1 **Site Visit Report** Scattergood Generating Station 12700 Vista Del Mar Playa Del Rey , CA 90203 August 31, 2009 (revised August 16, 2013) **1.0 Background and Objectives**  The Environmental Protection Agency (EPA) is in the process of developing 316(b) cooling water intake structure requirements that reflect the best technology available (BTA) for minimizing adverse environmental impact for all existing power plants and manu facturing facilities. As part of this process, EPA staff is visiting electric generators and manufacturers to better understand the cooling water intake structure (CWI S) technologies in use at facilities, including the site

specific characteristics of eac h facility and how these affect the selection and performance of CWI S technologies. EPA is also visiting facilities to better understand cooling water use and specific issues or technologies that can affect 316(b) compliance. EPA selected Scattergood Gen erating Station (SGS) for a site visit due to its location on the Pacific Ocean and its use of an offshore intake structure fitted with a velocity cap. **2.0 Facility Description**  SGS is a natural gas

– fired steam electric generating facility located in the Playa del Rey section of the City

of Los Angeles and owned and operated by the City of Los Angeles Department of Water and Power (LADWP). The facility occupies approximately

56 acres of an industrially zoned site opposite Dockweiler State Beach and Santa Monica Ba y. The cit y’s H yperion Wastewater Treatment Plant lies adjacent to the facility’s northern property line, with Grand Avenue bordering to the south (industrial area)

. Residential neighborhoods in the City of El Segundo and Los Angeles abut the eastern and northeastern boundaries (see Attachment B). In addition, SGS is located approximately one mile south of the southern

- most runway

at Los Angeles Airport. Elevations at the site vary significantl y. The three generating units are situated at approximate ly

3 5 ft above sea level ( asl ) along the facility ’s western boundary with Vista del Mar. Water treatment ponds and tanks, parking areas, and smaller maintenance buildings are also located at this level. Immediatel y east of the generating units, the prope rty rises sharpl y to approximately 100 ft asl, then graduall y rises to 155 feet at the eastern propert y l ine. This upper portion is occupied b y the switch ya rd, storage tanks, and two small cooling towers that provide bearing cool ing water using potable water. Wastewater discharges to and water withdrawals from Santa Monica Bay (Pacific Ocean) are covered under NPDES Permit No. CA0000370, which is administered at the state level b y a regional water board. Order No. 00

- 083, issued by the L os Angeles Regiona l Water Board, expired on May 10, 2005 but has been2 administratively

continued to the present. The facility had been previousl y notified that a reissued permit was delayed pending the outcome of the State Water Board’s ongoing once

- through cooling policy development. At the time of EPA’s site visit it was unclear when the NPDES permit would be reissued. Power generation began in 1958 with the commissioning of Unit 1. Unit 2 followed in 1959 while Unit 3 was commissioned in 1974. All units remain availa ble for service. SGS has a single two to three week outage annually and an eight to ten week outage every

few years for major projects. **3.0 Electricity Generation and Transmission**  SGS currently

operates three conventional steam turbine units (Unit 1, Unit 2, and Unit 3) with a combined boilerplate generating capacity of 8 20 MW ( Table 1 ). Facilit y representatives noted that the capacity utilization rate (CUR) at SGS has consistently

trended downward over recent years as more modern and efficient sources have come online in the region , including an expanded renewable portfolio to meet state greenhouse gas objectives. However, depending upon federal and state climate legislation, greater dependence on these local plants for base load energy

suppl y and the balancing of new inte rmittent renewable resources may

be necessary

if LADWP is required to undertake an early divestiture of its coal resources. **Table 1**  **– SGS Rated Capacity** 
**Unit Rated capacity**  **(MW) 2008 CUR**  Unit 1 180 31% Unit 2 180 15% Unit 3 460 18% **SGS total 820**  **20%** Units 1 and 2 are conventional natural gas while Unit 3 is a supercritical natural gas unit. Energy

efficiencies for SGS’s three natural

- gas fired units are t yp ical for units of this ty

pe and age. Under peak conditions, Units 1 and 2 can operate at approximate efficiencies of 33% (9,500 BTU/kWh) while Unit 3 is slightly more ef ficient at 37% (9,200 BTU/kWh). LADWP representatives noted that capacity utilization rates are an inexact metric for determining a particular facility ’s i mportance to the overall s ys tem. Although SGS’s CUR is relatively

low, it occupies a critical position in LADWP’s overall generation and transmission plans during peak periods. The existing transmission sy stem is limited in its ability to move electricit y between the northern and southern sections of LADWP’s service areas during high demand periods. The phy sical location of SGS, along with LADWP’s other coastal units, enables LADWP to maintain a proper balance in the s ys tem without compromising3 service. This is particularly notable since LADWP is its own balancing authority and as mentioned in Section 10 of this report, as a vertically integrated utility responsible for its own generation, transmission, and distribution of electricity , does not rel y on t he energy market for power purchases to supply its energy needs. Therefore, the role of its coastal plants, serve a critical function in providing local resource adequacy, reliability , and sy stem stability

. **4.0 Cooling Water System and Intake Structure**  Units 1

- 3 use ocean water for condenser cooling in a single

- pass configuration (“once

- through cooling”). SGS operates a single combined intake structure to serve all three units; water is divided after secondary screening to dedicated tunnels to each unit’s con denser. Water is withdrawn from Santa Monica Bay through an intake located approximately 1,600 feet from shoreline, terminating at a depth of approximately 29 feet. The intake pipe rises 13 feet above the sea floor and is fitted with a circular concrete velocity cap 32 feet in diameter (Figure 1). There is a 5 foot vertical gap between the top of the intake pipe and the bottom of the velocity

cap. In February

2009, SGS installed vertical exclusion bars spaced 9 inches apart on the velocity cap to reduce entrapment of large organisms (sea lions, sea turtles, etc.). Facility representatives indicated that the modification has noticeabl y reduced entrapment between the intake riser and the forebay.

**Figure 1**  **– Offshore Intake and**  **Velocity Cap** The intake structure’s onshore portion consists of 8 screen bay s arranged in a 60° arc that draw water from a common forebay

. Unit 3 is served by four of the screen bay s, with 2 each dedicated to Units 1&2. Primary screening is achieved4 with vertical bar racks spaced 5 inches apart (4

- 5/8 inch opening) to remove large debris. Secondary

screens for smaller debris consist of vertical traveling screens with 3/8

- inch by

3/4

- inch mesh openings (Figure 2). Screens are rotated once every 8 hours, at a minimum, and washed with a high pressure spray to remove collected debris, which is deposited in collection baske ts for disposal in a landfill.

**Figure 2**  **– Onshore Intake Structure** 5 Estimated intake velocities were calculated using the maximum intake flow and total screen area at MLLW:

 1.5 fps at velocit y cap opening
 6.8 fps in the intake pipe
 0.6 fps approach to screens for Units 1&2
 0.7 fps approach to screens for Unit 3 Four circu lating water pumps, each rated at 39,000 gpm ( 56 mgd), serve Units 1&2. Four additional pumps serve Unit 3 , with each pump rated at 47,000 gpm ( 68 mgd)

. The SGS design intake flow (DIF) is 344,000 gpm, or 495 mgd , although the peak intake capacity is used infrequently

throughout the y ear. Data provided b y SGS representatives shows the average daily intake flows from 2005 through 2008 ( Table 2 ). **Table 2**  **– Average Annual Intake Flows**  **Year Average Annual Intake**  **Flow (mgd)**  **Percentage of DIF**  2005 294 59 2006 316 64 2007 271 55 2008 315 64 A direct correlation between flow and generating capacity utilization cannot be easily made since generating CUR do not account for startup/shutdown periods, nor do they

account for “hot standby” periods during which units are held in a near - read y state wi thout generating electricit y but still require cooling water withdrawals

. SGS conducts periodic heat treatments (approx. every 8 weeks) to control biofouling (e.g., mussel growth) in the cooling water s ys tem. During heat treatment control gates on the intake and discharge tunnels are closed while a by pass gate is opened allowing all water to recirculate through the s ys tem until the temperature has reached 115° F and has circulated for 100 minutes. Biofouling is also controlled through periodic chlorine ( sodium hy pochlorite) injections to the intake flow. Chlorination for each unit occurs for 40 minutes once for each shift (3 times per day). **5.0 Impingement and Entrainment Information**  Following the adoption of the Phase II rule, SGS initiated compliance activ ities by submitting a Proposal for Information Collection (PI C) in October 2005 that outlined plans to conduct a source water characterization study

. Impingement and entrainment technologies would also be evaluated for their potential use at the site. Th e PI C identified fine

- mesh traveling screens, cylindrical wedgewire screens, operational measures, and restoration as technologies that might offer6 some benefit to SGS. These evaluations were not completed, however, due to the suspension of the Phase II r ule. Facilit y representatives noted that LA DWP evaluated the feasibility of using treated wastewater from the Hy perion facility

as a replacement for ocean water at SGS , but concluded this water source was insufficient to meet cooling water needs

. In addi tion, this alternate water source may be limited in the future because the state is advocating water reclamation , thereb y reducing opportunities for reclaimed water from POTWs

. Secondary issues included the elevated wastewater temperature coming from the Hy perion facility

an the presence of ammonia which would be detrimental to the copper/nickel allo y condenser tubes. At the direction of the Regional Water Board, SGS co nducted a source water baseline characterization study during 2006 to determine the composition and abundance of all life stages of fish and shellfish that might be influenced b y the intake structure. The study documented entrainable organisms in the vici nity of the intake and near the shoreline, but did not attempt to quantify an y entrainment reductions. SGS collected monthly sampling every

six hours in a 24 hour period at from ten source water stations located up and down the coast. SGS also conducted impingement and entrainment sampling as part of this study

. They collected weekl y (four in a 24 hour period) impingement samples at the traveling screens 1 and entrainment samples from a single entrainment station in the immediate proximity

of the CWI S (wi thin 50

- 100 meters)

. The stud y was published in November 2007

. SGS has twice evaluated the effectiveness of the intake structure’s velocity cap in reducing impingement. Following a major storm in 1970 that destroyed the velocity cap, SGS operated for 4 years without the cap. Comparisons between the protected and unprotected sy stem showed significant impingement reductions with the velocity

cap in place. More recentl y, SGS conducted a stud y over four months during the winter of 2007

- 08. During the study period, intake and discharge flows were reversed ( i.e., the intake became the discharge and vice versa ) such that the new “intake” was unprotected. Apart from the velocity cap, the principal difference between the intake and discharge is the distance fro m shore (1,600 vs 1,200 feet). At this location, however, the sea floor slopes gentl y away from shoreline and translates to a depth disparity

of only a few feet. Thus, the species composition and abundance are substantially similar at each location. The study reported impingement reductions of more than 97 percent based on abundance, and 95 percent based on biomass. A single species, pacific sardines, accounted for over 94% of fish abundance. Entrainment has not been studied in detail at SGS. The veloc ity cap stud y did not evaluate an y potential entrainment reduction that might be achieved b y the intake structure’s location at a point offshore.

1 The impingement samples do not represent the intake location as the traveling screens are located after the long intake pipe.7

**6.0 Cooling Tower Feasibility**  Facilit y representatives noted that the feasibility of cooling towers at the SGS lo cation as been considered at different points, whether as part of a repowering project or to retrofit one or all three of the existing units. SGS has not conducted a formal cost and engineering feasibility anal ys is, however. A report prepared for the Cal ifornia Ocean Protection Council (OPC) and State Water Board in 2008 identified several obstacles that would influence the feasibility of cooling towers at the SGS location. Available space at the facility is limited and cooling tower placement would be c omplicated by the disparity

in elevations. Siting cooling towers to either side of the generating units at the 30 foot elevation would be difficult given the limited space, the presence of other structures (treatment ponds/tank) and potential air circulat ion interference due to a tower’s proximity

to the steep slope east and south of the generating units. A more likely

scenario would place cooling towers on the upper portion of the facility at the 100 foot elevation where the current , but significantl y sm aller cooling towers for just the bearing cooling water , are located. Multiple towers could be configured in this area, although the elevation difference between the towers and condensers would require larger capacity circulating water pumps and might require modifications to the condensers to withstand higher pressures. To wers at this location would present a greater visible impact and might contribute to drift deposition on the adjacent switchyard. The potential for a large visible plume would likely require mitigation for at least a portion of the ye ar. SGS’s proximity to the southernmost runway at LAX and to residential neighborhoods in El Segundo would seem to indicate that plume abatement technologies would be required. Noise abatement measures, such as low

- noise fans or fan deck barriers would also be required to co mpl y with local ordinances. The 2008 OPC study considered these obstacles but was able to configure cooling towers for all three units on the upper portion with plume and noise abatement technologies included. The initial capital cost for these towers wa s estimated at $160.4 million, excluding long

- term costs such as operation and maintenance and energy

penalty costs. During the site visit, facility representatives cited many of the same obstacles as potential reasons wh y cooling towers were infeasible at the site. Space limitations and conflicts with local ordinances were the primary reasons wh y SGS does not consider cooling towers a practical alternative. Representatives noted that likely local opposition to cooling towers is not reflected in local bui lding and noise ordinances and would be a major concern

. Other concerns that were not re f lected in the OPC study

were: (1) while the report suggests relocation of critical, integral site equipment (e.g. ammonia storage tanks for NOx compliance, or the s wi tch yard) the ir costs and the associated outage time (e.g. replacement power costs) were not captured; (2) OPC concluded relocation of the switch yard was feasible, but is considered infeasible by LADWP for all sites evaluated ; (3) the suggested siting loc ation for the cooling towers was characterized as sufficientl y large (with equipment relocations), however, it resulted in a less than desirable configuration8 (roughly perpendicular to prevailing winds); and (4) the study assumes that the new towers could replace the need for the existing cooling towers for cooling the bearing (which would be required to be demolished to make room), but recognized that it was unknown whether the use of salt water for these s ys tems could be tolerated. Most significantl y, ho wever, representatives noted that retrofitting the existing once

- through cooling s ys tems with cooling towers made little economic sense given the age and capacity utilization of each unit. In addition, because SGS is a municipal utility , retrofit funds wo uld require a rate increase and bond issuance that would have to be approved by the Los Angeles City Council. See Section 10 .0

. **7.0 Debris Handling**  Debris is not a significant issue at SGS due to the intake’s deep offshore location. Any debris captured on th e bar racks or traveling screens is disposed of in a landfill. **8.0 Repowering/Future Uses**  LADWP is considering the possibility of repowering Units 1 and 2 or Unit 3 by 201 5
. The state’s final once

- through cooling policy will likely

influence the options se le cted for an y repower project. **9.0 Cooling Ponds**  SGS does not use cooling ponds for condenser cooling. **10.0 Ownership**  LADWP is the largest municipally owned utility

in the country

with a service population of approximately 4 million people. LADWP maintains a total generating capacity

of approximately

7,200 MW from diverse portfolio of fossil, hydroelectric, renewable, and nuclear units. SGS is one of three LADWP

- owned facilities on the California coast that continues to use once

- through cool ing (together with the Harbor and Hay nes Generating Stations). As a vertically

integrated utility , LADWP owns and operates the generating, transmission and distribution sy stems that provide electricit y to a dedicated customer base. This transmission sy st em is not limited to the City of Los Angeles, but extends into Nevada, Utah, and Arizona. The s ys tem is used to import power to all locations (LADWP owned and power exc hanges with other utilities). T his differs from many investor owned utilities, such as Pacific Gas & Electric or Southern California Edison, which must rely on the open market to procure a significant portion of their electricity needs. LADWP must obtain approval from the Los Angeles City Council to implement any electricity

rate increases

. LADWP is in the process of developing a new IRP and is currentl y soliciting input from the public on this new guidance document.9 This new 2010 IRP will help set the course that LADWP will take in determining the best path to take for repowering the exi sting OTC facilities. 2 **11.0 316(a)**  Thermal discharges to surface waters are governed by the state’s Thermal Plan (1972), which creates separate requirements for new and existing thermal discharges to ocean waters. As an existing thermal discharger, SGS is sub ject to the Thermal Plan’s narrative requirement that an y thermal discharge must ensure protection of identified beneficial uses. This requirement is incorporated into the existing permit as a temperature limitation of no more than 100 ° F during normal op eration and 135 ° F during heat treatments. The facility does not have a 316(a) variance for thermal discharges and has complied with the existing limitation during its most recent permit cycle. **12.0 Ash Handling**  SGS does not generate any ash. **13.0 Air Emissions Co**  **ntrols** Each unit at SGS employs selective cataly tic reduction to minimize NOx emissions. **14.0 Additional Information**  Facilit y representatives noted that an ongoing legal battle over the availability of emission credits within the South Coast Air Quality Managem ent District have raised the possibility

that no new projects would be able to obtain the necessary air permits. This would include facilities retrofitted with wet cooling towers. SGS’s current NPDES permit, adopted in 2000, does not contain an y numeric or narrative limitations regarding impingement or entrainment due to cooling water withdrawals. The permit carries over findings from previous permits that essentially

concluded the SGS cooling water sy stem represented the “best technology

available” for compliance with 316(b)

. A lthough these determinations were made prior to the adoption of the state policy on once

- through cooling , future studies will determine whether this statement is still accurate or whether other technologies are available that would represent “best technology available” with costs that can be borne by industry

. SGS is required to conduct semi

- annual impingement monitoring coinciding with scheduled heat treatments. In addition to once

- through cooling water, SGS discharges a sma ll volume of wastewater from several low volume waste streams. These low volume wastes consist of cooling tower blowdown, boiler blowdown, floor drains, and settling basin discharges, and are commingled with once

- through cooling water prior to

2 At the site visit, facility representatives indicated that earlier drafts of the report included costs of between $35 and 310 million for cooling towers at Scattergood.10 discharge through the main outfall. All wastewater is discharged to Santa Monica Ba y through a submerged conduit terminating at a point 1,200 from shore. Metal cleaning wastes (chemical and non

- chemical) are ty pically captured in portable Baker tanks and treated off site. SGS must comply

with both water qualit y - based and technology

- based effluent limitations for its wastewater discharge to Santa Monica Bay

. In 1988, the State Water Board granted a variance to the total residual chlorine water quality standard for bi ofouling control in the cooling s ys tem. EPA granted a similar variance for the total residual chlorine effluent limitation applicable to steam electric facilities. It is not clear if these variances will be revisited in any future permit reissuance.

**At tachments**  Attachment A List of Attendees Attachment B Aerial Photos Attachment C Facilit y Flows Attachment D Alden Report for Phase II Compliance (December 2003) Attachment E Addendum to Alden Report for Phase II Compliance (May 2007) Attachment F Impingement Mortality and Entrainment Study

(November 2007) Attachment G Impingement Mortality and Entrainment Study

Appendices (November 2007) Attachment H Revisions Requested by LADWP11

**Attachment A --**  **List of Attendees** Paul Shriner, EPA Jan Matuszko, EPA John Kemmerer, EPA Region IX Tim Havey , Tetra Tech Kelly Meadows, Tetra Tech Mich ael Hanson, LADWP Hamid Nejad, LADWP Peter Rudd, LADWP Kim Burmahln, LADWP Susan Damron, LADWP Dipak Patel, LADWP Dawson Dong, LADWP Ian Guthrie, LADWP Katherine Rubin, LADWP See also Attachment A (DCN 10

- 6545A accompanying this document) for the sign

- in sheet.12 **Attachment B**

**—**

**Aerial Photos**  See also DCN 10

- 6545B accompanying this document.13 **Aerial View Looking West**

**Ground View Looking North Aerial View Looking Northeast** 14 **Attachment C --**  **Fa cility**  **Flows** Please see DCN 10

- 6545C accompanying this document. **Attachment D --**  **Alden Report for Phase II Compliance (December 2003)** Please see DCN 10

- 6545D accompan yi ng this document. **Attachment E --**  **Addendum to Alden Report for Phase II Compliance (May 2007)** Please see DCN 10

- 6545E accompan yi ng this document. **Attachment F**  **-- Im**  **pingement Mortality and Entrainment Study (November 2007 , Revised**  **)** Please see DCN 10

- 6545F accompan yi ng this document. **Attachment G**  **-- Im**  **pingement Mortality and Entrainment Study Appendic**  **es (November 2007**  **,**

**Revised )**  Please see DCN 10

- 6545G accompan yi ng this document.15 **Attachment H**

**— Revisions Requested by LADWP**  In their comment letter on the proposed rule, LADWP requested that EPA make certain revisions to the Scattergood site visit report in addition to their previous comments. These revisions are below. 1) Replacement for the first paragraph of section 14.0 (Additional Information). Instead of “Facility representatives noted that an ongoing legal battle over the availability of emission credits within the South Coast Air Quality Management District have raised the possibility that no new projects would be able to obtain the necessary air permits. This would include facilities retrofitted with wet cooling towers. ” the text should read

“ Permits from the AQMD for repowers of the existing units are viable since emission offsets are available on a megawatt for megawatt replacement of existing boilers with new, advanced gas turbine units. ” 2) Edits to the last paragraph of section 2. 0 (Facility Description) Instead of “SGS has a single two to three week outage annually and an eight to ten week outage every few ye ars for major projects.” the text should read “SGS has a single two to three week outage for each unit annually and an e ight to ten week outage for each unit every five to seven years for major projects.” 3) Edits to the first sentence of section 3.0 (Electricity Generation and Transmission) Instead of “SGS currentl y operates three conventional steam turbine units (Unit 1, Unit 2, and Unit 3) with a combined boilerplate generating capacit y of 8 20 MW ( Table 1 ).” The text sh ould read “SGS currentl y operates three conventional steam turbine units (Unit 1, Unit 2, and Unit 3) with a combined generating capacity of 8 20 MW ( Table 1 ).”16 4) Revisions to the first sentence of second paragraph of section 3.0 (Electricity Generation and Transmission) Instead of “Units 1 and 2 are conventional natural gas while Unit 3 is a supercritical natural gas unit.” The text should read “Units 1 and 2 use a conventional natural gas

- fired boiler while Unit 3 uses a supercritical natural gas - fired boiler.”