Best Available Retrofit Technology 

(BART) 

Determination Analysis 

Riley Boiler 

The Amalgamated Sugar Company LLC 

Nampa Facility 

February 6, 2009 
 2

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 Subject Equipment........................................ 8 

2.1 Company Description ...................................................................................................... 8 

2.2 Beet Sugar Production Economics................................................................................... 9 

2.3 Description of Nampa Factory, Operations and Site 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 Control 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 SO2 ...................................................................... 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 NOX..................................................................... 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 Retrofit Technologies .................................... 23 

5.1 Feasibility of PM Controls........................................................................................ 23 

5.2 Feasibility of SO2 Controls ....................................................................................... 23 

5.3 Feasibility of NOX 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........................................ 24 
 3

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 Improvement 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 Consumer Price Index....................................... 10 

Figure 2 – Plan View of Nampa Factory ...................................................................................... 14 

INDEX OF TABLES 

Table 1 – Nampa Factory Fuel Costs from 1999 to 2008..............................................................11 

Table 2 – Product and Beet Hauling Costs ....................................................................................11 

Table 3 – Maximum Hourly and Average Annual Emission Rates for the Riley Boiler ..............15 

Table 4 – Technically Feasible and Infeasible Controls................................................................24 

Table 5 – Riley Boiler Control Technology Effectiveness Summary ...........................................25 

Table 6 – Summary of Cost Impact Analysis ................................................................................31 

Table 7 – Pollutant Reductions Attributable to Shutdown of the Pulp Dryers..............................32 

Table 8 – Visibility Impact Summary – Eagle Cap Wilderness Area ...........................................35 

INDEX OF APPENDICES 

Appendix A – Preliminary Draft Exemption Modeling Evaluations 

Appendix B – Estimating the Probability of the Public Perceiving a Decrease in Atmospheric 

Haze 

Appendix C – The Economics of Growing Sugar Beets in Southern Idaho: A Short Run Gross 

Margin Analysis 

Appendix D – Summary of Baseline Emissions Calculations and Assumptions 

Appendix E – Control Technology Cost and Impact Evaluations 

Appendix F – Dryer Emissions Calculations and Assumptions 

Appendix G – DEQ CALPUFF Impact Analysis Report 
 4

Executive Summary 

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

has been identified as a Best Available Retrofit Technology (BART) eligible source by the Idaho 

Department of Environmental Quality (IDEQ). CALPUFF 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 conducted pursuant to EPA guidelines that were 

developed for large electricity generating facilities. 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 steam and generates electricity for processing of 

sugarbeets into sugar and feed products at the Nampa facility. This boiler is located in an area 

on the factory site that is constrained by buildings and equipment. Predicted visibility impacts 

encompass emissions of particulate matter (PM), sulfur dioxide (SO2) and oxides of nitrogen 

(NOX). BART determination guidelines prescribe a step by step process to identify and screen 

retrofit technology options using several factors, including affordability, in identifying and 

assessing potential emission control technologies for the Riley Boiler. In addition the analysis 

considers the visibility benefits of a recently completed 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, SO2 and NOX from the Riley Boiler 

were identified. The alternatives were screened for 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 analysis found no other technologies that will control 

PM more effectively than the existing baghouse. Therefore, the BART determination analysis 

for the Riley Boiler focuses on technologies for control of SO2 and NOX emissions. 

Visibility modeling was conducted to evaluate potential improvements attributed to each viable 

retrofit technology. The modeling indicated the Eagle Cap Wilderness Area is most sensitive to 

Riley Boiler. The CALPUFF modeling found that NOX controls can theoretically reduce 

visibility impacts of the Riley Boiler in the Eagle Caps up to 0.47 deciviews. SO2 controls can 

reduce impacts up to 0.45 deciviews, while combined NOX and SO2 control scenarios could 

benefit visibility in the Eagle Caps up to 0.82 deciviews. However, it is important to note that 

recent studies have verified that these marginal improvements 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 influences 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 recommended the control technology of low NOX

burners and over fire air to reduce NOX combined with spray dryer flue gas desulfurization to 

reduce SO2 emissions from the Riley Boiler. The capital 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 forfeit more than two years of earnings to 
 5

reduce haze by an increment that is imperceptible. Therefore, after following BART guidelines 

including a cost-benefit analysis, TASCO has determined that additional emission controls for 

the Riley Boiler beyond the existing baghouse are not justified. 

TASCO proposes to include the reductions in emissions 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 in 2006 and made fully operational in the 4th

quarter of 2007. The shutdown of the pulp dryers significantly reduced emissions by decreasing 

coal usage. Coal usage has been reduced by approximately 200 tons per day which is equivalent 

to shutting down a 150,000 pound per hour boiler. Estimated annual emissions of PM, SO2 and 

NOX will be reduced by 350 tons per year. This project was affordable because the capital cost 

was offset by significant reduction in operating costs. The visibility improvement afforded by 

the steam dryer project is 0.31 deciviews, the same order of magnitude as the separate NOX and 

SO2 technologies and nearly half of the benefit of the most costly combined NOX and SO2

scenario. This project was feasible because it added 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 established a national goal to reduce manmade visibility impairment in all Class I scenic areas in the United States to natural 

background levels. To address visibility provisions of the statute, the U.S Environmental 

Protection Agency (EPA) promulgated regulations under 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 sources. The regulations require states to 

submit regional haze plans with “reasonable progress 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) to reduce emissions. EPA and Idaho 

Department of Environmental Quality (IDEQ) BART provisions are summarized as follows: 

• Eligible Sources – The BART provisions apply to “major stationary sources” from 26 

specified source categories, which have potential to emit 250 or more tons per year of 

any air pollutant. BART applies to sources constructed 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 conducted by 

state regulatory agencies to determine whether predicted impacts from the BART 

eligible sources may cause or contribute to impairment of visibility in a Class I area. 

A source is subject to a BART determination if it is reasonably anticipated to cause or 

contribute to impairment in a Class I area. According to Appendix Y Guidelines a 

source is considered to “cause” visibility impairment if the modeled 98th percentile 

change is 1.0 deciview or more. A source is considered to “contribute” to visibility 

impairment if the modeled change is equal to or greater 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 technologies are identified and 

subjected to impact analysis, including affordability 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 determination 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-fired boiler at the Nampa facility, which was 

identified by IDEQ modeling as a requiring a BART determination. 

It is important to acknowledge the genesis and scope of the Appendix Y Guidelines. They 

are specifically focused on large power plants. Section 169A(b) of the CAA states In the 
 7

case of a fossil-fuel fired generating powerplant having a capacity in excess of 750 

megawatts, the emission limitations required under this paragraph shall be determined 

pursuant to guidelines, promulgated by the Administrator under paragraph (1). The law 

does not specify whether or how the guidelines apply to other than 750 megawatt plants. In 

the preamble to the Regional Haze Regulations and Guidelines for BART determinations, 

EPA stated it would not be appropriate for EPA to require states 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 pollutants annually. 

Based on EPA guidance pollutants that have potential for impacting visibility in Class I areas 

include particulate matter (PM), sulfur dioxide (SO2), and oxides of nitrogen (NOX). On July 

19, 2007, IDEQ finalized the “Subject-to-BART” analysis for the Riley Boiler at the Nampa 

facility. As discussed in IDEQ’s report, visibility 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 wintertime visibility impacts from the Riley Boiler 

exceeded contribution threshold levels at three Class 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/Oregon border. 

The modeling analysis completed by IDEQ in July 2007 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 have never been validated against 

actual visibility measurements or observations in the Class I areas. In fact recent scientific 

studies of the ability of humans to perceive changes 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 by 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 Modeling 

System Pursuant to the Best Available Retrofit Technology (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 impacts 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 reasonably be anticipated from 

the use of BART. 

One factor in the cost impact analysis of the Appendix Y Guidelines is consideration of 

affordability of BART controls. Specifically, will installation of controls affect the viability 

of continued plant operations? For TASCO, affordability is the most important factor since 

the economic viability of continued operations within current sugar market constraints is an 

ongoing issue. 

In addition to evaluating potential BART for the Riley Boiler this analysis includes 

information and visibility evaluation of the recently completed project that eliminated three 

coal-fired dryers and replaced them with a steam-heated dryer. This project in combination 

with other energy-saving projects resulted in significant reduction in coal burning and 

associated emissions from the old dryers. 

2.0 Overview of Company, Facility, and BART Subject Equipment 

2.1 Company Description 

Privately owned until 1997, TASCO was purchased by the Snake River Sugar Company 

(SRSC), an Oregon agricultural cooperative, consisting of approximately 1,200 grower 

members. Since 1997 due to beet production economics the number of grower-owners has 

decreased to about 625. About ninety percent of SRSC members are residents of Idaho. The 

company operates three sugarbeet processing facilities which are located in Paul (est. 1918), 

Twin Falls (est. 1916), and Nampa (est. 1942), Idaho.2

 Each facility is a blend of new stateof-the-art and time proven technology and employs about 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 following section. 

Sugarbeet acreage varies from year to year due to growing and market conditions. SRSC 

members have farmed up to 220,000 acres of sugarbeets. During the current crop year 

 

2

 A fourth facility in Nyssa, Oregon was shutdown in 2005. 
 9

acreage has diminished to approximately 170,000 acres, 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) establish affordability as a key 

consideration when conducting a BART determination analysis. Regulatory agencies must 

consider whether the cost of BART controls will affect the profitability and viability of 

continued plant operations. 

Economically, sugarbeet processing facilities are high volume, low margin operations. 

Historically, TASCO has remained profitable by increasing the volume of sugarbeets 

processed and improving efficiencies in order to absorb increasing operating costs. The 

ability to remain profitable by increasing volume is no longer possible due to marketing 

allocations implemented by the U.S. Department of Agricultural (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 increased operating costs, and reduced acreage 

has severely impacted the profitability of the grower owned company. As a result, 

affordability is the critical component for this BART determination analysis. The 

profitability challenge is demonstrated in Figure 1 which compares beet sugar prices to the 

consumer price index from1980 through 2007. Through the past quarter century the sugar 

prices have remained relatively static, averaging 26.55 cents per pound. During the same 

time frame the CPI has increased 152%. Because sugar prices are controlled by the market 

and government factors, TASCO can process sugar beets and provide a return to its growerowners only by improving process efficiency and reducing costs. 
 10

Figure 1 – Comparison of Beet Sugar Prices to Consumer Price Index 

Wholesale Beet Sugar Price Compared to 

Consumer Price Index

0.00

50.00

100.00

150.00

200.00

250.00

1980

1985

1990

1995

2000

2005

Year

Sugar Price (cents per pound) Consumer Price Index

Sugar prices have remained low due in part to increased sugar imports from countries that 

subsidize these industries. These imports have increased through “free trade” agreements 

such as CAFTA (Central American Free Trade Agreement). Unlike TASCO, foreign sugar 

companies are not subject to the same labor, environmental and occupational safety standards 

required of U.S. sugarbeet companies. Increased imports 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 increased dramatically over the last ten years as 

shown in Table 1. The cost of natural gas has increased by nearly 240%, coal has increased 

over 30%, coke has increased by nearly 100%, and diesel 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 over $200 per ton, representing over a 

100% increase in the cost of coke. In 2008 TASCO had to switch from coke to anthracite 

coal to burn in the limekilns to mitigate the impact of coke pricing. Because energy costs for 

operating the facilities are significant, TASCO strives to optimize energy usage and 

maximize efficiency. 
 11

Table 1 – Nampa Factory Fuel Costs from 1999 to 2008 

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% 

 aP&M Coal 

bUtah Coal from 1999-2007; P&M Compliance Coal in 2008 

Transportation costs have increased significantly in 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 operating 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 significant 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 turning to alternative crops such as wheat and 

corn which provide better revenues for their farming operations. Loss of grower members 

diminishes the ability of the cooperative to sustain 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 three distinct production zones in southern 

Idaho: the Treasure Valley, the Magic Valley, and the lower Snake Plain. The report 

presents a methodology to help growers to choose which cash crop to grow based on 

expected market conditions and costs of doing business. In 2009 sugar beets are expected to 

provide a competitive gross margin over $300 per acre 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 Site Constraints 

The Nampa Factory is located in the city of Nampa along the north side of West Karcher 

Road generally to the north and west of the intersection of Northside Boulevard. The facility 

produces refined sugar for various markets from sugarbeets. Beet processing byproducts 

produced at the facility include dried beet pulp, concentrated separator byproduct (CSB), 

liquid sugar and betaine. Sugarbeets are typically processed from early October through 

January. The length of the beet processing campaign is dependent on the size of the beet 

crop, which varies considerably each year due to climatic factors and availability of irrigation 

water during the growing season. Following the beet 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 gas to provide steam to concentrate sugar 

juices, dry pressed pulp and co-generate electricity. Emissions from the coal-fired boilers are 

controlled with baghouses. The limekilns are capable 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 primarily 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 centrally 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 vicinity of the Boiler House. This congestion is 
 13

an impediment and will increase the cost of potential add-on emission control technologies 

that require real estate. 
 14

Figure 2 – Plan View of Nampa Factory 
 15

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 hour. The Riley Boiler is fired by 

pulverized coal and/or natural gas. The Riley Boiler has potential to emit (PTE) 250 tons 

per year (tpy) or more of SO2 or NOX. 

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 upcoming year. Typically industrial boilers 

such as the Riley Boiler can be maintained indefinitely. 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 that 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 based 

on the size of the beet crop. Short-term emissions (hourly or daily) vary significantly 

depending on the time of year. During the beet campaign, 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 the 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 accordance with the Appendix Y Guidelines. 

According to Appendix Y baseline emissions rate should represent a realistic 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 and are summarized in Table 3. A 

summary of baseline emission calculations and assumptions is presented in Appendix D. 

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

Pollutant Maximum Hourly 

(lbs/hour) 

Average Annual 

(tons/year) 

PM 12.4 34.5 

SO2 522 1457 

NOX 374 1042 
 16

In Table 3 the Maximum Hourly Emissions data represent 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 average of the three baseline years. 

Note that the PM emission rates in Table 3 are controlled because they are based on 

measured emissions of the exhaust from the existing Riley Boiler baghouse. 

Uncontrolled emission rates for PM have not been measured. Emission rates of SO2 and 

NOX in Table 3 are not controlled. 

3.0 BART Determination Analysis Methodology 

The methodology for this analysis follows the Appendix Y Guidelines. Pursuant to the 

guidelines, TASCO evaluated a variety of technologies that have potential to reduce PM, SO2, 

and NOX emissions from the Riley Boiler. It is important to note that these guidelines were 

created for large electric generating units, so they 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 technologies 

 Step 2: Eliminate technically infeasible options 

 Step 3: Evaluate control effectiveness of remaining technologies 

 Step 4: Evaluate impacts and document the results

 Step 5: Evaluate visibility impacts 

Data generated from the above-listed steps are recommended 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 beneficial improvements in visibility impacts within 

Class I areas. Most commonly discussed BART alternatives for industrial boilers are based on 

emission control technologies that were primarily developed for much larger coal-fired boilers at 

electric utility power plants. For industrial boilers like the Riley, electric utility boiler control

technologies are cost prohibitive.

The cost analysis for selected control technology alternatives 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 Control Technologies 

The first step of the BART guidelines is to identify 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 otherwise available within the common sense 

meaning of the term. A control technique is generally available if it has reached the stage of 

licensing and commercial availability. Technologies that have not been applied to full scale 

operations are not considered available. The technology can be a method, system, or technique 
 17

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 that have been applied to similar source 

categories and gas streams. 

An available control technology is considered “applicable” if it can reasonably be installed and 

operated on the same or similar source type under consideration. 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 available and applicable is generally considered 

technically feasible. Technical feasibility of control technology is determined in the Step 2 

evaluation which is presented in Section 5. 

TASCO evaluated the potential control technologies available for PM, SO2 and NOX emissions 

consistent with Appendix Y Guidelines. Technologies were identified based on the EPA 

clearinghouse and fact sheets, vendor reviews and industry experience. The available and 

emerging control technologies comprise a significant list of choices for review. TASCO relied 

on recently implemented and proven technologies identified in the EPA’s online RACT, BACT, 

and LAER Clearinghouse. These technologies are listed 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 lbs/MMBTU. Control efficiencies for 

baghouses are reported to be 99.0 to 99.9%. For the 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 baghouse. This option would expand the 

number of modules from four to five resulting in reduced baghouse velocities and 

pressure drop. Adding another baghouse module to the Riley Boiler baghouse will be 

difficult and expensive because of physical space limitations near the existing baghouse. 

PM control efficiency for the addition of the module 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 particulate using an electrical field. The 

plates are continuously or intermittently cleaned using a circulating water system. 

Control efficiencies for Wet ESP systems are reported to be 99.0 to 99.9%. For the 

purposes of this evaluation, TASCO assumed a control efficiency of 99%. 

TASCO evaluated the addition of a Wet ESP for the Riley Boiler. Because of physical 

space limitations, the installation of the Wet ESP equipment will require demolition and 

removal of the existing baghouse and installation of the Wet ESP in its place. In addition 
 18

because the system will produce saturated vapor conditions in the stack during some 

operating scenarios, a liner will need to be installed 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 collection 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 using 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 cycles at different times. Because this 

control technology does not result in saturated flue gas conditions, a stack liner is not 

needed. The Dry ESP will require demolition and removal of the existing baghouse to 

provide space for installation of equipment. 

4.2 Retrofit Technologies for Control of SO2 

4.2.1 Switch to Lower Sulfur Coal (LSC). This option consists of purchasing more 

costly coal that has lower sulfur content. The current low sulfur coal used at Nampa has 

a contract limit of less than 1% by weight to comply 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 could 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 per ton. The actual cost may be higher 

than current projections, because low sulfur coal is 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 availability of fuel than the Nampa 

facility. 

Because separating coal storage and handling systems to accommodate two different 

sulfur content coal supplies will be technically unacceptable, converting to lower sulfur 

coal will also result in SO2 emission reductions from the factory’s B&W boilers. 

However, for the purpose of the cost analysis for this 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 downstream of a particulate control device. 

The absorbers are usually configured as a flooded tray system or a spray tower. Flue gas 

entering the absorber reacts with slurried limestone or slaked lime to remove SO2 at the 

liquid/gas surface boundary. The reaction forms insoluble products or solids that are 

further treated with forced oxidation to convert to gypsum which is a marketable 

byproduct. Unlike other options considered for SO2 removal, Wet FGD will not affect 

flyash sales. The treated flue gas passes through a mist eliminator system to remove 
 19

water droplets from the flue gas stream. The flue gas leaving the absorber is saturated 

with water vapor and can present a visible steam plume from the stack. 

Wet FGD systems offer one of the highest SO2 removal efficiencies of the available 

control technologies with removal rates of 95% or greater. However, vendors report that 

WFGD technology has not been shown to be cost effective for industrial boilers the size 

of the Riley Boiler. 

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

considerations are as follows: 

Lining the Existing Stack – Wet FGD results in saturated stack conditions during 

periods of Riley only operation (shared stack operation during beet campaign with the 

B&W boilers is not anticipated to result in saturated 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 the 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 generate a 

wastewater stream. The actual wet process is expected to be contained within the 

Wet FGD system with a slip stream discharged for wastewater treatment. The 

impacts of this slip stream cannot be quantified without more design information 

which is beyond the scope of this level of technology evaluation. However the costs 

of added equipment and operation to handle the residuals 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 between the exhaust outlet of the boiler and 

upstream of a particulate removal device (usually an electrostatic precipitator or 

baghouse). The reactor consists of a spray dryer absorber tower and support equipment. 

Flue gas is introduced into a vessel and contacts an atomized spray pattern of lime slurry 

generated by either a set of dual fluid nozzles or a rotary atomizer. The reaction to 

remove SO2 occurs on lime slurry droplets as they are evaporated 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 gas (controlled by slurry feed rate), the 

product removed from the system is in dry form. The emission control efficiency of the 

reactor increases as the exit flue gas temperature approaches the adiabatic saturation 

temperature of the flue gas. The approach temperature is typically set at 30 to 40 oF 

above adiabatic saturation temperature (corresponding 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 chemical characteristics of the ash. It is 

important to note that spray dryer solids are not suitable as a concrete additive. This 

control option will eliminate the opportunity for sale of flyash. Control efficiencies for 
 20

Spray Dry FGD systems are reported to vary between 80 and 90%. For the purposes of 

this evaluation, TASCO assumed a higher approach temperature (40 oF to protect the 

baghouse) and a control efficiency of 80%. 

A Spray Dry FGD retrofit project will require significant modifications to the facility. 

Key site-specific considerations are as follows: 

Baghouse Interferences – The particulate loading to the baghouse will increase 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) contributes to significant overall 

particulate loading. Approximately 60% of the formed 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 baghouse is used for particulate removal, 

such as the case with the Riley Boiler baghouse. This can be avoided to some degree 

by operating at a higher approach temperature (at expense 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 less 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 supply the baghouse. The cost analysis 

for this option was determined using a new vendor supplied 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 the surface area for 

reaction. Lime is milled to less than 10 microns using 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 temperature of the flue gas. 

Flue Gas Mixing – Good lime particle mixing with the flue gas is important to 

provide uniform distribution of lime reactant in the baghouse. 

The Dry Lime FGD project will be costly if a new baghouse is required for the Riley 

Boiler. Although not considered in the economic analysis, the use of the existing 

baghouse (with significant modifications) may be possible. Modifications include 

expensive ductwork reconfiguration with the addition of at least one and possibly two 

baghouse modules. 
 21

The control efficiency for DLIFGD is reported to vary between 45 to 55%. For the 

purposes of this evaluation, TASCO assumed a control 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 injecting pulverized trona (milled to less 

than 10 microns) into the flue gas downstream of the existing baghouse and upstream of a 

newly installed baghouse. The injection system requirements and technical characteristic 

are very similar to the Dry Lime FGD system discussed above. 

The control efficiency for Dry Trona FGD is reported to range between 55 to 65%. For 

the purposes of this evaluation, TASCO assumed a control efficiency of 65%. 

4.3 Retrofit Technologies for Control of NOX 

4.3.1 Low NOX Burners (LNB). Low NOX burners are designed to reduce the flame 

temperature within combustion zones to lower NOX emissions. Generally fuel is staged 

in three combustion zones as follows: 1)Zone 1 – primary combustion occurs under fuel 

rich and oxygen deficient conditions; 2)Zone 2 – smaller amounts of fuel are added and 

NOX is chemically reacted in a slightly oxidized atmosphere; and 3)Zone 3 – final 

combustion is completed by limiting excess air to minimize flame temperatures. 

There are many LNB designs based on vendor proprietary information. LNB retrofit 

projects are technically challenging and require significant engineering evaluations to 

properly size and adapt a particular low NOX burner system to a given boiler and burner 

configuration. The estimated NOX removal efficiency reported for this technology is

30% to 50%. For the purposes of this evaluation, TASCO 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 of the fuel burner system to lower 

flame temperature and the formation of NOX. Over-fired air as a stand alone retrofit 

technology can be difficult to control causing combustion issues with a pulverized coal 

boiler, including water wall corrosion and reduced boiler efficiencies. When combined 

with a low NOX burner and reasonable combustion air control (approximately 10 to 20 % 

as OFA), NOX removal efficiencies can approach 65%. 

4.3.3 Ultra Low NOX Burners (ULNB). Ultra low NOX burners are upgraded LNB 

designs which involve further control and staging of combustion air and fuel. One 

refinement of the LNB is staged combustion air instead of staged fuel sometimes referred 

to as the Ultra Low NOX Burner. This technology can achieve high NOX emissions 

control in new boilers, especially fluid bed and natural gas application. However, for 

retrofit situations, especially pulverized coal fired boilers, ULNB is not a reasonable 

feasible for the Riley Boiler because the small firebox volume will adversely affect the 

flame management system. 
 22

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

reduce NOX by injecting ammonia or urea into the flue gas before it passes through a 

catalytic grid to reduce the NOX to N2. This technology requires the flue gas exhaust 

from the Riley baghouse to be heated to 500oC before injecting ammonia or urea and 

passing the hot gasses through the selective catalytic 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 NOX emissions by 70% to 90%. For the purposes of 

this evaluation, TASCO assumed a control efficiency of 90%. 

SCR retrofit projects generally result in significant modifications to an existing site. Key 

site-specific considerations are as follows: 

Exhaust Gas Temperature – SCR requires the exhaust gas temperature from the 

Riley Boiler to be heated to 500oC (932oF). 

Ammonia Slip – Ammonia slip may cause significant downstream issues including 

emissions of ammonia, ash contamination and ductwork 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 periodic replacement of the catalytic 

grid estimated to occur every three years. 

Ammonia Storage – Storing large volumes of ammonia is a significant potential 

hazard to facility operating personnel and the environment 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 consumption 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 NOX to N2 as the flue gas moves through the 

ductwork. Boiler load swings can lead to temperature changes at the injection that can 

significantly reduce removal efficiencies. In addition, temperature swings at the injection 

points can lead to “ammonia slip” or the condition where un-reacted ammonia passes 

through downstream equipment, including the baghouse and discharges from the stack. 
 23

5.0 Step 2: Technical Feasibility of Emission Retrofit Technologies 

Step 2 of the BART analysis involves screening of all available retrofit control technologies 

identified in Step 1 for technical feasibility. 

In addition to availability, a technology must be technically applicable to the source under 

consideration. That is, the technology must have been commonly used on similar source to be 

considered applicable. Potentially applicable retrofit control alternatives may also include 

pollution prevention, add-on controls, and combinations 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 explanation 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 Boiler at the TASCO Nampa facility. In describing 

the technology in Section 4, limitations and constraints that may affect applicability were 

highlighted. In this section technically infeasible retrofit technologies are identified along with 

rationale as to why they have been disqualified from additional analysis. 

5.1 Feasibility of PM Controls 

Based on vendor discussions, other BART reports, emission control literature and 

engineering judgment, all control options identified in Step 1 for PM are technically feasible. 

5.2 Feasibility of SO2 Controls 

Based on vendor discussions, other BART reports, emission control literature and 

engineering judgment, all control options identified in Step 1 for SO2 are technically feasible. 

5.3 Feasibility of NOX Controls 

5.3.1 ULNB. TASCO has determined that the ULNB control technology is not 

technically feasible for the Riley Boiler. The boiler’s existing firebox is not large enough 

to accept the full burner/flame management system necessary for ULNB. 

5.3.2 SNCR. TASCO has determined that SNCR technology is not technically feasible 

for the Riley Boiler. SNCR control effectiveness is predicated on reasonable flue gas 

residence time in the narrow temperature range required 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 the necessary residence time to reliably 

remove NOX. This is further exacerbated by boiler load swings 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 deteriorate 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

SO2 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

NOX Low NOX Burners Yes None

LNB/OFA Yes None

Ultra Low NOX 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 alternatives are identified in Step 2, the 

effectiveness of each control technology is evaluated 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 was obtained from regulatory evaluations, 

manufacturer’s performance data, engineering estimates, and demonstrated effectiveness of the 

technology at operating sources. If a range of control effectiveness for a technology was 

reported, generally the most stringent level was used in this ranking. 

6.1 Effectiveness of Technically Feasible Control Technologies 

For each of the feasible control technologies identified in Section 5, TASCO determined the 

baseline maximum hourly emission rate, baseline average annual emission rate, anticipated 

efficiency of emissions control, expected maximum hourly emission rate and expected 
 25

annual emission rate. This data is summarized in Table 5. Note that for PM the baseline 

emissions and the expected emissions are the same because the existing baghouse was used 

to establish baseline emissions and all technologies were assumed to have the same 

efficiency. 

Table 5 – Riley Boiler Control Technology Effectiveness 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 

SO2

 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 

 NOX Low NOX 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 improve removal efficiency or reliability 

over the existing baghouse, which (based on source/performance tests) is currently operating 

at very high control efficiency. Furthermore the existing baghouse has a significant 

environmental benefit over either ESP technology because it provides comparable removal 

efficiencies and provides the added benefit of improved trace metal removal. Because of the 

negligible benefits of added or alternate PM control technology, there is no merit in further 

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

on SO2 and NOX control technologies. The existing baghouse therefore is considered BART 

for PM. 
 26

7.0 Step 4: Impact Analysis 

As per EPA guidelines an impact analysis was performed for each feasible BART technology. 

The purpose of impact analyses is to identify factors other than feasibility and control 

effectiveness that could affect the choice of the best 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 assumptions are documented using appropriate 

control technology resources including vendors, information documents, guidelines, cost 

manuals, and engineering/performance test data. Estimates of capital and annual operating costs 

are based on annualized cost of controls. 

The cost-effectiveness of each feasible control technology is calculated from the cost of 

compliance and the amount of emissions reduced. The cost-effectiveness is described as the cost 

of control per amount of emissions removed. Two types of cost-effectiveness analysis are 

recommended: average and incremental cost-effectiveness. The average cost-effectiveness is 

defined as the total annualized cost of control divided by the average annual quantity of pollutant 

removed for each control technology. The incremental 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 comparing technologies that have similar removal 

efficiencies. 

Part 2, the energy impact analysis, involves quantification 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 only direct energy consumption and not 

indirect energy impacts. The analysis may encompass concerns over use of locally scarce fuels. 

Part 3 of the analysis assesses environmental impacts other than air quality impacts of feasible 

technologies, including irreversible or irretrievable commitment of resources. Environmental 

impacts may be caused by generation of solid or hazardous waste or discharge of polluted water 

as a result of the technology. There may also be impacts associated with consumption and 

storage of chemicals required by the control technology. 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 only 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 identified technically feasible control 

technologies. TASCO initially established the design parameters for each feasible control 

technology. The design parameters contain all pertinent information regarding the control 

technology system for specific application to the source. Examples of these design criteria 

include but are not limited to: emission rates, removal efficiencies, exhaust gas 

characteristics, fuel use, pressure drop across the control technology, scrubber water flow, 

reagent chemistry and consumption, and characteristics of byproduct produced. The 

information used to define the design parameters included 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 identified as technically feasible for 

application at the TASCO Nampa facility are summarized 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 maintenance 

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 commercially available costing 

software. 

The capital and operating annual costs are used to determine the annualized cost for each 

feasible control technology by prorating the capital cost over a twenty-year useful service 

life and adding the annual operating costs. The annualized costs are used to calculate the 

average and incremental costs of each control technology. 

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 for each feasible control technology are 

included in cost evaluation tables in Appendix E. 

Although the Appendix Y Guidelines present a detailed process for determining cost 

effectiveness of control technologies, including a least cost graphing analysis to screen 

control options, they do not include criteria or thresholds for determining which 

technology is cost effective. The preamble to the 40 CFR Part 51 regional haze rules and 
 28

guidelines specify BART presumptive limits for both SO2 and NOX for large coal-fired 

electric generating units (EGU) (see 70 FR 39131, July 6, 2005). In conjunction with the 

presumptive limits EPA specifies affordability ranges in dollars per ton of pollutant 

removed. However, neither the presumptive limits nor affordability ranges apply to 

smaller industrial sector units like the Riley Boiler. For this reason cost effectiveness and 

affordability of control systems for the Riley Boiler must be determined on as case by 

case basis. 

7.1.2 Energy Impacts. Energy impacts are estimated for each control technology that 

has consumption of auxiliary energy during its operation. Per EPA guidance only direct 

energy impacts, such as the auxiliary power consumption 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 equipment. Indirect energy impacts, such as 

the energy to produce raw materials used for the control technology system, are not 

considered. 

Considering the technologies for NOX 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 pressure that does not occur in LNB systems. 

Additional energy consumption is required to overcome the increased pressure drop of an 

SCR. Similarly for the control technologies for SO2 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 generation and management, quantity of 

freshwater utilized and whether visible plumes would increase. Specifically, for NOX

control, SCR has much higher non-air quality environmental impacts compared to LNB 

and other combustion control technologies. SCR catalysts must be replaced 

approximately every 3 years, increasing the quantity of hazardous waste. SCR also 

involves the storage and potential release of significant quantities of anhydrous ammonia. 

For SO2, the non-air quality environmental impacts are considerably greater for the Wet 

FGD control technology. Because of the saturated conditions in the reactor vessels the 

Wet FGD will generate a visible plume during most Riley Boiler operating conditions. 

The Wet FGD requires installation of a completely new wastewater handling system 

including an onsite waste water pond and piping that 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 control equipment differs from the service 

life of the source. TASCO determined that the remaining useful life of the controls will 

be 20 years, and the remaining useful life of the Riley Boiler will be longer than 20 years. 

Therefore, remaining useful life does not affect the 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 information for individual NOX and SO2

emission control technologies and combinations thereof. For each control scenario Table 6 

summarizes emissions, control effectiveness, capital 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 selection process, this analysis would include 

more exhaustive evaluations to screen the options, including a cost effectiveness curve and 

incremental cost evaluations. However, for the Riley Boiler affordability is a critical 

component of the feasibility analysis. The key impediment 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 the beet grower/shareholders have the 

available capital to fund such a project. Furthermore, because of existing debt, TASCO and 

its shareholders do not have access to capital in the financial markets for projects that provide 

no return on investment. 

The problem of funding new BART technology at the Nampa facility is magnified by its 

geographic location. Not only must the Nampa facility 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 arable land in the Treasure Valley, sugar 

beet farming in the valley has diminished. To accommodate this loss, beet production 

acreage has shifted to the east. In 2005 TASCO ceased 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 in Twin Falls and Mini-Cassia. 

Similar to the Nyssa facility, beet processing at Nampa has declined and production has 

increased at the Mini-Cassia facility in Paul, Idaho. These changes have been necessary to 

control beet hauling costs and to manage the overall 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 accompanying 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 sugarbeets for processing at Nampa. 

If the Nampa facility grower-owners were asked to finance additional emission controls on 

the Riley Boiler, the economic impact on them is illustrated as follows. Under ideal 

conditions the 627 grower-owners produce about 6 million 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 Treasure Valley growers at about $48,700. 
 30

In September 2008 when DEQ transmitted modeling results to TASCO, the Department 

recommended combined control technology scenario to reduce both NOX and SO2 emissions 

from the Riley Boiler: LNB with OFA and Spray Dry FGD. According to the impact 

analysis, the capital cost impact to install this combined control technology on the Riley 

Boiler to control both NOX and SO2 is $17.8 million or about $114,000 per each growerowner that supplies beets to the Nampa facility. In 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 SO2 or combined NOX/SO2 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 electric 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 electric power generating facilities, TASCO 

and its grower-owners have no ability to increase revenues 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 industry. 
31

Table 6 – SUMMARY OF COST IMPACT ANALYSIS 

Control Scenario 

Baseline 

Emissions 

(tons/yr) 

Removal 

Efficiency 

(percent) 

Annual Emissions 

Reduction 

(tons/yr) 

Total 

Reduction 

Total 

Capital 

Cost 

Total 

Annual 

Cost 

 NOX SO2 NOX SO2 NOX SO2 (tons/yr) (x1,000) (x1,000) NOX - Low NOx Burners 1,042 0 50% 0% 521 0 521 $2,720 $480 NOX – LNBwOFA 1,042 0 65% 0% 677 0 677 $4,875 $860 NOX - LNB + SO2 - Spray 

Dryer FGD 1,042 1,457 50% 80% 521 1,166 1,687 $15,690 $3,001 

NOX - LNBwOFA + SO2 - 

Spray Dryer FGD 1,042 1,457 65% 80% 677 1,166 1,843 $17,845 $3,381 

NOX - LNB + SO2 - Dry 

Trona FGD 1,042 1,457 50% 65% 521 947 1,468 $14,001 $2,902 

NOX - LNBwOFA + SO2 -

Dry Trona FGD 1,042 1,457 65% 65% 677 947 1,624 $16,156 $3,282 

SO2 - Spray Dry FGD 0 1,457 0% 80% 0 1,166 1,166 $12,970 $2,521 NOX - LNB + SO2 - Wet 

FGD 1,042 1,457 50% 95% 521 1,384 1,905 $24,786 $4,515 

NOX - LNBwOFA + SO2 - Wet FGD 1,042 1,457 65% 95% 677 1,384 2,061 $26,941 $4,895 SO2 - Dry Trona FGD 0 1,457 0% 65% 0 947 947 $11,281 $2,422 SO2 - Wet FGD 0 1,457 0% 95% 0 1,384 1,384 $22,066 $4,035 SO2 - Dry Lime FGD 0 1,457 0% 55% 0 801 801 $11,281 $2,687 NOX – SCR 1,042 0 90% 0% 938 0 938 $16,702 $3,534 Low Sulfur Coal 0 1,457 0% 15% 0 219 219 0 $1,024 
 32

8.0 Additional Emission Reduction and Visibility Improvement Project 

The Nampa facility recently completed installation and commenced operation of the world’s 

largest steam-heated beet pulp dryer. This state-of-the-art dryer project is a significant 

environmental improvement for the Nampa facility and 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 cooperatively with IDEQ by allocating 

over $20 million to the steam dryer and associated projects3

. The new steam pulp dryer, which 

dries residual beet pulp for cattle feed, began operating in December 2006. 

This project was a requirement of the Nampa facility Tier II Operating Permit and it was 

completed nearly one year ahead of schedule. Although the Tier II permit allows for partial 

operation of one direct-fired drum dryer, TASCO made the decision to completely shut down all 

three coal-fired drum dryers, demonstrating an ongoing commitment to protecting air quality. 

Capital for the steam dryer project was made available because it provided offsetting savings. 

The dryer replaced three direct coal-fired rotary drum dryers. Steam for heating the new dryer is 

supplied from existing boilers. Complementary energy 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 resulted 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 emission calculations and assumptions are 

provided in Appendix F. The emission reductions attributable 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 Shutdown of the Pulp Dryers 

Pollutant Maximum Hourly 

(lbs/hr) 

Average Annual 

(tons/year) 

PM 98.1 113 

SO2 17.8 20.6 

NOX 191 221 

 

3

 This project was required by IDEQ based on PM10 air dispersion modeling results. Ambient PM10 measurements 

at the Nampa facility boundary have been consistently well below the PM10 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 feasible BART control utilizing EPA’s predictive 

CALPUFF model to estimate visibility improvements. 

Actual measured visibility impairments are likely to be less than the findings of the model. In 

the preamble to the Regional Haze Regulation and Guidelines for BART Determinations EPA 

acknowledged that features of our recommended modeling approach are likely 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 source (see 70 FR 39121, July 6, 2005). This 

implies that differences of a fraction of a deciview are too small to be significant.

The BART visibility evaluation presumes that one deciview is a measurement of visual 

impairment that can be just discernable by an untrained 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 observers can discern any visual improvement at 2 to 

4 deciviews. To achieve a 90% observation probability 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 the 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 statistically discernable is not responsible 

expenditure of funds that (as discussed in other areas of this report) are clearly not affordable for 

the owners. 

9.1 Overview of BART Modeling Procedures 

The steps for determining potential visibility impact improvements include the following: 

• Develop a modeling protocol and run the model at pre-control and post-control 

emission rates using the 24-hour average actual emission rate from the highest 

emitting day of the meteorological period. 

• Make the net visibility improvement determination based on the modeled change 

in visibility impacts for the pre-control and post-control emission scenarios. 

• Use a comparison threshold to evaluate visibility improvement. 

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

Receptors used in the model should be located in the 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 from the highest emitting day of the 

meteorological period modeled. Model results are calculated for each receptor as the change 

in deciviews compared against natural visibility conditions. Post control emission rates for 

the net visibility improvement determination are calculated as a percentage of pre-control 

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

runs. 
 34

IDEQ used the CALPUFF model to conduct the BART determination 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, 2008. IDEQ provided modeling results to 

TASCO on September 16, 2008. IDEQ modeling results encompassed the three NOX control 

scenarios and five SO2 control scenarios identified in the feasibility assessment. IDEQ also 

modeled six scenarios involving various combinations of NOX and SO2 control technologies. 

Subsequent to receiving the DEQ modeling results, TASCO contracted with ENVIRON 

International corporation (formerly Geomatrix) to verify DEQ results and run additional 

scenarios. 

IDEQ ran the CALPUFF model to assess visibility impacts 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 Idaho-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 Riley Boiler. 

9.2 Findings of Visibility Impact Analysis 

The visibility impact model for the Riley Boiler was 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 Wilderness 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 NOX and SO2

controls is only 1 deciview. As discussed previously in this section the, the degree to which 

the Riley Boiler obscures emissions in the Eagle Caps cannot be detected by the human eye. 

Below this are the incremental visibility impact reductions provided by the feasible NOX and 

SO2 control technologies and combinations thereof. The values for each technology 

represent the reduction in deciviews and days for each 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. Based on the CALPUFF model, the highest 

predicted impacts occur primarily during the wintertime, 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 accessible and receive considerably less 

visitation. Visibility impacts of the Riley Boiler are less in the summertime when usage is 

highest.
35

Table 8 – Visibility Impact Summary - Eagle Cap Wilderness Area 

Reduction in deciviews & days above 0.5 dv 

Control 2003 2004 2005 2003-200

Scenario 8th % Days % 8th % Days % 8th % Days % 22nd % Da

Base - Riley Boiler only 0.721 15 1.086 41 1.109 41 1.086 9NOX - Low NOx Burners (LNB) 0.210 29% 4 27% 0.264 24% 12 29% 0.238 21% 12 29% 0.270 25% 2NOX - LNB with overfire air (LNBwOFA) 0.267 37% 8 53% 0.344 32% 17 41% 0.306 28% 16 39% 0.350 32% 4NOX - Selective Catalytic Reduction (SCR) 0.338 47% 9 60% 0.461 42% 25 61% 0.456 41% 23 56% 0.473 44% 5SO2 - Low Sulfur Coal 0.039 5% 0 0% 0.070 6% 2 5% 0.081 7% 5 12% 0.072 7% 7 SO2 - Dry Lime FGD 0.135 19% 6 40% 0.272 25% 13 32% 0.303 27% 12 29% 0.280 26% 3SO2 - Dry Trona FGD 0.156 22% 6 40% 0.322 30% 17 41% 0.370 33% 16 39% 0.325 30% 3SO2 - Spray Dryer FGD 0.194 27% 6 40% 0.383 35% 19 46% 0.402 36% 21 51% 0.400 37% 4SO2 - Wet FGD 0.222 31% 8 53% 0.439 40% 22 54% 0.464 42% 24 59% 0.448 41% 5NOX LNB + SO2 Dry Trona FGD 0.392 54% 10 67% 0.603 56% 35 85% 0.629 57% 35 85% 0.606 56% 8NOX LNB + SO2 Spray Dryer 0.427 59% 12 80% 0.684 63% 39 95% 0.692 62% 38 93% 0.684 63% 8NOX LNB + SO2 Wet FGD 0.451 63% 13 87% 0.727 67% 40 98% 0.757 68% 53 129% 0.738 68% 9NOX LNBwOFA + SO2 Dry Trona 0.463 64% 13 87% 0.691 64% 39 95% 0.715 64% 38 93% 0.692 64% 9NOX LNBwOFA + SO2 Spray Dryer 0.493 68% 14 93% 0.767 71% 40 98% 0.779 70% 40 98% 0.767 71% 9NOX LNBwOFA + SO2 Wet FGD 0.520 72% 14 93% 0.815 75% 41 100% 0.846 76% 41 100% 0.825 76% 9Base - Riley Boiler & Pulp Dryers 0.956 23 1.454 49 1.388 55 1.399 12Coal-Fired Pulp Dryers Shutdown 0.235 25% 8 35% 0.368 25% 8 16% 0.279 20% 14 26% 0.313 22% 3* Cost per deciview is the annual cost divided by the corresponding increment of deciview improvement for the 2003-05 period. 
 36

Considering that the visibility impact of the Riley Boiler without NOX or SO2 controls is not 

discernible to the human eye and that the major impacts occur during the low-use season, 

commitment of any resources to improvements that are not affordable is not responsible 

management. For the Eagle Cap area the Low NOX Burner provides a visibility impact 

reduction of 0.270 deciviews and 28 days over the baseline 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 NOX 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 deciview improvement. Note the cost per 

deciview improvement is $2,500,000 or more for all of the control scenarios except for the 

Low NOX Burner control option. The more sophisticated technologies provide marginal 

improvements in visibility at significantly higher cost. All of the SO2 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 NOX/SO2 control technologies is somewhat lower, the most cost 

effective combined scenario only provides a 0.767 deciview improvement in visibility. 

10.0 Conclusion and Recommendation 

TASCO’s Nampa facility provides cost effective conversion 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 investment. Unlike a typical electric utility, for 

which the regional haze rule was targeted, the increased 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 technical feasibility of installing haze-reducing 

technology on the Riley Boiler, all of the solutions are either not affordable or provide visibility 

improvements that will be imperceptible. Specifically, the cost for the combined technology to 

control NOX/SO2 exceeds the ability of TASCO and its grower-owners to fund the project. 

Funding the capital cost of a combined NOX/SO2 control system without considering annual 

costs would require the Nampa facility grower-owners to sacrifice over two years of net 

earnings. 

At a time when both sugar prices and sugar beet production acreage are at historic lows, there is 

no merit in expending significant additional capital and operating costs that result in marginal 

and imperceptible improvements in visibility at Class I areas located over 70 miles from the 

Nampa facility. Significant additional costs without offsetting savings or revenues could drive 

local growers and the Nampa facility out of the sugarbeet 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 Project in combination with maintaining the 

existing baghouse on the Riley Boiler provides significant 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 to be maintaining the existing baghouse for 

control of PM emissions in conjunction with the visibility improvements that have already been 

accomplished with the Steam Dryer Project.