# Best Available Retrofit Technology (BART) Determination Analysis

Riley Boiler

The Amalgamated Sugar Company LLC

Nampa Facility February 6, 20092 

### TABLE OF CONTENTS

Executive Summary..................................

................................................... ................................... 4

1.0 Introduction..................................

................................................... ..................................... 6 1.1 BART Regulatory Overview ......................

................................................... .................. 6 1.2 IDEQ “Subject to BART” Visibility Modeling for Riley Boiler..................................... 7 1.3 Approach to Riley Boiler BART Analysis ........

................................................... ........... 8 2.0 Overview of Company, Facility, and BART Subjec t Equipment........................................ 8 2.1 Company Description ...........................

................................................... ........................ 8 2.2 Beet Sugar Production Economics...............

................................................... ................. 9 2.3 Description of Nampa Factory, Operations and S ite Constraints.................................. 12 2.4 Riley Boiler Description and Constraints ......

................................................... ............. 15 2.4.1 Boiler Specifications and Fuel..............

................................................... ............... 15 2.4.2 Operating History and Useful Life. ..........

................................................... ........... 15 2.4.3 Existing Control Equipment. .................

................................................... .............. 15

2.4.4 Baseline Emission Rates.....................

................................................... ................. 15 3.0 BART Determination Analysis Methodology .......

................................................... ......... 16 4.0 Step 1: Identify All Available Retrofit Contr ol Technologies.................................... ...... 16 4.1 Retrofit Technologies for Control of PM.......

................................................... ............. 17 4.1.1 Existing Baghouse ...........................

................................................... .................... 17 4.1.2 Enhanced Baghouse...........................

................................................... .................. 17 4.1.3 Wet Electrostatic Precipitator (Wet ESP)....

................................................... ........ 17 4.1.4 Dry Electrostatic Precipitator (Dry ESP)....

................................................... ......... 18 4.2 Retrofit Technologies for Control of SO 2

................................................... ................... 18 4.2.1 Switch to Lower Sulfur Coal (LSC) ...........

................................................... ......... 18 4.2.2 Wet Flue Gas Desulfurization (Wet FGD). .....

................................................... .... 18 4.2.3 Spray Dryer Flue Gas Desulfurization (Spray Dry FGD) ...................................... 19 4.2.4 Dry Lime Injection Flue Gas Desulfurization (Dry Lime FGD) ............................ 20 4.2.5 Dry Trona Injection Flue Gas Desulfurization (Dry Trona FGD).......................... 21 4.3 Retrofit Technologies for Control of NO X

................................................... .................. 21 4.3.1 Low NOX Burners (LNB). ......................

................................................... ............ 21 4.3.2 Low NOX Burners with Over-fired Air (LNB/OFA )............................................. 21 4.3.3 Ultra Low NOX Burners (ULNB). ...............

................................................... ....... 21 4.3.4 Selective Catalytic Reduction (SCR).........

................................................... .......... 22 4.3.5 Selective Non-Catalytic Reduction (SNCR)....

................................................... .... 22 5.0 Step 2: Technical Feasibility of Emission Ret rofit Technologies ................................. ... 23 5.1 Feasibility of PM Controls.....................

................................................... ................ 23 5.2 Feasibility of SO 2 Controls .......................................... ............................................. 23 5.3 Feasibility of NO X Controls.......................................... ................................................. 23

5.3.1 ULNB........................................

................................................... ........................... 23

5.3.2 SNCR ........................................

................................................... ........................... 23 5.4 Summary of Technically Feasible and Infeasible Controls .......................................... . 24 6.0 Step 3: Evaluate Effectiveness of Technically Feasible Control Technologies ............... 24 6.1 Effectiveness of Technically Feasible Control Technologies....................................... . 243

7.0 Step 4: Impact Analysis .......................

................................................... ..................... 26 7.1 TASCO Methodology for Impact Analysis .........

................................................... ....... 27 7.1.1 Cost of Compliance..........................

................................................... .................... 27 7.1.2 Energy Impacts. .............................

................................................... ...................... 28 7.1.3 Non-Air Quality Environmental Impacts.......

................................................... ...... 28 7.1.4 Remaining Useful Life.......................

................................................... .................. 28 7.2 Impact Analysis Findings ......................

................................................... ..................... 29 8.0 Additional Emission Reduction and Visibility I mprovement Project ............................... 32 9.0 Step 5: Visibility Impact Analysis ...........

................................................... ...................... 33 9.1 Overview of BART Modeling Procedures ..........

................................................... ....... 33 9.2 Findings of Visibility Impact Analysis........

................................................... ............... 34

10.0 Conclusion and Recommendation ................

................................................... ................ 36

INDEX OF FIGURES

Figure 1 – Comparison of Beet Sugar Prices to Consu mer Price Index.................................... ... 10 Figure 2 – Plan View of Nampa Factory ..............

................................................... ..................... 14

INDEX OF TABLES

Table 1 – Nampa Factory Fuel Costs from 1999 to 200 8.................................................. ............11 Table 2 – Product and Beet Hauling Costs ...........

................................................... ......................11 Table 3 – Maximum Hourly and Average Annual Emissio n Rates for the Riley Boiler ..............15 Table 4 – Technically Feasible and Infeasible Contr ols................................................ ................24 Table 5 – Riley Boiler Control Technology Effective ness Summary ....................................... ....25 Table 6 – Summary of Cost Impact Analysis ..........

................................................... ...................31

Table 7 – Pollutant Reductions Attributable to Shut down of the Pulp Dryers............................ ..32 Table 8 – Visibility Impact Summary – Eagle Cap Wil derness Area ....................................... ....35

INDEX OF APPENDICES

Appendix A – Preliminary Draft Exemption Modeling E valuations Appendix B – Estimating the Probability of the Publ ic Perceiving a Decrease in Atmospheric

Haze Appendix C – The Economics of Growing Sugar Beets i n Southern Idaho: A Short Run Gross Margin Analysis Appendix D – Summary of Baseline Emissions Calculat ions and Assumptions Appendix E – Control Technology Cost and Impact Eva luations Appendix F – Dryer Emissions Calculations and Assum ptions Appendix G – DEQ CALPUFF Impact Analysis Report4 

### Executive Summary

The Riley Boiler at The Amalgamated Sugar Company L LC (TASCO) facility in Nampa, Idaho,

has been identified as a Best Available Retrofit Te chnology (BART) eligible source by the Idaho Department of Environmental Quality (IDEQ). CALPUF F modeling conducted by IDEQ predicted visibility impacts from the Riley Boiler exceeding BART exemption thresholds at three Class I areas, all of which are over 70 miles from the facility. As required by IDEQ, a sitespecific BART determination analysis has been condu cted pursuant to EPA guidelines that were developed for large electricity generating faciliti es. There are no published guidelines for

smaller industrial facilities.

This report summarizes the BART analysis performed for the Riley Boiler. The Riley Boiler is fired with coal and/or natural gas. It supplies st eam and generates electricity for processing of sugarbeets into sugar and feed products at the Namp a facility. This boiler is located in an area on the factory site that is constrained by building s and equipment. Predicted visibility impacts encompass emissions of particulate matter (PM), sul fur dioxide (SO 2) and oxides of nitrogen (NO X) . BART determination guidelines prescribe a step b y step process to identify and screen retrofit technology options using several factors, including affordability, in identifying and assessing potential emission control technologies f or the Riley Boiler. In addition the analysis considers the visibility benefits of a recently com pleted emissions control measure which involved replacement of coal-fired pulp dryers with a state-of-the-art steam dryer.

Multiple possible retrofit technologies for control of PM, SO 2 and NO X from the Riley Boiler

were identified. The alternatives were screened fo r applicability and then evaluated with regard to cost, energy and non-air environmental impacts. Emissions of PM from the Riley Boiler are presently controlled with a baghouse. This analysi s found no other technologies that will control PM more effectively than the existing baghouse. Th erefore, the BART determination analysis for the Riley Boiler focuses on technologies for co ntrol of SO 2 and NO X emissions.

Visibility modeling was conducted to evaluate poten tial improvements attributed to each viable retrofit technology. The modeling indicated the Ea gle Cap Wilderness Area is most sensitive to Riley Boiler. The CALPUFF modeling found that NO X controls can theoretically reduce visibility impacts of the Riley Boiler in the Eagle Caps up to 0.47 deciviews. SO 2 controls can reduce impacts up to 0.45 deciviews, while combined NO X and SO 2 control scenarios could benefit visibility in the Eagle Caps up to 0.82 dec iviews. However, it is important to note that recent studies have verified that these marginal im provements of less than one deciview will not be perceptible to people who recreate in the Eagle Caps or other affected Class I areas.

Affordability is also an important factor that infl uences the BART determination. The economic cost to TASCO and its grower-owners must be weighed against the benefit derived from BART implementation. In its modeling report DEQ recomme nded the control technology of low NO X burners and over fire air to reduce NO X combined with spray dryer flue gas desulfurization to reduce SO2 emissions from the Riley Boiler. The ca pital cost impact on TASCO to implement this scenario is estimated to be $17.8 million. This equates to about $114,000 for each grower that supplies sugarbeets to the Nampa factory. At current sugarbeet yields and prices this project would require the typical Nampa factory grower to f orfeit more than two years of earnings to5

reduce haze by an increment that is imperceptible. Therefore, after following BART guidelines including a cost-benefit analysis, TASCO has determ ined that additional emission controls for the Riley Boiler beyond the existing baghouse are n ot justified.

TASCO proposes to include the reductions in emissio ns and visibility impacts associated with the recent shutdown of the pulp dryers at the Nampa facility. This was accomplished by a $20 million steam dryer project that was commissioned i n 2006 and made fully operational in the 4 th
quarter of 2007. The shutdown of the pulp dryers s ignificantly reduced emissions by decreasing coal usage. Coal usage has been reduced by approxi mately 200 tons per day which is equivalent to shutting down a 150,000 pound per hour boiler. Estimated annual emissions of PM, SO 2 and

NO X will be reduced by 350 tons per year. This projec t was affordable because the capital cost was offset by significant reduction in operating co sts. The visibility improvement afforded by the steam dryer project is 0.31 deciviews, the same order of magnitude as the separate NO X and

SO 2 technologies and nearly half of the benefit of the most costly combined NO X and SO 2 scenario. This project was feasible because it add ed value by decreasing energy consumption which decreased annual operating costs by about the same amount as the annual payment to finance the capital for the steam dryer.6

1.0 Introduction

1.1 BART Regulatory Overview

The Clean Air Act (CAA) amendments of 1977 establis hed a national goal to reduce manmade visibility impairment in all Class I scenic ar eas in the United States to natural background levels. To address visibility provision s of the statute, the U.S Environmental Protection Agency (EPA) promulgated regulations und er 40 CFR Part 51 Subpart P. These regulations require states to adopt implementation plans to protect visibility by including measures to control regional haze from all sources such as forest fires, motor vehicles, wind blown dust, power plants and other stationary sourc es. The regulations require states to submit regional haze plans with “reasonable progres s goals” for reducing visibility impairment in Class I areas, to natural background levels, by 2064.

As part of the regional haze plans, specific types of stationary sources may be required to install Best Available Retrofit Technology (BART) t o reduce emissions. EPA and Idaho Department of Environmental Quality (IDEQ) BART pro visions are summarized as follows:

• Eligible Sources – The BART provisions apply to “major stationary s ources” from 26 specified source categories, which have potential t o emit 250 or more tons per year of any air pollutant. BART applies to sources constru cted between 1962 and 1977. The largest emitting stationary sources subject to the BART requirements are coal-fired electric utility boilers.

• Visibility Modeling Analysis – Air dispersion modeling evaluations are conducte d by state regulatory agencies to determine whether pred icted impacts from the BART eligible sources may cause or contribute to impairm ent of visibility in a Class I area. A source is subject to a BART determination if it i s reasonably anticipated to cause or contribute to impairment in a Class I area. Accord ing to Appendix Y Guidelines a source is considered to “cause” visibility impairme nt if the modeled 98 th percentile change is 1.0 deciview or more. A source is consid ered to “contribute” to visibility impairment if the modeled change is equal to or gre ater than 0.5 deciviews.

• BART Determination Analysis – This analysis focuses on evaluating feasible emission control alternatives for the BART eligible sources. To determine whether BART controls are appropriate, potential retrofit t echnologies are identified and subjected to impact analysis, including affordabili ty of additional emission controls and the degree of visibility improvement. This is followed by selection of BART.

The EPA prescribed approach for conducting a BART d etermination analysis is detailed in Appendix Y to 40 CFR Part 51 – Guidelines for BART Determinations Under the Regional
Haze Rule (Appendix Y Guidelines)

. TASCO and IDEQ have worked collaboratively to address the BART provisions for the Riley coal-fire d boiler at the Nampa facility, which was identified by IDEQ modeling as a requiring a BART d etermination.

It is important to acknowledge the genesis and scop e of the Appendix Y Guidelines. They are specifically focused on large power plants. Se ction 169A(b) of the CAA states In the7

case of a fossil-fuel fired generating powerplant h aving a capacity in excess of 750 megawatts, the emission limitations required under this paragraph shall be determined pursuant to guidelines, promulgated by the Administ rator under paragraph (1). The law does not specify whether or how the guidelines appl y to other than 750 megawatt plants. In the preamble to the Regional Haze Regulations and G uidelines for BART determinations,

EPA stated it would not be appropriate for EPA to require stat es to use the guidelines in making BART determinations for other categories of sources and that Congress intended the guidelines to be mandatory only with respect to 750 megawatt powerplants. In spite of this caveat in 2007 IDEQ incorporated the guidelines by reference in IDAPA Section 107.

1.2 IDEQ “Subject to BART” Visibility Modeling for Riley Boiler
The Riley Boiler is BART-eligible because it meets the minimum criteria: it falls in one of 26 sector categories; it was built between 1962 and 1977; and it exceeds the BART qualifying threshold of 250 tons of haze-causing po llutants annually.

Based on EPA guidance pollutants that have potentia l for impacting visibility in Class I areas include particulate matter (PM), sulfur dioxide (SO 2 ), and oxides of nitrogen (NO X ). On July 19, 2007, IDEQ finalized the “Subject-to-BART” anal ysis for the Riley Boiler at the Nampa facility. As discussed in IDEQ’s report, visibilit y modeling was based on a protocol jointly developed by environmental agencies in Washington, Oregon and Idaho. 1 On April 23, 2007 TASCO provided comments to IDEQ on a draft copy of the visibility modeling report. A copy of TASCO comments is included in Appendix A.

Visibility modeling was conducted by IDEQ using EPA ’s CALPUFF model. IDEQ utilized several conservative assumptions including maximum hourly emissions rates. Based on these conservative assumptions, predicted wintertim e visibility impacts from the Riley Boiler

exceeded contribution threshold levels at three Cla ss I areas, including the Eagle Cap Wilderness and Strawberry Mountain Wilderness, both in Oregon and the Hells Canyon National Recreation Area located on the Idaho/Orego n border.

The modeling analysis completed by IDEQ in July 200 7 found that the predicted visibility impacts of the Riley Boiler on Class I areas in the region exceed the 0.5 deciview threshold. Based on this analysis Riley Boiler emissions were found to “contribute to” rather than “cause” visibility impairment in Class I areas. As a result IDEQ determined the Riley Boiler is “subject to BART requirements.”

Visibility impacts predicted by the CALPUFF model h ave never been validated against actual visibility measurements or observations in t he Class I areas. In fact recent scientific studies of the ability of humans to perceive change s in atmospheric haze have concluded that a one deciview decrease in light extinction is not likely to be perceived by the general public. In order for a visibility change to be noticeable b y the general public the change must be at least 3.5 to 7 deciviews. This report, entitled Estimating the Probability of the Public Perceiving a Decrease in Atmospheric Haze, is included in Appendix B.

1 Modeling protocol for Washington, Oregon and Idaho : Protocol for the Application of the CALPUFF Mode ling System Pursuant to the Best Available Retrofit Tech nology (BART) Regulation.8

1.3 Approach to Riley Boiler BART Analysis
As requested by IDEQ in the July 2007 report, TASCO has conducted a BART determination for the Riley Boiler. TASCO utilized Appendix Y Guidelines and Idaho’s BART regulations in IDAPA 58.01.01.668. In making a BART determination the CAA and Appendix Y Guidelines require the state to consider the following five factors:

• The costs of compliance,

• The energy and non-air quality environmental impact s of compliance,

• Any existing pollution control technology in use at the source,

• The remaining useful life of the source, and

• The degree of visibility improvement which may reas onably be anticipated from

the use of BART.

One factor in the cost impact analysis of the Appen dix Y Guidelines is consideration of affordability of BART controls. Specifically, will installation of controls affect the viability of continued plant operations? For TASCO, affordab ility is the most important factor since the economic viability of continued operations with in current sugar market constraints is an ongoing issue.

In addition to evaluating potential BART for the Ri ley Boiler this analysis includes information and visibility evaluation of the recent ly completed project that eliminated three coal-fired dryers and replaced them with a steam-he ated dryer. This project in combination with other energy-saving projects resulted in signi ficant reduction in coal burning and associated emissions from the old dryers.

2.0 Overview of Company, Facility, and BART Subjec t Equipment

2.1 Company Description
Privately owned until 1997, TASCO was purchased by the Snake River Sugar Company (SRSC), an Oregon agricultural cooperative, consist ing of approximately 1,200 grower members. Since 1997 due to beet production economi cs the number of grower-owners has decreased to about 625. About ninety percent of SR SC members are residents of Idaho. The company operates three sugarbeet processing facilit ies which are located in Paul (est. 1918), Twin Falls (est. 1916), and Nampa (est. 1942), Idah o. 2 Each facility is a blend of new stateof-the-art and time proven technology and employs a bout 400 people.

TASCO is the second largest sugarbeet processor in the nation producing as much as 19,000,000 hundred weight (cwt) of granulated sugar per year. The annual economic impact of TASCO’s operations is approximately $1.5 billion . A more detailed description of the economics of the company is presented in the follow ing section. Sugarbeet acreage varies from year to year due to g rowing and market conditions. SRSC members have farmed up to 220,000 acres of sugarbee ts. During the current crop year

2 A fourth facility in Nyssa, Oregon was shutdown in 2005.9

acreage has diminished to approximately 170,000 acr es, in part due to poor springtime growing conditions and competition from other crops such as corn and wheat.

2.2 Beet Sugar Production Economics
Appendix Y Guidelines (70 FR 39171, July 6, 2005) e stablish affordability as a key consideration when conducting a BART determination analysis. Regulatory agencies must

consider whether the cost of BART controls will aff ect the profitability and viability of continued plant operations.

Economically, sugarbeet processing facilities are h igh volume, low margin operations. Historically, TASCO has remained profitable by incr easing the volume of sugarbeets processed and improving efficiencies in order to ab sorb increasing operating costs. The ability to remain profitable by increasing volume i s no longer possible due to marketing allocations implemented by the U.S. Department of A gricultural (USDA) beginning in 2002. The economic viability of the company is threatened by:

• Foreign competition

• Relatively flat sugar prices

• Rising costs to grow sugarbeets

• Rising costs to process sugarbeets

Consistently low sugar prices coupled with increase d operating costs, and reduced acreage has severely impacted the profitability of the grow er owned company. As a result, affordability is the critical component for this BA RT determination analysis. The profitability challenge is demonstrated in Figure 1 which compares beet sugar prices to the consumer price index from1980 through 2007. Throug h the past quarter century the sugar prices have remained relatively static, averaging 2 6.55 cents per pound. During the same time frame the CPI has increased 152%. Because sug ar prices are controlled by the market and government factors, TASCO can process sugar bee ts and provide a return to its growerowners only by improving process efficiency and red ucing costs.10 Figure 1 – Comparison of Beet Sugar Prices to Consu mer Price Index



### Wholesale Beet Sugar Price Compared to

Consumer Price Index

0.00 50.00 100.00 150.00 200.00 250.00

1 980

1

985

1

990

1

995
2

000 2

005

Year Sugar Price (cents per pound) Consumer Price Index

Sugar prices have remained low due in part to incre ased sugar imports from countries that subsidize these industries. These imports have inc reased through “free trade” agreements such as CAFTA (Central American Free Trade Agreemen t). Unlike TASCO, foreign sugar companies are not subject to the same labor, enviro nmental and occupational safety standards required of U.S. sugarbeet companies. Increased im ports have also reduced both USDA sugar allocations and TASCO revenues. As a result, beet payments to the SRSC growers are currently at levels that will not allow the company as a whole to remain competitive, or in the long-term to remain in business.

Factory and transportation fuel costs have increase d dramatically over the last ten years as shown in Table 1. The cost of natural gas has incr eased by nearly 240%, coal has increased over 30%, coke has increased by nearly 100%, and di esel has increased 185%. Due to the high cost of natural gas, coal has been used as the primary fuel for the facility boilers. Since 1990 the price of coke has increased from $100 to o ver $200 per ton, representing over a

100% increase in the cost of coke. In 2008 TASCO h ad to switch from coke to anthracite coal to burn in the limekilns to mitigate the impac t of coke pricing. Because energy costs for operating the facilities are significant, TASCO str ives to optimize energy usage and maximize efficiency.11 Table 1 – Nampa Factory Fuel Costs from 1999 to 200 8

Campaign Natural Gas Coal Coke Diesel Year ($/therm) ($/ton) ($/ton) ($/gal)

1999 0.2370 37.21 124.00 1.12

2000 0.5200 38.10 124.00 1.49

2001 0.4500 35.10 101.00 1.40

2002 0.3500 35.85 101.00 1.32

2003 0.5450 36.61 100.50 1.57

2004 0.6000 35.96 130.00 1.81

2005 0.6000 36.93 175.00 2.46

2006 0.6881 42.52 190.00 2.71

2007 0.7500 48.01 189.00 2.90

2008 0.8000 53.46 245.00 3.20

10 Year Net Increase 0.5630 16.25 121.00 2.08

10-Year % Increase 238% 43.7% 97.6% 186%

a P&M Coal

b Utah Coal from 1999-2007; P&M Compliance Coal in 20 08

Transportation costs have increased significantly i n the past 10 years as demonstrated in

Table 2. Product distribution costs have increased nearly 50% and beet hauling cost has

increased over 150% since 1998.

Table 2 – Product and Beet Hauling Costs

Product Distribution Beet Hauling
Year Cost ($) Cost ($)

1998 $43,100,000 $11,300,000

1999 $42,100,000 $11,400,000

2000 $42,200,000 $16,800,000

2001 $50,700,000 $13,100,000

2002 $40,700,000 $13,200,000

2003 $47,700,000 $18,500,000

2004 $50,300,000 $19,800,000

2005 $57,500,000 $21,800,000

2006 $54,500,000 $29,500,000

2007 $63,200,000 $28,900,000

Net $20,100,000 $17.600,000

% Increase 46.6% 156%12

This analysis does not account for increases in ope rating costs of other materials, including lime rock, byproducts. Since these other costs are directly affected by transportation costs,

similar increases have occurred.

All of these cost increases have resulted in signif icant decreases in beet payments to the growers, whose livelihood depends upon a reasonable return on their investment. More disturbing is that many of these growers are turnin g to alternative crops such as wheat and corn which provide better revenues for their farmin g operations. Loss of grower members diminishes the ability of the cooperative to sustai n itself.

The motivation for growers to make the decision to plant sugarbeets each year is their expected margin of return. The University of Idaho recently completed a report entitled The Economics of Growing Sugarbeets in Southern Idaho: A Short Run Gross Margin Analysis

. This report, contained in Appendix C, identified th ree distinct production zones in southern Idaho: the Treasure Valley, the Magic Valley, and t he lower Snake Plain. The report presents a methodology to help growers to choose wh ich cash crop to grow based on expected market conditions and costs of doing busin ess. In 2009 sugar beets are expected to provide a competitive gross margin over $300 per ac re to farmers in the Magic Valley and lower Snake Plain, while the margin in the Treasure Valley is expected to be about $168 per

acre.

2.3 Description of Nampa Factory, Operations and S ite Constraints
The Nampa Factory is located in the city of Nampa a long the north side of West Karcher Road generally to the north and west of the interse ction of Northside Boulevard. The facility produces refined sugar for various markets from sug arbeets. Beet processing byproducts produced at the facility include dried beet pulp, c oncentrated separator byproduct (CSB), liquid sugar and betaine. Sugarbeets are typically processed from early October through January. The length of the beet processing campaig n is dependent on the size of the beet crop, which varies considerably each year due to cl imatic factors and availability of irrigation water during the growing season. Following the bee t processing campaign, stored sugar juice and molasses are processed during the spring and summer.

Emission sources at the Nampa facility include four boilers, two limekilns and other minor

sources. Three of the boilers burn low sulfur coal (< 1%) or natural gas (Riley, B&W #1 and B&W #2) and one boiler (Union) fires only natural g as to provide steam to concentrate sugar juices, dry pressed pulp and co-generate electricit y. Emissions from the coal-fired boilers are controlled with baghouses. The limekilns are capab le of being fired with either coke or anthracite coal to produce calcium oxide and carbon dioxide gas for the juice purification process. Minor particulate sources, which are prim arily controlled with baghouses, include sugar and material handling equipment emissions.

A plan view drawing of the main buildings at Nampa facility is shown in Figure 2. The Riley Boiler is inside the Boiler House which is ce ntrally located. The Riley Boiler baghouse is adjacent to the Boiler House. For the purpose of this analysis it is important to note the numerous buildings and lack of space in the vicinit y of the Boiler House. This congestion is13

an impediment and will increase the cost of potenti al add-on emission control technologies that require real estate.14 Figure 2 – Plan View of Nampa Factory15

2.4 Riley Boiler Description and Constraints

2.4.1 Boiler Specifications and Fuel. The Riley Boiler at the Nampa sugarbeet processing facility has a heat input rating of 350 million BTUs per hour (MMBtu/hr) and a steam production rating of 250,000 pounds per hou r. The Riley Boiler is fired by pulverized coal and/or natural gas. The Riley Boil er has potential to emit (PTE) 250 tons per year (tpy) or more of SO 2 or NO X

.

2.4.2 Operating History and Useful Life. The Riley Boiler was placed in service in 1969. Each year the boiler is removed from service to perform maintenance as needed to ensure efficient and reliable service for the upcom ing year. Typically industrial boilers such as the Riley Boiler can be maintained indefini tely. The remaining service life of the Riley Boiler is likely to extend until the time in the future when the Company determines that it is no longer needed.

2.4.3 Existing Control Equipment. Particulate emissions from the Riley Boiler are controlled with a baghouse filtration system. The existing baghouse was installed in 1973 and has been in continuous operation since tha t time. An additional bag house module was installed in 1974 to improve collection performance. The baghouse was manufactured by Envirotech Corporation and consists of 4 modules.

2.4.4 Baseline Emission Rates . Annual emissions from the Nampa facility vary ba sed on the size of the beet crop. Short-term emissions (hourly or daily) vary significantly depending on the time of year. During the beet cam paign, which occurs in the fall and winter months, all factory equipment including the boilers, pulp dryers and lime kilns are operating at or near maximum capacities. During th e juice run, which occurs following the beet campaign (late winter, spring and summer), only one boiler and the sugar end equipment are in operation.

Baseline emissions have been estimated in accordanc e with the Appendix Y Guidelines. According to Appendix Y baseline emissions rate should represent a realisti c depiction of anticipated annual emissions for the source. Anticipated annual emissions are to be established from a baseline period. For the Riley Boiler TASCO identified the baseline period as the years 2003, 2004 and 2005. Estimated baseline emissions for the Riley Boiler for the years 2003 through 2005 operations a nd are summarized in Table 3. A summary of baseline emission calculations and assum ptions is presented in Appendix D.

Table 3 – Maximum Hourly and Average Annual Emissio n Rates for the Riley Boiler

Pollutant Maximum Hourly

(lbs/hour) Average Annual (tons/year)

PM 12.4 34.5

SO 2 522 1457

NO X 374 104216

In Table 3 the Maximum Hourly Emissions data repres ent emissions from Baseline Year

2004. Baseline Year 2004 data was used because it was the highest of the three baseline years. Average Annual Emissions represent the aver age of the three baseline years.

Note that the PM emission rates in Table 3 are cont rolled because they are based on measured emissions of the exhaust from the existing Riley Boiler baghouse.

Uncontrolled emission rates for PM have not been me asured. Emission rates of SO 2 and

NO X in Table 3 are not controlled.

3.0 BART Determination Analysis Methodology

The methodology for this analysis follows the Appen dix Y Guidelines. Pursuant to the guidelines, TASCO evaluated a variety of technologi es that have potential to reduce PM, SO 2 , and NO X emissions from the Riley Boiler. It is important to note that these guidelines were created for large electric generating units, so the y do not address considerations that may be unique to much smaller industrial boilers like the Riley Boiler. The guidelines prescribe data collection and analysis through a five step process :

Step 1: Identify all available retrofit control te chnologies Step 2: Eliminate technically infeasible options Step 3: Evaluate control effectiveness of remaini ng technologies Step 4: Evaluate impacts and document the results Step 5: Evaluate visibility impacts

Data generated from the above-listed steps are reco mmended to evaluate the costs and benefits of various potential control technologies in order to determine whether feasible controls can be

installed on the BART source that result in benefic ial improvements in visibility impacts within Class I areas. Most commonly discussed BART altern atives for industrial boilers are based on emission control technologies that were primarily d eveloped for much larger coal-fired boilers at electric utility power plants. For industrial boil ers like the Riley, electric utility boiler control technologies are cost prohibitive.

The cost analysis for selected control technology a lternatives follows the methodology outlined in the EPA Cost Control Manual ( QAQPS Control Cost Manual, Fifth Edition, February 1996, EPA 453/B-96-001)

.

4.0 Step 1: Identify All Available Retrofit Contr ol Technologies

The first step of the BART guidelines is to identif y all available retrofit control technologies. A control technology is considered “available” if: 1 )The technology is obtainable through commercial channels or other means, or 2)It is othe rwise available within the common sense meaning of the term. A control technique is genera lly available if it has reached the stage of licensing and commercial availability. Technologie s that have not been applied to full scale operations are not considered available. The techn ology can be a method, system, or technique17

that will reduce emission of a pollutant. Control technologies required as BACT or LAER are considered available for BART purposes and must be included as control alternatives. Control alternatives can include not only existing controls for the source category in question but also take into account technology transfer of controls t hat have been applied to similar source categories and gas streams.

An available control technology is considered “appl icable” if it can reasonably be installed and operated on the same or similar source type under c onsideration. Control technologies are “technically feasible” if either 1) they have been installed and operated successfully for the type of source under review under similar conditions, or 2) the technology could be applied to the source under review. A technology that is availabl e and applicable is generally considered technically feasible. Technical feasibility of con trol technology is determined in the Step 2 evaluation which is presented in Section 5.

TASCO evaluated the potential control technologies available for PM, SO 2 and NO X emissions consistent with Appendix Y Guidelines. Technologie s were identified based on the EPA clearinghouse and fact sheets, vendor reviews and i ndustry experience. The available and emerging control technologies comprise a significan t list of choices for review. TASCO relied on recently implemented and proven technologies ide ntified in the EPA’s online RACT, BACT, and LAER Clearinghouse. These technologies are lis ted below along with a discussion of their practical application to the Riley Boiler.

4.1 Retrofit Technologies for Control of PM

4.1.1 Existing Baghouse . The existing baghouse efficiently reduces PM to very low levels. Measured PM emissions are 0.036 lbs/MMBTU, well below the previously proposed industrial boiler MACT standard of 0.07 lb s/MMBTU. Control efficiencies for baghouses are reported to be 99.0 to 99.9%. For th e purposes of this evaluation, TASCO assumed the control efficiency is 99%.

4.1.2 Enhanced Baghouse. The addition of a baghouse module may marginally improve the removal efficiency of the existing bagh ouse. This option would expand the number of modules from four to five resulting in re duced baghouse velocities and pressure drop. Adding another baghouse module to t he Riley Boiler baghouse will be difficult and expensive because of physical space l imitations near the existing baghouse. PM control efficiency for the addition of the modul e is assumed to be 99%.

4.1.3 Wet Electrostatic Precipitator (Wet ESP) . A Wet ESP consists of a series of collection surfaces in the device that remove parti culate using an electrical field. The plates are continuously or intermittently cleaned u sing a circulating water system. Control efficiencies for Wet ESP systems are report ed to be 99.0 to 99.9%. For the purposes of this evaluation, TASCO assumed a contro l efficiency of 99%.

TASCO evaluated the addition of a Wet ESP for the R iley Boiler. Because of physical space limitations, the installation of the Wet ESP equipment will require demolition and removal of the existing baghouse and installation o f the Wet ESP in its place. In addition18

because the system will produce saturated vapor con ditions in the stack during some operating scenarios, a liner will need to be instal led in the existing stack to protect the

stack from corrosive conditions.

4.1.4 Dry Electrostatic Precipitator (Dry ESP) . A Dry ESP is very similar in operation to the WESP option considered above. The particulate to be removed is charged in an electric field and attracted to a col lection plate. Control efficiencies for Dry ESP systems are reported to be 99.0 to 99.9%. For the purposes of this evaluation, TASCO assumed a control efficiency of 99%.

Collected particulate is removed from the plate usi ng a mechanical “rapping system”. To avoid re-entrainment of particulate in the exhaust, the Dry ESP is designed with several staged fields of operation that perform cleaning cy cles at different times. Because this control technology does not result in saturated flu e gas conditions, a stack liner is not needed. The Dry ESP will require demolition and re moval of the existing baghouse to provide space for installation of equipment.

4.2 Retrofit Technologies for Control of SO 2

4.2.1 Switch to Lower Sulfur Coal (LSC). This option consists of purchasing more costly coal that has lower sulfur content. The cur rent low sulfur coal used at Nampa has a contract limit of less than 1% by weight to compl y with the Rules for Control of Air Pollution in Idaho. Average actual percent sulfur for the baseline period is approximately 0.75 %. The coal supplier indicates that they coul d provide a contract for 0.6% sulfur or

an actual reduction in sulfur content of 15%. This reduction is realized at a significant cost premium, currently estimated at about $10.00 p er ton. The actual cost may be higher than current projections, because low sulfur coal i s being proposed as BART for many major facilities (mainly electric power generation stations). This is expected to have a

more dramatic effect on the future demand and avail ability of fuel than the Nampa facility.

Because separating coal storage and handling system s to accommodate two different sulfur content coal supplies will be technically un acceptable, converting to lower sulfur

coal will also result in SO 2 emission reductions from the factory’s B&W boilers. However, for the purpose of the cost analysis for t his option, emission reduction and costs were assumed only for the Riley Boiler.

4.2.2 Wet Flue Gas Desulfurization (Wet FGD). A Wet FGD system typically

consists of saturated absorber towers located downs tream of a particulate control device. The absorbers are usually configured as a flooded t ray system or a spray tower. Flue gas entering the absorber reacts with slurried limeston e or slaked lime to remove SO 2 at the liquid/gas surface boundary. The reaction forms in soluble products or solids that are

further treated with forced oxidation to convert to gypsum which is a marketable byproduct. Unlike other options considered for SO 2 removal, Wet FGD will not affect flyash sales. The treated flue gas passes through a mist eliminator system to remove19

water droplets from the flue gas stream. The flue gas leaving the absorber is saturated with water vapor and can present a visible steam pl ume from the stack.

Wet FGD systems offer one of the highest SO 2 removal efficiencies of the available control technologies with removal rates of 95% or g reater. However, vendors report that WFGD technology has not been shown to be cost effec tive for industrial boilers the size of the Riley Boiler.

Wet FGD retrofit will require significant modificat ion of a facility. Key site-specific

considerations are as follows:

Lining the Existing Stack – Wet FGD results in saturated stack conditions durin g periods of Riley only operation (shared stack opera tion during beet campaign with the B&W boilers is not anticipated to result in saturat ed stack conditions). The resulting condensation formed in the stack is anticipated to have very low pH values that will require installation of a stack liner to protect th e integrity of the stack. Condensed vapors will need to be neutralized. Installation of stack liners is very expensive, currently estimated at $2,000,000.

Wastewater Treatment

– Because Wet FGD is a wet process, it will genera te a wastewater stream. The actual wet process is expec ted to be contained within the Wet FGD system with a slip stream discharged for wa stewater treatment. The impacts of this slip stream cannot be quantified wi thout more design information which is beyond the scope of this level of technolo gy evaluation. However the costs of added equipment and operation to handle the resi duals will offset the benefits of this technology.

4.2.3 Spray Dryer Flue Gas Desulfurization (Spray Dry FGD) . Spray Dry FGD consists of a spray dryer reactor to be located bet ween the exhaust outlet of the boiler and upstream of a particulate removal device (usually a n electrostatic precipitator or baghouse). The reactor consists of a spray dryer a bsorber tower and support equipment. Flue gas is introduced into a vessel and contacts a n atomized spray pattern of lime slurry generated by either a set of dual fluid nozzles or a rotary atomizer. The reaction to

remove SO 2 occurs on lime slurry droplets as they are evapora ted from the heat of the flue gas to form a dry particle.

Because the exit temperature of the reactor must be maintained at a set temperature above the adiabatic saturation temperature of the flue ga s (controlled by slurry feed rate), the product removed from the system is in dry form. Th e emission control efficiency of the reactor increases as the exit flue gas temperature approaches the adiabatic saturation temperature of the flue gas. The approach temperat ure is typically set at 30 to 40 oF above adiabatic saturation temperature (correspondi ng to removal efficiencies of 90% and 80% respectively). Recycling fly ash into the lime slurry feed mixture may increase emission control efficiency depending on the chemic al characteristics of the ash. It is important to note that spray dryer solids are not s uitable as a concrete additive. This control option will eliminate the opportunity for s ale of flyash. Control efficiencies for20

Spray Dry FGD systems are reported to vary between 80 and 90%. For the purposes of this evaluation, TASCO assumed a higher approach te mperature (40 oF to protect the baghouse) and a control efficiency of 80%.

A Spray Dry FGD retrofit project will require signi ficant modifications to the facility. Key site-specific considerations are as follows:

Baghouse Interferences – The particulate loading to the baghouse will increa se as a result of installing a spray dryer. In addition to the ash entering the reactor with the flue gas, the spent lime (with flyash recycle) cont ributes to significant overall particulate loading. Approximately 60% of the form ed solids are predicted to drop out (and be removed) in the reactor, while 40% will be carried to the baghouse for removal. The incremental particulate loading will likely require the addition of a baghouse module or a new baghouse.

Because the spray dryer outlet operates so close to the adiabatic saturation temperature of the flue gas, operational upsets can lead to significant moisture excursions and blinding of filter bags if a baghous e is used for particulate removal, such as the case with the Riley Boiler baghouse. T his can be avoided to some degree by operating at a higher approach temperature (at e xpense of control efficiency) or reheating the flue gas before entering the baghouse

.

4.2.4 Dry Lime Injection Flue Gas Desulfurization (Dry Lime FGD). Dry Lime FGD consists of injecting pulverized lime (milled to le ss than 10 microns) into the flue gas down upstream of a baghouse. Vendors are generally unwilling to provide emission control performance guarantees unless they also sup ply the baghouse. The cost analysis for this option was determined using a new vendor s upplied baghouse installed downstream of the existing baghouse. The emission control efficiency of Dry Lime FGD is critically dependent upon:

Particle Size – The smaller the lime particle size the greater t he surface area for

reaction. Lime is milled to less than 10 microns us ing ball mills. The smaller size of the particles is also important to avoid downstream deposition of dust in equipment

and ductwork.

Temperature – Reaction rate increases with increased temperatu re of the flue gas.

Flue Gas Mixing – Good lime particle mixing with the flue gas is i mportant to provide uniform distribution of lime reactant in th e baghouse.

The Dry Lime FGD project will be costly if a new ba ghouse is required for the Riley Boiler. Although not considered in the economic an alysis, the use of the existing baghouse (with significant modifications) may be po ssible. Modifications include expensive ductwork reconfiguration with the additio n of at least one and possibly two baghouse modules.21

The control efficiency for DLIFGD is reported to va ry between 45 to 55%. For the purposes of this evaluation, TASCO assumed a contro l efficiency of 55%.

4.2.5 Dry Trona Injection Flue Gas Desulfurization (Dry Trona FGD). Trona is a naturally occurring source of sodium carbonate that is available from mines in Wyoming. Similar to Dry Lime FGD, Dry Trona FGD consists of injectin g pulverized trona (milled to less than 10 microns) into the flue gas downstream of th e existing baghouse and upstream of a newly installed baghouse. The injection system req uirements and technical characteristic are very similar to the Dry Lime FGD system discuss ed above.

The control efficiency for Dry Trona FGD is reporte d to range between 55 to 65%. For the purposes of this evaluation, TASCO assumed a co ntrol efficiency of 65%.

4.3 Retrofit Technologies for Control of NO X

4.3.1 Low NOX Burners (LNB). Low NO X burners are designed to reduce the flame temperature within combustion zones to lower NO X emissions. Generally fuel is staged in three combustion zones as follows: 1)Zone 1 – pr imary combustion occurs under fuel rich and oxygen deficient conditions; 2)Zone 2 – sm aller amounts of fuel are added and

NO X is chemically reacted in a slightly oxidized atmos phere; and 3)Zone 3 – final combustion is completed by limiting excess air to m inimize flame temperatures.

There are many LNB designs based on vendor propriet ary information. LNB retrofit projects are technically challenging and require si gnificant engineering evaluations to properly size and adapt a particular low NO X burner system to a given boiler and burner configuration. The estimated NO X removal efficiency reported for this technology is 30% to 50%. For the purposes of this evaluation, T ASCO assumed a control efficiency

of 50%.

4.3.2 Low NOX Burners with Over-fired Air (LNB/OFA )

. Over fired air systems inject a portion of the combustion air downstream o f the fuel burner system to lower flame temperature and the formation of NO X . Over-fired air as a stand alone retrofit technology can be difficult to control causing comb ustion issues with a pulverized coal boiler, including water wall corrosion and reduced boiler efficiencies. When combined

with a low NO X burner and reasonable combustion air control (appr oximately 10 to 20 % as OFA), NO X removal efficiencies can approach 65%.

4.3.3 Ultra Low NOX Burners (ULNB). Ultra low NO X burners are upgraded LNB designs which involve further control and staging o f combustion air and fuel. One refinement of the LNB is staged combustion air inst ead of staged fuel sometimes referred

to as the Ultra Low NO X Burner. This technology can achieve high NO X emissions control in new boilers, especially fluid bed and na tural gas application. However, for retrofit situations, especially pulverized coal fir ed boilers, ULNB is not a reasonable feasible for the Riley Boiler because the small fir ebox volume will adversely affect the flame management system.22

4.3.4 Selective Catalytic Reduction (SCR) . Selective catalytic reduction systems

reduce NO X by injecting ammonia or urea into the flue gas bef ore it passes through a catalytic grid to reduce the NO X to N 2 . This technology requires the flue gas exhaust from the Riley baghouse to be heated to 500oC befor e injecting ammonia or urea and passing the hot gasses through the selective cataly tic grid. After treatment, heat is recovered in a heat exchanger to minimize operating costs to reheat the flue gas. This technology is capable of reducing NO X emissions by 70% to 90%. For the purposes of this evaluation, TASCO assumed a control efficiency of 90%.

SCR retrofit projects generally result in significa nt modifications to an existing site. Key site-specific considerations are as follows:

Exhaust Gas Temperature – SCR requires the exhaust gas temperature from th e Riley Boiler to be heated to 500oC (932oF).

Ammonia Slip – Ammonia slip may cause significant downstream issue s including emissions of ammonia, ash contamination and ductwor k deposits from the formation of sulfate compounds (may require periodic cleaning of the gas path and stack). Ammonia emission limits are typically between 2 and 10 ppm. If ammonia slip exceeds these values, a visible plume may result. Ammonia slip increases as the catalytic grid effectiveness declines, leading to p eriodic replacement of the catalytic grid estimated to occur every three years.

Ammonia Storage – Storing large volumes of ammonia is a significant p otential hazard to facility operating personnel and the envi ronment in the event of a catastrophic release of the material.

Soot Blowers – According to the literature, soot blowers are used to periodically clear the catalytic grid of solids buildup from the formation of ammonium sulfates and other particulate residues.

Other – Operating costs were based on periodic replacement of the catalyst, maintenance needs, and estimated ammonia consumptio n of 695 tons per year

4.3.5 Selective Non-Catalytic Reduction (SNCR)

. SNCR consists of injecting ammonia or urea into boiler flue gases in a narrow temperature zone of 1550 to 1950 oF. To achieve temperatures in this range the injection point must be located between the Riley Boiler economizer and the air preheater. The process relies on good gas mixing in this narrow high temperature zone to reduce NO X to N 2 as the flue gas moves through the ductwork. Boiler load swings can lead to temperatu re changes at the injection that can significantly reduce removal efficiencies. In addi tion, temperature swings at the injection points can lead to “ammonia slip” or the condition where un-reacted ammonia passes through downstream equipment, including the baghous e and discharges from the stack.23

5.0 Step 2: Technical Feasibility of Emission Ret rofit Technologies

Step 2 of the BART analysis involves screening of a ll available retrofit control technologies identified in Step 1 for technical feasibility.

In addition to availability, a technology must be t echnically applicable to the source under consideration. That is, the technology must have b een commonly used on similar source to be considered applicable. Potentially applicable retr ofit control alternatives may also include pollution prevention, add-on controls, and combinat ions of controls. Technical feasibility may be influenced by physical, chemical or engineering constraints of the site or the BART source. The Appendix Y Guidelines suggest including an expl anation of why technical limitations preclude use of a control option on the BART source . Cost is not a valid reason for excluding a potential control technology.

For all the technologies identified as available in Section 4, a determination was made regarding the feasibility of the technology for the Riley Boi ler at the TASCO Nampa facility. In describing the technology in Section 4, limitations and constr aints that may affect applicability were highlighted. In this section technically infeasibl e retrofit technologies are identified along with rationale as to why they have been disqualified fro m additional analysis.

5.1 Feasibility of PM Controls
Based on vendor discussions, other BART reports, em ission control literature and engineering judgment, all control options identifie d in Step 1 for PM are technically feasible.

5.2 Feasibility of SO 2 Controls
Based on vendor discussions, other BART reports, em ission control literature and engineering judgment, all control options identifie d in Step 1 for SO 2 are technically feasible.

5.3 Feasibility of NO X Controls

5.3.1 ULNB. TASCO has determined that the ULNB control techno logy is not technically feasible for the Riley Boiler. The boi ler’s existing firebox is not large enough to accept the full burner/flame management system n ecessary for ULNB.

5.3.2 SNCR . TASCO has determined that SNCR technology is not technically feasible for the Riley Boiler. SNCR control effectiveness i s predicated on reasonable flue gas residence time in the narrow temperature range requ ired for the reaction. As previously mentioned the injection point for the system would be between the economizer and the air preheater. The gas path for the boiler lacks t he necessary residence time to reliably

remove NO X . This is further exacerbated by boiler load swing s that will radically change the temperature profile at the injection point(s). Additionally the results of upsets could lead to “ammonia slip” or uncontrolled emissions of the reactant ammonia and sulfate formation in the air preheaters that can deteriorat e the performance of the Riley Boiler.24

5.4 Summary of Technically Feasible and Infeasible Controls

Table 4 summarizes the technically feasible control technologies that TASCO has selected

for further evaluation in the BART Determination. Infeasible technologies are also included with an explanation of why they were rejected:

Table 4 – Technically Feasible Control Technologies

Pollutant Technology Feasible Reason Not Feasible

PM Existing Baghouse Yes None

Enhanced Baghouse Yes None Dry ESP Yes None

Wet ESP Yes None

SO 2 Lower Sulfur Coal (LSC) Yes None

Wet FGD Yes None Spray Dry FGD Yes None Dry Lime FGD Yes None Dry Trona FGD Yes None

NO X Low NO X Burners Yes None

LNB/OFA Yes None

Ultra Low NO X Burners No Boiler firebox is not large enough to support the flame management system Selective Catalytic Reduction (SCR) Yes None

Selective Non-catalytic Reduction (SNCR) No Boiler gas path does not have adequate

residence time for reliable control

6.0 Step 3: Evaluate Effectiveness of Technically Feasible Control Technologies

After all technically feasible control technology a lternatives are identified in Step 2, the effectiveness of each control technology is evaluat ed and the technologies are ranked in order of

effectiveness. The effectiveness is rated in terms of tons per year of post-control emissions.

Data for control effectiveness of each technology w as obtained from regulatory evaluations, manufacturer’s performance data, engineering estima tes, and demonstrated effectiveness of the technology at operating sources. If a range of con trol effectiveness for a technology was reported, generally the most stringent level was us ed in this ranking.

6.1 Effectiveness of Technically Feasible Control Technologies
For each of the feasible control technologies ident ified in Section 5, TASCO determined the baseline maximum hourly emission rate, baseline ave rage annual emission rate, anticipated efficiency of emissions control, expected maximum h ourly emission rate and expected25

annual emission rate. This data is summarized in T able 5. Note that for PM the baseline emissions and the expected emissions are the same b ecause the existing baghouse was used to establish baseline emissions and all technologie s were assumed to have the same efficiency.

Table 5 – Riley Boiler Control Technology Effective ness Summary

Pollutant Control Option BART Baseline

Maximum

Emission Rate (lbs/hour) BART Baseline

Average Annual Emissions (tons/year) Removal Efficiency Expected

Maximum

Emission Rate (lbs/hour) Expected Average

Annual Emissions (tons/year)

PM Existing Baghouse 12.4 34.5 99% 12.4 34.5

Enhanced Baghouse 12.4 34.5 99% 12.4 34.5

Dry ESP 12.4 34.5 99% 12.4 34.5

Wet ESP 12.4 34.5 99% 12.4 34.5

SO 2 Lower Sulfur Coal 522 1457 15% 444 1238

Wet FGD 522 1457 95% 26 73

Spray Dry FGD 522 1457 80% 104 291

Dry Lime FGD 522 1457 55% 235 655

Dry Trona FGD 522 1457 65% 183 510

NO X Low NO X Burners 374 1042 50% 187 521

LNB/OFA 374 1042 65% 131 364

SCR 374 1042 90% 37 104

TASCO determined that either adding another module to the existing baghouse or installation of a Wet ESP or Dry ESP will not substantially impr ove removal efficiency or reliability over the existing baghouse, which (based on source/ performance tests) is currently operating at very high control efficiency. Furthermore the e xisting baghouse has a significant environmental benefit over either ESP technology be cause it provides comparable removal efficiencies and provides the added benefit of impr oved trace metal removal. Because of the negligible benefits of added or alternate PM contro l technology, there is no merit in further

consideration of PM controls. Therefore the remain der of the impact analysis will focus only

on SO 2 and NO X control technologies. The existing baghouse there fore is considered BART

for PM.26

7.0 Step 4: Impact Analysis

As per EPA guidelines an impact analysis was perfor med for each feasible BART technology. The purpose of impact analyses is to identify facto rs other than feasibility and control

effectiveness that could affect the choice of the b est retrofit technology. The following elements of the Appendix Y Guidelines were considered:

• Part 1: Costs of Compliance

• Part 2: Energy Impacts

• Part 3: Non-air Environmental Impacts

• Part 4: Remaining Useful Life

The Part 1 cost analysis provides a summary list of equipment and the associated control costs. Control system design parameters and design assumpt ions are documented using appropriate control technology resources including vendors, inf ormation documents, guidelines, cost manuals, and engineering/performance test data. Es timates of capital and annual operating costs

are based on annualized cost of controls.

The cost-effectiveness of each feasible control tec hnology is calculated from the cost of compliance and the amount of emissions reduced. Th e cost-effectiveness is described as the cost of control per amount of emissions removed. Two ty pes of cost-effectiveness analysis are recommended: average and incremental cost-effective ness. The average cost-effectiveness is

defined as the total annualized cost of control div ided by the average annual quantity of pollutant removed for each control technology. The increment al cost-effectiveness is a comparison of the cost and performance level of a control technology to the next most stringent option. The incremental cost-effectiveness is used when compari ng technologies that have similar removal

efficiencies.

Part 2, the energy impact analysis, involves quanti fication of each feasible technology with regard to energy penalties or benefits. Generally these impacts are factored into the overall cost analysis. Energy impact analysis should consider o nly direct energy consumption and not indirect energy impacts. The analysis may encompas s concerns over use of locally scarce fuels.

Part 3 of the analysis assesses environmental impac ts other than air quality impacts of feasible technologies, including irreversible or irretrievab le commitment of resources. Environmental impacts may be caused by generation of solid or haz ardous waste or discharge of polluted water as a result of the technology. There may also be i mpacts associated with consumption and storage of chemicals required by the control techno logy. To the extent possible environmental impacts should be quantified and costs included in the cost analysis.

Part 4, remaining useful life, is used to calculate the annualized cost impacts of retrofit controls. Remaining useful life affects the cost analysis onl y if remaining useful life of the BART source is different from the time period used to amortize the cost of a retrofit technology.27

7.1 TASCO Methodology for Impact Analysis

TASCO conducted impact analyses for all the identif ied technically feasible control technologies. TASCO initially established the desi gn parameters for each feasible control technology. The design parameters contain all pert inent information regarding the control technology system for specific application to the s ource. Examples of these design criteria include but are not limited to: emission rates, rem oval efficiencies, exhaust gas characteristics, fuel use, pressure drop across the control technology, scrubber water flow, reagent chemistry and consumption, and characterist ics of byproduct produced. The information used to define the design parameters in cluded the following:

• Information from discussions with equipment vendors ;

• EPA fact sheets and cost manuals;

• Engineering and performance test data; and

• Internet resources regarding control technology.

The design parameters for each control technology i dentified as technically feasible for application at the TASCO Nampa facility are summari zed in the tables in Appendix E Control Technology Cost and Impact Evaluations.

7.1.1 Cost of Compliance. The total capital investment and operating and main tenance costs were calculated for the Riley Boiler based on the following:

• EPA Air Pollution Control Cost Manual

• EPA Fact Sheets available on the Internet

• Budgetary cost information from equipment suppliers

.

• In-house engineering cost estimates based on commer cially available costing

software.

The capital and operating annual costs are used to determine the annualized cost for each feasible control technology by prorating the capita l cost over a twenty-year useful service life and adding the annual operating costs. The an nualized costs are used to calculate the average and incremental costs of each control techn ology.

For the cost effectiveness evaluation the expected emission reductions are estimated on an annual basis by applying the assumed efficiency of each feasible technology to the

baseline emissions and summarized in Table 5. The cost-effectiveness values are based on 2007 dollars and detailed cost analysis sheets f or each feasible control technology are included in cost evaluation tables in Appendix E.

Although the Appendix Y Guidelines present a detail ed process for determining cost effectiveness of control technologies, including a least cost graphing analysis to screen control options, they do not include criteria or th resholds for determining which technology is cost effective. The preamble to the 40 CFR Part 51 regional haze rules and28

guidelines specify BART presumptive limits for both SO 2 and NO X for large coal-fired electric generating units (EGU) (see 70 FR 39131, J uly 6, 2005). In conjunction with the presumptive limits EPA specifies affordability rang es in dollars per ton of pollutant removed. However, neither the presumptive limits n or affordability ranges apply to smaller industrial sector units like the Riley Boil er. For this reason cost effectiveness and affordability of control systems for the Riley Boil er must be determined on as case by

case basis.

7.1.2 Energy Impacts. Energy impacts are estimated for each control techn ology that has consumption of auxiliary energy during its oper ation. Per EPA guidance only direct energy impacts, such as the auxiliary power consump tion for the control technology and additional fans, if necessary. The auxiliary power consumption estimates are based upon the typical power consumption of similar equipment of an equivalent size. For any additional fans power consumption calculations are based on the flue gas volumetric flow rate and pressure drops across the control equipmen t. Indirect energy impacts, such as the energy to produce raw materials used for the co ntrol technology system, are not

considered.

Considering the technologies for NO X emissions, SCR has much higher energy impacts compared to combustion control systems such as LNB. The use of an SCR, (specifically the catalytic grid), creates additional back pressu re that does not occur in LNB systems. Additional energy consumption is required to overco me the increased pressure drop of an SCR. Similarly for the control technologies for SO 2 emissions, the energy impacts of the Wet FGD are significantly higher than those of the Spray Dryer FGD.

7.1.3 Non-Air Quality Environmental Impacts. Key non-air quality impacts evaluated for each control technology included waste generati on and management, quantity of freshwater utilized and whether visible plumes woul d increase. Specifically, for NO X control, SCR has much higher non-air quality enviro nmental impacts compared to LNB and other combustion control technologies. SCR cat alysts must be replaced approximately every 3 years, increasing the quantit y of hazardous waste. SCR also involves the storage and potential release of signi ficant quantities of anhydrous ammonia.

For SO 2 , the non-air quality environmental impacts are con siderably greater for the Wet FGD control technology. Because of the saturated c onditions in the reactor vessels the Wet FGD will generate a visible plume during most R iley Boiler operating conditions. The Wet FGD requires installation of a completely n ew wastewater handling system including an onsite waste water pond and piping tha t will need to be sited, permitted and constructed. Wet FGD consumes a significant amount of water and requires wastewater treatment, and solid waste disposal.

7.1.4 Remaining Useful Life. The remaining useful life is a factor in the BART evaluation only when the service life of the contro l equipment differs from the service

life of the source. TASCO determined that the rema ining useful life of the controls will be 20 years, and the remaining useful life of the R iley Boiler will be longer than 20 years. Therefore, remaining useful life does not affect th e BART cost analysis.29

7.2 Impact Analysis Findings

The results of the impact analysis for the feasible emission control technologies are

summarized in Table 6. This table contains cost in formation for individual NO X and SO 2 emission control technologies and combinations ther eof. For each control scenario Table 6 summarizes emissions, control effectiveness, capita l costs, annual operating costs, cost

effectiveness and incremental cost effectiveness. All of the control options are ranked in the table according to cost effectiveness. If affordability was not an issue in the BART selec tion process, this analysis would include more exhaustive evaluations to screen the options, including a cost effectiveness curve and incremental cost evaluations. However, for the Ril ey Boiler affordability is a critical component of the feasibility analysis. The key imp ediment to identifying BART is the cost of installing and operating any control technology on the Riley Boiler beyond the existing baghouse.

As stated previously, TASCO is not in a position to self-finance any improvements to the emission control system. Neither the company nor t he beet grower/shareholders have the available capital to fund such a project. Furtherm ore, because of existing debt, TASCO and its shareholders do not have access to capital in t he financial markets for projects that provide

no return on investment.

The problem of funding new BART technology at the N ampa facility is magnified by its geographic location. Not only must the Nampa facil ity compete with the national sugar market, it also competes internally with the other TASCO production facilities. Because of the population growth and accompanying loss of arab le land in the Treasure Valley, sugar beet farming in the valley has diminished. To acco mmodate this loss, beet production acreage has shifted to the east. In 2005 TASCO cea sed processing beets at its facility in Nyssa, Oregon, which is located on the western side of the valley. This resulted after several years of migrating production to TASCO facilities i n Twin Falls and Mini-Cassia.

Similar to the Nyssa facility, beet processing at N ampa has declined and production has increased at the Mini-Cassia facility in Paul, Idah o. These changes have been necessary to control beet hauling costs and to manage the overal l production costs of the company so TASCO can remain competitive in the national market . Each project that increases cost of doing business in Nampa and provides no accompanyin g cost savings will continue to shift production to the other plants thereby jeopardizing the continued viability of the Nampa factory and the grower-owners that supply sugarbeet s for processing at Nampa.

If the Nampa facility grower-owners were asked to f inance additional emission controls on the Riley Boiler, the economic impact on them is il lustrated as follows. Under ideal conditions the 627 grower-owners produce about 6 mi llion tons of sugarbeets. About 1.5 million tons will be supplied to the Nampa facility by approximately 156 owners growing beets on 290 acres. According to the University of Idaho report (see Appendix C), in crop year 2009 the expected yield is 33 tons per acre at a price of $45.00 per ton. The University of Idaho model predicts a net return for the Treasu re Valley growers at about $48,700.30

In September 2008 when DEQ transmitted modeling res ults to TASCO, the Department recommended combined control technology scenario to reduce both NO X and SO 2 emissions from the Riley Boiler: LNB with OFA and Spray Dry FGD. According to the impact analysis, the capital cost impact to install this c ombined control technology on the Riley

Boiler to control both NO X and SO 2 is $17.8 million or about $114,000 per each grower

owner that supplies beets to the Nampa facility. I n order to self-fund this project each grower would have to forfeit more than two years of earnings. Considering their high cost, similar analysis would show that none of the SO 2 or combined NO X /SO 2 technologies are

affordable.

BART regulations and implementation in the western region of the U.S. is primarily focused on the visibility issues associated with large elec tric utility power plants. In this noncompetitive market, electric utilities are allowed to pass the cost of additional emission controls onto consumers by raising rates. Unlike e lectric power generating facilities, TASCO and its grower-owners have no ability to increase r evenues to recover the costs. Because competitive market conditions dictate the price of sugar, raising the price of sugar is not feasible for a single competitor in the sugar indus try.31Table 6 – SUMMARY OF COST IMPACT ANALYSISControl ScenarioBaselineEmissions(tons/yr)RemovalEfficiency(percent)Annual EmissionsReduction(tons/yr)TotalReductionTotalCapitalCostTotalAnnualCostCostEffectivenessIncrementalCostEffectivenessNOXSO2NOXSO2NOXSO2(tons/yr) (x1,000) (x1,000) ($/ton) ($/ton)NOX- Low NOxBurners1,042050%0%5210521$2,720$480$921-NOX– LNBwOFA1,042065%0%6770677$4,875$860$1,270$2,431NOX- LNB + SO2- SprayDryer FGD1,0421,45750%80%5211,1661,687$15,690$3,001$1,779$2,121NOX- LNBwOFA + SO2-Spray Dryer FGD1,0421,45765%80%6771,1661,843$17,845$3,381$1,835$2,431NOX- LNB + SO2- DryTrona FGD1,0421,45750%65%5219471,468$14,001$2,902$1,977$1,278NOX- LNBwOFA + SO2-Dry Trona FGD1,0421,45765%65%6779471,624$16,156$3,282$2,021$2,431SO2- Spray Dry FGD01,4570%80%01,1661,166$12,970$2,521$2,163$1,659NOX- LNB + SO2- WetFGD1,0421,45750%95%5211,3841,905$24,786$4,515$2,370$2,696NOX- LNBwOFA + SO2-Wet FGD1,0421,45765%95%6771,3842,061$26,941$4,895$2,375$2,431SO2- Dry Trona FGD01,4570%65%0947947$11,281$2,422$2,557$2,219SO2- Wet FGD01,4570%95%01,3841,384$22,066$4,035$2,915$3,690SO2- Dry Lime FGD01,4570%55%0801801$11,281$2,687$3,353$2,313NOX– SCR1,042090%0%9380938$16,702$3,534$3,768$6,207Low Sulfur Coal01,4570%15%02192190$1,024$4,685$3,49032

8.0 Additional Emission Reduction and Visibility I mprovement Project

The Nampa facility recently completed installation and commenced operation of the world’s largest steam-heated beet pulp dryer. This state-o f-the-art dryer project is a significant environmental improvement for the Nampa facility an d the Treasure Valley airshed. This project was stimulated through IDEQ’s EPA-approved Northern Ada County PM-10 Maintenance Plan (40 CFR 52.670, October 27, 2003). TASCO worked co operatively with IDEQ by allocating over $20 million to the steam dryer and associated projects 3 . The new steam pulp dryer, which dries residual beet pulp for cattle feed, began ope rating in December 2006.

This project was a requirement of the Nampa facilit y Tier II Operating Permit and it was completed nearly one year ahead of schedule. Altho ugh the Tier II permit allows for partial operation of one direct-fired drum dryer, TASCO mad e the decision to completely shut down all three coal-fired drum dryers, demonstrating an ongo ing commitment to protecting air quality.

Capital for the steam dryer project was made availa ble because it provided offsetting savings. The dryer replaced three direct coal-fired rotary d rum dryers. Steam for heating the new dryer is supplied from existing boilers. Complementary ener gy efficiency projects completed at the facility enable the steam dryer to operate without increasing boiler capacity or fuel usage.

Elimination of the three coal-fired dryers has resu lted in significant reduction in coal burning and emission of associated air pollutants. Coal usage at the facility has been reduced by approximately 200 tons per day. The net reductions in emissions that are attributable to the steam dryer project are shown in Table 7. Dryer em ission calculations and assumptions are provided in Appendix F. The emission reductions at tributable to the steam pulp dryer project occur during the fall and winter months, which are the same time frame as when CALPUFF modeled visibility impacts of the Riley Boiler are the most significant.

Table 7 – Pollutant Reductions Attributable to Shut down of the Pulp Dryers

Pollutant Maximum Hourly

(lbs/hr) Average Annual

(tons/year)

PM 98.1 113

SO 2 17.8 20.6

NO X 191 221

3 This project was required by IDEQ based on PM 10 air dispersion modeling results. Ambient PM 10 measurements at the Nampa facility boundary have been consistent ly well below the PM 10 National Ambient Air Quality Standards (NAAQS).33

9.0 Step 5: Visibility Impact Analysis

The final element of the BART determination is Part 5, the visibility impact analysis. The visibility impact analysis is conducted for each fe asible BART control utilizing EPA’s predictive CALPUFF model to estimate visibility improvements.

Actual measured visibility impairments are likely t o be less than the findings of the model. In the preamble to the Regional Haze Regulation and Gu idelines for BART Determinations EPA acknowledged that features of our recommended modeling approach are l ikely to overstate the actual visibility impacts of an individual source and the simplified chemistry in the model tends to magnify the actual visibility effects of that so urce (see 70 FR 39121, July 6, 2005). This implies that differences of a fraction of a decivie w are too small to be significant.

The BART visibility evaluation presumes that one de ciview is a measurement of visual impairment that can be just discernable by an untra ined observer. Recent studies conducted by Dr. Ronald Henry (see Appendix B), on behalf of the Electric Power Research Institute, suggests that only 67 % of the general population of observe rs can discern any visual improvement at 2 to 4 deciviews. To achieve a 90% observation probabil ity of discerning a perceptible change the

level would need to be 3.5 to 7 deciviews. In both of these statistical probabilities, the

discernable deciview varies between 2 to 7 times th e predicted modeling results for the Riley Boiler. The implication that TASCO should consider spending over 15 million dollars (Spray Dry FGD) for a visual improvement that may not be s tatistically discernable is not responsible expenditure of funds that (as discussed in other ar eas of this report) are clearly not affordable for

the owners.

9.1 Overview of BART Modeling Procedures
The steps for determining potential visibility impa ct improvements include the following:

• Develop a modeling protocol and run the model at pr e-control and post-control emission rates using the 24-hour average actual emi ssion rate from the highest emitting day of the meteorological period.

• Make the net visibility improvement determination b ased on the modeled change in visibility impacts for the pre-control and post- control emission scenarios.

• Use a comparison threshold to evaluate visibility i mprovement.

• Compare the 98 th percent days for the pre- and post-control runs.

Receptors used in the model should be located in th e nearest Class I area with sufficient density to identify the highest predicted impacts. For the pre-control scenario the model must use the 24-hour average actual emission rate f rom the highest emitting day of the meteorological period modeled. Model results are c alculated for each receptor as the change in deciviews compared against natural visibility co nditions. Post control emission rates for the net visibility improvement determination are ca lculated as a percentage of pre-control

emission rates. The 98 th percent days are used to compare the pre- and post -control model

runs.34

IDEQ used the CALPUFF model to conduct the BART det ermination visibility impact modeling based on the BART Modeling Protocol which was developed jointly by the states of Idaho, Washington, and Oregon. Emission rates for the Riley Boiler and the coal-fired dryers used in the modeling were certified by TASCO on March 31, 2008. Various modeling parameters were refined and verified on July 10, 20 08. IDEQ provided modeling results to TASCO on September 16, 2008. IDEQ modeling results encompassed the three NO X control

scenarios and five SO 2 control scenarios identified in the feasibility as sessment. IDEQ also modeled six scenarios involving various combination s of NO X and SO 2 control technologies.

Subsequent to receiving the DEQ modeling results, T ASCO contracted with ENVIRON International corporation (formerly Geomatrix) to v erify DEQ results and run additional

scenarios.

IDEQ ran the CALPUFF model to assess visibility imp acts of potential emission control technology on affected Class I areas, including the Eagle Cap Wilderness in eastern Oregon, the Hells Canyon National Recreation Area on the Id aho-Oregon Border, and the Sawtooth

Wilderness in south central Idaho. Because of its location, the Eagle Cap Wilderness appears to be most sensitive to visibility impacts of the R iley Boiler.

9.2 Findings of Visibility Impact Analysis
The visibility impact model for the Riley Boiler wa s run for multiple scenarios. First emissions from the current operations were assessed to establish the baseline impacts. Then visibility impacts were evaluated for the baseline impacts including the operation of the coal fired pulp dryers.

The DEQ CALPUFF impact analysis report is included in Appendix G. Results of the visibility modeling analysis for the Eagle Cap Wild erness Area are summarized in Table 8. The first line Table 8 shows the modeled visibility impacts of the Riley Boiler at baseline emission levels. Note that the predicted impact of the Riley Boiler without NO X and SO 2 controls is only 1 deciview. As discussed previous ly in this section the, the degree to which the Riley Boiler obscures emissions in the Eagle Ca ps cannot be detected by the human eye.

Below this are the incremental visibility impact re ductions provided by the feasible NO X and

SO 2 control technologies and combinations thereof. Th e values for each technology represent the reduction in deciviews and days for e ach feasible control scenario. The bottom two lines represent the impacts and the incremental benefits that resulted from removal of the coal-fired dryers.

It is also important to recognize the time of year the highest model-predicted impacts are claimed by IDEQ to occur at the Class I areas. Bas ed on the CALPUFF model, the highest predicted impacts occur primarily during the winter time, but the specific number of days the impacts occur varies from year to year. Wintertime is typically when the Class I areas of concern to this analysis are significantly less acc essible and receive considerably less visitation. Visibility impacts of the Riley Boiler are less in the summertime when usage is highest.35Table 8 – Visibility Impact Summary - Eagle Cap Wilderness AreaReduction in deciviews & days above 0.5 dvAnnual Cost perControl 2003 2004 2005 2003-2005 Cost Deciview*Scenario 8th % Days % 8th% Days % 8th % Days % 22nd % Days % ($x1,000) $x1,000/dvBase - Riley Boiler only0.721151.086411.109411.08697NOX- Low NOx Burners (LNB) 0.210 29% 4 27% 0.264 24%12 29% 0.238 21% 12 29% 0.270 25% 28 29%$480 $1,780NOX- LNB with overfire air (LNBwOFA) 0.267 37% 8 53%0.344 32% 17 41% 0.306 28% 16 39% 0.350 32% 41 42%$860 $2,460NOX- Selective Catalytic Reduction (SCR) 0.338 47% 960% 0.461 42% 25 61% 0.456 41% 23 56% 0.473 44% 5759%$3,534 $7,470SO2- Low Sulfur Coal 0.039 5% 0 0% 0.070 6% 2 5% 0.081 7% 5 12% 0.072 7% 7 7%$1,024 $14,220SO2- Dry Lime FGD 0.135 19% 6 40% 0.272 25% 13 32% 0.303 27% 12 29% 0.280 26% 31 32%$2,687 $9,600SO2- Dry Trona FGD 0.156 22% 6 40% 0.322 30% 17 41% 0.370 33% 16 39% 0.325 30% 39 40%$2,422 $7,450SO2- Spray Dryer FGD 0.194 27% 6 40% 0.383 35% 19 46%0.402 36% 21 51% 0.400 37% 46 47%$2,521 $6,300SO2- Wet FGD 0.222 31% 8 53% 0.439 40% 22 54% 0.464 42% 24 59% 0.448 41% 54 56%$4,053 $9,050NOXLNB + SO2Dry Trona FGD 0.392 54% 10 67% 0.603 56% 35 85% 0.629 57% 35 85% 0.606 56% 80 82%$2,902 $4,890NOXLNB + SO2Spray Dryer 0.427 59% 12 80% 0.684 63% 39 95% 0.692 62% 38 93% 0.684 63% 89 92%$3,001 $4,410NOXLNB + SO2Wet FGD 0.451 63% 13 87% 0.727 67% 40 98% 0.757 68% 53 129% 0.738 68% 92 95%$4,515 $6,600NOXLNBwOFA + SO2Dry Trona 0.463 64% 13 87% 0.691 64% 39 95% 0.715 64% 38 93% 0.692 64% 90 93%$3,282 $4,740NOXLNBwOFA + SO2Spray Dryer 0.493 68% 14 93% 0.767 71% 40 98% 0.779 70% 40 98% 0.767 71% 94 97%$3,381 $4,410NOXLNBwOFA + SO2Wet FGD 0.520 72% 14 93% 0.815 75% 41 100% 0.846 76% 41 100% 0.825 76% 96 99%$4,895 $5,930Base - Riley Boiler & Pulp Dryers0.956231.454491.388551.399127Coal-Fired Pulp Dryers Shutdown 0.235 25% 8 35% 0.368 25% 8 16% 0.279 20% 14 26% 0.313 22% 30 24%* Cost per deciview is the annual cost divided by the corresponding increment of deciview improvementfor the 2003-05 period.36

Considering that the visibility impact of the Riley Boiler without NO X or SO 2 controls is not discernible to the human eye and that the major imp acts occur during the low-use season, commitment of any resources to improvements that ar e not affordable is not responsible management. For the Eagle Cap area the Low NO X Burner provides a visibility impact reduction of 0.270 deciviews and 28 days over the b aseline conditions of 2003-2005. Similarly the elimination of the coal-fired dryers provides a visibility reduction of 0.313 deciviews and 30 days over the baseline conditions of 2003-2005. This analysis leads to the conclusion that the visibility improvement provided by steam dryer project is equivalent to installing a Low NO X Burner on the Riley Boiler.

The two right hand columns in Table 8 summarize the annualized cost of each of the control scenarios and the calculated cost per incremental d eciview improvement. Note the cost per deciview improvement is $2,500,000 or more for all of the control scenarios except for the

Low NO X Burner control option. The more sophisticated te chnologies provide marginal improvements in visibility at significantly higher cost. All of the SO 2 controls exceed $6,300,000 per deciview and the most costly is $14, 220,000 per deciview. While the cost per

deciview of the combined NO X /SO 2 control technologies is somewhat lower, the most c ost effective combined scenario only provides a 0.767 d eciview improvement in visibility.

10.0 Conclusion and Recommendation

TASCO’s Nampa facility provides cost effective conv ersion of sugarbeets to sugar and feed products for sugarbeet growers whose livelihood and continued participation in the cooperative depends on a reasonable rate of return on their inv estment. Unlike a typical electric utility, for which the regional haze rule was targeted, the incr eased cost of installing emission control systems cannot be passed on to TASCO’s customers. Instead, these costs must be absorbed by TASCO’s owners, the beet growers. The analysis must consider the economic impact of installing emission controls on the grower-owners.

Although this impact analysis confirms the technica l feasibility of installing haze-reducing technology on the Riley Boiler, all of the solution s are either not affordable or provide visibility improvements that will be imperceptible. Specifica lly, the cost for the combined technology to

control NO X /SO 2 exceeds the ability of TASCO and its grower-owners to fund the project. Funding the capital cost of a combined NO X /SO 2 control system without considering annual costs would require the Nampa facility grower-owner s to sacrifice over two years of net earnings.

At a time when both sugar prices and sugar beet pro duction acreage are at historic lows, there is no merit in expending significant additional capita l and operating costs that result in marginal and imperceptible improvements in visibility at Cla ss I areas located over 70 miles from the Nampa facility. Significant additional costs witho ut offsetting savings or revenues could drive local growers and the Nampa facility out of the sug arbeet business, which is contrary to the objectives outlined for BART determinations in the CAA and related rules.37

Considering that EPA never intended that Appendix Y Guidelines be applied to industrial sources and that CALPUFF modeling overestimates the visibility impacts of singular sources, this analysis demonstrates that the Steam Dryer Pro ject in combination with maintaining the existing baghouse on the Riley Boiler provides sign ificant emission reductions and visibility improvements without harming the economic viability of the company. Visibility improvements achieved by elimination of the coal-fired dryer are comparable to installing a LNB control system on the Riley Boiler and should be recognized by the agencies as a haze-reducing solution that offsets any additional control technologies.

BART for the Riley Boiler is therefore determined t o be maintaining the existing baghouse for control of PM emissions in conjunction with the vis ibility improvements that have already been accomplished with the Steam Dryer Project.