AIR QUALITY
Where available, the significance criteria established by the applicable air quality management or air pollution control district may be relied upon to make the following determinations.

Would the project have:	Potentially Significant Impact	Less-Than-Significant With Mitigation Incorporate	Less-Than-Significant Impact	No Impact
a) Conflict with or obstruct implementation of the applicable air quality plan?	.	.	.	x
b) Violate any air quality standard or contribute substantially to an existing or projected air quality violation?	.	.	.	x
c) Result in a cumulatively considerable net increase of any criteria pollutant for which the project region is non-attainment under an applicable federal or state ambient air quality standard (including releasing emissions which exceed quantitative thresholds for ozone precursors)?	.	.	.	x
d) Expose sensitive receptors to substantial pollutant concentrations?	.	.	.	x
e) Create objectionable odors affecting a substantial number of people?	.	.	.	x

ENVIRONMENTAL SETTING
Coal-fired power plants contribute air pollutants to the atmosphere; therefore, they are subject to rigorous environmental regulations and requirements. The description of the environmental setting is organized as follows:
• Federal, state, and local regulatory framework governing air emissions,
• Air quality standards,
• Local measurements of certain criteria pollutants (nitrogen dioxide [NO2], sulfur dioxide [SO2], and fine particulates [PM10]), and other air quality issues of concern,
• Permitted and actual plant air emissions.

Regulatory Framework
The MGS is located in Clark County, Nevada. Pursuant to the statutes of the State of Nevada, generating stations that produce electricity from fossil fuel fired steam boilers, including the MGS, are regulated by the Nevada Division of Environmental Protection’s Bureau of Air Quality (BAQ). The Clark County Health District’s Air Pollution Control Division (APCD) has jurisdiction over all other sources within the county. As a result, the MGS has air quality operating permits issued by the BAQ for its boilers and auxiliary equipment.

The State of Nevada is responsible for protecting air quality through the monitoring and regulations of its three air pollution control agencies. The BAQ has been delegated authority to administer the majority of programs under the Clean Air Act by the U.S. Environmental Protection Agency (USEPA) for those areas and sources under its jurisdiction. Its duties include air quality monitoring, permitting, and enforcement.

The USEPA has the responsibility for enforcing, on a national basis, the requirements of the country’s air pollution laws. Nevada is under the jurisdiction of USEPA Region IX, with offices in San Francisco. USEPA’s responsibility in the State air pollution control programs focuses principally on reviewing submittals for the State Implementation Plan (SIP). The SIP is required by the 1990 Federal Clean Air Act to demonstrate how all areas of the state will meet national ambient air quality standards (NAAQS) within the federally-specified deadlines (42 USC §§7409,7411). The USEPA Region IX also directly administers the Acid Rain (Title IV) and Stratospheric Ozone (Title VI) programs of the Clean Air Act.
The BAQ regulates emissions from electric utility boilers through the issuance of a Class I Air Quality Operating Permit in compliance with the Nevada Administrative Code (Sections 445B.001 through 445B.395). The BAQ is currently in the process of transitioning from its previous permitting system to the Class I system, consistent with the requirements of Title V of the Clean Air Act. The station now operates under individual state permits for each of its major pieces of equipment. These permits do not list all federal emission limitations and requirements applicable to the facility, e.g., those required under the Acid Rain provisions (Title IV) of the Clean Air Act. When the new Class I permit is issued, it will clearly list both state and federal requirements, include ancillary equipment in addition to currently permitted equipment, and contain monitoring and record keeping requirements sufficient to ensure compliance.

Two contractors, Flyash Haulers and Boral Mineral Technologies, also own, maintain and operate equipment on plant premises that is subject to air quality permitting. Contractor equipment used in direct support of plant operations will be listed on the MGS’s Title V permit as required by EPA, even though this equipment does not belong to the facility. Contractor equipment used only to support these contractors’ separate operations will continue to be independently permitted by the contractors through the Clark County Health District (CCHD).

The main boilers at the MGS are restricted to emissions of oxides of nitrogen (NOx) less than 0.45 pounds per million British thermal units (lb/mmbtu) on an annual average, emissions of oxides of sulfur (SOx) less than 1.2 lb/mmbtu, and emissions of PM10 less than approximately 0.1 lb/mmbtu . Auxiliary Boiler #1 is limited to PM10 emissions of less than approxi-mately 0.29 lb/mmbtu. Auxiliary Boiler #2 is limited to PM10 emissions of less than approximately 0.1 lb/mmbtu, NOx emissions less than 0.2 lb/mmbtu, and SOx emissions less than 0.4 lb/mmbtu. In addition, Auxiliary Boilers 1 and 2 are jointly restricted to less than 40 tons per year (tpy) of NOx emissions combined.

State regulation (Nevada Administrative Code [NAC] 445B.287) prohibits the direct transfer of permits upon change in ownership of a facility. Therefore, a new owner would be required to obtain a new permit(s) from the BAQ. However, a new owner may apply for an administrative amendment under NAC 445B.319 to reissue the existing permits in the new owner’s name for their remaining term. If this application is approved, the permit will not be reopened and no substantive changes will be made. In no event will the application for an administrative transfer of ownership result in a relaxation of the conditions included in the original permit.

AIR QUALITY ISSUES

Air Quality Conditions for Criteria Pollutants
The USEPA has established National Ambient Air Quality Standards (NAAQS) for ozone (O3), nitrogen dioxide (NO2), carbon monoxide (CO), sulfur dioxide (SO2), particulate matter <10 microns in diameter (PM10), particulate matter <2.5 microns in diameter (PM2.5), and airborne lead (Pb). An area where the NAAQS for a pollutant is exceeded can be designated as a non-attainment area, subject to planning and pollution control requirements that are more stringent than those areas which attain the NAAQS.

NAAQS 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 potential 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., 1 hour), or to a relatively low average concentration over a longer period (e.g., 8 hours, 24 hours). For some pollutants, there is more than one air quality standard, reflecting both its short-term and long-term effects.

Clark County’s Las Vegas Valley has been designated as a non-attainment area for both CO and PM10. However, because the MGS is located in the town of Laughlin, approximately 100 miles to the south, it is part of the Colorado River Valley and is not part of the Las Vegas non-attainment area. Air quality in the town of Laughlin has historically been better than national standards. The Clark County Health District maintains an air quality monitoring network within the Las Vegas Valley metropolitan area. SCE has maintained a monitoring network in and around the Colorado River Valley since 1969. Table 4.3-1 presents the NAAQS and measured levels of selected pollutants from SCE’s Colorado River Valley Network.

Table 4.3-1: National Ambient Air Quality Standards

Pollutant	Averaging Time	NAAQS	Colorado River Valley Levels 1997	Laughlin, NV Attainment Status
Ozone	8 hours	0.08 ppmv	Not Monitored	TBD2
Carbon Monoxide	8 hours	9 ppmv	Not Monitored	Unclassifiable/ Attainment
.	1 hour	35 ppmv	.	.
Nitrogen Dioxide	Annual Average	100 µg/m3 (0.053 ppmv)	17.8 µg/m3	Unclassifiable/ Attainment
Sulfur Dioxide	Annual Average	80 µg/m3 (0.03 ppmv)	5.3 µg/m3	Attainment
.	24 hours	365 µg/m3(0.14 ppmv)	28.8 µg/m3	.
.	3 hours	1,300 µg/m3 (0.5 ppmv)	144 µg/m3	.
PM10 - Fine Particulate Matter (<10 Micron)	24 hours	150 µg/m3	51 µg/m3	Unclassifiable
.	Annual Geometric Mean	50 µg/m3	21 µg/m3	.
PM2.5 - Fine Particulate Matter (<2.5 micron)	24 hours	65 µg/m3	Not Monitored	TBD
.	Annual Average	15 µg/m3	.	.
Lead	Calendar Quarter	1.5 µg/m3	Not Monitored	Attainment

SOURCE: SCE 1999

Ozone. Ozone (O3) is an end product of complex reactions between reactive organic gases (ROG) or non-methane hydrocarbons (NMHC) and NOx in the presence of intense ultraviolet radiation. ROG and NOx emissions from both mobile and stationary sources, in combina-tion with daytime wind flow patterns, mountain barriers, a persistent temperature inversion, and intense sunlight, can result in high O3 concentrations. O3 is a powerful oxidant in the form of photochemical smog. A new, more stringent 8-hour ozone standard was adopted by the USEPA in 1997, replacing the previous 1-hour standard.

Nitrogen Dioxide. Nitrogen dioxide (NO2) is formed in the atmosphere primarily from a reaction between nitric oxide (NO) and oxygen (O2). NOx, which include both NO and NO2, are formed during high-temperature combustion processes when N2 and O2 in the combustion air combine. Although NO is much less harmful than NO2, it can be converted to NO2 in the atmosphere within a matter of hours, or even minutes under certain conditions. NO2 is an O3 precursor as well as a reddish-brown gas, that gives smog its characteristic color and can cause a visible plume. Colorado River Valley levels of NO2 have historically been significantly lower than national standards.

Carbon Monoxide. Carbon monoxide (CO) is a product of inefficient combustion, principally from small internal combustion engines such as those found in automobiles and other mobile sources of pollution. The highest levels of CO are typically recorded during evening hours from November through January. Winter inversions, which also occur during this time, trap cool air under a layer of warm air, allowing pollutants to build to unhealthy levels. CO levels in Las Vegas have declined since 1976 despite an increase in vehicle miles traveled. This decrease is attributed to cleaner cars, better traffic control, and Clark County Health District’s wintertime oxygenated gasoline program.

Sulfur Dioxide. Sulfur dioxide (SO2) is produced when any sulfur-containing fuel is burned. It is also emitted by facilities that treat or refine sulfur or sulfur-containing chemicals. Peak concentrations of SO2 occur at different times of the year in different parts of the state, depending on local fuel characteristics, weather, and topography. Clark County, the Laughlin area, and the State of Nevada have attained the federal SO2 standards.

Fine Particulate Matter. Particulate matter (PM) in the air is composed of a combination of wind-blown dust; particles directly emitted by combustion sources (e.g., soot); particles directly emitted by other sources (e.g., auto tires, carbon-black plants, etc.); and organic, sulfate, and nitrate aerosols formed in the air from emitted hydrocarbons, SOx, and NOx. In 1987, the USEPA replaced its total suspended particulate (TSP) NAAQS with a new NAAQS for PM10 (particulate matter <10 microns in size), since they believed that PM10 best reflected the size range of inhalable particles related to human health effects. In 1997, the USEPA adopted a new NAAQS for particles less than 2.5 microns in size (PM2.5), owing to more recent scientific data indicating possible adverse health impacts from ambient particles in this smaller size range.

With the exception of a few events due to wind storms and local construction activities, PM10 values within the Colorado River Valley have not been measured in excess of ambient standards. Ambient monitoring data addressing the new standard (PM2.5) is not currently available. Particulate emissions from the MGS have been found to contribute less than 1% of particulates measured in the local ambient air.

Other Air Quality Issues

Hazardous Air Pollutants (HAPs). A substance is considered hazardous (toxic) if it has the potential to cause or contribute to an increase in mortality or an increase in serious illness, or if it may pose a present or potential hazard to human health. Title III of the Federal Clean Air Act Amendments of 1990 identifies 189 hazardous air pollutants.

Control of toxic air emissions is implemented under Section 112 (Hazardous Air Pollutants) of the 1990 Federal Clean Air Act Amendments. There are currently no HAP regulations adopted under this section which affect the steam boilers at the MGS. However, in 1998, the USEPA required that all coal-fired utility electric steam generating units greater than 25 MW sample, analyze, and report the mercury content of their coal during calendar year 1999. This information will be used by the USEPA Administrator to determine whether it is appropriate and necessary to regulate HAP emissions from utility boilers in the future. SCE is complying with this data request.

Plume Opacity. The MGS particulate emissions are currently reduced on the outlets of Units 1 and 2 by means of ESPs. An ESP is a particle control device that uses electrical forces to move particles out of a flowing gas stream and onto collector plates. During normal operation, the MGS ESP performance averages 99% removal efficiency and produces emissions well below state and federal particulate limits.

The MGS plume is darker than plants with comparable particulate emissions because its slurry system produces a very fine ash that causes a higher than average scattering of light. In 1992, the state of Nevada responded to local citizen complaints by lowering the MGS’s existing 40%, in-duct, 1-hour average opacity limit to a 30%, in-stack, 6-minute average limit. Particulate limits remained unchanged. The effectiveness of the new opacity standard in addressing citizen’s aesthetic concerns was reviewed at a public hearing in December, 1995. At that time, no adverse comment on the plant’s opacity was received, and the existing standard was upheld. All other plant equipment is currently limited by state law to opacity less than 20%.

Opacity is monitored on Units 1 and 2 by an optical density meter installed on the common stack. At times, meeting the 30% opacity limit leads to reduced generation at the facility.

Fugitive Dust. In response to local citizen concerns regarding fugitive dust emissions, the state of Nevada mandated an SCE-sponsored study to ascertain the relative contribution of power plant operations to dry deposition in the area. The 1994 Mohave Power Project Fugitive Emissions Study consisted of source identification, emissions inventories, particle size and chemical characterizations, and proposed mitigation measures (SCE 1999). The study concluded that, "Compared to the level of fugitive emissions which could be expected from a typical well controlled coal-fired power plant, emissions from MPP are low." These low emissions were attributed to the MGS’s slurry system, which eliminates a significant number of potential fugitive dust sources. As a result of the study, additional control measures were adopted at the station to address local concerns.

Grand Canyon Trust, Inc./Sierra Club, Inc. Lawsuit
On February 19, 1998, the Grand Canyon Trust, Inc., and the Sierra Club, Inc., filed suit in the Federal District Court of Nevada against the owners and operators of the MGS alleging violations of various air quality emissions limitations pertaining to SO2 and opacity. The National Parks and Conservation Association has since joined the plaintiffs’ in the suit.

The consent decree has been entered and served by the Federal District Court of Nevada. The Consent Decree provides for the installation of a dry scrubber and bag house by specified deadlines, provided the plant continues to operate. Key provisions of the proposed consent decree are summarized below.

Installation of Controls. If the MGS continues to operate, the plant’s two generating units must have control equipment installed sufficient to meet the following opacity and SO2 limits: (a) a 20% opacity limit; and (b) SO2 emission limits of (1) 0.15 pounds per million Btu measured on a 365 boiler operating day rolling average basis and (2) an 85% reduction efficiency measured on a 90 boiler operating day rolling average basis.

Timing of Controls. Unless 100% of the four current owners’ ownership interests in the MGS are sold prior to December 30, 2002, one of the following two scenarios must occur: (a) the owners may operate the plant until December 31, 2005, and then shut down the plant without having installed controls and without incurring penalties; or (b) controls meeting the requirements summarized above must be installed and operational by January 1, 2006, for the first controlled unit, and by April 1, 2006, for the second controlled unit. However, if 100% of the current owners’ ownership interests in the MGS are sold prior to December 30, 2002, then the deadlines for installing controls accelerate for the first unit to the date 36 months from the closing of the last owner’s interest sold and, for the second unit, to the date 39 months from such closing date.

Penalties. The consent decree does not impose any penalties for the plant’s past or current operations. The consent decree does provide, under certain circumstances, for stipulated penalties if, in the future, the terms of the consent decree are not carried out.

Interim Limits. The decree imposes certain interim limits for opacity and SO2 based on the current operating conditions. The interim limits do not require the installation of control equipment.

Control Equipment. If the station continues to operate, the proposed consent decree contemplates the installation of the following control equipment: (a) for opacity control, polishing bag houses described as fabric filter dust collectors; and (b) for SO2 control, a dry scrubber system using lime spray dryer technology.

Visibility Issues
Visibility refers generally to the property of atmospheric clarity and is typically measured as the distance one can see at a particular location and time. The absorption and scattering of light by both gases and particles in the atmosphere restricts visibility. Visibility is affected by three factors: Rayleigh scattering, natural impairment, and man-made impairment. Rayleigh scattering is the scattering of sunlight by nitrogen and oxygen molecules that naturally occur in the atmosphere. Natural impairment is caused by sources such as volcanoes, wind-blown dust, wildfires, trees and plants. Man-made impairment is caused by sources such as industrial and vehicle emissions, wood burning, agriculture, prescribed fires, and road dust.

In 1977, Congress set as a national goal the prevention of any future, and the remedying of any existing, man-made visibility impairment at national parks and wilderness areas across the United States . Sections 169A & B of the Clean Air Act implement this goal for existing sources. In 1980, the USEPA issued plume blight regulations that address individual point sources that contribute to "reasonably attributable" visibility impairment. In 1999, the USEPA proposed regional haze regulations which address visibility impairment from multiple sources over large regional areas.

On June 17, 1999, the USEPA published in the Federal Register an Advanced Notice of Proposed Rulemaking (ANPR) which requested all interested parties to submit to USEPA any and all information concerning two questions: (1) is the visibility impairment observed at the Grand Canyon "reasonably attributable" to the MGS?; and (2) if so, what would the "best available retrofit technology" (BART) be for the MGS? That ANPR requested all comments by August 16, 1999. Thereafter, USEPA twice extended the comment deadline, so the comment deadline was October 21, 1999.

SCE and the plaintiffs in the Grand Canyon Trust, Inc./Sierra Club Inc. lawsuit discussed above agreed to submit comments to USEPA prior to the comment deadline. The plaintiffs and defendants will urge USEPA to adopt the terms of the consent decree as a USEPA rule. USEPA retains its authority to adopt rules that are necessary and appropriate to carry out USEPA’s statutory responsibilities.

Existing Air Emissions from the MGS
The MGS serves as essentially a base-loaded facility. Accordingly, its overall air emissions profile remains fairly constant over time. This section presents air emissions data obtained from existing documentation made available by SCE, other references, and general literature. The primary information sources for emissions quantities are the BAQ’s draft technical evaluation of SCE’s Title V Permit Application, existing state permits, the Mohave Power Project Fugitive Emissions Study, the Allowance Tracking System report, and SCE’s annual emissions reports. Permitted levels are described first, followed by emissions data from 1995 through 1997.

Regulatory Limits to Air Emissions. The MGS has emission limits under both state and federal air regulations. Table 4.3-2 summarizes applicable emission limits for all major equipment. Only the most stringent applicable limit is listed. Table 4.3-3 summarizes the Federal Operating Permit Program’s (Title V) maximum potential to emit (PTE) for the facility. In characterizing actual emissions, the percentage of a unit’s PTE is frequently used for comparison.

Actual Emissions. The MGS contains the following major air emissions sources:
• Steam Generator Units 1 and 2
• Auxiliary Boilers 1 and 2
• Ancillary Equipment and Operations

Actual air emissions from each of these sources are characterized in the following sections.

Table 4.3-2: Applicable Emission Limits - Major Equipment

Permitted Equipment	PM10	SO2	NOX	Opacity
Unit 1	0.1 lb/mmbtu	1.2 lb/mmbtu	0.45 lb/mmbtu	30%, 6-min
Unit 2	0.1 lb/mmbtu	1.2 lb/mmbtu	0.45 lb/mmbtu	30%, 6-min
Auxiliary Boiler 1	0.29 lb/mmbtu	NA	40 tpy2	20%, 3-min
Auxiliary Boiler 2	0.1 lb/mmbtu	0.4 lb/mmbtu	40 tpy 0.2 lb/mmbtu	20%, 3-min
West Lime Storage Silo	19.18 lbs/hr	NA	NA	20%, 3-min
East Lime Storage Silo	1.62 lbs/hr	NA	NA	20%, 3-min
Fly Ash Storage Silo	48.82 lbs/hr	NA	NA	20%, 3-min
Soda Ash Storage Silos	25.16 lbs/hr	NA	NA	20%, 3-min
Coal Handling System	Fugitive3	NA	NA	NA
Ash Disposal Site	Fugitive	NA	NA	NA

SOURCE: SCE 1999

tpy = tons per year
lb/mmbtu = pounds per million British thermal units
lbs/hr = pounds per hour NA = no applicable limit

1 These particulate limits vary slightly based on heat input.
See formulas in NAC 445B.362© and NAC 445B.363(2) and (3).
2 Joint limit for Auxiliary Boilers 1 and 2.
3 Must apply "best practical methods" to control fugitive dust emission

Table 4.3-3: Federal Title V Potential to Emit - Entire Facility

Pollutant	Pounds per Hour	Tons per Year
PM10	1,793	7,858
SO2	20,256	88,731
CO	749	4,450
NOX	16,994	39,453
VOC	56	316
Lead	0.4	2
HAPs1	1,080	4,733

SOURCE: SCE 1999 1 Main and auxiliary boilers only

Table 4.3-4: Actual Emissions Over Three Years (1995-1997) - Units 1 and 2

Pollutant	1995 (tpy)	1996 (tpy)	1997 (tpy)
PM10	4,294	4,530	2,607
SO2	42,980	40,524	41,354
CO	1,452	1,395	1,369
NOX	23,095	22,040	20,563
ROG1	166	161	159
Lead	0.99	0.97	0.95

SOURCE: SCE 1999 tpy = tons per year
1 Emissions were calculated using an emission factor for ROGs. This is similar but not identical to VOC emissions.

Steam Generator Units 1 and 2. The two main steam generators (boilers) are the principal source of air emissions from the MGS. Table 4.3-4 summarizes actual air emissions (1995-1997) from these units. Each boiler is rated at 8,439 million Btu per hour. At maximum output, each boiler consumes up to 380 tons per hour of coal and generates 5.45 million pounds per hour of superheated steam at 3,627 pounds per square inch gauge (psig) and 1,008°F, and 4.65 million pounds per hour of reheated steam at 629 psig and 1,003°F. This
steam is expanded in three stages in two separate turbine generators per unit to yield a total of 1.06 million horsepower and 790 MW of electrical power.

Combustion by-products emitted from the 500-foot stack include PM10/PM2.5, SO2, CO2, CO, NOX, volatile organic compounds (VOC), Pb, and various HAPs. Emissions of PM10 are reduced by 99% by ESPs on the outlet of each boiler. SO2 is reduced by the use of low-sulfur coal. NOX emissions are reduced through combustion optimization utilizing both tangential-fired and over-fired air techniques. Emissions in the flue gas are measured by a CEM on each unit, as required by federal regulation (40 CFR 75). Each CEM measures SO2, NOx, and CO2 concentrations, stack flow rate, and gas temperature. Quarterly emissions reports are telemetered to the USEPA's Acid Rain Division server in Washington, D.C. PM10 emissions are measured by an annual source test.

The PM10 emission rate from Units 1 and 2 is limited by state regulation to less than 0.1 lb/mmbtu and emissions are required to be controlled by the means of electrostatic precipitators. The PM10 emission rate of all other major equipment is similarly limited by state regulation. In addition, fugitive dust emissions from all operations are required to be controlled using the best practical methods.

Emission of SO2 and other SOX are regulated under Title IV of the Clean Air Act Amendments of 1990. The cornerstone of the Title IV regulatory mechanism is 40 CFR 73 (Sulfur Dioxide Allowance System). The allowance tracking system assigns each generating unit with Phase I or II applicability an annual allotment of SO2 credits, which reduce through time. Each unit must hold sufficient credits to cover its SO2 emissions every year. Credits can be bought or sold on the open market, thereby creating an incentive to reduce emissions. Total credits are fixed, thereby limiting SO2 emissions nationwide under a cap of 1.2 lb/mmbtu. Actual SO2 emissions from the MGS average approximately 80% of the Title IV allowance, consistent with the 70 to 75% annual plant utilization during recent years. Although federal or state law does not limit total mass SO2 emissions from Units 1 and 2, state law limits the SO2 emission rate to less than 1.2 lb/mmbtu.
Total mass emissions of NO2 from Units 1 and 2 are not specifically limited by permit condition, either federally or locally. However, the NOx emission rate of Units 1 and 2 is limited to 0.45 pounds per million BTU (annual average) by 40 CFR 76.8 under the early election provisions for Group 1, Phase II boilers.

For the period 1995-1997, actual PM10 emissions averaged 51% of PTE, SO2 emissions averaged 47% of PTE, and NOx emissions averaged 66% of PTE.

Auxiliary Boilers 1 and 2
Auxiliary Boilers 1 and 2 are used to start the main boilers following a cold-iron shutdown. Steam from the auxiliary boilers is used to drive the high-pressure boiler feedwater pumps and other auxiliaries which are powered by steam turbines until sufficient steam is available from the main boilers to power the auxiliary turbines. Annual mass emissions are low because the auxiliary boilers are operated only a few days during the
year and run on natural gas. Combined emissions of NOX from both auxiliary boilers are limited by permit condition to 40 tpy. There is also a 20% opacity limit on each auxiliary boiler. This effectively limits operating time to less than 3,000 hours per year for both auxiliary boilers.

Auxiliary Boiler 1 is rated at 236 million Btu per hour and consumes 225,000 cubic feet per hour of natural gas at maximum load. Auxiliary Boiler 2 is rated at 350 million Btu per hour and consumes 333,000 cubic feet per hour of natural gas at maximum load. Combustion byproducts emitted from the auxiliaries include PM2.5/PM10, SO2, CO2, CO, NOX, VOC, and various HAPs.

A comparison of actual versus potential emissions from Auxiliary Boilers 1 and 2 shows that for the period 1995-1997, actual PM10 emissions averaged 2% of PTE and NOX emissions averaged 5% of PTE for these units.

Ancillary Equipment and Operations
Other minor emissions sources at the MGS include:
• Cooling towers: PM2.5 and PM10
• Abrasive blasting room: PM2.5 and PM10
• Paint booths: VOCs
• Gasoline storage tanks: VOCs
• Dry materials handling (lime, ash, coal): PM2.5 and PM10

The MGS is not currently required to maintain emissions data for the majority of its smaller sources. Once the Title V permit is issued, however, these emissions will be tracked.

ENVIRONMENTAL IMPACTS
Sale of the MGS
a), b), c), d), e) The sale of the MGS would not in and of itself, result in physical changes and therefore would not result in impacts to air quality.

The following air quality-related issues are of interest in the case of a change of ownership. The first issue was discussed in the regulatory setting where it was noted that state regulations prohibit the transfer of permits upon change of ownership. SCE will remain as the operator for two years, possibly eliminating the necessity to apply for a transfer of permits. Upon a 100% sale, the new owner would apply for a reissuance of permits under the change of ownership provisions of the regulations. If this application is approved, no changes in air permit conditions or other applicable requirements would occur. Under no circumstances would the application for an administrative transfer of ownership result in a relaxation of the conditions included in the original permit. Therefore, no significant changes in air emissions would occur as a result of the transfer of ownership of the permits.

The second issue is that beginning January 1, 2000, the plant owner is required to obtain SO2 allowances adequate to offset the SO2 emissions from the MGS on an annual basis. SCE intends to auction its share of SO2 allowances related to the MGS along with the generating station.

Construction of 500 feet of Fence
a), b), c), d), e) Small scale structural additions, such as the addition of 500 feet of fencing, are not expected to impact air quality. The fence itself will not pollute into the atmosphere, due to its nature. The construction would require the use of some gas powered equipment and vehicles, but the duration of construction is brief (less than two weeks), the equipment will run for short periods of time, and the vehicles would have emission controls.

Continued Existing Operations
a), b), c), d), e) There will be no change in air emissions from current conditions.

Increased Plant Output by Approximately 10%
a), b), c) Increased electrical generation would create increased air pollution emissions compared to existing conditions. However, existing emissions are considerably less than those allowed under current MGS air permits. Permits are based upon the "potential to emit" (PTE). PTE is calculated assuming 100% load for 365 days per year. A variety of factors limit the ability to achieve the theoretical PTE level, including scheduled outages, non-scheduled outages, plume opacity, and condenser water temperature.

The existing capacity factor (annual generation/1580 MW/8760 hours/year) is nearly 70%. An increase of 10% of current generation through equipment modification, fuel variation, or delayed or altered major maintenance practices would increase emissions by approximately 10% over their current levels since the combustion and pollution control technologies would not be substantially altered. If installation of the mandated control system enhancements were to occur sooner than currently anticipated, then emissions of some pollutants could decline even though plant output is increased.

Table 4.3-5 shows the average annual electrical generation and associated air pollution emissions for 1995-97. All emissions are at or below the efficiency limits required by project permits. Combustion efficiency is adequate to allow an increase in annual generation, but the slurried coal contains a large fraction of fine material that escapes the control system and creates a smoky plume. With more stringent limits on smoke darkness (opacity), the opacity limits are the largest factor leading to generation constraint.

The most plausible scenario for increasing production is to accelerate the construction of scrubbers for SO2 removal, and for fabric bag houses that remove particulates more efficiently than existing electrostatic precipitators. The installation of a scrubber and bag house would be beneficial to the air quality by reducing sulfur dioxide and smoke-and dust-causing particles from plant emissions. Bag houses would remove at least one-third of all residual particulate matter. Scrubbers would reduce current SO2 emission levels by 85%, and a 66% reduction in PM-10 would occur from scrubber and bag house installation. The change in annual emissions, from the addition of a scrubber and bag house, for the same capacity factor experienced between 1995 through 1997 is presented in Table 4-3.7.

The emissions resulting from a 10% generation/emissions increase without major equipment changes (likely not feasible) for more than a year when maintenance needs are expected to reduce generation, as well as the net new emissions resulting from the possible accelerated control system installation, are shown in Table 4.3-6. A 10% increase in generation would still allow the MGS to remain well within its air pollution permit emission limits. There are no absolute standards that would characterize a substantial change in emissions from existing levels. In an attainment/maintenance area, annual emissions increases of 100 tons per year or less (50 tons/year for ROG) are considered de minimis changes in terms of Clean Air Act conformity. Potentially substantial increases in CO and NOx are offset by substantial reductions in PM10 and SO2.

Because PM10 and SO2 are more directly related to visibility as a critical issue in scenic resources of the southwestern United States, the net benefit would likely outweigh any impacts associated with increased CO and NOx. An increased generation capacity factor would create substantial additional emissions unless accompanied by an improvement in air pollution controls. Because it is unlikely that the capacity factor can be measurably increased for long periods of time without such installation, the proposed divestiture action and any associated operational changes are unlikely to engender any substantial increases in air pollution emissions. All emissions would be within permitted limits.

d) As discussed in the previous section, proposed operational changes are unlikely to create substantial increases in air pollution emissions. Therefore it is unlikely that sensitive receptors would be impacted by the potential increased air pollution.

e) The MGS does not currently create objectionable odors affecting numerous people. There is no evidence to suggest that increasing the facility’s capacity would cause strong odors.

MITIGATION MEASURES
None required.

Table 4.3-5: Annual Average MGS Electrical Generation and Stack Exhaust Emissions

Annual	1995	1996	1997	3-Yr.Avg.	Permit Limit
MW-HR	10,020,000	9,666,000	9,567,000	9,750,000	13,651,000
Emissions (lb/MW-HR):	.	.	.	.	.
PM10	0.857	0.937	0.545(1)	0.897	1.068
SO2	8.581	8.385	8.645	8.537	12.819
CO	0.290	0.289	0.286	0.288	0.446
NOx	4.611	4.560	4.299	4.490	4.806
ROG	0.033	0.033	0.033	0.033	0.033
(1) Inconsistent with other data, ignored in average.
Table 4.3-6: Annual Air Pollution Emissions -Possible MGS Operational Modifications
	1995-97	w/+10%	Potential	w/Scrubber/	Net
Pollutant	Base	Increase	to Emit	BagHouse	Change
PM10	4,368	4,805	7,858	3,203	-1,165
SO2	41,575	45,732	88,731	6,860	-34,715
CO	1,402	1,543	4,450	1,543	+141
NOx	21,866	24,053	39,453	24,053	+2,187
ROG	161	177	316	177	+16
Annual permitted emission limits with 10% annual generation increase. Values in tons per year
Table 4.3-7: Annual Air Pollution Emissions – Installation of Scrubber and Bag House
	1995-97	w/Scrubber/	Net
Pollutant	Base	BagHouse	Change
PM10	4,368	2,912*	-1,456
SO2	41,575	6,236	-35,339
CO	1,402	1,402	0
NOx	21,866	21,866	0
ROG	161	161	0
* Achieving a maximum 20% in-stack opacity level (one-third emissions reduction).