ML20196H188

Forwards Response to 980909 RAI for Review of Ccnpp,Units 1 & 2 License Renewal Application Re Severe Accident Mitigation Alternatives & Errata

ML20196H188
Person / Time
Site:	Calvert Cliffs
Issue date:	12/03/1998
From:	Cruse C BALTIMORE GAS & ELECTRIC CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
TAC-MA1524, TAC-MA1525, NUDOCS 9812080232
Download: ML20196H188 (77)

Text

{{#Wiki_filter:n. - :... i i CHCLES H. CRUSE Baltimore Gas and Electric Company Vice President Calvert Cliffs Nuclear Power Plant j Nuclear Energy 1650 Calven Cliffs Parkway Lusby, Maryland 20657 410 495-4455 December 3,1998 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Document Control Desk

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 Response to Request for Additional Information for the Review of the Calvert Cliffs Nuclear Power Plant, Unit Nos.1 & 2, License Renewal Application, Severe Accident Mitigation Alternatives, and Errata, (TAC Nos.MA1524 and MA1525) j

REFERENCES:

(a) Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated April 8,1998," Application for License Renewal" (b) Letter from Ms. C. M. Craig (NRC) to Mr. C. H. Cruse (BGE), dated September 9,1998," Request for Additional Information for the Review of the Calvert Cliffs Nuclear Power Plant (CCNPP), Unit Nos.1 & 2, License Renewal Application, Severe Accident Mitigation Alternatives (TAC Nos. MA1524 and MA1525) Reference (a) forwarded the Baltimore Gas and Electric Company (BGE) License Renewal Application (LRA). Reference (b) forwarded questions from NRC staff on the Severe Accident Mitigation Alternatives (SAMA) section of the BGE LRA Environmental Report. Attachment (1) provides our responses to the SAMA questions contained in Reference (b). Attachment (2) provides errata to Appendix (2) of the LRA, Applicant's Environmental Report - Operating License Renewal Stage. Attachment (3) provides the justification for BGE's position on the consideration of Averted Onsite Costs in SAMA analyses. Attachment (4) provides detailed implementation cost estimates in support of BGE's responses to Questions 14 and 16. Reference (a) provided the information specified in 10 CFR Sl.53(c)(3)(ii) for inclusion in an operating license renewal stage environmental report, including the SAMA analysis required by 10 CFR S t.53(c)(3)(ii)(L). Baltimore Gas and Electric Company did not commit to implement any SAMAs in Reference (a), nor does this Request for Additional Information response include or imply a commitment to implement any SAMAs as part of CCNPP's license renewal project. 1 pO3bf -4 nn I 9812080232 981203 P / PDR ADOCK 05000317 P PDR

2 Document Control Desk December 3,1998 Page 2 l Should you have questions regarding this matter, we will be pleased to discuss them with you. Very truly yours, i ) f wa-I STATE OF MARYLAND )

TO WIT:

I COUNTY OF CALVERT l 1, Charles H. Cruse, being duly sworn, state that I am Vice President, Nuclear Energy Division, J Baltimore Gas and Electric Company (BGE), and that I am duly authorized to execute and file this response on behalf of BGE. To the best of my knowledge and belief, the statements contained in this document are true and correct. To the extent that these statements are not based on my personal knowledge, they are based upon information provided by other BGE employees and/or consultants. Such information has been reviewed in accordance with company practice and I believe it t reliable. AJ Ad Subs bed an worn before me, a Notary Public in and for the State of Maryland and County of i .this 3 dayof 71 sed,1998. WITNESS my Hand and Notarial Seal: Notary Public j My Commission Expires: "6 CHC/KRE/ dim Attachments: (1) Response to Request for Additional Information; Severe Accident Mitigation Alternatives Analysis (2) Errata to Applicant's Environmental Report Operating License Renewal Stage; i Section 4.1.17, Severe Accident Mitigation Alternatives Analysis cc: R. S. Fleishman, Esquire C. I. Grimes, NRC J. E. Silberg, Esquire C. M. Craig, NRC l S. S. Bajwa, NRC Resident bspector, NRC A. W. Dromerick, NRC R. I. McLean, DNR H. J. Miller, NRC J. H. Walter, PSC l

. =. ATTACHMENT m i i I RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS t q J -{. Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant December 3,1998

e ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; I APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS l NRC Ouestion No.1 l

1. The Calvert Cliffs Probabilistic Risk Assessment (CCPRA) model on which the Severe Accident Mitigation Alternatives (SAMA) analysis [in the Baltimore Gas and Electric Company (BGE)

License Renewal Application] is based is said to be far more advanced than the Individual Plant Examination (IPE) submitted to NRC in December 1993, and slightly more advanced than the Individual Plant Examination of External Events (IPEEE) submitted in August 1997. l (a) Provide a description of the major differences in models/ assumptions between the CCPRA model used for SAMA and that submitted to and reviewed by the NRC, and the impact of these changes on the risk profile. Include a discussion regarding development of the CCNPP Level 3 model. (b) Confirm whether any of these changes were made in the Level 2 analysis, since the discussion and references in Section F.3.2 seem to indicate that the NUCAP+ model is based directly on the IPE Level 2 model. (c) Describe the independent peer reviews performed on the CCPRA model used for SAMA. Explain the significant results and overall conclusions of those peer reviews and describe how the results were incorporated in the CCPRA on which the SAMA analysis is based. (d) Discuss how the risk information from the external event analyses is incorporated within the NUCAP+ model for CCNPP. BGE Resnonse (a) The CCPRA model consists of an internal events portion, based on the IPE, and an external events portion, based on the IPEEE. The largest portion of the IPE model, from both a size and risk contribution perspective, is the general transient (GT) portion. The GT Module includes loss of offsite power, loss of feed, and loss of vital auxiliaries initiating Events. The GT Module does not include modules for Loss-of-Coolant Accidents (LOCAs), Steam Line Breaks (SLBs), and flooding events. The GT Module has undergone major changes since the IPE submittal. The update used for the SAMA analysis is referred to as Update 2. The Update 2 GT Module was i used as the foundation for developing the IPEEE. The major changes associated with the Update 2 GT Module between the IPE and SAMA evaluations are: Success Criteria Improvements e > Anticinated Transient Without Scram (ATWS) Success Criteria Imoroved: In the IPE, ATWS recovery was only credited when half of the control rods inserted. In Update 2, ATWS recovery is credited when either half the rods insert or no rods insert and the moderator temperature coefficient is desirable. [ core damage frequency (CDF) reduction] > 1moroved Closed System Leakage Modeling: Update 2 considers leakage rates as l maintenance alignments for service water (SRW) and component cooling water (CC). l Update 2 models all of the make-up options. [CDF increase] l > Revised Reactor Coolant Pumo (RCP) LOCA Success Criteria: Component Cooling cools the RCP seals, the high pressure safety injection (IIPSI) pump seals and bearings, I the low pressure safety injection pump seals and bearings, and the shutdown cooling heat exchangers, which provide the heat sink for the containment spray (CS) pumps and ultimately the containment emergency sump. Post-IPE calculations indicated that the 1 l

A'ITACHMENT (1) l RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT's ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SRW-cooled containment air coolers, along with one CS pump, are capable of maintaining the sump temperature without CC cooling. With low sump temperature, the seals and bearings for the HPSI pumps are adequately cooled by the process flow. In Update 2, this decoupling of a common-mode failure reduced the impact of RCP seal failure. [CDF Reduction] > Low Pressure Feed using Condensate System: Our existing Emergency Operating j Procedures (EOPs) consider the possibility of using a condensate pump, condensate booster pump, hotwell make-up, and the atmospheric dump valves (ADVs) to provide decay heat removal given auxiliary feedwater (AFW) and main feed water are lost. This j option is now credited in Update 2 prior to once-through-core-cooling (OTCC). If the i evolution fails from a human action perspective, then OTCC is also considered failed. [CDF Reduction] > More Complete Pressurized Thermal Shock (PTS) Evaluation: In the IPE, a bounding PTS likelihood (a single number) was used given an excessive de-pressurization (i.e., SLB). In Update 2, a specific likelihood of PTS for several different scenarios is developed. [CDF Increase] > Revised OTCC Success Criteria: In the IPE, OTCC was only credited when AFW is available in the short-term (available longer than six hours) or when the reactor trips with a normal steam generator water level. In Update 2, OTCC is credited given AFW is available for the first hour or AFW is lost at the time of the trip and two-of-three charging pumps are available. [CDF Reduction] e Common Cause Additions > Inverters: In the IPE, one of the most significant impacts was the failure of multiple inverters. Inverters support the 120 Volt AC (VAC) panels. The 120 VAC panels sup~ art the Engineering Safety Features Actuation System sensor channels. When two-of-rour channels are lost, a Spurious Safety System Actuation (SSSA) occurs. The impact of an SSSA, for the most part, is the same as described in Section 3.4.2.3.lb of the IPE (Reference 1). Although the air-cooled emergency diesel generator (EDG) added additional nuances, the impact is similar. Due to the significance of this issue, incorporation ofinverter common cause was a high priority for Update 2. [CDF Increase] > Transformers (500 kV/13 kV,13 kV/4kV,4kV/480 V): The industry evidence ofinverter common cause failure led BGE to conclude that transformer common cause should also be added. [CDF Increase] Multiple Bus Initiating Events: Multiple Bus Initiating Events are a logical extension of e common cause consideration. The key difference lies in consideration of repair times of 120V panel failures,480V AC bus failures, and 13kV bus failures. [CDF Increase] Human Action Related Improvements [CDFIncrease] e > Revised the human action methodology: The human action methodology utilized in the CCPRA model uses the Success Likelihood index Methodology Multi-Attribute Utility Decomposition (SLIM-MAUD) approach. The SLIM-MAUD approach to assessing human error probabilities is addressed in Reference 2. Within the SLIM-MAUD 2 l

ATTACHMENT (1) l RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; l APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; I SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS l approach, the "a" constants are used to convert the success likelihood index into a failure probability. The "a" constants used in Reference I were based on failure probabilities from other plants' IPEs. Within Update 2, the "a" constants are based on expert opinion l combined with data from the human cognitive reliability model. Additionally, within Update 2, unique "a" constants are used for the identification, diagnosis, and performance phases of human actions. l > Added indication dependencies for human actions for the GT Module. > Added imoroved SSSA recovery actions to the GT Module. > Uodated all human actions within the GT Module using the new human action methodolony.

• New EDG Addition: Modeled the plant configuration of five EDGs for the site. A dedicated j.

EDG for each of the safety-related buses (EDG No. I A for 4kV Bus 11, EDG No.1B for 4kV Bus 14, EDG No.2A for 4kV Bus 21, and EDG No.2B for 4kV Bus 24). A fifth diesel generator can also supply power to any of the four safety-related 4kV buses. At the time of the model development, the No.0C Diesel Generatcr could not support 4kV Bus 21. Although the No.0C Diesel Generator can now support all four of the safety-related 4kV buses, in Update 2, this diesel generator could not support 4kV Bus 21. [CDF Decrease] 1 The LOCA, Flood, SLB, and Steam Generator Tube Rupture (SGTR) modules used for the IPE are the same as those used for the SAMA evaluation. There are no major changes between the portion of the SAMA CCPRA model based on external events and the IPEEE. CCNPP Level 3 Model Development As noted in Reference 3, the CCPRA model used for the IPE and IPEEE describes the results of j the first two levels of the probabilistic risk assessment for CCNPP Unit 1. The Level 3 severe j accident consequence analysis was carried out with the Melcor Accident Consequence Code j System (MACCS) code Version 1.5.11.1. The MACCS code simulates the impact of severe j accidents at nuclear power plants on the surrounding environment. The development of the MACCS model (i.e., the MACCS input data) is described in Appendix F.1 of Reference 3. (b) The NUCAP+ Level 2 analysis is essentially the same as the IPE Level 2 analysis. The output of the Level I portion of the both the CCPRA and IPE consist of core damage sequences with a Plant Damage State (PDS) assigned to each sequence. A PDS defines the pressure at core damage, Safety Injection System status, containment breach size, and containment heat removal availability. The Level 1 PDS assignment convention used in the IPE is approximately the same as that used for Update 2 of the CCPRA model. Given a PDS, the Level 2 Containment Performance Event Tree (CPET) determines the fraction of each PDS that is assigned to each containment release category. In the IPE, the CPET was quantified using Microsoft Excel. For the SAMA evaluations, the CPET is quantified using NUCAP+. The Level 1-to-Level 2 assignment is considered the same between the IPE and Update 2 of CCPRA model. The Level 2 model translates PDS frequency changes into containment release frequency changes. i (c) As discussed in the response to NRC No. Question 1(a), the CCPRA model used for the SAMA analysis is based on the IPE and IPEEE models. No peer reviews were performed for the CCPRA 3 l i

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SAMA model other than those associated with the IPE and IPEEE. The IPE model peer review was discussed in Sections 5.2 and 5.3 of the IPE submittal (Reference 1). The IPEEE model peer review is discussed in Sections 6.2 and 6.3 of the IPEEE submittal (Reference 4). (d) The external events analysis is incorporated directly into the Level 2 evaluation. As discussed in the response to NRC Question No.1(b), the Level 2 model is used to determine the fraction of each PDS that should be assigned to each containment release frequency. Whether the PDS is from an external event scenario or internal event scenario has no direct impact on the Level 2 model results. NRC Ouestion No. 2 Explain how the potential for RCP seal LOCA was modeled in the CCPRA used for the SAMA analysis. Describe andjustify the major assumptions associated with the RCP seal LOCA model, gGE Response The RCP seals are cooled by the CC System. Each of the four RCPs has a four-stage seal. Each stage is capable of bearing the full Reactor Coolant System (RCS) pressure. As long as CC is available to the RCP seals, it is assumed that the chance of RCP seal failure is negligible. If CC is lost to the RCP seals for longer than 30 minutes, then the RCP seals are considered challenged. The likelihood of all four seal stages failing on one of the four RCPs is 15-in-10,000, as long the RCP is tripped within 45 minutes. If the RCP is not tripped within 45 minutes, then the seals are considered failed. Since CC provides cooling to the RCP lube oil cooler as well as the seals, it is considered likely that th: RCP will essentially self-trip. It is assumed that 90 percent of the time the RCP will self-trip within 45 minutes of the loss of CC. The leakage through a four-stage RCP seal failure is estimated to be 220 gallons per minute (gpm). At the time of the SAMA evaluation, the information related to RCP seals was contained in the Combustion Engineering Owners Group (CEOG) Report CE NPSD-755, " Reactor Coolant Pump Seal Failure Probability Given a Loss of Seal Cooling,"(November 1992), Reference 5. The report provided the basis for the failure likelihood of the RCP seals given cooling is lost to the seals. The report did not address any other key information such as the amount of time CC n'ust be lost to use the failure probability, whether the RCP would need to be tripped, or if the RCP does need to be tripped, how long it would take before the seal would fail. The raw data contained in CE NPSD-755, informal phone conversations with CEOG, other utilities, and CCNPP system engineers provided the only basis for information not included in the CEOG report. Recently (after completion of the SAMA evaluation), CEOG issued a revised standard to include more RCP seal timing information, CE NPSD - 755, " Reactor Coolant Pump Seal Failure Probability Given a Loss of Seal Injection,"(May 1998), Reference 6. Major insights from this report are: If CC is lost to the RCP seals for less than 30 minutes, then the RCP seals are NOT considered challenged. If the RCP is not tripped within 60 minutes, then the seals are considered failed. Self-tripped RCP can be credited, but only with the appropriate documentation. Reactor coolant pump four-stage seal failure is estimated to be 130 gpm given the RCP is tripped within I hour or 320 gpm given the RCP is not tripped. 4

l ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS The likelihood of all four seal stages failing on one of the four RCPs is 35-in-100,000 as long e I the RCP is tripped within 60 minutes. The success criteria used in the SAMA evaluation is generally either conservative or consistent with that provided in Reference 6. Consistent with Reference 6, the basis for the self-tripping of the RCPs is documented. The RCP technical manual indicates that tests have shown that the RCP thrust bearing temperature would reach 195 F within 10 minutes, given an initial temperature of 149 F. Since the CC System is temperature-regulated, it is believed that typically the initial bearing temperature will be consistent with that found in the technical manual. It is forther believed that the motor failure will occur within 10 minutes from the 190 F alarm setpoint. Based on this, the motor is expected to self-trip within 10 to 20 minutes. To bound this issue and address uncertainties, the Update 2 GT Module considered that the RCP will self-trip within 45 minutes 90 percent of the time. NRC Ouestion No. 3 The IPE indicated that the ATWS contribution was a significant risk contributor. Provide a discussion on the modeling of ATWS in the CCPRA used for the SAMA analysis. Explain and justify major i assumptions associated with the ATWS model, e.g.,the fraction of time during power operation with unfavorable moderator temperature coefficient. BGE Resnonse The ATWS success criteria used in the SAMA evaluation is similar to the success criteria used in Section 3.1.2.1.la of Reference 1, except when no control rods insert. The IPE success criteria is based on CE NPSD-591-P (Reference 7) and CE NPSD-672 (Reference 8). Although the ATWS success criteria document contained success criteria for the no-control-rod-insertion case, no credit is taken in the IPE for the no-control-rod-insertion case. In the version of the CCPRA model used for the SAMA analysis, credit is taken for this evaluation. The specific success criteria used in the CCPRA model for the SAMA analysis when no control rods insert is: Desirable Moderator Temperature Coefficient (MTC): -0.475E-04 delta rhoFF is acceptable e given the turbine bypass valves are available, or -0.550E-04 delta rhorF is acceptable given the turbine bypass valves fail to quick-open; Both power operated relief valves (PORVs) open; e Both primary safety relief valves open; Turbine trip succeeds; Operator initiates emergency boration with five minutes; and e Chemical Volume and Control System provides adequate boration and maximum letdown. e The fraction of core life having an MTC more positive than -0.475E-04 delta rhoPF is 22.2 percent of core life. The fraction of core life having an MTC more positive than -0.550E-04 delta rhorF is 25.9 percent of core life. 5 l l

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS The IPE did not credit this viable option due to: The limited amount of time available to perform the ATWS analysis; a The relatively high rate of non-recoverability due to high positive MTC (22 to 26 percent, as e noted above); The large amount of non-modeled systems required (e.g., Chemical Volume and Control e System); and The single failure nature of the support systems required (two-of-two PORVs must open, one-e of-one letdown lines must open, etc.). Despite these limitations, the incorporation of the full ATWS recovery modeling resulted in an ATWS contribution reduction of about 70 percent. In NUREG 1560, " Individual Plant Examination Program, Perspectives on Reactor Safety and Plant Performance,"(Reference 9), CCNPP was identified as having a high ATWS contribution. This was based on the IPE submittal. NUREG 1560 indicates that about 40 percent of the time the MTC is undesirable and an ATWS cannot be mitigated. This is true only when a turbine trip fails to occur. Without a successful turbine trip, the MTC must be more negative than -0.8E-04 delta rho / F. The primary turbine trip signal is obtained from the Reactor Protective System (RPS). In the IPE, a turbine trip required RPS success as a dependency. This was conservative as a large percentage of the failure of RPS is not related to that portion of the system required for a turbine trip. This is corrected in the Update 2 model. NRC Ouestion No. 4 The potential core damage risk during some shutdown plant operating states can also be as significant as the at-power risk. Provide a discussion on how the shutdown risk is considered in your SAMA analysis. BGE Response Shutdown plant operating states are not incorporated into the CCPRA model used for the SAMA analysis. Therefore, shutdown risk was not considered in BGE's SAMA analysis. NRC Ouestion No. 5 The discussion in Section 4.1.17.2 regarding offsite exposure cost states that the annual offsite exposure risk is 68.63 person-rem, however, a value of 54.2 person-rem is reported in Table F.1-4. Please explain this apparent discrepancy. BGE Response The value of 54.2 person-rem was calculated by weighting the MACCS-calculated risks (dependent on the accident occurrence) by the IPE accident frequencies (Reference 1, Table 4.8.4-A) and l summing the results. The value of 68.63 person-rem was calculated by using the Update 2 version of the CCPRA and the same dependent risk set. The 65.63 value is the correct value and is the value that was used in the SAMA evaluations. The occurrence of the 54.2 value in Table F.1-4 is an editorial error and will be replaced by the correct value. The average values for the total annual population dose risk from severe accidents for CCNPP Unit I are provided below. Additionally, it has been noted that the dose projections in the SAMA analysis were based on the 50-mile population 6 i

A'ITACHMENT (1). RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT's ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS dose risk only, and that the 10-mile population dose risk information presented in Table F.1-2 was not used in this analysis. Therefore, this information should be disregarded. Attachment (2) provides the revised text. . Ponulatinn Dose (nerson-rem) Late Containment Failure 1.38E+00 Small Early Containment Failure 3.87E+01 Large Early Containment Failure 2.62E+01 Small Containment Bypass 8.25E-01 13rge Containment Bvnacc 1.53E+00 Total Population Dose (within 50 miles) 6.86E+01 NRC Question No. 6 . Section F.1.2.6 identifies numerous offsite costs that were evaluated using MACCS and summed to arrive at the economic impact of an accident, but model input and assumptions are not identified. Please provide the following: (a) a description of the major input / assumptions for modeling economic impacts, (b) a discussion of the treatment of the economic impacts of fission product fallout into the Chesapeake Bay, and (c) a listing of the MACCS input file for CCNPP (excluding weather data). BGE Response (a) The economic model in the MACCS code addresses costs as follows: (1) Daily food and lodging costs are applied per person for short-term relocation of people who evacuate or relocate during the emergency phase of the accident (i.e.,the first seven days after the accident); (2) Decontamination costs are applied for propeny that can be returned to use; (3) Economic losses are incurred while property is temporarily interdicted to allow a period of decay following maximum decontamination, thereby reducing yearly doses to acceptable levels (i.e.,5.5 rem in eight years); and (4) Economic losses are applied from the permanent interdiction of property. H ' The model divides economic costs into two groups, farm costs and nonfarm costs. Farm costs are ~ calculated per hectare of farmland (wonh of farmland and improvements per hectare, crop worth per hectare). Nonfarm costs are calculated per person (temporary and permanent relocation costs per person, tangible worth of nonfarm property per person, decontamination costs of nonfarm propeny per person), where nonfarm propeny includes residential, commercial, and public land, improvements, equipment, and possessions. e Nonfarm Parameters Table I lists the values of nonfarm economic parameters used in the MACCS code application for CCNPP. The values in Table I are the same as those provided in the MACCS Users Manual (Reference 10) and NUREG-ll50 (Reference 11), including the Evaluation of Severe Accident Risks in NUREG/CR-4551 (Reference 12). The derivation of these numbers 7

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS is presented in Chapter 5 of Reference 11. The majority of the data presented in Reference 11 was taken from Statistical Abstract of the United States for 1988 (Reference 12). farm Parameters e Table 2 lbt the values of farm economic parameters used in the MACCS code application for CCNPP. He values in Table 2 are the same as those provided in References 10 and 11. The derivation of these numbers is presented in Chapter 5 of Reference 11. The data in Reference 11 was extracted from Reference 12 and Agricultural Statistics (Reference 13). Based on information provided in Reference 13, the total value of farm machinery and implements was valued at 84.5 billion dollars [ Table 1086]. Based on data provided in Reference 13 (Table 1057), there are 1002 million acres of farmland in the U.S.; therefore, the value of machinery and implements per acre is estimated to be $84.3 ($208.2 per/ hectare). Reference 13 (Table 1066) estimated the value of farmland and buildings in Maryland at $1,733 per acre ($4,281 per hectare). This value, combined with the value of the farm machinery and implements, results in the value of the farm wealth, VALWF. The fraction of the total farm value accounted for by farm buildings was determined from information provided in Reference 13 (Table 543). This was then used with the values derived for VALWF to determine the current value of buildings, as well as the total value of buildings and equipment. The value of farm wealth from improvements, FRFIM, was then derived as the fraction of VALWF that is represented by improvements (buildings and equipment). Regional Economic Data Table 3 presents the regional economic data portion of the MACCS Site Data File for CCNPP. The farming-related values in Table 3 are from the data provided in the Bureau of the Census County and City Data Book (Reference 14). The data on non-farm values in the last column are based on the MACCS input data and References 10 and i1. The derivation of these numbers is presented in Chapter 5 of Reference 11. See Table 1, for the per capita value of non-farm wealth (MACCS input variable VALWNR). (b) The economic impacts of fission product fallout into the Chesapeake Bay were not modeled directly in the MACCS calculations. The value of the land adjacent to the Bay, in part, reflects the value of the Bay. l (c) The five sets of MACCS input files used to generate the severe accident consequence / risk results for CCNPP's SAMA analysis are described below: ATMOS User Input File ATMOS calculates the dispersion and deposition of material released to the atmosphere as a function of downwind distance. It utilizes a Gaussian plume model with Pasquill-Gifford dispersion parameters. The phenomena that ATMOS treats are (1) building wake effects, (2) buoyant plume rise, (3) plume dispersion during transport, (4) wet and dry deposition, and (5) radioactive decay and in-growth. At the midpoint of each spatial interval along the transport path, air and ground concentrations for all the 8 l

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS radionuclides are calculated as well as miscellaneous information about plume size, height, and transport timing. These data are stored in common blocks that are used later by the EARLY and CIIRONC modules of MACCS. EARLY Userinput File e The EARLY module models the time period immediately following a radioactive release. This period is commonly referred to as the emergency phase. It may extend up to one week after the arrival of the first plume at any downwind spatial interval. The subsequent intermediate and long-term periods are treated by CliRONC. In the EARLY module, the user may specify emergency response scenarios that include evacuation, sheltering, and dose-dependent relocation. The EARLY module has the capability for combining results from up to three different emergency response scenarios. This is accomplished by appending change records to the EARLY input file. The first emergency-response scenario is defined in the main body of the EARLY input file. Up to two additional emergency-response scenarios can be defined through change record sets positioned at the end of the file. CIIRONC User Input File The CliRONC module simulates the events that occur following the emergency-phase time period modeled by EARLY. Various long-term protective actions may be taken during this period to limit radiation doses to acceptable levels. CliRONC calculates the individual health effects that result from both: (1) direct exposure to contaminated ground and from inhalation of resuspended materials, as well as (2) indirect health effects caused by the consumption of contaminated food and water by individuals who could reside both on and off of the computational grid. CliRONC also calculates the economic costs of the long-term protective actions as well as the cost of the emergency response actions that were modeled in the EARLY module. Meteorological Data File The meteorological data file contains a year of hourly recordings for the Calvert Cliffs site.

• Site Data File The population distribution and land use information for the region surrounding the CCNPP site are specified in the Site Data File. Contained in the Site Data file are the geometry data used for the site (spatial intervals and wind directions), population distribution, fraction of the area that is land, watershed data for the liquid pathways, model, information on agricultural land use and growing seasons, and regional economic information (Table 3). The use of this file is specified by an option in the EARLY input file. Some of the detailed data in this file supersedes certain data in the EARLY input file.

l NRC Ouestion No. 7 Baltimore Gas and Electric Company did not include several factors in the treatment of onsite economic costs. First, the onsite property damage costs associated with cleanup and decontamination were not included on the basis that such costs are covered by property damage insurance. The NRC's regulatory analysis guidelines, NUREG/BR-0058, Revision 2, [" Regulatory /nalysis Guidelines of the U.S. l 9 l l

l ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Nuclear Regulatory Commission"J consider a societal perspective in the performance of these analyses and call for the inclusion of these onsite impacts. The insurance payments are transfer payments and should not be considered as an impact because the insurance payments do not involve consumptive use of real resources. Second, BGE did not include replacement power costs as an onsite economic cost on the basis that such costs are unlikely to be incurred in a deregulated energy market. The NRC guidelines state that replacement power costs be included as impacts, albeit the guidance does not consider the implications of deregulation. In the evaluation of SAMAs, the staff will rely on cost estimates developed in a manner consistent with current regulatory guidance. Accordingly, please provide an estimate of the averted onsite costs (AOSC) for each affected SAMA and an updated maximum theoretical benent based on inclusion of the above costs, and update the net value analyses and SAMA screening accordingly. BGE Resnmaat Baltimore Gas and Electric Company has reviewed the position we presented in Reference 3, regarding the treatment of AOSC in SAMA analyses. Based on this review, we maintain our position that insured onsite property damage and replacement power costs are not proper considerations in the evaluation of SAMAs. There are a number of arguments supporting this conclusion. First and foremost, insured property damage and replacement power should not be considered in a cost benefit balance because they are not costs that will be or are likely to be incurred. With respect to insured property damage, BGE will already have paid for the damage through premiums reflecting the actuarial value of that damage. This insurance offsets any loss (any cost) of the insured amount. The insured cost cannot be ignored or dismissed as a " transfer payment" because it is not a free transfer of a benefit. Rather, it is the payment of an accumulated amount provided by insurance companies (some of which may be captives of the nuclear industry) in return for premiums. With respect to replacement power costs, the rapid transition to energy deregulation makes its extremely remote and speculative that such costs would be incurred. If BGE were no longer able to sell the power generated by CCNPP in a deregulated market, one would expect the next marginal producer to replace the power at approximately the same market price. Given this expectation, consumers should not see any significant price impact, and consequently there should be no appreciable public or societal impact. Beyond these factual arguments, AOSC does not even appear to be a proper National Environmental Policy Act (NEPA) consideration in the first place. The NEPA requires evaluation of environmental matters, and the proper focus of a SAMA analysis must remain on the mitigation of environmental impacts. Under judicial interpretations of NEPA (discussed in Attachment 3), economic impacts are only a consideration where there is a reasonably close causal relationship (similar to proximate cause) between a enange in the physical environment and an economic impact. Thus, for example, where a proposed action may adversely affect farmland, the economic impacts of crop loss causally related to the environmental harm are proper considerations. With respect to SAMAs, the causal link between the environmental impacts (the release of radiation to the environment) and the cost of repairing the reactor and replacing its power is generally lacking. These AOSC are not caused by, or a cost of, an impact on the natural environment. The appropriateness of this proximate cause requirement is apparent. Including insured property damage and replacement power costs would skew the evaluation of SAMAs towards economic rather than environmental impacts. For example, BGE's review of using the Fire Protection System as a 10

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGEt SECTION 4.1.17 SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS backup source of cooling for the EDGs indicated an offsite and occupational risk reduction value of approximately $176,000, but the "value" of this SAMA would be inflated to about $770,000 by adding in insured onsite damage and replacement power considerations. Thus, the onsite costs dwarf (by over 300 percent) the environmental considerations. Put another way, inclusion of the AOSC factors could militate toward implementing a SAMA even though its actual implementation cost exceeds its environmental benefit many times over. Clearly, this is inappropriate. To summarize, BGE believes that inclusion of these factors in AOSC is inappropriate because: (1) insured property damage is not a true cost that will be incurred; (2) replacement power costs are remote and speculative; (3) AOSC were included in the NRC guidelines for reasons that do not appear germane in this application; (4) AOSC will distort the NEPA analysis and promote SAMAs where the cost of implementation substantially outweighs the environmental benefits; and (5)it appears that AOSC is not a proper NEPA consideration. The bases for BGE's position that insured onsite property damage and replacement power costs should be excluded from AOSC are developed further in Attachment 3. The technical and legal basis for excluding these two aspects of AOSC notwithstanding, BGE has agreed to provide the replacement power cost and onsite property damage cost estimates for the 10 SAMA candidates with the greatest net value. The net value ranking is based on the value calculated l after factoring in the AOSC requested by this question. It should be noted that the provision of this data does not indicate BGE's concurrence with the basis for including these penalties in the determination of net value. The Replacement Power Cost was determined following the methodology provided in l NUREG/BR-0184, " Regulatory Analysis Technical Evaluation Handbook," (Reference 15), Section 5.7.6.2. The net present value of replacement power for a single event, PVap, was determined l using the equation in the middle of page 5.44: PVap = [$1.2E+08/r][1-exp(-rtr}}

where, PVap = net present value of replacement power for a single event ($)

r = real discount rate = 0.07 l tr = years remaining until end of facility life = 20 years (license renewal period) To attain a summation of the single-event costs over the entire license renewal period, the equation at the bottom of page 5.44 is used: Ugp = [PVgp/r][l-exp(-rtr)]2 l

where, Ugp = net present value of replacement power over life of facility ($-year)

After applying a correction factor to account for CCNPP's size relative to that of the " generic" reactor described in Reference 15 (i.e.,845 MWe/910-MWe), the replacement power costs are determined to be 7.33E+09 ($-year). Multiplying this value by the CDF reduction estimated by implementing each SAMA results in the averted replacement power costs for that SAMA. I1

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS The methodology for estimating onsite property damage cost associated with site clean-up and decontamination is described on page 4-26 of Reference 3. 1 i Baltimore Gas and Electric Company reviewed each of the 23 SAMAs listed in Referenx ?, Table 4-3, to determine the revised net values if the AOSC and replacement power costs are included ) in the estimated SAMA benefits. Additionally, since AOSC and replacement power costs would also j increase the value of the Base Case SAMA to approximately $8,600,000, BGE also revisited the benefit estimates for all SAMAs that were " screened out" from consideration because the Cost of Enhancement (COE) exceeded the maximum possible benefit of $2,400,000. Based on this review, a new list of was compiled, including the ten SAMAs with the highest calculated net values, and including AOSC and replacement power costs. This revised list, which includes 9 of the 23 SAMAs from Table 4-3 and 1 SAMA that was excluded because of a high COE (SAMA No. 77), is tabulated in Table 4. Based on the estimated COEs and the bounding benefit approach originally followed in Reference 3, only 6 of the " Top 10 SAMAs" indicate a positive net value. The last 4 of these " Top 10 SAMAs" indicate a negative net value, even after including these conservative factors; therefore, it was determined that inclusion of these factors in the remaining SAMAs would provide no useful information. NRC Ouestion No. 8 The meteorological data used for the MACCS calculations was based on measurements taken from January 1,1993 to December 31,1993. Explain why 1993 data was used, and justify that the data for 1993 is representative, e.g., by comparing 1993 with data collected over a longer period. BGE Resp 9mt The severe accident consequence analysis is one of the primary components of the Level 3 SAMA analysis. This part of the analysis was completed in early 1995, using the MACCS code. The data provided by our meteorological contractor, PLG, in June 1995, was taken for the calendar year 1993. It is presumed that the 1993 data was provided because this was the most readily available data at the time of the request. A review of the 1993 meteorological data by PLG indicated that these data were well within the normal trend for meteorology at the Calvert Cliffs site. Therefore, this data is considered representative of the climate for the site. NRC Ouestion No. 9 Describe the source of the population data for the year 2030 provided in Table F.1-3. Confirm that this data is based on the latest growth projection, and that geographic areas where major growth is anticipated are accounted for in the input file. BGE Respome As discussed in Section 3.8, Demography, the population data for the year 2030 were based on 1990 census data (Environmental Report Reference 113), with projections based on county population projections provided by State planning agencies in Maryland, Delaware, Virginia, and Washington, DC (Environmental Report References 116,117,118 and 119). These were the most current county population projections at the time the severe accident consequence analysis was completed (June 1995). More recent population projections have projected increases in some counties, and 12

A'ITACIIMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS decreases in other counties, beyond the projections used for this analysis, but BGE does not believe that this more current data would have an appreciable impact on the results of the MACCS Code analysis. NRC Ouestion No.10 Explain why evacuation times based on the current population and infrastructure are considered to be representative of conditions during the renewal period. Provide an assessment of the impact that longer evacuation times could have on risk results and SAMA findings. BGE Response An incr ease in the population would result in longer evacuation times, assumirp e infrastructure and emergency response approaches remain unchanged. However, the relationship vetween population and evacuation times would not necessarily be a one-for-one correlation, as population is only one of the many variables factored into the evacuation time estimates. A change in the evacuation times would have a proportional effect on the estimation of the Averted Public Exposure (APE) value; therefore, to account for the population increases and the resultant longer evacuation times, the estimated APES were doubled in the best estimate calculations as presented in the response to NRC Question No.14. NRC Ouestion No.11 Provide a breakdown of the consequence measures calculated for each release category, including person-rem doses, and costs anociated with each economic impact identified in Section F.1.3.2. BGE Response Table 5 provides a breakdown of the offsite costs associated with each release category. Environmental Report Table F.1-4 provides a breakdown of the person-rem doses for each release category. NRC Ouestion No.12 The latest CCNPP risk study provides the most relevant information regarding plant-specific contributors to CDF and risk, and should be used as the primary tool for identifying potential SAMAs. The information provided in Section 4.0 and Appendix F.2 does not indicate extensive use of the CCNPP risk study to identify potential SAMAs. The foliowing additional inbrmation should be provided in this regard: (a) Corrected references for each SAMA, if needed. Several SAMAs which appear to be highly focused on plant-specific systems or risk contributors (and which seem to derive from the CCNPP i IPE submittal) may be erroneously attributed to an Oak Ridge study (Reference 18 in Appendix F.2). j (b) A characterization of the leading contributors to CDF (from dominant sequences or sequence groups), large release frequency (from each containment failure mote or accident progression bin), and dose consequences (from each release class) based on the latest risk study. This information should be structured to provide a framework for subsequently demonstrating that SAMAs addressing esch of the major contributors have been identified and evaluated. l 13 l

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS (c) A listing of the SAMAs identified to address each of the major risk contributors identified in (a), j with emphasis on those SAMAs that were identified based on the CCNPP risk study. i l BGE Resanse (a) In drafting the final SAMA evaluation for inclusion in Appendix F of the Environmental Report, the SAMA candidates that were derived from Calven Cliffs plant risk insight were incorrectly attributed to Reference 18. Consequently, the SAMA candidate that should have been attributed to the Oak Ridge study (Reference 18) was attributed to Reference 19. The description of this SAMA candidate is " Create a core melt source reduction system"(Initial SAMA No. 46/ Revised SAMA No. 21). Therefore, in addition to the SAMA candidates that were attributed to CCNPP's IPE submittal, Reference 1, the SAMA candidates that were derived from CCNPP plant risk insight are: SAMA No. (Initial No./ Revised No.) Potential Enhancement SAMA No. 24/06 Provide a redundant train switchgear room heating, ventilation and air-conditioning (HVAC) system. l SAMA No. 79/48 Change Undervoltage (UV), AFW Actuation Signal Block, and High Pressurizer Pressure Actuation Signals to 3-out-of-4, instead of 2-out-of-4 logic. SAMA No. 80/49 Add an automatic bus transfer feature to allow the automatic l transfer of the 120V vital AC bus from the on-line unit to the stand-by unit. SAMA No. 81/50 Add disconnects at the junction box on the roof of the Auxiliary Building where 4kV power from Diesel Generator No. OC branches to all four switchgear rooms. SAMA No.109/68 Install separate accumulators for the AFW cross-connect and block valves. SAMA No.115/73 Create the abilin F .ergency connections of existing or alternate water &. c feedwater/ condensate. SAMA No.121/76 Redace the support system requirements for low pressure feed. SAMA No.122/77 Replace the current PORVs with larger ones such that only one is required for successful feed and bleed. SAMA No.158/92 Enhance the reliability of demineralized water (DW) make-up system through the addition of diesel-backed power to one or both of the DW make-up pumps. l 1 (b) The leading contributors to CDF are ATWS, loss of decay heat removal capability, and loss of inventory control. The ATWS, loss of decay heat removal, and loss of inventory control contributors may each be described in terms of four containment release parameters (i.e., intact containment, late containment failure, and small and large containment release). The remaining containment release parameters not directly associated with the CDF contributors are small and large containment bypass. The contribution of each of these 14 contributors to containment release are provided in Table 6, with a graphic depiction of the containment release break-down provided as Figure 1. 14

f ATTACIIMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; l APPLICANT'S ENVIRONMENTA1 REPORT - OPERATING LICENSE RENEWAL STAGE; l SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS l l Table 7 provides a matrix of the SAMAs evaluated by BGE in Reference 3 and the 14 leading contributors to containment release discussed above. Candidates that would eliminate at least 25 percent of any of the containment release contributors are annotated with a check mark in the I column for the contributor being addressed. This table provides a characterization of contribution to each containment release frequency (including large release frequency). If the risk benefits of a SAMA were not quantified based on its equivalence to another quantified SAMA, the unquantified SAMA is considered to address the same containment release contributors as the quantified. However, in cases where the risk benefit of one SAMA were bounded by another SAMA, it was not considered possible to quantify the contribution to containment release of the bounded SAMA. For all such cases, Table 7 was annotated to indicate that the risk benefits are less than the benefits of the quantified SAMA. l Table 8 identifies the CDF reduction and the onsite and offsite dose consequences attributable to each SAMA. A breakdown of offsite dose consequences attributable to each containment release class is provided. (c) The SAMAs that were derived from CCNPP risk insight are annotated with an asterisk (*) on Tables 7 and 8. Those that were derived from the IPE submittal are annotated with the pound symbol (#). NRC Ouestion No.13 Based on Tables F.2-1 and F.2-2, it appears that 24 rather than 25 SAMAs were combined into 9 "new" SAMAs, and 97 rather than 96 of the original SAMAs were designated for further analysis. Several SAMAs are multiple-part and effectively add 8 more SAMAs, bringing the total number of SAMAs subjected to further study to 105. 'Ihe discussion in Section 4.1.17.3 should be modified to be consistent with the information provided in the tables, if needed. BGE Respann A review of Tables F.2-1 and F.2-2 has confirmed that 25 SAMAs were combined into 9 "new" SAMAs, as follows: 1. Six SAMAs (Nos. 2,3,4,6,20,21) were combined into SAMA No. 01

2. Three SAMAs (Nos. 10,11,14) were combined into SAMA No. 03

3. Three SAMAs (Nos. 61,62,63) were combined into SAMA No. 33a, b, c

4. Two SAMAs (Nos. 94 and 97) were combined into SAMA No. 60

5. Two SAMAs(Nos.115 and 116) were combined into SAMA No. 73 L

6. Two SAMAs(Nos.124 and 125) were combined into SAMA No. 79

)

7. Two SAMAs (Nos.142 and 143) were combined into SAMA No. 84

( 8. Three SAMAs (Nos. 82,151,152) were combined into SAMA No. 87

9. Two SAMAs (Nos.103 and 104) were combined into SAMA No. 66a, b Severe Accident Mitigation Alternative Number 63, " Incorporate an alternate battery charging capability," was considered from two aspects. As noted in Table F.2-1, this SAMA would improve 15 l

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS DC power reliability by either cross-tying the AC buses, or installing a portable diesel-driven battery charger. As the first aspect was combined into SAMA Number 33, this SAMA was included in the list of" combined" SAMAs, above. This may account for the apparent discrepancy in the number of SAMAs that were combined into new SAMAs. For the second part of the question, we concur that 97, rather than 96 of the original SAMAs were designated for further analysis. Therefore, the last sentence of the discussion of Preliminary Screening in Section 4.1.17.3 should read: " Based on this preliminary screening,46 candidate SAMAs were eliminated,25 conceptual SAMAs were combined into 9 new SAMAs, and 97 of the original SAMAs were designated for further analysis. Several SAMAs are multiple-part and effectively add 8 more SAMAs, bringing the total number of SAMAs subjected to further study to 105." A similar change should be made to the next-to-last paragraph in Section F.2.2, Qualitative Screening ofSAMAs. NRC Onegipn No.14 Baltimore Gas and Electric Company estimated the net value for each SAMA, and eliminated SAMAs with a negative net value from further consideration. All remaining SAMAs were ultimately eliminated usir4g this criteria. Although a sensitivity analysis was performed to determine the effect of a lower discount rate on the study findings, the impact of uncertainties and incompleteness in other areas of the analysis were not addressed, i.e., uncertainties in CDF, offsite consequences, and cost analyses, and the impact of differences in CDF between Unit I and Unit 2, as discussed in Section 4.1.17.1. In previous evaluations, the staff" screened-in" any design alternative estimated to be within a factor of 10 of being cost beneficial in order to account for uncertainties and incompleteness in the analysis, and subjected those alternatives to further evaluation based on deterministic and engineering considerations. In this regard, please provide the following: (a) an assessment of the impact that uncertainties and Unit 1/ Unit 2 CDF difrerences could have on the identification of cost-beneficial SAMAs, (b) a listing of SAMAs that could become cost beneficial when these factors are taken into account, and (c) an engineering argun ent supporting BGE's implementation decision for each SAMA identified in item b. BGE Respons As discussed in Reference 3, Section 4.1.17.4, each SAMA was evaluated in a bounding fashion. These bounding evaluations were performed to address the generic nature of the initial SAMA concepts and to allow each SAMA benefit to be calculated using the saved sequences instead of re-quantifying the CCNPP plant risk model. The bounding evaluation assumed that the conceptual SAMA provides the total benefit of each of the many specific enhancements that could be implemented for each conceptual SAMA. As a result of following this conservative approach, re-analysis of each SAMA to address uncertainties and incompleteness would typically result in a reduced calculated risk benefit. On the other hand, evaluating the differences in plant design (and the resultant CDF) between Unit I and Unit 2 may result in a higher calculated risk benefit for the Unit 2 enhancement. Baltimore Gas and Electric Company's approach to evaluating the effects of uncertainty, changes to the plant model, and CDF variance between units followed a three-step approach: 16

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; { APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS i 1 l. Determine the "Besi Estimate" benefit; 2. Determine an adjustment factor to account for any known changes to the model; and

3. Determine an adjustment factor to be used to account for design differences between Unit I and Unit 2.

These three steps were based on a qualitative review of the CCPRA plant risk model and the method of analyzing the SAMA for the original analysis. As a result of the qualitative review, correction factors were derived for application to the calculated risk benefit. By applying the correction factors, a revised risk benefit value was calculated. This revised benefit, referred to as the Best Estimate, is considered to be much closer to the actual risk benefit of each SAMA than the previously-calculated bounding value. A more detailed discussion of the three-step approach, including an example of the application of this process to a representative candidate (SAMA No. 38-b) follows. 1

1. Determine the "Best Estiaate" Benefit As the SAMA benefits were estimated using the " saved sequence" quantification method described on page 4-29 of Reference 3, the resultant benefits are not as accurate as if full plant model quantification had been performed. Therefore, the determination of benefits for the SAMA analysis typically included two bounding benefits estimations, a lower bound and an upper bound estimate. The lower bound represents the minimum present value benefit over a 20-year period for the enhancement, and the upper bound represents the maximum benefit. In all cases, maximum benefit, based on the upper bound estimate was used in the original SAMA analysis.

Without re-quantifying the full plant model to more exactly determine the SAMA benefits, it was possible to qualitatively evaluate each SAMA to estimate how much conservatism was built into each bounding estimate. The bounding estimates are then re-quantified, and a "Best Estimate" was determined to be in the range between the two revised bounding estimates. The best estimate benefits were also adjusted to account for possible changes in the economic and evacuation time assumptions used as input into the MACCS analysis. The AOSC presented in Reference 3, Table 4-3 were doubled to account for changes to the economic input data resulting from infiation. The APE results presented in Table 4-3 were also doubled to account for increased evacuation times resulting from increased population. The modification proposed for SAMA No.38-b was to double the capacity of the fuel oil day i tanks. The original analysis estimated an upper bound benefit of $429,000. The AOSC and APE adjustments were incorporated by adding these values back into the original bounding estimate ($429,000 + $52,000 +$29,000 = $510,000). The bounding estimate was developed by assuming that the EDGs will never be required for a period of time in excess of the amount of time the fuel oil day tanks are available before make-up is required. This is very conservative, as during a long duration loss of offsite power, many components beyond the fuel system itself are required to function (e.g.,the EDG itself). To account for this, the best estimate was approximated by reducing the bounding estimate by 60 percent to 80 percent. The best estimate was determined to be $204,000 (i.e.,40% x $510,000). t 17

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS

2. Determine a correction factor to be used for known model changes or omissions The CCPRA model is constantly evolving to incorporate plant modifications, revisions to plant equipment availability factors, and revisions to modeling techniques and assumptions based on updated information. The SAMA analysis was based on a " snap-shot" of the CCPRA model, and is not intended to reflect these changes. However, to perform a comprehensive uncertainty analysis, a correction factor has been estimated for each of the 10 SAMAs subject to additional review. The correction factor is an attempt to quantitatively assess the effect of changes to the plant model, based on qualitative knowledge of the CCPRA model and the plant. In all cases, the correction factor is less than or equal to 1.00 (i.e., changes to the plant model would reduce the calculated risk benefit).

There were no known omissions or changes to the CCPRA model that would affect SAMA No. 38-b; therefore, the correction factor was 1.00.

3. Determine an adjustment factor to be used to account for design differences between Unit I and Unit 2 As noted in Reference 3, SAMAs that modify systems that support the EDGs (e.g., enhance SRW performance), would have a somewhat larger benefit on Unit 2 than on Unit 1. Improvements which are not associated with the configuration differences between the Units will produce nearly identical results. Therefore, if a SAMA modifies an EDG support system, the benefit may be much higher (up to four times) for Unit 2 than the estimated benefit for the same modification or Unit 1.

For SAMA No. 38-b, tne Unit 2 benefit would be higher than the corresponding Unit 1 benefit, because the SAMA modifies an EDG support system, However, the enhancement does not address EDG cooling, or the SRW System, so it was judged that an adjustment factor of 2 should be applied to the calculated Unit 1 benefit. The revised Best Estimate for Unit 2 was determined j to be $408,000 ($204,000 x 2). Baltimore Gas and Electric Company has evaluated the effect of uncertainties on the 10 SAMA candidates with the highest net values (see response to NRC Question No. 7 for a discussion of the derivation of the " Top 10" list). The results of the uncertainty evaluation is described in detail below. For each SAMA, six best estimates are provided (three for each Unit). The estimates vary depending upon which AOSC assumptions are used (i.e., whether or not to include replacement power costs or the insured portion of on-site property damage). I8

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SAMA No. 7 - Installation of redundant AFW pump room ventilation that automatically starts on high temperature. The system would be diverse (no common cause/ mode) and self-powered. Best Estimate Benefit Umt 1 Umt 2 Including replacement power cost and insured portion of AOSC: $166,000 $166,000 Including insured portion of AOSC only: $134,000 $134,000 Excluding replacement power cost and insured portion or AOSC: $85,000 $85,000 j Changes to COE Estimate The cost of this enhancement was estimated to be $226,000 in Reference 3. Although this estimate includes a considerate amount of conservatism (engineering and construction craft hours are low), the i only change that would be recommended at this time is to include the allowance for funds used during construction (AFUDC) costs (25 percent of total cdmated capital costs). This change will result in a revised estimate of $282,000. i Engineering / Operations Diseussion The engineering / operations discussion of this SAMA is unchanged from that provided in Reference 3, Appendix F.4. Conclusion Based on the best estimate benefits provided above, and the revised estimate of $282,000, this SAMA has a negative net value irrespective of the AOSC approach taken. SAMA No. 34 - Reduce the likelihood of battery depletion by modifying the plant such that a portthie generator could be used to directly feed each of the four ?25 Volt DC buses. I Best Estimate Benefit Umt 1 Umt 2 Including replacement power cost and insured portion of AOSC: $186.000 $186,000 Including insured portion of AOSC only: $138,000 $138,000 Excluding replacement power cost and insured portion or AOSC: $62,000 $62,000 t l Chanfes to COE Estimate l The cost of implementing this SAMA was based on an estimate submitted by the Tennessee Valley Authority for the Watts Bar Nuclear Plant Severe Accident Mitigation Design Alternatives analysis. A more precise estimate has been prepared for implementation of this SAMA at CCNPP. The revised cost of implementation for SAMA No.34 is approximately $220,000. The details of the revised estimate are provided in Attachment 4. 19 l i

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Engineering /Onerations Discussion The engineering / operations discussion of this SAMA is uncnanged from that provided in Reference 3, Appendix F.4. Conclusion Based on the best estimate benefits provided above, and the revised estimate of $220,000, this SAMA has a negative net value irrespective of the AOSC approach taken. A I SAMA No. 36 - Replace batteries with a more reliable model. Best Estimate Benefit Umt 1 Umt 2 including replacement power cost and insured portion of AOSC: $585,000 $585,000 including insured portion of AOSC only: $431,000 $431,000 Excluding replacement power cost and insured portion or AOSC: $186,000 $186,000 l Changes to COE Estimate As discussed in Reference 3, Appendix F.4, the cost of replacing the five banks of batteries was based on the cost of the recent battery replacement in 1997 ($750,000 for both units). However, this estimate would only apply if BGE could locate new batteries that are more reliable than the existing ones, at the same price as the existing batteries. Additionally, major structural modifications would be required if the new batteries are any larger than the existing batteries. The cost of structural modifications was not included in the estimated COE. Engineering /Onerations Discussign ne four station batteries and Diesel Generators No. l A and OC batteries are installed to provide emergency 125 VDC operating power in the event that normal 125 VDC power from the battery chargers becomes unavailable. An independent reserve battery, identical in design and construction to the four station batteries, is normally maintained in a standby condition to increase system reliability. The GNB Technologies batteries each consist of lead acid battery cells (59 cells for Batteries No. ll,12, 21 and 22; 60 cells for Batteries No.01,14 and 15) that are electrically connected in series to produce an output voltage of 125 VDC. He plates in each cell are made of a lead calcium alloy. Distilled water is required to maintain electrolyte level. Each battery is monitored by a battery monitor that detects the loss of battery availability. Individual battery current meters and battery trouble lights are provided in the Control Room. Lead acid battery technology has been available to the industry for several decades. Over the years, lead acid batteries have been proven to be one of the most reliable large storage cell designs on the market. Based on this proven record of reliability, BGE chose to replace the existing lead acid batteries with a new system manufactured by GNB Technologies in 1997. While some other plants have recently opted to install high specific gravity round cells, this technology has not been proven to be more reliable than lead acid batteries, and in some cases has resulted in failed capacity tests after a relatively short period of operation. Therefore, BGE does not believe that, at the present time, there 20

A'ITACHMENT (1) RESPONSE YO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS are any feasible options available that have been proven to be more reliable than the currently-installed lead acid batteries. Furthermore, BGE's current requirements for weekly, quarterly, and biennial surveillances are consistent with current industry practice and NRC requirements, to ensure an acceptable level of battery reliability. Conclusion Implementation of this SAMA would not be risk-beneficial, based on the best estimate benefit values, nor is it considered feasible, based on the reliability record of modern lead acid batteries. SAMA No.38-b-Double the capacity of fuel oil day tanks with the additional volume placed between the day tank level switches. Dgst Estimate Benefit Umt 1 Umt 2 Including replacement power cost and insured ponion of AOSC: $204,000 $408,000 Including insured portion of AOSC only: $151,000 $302,000 Excluding replacement power cost and insured portion or AOSC: $68,000 $135,000 Changes to COE Estimate The estimated cost of this enhancement was provided in Reference 3, Appendix F.4. This conceptual estimate has been revised to include the AFUDC costs (25 percent of total estimated capital costs). This change will result in a revised estimate of $674,000. Engineering /Onerations Discussion The engineering / operations discussion of this SAMA is unchanged from that provided in Reference 3, Appendix F.4. Conclusion Based on the best estimate benefits provided above, and the revised estimate of $674,000, this SAMA has a negative net value irrespective of the AOSC approach taken. . -- m = - l l SAMA No. 45 - Use Fire Protection System as a back-up r scret for 6esel cooling Best Estimate Benefit Umt 1 Umt 2 Including replacement power cost and insured portion of AUK $456,000 $1,825,000 Including insured portion of AOSC only: $320,000 $1,282,000 Excluding replacement power cost and insured portion or AOSC: $104,000 $418,000 i 21

l \\ ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Changes to Cost of Enhancement Estimate The cost ofimplementing this SAMA was re-estimated by BGE. The revised cost ofimplementation for SAMA No. 45 is $1,950,000. The details of the revised estimate are provided in Attachment 4. Engineering /Onerations Discussion The basis for this SAMA is to provide a back-up means of cooling the Fairbanks-Morse EDG jacket water, intercoolers, and lube oil subsystems should a loss of ofTsite power occur, thereby requiring the service of the EDGs for plant shutdown and accident mitigation. The normal source of EDG cooling is provided by the safety-related SRW System. Six-inch SRW supply and return lines provide the 850 gallons per minute required to cool each EDG. The heat removed from the EDGs is transferred I from SRW to the Chesapeake Bay by the safety-related Saltwater (SW) System. The SRW System is a closed system that uses DW with a corrosion inhibitor added. The ability to control the chemistry is crucial to maintaining the longevity of the SRW System as well as the equipment and components cooled by this system. The FP System water supply originates from three wells located onsite. The water is pumped to two 500,000 gallon pretreated water storage tanks located at the Fire Pump House. The chemistry of the water used in the FP System is not controlled, and no corrosion inhibitors are added. Although water chemistry would be a minimal consideration if the EDGs were actually called upon to mitigate an accident, this issue could be problematic during periodic testing of the proposed FP feed to the EDGs. Furthermore, although cooling water could be i returned to the pre-treated water storage tanks following testing or use in an actual event in which the FP System was needed to cool the EDGs, the system would need to be designed to ensure that all potable water requirements are maintained. 1 The diesci engine-driven fire pump starts automatically if electric power to the electrically-driven pump is interrupted. This pump is capable of providing 2500 gpm at a discharge pressure of 125 psig. Each EDG requires approximately 850 gpm of cooling water; leaving only 1650 gpm for fire suppression purposes. This quantity may be sufficient for most postulated plant fires; however, the plant's response to large fires may require the ability to block the FP feed to the EDGs, either automatically or manually. For example, a fire in the rooms that could result in a loss of SRW is estimated to require over 1,600 gpm for sprinkler flow and hose streams. Implementation of this SAMA would require extensive training and procedure changes to ensure plant operators are knowledgeable of the need to weigh the various water flow needs in the unlikely event of a simultaneous large fire, loss of offsite power, and SRW System loss. These are just a few of the of concerns that would need to be addressed prior to implementation of any modification that would cross-connect the FP System with the SRW System. The major concerns include: water chemistry concerns; 10 CFR Part 50, Appendix R compliance requirements; the acceptability of returning FP System inventory to the pretreated water storage tanks during testing; and Engineered Safety Features Actuation System (ESFAS) interface requirements. For this analysis, l it was assumed that these concerns could be resolved from both a plant design and regulatory l perspective, and that a feasible approach to implementing this SAMA could be ider;tified; however, the details of resolving each of these concerns would not be ascertained without performing a detailed i design review. No such review has been performed for this SAMA analysis. l 22

i ATTACHMENT (1) i RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; l APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; l SECTION 4.1.17 SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Conclusion Based on the best estimate benefits provided above, and the revised estimate of $1,950,000, this SAMA has a negative net value irrespective of the AOSC approach taken. Furthermore, due to concerns associated with cooling water chemistry,10 CFR Part 50, Appendix R, and ESFAS control considerations, the potential detrimental effects of this SAMA on the existing plant systems and our compliance with regulatory requirements may exceed the calculated benefits of its implementation. Therefore, no further consideration of this SAMA is warranted. SAMA No. 48-a - Convert UV, AFAS Block and High Pressurizer Pressure to 3-out-of-4 Logic. I Best Estimate Benefit Unit 1 Umt 2 Including replacement power cost and insured portion of AOSC: $840,000 $924,000 Including insured portion of AOSC only: $617,000 $679,000 Excluding replacement power cost and insured portion or AOSC: $263,000 $290,000 Changes to COE Estimate The cost ofimplementing this SAMA was re-estimated by BGE. The revised cost ofimplementation for SAMA No.48-a is $598,000 per Unit ($1,196,000 for two Units). The details of the revised estimate are provided in Attachment 4. Engineering /Onerations Discussion Severe Accident Mitigation Alternative No.48-a provides a means of mitigating a spurious safety system actuation. On the failure of two 120 Volt vital AC panels, all ESFAS, AFAS, and RPS actuation modules trip. The 120 Volt vital AC panels are assumed to fail due to failure of the 125 VDC buses or due to the loss oflong-term charging to the 125 VDC buses. The availability of long-term 125 VDC is primarily controlled by the availability of offsite power and 48') VAC transformers. The loss of multiple 480 VAC transformers is assumed to be the result of a postulated common cause failure. The spurious safety systems actuation impacts include loss of main feedwater, SRW-cooled EDGs, condensate booster pumps, AFW and safety injection, as well as a PORV spurious opening. If the PORV does not reseat and is not isolated, it is considered a LOCA. Severe Accident Mitigation Alternative No.48-a proposes mitigating this scenario by changing the coincidence logic of the ESFAS UV, RPS High Pressurizer Pressure PORV actuation, and AFAS Block signals from 2-out-of-4 to 3-out-of-4 logic. While the actual field modifications required to implement this modification would be relatively minimal (i.e., replacement of logic modules for UV and AFAS Block and auxiliary RPS PORV trip unit relays), regulatory aspects may cause the cost of i this rnodification to exceed the benefit. The CCNPP ESFAS, AFAS and RPS current designs meets the requirements ofInstitute of Electrical and Electronic Engineers 279-68, " Criteria for Protection Systems for Nuclear Power Generating Stations" and the applicable sections from the NRC's proposed General Design Criteria, as published February 20,1971. These standards contain requirements for single failure and channel bypass or 23 l

-- 1 i ATTACIIMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS removal capability. With a 3-out-of-4 logic configuration, a Technical Specification change would be required to allow for channel testing. There are two possible channel testing options both of which would place the altered ESFAS signals briefly in a 3-of-3 logic. The testing options are either placing the channel in bypass during the test or allowing the channel status to vary with the test conditions. Placing the channel in bypass has the advantage of maintaining positive control over the test, but during the entire bypass period the altered ESFAS signals being tested remain in a 3-of-3 logic. If the channel is not bypassed, the test itselfis slightly more thorough as the technician can observe the complete response of the ESFAS channel. The disadvantage of this test approach is the fluctuations could desensitize the control room operators to partial ESFAS actuations during the testing. In the non-bypassed approach, there is still a period of time when a test signal essentially blocks out any valid signals, effectively resulting in a 3-of-3 logic. During the brief period of time the altered ESFAS signals are in a 3-of-3 configuration, the testing technician and control room operators would be relied upon to restore the tested channel during an actual event. Therefore, it is probably best to place the ESFAS in bypass to avoid desensitising the operators to the actuations. Severe Accident Mitigation Alternative No.48-a alters the facility as it is described in the Updated Final Safety Analysis Report; therefore, implementing this change would require a 10 CFR 50.59 evaluation, and most likely, an Unreviewed Safety Question (USQ) submittal. Furthermore, the CCNPP Technical Specifications would also require revision. An estimate of the regulatory costs ] was included in the estimated cost of this SAMA; however, the actual costs could vary significantly from those provided in the estimate. Conclusion Based on the best estimate benefits provided above, and the revised estimate of $598,000 per Unit, this SAMA has a negative net value if replacement power costs and the insured portion of onsite property damages are not included in the AOSC portion of the benefits. For the reasons described in detail in response to NRC Question No. 7, BGE feels that these are the appropnate assumptions for a NEPA enalysis such as the SAMA analysis. Although the results of this analysis indicate a positive net value if property damage insurance is not credited, the actual costs of this modification could far exceed the calculated benefit, when all of the costs of the regulatory aspects of the modification are taken into account. Due to this concern, BGE has decided not to pursue this SAMA any further. SAMA No. 48-b - Operate with the PORV block valves shut. Best Estimate Benefit Umt 1 Umt 2 Including replacement power cost and insured portion of AOSC: $85,000 $93,000 Including insured portion of AOSC only: $60,000 $66,000 Excluding replacement pc,wer cost and insured portion or AOSC: $22,000 $24,000 Chances to COE Estimate The cost of this SAMA is unchanged from that provided in Reference 3 (i.e., $125,000). 24

ATTACHMENT (1) j RES?ONSE TO REQUEST FOR ADDITIONAL INFOR31ATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS 1 1 Engineering /Onerations Discussion The engineering / operations discussion of this SAMA is unchanged from that provided in Reference 3, Appendix F.4. ) Conclusion Based on the best estimate benefits provided above, and the original estimate of $125,000, this SAMA has a negative net value irrespective of the AOSC approach taken. I \\ \\ SAMA No. 68 - Install separate accumulators fcr the AFW cross-connect and AFW block valves to separate this equipment from the constant bleed equipment (e.g., AFW flow control valves). Best Estimate Benefit Umt 1 Umt 2 Including replacement power cost and insured portion of AOSC: $281,000 $309,000 Including insured portion of AOSC only: $209,000 $230,000 Excluding replacement power cost and insured portion or AOSC: $96,000 $106,000 Changes to COE Estimate l The estimated cost of this enhancement was provided in Reference 3, Appendix F.4. This conceptual estimate has been revised to include a factor for the AFUDC, which accounts for the cost of borrowing funds for capital projects. Based on this revised estimate, the revised cost of this enhancement is approximately $268,000 per unit ($535,154 for two units). The details of the revised estimate are provided in Attachment 4. Engineering /Onerations Discussion The engineering / operations discussion of this SAMA is unchanged from that provided in Reference 3, j Appendix F.4. Conclusion Based on the best estimate benefits provided above, and the revised estimate of $268,000, this SAMA has a negative net value for both Units if replacement power costs and the insured portion of onsite property damages are not included in the AOSC portion of the benefits. Furthermore, if the property damage insurance coverage is not credited, the net value of this SAMA is still negative for both Units. The net value for this SAMA only becomes positive when replacement power costs and insured onsite property damages are included in the analysis. For the reasons described in detail in response to NRC Question No.7, BGE feels that replacement power costs and insured onsite property costs are not appropriate considerations for a NEPA analysis such as the SAMA analysis. Therefore, this SAMA is not considered risk-beneficial. 25

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; l SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SAMA No. 74 - Automate DW make-up to Condensate Storage Tank No.12. This system must have a dedicated diesel generator. Best Estimate Benefit Umt 1 . Unit.2 Including replacement power cost and insur.d portion of AOSC: $276,000 $689,000 Including insured portion of AOSC only: $199,000 $498,000 Excluding replacement power cost and insured portion or AOSC: $78,000 $196,000 Changes to COE Estimate l The modification proposed by SAMA No. 74 affects a system that is common to both nuclear units (i.e., Condensate Storage Tank No.12 and the associated make-up system is common to CCNPP Units I and 2). In the analysis performed to Reference 3, the cost was divided by two, to facilitate the comparison between the estimated cost of implementing the modification and the estimated one-unit benefit. However, based on the Unit 1/ Unit 2 best estimate benefits provided above, it would be more i appropriate to compare the two-unit costs and benefits for this particular modification, as it is not possible to implement the SAMA on one unit without benefiting both Units. i The cost ofimplementing this SAMA was re-estimated by BGE. The revised cost ofimplementation for SAMA No. 74 on both Units is $752,000. The details of the revised estimate are provided in. l Engineering /Ooerations Discussion The engineering / operations discussion of this SAMA is unchanged from that provided in Reference 3, Appendix F.4. Conclusion l Based on the best estimate benefits provided above, and the revised two-unit estimate of $752,000, this SAMA has a negative net value (i.e.,-$478,000) if replacement power costs and the insured portion of onsite property damages are not included in the AOSC portion of the benefits. Furthermore, if the property damage insurance coverage is not credited, the two-unit net value of this SAMA is still negative (i.e.,-$55,000). The net value for this SAMA only becomes positive (i.e., $212,00) when replacement power costs and insured onsite property damages are included in the analysis. For the reasons described in detail in response to NRC Question No. 7, BGE feels that l replacement pcwer costs and insured on-site propeny costs are not appropriate considerations for a NEPA analysis such as the SAMA analysis. l 26 i

4 e ATTACHMENT (1) { RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; l APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS j SAMA No. 77 - Install high espacity PORVs such that a single PORV is capable of providing adequate decay heat removal Best Estimate Benefit i Umt 1 Umt 2 Including replacement power cost and insured portion of AOSC: $2,477,000 $2,477,000 Including insured portion of AOSC only: $1,917,000 $1,917,000 Excluding replacement power cost and insured portion or AOSC: $1,031,000 $1,031,000 l Changes to COE Estimate The estimated cost of replacing the CCNPP's PORVs, block valves, and associated discharge piping was based on the PORV replacement modification completed at Palisades Nuclear Power Plant (PNPP) in 1989. This estimate is considered applicable at CCNPP, as the Nuclear Steam Supply System for PNPP was also designed by Combustion Engineering. The cost of replacing the PORVs at PNPP was approximately $2.7 million (Reference 17). Accounting for inflation at three percent per year, the revised estimate for this SAMA is $3.5 million. i Enf neerinp/Ooerations Discussion The engineering / operations discussion of this SAMA is unchanged from that provided in Reference 3, Appendix F.4. Conclusion l Based on the best estimate benefits provided above, and the revised estimate of $3,500,000, this SAMA has a negative net value irrespective of the AOSC approach taken. l l NRC Ouestion No.15 l In general, where values for " Maximum Benefit" and/or " Cost of Enhancement" are provided in Table F.2-2, the basis for those values is described in Appendix F.4. However, this information is missing for many SAMAs (e.g., the bases for the Maximum Benefit estimates for SAMAs 2,4, and 10, and the bases for the COE estimates for SAMAs 3,6, and 9). The basis for all numerical values should be provided in order to clarify the screening that was performed based on the numerical values. Also, wherever a cost estimate is taken from another source, the applicability of the estimate to CCNPP should be addressed. For example, the cost to create a reactor cavity flooding system was estimated at over 8 l million dollars based on a TVA [ Tennessee Valley AuthorityJ estimate for Watts Bar. The applicability l of such cost estimates to CCNPP should be addressed since the CCNPP reactor cavity is easily flooded relative to the Watts Bar cavity due to differences in containment layout. BGE Response The method of estimating SAMA benefits is discussed in Reference 3 (Section 4.1.17.4). In general, the Maximum Benefit amount for each SAMA was estimated using a boulding approach. For example, if a SAMA would improve the reliability of plant cooling water systems, the SAMA benefit would be determined by setting the cooling water system function to success (i.e., assuming loss of the cooling water function is impossible). Table 10 provides a short description of the approach taken 27 l

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS to estimate the risk benefit that would be gained by implementing each SAMA. For SAMAs where a more detailed discussion of the approach has been provided elsewhere (e.g., in Attachment F.4 of the Reference 3), a reference to that discussion is provided in Table 10. Table 10 also provides a short description of the basis for determining the cost ofimplementation for each SAMA. In some cases, the estimated cost ofimplementation was based on an estimate prepared for another plant or the actual cost of a modification that was implemented at another plant. Prior to referencing such a cost estimate in CCNPP's SAMA analysis, BGE reviewed the estimate to verify its applicability to CCNPP's design. Even if the referenced plant's design did 1.ot correspond exactly to CCNPP's design, the cost of the modification may be used to indicate the magnitude of the difference between the benefit and the cost. For the case of the reactor cavity flooding system, the cost of this system was over three times the maximum benefit attainable for the base case SAMA (i.e.,the theoretical SAMA that would eliminate all of CCNPP's risk). In reality, the maximum benefit calculated for this modification would be a fraction of the benefit calculated for the base case SAMA. As this estimate was based on a plant that had not yet begun commercial operation, it did not include such costs as lost generation costs due to an extended outage required to implement the modification or additional costs of protecting construction workers from radiation effects. Furthermore, many of l the same design features of a core flooding system at Watts Bar Nuclear Power Plant would apply at CCNPP, such as power and control requirements, etc. Therefore, cost estimates from other plants were only used in CCNPP's SAMA analysis to estimate the magnitude of the cost of the modification, rather than to provide a precise determination ofits cost. These estimates were not used in modifications that were clearly inapplicable to CCNPP or where the variance between the referenced plant and the actual cost at CCNPP would affect the results of the analysis. NRC Ouestion No.16 Provide the results or a schedule for the results of BGE's evaluation of the three SAMAs that were still being reviewed at the time of the license renewal application submittal (SAMA numbers 49, 66b, and 96). BGE Response i A summary of the results of BGE's evaluation of SAMA Numbers 49,66-b, and 96 is provided in i Table 11. A discussion of the methodology and approach for evaluating each of these three SAMAs follows. l SAMA Number 49-Add an automatic bus transfer feature that would automatically transfer between either the back-up bus or the stand-by inverter on the failure of the operating i inverter. Discussion The 120 VAC panels can fail due to failure of the 125 VDC buses or due to the loss of long-term charging to the 125 VDC buses. Upon the failure of two 120 VAC panels, all ESFAS, AFAS, and RPS actuation modules trip. This failure may lead to the risk-significant scenario referred to as SSSA. This SAMA would address this potential vulnerability by minimizing the potential failure of a 120 VAC bus by automatically aligning an inverter to the back-up bus or stand-by inverter upon failure of the on-line inverter. Currently installed equipment and procedures allow for manual transfer only. 28 4

ATTACHMENT G) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Approach to Estimating Bounding SAMA Benefit This benefit is estimated in the plant model by setting the failure probability of all 125 VDC and 120 VAC hardware to zero and by setting the major initiating events, which cause a prolonged loss of offsite power to zero (using the bounding evaluation from SAMA 48-a). This is a conservative estimate. Following the assumptions in Section 4.1.17.2 of Reference 3, the averted environmental impacts (benefits) for Unit 1 are estimated to be: Averted Public Exposure (11.4 Rem): $245,000 Averted Offsite Costs: 133,000 Averted Onsite Costs: 0 Averted Occunational Exnosure (1.62 Remt 35.00Q Total Benefits $413,000 i The conservative evaluation of this SAMA results in a CDF reduction of 9.14E-05/ year. If BGE's property damage insurance is not credited, the averted onsite property damage would be $1,062,000; and if the effects of deregulation are disregarded, the replacement power costs would be $670,000. Therefore, using the modified AOSC assumptions, the total benefit of this SAMA becomes $2,145,000. As noted in response to Question No.14, BGE approached the SAMA analysis using a bounding approach to estimating SAMA benefits. The approach described above is a bounding approach to estimating the benefits of an automatic transfer switch (ATS) that would replace the preferred (or operating) invener with its back-up counterpart in the event of an inverter failure. The benefits of this S.AMA were determined to be similar to those of SAMA No. 48-a, as both SAMAs are intended to prevent the SSSA scenario. Therefore, the "best estimate" benefit discussed in response to Question No.14 for SAMA No.48-a could be considered appropriate for this SAMA, with the following exceptions:

1. If the failure of the operating inverter was caused by a fault on the bus, placing the back-up l

inverter on the same bus could result in damage to the back-up inverter as well; and

2. The analysis does not consider the potential for failure of the ATS, which could ultimately l

result in the loss or both inverters. (It should be noted that the design of the existing inverters excluded automatic transfer capability to eliminate this potential failure mode.) The best estimate benefits for SAMA No. 48-a are: Umt 1 Umt 2 l Including replacement power cost and insured portion of AOSC: $840,000 $924,000 Including insured portion of AOSC only: $617,000 $679,000 Excluding replacement power cost and insured portion or AOSC: $263,000 $290,000 Engineering / Operations Discussion Calvert Cliffs Nuclear Power Plant has a uniquely-designed inverter system. The original design consisted of one 7.5 KVA invener per vital bus. When the inverters were replaced, BGE installed two 7.5 KVA inverters per vital bus, with both inverters for each bus installed in a single cabinet. 29

ATTACIIMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS i The new inverters have a manual transfer switch with a synchronizing circuit so that the load can be shifted between either inverter or the back-up bus without dropping the load. The purpose of an ATS is to provide a source of energy large enough to clear a fault by opening an electrical protection device (i.e., a fuse at CCNPP). The reason for the required transfer is that inveners have a limited current output. In some cases, the current may not be large enough to clear a fault; consequently, the ATS transfers the fault to a source that has enough current to clear the fault, such as the back-up bus. Then the load could be transferred back to the preferred source or to the back-up inverter. The CCNPP design would require a specially-designed ATS. The logic would have to be developed such that it could sense a fault and transfer the load from either inverter to the back-up bus and then back to the non-faulted inverter. The fault-sensing circuit would have to be designed such that it would not allow the continuous transfer between the two inverters and damage both inverters simultaneously, i The use of the back-up bus at power requires the inverter to be declared inoperable according to CCNPP's Technical Specifications. The ATS would require Control Room indication / annunciation to inform the operators of the transfer and ensure that we do not unknowingly enter the Technical Specification action statement. The ATS would have to be designed to allow only one channel to be powered from the back-up bus due to the electrical separation criteria. Consequently, if two different inverters failed at the same time, only one inverter would be able to take advantage of an ATS. Cost Analysis Due to the unique design of CCNPP's inverters, a complicated ATS control circuit would need to be designed. Based on a quotation provided by a qualified vendor of electrical equipment, the estimated cost for the design of an ATS and the necessary installation hardware is $650,000. The qualification of the ATS for use on the CCNPP dual inverters would be in excess of $100,000. Based on the cost ofinstalling the existing dual inverters, BGE's labor costs, including engineering, are estimated to be in excess of $250,000. These costs assume no changes would be made to the electrical distribution system. Any changes to the electrical distribution system would greatly increase the cost of the engineering and labor. Based on current industry trends, it is expected that this modification would involve an USQ, as the ATSs would provide a new function that is not described in CCNPP's Safety Analysis Report. The typical USQ submittal at CCNPP costs approximately $50,000. A detailed conceptual estimate is provided in Attachment 4. As indicated in Attachment 4, the estimated cost ofimplementation on both Units is approximately $1,768,000 ($884,000 per Unit). Net Value Determination Based on the single-unit COE of $884,000 and the $413,000 benefit, this SAMA has a negative net value (-$471,000) if replacement power costs and the insured portion of onsite property damages are not included in the AOSC portion of the benefits. For the reasons described in detail in response to Question No. 7, BGE feels that these are the appropriate assumptions for a NEPA analysis such as the SAMA analysis. I 30 i

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Using the bounding approach for estimating the benefit, a positive net value is indicated if BGE's property damage insurance is not credited, and replacement power costs are added to the AOSCs. Ilowever, as discussed in response to Question No.14, the bounding approach is an extremely conservative approach for determining the benefit of many SAMAs. The best estimate benefits for SAMA No. 48-a may conservatively be applied to this SAMA, as they address the same scenario, an SSSA, but do not reflect the inherent failure mechanisms of ATSs. Based on these best estimate benefits, this SAMA results in a negative net value for all cases, except for the Unit 2 case with replacement power costs and insured property damages included. Based on the small positive net value for this case ($40,000), and the fact that the estimated benefits for SAMA No.48-a are conservative when applied to this SAMA, BGE has concluded that this SAMA is not risk-beneficial. { SAMA Number 66-b - Implement internal flood prevention and mitigation enhancement (i.e., water-tight doors). Discussion Calvert Cliffs' flood risk calculations consider the probability of a pipe rupture occurring, equipment that would be damaged in the room where the break occurred, flood propagation paths into other plant areas, and damage to redundant equipment in other areas within the flood propagation path. A pipe break will not typically lead to core damage, if redundant equipment remains ftmetional. Therefore, j BGE opted to evaluate this SAMA by considering an option to prevent flood propagation from one plant area to another. Flood propagation could be prevented by installing water-tight doors or hatches in place of existing doors / hatches. This type of modification would need to be considered on an area-by-area basis, beginning with the plant areas demonstrating the greatest risk of flood initiation, where propagation could result in the loss of redundant equipment needed to safely shut down the plant. l Approach to Estimating B_Runding SAMA Benefit i The overall benefit of eliminating all plant risk due to floods resulting from pipe breaks was estimated by setting all of the flood initiating event frequencies to zero. Following the assumptior.s in Attachment (2), Section 4.1.17.2 of Reference 3, the averted environmental impacts (benefits) of eliminating all plant risk from pipe break floods were estimated to be: Averted Public Exposure: $541,000 Averted Offsite Costs: 235,000 Averted Onsite Costs: 0 Averted Occuoational Exoosure: 6.000 Total Denefits $782,000 This SAMA results in a CDF reduction of 1.61E-05/ year. If BGE's property damage insurance is not l credited, the averted onsite property damage would be $187,000, and if the effects of deregulation are i disregarded, the replacement power costs would be $118,000. Therefore, using the modified AOSC assumptions, the total benefit of this SAMA becomes $1,087,000. At Calvert Cliffs, flood risk has been calculated for each plant area in which a pipe break may occur. Based upon these calculations, four plant areas are responsible for approximately 66 percent of all 31

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS plant risk due to Hood mitigation. These areas are the SRW Pump Room (33.4 percent), AFW Pump Room (12.5 percent), East Piping Penetration Room (11.1 percent), and CC Pump Room (8.8 percent). The contribution of each area may be multiplied by the total benefit of this SAMA to estimate the benefit of preventing Hood propagation fmm that particular area. For example, the benefit of a modification that would prevent flood propagation from the SRW Pump Room would be $261,000 ($782,000 x 33.4%). However, a water-tight door between the SRW Pump Room and the adjacent fan room would not only prevent flooding anLnf the SRW Pump Room, but would also prevent water from passing inin this room from the fan room. Therefore, installation of a water-tight door in this location would eliminate about 60 percent of all plant flooding risk, for a risk benefit about $470,000 (up to $650,000, depending upon which set of AOSC assumptions are used). The risk benefits to be gained by installing a water-tight door in this location have been identified by BGE's Reliability Engineering Unit. The existing door has been evaluated under a comprehensive evaluation of the flood propagation pathways at CCNPP. Based on this evaluation, an issue report was initiated to track the resolution of this issue. The evaluation and potential replacement of this door with a water-tight door is currently being resolved under BGE's Corrective Actions Program. It is expected that replacement of this door, if necessary, will eliminate about 60 percent of all plant flooding risk; therefore, the remaining flood propagation risk for other doors in the plant will also be reduced. Ifit is d ermined that the replacement of other doors or hatches would be risk beneficial, these rr.odificati' vill also be initiated and tracked by the Corrective Actions Program. Engineering /Og ations Discussion Baltimore Gas and Electric Company has confirmed that the standard 3-foot by 7-foot metal door installed between the SRW Pump Room and the Radiation Exhaust Ventilation Equipment Room would not withstand the full force of an unmitigated pipe rupture in the SRW Pump Room. Although this type of pipe rupture is extremely unlikely (on the order of IE-05 per year or IE-09 per hour), and is outside BGE's current licensing basis, the risk of such an event is relatively high, due to the potential consequences. As a result of the risk-significance of this scenario, BGE has initiated an issue report, and will track the implementation of any modifications to this doorway under the Corrective Actions Program. Cost Analysis Assuming the appropriate corrective action is to replace the existing door between the SRW Pump Room and the Radiation Exhaust Ventilation Equipment Room with a water-tight door, the cost of such a modification would be estimated under the plant modification process. Although a formal estimate has not been completed, it is expected to be well below the estimate benefit for this SAMA (i.e., $470,000). 32

l ATTACHMENT (1) l RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; } APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; i SECTION 4.1.17 SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS l SAMA Number % -Implement procedures to stagger HPSI Pump after a loss of SW. Discussion if the SW-cooled Emergency Core Cooling System (ECCS) pump room coolers fail to start due to a common-mode failure of the cooler circuitry, procedures to allow operators to stagger HPSI pump use l may allow the pumps to operate longer prior to failure of the pumps or components. Approach to Estimatine Boundine SAMA Benefit l-Staggering the HPSI pumps is considered to have two benefits. It is conservatively assumed that when HPSI pump operation is staggered, the ECCS pump room coolers will not be required and the l component cooling to the HPSI seals will not be required. This is conservative, as some form of cooling may actually be required. Given no cooling is in fact required, the benefit is estimated in the model by setting all CC-and SW-related cooling to success. This is very conservative as SW and CC cool systems other than safety injection. Following the assumptions in Attachment (2), Section 4.1.17.2 of Reference 3, the averted I environmental impacts (benefits) were estimated to be: Averted Public Exposure (6.02 Rem): $130,000 Averted Offsite Costs: 57,000 Avetted Onsite Costs: 0 Averted Occuoational Exoosure (0.94 Remh 20.000 l Total Benefits $207,000 If BGE's property damage insurance is not credited, the averted onsite property damage would be $617,000, and if the effects of deregulation are disregarded, the replacement power costs would be $390,000. Therefore, using the modified AOSC assumptions, the total benefit of this SAMA becomes $1,214,000. Fneineerine/Onerations Discussion Stendy-state room heat-up calculations have determined that the ECCS Pump Rooms would reach a maximum temperature of 150*-to-176 F (depending on which pumps are operating, and whether they are in an injection or recirculation mode of operation). Even at these temperatures, the HPSI pump l seals and bearings are expected to continue to perform their intended functions, since their l temperature is moderated by the CC System, rather than the air temperature of the room. The motor l windings could be expected to exceed the insulation temperature rating after extended operation at these temperatures. However, motor operation at a temperature that is slightly above the maximum insulation temperature rating indicates that the motor is in an unanalyzed condition, but is not necessarily an indication ofimminent motor failure. From an operational standpoint, motor failure would be less likely to occur if pump operation is uninterrupted than ifit were shut down for a brief period of time and restarted after cooling down by a few degrees. Furthermore, repeated operator actions to start and stop pumps while recovering from a LOCA would increase the potential for human error, and could also cause pump malfunction, which was not included in determining the maximum benefit of this SAMA. 33

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Based on the above discussion, BGE does not believe that the benefits that would theoretically be achieved by manually swapping-over between IIPSI pumps would actually be realized if the ECCS pump room coolers failed. Therefore, this SAMA is not considered further. Cost Analysis A cost estimate was not provided for this SAMA, as an engineering assessment determined that the proposed procedural modification would provide little, if any, benefit. References 1. Letter from Mr. R. E. Denton (BGE) to NRC Document Control Desk, dated December 30,1993, " Summary Report of Individual Plant Examination Results (Generic Letter 88-20)(TAC Nos. M74392 & M74393)" 2. NUREG/CR-3518," SLIM-MAUD: An approach to assessing human error probabilities using expert judgment" Volume 1 and 2, NRC,1984 3. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated April 8,1998, " Application for License Renewal; Attachment (2); Applicant's Environmental Report - Operating License Renewal Stage" l 4. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated August 28,1997, " Individual Plant Examination of External Events for Severe Accident Vulnerabilities (TAC Nos. M83603 & M83604)" l 5. CE NPSD-755, " Reactor Coolant Pump Seal Failure Probability Given a Loss of Seal Cooling," CEOG, November 1992 6. CE NPSD-755, " Reactor Coolant Pump Seal Failure Probability Given a Loss of Seal Injection," CEOG, May 1998 7. CE NPSD-591-P, "Best Estimate ATWS Scenarios and Success Criteria, CEOG Task 644," CEOG, October 1990 l l 8. CE NPSD-672, "An Evaluation of the Mechanical Scram Failure for ATWS Occurrence Frequency; CEOG Task 683," CEOG, September 1991 9. NUREG 1560, " Individual Plant Examination Program, Perspectives on Reactor Safety and l Plant Performance," NRC, December 1997 10. NUREG/CG-4691, "MELCOR Accident Code System (MACCS), Volume 1: User's Guide," Sandia National Laboratories, Albuquerque, NM,1990 l 11. NUREG-1150," Severe Accident Risk: An Assessment for Five U.S. Nuclear Power Plants," l NRC, June 1989 l 12. NUREG/CR-4551, " Evaluation of Severe Accident Risks: Quantification of Major Input Parameters MACCS Input, Volume 2," Sandia National Laboratories, Albuquerque, NM, Revision 1, December 1990 13. " Statistical Abstract of the United States", U.S. Department of Commerce,1988 14. " Agricultural Statistics," U.S. Department of Agriculture,1984 15. " County and City Data Book," U.S. Department of Commerce, Bureau of the Census,1988 34

) A'ITACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECFION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS 16. NUREG/BR-0184, " Regulatory Analysis Technical Evaluation Handbook," NRC, January 1997 17. Capital Additions Project Digest; Electric Utility Cost Group, Volume 5, Utility Data Institute, June 1988 l l r l l t ( 35

ATTACIIMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT's ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Table 1 MACCS Non-Farm Economie Parameter Values for CCNPP [ Question No. 6(a)] Variable [ Units] Value Definition DPRATE [per yr] 0.2 Property depreciation rate DSRATE [per yr] 0.12 Investment rate of return EVACST [$/ day] $27 Per diem living expenses for owners ofinterdicted property FRNFIM 0.8 Fraction of non-farm wealth in improvements for the region POPCST [$] $5000 Relocatior, costs for owners of interdicted property RELCST [$/ day] $27 Per diem living expenses for relocated population VALWNR [$] $93K Per capita value of nonfarm wealth (See Table 3 below) Table 2 MACCS Farm Economie Parameter Values for CCNPP l [ Question No. 6(a)] Variable l Units] Value Definition VALWF [$/ hectare] 4489 Value of farm wealth in region (includes all improvements belonging to both public and private sector) l FRFIM [x] 0.25 Fraction of farm wealth in region from l improvements (includes buildings, l equipment, infrastructure (such as roads, utilities, etc.) l { i 36

A'ITACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT's ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Table 3 MACCS Site Data File for CCNPP: Regional Economic Data [ Question No. 6(a)) 1 Fraction of Fraction of Average Average Average Land Farm Fales County / State / Annual Farmland Non-Farm er ted to from Dain R'E'"" Farm Sales Value Value Farming Production NMRGN FRMFRC DPF ASFP VFRM VNFRM [$/ha) [$/hal {$/ person] SUSSEX,DE 0.549 0.012 1,378 2,244 82,000 ANNE ARUNDEL 0.186 0.216 342 3,730 93,000 CALVERT 0.402 0.005 288 3,064 93,000 CAROLINE 0.626 0.056 828 1,984 93,000 CHARLES 0.307 0.006 248 2,579 93,000 DORCHESTER 0.388 0.017 502 1,853 93,000 PRINCE GEORGE'S 0.247 0.020 283 3,938 93,000 QUEEN ANNE 0.691 0.149 470 2,348 93,000 ST. MARY'S 0.431 0.025 325 2,239 93,000 SOMERSET 0.321 0.017 1,444 1,865 93,000 TALBOT 0.723 0.060 624 2,423 93,000 WICOMICO 0.421 0.005 2,059 2,353 93,000 CAROLINE, VA 0.382 0.198 371 2,075 84,000 ESSEX, VA 0.387 0.198 371 2,075 84,000 FAIRFAX, VA 0.382 0.198 371 2,075 84,000 LANCASTER, VA 0.382 0.198 371 2,075 84,000 NORTHUMBER. 0.382 0.198 371 2,075 84,000 LAND, VA RICHMOND, VA 0.382 0.198 371 2,075 84,000 WESTMORELAND, 0.382 0.198 371 2,075 84,000 VA l CHESAPEAKE BAY 0 0 0 0 0 DELAWARE 0.534 0.042 1,723 3,428 82,000 MARYLAND 0.429 0.216 956 4,489 93,000 l VIRGINIA 0.382 0.198 371 2,075 84,000 ATLANTIC OCEAN 0 0 0 0 0 l l l 37 l

ATTACIIMENT (1) j RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE' I SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS 1 \\ j Table 4 Averted Onsite Coct and Replacement Power Cost for Ten Most-Limiting SAMAs [ Question No. 7) SAMA Averted Replacement Potential Enhancement Number Onsite Costs Power Cost 48-a Convert UV, AFAS Block and liigh Pressurizer Pressure $1,062,000 $670,000 Actuation Signals to 3-out-of-4 logic. 77 Install high capacity PORVs such that a single PORV is $1,774,000 $1,119,000 l capable of providing adequate decay heat removal. 36 Replace batteries with a more reliable model. $326,000 $206,000 34 Reduce the likelihood of battery depletion by modifying $171,000 $108,000 the plant such that a portable generator could be used to directly feed each of the four 125 Volt DC buses. 74 Automate DW make-up to Condensate Storage Tank 12. $199,000 $126,000 This system must have a dedicated diesel generator. 45 Use Fire Protection System as a back-up source for diesel $364,000 $229,000 cooling. 68 Install separate accumulators for the AFW cross-connect $102,000 $65,000 and AFW block valves to separate this equipment from the constant bleed equipment (e.g., AFW flow Control Vr! /es). 1 48-b Operate with the PORV block valves shut. $54,000 $34,000 07 Installation of redundant AFW Pump Room ventilation $55,000 $35,000 that automaticaliy starts on high temperature. The system would be diverse (no common cause/ mode) and self-powered. 38-b Double the capacity of fuel oil day tanks with the $209,000 $132,000 additional volume placed between the day tank level switches. l 38 1

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Table 5 \\ Breakdown of the Offsite Costs Associated with Each Release Category [ Question No. I1] Late Small Early Large Early Small Large Economic Cost Measures Containment Containment Containment Containment Containment Failure Failure Failure Bypass Bypass { Population Dependent Costs i Decontamination 20 7,439 7,781 45 465 Interdiction 57 21,624 21,420 118 1,100 Condemnation 0 2,040 2,363 10 182 Evacuation and Relocation 569 63 39 14 2 Area Dependent Costs Decontamination 0 227 218 1 10 Interdiction 1 715 673 3 24 Condemnation 0 116 117 0 11 Milk Disposal 0 6 4 0 0 Crop Disposal 3 364 253 10 8 Total Economic Costs" $649 $32,504 $32,865 $203 $1,801 All values in Table 5 are rounded to the nearest dollar. Therefore, the Total Economic Costs presented in a. this table may differ slightly from the total of the constituent costs. l 39

^ \\ 4 ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Table 6 Base Core Damage Frequency Risk Categories and Contribution to Overall Plant CDF [ Question No.12(b)] Category Label Contribution Description ATWS Intact 4.85 % ATWS with no Containment failure ATWS Late Release 0.23 % ATWS with a Late Containment failure ATWS Small Release 0.03 % ATWS with an early small Containment release ATWS Large Release 0.21% ATWS with an early large Containment release Decay Heat Intact 21.48 % Loss of decay heat removal with no Containment failure Decay Heat Late Release 28.28 % Loss of decay heat removal with a Late Containment failure Decay Heat Small Release 3.62 % Loss of decay heat removal with an early small Containraent release i Decay Heat Large Release 2.86 % Loss of decay heat removal with an early j large Containment release l Inventory Control Intact 15.48 % Loss of inventory control with no l Containment failure ) Inventory Control Late Release 20.67 % Loss of inventory control with a Late Containment failure l Inventory Control Small Release 0.52 % Loss of inventory control with an early small Containment release j Inventory Control Large Release 0.17 % Loss ofinventory control with an early large Containment release Small Bypass 1.53 % Small Containment bypass i Large Bypass 0.08 % Large Containment bypass i l l l 40

i l ATTACIIMENT (1) RESPONSE To REQUEST I"OR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Figure 1 Base CDF Risk Categories and Contribution to Containment Release [ Question No.12(b)] ATWS Intact 4.85% inventory Control Large Release 0.17*/- - ATWS Late Release 0.23% Inventory Control Small Release 0.52*'. ATWS Small Release 0.03% -- ATWS Large Releata 0.21% inventory Control Late Release 20.67 Decay Heat intact 21.48 % i (, .;M uukzaa...--. j inventory Control Q 5b a intact F 3 15.48 % f w,, nyg.~ ~ Decay Heat Late Release M 28.28 % Small Bypass 1.53b - Decay Heat Small Release 3.62% Large Bypass 0.08% heay Heat Large Release 2.86% 4I w T

ATTACHMENT (1) ~ RESPONSE TO REQUEST FOR ADDITIONAL INFORMATIONi APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Table 7 IJentification of SAMAs that Reduce the Core Damage Frequency in a Given Category by Greater than 25% [ Question No.12(b)] Categorr is checked if SAMA would result in 25% or greater reduction SAMA Decay Decay Decay in W IWM 1mentM f A A 'C8Y Heat M Heat Imentory Control Control Control Large Small Number AN Late Large Small Heat Control intact Late Large Small Late Large Small Release Release Release intact IM Bypass Bypass Release Reisase Release Release Release Release 01-a 01-b 02 } 03 / / / l 04 l 05 / / / / j 06 1 07 08 l 09 This SAMA was screened on high cost. Risk Benefit was not quantified. 10 11 / / / / 12 / / 13 / / 14 / 15 / i 16 This 'N was screened on high cost. Risk Benefit was not quantified. 17 This SAMA was screened on high cost. Risk Benefit was not quantified. 18 Benefit was determined to be minimal, as no credit was taken for scrubbing in the iPE Level 2 analysis. 19 This SAMA was screened on high cost. Risk Benefit was not quantified. 20 / / 21 / / 22 / 23 / / / / 24 / / / / 25 This SAMA was screened on high cost. Risk benefit was not quantified. 26 This SAMA was screened on high cost. Risk benefit was not quanti _fied. 27 l / l / l / l l / l / l l l / l / l / l l 28 This SAMA was screened on high cost. Rink henefit was not quantified. 29 Thrs SAMA was screened on high cost r '-wf4 was not quantified. 30 / / 31 32 l w.. 42 m. m

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SAMA ~ Categor r is checked if SAMA would result in 25% or greater reduction W Decay Decay In g in m ory inmM I M Control Control Control A A 'C8Y Heat Heat Heat Number AN Late Large Small Heat Control Large Small Late Large Small Late Large Small Bypass Bypass I"M Release Release Release intact Intact Release Release Release Release Release Release 334 33-b 334: 34 35 36 37 Risk beneft was not quantified, as the 500kV prid is already in a nng configuraten. 384 38-b 39 i 40 This benefit of thrs SAMA is considered minimal, as existin y plant procedures already clearly address this issue. 41 3 42 43 / / 44 45 46 The benefit of thrs SAMA would be less than that calculated for SAMA No. 30. 47 The benefd of this SAMA would be less than that calculated for SAMA No. 30. 48-a* / / / 48-b* ey / / / I 50* Based on IPEEE results, it was determined that this SAMA would provide minrnal benefts. Therefore, the risk benef!t was not quantifed for thrs SAMA. 51 I I I I l l l l l l l l l / 52 The benefit of this SAMA would be much less than that calculated for SAMA 51. 53 The beneft of this SAMA would be much less than that calculated for SAMA 51. 54 The benefd of this SAMA would be much less than that calculated for SAMA 51. 55 Thrs SAMA was screened on high cost. Rrsk benefd was not quantrfied. Mi I I i I l l l l l l l l l / 57 The benefd of this SAMA would be less than that calculated for SAMA 51. I $8 This SAMA was screened on high cost. Risk benerd was not quantified. 59 l l l l l l l l l l l l / l / 60 The benefit of thrs SAMA would be less than that calculated for SAMA 59. 61 The benefit of this SAMA would be less than that calculated for SAMA 59. 62 l l l l l l l l l l l l l 63 The benefrt of this SAMA would be less than that calculated for SAMA 50 64 / / / / 65 66-a 66-b / l 43

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; ~ SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Categor r is checked if SAMA would result in 25% or greater reduction SAMA Decay Decay Decay Imentory Ime % Iwory ATWS ATWS ATWS Decay Heat Heat Heat I"V'"I"'Y Control Control Control Number ATWS Late Large Small Heat Control Large Small Intact Late Large Small Late Large Small Rh Release Release intact Intact Bypass Bypass am pm pmm Release Release Release 67 68* 69 70 71 / / / 72 73-a* / / / / 73-b* / / / / 74 75 This SAMA was screened on high cost. Risk benefit was not quantified. 76* The benefd of this SAMA would be less than that calculated for SAMA 73-a. 77* The benefd of this SAMA would be less than that calculated for SAMA 73-b. 78 79 / / / / / / 80 / / 81 This SAMA provides limited benefit, based on existing plant design and procedures. 82 83 84 The nsk benefit for this SAMA was determined to be minimal, as the existing plant configuration meets the intent of the SAMA. 85 The nsk benefit for this SAMA was determined to be minimal, as existing ATWS indication was deemed to be adequate. 86 The nsk benefit for this SAMA was determined to be minimal, as the existrng plant configuration meets the intent of the SAMA. 87# The benefit of this SAMA would be less than that calculated for SAMA 27. 88 The beneft of thrs SAMA would be less than that calculated for SAMA 48-b. 89 90 91 This SAMA was screened on high cost. Rrsk benefit was not quantified. 92* 938 94 95 Level 2 analysis indcated a neghgible benefit; therefore nsk benefd was not quantified for this SAMA. M i l I I I I I / I / I / I / I I / 97 The nsk benefit was not quantified for this SAMA, as injection of non-borated water into the RWT would result in reactivity excursens. Indicates SAMA concept was derived from CCNPP risk insight.

1. Indcates SAMA concept was derived from the CCNPP IPE.

44

ATTACHMENT (I) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S FNVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MrTIGATION ALTERNATIVES ANALYSIS Table 8 Core Damage Frequency Reduction and Averted Offsite and Onsite Doses for Quantified SAMAs [ Question No.12(b)] Averted Offsite Dosa Modification / Procedure (Person-RemlYear) DW Enhancement / Training Option Small Large Late Ctmt. Small Large SAMA CDF M p,;,,,, Ctmt. Ctmt. (Person-Rem Number Reduction Ctmt. Ctmt. Fal!ure Failure Bypass Bypass per Year) 01-a improve SW, SRW and CC pump recovery (post-tnp only). 1.29E-05 0.07 3.27 0.32 0.00 0.00 0.23 01-b improve SW. SRW and CC pump recovery (pre-tnp and 1.74E-05 0.08 3.56 0.63 0.00 0.00 0.31 post-tnp). 02 install an additional SW pump. 1.05E-05 0.07 0.87 0.77 0.00 0.00 0.19 03 InsMilimp oved RCP seals. 2.93E-05 0.16 5.00 0.62 0.00 0 00 0.52 04 Insta!! an additional CC purrp. 1.06E-06 0.00 0.04 0.01 0 00 0 00 0 02 05 Hard-pipe an FP System feed to CC System to allow an 3.76E-05 0.17 5.31 0.71 0.00 0.00 0.66 attemate cooling source for.. and RCP seals. 06* Install a redundant SWGR Room HVAC train. 3.53E-05 0.28 1.61 2.27 0 00 0.00 0 62 07 Install a redundant AFW Pump Room ventilation system. 4 78E-06 0.03 0 98 0.42 0.00 0.00 0.08 08 install CS pump header automatic throttle valves. 7.36E-06 0.01 0.28 0.08 0.00 0.00 0.13 09 Develop a redundant CS System. Thrs SAMA was screened on high cost. Risk benefit was not quantrfied. 10 Develop an enhanced CS System. 2.83E-07 0.01 0.05 0.00 0.00 0.00 0 01 11 Install a containment vent brge enough to remove ATWS 1.53E-04 0.61 15.61 14.33 0.01 0.01 2.70 decay heat. 12 Install a filtered contarnment vent to remove decay heat. 0.00E-00 0.20 0.00 0 00 0.00 0.00 0.00 13 Install an unfiltered hard-ended containment vent. 0 00E-00 0.20 0.00 0.00 0.00 0.00 0.00 14 Create / enhance hydrogen ignitors with an independent 0.00E-00 0.06 0.98 0.60 0.00 0.00 0.00 power supply. 15 Create a passive hydrogen ignition system. 000E4[ 0.06 0.98 0.60 0.00 0.00 0.00 16 Create a giant concrete crucible with heat removal potential under the basemat to contain molten debris. This SAMA was screened on high cost. Risk benefit was not quantified. 17 Create a water-cooled rubble bed on the pedestal. This SAMA was screened on high cost. Risk benefit was not quantified. 18 Enhance FP System.. hardwars and procedures. Benefit was determined to be minimal, as no credit was taken for scrubbing in the IPE Level 2 analysis. 19 Create a reactor cavity flooding system. This SAMA was screened on high cost. Risk benefit was not quantified. 20 Greate other options for recator cavity flooding. 0.00E-00 0.20 0.00 0.00 0.00 0.00 0.00 21 Create a core melt source reduction system. 0.00E-00 0.20 0.00 'O.00 0.00 0.00 0.00 22 Provide containment inerting capabihty. 0.00E-00 0 06 0.98 0.60 0.00 0.00 0.00 23 Use FP System as back-up source for CS System. 2.75E-07 1.12 4.62 2.74 0.00 0.00 0.00 24 Install a passive CS System. 2.75E-07 l 1.12 4.62 2.74 0.00 0.00 0.00 25 Increase containment design pressure. This SAMA was screened on high cost. Risk benefit was rtot quantified. 45

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS i ^ Averted Offsite Dose Ons Modification / Procedure (Person-RemtYear) EnhancementITraining Option Small Large Late Ctmt. Small Large SAMA CDF M M p,ii,,, Ctmt. Ctmt. (Person-Rem I Number Reduction Ctmt. Ctmt. Failure Failure Bypass Bypass per Year) 26 Increase the depth of the concrete basemat.. to ensure mett-through does not occur. This SAMA was screened on high cost. Risk benefit was not quantified. 27 Provide a reactor vessel extenor cooling system. 0.00E-00 l 1.38 l 9.80 l 1962 l 0.00 l 0 05 l 0.00 28 Construd a building.. connected to containment. Th6s SAMA was screened on high cost. Risk benefit was not quantified. 29 Add nbbing to the containment shell. This F * A was screened on high cost. Rrsk benefit was not quantified. 30 Provide an additional desel generator. 7L c5 0 37 4E8 5.70 0.05 0.00 1.34 31 Provide additional DC battery capabihty. 1.47E-05 0.08 0.69 1.21 0.00 0 00 0.26 32 Use fuel cells instead of lead-acid battenes. 1.47E-05 0 08 0.69 1.21 0.00 0.00 0.26 33-a implement automat =c cross-tie capabihty between 4kV 2.62E-05 0.17 2.67 1.25 0.05 0.00 0.46 Buses 11 and 14. 33-b implement automatic cross-te capabihty between 4kV 8.82E-06 0.07 0.42 0.69 0.00 0.00 0.16 Buses 21 and 24. 33-c implement automatic cross-te capabihty between 125VDC 2.62E-05 0.14 1.09 1.86 0.01 0.00 0.46 Buses 11 and 21. 34 incorporate an attemate battery charging capabihty. 1.47E-05 0.08 0.69 1.21 0.00 0.00 0.26 35 Increase / improve DC bus load shedding. 1.47E-05 0.08 0.69 1.21 0.00 0.00 0.26 36 Replace battenes with a more rehable model. 2.81 E-05 0.09 1.15 2.30 0.01 0.00 0.50 37 Create AC power cross-tie capability across units. Risk benefit was not quantified, as the 500kV gr6d is already in a ring configuration. 384 Create a cross-unit tie for diesel fuel oil. 1.00E-08 0.00 0.00 0.00 0.00 0.00 0.00 38-b Double the capacity of fuel oil day tanks. 1.80E-05 0.11 0.79 1.52 0.00 0.00 0.32 39 Develop procedures to repair or replace failed 4kV 1.38E-06 0.01 0.06 0.12 0.00 0.00 0.02 breakers. 40 Emphasize steps in recovery of offsite power after a Station The benefit of this SAMA is considered minimal, as existing plant procedures already address this Blackout (SBO). issue. 41 Develop a severe weather conditions procedure. 1.64E-05 l 0.08 l 0.68 l 1.33 l 0.00 l 0.00 l 0.29 42 Develop procedure for replentshing desel fuel oil. The benefit of this SAMA would be less than that calculated for SAMA No. 38-a. 43 Install gas turbine generators. 7.59E-05 0.37 4.88 5.70 0.05 0.00 1.34 44 Make the SRW-cooled EDGs air-cooled. 3.13E-05 0.19 2.99 1.89 0.04 0.00 0.55 45 Use FP System as back-up source for EDG coohng. 3.13E-05 0 19 l 2.99 1.89 0.04 0.00 0.55 46 Provide a connection to attemate offsite power source. 47 Irstall underground offsite power knes. The benefit of this SAMA would be less than that calculated for SAMA No. 30. 48-a* Change UV, AFAS Block, and Hgh Pressurizer Pressure 9.14E-05 0 62 3.94 6.83 0.02 0.00 1.62 Aduation Sqnals to 3-out-of-4 logic. 48-b" Operate with the PORV block valves shut. 4.66E-06 0.11 0.70 (0.29)' O.00 0 00 0.08 j 49* Add an automabc bus transfer feature that would 9.14E-05 0.62 3.94 6.83 0.02 0.00 1.62 automatically transfer between either the back-up bus or the stand-by inverter on the failure of the operating inverter. 46

ATTACHMENT (1) ~ RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS ^ Averted Offsite Dose O Modification / Procedure (Person-RemIYear) Enhancement / Training Option Small Large S' SAMA CDF Early Early (Person-Rom Number Reduction Ctmt. Ctmt-Failure Failure % pass % pass per Year) 50* Add desconnects at the juncton box.. from the OC Diesel Based on IPEEE results, it was detemuned that this SAMA would provde minimu n benefits. Therefore, Generator branches to all four SWGRs. the risk benefit was not quantified for this SAMA. 51 Improve SGTR cepng abildes. 3.47E-06 l 0.00 l 0.00 l 0.00 l 0.56 l 0.04 l 0.06 52 Install a redundant spray system to depresJunze the The benefit of this SAMA would be much less than that calculated for SAMA 51. primary system during a SGTR. 53 Add a highly rehable (closed loop) SG shell-side heat The benefit of this SAMA would be much less than that calculated for SAMA St. removal system that rekes on natural circulation and stored water sources. 54 increase secondary side pressure capacdy. The benefd of this SAMA would be less than that calculated for SAMA 51. 55 Replace steam generators with new design. This SAMA was semened on high cost. Risk benefit was not quantrfied. 56 Direct steam generator flooding after a SGTR, prior to core 0.00E-00 0.00 0.00 0.00 0.83 0.00 0.00 damage. The benefit of this SAMA would be less than that calculated for SAMA 51. 1 nt o the n team ge rator 58 Locata RHR inside of containment. This SAMA was screened on high cost. Risk benefit was not quantified. 59 Install additional instrumentaten for Inter-System Loss of 1.86E-06 0.00 0.00 0.00 0.26 1.49 0.03 Coolant Accidents (ISLOCAs). 60 increase the frequency of valve leak testing. The benefit of this SAMA would be less than that calculated for SAMA 59. 61 Increase operator training on ISLOCA coping The benefit of this SAMA would be less than that calculated for SAMA 59. 62 Install rehef valves in the CC System. 8.18E-07 l 0.00 l 0.00 l 0.00 l 0.13 l 0.00 l 0.01 63 Revise EOPs to unprove ISLOCA identification. 64 Fnsure all ISLOCA releases are scrubbed. 0.00E-00 0.00 0.00 U.00 0.83 1.53 0.00 65 Add redundant and diverse hmit switch to each 3.04E-08 0.00 0.01 0.02 0.00 0.02 0.00 containment isolation valve. 66-a Enhance procedures to improve flood mitigatn.9 gudance. 1.84E-06 0.00 4 99 0.15 0.00 0.00 0.03 66-b Comprehensive piping inspections or hardware 1.61 E-05 0.04 23.94 1.15 0.00 0.00 0.28 modifications that improve the plant's abihty to mitigate a flood. 67-a increase the capacity of AFW accumulators. 3.52E-07 0.00 0.04 0.04 0.00 0.00 0.01 67-b Install an accumulator of sufficent capacity to allow ADV 2.66E-07 0.00 0.00 0.00 0.04 0.00 0.00 operation for 24 hours. 68* Install separate accumulators for the AFW cross-connect 8.83E-06 0.02 0.37 0.87 0.00 0.00 0.16 and block valves. 69 install a new Condensate Storage Tank. 8.17E-06 0.02 0.37 0.73 0.00 0.00 0.14 70 Provide coohng of turbine-dnven AFW pumps in an SBO 4.78E-06 0.03 0.98 0.42 0.00 0.00 0.08 event. 71 Enhance procedures such that local manual operation of 7.38E-05 0.31 7.23 6.95 0.00 0.00 1.30 AFWis significantly improved. 47

NITACIIMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALT 5tNATIVES ANALYSIS ^ Averted Offsite Dose O ModificatiorWProcedure (Peon-RemNear) Dose Enhancement! Training Option Small Large Late Ctmt. Small Large SAMA CDF Number Reduction Ctmt. Ctmt. Ctmt. Ctmt. (Person-Rom Failure Failure Failure Bypass Bypass per Year) 72 install a self-suEmnt desel generator capable of dnving 1.36E-05 0.06 1.35 1.29 0.00 0.00 0.24 either the AFW turbine <! riven pump or motor <jriven pump. 73-a* Install hardware such that the FP System can be used to 9.75E-05 0.30 11.97 9.27 0.01 0.01 1.72 directly feed the steam generator. (manual alignment) 73-b* Install hardware such that the FP System can be used to 1.53E-04 0.61 15.61 14.33 0.01 0.01 2.70 directty feed the steam generator. (automatic alignment) 74 Automate DW make-up to Cvndmisate Stvimp Tank 12 1.72E-05 0.05 0.77 1.03 0.00 0.00 0.30 (with a dedicated desel generator). 75 Create passive secondary. side coolers. This SAMA was screened on high cost. Rrsk benefit was not quantified. 76* Reduce the support system requifoi.-nts for low pressure 77* Replace current PORVs with larger ones such that only one is required for succes=f.4 feed and bleed. 78 Provide capability ior desel<2nven, low pressure vessel 1.04E-05 0.02 0.24 0.29 0.00 0.00 0.18 make-up. 19 Provde an atditional HPSI pump with an independent 1.51E-04 0.51 15.24 11.97 0.39 0.03 2.67 diesel. 80 Implement a Refueling Water Tank make-up pOc.mdure. 5.33E-06 0.00 0.00 0.00 0.83 1.53 0.09 81 Stop low pressure safety injection pumps earter in medium This SAMA provdes limited benefit, based on exrsting plant design and procedures. or large LOCAs. 82 Ensure the plant air u.,nvressors are diesel generator 8.99E-06 0.03 0.40 0.90 0.00 0.00 0.16 backed. 83 Install more reliable plant air, instrument air, and SW air 3.37E-06 0.01 0.16 0.19 0.01 0.00 0.06 compressors. 84 Install motor generator set tnp breakers in the control room. The nsk benefit for this SAMA was determined to be minimal, as the existing plant conf!guration meets the intent of the SAMA. 85 Provde an additional instrumentation system for ATWS The nsk benefit for this SAMA was determined to be minimal, as existing ATWS indicabon was deemed mitigation. to be adeq. sate. 86 Provide capability for remote operation of secondary side The nsk benefit for this SAMA was determined to be minimal, as the existing p! ant configuration meets relief valves in an SBO event. the intent of the SAMA. 87# Create / enhance RCS depressunzation abahty. The benefit of this SAMA would be less than that calculated for SAMA 27. 88 Renvis PORV hft on high pressunzer pressure. The benefit of this SAMA wouid be less than that calculated for SAMA 48-b. 89 Install secondary sde guard pipes around existing piping 1.68E-06 0.00 0.06 0.15 0.00 0.00 0.03 up to the main steam isolation valves. 90 install dgital large break LOCA early detection. 4.97E-06 0.01 0.10 0 26 0.00 0.00 0.09 91 increase seismic capacity of the plant.. to twice the Safe Shutdown Earthquake. 48

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS ~^ Averted Offslee Dose m (Person-Rom / Year) EnhancementfTraining Option Smalt W SmaH W SAMA CDF Earh Early Failure Ctmt. CM (Person-Rom Numtpor pm a m Failure Failure % pass % pass - M *) 92* Install a dedcated desei generator for the DW transfer 7.20E-06 0.03 0.45 0.52 0.00 0.00 0.13 pumps SM Cap downstream pipeg of normaffy closed CC System 1.71 E-06 0.00 0.07 0.02 0.00 0.00 0'03 drain and vent valves. 94 Replace C..-v.sif Core Coohng System pump motors 9.45E-06 0.02 0.36 0.12 0.00 0.00 0.17 with air-cooled motors. 95 Provide a core detms control system. Level 2 analysis indcated a negligele benefit; therefore nsk benefit was not quantified for this SAMA. 96 Implement procedures to stagger HPSI pump use after a 5.31 E-05 0.21 4.54 0.95 0.31 - 0.01 0.94 loss of SW. e 97 Use FP System as a back-up make-up source for the The risk benefit was not quantified for this SAMA, as tripecton of non-borated water into the RWT would Refueling Water Tanks. result in reactivity excursions. Indicates SAMA concept was denved from CCNPP risk insight. Imlicates SAMA conapt was denved from the CCNPP IPE. Note 1 Implementation of SAMA No. 48-b cauaes an increase in Large Early Containment Failure. P -r t 49

~ ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Table 10 Method of Calculating Maximum Benefit for Quantified SAMAs [ Question No.15] SAMA Modification / Procedure Enhancement / Training No. Option W of Calculadng Maximum Benefit Basis for COE Estimate 01-a improve SW, SRW and CC pump recovery (post-tnp Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 only). 01-b improve SW, SRW and CC pump recovery (pre-tnp Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 and post-trip). 02 Install an additional SW pump. Set all SW Header hardware failure probabildes to Based on engineenng judgment, COE would greatty zero as well as all SW Initiating Events (IE) to zero. exceed maximum calculated benefit. 03 Installimproved RCP seals. Set RCP seal failure probabildy to zero. Based on previous CCNPP replacement of RCP seals. 04 Install an additional CC pump. Set all CC pump-related failure probabihtes to zero, Based on engineenng judgment, COE would greatly and set the probability for a!! total loss-of-CC IEs to exceed maximum calculated benefit zero. 05 Hard-pipe an FP System feed to CC System to allow Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 an attemate cooling source for.. and RCP seats. 06 Install a redundant SWGR Room HVAC train. Set all SWGR HVAC equiprnent failure probabihtes Based on previous CCNPP estrnate for instattation of to zero, set the likelihood of the hurricane IE to zero, a similar HVAC system (Control Room HVAC). set the likelihood of a tomado striking the HVAC condensers to zero, and set the likelihood of any tomado IE which fails HVAC to zero. OT install a redundant AFW Pump Room ventilation Described in Environmental Report, Appendix F.4 Desenbed in response to NRC Question No.14. system. 08 Install CS pump header automatic throttle valves. Desenbed in Emrironmental Report, Append!x F.4 Desenbed in Environmental Report, Appendix F.4 L 09 Develop a redundant CS System. Screened on High Cost Maximum Benefit not Based on estimate submitted by Tennessee Valley b calculated. Authority for Watts Bar SAMA analysis. 10 Develop an enhanced CS System. Set all CS Header hardware failure probabildies to Baseo' on engineering judgment, COE would greatfy zero. exceed maximum calculated benefit. l 11 install a containment vent targe enough to remove Set all AFW related hardware failure probabi! dies to No estmate provided, as thrs SAMA is not apphcable f ATWS decay heat. zero. to PWRs. 12 Install a filtered containment vent to remove decay Assume all debns in the reactor cavity is successfully Based on estimate submitted by Philadelphia Electnc heat. cooled and quenched. Company for Limerick SAMA anafysis. 13 Install an unfittered hardened containment vent. Assume all debns in the reactor cavity is successfully Based on estmate submitted by Philadelphia Electne cooled and quenched. Company for Limerick SAMA analysis. j 14 Create / enhance hydrogen ignitors with an Set hydrogen bum probabildy to zero. Based on engineering judgment, COE wou'd greatty independent power supply. exceed maximum calculated benefit. 15 Create a passive hydrogen ignition system. Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 16 Create a giant concrete crucible wrth heat removal Screened on High Cost. Maximum Benefit not Based on estimate submdted by Combustion potential under the basemat to contain molten debris. calculated. Engineering in CESSAR Design Certification. [ 17 Create a water-cooled rubble bed on the pedestal. Screened on High Cost. Maximum Benefit not Based on estimate submitted by Combustion calculated. Engineering in CESSAR Design Certification. 50 L b

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INI'ORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SAMA Modification / Procedure Enhancement / Training No. Option Method of Calculating Maximum Benefit Basis for COE Estimate 18 Enhance FP System.. hardware and procedures. Benefit was determined to be minmal, as no credit Refer to SAMA No. 23 for irnplementation estimate. was taken for scrubbing in the IPE Level 2 analysis. 19 Create a reactor cavity flooding system. Screened on High Cost. Maxmum Benefit not Based on estmate submitted by Tennessee Valley calcu!sted. Authonty for Watts Bar SAMA ana'ysis. 20 Deate other optens for reactor cavity flooding. Assume all debns in the reactor cavity is successfully Based on engineenng judgment COE would greatly cooled and quenched. exrmed maximum calculated benefit. 21 Create a core melt source reduction system. Assume all debns in the reactor cavity is successfulty Based on engineenng judgment, COE would greatty cooled and quenched. exceed maximum calculated benefit. 22 Provde containment inerting capabihty. Set hydrogen bum probabihty to zero. Based on estimate submitted by Tennessee Valley Authority for Watts Bar SAMA analysis. 23 Use FP System as back-up soerce for CS System. Desenbed in Environmentai Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 24 install a passrve CS System. Benef:t is assumed to be equivalent to SAMA No. 23. Based on engineenng judgment COE would greatty exceed maximum calculated benef:t. 25 fr, crease containment desgn pressure. Sceened on Ngh Cost. Maximum Benefit not No estmate provded, as this SAMA would reoutre calculated. extensive plant reconstruction. 26 increase the depth of the concrete basemat.. to Screened on H#gh Cost. Maximum Benefit not No estmste provded, as this SAMA would require ensure melt-through does not occur. calculated. extensive plant reconstruction. I 27 Provde a reactor vessel extenor coohng system. Modifed containment event tree to allow for Based on estirnate submrtted by Combustion containment failures due to hydrogen bums before Engineering in CESSAR Design Certification. vessel melt-through and isolation failures only. (Assumes all sequences wil! terminate with debris quenched in-vessel except for bypass sequence failures.) 28 Construct a butiding.. connected to containment. Screened on High Cost. Maxmum Benefrt not Based on engineenng judgment, COE would greatty calculated exceed maximum calculated benefit. 29 Add nbbing to the containment shell. This SAMA was screened on hgh cost. Risk benefit No estimate provided, as this SAMA would require was not quantifed. extensive plant reconstruction. 30 Provide an additional diesel generator. Set all EDG equipment failure probabihtes to zero; Thrs estimate was based on cost of CCNPP set SW & SRW failure probabihties to zero for modification to install two additional diesel headers 12,21, and 22. generators. 31 Provde additional DC battery capabihty. Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 32 Use fuel cells instead of lead-acid battenes. Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 33 a implement automatic cross-te capability between 4 Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 kV Buses 11 and 14. 33-b implernent automatic cross-te capabihty tn* ween 4 Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 i kV Buses 21 and 24. 33-c implement automatic cross-te capabdity between Set fa:!ure probabihty for 125 VDC Bus 21 and its Based on engineenng judgment, COE would greatty 125 VDC Buses 11 and 21. supports (including 480 VAC buses) to zero. exceed maximum calculateo benefit (per ER Table F.2-2, Note (d)). 34 incorporate an attemate battery charging capabikty. Desenbed in Environmental Report, Appendix F.4 Desenbed in response io NRC Ouestion No.14. 35 increasehmprove DC bus load shedding. Maximum Benefit is same as SAMA No. 34. No estimate provided, as thrs SAMA is not considered technically feasible. 36 Replace battenes with a more rehable model. Desenbed in Environmental Report, Appendix F.4 Desenbed in response to NRC Ouestion No.14. 51 l

ATTACIIMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SAMA Modification / Procedure Enhancement / Training No. Option Method of Calculating Maximum Benefit Basis for COE Estimate 37 Create AC power cross-te capability across unds. Risk benefit was not quantified, as the 500kV gnd is No estimate provded, as BGE's 500kV grd is already in a ring configuration. already in a ring configuration. 38-a Create a cross-unit te for desel fuel oli. Set the hkehhood of FOSTs 11 and 12 fashng or being No estimate provded, as CCNPP's EDG Nos.18,2A unavailable to zero. and 2B are already fed from common fuel oil storage tanks. 38-b Double the capacity of fuel oil day tanks. Desenbed in Environmental Report, Appendix F.4 Desenbed in response to NRC Ouestion No.14. 39 Develop procedures to repair or replace failed 4kV Benefit is estimated by subtracting breaker failure No estimate provided, as CCNPP's funcbonal test breakers. likelihoods from EDG Top Events. procedures and training already address this SAMA. 40 Emphasize steps in recovery of offsite power after a Risk benefit was not quantifed for this SAMA, as No estimate provded, as CCNPP procedures for Station Black Out (SBO). CCNPP procedures for SBO already clearty address SBO already clearfy address recovery of offsite recovery of offsite power. power. 41 Develop a severe weather conditions procedure. Set frequences for severe weather induced fadures No estimate provided, as CCNPP's emergency (tomado, hurricane, and long-term loss of offsite response procedures and Emergency Operating power) to zero. Procedures adequately address severe weather. 42 Develop procedure for replenishing desel fuel oil. The benefit of this SAMA would be less than that No estimate provided, as actions necessary to initiate calculated for SAMA No. 38-a. fuel oil procurement are addressed in CCNPP's existing procedures. 43 Install gas turtune generators. Maximum Benefit is bounded by SAMA No. 30. Cost was based on estimate to design and insta;l a 5.2 MW commercialgrade gas-powered turbine-generator unit, including switchgear. 44 Make the SRW-cooled EDGs air-cooled. Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 45 Use FP System as back-up source for EDG coohng. Desenbed in Environmental Report, Appendix F.4. Basis for estimate is provided in response to Question No.14. 46 Provde a connection to attemate offsite power Maximum Benefit ts bounded by SAMA No. 30. Based on BGE's expenence in instalhng South source. Circuit transmission hne in 1994, the cost of a new transmission line would be approximately $1,000,000 per mile. The nearest attemate offsite power source is at least 25 miles from CCNPP site. 47 Install underground offsite power knes. Maximum Benefit is bounded by SAMA No. 30. Based on engineenng judgment, the cost of burying existing transmission lines would greatty exceed cost of insta!!ing new transmission line (SAMA No. 46). 48-a Change UV, AFAS Block, and Wgh Pressunzer Desenbed in EnvirLnmental Report, Appendix F.4. Basis for estimate is provided in response to Pressure Actuation Signals to 3-out-of-4 logic. Question No.14 48-b Operate with the PORV block valves shut. Desenbed in Environmental Report Appendix F.4 Desenbed in Environmental Report, Appendix F.4 49 Add an automatic bus transfer feature that would Desenbed in response to Question No.16. Desenbed in response to Question No.16. automatically transfer between either the back-up bus or the stand-by inverter on the failure of the cperating inverter. 50 Add disconnects at the junction box.. from the OC Based on IPEEE results, it was determined that this No estimate was provided, as the benefit was Diesel Generator branches to alt four SWGRs. SAMA would provide minimal benefits. Therefore, determined to be minimal, and BGE has determined the risk benefit was not quantified for this SAMA. that the cost of hardware modifications would exceed $40.000. 51 Improve SGTR coping abihtes. Set SGTR frequency to z'ero. Based on engineenng judgment. COE would greatly exceed maximum calculated benefit. 52

~ ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SAMA Modification / Procedure Enhancement / Training OE M e No. Option 52 Install a redundant spray system to depressunze the Maximum Benefit is bounded by SAMA No. 51. Based on engineering judgment, COE would greatty primary system during a SGTR. exceed maximum calculated benefit. 53 Add a hghly rehable (closed loop) SG shell-sde heat Maxrnum Benefit is bounded by SAMA No. 51. Based on engineenng judgment, COE would greatly removal system that reles on natural circulation and exceed maximum calculated benefit. stored water sources. 54 increase secondary sde pressure capacity. Maximum Benefit is bounded by SAMA No. 51. No estimate provided, as replacement of secondary system would not be feasible for an existing plant. 55 Replace steam generators with new desgn. Screened on Hgh Cost. Maximum Benefit not The estmated cost of BGE's steam generator i calculated. replacement exceeds $300 milhon for two units. 56 Direct steam generator flooding after a SGTR, pnor Set all Small Bypass release frequencies to zero and No estimate provided, as CCNPP's procedures to core damage. add the same amount to the intact containment already include the change proposed by this SAMA. frequency. (This approach does not change CDF and effectively credits 100 percent fission product filtering in the faulted steam generator.) 57 Implement a maintenance practice that inspects Maximum Benefit is bounded by SAMA No. 51. The estimate of $29 milhon is based upon expanding 100 percent of the tubes in a steam generator. CCNPP's current steam generator tube inspection program to include 100 percent plus point inspections 58 Locate RHR insde of containment. Screened on Hgh Cost. Maxirnum Benefit not No estimate provded, as relocating the Shutdown calculated. Coo!ing System inside containment would not be feasible for an existing plant. 59 Insta!I additional instrumentation for inter-System Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 Loss of Coolant Accidents (ISLOCAs). 60 increase the frequency of valve leak testing. Maximum Benefit is bounded by SAMA No. 59. Based on BGE's expenence with perfomung leakage t rate testing on the valves that would be impacted with this SAMA, it was determined that the cost of implementing addibonal testing would greatly exceed the maximum calculated benefit. 61 increase operator training on ISLOCA coping Maximum Benefit is bounded by SAMA No. 59. No estimate was proveed, as CCNPP procedures and training already address the intent of this SAMA. 62 install rehef valves in the CC System. Set RCP heat exchanger LOCA frequency to zero. No estimate was provded, as BGE has determined that the cost of any hardware modification would [ exceed $40,000. l 63 Revise EOPs to improve ISLOCA dentification. Maximum Benefit is bounded by SAMA No. 59. No estimate was provided, as CCNPP procedures and training already address the intent of this SAMA. 64 Ensure aillSLOCA releases are scrubbed. Set two containment bypass release categones to Based on engineenng judgment, the cost of a new zero and add the same amount to the intact filter or scrubbing system would greatly exceed the containment release categories. calculated maximum benefit; therefore, no estimate was provided. 65 Add redundant and diverse hmat switch to each Set all containment isolation-related human action No estmate was provided, as BGE has determined containment isolation valve. failures to zero. that the cost of any hardware modification would i exceed $40,000. 66-a Enhance procedures to improve flood mitigation Set all flood frequences which incluoe a failed No estimate was provded, based on discussion in guidance. recovery action to zero. ER Table F.2-2, Note (e). 53

ATTACHMENT (1) ~ RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS SAMA Modification / Procedure Enhancement / Training No. Option 66-b Comprehensive piping inspections or hardware Desenbed in response to Question No.16. Desenbed in response to Question No.16. modifications that improve the plant's abihty to mitigate a flood. 67-a increase the capacity of AFW accumulators. Set AFW air function failures to zero. No estimate was provided, as BGE has determined that the cost of any hardware modification would exceed $40.000. 67-b install an accumulator of sufficient capacity to allow Set ADV failure probabilites to the values which No estimate was provided, as BGE has deterrruned ADV operation for 24 hours. would be used if air is always available to the ADVs. that the cost of any hardware modification would exceed $40,000. 68 Install separate accumulators for the AFW cross-Desenbed in Environmental Report, Appendix F.4 Desenbed in response to NRC Ouestion No.14. connect and block valves. 69 Install a new Condensate Storage Tank. Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4 70 Provide cooling of turturwMinven AFW pumps in an Desenbed in Environmental Report, Appendix F.4 Desenbed in Environmental Report, Appendix F.4. SBO event. 71 Enhance procedures such that local manual Set AFW System algnment4 elated human action No estimate was provided, based on adequacy of operation of AFW is significantly improved. failures to zero. CCNPP procedures and consistency with generic industry guidance on emergency procedures. 72 install a self-sufficent desel generator capable of Set AFW System steam ahgnment and pump rrTa Based on engineenng Judgment, COE would greatly driving either the AFW turbine-driven pump or motor-ventilation failures to zero. exceed maximum cciculated benefit. driven pump. 73-a Install hardware such that the FP System can be Set these hardware failure probabihtes to zero: one Based on engineenng judgment, the cost of used to directly feed the steam generator. (manual motor-driven AFW pump, one turbine-driven AFW upgrading the FP System to meet secondary side ahgnment) pump, AFW flow control lines. AFW steam admission pressure requirements would exceed the maximum knes, AFW long-term water availability, and calculated benefit. equipment directly related to the a'orementioned equipment. 73-b install hardware such that the FP System can be Set all AFW hardware and human action related Based on engineenng judgment, COE would greatty used to directly feed the steam generator. (automatic failure probabihties to zero. exceed maximum calculated benefit. alignment) 74 Automate DW make-up to Condensate Storage Tank Desenbed in Environmental Report, Appendix F.4 Desenbed in response to NRC Question No.14. 12 (with a dedicated diesel generator). 75 Create passive secondary side coolers. Screened on Hgh Cost. Maximum Benefit not No estimate provided, as this SAMA is not feasible calculated. for an existing plant. 76 Reduce the support system requirements for low Maximum Benefit is bounded by SAMA No. 73-a Based on engineenng judgment, the cost of proviGing pressure feed. diesel-backing to non-safety-related 4kV buses would exceed the maximum calculated benefit. 77 Replace current PORVs with larger ones such that Maximum Benefit is bounded by SAMA No. 73-b The estimated cost of instalhng larger PORVs was only one is required for successful feed and bleed. based on the actual cost of performing this modification at another CE Pressurized Water Reactor plant, Palisades Nuclear Plant, in 1989 (see NRC Ouestion No.14). t P 54

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; APPLICANT's ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS 4 SAMA Modification / Procedure Enhancement / Training Method of Calculating Maximum Benefit Basis for COE Estimate No. Option 7F Prowde capabihty for desel-dnven, low pressure Set the frequency of medium and large break LOCA This estimate was based on TVA's estmate for an vessel make-up. tu zero. attemate means of core injection (Environmental Report Reference 6), as modifed by BGE experience installing two new EDGs. 79 Provde an additional HPSI pump with an Set all AFW hardware and human action failure Based on estimate provided in Environmental Report independent diesel. probabihtses to zero. Set all sa'ety injection pump Reference (6), as modified to account for additional related hardware failure probabihties to zero. costs associated with modifying an operating plant. 80 Implement a Refuehng Water Tank make-up Set inter-System LOCA and SGTR frequences to No estimate provided, as CCNPP procedures already procedure. zero. address the intent of this SAMA. 81 Stop low pressure safety injection pumps earher in The LPSI pumps are automatica!!y stopped on a Based on engineenng judgment, the cost of medium or large LOCAs. RAS. Further, existing procedures direct the implementing this SAMA would exceed the "minimar operators to stop the LPSI pumps when not injecting benefits, so no estimate was provided. This SAMA is considered to provided limited benefit. 82 Ensure the plant air compressors are desel Set frequences for AFW-related air failures to zero. No estimate was provided, as CCNPP desgn and generator backed. procedures already address the intent of this SAMA. 83 Install more rehable plant air, instrument air, and SW Set safety-related and non-safety-related No estimate was provided, as BGE has determined air compressors. compressed air hardware failure probabilities to zero. that the cost of any hardware modification would exceed $40,000. 84 Install motor generator set tnp breakers tri the control The nsk benefit for this SAMA was determined to be Based on engineenng judgment, the cost of room. minimal, as the existing plant configuration meets the implementing this SAMA would exceed the "minimar intent of the SAMA. benefits, so no estimate was provided. 85 Provide an additional instrumentation system for The nsk benefit for this SAMA was determined to be Based on engineenng judgment, the cost of ATWS mitgation. minimal, as existing ATWS indication was deemed to implementing this SAMA would exceed the "minirnar be adequate. benefits, so no estimate was provided. 86 Provide capabihty for remote operation of secondary The nsk benefit for this SAMA was determined to be Based on engineenng judgment, the cost of side relief valves in an SBO event. minimal, as the existiag plant configuration meets the implementing this SAMA would exceed the "minimar intent of the SAMA. benefits, so no estimate was provided. 87 Create / enhance RCS depressunzation ability. Maximum Benefit is bounded by SAMA No. 27. Based on estimate submrtted by Tennessee Valley Authonty for Watts Bar SAMA anatysis. 88 Remove PORV hft on high pressunzer pressure. Maximum Benefit is bounded by SAMA No. 48-b. No estimate was provded, as the intent of this SAMA is also addressed by another, less costfy SAMA, and was determined to have a negativs net value. t 89 Install secondary sde guard pipes around existing Set Main Steam Line Break frequencies insde No estimate was provided, as the design feature piping up to the main steam isolation valves. containment and upstream of the MSIVs to zero. addressed by this SAMA is already included in i CCNPP design. 90 Install digital large break LOCA earty detection. Set Large Break LOCA frequencies to zero. Based on engineering judgment, COE would greatly exceed maximum calculated benefit. 91 increase seismic capacity of the plant.. to twice Screened on High Cost. Maximum Benefit not No estimate was provided, as this SAMA es not the Safe Shutdown Earthquake. calculated. feasible for an existing plant. 92 Install a dedicated diesel generator for the DW Assumed DW make-up is always available to SRW The estimate for thrs SAMA was provided for SAMA transfer pumps. and CCW. No.74. 93 Cap downstream piping of normally closed CC The total loss of CC initiator was reduced by Based on engineenng judgment, the cost of instalhng System drain and vent valves. 70 percent. The likelihood of post-tnp CC leakage redundant vatving on the uncapped knes would causing a CC failure was reduced by 10 percent. greatly exceed the maximum benefit. [ 55

ATTACHMENT (1) - ~ RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION; ^ APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS No Method of Calculating Maximum Benefit Basis for COE Estimate 94 Replace Emergency Core Coohng System pump Set all CC initiating events, hardware failure Based on engineenng judgment COE would greatty motors with air-cooled motors. probabilities, and human action failure probabilities to exceed maximum calculated benefit. zero. 96 Provide a core debns con *rol system. Benefit was determined to be minimal, as Based on estimate sutumtted by Tennessee Valley containment failure due to debris impmgement is not Authonty for Watts Bar SAMA analysis. considered in IPE Level 2 analysis. 96 Implement procedures to stagger HPSI pump use Desenbed in response to Queston No.16. Desenbed in response to Question No.16. after a loss of S"N. 97 Use FP System as a back-up make-up source for the The risk benefit was not quantified for this SAMA, as No estrnate was provided, as the modrficaten Refueling Water Tanks. injec+ ion of non-borated water into the RWT would proposed by this SAMA could provide an result in reactivity excursions. unnecessary challenge to nuclear safety. I I h b 56

ATTACHMENT (1) RESPONSE TO REQUEST FOR ADDITIONAL INM)RMATION; ~ APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS Table 11 Net Value for SAMA Numbers 49,66-b, and % [ Question No.16] NET VALUE FOR SAMAs RELATED TO CCNPP UNIT 1 Objective P nal Total Benefit Net Value Offs t sts Onsit C sts N Exposure Exposure 49 Add an automatic bus transfer feature $245,000 $133,000 50 $35,000 $413,000 $884,000 ($471,000) that would automatically transfer between either the back-up bus or the stand-by inverter on the failure of the operating inverter. 66-b implement internal flood prevention and $541,000 $235,000 $0 $6,000 $782,000 mitigation consideration (i.e., water-tight doors). - SRW Pump Room $328.000 $143,000 50 $4,000 $474,000 Not estimated. Not calculated. Implement procedures to stagger llPSI $130,000 $57,000 $0 $20,000 $2%,000 Not esti;nated. Not calculated. Pump use after a loss of SW. i 57

ATTACHMENT (2) l l [ t ERRATA TO APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS i l i l l l Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant Decemher 3,1998 l

ATTACHMENT (2) ERRATA TO APPLICANT'S ENVIRONMENTAL REPORT - OPERATING LICENSE RENEWAL STAGE; SECTION 4.1.17, SEVERE ACCIDENT MITIGATION ALTERNATIVES ANALYSIS The following changes apply to the Severe Accident Mitigation Alternatives analysis in Attachment 2 of the Baltimore Gas and Electric Company License Renewal Application. In response to Question No. 5, on page F.1-8, Table F.1-4, under Population: Delete all Population Dose data - within 10 miles, and make the following changes to the 50-mile Population Dose: Change the Late Containment Failure dose from 7.56E-01 to 1.38E+00; Change the Small Early Containment Failure dose from 3.93E+01 to 3.87E+01; e Change the Large Early Containment Failure dose from 1.27E+01 to 2.62E+01; ) e Change the Small Containment Bypass dose from 1.14E+00 to 8.25E-01; e Change the Large Containment Bypass dose from 2.10E-01 to 1.53E+00; and e Change the Total Annual Risk dose from 5.42E+01 to 6.86E+01. j e In response to Question No.12, please make the following changes: On page F.5, add Reference 20, " Risk insight by BGE's Reliability Engineering Unit based on e IPE/IPEEE experience." On page F.2-9, change Reference Source "I8" to "20" for SAMA No. 24. On page F.2-17, change Reference Source "18" to "20" for SAMA Nos. 79 and 30. j e On page F.2-18, change Reference Source "I8" to "20" for SAMA No. 81. On page F.2-22, change Reference Source "18" to "20" for SAMA No.109. On page F.2-23, change Reference Source "I8" to "20" for SAMA No. I 15. l l On page F.2-24, ci:ange Referen;e Source "I8" to "20" for SAMA No.121. t l. On page F.2-25, change Reference Source "18" to "20" for SAMA No.122. o 1 On page F.2-30, change Reference Source "18" to "20" for SAMA No.158. I

ATTACHMENT (3) i QUESTION 7 POSITION PAPER JUSTIFYING BGE's AVERTED ONSITE COST ASSUMPTIONS i i Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant December 3,1998

ATTACHMENT (3) QUESTION 7 POSITION PAPER JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS I. INTRODUCTION This paper examines whether certain Averted Onsite Costs (AOSC) -- specifically, insured onsite property damage and replacement power costs -- should be considered in an analysis of severe accident mitigation attematives (SAMAs) conducted as part of the National Environmental Policy Act (NEPA) evaluation of the renewal of nuclear plant operating licenses. In a September 9,1998 Request for Additional Information (RAI)' related to Baltimore Gas and Electric (BGE) Company's application to renew the operating license for the Calvert Cliffs Nuclear Power Plant, the Nuclear Regulatory Commission (NRC) staff has referred to the NRC's Regulatory Analysis Guidelines, NUREG/BR-0058, Revision 2, as " call [ing] for the inclusion of these onsite impacts." The NRC's Regulatory Analysis Guidelines refer in turn to more detailed guidance in the NRC's Regulatory Analysis Technical Evaluation 11andbook, NUREG/BR-0184, which provides a " net value" approach to cost benefit analysis. Under this approach, net value equals APE (averted public exposure) + AOFC (averted offsite costs) + AOE (averted occupational exposure) + AOSC (averted onsite costs)- COE (cost of enhancement). For the reasons discussed more fully below, this paper concludes that insured onsite property damage and replacement power costs are not proper considerations in the evaluation of SAMAs. There are a number of reasons for this conclusion. First and foremost, insured property damage and replacement power should not be considered in a cost benefit balance because they are not costs that will or are likely to be incurred. With respect to insured property damage, BGE will already have paid for the damage through premiums reflecting the actuarial value of that damage. This insurance offsets any loss (any cost) of the insured amount. The insured cost cannot be ignored or dismissed as a " transfer payment" because it is not a free transfer of a benefit. Rather, it is the payment of an accumulated amount provided by insurance companies (some of which may be captives of the nuclear industry) in return for premiums. With respect to replacement power costs, the rapid transition to energy deregulation makes its extremely remote and speculative that such costs would be incurred. If BGE were no longer able to sell the power generated by CCNPP in a deregulated market, one would expect the next marginal producer to replace the power at approximately the same market price. Given this expectation, consumers should not see any significant price impact, and consequently there should be no appreciable public or societal impact. Beyond these factual arguments, AOSC does not even appear to be a proper National Environmental Policy Act (NEPA) consideration in the first place. The National Environmental Policy Act requires evaluation of environmental matters, and the proper focus of a SAMA analysis must remain on the mitigation of environmental impacts. Underjudicial interpretations of NEPA (discussed later in this Attachment), economic impacts are only a consideration where there is a reasonably close causal relationship (similar to proximate cause) between a change in the physical environment and an economic impact. Thus, for example, where a proposed action may adversely affect farmland, the economic inpacts of crop loss causally related to the environmental harm are proper considerations. Letter from Ms. C. M. Craig (NRC). to Mr. C. H. Cruse (BGE). dated September 9.1998, " Request for Addnional information for the Review of the Calvert Cliffs Nuclear Power Plant (CCNPP) Unit Nos.1 & 2 License Renewal Application. Severe Accident Mrtigation Altematives (TAC Nos. MA1524 and MA 1525)" l

I l ATTACIIMENT (3) l QUESTION 7 POSITION PAPER JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS With respect to SAMAs, the causal link between the environmental impacts (the release of radiation to the environment) and the cost of repairing the reactor and replacing its power is generally lacking. These AOSC are not caused by, or a cost of, an impact on the natural environment. The appropriateness of this proximate cause requirement is apparent. Including insured property damage and replacement power costs would skew the evaluation of SAMAs towards economic rather than environmental impacts. For example, BGE's review of using the Fire Protection System as a backup source of cooling for the emergency diesel generators indicated an offsite and occupational risk reduction value of approximately $176,000, but the "value" of this SAMA would be inflated to about $770,000 by adding in insured onsite damage and replacement power considerations. Thus, the onsite costs dwarf (by over 300 percent) the environmental considerations. Put another way, inclusion of the AOSC factors could militate toward implementing a SAMA even though its actual implementation cost exceeds its environmental benefit many times { over. Clearly, this is inappropriate. II. BACKGROUND A. Prior SAMA Analyses re have been relatively few SAMA analyses conducted in connection with the licensing of . clear plants, and consideration of AOSC has been inconsistent. Prior to 1989, the NRC did not consider severe accident mitigation alternatives in its environmental impact statements supporting nuclear plant licensing. After the U.S. Court of Appeals for the Third Circuit held that SAMAs should be considered in the environmental impact statement (EIS) for the Limerick Generating Station,2 the NRC prepared a SAMA analysis for Limerick and also included such analyses in the environmental impact statements for the two other subsequently-licensed plants (Comanche Peak and Watts Bar). Neither the SAMA analysis for Limerick nor the SAMA analysis for Comanche Peak included any consideration of AOSC. NUREG-0974, Supplement (Aug.1994); NUREG-0775 Supplement (Oct.1989). But in the Watts Bar SAMA analysis, the NRC reduced the cost of enhancement by the avened onsite cost, comprised of a cleanup component and a replacement power component. NUREG-0498, Supp.1. at 7-25 and 7-25 (April 1995). The NRC's Watts Bar evaluation referenced a 1993 draft of NUREG/BR-0184, Regulatory Analysis Technical Evaluation Handbook.' B. The NRC Handbook and Guidelines The NRC Regulatory Analysis Technical Evaluation liandbook was developed for use in preparation of " regulatory analyses to aid NRC decision-makers in deciding whether a proposed new regulatory requirement should be imposed." NUREG/BR-0184 at xv. The Handbook calls for the identification of the " attributes" that could be affected by a proposed action. It lists a number of such attributes, including onsite property. With respect to onsite property, it cautions: "Particular care should be taken in estimating dollar savings associated with this attribute because (1) values for this attribute are difficult to accurately estimate, and (2) estimated values can potentially l significantly outweigh other values associated with an alternative." l 2 Lirnerick Ecology Action. Inc. v. NRC. 689 F.2d 719 (3d Cir.1989) 8 During rneetings between NRC and BGE to discuss the environrnental review of BGE's application for license renewal, the l staff has suggested that BGE refer to this Handbook (which was finalized in 1997)in preparing its SAMA analysis. l 2

l l ATTACHMENT (3) QUESTION 7 POSITION PAPER JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS l The NRC Handbook is based on NUREG/BR-0058, Revision 2, " Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission" issued in November 1995. Those guidelines are again l developed for " regulatory value-impact analyses to determine whether there is an adequate basis for imposing new requirements on licensees." E at vii. It must be noted that the guidelines require a safety goal screening. A proposed action is not subjected to detailed analysis ifit does not have a CDF (CDF) reduction of at least 10-5/ reactor year, and the NRC staff has the discretion uct to proceed with further analysis where the CDF reduction is less than 10-4/ reactor year. See 11 at 9,11. Like the Handbook, the guidelines contain the same warning about estimating AOSC savings. The l Commission's guidelines further state that "[i]n those instances where the exclusion of averted onsite costs and improved plant availability would be expected to result in a different or significantly altered conclusion, the staff should also display the results with these elements excluded for sensitivity analysis purposes, and to help clarify the basis for the regulatory decision." E at 20. J The NRC's inclusion of AOSC in the guidelines has been controversial. The issue whether averted plant damage should be considered a benefit was first raised in the 1980s when the NRC proposed its safety goals. He industry opposed this inclusion on the grounds that decisions should be made based on public health and safety considerations, not on the financial investment of the utilities and their investors. Based on these considerations, the NRC initially agreed not to include onsite l property damage factors. See SECY-93-167, Encl. 3 at 1. l After further internal deliberations, however, the NRC staff reversed its position and recommended that AOSC be included in cost-benefit analyses. The Commission initially expressed its support for this recommendation in SECY-89-102, " Implementation of the Safety Goals" (June 15,1990. This recommendation prompted further industry comments, particularly a March 27,1991 letter from NUMARC addressing the inappropriateness of including AOSC in cost-benefit analyses under the l backfit rule. NUMARC argued that the staff should be weighing real dollar costs ofimplementing a plant change against the benefit to the public health and safety. " Hypothesized costs incurred or avoided by a utility as the result of a postulated transient or accident at its nuclear plant is an economic risk factor, but it is not a proper basis for regulatory decision-making." Letter from B. Lee to K. Carr (March 27,1991) at 1. The NRC considered these comments but decided to retain AOSC as a factor to be considered in its l regulatory analyses. In a paper addressing the industry comments, the staff concluded that "it seems inconsistent to say that the NRC can consider financial costs which would tend against imposing a backfit but not financial benefits which would tend to favor the backfit." SECY-93-167, Encl. 3 at

3. The staff added that the key determinant is the need to display all meaningful consequences from a societal perspective,' because ultimately the staff is deciding whether to commit scarce societal resources. E Additional reasons identified for considering AOSC are that (1) TMl experience shows that onsite cleanup costs may be paid by customer revenues or by governmental cleanup (ir the financial risk is not borne exclusively by the utility); (2) the onsite exposures may be l

The staff paper suggests that this is similar to NEPA-type assessments. 3

.--. - _ _ = ATTACHMENT (3) QUESTION 7 POSITION PAPER JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS significant;' and (3) there is too much uncertainty in the risk analyses to permit making a distinction between accidents which threaten only the utilities' investment as opposed to public or offsite risks. 1 E, Encl. 3 at 2,3. The staff also considered the argument that estimates of AOSC should take into account the property insurance the agency requires oflicensees, in order to avoid double counting. Dismissing this argument, the staff stated: l The concern that this would constitute double-counting because the licensee already paid for that coverage ignores the fact that, from a societal perspective, insurance represents a redistribution of resources with no real loss for society. Insurance premiums, like taxes, are a transfer payment between different segments of society and, in and of themself, constitute no real consumptive use of resources. (The only exception is relatively minor transaction costs and costs of managing and administering the insurance fund). E at 6. III. DISCUSSION A. Insured Property Damage is not a True Cost That Will be Incurred Insured onsite property damage is not a true cost that would be incurred. With respect to insured onsite property damage, the licensee will already have paid for that loss through insurance premiums reflecting the actuarial value of the loss. In SECY-93-167, the staff dismissed onsite property insurance as a transfer payment. This position is reflected in the NRC's Regulatory Analysis Guidelines, which states that " Transfer payments such as insurance payments and taxes should not be included as impacts because they do not use consumptive use of real resources." NUREG/BR-0058, Revision 2, at 22 (emphasis added). This statement is echoed in the RAI. The NRC's statements in NUREG/BR-0058 and in the RAI are somewhat off the mark, because there has been no suggestion that insurance payments should be considered an " impact." Rather, the pertinent point is that insured offsite property damage is not an impact, because it has already been paid for. The NRC's statements also appear inconsistent with OMB Circular No. A-94, " Guidelines and Discount Rates for Benefit-Cost Analysis of Federal Programs" (Oct.1992), which defines transfer payments as: A payment of money or goods. A pure transfer is unrelated to the provision of any goods or services in exchange. Such payments alter the distribution of income, but do not directly affect the allocation of resources on the margin. Since averted occupational exposures (AOE) are considered separate!y from AOSC. it is not clear why this statement is relevant. 4 l

ATTACHMENT (3) QUESTION 7 POSITION PAPER JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS The OMB guidelines state that "[t]here are no economic gains from a pum transfer payment because j the benefits to those who receive such a transfer payment are matched by the costs borne by those who pay for it. Therefore, transfers should be excluded from the calculation of net present value.... " (emphasis added). l An example is a tax on electricity generated. If one calculates the benefit of the electricity generated as the price of that electricity and then claims the taxes on that electricity as a further l benefit, the benefits will be overstated. This overstatement occurs because in fact the tax merely l takes a portion of the benefit (the value of the generated electricity) and transfers it' free to the government. l Insurance payments to cover onsite property damage are not pure transfers that should be excluded f from consideration under these guidelines. First, an insurance payment is made in exchange for payment of premiums and contingent on the property damage. Accordingly, it is not just a redistribution of wealth without quid pro quo. Rather, it reflects the prepayment of actuarial value of the onsite property damage insured. In effect, the licensee and insurer are setting aside money to cover this risk. Second, the nuclear property insurers include industry captives, so it is not clear to what extent a " redistribution of wealth" occurs. Last but not least, consideration of the insurance l payments does not result in any double-counting of benefits or impacts (the basis on which transfer l payments are usually ignored). Double-counting would occur if an insurance payment were considered an impact (iA if an analysis counted both the value of the onsite property damage and l the value of the insurance payment as costs, in essence doubling the accident cost). Double-counting does not occur where insurance is being considered as offsetting to a purely economic risk. B. Replacement Power Costs are Remote and Speculative The advent of deregulation makes the possibility of significant replacement power costs (either to the licensee or the public) remote and speculative. In a deregulated market, electricity will be sold at marginal cost. If Calvert Cliffs' generating capacity were lost, replacement power would be supplied by the next marginal producer. Assuming (as one should) that the market is working, the cost of that replacement power would be expected to be very close to the existing market price, and it is very unlikely that customers would see any appreciable price increase. The Maryland Public Service Commission (PSC) has ordered that retail competition be phased in, to begin in July 2000 with full retail access to all Maryland residents and businesses by July 2002. In l the Matter of the Commission's Inauiry into the Provision and Regulation of Electric Service, Md. l PSC Case No. 8738, Order 73834 (Dec. 3,1997) at vii,38, modified, Order 73901 (Dec. 31,1997) l at 4, afCd on shearing, Order 74561 at 34 (Sept.10,1998). Through 2002, a " default" service will be established for customers who have not selected a new supplier, but the electric supply will be provided from the competitive market place. After this transition period, generation assets will be completely deregulated, and generators will no longer have an obligation to provide service to any service territory. Sec Order 73834 at 66; Order 74561 at 33.6 The Maryland PSC has also recommended an amendment to the Public Service Commission Law - Md. Ann. Code Art. 78, $ 54F (1993 ed.)- to allow it to eliminate the fuel rate adjustment clause. Order 73834 at 160. When this clause is eliminated. there will be no mechanism by which customers may be charged replacement power costs. I 5

i ATTACHMENT (3) j QUESTION 7 l POSITION PAPER JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS Under this framework, the concept of " replacement power costs" is essentially meaningless. Suppose, for example, that after deregulation, customers contract with BGE for generation services at a firm market price. In this case, if Calvert Cliffs' generating capacity were lost, BGE would still have to supply power at the firm price, and its customers would be unaffected. To provide this power, BGE would either have to use another of its own generating facilities or purchase power l from the competitive market (and presumably would choose the most economic option). If the electric market were truly competitive, the price of power on the open market would be the cost of the next marginal producer, which one would expect to be very close to the existing market price. l Alternatively, in a competitive market, BGE might have the ability to terminate its contracts with customers or increase its prices to the extent allowed by its contracts. In such event, one would expect customers to switch suppliers to again obtain power at the existing market price. l Consequently, the only " cost" that one could reasonably expect would be some lost profits by BGE, but this would be a purely private, economic cost. The magnitude of this cost would depend on the difference between Calvert Cliffs' production costs and the market price for electricity, and it would be a very speculative undertaking to estimate what this difference might be twenty or thirty years from now, during the period of extended operation. However, the $23 million competitive sale price for Three Mile Island Unit I reflects the present value of that unit's projected profit in a competitive market over the remaining 15-year life of the unit. This is nowhere near the multi-l billion dollar assumption in NUREG/BR-0184.' l C. Other Considerations Support the Exclusions of AOSC AOSC should also be excluded because such purely economic considerations in the net value j formula would distort the NEPA analysis and cuggest adoption of SAMAs where the cost of implementation substantially outweighs -- by over 300 percent as indicated in the example on j page 2 of this Attachment -- the environmental benefits. Such a distorted approach would clearly be l unreasonable and inconsistent with NEPA's focus on the environment. I l In addition, the other factors that prompted the NRC to include AOSC in its guidelines do not appear germane in this case.' In particular, (1) there are no excluded costs that may be paid by customer revenues or by governmental contributions (iA the insured risk is borne exclusively by the utility and already paid for, and replacement power costs are unlikely as discussed below); (2) onsite exposures are fully considered; and (3) BGE does not attempt to distinguish between accidents which threaten only the utilities' investment as opposed to public, or offsite risks. i D. NEPA Last, aside from the fact that onsite property damage is insured and replacement power costs are unlikely in a deregulated market, it also appears that AOSC is not a proper NEPA consideration in the first place. At the outset, it is clear that the Guidelines and Handbook discussed above were i developed for safety determinations -- to support rulemaking and backfit decisions. As the NRC l Regulatory Analysis Guidelines state, the guidelines were developed to determine whether there is an adequate basis "for imposing new requirements on licensees." NUREG/BR-0058, Revision 2, at i 7 San NUREG/BR-0184 at 5.44, See SECY-93-167. Enct 3, discussed at page 4 of this Attachment. 6

. ~.. ~ -... l 1 ATTACHMENT (3) QUESTION 7 l POSITION PAPER JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS l vii.' The Commission has not properly considered whether or how these guidelines might apply to NEPA reviews. The lack of explicit discussion and consideration of NEPA's requirements is significant, because the guidelines contemplate a safety-goal screening to limit evaluations to proposals with a threshold degree of benefit. Since such safety-goal screening has not been applied in prior SAMA analyses, application of the other provisions of the guidelines (iA_the net value formula) results in detailed analyses without any mechanism to maintain the reasonable perspective contemplated by the guidelines. l There is no judicial case law addressing whether NEPA mandates or even anticipates consideration of the economic impacts of mitigation measures. On the other hand, a number of courts have considered whether NEPA requires the balancing of the economic costs and benefits of a proposed action and its alternatives. While courts initially were split on the issue, after the Supreme Court's i ruling in Metropolitan Edison Co. v. Peoole Against Nuclear Energy,460 U.S. 766 (1983), most courts have held that NEPA does not anticipate that agencies will weigh the purely economic impacts of a proposed action. The Metrooolitan Edison decision made clear that NEPA does not require agencies to consider every impact of a proposed action, but only those impacts on the natural environment. The Court read the terms " environmental effects" and " environmental impact" to include a " reasonably close I causal relationship between a change in the physical environment and the effect at issue," a tequirement similar to that of proximate cause in tort law. 460 U.S. at 767, 774. Since this decision, courts have uniformly held that the requirement to prepare an EIS is triggered by a significant change in the physical environment and that NEPA does not protect purely economic interests, especially in the absence of an impact to the physical environment. Sss City of Los l Angeles v. U.S. Deot. of Agriculture,950 F. Supp.1005,1013 (C.D. Cal.1996); Morris v. Myers. 845 F. Supp. 750, 757 (D. Or.1993); Mall Prooerties. Inc. v. Marsh, 672 F. Supp. 561, 566 (D. l Mass.1987); Ono v. Harner. 592 F. Supp. 698,701 (D. Hawaii 1983); Nat'l Wildlife Fed. v. Marsh. 568 F. Supp. 985,1000-01 (D.D.C.1983). The court in Morris v. Myers held that homelessness and a dearth oflow-income housing do not fall within NEPA's zone of interests. The court explained that NEPA was not intended to create a process for correcting social and economic problems, but to force agencies to consider the l consequences of their actions on " land, air, water, and other natural resources upon which our society depends." 845 F. Supp. at 757. The court went on to explain that not just any change in our l physical surroundings constitutes an effect on the environment of which NEPA is cognizant. The plaintiffin the case argued that the demolition of a building constituted the requisite change in the physical environment triggering NEPA's EIS requirements. In rejecting this contention, the court held that the demolition itself is not the impact with which NEPA is concerned. It is the The stated purpose of the Handbook and Guidelines - to determine whether new regulatory requirements should be imposed. - immediately underscores the disconnection between these documents and NEPA. It is well settled that NEPA's requirements are procedural only. Vermont Yankee Nuclear Power Coro. v. NADC. 435 U.S. 519. 558 (1978). While other environmental statutes impose substantive obligations on agencies, "NEPA merely prohibits uninformed - as opposed to unwise - agency action." Robertson v. Methow Vallev Citizens Council 490 U.S. 332. 351 (1909). Further, the Supreme Court has held that NEPA's implied obligation to assess potential mitigation attematives to the proposed action does not entail an obligation to set forth a complete mitigation plan in the EIS, nor does NEPA require that a mitigaticn plan be adopted in the agency's final decision and actually implemented. According to the Court, to read NEPA otherwise would belie the statute's procedural nature. Robertson. 490 U.S. at 352-53 and n.16. Therefore. it is clear that NEPA does not " require" actual implementation of any mitigation measures, even cost-beneficial ones. l 1 7

.ATTACIIMENT (3) QUESTION 7 POSITION PAPER JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS l consequences of the demolition -- noise, dust, disposal of debris, etc. -- that constitute the l environmental impacts that must be addressed in an EIS. Id. Under this reasoning, mere damage to the physical structure of the Calvert Cliffs nuclear facility, without more, fails to rise to the level of an environmental impact. Thus, by negative implication, measures designed to avoid or reduce the environmental impacts of severe accidents at the facility should not be weighed (under NEPA) based upon the magnitude of the property damage to the facility avoided because this benent is not an " environmental" benent. In Mall Procenies. Inc. v. Marsh the district court reversed an Army Corps of Engineers decision denying a permit to develop a shopping mall because the Corps improperly based its decision upon economic effects unrelated to the impact of the development on the environment. The Corps withheld the permit based upon adverse economic competition the mall would create between the cities of North Haven and New Ilaven, Connecticut. In reversing the decision, the court concluded that: [NEPA] was enacted to protect the natural environment.... There is no suggestion that [the Corps] was perceived by those enacting [NEPA] to have expertise concerning whether the economic interests of aging cities or their newer suburbs should as a matter of policy be preferred. As the Supreme Court noted in Metronolitan Edison,.. a broad grant of authority to the Corps to decide general public policy issues would require an agency to seek to develop expertise 'not otherwise relevant to [its] congressionally assigned functions.' This would cause 'the available resources [to] be spread so thin that [the Corps in this case would be] unable adequately to pursue protection of the physical environment and natural resources.' In Metrooolitan Edison the Supreme Court found it could not ' attribute to Congress the intention to... open the door to such obvious incongruities and undesirable possibilities.' 672 F. Supp. at 573-74 (citations omitted). Courts have also held that where the economic benent or burden is privately borne, these impacts are not relevant to NEPA's analysis. South Louisiana Environmental Council v. Sand,629 F.2d 1005,1011 (5th Cir.1980); Nat'l Wildlife Fed. v. Marsh,568 F. Supp. 985,1000-01 (D.D.C.1983). In Nat'l Wildlife Fed. v. Marsh the court rejected a claim that an EIS was inadequate because it failed to consider rennery costs, transportation costs, raw materials costs, capital costs, labor costs, and maintenance costs associated with the construction of an oil refinery in the Chesapeake Bay. The court relied upon the fact that not only were these purely economic costs, but that these were private costs to be incurred by the permit applicant, not costs to be borne by the general public. NEPA, the court concluded, ... is concerned primarily with environmental costs affecting the public, not with private j economic costs.... [P]rivate investors can be relied upon to determine 'that the j establishment of an oil reGnery in Portsmouth would be, from their perspective, an i economic venture.' l I 8

=_ ATTACHMENT (3) QUESTION 7 ) POSITION PAPER JIJSTIFYING BGE's AVERTED ONSITE COST ASSUMPTIONS l 568 F. Supp. at 1000, quotme South Louisiana Environmental Council v iand,629 F.2d 1005,1011 (5th Cir.1980). This result is a logical extension of the case law holding that NEPA is unconcerned l with economic impacts related only tangentially to a change in the environment. Particularly whe e the economic impact is internalized by the entity whose proposal the agency is considering, NEPA l does not require these effects to be considered. 1 Like the judicial case law discussed above, apparently there is no NRC precedent addressing whether NEPA requires consideration of the economic impacts of mitigation alternatives. However. l there is a considerable number of Licensing Daard and Appeals Board decisions to tne effect that purely economic effects need not be weighed when considering a proposal and its alternatives in an EIS. The NRC has, at least since the Metronolitan Edison Supreme Court decision, interpreted NEPA as only protecting those economic interests "resulting from environmental damage." Sacramento Municinal Utility District (Rancho Seco Nuclear Generating Station), LPB-92-23,36 NRC 120,131 (1992). So, for exartyle, financial interests such as excessive electric rates or higher fuel costs do not come within the purview of NEPA. Portland General Electric Co. (Pebble Springs Nuclear i Plant, Units 1 and 2), ALAB-333,3 NRC 804,806, affd, CL1-76-27,4 NRC 610,614 (1976);IYA (Watt 3 Bar Nuclear Plant, Units 1 and 2), ALAB-413,5 NRC 1418,1420-21 (1977). In addition, the purpose cf an EIS is to " determine whether the proposed action brings about changes in the l environmental rtatus quo, and to measure the justification for the proposed action against those l changes." Florida Power & Light Co. (Turkey Point Nuclear Generating, Units 3 and 4), ALAB-660,14 NRC 987,1004 (1981). Taken together, these principles lead to the conclusion that the NRC need only consider those economic impacts of a proposal or an alternative that are related to, j x that result from, an adverse change in the status quo of the physical environment. Purely economic costs and benefits need not be discussed in an EIS because these "efTects" are not closely related to some form of erivironmental harm -- air or water pollution, noise, aesthetic blight, l physical harm to animal and plant life, habitat loss, etc. ke, e.g_ Morris v. Mvers, 845 F. Supp. l 750, 757 (D. Or.1993). This appears to be the conclusion of the Appeals Board in Turkev Point. In that case the board l declined to require the Commission to consider as an alternative to the proposed repair and upgrade of a nuclear generating facility the continued operation of the facility on a derated basis nnd use of j the moneys saved on an energy conservation program. The Board made it clear that even if the l unconsidered alternative made better economic sense, ... the financial pros and cons of the [ proposal) as against the [alternativ6] are not the Commission's concern at least where, as here,6ere has been no showing that signif' cant environmental consequences attach to the utility's proposal. Neither NEPA nor any other statute gives us the authority to reject an applicant's proposal solely because an alternative might prove less costly financially. 14 NRC at 1007. These concerns, the Board went on to note, are left to the business judgment of utility companies and to the supervision of State rs.satory agencies. Id., n.28. Similarly, the Licensing Board has held that evaluation of an alternative based upon " economic superiority" as 1 opposed to "environmer.tal superiority" is not NRC's responsibility..Yirginia Electric and Power Co. (North Anna Power Station, Units 1 and 2), LBP-85-34,22 NRC 481,492 (1985). Thus, while i 9

ATTACHMENT (3) QUESTION 7 POSITION PAPFR JUSTIFYING BGE'S AVERTED ONSITE COST ASSUMPTIONS all of these decisions address the consideration of the adverse economic effects of proposals and their alternatives, this line of cases supports the conclusion that the economic benefit associated with mitigation measures that avert Onsite property damage in the event of a severe accident is not the sort of" environmental" impact with which NEPA is concerned. W. Conclusion In conclusion, insured onsite property damage and replacement power costs should be excluded from SAMA analysis. Including these costs would infiate the "value" of a SAMA by introducing costs that will not in fact be incurred and distort the SAMA analysis so that it is driven by economic rather than environmental considerations. Further, both judicial and NRC case law militate against consideration of an action's economic impacts that are not proximately related to any adverse change in the physical environment. In this context, a change in the physical environment means some form of harm to environmental resources, not just any change to an object. In addition, courts have held that private costs, particularly the economic decisions of a utility, are not the sort of impacts with which NEPA is concerned. Therefore, there is little support for NRC's cost-benefit formula taking into account potential savings to a utility (in the form of averted property damage) associated with the adoption of SAMAs. Such economic costs may be proper considerations in performing value-impact analyses for rulemaking, but economic planning is not the goal of NEPA. I 4 10

ATTACHMENT (4) l QUESTIONS 14 AND 16 REVISED COST OF ENHANCEMENT ESTIMATES l-l l l l i 1 4 mans wmra l Baltimore Gas and Electric Company i Calvert Cliffs Nuclear Power Plant December 3,1998 i

ATTACIIMENT (4) QUESTION 14 ] REVISED COST OF ENHANCEMENT ESTIMATES CONCEPTUAL ESTIMATE SAMA No.34 PORTABLE GENERATOR BACK-UP TO 125 VDC BUSES l i BGE Labor, j Hours Bate Intal Field craft 300 $30 $9,000 Project M:nagement 100 $40 4,000 Design Engineering 400 $40 16,000 Radiation Control 0 l ALARA-0 Quality Verification 0 I Planning 50 $35-1,750 Scheduling 0 Procurement 50 $40 2,000 1 Training 200 $40 8,000 Procedures 200 $40 8,000 Material Processing 0 $48,750 Labor Burden: 30% 14,625 Material: 1 DG Set; i mch @ $35,000 per $35,000 - Conduit, cables, receptacles, breakers, etc. 5,000 40,000 Material Handling: 18 % 7,200 l Other: Maintenance: 60 MH per year x 20 years x $39/hr. = 46,800 Subtotal: $157,375 Indirect Supervision & Engineering: 13 % 20,459 Total Project Cost: $177,834 AFUDC 25% 44,458 E timated Cost of Enhancement $222,292 I

ATTACHMENT (4) QUESTION 14 REVISED COST OF ENHANCEMENT ESTIMATES I CONCEPTUAL ESTIMATE SAMA No.45 1 FIRE PROTECTION AS A BACK-UP FOR EDG COOI.ING SUPPLY BGE Labor: Hours Batt Intal Field crafts i Mechanical 2000 $30 $60,000 i Electrical / Controls 2000 $30 60,000 Project management 1000 $40 40,000 Design Engineering i Mechanical 1000 $40 40,000 Civil 200 $40 8,000 I&C 2400 $40 96,000 I Plant Engineering 200 $40 8,000 Chemistry 80 $40 3,200 Quality Verification 200 $40 8,000 Planning 400 $35 14,000 Schduling 100 $35 3,500 i Procurement 300 $40 12,000 Training 300 $40 12,000 Procedures - 300 $40 12,000 j Document Control 400 $25 10,000 $386,700 i Labor Burden: 30% 116,010 ) Material: 850 LF - 6" discharge piping (EDG to tank) 500,000 60 LF - 6" supply piping (fire main to EDG) Mechanical tie-ins at EDG and tank Six - 6" safety-related valves and actuators Select backfill and paving material Electrical / controls components I 500,000 Material Handling: i8% 90,000 Other: Maintenance: l 120 MH per year x 20 years x $39/hr. = 93,600 Testing: 120 MH per year :< 20 years x $39/hr. = 93,600 Licensing: USQ/ App. R submittal (include NRC fees) 100,000 Subtotal: $1,379,910 Indirect Supervision & Engineering: 13 % 179,388 Total Project Cost: . $1,559,298 AFUDC 25 % 389,825 Estimated Cost of Enhancement $1,949,123 2

l 'ATI'ACHMENT (4) QUESTION 14 REVISED COST OF ENHANCEMENT ESTIMATES CONCEPTUAL ESTIMATE SAMA No. 48-a . CONVERT UV. AFAS BLOCK AND EIGil PRESSURI7FR PRESSURE TO 3-OUT-OF 4 LOGIC BGE Labor: Hours Baie Total i Field craftsmen 300 $30 $9,000 Project management 300 $40 12,000 Design Engineering 2000 $40 80,000 Plant Engineering 200 $40 8,000 i Reliability Engineering 500 $40 20,000 ) Quality Verification 200 $40 8,000 Planning 50 $35 1,750 Scheduling 50 $35 1,750 j Procurement 50 $40 2,000 Training 200 $40 8,000 Procedures 500 $40 20,000 Document Control 60 $25 1,500 $172,000 Labor Burden: 30% 51,600 Material: ESFAS - 16 modules @ $15,000 each $240,000 AFAS - 8 modules @ $15,000 each 120,000 RPS - 4 relays @ $1,000 each 4,000 Miscellaneous wire, solder, etc. 1,000 365,000 Material Handling: 18% 65,700 Contractors (FTI)- ESFAS (2 people for 2 days @ $800/ person / day 3,200 AFAS (2 people for 2 days @ $800/ person / day 3,200 i Revise FTl drawings 5,000 Other: l l Nuclear Regulatory Matters: $100,000 (USQ submittal, including NRC review fees) i Testing. i (100 man-hours @ $39/ hour) 3,900 103,900 Subtotal: $769,600 Indirect Supervision & Engineering: 13 % 100,048 Contingency: 10% 86,965 Total Project Cost: $956,613 AFUDC 25 % 239,153 j Estimated Cost of Enhancemcot (2 units) 51,195,766 3

d ATTACHMENT (4) QUESTION 14 REVISED COST OF ENHANCEMENT ESTIMATES CONCEPTUAL ESTIMATE SAMA No. 49 ADD AUTOMATIC BUS TRANSEEE FEATURE BETWEEN INVERTERS " 120V VITAL AC BUSES BGE Labor: Hours Eate-Intal Field craftsmen 2200 $30 $66,000 Project management 600 $40 24,000 Design Engineering 950 $40 38,000 Plant Engineering 400 $40 16,000 Reliability Engineering 160 $40 6,400 Quality Verification 200 $40 8,000 Planning 80 $35 2,800 Scheduling 80 $35 2,800 Procurcment 160 $40 6,400 Training 300 $40 12,000 Procedures 300 $40 12,000 Document Control 160 $25 4,000 $198,400 Labor Burden: 30% 59,520 Material: i - Nine commercial-grade automatic transfer switches (based upon a quotation from an approved electrical equipment manufacturer) 650,000 650,000 Material Handling: 18% 117,000 Other: Nuclear Regulatory Matters: 50,000 (USQ submittal, including NRC review fees) Qualification: l-(based on quotation from an approved 100,000 j. equipment qualification provider) Maintenance: 80 man-hours / year x 20 years x $39/ hour = 62,400 Initial Testing 40 man-hours /ATS x 9 ATSs x $39/ hour = 14,040 226,440 Subtotal: $1,251,360 Indirect Supervision & Engineering: 13 % 162,677 Total Project Cost: $1,414,037 AFUDC 25 % 353,509 . Estimated Cost of Enhancement (2 units) $1,767,546 4

I 1 ATTACHMENT (4) QUESTION 14 REVISED COST OF ENIfANCEMENT ESTIMATES CONCEPTUAL ESTIMATE SAMA No. 68 INSTALL SEPARATE ACCUMULATORS FOR AFW CROS3-CONNECT AND BLOCK VALVES BGE Labor: Hours Rate Total Field crafts 1240 $30 $37,200 Project management 300 $40 12,000 Design Engineering 600 $40 24,000 Plant Engineering 60 $40 2,400 Radiation Control 40 $30 1,200 ALARA 20 $30 600 Quality Verification 80 $40 3,200 Planning 80 $35 2,800 Scheduling 60 $35 2,100 Procurement 80 $40 3,200 Training 40 $40 1,600 Procedures 80 $40 3,200 Document Control 80 $25 2,000 $95,500 Labor Burden: 30% 28,650 Material: Nine non-safety-related, 4-cubic-foot Code 150,000 vessels, x-ray with certifications, 3/8-inch thick w/ hydro tests Valves, piping, hangers, etc. 5,000 200,000 Material Handling: 18 % 36,000 OTHER: Maintenance: 20 manhours / year x 20 years x $39/ hour = 15,600 Initial testing: 80 manhours x $39/ hour = 3,120 Subtotal: $378,870 Indirect Supervision & Engineering: 13 % 49,253 Total Project Cost: $428,123 AFUDC 25 % 107,031 Estimated Cost of Enhancement (2 units) $535,154 5

ATTACHMENT (4) QUESTION 14 REVISED COST OF ENHANCEMENT ESTIMATES i CONCEPTUAL ESTIMATE i SAMA No. 74 AUTOMATE DEMINERAI.17FD WATER MAKE-UP TO CONDENSATE STORAGE TANK NO.12 BGE Labor: Honra Baie Total I Field craftsmen 2400 $30 $72,000 Project management 300 $40 12,000 Design Engineering 2870 $40 114,800 Plant Engineering 120 $40 4,800 Quality Verification 40 $40 1,600 Planning 80 $35 2,800 ] Scheduling 40 $35 1,400 J Procurement 80 $40 3,200 Training 160 $40 6,400 Procedures 200 $40 8,000 Document Control. 80 $25 2,000 $229,000 Labor Burden: 30% 68,700 Material: 230V/25A diesel generator Fuel tank, housing, conduit, cable, sprinkler system, electric transfer equipment, etc. Controls 170,000 Material Handling: 18% 30,600 Other: Maintenance: 40 manhours per year x 20 years x $39/ hour = 31,200 Post-modification testing: 80 manhours x $39/ hour = 3,120 l Subtotal: $532,620 Indirect Supervision & Engineering: 13 % 69,241 Total Project Cost: $601,861 .AFUDC 25 % 150,465 Estimated Cost of Enhancement $752,326 6 .}}