AMBIENT AIR QUALIT Y IMPACT REPORT (NSR 4-4-4, SAC 87-01-A)

This document serves as the Statement of Basi s and Ambient Air Quality Impact Report for the proposed PSD permit for the Sierra Pacific I ndustries - Loyalton f acility. This document describes the legal and fact ual 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 Lo yalton, 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 (SP I) 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 amendm ent of permit conditions for the cogeneration facility contained in Prevention of Signifi cant Deterioration permit number NSR 4-4-4, SAC 89-01. The Applicant proposes to increas e emission limits and averaging times of nitrogen (NO

x ) and carbon monoxide (CO). No change in the construction of the boiler is proposed.

The cogeneration facility incl udes a Riley spreade r-stoker boiler for the combustion of wood fuel and production of steam, a turbin e generator for conve rting the energy of steam into electrical energy, a fuel handli ng 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, andpneumatically-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 maxi mum 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 pressu res 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 tan k, 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 retu rns to the boiler. Cooling water is circulated in loop betw een the cooling tower, the condenser, and several air and oil cooling devices.

C. Fuel Handling and Storage

Wood residue (fuel) is received by truc k from various sources and unloaded by the existing on-site truck unloader. The fu el is transferred to a temporary outdoor fuel storage pile by a loader or pusher. As needed, it is tr ansferred 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 sc rew 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 fr om logging and chipping operations, and urban wood wastes from private and municipal landfills.

Scientific and indus trial experiences in the use of wood for the generation of

2electricity and steam have shown that the properties of wood (e.g., heating value and moisture content) vary depend ing on wood species and environmental conditions during growth. Fuel related calculations are base d on a typical fuel mixture having a heating value of 4005 BT U per pound (wet basis) and a moisture content of 55% by weight. These prope rties determine the quantity of fuel required to generate a given amount of energy and are used to establish the operating parameters and waste manage ment requirements for the facility.

F. Emission Controls

The facility uses emission control syst ems 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 re quired by EPA, and low excess air with staged combustion for the cont rol of nitrogen oxides (NO

x ) emissions.

The Riley stoker boiler exhausts through a multiclone to a 3-field electrostatic precipitator (ESP) for the cont rol of particulates and part iculate matter less than or equal to 10 micrometers in diameter (PM 10 )

The stoker boiler is equipped with a high-pr essure 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 boile r under the proposed emission limits have been estimated on the basis of source test and continuous emission monitoring (CEMS) data. Estimates of CO and NO

x emission rates were based

on collected stack data. Em ission rates for VOC and PM 10 were estimated from source test and operational data. Lead, which is not typically found in si gnificant quantities in wood, has been estimated at zero. No signi ficant 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 coge neration boiler is presented in Table 1.

3Table 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) 222.6 NO

x

NO

x trans: 65.00 (8-hr average) --

VOC 6.71 (3-hr average) 29.4

550 (8-hr average) 2,420.1 CO

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 Emissions 1

(lbs/hr) Annual Emissions 1

(TPY)

PM10 8.39 36.75

NO

x 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

4Net 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 NO

x 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 ty pe which emits or has the potential to emit such pollutants in amounts equa l 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 thresh old prescribed for any pollutant subject to regulation. The significant thresholds for the criteria pollutants are listed in Table 4.

PM 10 and SO 2 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

NO

x 40 60.9

5SO2 40 0.0

TSP 25 0.0

PM10 15 0.0

O 3 (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. Therefor e, for an existing major source, a PSD review would apply to each pollutant showing potenti al significant net increases in emissions.

The existing source is a "major" PSD s ource and the proposed project has potential significant net emission increases of fine particulate matter, nitrogen oxides, volatile organic compounds, and carbon monoxide. Theref ore, a PSD review for these pollutants is required as follows:

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

2. Analysis of Ambient Air Qu ality 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, Sier ra Pacific Industries must apply best available control technology (BAC T) to control emission of NO

x and CO from their Riley boiler. BACT is defined in the Cl ean Air Act Amendments of 1977 as ".. .an emission limitation based on the maximum degr ee 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." U nder environmental impacts, our review includes the impact from both regulated and unr egulated 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 NS R pollutant that it would have the potential to emit (PTE) in significant amounts. BA CT is defined as “an emission limitation (including a visible emission standard) ba sed on the maximum degree of reduction of each pollutant subject to regulation under [the ] Act ... which the Administrator, on a case6by-case basis, taking into account energy, e nvironmental, and economic impacts, and other costs, determines is achievable for su ch source.” 40 CFR 52.21(b)(12). In no event may application of BACT result in emissi ons 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 proces s 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-esta blished procedure that the Environmental Appeals Board (EAB) has consistently cons idered 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 co ntrol technologies be ranked in descending order of control effectiveness. The PSD applicant first examines the most stringent technology. That technol ogy 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 stringe nt 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 summ ary, the five steps involved in a top-down

BACT evaluation are:

1. Identify all available control options w ith practical potential for application to the specific emission unit for the re gulated pollutant under evaluation;

2. Eliminate technically in feasible technology options;

3. Rank remaining control technolo gies by control effectiveness;

4. Evaluate the most effective control alternative and documen t results; if top option is not selected as BACT, evaluate next most effective control option; and

5. Select BACT, which will be the most st ringent technology not rejected based on technical, energy, environmental, and economic considerations.

B. NO

x BACT Analysis

NO

x 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 NO

2 .

1. Identification of Possible Control Alternatives

There are a variety of options available for controlling NO

x emissions from combustion sources. Some options invol ve combustion controls that reduce NO

x

7formation, while others utilize ad d-on control devices to remove NO

x after it is

formed.

Combustion controls reduce NO

x emissions by controlling the combustion temperature and the availability of oxygen. Combustion air cont aining both nitrogen and oxygen can combine in a high temperat ure environment to form thermal NO

x . The oxidation of nitrogen that is chemically bound in fuel sources can also form what is called fuel-bound, or “prompt,” NO

x . Dry low-NO

x (DLN) burners control thermal

NO

x formation by avoiding high temperatur e combustion zones and uneven oxygen distribution. This is accomp lished by burner designs that carefully control the mixing of fuel and combustion air. Generally, us e 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 computer ized 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 su ch as selective catal ytic reduction (SCR) and selective non-cataly tic reduction (SNCR) systems are widely used technologies for controlling NO

x 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 mixtur e is passed through a catalyst bed. The

NO

x reacts with the ammonia aided by the cataly st to form nitrogen and water. An SCR system applied to a biomass-fired boile r 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 biom ass-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 Loyalt on, California area, so any exhaust reheat system would be fired us ing trucked-in propane or distillate oil.

The SNCR process is similar to SCR in that a reagent reacts with NO

x to form nitrogen and water, although no catalyst is us ed 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.

SCONO

x is similar to SCR, except that NO

x in the exhaust stream reacts with potassium carbonate (K 2 CO 3 ) to form potassium nitrate (KNO 3 ). This compound is reacted with hydrogen to fo rm gaseous nitrogen (N 2 ), and regenerate the K 2 CO 3 . The lower exhaust temperature limit required for the reactions in the SCONO

x to take place is less than that of SCR (300 oF as opposed to 450 oF). The SCONO

x system is

also said to control carb on monoxide (CO) by oxidation.

8Table 8 summarizes NO

x control technologies.

2. Control Alternative Review

The results of the database queries and permit investigations for NO

X control technologies are presented in Table 5, so rted by permit limit, beginning with the NO

X limit proposed for the boiler.

The following technologies were found to control NO

X from biomass-fired boilers:

• Proper combustion

• SNCR

• SCR

• RSCR

The database queries did not produce any instances of NO

x emissions from biomassfired boilers controlled by DLN burner, S CR, or RSCR systems. According to the Applicant, there is at least one SCR sy stem, and at least two RSCR systems being

used to control NO

X 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 ope rations. After an ESP removes particulate matter from the exhaust stream, an SCR system removes

NO

X . The permitted NO

X 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 Environmenta l Protection (FDEP) for the U.S. Sugar Corporation’s Clewiston Sugar Mill and Refinery. FDEP determined that 0.31

lb/MMBtu was BACT for NO

X emissions from a 738 MMBtu/hr bagasse and wood chip-fired boiler employing combustion controls. The most recent NO

X 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, wh ich determined that 0.25 lb/MMBtu was

BACT for NO

X emissions from a 309 MMBtu/hr combined heat and power biomass boiler employing a low- NO

X burner, over-fire air and SNCR.

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

limit the amount of NO

X generated during combustion. Co en 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

9recirculation and staged combustion, a NO X emission rate of 0.35 lb/MMBtu at the

furnace exit has been achieved.

RSCR systems have been added to control NO X emissions from existing wood-fired boilers at Boralex – Stratton Energy in Stratton, Maine, Bridgewater Power in Bridgewater, NH, and Whitefield Power & Li ght 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 NO X emissions from a biomass-fired boiler:

• Proper combustion

• DLN burner

• SCR

• RSCR

• SNCR

• SCONOx

b. Technical Feasibility of Control Alternatives

Most of the control altern atives described in the pr evious section have been shown to be technically f easible for controlling NO

X emissions from biomass-fired

boilers. Several of the alte rnatives have either not b een 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 appli cation of state-of-the-art design and appropriate operation of a combustion un it. Current design biomass-fired massburner-type boilers can generally achieve NO

X 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 NO

X 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 NO

x during combustion, and are generally suited to boilers that burn wood waste containing a high percentage of re sins, such as the waste from medium density fiberboard (MDF), plywood, or veneer operations.

10SNCR Ammonia-injection nozzles can be pos itioned at the furnace exit and use the relatively high temperatures ther e to promote the reaction of NO

x and ammonia. SNCR system design is often incorporated into the overall bo iler design, and can

be located at the furnace exit because SNCR systems do not rely on a catalyst which is subject to plugging from partic ulate matter in the flue gases. The relative simplicity of SNCR systems make s them technically feasible, and has resulted in them becoming the most popular add-on NO

x control technology for

biomass-fired boilers.

SCR and RSCR An SCR system used to control NO

x emissions from a biomass-fired boiler has

been demonstrated to control NO

x emissions to 0.20 lb/MMBtu on two 57 MMBtu/hr boilers (the Sauder Woodworki ng boilers). RSCR systems have been applied to 220 MMBtu/hr (Whitefield) , 250 MMBtu/hr (Bridgewater), and 672 MMBtu/hr (Boralex – Stratton) wood-fire d boilers. Both SCR and RSCR systems are considered technically feasible for controlling NO

X emissions from a biomassfired boiler. Because RSCR controls NO

x 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, SCONO

x (now called EMx) has been designed and used only on smallto medium sized natural gas-fired stationa ry turbines for demonstration purposes. The technology has never been applied to a biomass-fired boiler. Also, the

SCONO

x 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 SO 2 emission factor for wood- fired boilers is 0.025 lb/MMBtu, which is equivalent to about 7.2 lb/hr of SO 2 . Natural gas, the combustion fuel most commonly associated with SCONO

x applications, has maximum sulfur limit of one grain per 100 standard cubic feet (gr/scf) of gas in California, where SCONO

x has been applied. On a heat input basis, this is equivalent to an SO 2 emission rate of 0.43 lb/hr. The sensitivity to sulfur, combined with a lack of comparable ex isting applications suggests that SCONO

x is technologically infeasible as a control technology for controlling NO

x emissions

from a biomass-fired boiler.

The following is a list of the technically feasible NO

x control technologies and possible combinations:

• Proper combustion

• SNCR

• RSCR

• DLN burner

11c. Effectiveness of Remaining Technologies

This section describes the remaining tec hnologies in more detail and ranks them by effectiveness.

Proper Combustion A modern biomass-fired boiler furnace, ope rated with computerized controls to ensure proper combustion would result in a NO

x emission limit of between 0.25

and 0.3 lb/MMBtu. The boiler de sign proposed by SPI would emit 0.25 lb/MMBtu when utilizing only proper combustion techniques to reduce NO

X emissions. Proper combustion is a techni cally feasible technology for controlling

NO

x emissions from biomass-fired boilers . Proper combustion practices are currently being implemented at SPI by a fu lly 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 NO

X emissions from large biomass-fired boilers. SNCR systems rely on high temperatures to pr omote the reaction of NO

X with the introduced ammonia. As a result, the control system is ofte n 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 NO

x .

SPI employs an SNCR integral to the boiler design to reduce NO

x emissions to 0.151 lb/MMBtu. A boiler permitted by NESCO in Darrington, Washington with a 0.12 lb/MMBtu 24-hour average limit a nd a 0.1 lb/MMBtu annual average limit is unlikely to ever be co nstructed and may not have consistently achieved that limit with an acceptable ammonia slip. Dominion – Pittsylvania Power Station (formerly Multitrade of Pitts ylvania County, L.P.), in Hurt, Virginia, uses SNCR systems to control NO

x from three wood-fired boilers and has a permit limit of 0.1 lb/MMBtu on a 30-day rolling average basi s. It should be noted that, while a 0.1 lb/MMBtu permit limit based on a 30-day ro lling 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 lim it 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 a nd combustion. The RSCR systems which have been applied to existing wood- fired boilers (Boralex – Stratton, Bridegewater, and Whitefield) have en abled them to take a quarterly NO

X permit limit of 0.075 lb/MMBtu to qualify for Re newable Energy Cer tificates (RECs)

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

12facilities 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, achieve d by an uncontrolled mass burner-type boiler using fuel cells. Installing DLN bur ners in the Riley boiler at the Loyalton facility would effectively be a redesigning of the entire NO

X -control system. DLN burners require finely-ground, uniformly-si zed fuel. Therefore, additional fuel handling and processing equipment would need to be incorp orated, requiring the Riley boiler to be redesigned, if this c ontrol 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 summar ized in Table 6. As shown, SNCR provides the lowest cost per ton of NO

x removed, and is approximately twice as

cost effective as RSCR. As shown in Ta ble 6, the cost per ton difference between SNCR and RSCR is approxima tely $3,500 per ton of NO X removed. Based on this analysis, SNCR is deemed to be the most cost effective NO

x 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

NO

x 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 NO

x removed from the exhaust. There is an

13estimated capital cost of $5 million to install an RSCR system. The 0.075 lb/MMBtu is a voluntary limit, not an en forceable permit limit. The installed RSCR systems were retrofitted onto existi ng 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 NO

x

Based on the analysis presen ted in this section, SPI pr oposes that BACT for the

control of NO

x from biomass-fired mass-burner-type boilers is the use of an SNCR system combined with proper combustion practices. NO

x emissions are limited to 50.75 lb/hr, or 222.3 tons per year at th e anticipated annual average operating capacity, which is approximately e quivalent to 80 ppm limit of NO

x at 12% CO 2 , averaged over a rolling eight-hour pe riod. During transient operation, NO

x emissions are limited to 65 lbs/hr, or 102 ppm at 12% CO 2, 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 ch emical 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 CO 2 into CO (Wark and Warner, 1981).

1. Identification of Possible Control Alternatives

Similar to NO

X , the technology options available for controlling CO emissions

from combustion sources include combusti on controls and add-on control devices. CO combustion controls promote more co mplete oxidation to limit CO emissions, rather than discouraging the form ation of the pollutant as for NO

X , and instead of

the reduction reaction used to eliminate NO

X , CO add-on controls seek to oxidize

CO to CO 2 after it has left the combustion area. Combustion controls are intended

to maximize CO 2 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 NO

x 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 NO

x controls (i.e., SNCR) compar ed to add-on CO controls (i.e., oxidation catalysts ), sacrifice greater NO X emissions for reduced CO emissions. A combustion unit designed to either balance CO and NO

x emissions

or favor reduced CO emissions is co mmonly referred to as having “proper combustion control” when combined with appropriate operation.

14The only add-on technology used in pract ice 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 facili tate the conversion of a criteria pollutant to a non-pollutant (in this case, CO to CO 2 ). Catalytic oxidizers used for CO control typically operate in a te mperature range of approximately 500 o F to 1,000 o F.

In some cases, fuel use must be increased to maintain the CO-to-CO 2 conversion efficiency, which falls off ra pidly 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 cat alyst 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 acco mmodate the higher volume than would be needed for a typical installation where the particulate control is located just before the stack. Even with a particul ate control device loca ted upstream of the catalyst, a steam injection system is typically used to periodically remove particulate matter from the catalyst, a nd relatively frequent replacement of the catalyst (compared to combus tion units firing gaseous or liquid fuels) is required.

SCONO

x (described in the NO

x BACT analysis) also utili zes a catalytic technique

that oxidizes CO to CO 2 in addition to controlling NO

x 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 bi omass-fired boilers:

• Oxidation Catalyst

• Proper Combustion

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

emissions. There are two instances wher e permits have been issued for woodfired boilers using catalyti c oxidation to limit CO emissi ons. One of these boilers is no longer operating, and the other has not been cons tructed. Boilers with permit limits below 0.30 lb/MMBtu generally have some detail that differentiates them from “normal” mass-burner type biom ass-fired boilers. Examples of these differences include: consistently avai lable high heat-value -per-weight fuel sources, co-firing with fossil fuel s, and lenient or nonexistent NO

x and/or ammonia slip limits that allow operation at higher temperatures that limit CO

formation.

15a. Summary of Possible Control Alternatives

Based on literature and database search es 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 NO

x 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 oxidati on 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 tec hnically feasible control technology for CO emitted by bi omass-fired boilers. A facility in South Point, OH has proposed to use oxida tion 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 installati on 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 NO

X 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 emissi ons from a biomass-fired boiler.

16Although there are several re asons that can be used as justification to eliminate catalytic oxida tion technology due to techni cally 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 t echnologies 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 sy stem. Generally, emissions resulting from incomplete combustion (CO) are ba lanced with emissions related to high furnace temperatures (NO

x ) to achieve optimally low emissions of all pollutants. However, in orde r to achieve the proposed NO

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

reduced NO

X creation over reduced CO creati on. Proper combustion practices are currently being implemente d at the SPI-Loyalton facility.

Catalytic Oxidation Oxidation catalysts are generally capa ble of providing between 40 and 90 percent reduction in CO emissions, de pending 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 feasib le 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 Environm ental Protection for Russell Biomass,

LLC in 2008 determined that oxidati on catalysts applie d 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

1718 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

NO X section) to control CO from th e cogeneration unit at the Loyalton facility. While the costs provided an d the level of control indicated (75 percent reduction) suggest that in stalling 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 ar e not required by permit to operate. It is unclear that such unproven tech nology, 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 boile r at the Loyalton facility.

3. Selection of BACT for CO

Based on the analysis presen ted in this section, SPI pr oposes that BACT for the control of CO from mass-burner type biom ass-fired boilers is the use of proper

combustion controls. CO emissions ar e limited to 550.5 lb/hr, or 2,420.1 TPY, which is equivalent to approxi mately 1443 ppm of CO at 12% CO 2 , averaged over a rolling eight -hour period. During tran sient operation, CO emissions are limited to 772.42 lbs/hr, or 1998 ppm at 12% CO 2 , averaged over 8 hours, for periods aggregating no more than 100 hours per year.19TABLES20Table 5NOxControl Technology Search ResultsSierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, CaliforniaFacility NameLocationDate ofPermitHeat Input(MMBtu/hr)Permit Limit(lb/MMBtu)Control TechnologyBasisBridgewater PowerBridgewater, NH9/12/072500.23/0.33/0.0751SNCR/RSCRPSD/RACT/OTHERBoralex – StrattonStratton, ME1/4/056720.24/0.0751Proper Comb./RSCRBACT/OTHERWhitefield Power & LightWhitefield, NH9/10/042200.26/0.33/0.0751RSCRPSD/RACT/OTHERPittsylvania PowerHurt, VA2/21/923740.12SNCRBACT-PSDNESCODarrington, WA1/18/054030.12/0.13,4SNCRBACT-PSDSierra Pacific IndustriesLincoln, CA/ /893160.13SNCRBACT-PSDSierra Pacific IndustriesAnderson, CA0.13SNCRBACT-PSDSierra Pacific IndustriesBurlington, WA9/21/054300.13SNCRBACT-PSDSierra Pacific IndustriesAberdeen, WA10/17/023100.15/0.13SNCRBACT-PSDHampton Lumber MillsRandle, WA10/8/061650.15SNCRBACT-OTHERLaurentian EnergyVirginia, MN6/30/052300.15SNCRBACT-PSDHampton LumberDarrington, WA6/1/052450.15SNCRBACT-OTHERBoralex – AshlandAshland, ME4/2/925860.15SNCRBACT-OTHERADM Northern SunEnderlin, ND5/1/061800.203Proper CombustionBACT-PSDKES Chateaugay ProjectChateaugay, NY12/19/942750.23No ControlsBACT-OTHERWeyerhaeuser Co.Bruce, MS5/9/95900.23Proper combustionBACT-PSDKoda EnergyShakopee, MN8/23/073090.25SNCRBACT-PSDWheelabrator EnergySherman Station, ME4/9/993150.25Proper combustionBACT-PSDDeltic Timber Corp.Waldo, AR8/20/0364.30.3Proper combustionBACT-PSDU.S. SugarClewiston, FL12/06/077380.31Proper combustionBACT-PSDAnnual average/24-hour average/quarterly average or 24-hour average/quarterly average; the quarterly averages are not actuallypermit limits. Based on a30-day rolling average. 24-hour average limit, and the second is the annual average limit. Never constructed21Table 6NOxControl Technology Cost-Effectiveness AnalysisSierra Pacific Industries Biomass-FiredBoiler Facility Loyalton, CaliforniaControl TechnologyAnnualized Cost1 ($/yr)Reduction (tons/yr)Cost Effectiveness($/ton)Incremental CostEffectiveness($/ton)SNCR544,5031463,741---RSCR2,007,7622797,18710,9361Based on 20-years at 7% interest.22Table 7CO Control Technology Search ResultsSierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, CaliforniaFacility NameLocationDate ofPermitHeat Input(MMBtu/hr)Permit Limit(lb/MMBtu)Control TechnologyBasisSouth Point Power2South Point, OH4/4/063180.10Oxidation catalystBACT-PSDHampton Lumber MillsRandle, WA10/8/061650.23Proper combustionBACT-OTHERHampton Lumber MillsDarrington, WA6/1/052450.23Proper combustionBACT-OTHERLaurentian EnergyVirginia, MN6/30/052300.3Proper combustionBACT-PSDWillamette Industries, Inc.Marlboro, SC4/17/964700.3Proper combustionBACT-OTHERBoralex AshlandAshland, ME4/2/925860.3Proper combustionBACT-OTHERDecker Energy InternationalEast Ryegate, VT7/11/903000.3Proper combustionBACT-PSDSierra Pacific IndustriesBurlington, WA9/21/054300.35Proper combustionBACT-PSDNESCODarrington, WA1/18/054030.352Proper combustionBACT-PSDSierra Pacific IndustriesAberdeen, WA10/17/023100.35Proper combustionBACT-PSDKES Chateaugay ProjectChateaugay, NY12/19/942750.35Proper combustionBACT-OTHERPittsylvania PowerHurt, VA2/21/923740.35Proper combustionBACT-PSDSmurfit-Stone ContainerStevenson, AL1/15/976200.4Proper combustionBACT-PSDWeyerhaeuser CompanyBruce, MS5/9/95900.4Proper combustionBACT-PSDKoda EnergyShakopee, MN8/23/073090.25Proper combustionBACT-PSDGulf States Paper CorpMoundville, AL10/14/98980.5Proper combustionBACT-PSDInland Paperboard & PackagingBogalusa, LA11/23/047880.60Proper combustionBACT-PSDADM Northern SunEnderlin, ND5/1/061800.63Proper combustionBACT-PSDBio Energy Corp. (shutdown)West Hopkinton, NH7/23/982251.0Oxidation catalystBACT-OTHERU.S. SugarClewiston, FL11/19/996336.5Proper combustionBACT-PSDSPI - LincolnLincoln, CA/ /893161.17Proper combustionBACT-PSD23SPI - AndersonAnderson, CA0.6Proper combustionBACT-PSD12Annual averageheat input..Project was never constructedTable 8BACT Analysis Table –NOxSierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, CaliforniaControlTechnologyControl Efficiency (%)Cost/Ton NOxEnergyEnvironmentalOther PollutantsDLN burnerTechnically infeasible--------SCRN/A1--------RSCR75-90%$7,1872Fuel for reheatSome additionalemissions fromreheat fuel;ammonia slipPossible additionaltoxics from reheatfuel; ammonia slipSNCR40-60%$3,741NoneAmmonia slipAmmonia slipProper combustionN/A3--------SCONOxTechnically infeasible--------1RSCR was deemed to be a more cost-effective subcategory of SCR2It should be noted that the incremental cost effectivenessbetween 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 RenewableEnergy Credits (see Appendix A of the submitted permit application)3Baseline control technology24Table 9BACT Analysis Table –COSierra Pacific Industries Biomass-Fired Boiler Facility Loyalton, CaliforniaControlTechnologyControl Efficiency(%)Cost/Ton COEnergyEnvironmentalOther PollutantsCatalytic Oxidation40-75%$2,000-$47,0001NoneNoneNoneProper combustionN/A2--------SCONOxTechnically infeasible--------1See Appendix A of the submitted permit application2Baseline control technologyVII. 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 viola tion of (1) the applicable PSD increments, or (2) the applicable National Ambient Ai r Quality Standards (NAAQS). The proposed project will be located in a Fe deral Class II area. The near est Class I designated area is the Desolation Valley Wilderness Area (12 kilome ters to the south). This area has been examined for potential air quality impacts a nd visibility impairment (see Section VIII, Additional Impacts).

EPA informed Sierra Pacific Industrie s of the newly promulgated NAAQS for NO 2 , 1- hour standard (Federal Register refere nce: 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 pert aining to required NO 2 modeling before the SPI-Loyalton PSD permit is finalized.

A. Dispersion Modeling Analysis

The USDA’s Forest Service, Pacific Southw est Region reviewed and commented on the Class I Prevention of Significant Deteriorati on (PSD) permit application for the biomassfired cogeneration plant operate d by Sierra Pacific Industries (SPI), near Loyalton, CA.

The Forest Service reviewed the modeli ng report dated June 19, 2008. The June 2008 report was supplemented by digital modeli ng 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 boile r is fueled solely with w ood and agricultural residues, including rice hulls, in-fores t residues from logging and ch ipping operations, and urban wood wastes from private and municipal landfi lls. 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 selectiv e 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. PM 10 in the exhaust is controlled using a multiclone in series with an electrostatic precipitator (ESP).

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

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

25Table 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 th e January 2008 applica tion was that the CALPUFF modeling now addresses the total biomass boiler emissions rather than just the proposed emissions increase. Since the proj ect relaxes previously permitted emission limits, modeling only the NOx emissions increase was deemed inappropriate. Also, since the visibility impacts are based on the comb ined impacts of all precursor pollutant emissions, the visibility modeling for this pr oject was expanded to include emissions of all precursor pollutants (NOx, SO 2 and PM 10 ).

The revised CALPUFF modeling documented in the June 2008 report is consistent with the current practice and guidance regard ing the use of CALP UFF for PSD permit analyses. All technical options in CALP UFF matched the default selections. For background ozone (O 3 ), 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 ba ckground 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 lim it is based on an 8-hour average. NO

x 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 vi sibility precursor pollutants (SO 2 and PM 10 ) as well

26as “speciation” of the PM 10 emissions based on a prof ile in the EPA SPECIATE

database.

Table 11 Emission Rates (lbs/ hr)

Species 24-hour Average

SO 2 8.81

NO

x 50.75

PM 10 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 rela ted 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, s howed the highest impacts. All of the concentration and deposition values at the Desolation Wild erness were approximately one order of magnitude or greater below the applicable “s ignificant” threshold for Class I impacts. When modeling the PM 10 concentrations impacts, the applicant considered all potential

PM 10 species, including any secondary sulf ate 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 ar ea are shown in Table 12. The maximum flux for nitrogen and sulfur occurred at Desola tion which is ten times below the threshold for nitrogen and seventeen times below for sulfur.

Table 12

Maximum Predicted Class 1 A rea 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

27Hoover 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 Clas s 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 maximu m extinction change by Class I area and the date it occurred. The worst-case visibility impact at the Cari bou Wilderness was 1.98% change, which is well below the 5% threshol d 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

28Mokelumne 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 appear s 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 j udge 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 modi fication are not expect ed to significantly affect any industrial, commercial; and residential growth in the area.

B. Soils and Vegetation

This requirement addresses th e potential impact of the proposed project’s emissions on sensitive soils and vegetation, of commercial or recreationa l value, occurring in the project’s impact area. The NAAQ S establish the secondary sta ndards that are intended to protect public welfare, including vegetation. Soils in the impact area, which would be affected mainly through the deposition a nd subsequent leaching of particulate contaminants, are not expected to be adversely affected.

Ground level concentrations for all pollutant s and averaging times are well below the secondary national ambient air quality standar d, which have been established to include the protection of vegetation. At the point of maximum concentrati on, the predicted value is only a fraction of the related ambient air qua lity standard. It is therefore reasonable to expect that no adverse impact upon vegetation or soil is anticipated from this project.

29IX. 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 existe nce 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 projec t will have no effect on listed species, or their critical habitat, and thus, EPA has fu lfilled 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 dete rmination of EPA that the proposed project will employ Best Available Control Technology a nd will not interfere wi th the attainment or maintenance of any PSD increment of NAAQS in the Mountai n Counties Air Basin. Therefore, EPA intends to issue an approval to construct/modify, which will contain the following conditions.

30