5.1 Air Quality 

This section describes existing air quality conditions, maximum potential impacts from 

construction and operation of the new Carlsbad 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 proposed project that ensure that air quality 

impacts will not be significant include the following: 

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

• Reduced nitrogen oxides (NOx) emissions with selective catalytic reduction (SCR) 

control systems and dry low- NOx combustors on the gas turbines, 

• Reduced emissions of carbon monoxide (CO) and toxic air contaminants with dry lowNOx combustors and oxidation catalyst systems, 

• Reduced emissions of particulate matter 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 exhaust constituents with an appropriately 

sized exhaust stack. 

This section presents the methodology and results 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 calculating facility impacts, modeling, and analysis. 

The screening health risk assessment, visibility screening analysis, and construction impacts 

analysis are also discussed. Section 5.1.6 discusses 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 Section 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 weather variations all have important effects on the 

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SECTION 5.1: AIR QUALITY 

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 Encina Power Station site. The two new units 

(designated Units 6 and 7) will be on the northeast area of the existing site, between the 

existing rail line and I-5 highway, and at the location of three previously existing fuel oil 

tanks. 

5.1.1.2 Climate and Meteorology 

The climate of San Diego County is subtropical with large-scale wind and temperature 

regimes controlled by the proximity of the Pacific Ocean and seasonal migration of the 

Pacific high-pressure system. As a result, summers are relatively cool and winters are warm 

in comparison to other locations. Temperatures 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 pollutants. The project area receives significant 

sunshine throughout the year, even during winter. Annual average sunshine is the 

percentage of maximum possible time the sun can shine, and is approximately 68 percent in 

the San Diego area. 

Wind speed and direction are key factors influencing 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 dispersion modeling (approved by the San Diego Air 

Pollution Control District [SDAPCD]), the most frequent wind direction is from the 

west-northwest during February though October, and from the northeast during November 

through January. Wind speeds average approximately 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 speed 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 winter1. 

Air quality is determined primarily by the type 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, respectively. As indicated in the figures, winds in 

 

1 WorldClimate. Average Rainfall for San Diego Lindbergh, San Diego 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 (NO2), carbon monoxide (CO), 

sulfur dioxide (SO2), particulate matter with aerodynamic diameter less than or equal to 

10 microns (PM10), particulate matter with aerodynamic diameter less than or equal to 

2.5 microns (PM2.5), and airborne lead. Areas with ambient levels above these standards are 

designated by USEPA as “nonattainment areas” subject to planning and pollution control 

requirements that are more stringent than standard requirements. 

The California Air Resources Board (CARB) has established California ambient air quality 

standards for ozone, CO, NO2, SO2, sulfates, PM10, PM2.5, 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 which the concentration is to be measured. 

Allowable concentrations are based on the results 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 whether 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 concentration 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 selected 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 average of the annual 4th-highest 

daily maximum eight-hour average concentration measured at each monitor within an area. 

The NAAQS for particulates were revised in several respects. First, compliance with the 

current 24-hour PM10 standard is now based on the 99th percentile of 24-hour concentrations 

at each monitor within an area. Two new PM2.5 standards were added: a standard of 

15 μg/m3, based on the three-year average of annual arithmetic means from single or 

multiple monitors (as available); and a standard of 35 μg/m3, based on the three-year 

average of the 98th percentile of 24-hour average concentrations at each monitor within an 

area. Finally, the state adopted a new, lower annual PM10 standard of 20 μg/m3. The state 

PM2.5 standard is 12 μg/m3 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 NO2 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 

Ozone 1 hour 0.09 ppm — 

8 hours 0.070 ppm 0.08 ppma

Carbon 8 hours 9.0 ppm 9 ppm 

Monoxide 1 hour 20 ppm 35 ppm 

Nitrogen Annual Average 0.030 ppm 0.053 ppm 

Dioxide 1 hour 0.18 ppm — 

Annual Average — 80 μg/m3

 (0.03 ppm) 

24 hours 0.04 ppm (105 μg/m3) 365 μg/m3 (0.14 ppm) 

3 hours — 1300b

 μg/m3 (0.5 ppm) 

Sulfur 

Dioxide 

1 hour 0.25 ppm — 

Annual Arithmetic Mean 20 μg/m3 50 μg/m3 Respirable 

Particulate Matter 

(10 Micron) 24 hours 50 μg/m3 150 μg/m3 

70 μg/m3 (proposed by 

USEPA, Dec 20, 05) 

Annual Arithmetic Mean 12 μg/m3 15 μg/m3 Fine (3-year average) 

Particulate Matter 

(2.5 Micron) 24 hours — 35 μg/m3 c 

Sulfates 24 hours 25 μg/m3 — 

30 days 1.5 μg/m Lead 3 — 

Calendar Quarter — 1.5 μg/m3

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, which is designed to protect public welfare. 

c

 3-year average of 98th percentiles. 

d

 In sufficient amount to produce an extinction coefficient of 0.23 per kilometer due to particles when the relative 

humidity is less than 70%. 

5.1.3 Existing Air Quality 

Data from several ambient air monitoring stations 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 NO2 levels, for CO, PM10, and PM2.5 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 SO2 levels, the 

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SECTION 5.1: AIR QUALITY 

nearest monitoring station is located in San Diego approximately 55 kilometers to the south 

from the project site. The nearest sulfate monitor is located in Riverside, Riverside County 

(approximately 90 kilometers to the northeast from 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 μg/m3 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 NOx 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 inversions, 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 area2 for the state ozone standard and a nonattainment 

area for the federal 8-hour ozone standard. 

Maximum ozone concentrations at the Camp Pendleton 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 nonattainment classification system based on the amount by which 

monitored levels of ozone have exceeded ambient air quality standard during the last 3 years. The classification, in order of 

increasing magnitude, includes marginal, moderate, serious, severe, and extreme. 

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SECTION 5.1: AIR QUALITY 

The long-term trends of maximum one-hour ozone 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 highest 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 NO2 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 combine. Although NO is less harmful than NO2, it can be 

converted to NO2 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 NO2. 

Table 5.1-3 shows the long-term trend of maximum one-hour NO2 levels recorded at the 

Camp Pendleton monitoring station during the 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 standard or the federal annual average standard. 

Figure 5.1-7 shows the historical trend of maximum one-hour NO2 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, Camp 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 Resources Board website (http://www.arb.ca.gov/adam/welcome.html; EPA 

AIRData website (http://www.epa.gov/air/data/index.html). 

5.1.3.3 Carbon Monoxide 

CO is a product of inefficient combustion, principally 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 ambient CO levels. Peak CO levels usually occur 

during winter due to a combination 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 levels 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, California 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, with 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 

SO2 is produced when any sulfur-containing fuel is burned. It is also emitted by chemical 

plants that treat, or refine, sulfur or sulfur-containing chemicals. Natural gas contains only a 

small amount of sulfur, typically about 0.2 grains 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 SO2 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 SO2 for 

purposes of state and federal air quality planning. 

Table 5.1-5 presents the state air quality standard for SO2 and the maximum levels recorded 

from 1997 through 2006 at the San Diego monitoring station. The federal 24-hour average 

standard is 0.14 ppm; during the period shown, the average SO2 levels measured at this 

station have been less than approximately 20 percent of the federal standard. Figure 5.1-11 

shows that for several years the maximum 24-hour SO2 levels typically have been less than 

approximately one-half of the state standard. 

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SECTION 5.1: AIR QUALITY 

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 (PM10) 

Particulates in the air are caused by a combination of wind-blown fugitive dust; particles 

emitted from combustion sources and manufacturing processes; sea salts; and organic, 

sulfate, and nitrate aerosols formed in the air from emitted hydrocarbons, sulfur oxides, and 

nitrogen oxides, respectively. In 1984, CARB adopted standards for PM10 and phased out the 

total suspended particulate (TSP) standards that had been in effect previously. PM10

standards were substituted for TSP standards because PM10 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 PM10 standards. San Diego County is unclassified for the federal PM10

standard and is a nonattainment area for the state standard. 

Table 5.1-6 shows the federal and state air quality standards for PM10, maximum levels 

recorded at the Escondido monitoring station during 1997 through 2006, and arithmetic 

annual averages for the same period. The maximum 24-hour PM10 levels exceed the state 

standard for several years, but the annual average PM10 levels have remained below the 

Federal standards throughout the period. 

The trend of maximum 24-hour average PM10 levels is plotted in Figure 5.1-12, and the trend 

of expected violations of the state 24-hour standard (50 μg/m3) is plotted in Figure 5.1-13. 

Note that since PM10 is measured only once every six days, expected violation days are 

six times the number of measured violations. The trend of maximum annual average 

PM10 readings and the California standard is shown in Figure 5.1-14. Annual average 

PM10 concentrations are above the state standard of 20 μg/m3. 

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TABLE 5.1-6 

PM10 Levels in San Diego County, Escondido Monitoring Station, 1997-2006 (μg/m3) 

 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 (PM2.5) 

As discussed previously, the NAAQS for particulates were further revised by USEPA with 

new standards that went into effect on September 16, 1997; two new PM2.5 standards were 

added at that time. In June 2002, CARB established a new annual standard for PM2.5. PM2.5

data have been collected at the Escondido monitoring station since 1999, and are presented 

below. 

Table 5.1-7 shows the state and federal air quality standards for PM2.5, 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 μg/m3 established in 1997. However, this standard was 

reduced to 35 μg/m3 in December 2006. There is not enough data available to draw 

conclusions regarding trends in the 3-year average of 98th percentile values. During the past 

5 years annual average PM2.5 levels have generally been below the federal and above the 

state standards. San Diego County is considered a nonattainment area for the state PM2.5

standard, but is unclassified for the federal standard. 

The trends of 24-hour and annual average PM2.5 levels are plotted in Figures 5.1-15 and 

5.1-16, respectively. 

TABLE 5.1-7 

PM2.5 Levels in San Diego County, Escondido Monitoring Station, 1997-2006 (μg/m3)

 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 

PM2.5 Levels in San Diego County, Escondido Monitoring Station, 1997-2006 (μg/m3)

 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 automobiles 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 increasing 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 (μg/m3) 

 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, California Air Resources Board website 

(http://www.arb.ca.gov/adam/welcome.html; EPA AIRData 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 territories. 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 state 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-Carrell Air Resources Act, through the merger of 

two other state agencies. CARB’s primary responsibilities 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 program; 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 sources, 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 quality 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 regulations 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 stationary 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 applicable federal laws, ordinances, regulations, and 

standards (LORS) and compliance with these requirements 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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SECTION 5.1: AIR QUALITY 

TABLE 5.1-9 

Air Quality Agencies 

Agency Authority Contact 

USEPA Region 9 Permit issuance and oversight, 

enforcement 

Gerardo Rios, Chief 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 has 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 requirements 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 Hazardous 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 deterioration of ambient air quality. 

PSD applies to pollutants for which ambient concentrations do not exceed the 

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SECTION 5.1: AIR QUALITY 

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 wilderness areas). Although this program is normally 

implemented at the local level with federal oversight, 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 require pre-construction and/or post-construction 

ambient air quality monitoring for PSD sources if representative monitoring data are not 

already available. Pre-construction monitoring data must be gathered over a one-year 

period to characterize local ambient air quality. Post-construction air quality monitoring 

data must be collected as deemed necessary by USEPA Region 9 to characterize the impacts 

of proposed project emissions on ambient air quality. 

5.1.5.1.3 Best Available Control Technology 

BACT must be applied to any new or modified 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 conducted 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(μg/m3) 

NO2 Annual 25.0 

SO2 Annual 

24-Hour 

3-Hour 

20.0 

91.0 

512.0 

PM10 Annual 

24-Hour 

17.0 

30.0 

+

 40 CFR 52.21.c. 

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SECTION 5.1: AIR QUALITY 

5.1.5.1.5 Protection of Class I Areas 

The increase in ambient air quality concentrations for the relevant pollutants (i.e., NO2, 

PM10, or SO2) 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, industrial, and other growth must also be analyzed. 

This analysis includes cumulative effects 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 existing boilers at the existing Encina Power 

Station. With the shutdown of the existing boilers, the facility-wide net emission change is 

expected to be below PSD significance thresholds. 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 industrial growth without interfering with the 

attainment and maintenance of NAAQS. New source review jurisdiction has been delegated 

to the SDAPCD for all nonattainment pollutants 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 

SO2 and NOx emissions from electrical power generating facilities. These standards are 

implemented at the local level 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 permits 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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SECTION 5.1: AIR QUALITY 

5.1.5.1.10

5.1.5.1.11

 

National Standards of Performance 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 facilities in specific source categories. These 

standards are implemented at the local level with federal oversight. The applicability of 

these regulations depends on the equipment 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 Ignition Internal Combustion Engines will be 

applicable to the proposed project. Regarding 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 NOx and 

sulfur dioxide (SO2) emissions from gas turbines. Subpart KKKK limits NOx and SO2

emissions from new gas turbines based on power output. The limits for gas turbines greater 

than 30 MW are 0.39lb NOx per MW-hr and 0.58lb SO2 per MW-hr. For the size of engine 

proposed for the emergency firepump engine, the NSPS Subpart IIII, Standards of 

Performance for Stationary Compression Ignition 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/purchased. This regulation 

also requires the engines to use ultra-low sulfur content Diesel fuel. 

Administering Agency: SDAPCD, with USEPA Region 9 oversight. 

National Emission 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 oversight. Only the NESHAPs for gas turbines, 

which limit formaldehyde emissions from gas turbines, are potentially applicable to a new 

power plant project. However, as discussed further below, the gas turbine NESHAP is not 

expected to be applicable to the proposed project 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-Carrell Air Resources Act, through the merger of 

two other state agencies. CARB’s primary responsibilities 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 program; 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 per year (tpy) of any individual HAP, or more than 25 tpy of all 

HAPs combined. 

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SECTION 5.1: AIR QUALITY 

pollution control districts (APCDs); and to review and coordinate preparation of the SIP for 

achievement of the NAAQS. CARB has implemented the following state or federal 

stationary source regulatory programs in accordance 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 Stationary 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 which 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 preparation 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 Clean 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 prepare air quality plans demonstrating the means by 

which the ambient air quality standards will be attained and maintained. 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 toxic 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 potential 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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SECTION 5.1: AIR QUALITY 

include the 1875 federally identified hazardous air pollutants as toxic air contaminants. 

CARB reviews the emission sources of an identified 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 control 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 discharge from any source whatsoever such 

quantities of air contaminants or other material which causes injury, detriment, nuisance, or 

annoyance to any considerable number of persons 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 program, by requiring the development of a 

statewide inventory of air toxics emissions from 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 assessment, 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 facilities whose air toxics emissions are deemed to 

pose a significant health risk to implement risk 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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SECTION 5.1: AIR QUALITY 

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), regional, 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 several 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 source 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 review 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 District 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 pollutants must first obtain an Authority to Construct 

from the SDAPCD. Under Rule 20.5 (h) (Power Plants), the District’s Final Determination of 

Compliance acts as an authority to construct 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 Stationary Sources and PSD Sources) implements the 

federal NSR and PSD programs, as well as the 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/Aa N/Ab N/Ab

NOx 10 50 25 

PM10 10 100 15 

SO2 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 hence, not subject to LAER requirements

The SDAPCD defines BACT as the most stringent emission limitation or control technique 

that: 

• Has been proven in field application 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 modification, 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 USEPA 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 exceeding 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 NOx 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 emission 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 precursors) 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 increase subject to offset requirements. San Diego 

County is classified as a federal nonattainment area for the 8-hour ozone standard. 

Therefore, emissions of NOx and VOCs, as precursors to ozone are subject to the emission 

offset requirements. VOC emission reductions may be used to offset NOx 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 

NOx 50 25 

SOx N/Ac N/Ac

CO N/Ac N/Ac

VOC 50 25 

PM10 N/Ac N/Ac

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, SOx, and PM10 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 impacts 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 

NOx 25 250 40 

PM10 N/A 100 15 

SOx 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 Source Review) provides a mechanism for 

evaluating the potential impact of toxic air 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 source will not exceed the risk thresholds 

summarized in Table 5.1-14. As shown in this table, 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 NOx

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 Exemption (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 proposed 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 Stationary 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 the 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 Permit 

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 SO2 and NOx, and monitor SO2, NOx, 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 acid rain permit will be submitted according to 

the timeframe discussed above. 

Federal Operating Permit 

Rule 1414 (Applications) requires new or modified major facilities, NSPS sources, NESHAP 

sources, and/or Phase II acid rain facilities to obtain an operating permit containing the 

federally enforceable requirements mandated 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 operation. The application must present a 

process description, all new stationary sources at the facility, applicable regulations, 

estimated emissions, associated operating conditions, alternative operating scenarios, a 

facility compliance plan, and a compliance certification. 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 submitted according to the timeframe discussed above. 

New Source Performance Standards 

Regulation X (Standards of Performance for New Stationary Sources) adopts, by reference, 

the federal standards of performance for new or modified stationary sources. The 

applicability of the New Source Performance Standards is discussed above under the 

Federal regulations. 

SDAPCD Prohibitory Rules 

The general prohibitory rules of the SDAPCD applicable to the proposed project include the 

following: 

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. 

Rule 51 – Nuisance 

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 – Particulate Matter Emission Standards 

Prohibits PM emissions in excess of 0.10 grains per dry standard cubic foot (gr/dscf). 

Rule 53 – Combustion Contaminants 

Prohibits sulfur emissions, calculated as SO2, in excess of 0.05% by volume (500 parts 

per million by volume (ppmv), and combustion particulate emissions in excess of 

0.10 gr/dscf at 12 percent CO2. 

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5.1.5.3.19

5.1.5.3.20

5.1.5.3.21

Rule 62 – Sulfur 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. 

Rule 69.3.1 – Stationary Gas Turbines 

Limits NOx emissions from stationary gas turbines rated greater than or equal to 10 MW 

with post-combustion controls to 9 ppmv (at 15 percent O2, corrected for efficiency). 

Rule 69.4.1 – Stationary Reciprocating Internal Combustion Engines 

Limits CO, NOx, 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 QUALITY 

TABLE 5.1-15 Laws, Ordinances, Regulations, Standards and Permits for Protection of Air Quality 

LORS Purpose 

Regulating 

Agency Permit or Approval 

Schedule a

of Pe

Federal Clean Air Act (CAA) §160-169A and implementing regulations, Title 42 United States Code (USC) §7470-7491 (42 USC §7470-7491), Title 40 Code of Federal Regulations (CFR) Parts 51 & 52 (Prevention of Significant Deterioration Program) 

Requires prevention of significant deterioration (PSD) review and facility permitting for construction of new or modified major stationary sources of air pollution. PSD review applies to pollutants for which ambient concentrations are lower than NAAQS.

USEPA PSD Permit for a New Major 

Source or major modification. 

CECP is exthis regulati

CAA §171-193, 42 USC §7501 et seq. (New Source Review) 

Requires new source review (NSR) facility permitting for construction or modification of specified stationary sources. NSR applies to pollutants for which ambient concentration levels are higher than NAAQS. 

SDAPCD with USEPA oversight 

Determination of Compliance (DOC) with conditions limiting emissions. 

Agency appobtained beof construct

CAA §401 (Title IV), 42 USC §7651 (Acid Rain Program) 

Requires reductions in NOx and SO2emissions. 

SDAPCD with USEPA oversight 

Acid Rain program requirements included in Determination of Compliance, Permit to Operate, and Title V permit. 

Meet compldeadlines lisregulations. 

CAA §501 (Title V), 42 USC §7661 (Federal Operating Permits Program) 

Establishes comprehensive permit program for major stationary sources. 

SDAPCD with USEPA oversight 

Modified Title V permit after review of application. 

Permit applmodify existpermit will bsubmitted w12 months acommencemoperation. 

CAA §111, 42 USC §7411, 40 CFR Part 60 (New Source Performance Standards [NSPS]) 

Establishes national standards of performance for new stationary sources. 

SDAPCD with USEPA oversight 

DOC with conditions limiting emissions. 

Agency appobtained beof construct

5.1-24 EY072007001SAC/361219/07251
TABLE 5.1-15 Laws, Ordinances, Regulations, Standards and Permits for Protection of Air Quality 

LORS Purpose 

Regulating 

Agency Permit or Approval 

Schedule a

of Pe

State H&SC §44300-44384; California Code of Regulations (CCR) §93300-93347 (Toxic "Hot Spots" Act) 

Requires preparation and biennial updating of facility emission inventory of hazardous substances; risk assessments. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Screening Hsubmitted aAFC. 

California Public Resources Code §25523(a); 20 CCR §§1752, 2300-2309 (CEC and CARB Memorandum of Understanding) 

Requires that CEC’s decision on AFC include requirements to assure protection of environmental quality; AFC required to address air quality protection. 

CEC Final Certification with 

conditions limiting emissions. 

SDAPCD isDOC precedapproval of 

17 CCR § 93115 (ATCM for Stationary Compression Ignition Engines) 

Establishes emission and operational limits for diesel-fueled stationary compression ignition engines. 

SDAPCD and CARB 

DOC with conditions limiting emissions and operation. 

Agency appobtained beof construct

Local SDAPCD Rule 20.3 (New Source Review – Major Stationary Sources and PSD Sources) 

NSR: Requires that pre-construction review be conducted for all proposed new or modified sources of air pollution, including BACT, emissions offsets, and air quality impact analysis.

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained beof construct

SDAPCD Rule 1200 (Toxics, New Source Review) 

Requires that pre-construction review be conducted for all proposed new or modified sources of toxic air contaminants, including T-BACT, and a health risk assessment. 

SDAPCD with USEPA oversight 

DOC with conditions limiting emissions. 

Agency appobtained beof construct

SDAPCD Rule 1414 (Title V Applications) 

Implements operating permits requirements of CAA Title V. 

SDAPCD with USEPA oversight 

Issues modified Title V permit after review of application. 

Agency appobtained beof construct

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

TABLE 5.1-15 Laws, Ordinances, Regulations, Standards and Permits for Protection of Air Quality 

LORS Purpose 

Regulating 

Agency Permit or Approval 

Schedule a

of Pe

SDAPCD Rule 1412 (Federal Acid Rain Program Requirements) 

Implements acid rain regulations of CAA Title IV. 

SDAPCD with USEPA oversight 

Title IV requirements included in DOC, Permit to Operate, and Title V permit. 

Application within 12 mstart of faciloperation. 

SDAPCD Rule 50 (Visible Emissions) 

Limits visible emissions to no darker than Ringelmann No. 1 for periods greater than 3 minutes in any hour. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained pricommencemoperation. 

SDAPCD Rule 51 (Nuisance) Prohibits emissions in quantities that 

adversely affect public health, other businesses, or property. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained beof construct

SDAPCD Rule 52 (Particulate Matter) 

Limits PM emissions from stationary sources. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained beof construct

SDAPCD Rule 53 (Combustion Contaminants) 

Limits SO2 emissions from stationary 

sources. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained beof construct

SDAPCD Rule 62 (Sulfur Content of Fuels) 

Limits the sulfur content of fuels combusted in stationary sources. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained beof construct

SDAPCD Rule 69.3.1 (Stationary Gas Turbines) 

Limits NOx emissions from stationary 

gas turbines. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained beof construct

SDAPCD Rule 69.4.1 (Stationary Reciprocating Internal Combustion Engines) 

Limits CO, NOx, and VOC emissions 

from stationary reciprocating internal combustion engines. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Proposed nis exempt frregulation doperating lim

5.1-26 EY072007001SAC/361219/07251
EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 

TABLE 5.1-15 Laws, Ordinances, Regulations, Standards and Permits for Protection of Air Quality 

LORS Purpose 

Regulating 

Agency Permit or Approval 

Schedule a

of Pe

SDAPCD Regulation X (New Source Performance Standards: Subpart KKKK, Stationary Gas Turbines) 

Requires monitoring of fuel, other operating parameters; limits NOx, SO2, 

and PM emissions, requires source testing, emissions monitoring, and recordkeeping. 

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained beof construct

SDAPCD Regulation X (New Source Performance Standards: Subpart IIII, Stationary Compression Ignition Internal Combustion Engines) 

Limits VOC, NOx, CO, and PM 

emissions and requires recordkeeping.

SDAPCD with CARB oversight

DOC with conditions limiting emissions. 

Agency appobtained beof construct
SECTION 5.1: AIR QUALITY 

5.1.5.3.22 Attainment Status 

Based on the measured existing air quality described 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 

Ozone 1 hour Nonattainment Attainment 

8 hours Designation pending Nonattainment 

Carbon 8 hours Attainment Attainment 

Monoxide 1 hour Attainment Attainment 

Nitrogen Annual Average No CAAQS Attainment 

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 

Respirable Particulate Annual Arithmetic Mean Nonattainment Unclassifiable 

Matter (10 Micron) 24 hours Nonattainment Unclassifiable 

Fine Particulate Matter Annual Arithmetic Mean Nonattainment Attainment 

(2.5 Micron) 24 hours No CAAQS Attainment 

Sulfates 24 hours Attainment No NAAQS 

Lead 30 days Attainment No NAAQS 

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 analysis of impacts from criteria pollutants 

(NO2, CO, PM10, and SO2) and noncriteria pollutants during project construction and 

operation. The analyses cover each phase of the project. Section 5.1.5.1 gives an overview of 

the analytical approach. Section 5.1.5.2 presents 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. 

5.1-28 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

5.1.6.1 Overview of the Analytical 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 evaluation of the CECP compliance with the 

applicable air quality regulations, including the District’s NSR requirements. These 

analyses are designed to confirm that the project’s design features lead to less-than–

significant impacts even with the following conservative analysis assumptions and 

procedures: maximum allowable emission 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 ground-level impact from modeling, even when 

all of these situations could not physically 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 (HRSG), one condensing steam turbine generator 

(STG), an air-cooled fin-fan cooler, and associated 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 simple 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- NOx combustors and a selective catalytic 

reduction (SCR) system for NOx 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 O2 Concentration, dry volume* 13.69% 

Exhaust CO2 Concentration, dry volume* 3.83% 

Exhaust Moisture Content, wet volume* 7.72% 

Emission Controls Dry Low- NOx Combustor and SCR; oxidation catalyst 

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

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-29 
SECTION 5.1: AIR QUALITY 

As discussed above, the use of natural gas as the sole fuel will minimize emissions of VOC, 

SOx and PM10. 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 (CH4) 95.776% Carbon (C) 72.92 % 

Ethane (C2H6) 1.806% Hydrogen (H) 23.84 % 

Propane (C3H8) 0.335% Nitrogen (N) 1.13 % 

Butane C4H10) 0.122% Oxygen (O) 2.11 % 

Pentane (C5H12) 0.043 % Sulfur (S) 0.75 gr/100 scf (short 

term average) 

0.25 gr/100 scf (long 

term average)

Hexane (C6H14) 0.026% 

Nitrogen (N2) 0.682% 

Carbon Dioxide (CO2) 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 CECP 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 operated 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 summarized in Table 5.1-19, correspond to the 

calculated unit and project emission levels. 

5.1-30 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

Emissions and operating parameters for the CTGs/HRSGs under various loads and ambient 

conditions are shown in Appendix 5.1B. Emissions 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 emissions 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 calculations are included in Appendix 5.1B. 

5.1.6.2.1 Criteria Pollutant Emissions: CECP 

The CTG/HRSG and emergency firepump engine emission rates have been calculated from 

vendor data, project design criteria, and established emission calculation procedures. The 

emission rates for the CTGs and firepump engine are shown in the following tables. The 

detailed emission calculations for these units are shown in Appendix 5.1B. 

CTG Emissions during Normal Operations 

Emissions of NOx, CO, and VOC were calculated from emission limits (in ppmv @ 15% O2) 

and the exhaust flow rates. The NOx 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. SOx, PM10, and PM2.5 emission rates are based on the use of natural gas as 

the fuel and good combustion practices. Emissions are based on the heat input rates shown 

in Table 5.1-19. 

SOx emissions were calculated from the heat input (in MMBtu) and a SOx emission factor (in 

lb/MMBtu). The short-term SOx emission factor of 0.0021 lb/MMBtu was derived from the 

maximum allowable (i.e., tariff limit) fuel sulfur content of 0.75 grains per 100 standard 

cubic feet (gr/100 scf). The annual average SOx emissions were based on the expected 

annual average sulfur grain loading of 0.25 gr/100 scf. 

Maximum hourly PM10 emissions are based on vendor supplied emission levels. 

PM2.5 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 Table 5.1-20. The BACT analysis upon which the 

emission factors are based is presented in Appendix 5.1C and summarized in Section 5.1.6.3. 

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-31 
SECTION 5.1: AIR QUALITY 

TABLE 5.1-20 

Maximum Hourly Emission Rates: CTGs/HRSGS 

Pollutant ppmvd @ 15% O2 Lb/MMBtu lb/hr 

Each Gas Turbinea

NOx 2.0b 0.0072 15.1 

SO2

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 

PM10c n/a 0.0045 9.5 

Notes: 

a

 Emission rates shown reflect the highest value at any operating load. For NOx, CO, and VOC, emission levels 

exclude startups and shutdowns. 

b

 Applicant is requesting that the permit allow hourly average NOx concentrations to exceed 2.0 ppmc under 

certain limited conditions. See text following table. c

 100 percent of particulate matter emissions assumed to be emitted as PM2.5; PM10 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 NOx emissions from the combined cycle 

unit. The Applicant proposes the inclusion of the following NOx emissions excursion 

language in the CEC’s conditions of certification: 

Compliance with the NOx emission limitations shall not be required during 

short-term excursions limited to a cumulative total of 15 hours per calendar 

year. Short-term excursions are defined 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 NOx concentration exceeds 2.0 ppmvd @ 15% O2. 

The maximum 3-hour average NOx concentration for periods that include 

short-term excursions shall not exceed 30 ppmvd @ 15% O2. 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 protection system. All emissions during shortterm excursions shall accrue towards the daily and annual emissions 

limitations of this permit and shall be included 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 during a CTG startup or shutdown are shown in 

Table 5.1-21. PM10 and SO2 emissions are not included in this table because emissions of 

these pollutants will not be higher during startup and shutdown than during normal gas 

turbine operation. During a CTG startup, there are approximately 22 minutes with elevated 

emissions (emissions higher then during normal operation). Consequently, the hourly 

5.1-32 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

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 emission levels followed by 7 minutes of elevated 

emission levels. The Applicant also expects that 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 included in the ambient air impact analysis for the 

project. The detailed CTG startup hourly emission 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* 

NOx 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 shown 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 day containing a startup and/or shutdown. 

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

• The emergency firepump engine may operate up to 1 hours per day and 50 hours per 

year for testing and maintenance (the engine 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. 

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-33 
SECTION 5.1: AIR QUALITY 

TABLE 5.1-22 

Maximum Emissions from New Equipment 

Pollutant 

Emissions/Equipment NOx SO2 CO VOC PM10 

Maximum Hourly Emissionsa

Gas Turbinesa 171.3 8.8 1,627.0 41.4 19.0 

Diesel Firepump Engineb 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 Emissionsa

Gas Turbines 1,754.1 211.1 10,204.5 438.7 456.0 

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 Emissionsa

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 NOx, 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 NOx, CO, and VOC because maximum CTG emissions for these pollutants occur during 

startups/shutdowns. 

The maximum hourly, daily and annual emissions 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 following 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 firing 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 permitted 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 that there could be up to a 6-month stagger 

between the initial commercial operation dates 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 simultaneous operation of the new CTGs and the 

existing Units 1 through 3. The emissions reductions from the shutdown of the existing 

units are based on historical baseline operations and emissions during the most 

representative consecutive two-year period during the five years preceding the filing of the 

5.1-34 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

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 calculation of the historical baseline emissions for the 

existing units at the Encina Power Station is included in Appendix 5.1B. 

TABLE 5.1-23 

Emissions for Existing Units 

Pollutant 

Emissions/Equipment NOx SO2 CO VOC PM10 

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 project 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 NOx SO2 CO VOC PM10 

Potential to Emit for New Equipment 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 firepump engine. These emissions are summarized 

in Table 5.1-25. The detailed noncriteria pollutant emissions calculations and the associated 

screening level health risk assessment are included in the Public Health Impact Section 

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-35 
SECTION 5.1: AIR QUALITY 

(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 existing 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 

5.1-36 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

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 require 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 analyses 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 entrainment and dispersion to simulate the actual 

processes by which a pollutant emission is transported to potential ground-level impact 

areas. 

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-37 
SECTION 5.1: AIR QUALITY 

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 standards and PSD significance levels. If the 

standards are not exceeded in the analysis, then the facility will cause no exceedances under 

any operating or ambient conditions, at any location, under any meteorological conditions. 

In accordance with the air quality impact analysis guidelines developed by USEPA6 and 

CARB7, the ground-level impact analysis includes the following assessments: 

• Impacts in simple, intermediate, and complex terrain 

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

• Impacts from inversion breakup (fumigation) 

Simple, intermediate, and complex terrain impacts 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 concentrations is caused by building 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, resulting in a rapid mixing of pollutants out of the 

stable layer and towards the ground in the unstable layer underneath. 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 fumigation 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 roughness 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) factors. TIBL factors usually cover the range of 

what is expected. For screening modeling purposes, 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.

5.1-38 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

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 y z H z z z H (,,, ) * * / / // // = ⎛

⎝

⎜ ⎞

⎠

⎟ + − − − − +

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 

σyσz = 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 the 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 accurate 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 accordance 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 models were used for different meteorological conditions in 

the ambient air quality impact analysis. 

The USEPA-approved AERMOD8 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 settling and dry deposition of particulates; area, 

 

8 The acronym AERMOD was derived from American Meteorological Society/Environmental Protection Agency Regulatory 

Model. 

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-39 
SECTION 5.1: AIR QUALITY 

line, and volume source types; downwash effects; and gradual plume rise as a function of 

downwind distance. The model is capable of estimating 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 Pendleton monitoring station. AERMOD replaces 

the previous USEPA-recommended model, Industrial 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 gas 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 fumigation. Since the emissions from the emergency 

firepump engine are so small compared to the gas turbine emissions, they are excluded 

from this single-source model used for the fumigation 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 period. The refined modeling uses the stack 

parameters that the screening 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 guidance. 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 consistent with District policy and guidance11 for 

past modeling using ISCST3. 

The required emission source data inputs to both models used in this analysis include 

source locations, source elevations, stack heights, 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 set the fraction of incident heat flux that is transferred into 

the atmosphere. This fraction becomes important in urban areas having an appreciable “urban heat island” effect due to a large 

presence of land covered by concrete, asphalt, 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. 

5.1-40 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

Cartesian coordinate system used is the Universal Transverse Mercator Projection (UTM). 

The stack height that can be used in the model is limited by federal Good Engineering 

Practice (GEP) stack height restrictions, discussed in more detail below. In addition, 

Building Profile Input Program – Plume Rise Model Enhancements (BPIP-PRIME, current 

version 04274) requires nearby building dimension data to calculate the impacts of building 

downwash. 

For the purposes of modeling, a stack height beyond 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 result in excessive concentrations of any air 

pollutant in the immediate vicinity of the source 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 guidance12 for determining GEP stack height indicates that GEP is 

the greater of 65 meters or Hg, where Hg is calculated as follows: 

Hg =H + 1.5L 

where: 

Hg = 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 area 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 Hg = 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 considered 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 buildings analyzed as downwash structures were 

obtained from plot plans. The building dimensions 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 Engineering Practice Stack Height, Revised June 1985. 

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-41 
SECTION 5.1: AIR QUALITY 

Screening Procedures and Unit Impact Modeling 

Screening modeling was performed to select the worst-case gas turbine operating mode for 

each pollutant and averaging period. The modeling used emissions data based on an annual 

average temperature (61°F), average summer temperature (74°F), maximum temperature 

(104°F), and minimum temperature (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 depends 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-hour, 8-hour, 24-hour, and annual average 

concentration to emission rate (χ/Q in units of μg/m3 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 NO2, CO, SO2, and PM10/PM2.5 in units of μg/m3. Stack 

characteristics used in the screening modeling 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 operating 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 phases: 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 Appendix 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. Twenty-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 from 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. 

5.1-42 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

Terrain features were taken from the following 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 lies a short distance above the release point of a 

plume and unstable air lies below. Under these conditions, an exhaust plume may cause 

high ground-level pollutant concentrations 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 layer. Although fumigation conditions rarely last as long as 

one hour, relatively high ground-level concentrations may be reached during that time. For 

this analysis, fumigation was assumed to occur 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 hours or less). Guidance from the USEPA14 was followed 

in evaluating fumigation impacts. The maximum 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 during 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 denser cooler air over 

water displaces the warmer, lighter air over land. 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 second; the maximum ground-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 thermal inversion boundary layer (TIBL). The 

 

14 EPA, October 1992. 

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SECTION 5.1: AIR QUALITY 

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. Shoreline breakup fumigation was assumed to persist 

for up to 3 hours. The shoreline fumigation analysis is shown in more detail in 

Appendix 5.1D. 

Gas Turbine Startup 

CECP site impacts were also evaluated during 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 

NOx emission rates are shown in Appendix 5.1D. 

Ozone Limiting 

In accordance with the procedure followed for similar projects, one-hour NO2 impacts 

during project operation were modeled using the Plume Volume Molar Ratio Method 

(PVMRM) adaptation of the Ozone Limiting Method (Cole and Summerhays, 1979). 

AERMOD PVMRM was used to calculate the NO2 concentration based on the PVMRM 

method, and hourly ozone data. Hourly ozone data collected at the Camp Pendleton 

monitoring station during the years 2003 through 2005 were used in conjunction with PVMRM 

to calculate hourly NO2 concentrations from hourly NOx concentrations. Missing hourly ozone 

data were substituted prior to use with day-appropriate 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 NOx concentration and the ambient O3 concentration 

left in the plume after reaction of NO with O3 to determine which is the limiting factor to 

NO2 formation. If the remaining O3 concentration is greater than the maximum 

NOx concentration, total conversion is assumed. If the NOx concentration is greater than the 

remaining O3 concentration, the formation of NO2 is limited by the remaining ambient 

O3 concentration. In this case, the NO2 concentration is set equal to the O3 concentration plus a 

correction factor that accounts for in-stack and near-stack thermal conversion. 

Annual NOx impacts were converted to NO2 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 application of the air pollution control systems. 

The total set of commissioning tests will require 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 period 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 approximately one to six months apart, as described 

in the project description. During the commissioning phase of the project, the existing 

boilers Units 1, 2, and 3 at the Encina Power Station will remain available for operation, but 

these boilers will not be operated simultaneously with a CTG undergoing a commissioning 

test. 

5.1-44 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

There are several emissions scenarios possible during commissioning. The first is the period 

prior to SCR system installation, when the combustor is being tuned. Under this scenario, 

the NOx emissions control system would not be functioning and the combustor would not 

be tuned for optimum performance. CO emissions would also affected because combustor 

performance would not be optimized. The second emissions scenario will occur when the 

combustor has been tuned but the SCR installation is not complete, and other parts of the 

gas turbine operating system are being checked out. Since the combustor would be tuned 

but the control system installation would not be complete, NOx 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 operation of CECP, calculated from the refined, 

startup/shutdown and fumigation modeling analyses 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/m3) 

Pollutant 

Averaging 

Time 

Normal 

Operations 

AERMOD 

Startup/Shutdown

AERMOD 

Fumigation 

SCREEN3 

Shoreline 

Fumigation 

SCREEN3 

Combined Impacts Both CTGs 

NO2 1-hour 

Annual

13.8 

0.2 

87.4 

a 

2.8 

c 

19.4 

c 

SO2 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 

PM2.5/PM10 24-hour 

Annual 

2.2 

0.1 

b 

b 

0.6 

c 

0.9 

c 

Firepump Engine 

NO2 1-hour 

Annual

83.8 

0.0 

d 

d 

e 

e 

e 

e 

SO2 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 

PM2.5/PM10 24-hour 

Annual 

0.0 

0.0 

d 

d 

e 

e 

e 

e 

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-45 
SECTION 5.1: AIR QUALITY 

TABLE 5.1-27 

Normal Operation Air Quality Modeling Results for new equipment 

Modeled Maximum Concentrations (μg/m3) 

Pollutant 

Averaging 

Time 

Normal 

Operations 

AERMOD 

Startup/Shutdown

AERMOD 

Fumigation 

SCREEN3 

Shoreline 

Fumigation 

SCREEN3 

Combined Impacts New Equipment 

NO2 1-hour 

Annual

83.8 

0.2 

f 

f 

f 

f 

f 

f 

SO2 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 

PM2.5/PM10 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, NO2 and CO impacts may be higher than 

under the operating conditions evaluated above. The commissioning period is comprised of 

equipment tests and verification. These tests and the associated NOx and CO emissions are 

briefly summarized below. The emissions calculations 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 synchronized with its electric generator, and a 

test of the CTG’s overspeed system. 

• Minimum Load Tests – These tests will occur over several days. During this testing 

period, the CTG combustor will be tuned to minimize emissions and other checks will 

be performed. This test period will allow for complete combustion path warm-up, 

required for removing all debris that could potentially damage the SCR catalyst. 

• Multiple Load Tests (SCR/Oxidation Catalyst Operational at Various Levels) – These 

tests will occur over several days. By the beginning of this test period, the control 

systems will be installed and will be tuned to achieve NOx and CO control at design 

levels. 

5.1-46 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

• 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 NO2 and CO impact during commissioning will 

occur under the gas turbine operating conditions 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 commissioning are summarized in Table 5.1-28. 

Because there will be a staggered commissioning schedule for the project, the two CTGs 

will not undergo commissioning simultaneously. 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/m3 

NO2 – 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 concentrations and then compared to the applicable 

ambient air quality standards. The maximum background 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 NO2, CO, SO2, PM10, and PM2.5

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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SECTION 5.1: AIR QUALITY 

TABLE 5.1-29 

Maximum Background Concentrationsa, Project Area, 2004-2006 (μG/M3) 

Pollutant Averaging Time 2004 2005 2006 

1-hour 185.9 144.6 152.1 NO2 (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 SO2 (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 PM10 (Escondido) Annual 28 24 24 

24-hourb 37 32 28 PM2.5 (Escondido) Annual 14.1 12.3 11.5 

Notes: 

a With the exception of 24-hr PM2.5, bolded values are the highest during the three years and are used to 

represent background concentrations. 

b

 24-hour average PM2.5 concentrations shown are 98th percentile values rather than highest values because 

compliance with the ambient air quality standards is based on 98th percentile readings. Since the ambient 

standard is based on a 3-year average of the 98th percentile readings, the 3-year average of the 2004 to 2006 

98th percentile readings was used to represent 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/m3

 except for PM10 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 PM10 and PM2.5 standards. For these pollutants, existing 24-hour average PM10

background concentrations and PM10 and PM2.5 annual background concentrations already 

exceed state standards. The following discussion demonstrates that impacts from the 

proposed project will not exceed significant impact levels. 

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SECTION 5.1: AIR QUALITY 

TABLE 5.1-30 

Modeled Maximum proposed Project Impacts 

Pollutant Averaging Time 

Maximum Project 

Impact (μg/m3) 

Background 

(μg/m3) 

Total Impact 

(μg/m3) 

State 

Standard 

(μg/m3

) 

Federal 

Standard 

(μg/m3) 

NO2 1-hour Annual 83.8 

0.2 

185.9 

22.5 

270 

23 

338 

56 

— 

100 

SO2 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 

PM10 24-hour 

Annual 

2.2 

0.1 

57 

28 

59 

28 

50 

20 

150 

— 

PM2.5 24-hour 

Annual 

2.2 

0.1 

32.2 

14.1 

34 

14 

— 

12 

35 

15 

PSD Significance Levels 

The Prevention of Significant Deterioration (PSD) program was established to allow 

emission increases that do not result in significant deterioration of ambient air quality in 

areas where criteria pollutants have not exceeded the NAAQS. The net emission increase 

shown later in Table 5.1-33 shows that although 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 whether the ambient impacts of the project exceed 

the PSD significance thresholds, as these thresholds 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 significance 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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SECTION 5.1: AIR QUALITY 

TABLE 5.1-31 

Comparison of Maximum Modeled Impacts and PSD Significant Impact Levels 

Pollutant Averaging Time 

Significant Impact 

Level, μg/m3

Maximum Modeled 

Impact for CECP, 

μg/m3 Exceed Significant Impact Level? 

NO2 Annual 1 0.2 No 

SO2 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 

PM10 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 pollutant 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 Program Guidance Manual For Preparation Of 

Health Risk Assessments” (October 2003) and the March 2005 SDAPCD Supplemental 

Guidelines for Submission of Air Toxics “Hot Spots” Program Health Risk Assessments 

(HRAs). 

Following SDAPCD Rule 1200 (Toxics New Source 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 the potential long-term (chronic) and shortterm (acute) non-carcinogenic health impacts 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 pollutant carcinogenic risks are assumed to be 

additive. Because of the conservatism (overprediction) built into the established risk 

analysis methodology, the actual risks will be lower than those estimated. 

The potential health risks are presented in Table 5.1-32, and a detailed discussion of the 

approach 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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SECTION 5.1: AIR QUALITY 

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 will 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 proposed 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 results of the analysis indicate that the direct 

maximum construction impacts will be below the state and federal ambient air quality 

standards for criteria pollutants. The best available emission control techniques will be used. 

Combustion diesel PM10 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 Federal 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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SECTION 5.1: AIR QUALITY 

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 responsible for this regulatory program for purposes 

of the project. 

5.1.7.1.1 PSD Program 

USEPA has promulgated PSD regulations for areas 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 sources to be modified, while preserving the existing 

ambient air quality levels, protecting public health 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 responsibility 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 regulations.) (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 proposed 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? 

NOx 20.1 40 No 

SO2 -5.9 40 No 

VOC 5.0 N/A* N/A* 

CO -144.0 100 No 

PM10 0.0 15 No 

Note: 

* Since the project area is classified as a federal nonattainment 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 principal responsibility for regulating emissions from 

stationary sources. The CECP is under the local jurisdiction of the SDAPCD, and hence, 

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SECTION 5.1: AIR QUALITY 

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 pollutants. 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 Compliance from the SDAPCD, as well as demonstrate 

continued compliance with regulatory limits when the new equipment becomes operational. 

The preconstruction review includes demonstrating 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 analysis. 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 firepump engine are compared with the BACT 

thresholds. As shown in this table, the CTGs/HRSGs are subject to BACT for NOx, VOC, 

SOx, and PM10. However, emissions from the emergency 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 

PM10 10 228.0 0.0 

NOx 10 877.0 2.1 

SOx 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 Management District BACT Guidelines Manual,16

 

15 SDAPCD. New Source Review Requirements for Best Available Control Technology (BACT) Guidance Document, 

May 2002. 

16 SCAQMD. BACT Guidelines, http://www.aqmd.gov/bact/BACTGuidelines.htm. 

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SECTION 5.1: AIR QUALITY 

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 NOx emissions from the gas turbine will be the use of low-NOx emitting 

equipment and add-on controls. The project will use SCR and dry low-NOx combustion 

to reduce NOx emissions to 2.0 ppmvd NOx, corrected to 15 percent O2 (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 VOC emissions of 2.0 ppmc. 

• BACT for PM10 and SOx is best combustion practices and the use of natural gas. The 

proposed CTGs will burn exclusively PUC-regulated natural gas with a maximum 

short-term sulfur content of 0.75 grains per 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 source review program are the ozone precursors 

NOx and VOC. As shown in Table 5.1-35, net increases in NOx 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? 

NOx 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 review 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 applicable 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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SECTION 5.1: AIR QUALITY 

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 NOx, CO, and PM10. 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 attainment 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 

NOx 171 lbs/hr 25 lbs/hr Yes 

CO 1,627 lbs/hr 100 lbs/hr Yes 

PM10 N/A — N/A 

SOx 9 lbs/hr 25 lbs/hr No 

Daily Emissions 

NOx 1,756 lbs/day 250 lbs/day Yes 

CO 10,205 lbs/day 550 lbs/day Yes 

PM10 456 lbs/day 100 lbs/day Yes 

SOx 211 lbs/day 250 lbs/day No 

Annual Emissions 

NOx 76 tpy 40 tpy Yes 

CO 217 tpy 100 tpy Yes 

PM10 39 tpy 15 tpy Yes 

SOx 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 that damage business or property. The CECP 

would not emit odorous pollutants, and the screening health risk assessment demonstrated 

that the potential health risks from the emissions are less than significant. 

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SECTION 5.1: AIR QUALITY 

5.1.7.3.8 Rule 52 – Particulate Matter Emission Standards 

Prohibits PM emissions in excess of 0.10 grains per dry standard cubic foot (gr/dscf). 

The proposed PM10 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 SO2, in excess of 0.05 percent by volume 

(500 ppmv), and combustion particulate emissions in excess of 0.10 gr/dscf at 12 percent 

CO2. SO2 emissions from the project will be below 0.5 ppmv, based on the fuel sulfur 

content levels of 0.75 gr/100 scf (short-term 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 – Sulfur 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 engine 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 NOx emissions from stationary gas turbines rated greater than or equal to 10 MW 

with post-combustion controls to 9 ppmv (at 15 percent O2, corrected for efficiency). The 

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

Rule 69.4.1 – Stationary Reciprocating Internal Combustion Engines 

Limits CO, NOx, 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 operating limit of 50 hours per year for 

testing/maintenance, the new emergency firepump engine is exempt from these emission 

limits. 

40 CFR Part 60, Subpart KKKK (Standards 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 NOx and SO2 emissions from new gas turbines 

based on power output. The limits for gas turbines greater than 30 MW are 0.39 lb NOx per 

MW-hr and 0.58 lb SO2 per MW-hr. The emission limits of 2.0 ppmc NOx and 0.4 ppmc SO2

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

5.1-56 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

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 

NOx 2.0 15.1 0.05 0.39 

SO2 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 NOx emissions monitor, 

ongoing annual performance testing will not be required under the NSPS. 

5.1.7.3.14 40 CFR Part 60, 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 range to use fuel with a sulfur content not to 

exceed 15 ppm. The new emergency firepump engine 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 quality 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 Cumulative 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 through a photochemical process that can take 

hours to occur. Carbon monoxide, NOx, and SOx impacts are generally localized in the area 

in which they are emitted. PM10 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, SOx, and NOx. 

The cumulative effects analysis will consider the 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 emissions from CECP with emissions of ozone and 

PM10 precursors in San Diego County. Localized impacts will be evaluated by looking at 

other local sources of pollutants that are not included 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 NOx emissions in ozone formation differs 

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SECTION 5.1: AIR QUALITY 

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 estimate of the impact of CECP on regional 

ozone levels. Similarly, a comparison of the emissions of PM10 precursor emissions from 

CECP with regional PM10 precursor emissions provides an estimate of the impact of CECP 

on regional PM10 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 Appendix 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 projection software, available at 

www.arb.ca.gov/app/emsinv/emssumcat.php.

These comparisons show that the total ozone and PM10 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 PM10 formation. 

TABLE 5.1-38 

Comparison of CECP Emissions to Regional Precursor Emissions in 2010: Annual Basisa

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/yearb -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 

PM10 Precursors – Annual Basis 

Total San Diego County PM10 Precursors, tons/year 172,134 

Total CECP PM10 Precursor Emissions, tons/year 145.2 

CECP PM10 Precursor Emissions as Percent of Regional Total 0.08% 

Reductions from Shutdown of Boilers, tons/year -462.1 

CECP Net PM10 Precursor Emissions with Boiler Shutdowns, tons/year -316.9 

CECP Net PM10 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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SECTION 5.1: AIR QUALITY 

5.1.8.1.2 Localized Impacts 

To evaluate potential cumulative effects of CECP in combination with other projects in the 

area, projects within a radius of 6 kilometers of the project were examined for the 

cumulative localized impacts analysis. 

Within this search area, three categories of projects 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 represent background concentrations for the CECP; 

consequently, no further analysis of the emissions from this category of facilities was 

performed. 

Projects for which air pollution permits to construct 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 within six miles of the CECP. This search also 

included permit application packages the SDACPD 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, NOx, SOx, 

or PM10 emissions above the CEC established de minimis level of 5 tons/year: an emergency 

generator engine at Hunter Industries located 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 CECP. 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 increasing 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 gas turbines and diesel combustion in the 

emergency firepump engine will result in the emissions of the following GHG: 

carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O). These emissions from the 

CECP join the emissions of the same GHG from 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 cause a direct significant impact on the 

environment. 

GHG emissions of CO2, CH4, and N2O for the project are summarized in Table 5.1-39. The 

detailed GHG emission calculations for the CECP are included in Appendix 5.1B. 

EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 5.1-59 
SECTION 5.1: AIR QUALITY 

TABLE 5.1-39 

GHG Emissions Project

Pollutant 

Gas Turbines 

MMT CO2e * 

Firepump Engine 

MMT CO2e * 

Total 

MMT CO2e * 

CO2 8.46 x 105 6.19 x 100 8.46 x 105 

CH4 2.16 x 103 5.84 x 10-4 2.16 x 103 

N2O 4.96 x 102 2.62 x 10-3 4.96 x 102 

Total 8.50 x 105 6.19 x 100 8.50 x 105 

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 overall operation of less efficient units regionally 

because these fast starting and more efficient CECP units can be relied upon to provide 

quick electrical resources when needed. Historically, less efficient steam generating units in 

San Diego have operated at minimum load during 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 level 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 CO2e* 

Reductions from Shutdown of Existing Boilers

Unit 1 1.80 x 105 

Unit 2 1.92 x 105 

Unit 3 2.70 x 105 

Subtotal 6.42 x 105 

New Equipment 

Gas Turbines and Firepump Engine 8.50 x 105 

Net Emission Change 2.08 x 105 

Note: 

* Million metric tons of carbon dioxide equivalent.

5.1-60 EY072007001SAC/361219/072510001 (CECP_005.1_AIR_QUALITY.DOC) 
SECTION 5.1: AIR QUALITY 

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 significant. 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. Nonetheless, 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 emissions increases from the CECP in the form of 

emission reductions from the shutdown and retirement 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 demonstration of compliance with the BACT requirement 

is provided in Appendix 5.1C. 

As discussed in Section 5.1.6.3.2 above, the emissions 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 demonstrated that the project will result in a net 

reduction in emissions of CO and SOx, no net increase in PM10 emissions, and increases in 

NOx 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 

PM10 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 Guidelines Report for the Air Toxics “Hot Spots” 

Program, May 15, 1997. 

ARB. HARP User Guide. December 2003. 

ARB. Proposed Guidance for Power Plant Siting 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 NOx Emission Controls and Related 

Environmental Impacts. May 2004 

CAPCOA. Air Toxics “Hot Spots” Program Revised 1992 Risk Assessment Guidelines. 

October 1993. 

National Climatic Data Center. 1993 data for San Diego International Airport (Lindbergh 

Field). 

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

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

Office of Environmental Health Hazard Assessment. Acute and Chronic Exposure Levels 

Developed by OEHHA as of August 2004. 

Office of Environmental Health Hazard Assessment. Air Toxics Hot Spots Program Risk 

Assessment Guidelines. Part II. Technical Support 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 Guidance for Regulatory Model Applications, EPA450/4-87-013. August 1995. 

USEPA. Screening Procedures for Estimating the Air Quality Impact of Stationary Sources, 

Revised, EPA-454/R-92-019. October 1992. 

USEPA. Ambient Monitoring Guidelines for Prevention of Significant Deterioration (PSD), 

EPA-450/4-87-007. May 1987. 

USEPA. Guideline for Determination of Good Engineering Practice Stack Height. June 1985. 
FIGURE 5.1-1 

January Predominant Mean Circulation of the Surface Winds 
FIGURE 5.1-2 

April Predominant Mean Circulation of the Surface Winds 
FIGURE 5.1-3 

July Predominant Circulation of the Surface Winds 
FIGURE 5.1-4 

October Predominant Mean Circulation of the Surface Winds 
0.00

0.05

0.10

0.15

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Calendar Year

Ozone (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 Year

Ozone (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, 1997-2006 
0.00

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 Year

NO2 (parts per million)

Maximum 1-Hour Concentration

3-Year Average

California Standard (0.18 ppm)

FIGURE 5.1-7 

Maximum 1-hour Average NO2 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 Year

NO2 (parts per million)

Annual Average Concentration

3-Year Average

Federal Standard (0.053 ppm)

FIGURE 5.1-8 

Annual Average NO2 Levels Camp Pendleton, 1997-2006 
0

5

10

15

20

25

30

35

40

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Calendar Year

CO (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 Year

CO (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, 1997-2006 
0.00

0.04

0.08

0.12

0.16

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Calendar Year

SO2 (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 SO2 Levels San Diego (12th Avenue), 1997-2006 

,

0

50

100

150

200

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Calendar Year

PM10 (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 PM10 Levels Escondido, 1997-2006 
,

0

5

10

15

20

25

30

35

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Calendar Year

Expected Violation Days

Expected Violation Days

3-Year Average

FIGURE 5.1-13 

Expected Violations of the California 24-hour PM10 Standard (50 μg/m3) Escondido, 1997-2006 

Annual Average PM10 Levels

Escondido, 1997-2006

0

5

10

15

20

25

30

35

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Calendar Year

PM10 (ug/m3

)

Annual Average Concentration

3-Year Average

California Standard (20 ug/m3)

FIGURE 5.1-14 

Annual Average PM10 Levels Escondido, 1997-2006 
0

20

40

60

80

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Calendar Year

PM2.5 (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 Year

PM2.5 (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