Technical Analysis for Arizona and Hawaii Regional 

Haze FIPs: Task 7: Five-Factor BART Analysis for 

Chemical Lime Company Nelson, TEP Sundt 

(Irvington), and Catalyst Paper (Snowflake) Plants

Contract No: EP-D-07-102

Work Assignment: 5-12

Version: 1

Prepared for: Thomas Webb

Air Planning Office

U.S. EPA Region 9

75 Hawthorne Street

San Francisco, CA 94105

Prepared by: Uma Shankar, Elizabeth Adams, Mohammad Omary, 

Brian Naess and Saravanan Arunachalam

Institute for the Environment

University of North Carolina at Chapel Hill

Mark Lee, Juanita Haydel and Thomas Meyers

ICF International

Jim Staudt

Andover Technology Partners

Date delivered: October 9, 2012 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 ii October 9, 2012

Contents

Figures...........................................................................................................................................iii

Tables............................................................................................................................................ iv

Document Change Record .......................................................................................................... vi

1 Introduction............................................................................................................................ 1

2 Work Performed and Deliverable Summary ...................................................................... 2

2.1 General Considerations for Visibility Modeling............................................................. 2

2.2 Five-Factor Analyses...................................................................................................... 3

2.2.1 Nelson Lime Units 2 and 3..................................................................................4

2.2.2 Sundt Unit 4.......................................................................................................14

2.2.3 Catalyst Paper (Snowflake) Pulp Mill, Units 1-3..............................................24

2.3 Conclusions................................................................................................................... 36

References.................................................................................................................................... 38

Appendix A

Emissions Data Tables

Appendix B

Andover Technology Partners Report Chapter 3: BART Analysis (NOx, SO2 and PM)
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 iii October 9, 2012

Figures

Figure 1. Nelson Lime Plant ........................................................................................................... 4

Figure 2. Sundt Plant..................................................................................................................... 14

Figure 3. Power Boilers and Coal Pile at Catalyst Paper (Snowflake) Pulp Mill......................... 24
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 iv October 9, 2012

Tables

Table 1. CIAs Within 300 km of CLC Nelson, Sundt and Catalyst Paper..................................... 2

Table 2. Emissions and Controls at Nelson Lime Plant.................................................................. 4

Table 3. NOx Emission Reductions from Rotary Kilns with Various Control Technologies......... 5

Table 4. NOx Control Technologies for Nelson Lime Units 2 and 3.............................................. 6

Table 5. SO2 Emission Reductions from Rotary Kilns with Various Control Technologies......... 7

Table 6. SO2 Control Technologies for Nelson Lime Units 2 and 3 .............................................. 8

Table 7. Control Scenarios Used in Nelson Lime Visibility Modeling.......................................... 9

Table 8. Stack Parameters for Nelson Lime Units 1-3 ................................................................... 9

Table 9. 98th percentile Visibility Impairment (-dv) for Nelson Lime Scenarios Using 

IMPROVE Method 6 (a) and (b) Method 8(b).............................................................. 11

Table 10(a) . Visibility Benefits (dv) of Control Options for IMPROVE Method 6(a)............... 11

Table 10(b). Visibility Benefits (dv) of Control Options for IMPROVE Method 8(b)................ 12

Table 11. Control Effectiveness (million $/dv) for the Calculation Methods of Table 9............. 12

Table 12. Control Effectiveness (million $/dv) Summary for the Calculation Methods

of Table 9...................................................................................................................... 13

Table 13. Sundt Power Plant Data ................................................................................................ 14

Table 14. NOx Contol Technologies for Sundt Unit 4.................................................................. 16

Table 15. SO2 Contol Technologies for Sundt Unit 4 .................................................................. 17

Table 16. Control Scenarios Used in Sundt Visibility Modeling ................................................. 18

Table 17. Stack Parameters for Sundt Units 1-4........................................................................... 18

Table 18. 98th percentile Visibility Impairment (-dv) for Sundt Scenarios Using 

(a) IMPROVE Method 6(a) and (b) Method 8(b)........................................................ 20

Table 19. Visibility Benefits (dv) of Control Options for the Calculation Methods of Table 18. 21

Table 20. Control Effectiveness (million $/dv) for the Calculation Methods of Table 18........... 22

Table 21. Control Effectiveness (million $/dv) Summary for the Calculation Methods of 

Table 18........................................................................................................................ 23

Table 22. Catalyst Paper Boiler Data............................................................................................ 24

Table 23. Evaluated NOx Control Technologies for Catalyst Paper............................................ 25

Table 24. NOx Control Costs for Catalyst Paper Excluding Impact on Fly Ash.......................... 26

Table 25. SO2 BART Controls Evaluated for Catalyst Paper by Abitibi Bowater....................... 28

Table 26. ATP Analysis of SO2 BART Controls and Performance at Catalyst Paper ................. 28
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 v October 9, 2012

Table 27. Estimated Cost of a New Fabric Filter on Boiler #2 at Catalyst Paper ........................ 30

Table 28. Control Scenarios Used in Catalyst Paper Visibility Modeling ................................... 30

Table 29. Stack Parameters for Catalyst Paper Units 1-3............................................................. 31

Table 30. 98th Percentile Visibility Impairment (-dv) for Catalyst Paper Using 

(a) IMPROVE Method 6(a) and (b) Method 8(b)........................................................ 33

Table 31. Visibility Benefits (dv) of Control Options for the Calculation Methods of 

Table 30........................................................................................................................ 34

Table 32. Control Effectiveness (million $/dv) for the Calculation Methods of Table 30........... 35

Table 33. Control Effectiveness Summary (million $/dv) for the Calculation Methods of 

Table 30........................................................................................................................ 36

Table A-1(a). NOx, SO2 and PM Emission Inputs for Base and Control Scenarios for Nelson 

Lime Visibility Modeling..................................................................................... A-2

Table A-1(b). Speciated PM Emission Inputs for Base and Control Scenarios for Nelson Lime 

Visibility Modeling .............................................................................................. A-3

Table A-2(a). NOx, SO2 and PM Emission Inputs for Base and Control Scenarios for Sundt 

Unit 4 Visibility Modeling ................................................................................... A-4

Table A-2(b). Speciated PM Emission Inputs for Base and Control Scenarios for Sundt 

Unit 4 Visibility Modeling ................................................................................... A-5

Table A-3(a). NOx, SO2 and PM Emission Inputs for Base and Control Scenarios for Catalyst 

Paper Visibility Modeling .................................................................................... A-6

Table A-3(b). Speciated PM Emission Inputs for Base and Control Scenarios for Catalyst Paper 

Visibility Modeling .............................................................................................. A-6
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 vi October 9, 2012

Document Change Record

Revision Date Remarks

0.1 October 9, 2012 Draft version submitted to EPA
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 1 October 9, 2012

1 Introduction

This report describes the 5-factor BART analyses of all technically feasible NOx control options 

on the applicable units at the three facilities as listed below: 

 Chemical Lime Company (CLC) Nelson Plant Units 2 and 3 

 Sundt (TEP Irvington) Generating Station Unit 4

 Catalyst Paper (Snowflake) Pulp Mill Units 2. 

The five factors considered in these analyses are as follows:

1. Cost of compliance;

2. Energy and non-air quality impacts of compliance;

3. Any existing pollution control technology in use at each source;

4. Remaining useful life of the source, and 

5. Degree of visibility improvement that may be reasonably expected from the use of 

BART emissions controls.

Andover Technology Partners (ATP) estimated the cost of compliance for these units using data 

provided by Arizona Department of Environmental Quality (ADEQ) and the EPA Control Cost 

Manual (EPA, 2002). With assistance from ICF, ATP also examined data from EPA’s latest 

power sector modeling (Integrated Planning Model [IPM]) methods

1

, and other reasonable 

engineering methods to ensure consistency with the assumptions used in its control cost 

analyses. The control options were analyzed not only for the feasibility of implementation but 

also the first four factors listed above to estimate the total cost per year of each control 

technology and the cost of control per year for each.

Once all the feasible control options were identified, EPA reviewed and recommended control 

configurations on all applicable units to examine the visibility impacts of their emissions. UNC 

performed these impact assessments using the base configuration of existing controls as well as 

all EPA-approved control configurations for each BART facility at all Class I Areas (CIAs) 

within a 300-km radius through the use of dispersion modeling. Per EPA requirements these 

analyses used the following models and processors, and EPA-provided meteorological inputs 

available from a previous BART analysis done by ENSR (2009) using CALMET version 5.8:

 CALPUFF version 5.8 (v5.8) level 070623 puff dispersion model was used to estimate 

concentrations of visibility-impairing pollutants emitted by each facility at the relevant 

CIAs.

 The POSTUTIL utility version 1.56 was used to adjust these concentrations for the 

phase-partitioning of HNO3 between gas and particle based on additional input 

information.

 The adjusted concentrations were used in the CALPOST visibility post-processor 

version 6.221 (v6.221) to calculate the visibility impairment in deciview (dv) relative to 

the background visibility at each CIA. 

The change in deciview, or -dv, corresponding to the visibility-impairing pollutant emissions

reduction for each control option relative to the base configuration was used along with the 

 

1 Documentation of EPA IPM Base Case v4.10. http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 2 October 9, 2012

yearly cost of control to estimate the control cost effectiveness in $/dv at each CIA. It is also 

reported as the cost of the maximum dv benefit over all the CIAs, and for the dv benefit 

summed over all the CIAs. 

2 Work Performed and Deliverable Summary

In the five-factor analysis performed in this task ATP examined NOx, SO2 and particulate 

matter (PM) control options and their costs for each of the three facilities considering the first 

four factors listed in Section 1. UNC used these cost estimates along with its visibility impact 

assessments for each facility to estimate the control option effectiveness in a combined metric 

specified by EPA, namely, $/dv. The overarching considerations for the visibility impact 

assessments are provided in Section 2.1. The five-factor analyses for each plant are described in 

Section 2.2.

2.1 General Considerations for Visibility Modeling

In Task 4 of this WA UNC used a GIS software tool to determine the nearest distance D (km) to 

the boundaries of all the CIAs within a 300-km radius of the major emitting facilities; The 16 

CIAs and their nearest mean distances (as determined in the Task 4 screening) from the 

applicable BART facilities are listed in Table 1. The domain description and Lambert 

Conformal Conic (LCC) projection parameters to obtain the coordinates of the facilities and 

CIAs came from meteorological inputs for CALMET v5.8 provided by EPA from BART 

analysis by ENSR Corporation (ENSR, 2009) for the Navajo Generating Station for 2001-2003; 

this domain and meteorological inputs were also used in the CALPUFF modeling in this task. 

Table 1. CIAs Within 300 km of CLC Nelson, Sundt and Catalyst Paper

CIA

Short 

Name State Applicable Plant(s) from Nearest to Farthest

Respective Avg 

Near Distances (km)

Bryce Canyon brca UT Nelson 236

Chiricahua NM chir AZ Sundt, Cat. Paper 145, 299

Chiricahua Wilderness chrw AZ Sundt 140

Galiuro Wilderness gali AZ Sundt, Cat. Paper 63, 211

Gila Wilderness gila NM Sundt, Cat. Paper 129, 194

Grand Canyon NP grca AZ Nelson, Cat. Paper 25, 204

Joshua Tree NP jotr CA Nelson 237

Mazatzal Wilderness maza AZ Cat. Paper, Sundt, Nelson 113, 201, 205 

Mount Baldy Wilderness moba AZ Cat. Paper, Sundt 99, 231,

Petrified Forest NP pefo AZ Cat. Paper 39

Pine Mountain Wilderness pimo AZ Cat. Paper, Nelson, Sundt 136, 198, 246

Saguaro NP sagu AZ Sundt, Cat. Paper 26, 267

Sierra Ancha Wilderness sian AZ Cat. Paper, Sundt, Nelson 96, 178, 288 

Superstition Wilderness supe AZ Cat. Paper, Sundt, Nelson 135, 136, 285 

Sycamore Canyon 

Wilderness syca AZ Nelson, Cat. Paper 131, 154

Zion zion UT Nelson 183
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 3 October 9, 2012

The CALPUFF model set-up for the three facilities followed the guidance of the modeling 

protocol that was delivered to EPA on March 19, 2012 as a Task 5 deliverable. This modeling 

protocol invokes almost all the model input settings recommended in the WRAP BART Subject 

Protocol (2006) included in its Appendix A. Differences in model set-up from the 

recommendations of the WRAP protocol due to the CALPUFF version used, or other direction 

from the EPA are noted in this protocol. UNC verified and reconciled any discrepancies in the 

CALPUFF inputs through a series of test runs. Of note, CALPUFF modeling used a constant 

value of 1 ppb throughout for ammonia per EPA guidance. 

The CALPUFF model was run in each year 2001-2003, and the outputs were processed in the 

POSTUTIL processor to redistribute the HNO3 and PM nitrate using additional inputs. This 

step was necessitated by the limitations of CALPUFF v5.8 in modeling the gas-particle 

partitioning and formation of particulate nitrate. The annual concentration files output by 

POSTUTIL were combined in APPEND into a composite 3-year concentration file for visibility 

post-processing. CALPOST was used to determine the 98th percentile visibility impairment and 

the visibility benefits of control in the years 2001-2003, and in the composite period. Further 

facility-specific details on the visibility analyses are provided in Section 2.2.

2.2 Five-Factor Analyses

This section describes the control options analysis, followed by the details of the visibility 

modeling and the results of the five-factor analysis for each facility. The visibility modeling 

used combinations of control technologies (control “scenarios”) specified by the EPA with 

respect to the emissions inputs. The costs of compliance and visibility impacts for each scenario 

were estimated based on the following assumptions:

 The costs and emission reductions (in tons reduced) for the individual technologies that 

make up each control configuration are additive, i.e., the control scenario costs and

emission reductions can be expressed, respectively, as the sum of the component 

technology costs, and the sum of the associated emission reductions (in tons reduced). 

 The control effectiveness values are applicable to the baseline emission values used in

the visibility modeling. 

 The baseline periods used vary by source and unit, in order to account for differences in 

dates of installation of controls. This provides a more realistic assessment of “existing 

pollution control technology in use at each source” than a uniform baseline for all units.

 The baseline emissions used in the CALPUFF modeling are not identical to those used 

in the control options analyses because the BART Guidelines provide different methods 

for calculating baseline emissions for these two purposes. 

 The baseline emission inputs for NOx and SO2 use the 24-hour average emission rate 

from the highest emitting day of a representative baseline period (excluding periods of 

start-up, shutdown or malfunction). These data were extracted from the EPA Clean Air 

Market Division (CAMD) Continuous Emission Monitoring System (CEMS) database. 

 The baseline emission inputs for PM for visibility modeling are derived from the hourly 

plant heat input (from the CEMS database) multiplied by emission limits specified in 

ADEQ’s BART determinations for these units. This approach to estimating PM 

emissions accounts for the fact that EPA is proposing to approve ADEQ’s BART 

emission limits for PM at these units, and that these emission limits will go into effect 

prior to any NOx or SO2 limitations resulting from EPA’s action. 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 4 October 9, 2012

 The control cost analysis uses annual average emissions (TPY) based on actual 

emissions from a baseline period representing anticipated future annual emissions.

The visibility impacts of the control scenarios are discussed in the sections on visibility and

control effectiveness analysis for each facility.

2.2.1 Nelson Lime Units 2 and 3

2.2.1.1 General Plant Information

Nelson Lime plant (Figure 1) has two rotary kilns subject to BART (Units 2 and 3) rated at 859 

and 1,145 tons per day, respectively. There are no additional PM controls at the facilites beyond 

baghouses (fabric filters [FF]), and the one on Kiln 1 has been more recently installed. 2. Each 

kiln emits through a separate chimney; Table 2 summarizes the emissions data for the facility. 

Figure 1. Nelson Lime Plant

Table 2. Emissions and Controls at Nelson Lime Plant

Nelson Kiln 1 Nelson Kiln 2 Data Source

Maximum daily production, tons/day 859 1,145 Nelson 

BART 

Submittal

Emission Factors, lb/ton of product (lb/hr)

NOx 2.66 (95) 2.08 (99)

SO2 3.29 (118) 7.87 (375)

PM10 0.0423 (1.51) 0.0702 (3.35)

Controls Baghouse Baghouse, 

Multicyclone

Permit

 

2 BART Applicability Modeling Analysis, Chemical Lime Company, Nelson, AZ , September 2007
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 5 October 9, 2012

2.2.1.2 NOx Control Options Analysis

Coal combustion in the Nelson Lime Plant kilns is the source of NOx emissions from this 

facility. It is unclear if any NOx controls are installed, and for the purposes of this study it will 

be assumed that none are installed.

2.2.1.2.1 Available NOx Control Technologies

Table 3 shows technologies available for control of NOx from kilns and the expected percent 

reduction. As shown in the table, NOx reductions are possible through combustion controls or 

through post-combustion controls. This table was developed from data applicable to Portland 

Cement kilns.

Besides low NOx burners (LNBs), mid kiln firing (MKF), mixing air technology (MAT), 

Selective Non-Catalytic Reduction (SNCR) and SCR are available. These can be combined for 

higher NOx reduction than possible individually. Since the two Nelson plant kilns are preheater 

kilns, the most likely location for SNCR reagent injection is the preheater, where there is likely 

to be an available temperature window. For conservatism, it was assumed that SNCR in 

combination with other technologies provides a NOx reduction of 30% rather than 50%.

Table 3. NOx Emission Reductions from Rotary Kilns with Various Control Technologies†

NOx Control Technology Expected NOx Emissions Reduction (%)

Low - NOx Burner (LNB) 30

Mid - Kiln Firing 30

Mixing Air Technology (MAT)330

SNCR-Urea 50

SNCR-Ammonia 50

SCR 80

†

Source: ILEPA (2007)

2.2.1.2.2 Feasible NOx Control Technologies

All of the technologies discussed in the BART study are feasible. However, since SCR has had 

little or no known usage history on lime kilns, and a limited history in cement kilns, ATP 

regarded this technology as unfeasible and did not provide that evaluation. Also, since MKF 

with tires may not be an option for lime kilns, and its capital cost is much higher than some of 

the other combustion controls, it is not likely to be very economical and was thus not evaluated 

further. MAT reduces NOx emissions, but has a potential drawback in that it promotes gypsum 

formation in the product during SO2 capture. 

2.2.1.2.3 Evaluation of NOx Control Technologies

There are limited data on cost for NOx controls for lime kilns, and thus much of this evaluation 

was derived from data on cement kilns. In this case cost information developed for EPA’s 

Industrial Sector Integrated Solutions (ISIS) model was also used where applicable. 

4

 

3

http://www.cadencerecycling.com/papersbrochures.html
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 6 October 9, 2012

Table 4 shows the results of comparison of NOx emissions for the two Nelson kilns using 

feasible technologies. For conservatism in the cost estimates, it was assumed that LNB would 

be deployed in lieu of MAT to achieve 30% NOx reduction. Use of MAT rather than LNB 

would be less expensive, but increased gypsum formation in the product from SO2 capture 

might be undesireable. In the case of SNCR, a 50% reduction from uncontrolled levels was 

assumed. When combined with LNB, ATP assumed an additional 30% reduction of NOx by 

SNCR after the 30% reduction by LNB, for a total 51% reduction (=1.00 – 0.7*0.7). In either 

case, 50% reduction should be achievable and the costs shown in Tables 4(a) and (b) are 

conservative.

Table 4. NOx Control Technologies for Nelson Lime Units 2 and 3

Nelson Kiln 1 Nelson Kiln 2

LNB SNCR LNB and 

SNCR LNB SNCR LNB and SNCR

TPD Lime 859 859 859 1,145 1,145 1,145

Uncontrolled emissions

Uncontrolled NOx, 

lb/ton 2.66 2.66 2.66 2.08 2.08 2.08

PPH NOx 95 95 95 99 99 99

TPY NOx (90% 

capacity factor) 375 375 375 391 391 391

Controlled Emissions

Reduction 30% 50% 51% 30% 50% 51%

Controlled NOx, lb/ton 1.86 1.33 1.30 1.46 1.04 1.02

PPH NOx 67 48 47 69 50 49

TPY NOx (90% 

capacity factor) 263 188 184 274 196 192

Control Costs

Capital Cost $2,389,443 $679,055 $3,068,499 $2,857,256 $806,849 $3,664,105

Total Annualized Cost $396,129 $216,179 $597,335 $459,000 $235,465 $678,858

$/ton removed $3,518 $1,152 $3,121 $3,911 $1,204 $3,403

incremental, $/ton 

removed $3,518 -$2,397* $2,553* $3,911 -$2,857* $2,676*

*incremental cost compared to cost of LNB with 30% reduction since both of these provide roughly the same total 

NOx reduction

2.2.1.2.4 Energy and Environmental Impacts 

These technologies will have a very modest energy impact, requiring some additional auxiliary 

electrical load. NOx controls do have a potential environmental impact, but the extent of the 

negative impact is unclear. Modern burners have the benefit of much more advanced design 

methods than those used in earlier equipment and may even reduce carbon levels in fly ash 

while reducing NOx. In cases where carbon increases to untenable levels it can be mitigated by 

adjusting excess air levels, which will, however, have an adverse impact on NOx reduction.

SNCR technology also has the potential to result in ammonia on fly ash (ammonia slip), which 

may impact fly ash sales; however, this is dependent upon the coal fly ash pH and other factors. 

 

4 Memo from J. Staudt to R. Strivastava, et. al., regarding “Costs and Performance of Controls – revised from comments”, 

March 10, 2009 (part of ISIS development data)
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 7 October 9, 2012

Ammonia slip can generally be controlled to levels that do not adversely impact fly ash sales. 

EPRI performed a study in 2007 that examined the effects of ammonia slip from SCR systems 

and reached the conclusion that “The survey overwhelmingly indicated that ammonia 

contamination is not impacting the ability of plants to sell ash”. 5

2.2.1.3 SO2 Control Options Analysis

SO2 emissions from cement kilns are primarily from raw materials (limestone) rather than from 

coal combustion, which is mostly captured in the kiln and ends up in the product. However, fuel 

sulfur is more likely to be emitted in the form of SO2 in the case of lime kilns that try to avoid 

sulfur in the product, than in the case of cement kilns. Changing raw material sources is 

generally not possible; thus, “add-on” controls are likely to be needed to reduce SO2 emissions.

2.2.1.3.1 Available SO2 Control Technologies

Table 5 shows available SO2 control technologies. As discussed earlier, MAT may reduce SO2, 

but as it increases gypsum in the product, it is unclear if it would be deployed for a lime kiln.

Table 5. SO2 Emission Reductions from Rotary Kilns with Various Control Technologies

Technology Percent Removal

Mixing Air (MAT) Varies: assume ~ 30%

Dry Lime Injection ~ 50% 

Dry Sorbent Injection (DSI) using SBC 75% 

Dry FGD 90-95%

Wet FGD 95%

2.2.1.3.2 Feasible SO2 Control Technologies

All of the technologies are potentially feasible. Because FF is already installed on each kiln, a 

dry sorbent injection (DSI) system would likely be very effective. Lime and sodium bicarbonate 

(SBC) are potential DSI reagents, as is trona; however, SBC is preferable for SO2 capture. In 

practice, L’Hoist, the owner of the Nelson Plant, may choose to use a highly activated lime 

hydrate that they manufacture, in place of SBC, as it is capable of similar SO2 removal rates. 

DSI using SBC provides a reasonable surrogate for estimating the control cost of DSI using 

activated lime hydrate. Dry FGD is iikely to require a second baghouse because there does not 

appear to be room to install an absorber between the preheater and the FF, particularly for 

Kiln 2, and in any event, there may not be adequate space under the existing baghouses for air 

slides or recycle systems that would be used on a dry scrubber. Regardless, a dry FGD would 

provide similar SO2 removal as a wet FGD, and was evaluated as a conservative approach. Wet

lime or limestone FGD is feasible, and would be installed downstream of the existing baghouse.

2.2.1.3.3 Evaluation of SO2 Control Technologies

Table 6 shows the estimated costs and emission rates for the three technologies evaluated for 

the two kilns. DSI with SBC appears to have lower cost and higher reduction than dry lime 

injection (DLI), largely due to waste disposal costs associated with the higher material input for 

 

5

http://my.epri.com/portal/server.pt?Abstract_id=000000000001014269
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 8 October 9, 2012

DLI. However this analysis does not account for any difference in disposal cost per ton of waste 

for DLI versus SBC. Nor does it address any modifications to baghouse operation that may be 

necessary as a result of installing a DSI system. The wet scrubber has the highest removal, but 

also the highest cost. The SO2 reductions possible with MAT will vary.

The wet FGD capital cost shown here may be overestimated because very limted data re 

available. Costs were developed from data on wet FGD costs for cement kilns, which are also 

rather limited as few cement kilns are equipped with wet scrubbers. Most cost information has 

been gleaned from BACT analyses, described in supporting documentation for the ISIS model.

6

Table 6. SO2 Control Technologies for Nelson Lime Units 2 and 3

Nelson Kiln 1 Nelson Kiln 2

MAT Dry 

Lime

DSI with 

SBC Wet FGD MAT

Dry 

Lime

DSI with 

SBC Wet FGD

Historical SO2, lb/ton 3.29 3.29 3.29 3.29 7.87 7.87 7.87 7.87

Historical SO2, pph 118 118 118 118 375 375 375 375

Percent Removal 30% 50% 75% 95% 30% 50% 75% 95%

Outlet SO2, pph 82.4 58.9 29.4 5.9 262.5 187.5 93.8 18.8

Outlet SO2, lb/ton 2.30 1.65 0.82 0.16 5.51 3.94 1.97 0.39

% change in stack 

Velocity

No 

Change

No 

Change

No 

Change -20% No Change

No 

Change

No 

Change -20%

Exit temp No 

Change

No 

Change

No 

Change 130 F No Change

No 

Change

No 

Change 130 F

Impact on PM 

speciation

No 

Change

No 

Change

No 

Change

Yes, FF plus 

scrubber

No 

Change

No 

Change

No 

Change

Yes, FF plus 

scrubber

Capital Cost $754,196 $770,000 $409,382 8,082,077 $807,040 $1,940,000 $1,034,122 10,772,967

Annualized Costs $176,364 $545,415 $389,957 $1,369,380 $183,466 $1,502,933 $1,040,460 $1,958,408

TPY removed (90% 

capacity factor) 139 232 348 441 443 739 1109 1404

$/ton removed $1,266 $2,350 $1,120 $3,105 $414 $2,033 $938 $1,395 

Incremental $/ton $1,266 $3,975 ($1,340) $10,550 $414 $4,463 ($1,251) $3,105 

2.2.1.4 PM Control Options 

The Nelson Plant already has fabric filters installed on both kilns. As a result there is no 

additional technology available that provides a higher degree of PM reduction than what is 

already installed.

2.2.1.5 Visibility Modeling 

Although Nelson Lime Units 2 and 3 are the only units for which a BART determination is 

being made, Unit 1 was included in the visibility modeling for a realistic representation of the 

plumes. The EPA reviewed the control options presented in Tables 4 and 6 and provided a set of 

control technology configurations for Nelson Lime Units 2 and 3 for the visibility modeling. In 

 

6 Memo from J. Staudt to R. Srivastava , E. Torrez, K. Barnett, Re: Wet Scrubber Cost Algorithms, Feb 26, 2010
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 9 October 9, 2012

the following sections we describe the inputs used for Nelson Lime, and the control 

effectiveness we estimated in $/dv for each of these configurations.

Table 7. Control Scenarios Used in Nelson Lime Visibility Modeling

Control 

Option

Unit 2 Unit 3 All Units All Units

Control(s) 

Used

-Emis (TPY) Control(s) 

Used

-Emis (TPY) -Emis (TPY) $/year

SO2 NOx SO2 NOx SO2 NOx SO2+NOx

Base Case 0 0 0 0 0 0 $0

Ctrl-1 DLS 232 0 DLS 739 0 971 0 $2,048,348

Ctrl-2 SBC Inj. 348 0 SBC inj. 1109 0 1457 0 $1,430,417

Ctrl-3 Wet FGD 441 0 Wet FGD 1404 0 1845 0 $3,327,788

Ctrl-4 0 0 Wet FGD 1404 0 1404 0 $1,958,408

Ctrl-5 Wet FGD 441 0 0 0 441 0 $1,369,380

Ctrl-6 MAT 139 0 MAT 443 0 582 0 $359,830

Ctrl-7 SNCR 0 187 SNCR 0 195 0 382 $451,644

Ctrl-8 LNB+SNCR 0 191 LNB+SNCR 0 199 0 390 $1,276,193

2.2.1.5.1 Stack Parameters

The stack parameter data for Nelson Lime Units 1-3 used in the visibility modeling were 

obtained from the ADEQ BART reports for Units 2 and 3 and from the WRAP Planning 

Inventory of 2002 for Unit 1. Table 8 summarizes the stack parameters input to CALPUFF. 

Also shown in Table 8 are the changes in the stack parameters when wet FGD control is 

implemented, as it changes both the plume exit velocity and the stack temperature. 

Table 8. Stack Parameters for Nelson Lime Units 1-3

2.2.1.5.2 CALPUFF Emissions Inputs and Setup

EPA provided extensive guidance on the emissions data for all the BART sources analyzed in 

this WA. These data are documented for each applicable facility and unit in Table B-1 of the 

modeling protocol submitted as a Task 5 deliverable, and in the supporting spreadsheet 

documentation for this report. The input data underwent extensive quality assurance (QA) using 

scripts created for the purpose by UNC. The emissions data sources are described below and the 

data are shown in Table A-1 of Appendix A.:

 The only data available for this 3-unit plant are the WRAP BART analysis data of 2007 

(WRAP, 2007); these were used as baseline emissions for all pollutants for all units. 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 10 October 9, 2012

o PM speciation information was obtained from the National Park Service (NPS) 

spreadsheet data for the relevant source type, in this case, "Coal Fired Rotary 

Lime Kiln Fabric Filter Example" (see 

http://www.nature.nps.gov/air/Permits/ect/docs/limeK/2006FinalCoalfiredRotaryLi

meKilnFFSpeciation.xls).

Following the CALPUFF modeling, the concentration files were input to the POSTUTIL 

processor for the repartitioning of nitrate between gas and particulate phases, as the version of 

CALPUFF used does not have the advancements in chemistry available in the later versions. 

The POSTUTIL output concentration files for 2001-2003 were combined in the APPEND 

utility to produce a composite 3-year file, which was provided along with the annual files for 

CALPOST visibility processing.

2.2.1.5.3 CALPOST Setup

As with the CALPUFF modeling, the CALPOST model setup followed the modeling protocol. 

Post-processing of POSTUTIL output with CALPOST used both IMPROVE Methods 6 and 8 

(submode 5) for calculation and comparison of the incremental visibility impairment (-dv) 

relative to background at the affected CIAs. Each method used two sets of background visibility 

conditions in these assessments, corresponding to (a) annual average background, and (b) 

background visibility on the 20% best visibility days at the CIAs. For both methods, CALPOST 

uses the input values of monthly-average relative humidity adjustment factor f(RH), rather than 

the hourly values on the VISB.DAT file generated by CALPUFF. CALPOST input data were 

extensively quality-assured using scripts created for this purpose by UNC.

2.2.1.5.4 Extraction of Visibility Results with POSTCALPOST 

UNC extracted the results from the CALPOST visibility analysis for the four methods of 

calculating visibility using its Unix-based extraction script named POSTCALPOST. The results 

for the 98th percentile incremental visibility impairment -dv relative to background visibility at 

the 9 CIAs listed in Table 1 within 300-km of Nelson Lime Plant for each year modeled (2001-

2003), and for the composite 3-year period are documented in the supporting spreadsheet 

documentation submitted with this report. The results in this report are from Method 6(a) and 

8(b) for the composite 3-year period 2001-2003. Tables 9(a) and (b) summarize the incremental 

visibility impairment relative to background (22nd highest -dv, corresponding to 98th

percentile) at each CIA within 300 km of Nelson Lime Plant for the base case and controls 

scenarios from Method 6(a) and Method 8(b) respectively.
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 11 October 9, 2012

Table 9. 98th percentile Visibility Impairment (-dv) for Nelson Lime Scenarios Using

IMPROVE Method 6 (a) and (b) Method 8(b)

(a)

(b)

The maximum impairment is seen from Table 9 to occur at Grand Canyon National Park (grca) 

using either calculation method, and is higher than 0.5 dv for all scenarios. IMPROVE Method 

8(b) estimates equal or higher impairment compared to 6(a) for all scenarios and CIAs, but the 

difference decreases with increasing distance from the CIAs. SNCR on both kilns appears to 

produce the least impairment at the most visibility-impaired CIAs, but lower levels of 

impairment are also seen for the use of wet FGD at the farther CIAs (e.g., Sierra Ancha). 

Table 10 shows the greatest benefits occurring at (grca), but no CIA shows a benefit exceeding 

the minimum of 0.5 dv. The SNCR controls with and without LNB show virtually no benefit at 

the farther CIAs; SO2 controls, and in particular, the use of wet FGD on both kilns seem to be 

more effective from the visibility perspective in these locations. 

Table 10(a) . Visibility Benefits (dv) of Control Options for IMPROVE Method 6(a)

(a)
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 12 October 9, 2012

Table 10(b). Visibility Benefits (dv) of Control Options for IMPROVE Method 8(b)

(b)

2.2.1.6 Control Effectiveness Results

In this section we examine the results for the control effectiveness in million $/dv, which is the 

dollars (in millions) per year from Table 7 divided by the visibility improvement relative to base 

from Table 10 for each control scenario. The results are summarized for each CIA in Table 11. 

In both visibility methods, at the worst impaired CIA (grca) the highest control effectiveness 

(i.e., lowest $/dv) values are with SNCR, and MAT. However, at most CIAs farther away from 

Nelson Lime, e.g., Pine Mountain and Sierra Ancha, the SO2 control options of wet FGD on 

Unit 3 and DSI with SBC are seen to be more cost effective than SNCR and MAT. This is 

reflected in the difference between the effectiveness values for the maximum-impact CIA and 

the dv benefits summed over all CIAs in Table 12.

Table 11. Control Effectiveness (million $/dv) for the Calculation Methods of Table 9

(a)

(b)
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 13 October 9, 2012

Table 12. Control Effectiveness (million $/dv) Summary for the 

Calculation Methods of Table 9

(a)

(b)

Comparing the results of Table12(a) and (b) for the control effectiveness using dv summed over 

all CIAs against that using the dv for the CIA with the maximum impact, the wet FGD control 

on Unit 3 is seen to be more effective at the farther CIAs than at the ones with the maximum 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 14 October 9, 2012

impact. At the CIA with maximum dv impact, the most cost-effective controls are achieved with 

SNCR, followed by MAT, as estimated by either visibility method.

2.2.2 Sundt Unit 4

2.2.2.1 General Plant Information

Unit 4 of the Sundt plant (formerly Irvington) shown in Figure 2 is a coal-fired boiler that was 

found to be subject to BART from our previous analyses in Task 6 of this WA. Table 13 

displays the modeled and reported data for Sundt Unit 4 as an average over 2008-2010, and as 

an annual average averaged for 2011. The capacity factor, which is important in performing cost 

effectiveness calculations, is determined by dividing total reported heat input by the potential 

heat input if the unit were operating at 100% capacity, 365 days a year.

Sundt Unit 4 has a baghouse (FF) for PM control. In addition it is equipped with LNB and 

overfire air (OFA) for NOx control.

Figure 2. Sundt Plant

Table 13. Sundt Power Plant Data

Unit

Capacity

Fuel

2008-2010 

Reported Avg

2011 Reported 

Rates

2008-

2011

NOx SO2 NOx SO2

Capacity 

Factor

MW gross lb/MMBtu lb/MMBtu %

Unit 4 173.3 Coal 0.361 0.477 0.445 0.729 37%
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 15 October 9, 2012

2.2.2.2 NOx Control Options Analysis

2.2.2.2.1 Available NOx Control Technologies

Both combustion and post-combustion controls are available.

2.2.2.2.2 Feasible NOx Control Technologies

Since Sundt 4 already has combustion controls by way of LNB and OFA, the focus of ATP’s 

cost analysis was on post-combustion controls.

2.2.2.2.3 Evaluation of NOx Control Technologies

Although only post-combustion controls were examined, some advanced forms of OFA may 

permit further reductions. The results of this evaluation are shown in Table 14.

For the cost estimation, baseline emissions and capacity factors for all electric utility units were 

developed from historical data as follows:

 The capacity factor is the average of that estimated for the period 2008-2011 using 

reported heat input and plant capacity information.

 NOx and SO2 emission rates were examined for the average period of 2008-2010 and 

2011. The 2011 rate was selected as the baseline rate for estimating cost effectiveness.

In addition, a capital recovery factor of 9.44% (equal to 7% over 20 years) plus tax and 

insurance costs of 1.2% were assumed in the cost analysis. This rate for taxes and insurance 

differs from what is used for industrial sources per the EPA Air Pollution Control Cost Manual, 

and is consistent with what has been determined for electric generating units per the IPM 

documentation. 7

2.2.2.2.4 Energy and Environmental Impacts

SNCR has negligible energy impact. SCR will incur an additional parasitic loss, mainly due to 

pressure drop across the SCR system, which is roughly equal to 0.59% of output. Although the 

IPM calculations for which these algorithms were developed treated this not as a cost, but as a 

reduction in capacity, in these calculations it has been treated as an increase in variable 

operating costs.

Environmental impacts of SNCR and SCR are primarily due to ammonia slip. The main 

environmental concern is regarding fly ash odor and potential impact on fly ash sales/disposal. 

Ammonia slip can be well controlled so that fly ash is not adversely impacted. SCR catalyst can 

be recycled and therefore is not a significant concern. 

 

7

From Integrated Planning Model ver 4.10 documentation, page 8-11: 0.30% for insurance and 0.90% for taxes.
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 16 October 9, 2012

Table 14. NOx Contol Technologies for Sundt Unit 4 

Sundt 4 - NOx

SNCR SCR

Capacity Factor 37% 37%

Control Efficiency 30% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 813 813

NOx Rate (lb/MMBtu) 0.445 0.445

NOx (TPY) 1318 1318

Controlled Rate

NOx Rate (lb/hr) 569 91

NOx Rate (lb/MMBtu) 0.31 0.05

NOx (TPY) 923 148

Tons/Year Removed 395 1,170

Total Cost, $/year $1,308,000 $5,712,715

$/Ton $3,307 $4,882

$/Ton (incremental) $3,307 $5,686

* SCR is actually capable of 90% removal. The model that we used set a 

lower limit of 0.05 lb/MMBtu, but lower NOx levels should be achievable

2.2.2.3 SO2 Control Options Analysis

SO2 emission rates increased in 2011 from the 2008-2010 average, indicating a change in coal.

2.2.2.3.1 Available SO2 Control Technologies

Available technologies for Sundt are DSI, wet and dry FGD, and a change to lower sulfur coal.

2.2.2.3.2 Feasible SO2 Control Technologies

All of the available technologies are feasible. In fact, DSI is well suited to this unit since it is 

equipped with FF control. A dry FGD at Sundt Unit 4 is assumed to include a new FF since 

there is probably not enough space to install a new absorber between the boiler and the existing 

FF. A wet FGD would be installed downstream of the existing FF.

2.2.2.3.3 Evaluation of of SO2 Control Technologies

A change in coal was not evaluated for cost since coal cost data was not available.

Table 15 shows the estimated cost of each of the SO2 control technologies. In light of the low 

capacity factor and high capital costs of FGD, the two FGD approaches are much more 

expensive than DSI (based on $/tons SO2 removed). DSI is expected to have high control

efficiency due to the existing FF. The FGD removal efficiencies are limited by assumptions in 

the Sargent & Lundy model developed for CAMD that was used for the FGD cost analysis. In 

practice, we would expect both dry and wet FGD to achieve higher capture efficiencies and 

therefore somewhat lower emissions levels, i.e., the Table 15 results are conservative.
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 17 October 9, 2012

Table 15. SO2 Contol Technologies for Sundt Unit 4 

2.2.2.3.4 Energy and Environmental Impacts of Control Options

The energy impacts of DSI are small. FGD will have significant energy impacts (over 1% of 

output) due to pressure loss across the FGD system, and the additional pumping power and 

auxiliary loads involved. Energy costs are included for each technology analyzed in Table 15.

DSI using trona or SBC will result in increased solids collected by FF. These sodium-based 

materials may result in a by-product with a water-soluble component that may require some 

stabilization. The use of activated lime hydrate might avoid this problem. DSI has other benefits 

to air emissions.

Both the wet and dry scrubbers will have waste products. The dry scrubber waste is stable and 

can be disposed of in landfills. The wet scrubber waste can be dewatered and sold to the 

gypsum market. More information on these impacts is available in Section 2.1.2 of the ATP 

report attached in Appendix B.

2.2.2.4 PM Control Options 

Sundt Unit 4 is equipped with FF, and there is no technology available that would provide a 

higher degree of PM reduction than a properly designed and operated FF. Therefore, there are 

no changes assumed to the PM emission rates under the BART analysis.

Sundt 4 – SO2

DSI Dry FGD Wet FGD

Capacity Factor 37% 37% 37%

Control Efficiency 75% 89% 92%

Uncontrolled Rate

SO2 Rate (lb/hr) 1333 1333 1333

SO2 Rate (lb/MMBtu) 0.729 0.729 0.729

SO2 (TPY) 2160 2160 2160

Controlled Rate

SO2 Rate (lb/hr) 333 146 110

SO2 Rate (lb/MMBtu) 0.18 0.08 0.06

SO2 (TPY) 540 237 178

Tons/Year Removed 1620 1923 1982

% change stack velocity No Change -10% -20%

Exit temp No Change 175 F 130 F

Impact on PM speciation No Change Yes, FGD plus FF Yes, FGD plus FF 

Total Cost, $/year $2,967,501 $12,553,539 $13,986,681

$/Ton $1,832 $6,529 $7,057

$/Ton (incremental) $1,832 $31,647 $24,189
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 18 October 9, 2012

2.2.2.5 Visibility Modeling

Sundt Unit 4 is subject to BART controls, but for realistic representation of the emission 

plumes all four units of the plant were included in the CALPUFF model inputs. EPA reviewed 

the control options presented in Tables 14 and 15 and recommended the control configurations 

for the modeling presented in Table 16. The following sections describe the control scenarios, 

and the input data assumptions and sources of data for the various visibility modeling 

components.

Table 16. Control Scenarios Used in Sundt Visibility Modeling

Control 

Option

Unit 4 All Controls

SO2 Control -Emis SO2

(TPY) NOx Control -Emis NOx(TPY) 

SO2+NOx

-Emis 

(TPY) $/year

Base Case LNB+OFA; 

FF

0 LNB+OFA; FF 0 0 $0

Ctrl-1 DSI 1620 - 0 1620 $2,967,501

Ctrl-2 Dry FGD 1923 - 0 1923 $12,553,539

Ctrl-3 Wet FGD 1982 - 0 1982 $13,986,681

Ctrl-4 0 SNCR 395 395 $1,308,000

Ctrl-5 DSI 1620 SNCR 395 2015 $4,275,501

Ctrl-6 Dry FGD 1923 SNCR 395 2318 $13,861,539

Ctrl-7 Wet FGD 1982 SNCR 395 2377 $15,294,681

Ctrl-8 0 SCR 1170 1170 $5,712,715

Ctrl-9 DSI 1620 SCR 1170 2790 $8,680,216

Ctrl-10 Dry FGD 1923 SCR 1170 3093 $18,266,254

Ctrl-11 Wet FGD 1982 SCR 1170 3152 $19,699,396

2.2.2.5.1 Stack Parameters

Table 17 lists stack parameters for Sundt, taken from the National Emission Inventory 2008 

Version 2; stack elevation was taken from the WRAP BART analysis of 20078. The table 

includes changes in the exit velocity and temperature for each of the FGD control scenarios, as 

recommended in Table 15.

Table 17. Stack Parameters for Sundt Units 1-4

 

8

Summary of WRAP BART Modeling for Arizona, Draft #5, May 25, 2007. See 

http://pah.cert.ucr.edu/aqm/308/bart.shtml
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 19 October 9, 2012

2.2.2.5.2 CALPUFF Emissions Inputs

The modeling requirements and data sources for emissions for Sundt Units 1-4 were specified 

by EPA. These data are documented in Table B-1 of the modeling protocol submitted as a 

Task 5 deliverable, and in the supporting spreadsheet documentation for this report. They are 

included for convenience in Table A-2, Appendix A. The input data were extensively qualityassured using scripts created for this purpose by UNC. The emission data for Sundt were input 

as follows:

 The baseline emission rates for NOx and SO2 for all four units were obtained from 

CEMS for the average hourly emission rate of the maximum emission day during a 

period of continuous operation from 2008-2010. Units 1-3 of Sundt are natural-gas fired 

boilers, and in all scenarios modeled their NOx and SO2emission rates were held at their 

baseline values. 

 The EPA’s initial guidance on the emissions for these scenarios called for the use of the 

WRAP BART analysis (WRAP, 2007) for PM emissions from all units. However, that 

analysis covered only Unit 4 and one out of three of the natural gas-fired units. Thus the 

WRAP emission rates were used only for Unit 4. 

o PM speciation for Unit 4 was derived using the NPS speciation spreadsheets for drybottom coal-fired boiler with fabric filter (see 

http://www.nature.nps.gov/air/Permits/ect/docs/coalBoiler/2006FinalDryBottomPC_

FFpmSpeciationProfile.xls).

o The heating value, ash content and sulfur content of Rout Company (CO) coal

needed for PM speciation were provided by EPA.

 As reliable PM emissions information was not available for Units 1-3, and their PM 

emission rates are very low compared to the NOx and SO2 emissions from the facility, 

EPA eventually recommended that the PM emissions from Units 1-3 be set to zero. Thus 

no PM emissions or speciation data are provided for these units. 

The CALPUFF modeling and the post-processing of CALPUFF output files in POSTUTIL to 

provide concentration inputs to CALPOST followed the procedure described for Nelson Lime 

in Section 2.2.1.5.2.

2.2.2.5.3 CALPOST Setup

The CALPOST setup to calculate the visibility impacts for Sundt followed the steps described

for Nelson Lime in Section 2.2.1.5.3, using customized scripts to QA the large number of 

inputs, consisting of 9 CIAs to be processed for the base case and 11 control scenarios.

2.2.2.5.4 Extraction of Visibility Results with POSTCALPOST 

UNC extracted the results from the CALPOST visibility analysis for the four methods of 

calculating visibility using POSTCALPOST. The results for the 98th percentile incremental 

visibility impairment -dv relative to background visibility at the 9 CIAs listed in Table 1 

within 300-km of the Sundt Plant for each year modeled (2001-2003), and for the composite 

three-year period are documented in the supporting spreadsheet documentation submitted with 

this report. The results in this report are from Method 6(a) and 8(b) for the composite period 

2001-2003. Tables 18(a) and (b) summarize the incremental visibility impairment relative to 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 20 October 9, 2012

background (22nd highest -dv, corresponding to the 98th percentile) at each CIA within 300 

km of the Sundt Plant for the base case and controls scenarios from Method 6(a) and Method 

8(b) respectively.

Table 18 shows greater visibility impairment for Method 6(a) compared to Method 8(b). The 

maximum visibility impairment due to Sundt is seen at Saguaro for both visibility methods. The 

lowest values of visibility impairment at this CIA are obtained with SCR controls combined 

with DSI. However, at CIAs that are farther away such as Mazatzal and Mount Baldy, the 

visibility impairment is least for SCR with (dry or wet) FGD controls.

Table 18. 98th percentile Visibility Impairment (-dv) for Sundt Scenarios Using 

(a) IMPROVE Method 6(a) and (b) Method 8(b)

(a)

(b)
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 21 October 9, 2012

The above conclusion is confirmed by Table 19, which shows that the visibility benefits are 

greatest at Saguaro for SCR combined with DSI, followed by only SCR control. This applies to 

both visibility methods. At the more distant CIAs, the benefits are comparable among several 

technologies, including, in addition to these, SO2 control options such as dry and wet FGD in 

combination with the post-combustion NOx controls. 

Table 19. Visibility Benefits (dv) of Control Options for the Calculation Methods of Table 18

(a)

(b)
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 22 October 9, 2012

2.2.2.6 Control Effectiveness Results

This section discusses the control cost effectiveness in $/dv for each control option at each CIA, 

at the CIA with the maximum dv impact, and for the dv impact summed over all CIAs. Tables 

20(a) and (b) show the comparisons on a CIA-specific basis. The most effective control options 

when costs are considered are, in order, SNCR without and with dry FGD when considering 

impacts over all CIAs. At the most impaired CIA, SNCR is still the most cost-effective, 

followed by SCR alone, and SCR combined with DSI. The post-combustion NOx control 

outweighs the effectiveness of SO2 controls, because of the higher NOx emissions and their 

commensurate impact as well as the control efficiencies of these technologies. These results 

hold for both visibility methods. 

Table 20. Control Effectiveness (million $/dv) for the Calculation Methods of Table 18

(a)

(b)

The summary results are presented in Table 21. A comparison of the $/dv value using the 

summed visibility impacts over all CIAs shows that the SO2 controls (DSI, wet and dry FGD) 

are clearly more cost-effective for the CIAs farther away than for nearest ones, and that DSI is 

much more cost-effective at the nearest CIA in combination with SCR and SNCR, rather than as 

a sole control option. SCR, due to its much higher cost is not as cost-effective as SNCR despite 

its much greater control efficiency. Finally, Method 8(b) shows greater effectiveness than 

Method 6(a) for all control options and CIAs.
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 23 October 9, 2012

Table 21. Control Effectiveness (million $/dv) Summary for the 

Calculation Methods of Table 18

(a)

(b)
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 24 October 9, 2012

2.2.3 Catalyst Paper (Snowflake) Pulp Mill, Units 1-3

2.2.3.1 General Plant Information

Figure 3 shows a Google Earth image of this three-unit plant; all of which are power boilers.

Plant data and capacity factors for the plant are provided in Table 22. Boiler #2, subject to 

BART, is coal-fired with a rated heat input of 1,132 MMBtu/hr when firing coal; it may also 

use residual oil. ATP’s analysis examined methods for reducing NOx and SO2 at the mill.

Figure 3. Power Boilers and Coal Pile at Catalyst Paper (Snowflake) Pulp Mill

Table 22. Catalyst Paper Boiler Data

Data Element Data Source

Boiler Type (Unit 2) Wall Fired BART Submittal

Boiler Heat Input Boiler 1: 523 MMBtu/hr with Nat Gas, 472 MMBtu/hr 

with Oil

Boiler 2: 1132 MMBtu/hr with Coal, 1110 MMBtu/hr with 

Oil

Boiler 3: 337 MMBtu/hr with Nat Gas, 315 MMBtu/hr 

with Oil

Permit, page 45

Boiler Combustion Configuration

Existing NOx Controls Unit 3 has a low NOx burner listed in their permit, the 

other two have no NOx controls.

Permit

Current NOx Emission Rate 

(lbs/MMBtu)

Cap of 0.3 lb/MMBtu while burning oil in Unit 2. Cap of 

0.7 lb/MMBtu while burning coal in Unit 2.

Permit

Coal Type(s) Western Bituminous (Lee Ranch El Segundo) BART Submittal

Ash Content (%) 17.9 BART Submittal

Sulfur Content (%) 1.03 BART Submittal

Approx. Heating Value (Btu/lb) 9290 BART Submittal

Additional Information on 

Emissions Controls

Slipstream Wet Alkaline Scrubber by Flakt (tray type) 

installed on Unit 2 1990 must run 100% of the time. 

Treats 43% of Unit 2 flue gas

Permit and EIA 

Form 860

SO2 Emission Rate Cap of 1.0 lb/MMBtu while burning oil for Units 1&3, 

Cap of 0.8 lb/MMBtu while burning oil or coal for Unit 2

Permit

NOx Emission Rate (unit 2) 0.70 lb/MMBtu BART Submittal

PM Emission Rate Cap of 0.10 lb/MMBtu Permit

PM controls

- efficiency

- calculated emissions rate

- typical emissions rate

Hot Side ESP – no conditioning

99.2%

0.154 lb/MMBtu (from efficiency and fuel)

0.02 lb/MMBtu (from 2005 EIA form 767)

EIA Form 860, 

767
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 25 October 9, 2012

2.2.3.2 NOx Control Options Analysis

In this section the results of ATP’s analysis of a prior BART study conducted by Abitibi 

Bowater in January 2008 are presented. Based on this evaluation ATP made its final 

recommendations on control options and evaluated the cost of these controls for Catalyst Paper.

2.2.3.2.1 Available NOx Control Technologies

Technologies evaluated for AbitibiBowater in its BART analysis for NOx, and the projected 

emissions reductions are shown in Table 23. They cover all major categories of NOx controls. 

2.2.3.2.2 Feasible NOx Control Technologies

All of the technologies shown in Table 23 are feasible. The emissions targets developed by 

CH2MHill, Abitibi Bowater’s consultant who performed the BART analysis, incorporate 

additional margin over that offered by the technology supplier that varies by technology type. 

Table 23. Evaluated NOx Control Technologies for Catalyst Paper

2.2.3.2.3 Evaluation of of NOx Control Technologies

ATP reviewed the capital and operating costs directly associated with the NOx control 

technology analysis performed for AbitibiBowater, along with energy and environmental 

impacts. These costs all appeared to be reasonable, with the exception of SCR catalyst 

replacement cost, which seemed high. For a boiler of the size of Boiler 2 at Catalyst Paper, 

~150 m

3 of catalyst is expected (typically 1-1.5 m3 per 1000 MMBtu/hr). If half of that catalyst 

is replaced every two years, the cost is ~75 m3x $5000/m3or $375,000 every two years, i.e., 

less than $200,000 per year. Regenerated catalyst would reduce this cost by another ~40%, to 

about $120,000/year. Thus the $200,000 yearly cost for SCR catalyst shown in Table 24 is a 

conservative estimate.

The capital recovery factor of 13.5% assumed by AbitibiBowater roughly adds up to the 

combination of debt service (7% over 20 years, or 9.44% annually) and taxes, insurance and 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 26 October 9, 2012

administrative costs. EPA’s Control Cost Manual suggests using 4% of capital cost,

9

resulting

in 13.44% total annual cost.

Abitibi Bowater further assumed an additional indirect cost to NOx control associated with all 

fly ash being disposed of rather than sold. The impact of NOx controls on fly ash is likely 

overstated, by this assumption. Thus ADEQ requested, and Abitibi Bowater provided

supporting information on their fly ash purchase agreement, but did not address why they all fly 

ash was assumed to be unmarketable. As noted in Section 2.2.1.2.4, ammonia on fly ash can be 

controlled to levels that do not adversely impact fly ash sales. 

For the purpose of this BART analysis, the additional margin on NOx emission reduction 

assumed by Abitibi Bowater’s consulting engineer is assumed to provide adequate margin to 

allow for the possibility of operating at a higher NOx level than guaranteed by the supplier and 

for the likelihood of not having an impact on fly ash sales.

The costs from Abitibi Bowater’s BART analysis were considered reasonable with the 

exception of the estimated impacts on fly ash. The costs from the BART analysis are shown in 

Table 24 with the exception that the cost assigned to fly ash impacts from the NOx control are 

not included in the total cost and the estimate of $/ton of NOx removed. Another difference is 

the assumed capital recovery rate is 9.4% (consistent with 7% interest over 20 years) and an 

additional 4% for taxes, administrative, and insurance (per EPA’s control cost manual). The 

estimated $/ton of NOx removed is lower than what was estimated by Abitibi Bowater’s 

consultant, largely because of the difference in the way fly ash effects were addressed.

For the purpose of modeling, Cases 3 and 4 of Table 24 can be ignored since they would not be 

selected on the basis of cost.

2.2.3.2.4 Energy and Environmental Impacts 

Energy impacts have been evaluated and the cost shown as increased electrical load.

Environmental impacts of the combustion controls have a potential impact on fly ash; however, 

the original assumption made by Abitibi Bowater’s consultant that all of the fly ash would be 

affected is the worst case. In fact, many electric utility boilers firing many types of coals have 

combustion NOx controls and sell fly ash. Therefore, this assumption was considered an 

overstatement and ignored in this case.

Table 24. NOx Control Costs for Catalyst Paper Excluding Impact on Fly Ash

Case #

NOx Control

1

OFA with 

Existing 

Fan

2

LNB

3

MOBOTEC 

ROFA

4

MOBOTEC 

ROFA and 

Rotamix 

SNCR

5

LNB 

w/OFA

6

LNB w/ 

OFA and 

HERT 

SNCR

7

LNB with 

OFA and 

SCR

Heat Input Rate, 

MMBtu/hr

1132 1132 1132 1132 1132 1132 1132

Capacity Factor 100% 100% 100% 100% 100% 100% 100%

Heat Value, 

Bu/lb

9,290 9,290 9,290 9,290 9,290 9,290 9,290

 

9

EPA Air Pollution Control Cost Manual, Sixth Ed., 2002, Sect. 2.5.5.8, pp. 2-34
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 27 October 9, 2012

Case #

NOx Control

1

OFA with 

Existing 

Fan

2

LNB

3

MOBOTEC 

ROFA

4

MOBOTEC 

ROFA and 

Rotamix 

SNCR

5

LNB 

w/OFA

6

LNB w/ 

OFA and 

HERT 

SNCR

7

LNB with 

OFA and 

SCR

Historical Emissions Rate

Modeled Rate, 

pph*

914 914 914 914 914 914 914

NOx 

(lb/MMBtu)

0.7 0.7 0.7 0.7 0.7 0.7 0.7

NOx, pph 792 792 792 792 792 792 792

NOx, TPY 3,471 3,471 3,471 3,471 3,471 3,471 3,471

Controlled Emissions Rate

NOx 

(lb/MMBtu)

0.525 0.37 0.348 0.291 0.265 0.194 0.07

NOx, pph 594 419 394 329 300 220 79

NOx, TPY 2,603 1,835 1,725 1,443 1,314 962 347

NOx, Removed, 

TPY

868 1,636 1,745 2,028 2,157 2,509 3,124

Percent 

Removed

25% 47% 50% 58% 62% 72% 90%

Total Installed 

Cost

$20,000 $1,462,02

0 

$4,536,126 $5,964,840 $2,088,600 $2,792,400 $22,950,507 

Fixed O&M $25,740 $84,221 $207,185 $228,616 $109,284 $119,841 $137,689 

Non Fuel Var 

O&M

$1,802 $1,802 $468,389 

Make Up Water $4,322 $499 $246,973 

Urea/Ammonia $416,723 $347,240 $87,485 

SCR Catalyst $200,000 

Elect. Load $74,685 $323,637 $327,109 $3,472 $189,122 

Annualized 

Capital $1,888 $138,004 $428,178 $563,039 $197,149 $263,583 $2,166,366 

Taxes, Admin, 

Insurance $800 $58,481 $181,445 $238,594 $83,544 $111,696 $918,020 

Net Cost $103,113 $280,706 $1,140,445 $1,780,204 $389,977 $848,133 $4,414,044 

$/ton NOx $119 $172 $653 $878 $181 $338 $1,413 

Incremental 

$/ton NOx $119 $231 $7,882 $2,264 ($10,784) $1,301 $5,800 

* Modeled rate is the rate used by UNC in their historical modeling. Other historical rates are from AbitibiBowater BART 

study and may be more representative of average rate for the purpose of estimating cost effectiveness in $/ton 

removed.

2.2.3.3 SO2 Control Options Analysis

2.2.3.3.1 Available SO2 Control Technologies

The Abitibi Bowater BART analysis also included evaluation of SO2 control technologies. In 

this case only two options were considered in their analysis: (1) upgrade of the existing caustic 

wet scrubber, which only treats up to 43% of the flue gas as needed to ensure that the unit 

emissions remain below the permitted limit of 0.8 lb/MMBtu, and (2) addition of a second 

sodium wet FGD system that would allow treatment of 100% of the flue gas, as shown in 

Table 25. This is not a comprehensive list of possible control options. Other control options 

include dry FGD, which would offer the advantages of reduced water consumption, lower 

operating costs due to less expensive lime reagent, and much less costly disposal of waste, 

much lower PM emissions, and elimination of liquid waste. However, dry FGD would not 

provide the same level of SO2 removal and would have a higher capital cost than the wet 

scrubber option that Abitibi Bowater evaluated. Use of the dry scrubber would also continue to 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 28 October 9, 2012

allow segregation of fly ash with the hot-side electrostatic precipitators (ESPs) for sale into the 

concrete market. Another available technology is lower sulfur coal.

Table 25. SO2 BART Controls Evaluated for Catalyst Paper by Abitibi Bowater

2.2.3.3.2 Feasible SO2 Control Technologies

All of the available technologies are feasible.

2.2.3.3.3 Evaluation of SO2 Control Technologies

An order of magnitude estimate of the cost of a dry FGD system was developed by scaling the 

published cost information on the Turbosorp dry scrubber installed at the Greenidge power 

plant, and this is provided in an Excel workbook as supporting documentation for this report.

Table 26 compares control costs for all feasible control technologies. Total costs are shown as 

well as costs of controls relative to historical costs. The proposed costs relative to historical 

costs and proposed emissions reductions versus historical emissions are used to calculate the 

$/ton of SO2 removed.

Table 26. ATP Analysis of SO2 BART Controls and Performance at Catalyst Paper

Parameter

Case

Historical 1

Case

Historical 2

Case

1

Scrubber Upgrade

Case

2

Replace with 

new Dry Lime 

Scrubber

Case

3

Add’l Sodium 

Scrubber and 

Upgraded 

Scrubber

Heat Input Rate, MMBtu/hr 1132 1132 1132 1132 1132

Capacity Factor 100% 100% 100% 100% 100%

Heat Value, Bu/lb 9,290 9,290 9,290 9,290

Coal Sulfur, % 1.03% 1.03% 1.03% 1.03%

Uncontrolled SO2, lb/MMBtu 2.22 2.22 2.22 2.22

Uncontrolled Annual SO2 

Emissions, tons

10,994 10,994 10,994 10,994

Historical Emissions Rate

Modeled Rate, pph * 555 555 555 555 555

SO2 (lb/MMBtu) 0.799 0.799 0.799 0.799 0.799

SO2, pph 904 904 904 904 904

SO2, TPY 3,962 3,962 3,962 3,962 3,962

Controlled Emissions Rate

SO2 (lb/MMBtu) 0.80 0.80 0.74 0.111 0.04

SO2, pph 904 904 837 126 50

SO2, TPY 3,962 3,962 3664 550 220

SO2 Removed, TPY 0 0 298 3,412 3,742
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 29 October 9, 2012

Parameter

Case

Historical 1

Case

Historical 2

Case

1

Scrubber Upgrade

Case

2

Replace with 

new Dry Lime 

Scrubber

Case

3

Add’l Sodium 

Scrubber and 

Upgraded 

Scrubber

Percent Removed from 

historical

0 0 7.5% 86.1% 94.5%

% change in stack velocity none none None -10% -20%

Exit temp No change No change No change 175 F 130 F

Impact on PM speciation? none none none Yes – add FF Yes -all gas 

scrubbed

Total Installed Cost $650,000 $32,949,187 $15,650,000 

 Fixed O&M $60,665 $60,665 $60,665 $1,123,555 $90,998 

Non Fuel Var O&M $42,102 $42,102 $42,102 $236,704 $84,204 

Make Up Water $47,801 $115,960 $102,767 $15,780 $170,530 

Reagent $691,653 $2,308,793 $2,308,793 $2,278,391 $3,395,285 

Scrubber Waste Disposal $937,462 $3,129,323 $3,129,323 $669,604 $4,601,946 

Fly Ash Disp/Lost Ash ($889,759) ($1,400,085) ($1,400,085) ($1,400,085) ($1,400,085)

Elect. Load $673,696 $673,696 $673,696 $852,134 $640,312 

Annualized Capital $0 $0 $61,355 $3,110,170 $1,477,249 

Taxes, Admin, Insurance $0 $0 $26,000 $1,317,967 $626,000 

Annual Cost, incl ash $1,563,620 $4,930,454 $5,004,616 $8,204,221 $9,686,439 

Cost of Control (note – fuel costs are not shown, all control estimates assume the same fuel as Historical 2)

Net Cost, $/yr, greater than Historical 2 $74,162 $3,273,767 $4,755,985 

 $/ton of SO2 removed compared to historical $249 $960 $1,271 

 Incr. $/ton of SO2 removed $249 $1,027 $4,495

* Modeled rate is the rate used by UNC in their historical modeling. Other historical rates are from AbitibiBowater BART study and may be 

more representative of average rate for the purpose of estimating cost effectiveness in $/ton removed

2.2.3.4 PM Control Options Analysis 

The permitted PM emissions rate for Catalyst Paper is 0.1 lb/MMBtu; however, the recently 

proposed industrial boiler MACT has a PM emission limit of 0.044 lb/MMBtu. It is unclear if 

this will motivate the installation of a new FF system. Since boiler #2 has a hot-side ESP, 

upgrade of the ESP is not a likely an option. Therefore a FF is a viable option, and would 

ideally be installed downstream of a dry FGD system, or upstream of a wet FGD system; cost of 

the long ductwork that this will require has been included in the capital cost. The FF with the 

dry FGD program at the Greenidge plant was seen in tests to produce an emission rate of 

0.001 lb/MMBtu. Typical guarantee values might be in the range of 0.015 lb/MMBtu or less. 

An estimate of a dry FGD system was developed for estimating the cost of a system placed after 

the scrubbed and unscrubbed gas streams are joined and prior to the chimney. The estimated 

cost is shown in Table 27, as ~$21M to install a FF, which is about two-thirds the cost of a dry 

scrubber with FF. It should also be noted that when a dry scrubber is installed with FF for SO2

control, the PM control is a cobenefit of installing the dry scrubber. For this reason a DLS, as 

described in Table 26 would be very beneficial for both SO2 and PM control.
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 30 October 9, 2012

Table 27. Estimated Cost of a New Fabric Filter on Boiler #2 at Catalyst Paper

ACFM $408,300

Total Capital Requirement $21,413,481 

Annualized Capital $2,021,281 

Taxes, Admin, Insurance $856,539.25 

Maintenance $509,604 

Variable Operating Cost $427,038 

Total Cost $3,814,463 

Rated MMBtu/hr 1132

Modeled Rate, pph * 113

Current PM Rate, lb/MMBtu 0.1

 pph 113.2

 TPY 496

Rate with new FF, lb/MMBtu 0.015

 pph 16.98

 TPY 74

Percent Reduced 85%

Tons reduced per year 421

Total Annualized Cost $3,814,463 

$ per ton reduced $9,051 

* Modeled rate is the rate used by UNC in their historical modeling. Other historical rates are 

based on permit limit.

2.2.3.4.1 Energy and Environmental Impacts 

A new FF will require an additional booster fan and power, as well as compressed air, and the 

costs of these are included in the analysis. The new FF will also improve capture of mercury 

and other toxic materials.

2.2.3.5 Visibility Modeling

EPA reviewed the control options presented in Tables 24, 26 and 27, and provided a set of 

control technology combinations for Catalyst Paper Unit 2 for the visibility modeling. Table 28

provides the final list of eight control configurations used in the visibility modeling. They 

represent incremental controls on SO2 and NOx up to the maximum controls (Ctrl-7), and the 

impact of these when combined with a new fabric filter (Ctrl-8). To bracket the emission 

reductions achievable Ctrl-3 also examines the benefit of FF as the only control in effect. The 

emissions inputs for the modeling are discussed in Section 2.2.3.5.2.

Table 28. Control Scenarios Used in Catalyst Paper Visibility Modeling

$/year

S O2 + NOx + PM

Base 0 0 0 0 $0

Ctrl-1 DLS 3,412 0 0 3412 $8,204,221

Ctrl-2 Na Scrbr + upgrade 3,742 0 0 3742 $9,686,439

Ctrl-3 0 0 FF 422 422 $3,814,463

Ctrl-4 Na Scrbr + upgrade 3,742 LNB 1,636 0 5378 $9,967,145

Ctrl-5 Na Scrbr + upgrade 3,742 LNB + OFA 2,157 0 5899 $10,076,416

Ctrl-6 Na Scrbr + upgrade 3,742 LNB + OFA + SNCR 2,509 0 6251 $10,534,572

Ctrl-7 Na Scrbr + upgrade 3,742 LNB + OFA + SCR 3,124 0 6866 $14,100,483

Ctrl-8 Na Scrbr + upgrade 3,742 LNB + OFA + SCR 3,124 FF 422 7288 $17,914,946

PM -Emis 

(TPY)

Control

Unit 2

Control Option

Control Control D-Emis 

(TPY)

All Species

S O2 -Emis 

(TPY)

NOx -

Emis (TPY)
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 31 October 9, 2012

2.2.3.5.1 Stack Parameters

Stack parameters for Catalyst Paper Unit 2 and the stack elevations for all units were taken from 

the ADEQ BART report. All other parameters were taken from the NEI 2008 Version 2. In 

addition to the base case values for the stack parameters, Table 29 also includes the changes in 

stack temperature and exit velocity for the control cases involving scrubber installation, per the 

guidance of Table 26.

Table 29. Stack Parameters for Catalyst Paper Units 1-3

2.2.3.5.2 CALPUFF Emissions Inputs

Emission requirements for CALPUFF modeling were specified by the EPA, and are tabulated in 

Table B-1 of the modeling protocol submitted as a Task 5 deliverable, and in the master

spreadsheet documentation for this report, excerpted in Appendix A, Table A-3. We performed 

extensive QA of these inputs using customized scripts that we have developed. The following is 

a summary of the data sources and assumptions used in emission inputs for the CALPUFF 

modeling for Catalyst Paper:

 The NOx, SO2 and PM baseline emissions for the uncontrolled Unit 1 were calculated by

using their capacity heat inputs (472 MMBtu/hr and 315 MMBtu/hr respectively),

multiplied by their respective ADEQ permit emission limits (lb/MMBtu) as described in 

the Title V submittal. For Unit 3 EPA provided the permit emission limits.

 Unit 2 NOx, SO2 and PM baseline emissions were obtained from the WRAP BART 

analysis report of 200710.

o Unit 2 OFA with hot-side ESP and FGD; as an exact speciation profile match is not 

available in the NPS PM speciation spreadsheets, the PM speciation was specified as 

an average of the speciation profiles for a dry-bottom coal-fired boiler with ESP andFGD, and one with ESP (see 

http://www.nature.nps.gov/air/Permits/ect/docs/coalBoiler/2006FinalDryBottomPC_

FGD_ESPpmSpeciationProfile.xls and 

http://www.nature.nps.gov/air/Permits/ect/docs/coalBoiler/2006FinalDryBottomPC_

ESPpmSpeciationProfile.xls

o Units 1 and 3 used the speciation profile of an industrial residual oil boiler (see 

http://www.nature.nps.gov/air/Permits/ect/docs/oilBoiler/2006FinalUncontrolledInd

ustrialResOilBlrpmSpeciationProfile.xls).

 

10 Summary of WRAP RMC BART Modeling for Arizona, Draft #5, May 25, 2007. See 

http://pah.cert.ucr.edu/aqm/308/bart.shtml
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 32 October 9, 2012

The CALPUFF modeling and the post-processing of CALPUFF output files in POSTUTIL 

to provide concentration inputs to CALPOST followed the procedure described for Nelson 

Lime in Section 2.2.1.5.2.

2.2.3.5.3 CALPOST Setup

There are 12 CIAs within 300-km of Catalyst Paper; we followed the modeling protocol 

delivered with the Task 5 report in setting up the CALPOST inputs for each CIA using the 4 

visibility methods mentioned in the previous sections. Due to the large number of postprocessing runs required for the 8 control options for each of the 12 CIAs, we used customized 

scripts to set up the inputs and extensively QA them. 

2.2.3.5.4 Extraction of Visibility Results with POSTCALPOST

UNC extracted the results from the CALPOST visibility analysis for the four methods of 

calculating visibility using POSTCALPOST. The results for the 98th percentile incremental 

visibility impairment -dv relative to background visibility at the 12 CIAs listed in Table 1 

within 300-km of the Catalyst Paper Pulp Mill for each year modeled (2001-2003), and for the 

composite period are documented in the supporting spreadsheet documentation. The results in 

this report are from Method 6(a) and 8(b) for the composite period 2001-2003. Table 30

summarizes the incremental visibility impairment relative to background (22nd highest -dv, 

corresponding to the 98th percentile) at each CIA within 300 km of Catalyst Paper for the base 

case and controls scenarios from Methods 6(a) and Method 8(b).
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 33 October 9, 2012

Table 30. 98th Percentile Visibility Impairment (-dv) for Catalyst Paper Using 

(a) IMPROVE Method 6(a) and (b) Method 8(b)

(a)

(b)

In both methods the maximum visibility impairment occurs at Petrified Forest (pefo) NP. 

Greater visibility impairment is seen using Method 8(b) than with Method 6(a). On average, 

three out of 12 CIAs see a greater than 0.5-dv impairment with either method. As discussed in 

Section 2.2.3.4 the use of FF produces the least impairment, but SCR and SNCR also show 

strong reduction in the impairment at all CIAs relative to the base case.

Ctrl-2 with sodium scrubbers and a scrubber upgrade is seen to have worse impairment than the 

base case. An examination of this case found that the stack parameters could be incorrectly 

specified for Ctrl-2 and Ctrl-3. At the time of this reporting, the issue had not been resolved 

satisfactorily, and these two cases should be ignored pending a correction to these results.
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 34 October 9, 2012

Table 31. Visibility Benefits (dv) of Control Options for the 

Calculation Methods of Table 30

(a)

(b)

Table 31 summarizes the visibility benefits of these control options in dv relative to the base 

case for each of the visibility methods. Clearly SCR with FF, followed by SCR without FF and 

with the full complement of SO2 controls provide the greatest visibility benefits, and FF 

controls added to these other technologies show a greater than 0.5 dv benefit at 2 out of the 12 

CIAs (pefo, sian). Method 8 shows greater benefits compared to Method 6, both summed over 

all CIAs, and as a maximum at pefo. 

2.2.3.6 Control Effectiveness Results

This section summarizes the control effectiveness in $/dv (millions) for the control options 

modeled. Table 32 shows these results for each CIA and control option for the two calculation 

methods, and as before, Method 8(b) shows greater effectiveness (lower values) compared to 

Method 6(a). The effectiveness for the most advanced controls diminishes as the distance to the 

CIA increases. Petrified Forest benefits from the highest control effectiveness in almost all 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 35 October 9, 2012

scenarios, and due to the lower costs, the use of FF alone has the highest cost effectiveness of 

all control configurations, both when the dv impact of control is summed over all CIAs and 

when the maximum impact is used.

Table 32. Control Effectiveness (million $/dv) for the 

Calculation Methods of Table 30

(a)

(b)

These results are summarized in Table 33, and show the change in the effectiveness of certain 

technologies when considering all areas vs. the most impaired. It is clear that FF is the most 

cost-effective, even when used alone, due to the relative low cost compared to the visibility 

benefit; its effectiveness is greatly enhanced with post-combustion NOx controls (SCR). It is 

found to be the most effective technology whether the impact is the sum over all CIAs or at the 

most impaired CIA. Scrubbers are in general found to be least cost-effective unless combined 

with other technologies. The relative merits of these control technologies do not change 

significantly as the distance to the CIA increases.
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 36 October 9, 2012

Table 33. Control Effectiveness Summary (million $/dv) for the 

Calculation Methods of Table 30

(a)

(b)

2.3 Conclusions

The five-factor BART analysis of the three facilities Chemical Lime Nelson, Sundt Unit 4 and 

Catalyst Paper Pulp Mill led to the following conclusions:

 The visibility impacts are greatest for each facility at the nearest CIAs, and the control 

options are least effective (greatest in million $/dv) at the farthest ones. The CIAs which 

experience the greatest visibility impacts and show the greatest benefits due to controls 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 37 October 9, 2012

at the three facilities are, respectively, Grand Canyon, Saguaro and Petrified Forest. 

Sierra Ancha shows the least impact/benefit from control options at Nelson Lime, 

Mount Baldy, the least impacts due to Sundt, and Saguaro, the least impact from 

Catalyst Paper.

 The following are the technologies found to be most cost-effective at the highest impact 

CIA at each facility:

o SNCR (on both BART units) at Nelson Lime 

o SNCR, and SNCR in combination with DSI at Sundt Unit 4, followed by SCR 

with DSI

o Fabric filter at Catalyst Paper; however, its cost-effectiveness is somewhat 

diminished when used in combination with SCR despite the visibility benefit,

due to the relatively high cost of SCR.

 In the case of Nelson Lime and Sundt 4 the control effectiveness of SO2 controls such as 

wet and dry FGD is greater at the CIAs farther away from the source. NOx control 

technologies such as SCR and SNCR have a lot more effectiveness at nearby CIAs.

 FF is the most effective control technology available for Catalyst Paper. SCR and SNCR 

can be even more effective when combined with FF.

 Visibility Method 8(b) estimates greater impairment and shows greater benefits of 

control options in almost all case relative to Method 6(b).
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 38 October 9, 2012

References

ENSR, 2009: Revised BART Analysis for the Navajo Generating Station Units 1-3, ENSR 

Corporation, Document No. 05830-012-300, January 2009, Salt River Project – Navajo 

Generating Station, Tempe, AZ.

EPA, 2002: EPA Air Pollution Control Cost Manual (Sixth Edition), Report No. EPA/452/B02-001, U.S. Environmental Protection Agency. 

IL EPA, 2007: Technical Support Documentation for Control of Nitrogen Oxide Emissions 

from Lime Kilns”, June 2007, AQPSTR 07-04, Illinois Environmental Protection Agency.

Staudt, J., and C. Erickson, 2008: Selective Catalytic Reduction System Performance and 

Reliability Review. Presented at the 2008 International Power Generation Conference, 

December 2-4, 2008, Orlando, FL.

Western Regional Air Partnership (WRAP) Regional Modeling Center, 2006: 

CALMET/CALPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in 

the Western United States. Western Regional Air Partnership Air Quality Modeling Forum, 

Regional Modeling Center, August 15, 2006; 

http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf
Appendix A 

Emissions Data Tables
UNC-EMAQ 5-12-026.v1 A-2 October 9, 2012

This appendix provides the emissions data for CALPUFF modeling of the base case(s) and control scenarios analyzed for the three 

facilities. These data were extracted from a master spreadsheet that is being delivered as part of the documentation for this task. 

Table A-1(a). NOx, SO2 and PM Emission Inputs for Base and Control Scenarios for Nelson Lime Visibility Modeling 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 A-3 October 9, 2012

Table A-1(b). Speciated PM Emission Inputs for Base and Control Scenarios for Nelson Lime Visibility Modeling
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 A-4 October 9, 2012

Table A-2(a). NOx, SO2 and PM Emission Inputs for Base and Control Scenarios for Sundt Unit 4 Visibility Modeling 
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 A-5 October 9, 2012

Table A-2(b). Speciated PM Emission Inputs for Base and Control Scenarios for Sundt Unit 4 Visibility Modeling
EMAQ LOE (EPA Contract EP-D-07-102) WA 5-12: Task 7 Five-Factor BART Analysis Report

UNC-EMAQ 5-12-026.v1 A-6 October 9, 2012

Table A-3(a). NOx, SO2 and PM Emission Inputs for Base and Control Scenarios for Catalyst Paper Visibility Modeling 

Table A-3(b). Speciated PM Emission Inputs for Base and Control Scenarios for Catalyst Paper Visibility Modeling
Appendix B

Andover Technology Partners Report Chapter 3: 

BART Analysis (NOx, SO2 and PM)
3-1 www.AndoverTechnology.com

Chapter 3. BART Analysis (NOx, SO2 and PM)

Task 7: Determine BART Control Options (SO2, NOx, PM)

Under this task, Andover Technology Partners will conduct a full 5-factor BART analysis of all 

technically feasible control options for 

 Catalyst Paper, boiler #2

 Chemical Lime Company (Nelson Lime Plant), and

 Sundt (Unit 4).

Andover Technology Partners will review the submitted BART analysis from Catalyst Paper and 

Chemical Lime Company to evaluate if costs shown are permissible under BART guidance. 

Cost estimates performed in this section utilize methods consistent with the US EPA Control 

Cost Manual,11 cost estimating methods used in EPA’s latest Integrated Planning Model (IPM) 

methods12, and other reasonable engineering methods.

. 

 

11 EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B-02-001

12 Documentation of EPA IPM Base Case v4.10. http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation
3-2 www.AndoverTechnology.com

3.1 Catalyst Paper, Snowflake, AZ

Catalyst Paper operates a pulp mill in Snowflake, AZ that generates pulp from recycled 

newsprint and makes new newsprint, corrugated box, purchased pulp and other products. 

Three power boilers are operated on site. The power boilers are pictured in Figures 3-1 a and b 

and additional data is shown in Table 3-1. Boiler #2 is coal fired with a rated heat input of 1132 

million Btu/hr when firing coal. It may also fire residual oil. In January 2008 AbitibiBowater Inc. 

(then owner of the mill) submitted a BART analysis of the mill. This analysis examined methods 

for reducing NOx and SO2 at the mill.

Figures 3-1 a and b. The power boilers and coal pile at Catalyst Paper.

http://www.renegy.com/project_snowflake.html
3-3 www.AndoverTechnology.com

The following sections will comment on the BART analysis submitted by Abitibi Bowater in 

January 2008 and will make recommended BACT emissions rates and estimates of costs.

Table 3-1. Data for Catalyst paper

Data Element Data Source

Boiler Type (unit 2) Wall Fired BART Submittal

Boiler Heat Input Boiler 1: 523 MMBtu/hr with Nat Gas, 472 

MMBtu/hr with Oil

Boiler 2: 1132 MMBtu/hr with Coal, 1110 

MMBtu/hr with Oil

Boiler 3: 337 MMBtu/hr with Nat Gas, 315 

MMBtu/hr with Oil

Permit, page 45

Boiler Combustion Configuration

Existing NOx Controls Unit 3 has a low NOx burner listed in their 

permit, the other two have no NOx controls.

Permit

Current NOx Emission Rate 

(lbs/MMBtu)

Cap of 0.3 lb/MMBtu while burning oil in Unit 

2. Cap of 0.7 lb/MMBtu while burning coal in 

Unit 2.

Permit

Coal Type(s) Western Bituminous (Lee Ranch El Segundo) BART Submittal

Ash Content (%) 17.9 BART Submittal

Sulfur Content (%) 1.03 BART Submittal

Approx. Heating Value (btu/lb) 9290 BART Submittal

Additional Info on Emissions 

Controls

Slipstream Wet Alkaline Scrubber by Flakt (tray 

type) installed on Unit 2 1990 must run 100% 

of the time. Treats 43% of Unit 2 flue gas

Permit and EIA 

Form 860

SO2 Emission Rate Cap of 1.0 lb/MMBtu while burning oil for Units 

1&3, 

Cap of 0.8 lb/MMBtu while burning oil or coal 

for Unit 2

Permit

NOx Emission Rate (unit 2) 0.70 lb/MMBtu BART Submittal

PM Emission Rate Cap of 0.10 lb/MMBtu Permit

PM controls

- efficiency

- calculated emissions rate

- typical emissions rate

Hot Side ESP – no conditioning

99.2%

0.154 lb/MMBtu (from efficiency and fuel)

0.02 lb/MMBtu (from 2005 EIA form 767)

EIA Form 860, 767
3-4 www.AndoverTechnology.com

3.1.1 NOx Control

Available Technologies –

Technologies evaluated in the BART analysis for controlling NOx and the projected emissions 

reduction found in the BART analysis are shown in Table 3-2. In general this is a 

comprehensive list of available NOx controls for this type of boiler. There are no major control 

categories missing from this list. 

Feasible Technologies -

All of the technologies shown are feasible. The emissions targets developed by CH2MHill 

incorporate additional margin over that offered by the technology supplier that varies by 

technology type.

Table 3-2. Catalyst Paper Evaluated NOx Technologies for BART.

Evaluation of Technologies -

The capital and operating costs directly associated with the NOx control technology analysis 

were reviewed as well, along with energy and environmental impacts. These costs all appeared 

to be reasonable, with the exception of SCR catalyst replacement cost, which seemed high. For 

a boiler the size of Boiler 2 at catalyst paper, roughly 150 cubic meters of catalyst is expected 

(typically 1-1.5 cubic meters per 1000 MMBtu/hr). If half of that catalyst is replaced every two 

years, the cost is about 75 m3x $5000/m3 or $375,000 every two years, or under $200,000 per 

year. Regenerated catalyst would drop the cost of that by another 40% or so, to about 

$120,000/year. As a result, $200,000 per year for catalyst is a conservative estimate.

The capital recovery factor assumed by AbitibiBowater of 13.5% is roughly equivalent to the 

combination of debt service (7% over 20 years, or 9.44% annually) and taxes, insurance and 
3-5 www.AndoverTechnology.com

administrative costs, and the EPA Air Pollution Control Cost Manual suggests using 4% of 

capital cost.13 This results in 13.44% total annual cost.

Abitibi Bowater further assumed an additional indirect cost to NOx control. Abitibi Bowater 

assumed that with NOx control all fly ash would be disposed of rather than sold. This 

assumption regarding the impact of NOx controls on fly ash is likely overstated, and ADEQ had 

asked Abitibi Bowater to provide supporting information. Abitibi Bowater provided supporting 

information on their fly ash purchase agreement, but this did not address why they assumed 

that all fly would be unmarketable.

NOx controls do have a potential impact, but the negative impact is by no means certain. 

Modern burners have the benefit of much more advanced design methods than those used in 

original equipment and may even improve (reduce) carbon levels in fly ash while reducing NOx. 

In cases where carbon levels do increase they can be mitigated by adjusting excess air levels if 

it does become a problem. Increasing excess air levels, however, will have an impact on NOx 

reduction. SNCR and SCR technologies also have the potential to result in ammonia on fly ash, 

which may impact fly ash sales; however, this is dependent upon the coal fly ash pH and other 

factors. Ammonia slip can generally be controlled to levels that do not impact fly ash. EPRI 

performed a study in 2007 that examined the effects of ammonia slip from SCR systems and 

reached the conclusion that “The survey overwhelmingly indicated that ammonia contamination 

is not impacting the ability of plants to sell ash”. 14

For the purpose of this BART analysis, the additional margin on NOx emission reduction 

assumed by Abitibi Bowater’s consulting engineer is assumed to provide adequate margin to 

allow for the possibility of operating at a higher NOx level than guaranteed by the supplier and 

for the likelihood of not having an impact on fly ash sales.

The costs from Abitibi Bowater’s BART analysis were considered reasonable with the exception 

of the estimated impacts on fly ash. The costs from the BART analysis are shown in Table 3-3 

with the exception that the cost assigned to fly ash impacts from the NOx control are not 

included in the total cost and the estimate of cost in $/ton of NOx removed. Another difference 

is the assumed capital recovery rate is 9.4% (consistent with 7% interest over 20 years) and 

there is an additional 4% for taxes, admin, and insurance (per the EPA air pollution control cost 

manual. The estimated $/ton of NOx removed is lower than what was estimated by Abitibi 

Bowater’s consultant, largely because of the difference in the way fly ash effects were 

addressed.

For the purpose of modeling, Cases 3 and 4 of Table 3-3 can be ignored since they would not 

be selected on the basis of cost.

Energy and Environmental Impacts –

Energy impacts are evaluated and the cost shown as increased electrical load.

 

13 EPA Air Pollution Control Cost Manual, Sixth Ed., 2002, Sect. 2.5.5.8, pp. 2-34

14 http://my.epri.com/portal/server.pt?Abstract_id=000000000001014269
3-6 www.AndoverTechnology.com

Environmental impacts of the combustion controls are potential impact to fly ash; however, the 

original assumption made by Abitibi Bowater’s consultant that all of the fly ash would be 

impacted is a worst case. In fact, many electric utility boilers firing many types of coals have 

combustion NOx controls and sell fly ash. Therefore, this assumption is overstated and is 

ignored in this case.

Table 3-3. Catalyst Paper – NOx Control Costs, excluding impact on fly ash

Case # 1 2 3 4 5 6 7

NOx Control OFA with 

Existing 

Fan

LNB MOBOTEC 

ROFA

MOBOTEC 

ROFA and 

Rotamix 

SNCR

LNB w/OFA

LNB wOFA 

and HERT 

SNCR

LNB with OFA 

and SCR

Heat Input Rate, 

MMBtu/hr

1132 1132 1132 1132 1132 1132 1132

Capacity Factor 100% 100% 100% 100% 100% 100% 100%

Heat Value, Bu/lb 9,290 9,290 9,290 9,290 9,290 9,290 9,290

Historical Emissions Rate

Modeled Rate, 

pph*

914 914 914 914 914 914 914

NOx (lb/MMBtu) 0.7 0.7 0.7 0.7 0.7 0.7 0.7

NOx, pph 792 792 792 792 792 792 792

NOx, TPY 3,471 3,471 3,471 3,471 3,471 3,471 3,471

Controlled Emissions Rate

NOx (lb/MMBtu) 0.525 0.37 0.348 0.291 0.265 0.194 0.07

NOx, pph 594 419 394 329 300 220 79

NOx, TPY 2,603 1,835 1,725 1,443 1,314 962 347

NOx, Removed, 

TPY

868 1,636 1,745 2,028 2,157 2,509 3,124

Percent Removed 25% 47% 50% 58% 62% 72% 90%

Total Installed 

Cost

$20,000 $1,462,020 $4,536,126 $5,964,840 $2,088,600 $2,792,400 $22,950,507 

Fixed O&M $25,740 $84,221 $207,185 $228,616 $109,284 $119,841 $137,689 

Non Fuel Var O&M $1,802 $1,802 $468,389 

Make Up Water $4,322 $499 $246,973 

Urea/Ammonia $416,723 $347,240 $87,485 

SCR Catalyst $200,000 

Elect. Load $74,685 $323,637 $327,109 $3,472 $189,122 

Annualized Capital $1,888 $138,004 $428,178 $563,039 $197,149 $263,583 $2,166,366 

Taxes, Admin, 

Insurance

$800 $58,481 $181,445 $238,594 $83,544 $111,696 $918,020 

Net Cost $103,113 $280,706 $1,140,445 $1,780,204 $389,977 $848,133 $4,414,044 

$/ton NOx $119 $172 $653 $878 $181 $338 $1,413 

Incremental 

$/ton NOx $119 $231 $7,882 $2,264 ($10,784) $1,301 $5,800 

* Modeled rate is the rate used by UNC in their historical modeling. Other historical rates are from AbitibiBowater BART study and 

may be more representative of average rate for the purpose of estimating cost effectiveness in $/ton removed.
3-7 www.AndoverTechnology.com

3.1.2 SO2 Control

Available TechnologiesThe Abitibi Bowater BART analysis also included evaluation of SO2 control technologies. 

In this case only two options were considered in their analysis, upgrade of the existing caustic 

wet scrubber (which only treats up to 43% of the flue gas as needed to remain below the 

permitted limit of 0.8 lb/MMBtu), and addition of a second sodium wet FGD system that would 

allow treatment of 100% of the flue gas, as shown in Table 3-4. This is not a comprehensive list 

of possible control options. Other control options include dry FGD, which would offer the 

advantages of reduced water consumption, lower operating costs due to less expensive lime 

reagent and much less costly disposal of waste, much lower PM emissions, and elimination of 

liquid waste; however, it would not provide the same level of SO2 removal and would have a 

higher capital cost than the wet scrubber option that Abitibi Bowater evaluated. Use of the dry 

scrubber would also continue to allow segregation of fly ash with the hot side ESPs for sale into 

the concrete market. Another available technology is lower sulfur coal.

Feasible Technologies –

All of the available technologies are also feasible.

Evaluation of Technologies -

A rough, order of magnitude estimate of the cost of a dry FGD system was developed by 

scaling the published cost information on the Turbosorp dry scrubber installed at the Greenidge 

power plant, and this is provided in an Excel workbook.

Table 3-5 compares control costs for available and feasible control technologies. Total 

costs are shown as well as costs relative to historical costs. The costs relative to historical 

costs and emissions reductions versus historical emissions are used in the $/ton of SO2

removed calculation.

Energy Impacts

Each of the methods has significant energy load, and the cost of this is estimated.

Environmental Impacts

Both wet scrubber options produce subtantial amounts of liquid waste that must be 

disposed of. The dry scrubber produces a stable, dry product that is readily disposed of. The 

dry scrubber will also significantly reduce PM emissions.
3-8 www.AndoverTechnology.com

Table 3-4. Catalyst Paper SO2 Technologies evaluated by Abitibi Bowater for BART

Table 3-5. SO2 Control Costs and Performance at Catalyst Paper

Catalyst Paper

Case Case Case Case Case

Historical 1 Historical 2 1 2 3

SO2 Control Scrubber Upgrade

Replace with 

new Dry Lime 

Scrubber

Add'l Sodium 

Scrubber and 

Upgraded 

Scrubber

Heat Input Rate, MMBtu/hr 1132 1132 1132 1132 1132

Capacity Factor 100% 100% 100% 100% 100%

Heat Value, Bu/lb 9,290 9,290 9,290 9,290

Coal Sulfur, % 1.03% 1.03% 1.03% 1.03%

Uncontrolled SO2, lb/MMBtu 2.22 2.22 2.22 2.22

Uncontrolled Annual SO2 

Emissions, tons

10,994 10,994 10,994 10,994

Historical Emissions Rate

Modeled Rate, pph * 555 555 555 555 555

SO2 (lb/MMBtu) 0.799 0.799 0.799 0.799 0.799

SO2, pph 904 904 904 904 904

SO2, TPY 3,962 3,962 3,962 3,962 3,962

Controlled Emissions Rate

SO2 (lb/MMBtu) 0.80 0.80 0.74 0.111 0.04

SO2, pph 904 904 837 126 50

SO2, TPY 3,962 3,962 3664 550 220

SO2 Removed, TPY 0 0 298 3,412 3,742

Percent Removed from 

historical 0 0 7.5% 86.1% 94.5%

% change in stack velocity none none None -10% -20%

Exit temp No change No change No change 175 F 130 F

Impact on PM speciation? none none none Yes – add FF Yes -all gas 

scrubbed

Total Installed Cost $650,000 $32,949,187 $15,650,000 

 Fixed O&M $60,665 $60,665 $60,665 $1,123,555 $90,998 

Non Fuel Var O&M $42,102 $42,102 $42,102 $236,704 $84,204 

Make Up Water $47,801 $115,960 $102,767 $15,780 $170,530 

Reagent $691,653 $2,308,793 $2,308,793 $2,278,391 $3,395,285 

Scrubber Waste Disposal $937,462 $3,129,323 $3,129,323 $669,604 $4,601,946 

Fly Ash Disp/Lost Ash ($889,759) ($1,400,085) ($1,400,085) ($1,400,085) ($1,400,085)

Elect. Load $673,696 $673,696 $673,696 $852,134 $640,312 

Annualized Capital $0 $0 $61,355 $3,110,170 $1,477,249 

Taxes, Admin, Insurance $0 $0 $26,000 $1,317,967 $626,000 

Annual Cost, incl ash $1,563,620 $4,930,454 $5,004,616 $8,204,221 $9,686,439 

Cost of Control (note – fuel costs are not shown, all control estimates assume the same fuel as Historical 2)

Net Cost, $/yr, greater than Historical 2 $74,162 $3,273,767 $4,755,985 

 $/ton of SO2 removed compared to historical $249 $960 $1,271 

 Incr. $/ton of SO2 removed $249 $1,027 $4,495

* Modeled rate is the rate used by UNC in their historical modeling. Other historical rates are from AbitibiBowater BART study and may be 

more representative of average rate for the purpose of estimating cost effectiveness in $/ton removed
3-9 www.AndoverTechnology.com

3.1.3 PM Emissions

The permitted PM emissions rate is 0.1 lb/MMBtu; however, the recently proposed industrial 

boiler MACT has a PM emission limit of 0.044 lb/MMBtu. It is unclear if this will motivate the 

installation of a fabric filter system. Since boiler 2 has a hot-side ESP, upgrade of the ESP is 

not likely an option. Therefore a fabric filter is a viable option that would ideally be installed 

downstream of a dry FGD system or upstream of a wet FGD system (in the capital cost, long 

ductwork has been priced in). The fabric filter with the dry FGD program at the Greenidge plant 

tested to produce an emissions rate of 0.001 lb/MMBtu. Typical guarantee values might be in 

the range of 0.015 lb/MMBtu or less. An estimate of a dry FGD system was developed for the 

purpose of estimating the cost of a system placed after the scrubbed and unscrubbed gas 

streams are joined and prior to the chimney. The estimated cost is shown in Table 3-6, or 

roughly $21 million to install a fabric filter, or roughly two-thirds the cost of a dry scrubber with a 

fabric filter. It should also be considered that when a dry scrubber is installed, including a fabric 

filter, for SO2 control, the PM control is a cobenefit of installing the dry scrubber. For this reason 

a dry scrubber, as described in Table 3-5, would be very beneficial for both SO2 and PM control.

Table 3-6. Estimated cost of new fabric filter on boiler 2

ACFM 408,300

Total Capital Requirement $21,413,481 

Annualized Capital $2,021,281 

Taxes, Admin, Insurance $856,539.25 

maintenance $509,604 

Variable Operating Cost $427,038 

Total Cost $3,814,463 

Rated MMBtu/hr 1132

Modeled Rate, pph * 113

Current PM Rate, lb/MMBtu 0.1

 pph 113.2

 TPY 496

Rate with new FF, lb/MMBtu 0.015

 pph 16.98

 TPY 74

Percent Reduced 85%

Tons reduced per year 421

Total Annualized Cost $3,814,463 

$ per ton reduced $9,051 

* Modeled rate is the rate used by UNC in their historical modeling. Other historical rates are 

based on permit limit.

Energy and Environmental Impacts

The fabric filter will require an additional booster fan and power, as well as compressed air, and the costs 

of these are porvided for. The fabric filter will also improve capture of mercury and other toxic materials.
3-10 www.AndoverTechnology.com

3.2 Nelson Lime Plant

Nelson lime plant, pictured in Figure 3-2, has two preheater rotary kilns, rated at 859 and 1,145 

tons per day, respectively. The facilities have no additional controls beyond PM controls (both 

have baghouses, with kiln 1 a more recently installed baghouse). 15 Emission rates from the 

Chemical Lime BART study are shown in Table 3-7. Each kiln emits through a separate 

chimney. 

Figure 3-2. Nelson Lime Plant

Table 3-7. Emissions and Emission Controls at Nelson Lime Plant

Nelson Kiln 1 Nelson Kiln 2 Info. Source

Maximum daily production, tons/day 859 1,145 Nelson 

BART 

Submittal

Emission Factors, lb/ton of product (lb/hr)

NOx 2.66 (95) 2.08 (99)

SO2 3.29 (118) 7.87 (375)

PM10 0.0423 (1.51) 0.0702 (3.35)

Controls Baghouse Baghouse, 

Multicyclone

Permit

 

15 BART Applicability Modeling Analysis, Chemical Lime Company, Nelson, AZ , September 2007
3-11 www.AndoverTechnology.com

3.2.1 NOx Emissions and Controls

Fuel fired at the plant is coal. The coal contributes to NOx emissions formed from combustion. 

It is unclear if any NOx controls are installed, and for the purpose of this study it will be assumed 

that none are installed. 

Available Technologies –

Table 3-8 shows technologies available for control of NOx from kilns and the expected percent 

reduction. As shown, NOx reductions are possible through combustion controls or possibly 

through post-combustion controls. This table is developed from data applicable to Portland 

Cement kilns.

Besides low NOx burners, mid kiln firing, mixing air technology SNCR and SCR are possible 

technologies. These technologies can be combined for higher NOx reduction than possible 

using one technology alone. Because the two Nelson plant kilns are preheater kilns, the most 

likely location for SNCR reagent injection is the preheater, where there is likely to be an 

available temperature window. To be conservative, when combined with other technologies, it 

is assumed that SNCR provides 30% reduction rather than 50% reduction.

Feasible Technologies –

All of the technologies listed in Table 3-8 are potentially feasible; however, since SCR has no 

known experience on lime kilns and very limited experience with cement kilns, it will be 

regarded as not feasible and will not be evaluated further. Also, since Mid Kiln Firing with tires 

may not be an option for lime kilns and the capital cost is much higher than some of the other 

combustion controls, it is not likely to be as economical as some of the other controls and will 

not be evaluated further. MAT will produce NOx reductions, but also reduces SO2 emissions by 

promoting formation of gypsum in the product, which may be undesireable. So, MAT may be 

attractive from the perspective of emissions reduction but unattractive for other reasons.

TABLE 3-8: NOx Emissions Reduction from Rotary Kilns with

Various NOx Control Technologies16

NOx Control Technology Expected NOx Emissions Reduction (%)

Low - NOx Burner (LNB) 30

Mid - Kiln Firing 30

Mixing Air Technology (MAT)17 30

SNCR-Urea 50

SNCR-Ammonia 50

SCR 80

 

16 “TECHNICAL SUPPORT DOCUMENT For CONTROL OF NITROGEN OXIDE EMISSIONS From Lime Kilns” 

AQPSTR 07-04, June 2007, ILLINOIS ENVIRONMENTAL PROTECTION AGENCY

17 http://www.cadencerecycling.com/papersbrochures.html
3-12 www.AndoverTechnology.com

Evaluation of Technologies -

There is limited data on cost for NOx controls for lime kilns, and much is derived from data for 

cement kilns. In this case cost information developed for EPA’s Industrial Sector Integrated 

Solutions (ISIS) model will be used where applicable. 18

Tables 3-9a and b show the results of comparison of NOx emissions for the two Nelson kilns 

using feasible technologies. To be conservative from the perspective of cost, it was assumed 

that LNB would be deployed in lieu of MAT to achieve 30% NOx reduction. Use of MAT rather 

than LNB would be less expensive, but increased gypsum in the product from SO2 capture 

might be undesireable. In the case of SNCR, it is assumed that it achieves 50% reduction from 

uncontrolled levels and when combined with LNB will provide an additional 30% reduction after 

LNB has reduced NOx by 30% for a total of 51% reduction. In either case, 50% reduction 

should be achievable and the costs shown in Tables 3-9a and b should be conservatively high.

Table 3-9a. NOx Control Technologies for the Nelson Lime Kiln 1

Nelson Kiln 1

LNB SNCR LNB and 

SNCR

TPD Lime 859 859 859

Uncontrolled emissions

Uncontrolled NOx, lb/ton 2.66 2.66 2.66

PPH NOx 95 95 95

TPY NOx (90% capacity factor) 375 375 375

Controlled Emissions

Reduction 30% 50% 51%

Controlled NOx, lb/ton 1.86 1.33 1.30

PPH NOx 67 48 47

TPY NOx (90% capacity factor) 263 188 184

Control Costs

Capital Cost $2,389,443 $679,055 $3,068,499

Total Annualized Cost $396,129 $216,179 $597,335

$/ton removed $3,518 $1,152 $3,121

incremental, $/ton removed $3,518 -$2,397* $2,553*

*incremental cost compared to cost of LNB with 30% reduction since both of 

these provide roughly the same total NOx reduction

 

18 Memo from J. Staudt to R. Strivastava, et. al., regarding “Costs and Performance of Controls – revised from 

comments”, March 10, 2009 (part of ISIS development data)
3-13 www.AndoverTechnology.com

Energy and Environmental Impacts

These technologies will have a very modest energy impact, requiring some additional auxiliary 

electrical load.

SNCR has the potential for ammonia slip emissions. However, experience with cement kilns 

has demonstrated that these are generally well controlled.

Table 3-9b. NOx Control Technologies for the Nelson Lime Kiln 2

Nelson Kiln 2

LNB SNCR LNB and 

SNCR

TPD Lime 1,145 1,145 1,145

Uncontrolled emissions

Uncontrolled NOx, lb/ton 2.08 2.08 2.08

PPH NOx 99 99 99

TPY NOx (90% capacity factor) 391 391 391

Controlled Emissions

Reduction 30% 50% 51%

Controlled NOx, lb/ton 1.46 1.04 1.02

PPH NOx 69 50 49

TPY NOx (90% capacity factor) 274 196 192

Control Costs

Capital Cost $2,857,256 $806,849 $3,664,105

Total Annualized Cost $459,000 $235,465 $678,858

$/ton removed $3,911 $1,204 $3,403

incremental, $/ton removed $3,911 -$2,857* $2,676*

*incremental cost compared to cost of LNB with 30% reduction since both of 

these provide roughly the same total NOx reduction
3-14 www.AndoverTechnology.com

3.2.2 SO2 Emissions

SO2 emissions from cement kilns are primarily from raw materials (limestone) rather than coal 

because most SO2 from fuel combustion is captured in the kiln and ends up in the product. 

However, for lime kilns, that try to avoid having sulfur in the product, fuel sulfur is more likely to 

be emitted in the form of SO2 than for a cement kiln. Changing raw material sources is 

generally not possible. Therefore, “add on” controls are likely to be necessary to reduce SO2

emissions.

Available Technologies

Table 3-10 shows available technologies. As discussed earlier, mixing air technology may 

actually reduce SO2 somewhat. Because this increases the gypsum loading in the product 

somewhat, it is unclear if this would be deployed for a lime kiln.

Table 3-10 Available SO2 Controls

Technology Percent Removal

Mixing Air (MAT) Varies: assume about 30%

Dry Lime Injection About 50% 

Dry Sorbent Injection (DSI) using SBC 75% 

Dry FGD 90-95%

Wet FGD 95%

Feasible Technologies.

All of the technologies are potentially feasible. Because a fabric filter is already installed on 

each kiln, a dry sorbent injection system would likely be very effective. Lime and sodium 

bicarbonate (SBC) are potential DSI reagents, as is trona; however, SBC is preferable for SO2 

capture. In practice, L’Hoist, the owner of the Nelson Plant, may choose to use a highly 

activated lime hydrate that they manufacture in place of SBC that is capable of similar removal 

rates as SBC. Nevertheless, DSI using SBC provides a reasonable estimate of cost for DSI 

using activated lime hydrate. Dry FGD is iikely to require a second baghouse because there 

does not appear to be room to install an absorber between the preheater and the fabric filter, 

particularly for kiln 2, and in any event, there may not be adequate space under the existing 

baghouses for air slides or recycle systems that would be used on a dry scrubber. Regardless, 

a dry FGD would provide similar SO2 removal as a wet FGD. So, a wet limestone FGD will be 

evaluated as a conservative approach. Wet lime or limestone FGD is feasible, and would be 

installed downstream of the existing baghouse.

Evaluate Technologies

Table 3-11 shows the estimated costs and emission rates for the three technologies evaluated 

for the two kilns. The DSI with SBC appears to have lower cost and higher reduction than dry 

lime injection. This is largely the result of the higher waste disposal costs associated with the 
3-15 www.AndoverTechnology.com

higher material input for the DLI. This analysis does not factor in any difference in disposal cost 

per ton of waste for dry lime versus SBC. Not addressed in this analysis are modifications to 

baghouse operation that may be necessary as a result of installing a DSI system. The wet 

scrubber has the highest removal, but also the highest cost. The SO2 reductions possible with 

MAT will vary.

The wet FGD capital cost shown here may be too high. Unfortunately, there is very limted data 

available. Costs were developed from informaiton on wet FGD costs for cement kilns, which in 

itself is rather limited. Very few cement kilns are equipped with wet scrubbers. So, most cost 

information has been gleened from BACT analyses as described in supporting documentation 

for ISIS.19

Table 3-11 Evaluation of SO2 Controls

Nelson 1 Nelson 2

MAT Dry Lime DSI with 

SBC Wet FGD MAT Dry Lime DSI with SBC Wet FGD

Historical SO2, lb/ton 3.29 3.29 3.29 3.29 7.87 7.87 7.87 7.87

Historical SO2, pph 118 118 118 118 375 375 375 375

Percent Removal 30% 50% 75% 95% 30% 50% 75% 95%

Outlet SO2, pph 82.4 58.9 29.4 5.9 262.5 187.5 93.8 18.8

Outlet SO2, lb/ton 2.30 1.65 0.82 0.16 5.51 3.94 1.97 0.39

% change in stack 

Velocity

No 

Change

No 

Change

No 

Change -20% No Change No Change No Change -20%

Exit temp No 

Change

No 

Change

No 

Change 130 F No Change No Change No Change 130 F

Impact on PM 

speciation

No 

Change

No 

Change

No 

Change

Yes

FF plus 

scrubber

No 

Change No Change No Change

Yes, FF 

plus 

scrubber

Capital Cost $754,196 $770,000 $409,382 8,082,077 $807,040 $1,940,000 $1,034,122 10,772,967

Annualized Costs $176,364 $545,415 $389,957 $1,369,380 $183,466 $1,502,933 $1,040,460 $1,958,408

TPY removed (90% 

capacity factor) 139 232 348 441 443 739 1109 1404

$/ton removed $1,266 $2,350 $1,120 $3,105 $414 $2,033 $938 $1,395 

Incremental $/ton $1,266 $3,975 ($1,340) $10,550 $414 $4,463 ($1,251) $3,105 

3.2.3 PM Emissions

The Nelson Plant already has fabric filters installed on both kilns. As a result there is no 

additional technology available that provides a higher degree of PM reduction than what is 

already installed.

 

19 Memo from J. Staudt to R. Srivastava , E. Torrez, K. Barnett, Re: Wet Scrubber Cost Algorithms, Feb 26, 2010
3-16 www.AndoverTechnology.com

3.3 H. Wilson Sundt Power Plant

H. Wilson Sundt (Sundt) unit 4 requires a BART analysis, and it is the unit that is located at the 

bottom of Figure 3-3. Table 3-12 shows the modeled and reported data for Sundt unit 4. 2008-

2010 data was averaged and 2011 data is the average over that year. Capacity factor is 

determined by dividing total reported heat input by the potential heat input if the unit were 

operating at 100% capacity 365 days a year. Capacity factor is important in performing cost 

effectiveness calculations.

Sundt 4 is coal fired. Sundt Unit 4 is also equipped with a fabric filter, low NOx burners and 

overfire air. 

Figure 3-3. Sundt Power Plant.

Table 3-12. Sundt Power Plant Data

Unit Capacity

Fuel

2008-2010 

Reported Avg

2011 Reported 

Rates

2008-

2011

NOx SO2 NOx SO2

Capacity

Factor

MW gross lb/MMBtu lb/MMBtu %

Unit 4 173.3 Coal 0.361 0.477 0.445 0.729 37%
3-17 www.AndoverTechnology.com

3.3.1 NOx Control

Available Controls

Available controls include combustion controls and post-combustion controls.

Feasible Controls

Because Sundt 4 already has combustion controls, the focus will be post-combustion controls.

Evaluation of NOx Controls

Sundt 4 is reported to already have low NOx burners and Overfire Air, and emissions rates are 

consistent with that level of control for a wall fired boiler. Therefore, only post-combustion 

controls are examined, although some advanced forms of OFA may permit further reductions. 

Results are shown in Table 3-13.

For the purpose of cost estimation, baseline emissions and capacity factors for all electric utility 

units were developed from historical data in this manner.

 Capacity factor will be the average of that estimated for the period 2008-2011 using 

reported heat input and plant capacity information.

 NOx and SO2 emission rates were examined for the average period of 2008-2010 and 

2011. In the case of Sundt Unit 4, the 2011 rate was selected as the baseline rate for 

estimating cost effectiveness.

Also, a capital recovery factor of 9.44% (equal to 7% over 20 years) plus tax and insurance 

costs of 1.2% were assumed in the cost analysis. This charge rate for taxes and insurance 

differs from what is used for industrial sources per the EPA Air Pollution Control Cost Manual 

and is consistent with what has been determined for electric generating units per the Integrated 

Planning Model documentation. 20

Energy Effects

SNCR has negligible energy impact. SCR will incur an additional parasitic loss, mainly due to 

pressure drop across the SCR system, that is roughly equal to 0.59% of output. Although this is 

not treated as a cost in the IPM calculations that these algorithms were developed for, rather as 

a reduction in capacity, it has been treated as an increase in variable operating cost for these 

calculations.

 

20 From Integrated Planning Model ver 4.10 documentation, page 8-11. 0.30% for insurance and 0.90% for taxes.
3-18 www.AndoverTechnology.com

Environmental Impacts

Environmental impacts of SNCR and SCR are primarily due to ammonia slip. The main 

environmental concern is regarding fly ash odor and potential impact on fly ash sales/disposal. 

Generally, ammonia slip can be well controlled from both of these technologies so that fly ash is 

not adversely impacted.

SCR catalyst can be recycled and therefore is not a significant concern. 

Table 3-13. NOx Control for Sundt 4

Sundt 4 - NOx

SNCR SCR

Capacity Factor 37% 37%

Control Efficiency 30% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 813 813

NOx Rate (lb/MMBtu) 0.445 0.445

NOx (TPY) 1318 1318

Controlled Rate

NOx Rate (lb/hr) 569 91

NOx Rate (lb/MMBtu) 0.31 0.05

NOx (TPY) 923 148

Tons/Year Removed 395 1,170

Total Cost, $/year $1,308,000 $5,712,715

$/Ton $3,307 $4,882

$/Ton (incremental) $3,307 $5,686

* SCR is actually capable of 90% removal. The model that we used set a lower 

limit of 0.05 lb/MMBtu, but lower NOx levels should be achievable
3-19 www.AndoverTechnology.com

3.3.2 SO2 Control

SO2 emission rates increased in 2011 from the 2008-2010 average, indicating a change in coal. 

Available Technologies

Available Technologies for Sundt 4 include dry sorbent injection, wet FGD and dry FGD. Sundt 

could also change to lower sulfur coal.

Feasible Technologies

All of the above available technologies are also feasible. In fact, since Sundt 4 has a fabric 

filter, dry sorbent injection may be well suited to this unit. A dry FGD is assumed at Sundt 4 to 

include a new fabric filter since there likely is not enough space to install a new absorber 

between the boiler and the existing fabric filter. A wet FGD would be installed downstream of 

the existing fabric filter.

Evaluation of Technologies

A change in coal was not evaluated for cost since coal cost data was not available.

Table 3-14 shows the estimated cost of each of the SO2 control technologies. In light of the low 

capacity factor at Sundt 4 and the high capital costs of FGD, the two FGD approaches are 

significantly more expensive (on a $/ton of SO2 removed basis), than DSI. DSI is expected to 

deliver high removal efficiencies due to the fabric filter.

The FGD removal efficiencies are limited by assumptions in the Sargent & Lundy model 

developed for EPA’s Clean Air Markets Division that was used for the FGD cost analysis. In 

practice, we would expect both dry and wet FGD to achieve somewhat lower emissions levels 

(and higher capture efficiencies). In this respect these results are conservative.

Energy Impacts

The energy impacts of dry sorbent injection are small. FGD will have significant energy impacts 

(over 1% of output) due to pressure loss across the FGD system and due to additional pumping 

power and other auxiliary loads. In all cases energy costs are included in the results of Table 3-

14.

Environmental Impacts

DSI using trona or sodium bicarbonate will result in increased solids collected by the fabric filter. 

These sodium based materials may result in a by-product with a water soluble component that 

may require some stabilization. Activated lime hydrate, if used, might avoid that issue. DSI has 

other benefits to air emissions as described in Section 2.1.2.

Both the wet and dry scrubbers will have a by-product. The dry scrubber by product is stable

and can be landfilled. The wet scrubber waste can be dewatered and sold to the gypsum 

market. More information is available in Section 2.1.2.
3-20 www.AndoverTechnology.com

Table 3-14. SO2 Control for Sundt 4

Sundt 4 – SO2

DSI Dry FGD Wet FGD

Capacity Factor 37% 37% 37%

Control Efficiency 75% 89% 92%

Uncontrolled Rate

SO2 Rate (lb/hr) 1333 1333 1333

SO2 Rate (lb/MMBtu) 0.729 0.729 0.729

SO2 (TPY) 2160 2160 2160

Controlled Rate

SO2 Rate (lb/hr) 333 146 110

SO2 Rate (lb/MMBtu) 0.18 0.08 0.06

SO2 (TPY) 540 237 178

Tons/Year Removed 1620 1923 1982

% change stack velocity No Change -10% -20%

Exit temp No Change 175 F 130 F

Impact on PM speciation No Change Yes, FGD plus FF Yes, FGD plus FF 

Total Cost, $/year $2,967,501 $12,553,539 $13,986,681

$/Ton $1,832 $6,529 $7,057

$/Ton (incremental) $1,832 $31,647 $24,189

3.3.3 PM Control

Sundt 4 is equipped with a fabric filter, and there is no technology available that would provide a 

higher degree of PM reduction than a properly designed and operated fabric filter. Therefore, 

there are no changes to PM emission rates under the BART analysis.