AMBIENT AIR QUALITY IMPACT REPORT 

(NSR 4-4-4, SAC 87-01-A) 

This document serves as the Statement of Basis and Ambient Air Quality Impact Report for the 

proposed PSD permit for the Sierra Pacific Industries - Loyalton facility. This document 

describes the legal and factual basis for the proposed permit per 40 CFR 124.7, including 

requirements under the PSD regulations at 40 CFR 52.21. 

I. Applicant 

Sierra Pacific Industries 

Railroad Avenue 

Post Office Box 208 

Loyalton, California 96118 

II. Project Location 

The project is located on Railroad Avenue, in the town of Loyalton, Sierra County, 

California. This facility is located in the Northern Sierra Air Quality Management 

District and lies within the Mountain Counties Air Basin. 

The nearest Federal Class I area is the Desolation Valley Wilderness Area, located 43.7 

miles to the south. 

III. Project Description 

Sierra Pacific Industries (SPI) is seeking an amendment to the Prevention of Significant 

Deterioration (PSD) permit issued in 1987 by the U.S. Environmental Protection Agency 

(EPA). The proposed project is the amendment of permit conditions for the cogeneration 

facility contained in Prevention of Significant Deterioration permit number NSR 4-4-4, 

SAC 89-01. The Applicant proposes to increase emission limits and averaging times of 

nitrogen (NOx) and carbon monoxide (CO). No change in the construction of the boiler 

is proposed. 

The cogeneration facility includes a Riley spreader-stoker boiler for the combustion of 

wood fuel and production of steam, a turbine generator for converting the energy of 

steam into electrical energy, a fuel handling and storage area, and an ash handling 

facility. 

A. Wood-fired Riley Boiler 

The boiler system consists of a Riley conventional membrane water wall, woodfired (335.7 MMBtu per hour), water cooled stationary pin-hole grate, and 
pneumatically-assisted stoker fired, steam boiler. The boiler has combustion trim, 

superheater, air heater, and economizer and has a rated production capacity of 

200,000 1bs/hr of process steam at 850 psig and 900°F. The boiler is fueled 

solely with wood residues and has a maximum fuel feed rate of 41.9 tons per hour 

at 55% moisture content. 

B. Turbine Generator 

The turbine generator system consists of a 20 MW turbine generator designed for 

a maximum throttle flow of 200,000 lb/hr. Process steam is extracted from the 

turbine at two points at varying pressures and quantities depending on the load 

factor. The maximum combined extraction rate is 65,000 lb/hr, and the maximum 

combined extraction pressures are 50 and 150 psig. Extracted steam is used to 

supply process heat to deaerator tank, feedwater heater, and air ejectors. 

The remaining process steam completes its route through the turbine to be 

condensed in a tube and sheet condenser. The condensate returns to the boiler. 

Cooling water is circulated in loop between the cooling tower, the condenser, and 

several air and oil cooling devices. 

C. Fuel Handling and Storage 

Wood residue (fuel) is received by truck from various sources and unloaded by 

the existing on-site truck unloader. The fuel is transferred to a temporary outdoor 

fuel storage pile by a loader or pusher. As needed, it is transferred by the same 

equipment to the fuel house where it is then conveyed into the boiler. The 

fuelhouse is designed to provide a 54-hour supply of fuel to the boiler. 

D. Ash Handling 

Operation of the power generating facility will result in the production of bottom 

and fly ash. Bottom ash is collected in an enclosed hopper/conveyor at the front 

of the boiler. Classifiers separate the unburned carbon from the fine 

noncombustible fly ash. The carbon is re-injected into the furnace for complete 

burning and the ash is transferred via screw conveyors to the ash conveyor. The 

quenched and dewatered ash is hauled via enclosed truck to the nearby county 

sanitary landfill or other approved sites. 

E. Wood Fuel Supply 

The Riley boiler utilizes agricultural residues, including but not limited to rice 

hulls, in-forest residues from logging and chipping operations, and urban wood 

wastes from private and municipal landfills. 

Scientific and industrial experiences in the use of wood for the generation of 

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electricity and steam have shown that the properties of wood (e.g., heating value 

and moisture content) vary depending on wood species and environmental 

conditions during growth. Fuel related calculations are based on a typical fuel 

mixture having a heating value of 4005 BTU per pound (wet basis) and a moisture 

content of 55% by weight. These properties determine the quantity of fuel 

required to generate a given amount of energy and are used to establish the 

operating parameters and waste management requirements for the facility. 

F. Emission Controls 

The facility uses emission control systems and techniques for flue gas clean-up 

prior to discharge through an elevated stack. These control measures include the 

following: 

The Riley stoker boiler is equipped with a selective noncatalytic reduction system 

(SNCR) with ammonia injection, as required by EPA, and low excess air with 

staged combustion for the control of nitrogen oxides (NOx) emissions. 

The Riley stoker boiler exhausts through a multiclone to a 3-field electrostatic 

precipitator (ESP) for the control of particulates and particulate matter less than or 

equal to 10 micrometers in diameter (PM10) 

The stoker boiler is equipped with a high-pressure secondary air injection system 

for the control of carbon monoxide (CO) emissions. 

IV. Project Emissions 

Emissions under the Proposed Emission Limits 

Emissions resulting from the combustion of waste wood in the Riley boiler under the 

proposed emission limits have been estimated on the basis of source test and continuous 

emission monitoring (CEMS) data. Estimates of CO and NOx emission rates were based 

on collected stack data. Emission rates for VOC and PM10 were estimated from source 

test and operational data. Lead, which is not typically found in significant quantities in 

wood, has been estimated at zero. No significant amount of any noncriteria pollutant is 

estimated to be emitted from the proposed facility. A summary of the estimated future 

boiler stack emissions from the Riley cogeneration boiler is presented in Table 1. 

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Table 1

Estimated Future Stack Emission for the Riley Boiler 

Pollutant Emission Rate 

(lbs/hr) 

Annual 

Emission Rate (TPY) 

PM10 8.39 (3 hr average) 36.75 

50.75 (8-hr 

average) 

NOx 222.6 

NOx trans: 65.00 

(8-hr average) 

-- 

VOC 6.71 (3-hr average) 29.4 

CO 550 (8-hr average) 2,420.1 

CO trans: 772.42 

(8-hr average) 

-- 

Opacity Max. 20% for any 3 

min. in any 1 hour 

or 30 min in any 24 

hr period 

-- 

Existing Emissions 

Table 2

Estimated Existing Stack Emissions for the Riley Boiler 

Pollutant Emissions1

(lbs/hr) 

Annual Emissions1

(TPY) 

PM10 8.39 36.75 

NOx 36.9 (3-hr average) 161.7 

VOC 6.71 29.4 

CO 167.8 (3-hr average) 735.2 

 1 Emission rates from PSD permit 87-01

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Net Emissions 

When existing emissions are deducted from estimated future emissions from the Riley 

boiler, the net emission increases from the project are as follows: 

Table 3

Net Emission Increases (TPY) 

Source PM10 NOx VOC CO 

Proposed Riley 

Boiler 

36.75 222.6 29.4 2420.1 

Existing Riley 

Boiler 

36.75 161.7 29.4 735.2 

Net Emission 

Increase 

0.0 60.9 0.0 1684.9 

V. Applicability of Prevention of Significant Deterioration (PSD) Regulations 

The Prevention of Significant Deterioration (PSD) regulations (40 CFR 52.21) define a 

major source as any source type belonging to a list of 28 more source categories which 

emits or has the potential to emit 100 tons per year 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 tons per year. The cogeneration 

facility has the potential to emit over 250 tons per year of carbon monoxide and is 

therefore a major source. 

A significant emission increase is defined in the PSD regulations as a potential net 

increase in emissions greater than the threshold prescribed for any pollutant subject to 

regulation. The significant thresholds for the criteria pollutants are listed in Table 4. 

PM10 and SO2 emissions excluded because no increase in permitted emission rates for 

these pollutants is proposed. 

Table 4

PSD Significance Thresholds 

Pollutant Significant Emission 

Rate (TPY) Net Emissions Increase 

(TPY) 

CO 100 1684.9 

NOx 40 60.9 

5
SO2 40 0.0 

TSP 25 0.0 

PM10 15 0.0 

O3 (VOC) 40 of (VOCs) 0.0 

Lead 0.6 0.0 

The proposed project is located in an area for which the NAAQS have not been exceeded 

for any of the criteria pollutants. Therefore, for an existing major source, a PSD review 

would apply to each pollutant showing potential significant net increases in emissions. 

The existing source is a "major" PSD source and the proposed project has potential 

significant net emission increases of fine particulate matter, nitrogen oxides, volatile 

organic compounds, and carbon monoxide. Therefore, a PSD review for these pollutants 

is required as follows: 

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. 

4. Analysis of impact on soils and vegetation. 

VI. Best Available Control Technology (BACT) 

In accordance with the PSD regulations, Sierra Pacific Industries must apply best 

available control technology (BACT) to control emission of NOx and CO from their 

Riley boiler. BACT is defined in the Clean Air Act Amendments of 1977 as ".. .an 

emission limitation based on the maximum degree of reduction of each pollutant subject 

to regulation under the Act ..., on a case-by-case basis, taking into account energy, 

environmental and economic impacts." Under environmental impacts, our review 

includes the impact from both regulated and unregulated pollutant that might be affected 

by the choice of control technology. 

A. BACT Review Process 

In accordance with 40 CFR 52.21(j), a new or modified major stationary source is 

required to apply BACT for each regulated NSR pollutant that it would have the potential 

to emit (PTE) in significant amounts. BACT is defined as “an emission limitation 

(including a visible emission standard) based on the maximum degree of reduction of 

each pollutant subject to regulation under [the] Act ... which the Administrator, on a case6
by-case basis, taking into account energy, environmental, and economic impacts, and 

other costs, determines is achievable for such source.” 40 CFR 52.21(b)(12). In no event 

may application of BACT result in emissions of any pollutant which would exceed 

emissions allowed by any applicable New Source Performance Standards (NSPS) under 

40 CFR Part 60 or National Emission Standard for Hazardous Air Pollutants (NESHAP) 

under 40 CFR Part 61. EPA outlines the process it will use to do this case-by-case 

analysis (referred to as “top-down” BACT analysis) in a June 13, 1989 memorandum. 

The top-down BACT analysis is a well-established procedure that the Environmental 

Appeals Board (EAB) has consistently considered as guidance in adjudicating PSD 

permit appeals. See, e.g., In re Knauf, 8 E.A.D. 121, 129-31 (EAB 1999); In re Maui 

Electric, 8 E.A.D. 1, 5-6 (EAB 1998). 

In brief, the top-down process provides that all available control technologies be ranked 

in descending order of control effectiveness. The PSD applicant first examines the most 

stringent technology. That technology is established as BACT unless it is demonstrated 

that technical considerations, or energy, environmental, or economic impacts, justify a 

conclusion that the most stringent technology is not achievable for the case at hand. If the 

most stringent technology is eliminated, then the next most stringent option is evaluated 

until BACT is determined. 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 the 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 stringent technology not rejected based on 

technical, energy, environmental, and economic considerations. 

B. NOx BACT Analysis 

NOx is generated when combustion temperatures are high enough for the nitrogen in the 

combustion air or bound in the fuel to combine with oxygen to form NO. Depending 

upon conditions, some portion of the NO will react to form NO2. 

1. Identification of Possible Control Alternatives 

There are a variety of options available for controlling NOx emissions from 

combustion sources. Some options involve combustion controls that reduce NOx

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formation, while others utilize add-on control devices to remove NOx after it is 

formed. 

Combustion controls reduce NOx emissions by controlling the combustion 

temperature and the availability of oxygen. Combustion air containing both nitrogen 

and oxygen can combine in a high temperature environment to form thermal NOx. 

The oxidation of nitrogen that is chemically bound in fuel sources can also form what 

is called fuel-bound, or “prompt,” NOx. Dry low-NOx (DLN) burners control thermal 

NOx formation by avoiding high temperature combustion zones and uneven oxygen 

distribution. This is accomplished by burner designs that carefully control the mixing 

of fuel and combustion air. Generally, use of DLN burners in association with wood 

combustion requires a wall-fired furnace and pulverized wood fuel that is burned in 

suspension with coal or natural gas. 

Proper combustion generally refers to computerized control of the amount of flue gas 

recirculation (FGR), the fuel feed rate, and the amount of over- or under-fire 

combustion air in the furnace. This type of control is common on boilers constructed 

in the last few decades. Add-on controls such as selective catalytic reduction (SCR) 

and selective non-catalytic reduction (SNCR) systems are widely used technologies 

for controlling NOx emissions from combustion sources. In the SCR process, 

ammonia in some form (anhydrous, aqueous, or in urea) is mixed with the exhaust 

from the combustion device and the mixture is passed through a catalyst bed. The 

NOx reacts with the ammonia aided by the catalyst to form nitrogen and water. An 

SCR system applied to a biomass-fired boiler would typically require exhaust reheat, 

because cooling occurs in the particulate matter control device employed to reduce 

catalyst plugging, and the gas temperature must be increased to promote the reaction. 

Regenerative SCR (RSCR) systems have been developed recently to make 

application of an SCR system to a biomass-fired boiler more economical by using a 

regenerative ceramic bed to recover heat from the reheated flue gases. It should be 

noted that there is no existing natural gas service in the Loyalton, California area, so 

any exhaust reheat system would be fired using trucked-in propane or distillate oil. 

The SNCR process is similar to SCR in that a reagent reacts with NOx to form 

nitrogen and water, although no catalyst is used to aid the reaction. The catalyst used 

in SCR systems allows the reactions to occur at lower temperatures than is possible in 

SNCR systems (450 oF for SCR as opposed to 1,550 oF for SNCR). The reagent, 

which, as for SCR, can be urea, aqueous ammonia, or anhydrous ammonia, is 

typically vaporized and mixed with hot flue gas from the combustion device. 

SCONOx is similar to SCR, except that NOx in the exhaust stream reacts with 

potassium carbonate (K2CO3) to form potassium nitrate (KNO3). This compound is 

reacted with hydrogen to form gaseous nitrogen (N2), and regenerate the K2CO3. The 

lower exhaust temperature limit required for the reactions in the SCONOx to take 

place is less than that of SCR (300 oF as opposed to 450 oF). The SCONOx system is 

also said to control carbon monoxide (CO) by oxidation. 

8
Table 8 summarizes NOx control technologies. 

2. Control Alternative Review 

The results of the database queries and permit investigations for NOX control 

technologies are presented in Table 5, sorted by permit limit, beginning with the NOX

limit proposed for the boiler. 

The following technologies were found to control NOX from biomass-fired boilers: 

• Proper combustion 

• SNCR 

• SCR 

• RSCR 

The database queries did not produce any instances of NOx emissions from biomassfired boilers controlled by DLN burner, SCR, or RSCR systems. According to the 

Applicant, there is at least one SCR system, and at least two RSCR systems being 

used to control NOX emissions from biomass-fired boilers that are not identified in the 

RBLC database. Sauder Woodworking in Archbold, Ohio operates two 57 

MMBtu/hr boilers fired with wood waste from furniture making operations. After an 

ESP removes particulate matter from the exhaust stream, an SCR system removes 

NOX. The permitted NOX limit for each of the boilers at Sauder Woodworking is 0.20 

lb/MMBtu, which is higher than the proposed emission limit for SPI’s new 

cogeneration unit. 

The most recent biomass-fired boiler BACT determination in the RBLC was made by 

the Florida Department of Environmental Protection (FDEP) for the U.S. Sugar 

Corporation’s Clewiston Sugar Mill and Refinery. FDEP determined that 0.31 

lb/MMBtu was BACT for NOX emissions from a 738 MMBtu/hr bagasse and wood 

chip-fired boiler employing combustion controls. The most recent NOX BACT 

determination for a biomass-fired boiler with a firing rate similar to the cogeneration 

unit at the Loyalton facility was issued by the Minnesota Pollution Control Agency 

for Koda Energy’s Shakopee facility, which determined that 0.25 lb/MMBtu was 

BACT for NOX emissions from a 309 MMBtu/hr combined heat and power biomass 

boiler employing a low- NOX burner, over-fire air and SNCR. 

There are several instances of biomass-fired boilers using DLN burner technology to 

limit the amount of NOX generated during combustion. Coen manufactures the Dual 

Air Zone (DAZ) Scroll burner, which can be used to fire pulverized wood along with 

some natural gas (approximately ten percent of total heat input). These burners have 

generally been installed in units with less than 100 MMBtu/hr heat input, and require 

that the fuel be reduced to approximately 1/32 of an inch in size. With some flue gas 

9
recirculation and staged combustion, a NOX emission rate of 0.35 lb/MMBtu at the 

furnace exit has been achieved. 

RSCR systems have been added to control NOX emissions from existing wood-fired 

boilers at Boralex – Stratton Energy in Stratton, Maine, Bridgewater Power in 

Bridgewater, NH, and Whitefield Power & Light in Whitefield, New Hampshire. All 

three of these systems were retrofitted onto existing boilers to qualify under their 

state’s Renewable Portfolio Standards. 

a. Summary of Possible Control Alternatives 

Based on literature and database searches the following alternatives were found to 

control NOX emissions from a biomass-fired boiler: 

• Proper combustion 

• DLN burner 

• SCR 

• RSCR 

• SNCR 

• SCONOx 

b. Technical Feasibility of Control Alternatives 

Most of the control alternatives described in the previous section have been 

shown to be technically feasible for controlling NOX emissions from biomass-fired 

boilers. Several of the alternatives have either not been applied to biomass-fired 

boilers, or have been applied to boilers with significantly lower heat input than 

that currently proposed by SPI in Loyalton.. 

Proper Combustion

Proper combustion refers to the application of state-of-the-art design and 

appropriate operation of a combustion unit. Current design biomass-fired massburner-type boilers can generally achieve NOX emission rates of 0.20 to 0.30 

lb/MMBtu when operated in the manner recommended by the boiler designer and 

manufacturer. Proper combustion is a common and technically feasible 

technology for controlling NOX emissions from biomass-fired boilers. 

DLN Burner

In a DLN burner, the fuel would be burned in suspension using wall-mounted 

burners, which would be a significant departure from SPI’s proposed boiler 

design, which uses three combustion fuel cells positioned below the boiler. DLN 

burners are designed to limit the amount of fuel-bound nitrogen that is converted 

to NOx during combustion, and are generally suited to boilers that burn wood 

waste containing a high percentage of resins, such as the waste from medium 

density fiberboard (MDF), plywood, or veneer operations. 

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SNCR

Ammonia-injection nozzles can be positioned at the furnace exit and use the 

relatively high temperatures there to promote the reaction of NOx and ammonia. 

SNCR system design is often incorporated into the overall boiler design, and can 

be located at the furnace exit because SNCR systems do not rely on a catalyst 

which is subject to plugging from particulate matter in the flue gases. The 

relative simplicity of SNCR systems makes them technically feasible, and has 

resulted in them becoming the most popular add-on NOx control technology for 

biomass-fired boilers. 

SCR and RSCR

An SCR system used to control NOx emissions from a biomass-fired boiler has 

been demonstrated to control NOx emissions to 0.20 lb/MMBtu on two 57 

MMBtu/hr boilers (the Sauder Woodworking boilers). RSCR systems have been 

applied to 220 MMBtu/hr (Whitefield), 250 MMBtu/hr (Bridgewater), and 672 

MMBtu/hr (Boralex – Stratton) wood-fired boilers. Both SCR and RSCR systems 

are considered technically feasible for controlling NOX emissions from a biomassfired boiler. Because RSCR controls NOx as effectively as an SCR system, and is 

more economical because of the heat recovery feature, only RSCR systems will 

remain in consideration from this point forward. 

SCONOx

To date, SCONOx (now called EMx) has been designed and used only on smallto medium sized natural gas-fired stationary turbines for demonstration purposes. 

The technology has never been applied to a biomass-fired boiler. Also, the 

SCONOx system is sensitive to sulfur in the exhaust, which can degrade the 

performance of the system. While wood fuels are not generally considered highsulfur fuels, the AP-42 SO2 emission factor for wood-fired boilers is 0.025 

lb/MMBtu, which is equivalent to about 7.2 lb/hr of SO2. Natural gas, the 

combustion fuel most commonly associated with SCONOx applications, has 

maximum sulfur limit of one grain per 100 standard cubic feet (gr/scf) of gas in 

California, where SCONOx has been applied. On a heat input basis, this is 

equivalent to an SO2 emission rate of 0.43 lb/hr. The sensitivity to sulfur, 

combined with a lack of comparable existing applications suggests that SCONOx

is technologically infeasible as a control technology for controlling NOx emissions 

from a biomass-fired boiler. 

The following is a list of the technically feasible NOx control technologies and 

possible combinations: 

• Proper combustion 

• SNCR 

• RSCR 

• DLN burner 

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c. Effectiveness of Remaining Technologies 

This section describes the remaining technologies in more detail and ranks them 

by effectiveness. 

Proper Combustion

A modern biomass-fired boiler furnace, operated with computerized controls to 

ensure proper combustion would result in a NOx emission limit of between 0.25 

and 0.3 lb/MMBtu. The boiler design proposed by SPI would emit 0.25 

lb/MMBtu when utilizing only proper combustion techniques to reduce NOX

emissions. Proper combustion is a technically feasible technology for controlling 

NOx emissions from biomass-fired boilers. Proper combustion practices are 

currently being implemented at SPI by a fully computerized digital control system 

and oxygen trim referencing to control fuel/air ratios. 

SNCR

Currently, SNCR systems are the most common add-on control device used to 

reduce NOX emissions from large biomass-fired boilers. SNCR systems rely on 

high temperatures to promote the reaction of NOX with the introduced ammonia. 

As a result, the control system is often incorporated into the boiler design to 

facilitate the introduction of the ammonia as close to the furnace as possible. 

Emission limits of between 0.1 and 0.2 lb/MMBtu have been achieved using 

SNCR systems to control NOx. 

SPI employs an SNCR integral to the boiler design to reduce NOx emissions to 

0.151 lb/MMBtu. A boiler permitted by NESCO in Darrington, Washington with 

a 0.12 lb/MMBtu 24-hour average limit and a 0.1 lb/MMBtu annual average limit 

is unlikely to ever be constructed and may not have consistently achieved that 

limit with an acceptable ammonia slip. Dominion – Pittsylvania Power Station 

(formerly Multitrade of Pittsylvania County, L.P.), in Hurt, Virginia, uses SNCR 

systems to control NOx from three wood-fired boilers and has a permit limit of 0.1 

lb/MMBtu on a 30-day rolling average basis. It should be noted that, while a 0.1 

lb/MMBtu permit limit based on a 30-day rolling average is more stringent than 

the same limit based on an annual average, but can result in higher short-term 

concentrations than a 0.151 lb/MMBtu limit based on a daily or hourly average. 

RSCR

The Sauder boilers to which SCR systems have been applied have emission limit 

of 0.20 lb/MMBtu, which is equivalent to the emission rate of SPI’s proposed 

boiler using only proper boiler design and combustion. The RSCR systems which 

have been applied to existing wood-fired boilers (Boralex – Stratton, 

Bridegewater, and Whitefield) have enabled them to take a quarterly NOX permit 

limit of 0.075 lb/MMBtu to qualify for Renewable Energy Certificates (RECs) 

under Connecticut’s Renewable Portfolio Standard (RPS), although all three 

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facilities have much higher short-term permit limits (0.25 to 0.33 lb/MMBtu on a 

24-hour average basis. When applied to a new boiler of modern design, the 

manufacturer claims an RSCR system could achieve a guaranteed emission limit 

of 0.065 or 0.06 lb/MMBtu. The SPI boiler is over 20 years old. 

DLN Burner

In the current proposed SPI boiler design, which uses three combustion fuel cells 

positioned below the boiler, the emission rate with DLN burners would be 

approximately 0.30 lb/MMBtu, achieved by an uncontrolled mass burner-type 

boiler using fuel cells. Installing DLN burners in the Riley boiler at the Loyalton 

facility would effectively be a redesigning of the entire NOX-control system. DLN 

burners require finely-ground, uniformly-sized fuel. Therefore, additional fuel 

handling and processing equipment would need to be incorporated, requiring the 

Riley boiler to be redesigned, if this control technology were to be employed at 

the Loyalton facility. 

d. Ranking by Effectiveness 

The remaining technologically feasible control technologies ranked in decreasing 

order of effectiveness are: 

• RSCR 

• SNCR 

• Proper combustion 

• DLN burner 

e. Cost-Effectiveness Analysis 

The cost-effectiveness of SNCR and RSCR control systems were calculated. The 

calculations for each system are summarized in Table 6. As shown, SNCR 

provides the lowest cost per ton of NOx removed, and is approximately twice as 

cost effective as RSCR. As shown in Table 6, the cost per ton difference between 

SNCR and RSCR is approximately $3,500 per ton of NOX removed. Based on 

this analysis, SNCR is deemed to be the most cost effective NOx control 

technology for biomass-fired boilers. The applicant has proposed to use the most 

stringent technically feasible option which is also the most cost effective option. 

In addition, the cost for retrofitting an RSCR system onto the Riley boiler at SPI’s 

Loyalton facility to reduce emissions from the currently permitted emission limit 

of 0.151 lb/MMBtu to a hypothetical permit limit of 0.075 lb/MMBtu, matching 

the quarterly average permit limits for Bridgewater Power in Bridgewater, NH 

and DG Energy in Whitefield, NH. The annual cost of adding an RSCR to reduce 

NOx emissions would be in excess of $2 million per year (assuming the capital 

costs were amortized over a 20-year period at 7 % interest), which is equivalent to 

nearly $18,000 per additional ton of NOx removed from the exhaust. There is an 

13
estimated capital cost of $5 million to install an RSCR system. The 0.075 

lb/MMBtu is a voluntary limit, not an enforceable permit limit. The installed 

RSCR systems were retrofitted onto existing boilers to qualify under their state’s 

Renewable Portfolio Standards. Without financial assistance connected with 

RPS, it is questionable whether the 0.075 lb/MMBtu limit can be met. 

3. Selection of BACT for NOx

Based on the analysis presented in this section, SPI proposes that BACT for the 

control of NOx from biomass-fired mass-burner-type boilers is the use of an SNCR 

system combined with proper combustion practices. NOx emissions are limited to 

50.75 lb/hr, or 222.3 tons per year at the anticipated annual average operating 

capacity, which is approximately equivalent to 80 ppm limit of NOx at 12% CO2, 

averaged over a rolling eight-hour period. During transient operation, NOx emissions 

are limited to 65 lbs/hr, or 102 ppm at 12% CO2, averaged over 8 hours, for periods 

aggregating to no more than 100 hours per year 

C. CO BACT Analysis 

Carbon monoxide (CO) is a product of the chemical reaction between carbonaceous fuels 

and oxygen. In fuel-rich mixtures, CO occurs as the product of combustion. In fuel-lean 

mixtures CO can result due to poor mixing of fuel and air in the combustion zone (so the 

sub-region is fuel-rich) or because of very high temperatures in the combustion zone 

(above 1,727 °C), which causes dissociation of CO2 into CO (Wark and Warner, 1981). 

1. Identification of Possible Control Alternatives 

Similar to NOX, the technology options available for controlling CO emissions 

from combustion sources include combustion controls and add-on control devices. 

CO combustion controls promote more complete oxidation to limit CO emissions, 

rather than discouraging the formation of the pollutant as for NOX, and instead of 

the reduction reaction used to eliminate NOX, CO add-on controls seek to oxidize 

CO to CO2 after it has left the combustion area. Combustion controls are intended 

to maximize CO2 formation through adequate fuel residence time, proper fuel-air 

mixing, and maintaining temperatures that ensure complete oxidation. 

Designs that minimize CO emissions generally experience increased NOx

emissions. While biomass-fired boiler designs of the 1970s and 1980s strove to 

balance these competing factors, ore modern designs, recognizing the relative 

lower cost of add-on NOx controls (i.e., SNCR) compared to add-on CO controls 

(i.e., oxidation catalysts), sacrifice greater NOX emissions for reduced CO 

emissions. A combustion unit designed to either balance CO and NOx emissions 

or favor reduced CO emissions is commonly referred to as having “proper 

combustion control” when combined with appropriate operation. 

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The only add-on technology used in practice to control CO emissions from 

combustion sources in general are catalytic oxidizers that use a matrix or “bed” 

coated with noble metals (e.g., platinum) to facilitate the conversion of a criteria 

pollutant to a non-pollutant (in this case, CO to CO2). Catalytic oxidizers used for 

CO control typically operate in a temperature range of approximately 500 o

F to 

1,000 oF. 

In some cases, fuel use must be increased to maintain the CO-to-CO2 conversion 

efficiency, which falls off rapidly at lower temperatures. For solid fuel units such 

as biomass-fired boilers, a particulate control system (e.g., an electrostatic 

precipitator) must be located before the catalyst bed in the exhaust system in order 

to reduce catalyst masking and pressure drop across the oxidizer. The higher 

temperature exhaust passing through the particulate control device requires a 

physically larger control system to accommodate the higher volume than would 

be needed for a typical installation where the particulate control is located just 

before the stack. Even with a particulate control device located upstream of the 

catalyst, a steam injection system is typically used to periodically remove 

particulate matter from the catalyst, and relatively frequent replacement of the 

catalyst (compared to combustion units firing gaseous or liquid fuels) is required. 

SCONOx (described in the NOx BACT analysis) also utilizes a catalytic technique 

that oxidizes CO to CO2 in addition to controlling NOx emissions. 

Table 9 summarizes CO control technologies. 

2. Control Alternative Review 

The results of the database queries for CO control technologies are presented in 

Table 7, sorted by permit limit, beginning with the CO limit proposed for the 

project. The following technologies were found in the databases searched for 

controlling CO from biomass-fired boilers: 

• Oxidation Catalyst 

• Proper Combustion 

The majority of biomass-fired boilers use proper combustion to limit CO 

emissions. There are two instances where permits have been issued for woodfired boilers using catalytic oxidation to limit CO emissions. One of these boilers 

is no longer operating, and the other has not been constructed. Boilers with 

permit limits below 0.30 lb/MMBtu generally have some detail that differentiates 

them from “normal” mass-burner type biomass-fired boilers. Examples of these 

differences include: consistently available high heat-value-per-weight fuel 

sources, co-firing with fossil fuels, and lenient or nonexistent NOx and/or 

ammonia slip limits that allow operation at higher temperatures that limit CO 

formation. 

15
a. Summary of Possible Control Alternatives 

Based on literature and database searches the following control alternatives 

are possible for the boiler: 

• Proper combustion 

• Catalytic oxidation 

• SCONOx 

b. Technical Feasibility of Control Alternatives 

Proper combustion is the technique most commonly used to limit CO 

emissions from biomass fired boilers, and the existing unit incorporates a 

design that was common at the time it was originally permitted. Modifying 

the combustion unit design to decrease CO emissions (and likely increase NOx

emissions) would require an increase in the height of the boiler to extend the 

residence time of the exhaust gases, which is technically infeasible. 

The first instance of a catalytic oxidation system applied to a biomass-fired 

boiler to control CO Bio Energy in West Hopkinton, NH. Although the Bio 

Energy facility is no longer operating, it was permitted and operated for some 

period, and therefore catalytic oxidation is considered a technically feasible 

control technology for CO emitted by biomass-fired boilers. A facility in 

South Point, OH has proposed to use oxidation catalysts to limit CO emissions 

from several wood-fired boilers to 0.1 lb/MMBtu, but, although a permit has 

been issued (and renewed several times), the proponent has not begun 

construction and has not identified a vendor that will supply the catalyst to 

meet that permit limit. 

An oxidation catalyst system was permitted and installed on the Whitefield 

Biomass Power Plant in New Hampshire. However, the catalyst is used for 

testing purposes. Use of the catalyst is optional, and is not needed to meet the 

CO permit limits. The CO permit limits, which did not change when the 

permit was modified to allow installation of the catalyst, are 225 lb/hr on a 

daily average basis (approximately 1.02 lb/MMBtu) and 57 lb/hr on an annual 

average (approximately 0.259 lb/MMBtu). The control technology vendor, 

Babcock Power, also claims to have installed similar control devices for 

testing at Boralex Stratton in Maine, and Bridgewater Power in New 

Hampshire, though no permitting actions were found to confirm this. 

As discussed in the NOX BACT analysis, SCONOx is extremely sensitive to 

the presence of sulfur in the exhaust stream, and has never been demonstrated 

on a biomass-fired boiler. Therefore, SCONOx is not considered technically 

feasible for controlling CO emissions from a biomass-fired boiler. 

16
Although there are several reasons that can be used as justification to 

eliminate catalytic oxidation technology due to technically infeasibility, we 

will retain it in our top-down BACT analysis because it was applied 

successfully at the Bio Energy facility in New Hampshire. 

c. Effectiveness of Remaining Technologies 

The section describes the remaining technologies in more detail and ranks 

them by effectiveness. 

Combustion Controls

Proper combustion control provides for a wide range of control effectiveness, 

depending on the configuration of the system. Generally, emissions resulting 

from incomplete combustion (CO) are balanced with emissions related to high 

furnace temperatures (NOx) to achieve optimally low emissions of all 

pollutants. However, in order to achieve the proposed NOX emission limit 

(0.151 lb/MMBtu) as well as to limit ammonia slip, boiler operation will favor 

reduced NOX creation over reduced CO creation. Proper combustion practices 

are currently being implemented at the SPI-Loyalton facility. 

Catalytic Oxidation

Oxidation catalysts are generally capable of providing between 40 and 90 

percent reduction in CO emissions, depending on the application. Biomassfired boilers would generally be at the lower end of that range because of the 

relatively high particulate matter and ash loading in the exhaust gases. Low 

exhaust gas temperatures as a result of removing the particulate and ash to 

mitigate clogging or poisoning the catalyst diminishes the effectiveness of the 

catalyst. 

d. Ranking by Effectiveness 

The remaining technologically feasible control technologies ranked in 

decreasing order of effectiveness are: 

• Proper combustion 

• Catalytic oxidation 

e. Evaluation of Cost Effectiveness 

The CO BACT analysis in the Approval to Construct issued by the 

Massachusetts Department of Environmental Protection for Russell Biomass, 

LLC in 2008 determined that oxidation catalysts applied to control CO 

emissions from biomass-fired boilers was economically infeasible. This 

determination was based on the experience of the Bio Energy facility in West 

Hopkinton, NH, as well as an economic feasibility investigation conducted by 

17
18

Russell Biomass, which indicated that no more than 40 percent control could 

be expected and that the cost per ton controlled would be in excess of 

$47,000. 

A cost estimate was provided by Babcock Power in 2009 for installing an 

oxidation catalyst system (adapted from their RSCR system discussed in the 

NOX section) to control CO from the cogeneration unit at the Loyalton 

facility. While the costs provided and the level of control indicated (75 

percent reduction) suggest that installing such a device would reduce 

emissions for less than $2,000 per ton of CO, the system has been installed in 

only a testing capacity, and are not required by permit to operate. It is unclear 

that such unproven technology, while theoretically feasible, can reliably 

deliver the promised reduction for the proposed cost. As a result, oxidation 

catalyst systems to control CO emissions removed from consideration as 

BACT for the biomass-fired boiler at the Loyalton facility. 

3. Selection of BACT for CO 

Based on the analysis presented in this section, SPI proposes that BACT for the 

control of CO from mass-burner type biomass-fired boilers is the use of proper 

combustion controls. CO emissions are limited to 550.5 lb/hr, or 2,420.1 TPY, 

which is equivalent to approximately 1443 ppm of CO at 12% CO2, averaged over 

a rolling eight -hour period. During transient operation, CO emissions are limited 

to 772.42 lbs/hr, or 1998 ppm at 12% CO2, averaged over 8 hours, for periods 

aggregating no more than 100 hours per year. 
19

TABLES
20

Table 5 

NOx Control Technology Search Results 

Sierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, California 

Facility Name Location 

Date of 

Permit 

Heat Input 

(MMBtu/hr) 

Permit Limit 

(lb/MMBtu) Control Technology 

Bridgewater Power Bridgewater, NH 9/12/07 250 0.23/0.33/0.0751 SNCR/RSCR 

Boralex – Stratton Stratton, ME 1/4/05 672 0.24/0.0751 Proper Comb./RSCR 

Whitefield Power & Light Whitefield, NH 9/10/04 220 0.26/0.33/0.0751 RSCR 

Pittsylvania Power Hurt, VA 2/21/92 374 0.12 SNCR 

NESCO Darrington, WA 1/18/05 403 0.12/0.13,4 SNCR 

Sierra Pacific Industries Lincoln, CA / /89 316 0.13 SNCR Sierra Pacific Industries Anderson, CA 0.13 SNCR Sierra Pacific Industries Burlington, WA 9/21/05 430 0.13 SNCR Sierra Pacific Industries Aberdeen, WA 10/17/02 310 0.15/0.13 SNCR 

Hampton Lumber Mills Randle, WA 10/8/06 165 0.15 SNCR 

Laurentian Energy Virginia, MN 6/30/05 230 0.15 SNCR 

Hampton Lumber Darrington, WA 6/1/05 245 0.15 SNCR 

Boralex – Ashland Ashland, ME 4/2/92 586 0.15 SNCR 

ADM Northern Sun Enderlin, ND 5/1/06 180 0.203 Proper Combustion 

KES Chateaugay Project Chateaugay, NY 12/19/94 275 0.23 No Controls 

Weyerhaeuser Co. Bruce, MS 5/9/95 90 0.23 Proper combustion 

Koda Energy Shakopee, MN 8/23/07 309 0.25 SNCR 

Wheelabrator Energy Sherman Station, ME 4/9/99 315 0.25 Proper combustion 

Deltic Timber Corp. Waldo, AR 8/20/03 64.3 0.3 Proper combustion 

U.S. Sugar Clewiston, FL 12/06/07 738 0.31 Proper combustion 

Annual average/24-hour average/quarterly average or 24-hour average/quarterly average; the quarterly averages are not actually perm

30-day rolling average. 24-hour average limit, and the second is the annual average limit. Never constructed 
21

Table 6 

NOx Control Technology Cost-Effectiveness Analysis 

Sierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, California 

Control Technology Annualized Cost1 ($/yr) Reduction (tons/yr) 

Cost Effectiveness 

($/ton) 

I

SNCR 544,503 146 3,741 

RSCR 2,007,762 279 7,187 

1 Based on 20-years at 7% interest. 
22

Table 7 

CO Control Technology Search Results 

Sierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, California 

Facility Name Location 

Date of 

Permit 

Heat Input 

(MMBtu/hr) 

Permit Limit 

(lb/MMBtu) Control Technology 

South Point Power 2 South Point, OH 4/4/06 318 0.10 Oxidation catalyst 

Hampton Lumber Mills Randle, WA 10/8/06 165 0.23 Proper combustion Hampton Lumber Mills Darrington, WA 6/1/05 245 0.23 Proper combustion 

Laurentian Energy Virginia, MN 6/30/05 230 0.3 Proper combustion 

Willamette Industries, Inc. Marlboro, SC 4/17/96 470 0.3 Proper combustion 

Boralex Ashland Ashland, ME 4/2/92 586 0.3 Proper combustion 

Decker Energy International East Ryegate, VT 7/11/90 300 0.3 Proper combustion 

Sierra Pacific Industries Burlington, WA 9/21/05 430 0.35 Proper combustion 

NESCO Darrington, WA 1/18/05 403 0.352 Proper combustion 

Sierra Pacific Industries Aberdeen, WA 10/17/02 310 0.35 Proper combustion 

KES Chateaugay Project Chateaugay, NY 12/19/94 275 0.35 Proper combustion 

Pittsylvania Power Hurt, VA 2/21/92 374 0.35 Proper combustion 

Smurfit-Stone Container Stevenson, AL 1/15/97 620 0.4 Proper combustion 

Weyerhaeuser Company Bruce, MS 5/9/95 90 0.4 Proper combustion 

Koda Energy Shakopee, MN 8/23/07 309 0.25 Proper combustion 

Gulf States Paper Corp Moundville, AL 10/14/98 98 0.5 Proper combustion 

Inland Paperboard & Packaging Bogalusa, LA 11/23/04 788 0.60 Proper combustion 

ADM Northern Sun Enderlin, ND 5/1/06 180 0.63 Proper combustion 

Bio Energy Corp. (shutdown) West Hopkinton, NH 7/23/98 225 1.0 Oxidation catalyst 

U.S. Sugar Clewiston, FL 11/19/99 633 6.5 Proper combustion 

SPI - Lincoln Lincoln, CA / /89 316 1.17 Proper combustion 
23

SPI - Anderson Anderson, CA 0.6 Proper combustion 

1 2 

Annual average heat input.. Project was never constructed 

Table 8

BACT Analysis Table –NOx

Sierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, California

Control 

Technology 

Control Efficiency (%) Cost/Ton NOx Energy Environmental O

DLN burner Technically infeasible -- -- -- 

SCR N/A1 -- -- -- 

RSCR 75-90% $7,1872 Fuel for reheat 

Some additional 

emissions from 

reheat fuel; 

ammonia slip 

Po

to

fu

SNCR 40-60% $3,741 None Ammonia slip 

Proper combustion N/A3 -- -- -- 

SCONOx Technically infeasible -- -- -- 

1 RSCR was deemed to be a more cost-effective subcategory of SCR 2 It should be noted that the incremental cost effectiveness between and SNCR and an RSCR system is approximately $11,000/ton. 

Additionally, most RSCR sytems installed to date have had quarterly limits established only to establish eligibility for Renewable Energy Credits (see Appendix A of the submitted permit application) 

3 Baseline control technology 
24

Table 9

BACT Analysis Table –CO 

Sierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, California

Control 

Technology 

Control Efficiency 

(%) 

Cost/Ton CO Energy Environmental O

Catalytic Oxidation 40-75% $2,000-$47,0001 None None 

Proper combustion N/A2 -- -- -- 

SCONOx Technically infeasible -- -- -- 

1 See Appendix A of the submitted permit application 2 Baseline control technology 
VII. Air Quality Impacts 

The PSD regulations require that air quality analyses be performed to determine the 

impact of the proposed project on ambient air quality. The analysis must consider 

whether the proposed project will cause a violation of (1) the applicable PSD increments, 

or (2) the applicable National Ambient Air Quality Standards (NAAQS). The proposed 

project will be located in a Federal Class II area. The nearest Class I designated area is 

the Desolation Valley Wilderness Area (12 kilometers to the south). This area has been 

examined for potential air quality impacts and visibility impairment (see Section VIII, 

Additional Impacts). 

EPA informed Sierra Pacific Industries of the newly promulgated NAAQS for NO2, 1-

hour standard (Federal Register reference: EPA-HQ-OAR-2005-0922; FRL 9107-9). The 

new NAAQS will be effective on April 12, 2010. SPI has agreed to provide any 

additional analysis pertaining to required NO2 modeling before the SPI-Loyalton PSD 

permit is finalized. 

A. Dispersion Modeling Analysis 

The USDA’s Forest Service, Pacific Southwest Region reviewed and commented on the 

Class I Prevention of Significant Deterioration (PSD) permit application for the biomassfired cogeneration plant operated by Sierra Pacific Industries (SPI), near Loyalton, CA. 

The Forest Service reviewed the modeling report dated June 19, 2008. The June 2008 

report was supplemented by digital modeling files submitted later in July 2008. 

The plant was permitted in the late 1980s. During operation it was found that the boiler 

was unable to meet the permitted emission limits for nitrogen oxides (NOx) and carbon 

monoxide (CO). The EPA requested that SPI update the air quality modeling (including 

impacts to Class I PSD areas) to reflect current guidance and standard practices. 

The Riley spreader-stoker boiler is fueled solely with wood and agricultural residues, 

including rice hulls, in-forest residues from logging and chipping operations, and urban 

wood wastes from private and municipal landfills. The maximum fuel feed rate is 41.9 

tons per hour, assuming a 55 percent fuel moisture content. 

The facility uses low excess air and staged combustion schemes in the boiler furnace to 

limit the formation of NOx, and a selective non-catalytic reduction (SNCR) ammoniainjection to reduce the NOx in the exhaust. A high-pressure secondary air injection 

system is used to limit CO formation in the furnace. PM10 in the exhaust is controlled 

using a multiclone in series with an electrostatic precipitator (ESP). 

The nearest Class I PSD area (Desolation Wilderness) is 70 kms from the project. Table 

10 below shows the distance to Class I areas that the applicant has modeled. 

25
Table 10

Class 1 Area Distances from the Project Site 

Class 1 Area Distance 

 (km) 

Distance 

 (miles) 

Desolation 70 43.7 

Mokelumne 106 65.6 

Caribou 113 70.1 

Lassen Volcanic NP 116 72.4 

Thousand Lakes 152 94.2 

Emigrant 153 95.1 

Hoover 163 101 

South Warner 165 102 

Yosemite 169 105 

Ansel Adams 206 128 

The major update to the modeling since the January 2008 application was that the 

CALPUFF modeling now addresses the total biomass boiler emissions rather than just the 

proposed emissions increase. Since the project relaxes previously permitted emission 

limits, modeling only the NOx emissions increase was deemed inappropriate. Also, since 

the visibility impacts are based on the combined impacts of all precursor pollutant 

emissions, the visibility modeling for this project was expanded to include emissions of 

all precursor pollutants (NOx, SO2 and PM10). 

The revised CALPUFF modeling documented in the June 2008 report is consistent with 

the current practice and guidance regarding the use of CALPUFF for PSD permit 

analyses. All technical options in CALPUFF matched the default selections. For 

background ozone (O3), a constant value of 80 ppb was employed, which should be 

worst-case at it assumed constant concentrations at the current National Ambient Air 

Quality Standards (NAAQS) for ozone. For background ammonia, a constant value of 10 

ppb was employed. Again, this is conservative given the location of the project in a 

forested area 

The NOx emissions were modeled at the proposed allowable rate of 50.75 lb/hr 

 (Table 11). The proposed permit limit is based on an 8-hour average. NOx emissions 

would also be allowed at up to 65.0 lb/hr (8-hour average) for up to 100 hours per year. 

Also, the modeling included other visibility precursor pollutants (SO2 and PM10) as well 

26
as “speciation” of the PM10 emissions based on a profile in the EPA SPECIATE 

database. 

Table 11

Emission Rates (lbs/ hr) 

Species 24-hour Average 

SO2 8.81 

NOx 50.75 

PM10 9.96 

B. Class I AQRV Impact Analysis 

The revised permit would also increase CO emissions at the boiler, but these emissions 

do not impact air quality related values (AQRVs) for Class I areas and were not modeled 

using CALPUFF. 

 

For concentration and deposition, the Desolation Wilderness, which is the closest Class I 

areas to the project site, showed the highest impacts. All of the concentration and 

deposition values at the Desolation Wilderness were approximately one order of 

magnitude or greater below the applicable “significant” threshold for Class I impacts. 

When modeling the PM10 concentrations impacts, the applicant considered all potential 

PM10 species, including any secondary sulfate and nitrate mass predicted using 

CALPUFF. The applicant’s June 19, 2008 maximum deposition flux for nitrogen and 

sulfur CALPUFF modeling for each Class I area are shown in Table 12. The maximum 

flux for nitrogen and sulfur occurred at Desolation which is ten times below the threshold 

for nitrogen and seventeen times below for sulfur. 

Table 12

Maximum Predicted Class 1 Area Deposition Fluxes 

Class 1 Area Nitrogen Flux Sulfur Flux 

Threshold 

Of 0.005 

Exceeded? 

Caribou 0.0003 0.0003 No 

Desolation 0.0005 0.0003 No 

Emigrant 0.0001 0.0003 No 

27
Hoover 0.0001 0.0003 No 

Lassen Volcanic NP 0.0003 0.0003 No 

Mokelumne 0.0002 0.0003 No 

South Warner 0.0003 0.0003 No 

Thousand Lakes 0.0002 0.0003 No 

Yosemite 0.0001 0.0003 No 

Max Deposition Flux 0.0005 0.0003 No 

For visibility, the highest impacts were not at the closest Class I area, but instead 

occurred at the Caribou Wilderness, located to the northwest of the project site. Visibility 

impacts were modeled using “Method 2” and the standard FLAG natural background 

values. Table 13 shows the predicted maximum extinction change by Class I area and the 

date it occurred. The worst-case visibility impact at the Caribou Wilderness was 1.98% 

change, which is well below the 5% threshold established for potential change in light 

extinction. 

 Table 13

Maximum Predicted Class 1 Area Extinction Change 

Class 1 Area Date % Change 

Threshold of 

5% 

exceeded? 

Caribou 01/19/03 1.980 No 

Desolation 10/28/02 1.480 No 

Emigrant 03/22/01 0.610 No 

Hoover 03/22/01 0.600 No 

Lassen Volcanic NP 01/19/03 1.760 No 

28
Mokelumne 03/22/01 0.770 No 

South Warner 11/22/02 1.130 No 

Thousand Lakes 11/02/01 1.060 No 

Yosemite 03/22/01 0.480 No 

Max Change predicted 1.98 No 

 

The CALPUFF modeling for SPI-Loyalton appears to have been done following current 

guidance for such analyses and documents that expected air quality impacts will be less 

than the thresholds normally used to judge whether impacts are “significant”. 

VIII. Additional Impact Analysis 

A. Growth Analysis 

The purpose of the growth analysis is to project the industrial, commercial, and 

residential growth, and related emissions, that are anticipated to occur in the area due to 

the construction of the new major source or modification. The emissions associated with 

such projected growth are those not directly related to the new source or modification. 

The emission increases for the proposed modification are not expected to significantly 

affect any industrial, commercial; and residential growth in the area. 

B. Soils and Vegetation 

This requirement addresses the potential impact of the proposed project’s emissions on 

sensitive soils and vegetation, of commercial or recreational value, occurring in the 

project’s impact area. The NAAQS establish the secondary standards that are intended to 

protect public welfare, including vegetation. Soils in the impact area, which would be 

affected mainly through the deposition and subsequent leaching of particulate 

contaminants, are not expected to be adversely affected. 

Ground level concentrations for all pollutants and averaging times are well below the 

secondary national ambient air quality standard, which have been established to include 

the protection of vegetation. At the point of maximum concentration, the predicted value 

is only a fraction of the related ambient air quality standard. It is therefore reasonable to 

expect that no adverse impact upon vegetation or soil is anticipated from this project. 

29
IX. Endangered Species Act 

Pursuant to Section 7 of the Endangered Species Act, EPA is required to initiate 

consultation with the Fish and Wildlife Service (FWS) if any action, including permit 

issuance, might jeopardize the continued existence of endangered or threatened species or 

adversely modify their critical habitat.. 

Since the SPI-Loyalton project will not result in a physical change to the faculty, EPA 

has concluded that this project will have no effect on listed species, or their critical 

habitat, and thus, EPA has fulfilled its responsibility under Section 7 of the Endangered 

Species Act. 

X. Conclusion and Proposed Action 

Based on the information submitted by Sierra Pacific Industries and the analyses 

conducted by EPA, it is the preliminary determination of EPA that the proposed project 

will employ Best Available Control Technology and will not interfere with the attainment 

or maintenance of any PSD increment of NAAQS in the Mountain Counties Air Basin. 

Therefore, EPA intends to issue an approval to construct/modify, which will contain the 

following conditions. 

30