## Diablo Canyon Power Plant



# Cooling Tower Feasibility Study

March 2009

Prepared by:

Enercon Services Inc. 401 Roland Way Oakland, CA 94621i 

### DCPP Cooling Tower Feasibility Study

Table of Contents

Section Page

I. Executive Summary 1

1. Overview 1 2. Design and Construction 1 3. Nuclear Safety 2 4. Environmental Impact and Permitting 2 5. Project Schedule and Costs 3

II. Background & Introduction 4

III. Conceptual Design Overview 5 1. Location of Cooling Towers 5 2. Conceptual Design Summary 9

3. Reduction in Electrical Ou tput with Cooling Towers 13

IV. Construction and Engineering Assessment 15

1. Relocation and Excavation 15 A. Relocation of Existing Facilities 15

B. Relocation of ISFSI Haul Road 18

C. Site Civil Work 18 2. Constructability of Interconnecting Piping 19 3. Modifications to Existing Systems and Required New Systems 21

A. Condenser Modifications 21 B. Service Cooling Water Seawater Supply 22 C. Main Circulating Pumps 23 D. Circulating Water System Piping 24 E. Makeup Water Supply 25

F. Chlorination/Dechlo rination of Effluent Streams 25 4. Electrical System Requirements 26 A. Electrical Design 26

B. Instrumentation and Controls 27

V. Nuclear Safety and Licensing 29 1. Nuclear Safety System Requirements 29 2. NRC Licensing 31 3. Security 32ii 

### DCPP Cooling Tower Feasibility Study

Table of Contents (cont.)

VI. Environmental Impacts and Permitting 32 1. Air Quality – Plume/Salt Drift 32 2. Water Quality – Cooling Tower Blowdown 38 3. Adverse Impacts 42 4. Permitting 45

VII. Additional Studies 47 1. Special Studies 47

VIII. Conceptual Schedule 48

1. Introduction 48 2. Schedule Basis, Calendar, Resources 49

3. Pre-Shutdown Construction 50 4. Construction During Plant Shutdown 50

5. Plant Re-Start and Construction Completion 52

IX. Cost Estimate Summary 52

1. Cost Estimate Overview 52 2. Capital Project Costs 53 3. Decommissioning Costs 54 4. Operation and Maintenance Costs 54 5. Replacement Power During Construction 54 6. Replacement Power due to Derated Capacity 55

Acronyms And Abbreviations 58

Tables
Table 1 Issues that Would Threaten th e Feasibility of the Project 4 Table 2 Projected Average Flow to/from Ocean (per Unit) 11 Table 3 Reduction in Plant Electrical Output 14 Table 4 Buildings/Facilities that Would Require Relocation 15 Table 5 Visible Plume Length Fre quency Summary – Percent 33 Table 6 Plume Heights – Centerline Height Percent by Direction 34 Table 7 Summary of Thermal Plume Analysis 41 Table 8 Projected Direct Adverse Envi ronmental Impacts of DCPP Retro 44 Table 9 Required Construction and Operation Permits & Licenses 47 Table 10 Cost Estimate Summary 53 Table 11 Major Equipment Procurement Cost 56iii 

### DCPP Cooling Tower Feasibility Study

Table of Contents (continued)

Figures Figure 1 Diablo Canyon Site 6 Figure 2 Topographic Map of Site 7 Figure 3 Cooling Tower Location 8 Figure 4 50,000 Sq. Ft. Warehouse that Would Require Demolition 9 Figure 5 Cross Section Showing Required Excavation 9 Figure 6 Proposed Circulating Water Pump Pit (SK-C-8) 10 Figure 7 Decrease in Generator Output (per Unit) 14 Figure 8 Displaced Facilities 17 Figure 9 Revised Site Layout 17 Figure 10 Existing Circulati ng Water Conduits 19 Figure 11 Original Circulating Water Tunnel Excavation & Construction 19 Figure 12 Existing Underground Utilitie s West of Turbine Building 20 Figure 13 Cooling Tower Plume (Looking North) 36 Figure 14 Cooling Tower Plume (Looking Southeast) 36 Figure 15 Plumes from Nuclear Power Plant Cooling Towers 37 Figure 16 Hrs/Day that Blowdown Temp Would Exceed Discharge Limit 41 Figure 17 Conceptual Installation and Plum e – Perspective From Ocean 57

Sketches Circulating Water System Flow Diagram SK-M-1 Auxiliary Water Systems Flow Diagram SK-M-2 Auxiliary Water System Arrangement SK-M-3

Sketch of Blowdown Diffuser Lines SK-M-4 Cooling Tower Retrofit Electrical Single Line SK-E-1 Electrical System Oneline for CT Auxiliaries SK-E-2 Topo Layout of Cooling Towers SK-C-1 Cooling Tower Profile Existing Ground Elevation SK-C-2 Cooling Tower Cross Section SK-C-3 Cooling Tower Basin Layout-1 SK-C-4 Cooling Tower Basin Layout-2 SK-C-5 Cooling Tower Basin Details SK-C-6 Pump Pit Plan SK-C-7 Pump Pit Section SK-C-8 Pump Pit Walls SK-C-9 Cooling Tower Schematic Layout SK-C-10 Cooling Tower Layout & Access Road Relocation SK-C-11 Cooling Tower Circulating Water Piping Layout SK-C-12 Cooling Tower Concrete Pipe Cross Section-1 SK-C-13 Cooling Tower Concrete Pipe Cross Section-2 SK-C-14 Cooling Tower Concrete Tunnel Layout SK-C-15 Cooling Tower Concrete Tunnel Layout Sect A-A SK-C-16iv 

### DCPP Cooling Tower Feasibility Study

Table of Contents (continued)

Sketches (continued) Arrangement of Underground 13.8 kV Conduit Run SK-C-17 Before Proposed Control Board Changes SK-J-1 After Proposed Control Board Changes SK-J-2 DCPP Cooling Tower Control System C onceptual Block Diagram SK-J-3 Preliminary Triconex I/O Point Count SK-J-4 Preliminary Bently Nevada I/O Point Count SK-J-5

Appendices A-1 Equipment Cost Summary A-2 Equipment List A-3 Pre-Procurement Design Estimate A-4 Design Change Package Estimate A-5 Vendor Budget Quotes

A-6 I&C Detailed Cost Estimate

A-7 Plume Characteristics of Proposed Cooling Towers at DCPP A-8 Civil Quantities Summary A-9 Electrical Cable Tray & Conduit Estimate A-10 Fuel Consumption Summary A-11 Project Cost Estimate A-12 Conceptual Schedule A-13 Power Plant Systems Effluent Concerns1 of 59

March 2009 

### DCPP Cooling Tower Feasibility Study

I. Executive Summary

1. Overview

In response to the 2008 Tetra Tech Inc. coo ling tower feasibility assessment performed for the California Ocean Protection Council, PG&E engaged Enercon Services Inc. (Enercon) to prepare a more detailed, site-spe cific assessment of the feasibility of cooling towers at the Diablo Canyon site. This a ssessment builds upon earlier work, including the 2003 study by Burns Engineering, and provide s a further, more detailed analysis of the feasibility of a cooling tower retrofit. There is no precedent for mechanical draft cooling towers using saltwater makeup at a nuclear facility, a nd no precedent for a retrofit of the magnitude necessary at Di ablo Canyon. Enercon concludes that any retrofit at Diablo Canyon is a highly sp eculative project with likely insurmountable permitting obstacles, substantial engin eering challenges, significant adverse environmental impacts, costs exceeding $4-bi llion dollars, and uncer tainty regarding the Power Plant’s post-retrofit operating capacity fa ctors. Further, plant downtime, reduction of average net electrical output, and a pot ential for ongoing reduced capacity factors would together cause a significant loss in ge neration, and would greatly undermine the State’s ability to meet its Green Hous e Gas (GHG) emissions reduction goals under California Assembly Bill AB 32.

2. Design and Construction Concerns

Enercon concludes, as prior reports have found, that only mechanical draft cooling towers are remotely feasible at the site. Dry cooling is not feasible due to limited space availability, and natural draft towers are not suitable for the site given space and seismic concerns. Furthermore, due to limited space, mechanical draft towers could only be nonplume abated. The conceptual layout include s four tower arrays – each 140 feet by 620 feet, with two rows of ten cells each. Ke y design and construction issues include:

• Demolition and relocation of over 170,000 square feet of existing structures, parking for 1,000 vehicles, and the Indepe ndent Spent Fuel Storage Installation (ISFSI) storage cask haul road.

• Excavation of over 2 million cubic yards of soil and rock.

• 250,000 diesel truck round trips to haul construction materials and excavation spoils.

• Modification of major exis ting systems including the main condensers, service cooling water heat exchangers, and electrical systems.

• Extremely difficult tie-in process given ex isting underground fac ilities to the west and south of the power plant.2 of 59

March 2009 • Construction of an offshore diffusers sy stem for the discharge of a minimum 72- million gallons per day of high salinity cooling tower blowdown.

• Approximately 3-3/4 year construction tim eframe, with a minimum of 17 months

dual-unit downtime.

• An average of over 3,000 workers, requiring 7.4-million miles of bus trips.

3. Nuclear Safety Concerns

Enercon identified several significant issues that will likely require NRC review and approval of License Amendment Requests (LARs) in order to ensure acceptable safety levels during construction, as well as post retr ofit operation. Furthe r analysis of these issues is required to make determinations re garding potential conflicts with nuclear safety requirements. Key issues include:

• Increased flood risk to safety-related systems from cooling tower water.

• Accelerated aging of plant equipment and an increase in possible plant trips due to salt deposition.

• Interruption of the safety-required Aux iliary Saltwater (ASW) system during

construction.

• Increased potential loss of offsite power.

• Rerouting of existing approved ISFSI haul road.

• Increased risk of interruption to the fi re protection system during construction.

• Security concerns related to the openi ng of the protected area boundaries during

construction.

4. Environmental Impact and Permitting Concerns

The installation and operation of cooling towe rs raises significant adverse environmental impacts concerns and poses substantial, li kely insurmountable, permitting obstacles. Key

issues identified include:

• PM 10 emissions likely can not be permitted by the San Luis Obispo County Air Pollution Control District (APCD).

• Salt deposition of at least 7,500 tons pe r year would impact plant equipment, adjacent agricultural lands, and terrestrial habitat.

• The vapor plume from tower operations w ould be over 2,460 feet high 35% of the year. Although low visibility conditi ons may obscure the plumes, and many plumes large enough to be visible are lik ely to occur at night, meteorological conditions conducive to plume visibility are predicted to occur within 1 hour of sunrise or sunset on the order of 45 times per year for Avila Beach, and 300 times per year for San Luis Obispo.

• Fossil-fueled replacement power for the minimum 17 month dual-unit downtime will result in the emission of roughly 10,000,000-tons of GHGs. Derated capacity and additional auxiliary pow er requirements for cooling tower operations total an3 of 59

March 2009 average of approximately 55 MW, enough to supply power for approximately 42,000 California homes. Long term ne gative impacts on GHG emissions of roughly 180,000-tons per year would also result.

• Construction of a diffuser system in Patton Cove south of the power plant will directly disrupt approximately a half- acre of pristine rocky marine habitat.

• Permits for both construction and operat ion are required from many government agencies including: The Californi a Coastal Commission, State Lands Commission, Central Coast Regional Wate r Quality Control Board, San Luis Obispo County (Building and APCD), and the U.S. Army Corps of Engineers. It is highly unlikely that all the n ecessary permits can be obtained.

5. Project Schedule and Costs

Enercon’s assessment is that prior order-of- magnitude estimates grossly understate the cost of a cooling tower retrofit. A more deta iled evaluation of proj ect scope, design and engineering, and required construction resu lts in the following regarding costs and

schedule:

• The overall duration for construction woul d be approximately 3-3/4 years. The plant shutdown during the construction period would be at least 17 months:

o Extensive excavation west of the Turb ine Building in an area congested with both safety related and nonsaf ety related systems, piping and

conduits.

o Significant condenser modifications.

o Need to assure continued operation of the safety related ASW system to provide cooling to the spent fu el pools even during shutdown.

o Extensive relocation of exis ting systems and facilities.

o Massive excavation for coo ling tower installation.

• Total initial project costs are estimated at $4.5 bill ion (2008 Dollars) and would result in an estimated Utility cust omer rate increase of roughly 10%:

o Capital costs estimated at $2.7 billion.

o Cost of replacement power for the minimum 17 month downtime is estimated at $1.8 billion.

o Increased decommissioning costs total $67 million.

• Additional on-going costs total $39 million annually:

o Cooling tower operations and related maintenance is estimated at $7.4 million per year.

o Replacement Power for derated capacity and cooling tower operations totals $31.6 million per year.

Ongoing costs assume that the plant would be capable of continui ng to produce power at roughly current levels / capacity factors. If plant operational efficiency decreases, and net power production is reduced more than the 55 MW expected, electric rates will likely increase even more to cover the purc hase of additional replacement power.4 of 59

March 2009 Table 1: Issues that Would Threaten the Feasibility of the Project

II. Background and Introduction

Diablo Canyon Power Plant (DCPP) could be subject to a requirement to retrofit the existing once-through cooling syst em to closed-cycle cooli ng. Ongoing development of Federal Clean Water Act Section 316(b) re gulations regarding aquatic organism Impingement and Entrainment (I&E) and a Cali fornia Specific Policy for 316(b) rule implementation may require all coastal power plants to reduce Marine I&E to levels commensurate with a closed-cycle cooling sy stem. Previous conceptual analyses of retrofitting DCPP to closed-cycle cooling have been performed by Tetra Tech Inc. (2002, 2008) and Burns Engineering (2003). Th ese studies were limited in scope, and do not provide detailed analysis regarding existing plant operating system and site issues that influence the feasibility of such a project, and the engineering and construction challenges that would be posed by implementati on of a retrofit. At the request of PG&E, Enercon Services developed the following st udy to expand on the previous studies, and further develop the scope, site specific f easibility, projected cost s, and a conceptual implementation schedule associated with re trofitting DCPP to closed-cycle cooling.

Enercon developed a more detailed technica l conceptual design of the cooling tower

retrofit than was done in th e previous Tetra Tech and Bu rns studies, incl uding initial sizing of the equipment, electrical single line development, earthwork and concrete quantity estimation, site/equipment layout consid erations, and identification of significant technical, permitting, and nuclear licensing obstacles. Cost estimates for procurement of the major mechanical and el ectrical equipment have been obtained from equipment suppliers. The Engineering cost estimates fo r the project are based on years of industry Issues that Would Seriously Th reaten the Feasibility of a DCPP Cooling Tower Retrofit Project

• Significant Permitting Obstacles.

• Significant Adverse Environmental Effects.

• Significant Nuclear Safety/Licensing Obstacles.

• 17 Month Minimum 2-Unit Plant Shutdown.

• Severe Shortage of Suitable Land Available For Cooling Towers.

• Substantial Excavation.

• Demolition and Relocation of Numerous Facilities.

• Initial Costs Estimated at 4.5 Billion Dollars.

• Total Annual Salt Deposition Exceeding 7,500 Tons.

• Plumes Often Visible From San Luis Obispo and Avila Beach.

• Greatest Loss in Plant Electric Output (nearly 70 MW per Unit)

Would Occur at Times of Peak Summer Demand.5 of 59

March 2009 and Diablo Canyon specific experience. Enercon worked with PG&E and Cannon Associates in developing the construction co st estimate and project conceptual schedule.

Enercon Services, Inc., founded in 1983, is an engineering, environm ental, technical and management services firm with a wealth of engineering design and project management experience in the nuclear power industry, incl uding extensive design change experience at Diablo Canyon, as well as specific invol vement in studies for retrofitting cooling towers at existing power plants.

Cannon Associates, established in 1976, is a mu ltidisciplinary consulting firm composed of civil, structural, mechanical engineers and environmental and land use planners with expertise in construction management. Cannon performed civil engineering for the Diablo Canyon ISFSI, and coordinated with Granite Construction Inc. for the ISFSI

construction.

III. Conceptual Design Overview

1. Location of Cooling Towers

Perhaps the most challenging aspect of this study has been selection of a suitable location for the cooling towers. There is a severe s hortage of suitable land available for cooling towers at the plant due to its location on a small marine terrace sandwiched between the shoreline cliffs and the adjacent steep landsli de-prone hillsides. Every potential location for the cooling towers results in significant disadvantages or insurmountable obstacles.

Enercon concludes that mechanical draft cool ing towers utilizing seawater as makeup are the only potential option. Enercon further conc ludes that the only viable mechanical draft cooling towers would consis t of nonplume-abated rectangular bank cooling towers. Plume abated cooling towers cannot be instal led in any workable configuration at the facility due to size/t opographic constraints.

Ideally, from a piping layout viewpoint, it w ould be desirable to pl ace the Unit 1 cooling towers to the northwest of the power block, and the Unit 2 cooling towers to the southeast of the power block. However, the area north of the plant is unavailable for several reasons including its classification as a sens itive archeological site incorporating an extensive Native American (Central Coast Chumash) ancestral burial ground. The Diablo Creek and associated established ripa rian habitat is also located between the existing power plant and all no rthern areas. The creek environment would have to be extensively disrupted and developed to acco mmodate substantial northward construction for any plant systems. Additionally, such a location would be undesirable from a salt drift viewpoint, since prevailing winds from the northwest would maximize the salt drift on the plant and the associated 500 kV and 230 kV transmission lines.6 of 59

March 2009 Figure 1 – Diablo Canyon Site

Consideration was given to lo cating the cooling towers alongside the entrance road south of the plant. This has proved unworkable due to the steep terrain of the surrounding hills which would require substantial excava tion and retaining wa ll construction. Additionally, this area is fairly narrow, and placing the cooling towers too close to the ocean is undesirable due to the instability of the soil and the potential for future landslides. The great distance of the cooling towers at this location from the power block would also mean much greater frictiona l losses in pumping, driving up power requirements. Although locating the cooling towers in this area would have the least impact on existing facilities, it has been ruled out due to the reasons cited above.7 of 59

March 2009 Figure 2 – Topographic Map of Site Showing Steep Terrain and Limited Area for Cooling Towers

Other areas for the cooling towers considered were in the vicinity of Warehouse “B” and parking lot #1 as well as to the east of the plan t. Again, the steep hillsides to the east and

unstable soils to the west ruled out these areas. Another disadvantage of a site east of the plant would be to increase the salt buildup on the transmi ssion lines and switchyard. Additionally, locating the cooling towers at a height significantly higher than the

elevation of the condensers ra ises the condenser waterbox op erating pressure due to the higher static head from the cooling tower rise rs, as well as increasing the nuclear safety related flooding hazard in the turbine building due to the cooling tower supply lines draining backwards into the bui lding via a failed waterbox.

The only possible remaining site for the cooli ng towers was determined to be in the area including the main warehouse, cold machin e shop, hazardous materials building, fire station, parking lots 6, 7 and 8, engineer ing office buildings 201 and 202, and a dozen smaller buildings (Figure 3). All of these faci lities would need to be relocated with great impact on the administration and operation of the facility. The Independent Spent Fuel Storage Installation (ISFSI) ha ul road would require rero uting due to the excavation requirements for the cooling towers, sendi ng the proposed route through the security firing range, necessitating its relocation as well. All four cooling to wer arrays would be placed at an elevation of approximately 85’ to 90’, requiring a significant excavation

effort as described elsewhere in this report. It is critical to place the cooling tower basins

at these elevations in order to minimize the nuclear safety related threat of flooding, as well as to reduce overall pumping costs a nd excessive pressure s in the condenser

waterboxes.8 of 59

March 2009 As in the previous studies, a natural draft design for the c ooling towers was eliminated

from consideration because of seismic a nd other concerns. Likewise, circular arrangement mechanical draft cooling towers were eliminated from consideration due to

the lack of sufficient suitable land due to the narrow site layout.

Figure 3 – Cooling Tower Location (Displaced Facilities in Red) (SK-C-11 Rev. 0)

Based on the above evaluation, and discussions with a cooling towe r supplier as to the best size, number, and configuration of cells to fit the available space, the conceptual design for each unit consists of two rectilinear arrays of mechanical draft cooling towers, 20 cells per array, arranged in two rows (side-by-side) of 10 cells each. This configuration is called “back-to-back”, havi ng hot water risers coming from the outboard side of each cell, and air coming in from the outboard side of each cell. This configuration is less desirabl e than a circular arrangement where cooling air can enter from inside and outside the cells, but such a configuration was ruled out at DCPP because

of the lack of suitable land. The 2-Unit DCPP configuration would thus consist of 4 rectangular collections of 20 cells, having a footprint of 140’ by 620’ each. For each unit, a pump suction pit for the circulating wa ter pumps would be loca ted at the north end

of the two 20 cell assemblies to take suction from the cooling tower basins (Figure 6). The cooling towers proposed are based on an approach of 17 o F, with a cost estimate provided by Marley, a well known supplier.9 of 59

March 2009 Figure 4 – 50,000 Sq Ft Warehouse that Wo uld Require Demolition and Relocation

Figure 5 – Cross Section Showing Required Excavation

2. Conceptual Design Summary

Each unit would be retrofitted with two nonplume-abated rectangular configured mechanical draft cooling tower arrays. Each cooling tower would be arranged in a backto-back array, 2 cells wide by 10 cells long.

Each operating unit’s two existing 50% capac ity circulating water pumps would be replaced with five 25% capacity circulating water pumps (10 total for 2 units) located in a new pump pit adjacent to the cooling towers. The use of five 25% capacity circulating water pumps (4 plus 1 installed spare) is a typical and commercially prudent and cost effective configuration that effectively eliminates downtime due to pump/motor failure or maintenance, and eliminates plant load reductio ns in the event of a single pump trip. The pumps would discharge into two new 10 ft square buried conduits carrying the cooling

water to the west side of the turbine bu ilding where they would transition into the existing conduits on the way to the main c ondensers (reference SK-M-1 and SK-C-12). Likewise, the cooling flow exiting the conde nsers would utilize the existing conduits10 of 59

March 2009 until it reaches the west side of turbine bu ilding where it would transition into the proposed 10 ft square conduits retu rning to the coo ling towers.

Figure 6 – Proposed Circulating Water Pump Pit (SK-C-8)

Three new 50% capacity makeup water pumps per unit (6 total fo r 2 units) would be installed in the intake structure near the pr esent location of the existing circulating water pumps and intake coolers (which would be removed should the plant be retrofitted with cooling towers). The pumps would disc harge into a 48” paralined steel common discharge header which would be routed up through one of th e to be abandoned concrete tunnels going to the tu rbine building, and on to the two circulating water conduits going

to the main condensers.

The present Service Cooling Water (SCW) h eat exchangers are cooled by the existing once-through circulating water. As discusse d below, the warmer cooling water from the cooling towers would be too warm, necessi tating replacement of the two SCW heat exchangers per unit, and many of the components cooled by the SCW system. To avoid the need for this replacement and th e associated significant additional cost s , the SCW heat exchangers would be c ooled by their own once-through cooling system. Three new 50% SCW seawater supply pumps per unit, loca ted at the existing intake structure, would provide this cooling water for the system h eat exchangers. In a ddition to providing an installed spare, the third 50% capacity pump would be operated to supply dilution flow for the cooling tower blowdown when needed during times of high wet bulb temperature to meet the anticipated facility effluent thermal limit of 20 F ° above ambient.

The present Condensate Cooler in each unit is cooled by a side stream off the oncethrough circulating water, and is used when needed to reduce the main condensate temperature and thereby provide additiona l cooling for the main generator hydrogen

cooler and stator cooler. The need for th is “extra” cooling would increase since the condenser backpressure, and thus the condens ate temperature, would increase with the use of closed loop cooling towers. The warm er water from the cooling towers would be insufficient to provide the required cooling. Therefore, a side stream off the proposed SCW seawater supply pumps would be used to cool the Condensate Coolers.11 of 59

March 2009 The present once-through coo ling for the safety related ASW system would remain a once-through system by necessity , and continue to use exis ting dedicated intake pumps and ocean water supply. Warmer cooling towe r circulating water would be insufficient to provide the necessary cooling required for the existing plant Component Cooling Water (CCW) heat exchangers that are vital equipmen t in an installed critical nuclear safety system. Retrofit of this plant system to function within acceptable Nuclear Operating License parameters with closed-cycle cooling is infeasible.



### Flow From Ocean
Flow (gpm) Description Existing Cooling Towers
Condenser Cooling (gpm) 860,000 0
ASW System (gpm) 11,500 11,500
Service Cooling Water HX (gpm) 4,300 4,300
Condensate Cooler (gpm) n/a 2,000

Cooling Tower Makeup n/a 37,800
Blowdown Dilution ( ∆ T Control) n/a 6,400 *
Seawater Reverse Osmosis System 500 500
Total (gpm) 876,300 62,500
Percent of Existing Flow - 7.1%



### Discharge To Ocean
Flow (gpm) Description Existing Cooling Towers
Condenser Cooling (gpm) 860,000 0
ASW System (gpm) 11,500 11,500
Service Cooling Water HX (gpm) 4,300 4,300
Condensate Cooler (gpm) n/a 2,000
Cooling Tower Blowdown n/a 25,200
Blowdown Dilution ( ∆ T Control) n/a 6,400 *
Seawater Reverse Osmosis System 240 240
Total (gpm) 876,040 49,640
Percent of Existing Flow - 5.7%

* When needed for blowdown temperature dilution (~ 25% of the time)

Table 2: Projected Average Flow to/from Ocean (per Unit)

Both the SCW system supply and cooling to wer makeup seawater lines would require periodic chemical treatment (concentrated chlorination or chlorine/bromine treatment) to control pipeline biofouling. The ASW inle t flow is required to be continuously chlorinated to protect the vital function of the system. It would be necessary to continuously dechlorinate the effluent of th e ASW system, and most likely dechlorinate12 of 59

March 2009 SCW system effluent during chemical treatment, since the present ability to dilute these streams prior to discharge using the high volume main condenser once-through cooling water flow would no longer be possible.

Each unit would require a steady state cooli ng tower circulating system blowdown flow of approximately 25,200 gpm when running at full load. The concentration of the circulating water would be 1.5x normal seaw ater. Thus the blowdown would have a concentration of about 52,500 ppm total di ssolved solids (TDS) given an average seawater concentration of 35, 000 ppm TDS. The blowdown stream is toxic to marine life due to the higher salt concentration. Therefor e, it would either have to be rapidly mixed with the ambient seawater as it is introduced into the ocean, or it would have to be treated prior to discharge to reduce its TDS concentratio n back to that of seawater. As discussed elsewhere, treatment of this quantity of blowdown is not practical. It has been determined that the most practical means of disposal for cooling tower blowdown is discharge to an array of diffuser nozzles placed on the ocean floor offshore of the facility. The proposed location for a diffuser system is south of the existing power plant near Patton Cove. Routing high salinity coo ling tower blowdown to the existing plant outfall located on the shoreline at Diablo Cove cannot be permitted, nor is it an optimal configuration for efficien t cooling tower operation.

The tube side of the main condensers (water boxes) are designed for 25 psig. Due to the height and location of the c ooling towers, the new pressure in the waterboxes would be on the order of 45 psig, necessita ting strengthening or replacement of the waterboxes. In addition, the existing rolled tube-to-tubesheet joints in each condenser are presently susceptible to saltwater leaks. Leaks into th e condensate system can lead to damage of the safety related steam gene rators and/or unplanned plant shutdowns. An increase in condenser waterbox pressure would signifi cantly increase leakage and associated

chloride intrusion into the secondary system. Therefore, the condenser waterbox and tubes would be replaced with modular welded tube-to-tubesheet units.

Mechanical draft cooling towers have consid erably more power requirements than the existing once-through cooling system. This additional power is primarily for the mechanical draft fans required for the towe r cells. At 300 horsepower (hp) each, about 12 MVA per unit are needed at an assumed power factor of 0.88. Other new power required for the cooling tower installation would be the makeup water pumps drawing about 2,700 kVA per unit. Also, each unit woul d require a seawater supply to the SCW system, requiring another 170 kVA. The new circulating water pumps would have higher head requirements than the existing circul ating water pumps, resulting in an increase power requirement of 2.5 MVA. The various existing auxiliary transformers at Diablo Canyon do not have sufficient capacity to pr ovide the additional loads to power the cooling tower fans and other auxiliaries. Therefore, a new bay with circuit breakers, disconnects, and transformers would be added at the 500 kV switchyard with additional

transformers and other electri cal equipment added downstrea m to serve the new loads.

The existing sewage treatment system would most likely need to be upgraded to meet more stringent effluent limits. The hi gh volume circulating water system would no13 of 59

March 2009 longer be available to dilute the treated sewage effluent st ream. A new packaged system would be sized for 50,000-gpd, and would cons ist of a flow equalization tank, aeration tank, clarifier, clearwell, pr essurized multimedia filtration system, anoxic tank for nitrate reduction, and a UV light system for disinfectio n. The effluent could be treated by the proposed system to have 10 mg/L of biol ogical oxygen demand (BOD), 10 mg/L of total suspended solids (TSS), 5 mg/L of total nitrog en, and 1 mg/L of ammonia. The Seawater Reverse Osmosis Unit (SWRO) brine reject and filter backwash effluent would be

directed to the tower blowdown di ffuser system due to high salinity.

3. Reduction in Electrical Output with Cooling Towers

Replacing the once-through cooling system usi ng saltwater cooling towers would result in a higher backpressure in the main conde nsers because the cooling water temperature entering the condensers would be greater than the present once-through ocean water temperature. For purposes of this study, hourly wet bulb temperatures for the years 2003 through 2007 were taken from the National Weather Service (NWS) Station at the San Luis Obispo (SLO) Airport. This data was considered the most accurate of available local data, and therefore most appropriate for use in this study. Accurate Diablo Canyon site specific data for humidity or wet bulb te mperature was not available. The airport weather station data gives lower wet bulb temp eratures (due to drier inland conditions) than would actually be experienced at the Di ablo Canyon site. The lower wet bulb values cause a reduced estimate of plume size, a nd a lower prediction of circulating water temperatures. Thus the conservative bias introduced by use of SLO rather than site specific coastline data results in smaller predicted plumes, and a decrease in the predicted loss of plant electrical output.

The once-through ocean cooling water as measured at the intake structure has an average inlet temperature of 53.9oF, with a standard deviation of 2.5 o F. The average wet bulb temperature is 52.0oF, with a standard deviation of 6.8 o F. With the cooling tower approach of 17 o F, it is seen that with cooling towers in service the circulating water entering the condensers would be 69.0oF, on average. When compared with the oncethrough cooling water inlet temperature of 53. 9oF, this amounts to an increase of 15.1 o F on average for condenser inlet cooling water temperatures when using cooling towers.

The turbine exhaust pressure was determined using standard Heat Exchange Institute (HEI) condenser backpressure calcula tion methodology utilizing the DCPP turbine performance test data to determine the asso ciated cleanliness factor. The DCPP Turbine (Alstom) Thermal Kit backpressure correction curve was then used to determine the effect on generator electrica l output. (Note: The origin al Westinghouse low pressure turbine rotors were replaced with Alstom rotors in 2005 & 2006.)14 of 59

March 2009 Figure 7 – Decrease in Generator Output (per Unit)

The average yearly loss in generator output due to the proposed cooling tower retrofit project (including an optimized condenser) ba sed on a 90% capacity factor (both pre and assumed post cooling tower retrofit) woul d be approximately 204,000 Megawatt Hours (MWHr) for Units 1 & 2 combined. When considering the additional loads required for the cooling tower fans and pumps, the total de crease in plant electr ical output would be approximately 451,000 MWHr/yr. The average d ecrease in generator output with retrofit cooling towers and an optimized condenser would be 12.9 MW per unit (25.8 MW for 2

- units). As can be seen in Figure 7, the change in Megawatts would vary from an increase of approximately 21 MW per unit to a loss of approximately 69 MW per unit depending on the corresponding wet bulb and ocean water temperatures. The gain in MW during certain temperature conditions is due to the proposed replacement of the condenser tube bundles with new optimized bundles. Unfortunately, as can be seen in Figure 7, the greatest loss in generator output would be at the time of peak summer electric demand.

Description MW/Unit MW/2-Units MWHr/year*
Circulating Water Pumps ∆ MW 2.2 4.4 36,810 Makeup Water Pumps 2.4 4.8 40,157 Cooling Tower Fans 10.0 20.0 167,320 SCW Seawater Supply Pumps 0.2 0.4 3,346 Average Lost Generation 12.9 25.8 203,547
Net Loss in Plant Output 27.7 55.4 451,180
* 2-Units - Based on a 90% Capacity Factor & 25-Day Refueling Outages.

Table 3: Reduction in Plant Electrical Output

Without optimized condensers, the average 2- unit decrease in gene rator output with retrofit cooling towers would be 59.8 MW (versus 25.8 MW with optimized condensers) with an average yearly gene rator loss of approximately 471,700 MWHr, and a net loss in15 of 59

March 2009 plant output of 719,000 MWHr (versus 451,200 MWHr with installation of new optimized condensers).

For purposes of this study and associated co st estimates, it has been assumed that the plant capacity factor after the cooling towe r installation would be identical to the precooling tower capacity factor (approximatel y 90% including refueling outages). In reality, the capacity factor would likely be re duced due to the increased complexity of a saltwater tower cooling system, the corrosi ve effects on plant equipment due to salt deposition from the tower drift, and the potenti al for tripping of the 500 kV lines due to flash-over from excessive salt deposition.

IV. Construction and Engineering Assessment

1. Relocation and Excavation

A. Relocation of Existing Facilities

In order to adequately site the cooling towe rs, many existing facilities would need to be relocated, either onsite to a less conven ient location or offsite to the surrounding community. These include parking lots 6, 7 and 8, with some 1,000 parking spots, and the main warehouse building. The cold machine shop (CMS) is presently located inside the security protected area boundary in close proximity to the power block which provides significant convenience. With the cold machine shop relo cated outside of the protected area boundary, this conv enience and efficiency would be lost. An even greater loss of convenience and efficiency would a pply to the main warehouse which would be relocated 50% onsite but outside of the protecte d area and 50% offsite. Facilities such as the security firing range, desi gn engineering offices, record st orage, etc., would have to be relocated entirely offsite adding consider able cost and inconvenience. The following table is a list of buildings and facilities that would require relocation and/or demolition.

Buildings/Facilities that Would Require Relocation and/or Demolition

Blg # Description Impact Relocate Onsite or

Offsite? Existing Sq Ft Required Sq Ft

Onsite Offsite

115 Main Warehouse Demo &

Relocate Part Onsite & Part

Offsite 50,000 25,000 25,000

116 Cold Machine Shop (CMS) Demo &

Relocate Onsite 15,000 15,000 0

506 Radwaste Offices Demo &

Relocate Onsite 1,000 1,000 0

508 (near cold machine shop) Demo &

Relocate Onsite 1,000 1,000 0

127 Haz Materials

Warehouse Demo &

Relocate Onsite 4,000 4,000 0

201 Design Engineering

Offices Demo &

Relocate Part Onsite & Part

Offsite 12,000 6,000 6,000

202 Design Engineering

Offices Demo &

Relocate Part Onsite & Part

Offsite 4,000 2,000 2,000

220 Design Engineering

Offices Demo &

Relocate Part Onsite & Part

Offsite 1,000 500 500
Buildings/Facilities that Would Require Relocation and/or Demolition (cont.)16 of 59

March 2009 Blg # Description Impact Relocate Onsite or

Offsite? Existing Sq Ft Required Sq Ft

Onsite Offsite

248 Outage Human

Resources Demo &

Relocate Part Onsite & Part

Offsite 1,000 500 500

250 Project Offices Demo &

Relocate Part Onsite & Part

Offsite 3,000 1,500 1,500

252 Project Offices Demo &

Relocate Part Onsite & Part

Offsite 3,000 1,500 1,500

217 Restrooms Demo &

Relocate Onsite 500 500 0

253 Offices Demo &

Relocate Part Onsite & Part

Offsite 500 250 250

260 Security/Records Storage Demo &

Relocate Part Onsite & Part

Offsite 2,000 1,000 1,000

261 Records Storage/

Offices Demo &

Relocate Part Onsite & Part

Offsite 2,000 1,000 1,000

262 Telecom/Project

Offices Demo &

Relocate Part Onsite & Part

Offsite 2,000 1,000 1,000

263 Training Facility Demo &

Relocate Part Onsite & Part

Offsite 2,000 1,000 1,000

264 Building Services Demo &

Relocate Part Onsite & Part

Offsite 2,000 1,000 1,000

251 Fire House Demo &

Relocate Onsite 3,000 3,000 0

254 Storage Facility Demo Neither - Eliminate 8,000 0 0

255 Storage Facility Demo Neither - Eliminate 8,000 0 0

114 Firing Range Demo &

Relocate Offsite 3,000 0 3,000

114A Security Training Demo &

Relocate Offsite 500 0 500

114B Security Training Demo &

Relocate Offsite 500 0 500

113 Warehouse B Demo Neither - Eliminate 18,000 0 0

120 Hazardous Waste Demo &

Relocate Onsite 3,000 3,000 0

125 Fire Water Tank/ Pump House Demo &

Relocate Onsite 2,000 2,000 0

124 Sewage Treatment

Plant Demo &

Relocate Onsite 1,000 2,000 -

165 Biology
Offices/Career Ctr Demo Neither - Eliminate 2,000 0 0

160 Biology Laboratory Demo Neither - Eliminate 4,000 0 0

110 Blast and Paint Facility Demo Neither * 3,000 0 0

122 GC Fab Shop Demo Neither * 8,000 0 0

n/a Vehicle Inspection

Station Demo &

Relocate Onsite 1,000 1,000 0

n/a Parking Garage I New Onsite - 180,000 -
n/a Parking Garage II New Onsite - 320,000 -

Total Square Feet 171, 000 574,750 46,250

* The Blast & Paint Facility and the GC Fab Shop would be incorporated in the new CMS. Table 4: Buildings/Facilities that Would Require Relocation and/or Demolition17 of 59

March 2009 Figure 8 – Displaced Facilities

Figure 9 – Revised Site Layout18 of 59

March 2009 B. Relocation of ISFSI Haul Road

Location of the cooling towers would make it necessary to reroute th e existing ISFSI haul road and re-engineer the subgrade for the anticip ated loads. In particular, the new road would need to pass to the west of the cooling towers, just east of the Simulator Building and the Maintenance Training Building. Ben eath the road would be the new circulating water concrete tunnels, each having an internal cross section of approximately 10’ x 10’,

with reinforced concrete walls 3 feet thick. This dimension was selected in order to be able to fit all 8 tunnels (4 supply and 4 retu rn) for both units alongsid e each other as they approach the western side of the turbine build ing. Because of the location of the cooling towers with respect to the c ondensers, the tunnels would have to cross over each other in certain areas, meaning deeper excavation. Th e tunnels would have to be engineered for the excessive loads anticipated on the road above them, not only due to the ISFSI casks but also due to normal operational/maintenan ce loads, as well as outage-related loads.

The revised ISFSI haul road would need to avoid the zones where the potential for landslides will exist for 75 years after the installation. This setback requirement originates from the California Coastal Commissi on, and is necessary in order to obtain a building permit from San Luis Obispo County. The potential for future landslides exists

at the location of the exis ting access road near Warehous e “B” and parking lot #1.

California Coastal Commission rules do not allow for reinforcement of the littoral area

around landslides in order to reduce the like lihood of future landslides. These points

would need to be taken into account when finalizing the new ISFSI haul road.

C. Civil Site Work

Siting the cooling towers to the southeast of the turbine buildi ng would necessitate

massive excavation of the hillside to the east of the cooling towers. All four separate

tower basins would be excavated to a base elevation of 85’ to 90’. The excavations would leave slopes of 2 to 1 (tangent = 0.5). Although choosing a higher slope would

reduce the amount of excavated fill to be re moved, the higher slope would be hazardous for personnel. On the west side of the co oling towers some excavation and relocation

work for the access/ISFSI haul road would be necessary (Reference Sketches SK-C-1, 2, & 3).

The volume of excavated soil and rock has b een estimated at 2,011,000 bank cubic yards.

This material would need to be trucked to an offsite disposal f acility, requiring roughly 200,000 truckloads. The total amount of soil a nd rock includes an estimate that 52% is rock, based on review of the geological info rmation in the ISFSI Final Safety Analysis Report (FSAR) Update.19 of 59

March 2009 2. Constructability of Interconnecting Piping

Figure 10 schematically shows the existing circulating water conduits to the main

condensers. Connections would have to be made to all the supply and return conduits including those coming from the north end of the Unit 1 condensers. Review of detailed site drawings clearly shows that the excav ations and routing required for these large diameter connections would quickly become an extremely complex engineering and

construction task.

1-1 NW 1-2 NE

1-1 SW 1-2 SE

2-2 NW 2-2 SW 2-1 SE 2-1 NE Unit 1 Unit 2

ASW Pumps Circ. Water Pumps

Demusseling Gates

Traveling Screens

Dewatering Gates

Bar Racks

Intake Structure Discharge Structure Weir (Blending) Cutouts (Crossflow) Discharge Throttle Gates

Figure 10 – Existing Circulating Water Conduits

Figure 11 – Original Circulating Wat er Tunnel Excavation & Construction20 of 59

March 2009 The limited area for this intertie in front of the turbine building is extremely congested with both safety related and nonsafety related systems, pipi ng, and conduits as shown in Figure 12.

Figure 12 – Existing Underground Utilities West of Turbine Building

Constructing the large diameter concrete tunne ls with the associated excavation in this area would result in the disruption of numerous systems that would have to be relocated to accomplish this construction. The safety re lated ASW system bisects this area, and is required to remain in operation even with both units shut down. The difficulty, time, and cost associated with these excavations, tie-i ns, and system interferences are immense. The development of the details of this as pect of the retrofit would likewise be an

immense task.

Those utilities which are buried in the vicin ity of the proposed tunnel excavations, which would require temporary protection and/or relocation during constr uction and/or final relocation upon construction completi on, include but are not limited to:

Seawater Reverse Osmosis Li nes I&C Conduits & Pull Boxes Telephone Communications Aux Sa ltwater Vacuum Breaker Lines Microwave Communications Building Roof Drains Security Systems (undefined) Storm Drains Potable Water Piping Yard Fire Loop & Branch Lines Sewage Lines & Septic Tanks Instrument Air & Service Air Electrical Conduits & Pull Boxes Outdoor Lighting Fiber Optic Cables Electrical Grounding Cable 12 kV Power Cables Auxiliary Saltwater Lines (ASW)21 of 59

March 2009 3. Modifications to Existing Systems and Required New Systems

A. Condenser Modifications

The present condenser has a history of t ube leaks which would be made worse by significantly increasing the water box pressures. The present condensers have 2 to 3% of their tubes plugged due to leakage. Increased tube leaks would have an adverse impact on the operation of the condensate polishers and potentially an adverse impact on transient feedwater and main steam chemistry. Secondary side water chemistry is an important aspect of nuclear safety due to potential degrada tion of steam generators and main turbines (missile generation) and potential plant trips. Plant trips due to chemistry excursions unnecessarily exercise plant safety systems. Transient departures from water and steam chemistry limits would, as a minimum, impact the steam generator and main

turbine warranties.

The tube side of the existing main condensers (tubes, waterboxes, and transition pieces) is designed for 25 psig. Due to the height and location of the cooling towers, the new pressure in the waterbox would be on the or der of 45 psig, necessitating strengthening or replacement of the waterbox. Additionally, as noted previously in th is report, the rolled tube-to-tubesheet joints in the installed conde nsers are currently sus ceptible to saltwater leaks into the condensate system (which can lead to damage of the safety related steam generators and/or unplanned unit shutdowns ). The increase in condenser waterbox pressure would increase leakage. Because of these current design limitations and the high probability of significantly increased chloride salts intrusion associated with elevated system pressures, the condenser waterboxes and tubes would be replaced by necessity with modular welded tube-to tube sheet units. The transitions from the buried conduits to the waterboxes would also be upgraded to withstand the increase in pressure.

In order to optimize the performance of th e new bundles and thereby minimize the lost generation due to hotter inlet cooling wa ter, the proposed tube bundles would be composed of 3⁄4” diameter titanium tubes (c ompared to the present 1” diameter tubes) resulting in increased total tube surface area.

Installation of the new condenser tube bundles would be a major undertaking. In order to provide access for the new bundles, existing equipment and large structural members

would have to be removed and then reinstalle d. The lower end of the large transition pieces from the waterboxes to the underground conduits are imbedded in the turbine building floor concrete, necessitating c oncrete excavation and replacement.22 of 59

March 2009 B. Service Cooling Water Seawater Supply

Inside the turbine building the circulating water presently cools not only the main condensers but also the SCW heat exchangers and the condensate cooler for the main generator hydrogen coolers (to maintain ge nerator gas temperature within limits).

The increase of cooling water temperat ure to 17°F above the highest wet bulb temperatures (as well as the increase in pr essure) would necessitate replacement of both the SCW heat exchangers and the condensate cooler for each unit, and many of the components cooled by the SCW system.

The SCW system removes heat from various secondary system components via a closed loop cooling cycle and rejects the heat to the main circulating water system. The closed loop SCW system presently runs with a typica l cold end temperature on the order of 79°F (e.g. 54°F on average seawater in let flow cools the service c ooling water to 79°F). Even if the existing heat exchangers were replaced with much larger heat exchangers, it would not be possible to cool the SCW to 79°F us ing the warmer circulating water from the cooling towers during periods of highest wet bulb temperature.

The heat loads cooled by the SCW system include:

• Main Feed Pumps Turbine Lube Oil Coolers

• Condensate Booster Pumps Lube Oil Coolers

• Generator Exciter

• Fuse Wheel

• Generator Seal Oil Coolers

• Iso-Phase Bus Coolers

• Main Turbine Reservoi r Lube Oil Coolers

• Post LOCA Sampling System Room Ai r Conditioning and Sample Panel Chiller

• Plant Air Compressors 05 and 06 (via the SCW Booster Pumps)

• Reciprocating Air Compressor Jack et Coolers and Aftercoolers

• Air System Air Dryers

• TSC Air Conditioning Units

• Personnel Access Control Room Air Conditioning Unit

• Operations Ready Room Air Conditioning Unit

• Condenser Vacuum Pump Seal Water Heat Exchanger

• Electro-Hydraulic Control Coolers

• Feedwater Sample Cooler 72

• #2 Heater Drain Pump Lube Oil Coolers and Sample Cooler

• Secondary Process Control Room Isothermal Bath Water Chiller

In addition to replacement of the SCW heat exchangers themselves, many of the above components cooled by the system would requ ire modification or replacement due to the higher SCW closed loop circulat ing cooling water temperatures. To avoid the need for these extensive plant equipm ent upgrades, the existing SCW heat exchangers would be cooled by their own once-through cooling syst em. Therefore, for each unit, three new23 of 59

March 2009 50% SCW seawater supply pumps (6 total) sized at 3,150 gpm at 86’ total differential head (TDH) would be provided. They would draw water from the intake structure and the cooling flow would be routed in new 20” paralined steel pipes up to the turbine building. The new 20” lines must be routed through an already congested area surrounding the main condensers to the SCW heat exchangers located on the east side of the turbine building. A branch to the conde nsate coolers would be provided even though the equipment is infrequently used at present for either unit. This routing would replace routing which presently consists of short runs from near the main condenser intake lines embedded in concrete below the 85’ (ground) level. The new piping would not be embedded in the concrete, and would therefor e invariably have a negative impact on operating and maintenance activities in the vicinity.

To minimize biofouling, it would be necessa ry to chlorinate the SCW seawater supply lines. The sodium hypochlorite injection syst em used for the existing main circulating water system would be used for this purpose.

C. Main Circulating Water Pumps

The proposed cooling systems new main circ ulating water pumps would be 25% capacity each, with one installed spare per unit. They would be rated at 215,000 gpm at 110’ TDH. The motor size would be 7,600 hp and w ould operate at 327 rpm. The five pumps

would be vertical turbine conf iguration, arranged in a row, taking suction from the pump pit which is adjacent to the cooling towers . The pumps would discharge into a common 8’ diameter paralined steel circular cross sect ion manifold with valv es on either side of the middle pump’s tee into the manifold. This would allow any 4 of the 5 pumps to be operated. At either end of the manifold, a transition is made into a 10’ by 10’ square

cross section reinforced concrete tunnel. Th ese two tunnels are dir ected side-by-side and transition into the existing 11’-9” square conc rete tunnels which lead to each unit’s main condensers. With this configuration, simila r to the existing configuration, the plant may be operated at 50% capacity while one side of each main condenser is taken out of service. Unlike the present configuration w ithout a spare, the spar e pump would be able to serve either supply tunnel in the event of another pump’s failure.

Each pump’s capacity of 215,000 gpm would me an a sudden reduction of flow whenever that pump is taken out of service. This coul d give rise to pressure fluctuations, known as “water hammer”, with possible destructive result s. Thus, studies of the effects of water hammer would be recommended, in order to mitigate its detrimental effects. Another characteristic of the closed cooling tower loop being considered is the fact that upon shutdown of the circulating water pumps, so me water would flow backward from the high points in the condenser waterboxes (elevation of ~104’) and the cooling tower hot side distribution piping (elevation ~125’) into the cooling tower basin / pump pit. The basin and pit combined capacity would be sized to accommodate this overflow, which would be routed to the ocean through the weirs discharging to the system blowdown

lines.24 of 59

March 2009 D. Circulating Water System Piping

Piping conforming to Piping Specification “G” woul d be utilized. This is steel pipe with an internal coating called “paralining”. It has provided excellent service for existing Diablo Canyon seawater applications such as the ASW system, and is suitable for the proposed circulating water system. Concrete coated steel pipe is inferior because of minute cracks in the concrete lining allowing chloride migration to the underlying steel with subsequent destructive corrosion.

Although Specification “G” includes pipe up to a maximum diameter of 24”, the company that provided the pipe in the past, Ba rber-Webb, has indicate d that pipe up to 8’ diameter can be paralined. The coating must be applied under controlled conditions in the factory. This means it would need to be flanged as opposed to welded in the field since the coating cannot be applied reliably in the field. Sections up to 40’ in length can be shipped to the jobsite. Paralined pipe would be used for the makeup water supply, cooling tower blowdown, and the SCW seawater supply. Additionally, the discharge of each of the circulating water pumps would be a paralined 78” diameter steel pipe (Reference Sketches SK-C-12 to 16). The common discharge line that all five pumps connect to would be an 8’ paralined pipe.

For the long sections of buried circulating water conduit to and from the cooling towers, concrete-walled tunnels are spec ified. Conveying 50% of the total flow, they would be a 10’ by 10’ square cross section with 12” 45° f illets at the corners. The walls would be

about 3’ thick with steel reinforcement. Th is configuration and ma terial of construction is consistent with the existing tunnels, a lthough the existing tunnels are larger, with a

cross section of 11’-9”. The new tunnels w ould have a velocity of 9.8 feet per second (fps) vs. 7.0 fps for the existing tunnels, but the increased pressure drop is tolerable. Having the smaller cross section allows for a more compact arrangement, especially to the west of the turbine building where all 8 tunnels (4 supply a nd 4 return) would be buried side-by-side. The new tunnels would be built in place in excav ations prepared for them. In some areas to the west of the turbine building and to the west of the cooling towers, the tunnels would need to cross unde rneath each other, requiring extra deep trenching. This configurat ion cannot be avoided since the proposed cooling towers for both units are on the south side of the plant.

In the area to the west of the turbine build ing the new tunnels would transition into the existing tunnels. At this in terface, a barricade would be cons tructed in the old tunnels to isolate them from the empty sections coming fr om the ocean intake structure and going to the discharge structure. These empty tunnels coming up the hill from the intake structure, specifically lines 1-1 and 2-1, would have the 48” makeup water lines and the 20” SCW system lines routed inside them up to an ar ea near the transition point where they would be routed out of the tunnel on to their respective destinations.25 of 59

March 2009 E. Makeup Water Supply

New makeup water pumps would be installed in the intake structure near the removed circulating water pumps. Each unit would be furnished with thr ee, 50% capacity makeup water pumps sized at 22,500 gpm at 216’ TDH. With two pumps running, a maximum makeup flow of 45,000 gpm can be delivered , providing a margin over the steady-state makeup requirement of 37,800 gpm. The indi vidual pumps would discharge into a 36” paralined steel pipe. The common discha rge header for each unit would be a 48” paralined steel pipe. This pipe would be routed through one of the existing concrete tunnels going to the turbine bui lding that would be abandoned if the plant we re retrofit with cooling towers. The 48” makeup water line would be taken through the tunnel wall near the junction point where the new 10 ft square concrete tunnels coming from the cooling towers joined the existing tunnels. The makeup water line for each unit would then branch into two 36” paralined steel pipes each going to one of the two main circulating water tunn els leading to the main condensers.

F. Chlorination and Dechlorination of Effluent Streams

As mentioned elsewhere in this report, both the service coolin g water supply lines and the makeup water supply lines would be chlorinate d to control pipeline marine biofouling. The ASW stream is also continuously chlorinate d. It would be necessary to dechlorinate both the ASW and SCW systems downstream of th e heat exchangers since the ability to

dilute with main condenser flow would no longer be possible.

The existing site dechlorination system utilizes aqueous sodium bisulfite injected into the condenser discharges. This system is cu rrently installed to service only the main condensers periodically, and would require significant modification to service other effluent streams directly, as well as operate on a continuous basis. For a combined flow of 16,000 gpm per unit (ASW and the SCW s eawater supply) approximately 61 gallons

of commercial bulk sodium bisulfite woul d be required each day to adequately

dechlorinate. This would result in additio nal annual chemical supply costs of $150,000.

The estimate is based on an initial residual chlorine level target of 1 part per million (ppm) at system heat exchanger inlets.

The blowdown stream could contain residual ch lorine, however it would be expected in very low concentrations under most circumstan ces. Chlorine would be introduced into the main circulating water system under normal operating conditions by the makeup water supply. However, the treated influent would represent only a small percentage of the systems total circulati ng volume at any given time. System chemical demand, including operation of the cooling towers that would result in extensive exposure of the circulating water to the atmosphere, woul d likely cause rapid reduction of residual biofouling treatment chemicals. It is not an ticipated that routine injection of additional sodium hypochlorite into the cooling tower circulating water woul d be required because the concentration of salts in the system woul d be toxic to most common forms of aquatic

life.26 of 59

March 2009 If excessive organic microfouling of main condenser tube surfaces did occur under certain conditions, periodic oxidant treatment of the cooling tower circulating system may be required. In that event, the blowdown stream could be temporarily isolated until

residual chlorine levels reduced below discha rge limitations, the entire circulating system could be dechlorinated, or the blowdown flow could be directly dechlorinated. Main condenser circulating system effluents shoul d not otherwise require dechlorination.

4. Electrical System Requirements

A. Electrical Design Features

Mechanical draft cooling towers have consid erably more power requirements than the existing once-through cooling system. This addi tional parasitic power is primarily for the mechanical draft fans required for the cells . At 300 hp each, about 12 MVA per unit are needed at an assumed power factor of 0.88. Other new power required for the cooling tower installation would be the makeup water pumps drawing about 2,700 kVA per unit. Also, each unit would require a seawater supply to the service cooling water system, requiring another 170 kVA.

The new circulating water pumps would repl ace the existing circulating water pumps

which would be abandoned and removed from th e intake structure. The new circulating water power requirements are roughly equivale nt to the existing requirements but would not be fed from the existing 12 kV buses. Rather, new 13.8 kV power would be brought down from the 500 kV switchyard.

The various existing auxiliary transformers at Diablo Canyon do not have nearly enough margin to provide the additional loads to power the cooling tower fans and other auxiliaries. The most practical and cost effective way to provide the new power requirements has been determined to take power from the outgoing 500 kV transmission lines, one 500 kV line source for Unit 1, the other for Unit 2. A new bay at the 500 kV switchyard would be required to locate each unit’s cooling tower transformer (Reference Sketch SK-E-1). The power sent to these tran sformers would need to be metered in order to make corrections to the power sent out. The voltage would be first reduced from 500 kV to 13.8 kV, with the outgoing 13.8 kV conductors routed down to the cooling tower locations (Reference Sketch SK-C-17). A voltage level of 13.8 kV is selected rather than

12 kV because 13.8 kV is a more standardized high voltage level used in industry. The

500 kV/13.8 kV transformers would be rated at 64 MVA with a power factor of 0.88. At the cooling tower area, the 13.8 kV conductors would be routed to the new circulating water pumps, rated at about 7,600 hp each, five per unit. The other 13.8 kV conductors would be routed to three transformers per uni t, each having a rating of 13.8 kV/4 kV, 5.4 MVA capacity. Individual 4 kV buses would be routed from each of the three transformers into an adjoining electrical eq uipment building where the 4 kV breakers for the 40 cooling tower fan motors would be loca ted. Each unit’s cooling tower electrical building would be approximately 16’W x 160’L x 12’ H, constructed of protected coating steel, and set atop a concrete foundation.27 of 59

March 2009 The new service cooling water supply pumps and makeup water pumps and their transformers and switchgear would be located in the existing intake structure, placed immediately on the upstream (intake bay) side of where the existing circulating water pumps now reside. Power for the makeup water pumps would be 4 kV, from new transformers, one per unit, rated at 12 kV/4 kV with a capacity of 9 MVA each. The service cooling water seawater supply pump motors, at 100 hp nameplate each, would be stepped down to 440V, requiring additional small transformers. The 12 kV input power for the 12 kV/4 kV transformers would come from the existing 12 kV feeds to the abandoned circulating water pumps (Reference Sketch SK-E-2).

B. Instrumentation and Controls

The existing high voltage electrical bus and ci rculating water system controls are via hard wired relay logic. The operator interfaces for these systems consist of hardwired switches, indicators, and annunciator window s on vertical boards VB-5 and VB-4, respectively, in the main control room. Th ere is insufficient space in the main control room to provide similar hardwired operator interfaces for the additional high voltage buses and circulating water system controls . Modern control sy stems reliably utilize touch screen operator interfaces and digital co ntrols. Therefore this approach would be

used.

Refer to Sketch SK-J-3 for a conceptual bl ock diagram of the proposed control system and operator interface. The proposed control system for the new high voltage buses and the circulating water system would be the Tr iconex Tricon digital control system. This highly reliable, triple redundant platform al ready provides the main turbine controls and feed water system controls at DCPP. It has been approved for safety related applications by the NRC, and DCPP intends to use it for sa fety related control and protective systems in future upgrade projects (Note: Electrical protective functions such as over-current protection would be performed by equipment other than the Triconex). The Triconex control hardware (one main chassis, thr ee expansion chassis, and associated field termination panels per unit) would be locate d in the electrical room at the new cooling

tower location. A total of four Triconex cab inets per unit would be anticipated in this

location. There would also be a remote i nput/output (I/O) expansion chassis per unit and associated field termination panels located in the intake structure. A total of two Triconex cabinets per unit are anticipated in this location. Reference Sketch SK-J-4 for a preliminary Triconex I/O list.

Machinery vibration monitoring would be prov ided by four Bently Nevada racks per unit in the cooling tower electrical room and three racks per unit in the intake structure. Three Bently Nevada cabinets are expected to be re quired in the former location and two in the latter per unit. Data would be transmitted to the Triconex control system via data links. Reference Sketch SK-J-5 for a preliminary Bently Nevada I/O list.

Chemistry monitoring and injection controls would be required fo r the new bisulfite injection system. Control would be through the Triconex.28 of 59

March 2009 Interface equipment would be required for a connection to the Cal ISO for monitoring power usage of the new equipment.

The main operator interface would consist of touch screen huma n machine interfaces (HMIs) in the main control room. Sketches SK-J-1 and 2 show that two HMIs would be

installed on the bench board se ction of VB-4. A panel in the cooling tower electrical

room would have two additional HMIs as we ll as backup hardwired control switches and

indications for critical electri cal bus controls. Ex isting annunciator panels in the main control room would be revised to provide alarm windows for the new equipment. Data would be provided to the plant process comput er (PPC) via a data link to the plant data network (PDN). This would allow process data to be displayed on PPC HMIs on the operator control consoles in the main control room.

Communication between the Triconex main chassis and main control room HMIs, between the Triconex main chassis and the remote I/O chassis, and between the Triconex main chassis and the plant data network woul d be via new redundant fiber optic cables. A relatively small number of hardwired ci rcuits would be required from the cooling

tower electrical room to the intake structure or directly to the turbine building. In the former case, it is expected that existing ci rcuits between the intake structure and the turbine building could be reused. In the latter case, the new circuits could be run with the fiber optic cables. I/O circ uits from new equipment to Triconex and Bently Nevada equipment would be hardwired. By lo cating the Triconex I/O chassis near the equipment, circuit lengths would be reduced.

Uninterruptible Power Supplies (UPS) woul d be required for the new Triconex and Bently Nevada equipment. There would be a UPS in the cooling tower electrical equipment room and a UPS in the intake structure for each unit. Operating parameters and alarms would input to the Triconex and this information would be available at the

main control room and HMIs in th e cooling tower el ectrical room.

The control system would provide manual st art and stop capabilities for equipment and, where appropriate, automatic sequenced opera tion of equipment (e.g. cooling tower fans) during startups and shutdowns. Cooling fan starts would be sequenced based on unit load via a signal from the existing main turbine control system (MTCS).

Changes would be required to the existi ng MTCS. A turbine load signal would be needed to the circulating water control system . Existing logic that reduces turbine load upon loss of a circulating water pump would require changes. A turbine trip upon 13.8 kV bus undervoltage may be desirable in a ddition to the existing turbine trip on low vacuum. The existing MTCS cannot accommodate significant additional logic since it is heavily loaded. Changes are expected to be minimal so are not expected to require an upgrade to the MTCS.

Changes to the reactor trip logic are not antici pated but would need to be investigated if this project was to be implemented. If requi red, this could result in changes to the solid29 of 59

March 2009 state protective system (SSPS) inputs and ch anges to significant numbers of plant drawings, documents, and procedures.

V. Nuclear Safety and Licensing

1. Nuclear Safety System Requirements

Retrofitting Diablo Canyon with closed loop cooling towers cr eates several nuclear safety

issues that would have to be addressed. It is most likely that these issues would require Nuclear Regulatory Commission (NRC) revi ew and approval via License Amendment Requests (LARs) to insure an acceptable level of safety. There is a risk that such issues could result in LARs that would not pass th e NRC review and approval process. As noted previously, retrof it of the ASW system to a closed -cycle cooling configuration is not feasible from a Nuclear Safety and Licensi ng perspective. The nuclear safety related

issues include:

• Flooding The condenser cooling water system is a nonsafety related system and is not required for the safe shutdown of the plant. However, flooding caused by failure of the system in the area of the condensers could jeopardize safety related systems located in the turbine building (Emergency Diesel Generators, Component Cooling Water heat excha ngers, safety related conduits and controls). The Diablo Canyon Final Sa fety Analysis Report (FSAR) discusses the possibility of flooding from the cooli ng water system, and the attributes of the system that lessen the ri sk due to flooding. Key to those attributes is the present low pressure in the condenser waterboxes and a circulating water pump trip upon high water in the turb ine building sump. With the present system, after a circulating water pump trip and coastdown, the water in the large conduits would drain by gravity flow back to the ocean and not into the turbine building. Retrofitting the pr esent system with cooling towers adversely changes both these system attr ibutes – the waterbox pressure would approximately double, and after a pump tr ip, large quantities of water in the circulating water pipes ( now at an elevation high er than the condensers) would gravity drain into the turbine bu ilding. This increase in flood risk

would have to be addressed in the FSA R Update and may not be acceptable to the Nuclear Regulatory Commission (NRC).

• Salt Deposition – Increase in Plant Trips As discussed further under “Air Quality – Plume / Salt Drift”, there would be significant salt deposition on the power lin es leaving the plant giving rise to an increase in the frequency of plant tr ips due to “loss of off site power”. Although the plant is designed to safely shut down after such an event, it

would result in an increased reliance on the plant safety systems which increases the plant safety risk, and is a topic of interest to the NRC.30 of 59

March 2009 • Salt Deposition – Accelerated Aging of Plant Equipment Salt deposition from the cooling towers would have the general effect of increasing corrosion, required maintena nce, and frequency of failure of exposed plant equipment. For example, with a southeasterly wind the plume could engulf the safety related Emergenc y Diesel Generator (EDG) ventilation

intakes. This would accelerate the co rrosion problems with the EDG radiators (already a problem with existing sa lty air), and may cause operational problems with the EDG controls. See fu rther discussion under “Air Quality –

Plume / Salt Drift”

• ASW System Interruption The massive and complex construction excavation activities west of the turbine building necessitated by the coo ling tower retrofit would increase the probability of interruption of the safe ty related Auxiliary Saltwater (ASW) cooling system during construction. Even during plant shutdown, the ASW system is required for spent fuel pool cooling. The NRC may prohibit this increased risk of disruption of the sa fety related ASW cooling system, and may require an alternate means of cooling the spent fuel pools.

• Loss of Offsite Power The past plant design basis was to with stand a full load re jection without a reactor trip by running back the turbin e. The plant would remain online powering the house loads off the 25 kV bus . With the recen t replacement of the steam generators, the design basis of the plant has been changed to a 50% load reduction rather than a full load rejection. However, previous plant load rejection controls are still functional, and there are scenarios in which the reactor will not trip a nd the turbine generator wi ll continue to supply house loads (including the reactor coolant pu mps and the circulating water pumps) after both 500 kV breakers open. If c ooling towers were installed, power to the circulating water pumps would no longer be from the 25 kV generator output bus but from the 500 kV system. Similarly, power to the new cooling tower fans would be provided from the 500 kV system. Therefore, unlike the existing system, condenser vacuum would be lost if both 500 kV breakers open. Existing protective systems would result in a turbine low vacuum trip and subsequent reactor trip. It may be necessary for protective logic to be implemented to immediately trip the reactor when both 500 kV breakers open rather than relying on an eventual lo w vacuum turbine trip. This would require changes to the SSPS inputs and changes to significant numbers of plant drawings, documents, and procedur es. Further study of this issue and NRC review and approval would be requi red if the project were implemented.

• ISFSI Haul Road Rerouting Hauling dry casks of spent fuel from the Fuel Handling Building up to the ISFSI storage area has been describe d in the ISFSI FSAR, and has been reviewed/approved by the NRC. The haul road is important to safety and has several requirements including a maximum slope of 8.5%, as well as support of loadings from the dry cask transporter. The present route has avoided31 of 59

March 2009 existing and future landslide-prone areas and has been designed to withstand the effects of a Hosgri Fault earthquake while encumbered with a loaded transporter without the transporter bei ng damaged (tipping over). Therefore, the new routing of this haul road due to the installation of cooling towers and their auxiliaries would require a new de tailed analysis and review/approval by

the NRC.

• Landslide Potential

Certain areas of the site are active landslide zones. The relocation of the ISFSI haul road, as well as the loca tion of the cooling towers and their auxiliaries, would need to be located to avoid areas of anticipated future landslides. This issue would be subject to NRC scrutiny.

• Fire Protection System Interrupt ions During Construction

The NRC would have concerns with the possibility of any compromises to the fire protection system, such as accidenta l damage to the yard fire loop, which could occur during construction. This is a risk since extensive excavation would be required for the cooling towe rs and concrete tunnel construction.

• Security During Construction The massive excavations and disruption s of normal site security boundaries, and the large numbers of construction personnel and equipment crossings of Protected Area (PA) boundaries, would be of concern to the NRC.

2. NRC Licensing

NRC regulations 10 CFR 50.59, 10 CFR 50.90 and 10 CFR Part 51 govern proposed changes to a nuclear plant. These regulat ions specify when prior NRC review and approval of plant changes is n ecessary. As part of a cooling tower retrofit, PG&E would perform a 10 CFR 50.59 evaluation in accordan ce with the guidance provided in Revision 1 of NEI 96-07 and Regulatory Guide 1.187, both dated November 2000. As discussed previously in this report, retrofitting Diab lo Canyon with closed loop cooling towers creates several nuclear safety issues that in accordance with 10 CFR 50.59 would require NRC review and approval via the License Amendment Request (LAR) process (10 CFR 50.90 and 10 CFR Part 51). These issues includ e the increased risk of flooding of safety related equipment, the increased risk of plant trips and accelerated aging of plant equipment due to salt deposition, the rerouting of the ISFSI haul road, and the risk of disruption of the ASW system during construction. There is a significant risk that that the NRC would not be willing to grant a licen se amendment to allow the change in design that creates or increases these nuclear safety issues. Also, the NRC will need to ensure that the National Environmental Policy Act (N EPA) is appropriately implemented for the environmental effects of the proposed cooli ng towers construction and operation. In order to request NRC approval, the final de sign must be completed, applicable State permits issued, and an LAR prepared and subm itted to the NRC. The NRC review period typically takes one year after submittal of the LAR. In addition, it is anticipated that interveners would request NRC hearings. NRC hearings could take two to three additional years.32 of 59

March 2009 3. Security

Retrofitting cooling towers at DCPP would ha ve a major impact on site security. The plant PA boundary would have to be ultimatel y relocated to accommodate the installation of the cooling towers and their auxilia ries. The boundary for this would be approximately in the same area to the south east of the power block, with the cooling towers, circulating water pumps, and the asso ciated electrical buildings being located

outside the PA. The relocated main warehous e would also be located outside the PA.

VI. Environmental Impacts and Permitting

1. Air Quality – Plume / Salt Drift

Significant visible plumes would be generated by cooling towers at DCPP, and would be frequently visible from San Luis Obispo and/ or Avila Beach. The largest plumes would have lengths exceeding 5 miles and heights exceeding 2,500 feet.

Background: When the ambient air is cooler th an the moist cooling tower exhaust air, it cannot absorb all the moisture, and the ex cess moisture in the exhaust air stream condenses creating a visible plume. Unde r certain conditions, a cooling tower plume presents a significant fogging hazard to its surroundings. The water evaporated in the cooling process is "pure" water, in contrast to the drift droplets carried along with the plume. “Drift” is the water droplets that b ecome entrained in the air stream as it passes through the cooling tower. The rate of drift loss is a function of cooling tower design and configuration, airflow rate th rough the cooling tower, and wa ter loading. Drift droplets have the same or greater concentration of impurities as the water entering the cooling

tower. Because the drift c ontains the minerals and chemicals of the makeup water,

contact of these salts and chemicals with plants, building surfaces, and human activity

can be detrimental and/or hazardous. Sedi mentation of drift droplets downwind of the cooling towers would result in an increase in ground le vel concentrations of salt

chemicals.

Due to their size and the limite d space available at DCPP, plume-abated cooling towers could not be located at the plant site. They are larger than the nonplume-abated cooling towers being evaluated in this study, and requi re a significantly larger footprint. The plume-abated cooling towers have a greater height required for the cooling tubes and additional fans for the incoming hot water. For proper operation they also need to have air coming in from both sides ruling out the back-to-back rectilinear arrangement selected for the nonplume-abated cooling towers. The only layout possibilities for plume-abated cooling towers would either be circular or extended rectilinear footprints with a width of only one cell and a length necessary for 40 ce lls (~2,400’). Neither configuration is a possibility given the characteristics of the site discussed elsewhere. The tubes would

have to be titanium for corrosion resistance. The fan power would be about double what33 of 59

March 2009 the nonplume-abated cooling towers consume. The cost for plume-abated cooling towers

is at least 150% of that fo r nonplume-abated cooling towers. In summary, the lack of a suitable location has ruled out plume- abated cooling towers for DCPP.

To determine the environmental impact of cooling towers at DCPP, the seasonal/annual cooling tower impact (SACTI) prediction code was utilized along with the cooling tower design data and local meteorology data. The SACTI software is described by the NRC in Section 5.3.3.1 of Standard Review Plan, NUR EG-1555, as appropriate for this purpose. For purposes of this study it is assumed th at both units are ope rating at 100% power.

As noted previously, accurate Diablo Canyon s ite specific data for humidity or wet bulb temperature is not available. Th erefore, for purposes of this study, hourly wet bulb temperatures for the years 2003 through 2007 were taken from the National Weather Service (NWS) station at the San Luis Obispo (SLO) Airport

. Site specific wind velocity and direction data for DCPP was utilized. The SLO Airport weather station data gives lower wet bulb temperatures (due to drier inland conditions) than would be experienced at the Diablo Canyon site. The use of thes e lower wet bulb values rather than site specific coastline data results in smaller predicted plumes (provides a conservative study bias).

A summary of visible plume lengths that would result from cooling towers at DCPP is presented in Table 5. Plumes gr eater than 1/3 of a mile in length would be present approximately 73% of the time during winter and 60% of the time in the fall. Plumes greater than 2 miles in le ngth would be present approximately 35% of the time during winter and 25% of the time in the fall. In most cases, the plumes tend to lie either towards the northwest ( over the plant itself, especially in the winter) or to the southeast (along the access road from Avila Beach).

Winter Spring Summer Fall Most Frequent Plume Heading

Directions NW,SE SE,ESE,SSE SE,ESE SE,ESE,SSE

Percent of

Plumes < 1/3

miles 26.9 35.0 44.2 40.4

Percent of

Plumes >1/3 to

2 mile 38.5 28.2 30.3 34.8

Percent of

Plumes >2 to 5

miles 30.3 32.8 24.3 22.5

Percent of

Plumes >5

Miles 4.3 4.0 1.3 2.2

Table 5: Visible Plume Length Frequency Summary – Percent34 of 59

March 2009 Table 6 shows the percent of time for various centerline heights of the plumes above the tops of the proposed cooling towers. The hi ghest plumes, like the longest ones shown in Table 5, extend down the coast in the ESE to SSE direction.

<100m (<330 ft) 100 - <500m (330 - 1640 ft) 500-<750m (1640 - 2460 ft) 750 - 810m (2460 - 2700 ft) Total

Percent

S 0.43 0.36 0.71 1.5 3

SSW 0.26 0.39 0.66 1.22 2.53

SW 0.35 0.49 0.86 1.4 3.1

WSW 0.39 0.42 0.67 1.3 2.78

W 0.38 0.4 0.83 1.6 3.21

WNW 0.23 0.78 1 2.55 4.56

NW 0.56 1.89 1.94 4 8.39

NNW 1.24 2.51 1.26 1.93 6.94

N 1.36 1.02 0.62 0.97 3.97

NNE 0.43 0.52 0.3 0.45 1.7

NE 0.36 0.44 0.27 0.37 1.44

ENE 0.43 0.42 0.22 0.31 1.38

E 1.24 0.75 0.49 0.76 3.24

ESE 7.44 2.87 1.29 2.08 13.68

SE 13.81 3.34 3.8 9.75 30.7

SSE 1.44 0.71 1.87 5.36 9.38

All 30.35 17.31 16.79 35.55 100.00

Table 6: Plume Heights – Centerline Height Percent by Direction

Plume visibility by calendar time is not an output of the SACTI program, but

estimates can be made based on the frequency of conducive meteorological

conditions. Such an estimate determined that plumes would be generated of

sufficient size to be seen from Avila Beach between an hour before sunrise and an hour after sunset approximately 45 time s per year, and from San Luis Obispo approximately 300 times per year. The plumes would be visible from San Luis for approximate 200 sunsets per year.

Estimates of salt, TDS, PM 10 , and water deposits are give n in Tables 9a, 9b, 9c, and 10 of Appendix A-7. Due to the use of saltwater, the salt deposition rates are

notable for some distance. The five m iles of plant access road along the coastline will be exposed to some amount of salt. The makeup of the total dissolved solids

is over 75% sodium chloride. The total annual salt depositio n would exceed 7,500

tons.

Buildup of salt on the transformers, conductors, and insulators associ ated with the 500 kV system would require conti nuous attention in the form of frequent water washings and monitoring of the system to minimize flashover incidents. The power generation industry35 of 59

March 2009 experiences significant problems caused by salt buildup on electrical systems at plants which are less exposed to salt deposition than that which would be seen at DCPP should cooling towers be installed. Numerous pl ants located on coastal areas, e.g., SONGS in Southern California, Turkey Point in Florid a, and Brunswick in North Carolina, have experienced flashover of high voltage equipmen t due to excessive accumulations of salt. (Reference Nuclear Industry OE 21874, OE 21784, and SER 10-93). To combat the problems of excessive salt buildup, operator s have found it necessa ry to increase the frequency of water washing. Also, increased vigilance is placed on monitoring electrical

measurements associated with the transmi ssion system to obtain early warnings of flashover in order to avoid equipment damage.

At DCPP, salt drift from the cooling towers would deposit large quantities of salt in a broad radius surrounding the cooling to wers (Reference Table 8 for Adverse Environmental Impacts). The amount of sa lt deposits on the exposed high voltage electrical components would gr eatly increase over the existi ng salt deposition rates. Frequent washings and monitoring would be required – at a minimum. Precise predictions of increased outages due to electr ical flashover of equipment attributable to excessive salt buildup associated with cooling to wer drift is not possible, but an increase in such outages with attendant interrupti on of generation would be expected. The alternative of locating high voltage transmission lines unde rground between the generator step up transformers and the switchyard is extremely costly and of questionable reliability, and has not been considered in this study.

Shading and fog from the plumes are given in Tables 11 and 12 of Appendix A-7. There will be some loss of sunlight n ear the cooling towers. The fogging is predicted to interact directly with plan t components to the NW and plant worker and equipment or commercial transport vehicles approaching from the SE.36 of 59

March 2009 Figure 13 – Cooling Tower Plume (Looking North)

Figure 14 – Cooling Tower Plume (Looking Southeast)37 of 59

March 2009 Palo Verde – Mechanical Draft Towers in a Dry Environment

Cattenom Palo Verde

Washington Public Power #2

Cattenom

Figure 15 – Plumes from Nuclea r Power Plant Cooling Towers38 of 59

March 2009 2. Water Quality – Cooling Tower Blowdown

Each unit would require a steady state bl owdown flow of approximately 25,200 gpm when running at full load. The concentration of the circulating water would be 1.5 times

normal seawater. Thus the blowdown would have a concentration of about 52,500 ppm TDS given an average seawater concentr ation of 35,000 ppm TDS. The blowdown

stream is toxic to marine life due to the higher TDS concentration, therefore it would either have to be rapidly diluted with ambien t seawater as it is in troduced into the ocean

or it would have to be treated to reduce its TDS concentratio n back to that of seawater.

Technology exists for removing salt from concen trated waste streams. The technology is known as zero liquid discharge (ZLD) and typica lly involves successive stages of reverse osmosis, brine concentration, followed by crysta llization where a salt cake is created. At

DCPP the waste stream of concen trate obviously could not be put back into the ocean, so

the salt cake would have to be dried and truc ked offsite to a waste disposal facility. Besides this waste disposal activity, the main disadvantage of ZLD for this application is the very high cost of the equipment and the high levels of electric power required. A rule of thumb for power requirements for ZLD (per discussion with Aquatech) is 15 kW of power are required for each gpm of waste stream to be treated. Thus, for DCPP’s waste stream of 25,200 gpm per unit that would mean 378 MW of power. In DCPP’s case this power is overstated since not all the disso lved solids would be extracted from the blowdown, but rather just about 1/3 of them in order to ach ieve a TDS level equal to the ocean. However, DCPP would still require the brine concentrator and crystallizer systems since whatever salt levels removed woul d have to be trucked away in solid form. Brine concentrator and crystall izer engineering and operation is fraught with challenges because of scale buildup on the heat excha nge surfaces as well as corrosion. Dryer operation is also problematic. Periodic acid cleaning of the systems is required.

Due to the problems associated with ZLD systems as described above, they are not considered practical for the massive applic ation that would be required for DCPP. Rather, the blowdown stream would be mixed with receiving waters by use of diffuser arrays in order to mitigate the effects of th e concentrated wastewater stream on sea life.

Plant effluent salinity within 10% of ambi ent has been provided (regulator guidance) as the acceptable range for discharge permit appr oval if the outfall configuration does not facilitate rapid diffusion in the ocean receiving water. This concentration range cannot be

achieved even with dilution of cooling tower blowdown with the 51-mgd remaining once-through cooling volume proposed fo r the ASW/SCW systems (72-mgd at 1.5x combined with 51-mgd at 1.0x results in a di scharge salinity of approximately 1.3x). Therefore, the cooling tower blowdown cannot be permitted for discharge to a single shoreline or submerged outfall point without su bstantial additional d ilution water sources. Other plant effluent streams (including fres hwater wastewater streams) do not provide enough volume to appreciably impact dilution. Additionally, use of excessive amounts of ambient seawater purposefully drawn into pl ant systems to achieve acceptable outfall salinity would be counter to any retrofit effo rt implemented to minimize seawater use.39 of 59

March 2009 The only practical option for rapid dilution to ambient salinity is use of a diffusion system spread across an acceptably large area in the receiving water body. For this application, a seafloor-anchor ed diffuser piping array placed out from the shoreline and

intertidal zone would be re quired to reduce or eliminate potential negative impacts to receiving water quality and marine life.

Of specific concern for cooling tower blow down (in addition to necessity for rapid dilution in receiving waters) are the Efflue nt Limit Guidelines (ELGs) for select

constituents. These ELGs are specific for point of discharge from cooling tower systems,

and not for final concentrations detected at a facility’s combined wastewater outfall. Chromium (Cr) and Zinc (Zn) have blowdown ELGs of 0.2 mg/L (milligrams per liter or parts per million) and 1.0 mg/L respectively. An assessment of intake seawater (influent) samples taken monthly for DCPP during the period 2005-2007 determined that Cr was almost exclusively non-detectible with one value of 0.2 ug/L (micrograms per liter or parts per billion) concentrati on during the period. Zn was al so routinely non-detectible; however, several instances of detection did occur with a maximum concentration of 59 ug/L during the period. For both of these cons tituents, concentration factors of 1.5x or even 2.0x in cooling tower blowdown would not result in an exceedance of the process specific ELGs provided available makeup at DCPP continued to exhibit low

concentrations. Other coo ling tower blowdown priority pollutant ELGs should likewise not be problematic provided ambient seawater chemistry off the plant site remained

stable.

Closed-cycle systems tend to exhibit more alkaline pH than makeup water. For DCPP, ambient seawater normally has a pH in the range of 7.8 to 8.4. This pH range facilitates chlorine/bromine control of biological fouling in existing seawater systems. As discussed previously in this report, the high salinity projected for cooling tower system operations should reduce or eliminate macrofouling concer ns (primarily marine barnacle and mussel fouling) within the system. However, fouli ng of main condenser tube surfaces might still

occur under certain conditions due to micro- organisms capable of withstanding the high salinity. This could require periodic chlorination treatment of the main condensers. However, such treatment would be hindered by elevated pH conditions. Acid (hydrochloric or sulfuric acid) injection to depress system pH could be necessary in order to facilitate microfouling oxidation treatment within the main condensers. It is not anticipated that addition of inorganic acids to effect m oderate pH depression would negatively impact overall water quality in the system, or subsequently reduce the ability to discharge the blowdown.

Chlorine treatment on an as-needed basis in jected immediately upstream of the main condenser inlets could be accomplished with only a temporary increase in residual oxidants within the system. The cooli ng tower blowdown may require temporary

isolation in the event residual chlorine wa s persistent. If actual operations required extended chlorination treatment, or resu lted in excessive residual chemical concentrations, cooling tower blowdown dech lorination capability could be required. Actual need for pH moderation, main condens er biofouling treatment, and/or periodic cooling tower blowdown dechlorination is hi ghly speculative. Therefore, equipment40 of 59

March 2009 specifications and costs to implement these pr ocesses have not been considered in this study.

The blowdown stream would be taken from the cold side of the cooling towers, having a maximum temperature of 83°F given a “max imum” wetbulb temperature of 66°F (this “maximum” wetbulb represents a point 2 standa rd deviations to the right of the mean wetbulb value of 52.0°F, representing a ll but 193 hours per average year when the wetbulb is greater than 66°F).

Blowdown would be directed into a pipe from a weir gate at the pump pit to achieve the desired flow. From there the pipe would be directed to the ocean near Patton Cove, south of the intake cove. The temperature and concentration of the blowdown being higher

than that of the seawater would result in a density of 64.7 lb/cu ft, as compared with a seawater density of 64.0 lb/cu ft. Being heav ier, the blowdown stream would tend to sink amid the seawater, with negative effects on be nthic marine communities. To counter this tendency, the blowdown stream would be cha nneled through diffusers at a high velocity, (5 ft/sec minimum) in order to promote mixing with the surrounding seawater. The blowdown distribution system would consist of a large distribution header, approximately 36”, which would be filled from a weir at each circulating water pum p pit where the flow could be set for a steady state flow of 25,200 gpm per unit, and would discharge under water on the sea floor (Reference Sketch SK-M -4). On the top of the underwater pipe would be located an array of di ffuser nozzles (approximately 600 1 1⁄2 -inch diameter nozzles). Given equal flow they would each have a discharge velocity of 6.6 feet per second. At this velocity, the concentrated st ream would be forced to mix with the less

concentrated seawater as it exited the nozzle. Static head from the 85 foot elevation at the inlet of the blowdown line would provide th e driving force for the flow. The nozzles would be located on 1 foot centers, two at each station, symmetrically configured pointing upward at an angle of 60° from the hor izontal. The diffuser section of the piping

would start 200 feet from shore and extend an other 300 feet for a to tal of 500 feet per unit. Fiberglass would be a suitable material for the diffuser system.

The blowdown plume was modeled with CORMIX, a comprehensive software system for the analysis, prediction, and design of outfa ll mixing zones resulting from the discharge of aqueous pollutants into diverse water bodies. It contains mathematical models of point source discharge mixing within an intellig ent computer-aided design interface. The programs focus is environmental impact assessment and regulatory management. It has been developed under several cooperative fundi ng agreements between U.S. EPA, U.S. Bureau of Reclamation, Cornell University , Oregon Graduate Inst itute, University of Karlsurhe, Portland State University, a nd MixZon Inc. during the period 1985-2007.

CORMIX is a recommended analysis tool in the permitting of industrial, municipal, thermal, and other point source discharges to receiving waters. The system’s major emphasis is on predicting the geometry and d ilution characteristics of the initial mixing zone so that compliance with water qualit y regulatory constraints may be judged.

CORMIX was used to evaluate the thermal a nd total dissolved solids (TDS) plumes that would be discharged as a result of the clos ed-cycle cooling installation. The expected41 of 59

March 2009 thermal plume from the diffuser array ports was found to be 0.80 me ters (2.6 feet) long before reaching the 2.78 o C (5 o F) isotherm above the ambient. The expected TDS plume was found to be approximately 0.77 meter (2.5 feet) long. The curr ent thermal discharge associated with the once-through cooling system is much larger, has an average thermal differential of approximately 11.1 o C (20 o F), and dissipates from a single shoreline outfall. An amendment would be required to the power plant’s NPDES Permit to define the modified thermal discharge characteristics, including use of the en tirely new offshore diffuser array. The actual plant discharge has not been designed, but the results provided would be bounding for any similar discharge. Table 7 summarizes the CORMIX results:

Plume Type Ocean Temperature °C (°F) Discharge Flow Rate (Per Unit)

m 3 /s (gpm) Isotherm

Considered

°C (°F) Plume Length m (ft)

Thermal 9.33 (48.8) 1.59 (25,200) 2.78 (5) 0.80 (2.6)

TDS 9.33 (48.8) 1.59 (25,200) 2.78 (5) 0.77 (2.5)

Table 7: Summary of Thermal Plume Analysis

DCPP is currently permitted to return wastewater to the ocean at a temperature of no

more than 22 o F higher than ambient seawater intake temperature. It has been assumed that a reconfigured DCPP woul d be required to meet the 20 o F limit above ambient receiving water temperatures for a ‘new’ di scharge in accordance with the California Thermal Plan. Since the cooling water blowdown would always be 17 o F higher than the wet bulb temperature, there would be numerous occasions when the blowdown temperature would be more than 20 o F above the ocean temperature. Examination of wet bulb temperature and ocean temperature at the intake structure show that the differential temperature would exceed 20 o F approximately 25% of the time. The use of SLO Airport weather station wet bulbs, which are likely lo wer than the wetter immediate coastal zone,

adds a bias which tends to reduce the esti mated hours per year that the blowdown would exceed the ocean water temperature by more than 20 o F.

Figure 16 shows the hours per day that th e blowdown would exceed the ocean water temperature by more than 20°F (based on da ta from the years 2003 – 2007). Note that the limit is rarely exceeded in winter, but often in summer.

0 5 1 0 1 5 2 0 2 5

1/1/2003 1/1/2004 1/1/2005 1/1/2006 1 /1/2007 1/1/2008

Figure 16 – Hours/Day that the Blowdown Water Temperature Would Exceed the Discharge Limit42 of 59

March 2009 Under such conditions it would be necessary to cool/dilute the blowdown stream with a

colder stream such as the service cooli ng water seawater suppl y or the makeup water system. For purposes of this study, a 20” branch from the SCW seawater supply would

be routed to the inlet of th e blowdown line to achieve the desired mixing. During these periods when blowdown temperature reduction is required, it would be necessary to run the third SCW supply pump. This would result in an additional volume of raw seawater use during these periods.

3. Adverse Impacts

Retrofit of DCPP to closed-cycle cooling woul d create significant adverse environmental impacts. These direct adverse impacts, as discussed below, would be realized both during implementation of the project, as we ll as during post-retrofit operation of the facility. Additionally, the large workforce, and transportation of equipment and materials required during the construction phase, would ge nerate negative impacts to the immediate surrounding communities. Personnel transpor tation to and from the facility would substantially increase light vehicular traffic in the immediate area for an extended period. Heavy equipment and materials trucking woul d significantly impact traffic flow and generate appreciable road noise.

The project would generate signi ficant adverse impacts related to overall electric industry green house gas (GHG) emissions. Loss of DCPP Units 1 & 2 for an extended period of time during construction (projected at 17 m onths minimum) would require replacement of the entire base load genera tion capacity of the facility. Th is lost electric supply would most likely be replaced throughout the period of construction with hi gher utilization of available fossil fuel generation units. Additi onally, the permanent loss of unit efficiency and increase in required auxiliary power fo r the cooling tower system operations would result in an ongoing reduction in net base load generation. This post implementation reduction in electric generation capacity woul d need to be replaced by other base load generation facilities (fossil units). The loss of long term capacity would effectively reduce future supply gains from planned efficient fossil and renewable resource generation projects in the State.

Demolition, construction, and transport activities associated with a retrofit project would be substantial. The very large equipment a ssociated with these activities would rely on diesel combustion, and therefore result in subs tantial consumption of fuel oil as well as the associated onsite emissions of GHG and pa rticulates. Most construction activities would occur within the existing, previously dist urbed, site industrial areas. However, the placement of a discharge dispersion system on the seafloor offsite of the plant would disrupt and segment pristine rocky marine habi tat, as well as disrupt transited intertidal zones during pipe placement. The large de molition and new construction projects would also generate substantial volum es of related debris. Meta ls, wood, concrete, and asphalt can be recycled; however they would still requi re offsite transport resulting in additional fossil fuel consumption. Non-recyclable fi lls, plastics, equipment and existing building43 of 59

March 2009 materials would need to be transported offsite as well, and disposed in limited available landfill space.

Salt emissions from the saltwater makeup mech anical draft cooling towers would present a significant new adverse impact at the plan t site. Salt drift would plague the entire industrial site and all exposed plant equipmen t, as well as settle on surrounding lands. The deposition of salt to the terrestrial plant and animal community on coastal bluffs southeast of the facility w ould dramatically increase, far in excess of the natural contamination from winds coming off the adj acent sea. Additiona lly, substantial vapor plumes from the cooling tower complex w ould be visible during certain periods to surrounding communities.

Operation of the cooling tower systems woul d generate large volum es of high salinity elevated temperature blowdown requiring disposal to the Pacific Ocean. Construction of the diffuser system for discharge of the bl owdown would disrupt the existing seafloor community, and operation of the system coul d result in establishment of high salinity zones potentially toxic to microscopic organi sms in the immediate vicinity of diffuser ports. Such unfavorable conditions could occu r in the receiving water when currents are low and ocean conditions calm resulting in less efficient mixing and dispersion.

Since PG&E owns large acreage tracts surround ing the power plant, noise generated from the cooling towers, primarily due to the fa ns, should not be a significant issue at the industrial site boundary. However, the cooli ng towers would increase the ambient noise levels in their surrounding vi cinity which would impact the occupancy of nearby offices

and facilities.44 of 59

March 2009 The following table summarizes the projected significant adverse environmental impacts:

Adverse Impact Cause Projected Magnitude

Project Implementation (Construction Phase):

Green House Gas (GHG) Emissions for Replacement Power Unit 1 & 2 Replacement Power During Extended Outages. (Lost carbon-free generation most likely replaced by fossil-fuel generation.) See Notes 1 & 2. 10,318,500 Tons CO 2 GHG Emissions

Project Fossil Fuel Combustion Transport of Construction Equipment, Construction Materials, Removal of Spoils, Debris, & Recyclable Materials, Onsite Grading & Construction Activities and Bussing of Craft Workers. > 4.424,000 Gallons of Diesel Fuel. Reference Appendix A-10 ,”Fuel Consumption Summary”

Disruption of Benthic Marine

Habitat Area Preparation and Placement of Discharge Dispersion Piping on Seafloor. Loss of 0.35 Acres of Rocky Subtidal

Construction Debris Disposal Landfill of Non-Recyclable (Non-Metal or Wood)

Construction and Site Debris. 3,600 Cubic Yards Landfill Disposal 300 roll-offs filled to 12-cubic yards

Facility Operations Post-Construction:

Green House Gas (GHG) Emissions for Replacement Power Generation Required to Replace Unit 1 & 2 Efficiency Loss & Increased Site Auxiliary Power Requirements. (Lost carbon-free generation most likely replaced by fossil-fuel generation.). See Notes

1 & 3. 180,500 Tons CO2/Year GHG Emissions

.

Salt Emissions and Deposition Cooling Tower Salt Drift 15,000,000 Pounds per Year Deposited on surrounding lands & equipment.

Calculation based on 25 day outages, drift of 86 gpm and .0405 gm/gm fraction of salts (Reference Appendix A-7).

Vapor Plume Cooling Tower Emissions Plume Lengths Exceeding 5 miles Plume Heights Exceeding 2,500 feet

45+ Times/Yr Visible from Avila Beach

300+ Times/Yr Visible from SLO

Blowdown Discharge Dispersion Zone with High TDS High salinity and thermal dispersion zone. Potential for negative impacts to marine organisms that come in direct contact. (Estimate of water volume affected by 1200 operating diffuser array nozzles.) 350 Cubic Meters in Receiving Water Estimated high TDS zone above each diffuser array: 91m long * 2.5m wide * 0.77m high = 176 cubic meters per unit

Corrosion Control Emissions Site corrosion control initiatives would substantially increase including necessity to resurface and paint metal equipment and structures. > 500 lbs/year Increase in Volatile Organic Compound (VOC) Emissions

Table 8: Projected Direct Adverse Environmental Impacts of DCPP Retrofit.

Table 8 Notes:

1. GHG calculations based on California Public Utilities Commission (CPUC) Greenhouse Gas Emissions Performance Standard Documents: 800-900 Pounds of CO2 per MW-Hr provided as emissions from efficient combined-cycle turbine natural gas fueled generation. 800 Lbs/MW-Hr used in GHG emissions

estimates.

2. GHG emissions for Pr oject Replacement Power During Constr uction (Unit 1 & Unit 2 Net Generation Capacity of 1155 MW/Unit with 17 Month Dual-Unit Outage): [2310 MW * 0.9 * 517 Days/project * 24 Hrs/day] = [25,796,232 MW-Hrs] * 800 lbs. CO2/MW-Hr = 20,636,985,600 lbs. CO2 = 10,318,493 To ns C02 or 9,380,448 Metric Tons CO2.

3. GHG emissions for Annual Repl acement Power Post-Project Opera tions (Average 55.4 MW Facility Reduction in Electric Output & Anticipated 90% Facility Capacity Including One 25-Day Unit Refueling Outage per Cycle): 451,180 MW-Hrs/Yr [Ref. Table 3] * 800 lbs. CO2/MW-Hr = 360,944,000 lbs.CO2/Yr = 180,472 Tons C02/Yr or 163,693 Metric Tons CO2/Yr.45 of 59

March 2009 4. Permitting

Implementation of retrofitting DCPP to a cl osed-cycle cooling configuration would require a substantial regulatory permitting effort. In addition, due to existing or potential restrictive requirements and conditions, th e ability to acquire all key construction approval and/or post project pl ant system operating permits w ould be very difficult. One key environmental permit (air emissions perm it) presents a potentially insurmountable obstacle to project feasibility. Furthermore, no single regulatory agency controls or has overriding authority over all required projec t permits and licenses further complicating any permitting assessment.

In accordance with power plant construction proj ects in the State of California within the last decade, crucial operating permits would ha ve to be secured (or at minimum a firm legal commitment obtained from the regulat ory agency responsible) before project construction could start. These include permits required for unit operations post retrofit. Without the assurance that operating perm its will be obtainable/approved following construction, a power plant re trofit project would be too ri sky to proceed. For DCPP these key permits would include, at a minimu m: 1) a substantially revised facility wastewater discharge requirements permit (National Pollution Discharge Elimination System [NPDES] Permit), and 2) an Air Emi ssions Permit-to-Operate (PTO) for cooling tower operations due to projected substantial PM 10 emissions.

A Coastal Zone Coastal Development Permit (CDP) would be required for the overall project from the California Coastal Commission prior to initiating construction. Obtaining final Coastal Commission approval for such a project is highly speculative, and assurance of post project operating permit and license av ailability would likely be a CDP approval condition under any scenario. Ad ditionally, the fact that plume abatement cooling towers are infeasible on the plant site , and frequent substant ial vapor plumes are projected to be visible from surrounding communities, reduces the likelihood of commission approval. Conditions in a CDP would also likely include significant mitigation or offsets for environmental impacts of project implementation (construction traffic, construction pollution, site aesthetic impacts, salt plume impacts to surrounding lands, etc.), and could result in substantial addi tional project costs that are not included in

the current estimates.

Air permitting for mechanical draft wet cooling towers, a key required post retrofit environmental operating permit, is problematic for DCPP. San Luis Obispo County is a non-attainment region for State of California PM 10 air quality parameters. Obtaining a permit for significant new PM 10 emissions would require su bstantial emissions offsets that currently are not available within the air district. With the projected growth of local and state populations, the lack of emissions offsets presents a real and potentially insurmountable obstacle to permitting a cooling tower system at DCPP.46 of 59

March 2009 The implementation of a retrofit would re quire significant modification to the Power Plant’s current NPDES Permit issued by the California Regional Water Quality Control Board, Central Coast Region (CCRWQCB). Po tential modifications could include more restrictive effluent limitations, as well as additional discharge and receiving water monitoring. This could add substantially to ongoing facility oper ation and maintenance costs. If the discharge would be consider ed “new” under the State Thermal Plan (likely due to the proposed installati on of an offshore diffuser array for tower blowdown), the

outfall limit would be set at 20 ° F above ambient receiving water temperatures. The thermal limit could necessitate periodic uni t power reductions, and/or the use of additional raw seawater for mixing with towe r blowdown (Reference Report Section III.2 Conceptual Design Summary).

As previously discussed, the only practica l/viable option for discharge of the large volume of high salinity cooling tower blowdown is diffusion offshore. Construction of an offshore piping system would require a State tidal and submerged lands lease and Army Corp of Engineers permit before th e overall retrofit proj ect could begin. Additionally, approval for diffu ser system installation would be a prerequisite for obtaining NPDES Permit approval. The scen ario of nested regulatory approvals would necessitate significant administrative lead time for wastewater discharge system related permit and license authorizations, and to insure timely sequenced resolution.

Approval of all project related Local and St ate permits, or at a minimum firm agency commitments to provide final approval fo r fully developed draft permits, would be necessary to support NRC licensing for th e extensive nuclear plant modifications.

Estimates of lead time for various administra tive efforts reflect allowances to adequately resolve anticipated Local and State permitting challenges prior to submittal of an NRC Operating License Amendment Request (LAR).47 of 59

March 2009 The following table summarizes anticipated project permit and licensing requirements:

Regulatory Agency Permit Type & Function Administrative Allowance (Begin Documentation and Permitting Process) Probable Constraints & Significant Special Conditions

Project Implementation/Construction Permits:

California Coastal

Commission Coastal Zone Development Permit (CDP). ( Overall Project Construction and Building Authorization Permit ) 3-Years prior to project

NRC LAR Submittal. Obtain key environmental operating permit commitments before overall project approval. Special conditions and offsets.

County of San Luis Obispo Project Component Building Permits(s) & Grading Permits. 3-Years prior to project

NRC LAR Submittal. ( In conjunction with CDP ) Special conditions and offsets likely required. Scope unknown.

U.S. Army Corps of Engineers (ACE) Section 404 Nationwide Permit (NWP) for Structural Discharge. ( Permit for seafloor dredging and materials placement for offshore wastewater diffuser array ) 5-Years prior to project

NRC LAR Submittal. (C ommitment to support NPDES permitting effort ) Seafloor damage and disruption mitigation likely required.

California State Lands Commission (SLC) Right of Way (ROW) and Lease for Tidal and Submerged Lands at Patton Cove. ( Lease for wastewater diffuser array lands use ) 5-Years prior to project

NRC LAR Submittal. ( In conjunction with ACE Section 404 permit effort ) Unknown

State Water Resources Control Board (SWRCB) Construction Storm Water Discharge Permit. ( Required for project >1 acre of ground disturbance ) 4-Months prior to initial

construction. None-Anticipated. Routine type project permit.

SLO County Air Pollution Control District (APCD) Concrete Batch Plant Permit-toOperate (PTO). 4-Months prior to batch plant operations. Dust control measures and fuel

combustion emissions restrictions (if fossil-fueled). New/Revised Facility Operating Permits:

Regional Water Quality Control Board (RWQCB) Central Coast Region-3 National Pollution Discharge Elimination Systems (NPDES) Permit. Facility Wastewater Discharge Requirements. 4-Years prior to project

NRC LAR Submittal. ( Draft Permit and Agency commitment likely required before CDP approval ) No variance from California

Thermal Plan maximum temperature limits. More

restrictive constituent limitations on equipment specific wastewater pathways (Sewage, SWRO, etc.).

SLO County Air Pollution Control District (APCD) New Cold Machine Shop Abrasive Blasting & Painting Unit Air Emissions Permit-to-Operate (PTO) 4-Months prior to initial unit operations. None-Anticipated. In-kind or similar equipment replacement for existing unit.

SLO County Air Pollution Control District (APCD) Cooling Tower Air Emissions Permitto-Operate (PTO). 4-Years prior to project

NRC LAR Submittal. ( Draft Permit and Agency commitment likely required before CDP approval ) Require procurement of PM 10 emissions offsets. Offsets are currently unavailable and potentially unattainable.

Table 9: Required Construction and Operation Permits & Licenses Not Including NRC Nuclear Reactor Operating Li cense Amendments/Extensions for Units 1 & 2

VII. Additional Studies

1. Special Studies

Numerous technical issues would require fu rther study at a point during the design phase of the cooling tower retrofit. These include (but are not limited to):

• Circulating Water Pump Pit: It is recommended that the pits be designed by modeling studies, which can be done by the circulating pump suppliers, among

others.48 of 59

March 2009 • Diffuser Design: Effective diffusion of the heated and concentrated blowdown needs to be analyzed further to ensure sufficient mixing would be achieved.

• Soils Investigations: Additional borings and soil testing is advisable where heavy loads are anticipated due to the cooling tower basins and the pump pits.

• Water Hammer Analyses: Very large water flows can be subjected to high pressure spikes or low pressure vacuum forma tion during transient conditions. These fluctuations, known as “water hammer” requi re analyses to avoid or minimize the pressure fluctuations through design features.

• Cooling Tower/Condenser/Flow Rate Optimization: If the retrofit were to proceed, a more detailed optimization of the combined cooling tower performance, condenser design, piping size and cooling water flow rate should be performed.

• Power Plant System Effluents: Further design of a retrof it would require additional analyses of a variety of existing effluent streams which would remain even with a closed-cycle cooling system. Needed analys es include evaluating the capacity of the liquid radwaste system to manage smaller ba tch discharges, assess ing the potential to redirect the reverse osmosis system to a newly constructed offshore diffuser, and the need to further treat other remaining discharges such as the steam generator blowdown, turbine building sump efflue nt, and makeup water treatment system blowdown. In addition, the effect of reduced seawater flows and potential for extended periods of stagnation within auxili ary system heat exchangers, would likely create challenges due to elevated copper c oncentrations in the remaining discharge. Reference Appendix 13, Power Plan t System Effluents Concerns.

VIII. Conceptual Schedule

1. Introduction

The conceptual schedule for implementing cl osed-cycle cooling using mechanical draft cooling towers at Diablo Canyon was developed using current regulato ry proposals. Start dates for construction were chosen to accommodate the 01/01/2021 deadline provided in the California SWRCB draft policy for impl ementing I&E reduction goals at operating facilities that use once-though c ooling. The schedule provides that both units will be shutdown in extended closed-cycle retrofit outages prior to the deadline, with return to service and commercial power generation not occurring until after the deadline. The schedule also provides for substantial proj ect lead time which will be necessary to facilitate extensive permitting, licensi ng, design, and work planning activities.

The conceptual schedule is based on bot h units operating as long as practical (approximately 21-22 months) during constructi on of new site replacement facilities, and the cooling tower/site excavation. Initial construction (10 months) involves building new site facilities to replace those displaced by th e new cooling towers and related services. Permitting (SLO County Building, Californi a Coastal Commission, NRC LAR approval,49 of 59

March 2009 etc.) would be required prior to start of new facility construction. Demolition of displaced facilities can begin after warehous e inventories and disp laced personnel have

been moved. Excavation and construction of the cooling towers would then follow.

Cooling tower basin excavation, re-configura tion of the Protected Area (PA) perimeter, and start of the Circulating Water Tunnel (C WT) construction between the tower basins and the tie-in inside the PA would require that major yard utilities be taken out of service.

This would initiate the overall plant shutdown. Specifically, loss of service for the 480V & 4,160V (non-vital) electrical yard loops would challenge the ope rability of several mechanical systems needed to run the plant. Disruption of the fire loop, domestic water, circulating water and other water systems w ould result. The shutdown and eventual restart would be staggered with 2 to 3 week s between Unit 1 and Unit 2. During plant shutdown and tunnel construction (includi ng tie-ins), both units' ASW piping would remain in service supporting CCW. Special protection measures would be in place.

Several parallel construction paths woul d be ongoing during plant shutdown: (a) Condenser retrofit, SCW piping and other di splaced turbine building equipment rework, (b) Construction and tie-in of new/existing CW tunnels west of the turbine building, including displaced/re-routed utilities, (c) Re work/configuration of the intake structure for new makeup and SCW pumps, piping, and re lated services, and (d) Electrical service changes to match new equipment at the intake , the cooling tower basins, and the 500 kV switchyard.

The overall duration for construction would be approximately 3-3/4 years. The plant shutdown during the construction period would be at least 17 months. Durations assume that engineering design can be developed to support permitting, that permits can be obtained, and that the re gulatory process does not ex tend overall construction. Anticipated Federal, State, and County (S LO) permitting are included in the schedule.

2. Schedule Basis, Calendar, Resources

The schedule assumes an average (plateau) p eak work force of approximately 3,000 craft

between 2 nd Q, 2020 and 4 th Q, 2021 (18 months). This occurs primarily during plant shutdown. Actual peaks within this timeframe could be as high as 4,000. The conceptual

schedule has not been resource loaded at this level of detail. Bussing from several offsite staging areas would be required to reduce the nu mber of automobile trips to and from the site. Prior to the plant shutdown, craft re quirements would be approximately half the peak period level (1,500), and for the last 9 months of construction that number would reduce to approximately 1,000 workers.

The distribution of cr aft would be such that approxima tely 2/3 of the above hours are based upon 2 x 10 hour/day shifts and a 6 day wo rk week. Non-critical craft would work a single 10 hour x 5 days/week shift.

The construction and engineering activity dur ations are based upon judgment. Input for the overall durations has been reviewed by DCPP System and Design Engineering and50 of 59

March 2009 Construction Planning. Many of the durations are based upon historical information from original construction or more recently completed projects.

The permanent (existing) plant staff is assume d to remain constant at about 1,250. The plant shutdown and on-going construction are expected to require support for capital improvement and maintenance projects similar in size and value to those presently being conducted during both ongoing opera tions and refueling outages.

3. Pre-Shutdown Construction

Permitting for anticipated Federal, State, and County agencies covers about 7 years; this can be adjusted relative to the start of engineering. Design is only shown for the replacement facilities. Thes e are the "drivers" for early site construction. Other engineering design (cooling towers, pumps, piping, tunnels and supporting system changes, and related design) has not been shown on the schedule, but is understood to

occur in the overall timeframe. Front-end engineering is precedent to the permitting process. Final engineering supports site construction and is assumed dependent on the permitting process. The initial construction would be for facilities needing to relocate before cooling tower construction: main warehouse, cold machine shop, engineering/other offices (Parking Lot #7), new sewage treatment plant, new parking structure (1,000 spaces) and the vehicle inspectio n station. Locations for some of these are tentative and require more engineering ev aluation. Some of these may have to be located offsite, or divided to suit multiple smaller (partial) footprints.

The overall duration to cons truct new/displaced facilitie s would be approximately 10 months, plus 1 to 2 months for personnel and inventory moves. After that, cooling tower excavation could proceed (generally) from we st to east. Cooling tower basins' grade

would be at elevation 83' to elevation 85' and would cover approximately 40 acres (encompassing Lots #6, 7, 8, the main warehouse and southern portions of Reservoir Road).

Security changes needed to support construction are extensiv e. These affect the rearrangement of the existing PA fencing, circuitry, and camera/microwave systems. During re-work and restoration of the PA, compensatory security measures will be in place (24/7) to ensure the integrity of the Plant Security PA Boundary.

During 2019 through 1 st Q 2020, it would be necessary to conduct fuel cask campaign operations to ready both fuel pools for full co re offloads that o ccur during the plant shutdown(s). Limited access during realignment of Reservoir Road (2 nd /3 rd Q of 2019) could impact ISFSI operations.

4. Construction During Plant Shutdown

Excavation of the cooling tower basins, th e pump pits and new tunnels between the cooling towers and inside the PA would invol ve interruption of main plant 480V & 4 kV electrical systems. As tunnel trenching proc eeds past the security building into the PA,51 of 59

March 2009 the entire southern security boundary must be protected and eventually re-worked.

Excavation for the tunnels into the PA west of the turbine building expands the number of systems to be temporarily shut down and re-c onfigured. It is not pr actical to reroute or try to "jumper" the affected systems because th e tunnels' path for both units covers such a large area (the planned excavation extends northward past the actual plant centerline between Unit 1 & Unit 2). Key vital systems ar e not allowed to be shut down, but require special protection to ensure c ontinued operability. The main fire loop, the ASW piping, the diesel fuel oil tanks and pipi ng are among those requiring protection.

The new circulating water tunnels would requ ire 8 connections to existing tunnels. On the supply side, 4 of these would meet the exis ting inlet tunnels and penetrate them. Tiein of the new tunnels would have to mini mize the impact and exposure of the 4 ASW supply pipes. These are on the upper opposing CWT walls. The proposed routing avoids the ASW pipes on the inner wa lls and the 480V vital duct ba nks on top of the tunnels by using tie-in routing from the outside or belo w. Shoring and sequencing of the work in getting to the required eleva tion requires dedicated constr uction engineering to map, expose and protect all of the U/G utilities in the areas.

The excavation in front (west) of the turbin e building and the corresponding reinstallation of the affected underground utilities followe d by backfill need to be completed before and after movement and access of equipment for the main condenser rework and other affected equipment on elevation 85' of the turbine building. The PA west of both (especially Unit 2) buildings could not suppor t equipment movement during much of the

first half of 2020.

During plant shutdown, fuel would be offloaded and stored in each unit’s spent fuel pool. Essentially, each unit would be in a 17 month refueling outage. Considerable capital and maintenance work would be planned during the shutdowns in addition to the cooling tower scope, but is not included in this concep tual schedule or estimate. The ramp down and power ascension of both units will be staggered by approximately 2 to 3 weeks.

Normal unit refuelings and cycle lengths woul d be utilized for the cycle preceding each unit’s shutdown. The schedule for starting c onstruction of replacement facilities in 2018 and plant shutdowns commencing in early 2020 would be preceded by 1R21 in the 4 th Q of 2018, and 2R21 in the 4 th Q of 2019. Refuelings would not resume until approximately 18 months and 21 months after the re-start of commercial operations or September of 2023 and February of 2024 in acco rdance with the conceptual schedule.

Other critical activities, need ed to integrate the new cooli ng towers, pumps, and hardware into the plant, involve construction of a new access road into the back (east) side of the powerblock. This occurs at the bench at el evation 115' and allows cask transporter traffic between the Fuel Handling Building (FHB) and the ISFSI facility via Reservoir Road up

the hill. The new road to the bench at elev ation 115' must transition approximately 30 ft of elevation over almost 400 ft of length. Routing of grading, compaction and paving equipment in this area, and overall construc tion represent a challenge to electrical and compressor equipment southeast of the Un it 2 Turbine Building. The Radwaste52 of 59

March 2009 maintenance and compressor facility would re quire relocation (related services are also affected). Tie-ins for switchgear at the 500 kV Switchyard and main buried electrical services down to the power block and the cooling tower basins would take place while the plant is shut down.

No specific line activities are included in the conceptual schedule for control room simulator changes. Engineering design and hardware order placement for affected boards would be in 2018 and 2019. Physical change s would be done in 2020 to support actual operator training in 2021 before restart.

The new makeup and blowdown lines, between the cooling towers and intake (and the cooling towers and offshore diffuser), follow the CWT work and mechanical installations at the intake; the work is not critical path. Two 36" diameter blowdown lines are routed underground from the cooling tower basins to Patton Cove and then several hundred feet offshore to the discharge (diffuser array) lo cation. The existing CWT bores 1-2 and 2-2 will serve as a corridor for routing the makeup piping from the intake to the new tunnel

tie-ins inside the PA. The blowdown lines require special engineering, permitting and

installation to ensure that ocean floor and s ea life protection is maximized. The schedule has very summary level of detail showing these activities over an approximate 15

months.

5. Plant Re-start and Construction Completion

The schedule assumes that Unit 1 & Unit 2 rest arts are on staggered schedules (2 to 3 weeks apart) to facil itate safe startup operations for each unit. Approximately 2 months of startup and testing would pr ecede fuel loading and restart per unit. Reloading of fuel, system tests and paralleling each unit to the grid including power ascension would require about two weeks. During this period, and the 2 to 3 months preceding, plant security must complete all of its final test ing of the new, reconfigured, PA boundaries.

The post-startup duration for construction is a bout 4 to 6 months. Very little definition

has been included for these noncritical activi ties. Backfilling, grading & paving outside the PA, noncritical utilities' te sting and restoration, signage , painting, training and closeout of all construction packages can all complete after plant restart.

IX. Cost Estimate Summary

1. Cost Estimate Overview

The cost of retrofitting DCPP with mechanical draft cooling towers is comprised of 5 elements; 1) Capital Project Cost, 2) Decommissioning Cost, 3) Operation and Maintenance Cost, 4) Cost of Replacement Power to compensate for lost MW during construction shutdown period, and 5) Cost of Replacement Power for lost MW Capacity due to the derating of DCPP caused by the cooling system reconfiguration. A summary of these costs and a high level description of the basis for each of these estimates follows:53 of 59

March 2009 Capital Project Cost $2,689,000,000*

Decommissioning Cost $67,000,000*

Operation and Maintenance Cost $7,400,000/Year*

Replacement Power – Lost During Construction $1,806,000,000*

Replacement Power – Loss in Net Plant Output $31,600,000/Year*

* 2008 Dollars Excluding Escalation and AFUDC

Table 10: Cost Estimate Summary

Unit prices used in determining capital pr oject costs are derived using PG&E capital projects guidelines, manufacturer/vendor i nput, recent actual costs from other major capital projects at DCPP and input from the engineering, op erations, project management and the work planning departments, as well as estimating judgment.

2. Capital Project Cost: $2,689 Million

This cost is based on the conceptual design prepared by Enercon Services and described in this report (Reference Ca pital Project Cost Estimate Details Appendix A-11). The estimate includes permitting, engineering, proc urement and installation of the new system and re-design of existing systems to accommodate the new system. Construction cost includes relocation of the plant infrastruc ture to accommodate the new equipment. Reconstruction of displaced plant facilities onsite would be limited to the existing developed footprint at DCPP. Not all of the facilities which would be displaced can be fully relocated onto the existing DCPP footpr int. Allowances have been included for

reconstruction of those faciliti es at an offsite location. Equipment manufacturers have provided budgetary proposals based on the conc eptual design and are incorporated into the cost estimate including applicable taxes. Based on the size of this project, its manpower requirements and recent DCPP experi ence, travel through the town of Avila

Beach would be restricted to a limited num ber of ‘trips’ through the community. This restriction would require DCPP to provide offs ite parking, bussing (transportation to and from the facility for approximately 3,000 craft personnel), as well as pay for the associated travel time. Maintenance or repa irs to public roadways outside of DCPP are

not included in this cost estimate. As safe ty and security are always a foremost concern at DCPP, the cost of maintaining and ensuring a safe and secure facility are included in

the construction costs.

No allowances have been made for escalati on, project financing costs and/or foreign currency exchange rate fluctuations. All co sts are in present da y (2008 US Dollars) and include indirect cost and corporate overhead exclusive of financing costs (Accumulated Funds Used During Construction - AFUDC). AF UDC is an estimate of PG&E’s cost of capital invested in a project during constructi on, and is applied to all the Utility’s capital orders or projects that have a constructi on period greater than 30 days. AFUDC is54 of 59

March 2009 applied to a project’s total di rect cost, applicable taxes, and capital administrative & general (A&G). AFUDC is accrued from the fi rst month that costs are first charged to a project and continues until the month the proj ect is declared operational. AFUDC is included in a project’s overall cost and r ecovered from the rate payers. Based on the proposed schedule, it is estimated that the total capital project costs presented would

double if it were to include AFUDC and es calation. Demolition cost includes an allowance for fluorescent light fixture and ballast disposal, asbestos di sposal as contained in some building systems, and lead abatemen t at the existing security firing range. No

other allowances have been made for h azardous, contaminated or environmentally adverse material abatement of any kind.

3. Decommissioning Cost: $67 Million

The project would have a significant impact on the overall decommissioning cost at the end of the useful life of DCPP. Though th e current developed footprint would not be expanded, the areas currently used for parki ng would be replaced by structures. The new construction put in place would eventually be removed as part of the station’s decommissioning process. The cost of this added removal scope must be included in the decommissioning fund. The cost estimate for the decommissioning is based on analysis of the current estimate of the cost to decommission DCPP as a percentage of the escalated cost to build the pl ant, and is adjusted to a lower value to reflect the noncontaminated nature of the new systems (d ecommissioning at 2.5% of install costs).

4. Operation and Maintenance Cost: $7.4 Million Annually

The operation and maintenance cost of mainta ining the mechanical draft cooling towers is based on general vendor recommendations . The costs which have been provided include daily, weekly, monthly, quarter ly, semi-annual and annual inspections and maintenance. Labor, material and chemicals are also included

. Allowances have been

included for the cost of increased maintenance to electrical equipment due to salt drift

and for the cost of travel between onsite and offsite facilities. Th ese costs would be in addition to costs currently incurred for opera tion and maintenance of the existing cooling system. Combined intake pump and electrical systems, cooling systems piping, concrete conduit, and main condenser operation and main tenance cost are assumed to be roughly equivalent (Reference Appendix A-11 Projec t Cost Estimates Page-2 Annual Increase to Station Operation & Maintenance Cost).

5. Replacement Power – Lost MW During Construction: $1,806 Million

In order to safely execute this project, bot h nuclear units would be shut down when construction activities expose main mechanical or electrical systems or jeopardize any nuclear safety related systems. During this shutdown period, power must be purchased to

meet the demand of the PG&E service area. Th is period is expected to last a minimum of 17 months (517 days). The formula for cal culating replacement pow er is based on an estimate of each unit’s annual output priced using PG&E’s current (2008) long term power procurement forecasts of $70 per MWHr, and a Plant Capacity Factor of 90%.55 of 59

March 2009 Construction Replacement Power Cost Estimate Calculation: $70/MW * 1,155 MW/Hr * 24 Hr/Day * 517 Days * 2 (Units) * 0.9 (Capacity Factor) = $1,805,736,240 (say $1,806,000,000)

6. Replacement Power – Lost MW due to Derated Capacity plus Additional Auxiliary Power: $31.6 Million Annually

After installation, the cooling towers would re sult in decrease in net plant output due to a decrease in generator output, and an increase in required pl ant auxiliary power. PG&E

would meet service territor y demand by purchasing an equal quantity of replacement power ongoing. The cost of replacement power is calculated using an average of $70 per MWHr based conservatively low on PG&E’s 2008 replacement energy costs. Plant Capacity Factor of 0.9 assumes a one unit 25 -day refueling outage during any given year.

Average Derate Annual Replacement Power Cost Estimate Calculation: $70/MW * 451,180 MW-Hrs/Yr [Ref. Table 3] = $31,582,600 (say $31,600,000)

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March 2009 Description Total Price

2 Units Mechanical Equipment:
Cooling Towers $80,000,000
Condenser Waterbox/Tubesheets/Tubes $62,780,000
Circulating Water Pumps $46,400,000
Other Pumps $4,900,000
Valves (96”, 78”, & 36”) $3,999,000

Electrical Equipment:
500 kV/13.8 kV Transformers $8,000,000
Other Transformers $3,420,000
Cooling tower electrical building. Foundation not

included $2,870,000

500 kV substation package for cooling tower power supply (excluding transformers) $12,000,000

Other:
Dechlorination System $500,000
Paralined Steel Piping $18,222,000
Fiberglass Reinforced Plastic Piping $1,072,000
Instrumentation and Controls $4,254,000
Sewage Treatment Plant $300,000

Total Major Equipment Procurement Cost $248,189,000

* Excludes shipping, taxes, import fees, etc.

Table 11: Major Equipment Procurement Cost*57 of 59

March 2009Figure 17–Conceptual Installation and Plume–Perspective From Ocean58 of 59

March 2009 Acronyms and Abbreviations

A&G Administrative & General AFUDC Accumulated Funds Used During Construction

APCD Air Pollution Control District ASW Auxiliary Saltwater BOD Biological Oxygen Demand

C Celsius

CARB California Air Resource Board CCW Component Cooling Water CDP Coastal Development Permit CDR Condensate Regeneration System CFR Code of Federal Regulations Cu Copper CWP Circulating Water Pump CWT Circulating Water Tunnel

CY Cubic Yard DCPP Diablo Canyon Power Plant EDG Emergency Diesel Generator

ELGs Effluent Limit Guidelines EPA Environmental Protection Agency

F Fahrenheit FHB Fuel Handling Building FSAR Final Safety Analysis Report

GHG Green House Gas GPD Gallons per Day GPM Gallons per Minute HEI Heat Exchange Institute

HMI Human Machine Interface hp Horsepower HX Heat Exchanger

I&C Instrumentation & Control I&E Impingement and Entrainment I/O Input/Output ISO Independent System Operator ISFSI Independent Spent Fuel Storage Installation

kW Kilowatt

kV Kilovolt kVA Kilovolt-Amps LAR License Amendment Request LRW Liquid Radioactive Waste MGD Million Gallons per Day mg/L Milligrams per Liter (parts per million) MTCS Main Turbine Control System MVA Million Volt-Amps MWHr Megawatt Hour59 of 59

March 2009 MWTS Makeup Water Treatment System NEI Nuclear Energy Institute NEPA National Environmental Policy Act NPDES National Pollutant Discharge Elimination System NRC Nuclear Regulatory Commission

NWS National Weather Service OE Operating Experience OTC Once-Through Cooling PA Protected Area (inside security perimeter)

PM 10 Particulate Matter 10μm and smaller

PDN Plant Data Network PPC Plant Process Computer PTO Permit to Operate PSIG Pounds per Square Inch Gauge Q Quarter

RO Reverse Osmosis RWQCB Regional Water Quality Control Board SACTI Seasonal/Annual Cooling Tower Impact SCW Service Cooling Water SER Safety Evaluation Report

SGBD Steam Generator Blowdown SLO San Luis Obispo SONGS San Onofre Nuclear Generating Station SSPS Solid State Protective System

SWRCB State Water Resources Control Board

SWRO Seawater Reverse Osmosis TBS Turbine Building Sump

TDH Total Differential Head

TDS Total Dissolved Solids ug/L Micrograms per Li ter (parts per billion) UPS Uninterruptable Power System

UV Ultra Violet

WB Wet Bulb ZLD Zero Liquid Discharge