# 5.1 Air Quality
This section describes existing air quality conditions, maximum potential impacts from construction and operation of the new Ca rlsbad Energy Center Project (CECP), and mitigation measures that keep these impacts below thresholds of significance. The project will use natural gas-fired combined-cycle gas turbine technology to generate electricity efficiently and cleanly. Other beneficial environmental aspects of the pr oposed project that ensure that air quality impacts will not be significant include the following:

• Reduced air emissions by using cl ean-burning natural gas as fuel,

• Reduced nitrogen oxides (NO x 

### ) emissions with selective catalytic reduction (SCR) control systems and dry low- NO x 

### combustors on the gas turbines,

• Reduced emissions of carbon monoxide (CO) and toxic air contaminants with dry lowNO x 

### combustors and oxidation catalyst systems,

• Reduced emissions of particulate matte r through the use of dry cooling,

• Reduced emissions during gas turbine startups as compared with traditional combined cycle units with the use of quick start units, and

• Reduced ground-level concentrations of ex haust constituents with an appropriately sized exhaust stack. This section presents the methodology and resu lts of the air quality analyses performed to assess potential impacts associated with air emissions from construction and operation of the CECP. Potential public health risks posed by emissions of non-criteria pollutants are also addressed in Section 5.9, Public Health. Section 5.1.1 presents the air quality setting, including geography, topography, climate, and meteorology. Section 5.1.2 provides an overview of air quality standards and health effects. Section 5.1.3 discusses the criteria pollutants and existing air quality in the vicinity of the proposed project. The affected environment is analyzed in Section 5.1.4, and air quality regulatory agencies relevant to the project are identified, along with the Laws, Ordinances, Regulations, and Standards (LORS) that can affect the project and project conformance. Section 5.1.5 discusses the environmental consequences of emissions from the project and presents an overview of approaches for calc ulating facility impacts, modeling, and analysis. The screening health risk assessment, visibility screening analysis, and construction impacts analysis are also discussed. Section 5.1.6 di scusses compliance with LORS applicable to project. A discussion of cumulative effects is presented in Section 5.1.7. Mitigation for project air quality impacts is discussed in Sectio n 5.1.8. A list of references used in preparing the section is provided in Section 5.1.9.


# 5.1.1 Air Quality Setting The geography of the potential site, elevations of the surrounding landscape, long-term climatic characteristics, and short-term weathe r variations all have important effects on the

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### resulting ground-level pollutant concentrations that result from CECP air emissions. The effects of the land and atmospheric variables are discussed separately.



## 5.1.1.1 Geography and Topography The CECP will be located at the existing En cina Power Station site. The two new units (designated Units 6 and 7) will be on the nort heast area of the existing site, between the existing rail line and I-5 highway, and at the lo cation of three previously existing fuel oil tanks.



## 5.1.1.2 Climate and Meteorology The climate of San Diego County is subtropi cal with large-scale wind and temperature regimes controlled by the proximity of the Pa cific Ocean and seasonal migration of the Pacific high-pressure system. As a result, summe rs are relatively cool and winters are warm in comparison to other locations. Temperatur es below freezing occur infrequently, as do temperatures over 100 °F.
The amount of solar radiation is one factor influencing thermal turbulence; the more thermal turbulence, the more dispersion of pollu tants. The project area receives significant sunshine throughout the year, even during winter. Annual aver age sunshine is the percentage of maximum possible time the sun c an shine, and is approximately 68 percent in the San Diego area. Wind speed and direction are key factors in fluencing the dispersion and transport of pollutants. Wind flows on an annual basis are predominantly westerly. At Camp Pendleton, which is located approximately 10 kilometers north of the project and is the source of the meteorological data used in air dispersi on modeling (approved by the San Diego Air Pollution Control District [SDAPCD]), the mo st frequent wind direction is from the west-northwest during February though Octobe r, and from the northeast during November through January. Wind speeds average approx imately 7 miles per hour, and the maximum wind speed is approximately 29 miles per hour (NCDC, 1993). Appendix 5.1A contains the quarterly and annual wind roses and wind sp eed frequency tables for the three years, 2003 through 2005, used in the air dispersion modeling. Temperatures in the project area range from an average of 57oF in December and January to 72oF in August, and relative humidity averages 58 percent during the daytime and 74 percent during the nighttime. Precipitation in the vicinity of the project site averages approximately 10.6 inches per year, with most of the precipitation occurring during winter 1



### . Air quality is determined primarily by the ty pe and amount of pollutants emitted into the atmosphere, the topography of the air basin, and local meteorological conditions. The stable atmospheric conditions and light winds in the project area are conducive for accumulation of pollutants in the air basin. The predominant winds over all of California are shown in Figures 5.1-1 through 5.1-4 for January, April, July, and October, respective ly. As indicated in the figures, winds in

1 WorldClimate. Average Rainfall for San Diego Lindbergh, San Die go County, California, USA, taken from NCDC Cooperative Stations for the 46 years 1950 through 1995, http://www. worldclimate.com/cgi-bin/data.pl?ref=N32W117+2200+047740C, accessed January 15, 2006.

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### California generally are light and easterly in the winter, but strong and westerly in the spring, summer, and fall.


# 5.1.2 Overview of Air Quality Standards The U.S. Environmental Protection Agency (USEPA) has established national ambient air quality standards (NAAQS) for ozone, nitrogen dioxide (NO 2 

### ), carbon monoxide (CO), sulfur dioxide (SO 2 

### ), particulate matter with aerodynamic diameter less than or equal to 10 microns (PM 10 

### ), particulate matter with aerodynamic diameter less than or equal to 2.5 microns (PM 2.5 

### ), and airborne lead. Areas with ambi ent levels above these standards are designated by USEPA as “nonattainment areas” subject to planning and pollution control requirements that are more stri ngent than standard requirements. The California Air Resources Board (CARB) has established California ambient air quality standards for ozone, CO, NO 2 

### , SO 2 

### , sulfates, PM 10 

### , PM 2.5 

### , airborne lead, hydrogen sulfide, and vinyl chloride at levels designed to protect the most sensitive members of the population, particularly children, the elderly, and people who suffer from lung or heart diseases. Both state and national air quality standards consist of two parts: an allowable concentration of a pollutant, and an averaging time over wh ich the concentration is to be measured. Allowable concentrations are based on the result s of studies of the effects of the pollutants on human health, crops and vegetation, and, in some cases, damage to paint and other materials. The averaging times are based on wh ether the damage caused by the pollutant is more likely to occur during exposures to a high concentration for a short time (one hour, for instance), or to a relatively lower average co ncentration over a longer period (8 hours, 24 hours, or 1 month). For some pollutants there is more than one air quality standard, reflecting both short-term and long-term effects. Table 5.1-1 presents the NAAQS and California ambient air quality standards for sele cted pollutants. The California standards are generally set at concentrations lower than the federal standards and, in some cases, have shorter averaging periods. USEPA’s current NAAQS for ozone and fine particulate matter went into effect on September 16, 1997. For ozone, the previous federal one-hour standard of 0.12 parts per million (ppm) was replaced by an eight-hour average standard at a level of 0.08 ppm. Compliance with this standard is based on the three-year aver age of the annual 4th-highest daily maximum eight-hour averag e concentration measured at each monitor within an area. The NAAQS for particulates were revised in several respects. First, compliance with the current 24-hour PM 10 

### standard is now based on the 99th percentile of 24-hour concentrations at each monitor within an area. Two new PM 2.5 

### standards were added: a standard of 15 μ g/m 3 

### , based on the three-year average of an nual arithmetic means from single or multiple monitors (as available); and a standard of 35 μ g/m 3 

### , based on the three-year average of the 98th percentile of 24-hour aver age concentrations at each monitor within an area. Finally, the state adopted a new, lower annual PM 10 

### standard of 20 μ g/m 3 

### . The state PM 2.5 

### standard is 12 μ g/m 3 

### on an annual average basis. On April 28, 2005, CARB approved a new 8-hour ozone standard of 0.070 ppm; this new standard became effective on May 17, 2006. Finally, on February 22, 2007, CARB approved a new 1-hour NO 2 

### standard of 0.18 ppm; final approval of this new standard is expected to occur later in the year.

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TABLE 5.1-1 

### Ambient Air Quality Standards
Pollutant Averaging Time California National

1 hour 0.09 ppm — Ozone
8 hours 0.070 ppm 0.08 ppm a
8 hours 9.0 ppm 9 ppm Carbon Monoxide 1 hour 20 ppm 35 ppm Annual Average 0.030 ppm 0.053 ppm Nitrogen Dioxide 1 hour 0.18 ppm — Annual Average — 80 μg/m 3 (0.03 ppm)
24 hours 0.04 ppm (105 μg/m 3 ) 365 μg/m 3 (0.14 ppm)
3 hours — 1300 b μg/m 3 (0.5 ppm) Sulfur Dioxide

1 hour 0.25 ppm — Annual Arithmetic Mean 20 μg/m 3 50 μg/m 3 Respirable Particulate Matter (10 Micron) 24 hours 50 μg/m 3 150 μg/m 3
70 μg/m 3 (proposed by

USEPA, Dec 20, 05)
Annual Arithmetic Mean 12 μg/m 3 15 μg/m 3 (3-year average) Fine Particulate Matter (2.5 Micron) 24 hours — 35 μg/m 3 c

Sulfates 24 hours 25 μg/m 3 — 30 days 1.5 μg/m 3 — Lead Calendar Quarter — 1.5 μg/m 3 Hydrogen Sulfide 1-hour 0.03 ppm — Vinyl Chloride 24-hour 0.010 ppm — Visibility Reducing Particles 8-hour (10am to 6pm PST) d —

Notes:

a 3-year average of annual 4th-highest daily maximum.

b This is a national secondary standard, whic h is designed to protect public welfare.

c 3-year average of 98th percentiles.

d In sufficient amount to produce an exti nction coefficient of 0.23 per kilomete r due to particles when the relative humidity is less than 70%.


# 5.1.3 Existing Air Quality Data from several ambient air monitoring statio ns were used to characterize air quality for the CECP site. The Camp Pendleton monitoring station is the nearest ambient air quality monitoring station to the project site. This monitoring station is located approximately 19 kilometers to the northeast from the project site. However, because the Camp Pendleton station only measures ambient ozone and NO 2 

### levels, for CO, PM 10 

### , and PM 2.5 

### data collected at the Escondido monitoring station were used. The Escondido monitoring station is located approximately 24 kilometers to the east from the project site. For ambient SO 2 

### levels, the

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### nearest monitoring station is located in San Diego approximately 55 kilometers to the south from the project site. The neares t sulfate monitor is located in Riverside, Riverside County (approximately 90 kilometers to the northeast fr om the project site). Sulfate measurements at most monitoring stations in California were discontinued years ago because sulfur dioxide emissions are low enough to prevent sulfate levels from being anywhere near the California ambient air quality standard of 25 μ g/m 3 

### on a 24-hour average basis. All ambient air quality data presented in this section were taken from CARB publications and data sources or USEPA air quality data tables.



## 5.1.3.1 Ozone Ozone is generated by a complex series of chemical reactions between volatile organic compounds (VOC) and NO x 

### in the presence of ultraviolet radiation. Ambient ozone concentrations follow a seasonal pattern: higher in the summertime and lower in the wintertime. At certain times, the general area can provide ideal conditions for the formation of ozone due to the persistent temperature invers ions, clear skies, mountain ranges that trap the air mass, and exhaust emissions from millions of vehicles and stationary sources. Based upon ambient air measurements at stations throughout the area, San Diego County is classified as a serious nonattainment area 2 

### for the state ozone standard and a nonattainment area for the federal 8-hour ozone standard. Maximum ozone concentrations at the Camp Pe ndleton station usually are recorded during the spring and fall months. Table 5.1-2 shows the annual maximum hourly ozone levels recorded at this station during the period 1997 through 2006, as well as the number of days in which the state and federal standards were exceeded.

TABLE 5.1-2 

### Ozone Levels in San Diego County, Camp Pendleton Monitoring Station, 1997-2006 (ppm )

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Highest 1-Hour Average 0.120 0.113 0. 098 0.109 0.113 0.087 0. 099 0.110 0.090 0.086
Highest 8-Hour Average 0.096 0.096 0. 086 0.099 0.098 0.073 0. 084 0.095 0.074 0.073
Number of Days Exceeding:

State Standard (0.090 ppm, 1-hour) 10 9 1 2 2 0 4 4 0 0

State Standard (0.070 ppm, 8-hour) 3 5 1 2 1 1 0 2 1 1

Federal Standard (0.080 ppm, 8-hour) 3 5 1 2 1 0 1 2 0 0

Source: California Air Quality Data, California Air Resources Board website (http://www.arb.ca.gov/adam/welcome.html; EPA AIRData website. http://www.epa.gov/air/data/index.html

.

2 Serious nonattainment is of “mid-range” magnitude in a nonatta inment classification system based on the amount by which monitored levels of ozone have exceeded ambient air quality standard during the last 3 ye ars. The classification, in order of increasing magnitude, includes marginal, moderate, serious, severe, and extreme.

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### The long-term trends of maximum one-hour ozon e readings and violations of the state and federal standard are shown in Figure 5.1-5 for this monitoring station. The data show that, on average, the state ozone standards have been exceeded in 9 of the past 10 years. The federal 8-hour ozone standard has been exceeded in 7 of the past 10 years. Trends of maximum and 3-year average of the 4th highes t daily concentrations of 8-hour average ozone readings and exceedances of the federal standard are shown in Figure 5.1-6.



## 5.1.3.2 Nitrogen Dioxide Atmospheric NO 2 

### is formed primarily from reactions between nitric oxide (NO) and oxygen or ozone. NO is formed during high temperature combustion processes, when the nitrogen and oxygen in the combustion air combin e. Although NO is less harmful than NO 2 

### , it can be converted to NO 2 

### in the atmosphere within minutes to hours, depending on the composition and temperature of the atmosphere. For purposes of state and federal air quality planning, San Diego County is in attainment for NO 2 

### . Table 5.1-3 shows the long-term trend of maximum one-hour NO 2 

### levels recorded at the Camp Pendleton monitoring station during th e period from 1997 to 2006, as well as the annual average level for each of those years. During this period there has not been a single violation of either the state one-hour stand ard or the federal annual average standard. Figure 5.1-7 shows the historical trend of maximum one-hour NO 2 

### levels at this monitoring station. Annual average concentrations and trends are shown in Figure 5.1-8.

TABLE 5.1-3 

### Nitrogen Dioxide Levels in San Diego County, Ca mp Pendleton Monitoring Station, 1997-2006 (PPM)

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Highest 1-Hour Average 0.134 0.085 0. 157 0.117 0.092 0.109 0. 095 0.099 0.077 0.081 Annual Average (State Standard = 0.030 ppm) (Federal Standard = 0.053 ppm) 0.012 0.012 0.014 0.014 0.013 0.013 0.012 0.012 0.012 0.011

Number of Days Exceeding:

State Standard (0.180 ppm, 1-hour) 0 0 0 0 0 0 0 0 0 0

Source: California Air Quality Data, California Air Resource s Board website (http://www.arb.ca.gov/adam/welcome.html; EPA AIRData website (http://www.epa.gov/air/data/index.html).



## 5.1.3.3 Carbon Monoxide CO is a product of inefficient combustion, pr incipally from automobiles and other mobile sources of pollution. In many areas of California, CO emissions from wood-burning stoves and fireplaces can also be measurable contributors to ambient CO levels. Industrial sources typically contribute less than 10 percent of ambi ent CO levels. Peak CO levels usually occur during winter due to a combi nation of higher emission rates and calm weather conditions with strong, ground-based inversions. San Diego County is classified as an attainment area for CO with respect to both state and national standards.

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### Table 5.1-4 shows the California and National Ambient Air Quality Standards for CO, and the maximum one- and eight-hour average leve ls recorded at the Escondido monitoring station during the period 1997 through 2006.

TABLE 5.1-4 

### Carbon Monoxide Levels in San Diego County, Escondido Monitoring Station, 1997-2006 (PPM)
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Highest 1-hour average 9.3 10.2 9.9 9.3 8.5 8.5 12.7 6.3 5.9 5.7 Highest 8-hour average 4.9 4.5 5.3 4.9 5.1 3.9 10.6 3.8 3.1 3.6 Number of days exceeding:

State Standard (20.0 ppm, 1-hr) 0 0 0 0 0 0 0 0 0 0

State Standard (9.0 ppm, 8-hr) 0 0 0 0 0 0 1 0 0 0

Federal Standard (9.3 ppm, 8-hr) 0 0 0 0 0 0 1 0 0 0

Source: California Air Quality Data, Ca lifornia Air Resources Board website http://www.arb.ca.gov/adam/welcome.html ; EPA AIRData website http://www.epa.gov/air/data/index.html

.



### Trends of maximum one- and eight-hour average CO concentrations are shown in Figures 5.1-9 and 5.1-10, which show that, wi th the exception of 2003, maximum ambient CO levels monitored at the Escondido station have been well below the state standards for the last 10 years.



## 5.1.3.4 Sulfur Dioxide SO 2 

### is produced when any sulfur-containing fuel is burned. It is also emitted by chemical plants that treat, or refine, sulfur or sulfur-c ontaining chemicals. Natural gas contains only a small amount of sulfur, typically about 0.2 grai ns per standard cubic foot, while fuel oils contain larger amounts, typically in the range of 15 ppm (for ultra-low sulfur Diesel fuel) to 4 percent (for marine bunker fuels). Peak, but low, concentrations of SO 2 

### occur at different times of the year in different parts of California, depending on local fuel characteristics, weather, and topography. San Diego County is considered to be in attainment for SO 2 

### for purposes of state and federal air quality planning. Table 5.1-5 presents the state air quality standard for SO 2 

### and the maximum levels recorded from 1997 through 2006 at the San Diego monitori ng station. The federal 24-hour average standard is 0.14 ppm; during the period shown, the average SO 2 

### levels measured at this station have been less than approximately 20 pe rcent of the federal standard. Figure 5.1-11 shows that for several years the maximum 24-hour SO 2 

### levels typically have been less than approximately one-half of the state standard.

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TABLE 5.1-5 

### Sulfur Dioxide Levels in san Diego County, San Diego Monitoring Station, 1997-2006 (PPM)

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Highest 1-Hour Average 0.052 0.040 0. 039 0.038 0.052 0.028 0. 036 0.042 0.040 0.034
Highest 3-Hour Average 0.032 0.037 0. 025 0.029 0.036 0.015 0. 019 0.020 0.026 0.030
Highest 24-Hour Average 0.011 0.011 0.008 0.010 0.010 0.007 0.008 0.009 0.009 0.009
Annual Average (Federal Standard = 0.030 ppm) 0.003 0.003 0.002 0.004 0.003 0.003 0.005 0.004 0.003 0.004

Number of days exceeding:

State Standard (0.040 ppm, 24-hr) 0 0 0 0 0 0 0 0 0 —

Federal Standard (0.140 ppm, 24-hr) 0 0 0 0 0 0 0 0 0 0

Source: California Air Quality Data, California Air Resources Board website (http://www.arb.ca.gov/adam/welcome.html; EPA AIRData website (http://www. epa.gov/air/data/index.html).



## 5.1.3.5 Respirable Particulate Matter (PM 10



## ) Particulates in the air are caused by a combi nation of wind-blown fugitive dust; particles emitted from combustion sources and manufacturing processes; sea salts; and organic, sulfate, and nitrate aerosols formed in the ai r from emitted hydrocarbons, sulfur oxides, and nitrogen oxides, respectively. In 1984, CARB adopted standards for PM 10 

### and phased out the total suspended particulate (TSP) standards that had been in effect previously. PM 10 

### standards were substituted for TSP standards because PM 10 

### corresponds to the size range of particulates that can be inhaled into the lungs (respired), and therefore is a better measure to use in assessing potential health effects. In 1987, USEPA also replaced national TSP standards with PM 10 

### standards. San Diego County is unclassified for the federal PM 10 

### standard and is a nonattainment area for the state standard. Table 5.1-6 shows the federal and state air quality standards for PM 10 

### , maximum levels recorded at the Escondido monitoring station during 1997 through 2006, and arithmetic annual averages for the same period. The maximum 24-hour PM 10 

### levels exceed the state standard for several years, but the annual average PM 10 

### levels have remained below the Federal standards throughout the period. The trend of maximum 24-hour average PM 10 

### levels is plotted in Figure 5.1-12, and the trend of expected violations of the state 24-hour standard (50 μ g/m 3 

### ) is plotted in Figure 5.1-13. Note that since PM 10 

### is measured only once every six days, expected violation days are six times the number of measured violations. The trend of maximum annual average PM 10 

### readings and the California standard is shown in Figure 5.1-14. Annual average PM 10 

### concentrations are abov e the state standard of 20 μ g/m 3



### .

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TABLE 5.1-6 

### PM 10 

### Levels in San Diego County, Escondido Monitoring Station, 1997-2006 ( μ g/m 3 

### )

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Highest 24-Hour Average 63 51 52 65 74 51 179 57 42 51
Annual Arithmetic Mean (State Standard = 20 μg/m3) 29 19 30 30 31 27 33 28 24 24

Number of Days Exceeding: State Standard (50 μg/m3, 24-hour) 19 — 0 12 13 0 31 6 0 6

Federal Standard (150 μg/m3, 24-hour) 0 — 0 0 0 0 3 0 0 0

Source: California Air Quality Data, California Air Resources Board website http://www.arb.ca.gov/adam/welcome.html ; EPA AIRData website http://www.epa.gov/air/data/index.html

.



## 5.1.3.6 Fine Particulate Matter (PM 2.5



## ) As discussed previously, the NAAQS for partic ulates were further revised by USEPA with new standards that went into effect on September 16, 1997; two new PM 2.5 

### standards were added at that time. In June 2002, CARB established a new annual standard for PM 2.5 

### . PM 2.5 

### data have been collected at the Escondido mo nitoring station since 1999, and are presented below. Table 5.1-7 shows the state and federal air quality standards for PM 2.5 

### , maximum levels recorded at the Escondido monitoring station 1999 through 2006, and 3-year averages for the same period. During the past 10 years, the 24-hour average concentrations have not exceeded the federal standard of 65 μ g/m 3 

### established in 1997. However, this standard was reduced to 35 μ g/m 3 

### in December 2006. There is not en ough data available to draw conclusions regarding trends in the 3-year aver age of 98th percentile values. During the past 5 years annual average PM 2.5 

### levels have generally been below the federal and above the state standards. San Diego County is considered a nonattainment area for the state PM 2.5 

### standard, but is unclassified for the federal standard. The trends of 24-hour and annual average PM 2.5 

### levels are plotted in Figures 5.1-15 and 5.1-16, respectively.

TABLE 5.1-7 

### PM 2.5 

### Levels in San Diego County, Escondido Monitoring Station, 1997-2006 ( μ g/m 3 

### )

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Highest 24-Hour Average — — 64. 0 66.0 60.0 54.0 38. 0 67.0 43.0 41.0 Number of Days Exceeding:
Federal Standard (65 μg/m3, 24-hour) 0 0 0 0 0 0 0 0 0 0
(35 μg/m3, 24-hour effective December 17, 2006) — — — — — — — — — —

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TABLE 5.1-7 

### PM 2.5 

### Levels in San Diego County, Escondido Monitoring Station, 1997-2006 ( μ g/m 3 

### )

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
98th Percentile — — 45.0 48. 0 41.0 39.0 34.0 37.0 32.0 28.0 3-yr Average, 98th Percentile — — — — 44.7 42.7 38.0 36.7 34.3 32.3

Annual Arithmetic Mean — — 18. 0 15.8 17.5 16.0 14. 1 14.1 12.3 11.5 3-yr Annual Average (Federal Std = 15 μg/m3) (State Std = 12 μg/m3) — — — — 17.1 16.4 15.9 14.7 13.5 12.6

Source: California Air Quality Data, California Air Resources Board website (http://www.arb.ca.gov/adam/welcome.html; EPA AIRData website (http://www. epa.gov/air/data/index.html).



## 5.1.3.7 Airborne Lead The majority of lead in the air results from the combustion of fuels that contain lead. Twenty-five years ago, motor gasoline contained relatively large amounts of lead compounds used as octane-rating improvers, and ambient lead levels were relatively high. Beginning with the 1975 model year, new auto mobiles began to be equipped with exhaust catalysts, which were poisoned by the exhaust products of leaded gasoline. Thus, unleaded gasoline became the required fuel for an incr easing fraction of new vehicles, and the phase-out of leaded gasoline began. As a result , ambient lead levels decreased dramatically. San Diego County has been in attainment of state and federal airborne lead levels for air quality planning purposes for a number of years. The ambient lead levels were monitored in San Diego until the end of 2004. Table 5.1-8 lists the federal air quality standard for airborne lead and the levels recorded in San Diego between 1997 and 2004. Maximum quarterly levels are well below the federal standard. 3

TABLE 5.1-8 

### Airborne Lead Levels in San Diego County, San Diego Monitoring Station, 1997-2006 ( μ g/m 3 

### )

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Highest Quarterly Average 0.03 0.02 0.02 0. 02 0.02 0.02 0.01 — — — Number of Days Exceeding:

Federal Standard (1.5 μg/m3, quarterly) 0 0 0 0 0 0 0 — — —
Source: California Air Quality Data, Ca lifornia Air Resources Board website (http://www.arb.ca.gov/adam/welcome.html; EPA AIRDa ta website (http://www.epa.gov/air/data/index.html).

3 ARB no longer reports summary lead statistics on its website.

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# 5.1.4 Affected Environment The USEPA has responsibility for enforcing, on a national basis, the requirements of many of the country’s environmental and hazardous waste laws. California is under the jurisdiction of USEPA Region 9, which has its offices in San Francisco. Region 9 is responsible for the local administration of USEPA programs for California, Arizona, Nevada, Hawaii, and certain Pacific trust terri tories. USEPA’s activities relative to the California air pollution control program focus principally on reviewing California’s submittals for the State Implementation Plan (SIP ). The SIP is required by the federal Clean Air Act to demonstrate how all areas of the st ate will meet the national ambient air quality standards within the federally specified deadlines (42 USC §7409, 7411). CARB was created in 1968 by the Mulford-Carre ll Air Resources Act, through the merger of two other state agencies. CARB’s primary respon sibilities are to develop, adopt, implement, and enforce the state’s motor vehicle pollution control program; to administer and coordinate the state’s air pollution research prog ram; to adopt and update, as necessary, the state’s ambient air quality standards; to review the operations of the local air pollution control districts; and to review and coordinate preparation of the SIP for achievement of the federal ambient air quality standards (California Health & Safety Code (H&SC) §39500, et seq.). When the state’s air pollution statutes were reorganized in the mid-1960s, local air pollution control districts (APCDs) were required to be established in each county of the state (H&SC §4000 et seq.). There are three different types of districts: county, regional, and unified. In addition, special air quality management districts (AQMDs), with more comprehensive authority over non-vehicular so urces, as well as transportation and other regional planning responsibilities, have been established by the Legislature for several regions in California. Air pollution control districts and air qual ity management districts in California have principal responsibility for:

• Developing plans for meeting the state and federal ambient air quality standard;

• Developing control measures for non-vehicular sources of air pollution necessary to achieve and maintain both state and federal air quality standards;

• Implementing permit programs established for the construction, modification, and operation of sources of air pollution; and

• Enforcing air pollution statutes and regulati ons governing non-vehicular sources and for developing employer-based trip reduction programs. Each level of government (state, federal, and county/local air district) has adopted specific regulations that limit emissions from stationar y combustion sources, several of which are applicable to this proposed project. The air agencies having permitting authority for this project are shown in Table 5.1-9. The applicab le federal laws, ordinances, regulations, and standards (LORS) and compliance with these re quirements are discussed in more detail in the following sections. The SDAPCD staff will treat the Application for Certification (AFC) as an application for a Determination of Compliance.

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TABLE 5.1-9 

### Air Quality Agencies Agency Authority Contact
USEPA Region 9 Permit issuance and oversight, enforcement Gerardo Rios, Chie f Permits Office USEPA Region 9 75 Hawthorne Street San Francisco, CA 94105 (415) 744-1259

California Air Resources Board Regulatory oversight Mike Tollstrup, Chief Project Assessment Branch California Air Resources Board 2020 L Street Sacramento, CA 95814 (916) 322-6026
San Diego Air Pollution Control District Permit issuance, enforcement Tom Weeks Chief, Engineering Division 10124 Old Grove Road San Diego, CA 92131 (858) 586-2600



# 5.1.5 Laws, Ordinances, Regulations, and Standards Requirements of federal, state, and local jurisdictions are discussed in the following Sections 5.1.4.1.1, 5.1.4.1.2, and 5.1.4.1.3, respectively. Compliance with each of these requirements is addressed in Section 5.1.6.



## 5.1.5.1 Federal LORS The USEPA implements and enforces the requirements of many of the federal environmental laws. USEPA Region 9, which ha s its offices in San Francisco, administers federal air programs in California. The federal Clean Air Act, as most recently amended in 1990, provides USEPA with the legal authority to regulate air pollution from stationary sources such as CECP. USEPA has promulgated the following stationary source regulatory programs to implement the requiremen ts of the Federal Clean Air Act:

• Prevention of Significant Deterioration (PSD);

• New Source Review (NSR);

• Title IV: Acid Rain Program;

• Title V: Operating Permits;

• National Standards of Performance for New Stationary Sources (NSPS) ; and

• National Emission Standards for H azardous Air Pollutants (NESHAPs).


## 5.1.5.1.1 Prevention of Significant Deterioration Program Authority: Clean Air Act §160-169A, 42 USC §7470-7491; 40 CFR Parts 51 and 52 Requirements: Requires pre-construction review and permitting of new or modified major stationary sources of air pollution to prevent significant deterior ation of ambient air quality. PSD applies to pollutants for which ambi ent concentrations do not exceed the

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### corresponding NAAQS (i.e., attainment pollutants). The PSD program allows new sources of air pollution to be constructed, or existing sources to be modified, while preserving the existing ambient air quality levels, protecting public health and welfare, and protecting Class I areas (e.g., national parks and wilderne ss areas). Although this program is normally implemented at the local level with federal ov ersight, it is presently implemented in San Diego by USEPA Region 9. The PSD regulation contains the following elements:

• Air quality monitoring

• BACT

• Air quality impact analysis

• Protection of Class I areas

• Growth, visibility, soils, and vegetation impacts


## 5.1.5.1.2 Air Quality Monitoring At its discretion, USEPA Region 9 may requir e pre-construction and/or post-construction ambient air quality monitoring for PSD sources if representative monitoring data are not already available. Pre-construc tion monitoring data must be gathered over a one-year period to characterize local ambient air qua lity. Post-construction air quality monitoring data must be collected as deemed necessary by USEPA Region 9 to characterize the impacts of proposed project emission s on ambient air quality.


## 5.1.5.1.3 Best Available Control Technology BACT must be applied to any new or modifi ed major source to minimize the emissions increase of those pollutants exceeding the PSD emission thresholds. BACT is defined below in the discussion of the SDAPCD NSR regulatory requirements.


## 5.1.5.1.4 Air Quality Impact Analysis An air quality dispersion analysis must be co nducted to evaluate impacts of significant emission increases from new or modified facilities on ambient air quality. PSD source emissions must not cause an exceedance of any ambient air quality standard, and the increase in ambient air concentrations must not exceed the allowable increments shown in Table 5.1-10.

TABLE 5.1-10 

### PSD Class II Increments *
Pollutant Averaging Period Allowable Increment( μ g/m 3 )
NO 2 Annual 25.0
SO 2 Annual 24-Hour 3-Hour 20.0 91.0 512.0
PM 10 Annual 24-Hour 17.0 30.0

+ 40 CFR 52.21.c.

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## 5.1.5.1.5 Protection of Class I Areas The increase in ambient air quality concentr ations for the relevant pollutants (i.e., NO 2 

### , PM 10, 

### or SO 2 

### ) within Class I areas located in the project area must be characterized if there is a significant emission increase associated with the new or modified PSD source. In addition, a Class I visibility impact analysis must also be performed.


## 5.1.5.1.6 Growth, Visibility, Soils, and Vegetation Impacts Impairment to visibility, soils, and vegetation resulting from PSD source emissions as well as associated commercial, residential, industri al, and other growth must also be analyzed. This analysis includes cumulative e ffects to local ambient air quality. As discussed in more detail below, the CECP includes the installation of two new gas turbine units and the shutdown of three exis ting boilers at the existing Encina Power Station. With the shutdown of the existing bo ilers, the facility-wide net emission change is expected to be below PSD significance threshol ds. Hence, the CECP is not subject to the PSD program. Administering Agency: USEPA Region 9.


## 5.1.5.1.7 New Source Review Authority: Clean Air Act §171-193, 42 USC §7501 et seq.; 40 CFR Parts 51 and 52 Requirement: Requires pre-construction review and permitting of new or modified major stationary sources of air pollution to allow in dustrial growth withou t interfering with the attainment and maintenance of NAAQS. New sour ce review jurisdiction has been delegated to the SDAPCD for all nonattainment pollutant s and is discussed further under local LORS and conformance below. Administering Agency: SDAPCD, with USEPA Region 9 oversight.


## 5.1.5.1.8 Acid Rain Program Authority: Clean Air Act §401 (Title IV), 42 USC §7651 Requirement: Requires the monitoring and reporting of emissions of acidic compounds and their precursors. The principal source of these compounds is the combustion of fossil fuels. Therefore, Title IV established national standards to monitor, record, and in some cases limit SO 2 

### and NO x 

### emissions from electrical power gene rating facilities. These standards are implemented at the local leve l with federal oversight. Administering Agency: SDAPCD, with USEPA Region 9 oversight.


## 5.1.5.1.9 Title V Operating Permits Program Authority: Clean Air Act §501 (Title V), 42 USC §7661 Requirements: Requires the issuance of operating pe rmits that identify all applicable federal performance, operating, monitoring, recordkeeping, and reporting requirements. Title V applies to major facilities, Phase II acid rain facilities, subject solid waste incinerator facilities, and any facility listed by USEPA as requiring a Title V permit. SDAPCD has received delegation authority for this program. Administering Agency: SDAPCD, with USEPA Region 9 oversight.

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## 5.1.5.1.10

5.1.5.1.11 National St andards of Performan ce for New Stationary Sources Authority: Clean Air Act §111, 42 USC §7411; 40 CFR Part 60 Requirements: Establishes standards of performance to limit the emission of criteria pollutants (air pollutants for which USEPA has established national ambient air quality standards [NAAQS]) from new or modified fac ilities in specific source categories. These standards are implemented at the local level wi th federal oversight. The applicability of these regulations depends on the equipmen t size, process rate, and/or the date of construction, modification, or reconstruction of the affected facility. The NSPS for Stationary Gas Turbines and for Stationary Compression Ig nition Internal Combustion Engines will be applicable to the proposed project. Regard ing the NSPS for Gas Turbines, the new NSPS Subpart KKKK, Standards of Performance for Stationary Gas Turbines (constructed after February 18, 2005), supersedes existing NSPS Subpart GG in setting limits on NO x 

### and sulfur dioxide (SO 2 

### ) emissions from gas turbines. Subpart KKKK limits NO x 

### and SO 2 

### emissions from new gas turbines based on powe r output. The limits for gas turbines greater than 30 MW are 0.39lb NO x 

### per MW-hr and 0.58lb SO 2 

### per MW-hr. For the size of engine proposed for the emergency firepump engi ne, the NSPS Subpart IIII, Standards of Performance for Stationary Compression Igniti on Internal Combustion Engines requires facilities to purchase engines meeting the USEPA engine non-road certification level of Tier II or better depending on the year the engine is manufactured/purchas ed. This regulation also requires the engines to use ul tra-low sulfur content Diesel fuel. Administering Agency: SDAPCD, with USEPA Region 9 oversight.


## National Em ission Standards for Hazardous Air Pollutants Authority: Clean Air Act §112, 42 USC §7412 Requirements: Establishes national emission standards to limit emissions of hazardous air pollutants (HAPs, or air pollutants identified by USEPA as causing or contributing to the adverse health effects of air pollution, but for which NAAQS have not been established) from major sources of HAPs in specific source categories. 4 

### These standards are implemented at the local level with federal ov ersight. Only the NESHAPs for gas turbines, which limit formaldehyde emissions from gas tu rbines, are potentially applicable to a new power plant project. However, as discussed fu rther below, the gas turbine NESHAP is not expected to be applicable to the proposed pr oject because the facility would not be a major source of HAPs (i.e., 10 tpy of one HAP or 25 tpy of all HAPs). Thus, NESHAPs requirements will not be addressed further. Administering Agency: SDAPCD, with USEPA Region 9 oversight.



## 5.1.5.2 State LORS CARB was created in 1968 by the Mulford-Carre ll Air Resources Act, through the merger of two other state agencies. CARB’s primary respon sibilities are to develop, adopt, implement, and enforce the state’s motor vehicle pollution control program; to administer and coordinate the state’s air pollution research prog ram; to adopt and update, as necessary, the California Ambient Air Quality Standards (CAAQS); to review the operations of the local air

4 A major source of HAPs is one that emits more than 10 tons pe r year (tpy) of any individual HAP, or more than 25 tpy of all HAPs combined.

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### pollution control districts (APCDs); and to review and coordinate preparation of the SIP for achievement of the NAAQS. CARB has impl emented the following state or federal stationary source regulatory programs in acco rdance with the requirements of the federal Clean Air Act and California Health & Safety Code (H&SC):

• State Implementation Plan

• California Clean Air Act

• Toxic Air Contaminant Program

• Airborne Toxic Control Measure for St ationary Compression-Ignition Engines

• Nuisance Regulation

• Air Toxics “Hot Spots” Act

• CEC and CARB Memorandum of Understanding


## 5.1.5.2.1 State Implementation Plan (SIP) Authority: Health & Safety Code (H&SC) §39500 et seq. Requirements: The SIP demonstrates the means by wh ich all areas of the state will attain and maintain NAAQS within the federally mandated deadlines, as required by the federal Clean Air Act. CARB reviews and coordinates pr eparation of the SIP. Local districts must adopt new rules or revise existing rules to demonstrate that the resulting emission reductions, in conjunction with reductions in mobile source emissions, will result in attainment of the NAAQS. The relevant SDAPCD Rules and Regulations that have also been incorporated into the SIP are discussed with the local LORS in Section 5.1.4.1.3. Administering Agency: SDAPCD, with CARB and USEPA Region 9 oversight.


## 5.1.5.2.2 California Clean Air Act Authority: H&SC §40910 – 40930 Requirements: Established in 1989, the California Cle an Air Act requires local districts to attain and maintain both national and state ambient air quality standards at the “earliest practicable date.” Local districts must prepar e air quality plans demonstrating the means by which the ambient air quality standards will be attained and main tained. The relevant components of the SDAPCD Air Quality Plan are discussed with the local LORS. Administering Agency: SDAPCD, with CARB oversight.


## 5.1.5.2.3 Toxic Air Contaminant Program Authority: H&SC §39650 – 39675 Requirements: Established in 1983, the Toxic Air Contaminant Identification and Control Act created a two-step process to identify to xic air contaminants (TACs) and control their emissions. CARB identifies and prioritizes the pollutants to be considered for identification as toxic air contaminants. CARB assesses the po tential for human exposure to a substance, while the Office of Environmental Health Hazard Assessment evaluates the corresponding health effects. Both agencies collaborate in the preparation of a risk assessment report, which concludes whether a substance poses a significant health risk and should be identified as a toxic air contaminant. In 1993, the Legislature amended the program to

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### include the 187 5 

### federally identified hazardous air pollutants as toxic air contaminants. CARB reviews the emission sources of an identi fied toxic air contaminant and, if necessary, develops air toxics control measures to reduce the emissions. Administering Agency: CARB


## 5.1.5.2.4 Airborne Toxic Control Measure for Stationary Compression-Ignition Engines Authority: Title 17, California Code of Regulations, §93115 Requirements: The purpose of the airborne toxic co ntrol measure (ATCM) is to reduce diesel particulate matter (DPM) and criteria pollutant emissions from stationary diesel-fueled compression ignition engines. The ATCM applies to stationary compressionignition engines with a rating greater than 50 brake horsepower. The ATCM requires the use of CARB-certified diesel fuel or equivalent, and limits emissions from, and operations of, compression ignition engines. Administering Agency: SDAPCD and CARB


## 5.1.5.2.5 Nuisance Regulation Authority: CA Health & Safety Code §41700 Requirements: Provides that “no person shall dischar ge from any source whatsoever such quantities of air contaminants or other material which causes injury, detriment, nuisance, or annoyance to any considerable number of person s or to the public or which endanger the comfort, repose, health, or safety of any such persons or the public, or which cause, or have a natural tendency to cause injury or damage to business or property.” Administering Agency: SDAPCD and CARB


## 5.1.5.2.6 Air Toxic “Hot Spots” Act Authority: H& SC §44300-44384; 17 CCR §93300-93347 Requirements: Established in 1987, the Air Toxics "Hot Spots" Information and Assessment Act supplements the toxic air contaminant pr ogram, by requiring the development of a statewide inventory of air toxics emissions fr om stationary sources. The program requires affected facilities to prepare: (1) an emissions inventory plan that identifies relevant air toxics and sources of air toxics emissions; (2) an emissions inventory report quantifying air toxics emissions; and (3) a health risk assessme nt, if necessary, to characterize the health risks to the exposed public. Facilities whose air toxics emissions are deemed to pose a significant health risk must issue notices to the exposed population. In 1992, the Legislature amended the program to further require faciliti es whose air toxics emissions are deemed to pose a significant health risk to implement ri sk management plans to reduce the associated health risks. This program is implemented at the local level with state oversight. Administering Agency: SDAPCD and CARB


## 5.1.5.2.7 CEC and CARB Memorandum of Understanding Authority: CA Pub. Res. Code §25523(a); 20 CCR §1752, 1752.5, 2300-2309 and Div. 2, Chap. 5, Art. 1, Appendix B, Part (k)

5 Methyl ethyl ketone was removed from the list on December 19, 2005, http://www.epa.gov/ttn/atw/pollutants/atwsmod.html, accessed April 9, 2006).

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### Requirements: Provides for the inclusion of requirements in the CEC’s decision on an AFC to assure protection of environmental quality; the application is required to include information concerning air quality protection. Administering Agency: CEC



## 5.1.5.3 Local LORS When the state’s air pollution statutes were reorganized in the mid-1960s, local districts were required to be established in each county of the state. There are three different types of districts: county (including the SDAPCD), re gional, and unified. In addition, special air quality management districts (AQMDs), with more comprehensive authority over nonvehicular sources, as well as transportation and other regional planning responsibilities, have been established by the Legislature for se veral regions in California. Local districts have principal responsibility for the following:

• Developing plans for meeting the NAAQS and California ambient air quality standards;

• Developing control measures for non-vehicular sources of air pollution necessary to achieve and maintain both state and federal air quality standards;

• Implementing permit programs established for the construction, modification, and operation of sources of air pollution;

• Enforcing air pollution statutes and regulations governing non-vehicular sources; and

• Developing programs to reduce emissions from indirect sources.


## 5.1.5.3.1 San Diego Air Quality Plans Authority: H&SC §40914 Requirements: Air quality plans define the proposed strategies, including stationary source and transportation control measures and new so urce review rules that will be implemented to attain and maintain the state ambient air quality standards. The relevant stationary source control measures and new source revi ew requirements are discussed with SDAPCD Rules and Regulations. Administering Agency: SDAPCD with USEPA Region 9 and CARB oversight.


## 5.1.5.3.2 San Diego Air Pollution Control Di strict Rules and Regulations Authority: H&SC §4000 et seq., H&SC §40200 et seq., indicated SDAPCD Rules Requirements: Establishes procedures and standards for issuing permits; establishes standards and limitations on a source-specific basis. Administering Agency: SDAPCD with USEPA Region 9 and CARB oversight.


## 5.1.5.3.3 Authority to Construct Rule 10 (Permits Required) specifies that any facility installing nonexempt equipment that causes or controls the emission of air pollut ants must first obtain an Authority to Construct from the SDAPCD. Under Rule 20.5 (h) (Power Pl ants), the District’s Final Determination of Compliance acts as an authority to construc t for a power plant upon approval of the proposed project by the CEC.

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## 5.1.5.3.4 Review of New or Modified Sources Rule 20.3 (New Source Review, Major Stationar y Sources and PSD Sources) implements the federal NSR and PSD programs, as well as th e new source review requirements of the California Clean Air Act. The rule contains the following elements:

• Best Available Control Technology (BACT) and Lowest Achievable Emission Rates (LAER)

• Emission offsets

• Air quality impact analysis (AQIA)


## 5.1.5.3.5 Best Available Control Technology BACT must be applied to any new or modified source resulting in an emissions increase exceeding any SDAPCD BACT threshold shown in Table 5.1-11.

TABLE 5.1-11 

### SDAPCD BACT and LAER Emission Thresholds

Pollutant BACT Threshold (lb/day) LAER Major Source Threshold (tpy) LAER Major Modification Threshold (tpy)
CO N/A a N/A b N/A b

NO x 10 50 25
PM 10 10 100 15
SO 2 10 100 40
VOC 10 50 25
Notes:

a SDAPCD regulates BACT for CO under the PSD component of Rule 20.3

b CO is an attainment pollutant, and henc e, not subject to LAER requirements


### The SDAPCD defines BACT as the most string ent emission limitation or control technique that:

• Has been proven in field applic ation and that is cost-effective unless not achievable ; or

• Has been demonstrated, but not necessarily proven, in field applications, and that is cost-effective; or

• Is any control equipment, process modifica tion, changes in raw material including alternate fuels, and substitution of equipment or processes with any equipment or processes (or any combination of these) determined to be technologically feasible and cost-effective; or

• Is contained in any SIP approved by USEP A for such emission unit category, unless demonstrated to not be proven in field application, not be technologically feasible, or not be cost-effective. LAER must be applied to any federal nonattainment pollutants (or their precursors) at new major sources or major modifications ex ceeding any emission threshold shown in Table 5.1-11. LAER is more stringent than BACT because it does not contain restrictions for

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### cost-effectiveness. Only NO x 

### and VOCs are federal nonattainment precursors in SDAPCD and, therefore, potentially subject to LAER. The SDAPCD defines LAER as:

• The most stringent emission limitation that is achieved in practice by such class or category of emission unit; or

• The most stringent emission limitation, or most effective emission control device or technique, contained in any SIP approved by the USEPA for such emission unit class or category unless demonstrated to not be achievable; or

• BACT.


## 5.1.5.3.6 Emission Offsets A new or modified source resulting in emissi on increases above the major source or major modification emission thresholds, as shown in Table 5.1-12, must offset emission increases of federal nonattainment pollutants (and their pr ecursors) at a ratio of 1.2-to-1. If existing equipment is shut down at a source as part of a facility modification, the reductions in emissions from those shutdowns are subtracted from the increases associated with the new equipment to determine the net emissions increa se subject to offset requirements. San Diego County is classified as a federal nonattainment area for the 8-hour ozone standard. Therefore, emissions of NO x 

### and VOCs, as precursors to ozone are subject to the emission offset requirements. VOC emission reductions may be used to offset NO x 

### emission increases at an offset ratio of 2 to 1.

TABLE 5.1-12 

### SDAPCD Offset Emission Thresholds

Pollutant Major Source Threshold a , tpy Major Modification Threshold b , tpy

NO x 50 25
SO x N/A c N/A c

CO N/A c N/A c

VOC 50 25

PM 10 N/A c N/A c

Notes:

a SDAPCD Regulation II, Rule 20.1, Table 20.1-6

b SDAPCD Regulation II, Rule 20.1, Table 20.1-5

c Not applicable because CO, SO x , and PM 10 are federal attainment pollutants, and hence, are not subject to offset requirements.



## 5.1.5.3.7 Air Quality Impact Analysis (AQIA) An AQIA must be conducted to evaluate im pacts on ambient air quality of emission increases from new or modified projects exceeding any AQIA threshold shown in Table 5.1-13. Project emissions must not cause a new exceedance or contribute significantly to an existing exceedance of any ambient air quality standard.

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TABLE 5.1-13 

### SDAPCD AQIA Emission Thresholds * Emission Thresholds Pollutant lb/hr lb/day tpy
CO 100 550 100
NO x 25 250 40
PM 10 N/A 100 15
SO x 25 250 40 Note: * SDAPCD Regulation II, Rule 20.3, Table 20.3-1.



## 5.1.5.3.8 Toxic Risk Management Rule 1200 (Toxic Air Contaminants, New So urce Review) provides a mechanism for evaluating the potential impact of toxic ai r contaminant (TAC, also called non-criteria pollutants) air emissions from new, modified, and relocated sources in the SDAPCD. The rule requires a demonstration that the so urce will not exceed the risk thresholds summarized in Table 5.1-14. As shown in this tabl e, there are different acceptable risk levels depending upon whether a project uses Toxics-Best Available Control Technology (T-BACT). The proposed CECP will use T-BACT with the use of natural gas, dry-low NO x 

### combustors, and installation of an oxidation catalyst system.

TABLE 5.1-14 

### SDAPCD Health Risk Thresholds Risk Criterion Risk Threshold
Cancer Risk with T-BACT 1 x 10-5
Cancer Risk without T-BACT 1 x 10 -6
Acute Noncarcinogenic Health Hazard Index 1 Chronic Noncarcinogenic Health Hazard Index 1



## 5.1.5.3.9 CEC Review Rule 20.5 establishes a procedure for coordinating SDAPCD review of power plant projects with the CEC’s AFC, and Small Power Plant Ex emption (SPPE) processes. Under this rule, the SDAPCD reviews the AFC/SPPE and issues a Determination of Compliance for a proposed project. Upon approval of the propos ed project by the CEC, this Determination of Compliance is equivalent to an Authority to Construct. A Permit to Operate is issued following demonstration of compliance with all permit conditions.


## 5.1.5.3.10 Prevention of Significant Deterioration Rule 20.3 (New Source Review, Major Stationar y Sources and PSD Sources) implements the federal NSR and PSD programs. Currently the PSD program in the SDAPCD is implemented by USEPA Region 9 based on th e federal version of the PSD regulations. Consequently the applicability of Rule 20.3 will not be discussed further.

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## 5.1.5.3.11

5.1.5.3.12

5.1.5.3.13

5.1.5.3.14

5.1.5.3.15

5.1.5.3.16

5.1.5.3.17

5.1.5.3.18 Acid Rain Pe rmit Rule 1412 (Federal Acid Rain Program Requirements) adopts, by reference, the federal requirements of 40 CFR Part 72, which requires that certain subject facilities comply with maximum operating emissions levels for SO 2 

### and NO x 

### , and monitor SO 2 

### , NO x 

### , and carbon dioxide emissions and exhaust gas flow rates. A Phase II acid rain facility, such as a new power plant project, must obtain an acid rain permit. A permit application must be submitted to the SDAPCD at least 24 months before operation of the new unit commences. The application must present all relevant Phase II sources at the facility, a compliance plan for each unit, applicable standards, and an estimated commencement date of operations. The proposed project will be a modification to an existing Phase II facility. Consequently, an application for a modification to the existing ac id rain permit will be submitted according to the timeframe discussed above. 

## Federal Ope rating Permit Rule 1414 (Applications) requires new or modifi ed major facilities, NSPS sources, NESHAP sources, and/or Phase II acid rain facilities to obtain an operating permit containing the federally enforceable requirements mandat ed by Title V of the 1990 Clean Air Act Amendments. A permit application for a new or modified source must be submitted to the SDAPCD within 12 months of commencing op eration. The application must present a process description, all new stationary source s at the facility, applicable regulations, estimated emissions, associated operating co nditions, alternative operating scenarios, a facility compliance plan, and a compliance cert ification. The proposed project will be a modification to an existing Title V facility. Consequently, an application for a modification to the existing Title V permit will be submitte d according to the timeframe discussed above.


## New Source P erformance Standards Regulation X (Standards of Performance for Ne w Stationary Sources) adopts, by reference, the federal standards of performance for new or modified stationary sources. The applicability of the New Source Performanc e Standards is discussed above under the Federal regulations.


## SDAPCD Pro hibitory Rules The general prohibitory rules of the SDAPCD a pplicable to the proposed project include the following:


## Rule 50 – Vis ible Emissions Prohibits visible emissions as dark as, or darker than, Ringelmann No. 1 for periods greater than three minutes in any hour.


## Rule 51 – Nui sance Prohibits the discharge from a facility of air pollutants that cause injury, detriment, nuisance, or annoyance to the public, or that damage business or property.


## Rule 52 – Par ticulate Ma tter Emission Standards Prohibits PM emissions in excess of 0.10 grai ns per dry standard cubic foot (gr/dscf).


## Rule 53 – Com bustion Contaminants Prohibits sulfur emissions, calculated as SO 2 

### , in excess of 0.05% by volume (500 parts per million by volume (ppmv), and combus tion particulate emissions in excess of 0.10 gr/dscf at 12 percent CO 2 

### .

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## 5.1.5.3.19

5.1.5.3.20

5.1.5.3.21 Rule 62 – Sul fur Content of Fuels Prohibits the burning of gaseous fuel with a sulfur content of more than 10 gr/100 scf and liquid fuel with a sulfur content of mo re than 0.05 percent sulfur by weight.


## Rule 69.3.1 – Stationary Gas Turbines Limits NO x 

### emissions from stationary gas turbines rated greater than or equal to 10 MW with post-combustion controls to 9 ppmv (at 15 percent O 2 

### , corrected for efficiency).


## Rule 69.4.1 – Stationary Recipro cating Internal Combustion Engines Limits CO, NO x 

### , and VOC emissions from stationary reciprocating internal combustion engines rated greater than or equal to 50 bhp. However, emergency equipment operating less than or equal to 52 hours per year for testing or maintenance purposes and less than or equal to 200 hours per year for any purpose are exempt from the emission limits of Rule 69.4.1. All applicable LORS are summarized in Table 5. 1-15 along with identification of the section that discusses compliance with each requirement.SECTION 5.1: AIR QUALITYTABLE 5.1-15Laws, Ordinances, Regulations, Standards and Permits for Protection of Air QualityLORSPurposeRegulatingAgencyPermit or ApprovalSchedule and Statusof PermitConformance(Sections)FederalClean Air Act (CAA) §160-169Aand implementing regulations,Title 42 United States Code(USC) §7470-7491 (42 USC§7470-7491), Title 40 Code ofFederal Regulations (CFR)Parts 51 & 52 (Prevention ofSignificant Deterioration Program)Requires prevention of significantdeterioration (PSD) review and facilitypermitting for construction of new ormodified major stationary sources ofair pollution. PSD review applies topollutants for which ambientconcentrations are lower than NAAQS.USEPAPSD Permit for a New MajorSource or major modification.CECP is exempt fromthis regulation.5.1.6.1CAA §171-193, 42 USC§7501 et seq. (New SourceReview)Requires new source review (NSR)facility permitting for construction ormodification of specified stationarysources. NSR applies to pollutants forwhich ambient concentration levelsare higher than NAAQS.SDAPCD withUSEPAoversightDetermination of Compliance(DOC) with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.1CAA §401 (Title IV), 42 USC§7651 (Acid Rain Program)Requires reductions in NOxand SO2emissions.SDAPCD withUSEPAoversightAcid Rain programrequirements included inDetermination of Compliance,Permit to Operate, and Title Vpermit.Meet compliancedeadlines listed inregulations.5.1.6.1CAA §501 (Title V), 42 USC§7661 (Federal Operating PermitsProgram)Establishes comprehensive permitprogram for major stationary sources.SDAPCD withUSEPAoversightModified Title V permit afterreview of application.Permit application tomodify existing Title Vpermit will besubmitted within12 months aftercommencement ofoperation.5.1.6.1CAA §111, 42 USC §7411,40 CFR Part 60 (New SourcePerformance Standards [NSPS])Establishes national standards ofperformance for new stationarysources.SDAPCD withUSEPAoversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.15.1-24EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC)SECTION 5.1: AIR QUALITYTABLE 5.1-15Laws, Ordinances, Regulations, Standards and Permits for Protection of Air QualityLORS PurposeRegulatingAgency Permit or ApprovalSchedule and Statusof PermitConformance(Sections)StateH&SC §44300-44384; CaliforniaCode of Regulations (CCR)§93300-93347 (Toxic "Hot Spots"Act)Requires preparation and biennialupdating of facility emission inventoryof hazardous substances; riskassessments.SDAPCD withCARB oversightDOC with conditions limitingemissions.Screening HRAsubmitted as part ofAFC.5.1.6.2California Public Resources Code§25523(a); 20 CCR§§1752, 2300-2309 (CEC andCARB Memorandum ofUnderstanding)Requires that CEC’s decision on AFCinclude requirements to assureprotection of environmental quality;AFC required to address air qualityprotection.CECFinal Certification withconditions limiting emissions.SDAPCD issuance ofDOC precedes CECapproval of AFC.5.1.6.217 CCR § 93115 (ATCM forStationary Compression IgnitionEngines)Establishes emission and operationallimits for diesel-fueled stationarycompression ignition engines.SDAPCD andCARBDOC with conditions limitingemissions and operation.Agency approval to beobtained before startof construction.5.1.6.2LocalSDAPCD Rule 20.3 (New SourceReview – Major StationarySources and PSD Sources)NSR: Requires that pre-constructionreview be conducted for all proposednew or modified sources of airpollution, including BACT, emissionsoffsets, and air quality impact analysis.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3SDAPCD Rule 1200 (Toxics, NewSource Review)Requires that pre-construction reviewbe conducted for all proposed new ormodified sources of toxic aircontaminants, including T-BACT, anda health risk assessment.SDAPCD withUSEPAoversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3SDAPCD Rule 1414 (Title VApplications)Implements operating permitsrequirements of CAA Title V.SDAPCD withUSEPAoversightIssues modified Title V permitafter review of application.Agency approval to beobtained before startof construction.5.1.6.3EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC)5.1-25SECTION 5.1: AIR QUALITYTABLE 5.1-15Laws, Ordinances, Regulations, Standards and Permits for Protection of Air QualityLORS PurposeRegulatingAgency Permit or ApprovalSchedule and Statusof PermitConformance(Sections)SDAPCD Rule 1412 (FederalAcid Rain ProgramRequirements)Implements acid rain regulations ofCAA Title IV.SDAPCD withUSEPAoversightTitle IV requirements includedin DOC, Permit to Operate,and Title V permit.Application to be madewithin 12 months ofstart of facilityoperation.5.1.6.3SDAPCD Rule 50 (VisibleEmissions)Limits visible emissions to no darkerthan Ringelmann No. 1 for periodsgreater than 3 minutes in any hour.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained prior tocommencement ofoperation.5.1.6. 3.3SDAPCD Rule 51 (Nuisance)Prohibits emissions in quantities thatadversely affect public health, otherbusinesses, or property.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3.3SDAPCD Rule 52 (ParticulateMatter)Limits PM emissions from stationarysources.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3.3SDAPCD Rule 53 (CombustionContaminants)Limits SO2emissions from stationarysources.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3.3SDAPCD Rule 62 (Sulfur Contentof Fuels)Limits the sulfur content of fuelscombusted in stationary sources.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3.3SDAPCD Rule 69.3.1 (StationaryGas Turbines)Limits NOxemissions from stationarygas turbines.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3.3SDAPCD Rule 69.4.1 (StationaryReciprocating InternalCombustion Engines)Limits CO, NOx, and VOC emissionsfrom stationary reciprocating internalcombustion engines.SDAPCD withCARB oversightDOC with conditions limitingemissions.Proposed new engineis exempt from thisregulation due tooperating limits.5.1.6.3.35.1-26EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC)SECTION 5.1: AIR QUALITYEY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC)5.1-27TABLE 5.1-15Laws, Ordinances, Regulations, Standards and Permits for Protection of Air QualityLORS PurposeRegulatingAgency Permit or ApprovalSchedule and Statusof PermitConformance(Sections)SDAPCD Regulation X(New Source PerformanceStandards: Subpart KKKK,Stationary Gas Turbines)Requires monitoring of fuel, otheroperating parameters; limits NOx, SO2,and PM emissions, requires sourcetesting, emissions monitoring, andrecordkeeping.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3.3SDAPCD Regulation X(New Source PerformanceStandards: Subpart IIII, StationaryCompression Ignition InternalCombustion Engines)Limits VOC, NOx, CO, and PMemissions and requires recordkeeping.SDAPCD withCARB oversightDOC with conditions limitingemissions.Agency approval to beobtained before startof construction.5.1.6.3.3SECTION 5.1: AIR QUALITY



## 5.1.5.3.22 Attainment Status Based on the measured existing air quality desc ribed in Section 5.1.3, the ambient air quality standards presented in Table 5.1-1, and the responsibilities of the USEPA and the CARB discussed in Sections 5.1.4.1.1 and 5.1.4.1.2, respectively, the resulting attainment status of the San Diego Air Basin is shown in Table 5.1-16.

TABLE 5.1-16 

### Ambient Air Quality Standard Attainment Status in San Diego Air Basin
Pollutant Averaging Time California National

1 hour Nonattainment Attainment Ozone 8 hours Designation pending Nonattainment

8 hours Attainment Attainment Carbon Monoxide 1 hour Attainment Attainment
Annual Average No CAAQS Attainment Nitrogen Dioxide 1 hour Attainment No NAAQS
Annual Average No CAAQS Attainment 24 hours Attainment Attainment 3 hours No CAAQS Attainment Sulfur Dioxide

1 hour Attainment No NAAQS

Annual Arithmetic Mean Nonattainment Unclassifiable Respirable Particulate Matter (10 Micron) 24 hours Nonattainment Unclassifiable

Annual Arithmetic Mean Nonattainment Attainment Fine Particulate Matter (2.5 Micron) 24 hours No CAAQS Attainment
Sulfates 24 hours Attainment No NAAQS
30 days Attainment No NAAQS Lead Calendar Quarter No CAAQS Attainment Hydrogen Sulfide 1-hour Unclassified No NAAQS Vinyl Chloride 24-hour Unclassified No NAAQS Visibility Reducing Particles 8-hour (10am to 6pm PST) Unclassified No NAAQS



# 5.1.6 Environmental Analysis Ambient air quality impact analyses for the CECP have been conducted to satisfy the SDAPCD, USEPA, and CEC requirements for anal ysis of impacts from criteria pollutants (NO 2 

### , CO, PM 10 

### , and SO 2 

### ) and noncriteria pollutants duri ng project construction and operation. The analyses cover each phase of th e project. Section 5.1.5.1 gives an overview of the analytical approach. Section 5.1.5.2 presen ts the emissions for operation of the CECP, and Section 5.1.5.3 gives the ambient air quality impacts of operation. Section 5.1.5.4 gives the analysis for construction of the CECP.

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## 5.1.6.1 Overview of the Analyt ical Approach to Estimating Facility Impacts The following sections describe the emission sources that have been evaluated, the results of the ambient impact analyses, and the evalua tion of the CECP compliance with the applicable air quality regulations, includ ing the District’s NSR requirements. These analyses are designed to confirm that the pr oject’s design features lead to less-than– significant impacts even with the following conservative analysis assumptions and procedures: maximum allowable em ission rates, project operating schedules that lead to maximum emissions, worst-case meteorological conditions, and adding the worst-observed existing air quality to the highest potential gr ound-level impact from modeling, even when all of these situations could not ph ysically occur at the same time.


## 5.1.6.1.1 Emitting Units The new CECP combined-cycle gas turbine plant will be made up of two Siemens Rapid Response SGT6-5000F Combined Cycle (R2C2) combustion turbine generators (CTGs) arranged as one CTG-on-one steam turbine. The gas turbines will be equipped with steam power augmentation and evaporative cooling. Each gas turbine will be followed by an unfired heat recovery steam generator (HRS G), one condensing steam turbine generator (STG), an air-cooled fin-fan cooler, and asso ciated support equipment. The two units will provide a total nominal generating capacity of 558 MW gross/540 MW net. Each unit combines the fast starting capability of a simp le cycle gas turbine and the efficiency of a combined cycle plant. Each unit is designed to start and ramp up to 150 MW in ten minutes and still be capable of operating with combined-cycle efficiency. Each gas turbine will be equipped with dry low- NO x 

### combustors and a selective catalytic reduction (SCR) system for NO x 

### control. An oxidation catalyst will be used to reduce CO emissions. Particulate and VOC emission will be minimized through the use of natural gas as the fuel. Emissions control systems will operate full time except during startups and shutdowns. Specifications for the new gas turbines are summarized in Table 5.1-17.

TABLE 5.1-17 

### New Combined-Cycle Gas Turbine Design Specifications Manufacturer Siemens
Model SGT6-5000F
Fuel Natural gas Design Ambient Temperature * 37°F Maximum Gas Turbine Heat Input Rate * 2,085 MMBtu/hr @ HHV (each turbine)
Maximum Gas Turbine Power Generation Rate 219 MW (nominal gross each CTG) Maximum Steam Turbine Power Generation Rate 60 MW (nominal gross each STG) Stack Exhaust Temperature* 371°F (after HRSG)
Exhaust Flow Rate* 1,487,415 acfm Exhaust O 2 Concentration, dry volume* 13.69% Exhaust CO 2 Concentration, dry volume* 3.83% Exhaust Moisture Content, wet volume* 7.72% Emission Controls Dry Low- NO xCombustor and SCR; oxidation catalyst

* Low-temperature baseload operating scenario corresponds to maximum heat input rate.

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### As discussed above, the use of natural gas as the sole fuel will mini mize emissions of VOC, SO x 

### and PM 10 

### . A typical analysis for the natural gas fuel to be used by the gas turbines is summarized in Table 5.1-18.

TABLE 5.1-18 

### Nominal Fuel Properties – Natural Gas Component Analysis Chemical Analysis

Component Average Concentration, Volume Constituent Percent by Weight Methane (CH 4 ) 95.776% Carbon (C) 72.92 % Ethane (C 2 H 6 ) 1.806% Hydrogen (H) 23.84 % Propane (C 3 H 8 ) 0.335% Nitrogen (N) 1.13 %
Butane C 4 H 10 ) 0.122% Oxygen (O) 2.11 % Pentane (C 5 H 12 ) 0.043 % Sulfur (S) 0.75 gr/100 scf (short term average) 0.25 gr/100 scf (long term average) Hexane (C 6 H 14 ) 0.026% Nitrogen (N 2 ) 0.682% Carbon Dioxide (CO 2 ) 1.112% Sulfur (S) <0.00% Higher Heating Value 1,019 Btu/scf 22,848 Btu/lb



### The CECP will also include the installation of a new diesel emergency firepump engine rated at 246 horsepower with a maximum fuel consumption rate of 12.2 gallons per hour. The auxiliary equipment associated with the CE CP will also include the installation of two 10,000 gallon aqueous ammonia (19 percent) storage tanks.


## 5.1.6.1.2 Facility Operations Gas turbine performance specifications were developed for four temperature scenarios: extreme hot temperature (104 ° F), summer average temperature (74 ° F), annual average temperature (61 ° F), and extreme low temperature (37 ° F). The low-temperature scenario was used to characterize maximum hourly emissions because it has the highest hourly heat input and emission rates. The plant may be op erated under a wide variety of conditions over its life. Maximum daily operations are based on extreme low temperature full-load operation of both CTGs for 24 hours and the emergency firepump engine operating for 1 hour. Maximum annual emissions for the CTGs/HRSGs were based on operating 4,100 hours per year at the annual average full-load operation of both CTGs. Annual emissions for the emergency firepump engine were based on operating 50 hours per year. Heat input levels for the CTGs/HRSGs, as su mmarized in Table 5.1-19, correspond to the calculated unit and proj ect emission levels.

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### Emissions and operating parameters for the CTGs/HRSGs under various loads and ambient conditions are shown in Appendix 5.1B. Em issions and operating parameters for the emergency firepump engine are shown in Appendix 5.1B.

TABLE 5.1-19 

### Maximum Proposed Project Fuel Use – CTGs (MMBtu)* Period Gas Turbines (each) Total Fuel Use (both units) Per Hour 2,085 4,170 Per Day 50,040 100,080 Per Year 7,999,510 15,999,020 Note: * MMBtu: million Btu 

## 5.1.6.2 Emissions Calculations This section presents calculations of emissi ons increases from the CECP generating and auxiliary equipment and of the emissions reductions from the shutdown of the existing boilers Units 1, 2, and 3 at the Encina Power Station for the purpose of demonstrating rule compliance. Tables containing the detailed calc ulations are included in Appendix 5.1B.


## 5.1.6.2.1 Criteria Pollutant Emissions: CECP The CTG/HRSG and emergency fire pump engine emission rates have been calculated from vendor data, project design criteria, and esta blished emission calculation procedures. The emission rates for the CTGs and firepump en gine are shown in the following tables. The detailed emission calculations for thes e units are shown in Appendix 5.1B. 

## CTG Emissions during Normal Operations Emissions of NO x 

### , CO, and VOC were calculated from emission limits (in ppmv @ 15% O 2 

### ) and the exhaust flow rates. The NO x 

### emission limit reflects the application of SCR. The VOC and CO emission limits reflect the use of good combustion practices and, for CO, an oxidation catalyst. SO x 

### , PM 10, 

### and PM 2.5 

### emission rates are based on the use of natural gas as the fuel and good combustion practices. Emi ssions are based on the heat input rates shown in Table 5.1-19.
SO x 

### emissions were calculated from the heat input (in MMBtu) and a SO x 

### emission factor (in lb/MMBtu). The short-term SO x 

### emission factor of 0.0021 lb/MMBtu was derived from the maximum allowable (i.e., tariff limit) fuel su lfur content of 0.75 grains per 100 standard cubic feet (gr/100 scf). The annual average SO x 

### emissions were based on the expected annual average sulfur grain loading of 0.25 gr/100 scf. Maximum hourly PM 10 

### emissions are based on vendor supplied emission levels. PM 2.5 

### emissions were determined based on the assumption that all gas turbine exhaust particulate is less than 2.5 microns in diameter.
Emissions for the CTGs are summarized in Tabl e 5.1-20. The BACT analysis upon which the emission factors are based is presented in Appe ndix 5.1C and summarized in Section 5.1.6.3.

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TABLE 5.1-20 

### Maximum Hourly Emission Rates: CTGs/HRSGS
Pollutant ppmvd @ 15% O 2 Lb/MMBtu lb/hr

Each Gas Turbine a

NO x 2.0 b 0.0072 15.1

SO 2 0.42 (short term) 0.14 (long term) 0.0021 0.0007 4.4 1.5
CO 2.0 0.0044 9.2
VOC 2.0 0.0025 5.3
PM 10 c n/a 0.0045 9.5

Notes:

a Emission rates shown reflect the highest value at any operating load. For NO x , CO, and VOC, emission levels

exclude startups and shutdowns.

b Applicant is requesting that the permit allow hourly average NO x concentrations to exceed 2.0 ppmc under certain limited conditions. S ee text following table.

c 100 percent of particulate matter em issions assumed to be emitted as PM 2.5 ; PM 10 emissions include both front

half and back half as those terms are used in EPA Method 5.


### The Applicant believes that there may be transient load conditions, such as rapid load changes, which may result in short-term elevated NO x 

### emissions from the combined cycle unit. The Applicant proposes the inclusion of the following NO x 

### emissions excursion language in the CEC’s conditions of certification: Compliance with the NO x 

### emission limitations sha ll not be required during short-term excursions limited to a cumu lative total of 15 hours per calendar year. Short-term excursions are define d as 15-minute periods designated by the owner/operator and approved by the APCO that are the direct result of transient load conditions, not to exceed four consecutive 15-minute periods, when the 15-minute average NO x 

### concentration exceeds 2.0 ppmvd @ 15% O 2 

### . The maximum 3-hour average NO x 

### concentration for periods that include short-term excursions shall not exceed 30 ppmvd @ 15% O 2 

### . Examples of transient load conditions include but are not limited to the following: (1) rapid gas turbine load changes initiated by the California ISO or a successor entity when the plant is operating under Automatic Generation Control; or (2) rapid combustion load changes due to activation of a plant automatic safety or equipment protecti on system. All emissions during shortterm excursions shall accrue towards the daily and annual emissions limitations of this permit and shall be in cluded in all calculations of daily and annual mass emission rates as required by this permit. 

## CTG Emissions During Startup and Shutdown Maximum emission rates expected to occur duri ng a CTG startup or shutdown are shown in Table 5.1-21. PM 10 

### and SO 2 

### emissions are not included in this table because emissions of these pollutants will not be higher during st artup and shutdown than during normal gas turbine operation. During a CTG startup, there are approximately 22 mi nutes with elevated emissions (emissions higher th en during normal operation). Consequently, the hourly

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### emission rates during CTG startups are based on 22 minutes of elevated emissions followed by 38 minutes of normal operating emission levels. During a CTG shutdown, there are approximately seven minutes with elevated emissions (emissions higher then during normal operation). Consequently, the hourly emission rates during CTG shutdowns are based on 53 minutes of normal operating emissi on levels followed by 7 minutes of elevated emission levels. The Applicant also expects t hat periodically there could be an hour when both a startup and shutdown occurs. For this hour, there would be 22 minutes of elevated emissions due to the startup, 31 minutes of normal operation emissions, followed by 7 minutes of elevated emissions due to a shutdown. While this situation is expected to occur very infrequently, from an hourly emission standpoint this would represent worst case hourly emissions, and as such it is includ ed in the ambient air impact analysis for the project. The detailed CTG startup hourly emissi on calculations are shown in Appendix 5.1B. Included in this appendix are the CTG vendor supplied startup/shutdown emission levels for the Siemens CTGs.

TABLE 5.1-21 

### CTG Startup and Shutdown Emission Rates*
NO x CO VOC CTG Startup, lbs/hr, per gas turbine 69 546 16 CTG Shutdown, lbs/hr, per gas turbine 47 286 10 CTG Startup/Shutdown, lbs/hr, per gas turbine 86 814 21

Note: * Emission rates shown are maximum short term average emission levels. Lower emission levels are expected when averaged annually. 

## CECP Criteria Pollutant Emissions Summary The calculation of maximum project emissions shown in Table 5.1-22 is based on the CTG emission rates and heat input levels show n in the above tables and the following assumptions:

• Each CTG may operate up to 24 hours per day.

• Each CTG may have up to 6 hours per da y containing a startup and/or shutdown.

• Annual emissions are based on 4,100 hours of operation for each CTG.

• The emergency firepump engine may operat e up to 1 hours per day and 50 hours per year for testing and maintenance (the engi ne will not be operated during a CTG startup/shutdown). The assumptions used in calculating maximum hourly, daily and annual emissions from the new facility are shown in Appendix 5.1B.

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TABLE 5.1-22 

### Maximum Emissions from New Equipment
Pollutant Emissions/Equipment NO x SO 2 CO VOC PM 10 Maximum Hourly Emissions a
Gas Turbines a 171.3 8.8 1,627.0 41.4 19.0 Diesel Firepump Engine b n/a 0.00 n/a n/a 0.04 Total, pounds per hour 171.3 8.8 1,627.0 41.4 19.0 Maximum Daily Emissions a
Gas Turbines 1,754.1 211.1 10,20 4.5 438.7 456.0 Diesel Firepump Engine 2.1 0.00 0.24 0.05 0.04 Total, pounds per day 1,756. 2 211.1 10,204. 8 438.8 456.0
Maximum Annual Emissions a
Gas Turbines 75.5 5.6 217.3 25.0 39.0 Diesel Firepump Engine 0.05 0.0 0.0 0.0 0.0 Total, tons per year 75.6 5.6 217.3 25.0 39.0
Notes:

a Maximum hourly, daily and annual NO x , VOC and CO CTG emission rates include emissions during startups/shutdowns.

b The Diesel firepump engine will not be operated during a gas turbine startup and/or shutdown. Consequently, n/a is shown for NO x , CO, and VOC because maximum CTG emissions for these pollutants occur during startups/shutdowns. 

### The maximum hourly, daily and annual emissi ons in Table 5.1-22 are used in the air dispersion modeling to calculate the maximum potential ground-level concentrations contributed by the proposed project to the ambient air.


## 5.1.6.2.2 Emissions for Existing Boilers at the Encina Power Station The Encina Power Station consists of five dual-fuel steam boilers (Units 1-5), and one simple-cycle gas turbine, rated at the follo wing nominal levels: 113 MW, 109 MW, 115 MW, 293 MW, 315 MW, and 18 MW, respectively. The boilers are normally fired on natural gas, but can be fired on fuel oil as well. Fuel oil fi ring of the boilers rarely occurs, and then only for testing or during curtailment of natural gas supplies to the power plant. The gas turbine is normally fired on natural gas, but is also pe rmitted to be operated on Diesel fuel and up to 876 hours per year on either fuel. As part of the CECP, the existing boiler Units 1, 2, and 3 at the Encina Power Station will be shut down and retired prior to the commercial operation of the new equipment. Since it is possible t hat there could be up to a 6-month stagger between the initial commercial operation da tes of the two new CTGs, there may be a corresponding staged shutdown of the three existing boilers with Unit 1 shutting down at the commercial operation of the first new CTG, followed by the shutdown of Units 2 and 3 at the commercial operation of the second new CTG. During the staged shutdown of the three existing boilers, there will be no simu ltaneous operation of the new CTGs and the existing Units 1 through 3. The emissions redu ctions from the shutdown of the existing units are based on historical baseline op erations and emissions during the most representative consecutive two-year period duri ng the five years preceding the filing of the

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### AFC for the proposed project (2002 to 2006). The emission reductions associated with the shutdown of Units 1, 2, and 3 are shown in Table 5.1-23. Also shown for regulatory applicability purposes are the 2-year average baseline emissions for Units 4, 5, and the simple cycle gas turbine. The detailed calculatio n of the historical baseline emissions for the existing units at the Encina Power Stat ion is included in Appendix 5.1B.

TABLE 5.1-23 

### Emissions for Existing Units
Pollutant Emissions/Equipment NO x SO 2 CO VOC PM 10 Annual Emissions Units 1, 2, and 3
Unit 1 13.9 2. 6 97.8 5.2 9.8
Unit 2 18.5 5. 8 122.6 6.1 13.4
Unit 3 22.5 3. 1 140.9 8.7 15.8 Subtotal, tons per year 54.9 11.5 361.3 20.0 39.0 Annual Emissions Units 4, 5, and Gas Turbine
Unit 4 88.8 4. 2 610.6 32.4 62.0
Unit 5 100.6 4. 5 701.6 33.3 56.4
Gas Turbine 3.0 0.2 0.8 0.2 0.3 Subtotal, tons per year 192.4 8.9 1,313. 0 65.9 118.7 Annual Emissions Facility Wide Total, tons per year 247. 3 20.4 1,674.3 85.9 157.7



## 5.1.6.2.3 Net Changes in Criteria Pollutant Emissions for the Proposed Project Net emissions changes as a result of the projec t are calculated on an annual basis for federal PSD, SDAPCD NSR, and CEQA purposes. These net emission changes are shown in Table 5.1-24 below.

TABLE 5.1-24 

### Net Emissions Change for Proposed Project
Pollutant Emissions/Equipment NO x SO 2 CO VOC PM 10 Potential to Emit for New E quipment 75.6 5. 6 217.3 25.0 39.0 Reductions from Shutdown of Units 1, 2, and 3 -54.9 -11. 5 -361.3 -20.0 -39.0 Net Emission Change, tons per year 20.1 -5.9 -144.0 5.0 0.0



## 5.1.6.2.4 Non-Criteria Pollutant Emissions Noncriteria pollutant (toxic air contaminant [TAC]) emissions were estimated for the proposed CTGs/HRSGs and emergency firepu mp engine. These emissions are summarized in Table 5.1-25. The detailed noncriteria pollut ant emissions calculations and the associated screening level health risk assessment are incl uded in the Public Health Impact Section

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### (see Section 5.9). Also shown below in Table 5.1-26 is a summary of the maximum potential to emit for noncriteria pollutants for the existi ng units at the facility. This information is provided for regulatory applicability purposes . The detailed noncriteria pollutant emission calculations for the existing units are included in the Public Health Impact Section (see Section 5.9).

TABLE 5.1-25 

### Non-criteria Pollutant Emissions for the New Equipment Compound Maximum Proposed Emissions (tpy) Gas Turbines and HRSGs (two units) Ammonia (not a HAPs) 53.62 Propylene (not a HAPs) 6.47 Acetaldehyde 0.34
Acrolein 0.03
Benzene 0.03 1,3-Butadiene 0.00 Ethylbenzene 0.27 Formaldehyde 3.08
Hexane 2.17 Naphthalene 0.01 PAHs (other) 0.00 Propylene Oxide 0.25
Toluene 1.12 Xylene 0.55 Total HAPs (CTGs/HRSGs) 7.85 Emergency Firepump Engine Diesel PM (not a HAPs) 0.00
Acrolein 0.00
Arsenic 0.00
Benzene 0.00 Copper (not a HAPs) 0.00 Formaldehyde 0.00 Hydrogen Chloride 0.00 Mercury 0.00

Nickel 0.00
Toluene 0.00 Xylene 0.00 Total HAPs (Firepump Engine) 0.00 Total HAPs (Proposed Project) 7.85

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TABLE 5.1-26 

### Non-criteria Pollutant Emissions for the Existing Boiler Units 1, 2, 3, 4, 5, and Gas Turbine Compound Maximum Potential Emissions (tpy) Boilers (Units 1, 2, 3, 4, and 5)
Benzene 

### 0.08 Formaldehyde 

### 3.17
Hexane 

### 0.06 Naphthalene 

### 0.03
Dichlorobenzene 

### 0.05
Toluene 0.15 Total HAPs (Boilers) 3.54
Gas Turbine Acetaldehyde 

### 0.06
Acrolein 

### 0.01
Benzene 0.02 Formaldehyde 0.99 Ethylbenzene 0.04
Toluene 0.18 PAHs (other) 0.00 Xylene 0.09 Total HAPs (Gas Turbine) 1.39 Total HAPs (Existing Facility) 4.93



## 5.1.6.2.5 Greenhouse Gas Emissions The CECP will emit greenhouse gas emissions. These emissions are summarized below in the Cumulative Effects section.



## 5.1.6.3 Air Quality Impact Analysis The SDAPCD new source review regulations re quire the Applicant to provide ambient air quality modeling analyses and other impact assessments. An ambient air quality impact assessment is also required by the CEC for CEQA review. These anal yses are presented in this section.


## 5.1.6.3.1 Air Quality Modeling Methodology An assessment of impacts from the CECP on ambient air quality has been conducted using the USEPA-approved air quality dispersion models. These models use a mathematical description of atmospheric turbulent entrainm ent and dispersion to simulate the actual processes by which a pollutant emission is tr ansported to potential ground-level impact

areas.

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### Using the most stringent and conservative assumptions, the modeling was used to determine the maximum ground-level impacts of the CECP. The results were compared with state and federal ambient air quality st andards and PSD significance levels. If the standards are not exceeded in the analysis, then the fac ility will cause no exceedances under any operating or ambient conditions, at any lo cation, under any meteorological conditions. In accordance with the air quality impact analysis guidelines developed by USEPA 6 

### and CARB 7 

### , the ground-level impact analysis includes the following assessments:

• Impacts in simple, intermed iate, and complex terrain

• Aerodynamic effects (downwash) due to nearby building(s) and structures

• Impacts from inversion breakup (fumigation) Simple, intermediate, and complex terrain im pacts were assessed for all meteorological conditions that would limit the amount of final plume rise. Plume impaction on elevated terrain, such as on the slope of a nearby hill, can cause high ground-level concentrations, especially under stable atmospheric conditions . Another dispersion condition that can cause high ground-level pollutant co ncentrations is caused by bu ilding downwash. A stack plume can be downwashed when wind speeds are high and a sufficiently tall building or structure is in close proximity to the emission stack. This can result in building wake effects where the plume is drawn down toward the ground by the lower pressure region that exists in the lee (downwind) side of the building or structure. Fumigation conditions occur when the plume is emitted into a layer of stable air (inversion) that then becomes unstable from below, result ing in a rapid mixing of pollutants out of the stable layer and towards the ground in the unstable layer undern eath. The low mixing height that results from this condition allows little diffusion of the stack plume before it is carried downwind to the ground. Although fu migation conditions are short-term, rarely lasting as long as an hour, relatively high ground-level concentrations may be reached during that period. Fumigation tends to occur under clear skies and light winds, and is more prevalent in summer. Two types of fumigation are analyzed: inversion breakup and shoreline. Inversion breakup fumigation occurs under low-wind conditions when a rising morning mixing height caps a stack and “fumigates” the air below. Shoreline fumigation occurs when a roughne ss boundary (generally a beach) causes turbulent dispersion to be much more enhanced near the ground, once again fumigating the air below. For shoreline fumigation, the lens-shape of the wedge of turbulent air rising from the beach is governed by several factors, which are summarized by use of what are called TIBL (turbulence-induced boundary layer) fact ors. TIBL factors usually cover the range of what is expected. For screening modeling purp oses, usually TIBL = 6 is the worst-case, and hence, is used for SCREEN3 modeling here. Impacts are also governed by the distance of the stack from the beach. The basic model equation used in this analysis assumes that the concentrations of emissions within a plume can be characterized by a Gaussian (statistical) distribution around the

6 EPA. Guideline on Air Quality Models, 40 CFR Part 51, Appendix W. 7 ARB. Reference Document for California Statewide Modeling Guideline, April 1989.

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### centerline of the plume. Concentrations at any location downwind of a point source such as a stack can be determined from the following equation:

( ) 

# ( ) ( ) 

# { } ( ) 

# { } 

# [ ] CxyzH Q

u ee e y z y z H z H y z z 

## (,,, ) * * / / // // 

## = ⎛

⎝ ⎜ ⎞ ⎠ ⎟ + − − − − + 

## 2 1 2 1 2 1 2 2 2 2


## πσ σ σ σ σ 

### (Eq. 1)

where C = pollutant concentration in the air Q = pollutant emission rate

σ y 

### σ z 

### = horizontal and vertical dispersion coefficients, respectively, at downwind distance x u = wind speed at the height of the plume center x,y,z = variables that define the downwind , crosswind, and vertical distances from the center of the base of the stack in the model’s 3-dimensional Cartesian coordinate system H = the height of the plume above the stack base (the sum of the height of the stack and the vertical distance that th e plume rises due to the momentum and thermal buoyancy of the plume) Gaussian dispersion models are approved by USEPA for regulatory use and are based on conservative assumptions (i.e., the models tend to over predict actual impacts by assuming steady-state conditions, no pollutant loss through conservation of mass, no chemical reactions). The USEPA models were used to determine if ambient air quality standards would be exceeded, and whether a more accu rate and sophisticated modeling procedure would be warranted to make the impact determination. The following sections describe:

• Gas turbine screening modeling;

• Refined air quality impact analysis;

• Specialized modeling analyses;

• Results of the ambient air quality modeling analyses; and

• PSD significance levels. Modeling for the CECP was performed in acco rdance with the modeling protocol submitted to the SDAPCD and CEC. The modeling procedures used for each type of modeling analysis are described in more detail in the following sections. Two different USEPA guideline mo dels were used for different meteorological conditions in the ambient air quality impact analysis. The USEPA-approved AERMOD 8 

### model was used to evaluate impacts in simple, intermediate, and complex terrain. AERMOD is a Gaussian dispersion model capable of assessing impacts from a variety of source types in areas of simple, intermediate, and complex terrain. The model can account for sett ling and dry deposition of particulates; area,

8 The acronym AERMOD was derived from American Meteorol ogical Society/Environmental Protection Agency Regulatory Model.

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### line, and volume source types; downwash effect s; and gradual plume rise as a function of downwind distance. The model is capable of es timating concentrations for a wide range of averaging times (from one hour to one year), and was applied with three years of actual meteorological data recorded at the Camp Pe ndleton monitoring station. AERMOD replaces the previous USEPA-recommended model, Indust rial Source Complex, Version 3 (ISCST3), which has been used for many years for air quality impact analyses in CEC AFCs. The analysis using the AERMOD model is discussed in more detail below. The SCREEN3 model was used to evaluate ga s turbine impacts under inversion breakup and shoreline fumigation conditions because these are special cases of meteorological conditions. The SCREEN3 model uses a range of meteorological conditions that could occur under inversion breakup and shoreline fumigati on. Since the emission s from the emergency firepump engine are so small compared to th e gas turbine emissions, they are excluded from this single-source model used for the fu migation analysis. The fumigation analysis is discussed in more detail below. 

## Gas Turbine Screening Modeling The screening and refined air quality impact analyses were performed using the AERMOD model. The screening modeling is performed to determine the combination of ambient temperature and CTG operating conditions that generates the highest ambient air quality levels for each pollutant and averaging pe riod. The refined modeling uses the stack parameters that the screenin g level modeling shows produced the highest ambient impacts (per pollutant and averaging period).

• Inputs required by AERMOD include the following:

• Model options

• Meteorological data

• Source data

• Receptor data Standard AERMOD control parameters were used, including stack tip downwash, nonscreening mode, non-flat terrain, and sequential meteorological data check. Stack-tip downwash, which adjusts the effective stack height downward following the methods of Briggs (1972) for cases where the stack exit velocity is less than 1.5 times the wind speed at stack top, were selected per USEPA gu idance. As directed by the District, 9 

### the rural default option will be used by not invoking the URBANOPT option. 10 

### The use of the rural default in modeling for the proposed project is co nsistent with District policy and guidance 11 

### for past modeling using ISCST3. The required emission source data inputs to both models used in this analysis include source locations, source elevations, stack heig hts, stack diameters, stack exit temperatures and velocities, and emission rates. The source locations are specified for a Cartesian (x,y) coordinate system where x and y are distances east and north in meters, respectively. The

9 Personal communication, Ralph DeSiena, September 14, 2006. 10 The rural vs. urban option in AERMOD is primarily designed to se t the fraction of incident heat flux that is transferred into the atmosphere. This fraction becomes im portant in urban areas having an appreciable “urban heat island” effect due to a large presence of land covered by concrete, as phalt, and buildings. This situation does not exist for the proposed project site. 11 SDAPCD. Use of Rural vs Urban Modeling Coefficients, Memorandum from Richard J. Smith, Deputy Director, to Judith M. Lake, Chief, Monitoring and Technical Services, October 29, 1996.

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### Cartesian coordinate system used is the Univ ersal Transverse Mercator Projection (UTM). The stack height that can be used in the mo del is limited by federal Good Engineering Practice (GEP) stack height restrictions, di scussed in more detail below. In addition, Building Profile Input Program – Plume Rise Model Enhancements (BPIP-PRIME, current version 04274) requires nearby building dimens ion data to calculate the impacts of building downwash. For the purposes of modeling, a stack height be yond what is required by Good Engineering Practices (GEP) is not allowed. However, this requirement does not place a limit on the actual constructed height of a stack. GEP as used in modeling is the height necessary to assure that emissions from the stack do not re sult in excessive concentrations of any air pollutant in the immediate vicinity of the so urce as a result of atmospheric downwash, eddies, or wakes that may be created by the source itself, nearby structures, or nearby terrain obstacles. In addition, the GEP modeling restriction assures that any required regulatory control measure is not compromised by the effect of that portion of the stack that exceeds the GEP. USEPA guidance 12 

### for determining GEP stack height indicates that GEP is the greater of 65 meters or H g 

### , where H g 

### is calculated as follows:

H g 

### =H + 1.5L

where:

H g 

### = Good Engineering Practice stack height, measured from the ground-level elevation at the base of the stack H = height of nearby structure(s) measured from the ground-level elevation at the base of the stack L = lesser dimension, height or maximum projected width, of nearby structure(s) In using this equation, the guidance document indicates that both the height and width of the structure are determined from the frontal ar ea of the structure, projected onto a plane perpendicular to the direction of the wind. For the new gas turbine stacks, the nearby (influencing) structures are the HRSGs for the new units, which are 88 feet (26.8 m) high, 131.5 feet (40.1 m) long and 26.8 feet (8.2 m) wide. Thus H = L = 88 feet, and H g 

### = 2.5 * 88 = 220 feet (67.1 m). The proposed stack height of 100 feet (30.5 m) does not exceed GEP stack height of 220 feet (67.1 m), and consequently satisfies the USEPA requirement. For regulatory applications, a building is cons idered sufficiently close to a stack to cause wake effects when the downwind distance between the stack and the nearest part of the building is less than or equal to five times the lesser of the height or the projected width of the building. Building dimensions for the build ings analyzed as downwash structures were obtained from plot plans. The building dimensio ns were analyzed using the BPIP-PRIME to calculate 36 wind-direction-specific building heights and projected building widths for use in building wake calculations. The building dimensions used in the GEP analysis are shown in Appendix 5.1D.

12 EPA. Guideline for Determination of Good Engi neering Practice Stack Height, Revised June 1985.

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## Screening Procedures and Unit Impact Modeling Screening modeling was performed to select th e worst-case gas turbine operating mode for each pollutant and averaging period. The mode ling used emissions data based on an annual average temperature (61°F), average summer temperature ( 74°F), maximum temperature (104°F), and minimum temperat ure (37°F), and at nominal minimum and maximum gas turbine operating load points of 60 percent and 100 percent. The determination of the worst-case gas turbine operating condition de pends on how changes in emissions rates and stack characteristics (plume rise characteristics) interact with terrain features. For example, lower mass emissions resulting from lower load operations may cause higher concentrations than other operating conditions because lower final plume height may have a greater significant interaction with terrain features. Initial AERMOD modeling runs were performed using normalized emission rates to assess the zone of impact and relative magnitude of the impacts. For the AERMOD gas turbine screening modeling, each gas turbine was modeled with a unit emission rate of 1 gram per second to obtain maximum 1-hour, 3-ho ur, 8-hour, 24-hour, and annual average concentration to emission rate ( χ /Q in units of μ g/m 3 

### per g/s) values. These χ /Q values were multiplied by the actual emission rate in grams per second from the gas turbine to calculate ambient impacts for NO 2 

### , CO, SO 2 

### , and PM 10 

### /PM 2.5 

### in units of μ g/m 3 

### . Stack characteristics used in the screening mode ling analysis are shown in Appendix 5.1D. The results of the screening analysis are shown in the Appendix 5.1D. The stack parameters and emission rates corresponding to the op erating case that produced the maximum impacts in the gas turbine screening analysis for each pollutant and averaging period were used in the refined modeling analysis to evaluate the impacts of the new units. For the unit impacts analysis, the CEC staff’s recommendation regarding receptor grid spacing has been followed. 13 

## Refined Air Quality Impact Analysis In simple, intermediate and complex terrain , AERMOD was used to estimate project impacts. The AERMOD model was used to calculate 1-hour, 3-hour, 8-hour, 24-hour, and annual average concentrations. Refined modeling was performed in two phas es: coarse grid modeling and fine grid modeling. Preliminary modeling was performed with the coarse grid to locate the areas of maximum concentration. Fine grids were used to refine the location of the maximum concentrations. The stack parameters and emission rates used to model combined impacts from all new equipment at the facility are shown in Appe ndix 5.1D. The model receptor grids were derived from U.S. Geological Survey (USGS) 30-meter Digitized Elevation Map (DEM) data. CEC guidance was used to locate receptors. Tw enty-five-meter refined receptor grids were used in areas where the coarse grid analyses indicated modeled maxima would be located. A map showing the layout of the receptor grids used for the refined modeling is included in Appendix 5.1D.

13 25-meter resolution along the facility fenceline to 100 meters fr om the fenceline; 100 meter resolution from 100 meters to 1,000 meters from the fenceline; and 250-meter spacing out to as far as 10 kilometers from the site.

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### Terrain features were taken from the followi ng 7.5-minute USGS Digital Elevation Model (DEM) quadrangles in California:

• Bonsall

• Las Pulgas Canyon

• Morro Hill

• Rancho Santa Fe

• San Marcos

• Encinitas

• Oceanside

• San Luis Rey These terrain data are included in the modeling CD that was submitted to the CEC as part of this AFC.


## 5.1.6.3.2 Specialized Modeling Analyses Fumigation Modeling Fumigation occurs when a stable layer of air lie s a short distance above the release point of a plume and unstable air lies below. Under th ese conditions, an exhaust plume may cause high ground-level pollutant co ncentrations because the plume is unable to rise upwards normally due to the stable layer capping it from above, and be drawn to the ground by turbulence within the unstable la yer. Although fumigation condit ions rarely last as long as one hour, relatively high ground-level concentr ations may be reached during that time. For this analysis, fumigation was assumed to occu r for up to 90 minutes as required by USEPA guidance.
The SCREEN3 model was used to evaluate maximum ground-level concentrations for short-term averaging periods (24 hour s or less). Guidance from the USEPA 14 

### was followed in evaluating fumigation impacts. The maxi mum fumigation impact from the gas turbine occurred approximately 10 to 23 kilometers from the CECP site. This analysis, which is shown in more detail in Appendix 5.1D, showed that impacts under fumigation conditions are less then the maximum impacts du ring normal equipment operation. 

## Shoreline Fumigation Modeling Shoreline fumigation modeling is used to determine the impacts as a result of over-water plume dispersion. Because land surfaces tend to both heat and cool more rapidly than water, shoreline fumigation tends to occur on sunny days when the de nser cooler air over water displaces the warmer, lighter air over la nd. During an inland sea breeze, the unstable air over land gradually increases in depth with inland distance. The boundary between stable air over the water and unstable air over the land and the wind speed determine whether the plume will loop down before much dispersion of the pollutants has occurred. SCREEN3 can examine sources within 3000 meters of a large body of water, and was used to calculate the maximum shoreline fumigation impact. The model uses a stable onshore flow and a wind speed of 2.5 meters per seco nd; the maximum grou nd-level shoreline fumigation concentration is assumed by the model to occur where the top of the stable plume intersects the top of the well-mixed th ermal inversion boundary layer (TIBL). The

14 EPA, October 1992.

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### model TIBL height was varied between 2 and 6 to determine the highest shoreline fumigation impact. The worst-case (highest) impact was used in determining facility impacts due to shoreline fumigation. Shorelin e breakup fumigation was assumed to persist for up to 3 hours. The shoreline fumigati on analysis is shown in more detail in Appendix 5.1D. 

## Gas Turbine Startup CECP site impacts were also evaluated duri ng simultaneous startup of the two new gas turbines to evaluate short-term impacts under worst-case startup emissions. Gas turbine exhaust parameters used to characterize gas turbine exhaust during startup and the CO and NO x 

### emission rates are shown in Appendix 5.1D. 

## Ozone Limiting In accordance with the procedure followed for similar projects, one-hour NO 2 

### impacts during project operation were modeled using the Plume Volume Molar Ratio Method (PVMRM) adaptation of the Ozone Limiti ng Method (Cole and Summerhays, 1979). AERMOD PVMRM was used to calculate the NO 2 

### concentration based on the PVMRM method, and hourly ozone data. Hourly ozone data collected at the Camp Pendleton monitoring station during the years 2003 thro ugh 2005 were used in conjunction with PVMRM to calculate hourly NO 2 

### concentrations from hourly NO x 

### concentrations. Missing hourly ozone data were substituted prior to use with day-approp riate values (e.g., from the previous day, or the next day, for the same hour). Any other missing hourly ozone data were substituted with 40 ppb ozone (typical ozone tropospheric background level). The PVMRM involves an initial comparison of the estimated maximum NO x 

### concentration and the ambient O 3 

### concentration left in the plume after reaction of NO with O 3 

### to determine which is the limiting factor to NO 2 

### formation. If the remaining O 3 

### concentration is greater than the maximum NO x 

### concentration, total conversion is assumed. If the NO x 

### concentration is greater than the remaining O 3 

### concentration, the formation of NO 2 

### is limited by the remaining ambient O 3 

### concentration. In this case, the NO 2 

### concentration is set equal to the O 3 

### concentration plus a correction factor that accounts for in-stack and near-stack thermal conversion.
Annual NO x 

### impacts were converted to NO 2 

### using the USEPA-guidance Ambient Ratio Method and the nationwide default conversion rate of 0.75. 

## Gas Turbine Commissioning Gas turbine commissioning is the process initial startup, turning and adjustment of the new CTGs and auxiliary equipment and of the emission control systems. The commissioning process consists of sequential test operation of each of the two gas turbines up through increasing load levels, and with successive appl ication of the air pollution control systems. The total set of commissioning tests will requir e approximately 49 days with approximately 415 operating hours for each CTG. With the simultaneous testing of the two gas turbines, the overall length of the commissioning peri od would remain at approximately 49 days. Commissioning of the project may be phased into two separate commissioning periods each approximately 49 days long and each approximat ely one to six months apart, as described in the project description. During the commi ssioning phase of the project, the existing boilers Units 1, 2, and 3 at the Encina Power St ation will remain available for operation, but these boilers will not be operated simultane ously with a CTG undergoing a commissioning test.

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### There are several emissions scenarios possible du ring commissioning. The first is the period prior to SCR system installation, when the co mbustor is being tuned. Under this scenario, the NO x 

### emissions control system would not be functioning and the combustor would not be tuned for optimum performance. CO emissi ons would also affected because combustor performance would not be optimized. The seco nd emissions scenario will occur when the combustor has been tuned but the SCR installati on is not complete, and other parts of the gas turbine operating system are being checke d out. Since the combustor would be tuned but the control system installation would not be complete, NO x 

### and CO levels could again be affected. Commissioning activities and expected emissions are discussed in more detail below.


## 5.1.6.3.3 Impacts during Normal Operation The maximum impacts during the normal operat ion of CECP, calculated from the refined, startup/shutdown and fumigation modeling an alyses described above, are summarized in Table 5.1-27.

TABLE 5.1-27 

### Normal Operation Air Quality Modeling Results for new equipment Modeled Maximum Concentrations (μg/m 3 )

Pollutant Averaging Time Normal Operations AERMOD Startup/Shutdown AERMOD Fumigation SCREEN3 Shoreline Fumigation SCREEN3
Combined Impacts Both CTGs

NO 2 1-hour Annual 13.8 0.2 87.4 a 2.8 c 19.4 c
SO 2 1-hour 3-hour 24-hour Annual 4.5 2.5 0.7 0.0 b b b b 0.8 0.7 0.3

c 5.6 2.8 0.4 c
CO 1-hour 8-hour 9.4 3.7 1127.2 470.5 1.7 1.0 11.8 2.3

PM 2.5 /PM 10 24-hour Annual 2.2 0.1 b b 0.6 c 0.9 c Firepump Engine

NO 2 1-hour Annual 83.8 0.0 d d e e e e
SO 2 1-hour 3-hour 24-hour Annual 0.2 0.0 0.0 0.0 d d d d e e e e e e e e
CO 1-hour 8-hour 17.5 4.6 d d e e e e

PM 2.5 /PM 10 24-hour Annual 0.0 0.0 d d e e e e

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TABLE 5.1-27 

### Normal Operation Air Quality Modeling Results for new equipment Modeled Maximum Concentrations (μg/m 3 )

Pollutant Averaging Time Normal Operations AERMOD Startup/Shutdown AERMOD Fumigation SCREEN3 Shoreline Fumigation SCREEN3
Combined Impacts New Equipment

NO 2 1-hour Annual 83.8 0.2 f f f f f f

SO 2 1-hour 3-hour 24-hour Annual 4.5 2.5 0.7 0.0 f f f f f f f f f f f f

CO 1-hour 8-hour 17.5 4.6 f f f f f f

PM 2.5 /PM 10 24-hour Annual 2.2 0.1 f f f f f f

Notes: a = applicable, because startup/shutdown emissions are included in the modeling for annual average. b = Not applicable, because emissions are not elevated above normal operation levels during startups/shutdowns.c = Not applicable, because inversion breakup is a short-term phenomenon and as such is evaluated only for shortterm averaging periods. d = Not applicable, because engine will not operate during CTG startups/shutdowns. e = Not applicable, this type of modeling is not performed for small combustion sources with relatively short stacks. f = Impacts are the same as shown for CTGs.



## 5.1.6.3.4 Impacts During Gas Turbine Commissioning During the gas turbine commissioning phase, NO 2 

### and CO impacts may be higher than under the operating conditions evaluated abov e. The commissioning period is comprised of equipment tests and verification. These tests and the associated NO x 

### and CO emissions are briefly summarized below. The emissions ca lculations are shown in more detail in Appendix 5.1B.

• Full Speed No Load Tests (FSNL) – The tests include a test of the gas turbine ignition system, a test to assure that the CTG is sync hronized with its electric generator, and a test of the CTG’s overspeed system.

• Minimum Load Tests – These tests will occur over seve ral days. During this testing period, the CTG combustor will be tuned to minimize emissions and other checks will be performed. This test period will allo w for complete combustion path warm-up, required for removing all debris that co uld potentially damage the SCR catalyst.

• Multiple Load Tests (SCR/Oxidation Cataly st Operational at Various Levels) – These tests will occur over several days. By the be ginning of this test period, the control systems will be installed and will be tuned to achieve NO x 

### and CO control at design levels.

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### • Performance Tests (SCR/Oxidation Catalyst at Full Control) – These tests will also occur over a several-day period, with the CTGs operating from minimum to maximum load.
It is assumed that the maximum modeled NO 2 

### and CO impact during commissioning will occur under the gas turbine operating conditio ns that are least favorable for dispersion. These conditions are expected to occur under low-load conditions. Emission rates and stack parameters for the gas turbines during commissioning are shown in Appendix 5.1D. Modeled impacts during co mmissioning are summarized in Table 5.1-28. Because there will be a staggered commissionin g schedule for the project, the two CTGs will not undergo commissioning simultaneousl y. Consequently, the impacts shown in Table 5.1-28 are based on one CTG undergoing commissioning and the second CTG undergoing a normal startup/shutdown.

TABLE 5.1-28 

### Modeled Impacts During Commissioning (Combined Impacts Both CTGS) Pollutant/Averaging Period Modeled Concentration, μg/m 3

NO 2 – 1-hour 129.2
CO – 1-hour 3321.7
CO – 8-hour 1363.6



## 5.1.6.3.5 Ambient Air Quality Impacts from the Proposed Project To determine a project’s air quality impacts, the modeled concentrations are added to the maximum background ambient air concentratio ns and then compared to the applicable ambient air quality standards. The maximum ba ckground ambient concentrations are listed in the following text and tables. A discussion of why the data collected at these stations are representative of ambient concentrations in the vicinity of the proposed project was provided above. Table 5.1-29 presents the maximum concentrations of NO 2 

### , CO, SO 2 

### , PM 10 

### , and PM 2.5 

### recorded between 2004 and 2006 from nearby monitoring stations, as required by Appendix B(g)(8)(G) of the CEC guidelines.

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TABLE 5.1-29 

### Maximum Background Concentrations a 

### , Project Area, 2004-2006 ( μ G/M 3 

### )

Pollutant Averaging Time 2004 2005 2006

1-hour 185.9 144.6 152.1 NO 2 (Camp Pendleton) Annual 22.5 22.5 20.7
1-hour 110.0 94.3 89.1 3-hour 52.4 68.1 78.6 24-hour 23.6 23.6 23.5 SO 2 (San Diego)
Annual 10.5 7.9 10.5
1-hour 6,300 5,900 5,700 CO (Escondido) 8-hour 3,800 3,100 3,600
24-hour 57 42 51 PM 10 (Escondido) Annual 28 24 24
24-hour b 37 32 28 PM 2.5 (Escondido) Annual 14.1 12.3 11.5
Notes:

a With the exception of 24-hr PM 2.5 , bolded values are the highest during the three years and are used to

represent background concentrations.
b 24-hour average PM 2.5 concentrations shown are 98 th percentile values rather than highest values because

compliance with the ambient air quality standards is based on 98 th percentile readings. Since the ambient standard is based on a 3-year average of the 98 th percentile readings, the 3-year average of the 2004 to 2006 98th percentile readings was used to r epresent the background concentration.
Source: California Air Quality Data, California Air Resources Board website; EPA AIRData website. Reported values have been rounded to the nearest tenth of a μg/m 3 except for PM 10 which were already rounded to the nearest integer.



### The maximum modeled concentrations in Tables 5.1-27 and 5.1-28 are combined with the maximum background ambient concentrations in Table 5.1-29 and compared with the state and federal ambient air quality standards in Table 5.1-30. Using the conservative assumptions described earlier, the results indicate that the CECP will not cause or contribute to violations of state or federal air quality standards, with the exception of the state PM 10 

### and PM 2.5 

### standards. For these pollutants, existing 24-hour average PM 10 

### background concentrations and PM 10 

### and PM 2.5 

### annual background concentrations already exceed state standards. The following discu ssion demonstrates that impacts from the proposed project will not exceed significant impact levels.

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TABLE 5.1-30 

### Modeled Maximum proposed Project Impacts

Pollutant Averaging Time Maximum Project Impact (μg/m 3 ) Background (μg/m 3 ) Total Impact (μg/m 3 ) State Standard

(μg/m 3 ) Federal Standard

(μg/m 3 )
NO 2 1-hour Annual 83.8 0.2 185.9 22.5 270 23 338 56 — 100

SO 2 1-hour 3-hour 24-hour Annual 4.5 2.5 0.7 0.0 110.0 78.6 23.6 10.5 115 81 24 11 650

— 109

— — 1300 365 80

CO 1-hour 8-hour 3,321.7 1,363.6 6,300 3,800 9,622 5,164 23,000 10,000 40,000 10,000

PM 10 24-hour Annual 2.2 0.1 57 28 59 28 50 20 150

—
PM 2.5 24-hour Annual 2.2 0.1 32.2 14.1 34 14 — 12 35 15



## PSD Significance Levels The Prevention of Significant Deterioratio n (PSD) program was established to allow emission increases that do not result in sign ificant deterioration of ambient air quality in areas where criteria pollutants have not exc eeded the NAAQS. The net emission increase shown later in Table 5.1-33 shows that althou gh the CECP will be a major source, the net increases resulting from the project will not exceed regulatory significance thresholds with the shutdown of the existing Units 1, 2, and 3 at the Encina Power Station. Consequently, the project will not be subject to PSD review. While the project will not trigger a PSD review, an analysis was conducted to determine whethe r the ambient impacts of the project exceed the PSD significance thresholds, as these thresh olds are generally used as one measure of whether the project’s ambient impacts will be significant. Modeled project impacts during normal operation are compared with the PSD si gnificance thresholds in Table 5.1-31 below. As shown in this table, the maximum impacts for the project during normal operation are below the PSD significance thresholds.

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TABLE 5.1-31 

### Comparison of Maximum Modeled Impacts and PSD Significant Impact Levels

Pollutant Averaging Time Significant Impact Level, μg/m 3 Maximum Modeled Impact for CECP, μg/m 3 Exceed Significant Impact Level?

NO 2 Annual 1 0.2 No

SO 2 3-hour 24-Hour Annual 25 5 1 2.5 0.7 0.0 No

CO 1-Hour 8-Hour 2000 500 1127 471 No

PM 10 24-Hour Annual 5 1 2.2 0.1 No



## 5.1.6.4 Screening Health Risk Assessment A screening health risk assessment (SHRA) was conducted to determine expected impacts on public health of the noncriteria pollu tant emissions from the operation of two CTGs/HRSGs and emergency firepump engine . The SHRA was conducted in accordance with the OEHHA’s “Air Toxics Hot Spots Pr ogram Guidance Manual For Preparation Of Health Risk Assessments” (October 2003) and the March 2005 SDAPCD Supplemental Guidelines for Submission of Air Toxics “H ot Spots” Program Health Risk Assessments (HRAs). Following SDAPCD Rule 1200 (Toxics New Sour ce Review) guidance, the SHRA estimated the offsite potential Maximum Incremental Cancer Risk (MICR) at the point of maximum impact, at the location (e.g., residence) of the maximally exposed individual (MEI) and to the maximally exposed worker (MEW), and th e potential long-term (chronic) and shortterm (acute) non-carcinogenic health impa cts from non-carcinogenic emissions. The CARB/OEHHA-approved Hotspots Analysis and Reporting Program (HARP) (Version 1.3, October 18, 2005) computer program was used to evaluate multipathway exposure to noncriteria pollutant emissions. The individual po llutant carcinogenic risks are assumed to be additive. Because of the conservatism (overpre diction) built into the established risk analysis methodology, the actual risk s will be lower than those estimated. The potential health risks are presented in Ta ble 5.1-32, and a detailed discussion of theapproach used for the screening level risk assessment including the detailed non-criteriapollutant calculations is provided in the Public Health Impact Section 5.9.

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TABLE 5.1-32 

### Potential Health Risks from the Operation of CECP Significance Thresholds CECP Significant?

Maximum Incremental Cancer Risk (MICR) at Point of Maximum Impact * 10 In one million 0.16 No

Acute Inhalation Health Hazard Index 1.0 0.10 No

Chronic Inhalation Health Hazard Index 1.0 0.005 No

Note: * The Diesel firepump engine is responsible for the majority of the cancer risk.


### The acute and chronic health hazard indices are well below 1.0, and hence, are not significant. The MICR is 0.16 in one million, well below the ten in one million limit for the project proposed with Toxics-BACT. The CECP w ill not pose a significant health risk at any location, under any weather conditions , under any operating conditions.



## 5.1.6.5 Construction Impacts Analysis The overall construction phase of the prop osed project is scheduled to occur over approximately a 19-month period provided that both CTGs units are constructed simultaneously (Single Phase Construction). If the construction of the two CTGs is staggered, the overall construction schedule would increase to approximately 25 months (Phased Construction). Emissions due to the construction phase of the project have been estimated, including an assessment of emissions from vehicle and equipment exhaust and the fugitive dust generated from material handling. A dispersion modeling analysis was conducted based on these emissions. A detailed analysis of the emissions and ambient impacts is included in Appendix 5.1E. The resu lts of the analysis indicate that the direct maximum construction impacts will be belo w the state and federal ambient air quality standards for criteria pollutants. The best ava ilable emission control techniques will be used.
Combustion diesel PM 10 

### emission impacts from delivery trucks and other construction equipment have also been evaluated to demonstrate that the carcinogenic risk from construction activities will be below ten in one million at all receptors. This screening health risk assessment is included in the Section 5.9, Public Health Impact.


# 5.1.7 Consistency with Laws, Ordinances, Regulations, and Standards This section considers consistency separately for federal, state and local requirements.



## 5.1.7.1 Consistency with Federal Requirements The SDAPCD has been delegated authority by the USEPA to implement and enforce most federal requirements that may be applicable to the proposed project, including new source performance standards and new source review for nonattainment pollutants. The project will also be required to comply with the Federa l Acid Rain requirements (Title IV). Because the SDAPCD is delegated authority to implement Title IV through its Title V permit program, the modified Title V Federal Operating Permit that will be issued as a result of the

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### project will include the necessary requirements for compliance with the Title IV Acid Rain provisions. Because the SDAPCD has not been delegated the authority to implement the PSD program, USEPA Region 9 retains responsibl e for this regulatory program for purposes of the project.


## 5.1.7.1.1 PSD Program USEPA has promulgated PSD regulations for ar eas that are in compliance with national ambient air quality standards (40 CFR 52.21). The PSD program allows new sources of air pollution to be constructed, or existing source s to be modified, while preserving the existing ambient air quality levels, protecting public he alth and welfare, and protecting Class I areas (e.g., specific national parks and wilderness areas). There are five principal areas of the PSD program: (1) Applicability; (2) Best Available Control Technology; (3) Pre-construction Monitoring; (4) Increments Analysis; and (5 ) Air Quality Impact Analysis. Although issuance of the PSD permit will be the responsi bility of USEPA Region 9, the protection of Class I areas is still the responsibility of the Federal Land Managers (FLMs). The federal PSD requirements apply on a pollutant -specific basis to any project that is a new major stationary source or a major modification to an existing stationary source. (These terms are defined in federal re gulations.) (40 CFR 52.21) Since the Encina Power Station is an existing major source, the determination of applicability is based on evaluating the emissions changes associated with the proposed project in addition to all other emissions changes at the facility over a 5-year lookback period. In Table 5.1-33 the net emission change at the Encina Power Station, based on the emissions from the new equipment and the shutdown of the existing units, are compared to the regulatory significance thresholds. As shown in this table, the net emission changes associated with the project are below these significance thresholds, and thus the propos ed project is not subject to PSD review. Consequently, the requirements of this regulation will not be discussed further.

TABLE 5.1-33 

### Net Emission Change and PSD Applicability

Pollutant Facility Net Increase (tpy) PSD Significance Levels (tpy) Are Increases Significant?

NO x 20.1 40 No
SO 2 -5.9 40 No
VOC 5.0 N/A* N/A*
CO -144.0 100 No

PM 10 0.0 15 No

Note: * Since the project area is classified as a federal nonattainme nt for ozone, this pollutant is not subject to the PSD regulations.



## 5.1.7.2 Consistency with State Requirements As discussed in Section 5.1.4.1.2, State law set up local air pollution control districts and air quality management districts with the principa l responsibility for regulating emissions from stationary sources. The CECP is under the local jurisdiction of the SDAPCD, and hence,

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### compliance with District regulations will assure compliance with state air quality requirements.



## 5.1.7.3 Consistency with Local Requirements: SDAPCD. The SDAPCD has been delegated responsibility for implementing local, state, and Federal air quality regulations in the San Diego Air Basin. The project is subject to District regulations that apply to new stationary sources, to the prohibitory regulations that specify emission standards for individual equipment categories, and to the requirements for evaluation of impacts from non-criteria po llutants. The following sections include the evaluation of the CECP compliance with applicable District requirements.


## 5.1.7.3.1 New Source Review Requirements Under the regulations that govern new sources of emissions, the project is required to secure a preconstruction Determination of Complianc e from the SDAPCD, as well as demonstrate continued compliance with regulatory limits when the new equipment becomes operational. The preconstruction review includes demons trating that subject new equipment will use best available control technology (BACT), will provide any necessary emission offsets, and will perform an ambient air quality impact anal ysis. The requirements of each of these elements of the SDAPCD’s new source review program are discussed below.


## 5.1.7.3.2 Best Available Control Technology (BACT) BACT must be applied to a new or modified emissions unit resulting in an emissions increase exceeding SDAPCD BACT threshold levels. In Table 5.1-34, the maximum daily emissions from each gas turbine and the fire pump engine are compared with the BACT thresholds. As shown in this table, th e CTGs/HRSGs are subject to BACT for NO x 

### , VOC, SO x 

### , and PM 10 

### . However, emissions from the emerge ncy firepump engine are below the BACT trigger levels, so the engine is not required to use BACT.

TABLE 5.1-34 

### SDAPCD BACT Emission Thresholds CECP Emission Rates (lbs/day) Pollutant * Threshold (lbs/day) Each CTG/HRSG Firepump Engine
PM 10 10 228.0 0.0
NO x 10 877.0 2.1
SO x 10 105.5 0.0
VOC 10 219.4 0.1

Note: * SDAPCD Rule 20.3 does not include a BACT requirement for CO.


### BACT for the applicable pollutants was determined by reviewing SDAPCD BACT Guidance, 15 

### the South Coast Air Quality Managemen t District BACT Guidelines Manual, 16

15 SDAPCD. New Source Review Requirements for Best Av ailable Control Technology (BACT) Guidance Document, May 2002. 16 SCAQMD. BACT Guidelines, http://www.aqmd.gov/bact/BACTGuidelines.htm.

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### the most recent Compilation of California BACT Determinations, 17 

### CAPCOA (2nd Ed., November 1993), and USEPA’ s RACT/BACT/LAER Clearinghouse. 18 

### For the gas turbines, the SDAPCD considers BACT to be the most stringent level of demonstrated emission control that is feasible. The detailed BACT analysis is included in Appendix 5.1C. The CECP gas turbines will use the BACT measures discussed below.

• BACT for NO x 

### emissions from the gas turbine will be the use of low-NO x 

### emitting equipment and add-on controls. The project will use SCR and dry low-NO x 

### combustion to reduce NO x 

### emissions to 2.0 ppmvd NO x 

### , corrected to 15 percent O 2 

### (ppmc).

• BACT for CO emissions will be achieved by using good combustion practices and an oxidation catalyst to achieve CO emissions of 2.0 ppmc.

• BACT for VOC emissions will be achieved by use of good combustion practices in the gas turbines to achieve VO C emissions of 2.0 ppmc.

• BACT for PM 10 

### and SO x 

### is best combustion practices and the use of natural gas. The proposed CTGs will burn exclusively PU C-regulated natural gas with a maximum short-term sulfur content of 0.75 grains pe r 100 scf (gr/100 scf), and an annual average level of 0.25 gr/100 scf.


## 5.1.7.3.3 Emission Offsets Because the Encina Power Station is an existing major facility, emission offsets are required for net emission increases that occur at the facility above SDAPCD offset threshold levels. Emission offsets are required only for federal nonattainment pollutants. Since the District is classified as a federal nonattainment area for ozone, the pollutants regulated under the emission offset section of the District new so urce review program are the ozone precursors NO x 

### and VOC. As shown in Table 5.1-35, net increases in NO x 

### and VOC associated with the installation of the new equipment and shutdown of existing units are below the emission offset trigger levels. Therefore, the project does not trigger the SDAPCD emission offset requirements.

TABLE 5.1-35 

### SDAPCD Nonattainment Pollutant Emission Offset Thresholds (tpy)
Pollutant Emission Offset Trigger Level* Net Emission Change Emission Offsets Required?
NO x 25 20.1 No
VOC 25 5.0 No
Note:

* SDAQPD Rule 20.1, Table 20.1-5.



## 5.1.7.3.4 Air Quality Impact Analysis Under the SDACPD new source re view regulations, an air quality impact analysis must be performed if new or modified emission units result in emission increases above specific trigger levels. This analysis must confirm that the above emission increases will not interfere with the attainment or maintenance of an app licable ambient air quality standard or cause

17 ARB. Statewide Best Available Control Technology ( BACT) Clearinghouse, http://www.arb.ca.gov/bact/bact.htm, August 16, 2005. 18 EPA. RACT/BACT/LAER Clearinghouse, http://cfpub.epa.gov/rblc/htm/bl02.cfm.

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### additional violations of a standard anywhere the standard is already exceeded. As shown in Table 5.1-36, the emissions for the new equipment are above the air quality impact analysis trigger levels for NO x 

### , CO, and PM 10 

### . Consequently, an air quality impact analysis must be performed for these pollutants. The modeling analyses presented in Section 5.1.5.3 show that the project will not interfere with the atta inment or maintenance of the applicable air quality standards or cause additional violations of any standards.

TABLE 5.1-36 

### Air Quality Impact Analysis (AQIA) Trigger Levels
Pollutant Emissions for New Equipment Trigger Level* AQIA Required? Hourly Emissions
NO x 171 lbs/hr 25 lbs/hr Yes
CO 1,627 lbs/hr 100 lbs/hr Yes
PM 10 N/A — N/A
SO x 9 lbs/hr 25 lbs/hr No Daily Emissions
NO x 1,756 lbs/day 250 lbs/day Yes
CO 10,205 lbs/day 550 lbs/day Yes
PM 10 456 lbs/day 100 lbs/day Yes
SO x 211 lbs/day 250 lbs/day No
Annual Emissions
NO x 76 tpy 40 tpy Yes
CO 217 tpy 100 tpy Yes
PM 10 39 tpy 15 tpy Yes
SO x 6 tpy 40 tpy No
Note: * SDAPCD Rule 20.3, Table 20.3-1.


## 5.1.7.3.5 SDAPCD Prohibitory Rules The general prohibitory rules of the SDAPCD applicable to the project include the following:


## 5.1.7.3.6 Rule 50 – Visible Emissions Prohibits visible emissions as dark as, or darker than, Ringelmann No. 1 for periods greater than three minutes in any hour. The CECP use of natural gas would eliminate the possibility of a dark visible emission.


## 5.1.7.3.7 Rule 51 – Nuisance Prohibits the discharge from a facility of air pollutants that cause injury, detriment, nuisance, or annoyance to the public, or t hat damage business or property. The CECP would not emit odorous pollutants, and the sc reening health risk assessment demonstrated that the potential health risks from the emissions are less than significant.

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## 5.1.7.3.8 Rule 52 – Particulate Ma tter Emission Standards Prohibits PM emissions in excess of 0.10 grai ns per dry standard cubic foot (gr/dscf). The proposed PM 10 

### emission rate for the CTGs will limit PM emissions to less than 0.002 gr/dscf.


## 5.1.7.3.9 Rule 53 – Combustion Contaminants Prohibits sulfur emissions, calculated as SO 2 

### , in excess of 0.05 percent by volume (500 ppmv), and combustion particulate emissi ons in excess of 0.10 gr/dscf at 12 percent CO 2 

### . SO 2 

### emissions from the project will be belo w 0.5 ppmv, based on the fuel sulfur content levels of 0.75 gr/100 scf (short-ter m average) and 0.25 gr/100 scf (long-term average). Compliance with Rule 52 will assure compliance with the grain loading limit of Rule 53.


## 5.1.7.3.10

5.1.7.3.11

5.1.7.3.12

5.1.7.3.13 Rule 62 – Sul fur Content of Fuels Prohibits the burning of gaseous fuel with a sulfur content of more than 10 gr/100 scf and liquid fuel with a sulfur content of more than 0.05 percent sulfur by weight. The natural gas that would be used in the CECP will have a sulfur content that will be less than 0.75 gr S/100 scf (short-term average) and 0.25 gr S/100 scf (long-term average). The Diesel fuel used in the Diesel firepump engi ne will comply with current CARB fuel sulfur limit of 15 ppm, or 0.0015 percent, well below the limit of this rule.


## Rule 69.3.1 – Stationary Gas Turbine Limits NO x 

### emissions from stationary gas turbines rated greater than or equal to 10 MW with post-combustion controls to 9 ppmv (at 15 percent O 2 

### , corrected for efficiency). The NO x 

### emissions from the CECP gas turbines will be limited to 2 ppmv.


## Rule 69.4.1 – Stationary Recipro cating Internal Combustion Engines Limits CO, NO x 

### , and VOC emissions from stationary reciprocating internal combustion engines rated greater than or equal to 50 bhp. However, emergency equipment operating less than or equal to 52 hours per year for testing or maintenance purposes and less than or equal to 200 hours per year for any purpose are exempt from the emission limits of Rule 69.4.1. Therefore, with an annual op erating limit of 50 hours per year for testing/maintenance, the new em ergency firepump engine is exempt from these emission limits.


## 40 CFR Part 6 0, Subpart KKKK (Standar ds of Performance for Stationary Combustion Turbines) This new source performance standard applies to gas turbines with a heat input in excess of 1 MMBtu/hr that commence construction after February 18, 2005, and hence, it is applicable to the CECP CTGs. Subpart KKKK limits NO x 

### and SO 2 

### emissions from new gas turbines based on power output. The limits for gas turbines greater than 30 MW are 0.39 lb NO x 

### per MW-hr and 0.58 lb SO 2 

### per MW-hr. The emission limits of 2.0 ppmc NO x 

### and 0.4 ppmc SO 2 

### proposed for the CECP are well below the Su bpart KKKK limits, as shown in Table 5.1-37.

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TABLE 5.1-37 

### Compliance with 40 CFR 60 Subpart KKKK Proposed Permit Limits Pollutant ppmc lb/hr lb/MW-hr (Max) Subpart KKKK Limit, lb/MW-hr NO x 2.0 15.1 0.05 0.39 SO 2 0.4 4.4 0.02 

### 0.59



### Compliance with the NSPS limits must be demonstrated through an initial performance test. Because the CECP gas turbines will be equipped with a continuous NO x 

### emissions monitor, ongoing annual performance testing will not be required under the NSPS.


## 5.1.7.3.14 40 CFR Part 6 0, Subpart IIII (Standards of Performance for Stationary Compression Ignition Internal Combustion Engines) The new emergency diesel firepump engine will be subject to this NSPS. For engines in this size range, the NSPS requires manufacturers to provide engines that are certified to meet the NSPS emission standards (depending on the year an engine is manufactured). The CECP will comply with the emission limitations of the NSPS by purchasing an engine certified for this application. The NSPS also requires engines in this size r ange to use fuel with a sulfur content not to exceed 15 ppm. The new emergency firepump engi ne will comply with this requirement by using only CARB diesel fuel.


# 5.1.8 Cumulative Air Quality Impacts Analysis An analysis of potential cumulative air qualit y impacts that may result from the CECP and other reasonably foreseeable projects is required by the SDAPCD and the CEC.



## 5.1.8.1 Criteria Pollutant Cumu lative Effects Analysis Cumulative air quality impacts from the CECP and other reasonably foreseeable projects will be both regional and localized in nature. Regional air quality impacts are possible for pollutants such as ozone, which is formed th rough a photochemical process that can take hours to occur. Carbon monoxide, NO x 

### , and SO x 

### impacts are generally localized in the area in which they are emitted. PM 10 

### can create a local air quality problem in the vicinity of its emission source, but can also be a regional issue when it is formed in the atmosphere from VOC, SO x 

### , and NO x 

### . The cumulative effects analysis will consider th e potential for both regional and localized impacts due to emissions from operation of CECP. Regional impacts will be evaluated by comparing maximum daily and annual emission s from CECP with emissions of ozone and PM 10 

### precursors in San Diego County. Localized impacts will be evaluated by looking at other local sources of pollutants that are not in cluded in the background air quality data to determine whether these sources in combination with CECP would be expected to cause significant cumulative air quality impacts.


## 5.1.8.1.1 Regional Impacts Regional impacts are evaluated by assessing CECP’s contribution to regional emissions. Although the relative importance of VOC and NO x 

### emissions in ozone formation differs

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### from region to region and from day to day, state law requires reductions in emissions of both precursors to reduce overall ozone levels . The change in the sum of emissions of these pollutants, equally weighted, provides a rough es timate of the impact of CECP on regional ozone levels. Similarly, a comp arison of the emissions of PM 10 

### precursor emissions from CECP with regional PM 10 

### precursor emissions provides an es timate of the impact of CECP on regional PM 10 

### levels. Table 5.1-38 summarizes these comparisons; detailed calculations for the CECP and the emission reductions for the shutdown and retirement of the existing boiler Units 1, 2, and 3 at the Encina Power Station are shown in A ppendix 5.1B. CECP emissions are compared with regional emissions in 2010, as the project is expected to begin operation in this year. San Diego County emissions projections for 2010 were taken from the Air Resources Board’s web-based emission inventory proj ection software, available at www.arb.ca.gov/app/emsinv/emssumcat.php

. These comparisons show that the total ozone and PM 10 

### precursor emissions reductions from the shutdown and retirement of the existing boilers (Units 1, 2, and 3) at the Encina Power Station will be larger than the maximum potential emissions for the CECP. Therefore, CECP will have an overall positive impact on regional ozone and PM 10 

### formation.

TABLE 5.1-38 

### Comparison of CECP Emissions to Regional Precursor Emissions in 2010: Annual Basis a
Ozone Precursors – Annual Basis Total San Diego County Ozone Precursors, tons/year 121,399 Total CECP Ozone Precursor Emissions, tons/year 100.6
CECP Ozone Precursor Emissions as Percent of Regional Total 0.08% Reductions from Shutdown of Boilers, tons/year b -351.0 CECP Net Ozone Precursor Emissions with Boiler Shutdowns, tons/year -250.4

CECP Net Ozone Precursor Emissions as Percent of Regional Total, with Boiler Shutdowns Net Benefit

PM 10 Precursors – Annual Basis Total San Diego County PM 10 Precursors, tons/year 172,134
Total CECP PM 10 Precursor Emissions, tons/year 145.2
CECP PM 10 Precursor Emissions as Percent of Regional Total 0.08%
Reductions from Shutdown of Boilers, tons/year -462.1
CECP Net PM 10 Precursor Emissions with Boiler Shutdowns, tons/year -316.9
CECP Net PM 10 Precursor Emissions as Percent of Regional Total, with Boiler Shutdowns Net Benefit

Notes:

a County-wide emissions calculated as 365 times daily emissions. b Based on maximum 2-year average emissions during a 10-year lookback period.

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## 5.1.8.1.2 Localized Impacts To evaluate potential cumulative effects of CE CP in combination with other projects in the area, projects within a radius of 6 kilome ters of the project were examined for the cumulative localized impacts analysis. Within this search area, three categories of pr ojects with combustion sources were used as criteria for identification:

• Existing projects that have been in operation since at least 2006.

• Projects for which air pollution permits to construct have been issued and that began operation after 2006.

• Projects for which air pollution permits to construct have not been issued, but that are reasonably foreseeable. Existing projects that have been in operation since at least 2006 are reflected in the ambient air quality data that has been used to repr esent background concentrations for the CECP; consequently, no further analysis of the emi ssions from this category of facilities was performed. Projects for which air pollution permits to co nstruct have been issued but that were not operational in 2006 were identified through a request of permit records from the SDAPCD. The SDAPCD performed a search of its permit computer tracking system for permits issued after January 1, 2006 for projects located with in six miles of the CECP. This search also included permit application packages the SD ACPD is currently processing for projects located within six miles of the CECP. Enclosed as Appendix 5.1F is a copy of the list of projects provided by the SDAPCD. As shown on this list, only one project has CO, NO x 

### , SO x 

### , or PM 10 

### emissions above the CEC established de mi nimis level of 5 tons/year: an emergency generator engine at Hunter Industries loca ted in San Marcos, California. The SDACPD modeling group reviewed this list of projects and concluded that since the above engine is located more than 6 miles from the CECP, there was no need to perform a localized cumulative impact modeling analysis for the CE CP. Consequently, no localized cumulative impact modeling analysis was performed for the project.



## 5.1.8.2 Greenhouse Gas Cumulative Effects Analysis Greenhouse gas (GHG) emissions have received in creasing attention; most significantly, in 2006 the Governor signed the California Global Warming Solutions Act of 2006. Combustion of natural gas in the proposed project’s ga s turbines and diesel combustion in the emergency firepump engine will result in the emissions of the following GHG: carbon dioxide (CO 2 

### ), methane (CH 4 

### ), and nitrous oxide (N 2 

### O). These emissions from the CECP join the emissions of the same GHG fr om the combustion of fossil fuels from all sources (e.g., home natural gas heaters, coal-fired power plants). To the extent that anthropogenic sources of GHGs contribute to climate change, these impacts are global; the project-emitted amount of GHG does not ca use a direct significant impact on the environment.
GHG emissions of CO 2 

### , CH 4 

### , and N 2 

### O for the project are summarized in Table 5.1-39. The detailed GHG emission calculations for th e CECP are included in Appendix 5.1B.

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TABLE 5.1-39 

### GHG Emissions Project

Pollutant Gas Turbines MMT CO 2 e * Firepump Engine MMT CO 2 e * Total MMT CO 2 e *

CO 2 8.46 x 10 5 6.19 x 10 0 8.46 x 10 5

CH 4 2.16 x 10 3 5.84 x 10 -4 2.16 x 10 3

N 2 O 4.96 x 10 2 2.62 x 10 -3 4.96 x 10 2

Total 8.50 x 10 5 6.19 x 10 0 8.50 x 10 5

Note: * Million metric tons of carbon dioxide equivalent.


### GHG emissions from the CECP will be offset in part by the shutdown and retirement of Encina Power Station Units 1, 2, and 3. The net GHG emission increase is shown below in Table 5.1-40 based on a 10-year lookback period for Units 1, 2, and 3. The detailed GHG emission calculations for the Encina Units 1-3 are included in Appendix 5.1B. Further, the CECP will likely result in a reduction of over all operation of less efficient units regionally because these fast starting and more efficien t CECP units can be relied upon to provide quick electrical resources when needed. Histori cally, less efficient steam generating units in San Diego have operated at minimum load duri ng off-peak hours in order to be available for quick response when demand rises. This practice will occur less once the fast starting CECP units are available, which will have a corresponding benefit of reduction in GHG emissions regionally and improvement in overall GHG emission performance per megawatt-hour of production. The exact leve l of regional GHG emission reductions attributed to this is difficult to calculate, however, this benefit is expected to occur regardless.

TABLE 5.1-40 

### Net GHG Emissions Change for Proposed Project

Equipment Total MMT CO 2 e* Reductions from Shutdown of Existing Boilers
Unit 1 1.80 x 10 5

Unit 2 1.92 x 10 5

Unit 3 2.70 x 10 5

Subtotal 6.42 x 10 5
New Equipment Gas Turbines and Firepump Engine 8.50 x 10 5 Net Emission Change 2.08 x 10 5

Note: * Million metric tons of carbon dioxide equivalent.

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### Because GHG emissions can affect climate change on only a global basis, and the project’s GHG emissions are not substantial compared to global emissions, the cumulative impact of the project’s GHG emissions is less than signif icant. The project’s emissions will be subject to regulation pursuant to AB 32; through the implementation of this statute, any remaining cumulative effects will be mitigated. Nonethel ess, through the use of advanced, efficient generating technology for the production of electrical power, the project reasonably minimizes GHG emissions associated with this type of activity.


# 5.1.9 Mitigation Mitigation will be provided for all emission s increases from the CECP in the form of emission reductions from the shutdown and retire ment of existing boilers (Units 1, 2, and 3) at the Encina Power Station and the installation of BACT for the new equipment, as required under SDAPCD regulations. The demonstratio n of compliance with the BACT requirement is provided in Appendix 5.1C. As discussed in Section 5.1.6.3.2 above, the em issions increases from the CECP will be offset through the reductions achieved by shutting down the existing boiler Units 1, 2, and 3 at the Encina Power Station. Table 5.1-35 demonstrat ed that the project will result in a net reduction in emissions of CO and SO x 

### , no net increase in PM 10 

### emissions, and increases in NO x 

### and VOC emissions that are below SDAPCD regulatory offset thresholds. Table 5.1-38 demonstrated that when a 10-year lookback is used to develop the baseline emissions for boiler Units 1, 2, and 3, the project will result in a net reduction in emissions of ozone and PM 10 

### precursors with the shutdown of Units 1, 2, and 3. Therefore, no further mitigation will be needed for the CECP.


# 5.1.10 References ARB. http://www.arb.ca.gov/adam. ARB. Emission Inventory Criteria and Guidelin es Report for the Air Toxics “Hot Spots” Program, May 15, 1997.
ARB. HARP User Guide. December 2003. ARB. Proposed Guidance for Power Plant Siti ng and Best Available Control Technology. June 23, 1999. ARB. Recommended Interim Risk Management Policy for Inhalation-Based Residential Cancer Risk. June 2003.
ARB. Reference Document for California Statewide Modeling Guideline. April 1989. ARB. Report to the Legislature: Gas-Fired Power Plant NO x 

### Emission Controls and Related Environmental Impacts. May 2004 CAPCOA. Air Toxics “Hot Spots” Progra m Revised 1992 Risk Assessment Guidelines. October 1993.
National Climatic Data Center. 1993 data fo r San Diego International Airport (Lindbergh Field).

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-61SECTION 5.1: AIR QUALITY

5.1-62 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 

### Office of Environmental Health Hazard Asse ssment. Acute and Chronic Exposure Levels Developed by OEHHA as of August 2004.
Office of Environmental Health Hazard Asse ssment. Air Toxics Hot Spots Program Risk Assessment Guidelines. Part II. Technical Su pport Document for Describing Available Cancer Potency Factors. December 2002. Smith, T.B., W.D. Sanders, and D.M. Takeuchi . Application of Climatological Analysis to Minimize Air Pollution Impacts in California, Final Report on ARB Agreement A2-119-32. August 1984. South Coast Air Quality Management District. “Risk Assessment Procedures for Rules 1401 and 212,” Version 4.1, November 1998. U.S. Department of Commerce, Weather Bureau. “Climate of the States—California,” December 1959.
U.S.EPA. AirData website. http://www.epa.gov/air/data/

. USEPA. Compilation of Emission Factors. AP-42. Revised 7/00. USEPA. Guideline on Air Quality Models, 40 CFR, Part 51, Appendix W. July 1, 1999. USEPA. Onsite Meteorological Program Guid ance for Regulatory Model Applications, EPA450/4-87-013. August 1995. USEPA. Screening Procedures for Estimating th e Air Quality Impact of Stationary Sources, Revised, EPA-454/R-92-019. October 1992. USEPA. Ambient Monitoring Guidelines for Prev ention of Significant Deterioration (PSD), EPA-450/4-87-007. May 1987.
USEPA. Guideline for Determination of Good En gineering Practice Stack Height. June 1985.FIGURE 5.1-1 

### January Predominant Mean Circulation of the Surface WindsFIGURE 5.1-2 

### April Predominant Mean Circulation of the Surface WindsFIGURE 5.1-3 

### July Predominant Circulation of the Surface WindsFIGURE 5.1-4 

### October Predominant Mean Circulation of the Surface Winds0.00 0.05 0.10 0.15

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearOzone (parts per million)

Maximum 1-Hour Concentration

3-Year Average
California Standard (0.09 ppm)

FIGURE 5.1-5 

### Maximum 1-hour Average Ozone Levels Camp Pendleton 1997-2006

0.00 0.02 0.04 0.06 0.08 0.10

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearOzone (parts per million)

3-Year Average 4th Highest 8-Hour Average California Standard (0.07 ppm) Federal Standard (0.08 ppm)

FIGURE 5.1-6 

### 3-year Average 4th Highest 8-hour Average Ozone Levels Camp Pendleton, 1997-20060.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16 0.18 0.20

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearNO2(parts per million)

Maximum 1-Hour Concentration
3-Year Average California Standard (0.18 ppm)

FIGURE 5.1-7 

### Maximum 1-hour Average NO 2 

### Levels Camp Pendleton, 1997-2006

0.00 0.01 0.02 0.03 0.04 0.05 0.06

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearNO2(parts per million) Annual Average Concentration 3-Year Average Federal Standard (0.053 ppm)

FIGURE 5.1-8 

### Annual Average NO 2 

### Levels Camp Pendleton, 1997-20060 5 10 15 20 25 30 35 40

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearCO (parts per million) Maximum 1-Hour Concentration 3-Year Average California Standard (20 ppm) Federal Standard (35 ppm)

FIGURE 5.1-9 

### Maximum 1-Hour Average CO Levels Escondido, 1997-2006

0 2 4 6 8 10 12

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearCO (parts per million)

Maximum 8-Hour Concentration 3-Year Average California Standard (9 ppm) Federal Standard (9 ppm)

FIGURE 5.1-10 

### Maximum 8-hour Average CO Levels Escondido, 1997-20060.00 0.04 0.08 0.12 0.16

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearSO2(parts per million) Maximum 24-Hour Average Concentration 3-Year Average California Standard (0.04 ppm) Federal Standard (0.14 ppm)

FIGURE 5.1-11 

### Maximum 24-hour Average SO 2 

### Levels San Diego (12th Avenue), 1997-2006



## ,

0 50 100 150 200

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearPM10(ug/m3) Maximum 24-Hour Average Concentration 3-Year Average California Standard (50 ug/m3) Federal Standard (150 ug/m3)

FIGURE 5.1-12 

### Maximum 24-hour Average PM 10 

### Levels Escondido, 1997-2006

## ,

0 5 10 15 20 25 30 35

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearExpected Violation Days Expected Violation Days

3-Year Average

FIGURE 5.1-13 

### Expected Violations of the Ca lifornia 24-hour PM10 Standard (50 μ g/m 3 

### ) Escondido, 1997-2006



## Annual Average PM 10 

## Levels Escondido, 1997-2006

0 5 10 15 20 25 30 35

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearPM10(ug/m3)

Annual Average Concentration

3-Year Average

California Standard (20 ug/m3)

FIGURE 5.1-14 

### Annual Average PM 10 

### Levels Escondido, 1997-20060 20 40 60 80

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearPM2.5(ug/m3)

Maximum 24-Hour Average Concentration 3-Year Average Federal Standard (65 ug/m3) Federal Standard (35 ug/m3) Effective 12/17/2006

FIGURE 5.1-15 

### Maximum 24-hour Average PM2.5 Levels Escondido, 1997-2006

0 5 10 15 20

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Calendar YearPM2.5(ug/m3)

Annual Average Concentration 3-Year Average California Standard (12 ug/m3) Federal Standard (15 ug/m3)

FIGURE 5.1-16 

### Annual Average PM2.5 Levels Escondido, 1997-2005