Exhibit 7
AMBIENT AIR QUALITY IMPACT REPORT 

(NSR 4-1-3, AZP 04-01) 

This document serves as the statement of basis and fact sheet required by 40 CFR 124.7 and 

124.8. This document sets forth the legal and factual basis for the permit conditions and 

provides references to applicable statutory or regulatory provisions, including provisions under 

40 CFR 52.21. This document is intended for use by all parties interested in the permit. 

I. APPLICANT 

Sithe Global Power, LLC 

Desert Rock Energy Project 

Three Riverway, Suite 1100 

Houston, TX 77056 

II. PROJECT LOCATION 

Sithe Global Power, LLC (“Sithe”or “applicant”), under a development agreement with 

the Navajo Nation’s Diné Power Authority, is proposing to construct a 1,500 megawatt 

(“MW”) mine-mouth, coal-fired power plant (“Facility” or “DREF”). The Facility will 

be located in the Northeastern Area of the Navajo Nation adjacent to Navajo Nation coal 

reserves at a mine operated by BHP Billiton. Sithe submitted an application for a 

Prevention of Significant Deterioration (“PSD”) permit to allow construction and 

operation of the coal-fired, nominal 1500 MW Facility on the Navajo Indian Reservation. 

The project is generally called the Desert Rock Energy Facility (“DREF”). The proposed 

580 acre site is located approximately 25 miles southwest of Farmington, New Mexico. 

The proposed DREF is located within the New Mexico portion of the Four Corners 

Interstate Air Quality Control Region. The area is currently designated as attainment for 

all regulated pollutants: nitrogen dioxide (NO2), sulfur dioxide (SO2), carbon monoxide 

(CO), particulate matter less than 10 microns in aerodynamic diameter (PM10), lead, and 

ozone (regulated as volatile organic compounds (VOC) and oxides of nitrogen (NOx)). 

For purposes of this PSD permit and analysis, EPA will refer to NOx, which is 

functionally equivalent to NO2, for both pollutants. The Facility’s surrounding area is 

classified as Class II. The nearest Class I area is the Mesa Verde National Park, which is 

located approximately 75 kilometers (km) north of the site. The Grand Canyon National 

Park is located approximately 290 km west of the site. 

III. PROJECT DESCRIPTION 

The proposed PSD permit, if finalized after EPA receives and considers significant 

comments from the public, will allow Sithe to construct two supercritical pulverized coal 

fired boilers designed for a total nominal generation capacity of 1,500 MW (gross). Each 

of the two units will be 750 MW (gross) and 683 MW (net). Sithe’s Facility will use a 
once through, supercritical steam cycle and other design features that will enable this 

Facility to achieve a net efficiency greater than 40% based on the lower heating value of 

the fuel. Sithe will install and operate Best Available Control Technology (BACT) 

emission controls to minimize the Facility’s emissions of regulated air pollutants. 

Sithe’s Facility will minimize its water consumption by using a Heller system, dry natural 

draft cooling tower. The Facility’s solid wastes produced by combustion of the coal and 

the air pollution control system will be returned to the mine. 

Pulverized Coal-fired Boilers 

The proposed PSD permit, if finalized, will allow Sithe to construct two supercritical 

pulverized coal fired boilers designed for a total nominal generation capacity of 1,500 

MW (gross) divided into two units of 750 MW (gross) and 683 MW (net) each. Each 

boiler will have a heat input capacity of approximately 6,800 MMBTU/hr (extreme 

maximum) and will burn up to 382 tons/hour of coal. In the supercritical cycle, each 

boiler will produce steam at 3,626 psi and 1,112/F at a rate of 4,636,000 lb/hour. The 

boilers will feed the high-pressure steam through a steam turbine generator to produce 

electricity and then to a direct contact jet condenser. 

The proposed PSD permit’s BACT air pollution controls for Sithe’s supercritical 

pulverized coal-fired boilers consist of the following: 

Low-NOx burners and selective catalytic reduction (SCR) to reduce NOx 

emissions; 

Low sulfur coal, hydrated lime injection before a fabric filter, and wet limestone 

flue gas desulfurisation to reduce SO2 emissions; 

Hydrated lime injection before a fabric filter, and wet limestone flue gas 

desulfurisation to reduce acid gas emissions including sulfuric acid mist; 

A fabric filter to reduce particulate emissions; and 

Good combustion controls to reduce CO and VOC emissions. 

Auxiliary Boilers 

The proposed PSD permit, if finalized, will also allow Sithe to construct and operate 

three auxiliary steam generators to provide auxiliary steam during startup and shutdown 

of the main steam generator. Sithe will use auxiliary steam generators that are firetube/smoke-tube type (package boilers, shell type). Each auxiliary steam generator will 

have a heat input capacity of 86.4 MMBTU/hour. Sithe will reduce emissions from these 

units by only burning low sulfur (0.05% sulfur) distillate oil, operating Low-NOx 

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burners, practicing good combustion, and limiting operation to an average of 1,650 

hours/year for the three boilers (equivalent to a total maximum annual fuel use in the 

three boilers of 142,560 MMBTU/year at full load operation). 

Coal Handling 

As a mine mouth facility, Sithe will burn only the low sulfur, blended coal from the 

Navajo Nation mine operated by BHP Billiton. The coal will be delivered to the Facility 

by an enclosed conveyor system. Sithe will build a passive or inactive coal pile on the 

site for emergency purposes. Normal preparation and storage will be handled by BHP 

Billiton at the mine site. The conveyor from the Navajo Nation/BHP Billiton mine will 

move the coal through a series of enclosed transfer houses where the coal will drop onto 

conveyors for transport to bunkers provided for each boiler. From the bunkers, Sithe will 

feed the coal through pulverisers to the boilers. The Sithe Facility on-site coal piles will 

be covered or sealed to prevent emissions and spontaneous combustion. All of the 

conveyors that Sithe will operate will be totally enclosed to prevent emissions. The 

proposed PSD permit, if finalized, will require Sithe to operate dust suppression, 

enclosures, or baghouses to reduce emissions from material transfer points and the coal 

bunkers. 

Cooling Towers 

The PSD permit, if finalized, will require Sithe to install and operate a direct contact jet 

condenser with a Heller dry cooling tower system. In this cooling system, the process 

steam from the steam turbine is fed to the condenser and condensed by direct cooling 

with the cooling water coming from the cooling cycle. The blended cooling water and 

condensate are collected in the hot-well and extracted by circulating water pumps. 

Approximately 2% of this flow – corresponding to the steam condensed – is fed to the 

boiler feed water system by condensate pumps. The major part of the flow is returned to 

the cooling tower for recooling. The cooling duty is performed by the cooling deltas, 

divided into parallel sectors, where cooling air flow is induced by a natural draft dry 

cooling tower. Sithe has applied to use, and the PSD permit is proposing to require, the 

Heller-type hybrid cooling tower to minimize water consumption. When the ambient 

temperature is below 80/F, the cooling tower will operate like a natural draft dry cooling 

tower. When the temperature exceeds 80/F, the Facility has the option of applying water 

oversprays on the heating surfaces inside of the cooling tower to provide additional 

cooling. This type of cooling tower does not emit any particulate matter or other 

pollutants. 

Ash Handling 

Sithe will reduce emissions of fly ash by collecting the fly ash in the main fabric filter. 

The pulverized coal-fired boilers will also generate bottom ash. Fly ash and bottom ash 

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will be mixed in an ash silo. The proposed PSD permit, if finalized, will require any 

particulate matter emissions from the ash silo to be reduced by a fabric filter. Gypsum, 

with a water content in the 10% to 20% range, will be generated by the wet flue gas 

desulfurisation system. The gypsum fly ash and bottom ash will be mixed together and 

then transported back to the mine by an enclosed conveyor. 

IV. EMISSIONS FROM THE PROPOSED PROJECT 

The proposed Facility’s estimated maximum annual potential emissions are summarized 

in Table 1 and are based on vendors’ data, Sithe’s design criteria, EPA emission factors 

from AP-42, and established emission calculation procedures. The estimated maximum 

annual potential emissions include emissions from the two supercritical pulverized coal 

boilers, the three auxiliary boilers, the emergency generators, the fire pumps, and 

materials handling. The estimated maximum annual potential emissions assume a 95% 

annual capacity factor at full load and include emissions from an anticipated 60 startups 

per year, with an average of 30 startups per boiler (4 cold, 10 warm and 16 hot). The 

Facility’s startup and shutdown operations will not result in any excess daily or annual 

emissions compared to normal continuous operation. EPA has determined that Sithe’s 

95% capacity factor assumption and estimate of 60 startups per year is conservative, 

which means these assumptions are likely to lead to estimating higher potential emissions 

than the Facility will actually emit. 

V. APPLICABILITY OF THE PREVENTION OF SIGNIFICANT 

DETERIORATION (PSD) REGULATIONS 

The PSD regulations define a "major stationary source" as any source type belonging to a 

list of 28 source categories which emits or has the "potential to emit" 100 tons per year 

(tpy) or more of any pollutant regulated under the Clean Air Act, or any other source type 

which emits or has the potential to emit such pollutants in amounts equal to or greater 

than 250 tpy. 40 CFR 52.21(b)(1). Sithe has applied to construct a fossil fuel-fired steam 

electric plant of more than 250 MMBTU/hr heat input. It is, therefore, one of the 28 

source categories specified in EPA regulations and the 100 tpy threshold applies for 

purposes of PSD applicability. The proposed Facility has the potential to emit over 100 

tpy and is a major stationary source for all regulated pollutants except lead, fluorides and 

sulfuric acid mist. 

Under the PSD regulations, a significant emissions increase is defined as an increase in 

emissions greater than the threshold prescribed for any pollutant subject to the regulation. 

40 CFR 52.21(a)(1)(d). The significance thresholds prescribed by the PSD regulations at 

40 CFR 52.21(b)(23) for lead, fluorides and sulfuric acid mist are listed in Table 2. 

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Table 1 

Estimated Maximum Annual Potential Emissions 

Pollutant PC Boilers 

(tpy) 

Auxiliary 

Boilers 

(tpy) 

Emergency 

Generators 

(tpy) 

Fire Water 

Pumps 

(tpy) 

Material 

Handling 

(tpy) 

Project 

Estimated 

Emissions 

NOx 3,315 7.13 2.26 0.41 n/a 3,325 

CO 5,526 2.55 0.17 0.031 n/a 5,529 

VOC 166 0.17 0.11 0.019 n/a 166 

SO2 3,315 3.61 0.068 0.012 n/a 3,319 

PM 553 1.02 0.083 0.015 16.1 570 

PM10 1,105 1.68 0.077 0.014 12.9 1,120 

Lead 11.1 0.00064 0.00012 0.0000022 n/a 11.1 

Fluorides 13.3 neg neg neg neg 13.3 

H2SO4 221 0.062 0.002 0.0004 n/a 221 

Mercury 0.057 0.000071 neg neg n/a 0.057 

Note: 1. tpy - tons per year 

2. PM is defined as filterable particulate matter as measured by EPA Method 5. 

3. PM10 is defined as solid particulate matter smaller than 10 micrometers diameter 

as measured by EPA Method 201 or 201A plus condensable particulate matter as 

measured by EPA Method 202. EPA is treating PM10 as a surrogate for PM2.5. 

PSD review applies to all pollutants that exceed the major stationary source threshold 

(100 tpy) or that exceed the significance thresholds for which the applicable federal 

National Ambient Air Quality Standards (NAAQS) have not been exceeded (attainment 

areas), or areas where the status of the area is uncertain (unclassified). The proposed 

Facility will be located in an area in the New Mexico Air Quality Control Region, which 

currently has a designation of attainment for all pollutants. 

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Table 2 

Comparison of the Project Annual Emissions to the PSD Thresholds 

Pollutant PSD Significance Level 

(tpy) 

Project Emissions 

(tpy) 

CO 100 5,529 

NOx 40 3,315 

SO2 40 3,315 

TSP/PM 25 570 

PM10 15 1,120 

Ozone (VOC) 40 166 

Lead 0.6 11.1 

Fluorides 3 13.3 

Sulfuric Acid Mist (H2SO4) 7 221 

The estimated maximum annual potential emissions profile in Table 2 shows that the 

Facility is a major stationary source because its potential to emit exceeds 100 tpy for 

NOx, CO, SO2, PM, PM10 and VOC. Table 2 also shows that the Facility’s potential to 

emit lead, fluorides and sulfuric acid mist exceeds the significance thresholds. Therefore, 

all of these pollutants are subject to PSD review and must satisfy the following 

requirements: 

1. Application of Best Available Control Technology (BACT); 

2. Analysis of ambient air quality impacts from the project; 

3. Analysis of air quality and visibility impacts on Class I areas; and 

4. Analysis of impacts on soils and vegetation. 

VI. BEST AVAILABLE CONTROL TECHNOLOGY (BACT) 

Section 169(3) of the Clean Air Act (CAA) defines BACT as follows: 

The term "best available control technology" means an emission limitation based 

on the maximum degree of reduction of each pollutant subject to regulation under 

the Clean Air Act emitted from or which results from any major emitting facility. 

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The permitting authority, on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, makes a BACT 

determination through application of processes and available methods, systems, 

and techniques, including fuel cleaning or treatment or innovative fuel 

combustion techniques for control of each such pollutant. In no event shall 

application of BACT result in emissions of any pollutant which will exceed the 

emissions allowed by any applicable standard established pursuant to section 7411 

(NSPS) or 7412 (NESHAP) of the Clean Air Act. 

For attainment pollutants being regulated in a PSD permit, EPA evaluates emissions 

control requirements through a “top-down” BACT determination, which is described in 

EPA’s New Source Review Workshop Manual, Draft October 1990 (“PSD Manual”), 

page B-6. The top-down approach to the BACT review process involves identifying all 

demonstrated and potentially applicable control technology alternatives. PSD Manual, 

page B.11. EPA would typically review information in EPA’s BACT/LAER (Lowest 

Achievable Emission Rate) Clearinghouse, federal/state/local new source review permits, 

technical journals and other such sources. PSD Manual, page B.11. After broadly 

identifying potential control technology alternatives, EPA can eliminate any control 

alternatives that are not technically feasible because the alternative is either not available 

or not applicable. PSD Manual, page B.17. Next, EPA ranks each technically feasible 

control alternative to establish a hierarchy. PSD Manual, page B. 22. In the next step, the 

process either “validates the suitability of the top control option in the listing for selection 

as BACT, or provides clear justification why the top candidate is inappropriate as 

BACT.” PSD Manual, page B. 26. If the PSD applicant, Sithe in this instance, accepts 

the top (most stringent) control technology alternative as BACT, and that control 

alternative is not eliminated based on collateral environmental impacts, then the BACT 

analysis is complete and the top control technology alternative is selected. PSD Manual, 

page B.26. The top-down BACT analysis is a case-by-case exercise for the particular 

source under evaluation. In summary, the five steps involved in a top-down BACT 

evaluation are: 

1. Identify all available control options with practical potential for application to the 

specific emission unit for the regulated pollutant under evaluation; 

2. Eliminate technically infeasible technology options; 

3. Rank remaining control technologies by control effectiveness; 

4. Evaluate most effective control alternative and document results; if top option is 

not selected as BACT, evaluate next most effective control option; and 

5. Select BACT, which will be the most effective practical option not rejected based 

on energy, environmental, and economic impacts. 

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Sithe provided BACT analyses for NOx, CO, PM10, SO2, VOC, lead, hydrogen fluorides, 

and sulfuric acid mist and EPA independently evaluated the information Sithe submitted. 

The analysis and our evaluation for each pollutant is presented below. 

A. Nitrogen Oxides (NOx)/Nitrogen Dioxide 

1. Pulverized Coal-Fired Boilers 

NOx is formed during the combustion of fossil fuels, including coal, and is 

generally classified as either thermal NOx or fuel NOx. Thermal NOx is formed 

when elemental nitrogen reacts with oxygen in the combustion air within the high 

temperature environment of the furnace. The rate of formation of thermal NOx is 

a function of residence time and free oxygen, and is exponential with peak flame 

temperature. Fuel NOx is generated when nitrogen contained in the coal itself is 

oxidized. The rate of formation of fuel NOx is primarily a function of fuel bound 

nitrogen content of the coal but is also affected by fuel air mixing. 

NOx emissions can be reduced using either combustion controls (i.e., staged 

combustion techniques such as Low-NOx burners (LNB), flue gas recirculation 

(FGR), overfire air (OFA), natural gas reburn, or flue gas treatment including 

selective non-catalytic reduction (SNCR) or selective catalytic reduction (SCR). . 

In accordance with the top-down BACT process, Sithe’s PSD application first 

identified all of the potentially available control technologies for pulverized coal 

fired boilers , eliminated technically infeasible options, and then ranked the 

remaining control technologies, beginning with the technologies that will result in 

the most stringent control and the lowest emissions. EPA agrees that Sithe 

considered all of the potentially available controls, as shown below in Table 3, 

for pulverized coal-fired boilers. They include: 

Table 3 

NOx Control Technologies for Pulverized Coal Boilers 

Pulverized Coal Control 

Technologies 

Control Efficiency Range 

(% Removal) 

Typical Emission Rate 

(lb/MMBTU) 

SCR and Low-NOx Burners 80 - 90 0.06 - 0.15 

SNCR 40 - 60 0.2 - 0.3 

Staged Combustion and LowNOx Burners 30 - 50 0.15 - 0.5 

Gas Reburn 40 - 60 0.15 - 0.3 

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Selective Catalytic Reduction 

SCR is a process that involves post-combustion removal of NOx from flue gas 

with a catalytic reactor. In the SCR process, ammonia injected into the exhaust 

gas reacts with nitrogen oxides and oxygen to form nitrogen and water. The 

reactions take place on the surface of a catalyst. The function of the catalyst is to 

effectively lower the activation energy of the NOx decomposition reaction. 

Technical factors related to this technology include the catalyst reactor design, 

optimum operating temperature, sulfur content of the fuel, catalyst de-activation 

due to aging or poisoning, ammonia slip emissions, and design of the ammonia 

injection system. 

The SCR system is comprised of a number of subsystems. These include the SCR 

reactor and flues, ammonia injection system and ammonia storage and delivery 

system. The SCR reactor with necessary inlet and outlet duct work will be located 

downstream of the economizer and upstream of the air heater and the particulate 

control system. From the economizer outlet, the flue gas will first pass through a 

low-pressure ammonia/air injection grid designed to provide optimal mixing of 

ammonia with flue gas. The ammonia treated flue gas will then flow through the 

catalyst bed and exit to the air heater. 

The SCR system for a pulverized coal boiler typically utilizes a fixed bed catalyst 

in a vertical downflow multi-stage reactor. The reactor will include a seal system 

to prevent gas from bypassing the catalyst bed. Access openings for catalyst 

loading/removal and periodic internal inspection will be provided. The reactor 

will contain multiple stages of catalyst with room for loading a future stage. For 

each stage, a soot blowing system will be provided. Each stage will be equipped 

with a platform with monorails and hoists to accommodate catalyst loading and 

unloading. 

Reduction catalysts are divided into two groups: base metal (lower temperature, 

primarily vanadium, platinum or titanium) and zeolite (higher temperature). Both 

groups exhibit advantages and disadvantages in terms of operating temperature, 

reducing agent/NOx ratio, and optimum oxygen concentration. A disadvantage 

common to base metal catalysts is the narrow range of temperatures in which the 

reactions will proceed. Platinum group catalysts have the advantage of requiring 

lower ignition temperature, but have been shown to also have a lower maximum 

operating temperature. Operating above the maximum temperature results in 

oxidation of ammonia to either nitrogen oxides (thereby actually increasing NOx 

emissions) or ammonium nitrate. 

Optimum operating temperature for a vanadium-titanium catalyst system has been 

shown to be in the range of 550/ to 800/F, which is significantly higher than for 

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platinum catalyst systems. However, the vanadium-titanium catalyst systems 

begin to break down when continuously operating at temperatures above this 

range. Consequently, operating above the maximum temperature for the catalyst 

system again results in the oxidation of ammonia to either nitrogen oxides 

(increasing NOx emissions) or ammonium nitrate. 

Sulfur content of the fuel can be a concern for systems that employ SCR. Catalyst 

systems promote partial oxidation of sulfur dioxide to sulfur trioxide (SO3), which 

combines with water to form sulfuric acid. At typical SCR operating 

temperatures, SO3 and sulfuric acid react with excess ammonia to form 

ammonium salts. These ammonium salts may condense as the flue gases are 

cooled and can lead to increased uncontrolled emissions of PM10 entering the 

particulate collector. Fouling may eventually lead to decreased NOx reduction 

performance, increased system pressure drop over time and decreased heat 

transfer efficiencies. 

The SCR process is subject to catalyst deactivation over time. Catalyst 

deactivation occurs through two primary mechanisms: physical deactivation and 

chemical poisoning. Physical deactivation is generally the result either of 

prolonged exposure to excessive temperatures or masking of the catalyst due to 

entrainment of particulate from ambient air or internal contaminants. Chemical 

poisoning is caused by the irreversible reaction of the catalyst with a contaminant 

in the gas stream and is a permanent condition. Catalyst suppliers typically only 

guarantee a limited lifetime to very low emission level, high performance catalyst 

systems. 

SCR manufacturers typically estimate 10 ppmvd of unreacted ammonia emissions 

(ammonia slip) when making guarantees at very high efficiency levels. To 

achieve high NOx reduction rates, SCR vendors suggest a higher ammonia 

injection rate than stoichiometrically required, which conversely results in 

ammonia slip. Thus an emissions trade-off between NOx and ammonia may occur 

in high NOx reduction applications. 

The potential environmental impacts associated with the use of SCR include: 

• Unreacted ammonia would be emitted to the atmosphere (ammonia slip). 

• Ammonium salts would increase loading to the particulate collection stage 

as PM10 (and PM2.5). 

• Safety issues and Risk Management Planning may be required relative to 

the transportation, handling, and storage of ammonia (aqueous or 

anhydrous). 

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Selective Non-Catalytic Reduction 

SNCR has been applied to a number of different types of combustion sources, 

including petroleum heaters, utility and industrial boilers fired with natural gas 

and oil, as well as PC boilers and to coal-fired Circulating Fluidized Bed (CFB) 

boilers. 

The SNCR process is based on a gas-phase homogeneous reaction, within a 

specified temperature range, between NOx in the flue gas and either injected NH3 

or urea to produce gaseous nitrogen and water vapor. SNCR systems do not 

employ a catalyst; the NOx reduction reactions are driven by the thermal 

decomposition of ammonia and the subsequent reduction of NOx. Consequently, 

the SNCR process operates at higher temperatures than the SCR process. 

Critical to the successful reduction of NOx with SNCR is the temperature of the 

flue gas at the point where the reagent is injected. For the ammonia injection 

process, the necessary temperature range is 1,700 - 1,900/F; for the urea injection 

process the nominal temperature range is 1,600 - 2,100/F. Also critical to 

effective application of these processes are gas mixing, residence time at 

temperature, and ammonia slip. 

Theoretically, one mole of ammonia (or one-half mole of urea) will react with one 

mole of NOx, forming elemental nitrogen and water. In reality, not all the 

injected reagent will react due to imperfect mixing, uneven temperature 

distribution, and insufficient residence time. These physical limitations may be 

compensated for by injecting a large amount of excess reagent and essentially 

achieving low NOx emissions at the expense of emissions of unreacted reagent, 

referred to as ammonia slip. These emissions represent an adverse environmental 

impact and can lead to formation of ammonium salts and may contribute to 

regional haze as a precursor to PM2.5. Thus, for a given boiler configuration, there 

is a limit on the degree of NOx reduction which can be achieved with SNCR 

while maintaining acceptable levels of ammonia slip. 

Pulverized coal-fired units have a limited furnace temperature window and poor 

lateral mixing, conditions which render SNCR less effective in these units. SNCR 

has been applied to PC boilers more often to achieve 30 – 50% reductions in 

response to Reasonably Available Control Technology (RACT) requirements 

since the technology can be retrofit more easily than other add-on controls. Due 

to mixing limitations and a brief temperature window in which to react, SNCR is 

fundamentally less effective at controlling NOx from PC’s as compared with other 

combustion processes. 

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Staged Combustion 

A number of techniques have been employed to reduce the formation of NOx by 

reducing peak flame temperature and/or starving the hottest parts of the flame for 

oxygen. By staging the combustion process, a longer, cooler flame results, which 

forms less NOx. Staged combustion techniques include Low-NOx burners, flue 

gas recirculation, overfire air, burners out of service, and combinations of these. 

A collateral impact of staged combustion is an increase in emissions of products 

of incomplete combustion including CO, VOC and carbon in ash. 

Gas Reburn 

Natural gas reburn is a control technique that has shown promise as a potential 

retrofit to existing boilers, and may be capable of reducing emissions of NOx to 

0.15 lb/MMBTU simply by starving the coal burners for excess oxygen and 

completing combustion with 12-15% gas in the upper furnace. Application of this 

technology assumes that natural gas in substantial quantity is already available on 

site – otherwise it is technically infeasible. In any event, the level of NOx control 

that may be achieved is less than for the other add-on control technologies and 

therefore it is not considered further in this analysis. 

Proposed Pulverized Coal-Fired Boiler BACT for NOx 

Sithe has proposed to construct and operate the Facility with a combination of 

LNB and SCR for each of the two proposed boilers. Sithe is proposing to achieve 

a BACT NOx emission rate of 0.06 lb/MMBTU as a 24-hour average during 

operation based on using Navajo Nation coal from the BHP mine. Sithe’s 

application for the PSD Permit contained a top-down BACT analysis which EPA 

has independently evaluated. 

EPA’s independent analysis of available control technologies for pulverized coal 

fired boilers included reviewing the DOE/NETL (National Energy Technology 

Laboratory) database, EPA’s RACT/BACT/LAER Clearinghouse, EPA’s 

National Coal BACT Workgroup database, the EPA spreadsheet of recently 

permitted and proposed coal-fired power plants, review of issued permits or 

applications for permits, discussions with EPA and State permitting staff, trade 

journals, information from industry conferences and vendor guarantees. 

EPA’s review of all available data and technologies demonstrates that Sithe’s 

proposed choice of LNB and SCR is the most stringent combination of control 

technologies available for pulverized coal fired boilers. The NOx emission rate of 

0.06 lb/MMBTU that Sithe has proposed, particularly because Sithe has proposed 

to meet 0.06 lb/MMBTU as a 24-hour average, is lower than other NOx emissions 

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rates that have been proposed for or achieved by pulverized coal fired boilers 

recently. 

The National Coal Workgroup database shows that the NOx BACT emissions 

limits in recent PSD permits for pulverized coal fired boilers using LNB and SCR 

range from 0.07 lbs/MMBTU to 0.10 lbs/MMBTU, often as a 30-day average. 

Similarly, the information contained in the DOE/NETL’s database of information 

for pulverized coal fired boilers shows that 0.06 lbs/MMBTU is below the lowest 

NOx BACT emission limits for recently permitted facilities. Further examples of 

NOx BACT emissions limits for recently permitted pulverized coal boilers using 

LNB and SCR, or solely LNB for the Sand Sage facility, is shown below. 

Examples of Recently Permitted/Proposed Coal-Fired Power Plants 

Facility Size 

(MW) 

Emission 

Controls 

NOx Emission Rate 

(lbs/MMBTU) 

Thoroughbred 

(Kentucky) 

1500 SCR 0.08 (30-day avg.) 

Prairie State (Illinois) 1500 SCR 0.10 

Intermountain Power 

(Utah) 

950 SCR 0.07 (30-day avg.) 

Longleaf 1200 SCR 0.07 (30-day avg.) 

Sand Sage 660 LNB 0.12 - 0.08 (30-day avg.) 

Roundup Power 

(Montana) 

780 SCR 0.07 (24-hr avg.) 

Longview 600 SCR 0.08 (24-hr avg.) 

EPA has also reviewed the decisions of EPA’s Environmental Appeals Board 

(EAB) and the Wisconsin Division of Hearings and Appeals on challenges to the 

NOx BACT decisions in PSD permitting actions for pulverized coal fired boilers. 

The Nevada Department of Environmental Protection issued a PSD permit to 

Newmont Nevada Energy Center LLP. The PSD Permit for that facility, which is 

a 200 MW pulverized coal fired boiler, established a BACT emission limit for 

NOx at 0.067 lbs/MMBTU as a 24 hour average, using LNB and SCR. The 

Newmont facility will burn coal from the Powder River Basin (PRB) The 

appropriateness of Newmont’s NOx BACT emission limit of 0.067 lbs/MMBTU 

was appealed to the EAB. The petitioner challenged whether 0.067 lbs/MMBTU 

(24 hour average) was BACT because Sithe had applied for a lower NOx BACT 

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limit (0.06 lbs/MMBTU as a 24 hour average) for DREF. The petitioner also 

cited a report for Baldwin Generating Station in Illinois, a determination by the 

Texas Natural Resource Conservation Commission discussing potentially 

achievable lower NOx emissions limits and a few other sources. See In Re: 

Newmont Nevada Energy Investment, LLC, 12 E.A.D. (June 3, 2005). The EAB 

recognized the importance of the type of coal being combusted and other relevant 

case-specific factors in a BACT determination. The EAB was not persuaded by 

citations to lower NOx emissions rates in trade journals and permits that only 

required such operation during the ozone season. The EAB recognized that the 

precise conditions, including the selection of coal type, surrounding the operation 

of the facility under PSD review should dictate the NOx BACT emissions limit, 

and held that 0.067 lbs/MMBTU as a 24 hour average was BACT. 

The Wisconsin Division of Hearings and Appeal upheld the State’s PSD NOx 

BACT determination during a permit appeal. The Wisconsin Department of 

Natural Resources (WDNR) determined that a NOx emission limit of 0.06 

lbs/MMBTU as a 30 day average was BACT. The WDNR initially permitted the 

facility with a NOx BACT emission limit of 0.06 lbs/MMBTU as a 30 day 

average and 0.07 lbs/MMBTU as an annual average. The Judge in that appeal 

found 0.06 lbs/MMBTU was “consistent with or lower than other BACT NOx 

emission limits established for other coal-fired utility boilers which were issued 

air permits contemporaneous with [the Wisconsin facility].” Decision at 10. The 

Judge modified the PSD permit to remove the higher emissions limit (0.07 

lbs/MMBTU) for the annual average so that the permittee was required to meet a 

NOx BACT emission limit of 0.06 lbs/MMBTU as a 30 day and annual average. 

In summary, the two lowest BACT emissions limits for NOx are 0.067 

lbs/MMBTU as a 24 hour average for Newmont and 0.06 lbs/MMBTU as a 30 

day average for the Wisconsin facility. The NOx BACT emissions limit in the 

proposed permit for DREF is 0.06 lbs/MMBTU as a 24 hour average, making the 

proposed NOx BACT emissions limit for DREF the lowest in an issued PSD 

permit for a pulverized coal fired boiler. When an emission limit is averaged over 

a shorter period of time (e.g. 24 hours rather than 30 days), it reduces the number 

of spikes that a facility can experience while still maintaining compliance with the 

emissions limit. Therefore, the NOx emission limit of 0.06 lbs/MMBTU as a 24 

hour average is lower than any other reported BACT emission limit. EPA is 

proposing BACT for NOx for DREF to be LNB and SCR, meeting an emission 

limit of 0.06 lb/MMBTU on a 24 hour average. 

2. Auxiliary Boilers 

The Desert Rock Energy Facility includes three small distillate oil-fired auxiliary 

boilers with heat input capacities of approximately 86.4 MMBTU/hour. These 

14 
boilers will be subject to NSPS 40 CFR 60, Subpart Dc. Total annual fuel use in 

the three boilers will be limited to 142,560 MMBTU/year, which is equivalent to 

an average of 550 hours of operation per year per boiler at full load. Based on a 

review of recent permits for similar boilers and EPA’s RACT/BACT/LAER 

Clearinghouse, the applicant has concluded that BACT for NOx for these boilers 

is 0.10 lb/MMBTU using Low-NOx burners. After reviewing the submitted 

materials, EPA agrees and proposes BACT for NOx for the auxiliary boilers to be 

Low-NOx burners and an emission rate of 0.10 lb/MMBTU. 

3. Emergency Generators 

The Desert Rock Energy Facility includes two emergency diesel generators (1,000 

kW each) and two diesel generator powered firewater pumps (180 kW each). 

These emergency diesel engines will not operate for more than 100 hours/year 

each. NOx emissions during operation will be controlled by only burning low 

sulfur distillate oil and ignition timing retard with turbocharging and aftercooling. 

Based on review of recent permits for similar emergency diesel engines and 

EPA’s RACT/BACT/LAER Clearinghouse, the top level of control or lowest 

NOx emission rate is approximately 6.5 g/hp-hr. The applicant has concluded that 

this level of control represents BACT for the emergency diesel engines. After 

reviewing the submitted materials, EPA concurs and proposes the use of ignition 

timing retard with turbocharging and aftercooling with an emission rate of 6.5 

g/hp-hr to be BACT for NOx for the emergency generators. 

B. Sulfur Dioxide (SO2) 

1. Pulverized Coal-Fired Boilers 

Emissions of sulfur dioxide are generated in fossil fuel-fired sources from the 

oxidation of sulfur present in the fuel. Approximately 98% of sulfur in solid fuels 

is emitted upon combustion as gaseous sulfur oxides. Uncontrolled emissions of 

SO2 are thus affected by fuel sulfur content alone, and not by the firing 

mechanism, boiler size, or operation. Many coal-fired boilers limit emissions of 

SO2 through the use of low sulfur western coals, including PRB coal. Compared 

with a high sulfur eastern bituminous coal that may contain as much as 4% sulfur, 

burning western coal can reduce SO2 emissions by approximately 70% to 90%. 

The selection of coal type and sulfur content is therefore one of the aspects that 

must be considered when making a determination of SO2 BACT and needs to be 

considered in conjunction with add-on control alternatives when performing the 

top-down analysis. 

Generally, there are two types of add-on control applicable to a coal-fired boiler: 

in-situ combustion control (sorbent injection) and post-combustion control (flue 

15 
gas desulfurisation). In-situ control is used effectively in CFB boilers, and may be 

used in a PC boiler by using limestone injection into the furnace, however the 

level of control that is achievable is not comparable to post-combustion SO2 

control systems. Post-combustion controls applicable to PC boilers are a wet 

scrubbing system or spray dryer absorber (SDA) using reagents such as lime, 

limestone, sodium bicarbonate or magnesium oxide. 

A comparative ranking of available SO2 control technologies (see Table 4) must 

take into consideration multiple variables including coal sulfur content, % 

removal and the resulting emission rate (lb/MMBTU) in addition to collateral 

impacts on other pollutants, energy impacts, and other environmental impacts. 

Table 4 

SO2 Control Technologies for Pulverized Coal Boilers 

Pulverized Coal Control 

Technologies 

Control Efficiency Range 

(% Removal) 

Typical Emission Rate 

(lb/MMBTU) 

Wet Flue Gas Desulfurisation 90 - 98 Depends on coal sulfur content 

(lower with western coal) 

Limestone Injection 25 - 35 Depends on coal sulfur content 

(lower with western coal) 

Spray Dryer Absorber 70 - 92 Depends on coal sulfur content 

(lower with western coal) 

Use of Low Sulfur Coal 30 - 90 

Wet Flue Gas Desulfurisation 

The most frequently utilized wet flue gas desulfurisation (FGD) technology is the 

wet limestone spray tower system. Typically, flue gas enters at the bottom of the 

absorber tower, continues vertically through the limestone/water spray, passes 

through a mist eliminator to control the re-entrained slurry drops, and then exits 

the tower. Limestone (calcium carbonate) reacts with the sulfur dioxide to form 

calcium sulfite. The calcium sulfite may then be oxidized to form calcium sulfate, 

since it is easier to de-water than calcium sulfite. This can be achieved by 

blowing compressed air into the slurry in the retention tank in the base of the 

tower or in an external oxidation tank. 

To fully utilize the limestone, the slurry is re-circulated through the tower and a 

bleed stream is taken off for de-watering. The bleed stream can be de-watered 

using a variety of techniques, including thickeners, centrifuges and vacuum filters. 

16 
The final slurry may contain 10% to 40% water by weight. 

Wet scrubbers can also utilize limestone rather than lime. Some of the lime 

(calcium oxide) becomes calcium hydroxide in water. The slurry of calcium 

hydroxide and lime is fed to the spray tower. Since the cost of limestone is much 

less than lime, the limestone alternative is much more common. This is especially 

the case for medium to high sulfur coals. 

Spray Dryer Absorber/Limestone Injection 

The spray dryer absorber is located upstream of the particulate collection system, 

typically fabric filters. The flue gas passes through a spray dryer vessel where it 

encounters a fine mist of lime slurry. The lime slurry is injected into the spray 

dryer absorber through either a rotary atomizer or fluid nozzles. The moisture in 

the droplets evaporates and reacts with the SO2 in the flue gas to form insoluble 

calcium salts. The flue gas is cooled to approximately 18 to 30 /F above the 

adiabatic saturation of the flue gas. The calcium salts have a moisture content of 

approximately 2 to 3%, which falls to 1% before reaching the particulate control 

device. When a fabric filter is used as the particulate control device, it allows for 

further reaction of the lime with the sulfur (and other acid gases) in the flue gas. 

This is due to the layer of porous filter cake on the surface of the filter that 

contains the reagent that all flue gas must pass through. This allows for increased 

efficiency of control of sulfuric acid mist, hydrogen chloride and mercury as 

compared to wet scrubbers. 

Use of Low Sulfur Coal 

Any discussion of the relative effectiveness of add on SO2 control must also take 

into account the level of uncontrolled SO2 to be handled, which is highly 

dependent on the sulfur content of the coal to be burned. Higher removal 

efficiencies tend to be more practical when there is a high concentration of SO2 in 

the flue gas, and vice versa. This is reflected in a comparison of the resulting 

emission rate in units of lb of SO2 per MMBTU of fuel burned (or lb of SO2 per 

kW produced). For example, a proposed project with a BACT limit of 0.16 

lb/MMBTU using an 80% removal control system is environmentally superior to 

another project with a BACT limit of 0.32 lb/MMBTU and 95% removal. For a 

project located in the Western U.S., BACT generally includes use of low sulfur 

western coal as a part of a strategy to limit SO2 to BACT levels in combination 

with add-on control. 

Proposed Pulverized Coal-Fired Boiler BACT for SO2 

Sithe has proposed to construct and operate the Facility using a combination of 

17 
low sulfur western coal and wet limestone flue gas desulfurisation. Sithe is 

proposing to achieve an SO2 BACT emission rate of 0.06 lb/MMBTU as a 24-

hour average during operation. 

EPA’s independent analysis of available control technologies for pulverized coal 

fired boilers included reviewing the DOE/NETL (National Energy Technology 

Laboratory) database, EPA’s RACT/BACT/LAER Clearinghouse, EPA’s 

National Coal BACT Workgroup database, and the EPA spreadsheet of recently 

permitted and proposed coal-fired power plants as well as the other sources 

discussed above for NOx. 

EPA’s review of all available data and technologies demonstrates that the choice 

of low sulfur coal and wet limestone desulfurisation is the most stringent 

combination of control technologies available for pulverized coal fired boilers. 

The emission rate of 0.06 lb/MMBTU that Sithe has proposed, as a 24-hour 

average, is lower than other SO2 emission rates that have been proposed for 

pulverized coal fired boilers recently. 

The PSD Permit that Nevada Department of Environmental Protection issued to 

Newmont Nevada Energy Center, LLP last year allowed dry scrubbing rather than 

requiring wet limestone desulfurisation. Newmont’s PSD permit established an 

SO2 BACT emission limit of 0.065 to 0.09 lbs/MMBTU. 

EPA is also persuaded that 0.06 lbs/MMBTU SO2 is BACT for DREF based on 

the information in the National Coal Workgroup database. The database shows 

that SO2 emission limits for recent PSD permits for pulverized coal fired boilers 

range from 0.09 to 0.30 lb/MMBTU (30-day average). Similarly, the information 

contained in the Department of Energy’s compilation of information for 

pulverized coal fired boilers shows that 0.06 lbs/MMBTU is below the lowest SO2 

BACT emission limit for recently permitted facilities. 

Examples of Recently Permitted/Proposed Coal-Fired Power Plants 

Facility Size 

(MW) 

Emission 

Controls 

SO2 Emission Rate 

(lbs/MMBTU) 

Thoroughbred 1500 Wet scrubber 0.167 (30-day avg.) 

0.41 (24-hr avg.) 

Prairie State 1500 Wet scrubber 0.30 

Intermountain Power 950 Wet scrubber 0.09 (30-day avg.) 

0.12 (24-hr avg.) 

Longleaf 1200 Dry scrubber 0.12 (30-day avg.) 

18 
Sand Sage 660 Dry scrubber 0.15 (30-day avg.) 

Roundup Power 780 Dry scrubber 0.12 (24-hr avg.) 

2. Auxiliary Boilers 

The Desert Rock Energy Facility also includes three small distillate oil-fired 

auxiliary boilers with heat input capacities of approximately 86.4 MMBTU/hour. 

Total annual fuel use in the three boilers will be limited to 142,560 MMBTU/year, 

which is equivalent to an average of 550 hours/year per boiler at full load. SO2 

emissions will be controlled by only burning low sulfur distillate oil with a 

maximum sulfur content of 0.05%. No add-on SO2 controls have ever been 

applied to similar sources. The burning of low sulfur fuels such as low sulfur 

distillate oil is the only available SO2 control option and is the top level of control. 

Therefore, the applicant is proposing to only burn low sulfur distillate oil (0.05% 

sulfur maximum) and to restrict total annual fuel consumption to 142,560 

MMBTU/year as BACT for the auxiliary boilers. After reviewing the submitted 

materials we concur with the applicant and propose BACT for SO2 for the auxiliary 

boilers to be the burning of low sulfur distillate oil not to exceed 0.05% sulfur 

content and no more than 142,560 MMBTU/year. 

3. Emergency Diesel Engines 

The project includes two emergency diesel generators (1,000 kW each) and two 

diesel generator powered firewater pumps (180 kW each). These emergency diesel 

engines will not be operated for more than 100 hours/year each. No add-on SO2 

controls have ever been applied to similar sources. The burning of low sulfur fuels 

such as low sulfur distillate oil is the only available SO2 control option and 

represents the top level of control. Therefore, the applicant proposes to only burn 

low sulfur distillate oil (0.05% sulfur maximum) and to restrict operation to 100 

hours per year each as BACT for the proposed emergency diesel engines. EPA 

concurs and proposes BACT for SO2 for the emergency diesel engines to be 

burning low sulfur distillate oil and limiting operation to no more than 100 hours 

per year per engine. 

C. Carbon Monoxide (CO) 

1. Pulverized Coal-Fired Boilers 

Carbon monoxide is formed as a result of incomplete combustion of a hydrocarbon 

fuel. Control of CO is accomplished by providing adequate fuel residence time, 

excess oxygen and high temperature in the combustion zone to ensure complete 

combustion. These control factors, however, also tend to result in increased 

19 
emissions of NOx. Conversely, a low NOx emission rate achieved through 

combustion modification techniques such as Low-NOx Burners can result in higher 

levels of CO formation. Thus, a compromise is established to achieve the lowest 

NOx formation rate possible while keeping CO emission rates at acceptable levels. 

CO emissions from pulverized coal-fired boilers are a function of oxygen 

availability (excess air), flame temperature, residence time at flame temperature, 

combustion zone design, and turbulence. All pulverized coal-fired boilers 

identified utilize front-end methods such as good combustion control wherein CO 

formation is suppressed within the boiler. All listings in EPA’s 

RACT/BACT/LAER Clearinghouse for pulverized coal-fired boilers utilize 

combustion control techniques for CO (see Table 5). While gas-fired combustion 

turbines have been widely equipped with oxidation catalyst control technology, this 

technology has not been applied to coal-fired boilers. In addition to oxidizing CO, 

an oxidation catalyst would oxidize SO2 to produce SO3, which would exacerbate 

sulfuric acid mist emissions. The SO2 oxidation rate would be in the range of 5% 

or more resulting in very high sulfuric acid mist emissions if an oxidation catalyst 

were to be applied to a coal-fired boiler. 

Table 5 

CO Control Technologies for Pulverized Coal Boilers 

Pulverized Coal Control 

Technologies 

Emission Rate 

(lb/MMBTU) 

Technical Feasibility for 

Pulverized Coal-Fired Boilers 

Combustion Controls 0.05 - 0.15 Yes 

Oxidation Catalyst Not determined May not be feasible 

Combustion Controls 

Combustion control refers to controlling emissions of CO through the design and 

operation of the boiler in a manner so as to limit CO formation. In general, a 

combustion control system seeks to maintain the proper conditions to ensure 

complete combustion through one or more of the following operation design 

features: providing sufficient excess air, staged combustion to complete burn out 

of products of incomplete combustion, sufficient residence time, and good mixing. 

All of these factors also tend to reduce emissions of VOC as well as CO. 

However, this process must be optimized with the efforts to reduce NOx 

emissions, which may increase when steps to lower CO are taken. 

Catalytic Oxidation 

Catalytic oxidation is the technology that has been used to obtain the most 

20 
stringent control level for CO from natural gas-fired turbine combustion units. 

This technology has never been applied to a coal-fired unit. It is evaluated here to 

determine if it could be considered transferable technology for application to the 

proposed pulverized coal-fired boilers. In this alternative, a catalyst would be 

situated in the flue gas stream to lower the activation energy required to convert 

products of incomplete combustion (CO and VOC) in the presence of oxygen (O2) 

to carbon dioxide and water. The catalyst permits combination of the reactant 

species at lower gas temperatures and residence times than would be required for 

uncatalyzed oxidation. 

The catalyst would have to be located at a point where the gas temperature is 

within an acceptable range. The effective temperature range for CO oxidation is 

between 600 /F and about 1,000 /F. Catalyst non-selectivity is a problem for 

sulfur containing fuels such as coal. Catalysts promote oxidation of SO2 to SO3 as 

well as CO to CO2. The amount of SO2 conversion is a function of temperature 

and catalyst design. Under optimum conditions, formation of SO3 can be 

minimized to 5% of inlet SO2. This level of conversion would result in a large 

collateral increase in H2SO4 emissions which aside from the increased ambient air 

impacts, could result in unacceptable amounts of corrosion to the fabric filter 

particulate collector, air preheater, ductwork and stack. 

The applicant contacted an oxidation catalyst system vendor to determine the 

technical feasibility of installing this system on a coal-fired boiler. Due to the high 

particulate loading of the flue gas, variable trace element concentration in the flue 

gas and the SO2 loading before air pollution control systems, the vendor stated that 

they could not provide a catalyst system for coal-fired applications. Consequently, 

the applicant has determined that oxidation catalyst systems are considered 

technically infeasible for application to the proposed coal-fired boilers. 

Proposed Pulverized Coal-Fired Boiler BACT for CO 

Sithe has proposed, and EPA’s analysis supports, that the only practical or 

demonstrated in practice measure to control CO from coal-fired boilers is good 

combustion practices. Combustion control, and the resulting optimized emission 

rate to minimize formation of CO while also minimizing NOx, therefore represents 

BACT for the proposed boilers. BACT for CO from the proposed Facility is 0.10 

lb/MMBTU. This level is consistent with or lower than recent permits for new 

coal-fired boilers. 

2. Auxiliary Boilers 

The Desert Rock Energy Facility includes three small distillate oil-fired auxiliary 

boilers with heat input capacities of approximately 86.4 MMBTU/hour. Total 

21 
annual fuel use in the three boilers will be limited to 142,560 MMBTU/year, which 

is equivalent to an average of 550 hours/year per boiler at full load. A BACT limit 

for CO emissions of 0.036 lb/MMBTU and the annual total fuel restriction of 

142,560 MMBTU/year are proposed for these boilers, which reflect the lowest 

emission limits listed in EPA’s RACT/BACT/LAER Clearinghouse. After 

reviewing the submitted materials, EPA concurs with the applicant and proposes 

BACT for CO from the auxiliary boilers to be an emission limit of 0.036 

lb/MMBTU and a fuel limit of 142,560 MMBTU/year. 

3. Emergency Diesel Engines 

The project includes two emergency diesel generators (1,000 kW each) and two 

diesel generator powered firewater pumps (180 kW each). The diesel engines will 

not be operated for more than 100 hours/year each. The applicant proposes a 

BACT emission limit for these diesel engines of 0.5 g/hp-hr and a limitation of 100 

hours of operation per year (each). After reviewing the submitted materials, EPA 

agrees and proposes BACT for CO from the emergency diesel engines to be a limit 

of 0.5 g/hp-hr and a limit of 100 hours of operation per year per engine. 

D. Volatile Organic Compounds (VOC) 

1. Pulverized Coal-Fired Boilers 

VOCs are also emitted from coal-fired boilers as a result of incomplete combustion 

of the fuel. Control of incomplete combustion is accomplished in the same way 

CO emissions are controlled: by providing adequate fuel residence time and high 

temperature in the combustion zone to ensure complete combustion. 

VOC emissions from coal-fired boilers are a function of oxygen availability 

(excess air), flame temperature, residence time at flame temperature, combustion 

zone design, and turbulence. All coal-fired boilers identified utilize front-end 

methods such as combustion control wherein VOC formation is suppressed within 

the boiler. All listings in EPA’s RACT/BACT/LAER Clearinghouse for coal-fired 

boilers utilize combustion control techniques for VOC. While gas-fired 

combustion turbines have been widely equipped with oxidation catalyst control 

technology, this technology is not easily applied to coal-fired boilers. 

A review of EPA's RACT/BACT/LAER Clearinghouse, and the applicant's review 

of recent permit decisions, indicates levels of VOC control which may be achieved 

for pulverized coal-fired boilers. Emission levels and control technologies have 

been identified and ranked in Table 6. 

22 
Table 6 

VOC Control Technologies for Pulverized Coal Boilers 

Pulverized Coal Control 

Technologies 

Emission Rate 

(lb/MMBTU) 

Technical Feasibility for 

Pulverized Coal-Fired Boilers 

Combustion Controls 0.002 - 0.01 Yes 

Oxidation Catalyst Not determined May not be feasible 

Combustion Control 

Combustion control refers to controlling emissions of VOC through the design and 

operation of the boiler in a manner so as to limit VOC formation. In general, a 

combustion control system seeks to maintain the proper conditions to ensure 

complete combustion through one or more of the following operation design 

features: providing sufficient excess air, staged combustion to complete burn out 

of products of incomplete combustion, sufficient residence time, and good mixing. 

All of these factors also have the by-product of reducing the emissions of CO. 

Pulverized coal-fired boilers are designed specifically for efficient fuel combustion 

with thorough mixing and residence time at temperature, plus staged combustion. 

The applicant believes that this level of combustion control represents BACT for 

the proposed boilers. 

Add-On Emission Controls 

Catalytic oxidation and other add-on controls are not applicable to coal-fired 

boilers as discussed in the CO BACT section above. 

Proposed Pulverized Coal-fired Boiler BACT for VOC 

Sithe has proposed, and EPA’s analysis supports, that the only practical or 

demonstrated in practice measure to control VOC emissions from coal-fired boilers 

is good combustion. Combustion control, and the resulting optimized emission 

rate to minimize formation of VOC while also minimizing NOx, therefore 

represents BACT for the proposed boilers. Sithe is proposing a VOC BACT limit 

of 0.003 lb/MMBTU, which is lower than the lowest emission rate in recent 

permits for new coal-fired boilers. 

23 
2. Auxiliary Boilers 

The project includes three small distillate oil-fired auxiliary boilers with heat input 

capacities of approximately 86.4 MMBTU/hour. Total annual fuel use in the three 

boilers will be limited to 142,560 MMBTU/year, which is equivalent to an average 

of 550 hours/year per boiler at full load. The applicant proposes BACT for VOC 

emissions from the auxiliary boilers to be an emission limit of 0.0024 lb/MMBTU 

and a total fuel restriction of 142,560 MMBTU/year based on EPA’s 

RACT/BACT/LAER Clearinghouse. After reviewing the submitted materials, 

EPA concurs with the applicant and proposes BACT for VOC from the auxiliary 

boilers to be an emission limit of 0.0024 lb/MMBTU and a fuel limit of 142,560 

MMBTU/year. 

3. Emergency Diesel Engines 

The project includes two emergency diesel generators (1,000 kW each) and two 

diesel generator powered firewater pumps (180 kW each). The diesel engines will 

not be operated for more than 100 hours/year each. The applicant proposes a 

BACT emission limit for these diesel engines of 0.3 g/hp-hr and an operating 

restriction of 100 hours per year (each) for VOC from these units. After reviewing 

the submitted materials, EPA agrees and proposes BACT for VOC from the 

emergency diesel engines to be a limit of 0.3 g/hp-hr and a limit of 100 hours of 

operation per year per engine. 

E. Particulate Matter 

1. Pulverized Coal-Fired Boilers 

The composition and amount of particulate matter emitted from coal-fired boilers 

are a function of firing configuration, boiler operation, coal properties and 

emission controls. Particulate matter will be emitted from the pulverized coal-fired 

boilers as a result of entrainment of incombustible inert matter (ash) and 

condensable substances such as acid gases. Both particulate matter (PM), and 

particulate matter smaller than 10 micrometer diameter (PM10) require the 

application of BACT under the Federal PSD program. Particulate matter is total 

filterable particulate matter as determined by EPA Method 5 or 17. PM10 includes 

filterable particulate matter smaller than a 10 micrometer diameter as determined 

by EPA Method 201 or 201A and condensable particulate matter as determined by 

EPA Method 202. 

A review of EPA's RACT/BACT/LAER Clearinghouse indicates several levels of 

particulate control that may be achieved for pulverized boilers. Emission levels 

and control technologies have been identified and ranked in Table 7. There are 

24 
almost 50 coal-fired boilers listed in the EPA's BACT/LAER Clearinghouse with 

emission limits for filterable particulate matter that are less than or equal to 0.02 

lb/MMBTU. All but one of these listings report that a fabric filter is utilized (the 

AES Puerto Rico facility is the only exception). The control of PM using fabric 

filtration is clearly demonstrated for coal-fired boilers. Wet control techniques 

(venturi or other high-energy scrubbers), on the other hand, do not represent a 

recently applied or demonstrated control technique for coal-fired boilers and do not 

offer more stringent levels of control of particulate matter than fabric filters. 

Table 7 

Particulate Control Technologies for Pulverized Coal Boilers 

Pulverized Coal Control 

Technologies 

Typical Emission Rate 

(lb/MMBTU) 

Technical Feasibility for 

Pulverized Coal-Fired Boilers 

Fabric Filter 0.01 - 0.02 Yes 

Electrostatic Precipitator 0.015 - 0.025 Yes 

High Energy Wet Scrubber Not determined No applications for recent 

coal-fired boilers 

Note: Emission levels represent steady-state values at base load, for front-half (filterable) 

only. 

Fabric Filter 

Fabric filters are widely used for particulate control from PC boilers and are 

capable of over 99% control efficiency. According to EPA’s Fabric Filter Fact 

sheet (EPA, 2000), “flue gas is passed through a tightly woven or felted fabric, 

causing PM in the flue gas to be collected on the fabric by sieving and other 

mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with a 

number of the individual fabric filter units housed together in a group. Bags are 

most common type of fabric filter. The dust cake that forms on the filter from the 

collected PM can significantly increase collection efficiency. Fabric filters are 

frequently referred to as baghouses because the fabric is usually configured in 

cylindrical bags. Bags may be 6 to 9 m (20 to 30 ft) long and 13 to 31 centimeters 

(cm) (5 to 12 inches) in diameter. Groups of bags are placed in isolatable 

compartments to allow cleaning of the bags or replacement of some of the bags 

without shutting down the entire fabric filter. 

The advantages of fabric filters include: 

1) High collection efficiency for a broad range of particle sizes; 

25 
2) Flexibility in design (various methods of cleaning methods and filter 

media); 

3) Wide range of volumetric capacities; 

4) Reasonable pressure drops and power requirements; and 

5) Handles a wide range of solid materials. 

Some disadvantages of fabric filters are as follows: 

1) Danger of explosion in the presence of a spark; or catastrophic bag damage 

due to fire; and 

2) Wet particles can agglomerate on a filter cloth if the waste gases are at a 

temperature close to their dew point. 

Proposed Pulverized Coal-fired Boiler BACT for Particulate Matter 

Fabric filters and electrostatic precipitators (ESP’s) represent technically feasible 

options for the control of particulate matter from coal-fired boilers. Wet control 

techniques (scrubbers), on the other hand, do not represent a demonstrated control 

technique and do not offer more stringent levels of control of particulate matter 

than fabric filters or ESP’s. ESP’s are generally less effective at controlling fine 

particulate, and are generally incapable of any additional control of other pollutants 

such as acid gases or mercury, and are not considered to represent the top level of 

available control technology. 

Based on numerous projects using fabric filters, Sithe has proposed to use a fabric 

filter as BACT to limit PM emissions to 0.010 lb/MMBTU. In addition, Sithe 

proposes to limit total PM10 (including condensable PM10) emissions to 0.02 

lb/MMBTU. Very little data are available on condensable PM10 emissions from 

coal-fired boilers burn western coal, and for that reason Sithe has proposed a 

condensable PM10 limit of 0.02 lb/MMBTU as BACT for total PM10, but requests a 

trial period of three years to determine the feasibility of this exceptionally low 

limit. The proposed PM emission rate is lower than the lowest emission level for a 

new coal fired boiler (Wygen 2 in Wyoming) listed in EPA’s RACT/BACT/LAER 

Clearinghouse or the other reference materials discussed in the BACT analysis for 

NOx and SO2. 

EPA’s independent review of the materials supports Sithe’s analysis that proposed 

BACT for PM emissions from the coal-fired boilers is a fabric filter with an 

emission limit of 0.01 lb/MMBTU. In addition, EPA is proposing BACT for total 

26 
PM10 emissions to be a fabric filter with an emission limit of 0.02 lb/MMBTU. 

However, EPA does not believe that a three year trial period of the 0.02 

lb/MMBTU emission limit is warranted. EPA believes that the feasibility of the 

0.02 lbMMBtu emission limit can be determined during the first 18 months of 

operation and will propose an 18 month trial period commencing upon initial 

startup. 

2. Auxiliary Boilers 

The project includes three small distillate oil-fired auxiliary boilers with heat input 

capacities of approximately 86.4 MMBTU/hour. Total annual fuel use in the three 

boilers will be limited to 142,560 MMBTU/year, which is equivalent to an average 

of 550 hours/year per boiler at full load. The applicant is proposing BACT limits 

for PM and PM10 based on the use of very low sulfur distillate oil, the total annual 

fuel limitation of 142,560 MMBTU/year, and EPA emission factors published in 

AP-42 and EPA’s RACT/BACT/LAER Clearinghouse. For PM, BACT for the 

auxiliary boilers is the annual fuel limitation, the use of 0.05% sulfur distillate oil, 

and an emission limit of 0.014 lb/MMBTU based on the EPA emission factor of 2 

lb/1000 gal. For PM10, BACT includes an emission limit of 0.024 lb/MMBTU 

based on adding the condensable PM10 emissions of 0.01 lb//MMBTU (1.3 

lb/1,000 gal based on AP-42) to the PM emission rate. After reviewing the 

submitted materials, EPA concurs and proposes BACT for PM emissions from the 

auxiliary boilers to be an emission rate 0.014 lb/MMBTU, the use of 0.05% sulfur 

distillate oil, and an annual fuel limitation of 142,560 MMBTU/year. For PM10, 

EPA is proposing BACT to be an emission limit of 0.024 lb/MMBTU, the use of 

0.05% sulfur distillate oil, and an annual fuel limitation of 142,560 MMBTU/year. 

3. Emergency Diesel Engines 

The project includes two emergency diesel generators (1,000 kW each) and two 

diesel generator powered firewater pumps (180 kW each). The diesel engines will 

not be operated for more than 100 hours/year each. The applicant proposes that 

BACT emission limits include the 100 hour per year (each) operating restriction, 

and limits of 0.19 g/hp-hr and 0.22 g/hp-hr PM and PM10, respectively, based on 

EPA emission factors in AP-42. After reviewing the submitted materials, EPA 

concurs and proposes BACT for PM and PM10 from the emergency diesel engines 

to be emission limits of 0.19 g/hp-hr and 0.22 g/hr-hr respectively and an operating 

limit of not more than 100 hours/year per engine. 

4. Material Handling Sources 

Sithe has proposed that its material handling sources will be controlled by dust 

suppression systems, enclosures and/or fabric filters. For example, conveyors will 

be constructed of enclosed design in order to eliminate wind-blown dust emissions. 

27 
Conveyors will lead to transfer towers, bunkers or silos that will include a “coal 

drop”. Such structures will also be of enclosed design and will be evacuated (when 

operating) through fabric filter units, sometimes referred to as “bin vent filters”. 

Enclosed design of materials handling system and evacuation through bin vent 

filters represents BACT for material handling equipment. 

In addition, coal handling systems will be subject to NSPS Subpart Y and 

limestone handling systems will be subject to NSPS Subpart OOO. A review of 

the EPA RACT/BACT/LAER Clearinghouse gives a range of control efficiencies 

from baghouses. Although the most recent permits for coal fired power plants, 

Bull Mountain and Roundup Power Projects, determined that BACT was 0.01 

gr/dscf for all sources, the Mid America permit identified 0.005 gr/dscf for 

baghouses associated with coal sources and 0.01 gr/dscf for other material handling 

activities. The applicant proposes to also specify these filterable PM/PM10 

emissions limits of 0.005 gr/dscf for coal and 0.01 gr/dscf for limestone and other 

materials. 

The applicant also pointed out that as a mine-mouth power plant, the Desert Rock 

Energy Facility will avoid fugitive dust emissions associated with rail unloading 

operations and active on-site storage piles. The inactive storage pile will be 

covered with soil, geotextile or chemical crusting agents to prevent both 

weathering of the coal and fugitive dust emissions. When coal is added to or 

reclaimed from the inactive pile, which is expected to be very infrequently, the coal 

will be wetted and/or treated with chemical agents to minimize any emissions of 

fugitive dust. The Applicant believes that these operational measures, and those of 

the NSPS for coal handling operations (Subpart Y), represent BACT for inactive 

storage and associated coal handling operations. After reviewing the submitted 

materials, EPA concurs and proposes as BACT for PM/PM10 from materials 

handling sources that all conveyors, transfer towers and silos be enclosed and vent 

to a fabric filter with emission limits of 0.005 gr/dscf for coal and 0.01 gr/dscf for 

limestone and other materials. In addition, the inactive coal storage pile will 

covered with soil or other crusting agents and when coal is added or reclaimed it 

will be wetted and/or treated with chemical agents to minimize fugitive dust 

emissions. 

F. Sulfuric Acid Mist (H2SO4) 

1. Pulverized Coal-Fired Boilers 

Emissions of sulfuric acid mist are generated in fossil fuel-fired sources from the 

oxidation of sulfur present in the fuel. The amounts of sulfur or SO2 that are 

oxidized to sulfuric acid mist may be affected by trace metal catalysis. 

In addition to applying BACT, the applicant recognizes that sulfuric acid mist is a 

28 
precursor to the formation of regional haze, and for this reason is proposing to 

include active control of sulfuric acid mist in the design of the Desert Rock Energy 

Facility. As a result, an additional stage of acid gas removal using hydrated lime (a 

proprietary technology) has been included upstream of the fabric filter to remove 

sulfuric acid mist before it enters the wet scrubber. The application of this 

technology will result in emission levels lower than those permitted for 

Thoroughbred (with an add-on WESP), and represents a sulfuric acid mist 

emission rate of 0.004 lb/MMBTU. After reviewing the submitted materials, EPA 

concurs and proposes BACT for sulfuric acid mist from the PC boilers to be the 

use of hydrated lime injection and an emission limit of 0.004 lb/MMBTU. 

2. Auxiliary Boilers and Diesel Generators 

No control alternatives beside the use of very low sulfur fuels have been identified 

for controlling emissions of sulfuric acid mist from industrial boilers or emergency 

diesel generators. BACT for sulfuric acid mist for the proposed auxiliary boilers 

and emergency diesel engines is the use of low sulfur (0.05% S) distillate oil. 

After reviewing the submitted materials, EPA agrees and proposes BACT for the 

control of sulfuric acid mist from the auxiliary boilers and the emergency diesel 

generators to be the use of distillate fuel oil with a sulfur content less than 0.05%. 

G. Hydrogen Fluoride (HF) 

Emissions of hydrogen fluoride are generated in fossil fuel-fired sources from the 

oxidation of fluorine present in the fuel. For the PC boilers, the same proprietary acid gas 

pre-control technology proposed for the control of sulfuric acid mist will control hydrogen 

fluoride emissions through the injection of hydrated lime before the fabric filter, with 

additional removal expected from the wet limestone scrubbing. The applicant is proposing 

a hydrogen fluoride emission rate of 0.00024 lb/MMBTU based on an assumed 

concentration of fluorine in the coal of 100 ppm (estimated 98% control) as BACT. This 

emission rate is consistent with or lower than all recent BACT decisions. 

No appreciable HF is emitted from distillate oil-fired industrial auxiliary boilers or 

emergency diesel engines, and the use of low fluorine bearing fuel (very low sulfur 

distillate oil) represents BACT for HF for these emission sources. After reviewing the 

submitted materials, EPA concurs and proposes BACT for emissions of hydrogen fluoride 

to be the use of hydrated lime injection and an emission limit of 0.00024 lb/MMBTU. 

H. Lead (Pb) 

Emissions of lead are generated in fossil fuel-fired sources from the impurities present in 

the fuel. Since lead is emitted as solid particulate from coal-fired boilers, it is already 

included in the PM and PM10 emission rates selected as BACT. BACT for lead emissions 

from the proposed PC boilers is the control of PM emissions using fabric filtration 

29 
(baghouse), and the emission limits determined to represent BACT for PM10. 

For distillate oil-fired industrial auxiliary boilers and emergency diesel engines, the use of 

low ash fuel such as distillate oil represents BACT. 

I. Summary of BACT Emission Levels 

The BACT levels determined through this evaluation for the Desert Rock Energy Facility 

are summarized in Tables 8 thru 11. 

Table 8 

Summary of Proposed BACT Emission Limits for Pulverized Coal Boilers 

Pollutant Emission Limit 

(lb/MMBTU) 

Control Technology 

NOx 0.06, 24-hour average Low NOx Burners and SCR 

SO2 0.06, 24-hour average Low sulfur western coal, hydrated 

lime injection before the fabric filter, 

and wet limestone desulfurisation 

CO 0.10, 24-hour average Good combustion practices 

VOC 0.003, 3-hour average Good combustion practices 

PM 0.01, 6-hour average Baghouse 

PM10 0.02, 6-hour average Baghouse 

H2SO4 0.004, annual average Low sulfur western coal, hydrated 

lime injection before the fabric filter, 

and wet limestone desulfurisation 

HF 0.00024, annual average Hydrated lime injection before the 

fabric filter, and wet limestone 

desulfurisation 

Pb 0.00020, quarterly Baghouse 

Note: EPA test methods require that the emission limits in the permit for H2SO4, HF, and Pb be 

measured as 3-hour averages. 

30 
Table 9 

Summary of Proposed BACT Emission Limits for the Auxiliary Boilers 

Pollutant Emission Limit 

(lb/MMBTU) 

Control Technology 

NOx 0.10, 3-hour average Low NOx Burners 

SO2 0.05, 3-hour average Low sulfur distillate fuel (0.05%) 

CO 0.036, 3-hour average Good combustion practices 

VOC 0.0024, 3-hour average Good combustion practices 

PM 0.01, 3-hour average Low sulfur distillate fuel oil and 

good combustion practices 

PM10 0.024, 3-hour average Low sulfur distillate fuel oil and 

good combustion practices 

H2SO4 0.00087, annual average Low sulfur distillate fuel (0.05%) 

Notes: 1) PM is defined as filterable particulate matter as measured by EPA Method 5. 

2) PM10 is defined as solid particulate matter smaller than 10 micrometers diameter as measured 

by EPA Method 201 or 201A plus condensable particulate matter as measured by EPA Method 202. 

Because PM10 includes condensable particulate matter and PM does not include condensable 

particulate matter, PM10 emissions are higher than PM emissions. 

Table 10 

Summary of Proposed BACT Emission Limits for the Emergency Generators 

Pollutant Emission Limit 

(lb/MMBtu) 

Control Technology 

NOx 6.5 g/hp-hr Ignition timing retard, turbo-charging and aftercooling 

SO2 0.19 g/hp-hr Low sulfur distillate fuel (0.05%) 

CO 0.5 g/hp-hr Good combustion practices 

VOC 0.3 g/hp-hr Good combustion practices 

PM/PM10 0.24 g/hp-hr Low sulfur distillate fuel oil and good 

combustion 

H2SO4 0.006 g/hp-hr Low sulfur distillate fuel (0.05%) 

31 
Table 11 

Summary of Proposed BACT Emission Limits for the Materials Handling System 

Pollutant Emission Limit 

(lb/MMBTU) 

Control Technology 

PM/PM10 0.005 gr/dscf (filterable) for coal 

handling baghouses and 0.01 

gr/dscf (filterable) for other 

materials 

Enclosures, dust suppression, and 

fabric filters 

J. Circulating Fluidized Bed Technology 

Normally, for each pollutant being regulated in a PSD permit, EPA evaluates control 

technologies through a “top-down” BACT determination process for each unit at the 

facility that emits the regulated pollutant (see Section VI above). However, EPA is 

comparing the emissions from Circulating Fluidized Bed Technology (CFB) separately 

because an applicant must choose either a pulverized coal boiler or CFB for all pollutants. 

Therefore, EPA in this permitting evaluation is comparing the two technologies separately. 

Table 12 

Range of Emissions Control from Coal Combustion Technologies 

Coal Technology Efficiency (%) % NOx Controlled % SO2 Removed 

Sub-critical PC 34 to 37% 90% (add-on) 92 to 96% (add-on) 

Super-critical PC 39 to 45% 90% (add-on) 92 to 96% (add-on) 

CFB 34 to 37% 50 to 80% 75 to 92% 

Notes: CFB control efficiencies are dependent on sorbent activity and injection rates. 

CFB suspends crushed coal in upward flowing air and a “bed” of inert solids, enhancing the 

turbulent mixing of the air with the coal. In a CFB, the average temperature within the 

combustion zone can be maintained at less than 2,000 degrees F, while contact with 

fluidized solids can increase combustion reaction rate and heat transfer. This technology 

was first introduced to efficiently utilize a wide variety of off-spec, variable or waste fuels 

and also as a way to decrease inherent pollutant emissions. In a CFB, NOx formation is 

limited by maintaining low temperatures (1,600 /F to 2,000 /F) within the combustion 

zone. The hot cyclone of the CFB is an ideal location for injection of ammonia (called 

selective non-catalytic reduction) for additional NOx control. A sulfur-adsorbing reagent, 

32 
such as limestone or dolomite, is added to the bed which can achieve a 90-92% capture of 

SO2 within the CFB boiler process itself. Efficiencies for standard atmospheric circulating 

fluidized bed combustion units range from 36 to 38%. 

The most recent atmospheric CFB plants currently operating include: 

A Tractebel Red Hills in Choctaw, MS (operating since mid 2001) 

A First Energy Bay Shore power plant in Oregon, OH (operating since May, 2000) 

A AES Warrior Run in Cumberland, MD (operating since February, 2000) 

A AES Guayama, PR (operating with very low SO2 limits) 

A JEA Northside (an earlier generation Foster Wheeler unit) 

The majority of support systems for fluidized bed boilers are very similar to pulverized coal 

operations; however, CFB technology has inherent advantages in flexibility to utilize low 

grade fuels and, as a result, may have lower fuel costs relative to other coal technologies 

because they are able to burn less expensive fuels. CFBs have long been considered “Clean 

Coal” technology due to the inherent limitation of emissions of SO2 and NOx from within 

the process itself, without the need for add-on pollution control equipment. Disadvantages 

include limited unit size (about 300 MW maximum), somewhat more complex equipment 

and operations, and the generation of large quantities of lime-rich dry CFB residue solid 

waste. 

The conclusions and concerns regarding CFB technology that were expressed in Sithe’s 

supplemental analysis are listed below: 

• Five or six CFB units would be required instead of two pulverized coal boilers to 

achieve the planned Desert Rock power output. The loss of economy of scale 

would significantly increase the capital and operational costs of a CFB plant. 

• On a lb/MMBTU basis, most emissions from a CFB plant would be similar to or in 

some cases higher than the proposed Facility’s emissions. 

• Sithe estimates the heat rate for a CFB plant would be about 9,950 Btu/kWh while 

the heat rate for Desert Rock is 8,792 Btu/kWh (net, higher heating value basis). 

For the same net electricity production and emission rates, a CFB plant would 

generate 11% more emissions than Desert Rock. 

• On an annual ton/yr basis, all emissions from a CFB plant would be higher than the 

proposed Facility’s emissions due to the higher heat rate. 

33 
Table 14 

Proposed Desert Rock Emission Comparison to a New CFB Plant 

Parameter Desert Rock CFB Units Comments 

Average heat rate 8,792 9,775 Btu/kWh Sub-critical CFB. Supercritical CFBs are under 

development. 

SO2 emission rate 0.060 0.0576 lb/MMBTU Sevier Power October 12, 

2004 permit limits SO2 

emissions to 0.05 

lb/MMBTU as a 24-hr 

average and 0.022 

lb/MMBTU as a 30-day 

average. Desert Rock 

design fuel contains 2.62 

times as much sulfur on a 

lb/MMBTU basis. 

SO2 emissions 2,998 3,258 tons/yr 1,366 net MW, 95% 

capacity factor 

NOx emission rate 0.060 0.10 lb/MMBTU Sevier Power October 12, 

2004 permit. 

NOx emissions 2,998 5,656 tons/yr 1,366 net MW, 95% 

capacity factor 

PM10 emission rate 0.010 0.010 lb/MMBTU Filterable PM10 only, no 

condensable PM10 data 

are available. Filterable 

PM emissions from a 

baghouse will be similar 

for both combustion 

technologies. 

PM10 emissions 500 566 tons/yr 1,366 net MW, 95% 

capacity factor 

VOC emission rate 0.0030 0.005 lb/MMBTU 

VOC emissions 150 283 tons/yr 1,366 net MW, 95% 

capacity factor 

CO emission rate 0.10 0.10 lb/MMBTU 

CO emissions 4,997 5,656 tons/yr 1,366 net MW, 95% 

capacity factor 

34 
Sulfuric acid mist 

emission rate 

0.0040 0.0063 lb/MMBTU Sevier Power October 12, 

2004 permit limits H2SO4 

emissions to 0.0024 

lb/MMBTU as a 24-hr 

average. Desert Rock 

design fuel contains 2.62 

times as much S on a 

lb/MMBTU basis. 

Sulfuric acid mist 

emissions 

200 356 tons/yr 1,366 net MW, 95% 

capacity factor 

Note: EPA is aware of permit that was recently proposed by EPA Region 8 for Deseret Power that 

contains emission rates slightly lower than the above for SO2 and NOx. 

After reviewing the submitted materials, as well as our own coal-fired boiler databases, 

EPA concludes that CFB is not an appropriate technology for this project and will result in 

higher emissions than the Facility as proposed. 

K. Integrated Gasification Combined Cycle Technology 

Consideration of Integrated Gasification Combined Cycle (IGCC) technology, as an 

alternative to a pulverized coal fired boiler, has not been included in Step 1 of the BACT 

analyses above, since IGCC would be redefining the source. In preparing the draft permit, 

EPA did consider whether IGCC is a BACT option, but concluded it is not because it 

would fundamentally change the basic design of the proposed source. Prior to reaching this 

conclusion, EPA did, however, request detailed information from Sithe regarding whether 

or not IGCC would be technically feasible using Navajo Nation coal from the BHP mine. 

Correspondence from Sithe on this topic has been included in the Administrative Record 

for this permit action. 

VII. AIR QUALITY IMPACTS 

The PSD regulations require an air quality analysis to determine the impacts of the 

proposed project on ambient air quality. For all regulated pollutants emitted in significant 

quantities, the analysis must consider whether the proposed Facility will cause a violation 

of (1) the National Ambient Air Quality Standards (NAAQS), and (2) the applicable PSD 

increments. A discussion of the general approach, air quality model selection, significant 

impact levels, PSD increment consumption, and the project’s compliance with ambient air 

quality standards is presented below. 

EPA’s conclusion is that Sithe used appropriate modeling procedures and followed 

applicable guidance documents demonstrating that the proposed project will not violate any 

NAAQS or PSD increment, and will not have an adverse impact on any Air Quality Related 

Value (AQRV) at any Class I area. 

35 
In summary, the proposed Facility’s impact will be well below the significant impact level 

for NO2 and CO. The proposed Facility’s impact will exceed the significant impact level 

for SO2 and PM10, thereby triggering a cumulative impact analysis. The cumulative impact 

analysis Sithe submitted, however, demonstrated that the proposed Facility will not cause 

or contribute to an exceedance of the SO2 or PM10 NAAQS or PSD increments. The 

proposed Facility will not exceed the NAAQS for lead (Pb). Finally, the proposed Facility 

will not have a significant impact on acid deposition at any Class I area, or on the acidneutralizing capacity of sensitive lakes. Sithe provided substantial additional modeling in 

response to requests from the Federal Land Managers (FLMs) to address potential concerns 

about visibility impacts at Class I areas. The FLMs did not find that the proposed Facility 

will result in an adverse impact on visibility in the Class I areas. 

A. Meteorological and Background Ambient Air Quality Data 

The ambient impact analysis required Sithe to provide representative meteorological data as 

an input into the air quality model. Recently, EPA updated its Guidance to allow applicants 

to use three years of prognostic meteorological data (i.e., data from a weather model), 

providing a full three-dimensional wind field, in lieu of data collected from one fixed 

station. This kind of data is a necessary input to the chosen air quality model, CALPUFF 

(see below). Sithe originally used data from RUC2 ("Rapid Update Cycle"), a National 

Weather Service model that incorporates data from many sources, including regular 

weather stations, NEXRAD radar stations, and satellites. After consultation with and 

concurrence by the National Park Service, Sithe updated the modeling using data from the 

MM5 meteorological model at a higher spatial resolution. CALMET is a preprocessor that 

prepares the meteorological fields for input to CALPUFF by incorporating local weather 

observations, and also local terrain effects on the wind flow. Various CALMET input 

options for accomplishing this, such as radius of influence of observation stations, were 

provided by the National Park Service (NPS). These approaches meet EPA Guidance 

requirements for meteorological data. 

Sithe was also required to provide representative background air quality data. For the 

NAAQS compliance analysis, Sithe added background concentration to modeled 

concentrations, and compared the total to the NAAQS. To determine the background 

concentration, Sithe used the closest monitors to the site of the proposed Facility which are 

22-24 km away in Farmington, New Mexico for SO2, NOx, PM10, and O3 and 136 km 

away in Rio Rancho, New Mexico for CO. EPA has determined that these monitors will 

record higher background concentrations of pollutants than we would expect closer the 

DREF site because Farmington and Rio Rancho have much greater residential and 

commercial activity than the project site on the Navajo Nation. We have also determined 

that the Farmington and Rio Rancho monitors are regionally representative because they 

record the multi-day buildup of pollutants in the general Four Corners area which is 

important since pollution tends to mix throughout the basin over several days. The 

background data recorded by the Farmington and Rio Rancho monitors is used only to add 

to the modeled impact for comparison to the NAAQS, and not for comparison to the PSD 

36 
increments. The information from the monitors and Sithe’s modeling demonstrates that the 

total project impact, including background, will be at most 44% of the NAAQS. 

B. Modeling Methodology 

The model recommended by the Federal Land Managers (FLMs) for analyzing impacts on 

Class I areas, which are typically rather distant, is CALPUFF. EPA guidance also 

recommends the use of CALPUFF in near-field Class II analyses if there are complex 

winds, for which the standard plume models ISCST3 or AERMOD would be inadequate. 

In CALPUFF, the individual puffs composing a plume may follow independent paths, 

which is a much more realistic simulation than the single straight line plume assumed in 

ISCST3 and AERMOD. As shown by Sithe, the area surrounding the site for the proposed 

Facility is subject to complex winds. The varying strengths of competing regional flows 

and the more local upslope / downslope flows driven by solar heating mean that flow 

reversals can occur. This condition is exacerbated by the complex terrain in the area and its 

non-uniform slopes. Multi-day stagnation is also an issue. These conditions can be 

handled by CALPUFF, but not by the standard plume models. Therefore, Sithe’s choice of 

CALPUFF for the Class II analysis as well as the Class I analysis is correct and provides 

consistency with the approach required for Class I areas. 

In addition to the meteorological inputs discussed above, an air quality model needs inputs 

characterizing emissions sources. Sithe modeled the proposed Facility’s emissions at their 

proposed maximum allowable emission rates. Sithe’s approach guarantees a conservative 

air quality assessment meaning that the assessment will predict higher impacts than will 

occur. (For example, for the 3-hour SO2 NAAQS, Sithe modeled the main stack at 50% 

higher than the proposed PSD permit’s allowable 24-hour average maximum, i.e. Sithe 

modeled the SO2 emissions at 0.09 lb/MMBtu although the proposed PSD permit will only 

allow the Facility to emit SO2 at 0.06 lbs/MMBtu). Sithe chose to model the proposed 

Facility’s emissions conservatively to account for short-term variability that might occur 

during any 24-hour period. Sithe also used inputs for the proposed Facility’s stack height, 

temperature, and exit velocity, which determine the plume's buoyancy and momentum, and 

hence the emissions’ distance from the ground. Because these factors vary with the work 

load of the source, Sithe performed load screening, which is an estimate of impacts under 

different load conditions, with the SCREEN3 model, and then with CALPUFF itself. Sithe 

then used the worst case scenario, assuming 100% load, for the rest of the modeling. 

EPA recognizes that nearby buildings can cause plume downwash, leading to high pollutant 

concentrations. Sithe used the model option to simulate this effect for the proposed 

project's auxiliary boilers, diesel generators and fire pumps. Sithe did not use this model 

option for the main stacks of the two proposed pulverized coal fired boilers, because Sithe 

has proposed to construct a stack that will be sufficiently tall to avoid downwash. Sithe’s 

proposed stack height of 917 feet was determined through a Good Engineering Practice 

(GEP) stack height analysis, using the BPIP software EPA provides for that purpose. The 

procedures that Sithe followed meet EPA guidelines. 

37 
The final inputs are the locations, or receptors, at which the model will compute pollutant 

concentrations. Sithe followed good receptor placement procedures that are in accordance 

with EPA guidelines. This procedure includes a set of receptors out to 50 km from the 

source, which is standard for Class II area analyses, but Sithe also included additional sets 

of receptors that are progressively more closely spaced nearer the source, and also fence 

line receptors. Sithe used dense receptor grids in areas with potentially high impacts, i.e. 

hillsides where plume impaction can occur. Other sets of receptors are prescribed by the 

FLMs for each Class I area; all 15 Class I areas within 300 km of the proposed Facility 

were modeled. Finally, receptors were modeled at 26 distant sensitive Class II areas, such 

as National Historic Parks, Wilderness Areas, and National Monuments; while these are not 

Class I areas, they are of special concern to the FLMs. 

The proposed Facility’s modeled impacts are shown in Table 15 and 16 below. The PSD 

regulations do not allow a project to make a "significant" contribution to a violation of the 

NAAQS or of the PSD increment. That is, the applicant must show that its own impact is 

below the Significant Impact Level (SIL), or else show that there is no violation at locations 

where its impact is above the SIL. The proposed Facility’s impact does not exceed the SIL 

for NO2 and CO, which demonstrates the proposed Facility’s compliance with the NAAQS 

and PSD increment for those pollutants. 

The proposed Facility’s modeled impacts from PM10 and SO2 exceeded the SIL, triggering 

the requirement for a cumulative analysis for those two pollutants. Sithe’s cumulative 

analysis demonstrated that the proposed Facility would remain well below the NAAQS and 

PSD Class II increment. 

For Class I areas, Sithe's modeling showed that the emissions from the Facility could 

potentially have an impact on an Air Quality Related Value (AQRV). Specifically, Sithe's 

modeling indicated that the Facility's emissions would result in greater than 5% extinction 

of visibility on at least 1 day at 11 of the surrounding 15 Class I areas. The FLMs requested 

Sithe to perform additional modeling. Sithe performed several rounds of additional 

modeling to evaluate if the Facility's emissions would have an adverse impact on Class I 

area visibility. On April 25, 2006, the United States Forest Service (USFS) sent a letter to 

EPA referring to a "mitigation strategy" that Sithe had proposed to the FLMs. The USFS 

letter indicated that Sithe's performance of the mitigation strategy would be sufficient to 

alleviate its concerns about visibility. The USFS letter requested EPA to include the 

mitigation strategy in Sithe's PSD permit so that Sithe's proposal would be federally 

enforceable. EPA had subsequent discussions with the FLMs to explain EPA's preference 

for the mitigation strategy to remain in a side agreement between Sithe and the FLMs rather 

than in Sithe's PSD permit. We understand that Sithe and the FLMs are continuing to 

discuss appropriate mechanisms other than the PSD permit to memorialize Sithe's 

commitment to perform the mitigation strategy. Accordingly, EPA has concluded it is 

appropriate to propose approval of the PSD permit while Sithe and the FLMs continue to 

discuss memorializing Sithe's commitment to perform the agreed upon mitigation strategy. 

38 
Table 15 

Maximum Predicted Air Quality Impacts from the Proposed Project 

Pollutant Averaging 

Period 

Modeled 

Impact 

SIL 

(ug/m3) 

PSD Class II 

Increment 

(ug/m3

) 

NAAQS 

(ug/m3) 

NOx Annual 0.56 1 25 100 

SO2 3-hour 271.2 25 512 1300 

24-hour 23.6 5 91 365 

Annual 0.41 1 20 80 

PM10 24-hour 27.73 5 30 150 

Annual 1.75 1 17 50 

CO 1-hour 1375.7 2000 N/A 40000 

8-hour 465.2 500 N/A 10000 

Pb Quarterly 0.0028 N/A N/A 2 

Note: For 3-hour averages, an SO2 emission rate of 0.09 lb/MMBTU was assumed to 

account for short term variability. 

Table 16 

Maximum Predicted Air Quality Impacts from the Project at Class I Areas 

Pollutant and Averaging Time 

Class I Area 

NOx SO2 PM10 

Annual 3-hour 24-hour Annual 24-hour Annual 

Arches NP 0.0021 0.720 0.172 0.008 0.062 0.004 

Bandelier NM 0.0074 1.268 0.273 0.017 0.092 0.006 

Black Canyon of the 0.0026 0.929 0.180 0.008 0.050 0.003 

Gunnison NM 

Canyonlands NP 0.0045 1.479 0.476 0.013 0.184 0.005 

Capitol Reef NP 0.0010 0.711 0.159 0.005 0.072 0.002 

39 
Grand Canyon NP 0.0003 0.447 0.127 0.002 0.053 0.001 

Great Sand Dunes NM 0.0018 0.547 0.147 0.006 0.050 0.002 

La Garita WA 0.0028 0.761 0.151 0.007 0.053 0.003 

Mesa Verde NP 0.0261 4.706 0.790 0.044 0.263 0.016 

Pecos WA 0.0041 0.690 0.190 0.011 0.068 0.004 

Petrified Forest NP 0.0008 0.939 0.212 0.004 0.091 0.002 

San Pedro Parks WA 0.0169 2.379 0.533 0.030 0.187 0.011 

Weminuche WA 0.0086 1.803 0.270 0.017 0.093 0.007 

West Elk WA 0.0016 0.722 0.173 0.006 0.049 0.002 

Wheeler Peak WA 0.0028 0.727 0.092 0.008 0.046 0.003 

Proposed Class I SIL 0.1 1.0 0.2 0.1 0.3 0.2 

PSD Class I Increment 2.5 25.0 5.0 2.0 8.0 4.0 

Note: Bold values indicate predicted values above the proposed Class I Significant Impact 

Levels. 

C. NAAQS Compliance 

As discussed above in general, to show NAAQS compliance, Sithe performed cumulative 

analyses for PM10 and SO2 by including the emissions of nearby sources. Sithe used data 

on source allowable emissions from State emission inventories where available, and Sithe 

supplemented this data by using EPA's National Emissions Inventory (NEI). Sithe used a 

"distance rule", agreed upon with EPA and the NPS, to simplify the cumulative analyses 

and allow for reasonable model run times. For SO2, if a source's emissions in tons per year 

are less than 0.8D, where D is distance in km, then it is deemed small enough to omit from 

the modeling. The 0.8 in the rule was suggested by NPS and is based on past modeling 

work and experience showing that the impact of such small and distant sources to be 

negligible. A 40 tpy source would be omitted only if it were 50 km or more away, which 

illustrates the conservativeness of the distance rule used by Sithe. 

The results of the cumulative NAAQS analyses are shown in Table 17 below. The results, 

including the monitored background concentration, are less than half the NAAQS in every 

case. Sithe has thus demonstrated compliance with all the NAAQS. 

40 
Table 17 

Predicted Cumulative Air Quality Impacts on the NAAQS 

Pollutant Averaging 

Period 

Modeled 

Impact 

(ug/m3) 

Background 

Concentrations 

(ug/m3) 

Total Impact 

(ug/m3) 

NAAQS 

(ug/m3) 

SO2 3-hour 403.56 6.2 409.7 1300 

24-hour 98.3 6.2 104.5 365 

PM10 24-hour 8.55 20 28.5 150 

Annual 1.9 20 21.95 50 

Note: For the cumulative analysis, because of the way the NAAQS are defined, the second 

highest predicted concentration is compared to the NAAQS level. Thus some 

values in this table may be lower than in Table 15, where the first high is used, to 

provide a more conservative assessment of whether the Facility has any impacts 

above the SIL. 

D. Increment Consumption Analysis 

The cumulative analysis for PSD increment, which is discussed generally above, is more 

complicated than the analysis for the NAAQS, because not all emissions "count" toward, or 

consume, increment. EPA’s regulations provide that the only emissions changes that 

consume increment are those emissions that have occurred since the "baseline date". The 

reason for this provision is that the PSD program is aimed at the preventing the significant 

deterioration of the air quality in an area relative to the baseline conditions of that area. In 

addition, emissions decreases in the same area expand or increase the available increment, 

because the emissions decreases tend to improve air quality relative to the baseline date of 

the area. 

For the PSD increment analysis, Sithe used State databases for much of the required data. 

Sithe also used a conservative procedure (i.e. likely to overestimate emissions) to simplify 

the analysis for major sources. Sithe’s procedure assumed that all of the emissions at major 

sources, with two exceptions discussed below, consumed increment, regardless of when the 

emissions began to occur relative to the baseline date. PSD increment consumption is 

based on changes in actual emissions (not maximum allowable emissions), of which 

records are kept. Continuous Emissions Monitors (CEMs) in the stack of each major source 

are required under various regulatory programs, such as the Acid Rain Program. EPA, 

therefore, provided Sithe with nearby sources' maximum actual emission rates that were 

representative of their normal operation. 

In some cases, the PSD increment analysis is more complicated than that needed in this 

41 
case. For example, the emissions from minor sources are often omitted or undercounted in 

State databases. That potential problem is not present for this permitting action because the 

area surrounding the site of the proposed Facility is sparsely populated, and has relatively 

little commercial or industrial activity or growth. Therefore, this issue is not of concern for 

Sithe’s Class II increment analysis. For the Class I increments, Sithe agreed to a much 

larger modeling domain encompassing all Class I areas within 300 km. EPA and Sithe 

consulted with the State air agencies of the Four Corners States of Arizona, Colorado, New 

Mexico, and Utah. In each case, based on general knowledge of the areas, minor source 

permitting programs, and previous studies of the status of the increment, State regulators 

concluded that minor source growth had a negligible impact on the PSD increment. Thus, 

EPA has determined that emissions from minor sources and the potential for minor source 

growth will not have any effect on either the Class II or Class I increment analysis. 

A second potentially complicating factor for PSD increment analysis is that the "baseline 

date" may be different for different areas, because the baseline date is triggered by the 

issuance of the first major source permit in each area. This means that each source could 

have different fractions of its emissions count toward increment depending on which Class 

I area was being evaluated; in the worst case this would require different combinations of 

emissions estimates and different modeling runs for every Class I area. Sithe, however, 

handled this issue by applying the conservative procedure mentioned above, which assumes 

that all emissions at each major source consume increment regardless of baseline date. 

This procedure is considered conservative because it overestimates potential emissions. 

Sithe applied two exceptions to this conservative procedure. The two nearest major sources 

of emissions to the site of the proposed Facility are the Four Corners Power Plant (FCPP), 

and the San Juan Generating Station (SJGS). FCPP is 22 km away from the site of the 

proposed Facility and SJGS is 35 km away. Both FCPP and SJGS have reduced their 

emissions substantially in the past two decades by installing pollution control equipment 

and improving operations. The emissions reductions from FCPP and SJGS have expanded 

the available increment in the area surrounding the site of the proposed Facility, leaving 

more of the increment available. Although some of the emissions reductions from FCPP 

and SJGS were required by EPA to remedy SO2 NAAQS violations monitored in the 1970s, 

the actual reductions were far greater than required to cure the NAAQS violation. 

EPA provided Sithe with the emission rates promulgated in 46 FR 43152-43154 (Aug. 27, 

1981) and 46 FR 30653-30654 (June 10, 1981), for FCPP and SJGS that were required for 

attainment of the SO2 NAAQS. Sithe then modeled only the emissions reductions from 

FCPP and SJGS that went beyond those required for NAAQS attainment. 

The results of the cumulative PSD increment analysis are shown in the table below. The 

results, including the monitored background concentration, are well below the Class I and 

Class II increments where they are respectively applicable. Sithe has thus demonstrated 

compliance with the PSD increments. 

42 
Table 18 

Predicted Cumulative Air Quality Impacts on the Class II Increments 

Pollutant Averaging Period Modeled Impact 

(ug/m3) 

Increment 

(ug/m3) 

SO2 3-hour 67.3 512 

24-hour 10.75 91 

PM10 24-hour 8.47 30 

Annual 1.82 17 

Table 19 

Predicted Cumulative Impacts on the Class I SO2 Increments 

Class I Area 

SO2 impacts, μg/m3 

3-hour 24-hour Annual 

Bandelier NM 6.76 2.15 0.054 

Canyonlands NP 6.76 2.15 0.097 

Mesa Verde NP 12.84 2.15 -0.034 

Petrified Forest NP 16.38 3.72 0.374 

San Pedro Parks WA 2.54 0.90 -0.028 

Weminuche WA 3.51 0.45 0.009 

PSD Class I Increment 25 5 2 

Note: Proposed Facility impacts exceeded the proposed Class I Significant Impact Level only for 

SO2, and only at six Class I areas. Negative numbers indicate increment expansion, due to 

emission reductions at FCPP and SJGS. 

VIII. ADDITIONAL IMPACT ANALYSIS 

In addition to assessing the ambient air quality impacts expected from a proposed new 

source or modification, the PSD regulations require that certain other impacts be 

considered. These include impacts on visibility, soils and vegetation, and growth. 

43 
A. Visibility 

Sithe modeled the proposed Facility’s potential impact on visibility and other AQRVs, 

which are defined by the FLM for each Class I area. As mentioned above, Sithe conducted 

several rounds of additional modeling, after extensive consultations on modeling 

procedures with the FLMs. 

The "Federal Land Managers' Air Quality Related Values Workgroup (FLAG) Phase I 

Report" (USFS, NPS, US F&WS, December, 2000), also known as the "FLAG document" 

prescribes procedures for assessing impacts on Class I areas. Sithe followed the FLM’s 

recommended procedures for using CALPUFF along with the post-processing program 

CALPOST, for assessing acid deposition impacts and regional haze impacts. The modeled 

sulfur and nitrogen deposition were below the FLMs' "Deposition Analysis Thresholds" 

(DATs) of 0.005 kg/ha (kilograms per hectare). Therefore, the FLMs concluded that 

further analysis was not required and have not made any finding of adverse impact on 

AQRVs related to deposition or visibility. For visibility, see page 38 for a discussion of the 

USFS letter dated April 25, 2006. 

At the request of the USFS, Sithe also performed an analysis of the proposed Facility’s 

effect on the acid-neutralizing capacity (ANC) of 10 lakes in four Class I areas. Using the 

Forest Service screening methodology, which is based on the modeled acid deposition and 

the lakes' size and rainfall, Sithe showed that the proposed Facility’s impacts were below 

the USFS level of concern. 

For assessing regional haze impacts, the FLAG document prescribes a screening procedure 

based on changes in extinction, which is defined as changes in the attenuation of 

transmitted light, per unit distance, caused by the proposed Facility project. CALPUFF 

predictions for sulfate, nitrate, and particulate matter are multiplied by the light extinction 

capacity of each, then the daily averages of the resulting total extinction increase above 

natural background is compared to the 5% level. The 5% level of extinction indicates an 

amount of haze just perceptible to an observer. If the 5% level of extinction is exceeded on 

any day the FLAG document recommends additional analysis to assess whether there is an 

adverse impact. 

Sithe carried out the FLAG screening procedure and found days over the 5% concern level 

at 11 of the 15 Class I areas; six areas had at least one day over 10% extinction. Sithe then 

conducted an additional analysis. The most significant part of this alternative analysis was 

an examination of individual hours within each daily average, to check for times when 

visibility was already naturally obscured by rainy or cloudy weather. Sithe concluded that 

excluding those problematic hours from the averages brings the proposed Facility’s 

emissions impact project back under the 5% level, so that its visibility impacts are 

acceptable. 

Sithe also performed a supplemental analysis to assess the impact of the proposed Facility 

44 
on requirements for progress toward natural visibility conditions. Sithe modeled the 

emission changes at FCPP and SJGS, added the emissions from the proposed Facility and 

evaluated the change in visibility at Class I areas using the same metric that is used under 

the Regional Haze Rulemaking (extinction improvement in the best 20% and worst 20% of 

the days). This modeling showed that visibility would improve in the area regardless of the 

emissions from the proposed Facility. Sithe’s analysis showed that the resulting visibility 

improvement exceeded the 10% Regional Haze Rulemaking progress requirement through 

2010 (based on a six year period, 10% of the way to the final goal in 2064). In addition, 

Sithe has agreed to perform additional mitigation that will more than offset any potential 

contribution to visibility impairment. 

EPA has concluded that construction and operation of the proposed Facility is consistent 

with the requirements for visibility improvement under the Regional Haze Rule. 

B. Soils and Vegetation 

The PSD regulations require analysis of air quality impacts on sensitive vegetation types, 

with significant commercial or recreational value, and sensitive types of soil. Evaluation of 

impacts on sensitive vegetation were performed by comparing the predicted impacts 

attributable to the project with the screening levels presented in A Screening Procedure for 

the Impacts of Air Pollution Sources on Plants, Soils, and Animals (EPA 1980). 

The modelling analysis showed all impacts to be well below the screening levels. Most of 

the designated vegetation screening levels are equivalent to or less stringent than the 

NAAQS and/or PSD increments, therefore satisfaction of NAAQS and PSD increments 

assures that sensitive vegetation will not be negatively affected. 

C. Growth 

Growth impacts due to the proposed project are not expected to be significant. There will 

be little new growth in the area due to the small work force (200-225 employees) expected 

during plant operation. The emissions associated with the workforce will be primarily the 

result of motor vehicle exhaust emissions associated with the commute of workers to and 

from the plant site. 

IX ENDANGERED SPECIES 

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. § 1536, and its 

implementing regulations at 50 C.F.R. Part 402, EPA is required to ensure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued existence 

of any endangered species or threatened species or result in the destruction or adverse 

modification of such species’ designated critical habitat. EPA has determined that this PSD 

permitting action triggers ESA Section 7 consultation requirements. EPA is therefore 

required to consult with the U.S. Fish and Wildlife Service (FWS) and/or the National 

45 
Marine Fisheries Service (NMFS) if an endangered species or threatened species may be 

present in the area affected by the permit project and EPA’s action (i.e., permit issuance) 

may affect such species. EPA is also required to confer with the Services on any action 

which is likely to jeopardize the continued existence of any species proposed for listing (as 

endangered or threatened) or result in the destruction or adverse modification of habitat 

proposed to be designated as critical for such species. 

When a Federal action involves more than one agency, consultation and conference 

responsibilities may be fulfilled through a lead agency pursuant to 50 CFR § 402.07. Since 

the land, electrical transmission lines, and access roads required for the proposed project 

are located on the Navajo Indian Reservation and lands under the jurisdiction of the Bureau 

of Indian Affairs (BIA), the BIA will act as the lead Federal agency for purposes of 

fulfilling the responsibilities under Section 7 of the ESA for the project. 

EPA may proceed with the final permit issuance upon conclusion of consultation, review of 

FWS’s Biological Opinion, and our determination that issuance of the permit will be 

consistent with the ESA requirements. 

X. NATIONAL HISTORIC PRESERVATION ACT (NHPA) 

Section 106 of the NHPA requires responsible Federal officials to take into account the 

effects of their decisions on historic properties eligible for the National Register of Historic 

Places, and consult with appropriate State or Tribal Historic Preservation Officers and other 

interested parties to avoid, reduce, or mitigate any identified adverse effects. The applicant 

has retained a consultant to conduct cultural resource studies to support Section 106 

consultations. On 17 February 2004, the consultant contacted the Navajo Nation Tribal 

Historic Preservation Officer (THPO) to provide initial notification about the proposed 

Facility, inform him of the purpose of the project, and briefly describe the elements of the 

project. As a follow up to the initial contact, the applicant is prepared to work with the BIA 

in consulting with the Navajo Nation THPO about defining the area of potential effect, 

identifying other potentially interested parties who should be involved in the consultations, 

and developing an appropriate strategy to inventory and evaluate cultural resources that 

could be affected. 

XI. TITLE IV (ACID RAIN PERMIT) 

The applicant must apply for and obtain an acid rain permit. The applicant will apply for 

this permit prior to facility operation. 

XII. ENVIRONMENTAL JUSTICE 

On February 11, 1994, Executive Order 12898, “Federal Actions to Address Environmental 

Justice in Minority Populations and Low-Income Populations,” was signed. EPA defines 

environmental justice as the fair treatment and meaningful involvement of all people 

46 
regardless of race, color, national origin, or income with respect to the development, 

implementation, and enforcement of environmental laws, regulations, and policies. EPA 

has this goal for all communities and persons across this Nation. In addition, EPA 

published guidance entitled, “Final Guidance For Incorporating Environmental Justice 

Concerns in EPA's NEPA Compliance Analyses” in April 1998. 

With respect to the proposed Facility, EPA is aware that the public is raising environmental 

justice concerns in the NEPA process. Please see our June 15, 2005 letter which reflects 

our comments on the May 2005 Draft Summary Scoping Report for the Desert Rock 

Energy Project. In this letter, we note that the public has identified five issues of concern. 

These issues are: 

1) Lack of jobs provided to people of Navajo Nation, 

2) Social impacts, 

3) Use of local water sources as disproportionately damaging to local communities, 

4) Disproportionate exposure to pollutants, potential health problems (respiratory, 

heavy metals in fish), and 

5) Impacts without benefits: power goes to other locations and is not distributed 

locally. 

In response to the concerns listed above, EPA is conducting additional outreach on the PSD 

aspects of the proposed Facility in the form of workshops with Dine translators, radio 

announcements in Dine, and translations of fact sheets in Dine. The applicant has also 

prepared a data presentation to better characterize the issues raised in the NEPA scoping 

effort regarding environmental justice and EPA expects that these issues will be addressed 

through the NEPA process. 

XIII. CONCLUSION AND PROPOSED ACTION 

Based on the information supplied by Sithe, our review of the analyses contained in the 

permit application, and our independent evaluation of the information contained in our 

Administrative Record, it is our determination that the proposed Facility will employ 

BACT and will not cause or contribute to a violation of the NAAQS, or an exceedance of 

PSD increments. Therefore, EPA is proposing to issue Sithe a PSD permit for the Facility, 

subject to the PSD permit conditions specified herein. This permit is subject to review and 

comments. A final decision on issuance of the permit will be made by EPA after 

considering comments received during the public comment period and upon completion of 

the ESA consultation process. 

47