NL-14-106, 10 C.F.R. 50.59 Safety Evaluation and Supporting Analyses Prepared in Response to the Algonquin Incremental Market Natural Gas Project Indian Point Nuclear Generating Unit Nos. 2 & 3

10 C.F.R. 50.59 Safety Evaluation and Supporting Analyses Prepared in Response to the Algonquin Incremental Market Natural Gas Project Indian Point Nuclear Generating Unit Nos. 2 & 3

ML14253A339
Person / Time
Site:	Indian Point
Issue date:	08/21/2014
From:	Dacimo F Entergy Nuclear Northeast, Entergy Nuclear Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML14253A338	List: NL-14-106, 10 C.F.R. 50.59 Safety Evaluation and Supporting Analyses Prepared in Response to the Algonquin Incremental Market Natural Gas Project Indian Point Nuclear Generating Unit Nos. 2 & 3
References
NL-14-106
Download: ML14253A339 (26)

Text

EntergQ Nuclear Northeast Indian Point Energy Center

'~Entergy, 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-2055 Fred Dacimo Vice President Operations License Renewal SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 NL-14-106 August 21, 2014 U.S. Nuclear Regulatory Commission Document Control Desk 11545 Rockville Pike, TWFN-2 F1 Rockville, MD 20852-2738

SUBJECT:

10 C.F.R. 50.59 Safety Evaluation and Supporting Analyses Prepared in Response to the Algonquin Incremental Market Natural Gas Project Indian Point Nuclear Generating Unit Nos. 2 & 3 Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64

REFERENCES:

1. Algonquin Gas Transmission, LLC, Abbreviated Application of Algonquin Gas Transmission, LLC for a Certificate of Public Convenience and Necessity and For Related Authorizations, Docket No. CP14-96-000 (Feb. 28, 2014) ("Certificate Application").

2. Algonquin Incremental Market Project Draft EnvironmentalImpact Statement Algonquin Gas Transmission, LLC, August 6, 2014, Docket No. CP14-96-000, FERC/EIS-0254D

3. MOTION TO INTERVENE AND COMMENTS OF ENTERGY NUCLEAR INDIAN POINT 1, LLC, ENTERGY NUCLEAR INDIAN POINT 2, LLC, ENTERGY NUCLEAR INDIAN POINT 3, LLC AND ENTERGY NUCLEAR OPERATIONS, INC. Algonquin Gas Transmission, LLC) Docket No.

CP14-96-000, April 8, 2014

Dear Sir or Madam:

As the Nuclear Regulatory Commission ("NRC") is aware, Algonquin Gas Transmission, LLC

("AGT") has proposed to construct and operate a new natural gas pipeline near the Indian Point Entergy Center ("IPEC"). The Project, known as the Algonquin Incremental Market Project

("AIM Project"), involves the construction and operation of about 37 miles of natural gas pipeline and associated facilities to expand natural gas transportation service to Connecticut, Rhode Island, and Massachusetts. The majority of the pipeline facilities would replace existing SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 When Enclosure 2 is detached, the remainder of this letter may be made publicly available

NL-14-106 Docket Nos. 50-247 and 50-286 Page 2 of 4 SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 Algonquin pipelines, but the Project also includes the installation of new 42-inch diameter pipeline near the southern boundary of IPEC to replace the existing 26-inch pipeline in vicinity of IPEC which will remain in place but idled. On February 28, 2014, AGT filed a formal application with the Federal Energy Regulatory Commission ("FERC" or "Agency") related to the AIM Project (Reference 1).

On August 6, 2014, FERC issued the draft environmental impact statement ("EIS") for the AIM Project (Reference 2). As it relates to IPEC, the draft EIS states as follows:

Based on our consultation with NRC, Entergy is required to assess any new safety impacts on its IPEC facility and provide that analysis to the NRC. Algonquin has coordinated with Entergy to provide information about its proposed pipeline, and Entergy is currently performing a Hazards Analysis. To ensure that no new safety hazards would result from the AIM Project, we are recommending that Algonquin file the final conclusions regarding any potential safety-related conflicts with the IPEC based on the Hazards Analysis performed by Entergy.

FERC's conclusions in the draft EIS were based, in part, on comments Entergy submitted to FERC to assist the Agency in identifying issues for evaluation in the EIS (Reference 3). Entergy noted in its comments to FERC that the existing AGT system has been operating safely next to IPEC for several decades, and evaluations of the potential hazards posed by the existing pipelines, conducted pursuant to NRC regulations and guidance, establish that the existing pipelines do not impair the safe operation of IPEC. The proposed AIM Project, however, expands the existing AGT system, including pipeline capacity and pressure. Thus, the potential for increased nuclear safety risks, including in terms of the probability and consequences of a potential malfunction or failure of the expanded natural gas pipeline near IPEC, must be evaluated and found to be acceptable in accordance with applicable NRC regulations.

Accordingly, while such occurrences are unlikely, Entergy must analyze any increased risk and consequences of such events prior to FERC's approval of the project. Entergy further noted that, depending on the results of the analysis, prior NRC review and approval of the new hazards analysis could be required before the project can be approved by FERC. FERC received numerous other scoping comments from members of the public and government officials concerning the safety of the Project and its proximity to IPEC. Thus, there is significant public interest in this project and its potential impacts on IPEC.

As noted in the EIS, Entergy has worked closely with AGT to better understand the scope of the project and confer regarding means to avoid any potential adverse impacts to IPEC. As a direct result of those efforts, Entergy and AGT have agreed to a comprehensive set of design and installation enhancements for piping routed near IPEC. These enhancements include, but are not limited to, thicker piping, thicker corrosion protection, greater burial depth, and installation of protective reinforced concrete mats to impede access to the buried piping.

Consistent with applicable NRC regulations and guidance, Entergy prepared the enclosed 10 C.F.R. § 50.59 Safety Evaluation related to the proposed AIM Project. Entergy also prepared two supporting evaluations; (1) Consequences of a Postulated Fire and Explosion Following the SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 When Enclosure 2 is detached, the remainder of this letter may be made publicly available

NL-14-106 Docket Nos. 50-247 and 50-286 Page 3 of 4 SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 Release of Natural Gas from the Proposed New AIM 42" Pipeline Taking a Southern Route Near IPEC and an Analysis of the Causes of and (2) Determination of Exposure Rates Associated with a Failure of the Proposed AIM 42" Natural Gas Pipeline Near IPEC (also enclosed and collectively referred to as the "Hazards Analyses"). Both supporting analyses were prepared for Entergy by The Risk Research Group, the consultant that prepared the hazards analysis for the existing pipelines near IPEC.

As documented in the attached Hazards Analyses, Entergy has concluded that based on the proposed routing of the 42-inch pipeline further from safety related equipment at IPEC and accounting for the substantial design and installation enhancements agreed to by AGT, the proposed AIM Project poses no increased risks to IPEC and there is no significant reduction in the margin of safety. Accordingly, as documented in the enclosed 10 C.F.R. § 50.59 Safety Evaluation, Entergy has concluded that the change in the design basis external hazards analysis associated with the proposed AIM Project does not require prior NRC approval.

Entergy's comments on the AIM Project draft EIS are due to be filed with FERC by September 29, 2014. Given the current status of the AIM Project, Entergy believes this is the last opportunity as a matter of right for Entergy to inform FERC as to the results of the Hazards Analysis, whether additional mitigation is necessary, and whether prior NRC review and approval is required. In addition, FERC requested that AGT file the final conclusions regarding any potential safety-related conflicts with IPEC based on the Hazards Analysis performed by Entergy by that same date.

As noted above, Entergy has determined that there are no increased risks to Indian Point and, pursuant to 10 CFR § 50.59, has concluded that prior NRC review and approval is not required.

In our submittal to FERC we plan to point out that as part of the routine inspection program NRC always has the right to review and challenge any analysis done pursuant to 10 CFR 50.59. Unless NRC chooses to perform such a review we cannot guarantee that they would ultimately concur with our position. Therefore we will suggest that prior to approving the Project, FERC should consider conferring with the NRC before reaching a conclusion regarding the potential hazards posed by the AIM project on IPEC and whether any additional mitigation is necessary. Accordingly, we are forwarding to the NRC the enclosed Safety Evaluation and Hazards Analyses and are prepared to answer any questions NRC may have on the Analyses or support inspections of the same.

Please withhold the hazards analysis (Enclosure 2) under 10 CFR 2.390 as security related information.

SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 When Enclosure 2 is detached, the remainder of this letter may be made publicly available

NL-14-106 Docket Nos. 50-247 and 50-286 Page 4 of 4 SECURITY-RELATED INFORMATION -WITHHOLD UNDER 10 CFR 2.390 If you have any questions, or require additional information, please contact Mr. Robert Walpole, Regulatory Assurance Manager, at [914] 254-6710.

Sincerely, FRD/sp

Enclosures:

1. 10 C.F.R. 50.59 Safety Evaluation 2 Hazards Analysis (SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 cc: Mr. Douglas Pickett, Senior Project Manager, NRC NRR DORL Mr. William M. Dean, Regional Administrator, NRC Region 1 NRC Resident Inspector Mr. John B. Rhodes, President and CEO, NYSERDA w/o Enclosure 2 Ms. Bridget Frymire, New York State Dept. of Public Service w/o Enclosure 2 SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 When Enclosure 2 is detached, the remainder of this letter may be made publicly available

SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 ENCLOSURE 1 TO NL-14-106 10 C.F.R. 50.59 SAFETY EVALUATION ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOs. 2 and 3 DOCKET NOs. 50-247 50-286 SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390 When Enclosure 2 is detached, the remainder of this letter may be made publicly available

10 CFR 50.59 EVALUATION FoRM Sheet 1 of 21 r

I. OVERVIEW / SIGNATURES' Facility: IP2/IP3 Evaluation # / Rev. #:

Proposed Change I Document: Installation of a New 42" Natural Gas Pipeline South of IPEC Description of Change: Installation of New 42" Natural Gas Pipeline South of Gypsum Plant and crossing IPEC Property Near Switchyard / GT2/3 Fuel Oil Storage Tank.

Summary of Evaluation:

The proposed pipeline was evaluated under the criteria of 10 CFR 50.59 and the evaluation shows that current Nuclear Regulatory Commission criteria were satisfied that would permit the pipeline to be installed without a license amendment requiring NRC approval Backaround The Indian Point Energy Center (IPEC) is traversed by two natural gas pipelines owned and operated by Spectra Entergy. The pipelines are 26 in. and 30 in. in diameter and operated at a pressure of 600-650 psig and 600-750 psig, respectively. The two gas pipelines traverse the owner-controlled area and are physically located closer to Indian Point Unit 3 (IP3) than Indian Point Unit 2 (IP2). The two lines are buried about 3 ft. deep in a trench formed in excavated rock. Portions of the pipelines at the shoreline of the Hudson River exit the trench and are above ground. The nearest approach of the buried portion of the pipelines to safety related structures, systems and components (SSC) is about 400 ft. The nearest above ground portion is approximately 800 ft. from the nearest safety-related structure (diesel generator building).

The initial licensee and the Atomic Energy Commission considered the hazards posed by these pipelines during the initial licensing process of 1P3, and determined that the presence of the gas pipelines did not endanger the safe operation of IP3 (Reference 1). Section 2.2 of the AEC's safety evaluation report (SER) for IP3 describes the Staff's conclusions regarding this analysis that the rupture of these gas pipelines would not impair the safe operation of IP3 (Reference 2).

On September 27, 1997 the New York Power Authority (NYPA) submitted the Individual Plant Examination of External Events (IPEEE) report for IP3 (Reference 3). In that report, it evaluated the susceptibility of IP3 to damage to the pipelines from seismic events. NYPA concluded that the probability of occurrence was low enough that the pipelines could be screened out as a seismic vulnerability. NYPA also considered pipeline ruptures from other causes, such as an inadvertent overpressure condition. Although NYPA stated that a vapor cloud rupture scenario could subject some IP3 structures to overpressures exceeding 1 psi, it concluded that the probability of an accidental leak from the line leading to such an event was extremely low. The NRC Staff's evaluation of the IP3 IPEEE did not identify any concerns with that approach (Reference 4).

In March 2003, questions were raised regarding the safety of the existing natural gas pipelines that pass through the Indian Point site, and suggested that they could be subject to sabotage. At the request of NRC Region I, the NRC Staff reviewed the prior evaluations of the lines and associated potential external hazards to the safe operation of the facility. The Staff's review is documented in an 1 Signatures may be obtained via electronic processes (e.g., PCRS, ER processes), manual methods (e.g., Ink signature),

e-mail, or telecommunication. if using an e-mail or telecommunication, attach it to this form.

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 2 of 21 April 25, 2003 NRC internal memorandum (Reference 5). The NRC Staff made an assessment of the risks associated with the potential for large releases of natural gas from the pipelines in the vicinity of IP3 given the statements made in the IP3 IPEEE, and the focus of prior external hazards evaluations on the likelihood of an accidental pipe rupture. The NRC Staff also considered intentional acts to damage the line(s) in its gas pipeline hazard assessment, which is not available to the public for security-related reasons. The NRC's April 25, 2003 memorandum states: "For a large rupture and resulting fire, the staff found that safety-related structures would not be significantly affected. For unconfined vapor cloud ruptures, the staff found that the factors involved to achieve a rupture creating sizeable overpressures make the probability for occurrence very low. However, the NRR staff believes that this aspect should be further evaluated by the Office of Nuclear Safety and Incident Response (NSIR) in conjunction with Region I" In March 2008, the NRC Staff requested information from Entergy as a result of a concern from a member of the public that there are "weak spots" in the IPEC security defense/structure, including a National Guard security position known as "Point 8." That request included any analyses or calculations supporting Entergy's conclusions regarding the vulnerability of Point 8. In an April 23, 2008 letter (ENOC-08-00021) to the NRC, Entergy explained that Point 8 encompasses the above-ground pressurized gas piping and valves that are part of the Algonquin natural gas pipelines in the Owner Controlled Area (OCA) at IPEC. It noted that although the IPEEE had examined an accidental rupture of the gas pipelines, no evaluation of sabotage on the gas pipelines within Point 8 previously had been performed. Entergy further explained that it had implemented additional compensatory measures to minimize the potential for such an event while it performed the additional assessment requested by NRC. Those measures are described in Entergy's April 23, 2008 letter.

As a follow-up to the Request for Information, Entergy completed an evaluation in August 2008 of the consequences of an assumed rupture of the two gas pipelines as a result of a sabotage on Point 8.

IPEC Engineering completed that evaluation using inputs from an analysis performed by Risk Research Group, Inc. In that analysis, which Entergy submitted to the NRC on September 30, 2008 (see ENOC-08-00046), Entergy considered the following hazards created by a postulated breach and rupture of the pressurized aboveground portions of the pipelines: (1),potential missiles, (2) an over-pressurization event, (3) a vapor cloud (or flash) fire, (4) a hypothetical vapor cloud explosion, and (5) a jet fire. Entergy's August 2008 evaluation concluded that "[tlhe concern that an attack on Point 8 would result in a lot of damage and casualties is not substantiated to the extent the Security Plan and Safe Shutdown capabilities of the plants remain assured in the event of an attack and rupture of the exposed portions of the Algonquin natural gas pipelines within Point 8." The IP3 Updated Final Safety Analysis Report (UFSAR), Rev. 3, Section 2.2.2, discusses the pipelines and lists the 2008 report as a reference.

On October 25, 2010, a member of the public filed a 10 C.F.R. § 2.206 petition requesting that the NRC order Entergy to demonstrate that it has the capability to protect the public in the event of a rupture, failure, or fire on the gas pipelines that cross the Indian Point site. The petition also requested that the NRC review all available information, and request any necessary information from Entergy to ensure compliance with all NRC regulatory requirements related to external hazards. In a letter to the petitioner dated March 31, 2011, the NRC stated that it had reviewed previous licensee and NRC reports related to this issue and "did not identify any violations of NRC regulations or any new information that would change the staff's previous conclusion that the pipelines do not endanger the safe or secure operation of IP2 or IP3."

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 3 of 21 Proposed AIM Pipeline Expansion Project Spectra Energy Transmission LLC / Algonquin Gas Transmission, LLC (hereinafter Spectra or AGT)has filed with FERC a proposal to expand its natural gas transmission capacity, discussed above, by installing a new 42 inch diameter pipeline that transmits gas at higher pressures than the current pipelines described above. For purposes of this evaluation, once installed the existing 26 inch pipeline and 30 inch pipeline are assumed to remain in use. The 42 inch pipeline is currently proposed to cross the Hudson River south of Indian Point, be routed on the west side of Broadway where it enters the IPEC owner controlled area before passing under Broadway and near the IPEC switchyard and the Gas Turbine 2/3 Fuel Oil Storage Tank (GT 2/3 FOST) and eventually joining with the existing natural gas pipelines. The proposed routing is referred to in this evaluation as the

'southern route" (The term "southern route" is the term used by Spectra to describe the final selected pipe routing for the new 42 inch pipeline). Only natural gas would be transmitted through these pipelines (Reference 6). In response to certain issues identified by Entergy with regard to the proposed routing of the new 42-in pipeline near IPEC, Spectra has stated that it would take additional design and construction measures on a - ...... . f the new pipeline to further limit the potential for adverse effects on the continued safe operation of Indian Point.

While the proposed 42 inch pipeline is further from IP2 and IP3 structures, systems and components (SSC) within the Security Owner Control Area (SOCA) used to control access to the main plant area than the existing pipelines, the new pipeline has a larger diameter than the existing lines and operates at a higher pressure, and therefore is a change to the current licensing basis for external hazards located near IP2 and IP3. The potential effects of the proposed pipeline on IP2 and IP3 have been evaluated using current NRC guidelines. Specifically, the Standard Format and Content Regulatory Guide 1.70 identifies the information to be provided for offsite events that could create a plant hazard.

The NUREG 0800 Standard Review Plan (SRP) sections 2.2.1 to 2.2.3 (Rev 3) further discuss information to be assessed against current regulations and the descriptions and evaluations to be considered for acceptability. RG 1.91 Rev 2 provides guidance on how the evaluation should be performed and states the evaluation is to consider structures, systems and components (SSC) important to safety as well as safety related SSCs.

Desiqn and Construction

1) Design As discussed further below, the proposed southern routing must consider potential adverse effects on SSCs important to safety nearer to the southern route, including the GT 2/3 Fuel Oil Storage Tank (FOST), electrical switchyard (includes lines to and from Indian Point),

Emergency Operations Facility (EOF)/ meteorological tower, and the city water tank.

Additional features also considered, include the FLEX Storage Building, IP2 and IP3 Steam Generator Mausoleums, and the fuel oil tanker. The design of the 42 inch gas pipeline is to use X-52 to X-65 steel, to require a wall thickness of 0.469 to 0.510 inches, and to bury the pipeline underground with a minimum of 3 feet to the surface from the top of the pipeline (References 7 and 8). Spectra Energy however, has indicated (Reference 8) that, in the area where a postulated pipeline rupture could adversely affect IPEC SSCs ITS, about 3935 feet of the pipeline would be of enhanced design and construction to further limit the already very low potential for a gas pipeline rupture. The pipeline design will incorporate the following additional design and construction features:

0 The Pipe Grade will be upgraded to X-70, (70,000 psig minimum yield strength and 82,000 psig minimum tensile strength) and manufactured to API 5L standards like all pipeline.

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUA'iON FORM Sheet 4 of 21 The 0.720 inch wt (thickness in inches), X-70 material operating at the maximum operating pressure (MAOP) of 850 psi is over 40% greater wt than required by the United States Department of Transportation's Pipeline and Hazardous Materials Safety Administration Natural Gas Pipeline Minimum Federal Safety Standards (49 CFR Part 192) (the "DOT Code"). The resulting wt exceeds Class 4 requirements, the most stringent DOT Code classification. The actual length of the enhanced portion of the gas pipeline will be subject to field survey verification of the proposed Algonquin Gas Transmission, LLC (AGT) 42 inch diameter AIM Project pipeline shown in the enclosed report "Consequences of a Postulated Fire and Explosion Following the Release of Natural Gas from the Proposed New AIM 42 inch Pipeline Taking a Southern Route Near IPEC" (hereinafter called Report).

The following information was provided by Spectra (Reference 8) regarding the design enhancements:.

o The 0.720 inch X-70 piping is virtually impervious to one of the most frequent causes of pipe rupture (excavation). The Pipeline Research Committee International (PRCI) report "Modified Criteria to Evaluate the Remaining Strength of Corroded Pipelines" documents the size of defect required to cause a pipeline rupture, based upon over 100 pipe defect burst tests. ASME B31G "Manual for Determining Remaining Strength of Corroded Pipelines" is a guideline used in the pipeline industry that applies this research to predict pipe defect rupture pressure, including the Modified B31 G equation.

There is also a PRCI report (PR-244-9729) "Reliability Based Prevention of Mechanical Damage to Pipelines" which is available to the public through the Center for Frontier Engineering Research (C-FER), and Section 6 provides a model, based upon excavator data, which can be used to predict the force required to puncture a pipeline. Puncture force is calculated from Equation 6.4 on p.28 of the referenced PRCI report (PR-244-9729), using a very conservatively low sample ultimate tensile strength of 79,300 psi and a relatively sharp excavator tooth of 0.5 x 1.5 inches. The weight of the excavator is based upon Figure 6.3 on p.31 of the PRCI report, but the required excavator weight to damage the proposed enhanced piping is so great that it must be extrapolated well beyond the end of the graph. If the curved relationship were continued, it would never reach the 508 kN (kilo newton) force required to puncture the 0.720 inch wall pipe, but by projecting an over-conservative straight line to continue the upper right slope of the curve, an excavator weight of 193 tons at 508 kN would be necessary to damage the enhanced piping. The probability of excavator size comes from Figure 6.1 on p.30 of the PRCI report. This type excavator has not been seen at IPEC as can be demonstrated by the fact the largest Caterpillar backhoe (385CL) is less than half that size at 94 tons o The criterion for whether a defect fails as a leak versus a rupture comes from NG-18 research. The "Through Wall Collapse" (TWC) equation was developed many years ago from analyses of numerous full-scale pressure tests of pipe by Dr. Kiefner and others at Battelle. A puncture is nowhere close to the leak-rupture line, so it is very apparent that a puncture of the pipe wall would only cause a leak and would not rupture the pipe.

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 5 of 21 The Modified B31G equation is:

(b) Modified B31G. For z ! 50, 2

M = (1 + 0.6275z - 0.003375z )1/2 For z > 50, M = 0.032z + 3.3 I - 0.85(d/t)I SF = Sf. - O.85(d/t)/M z - /-t=

Inputting a 70% depth defect with length of 20' into the above equation produces a minimum failure pressure SF = 1121 psig, whereas the maximum operating pressure of the pipeline is only 850 psig.

• All pipe is procured from vendors who have passed a stringent quality audit, and full-time mill inspection is performed by AGT during pipe production. AGT pipe specifications require additional quality testing and integrity requirements above and beyond API-5L standards.

• Standard coating for all the pipe will be Fusion Bond Epoxy (FBE) coating 16 mils (thousands of an inch) nominal; 12 -14 mils is industry standard. Coating for the enhanced pipe will be a dual layer with FBE and Abrasion Resistant Overlay ("ARO"). AGT will specify 25 mils of coating, consisting of 16 mils of FBE and 9 mils of ARO. ARO will provide for enhanced protection during installation and provide additional external corrosion protection. Internal corrosion protection will also be provided (1.5 mils of FBE).

" A physical barrier to impede access to the buried piping will be installed above the enhanced pipe. Installation will include two (2) parallel sets of fiber-reinforced concrete slabs with dimensions of 3 feet wide by 8 feet long by 6 inch thick (a cross-sectional view of the proposed design is provided in Appendix B, Exhibit C of the attached report). Yellow warning tape will be placed at the top of the concrete slabs and another layer 1 foot above the pipe.

• The latest state of the art cathodic protection will be used on the pipeline.

Piping was or will be purchased to AGT Pipe standards ES-PP3.11 and/or ES-PP3D.3. Mill inspection will follow standards IS-IP1.1, IS-IC1.1, and IS-IC2.1. Non-Destructive Examination

("NDE") will follow APL-5L PSL-2 requirements as well as AGT Standards in the mill. All pipe is tested in the mill in accordance with AGT Standards,

2) Construction The construction of the new pipeline is not going to result in any issues affecting plant operation. The construction pathway will result in construction under the power lines from the switchyard, but appropriate protective measures will be used to prevent interference with the EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FoRM Sheet 6 of 21 power lines. The construction pathway will not require construction above the existing gas pipeline and (per Reference 8):

" There will be no blasting for rock removal in the region of the enhanced design pipe.

• The Broadway crossing on the west side of the tank will be made using an open cut installation method. Spectra will ensure that traffic flow is maintained during construction, and access to the Indian Point facility is not impeded.

• Work near electrical power lines will follow industry standard practices and OSHA regulations.

• The enhanced gas pipeline would be buried to a minimum greater depth of 4 feet from the top of the pipeline to the surface and buried 5 feet under Broadway.

• The pipeline coatings will be inspected electronically as the enhanced pipeline is lowered into the ground. A coating fault test is normally performed to detect any faults prior to backfill. In addition a Direct Current Voltage Gradient (DCVG) survey will be performed to ensure coating integrity following enhanced pipe installation and partial backfill.

Spectra pipe installation welders must be qualified by destructive testing. To maintain their qualification, they must have a qualifying weld inspected via non-destructive testing and found to be acceptable at intervals not exceeding 6 months. A welder must re-qualify via destructive testing every 2 years. The welder's qualifications and continuation of qualification must be documented. All pipeline/piping welding procedures shall be qualified by destructive testing.

All welding (including temporary welds) will be in compliance with approved welding procedures and performed by an AGT approved qualified welder.

All field welds for enhanced gas pipeline shall also undergo Non Destructive Examination which will include as a minimum 100% radiography of all field butt welds for Class Locations 1.

The normal radiography requirement is 10% of all butt welds. All installed pipe will also undergo a full hydrostatic test in the field after installation to verify pipe integrity per the DOT Code requirements and AGT standards.

3) Ongoing Pipeline Maintenance and Monitoring Activities Spectra monitors the cathodic protection levels on its pipeline system in accordance with the 49 CFR § 192.465(a): "Each pipeline that is under cathodic protection must be tested at least once each calendar year, but with intervals not exceeding 15 months, to determine the cathodic protection meets the requirements of 49 CFR § 192.463." Spectra also performs an assessment of its pipeline system in high consequence areas in accordance with 49 CFR § 192.921, which will include IPEC. Subsequent reassessments are done at a maximum of 7 years in accordance with 49 CFR § 192.939. Cathodic protection surveys will confirm, at test sites installed along the pipeline, that cathodic protection voltage potentials are maintained at levels necessary to prevent corrosion. Sophisticated inline inspection tools will be run through the pipeline at least once every seven years to identify internal and external corrosion, and other defects. These inspection tools continue to advance and can detect, size and locate pipe anomalies with high accuracy. Any defect noted by a tool run are tracked and corrected as necessary.

The methods used to prevent pipeline overpressure have been successful for many decades at compressor stations. Spectra has stated that it never had a pipeline rupture attributable to over-pressuring a pipeline. There are multiple levels of protection:

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 7 of 21

• The first level of protection is a precautionary alarm at 5 psi below the maximum allowable operating pressure (MAOP) to alert the Gas Control center in Houston to determine ifany action needs to be taken and to ensure conditions are under control.

" The automated control system for the compressor unit is set to ensure that the discharge pressure does not exceed the pipeline MAOP.

• It is extremely rare that pressure ever exceeds MAOP, but ifthis were to happen, a "critical" alarm would alert the local station attendant and the Gas Control center in Houston to take immediate manual control measures (e.g., slowing or shutting down compressors, adjusting conditions at nearby facilities, etc.) to reduce pressure. These personnel are trained on how to respond to abnormal operating conditions.

• The Stony Point station control system is set to automatically shut down the unit and close the unit isolation valves when pipeline pressure reaches MAOP for 305 consecutive seconds.

• The Stony Point station control system is set to automatically shut down the unit and close the unit isolation valves when pipeline pressure reaches MAOP + Ipsig for 10 consecutive seconds.

• The turbine compressor units also have a manufacturer-installed, automatic shutdown system to protect the equipment from damage and the set point on this device is lowered to trigger at 15 psi above MAOP.

" In the very unlikely event that the pressure were to continue to climb, the standard over pressure protection ("OPP") system is in place to automatically shut down all compressors at the station, and-this is set at the OPP limit specified in the DOT Code 49 CFR § 192.169 (or 34 psi above MAOP for the new 42 inch pipeline).

• Relief valves are also in place at most compressor stations, as noted, but are part of an older operating strategy and are not relied upon as the primary means of overpressure protection (gas emissions and noise from relief valves are undesirable).

• The pressure control and overpressure devices are reliable, and the accuracy of set points is verified at periodic time intervals in accordance with the DOT Code.

Maintenance records are audited by internal teams as well as the United States Department of Transportation's Pipeline and Hazardous Materials Safety Administration auditors to ensure compliance.

4) Actions in the event of a rupture The existing pipeline automation and control system, which will be used for the proposed new 42 inch pipeline near IPEC, does not provide for an automatic isolation of the closest upstream and downstream mainline valves upon the detection of a pipeline rupture. The two closest actuated valves are located at mile post 2.61 on the west side of the Hudson River and at mile post 5.47 just east of IPEC. They would require an operator to take action to close these valves. The system, however, is monitored 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day and an alarm would immediately alert the control point operator, located in Houston, Texas, of an event and isolation would be initiated. This would result in all the gas between these valves at the time of closure being able to vent or burn. The estimated time to respond to the alarm (less than one minute) and the EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 8 of 21 closure time of the valves (about one minute) was used as the basis for an assumed closure time of three minutes for the analysis performed in the attached report.

The next closest isolation valve locations are at the Stony Point Compressor Station mile post 0.0 and at MLV 15 at mile post 10.52. Valve operation follows the requirements of the DOT Code and is tested on a periodic basis to ensure compliance with code requirements.

Evaluation Criteria The Standard Format and Content Guide (RG 1.70) requires in Section 2.2.3.1 (Determination of Design Basis Events) that design basis events external to the nuclear plant be defined as those accidents that have a probability of occurrence on the order of about lx10"7 per year or greater and have potential consequences serious enough to affect the safety of the plant to the extent that Part 100 guidelines could be exceeded. It further states:

• "The determination of the probability of occurrence of potential accidents should be based on an analysis of the available statistical data on the frequency of occurrence for the type of accident under consideration and on the transportation accident rates for the mode of transportation used to carry the hazardous material. Ifthe probability of such an accident is on the order of 10"' per year or greater, the accident should be considered a design basis event, and a detailed analysis of the effects of the accident on the plant's safety-related structures and components should be provided."

• Ruptures - Accidents involving detonations of high explosives, munitions, chemicals, or liquid and gaseous fuels should be considered for facilities and activities in the vicinity of the plant where such materials are processed, stored, used, or transported in quantity. Attention should be given to potential accidental ruptures that could produce a blast overpressure on the order of 1 psi or greater at the plant, using recognized quantity-distance relationships. Missiles generated in the rupture should also be considered.

• Flammable Vapor Clouds (Delayed Ignition) - Accidental releases of flammable liquids or vapors that result in the formation of unconfined vapor clouds should be considered. Assuming that no immediate rupture occurs, the extent of the cloud and the concentrations of gas that could reach the plant under 'Worst-case" meteorological conditions should be determined. An evaluation of the effects on the plant of detonation and deflagration of the vapor cloud should be provided. Missiles generated in the rupture should also be considered.

• Fires - Accidents leading to high heat fluxes or to smoke, and nonflammable gas- or chemical-bearing clouds from the release of materials as the consequence of fires in the vicinity of the plant should be considered. Fires in adjacent industrial and chemical plants and storage facilities and in oil and gas pipelines, brush and forest fires and fires from transportation accidents should be evaluated as events that could lead to high heat fluxes or to the formation of such clouds.

• Missiles Generated by Events near the Site - Identify all missile sources resulting from accidental ruptures in the vicinity of the site. The presence of and operations at nearby industrial, transportation, and military facilities should be considered. Missile sources that should be considered with respect to the site include, among others, pipeline ruptures.

NUREG 0800 is the NRC Standard Review Plan (SRP) which provides the NRC review criteria and acceptance criteria. The current revision of SRP Section 2.2.3 acceptance criteria states EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUAT1ON FORM Sheet 9 of 21 "Specific SRP acceptance criteria acceptable to meet the relevant requirements of the NRC's regulations identified above are as follows for the review described in this SRP section. The SRP is not a substitute for the NRC's regulations, and compliance with it is not required. However, an applicant is required to identify differences between the design features, analytical techniques, and procedural measures proposed for its facility and the SRP acceptance criteria and evaluate how the proposed alternatives to the SRP acceptance criteria provide acceptable methods of compliance with the NRC regulations.

1. Event Probability The identification of design-basis events resulting from the presence of hazardous materials or activities in the vicinity of the plant or plants is acceptable if all postulated types of accidents are included for which the expected rate of occurrence of potential exposures resulting radiological dose in excess of the 10 CFR 50.34(a)(1) as it relates to the requirements of 10 CFR Part 100 is estimated to exceed the NRC staff objective of an order of magnitude of 10-7 per year.

If data are not available to make an accurate estimate of the event probability, an expected rate of occurrence of potential exposures resulting in radiological dose in excess of the 10 CFR 50.34(a)(1) as relates to the requirements of 10 CFR Part 100, by an order of magnitude of 10-6 per year is acceptable if, when combined with reasonable qualitative arguments, the realistic probability can be shown to be lower.

2. Design-Basis Events The effects of design-basis events have been adequately considered, in accordance with 10 CFR 100.20(b), if analyses of the effects of those accidents on the safety-related features of the plant or plants have been performed and measures have been taken (e.g., hardening, fire protection) to mitigate the consequences of such events.

The SRP says that the "technical rationale for application of these acceptance criteria to the areas of review addressed by this SRP section is discussed in the following paragraphs:

1. Offsite hazards that have the potential to cause onsite accidents leading to the release of significant quantities of radioactive fission products, and thus pose an undue risk of public exposure, should have a sufficiently low probability of occurrence and should fall within the scope of the low-probability-of-occurrence required by 10 CFR 100.20(b) based on criterion of 10 CFR 50.34(a)(1) as it relates to the requirements of 10 CFR Part 100.

2. Data are often not available to enable the accurate calculation of probabilities because of the low probabilities associated with the events under consideration. Accordingly, the expected rate of occurrence of potential exposures in excess of the 10 CFR 50.34 (a)(1) requirements as they relate to the requirements of 10 CFR Part 100 guidelines by an order of magnitude of 10-6 per year is acceptable if, when combined with reasonable qualitative arguments, the realistic probability can be shown to be lower.

Regulatory Guide ("RG") 1.91 describes methods for nuclear power plant licensees that the NRC Staff finds acceptable for evaluating postulated failures at nearby facilities and transportation routes. One method includes the calculation of minimum safe distance based on estimates of TNT-equivalent mass of potentially explosive materials. Once blast load effects are calculated, the safe distances can EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 10 of 21 be based on peak positive incident overpressure below one pound per square inch, or 1.0 psi for which no significant damage would be expected. The RG goes on to say "Ifthe facility with potentially explosive materials or the transportation routes are closer to SSCs important to safety than the distances computed using Equation (1), the applicant or licensee may show that the risk is acceptably low on the basis of low probability of failures. A demonstration that the rate of exposure to a peak positive incident overpressure in excess of 1.0 psi (6.9 kPa) is less than 1x10-8 per year when based on conservative assumptions, or lxI07 per year when based on realistic assumptions, is acceptable.

Due consideration should be given to the comparability of the conditions on the route to those of the accident database. Ifthe facility with potentially explosive materials or the transportation routes are closer to SSCs important to safety than the distances computed using Equation (1), the applicant may show through analysis that the risk to the public is acceptably low on the basis of the capability of the safety-related structures to withstand blast and missile effects associated with detonation of the potentially explosive material."

Results of Evaluation of Proposed Southern Route Pipeline Rupture Event The potential failure of the proposed new 42 inch pipeline along the more-distant (from IP2 and IP3) southern route has been evaluated for both exposure rates and effects.

The NRC noted in the discussion in RG 1.91, Rev 2, that 'The NRC staff determined that if the probability of an failure at a nearby facility or the exposure rate, based on the theory in the Federal Emergency Management Agency's Handbook of ChemicalHazardAnalysis Procedures,November 2007 (Ref. 11) for material in transit, can be shown to be less than lx10-7 per year, then the risk of damage caused by failures is sufficiently low" Chapter 11.0 "Probability Analysis Procedures,"

Section 11.6 "Transportation of Hazardous Materials By Pipeline," has developed a formula for estimating the frequency of pipeline releases considering the size of the pipeline (> 20 inches diameter applies to this pipeline), the length of pipe under consideration (about 3935 feet) to exclude damage to the switchyard and the GT 2/3 FOST), and size of the breach (guillotine breaks are considered which is 20% of all breaks).

For the proposed pipeline, the FEMA "Handbook of Chemical Hazard Analysis Procedures" identifies (page 11-28) the accident rate for pipelines with diameters greater than or equal to 20 inches is 5E-4 releases per year-mile. The length of pipe that could affect the SSC important to safety is greater than the enhanced gas pipeline of 3935 feet or 0.745 miles. This length corresponds to the probability of 3.73E-4. This value is not used to assess the 42 inch gas pipeline but is used to conclude that the rupture of the gas pipeline must be considered as a design basis event under NRC guidance. The value is not used to assess the gas pipeline because the data base from which frequency is determined is not applicable to this gas pipeline (it includes mostly pipelines of steel but also considers pipes of other materials, considers pressure of up to several thousand pounds per square inch (psi), pipes of various different diameters, and pipes of older and less rigorous design).

Consideration of the gas pipeline rupture as a design basis event requires a hazard analysis to be prepared. The hazard analysis must consider the location of safety related and important to safety structures, systems and components (SSCs) relative to the gas pipeline. The acceptance criteria for the hazard analysis considers; if the probability of a gas pipeline rupture is sufficiently low the event may be excluded; if the rupture does not damage the safety related or ITS SSCs then the rupture is acceptable; or, if the safety-related SSCs remain available to safely shutdown the plant and the risk of damage to the SSCs is low, then the risk to the public can be considered acceptable.

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 11 of 21 If the gas pipeline distances are sufficient to limit overpressure to less than 1.0 psi, the continued capability of safety related structures to withstand the effects of a gas pipeline rupture can be shown.

This hazards analysis considers the effects of the gas pipeline rupture to involve the approximately 3 miles of pipeline between isolation valves and considers the event to be terminated by manual action within 3 minutes after any pipeline rupture event by closing the closest isolation valves and limiting the event to the gas between these valves. Further, local fire departments have been trained in large gasoline fires of the type postulated for IPEC security events and will therefore have the ability to address any secondary fires and fire damage that will be of a lesser size when the gas pipeline flow has been terminated.

Evaluation of significance to margin of safety The effects on safety related and important to safety (ITS) SSCs from a postulated gas pipeline failure could come from (1) potential missiles, (2) an over-pressurization event, (3) a vapor cloud (or flash) fire, (4) a hypothetical vapor cloud explosion, and (5) a jet fire. The attached analysis of the effects of a postulated gas pipeline failure and explosion along the southern route near IPEC is consistent with NRC guidance and demonstrates that there will be no damage to safety-related SSCs. However, the attached analysis also shows that certain SSCs important to safety (i.e., Switchyard with associated transmission lines, Gas Turbine 2/3 Fuel Oil Storage Tank (GT 2/3 FOST), City Water Tank, and Emergency Operations Facility (EOF) and meteorological tower) have to be evaluated for loss under certain postulated rupture scenarios. Entergy is also considering potential impacts to the FLEX Storage Building, the fuel oil tanker, and the IP2 and IP3 steam generator mausoleums.

Regulatory Guide (RG) 1.91 Rev 2 defines an acceptable method for establishing the distances beyond which no adverse effect would occur based on a level of peak positive incident overpressure.

The peak overpressure of 1.0 psi (6.9 kPa) is considered to define this distance and can be calculated by Rmin = Z

• W1/3 where Rmin = distance from explosion where Ps, will equal 1.0 psi (6.9 kPa) (feet or meters)

W = mass of TNT (pounds or kilograms (kg))

Z= scaled distance equal to 45 (ft/lb 1/3) when R is in feet and W is in pounds Z= scaled distance equal to 18 (m/kg 113) when R is in meters and W is in kilograms The attached report contains the hazard evaluation which calculates the minimum safe distances from a vapor cloud explosion using the RG 1.91 formula (Table 10). The hazard evaluation also 2 conservatively assumed damage to SSC important to safety from thermal radiation of 12.6 kW/m (Table 4) due to a jet fire (immediate ignition of the release produces a jet fire anchored on the pipeline) and calculated the distance to achieve this value. The hazard analysis also defines the missile hazard based on historical industry pipeline failure data and demonstrates the delayed vapor cloud explosion (deflagration) is not a concern. The hazard evaluation is considered to be very conservative since the methodologies used for calculating the overpressure distance and the selection of the thermal radiation of 12.6 kW/m 2 (the distance that plastic melts / piloted ignition of wood are well below the thermal radiation for building damage) The attached hazard analysis identifies distances beyond which damage is not postulated even in worst case ruptures as follows:

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 12 of 21 Type of Effect Evalulated Exclusion Distance Basis Jet fire 1266 ft (386 m) A heat flux of 12.6 kW/m 2 was chosen as a basis for limiting postulated damage Vapor Cloud explosion 1155 ft (352 m) A 1.0 psi overpressure will not occur at (detonation) greater distance Missile 900 ft (274 m) The maximum distance that missiles I have been observed The first assessment assumes that these SSCs ITS could be damaged by a postulated explosion and evaluates whether there would be a significant reduction in the margin of safety. The assessment is to quantify potential effects assuming a postulated gas pipeline rupture and does not consider the frequency of a gas pipeline rupture and explosion or the capability of SSC. The assessments are based on the closest distances from the enhanced and unenhanced pipeline, as follows:

SSC ITS Closest distance from Closest distance non-enhanced enhanced gas pipeline gas pi9in Switchyard 115 ft ( 35 m) >1266 ft (386 m)

GT2/3 fuel tank 105 ft (32 m) >1266 ft (386 m)

City water tank 1336 ft (407 m) >1266 ft (386 m)

Meteorological tower Not applicable 551 ft_(168 m)

EOF 1002 ft(305 m) >1266 ft (522 m)

SOCA 1580 ft (482 m) >1580 ft (482 m)

Backup Meteorological tower 1844 ft (562 m) >1266 ft (386 m)

SSC Of Interest FLEX Building 1033 ft (315 m) 1162 ft (354 m)

Unit 2 SG Mausoleum 1440 ft (439 m) >1266 ft (386 m)

Unit 3 SG Mausoleum Not Applicable 477 ft (145 m)

The following assessment discusses the safety significance of a postulated loss of SSCs ITS from a postulated gas pipeline rupture. It concludes a loss of the SSCs important to safety would not result in a significant decrease in the margin of safety provided for public health and safety except for the assumed loss of the switchyard and GT 2/3 FOST which are more significant SSCs ITS.

A postulated gas pipeline rupture near the switchyard could cause total loss of the switchyard of the type that could occur with low probability events such as extreme natural phenomena (e.g., earthquake, tornado winds / missiles, hurricanes, etc.) that the switchyard is not protected against. The potential loss of the switchyard can result in loss of offsite power to the plant and result in a generator or turbine trip with or without fast bus transfer to the turbine generator bus. This is considered a relatively high probability event and is analyzed in the Updated Final Safety Analysis Report (UFSAR). The loss of offsite power would result in automatic operation of the Emergency Diesel Generators (EDG) to provide essential power to cool down and shutdown each plant. The loss of offsite power is also considered as an initiator of the station blackout event (SBO) where the three EDG (three for IP2 or three for IP3) at one plant are postulated to fail to start. Both IP2 and IP3 have a separate SBO diesel generator for such an event. - - . - f. ... .. ...

lion .The SBO event considers the ability to restore the switchyard in determining the duration for which a SBO is evaluated. However, loss of the switchyard for an extended period of time due to a postulated pipeline rupture does EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 13 of 21 not need to be considered for the SBO. NRC acceptance criteria for SBO (NUMARC 87-00) do not require consideration of low probability events such as severe natural phenomena or pipeline rupture for SBO. Therefore there would be no significant reduction in margin of safety due to loss of the switchyard from the contribution of a switchyard failure due to a gas pipeline rupture.

A postulated gas pipeline rupture near the GT 2/3 FOST could cause loss of the tank. The purpose of the tank is to provide a supply of fuel oil to the IP2 and IP3 EDG so that they would have an overall 7 day supply of fuel oil (it is presumed that additional fuel oil as well as backup generators could be made available in that time). The function of the GT 2/3 FOST is backed up by the ability to provide fuel oil from outside the plant. The gas pipeline rupture that could cause loss of the GT 2/3 FOST could also result in loss of the switchyard due to their close proximity. This will require the backup fuel oil from offsite to be provided as the primary means of achieving a 7 day fuel oil supply. The gas pipeline rupture could also cause loss of the main access gate to the site directly across from the switchyard but there are other access gates for delivery of the fuel oil. The gate several hundred feet further south (it used to access IP3 when the two units were independent) could be blocked by the rupture since it is not too far from the GT 2/3 FOST. This gate has been blocked with two concrete barriers (a crane could be used to remove them). To the north about 1850 feet is the gate used for access to IP2 when the two sites were independently owned and this gate is expected to be available. It is easily accessible by opening the gates in the owner controlled fence and manually opening the blocking bar used in place of concrete barriers. Although access is feasible, the dependency on the offsite delivery results in a reduction in the margin of safety for the safety related EDG to provide the power for plant shutdown. The tanker that is stored onsite to transport fuel oil from the GT 2/3 FOST is within the damage range but will be relocated to assure availability for all cases where the GT 2/3 FOST remains available. Therefore it is concluded that the reduction in the margin of safety is more significant assuming a pipeline failure that results in the loss of

• A postulated gas pipeline rupture will not cause loss of the city water tank because the distance from the gas pipeline is sufficient to prevent loss of the tank (see above table) since the peak positive incident overpressure will not exceed 1.0 psi and the heat flux will not exceed 12.6 kW/m 2 . The city water tank functions as alternate water supply to the IP2 and IP3 Auxiliary Feedwater Systems. It also serves as a backup for other SSCs, including the IP2 Appendix R / SBO diesel. ..

111111_Therefore there is no significant reduction in the margin of safety.

A postulated gas pipeline rupture could cause loss of the important to safety Emergency Operations Facility (EOF) because it can see a heat flux of 12.6 kW/m 2 and be exposed to an overpressure in excess of 1 psi, as well as loss of the meteorological tower which is also within both exclusion distances. The function of the EOF is to act as a central command post for a plant emergency that meets the criteria for emergency responders to assemble. The function of the meteorological tower is to provide weather information in the event of a plant emergency that requires activation of the emergency response organization, it contains instrumentation for Entergy activation of the siren system and communications with the offsite assessment team.

No gas pipeline rupture will cause any plant damage meeting the criteria for emergency EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 14 of 21 planning to assemble in the EOF. The EOF is activated for Alert Emergency Level declaration or above. An Unusual Event would likely be declared in the event of a pipeline rupture that results in switchyard failure (Loss of all offsite AC power to 480 V safeguards buses (5A, 2A/3A, 6A) for > 15 min) but the Alert Emergency Level criteria criteria would not be reached.

The failure that does damage the meteorological tower would not result in damage to the switchyard. Also, there is a backup meteorological tower (it does not contain the 60 meter and 122 meter instruments), normal means to activate the siren systems from the counties, alternate communications with the assessment teams, and a backup EOF that would not be affected by the rupture. There would therefore be no significant reduction in the margin of safety since the EOF and meteorological tower functions would not be required and backups are available.

There is no damage to the SOCA which is beyond the exclusion distance for which the effects of the gas pipeline explosion are considered for damage to SSCs. The SOCA boundary was identified for evaluation since the plant safety related SSCs are within the SOCA boundary and the SOCA represents the outer security boundary. Therefore there is no damage to safety related or security required SSCs.

In addition to the SSCs important to safety discussed above, other features have been considered.

• The building for storage of FLEX equipment (used for beyond design basis events) is required to address Fukushima orders. The building is constructed of reinforced concrete and was designed for a tornado overpressure. It does not have a damage potential from vapor cloud detonation because the overall structural capability of the building is designed for 3.0 psi overpressure compared to the predicted overpressure which is only slightly over 1 psi. The FLEX storage building is outside the postulated distance for a missile. The building is within the heat flux distance but the heat flux will not be great enough to affect the concrete and there is no other equipment to be affected.

• The storage of the steam generators replaced on IP2 and 1P3 is in mausoleum buildings. The Unit 3 mausoleums are subject to potential damage since they are within the exclusion distance for heat flux, missile damage and overpressure. The Unit 3 building has 3 foot thick reinforced concrete walls supported by a pile foundation with reinforced concrete pile, an 18 inch (average) thick reinforced concrete roof supported by metal decking and steel beams, and an 8 inch thick reinforced concrete grade slab. Although the structure contains radioactive material, analyses have demonstrated the failure of the structure would not result in releases exceeding the limits in 10 CFR 20 (10 CFR 50.59 analysis dated May 1987). The Unit 2 mausoleum is outside the exclusion distances and a postulated rupture would have no effect.

A rupture of the buried gas pipeline due to a sabotage event is not considered deterministically or in the evaluation of frequency because the ..... _...,* r . " Rig

=-'. . . -' and due to the substantial difficulty of intentionally causing an rupture of underground piping coupled with the extra design features that have been included in the proposed enhanced pipeline design. A gas pipeline rupture of exposed (above-ground) portions of the pipeline due to sabotage, however, has been postulated at IPEC in the past in response to a concern, although there is no regulatory requirement to do so. Consistent with this precedent, a sabotage event is postulated, but limited to considerations of potential sabotage of above ground piping. The above ground piping, however, is sufficiently far from any SSC important to safety so that all SSCs are outside the exclusion areas of the hazard analysis.

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 15 of 21 A gas pipeline rupture due to natural phenomena was also evaluated and is not considered to represent a credible threat to the pipeline. Tornadoes and hurricanes do not present a threat to the buried pipeline due to winds or missiles. Missile impacts are resisted by the strength of the piping and the 3 to 4 foot depth of the soil. Additionally, the effects of tornado missiles are not part of the IP2 design basis and are restricted to a single missile at IP3. A seismic event has the potential to cause loss of supporting soils due to the potential liquefaction of the underlying soils and susceptibility to other damage that could cause loss of the pipeline. However, due to the rocky soil in this area at relatively shallow depths combined with low seismicity, liquefaction of the underlying soil is not likely (Reference 9). As a result, the pipeline will be continuously supported along the entire length of burial by the soil and will tend to move in phase with the soil during an earthquake resulting in low stresses.

The primary risks from ground movement hazards come from active seismic faults, landslides, long wall mine subsidence, and frost heaves in areas with deep frozen ground, none of which apply along the pipeline in the area near the Indian Point Facility. Therefore, a seismic event is not postulated to adversely affect the buried portion of the pipe.

The potential exists where the 26 / 30 inch pipeline will come together with the 42 inch pipeline for an explosion in one of the three pipelines to cause an explosion in one or more of the other lines. This would be possible in the above ground portion of the pipeline but the blasts would be sequential and this distances are great enough that the effects would be acceptable. Experience has shown that the rupture of one underground pipe would not affect another since the forces are upward. Also the lines are not close enough to even create this possibility until they reach the area where they are brought above ground. Therefore, a postulated simultaneous failure of the buried portions of the existing 26 /

30 inch pipelines and new 42 inch pipeline is not a credible event.

Frequency of Events The prior discussion indicates that the new gas pipeline represents no potential damage to safety related SSC but a gas pipeline rupture could cause potential damage to SSCs ITS closer to the proposed southern route. The discussion also assesses the effects on the safety margin for protection of the public for a postulated gas pipeline rupture. The following information shows that the frequency of postulated gas pipeline ruptures that could damage SSCs ITS are, based in part on the enhanced design and installation features, sufficiently low and do not result in a significant reduction in the margin of safety. This is because they are excluded from consideration in accordance with NRC guidance due to the very low frequency of a gas pipeline rupture that could damage these SSCs ITS and because the frequency is sufficiently low that the undamaged safety related SSCs can be credited with safely shutting down the plant, or because the SSCs are not within the distance where they could be damaged. The one exception to this being the Meteorological Tower, which is above 10-6/yr. however, there is a backup Meteorological Tower and other means of obtaining meteorological data (e.g., NOAA)

The frequency of a pipeline explosion was evaluated using industry data and correlating it to more recent data. The frequency of a pipeline rupture and enhanced pipeline rupture is 1.32E-5 per mile-year and 1.98E-6 per mile-year, respectively. These are considered conservative values. The frequency of damage to the various SSCs ITS is calculated by the length of pipeline exposure and the frequency of occurrence of the types of events. The results are as follows:

. .. _ _ _ _ _ __.... .. , . Event.; ,,.requency I /year Switchyard .. .. fire _Jet 7.23E-7

.... _ _ _ Vapor Cloud explosion 5.52E-8 Missile 1.32E-7 GT2/3 fuel tank / switchyard Jet fire 5.20E-7 EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 16 of 21 Vapor Cloud explosion 4.25E-8 GT2/3 fuel tank Missile 1.51 E-8 City water tank Jet fire Outside damage distance Vapor Cloud explosion Outside damage distance Missile Outside damage distance Meteorological tower Jet fire 1..86E-6

... ..... ________ Vapor Cloud explosion 1.51 E-7 Missile 2.06E-9 EOF Jet fire 4.02E-7 Vapor Cloud explosion 2.79E-8 Missile Outside damage distance SOCA Jet fire Outside damage distance Vapor Cloud explosion Outside damage distance Missile Outside damage distance Backup Meteorological tower Jet fire Outside damage distance Vapor Cloud explosion Outside damage distance Missile Outside damage distance City Water Tank Jet fire Outside damage distance Vapor Cloud explosion Outside damage distance Missile Outside damage distance Othe S.SCotý Intferest.. ______________

FLEX Building Jet fire No exposed 2instruments for 12.kW/m to damage Vapor Cloud explosion Overpressure 1.19 psi building design for 3.0 psi Missile Outside damage distance Unit 2 SG Mausoleum Jet fire Outside damage distance Vapor Cloud explosion Outside damage distance Missile Outside damage distance Unit 3 SG Mausoleum Jet fire 1.38E-6 (for thermal radiation that would damage the building)

Vapor Cloud explosion 1.95E-7 Missile 3.83E-8 Conclusion Based on the considerations discussed above, the potential for an increase in risk to the public is acceptably low on the basis of:

• there is no damage to safety related SSC or plant security from a postulated pipeline rupture;

• the effect on SSCs ITS of a postulated gas pipeline rupture would not have a significant effect on plant safety because:

• The SSCs ITS have been shown to be sufficiently far away from a postulated gas pipeline failure so as to be unaffected by the failure, or EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 17 of 21 Based on the agreed-upon pipeline design and construction enhancements, the low frequency of a gas pipeline rupture would preclude consideration of rupture with damage to SSC ITS, with the exception of the Meteorological Tower where frequency is greater that 1 OE-6. The meteorological tower, is not required for shutdown and the undamaged safety related SSCs can be credited with safely shutting down the plant.

The meteorological tower also has backup capability and other means of obtaining meteorological data are available (e.g., NOAA).

Therefore there is no significant reduction in the margin of safety with regard to public safety.

References (1) Preliminary Safety Analysis Report (PSAR) for IP3, dated August 30, 1968, ADAMS Accession No. ML093480204 ("Gas Pipeline Fire" describing the design and construction of the gas lines.,

operation and maintenance practices, postulated failure modes, and standoff distances provided to determine safety-related structures would not be affected).

(2) Safety Evaluation Report dated September, 21, 1973, ADAMS Accession No. ML072260465.

(3) New York Power Authority letter to NRC (IPN-97-132) Regarding Indian Point 3 Nuclear Power Plant - Individual Plant Examination of External Events (IPEEE), dated September 26, 1997.

(4) Letter to M Kansler regarding "Review of Individual Plant Examination of External Events (TAC NO. M83632),"' dated February 15, 2001 (5) Memorandum from Richard J. Laufer, Chief, Section 1, Project Directorate 1, Division of Licensing Project Management Office of Nuclear Reactor Regulation, NRC, to Peter Eselgroth, Chief, Branch 2, Division of Reactor Projects, Reg ion 1, NRC, "

Subject:

Review of Natural Gas Hazards, Indian Point Nuclear Generating Unit Nos. 2 and 3 (TAC Nos. MB8090 and MB8091)" (Apr. 25, 2003) (ADAMS Accession No. ML 1223A040).

(6) Berk Donaldson, Algonquin Gas Transmission, LLC letter to Ms Kimberly D Bose, FERC regarding Algonquin Gas Transmission, LLC, Docket No. CP14-96-000, Abbreviated Application for a Certificate of Public Convenience and Necessity and for Related Authorizations, dated February 28, 2014 (7) Timothy C O'Brien, Spectra, E mail to Charles A. Moore, Morgan Lewis& Brockius, LLP, dated July 29, 20124 (8) Spectra Energy (Algonquin Gas Transmission) memorandum to Energy regarding Response to Entergy Document entitled "Pipeline Enhancements Being Evaluated to Mitigate a Pipeline Failure" dated July 29, 2014.

(9) "Enercon Report of Liquefaction Potential Assessment' dated June 26, 2014 (IP-RPT-14-00010)

Is the validity of this Evaluation dependent on any other change? El Yes [ No EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 18 of 21 If "Yes," list the required changes/submittals. The changes covered by this 50.59 Evaluation cannot be implemented without approval of the other identified changes (e.g., license amendment request). Establish an appropriate notification mechanism to ensure this action is completed.

Based on the results of this 50.59 Evaluation, does the proposed change El Yes Z No require prior NRC approval?

Preparer Stephen Prussman/

Name (print) / Sigfature / CJnpany / Ddpartment / Date Reviewer John Skonieczny/,*-v /g .. JA7"/

• c /92 Name (print) / Sidgature / Company rDeePment / Date.

OSRC: John Kirkpatrick/ . ;;;,/,

Chairman's Nam prinvf/ nature / Date Meetinq 14-13 on 8-18-2014 OSRC Meeting #

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 19 of 21 II. 50.59 EVALUATION Does the proposed Change being evaluated represent a change to a method of evaluation ONLY? If "Yes," Questions 1 - 7 are not applicable; answer only Ouestion 8. If "No," answer El Yes all questions below. ED No Does the proposed Change:

1 Result in more than a minimal increase in the frequency of occurrence of an accident El Yes previously evaluated in the UFSAR? [No BASIS:

Currently, a 26 inch and 30 inch pipeline traverse the site along a route just south of the protected area and the effects of a rupture of that pipeline has been evaluated. The addition of a 42 inch pipeline south of the IPEC property that crosses IPEC property near the GT 2/3 Fuel Oil Storage Tank (FOST) and Buchanan substation creates the possibility of a gas pipeline rupture.

Gas pipelines have a low frequency of rupture. The new gas pipeline has been designed with the latest methodology and a significant portion has been enhanced with additional features (e.g., deeper burial, thicker pipe, stronger materials, positive means to prevent excavation and abrasion resistance coating) intended to further reduce the frequency of gas pipeline rupture in the area of Structures Systems and Components (SSC) important to safety (ITS). The frequency is sufficiently low that the new gas pipeline will not result in more than a minimal increase in the frequency of occurrence of an accident (gas pipeline rupture) currently evaluated in the UFSAR.

2. Result in more than a minimal increase in the likelihood of occurrence of a malfunction El Yes of a structure, system, or component important to safety previously evaluated in the Z No UFSAR?

BASIS:

A rupture of the new gas pipeline could be the cause of a malfunction of a SSC previously evaluated. The new gas pipeline has been routed where a gas pipeline rupture could not cause malfunction of a safety related SSC or security provisions and therefore there would be no increase in the likelihood of damage to those SSC. The routing is where a postulated rupture could cause a malfunction of SSC's ITS (Switchyard with associated transmission lines, Gas Turbine 2/3 Fuel Oil Storage Tank (GT 2/3 FOST), and Emergency Operations Facility (EOF) and meteorological tower) due to proximity. The likelihood of a gas pipeline rupture causing malfunction of SSC ITS will be minimized by the gas pipeline design and maintenance as well as the enhancement of a substantial portion of that gas pipeline routed near the SSC ITS. The increase in likelihood of a gas pipeline rupture affecting the SSCs ITS has been determined to have a very low frequency. As a result, this new pipeline is not considered to result in a more than minimal increase in the likelihood of occurrence of a malfunction of a SSCs important to safety previously evaluated in the UFSAR.

3. Result in more than a minimal increase in the consequences of an accident previously El Yes evaluated in the UFSAR? [No EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 20 of 21 BASIS:

The rupture of the gas pipeline previously considered in the UFSAR assessed if it could result in loss of safety related SSCs. This is the rupture of the 26 inch and 30 inch gas pipelines which were previously evaluated as acceptable during the original Licensing stage, and as during the performance of the IPEEE as of acceptably low probability. It was evaluated for an aboveground rupture as a potential security event and the evaluation concluded the effects were acceptable.

The evaluation of the consequences of these prior ruptures showed there was no damage to safety related SSCs. The effects of a gas pipeline rupture of the new 42 inch gas pipeline were evaluated to determine whether the consequences of the previous evaluations were increased.

The evaluation showed there was no damage to safety related SSCs due to gas pipeline rupture and therefore there is no increase in consequences. The evaluation, performed using methodologies consistent with the current NRC guidance, looked at the effects on SSC important to safety as well as safety related SSC. The evaluation shows that, due to the proximity of the proposed southern route to SSCs ITS, there was a potential for damage. However, it also showed that the damage frequency was sufficiently low, according to NRC criteria, that it was acceptable. Additionally, the evaluation of SSCs ITS was not an accident previously considered.

Therefore there is no increase in consequences since the safety related SSCs are not damaged and the effects of damage to SSCs ITS were not previously evaluated and are acceptable. As a result, it can be concluded that this activity will not result in a more than minimal increase in the consequence of previously evaluated accidents.

4. Result in more than a minimal increase in the consequences of a malfunction of a LI Yes structure, system, or component important to safety previously evaluated in the [ No UFSAR?

BASIS:

The effects of a rupture in the new 42 inch gas pipeline have been evaluated to determine the effects on SSCs ITS. The evaluation shows the frequency of a rupture affecting a SSCs ITS have been reduced to where a rupture will have no more than a minimal increase- in the consequences of malfunction of the SSCs ITS affected. Natural phenomena with a probability greater than the rupture of the gas pipeline can damage the SSCs ITS that the postulated gas pipeline rupture can affect. The ability of the plant to safely shutdown and maintain cold shutdown has been assessed with this damage. There is a minimal increase in the consequence of a malfunction of the SCCs since a gas pipeline rupture has the lower frequency.

Therefore, this activity will not result in a more than minimal increase in the consequences of a malfunction of a SSCs important to safety previously evaluated in the UFSAR.

5. Create a possibility for an accident of a different type than any previously evaluated in U Yes the UFSAR? [ No BASIS:

The previously considered rupture of the 26 and 30 inch pipelines is considered a similar accident. A rupture of the new 42 inch gas pipeline has been evaluated and would not result in damage to a safety related SSC but could result in damage to SSC important to safety (Buchanan switchyard, the GT2/3 storage tank, and the EOF / meteorological tower). Loss of these components could not create the possibility of an accident of a different type than previously evaluated since their loss has previously been evaluated. There are no other changes to the plant operations, operating procedures or site activities that could possibly create an accident of a different type than previously evaluated. As a result, this activity does not create a possibility for an accident of a different type than previously evaluated in the UFSAR.

EN-LI-101-ATT-9.1, Rev. 11

10 CFR 50.59 EVALUATION FORM Sheet 21 of 21

6. Create a possibility for a malfunction of a structure, system, or component important to EL Yes safety with a different result than any previously evaluated in the UFSAR? [ No BASIS:

A rupture of the new 42 inch gas pipeline has been evaluated and would not result in damage to a safety related SSC but could result in damage to SSCs ITS. The potential for damage could not result in a malfunction with a different result that any previously considered in the UFSAR because the potential damage is not different than previously evaluated and there is no damage to safety related SSC. Rupture of the pipeline is postulated to occur in normal operation since it is not postulated to occur as a result of a plant accident or natural phenomena. The malfunction of SSCs ITS that could be affected by the gas pipeline is no different than those previously considered in the UFSAR. That failure is just a loss of the component since there is no interface with safety related SSC. Therefore the malfunction of the affected components would not have a different result than the rupture of these components as previously evaluated.

7. Result in a design basis limit for a fission product barrier as described in the UFSAR El Yes being exceeded or altered? [No BASIS:

A rupture of the new 42 inch gas pipeline has been evaluated and would not result in damage to a safety related SSC and damage to a ITS would not affect the ability to safely shutdown. The postulated rupture of the new 42" gas pipline has no impact on fission product barriers.

Therefore there will be no fission product barrier design basis limit approached.

8. Result in a departure from a method of evaluation described in the UFSAR used in El Yes establishing the design bases or in the safety analyses? Z No BASIS:

This activity installs a new gas pipeline routed south of the IPEC plant and partially on IPEC property. The UFSAR describes past evaluations of pipeline rupture but does not discuss the methodology. The new evaluation of the potential for rupture uses methodology consistent with past evaluations and approved by NRC and evaluates the frequency of rupture using methodology consistent with the NRC criteria. Therefore, it is concluded there is no departure from past methodologies used for the plant and does not depart from a method of analysis contained in the UFSAR.

If any of the above questions is checked "Yes," obtain NRC approval prior to implementing the change by initiating a change to the Operating License In accordance with NMM Procedure EN-LI-1 03.

EN-LI-101-ATT-9.1, Rev. 11