This section addresses issues related to air pollutant emissions, including "criteria air pollutants" and "toxic air contaminants." "Criteria air pollutants" refers to those pollutants that are pervasive in urban environments and for which health-based state or national ambient air quality standards have been established. "Toxic air contaminants" refers to those pollutants that occur at relatively low concentrations and are associated with carcinogenic and other adverse health effects, but for which no ambient air quality standards have been established.

4.5.1 SETTING

Both the rate and location of pollutant emissions affect air quality and are affected by meteorological conditions, which influence movement and dispersal of pollutants. Atmospheric conditions such as wind speed, wind direction, and air temperature gradients, along with local topography, provide the link between air pollutant emissions and air quality.

As described in the Project Description, Chapter 2 , the three fossil-fuel plants to be divested by PG&E are configured to burn natural gas almost exclusively. Of the various fossil fuels that can be burned in power plants to generate electricity – natural gas, oil, or coal -- natural gas is the cleanest burning. Combustion of natural gas results in lower emissions of sulfur dioxide, particulate matter, carbon monoxide, reactive hydrocarbons, nitrogen oxides, and carbon dioxide than combustion of other fossil fuels.

Natural gas burns cleaner than other fossil fuels because it is composed chiefly of methane, the least complex organic molecule. Methane is comprised of only one carbon atom and four hydrogen atoms. When methane is burned, the principal products of combustion are carbon dioxide and water vapor. In comparison, coal and oil are made up of compounds having much more complicated molecular structures that include higher ratios of carbon as well as various sulfur and nitrogen compounds. These compounds do not burn as cleanly as methane. In addition, coal and fuel oil combustion produces ash particles that can be carried into the atmosphere. Relative emissions of natural gas and oil are provided later in this section.

The State of California is divided into discrete air basins that are defined partly by their meteorological and topographical characteristics. The Potrero, Contra Costa, and Pittsburg Power Plants are located within the San Francisco Bay Area Air Basin (Bay Area), which includes San Francisco, San Mateo, Santa Clara, Alameda, Contra Costa, Napa, and Marin counties and portions of Sonoma and Solano counties. The Geysers are located along the ridgeline that separates Sonoma County from Lake County, and power plant facilities associated with the Geysers are located in both counties. The northern half of Sonoma County is located within the North Coast Air Basin while Lake County lies within its own air basin. These three air basins (Bay Area, North Coast, and Lake County) are shown in Figure 4.5-1 along with the other California Air Basins.

The climate of all three air basins is determined largely by a semi-stationary Pacific high pressure system that is almost always present off the west coast of North America. This broad region of descending air is normally warm, dry and stable. In winter, the Pacific high pressure system shifts southward, allowing storms to pass through the region.

The Potrero Power Plant is located within San Francisco, which lies at the northern end of the peninsula climatological subregion of the Bay Area. The peninsula climatological subregion extends from northwest of San Jose to the Golden Gate. The Santa Cruz Mountains run up the center of the peninsula, with elevations exceeding 2,000 feet at the southern end, decreasing to 500 feet in South San Francisco. Because most of San Francisco’s topography is below 200 feet, marine air is able to flow easily across most of the City, making its climate cool and windy. On the east side of the subregion, winds are generally from the west. At the northern end of the subregion, pollutant emissions are high, especially from motor vehicle congestion. Localized pollutants, such as carbon monoxide, can build up in "urban canyons." However, winds are generally fast enough to carry the pollutants away before they can accumulate (Bay Area Air Quality Management District, 1996a).

The Pittsburg and Contra Costa Power Plants are located within the Carquinez Strait climatological subregion of the Bay Area. The Carquinez Strait is the only sea-level gap between San Francisco Bay and the Central Valley. This subregion includes the lowlands bordering the strait to the north and south, and includes the area adjoining Suisun Bay and the western part of the Sacramento-San Joaquin Delta as far east as Bethel Island. Prevailing winds are from the west in the Carquinez Strait. Afternoon wind speeds of 15 to 20 miles per hour are common throughout the strait region. Sometimes atmospheric conditions cause air to flow from the east. Summer mean maximum temperatures reach approximately 90 (in degrees Fahrenheit) in the subregion. Mean minimum temperatures in the winter are in the high 30s. While many industrial facilities with substantial air pollutant emissions are located within the Carquinez Strait subregion, the pollution potential of this area is often moderated by high wind speeds (Bay Area Air Quality Management District, 1996a).

As described above, the Geysers are located in both the North Coast Air Basin and the Lake County Air Basin. While the regional weather patterns that affect the Bay Area also affect these two air basins, there are long periods when regional systems are weak and locally-generated wind systems predominate. In the Geysers portion of the North Coast Air Basin, the mountains of the Mayacmas Range affect both surface-wind direction and speed. Wind directions and wind speeds are often different at the operating units because of the varying terrain features. These terrain features can result in up-valley winds during the day and down-valley winds during the night. Wind speeds typically increase with elevation. In the Lake County Air Basin, the steep mountains and valleys that channel the wind affect local wind patterns. Anderson Springs, a sheltered location in Lake County, experiences calm conditions often (approximately 75 percent of the time), while open locations, such as Middletown, experience calm conditions less frequently (approximately 18 percent of the time). The predominant regional northwest winds tend to flush out air pollutants from Lake County Air Basin. When local winds dominate, air pollutants tend to become entrained within the lake-mountain-valley circulations, resulting in reduced air quality.

While air quality in a given air basin is usually determined by emission sources within the Basin, the air quality in some air basins can also be affected by pollutants transported from upwind air basins by prevailing winds. For instance, emissions generated within the Bay Area are known to adversely affect air quality in the San Joaquin Valley Air Basin, the metropolitan Sacramento area, Mountain Counties Air Basin, and the North Central Coast Air Basin (California Air Resources Board, 1996). Air quality in the Bay Area itself is occasionally adversely affected by pollutant transport from the metropolitan Sacramento area.

The California Air Resources Board is the state agency responsible for approving the air quality plans developed by air districts to meet both the national standards and state standards. The California Air Resources Board also has primary responsibility for regulating mobile and area source emissions and for overseeing the activities of regional and local air districts called Air Pollution Control Districts (APCDs) or Air Quality Management Districts (AQMDs).

In addition to having primary responsibility for preparing air quality plans for the areas within their jurisdiction, APCDs and AQMDs are also responsible for regulating stationary sources. Stationary sources, such as power plants, are regulated through a permitting process in which applicants must secure an Authority to Construct (ATC) and a Permit to Operate (PTO) from the applicable APCD or AQMD prior to operation of new or modified equipment that may affect air quality. Stationary sources can also be subject to retrofit requirements imposed by the applicable APCD and AQMD.

The three power plants located in the San Francisco Bay Area Air Basin lie within the jurisdiction of the Bay Area Air Quality Management District. The local air district in Lake County is the Lake County Air Quality Management District. The local air district in northern Sonoma County is the Northern Sonoma County Air Pollution Control District. (The southern half of Sonoma County lies within the jurisdiction of the Bay Area Air Quality Management District.)

The federal Clean Air Act requires the U.S. Environmental Protection Agency (EPA) to list air pollutant compounds which may endanger public health or welfare; to publish air quality "criteria" describing the latest scientific knowledge on these compounds, their pollutant interactions, and control techniques; and to identify National Ambient Air Quality Standards (national standards) protective of public health and welfare. Currently, EPA has established national standards for ozone, carbon monoxide, nitrogen dioxide, sulfur dioxide, particulate matter (PM-10 and PM-2.5), and lead. California has adopted more stringent standards for most of the criteria air pollutants (referred to as State Ambient Air Quality Standards, or state standards) and has adopted ambient air quality standards for some pollutants for which there are no corresponding national standards. Both sets of ambient air quality standards (i.e., national and state) are presented in Table 4.5-1.

State and national ambient air quality standards alike consist of two parts: an allowable concentration of a pollutant, and an averaging time over which the concentration is to be measured. The 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 (e.g., one hour), or to a relatively lower average concentration over a longer period (e.g., eight hours, 24 hours, or one month). For some pollutants, there is more than one air quality standard, reflecting both its short-term and long-term effects.

Carbon monoxide is a non-reactive pollutant that is a product of incomplete combustion. Ambient carbon monoxide concentrations generally follow the spatial and temporal distributions of vehicular traffic and are also influenced by meteorological factors such as wind speed and atmospheric mixing. Under inversion conditions, carbon monoxide concentrations may be distributed more uniformly over an area out to some distance from vehicular sources. When inhaled at high concentrations, carbon monoxide combines with hemoglobin in the blood and reduces the oxygen-carrying capacity of the blood (Bay Area Air Quality Management District, 1996a). This results in reduced oxygen reaching the brain, heart, and other body tissues. This condition is especially critical for people with cardiovascular diseases, chronic lung disease or anemia, as well as fetuses.

PM-10 consists of particulate matter that is 10 microns or less in diameter (a micron is one- millionth of a meter), and PM-2.5 consists of particulate matter 2.5 microns or less in diameter. Both PM-10 and PM-2.5 represent fractions of particulate matter, which can be inhaled into the air passages and the lungs and can cause adverse health effects. Particulate matter in the atmosphere results from many kinds of dust- and fume-producing industrial and agricultural operations, combustion, and atmospheric photochemical reactions. Some of these operations, such as demolition and construction activities, contribute to increases in local PM-10 concentrations, while others, such as vehicular traffic, affect regional PM-10 concentrations.

National ambient air quality standards for particulate matter were first established in 1971. The standards covered total suspended particulate matter (TSP), or particles that are 30 microns or smaller in diameter. In 1987, EPA changed the standards from TSP to PM-10 as the new indicator. The new standards were based on a comprehensive study of information on the health effects from inhaling particulate matter. In December 1994, EPA began a long review process to determine if the PM-10 standards set in 1987 provide a reasonable margin of safety, and if a new standard should be established for finer particles.

Based on numerous epidemiological studies and other health and engineering related information, EPA established new standards for fine particulate matter (PM-2.5) in 1997. Before establishing the new PM-2.5 standards, discussions were conducted with the Clean Air Scientific Advisory Committee (CASAC). CASAC is a group of nationally recognized experts in the fields related to air pollution, environmental health, and engineering. CASAC reviewed and commented on the information generated by EPA regarding proposed particulate matter standards.

Subsequent to these discussions and reviews, EPA established PM-2.5 standards of 65 micrograms per cubic meter, 24-hr average concentration, and 15 micrograms per cubic meter, annual average concentration. EPA also confirmed the national PM-10 standards of 150 micrograms per cubic meter, 24-hr average, and 50 micrograms per cubic meter, annual average, as providing an adequate margin of safety for limiting exposure to larger particles. The recommendations for new PM-2.5 standards and for maintaining the PM-10 standards were released in a staff report (U.S. Environmental Protection Agency, 1996) that presents the conclusions of the Agency and of the review committee, CASAC.

Several studies that EPA relied on for their staff report have shown an association between exposure to particulate matter, both PM-10 and PM-2.5, and respiratory ailments or cardiovascular disease (Pope et al., 1992; Thurston et al., 1992; Burnett et al., 1995). Other studies have related particulate matter to increases in asthma attacks (Whittemore and Korn, 1980; Pope et al., 1991). In general, these studies have shown that short-term and long-term exposure to particulate matter can cause acute and chronic health effects. Fine particulate matter (PM-2.5), which can penetrate deep into the lungs, causes more serious respiratory ailments. These studies, along with information provided by EPA in the 1996 staff report, were used as the basis for evaluating the impacts of PG&E emissions of PM-10 and PM-2.5, on public health.

Sulfur dioxide and nitrogen oxides emissions can be oxidized in the atmosphere to eventually form sulfates and nitrates, which contribute to acid rain. Large power plants with high emissions of these substances because of the use of coal or oil are subject to emissions reductions under the Phase I Acid Rain Program of Title IV of the 1990 Clean Air Act Amendments. Other power plants that use natural gas or other fuels with low sulfur content such as the PG&E plants, are subject to the Phase II Program of Title IV. The Phase II program requires plants to install Continuous Emissions Monitoring Systems (CEMS) in accordance with the Code of Federal Regulations (40 CFR Part 75) and report annual emissions of sulfur oxides and nitrogen oxides. PG&E has installed CEMS at the fossil fuel burning plants in compliance with the Phase II program.

Gasoline-powered automobile engines used to be the major source of airborne lead in urban areas. Excessive exposure to lead concentrations can result in gastrointestinal disturbances, anemia, kidney disease, and in severe cases of neuromuscular and neurologic dysfunction. The use of lead additives in motor vehicle fuel has been eliminated in California, and lead concentrations have declined substantially as a result.

Under amendments to the federal Clean Air Act, EPA has classified air basins, or portions thereof, as either "attainment" or "non-attainment" for each criteria air pollutant, based on whether or not the national standards have been achieved. The project involves power plants located in three air basins: the San Francisco Bay Area Air Basin, the Lake County Air Basin, and the North Coast Air Basin. In 1988, the State Legislature passed the California Clean Air Act, which is patterned after the federal Clean Air Act to the extent that areas are required to be designated as "attainment" or "non-attainment" for the state standards, rather than the national standards. Thus, areas in California have two sets of attainment/non-attainment designations: one set with respect to the national standards and one set with respect to the state standards. Table 4.5-2 shows the current attainment/non-attainment status of the three applicable air basins for the various criteria air pollutants.

Table 4.5-3 summarizes the past three years of monitoring data collected in the three applicable air basins. As shown in Table 4.5-3, exceedences of state standards for ozone and PM-10 are recorded on occasion in the San Francisco Bay Area Air Basin and are recorded less frequently in the North Coast Air Basin. Exceedences of any ambient air quality standard are very infrequent in Lake County.

"Toxic air contaminants" are air pollutants that are believed to have carcinogenic or adverse non-carcinogenic effects but do not have a corresponding ambient air quality standard. There are hundreds of different types of toxic air contaminants, with varying degrees of toxicity. Sources of toxic air contaminants include industrial processes such as petroleum refining, electric utility and chrome plating operations, commercial operations such as gasoline stations and dry cleaners, and motor vehicle exhaust.

Toxic air contaminants are regulated under both state and federal laws. Federal laws use the term "Hazardous Air Pollutants" (HAPs) to refer to the same types of compounds referred to as "Toxic Air Contaminants" (TACs) under State law. Both terms encompass essentially the same compounds. For the sake of simplicity, this report will use TACs when referring to these compounds rather than HAPs. Under the 1990 Clean Air Act Amendments, approximately 190 substances are regulated under a two-phase strategy. The first phase involves requiring facilities to install Maximum Achievable Control Technology (MACT); EPA has established MACT standards for 20 industries that emit toxic air contaminants and will develop MACT standards for others over the next several years. Electric Utility Boilers were omitted from the list of industries to be considered pending an EPA study that will determine if MACT is required. Even if MACT is established for a given source category, a facility in that category is subject to MACT only if the TAC emissions are 10 tons per year or more for any substance or 25 tons per year or more for any combination of TACs. Since TAC emissions from the PG&E plants are less than one ton per year per facility, none of the plants being divested would be subject to MACT.

The second phase of control involves determining the residual health risk represented by TAC emissions sources after implementation of MACT standards. EPA will determine residual risks within eight years after MACT standards for a source category are set. Results of this analysis will be used to determine if the residual risks allow for a reasonable margin of safety for public health.

With respect to State law, in 1983 the State legislature adopted Assembly Bill 1807 (AB 1807), which established a process for identifying toxic air contaminants and provided the authority for developing retrofit air toxics control measures on a statewide basis. In 1992, the State legislature adopted Assembly Bill 2728 to provide a legal framework for the integration of the existing State air toxics programs, including those developed under AB 1807, with the new federal program discussed above. Air toxics in California may also be regulated because of another state law, the Air Toxics "Hot Spots" Information and Assessment Act of 1987, Assembly Bill 2588 (AB 2588). Under AB 2588, toxic air contaminant emissions from individual facilities are required to be quantified by the facility and reported to the local air pollution control agency. The facilities are prioritized by the local agencies based on the quantity and toxicity of these emissions, and their proximity to areas where the public may be exposed. High priority facilities are required to perform a health risk assessment, and if specific risk thresholds are exceeded, they are required to communicate the results to the public in the form of notices and public meetings. Depending on the health risk levels, emitting facilities can be required to implement varying levels of risk reduction measures.

Health effects resulting from exposure to toxic air contaminants can be categorized as either carcinogenic (cancer-causing), or non-carcinogenic. Health effects from carcinogenic air toxics are usually described in terms of individual cancer risk. "Individual cancer risk" is the likelihood that a person exposed to concentrations of toxic air contaminants over a lifetime will contract cancer, based on the use of standard risk assessment methodology established for AB 2588. These cancer risks are based on the best estimates of plausible cancer potencies as determined by the State Office of Environmental Health Hazard Assessment. (1) When exposure to more than one potential carcinogen is evaluated, the risks posed by the various individual air toxics is summed; this sum is the overall cancer risk estimate. (2) Incremental risks estimated through standard methods are typically compared to risks estimated by the same methods for other facilities, and to standards selected to define the acceptable incremental risk from a project or facility (e.g., the Proposition 65 standard risk of 10 in a million). Non-carcinogenic health effects associated with air toxics vary depending on the types and quantities of air toxics exposure. Adverse effects on health, as well as the potential for nuisance and other forms of irritation, depend largely on the susceptibility of the individual, and are evaluated for two different periods of exposure: acute (short-term exposure) and chronic (long-term exposure). Non-cancer health effects (both acute and chronic) are considered by comparing estimated exposure levels to known or estimated thresholds (termed "reference exposure levels"). Information on risk assessment methodology is presented in the discussion of the Potrero Power Plant setting.

The Bay Area Air Quality Management District (BAAQMD) operates a regional network of monitoring stations that measure ambient concentrations of the specific toxic air contaminants that are believed to contribute most to the risk-associated toxic air contaminants emitted to the atmosphere in the Bay Area. Based on monitoring data, the BAAQMD estimates that the incremental cancer risk due to lifetime exposure to average ambient concentrations of toxic air contaminants in the Bay Area in 1995 was 303 in one million (Bay Area Air Quality Management District, 1996b). The average cancer risk has decreased over recent years; this same estimate was 339 in one million based on 1993 data, and 356 in one million based on 1991 data.

Of the pollutants for which monitoring data are available, benzene and 1,3-butadiene contribute most significantly to the ambient cancer risk in the Bay Area. These two pollutants together account for nearly two thirds of the total risk. Over 90 percent of the total benzene and butadiene emissions are from mobile sources.

The contaminant 1,3-butadiene has not been reported in power plant emissions in the Bay Area. The only toxic air contaminants attributed to the power plants to be divested are benzene and formaldehyde. These two compounds together accounted for 100 percent of the toxic air contaminants emitted from the power plants.

Formaldehyde (HCHO) is the toxic air contaminant emitted from power plant stacks in the largest quantities. Formaldehyde is a simple organic substance that can be generated by incomplete combustion of natural gas. Pure formaldehyde is a colorless volatile liquid with a characteristic pungent odor. It is soluble in water. Formaldehyde is considered to be a toxic substance and a carcinogen. The primary pathway of exposure to formaldehyde in stack emissions would be inhalation.

At trace concentrations, benzene does not pose an acute health hazard. Over the long term, benzene exposure might produce headaches or respiratory problems. The carcinogenic nature of benzene is its greatest health threat. Benzene attacks the liver and can alter genetic matter in bone marrow, causing leukemia.

In addition to criteria air pollutants and toxic air contaminants, larger-sized particulate matter can be emitted by power plants. These particles, which are more of a nuisance than a health hazard, are known by several different names: fallout type particulates (FTP), fallout, or acid smut fallout. This EIR will use the term "FTP." This emission consists of large-size particles of dirt or soot that quickly fall from the air by virtue of their large size and weight and are deposited on horizontal surfaces. FTP, and its effects on boats and cars, has been a historically reported public concern at both the Pittsburg and Contra Costa power plants.

Once FTP is released to the atmosphere from an elevated release point (i.e., exhaust stack or vent), the relatively large size of FTP causes the particles to fall to ground quickly, within a short distance. This distance depends on several factors, such as the height of the release point, the temperature of the gas, and the ambient wind speed. FTP released from a source such as a power plant with a tall stack could be reasonably expected to affect a region within 1 to 1.5 miles downwind from the power plant site (Moss Landing AMPAC, 1996). When deposited on surfaces, FTP can become aesthetically bothersome and appear as rust-colored stains when moistened or wet. Horizontal surfaces of boats and cars are the most susceptible receptors and, in general, white or light colored surfaces are more affected by FTP stains than other surfaces. FTP is typically not found on vertical surfaces. When wetted, FTP forms stains that require determined scrubbing efforts to remove. In the case of fossil-fueled power plants such as those being discussed in this report, FTP can occur regardless of the fuel burned (fuel oil or natural gas), but is much more prevalent with fuel oil (Moss Landing AMPAC, 1996). Additionally, aside from the nuisance effect, there are no known environmental health impacts resulting from FTP (Kendig, 1998).

More than 20 years ago, at PG&E’s Contra Costa and Pittsburg Power Plants, due to complaints from local boat owners, PG&E implemented a FTP program to regularly wash boats (typically several times per month and periodic detailing of the vessels) to remove FTP-caused stains on boats. PG&E set up a "Harbor Claims Office" to administer this program. At the time, these power plant’s primary source of fuel was fuel oil. Since the end of 1994, use of fuel oil at these plants has ended and, in response to BAAQMD Regulation 9, Rule 11, only natural gas is burned in these plants. While the switching of fuels at the plants from fuel oil to natural gas has reduced this FTP problem, it has not eliminated it, and FTP-related claims continue to be reported today. (The overall cost of this fallout program is included in PG&E’s current rates.)

PG&E’s existing fallout program (FTP/Harbor Claims Program) is designed to respond to claims resulting from emissions of FTP from PG&E’s existing fossil-fueled power plants where FTP has been a historical problem for nearby property owners (PG&E, 1998c). This program offers a variety of means to assist claimants with the maintenance of property that is approved for the program, typically including pleasure and commercial vessels, motor homes, and automobiles. At the present time, PG&E maintains these programs on a voluntary basis. The programs at the Pittsburg plant are the Self-Wash Program, the Canvas Program, the Vehicle Maintenance Program, and the As-Needed Program. The programs at the Contra Costa plant are the Self-Wash Program, the Vendor Maintenance Program, the Canvas Program, and the Vehicle Maintenance Program.

Under the Self-Wash Program, vessel owners receive direct compensation for washing the exterior surfaces of their vessels to an acceptable standard. Owners are compensated monthly if they are permanently berthed or stored in close proximity to the plants. Vessels are inspected regularly to verify their condition. In the Canvas Program, vessel owners are provided custom covers to protect the vessels from FTP. The owner signs a five-year contract with PG&E; at its expiration, the cover becomes the owner’s property and the owner is eligible to participate in the Self-Wash Program. Under the Vendor Maintenance Program, vessel owners take their vessels to local vendors or brokers, who are compensated by PG&E for washing boats. The Vehicle Maintenance Program is similar to the Vendor program but is specific to motor vehicles. The As-Needed Program is not a regular program, but the claims are processed in the same manner as a regular third-party claim. Should FTP affect a vessel owned by someone not participating in the FTP/Harbor Claims Program, the claim is processed as a third-party claim. Boat and autos comprise the regular programs. Claims for damages to buildings or awnings are handled as third-party claims (PG&E, 1998c).

It should be noted that there are no specific BAAQMD rules or regulations that require PG&E to address FTP. If any district rules apply to FTP impacts at all, the BAAQMD’s regulation 1-301, Public Nuisance, would be the most applicable. PG&E has historically operated its Harbor Claim Office as a good neighbor policy (although for several years this program was mandated by out of court settlements), and not in response to any BAAQMD mandated actions. Over the years PG&E has, in response to complaints from locally affected parties and changes in plant operations, changed both the frequency of FTP-stain removal actions and the amount of monetary compensation to affected parties for these removal actions. Currently, PG&E’s FTP fallout program is applied to impacts that occur within loosely defined fallout zones surrounding both the Contra Costa and Pittsburg power plants. These fallout zones are dependent on wind conditions (speed and direction), who or what is in the area, the amount of FTP released, and plant operating conditions, etc. While no formal definitions of these fallout zones exists, historical experience has shown PG&E that certain areas located in close proximity to these power plants tend to be more affected than others. PG&E employees administering these programs are familiar with these areas (PG&E, 1998c). Through these FTP cleanup programs, the potential nuisance effects from FTP-stains appear to be abated.

There are no FTP programs in place at the Potrero plant; however, claims arising from FTP from this plant would be treated on an as-needed basis (PG&E, 1998c). There also are no FTP programs in place at the Geysers Geothermal plant since fossil fuel is not burned at the Geysers units.

4.5.2 REGIONAL SETTING

As discussed above and shown in Table 4.5-2, the Bay Area has been classified "attainment" or "non-attainment" for the criteria air pollutants. Under the federal Clean Air Act Amendments, air quality plans (known as State Implementation Plans, or SIPs) were required to be prepared for areas classified as "non-attainment" for any of the national standards. These plans were to contain a strategy to improving air quality and achieving the national standards.

Based on monitoring data in the 1970s, the Bay Area was designated "non-attainment" with respect to the national standards for ozone and carbon monoxide, and a SIP for the Bay Area was prepared (Association of Bay Area Governments, 1982). This 1982 SIP was intended to bring the Bay Area into compliance with the national standards by 1987. Under the federal Clean Air Amendments of 1990, SIPs were required to be revised to meet new requirements for those areas, like the Bay Area, that did not meet the 1987 deadline.

With respect to carbon monoxide, EPA recently announced its decision to approve a redesignation request for the Bay Area to "attainment" for the national carbon monoxide standard and to approve a Carbon Monoxide Maintenance Plan (Association of Bay Area Governments, 1994b), which is the new carbon monoxide SIP for the Bay Area.

Under the California Clean Air Act, areas designated as "non-attainment" for the state standards were required to develop air quality plans in addition to those required under federal laws. In 1991, an air quality plan, Bay Area ‘91 Clean Air Plan (‘91 Clean Air Plan), was developed to address the Bay Area’s (then) designation of "non-attainment" for the state ozone and carbon monoxide standards (Bay Area Air Quality Management District, 1991). (3) The goal of the ‘91 Clean Air Plan was to improve air quality in the 1990s through tighter industry controls, cleaner cars and trucks, cleaner fuels, and increased commute alternatives. Power plants were among the industries targeted in the ‘91 Clean Air Plan for more stringent controls, and two control measures described in that plan were adopted as BAAQMD Regulation 9, Rules 9 and 11, discussed below. The ’91 Clean Air Plan has been updated on a triennial basis. The most recent update is the Bay Area ’97 Clean Air Plan, which contains additional control strategies but none that relate directly to power plants (Bay Area Air Quality Management District, 1997).

As is the case with most other stationary sources, power plants in the Bay Area operate subject to permits issued by the BAAQMD as well as specific standards set forth in BAAQMD’s Rules and Regulations. Two of the most important Rules and Regulations that apply to power plants are Regulation 9, Rule 9 (Nitrogen Oxides from Stationary Gas Turbines) and Regulation 9, Rule 11 (Nitrogen Oxides and Carbon Monoxide from Utility Electric Power Generation Boilers).

The purpose of BAAQMD Regulation 9, Rule 9 is to limit emissions of nitrogen oxides from "stationary gas turbines." BAAQMD Rules and Regulations define "stationary gas turbines" as any gas turbine system that is attached to a foundation and that is gas and/or liquid fueled with or without power augmentation. In this section of the EIR, such turbines are referred to as "combustion turbines" to distinguish them from "steam boilers," which are the subject of Regulation 9, Rule 11, which is described below. (4) The combustion turbines described in this section are fired with distillate fuel rather than natural gas.

Regulation 9, Rule 9 sets forth emission concentration limits (5) for nitrogen oxides from combustion turbines; these limits differ depending upon the size of the combustion turbine, the fuel used to fire the turbine, and the presence or absence of selective catalytic reduction (SCR) abatement technology. The rule distinguishes between combustion turbines with ratings below 10 MW and those with ratings above 10 MW, with the more stringent requirements applying to the larger-sized units. The combustion turbines discussed in this report are rated higher than 10 MW are thus subject to the more stringent requirements of the rule. However, the rule allows for more relaxed emission concentration limits so long as the combustion turbine is used less than 10 percent of the year (i.e., less than 10 percent gross annual capacity, which is equivalent to 877 hours).

Two of the 14 operating units of the Geysers geothermal plant are located within the Lake County Air Basin (LCAB) under the jurisdiction of the Lake County Air Quality Management District (LCAQMD).

As was shown in Table 4.5-2, Lake County is designated "attainment" for all state and national ambient air quality standards and for state visibility standards (California Air Resources Board, 1998). Lake County is alone among California counties with this status. The good air quality of the County is documented in Table 4.5-3, which summarizes the last three years of monitoring data. Due to its "attainment" status, LCAQMD has not been required to develop a regional air quality plan such as a SIP or Clean Air Plan. With regard to the new Federal PM-2.5 standards, the County believes that they are in attainment of the new standards, since measured PM-10 levels are below the allowed PM-2.5 levels. This will be verified in the next two years, when the County will be setting up a PM-2.5 monitoring station and will be comparing measured ambient air levels with the standards.

Lake County’s Comprehensive General Plan recognizes good air quality as one of Lake County’s most valuable resources and also recognizes the potential for degraded air quality in the Basin given that the topography of the Lake County Air Basin makes dispersion of pollutants difficult under inversion conditions (Lake County, 1981). To protect and preserve Lake County’s air quality, the Comprehensive General Plan calls for the County to encourage the use of the best available air pollution control technologies to maintain healthful air quality and high visibility standards.

LCAQMD regulates emissions from geothermal power plants through its permitting authority over stationary sources. Local regulations limit emissions of particulate matter for each operating unit to 40 pounds per hour, and hydrogen sulfide emissions are limited to 15 pounds per hour.

Emissions trends for the Lake County Air Basin are shown in Table 4.5-5. The trends show that there will be emission reductions for most of the criteria pollutants in the region, mainly because of the use of less polluting vehicles in the future. The only pollutant showing an increase is PM-10, which is due principally to increases in area source emissions due to increases in vehicle-miles-traveled (VMT) and associated entrainment of dust from paved and unpaved roads.

Twelve of the operating units of the Geysers geothermal plant are located within the southern portion of the North Coast Air Basin under the jurisdiction of the Northern Sonoma County Air Pollution Control District (NSCAPCD). The Sonoma County portion of the North Coast Air Basin is "attainment" or "unclassified" for all state and national ambient air quality standards except for state standards for PM-10, for which it has been designated "non-attainment" (California Air Resources Board, 1998). State law does not require preparation of air quality plans to address "non-attainment" issues related to the state ambient standard for PM-10, and due to its "attainment" or "unclassified" status for the other criteria air pollutants, NSCAPCD has not been required to develop a regional air quality plan such as a SIP or Clean Air Plan. With regard to the new PM-2.5 standards, the air district cannot evaluate the attainment status of the region until PM-2.5 monitoring data are collected. This will be carried out when the County receives PM-2.5 monitoring equipment from the CARB. Since the region has been placed in the second tier for attainment classification by CARB, a PM-2.5 monitoring station will not be issued to the County until 1999 or 2000, after which the County will establish the attainment status.

The Sonoma County General Plan recognizes the importance of maintaining the good air quality that exists in the County (Sonoma County, 1989). Sonoma County identifies geothermal power plants in the Geysers as the largest stationary air pollutant source in the County and encourages adoption of standards, development of new technology, and retrofitting to reduce the air pollution resulting from geothermal development. Local NSCAPCD regulations limit emissions of particulate matter for each operating unit to 40 pounds per hour and hydrogen sulfide to 0.44 pounds per gross megawatt hour.

Emissions trends for the North Coast Air Basin are shown in Table 4.5-6. The trends show that emissions of criteria pollutants, except for PM-10, will be reduced significantly by the year 2010. Similar to Lake County, PM-10 emissions are predicted to increase slightly because of growth in area source activities, including entrained road dust.

4.5.3 LOCAL SETTING

The BAAQMD operates a network of monitoring stations in the Bay Area that provide concentration data for both criteria air pollutants and toxic air contaminants.

Table 4.5-7 summarizes the past five years of criteria air pollutant concentration data collected at the closest air quality monitoring station, which is located on Arkansas Street in San Francisco, and compares that data with the corresponding state ambient air quality standards. This station is located approximately 1.1 miles northwest of the Potrero Power Plant. Table 4.5-7 indicates that, with the exception of PM-10, background concentrations do not currently violate ambient air quality standards. Exceedences of the state 24-hour PM-10 standard are recorded on occasion in San Francisco.

Table 4.5-8 summarizes the past two years of toxic air contaminant concentration data collected at the air quality monitoring station located on Arkansas Street in San Francisco and compares the data with the concentration data based on the entire regional network of toxic air contaminant monitoring stations in the Bay Area. Table 4.5-8 indicates that toxic air contaminant concentrations at the Arkansas Street station are similar to, or less than, the average concentrations of those pollutants measured at other stations in the Bay Area.

The Potrero power plant consists of four electricity-generating units. Unit 3 is a steam boiler, and Units 4, 5, and 6 are combustion turbines. (Units 1 and 2 have been retired.) Unit 3 is coupled to a single boiler, which is capable of burning natural gas or fuel oil; however, since 1995, only natural gas has been burned because of Regulation 9, Rule 11. Units 4, 5, and 6 burn only distillate. The power plant also includes a switchyard, a control building, fuel oil tanks, and a firewater tank. Each of these smaller sources emitted less than half a ton per year of any single criteria pollutant and less than 50 pounds per year of any single toxic air contaminant in 1993 (Pacific Gas and Electric Company, 1995c).

Wind speeds at the plant average about eight miles per hour and are predominantly from the west. The area surrounding the project site includes heavy and light industrial land uses. The closest residences are located on Potrero Hill, approximately one-half mile to the west of the site.

The primary source of air pollutant emissions from the Potrero Power Plant is the combustion of fuel by the one steam boiler and three combustion turbines. Table 4.5-9 summarizes emissions estimates for the boiler and combustion turbines at the power plant for 1995, 1996, and 1997. The emissions from the plant depend on the capacity factor of each unit, which varies from year to year, and the emission rate of each unit, which is itself dependent upon the fuel that is combusted and the type of emissions control technology that has been installed.

From 1991 to 1997, the annual capacity factor for Unit 3 (steam boiler) has varied from 39 percent to 68 percent, and the annual capacity factor for Units 4, 5, and 6 (combustion turbines) has varied from 0.3 percent to 6.0 percent. In 1997, Unit 3 was used approximately 39 percent of the time; Units 4, 5, and 6 were used approximately 5.4 percent of the time, collectively. Currently, the steam boiler burns only natural gas; fuel oil consumption by the boiler has dropped from 375,000 equivalent barrels (of energy) in 1989 to zero barrels in 1995.

The power plant emissions contribute to ambient pollutant concentrations of criteria air pollutants in the plant vicinity. This local effect depends upon stack characteristics (such as the number of stacks, stack heights, stack gas exit temperature and velocity), local meteorology, as well as the overall amount of pollutants released. Figure 4.5-2 is a "wind rose" plot for the Potrero Power Plant showing the percentage of time from which the wind blows a given direction during a year. Impact 4.5-2, provided later in this Air Quality section, analyzes local pollutant concentrations with and without the project. As shown in the wind rose, the prevailing winds are from the southwest.

Power plant emissions include toxic air contaminants as well as criteria air pollutants. Table 4.5-10 shows the trend in toxic air contaminant emissions from the power plant since 1987 and presents 1995 emissions as a percentage of county-wide emissions. As shown in Table 4.5-10, emissions of most types of toxic air contaminants from the power plant have decreased substantially since 1987, because of the reduction in the use of fuel oil.

Generally, the effects of emissions of toxic air contaminants are evaluated by preparing a health risk assessment, and a health risk assessment was carried out for the power plant in 1993 to comply with AB 2588, the Air Toxics "Hot Spots" regulation. Health risk assessments estimate the risk of cancer due to exposure to toxic air contaminant emissions and evaluates the potential for other (non-cancer) acute or chronic health effects that may be caused by facility emissions. The calculated health risk is the worst-case reasonably foreseeable risk, considering the inherent uncertainties and assumptions made for the assessment. Preparing a health risk assessment requires four analytical steps: (1) hazard identification (determining the hazardous emissions resulting from a facility), (2) dose-response assessment (evaluating the health effects of exposure to these emissions), (3) exposure assessment (estimating the possible level of exposure), and (4) risk characterization (integration of the first three steps to estimate risk). Each step of the process involves making assumptions that lead to uncertainties in the risk assessment. Due to the use of conservative assumptions, the final calculated risk number is likely to be an overestimate of the actual risk.

The first step in the analysis is to estimate the type and amounts of toxic air contaminant emissions. The plant’s 1993 health risk assessment was based on 1989 emission data (Pacific Gas and Electric Company, 1993). The estimated emissions assumed that 17 percent of the total fuel consumed at the plant was oil (the maximum oil usage over the period of 1983 to 1991). In order to determine the health risks associated with the existing, 1999 baseline, 1999 A-Max and 2005 Cumulative A-Max scenarios, the emissions estimates of PG&E’s 1993 health risk assessment were revised to reflect actual current, and projected conditions of fuel oil replaced by natural gas in the boilers because of BAAQMD Regulation 9, Rule 11.

The second step, dose-response assessment, consists of identifying the chronic and acute health effects of these hazardous emissions. This step in the assessment is done by using unit risk values (for carcinogens) and acute and chronic reference exposure levels (for non-carcinogens) developed by government agencies. The updated health risk assessment presented in this EIR has used the latest available unit risk values and chronic-hazards reference exposure levels from the California Air Pollution Control Officer’s Association and the latest acute-hazards reference exposure levels from the California EPA Office of Environmental Health Hazard Assessment.

The third step in the analysis, exposure assessment, is to determine the manner in which the public would be exposed to toxic air contaminants generated by the facility and the extent to which they would be exposed. The most direct exposure to toxic air emissions from the power plant would be via inhalation of ambient air. Other routes of exposure to toxic air contaminants include non-inhalation pathways such as dermal contact, ingestion of contaminated soil, and ingestion of contaminated crops.

The health risk assessments reported in this document for existing conditions, for the 1999 baseline, and for the 1999 and 2005 A-Max scenarios were calculated using dispersion models approved by the California Air Pollution Control Officers Association (CAPCOA).The modeling effort used actual meteorological data collected at each project site. For the purposes of the health risk assessment, the computer modeling seeks to find the location with the highest calculated ground-level concentration of the contaminants. A person at this point would have the greatest exposure to emissions from the plant. The hypothetical maximally exposed individual (MEI), whose exposure is used to evaluate the worst-case exposure level, would be located at this point. In residential areas, this MEI is assumed to be exposed to toxic air contaminant emissions for 24 hours per day, 365 days per year, for 70 years. In non-residential areas, where the exposure relates to an occupational setting, the MEI is assumed to be exposed for eight hours per day, 240 days per year, for 46 years. These levels of exposure are highly unlikely in actual situations, and are typical of standard conservative health risk assessment assumptions (California Air Pollution Control Officers Association, 1993).

For carcinogens, the health risk at the MEI receptor is normally expressed as the chance in a million that an individual would contract cancer if he or she were exposed to the estimated concentration for 46 or 70 years, depending on whether the MEI is a worker or a resident. If there were a one percent chance that an individual would contract cancer from exposure, the risk would be ten thousand in a million.

For non-cancer health effects, the potential for human health hazards is evaluated by calculating ratios ("hazard quotients") between the estimated level of exposure to reference doses for various substances. Reference doses for non-carcinogens are levels established by the scientific community and by State and Federal agencies responsible for protecting human health. Reference doses for some substances are based on observed effects on laboratory animals. Others have been derived from observed health effects on humans.

Reference doses for some substances are defined in the EPA’s Integrated Risk Information System (IRIS). Others are based on calculations conducted by the California Office of Environmental Health Hazard Assessment, in which a 100-fold safety factor is applied to the threshold for "no observed effects level" (NOEL). When the ratio of the estimated concentration level to the reference dose is less than 1.0, no health effect would be anticipated. In a conservative analysis, the ratios for the various substances considered are added together to obtain a "hazard index," which, when less than 1.0, would indicate no health effect. This method is intended to account for the possibility that more than one chemical could contribute to the same health effect. The final step, risk characterization, combines the information about pollutant concentrations and health effects of those pollutants to determine the potential cancer risk and chronic and acute health hazards that would result from a facility.

The updated health risk assessment conducted for this EIR adjusts the risks portrayed in PG&E’s 1993 health risk assessment to reflect the changes from fuel oil to natural gas. under existing conditions. Applying this adjustment, the current estimate of the maximum cancer risk from existing plant emissions at offsite locations is significantly lower than one in a million (0.173 in a million). The contributions of the individual sources to cancer risks are shown in Table 4.5-11. There is no standard significance threshold for acceptable cancer health risks. However, several air pollution agencies in California, including the BAAQMD and the California Air Pollution Control Officer’s Association (CAPCOA), consider an incremental risk from an existing facility to be acceptable if it is less than ten in a million. The ten in a million risk is therefore considered to be the significance threshold.

A study conducted by the San Francisco Department of Health (1995) reported that there were higher incidences than expected of breast and cervical cancer in the Bayview-Hunters Point Area in the years 1988-1992. A follow-up to the findings of this study was carried out by the California Department of Health Services (Glazer et al., 1998). This follow-up study evaluated the incidence of cancer in the same area for the period 1993-1995. The findings state that, for 1993-1995, the observed numbers of cancer among Bayview-Hunters Point residents were very similar to other regions of the Bay Area. According to the study, the observed increase during 1988-1992 may of been explained by increased breast cancer screening that was started in the late 1980s, in order to provide more opportunity for early detection.

For non-carcinogenic pollutants, the maximum exposure levels (adjusted for natural gas) beyond the plant boundaries were well below the level associated with adverse effects. The chronic hazard index for non-carcinogenic effects from the entire plant were estimated to be less than 0.02 at the location of maximum pollutant concentrations. Since this total level is well below the "safe level" index of 1.0, the contributions of the individual units at the plant were not reported in the Table 4.5-11. The maximum hazard index for acute exposure to non-carcinogenic substances was calculated to be less than 0.18, which also is well below the significance threshold of 1.0.

A draft study released by the Bayview Hunters Point Health and Environmental Assessment Task Force (Aragon and Grumbach, 1997) reported that hospitalization rates for asthma, hypertension, diabetes and congestive heart failure are higher in this area than any other part of San Francisco. However, the draft study does not identify the cause(s) of the observed increased respiratory problems, and does not consider individual pollutant exposure. To better understand the causes of the increased incidences, a detailed study would have to be carried out that can characterize individual exposure. Without a detailed study, only inferences can be made regarding the relationship between industrial emissions, vehicle emissions, other sources, and respiratory problems in the area. Because the Potrero Power Plant is close to the Bayview-Hunters Point area and to other nearby sensitive receptors, a detailed dispersion modeling analysis of PM-10 emissions was conducted to determine the respiratory effects on residents in the area. These impacts are reported in Impact 4.5-2 (impacts of criteria pollutant emissions).

Studies cited by EPA (Schwartz, 1996; Pope et al., 1992; Dockery et al., 1992; Schwartz, 1993; Ito and Thurston, 1996; Kinney et al., 1995) show significant relationships between respiratory illness and symptoms and exposure to total suspended particulates (TSP) and some studies show similar relationships from exposure to smaller particles, including particulate matter less than 10 microns in size (PM-10) and fine particles (PM-2.5).

As stated earlier, emissions from the combustion of natural gas and distillate at the PG&E plants are particulate matter typically less than 2.5 microns in size. There are no data on background ambient air concentrations of PM-2.5 in the area, because the new Federal Standard has only recently been adopted by EPA, and monitoring for PM-2.5 has not been undertaken yet. Since background levels of PM-2.5 are not known, the impacts of particulate matter emissions on ambient air standards will be evaluated with respect to estimated PM-10 levels instead of PM-2.5. However, the effects on health through changes in hospitalizations from respiratory effects can be evaluated for PM-2.5, because of recent studies reported by EPA on the health effects from increased exposure to PM-2.5. will be evaluated with respect to acceptable levels for PM-10 and for PM-2.5.

The maximum 24-hr average contribution of PM-10 and of PM-2.5 are assumed to be the same, because nearly all particles emitted from natural gas combustion in boilers and from distillate combustion in CTs are smaller than 2.5 microns. Estimated contributions of PM-10 from the fossil fuel plants under baseline conditions, and under the 1999 A-Max scenarios are reported under impacts, later in this section.

Table 4.5-12 summarizes the past five years of criteria air pollutant concentration data collected at the air quality monitoring station located on Bethel Island Road, east of Oakley in eastern Contra Costa County and compares the data with the corresponding state ambient air quality standards. The pollutant concentrations measured at this station reflect local pollutant sources as well as emissions sources to the west and south whose emissions are blown into the Delta region by prevailing winds. This station is located on Bethel Island Road, which is located approximately seven miles east of the Contra Costa Power Plant. Table 4.5-12 shows that violations of the state ambient ozone standard occur on an average of approximately 5 days per year. Table 4.5-12 also shows that background PM-10 concentrations violate the state 24-hour standard on occasion.

The Contra Costa Power Plant consists of two operational electricity-generating units. Unit 6 and Unit 7 are both steam turbines, and they are each coupled to a single boiler. Units 1 through 5 are retired and are incapable of operating to generate electricity; however, Units 4 and 5 have been reconfigured to operate as synchronous condensers to help the electrical grid respond to changing system conditions and upsets. Units 4 and 5 do not generate air pollution or electricity when operating in synchronous mode. The Contra Costa Power Plant also includes an electric switchyard, buildings for offices and turbine generators, cooling water intake structures and discharge canals, and a fuel tank farm consisting of fuel oil tanks, pipelines, and an inactive marine terminal. Units 6 and 7 are capable of burning natural gas or fuel oil; however, fuel oil is no longer used at the plants except in the event of a natural gas curtailment.

Wind speeds at the plant average about 8 miles per hour in Martinez and 9 to 10 mph farther east, and prevailing winds are from the west. The area surrounding the project site includes industrial, commercial, and agricultural land uses. A yacht harbor borders the plant to the east, and a Pacific Service Employees Association recreational facility lies to the northeast. The City of Antioch is located to the east of the site, and the City of Oakley is located to the west.

The primary source of air pollutant emissions from the Contra Costa power plant is the combustion of fuel by the boilers. Other contributors to air emissions include lube oil and distillate storage tanks, a gasoline dispensing facility, boiler standby equipment (distillate fire engine and mobile combustion turbine), solvent cleaning operations, maintenance coating operations, a wastewater treatment facility, sandblasting, and miscellaneous sources. Each of these minor sources emit less than a half ton per year of any single criteria pollutant and less than 50 pounds per year of any single toxic air contaminant under existing operations in the year 1993 (Pacific Gas and Electric Company, 1995a).

Table 4.5-14 shows emissions estimates for the boilers at Contra Costa power plant for 1995, 1996, and 1997. The emissions from the plant depend on the capacity factor of each unit, which varies from year to year, and the emission rate of each unit, which is itself dependent upon the fuel that is consumed and the type of emission control technology that has been installed. From 1991 through 1997, the average annual capacity factor for Units 6 and 7 was approximately 38 percent, with a range from approximately 20 percent to 58 percent. In 1997, the capacity factor was 24 percent. Currently, the boilers associated with Units 6 and 7 burn only natural gas; fuel oil consumption at Contra Costa power plant has dropped from 667,000 equivalent barrels (of energy) in 1989 to zero barrels in 1995.

The power plant emissions contribute to ambient pollutant concentrations of criteria air pollutants in the plant vicinity. This local effect depends upon stack characteristics (such as the number of stacks, stack heights, stack gas exit temperature and velocity), local meteorology, as well as the overall amount of pollutants released.

Figure 4.5-3 is a wind rose plot of the Contra Costa Power Plant showing the percentage of time from which the wind blows a given direction during a year. Impact 4.5-2, provided later in this Air Quality section, analyzes local concentrations of criteria air pollutants with and without the project.

Table 4.5-15 shows the trend in toxic air contaminants from the Contra Costa power plant since 1987 and presents 1995 emissions as a percentage of county-wide and region-wide emissions. As shown in Table 4.5-15, emissions of most types of toxic air contaminants have decreased substantially since 1987, primarily due to the reduced use of fuel oil to operate the boilers.

PG&E conducted a health risk assessment to comply with AB 2588. The health risk assessment for the plant was based on 1989 emission data (Pacific Gas and Electric Company, 1992a). Dispersion modeling in the health risk assessment used hourly meteorological measurements that were taken for a year at the nearby Louisiana Pacific plant. Figure 4.5-3 shows a wind rose plot for this location. The AB 2588 health risk assessment assumed that 12.8 percent of the total fuel consumed at the plant was oil (the maximum oil usage over the period of 1983 to 1991).

Results of the health risk assessment indicate that the maximum impact from toxic air contaminant emissions occurs within the plant site. The maximum cancer risk for off-site exposure was calculated to be 0.17 in a million. This occurred in an industrial area. Over 99.7 percent of the excess cancer risk was attributed to benzene from gasoline storage and dispensing, rather than from electricity generation (Pacific Gas and Electric Company, 1992a). Since 1996, benzene emissions from gasoline have been reduced by 25 percent to 40 percent because of the State Clean Fuels program. Thus, exposure to benzene would be reduced significantly, resulting in the total cancer risk at the maximum receptor to be reduced to 0.1 in a million. The maximum contribution from the steam boilers was estimated to be significantly lower than from gasoline handling. Adjusting the AB 2588 study for the use of natural gas results in a maximum risk from the steam boilers of 0.05 in a million, at a different location approximately one-half mile east of the plant.

The AB 2588 health risk assessment found both the chronic and acute hazard indices to be approximately 0.02, well below the significance threshold of 1.0.

The Pittsburg power plant consists of seven electricity-generating units. Each of these units is a steam turbine with is coupled to a single boiler. Other facilities at the plant include an electric switchyard, cooling water intake structures, a cooling water canal and a cooling tower, and a fuel farm consisting of fuel oil tanks, an offsite pipeline terminus, and a marine terminal. While two of the seven boilers are permitted to burn either natural gas or fuel oil, all of them currently burn only natural gas (because of restrictions in BAAQMD Regulation 9, Rule 11).

Wind speeds at the plant average about 8 miles per hour in Martinez and 9 to 10 mph farther east, and prevailing winds are from the west. The area surrounding the project site includes light industry, residential property, commercial property, and boat harbors.

The primary source of air pollutant emissions from the Pittsburg power plant is the combustion of fuel by the boilers. Other contributors to air emissions include storage tanks for organic liquids, a gasoline service station, sandblasting operations, solvent cleaning operations, maintenance coating operations, oil-water separating operations, and miscellaneous sources. Each of these other sources (i.e., not including the boilers) emitted less than a ton per year of any single criteria pollutant and less than 50 pounds per year of any single toxic air contaminant in the year 1993 (Pacific Gas and Electric Company, 1995c).

Table 4.5-17 shows emissions estimates for the boilers at the Pittsburg power plant for 1995, 1996, and 1997. The emissions from the plant depend on the capacity factor of each unit, which varies from year to year, and the emission rate of each unit, which is itself dependent upon the fuel that is combusted and the type of emissions control technology that has been installed.

From 1991 through 1997, the annual capacity factor for Units 1 through 4 (i.e., the 170 MW steam turbines) varied from 4 to 36 percent; the annual capacity factor for Units 5 and 6 (the 330 MW steam turbines) varied from 25 to 59 percent; and the annual capacity factor for Unit 7 (the 720 MW steam turbine) varied from 17 to 71 percent. Over that same period, the average annual capacity factor was approximately 18 percent for Units 1 through 4, 36 percent for Units 5 and 6, and 46 percent for Unit 7. In 1997, the utilization rate was approximately 5 percent for Units 1 through 4; 25 percent for Units 5 and 6, and 37 percent for Unit 7. Currently, the boilers at the Pittsburg power plant burn only natural gas, although two of the boilers are permitted to burn fuel oil. Fuel oil consumption by the boilers at the Pittsburg plant has dropped from 1.5 million equivalent barrels of energy in 1989 to zero barrels in 1995.

With respect to emissions control technology, all of the units at the Pittsburg power plant are subject to the requirements of BAAQMD Regulation 9, Rule 11. Under this Rule, combustion modifications have been made to Units 5 (in 1997), 6 (in 1996), and 7 (in 1997). Similar combustion modifications are planned for installation in 1998 for Units 1 through 4.

The existing power plant emissions contribute to ambient pollutant concentrations of criteria air pollutants in the plant vicinity. This local effect depends upon stack characteristics (such as the number of stacks, stack heights, stack gas exit temperature and velocity), local meteorology, as well as the overall amount of pollutants released.

Power plant emissions include toxic air contaminants as well as criteria air pollutants. Table 4.5-18 shows emissions of toxic air contaminants from the Pittsburg plant for previous years. Most of the toxic metal emissions reported in Table 4.5-18 for the years 1987 to 1992 were the result of burning oil rather than natural gas. With the elimination of fuel oil and the increased use of natural gas, toxic metal emissions decreased significantly, and emissions of formaldehyde increased. As shown in Table 4.5-18, formaldehyde emissions, which are a by-product of natural gas combustion, generated at the Pittsburg Power Plant in 1995 have been estimated to represent approximately one percent of County-wide formaldehyde emissions. Figure 4.5-4 is a wind rose plot for the Pittsburg Power Plant.

The plant’s health risk assessment was based on 1989 emission data (Pacific Gas and Electric Company, 1992b). The dispersion modeling in the health risk assessment used hourly meteorological measurements taken at the Pittsburg Power Plant. The assessment assumed that 11.7 percent of the total fuel consumed at the plant was oil (the maximum oil usage over the period of 1983 to 1991). Results of the health risk assessment indicate that the maximum impacts from toxic air contaminant emissions occur within the plant site, for which the maximum lifetime exposure duration is considered to be eight hours/day, 240 days/year, for 46 years, or 14.4 percent of the maximum residential lifetime exposure of 24 hours/day, 365 days/year for 70 years.

The excess cancer risk attributed to plant emissions for 1989 emissions was calculated to be 4.5 excess cancer cases per million workers exposed for a lifetime at the location of maximum non-residential exposure. Most of this incremental worker risk was due to exposure to gasoline vapors from a vehicle refueling station on the property.

For the maximum residential exposure (lower concentration, but longer exposure) the maximum individual excess cancer risk was calculated to be 0.50 in a million.

The main contributors to this calculated cancer risk were hexavalent chromium and nickel, both of which are emitted only when burning oil (Pacific Gas and Electric Company, 1992b). Since the burning of oil in the steam boilers was discontinued at the end of 1994, the excess individual cancer risk for existing operations are estimated to be 1.3 in a million for workers and 0.1 in a million for residential exposure.

For exposure to non-carcinogenic pollutants, the maximum exposure levels beyond the plant were well below the level associated with adverse chronic effects. The chronic hazard index for non-carcinogenic effects was calculated to be less than 0.02 at the location of maximum pollutant concentrations. An index of less than 1.0 is considered to be a "safe" level. The main contributor to this chronic non-carcinogenic hazard index was nickel, accounting for over half the calculated risk, with the second highest contributor being hexavalent chromium. Thus, the chronic hazard index is less than 0.01.

During September 1995, a one-hour hydrogen sulfide concentration of 0.05 ppm, exceeding the state standard of 0.03 ppm, was measured at one of the monitoring stations. On the same day, a level of 0.03 was measured at another station. Investigation of the exceedance by California Air Resources Board revealed that over a three year period surrounding this exceedance, 1994-1996, no other exceedences were observed. The California Air Resources Board staff, therefore, recommended that the area remain designated as being in attainment of the hydrogen sulfide ambient air standard (California Air Resources Board, 1997a).

The Geysers Power Plant consists of 14 steam-powered generating units in operation at 11 sites. The steam used to operate these units originates from a fractured reservoir above a magma heat source that lies beneath an area of several hundred square miles near the south and east end of

Clear Lake. The dry steam in this reservoir is at a pressure of several hundred pounds per square inch at a temperature of approximately 450 degrees Fahrenheit. It is produced from wells ranging in depth from 6,000 to more than 12,000 feet, gathered and transported by pipelines to the generating units.

In the mid 1980s, a pipe manifold network was installed, and pressure was regulated with an automatic steam distribution system. The distribution system links several units together through a manifold piping system. By using automatically activated valves, the manifold distributes the steam according to need, thereby relieving pressure in the line. Also, the manifold system increases the overall volume of the piping network, allowing for the accumulation of more steam in the line before pressure relief would have to occur. Since the system was installed, stacking has been reduced significantly.

The Geysers Plant also generates relatively minor quantities of emissions of nitrogen oxides, sulfur oxides and carbon monoxide that result primarily from the use of a burner/scrubber system. Because geothermal steam may contain radon gas, measurements were carried out to determine levels in the area. The measurements indicated levels of radon ranging from 3 to 5 pico-curies per liter of air, which is above typical background levels of 1 pico-curie per liter (1998, personal communication with Lake County APCD).

Other emissions sources associated with the Geysers Plant include ovens (used to dry "solventless" insulation coatings on electric motor parts and to remove old coatings in preparation for repair), parts washing stations, a solvent recovery distillation facility, gasoline dispensing facilities, a spray painting booth, emergency distillate generators, and solvent cleaning and painting maintenance activities. Emissions from such sources are relatively minor.

Table 4.5-21 shows criteria air pollutant emissions from the plant for 1995, 1996, and 1997 and compares the 1997 estimates with county-wide emissions for Lake County in that year. Table 4.5-22 shows the 1995, 1996, and 1997 criteria pollutant emissions and compares the values with county-wide and basin-wide emissions for Sonoma County. As indicated in

Table 4.5-22, the Geysers Power Plant accounted for relatively large portions of Sonoma County’s 1997 inventory of PM-10.

LCAQMD and NSCAPCD calculated risk prioritization scores for the Geysers plants to determine if toxic pollutant emissions can be significant. The prioritization scoring uses the methodologies recommended by CAPCOA. A risk prioritization score, which is a screening health risk assessment, is calculated for each plant based on the quantities of emissions, the potencies or toxicities of the emissions, and the proximity of potential receptors.

Generally, scores over 10 are typically considered "higher priority," and would require a detailed health risk assessment. For carcinogens, all of the Geysers units scored less than 1.0; the highest score was 0.58 for Unit 17 (Pacific Gas and Electric Company, 1998b). Scores of less than 1 are considered "low priority." The chronic non-carcinogenic effects risk scores for the Geysers units ranged from 0.43 to 4.3. Regulatory decisions on whether to require detailed health risk assessments where chronic effects scores are between 1 and 10 depend upon the consideration of other factors in addition to the calculated risk. The acute effects risk scores were calculated only for the two Lake County Units, and they ranged from 0.52 to 1.03 (the higher score was for Unit 16). Both LCAQMD and NSCAPCD have requested data from the facilities every four years to update the prioritization scores.

4.5.4 SIGNIFICANCE CRITERIA

A project may be deemed to have a significant effect on the environment if it would violate any ambient air quality standard, contribute substantially to an existing or projected air quality violation, expose sensitive receptors to substantial pollutant concentrations, or conflict with adopted environmental plans and goals of the community where it is located (Governor’s Office, 1997).

If an air emission meets the existing standard for a particular pollutant, the Lead Agency may presume that the emission or discharge of the pollutant will not be a significant effect on the environment. If other information is presented suggesting that the emission may cause a significant effect, the Lead Agency shall evaluate the effect and decide whether it may be significant (CEQA Guidelines 15064(i)) (Governor’s Office, 1997); BAAQMD CEQA Guidelines restate this notion in the following way: "Sources of air pollutant emissions complying with all applicable District regulations generally will not be considered to have a significant air quality impact." However, BAAQMD CEQA Guidelines recommend that Lead Agencies make an exception to this presumption where special circumstances suggest that the emissions from the permitted source may cause a significant air quality impact.

With the above introduction, the following significance criteria are used herein to evaluate the impacts of the project:

4. With regard to the potential for causing increased respiratory problems, the impact would be significant if the total contribution of PM-2.5 emissions from the plant (baseline operations plus added operations under A-Max conditions) would contribute to ambient air levels sufficiently to cause increased respiratory ailments. The levels shown to cause increased ailments are described earlier in this section under Health Effects from Particulate Matter and are based on cited studies. For short-term exposure, the contribution from the plant would be significant if the maximum 24-hour average contribution exceeds 20 micrograms per cubic meter, or if the expected number of days exceeding 20 micrograms per cubic meter increases compared to the baseline. For chronic exposure, the contribution of PM-2.5 emissions from the plant would be significant if the maximum annual average contribution exceeds 10 micrograms per cubic meter.
5. Inconsistency with the regional air quality plan. For quantitative evaluation purposes in this context, inconsistency with the plan is defined as an increase in emissions (over those included in the plan) equivalent to one percent of the regional inventory.

4.5.5 IMPACTS AND MITIGATION MEASURES

The following air quality evaluation has been divided into five general impacts including: 1) changes in criteria air pollutant emissions, 2) changes in local criteria air pollutant concentrations, 3) changes in facility-specific health risks, 4) changes in fallout type particulate (FTP), and 5) consistency with regional air quality plans. Where appropriate, impacts are described for both analysis years, 1999 and 2005. In contrast, for the other types of potential impacts (traffic, noise, land use, etc.) identified in this EIR, the discussion of cumulative impacts in Year 2005 is presented in Chapter 5.

The project would allow the transfer of ownership of the power plants from PG&E to some other entity. Construction emissions would be minimal; the only potential construction being activities necessary to separate sale and non-sale property, such as a switchyard and generating unit. Indirect emissions sources, such as power plant employee motor vehicle trips, would be essentially unchanged since the number of employees could increase, but only to a minor degree. While the transfer itself would not have air quality effects, the change in ownership could theoretically lead to changes in emissions generated by the power plants due to changes in the amount or pattern of electricity generation at the plant, changes in the type of fuel used, or changes in pollution control technologies employed.

The first factor that could influence future power plant emissions is the amount and pattern of electricity generation. This EIR assumes, for conservative purposes, that new owners would operate the plants at their Analytical Maximum capacities (see Chapter 3, Approach to Environmental Analysis). The Analytical Maximum capacities were used as the basis for the emissions estimates presented later in this section.

The second factor that could influence power plant emissions is the type of fuel that would be consumed. Under existing conditions, the Bay Area power plants use two types of fuel: the combustion turbines burn distillate, and the steam boilers burn natural gas. The steam boilers burn natural gas rather than fuel oil due to both economic and regulatory factors. Even if regulatory conditions were to change with respect to BAAQMD Regulation 9, Rule 11, economic factors could tend to dictate use of natural gas rather than fuel oil in the boilers. Therefore, the emissions estimates presented in this section reflect the continued use of distillate by the combustion turbines and natural gas by the steam boilers. For informational purposes, it is noted that, on an equal-energy basis (i.e., pounds of pollution per million BTU), fuel oil combustion results in approximately 3 to 4 times more PM-10 than natural gas combustion based on the latest EPA emissions factors. Also, fuel oil combustion generates higher emissions than natural gas for most of the applicable toxic air contaminants, including arsenic (50 times more), chromium (four times more), mercury (three times more), and nickel (200 times more). The Geysers units are, and would continue to be, powered by geothermal steam.

The third factor that could influence future power plant emissions relates generally to the regulatory context under which the plants operate. Under the project, PG&E would "transfer" its existing air quality permits for the power plants to the new owners. Typically, Air District regulations technically prohibit transfer of permits from one owner to another upon change of ownership of a facility. However, state law requires the air districts to provide a mechanism for reissuing a permit to a new owner or operator and prohibits the imposition of more stringent controls or operating conditions solely as a result of a change of ownership (Health and Safety Code §42301(f)). Thus, the new owner of a power plant acquired as a result of the project would be required to apply for and obtain a new permit from the applicable air district, but the new permit cannot contain limitations or other requirements that are more stringent than those contained in the existing permits.

In anticipation of the changes brought about by restructuring and divestiture, BAAQMD has expressed its intention to modify Regulation 9, Rule 11 to ensure its continued applicability to all of the electric utility steam boilers at the four Bay Area power plants (Garvey, 1998), regardless of whether they are utility-owned. In addition, several options for modifying the emissions limits of the rule are currently under consideration by the BAAQMD. These options include a modification of the "bubble" option that would apply the current "bubble" emissions limit at each of the four Bay Area plants (the three plants to be divested and the Hunters Point Power Plant), creating essentially four "bubbles," or a modification that would allow for an owner-based "bubble" option. An owner-based bubble option would apply the emissions "bubble" limit to as many steam boilers as would be under the control of a single owner, thereby creating the possibility for one, two, three, or four "bubbles" for one, two, three or four owners, respectively. The amended rule will also likely retain the individual boiler emissions limits as an option.

Since it is uncertain if, and how, BAAQMD would modify Regulation 9, Rule 11 to address the issues raised by divestiture and restructuring, the air quality analysis includes a set of estimates, which assume that BAAQMD modifies the rule and another set of estimates, which assume that BAAQMD does not modify the rule.

Emissions estimates have been made for the Potrero, Contra Costa, and Pittsburg Power Plants, taking into account the three main factors discussed above. The following tables show estimates of criteria air pollutants for the Potrero (Table 4.5-23), Contra Costa (Table 4.5-24) and Pittsburg (Table 4.5-25) power plants. Each of these tables shows emissions estimates under two different operational scenarios (baseline and analytical maximum) and under two different regulatory scenarios (with modifications to BAAQMD Regulation 9, Rule 11 and without such modifications). Table 4.5-26 combines the emissions estimates for the three power plants and combines them with emissions estimates for Hunters Point (in 1999) and a new San Francisco power plant (in 2005) to provide estimates of total power plant emissions in the Bay Area in those analysis years.

The operational scenarios include "baseline" estimates and "analytical maximum," or "A-Max" estimates. (9) Baseline estimates represent the condition whereby PG&E would continue to own and operate the three plants, i.e., the no project alternative. The A-Max estimates represent the condition whereby the plants would be run at their highest possible capacities in light of technical and demand constraints. The A-Max assumes that natural gas could be purchased in unlimited quantities at a 25 percent discount from the least expensive supply of gas assumed to be available to fuel California power plants. The purpose of this assumption was to remove, to a great degree, the cost of fossil fuel from the new owner’s decision whether and when to generate power. Although it is extremely unlikely that such a reduced gas price could be obtained, this assumption further strengthens the conservative nature of the impact analysis. With a discounted price for natural gas, the power generated by the new owner would have a competitive advantage over other generators and would thus generate more power and higher corresponding emissions. The difference between the two values, i.e., between the baseline values and the A-Max values, represents the maximum possible impact of the project in 1999. The actual impact of the project may be less and may approach zero (i.e., no difference between the emissions with a new owner and those with PG&E).

The A-Max emissions for 2005 estimate the high-end of the possible range of power plant emissions in that analysis year. The emissions estimates for 2005 take into account a number of cumulative projects and factors, including load growth and an emissions control installation schedule. Because of PG&E’s recent agreement with the City and County of San Francisco to close Hunters Point Power Plant as soon as alternatives are available to meet reliability needs in San Francisco, this analysis assumes that Hunters Point Power Plant would be closed by 2005 and a new 480 MW power plant would be installed at an undetermined location to meet load growth and maintain reliability.

With the above introduction, the following conclusions can be made with respect to the potential changes in emissions estimated for the Potrero Power Plant shown in Table 4.5-23.

The following conclusions can be made with respect to the estimated changes in annual emissions at the Contra Costa Power Plant shown in Table 4.5-24:

The following conclusions can be made with respect to the estimated changes in annual emissions at the Pittsburg Power Plant shown in Table 4.5-25:

The capacity factors for the Geysers units would not be affected by the project to the same degree as the Bay Area plants. Therefore, the emissions changes would be more modest. In addition, the types of issues raised by BAAQMD Regulation 9, Rule 11 are not relevant within the regulatory context in which the Geysers plant operates. Existing and projected emissions from the Lake County units of the Geysers plant are shown in Table 4.5-27. Based on the difference in emissions in 1999 between the "A-Max" case and the "baseline" case, emissions from the Lake County units are not expected to be change substantially due to divestiture. Furthermore, cumulative changes in emissions, as shown by the difference between emissions in 2005 under the A-Max case and the 1999 baseline, would not be substantial.

Existing and projected emissions from the northern Sonoma County units of the Geysers plant are shown in Table 4.5-28. This table shows that emissions of hydrogen sulfide would increase in the 1999 A-Max scenario compared with the 1999 Baseline scenario by approximately 40% and that increases of the other criteria air pollutants would be slightly less (on a percentage basis). Table 4.5-28 also shows that emissions in the cumulative 2005 A-Max scenario would be similar to those in the 1999 A-Max scenario. The increase in emissions (relative to the 1999 Baseline) would occur because of the estimated increase in annual capacities of individual units in Sonoma County under the A-Max scenario that would be expected to accompany the availability of relatively less expensive steam. (In contrast to many of the Sonoma County units, the Lake County units already use relatively less expensive steam and, therefore, for those units, there would be little difference between the Baseline case and the A-Max case.) The hydrogen sulfide

emissions estimates shown in Table 4.5-28 represent "controlled" emissions releases, which are the residual emissions subsequent to abatement by unit-specific hydrogen sulfide control systems (see Table Table 4.5-20). These emissions increases would occur within the limitations of existing air quality permits.

None.

None required.

For Potrero and Pittsburg Power Plants, new atmospheric dispersion modeling was performed using an EPA approved dispersion model, ISCST3 (Industrial Source Complex Short Term 3, version 97363). The analysis for the Potrero plant utilized meteorological data from PG&E’s on-site meteorological monitoring station for the year 1991. The analysis for the Pittsburg plant utilized meteorological data from PG&E’s on-site meteorological monitoring station for the year 1994. Plant input parameters, such as topography, building configurations, and stack heights were provided by PG&E, and modeling was conducted using standard regulatory default modeling assumptions.

Impacts from the plant emissions on ambient air quality were determined by comparing the modeled maximum ambient air concentrations for the 1999 Baseline scenario with modeled A-Max scenarios. The incremental changes in air pollutant concentrations were compared with ambient air standards to determine whether the predicted concentrations would exceed the standards or would add to exceedances. For determining if the project may cause respiratory related effects because of changes in particulate matter emissions, the impacts were determined by evaluating the total contribution of PM-10/PM-2.5 emissions to ambient air levels for the A-Max scenario. The impacts for each plant are described below.

For short-term impacts, the maximum 24-hour concentration for PM-10 reported in Table 4.5-29 is predicted to increase by 0.5 micrograms per cubic meter over 1999 Baseline scenario conditions. For both the 1999 Baseline and the 1999 A-Max scenario, over 98 percent of the maximum level is contributed by emissions from the CTs at the plant (Units 4, 5, and 6). The maximum 24-hr concentrations of PM-10 for both the 1999 Baseline and for the 1999 A-Max scenario were determined from dispersion modeling runs of the maximum daily operating conditions. The maximum daily operating scenarios were extracted from a SERASYM^TM modeling run of plant operations for an entire year. Table 4.5-29 shows that the maximum impact for the 1999 A-Max scenario is the difference between the Baseline and A-Max concentrations for the highest day in the year. Since the estimated increase is well below the 5 microgram per cubic meter significance threshold, the impact is less than significant.

For evaluating 1-hour NO₂ and CO impacts, it was assumed that, over such a short time interval, the maximum operating rates for all units at the plant could be operating at the same maximum rate for both the 1999 baseline and for 1999 A-Max. Therefore the maximum 1-hour ambient air concentrations would not change. For the 8-hour CO and 24-hour SO₂ impacts, is was assumed that the plant would operate at maximum capacity under both scenarios and would not change.

For the estimated maximum 24-hour concentration of PM-10, Table 4.5-31 shows that the maximum concentration is expected to increase as a result of the project by less than one microgram per cubic meter. Thus, the impact would be less than significant.

The modeling results in Table 4.5-32 show that the maximum one hour average concentration of nitrogen dioxide may exceed the state standard under both the 1999 baseline conditions and under the 1999 Analytical Maximum scenario. The estimated maximum concentrations for both scenarios incorporate extremely conservative background conditions. For the worst case modeling analysis, it is assumed that the highest background levels for nitrogen dioxide and ozone occur simultaneously at the same location. The background levels for these pollutants directly affect the magnitude of the estimated one-hour nitrogen dioxide total concentration. Since it is highly unlikely that the maximum background levels occur simultaneously, it can be assumed that the state one-hour standard will not be exceeded. It should be noted that the maximum 1-hour concentration is predicted to be the same, with or without the project.

The contributions to ambient air concentrations for the year 2005 are based on the emissions estimated under the 2005 A-Max scenarios defined earlier in Tables 4.5-23 through 4.5-28. The estimated concentrations for the three fossil-fueled plants under these scenarios are shown in Tables 4.5-29, 31, and 32. Nitrogen dioxide concentrations are expected to be less than the 1999 Analytical Maximum scenarios if Regulation 9, Rule 11 applies., but the impacts would be higher if the rule does not apply to the new owner. Sulfur dioxide concentrations are not expected to change significantly and at some plants will decrease. The impacts would therefore be less than significant. PM-10 annual concentrations would not change over the 1999 Baseline and would decrease slightly at the Pittsburg plant because of the shut down of two units. Thus, the impacts are less than significant. For short-term impacts, there would be no change in maximum concentrations, because the maximum short-term operating rates would not change.

Tables 4.5-27 and 4.5-28 show that emissions of criteria air pollutants are not expected to change at the Lake County units, but that emissions would increase at the Sonoma County units. On a local basis, the only criteria air pollutants of concern would be PM-10 and hydrogen sulfide. Based on Table 4.5-28, the increase in PM-10 emissions is estimated to be approximately 36 percent. Such an increase would not result in standard exceedances given the low background concentrations in the project vicinity. To support this conclusion, it is noted that Table 4.5-19 shows that the highest monitored 24-hour PM-10 concentrations in the vicinity over the past five years are approximately 60 percent of the state standard and the highest annual average PM-10 concentrations are approximately 40% of the standard. Further, even if one were to assume that all of the monitored PM-10 were from the Sonoma County units, which is a grossly conservative assumption, a 36 percent increase in PM-10 concentrations would not result in exceedances of either the 24-hour or annual average state PM-10 standards. Thus, the estimated increase in PM-10 would not be significant. The same logic can be used to conclude that the PM-10 impacts associated with the cumulative 2005 A-Max scenario would also be less than significant. The potential effects associated with the estimated increase in hydrogen sulfide emissions are discussed under Impact 4.5-3.

None.

None required.

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The predicted maximum health risk from emissions of carcinogenic substances for Baseline conditions was reported earlier in this section. The maximum reported risk under existing conditions (0.17 in a million) was the result of burning natural gas to power Unit 3 and burning distillate in the combustion turbines (CTs). Since the same fuel types will be burned under 1999 baseline conditions, the risks from exposure to carcinogenic substances will change in proportion to the amount of annual fuel use changes in future years. Both the 1999 A-Max and 2005 Cumulative A-Max show the potential for the plant to increase operations, and those levels are quantified in Chapter 3 and Appendix G of this EIR. Table 4.5-34 summarizes the estimated health risks for the three fossil-fueled plants under existing, 1999 Baseline, 1999 A-Max, and 2005 Cumulative A-Max conditions.

Under the 1999 Baseline conditions, emissions of carcinogenic substances are not expected to change significantly, and the estimated maximum risk would remain at 0.17 in a million. Under divestiture, assuming that the plant operates at its Analytical Maximum capacity, annual fuel use is expected to increase, thus increasing emissions of carcinogenic substances slightly. The estimated risk from additional fuel usage under the 1999 A-Max scenario is expected to increase by 0.06 in a million over 1999 baseline conditions. The total risk in 1999 A-Max is therefore estimated to be 0.23 in a million. Since the total estimated risk is well below the significance threshold of 10 in a million, the health risk from exposure to carcinogenic substances under divestiture would be less than significant. The predicted maximum hazard index for chronic exposure to non-carcinogens is estimated to be less than 0.03, and the estimated acute hazard index would remain the same as for the baseline (less than 0.2 in a million). For chronic and acute exposure to non-carcinogens, the hazard indices would therefore remain well below the significance threshold of 1.0 and would be less than significant.

Table 4.5-34 shows that the maximum incremental health risk from emissions of carcinogenic substances from the plant was estimated to be about 0.03 in a million. Under 1999 Baseline conditions, the estimated risk would be 0.04 in a million. Under divestiture, assuming that the plant operates under its Analytical capacity, the health risk would increase slightly, because of the expected increase in annual fuel use. Both the 1999 A-Max and 2005 Cumulative A-Max show the potential for the plant to increase operations, and those levels are quantified in Chapter 3 and Appendix G of this EIR. The emissions changes would cause the estimated maximum risk to be about 0.05 in a million, which is well below the significance threshold of 10 in a million. Most of the risk is due to exposure to gasoline vapors during the handling of fuel for vehicles, which is not expected to change under divestiture. Thus, the impact is less than significant.

For exposure to non-carcinogenic substances under existing and 1999 Baseline conditions, the hazard indices for chronic and acute exposure were estimated to be 0.01and 0.02, respectively. Because emissions would increase under divestiture, the hazard indices for both chronic and acute exposure would increase slightly to levels less than 0.02, and the hazard index for acute exposure would remain at 0.02. The impacts are less than significant since they are below the significance threshold of 1.0.

Table 4.5-34 shows that the maximum incremental health risk from emissions of carcinogenic substances from the Pittsburg plant under existing conditions is estimated to be 0.1 in a million. Under 1999 baseline conditions, the estimated risk would be 0.13 in a million. Both the 1999

A-Max and 2005 Cumulative A-Max show the potential for the plant to increase operations, and those levels are quantified in Chapter 3 and Appendix G of this EIR. Under the 1999 A-Max scenario, the health risk would increase slightly to 0.17 in a million, which is well below the significance threshold of 10 in a million.

For exposure to non-carcinogenic substances under existing conditions, both the chronic and acute hazard indices at the maximum receptor are estimated to be 0.01. Under 1999 baseline conditions, the hazard indices for chronic and acute exposure were estimated to be 0.02 and 0.01, respectively. Because annual emissions would increase under divestiture, the chronic hazard index would increase slightly to 0.03. The hazard index for acute exposure would remain at 0.01. The impacts are less than significant since they are below the significance threshold of 1.0.

Table 4.5-34 shows that the cancer risks for the three plants will not change significantly under the 2005 Cumulative A-Max scenario. Compared to 1999 Baseline conditions, the cancer risk at the Potrero Plant increases slightly to 0.28 in a million; for Contra Costa the risk stays the same as the 1999 baseline (0.04 in a million); and for the Pittsburg plant, the risks increase slightly over 1999 Baseline to 0.14 in a million. Maximum risks at all three plants remain well below the significance threshold of 10 in a million.

Table 4.5-34 shows that, under the 2005 Cumulative A-Max scenario, the chronic and acute hazard indices remain well below the significance threshold of 1.0 at each of the three plants. These impacts would remain less than significant.

The City and County of San Francisco uses 2015 as an analysis year for evaluating the long-term environmental impacts of cumulative development. The Mission Bay SEIR notes:

Foreseeable development in San Francisco and throughout the Bay Area would contribute to cumulative toxic air contaminant emissions and their resulting risks. Both stationary and mobile sources would contribute to these toxic air contaminant emissions. Only sources that would be relatively close to one another would be likely to directly result in any substantial cumulative exposure and risk because toxic air contaminant concentrations attenuate substantially with distance. However, all toxic air contaminant sources would likely contribute to ambient conditions in the Bay Area (City and County of San Francisco, 1998).

Power plant emissions of toxic air contaminants contribute incrementally to risks in the immediate vicinity of the power plants and to overall ambient risks in the Bay Area. However, as described above, the facility-specific (as opposed to overall ambient) risks from the power plants would be less than significant. By 2015, cumulative ROG emissions from power plants would be higher than in 2005 due to cumulative increases in load demand, and formaldehyde and benzene emissions would increase in rough proportion to the increase in ROG emissions. However, in the vicinities of the power plants evaluated in this report, this cumulative increase would not result in significant local effects given the extent to which the calculated risks would be below the applicable significance criteria.

With respect to the cumulative contribution to overall ambient risk from toxic air contaminants in the Bay Area (from all sources, including mobile and stationary), the Mission Bay SEIR notes that no authoritative regulatory body has adopted any standard to determine whether the risks posed by existing levels of toxic air contaminants should be considered acceptable and, in turn, whether possible increases in ambient risks could potentially be considered significant. The Mission Bay SEIR declines from adopting a significance criterion and, instead, assumes that the cumulative impact on ambient concentrations of toxic air contaminants would be significant since the project-specific impact would be significant. Based on the converse to that concept, the contribution of divestiture to overall cumulative ambient risk would be less than significant because the project-specific impact would be less than significant.

The principal health risk that could be experienced from plant operations under the 1999 A-Max scenario would be the potential for increased acute exposure to toxic hydrogen sulfide emissions. For the Lake County units, emissions of hydrogen sulfide are estimated to remain the same (see Table 4.5-27) under the 1999 A-Max scenario as compared with the 1999 Baseline, while the corresponding emissions at the Sonoma County units are estimated to increase by approximately 40 percent (see Table 4.5-28). However, this increase in hydrogen sulfide emissions would not be expected to result in a significant increase in health risk or nuisance odor complaints since the two phenomena are essentially independent of one another. This is because the peaks in hydrogen sulfide concentrations (and ensuing complaints) that have occurred in the past have been the result of uncontrolled releases of steam due to events like steam stacking rather than from the steady-state, "controlled" emissions released at the power plants. As discussed in the setting section, an automated pipe manifold system has been installed, and this system has significantly reduced the incidents of steam stacking. Since the project would not affect operation of the manifold system, the project would not have a significant effect on the local health risks or the potential for nuisance odor complaints that are associated with steam stacking and related uncontrolled releases of steam.

None.

None required.

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While PG&E does not maintain FTP programs at the Potrero power plant, the company addresses claims on an as-needed basis. As shown on Figure 4.5-2, unlike the winds at Contra Costa and Pittsburg (see Figures 4.5-3, -4), the winds at Potrero exhibit strong west-southwesterly directional predominance a substantial portion of the time, on a yearly basis. This directional preference in local wind direction should tend to cause FTP resulting from Potrero to be deposited downwind of the plant, out over San Francisco Bay. This same directional preference further makes it unlikely that the China Basin would be impacted. As there is no established, ongoing cleanup program for the Potrero plant, the potential impact would be less than significant. Furthermore, BAAQMD Reg. 1-301 provides potential relief to affected parties, as would a civil claim for nuisance damages.

PG&E’s current FTP cleanup programs are not mandated by any specific rule or regulation. With the project, a new owner would not be obligated to continue these FTP cleanup programs as currently implemented by PG&E. As is discussed elsewhere in this report, a new owner may have the tendency to operate these plants more than PG&E. Such increased operations could potentially increase either the amount or frequency of FTP locally deposited, although by how much or how much more often would be difficult to determine. Increased operations may in fact actually decrease FTP releases, as they generally occur during plant start-up. While BAAQMD Reg. 1-301 provides potential relief to affected parties, as would a civil claim for nuisance damages, the loss of any program to address FTP could still represent a negative, but less-than-significant, impact.

Because there are no combustion sources used in the process that can generate acidic particles at the Geysers, no measurable impact from FTP is expected. Therefore, the project would have a less than significant impact.

None.

Mitigation Measure 4.5-4: PG&E will provide the buyers of the Pittsburg and Contra Costa power plants with a summary of the history of FTP emissions and claims involving these plants, and information regarding PG&E’s procedures for inspecting and cleaning the boilers and stacks at these two plants to minimize FTP. The buyers of the Pittsburg and Contra Costa power plants will develop procedures for minimizing FTP emissions in future operations, and institute a program for processing FTP claims that includes, at a minimum, a point of contact for claimants and procedures for expeditiously verifying and processing claims. PG&E shall not be required to disclose attorney-client work product information to enable the buyers to satisfy this condition.

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The potential for inconsistency relates to the Bay Area fossil-fueled power plants but not to the Geysers plant because the Bay Area is the subject of regional air quality plans, whereas no such plans have been required for Lake County or northern Sonoma County.

A series of air quality plans has been developed for the San Francisco Bay Area to address non-attainment of national and state ambient air quality standards. The two applicable air quality plans are the ’97 Clean Air Plan, which was developed to address the non-attainment status relative to the state ambient ozone standard, and the Ozone Maintenance Plan, which was developed to address the "maintenance" status (i.e., of a former non-attainment area) for the national ambient ozone standard. The latter plan, the Ozone Maintenance Plan, is subject to revision due to EPA’s recent announcement of a final decision to re-designate the Bay Area back to "non-attainment" for the national one-hour ozone standard.

The potential inconsistency of the project with these plans can be described qualitatively in relation to control measures adopted as part of these plans. Under the California Clean Air Act, the ’97 Clean Air Plan is required to include control measures that will require certain types of major stationary sources to implement Best Available Retrofit Control Technology (BARCT). The boilers included in this project are among the types of sources for which BARCT is required. If the BAAQMD declines to modify Regulation 9, Rule 11, which is the rule that requires BARCT to be installed at the boilers, then the project could be characterized as being inconsistent with the ’97 Clean Air Plan. The potential inconsistency with a specific control measure included in the ’97 Clean Air Plan would be a significant effect of the project.

The potential inconsistency of the project with these plans can also be described quantitatively in relation to the emissions projections included in these plans. The ’97 Clean Air Plan contains emissions estimates and projections for power plants. These emissions estimates were made with certain assumptions concerning electricity generation and with certain assumptions about the effectiveness of BAAQMD Regulation 9, Rule 11. Neither set of assumptions (electricity generation and Regulation 9, Rule 11) may prove accurate.

The principal reason for the difference in power plant emissions estimates is the difference in Bay Area electric power generation projections from which the emissions estimates are derived. For example, the electric power generation projections developed by using a model known as

UPLAN (and used for the ’97 Clean Air Plan power plant emissions estimates) predict electric power generation in 2000 from the steam turbines of 8,536 GWh. In contrast, the electric power generation modeling prepared for this report predicts Bay Area generation that is interpolated to

be between 9,724 GWh (baseline) and 18,534 (A-Max) in 2000 (not including the combustion turbines). (10) Likewise, in 2003, the ’97 Clean Air Plan predicts a generation rate of 8,734 GWh whereas the modeling results for this report provides the basis for a prediction of a generation rate of between 11,964 to 18,732 GWh (not including the existing combustion turbines, but including a future 480 MW power plant assumed to replace the Hunters Point Power Plant).

None.

REFERENCES – Air Quality