDHS Control Rod Drive Hydraulic System CREF control room emergency filter CRIDS Control Room Integrated Display System CRPIS Control Rod Position Indication System CRRA control room return air CRS control room supply CRT cathode ray tube CRW clean radwaste CSCM containment spray cooling mode CSR cable spreading room CST condensate storage tank CVN Charpy V-notch CWS Circulating Water System DABE diesel area battery room exhaust DAPRS diesel area panel room supply DBA design basis accident DBE design basis event DCR design change request DCRMS document control records management system DECRW decontamination radwaste DIDA Defense-in-Depth Algorithm DOP dioctyl phthalate DRR diesel generator room recirculation DRW dirty radwaste DSS-CD Detect and Suppress Solution - Confirmation Density 2 of 9 HCGS-UFSAR Revision 23 November 12, 2018

TABLE 1.13-1 (Cont) EAB exclusion area boundary EACS Equipment Area Cooling System EAS essential auxiliary support ECCS Emergency Core Cooling System EHC electrohydraulic control ELS emergency load sequencer ENS Emergency Notification System EOC end of cycle EOF emergency offsite facility EOL end of life EPA electrical penetration assembly ER environmental report ERF emergency response facility ERFDS Emergency Response Facility Display System ESF engineered safety features FATT fracture appearance transition temperature FCS Feedwater Control System FCD flow control diagram FFWT final feedwater temperature FHA fuel handling accident FMEA failure modes and effects analysis FPCC fuel pool cooling and cleanup FPS Fire Protection System FRVS Filtration, Recirculation, and Ventilation System FSAR Final Safety Analysis Report FSTF full scale test facility FWPCA Federal Water Pollution Control Act FWS Feedwater System GDC General Design Criterion GE General Electric Company GRA Growth Rate Algorithm GWMS Gaseous Waste Management System 3 of 9 HCGS-UFSAR Revision 23 November 12, 2018

TABLE 1.13-1 (Cant) HCGS Hope Creek Generating Station HCU hydraulic control unit HEPA High particulate air HOAS Hydrogen-Oxygen Analyzer System HPCI high pressure coolant injection HPLPSI high pressure/low pressure system interlocks HVAC heating, ventilating, and air conditioning I&C instrumentation and control I/O input/output res Control System

 !ED        instrument engineering diagram, or instrument electrical diagram, or instrument and electrical diagram IES        Illumination Engineering Society ILRT       integrated leak rate test IRM        intermediate range monitor LDBA       leakage design basis accident LOIS       Leakage Detection and Isolation System LOS        Leak Detection system LEFM       linear elastic fracture mechanics LER        licensee event report LHGR       linear heat generation rate LOCA       loss-of-coolant accident LPCI       low pressure coolant injection LPRM       local power range monitor LPSP       low power setpoint LPZ        low population zone LSTG       Large Steam Turbine-Generator, General Electric Company LTD        long time delay LWMS       Liquid Waste Management System LWR        light water reactor 4 of 9 HCGS-UFSAR                                       Revision 14 July 26, 2005

TABLE 1.13-1 (Cont} M&TE measuring and test equipment MAPHGR maximum average plant & heat generation rate MCC motor control center MCHFR minimum critical heat flux ratio MCPR minimum critical power ratio MCR main control room MCRHIS Main Control Room Habitability and Isolation System MGV motor generator ventilation MPL Master Parts List MPC maximum permissible concentration I MSIV main steam isolation valve MSIVSS Main Steam Isolation Valve Sealing System (Deleted System) MSSV main steam stop valve MSV main stop valve MTBE mean time between events NBS National Bureau of Standards NBU Nuclear Business Unit NCO nuclear control operator NDL nuclear data link NDT nondestructive testing NDTT nil-ductility transition temperature NEC National Electric Code NMS Neutron Monitoring System NPSH net positive suction head NRB nuclear review board NSOA nuclear safety operational analysis NSSS Nuclear Steam Supply System NSSSS Nuclear Steam Supply System shutoff NWS National Weather Service OBE operating basis earthquake OHLHS Overhead Heavy Load Handling Systems ORW oily radwaste OS Operations Superintendent OS&Y outside screw and yoke (valve} 5 of 9 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 1.13-1 (Cont) P&ID piping and instrumentation diagram PAMI post-accident monitoring instrumentation PASS Post-Accident Sampling System PBDA Period Based Detection Algorithm PCA primary coolant activity PCRVICS Primary Containment and Reactor Vessel Isolation Control System PCS Process Computer System PCIGS Primary Containment Instrument Gas System PCIS Primary Containment Isolation System PDM Pittsburgh-Des Moines Steel Company PLC programmable logic controller PMF probable maximum flood PMH probable maximum hurricane PORC preoperational test review committee PRMS Process Radiation and Monitoring System PRTGS Pressure Regulator and Turbine-Generator System PSS Process Sampling System PSAR Preliminary Safety Analysis Report PVC polyvinyl chloride PWR pressurized water reactor QA quality assurance QAD quality assurance department QAI quality assurance instruction QAM quality assurance manual QAP quality assurance program QSTF quarter scale test facility RACS Reactor Auxiliaries Cooling System RAMPS Repair and Maintenance Procedure System RBEAC reactor building equipment area cooling RBM rod block monitor RBSCR reactor building to suppression chamber relief RBVIS Reactor Building Ventilation Isolation System RBVS Reactor Building Ventilation System 6 of 9 HCGS-UFSAR Revision 23 November 12, 2018

TABLE 1.13-1 (Cont) RCIC reactor core isolation cooling RCPB reactor coolant pressure boundary RCS Reactor Coolant System RDCS RMCS Rod Drive Control System RFCS Recirculation Flow Control System RFPT reactor feedpump turbine RHR residual heat removal RHR-RSCM residual heat removal-reactor shutdown cooling mode RI refueling interlocks RMCS Reactor Manual Control System RMS Radiation Monitoring System RO reactor operator RPC rod pattern controller RPIS Rod Position Information System RPM radiation protection manager RPS Reactor Protection System RPT recirculation pump trip '-/ RPV reactor pressure vessel RRCS Redundant Reactor Control System RSCS Rod Sequence Control System RSF remote shutdown facility RSP remote shutdown panel RTD resistance temperature detector RWCU reactor water cleanup RWE rod withdrawal error RWM rod worth minimizer RWS radwaste area supply RWTF radwaste area tank filter SACF single active component failure SACS Safety Auxiliaries Cooling System SAF single active failure SAS service area supply SCDPR suppression chamber to drywell pressure relief

\.,.__,.-'

7 of 9 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 1.13-1 (Cont) SDIV scram discharge instrument volume SDV scram discharge volume SJAE steam jet air ejector SLC standby liquid control SOE single operator error SORC station operations review committee SPCM suppression pool cooling mode SPDS Safety Parameter Display System SPE steam packing exhauster SQAE station quality assurance engineer SQRT seismic qualification review team SRC switchgear room unit coolers SRLR Supplemental Reload Licensing Report SRG safety review group SRM source range monitor SRO senior reactor operator SRP Standard Review Plan SRV main steam safety/relief valve SRWE solid radwaste exhaust SRWS solid radwaste supply SS nuclear shift supervisor SSE safe shutdown earthquake SSNSSI safety system/non-safety system isolation SSVS Safe Shutdown Equipment Ventilation System SSWS Station Service Water System STA shift technical advisor STACS Safety and Turbine Auxiliaries Cooling System STCS Steam Tunnel Cooling System STD short time delay STMS Startup Transient Monitoring System SWIS service water intake structure SWMS Solid Waste Management System TBVS Turbine Building Ventilation System TCTFE trichlorotrifluoroethane 8 of 9 HCGS-UFSAR Revision 23 November 12, 2018

TABLE 1.13*1 (Cont) TDH total dynamic head TDS total dissolved solids TID total integrated radiation dose TIP traversing inwcore probe TLV threshold limit valve TSC technical support center TSCEF technical support center emergency filters TSCS technical support center supply TW"S traveling water screens UBC uniform building code UCL upper confidence limit UPS uninterruptible power supply URC ultrasonic resin cleaner US PHS United States Public Health Service VBWR. Vallecitos Boiling Water Reactor VFMG variable frequency motor-generator VRVS Vacuum Relief Valve System VWO valves wide open WAE wing area exhaust WAS wing area supply ZPA zero period acceleration 9 of 9 HCGS-UFSAR Revision 0 April 11, 1988

PIPING AND VALVE CLASS IDENTIFICATION Pipe and valve classes are designated by a three-letter code. The first letter indicates the primary valve and flange pressure rating; the second letter, the type of material; and the third letter, the code to which the piping is designed.

First Letter - Primaxy Pressure Rating A- Specific pressure at specific temperature B 2500 psi C - 1500 psi D 900 psi E 600 psi F - 400 psi G - 300 psi H- 150 psi J- 125 psi ANSI Bl6.1 K- 175 psi WOG Underwriter's Laboratories, Inc L- 250 psi ANSI Bl6.1 M- 200 psi WOG N- 150 psi ANSI Bl6.24 P - 100 psi AWWA (or manufacturer's rating) R- 75 psi AWWA (or manufacturer's rating) S - 180 psi AWWA-non-Seismic Category I T- 25 psi AWYA V- Vendor supplied X- Gravity rating Y- 180 psi AWWA - Seismic Category I

HCGS-UFSAR 1 of 3 Revision 0 April 11, 1988

TABLE 1.13-2 (Cont) Second Letter - Material A - Alloy steel (1-1/4 Cr - 1/2 Mo) B- Carbon steel C - Austenitic stainless steel D- Copper, brass or bronze E- Aluminum bronze F- Carbon steel - copper bearing G- Carbon steel - cement mortar lined H- Cast iron I- 90 - 10 copper nickel J- Alloy steel 6 percent Cr K- Fiberglass reinforced pipe L- Carbon steel - impact tested M- Cast iron - high silicon N- Carbon steel - galvanized P - Cast iron - cement mortar lined Q- Ductile iron - teflon (FEP) lined R- Ductile iron S - Ductile iron - cement lined T- Prestressed concrete U- Carbon steel - saran lined V- Carbon steel - polypropylene lined W Carpenter 20 CB-3 alloy X- Carbon steel - epoxy phenolic lined Y

Carbon steel
teflon (FEP) lined Z - Reinforced concrete Third Letter - Applicable Codes A- Nuclear power plant components, ASME B&PV Code, Section III, Class 1 B- Nuclear power plant components, ASME B&PV Code, Section III, Class 2 2 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 1.13-2 (Cont) c - Nuclear power plant components. ASME B&PV Code, Section III, Class 3 D- Power piping code, ANSI B31.1 E - Petroleum refinery piping code, ANSI B31.3 F- National Fire Protection Association code G- The National Standard Plumbing code H- Power boilers, ASME B&PV Code, Section I I - Manufacturers standard J- American Water Works Association T- GE LSTG code X- ASTM standards

HCGS-UFSAR 3 of 3 Revision 0 April 11, 1988

Figure F1.13-1 SH 1-2 intentionally deleted. Refer to Plant Drawing M-00-0 for both sheets in DCRMS HCGS-UFSAR Revision 20 May 9, 2014

1111'111 1111'111 ICawll("'. u....a: REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION LOGICSYMBOLS UPDATED FSAR FIGURE1.13-2

1.14 GENERIC LICENSING ISSUES 1.14.1 Licensing Issues HCGS has identified generic licensing issues from the dockets of several operating license applicants. These generic issues were originally in the form of NRC questions, and dealt with TMI related issues or Regulatory Guides which have undergone recent revision. HCGS has evaluated each of these issues and has a response to each of them in the following sections. A list of these licensing issues is provided below: Licensing Issue Title 1 Internally Generated Missiles 2 CRD Return Line Removal 3 SRV Surveillance Program 4 SRV Performance Testing 5 Applicability of Liquid Flow Through SRV Test Performed in Response to TMI Action Plan Item II.D.1 6 Trip of Recirculation Pumps to Mitigate ATWS 7 Detection of Intersystem Leakage 8 RCIC Pump Suction Switchover 9 Unintentional Shutdown of the RCIC System 10 Design Adequacy of the RCIC System - Providing Automatic Restart Capability 1.14-1 HCGS-UFSAR Revision 0 April 11, 1988

11 Adequate SRV Fluid Flow 12 Provisions to Preclude Vortex Formation 13 Categorization of Valves Which Isolate RHR From Reactor Coolant System 14 Available Net Positive Suction Head 15 Assurance of Filled ECCS Line 16 Operability of ADS 17 Assurance For Long Term Operability of the Automatic Depressurization System (ADS) 18 Leakage Testing of Reactor Coolant System Isolation Valves 19 Assurance For Long-Term Operability of the Automatic Depressurization System 20 Control of Post-LOCA Leakage to Protect ECCS and Preserve Suppression Pool Level 21 Required Operator Action Assumed in LOCA Analysis in the 10 to 20 Minute Time Frame 22 Replace High Drywell Pressure Interlock on HPCS Trip Circuitry With Level-8 Trip to Prevent Main Steam Line Flooding 23 Additional LOCA Break Spectrum 24 LOCA Analysis With Closure of the Recirculation Flow Control Valve Closure 1.14-2 HCGS-UFSAR Revision 0 April 11, 1988

25 Adequate Time Available for Required Operator Action 26 Requirement for Automatic Restart of HPCS After Manual Termination 27 Adequate Core Cooling Maintained With LPCI Diversion 28 Temperature Drop With Feedwater Heater 29 Use of Nonreliable Equipment in Anticipated Operational Transients 30 Reliance on Nonsafety Grade Equipment in the Analysis of Recirculation Pump Shaft Seizure 31 ATWS 32 ODYN Transient Analysis Code 33 Classification of Load Rejection Without Bypass and Turbine Trip Without Bypass and Recalculation of MCPR 34 Proper Classification of Transients 35 Adequacy of the GEXL Correlation - Reload Operation 36 Core Thermal Hydraulic Stability Evaluation 37 Low or Degraded Grid Voltage 38 Test Results for Diesel Generators 39 Containment Electrical Penetrations 40 Adequacy of the 120 V ac RPS Power Supply 41 Thermal Overload Protection Bypass 1.14-3 HCGS-UFSAR Revision 0 April 11, 1988

42 Reliability of Diesel Generator 43 Diesel Generator Reliability 44 Shared DG Conformance to Regulatory Guide 1.81 45 Periodic Diesel Generator Testing 46 Special Low Power Testing Program 47 Emergency Procedures Reactivity Control Guidelines 48 Common Reference for Reactor Vessel Level Measurement 49 Reactor Coolant Sampling 50 Suppression Pool Sampling 51 Estimation of Fuel Damage from Post-Accident Samples 52 Failures in Vessel Level Sensing Lines Common to Control and Protective Systems 53 Physical Separation and Electrical Isolation 54 Redundancy and Diversity of High/Low Pressure System Interlocks 55 ATWS 56 Test Techniques 57 Potential for Both Low-Low Setpoint Valves to Open Due to a Single Failure 58 Safety System Setpoints, Instrument Range 1.14-4 HCGS-UFSAR Revision 0 April 11, 1988

59 IE Bulletin 80-06: Engineered Safety Feature Reset Control 60 Drawings 61 Control Systems Failure 62 RCIC Classification 63 Safety-Related Display 64 Rod Block Monitor 65 MSIV Leakage Control System (Historical Information) 66 Procedures Following Bus Failure (IE Bulletin 78-27) 67 Harsh Environment for Electrical Equipment Following High Energy Line Breaks 68 Steam Bypass of the Suppression Pool 69 Pool Dynamic LOCA and SRV Loads 70 Containment Dynamic Loads 71 Containment Purge System 72 Combustible Gas Control 73 Hydrogen Control Capability 74 Containment Leakage Testing 75 BWR Scram Discharge Volume Modifications 76 Safe Shutdown for Fires and Remote Shutdown System 1.14-5 HCGS-UFSAR Revision 12 May 3, 2002

77 Protection of Equipment in Main Steam Pipe Tunnel 78 Design Adequacy of the RCIC System Pump Room Cooling System 79 Reassessment of Accident Assumptions as Related to Main Steam Line Isolation Valve Leakage Rate 80 Asymmetrical LOCA, SSE and Annulus Pressurization Loads on Reactor Vessel, Internals, and Supports 81 Preoperational Vibration Assurance Program 82 RPV Internals Vibration Test Program for BWR/6 83 Dynamic Response Combination Using SRSS Technique 84 Input Criteria for Use of SRSS for Mechanical Equipment 85 Loading Combinations, Design Transients, and Stress Limits 86 Stress Corrosion Cracking of Stainless Steel 87 Pump and Valve Operability Assurance Program 88 Bolted Connections for Supports 89 Pump and Valve Inservice Testing Program 90 SRV In-Situ Test Program 91 CRD System Return Line Removal 92 Test Program Documentation for High and Moderate Energy Piping Systems 1.14-6 HCGS-UFSAR Revision 0 April 11, 1988

93 OBE Stress Cycles Used for the Mechanical Design on NSSS Equipment and Components 94 Kuosheng Incore Instrument Tube Break 95 Preservice and Inservice Inspection of Class 1, 2, and 3 Components 96 Inspectability of Welded Flued Head Design on Main Steam Line Containment Penetration 97 Clarification and Justification of the Methods Used to Construct the Operating Pressure/Temperature Limits 98 Exemptions from Appendix H to 10CFR50 99 Reactor Testing and Cooldown Limits 100 Exposure Resulting from Actuation of SRVs 101 Routine Exposures Inside Containment 102 Controlling Radioactivity During Steam Dryer and Steam Separator Refueling Transfer 103 Shielding of Spent Fuel Transfer Tube and Canal During Refueling 104 Combination of Loads 105 Fluid/Structure Interaction 106 Loads Assessment of Fuel Assembly Components 107 Combined Seismic and LOCA Loads Analysis on Fuel 1.14-7 HCGS-UFSAR Revision 0 April 11, 1988

108 Nonconservatism in the Models for Fuel Cladding, Swelling, and Rupture 109 Fuel Rod Cladding Ballooning and Rupture 110 High Burnup Fission Gas Release 111 Channel Box Deflection 112 Water Side Corrosion of Fuel Cladding Due to Copper in the Feedwater 113 Cladding Water Side Corrosion 114 Instruments to Detect Inadequate Core Cooling 115 Rod Withdrawal Transient Analysis 116 Fuel Analysis for Mislocated or Misoriented Bundles 117 Discrepancy in Void Coefficient Calculation 118 Bounding Rod Worth Analysis 119 Core Thermal Hydraulic Stability Analysis 120 Seismic Qualification of Equipment 121 Environmental Qualification of Equipment 1.14.1.1 Internally Generated Missiles, LRG I/RSB-1 1.14.1.1.1 Issue Each applicant, on a plant specific basis, to demonstrate acceptability using one of, or a combination of, the following: 1.14-8 HCGS-UFSAR Revision 0 April 11, 1988

1. Provide protection from internally generated missiles

2. Perform analysis to show that missiles are not generated, or, if generated, have insufficient energy to cause unacceptable damage This item relates to ACRS generic concern II-8, recirculation pump overspeed during a LOCA.

1.14.1.1.2 Response The potential for internal missiles was discussed in Sections 3.5.1.1 and 3.5.1.2. It was concluded in these sections that internal missiles generated by rotating and pressurized components, and gravitationally generated missiles are not considered to be probable, or the consequences of a postulated missile have been evaluated, and safe shutdown of the plant is not affected. 1.14.1.2 CRD Return Line Removal, LRG I/RSB-2 1.14.1.2.1 Issue The NRC staff was concerned with the impact of the elimination of the control rod drive (CRD) return line on the performance of the CRD system. 1.14.1.2.2 Response The acceptability of the CRD system performance without the CRD return line (see Plant Drawing M-46-1) has been demonstrated by a GE analysis of the CRD performance characteristics. 1.14-9 HCGS-UFSAR Revision 20 May 9, 2014

1.14.1.3 SRV Surveillance Program, LRG II/3-RSB-3 1.14.1.3.1 Issue LRG II participants must commit to participate in a safety/relief valve surveillance program. 1.14.1.3.2 Response HCGS is participating in the BWROG program to test safety/relief valves. For further details see Section 1.10, Item II.D.1. Section 5.2.2.10 describes additional safety/relief valve inspection and test programs. 1.14.1.4 SRV Performance Testing/ LRG I/RSB-3 1.14.1.4.1 Issue Additional information is required both for qualification tests and operating experience with the applicants safety/relief valves. 1.14.1.4.2 Response Section 5.2.2 describes the design, fabrication, test, installation and inspection requirements for the safety/relief valves. Section 1.10, Item II.D.1 describes the HCGS participation in the BWROG program to test safety/relief valves. 1.14.1.5 Applicability of the Liquid Flow Through SRV Tests Performed in Response to TMI Action Plan Item II.D.1, LRG II/6-RSB 1.14.1.5.1 Issue An alternate shutdown cooling condition, which is considered in the design evaluation of many BWR plants, requires the flow of water through the safety/relief valve (SRV) and into the suppression pool. 1.14-10 HCGS-UFSAR Revision 0 April 11, 1988

In order to take credit for this alternate mode of shutdown cooling, it is necessary to demonstrate the ability of the SRVs and their discharge piping to withstand the resulting flow conditions. 1.14.1.5.2 Response The original Hope Creek SRVs were Target Rock 2-Stage SRVs. The 2-Stage SRVs were qualified as described below. The BWR Owners' Group SRV test program, undertaken to satisfy NUREG-0737 Item II.D.1 requirements, fully demonstrates the adequacy of the HCGS Target Rock SRVs for the alternate shutdown cooling mode of operation. The test program results are documented in General Electric Licensing Topical Report NEDE-24888-P/NEDO-24888. The Applicant's participation and the applicability of the test results to HCGS valves are described in Appendixes B and A, respectively, of that report. Subsequently, Target Rock 3-Stage SRVs have been evaluated and approved for installation at Hope Creek. The Hope Creek 3-Stage SRVs utilize the same SRV Main body, require the same opening pressure in the electro-pneumatically operated mode (which is required for alternate mode of shutdown cooling) have the same response time, capacity and set pressures as the 2-Stage SRVs, and have been evaluated by the NSSS vendor General Electric (Report 001N2205, Hope Creek VTD 432432) to meet the requirements of NUREG 0737 Item II.D.1. 1.14.1.6 Trip of Recirculation Pumps to Mitigate ATWS, LRG I/RSB-4 1.14.1.6.1 Issue The NRC staff required the overpressure protection analysis to consider the effect of an ATWS initiated recirculation pump trip (RPT). 1.14.1.6.2 Response The overpressure protection analysis for the HCGS was done with credit taken for a RPT. 1.14.1.7 Detection of Intersystem Leakage, LRG I/RSB-5 1.14.1.7.1 Issue Regulatory Guide 1.45 requires provisions to monitor systems connected to the RCPB for signs of intersystem leakage. 1.14-11 HCGS-UFSAR Revision 23 November 12, 2018

1.14.1.7.2 Response HCGS interprets intersystem leakage as leakage from the reactor coolant pressure boundary (RCPB) and subsystems closely allied to the RCPB to secondary systems. Intersystem leakage is discussed in Sections 5.2.5.1.4, 11.5.2.2.16, and 11.5.2.2.17. Leakage from the RCPB to the closely allied systems is not monitored directly because:

1. It does not represent a breach of the integrity of the RCPB

2. It does not threaten the ability to maintain water inventory

3. It does not jeopardize the integrity of the closely allied systems or the rest of the plant.

The principal reason for measuring RCPB leakage is to assure RCPB integrity. Leakage from the RCPB to closely allied systems does not indicate a degradation of the RCPB and leakage is expected to be well below the normal makeup capabilities of the feedwater and control rod drive systems. Where it is possible that a low pressure system could become pressurized, due to leakage through a RCPB isolation valve, relief valves are provided to prevent overpressurization and to assure the integrity of the low pressure system. Periodic testing of the isolation valves between the RCPB and the closely allied systems will provide additional assurance that the integrity of the low pressure system will not be threatened. 1.14-12 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.8 RCIC Pump Suction Switchover, LRG I/RSB-6 and LRG II/6-RSB 1.14.1.8.1 Issue The NRC staff wanted assurance of the availability of a Seismic Category I water source by an automatic switchover to the suppression pool upon failure of the condensate storage tank. 1.14.1.8.2 Response The HCGS design incorporates an automatic transfer of the RCIC pump intake to the suppression pool when the water level in the condensate storage tank reaches a predetermined low level (see Section 1.10.2). 1.14.1.9 Unintentional Shutdown of the RCIC System, LRG I/RSB-7 1.14.1.9.1 Issue Show how the design of the RCIC system prevents unintentional shutdown of the system, when the system is required, because of spurious ambient temperature signals from areas in and around the system (especially in the RCIC pump room). 1.14.1.9.2 Response The temperature monitoring instrumentation provided for leak detection in the RCIC equipment compartment is described in FSAR Sections 5.2.5 and 7.6.1.3. The alarm and system isolation setpoints have been calculated based on analysis. The alarm/trip setpoints include sufficient margin to preclude spurious or unintentional annunciation or isolation. The temperature elements are located/or shielded so that they are sensitive to ambient air temperature and not radiated heat from operating equipment. 1.14-13 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.10 Design Adequacy of the RCIC System - Providing Automatic Restart Capability, LRG II/2-RSB(a), LRG 11/2-RSB(b), LRG 11/2-RSB(d) 1.14.1.10.1 Issue (LRG II/2-RSB(a)) TMI Action Plan Item 11.K.3.13 identified a need to modify the RCIC system to allow for automatic restart of the system at RPV Level 2 after the system has been tripped by a RPV Level 8 signal. The NRC Staff requires a commitment to install the automatic restart capability. The design details of this modification should also be provided. 1.14.1.10.2 Response (LRG II/2-RSB(a)) The HCGS response to TMI Action Plan Item 11.K.3.13 is provided in Section 1.10.2 of the HCGS FSAR. 1.14.1.10.3 Issue (LRG II/2-RSB(b)) TMI Action Plan Item II.K.3.15 identified a need to modify the break detection logic on the RCIC system steam supply line in order to prevent spurious isolation of the system. The NRC Staff requires a commitment to install a modification to correct the problem. The design details of this modification should also be provided. 1.14.1.10.4 Response (LRG II/2-RSB(b)) The HCGS response to TMI Action Plan Item II.K.3.15 is provided in Section 1.10.2 of the HCGS FSAR. 1.14.1.10.5 Issue (LRG II/2-RSB(d)) Provide water hammer protection for the RCIC system which is comparable to that provided for ECCS systems. 1.14-14 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.10.6 Response (LRG II/2-RSB(d)) As indicated by FSAR Section 5.4.6.2.4(f), water hammer protection is provided for the RCIC system which is comparable to that provided for the ECCS injection systems. 1.14.1.11 Adequate SRV Fluid Flow, LRG I/RSB-8 1.14.1.11.1 Issue The applicant must perform tests to show that flow through the safety/relief valves is adequate to provide the necessary fluid relief required consistent with the analysis reported in Section 15.2.9 of the FSAR. 1.14.1.11.2 Response See response to LRG Issue No. 5, Section 1.14.1.5. 1.14.1.12 Provisions to Preclude Vortex Formation, LRG II/7-RSB 1.14.1.12.1 Issue To preclude vortex formation, air entrainment, and subsequent damage to ECCS pumps due to cavitation, it must be shown that adequate margin exists between the minimum suppression pool level and the depth of submergence of the ECCS pump suction strainers. This can be shown by analysis or by observations during pre-op testing that no vortex is formed. 1.14.1.12.2 Response The ECCS pump suction strainers in the HCGS suppression chamber are provided with a minimum submergence of at least 10 feet, as measured from minimum suppression pool level. This amount of submergence has been analyzed to provide sufficient margin to preclude formation of vortices, as indicated by FSAR Section 6.3.2.2.5. 1.14-15 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.13 Categorization of Valve Which Isolates RHR from Reactor Coolant System, LRG I/RSB-8 1.14.1.13.1 Issue We require that the valves which serve to isolate the Residual Heat Removal System from the Reactor Coolant System be classified category A/C in accordance with the provisions of Section XI of the ASME B&PV Code. 1.14.1.13.2 Response Inservice testing of valves is discussed in Section 3.9.6. 1.14.1.14 Available Net Positive Suction Head, LRG I/RSB-10 1.14.1.14.1 Issue The applicant must verify that the suction lines in the suppression pool leading to the ECCS pumps are designed to preclude adverse vortex formation and air injection which could affect the pumps' performance. 1.14.1.14.2 Response See response to LRG Issue No. 12, Section 1.14.1.12. 1.14.1.15 Assurance of Filled ECCS Lines, LRG I/RSB-11 1.14.1.15.1 Issue Instrumentation is not sufficiently sensitive to detect voids at the top of ECCS pipelines. The applicant must provide adequate instrumentation to assure filled ECCS lines. 1.14-16 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.15.2 Response The design of the ECCS discharge line fill network is described in FSAR Section 6.3.2.2.6. The jockey pumps for the fill network will pressurize the ECCS pump discharge lines sufficiently above atmospheric pressure to preclude either air inleakage or the formation of voids at the top of ECCS pipelines. Instrumentation is provided for each of the ECCS pump discharge lines to detect unacceptably low pressure in the lines. To further ensure that the ECCS lines are full, the fill network is periodically surveillance tested in accordance with plant technical specifications. 1.14.1.16 Operability of ADS, LRG I/RSB-12 1.14.1.16.1 Issue The applicant must show that the air supply for the ADS is sufficient for the extended operating time required and assures us the reliability data that the ADS valves will function as required. 1.14.1.16.2 Response See response to LRG Issue No. 17, Section 1.14.1.17. 1.14.1.17 Assurance for Long Term Operability of the Automatic Depressurization System (ADS), LRG II/8-RSB 1.14.1.17.1 Issue TMI Action Plan Item II.K.3.28 identified the need to assure that air or nitrogen accumulators for the ADS valves are provided with sufficient capacity to cycle the valves open five times at design pressures. The long term air supply must also be designed to withstand a hostile environment and still perform its function 100 days after an accident. 1.14-17 HCGS-UFSAR Revision 0 April 11, 1988

Since the time when the ADS would be needed during or after an accident is dependent upon a variety of scenario specific unknowns such as equipment availability, operator actions, break size, etc., it is unacceptable to NRC to allow the ADS to be unavailable anytime the reactor is pressurized. Leakage through the accumulator check valves must not disable the ADS before action is taken to provide the backup air supply. No single active failure may disable the long term air supply. 1.14.1.17.2 Response The response for TMI Action Plan Item II.K.3.28 is discussed in Section 1.10. 1.14.1.18 Leakage Testing of Reactor Coolant System Isolation Valves, LRG I/RSB-13 1.14.1.18.1 Issue Periodic testing and establishment of leak rate criteria required for the valves that isolate the Reactor Coolant System from all the emergency core cooling systems. 1.14.1.18.2 Response Leakage testing of isolation valves and acceptance criteria for the tests are discussed in Sections 6.2.4 and 6.2.6, and Table 6.2-16. 1.14.1.19 Assurance for Long Term Operability of Deep Draft Pumps, LRG II/9-RSB and LRG I/RSB-14 1.14.1.19.1 Issue IE Bulletin 79-15, dated July 1979, identified problems with deep draft ECCS pumps that could threaten their long term post-LOCA operability. Structure flexibility, shaft/column misalignment, 1.14-18 HCGS-UFSAR Revision 0 April 11, 1988

vibrational frequencies near rotation speeds, inlet flow induced vortices, and dimensional deficiencies such as those discovered with certain LaSalle ECCS pumps, could cause excessive vibration and bearing wear. The NRC staff has asked applicants to define programs and provide data that compare the expected service life with the accumulated operating time and confirm the long term operability. 1.14.1.19.2 Response The inherent design features of the Ingersoll Rand ECCS pumps in HCGS preclude excessive vibration and bearing wear. Each pump is supplied with a casing or suction barrel and is not installed in a wet sump. They do not have long, limber columns; the longest pump is only 18 feet, compared to the 30 to 60-foot pumps described in IE Bulletin 79-15. Also the pump assembly rigidity is enhanced by a seismic pin. The pumps use a double suction first stage to provide stability over a wide range of flows. Column frequencies are well removed from pump speed. Larger diameter barrels provide low flow velocities around pump inlets, and pin seismic restraints act as flow straighteners to suppress vortex formation. The pumps have high precision, keyed, sleeve type couplings. Long term operability is assured by the use of a predictive maintenance program, and periodic functional testing under the In Service Testing (IST) Program. The predictive maintenance program tracks and trends the vibration and performance data collected under the IST Program. When the data indicates a reduction in pump performance, pump repairs or overhaul are performed to restore the pumps performance. Functional testing measurements of pump inlet pressure, differential pressure, flow rate, and vibration, quarterly as prescribed by OM - Part 6 of the ASME B&PV Code, provide data for engineering analysis to identify performance changes or trends. In addition, vibration data bases are maintained and compared with functional testing vibration data to monitor journal bearing wear and shaft whip. 1.14-19 HCGS-UFSAR Revision 15 October 27, 2006

1.14.1.20 Control of Post-LOCA Leakage to Protect ECCS and Preserve Suppression Pool Level, LRG II/5-RSB 1.14.1.20.1 Issue The applicant must demonstrate that passive failures (i.e., leakage from the first isolation valve outside of the suppression pool) will be contained so that the suppression pool is not drained nor is redundant ECCS equipment flooded. 1.14.1.20.2 Response The ECCS suction lines and the isolation valves between the suppression chamber and the ECCS pumps are safety grade. The isolation valves are designed to preclude leakage, and no seals or gaskets are installed between the containment penetration and the isolation valves. Leak detection and mitigation capabilities for the ECCS pump compartments are discussed in FSAR Sections 5.2.5 and 9.3.3.5. 1.14.1.21 Operator Action Required/Assumed in LOCA Analyses in the 10-to-20 Minute Time Frame, LRG II/4-RSB 1.14.1.21.1 Issue Section 6.3 of the Standard Review Plan states that no credit for operator actions should be taken in loss-of-coolant accident (LOCA) analyses prior to 20 minutes into the transient. 1.14.1.21.2 Response The LOCA analyses for the HCGS meet the SRP criterion. No operator actions are required within 20 minutes. While 10-minute operator actions are assumed in the containment analyses, the actions are assumed for the purpose of adding conservatism to the analyses 1.14-20 HCGS-UFSAR Revision 0 April 11, 1988

rather than to meet a design requirement. Further description is provided in Sections 6.2 and 6.3. 1.14.1.22 Replace High Drywell Pressure Interlock on HPCS Trip Circuitry with Level-8 Trip to Prevent Main Steam Line Flooding, LRG II/13-RSB 1.14.1.22.1 Issue Other designs included an interlock that prevented shutoff of the flow of the high pressure core spray at high water level (8) in the reactor vessel when a high drywell pressure signal is present. Such systems should be removed. 1.14.1.22.2 Response HCGS has no high pressure core spray. 1.14.1.23 Additional LOCA Break Spectrum, LRG I/RSB-15 1.14.1.23.1 Issue The NRC staff requested the following additional LOCA analyses to complete the break spectrum:

1. An additional recirculation line break with a discharge coefficient 0.6 times the design bases accident, using the large break model analysis.

2

2. An additional recirculation line break with a 0.02 ft area, using the small break model analysis.

1.14.1.23.2 Response The adequacy of the LOCA break spectrum is addressed in Section 6.3.3. The lead plant analyses (Brunswick), supported by 1.14-21 HCGS-UFSAR Revision 0 April 11, 1988

confirmatory plant unique Appendix K calculations, have been found acceptable to the NRC staff without further commitment. 1.14.1.24 LOCA Analyses with Closure of the Recirculation Flow Control Valve, LRG I/RSB-16 and LRG II/10-RSB 1.14.1.24.1 Issue The ECCS analyses described in Section 6.3 assume the nonsafety grade, recirculation flow control valve (FCV) locks at its existing position during the LOCA. The NRC staff requested a discussion of the effects on the analyses if it is assumed the FCV closes at a realistic rate and of the probability the FCV will fail in this manner. 1.14.1.24.2 Response The HCGS recirculation system does not contain a FCV so this issue is not applicable to the HCGS. 1.14.1.25 Adequate Time Available for Operator Action Required, LRG I/RSB-17 1.14.1.25.1 Issue In an applicant's analysis to evaluate a crack in the residual heat removal line postulated to occur during normal shutdown cooling, operator action was indicated to restore core cooling. The NRC staff required the applicant to show that adequate time is available for this operator action. 1.14.1.25.2 Response Should the RHR shutdown cooling line crack during a normal shutdown, a total reactor isolation will automatically occur. Subsequently, vessel water will decrease to Level 2, and automatic initiation of 1.14-22 HCGS-UFSAR Revision 0 April 11, 1988

HPCI will occur. HPCI will cycle on and off between Levels 2 and 8 until the operator establishes an alternate water source. If HPCI were unavailable, representative analyses for similar BWR/4 plants have been performed to demonstrate that operator action would not be required before 20 to 30 minutes following the pipe crack to assure adequate core cooling in accordance with the acceptance criteria of 10CFR50.46. 1.14.1.26 Requirement for Automatic Restart of HPCS After Manual Termination, LRG II/1-RSB 1.14.1.26.1 Issue The NRC staff required a commitment to install the automatic restart of high pressure core spray (HPCS) on low reactor vessel water level after manual termination by the operator. 1.14.1.26.2 Response This issue is not applicable to the HCGS because it does not have a HPCS. 1.14.1.27 Adequate Core Cooling Maintained with LPCI Diversion, LRG I/RSB-18 1.14.1.27.1 Issue The NRC staff asked for a demonstration that adequate core cooling would be maintained if the flow of the low pressure coolant injection were diverted to the wetwell and drywell sprays and to suppression pool cooling. 1.14.1.27.2 Response This situation is addressed in Section 6.3. Sufficient margin exists in the peak cladding temperature to accommodate the diversion 1.14-23 HCGS-UFSAR Revision 0 April 11, 1988

of low pressure coolant injection at 600 seconds into the transient. This demonstrates adequate core cooling. 1.14.1.28 Temperature Drop with Feedwater Heater Failure, LRG I/RSB-19 1.14.1.28.1 Issue The analysis of the feedwater heater failure event is based on a temperature drop no greater than 100F. However, an actual failure demonstrated a 150F drop. The NRC staff has requested a justification for the smaller temperature drop or a reanalysis with a justified temperature decrease. 1.14.1.28.2 Response The design specification for the Feedwater Heating System requires that the maximum temperature decrease due to a single failure be no greater than 100F. Sufficient analyses have been performed for BWR/4 plants to show that the net effect of a larger temperature drop is an earlier scram initiation rather than a change in the critical power ratio (CPR). The resulting minimum CPR is essentially unchanged, and this event is not the limiting event for establishing the operating limit on the minimum CPR. 1.14.1.29 Use of Nonreliable Equipment in Anticipated Operational Transients, LRG I/RSB-20 1.14.1.29.1 Issue In analyzing anticipated transients, if credit is taken for equipment that has not been shown to be reliable, this equipment should be identified in the technical specifications with regard to availability, setpoints, and surveillance testing. 1.14-24 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.29.2 Response The NRC staff's concern for the use of nonsafety grade equipment in the analysis of transient mitigation is exemplified by questions on many dockets relative to credit taken for:

1. Non-Class 1E relief function versus setpoints for Class-1E safety functions

2. Inputs to the Reactor Protection System from the turbine building

3. The level-8 turbine trip and the Turbine Bypass System.

A November 1978 GE/NRC meeting determined that the most limiting anticipated operation transient with an analysis that takes credit for nonsafety-grade equipment is the excess feedwater transient analysis that relies on a level-8 turbine trip and turbine bypass. The NRC staff agreed that technical specifications for the level-8 turbine trip and the turbine bypass valves would satisfactorily resolve this issue. The HCGS technical specifications will include appropriate provisions regarding the availability, setpoints, and surveillance testing of the trip system and bypass valves. 1.14.1.30 Reliance on Nonsafety-Grade Equipment in the Analysis of Recirculation-Pump Shaft Seizure, LRG /RSB-21 and LRG II/11-RSB 1.14.1.30.1 Issue Demonstrate that the limit for the minimum critical power ratio of 1.06 and the 10CFR 00 limits are not violated when the analysis of this accident does not take credit for nonsafety grade equipment. 1.14-25 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.30.2 Response The nonsafety-grade equipment for which credit is taken in this analysis (Section 15.3.3) are the level-8 turbine trip and the Turbine Bypass System. Failure of the level-8 turbine trip would produce a transient no worse than if a level-8 trip had occurred, and it would be less severe than the recirculation pump trip event (Section 15.3.1) because the eventual turbine trip (due to high steam moisture and/or turbine vibration) would be at a reduced fuel heat flux. Failure of the turbine bypass would produce a transient similar to but less severe than a turbine trip without bypass (Section 15.2.3) and also would be bounded by the feedwater controller failure event without bypass because of the reduced core power at the time of the turbine trip. 1.14.1.31 ATWS, LRG I/RSB-22 1.14.1.31.1 Issue The issue requires the applicant to:

1. Develop emergency procedures to train operators to recognize an ATWS event, including consideration of scram indicators, rod position indicators, flux monitors, vessel level and pressure indicators, relief valve and isolation valve indicators, and containment temperature, pressure, and radiation indicators.

2. Train operators to take actions in the event of an ATWS including consideration of immediately manual scramming the reactor by using the manual scram buttons followed by changing rod scram switches to the scram position, tripping the feeder breakers on the reactor protection system power distribution buses, opening the scram discharge volume drain valve, prompt actuation of the Standby Liquid Control (SLC) System, and prompt placement 1.14-26 HCGS-UFSAR Revision 0 April 11, 1988

of the RHR in the suppression pool cooling mode to reduce the severity of the containment conditions. 1.14.1.31.2 Response The following actions will be implemented at HCGS in order to further reduce the risk associated with ATWS events: HCGS is implementing Alternate 3A of NUREG-0460, with manual initiation of the SLC system. Emergency procedures will be developed for ATWS events. These procedures will address the following:

1. Symptoms

2. Automatic actions

3. Immediate actions

4. Subsequent actions

5. Final conditions Operators will be trained to perform the proper actions for ATWS events as part of the formal operator training program.

Emergency operating procedures have been developed from the BWR Owners' Group Emergency Procedure Guidelines (EPGs). Although these procedures are symptomatic in nature, specific actions are provided to mitigate ATWS events. The development of these procedures is described in the PGP and P-STG which have been submitted for NRC review. Subsequent revisions to the emergency operating procedures will be developed from revisions to the BWR Owner's Group EPGs, as applicable. Description of the process used to revise the EOPs is contained in the applicable administrative procedures. 1.14-27 HCGS-UFSAR Revision 9 June 13, 1998

1.14.1.32 ODYN Transient Analysis Code, LRG I/RSB-23 1.14.1.32.1 Issue The NRC staff requested that the pressurization transients be reevaluated and assessed using the ODYN computer code. At the time the NRC had not completed its review of the ODYN code. 1.14.1.32.2 Response The ODYN code has been reviewed and accepted by the NRC. All the pressurization transients in Sections 5 and 15 were analyzed using the ODYN code. 1.14.1.33 Classification of Load Rejection Without Bypass and Turbine Trip Without Bypass and Recalculation of MCPR, LRG I/RSB-24 and LRG II/12-RSB 1.14.1.33.1 Issue The minimum critical power ratio (MCPR) should be recalculated for the generator load rejection event, taking into consideration that turbine bypass fails. The NRC staff disagrees with an infrequent occurrence classification for this event, hence the operating limit should be modified to satisfy the MCPR limit of 1.06. 1.14.1.33.2 Response This issue is addressed in Sections 15.2 and 15.3. In spite of an infrequent occurrence classification, the ODYN code was used to analyze load rejection without bypass and turbine trip without bypass. Neither transient is limiting in determining the operating limit for the MCPR. 1.14-28 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.34 Proper Classification of Transients, LRG II/12-RSB 1.14.1.34.1 Issue The minimum critical power ratio (MCPR) should be recalculated for the generator load rejection event, taking into consideration that turbine bypass fails. The NRC staff disagrees with an infrequent occurrence classification for this event, hence, the operating limit should be modified to satisfy the MCPR limit of 1.06. 1.14.1.34.2 Response See response to LRG Issue No. 33, Section 1.14.1.33. 1.14.1.35 Adequacy of the GEXL Correlation, LRG I/RSB-25 1.14.1.35.1 Issue The GEXL correlation must de demonstrated to be applicable to the 8X8 design by comparison to applicable data. 1.14.1.35.2 Response The NRC staff has concluded that the GEXL correlation is conservative for the first core cycle. Adequate negative worth is provided by the control rods to assure shutdown capability. 1.14.1.36 Core Thermal Hydraulic Stability Analyses, LRG I/RSB-26 and LRG II/11-CPB 1.14.1.36.1 Issue Fuel design changes have increased the maximum decay ratio (MDR) beyond the original design criterion of 0.5 for thermal hydraulic stability, and the NRC staff has not accepted General Electric's proposed new criterion of 1.0. The Staff has approved for operation previous core designs with MDRs as high as 0.7 for the initial 1.14-29 HCGS-UFSAR Revision 0 April 11, 1988

cycle, but it will condition the licenses of BWR/6s (MDR = 0.98) to prohibit operation at natural circulation and to require new stability analyses be submitted and approved prior to second cycle operation. The NRC is performing a generic study of the hydrodynamic stability characteristics of light water reactors. The results will be applied to the Staff's review and acceptance of stability analyses, criteria, and analytical methods of reactor vendors. 1.14.1.36.2 Response Sufficient documentation of an adequate stability margin for the HCGS first cycle has been provided. As a result of the NRC staff position in references 1 and 2, future cycle specific stability margin analysis is not required. In addition, Technical Specification 3/4.4.1 states the operating limitations which provide for the detection and suppression of flux oscillations in operating regions of potential instability consistent with the recommendations of General Electric SIL-380. The NRC staff has found this acceptable to demonstrate compliance with GDC 10 and GDC 12 for cores loaded with approved fuel designs. 1.14.1.36.2.1 Response References

1. NRC Letter, C. O. Thomas to H.C. Pfefferlen, Acceptance for Referencing of Licensing Topical Report NEDE-24011, Rev. 6, Amendment 8, "Thermal Hydraulic Stability Amendment to GESTAR II",

dated April 24, 1985.

2. NRC Letter, R. M. Bernero to All Licensees of Operating BWR's, "Technical Resolution of Generic Issue B-19-Thermal Hydraulic Stability (Generic Letter No. 86-02)", dated January 23, 1986.

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1.14.1.37 Low or Degraded Grid Voltage, LRG I/PSB-1 1.14.1.37.1 Issue Either:

1. Applicant will commit to implement a second level of undervoltage protection consistent with the guidance provided by the NRC Staff before the start of the second fuel cycle; or

2. Applicant will demonstrate the adequacy of the grid without the second level of voltage protection to the satisfaction of the NRC staff.

3. Provide system voltages at all levels during degraded grid voltage condition.

1.14.1.37.2 Response Undervoltage relays for monitoring degraded grid voltage have been implemented into the HCGS design. System voltage studies have established the setpoints of these undervoltage relays. The setpoints for these relays and system voltages at various buses for various operating conditions are discussed in Section 8.3.1.2.1. 1.14.1.38 Test Results for Diesel Generators, LRG I/PSB-2 1.14.1.38.1 Issue Test results for the diesel generators to indicate margin are to be provided. 1.14-31 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.38.2 Response This issue is related to the diesel generator for HPCS system. This issue does not apply, since the high pressure coolant injection pump for HCGS plant is steam turbine driven. 1.14.1.39 Containment Electrical Penetrations, LRG I/PSB-3 1.14.1.39.1 Issue The reactor containment electrical penetrations shall conform to Regulatory Guide 1.63 and test results shall demonstrate that the electrical penetrations can maintain their integrity for maximum fault current. 1.14.1.39.1.1 Position The penetration design will conform to position C1 of Regulatory Guide 1.63 (Oct 1973) with respect to backup overcurrent protection; either:

1. "Incorporating adequate self-fusing characteristics within the penetration conductors themselves constitute an acceptable design approach"; or

2. "Where self-fusing characteristics are not incorporated the current overload protection system will conform to the single failure criteria of IEEE-279(1971) Section 4.2; ANSI-N42.7(1972)".

Note

1. Position 2 above applies to power circuits only. Control and instrument circuits are not subject to detrimental high level fault currents.

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2. Regulatory Guide 1.63, Rev. 1 (May 1977) was identified for implementation on CP applications docketed after December 30, 1977.

In addition, as listed in NUREG-0427 Table III-13 and III-14; Regulatory Guide 1.63 is identified as a Category I or Category II item. As such applicants shall be allowed to demonstrate the adequacy of Rev. 0 of the Regulatory Guide.

3. The positions discussed above are not applicable to Fermi-2. The issue is considered closed by NUREG-0314.

1.14.1.39.2 Response The design of the HCGS electrical penetration assemblies is in compliance with Regulatory Guide 1.63 as discussed in Section 8.1.4.12. 1.14.1.40 Adequacy of the 120 V ac RPS Power Supply, LRG I/PSB-4 PRS-4 1.14.1.40.1 Issue The NRC staff questioned the adequacy of the 120 V ac power supply for the Reactor Protection System. 1.14.1.40.2 Response This issue is addressed in Section 8.3.1.5. The MS set design modification developed by General Electric has been incorporated in the HCGS design. 1.14.1.41 Thermal Overload Protection Bypass, LRG I/PSB-5 1.14.1.41.1 Issue NRC required the applicant to provide the detailed analysis and/or criteria used to select the setpoints for the thermal overload 1.14-33 HCGS-UFSAR Revision 17 June 23, 2009

protective devices for valve motors in safety systems and the details as to how the devices will be tested. 1.14.1.41.2 Response Position C.1.b of Regulatory Guide 1.106 has been implemented in the HCGS design. Under this position the thermal overload contact for a safety-related motor operated valve that is normally operational during plant operation is bypassed during accident conditions. The requirements for main control room indication of bypasses alluded to by the reference to Section 4.13 of IEEE-279 is judged not to be applicable because no "protective action" is involved. This position was found acceptable by the NRC staff on the Zimmer docket (SER 7.1.3). 1.14.1.42 Reliability of Diesel Generator, LRG I/PSB-6 1.14.1.42.1 Issue Reliability of Diesel Generator. 1.14.1.42.2 Response Each standby diesel generator will be tested in accordance with HCGS Technical Specification 4.8.1.1.2. 1.14.1.43 Diesel Generator Reliability, LRG II/1-PSB 1.14.1.43.1 Issue The NRC issued specific recommendations on increasing the reliability of nuclear power plant emergency diesel generators via the document NUREG/CR-0660, "Enhancement of Onsite Emergency Diesel Generator Reliability". Information requests concerning these recommendations are routinely transmitted to the applicants during the review process. 1.14-34 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.43.2 Response HCGS intends to implement the appropriate recommendations of NUREG/CR-0660 as they apply to the onsite standby diesel generators. A summary of each recommendation is given below by a discussion of how the recommendation will be implemented. 1.14.1.43.2.1 Recommendation 1 - Moisture in Air Starting System The Air Starting System for the diesel generators relied on periodic blowdown of the air receivers for removal of entrained oil and excess water from the starting air. Operating experience has shown that accumulation of water in the Starting Air System has been one of the most frequent causes of diesel engine failure to start. It is recommended that air dryers be installed upstream of the air receivers. 1.14.1.43.2.1.1 HCGS Compliance HCGS uses an air dryer upstream of the air receivers to ensure a continual supply of dry starting air. The receivers also have drain valves. 1.14.1.43.2.2 Recommendation 2 - Air Quality in Diesel Generator Room Malfunction or failure of the contacts and relays to function properly is another major cause of diesel engine failure to start. The root cause is usually dust, dirt and grit between the electrical contact surfaces. It is recommended that all contacts and relays be inside dust tight enclosures and that dust control measures be implemented in the diesel generator rooms. 1.14-35 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.43.2.2.1 HCGS Compliance In order to protect electrical contact surfaces, diesel generator control panels are dust tight and drip proof in accordance with the design requirements for NEMA type 12 cabinets. In order to control dust in the area of the diesel generators, each unit is placed in its own cell. During normal plant operation, the ventilation systems provide filtered air, as a minimum, to areas containing diesel generator electrical controls. Ventilation system filters will be cleaned or replaced periodically. 1.14.1.43.2.3 Recommendation 3 - Turbocharger Heavy Duty Gear Drive The scheduling and frequency of surveillance testing can result in excessively long periods of no load and light load running of a diesel generator at full rated speed. This light loading results in insufficient exhaust gas energy to drive the turbocharge on the General Motors - Electro-Motive Division (GM-EMD) diesel engines. This results in the need to mechanically drive the turbocharger. Mechanically driving the turbocharger will result in a short life expectancy for the standard design turbocharger gear drive. It is recommended that a heavy duty gear drive be installed on the turbocharger. 1.14.1.43.2.3.1 HCGS Compliance This issue is not applicable since the HCGS diesel engines are by Colt-Pielstick. These engines do not have turbocharger gear drives. The turbochargers are driven by the exhaust gases only and are designed to operate properly even when no load is applied. 1.14.1.43.2.4 Recommendation 4 - Personnel Training There is a particularly difficult problem in developing knowledge and maintaining skills of the operators and maintenance personnel of 1.14-36 HCGS-UFSAR Revision 0 April 11, 1988

the diesel generator units. These units normally operate only during surveillance and trouble shooting tests to give assurance of readiness, should an emergency arise. The relatively short exposure to an operating unit makes "on the job" training especially difficult. When a nuclear power plant is put into operation, the operators having the diesel generator responsibility may have little or no related skills on such units. It is recommended that the training of the operators and maintenance personnel, and especially their immediate supervisors, be an intensive and continuing education program. This would serve to develop knowledge and skills among those less experienced and act as "refresher training" to maintain the familiarity and skills of the qualified personnel. 1.14.1.43.2.4.1 HCGS Compliance PSE&G will provide ongoing training for the maintenance personnel. Vendor training programs will be contracted for prior to operation. 1.14.1.43.2.5 Recommendation 5 - Automatic Pre-Lube Long periods on standby have a tendency to drain or nearly drain the engine lube oil piping systems. On an emergency start of the engine as much as 5 to 14 or more seconds may elapse from the start of cranking until full lube oil pressure is attained even though full engine speed is generally reached in about five seconds. With an essentially dry engine, the momentary lack of lubrication at the various moving parts may damage bearing surfaces with resultant equipment unavailability. It is recommended that the engine's electrically driven pre-lube pump be started by the same signal which initiates the cranking of the engine and be stopped when the engine stops cranking. An alternative approach would be to start the pre-lube pumps by the same signal but stop the pump when the pressure in the engine lube oil header has achieved a predetermined level. An electrically driven pre-lube pump accelerates to full speed quite rapidly with full delivery while the engine driven pump accelerates more slowly 1.14-37 HCGS-UFSAR Revision 0 April 11, 1988

with the engine. In either case, such modifications should be carried out in close consultation with the engine manufacturer. 1.14.1.43.2.5.1 HCGS Compliance The HCGS diesel engines are provided with a keepwarm/prelube system. This system is operated continuously, thus providing adequate lubrication to the various moving parts and bearing surfaces at all times. 1.14.1.43.2.6 Recommendation 6 - Testing Loading and Preventative Maintenance Testing and test loading are the essence of the surveillance test as practiced in the nuclear power plant. The basic function and value of a surveillance test on a diesel generator unit is to demonstrate operability. The following recommendations are provided to guide and standardize the general approach in surveillance testing:

1. No load and light load operation causing incomplete combustion should be minimized to reduce the formation of gum and varnish deposits on engine parts and to reduce the likelihood of mechanical failures. Minimum load should be at least 25 percent of rated load.

2. The surveillance test should be within the NRC guidelines and the frequency of testing, size of test load, and duration should generally follow the recommendations of the engine manufacturer.

3. Investigative testing, replacement and adjustment should be part of the preventative maintenance program. Testing, per se, is not a corrective measure and serves only as confirmation of readiness and operability, or as an indication of the need for corrective action.

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4. A "check off test" should be the final step after any corrective action.

An actual start, run, and load test would help to determine if mistakes were made during a corrective action. 1.14.1.43.2.6.1 HCGS Compliance The HCGS position on the above recommendation is as follows:

1. For no load and light load operation, the following conditions will be satisfied.

(a) Implement the manufacturer's recommendations for no load and light-load operations. (b) During periodic testing, the diesel will be loaded to a minimum of 25 percent of full load or as recommended by the manufacturer. (c) During troubleshooting, no load operation will be minimized. If the troubleshooting operation is over an extended period (that is, 3 to 4 hr or more), the engine shall be cleared in accordance with item 1 above.

2. Surveillance testing of standby diesel generators will comply with requirements provided in the HCGS Technical Specifications. These Technical Specifications will reflect the NRC guidance provided in the BWR Standard Technical Specifications, NUREG-0123 Rev. 3.

3. Preventive maintenance will go beyond the normal routine adjustments, servicing, and repair or components when a malfunction occurs. The preventive maintenance program will encompass investigative testing of components that have a history of repeated malfunctioning and require constant attention of repair. Furthermore, industry operating experience from sources such as the nuclear plant reliability 1.14-39 HCGS-UFSAR Revision 0 April 11, 1988

data system will be utilized as an aid in evaluating industry history for diesel generator component failure.

4. Upon the completion of repairs or maintenance and before an actual start, run, and load test, a final equipment check will be made to ensure that all electrical circuits are functional; that is, fuses are in place, switches and circuit breakers are in their proper position, no wires are loose, all test leads have been removed, and all valves are in the proper position to permit a manual start of the equipment. After the unit has been satisfactorily started and load tested, it will be returned to automatic standby service.

1.14.1.43.2.7 Recommendation 7 - Identification of Root Causes of Failures Improvement in reliability hinges on identification of the basic problem or "root cause" and the proper choice of corrective action. The effectiveness of all efforts to improve reliability depends on the proper execution in finding the true root cause of problems. This is especially difficult because of the usual chain of related cause and effect relationships. In order to detect "root causes" of problems, the following guidance should be observed:

1. The obvious cause should always be suspect as the "root cause". To be sure, the obvious is usually the direct cause of failure or malfunction.

The possible chain of cause and effect may fail to be investigated.

2. Closely spaced component failures should not be accepted unless accompanied by specific assurance of the absence of contributing causes and that alternate improved components are unavailable.

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3. The LER system and the records so produced have proven to be the best single source of information on the reliability status of the emergency diesel generators. Continued reliance of this source of information for reliability data should be encouraged.

1.14.1.43.2.7.1 HCGS Compliance In general, the above recommendations are inherent in the philosophy of good engineering and operating judgment. Such a philosophy is difficult to incorporate directly into a maintenance procedure and therefore is best accomplished as a function of an onsite review group. The purpose of such a group is to independently review atypical events, repetitive events and operating data from other stations in order to improve plant safety. PSE&G will establish such review groups in compliance with TMI Action Plan Item I.B.1.2 as contained in NUREG-0737. 1.14.1.43.2.8 Recommendation 8 - Diesel Generator Room Ventilation and Combustion Air Inlet Some installed diesel generator units take their combustion air from the engine room regardless of the extent of airborne dirt and the arrangement of the Fire Suppression System. Some units have inherent recirculation of hot cooling system air, hot room ventilation air, and even hot exhaust gas. It is recommended that the following design guidance be observed for ventilation and combustion air inlet systems:

1. Engine combustion air should be through piping directly from outside the building and at least 20 feet from ground level through proper filters.

2. Room ventilation air should be filtered and taken from a level at least 20 feet above ground level. The piping for the room ventilation air should be separate from that used for the engine combustion air.

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3. Room ventilation air, hot cooling system air and/or engine exhaust gas should not be permitted to circulate back into the diesel generator room, fuel storage area, or into any other part of the power plant.

1.14.1.43.2.8.1 HCGS Compliance The HCGS position on the above recommendations are as follows:

1. A separate source of combustion air for each diesel engine is taken from the diesel outside air intakes which are located at least 20 feet above ground level. This air is filtered prior to combustion.

2. The Auxiliary Building Ventilation System air is drawn from intakes which are at least 20 feet above ground level. As a minimum, ventilation for areas which house control equipment with electrical contacts is filtered.

The piping for the Auxiliary Building Ventilation System is separate from that used for the engine combustion air.

3. The air intake and exhaust gas openings are designed to prevent contamination of the intake air by exhaust products. Room ventilation air is recirculated to cool the diesel generator rooms when the diesels are running. It is a closed system not connected to the air intake or exhaust systems.

1.14.1.43.2.8 Recommendation 9 - Fuel Oil Storage and Transfer In order to assure proper fuel oil storage and handling, the following recommendations are made:

1. Bulk fuel storage tanks should have provisions for water removal. In addition, the fuel outlet pipe should be several inches above the tank bottom to allow some tank volume for settling of any water.

1.14-42 HCGS-UFSAR Revision 0 April 11, 1988

2. Fuel supply pumps for the engine fuel system should be engine driven. The fuel supply to the engine driven fuel pump should either be an assured gravity fed supply or else by a booster pump powered from a Class 1E station battery.

1.14.1.43.2.8.1 HCGS Compliance The HCGS position on the above recommendations is as follows:

1. Bulk fuel oil storage tanks have provisions for water removal. Water removal is via a drain located at the bottom of the tank.

The suction point in each storage tank is located six inches from the tank bottom to prevent any accumulated water from being transferred to the day tank.

2. Fuel supply pumps for the engine fuel system are engine driven. The fuel supply to these pumps is an assured gravity fed supply from the day tank.

1.14.1.43.2.10 Recommendation 10 - High Temperature Insulation for Overload Conditions The nature of the emergency diesel generator duty includes a possibility of large overloads which could extend longer than the time required to start large water pumps, etc. There is a possibility of engine overheating from such extreme emergency overloads causing a generator fire. It is recommended that high temperature rated generator insulation be utilized for the diesel generator units to reduce the generator fire hazard. 1.14.1.43.2.10.1 HCGS Compliance Adequate reliability is provided by the design, margin, and qualification testing requirements that are applied to HCGS standby diesel generators. 1.14-43 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.43.2.11 Recommendation 11 - Engine Cooling Water Temperature Control A water thermostat of the "3-way" or bypass type splits the water flow so that only as much water passes through the coolers or radiator as needed to maintain the proper water outlet temperature. This type of cooling water temperature control is used in most nuclear power plant diesel engine cooling systems and was the only design reviewed which gave no indication of trouble. It is recommended that all engine cooling water temperature control arrangements be by means of the 3-way thermostat design. 1.14.1.43.2.11.1 HCGS Compliance Temperature regulation of the HCGS standby diesel engine coolant is accomplished through the use of a "3-way" thermostatic valve. 1.14.1.43.2.12 Recommendation 12 - Concrete Dust Control Concrete floors tend to shed abrasive dust of sufficient particulate size to not only become airborne, but also to enter electrical cabinets and prevent contact from completely closing. It is recommended that the floors be painted in all rooms which house equipment with electrical contacts. 1.14.1.43.2.12.1 HCGS Compliance The accumulation of dust, including dust generated from concrete floors and walls, on the electrical equipment associated with the starting of the diesel generators is limited by:

1. Concrete floors are painted in all diesel generator areas which house equipment with electrical contacts.

2. The Auxiliary Building/Diesel Generator Area Ventilation System design and operation which provides filtered air to all diesel generator areas which house equipment with electrical contacts.

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3. Plant design which separates each standby diesel generator from other plant equipment and areas.

4. Administrative procedures for cleanliness and ventilation system maintenance.

1.14.1.43.2.13 Recommendation 13 - Mounting and Support of Instrumentation to Protect It From Vibration Damage It is recommended that instruments, controls, monitors, and indicating elements be supported in or on a freestanding, directly floor mounted panel to the extent functionally practical to reduce vibration induced wear. 1.14.1.43.2.13.1 HCGS Compliance Except for sensors and other equipment that must be directly mounted on the engine and associated piping, the controls and monitoring instrumentation for the standby diesel generators used at HCGS are installed on freestanding, floor mounted panels separate from the engine skids. 1.14.1.44 Shared DG Conformance To R.G. 1.81, LRG I/PSB-7 1.14.1.44.1 Issue Shared diesel design must meet position 2 of Regulatory Guide 1.81. 1.14.1.44.2 Response This issue is not applicable to HCGS since it is a single unit. 1.14-45 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.45 Periodic Diesel Generator Testing, LRG I/PSB-8 1.14.1.45.1 Issue Diesel Generator testing once every 18 months as required by Regulatory Guide 1.108. 1.14.1.45.2 Response Pre-operational and operational testing of the Hope Creek Generating Station standby diesel generators will be in accordance with Regulatory Guide 1.108 Revision 1 and errata dated September 1977. 1.14.1.46 Special Low Power Testing Program, LRG II/1-HFS 1.14.1.46.1 Issue TMI Action Plan Item I.G.1 indicated the need to supplement operator training by completing a special low power test program. Further clarification of this item includes the need to perform a simulated loss of offsite and onsite ac power. 1.14.1.46.2 Response See Section 1.10, Item I.G.1, for a discussion of operator training during low power testing. The Nuclear Training Center has formulated and implemented a training program for station blackout. Station Blackout Simulation Training is conducted with the Hope Creek Simulator. 1.14-46 HCGS-UFSAR Revision 8 September 25, 1996

1.14.1.47 Emergency Procedures Reactivity Control Guidelines, LRG II/2-HFS 1.14.1.47.1 Issue Develop a generic reactivity control guideline which can be utilized for preparing an emergency operating procedure for an anticipated transient without scram (ATWS) event. 1.14.1.47.2 Response HCGS Emergency Operating Procedure, OP-EO.ZZ-101, Reactor Control, contains the necessary actions to be taken during an ATWS event. 1.14.1.48 Common Reference For Reactor Vessel Level Measurement, LRG II/3-HFS 1.14.1.48.1 Issue The NRC has asked that a common reference level be established for reactor water level instruments. This is TMI action Item II.K.3.27. 1.14.1.48.2 Response A common reference point will be established for instruments measuring water level in the reactor vessel. Appropriate design modifications will be implemented by December 1984. See Section 1.10, Item II.K.3.27 for further details. 1.14.1.49 Reactor Coolant Sampling LRG II/1-CHEF 1.14.1.49.1 Issue In response to TMI Action Item II.B.3, applicants must demonstrate that the locations for post-accident sampling of the reactor coolant will provide samples representative of core conditions. Of specific concern is the potential for dilution of makeup water. 1.14-47 HCGS-UFSAR Revision 8 September 25, 1996

1.14.1.49.2 Response This issue is addressed in Section 9.3.2. Samples will be obtained from a tap off the jet pump pressure instrument system. Sample representativeness will be assured if there is sufficient core flow to circulate water from the core to the jet pump intake. After a small break or nonbreak accident, the operator would maintain the reactor water level at or near normal by using emergency procedures. For decay power greater than 1 percent of rated power, it is estimated that the core flow would be greater than 10 percent of the rated flow due to natural circulation. The entire reactor water inventory would be circulated through the jet pumps in about 3 to 4 minutes, thus assuring that representative samples of core coolant will be available at the jet pumps. At power levels of less than 1 percent of rated power, a representative sample would be obtained by increasing the reactor water level by 18 inches to fully flood the moisture separators and provide a thermally induced recirculation flow path for mixing. Makeup water would not significantly dilute the sample. Makeup water flow amounts to approximately 2 percent of the core flow for small steam line breaks or nonbreak accidents. For small liquid line breaks, the makeup water flow rate is estimated to be less than 18 percent of the core flow. Thus, no significant dilution would occur, and the water circulating through the jet pump would be representative of reactor coolant inventory for small break or nonbreak accidents. Furthermore, sample lines in the RHR system provide for a reactor coolant sample when the reactor is depressurized and at least one of the loops of the Residual Heat Removal (RHR) System is operating in the shutdown cooling mode. For larger line breaks where reactor water level cannot be maintained, reverse flow through the core to the suppression pool is 1.14-48 HCGS-UFSAR Revision 0 April 11, 1988

provided. Representative suppression pool samples are obtained from the RHR pump discharge as discussed in Licensing Issue No. 50, see Section 1.14.1.50. 1.14.1.50 Suppression Pool Sampling, LRG II/2-CHEB 1.14.1.50.1 Issue In response to TMI Action Item II.B.3, applicants must demonstrate the locations for post-accident sampling of the suppression pool will provide samples representative of the pool inventory. 1.14.1.50.2 Response This issue is addressed in Section 9.3.2. Samples will be taken from the pump discharge from the Residual Heat Removal (RHR) System when the RHR loop is in the suppression pool cooling mode. The sample lines are installed on the discharge side of the RHR pumps downstream of the pump check valve. Representative samples will be assured by operating the selected RHR loop for approximately 30 minutes prior to taking a sample. Since no SRVs discharge directly into the RHR intake and the locations of the SRV discharge facilitate pool mixing, the suppression pool sample location will provide samples representative of pool inventory. 1.14.1.51 Estimation of Fuel Damage From Post-Accident Samples, LRG II/3-CHEB 1.14.1.51.1 Issue The NRC Staff required LRG II plants to prepare a procedure for estimating fuel damage from the radionuclide concentration in the reactor coolant and the suppression pool. 1.14-49 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.51.2 Response The BWR Owners' Group (BWROG) transmitted to the NRC staff in a June 17, 1983 letter from T. J. Dente (BWROG) to D. G. Eisenhut (NRC), generic procedures for estimating core damage from post-accident measurements of radionuclide concentration in the reactor coolant and the suppression pool and of hydrogen and radiation levels in the containment. During a July 20, 1983 meeting with the BWROG, the NRC staff accepted these generic procedures. Public Service Electric and Gas endorses these generic procedures and will prepare HCGS unique core damage estimation procedures based on the generic procedures. 1.14.1.52 Failures in Vessel Level Sensing Lines Common to Control and Protective Systems, LRG II/1-ICSB 1.14.1.52.1 Issue The NRC staff is concerned about the failure of a vessel level sensing line that is common to control and protective systems. They have asked the applicants to analyze the consequences of such a failure concurrent with the worst additional single failure in the protective systems or their initiation circuits. 1.14.1.52.2 Response An analysis was performed to determine the consequences of failure in a vessel level sensing line, common to control and protective circuits, in combination with the worst single failure in a protective channel. The results of this analysis are contained in the response to Question 421.23. More recently, NRC Generic Letter 92-04 identified that under certain conditions the reference legs can become filled with condensate that contains high levels of dissolved noncondensible gases. If the reactor vessel were to rapidly depressurize these gases would come out of solution causing the dp transmitters to sense a level that would be non conservative. Subsequently, NRC Bulletin 93-03 was issued and stated that as a result of the phenomenon described in the Generic Letter the water level instrumentation may not satisfy GDC 13, 21, 22 and Section 4.20 of IEEE-279. To satisfy the requirements of NRC Bulletin 93-03 a backfill system has been installed. 1.14-50 HCGS-UFSAR Revision 7 December 29, 1995

The backfill system consists of four independent pressure regulating stations, one for each reference leg. Each regulating station is supplied from the CRD system drive water header. Two adjustable orifice valves on each station are used to drop approximately 50 percent of this differential pressure across each valve and to set the backfill flow to approximately 0.50 GPH. Each regulating station also provides backup pressure regulation so that, if the drive water header pressure were to fail high, the backfill flow would be limited. Each pressure regulating station also has a local flow indicating device that assures positive flow into each reference leg. Isolation, bypass, and drain valves are provided for each station to facilitate maintenance and calibration of the components on the regulating station. The output of each regulating station is connected to 3/8 in. stainless steel tubing routed through the Reactor Building. This tubing is connected to safety related check valves, two in series, for each reference leg. This configuration is the interface for the non safety related backfill tubing and the safety related instrument tubing. These safety related check valves are spring loaded so that a positive dp across the check valves is required for backfill flow into the reference leg. These check valves are connected to the outboard side of the excess flow check valve for each reference leg. 1.14-50a HCGS-UFSAR Revision 7 December 29, 1995

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1.14.1.53 Physical Separation and Electrical Isolation, LRG I/ICSB-2 1.14.1.53.1 Issue The applicant's design, Class 1E instrumentation do not adhere to adequate separation criteria, have not been qualified, and do not adhere to separation of Class 1E to non-Class 1E instrumentation. 1.14.1.53.2 Response HCGS complies with Regulatory Guide 1.75 to the extent stated in Section 1.8.75, and therefore this issue is not applicable to HCGS. 1.14.1.54 Redundancy and Diversity of High/Low Pressure System Interlocks, LRG II/2-ICSB 1.14.1.54.1 Issue During normal and emergency conditions, it is necessary to keep low pressure systems, which are connected to the high pressure Reactor Coolant System, properly isolated from high reactor coolant pressure. Overpressurization of low pressure ECCS lines would increase the potential for the loss of the integrity of the low pressure system. The NRC staff asked for redundant overpressure protection of the low pressure ECCS lines and for independent and diverse interlocks on the valves when two motor operated valves constitute the low pressure/high pressure interface. 1.14.1.54.2 Response The design of the isolating interlocks for the HCGS low pressure, high pressure interfaces with two motor operated valves (i.e., the intake valves for the Residual Heat Removal System in the shutdown cooling mode) provides for diversity by incorporating: 1.14-51 HCGS-UFSAR Revision 0 April 11, 1988

1. Redundant isolating interlock equipment

2. Separate divisional power and signal sources as well as transmission channels.

3. Diverse installation locations of isolation interlock equipment and by administrating a comprehensive program for monitoring, operating, and testing isolating valves and interlocks.

1.14.1.55 ATWS, LRG I/ICSB-3 1.14.1.55.1 Issue ATWS 1.14.1.55.2 Response See response to LRG Issue No. 31, Section 1.14.1.31. 1.14.1.56 Test Techniques, LRG I/ICSB-4 1.14.1.56.1 Issue In order to perform routine surveillance testing, it is necessary for the applicant to pull fuses. We consider that this design does not satisfy the requirements of IEEE 279-1971, Paragraphs 4.11 and 4.20. 1.14.1.56.2 Response HCGS does not take exception to paragraphs 4.11 and 4.20 of IEEE 279-1971 and therefore this issue is not applicable to HCGS. 1.14-52 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.57 Potential for Both Low-Low Setpoint Valves to Open Due to Single Failures, LRG II/3-ICSB 1.14.1.57.1 Issue In other low-low set designs, single electrical or mechanical failures could allow both low-low setpoint valves to reopen simultaneously or to be open concurrently, potentially defeating the safety design basis. 1.14.1.57.2 Response SRV low-low setpoint logic is discussed in FSAR Section 7.6.1.6.2. 1.14.1.58 Safety System Setpoints, Instrument Range, LRG I/ICSB-5 1.14.1.58.1 Issue The NRC staff was concerned that the ranges of the sensors in class 1E systems may be exceeded by the worst-case combination of their setpoints and accuracies. 1.14.1.58.2 Response The review of safety system setpoints verifies that the sensor ranges are not exceeded by the worst-case combination of setpoints and accuracies. The safety system setpoints provided by GE are being reviewed in the "Instrument Setpoint Methodology Program" described in response to Question 421.18. 1.14.1.59 IE Bulletin 80-06: Engineered Safety Feature Reset Control, LRG II/4-ICSB 1.14.1.59.1 Issue The NRC staff asked that during the evaluation of compliance with I&E Bulletin 80-06, applicants identify those systems that do not 1.14-53 HCGS-UFSAR Revision 0 April 11, 1988

remain in the emergency mode if there is a reset of the actuation signal and that any deviations or proposed design changes be justified. 1.14.1.59.2 Response This bulletin has been reviewed with respect to the HCGS design. The review indicates that all systems serving safety-related functions do not change modes or status and are returned to normal control after an ESF actuation signal is reset. However, subsequent equipment failures could cause status changes, such as standby or backup systems coming online to maintain the system parameters within the set limits. In short, resetting an ESF signal will not trip any systems off or defeat isolation of containment. 1.14.1.60 Drawings, LRG I/ICSB-6 1.14.1.60.1 Issue The one line drawings and schematics contradict the functional control drawings and system descriptions which are provided in the FSAR. Furthermore, contact utilization charts contradict the actual schematics. 1.14.1.60.2 Response For HCGS, the General Electric (GE) functional control drawings are generic in nature and are not updated to show the HCGS' specific design. HCGS plant wiring diagrams are developed from the GE elementaries, system digital logic diagrams, system analog loop diagrams, vendor wiring diagrams, and station one line drawings (where applicable). The HCGS schematics and wiring diagrams are an accurate representation of the engineered design. 1.14-54 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.61 Control Systems Failure, LRG II/5-ICSB 1.14.1.61.1 Issue LRG-II plants are required to identify any failures which could result in the malfunctions of more than one control system and show that such failures would not yield consequences beyond those considered in Section 15 nor would require response beyond operator or safety system capability. 1.11.1.61.2 Response All HCGS safety-related control systems have been designed to satisfy requirements of 10CFR50, Appendix A, General Design Criterion 21, 22, 23, 24, 25, and 29 and IEEE 279-1971, as stated in Section 7.1. By following these standards the HCGS design precludes the possibility of any single failure causing the simultaneous failure or malfunction of more than one safety-related control system. 1.14.1.62 RCIC Classification, LRG I/ICSB-7 1.14.1.62.1 Issue The NRC staff wanted assurance of the availability of a Seismic Category I water source by an automatic switchover to the suppression pool upon failure of the condensate storage tank. 1.14.1.62.2 Response See response to LRG Issue No. 6, Section 1.14.1.8. 1.14-55 HCGS-UFSAR Revision 8 September 25, 1996

1.14.1.63 Safety-Related Display, LRG I/ICSB-9 1.14.1.63.1 Issue The design of safe shutdown systems of LRG-I/II plants must satisfy the requirements of IEEE 279-1971, Paragraph 4.10. 1.14.1.63.2 Response HCGS control and instrumentation systems important to safety are designed to satisfy the requirements of IEEE 279-1971. HCGS takes no exception to paragraph 4.10 of IEEE 278-1971, therefore this issue is not applicable to HCGS. 1.14.1.64 Rod Block Monitor LRG I/ICSB-10 1.14.1.64.1 Issue Section 7.7 of the FSAR indicates that the Rod Sequence Control System (RSCS) is utilized to restrict rod worths for the design basis rod drop accident and the rod block monitor (RBM) is utilized to prevent erroneous withdrawal of control rods to prevent local fuel damage. The NRC staff asked for the rationale and basis for not including these systems or portions of these systems as safety-related and for a discussion of their interfaces with safety-related portions of the design (e.g., average power range monitor (APRM), refueling interlocks, etc.). 1.14.1.64.2 Response The Rod Worth Minimizer (RWM) acts to prevent withdrawal of an out of sequence control rod, to prevent an erroneous continuous control rod withdrawal during reactor startup, and to minimize the core reactivity transient during a rod drop accident. The consequences of a rod withdrawal error in the startup range are analyzed in Appendix 15.B where it is demonstrated that the licensing basis criterion for fuel failure is still satisfied even when the RWM fails to block rod 1.14-56 HCGS-UFSAR Revision 9 June 13, 1998

withdrawal. Thus, the RWM and the Manual Control System (RMCS) are not safety-related. The safety action required for the continuous control rod drop incident (a reactor scram) is provided by the safety related intermediate range monitor (IRM) subsystem of the Neutron Monitoring Systems (NMS). If the setpoint that trips a core flux scram is reached during a flux transient, the IRM will both block further rod withdrawal and initiate a scram. Furthermore, a second safety related NMS scram trip, supplied by the APRM, can terminate the core power transient. The RWM does not interface with safety-related systems. Refueling interlocks are not considered safety-related. The rod block monitor is designed to prohibit erroneous withdrawal of a control rod during operation at core high power levels. This prevents local fuel damage under permitted bypass and/or detector chamber failure in the local power range monitor (LPRM), and prevents local fuel damage during a single rod withdrawal error. Local fuel damage poses no significant threat relative to radioactive release from the plant. Although the RBM does not perform a safety-related function, in the interest of plant economics and availability, it is designed to meet certain salient design principles of a safety system. These include the following:

1. Redundant, separate, and isolated RBM channels.

2. Redundant, separate, and isolated rod selection information, including isolated contacts for each rod selection pushbutton providing input to each RBM channel.

3. Independent, isolated RBM level readouts and status displays from the RBM channel.

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4. A mechanical barrier between Channels A and B of the manual bypass switch.

5. Multiple manual RBM channel bypass prohibited by switch design.

6. Independent, separate, isolated rod block signals from the RBM channels to the RMCS circuitry.

7. Fail safe design, since loss of power initiates a rod block.

8. Initiation of a rod block by trip of either RBM channel The RBM interfaces with the following safety-related systems:

1. LPRM: LPRM signal information is provided to each RBM channel from either the APRM instrument or LPRM instrument for each division via fiber optic link.

2. Flow Signal: Recirculation flow inputs are provided to the RBM from either the APRM instrument or LPRM instrument for each division via fiber optic link for trip reference.

3. APRM System: Independent, separate, and isolated APRM reference signals are supplied to each RBM channel for trip reference.

(Historical Information) 1.14.1.65 MSIV Leakage Control System, LRG I/ICSB-11 1.14.1.65.1 Issue We identified a single failure to the MSIV Leakage Control System which could lead to possible failure of the system during testing or operation. 1.14.1.65.2 Response The MSIV Sealing System is capable of performing its function following a LOCA concurrent with an assumed single active failure including failure of any one of the MSIVs to close. The MSIV Sealing System is discussed in Section 6.7 and its instrumentation and controls are covered in Section 7.3. 1.14-58 HCGS-UFSAR Revision 23 November 12, 2018

1.14.1.66 Procedures Following Bus Failure (IE Bulletin 79-27), LRG II/6-ICSB 1.14.1.66.1 Issue IE Bulletin 79-27 requires all LRG-II plants to provide cold shutdown procedures to be followed upon loss of a non-Class 1E instrumentation and control bus during plant operation. 1.14.1.66.2 Response Procedures will be used by control room operators to achieve cold shutdown conditions upon loss of power to each Class 1E and non-Class 1E bus supplying power to safety and non safety-related instrument and control bus. Procedures are available for review. 1.14.1.67 Harsh Environment For Electrical Equipment Following High Energy Line Breaks, LRG II/7-ISCB 1.14.1.67.1 Issue LRG-II plants need to perform a review to determine any required design changes or operator actions necessary to assure that high energy line breaks would not cause control systems malfunction and complicate the event beyond the existing FSAR analysis. 1.14-59 HCGS-UFSAR Revision 12 May 3, 2002

1.14.1.67.2 Response HCGS has performed a plant specific review of all safety-related areas with regard to high energy line break. The hazards considered in high energy line break analysis (HELBA) are pressurization, temperature, pipe whip, flooding and jet impingement. All components, that are required to operate for pipe break mitigation (PBOC, PBIC) are either qualified for the harsh environment or rerouted or relocated to avoid the harsh environment. If the above alternatives are not possible, the components are to be modified (more supports, protective shields, or upgrade component material, etc.,) to withstand the harsh environment. 1.14.1.68 Steam Bypass of the Suppression Pool, LRG I/CSB-1 1.14.1.68.1 Issue The applicant's approach to suppression pool bypass is not consistent with Branch Technical Position CSB 6-5. The applicant must commit to perform a lower power surveillance leakage test of the containment during refueling outage. 1.14.1.68.2 Response HCGS commitments to a drywell to suppression chamber bypass test discussed in Section 6.2.6. 1.14.1.69 Pool Dynamic LOCA and SRV Loads, LRG I/CSB-2 1.14.1.69.1 Issue The large scale testing of an advanced design pressure-suppression containment, and the in-plant testing of Mark containments identified new suppression pool hydrodynamic loads that had not been explicitly accounted for in the original Mark I containment system design. The new loads resulted from postulated loss-of-coolant accident and safety/relief valve operation. Because these hydrodynamic loads had not been considered in the original design basis of the Mark I containment system, a detailed reevaluation of Mark I containment design is required to restore the originally intended design safety margins. 1.14-60 HCGS-UFSAR Revision 23 November 12, 2018

1.14.1.69.2 Response HCGS FSAR Appendix 3B contains a summary of the plant unique analysis of the HCGS containment. It was performed in accordance with the requirements of the NUREG-0661, and demonstrates that the HCGS primary containment meets the acceptance criteria of NUREG-0661. The original Hope Creek SRVs were Target Rock 2-Stage SRVs, and the plant unique analysis summarized in Appendix 3B was prepared for the 2-Stage SRVs. Target Rock 3-Stage SRVs have been evaluated and approved for installation at Hope Creek. The Plant Unique Analysis does not require revision for installation of 3-Stage SRVs. The 3-Stage SRVs have the same set pressures, capacity and response time as the 2-Stage SRVs. They also utilize the same main valve body as the 2-Stage SRV, with minor modification. 1.14.1.70 Containment Dynamic Loads, LRG II/1-CSB 1.14.1.70.1 Issue LRG-II plants must use NRC approved containment load definitions as the basis for containment dynamic load evaluations. LRG-II plants must demonstrate that previous tests are applicable or must commit to perform in-situ safety/relief valve (SRV) tests. The original Hope Creek SRVs were Target Rock 2-Stage SRVs. Target Rock 3-Stage SRVs have been evaluated and approved for installation at Hope Creek. Confirmatory in-situ tests were not repeated when the 3-Stage Target Rock SRVs were approved for installation because they have the same set pressures, capacity and response times as the original 2-Stage SRVs. 1.14.1.70.2 Response HCGS is using NRC approved containment load definitions (NUREG-0661) as the basis for containment dynamic load evaluations with certain exceptions, identified in Appendix 3B. Hope Creek intends to perform confirmatory in-situ SRV tests. 1.14.1.71 Containment Purge System, LRG I/CSB-3 1.14.1.71.1 Issue Containment purge systems often have small vent lines that are used to bleed off excess primary containment pressure during normal operation. Because the lines provide an open path from the 1.14-61 HCGS-UFSAR Revision 23 November 12, 2018

containment to the environs, they must be evaluated against the requirements of Branch Technical Position CSB 6-4. 1.14.1.71.2 Response The Containment Inerting and Purge System (CIPS) is designed to purge the primary containment prior to and during outages. The Containment Prepurge Cleanup System (CPCS) is designed to reduce the level of atmospheric halogen radioactivity to within radiological effluent Technical Specification limits, as required, prior to purging the primary containment. The requirements outlined in BTP CSB 6-4 pertain to the use of CIPS/CPCS during normal power operation. During normal operation the 6-, 24-, and 26-inch containment isolation valves will be administratively controlled to assure that they are not opened except as permitted by the Technical Specifications. To relieve the initial containment pressure buildup caused by the temperature increase during reactor power ascension and to reduce pressure as required during other normal operating transients, the first containment isolation valve from the drywell and/or suppression chamber may be opened in accordance with the Technical Specifications to permit the use of the 2-inch vent lines that bypass the second isolation valve. The frequency of operation of the 2-inch bypass vent paths used to reduce containment pressure during normal plant operation will depend on operating experience at HCGS. The operator will open the 2-inch bypass vent paths if the drywell normal operating pressure approaches the technical specification limit. The containment isolation valves and the bypass lines are shown on Plant Drawing M-57-1. The following is an evaluation of CIPS/CPCS with respect to the criteria specified in BTP CSB 6-4, when used during normal power operation. The evaluation is keyed to the criteria of BTP CSB 6-4. 1.14-62 HCGS-UFSAR Revision 20 May 9, 2014

1.14.1.71.2.1 Criterion 1.a The reliability and performance capabilities of the containment isolation valves should be commensurate with the importance to safety of isolating the system penetrating the primary containment boundary. 1.14.1.71.2.1.1 Response The CIPS/CPCS isolation valves, bypass vent valve, and interconnecting piping are designed as ASME Section III, Class 2 components. The design criteria for these components include the pressure, temperature, flow, and other environmental conditions associated with closure following a DBA in the containment. Therefore, the HCGS design complies with this criterion. 1.14.1.71.2.2 Criterion 1.b The number of supply and exhaust lines should be limited to one supply line and one exhaust line to improve the reliability of the isolation function. 1.14.1.71.2.2.1 Response Only one supply line and one exhaust line may be open at any given time during power operation, startup, or hot shutdown, as required, in accordance with the Technical Specifications. 1.14.1.71.2.3 Criterion 1.c The size of the vent lines should not exceed 8 inches in diameter. 1.14-63 HCGS-UFSAR Revision 1 April 11, 1989

1.14.1.71.2.3.1 Response The radiological analysis presented in Section 1.14.1.71.2.11.1 justifies the use of 26-inch purge supply and exhaust lines with the purge valves closing within 5 seconds, including an assumed 1-second instrument time delay, of the onset of a LOCA. 1.14.1.71.2.4 Criterion 1.d The containment isolation provisions for the purge system lines should meet the appropriate standards of engineered safety features. 1.14.1.71.2.4.1 Response The isolation provisions for the CIPS/CPCS fully comply with the required standards of an engineered safety feature. The redundant isolation valves and the bypass vent valve are designed to Seismic Category I standards, classified as Quality Group B, protected from missiles, and are powered and actuated by diverse means, thus allowing them to accommodate a single failure. 1.14.1.71.2.5 Criterion 1.e The instrumentation and control systems provided to isolate the vent system lines should be independent and actuated by diverse parameters. Motive power to close the isolation valves should also be from diverse sources. 1.14.1.71.2.5.1 Response The instrumentation and controls provided to isolate the CIPS/CPCS vent path comply with the stated criterion. 1.14.1.71.2.6 Criterion 1.f The isolation valve closure times should not exceed 5 seconds to facilitate compliance with 10CFR100. 1.14-64 HCGS-UFSAR Revision 1 April 11, 1989

1.14.1.71.2.6.1 Response The isolation valve maximum closure time is 5 seconds, including instrument delay time. 1.14.1.71.2.7 Criterion 1.g Provisions should be made to ensure that isolation valve closure will not be prevented by debris which could potentially become entrained in the escaping air and steam. 1.14.1.71.2.7.1 Response Debris protection for the containment vent and purge lines is discussed in Section 6.2.4.3.2.1. It is also unlikely that any debris will be thrown directly into the vent line opening since there is only one high energy line in the immediate vicinity of the containment penetration and any postulated breaks in it will not be favorably oriented to project any debris into the opening. 1.14.1.71.2.8 Criterion 2 The purge system should not be relied on for temperature and humidity control. 1.14-65 HCGS-UFSAR Revision 1 April 11, 1989

1.14.1.71.2.8.1 Response The purge system and the bypass vent path are not relied on for temperature and humidity control within the containment. The drywell coolers perform this function. 1.14.1.71.2.9 Criterion 3 Containment atmosphere cleanup systems should be provided within containment to minimize the need for purging. 1.14.1.71.2.9.1 Response The containment prepurge cleanup system, located in the Reactor Building, is connected to the primary containment, as shown on Plant Drawings M-57-1 and M-76-1, and is used for cleanup prior to reactor shutdown, as required. Location of the CPCS within the primary containment is not practical for a BWR Mark I containment. Operation of the CPCS will be limited to the minimum time necessary to allow purging of the primary containment and only when deinerting of the primary containment is planned (see Section 6.2.5.2.1). 1.14.1.71.2.10 Criterion 4 Provisions should be made for testing the availability of the isolation function and the leakage rate during reactor operation. 1.14.1.71.2.10.1 Response Operation of individual actuators can be independently verified during normal operation. Provisions have also been made to perform leakage rate tests during reactor operation. 1.14.1.71.2.11 Criterion 5.a An analysis of the radiological consequences of a LOCA should be performed. Radiological consequences should be within 10CFR50.67 limits. 1.14-66 HCGS-UFSAR Revision 20 May 9, 2014

(Historical Information) 1.14.1.71.2.11.1 Response An analysis of the radiological consequences associated with a LOCA occurring while operating the CIPS/CPCS has been performed. The resultant site boundary dose to the thyroid, which is the most limiting dose due to the purge duct

                  -2 alone, is 1.5 x 10    rem. Dose impact due to tritium and particulate release is  considered  negligible. This  dose   is   a  very  small   fraction  of  the 10CFR100 guideline value of 300 rem - thyroid.      The resultant dose is based on the realistic release assumptions given in BTPCSB 6-4 (SRP 6.2.4) for showing acceptable purge valve closure times.      The analysis assumes that the drywell purge supply and exhaust valves are open when the LOCA occurs.          These valves take 5 seconds to close following a LOCA (including instrument delay time), and the releases are assumed to be unfiltered.      Specifically, the analysis assumes a 1-second instrument delay time and a 4-second valve stroke time totaling 5 seconds, including instrument delay. This analysis bounds the case of a LOCA occurring  when  the  2-inch   bypass  vent  valves   are  open   and  the  outboard isolation valves are closed. The total mass released is 1694 pounds.

1.14.1.71.2.12 Criterion 5.b Protection of safety-related equipment downstream of the vent path isolation valves shall be provided to prevent the effects of a LOCA from adversely affecting their ability to function. 1.14.1.71.2.12.1 Response The effects of a LOCA, with the purge isolation valves open, on the safety-related equipment downstream of the valves has been analyzed and evaluated. The FRVS fan and filter units are normally isolated from the RBVS ducts and are not used during cleanup or purge operations. Blowout panels have been added to the CPCS ducts before the RBVS/FRVS isolation dampers. These blowout panels limit the pressure pulse in the ducts required for FRVS operation. The integrity of the FRVS ducts and equipment due to the resulting 1.14-67 HCGS-UFSAR Revision 12 May 3, 2002

pressurization was verified. The FRVS air handling units are individually isolated from the ducts on the inlet and outlet by dampers at the fan/filter units. These dampers will remain closed during the pressure pulse due to a LOCA during purging. The pressure pulse will have ended before the FRVS fans are started. The effects of steam release during the blowdown also were evaluated. The evaluation verified that the steam will not adversely affect the performance of the FRVS. 1.14-67a HCGS-UFSAR Revision 3 April 11, 1991

THIS PAGE INTENTIONALLY BLANK 1.14-67b HCGS-UFSAR Revision 1 April 11, 1989

1.14.1.71.2.13 Criterion 5.c The effects on ECCS of a loss of containment atmosphere through the containment purge during a LOCA should be analyzed. 1.14.1.71.2.13.1 Response There will be no significant reduction in containment pressure resulting from the blowdown. Furthermore, this reduction would have no effect on ECCS performance, since the ECCS pumps are sized for atmospheric suction pressure. No credit is taken for containment pressure acting on the pump suction. 1.14.1.71.2.14 Criterion 5.d The maximum allowable leak rate of the purge isolation valves shall be specified based on proper consideration of valve size, allowable containment leakage, and bypass leakage limitations (if applicable). 1.14.1.71.2.14.1 Response Leakage rates on the purge and vent isolation valves are based on complying with the limits established by the HCGS Technical Specifications, 10CFR50, Appendix J, and the Primary Containment Leakage Rate Testing Program, and are periodically tested to verify their performance. 1.14.1.71.3 Summary As discussed above, the HCGS purge supply and exhaust valves comply, to the maximum extent practical, with the criteria of BTP CSB 6-4. When coupled with the extremely unlikely event of a LOCA occurring while the drywell or suppression chamber valves are open, it is concluded that an adequate safety design exists for limited operation of the CIPS/CPCS during modes other than cold shutdown or refueling. 1.14-68 HCGS-UFSAR Revision 9 June 13, 1998

1.14.1.72 Combustible Gas Control, LRG I/CSB-4 1.14.1.72.1 Issue The proposed Combustible Gas Control System is designed in accordance with the requirements of 10CFR50.14, we require the applicant to commit to the following:

1. When the containment pressure is above 15.3 psig and the hydrogen concentration is 3.3 volume percent, the Containment Spray System must be actuated to reduce the containment pressure.

2. Following a LOCA, the recombiner system becomes an extension of the containment boundary. We require the applicant to demonstrate the leaktight integrity of the recombiner system.

3. Applicants for which the recombiner system design pressure is less than the predicted containment design pressure; the applicants commit to actuate the containment spray system as listed on the individual docket.

4. Applicants agree to perform system leak tests.

1.14.1.72.2 Response

1. The HCGS FSAR Section 6.2 does not postulate containment pressure greater than 15.3 psig concurrent with hydrogen concentration greater than or equal to 3.3 volume percent. Even without containment spray, Figure 6.2-7 (Case C) shows that 15.3 psig containment pressure (after the initial spike) occurs at 8.33 hours.

While Figure 6.2-32 shows hydrogen concentration of 3.3 volume percent is not reached until approximately 36 hours. 1.14-69 HCGS-UFSAR Revision 0 April 11, 1988

Therefore, assuming the pressure remains above 15.3 psig, the operator has more than 27 hours to actuate the containment spray. The containment spray will quickly lower the containment pressure below that required for recombiner operation.

2. The recombiner system is designed and inspected in accordance with ASME Section III, Class 2 requirements. Prior to installation, the recombiners will be shown to have no detectable leakage, using soap solution, when tested in accordance with Article NC-6300 of the ASME Section III B&PV Code. Valve stems and gasketed flange joints are exempted from this test.

Additionally, the complete recombiner unit (including valve stems and gasketed flange joints) shall have a leak rate equal to or less than 0.5 standard cubic centimeters per second (standard conditions are 68F and 14.7 psia) when tested at a pressure equal to or greater than 30 psia. Section 6.2.5.4 and Section 1.10, Position III.D.1.1 refer to additional test requirements.

3. The HCGS recombiner design pressure equals the containment design pressure. Reference Table 6.2-17.

4. See response to Item 2 above.

1.14.1.73 Hydrogen Control Capability, LRG II/2-CSB 1.14.1.73.1 Issue Provide a description of the program to improve the hydrogen control capability. 1.14-70 HCGS-UFSAR Revision 0 April 11, 1988

The program should include:

1. A description of the system the plants propose to install

2. The installation schedule

3. Its design bases

4. Research programs (including schedules) designed to demonstrate and/or confirm efficacy of the proposed system.

1.14.1.73.2 Response Section 6.2.5 describes the current proven design which assures control of postulated hydrogen generation with the following major features:

1. Inerted containment

2. Redundant safety-related containment hydrogen recombiners.

3. Redundant safety-related hydrogen/oxygen analyzers.

1.14.1.74 Containment Leakage Testing, LRG I/CSB-5 1.14.1.74.1 Issue Detailed information is required to demonstrate compliance with 10CFR50, Appendix J and to evaluate any exceptions. 1.14.1.74.2 Response Compliance with Appendix J is discussed in Section 6.2.6. Exceptions are identified in Table 6.2-26 and justified in the footnotes. 1.14-71 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.75 BWR Scram Discharge Volume Modifications LRG II/1-ASB 1.11.1.75.1 Issue The Control Rod Drive Hydraulic System (CRDHS) should conform to the Scram Discharge System design criteria enumerated in the generic Safety Evaluation Report (SER), BWR Scram Discharge System, dated December 1, 1980. 1.14.1.75.1.1 Response HCGS complies with the criteria enumerated in the generic Safety Evaluation Report, BWR Scram Discharge System. The criteria given in the referenced SER are organized according to; 1) functional, 2) safety, 3) operational, 4) design and 5) surveillance criteria. A summary of each criteria is given below along with a discussion of HCGS CRDHS compliance. 1.14.1.75.2 Functional Criteria 1.14.1.75.2.1 Functional Criterion 1 The scram discharge volume (SDV) shall have sufficient capacity to receive and contain water exhausted by a full reactor scram without adversely affecting control-rod-drive scram performance. 1.14.1.75.2.1.1 Response A minimum scram discharge volume of 3.34 gallons per drive is provided. This minimum scram discharge volume is based on conservative assumptions as to the performance of the scram system. In the event of a coolant leak into the SDV, an automatic scram will occur before the SDV's available volume is threatened. 1.14-72 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.75.2.2 Safety Criteria 1.14.1.75.2.2.1 Safety Criterion 1 No single active failure of a component or service function shall prevent a reactor scram, under the most degraded conditions that are operationally acceptable. 1.14.1.75.2.2.1.1 Response No single active failure in the HCGS scram system design will prevent a reactor scram. The Scram Discharge System design meets the NRC acceptance criterion for Safety Criterion 1. Partial or full loss of service functions will not adversely affect the scram system function or will result in a full reactor scram. There are no reductions in the pipe size of the header piping going from the hydraulic control units (HCUs) to and including the scram discharge instrument volume (SDIV). This hydraulic coupling permits operability of the scram level instrumentation prior to loss of system function. The scram level instrumentation are redundant and diverse to assure no single active failure or common mode failure prevents a reactor scram. 1.14.1.75.2.2.2 Safety Criterion 2 No single active failure shall prevent an uncontrolled loss of reactor coolant. 1.14.1.75.2.2.2.1 Response Redundant scram discharge volume (SDV) vent and drain valves are a part of the HCGS design. The redundant SDV valve configuration shown in Plant Drawing M-47-1 assures that no single active failure can result in an uncontrolled loss of reactor coolant. An additional solenoid operated pilot valve controls the redundant vent and drain valves. The vent and drain system is sufficiently redundant to avoid a failure to isolate the SDV due to solenoid failure. The 1.14-73 HCGS-UFSAR Revision 20 May 9, 2014

opening and closing sequences of the vent and drain valves are controlled to minimize excessive hydrodynamic forces. 1.14.1.75.2.2.3 Safety Criterion 3 The Scram Discharge System instrumentation shall be designed to provide redundancy, to operate reliably under all conditions, and shall not be adversely affected by hydrodynamic forces or flow characteristics. 1.14.1.75.2.2.3.1 Response Diverse, and redundant level sensing instrumentation is provided for the automatic scram function. SDIV water level is measured by utilization of both float switches and differential pressure sensing devices. All instrument taps are located on the SDIV to protect the level sensing instrumentation from the flow dynamics in the Scram Discharge System. Each SDIV has a redundant instrument loop. A one-out-of-two taken twice logic is employed for the automatic Scram function. This instrumentation arrangement assures the automatic scram function on high SDIV water level in the event of a single active or passive failure. 1.14.1.75.2.2.4 Safety Criterion 4 System operating conditions which are required for scram shall be continuously monitored. 1.14.1.75.2.2.4.1 Response Continuous and reliable signals are monitored to detect unsatisfactory SDIV water levels and to provide indication of such to the operator. Sensors monitoring the SDIV level provide alarm and scram signals that are displayed in the main control room. See the response to Safety Criterion 3 (Section 1.14.1.75.2.2.3.1). 1.14-74 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.75.2.2.5 Safety Criterion 5 Repair, replacement, adjustment, or surveillance of any system component shall not require the scram function to be bypassed. 1.14.1.75.2.2.5.1 Response The SDIV scram level instrumentation arrangement and trip logic allows instrument adjustment or surveillance without bypassing the scram function or directly causing a scram. Each level instrument can be individually isolated without bypassing the scram function. A one-out-of-two taken twice trip logic is employed. The HCGS Technical Specifications will ensure that the scram function is not bypassed during repair, replacement, adjustment or surveillance of any system component. 1.14.1.75.2.3 Operational Criteria 1.14.1.75.2.3.1 Operational Criterion 1 Level instrumentation shall be designed to be maintained, tested, or calibrated during plant operation without causing a scram. 1.14.1.75.2.3.1.1 Response The HCGS design provides for half-scram conditions during maintenance, testing or calibration during plant operation. See the response to Safety Criteria 5 (Section 1.14.1.75.2.2.5.1). 1.14.1.75.2.3.2 Operational Criterion 2 The system shall include sufficient supervisory instrumentation and alarms to permit surveillance of system operation. 1.14-75 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.75.2.3.2.1 Response Supervisory instrumentation and alarms such as accumulator trouble, scram valve air supply low pressure, and SDV not drained alarms, are adequate and permit surveillance of the scram system's readiness. 1.14.1.75.2.3.3 Operational Criterion 3 The system shall be designed to minimize the exposure of operating personnel to radiation. 1.14.1.75.2.3.3.1 Response Minimizing the exposure of operating personnel to radiation is a consideration in the design and location of all plant equipment. 1.14.1.75.2.3.4 Operational Criterion 4 Vent paths shall be provided to assure adequate drainage in preparation for scram reset. 1.14.1.75.2.3.4.1 Response A vent line is provided as part of the Scram Discharge System to assure proper drainage in preparation for scram reset. HCGS provides a dedicated vent line with a nonsubmerged discharge into one of the Reactor Building equipment drain sumps. The sumps are vented to the atmosphere. Furthermore, additional vent capability is provided by the vent line vacuum breaker. The vacuum breaker has a differential pressure operating setpoint of 0.2 psid (5.5 inches of water). 1.14.1.75.2.3.5 Operational Criterion 5 Vent and drain functions shall not be adversely affected by other system interfaces. The objective of this requirement is to preclude 1.14-76 HCGS-UFSAR Revision 0 April 11, 1988

water backup in the scram instrument volume which could cause spurious scram. 1.14.1.75.2.3.5.1 Response The SDV vent and drain lines are dedicated lines that discharge into the Reactor Building equipment drain sump as shown on Plant Drawing M-61-0. A vacuum breaker on the SDV vent line and shutoff valves on the SDV vent and drain lines preclude water from siphoning back into the SDIV from the equipment drain sump. 1.14.1.75.2.4 Design Criteria 1.14.1.75.2.4.1 Design Criterion The scram discharge headers shall be sized in accordance with GE Operation Experience Report No. 54 and shall be hydraulically coupled to the instrumented volume(s) in a manner to permit operation of the scram level instrumentation prior to loss of system function. Each system shall be analyzed based on plant specific maximum in-leakage to ensure that the system function is not lost prior to initiation of automatic scram. Maximum in-leakage is the maximum flow rate through the scram discharge line without control rod motion, summed over all control rods. The analysis should show no need for vents or drains. 1.14.1.75.2.4.1.1 Response As discussed in response to Functional Criterion 1, a minimum SDV of 3.34 gallons per drive is specified in the system design specifications. Furthermore, there is good communication between the scram discharge header and the SDIV. There are no reductions in the pipe size of the header piping from the HCUs to and including the SDIV. The SDIV is directly connected to the scram discharge volume at the low point of the scram discharge header piping. 1.14-77 HCGS-UFSAR Revision 20 May 9, 2014

1.14.1.75.2.4.2 Design Criterion 2 Level instrumentation shall be provided for automatic scram initiation while sufficient volume exists in the scram discharge volume. 1.14.1.75.2.4.2.1 Response The SDV size and SDV instrumentation assures automatic scram initiation while there is sufficient scram discharge volume remaining to accept the water discharged during a scram. See response to Functional Criteria 1 and Design Criteria 1 (Section 1.16.1.75.2.1.1 and 1.16.1.75.2.4.1.1). 1.14.1.75.2.4.3 Design Criterion 3 Instrumentation taps shall be provided on the vertical instrument volume and not on the connected piping. 1.14.1.75.2.4.3.1 Response All instrument taps are located on the SDIV. See response to Safety Criterion 3 (Section 1.14.1.75.2.2.3.1). 1.14.1.75.2.4.4 Design Criterion 4 The scram instrumentation shall be capable of detecting water accumulation in the instrumented volume(s) assuming a single active failure in the instrumentation system or the plugging of an instrument line. 1.14.1.75.2.4.4.1 Response HCGS provides redundant instrumentation and redundant instrument sensing lines. See response to Safety Criterion 3 (Section 1.14.1.75.2.2.3.1). 1.14-78 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.75.2.4.5 Design Criterion 5 Structural and component design shall consider loads and conditions including those due to fluid dynamics, thermal expansion, internal pressure, seismic considerations and adverse environments. 1.14.1.75.2.4.5.1 Response The SDV and associated vent and drain piping is classified as safety-related and meets the ASME Section III, Class 2 and Seismic Category I requirements. It is designed for maximum postulated temperatures and internal pressure conditions. Dynamic transient loading is still being evaluated. PSE&G is participating in the BWROG investigation into fluid dynamic phenomenon in the SDV. See Section 3.11 for discussion of environmental qualification of SDV instrumentation and components. 1.14.1.75.2.4.6 Design Criterion 6 The power operated vent and drain valves shall close under loss of air and/or electric power. Valve position indication shall be provided in the main control room. 1.14.1.75.2.4.6.1 Response SDV vent and drain valves close on loss of air and/or electrical power, and position indication is provided in the main control room. 1.14.1.75.2.4.7 Design Criterion 7 Any reductions in the system piping flow path shall be analyzed to assure system reliability and operability under all modes of operation. 1.14-79 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.75.2.4.7.1 Response Reductions in the piping flow path between the SDV headers and SDIVs have not been analyzed because there are no piping restrictions between the SDV headers and SDIVs. 1.14.1.75.2.4.8 Design Criterion 8 System piping geometry (i.e., pitch, line size, orientation) shall be such that the system drains continuously during normal plant operation. 1.14.1.75.2.4.8.1 Response All SDV piping is continuously sloped from its high point to its low point to facilitate system drainage. 1.14.1.75.2.4.9 Design Criterion 9 Instrumentation shall be provided to aid the operator in the detection of water accumulation in the instrumented volume(s) prior to scram initiation. 1.14.1.75.2.4.9.2 Response There are three different water levels in the SDIV that are monitored. At the lowest level, a level monitor provides an alarm in the main control room to indicate that the SDIV is not completely empty during post-scram draining, or to indicate that the volume has started to fill through leakage accumulation during reactor operation. At the second level, a level monitor provides a rod withdrawal block to prevent further withdrawal of any control rod. The third level initiates a reactor scram. 1.14-80 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.75.2.4.10 Design Criterion 10 Vent and drain line valves shall be provided to contain the scram discharge water, with a single active failure and to minimize operational exposure. 1.14.1.75.2.4.10.1 Response The redundant vent and drain valve configuration assures that no single active failure can result in uncontrolled releases of radioactivity to the environs. 1.14.1.75.2.5 Surveillance Criteria 1.14.1.75.2.5.1 Surveillance Criterion Vent and drain valves shall be periodically tested. 1.14.1.75.2.5.1.1 Response Surveillance procedures are provided to periodically demonstrate operability of the SDV vent and drain valves in accordance with HCGS Technical Specification 4.1.3.1.1. 1.14.1.75.2.5.2 Surveillance Criterion 2 The SDV level detection instrumentation shall be periodically tested in place. 1.14.1.75.2.5.2.1 Response Level detection instrumentation will be periodically tested in place in accordance with HCGS Technical Specification 4.3.1.1. 1.14-81 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.75.2.5.3 Surveillance Criterion 3 The operability of the entire system as an integrated whole shall be demonstrated periodically and during each operating cycle, by demonstrating scram instrument response and valve function at pressure and temperature at approximately 50 percent control rod density. 1.14.1.75.2.5.3.1 Response Periodic operability demonstration of the system as an integrated whole will be in accordance with HCGS Technical Specification 4.1.3.1.4. Additionally, SDV functional testing, and calibration of the SDV water level will be performed in accordance with the frequency specified in HCGS Technical Specification Table 4.3.1.1-1. 1.14.1.76 Safe Shutdown for Fires and Remote Shutdown System, LRG II/2-ASD 1.14.1.76.1 Issue Demonstrate compliance with Sections III.G and III.L of Appendix R. 1.14.1.76.2 Response See HCGS FSAR Appendix 8A for a description of compliance to Appendix R. 1.14.1.77 Protection of Equipment in Main Steam Pipe Tunnel LRG II/3-ASB 1.14.1.77.1 Issue It is required that the compartment in the Auxiliary Building between the containment and the Turbine Building which houses the main steam lines and feedwater lines and their isolation valves, be designed to consider the environmental effects (pressure, 1.14-82 HCGS-UFSAR Revision 0 April 11, 1988

temperature, humidity) and potential flooding consequences from an assumed crack, equivalent to the flow area of a single ended pipe rupture in these lines. It is also required that if this assumed crack could cause the structural failure of this compartment, then the structural failure should not jeopardize the safe shutdown of the plant. Finally, it is required that essential equipment located within the compartment, including the main steam isolation and feedwater valves and their operators be capable of operating in the environment resulting from the above crack. 1.14.1.77.2 Response Pipe breaks in the main steam tunnel are discussed in Section 3.6 of the HCGS FSAR. A pipe break inside the main steam tunnel will not cause failure of the structure due to overpressurization, because of blowout panels (discussed in Section 3.6.1), nor due to flooding, because the structure is designed for internal flooding, as discussed in Section 3.4. Environmental Qualification (EQ) of components located in the main steam tunnel is being addressed, as stated in Section 3.6. The HCGS environmental qualification program is described in Section 3.11. 1.14.1.78 Design Adequacy of the RCIC System Pump Room Cooling Systems, LRG II/4-ASB 1.14.1.78.1 Issue TMI Action Plan Item II.K.3.24 identified the need to confirm the adequacy of the RCIC System Pump Room Cooling System to maintain allowable room temperature for at least two hours during a loss of offsite power event. 1.14-83 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.78.2 Response The HCGS response to TMI Action Plan Item II.K.3.24 is provided in Section 1.10.2 of the HCGS FSAR. 1.14.1.79 Reassessment of Accident Assumptions as Related to Main Steam Line Isolation Valve Leakage Rate, ILRG II/1-AEB 1.14.1.79.1 Issue Proposed technical specification limits for main steam line isolation valves (MSIV) which are greater than 11.5 SCFH may increase potential offsite doses significantly. A reassessment of accident consequences is required to justify a higher limit. 1.14.1.79.2 Response Operational requirements are imposed on the MSIV sealing system which allow MSIV leakage rates up to 11.5 SCFH for each inboard. MSIV in each main steam line. See Section 6.7 for further details. The MSIV leakage rate has been raised to 150 SCFH and the MSIV Sealing System was removed from the plant. The above Issue and Response is retained for historical purposes only. 1.14.1.80 Asymmetrical LOCA and SSE and Annulus Pressurization Loads on Reactor, Vessel, Internals and Supports, LRG I/MEB-1 1.14.1.80.1 Issue Document your reevaluation of the safety-related systems and components based upon the load combinations, response combination methodology, and acceptance criteria required by us as presented at our meeting of December 12, 1978. (Reference letter dated September 18, 1978). 1.14-84 HCGS-UFSAR Revision 12 May 3, 2002

1.14.1.80.2 Response The load combination of normal operating loads, plus operating basis earthquake and the simultaneous actuation of all safety/relief valves is applicable to GE Mark II plants only. The load combination of normal operating loads plus annulus pressurization plus safe shutdown earthquake has been considered by HCGS. 1.14.1.81 Pre-Operational Vibration Assurance Program, LRG I/MEB-2 1.14.1.81.1 Issue Additional information is required concerning the basis for the allowable vibration amplitudes derived. 1.14.1.81.2 Response HCGS preoperation vibration assurance program, including acceptance criteria is described in Section 3.9.2. 1.14.1.82 RPV Internals Vibration Test Program For BWR/6, LRG II/2-MEB 1.14.1.82.1 Issue Explain how LRG II plants will document their RPV internals testing. In particular, will a licensing topical report similar to that submitted for BWR 4/5, NEDE-24057, be submitted? 1.14.1.82.2 Response HCGS is a BWR 4 and appropriate documentation is provided by Licensing Topical Report NEDE-24057-P, as discussed in Section 3.9.2.6. 1.14-85 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.83 Dynamic Response Combination Using SRSS Technique, LRG I/MEB-3 1.14.1.83.1 Issue We are studying the problem of utilizing the square root of the sum of the squares (SRSS) for determining dynamic responses other than LOCA and SSE as you have used. By not utilizing the absolute sum method, the review may be extended if we do not agree that the SRSS methodology is applicable. 1.14.1.83.2 Response HCGS is using absolute sum for determining dynamic responses other than LOCA and SSE except for ASME B&PV Code Class 1, 2 and 3 non-NSSS components and supports. For load combination tables for these components and supports, refer to Tables 3.9-8 and 3.9-21, respectively. 1.14.1.84 Input Criteria for Use of SRSS for Mechanical Equipment (NUREG-0484, Rev. 1), LRG II/1-MEB 1.14.1.84.1 Issue The LRG II participants must justify the use of SRSS methodology for mechanical equipment in LRG II plants. 1.14.1.84.2 Response Dynamic load combination, where applicable, is consistent with NUREG-0484, Rev. 1 guidelines for HCGS. 1.14-86 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.85 Loading Combinations, Design Transients, and Stress Limits, LRG I/MEB-4 1.14.1.85.1 Issue The NRC staff asked the applicants' to consider in their NSSS fatigue analyses the cyclic loadings due to the operating basis earthquake and safety/relief valve actuation. 1.14.1.85.2 Response The issue is addressed in Section 3.7.3.2 and Table 3.9-5a (Note 2). 1.14.1.86 Stress Corrosion Cracking of Stainless Steel, LRG I/MEB-5 1.14.1.86.1 Issue There have been numerous occurrences of stress corrosion cracking in stainless steel components of nuclear reactors, diminishing their safety function. To assure that stainless steel components can perform commensurate with their safety function, there must be adequate controls to remedy the causes of stress corrosion cracking. 1.14.1.86.2 Response Stress corrosion cracking is caused by a combination of oxygen in the wetting fluid, high stresses, and sensitization of the stainless steel. Oxygen in the reactor coolant and BWR water chemistry is discussed in Section 5.2.3. Sensitization of the stainless steel components is minimized whenever possible through the implementation of the fabrication control requirements outlined in Regulatory Guides 1.31, 1.36, and 1.44 in conjunction with Regulatory Guides 1.37, 1.38, and 1.39. 1.14-87 HCGS-UFSAR Revision 0 April 11, 1988

Compliance with these regulatory guides is discussed in Section 1.8. Processing controls in the fabrication of stainless steel components are further discussed in Sections 4.5.1, 4.5.2, and 5.2.3. 1.14.1.87 Pump and Valve Operability Assurance Program, LRG I/MEB-6 1.14.1.87.1 Issue The NRC staff requested additional information regarding the applicant's analyses and testing for their pump and valve operability assurance programs. 1.14.1.87.2 Response This issue is addressed in Section 3.9.3.2. 1.14.1.88 Bolted Connections for Supports, LRG I/MEB-7 1.14.1.88.1 Issue Provide the allowable limits for buckling for the reactor vessel support skirt subjected to faulted conditions. 1.14.1.88.2 Response A buckling analysis of the reactor vessel support skirt for HCGS was performed combining the effects of faulted-condition mechanical loads, thermal stress, and external pressure. This analysis showed that the support skirt has the capability to meet the faulted condition limit in the ASME B&PV Code, Section III, paragraph F-1370(c) of 0.67 times the critical buckling strength for linear supports at temperature. The buckling stress of the skirt was calculated to be 0.316 of the critical buckling strength. The mechanical loads (axial, shear, and overturning moment) were taken from the most limiting faulted load combination. This load 1.14-88 HCGS-UFSAR Revision 0 April 11, 1988

combination included weight and the dynamic loads due to jet reaction, annulus pressurization, and SSE. 1.14.1.89 Pump and Valve Inservice Testing Program, LRG I/MEB-8 1.14.1.89.1 Issue Indicate compliance with 10CFR50.55a(g). 1.14.1.89.2 Response As discussed in Section 3.9.6, inservice testing of certain safety- related pumps and valves is in accordance with 10CFR50.55a(g); and equipment lists, test schedules, methods and procedures are presented separately from the FSAR in the HCGS inservice pump and valve testing programs. Requests for relief from ASME B&PV Code, Section XI are discussed in Section 3.9.6.3. 1.14.1.90 SRV In-Situ Test Program, LRG I/MEB-9 1.14.1.90.1 Issue Review of in-situ test program of the safety relief valve. 1.14.1.90.2 Response HCGS participated in the BWROG program to test safety relief valves. For further details see Section 1.10, Item II.D.1. Section 3.9.2 describes seismic testing and analyses for the safety/ relief valves. Section 5.2.2 describes additional safety/relief valve inspection and test requirements. The original SRVs at Hope Creek were the 2-Stage Target Rock SRVs. Target Rock 3-Stage SRVs have been evaluated and approved for installation at Hope Creek. The 3-Stage SRVs have been evaluated by the NSSS vendor General Electric to meet the requirements of Section 1.10, Item II.D.1 (GE Document 001N2205, PSEG VTD 432432. UFSAR Sections 3.9.2 and 5.2.2 have been updated as necessary. 1.14-89 HCGS-UFSAR Revision 23 November 12, 2018

1.14.1.91 CRD System Return Line Removal, LRG I/MEB-11 1.14.1.91.1 Issue The NRC staff was concerned with the impact of the elimination of the control rod drive (CRD) return line on the performance of the CRD system. 1.14.1.91.2 Response See response to LRG Issue No. 2, Section 1.14.1.2. 1.14.1.92 Test Program Documentation for High and Moderate Energy Piping Systems, LRG I/MEB-12 1.14.1.92.1 Issue On some dockets the NRC staff has requested that the test program be documented for non-Class 1, 2, and 3 piping systems that carry high energy fluids outside the containment and for all Seismic Category I portions of piping systems that carry moderate energy fluids outside containment. 1.14.1.92.2 Response This issue is adequately addressed for NSSS piping in Section 3.9.2.1 and non-NSSS piping in Section 3.9.2.2. 1.14.1.93 OBE Stress Cycles for the Mechanical Design of NSSS Equipment and Components, LRG II/3-MEB 1.14.1.93.1 Issue The fatigue evaluation for the reactor pressure vessel and internals is based on 10 peak operating basis earthquake (OBE) cycles. However, the Standard Review Plan (SRP) requires that this evaluation include contributions from five OBEs with 10 cycles each. 1.14-90 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.93.2 Response For NSSS piping, 50 cycles are postulated in accordance with the SRP criterion. For other NSSS equipment and components, ten peak OBE cycles are postulated as documented in a December 3, 1981 letter from R. Artigas (General Electric) to R.J. Bosnak (NRC). Mr. Bosnak's response, dated February 18, 1982 accepted this approach but pointed out that "Results were not provided for BWR/4 plants... (and the NRC) will require that the plant-specific results... be provided to the staff when the fatigue calculations are completed." During a subsequent MEB-SER review meeting for Limerick, the NRC staff accepted the results of a generic BWR/4 study which showed that for the most limiting BWR/4 component, the vessel feedwater nozzle, the to the cumulative fatigue usage factor contribution from 10 peak OBE cycles would be 0.006; the contribution from all other sources would be 0.067. 1.14.1.94 Kuosheng Incore Instrument Tube Break, LRG II/4-MEG 1.14.1.96.1 Issue During a Kuosheng 1 shutdown, an incore instrument tube break resulted in an extended low-pressure coolant injection (LPCI), eventually causing fatigue failure of an incore instrument tube and a subsequent one-gpm leakage from the vessel. 1.14.1.94.2 Response This situation can only occur in BWR/6 plants where the LPCI is connected to the core shroud below the top guide plate, allowing the LPCI flow to impinge directly on the upper end of the core and causing instrument tube vibration. In previous BWR designs the LPCI is connected to the shroud above the top guide plate. Hence, this issue is not applicable to the HCGS. 1.14-91 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.95 Preservice and Inservice Inspection of Class 1, 2, and 3 Components, LRG I/MTEB-1 1.14.1.95.1 Issue Submit preservice and inservice inspection programs. 1.14.1.95.2 Response As discussed in Section 5.2.4 and 6.2.6, the preservice and inservice inspection of Class 1, 2, and 3 components will be in accordance with the provisions of 10CFR50.55a(g). 1.14.1.96 Inspectability of Welded Fluid Head Design on Main Steam Line Containment Penetration LRG II/1-MTEB 1.14.1.96.1 Issue The inspectability of welded flued head design on main steam line containment penetration should be demonstrated via the following activities:

1. Verify that the plant configuration allows adequate accessibility to the penetration to perform necessary inspections.

2. Determine if the penetration weld was ultrasonically examined during manufacturing. If so, report on examination results.

3. Determine if additional details exist on the flued head design and inspectability demonstrations performed at the Associated Pipe and Engineering facility in 1976 and 1977 and documented in General Electric Company Topical Report NEDO-23652, "Analysis on General Electric Designed Welded Flued Head Fitting at Containment Penetration Assembly and Provisions for Nondestructive Examination of Flued Head Fitting to Process Pipe Weld for BWR/6 Mark III - 218, 238, 251 Plants".

1.14-92 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.96.2 Response The inspectability of the main steam containment penetration has been verified as follows:

1. The plant configuration permits adequate accessibility to the main steam line containment penetration to perform the necessary inspections. An attached anchor ring prevents access to the top of the flued head.

However, GE has demonstrated the feasibility of achieving full volumetric coverage of the flued head to process pipe attachment weld when access to only the front face of the flued head is available. For Ultrasonic (UT) examination of the inaccessible inner (nearest the drywell) flued head to process pipe weldseam, refracted longitudinal wave search units were placed against the front face just above the outer weld fillet, and scanned circumferentially around the flued head. Those UT exams demonstrated strong signal amplitudes with minimum geometric reflection from the process pipe when 250 and 200 refracted 2-wave search units were used.

2. The flued head fitting to main steam line process pipe attachment weld seams were not ultrasonically examined during manufacturing. Instead the fabricator performed liquid penetrant, magnetic particle, and radiographic examinations.

These examinations revealed no indications that required repair.

3. In July 1976, General Electric Company conducted the feasibility study of pulse echo ultrasonic testing (UT) to assure full volume coverage of the flued head attachment weld. This UT examination technique as repeated as a demonstration for utility, architect/engineer and NRC representatives during July 1976 and May 1977 at the Associated Pipe and Engineering facility in Compton, California. The results of the demonstration are documented in the draft report NEDO-23652. No additional documentation on a demonstration performed is 1.14-93 HCGS-UFSAR Revision 0 April 11, 1988

available. The preservice inspection contractor for HCGS, Southwest Research Institute, intends to develop and qualify a UT examination procedure prior to performance of the examination. 1.14.1.97 Clarification and Justification of the Methods Used to Construct the Operating Pressure/Temperature Limits LRG I/MTEB-2 and MTEB-4 1.14.1.97.1 Issue Some plants have had to take certain exceptions to Appendix G of 10CFR50 and to Appendix G of Section III of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code. The NRC staff has requested that sufficient information be submitted to establish that the methods used to provide stress intensity values and to construct the operating pressure/temperature are equivalent to those obtained from Appendix G of Section III of the ASME B&PV Code. 1.14.1.97.2 Response The HCGS reactor will be operated in a manner that will minimize the possibility of rapidly propagating a failure. For all phases of plant operation, the pressure/temperature limit curves were established by using the available impact test data and conservative estimates of the nil-ductility transition reference temperatures (RT ) to perform fracture toughness NDT calculations by the methods of Appendix G (Summer 1972 Addenda) of Section III of the ASME B&PV Code for all shell and head areas of the vessel remote from discontinuities. These calculations were based on a postulated surface flaw equal to one quarter of the material thickness. The maximum through-wall temperature difference resulting in continuous heating or cooling at 100F per hour was considered. The safety factors applied were in accordance with Appendix G of Section III of the ASME B&PV Code, with paragraph IV.A.2.c of Appendix G 1.14-94 HCGS-UFSAR Revision 0 April 11, 1988

of 10CFR50, and with Reference 5.3-3. In addition, the vessel nozzle discontinuities (including the feedwater nozzle and the bottom head penetration for the control rod drives) were evaluated by adjusting the results of a BWR/6 discontinuity analysis to the HCGS reactor. The adjustments were made by increasing the minimum temperatures required by the differences in the material's RT values. Also, the effect of the main NDT closure flange discontinuity was considered by adding 60F to the flange region RT values whenever the pressure exceeded 20 percent of the hydrotest XDT pressure (see Figure 5.3-1). Additions of 120F and 160F to the RT values for nonnuclear heatup and nuclear heating, respectively, did not yield limiting curves. 1.14.1.98 Exemptions from Appendix H To 10CFR50, LRG I/MTEB-3 1.14.1.98.1 Issue The applicants' surveillance programs for the reactor pressure vessel (RPV) did not conform to all of the provisions of Appendix H of 10CFR50. The NRC staff asked for exceptions to be identified and justified. 1.14.1.98.2 Response This issue is covered in Section 5A.4. The HCGS RPV was built according to the provisions of the 1968 Edition of the ASME B&PV Code, Section III, with the Winter, 1969 addenda. This was prior to the promulgation of Appendix H of 10CFR50. The HCGS surveillance program is designed to conform to the regulatory requirements applicable at the time the RPV was fabricated. 1.14.1.99 Reactor Testing and Cooldown Limits, LRG I/MTEB-4 1.14.1.99.1 Issue Some plants have had to take certain exceptions to Appendix G of 1.14-95 HCGS-UFSAR Revision 0 April 11, 1988

10CFR50 and to Appendix G of Section III of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code. The NRC staff has requested that sufficient information be submitted to establish that the methods used to provide stress intensity values and to construct the operating pressure/temperature are equivalent to those obtained from Appendix G of Section III of the ASME B&PV Code. 1.14.1.99.2 Response See response to LRG Issue No. 97, Section 1.14.1.97. 1.14.1.100 Exposure Resulting From Actuation of Safety/Relief Valves (SRVs), LRG II/1-RAB 1.14.1.100.1 Issue The occupational dose assessment should include projected doses during normal operation and anticipated operational occurrences. The doses to plant personnel in the Reactor Building following a Type 2 SRV isolation scram should estimate maximum doses to workers rather than the average values. Provide the assumptions used in the calculations and estimate the whole body, skin, and thyroid doses to plant personnel following a SRV discharge. 1.14.1.100.2 Response The above issue is not applicable to HCGS since HCGS is a Mark I containment design and the SRV discharges are directed to the suppression pool where access is not permitted (design basis). 1.14.1.101 Routine Exposures Inside Containment, LRG II/2-RAB 1.14.1.101.1 Issue High radiation levels may be expected in routinely visited areas of containment in the vicinity of major drywell shield penetrations. 1.14-96 HCGS-UFSAR Revision 0 April 11, 1988

Specific areas of concern are the reactor water cleanup rooms, standby liquid control areas, TIP station, CRD hydraulic control unit, and containment personnel lock. Provide maximum neutron and gamma exposure levels in these routinely visited areas. 1.14.1.101.2 Response The reactor water cleanup rooms, standby liquid control areas, TIP Station, CRD hydraulic control unit, and the containment personnel lock are located outside the primary containment. The reactor water cleanup rooms are not located adjacent to the primary containment and frequent access is not anticipated during normal operation. Standby liquid control areas are not located adjacent to the drywell. During normal operation, controlled personnel access is possible into this area. CRD hydraulic control areas are not located adjacent to the drywell and controlled personnel access is possible into the CRD hydraulic control area. The TIP station is located adjacent to the drywell, however the TIP drive mechanism is installed in a low radiation area to allow controlled personnel access. The containment personnel lock is provided with removable shielding to reduce radiation level in adjacent containment areas. As a design practice, all penetrations to the areas of low radiation are located and designed to reduce the possibility of streaming from high to low radiation areas or otherwise external shielding is provided. All plant areas are categorized into radiation zones according to design basis radiation levels and anticipated personnel occupancy with consideration given to toward maintaining personnel exposure as low as reasonably achievable and within the standards of 10CFR20. Radiation levels including any neutron contribution are given in shielding and radiation zoning drawings (Plant Drawings N-1011 through N-1016, N-1031 through N-1038, N-1041 through N-1047 and Figures 12.3-22 through 12.3-28). 1.14.1.102 Controlling Radioactivity During Steam Dryer and Steam 1.14-97 HCGS-UFSAR Revision 20 May 9, 2014

Separator Refueling Transfer, LRG II/3-RAB 1.14.1.102.1 Issue Potentially high airborne radioactivity concentrations during refueling are expected since the steam dryer and steam separator must be transferred partially out of water. In addition to maintaining the equipment wet, other methods should be outlined to reduce the airborne radioactivity during transfers. 1.14.1.102.2 Response In order to minimize exposure to airborne radioactivity during the refueling outage HCGS refueling procedure has considered the following. Normally the dryer is transported in air. However, if the dryer becomes highly contaminated, the reactor well and the storage pool are flooded and a submerged transfer effected. This is described in Section 9.1.4. Administrative controls, including direct health physics surveillance will be implemented to minimize personnel exposure. 1.14.1.103 Shielding of Spent Fuel Transfer Tube and Canal During Refueling, LRG II/4-RAB 1.14.1.103.1 Issue All accessible portions of the spent fuel transfer tube and canal will be shielded during fuel transfer such that contact radiation levels are less than 100 rads per hour. All accessible portions must be clearly posted to identify potentially lethal radiation fields during fuel transfer. 1.14.1.103.2 Response HCGS does not utilize a spent fuel transfer tube. Spent fuel transfer and storage is performed underwater in the fuel transfer canal and in the spent fuel pool. Since HCGS does not have a cattle 1.14-98 HCGS-UFSAR Revision 0 April 11, 1988

chute shield design, administrative controls will be used to preclude access to the drywell during fuel movement. Personnel will not be allowed in the upper levels of the drywell during refueling operations where dose rates are normally higher. However, personnel may be permitted limited access to the lower levels for necessary work during refueling operations. A portable shielded fuel transfer chute also is installed in the reactor cavity during refueling operations to provide additional shielding to upper drywell areas. 1.14.1.104 Combination of Loads, LRG II/1-SEB 1.14.1.104.1 Issue For combining various dynamic loads, it is the NRC staff's position that the absolute sum method should be used unless actual time histories of the dynamic load occurrences are combined. If actual time histories are combined, details of the method used should be provided. The Staff has given to each Mark III applicant its position concerning the combination of loads. The position is specific with respect to the consideration of pool swell and SRV loading but is not as clear as a load combination table listing all the permissible combinations of loads with their respective specified load factors. LRG-II plants should provide one such table for concrete containment, steel containment, concrete internal structures, and steel internal structures respectively. In addition to the load combination requirement for the containment design, there is a fatigue analysis requirement for the liner of a concrete containment. For steel containment, the consideration of fatigue is specified in ASME Boiler and Pressure Code Section III, Division 1, Subsection NE. However, the liner of the concrete foundation mat of the steel containment should be treated as the liner of a concrete containment. Since the staff's position requires the pool liner to be designed in accordance with the ASME B&PV Code Section III, Division 1, Subsection NE, it is suggested that a generic method to consider fatigue of both the steel containment and the steel liner in the concrete containment should 1.14-99 HCGS-UFSAR Revision 18 May 10, 2011

be adopted. 1.14.1.104.2 Response HCGS uses absolute sum method or actual time histories for combining load in the design of structures. Load combinations are listed in Tables 3.8-2 and 3.8-3 for primary containment and component supports, respectively. Fatigue analysis for the HCGS steel containment vessel is performed in accordance with ASME B&PV Code, Section III, Division 1, Subsection NE. 1.14.1.105 Fluid/Structure Interaction, LRG II/2-SEB 1.14.1.105.1 Issue The dynamic forcing functions for various loads have been established mostly through testing on models which are generally more stiff than the actual structures to which the loads will be applied. By applying directly such forcing functions to actual structures in the analysis, the interactive effect between the fluid mass and the structure is neglected. Under certain conditions, this effect may be significant. It is proposed that a generic approach to study such effects should be established. 1.14.1.105.2 Response HCGS is following NRC accepted guidelines (NUREG-0661) in the plant unique analysis of the containment structure. Fluid is included in the containment structural models to account for any fluid structure interaction effects (Reference Appendix 3B). 1.14-100 HCGS-UFSAR Revision 0 April 11, 1988

1.14.1.106 Loads Assessment of Fuel Assembly Components, LRG I/CPB-1 1.14.1.106.1 Issue Appendix A to SRP 4.2 provides guidance for the analysis of Fuel Assembly Components and Acceptance Criteria for Fuel Assembly Response to externally applied forces. The applicants fuel assembly capability should be assessed accordingly. 1.14.1.106.2 Response The potential for fuel lift for HCGS is negligibly small. Screening calculations performed were based on linear seismic and annulus pressurization analyses and comparisons of HCGS bounding limits (net holdown forces) to those for previously analyzed BWR/4 and small vessel BWR/5 plants. Although the fuel lift analysis is intrinsically non-linear, the negligibly small results justify the adequacy of the linear analyses. The methodology and acceptance criteria used to evaluate fuel assembly components to externally applied forces are described in references 1 and 2. Both references contain NRCs acceptance of the methodology for determining the dynamic response to external loading conditions. 1.14.1.106.3 Response References

1. General Electric Standard Application for Reactor Fuel (GESTAR II),

NEDE-24011-P-A (latest approved revision). 1.14.1.107 Combined Seismic and LOCA Loads Analysis on Fuel, LRG II/2-CPB 1.14.1.107.1 Issue Appendix A to SRP 4.2 provides guidance for the analysis of Fuel Assembly Components and Acceptance Criteria for Fuel Assembly Response to externally applied forces. The applicants fuel assembly capability should be assessed accordingly. 1.14.1.107.2 Response See response to LRG Issue No. 106, Section 1.14.106. 1.14-101 HCGS-UFSAR Revision 14 July 26, 2005

1.14.1.108 Nonconservatism in the Models For Fuel Cladding Swelling and Rupture, LRG I/CPB-2 and LRG II/1-CPB 1.14.1.108.1 Issue The procedures proposed in NUREG-0630 introduce additional conservatism in the models for fuel cladding swelling and rupture during a loss-of-coolant accident. To assure the degree of swelling and incidence of rupture are not underestimated as required by Appendix K of 10CFR50.46, supplemental calculations to the current ECCS analyses should be performed. If the swelling is underestimated, the bundle cooling may be overestimated, and the peak cladding temperature may be nonconservative. 1.14.1.108.2 Response The HCGS unique ECCS calculations were prepared utilizing a cladding rupture and strain model contained in the SAFER/GESTR-LOCA methodology. The NRC staff found this methodology acceptable (see References in Section 1.14.108.2.1). 1.14.1.108.2.1 Reference

1. General Electric Standard Application for Reactor Fuel (GESTAR II) (U.S.

Supplement), NEDE-24011-P-A-US (latest revision) 1.14.1.109 Fuel Rod Cladding Ballooning and Rupture 1.14.1.109.1 Issue The procedures proposed in NUREG-0630 introduce additional conservatism in the models for fuel cladding swelling and rupture during a loss-of-coolant accident. To assure the degree of swelling and incidence of rupture are not underestimated as required by 1.14-102 HCGS-UFSAR Revision 14 July 26, 2005

Appendix K of 10CFR50.46, supplemental calculations to the current ECCS analyses should be performed. If the swelling is underestimated, the bundle cooling may be overestimated, and the peak cladding temperature may be nonconservative. 1.14.1.109.2 Response See response to LRG Issue No. 108, Section 1.14.1.108. 1.14.1.110 High Burnup Fission Gas Release, LRG II/4-CPB 1.14.1.110.1 Issue An NRC enhancement factor should be applied to calculated fission gas releases at burnups greater than 20,000 MWd/t because General Electric's GEGAP III model may underpredict these releases. If the release of low thermal conductivity fission gas is underestimated, the calculated gap conductance will be overestimated, and the peak cladding temperature (PCT) calculation will be nonconservative. 1.14.1.110.2 Response Application of the NRC's enhancement factor is not necessary. The NRC staff has approved the taking of credit for the calculated PCT margin and for changes in the ECCS evaluation model to offset any operating penalties due to high burnup fission gas release (see References 1 and 2). 1.14.1.110.2.1 Response Reference

1. Letter from L. R. Rubenstein (NRC) to T. M. Novack (NRC), "General Electric ECCS Analysis at High Burnup", October 22, 1981.

2. General Electric Standard Application for Reactor Fuel (GESTAR II) (U.S.

Supplement), NEDE-24011-P-A-US (latest approved revision). 1.14.1.111 Channel Box Deflection, LRG II/3-CPB and LRG I/CPB-3 1.14.1.111.1 Issue General Electric report NEDO-21354 and Safety Communication (SC) 08-05 describe a channel deflection phenomena that may interfere with control rod insertion. Long term channel bow occurs when fuel channels are irradiated to high exposures and either are controlled early in life (shadow corrosion-induced bow) or are located in peripheral locations that have a gradient in fast neutron flux (fluence-gradient bow). Channel bulge results from the pressure difference between the inside of the bundle and the water gaps. 1.14-103 HCGS-UFSAR Revision 17 June 23, 2009

This channel deflection reduces the size of the gap available for control rod insertion. A program to detect the onset of interference between the channel box and the control blade is required. NEDO-21354 and SC08-05 describe testing that can be used to measure the interference of the channel with the control blades. This testing should be included in the program or an alternative proposed. 1.14.1.111.2 Response HCGS will follow the vendor guidelines to minimize the potential for and to detect the onset of interference between the channel box and the control blade. The following guidelines will be used to minimize the potential for the interference between the channel box and the control blade:

1. Records should be kept of channel location and exposure for each operating cycle.

2. Channels should not reside in the outer row of the core for more than two operating cycles.

3. Channels that reside in the periphery (outer row) for more than one cycle should be oriented such that a different side faces the core edge for each successive peripheral cycle.

4. Channels that reside in the outer row of the core for three or more cycles should not be shuffled inward.

5. At the beginning of each fuel cycle, the combined outer row residence time for any two channels in any control rod cell should not exceed four peripheral cycles.

The following guidelines will be used to detect the onset of interference between the channel box and the control blade: As a part of the core design process, analytic channel lifetime prediction methods are being used to assure clearance between control blades at BOC and during operations. The scram time testing at BOC required by the Technical Specifications after completion of core alterations and prior to exceeding the power level specified for the scram time surveillance in Technical 1.14-104 HCGS-UFSAR Revision 17 June 23, 2009

Specification 4.1.3.3.d may be used to confirm that channel-control blade interference is not present. If the control rod settles into notch 00 after the scram-time test, interference is not considered an operational issue. In addition, observations of interference are made periodically during the cycle whenever scram-time tests are conducted to meet the requirements of the Technical Specifications. If the analytical lifetime predictions indicate specific cells are susceptible to channel-control blade interference or a cell exhibits signs of interference, settle testing will be performed following the recommendations in SC08-05. In the settle test, the time a control rod takes to settle is measured by performing a single notch withdrawal starting from notch 00, 02, 04, or 06. The test result is acceptable if the rod settles, under its own weight, to the target (even) notch within 7 seconds. The settle time is defined from initiation of the settle indicator light to initiation of the target (even) notch position indication. This testing will give an early indication of interference between the channel box and the control blade and will prompt an investigation into the source of the friction. This control rod settling friction test, along with the control rod movement requirement of Technical Specification Section 4.1.3.1.2.a, provides an equivalent level of safety as the test described in NEDO-21354. The settling friction test provides adequate assurance of the scram function. The amount of friction detectable by this test is approximately 250 lbs. Control rod drive (CRD) tests indicate that the CRD will tolerate a relatively large increase in driveline friction (350 lbs) while its performance still remains within Technical Specification limits. The control rod is in its most constrained, highest friction location when it is close to fully inserted (notches 00-06). The ability of the blade to settle from any of these positions demonstrates that the total driveline friction is less than the weight of the blade (250 lbs). In the future, analytic channel lifetime prediction methods, benchmarked by periodic deflection measurements of a sample of the highest duty channels, could be used to assure clearance between control blades and channels without additional settling friction testing. In lieu of settling friction testing, channel deflection measurements may be used to identify the amount of remaining channel lifetime for channels exceeding 36,000 MWd/ST (associated fuel bundle exposures). 1.14-105 HCGS-UFSAR Revision 22 May 9, 2017

The introduction of new channel boxes or control blades will not invalidate the HCGS guidelines for minimizing the potential for and the detection of interference between the channel box and the control blade unless so identified. 1.14.1.112 Water Side Corrosion of Fuel Cladding Due to Copper in the Feedwater, LRG I/CPB-4 and LRG II/5-CPB 1.14.1.112.1 Issue Copper-bearing materials in such feedwater equipment as the main condenser tubes or the feedwater heater tubes can lead to high fuel cladding corrosion rates if the copper-ion concentrations in the feedwater are above industry guideline recommendations. Corrosion can be satisfactorily controlled with deep bed demineralizers and supplemental surveillance to determine if cladding corrosion is occurring. 1.14.1.112.2 Response The HCGS feedwater heater tubes are made of stainless steel. The main condenser tubes are made of titanium, and the tube sheets are aluminum bronze. The condensate demineralizer system is designed to maintain adequate feedwater chemistry quality. In cases where industry guideline recommendations are not satisfied for feedwater chemistry quality parameters, an evaluation will be performed to document potential impacts and justify the new limit. 1.14.1.113 Cladding Water Side Corrosion, LRG II/5-CPB 1.14.1.113.1 Issue Copper-bearing materials in such feedwater equipment as the main condenser tubes or the feedwater heater tubes can lead to high fuel cladding corrosion rates if the copper ion concentrations in the feedwater are above about 2 ppb. Corrosion can be satisfactorily controlled with deep bed demineralizers and supplemental surveillance to determine if cladding corrosion is occurring. 1.14.1.113.2 Response See response to LRG Issue No. 112, Section 1.14.1.112. 1.14-106 HCGS-UFSAR Revision 17 June 23, 2009

1.14.1.114 Instrumentation to Detect Inadequate Core Cooling, LRG-II/6-CPB 1.14.1.114.1 Issue As a response to TMI Action Plant Item II.F.2, the NRC staff has asked licensees to provide descriptions of any additional instrumentation for an unambiguous, easy to interpret indication of inadequate core cooling. 1.14.1.114.2 Response The HCGS design does not include the use of in-core thermocouples or any other additional instrumentation for the detection of inadequate core cooling. PSE&G endorses the position of the BWR Owners Group that a diverse parameter used to monitor the adequacy of core cooling would not provide a significant benefit and that the existing design is adequate. 1.14.1.115 Rod Withdrawal Transient Analysis, LRG II/7-CPB 1.14.1.115.1 Issue In the BWR/6 design, the total core power input to the rod withdrawal limiter is determined from first stage turbine readings. However, if the turbine bypass valve is open, the core power may be underestimated by as much as the bypass capacity; and restrictions on the use of the rod withdrawal limiter may be violated. 1.14.1.115.2 Response This issue is not applicable to HCGS. In the BWR/4 design, the rod block monitor serves the functions of the rod withdrawal limiter in the BWR/6. The total core power input, used in the nulling and bypass circuits, is provided by the reference, average power range monitors rather than turbine first stage pressure. Therefore, the position of the turbine bypass valves has no effect on the operation of the rod block monitor. 1.14-107 HCGS-UFSAR Revision 17 June 23, 2009

1.14.1.116 Fuel Analysis for Mislocated or Misoriented Bundles, LRG II/8-CPB 1.14.1.116.1 Issue Another misloading event that is sometimes limiting, especially for reloaded cores, is an assembly misorientation event. Since Clinton has a C lattice core, the only effect of misorientation is presumably on the R-factor for the tilted bundle. The NRC staff asked the applicants to comment on the size of this effect and its consequences. 1.14.1.116.2 Response HCGS has a C lattice core and the misoriented bundle loading error, i.e., rotated 180, is of minor consequences. The C lattice configuration has equal size water gaps on all four sides of the bundle, therefore the effect of re-distribution of pin power on R-factor for misoriented bundle is small. Similar to the D lattice, the bundle in a C lattice configuration would tilt axially due to the channel buttons at the top of the fuel assembly and the R-factor increases slightly for the C lattice. The effect of a misoriented bundle on the R-factor and CPR has been analyzed for a C lattice core. The results show increases in R-factor and CPR. However, the magnitude of the CPR is less than that calculated for the limiting transient. Therefore the misoriented bundle event is not limiting CPR event. Both the mislocated and misoriented bundle accidents are evaluated as AOOs, and if their results are potentially limiting from a transient evaluation standpoint, they are analyzed prior to each reload (see Appendix 15D). 1.14.1.117 Discrepancy in Void Coefficient Calculation, LRG II/9-CPB 1.14.1.117.1 Issue Using two different calculation approaches, void worths differing by a factor of two are calculated. For example, in the Perry FSAR, data from Table 4.3-3, Reactivity and Control Fraction for Various Reactor States, gives a value of 0.074 (after subtracting 0.012 for the Doppler effects) while the result of integrating the curve shown on Figure 4.3-24 is approximately 0.03. 1.14-108 HCGS-UFSAR Revision 14 July 26, 2005

1.14.1.117.2 Response This issue is not applicable to HCGS. The HCGS FSAR incorporates references to the Licensing Topical Report NEDE-24011-P-A (GESTAR II), precluding the need for the subject table and figure. 1.14.1.118 Bounding Rod Worth Analysis, LRG II/10-CPB 1.14.1.118.1 Issue FSAR Section 15.4.9 "Control Rod Drop Accident" states that no bounding analysis needs to be performed for a rod worth of less than one percent K. Provide the basis of this statement. 1.14.1.118.2 Response Sensitivity studies presented in Response References 1 through 4 show large margins in peak enthalpy for rod worths below 1 percent K. This margin is sufficiently large that changes in Doppler coefficients, scram curves, reactivity insertion shape, etc. for rod worths below 1 percent K will not significantly reduce this margin. Therefore, if the compliance check shows the rod worth is below 1 percent K, the peak enthalpy for the control rod drop accident will be well below the 280-cal/gm limit. No unique bounding analysis is needed. 1.14.1.118.2.1 Responses References

1. R.C. Stirn, et. al., "Rod Drop Accident Analysis for Large BWRs,"

March 1972 (NEDO-10527).

2. C.J. Paone, "Bank Position Withdrawal Sequence," September 1976 (NEDO-21231).

3. R.C. Stirn, et. al., "Rod Drop Accident Analysis for Large BWRs,"

July 1972 Supplement 1 (NEDO-10527). 1.14-109 HCGS-UFSAR Revision 0 April 11, 1988

4. R.C. Stirn, et. al, "Rod Drop Accident Analysis for Large BWRs,"

January 1973 Supplement 2 (NEDO-10527). 1.14.1.119 Core Thermal Hydraulic Stability Analysis, LRG II/11-CPB 1.14.1.119.1 Issue Fuel design changes have increased the maximum decay ratio (MDR) beyond the original design criterion of 0.5 for thermal-hydraulic stability, and the NRC staff has not accepted General Electric's proposed new criterion of 1.0. The Staff has approved for operation previous core designs with MDRs as high as 0.7 for the initial cycle, but it will condition the licenses of BWR/6s (MDR = 0.98) to prohibit operation at natural circulation and to require new stability analyses be submitted and approved prior to second-cycle operation. The NRC is performing a generic study of the hydrodynamic stability characteristics of light water reactors. The results will be applied to the Staff's review and acceptance of stability analyses, criteria, and analytical methods of reactor vendors. 1.14.1.119.2 Response The NRC staff has since completed its technical review of the generic stability issue via NRC Generic Letter 86-02. See response to LRG Issue No. 36, Section 1.14.1.36. 1.14.1.120 Seismic Qualification of Equipment, LRG I 1.14.1.120.1 Issue

1. The applicants commit to complete the reevaluation of the dynamic (seismic and applicable hydrodynamic) loads on safety-related equipment prior to fuel loading. Each of the plants either has or shall respond to NRC requests for 1.14-110 HCGS-UFSAR Revision 0 April 11, 1988

information on this subject in order that the Staff may complete its SQRT review for the plant.

2. The applicants commit to complete, to the extent practicable, the requalification of equipment necessary as the result of the evaluation in item 1 prior to full power operation. Replacement of equipment if required will be accomplished on a best effort basis.

1.14.1.120.2 Response HCGS has committed to an equipment Seismic Qualification program which meets NRC requirements (Reference FSAR Section 3.10). HCGS has submitted the appropriate "long" equipment qualification forms for each of the SQRT audit components in letter, R. L. Mittl, PSE&G, to A. Schwencer, NRC, dated April 23, 1985, in fulfillment of the NRC request. 1.14.1.121 Environmental Qualification of Equipment, LRG I 1.14.1.121.1 Issue NRC environmental qualification guidelines. 1.14.1.121.2 Response HCGS has committed to an environmental qualification program as discussed in Section 3.11. 1.14-111 HCGS-UFSAR Revision 0 April 11, 1988

1.15 CONFORMANCE TO RULES ISSUED AFTER PLANT LICENSING 1.15.1 NRC Rule on Station Blackout On July 21, 1988, the Code of Federal Regulations, Title 10, Part 50 was amended to include a new Section 50.63, "Loss of all Alternating Current Power,"' (Station Blackout). The Station Blackout ( SBO) rule requires that each light-water cooled nuclear power plant licensed to operate must be able to withstand and recover from a SBO. An sao is defined in 10CFR50.2 as the complete loss of alternating current (AC) electric power to the essential and non-essential switchgear busses (i.e., loss of offsite power concurrent with a turbine trip and unavailability of the onsite emergency ac power system). sao does not include station batteries through inverters, nor does it assume a concurrent single failure or design basis accident of the affected Unit. The NRC issued Regulator Guide (RG) 1.155 in August of 1988, to provide the industry with guidance that was acceptable for meeting the requirements of 550.63 of 10 CFR Part so. In RG 1.155, the NRC states that NUMARC 87-00 (Reference 1) also provides guidance acceptable for meeting the requirements of 10 CFR 50.63, except when RG 1.155 takes precedence over NUMARC 87-00 as indicated in Table 1 of RG 1.155. 1.15.1.1 conformance to NRC Rule on Station Blackout An SBO coping analysis was performed to determine HCGS's coping duration and 1 ability to cope with a SBO. This coping duration was based on:

a. Offsite Power Design Characteristic

b. Emergency AC Power Supply System Configuration

c. Calculated BDG Reliability; and

d. Allowed EDG Target Reliability as described in programmatic standard HC.DB-PS.ZZ-0041, '"'Hope creek Station Blackout Program."

The coping duration for HOGS was calculated as four hours in accordance with NUMARC 87-00, Section 3 .. 0 with the exception of the frequency of Loss of Offsite Power events due to severe weather (SW) and Extremely Severe weather (ESW). Site-specific weather data was used to determine the sw and ESW frequency as detailed in report no. NUS-5175, Rev. 1 (Reference 2). 1.15-1 HCGS-UFSAR Revision 8 September 25, 1996

The ability to cope with a SBO event is based on the ability to maintain "appropriate containment integrity" as defined in RG 1.155), provide adequate condensate inventory for decay heat removal, provide adequate class 1E battery capacity and compressed air capacity for the coping duration period, and evaluate equipment operability due to loss of ventilation. The ability to cope with a SBO event is described in programmatic standard HC.DE-PS.ZZ-0041, "Hope Creek Station Blackout Program." In some instances, the GOTHIC computer program was used for room heat-up temperature calculation (due to loss of ventilation) instead of the NUMARC 87-00 method. 1.15.2 References

1. NUMARC 87-00, "Guidelines and Technical Bases for Initiatives Addressing Station Blackout at Light Water Reactors," Rev. 1, August 1991.

2. Halliburton NUS Environmental Corporation, NUS-5175, Rev. 1, "Estimated Frequency of Loss of Off-Site Power Due to Extremely Severe Weather (ESW) and Severe Weather (SW) for Salem and Hope Creek Generating Stations,"

March 1992. 1.15-2 HCGS-UFSAR Revision 22 May 9, 2017

SECTION 2 SITE CHARACTERISTICS TABLE OF CONTENTS Section Title Page 2.1 GEOGRAPHY AND DEMOGRAPHY 2.1-1 2.1.1 Site Location and Description 2.1-1 2.1.1.1 Specification of Location 2.1-1 2.1.1.2 Site Area Map 2.1-1 2.1.1.3 Boundaries for Establishing Effluent 2.1-1 Release Limits 2.1.2 Exclusion Area Authority and Control 2.1-2 2.1.2.1 Authority 2.1-2 2.1.2.2 Control of Activities Unrelated to 2.1-2 Plant Operation 2.1.2.3 Arrangements for Traffic Control 2.1-2 2.1.2.4 Abandonment or Relocation of Roads 2.1-3 2.1.3 Population Distribution 2.1-3 2.1.3.1 Population Within 10 Miles 2.1-3 2.1.3.2 Population Between 10 and 50 Miles 2.1-5 2.1.3.3 Transient Population 2.1-6 2.1.3.4 Low Population Zone 2.1-9 2.1.3.5 Population Center 2.1-10 2.1.3.6 Population Density 2.1-10 2.1.4 References 2.1-11 2.2 NEARBY INDUSTRIAL, TRANSPORTATION, AND 2.2-1 MILITARY FACILITIES 2.2.1 Locations and Routes 2.2-1 2.2.2 Descriptions 2.2-1 2.2.2.1 Description of Facilities 2.2-1 2.2.2.2 Description of Products and Materials 2.2-1 2.2.2.3 Pipelines 2.2-1 2.2.2.4 Waterways 2.2-1 2-i HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 2.2.2.5 Airports 2.2-2 2.2.2.6 Projections of Industrial Growth 2.2-8 2.2.3 Evaluation of Potential Accidents 2.2-8 2.2.3.1 Determination of Design Basis Events 2.2-8 2.2.3.2 Effects of Design Basis Events 2.2-18 2.2.4 References 2.2-18 2.3 METEOROLOGY 2.3-1 2.3.1 Regional Climatology 2.3-1 2.3.1.1 General Climate 2.3-1 2.3.1.2 Regional Meteorological Conditions for 2.3-2 Design and Operating Bases 2.3.2 Local Meteorology 2.3-9 2.3.2.1 Normal and Extreme Values of 2.3-10 Meteorological Parameters 2.3.2.2 Potential Influence of the Plant and its 2.3-28 Facilities on Local Meteorology 2.3.2.3 Local Meteorological Conditions for 2.3-34 Design and Operating Bases 2.3.3 Onsite Meteorological Measurements Program 2.3-35 2.3.3.1 Meteorological Data Collection Program 2.3-35 2.3.3.2 Preoperational Data Collection Program 2.3-35 2.3.3.3 Operational Data Display 2.3-38 2.3.4 Short-Term Diffusion Estimates 2.3-41 2.3.4.1 Objective 2.3-41 2.3.4.2 Accident Assessment 2.3-41 2.3.4.3 Atmospheric Diffusion Model 2.3-44 2.3.4.4 Diffusion Estimates 2.3-46 2.3.5 Long-Term (Routine) Diffusion Estimates 2.3-47 2.3.5.1 Objective 2.3-47 2.3.5.2 X/Q and D/Q Estimates 2.3-47 2.3.5.3 Methodology 2.3-47 2.3.6 References 2.3-54 2-ii HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 2.4 HYDROLOGIC ENGINEERING 2.4-1 2.4.1 Hydrologic Description 2.4-1 2.4.1.1 Site and Facilities 2.4-1 2.4.1.2 Hydrosphere 2.4-2 2.4.2 Floods 2.4-7 2.4.2.1 Flood History 2.4-7 2.4.2.2 Flood Design Considerations 2.4-9 2.4.2.3 Effects of Intense Local Precipitation 2.4-10 2.4.3 Probable Maximum Flood on Streams and 2.4-11 Rivers 2.4.3.1 Probable Maximum Precipitation (PMP) 2.4-11 2.4.3.2 Precipitation Losses 2.4-11 2.4.3.3 Runoff and Stream Course Models 2.4-12 2.4.3.4 Probable Maximum Flood Flow 2.4-12 2.4.3.5 Water Level Determinations 2.4-12 2.4.3.6 Coincident Wind Wave Activity 2.4-14 2.4.4 Potential Dam Failures, 2.4-16 Seismically Induced 2.4.4.1 Dam Failure Permutations 2.4-17 2.4.4.2 Unsteady Flow Analysis of Potential Dam 2.4-19 Failures 2.4.4.3 Water Level at Plant Site 2.4-22 2.4.5 Probable Maximum Surge and Seiche 2.4-23 Flooding 2.4.5.1 Probable Maximum Winds and Associated 2.4-24 Meteorological Parameters 2.4.5.2 Surge and Seiche Water Levels 2.4-24 2.4.5.3 Wave Action 2.4-26 2.4.5.4 Resonance 2.4-29 2.4.5.5 Protective Structures 2.4-31 2.4.6 Probable Maximum Tsunami Flooding 2.4-32 2.4.6.1 Probable Maximum Tsunami 2.4-33 2.4.6.2 Historical Tsunami Record 2.4-34 2-iii HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 2.4.6.3 Source Generator Characteristics 2.4-35 2.4.6.4 Tsunami Analysis 2.4-35 2.4.6.5 Tsunami Water Levels 2.4-38 2.4.6.6 Hydrography and Harbor or Breakwater 2.4-38 Influences on Tsunami 2.4.6.7 Effects on Safety-Related Facilities 2.4-38 2.4.7 Ice Effects 2.4-39 2.4.8 Cooling Water Canals and Reservoirs 2.4-39 2.4.9 Channel Diversions 2.4-39 2.4.10 Flooding Protection Requirements 2.4-40 2.4.11 Low Flow Considerations 2.4-41 2.4.11.1 Low Flow in Streams 2.4-41 2.4.11.2 Low Water Resulting from Surges, 2.4-42 Seiches, or Tsunami 2.4.11.3 Historical Low Water 2.4-45 2.4.11.4 Future Controls 2.4-45 2.4.11.5 Plant Requirements 2.4-46 2.4.11.6 Heat-Sink Dependability Requirements 2.4-47 2.4.12 Dispersion, Dilution, and Travel Times of 2.4-48 Accident Releasers of Liquid Effluents in Surface Water 2.4.13 Groundwater 2.4-51 2.4.13.1 Description and Onsite Use 2.4-51 2.4.13.2 Sources 2.4-78 2.4.13.3 Accidental Releases of Liquid Effluents in Ground and Surface Waters 2.4-86 2.4.13.4 Monitoring or Safeguard Requirements 2.4-87 2.4.13.5 Design Bases for Subsurface Hydrostatic 2.4-88 Loading 2.4.14 Technical Requirements Manual and Emergency 2.4-90 Operation Requirements 2.4.15 References 2.4-90 2-iv HCGS-UFSAR Revision 21 November 9, 2015

TABLE OF CONTENTS (Cont) Section Title Page 2.5 GEOLOGY, SEISMOLOGY, AND GEOTECHNICAL 2.5-1 ENGINEERING 2.5.1 Basic Geologic and Seismic Information 2.5-2 2.5.1.1 Regional Geology 2.5-2 2.5.1.2 Site Geology 2.5-48 2.5.1.3 SRP Rule Review 2.5-71 2.5.2 Vibratory Ground Motion 2.5-72 2.5.2.1 Historical Seismicity 2.5-72 2.5.2.2 Geological and Tectonic Characteristics 2.5-74 of Site and Region 2.5.2.3 Correlation of Earthquake Activity with 2.5-82 Geologic Structure or Tectonic Provinces 2.5.2.4 Maximum Earthquake Potential 2.5-96 2.5.2.5 Seismic Wave Transmission Characteristics 2.5-103 of the Site 2.5.2.6 Safe Shutdown Earthquake 2.5-103 2.5.2.7 Operating Basis Earthquake 2.5-206 2.5.2.8 SRP Rule Reviews 2.5-107 2.5.3 Surface Faulting 2.5-110 2.5.3.1 Geologic Conditions at the Site 2.5-110 2.5.3.2 Evidence of Fault Offset 2.5-110 2.5.3.3 Earthquake Associated with Capable Faults 2.5-111 2.5.3.4 Investigation of Capable Faults 2.5-111 2.5.3.5 Correlation of Epicenters with Capable 2.5-111 Faults 2.5.3.6 Description of Capable Faults 2.5-111 2.5.3.7 Zone Requiring Detailed Faulting 2.5-111 Investigation 2.5.3.8 Results of Faulting Investigation 2.5-111 2.5.4 Stability of Subsurface Materials and 2.5-111 Foundations 2.5.4.1 Geologic Features 2.5-112 2-v HCGS-UFSAR Revision 0 April 11, 1988

TABLE OF CONTENTS (Cont) Section Title Page 2.5.4.2 Properties of Subsurface Materials 2.5-116 2.5.4.3 Exploration 2.5-123 2.5.4.4 Geophysical Surveys 2.5-125 2.5.4.5 Excavations and Backfill 1.5-132 2.5.4.6 Groundwater Conditions 2.5-136 2.5.4.7 Response of Soil and Rock to Dynamic 2.5-143 Loading 2.5.4.8 Liquefaction Potential 2.5-144 2.5.4.9 Earthquake Design Basis 2.5-152 2.5.4.10 Static Stability 2.5-152 2.5.4.11 Design Criteria 2.5-159 2.5.4.12 Techniques to Improve Subsurface 2.5-160 Conditions 2.5.4.13 Subsurface Instrumentation 2.5-160 2.5.4.14 Construction Notes 2.5-162 2.5.5 Stability of Slopes 2.5-162 2.5.6 Embankments and Dams 2.5-163 2.5.7 References 2.5-163 2-vi HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES Table Title 2.1-1 Transient and Special Facilities Population Within 0-10 Miles of the Artificial Island Site, 1981 2.1-2 Location of Special Facilities Within 10 miles of the Artificial Island Site, 1982 2.1-3 Recreation and Tourism Within 0-10 Miles of the Artificial Island Site, 1981 2.1-4 Major Employment Centers Located Within 10-50 Miles of the Artificial Island Site, 1981 2.1-5 Seasonal and Tourist Population, New Jersey Shoreline, 40-50 Miles 2.1-6 Population Distribution Within the Low Population Zone, 1982 2.1-7 Cumulative Population and Density Within 0-30 Miles of the Artificial Island Site 2.2-1 Number of Operations at Greater Wilmington Airport 2.2-2 Number of Operations Over the HCGS Site Itinerant FAA Controlled Over Flights 2.2-3 Number of Operations Over the HCGS Site NFR Observed on Radar from Philadelphia Approach Control 2.2-4 Hazardous Chemicals Stored at Salem Generating Station 2-vii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES (Cont) Table Title 2.2-5 Estimates of Hazardous Chemical Traffic 2.2-6 Chemicals Stored at Hope Creek Site 2.3-1 Percentage of Days with Various Hydrometers, Dover Delaware Air Force Base 2.3-2 Snowfall, Philadelphia International Airport 2.3-3 Snowfall, Trenton International Airport 2.3-4 Data Availability for Onsite Meteorological Parameters. January 1977 - December 1981 2.3-5 Comparison of Annual Onsite Direction Frequency Distributions January 1977 - December 1981 2.3-6 Comparison of Annual Onsite with Wilmington NWS Wind Direction Frequency Distributions 2.3-7 Onsite Comparison of Average Wind Speeds, January 1977 - December 1981 2.3-8 Wilmington National Weather Service Average Wind Speeds 2.3-9 Onsite Temperature Means and Extremes, January 1977 - December 1981 2.3-10 Onsite Hourly Temperature Frequency Distributions, January 1977 - December 1981 2-viii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES (Cont) Table Title 2.3-11 Onsite Diurnal Temperature Variations, January 1977 - December 1981 2.3-12 Temperature Means and Extremes, January 1977 - December 1981 2.3-13 Wilmington NWS Temperature Means and Extremes 2.3-14 Onsite Dew Point Temperature Means and Extremes, January 1977 - December 1981 2.3-15 Onsite Hourly Dew Point Temperature Frequency Distributions, January 1977 - December 1981 2.3-16 Onsite Diurnal Dew Point Temperature January 1977 - December 1981 2.3-17 Onsite Relative Humidity Means and Extremes January 1977 - December 1981 2.3-18 Onsite Hourly Relative Humidity Frequency Distributions, January 1977 - December 1981 2.3-19 Onsite Diurnal Relative Humidity Variations, January 1977 - December 1981 2.3-20 Wilmington NWS Diurnal Relative Humidity Variations 2.3-21 Onsite Hourly Absolute Humidity Means and Extremes, January 1977 - December 1981 2-ix HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES (Cont) Table Title 2.3-22 Onsite Hourly Absolute Humidity Frequency Distribution, January 1977 - December 1981 2.3-23 Onsite Diurnal Absolute Humidity Variations, January 1977 - December 1981 2.3-24 Wilmington NWS Precipitation Means and Extremes 2.3-25 Wilmington NWS Snowfall Means and Extremes 2.3-26 Mean Numbers of Days at Wilmington NWS with Fog, Haze, and/or Smoke 2.3-27 Comparison of Onsite and Wilmington NWS Stability Frequency Distributions 2.3-27a Delta Temperature Stability Distribution 300 to 33 Ft, 1977 to 1981, Counts/(Percent) 2.3-27b Delta Temperature Stability Distribution 150 to 33 Ft, 1977 to 1981, Counts/(Percent) 2.3-28 300-33 Ft. Onsite Temperature Inversion Persistence, January 1977 - December 1981 2.3-29 Meteorological Instrumentation 2.3-29a Data Acquisition System Hardware 2.3-29b System Measurement Error 2.3-29c Artificial Island Digital Data Acquisition System Accuracies 2-x HCGS-UFSAR Revision 11 November 24, 2000

LIST OF TABLES (Cont) Table Title 2.3-30 Accident X/Q Estimates 2.3-30a Accident X/Q Values at LPZ by Sector 2.3-31 Vent X/Q at Ground Level, Long Term Routine Gaseous Releases, Annual Average X/Q by Sector 2.3-32 Vent Depleted X/Q at Ground Level, Long-Term Routine Gaseous Release, Annual Average Depleted X/Q by Sector 2.3-33 Vent X/Q at Ground Level, Long-Term Ground Level Routine Gaseous Releases, Annual Average X/Q by Sector 2.3-34 Yearly Precipitation Totals, 1977 to 1981 2.3-35 Precipitation Statistics, 1977 to 1981 2.3-36 Wind Direction Distributions Artificial Island June 1969 to May 1971 2.3-37 Wind Direction Distributions Artificial Island January 1977 to December 1981 2.3-38 Wind Direction Distributions Artificial Island January 1977 to December 1981 Wind Elevation = 150 Feet 2.3-39 Wind Direction Distributions Artificial Island January 1977 to December 1981 Wind Elevation = 300 Feet 2-xi HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES (Cont) Table Title 2.3-40 Stability Distributions Artificial Island June 1969 - May 1971 2.4-1 Drainage Areas and Gaged River Flow of Streams Tributary to Delaware River and Bay 2.4-2 Major Existing Upstream Surface Water Impoundments 2.4-3 Major Proposed New or Modified Upstream Impoundments 2.4-4 Peak Discharge Data for the Delaware River at Trenton, New Jersey 2.4-5 Tidal Floods on Delaware River 2.4-6 Postulated Flood Producing Phenomena 2.4-7 Unsteady Flow Analysis of Single Dam Failures 2.4-8 Single Dam Failures 2.4-9 Unsteady Flow Analysis of Multiple Dam Failures 2.4-10 Probable Maximum Hurricane (PMH) Design High Water Levels At Power Block 2.4-10a (PMH) Non-Breaking Wave Runup on the Vertical Wall of the Intake Structure Facing the Delaware River 2.4-11 Occurrence of Atlantic Tsunamis 2.4-11a Summary of Wave Loading Conditions 2-xii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES (Cont) Table Title 2.4-12 Atlantic Tsunamis Occurring Between 1891 and 1961 2.4-13 Summary of Results from Aquifer Tests Conducted at HCGS 2.4-14 Chemical Analysis of Water Samples 2.4-15 Laboratory Permeability Test Data 2.4-16 Public Water Supplies in Vicinity of the Site 2.4-17 Private Water Wells in Vicinity of the Site 2.4-18 Coefficients of Permeability, Transmissibility, and Storage in the Raritan Formation 2.4-19 Summary of Water Analyses of Salem Generating Station Wells 2.4-20 Water Analysis, Well 1 2.4-21 Water Analysis, Well 2 2.4-22 Water Analysis, Well 3 2.4-23 Water Analysis, Well 5 2.5-1 Earthquake List 2.5-2 Index Properties, Hydraulic Fill 2.5-3 Index Properties, River Bottom Sands 2-xiii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES (Cont) Table Title 2.5-4 Index Properties, Kirkwood Clays 2.5-5 Index Properties, Basal Sands 2.5-6 Index Properties, Vincentown Sands 2.5-7 Consolidation Test Data 2.5-8 Coefficient of Consolidation, C 2.5-9 Results of Unconfined Compression and Unconsolidated Undrained Tests 2.5-10 Results of Consolidated Undrained Triaxial Compression Tests 2.5-11 Results from Resonant Column Tests on Sand 2.5-12 Results from Resonant Column Tests on Clay 2.5-13 Results from Dynamic Strain Controlled Tests on Sand 2.5-14 Results from Dynamic Strain Controlled Tests on Clay 2.5-15 Summary of Compression and Shear Wave Velocities from Geophysical Surveys 2.5-16 Dynamic Subsurface Model, Boring 201 2.5-17 Dynamic Subsurface Model, Boring 229 2.5-18 Foundation Design Data 2-xiv HCGS-UFSAR Revision 0 April 11, 1988

LIST OF TABLES (Cont) Table Title 2.5-19 Lateral Forces During Earthquake Excitation and Factor of Safety Against Sliding for Intake and Power Block Structures 2.5-20 Lateral Forces During Earthquake Excitation and Factor of Safety Against Sliding for Pipeline 2.5-21 Earthquakes > M = 4.0 Used in a 5° x 5° Comparison Between L the Hope Creek Site and Miramichi, N.B. 2.5-22 Recurrence Parameters 2.5-23 Seismic Events within a 1° x 1° Area Centered About the HCGS Site and the Miramichi Magnitude 5.7 Epicenter 2.5-24 Earthquakes Used in a 1° x 1° Comparison Between the Hope Creek Site and Miramichi, New Brunswick 2-xv HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES Figure Title 2.1-1 Site Plan 2.1-2 Site Area 2.1-3 Population Distribution - Year 1980, Within 0 to 10 Miles 2.1-4 Population Distribution - Year 1987, Within 0 to 10 Miles 2.1-5 Population Distribution - Year 1990, Within 0 to 10 Miles 2.1-6 Population Distribution - Year 2000, Within 0 to 10 Miles 2.1-7 Population Distribution - Year 2010, Within 0 to 10 Miles 2.1-8 Population Distribution - Year 2020, Within 0 to 10 Miles 2.1-9 Population Distribution - Year 2030, With 0 to 10 Miles 2.1-10 Population Distribution - Year 1980, With 10 to 50 Miles 2.1-11 Population Distribution - Year 1987, With 10 to 50 Miles 2-xvi HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.1-12 Population Distribution - Year 1990, With 10 to 50 Miles 2.1-13 Population Distribution - Year 2000, With 10 to 50 Miles 2.1-14 Population Distribution - Year 2010, With 10 to 50 Miles 2.1-15 Population Distribution - Year 2020, With 10 to 50 Miles 2.1-16 Population Distribution - Year 2030, With 10 to 50 Miles 2.1-17 State Parks and Forests, Within 0 to 50 Miles 2.1-18 Wildlife Management Areas - Year 1982, Within 0 to 50 Miles 2.1-19 Ports of Landing for Commercial and Recreational Saltwater Fishing Within 0 to 50 Miles 2.1-20 Commercial and Recreational Fishing and Shell-fishing Areas, Within 0 to 80 Kilometers 2.1-21 Low Population Zone - Year 1982 2.1-22 Population Centers Within 0 to 30 Miles of Artificial Island Site - Year 1980 2.1-23 Population Density 2-xvii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.2-1 Site Map With Airports 2.2-2 Low Level Airways Near the Site 2.2-3 High Level Airways Near the Site 2.2-4 Military Low Level Routes Near the Site 2.3-1 Five Mile Topographic Map 2.3-2 Fifty Mile Topographic Map 2.3-3 Terrain Vs. Distance 2.3-4 Sources of Data 2.3-5 Meteorological Tower Schematic 2.3-6 Meteorological Data Acquisition Display System 2.4-1 Regional Location Map 2.4-2 Location of Major Impoundments In the Delaware River Basin 2.4-3 Datum and Water Level Relationships 2.4-4 PMF Peak Discharge 2.4-5 River Channel Cross Sections for PMF Water Level Estimation 2.4-6 Fetch Diagram for Coincident Wind-Wave Analysis 2-xviii HCGS-UFSAR Revision 21 November 9, 2015

LIST OF FIGURES (Cont) Figure Title 2.4-7 Critical Path of PMH for Maximum Water Level Estimation 2.4-8 Computed Surge Hydrograph and Wave Run-up Hydrograph 2.4-9 HCGS Plot Plan 2.4-10 Critical Path of the Hurricane for Extreme Low Water Estimation 2.4-11 Generalized Geological Cross-Section of the HCGS Site 2.4-12 Schematic Monitoring System Plan 2.4-13 Schematic Dewatering System Plan 2.4-14 Schematic Well Point System - Sumps, Discharge Header, Discharge Lines & Valves 2.4-15 Shallow Aquifer Piezometric Levels - 05/17/78 2.4-16 Vincentown Aquifer Piezometric Levels - 05/17/78 2.4-17 Shallow Aquifer Piezometric Levels - 01/16/78 2.4-18 Shallow Aquifer Piezometric Levels - 08/24/76 2.4-19 Vincentown Aquifer Piezometric Levels - 08/24/76 2.4-20 Shallow Aquifer Piezometric Levels - 06/21/77 2.4-21 Groundwater Quality Map for the Shallow Aquifer 2-xix HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.4-22 Vincentown Aquifer Piezometric Levels - 04/22/75 2.4-23 Groundwater Quality Map for the Vincentown Aquifer 2.4-24 Groundwater Quality Map for the Mount Laurel Wenonah Aquifer 2.4-25 Deleted: Refer to Plant Drawing C-5018-0 2.4-26 Historical Use of Well Water by SNGS 2.4-27 Public Water Supplies in Vicinity of HCGS Site 2.4-28 Map of Area - Known Water Wells in New Jersey in Vicinity of Site 2.4-29 Water Level Hydrograph - Well No. 302 2.4-30 Water Level Hydrograph - Well No. 303 2.4-31 Water Level Hydrograph - Well No. 312-A 2.4-32 Water Level Hydrograph - Well No. 313-A 2.4-33 Water Level Hydrograph - Well No. 323 2.4-34 Water Level Hydrograph - Well No. OWS-1 2.4-35 Water Level Hydrograph - Well No. OWS-2 2.4-36 Water Level Hydrograph - Well No. 300-A 2-xx HCGS-UFSAR Revision 20 May 9, 2014

LIST OF FIGURES (Cont) Figure Title 2.4-37 Water Level Hydrograph - Well No. 301 2.4-38 Water Level Hydrograph - Well No. 311-A 2.4-39 Water Level Hydrograph - Well No. 314 2.4-40 Water Level Hydrograph - Well No. 322 2.4-41 Regional Map - Theoretical Flow Pattern, Location of Interface Between Fresh Water & Salt Water in Raritan and Magothy Formations Before Artificial Withdrawals of Water 2.4-42 Set Configuration for Low Discharge Velocity and High Density Excess Over Ambient 2.4-43 Delaware River Flow Velocity 2.4-44 Schematic Structure of Hope Creek Blowdown Discharge 2.5-1 Regional Location Map 2.5-2 Regional Physiographic Map 2.5-3 Regional Stratigraphic Column 2.5-4 New Jersey Coastal Plain Geologic Cross Section 2.5-5 Regional Geologic Map 2.5-6 Generalized Regional Geologic Cross Section 2.5-7 Regional Gravity and Magnetic Map 2-xxi HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.5-8 Tectonic Map Showing Structural Provinces 2.5-9 Tectonic Map Showing Triassic and Jurassic Basins 2.5-10 Tectonic Map Showing Late Cretaceous and Cenozoic Structures 2.5-10a Review of Recent Landsat Analysis 2.5-11 Site Stratigraphic Relationships 2.5-11A Surficial Geologic Map 2.5-12 Stratigraphy of Deep Test Borings 2.5-13 Geologic Cross Section A-A 2.5-14 Geologic Cross Section C-C 2.5-15 Geologic Cross Section D-D 2.5-16 Plot Plan of Main Excavation 2.5-17 Geological Profiles of Main Excavation Walls 2.5-18 Geologic Profiles of Main Excavation Walls 2.5-19 Subsurface Contour Map (Top of Vincentown Formation) 2.5-20 Contour Map (Top of Vincentown Formation) 2.5-21 Contour Map (Kirkwood Formation Clay/Sand Contact) 2-xxii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.5-22 Regional Epicenter 2.5-23 Location of Epicenters (50 Miles) 2.5-24 Isoseismal Map of February 28, 1973 Wilmington Event 2.5-25 Regional Focal Mechanism Solutions 2.5-26 Attenuation Relationships 2.5-26a 1982 Miramichi Earthquake Sequence 2.5-27 Horizontal Response Spectra - Safe Shutdown Earthquake 2.5-28 Vertical Response Spectra - Safe Shutdown Earthquake 2.5-28a Comparison of Site Specific Spectra for Soil and Rock Sites at 50th and 84th Percentiles (Damping = 5.0) 2.5-28b Comparison of Site Specific Spectra for Soil Sites at 50th and 84th Percentile 2.5-29 Horizontal Response Spectra - Operating Basis Earthquake 2.5-30 Vertical Response Spectra - Operating Basis Earthquake 2.5-31 Plot Plan and Boring Locations 2.5-32 Site Subsurface Sections 2-xxiii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.5-33 Particle Size Distribution Envelope for Hydraulic Fill 2.5-34 Particle Size Distribution Envelope for River Bottom Sands 2.5-35 Particle Size Distribution Envelope for Basal Sands 2.5-36 Particle Size Distribution Envelope for Vincentown Sands 2.5-37 Normalized Undrained Shear Strength vs. Consolidation Pressure for Vincentown Sands 2.5-38 Isotropically Consolidated Undrained Triaxial Extension Tests, Vincentown Sands 2.5-39 K - Consolidated Undrained Triaxial Extension Test, 0 Vincentown Sands 2.5-40 K - Consolidated Undrained Triaxial Compression Test, 0 Kirkwood Clay 2.5-41 Variation of Normalized Shear Modulus with Shear Strain for Sand 2.5-42 Variation of Damping with Shear Strain for Sand 2.5-43 Variation of Shear Modulus with Shear Strain for Clay 2.5-44 Variation of Damping with Shear Strain for Clay 2-xxiv HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.5-45 Typical Cyclic Static Triaxial Test Data for Granular Soils 2.5-46 Dynamic Strengths - Vincentown Sands 2.5-47 Dynamic Strengths - River Bottom Sands 2.5-48 Dynamic Strengths - Basal Sands 2.5-49 Unified Soil Classification System 2.5-50 Log of Borings 2.5-51 Seismic Refraction Survey, Seismic Line 1 2.5-52 Seismic Refraction Survey, Seismic Line 2 2.5-53 Uphole Compression and Shear Wave Velocity Survey 2.5-54 Theoretical Variation of Effective Depth of Investigation with Velocity Contrast 2.5-55 Location of Extensometers 2.5-56 Extensometer No. 1 (As Built) 2.5-57 Pipeline Stability During Earthquake Excitation 2.5-58 Model Used in the Analysis for Intake Structure Without Liquefaction 2.5-59 Models Used in the Analysis for the Power Block and Intake Structure Assuming Liquefaction 2-xxv HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.5-60 Static Earth Pressure Distribution 2.5-61 Dynamic Earth Pressure Distribution 2.5-62 Recurrence Curves 2.5-63 Isopach Form Lines 2.5-64 Water Level Hydrographs of Pressure Cell Piezometers P-1, P-2, and P-2A 2.5-65 Water Level Records for Observation Wells Nos. 39, 300A, 301, 302 and 303 2.5-66 Load/Settlement Plot for Intake Structure 2.5-67 Load/Settlement Plot for Marker No. 1 2.5-68 Load/Settlement Plot for Marker No. 2 2.5-69 Load/Settlement Plot for Marker No. 3 2.5-70 Load/Settlement Plot for Marker No. 4 2.5-71 Load/Settlement Plot for Marker No. 5 2.5-72 Load/Settlement Plot for Marker No. 6 2.5-73 Load/Settlement Plot for Marker No. 7 2.5-74 Load/Settlement Plot for Marker No. 8 2.5-75 Load/Settlement Plot for Marker No. 9 2-xxvi HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.5-76 Load/Settlement Plot for Marker No. 10 2.5-77 Load/Settlement Plot for Marker No. 11 2.5-78 Load/Settlement Plot for Marker No. 12 2.5-79 Load/Settlement Plot for Marker No. 13 2.5-80 Load/Settlement Plot for Marker No. 14 2.5-81 Load/Settlement Plot for Marker No. 15 2.5-82 Load/Settlement Plot for Marker No. 16 2.5-83 Load/Settlement Plot for Marker No. 17 2.5-84 Load/Settlement Plot for Marker No. 18 2.5-85 Load/Settlement Plot for Marker No. 19 2.5-86 Load/Settlement Plot for Marker No. 20 2.5-87 Differential/Load Settlement Plot for Marker No. 16 vs. No. 18 2.5-88 Differential/Load Settlement Plot for Marker No. 15 vs. No. 4 2.5-89 Differential/Load Settlement Plot for Marker No. 13 vs. No. 2 2.5-90 Differential/Load Settlement Plot for Marker No. 15 vs. No. 17 2-xxvii HCGS-UFSAR Revision 0 April 11, 1988

LIST OF FIGURES (Cont) Figure Title 2.5-91 Differential/Load Settlement Plot for Marker No. 11 vs. No. 8 2.5-92 Differential/Load Settlement Plot for Marker No. 19 vs. No. 12 2.5-93 Differential/Load Settlement Plot for Marker No. 3 vs. No. 5 2.5-94 Differential/Load Settlement Plot for Marker No. 9 vs. No. 6 2.5-95 Differential/Load Settlement Plot for Marker No. 4 vs. No. 10 2.5-96 Differential/Load Settlement Plot for Marker No. 17 vs. No. 10 2-xxviii HCGS-UFSAR Revision 0 April 11, 1988

SECTION 2 SITE CHARACTERISTICS 2.1 GEOGRAPHY AND DEMOGRAPHY 2.1.1 Site Location and Description 2.1.1.1 Specification of Location HCGS is located in the southern section of Artificial Island on the east bank of the Delaware River in Lower Alloways Creek Township, Salem County, New Jersey. The site center point is located at latitude 39° 27' 53" north and longitude 75° 32' 12" west. The Universal Transverse Mercator coordinates of the site center are 4368307mN and 453872mE, Zone 18.

2.1.1.2 Site Area Map A detailed map of the site area is provided on Figure 2.1*1.

map details plant property lines and site boundaries. site boundaries may be scaled from this map. The HCGS This Distance to site dimensions, shape, and area are shown on Figure 2.1-2. 2.1.1.3 Boundaries for Establishing Effluent Release Limits The land boundary, on which technical specification limits for release of gaseous radioactive effluents are based, is the property line defining land owned by Public Service Electric and Gas Company (PSE&G). Distances from station vents to the property line in any direction may be scaled from Figure 2.1-1 .

HCGS-UFSAR 2.1-1 Revision 0 A ril . 1988

2.1.2 Exclusion Area Authority and Control 2.1.2.1 Authority PSE&G has fee simple ownership, including mineral rights, of the 740-acre Artificial Island site. The site boundary and exclusion area boundary are one and the same except along the Delaware River. The Hope Creek Generating Station property line lies within the site boundary as indicated on Figure 2.1-1. The minimum distance from the accident release point of the reactor to the nearest exclusion area boundary formed by land is 901 meters. In accordance with 10CFRlOO, Paragraph 100.3(a), arrangements have been made by a letter of agreement with the United States Coast Guard for the control and evacuation of persons on the adjacent waterway-the Delaware River. 2.1.2.2 Control of Activities Unrelated to Plant Operation The only activity within the PSE&G property boundary not directly related to power generation is the PSE&G Visitor Information Center. The visitor center is located on the south edge of the property boundary as identified on Figure 2.1-1. Activities at the visitor center are controlled by PSE&G. The location of the two unit Salem Generating Station (SGS) is also identified on Figure 2 .1-1. 2.1.2.3 Arraniements for Traffic Control There are no highways, railways, or waterways crossing the exclusion area. HCGS-UFSAR 2.1-2 Revision 0 April 11, 1988

2.1.2.4 Abandonment or Relocation of Roads There are no public roads to be abandoned or relocated in the exclusion area. 2.1.3 Population Distribution Population and population distribution for the 0 to 10 and 10 to 50-mile areas are keyed to sectors and zones. The 0 to 10-mile area is divided into concentric circles around the site center point, at distances of 1, 2, 3, 4, 5, and 10 miles. The same was done for the 10 to 50 miles, but at 10-mile intervals between the 10 and 50-mile radii. The circles are divided into 22-1/2-degree segments with each segment centered on one of the 16 compass points. 2.1.3.1 Population Within 10 Miles Current residential population within 10 miles of the Artificial Island site by sector and ring is shown on Figure 2.1-3, using References 2.1-1 and 2.1-2. The projected population for the first full year of station operation in 1987 is shown on Figure 2.1-4. The projected populations by sector and ring for each census decade from 1990 through the projected station life in 2030 are shown on Figures 2.1-5 through 2.1-9. Field surveys were conducted to determine the number and distribution of population by ring and sector within 0 to 5 miles of the site as discussed in Reference 2.1-3. Dwelling units within the 0 to 5-mile area were identified in the field and noted on a map by ring and sector. A dwelling unit vacancy rate was applied to the dwelling units in each sector to determine the number of occupied dwelling units. A separate vacancy rate was established for New Jersey and Delaware sectors, as mentioned in References 2 .1-1 and 2.1-2, respectively, based on the 1980 Census of Housing. The following are the 1980 vacancy rates by county:

1. Cumberland County, NJ -Vacancy rate of 6.7 percent 2.1-3 HCGS-UFSAR Revision 0 April 11. 1988

2. Salem County, NJ - Vacancy rate of 6.8 percent

3. New Castle County, DE - Vacancy rate of 5.9 percent Having identified the 1980 distribution of occupied housing units in the 0 to 5-mile area, an average household size was determined, based on the 1980 census in References 2.1-1 and 2.1-2, as follows:

1. Cumberland County, NJ - Average household size 2.9

2. Salem County, NJ - Average household size 2.9

3. New Castle County, DE - Average household size 3.1.

The number of occupied dwelling units was then multiplied by the average household size to determine the 1980 distribution of population by sector and ring within 0 to 5 miles of the site. Current 1980 census tract data from Reference 2.1-4 were used to determine the number and distribution of population by ring and sector for the 5 to 10-mile area. Where census tract boundaries did not coincide with sector ring boundaries, it was assumed that population within the census tract was uniformly distributed. A land use comparison with the U.S. Geological Survey (USGS) quadrangles and county master plans was conducted to identify both significant concentrations of population and large vacant undeveloped areas. In this way, the uniform distribution of population within each census tract was adjusted to reflect actual conditions. The basis for the 0 to 10-mile population projections were field surveys from Reference 2. 1-3 , the 1980 Census of Population and Housing for New Jersey and Delaware, state and county projections for the years 1987 to 2010 from References 2.1-5 and 2.1-6, and federal projections by state for the years 2020 to 2030 from Reference 2.1-7. The federal projections were consistently lower than the state projections; accordingly, state projections were used 2.1-4 HCGS-UFSAR Revision 0 April 11, 1988

in order to be conservative. However, the state projections for the year 2000 were consistently higher than federal projections for the year 2010. To avoid a dip or decline in population, it was assumed that the populations between the years 2000 and 2010 were stable. For the years 2020 and 2030, the federal projections were used. In this way, an artificial decrease in projected population does not occur during the transition period from state to federal projections. The major difference between state and federal projections appears to be the more optimistic state view of growth compared with the more balanced federal approach, particularly in terms of economic activity. 2.1.3.2 Population Between 10 and 50 Miles Current residential population within 10 to 50 miles of the Artificial Island site is shown on Figure 2.1-10. The projected population for the first full year of station operation in 1987 is shown on Figure 2 . 1-11. The projected population for each census decade from 1990 through the projected station life in 2030 are shown on Figures 2.1-12 through 2.1-16. The bases for the 10 to 50-mile population projections were 1980 Census of Population and Housing for New Jersey, Delaware, Maryland, and Pennsylvania, from References 2.1-1, 2.1-2, 2.1-8 and 2.1-9, state projections by county for the years 1987 to 2010 from References 2.1-5, 2.1-10, 2.1-11, and 2.1-12, and federal projections by state for the years 2020 to 2030 from Reference 2.1-7. The federal projections were consistently lower than the state projections; accordingly, state projections were used in order to be conservative. However, the state projections for the year 2000 were consistently higher than federal projections for the year 2010. To avoid a dip or decline in population, it was assumed that the year 2000 and 2010 populations were stable. For the years 2020 and 2030, the federal projections were used. In this 2.1-5 HCGS-UFSAR Revision 0 April 11, 1988

way, an artificial decrease in projected population does not occur during the transition period from state to federal projections. The major difference between state and federal projections appears to be the more optimistic state view of growth compared with the more balanced federal approach, particularly in terms of economic activity. 2.1.3.3 Transient Population Transient population is discussed below in terms of 0 to 10 and 10 to 50 miles from the Artificial Island site. It is noted that the transient population includes a substantial double-counting of the resident population. 2.1.3.3.1 Transient Population Within 0 to 10 Miles The distribution of transient and special facilities population within 0 to 10 miles of the Artificial Island site is shown in Table 2.1 .. 1. This distribution is based on the transient and special facilities populations identified in the Artificial Island site's Evacuation Time Estimates in Reference 2.1-13. Employment concentration centers within 0 to 10 miles of the Artificial Island site are:

1. Delaware City Industrial Complex, DE - 10 to 10.5 miles north-northwest

2. Middletown, DE - 10.0 miles west

3. Salem, NJ - 8.0 miles north-northeast.

Other than in the city of Salem, there are no major shopping centers within 0 to 10 miles of the site. 2.1-6 HCGS-UFSAR Revision 0 April 11, 1988

The Delaware City Industrial Complex consists of industries predominantly of the petrochemical classification. Approximately 2,000 persons are employed at this complex, about 1,000 of which are within 10 miles of the site, as mentioned in Reference 2.1-14. Employees travel to work from up to 40 miles distant, primarily on the west side of the Delaware River, as mentioned in Reference 2.1-14. Employment in Salem, New Jersey and Middletown, Deleware, is more localized. Employees generally live within 5 to 15 miles of their place of work, according to Reference 2.1-14. The locations of special facilities, from Reference 2.1-3, are shown in Table 2.1-2. Special facilities populations, from* Reference 2.1-13, are included in Table 2.1-1. Annual visitations to parks and wildlife areas and other recreational facilities within 0 to 10 miles of the site are shown in Table 2.1-3 and on Figures 2.1-17 and 2.1-18, using References 2.1-15, 2.1-16, and 2.1-17. Within the 0 to 10-mile area, there are transient populations related to the use of the Delaware River. Ports of landing for both commercial and recreational salt water fishing are shown on Figure 2.1-19, using References 2.1-18 and 2.1-19. The waters within the Delaware River are locations of both commercial and recreational fish and shellfisheries as shown on Figure 2.1-20, using References 2.1-18 and 2.1-19. The Delaware River is the major route for barge and freight traffic between the Philadelphia area ports and the Atlantic Ocean. According to the U.S. Army Corps of Engineers Philadelphia District, in Reference 2.1-19, approximately 111,500 vessel trips were made past the Artificial Island site in 1979, carrying 1,443,570 persons . 2.1-7 HCGS-UFSAR Revision 0 April 11, 1988

2.1.3.3.2 Transient Population Within 10 to 50 Miles of the Site The major employment centers located within the 50-mile radius area are shown in Table 2.1-4. The estimated total employment for these centers is 888,900 persons, as discussed in Reference 2.1-20. These major employment centers include Philadelphia, which is the core of the Philadelphia Standard Metropolitan Statistical Area, as well as subregional centers such as Camden and Vineland, New Jersey; and Wilmington, Newark and Dover, Delaware. Philadelphia generates employment for a large area that is outside of the 50-mile radius from the Artificial Island site. The other communities, however, attract employees from a relatively narrow area within the 50-mile radius. Philadelphia also generates the largest student population in the area due to a concentration of major colleges and universities. Students at colleges and universities are counted in the U.S. Census as year-round residents in their place of residence in February and March. Therefore, virtually all students are permanent, not transient, persons. Major shopping areas within the 10 to 50-mile radius area are Philadelphia, Pennsylvania; Wilmington and Newark, Delaware; and Camden (Cherry Hill), New Jersey. The recreation and tourism area of the site within the 10 to 50-mile area are located along the New Jersey ocean shoreline and also along the Delaware and Chesapeake Bays in New Jersey, Delaware, and Maryland, as mentioned in Reference 2.1-21. The major seasonal recreation and tourist population concentrations are close to the New Jersey ocean shoreline, 40 to 50 miles, east, east-southeast, and southeast from the Artificial Island site. Table 2.1-5 shows the population concentrations for this area, using Reference 2.1-21. State parks, forests, and wildlife management areas are used predominantly from the spring through the fall months. 2.1-8 HCGS-UFSAR Revision 0 April 11, 1988

Figures 2.1-17 and 2.1-18 show the locations of these areas as well as annual visitations to them, using References 2.1-17 and 2.1-21 . Within the 10 to 50 mile area, there are transient populations related to the use of Chesapeake Bay and the Delaware Bay and River. Ports of landing for both commercial and recreational salt water fishing are shown on Figure 2 .1-19, using References 2. 1-18 and 2.1-19. The waters within the Chesapeake Bay and the Delaware Bay and River are locations of both commercial and recreational fish and shellfisheries as shown on Figure 2.1-20, using References 2.1-18 and 2.1-19. 2.1.3.4 Low Population Zone The low population zone (LPZ) for the Artificial Island site has a S-mile radius with a 1980 population of 1190 persons . The major population clusters within the LPZ are as follows:

1. Hancock's Bridge, NJ - 327 persons, 4.9 miles northeast

2. Port Penn, DE - 236 persons, 4.2 miles north-northwest

3. Bay View, DE - 104 persons, 3.5 miles west-northwest The location of highways, waterways, beaches, and wildlife areas within the LPZ are shown on Figure 2.1-21, using References 2.1-22, 2.1-23, 2.1-24, and 2.1-25. Seasonal and tourist population distributions within the LPZ are shown in Table 2.1-6, using References 2.1-26 and 2.1-27. Except for Delaware River traffic, virtually all of the seasonal users of recreation facilities in the LPZ come from within 50 miles of the site *

HCGS-UFSAR Revision 0 April 11, 1988

2.1.3.5 Population Center The nearest population center to the Artificial Island site is Newark, Delaware, with a 1980 population of 25,247 people. The 1980 population of Newark increased by 18.5 percent from the 1970 population of 21,298. Newark is located 17.8 miles northwest of the site. The location and population of Newark and other lesser population centers within 30 miles of the Artificial Island site are shown on Figure 2.1-22. The location of the population center was determined in accordance with 10CFRlOO. Bridgeton and Salem, New Jersey, with 1980 populations of 18,795 and 6959, are located 14.9 and 7. 9 miles, respectively, from the site, as given in Reference 2.1-1. Transient populations were not used in determining the population center within the 0 to 30-mile area because they do not significantly alter the general population distribution within the 0 to 30-mile area around the Artificial Island site. 2.1.3.6 Population Density The 0 to 30-mile cumulative resident population projected for the initial full year of plant operation, 1987, is 1,009,117, shown in Table 2.1-7, using References 2.1*1, 2.1-5, 2.1-6, and 2.1-7. This population density of 356 persons per square mile is less than the standard uniform population density of 500 people per square mile within 0 to 30 miles of the Artificial Island site. The 0 to 30-mile projected cumulative resident population for the end of the plant life, the year 2030, is 1,181,153. This population density of 417 persons per square mile is less than the uniform population density standard of 1000 people per square mile. HCGS-UFSAR 2.1-10 Revision 0 April 11, 1988

2.1.4 References 2.1-1 U.S. Bureau of the Census, "1980 Census of Population and Housing, New Jersey, n Advance Reports, PHCSO-V-32, U.S. Department of Commerce, March 1981. 2.1-2 U.S. Bureau of the Census, "1980 Census of Population and Housing, Delaware," Advance Reports, PHCSO-V-9, U.S. Department of Commerce, February 1981. 2.1-3 Field Surveys by Dresdner Associates conducted during May and June 1982. 2.1-4 Unpublished U.S. Bureau of the Census tract data and maps available at county planning departments, and census tract data and maps reviewed at the planning department offices of Cumberland and Salem Counties, New Castle and Kent Counties,. DE

2.1-5 New Jersey Department of Labor and Industry, "New Jersey Population Projection 1980-2000," February 1982.

2.1-6 New Castle County Planning Board, "Population Projections 1980-2000," March 1982. 2.1-7 U.S. Department of Commerce, "1980 OBERS BEA Regional Projections," February 1982. 2.1*8 U.S. Bureau of the Census, "1980 Census of Population and Housing, Maryland," Advance Reports, PHC80-V-22, March 1981. 2.1-9 U.S. Bureau of the Census, "1980 Census of Population and Housing, Pennsylvania," Advance Reports, PHCSO-V-40, March 1981 . 2.1-11 HCGS-UFSAR Revision 0 April 11, 1988

2.1-10 Delaware Department of Health and Social Services, "Population Projections by County and City 1975-2000," February 1980. 2.1-11 Maryland Department of State Planning, "Interim Population Projections for Maryland Political Subdivision 1980-2000," June 1981. 2.1-12 Pennsylvania Office of State Planning and Development, "Pennsylvania Projection Series 1980-2000, Summary Report, 78 PPS-1," June 1978. 2.1-13 Parsons, Brinckerhoff, Quade and Douglas, "Evacuation Time Estimates," February 1981. 2.1-14 "Delaware Directory of Commerce and Industry," 1979. Also, personal communications with: D. Timmens, Technical Supervisor, Diamond Shamrock, May 28, 1982.

L. Fleming, Manager, Schargen Gas Co, May 28, 1982.

D. Press, Public Affairs, Getty Refining & Manufacturing Co, May 25, 1982. M. Morris, Manager, Stauffer Chemical Co, May 26, 1982. J. Butler, American Hoechst Corp, May 28, 1982. L. Evo, Standard Chlorine of Delaware, Inc, May 26, 1982. H. McFadden, Plant Manager, Chloromone Corp, June 4, 1982. G. Hobbie, Plant Manager, Cardox, June 2, 1982. 2.1-15 New Jersey Department of Labor and Industry, "Boat Basins in New Jersey," 1978. 2.1-16 Sea Grant Advisory Service, "A Guide to Delaware's Coastline Marinas," 1979. HCGS-UFSAR 2.1-12 Revision 0 April 11, 1988

2.1-17 Personal communications with officials of: New Jersey Division of Parks and Forestry, June 23, 1982. Delaware Division of Parks and Recreation, June 23, 1982. Delaware Division of Fish and Wildlife, June 23, 1982. 2.1-18 Townsend, R., "Guide to New Jersey's Saltwater Fishing, 1974. 11 2.1-19 Personal communications with: D. Christian, National Marine Fisheries Service, June 21, 1982. M. Carson, U.S. Army Corps of Engineers, Philadelphia District, June 21, 1982. 2.1-20 Personal communications with: R. Alzarski, Economist, Pennsylvania Department of Labor, June 25, 1982. J. Major, Principal Labor Market Analyst, New Jersey Department of Labor and Industry, June 24, 1982. E. Simmons, Planning and Research, Pennsylvania Department of Labor, June 25, 1982. 2.1-21 Personal communications with employees of: Maryland State Park and Recreation Service, June 24, 1982. Pennsylvania Bureau of State Parks, June 24, 1982. 2.1-22 New Castle County Planning Board, "The Red Lion Planning District Plan, 1995," September 1973 .

HCGS-UFSAR 2.1-13 Revision 0 April 11, 1988

2.1-23 New Castle County Planning Board, "The Middletown-Odessa-Townsend Planning District Plan 1995." September 1973. 2.1 .. 24 U.S. Department of Agriculture, South Jersey Resource Conservation & Development Area Plan," April 1979. 2.1*25 Personal communications with: R. Chartawich, New Castle County Department of Planning, May 20, 1982. C. Warren, Salem Country Department of Planning, May 20, 1982. 2.1-26 Dames & Moore, "New Jersey Shore Area Seasonal Population Study," 1973. 2.1-27 Dresdner Associates, Reevaluations of AGS PSAR Population Projections," 1977. HCGS-UFSAR Revision 0 April 11, 1988

TABLE 2.1-1 TRANSIENT AND SPECIAL FACILITIES POPULATION WITHIN 0-10 MILES OF THE ARTIFICIAL ISLAND SITE 1981(l) Miles Sector 0-2 .2..::..2 5-10 Total N 0 7 141 148 NNE 0 0 3,569 3,569 NE 0 0 384 384 ENE 0 0 0 0 E 0 0 285 285 ESE 0 0 0 0 SE 2 8 8 18 SSE 2 8 58 68 s 2 2 0 4 ssw 2 0 1,011 1,013 SW 2 0 0 2 WSW 2 0 484 486 w 2 0 2,754 2,756 WNW 2 3 0 5 NW 2 3 1,341 1,346 NNW 2. 10 1.391 1.403 Total 20 41 11,426 11,487 (1) Source: Parsons, Brinckerhoff, Quade & Douglas, Evacuation Time Estimates, 1981 .

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988
LOCATION OF SPECIAL FACILITIES WITHIN 10 MILES OF THE ARTIFICIAL ISLAND SITE 1982(l)

Facilities Delaware Schools Location Silver Lake - Elementary (Middletown) 9.5 mi W Middletown - High School 9.5 mi W Redding - Middle (Middletown) 9.5 mi W Broad Meadow School - Private Middle & Elementary 9.5 mi W (Middletown) St. Andrews - Private Protestant High School 9.5 mi W (all boys) (Middletown) Townsend - Elementary (Townsend) 9.8 mi SW Commodore MacDonough - Elementary (St. Georges) 8.8 mi SW Delaware City - Elementary (Delaware City) 8.0 mi NNW Gunning Bedford - Middle (Delaware City) 8.0 mi NNW Corbit - Elementary (Odessa) 6.5 mi W Au Clair - Elementary (St. Georges) 9.0 mi NW

HCGS-UFSAR 1 of 3 Revision 0 April 11. 1988

TABLE 2.1-2 (Cont) New Jersey Schools Quinton Township - Elementary (Quinton) 8.5 mi NE John Fenwick - Elementary (Salem) 8.0 mi NE Salem Day Care Center 8.0 mi NE Salem - Middle (Salem) 8.0 mi NE Salem - High School (Salem) 8.0 mi NE Lower Alloways Creek Elementary (Hancock's Bridge) 4.9 miNE Elsinboro - Elementary (Elsinboro) 7.0 mi NNE Stow Creek - Elementary (Stow Creek) 9.9 mi E Woodland Country Day School - Pre-School to Elementary (Stow Creek)

97. mi E -

St. Mary's Elementary (Salem) 8.0 mi NNE Hospitals Salem County Memorial 8.0 mi NE Salem County Nursing and Convalescent Center 8.0 mi NE Governor Bacon Health Center, DE 8.0 mi NNW'

HCGS-UFSAR 2 of 3 Revision 0 April 11, 1988

TABLE 2.1-2 (Cont) Jails Salem County Jail 8.0 mi NE (1) Source: Survey by Dresdner Associates, May, 1982 .

HCGS-UFSAR 3 of 3 Revision 0 April 11, 1988

TABLE 2.1-3 RECREATION AND TOURISM WITHIN 0-10 MILES OF THE ARTIFICIAL ISLAND SITE 1981 Annual Location Visitations Fort Delaware Park, DE 9.0 mi NNW 12,200(l) Fort Mott State Park, NJ 10.0 miN 45,700( 2 ) Wildlife Refuges & Management Areas Mad Horse Creek Wildlife Management Area, NJ 2-8.0 mi SE l,ooo< 2 > Appoquinimink Wildlife Area, DE 2-5.0 mi WSW loo< 3 > Reedy Island Wildlife Refuge, DE 4.0 mi NNW 5oo< 3 > Augustine Creek Wildlife Area, DE 4.5-8.0 mi NNW 500( 3 ) Woodland Beach Wildlife Area, DE 7-10.0 mi SSE 1,200( 3 ) Canal National Wildlife Refuge, DE 8-10.0 mi NNW 2,ooo< 3 ) Maskells Mill Pond Wildlife Management Area, NJ 7.0 mi ENE 800( 2 ) Killcohook National Wildlife Refuge, NJ 10.0 mi N 500( 2 ) Beaches Augustine Beach, DE 4.0 mi NNW Not available Bay View Beach, DE 3.5 mi WNW Not available Woodland Beach, DE 10.0 mi SSE Not available Oakwood Beach, NJ 6.5 mi N Not available Country Clubs Country Club of Salem, NJ 6.5 mi N 11,250( 4 ) Wild Oaks Country Club, NJ 7.5 miNE 20,000( 5 ) 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 2.1-3 (Cont} Annual Parks Location Visitations Boat Marinas and Launches Marboro Marina, NJ 8.0 mi NNE 4, ooo< 6> Delaware City Marina, DE 8.0 mi NNW 2,6oo< 7 > Delaware City Launching Ramp, DE 8.0 mi NNW 3,ooo< 7 > Port Penn Launching Ramp, DE 4.2 mi NNW 2,1oo< 7> Woodland Beach Launching Ramp. DE 9.8 mi SSE 2,ooo< 7> (1) Delaware Division of Parks and Recreation, June 23, 1982. (2) New Jersey Division of Parks and Forestry, June 23, 1982. (3) Delaware Division of Fish and Wildlife, June 23, 1982. (4) J. Stradley, President, Country Club of Salem, Salem, New Jersey, June 21, 1982. (5) J. Hasler, President, Wild Oaks Country Club, Salem, New Jersey, June 21, 1982. (6) New Jersey Department of Labor and Industry, Division of Travel and Tourism, Boat Basins in New Jersey, 1978. (7) Sea Grant Advisory Service, A Guide to Delaware's Coastline Marinas, 1979 .

HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 2.1-4 MAJOR EMPLOYMENT CENTERS LOCATED WITHIN 10-50 MILES OF THE ARTIFICIAL ISLAND SITE 1981 Total Employment Location Philadelphia, PA 775,700(l) 35-50 mi NNE Camden, NJ 40,900( 2) 40 mi NE Wilmington, DE 32 8oo< 3 >

                                  ,                      20 miN Vineland, NJ                  19,400( 2 )               24 mi E Newark, DE                    10,soo< 3 >               19 mi NW Dover, DE                       9,7oo< 3 >              22 mi S Total                    888,900

(1) Bob Alzarski, Economist, Pennsylvania Department of Labor, Bureau of Labor Statistics, June 25, 1982.

(2) Jim Major, Principal Labor Market Analyst, New Jersey State Department of Labor and Industry, June 24, 1982. (3) Ed Simmons, Planning & Research, Delaware Department of Labor, June 25, 1982 .

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.1-5 SEASONAL AND TOURIST POPULATION NEW JERSEY SHORELINE, 40-50 MILES AVERAGE SUMMER DAY POPULATION(l) Seasonal E 17,190 ESE 66,690 SE 191,020 (1) Sources: Dames & Moore, New Jersey Shore Area Seasonal Population Study, 1973. Dresdner Associates, Reevaluation of AGS PSAR Population Projections, 1977 .

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.1-6 POPULATION DISTRIBUTION WITHIN THE LOW POPULATION ZONE 1982 Seasonal Transient Peak Daily Population Population (annual) Delaware River Ship Traffic 4,000(l) 1,443,570(l) Wildlife Areas Augustine Creek 45( 2 ) 500( 2 ) Wildlife Area, DE Reedy Island 15( 2 ) 500( 2 ) Wildlife Refuge, DE Appoquinimink Wildlife Area, DE Mad Horse Creek 1,000( 3 ) Wildlife Management Area, NJ

HCGS-UFSAR 1 of 2 Revision 0 April 11, 1988

TABLE 2.1*6 (Cont) Seasonal Transient Peak Daily Population Popu.lat:ion (annual} Beaches Augustine Beach, DE Not available Not available Bay View ~each, DE Not available Not available (1) U.S. Army Corps of Engineers, Philadelphia District, Waterborne Commerce of the United States, 1979. (2) Delaware Division of Fish and Wildlife, June 23, 1982. (3) New Jersey Division of Parks and Forestry, June 23, 1982 .

HCGS*UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 2.1-7 CUMULATIVE POPULATION AND DENSITY WITHIN 0-30 HILES OF THE ARTIFICIAL ISLAND SITE(l) Hiles From Cumulative Population Site l21Z. 2030 0-1 0 0 0-2 0 0 0-3 0 0 0-4 289 357 0-5 1,286 1,565 0-10 25,479 28,921 0-20 395,613 484,340 0-30 1,009.117 1,181,153 Density 0-30 356 417 (1) Sources: 1980 Census of Population & Housing. New Jersey Department of Labor, New Jersey Population Projections 1980-2000, February, 1982. U.S. Department of Commerce, 1980 OBERS BEA Regional Projections (1969-2030), July 1981. New Castle County Planning Board, Population Projection 1980-2000, March 1982 .

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

a: w

 -a:
  >                           PROPERTY~RSEY STATEOF NEW EXCLUSIO SITE ANDBOUNOARY AREA w

a: c

  ~
 ..J w

a PROPERTY~8EY STATEOF NEW REVISION0 APRIL 11, 1988

                                                               ..2 0          0 MINIMUMOEUX~~~~I~N                       0       0 0

AREAB 0 0 (gQ1 METERS) "'-.- 0 ~ FEET DEL*AWARE RIVER

                                                  *       *Cl!   C)

CN SITEPLAN

..=

CD ~ Ill) CN CD 0 flo METERS UPDATEDFSAR FIGURE2.1-1

SITE AREA ____. PROPERTY LINE/EXCLUSION AREA

                                                       ~ 740 ACRES, UTlliTY PROPERTY r----**

d

I\ i i

    ~     i
     ,..j
      -:1\i
         ~             0
                       ~i 10 7200 FT
                   -f:i
                        """~
                                  ..p DEL ARE REVISION0 APRIL 11, 1988 1         0 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION MILES 1
                                                         --  0 KILOMETERS 1

SITEAREA UPDATED FSAR FIGURE2.1*2

N POPULATIONDISTRIBUTION 1980 SEE FIGURE2.1-4 FOR 1980 TABULARDATA MILE DETAIL
E SOURCES: 1980 CENSUS OF POPULATION &HOUSING FOR NEW JERSEY AND DELAWARE 0*10 MILES REVISION 0 1 0 1 2 3 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY MILE& HOPE CREEK NUCLEAR GENERATING STATION REfEftfHCf: :

1 0 1 23 KILOMETER& POPULATION DISTRIBUTION-YEAR1980, WITHIN0 TO 10 MILES tHIS IIAP WAS PR£PAA£D Fllllft A POIITlflll II' ll£Fll.* UliiiN6 tJ.S.G.S. IIAP1 IIIUtlNGTOII. oo.AIW£, 1966. UPDATEDFSAR FIGURE2.1-3

POPULATIONPROJECTIONS N

                                                                                                    & POPULATIONDISTRIBUTION 1987 MILES         o~t       1-2     2*3    a-c     c-a    S*10 TOTM.

N - - - -- !!.!!.... 381

                                                                                                                                                                            !!lll 3111 NNE           -         -      -      -        it ml-              Iii/

NE - - - 6 i"' 319 iiT 2027 Ii'r4 '-mi-ENE -- - 56 ii; 1! !%i.. H* E - - - - - ~ *i ESE -- - - - m m

                                                                                                                                                                            ..n SE           - -              --              -          ii 1i SSE           - -              -      --                Ri fit I           - -              --              .!!!

ffi !.!!..

m

                                                                                                                                                       !9                    317 ssw            --               -      ll 9

IW -- - - ill 5.. 2 WSW -- - - !1-9 lffi lWf w -- - !! g fi tm W! 3226 WNW -- - m 10 .. n -ffi m 25 NW - - ~ ffl We ~ NNW -- - t .ill 236

1902 fffi TOTAL - *- - ~ ~

                                                                                                                                                            ~7 20972
                                                                                                                                                                         ~

2216~ 1981 P!!P!!t.ATIO!! PROJECTED 19110 IV'I.UTUIH EXISTING aaaa MDIUSitiii.IS !YEAR 0-1 0*2 0*3 o-c o-a 0*10 8188 ACCUMULATED1987 - -- 289 121!16 2lfi9J MIDDLETOWN E POPULATION 1980

                                                                                                                         --                -       261      1190         22162 SOURCES: 1980 CENSUS OF POPULATION.& HOUSING FOR NEW JERSEY AND DELAWARE NEW 'JERSEY DEPT. OF LABOR, . NEW JERSEY POPULATION PROJECTIONS 1980-2000, FEBRUARY 1982.

U.S. DEPT. OF COMMERCE, 1980 OBERS BEA REGIONAL PROJECTIONS, JULY 1981. NEW CASTLE COUNTY PLANNING BOARD~ POPULATION PROJECTIONS 1980-2000, MARCH 1982. 0*10 MILES REVISION 0 1 0 f 2 a APRIL 11, 1988 MILES PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION 1 o 12 a KILOMETERS POPULATION DISTRIBUTION - IIUEliEHCE; YEAR 1987,WITHIN0 TO 10MILES TIUS !UP liAS PIIEPAII£D fRilllA l'c.TIOIIOF liE FIL* LOWING U.S.G.S. !UP: IIIUtiiiGJOfl, DEI.AIWIE, 1!116. 0-MfLE--~tAOlU8 s UPDATEDFSAR FIGURE2.1-4

I N POPULATIONPROJECTIONS

                                                                                            & POPULATIONDISTRIBUTION 1990 MIL18 0-1            1-2     2*1                        5*10 TOTAl.

11'"*

N - - - - - tllf

                                                                                                          -                - -                                     jffi.

81 NNE - l.!!l! iDes NE - - - f ~ ll!.!!. ~* 21'!1(1 ENE -- - ;; .!!.

12~ 18 112& E - - m 978

                                                                                                                           --                -                       m TiD ESI         --                                           ~

SE -- -- - ltl ii ~ SSE -- -- - .ll.!! !!!"

m

                                                                                                                                                        )50          l!ill
                                                                                                          -        -       - -                ~~

ssw -- - -;- 1 ..

                                                                                                                                             -         ffi           21T m

mt""

sw - - it ~ WSW -- - - .!!!.

                                                                                                                                                      !ffi          ~
                                                                                                                   - - ~
                                                                                                                                                '!I w         -                                  ft       ~

3189 WNW -- - ~ ~

                                                                                                                                                       ..'!.!.!. w.
                                                                                                                    - - ~

Itt') 51t8 NW - !.!.!!. 176 m 718 ~ NNW -- - ...i!. 3 fft 1.!!.2 1902 ffif TOTAL - - £!.:! 1.61 ~ ~

                                                                                                                                                    ,0,72 li!!ll
                                                                                                                                                                  16' 1990POP\1\.ATION PIIO£CTED 1980 POPULATIOH   EXISTING IIADIUS.. MLES YEAR        0-1        0*2     0*1        0*4        o-*           0*10 ACCUMULATED1990              ---                          299        1325         21t87S E               POPULATION 1980
                                                                                                            --                 -          261       1190         22162 SOURCES: 1980 CENSUS OF POPULATION &HOUSING FOR NEW JERSEY AND DELAWARE NEW JERSEY DEPT. OF LABOR, NEW JERSEY POPULATION PROJECTIONS 1980-2000.

FEBRUARY 1982. U.S. DEPT. OF COMMERCE; 1980 OBERS BEA REGIONAL PROJECTIONS, JULY 1981. NEW CASTLE COUNTY PLANNING BOARD, POPULATION PROJECTIONS 1980-2000. MARCH 1982. 0-10 MILES REVISION 0 1 0 1 2 3 APRIL* 11. 1988 MILES PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION 1 0 12 3 KILOMETERS POPULATION DISTRIBUTION-M:f£IIEIIC£ I TillS IUoP liAS fiREPAIIEJ)FROM A I'OITIOH tS' nE Fill-YEAR 1990,WITHIN Oto10MILES LOlliNG 1J .S.G.S. IU.P: MIUUIIGTOII. IJUIWt£, 1965. 0-UILE-RADIUS s UPDATEDFSAR FIGURE 2.1-5

N POPULATIONPROJECTIONS

                                                                                                      & POPULATIONDISTRIBUTION 2000 MILE. 0*1             1*2     2~a    3-4   4*15          1*10 TOTAt.

N - - - - - .:.ll 381 ffi NNE - - - - ft lttn: !ffrr

H* AA NE 7 T

tffi ENE ,~H E - - - - - 1 RU Ut 1 ESE - - - - - ffi .ll.!

1+19 SE - - - - ri SSE - - - - - Wn Hi s -- - - H ffi ffi ffi

ssw - - 15 9 - ffi sw - - - - ..!..!!.

2:2 ffi WSW - - - - ~ !~ I~ w - - -- ll .!.!. !!...!l.!.! !.!...!...!!. 9 28 322:6 318'9 WNW - ffi !.!.'!.

                                                                                                                                                                 .. u
                                                                                                                                                                              .il.J 51+9 NW         -          -       -    ll    l..!..!!..     ~          !,Hi
                                                                                                                                       -     +

76 176 718

                                                                                                                    -          -                  ffl' NNW TOTAL        -          -      -    ffi   l!..ll fH-~
                                                                                                                                                              ~ ~

929 20QQ PQPI.UTIOtt PROJECTED 1980 P!N..ATl(lt EXISTING 4085 3188 RADIUIItMLES !YEAR 0*1 0*2 0*3 0*4 o-a 0*10 MIDDLETOWN ACCUMULATED2000 - -- 331 11+65 273110 POPULATION 198.0 - - - 261 1190 22162 SOURCES: 1980 CENSUS OF POPULATION.& HOUSING FOR NEW JERSEY AND DELAWARE NEW JERSEY DEPT. OF LABOR, NEW JERSEY POPULATION PROJECTIONS 1980*2000. FEBRUARY 1982. U.S. DEPT. OF COMMERCE. 1980 OBERS BEA REGIONAL PROJECTIONS, JULY 1981. NEW CASTLE COUNTY PLANNING BOARD. POPULATION PROJECTIONS 1980-2000, MARCH 1982. 0-10 MILES 1 REVISION0 0 1 2 8 APRIL 11, 1888 MILES PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION 1 0 12 3 IIEFEfOC£: KILOMETERS POPULATION DISTRIBUTION-THIS IIAP WAS PREPAIIEO flltiKA PCJIJI(lt IF 11£ F{l.* YEAR2000,WITHIN0 TO 10MILES I.OIIIIIG U.S.G.S. IW': IIIUUIIGTOit. 1lEI.AWAR£.1966. 0-MILE--ttADIUS s UPDATEDFSAR FIGURE2.1-6

N POPULATIONPROJECTIONS

                                                                                        & POPULATIONDISTRIBUTION 2010 MILl I                                   .t-5 5*10 TOTA&.
                                                                                                                                    - -m 0-1     1-2       2-3    3-4 N      -       -         -      -                         ffi NNE      -       -         -      -       it 00 itH NE      -       -         -      1 ffi 11* 1-Mt T

ENE - - - '!H iOO E - - 1 2H lf!!

                                                                                                   -        - - - -                            ffi    .u!

mm*

ESE lol'J SE - - - SSE - - - - tt! s - - - - H ffi ssw - 1s g - sw - - - - # *m ffi

                                                                                                    -         -      -       -    '"t l.ffi WSW                                                        I~

w - - ll .!.!!. m-i .._I_!_!_ 211 32t6 N; 9 WNW - ffi .ill

                                                                                                                      -           m 51o8 NW        -                      .11                       1..!1:'
                                                                                                                                                     -rro 16 NNW        -         -             f      ffi UJ.!!. fi/12 tffi
                                                                                                   - --                   lf}    !...!..!.!!
                                                                                                                                             ~      ~*

TOTAl. 26 929 2010POP!JUTIOH PIIOJ!CTED 1980PmJUTIOtl EXISTING RAbiJSIIMLES ~\'EAR 0-1 0-2 0*3 0*4 o-s 0*10 ACCUMULATED2010 --- Hl 11o65 27380 POPULATION 1980 - -- 261 1190 22162 SOURCES: 1980 CENSUS OF POPULATION &HOUSING FOR NEW JERSEY AND DELAWARE NEW JERSEY DEPT. OF LABORI NEW JERSEY POPULATION PROJECTIONS 1980-2000. FEBRUARY 1982. U.S. DEPT. OF COMMERCE, 1980 OBERS BEA REGIONAL PROJECTIONS~ JULY 1981. NEW CASTLE COUNTY PLANNING BOARD., POPULATION PROJECTIONS 1980-2000, MARCH 1982. 0*10 MILES 1 0 12 3 REVISION 0 APRIL 11, 1988 MILES PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION 1 0 12 3 rotii£NC£s KILOMETERS POPULATION DISTRIBUTION-tHIS 11AP WAS PIIEPAAED fRtll A faltll* t6 1'1£ fOI.- YEAR 2010,WITHIN0 TO 10MILES lOIIIIIG U.S.G.S. IIAP: 111Ut1NGTC*, IEUICAR£. 19&6. 0-MILE-flAOlU8 s UPO.t\TED FSAR FIGURE2.1*7

N POPULATIONPROJECTIONS

                                                                                                           & POPULATIONDISTRIBUTION 2020 MILt:I       0*1     1*2     2*3    3-4        4*5        1*10 tOTAL N           -       ----                                 m 45?

NNE - -- - ft lim-1-HH- ~* NE - - - 7

                                                                                                                                                            -m-         iUf    §f~ij
                                                                                                                                                  *

w- w T

ENE --- ~ E - - -- - JNj ESE - - - - - ttt ~

it SE liE - - -- - m t~i I -- - - - 21o iT ill m

m 298 saw - -- T 16

                                                                                                                                                              -          ffl aw -                  -      --                -H. -!if iN waw -                  -      - -             *v- Wf wt w            --                    :y.                   tffi Hit WNW            - -            -     ~           .n          m 19-w- ffi- m wr 10 ..       25 NW            - -            -

NNW - - - .!.... 3 236

                                                                                                                                                                       .Ell 1902 2llol
                                                                                                                            ---                                                UfU TOTAL                               .!!!!.    .!.!..!J..  ~

261 929 20972 2920 POI'!J!.ATION PRO..ECTED 1980POPI.UTION EXISTING

     .!!.!..!.                                                                                RADIUS.. IIMU!S [YEAR 0-1               0-2     o-a       0*4           o-1     0*10 3188 MIDDLETOWN                                                                    E              ACCUMULATED2020                  -        -      -        31o6          l5t7    280112 POPULATION 1980                 -        -      -        261           ]1')0   22162*

SOURCES: 1980 CENSUS OF POPULATION & HOUSING FOR NEW JERSEY AND DELAWARE NEW JERSEY DEPT. OF LABOR, NEW JERSEY POPULATION PROJECTIONS 1980*2000~ FEBRUARY 1982. U.S, DEPT. OF COMMERCE; 1980 OBERS BEA REGIONAL PROJECTIONS. JULY 1981. NEW CASTLE COUNTY PLANNING BOARD, POPULATION PROJECTIONS 1980-2000) MARCH 1982. 0*10 MILES REVISION0 1 0 1 2 3 APRIL 11, 1988 MILES PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION 1 0 1 2 3 ltEFEREHC£ I KILOMETERS POPULATION DISTRIBUTION-TillS MAP IIA$ PQEPAR£1) FROM A P(MtJION (f' Tl£ FOI..* YEAR2020,WITHIN0 TO 10MILES LOWING U.S.G.S. IW': llll.llllGlON, ~. 1966. 0-MILE--RADIUS s UPDATEDFSAR FIGURE2.1-8

N POPULATIONPROJECTIONS

                                                                                                & POPULATIONDISTRIBUTION 2030 MILES 0-1              1*2     2-3     3-4       4*5     5*10 TOTAL H          -         - -             -         -       llt .!!!!!..

381 381 NNE - - - - To* !ffif NE - -- T 7 369 m ~=~:- ~1~o ENE -- - ll s~o 92 7i 12lt5 Jf+02

                                                                                                                                                             'J'Jio 'i"i'2l:'

E - - - - - ~ ~ ESE - - - - 1!!. lolQ m_ SE - -- - - ii !!. m 311 SSE - -- - - ffi I - - - - ti- lt02 m -m saw - -- l7

                                                                                                                                                     -      -m -m-
                                                                                                                                         ~

sw - - - !! 22 lB. 51o2 m-WSW - - - - 1-f -m !ffi

                                                                                                                                                           !.252

m mil.ffi w -:;_ !!.!!.

m 3189 WNW - - - m lloO

NW .!2l. .:!.ll

                                                                                                                                                    * *~

76 718 NNW - - - :!.. 3 Tm *§i:i TOTAL - - - ill 261 l2Q.! ~

                                                                                                                                                   "T2"f 20972      22162 20JO P!!'IUT!Oft    PIIO.ECTED 1980 I'OPlllATIOH  EX ISTING 422 8188                                                                              RADIUSIN MILES rrEAA         o-t        0-2    0*3         0*4       o-s       0*10 w                                                                     E            ACCUMULATED2030                -          -      -           357     1565       28921 POPULATION 1980               -          -      -           261     ll!IO      22162 SOURCES: 1980 CENSUS OF POPULATION &HOUSING FOR NEW JERSEY AND DELAWARE NEW JERSEY DEPT. OF. LABOR, NEW JERSEY POPULATION PROJECTIONS 1980-2000~

FEBRUARY 1982. U.S. DEPT, OF COMI'lERCE., 1980 OBERS BEA REGIONAL PROJECTIONS, JULY 1981. NEW CASTLE COUNTY PLANNING BOARD, POPULATION PROJECTIONS 1980-2000, MARCH 1982. 0-10 MILES 1 REVISION 0 APRIL 11, 1988 MtLE8 PUBLIC SERVICE ELECTRIC AND GAS COMPANY 1 0 12 3 HOPE CREEK NUCLEAR GENERATING STATION KILOMETERS IERRENCEc POPULATION DISTRIBUTION-THIS 1W' IIA$ PREPNO FA(II A PORTUII 1:# TIE FIX.* lOlliNG U.S.G.S. IW'1 VIUIINGTOII. laAW.W:. 1966. YEAR2030,WITHIN0 TO tOMILES 0-IULE-ftADIU8 s UPDATEDFSAR FIGURE2.1-9

POPULATIONDISTRIBUTION 1980 MILES 10-:20 20-30 3 0-40 f-40-50!TOTAL N 7G s ~0 g II 0, 5 Jl*l. 6 ~l'l,B KNE qzs 8 2 2 2 <; 3 IS G ]4 7 7 1 1 3 .. 2 NE 7,3 43.7 391. 'l 528. 1 971.0 ENE 6 I 2'1, 1 5'3. l ,q. 2 133.6 E 20 2 ~e. 1 39,9 21.2 132,0 ESE 1 ... 2: 16. 3 10. 5 2~.0 64.0 SE ,3 I, 0 - 27. 'l 2"1. e SSE - *2 ,E l 7. 2 18,0 s 10. & 30.7 11. 3,8 SG. 3 ssw IB 7 II, 6 21. ~ U,l 6 5.1 sw 20 2 5 2 1 2 .~ 7,5 .. s. 7 WSW 16. 0 2.':1 6. ( 9.3 37. l

                                                                                                                        'W         \3. s       1.2          lt3.      ?29,6       288, I WNW          17 ... 22.    (l       41,         15.!        97,3 NW         53.2       26.2             1 s.       2':1. \    u~.2 NNW          (o£,9     63,6              so.~       38. E      1'19. 7 TOTAL                 s .. J * ~     19 52,0 2077.1          4 910 ,ll 3" (). 6
                                                                                                       ~~t""::'E 1 8   YEAR    0-10        0-2 0           0-30           0-40         o-so ACCUMULATEC POI"'A.A  TIOH 1980     22.2         162,B          90<<.0       ;a 55.9       ~93). 0 POPULATION IN DOD'S 10-50 MILES SOURCE: 1980 CENSUS OF POPULATION & HOUSING FOR NEW JERSEY, DELAWARE, PENNSYLVANIA AND MARYLAND.

REVISION0 APRIL 11, 1988 THIS "">1e.o ~".JAS P~E.PARt[.) OF trtf 5 0 6 MILES 20 PUBliC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION 5 0 5 50 POPULATIONDISTRIBUTION-KILOMETERS YEAR 1980,WITHIN10 TO 50 MILES UPDATED FSAR FIGURE2.1-10 - *--~ .,..~ ...._ __

                                   -****-------.-~--------------------------------------1...-----------------'

POPULATIONPROJECTIONS& POPULATIONDISTRIBUTION 1987 MILES 10-20 20~30 30-40 14o~so n-oTAL

                                                                                                                'J 'l 3         .l.l..L..Q.

N ~ 76 a '10. <j ll 0. 5 ~ ~~ NNE ~ ffi1-;:; H- !._,_; l l 41.7 9< e e I~' '" NE -i~ ~

                                                                                                                 "3. 7        -=t ~             -{     ~

971. 0 ENE _..2...1. 6 I -=tH ~ - 1- '-'.. I~

                                                                                                ~ -~ --fiC9 f3.:2 i-~                             -

E ESE ~ 1 7. 7 8 -~ ~; I SE

                                                                                                                 ~                  -               30.2 27.9 l}.'

29. a

                                                                                  -SSE            -                                   ~             ~-

I 7, 2 2

                                                                                                                                                                --re:o
                                                                                                                                                                      ,L s         -    L:.f 1F                       11:2
                                                                                                                                                       ~
                                                                                                                                                                  ~

ssw - H- l...L...'l. ll, 8 ~:t....'

                                                                                                                                                   .p-.-          m-sw              8 w
                                                                                                                   +1 --=t37                        ----r:s
                                                                                                                                                    -~

_::_~ 45.7 WSW ~ ~

                                                                                                                   ~--~
                                                                                                  !&,()              2.'1 w           fB                 ~_!.          ""** ~ ¥at-43, WNW             FB             ~~                 ~
                                                                                                                                     "1.            ~
                                                                                                                                                               !liT, 97.3 l 3:*. '

NW i~ ~ TI'li-:-1 NNW S2 0

                                                                                                  ~6. 9 1._l__l__..i 63.6             lli             ~ ~e ::l 2'i22. 5 54
                                                                                                                                                              ~

TOTAL ~ -~ i~ 'N"Dl;liTU;ll

                                                                  ~~~e o 8

YEAR 0-10 0-20 r 0-30 0-40 0-50 ACCI.MAAT'EO 1 'lH l l i *_,. '-I l 0 09 I ?'ll':l, 5~(: l. lf 1

                                                                                         / c *'

POPUI..A TIOH 19 8C 22.2 3S?, ')04. 55." 4';!3 3. 0 1987 POPULATION PROJECTED POPULATION IN OOO'S 1980 POPULATION EXIStiNG 10-50 MILES SOURCE: 1980 CENSUS OF POPULATION & HOUSING FOR NEW JERSEY. DEIAWAQE, PENNSYLVnNIA AND MARYLAND. NEW JERSEY DEPT. OF LABOR. POPULATION PROJECTIONS 1980-2000, FEBRUARY 1982. U.S. DEPT. OF COMMERCE, REVISION0

  ~EFCAENCE rHIS MAP WAS PREPARED O::RC,M PORTIONS OF THF.

5 0 5 MILES 20 BEA REGIONAL PROJECTIONS, JULY 1981, NEW CASTLE COUNTY PLANNING BOARD. APR ll 11, 1988 PUBLICSERVICE ELECTRICAND GAS COMPANY HOPE CREEKNUCLEARGENERATINGSTATION FOLLOWINGSF:CTit!NAL 6 0 5 20 MARCH 1982. O.ERnN<l.!_,TiCALCH.l. 9

                                                                                                            ~63,1 381,0      b23, TOTAL      3 .. 0.6   ~
                                                                     ~--

YI!AR 0-1 D 0*20 0-30 0-40 0-110 I Ol'i, 2 30 21.8 AC:aa.u..ATE£1l 990 24.9 ~o~.c, ~Gs~.a POPUI.ATlON 1360 22.2 3&2. 8 904,() 26 55.3 ~933.0 1990 POPULATION PROJECTED POPULATION IN OOO'S 1980 POPULATION EXISTING 10-50 MILES SOURCE: 1980 CENSUS OF POPULATION & HOUSING FOR NEW JERSEY, DELAWARE, PENNSYLV4NIA AND MARYLAND. NEW JERSEY DEPT. OF LABOR, '-'='--=;;.;..:.:::.;;::..:.. POPULATION PROJECTIONS 1980-2000, FEBRUARY 1982. REVISION0 U.S. DEPT. OF COMMERCE, APRIL 11, 1988 0 6 20 JULY 1981.

        'lEFEAENCE THIS MAP WAS PREPARED                          NEW CASTLE COUNTY PLANNING BOARD,                                           PUBliC SERVICE ELECTRIC AND GAS COMPANY FROM PORTIONS OF THE       MILES                                                                                            HOPE CREEK NUCLEAR GENERATING STATION FOLLOWINGSECTIONAL 6 0  6    20            MARCH 1982.

AERONAUTICALCHART NEW YORK -- I POPULATIONDISTRIBUTION-KILOMETERS YEAR 1990,WITHIN10TO 50 MILES UPDATED FSAR FIGURE2.1-12

--~-"--~~----~-----------------------------------, POPULATION PROJECTIONS & POPULATION DISTRIBUTION 2000 MILES 10-20 20-30 30*40 140-50 TOTAL N ~ 1~ -18 ill1 -~ NNE fa->:% t~4 ~i ~ .2 1WeS l2 '8 lffiD NE ~ 7,3

                                                                                                                                .~
                                                                                                                                 "3. 7
                                                                                                                                                 -     H ~ 11~

_7.1...2 16_!_.2 ENE -t1- -c ~.L 59,1

3q.] l 33. I; E ..l~ 20.2

                                                                                                                               -~     ~:...
                                                                                                                                                  ~               ~~       ii-H ESE 13 it l ~. 2 I; 1
                                                                                                                                -~                 ¥oj            -
                                                                                                                                                                     +/-:-     ~

SE ,9 -;""': -~ ~

                                                                                                                                                                             ..£::*.

SSE - ----;2 ~ ~ 1 e. o s ~ l 0. 6 l.2....1_ 3(), 7

                                                                                                                                                       !.....:!     n         it}

ssw _.l_l._}_

                                                                                                                      !  s. 7 J.l;_,__:_

l 1. B ~ T fu sw +H -++ - v ~

7. 5 -H:-:i WSW ---'-'--'-

                                                                                                                                                      ~ l~ ~
                                                                                                                     ~

I G. 0 ? *~ w tH +.-t -i;f-; ~ ~ WNW ~ 1ti ~

                                                                                                                                                     ~l.
                                                                                                                                                                    ~

lb. l_Q_ . 91.3

                                                                                                                                                                                    ..2 NW                ~         ~

l G." 3!,,

                                                                                                                                                                    ~       _WQ m
                                                                                                                                                     ~

NNW ~ ~ ~ r?<,~ TOTAL -Nb ~

                                                                                                                                                 .'vb o, .,
                                                                                                                                                 ~2.0           *;,l}fiAii;;*~

IIIAOIJ8 YEAR D-1 0 0-30 0-HI D-50 tH MILES 0-20 t i . i..t ~

                                                                                                                                            ' ' l 9. 3         318(-. 0   ~*,~~.5.:

I'.CCUMUI.ATED )~ POPUI.ATION 1980 22. < 362' 8 go*.o 2B5S.9 4333,0 PROJECTED POPULATION IN OOO'S 1980 POPULATION EXISTING 10-50 MILES SOURCE: 1980 CENSUS OF POPULATION & HOUSING FOR NEW JERSEY, DELAWARE. PENNSYLVA~IA AND MARYLAND. NEW JERSEY DEPT. FEBRUARY 1982. U.S. DEPT. OF COMMERCE, REVISION0 5 0 6 20 BEA REGIONAL PROJECTIONS, JULY 1981. APRIL 11, 1988 i'H"t'RENC*:O

 '1*iiS MAP WAS PRtPAREO                                                NEW CASTLE COUNTY PLANNING BOARD.                                                             PUBLIC SERVIr.E ELECTRif. Al\ll'l GAS r.OMPANY FROM      PO>'l<!O~S          OF   ~HE          Mll.. ES               POPULATION PROJECTIONS 1980-2000.
   /:*                   sFr:TI..Jr,!At..

HOPE CREf:K ~Wf.U:AR Gf.rJf-P.ATU,Jr. STATION u 5 0 5

                                                   -r-,   20            MARCH 1982.
       '.c)w~?~<..l l,i f , C~ A*- C ~ A R T KILOMETERS                                                                                                                   POPULATIONDISlAIBUTION-YEAR 2000,WITHIN10 fO 50 MILES lJP~A TED             FSAR           FIGURE2.1-13

                           *--------------------------------~------------------.

POPULATION PROJECTIONS & POPULATION DISTRIBUTION 2010

                                                               ~~:~""      YEAR    0-10    0-20             0-30           0*<40      0-60 lc :;:

ACCI.MJI..ATI;O

4 ll ':; 3 ... , : I j 9,. :~ .~ 1 ~l*. 0 ~,':H.:.~ ;:

POPULATION 1181) 22.2 352.9 9:4.0 2955.~

3 3 3. 0 20!0 POPULATION PROJECTED POPULATION IN 000' 1980 POPULATION EXISTING 10-50 MILES SOURCE: 1980 CENSUS OF POPULATION & HOUSING FOR NEW JERSEY. DELAWARE, P~NNSYLVANIA AND MARYLAND.

NEW JERSEY DEPT. OF LABOR, POPULATION PROJECTIONS 1980-2000, FEBRUARY 198~. REVISION0 APRIL 11, 1988 JULY 1981.

REFERENCE:

6 0 6 20 THIS MAP WAS PREPARED NEW CASTLE COUNTY PLANNING BOARU, PUBLICSERVICEElECTRICAND GAS COMPANY FROM PORTIO"JSOF THE MILES HOPE CREEK NUCLEARGENERATINGSTATION >itl.OWINGSECTIO,..Al 6 0 5 20 MARCH 1'382. AERONAUT ICA:_ CH Aflr NEW YORI(

                          ~*                                                                                                        POPULATION   DISTRIBUTION-KILOMETERS YEAR 2010, WITHIN10 TO 50 MILES UPDATEDFSAR                PIGURE2.1-14

POPULATIONPROJECTIONS& POPULATIONDISTRIBUTION 2020 IH"":~-- YEAR 0-10 0-20 0-30 0-40 o-so ACC\JMUL.A. TEC 20 20 I B. 0 t.69.; I :51,0 1247..,1 6054,8 POPUL.ATION 1'180 22,2 362.8 'JO". 0 2 e ss. 9 4933,0 2020 POPULATION PROJECTED POPULATION IN OOO'S 1980 POPULATION EXISTING 10-50 MILES SOURCE: 1980 CENSUS OF POPULATION & HOUSING FOR NEW JERSEY, DELAWARE, PENNSYLVANIA AND MARYLAND. NEW JERSEY DEPT. OF LABOR, POPULATION PROJECTIONS 1980-2000, FEBRUARY 1982. REVISION0 JULY 1981. APRIL 11, 1988 REFERENCE 6 0 6 20 THIS MAP WAS PREPARED NEW CASTLE COUNTY PLANNING BOARD, PUBliCSERVICE ElECTRICAND GAS COMPANY HOPE CREEK NUCLEARGENERATINGSTATION

=--

FROM PORTIONS OF THE MILES FOLLOWINGSECTIONAL 606 20 MARCH 1982. AERONAUTICALCHART NEW YORK b4 J POPULATION DISTRIBUTION-KILOMF.TEflS YEAR 2020.WITHIN10 TO 50 MILES UPDATED FSAR FIGURE2.1-15

*~--~*--* ------*-----------------------** *--~~-------~~--------,

POPULATION PROJECTIONS & POPULATION DISTRIBUTION 2030 N NNE NE ENE E ESE SE SSE s ssw sw WSW w WNW NW NNW TOTAL r:".f~ YEAR 0-10 0-20 0-30 0-.40 0-50 TEC ?030 ACCI.M.ILA £ 2*, 9 . . a*~ .. J 1 18\.] j :q ~ .. :, on>.g POPUI..A TION 1980 2 2. 2 JS2. 8 ~04,0 2855,9 "'J.j 3. 0 2030 POPULATION PROJECTED POPULATION IN OOO'S 1980 POPULATION EXIST~NG 10-50 MILES SQURCE: 1980 CENSUS OF POPULATION & HOUSING FOR NEW JERSEY, DELAWARE, PENNSYLVANIA AND MARYLAND. NEW JERSEY DEPT. OF LABOR, POPULATION PROJECTIONS 1980-200Q, FEBRUARY 1982. REVISION0 U.S. DEPT. OF COMMERCE, APRIL 11, 1988 6 0 6 20 BEA REGIONAL PROJECTIONS, JULY 1981. REFERENCE

                               !HIS MAP WAS PRH'.ARED                                           NEW CASTLE COUN1Y PLANNING BOARD,                             PUBLIC SERVICE ElECTRIC AND GAS COMPANY MILES                                                                                    HOPE CREEK NUCLEARGENERATINGSTATION
                               ~R<JV     P<..)R fiQNS Cf "THE                                   POPULATION PROJECTIONS J980-200i.'L SFCT!'JNAL FOL\.G',\'1~-.f\l 5 0  6           20            MARCH 1982.

HICkI. CHA;< f ;;; ;;;;IP"'!!IIii POPULATIONDISTRIBUTION-Al:i'i<;N.~. t>f W Y ')Ri' KILOtAETERS YEAR 2030, WITHIN10 TO 50 MILES UPDATED FSAR FIGURE2.1-16

                ------------**---**----~

*-----~*.-----------------

STATE PARKS & FORESTS WITHIN 0-50 MILES 1981 ANNUAL VISITATIONS

1. TUCKAHOE STATE PARK, MD 50,149

2. GUNPOWDER FALLS STATE PARK. MD 405,922

3. ROCK STATE PARK, MD 218,608

4. ELK NECK STATE PARK, MD 218,602

5. REDDEN STATE FOREST, DE 4,000

6. ELKENDALE STATE FOREST, DE 2,000

7. KILLEN POND STATE PARK, DE 130,152

8. BLACKBIBD STATE FOREST, DE 7,000

9. PARVIA STATE PARK, DE 3,000

10. BELLEPLAIN STATE FOREST, NJ 110,105 ll. WHARTON STATE FOREST, NJ 374,085

12. FRENCH CREEK STATE PARK, PENN 36L 121

13. SUSQUCHANNOCK, PENN 32,383 Jq, BRANDYWINE BATTLEFIELD STATE PARK, PENN 117,837

15. FORT WASHINGTON, PENN 335,494

16. INDEPENOANCE PARK, FENN 3.828,497

17. VALLEY FORGE, PENN 12, 18L7ll0

18. FORT MOTT STATE PARK, NJ 45,700

19. FORT DELAWARE PARK, DE 12.200 SOURCE: DELAWARE STATE PARKS SERVICE, JUNE 1982 DEVELOPMENT AREA PLAN, U.S. DEPT. OF AGRICULTURE, SOIL CONSERVATION SERVICE, SOMERSET, NJ APRIL 1979 MARYLAND STATE PARK & RECREA Tl ON SERV ICC JUNE 1982 PENNSYLVANIA BUREAU OF STATE PARKS, JUNE 1982 REVISION 0 APRIL 11, 1988 REFERENCE*

TH!S MAP WAS PREPARt;;t* FROM i>ORriOWl OF *,*HE 5 0 5 MILES 20 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SECTIONAL FOLLCWI~~G AERONAUTICALCHART 5 0 5 20 STATE PARKS & FORESTS NEW YOR;< -- I WITHIN 0 TO 50 MilES KILOME"~'ERS UPDATED FSAR FIGURE 2.1-17

WILDLIFE MANAGEMENT AREAS WITHIN 0-50 MILES 1982 ANNUAL VISrTATION I. EASTERN NECK ISLAND NATIONAL WILDLIFE REFUGE, MD Ll5,1.100

2. PRIME HOOK NATIONt.* ! ~. !J:E REFUGL DE 5,000

3. MILFORD NECK WILDLIFE AREA, DE 2,000

                                                       ~. NORMAN G. WILDER WILDLIFE AREA, OE                                    I ,500

5. LITTLE CREEK WILDLIFE AREA, DE 2,500

6. BOMBAY HOOK NATIONAL WILDLIFE REFUGE, DE 55,700

7. WOODLAND BEACH WILDLIFE AREA, DE 8,000

8. BLACKlSTON WILDLIFE AREA, DE 2,500

9. MILLINGTON WILDLIFE MANAGEMENT AREA, MD 4,000

10. CANPL NATIONAL WILDLIFE REFUGE, OE 2,000

11. KILLCOHOOK NATIONAL WILDLIFE REFUGE, DE 500

12. MAD HORE*E CREEK WILDLIFE MANAGEMENT AREA, NJ I ,000

13. GLASSBORO FISH & WILDLIFE MANAGEMENT AREA, NJ 1,300

14. OIX FISH & WILDLIFE MANAGtMENT AREA, NJ 700

15. NANTUXENT FISH & WILDLIFE MANAGEMENT AREA, NJ 800

16. FORTESCUE FISH & WILDLIFE MANAGEMENT AREA, NJ 300

17. EGG ISLAND FISH & WILDLIFE MANAGEMENT AREA, NJ I ,200

18. HEISLERVILLE FISH & WILDLIFE MANAGEMENT AREA, NJ 900

19. EDWARD G. BEVON FISH & WILDLIFE MANAGEMENT AREA, NJ 500

20. CORSON TRACT STATE WILDLIFE MANAGEMENT AREA, NJ 200

21. DENNIS CREEK WILDLIFE MANAGEMENT AREA, NJ 700

22. BEAVER SWAMP WILDLIFE MANAGEMENT AREA, NJ 500

23. TUCKAHOE WILDLIFE MANAGEMENT AREA, NJ 1,200 2~. APPOQUINIMINK WILDLIFE AREA, DE 100

25. REEDY ISLAND WILDLIFE REFUGE, DE :oo

26. AUGUSTINE CREEK WILDLIFE AREA, DE 500

27. MASKELL$ MILL FOND WILDLIFE MANAGEMENT AREA, NJ 800 SOURCE: DELAWARE DIVISION OF PARKS & RECREATION. JUNE 1982 NEW JERSEY DIVISION OF PARKS & FORESTRY, JUNE 1982 DELAWARE DEPT. OF FISH & WILDLIFE, JUNE 1982 MARYLAND WILDLIFE ADMINISTRATION, JUNE 1982 REFERENCE frliS MAF NP.S F'RfcPMi(

FROM PORT10~J S GF ! t*if 0 5 MilES

                                             --   20 REVISION0 APRIL 11, 1988 fGLLOWI'H:l SEC;    !O~AL 5 0 5                20                                               PUBLIC SERVICE ELECTRIC AND GAS COMPANY AFR ONAl!T 'C .'\L CHili<'
                           -     """lllf'""""'  I                                               HOPE CREEK NUCLEAR GENERATING STATION KILOM~-!ERS WILDLIFEMANAGEMENT          AREAS-YEAR 1982,WITHIN0 TO 50 MILES UPD.A.TED FSAR              FIGURE2.1-18

     ,    .. " '-~.-~-*..~*--** ---- ------ --*-           ..              *-*--,-~--------------------------------------------------------                                                    ...

PORTS OF LANDING FOR COMMERCIAL& RECREATIONAL SALTWATERFISHING WITHIN0-50 MILES 1982

l. WILDWOOD, NJ 15. HANCOCK BRIDGE, NJ

2. STONE HARBOR, NJ 16. LEWES, DE

3. AVALON. NJ 17. BAUERS BEACH, DE

4. SEA ISLE CITY, NJ 18. LITTLE CREEK, DE

5. MARMORA, NJ 19. PORT MAHON, DE

6. OCEAN CITY, NJ 20. MISPILllON, DE

7. TUCKAHOE. NJ 21. PORT PENN, DE

8. SOMERS POINT, NJ 22. WOODLAND BEACH, DE

9. SCULLVILLL NJ 23. CAPE MAY, NJ

10. MAYS LANDING. NJ 24. PORT NORRIS, NJ ll. HEISLERVILLE, NJ 25. ROCK HALL, MD

12. MATTS LANDING, NJ 26. ESSEX, MD

13. FORTESCUE. NJ 27. CENTERV I LLL MD

14. NEWPORT, NJ SOURCES: TOWNSEND. R. GUIDE TO NEW JERSEY'S SALTWATER FISHING, nr:n, niVlSIONOF FT~H. GAMF R. SHELLFISHERIES. 1974 DAREL CHRISTIAN. CHIEF FISHERIES STATISTIC INVESTIGATION NE REGION, NATIONAL MARINE FISHERIES SERVICE, JUNE 1982 MARYANN CARSON, BUDGET TECHNICIAN, ARMY CORPS OF ENGINEERS, PHILADELPHIA DISTRICT, JUNE 1982 REVISION0 APRIL 11, 1988 Ri::"FHEN(;[ 5 0 6 20 TH! '! MAP WA ~; i'-P:cP*Ht-*:, PUBLIC SERVICE ELECTRIC AND GAS COMPANY

                                        *G*:J~  PC"R: ~O:t*~S   *.*:.r i * ;.               MILES                                                   HOPE CREEK NUCLEAR GENERATING STATION 6 0  6     20 PORTSOF LANDINGFOR COMMERCIAL KlLOMETERS2                                                  AND RECREATIONAL         SALTWATER FISHINGWITHII'J0 TO 50 MILES UPDATEDFSAR                   FIGURE2.1-19
                                                                                 *-***------------------------------------------11...-----------------1

""----------------------------------------------------------------------------~

COMMERCIAL& RECREATIONAL FISHING& SHELLFISHING AREAS WITHIN0-80 KILOMETERS 1982

                                                                            ~    RECREATIONAL AND COMMERCIAL FISHING AND
                                                                            ~

SHELLFISHING AREAS SOURCES: TOWNSEND. R, GUIDE TO NEW JERSEY'S SALTWATER FISHING, OED, DIVISION OF FISH, GAME & SHELLFISHERIES, 1974 OAREL CHRISTIAN, CHIEF FISHERIES STATISTIC INVESTIGATION NE REGION, NATIONAL MARINE FISHERIES SERVICE, JUNE 1982 REVISION0

                                             ---=I REFERENCE             6 0   6        20                                                            APRIL: 11, 1988 THIS MAP WAS PREPARED FROM PORTIONS OF THE        MILES                                   PUBLIC SERVICE ELECTRIC AND GAS COMPANY FOLLOWINGSEC:TIOW\L                                                 HOPE CREEK NUCLEAR GENERATING STATION AERONAUTICAlCHAR1       5 0 5  -  20
                    "'EW vORl<

KILOMETERS COMMERCIALAND REACREATIONAL FISHINGAND SHELLFISHINGAREAS WITHIN0 TO 30 KM --YEAR 1982 UPDATEDFSAR FIGURE2.1-20

LOW POPULATIONZONE 1982

                                                                                                  --~             \
                                                                                                                '     \
                                                                                                                     /\                       DELAWARE            9
                                                                                                      '       /' \                                             420 423
                                                                                                        *~~::~';.,~~~"'              .                         424
                                                                                                           ~* ~     ~   ,..,.....             NEW JERSEY       ALLOWAY CREEK NECK ROAD
                                                                                                                          /'"""'*

RIVER DELAWARE RIVER

                                                                                                                                       ~ WILDLIFE AREAS

1. AUGUSTINE CREEK WILDLIFE AREA

2. REEDY ISLAND WILDLIFE REFUGE

3. APPOQUINIMINK WlLDLIFE AREA q, MAD HORSE CREEK WILDLIFE MANAGEMENT AREA

BEACH AREAS

5. AUGUSTINE BEACH

6. BAY VIEW BEACH SOURCE: NEW CASTLE COUNTY PLANNING BOARD. THE REO LION PLANNING DlSlRlCT PLAN. 1995. SEPTEMBER 1973 NEW CASTLE COUNTY PLANNING BOARD, THE MIDDLETOWN-ODESSA-TOWNSEND PLANNING DISTRICT PLAN, 1995, SEPTEMBER 1973 R. CHARTAWlCH. DEPT. OF PLANNING, NEW CASTLE COUNTY PLANNING BOARD, MAY 1982 C. WARREN, DEPT. OF LAND USE & POPULATION, SALEM COUNTY PL~NNJNG BOARD, APRIL 1982 U.S. DEPT. OF AGRICULTURE, SOUTH JERSEY RESOURCE CONSERVATION & DEVELOPMENT AREA PLAN, APRIL 1979 REVISION0 APRIL 11, 1988 0 1~--------------------------------~

PUBLIC SERVICE ElECTRIC AND GAS COMPANY MILES HOPE CREEK NUCLEAR GENERATING STATION

./~

0

                                                                            -----~~ ;~~                                                                                            LOW POPULATION      ZONE-KILOMETERS                                YEAR 1982
                                             ~y~~~~~~~~~~=----

.,l)t;:~ft~&?.~~"(r'::~- .. _*. -'* ' UPDATEDFSAR FIGURE2.1-21 L--------------------------------------------------------------------------------------*----------------------------------------------------------~----------------------------------~

POPULATION CENTERS WITHIN 0-30 MILES OF THE ARTIFICIAL ISLAND SITE

980 QJSTANCE! lll_RE r:T.l ~lN I, WILMINGTON, DE 70,195 ! 8. 3 m1 ! es ~~

2. VINELAND, NJ 53,753 25. 1 mll es E

3. NEWARK, DE 25,247 !7 . 8 m! J es NW SOURCE: 1980 CENSUS POPULATION& HOUSING CHARACTERISTIC2.

REV!SJON0 APRIL 11, 1988 REFERENCE 5 0 5 20 PUBLIC SERVICE ElECTRIC AND GAS COMPANY THIS MAP WAS PREP.'IREO HOPE CREE:K NUCLEAR GENERATING STATION FRQtl PORTIONS OF THf F::.;L LC.VVi"'G:-rc::.TiONAL 5 0 5 MilES

                                                                     ;20 r------------------------------

POPULATION CENTERSWITHIN AEFH)NAUTIC *.t CHARY

~~

KlLOWtt;TERS 0 TO 30 MILESOF ARTIFICIAL ISLANDS!TF-YEAR 1980 UPDATED FSAR FIGURE2.1-22 L---------------~------------~---------------------------------------------------------~-----------------

I .,

                                      ~ *'  ~

I I 1-0

                    -.9!....s:::

UJ I I I \ I UJ I l I CD I I 0 s::: 1 I ....0

                    *- 0                                 I   t It)

I I \ N

                     'S                    I 0..

cf I I l 1 I

                     ",...o
                     ..1!!

0 .-i N I' sj I I I CD .... ~ s...

                     £ ~l ~

I \ l

                    * - a! a

_o I N I I I \

I I'll I I

                                                                         \                             ~
                                                                           \~

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                                                                                                  -..e
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0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 C"1 ..... tO It) N (!UJi>sfetdoed) 4ssuea UO!+DJTldod REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION POPULATION DENSITY UPDATEDFSAR FIGURE2.1*23

2.2 NEARBY INDUSTRIAL, TRANSPORTATION, AND MILITARY FACILITIES All activities and facilities within 5 miles of the Hope Creek Generating Station (HCGS) site were considered. 2.2.1 Location and Routes No significant manufacturing and chemical plants, oil refineries, storage facilities, transportation routes other than the Delaware River, and gas pipelines are located within 5 miles of the HCGS site, as found in Reference 2.2-1. 2.2.2 Descriptions 2.2.2.1 Description of Facilities No manufacturing, industrial chemical plants, or storage facilities are located within 5 miles of the site. Nor are any military facilities located within 5 miles of the site. 2.2.2.2 Description of Products and Materials No significant amounts of hazardous or toxic products and materials are regularly stored, manufactured, used, or transported within 5 miles of the Hope Creek Generating Station except as noted in either Tables 2.2-4, 2.2-5, or 2.2-6. 2.2.2.3 Pipelines No pipelines are located within 5 miles of the HCGS site. 2.2.2.4 Waterways The intake structure for the HCGS site is located on the east bank of the Delaware River on Artificial Island approximately 1 mile east of the Intercoastal Waterway. The waterway has a width of 800 feet in the location of the HCGS site. 2.2-1 HCGS-UFSAR Revision 5 May 11, 1993

The predominant types of river traffic are barges and freighters with a maximum draft range of 31 to 41 feet. The Delaware River hydrographic chart indicates an anchorage zone northwest of Artificial Island. According to the U.S. Coast Guard's Safety Division, this is the only area within the vicinity of the HCGS site used for the anchorage of vessels carrying explosives. It has not been used in recent years. 2.2.2.5 Airports 2.2.2.5.1 Private Airports There are three privately owned airports within approximately 10 miles of the site, as shown on Figure 2.2-1. The Evergreen Airport is located approximately 5 miles west-northwest of the site. It has a 1400 foot grass runway, which is open only for emergency landings by small fixed-wing civil aircraft. Salem Airport is located approximately 8 miles northeast of the site and has a 2200 foot grass runway. The airport owner operates a small agricultural spraying and dusting business. He also provides tie-down facilities for several privately owned and operated small fixed wing aircraft, as noted in Reference 2.2-3. A visual inspection revealed that neither the based aircraft nor the runway were in frequent use. Summit Airport is located approximately 10 miles west-northwest of the site. It has a 4500-foot hard surfaced runway, 17/35 oriented 350°-170° 6 magnetic, with lighting for nighttime operations and a perpendicular 3500-foot grass runway. There is a UNICOM (radio) available for aeronautical advisories, as noted in Reference 2.2-4. There are approximately 70 aircraft based at Summit Airport. The operators of these aircraft, including a company called Charter Service, may conduct a combined total of 72 operations (36 flights} 2.2-2 HCGS-UFSAR Revision 0 April 11, 1988

per day. This number also includes the average 16 flights per day reported by Summit Aviation, which conducts a flight training school on the airport, Reference 2.2-4. The inflight local training area for Summit Airport is west of U.S. Route 13. This boundary is approximately 6 miles west of the site and is vigorously enforced, in that to conduct any inflight training further east could interfere with aircraft on an extended final approach to runway 01 at the Greater Wilmington Airport and create potential mid-air collisions, References 2.2-4 and 2.2*5. There are no current plans for a major expansion of Summit Airport. However, there are normal maintenance programs and Charter Service is planning to increase operations. It is not anticipated that this would increase the overall number of operations by more than an additional 10 flights per day, Reference 2.2-4. The total is estimated to be approximately 35,000 operations per year. There are no plans for construction of new runways or sufficient expansion of operations at these three private airports to cause, or contribute to, any hazard at the HCGS. Therefore, these airports will not be discussed further. PSE&G plans approximately 700 annual operations at the helicopter landing pad located onsite. These helicopter operations are discussed further in Section 3.5.1.6. 2.2.2.5.2 Commercial Airports Greater Wilmington Airport is the nearest commercial airport, located approximately 14 miles north-northwest of the plant site, see Figure 2.2-1. There are three crossing runways: runway 09/27 is 7165 feet long, 150 feet wide, and is oriented 088° and 2680 magnetic; runway 14/32 is 5004 feet long, 150 feet wide, and is oriented 141° and 3210 magnetic; and the primary instrument approach runway is 01/19, is 7002 feet long, 200 feet wide, and is oriented 0150 and 1950 magnetic, Reference 2.2-6. 2.2-3 HCGS-UFSAR Revision 0 April 11, 1988

There were 205,000 total operations at Greater Wilmington Airport in 1977. Reference 2. 2-7. Based on this number and Department of Transportation predictions through 1992, Reference 2. 2-7, the Greater Wilmington Airport local and itinerant operations will be discussed further in Section 3.5.1.6, even though the total number of operations during 1978 through 1981 have declined, Reference 2.2-8. 2.2.2.5.3 Airways The VOR(V) airways service the low level air navigation structure. The V airways are 8 nautical miles wide (4. 6 statute miles either side of center line), and extend from the minimum enroute altitudes up to but not including 18,000 feet mean sea level (MSL), Reference 2.2-6. There are two low level V airways with centerline& that pass within approximately 7 miles of the site (see Figure 2.2-2). Airway Vl23-312 passes within 1 mile to the northwest, over the northern portion of Artificial Island. Airway V29-157 passes approximately 2 miles west of the site. Jet routes (J) service the high level air navigation structure. The J airways are 10 nautical miles wide (5.7 statute miles either side of centerline), and extend from 18,000 feet up through 45,000 feet MSL, Reference 2.2-6. The airspace structure above 45,000 feet contains no airways or predetermined routes. There is one high level airway Jl50, which is directly above Vl23-312, and also passes within 1 mile of the plant, as shown on Figure 2.2-3. Because Jl50 is directly above Vl23-312, the number of aircraft operations on the two airways are combined. The number of operations on airways Vl23-312/Jl50 and V29-157 are considered in the next section and is discussed further in Section 3.5.1.6. 2.2-4 HCGS-UFSAR Revision 0 April 11, 1988

2.2.2.5.4 Itinerant, Federal Aviation Administration-controlled Overflights The Philadelphia Terminal Radar Approach Control (TRACON) controls all traffic under instrument flight rules (IFR) below 9000 feet, Reference 2.2-9, in the Philadelphia area, which includes the Greater Wilmington Airport. The Philadelphia TRACON provided flight strips which covered four days (96 hours) of operations, three weekdays, July 18, 19, and 21, and one weekend day, August 2, 1982, Reference 2.2-10. The flight strips were sorted to determine the total number of flights using each of the airways V123-312 and V29-157 and/or radio navigational fix-stations or radiale that would overfly the HCGS site during the course of an arrival or departure route to any airport in the Philadelphia area. The weekday flight strips were averaged and multiplied by 261, the weekend number averaged and multiplied by 104, and the totals added. This results in an estimated annual number of 3000 operations below 9000 feet altitude for V123-312, and 16,000 operations below 9000 feet for V29-157, see Table 2.2-2, columns one and three. The transition from Washington Air Route Traffic Control Center (ARTCC) to the New York ARTCC takes place in the airspace near the plant and varies with the assigned altitude of the aircraft traffic. All traffic above 9000 feet on Vl23-312, JlSO and V29-157 is controlled by either Washington or New York ARTCC. To determine an estimate of the annual aircraft activity on the airways in the vicinity of Hope Creek, flight strips were obtained from both ARTCCe. The flight strips obtained from New York ARTCC covered five weekdays of operation, September 2 and 3, 1982 and September 6, 7, and 8, 1982. The flight stripe obtained from washington ARTCC covered eight days of operation, August 30, through September 5, and september 7, 1982, which included the Labor Day weekend. For each day, both sets of flight strips were sorted and tabulated according to the applicable airway and aircraft classification (air carrier, commuter air carrier and on-demand air taxi, general aviation small fixed wing, and military). Since there was no variance between the weekday count and the weekend count, the total annual number of 2.2-5 BCGS-UFSAR Revision 0 April 11, 1988

operations was determined by multiplying the average daily count for each set by 365 days/year and summing the total count from each set. The number of operations on these airways, as tracked by the New York and Washington ARTCCs, are shown in Table 2.2-2, columns two and four, and discussed further in Section 3.5.1.6. 2.2.2.5.5 Military Routes and Traffic Patterns There are four military low level, slow speed, low altitude training routes, 844, 845, 846 and 847, in the area, see Reference 2.2-6 and Figure 2.2-4. These routes pass approximately 7 miles, NE, E, and SE of the site. The routes are flown in C-130 (four-turboprop engine) type aircraft by crews from the u.s. Air National Guard, 166th Tactical Airlift Group (TAG) stationed at Greater Wilmington Airport, New Castle, Delaware. These routes are open for training by any military organization but are controlled by, and used primarily by, the 166th TAG. The minimum altitude is 500 feet above ground level (AGL) for day and 1400 feet AGL for night operations. The ceiling, or maximum altitude for the routes, is 1500 feet AGL. The routes are flown approximately 200 times a year as a portion of a particular mission to train for, and test, combat readiness, Reference 2.2-11. The routes, as well as the entries and departures, are planned to avoid flying within 5 nautical miles (5. 7 statute miles) of the site, References 2.2-6 and 2.2-11. u.s. Air Force Regulation 60-16 also restricts flight over any nuclear plant to 2000 feet vertically and 3 nautical miles horizontally. The combination of the number of operations (200 per year), the route distance from the site (7 miles), the altitudes at which the aircraft are flown on these routes (500 to 1500 feet}, and the highly reliable four-turboprop engine type aircraft, makes it extremely unlikely that this military operation poses any potential hazard to BCGS. Therefore, the four military low level, slow speed, low-altitude training routes will not be considered further. The 166th TAG practices approximately 200 local airborne radar 2.2-6 BCGS-UFSAR Revision 8* September 25, 1996

approaches (ARA) to runway 01 at Greater Wilmington Airport. This approach, controlled by the FAA and conducted only in VFR weather conditions, passes within one mile of the HCGS site, Reference 2.2*11. The 200 total number of operations is shown in Table 2.2*2, column five, and is discussed further in Section 3 . 5 .1. 6 . 2.2.2.5.6 HCGS Site Helicopter Pad/Operations Public Service Electric and Gas Company plans to fly a company owned helicopter to the HCGS site helipad approximately seven times a week, Reference 2.2-12. These flights will be controlled by the FAA, and approaches will be under visual flight rules (VFR) conditions. Helicopter VFR minimums are lower than fixed wing VFR minimum criteria. This average number of 700 annual operations (7x2x50 weeks) is shown in Table 2.2-2, column five, and is discussed further in Section 3.5.1.6. 2.2.2.5.7 Local VFR Over Flights A radar survey was conducted from the Philadelphia Approach Control to determine the frequency of VFR flights within 5 miles of the HCGS site. The radar scope upper and lower altitude limits were set at 10,000 feet and 300 feet. Ten thousand feet was the upper limit, because these type aircraft normally do not have pressurized cabins and/or oxygen that would enable them to be flown at higher altitudes. The lower limit was set at 300 feet because the permanent ground returns at a lower setting would clutter the scope and preclude a count, and because even the aost novice private aviator does not fly at altitudes below 500 feet except to perform specific proficiency training maneuvers. The radar survey was conducted over a 3*day period. The weather was VFR-clear with good visibility on Thursday, August 5, 1982. From 4:00 to 7:00 p.m. , there were no VFR operations observed within 5 miles of the site. On Friday, August 6, 1982, the weather was VFR, but there were some clouds at 2000 feet and the visibility was 2.2-7. HCGS-UFSAR. Revision 0 April 11, 1988

estimated at 5 miles. There was one VFR aircraft observed approximately 1 to 2 miles from the site between the hours of 9:00 a.m. and 7:30 p.m. On Saturday, August 7, 1982, the weather was VFR-clear with unlimited visibility. Between 8:00 a.m. and 2:00p.m., 14 VFR aircraft were observed. Even though HCGS is in a fairly remote location, as shown on Figure 2.2-1, the number of VFR flights observed within a S*mile area of the HCGS site during the survey, multiplied by the respective weekdays and weekend days, produced an estimate of 1700 annual operations, shown in Table 2.2-3. These operations are given further consideration in Section 3.5.1.6. 2.2.2.6 Projections of In4ustrial Growth Most of the area within 5 miles of the HCGS site lacks the infrastructure to support new industrial growth, as noted in Reference 2.2-1. Additionally, New Jersey and Delaware coastal protection legislation limits development in wetland areas. Much of the area within 5 miles of the site is wetland area within which industrial development is prohibited. No significant changes from the past trends in the waterborne commerce and industry in the Delaware River are expected according to discussions with the U.S. Army Corps of Engineers, Philadelphia District, Reference 2.2*2. 2.2.3 Evaluation of Potential Accidents This section provides an evaluation of potential accidents in nearby transportation and industrial facilities to determine what events need to be considered in the plant design. A description of design features to mitigate such events is also provided. 2.2.3.1 Determination of Desicn Basis Eyents The information presented in Sections 2.2.1 and 2.2.2 shows that the 2.2-8 HCGS-UFSAR Revision 0 April 11, 1988

Security-Related Information - Withheld Under 10 CFR 2.390 Hope Creek Generating Station (HCGS) Artificial Island site is located in a rural area consisting of marshes, meadowlands, and some farmland. There are no major manufacturing or chemical plants within 5 miles of the site. All such facilities are beyond 8 miles and would not interfere with the operation of HCGS. There are no military bases or missile sites within 10 miles of the site. There are no pipelines within 10 miles of the site. There are no major harbors, railway yards, or airports within 10 miles of the site. The only harbor facility of any significance is Getty Oil Company pipeline terminal in Delaware City, 9 miles north-northwest of the site. There are no railroads within 5 miles of the site.

There are no petroleum wells, mines, or hard rock quarries within 10 miles of the site.

Reference 2.2-14 contains the details of these findings. Based on the above information, it is concluded that the only events that could have an impact on the safety of HCGS relate to

2.2-9 HCGS-UFSAR Revision 8 September 25, 1996

Security-Related Information - Withheld Under 10 CFR 2.390

The estimates of probability of various accidents presented in this section were developed in accordance with the following steps:

1. The traffic history along the Delaware was established by using data from the U.S. Army Corps of Engineers, (Waterborne Commerce of the United States Data Base), the Philadelphia Maritime Exchange, the U.S. Coast Guard, and Poten and Partners, References 2.2-13, 2.2-14, and 2.2-15.

2. The probability of occurrence of a collision of sufficient severity to cause a major release of several types of cargo was estimated using the U.S. Coast Guard accident records, worldwide tanker experience, and a simplified statistic model, References 2.2-13 and 2.2-14.

3. For each major type of cargo, the distance to the plant within which the accident could pose a threat was estimated, References 2.2-13 and 2.2-14.

4. The probability of each type of cargo presenting a potential threat to plant safety was determined, References 2.2-13 and 2.2-14.

In evaluating the many estimates of the probability of potential impact, several simplifications and assumptions were made. However, the simplifications and assumptions were made in a conservative fashion so as not to underestimate the probability of occurrence of 2.2-10 HCGS-UFSAR Revision 0 April 11, 1988

Security-Related Information - Withheld Under 10 CFR 2.390 various events of concern. The probability of potential impact to HCGS associated with the hazards from the SGS site are those relating to flammable liquid, corrosive liquid, flammable and toxic vapor dispersion, and liquid spills. Because of the land based nature of the chemical storage operation, only accidental spills on land are of concern, and ingestion of chemicals in the water intakes is not an issue. The spills on land were analyzed to determine if they presented any potential threat to the occupancy of the HCGS control room. 2.2.3.1.1 Explosions

2.2-11 HCGS-UFSAR Revision 0 April 11, 1988

Security-Related Information - Withheld Under 10 CFR 2.390

2.2-12 HCGS-UFSAR Revision 17 June 23, 2009

Security-Related Information - Withheld Under 10 CFR 2.390 2.2.3.1.3 Toxic Chemicals Accidents involving the release of toxic chemicals from outside storage facilities and nearby mobile and stationary sources were considered. Regulatory Guide 1.78, Position C.2, states that hazardous chemicals such as those indicated in Table C-1 of the guide must be included in the analyses if they are frequently shipped within a 5-mile radius of the plant. The guide also defines frequent shipments as 50 or more trips per year for barge traffic and specifies, in Position C.1, that chemicals stored or situated at distances greater than 5 miles from the facility need not be considered. Table 2.2-4 shows the chemicals stored at the adjacent SGS site. Table 2.2-5 shows estimates of hazardous chemical traffic in the vicinity of HCGS. An analysis of the SGS control room habitability, Reference 2.2-16, performed for a postulated hazardous chemical release occurring at the SGS site or within a 5-mile radius of the station demonstrated that the SGS control room personnel are adequately protected against the effects of accidental release of toxic gases. Due to the use of a sodium hypochloride biocide system at SGS, there is no onsite chlorine hazard.

Calculations of the concentration of sulfuric acid and nitrogen that could reach the SGS control room air intakes show that they are well below the toxicity limits given in Table C-1 of Regulatory Guide 1.78. Calculations pertaining to the ammonia concentration that could reach the HCGS Control Room resulting from a postulated ammonium hydroxide release at SGS show that sufficient time exists for the control room personnel to take corrective actions to prevent exceeding the toxicity limit listed in Table C-1 of Regulatory Guide 1.78. Hydrazine stored at the SGS will not impact the HCGS control room as determined from calculations due to its low release rate and relatively small storage quantity. The 2.2-13 HCGS-UFSAR Revision 13 November 14, 2003

physical properties of sodium hydroxide preclude the formation of a plume and impacting the HCGS control room. It has a very low vapor pressure, and upon a release, mostly water will evaporate from the spill. Helium is stored in relatively small containers at the SGS. Upon a release, it will rapidly disperse and not pose a hazard to the HCGS control room. It is therefore clear that these chemicals will affect even less the HCGS main control room, since it is located further away from the source of any potential spill than the SGS control room. There are several chemicals stored onsite at HCGS, as shown in Table 2.2-6. The effects of accidents involving these chemicals on the HCGS control room were studied, Reference 2.2-14. The study demonstrated that such accidents will not adversely affect the habitability of the control room, since even under the worst conditions it was not possible to generate unacceptable concentration of the chemicals of concern at the HCGS control room air intakes. Table 2.2-6 also lists Purate, which was evaluated and does not pose a control room hazard. Chlorine dioxide (dissolved in Circulating Water) is produced by the Purate System in a structure near the Hope Creek Station cooling tower. Evaluations concluded that the control room would remain habitable during a postulated chlorine dioxide release at the Purate System structure. Table 2.2-5 shows that the mobile sources of hazardous chemicals shipped on the Delaware River are below the "frequent" criteria of Regulatory Guide 1.78, and are not required to be evaluated for impact on control room habitability due to the probability of such an accident. Hazardous chemicals are also delivered to the HCGS and the SGS. Table 2.2-5 lists the shipments of hazardous chemicals to and near the Generating Stations. A review of the shipment deliveries were 2.2-14 HCGS-UFSAR Revision 25 November 15, 2021

compared to the "frequent" shipment criteria as stated in Regulatory Guide 1.78. Aqueous sodium hydroxide, sodium hypochlorite, and ammonium bisulfite shipments are considered "frequent". As mentioned previously, a release of either sodium hydroxide or sodium hypochlorite will not impact the control room due to the physical properties of these chemicals. Ammonium bisulfite is also characterized as a chemical that will not readily evaporate and form a plume during a release due to its very low volatility. Therefore, a catastrophic failure of the tankers delivering these hazardous chemicals onsite will not impact control room habitability. Ammonium hydroxide and sulfuric acid shipments delivered onsite also require an evaluation of their impact on control room habitability at the HCGS since their delivery schedule exceeds the criteria in Regulatory Guide 1.78. Calculations conclude that a release of ammonium hydroxide while onsite will not impact control room habitability at the HCGS. Also, calculations regarding the delivery of sulfuric acid to the SGS demonstrate that the control room will not be impacted during a catastrophic failure. A more detailed analysis of the control room habitability is provided in Section 6.4. 2.2-14a HCGS-UFSAR Revision 5 May 11, 1993

THIS PAGE INTENTIONALLY RLANK 2.2-14b HCGS-UFSAR Revision 5 May 11, 1993

2.2.3.1.4 Fires In addition to the flammable vapor clouds discussed earlier, events onsite and offsite that could lead to fires were evaluated. The offsite events relate to releases of flammable liquids from barge and ship traffic on the Delaware River. A pool fire as a result of a barge or ship accident would present a potential threat only to the water intakes, and only if the fire involved more than five million gallons of gasoline or oil. There have been very few tanker related spills of flammable material where cargo in excess of 5 million gallons was released, as mentioned in References 2.2-19 and 2.2~14. In the limited number of such spills that have occurred on a worldwide basis, there is no record of the spill having ignited. In attempting to determine the probability of ignition of a spill given a release of over 5 million gallons, discussions were held with several officers of the U.S. Coast Guard. The consensus was that the probability of ignition for such cases was under 5 percent as discussed in Reference 2. 2-20. The probability of a fire, due to flammable material shipping, presenting a potential threat to HCGS was calculated taking into account the number of annual barge and tanker trips, the number of accidents per mile of trip, catchment distances, spills per accident, and the probability of ignition when a spill occurs. These calculations show that the risk of a large fire occurring at the water intake is in the order of 10*8 occurrences per year as mentioned in References 2.2-13,

2. 2-14, and 2. 2-20. Therefore, these fires do not have to be considered as DBEs.

Onsite events that could lead to fires are the release and ignition of the chemicals stored onsite and the release and ignition during their periodic resupply. Table 2.2-6 shows the chemicals stored at the HCGS site. An analysis of the potential for fires due to these chemicals and their periodic resupply method shows that these fires would be far too small in size and duration to affect the safety of the plant, and as such, do not have to be considered as DBEs, Reference 2.2-14. 2.2-15 HCGS-UFSAR Revision 0 April 11, 1988

2.2.3.1.5 Collisions With Intake Structure Since the HCGS site is located near a navigable waterway, the probability and potential effects of collision impact of a ship or barge on the plant cooling water intake structure were considered. The size of the ships that could conceivably work their way to the river bank and ram into the water intake structure is limited by water depth and tidal conditions. Under normal tidal range, ships in excess of approximately 15,000 tons would likely ground on the shallow shoal areas outside the river channels before reaching the intake structure. Under extreme tidal conditions, however, such as the design high water level corresponding to hurricane conditions, the largest ships transiting the Delaware could reach the intake without grounding, as discussed in References 2.2-14 and 2.2-21. The kinetic energy levels associated with the postulated rammings have been determined to be of the same order of magnitude as those from major collisions, as discussed in Reference 2.2-22. From ship collision studies, however, it can be argued that the expected structural damage from ship ramm~ngs of the intake structure will be mostly damage to the ship structure, and furthermore, that the damage will not be extensive enough to block the intake with structural rubble, as discussed in Reference 2.2-21. A further qualitative comparison of the seismic design input and the inertial loadings of the intake structure and its components caused by rammings indicate that the intake structure will suffer only local damage from the ramming accident. Its integrity would be maintained and equipment located inside would remain operable. Our analysis in References 2.2-14 and 2.2-22 concluded that blockage of the intake structure opening by a runaway ship or barge is not possible. Under the most extreme low water conditions assumed in the design of the facility, consideration of the main intake area showed that the blockage to cause cavitating flow (97 percent of the area in the extreme low water condition) could not be accomplished by a conventional vessel with hull curvature, nor by any barge currently transiting the Delaware River near Artificial Island site, 2.2-16 HCGS-UFSAR Revision 0 April 11, 1988

Reference 2.2-14. The most recent river bathymetry and National Oceanic and Atmospheric Administration charts were reviewed and it was determined that a smaller 2,000-ton displacement ship with a draft of 12 ft would be grounded 400 ft before it reached the intake structure. It was reconfirmed that the major damage would occur to the impacting vessel rather than to the intake structure. on the basis of past historical collision data on the Delaware River, the probability of a ship or barge impacting the intake structure during normal water

                         -7 levels is less than 10    per year.

Therefore, collisions with the intake structure do not have to be considered as DBEs for the BCGS site. 2.2.3.1.6 Liquid Spills The accidental release of oil or liquids that may be corrosive, cryogenic, or coagulant was considered to determine if the ~otential exists for such liquids to be drawn into the plant intake structure and circulating water systems, or to affect the plant's safe operation. Petroleum, oil products and cryogens floating on the Delaware River surface could approach the intake structure due to a spill upstream. The water intake itself occurs several feet under water, so these materials are excluded from entry into the service water supply line, even if the materials get past the intake surface ~. skimmers. The most severe possible condition occurs at the design low water level condition, with water surface at plant elevation 76 feet. At this level, the service water pump intake is still submerged by 4 feet. In addition, Hope Creek Technical Specifications require a plant shutdown when river water level reaches 80 feet PSE&G datum. Thus, floating liquid spills do not have to be considered as OBEs for the HCGS site. There are no known coagulants shipped on the Delaware River, and the only corrosive of potential concern is sulfuric acid. As discussed in Section 2.2.3.1.3 and in Reference 2.2-14, the probability of ingesting unacceptable

                                                                -9 concentrations of sulfuric acid is estimated to be about 10      occurrences per year. As a result, these types of 2.2-17 HCGS-UFSAR                                                    Revision 9 June 13, 1998

liquid spills do not have to be considered as design basis events for the HCGS site. 2.2.3.2 Effects of Design Basis Events From the foregoing discussion, it can be seen that no events arLsLng from nearby industrial activities were identified as DBEs. The plant's safety-related components are designed to withstand the effects of potential accidents without endangering the health and safety of the public. 2.2.4 References 2.2-1 Personal communication with: R. Chartawich, New castle county Department of Planning, May 20, 1982.

c. Warren, Salem County Department of Planning, May, 20, 1982.

2.2-2 Personal communication with:

o. Chistian, National Marine Fisheries Service, June 21, 1982.

M. Carson, u.s. Army Corps of Engineers, Philadelphia District, June 21, 1982. 2.2-3 Personal communication with: Elmer Grieves, August 2, 1982. (A drive-by visual inspection was conducted on August 6, 1982). 2.2-4 Personal communication with: Edmund, M. Conaway, Summit Aviation, and K.J. Toth, NUS corporation, letter dated August 31, 1982. 2.2-18 HCGS-UFSAR Revision 0 April 11, 1988

2.2-5 Personal communication with: Summit Flight School chief flight instructor, August 6, 1982. 2.2-6 The Defense Mapping Agency Aerospace Center, "United States Government Flight Information Publications (FLIP)," June 1982. 2.2-7 T. F. Henry, Terminal Area Forecast, Department of Transportation, Federal Aviation Administration, FAA-APD-80-10, February 1981. 2.2-8 c. Zimmerman, PSE&G, to R.P. Douglas, PSE&G, Aircraft Hazard Analysis Data, memorandum dated February 25, 1982. 2.2-9 Personal communication with: M. Isaacson, FAA, New York ARTCC, and K.J. Toth, NUS Corporation, letter dated August 31, 1982. 2.2-10 FAA, Terminal Radar Approach Control (TRACON) Flight Strips, 7/18/82, 7/19/82, 7/21/82, and 8/2/82 from John Furlong, Philadelphia TRACON. 2.2-11 Personal communication with: J. Lanahan Lt. Col. USAF Reserve, 166th Tactical Airlift Group, and K.J. Toth, NUS Corporation, letter dated September 3, 1982. 2.2-12 Personal communication with; J. James, PSE&G pilot, and K.J. Toth, NUS Corporation, letter dated September 13, 1982. 2.2-13 salem Generating station FSAR, July 1982, p. 2.2-5. 2.2-19 HCGS-UFSAR Revision 0 April 11, 1988

2.2-14 "An Update on the Analysis of Potential Effects of Waterborne Traffic on the Safety of the control Room and Water Intakes at Hope Creek Generating Station," A.D. Little, Inc., March 1983. .2 * .2-15 Poten and Partners, Inc, "Summary of Gas Ships Transiting the Delaware River," reports to PSE&G, February 1982. 2.2-16 "Control Room Habitability Analysis," NRC Docket No. 50-311, Salam Generating Station, July 1, 1980. 2.2-17 A.D. Little, Inc, "Analysis of Potential Effects of Waterborne Traffic on the Safety of the control Room and Water Intakes at Hope Creek Generating Station," September 1974, p. 6. 2.2-18 Ibid, p. 7. 2.2-19 Ibid, pp. 3, 5. 2.2-20 Ibid, p. 5. 2.2-21 Ibid, p. 7, 8. 2.2-22 Ibid, P* 8. 2.2-23 u.s. Coast Guard, vessel Chemical Traffic Report, "Hazardous Traffic l Passing Salem and Hope Creek Stations," dated July 15, 1993. 2.2-.20 HCGS-UFSAR Revision 8 September 25, 1996

TABLE 2.2-1 NUMBER OF OPERATIONS AT GREATER WILMINGTON AIRPORT Total Total Year Operations(l) 0perations( 2 } ACTUAL ACTUAL 1976 171,000 186,586 1977 205,000 202,242 1978 184,000 190,767 1979 176,000 171,497 FORECAST 1980 177,002 1981 190,000 155,024 1982 196,000 1983 203,000 1984 209,000 1985 216,000 1986 223,000 1987 230,000 1988 237,000 1989 245,000 1990 253,000 1991 261,000 1992 270,000 (1) From FAA Terminal Area Forecasts 1981-1982, Reference 2.2-7 (2) From Andrew Nonnenmacher, FAA Facility Chief at the Greater Wilmington Airport, Reference 2.2-8 1 of 1 HCGS*UFSAR Revision 0 April 11, 1988

TABLE 2.2-2 NUMBER OF OPBRATIOOS OVER 'l1IE11008 SITE ITINmANT FAA (X)N'J'R()LLEO OV'Im FLIGHTS IF'R-<Dl'lDJLLED VFR-OON'I.BJLLED V123-312 V123-312 & Jl50 V29-157 V29-157 Philadelphia Washington & NewYork Philadelphia Washington a. New York TRA~(l) ARTCX:i(2) '.lRA(X)N ARTCX:i Traffic Pattern Catego!Z of Aircraft Below 9000 ft Above 9000 ft Below 9000 ft Above 9000 ft Within 5 Miles SFW-GA, single-engine 610 1551 4500 460 SFW-GA, multi-engine 200 4650 1500 1400

(<12,500 lb) Air taxi/catmUter/on-demand 1900 1820 7020 1820 (>12,500 lb) Air carrier 180 116,000 1600 1460 (>12,500 lb) Military 100 1460 1000 700 200 (ARA) (S) Helicopter

                                                                                     --   -         -- -                  700 (PSB&G)

Totals 3000 125,481 15,620 5840 ( 1) Terminal RadarApproach Control. (2) Air Route Traffic Control Center. ( 3) Airborne RadarApproaches. 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 2.2-3 NUMBER OF OPERATIONS OVER THE HCGS SITE VFR OBSERVED ON RADAR FROM PHILADELPHIA APPROACH CONTROL Period Witbin 1 Mile 1-2 Miles 2-3 Miles 3-5 Miles (Thur) 8/5/82 4:00-6:30 p.m. 0 0 0 0 (Fri) 8/6/82 9:45*11:59 a.m. 0 0 0 0 12:00-4:59 p.m. 0 1 0 0 5:00-7:00 p.m. 0 0 0 0 0 i 0 0

                                    *xlli 261 (Sat) 8/7/82 VFR 8:00-10:59 a.m.           0             0           1           0 11:00-12:59 p.m.          1             1           0           6 1:00-2:00 p.m.            1         ____a_          1           1 2             3           2           7 x104         ~          ~             ~

200 ill .2.QQ. 12Q. Totals 200 575 200 700

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.2-4 SECURITY-RELATED INFORMATION WITHHELD UNDER 10 CFR 2.390 1 of 1 HCGS-UFSAR Revision 13 November 14, 2003

TABLE 2.2-5 SECURITY-RELATED INFORMATION WITHHELD UNDER 10 CFR 2.309 1 of 2 HCGS-UFSAR Revision 8 September 25, 1996

TABLE 2.2-5 (Cont) SECURITY-RELATED INFORMATION WITHHELD UNDER 10 CFR 2.309 2 of 2 HCGS-UFSAR Revision 25 November 15, 2021

TABLE 2.2-6 CHEMICALS STORED AT HOPE CREEK SITE(2) SECURITY-RELATED INFORMATION WITHHELD UNDER 10 CFR 2.309 1 of 1 HCGS-UFSAR Revision 25 November 15, 2021

Legend:

Commercial/Military Controlled Airports A Civil/Private Uncontrolled Airports

                     .N REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Kilometers                  HOPE CREEK NUCLEAR GENERATING STATION 10         0    5     10 Statute Miles 10               0        5     10             SITEMAPWITHAIRPORTS Nautical Miles 10                 0          5     10 UPDATEDFSAR                 FIGURE2.2*1

REVISION0 APRIL 11. 1988 N PUBLIC SERVICE ELECTRIC AND GAS COMPANY Kilometers HOPE CREEK NUCLEAR GENERATING STATION 10 0 5 10 Statute Miles 10 0 5 10 LOW LEVELAIRWAYS Nautical Miles NEARTHESITE 10 0 5 10 UPDATEDFSAR FIGURE2.2-2

REVISION 0 APRIL' 11. 1988 N PUBLIC SERVICE ELECTRIC AND GAS COMPANY Kilometers HOPE CRI;EK NUCLEAR GENERATING STATION 10 0 5 10 Statute Miles 10 0 5 10 HIGHLEVELAIRWAY NauticalMiles NEARTHESITE 10 0 5 10 UPDATEDFSAR FIGURE2.2*3

              .                                                   REVISION 0 APRIL 11, 1988 N

PUBLIC SERVICE ELECTRIC AND GAS COMPANY Kilometers HOPE CREEK NUCLEAR GENERATING STATION 10 0 5 10 Statute Miles 10 0 5 10 MILITARY LOW LEVELROUTES Nautical Miles NEARTHESITE 10 0 5 10 UPDATED FSAR FIGURE2.2-4

2.3 METEOROLOGY 2.3.1 Regional Climatology 2.3.1.1 General Climate Based on the Koeppen Climatic Classification System, the region intersects two climatic zones: humid continental and humid subtropical. Both zones have characteristics of warm summers and mild winters (Reference 2.3-1). Maximum summer average temperatures are near 80°F, and. the coldest month is January with an average daily temperature of approximately 32°F. Examining a 30-year mean of precipitation amounts for Wilmington, Delaware National Weather Service (NW'S) station shows that the most rainfall occurs in the summer months, followed by spring, fall, and winter (Reference 2.3-2). Southern New Jersey is frequented by Polar Canadian air masses in the fall and winter and occasionally invaded by Arctic Canadian air late in winter. During the spring and summer, the dominant air mass is Maritime Tropical according to (Reference 2.3-l). 2.3.1.1.1 Precipitation The frequency of precipitation events such as rain, snow, ice storms, thunderstorms, and hail are listed in Table 2.3-1. The data in Table 2. 3 *1 were obtained from the Revised Uniform Summary of Surface Weather Observations, from Dover (Delaware) Air Force Base, during 1942 to 1965. The snowfall data presented in Tables 2.3-2 and 2.3-3 were obtained from Philadelphia International Airport and Trenton Airport, respectively. 2.3-1 HCGS-UFSAR Revision 0 April 11, 1988

2.3.1.1.2 Humidity, Winds Humidity annually averages 70 percent, according to Reference 2.3-3. Prevailing winds on a monthly average during the winter (December through March) are from a northwest direction with a range of speeds from 9 to 13 mph. Average monthly winds for the spring and summer months (April through August) are from a southerly to southwesterly direction at speeds ranging from 7 to 10 mph. Winds during the fall are predominantly from the west-southwest veering to a west-northwest direction by December. The average wind speeds are higher during the winter months, as discussed in Reference 2.3-3. 2.3.1.2 Reeional Meteoroloeical Conditions for Design and O:Qeratin& Bases 2.3.1.2.1 Seasonal and Annual Frequencies of Severe Weather Severe weather is any destructive storm, such as tropical cyclones (hurricanes), tornadoes, waterspouts, thunderstorms, hail, and freezing rain or ice storms. The frequency and severity of these storms in the region surrounding Hope Creek have been assessed in the following sections. 2.3.1.2.1.1 Tropical Cyclones Tropical cyclones originate over the tropical waters of the Atlantic Ocean, the Caribbean, and the Gulf of Mexico during early summer through fall. The most intense form is called a hurricane, which has wind speeds greater than 73 mph; however, other less destructive stages can exist. These are known as tropical depressions and tropical storms. The remnants of these cyclones, which dissipate over land, often become extratropical cyclones. Reference 2. 3-4 shows that from 1899 through 1980, 12 extratropical cyclones, 8 tropical storms, and no hurricanes passed through the region. The average annual frequency of destructive tropical cyclones is less than 0.2 (less than 10 storms per 55 years), according to Reference 2.3-5. 2.3-2 HCGS-UFSAR Revision 0 April 11, 1988

The region is fairly well shielded from the most destructive forces of tropical cyclones, since it is not located directly on the Atlantic Coast. In fact, no hurricanes have been documented as having entered the state of Delaware directly from the Atlantic Coast, as shown in Reference 2.3-6. 2.3.1.2.1.2 Tornadoes Tornadoes, although infrequent, do occur in the region, primarily during the spring and summer. Summaries prepared by Pearson, noted in Reference 2.3*7, indicate that there were 108 tornadoes reported within a 2°-latitude-by*2°-longitude area centered on the site during the period 1950 through 1981. This 2° by 2° area represents approximately 15,000 square miles. Of these 108 tornadoes, none had an estimated Fujita-Pearson force scale exceeding F3, 206 mph. The closest reported tornado came within 10 miles of the site on July 1, 1954, across the Delaware River in Delaware. This tornado had a path area of 0.03 square miles. Using the statistical methods of Thorn, noted in Reference 2.3-8, the probability of a tornado striking any given point in the one degree latitude*longitude square centered on the Hope Creek site is once in every 10,229 years. This probability estimate is based upon a frequency of 1. 4 tornadoes/year in the one degree square. The annual frequency of tornadoes was obtained from Pearson's summary, which showed that 44 tornadoes, of which three had multiple touchdowns , occurred in the one degree latitude *longitude square encompassing the site. The average path area for these 44 tornadoes was 0.26 square miles. HCGS-UFSAR Revision 0 April 11, 1988

2.3.1.2.1.3 Waterspouts Golden states in Reference 2.3-9, that a waterspout is an intense columnar vortex of limited horizontal extent, existing over a body of water, but not necessarily containing a funnel cloud. The basic differences between tornadoes and waterspouts are that tornadoes are generally more intense, larger, and longer lived. The data on waterspouts is limited and concentrates on events occurring in the vicinity of the Florida Keys. Several studies on their size, duration, intensity, associated phenomena and effects have been made in the Keys area, yet little information is available to relate these storms to those occurring elsewhere, discussed in References 2.3-9 and 2.3-10. Basically, the largest and most intense waterspouts can be of tornadic size. The upper limit to the rotational velocity is presently estimated as approaching 200 mph with typical translational velocities approaching 15 to 20 mph. Estimates of the frequency of waterspouts at the Hope Creek site are extremely difficult to project. Waterspouts rarely leave evidence of their occurrence. The frequency of waterspouts occurring in the Hope Creek region, over the Delaware River or Bay, probably approaches that of tornadoes in the region. 2.3.1.2.1.4 Thunderstorms and Lightning Thunderstorms are a seasonal phenomena in the region of the Hope Creek site. The Wilmington NWS records, found in Reference 2.3-11, shows an average of 31 thunderstorm days per year, with 26 of these days occurring during the warmer months of April through September. Direct observation of lightning strikes is not a routine function at any of the standard observing stations. However, in Reference 2.3-12, Uman has developed a statistic that indicates 2.3-4 HCGS-UFSAR Revision 0 April 11, 1988

that the number of lightning flashes (cloud to ground) per square mile, per year, is equal to between 0.05 and 0.8 times the number of thunderstorm days per year. A conservative estimate of the number of lightning strikes per year in the square mile area containing the Hope Creek site is 25. The following provides monthly and annual estimates of lightning strikes at Wilmington NWS station as tabulated in NUREG/CR-2252,

National Thunderstorm Frequencies for the Contiguous United States.":

WILMINGTON NWS MEAN NUMBER OF THUNDERSTORMS Month J F M AM J J A s 0 ND Annual 0.2 0.4 1 35 8 8 8 3 11 0.3 39 As given in NUREG/CR-2252 a thunderstorm day is defined as any day during which thunder is heard, whereas the aforementioned frequency estimates are based on surface data and special observations taken at the station. The summer months (June, July, and August) have the highest number of thunderstorms while the winter months have the fewest, which is expected. The annual number of thunderstorms is slightly higher than the aforementioned number derived from Uman' s methodology, however, these frequencies are low compared to those for the Midwestern and Southeastern states. The tallest structure on the Hope Creek site is the 512 ft cooling tower. This structure would be expected to attract the maJority of the lightning strikes. Lightning protection is provided in the HCGS design and is not related to frequency of lightning strikes. A description of electrical protection of safety-related equipment is provided in Sections 7 and 8. 2.3-5 HCGS-UFSAR Revision 0 April 11, 1988

2.3.1.2.1.5 Hail Severe hail storms are a relatively rare phenomenon in the region. Pautz, in Reference 2.3-13, reports only eight occurrences of hail with diameters of 0. 75 inch or greater in New Jersey, and none in Delaware, during the period of 1955 through 1967. Of these eight occurrences in New Jersey, six storms had hail with diameters ranging from 0.75 to 1.50 inches, and two had diameters greater than 1.50 inches. Baldwin, in Reference 2.3-14, and Changnon, in Reference 2. 3 -15, report an annual frequency of approximately one hail storm per year in the Hope Creek region. Hail is generally associated with severe thunderstorms, and is most likely to occur during the late spring and summer. Reference 2.3-16 shows six occurrences of hail during the period 1977 through 1981, which agrees well with frequencies reported by Baldwin and Changnon. 2.3.1.2.1.6 Ice Storms A survey by Bennett, found in Reference 2.3-17, for 1928 through 1937, indicates that ice or freezing rain may occur up to one to three times per year in the site region. These occurrences are most frequent during the winter. Glaze accumulations greater than 0.25 inches are expected only once per year. A more recent summary of glaze statistics in Reference 2.3-14 indicates that during the 20-year period, 1950 through 1969, approximately four days of freezing rain annually occur through the region. Freezing rain has occurred on 25 days during 1977 through 1981 at the Wilmington NWS Station, as mentioned in Reference 2.3-16. The longest duration of freezing rain at the Wilmington NWS Station during this period lasted for 15 hours on February 15 and 16 of 1979. 2.3.1.2.1.7 High Air Pollution Potential Episodes of limited atmospheric dispersion in the U.S. have been studied by Holzworth, in Reference 2. 3-18 in terms of urban and 2.3-6 HCGS-UFSAR Revision 0 April 11, 1988

area source problems. Holzworth has estimated approximately 20 forecast days of high potential for air pollution during a 5-year period in the vicinity of the site. Using a pressure gradient technique to define stagnating conditions, Korshover, in Reference 2.3-19, found between 150 to 175 stagnation days in the region during the 40-year period from 1936 through 1975. This converts to approximately four stagnation days per year, which is the same as Holzworth's estimate. The summer and fall experience the highest potential for stagnation days. 2.3.1.2.2 Maximum Snow Load The weight on the ground of the 100-year mean recurrence interval snowpack at the Hope Creek site is 20 psf. This value was obtained from estimates made in References 2.3-20 and 2.3-21, both of which are based on the work of Thom, according to Reference 2. 3-22. The extreme snow load may be conservatively estimated by adding the weight of the 48 hour probable maximum winter precipitation assumed to occur as snow, to the weight of the 100-year snowpack. From the work of Ho and Riedel, NUREG/CR-1486, as indicated in Reference 2.3-23, the 48-hour probable maximum winter precipitation is estimated to have a water equivalent of 19.8 inches, which has a ground force of 103 psf. Therefore, the extreme snow load on the ground at the Hope Creek site is estimated to be 123 psf. For roof design of Seismic Category I structures, this load is increased to 150 psf to account for building configuration and roof shapes and is considered a live load as discussed in Section 3.8.4. It should be emphasized that this estimate is highly conservative and is presented only for building design purposes. The 48-hour probable maximum precipitation is based upon theoretical considerations, not measured values. The extreme load snowpack is equivalent to 24 inches of water or, using a typical ratio of snow to water (10:1), becomes 240 inches (20 feet) of snow. 2.3-7 HCGS-UFSAR Revision 0 April 11, 1988

2.3.1.2.3 Design Basis Tornado The design basis tornado parameters at the Hope Creek site have been determined in accordance with the criteria given in Reference 2.3-24. These parameters are as follows: Maximum wind speed 360 mph Rotational speed 290 mph Translational speed Maximum 70 mph Minimum 5 mph Radius of maximum rotational speed 150 ft Pressure drop 3 psi Rate of pressure drop 2 psi/s 2.3.1.2.4 Fastest Mile of Wind The 100-year recurrence interval fastest mile of wind expected at the Hope Creek site is 93 mph, according 'to Reference 2. 3-21 and 2.3-25. This is equivalent to a mean hourly wind speed of approximately 73 mph, as indicated in Reference 2.3-26. The fastest mile of wind value is valid 30 feet above the ground. The vertical distribution of the fastest mile of wind is computed using the common power law, in the form: (2.3-1) where: Uz wind speed at height Z UL wind speed at lower height ZL P stability dependent exponent 2.3-8 HCGS-UFSAR Revision 0 April 11, 1988

Thom indicates in Reference 2. 3-25 that a value for P of 1/7 is appropriate for high wind speeds in flat to rolling rural terrain, such as that at the Hope Creek site. The following table presents the vertical distribution of the fastest mile: Hei&ht Above Ground. ft Fastest Mile. mph 30.0 93 100.0 110 150.0 117 200.0 122 300.0 129 400.0 135 500.0 139 A gust factor of 1.3 is commonly used at the 30-foot level. Since the gust factor is known to decrease both as a function of height and increasing wind speed, the use of 1.3 is conservative at higher heights. For design of Seismic Category I structures, a basic wind speed (V30) of 108 mph is used as discussed in Section 3.3.1. The design wind velocities are given in Sections 2.3.2.3 and 3.3.1.1. 2.3.1.2.5 Ultimate Heat Sink The ultimate heat sink (UHS) for the Hope Creek Generating Station (HCGS) is the Delaware River. Because of its large volume, a climatological analysis of maximum evaporation, drift loss, and minimum heat transfer is not necessary. 2.3.2 Local Meteorology The analysis of the local meteorology in the vicinity of the Hope Creek Site is based upon 5 years of data, January 1977 through December 1981, collected at the onsite meteorological tower. The 300-feet tower is located on Artificial Island, approximately 1 mile 2.3-9 HCGS-UFSAR Revision 0 April 11. 1988

southeast of Hope Creek. A full description of the meteorological tower and its instrumentation is given in Section 2.3.3. The analysis of regional meteorology of the Hope Creek area is based upon data from the Wilmington, Delaware National Weather Service (NWS) first order station, 15 miles north of the site. This station provides both representative long term data for the region, as well as meteorological data concurrent with the onsite data period. The relevance of the meteorological data from the site tower and from the Wilmington NWS station to that over the long term meteorological conditions at the Hope Creek site is assessed by contrasting the two data sets. This assessment contrasts the extremes and distributions of the key meteorological parameters crucial to the safety, operation, and construction of HCGS. Obviously, no two meteorological data sets collected at the same location during different time periods or at two different locations for the same time period are identical. However, the differences between the data sets must be assessed to ensure, in this application, that the onsite and/or long term data set reasonably represent the conditions that would be expected over the approximately 40-year lifetime of the plant. 2.3.2.1 Normal and Extreme Values of Meteorolo&ical Parameters Meteorological data collected at the Artificial Island tower from January 1, 1977, through December 31, 1981, comprise the onsite data base. This 5-year data set includes the latest available annual cycle of meteorology. Table 2.3-4 lists the 5-year data availability for each meteorological parameter with the incorporation of appropriate backup data. Substitutions are made for missing wind data at the 150 and 300-foot tower levels. Concurrent wind direction data from the 150 and 300-foot levels are interchanged in all summaries if either is 2.3-10 HCGS-UFSAR Revision 0 April 11, 1988

missing. The wind direction substitutions are only made if both corresponding wind speeds are at least 3 mph. The 3-mph minimum wind speed criteria is used to ensure the accuracy of the substitution. Similarly, concurrent wind speed data from 150 and 300-foot levels are interchanged if either is missing. The substituted wind speeds are adjusted to the proper level by the following stability dependent power law equation: where: Uz wind speed at height Z UL wind speed at lower height ZL P stability dependent exponent The values of the stability dependent exponent, P, are: Pasguill Stability A 0.10 B 0.15 c 0.20 D 0.25 E 0.25 F 0.30 G 0.30 Stability, determined from the 300 to 33-foot tower lapse rate, must be available to make any wind speed substitutions. The Wilmington NWS data, concurrent with the onsite data, have been obtained from the National Climatic Center in North Carolina in several publications, as indicated in References 2.3-27 through 2.3-29, and References 2.3-11 and 2.3-16. Summaries of the 2.3-11 HCGS-UFSAR Revision 0 April 11, 1988

Wilmington NWS data over extended time periods of 10 years or more have also been obtained from the National Climatic Center. 2.3.2.1.1 Wind Flow 2.3.2.1.1.1 Wind Direction and Speed Onsite wind measurements are made at three heights on the tower, 33, 150, and 300 feet. Annual wind direction and speed distributions have been computed by atmospheric stability class, according to the classification system recommended in Reference 2.3-30. These distributions are used in the diffusion models discussed in Sections 2.3.4 and 2.3.5, and are presented in Reference 2.3-31, Tables A*l through A-3. In addition to the seven stability class wind direction and speed distributions, a summary for all stabilities is presented for each level directly following the individual stability distributions. Monthly distributions of wind direction and speed, by atmospheric stability for each level, are given in Reference 2.3~31, Tables A-4 through A-6 for the 33, 150, and 300-foot levels, respectively. A summary of the annual wind direction distributions independent of stability for the three tower levels is presented in Table 2. 3-5. These frequency distributions are extremely similar. The annual sector frequencies show differences of less than 2.8 percent between any two levels. with over 80 percent of the comparisons having less than a 1.0 percent difference. All three levels show primary frequency peaks in the northwest and west-northwest directions. Secondary wind direction frequency peaks are recorded in the southeast, south-southeast, and southwest sectors for the 33, 150, and 300-foot levels, respectively. The Wilmington NWS wind direction and speed distributions are categorized by atmospheric stability class devised by Pasquill and modified by Turner in the STAR program, as discussed in Reference 2.3-32. The STAR program distributions are tabulated for the concurrent onsi te data period in Reference 2. 3-31, Table A- 7. HCGS-UFSAR Revision 0 April 11, 1988

and for the 10-year period, 1972-1982, in Reference 2.3~31, Table A-8. The concurrent and long term period wind direction distributions at Wilmington are very similar. All stability distributions are bimodal, with a primary peak in the west-northwest and northwest sectors, and a secondary peak in the south sector. A summary of the wind direction frequencies for the concurrent and long term periods are contrasted with the onsite wind direction frequencies in Table 2.3-6. Although the onsite and NWS data are reasonably similar, there are some differences worth noting. The Wilmington NWS records for the concurrent time period, as well as the 10-year period also presented in this table, show a higher frequency of winds from the south and northwest compared to the site. However, the site distributions show a considerably higher frequency of winds from north-northeast and southeast. The frequencies in all other sectors at the site are within 2.5 percent, and most are within 2 percent of the concurrent and long term records at Wilmington. The low frequency of calms at the site is expected as a results of the excellent exposure in all directions. Onsite monthly average wind speeds from the three tower levels are summarized in Table 2. 3-7. The highest average wind speeds occur during the winter, while the lowest average wind speeds predominate in the summer months. The higher wind speeds measured at the tower usually occur with west-northwest, northwest, and southeast winds. The maximum hourly average wind speed measured during the five-year period was 40 mph at the 33-foot level, 54 mph at the 150-foot level, and 58 mph at the 300-foot level. The monthly average wind speed distributions presented in Table 2.3-7 for the onsite data, and Table 2.3-8 for the long term Wilmington NWS data, are similar. Both locations report higher average wind speeds during the winter and spring months, while the summer months record the lowest seasonal wind speeds. HCGS-UFSAR Revision 0 April 11, 1988

Annual mean wind speeds at the two locations are within 1 mph of each other at a height of 33 feet. Annual wind direction frequencies at the 33 ft, 150 ft, and 300 ft levels observed during June 1969 to May 1971 (SGS preoperational data) are shown in Table 2.3-36. The 150 ft wind distribution was derived from January 1970 to May 1971 data. Annual wind direction distribution for the same three levels for the period January 1977 to December 1981 are presented in Tables 2.3-37, 2.3-38 and 2.3-39, respectively. Data collection for the period of 1969 to 1971 was from a tower located 1400 feet north of the Hope Creek Reactor Building at a latitude of 39 degrees, 28 minutes, 13 seconds north, and a longitude of 75 degrees, 32 minutes, 12 seconds west. This tower was originally located to support preoperational data collection for the Salem units. The tower was relocated to the existing location to facilitate the construction of the Hope Creek Station and the cooling tower. The comparison of annual wind direction frequencies at the 33 ft, 150 ft, and 300 ft levels for both Salem and Hope Creek for the available period of record is as follows: 33 feet Highest wind direction frequencies from the period 1969 to 1971 (SGS) compare favorably with those from 1977 to 1981 (HCGS). The site has a bimodal distribution. SGS data shows the highest frequency of wind directions are SE*SSE-S and W-WNW-NW. HCGS data shows the same pattern. Frequencies other than these modes are evenly distributed throughout the compass points. For all individual years, the data recovery rates are above 90 percent. Variation among frequencies for individual years within the two data bases could be caused by overall synoptic conditions and related storm tracks. The bimodal distribution can be explained by synoptic conditions over the general area. 2.3-14 HCGS-UFSAR Revision 0 April 11, 1988

150 feet Any comparison between the two data bases would be obscured because the SGS data starts in January 1970 rather than June 1969. In addition, the data recovery of the 150 ft wind direction for the period January 1970 to May 1970 is less than 65 percent due to installation and maintenance problems. The same bimodal distribution is observed between the two data bases at the 150 ft level as was observed at the 33 ft level. 300 feet Any comparison between the two data sets shows the same bimodal distribution as was seen at the two lower levels. The data recovery rate for June 1969 to May 1970 was below 85 percent. Minor differences between the two data sets are caused by seasonal variations. The SGS data was observed over a period of time that seasonally does not coincide with the HCGS data. Weather patterns are related to changes of seasons. The prevailing winter wind directions at Artificial Island for the period 1977 to 1981 were WNW-NY. during the summer were SSW-SW, during the spring were evenly distributed between SSE-SW-WNW, and during the fall were SSE-S and WNW-NY (Reference 2. 3- 31). These wind direction frequency results were the same for the 150 ft and 300 ft levels. 2.3.2.1.1.2 Wind Direction Persistence Wind direction persistence at the Hope Creek site has been analyzed using a technique that determines the number of consecutive hours during which the wind direction at a given level remains within the same 22-1/2° sector. This analysis is performed using a sliding technique, so that the longest persistence is obtained incorporating a given hour. The results are summarized in tabulations of the number of times the wind direction at each level remains in the same sector for various time periods ranging from 2 to 3 hours to longer than 48 hours. 2.3-15 HCGS-UFSAR Revision 0 April 11, 1988

The 5-year annual summary of wind direction persistence is given in Tables A-9, A-10 and A*ll of Reference 2.3-31 for the three tower levels. The wind persistence distributions in these tables are categorized by stability, in addition to those independent of stability. The unstable and neutral classes are combined as well as the slightly to very stable classes. The stability is defined in accordance with criteria described in Reference 2.3-30. It is based on the 300 to 33-foot temperature difference measured on the tower. These tables indicate that wind direction persistence of more than 8 hours does not seem to be a function of stability. Numerous cases in all sectors and stabilities are associated with shorter persistence time. The southeast and northeast wind direction sectors at all levels show the highest frequencies of persistence. These are the only two sectors to record a case of wind direction persistence greater than or equal to 48 hours in duration. The combined monthly distributions of persistence by level are presented in Tables A-12, A-13 and A-14 of Reference 2.3-31. The monthly summaries for the 5 years show that persistent winds greater than 12 hours occur more often in the winter than the other seasons. The upper wind level has the highest number of wind direction persistence cases greater than 12 hours in December. 2.3.2.1.2 Temperature and Dew Point 2.3.2.1.2.1 Temperature The onsite monthly and annual means and extremes of temperatures are summarized in Table 2. 3-9. January has the lowest mean monthly temperature of -2.1*c, and July has the highest mean monthly temperature of 23.s*c. The overall maximum hourly temperatu~e at the site is 34.s*c, recorded on July 19, 1977, and on July 20, 1980. The lowest hourly temperature recorded during the period is -1s.s*c, on February 18, 1979, and on January 17, 1977. 2.3-16 HCGS-UFSAR Revision 0 April 11, 1988

Monthly and annual frequency distributions of the hourly temperature data are shown in Table 2.3 .. 10. These distributions demonstrate that larger temperature ranges exist during the winter months, compared to the relatively small temperature ranges of the summer months. Annually, temperatures below -5. 0°C occur less than 5 percent of the time, and temperatures greater than or equal to 25.0°C occur less than 9 percent of the time. The diurnal range of hourly temperatures for the period are summarized in Table 2. 3-11. The average temperature for each hour of the day is listed on an annual and monthly basis. Table 2.3-12 contrasts the monthly and annual mean temperatures at the site and Wilmington for the 5*year onsite data period. The Artificial Island temperatures are converted to degrees Fahrenheit for comparison with the Wilmington temperatures. This table shows a tendency for summer maximum temperatures at the site to be slightly lower than at Wilmington and winter minimums to be slightly higher. Specifically, the maximum annual temperature at the site was 4 .. F cooler than Wilmington, while the minimum temperature at the site was 5°F warmer. During this concurrent period, the mean monthly and annual temperatures at the site compare very favorably with Wilmington. Table 2.3-13 lists the Wilmington NWS long term temperatures means and extremes. These means are generally similar to the concurrent 5-year period mean temperatures measured at Wilmington. The mean temperatures at Wilmington during the 5-year period are considerably cooler than the long term Wilmington mean temperature for January and February. Both of these months have average temperatures more than 4°F lower than the long term means. This substantiates the extremely cold winters the Northeast has experienced during the last few years. The annual average temperature during the 5-year concurrent period in Wilmington is only 0.6°F lower than the long term record. The long term extreme temperatures are comparable to those measured during the 5-year period. 2.3-17 HCGS-UFSAR Revision 0 April 11, 1988

2.3.2.1.2.2 Dew Point The means and extremes of dew point temperature are shown in Table 2.3-14. The highest dew point temperatures occur during the summer, with the overall maximum hourly dew point of 28.4°C recorded in August. The overall minimum hourly dew point temperature of -24.7°C occurs in December. The monthly and annual frequency distributions of the hourly dew point temperature are given in Table 2.3-15. On an annual basis, 9.3 percent of the hours record dew point temperatures greater than or equal to 20. 0°C and 9. 6 percent of the hours have dew point temperatures less than -l0°C. Table 2.3-16 shows the monthly and annual diurnal range of dew point temperature. There is little diurnal variation of the dew point temperatures within each month. 2.3.2.1.3 Atmospheric Moisture Onsite summaries of atmospheric moisture content are compiled from the 33-foot tower data of 1977 through 1981. These include relative and absolute humidity. These summaries are obtained by using the measured dew point temperature and the ambient temperature. 2.3.2.1.3.1 Relative Humidity The monthly and annual means and extremes of onsite relative humidity are given in Table 2.3-17. There is little variation in the monthly mean relative humidities. The lowest monthly mean value, 62 percent, occurs in April, and the highest mean value is 76 percent in August. The overall lowest hourly relative humidity, 15 percent, occurred during April 1980. HCGS-UFSAR Revision 0 April 11, 1988

Onsite monthly and annual frequency distributions of relative humidity are shown in Table 2. 3-18. The annual frequency distribution shows 17.7 percent of the hourly relative humidities are greater than or equal to 90 percent, with approximately 1.5 percent of the relative humidities under 30 percent. April has the highest frequency of low relative humidities. The diurnal ranges of relative humidity on a monthly and annual basis are presented in Table 2.3-19. These summaries show the highest relative humidities occur during the morning hours around the time of sunrise. The minimum relative humidity values are recorded during the afternoon hours. The mean annual and monthly relative humidities at Artificial Island, shown in Table 2.3-19, and Yilmington, shown in Table 2.3-20, are very compatible. The mean relative humidity at Artificial Island tends to be slightly lower than the values at Wilmington at 0100 local time, and slightly higher at 1300 local time. 2.3.2.1.3.2 Absolute Humidity Absolute humidity is summarized into monthly and annual means and extremes in Table 2.3-21. Frequency distributions of absolute humidity are given in Table 2.3-22. Absolute humidity is defined as the ratio of the mass of water vapor present to the volume occupied by the mixture, the density of the water vapor component according to Reference 2.3-33. The maximum absolute humidity of 26.9 g/m 3 occurs in August, and the minimum of 0.6 g/m3 in December and January. The maximum annual frequency distribution is skewed toward the lower absolute humidity categories. There is also a large seasonal variation of absolute humidity, as the monthly distributions show. This is expected, since the ability of air to hold water vapor is temperature dependent. W'arm air can hold more water vapor than cold air. Table 2.3-23 shows there is 2.3-19 HCGS*UFSAR Revision 0 April 11, 1988

very little diurnal variation of absolute humidity within each month. 2.3.2.1.4 Precipitation Onsite precipitation measurements are summarized monthly for the five 1-year periods, as well as annually in Table A-15 of Reference 2.3-31. Combined monthly and the overall precipitation distributions for the five years are also tabulated in Table A-16 of Reference 2. 3-31. The hourly measurements are categorized by the amount of water equivalent precipitation which fell during each hour. In addition, maximum hourly, daily, and monthly total precipitation amounts are highlighted in summarizations. Time Period Maximum Measured Water Equivalent (hours) Date Precipitation (inches) 1 August 3, 1981 1.60 2 1.90 3 2.10 6 2.40 12 2.80 24 October 25, 1980 3.10 1 month January 1979 7.90 During the 5-year period, the precipitation was fairly evenly distributed throughout the year. The precipitation intensity was generally light. More than 70 percent of the recorded precipitation hours during the 5 years occurred at rates of less than or equal to 0 .10 in/h. The monthly distributions show that the summer months exhibit higher hourly precipitation rates than the winter months. The duration of precipitation and the accumulated amounts are shown in Reference 2.3-31, Tables A-17 and A-18, as frequency distributions for the entire 5-year period, and by month. The majority of precipitation events last less than 6 consecutive hours. There was only one case of precipitation lasting between 12 and 23 consecutive hours during the 5 years. HCGS-UFSAR Revision 0 April 11, 1988

Those hours with recorded precipitation are distributed by wind direction and ,speed, recorded at the three tower levels and categorized by precipitation rates. In addition, all precipitation hours are grouped into frequency distributions by wind speed and direction. Eight hourly rate categories are used and range from the smallest, an amount equal to 0.10 inches, to the largest, amounts exceeding 1.50 inches. Reference 2.3-31, Tables A-19 to A-21, present the distributions for the entire period, and Reference 2.3-31, Tables A-22 to A-24, list the combined monthly distributions. These distributions indicate that precipitation is most frequently associated with winds containing an easterly component at all levels. Furthermore, winds at the 33-foot level are most frequently southeast during precipitation, and northeast and east-northeast winds are the most common 150 and 300-foot wind directions during precipitation. A comparison of the onsite and Wilmington precipitation extremes during January 1977 through December 1981 reveals that the onsite extremes are comparable to those at Wilmington. The 1-hour, 24-hour, and 1*month maximum precipitation totals are shown in the following table: Time Period Artificial Island Wilmington NWS (hours) Cinches) Cinches) 1 1.60 1.35 24 3.10 3.94 1 month 7.90 8.41 The long term maximum 24-hour and monthly precipitation totals measured at the Wilmington NWS are 6.53 inches in August 1945 and 14.91 inches in August 1911. respectively. These maximums significantly exceed those measured at the site. HCGS*UFSAR Revision 0 April 11, 1988

The monthly and annual means, along with the monthly extremes and 24*hour maximums of precipitation at the Wilmington NWS station, are given in Table 2.3-24. The mean monthly precipitation totals range from a minimum of 2.60 inches in October to a minimum of 4.31 inches in July. The mean annual total precipitation for the 1941 through 1970 period was 40.25 inches. These long term climatological monthly precipitation means are shown in Reference 2.3-31, Table A-16. Unlike wind frequency and temperature (including stability indicators) where random missing data has only a limited effect in describing site annual meteorological characteristics, missing precipitation data does have an impact on annual averages. This fact is obvious as precipitation is an accumulative measurement. Missing precipitation data is attributed to three main causes:

1) equipment failure or malfunction, 2) system outage due to calibration or maintenance, 3) deletion of suspect data by the meteorologist reviewing the data collected from the data base. With respect to precipitation a conscientious effort to invalidate suspect data results directly in a potential underestimate of annual precipitation.

The digital Meteorological Data Acquisition Systems provide increased data recovery. It should be noted, that the Meteorological Data Acquisition System was designed to meet the requirements of Regulatory Guide 1.23 and precipitation data was not mentioned in this Regulatory Guide. However, one would expect statistical differences to occur regardless of any small precipitation data loss. Yearly precipitation totals and precipitation statistics for the period 1977 to 1981 are presented in Tables 2.3-34 and 35 for Hope Creek, Wilmington NWS Station, Glassboro and Woodstown cooperative stations. Wilmington NWS Station is located 15 miles north of the HCGS. The. Glassboro Station is located approximately 27 miles 2.3-22 HCGS-UFSAR Revision 3 April 11, 1991

northeast of the HCGS. The Woodstown Station is located 17 miles northeast of the HCGS. The statistics indicate that the Wilmington precipitation data has the greatest standard deviation and standard error. The means do not show good agreement in precipitation data from Wilmington and onsite data. Further analysis shows that during the year 1980 precipitation data was not collected during July and August due to an instrument equipment problem. Difference of more than five inches in a year is not unusual as shown in the table. The greatest difference between Wilmington and the three other stations occurred in 1978. Wilmington precipitation was 11.74 inches higher than observed at Glassboro and 6. 84 inches higher than observed at Woodstown. The distance from Woodstown to Glassboro is 10 miles. The largest difference in observed precipitation between Woodstown and Glassboro is in 1981 (6.21 inches) . These differences in observed precipitation can be attributed to spatial differences between stations, frequency and intensity of localized convective storms (generally observed during the summer months) and the accuracy of precipitation measurements. NWS stations observed precipitation to 0.01 inches while onsite data was to the nearest 0.10 inches. The onsite rain gauge has been replaced with instrumentation that has an accuracy of 0.01 inches. Precipitation data changes with distance in areas where localized short lived convective storms occur. The higher the frequency of occurrence, the greater the precipitation differences between stations. Precipitation data is not a good measure of representativeness between stations such as HCGS and Wilmington NWS Station. on a larger scale, almost approaching synoptic, measured parameters such as wind direction and speed, absolute humidity and 2.3-23 HCGS-UFSAR Revision 0 April 11, 1988

stability provide a more precise measure of representativeness between stations. Since snowfall is not measured at the site, the Wilmington NWS records are presented. Monthly and annual means, as well as the monthly and 24-hour maximum snowfall, are given in Table 2. 3-25. February had the highest mean monthly snowfall of 6.4 inches. The maximum monthly snowfall of 27.5 inches occurred in February 1979 . The maximum 24-hour snowfall of 22. o inches was recorded in December 1909. 2.3.2.1.5 Fog and Haze Table 2.3-26 presents the monthly and annual sununary of fog, haze, and/or smoke for Wilmington. At Wilmington, between 1965 and 1974, light fog (visibility less than 7.0 miles} occurs on an average of 156 days per year and is rather evenly distributed throughout the year, with the exception of a slight relative minimum during the winter, as indicated in Reference 2.3-29. Heavy fog, (visibility less than or equal to 0.25 miles), is far less frequent, occurring on an average of 34 days per year. Haze and/or smoke is reported on an average of 167 days per year, as found in Reference 2.3-29. Most of these days are between June and September. 2.3.2.1.6 Atmospheric Stability Determinations of atmospheric stability are made from the temperature difference measured between the 300 to 33-foot and the 150 to 33-foot levels on the onsite tower. These temperature difference data are grouped into seven stability classes, A through G, according to the NRC lapse rate criteria shown in Reference 2.3-30. I Delta temperature stability distributions for the 300 to 33 ft and 33 ft intervals in the Artificial Island meteorological tower 150 to 2.3-24 HCGS-UFSAR Revision 11 November 24, 2000

are given in Tables 2.3-27a and 2.3-27b, respectively. The 300 to 33 ft delta temperature distribution shows a majority of hours with neutral and stable conditions. The 150 to 33 ft delta temperature distribution also shows this pattern. The 150 to 33 ft delta temperature was designed to provide backup data if the upper delta system was inoperable. The interval of measurement is only 117 ft. and to the nearest 0.1 degrees Celsius as required by Regulatory Guide 1.23 (Safety Guide 23). Therefore, when converting the C/lOOm, stability Class B does not exist. This is a further reason to use the 150-33 ft delta temperature data for backup purposes only. Monthly and annual summaries of atmospheric stability have been incorporated into the wind roses previously presented in Tables A-1 through A-6 of Reference 2 .4*31. The onsite distribution of only atmospheric stability for the 5-year record is summarized in Table 2 3-27 0 0 The temperature difference scheme classifies 43.9 percent of the hours as unstable neutral (Pasquill Classes A through D) and 56.1 percent of the hours as stable (Pasquill Classes E through G). Table 2.3-27 also shows the Wilmington stability distributions for the concurrent onsite data period, as well as the long term 1972 through 1981 record. The Wilmington NYS stability is determined from the STAR program methodology consistent with Turner's scheme, found in Reference 2.3-32. Because of different techniques used to determine atmospheric stability, e.g., the (temperature difference method for onsite data and the STAR method for the Wilmington data, the stability distributions given in Table 2.3-27 are also expectedly different. Differences have been documented in several papers and should not be alarming. See References 2.3*34 and 2.3-35. Annual atmospheric stability distributions (Pasquill stability classes A-G) based on measured 300 to 33 ft and 150-33 ft delta 2.3-25 HCGS-UFSAR Revision 0 April 11, 1988

temperature for the period June 1969 to May 1971 are presented in Table 2.3*43. Annual stability distributions for the period January 1977 to December 1981 are presented in Tables 2.3-27a and 2.3-27b. The 1969 to 1971 data shows the same predominantly neutral to slightly stable conditions both at the 150-33 ft and 300*33 ft levels as is shown in the 1977 to 1981 data set. 2.3.2.1.7 Monthly Mixing Height Data The table below was derived from isopleths of mixing height data by season, presented in U.S. EPA Publication 101 entitled "Mixing Heights, Wind Speeds, and Potential for Urban Air Pollution Throughout the Contiguous United States. MiJ1Di Heisht <meters) Season Mornin& Afternoon Winter 850 1000 Spring 750 1700 Summer 600 1800 Autumn 700 1300 Annual 700 1300 2.3.2.1.8 Temperature Inversion Persistence The frequency and duration of inversion conditions defined by the NRC delta temperature stability scheme are presented in Table 2.3-28. Table 2.3-28 was derived from hourly 300 to 33*foot delta temperature data for the period January 1977 through December 1981. The NRC delta temperature stability scheme was used in conjunction with a duration - frequency program. Table 2.3-28 shows frequencies 2.3-26 HCGS-UFSAR Revision 0 April 11. 1988

and duration of hourly stability greater than 0.0°C/100 meters and greater than 1.5°C/100 meters on a monthly and annual basis. The following are the results of the analysis. All Inversions - Lapse Rate >0.0°C/100m (Stability E, F, and G)

1. The duration of inversions, (NRC stabilities E, F, and G) lasting up to 12 hours were observed for over 50 percent of all cases, regardless of month.

2. For the months May through September, 75 percent of all these inversions had a persistence duration of less than or equal to 12 hours. 89.8 percent of the cases in August, the month with the highest number of cases, had a persistence less than or equal to 12 hours.

3. The highest percentage of cases when the duration of inversions was 13-24 hours was in November 36.3 percent), the lowest was in June (10.8 percent), and on an annual basis, it is 24.1 percent.

4. The highest number of inversions was in August (156 cases) and the lowest in January ( 83 cases)

Averaged over a 5-year period, the number of occurrences equals 30 cases for each August and 15 cases for each January.

s. The highest percentage of cases, by month, that persisted for longer than 4 hours (2 days) was in March (1.7 percent of 121 cases or 2 occurrences).

strong Inversions - Lapse Rate >l.5°C/l00 meters (F, and G) 2.3-27 HCGS-UFSAR Revision 0 April 11, 1988

6. Strong inversion persistence with durations less than or equal to 12 hours comprised the majority of all cases (75 percent of all cases for each month). Durations of up to seven hours occurred for SO percent of the cases regardless of month. Analyzing the percentages of each case shows that, from April to October the duration was to 12 hours for over 90 percent of all monthly cases. On an annual basis, 90.8 percent of the cases had a duration of 12 hours or less and 86.6 percent had a duration of two to seven hours.

7. The highest number of persistence occurrences were in April (95) and the lowest in January (39). Averaged over a 5-year period, this translates into 20 cases during any April and 8 cases during any January.

2.3.2.1.9 onsite Meteorological Data Tape Hourly averages of wind speed and direction at the 300, 150, and 33-foot levels of atmospheric stability, determined by the 300 to 33-foot delta temperature, can be derived from the hourly data (January 1977 through December 1981) supplied to the NRC on magnetic tape. 2.3.2.2 Potential Influence of the Plant and Its Facilities on Local Meteorology An EPRI study by Laurmann has concluded that, although quantitative predictions of the meteorological effects resulting from power plant operation cannot be made, evidence and theory indicate that plants of conventional size (up to 4000 MWe) rarely produce noticeable weather changes; see Reference 2.3-36. Minor effects on local meteorology, which might occur, are divided into two distinct categories: those attributable to the turbulent wakes associated with the plant structures, and those attributable to waste heat dissipation systems. 2.3-28 HCGS-UFSAR Revision 8 September 25, 1996

2.3.2.2.1 Turbulent Wake Effects From Plant Structures As part of the technical support for the tall stack regulations in the 1977 Clear Air Act Amendments, the U.S. EPA has published a comprehensive review and literature search on the aerodynamic effects caused by building structures, as indicated in Reference 2.3*37. The consensus of this review is that a structure produces a cavity of increased turbulence on its leeward side, 1.5 building height deep, and persists for approximately five building heights downwind. Based upon these criteria, it is estimated that the Hope Creek turbine/reactor enclosure complex produces a turbulent wake on its leeward side, extending approximately 90 meters vertically and persisting 305 meters downwind. Halitsky has shown through wind tunnel testing that the turbulent effects produced by rounded structures are not as large or severe as those produced by sharp edged buildings. as indicated in Reference 2.3-38. This is consistent with the result of a combined wind tunnel-field measurement study conducted by Smith and Mirabella on the cooling tower induced wake at the Rancho Seco Plant mentioned in Reference 2. 3-39. Their results indicate that the cooling towers produce a turbulent wake only when wind speeds exceed 2 meters/s. They estimate that the wake would be 1.5 structure heights deep, and would persist*for 2 to 3 tower diameters downwind. According to these criteria, the maximum wake produced by the Hope Creek cooling tower would be turbulent region extending 235 meters vertically and persisting 395 meters downwind. 2.3.2.2.1.1 Effect of the Turbulent Wake on the Gaseous Reactor Effluent The primary effect of the structurally induced wakes on the reactor effluent is to enhance dispersion, and is discussed briefly in Section 2.3.5. 2.3*29 HCGS*UFSAR Revision 0 April 11, 1988

2.3.2.2.1.2 Effect of the Turbulent Yake on the Meteorological Tower Measurements The turbulent wakes produced by the turbine/reactor enclosure and the cooling tower do not extend far enough to affect the meteorological tower. The tower is located approximately 1 mile from the Turbine/Reactor Buildings and the cooling tower, well beyond the distorted flow region in the lee of the plant. 2.3.2.2.2 Potential Effects of the Waste Heat Dissipation System on the Local Meteorology The natural draft cooling tower at the Hope Creek site is the only source of effluents capable of influencing the local meteorology. Warm moist air is released from the cooling tower containing its moisture in both vapor and liquid forms. The liquid or visible forms of moisture are either very small droplets formed when the vaporous plume interacts with cooler ambient air, or drift droplets. The drift droplets originate when the high velocity air flowing through the cooling tower entrains small water droplets from the circulating water falling through the fill section of the cooling tower. The possible effects of both the vaporous and liquid forms of the cooling tower effluent are discussed in the following sections. 2.3.2.2.2.1 Visible Plume Occurrence The cooling tower plume only becomes visible if the water vapor contained within the plume condenses. The plume will remain visible until the droplets evaporate into the drier ambient air. Whether or not the plume will be visible at any particular time depends primarily on the temperature and moisture content of the ambient air. Studies have shown that ambient saturation deficit is the best indicator of visible plume persistence, mentioned in References 2.3*40, and Reference 2.3*41. Saturation deficit is defined as additional water vapor required to produce moisture saturation at a given ambient temperature and pressure. Saturation 2.3*30 HCGS*UFSAR Revision 0 April 11, 1988

of the air by the cooling tower plume results in a visible plume of condensed water droplets. Observational evidence has shown that the vast majority of visible plumes from natural draft cooling towers do not persist downwind for more than 0.6 miles, as indicated in Reference 2.3-42. 2.3.2.2.2.2 Cooling Tower Drift When the heated brackish circulating water falls through the fill section of the cooling tower, small water droplets are entrained by the relatively high velocity of the air flowing through the tower. The entrained water droplets and salt particles, called cooling tower drift, are carried from the tower and, subsequently, fall to the ground downwind from the tower. The very efficient drift eliminators installed on the Hope creek cooling tower insure that the drift emitted from the tower is the minimum achievable under current technology. Experiences at natural draft cooling towers have shown that the fallout of water and chemicals under the majority of weather conditions is too small to be observed or measured except in the immediate tower vicinity, and no significant offsite environmental effects are created, as indicated in Reference 2.3-42. 2.3.2.2.2.3 Ground Fogging and Icing several studies have shown that natural draft cooling tower plumes never intersect the ground, thus they do not cause ground fogging or icing, as derived from References 2. 3-40 and 2. 3-42. The height of release and buoyancy of natural draft cooling tower plumes ensures this. Ground icing due to cooling tower drift is also negligible, since the total surface accumulation of water drift from natural draft towers is insignificant. Measurements done in England downwind from a natural draft cooling tower complex of eight towers for a 2000 MW fossil plant, with efficient drift eliminators, indicate a maximum drift deposition rate of 0.02 mm/h of liquid 2.3-31 HCGS-UFSAR Revision 0 April ll, 1988

water, found in Reference 2. 3-43. This rate is too low to cause any ground. icing or wetting. 2.3.2.2.2.4 Cloud. Enhancement and Shaaowing The extent to which natural araft cooling tower plumes contribute to cloud formation can be qualitatively assessed based on observational studies conducted at three operating cooling tower sites, as mentioned in Reference 2.3-40. At each of these sites, cooling tower plumes were observed to occasionally cause broken cloud decks to become overcast and to enhance thin clouds. Separate cloud formations were occasionally observed to result from visible plume formation from the cooling towers, but usually at altitudes of several thousand feet above ground. Based on the above observations, the potential for increased cloud development due to cooling tower operation appears to be minLmal compared to the potential for development due to natural causes. The cooling tower does have the potential to cause slight decreases in the amount of solar radiation received at a point on the ground due to visible plume shadowing. A study conducted on a natural draft cooling tower from a 1500 MW fossil plant in Europe found that on a cloudy day, the maximum shadowing effect is a 20 percent reduction in total radiation for short time periods as discussed in Reference 2.3-44. The effects of visible plume shadowing are obviously mitigated. by the fact that the variability in wind direction causes the plume to move horizontally and does not remain over any one point for long periods of time. The relative rarity of long persistent visible plumes, detailed in Section 2.3.2.2.2.1, also minimizes the effects of plume shadowing. 2.3.2.2.2.5 Precipitation Modification Observations of precipitation falling from natural draft plumes are very limited. Kramer et al. have aocumented an observation of light rain falling from a natural draft plume, and several observations of light snowfall, mentioned in Reference 2.3-45. 2.3-32 HCGS-UFSAR Revision 8 September 25, 1996

Though it may be possible for a cooling tower to modify the precipitation pattern immediately downwind of the tower, it would not significantly alter the total precipitation in the region, as the water vapor emissions from the towers are small compared to natural fluxes, as indicated in Reference 2.3-42. During the winter of 1975*1976, Kramer et al. observed light snow from several different cooling towers on ten separate days, as found in Reference 2. 3*46. This effect was found only during stable atmospheric conditions, with temperatures below l0°F at the height of the plume centerline. In the 1-year summary of Philadelphia upper air soundings on 22 days, for short periods, the temperature criteria necessary for snowfall were met. This should not be interpreted as a prediction of snowfall frequency. There are several other variables, such as atmospheric stability, blowdown water chemistry, drift eliminator condition, and condensation nuclei availability, which play a role in snowfall formation. The h~ight to which the plume rises is such that, in most cases, the snow crystals would sublimate before reaching the ground. 2.3.2.2.2.6 Relative Humidity Increases Observational studies have shown that the changes in ground level relative humidity should not be expected as a result of natural draft cooling tower operation. Spurr, in a study of a 2000 MW eight tower complex in England, found no ground level relative humidity increases either upwind or downwind of the plant; see Reference 2.3-43. 2.3.2.2.2.7 Interaction with Other Plumes There are no significant sources of pollutants within 1.2 miles of the Hope Creek Plant. Therefore , there is no concern for any chemical interactions between the cooling tower and other industrial plumes. 2.3-33 HCGS-UFSAR Revision 0 April 11, 1988

2.3.2.2.3 Topographic Features The terrain that surrounds the Hope Creek site is extremely flat within the first 5 miles. The maximum terrain within 5 miles of the plant is less than 60 feet above plant grade. The only appreciable terrain features (greater than 500 feet above grade) are located northwest of the site at distances of over 15 miles. Figures 2.3*1 and 2.3-2 are detailed 5 and 50 mile topographic maps, respectively. Figure 2.3-3 illustrates the terrain features around the Hope Creek site. These figures give the maximum terrain in each of the 16 directional sectors out to 50 miles. 2.3.2.3 Local Meteorolosica1 Conditions for Desi&n and Operatin& Bases Meteorological conditions used for design and operating basis considerations. and their bases. are discussed and referenced in HCGS-FSAR Section 3.3, Wind and Tornado Loadings. O@§iJn Wind Velocity Wind velocities at 30 feet of 108 mph and 100 mph were used as design bases for Seismic Category I and Non-Seismic Category I structures respectively. Recurrence interval is at least 100 years. Depisn Basis Tornado Refer to HCGS Sections 2.3.1.2.3 and 3.3.2.1. The design numbers were derived from Regulatory Guide 1.76, mentioned in Reference 2.3-24. 2.3-34 HCGS-UFSAR Revision 0 April 11, 1988

2.3.3 Onsite Meteorological Measurements Program 2.3.3.1 Meteorological Data Collection Program To arrive at atmospheric dispersion factors for use in calculating radiological exposures from both low level routine and accidental releases, an extensive data collection program was undertaken at the site. This data collection program is described in detail in the following paragraphs. The present meteorological monitoring program is in conformance with the recommendations of Regulatory Guide 1.23 (Safety Guide 23 February 7, ~972}, and all requirements in Standard Review Plan Section 2.3.3 (Revision 2} and Regulatory Guide 4.2 (Revision 2 - July 1976). 2.3.3.2 Operational Data Collection Program A detailed representation of the meteorological facility is not necessary because of the simplicity of the terrain. The tower data used are primarily those from the 33 and 300-foot levels, although data were obtained at the intermediate 150-foot elevation. The wind instrumentation consisted of anemometers and wind vanes, and the temperature difference measurements were obtained from aspirated thermometers. Precipitation, humidity, and solar radiation measurements are on record for possible use in general environmental applications. The system became operational in April 1976. The location of the tower, a 300-foot guy wire supported structure, is latitude 39° 27', 48.9 11 north, and longitude 75° 31' 11.76 11 west. The site and nearby sources of data are presented in Figure 2.3-4. 2.3-35 HCGS-UFSAR Revision 13 November 14, 2003

The data collection program also includes an additional tower, identified as a backup meteorological tower, consisting of a 10-meter telephone pole. The backup tower is located approximately 500 feet south of the primary meteorological monitoring tower. Backup meteorological data provides wind speed, wind direction, and a computed sigma theta. Wind speed and direction instrumentation is located at 300, 150 and 33-foot elevations on the primary tower and at the 33-foot elevation on the backup tower. Temperature measurement includes ambient temperature taken at the 33-foot elevation and temperature difference taken between T300 to T33 and T150 to T33. Temperature sensors consist of RTDs in a fan aspirated solar radiation shield. The vertical temperature gradient is determined using the difference between the ambient temperature RTDs. The dew point is measured at the 33 foot level. Rainfall and barometric pressure are measured at approximately 3 and 6 feet, respectively. Solar radiation is measured at a height of 8 feet above ground level. Figure 2.3-5 depicts the heights of these instruments on the tower. 2.3-36 HCGS-UFSAR Revision 26 April 13, 2023

All meteorological parameters are electronically recorded in the Meteorological Instrument Building at the base of the tower. The data acquisition system includes capabilities for remote interrogation in addition to data acquisition. The data acquisition systems consist of primary and backup data acquisition systems (DAS) located at the Meteorological Instrument Building. A diagram of the system configuration is provided on Figure 2.3-6. The rain gauge uses a tipping bucket. The primary and backup DAS, shown in Figure 2.3-6, are configured with identical hardware. Each DAS is provided with communication ports, including one as a link to the Safety Parameter Display System (SPDS). Each DAS provides storage for at least 7 days of 15-minute averages. The primary DAS collects wind speed and direction from the primary tower. The backup DAS collects wind speed and direction from the backup meteorological tower. Each DAS calculates a sigma theta for its respective meteorological tower (each of the three level wind directions on the primary tower, one level on the backup tower). The host computers acquire the meteorological data collected by the data loggers. 2.3-37 HCGS-UFSAR Revision 26 April 13, 2023

The calculations of the sigma thetas use samples of horizontal wind direction at each elevation/location. Data interrogation is possible through connection to the digital data acquisition systems. The digital data acquisition systems provide data to the SPDS. The SPDS supports display units in the EOF, the Hope Creek Control Point, the Salem and Hope Creek TSCs, the Hope Creek OSC, the Hope Creek Control Room, and the Salem OPS Ready Room. Additional sources of meteorological data to provide a description of airflow trajectories from the site out to a distance of 50 miles include Wilmington and Philadelphia National Weather Service (NWS) stations. Hourly wind, temperature, and cloud cover data are readily available from these NWS stations. Monthly and annual joint frequency distributions of wind speed and direction, based on atmospheric stability classes, are referenced in Section 2.3.2.1.1. The 5-year database containing hourly site meteorological data from January 1977 to December 1981 was used as input in the analysis. 2.3.3.3 Operational Data Display Several meteorological parameters are incorporated in the database of the Control Room Integrated Display System (CRIDS) computer. 2.3-38 HCGS-UFSAR Revision 26 April 13, 2023

I The Hope Creek Safety Parameter Display System {SPDS) provides 15-minute average meteorological monitoring system parameters. The parameters available for display are 33-ft wind speed1 direction 1 sigma theta, and horizontal stability class; 150-ft wind speed 1 direction, sigma theta, and horizontal stability class; 300-ft wind speed, direction, sigma theta, and horizontal stability class; delta temperature between 300 and 33-ft; delta temperature between 150 and 33-ft; vertical stability class for each delta temperature; precipitation; barometric pressure; solar radiation; and ambient and dew point temperatures. Atmospheric transport and diffusion is calculated by the Meteorological Information and Dose Assessment System (MIDAS) computers installed in both Salem and Hope Creek. A method for determining atmospheric transport and diffusion throughout the plume exposure emergency planning zone during emergency conditions has been developed. 2.3-39 HCGS-UFSAR Revision 15 October 27, 2006

THIS PAGE INTENTIONALLY LEFT BLANK 2.3-40 HCGS-UFSAR Revision 3 April 11, 1991

2.3.4 Short Term Diffusion Estimates 2.3.4.1 Objective The objective is to provide conservative and realistic short term estimates of relative concentration (X/Q), at both the site boundary and the outer boundary of the low population zone (LPZ) following a hypothetical release of radioactivity from HCGS. The assessment is based on the results of atmospheric diffusion modeling and onsite meteorological data. A ground level accidental radionuclide release from HCGS is analyzed at various distances. Conservative and realistic X/Q values at the exclusion area boundary (EAB) are derived for the 0 to 2-hour period following a postulated accident. Conservative and realistic estimates of the X/Q value at the outer boundary of the LPZ are* computed for 2, 8, 16, 72, and 624 hours following a postulated accident. For this modeling assessment, the EAB is assumed to be a circle with a radius of 901 m, which is the shortest actual distance to the EAB bearing north. 2.3.4.2 Accident Assessment The short term, 0 to 2-hour X/Q values for ground level releases are calculated with the sector dependent model described in Regulatory Guide 1.145 Reference 2.3*47. Annual accident X/Q values are also required to derive the intermediate time period X/Q values. These annual accident X/Q values are derived using the long term diffusion model described in Regulatory Guide 1.111, Revision 1, Reference 2.3-48, and in Section 2.3.5. Long Term (Routine) .Diffusion Estimates. 2.3.4.2.1 Methodology The procedure used to estimate the X/Q values for the appropriate time periods following a postulated accident are described in Regulatory Guide 1.145. The diffusion model generates a cumulative 2.3-41 HCGS-UFSAR Revision 0 April 11, 1988

frequency distribution of X/Q values for each sector~distance combination representing the first 2 hours after the postulated accident. These 2~hour X/Q values are based on 1-hour averaged data, but are assumed to apply for 2 hours. The frequency distributions are plotted on a log probability scale for each sector distance combination, and are then enveloped in accordance with the methodology described by Markee and Levine in Reference 2.3-49. The X/Q value that is equalled or exceeded 0.5 percent of the time at each sector percent distance combination is then determined from the intersection of the envelope and the 0.5 percent probability level. The highest sector dependent X/Q value is then compared with the "overall" 5 percent accident X/Q value. The highest value represents the conservative 2 -hour accident X/Q. The realistic 2-hour accident X/Q is evaluated at the 50 percent probability level. The X/Q value that is equalled or exceeded 50 percent of the time at each sector distance combination is determined from the intersection of the envelope and the normalized (probability normalized to 100 percent in each sector) 50 percent probability level. The highest sector dependent X/Q value is then compared with the "overall" 50 percent accident X/Q. The highest value represents the realistic 2-hour accident X/Q. The overall 5 percent and 50 percent X/Q values are determined by summing the sixteen sector dependent X/Q distributions for each distance into a cumulative frequency distribution representing all sectors and again enveloping the data points. The 5 percent and 50 percent values are determined by the intersection of the envelope with the 5 percent and 50 percent probability levels, respectively. The X/Q accident values for time periods of up to 30 days following an accident are derived by logarithmic interpolation between the 2- hour 0. 5 percent and 50 percent accident X/Q values , and the annual accident X/Q value at each sector distance combination. The intermediate time periods for the overall 5 percent and 50 percent X/Q values are determined by logarithmic interpolation between the overall 2-hour 5 percent and 50 percent X/Q values and the maximum HCGS-UFSAR Revision 0 April 11, 1988

X/Q values and the maximum annual X/Q. The maximum X/Q value for a given five distance is the maximum sector 0.5 percent X/Q, or the overall S percent X/Q, whichever is higher, for the conservative assessment. The realistic assessment compares the maximum sector 50 percent X/Q and the overall 50 percent X/Q. The higher X/Q value is chosen again. 2.3.4.2.2 Meteorological Data 2.3.4.2.2.1 Representativeness The Artificial Island meteorological tower data from January 1977 through December 1981 are employed in the accident assessment. The data collected at the tower are representative of the meteorological conditions under which effluents are released, since both are located on the Delaware River shoreline. Furthermore, the proximity of the 300-foot tower to HCGS ensures that the data are representative of the conditions used in an accident evaluation. 2.3.4.2.2.2 Joint Frequency Distributions Joint frequency distributions of wind speed and direction by atmospheric stability class are used as input to the diffusion calculations. Wind speed and direction data from the 33-foot level are used in the assessment of diffusion for the ground level releases. Atmospheric stability is determined for the 33-foot distributions by the vertical temperature difference between the 300 and 33-foot levels. Joint frequency distributions of wind speed and direction by atmospheric stability class are computed for 22.5° sector using the wind speed groups and atmospheric stability classes suggested in Regulatory Guide 1.23. The 5-year frequency distributions are shown in Section 2.3.2.1, and in Reference 2.3-31, Table A-1 for the 33-foot level. 2.3-43 HCGS-UFSAR Revision o April 11, 1988

With the exception of the calm and 25+ mph wind speed groups, the highest wind speed in each group is used to represent that group in the diffusion calculations. For conservatism, a wind speed of 0.5 mph is used to represent calms at the 3 3- foot level . This value represents a conservative threshold wind speed for the 33-foot wind instrumentation. Due to the high wind speeds associated with this site, a wind speed of 30 mph is used to represent the 25+ mph wind speed group. 2.3.4.3 Atmospheric Diffusion Model The Reactor Building vent is treated as a ground level source for both short term and long term calculations. This implies that no plume rise is calculated and no terrain corrections are applied. A building wake correction factor is used, in accordance with the methodology discussed in Regulatory Guide 1.145 for vent releases. The building wake correction factor takes into account the initial mixing of the plume within the building cavity. The vent release X/Q values are calculated with the following equations from Regulatory Guide 1.145: X/Q = 1 (2.3-2) u1o (1tSY Sz + A/2) X/Q = 1 (2.3-3) u1o (31tSY sz> X/Q = 1 (2.3-4) u101tl;Y sz ) where: 3 X/Q = relative concentration, s/m u1o = wind speed at 10 m level, m/s 2.3-44 HCGS-UFSAR Revision 13 November 14, 2003

Sy lateral plume speed, m ~ lateral plume spread with meander and building wake y effects, m SZ vertical plume spread, m A smallest vertical plane cross sectional area of the reactor building, and adjacent structures m2. A building wake correction factor (A/2) of 2915 m2 is used for calculations of the short term X/Q. The calculation of the "A 6 term in Equation 2.3*2 is based on Figure 2.3-7. The "smallest vertical-plane cross-sectional area," also happens to be the orientation of the station with respect to the minimum exclusion distance boundary formed by land (Section 2 .1. 2 .1). A calculation of the Reactor Building cross-sectional area only, yields an area of 3341 m2 . If the service and radwaste area of the Auxiliary Building are added, this yields an additional 2 646 m . It should also be noted that a different building wake correction factor is used in calculating the long term X/Q. due to the different assumptions inherent in the guidance in Regulatory Guide 1.111. The smaller building wake correction factor used in this short term calculation is more conservative. As can be seen from Figure 2.3-7 the Auxiliary Building and Turbine Building are contiguous adjacent structures. It must be pointed out however 1 that at 901 m exclusion area boundary where the critical X/Q occurs 1 the 6 A" term is of small importance. The reason for this is as follows. Under unstable conditions, the Pi, Sy, and Sz terms dominate the denominator of the calculations (Equation 2.3-2). Under stable conditions and low wind speeds Equation 2.3*4 becomes the dominate equation. The Turbine 2 Building contributes 1843 m

The total smallest vertical-plane 2

cross-sectional area "A" is 5830 m . The above reasoning supports 3 the use of 1.9E-4 sec/m as the short term exclusion area boundary. 2.3-45 HCGS-UFSAR Revision 0 April 11, 1988

For neutral or stable conditions combined with wind speeds less than 6.0 mjs, calculations of X/Q values are made using Equation 2.3~4. For all other meteorological conditions, X/Q values are calculated using Equations 2.3*2 and 2.3-3. The values computed from Equations 2,3 2 and 2.3-3 are compared, and 4 the higher value is selected. For neutral and stable conditions with a wind speed less than 6 m/s, the value from Equation 2.3-4 is compared with the value chosen from Equations 2.3-2 and 2.3-3, and the lower value is chosen to represent these conditions. 2.3.4.4 Diffusion Estimates 2.3.4.4.1 Exclusion Area Boundary The maximum conservative 2-hour X/Q at the EAB, 0.56 miles from the

                                   ~4       3 Reactor Building vent, is 1.9 x 10       s/m . This is the overall 5 percent value at this distance. This value is larger than each of the 16 sector dependent X/Q values.         The maximum realistic (50
                                               -5     3 percent) 2-hour X/Q at the EAB is 6.3 x 10          s/m . This is the normalized 50 percent X/Q value in the WNW sector. Conservative and realistic X/Q values for the EAB (0. 56 miles) are given in Table 2.3-30. Conservative 2-hour X/Q values at the LPZ are given in Table 2.3-30a.

2.3.4.4.2 Low Population Zone The maximum. conservative and realistic X/Q values, 0.5 percent and 50 percent, respectively, given in Table 2.3-30 represent the maximum X/Q values (sector value used if greater than the overall value) for the Reactor Building vent at the LPZ boundary, 5.0 miles. HCGS-UFSAR Revision 0 April 11, 1988

2.3.5 Long Term (Routine) Diffusion Estimates 2.3.5.1 Objective The objective is to provide realistic annual average estimates of relative concentration (X/Q), relative concentration depleted by deposition (depleted X/Q), and relative deposition per unit area (D/Q) at appropriate distances from all routine gaseous releases of radioactive materials from HCGS. The assessment is made with the use of an atmospheric model. 2.3.5.2 X/0 and D/0 Estimate@ Radionuclides are routinely emitted to the atmosphere from two locations at HCGS. They are the south and north vents, located adjacent to the turbine buildings. Estimates of annual average X/Q, depleted by deposition X/Q, and D/Q have been made for receptor locations out to 50 miles in each of 16 radial sectors. These annual average values are presented in the following tables for compliance with 10CFRSO, Appendix I:

1. Table 2.3 vent ground level release - X/2

2. Table 2.3 vent ground level release - depleted X/A

3. Table 2.3 vent ground level release - D/Q 2.3.5.3 Methodology The analysis of the atmospheric transport and diffusion properties is based on the onsite meteorological data, the source configuration, the terrain, and a sector average diffusion model.

2.3.5.3.1 Meteorological Input Joint frequency distributions of wind speed and direction by atmospheric stability class are used for the diffusion calculations. 2.3-47 HCGS-UFSAR Revision 0 April 11, 1988

The meteorological tower is located approximately 1.0 mile southeast of HOGS. All meteorological data are from the Artificial Island meteorological tower. The flat, uncomplicated terrain that surrounds the site for a considerable distance in every direction, ensures excellent representation of the regional airflow --..._.; measured by the Artificial Island meteorological tower. Wind speed and direction data from the 33-foot tower level are used as input for the joint frequency distributions. Joint frequency distributions of wind speed and direction by atmospheric stability class are computed for 22.5° sectors using the wind speed groups and atmospheric stability classes suggested in Regulatory Guide 1.23. The 8-year joint frequency distributions of wind direction, speed, and stability from the 33-foot level are used as input for both vents. With the exception of the calm and the 25+ mph groups, the median speed from each wind speed group is used to represent the group in the diffusion calculations. For conservatism, a wind speed of 0.38 mph, equal to one-half of the highest threshold of the vane and propeller is assigned to the calms. A wind speed of 26 mph is used to represent the 25+ mph group. 2.3.5.3.2 source Configuration Radionuclides are routinely released from two sources, the south and north vents. Their source characteristics are given as follows; Para,meter south vent North Vent Height above grade, m 35.05 35.05 Exit diameter; m,the equivalent 4.13 2.23 eire diam for rectangular vents Exit velocity m/s summer (Apr - Sept) 15.54 5.08 Winter (Oct - Mar) 10.82 5.08 2.3-48 HCGS-UFSAR Revision 8 September 25, 1996

Both vents, pointing upward, are adjacent to the tops of the turbine buildings, below the level of the reactor containment dome. Therefore, the vents are affected by the nearby building aerodynamics with moderate to strong winds. The release is assumed to be a ground level, and a building wake correction factor (Reactor Building height squared) of 3819 m2 is used in accordance with the methodology of Regulatory Guide 1. 111, Revision 1. The building wake correction factor takes into consideration the initial mixing of the plume within the building cavity. Regulatory Guide 1.111 states "For effluents released from points less than the height of adjacent solid structures, a ground level release should be assumed" (Reference 2.3-48). The exit velocities for the south plant vent are significantly higher than those for the north plant vent. The assumption made in Regulatory Guide 1.111 (Revision 1) about the height of adjacent solid structures (i.e., Reactor Building dome) is simplistic in the case of effluents released at high exit velocities from vents oriented upward (versus horizontal). With the consideration of the Reactor Bu~lding dome as an adjacent structure, the projected effluent path becomes complicated because the transport wind and associated entrainment will be sector dependent. Therefore, the X/Q, depleted X/Q and D/Q values (Tables 2.3~31, 2.3-32, a~d 2.3-33) are conservative when based on a ground level release. 2.3.5.3.2.1 Site Impact on Vent Releases The final consideration of the source configuration is to determine the effects, if any, of the natural draft cooling tower on the effluent released from the two vents. The natural draft cooling tower is located approximately 1250 feet northeast of the south vent and 920 feet northeast of the north vent. The physical dimensions of the natural draft cooling tower are: 2.3-49 HCGS*UFSAR Revision 0 April 11, 1988

1. Height above grade - 156.1 m

2. Base diameter - 130.8 m

3. Throat diameter - 75.9 m

4. Exit diameter

82.6 m.

Field data obtained at Rancho Seco, especially during stable conditions, were used to determine the flow perturbations generated by natural draft cooling towers. The report, noted in Reference 2.3-50, states, "The overall interpretation of ground level concentrations, i.e. , crosswind integrated concentrations and sigma-y values, are probably not severely distorted even when the observations are influenced by the by the cooling tower wakes,". Thus, the effects of the natural draft cooling tower for the vent releases during stable conditions are neglected. The effect of the cooling tower on the relatively low level vent releases during neutral and unstable atmospheric conditions would be to enhance the vertical diffusion through increased mechanical turbulence and thus reduce ground level concentrations. Therefore, to be conservative in the estimation of ground level concentrations for neutral and unstable conditions, the wake effect of the cooling tower has been neglected. 2.3.5.3.3 Diffusion Model The sector average Gaussian plume equation, as expressed in Regulatory Guide 1.111, Revision 1, is used for all X/Q calculations. The straight line Gaussian diffusion model did not need to be modified to calculate long term annual relative concentration values for the SO-kilometer (50-mile) region surrounding the HCGS site. HCGS-UFSAR Revision 0 April 11, 1988

Consideration of temporal and spatial airflow changes in the site vicinity would insignificantly alter the long term diffusion estimates. In addition, the lack of local mesoscale circulations in the site region during the summer months eliminates the necessity of modifying the straight line diffusion model. NRC Regulatory Guide 1.111 recognizes three basic situations that would require the consideration of temporal and spatial airflow changes (Reference 2.3-48). These are: 1) recirculation of airflow during periods of prolonged atmospheric stagnation at inland sites located in open terrain; 2) valley airflows at sites located in pronounced river valleys; and 3) sea or lake breeze flows at sites located along coasts of large bodies of water. Recirculation of airflow during periods of prolonged atmospheric stagnation seldom occurs at the BeGS site. The airflow in the region is dominated by large-scale meteorological patterns. There are no terrain-induced alterations in the airflow since the region is extremely flat and uniform out to a distance of ten miles in all directions. Past ten miles, the topography is either flat or gently rolling. An analysis of atmospheric stagnation by Korshover has found between 150 and 175 stagnation days in the region during the 40-year period of 1936 through 1975 (Reference 2.3-10). Consequently, there is an average of only four cases of stagnating conditions occurring annually in the region. This agrees with Holzworth's estimate of an annual frequency of four stagnation periods (Reference 2.3-18). The annual average diffusion estimates, which are based upon climatology, would not be significantly altered by modifying the straight line Gaussian equation to attempt to simulate these infrequent air stagnation events. The second consideration cited in Regulatory Guide 1.111 applies to sites located in pronounced river valleys. While the HCGS site is located on the shore of the Delaware River, the river "valley" is extremely flat and open in this area. Typical valley airflows that 2.3-51 HCGS-UFSAR Revision 0 April 11, 1988

are associated with sharp "V-shaped" river valleys do not occur. The marshy land areas bordering the water are only slightly higher than the river level in the region. The third situation in which Regulatory Guide 1.111 states that spatial and temporal airflow variations may need additional considerations concerns coastal locations. The HCGS site is located on a man-made island in the Delaware River. It is located at a point where the river gradually widens into the Delaware Bay. From the site northward, the river is less than five kilometers (three miles) wide. south of the site, the river opens up into the bay, which eventually empties into the Atlantic Ocean, approximately 72 kilometers (45 miles) to the south-southeast. Since this site is not located on the coastline of a large body of water, such as an ocean or the Great Lakes, it should not be considered a coastal location. The site is not subject to the frequent sea-breeze mesoscale circulations commonly observed at coastal locations, that arise from the differential heating of the land and water surfaces. A PSE&G study showed that sea breeze regimes that were often present at regional sites directly on the Atlantic ocean generally do not affect the HCGS area (Reference 2.3-52). There was no evidence of substantial alteration of the synoptic airflow or of closed mesoscale circulations at the site. Additionally, the meteorological characteristics of the air flowing over the site from the waters of the Delaware Bay to the south-southeast are not significantly altered by passing over the site. Artificial Island is small, marshy and flat, and only '--# five kilometers (three miles) in length and 2.5 kilometers (1.5 miles) wide at the widest point. Airflows originating from directions other than south-southeast are not significantly affected because of their short over-water fetch. The PSE&G study concluded that the present meteorological tower location allows adequate and representative measurements of the airflows and atmospheric stability required to simulate atmospheric dispersion in the region. 2.3-52 HCGS-UFSAR Revision 8 September 25, 1996

2.3.5.3.4 Terrain Corrections Changes in terrain elevation, though very small in the immediate vicinity of the plant, have been applied at each receptor. Terrain heights above plant grade, which is 4 meters mean sea level (MSL), are used in the calculations, where applicable. The terrain height correction applied to any particular receptor is the highest terrain between the source and the receptor. 2.3.5.3.5 Atmospheric Stability Atmospheric stability classes are determined using the vertical temperature difference between the 300 and the 33-foot levels of the Artificial Island tower. The seven lapse rate classes are those recommended in Regulatory Guide 1.23 for stability classification. 2.3.5.3.6 Dispersion Coefficients The horizontal and vertical dispersion coefficients, sigma y and sigma z for each turbulence class, are computed using analytical approximations to the P-G sigma curves given in Regulatory Guide 1.111 Revision 1. These dispersion coefficients were developed for flat to rolling terrain, similar to that surrounding the Hope Creek site. 2.3.5.3.7 Dry Deposition 2.3.5.3.7.1 Depleted X/Q Values Relative depletion by dry deposition has been estimated in accordance with Regulatory Guide 1.111, Revision 1. The depleted by deposition X/Q values are obtained from the X/Q values by multiplying the X/Q values by the fraction remaining in the plume. These fractions are determined from Regulatory Guide 1.111, Revision 1, Figures 2 through 5. 2.3-53 HCGS-UFSAR Revision 0 April 11, 1988

2.3.5.3.7.2 D/Q Values Relative dry deposition has been estimated in accordance with Regulatory Guide 1.111, Revision 1. The relative deposition per unit area, D/Q, is obtained by:

1. Determining the relative deposition rate at each receptor, which is a function of distance from the source, source height, and atmospheric stability. This rate is obtained for Regulatory Guide 1.111, Revision 1, ground releases.

2. Multiplying the relative deposition rate by the fraction of the release transported into the sector.

3. Taking this product and dividing by the appropriate crosswind distance, which is the arc length of the sector at the point being considered.

2.3.6 References 2.3-1 H. J. Chritchfield, "General Climatology," Prentice Hall, Inc, Englewood Cliffs, NJ, pp. 148-151, 1966. 2.3-2 U.S. Department of Commerce, Wilmington, "Delaware Local Climatological," 1980 ed. 2.3-3 U.S. Department of Commerce, "Weather Atlas of the United States," June 1968, pp. 170-175, 228-234. 2.3-4 C. J. Neumann, G.W. Cry, E.L. Cass, and B.R. Jarvinen, "Tropical Cyclones of the North Atlantic Ocean," NOAA, U.S. Department of Commerce, Environmental Data Service. 1981. 2.3-5 D. V. Dunlap, "Climate of the States - New Jersey," U.S. Department of Commerce, NOAA Environmental Data Service, 1967. 2.3-54 HCGS-UFSAR Revision 0 April 11, 1988

2.3-6 U.S. Department of Commerce, "Climate of Delaware,"

          "Climatography of the States No. 60n NOAA, Environmental Data Service, 1977.

2.3-7 A. D. Pearson, "Tornado Data", National Severe Storm Forecast Center, Kansas City, November, 1982. 2.3-8 H. S. Thom, "Tornado Probabilities," "Monthly Weather Review," Vol 91, 1963. 2.3-9 J. H. Golden, "The Life Cycle of the Florida Keys Waterspout as the Result of Five Interacting Scales of Motion," PhD Dissertation, Florida State University, College of Arts and Sciences, 1973. 2.3-10 J. H. Golden, "Waterspouts and Tornadoes Over South Florida," Monthly Weather Review, Vol 99, No. 2, 1971. 2.3-11 Department of Commerce, "Local Climatological Data -Annual Summary with Comparative Data - Wilmington, Delaware," NOAA, Environmental Data Service, 1980. 2.3-12 M. A. Uman, "Understanding Lightning," Bek Technical Publications, Inc. Carnegie, PA, 1971. M. E. Pautz, ed, "Severe Local Storm Occurrences 1955-1967," U.S. Department of Commerce, ESSA Technical Memorandum WBTM FCST 12, 1969. 2.3-14 J. L. Baldwin, "Climates of the United States, U.S. Department of Commerce, Environmental Data Service, 1973. 2.3-15 S. A. Changnon, "The scales of Hail," Journal of Applied Meteorology, Vol 16, No. 6, 1977. 2.3-55 HCGS-UFSAR Revision 0 April 11, 1988

2.3-16 U.S. Department of Commerce, "Local Climatological Data Monthly Summary," NOAA, Wilmington, Delaware, National Climatic Center, Asheville, North Carolina, January 1977-December 1981. 2.3-17 I. Bennett, "Glaze - Its Meteorology and Climatology, Geographical Distribution, and Economic Effects," U.S. Army Quartermaster Research and Engineering Command, Technical Report EP-105, Natick, MA, 1959. 2.3-18 G. c. Holzworth, "Mixing Heights, Wind Speeds, and Potential for Urban Air Pollution Throughout the Contiguous United States," u.s. EPA, Office of Air Programs, Publication No. AP-101, 1972. 2.3-19 J. Korshover, "Climatology of Stagnating Anticyclines East of the Rocky Mountains, 1936-1975," NOAA, Environmental Research Laboratory Technical Memorandum ERT ARL-55, 1976. 2.3-20 L. T. Steyaert, et al, "Estimating Water Equivalent Snow Depth From Related Meteorological Variables," NOAA, Prepared for NRC, NUREG/CR-1389, 1980. 2.3-21 American National Standards Institute, "Building Code Requirements for Minimum Design Loads in Buildings and Other Structures," ANSI A 58.1-1972, 1972. 2.3-22 H. C. S. Thom. "Distribution of Annual Water Equivalent of Snow on the Ground," "Monthly Weather Review," Vol 94, No. 4, 1966. 2.3-23 F. P. Ho and J. T. Ridel, "Seasonal Variation of 10-Square-Mile Probable Maximum Precipitation Estimates - United States East of 105th Meridian," National Weather Service/NOAA, Hydrometeorological Report No. 53, Prepared for NRC, NUREG/CR-1486, 1980. 2.3-56 HCGS-UFSAR Revision 0 April 11, 1988

2.3-24 Nuclear Regulatory Commission: Regulatory Guide 1. 76, Design Basis Tornado for Nuclear Power Plants, (1974). 2.3-25 H. C. S. Thom, "New Distribution of Extreme Winds in the United States," Journal of the Structural Division, Proceeding of the American Society of Civil Engineering, 1968. 2.3-26 R. D. Marshall and H. C. S. Thom, "The Engineering Interpretation of Weather Bureau Records for Wind Loadings on Structures," by S.C. Hollister, January 27-28, 1969, proceedings of technical meeting concerning wind loads on buildings and structures National Bureau of Standards, Gaithersburg, Maryland, 1970. 2.3-27 U.S. Department of Commerce, "Annual Wind Distribution of Pasquill Stability Classes

STAR Program - Wilmington, Delaware, January 1971 December 1981," NOAA, Environmental Data Service National Climatic Center, Asheville, NC, 1982.

2.3-28 U.S. Department of Commerce, "Annual Wind Distribution of Pasquill Stability Classes - STAR Program - Wilmington, Delaware, January 1977 December 1981," NOAA, Environmental Data Service, National Climatic Center, Asheville, NC, 1982. 2.3-29 U.S. Department of Commerce, "Airport Climatological SUDDD.ary

Wilmington, Delaware," "Climatography of the United States No. 90 (1965-1974)," NOAA, Environmental Data Service, National Climatic Center, Asheville, NC, (1978).

2.3-30 Nuclear Regulatory Commission: Regulatory Guide 1.23, Revision 0, Onsite Meteorological Programs, 1972. 2.3-57 HCGS-UFSAR Revision 0 April 11, 1988

2.3-31 Public Service Electric and Gas Company, "Onsite and Regional Meteorological Analysis for the Hope Creek Generating Station Environmental Report Operating License State and Final Safety Analysis Report Submittals, (Section 2.3.2), (Data Period, January 1977 Through December 1981)". 2.3-32 D. B. Turner, "A Diffusion Model for an Urban Area," Journal of Applied Meteorology, Vol 3, No. 1, (1964). 2.3-33 R. E. Huschke, Ed, Glossary of Meteorology, American Meteorological Society, Boston, MA, 1970. 2.3-34 J. H. Carlson, R.A. Hollister, M. E. Smith, and F. P. Castelli. "Inadequacies of Atmospheric Stability Measurements and Recommendations for Improvement - Air Quality and Atmospheric Ozone," American Society for Testing and Materials, Special Technical Publications 653, 1978. 2.3-35 R. V. Portelli, "A Comparative Study of Experimentally Measured Atmospheric Stability and 'STAR Program' Predictions," Third Symposium On Atmospheric Turbulence, Diffusion and Air Quality, American Meteorological Society, Boston, MA 1976. 2.3-36 Laurman, J, "Modification of Local Weather by Power Plant Operation," EPRI Report BA-886-SR, TPS 76-660, August 1978. 2.3-37 U.S. EPA, "Guideline for Determination of Good Engineering Practice Stack Height," Office of Air Quality Planning and Standards, 1980. 2.3-38 J. Hali tsky, "Gas Diffusion Near Buildings, Meteorology and Atomic Energy" - 1968, D. H. Slad, ed., Chapter 5-S, 1968. 2.3-58 HCGS-UFSAR Revision 0 April 11, 1988

2.3-39 T. B. Smith and V. A. Mirabella, "Meteorological Effects of Cooling Towers at the SMUD Site," Appendix 3C, Rancho Seco Nuclear Generating Station Unit No. 1 Environmental Report, Sacramento Municipal Utility District, 1971. 2.3-40 M. L. Kramer. et al. , "Cooling Towers and the Environmental," Journal APCA, Vol 26, No. 6, pp. 582-584, 1976. 2.3-41 J. H. Coleman and T. L. Crawford "Characterization of Cooling Tower Plumes," from Paradise Steam Plant, Proceeding of the Symposium on Environmental Effects of Cooling Tower Emissions, 1978. 2.3-42 J. E. Carson, *Atmospheric Impacts of Evaporative Cooling Systems," Argonne National Laboratory Report ANL/ES-53, 1976. G. Spurr, "Meteorology and Cooling Tower Operation," Atmos. Environ., Vol. 8, pp. 321-324, 1974. 2.3-44 J. Seeman, et al., "Effects Produits sur 1' Agriculture par les Tours de Refroidissement dans 1' Environment des centrales Nucleaires," Department Etudes Generales Programmes, Sites - Environment, Paris, France, 1976. M. L. Kramer and D. E. Deymour, John E. Amos Cooling Tower Flight Program Data, December 1975 - March 1976; available A.E.P. Service Corporation, Environmental Engineering Division Canton, Oh, 1916. 2.3-46 M. L. Kramer, "Snowfall Observations from Natural Draft Cooling Tower Plwnes," Science, Vol 193, pp. 1239-1241, 1976. 2.3-59 HCGS-UFSAR Revision 0 April 11, 1988

2.3-47 Nuclear Regulatory Commission: Regulatory Guide 1.145, Atmospheric Dispersion Models for Potential Accident Consequence Assessments at Nuclear Power Plants. Issued for Comment 1979. 2.3-48 Nuclear Regulatory Commission: Regulatory Guide 1.111, Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light-Water-Cooled Reactors. Revision 1, 1977. 2.3-49 E. H. Markee, and J. R. Levine, *Probabilistic Evaluations of Atmospheric Diffusion Conditions for Nuclear Facility Design and Siting," Proceedings of the American Meteorological Society Conference on Probability and Statistics in Atmospheric Sciences, Las Vegas, NE, 1977, pp. 146-150. 2.3-50 G. E. Start, J. H. Gate, C.R. Dickson, N.R. Ricks, G. R. Ackermann, and J.F. Sagendorf, "Rancho Seco Building Wake Effects on Atmospheric Diffusion," NOAA Technical Memorandum ERL ARL-69, Air Resources Laboratories, Idaho Falls, Idaho, 1977. 2.3-51 J. R. Martin, ed, "Recommended Guide for the Prediction of the Dispersion of Airborne Effluents - Third Edition, n American Society of Mechanical Engineers, New York, New York, 1979. 2.3-52 Letter from R.L. Mittl to F.J. Miraglia dated June 30, 1981. NRC Docket No. 50-311. 2.3-60 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 2. 3-1 PERCENTAGE OF DAYS YITH VARIOUS HYDROMETERS DOVER DELAYARE AIR FORCE BASE 1942-1965 Month Fog Snow and/or Sleet 1li!.U. Thunderstorms Jan 43.7 4.1 0.4 0.6 Feb 45.0 3.4 0.2 0.9 Mar 48.4 2.7 3.7 Apr 44.4 0.3 0.2 8.9 May 49.0 0.9 16.6 Jun 55.3 0.4 17.1 Ju1 54.3 0.2 19.6 Aug 66.3 17.4 Sept 59.0 6.8 Oct 53.8 0.2 3.0 Nov 47.6 0.6 0.2 1.2 Dec 44.5 2.5 0.2 0.5 Annual 51.2 1.2 0.3 8.2

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.3-2 SNOWFALL (inches) PHILADELPHIA INTERNATIONAL AIRPORT Monthly Month Mean Maximum Jan 5.7 19.7 Feb 6.1 18.4 Mar 4.1 13.4 Apr 0.3 4.3 May T(l) T(l) Jun Jul Aug Sept Oct T(1) T(1) Nov 0.8 8.8 Dec 4.6 18.8 Annual 21.6 Length of record (yr) 28 (1) Trace of precipitation .

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.3-3 SNOWFALL (inches} TRENTON INTERNATIONAL AIRPORT Monthly 24-Hour Month Mean Maximum Maximum Jan 5.8 16.1 10.1 Feb 6.7 23.1 13.0 Mar 4.4 21.5 14.3 Apr 0.4 4.2 4.2 May T(l) T(l) T(l) Jun Jul Aug Sep Oct 0.1 1.6 1.6 Nov 1.0 13.0 7.7 Dec 4.9 21.5 16.6 Annual 23.3 Length of record {yr) 34 (1) Trace of precipitation .

HCGS-UFSAR 1 of 1 Revision 0 April 11. 1988

TABLE 2.3-4 DATA AVAILABILITY FOR ONSITE METEOROLOGICAL PARAMETERS JANUARY 1977 - DECEMBER 1981 Height Above Tower Grade, Data Availability, Meteorological Parameter ft percent Wind direction 33 92.4 150 97.3 300 97.4 Wind speed 33 96.1 150 97.3 300 97.4

Temperature difference Temperature 150 to 33 300 to 33 33 90.4 93.3 94.0 Dew point 33 83.2 Precipitation 7 91.2 Pressure 3 99.9
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TABLE 2.3-5 COMPARISON OF ANNUAL ONSITE WIND DIRECTION FREQUENCY DISTRIBUTIONS JANUARY 1977

DECEMBER 1981 Wind Instrument Height Above Tower Grade Directional 33 ft, 150 ft, 300 ft, Sector percent percent percent N 6.8 6.3 6.0 NNE 5.2 4.9 4.6 NE 4.8 5.2 4.6 ENE 3.1 3.1 3.1 E 2.8 2.8 2.7 ESE 2.6 2.1 1.9 SE 8.4 6.5 5.6 SSE 6.9 7.1 6.8 s 6.4 6.9 7.1 ssw 5.8 6.0 6.5 sw 6.0 6.7 7.4 WSW 5.8 5.7 5.7 w 7.8 8.5 9.2 WNW 9.5 9.2 8.9 NW 11.6 12.1 12.2 NNW 6.5 7.2 7.8 Calm 0.3 <0.1 0.1
HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988
COMPARISON OF ANNUAL ONSITE WITH WILMINGTON NWS WIND DIRECTION FREQUENCY DISTRIBUTIONS 5-Year Concurrent Period(l) Long Term Wilmington NWS Onsite NWS 1972 - 1981 Directional 33 feet, 20 feet, 20 feet, Sector percent percent percent N 6.8 7.6 7.4 NNE 5.2 2.5 2.8 NE 4.8 3.8 3.9 ENE 3.1 4.1 4.7 E 2.8 4.0 4.0 ESE 2.6 1.8 2.0 SE 8.4 3.6 3.2 SSE 6.9 4.4 4.5 s 6.4 10.1 10.2 ssw 5.8 4.0 4.2 sw 6.0 6.1 5.9 WSW 5.8 5.8 6.1 w 7.8 10.0 9.6 WNW 9.5 11.2 10.8 NW 11.6 14.9 13.6 NNW 6.5 6.4 7.1 Calm 0.3 6.0 5.6 (1) January 1977 to December 1981 .
HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.3-7 ONSITE COMPARISON OF AVERAGE WIND SPEEDS JANUARY 1977 - DECEMBER 1981 Wind Instrument Height Above Tower Grade Combined 33 ft, 150 ft, 300 ft, Months mph mph mph Jan 9.9 14.8 17.2 Feb 9.7 14.1 16.8 Mar 10.5 15.4 18.1 Apr 9.8 14.2 16.5 May 8.5 12.1 14.0 Jun 8.6 11.9 13.7 Ju1 7.9 10.5 12.4 Aug 7.8 10.2 11.9 Sep 8.3 11.4 13.7 Oct 8.6 12.7 15.1 Nov 8.9 13.5 16.1 Dec 8.8 13.9 16.3 Annual 8.9 12.9 15.1

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.3-8 WILMINGTON NATIONAL WEATHER SERVICE AVERAGE WIND SPEEDS(l) (2 ) Period of Record 1977-1981, 1972-1981, Months mph mph Jan 11.4 10.4 Feb 10.8 10.7 Mar 11.4 11.4 Apr 10.6 10.6 May 9.1 9.2 Jun 8.8 8.9 Jul 8.2 8.1 Aug 7.7 7.7 Sep 8.4 8.2 Oct 8.8 8.6 Nov 9.8 9.6 Dec 10.0 9.9 Annual 9.6 9.4 I (1) U.S. Department of Commerce, "Wind Direction by Pasquill Stability Classes, STAR Program, Wilmington, Delaware," NOAA, Environmental Data Services, National Climatic Center, 1982. (2} Location of wind speed sensor height is at 20 feet above ground level. 1 of 1 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 2.3-9 ONSITE TEMPERATUREMEANS AND EXTREMES JANUARY 1977 - DECEMBER 1981 Tem:Eerature 2 oc(l) Combined Hourly Hourly Months Mean Maximum Minimum Jan -2.1 15.5 -18.5 Feb -0.9 16.5 -18.5 Mar 5.4 24.5 -13.0 Apr 11.6 29.8 -2.6 May 16.6 29.0 4.0 Jun 20.8 32.0 9.5 Ju1 23.8 34.5 12.5 Aug 23.6 32.5 12.0 Sep 19.7 31.5 7.0 Oct 12.4 24.5 0.5 Nov 7.9 21.5 -4.0 Dec 2.5 19.5 -15.5 Annual 11.7 34.5 -18.5 (1) Temperature is measured at the 33-foot level .

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.3-10 OOSITE :H<:XJRLY TEMPERATURE ~CY DIS1RIBUl'IONS JANUARY1977 - DECEMBER 1981 Month lJanuaryto June~ Temperature(!) Jan Feb Mar A~r ~ June oc St111 Percent Sum Percent Sum Percent Sun Percent Sum Percent Sum Percent 32.5 - 34.9 0 o.o 0 o.o 0 0.0 0 o.o 0 o.o 0 o.o 30.0 - 32.4 0 o.o 0 o.o 0 o.o 0 o.o 0 0.0 30 0.9 27.5 - 29.9 0 o.o 0 o.o 0 o.o 11 0.3 43 1.2 129 4.0 25.0 - 27.4 0 0.0 0 o.o 0 o.o 20 0.6 121 3.5 332 10.2 22.5 - 24.9 0 o.o 0 o.o 16 0.4 41 1.2 205 5.9 643 19.8 20.0 - 22.4 0 o.o 0 o.o 18 0.5 114 3.3 471 13.6 917 28.3 17.5 - 19.9 0 o.o 0 o.o 30 0.8 226 6.4 704 20.3 592 18.3 15.0 - 17.4 6 0.2 12 0.4 80 2.2 379 10.8 758 21.8 386 11.9 12.5 - 14.9 13 0.4 31 0.9 202 5.5 647 18.5 529 15.2 165 5.1 10.0 - 12.4 30 0.8 89 2.7 320 8.8 821 23.4 403 11.6 46 1.4 7.5 - 9.9 67 1.9 194 5.8 620 17.0 653 18.6 166 4.8 1 o.o 5.0 - 7.4 181 5.1 265 8.0 737 20.2 424 12.1 67 1.9 0 o.o 2.5 - 4.9 389 11.0 379 11.4 655 17.9 105 3.0 5 0.1 0 0.0 o.o - 2.4 607 17.1 440 13.3 498 13.6 55 1.6 0 o.o 0 o.o

          -2.5    - -0.1     638     18.0     562    16.9        248    6.8        7      0.2         0   o.o       0   o.o
          -5.0 -     -2.6    681     19.2     598    18.0        145    4.0        2      0.1         0   o.o       0   0.0
          -7.5 -     -5.1    520     14.7     388    11.7         33    *o.9       0      o.o         0   o.o       0   0.0
         -10.0 -     -7.6    219      6.2     182     5.5         32    0.9        0      o.o         0   o.o       0   o.o
         -12.5    - -10.1    129      3.6     117     3.5         15    0.4        0      o.o         0   o.o       0   0.0
         -15.0 -    -12.6      49     1.4     . 50    1.5          3    o.o        0      o.o         0   o.o       0   0.0
         -17.5 -    -15.1      11     0.3        7    0.2          0    o.o        0      0.0         0   o.o       0   0.0
         -20.0  *- -17.6         7    0.2        5    0.2          0    o.o        0      o.o         0   o.o       0 0.0 Total            3,547     100.0   3,319   100.0      3,652  100.0    3,505   100.0     3,472  100.0   3,241 100.0 1 of 2 HCGS-UFSAR                                                                                                                   Revision 0 April 11, 1988

TABLE 2.3-10 (Cont) Month (Jull to December~ T~rature ( 1 ) Jul Aug Se~ Oct Nov Dec Annual c Sum Percent Sum Percent Sum Percent Sun Percent Sum Percent SliD. Percent Sum Percent 32.5 - 34.9 52 1.5 6 0.2 0 o.o 0 o.o 0 o.o 0 o.o 58 0.1 30.5 - 32.4 136 3.9 137 4.0 13 0.4 0 o.o 0 o.o 0 o.o 316 0.8 27.5 - 29.9 381 11.0 366 10.7 79 2.4 0 o.o o.o 0 o.o 0 o.o o.o 1,009 2.4 25.0 - 27.4 791 22.9 797 23.2 264 8.1 0 0 o.o 0 2,325 5.6 22.5 - 24.9 957 27.7 991 28.9 555 17.1 36 LO 0 o.o 0 o.o 3,444 8.4 20.0 - 22.4 684 19.8 616 18.0 776 23.9 131 3.7 7 0.2 0 o.o 3,734 9.1 17.5 15.0

                 -- 19.9 299 17.4 117 8.7 3.4 332 149 9.7 4.3 640     19.7 17.0 303 523 8.6 14.9 85 207 2.6 6.3 12 32 0.3 0.9 3,223 3,200 7.8 7.8 551 12.5      14.9 36         1.0    35       1.0   234      7.2    805     22.9     416   12.6     46      1.3 3,159     7.7 10.0 7.5
                 -  12.4 9.9 0

0 o.o o.o 2 0 0.1 0.0 103 31 3.2 1.0 681 641 19.4 18.2 449 595 13.6 18.0 126 336 3.6 9.5 3,070 3,304 7.4 8.0 5.0 7.4 0 o.o 0 0.0 3 0.1 298 8.5 628 19.0 616 17.5 3,219 7.8 2.5 4.9 0 o.o 0 o.o 0 o.o 93 2.6 513 15.5 687 19.5 2,826 6.9 o.o 2.4 0 o.o 0 o.o 0 o.o 7 0.2 293 8.9 664 18.9 2,564 6.2

          -2.5   -  -0.1     0     o.o      0      o.o      0      o.o       0     o.o      94    2.8   495     14.1  2,044     5.0
          -5.0   -  -2.6     0     o.o      0      o.o      0      o.o       0     o.o      14    0.4   272      7.7  1, 712    4.2
          -7.5   -  -5.1     0     o.o      0      o.o      0      o.o       0     o.o       0    o.o   160      4.5  1,101     2.7
          -10.0  -  -7.6     0     o.o      0      o.o      0      o.o       0     0.0       0    o.o     47     1.3     480    1.2
          -12.5  -  -10.1    0     o.o      0      o.o      0      o.o       0     o.o       0    o.o     20     0.6     281    0.7
          -15.0  -  -12.6    0     o.o      0      o.o      0      0.0       0     o.o       0    o.o      6     0.2     108    0.3
          -17.5  -  -15.1    0     o.o      0      o.o      0      o.o       0     o.o       0    o.o      2     0.1      20    o.o
          -20.0  -  -17.6    0     o.o      0      o.o      0      o.o       0     o.o       0    0.0      0     o.o      12    o.o Total           3,453  100.0 3,431     100.0 3,249     100.0  3,518    100.0  3,301   100.0 3,521    100.0 41,209   100.0 (1)    Temperature is measured at the 33-foot level.

2 of 2 HCGS-UFSAR Revision 0 April 1l, 1988

TABLE 2.3-11 ONSITE DIURNAL 'I'EMPERATURE VARIATIONS JANUARY1977 - DECEMBER 1981 Tem~rature 1 °C(l) Hour Jan Feb Mar t\:12!: ~ Jun Jul &:!{ fum Oct Nov Dec Arm.ual 1 -2.6 -1.9 4.2 10.0 14.9 19.2 22.1 22.1 18.4 11.3 7.0 1.8 10.4 2 -2.8 -2.2 3.8 9.6 14.5 18.8 21.8 21.8 18.1 11.0 6.8 1.7 10.1 3 -2.9 . -2.4 3.6 9.3 14.1 18.5 21.5 21.5 17.8 10.7 6.6 1.5 9.9 4 -3.1 ~2.6 3.4 9.0 13.8 18.2 21.2 21.3 17.6 10.5 6.5 1.3 9.7 5 -3.2 -2.8 3.2 8.8 13.6 18.0 21.0 21.0 17.4 10.3 6.3 1.2 9.5 6 -3.4 -3.0 2.9 8.6 13.5 17.9 20.9 20.9 17.2 9.9 6.3 1.0 9.3 7' -3.6 -3.1 2.7 8.9 13.8 18.2 21.1 20.9 17.1 9.8 6.2 0.9 9.3 8 -3.6 -3.0 3.2 9.9 14.6 18.9 21.8 21.4 17.4 9.8 6.2 0.8 9.7 9 -3.2 -2.4 4.2 11.0 15.5 19.8 22.8 22.4 18.2 10.5 6.9 1.1 10.5 10 -2.6 -1.5 5.2 12.0 16.6 20.8 23.9 23.5 19.4 11.8 7.9 1.9 11.4 11 -1.9 -0.6 6.1 12.8 17.6 21.8 24.9 24.4 20.5 13.0 8.8 2.8 12.4 12 -1.3 0.3 6.8 13.5 18.4 22.6 25.5 25.2 21.3 14.0 9.5 3.5 13.2 13 -1.0 1.0 7.5 14.1 19.2 23.1 26.1 25.8 21.9 14.7 10.0 4.1 13.8 14 -0.6 1.4 8.1 14.4 19.7 23.6 26.5 26.2 22.4 15.1 10.5 4.4 14.2 15 0.2 1.6 8.5 14.7 19.9 23.9 26.8 26.5 22.7 15.3 10.5 4.6 14.5 16 0.2 1.5 8.4 14.7 19.8 23.7 26.7 26.5 22.8 15.3 10.3 4.4 14.4 17 0.4 1.4 8.1 14.4 19.5 23.5 26.6 26.2 22.6 14.9 9.6 4.0 14.1 18 -1.0 0.8 7.4 13.9 19.1 23.3 26.3 25.8 22.1 14.4 9.0 3.5 13.6 19 -1.3 0.2 6.6 13.1 18.3 22.6 25.7 25.2 21.3 13.7 8.5 3.2 13.0 20 -1.6 -0.2 6.1 12.3 17.5 21.9 24.9 24.5 20.5 13.0 8.1 2.9 12.4 21 -1.9 -0.6 5.6 11.6 16.9 21.0 24.1 23.8 19.9 12.4 7.7 2.6 11.8 22 -2.2 -0.9 5.3 11.2 16.3 20.5 23.6 23.3 19.4 12.0 7.5 2.4 11.4 23 -2.4 -1.2 5.0 10.8 15.8 20.1 23.0 22.9 18.9 11.6 7.2 2.1 n.o 24 -2.5 -1.4 4.7 10.4 15.5 19.7 22.6 22.5 18.6 11.3 7.0 2.0 10.7 (1) Temperature is measured at the 33-foot level. 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 2.3-12 TEMPERATUREMEANS AND EXTREMES ~ JANUARY 1977 - DECEMBER 1981 Artificial Island 1 °F(l) Wilmington NWS Station 1 °F{ 2 ) Combined Hourly Hourly Hourly Hourly Months Mean Maximum Minimum Hun Maximum Minimum Jan 28.2 60 -1 27.4 64 -3 Feb 30.4 62 -1* 29.2 69 -6 Mar 41.7 76 9 42.1 82 7 Apr 52.9 86 27 53.0 87 25 May 61.9 84 39 63.1 91 30 Jun 69.4 90 49 69.7 94 44 Jul 74.8 94 55 76.0 98 50 Aug 74.5 91 54 75.8 95 49 Sep 67 .5* 89 45 68.5 98 40 Oct 54.3 76 33 54.1 82 30 ~ Nov 46.2 71 25. 46.3 76 22 Dec 36.5 67 -4 35.2 70 2 Annual 53.1 94 -1 53.4 98 -6 (1) Sensor height 33 feet. (2) Source, U.S. Department of Commerce, "Local Climatological Data Annual Summary with Comparative Data - Wilmington, Delaware," NOAA, Environmental Data Service, 1977-1981. ~ 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 2.3-13

WIUIINGTON NWS TEMPERATUREMEANS AND EXTREMES ( 1 )

Te!Eerature 1 0 F Months Mean( 2) Maximum( 3) Minimum( 3 ) Jan 32.0 75.0 -4.0 Feb 33.6 74.0 -6.0 Mar 41.6 86.0 -6.0 Apr 52.3 91.0 22.0 May 62.4 95.0 30.0 Jun 71.4 99.0 41.0 Ju1 75.8 102.0 50.0 Aug 74.1 101.0 46.0 Sep 67.9 100.0 36.0 Oct 57.2 91.0 24.0 Nov 45.7 85.0 14.0 Dec 34.7 72.0 -2.0 Annual 54.0 102.0 -6.0 (1) Source, U.S. Department of Commerce, "Local C~imato1ogical Data Annual Summary with Comparative Data - Wilmington, Delaware,* NOAA, Environmental Data Service, 1977-1981. (2) Period of record 1941 to 1970. (3) Period of record 1948 to 1981 .

HCGS*UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.3~14 ONSITE DEW POINT TEMPERATURE MEANS AND EXTREMES JANUARY 1977 - DECEMBER 1981 Absolute Humidi~ 1 gl.m3 Combined Hourly Hourly Months Hun Maximum Minimum Jan -7.5 12.8 -23.4 Feb -6.6 12.5 -20.5 Mar -1.5 14.7 -21.7 Apr 3.6 18.3 -13.1 May 10.4 21.1 -12.2 Jun 14.6 24.7 *1.6 Jul 18.3 26.7 4.4 Aug 18.8 28.4 6.1 Sep 14.4 26.1 -1.1 Oct 6.9 19.7 -5.6 Nov 2.3 18.3 *13.3 Dec -3.6 15.8 -24.7 Annual 5.1 28.4 -24.7

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2.3-15 ONSITE HOURLY DEW POINT TEMPERA'ItlRE FREX:J)ENCY DIS'miBlTI'I<>>lS JANUARY 1977 - DBCIMBBR 1981 Dew Point Month ~ Janua.r:v to June! T~raturet oc Jan Feb Mar Ap_r !'1!!x June Sum Percent Sum Percent Sun Percent Sun Percent Sum Percent Sun Percent 27.5- 29.9 0 o.o 0 o.o 0 o.o 0 o.o 0 o.o 0 0.0 25.0 - 27.4 0 o.o 0 o.o 0 o.o 0 o.o 0 o.o 0 o.o 22.5 - 24.9 0 o.o 0 o.o 0 o.o 0 o.o 0 o.o 51 1.5 20.0 - 22.4 0 o.o 0 o.o 0 0.0 0 o.o 39 1.3 428 12.8 17.5- 19.9 0 o.o 0 o.o 0 0.0 1 o.o 332 10.9 672 20.0 15.0 - 17.4 0 o.o 0 o.o 0 o.o 68 1.9 473 15.6 662 19.7 12.5 - 14.* 9 2 0.1 1 0.0 47 1.3 251 7.2 445 14.7 527 15.7 10.0 - 12.4 . 34 0.9 36 1.2 94 2.6 325 9.3 434 14.3 436 13.0 7.5- 9.9 48 1.3 86 3.0 257 7.1 411 l1.8 386 12.7 260 7.8 5.0 - 7.4 70 1.9 108 3.7 314 8.6 489 14.0 330 10.9 171 5.1 2.5 - 4.9 121 3.3 126 4.3 377 10.3 467 13.4 251 8.3 98 2.9 o.o - 2.4 162 4.4 159 5.5 409 11.2 484 13.8 185 6.1 42 1.3

      -2.5 -    -0.1     334     9.2    286    9.9      614   16.9        311      8.9        97       3.2       7    0.2
      -5.0 -    -2.6     550    15.1    300   10.3      444   12.2        330      9.4       45        1.5       0    o.o
      -7.5-     -5.1     486    13.3    318   11.0      397   10.9        203      5.8        10       0.3       0    o.o
     -10.0 -    -7.6     484    13.3    455   15.7      272    7.5        108      3.1         4       0.1       0    o.o
     -12.5 -   -10.1     519    14.2    468   16.1      231    6.3         43      1.2         2       0.1       0    o.o
     -15.0 -   -12.6     427    11.7    301   10.4      113    3.1          4      0.1         0       o.o       0    o.o
     -17.5-    -15.1     259     7.1    162    5.6       44    1.2          0      o.o         0       o.o       0    o.o
     -20.0 -   -17.6     104     2.9     95    3.3       22    0.6          0      o.o         0       o.o       0    o.o
     -22.5 -   -20.1       45    1.2      2    0.1        8    0.2          0      o.o         0       o.o       0    0.0
     -25.0 -   -22.6        4    0.1      0    o.o        0    o.o          0      o.o         0       o.o       0    o.o Total             3,649   100.0  2,903  100.0    3,643  100.0     3t495    100.0     3,033     100.0   3,354   100.0 1 of 2 HCGS-UFSAR                                                                                                                   Revision 0 April 11, 1988

Dew Point TABLE 2.3-15 (Cont)

Month (Jul;r to December) T~rature, Jul Awt Se:g ~t Nov Deo Annual oc Sun Percent SliD Percent SliD Percent Sun Percent SliD Percent SUm Percent Stm Percent 27.5 to 29.9 0 0.0 3 0.1 0 o.o 0 o.o 0 o.o 0 o.o 3 o.o 25.0 to 27.4 24 o~g 35 1.4 8 0.3 0 o.o 0 o.o 0 o.o 67 0.2 22.5 to 24.9 377 13.8 391 15.9 42 1.7 0 o.o 0 o.o 0 o.o 861 2.4 20.0 to 22.4 805 29.4 885 36.1 304 12.6 0 o.o 0 o.o 0 o.o 2,461 6.7 17.5 to 19.9 611 22.3 354 14.4 425 17.5 73 2.6 19 0.7 0 o.o 2,487 6.8 15.0 to 17.4 362 13.2 330 13.5 510 21.1 223 8.0 75 2.7 10 0.3 2,713 7.4 12.5 to 14.9 255 9.3 196 8.0 368 15.2 250 8.9 149 5.3 3 0.1 2,494 6.8 10.0 to 12.4 186 6.8 158 6.4 303 12.5 305 10.9 153 5.5 28 0.9 2,492 6.8 7.5 to 9.9 77 2.8 79 3.2 194 8.0 303 10.8 261 9.3 116 3.6 2,478 6.8 5.0 to 7.4 41 1.5 21 0.9 121 5.0 507 18.1 346 12.4 186 5.8 2,704 7.4 2.5 to 4.9 1 ' o.o 0 0.0 121 5.0 597 21.3 311 11.1 261 8.2 2,731 7.5 0.0 to 2.4 0 o.o 0 o.o 22 0.9 319 11.4 344 12.3 419 13.2 2,545 7.0

      -2.5  to    -.1     0 o.o       0    o.o     4    0.2     158   5.6     398  14.2 442 13.9    2,651      7.3
      -5.0  to   -2.6     0 o.o       0    o.o     0    o.o      60   2.1     414  14.8 479 15.0    2,622      7.2
      -7.5  to   -5.1     0 o.o       0    o.o     0    o.o       4   0.1     217   7.8 359 11.2    1,994      5.5
     -10.0  to   -7.6     0 o.o       0    o.o     0    o.o       0   o.o      92   3.3 263   8.3   1,678      4.6
     -12.5  to  -10.1     0 o.o       0    o.o     0    o.o       0   o.o      18   0.6 282 8.9     1,563      4.3
     -15.0  to  -12.6     0 o.o       0    o.o     0    o.o       0   o.o       1   o.o 244   7.7   1,090      3.0
     -17.5  to  -15.1     0 o.o       0    o.o     0    o.o       0   o.o       0   o.o  64 2.0       529      1.5
     -20.0  to  -17.6     0 o.o       0    o.o     0    o.o       0   o.o       0   o.o  14 0.4       235      0.6
     -22.5  to  -20.1     0 o.o       0    o.o     8    o.o       0   0.0       0   o.o   7   0.2      62      0.2
     -25.0  to  -22.6     0 o.o       0    o.o     0    o.o       0   o.o       0   o.o   7   0.2      11      o.o Total            2,739 100.0 2,452 100.0 2,422 100.0 2,799 100.0 2,798 100.0 3,184 100.0      36,471    100.0 2 of 2 HCGS-UFSAR                                                                                                           Revision 0 April 11, 1988

TABLE 2.3-16 CNSITE DIURNAL DEW roiNT 'ID1PERATURE JANUARY1977 - DECIJ<tBER 1981 Absolute Hunidit;E 1 s.Lm3 Hour Jan Feb Mar Am: Jtm Jul

                                    ~                        AY&       ~     Oct Nov Dec  ~

1 -7.5 -6.7 -1.3 3.9 10.5 15.1 18.5 19.0 14.6 2 7.2 2.6 -3.3 5.3

           -7.5  -6.8  -1.5 3.8     10.5    15.0     18.5    19.1       14.5 7.2 2.5 -3.4 5.2 3  -7.5 -6.7  -1.6 3.7     10.4    14.9     18.5    18.8      14.4  7.1 2.5 -3.6 5.2 4  -7.6  -6.9 -1.8  3.7     10.5    14.8     18.3    18.8      14.4  6.9 2.3 -3.7 5.0 5  -7.6  -6.9 -1.8  3.7     10.5    14.8     18.3    18.8      14.4  6.9 2.3 -3.7 5.0 6  -7.7  -6.9 -1.8  3.7     10.4    14.7     18.3    18.8      14.3  6.8 2.2 -3.8 5.0 7  -7.7  -6.8 -2.0  3.8     10.4    14.8     18.4    18.8      14.2  6.7 2.2 -3.9 5.0 8  -7.7  -6.8 -1.9  3.7     10.4    14.7     18.3    18.8      14.3  6.8 2.2 -3.8 5.0 9  -7.6  -6.8 -2.0  3.4     10.1    14.7     18.3    18.8      14.4  7.0 2.2 -3.8 10                                                                                 4.9
           -7.7  -6.8 -2.1  2.9     10.1    14.5    18.2     18.6      14.2  7.0 2.2 -3.7 4.8 11  -7.6  -6.8 -2.0  2.8      9.9    14.2    17.8     18.5      14.1  6.8 2.1 -3.7 4.7 12  -7.7  -6.8 -2.0  2.9      9.8    14.3    17.8     18.4      14.2  6.6 2.1 -3.9 4.7 13  -7.7  -6.8 -1.9  3.0      9.8    14.1    17.7     18.4      14.2  6.6 2.1 -3.8 4.7 14  -7.5  -6.8 -1.7  2.9      9.7    13.9    17.7     18.3      14.5  6.3 2.0 -3.9 4.8 15  -7.3  -6.7 -1.6  2.9      9.9    14.0    17.8     18.4      14.6  6.5 2.0 -3.8 4.9 16  -7.3  -6.7 -1.5  3.0      9.8    14.1    17.9     18.5      14.4  6.6 2.2 -3.7 4.9 17  -7.3  -6.7 -1.4  3.1     10.0    14.2    18.0     18.6      14.4  6.8 2.5 -3.4 5.1 18  -7.3  -6.4 -1.1  3.6     10.1    14.3    18.4     18.7      14.7  7.3 2.7 -3.1 5.3 19  -7.1  -6.1 -0.8  3.9     10.7    14.6    18.7     18.9      14.8  7.3 2.6 -3.1 5.5 20  -7.1  -5.9 -0.7  4.3    11.0     14.9    18.8     19.1      14.8  7.3 2.6 -3.1 5.6 21  -7.2  -6.0 -0.6  4.3    11.3     15.2    18.8     19.2      14.7  7.2 2.6 -3.3 5.7 22  -7.3  -6.1 -0.7  4.3    11.5     15.3    18.9     19.2      14.7  7.1 2.5 -3.2 5.7 23  -7.4  -6.1 -0.8  4.3     11.3    15.2    18.8     19.1      14.6  7.1 2.4 -3.5 5.5 24  -7.5  -6.2 -0.8  4.1    11.0     15.1    18.8     19.0      14.4  7.1 2.4 -3.6 5.4 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 2.3-17 ONSITE RELATIVE HUMIDITY MEANS AND EXTREMES JANUARY 1977 - DECEMBER 1981 Relat!v~ BYmiditi. ;Qexeent Combined Hourly Hourly Months Mean Maximum Minimum Jan 66 100 28 Feb 64 100 23 Mar 64 100 18 Apr 62 100 15 May 71 100 18 Jun 70 100 18 Ju1 73 100 30 Aug 76 100 32 Sep .74 100 30 Oct 72 100 31 Nov 71 100 19 Dec 69 100 20 Annual 69 100 15

HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 2. 3-18 ONSITB HOURLY RELATIVE HUMIDITY ~CY DISTRIBUl'IONS JANUARY 1977 - DECEMBER 1981 Relative Month !Januarl:: to Jtme~ Humidity, Jan Feb Mar A'fi.r l1a.:¥: Jtme

          %      Sl.Dn Percent   Sum Percent     Sum Percent Sum Percent            Sum     Percent Sum Percent 100          23    0.7     45     1.6       12     0.3         72      2.1   150         5.0     54   1.8 95 -   99     165      4.7   148    5.2       184     5.1        217      6.4   280         9.4    158 5.2 90 -   94     271      7.7   173    6.0      264      7.4        240      7.0   299       10.1     256   8.4 85 ._  89     157      4.5   156    5.4      239      6.7        227      6.6   301       10.1     310 10.2 80 -   84     188      5.4   126     4.4      209     5.8        199      5.8   258          8.7   302   9.9 75 -   79     205      5.9   126     4.4      259     7.2        197      5.8   218          7.3   310 10.2 70 -   74     270      7.7   173    6.0       258     7.2        221      6.5   212          7.1   266 8.7 65 -   69     401    11.4    259    9.0      255      7.1        231      6.8    166         5.6   285   9.3 60 -   64     471    13.4    287   10.0      257      7.2        194      5.7    179        6.0    244   s.o 55 -   59     453    12.9    370   12.9      317      8.8        216      6.3    165         5.5   210 6.9 50 -   54     434    12.4    372   13.0      312      8.7        246      7.2   157          5.3   169 5.5 45 -   49     281     8.0    287   10.0      327      9.1        263      7.7   165          5.5   174   5.7 40 -   44     132      3.8   177    6.2      270      7.5        243      7.1    111        3.7    142   4.7 35 -   39       38     1.1   107    3.7      237      6.6        196      5.7   105         3.5     91   3.0 30 -   34       12     0.3    39     1.4      118     3.3        183      5.4   102         3.4     57   1.9 25 -   29        3     0.1    19    o. 7       51     1.4        160      4.7     78        2.6     19 0.6 20 -   24        0    o.o      3    0.1        13    0.4          91      2.7   267         0.9      4 0.1 15 -   19        0     o.o     0    o.o         3     0.1         21      0.6      4        0.1      1   o.o 10 -   14        0    0.0      0    o.o         0    o.o           0     o.o       0        o.o      0   0.0 5-     9        0    o.o      0    0.0         0    0.0           0     o.o       0        o.o      0   0.0 0 -   4         0    o.o      0    o.o         0    o.o           0     o.o       0        o.o      0   0.0 Total      3,504    100.0  2,867  100.0    3,585   100.0      3,417   100.0   2,976    100.0     3,052 100.0 1 of 2 HCGS-UFSAR                                                                                                         Revision 0 April 11, 1988

TABLE 2.3-18 (Cont) Relative Month {Jul:i to December~ Humidity, Jul A!!S Sep Oct Nov Dec Annual

          %      Sum   Percent    Sum   Percent  Sum Percent Sum Percent Sum Percent Sum Percent Sun Percent 100      39     1.5       59     2.4     24    1.0        111     4.1      83    3.2   108     3.5    780   2.2 95 -   99    184     7.0      151     6.2    140    5.9        203    7.5      277   10.6   215     7.0  2,322   6.6 90 - 94      280   10.6       294    12.0    283   11.9       240     8.9      276   10.6   252     8.2  3,128   8.9 85 - 89      313   11.9       351    14.4    279   11.7        215    7.9      171    6.6   187     6.1  2,906   8.2 80 - 84      306   11.6       330    13.5    301   12.6       249     9.2      129    4.9   196     6.4  2,793   7.9 75 - 79      267   10.1       318    13.0    286   12.0        223    8.2      168    6.4   227     7.4  2,804   8.0 70 - 74      245     9.3      240     9.8    229    9.6       272    10.0      214    8.2   246     8.0  2,846   8.1 65 - 69      216     8.2      155     6.3    184    7.7        255    9.4      255    9.8   2'70    8.8  2,932   8.3 60 - 64      188     7.1      138     5.7    183    7.7        225    8.3      211    8.1   286     9.4  2,863   8.1 55 - ,59     194     7.4      134     5.5    157    6.6        197    7.3      248    9.5   309    10.1  2,970   8.4 50 - 54      133     5.0      105     4.3    127    5.3        184    6.8      202    7.7   261     8.5  2,702   7.7 45 - 49      111     4.2       90     3.7     87    3.7        152    5.6      177    6.8   213     7.0  2,327   6.6 40 - 44       81     3.1       47     1.9     54    2.3        110     4.1      97    3.7   158     5.2  1,622   4.6 35 - 39       70     2.7       29     1.2     42    1.8         58     2.1      59    2.3    70     2.3  1,102   3.1 30 - 34       13     0.5        3     0.1      9    0.4         15    0.6       23    0.9    42     1.4    616   1.8 25 - 29        0     o.o        0     o.o      0    o.o          0    o.o       13    0.5     14    0.5    357   1.0 20 - 24        0     o.o        0     o.o      0    o.o          0    o.o        7    0.3      6}}

LR-N23-0027, Updated Final Safety Analysis Report, Rev. 26,

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