Portland General Electric 

Boardman Plant 

Best Available Retrofit Technology (BART) Analysis 

Black & Veatch Project: 144449 

Black & Veatch File No.: 40.0000 

November 2, 2007 
Boardman Plant Contents 

110207 TC-1 

Contents 

Acronym List ................................................................................................................AL-1 

Executive Summary.......................................................................................................ES-1 

1.0 Introduction and Objectives................................................................................. 1-1 

1.1 Source Description and Background ....................................................... 1-1 

1.2 BART Analysis Methodology ................................................................. 1-3 

1.2.1 Identify All Available Retrofit Control Technologies 

(Step 1) ...................................................................................... 1-4 

1.2.2 Eliminate Technically Infeasible Options (Step 2) ................... 1-4 

1.2.3 Evaluate Control Effectiveness of Remaining Control 

Technologies (Step 3)................................................................ 1-4 

1.2.4 Evaluate Impacts and Document the Results (Step 4)............... 1-5 

1.2.5 Evaluate Visibility Impacts (Step 5).......................................... 1-6 

1.2.6 Selecting the Best Alternative ................................................... 1-6 

2.0 Basis of Analysis.................................................................................................. 2-1 

2.1 Design Basis............................................................................................. 2-1 

2.2 Economic Data......................................................................................... 2-1 

2.2.1 Capital Cost Estimates............................................................... 2-1 

2.2.2 Annual Operating and Maintenance Cost Estimate................... 2-4 

2.3 Baseline Emissions .................................................................................. 2-7 

2.4 Project Assumptions ................................................................................ 2-7 

2.5 Modeling Baseline Conditions................................................................. 2-8 

3.0 Identification of All Available Retrofit Emission Control Technologies 

(Step 1)................................................................................................................. 3-1 

3.1 NOx Control Technologies....................................................................... 3-1 

3.1.1 Overfire Air System Operation ................................................. 3-1 

3.1.2 Upgraded Low NOx Burners ..................................................... 3-3 

3.1.3 Upgraded Low NOx Burners and Existing OFA System 

Operation ................................................................................... 3-4 

3.1.4 Upgraded Low NOx Burners and Existing OFA System 

Operation and Selective Non-Catalytic Reduction.................... 3-4 

3.1.5 New Low NOx Burners and Modified OFA System................. 3-5 

3.1.6 New Low NOx Burners, Modified OFA, and Selective 

Non-Catalytic Reduction........................................................... 3-5 
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110207 TC-2 

3.1.7 New Low NOx Burners, Modified OFA, and Selective 

Catalytic Reduction ................................................................... 3-6 

3.1.8 Selective Noncatalytic Reduction.............................................. 3-8 

3.1.9 SNCR/SCR Hybrid (Cascade)................................................. 3-10 

3.1.10 Mobotec ROFA and ROTAMIX............................................. 3-11 

3.1.11 NOxStar and NOxStar Plus ...................................................... 3-12 

3.1.12 ECOTUBE............................................................................... 3-12 

3.1.13 Induced Flue Gas Recirculation .............................................. 3-13 

3.1.14 LoTOx ..................................................................................... 3-14 

3.1.15 Natural Gas Reburn ................................................................. 3-14 

3.1.16 New LNBs, Modified OFA, and SNCR.................................. 3-15 

3.2 SO2 Control Technologies ..................................................................... 3-15 

3.2.1 Wet Flue Gas Desulfurization ................................................. 3-16 

3.2.2 Semi-Dry Flue Gas Desulfurization ........................................ 3-19 

3.2.3 Circulating Dry Scrubber ........................................................ 3-21 

3.2.4 Furnace/Duct Reagent Injection.............................................. 3-23 

3.3 PM Control Technologies...................................................................... 3-24 

3.3.1 Existing ESP with Operational Restrictions............................ 3-24 

3.3.2 Pulse Jet Fabric Filter .............................................................. 3-24 

3.3.3 Compact Hybrid Particulate Collector .................................... 3-26 

3.3.4 GE MAX-9 Hybrid.................................................................. 3-26 

3.3.5 Multiple-Cyclone Separators................................................... 3-28 

3.3.6 Wet ESP................................................................................... 3-29 

3.4 Emerging Pollution Control Technologies ............................................ 3-31 

3.4.1 PowerSpan............................................................................... 3-31 

3.4.2 Enviroscrub.............................................................................. 3-32 

3.4.3 Phenix Clean Coal ................................................................... 3-33 

3.4.4 J-Power ReACT System.......................................................... 3-35 

4.0 Technically Feasible Retrofit Emission Control Technologies (Step 2) ............. 4-1 

4.1 Technically Infeasible NOx Control Technologies.................................. 4-1 

4.1.1 Mobotec ROFA and ROTAMIX............................................... 4-1 

4.1.2 NOxStar and NOxStar Plus ........................................................ 4-1 

4.1.3 ECOTUBE................................................................................. 4-2 

4.1.4 Induced Flue Gas Recirculation ................................................ 4-2 

4.1.5 LoTOx ....................................................................................... 4-2 

4.1.6 Natural Gas Reburn ................................................................... 4-2 

4.1.7 SNCR/SCR Hybrid (Cascade)................................................... 4-2 

4.2 Technically Infeasible SO2 Control Technologies .................................. 4-3 
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4.2.1 Dry Flue Gas Desulfurization.................................................... 4-3 

4.2.2 Furnace/Duct Reagent Injection................................................ 4-3 

4.3 Technically Infeasible PM Control Technologies ................................... 4-3 

4.3.1 GE MAX-9 Hybrid.................................................................... 4-3 

4.3.2 Multiple-Cyclone Collector....................................................... 4-3 

4.4 Technically Infeasible Emerging Pollution Control Technologies.......... 4-3 

4.4.1 PowerSpan................................................................................. 4-3 

4.4.2 Enviroscrub................................................................................ 4-4 

4.4.3 Phenix CCS ............................................................................... 4-4 

4.4.4 J-Power ReACT System............................................................ 4-4 

4.5 Summary of Retrofit Emission Control Technologies Technical 

Feasibility................................................................................................. 4-4 

5.0 Evaluation of Technically Feasible Retrofit Emission Control 

Technologies (Step 3) .......................................................................................... 5-1 

5.1 Control Effectiveness............................................................................... 5-1 

6.0 Impact Analyses (Step 4)..................................................................................... 6-1 

6.1 Types of Impact Analyses........................................................................ 6-1 

6.2 Methods of Impact Analyses ................................................................... 6-1 

6.2.1 Costs of Compliance.................................................................. 6-2 

6.2.2 Energy Impacts.......................................................................... 6-2 

6.2.3 Non-Air Quality Environmental Impacts .................................. 6-2 

6.2.4 Remaining Useful Life .............................................................. 6-3 

6.3 Cost-Effectiveness ................................................................................... 6-4 

6.4 Impact Analyses Results.......................................................................... 6-4 

6.4.1 NOx Control Technologies ...................................................... 6-10 

6.4.2 SO2 Control Technologies....................................................... 6-10 

6.4.3 PM Control Technologies........................................................ 6-10 

7.0 Visibility Impacts (Step 5)................................................................................... 7-1 

7.1 Modeling Methodology ........................................................................... 7-1 

7.2 Emissions ................................................................................................. 7-3 

7.3 Control Technologies............................................................................... 7-3 

7.4 Modeling Results ..................................................................................... 7-4 

8.0 Selection of Best Alternative ............................................................................... 8-1 

8.1 Selection of PM BART............................................................................ 8-1 

8.2 Selection of SO2 BART ........................................................................... 8-2 
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8.3 Selection of NOX BART.......................................................................... 8-3 

9.0 References............................................................................................................ 9-1 

Appendix A Design Basis 

Appendix B Stack Outlet Conditions 

Appendix C Design Concept Definitions 

Appendix D Cost Analysis Summary 

Appendix E Visibility Modeling Results 

Appendix F Visibility Modeling Protocol 

Appendix G Emissions Performance Analysis Memo 

Tables 

Table 1-1 Boardman Plant Operational Characteristics........................................... 1-3 

Table 2-1 Typical Owner Costs................................................................................ 2-3 

Table 2-2 Economic Evaluation Factors .................................................................. 2-5 

Table 2-3 Baseline Emissions .................................................................................. 2-7 

Table 4-1 Technically Feasible NOx Control Technologies .................................... 4-5 

Table 4-2 Technically Feasible SO2 Control Technologies ..................................... 4-6 

Table 4-3 Technically Feasible PM Control Technologies...................................... 4-7 

Table 4-4 Technically Feasible Emerging Pollution Control Technologies ............ 4-8 

Table 5-1 Highest Rolling 12 Month Data for Heat Input ....................................... 5-1 

Table 5-2 NOx Technologies Control Effectiveness ................................................ 5-2 

Table 5-3 SO2 Technologies Control Effectiveness................................................. 5-2 

Table 5-4 PM Technologies Control Effectiveness ................................................. 5-3 

Table 6-1 Impact Analysis and Cost-Effectiveness Results..................................... 6-6 

Table 7-1 Visibility Impact Summary Boardman Plant BART 

Determination .......................................................................................... 7-5 

Table 8-1 Visibility Impact Summary Boardman Plant BART 

Determination .......................................................................................... 8-8 

Figures 

Figure 3-1 Staged Combustion of Low NOx Burners and Overfire Air 

System...................................................................................................... 3-5 

Figure 3-2 Schematic Diagram of a Typical SCR Reactor........................................ 3-7 

Figure 3-3 Schematic of SNCR System with Multiple Injection Levels................... 3-9 
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110207 TC-5 

Figure 3-4 Mobotec ROFA and ROTAMIX Simplified Process Flow 

Diagram (Mobotec USA)....................................................................... 3-12 

Figure 3-5 ECOTUBE Installation in a Boiler ........................................................ 3-13 

Figure 3-6 Schematic of Gas Reburn System.......................................................... 3-15 

Figure 3-7 Process Flow Diagram of a Spray Tower Wet FGD System................. 3-17 

Figure 3-8 Cutaway View of a Jet Bubbling Reactor Wet FGD System ................ 3-18 

Figure 3-9 Spray Dryer System. .............................................................................. 3-20 

Figure 3-10 SDA FGD System.................................................................................. 3-21 

Figure 3-11 Circulating Dry Scrubber System (Lurgi Lentjes North America)........ 3-22 

Figure 3-12 Pulse Jet Fabric Filter Compartment (Babcock & Wilcox)................... 3-25 

Figure 3-13 Max-9 Electrostatic Filter ...................................................................... 3-27 

Figure 3-14 Multiple-Cyclone Particulate Collector ................................................. 3-29 

Figure 3-15 ECO Process Flow Diagram (PowerSpan). ........................................... 3-32 

Figure 3-16 Pahlman Process Simplified Process Flow Diagram............................. 3-33 

Figure 3-17 Phenix Clean Coal Process Flow Diagram ............................................ 3-34 

Figure 3-18 J-POWER ReACT System .................................................................... 3-36 

Figure 6-1 NOx Control Cost-Effectiveness.............................................................. 6-7 

Figure 6-2 SO2 Control Cost-Effectiveness............................................................... 6-8 

Figure 6-3 PM Control Cost-Effectiveness ............................................................... 6-9 
Boardman Plant Acronym List 

110207 AL-1 

Acronym List 

A/C Air-to-Cloth 

AFDC Allowance for Funds During Construction 

ASN Ammonium Sulfate Nitrate 

BART Best Available Retrofit Technology 

Btu or BTU British Thermal Unit 

CaS Calcium Sulfide 

CCS Clean Combustion System 

CDS Circulating Dry Scrubber 

CO Carbon Monoxide 

CRGNSA Columbia River Gorge National Scenic Area 

CUECost Coal Utility Environmental Cost 

DCS Distributed Control System 

DEQ Department of Environmental Quality 

EPA Environmental Protection Agency 

EPRI Electric Power Research Institute 

ESP Electrostatic Precipitator 

FF Fabric Filter 

FGD Flue Gas Desulfurization 

ID Induced Draft 

IFGR Induced Flue Gas Recirculation 

LNB Low NOx Burners 

LNB/MOFA Low NOx Burners with Modified Overfire Air 

NLNB/MOFA/SNCR New Low NOx Burners with Modified Overfire Air and 

Selective Noncatalytic Reduction 

NLNB/MOFA/SCR New Low NOx Burners with Modified Overfire Air and 

Selective Catalytic Reduction 

Mg(OH)2 Magnesium Hydroxide 

MMBtu or MMBTU Million (106) British Thermal Units 

MW Megawatt 

N2O5 Nitrogen Pentoxide 

NH3 Ammonia 

NOx Nitrogen Oxides 

OFA Overfire Air 

O&M Operating and Maintenance 

PGE Portland General Electric 
Boardman Plant Acronym List 

110207 AL-2 

PJFF Pulse Jet Fabric Filter 

PM Particulate Matter 

PRB Powder River Basin 

SCR Selective Catalytic Reduction 

SNCR Selective Noncatalytic Reduction 

Semi-Dry FGD Semi-Dry Flue Gas Desulfurization 

SO2 Sulfur Dioxide 

VOC Volatile Organic Compounds 

WESP Wet Electrostatic Precipitator 

WFGR Windbox Flue Gas Recirculation 
Boardman Plant Executive Summary 

110207 ES-1 

Executive Summary 

The Boardman Plant is a 584 megawatt (MW) net pulverized coal fired steam 

electric plant of more than 250 million British thermal unit (MMBTU) per hour heat 

input located near Boardman, Oregon, about 150 miles east of Portland. The plant was 

issued its construction authorization on February 27, 1975 by the Oregon Nuclear and 

Thermal Energy Council. 

On July 6, 2005, the Environmental Protection Agency (EPA) issued its final 

Regional Haze Regulations and Guidelines for Performing Best Available Retrofit 

Technology (BART) Determinations. These rules/guidelines established a procedure for 

identifying those sources that must retrofit their existing facilities with BART and for 

determining what constitutes BART. The purpose of the BART program was to require 

controls, where appropriate, for facilities that were “grandfathered” from the new source 

review requirements of the 1977 Clean Air Act Amendments. Specifically, the BART 

rules apply exclusively to sources within one of the enumerated source categories that 

were in existence prior to August 7, 1977. 

Because the Boardman Plant is a steam electric plant of more than 250 MMBTU 

per hour heat input that was in existence (as that term is defined by EPA) before August 

7, 1977, it was identified by the Oregon Department of Environmental Quality (DEQ) as 

a BART source. Portland General Electric (PGE) volunteered to serve as the pilot source 

for DEQ’s BART determination process. This analysis has been prepared in accordance 

with the five-step process identified in the EPA’s Regional Haze Regulations and 

Guidelines for Performing BART Determinations (40 CFR Part 51, Appendix Y) to 

evaluate the best available retrofit control technologies for the reduction of nitrogen 

oxides (NOx), sulfur dioxide (SO2), and particulate matter (PM) emissions from the 

Boardman Plant. 

The five-step BART analysis was used to generate the information needed to 

identify the best control technology package that constitutes BART for the Boardman 

Plant. In Step 1, available NOx, SO2, and PM retrofit control technologies were identified 

for the Boardman Plant. In Step 2, this list was shortened by eliminating those 

technologies that are not considered technically feasible. In Step 3, the control 

effectiveness of each technically feasible control technology was evaluated and, based on 

this evaluation, the technologies were ranked in order of effectiveness. In Step 4, the 

cost, energy, and environmental impacts were evaluated for each technically feasible 

control technology. In the final step, the visibility improvements associated with the topranked options were evaluated consistent with the modeling protocol approved by DEQ 

on January 18, 2007 and amended on August 28, 2007. 
Boardman Plant Executive Summary 

110207 ES-2 

NOx Control Selection

After all of the statutory factors were considered, the NOx controls combination of 

new low NOx burners with modified overfire air and selective noncatalytic reduction 

(NLNB/MOFA/SNCR) was identified as the Best Available Retrofit Technology for NOx

control. This NOx control combination results in significant modeled visibility 

improvement at the Class 1 areas for Boardman Plant impacts. 

An alternative NOx control package that utilizes selective catalytic reduction 

(SCR) in lieu of SNCR was considered, but ultimately determined to have excessive 

impacts and so eliminated from consideration as BART. The controls combination of 

new LNBs with modified OFA and SCR (NLNB/MOFA/SCR) would result in greater 

NOx reductions and slightly better modeled visibility improvements than 

NLNB/MOFA/SNCR. However, as EPA recognized in the 2005 preamble, the modeling 

system required for evaluating visibility impacts magnifies and overstates those impacts. 

Therefore, the small incremental improvement between the NOx controls incorporating 

SNCR and the NOx controls incorporating SCR is not, by itself, determinative. In 

addition, the use of the NOx controls incorporating SCR has other impacts that are more 

severe than new LNBs with modified OFA system and SNCR. Specifically, the non-air 

quality environmental impacts (i.e., hazardous material disposal during catalyst 

replacement) and the energy impacts (i.e., significant fan auxiliary power to overcome 

additional system resistance) associated with NLNB/MOFA/SCR are higher than for 

NLNB/MOFA/SNCR. 

The economic impacts also support selecting NLNB/MOFA/SNCR as BART. 

The economic impacts associated with the NLNB/MOFA/SCR alternative are 

considerably higher than the economic impacts associated with the NLNB/MOFA/SNCR 

alternative. The total capital cost of the NOx controls incorporating SNCR is 

approximately $50 million while the total capital cost associated with the NOx controls 

including SCR is approximately $223 million. Operating costs are similarly much higher 

with the SCR alternative than the SNCR alternative ($5.7 million per year as opposed to 

$2.4 million per year). However, the visibility improvements associated with the NOx

controls incorporating SCR are not commensurate with the additional $173 million in 

capital cost (as compared to the NOx controls incorporating SNCR). Even if the plant 

were assumed to operate at its highest daily emission rate for every day of the year 

(something that never occurs), the use of the NOx control package with SCR as opposed 

to that with SNCR, would result in only 7 fewer days per year where Mt Hood 

Wilderness Area visibility impacts exceeded 0.5 deciviews. The additional $173 million 

capital cost and $3.3 million per year of operating cost associated with the SCR control 
Boardman Plant Executive Summary 

110207 ES-3 

package is not justified by the minimal benefit. This limited benefit carries across all of 

the Class I areas. The average 98th percentile impact level across all the Class I areas is 

only 0.27 deciviews better with the control option incorporating SCR than the control 

option incorporating SNCR. This equates to an incremental annualized control cost 

associated with moving from the NOx controls with SNCR to the NOx controls with SCR 

of approximately $72 million per deciview (based on an annualized cost of $27 

million/year for package with SCR v. $7 million per year for package with SNCR). 

Again, the minimal improvement in visibility associated with the NOx control option 

incorporating SCR does not justify the extreme incremental cost. This conclusion is 

confirmed through reference to the EPA cost-effectiveness recommendations. The cost 

effectiveness of the NOx control package incorporating SCR ($3,096/ton) is significantly 

higher than the range ($100 to $1000/ton) considered reasonable in EPA’s BART 

guidelines. 

Consideration of the impact of requiring SCR on plant viability also supports the 

conclusion that BART for NOx constitutes the control package with SNCR. The EPA 

Guidelines state that it is appropriate to take into account the affordability of particular 

controls as part of the BART analysis where the cost of installing and operating the 

controls is judged to have a severe impact on plant operations. That would be the case 

were BART considered to include SCR. The Boardman Plant is a key resource for 

providing baseload power to the region throughout the year. The imposition of SCR as 

BART, on top of the $300 million in air pollution control capital investments being 

proposed, could possibly require an investment in excess of what the plant can support. 

Under such circumstances the EPA Guidelines state that it is appropriate to consider the 

non-affordability of SCR and to therefore conclude that SCR is not BART. Based on the 

discussion within this report there is no need to rely on this factor to conclude that BART 

does not include SCR. However, this additional consideration lends further support to 

the conclusion that BART for NOx constitutes the control package with SNCR. 

From a design standpoint, since the Boardman boiler was not designed with space 

in the ductwork or with an appropriate temperature profile for utilization of SCR, very 

challenging and complex modifications to the boiler would be required at significant cost 

to lower the gas path temperature to the desired range while maintaining combustion 

efficiency. Therefore, a balancing of the statutory factors strongly supports 

NLNB/MOFA/SNCR as the best alternative. 
Boardman Plant Executive Summary 

110207 ES-4 

SO2 Control Selection

After all of the statutory factors were considered, the semi-dry flue gas 

desulfurization (semi-dry FGD) technology was determined to be the best BART 

alternative for SO2 control. The two top SO2 control technologies (wet FGD and semidry FGD) were modeled as having essentially the same level of visibility improvement at 

the Class I areas. However, the non-air quality environmental impacts and negative 

energy impacts are significantly greater for the wet FGD control technology, since it 

generates a visible plume, consumes more water, generates a wastewater stream requiring 

treatment and disposal, generates slightly more solid byproducts for landfill, and because 

the wet FGD requires significantly more auxiliary power consumption during operation. 

The economic impacts associated with the wet FGD are also much higher than the 

economic impacts associated with the semi-dry FGD. The costs associated with 

installing semi-dry FGD are very high, with a total capital cost of approximately $247 

million and operating costs of approximately $13 million per year. While these costs are 

extremely high, the costs of the wet FGD system would be considerably higher with a 

total capital cost of approximately $382 million and operating costs of approximately $16 

million per year. As a result, the cost effectiveness of the wet FGD control option is 

significantly higher than the range ($400 to $2000/ton) considered to be reasonable in 

EPA’s BART guidelines. Given that wet FGD does not perform materially better than 

semi-dry FGD, there is no basis for spending the additional $135 million in capital and $3 

million per year in operating expenses to implement the wet FGD technology. Therefore, 

consistent with the statutory factors, semi-dry FGD was chosen as the best alternative for 

SO2 control. 

Particulate (PM) Control Selection

After all of the statutory factors were considered, the pulse jet fabric filter (PJFF), 

in combination with the existing ESP, was determined to be the best BART control 

alternative for PM. Multiple technologies had equal control effectiveness, but the 

utilization of PJFF enables the highest level of mercury control. This improvement to 

water quality from reduction of mercury bioaccumulation is a significant positive 

environmental benefit and, therefore, supports the choice of PJFF as BART. 

Best Control Combination Selection

The package of the selected controls (NLNB/MOFA/SNCR for NOx and semi-dry 

FGD including PJFF for SO2 and PM) constitutes BART for the Boardman Plant. This 

also constitutes the most effective package for integration with the controls being 
Boardman Plant Executive Summary 

110207 ES-5 

designed for the Boardman Plant to meet the Oregon mercury standards for coal fired 

power plants. 

While the Columbia River Gorge National Scenic Area (CRGNSA) is not a Class 

I area and so not a part of the BART analysis, there was interest in the benefits to that 

area as a result of the proposed BART controls. The modeling of the benefits predicted 

from the proposed BART control package show significant improvement in visibility in 

the CRGNSA. While slightly greater improvements are shown by the model from the 

use of a control package that includes SCR, these improvements are not considered 

significant. This conclusion was independently verified in the draft Columbia River 

Gorge Air Quality Study Science Summary Report (September 27, 2007) prepared by 

DEQ in conjunction with other state and federal governmental authorities. The report 

authors compared CRGNSA visibility as a result of the proposed BART controls (i.e., 

NLNB/MOFA/SNCR, semi-dry FGD and PJFF) to CRGNSA visibility if Boardman 

emissions were reduced to “0” (i.e., complete shutdown of the plant). As the report 

notes, “practically zero” additional visibility benefit is achieved by reducing plant 

emissions from those achieved by the proposed BART control package all the way to 

zero plant emissions. 

That assessment serves as independent verification of the conclusion that no 

material visibility benefit would be gained by controlling NOx through the use of new 

LNB with modified OFA and SCR rather than new LNB with modified OFA and SNCR. 

If eliminating the Boardman Plant generates “practically zero” additional benefit as 

compared to the proposed BART control package, the much smaller incremental benefit 

achieved by requiring SCR rather than SNCR would be immaterial. Given the extreme 

incremental cost associated with the use of new LNB with modified OFA and SCR for 

NOx control, there is no technically sound basis for requiring SCR as part of the BART 

control package. 

 PGE’s implementation of the suite of BART controls identified through this 

report will cost more than $297 million dollars to install and approximately $15 million 

per year to operate. While this poses a significant economic impact to the Boardman 

Plant and to Northwest electric utility customers, the controls are predicted to improve 

the plant’s modeled worst-case visibility impacts in the Class I areas by an average 

64 percent, improve the plant’s modeled worst-case visibility impacts at the most 

severely impacted Class I area by 56 percent, and enable the enhanced control of mercury 

emissions. Therefore, the utilization of the NLNB/MOFA/SNCR and semi-dry FGD 

(including PJFF) is the best alternative and constitutes BART. 

 The following appendices contain supporting data for the BART analysis 

described in this report: 
Boardman Plant Executive Summary 

110207 ES-6 

• Appendix A Design Basis. 

• Appendix B Stack Outlet Conditions. 

• Appendix C Design Concept Definitions. 

• Appendix D Cost Analysis Summary. 

• Appendix E Visibility Modeling Results. 

• Appendix F Visibility Modeling Protocol. 

• Appendix G Emissions Performance Analysis Memo. 
Boardman Plant Introduction and Objectives 

110207 1-1 

1.0 Introduction and Objectives 

 The primary objective of this report is to summarize the BART analysis for the 

Boardman Plant. This plant has been identified as a BART source under the EPA’s 

Regional Haze Rules (40 CFR Part 51). Three pollutants: NOx, SO2, and PM, were 

identified as having a potential impact on visibility at federal Class I areas, and these 

pollutants are the focus of this BART analysis. This report documents the BART 

evaluation process and results obtained, as well as the recommended best retrofit control 

alternative for each of the pollutants. 

1.1 Source Description and Background 

 The Boardman Plant is a 584 MW electric utility steam generating facility located 

near Boardman, Oregon, about 150 miles east of Portland. The Boardman Plant is jointly 

owned by PGE (65%), Idaho Power (10%), Power Resources Cooperative (10%) and 

General Electric Capital Corporation (15%). The Boardman Plant was issued its 

construction authorization from the Nuclear and Thermal Energy Council on February 

27, 1975 and an Air Contaminant Discharge Permit from the Oregon Department of 

Environmental Quality (DEQ) on April 6, 1977. As part of the permitting process, PGE 

performed extensive modeling to demonstrate that the plant would operate in compliance 

with the ambient air quality standards. PGE also agreed to implement various controls to 

reduce air emissions, including the use of a cold-side ESP to reduce particulate 

emissions, the exclusive use of low sulfur coal to reduce SO2 emissions, and the use of 

LNB and OFA to reduce NOx emissions. 

The Boardman Plant’s steam generator consists of a subcritical, opposed wallfired boiler that operates on balanced draft. The plant currently burns low sulfur Powder 

River Basin (PRB) coal from the Buckskin mine. A summary of the operational 

characteristics are noted in Table 1-1. A detailed design basis of the Boardman Plant is 

included in Appendix A. 

On July 6, 2005, the EPA issued its final Regional Haze Regulations and 

Guidelines for Performing BART Determinations. These rules/guidelines established a 

procedure for identifying those sources that must retrofit their existing facilities with 

BART and for determining what constitutes BART. The purpose of the BART program 

was to require controls, where appropriate, for facilities that were “grandfathered” from 

the new source review requirements of the 1977 Clean Air Act Amendments. 

Specifically, the BART rules apply exclusively to sources within one of the enumerated 

source categories and that were in existence prior to August 7, 1977. 
Boardman Plant Introduction and Objectives 

110207 1-2 

Although the Boardman Plant did go through all the substantive new source 

review requirements of the 1977 Clean Air Act Amendments, DEQ has still characterized 

the facility as subject to BART. Because the Boardman Plant is a steam electric plant of 

more than 250 MMBTU per hour heat input, it is in one of the BART eligible source 

categories. In order to be BART eligible, the plant would have to have been in existence, 

as that term is defined by EPA in the BART rules, before August 7, 1977. A plant is 

considered “in existence” if 

“the owner or operator has obtained all necessary 

preconstruction approvals or permits required by Federal, 

State, or local air pollution emissions and air quality laws or 

regulations and either has (1) begun, or caused to begin, a 

continuous program of physical on-site construction of the 

facility or (2) entered into binding agreements or contractual 

obligations, which cannot be cancelled or modified without 

substantial loss to the owner or operator, to undertake a 

program of construction of the facility to be completed in a 

reasonable time.” 40 CFR 51.301 

DEQ determined that the Boardman Plant had obtained all necessary 

preconstruction approvals or permits required by Federal, State, and local laws by April 

6, 1977. Therefore, even though it had not yet begun normal operations in 1977, because 

the Boardman Plant was fully permitted and construction had commenced prior to August 

7, 1977, the Boardman Plant was identified by DEQ as a BART source.1

 PGE 

volunteered to serve as the pilot source for DEQ’s BART determination process. 

 

1

 For the same reasons that the Boardman Plant is considered a BART source, the plant was 

necessarily determined to have 1978 “actual emissions,” as that term is defined in the Oregon Plant Site 

Emission Limit rules, equal to the plant’s potential to emit. 
Boardman Plant Introduction and Objectives 

110207 1-3 

Table 1-1 

Boardman Plant Operational Characteristics 

Item Unit 1 

Fuel Type Subbituminous 

Heating Value of Fuel, BTU/lb (HHV) 8,020 – 9,800 

Unit Rating, MW (gross/net) 617 / 584 

Net Plant Heat Rate, BTU/kWh 9,841 

Boiler Heat Input, MMBTU/hr 5,793 

Type of Boiler/Manufacturer Opposed-wall/Foster Wheeler 

Steam Cycle Subcritical 

Draft of Boiler Balanced 

Existing Emissions Controls 

SO2 (Precombustion Controls - Coal 

Type) 

Low-sulfur coal 

NOx (Combustion Controls) LNB, OFA (1st generation) 

PM (Postcombustion Controls) Cold-side ESP 

1.2 BART Analysis Methodology 

 BART is an engineering, economic, and visibility modeling analysis to identify 

the best method of emission reduction for pollutants that cause visibility impacts in 

federal Class I areas (NOx, SO2, and PM). To identify the best method of emission 

reduction, data are collected through a five step process to arrive at a selection of the best 

methods of emissions reduction of NOx, SO2, and PM at the BART source. The five 

steps followed to develop information for making the BART determination are the 

following: 

1. Identify all available retrofit control technologies. 

2. Eliminate technically infeasible options. 

3. Evaluate control effectiveness of remaining control technologies. 

4. Evaluate impacts and document the results. 

5. Evaluate visibility impacts. 

 These steps generate data that are used to evaluate the costs and benefits of 

various control technologies and, ultimately, identify the retrofit technology appropriate 

for installation at the source. Each of these steps is further explained in the following 

subsections. 
Boardman Plant Introduction and Objectives 

110207 1-4 

1.2.1 Identify All Available Retrofit Control Technologies (Step 1) 

 The first step of the BART analysis is to identify all available retrofit control 

technologies. A control technology is considered as an available retrofit if it has practical 

potential for application to the BART-eligible source. The technology considered can be 

a method, system, or a combination of both options for control of a pollutant. 

Technologies that have been successfully applied to similar sources with similar gas 

stream characteristics are considered available. However, technologies that have not 

been applied to full scale operations are not considered available. Since the Boardman 

Plant is equipped with existing control technologies, the control options evaluated 

included improvements or optimization of the existing control technologies. Section 3.0 

addresses the requirements of Step 1 of the BART analysis. 

1.2.2 Eliminate Technically Infeasible Options (Step 2) 

 Step 2 of the BART analysis involves the evaluation of all the identified available 

retrofit control technologies to determine technical feasibility. A control technology is 

technically feasible if it has been previously installed and operated successfully at a 

similar type of source or if there is technical agreement that the technology can be 

applied to the source. Two terms, available and applicable, are used to define the 

technical feasibility of a control technology. A technology that is being offered 

commercially by vendors or is in commercial demonstration or licensing is deemed an 

available technology. Technologies that are in development and testing stages are 

classified as not available. A commercially available technology is applicable if it has 

been previously installed and operated at a similar type of source, or a source with similar 

gas stream characteristics. Section 4.0 addresses the requirements of Step 2 of the BART 

analysis. 

1.2.3 Evaluate Control Effectiveness of Remaining Control Technologies 

(Step 3) 

 Once all the technically feasible control technology alternatives are identified in 

Step 2, the control effectiveness of each control technology is evaluated in Step 3, and the 

technologies are ranked. The control effectiveness is documented for each technology 

and expressed both in terms of tons per year of post-control emissions and pounds of 

emissions per MMBTU heat input. Data for the control effectiveness of a technology 

were obtained by considering regulatory decisions or evaluations that have been 

performed on the effectiveness of the technology. Other reference sources for control 

effectiveness data are technology performance data provided by manufacturers (usually 

in the form of performance guarantees), engineering estimates, and demonstrated 
Boardman Plant Introduction and Objectives 

110207 1-5 

effectiveness of the technology at existing operating sources. The most stringent level of 

control demonstrated for each technology was used for its control effectiveness. For 

purposes of comparison, the technologies were ranked in order of effectiveness, from the 

current controls to the most effective control. Section 5.0 describes the evaluations 

performed for Step 3 of the BART analysis. 

1.2.4 Evaluate Impacts and Document the Results (Step 4) 

 Once the control effectiveness is established in Step 3 for all the feasible control 

technologies identified in Step 2, additional evaluations of each technology are performed 

in Step 4. The impacts of utilizing the control technology at the Boardman Plant are 

evaluated. The evaluation of the impacts (impact analyses) is included in Section 6.0. 

The impact analyses performed are: 

• Costs of compliance. 

• Energy impacts. 

• Non-air quality environmental impacts. 

• Remaining useful life. 

The first impact analysis evaluates the costs of compliance. This analysis is 

performed to indicate the cost to install and operate the control technology. The capital 

and operating annual costs is estimated based on established design parameters, and then 

the annualized cost is determined. The annualized cost ($/year) is then divided by the 

estimated quantity of pollutant removed (tons/year) to determine the cost-effectiveness 

($/tons) of each control technology. Establishing cost-effectiveness allows the 

comparison of the different control technologies on an economic basis. Consistent with 

the EPA’s directive, two types of cost-effectiveness are considered in this BART 

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

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

removed for each control technology. The incremental cost-effectiveness is a comparison 

of the cost and performance level of a control technology to the next most stringent 

option. It has a unit of $/incremental ton removed. The incremental cost-effectiveness is 

a good measure when comparing technologies that have similar removal efficiencies. 

 The second impact analysis evaluates the energy impacts of a particular control 

technology. The energy impact of each evaluated control technology is the energy 

penalty or benefit resulting from the operation of the control technology at the source. 

Examples of direct energy impacts include the auxiliary power consumption of the 

control technology and the additional draft system power consumption to overcome the 

additional system resistance (pressure loss) of the control technology in the flue gas flow 

path. The cost of these energy impacts includes additional fuel cost and/or the cost of 
Boardman Plant Introduction and Objectives 

110207 1-6 

lost generation that would need to be purchased from another source because of 

implementation of the technology. 

 The third impact analysis evaluates the non-air quality environmental impacts. 

Non-air quality environmental impacts are evaluated to determine whether a particular 

control technology has any environmental impacts not related to air quality – either 

positive or negative. An example of a positive non-air quality environmental impact is 

the generation of wallboard-quality gypsum; an example of a negative non-air quality 

environmental impact is the generation of wastewater discharge and solid waste. 

 Lastly, the remaining useful life is only considered when there is an effect on the 

annualized costs of the retrofit controls for capital recovery. This occurs when the source 

has a shorter remaining useful life than the expected service life of the control 

technology. This would require expedited capital recovery, thus affecting the costeffectiveness of the control technology, particularly for technologies that require a large 

capital expenditure. 

1.2.5 Evaluate Visibility Impacts (Step 5) 

 Potential visibility improvement from the addition of each control technology is 

determined from modeling results using the CALPUFF dispersion modeling system. A 

modeling protocol has been developed in consultation with, and approval of, DEQ. Items 

that were considered in the modeling protocol include the following: 

• Meteorological and terrain data. 

• Stack height, temperature, exit velocity, and elevation. 

• Pre- and post-control emission rates. 

• Receptor data from appropriate Class 1 areas. 

After completing model runs at pre- and post-control emission rates, a 

determination of the visibility improvement was made. The visibility improvement was 

determined by comparing the 98th percentile days at pre- and post-control emission rates. 

1.2.6 Selecting the Best Alternative 

 From the analyses performed in the five steps described above, tables were 

prepared assessing the merits and demerits of the control technology options, with the 

focus on the top-ranked technologies. These factors were then evaluated to select the 

best alternative. 
Boardman Plant Basis of Analysis 

110207 2-1 

2.0 Basis of Analysis 

2.1 Design Basis 

 A detailed design basis was established for the Boardman Plant. The information 

in the design basis was used for equipment sizing, performance calculations, cost 

estimates (capital, operating, and maintenance), and estimating resources consumption, 

auxiliary power requirements, and byproduct disposal. The complete design basis is 

shown in Appendix A. The design basis with the original design coal case was used as 

the basis for this BART analysis. The design basis was also established for two other 

coal cases: typical (Buckskin Mine) and maximum (Black Butte Mine). Performance 

calculations were based on the design basis coal. 

2.2 Economic Data 

2.2.1 Capital Cost Estimates 

 Capital cost estimates were developed for retrofit control technologies that were 

identified as technically feasible for the Boardman Plant. The capital cost estimates were 

based on the Coal Utility Environmental Cost (CUECost) generated estimates, cost data 

supplied by equipment vendors (budget estimates), and estimates from in-house 

design/build projects. The capital cost estimates include direct and indirect costs and are 

stated in 2007 dollars. The cost estimates are consistent in format with the guidance from 

the EPA’s Office of Air Quality Planning and Standards Cost Manual. The capital cost 

accuracy is expected to be +/- 30 percent. The costs presented in this report are 

preliminary and should only be used for comparative purposes in the BART analysis. 

The capital cost estimates will be refined throughout the upcoming preliminary 

engineering phase until actual equipment and construction contracts are procured. 

 Direct costs consist of purchased equipment, installation, and miscellaneous costs. 

The purchased equipment costs are the costs for purchasing the control technology 

equipment from equipment vendors (including freight). An itemized list of major 

components of the direct capital cost is included for each feasible control technology in 

Appendix D. The installation costs include construction costs for installing the new 

controls and also take into account the retrofit difficulty that can be expected from the 

existing site configuration and the installation requirements of the controls. Finally, 

miscellaneous costs include the costs for additional items such as site preparation, 

buildings, and other site structures needed to support the controls. The direct cost 

estimates were based on the following assumptions: 

• Regulatory permitting has been completed. 
Boardman Plant Basis of Analysis 

110207 2-2 

• Ample supply of craft labor and construction equipment is available. 

• Normal lead-times for equipment deliveries are expected. 

Indirect costs are costs that are not related to the equipment purchased but are 

associated with any engineering project, such as the retrofit of an air quality control 

technology. Indirect costs considered in this evaluation include the following: 

• Contingency. 

• Engineering. 

• Owner Costs. 

• Construction management. 

• Startup and spare parts. 

• Performance Tests. 

2.2.1.1 Contingency. Contingency accounts for unpredictable events and costs that 

could not be anticipated during the normal cost development of a project. Costs assumed 

to be included in the contingency cost category are items such as possible redesign and 

equipment modifications, unforeseen weather-related delays, strikes and labor shortages, 

escalation increases in equipment costs, increases in labor costs, delays encountered in 

startup, etc. 

2.2.1.2 Engineering. Engineering costs include any services provided by an 

architect/engineer or other consultant for support, design, and procurement of the air 

quality control project. 

2.2.1.3 Owner Costs. Table 2-1 lists possible owner costs. Some of the costs are not 

applicable to all of the evaluated technologies but are representative of the typical 

expenditures that the owner(s) will experience through an air quality control retrofit 

project. 

2.2.1.4 Construction Management. Construction management includes costs for 

field management staff, such as supporting staff personnel, field contract administration, 

field inspection and quality assurance, project controls, technical direction, and startup 

management. It also includes cleanup expenses for the portion not included in the directcost construction contracts, safety and medical services, guards and other security 

services, insurance premiums, other required labor-related insurance, performance bond, 

and liability insurance for equipment and tools. 

2.2.1.5 Startup and Spare Parts. Startup services include the costs for management 

of the startup planning and procedure and training of personnel for the commissioning of 

the newly installed control technology. Also included are the general low-cost spare 

parts required for each control technology system. High-cost critical spare parts are not 

included in this analysis; they are determined on a case-by-base basis from manufacturer 

recommendations and owner requirements. 
Boardman Plant Basis of Analysis 

110207 2-3 

Table 2-1 

Typical Owner Costs 

Project Development: 

Legal assistance 

Permitting compliance 

Public relations/community development 

Road modifications/upgrades 

Financing: 

Debt service reserve fund 

Financial analysis 

Plant Startup/Construction Support: 

Owner’s site mobilization 

O&M staff training 

Initial test fluids and lubricants 

Initial inventory of chemicals/reagents 

Consumables 

Construction all-risk insurance 

Startup/construction auxiliary power 

purchase 

Owner’s Project Management: 

Project management 

Engineering due diligence 

Preparation of bid documents and selection 

of contractors and suppliers 

Taxes/Advisory Fees/Legal: 

Taxes 

Market and environmental consultants 

Owner’s legal expenses: 

Interconnect agreements 

Contract-procurement and 

construction 

Property transfer 

2.2.1.6 Cost Escalations. No contingency has been devoted to cost escalations over 

those of inflation. It is noted that a large number of coal plants will be built, or undertake 

emissions controls retrofits during this period. This is expected to intensify competition 

for equipment, basic materials, craft labor and engineering talent. The trend is concurrent 

with global competition for infrastructure improvements in China, India and the Third 

World. Most suppliers are at, or beyond, their resource capacity today and conditions are 

not expected to improve. Suppliers’ expectations will continue to force buyers to 

increasingly take commodity, schedule and currency risks. The costs impacts of these 

factors are being experienced in today’s market and are anticipated to continue to 

increase the cost of retrofit projects well beyond inflation in the future. 

2.2.1.7 Performance Tests. Performance tests are conducted after installation of the 

control technologies to validate the performance of the emissions reduction systems. 

Typical performance tests are flue gas emissions testing that may be performed at various 

points of the flue gas flow path. The results of the performance tests are used to ensure 

compliance with performance guarantees and emissions limits. 
Boardman Plant Basis of Analysis 

110207 2-4 

2.2.2 Annual Operating and Maintenance Cost Estimate 

Annual operating and maintenance (O&M) costs typically consist of the following 

cost categories: 

• Reagent costs. 

• Electric power costs. 

• Makeup water costs. 

• Wastewater treatment and byproduct disposal costs. 

• Operating labor costs. 

• Maintenance materials and labor costs. 

 The costs of reagent, electric power, makeup water, wastewater, and byproduct 

disposal are variable annual costs that are dependent on the specific control technology. 

Operating and maintenance materials and labor are fixed annual costs that do not vary 

with these factors. Table 2-2 lists the major economic factors used to estimate annual 

O&M costs. 

2.2.2.1 Reagent Costs. Reagent costs include the costs for the material and delivery 

of the reagent to the facility as well as for reagent preparation. Reagent costs are a 

function of the quantity of the reagent used and the market price of the reagent. The 

quantity of reagent used will vary with the quantity of pollutant that must be removed as 

well as the reagent utilization ratio. Reagent costs were defined for the following 

reagents: 

• Limestone. 

• Lime. 

• Anhydrous ammonia. 

• Urea. 

• Magnesium hydroxide (Mg(OH)2) for wet ESP (WESP) applications. 

2.2.2.2 Electric Power Costs. Additional auxiliary power will be required to run 

some of the control technology systems evaluated for the Boardman Plant. The power 

requirements of each system vary depending on the type of technology and the 

complexity of the system. Electric power costs include increases in induced draft (ID) 

fan power consumption caused by the flue gas pressure losses through the new 

equipment. 
Boardman Plant Basis of Analysis 

110207 2-5 

Table 2-2 

Economic Evaluation Factors 

Reagent Cost 

Lime $132/ton 

Limestone $46/ton 

Ammonia (anhydrous) $450/ton 

Urea $315/ton 

Mg(OH)2 $1.20/ton 

SCR Catalyst Cost $6,000/m3

Makeup Water Cost $2/1,000 gal 

Service Water Cost $0.50/1,000 gal 

Wastewater Treatment Cost $0.50/1,000 gal 

Byproduct Disposal Cost $10/ton 

Electric Power Cost $50/MWh 

Steam Cost $3.50/1,000 lbs 

Maintenance Cost 3% of cap cost/yr 

Control Technology Economic Life 20 years 

Interest Rate 7% 

Present Worth Discount 9.2% 

Capital and O&M Escalation Factor 3% 

Capital Recovery Factor (to annualize capital cost) 9.44% 

Allowance for Funds During Construction (AFDC) 8.99% 

Fully Loaded Operating Labor Cost, per person $100,000/year 
Boardman Plant Basis of Analysis 

110207 2-6 

2.2.2.3 Makeup and Service Water Costs. Makeup water or service water is 

required for some of the control technology systems evaluated for the Boardman Plant. 

Examples of water consumption in control technologies include water to support reagent 

preparation for limestone-forced oxidation or lime-based scrubbers, ammonia solution 

preparation from urea for SCR and selective noncatalytic reduction (SNCR) processes 

and for electrode plate washing in a WESP. Additional costs might be incurred for water 

treatment to obtain the required water quality. For the cost estimations, two types of 

water quality were considered: makeup and service water. Depending on the process, 

the appropriate water type was included in this cost category. 

2.2.2.4 Wastewater and Byproduct Disposal Costs. Some control technologies 

generate wastewater and/or byproduct that will require treatment and/or disposal. For 

example, a wet FGD system generates a blowdown wastewater stream to regulate the 

level of chlorides in the slurry recirculation system. Also, a wet FGD system forms 

calcium sulfate and calcium sulfite byproducts when the limestone reacts with SO2. For 

wastewater treatment and byproduct disposal cost, the following key assumptions were 

utilized: 

• Sales of fly ash captured in the existing ESP is unaffected by retrofit 

technologies downstream of the existing ESP. 

• All collected byproducts (excluding existing ESP fly ash) are landfilled. 

• All wet scrubber equipment effluent requires wastewater treatment prior to 

being discharged to the environment. 

• Ammonia-based NOx reduction systems may affect the saleability of fly 

ash. However, for this analysis, the impacts were assumed to be minimal. 

2.2.2.5 Operating Labor Costs. Operating labor costs are developed by estimating 

the number and type of employees that will be required to run the new control equipment. 

These estimates are based on industry common practices. The labor costs are based on a 

fully loaded labor rate and a 40 hour per week work schedule. 

Typically, a complex emissions control technology will require a combination of 

the following personnel: 

• Supervisor 

• Control room operator. 

• Roving operator. 

• Relief operator. 

• Laboratory technicians. 

• Equipment operators. 

• Maintenance technicians. 
Boardman Plant Basis of Analysis 

110207 2-7 

In the evaluation of direct annual costs for each control technology in 

Appendix D, the estimated full-time-equivalent operating labor required is identified. 

2.2.2.6 Maintenance Materials and Labor Costs. The annual maintenance 

materials and labor costs are estimated as a percentage of the total equipment costs of the 

system. On the basis of typical utility industry experience, maintenance materials are 

estimated to be between 1 and 5 percent of the total direct capital costs, depending on the 

retrofit technology. For technologies that replace a similar existing technology at the 

plant site, a determination of the additional maintenance requirements was performed. If 

the required maintenance materials and labor are similar to the existing technology, no 

additional maintenance costs are included for the new control technology. 

2.3 Baseline Emissions 

For this BART analysis, the baseline emissions for NOx, SO2, and PM were 

established for the comparisons of the various control technology options. The baseline 

emissions established for the Boardman Plant are summarized in Table 2-3. The 

emission rates used represent the highest rolling 12 month total between 2003 and 2005. 

Table 2-3 

Baseline Emissions 

Pollutant Emissions Data Source 

NOx 0.426 lb/MMBTU 2003-2005 CEMS Data 

10,348.8 ton/yr 2003-2005 CEMS Data 

SO2 0.614 lb/MMBTU 2003-2005 CEMS Data 

14,901.8 ton/yr 2003-2005 CEMS Data 

PM 0.017 lb/MMBTU 2003-2005 CEMS Data 

417.3 ton/yr 2003-2005 CEMS Data 

2.4 Project Assumptions 

In performing the BART analysis, several general assumptions were made to 

facilitate the conceptual design of the technically feasible control technologies. The 

following are key project assumptions: 

• Plant availability will potentially be affected by the installation of new 

control equipment. However, any changes in plant availability are assumed to 

be insignificant in this analysis. 
Boardman Plant Basis of Analysis 

110207 2-8 

• The site will have sufficient area available to accommodate construction 

activities including, but not limited to, offices, lay-down and staging. 

• Any repairs, rehabilitation, and/or ductwork stiffening of the existing 

boiler and ductwork equipment are assumed to be minor and are included in 

contingency costs. 

• Byproducts produced from the emissions reduction processes will be 

disposed at the available landfill area on-site. 

• When not contaminated with scrubber products or mercury sorbents, fly 

ash captured by PM control technologies is sold. Therefore, no disposal costs 

are accounted for the captured fly ash. 

• There is no natural gas supply to the site, and it is cost prohibitive to 

construct a new 20 mile long pipeline from the nearest source of natural gas to 

the plant site. There are also concerns with permitting, land acquisition, 

environmental impacts during construction, and proximity to military bombing 

training areas. 

2.5 Modeling Baseline Conditions 

 Stack outlet conditions for all the technically feasible control technologies were 

calculated and are presented in Appendix B. The outlet conditions were calculated 

according to the design basis data, technology control effectiveness, and design 

parameters. The types of stack outlet data included are the following: 

• Flue gas flow rate. 

• Flue gas velocity. 

• Flue gas temperature. 

• Flue gas pressure. 

• SO2 emissions rate. 

• NOx emissions rate. 

• PM emissions rate. 
 Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

110207 3-1 

3.0 Identification of All Available Retrofit Emission 

Control Technologies (Step 1) 

 In Step 1 of the BART analysis, all available retrofit control technologies that 

have a practical potential for application at the Boardman Plant were identified. These 

technologies were considered as available technologies. The control technology may be 

a method, system, or combination of reduction technologies for control of a pollutant. 

Sections 3.1 through 3.3 describe the control technologies for the three pollutants: NOx, 

SO2 and PM. Information on the working principle, retrofit considerations, and 

advantages and disadvantages of each technology is also provided. 

3.1 NOx Control Technologies 

 The following NOx control technologies were identified as available for retrofit at 

the Boardman Plant and are summarized in Subsections 3.1.1 through 3.1.15: 

• Existing OFA system operation. 

• Upgraded LNBs. 

• Upgraded LNBs with existing OFA system operation. 

• Upgraded LNBs with existing OFA system operation and SNCR. 

• New LNBs and modified OFA system. 

• New LNBs, modified OFA system, and SNCR. 

• New LNBs, modified OFA system, and SCR. 

• SNCR. 

• SNCR/SCR hybrid (Cascade). 

• Mobotec ROFA and ROTAMIX. 

• NOxStar and NOxStar Plus. 

• ECOTUBE. 

• Induced flue gas recirculation (IFGR). 

• LoTOx. 

• Natural gas reburn. 

3.1.1 Overfire Air System Operation 

OFA works by reducing the excess air in the burner zone, thereby enhancing the 

combustion staging effect and reducing NOx emissions. Any residual unburned material, 

such as carbon monoxide (CO) and unburned carbon that escapes the main burner zone is 

subsequently oxidized as the OFA is added. 

As with primary NOx control, the performance from a given OFA system depends 

on a number of factors. As the amount of OFA is increased, the stoichiometry in the 
 Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

110207 3-2 

burner zone decreases, and a point is reached at which CO emissions reach high levels 

and become uncontrollable. The point at which this occurs can be specific to the boiler 

and coal type, particularly if a fuel is in any way difficult to burn, and will also depend on 

the extent to which it is possible to balance flows between the individual burners. 

As the OFA amount approaches 10 to 15 percent, the probability for individual 

burners operating under fuel-rich conditions increases, potentially forming pockets of 

high CO emissions and unburned carbon. Similarly, fuel-rich operation at burners close 

to the waterwalls can lead to local slag formation and increased tube wastage rates, 

particularly if slagging is an ongoing problem and the coals have a high sulfur content. A 

fairly high level of unburned material leaving the burner zone can be accommodated by 

proper overfire port design, with rapid and complete mixing of the OFA with the boiler 

flue gases. 

Aggressively staging combustion to reduce NOx emissions creates a reducing 

environment in the boiler and can damage the boiler waterwall tubes. The reducing 

environment attacks the iron oxides in the tube metal and can lead to pin holes in the 

boiler tubes. This phenomenon is referred to as tube wastage. Poor staging in the boiler 

could lead to tube wastage resulting in an increase in the amount of maintenance and, in 

the worst case scenario, may require a forced outage to repair the tubes. 

The Boardman Plant is equipped with existing OFA ports. However, because of 

extensive slagging issues and poor operability, these OFA ports are only opened on an asneeded basis. To overcome the slagging problems when operating the OFA ports, 

addition of a NOx combustion controls system with monitors and installation of a water 

cannon system to replace the existing soot blowers is required and included as part of the 

equipment evaluation. 

High-pressure water wash systems (water cannons or hydro jets) are the standard 

furnace cleaning systems being installed on all new boilers firing PRB. High-pressure 

water wash systems provide a means of locating the specific buildup of ash on a furnace 

wall and locally removing the slag. By maintaining furnace cleanliness, the furnace heat 

absorption profile is maintained, and gas temperature profiles are less erratic. This 

improved furnace operation allows for better control of the individual burners and lower 

emissions. 

The systems are designed to selectively evaluate the areas of reduced heat transfer 

in the furnace and provide an effective cleaning procedure, using high-pressure water, to 

remove deposits while minimizing the thermal shock effects of temperature gradients 

created during the cleaning process. 
 Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

110207 3-3 

The systems use several heat flux sensors located throughout the furnace to 

monitor a portion of the furnace wall or zone. Each zone is monitored for a rapid 

reduction in heat flux; after which, a cleaning cycle would be initiated. 

These systems are designed to be automatic and are controlled with a 

programmable microprocessor-based control system. The programmable control system 

communicates to the plant’s distributed control system (DCS) via a data link. Water for 

the cannons is typically supplied by the service water or the plant’s cooling water system. 

A total boiler cleaning system incorporating sensors, soot blowers, water cannons, 

and intelligent algorithms for interpreting and optimizing cleaning systems can improve 

boiler performance and potentially increase boiler efficiency. 

3.1.2 Upgraded Low NOx Burners 

LNBs are available to control the formation and emission of NOx through staged 

combustion in the boiler. The basic NOx reduction principles for LNBs are to control and 

balance the fuel and airflow to each burner and to control the amount and position of 

secondary air in the burner zone so that fuel devolatization and high-temperature zones 

are not oxygen rich. In this process, the mixing of the fuel and the air by the burner is 

controlled in such a way that ignition and initial combustion of the coal take place under 

oxygen-deficient conditions, while the mixing of combustion air is delayed along the 

length of the flame. 

 The objective of this process is to minimize flame temperature and to drive the 

fuel-bound nitrogen out of the coal as quickly as possible, under conditions where no 

oxygen is present, and force it to form molecular nitrogen, rather than be oxidized to 

NOx. Any nitrogen escaping the initial fuel-rich region has a greater opportunity to be 

converted to NOx as the combustion process is completed. The net result of staged 

combustion is usually longer and/or wider flames because of the delayed mixing process. 

Staged combustion can also lead to the potential for increased unburned carbon in ash 

and higher CO emissions. This is particularly true of wall-fired boiler systems, where, in 

contrast to tangential firing, the combustion process must be confined to well-defined 

flame zones and is less able to make maximum use of the available burner zone volume. 

 There have been advances in LNB technology that may be applicable to the 

existing older generation LNBs at the Boardman Plant. Modifications such as to the fuel 

injector and the combustion air swirlers can be made to increase the NOx reduction 

capability. In addition to these modifications, proper balance of fuel and air flow to the 

burners is critical. The reduction in NOx is achieved from the ability to control the 

location of the flame, the length of the flame, and, to a certain extent, the duration of the 

flame. 
 Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

110207 3-4 

By balancing the fuel and air flows to the burners, an important step is achieved in 

controlling the flame characteristics and improving the overall combustion process. 

Balanced fuel flow ensures that each burner is operated with a similar air-to-fuel ratio, 

allowing the burners to operate as a NOx control system as opposed to individual burners. 

Low-load stability is also questionable with imbalanced flow to the burners. The 

flow imbalance from a single pulverizer is further exacerbated at low loads where fuel 

flow is reduced. Under this condition with an imbalanced flow rate, starving a single 

burner can result in a flame-out condition for that burner and subsequent loss of the 

pulverizer or, potentially, the unit. To ensure there is a flame present at all times, flow to 

each burner needs to be adequate and balanced. By balancing the flow, an operator can 

run a row of burners at a lower flow rate and be confident the entire row has sufficient 

fuel to maintain flame stability. 

A system for monitoring the air and coal flows provides real time data for tuning 

of the burners and maximizing performance of the combustion system. 

Air flow systems measure primary air flow, bulk secondary air, total secondary air 

flow, and OFA flow distribution. One specific system uses a derivative of the multipoint, self-averaging Pitot principle to measure the total and static pressure components 

of air flow. Pulverized fuel flow is determined by measuring the mass flow distribution 

and transport velocity of the fuel in the pipelines from the mill to the individual burners. 

The precise technology used for the measurements varies depending on the specific 

vendor. 

Air and coal monitoring equipment can be integrated into the plant control system 

to provide a level of automatic adjustments within a predetermined operational zone. The 

system can be fine tuned to control individual burner stoichiometry through a 

combination of manual tuning adjustments and automatic fuel flow and air flow 

adjustments. 

3.1.3 Upgraded Low NOx Burners and Existing OFA System Operation 

 NOx reduction can be increased by combining upgrades to the LNBs and 

operating the OFA system. These technologies are described in Subsections 3.1.1 

and 3.1.2. 

3.1.4 Upgraded Low NOx Burners and Existing OFA System Operation 

and Selective Non-Catalytic Reduction 

LNBs, OFA, and SNCR technologies can be combined to provide an overall 

reduction in NOx emissions. These technologies are described in Subsections 3.1.2, 

3.1.1, and 3.1.8, respectively. 
 Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

110207 3-5 

3.1.5 New Low NOx Burners and Modified OFA System 

This alternative includes the addition of new LNBs with modified OFA 

technologies close-coupled to provide an overall performance and emissions reduction 

better than those of the upgraded LNBs and existing OFA system alternative. The 

difference in the scope of work is the complete replacement of the existing LNBs and 

OFA ports. 

The scope also may include the replacement of the existing manual controls of the 

OFA dampers with automated controls; the replacement of existing OFA dampers with 

dual air zone OFA ports; enhanced fuel distribution to the burners using rotating 

classifiers in the pulverizers; enhanced fuel control by installing instrumentation and 

dampers in coal conduits; neural networks, or operational modifications such as reduced 

excess air or biased firing. 

A diagram illustrating the staged combustion of LNBs and OFA is illustrated on 

Figure 3-1. 

Figure 3-1 

Staged Combustion of Low NOx Burners and Overfire Air System 

3.1.6 New Low NOx Burners, Modified OFA, and Selective Non-Catalytic 

Reduction 

New LNBs, OFA, and SNCR technologies can be combined to provide an overall 

reduction in NOx emissions. These technologies are described in Subsections 3.1.5 and 

3.1.8, respectively. When combined with new LNBs and OFA, the effectiveness of 

SNCRs at reducing NOx is diminished to approximately 20 percent. 

Overfire 

Air 
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3.1.7 New Low NOx Burners, Modified OFA, and Selective Catalytic 

Reduction 

The new LNBs and modified OFA system are described in Subsection 3.1.5. 

SCR systems are widely used for achieving post-combustion reductions in NOx

emissions. In SCR systems, vaporized ammonia (NH3) injected into the flue gas stream 

acts as a reducing agent, achieving NOx emission reductions when passed over an 

appropriate amount of catalyst. The NOx and ammonia reagent react to form nitrogen 

and water vapor. The reaction mechanisms are very efficient, with a reagent 

stoichiometry of approximately 1.05 (on a NOx reduction basis) and with low ammonia 

slip (unreacted ammonia). A simplified schematic diagram of a typical SCR reactor 

utilizing aqueous ammonia injection is illustrated on Figure 3-2. 

The SCR reactor is the housing for the catalyst. The reactor is basically a 

widened section of ductwork modified by the addition of gas flow distribution devices, 

catalyst, catalyst support structures, access doors, and sonic horns/soot blowers. An 

ammonia injection grid is located upstream of the SCR reactor. The SCR reactor is 

typically elevated above and upstream of the air heater and particulate emissions control 

equipment (typically an ESP). Gas flow direction through the reactor is vertically downward for coal fired applications. In a “high-dust” SCR arrangement, the reactor is located 

between the outlet of the economizer and the inlet of the air heater. The high-dust system 

is typically the most economical and preferred arrangement where physically possible. 

From a design standpoint, the SCR ammonia-catalytic reaction requires a 

temperature range of 600-750o F to be effective. As such, the SCR must be located after 

the convective pass of the boiler but before the air preheater. For the Boardman plant, the 

temperature of the hot combustion gases exiting the boiler before entry to the air 

preheater is well in excess of 800o F. The Boardman boiler was not designed with space 

in the ductwork or with an appropriate temperature profile for a future SCR. Very 

challenging and complex modifications to the boiler will be required to lower the gas 

path temperature to the desired range while still maintaining the air temperature exiting 

the air preheater to the pulverizer in order to properly dry the coal and maintain 

combustion efficiency. The costs of such modifications are expected to be substantial, up 

to approximately $40 million dollars. 

The oxidation of SO2 to SO3 could also require moderate air heater modifications 

since the acid dew point temperature of the flue gas is directly related to SO3

concentration. As the SO3 concentration increases, the acid dew point of the flue gas 

increases, potentially increasing corrosion in downstream equipment or possibly 

requiring an increase in the air heater gas outlet temperature. 
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Figure 3-2 

Schematic Diagram of a Typical SCR Reactor 

The ammonia reagent for the SCR systems can be supplied by anhydrous 

ammonia, aqueous ammonia, or by conversion of urea to ammonia. Since the ammonia 

is vaporized prior to contact with the catalyst, the selection of ammonia type does not 

influence the catalyst performance. However, the selection of ammonia type does affect 

other subsystem components, including reagent storage, vaporization, injection control, 

and balance-of-plant requirements. The vast majority of worldwide installations use 

anhydrous ammonia. 

SCR systems have a variety of interfacing system requirements to support 

operations. These requirements predominantly relate to draft, auxiliary power, soot 

blowing steam, gas temperature, controls, ductwork, reactor footprint, and air heater. The 

SCR system will affect the boiler draft system. Depending on arrangement and 

performance requirements, draft losses can range from 4 to 10 in. wg, requiring the 

addition of ID booster fans. If necessary, ductwork and/or boiler box reinforcement may 

also be required. Auxiliary power modifications may also be necessary for the fan 

modifications and for ammonia supply system requirements. 

The major impact of the SCR system can be seen at the air heater, where there are 

two areas of concern. One concern is the formation and deposition of ammonium 

bisulfate on the air heater surface. This will cause an increase in the pressure drop of the 

air heater, degrade its performance, and decrease plant efficiency. The other potential 
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danger for the air heater is high concentrations of SO3 in the flue gas. If the acid dew 

point temperature has been increased to more than the exhaust temperature, a significant 

amount of acid gases will condense in the air heater and lead to pluggage and corrosion. 

Several measures can be taken to avoid or correct this situation. Most important is the 

right composition of the catalyst to minimize the SO2 to SO3 conversion rate. 

The effectiveness of the SCR system in a high-dust application is limited by ash 

fouling of the catalyst. Continuous heavy soot blower cleaning is required, which results 

in temperature cycles in the air heater and boiler. It can also erode the catalyst. The 

activity of the catalyst degrades over time even with cleaning. As the catalyst becomes 

deactivated, more ammonia must be injected to maintain NOx reduction levels. This 

results in an increased amount of ammonia slip and ammonia bisulfate fouling of the air 

heaters. 

For many units, the use of NLNB/MOFA along with SCR has been utilized. It 

should be noted that in the case of a new unit, the SCR can be designed for optimum 

performance with long residence times. The economizer outlet duct can also be designed 

for an optimum SCR arrangement. On an existing unit however, the ability to install an 

“optimum” arrangement for an SCR is limited by the existing plant and unit specific 

conditions and restrictions. SCRs as stated previously are located between the 

economizer and the air heater for a high dust arrangement. This is typically a very 

congested area of the plant. Plant equipment (such as fans, boiler support steel, and 

underground utilities) restrict the possible ductwork arrangements as well as increase the 

complexity of the retrofit. SCR performance is highly dependant on having even flow 

distribution into the ammonia injection grid and the catalyst. Due to these reasons, the 

expected outlet emission rate controlled by the SCR will not be significantly decreased 

by a lower SCR inlet NOx. The use of NLNB/MOFA however will minimize SCR out of 

control conditions and reduce the amount of ammonia injection (not ammonia slip) while 

basically achieving the same outlet emission rate for the Boardman unit. 

3.1.8 Selective Noncatalytic Reduction 

SNCR systems reduce NOx emissions by injecting a reagent at multiple levels in 

the boiler, as illustrated on Figure 3-3. SNCR systems rely solely on reagent injection, 

rather than a catalyst, and an appropriate reagent injection temperature, good reagent/gas 

mixing, and adequate reaction time to achieve NOx reductions. SNCR systems can use 

either ammonia or urea as the reagent. Ammonia or urea is injected into areas of the 

steam generator where the flue gas temperature ranges from 1,500 to 2,200° F. The 

furnace of a pulverized coal fired boiler operates at temperatures between 2,500 to 

3,000° F. 
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SNCR systems are capable of achieving a NOx emissions reduction as high as 50 

to 60 percent in optimum conditions (adequate reaction time, temperature, and reagent/ 

flue gas mixing, high baseline NOx conditions, multiple levels of injectors) with ammonia 

slips of 10 to 50 ppmvd. Lower ammonia slip values can be achieved with lower NOx

reduction capabilities. Typically, optimum conditions are difficult to achieve, resulting in 

emissions reduction levels of 20 to 25 percent for retrofit applications. Potential 

performance is very site-specific and varies with fuel type, steam generator size, 

allowable ammonia slip, furnace CO concentrations, and steam generator heat transfer 

characteristics. 

SNCR systems reduce NOx emissions using the same reduction mechanism as 

SCR systems. Most of the undesirable chemical reactions occur when reagent is injected 

at temperatures above or below the optimum range. At best, these undesired reactions 

consume reagent with no reduction in NOx emissions, while, at worst, the oxidation of 

ammonia can actually generate NOx. Accordingly, NOx reductions and overall reaction 

stoichiometry are very sensitive to the temperature of the flue gas at the reagent injection 

point. This complicates the application of SNCRs for boilers larger than 100 MW. 

Combustion Air

Injection

Level 2

Injection

Level 3

Burners

Steam Generator

Air Heater

Injection Level 1

Flue

 Gas

Ammonia or 

Urea Storage Tank

Figure 3-3 

Schematic of SNCR System with Multiple Injection Levels 

The NOx reduction potential of SNCR systems is limited by boiler geometry and 

temperature profiles (which vary as a function of load) that affect reagent and flue gas 

mixing. For large boilers, the design challenge is to achieve appropriate residence times 
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(in excess of 1 second) in the optimum temperature range (1500 to 2200o F). For an 

existing boiler, waterwall and steam piping modifications would be necessary to 

accommodate the installation of SNCR reagent injectors. Multiple levels of steam-cooled 

reagent injectors or lances would be required. For existing boilers, the convection pass is 

very congested for optimum SNCR system operation. Without extensive modifications, 

this could lead to limited NOx reduction capabilities. SNCR systems also tend to have 

higher ammonia slip, which fouls air heater surfaces. 

3.1.9 SNCR/SCR Hybrid (Cascade) 

The SNCR/SCR hybrid system uses components and operating characteristics of 

both SNCR and SCR systems. Hybrid systems were developed to combine the low 

capital cost and high ammonia slip associated with SNCR systems with the high 

reduction n potential and low ammonia slip inherent in the catalyst of SCR systems. The 

result is a NOx reduction alternative that can meet initially low NOx reduction 

requirements but can be upgraded to meet higher reductions at a future date, if required. 

The SNCR component of the hybrid system is identical to the SNCR system 

described previously, except that the hybrid system may have more levels of multiple 

lance nozzles for reagent injection. This will increase the capital cost of the SNCR 

component of the hybrid system. During operation, the SNCR system would be allowed 

to inject higher amounts of reagent into the flue gas. This increased reagent flow has a 

twofold effect: NOx reduction within the boiler is increased while ammonia slip also 

increases. The ammonia that slips from the SNCR is then used as the reagent for the 

catalyst. 

There are two design philosophies for using this excess ammonia slip. The most 

conservative hybrid systems use the catalyst simply as an ammonia slip “scrubber” with 

some additional NOx reduction. As with in-duct systems, the flue gas velocity through 

the catalyst is an important factor in design. Operating in this mode allows maximum 

NOx reduction within the boiler by the SNCR, while minimizing the catalyst volume 

requirement. While some NOx reduction is realized at the catalyst, the relatively small 

catalyst requirement of this design can potentially allow the retrofit of all the catalyst in a 

true in-duct arrangement with no significant ductwork changes, arrangement interference, 

or structural modifications. The second philosophy uses adequate catalyst volume to 

obtain significant levels of additional NOx reduction. The additional reduction is a 

function of the quantity of ammonia slip, catalyst volume, and distribution of ammonia to 

NOx within the flue gas. Using ammonia slip produced by the SNCR system is not a high 

efficiency method of introducing reagent, because of the low reagent utilization discussed 

as a part of the SNCR. Therefore, even though the reaction at the catalyst requires 1 ppm 
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of ammonia to remove 1 ppm of NOx, the SNCR must inject at least 3 ppm of ammonia 

to generate 1 ppm of ammonia at the catalyst. 

Catalyst volume is strongly influenced by the NOx reduction required and the 

ammonia distribution. The impact of catalyst volume on the design of a hybrid system is 

on the size of the reactor required to hold the catalyst. If multiple levels of catalyst 

operating at low flue gas velocity are required, some modifications will be required to the 

existing ductwork. If widening the ductwork cannot provide adequate catalyst volume, 

then a separate reactor is required, which quickly reduces the capital cost advantage of a 

hybrid system. 

As described in Subsection 3.1.7, the SCR catalyst reaction occurs within the 

temperature range of 600 to 750° F. As such, the catalyst must be located after the 

convective pass of the boiler but before the air preheater. For the Boardman plant, the 

temperature of the hot combustion gases exiting the boiler before entry to the air 

preheater is well in excess of 800o F. The Boardman boiler was not designed with space 

in the ductwork or with an appropriate temperature profile for a future SCR. Very 

challenging and complex modifications to the boiler will be required to lower the gas 

path temperature to the desired range while still maintaining the air temperature exiting 

the air preheater to the pulverizer in order to properly dry the coal and maintain 

combustion efficiency. The costs of such modifications are expected to be substantial, 

negating the capital cost advantage of a hybrid system. 

3.1.10 Mobotec ROFA and ROTAMIX 

Mobotec provides a NOx reduction system that combines LNB, OFA, and SNCR 

technologies into an integrated system. The system uses a modified OFA system with 

mixing characteristics achieved through adding a rotation to the OFA. This system is 

called ROFA - Rotating Opposed Firing Air. In addition, ROTAMIX can be added to the 

system; ROTAMIX consists of adding urea or ammonia injection into the ROFA air 

nozzles. The extra mixing produced by combining the OFA nozzles with the reagent 

injection can result in additional NOx reduction because of a homogeneous temperature 

profile in the boiler. A simplified process flow diagram of the ROFA and ROTAMIX 

system is illustrated on Figure 3-4. 
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Figure 3-4 

Mobotec ROFA and ROTAMIX Simplified Process Flow Diagram (Mobotec USA). 

3.1.11 NOxStar and NOxStar Plus 

NOxStar is the trademarked name for a NOx control technology that involves the 

injection of ammonia and a hydrocarbon (typically natural gas) into the flue gas path of a 

coal fired boiler at around 1,600 - 1,800o F for reduction of NOx. The ammonia reduces 

NOx through an SNCR reaction with the hydrocarbon; this reaction minimizes the 

ammonia slip. This arrangement enables higher reagent injection rates for NOx

reductions than achievable with a typical SNCR technology. The technology supplier 

claims the ability to achieve NOx emissions of less than 0.20 lb/MMBTU without the use 

of a catalyst and large SCR reactor. Although initially targeting high NOx reductions, full 

scale demonstrations to date have been limited to nominally 50 percent NOx reduction 

performance. 

NOxStar eliminates the need to install a solid catalyst layer and the associated 

problems of chemical poisoning, physical plugging, sintering due to temperature 

excursions, pressure drop requiring new ID fans, and disposal of a hazardous solid waste. 

The other advantage of the NOxStar system is that the conversion of SO2 to SO3 is said to 

be negligible, thus eliminating one of the main drawbacks of the SCR technology. 

The major consideration for the NOxStar technology is that it currently has only 

one major installation in the United States and may require the installation of a single 

layer of in-duct catalyst (NOxStar Plus) to achieve the advertised levels of NOx reduction. 

In addition, through recent discussions, the supplier has identified limited ability and 

willingness to market the commercial technology. 

3.1.12 ECOTUBE 

The ECOTUBE system utilizes retractable lance tubes that penetrate the boiler 

above the primary burner zone and inject high-velocity air as well as reagents. The lance 
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tubes work to create turbulent airflow and to increase the residence time for the air/fuel 

mixture. In principle, the OFA and SNCR processes are combined in this technology. 

ECOTUBE is capable of reducing NOx, while improving thermal efficiency, by 

optimizing the combustion process in boilers. An illustration of the ECOTUBE 

installation in a typical boiler is shown on Figure 3-5. 

The water-cooled ECOTUBEs are automatically retracted from the boiler on a 

regular basis and cleaned to remove layers of soot and other deposits. Additional benefits 

have been identified by the supplier in terms of furnace combustion improvements that 

increase efficiency, reduce fuel usage, and reduce corrosion and erosion in the boiler and 

backend equipment. 

Figure 3-5 

ECOTUBE Installation in a Boiler 

3.1.13 Induced Flue Gas Recirculation 

Injection of flue gas into the combustion air is a proven method for controlling 

NOx production from gas-fired utility boilers. For units not equipped with gas 

recirculation fans, flue gas can be injected into the combustion air by a technique known 

as induced flue gas recirculation (IFGR). 

IFGR acts to reduce NOx formation by reducing peak flame temperatures. In 

conventional applications, the recirculated flue gas is typically extracted from the boiler 

outlet duct upstream of the air heater. The flue gas is then returned through a separate 

duct and hot gas fan to the combustion air duct that feeds the windbox. The recirculated 

flue gas is mixed with the combustion air via air foils or other mixing devices in the duct. 

This technology is known as windbox FGR (WFGR). WFGR systems require 

installation of a separate hot gas FGR fan to move flue gas from the boiler exit to the air 
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supply ducting at the windbox inlet, where uniform mixing of the air and flue gas must be 

achieved by installation of appropriate mixing devices. 

3.1.14 LoTOx 

The LoTOx technology is the low temperature gas-phase oxidation of NOx by 

ozone injection. In this method, ozone is injected into the flue gas upstream of a wet 

FGD system. The ozone reacts with the NO and NO2 to form nitrogen pentoxide (N2O5). 

The N2O5 formed is soluble in water and can be removed from the flue gas using a wet 

FGD system. 

The LoTOx technology has been demonstrated on several industrial sized plants. 

In May 2002; the technology was used at Abitibi Consolidated (Sheldon, Texas), a paper 

recycling plant. The Ohio Coal Development Office funded a $6.3 million LoTOx unit at 

the Medical College of Ohio, and there have been several refinery applications. 

The LoTOx technology offers high NOx removal efficiency with a reported 

potential of 15 to 25 percent savings in capital cost over an SCR system. The major 

drawbacks of this system are the lack of experience on larger power generating units, 

high power consumption, and the production of nitrates. 

The high auxiliary power consumption from the multiple ozone generators 

required to produce the ozone for the process is expected to be comparable to what is 

needed for a conventional FGD system and is significantly higher than the power 

consumption from an SCR. The nitrate production from this technology is captured in 

the FGD waste product, possibly requiring the need for a wastewater treatment plant. 

3.1.15 Natural Gas Reburn 

The natural gas reburning process employs three separate combustion zones to 

reduce NOx emissions, as illustrated on Figure 3-6. The first zone consists of the normal 

combustion zone in the lower furnace, which is formed by the existing wall burners. In 

this zone, 75 to 80 percent of the total fuel heat input is introduced. The first zone 

burners are operated with about 10 percent excess air (a 1:10 stoichiometric ratio). A 

second combustion zone (the reburn zone) is created above the lower furnace by 

operating a row of conventional natural gas burners at a stoichiometric ratio less than 1.0. 

This technology also has the potential for increased furnace corrosion (especially with 

higher sulfur fuels) because of the reducing atmosphere in the lower furnace. 

The substoichiometric reburn zone causes NOx produced in the lower furnace 

units to be reduced to molecular nitrogen and oxygen because the oxygen stripped from 

the NOx molecules is combined with the more active CO molecules to form carbon 

dioxide as combustion is completed in the upper furnace. Fuel burnout is completed in 

the third zone (the burnout zone) by the introduction of OFA. Sufficient OFA is 
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introduced to complete combustion of the unburned materials in the upper furnace with 

an overall excess air rate for the boiler of 15 to 20 percent. Reburn technology has 

demonstrated NOx reduction of 40 to 65 percent. 

Sufficient residence time (adequate furnace height) in the reburn and OFA zones 

is a key factor in determining whether the reburning technology can be applied. 

Successful retrofit of this technology requires space within the boiler to allow adequate 

residence time for both the additional burning zone (0.4 to 0.6 second) and the associated 

OFA burnout zone (0.6 to 0.9 second). When this space is available, reburning can be 

highly effective, but a low residence time will limit system performance. Also, the high 

cost of natural gas makes the annual operating costs of this technology prohibitive. 

Burnout Zone

•Normal Excess Air

Reburning Zone

•Slightly Fuel Rich

•NOx Reduced to N2

Primary Combustion

Zone

•Reduced Firing Rate

•Low Excess Air

•Lower NOx

Overfire Air

40 to 60% NOx Reduction

10 to 20 % Gas

Fuel Rich

80 to 90% Coal

10% Excess Air

Figure 3-6 

Schematic of Gas Reburn System 

3.1.16 New LNBs, Modified OFA, and SNCR 

NOx reduction can be increased by combining new LNBs, modified OFA, and 

SNCR. The new LNBs, modified OFA, and SNCR are described in Subsections 3.1.5 

and 3.1.11. 

3.2 SO2 Control Technologies 

 The following SO2 control technologies were identified as available for retrofit at 

the Boardman Plant are summarized in Subsections 3.2.1 through 3.2.4: 

• Wet FGD. 
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• Semi-dry FGD. 

• Dry FGD (Circulating Dry Scrubber [CDS]). 

• Furnace/duct reagent injection. 

3.2.1 Wet Flue Gas Desulfurization 

Although wet lime and ammonia FGD systems are available, the wet limestone 

FGD process is the most frequently applied FGD technology in the United States when 

treating flue gas from combustion of medium- and high-sulfur coals (typically greater 

than 1.5 percent sulfur). Wet limestone FGD systems are also applicable for units 

burning low-sulfur bituminous and subbituminous coals. Wet limestone FGD systems 

are capable of achieving slightly higher SO2 removal than other types of FGD systems 

but have not demonstrated significant removal of elemental mercury. A typical wet 

limestone FGD system consists of reagent storage and handling system, FGD spray tower 

absorber, and byproduct dewatering system as illustrated on Figure 3-7. 
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Reaction Tank

Recycle

Pumps

Mist

Eliminators

To

Chimney

From

Booster

Fans

Reagent and

Makeup Water

Byproduct

Solids to

Dewatering Oxidation Air

Agitators

Figure 3-7 

Process Flow Diagram of a Spray Tower Wet FGD System. 

For most wet limestone FGD applications, the absorber module is located 

downstream of the ID fans (or booster ID fans, if required). For a wet FGD system, the 

flue gas enters the absorber and is contacted with a slurry containing reagent and 

byproduct solids. The SO2 is absorbed into the slurry and reacts with the calcium to form 

CaSO3•1/2H2O and CaSO4•2H2O. 

There are several types of absorber modules, and each has characteristic 

advantages and disadvantages. FGD equipment vendors have specific designs for one or 

more types, and all compete on a capital/operating cost and guarantee basis. Depending 

on the process vendor, the absorber may be a co-current or countercurrent spray tower, 

with or without internal packing or trays. Other vendors use a unique absorber where the 

flue gas is bubbled into a reaction tank, as illustrated on Figure 3-8. Regardless of the 
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type of absorber used, the flue gas leaving the absorber is saturated with water and the 

stack will have a visible, persistent moisture plume. Generally, wet FGD systems do not 

remove significant quantities of SO3 from the flue gas. Condensed SO3, in the form of 

sulfuric acid mist (H2SO4), can be removed with a WESP, which is discussed in 

Subsection 3.3.6. 

Figure 3-8 

Cutaway View of a Jet Bubbling Reactor Wet FGD System 

Because of the chlorides present in the mist carryover from the absorber and the 

pools of low pH condensate that can develop, the conditions downstream of the absorber 

are highly corrosive to most materials of construction. Highly corrosion-resistant 

materials are required for the downstream ductwork and for the stack flue. Careful 

design of the stack is needed to prevent “rainout” from condensation that occurs in the 

downstream ductwork and stack. 

The reaction byproducts are typically dewatered by a combination of hydrocyclones and vacuum filters. For natural oxidation wet limestone FGD systems, the 

resulting filter cake is suitable for landfill disposal. In some instances, the FGD 

byproduct requires mixing with fly ash and/or lime (fixation) to produce a physically 

stable material. 
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If air is bubbled through the reaction tank, practically all of the CaSO3•1/2H2O 

can be converted to CaSO4•2H2O, which is commonly known as gypsum. This oxidation 

step is termed “forced oxidation.” Compared to calcium sulfite, gypsum has much 

superior dewatering and physical properties, and forced-oxidized systems tend to have 

few scaling problems in the absorber and mist eliminators. Dewatered gypsum can be 

landfilled without stabilization or fixation. Many wet FGD systems in the United States 

are using the forced-oxidation process to produce commercial grade gypsum that can be 

used in the production of portland cement or wallboard. Marketing of the gypsum can 

eliminate or greatly reduce the need to landfill FGD byproducts. 

The wet FGD processes are characterized by high efficiency and high reagent 

utilization. The absorber vessels are fabricated from corrosion-resistant materials such as 

epoxy/vinylester-lined carbon steel, rubber-lined carbon steel, stainless steel, or 

fiberglass. The absorbers handle large volumes of abrasive slurries. The reagent 

handling and byproduct dewatering equipment is also relatively complex and expensive. 

These factors result in relatively higher initial capital costs and lower annual operating 

costs compared to the semi-dry FGD alternatives. 

3.2.2 Semi-Dry Flue Gas Desulfurization 

The semi-dry FGD process is based on the spray drying of lime slurry into flue 

gas. This is performed in a spray dryer absorber (SDA). There are numerous SDA FGD 

system installations on boilers using low-sulfur fuels. These installations, primarily 

located in the western United States, use either lignite or subbituminous coals as boiler 

fuel and generally have spray dryer systems designed for a maximum fuel sulfur content 

of less than 2 percent. 

There are several variations of this process, but the most prevalent is the 

installation of one or more spray dry vessels upstream of a supplied particulate control 

device, as shown on Figures 3-9 and 3-10. For new plants, the SDA absorber vessel is 

located between the air heater and the particulate removal device, most commonly a 

PJFF. For the Boardman Plant, the SDA absorber vessel and PJFF would be located 

downstream from the existing ID fans. 

Although either quicklime slurry (CaO) or a sodium carbonate (soda ash) solution 

may be used as the scrubbing reagent, the current generation of SDA FGD processes uses 

primarily quicklime. The quicklime is first slaked with water to form a calcium 

hydroxide (Ca(OH)2) slurry. The lime slurry is combined with the recycled solids from 

the PJFF to form the reagent slurry. The reagent slurry is injected into the absorber using 

either a rotary or dual-fluid atomizer, where the lime reacts with the SO2 in the flue gas. 

Sufficient water is added to the reagent slurry to lower the flue gas temperature to within 
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32 to 40°F of the adiabatic saturation temperature. The SO2 is absorbed into the fine 

spray droplets and reacts with the lime slurry to form both calcium sulfite (~1/3) and 

calcium sulfate (~2/3). Before the droplets can reach the wall of the vessel, the heat of 

the flue gas evaporates the droplets to dry particles containing the byproduct solids and 

excess reagent. As the reagent slurry evaporates, a relatively dry powder remains. 

Figure 3-9 

Spray Dryer System. 

The byproduct solids and fly ash are collected in the PJFF. The PJFF is always 

supplied as a system along with the SDA. The PJFF is an integral component of the SO2

removal system, since a significant percentage of removal occurs as the flue gas passes 

through the dust cake on the bags. The vendor guarantee is based on the total removal as 

measured at the exit of the PJFF. The PJFF is also an integral component of the mercury 

removal system. The PJFF will be designed to collect the SDA byproducts along with 

mercury and activated carbon sorbent. 

The byproducts and fly ash are conveyed pneumatically to the fly ash silo in the 

conventional manner. These solids are unloaded, conditioned with water, and transported 

to a landfill. Because of the level of free lime in the byproduct solids, the byproduct/fly 

ash mixture attains a very high bearing strength and low permeability in the landfill. 

Unlike a wet limestone FGD system, there is currently no commercial use for the 

byproduct/fly ash. 
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Figure 3-10 

SDA FGD System 

3.2.3 Circulating Dry Scrubber 

CDS is a form of dry FGD for SO2 removal. Hydrated lime (Ca[OH]2) is the 

reagent used; it is introduced as a dry, free flowing powder into the scrubber vessel. Flue 

gas is then flowed through the lime reagent in a circulation pattern for adsorption of SO2

by the lime. A schematic of the process flow of a CDS process is shown on Figure 3-11. 

Generally, there are no constraints on the maximum fuel sulfur content; the CDS 

can be adjusted to account for the higher SO2 loading by increasing the concentration of 

reagent. However, this flexibility is limited by the cost of the lime reagent. An 

evaluation on the overall reagent cost is important before selecting this technology. Lime 

utilization is improved by cooling the flue gas before it reacts with the lime. Flue gas 

coming into the scrubber vessel is cooled to about 30o

 F above the adiabatic saturation 

temperature. 
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HYDRATED 

LIME SILO CDS ESP

H2O

FLY

ASH

SILO

FLUE GAS DUCT

TO ID

FANS

TO

LANDFILL

Figure 3-11 

Circulating Dry Scrubber System (Lurgi Lentjes North America) 

As is the case with the SDA, a downstream particulate collection device is 

required, usually an ESP or FF, for the removal of PM from the ash in the coal and the 

product of the reaction of lime with the SO2 in the flue gas. Because of the relatively 

high velocity of the flue gas through the scrubber vessel (approximately 19 ft/s), the 

treated flue gas carries entrained reagent and reaction products from the module to the 

downstream particulate control device. 

Over 90 percent of the collected solids in the ESP or FF contain unreacted lime. 

Because of abrasion and impacts of the other particles in the flue gas as well as material 

handling dynamics, the “shell” of reaction products on the reagent particles is broken up. 

This material is recycled into the scrubber vessel to further improve lime utilization. This 

solids recirculation also maintains the bed densities needed for contact and removal of 

SO2. Typically, reagent is recirculated 35 to 50 times, providing a residence time of 30 

minutes or more. Collected solids, which are not recirculated, are disposed of. 

The CDS is a small vessel; the associated ESP or FF is in an elevated location 

because flue gas travels upwards in a CDS vessel. This arrangement results in a smaller 

footprint for applications with space constraints. However, depending on the site 

situation, the retrofit of such a system might be costly, especially if there are substantial 

construction and structural difficulties. 

Disadvantages of this process include high dust loading at the particulate removal 

system and lack of US utility operating experience in the size range of the Boardman 
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Plant. Higher FF pressure drops are encountered because of the flue gas dust loading, 

thus ESPs are preferred for particulate removal. The high particulate loadings make 

sizing of the ESP critical to ensure compliance with particulate emission requirements. 

3.2.4 Furnace/Duct Reagent Injection 

Furnace and duct reagent injection systems require either a wet or dry reagent 

such as sodium bicarbonate, powdered lime, hydrated lime, lime slurry, limestone or 

Mg(OH)2 to remove SO2. This technology is typically capable of removing between 20 

to 50 percent of the SO2 in the flue gas, and its removal efficiency is highly dependent on 

the application, primarily the configuration of the existing ductwork and the flue gas 

residence time in the ductwork. 

Because of the type of reaction, temperature, percentage reduction rate, and the 

corresponding retention time requirements, a dry reagent such as powdered lime and 

hydrated lime are preferred for furnace injection applications. A wet reagent, such as 

lime slurry, sodium bicarbonate, or Mg(OH)2, is typically preferred for duct injection 

applications because of the removal requirements and the flue gas properties. 

The use of a wet reagent for duct injection is preferred over a dry reagent because 

of the elevated gas temperatures that exist during normal operating conditions. The use 

of a wet reagent upstream of an existing ESP will help reduce the gas temperature, 

improve ESP performance for opacity and particulate control, and eliminate the need for 

additional ID booster fans for additional draft control. 

CFD and chemical kinetic modeling may be necessary to determine which reagent 

is preferred; the preferred location of reagent injection; the amount of SO2 emissions 

removed; and whether furnace injection, duct injection, or both furnace/duct injection 

systems are required for effective removal. Unit design and operational data will be 

collected for the CFD computer model inputs. This data, combined with unit mapping 

information, will enable the model to develop precise injection locations and reagent 

injection characteristics for each boiler. 

The major components of a typical reagent injection system include an air 

compressor, chemical storage tank, heat tracing, controls, injection system (e.g., flanges, 

lances, nozzles, hoses, hardware, etc.), injection platform, and slurry pump. 

Furnace injection can reduce or eliminate fireside slagging, fouling, corrosion, 

and erosion problems in the furnace. Other benefits of various efficiency improvements 

include savings through greater heat transfer cleanliness, reduction of periodic air heater 

replacement, increase in overall unit reliability, reduction of boiler cleaning costs, and, 

ultimately, the extension of unit runs to the point where only scheduled outages are taken. 
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3.3 PM Control Technologies 

 The following PM control technologies were identified as available for retrofit at 

the Boardman Plant and are summarized in Subsections 3.3.1 through 3.3.6: 

• Existing ESP with operational restrictions. 

• PJFF. 

• Compact Hybrid Particulate Collector (COHPAC). 

• GE MAX-9 hybrid. 

• Multi-cyclone 

• WESP. 

3.3.1 Existing ESP with Operational Restrictions 

The Boardman Plant is currently equipped with a cold-side ESP. To improve the 

performance of the ESP to achieve lower PM emissions than the current permitted limit, 

operational restrictions such as minimizing the range in characteristics of the type of coal 

burned at the unit and increased use of the flue gas conditioning system could 

consistently produce slightly lower PM emissions. Additionally, other ESP 

improvements may be considered to improve its particulate capture capability. 

3.3.2 Pulse Jet Fabric Filter 

FFs are media filters that the flue gas passes through to remove the particulate. 

Reduced particulate emissions limits and the selection of low-sulfur fuels has promoted 

the use of FFs for the last 15 years. 

 Cloth filter media is typically sewn into cylindrical tubes called bags. Each FF 

unit may have thousands of these filter bags. The filter unit is typically divided into 

compartments that allow online maintenance or bag replacement. The quantity of 

compartments is determined by maximum economic compartment size, total gas volume 

rate, air-to-cloth (A/C) ratio, and cleaning system design. Each compartment includes at 

least one hopper for temporary storage of the collected fly ash. A cut-away view of a 

PJFF compartment is illustrated on Figure 3-12. 

 Fabric bags vary in composition, length, and cross section (diameter or shape). 

Bag selection characteristics vary with cleaning technology, emissions limits, flue gas 

and ash characteristics, desired bag life, capital cost, A/C ratio, and pressure differential. 

Fabric bags are typically guaranteed for 3 years. 
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Figure 3-12 

Pulse Jet Fabric Filter Compartment (Babcock & Wilcox) 
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In PJFFs, the flue gas typically enters the compartment hopper and passes from 

the outside of the bag to the inside, depositing particulate on the outside of the bag. To 

prevent the collapse of the bag, a metal cage is installed on the inside of the bag. The 

flue gas passes up through the center of the bag into the outlet plenum. The bags and 

cages are suspended from a tube sheet. 

Cleaning is performed by initiating a downward pulse of air into the top of the 

bag. The pulse causes a ripple effect along the length of the bag. This releases the dust 

cake from the bag surface. The dust then falls into the hopper. This cleaning may occur 

with the compartment online or offline. Care must be taken during design to ensure that 

the upward velocity between the bags is minimized so that particulate is not re-entrained 

during the cleaning process. The PJFF cleans bags in sequential, usually staggered, rows. 

During online cleaning, part of the dust cake from the row being cleaned may be captured 

by the adjacent rows. Online PJFF cleaning has been successfully implemented on many 

large units and is a standard feature of the technology. 

3.3.3 Compact Hybrid Particulate Collector 

Another control technology that is effective in removing particulate is a high A/C 

ratio FF installed after an existing cold-side ESP. Commonly referred to as a COHPAC, 

this technology was developed and trademarked by the Electric Power Research Institute 

(EPRI). The COHPAC filter typically operates at A/C ratios ranging from 6 to 8 ft/min., 

compared to a conventional FF that typically operates at A/C ratios of about 4 ft/min. 

The majority of the particulate is collected in the upstream ESP. Therefore, the 

performance requirements of a high A/C ratio FF is reduced, allowing installation of this 

technology in a smaller footprint area and with less steel and filtration media, which 

substantially lowers both capital and operating costs compared to conventional FFs. 

3.3.4 GE MAX-9 Hybrid 

The Max-9 electrostatic filter is a hybrid combination of a high-efficiency PJFF and an 

ESP without collecting plates. A front and side elevation view of the Max-9 particulate 

filter is illustrated on Figure 3-13. When the dust particles are charged, they are attracted 

to the grounded metal cage inside the filter element, just as they would be attracted to the 

collecting plates in an ordinary precipitator. Since the particles are positively charged, 

they repel each other on the surface of the filter, making the collected dust cake very 

porous. This results in a reduction of filter drag at a pressure drop about 25 percent of a 

normal FF. Consequently, the Max-9 can operate at an A/C ratio higher than a 

conventional FF and can treat a significant gas volume with a smaller footprint. 
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Figure 3-13 

Max-9 Electrostatic Filter 
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Process gas enters the Max-9 from a hopper inlet duct. The gas then flows 

upward through the filters and out through the top of the filters. The area above the tube 

sheet is a clean gas plenum. Compressed air pulses are used to clean the filters. A brief, 

intense blast of air is fired through the purge air manifold; holes in the blowpipes located 

above the filters direct the cleaning air pulse down through the filters. The cleaning 

sequence is controlled by timers that trigger solenoids. The high voltage system operates 

at very low current densities and at a steady state. There is no danger of fire caused by 

sparking, and the transformer/rectifier requires no voltage control. 

The Max-9 can be supplied as shop-assembled modules that can be erected on 

site, although the units are usually custom-engineered for each plant site and application 

to make the best use of available space. 

3.3.5 Multiple-Cyclone Separators 

Multiple-cyclone separators, also known as multiclones, consist of a number of 

small-diameter cyclones, operating in parallel and having a common gas inlet and outlet, 

as shown on Figure 3-14. Multiclones operate on the same principle as cyclones--

creating a main downward vortex and an ascending inner vortex. Multiclones are more 

efficient than single cyclones because they are longer and smaller in diameter. The 

longer length provides longer residence time, while the smaller diameter creates greater 

centrifugal force. These two factors result in better separation of dust particulates. The 

pressure drop of multiclone collectors is higher than that of single-cyclone separators. 

Cyclone collectors are centrifugal collectors that rely on the particle density and 

velocity to separate the fly ash from the flue gas. The particulate-laden flue gas enters 

the top or the side of the cyclone. An illustration of the components and working 

principles of a multiclone is shown on Figure 3-14. Vanes impart a rotational velocity to 

the flue gas, driving the fly ash to the edge of the cylinder. The flue gas then exits the 

center of the cyclone out the top, leaving the fly ash to fall out the bottom. At pressures 

near one atmosphere and 2 to 5 in. wg pressure differential, this technology can 

effectively remove particles larger than 20 microns in size; particles less than 10 microns 

are usually unaffected and not removed. 
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Figure 3-14 

Multiple-Cyclone Particulate Collector 

3.3.6 Wet ESP 

A WESP collects particles on the same theoretical basis as a dry ESP: negatively 

charged particles are collected on positively charged surfaces. The collecting surfaces 

are wet instead of dry and are flushed with water to remove the particulate. Typically, a 

WESP is installed downstream of an existing wet FGD system where the flue gas is 

already saturated, so the amount of added water is minimized. The particulate collection 

efficiency is enhanced by a lack of re-entrainment after contact with the wet walls (as 

contrasted with re-entrainment due to rapping on a dry ESP). Therefore, the WESP is 

well suited for fine particulate or acid mist applications because it reduces opacity, 

sulfuric acid mist (H2SO4), and other aerosols. 

The use of WESPs for acid mist collection was one of the earliest applications for 

ESPs. Although there are few applications in the utility industry, this is a mature 

technology with hundreds of industrial installations. The particulate characteristics, 

temperature, and humidity in WESPs provide excellent fuel flexibility regarding 

particulate removal. However, water chemistry, scaling, and corrosion potential need to 

be carefully investigated. 

The WESP collecting fields impart a negative charge to the particles and collect 

them on positively charged collecting electrodes. Each collection field is equipped with 

independent electrical bus sections, each of which has a dedicated high voltage 

transformer/rectifier and controller. The controllers for each transformer/rectifier are 

located in an environmentally controlled enclosure. Each electrical field has a separate 

discharge electrode support frame suspended by alumina insulators. A heater-blower 

system dedicated to each module supplies warm purge air for each of the insulator 

compartments. The discharge electrode support frames are constructed from Type 304 
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stainless steel. The discharge electrodes are suspended from the upper guide frame and 

held in the tube center line. The discharge electrode is a rigid electrode constructed from 

304 stainless steel; it contains split corona-generating elements that are welded to the 

electrode in an opposed orientation. 

A WESP can be installed in either horizontal or vertical gas flow orientation. In a 

horizontal gas flow orientation, a WESP is similar to a common dry ESP. The collection 

plates are arranged in parallel horizontal paths with discharge electrodes hanging between 

them. Vertical gas flow WESPs are usually of the tubular collection plate type. The 

collection plates are arranged in an array of vertical pipes or channels with a discharge 

electrode hanging down the center of the pipe or channel. Channel shapes such as 

squares or hexagons have more efficient packing densities than circular pipes (with a 

small loss in the maximum voltage that can be applied before sparking) and are more 

common. Where multiple electrical stages are used (analogous to the electrical fields in a 

horizontal gas flow ESP), the stages are stacked one above the other. Two to three fields 

are common. 

Several major hurdles exist with the use of a WESP. First, the flue gas must be 

saturated with moisture prior to entering the ESP to allow the WESP to work correctly. 

Therefore, a quenching system must be installed to add water to the flue gas to reduce the 

flue gas temperature to the saturation point or the WESP must be installed downstream of 

an existing wet FGD system. Without the presence of a wet FGD system, the use of a 

WESP adds additional cost, increases water demand on the plant, and generates a visible 

moisture plume at the stack outlet. The removed particulate would be contained in a 

wastewater stream that is generated by the WESP. In addition to this issue, the capital 

cost of a WESP is high compared to other technologies because of the higher cost of the 

alloy materials required for the WESP. Higher grades of material are required to 

withstand the highly corrosive conditions presented by the wet and acidic flue gas stream 

that will be collected in the wastewater stream. Alternatively, addition of alkaline 

reagents can be used to neutralize the acid in the wastewater stream. 

Each WESP module is cleaned by spraying flush water over the WESP 

components. Flush water is sprayed in the WESP at different spray levels. It is 

anticipated that each WESP module will be flushed once per day. Individual electrical 

sections of each field may be flushed online while the power is turned off to the electrical 

section being cleaned. 

If the WESP system is installed downstream of a wet FGD system, there is a 

potential for gypsum scale to form because sulfuric acid and calcium may be carried over 

from the scrubber into the WESP. A continuous injection of dispersant into the system 

can be employed to help eliminate scale formation within the module. The dispersant can 
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be stored in a small tank and fed into the flush water surge tank to allow dispersant to 

enter the modules through the spray levels. In addition to this control of the water 

chemistry in the WESP, periodic out-of-service cleaning of a more intense nature might 

be required. Physical cleaning using high-pressure water jets (“hydro lasers”) or 

chemical flushing using an acid based solvent to dissolve the scale buildup are two 

potential options. 

3.4 Emerging Pollution Control Technologies 

Research is ongoing to develop new and improved technologies for multipollutant control. The list of emerging technologies is numerous, and the technologies 

with the most promise include the PowerSpan ECO and Enviroscrub systems. Several 

other promising emerging technologies, such as the Airborne system, are also in the early 

stages of development but are not as far along in pilot testing as the others. Since many 

of these technologies are still at the pilot (slipstream) stage of development, they should 

be viewed with caution until more is known and performance guarantees become 

available. 

3.4.1 PowerSpan 

There are several emerging multi-pollutant technologies that use high electron 

beams or other proprietary processes. The PowerSpan ECO system has only limited 

experience and has not been fully tested on full-scale systems. The ECO system is 

located downstream of an existing particulate control device, and the process consists of 

three stages. In the first stage, the flue gas passes through a barrier discharge reactor 

where it is exposed to a high voltage discharge that generates high energy electrons. The 

electrons initiate a chemical reaction that forms oxygen and hydroxyl radicals, which 

then oxidize NOx, SO2, and mercury. This reaction results in the formation of nitric acid, 

sulfuric acid, and mercuric oxides. A process flow diagram of the ECO system is 

illustrated on Figure 3-15. Stage 2 is the collection of these acids and oxides in a 

downstream ammonia scrubber. The final stage is the collection of acid aerosols, fine 

PM, and oxidized mercury in the downstream WESP. Scrubber effluents contain 

dissolved ammonium sulfate nitrate (ASN) salts along with solids and mercury. The 

ASN solution is sent to a recovery process where the mercury is removed via a sulfurimpregnated activated carbon structure. Once the carbon activated bed becomes 

saturated with mercury, it is disposed of as a hazardous waste. The cleaned stream of 

ASN is converted to a saleable fertilizer. 
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Figure 3-15 

ECO Process Flow Diagram (PowerSpan). 

PowerSpan also offers a mercury-only control technology that uses a 

photochemical oxidation process. In this process, mercury is oxidized via ultraviolet 

lights. The ultraviolet lights are placed in the ductwork upstream of the particulate 

control device. Photochemical oxidation technology is in its infancy stage, as are most 

mercury reduction technologies. 

The ECO system is under pilot testing at FirstEnergy’s 50 MW Burger Plant and 

has achieved 82, 99, and 85 percent reduction for NOx, SO2, and mercury, respectively, 

while combusting eastern high-sulfur bituminous coal. However, because the ECO 

system has not been pilot tested at a facility burning a low-sulfur (less than 1.5 percent) 

subbituminous coal or within the Boardman Plant size range, this system was not 

evaluated further. 

3.4.2 Enviroscrub 

 Enviroscrub is a multi-pollutant control technology that is capable of removing 

significant amounts of elemental and oxidized mercury, NOx, PM2.5, and SO2. This 

technology is based on the Pahlman Process. A sorbent made up of oxides of manganese 

called Pahlmanite sorbent is injected upstream of the SDA, where the flue gas mixes 

with the Pahlmanite sorbent. This is where the oxidation and adsorption of mercury takes 

place. Other pollutants, such as SO2 and NOx, are also adsorbed by the Pahlmanite 

sorbent at this stage. The SDA byproducts are then separated from the flue gas in the 

PJFF. The fly ash and waste byproduct collected in the PJFF hopper is eventually 
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transported to a slurry tank for subsequent Pahlmanite sorbent regeneration in a reactor. 

A process flow diagram of the Pahlman Process is illustrated on Figure 3-16. 

Figure 3-16 

Pahlman Process Simplified Process Flow Diagram. 

The configuration for this technology is as follows: particulate removal (existing 

ESP), SDA, PJFF, sorbent regeneration, and byproduct separation. Currently, 

Enviroscrub is performing slip-stream pilot testing using third-party contractors, and the 

initial results are encouraging (Hammel, Charlie; Enviroscrub Technologies Corp., 

“Pahlman Process Shows Promise,” Power, Vol. 148, Nov. 8, October 2004, pp. 60-63). 

The technology is considered to be developing; but it has not yet moved beyond pilotscale testing and was not evaluated further. 

3.4.3 Phenix Clean Coal 

The Clean Combustion System (CCS) is an advanced hybrid coal 

gasification/combustion process that prevents the formation of NOx and SO2 emissions 

when coal is burned. The only reagent required for pollution control is limestone. 

The CCS concept is that an entrained-flow coal gasifier is followed by stages of 

combustion air. The CCS burner is designed to provide the necessary time, temperature, 

and stoichiometry required for all the chemicals in coal to complete their combustion 

reactions (to reach equilibrium conditions). 
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The coal, with limestone added as a source of calcium for sulfur capture, is 

pulverized and introduced to the burner along with a limited amount of hot combustion 

air. The initial high-temperature combustion gasifies and/or releases all the constituents 

of coal into the gas; i.e., carbon, sulfur, nitrogen, and ash compounds. At these high 

temperatures and with limited available oxygen, the carbon aggressively commands 

oxygen to form CO from all sources, including such compounds as water (H2O). 

Nitrogen compounds that may form, such as NOx, hydrogen cyanide, and ammonium, are 

simply forced to the molecular form (N2) by the aggressive action of carbon for oxygen. 

In the presence of calcium, the sulfur reacts to form calcium sulfide (CaS), a solid nongaseous particle). 

The high combustion temperatures melt the coal ash and CaS solids to form an 

inert slag that drains from the bottom of the boiler. Hot gases, high in CO and H2 and 

nearly free of NOx and sulfur, exit into the boiler furnace. As the gases cool and generate 

steam, additional OFA is added in stages to the furnace to complete the combustion of 

CO to CO2 and H2 to water. This action prevents the formation of any new (thermal) 

NOx and completes the combustion with excess air. The clean hot gases then enter the 

boiler superheat section as before the retrofit. A schematic of the process is shown on 

Figure 3-17. 

Figure 3-17 

Phenix Clean Coal Process Flow Diagram 
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Retrofits require an annual outage period with a 2 to 3 week extension. The CCS 

retrofit modification requires replacing the existing pulverized coal burners with new 

down-fired CCS burners and adding separated OFA to the boiler furnace and powdered 

limestone to the coal fuel. Most of the new, off-the-shelf equipment fits within the 

existing boiler space. 

The Phenix CCS technology is not in use at a commercial-scale installation with a 

similar-sized boiler as that at the Boardman Plant. Therefore, the technology was not 

considered to be technically feasible for application at the Boardman Plant and was not 

evaluated further. 

3.4.4 J-Power ReACT System 

Japan’s J-POWER is the developer of this enhancement to the original Bergbau 

Forschung activated coke (AC) process. The original and the enhanced versions of the 

technology have been installed at several industrial facilities in Japan, as well as at Isogo 

Unit 101, a 600 MW pulverized coal power plant, and at the Takehara Station, a 350 MW 

atmospheric fluidized bed combustion (AFBC) boiler. Regenerative Activated Coke 

Technology (ReACT) is offered in the United States by J-POWER EnTech, Inc. 

The J-POWER ReACT system consists of an AC process that involves three 

steps: (1) adsorption, (2) regeneration, and (3) byproduct recovery. Figure 3-18 

illustrates the J-POWER ReACT System. The process consists of an adsorber2 located 

after the primary particulate control devices and a sorbent regenerator. In the adsorber, 

the flue gas passes through a bed of AC moving slowly downward at a constant flow rate. 

The adsorber is of a single-stage design. AC pellets are circulated by a conveyor between 

the adsorber and regenerator, and ammonia is injected into the flue gas, typically as it 

enters the adsorber. SO2, SO3, NOx, mercury, and additional particulates (along with 

associated trace metals) are removed in the adsorber in one step, and the pollutant 

saturated AC is regenerated in the regenerator, where it is conveyed through a bucket 

elevator. 

The regenerator operates at temperatures in the 750° F to 930° F range. 

Simultaneously, sulfuric acid or ammonium compounds in the AC are decomposed to 

nitrogen (N2), SO2, and water. Mercury is retained in the AC and removed from the unit 

every few years, depending on the mercury concentrations at the inlet of ReACT. After 

cooling, the regenerated AC passes through a vibrating screen to eliminate the 

 

2

 The term “adsorption” refers to a surface chemical reaction where the reaction products remain on 

the surface of the solid sorbent material. Because ReACT relies on adsorption of mercury onto activated 

coke, its reaction vessel is termed an “adsorber.” “Absorption” refers to a chemical reaction in which the 

material (the solute) is absorbed into the bulk of the solvent medium. An example is the absorption of SO2

in an alkaline liquid in a wet spray tower, and its reaction vessel is termed an “absorber.” 
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mechanically degraded AC and captured dust; then, it is returned to the adsorber. The 

degraded AC can be returned to the boiler for burning, but it can also be sold and used in 

other industrial applications, such as dioxin adsorbent. SO2-rich gas from the regenerator 

is converted to a salable product, such as sulfuric acid and gypsum, in the byproduct 

recovery facility. 

Figure 3-18 

J-POWER ReACT System 

Unlike the original installations of 10 to 20 years ago, this process uses just one 

adsorber for all the pollutants, and the coke pellets have been reformulated to be more 

durable. These upgrades have substantially reduced adsorber size and coke attrition. 

Consequently, they have reduced the capital cost, coke replacement cost, and required 

footprint. 

Lastly, slipstream testing has demonstrated 90 percent mercury removal with the 

ReACT system. An EPRI slipstream test of the technology is currently under way at 

North Valmy Station. The ReACT technology is not in use at a commercial-scale 

installation in North America with a similar-sized boiler as that at the Boardman Plant 

burning PRB coal. Therefore, the technology was not considered to be technically 

feasible for application at the Boardman Plant and was not evaluated further. 
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4.0 Technically Feasible Retrofit Emission Control 

Technologies (Step 2) 

Step 2 of the BART analysis consisted of limiting the list of potential control 

technologies developed in Step 1 by eliminating technically infeasible options. In order 

for a technology identified in Step 1 to be included in the list of technically feasible 

controls developed in Step 2, that technology must be technically feasible. The EPA has 

defined “technically feasible” as meaning that a technology is both available and 

applicable. A technology is considered available if it has reached the licensing and 

commercial sales stage of development. For example, technologies in the pilot-scale 

testing stages of development are not considered available. The fact that a technology is 

considered available is not a sufficient basis for concluding that a technology is 

applicable, and, therefore, technically feasible. That technology must have been used in 

the same or a substantially similar source type to be considered applicable. 

For all the technologies identified as available in Section 3.0, a determination was 

made on the technical feasibility of the technology at the Boardman Plant site according 

to the evaluative process identified by the EPA. 

4.1 Technically Infeasible NOx Control Technologies 

4.1.1 Mobotec ROFA and ROTAMIX 

Mobotec’s ROTAMIX technology is not considered as technically feasible 

because there are no current installations at pulverized coal fired boilers of equivalent 

size to the Boardman Plant. The ROFA technology is a variant of the OFA system that is 

already being considered in this BART analysis. Therefore, to avoid duplication of 

technologies, it was not evaluated independently. 

4.1.2 NOxStar and NOxStar Plus 

The NOxStar technology is dependent on using natural gas as a reaction catalyst 

for NOx removal. This technology was considered to be not technically feasible since 

there is no natural gas supply at the Boardman Plant site. In addition to the high volatility 

in natural gas prices and the emissions of other pollutants from natural gas combustion, 

there are no existing natural gas pipelines to the Boardman site and the cost and impacts 

of building a new pipeline (across a U.S. military bombing practice range) are 

prohibitive. 
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4.1.3 ECOTUBE 

 Since most of the existing installations of the ECOTUBE system are on 

industrial/small-sized boilers firing solid waste, wood, or biomass, this technology is not 

technically feasible for the size range of the Boardman Plant. 

4.1.4 Induced Flue Gas Recirculation 

 IFGR systems are generally not applied to coal fired boilers. IFGR systems are 

suited for low nitrogen content fuel fired boilers, such as oil or natural gas boilers. 

Therefore, IFGR is not technically feasible. 

4.1.5 LoTOx 

The LoTOx system has only been demonstrated on small-sized medical waste 

combustors. It is therefore considered as not technically feasible. 

4.1.6 Natural Gas Reburn 

 Natural gas reburn in the Boardman Plant boiler is not technically feasible 

because of a lack of sufficient furnace height (i.e., inadequate residence time for NOx

reduction) and because of the absence of a natural gas supply at the Boardman Plant site, 

as discussed in Subsection 4.1.2. 

4.1.7 SNCR/SCR Hybrid (Cascade) 

As described in Subsection 3.1.7, the SCR catalyst reaction occurs within the 

temperature range of 600 to 750° F. As such, the catalyst must be located after the 

convective pass of the boiler but before the air preheater. For the Boardman plant, the 

temperature of the hot combustion gases exiting the boiler before entry to the air 

preheater is well in excess of 800o F. The Boardman boiler was not designed with space 

in the ductwork or with an appropriate temperature profile for a future SCR. Since the 

SCR catalyst cannot be located in the existing ductwork without significant modifications 

to the boiler to lower the gas path temperature to the desired range while still maintaining 

the air temperature exiting the air preheater to the pulverizer in order to properly dry the 

coal and maintain combustion efficiency, the SNCR/SCR hybrid system was considered 

as not technically feasible. 
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4.2 Technically Infeasible SO2 Control Technologies 

4.2.1 Dry Flue Gas Desulfurization 

Dry FGD using a CDS or similar technology has been applied only to boilers 

rated up to a maximum of 300 MW. Furthermore, most applications of this technology 

are typically on circulating fluidized bed boilers and not pulverized coal boilers such as 

the boiler at the Boardman Plant. Therefore, this technology was considered as not 

technically feasible. 

4.2.2 Furnace/Duct Reagent Injection 

Furnace or duct reagent injection is considered as not technically feasible because 

of the lack of installations on boilers in the same size range as the boiler at the Boardman 

Plant. 

4.3 Technically Infeasible PM Control Technologies 

4.3.1 GE MAX-9 Hybrid 

Current demonstrated GE MAX-9 Hybrid installations are in power boilers that 

are much smaller than that at the Boardman Plant. Therefore, this technology was 

considered as not technically feasible. 

4.3.2 Multiple-Cyclone Collector 

 Because of the lower efficiency of multiple-cyclone collectors in reducing PM 

emissions, this technology is not capable of controlling PM emissions better than the 

currently existing ESP. Therefore, this technology was not considered further in the 

analysis.

4.4 Technically Infeasible Emerging Pollution Control 

Technologies 

4.4.1 PowerSpan 

As discussed in Subsection 3.4.1, the PowerSpan ECO technology has not been 

pilot tested in a low-sulfur coal burning facility or in a facility similar in size to the 

Boardman Plant. Therefore, the PowerSpan ECO system was not considered as 

technically feasible. 
 Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

110207 4-4 

4.4.2 Enviroscrub 

The Enviroscrub technology is currently in pilot-scale testing, and there are no 

current developments in full-scale implementation. Therefore, the Enviroscrub 

technology is not technically feasible for retrofit at the Boardman Plant. 

4.4.3 Phenix CCS 

The Phenix CCS technology does not have a commercial-scale installation in a 

boiler similar in size to the one at the Boardman Plant. Therefore, this technology was 

not considered technically feasible for application at the Boardman Plant. 

4.4.4 J-Power ReACT System 

The J-Power ReACT system is currently undergoing slipstream testing in a North 

American plant. The performance for multi-pollutant removal will be evaluated during 

this testing before further commercial implementations. Therefore, this technology was 

not considered technically feasible for application at the Boardman Plant. 

4.5 Summary of Retrofit Emission Control Technologies 

Technical Feasibility 

A summary of the feasibility evaluation process is detailed in Tables 4-1 to 4-4. 

Also included in the tables are the reasons for the technical infeasibility of the eliminated 

control technologies. 
Technically Feas

Boardman Plant Contr110207 

Table 4-1 

Technically Feasible NOx Control Technologies 

Pollutant Technology 

Technically 

Feasible and 

Applicable? Reasons for Technical Infeasibilit

NOx Existing OFA system operation Yes --  Upgraded LNBs Yes --  Upgraded LNBs with existing OFA system 

operation 

Yes -- 

 Upgraded LNBs with existing OFA system 

operation and SNCR 

Yes -- 

 New LNBs and modified OFA system Yes --  New LNBs with modified OFA system and 

SNCR 

Yes -- 

 New LNBs with modified OFA system and 

SCR 

Yes -- 

 SNCR Yes --  SNCR/SCR hybrid (Cascade) No Not technically feasible to install 

existing ductwork. 

 Mobotec ROFA and ROTAMIX No ROTAMIX not demonstrated on B

boilers. ROFA system is in the sasystem. 

 NOxStar and NOxStar Plus No No existing natural gas pipeline to  ECOTUBE No No existing installation at similar  Induced flue gas recirculation (IFGR) No Applicable to low nitrogen conten

only. 
Technically Feas

Boardman Plant Contr110207 

Table 4-1 

Technically Feasible NOx Control Technologies 

Pollutant Technology 

Technically 

Feasible and 

Applicable? Reasons for Technical Infeasibilit

 LoTOx No Not commercially available.  Natural Gas Reburn No No existing natural gas pipeline to 

Table 4-2 

Technically Feasible SO2 Control Technologies 

Pollutant Technology 

Technically 

Feasible and 

Applicable? Reasons for Technical Infeasibili

SO2 Wet FGD Yes --  Semi-Dry FGD (SDA/FF) Yes --  Dry FGD (CDS) No No installation at unit larger than  Furnace/Duct Reagent Injection No No existing installation at similar 
Technically Feas

Boardman Plant Contr110207 

Table 4-3 

Technically Feasible PM Control Technologies 

Pollutant Technology 

Technically 

Feasible and 

Applicable? Reasons for Technical Infeasibili

PM Existing ESP with operational restrictions(1) Yes --  PJFF Yes --  COHPAC Yes --  GE MAX-9 Hybrid No No commercial installation at sim Multiple-cyclone collector No Level of emissions control is less 

currently existing ESP. 

 WESP Yes -- Notes:(1)Existing ESP with operational restrictions is estimated to have similar impact analysis and cost-effectiveness r

ESP, therefore it will not be evaluated in those sections. 
Technically Feas

Boardman Plant Contr110207 

Table 4-4 

Technically Feasible Emerging Pollution Control Technologies 

Pollutant Philosophy Technology 

Technically 

Feasible and 

Applicable? Reasons for Technica

Multi-Pollutants Control technologies PowerSpan No No commercial insta

sized source. 

 Enviroscrub No No commercial insta

sized source. 

 Phenix Clean Coal No No commercial insta

sized source. 

 J-Power ReACT No Currently in slipstrea

evaluation before cominstallations in North 
 Evaluation of Technically Feasible Retrofit 

Boardman Plant Emission Control Techniques (Step 3) 

110207 5-1 

5.0 Evaluation of Technically Feasible Retrofit Emission 

Control Technologies (Step 3) 

 Step 3 of the BART determination process was an evaluation of all the technically 

feasible control technologies for control effectiveness so that they could be ranked. 

5.1 Control Effectiveness 

The evaluation process in Step 3 determined the control effectiveness of each 

control technology. The control effectiveness was expressed in a common metric based 

on the amount of pollutant generated per unit of heat input (lb/MMBTU). This 

evaluation of the control effectiveness was then translated into a yearly rate (ton/yr) for 

each pollutant according to the highest rolling 12 month data for heat input in the 2003 to 

2005 period. The highest rolling 12 month data for heat input are summarized in 

Table 5-1. The control effectiveness was evaluated according to the sources of 

information indicated in Subsection 1.2.3. 

Table 5-1 

Highest Rolling 12 Month Data for Heat Input 

Pollutant Data Period Ending Heat Input (MMBTU/yr) 

NOx September 2003 48,630,688.4 

SO2 August 2005 48,571,330.3 

PM March 2004 49,093,487.4 

Tables 5-2 to 5-4 identify the baseline emissions and the control effectiveness for 

each control technology. The tables show the control technology rankings from baseline 

to the most effective control. The control effectiveness for each technology is also 

summarized in the Design Concept Definition sheets in Appendix C. 
 Evaluation of Technically Feasible Retrofit 

Boardman Plant Emission Control Techniques (Step 3) 

110207 5-2 

Table 5-2 

NOx Technologies Control Effectiveness 

Control Effectiveness 

(at stack) 

Control Technology lb/MMBTU tons/yr 

Baseline 0.43 10,349 

Existing OFA system operation 0.40 9,726 

Upgraded LNBs 0.38 9,240 

SNCR 0.32 7,781 

Upgraded LNBs with existing OFA system operation 0.32 7,781 

New LNBs with modified OFA system 0.28 6,808 

Upgraded LNBs with existing OFA system operation and 

SNCR 

0.27 6,565 

New LNBs with modified OFA system and SNCR 0.23 5,593 

New LNBs with modified OFA system and SCR 0.07 1,702 

Table 5-3 

SO2 Technologies Control Effectiveness 

Control Effectiveness 

(at stack) 

Control Technology lb/MMBTU tons/yr 

Baseline 0.61 14,902 

Semi-Dry FGD 0.15 3,643 

Wet FGD 0.10 2,429 
 Evaluation of Technically Feasible Retrofit 

Boardman Plant Emission Control Techniques (Step 3) 

110207 5-3 

Table 5-4 

PM Technologies Control Effectiveness 

Control Effectiveness 

(at stack)(1)

Control Technology lb/MMBTU tons/yr 

Baseline 0.017 417 

Existing ESP with operational restrictions 0.012 295 

PJFF 0.012 295 

COHPAC 0.012 295 

WESP 0.012 295 

(1)Particulate data are filterable values determined by US EPA Method 5. 
Boardman Plant Impact Analysis (Step 4) 

110207 6-1 

6.0 Impact Analyses (Step 4) 

6.1 Types of Impact Analyses 

For all the technologies considered, impact analyses were performed as part of the 

BART determination process. The purpose of these analyses was to identify factors other 

than control effectiveness that could affect the choice of the best retrofit technology. In 

summary, the following four types of impact analyses were performed: 

• Costs of compliance. 

• Energy impacts. 

• Non-air quality environmental impacts. 

• Remaining useful life. 

6.2 Methods of Impact Analyses 

The first step in performing the impact analyses was to define the design 

parameters for each control technology that was identified as technically feasible. The 

design parameters contain all pertinent information on the control technology system for 

specific application to the source. Examples of these design parameters include: type of 

reagent used and consumption rate, type of byproduct produced and production rate, flue 

gas pressure drop across the control technology, etc. The information used to define the 

design parameters included the following: 

• Information from equipment vendors. 

• Background information documents used to support New Source 

Performance Standards development. 

• Control technique guidelines document. 

• EPA cost manuals. 

• Trade publications. 

• Engineering and performance test data. 

The design parameters for each control technology that has been identified as 

technically feasible for application at the Boardman Plant site are summarized in the 

Design Concept Definition sheets, which can be found in Appendix C. 
Boardman Plant Impact Analysis (Step 4) 

110207 6-2 

6.2.1 Costs of Compliance 

The costs of compliance were identified for implementing each technically 

feasible control technology. The total capital investment for each control technology 

when applied specifically to the Boardman Plant site and the annual operating and 

maintenance costs were calculated. These cost calculations were based on the following: 

• CUECost Workbook, Version 1.0. 

• EPA Air Pollution Control Cost Manual - Sixth Edition. 

• Budgetary quotes from equipment vendors. 

• Quotes or cost estimation for previous design/build projects or in-house 

engineering estimates. 

6.2.2 Energy Impacts 

Energy impacts are estimated for each control technology that has consumption of 

auxiliary energy during its operation. Only direct energy impacts for each control 

technology, such as the auxiliary power consumption of the control technology and the 

additional draft system power consumption to overcome the additional system resistance 

of the control technology in the flue gas flow path, are accounted for. Indirect energy 

impacts, such as the energy to produce raw materials used for the control technology 

system, are not considered. The auxiliary power consumption estimates for each control 

technology are based on the typical power consumption of similar equipment of an 

equivalent size. The additional draft system power consumption calculations are based 

on the volumetric flow rate of the flue gas through the control technology systems and 

the flue gas pressure drops defined in the design parameter of each control technology. 

Between the two top-ranked control technologies for NOx emissions, new LNBs 

with modified OFA and SCR has materially higher energy impacts compared to new 

LNBs with modified OFA and SNCR. The use of an SCR creates additional back 

pressure that the SNCR system does not cause; additional energy consumption is required 

to overcome the additional system resistance of an SCR. 

Between the two top-ranked control technologies for SO2 emissions, the energy 

impacts of the wet FGD are significantly higher than those of the semi-dry FGD. 

6.2.3 Non-Air Quality Environmental Impacts 

Non-air quality impacts were evaluated for each of the control technologies. The 

major non-air quality impacts evaluated were the mercury deposition impacts to surface 

waters and disposal requirements for the byproduct and waste generated by each control 

technology. In 2006, the Oregon Environmental Quality Commission adopted among the 

most stringent restrictions on mercury from coal fired power plants in the country. The 
Boardman Plant Impact Analysis (Step 4) 

110207 6-3 

stated purpose of these restrictions was to decrease the amount of mercury in bodies of 

water. PGE is currently investigating controls to greatly enhance collection of mercury in 

the Boardman Plant exhaust gases to ensure compliance with these requirements. Certain 

BART control technologies also enhance the ability to capture and control mercury; these 

technologies were specifically identified as having a beneficial water quality impact. 

Other control technologies generate wastes and/or deleterious byproducts, use excessive 

water, and/or cause unsightly plumes. In addition, certain control technologies require 

the storage of large quantities of ammonia and result in the emission of ammonia as slip. 

These control technologies were identified as having negative environmental impacts. 

Between the two top-ranked control technologies for NOx, the new LNBs with 

modified OFA system and SCR have higher non-air quality environmental impacts than 

the new LNBs with modified OFA system and SNCR. SCR catalysts must be replaced 

approximately every 3 years, thus creating a potentially hazardous waste stream, and 

SCRs require the storage and emission of significant quantities of anhydrous ammonia 

(the SNCR system is designed for use of urea and less storage is required because of the 

differences in system use). 

Between the two top-ranked control technologies for SO2, the non-air quality 

environmental impacts are significantly greater for the wet FGD control technology. The 

wet FGD generates a visible plume, consumes more water, and generates a wastewater 

stream requiring disposal. The wet FGD also generates slightly more solid byproducts 

for landfill than the semi-dry FGD. 

Between the PM control technologies, PJFF has a significant environmental 

benefit in that it allows enhanced mercury collection. 

6.2.4 Remaining Useful Life 

Lastly, the remaining useful life is only considered when there is an effect on the 

annualized costs of the retrofit controls for capital recovery. This occurs when the source 

has a shorter remaining useful life than the expected service life of the control 

technology. For this BART analysis, the remaining useful life of the controls was 

defined as 20 years, and the remaining useful life of the source was defined as longer 

than 20 years. These assumptions could obviously change if an unreasonable control 

package is imposed on the Boardman Plant. However, for purposes of this analysis the 

remaining useful life was not considered a factor. If the ultimate BART determination 

were to vary materially from the conclusions stated in this report, this factor could require 

reassessment. 
Boardman Plant Impact Analysis (Step 4) 

110207 6-4 

6.3 Cost-Effectiveness 

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

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

the cost of control per amount of emissions removed. The emissions reduced are 

estimated on an annual basis based on the reduction from baseline emissions. Both the 

baseline emissions and post-control emissions values are documented in the Design 

Concept Definition sheets located in Appendix C. 

Two types of cost-effectiveness are calculated during the BART 

determination: average and incremental cost-effectiveness. The general definition of the 

two types of cost-effectiveness can be found in Subsection 1.2.4. The cost-effectiveness 

values are based on 2007 dollars. Cost impact analyses were performed for all the 

identified technically feasible control technologies. Summaries of the calculated cost 

impact analyses are presented in Appendix D. 

 In its June 24, 2005 Regional Haze Final Rule Preamble, EPA estimated ranges of 

cost effectiveness that were used to establish the presumptive limits for NOx and SO2 as 

follows: 

• $400 to $2000 per ton of SO2 removed. 

• $100 to $1000 per ton of NOx removed. 

For SO2 controls, EPA stated that plants like Boardman that burn low sulfur coal 

“could meet the emission limit of 0.015 lb/MMBTU in a cost effective manner by 

utilizing [semi-]dry FGD technologies.” For NOx controls, EPA stated that its 

presumptive NOx “limits...are based on the use of current combustion control 

technology. Current combustion control technology is generally, but not always, more 

cost-effective than post-combustion controls such as SCRs." EPA further stated that they 

were “not establishing presumptive limits based on the installation of SCR. Although 

States may in specific cases find that the use of SCR is appropriate, we have not 

determined that SCR is generally cost-effective for BART across unit types." 

As shown in Table 6-1, the NOx and SO2 control technologies analyzed for 

Boardman are generally consistent with EPA’s guidance. The combustion control 

technologies are significantly more cost effective than SCRs and semi-dry FGD 

technologies are significantly more cost effective than wet FGD technologies. 

6.4 Impact Analyses Results 

A summary table (Table 6-1) was developed for the impact analyses performed. 

Additionally, the expected post-control emissions levels are shown. The cost impact data 

in the summary table was used to produce graphical plots of the total annualized cost 
Boardman Plant Impact Analysis (Step 4) 

110207 6-5 

versus the expected emissions reduction for all control alternatives identified in the 

BART analysis (Figures 6-1, 6-2, and 6-3). 

From the graphical plots, a “least-cost envelope” for each group of control 

technologies was identified. Control technologies that lie on this least-cost envelope are 

“dominant controls” that should be the focus for the BART determination. Dominant 

controls are the technologies that have the lowest cost for implementation per quantity of 

pollutant removed. Therefore, these technologies will be the top choice as the best 

method for emissions reduction, barring any additional factors or considerations. 

For all the dominant controls, the incremental cost-effectiveness between a 

technology and the next most stringent control technology was also calculated. This 

incremental cost-effectiveness indicates the additional cost to increase the emissions 

reduction when comparing technologies that have different emissions removal capability. 
Boardman Plant Im

110207 

Table 6-1 

Impact Analysis and Cost-Effectiveness Results 

Emission Expected Expected Total Incremen

Performance Emission Emission Capital Annualized Cost Cost 

Level Rate Reductions Costs Cost Effectiveness Effectiven

All Feasible Technologies (lb/mmBtu) (tons/yr) (tons/year) (1,000$) (1,000$) ($/ton) ($/ton

NOx Control Technologies

Overfire Air (OFA) System Operation 0.40 9,726 623 4,022 1,007 1,617 -- Upgraded Low NOx Burners (LNB) 0.38 9,240 1,109 10,428 1,211 1,092 419 Selective Non-Catalytic Reduction (SNCR) 0.32 7,781 2,568 17,429 5,386 2,097 -- Upgraded LNB with Existing OFA System Operation 0.32 7,781 2,568 14,198 2,190 853 671 New LNB with Modified OFA System 0.28 6,808 3,541 32,651 3,718 1,050 1,571 Upgraded LNB with Existing OFA System Operation and SNCR 0.27 6,565 3,784 31,627 6,914 1,827 -- New LNB with Modified OFA System and SNCR 0.23 5,593 4,756 50,080 7,117 1,496 2,796 New LNB with Modified OFA System and Selective Catalytic Reduction 0.07 1,702 8,647 223,510 26,772 3,096 5,052 

SO2 Control Technologies

Semi-Dry FGD 0.15 3,643 11,259 247,293 36,322 3,226 -- 

Wet FGD 0.10 2,429 12,473 382,377 51,815 4,154 12,759 

PM Control Technologies

Existing ESP with Operational Restrictions 0.012 295 123 0 0 0 -- Pulse Jet Fabric Filter (PJFF) 0.012 295 123 94,353 12,836 104,580 -- 

Compact Hybrid Particulate Collector (COHPAC) 0.012 295 123 82,951 10,907 88,863 -- Wet ESP 0.012 295 123 179,290 21,057 171,559 -- 

Notes:1. All costs are in 2007 US$2. Incremental costs are based on:a) New LNB with Modified OFA System and SCR incremental cost relative to New LNB with Modified OFA System and SNCRb) New LNB with Modified OFA System and SNCR incremental cost relative to New LNB with Modified OFA Systemc) New LNB with Modified OFA System incremental cost relative to Upgraded LNB with Existing OFA System Operationd) Upgraded LNB with Existing OFA System Operation incremental cost relative to Upgraded LNBe) Upgraded LNB incremental cost relative to OFA System Operationf) Wet FGD incremental cost relative to Semi-Dry FGD
Boardman Plant Im

110207 

0

3,0006,0009,000

12,00015,00018,00021,00024,00027,00030,000

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

Overfire Air (OFA) System Operation Upgraded Low NOx Burners (LNB) Selective Non-Catalytic Reduction (SNCR) Upgraded LNB with Existing OFA System Operation New LNB with Modified OFA System Upgraded LNB with Existing OFA System Operation and SNCR New LNB with Modified OFA System and SNCR New LNB with Modified OFA System and Selective Catalytic Reduction Dominant Controls

Figure 6-1 

NOx Control Cost-Effectiveness 
Boardman Plant Im

110207 

0

5,000

10,00015,00020,00025,00030,00035,00040,00045,00050,00055,000

0 1,500 3,000 4,500 6,000 7,500 9,000 10,500 12,000 

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

Semi-Dry FGD Wet FGD Dominant Controls

Figure 6-2 

SO2 Control Cost-Effectiveness 
Boardman Plant Im

110207 

0

2,0004,0006,0008,000

10,00012,00014,00016,00018,00020,00022,000

0 20 40 60 80 100 120 140 160 

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

Pulse Jet Fabric Filter (PJFF) Compact Hybrid Particulate Collector (Wet ESP Dominant ControlsExisting ESP with Operational Restrictions

Figure 6-3 

PM Control Cost-Effectiveness 
Boardman Plant Impact Analysis (Step 4) 

110207 6-10 

6.4.1 NOx Control Technologies 

At the completion of the evaluation of the impacts, it was determined that the 

following technologies lie on the least-cost envelope and are the dominant control 

technologies for the reduction of NOx emissions: 

• OFA system operation 

• Upgraded LNBs. 

• Upgraded LNBs with existing OFA system operation. 

• New LNBs with modified OFA system (NLNB/MOFA). 

• New LNBs with modified OFA system and SNCR 

(NLNB/MOFA/SNCR). 

• New LNBs with modified OFA system and SCR (NLNB/MOFA/SCR or 

SCR). 

 These technologies have been identified as the least-cost control option. Two of 

the six technologies (NLNB/MOFA/SNCR and NLNB/MOFA/SCR) also represent the 

two most effective NOx control technologies and were evaluated to determine their 

respective improvement to visibility in the Class I areas. Of the two, the control package 

utilizing SCR has significantly greater costs of compliance, negative energy impacts, and 

negative non-air quality environmental impacts. 

6.4.2 SO2 Control Technologies 

As observed on the SO2 cost-effectiveness graphical plot (Figure 6-2), both 

technically feasible SO2 control technologies are dominant controls and therefore, were 

evaluated to determine their respective improvement to visibility in the Class I areas. Of 

the two, the costs of compliance and the negative non-air quality environmental impacts 

are greater for the wet FGD control technology. 

6.4.3 PM Control Technologies 

 On the PM cost-effectiveness graphical plot (Figure 6-3), the existing electrostatic 

precipitator with operational restrictions was shown on the least-cost envelope as the 

most cost-effective PM control technology. The other technically feasible PM control 

technologies have the same expected emissions reduction but have a higher total 

annualized cost. However, since the SO2 control technologies include PJFFs, and the 

PJFFs have a beneficial non-air quality environmental impact because of their role as a 

critical element in an advanced mercury control system, PJFFs were considered for 

BART determination. 
Boardman Plant Visibility Impacts (Step 5) 

110207 7-1 

7.0 Visibility Impacts (Step 5) 

 Evaluation of visibility impacts is the fifth step required under the BART 

guidelines. This step addresses the visibility improvements that would result from 

installation of the top-ranked technology options identified in the impact evaluation 

(Step 4). The visibility improvements are the differences between the results of the preBART controls and the post-BART controls analyses. 

 Analyses were conducted using CALPUFF. First, emissions associated with preBART controls were modeled to establish the baseline for the pre-BART control 

analyses. Second, individual post-BART control technologies were analyzed for use in 

selecting final control alternatives. 

 The methodology used in these analysis was presented in Protocol for the 

Application of CALPUFF Determination Modeling Pursuant to BART Regulation—PGE 

Boardman Plant (Revised) (Protocol) (CH2M HILL, 2007). The protocol was initially 

approved by DEQ on January 18, 2007. As specified in the protocol, all Class I areas 

within a 300 kilometer (km) radius of the plant were included in the analysis. In addition, 

although not a Class I area, the Columbia River Gorge National Scenic Area (CRGNSA) 

was also modeled for informational purposes only as requested by DEQ. A copy of the 

protocol and the DEQ approval are provided in Appendix F. 

 The following sections discuss in greater detail the modeling methodology and 

results. 

7.1 Modeling Methodology 

 The EPA-approved CALPUFF modeling system was used to assess the visibility 

impacts as required by the EPA in the BART guideline. CALPUFF is a non-steady-state 

Lagrangian dispersion model that simulates pollutant releases as a continuous series of 

“puffs.” It includes algorithms for pollutant removal caused by wet scavenging and dry 

deposition, chemical transformation, and plume fumigation. It is supported by two 

primary programs, CALMET and CALPOST. Version numbers of the various programs 

in the CALPUFF system used are as follows: 

• CALMET Version 6.211, Level 060414. 

• CALPUFF Version 6.112, Level 060412. 

• CALPOST Version 6.131, Level 060410. 

 CALMET is used to create three-dimensional wind fields based on multiple 

sources of geophysical and meteorological data. The CALMET data used in CALPUFF 

was provided by DEQ and included meteorological data for 2003, 2004, and 2005. The 
Boardman Plant Visibility Impacts (Step 5) 

110207 7-2 

output of the CALPUFF model consists of binary concentration data files. CALPOST 

post-processes these data on the basis of specified input parameters. 

 CALPUFF was run using the control file settings summarized in the protocol. 

The BART guidelines call for evaluation of the 98th percentile visibility impact, which 

translates to the 8th highest day in a year or the 22nd highest day in a 3-year period. 

Therefore, change in visibility was calculated for the 8th highest day for each year 

modeled and for the 22nd highest day over the 3 years modeled. The number of days 

where the change in visibility exceeds 0.5 deciview was calculated for each year 

modeled. 

 Each of the 14 Class I areas and the CRGNSA were evaluated. A figure showing 

the modeling domain is included in Appendix F in the modeling protocol. The modeling 

domain was established to encompass the Boardman Plant and allow for a 50 km buffer 

around the Class I areas that were within 300 km of the facility. The Class I areas 

included in the analysis are the following: 

1. Alpine Lakes Wilderness Area. 

2. Diamond Peak Wilderness Area. 

3. Eagle Cap Wilderness Area. 

4. Glacier Peak Wilderness Area. 

5. Goat Rocks Wilderness Area. 

6. Hells Canyon Wilderness Area. 

7. Mount Adams Wilderness Area. 

8. Mount Hood Wilderness Area. 

9. Mount Jefferson Wilderness Area. 

10. Mount Rainer National Park. 

11. Mount Washington Wilderness Area. 

12. North Cascades National Park. 

13. Strawberry Mountain Wilderness Area. 

14. Three Sisters Wilderness Area. 

An ozone.dat file for the 3 year meteorological period was developed by Eri 

Ottersberg (SLR International) and Mary Beth Yansura (CH2M HILL) with input and 

review by Oregon DEQ. This file was used in lieu of the default 60 ppb value that was 

specified in the three states BART Modeling Protocol. The ozone data incorporated in 

the file was compiled from state and federal monitors in the three state area. The 

ozone.dat file is considered an addition to the protocol and accepted for use in BART 

modeling. This was documented in a memo from Phil Allen of Oregon DEQ to Ray 

Hendricks of PGE dated August 28, 2007 and shown in Appendix F. 
Boardman Plant Visibility Impacts (Step 5) 

110207 7-3 

7.2 Emissions 

 Emissions were modeled for the following pollutant species: 

• Nitrates (NOx). 

• SO2.

• Nitric Acid (HNO3). 

• PM Filterable: 

- Elemental Carbon (EC) (< 2.5 microns [μm]). 

- PM Fine (PMF) (< 2.5 μm). 

- PM Coarse (PMC) (2.5 – 10 μm). 

• PM Condensable: 

- Organic Carbon (OC) (secondary organic aerosol [SOA]). 

- Inorganic Aerosol (SO4). 

- Non-SO4 inorganic aerosol. 

 Table E-1 summarizes the emission rates and stack parameters that were used for 

the exemption modeling and BART control modeling. Emission rates and stack 

parameters have been revised since the January 2007 protocol to reflect current design 

information. The PM10 emissions provided included the front half filterable emissions 

only. The speciation spreadsheets downloaded from the National Park Service website 

were used to determine the condensable and total particulate emissions. Total, 

condensable, and filterable PM emissions are presented in Table E-1.

7.3 Control Technologies 

 Four post-control technologies were selected to cover the range of effectiveness 

of the individual control technologies evaluated in Step 4. Retrofit PM control 

technologies were not evaluated because of the small contribution PM makes to visibility 

compared to NOx and SO2 in the exemption modeling and based on the SO2 control 

technologies including PJFF systems in the analyses. The percent of total emissions and 

percent of total visibility impact related to PM for the exemption modeling was less than 

2 percent. 

 The control technologies evaluated include two NOx and two SO2 controls: 

• NOx

- New LNBs with modified OFA system and SCR. 

- New LNBs with modified OFA system and SNCR. 

• SO2

- Wet FGD. 

- Semi-Dry FGD. 
Boardman Plant Visibility Impacts (Step 5) 

110207 7-4 

7.4 Modeling Results 

The last column of Table 7-1 presents the visibility improvements for the Class I 

area with the highest impacts, Mount Hood Wilderness Area, based on the 22nd highest 

impact for the 3-year period. Table 7-1 also shows the reduction or improvement in the 

number of days where the change in visibility exceeds 0.5 deciview for the Class I area 

with the highest number of days, Hells Canyon Wilderness Area. More detailed 

modeling results for each Class I area and the CRGNSA by technology are presented in 

Appendix E. 

A comparison of the modeled visibility improvements between the two 

combinations of NOx control technologies shows that in all Class I areas, the new LNBs 

with modified OFA and SNCR combination produces significant modeled visibility 

improvement in Boardman’s contribution to regional haze. The new LNBs with modified 

OFA and SCR combination produces additional incremental improvement as compared 

to the NOx controls with SNCR, but the incremental improvement associated with 

moving from SNCR to SCR is much smaller than the improvement gained by moving 

from the baseline case to the NOx controls using SNCR. For the SO2 control 

technologies, the wet FGD and semi-dry FGD options have roughly equivalent modeled 

visibility improvements. The semi-dry FGD option has a slightly better visibility 

improvement than the wet FGD case at some of the Class I areas such as Eagle Cap, 

Mount Hood, Mount Jefferson and Glacier Peak, while improvements at the other Class I 

areas such as Alpine Lakes and North Cascades are slightly better for the wet FGD 

option. For all Class I areas, the differences between the two control technologies are 

very small. 
Boardman Plant Visibility Impacts (Step 5) 

110207 7-5 

Table 7-1 

Visibility Impact Summary 

Boardman Plant BART Determination 

Reduction in Number of Days Above 

0.5 deciview at Highest Frequency 

Area (Hells Canyon) 

(Percent Improvement) 

Reduction in Maximum 

Visibility Impact at 

Nearest Class I Area 

(Mt Hood) (deciviews) 

(Percent Improvement) 

Individual Control Technologies 2003 2004 2005 2003-2005(1) 

NOx 

 NLNB/MOFA/SCR 51 (45%) 49 (46%) 58 (57%) 1.84 (40%) 

 NLNB/MOFA/SNCR 33 (29%) 38 (36%) 31 (30%) 1.20 (26%) 

SO2 

 Wet FGD 53 (46%) 40 (37%) 51 (50%) 0.88 (19%) 

 Semi-Dry FGD 45 (39%) 33 (31%) 42 (41%) 0.97 (21%) 

(1)Based on 22nd highest impact (98th percentile for 3 year period). 

NLNB/MOFA/SCR – New Low NOx Burners with Modified Overfire Air and Selective Catalytic 

Reduction. 

NLNB/MOFA/SNCR – New Low NOx Burners with Modified Overfire Air and Selective Noncatalytic 

Reduction. 

FGD – Flue Gas Desulfurization. 
Boardman Plant Selection of Best Alternative 

110207 8-1 

8.0 Selection of Best Alternative 

The CAA and the Guidelines specify that after gathering the data presented in the 

previous pages of this report, five factors must be applied in order to determine what 

constitutes BART. These factors, identified in CAA Section 169A(g)(7) and codified in 

40 C.F.R. § 51.308(e)(1)(ii), are: (1) the costs of compliance, (2) the energy and non-air 

quality environmental impacts, (3) any existing pollution control technology in use at the 

source, (4) the remaining useful life, and (5) the degree of improvement in visibility 

which may reasonably be anticipated to result from the use of such technology. Of these 

five factors, the third factor (existing pollution control technology) is not relevant to this 

facility in the analysis. The fourth factor (remaining useful life) is not relevant in this 

analysis to the extent that the recommended controls are considered BART. If the NOx

control package that includes SCR were considered BART, the economic impacts section 

would have to be revised to reflect the impact on plant viability. Because there is such a 

strong argument that BART for NOx constitutes the control package with SNCR, this 

viability analysis was not incorporated into this report. Were serious consideration given 

to the NOx controls package incorporating SCR notwithstanding their limited benefits 

and substantial capital and operating costs, then this report would have to be revised to 

address the potential closure of the plant and that impact on remaining useful life (i.e., 

factor 4). In order to simplify the report, the third and fourth factors are not considered at 

this time and the evaluation focuses on the first, second and fifth factor. Based on these 

three factors, the control technologies constituting BART are identified. 

Consistent with the EPA guidelines and the statutory requirements for performing 

a BART analysis, PGE completed its five step analysis. The basis for its BART 

determination for each of the three BART pollutants and applying each of the statutory 

factors is outlined below. 

8.1 Selection of PM BART 

The selection of the particulate controls that constitute BART is straightforward. 

Of the four technology options identified in Table 5-4, each of the four offered the same 

degree of control. Of the four, the PJFF option (in combination with the existing ESP) 

offered the additional non-air quality benefit of controlling mercury emissions. 

Therefore, PJFF (in combination with the existing ESP) was chosen as BART for 

particulate. 
Boardman Plant Selection of Best Alternative 

110207 8-2 

8.2 Selection of SO2 BART 

In the evaluation of the SO2 controls, the two top-ranked technologies share 

essentially the same degree of improvement in modeled visibility which may reasonably 

be anticipated to result from the use of such technology (BART Factor 5). While the 

maximum 24-hour emission rate for the wet FGD technology is lower than the maximum 

24-hour emission rate achieved by the semi-dry FGD, this does not translate into 

significantly better visibility improvements. The Boardman Plant currently relies on lowsulfur coal for SO2 control. As a result, the installation of either wet FGD or semi-dry 

FGD results in decreases of approximately 19,000 and 18,000 tons, respectively. Given 

the tremendous decrease that these controls will generate, the difference in the emissions 

from one technology versus the other is comparatively insignificant. That, combined 

with the differences in emissions parameters associated with the wet versus semi-dry 

technologies means that the improvements in visibility are very similar. For example, the 

maximum modeled impact (98th percentile over the three year period) average across all 

fourteen Class 1 areas for the two FGD options are only separated by 0.02 deciview (1.49 

v. 1.51). With numbers this close, there is no significant improvement using one 

technology versus the other. Based on this analysis, there is no basis under the fifth 

factor (the degree of improvement in visibility which may reasonably be anticipated to 

result from the use of such technology) for choosing one SO2 control technology over 

another. 

Evaluation of the second factor clearly indicates that the preferred SO2 control 

technology is semi-dry FGD. The non-air quality environmental and energy impacts are 

significantly greater for the wet FGD control technology than for the semi-dry FGD 

control technology. A key non-air quality environmental impact of the wet FGD versus 

semi-dry FGD technology is that the wet FGD technology is a tremendous consumer of 

water. Wet FGD consumes approximately 600 gallons/minute of water—nearly double 

the amount of water that a semi-dry system would consume. In the arid area of eastern 

Oregon where the Boardman Plant is located, water is a scarce commodity. A technology 

as water-intensive as wet FGD would have to generate dramatically better improvements 

in visibility in order to be selected over the semi-dry FGD technology. That is not the 

case here. In addition to, and as a result of, wet FGD’s water consumption, the wet FGD 

technology would also generate a tremendous visible plume. This plume would be 

visible for many miles in all directions, producing plume blight in the region surrounding 

the plant. Finally, the energy impacts of wet FGD are significant as compared to the 

semi-dry FGD, with wet FGD consuming more than three times the operating energy 

required for semi-dry FGD (15,254 kW v. 4,088 kW). 
Boardman Plant Selection of Best Alternative 

110207 8-3 

The final BART selection factor is determinative in that the economic impacts 

associated with the wet FGD (measured in dollars/ton) are approximately 29 percent 

higher than the economic impacts associated with the semi-dry FGD. The average costeffectiveness of semi-dry FGD and wet FGD are $3,226 per ton and $4,154 per ton, 

respectively (see Table 6-1). The incremental cost-effectiveness of moving from the 

semi-dry technology to the wet technology is approximately $12,800 per ton. The 

average cost effectiveness of the wet FGD control option is significantly higher than the 

upper end of the range ($400 to $2000/ton) considered to be reasonable in EPA’s BART 

guidelines. The incremental cost-effectiveness of moving from the semi-dry to the wet 

technology far exceeds the reasonableness threshold. 

Based on an analysis of all the statutory factors, it was concluded that the best 

alternative for SO2 control is semi-dry FGD. The cost (both average and incremental) of 

implementing wet FGD is much higher than the cost of implementing semi-dry and yet 

the improvements in visibility by moving to the wet technology are insignificant. In 

addition, the energy and non-air quality impacts of utilizing the wet technology are 

extreme. Therefore, BART for SO2 for the Boardman Plant is semi-dry FGD. 

8.3 Selection of NOX BART 

The application of the statutory factors indicates that the best choice for BART 

for NOx is new LNBs with modified OFA system and SNCR. Each of the top two NOx

control options involve the installation of new LNBs with a modified OFA system. The 

top two options differ in terms of whether they utilize SNCR or SCR for additional 

control. While the option incorporating SCR results in lower emissions than the option 

incorporating SNCR (a reduction of 12,000 tons/year at the maximum modeled emission 

rate v. 8,000 tons/year), the visibility improvements are, again, not linear. Therefore, a 

careful evaluation of each of the statutory factors is required. 

The modeling indicates slightly lower visibility impacts with the use of the 

control option incorporating SCR as opposed to the control option incorporating SNCR, 

but the evidence does not indicate that the difference in impacts is material. The 

modeling indicates that each of the top two control options results in significant visibility 

improvement, although not nearly as dramatic as the improvements created by SO2

control. The NOx control option incorporating SCR appears to generate better 

improvements in visibility, but the incremental benefit over the option incorporating 

SNCR is not substantial and it does not represent a material improvement. 

For example, the Class I area with the greatest modeled impacts from the 

Boardman Plant is the Mt. Hood Wilderness Area. The modeling indicates that the 

current plant configuration results in an average of 85 days per year at the Mount Hood 
Boardman Plant Selection of Best Alternative 

110207 8-4 

Wilderness Area where the visibility impacts attributable to the Boardman Plant 

exceeded 0.5 deciviews. Employing the NOx control option that incorporates SNCR 

reduces the average number of days with modeled impacts over 0.5 deciviews to 73. 

Utilizing the NOx control that incorporates SCR only reduces the number of days with 

modeled impacts over 0.5 deciviews by only an additional 7 days. The magnitude of the 

total impact reflects a similar trend, i.e., improvements with both technologies, but only a 

moderate incremental improvement as a result of using SCR versus SNCR. Again using 

Mt. Hood Wilderness Area as an example, the use of the NOx control option 

incorporating SNCR will reduce the 98th percentile impacts over the three year period 

from 4.6 deciviews to 3.4 deciviews—a material decrease in the peak impacts, but not as 

significant as that achieved with the SO2 controls. However, utilization of the NOx

control technology that incorporates SCR will only reduce the 98th percentile impact by 

an additional 0.6 deciviews. As EPA stated in the July 2006 preamble, “the simplified 

chemistry in the model tends to magnify the actual visibility effects of that source.” 

EPA also stated that the modeling is “likely to overstate the actual visibility effects of an 

individual source.” This indicates that the difference in benefits associated with the two 

technologies are similarly overstated and that differences of a fraction of a deciview are 

too small to be significant. Therefore, while the modeling suggests that the use of the 

NOx control option incorporating SCR results in lower impacts than the NOx control 

option incorporating SNCR, they are not substantially lower enough to constitute a 

significant difference. 

Evaluation of the energy and non-air quality environmental impacts factor 

indicates that the use of the NOx control option incorporating SNCR is the appropriate 

choice for BART. Based on energy consumption, the NOx controls incorporating SNCR 

are clearly preferable. The energy consumption of the NOx controls incorporating SCR is 

36 times greater than the energy consumption of the NOx controls incorporating SNCR 

(2,537 kW v. 70 kW) as a result of the fan auxiliary power needed to overcome additional 

system resistance. This 2,467 kW difference is significant in that it materially decreases 

the efficiency of the plant, as measured by number of kW placed into the grid. 

The non-air quality environmental impacts also favor the NOx controls 

incorporating SNCR over the NOx controls incorporating SCR. The SCR system 

generates hazardous material as a result of catalyst replacement, a concern that does not 

exist for the SNCR system. The SCR system also relies on anhydrous ammonia while the 

SNCR utilizes urea—a significant concern given anhydrous ammonia storage carries 

greater risk in the event of a release. Related to this concern, the SCR system must store 

larger amounts of anhydrous ammonia on site due to the differences in operating 

scenarios between the controls incorporating SCR versus those incorporating SNCR. 
Boardman Plant Selection of Best Alternative 

110207 8-5 

Therefore, the non-air quality environmental concerns favor the choice of new LNBs and 

modified OFA with SNCR. 

The economic impacts strongly support selecting the NOx controls incorporating 

SNCR as BART. The economic impacts associated with the NOx controls incorporating 

SCR are considerably higher (by an order of magnitude) than the economic impacts 

associated with the NOx controls incorporating SNCR. The economic impacts of the NOx

controls incorporating SNCR are substantial, with a capital cost of approximately $50 

million and annual operating costs of approximately $2.4 million. This equates to an 

annualized cost for the NOx controls with SNCR of over $7 million per year and 

approximately $1,500 per ton of NOx controlled (Table 6-1). This cost effectiveness is 

significantly higher than the range ($100 to $1000/ton) considered reasonable in EPA’s 

BART guidelines. The costs of installing and operating NOx controls incorporating SCR 

are substantially greater still, with a capital cost of $224 million and annual operating 

costs of $5.7 million. This equates to an annualized cost for the NOx controls with SCR 

of nearly $27 million per year and approximately $3,100 per ton of NOx controlled 

(Table 6-1). Therefore, whether the controls use SCR or use SNCR, the average cost 

effectiveness is significantly higher than that established by EPA as reasonable. 

The EPA Guidelines also require that incremental cost effectiveness between 

control options be considered. The incremental cost effectiveness of the NOx controls 

utilizing SCR as compared to the NOx controls with SNCR is $5,052 per ton NOx

removed. The incremental cost effectiveness of moving from the NOx controls with 

SNCR to the NOx controls with SCR far exceeds EPA’s reasonableness threshold. The 

incremental cost effectiveness associated with visibility improvement reaches a similar 

result. The average 98th percentile impact level across all the Class I areas is only 0.27 

deciviews better with the NOx control option incorporating SCR than the NOx control 

option incorporating SNCR. This equates to an incremental annualized control cost 

associated with moving from the NOx controls with SNCR to the NOx controls with SCR 

of approximately $72 million per deciview (based on an annualized cost of $27 

million/year for package with SCR v. $7 million per year for package with SNCR). The 

tremendous incremental cost associated the NOx controls with SCR do not justify the 

limited incremental benefit. 

The likelihood that the plant will close if required to install SCR is also a key 

consideration in concluding that BART for NOx consists of the control package with 

SNCR. The EPA Guidelines state that it is appropriate to take into account the 

affordability of particular controls as part of the BART analysis where the cost of 

installing and operating the controls is judged to have a severe impact on plant operations 

and plant viability. That would be the case here were BART considered to include SCR. 
Boardman Plant Selection of Best Alternative 

110207 8-6 

The Boardman Plant is a key resource for providing baseload power to the region 

throughout the year. The imposition of SCR as BART, on top of the $300 million in 

other capital control investments, could possibly require an investment beyond what the 

plant’s return can justify or support. Under such circumstances the EPA Guidelines state 

that it is appropriate to consider the non-affordability of the controls and to therefore not 

require SCR. Based on the discussion within this report there is no need to rely on this 

factor to conclude that BART does not include SCR. However, this additional 

consideration lends further support to the conclusion that BART for NOx constitutes the 

control package with SNCR. 

Based on the EPA Guidelines the economic impacts associated with the NOx

controls incorporating SCR are significant both on an average and an incremental basis 

and support the conclusion that the best alternative for NOx control is new LNBs with 

modified OFA system and SNCR. 

8.4 Visibility Improvement for Combined BART Controls 

 As a final step in the evaluation, visibility improvement was evaluated with the 

combination of controls identified as BART for particulate, SO2, and NOx (Table 8-1 and 

Appendix E). The modeling methodology used for this combination of controls 

evaluation was the same as the methodology summarized in Section 7.0. This control 

package using semi-dry FGD (including PJFF) and NLNB/MOFA/SNCR will impose a 

capital cost of more than $297 million dollars and annual operating costs of 

approximately $15 million. Nonetheless, while these controls are very expensive to 

install and operate, they are predicted to result in an average improvement in the plant’s 

modeled visibility impacts across all Class I areas of 64 percent and an improvement at 

the most severely impacted Class I area of 56 percent. There would be, on average, only 

5.0 days per year where the impacts would exceed 1.0 deciview, as compared to 30 days 

per year in the exemption (i.e., baseline) modeling. 

For purposes of comparison, the complete combination of BART controls was 

modeled except that SCR was substituted for SNCR. That control package resulted in 

slightly lower impacts then the control package with SNCR, but not dramatically so. For 

example, the average number of days where the impacts would exceed 1.0 deciview 

drops from 30 days when modeled with the current controls to 5.0 with SNCR to 1.3 with 

SCR. The 98th percentile impact (in deciviews) over the three year period drops from 

2.22 when modeled with the current controls to 0.81 with SNCR to 0.44 with SCR. 

While the modeling suggests that there is a slight improvement in visibility impacts with 

the SCR package as opposed to the SNCR package, it is important to recognize that such 

differences may not be meaningful. As noted above, EPA recognized that the CALPUFF 
Boardman Plant Selection of Best Alternative 

110207 8-7 

model exaggerates the impacts. Therefore, differences of a few tenths of a deciview are 

not considered significant. The improvements when the entire multipollutant control 

package is considered are lower with SCR as opposed to SNCR. However, actual 

detectable improvements are anticipated to be negligible. As a result, there is no 

reasonable justification for spending an additional $173 million in capital and $3.3 

million per year in operating expense to achieve the minimal incremental improvements 

that would be gained by utilizing SCR. Requiring such a large additional expenditure 

calls into question the viability of the plant without generating significant results. 

While the Columbia River Gorge National Scenic Area (CRGNSA) is not a Class 

I area and so not a part of the BART analysis, there was interest in the benefits to that 

area as a result of the proposed BART controls (semi-dry FGD with PJFF and 

NLNB/MOFA/SNCR). The modeling of the benefits predicted from the proposed BART 

control package show significant improvement in visibility in the CRGNSA. While 

slightly greater improvements are shown by the model from the use of a control package 

that includes SCR, these incremental improvements are not considered significant. 

This conclusion was independently verified in the draft Columbia River Gorge 

Air Quality Study Science Summary Report prepared by DEQ in conjunction with other 

state and federal governmental authorities and released publicly on September 27, 2007. 

There the report authors modeled the CRGNSA visibility impacts from all sources – 

natural and anthropogenic. For Boardman, the report analyzed visibility improvements 

associated with the emission levels achieved using new LNBs with modified OFA and 

SNCR for NOx control, semi-dry FGD (including PJFF) for SO2 and PM control. The 

report then compared these impacts to the modeled visibility improvements if Boardman 

emissions were reduced to “0” (i.e., complete shutdown of the plant). As the report 

notes, “practically zero” additional visibility benefit is achieved by reducing plant 

emissions from those achieved by the proposed BART control package all the way to 

zero plant emissions.3

 That assessment serves as independent verification of the 

conclusion that no material visibility benefit would be gained by controlling NOx through 

the use of new LNBs with modified OFA and SCR rather than new LNBs with modified 

OFA and SNCR. 

If eliminating the Boardman Plant generates “practically zero” additional benefit 

as compared to the proposed BART control package, the much smaller incremental 

benefit achieved by requiring SCR rather than SNCR would be immaterial. Given the 

extreme incremental costs associated with the use of new LNBs with modified OFA and 

SCR for NOx control, there is no technically sound basis for requiring SCR as part of the 

 

3 Columbia River Gorge Air Quality Study Science Summary Report (September 24, 2007), page 92. 
Boardman Plant Selection of Best Alternative 

110207 8-8 

BART control package. Therefore, while the BART control package poses significant 

economic impacts to the Boardman Plant and to electric utility customers throughout the 

Northwest, the selection of the new LNBs with modified OFA and SNCR and semi-dry 

FGD (including PJFF) control package will provide significant modeled visibility 

improvement in the Class I areas (as well as the CRGNSA) and enable enhanced mercury 

control. 

Table 8-1 summarizes the modeling results for the combination of 

NLNB/MOFA/SNCR and semi-dry FGD (including PJFF) as well as NLNB/MOFA/SCR 

and semi-dry FGD (including PJFF) controls. As shown in Appendix E, the CRGNSA 

correlates reasonably well with maximum impacts at any Class I area. As described 

above, in the draft Columbia River Gorge Air Quality Study Science Summary Report, 

reducing emissions from the presumptive BART levels to “0” emissions shows no 

improvement in visibility. Therefore, the improvement shown through modeling and 

identified in Table 8-1 may not be realized and does not justify the expense and 

additional impacts associated with NLNB/MOFA/SCR controls. 

Table 8-1 

Visibility Impact Summary 

Boardman Plant BART Determination 

Reduction in Number of Days Above 

0.5 deciview at Highest Frequency 

Area (Hells Canyon) 

(Percent Improvement) 

Reduction in Maximum 

Visibility Impact at 

Nearest Class I Area 

(Mt Hood) (deciviews) 

(Percent Improvement ) 

Combined Control Technologies 2003 2004 2005 2003-2005(1) 

NLNB/MOFA/SNCR and SemiDry FGD (Best Available Retrofit 

Technology) 95 (83%) 87 (81%) 88 (86%) 2.58 (56%) 

NLNB/MOFA/SCR and Semi-Dry 

FGD 112 (98%) 

105 

(98%) 101 (99%) 3.53 (77%) 

(1)Based on 22nd highest impact (98th percentile for 3 year period). 

NLNB/MOFA/SNCR – New Low NOx Burners with Modified Overfire Air and Selective Noncatalytic 

Reduction 

NLNB/MOFA/SCR – New Low NOx Burners with Modified Overfire Air and Selective Catalytic 

Reduction 

FGD – Flue Gas Desulfurization. 
Boardman Plant References 

110207 9-1 

9.0 References 

(1) CH2M HILL, Protocol for the Application of CALPUFF Determination Modeling 

Pursuant to BART Regulation—PGE Boardman Plant (Revised), January 2007 

(2) Federal Land Managers’ Air Quality Related Values Workgroup (FLAG), Phase I 

Report, December 2000. 

(3) Oregon Department of Environmental Quality (DEQ), Modeling Protocol for 

Washington, Oregon, and Idaho: Protocol for the Application of the CALPUFF 

Modeling System Pursuant to the Best Available Retrofit Technology (BART) 

Regulation, October 11, 2006. 

(4) US Environmental Protection Agency (EPA), Interagency Workgroup on Air 

Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations for 

Modeling Long-Range Transport Impacts, EPA-454/R-98-019, December 1998. 

(5) US Environmental Protection Agency (EPA), Guidance for Estimating Natural 

Visibility Conditions under the Regional Haze Rule, EPA-454/B-03-005, 

September 2003. 

(6) US Environmental Protection Agency (EPA), Regional Haze Regulations and 

Guidelines for Best Available Retrofit Technology (BART) Determinations, 

Federal Register, Vol. 70, No. 128, pp. 39104–30172, July 6, 2005. 

(7) Columbia River Gorge Air Quality Study Science Summary Report (September 

24, 2007). 
Boardman Plant Appendix A 

110207 A-1 

Appendix A 

Design Basis 
Boardman Plant Appendix A 

110207 A-2 

7/23/2007

Buckskin Original Design Black Butte Worst Case

Typical Low BTU High BTU High S Low Btu Minimum Maximum Reference

Coal Quality

Ultimate Coal analysis (wet basis)

Carbon (%) 49.01 47.85 55.96 46.90 - 58.51 Provided by PGE

Hydrogen (%) 3.52 3.40 3.70 2.98 - 4.00 Provided by PGE

Sulfur (%) 0.36 0.48 1.00 1.00 0.17 - 1.00 Provided by PGE

Nitrogen (%) 0.69 0.62 1.28 0.35 - 1.37 Provided by PGE

Oxygen (%) 10.87 10.82 9.88 9.67 - 13.20 Provided by PGE

Chlorine (%) 0.01 0.03 0.02 0.00 - 0.06 Provided by PGE

Ash (%) 4.88 6.40 8.00 2.75 - 9.00 Provided by PGE

Moisture (%) 30.66 30.40 20.16 17.30 - 35.65 Provided by PGE

Total (%) 100.00 100.00 100.00

Higher Heating Value, Btu/lb 8,316 8,020 9,500 8,020 8,020 - 9,800 Provided by PGE

Ash Analysis

Silica (SiO2) 30.76 31.59 51.53 25.00 - 61.34 Provided by PGE

Alumina (Al2O3) 13.51 15.29 19.68 12.27 - 23.53 Provided by PGE

Iron Oxide (Fe2O3) 5.65 4.55 5.25 2.22 - 8.60 Provided by PGE

Titania (TiO2) 1.03 1.12 0.96 0.36 - 1.42 Provided by PGE

Phosphorous (P2O5) 0.70 0.75 0.80 0.04 - 1.83 Provided by PGE

Lime (CaO) 24.78 22.85 8.28 4.09 - 26.83 Provided by PGE

Magnesia (MgO) 5.71 4.74 2.62 0.54 - 8.80 Provided by PGE

Sodium Oxide (Na2O) 1.59 1.27 2.40 0.65 - 3.37 Provided by PGE

Potassium Oxide (K2O) 0.23 0.44 0.56 0.17 - 1.41 Provided by PGE

Sulfur Trioxide (SO3) 15.10 16.55 7.50 3.00 - 19.80 Provided by PGE

Undetermined 0.96 0.85 0.43 0.43 - 2.50 Provided by PGE

Total (%) 100.00 100.00 100.00

Unit Characteristics

Unit Rating, Gross MW 617 617 617 Provided by PGE

Unit Rating, Net Normal Operating, MW 584 584 584 Provided by PGE

Net Turbine Heat Rate, Btu/kWh 7,650 7,650 7,650 Provided by PGE

Net Plant Heat Rate, Btu/kWh (HHV) 9,817 9,841 9,828 B&V Calculated

Boiler Efficiency, % 85.15 84.95 85.06 B&V Combustion Calculations

Boiler Heat Input, MBtu/hr (HHV) 5,736 5,750 5,742 5,793 Provided by PGE

Coal Flow Rate, ton/hr 345 358 302 B&V Calculated

Coal Flow Rate, lb/hr 689,795 716,947 604,467 B&V Combustion Calculations

Capacity Factor, % 85 85 85 Provided by PGE

Fly Ash Portion of Total Ash, % 80 80 70 Provided by PGE

Air Heater Leakage, % 11.00 11.00 11.00 B&V Combustion Calculations

Boiler Excess Air, % 17.111 17.131 16.545 B&V Combustion Calculations

Boiler Excess Oxygen, %O2 by w.v. 2.79 2.79 2.79 Provided by PGE

Economizer Outlet Conditions

Flue Gas Temperature, F 807 807 807 Provided by PGE

Flue Gas Pressure, in. w.g. -5.00 -5.00 -5.00 Provided by PGE

Flue Gas Mass Flow Rate, lb/hr 5,879,340 5,957,678 5,748,640 B&V Combustion Calculations

Volumetric Flue Gas Flow Rate, acfm 3,264,777 3,307,813 3,154,505 B&V Combustion Calculations

Flue Gas Composition

Oxygen, % by volume 2.70 2.70 2.70 B&V Combustion Calculations

Carbon Dioxide, % by volume 13.92 13.94 14.34 B&V Combustion Calculations

Moisture, % by volume 13.70 13.74 11.13 B&V Combustion Calculations

Sulfur Dioxide, % by volume 0.04 0.05 0.10 B&V Combustion Calculations

Sulfur Dioxide, acfm 1,251 1,734 3,046 B&V Combustion Calculations

Sulfur Dioxide, ppmv 383 524 966 B&V Calculated

Sulfur Dioxide, lb/hr 4,961 6,876 12,076 14,320 B&V Combustion Calculations

Sulfur Dioxide, lb/MBtu 0.86 1.20 2.10 2.49 B&V Calculated

Particulate Mass Rate, lb/hr 33,865 46,161 50,372 B&V Combustion Calculations

Particulate Concentration, gr/acf 1.210 1.628 1.863 B&V Calculated

Particulate Concentration, lb/MBtu 5.904 8.028 8.772 B&V Calculated

NOx Emissions, lb/MBtu 0.40 0.40 0.40 Provided by PGE

Portland General Electric

Boardman Unit 1

Design Basis Rev. 2

Range
Boardman Plant Appendix A 

110207 A-3 

7/23/2007

Air Heater Outlet Conditions

Flue Gas Temperature, F 297 297 297 Provided by PGE

Flue Gas Pressure, in. w.g. -13.00 -13.00 -13.00 Provided by PGE

Flue Gas Mass Flow Rate, lb/hr 6,526,072 6,613,025 6,380,543 B&V Combustion Calculations

Volumetric Flue Gas Flow Rate, acfm 2,213,484 2,242,692 2,141,130 B&V Combustion Calculations

Flue Gas Composition

Oxygen, % by volume 4.48 4.48 4.50 B&V Combustion Calculations

Carbon Dioxide, % by volume 12.53 12.54 12.89 B&V Combustion Calculations

Moisture, % by volume 12.54 12.58 10.22 B&V Combustion Calculations

Sulfur Dioxide, % by volume 0.03 0.05 0.09 B&V Combustion Calculations

Sulfur Dioxide, acfm 763 1,058 1,858 B&V Combustion Calculations

Sulfur Dioxide, ppmv 345 472 868 B&V Calculated

Sulfur Dioxide, lb/hr 4,961 6,876 12,076 14,320 B&V Combustion Calculations

Sulfur Dioxide, lb/MBtu 0.86 1.20 2.10 2.49 B&V Calculated

Particulate Mass Rate, lb/hr 33,865 46,161 50,372 B&V Combustion Calculations

Particulate Concentration, gr/acf 1.785 2.401 2.745 B&V Calculated

Particulate Concentration, lb/MBtu 5.904 8.028 8.772 B&V Calculated

NOx Emissions, lb/MBtu 0.40 0.40 0.40 Provided by PGE

ID Fan Outlet Conditions

Flue Gas Temperature, F 293 293 293 Provided by PGE

Flue Gas Pressure, in. w.g. 1.00 1.00 1.00 Provided by PGE

Flue Gas Mass Flow Rate, lb/hr 6,526,072 6,613,025 6,380,543 B&V Combustion Calculations

Volumetric Flue Gas Flow Rate, acfm 2,123,666 2,151,689 2,054,247 B&V Combustion Calculations

Flue Gas Composition

Oxygen, % by volume 4.48 4.48 4.50 B&V Combustion Calculations

Carbon Dioxide, % by volume 12.53 12.54 12.89 B&V Combustion Calculations

Moisture, % by volume 12.54 12.58 10.22 B&V Combustion Calculations

Sulfur Dioxide, % by volume 0.03 0.05 0.09 B&V Combustion Calculations

Sulfur Dioxide, acfm 732 1,015 1,783 B&V Combustion Calculations

Sulfur Dioxide, ppmv 345 472 868 B&V Calculated

Sulfur Dioxide, lb/hr 4,961 6,876 12,076 14,320 B&V Combustion Calculations

Sulfur Dioxide, lb/MBtu 0.86 1.20 2.10 2.49 B&V Calculated

Particulate Mass Rate, lb/hr 56 56 56 B&V Calculated

Particulate Concentration, gr/acf 0.003 0.003 0.003 B&V Calculated

Particulate Concentration, lb/MBtu 0.0098 0.0098 0.0098 Provided by PGE

NOx Emissions, lb/MBtu 0.40 0.40 0.40 Provided by PGE

Stack Outlet Emissions

Sulfur Dioxide, lb/MBtu 0.86 1.20 2.10 2.49

Particulate Concentration, lb/MBtu 0.0098 0.0098 0.0098 Provided by PGE

NOx Emission Rate, lb/MBtu 0.40 0.40 0.40 Provided by PGE

Portland General Electric

Boardman Unit 1

Design Basis Rev. 2
Boardman Plant Appendix B 

110207 B-1 

Appendix B 

Stack Outlet Conditions 
Boardman Plant 

110207 

Heat Input (HHV) = 5,793 MBtu/hrStack Outlet Conditions Flow (acfm) Stack Velocity (ft/s) Temperature (°F) Pressure (in, wg) SO2 (lb/MBtu) SO2 (lb/hr) NOx (lb/MBtu) 

Baseline Case1. Existing Operation 2,159,900 95 293 0.50 0.85 4,943 0.54 NOx Controlled Outlet Conditions1. New Low NOx Burners with Modified OFA System and Selective Catalytic Reduction or SCR 2,098,800 92 270 0.50 0.85 4,943 0.07 

2. New Low NOx Burners with Modified OFA System and SNCR 2,160,500 95 293 0.50 0.85 4,943 0.23 3. Upgraded Low NOx Burners with Existing OFA System Operation and SNCR 2,161,300 95 293 0.50 0.85 4,943 0.27 

4. New Low NOx Burners with Modified OFA System 2,159,900 95 293 0.50 0.85 4,943 0.28 5. Upgraded Low NOx Burners with Existing OFA System Operation 2,159,900 95 293 0.50 0.85 4,943 0.32 6. Selective Non-Catalytic Reduction (SNCR) 2,162,600 95 293 0.50 0.85 4,943 0.32 7. Upgraded Low NOx Burners 2,159,900 95 293 0.50 0.85 4,943 0.38 8. Overfire Air System Operation 2,159,900 95 293 0.50 0.85 4,943 0.40 SO2 Controlled Outlet Conditions1. Wet Flue Gas Desulfurization (FGD) 1,823,200 60 136 0.50 0.10 579 0.54 2. Semi-Dry Flue Gas Desulfurization (FGD) 1,901,700 83 170 0.50 0.15 869 0.54 PM Controlled Outlet Conditions1. Pulse Jet Fabric Filter (PJFF) 2,159,900 95 293 0.50 0.85 4,943 0.54 2. Compact Hybrid Particulate Collector (COHPAC) 2,159,900 95 293 0.50 0.85 4,943 0.54 

3. Wet ESP 1,823,200 60 136 0.50 0.85 4,943 0.54 4. Existing ESP with Operational Restrictions 2,159,900 95 293 0.50 0.85 4,943 0.54 

Composite Controlled Outlet Conditions1. New Low NOx Burners with Modified OFA System and SNCR and Semi-Dry FGD 1,902,200 83 170 0.50 0.15 869 0.23 2. New Low NOx Burners with Modified OFA System and SCR and Semi-Dry FGD 1,905,800 84 170 0.50 0.15 869 0.07 Notes1. SO2 based upon no SO2 to SO3 conversion.

2. All PM values based upon front half filterable amounts only.3. Stack velocity (except for Wet FGD and Wet ESP) based upon existing stack diameter of 22 ft.

Portland General Electric (PGE) - Boardman Unit 1

Best Available Retrofit Technology (BART) Engineering Analysis

Stack Outlet Data for Visibility Modeling
Boardman Plant Appendix C 

110207 C-1 

Appendix C 

Design Concept Definitions 
Boardman Plant Appendix C 

110207 C-2 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Overfire Air System Operation 

Process Description Operate existing overfire air (OFA) system during normal operation. Existing OFA system currently only used when needed to meet 

permit limit due to boiler efficiency impacts, slagging issues, and poor operability. 

 Pollutant NOx 

 Emissions 

 lb/MMBTU 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBTU 0.40 

 ton/yr 9,726 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Existing system to be operational at all times in order to reduce combustion NOx formation. 

Addition of coal flow monitors in coal pipes leading to burner. Addition of water cannon system 

to boiler wall. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Addition of NOx optimization into combustion monitoring process. 

Fan Modifications None. 

Power Supply/Aux Power Modifications No significant aux power impacts from additional equipments. 

Enclosures Requirements None. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Boiler slagging 

Other Assumptions 

• Water cannon system, NOx optimization, and monitoring systems added to overcome boiler slagging issues to allow OFA system operations. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Equipment exists at plant but presently not used. 
Boardman Plant Appendix C 

110207 C-3 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Upgraded Low NOx Burners 

Process Description Low NOx Burners (LNB) - Upgrade existing. Modifications of burner tips and burner balancing using CFD modeling, combustion air 

monitoring, and coal flow monitoring. 

 Pollutant NOx 

 Emissions 

 lb/MMBTU 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBTU 0.38 

 ton/yr 9,240 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other N/A 

Location of Major Process Equipment Upgrade/additional components to existing burners. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. 

Reagent Storage None. 

Control System Modifications None. 

Fan Modifications None. 

Power Supply/Aux Power Modifications None. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

• No major impact in plant availability. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Low NOx Burners already in operation. 
Boardman Plant Appendix C 

110207 C-4 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Upgraded Low NOx Burners with Existing OFA System Operation 

Process Description Upgrade existing Low NOx Burners (LNBs) with existing OFA system. Modifications of burner tips and burner balancing. 

 Pollutant NOx 

 Emissions 

 lb/MMBTU 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBTU 0.32 

 ton/yr 7,781 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other N/A 

Location of Major Process Equipment Upgrade existing burners. Location remains the same. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. 

Reagent Storage None. 

Control System Modifications None 

Fan Modifications None. 

Power Supply/Aux Power Modifications None 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

• No major impact in plant availability. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Low NOx burners already in operation. Existing OFA system would be placed in operation full time. 
Boardman Plant Appendix C 

110207 C-5 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology New Low NOx Burners with Modified OFA System 

Process Description New low NOx burners (LNB), modified overfire air (OFA) system. Install new OFA ports at location to be determined during detailed 

engineering analysis. 

 Pollutant NOx 

 Emissions 

 lb/MMBTU 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBTU 0.28 

 ton/yr 6,808 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description Slight increase in LOI and CO. No impact on ash sales 

 Other N/A 

Location of Major Process Equipment Install new burners in the existing burner openings. Install new OFA ports at location to be 

determined after analysis. 

Inlet/Outlet Connections and Interconnecting Ducts OFA and burners tie-in to existing air duct and coal pipes. 

Reagent Storage None. 

Control System Modifications Existing control system modification to utilize new equipment. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

• No major impact in plant availability. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

• No air heater modifications or boiler/duct stiffening included. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Replacing older low NOx burners already in operation and modifying OFA system to support current technology low NOx burners is 

common retrofit system. 
Boardman Plant Appendix C 

110207 C-6 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Selective Noncatalytic Reduction (SNCR) 

Process Description Selective Noncatalytic Reduction (SNCR) 

 Pollutant NOx 

 Emissions 

 lb/MMBTU 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBTU 0.32 

 ton/yr 7,781 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Urea) 2,637 lb/hr 

 Water 200 gpm 

 Energy 70 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Minimal impact on ash sales. 

 Other Up to 10 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. 

Inlet/Outlet Connections and Interconnecting Ducts Install wall injectors and lance-type injectors for SNCR in the boiler. 

Reagent Storage Storage tank for urea at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions 

• No major impact in plant availability. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

• No boiler/duct stiffening included. 

• Air heater modifications included in analysis. 

• No impact on potential ash sales. 

• Reagent used in SNCR process is aqueous urea. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

110207 C-7 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Upgraded Low NOx Burners with Existing OFA System Operation 

and SNCR 

Process Description Upgrade existing Low NOx Burners (LNBs) with existing OFA system. Modifications of burner tips and burner balancing. Selective 

Noncatalytic Reduction (SNCR) system for postcombustion reduction of NOx. 

 Pollutant NOx 

 Emissions 

 lb/MMBTU 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBTU 0.27 

 ton/yr 6,565 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Urea) 2,072 lb/hr 

 Water 200 gpm 

 Energy 70 kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, minimal impact on ash sales 

 Other Up to 10 ppm ammonia slip. 

Location of Major Process Equipment Upgrade existing burners. Location remains the same. Injection skid and ammonia tank at 

grade with truck unloading station. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

• No major impact in plant availability. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

• No boiler/duct stiffening included and no impact on ash sales. 

• Reagent used in SNCR process is aqueous urea. 

• Upgraded low NOx burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

110207 C-8 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology New Low NOx Burners with Modified OFA System and SNCR 

Process Description New low NOx burners (LNB), modified overfire air (OFA) system. Install new OFA ports at locations determined during detailed 

engineering analysis. A new SNCR system shall be installed into upper boiler level. 

 Pollutant NOx 

 Emissions 

 lb/MMBTU 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBTU 0.23 

 ton/yr 5,593 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Urea) 942 lb/hr 

 Water 200 gpm 

 Energy 70 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Slight increase in LOI and CO. Minimal impact on ash sales 

 Other Up to 10 ppm ammonia slip 

Location of Major Process Equipment Install new burners in the existing burner openings. Install new OFA ports at location to be 

determined after engineering analysis. Injection skid and urea tank for SNCR at grade with 

truck unloading station. 

Inlet/Outlet Connections and Interconnecting Ducts OFA and burners tie-in with existing air duct and coal pipes. Install wall injectors and lance-type 

injectors for SNCR in the boiler. 

Reagent Storage Storage tank for urea at grade. 

Control System Modifications Existing control system modification to utilize new equipment. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

• No major impact in plant availability. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

• No boiler/duct stiffening included. 

• Air heater modifications included in analysis. 

• Reagent used in SNCR process is aqueous urea. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Replacing older low NOx burners already in operation and modifying OFA system to support new technology low NOx burners is a 

common retrofit system. SNCR can be included with NLNB/MOFA combustion controls to increase overall system removal. 
Boardman Plant Appendix C 

110207 C-9 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology New Low NOx Burners with Modified OFA System and Selective 

Catalytic Reduction (SCR) 

Process Description New low NOx burners (LNB), modified overfire air (OFA) system complementing new SCR system. 

 Pollutant NOx 

 Emissions 

 lb/MMBTU 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBTU 0.07 

 ton/yr 1,702 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added 8 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Ammonia) 475 lb/hr 

 Energy 2,537 kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Minimal impact on ash sales. 

 Other 5 ppm ammonia slip 

Location of Major Process Equipment Install new burners in the existing burner openings. Install new OFA ports at location to be 

determined after engineering analysis. Install SCR reactor above space between the boiler and 

air heater. Install NH3 vaporizers at grade. 

Inlet/Outlet Connections and Interconnecting Ducts OFA and burners tie-in with existing air duct and coal pipes. SCR inlet and outlet ducts 

connected into duct entering the air heater. 

Reagent Storage Locate NH3 storage at grade in suitable protective structure or away from unit to limit risk from 

leaks. 

Control System Modifications Existing control system modification to utilize new equipment. 

Fan Modifications Assume booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume medium cost expansion will be required for aux electric system. 

Enclosures Requirements Ammonia injection grid area and sonic horns are to be enclosed. Burner and OFA systems are 

enclosed in boiler building. 

Demolition or Relocation Requirements Existing economizer outlet ductwork and boiler building wall. 

Major Constructability Issues Finding support steel location under SCR reactor. Tying the SCR into the ductwork 

downstream of the economizer in the ductwork. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning. SO2 to SO3 conversion by the catalyst, causing pluggage and 

corrosion in air heater. 

Other Assumptions 

• No major impact in plant availability. 

• Temperature range of flue gas at economizer outlet is acceptable after modifications of boiler superheater section. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

• Air heater modifications, flue gas handling systems and ammonia handling systems included. 

• No boiler/duct stiffening included. 

• Modifications made to boiler heat transfer surface area to optimize boiler flue gas outlet temperature for SCR operations. 

• No impact on potential ash sales and no additional heating i.e. economizer bypass or duct burners required to achieve operating temperature at low loads. 

• Reagent is ammonia and can be anhydrous, aqueous or from urea. Anhydrous ammonia selected as basis. 

• SCR reactor includes three initial catalyst layers and one spare layer (3 + 1 arrangement). 

• Energy consumption includes ID fan power requirements to overcome SCR system resistance. 
Boardman Plant Appendix C 

110207 C-10 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

110207 C-11 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Wet Flue Gas Desulfurization (FGD) and upstream Fabric Filter 

Process Description Limestone forced oxidation wet flue gas desulfurization process (wet scrubber) with fabric filter upstream of wet scrubber for mercury 

and particulate control. Description is typical for all absorber/scrubber based FGD systems. 

 Pollutant SO2 

 Emissions 

 lb/MMBTU 0.614 

 ton/yr 14,902 

 Controlled Emissions 

 lb/MMBTU 0.10 

 ton/yr 2,429 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 14 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Limestone) 5.9 tph 

 Water 595 gpm 

 Energy 15,254 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Calcium Sulfite (CaSO3•1/2H20), Calcium Sulfate (CaSO4•2H2O) mixture 

 Production Rate 10.8 tph 

Location of Major Process Equipment Fabric filter and wet FGD absorber module flue gas path location is after ID fans and before 

new wet stack. Reagent preparation and byproduct dewatering equipment to be located around 

absorber module, location of new wet stack to be determined later. 

Inlet/Outlet Connections and Interconnecting Ducts Connected to ID fan outlet ducts and discharge to the new stack. 

Reagent Storage Silo for reagent will be required. 

Control System Modifications New stand-alone control system, tie in to plant DCS control system. 

Fan Modifications Assume new booster/ID fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Aux electric system modifications will be required. 

Enclosures Requirements Oxidation air blower building, control building, slaker and slurry tank building, byproduct 

dewatering building. 

Demolition or Relocation Requirements Abandon existing stack in place. 

Major Constructability Issues Construction of new stack with impacts on restricted safety zone possibly limiting or extending 

schedule for construction of ductwork, fabric filter system, ID booster fans and wet FGD system. 

Significant Issues or Challenges Tie-in to the current fan ID outlets during a major planned outage. 

Other Assumptions 

• No modifications to ESP and existing ESP remain in service 

• No impact on potential ash sales since existing ESP remains in operation upstream of new AQC equipment. 

• One FGD absorber is assumed. 

• Fabric filter upstream of wet FGD system is required for mercury and particulate control. 

• New wet chimney included. 

• No major impact on plant availability is assumed. 

• Flue gas handling and ID fan system costs included. 

• The FGD byproduct solids would be processed for disposal in a landfill. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

110207 C-12 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Semi-Dry Flue Gas Desulfurization (FGD) 

Process Description Semi-dry lime FGD process using the Spray Dryer Absorber (SDA) with downstream Pulse Jet Fabric Filter (PJFF) 

 Pollutant SO2 

 Emissions 

 lb/MMBTU 0.614 

 ton/yr 14,902 

 Controlled Emissions 

 lb/MMBTU 0.15 

 ton/yr 3,643 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 12 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Lime) 5.0 tph 

 Water 336 gpm 

 Energy 4,088 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Calcium Sulfite (CaSO3•1/2H20), Calcium Sulfate (CaSO4•2H2O) mixture 

 Production Rate 10.0 tph 

Location of Major Process Equipment Spray Dryer Absorber and Pulse Jet Fabric Filter flue gas flow path location is after ID fans and 

before stack. 

Inlet/Outlet Connections and Interconnecting Ducts Connected to ID fan outlet ducts and discharge to the existing stack. 

Reagent Storage Silo for reagent will be required. 

Control System Modifications New stand-alone control system, tie in to plant DCS control system. 

Fan Modifications Assume new booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Aux electric system modifications will be required. 

Enclosures Requirements Compressor building, control building, slaker and slurry tank building. Enclose the top pendant 

areas, the bottom exit and hopper areas of spray dryer and fabric filter. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Tie-in to the current fan ID outlets and stack breaching during a major planned outage. 

Other Assumptions 

• No modifications to ESP and existing ESP remain in service 

• No impact on potential ash sales since existing ESP remains in operation upstream of new AQC equipment. 

• Two x 60% FGD absorbers are assumed. 

• PJFF provided as integral part of scrubber system also provides mercury and particulate control. 

• No major impact on plant availability is assumed. 

• Flue gas handling system and ID fans upgrades/addition included. 

• Lime reagent storage and handling system included. 

• Existing chimney is acceptable for resulting flue gas. 

• The FGD byproducts solids would be collected in the new fabric filter and would require a separate ash transport system and silo (included). 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

110207 C-13 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Existing ESP with Operational Restrictions 

Process Description Existing electrostatic precipitator (ESP) with operational restrictions (such as more limitations on coal specifications). 

 Pollutant PM 

 Emissions 

 lb/MMBTU 0.0170 

 ton/yr 417 

 Controlled Emissions 

 lb/MMBTU 0.012 

 ton/yr 295 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 2.0 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy None kW 

 Maintenance 1% of direct material cost 

Byproduct Description Fly ash 

 Other N/A 

Location of Major Process Equipment Currently Existing. 

Inlet/Outlet Connections and Interconnecting Ducts Existing/None. 

Reagent Storage None. 

Control System Modifications None. 

Fan Modifications None. 

Power Supply/Aux Power Modifications None. 

Enclosures Requirements None. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges None. 

Other Assumptions 

• Will limit fuel flexibility and require increased use of flue gas conditioning equipment. 

State of Availability Commercial. 

Technical Feasibility Technically feasible. 

Reasons Currently existing at unit. 
Boardman Plant Appendix C 

110207 C-14 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Pulse Jet Fabric Filter (PJFF) 

Process Description Pulse Jet Fabric Filter (PJFF) 

 Pollutant PM 

 Emissions 

 lb/MMBTU 0.0170 

 ton/yr 417 

 Controlled Emissions 

 lb/MMBTU 0.012 

 ton/yr 295 

 Inlet Flow Basis, acfm 2,242,692 

 Pressure Drop Added (in. wc) 8 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy 3,574 kW 

 Maintenance 3% of direct material cost. (Not including bag replacement). 

Byproduct Description None. 

 Other N/A 

Location of Major Process Equipment Replace existing ESP with new Pulse Jet Fabric Filter (PJFF). Flue gas flow path location will 

be after air heater outlet and before existing ID fan inlet. 

Inlet/Outlet Connections and Interconnecting Ducts Ductwork connection after air heater outlet and before existing ID fan inlet. 

Reagent Storage None. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume new booster fans or ID fan modifications and duct stiffening will be required. 

Power Supply/Aux Power Modifications Aux electric system modification will be required. 

Enclosures Requirements The top pendent area and bottom hopper area of the fabric filter should be enclosed. 

Demolition or Relocation Requirements None. Existing ESP to be abandoned in place. 

Major Constructability Issues Modification to existing ash handling system. 

Significant Issues or Challenges Installation of new PJFF during a planned major outage. 

Other Assumptions 

• No major impact in plant availability. 

• Collector bag life is 3 years. 

• Existing ash disposal system should be capable of servicing the PJFF. 

• Flue gas handling and ID fan system upgrades/addition included. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons . 
Boardman Plant Appendix C 

110207 C-15 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Compact Hybrid Particulate Collector (COHPAC) 

Process Description High A/C Ratio Fabric filter, or known as Compact Hybrid Particulate Collector (COHPAC) 

 Pollutant PM 

 Emissions 

 lb/MMBTU 0.0170 

 ton/yr 417 

 Controlled Emissions 

 lb/MMBTU 0.012 

 ton/yr 295 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 6.0 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy 2,716 kW 

 Maintenance 3% of direct material cost (not including bag costs) 

Byproduct Description None. 

 Other N/A 

Location of Major Process Equipment COHPAC flue gas path location to be downstream of existing ESP. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to flue gas ductwork downstream of existing ESP. 

Reagent Storage None. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume new booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Aux electric system upgrade will be required. 

Enclosures Requirements The top pendant area and the bottom hopper area are enclosed. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Tie-in to the current ID fan outlets during a major planned outage. 

Other Assumptions 

• No major impact in plant availability. 

• Collector bag life is 3 years. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

• The existing ESP will be left in place upstream of the fabric filter. The fly ash that is collected in the ESP is handled separately and can be sold. 

• COHPAC might be used as a component for mercury removal systems. 

• Additional ash handling system. 

State of Availability Commercial. 

Technical Feasibility Technically feasible. 

Reasons COHPAC can function as a polishing filter for additional particulate removal and may be used as a component for mercury removal

systems. 
Boardman Plant Appendix C 

110207 C-16 

Design Concept Definition 

Site Name Boardman Units 1 

Client Name Portland General Electric Process Technology Wet ESP 

Process Description Wet Electrostatic Precipitator (WESP or Wet ESP) 

 Pollutant PM 

 Emissions 

 lb/MMBTU 0.0170 

 ton/yr 417 

 Controlled Emissions 

 lb/MMBTU 0.012 

 ton/yr 295 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 4.0 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Mg(OH)2) 20 lb/hr 

 Water 100 gpm 

 Energy 1,752 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description None. 

 Other N/A 

Location of Major Process Equipment Wet ESP flue gas path location to be downstream of existing ESP. Water treatment system to 

be located next to wet ESP. Additional byproduct disposal system is required. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to flue gas ductwork downstream of existing ESP. 

Reagent Storage (Mg(OH)2) storage at grade as part of water treatment system. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume new booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Substantial aux electric system modification will be required. 

Enclosures Requirements The top pendant area and the bottom hopper area are enclosed. 

Demolition or Relocation Requirements Abandon existing stack in place. 

Major Constructability Issues Construction of new stack with impacts on restricted safety zone possibly limiting or extending 

schedule for construction of other control technology equipment. 

Significant Issues or Challenges Tie-in to the current ID fan outlets during a major planned outage. 

Other Assumptions 

• No major impact in plant availability, however, periodic outages for intense off-line cleanings may be required. 

• Aux electric usage is a major factor if using wet ESP as a polishing filter and for SO3 mitigation. 

• The site has sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down, and staging. 

• The existing ESP will be left in place upstream of the WESP. The fly ash that is collected in the ESP is handled separately and can be sold. 

• Waste water treatment system included. 

State of Availability Commercial. 

Technical Feasibility Technically feasible. 

Reasons . 
Boardman Plant Appendix D 

110207 D-1 

Appendix D 

Cost Analysis Summary
Boardman Plant Appendix D 

110207 D-2 

Technology: Overfire Air System Operation Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

Neural network system for NOx optimization $345,000 B&V cost estimate

NOx monitoring equipment $182,000 B&V cost estimate

Water cannon system $1,452,000 B&V cost estimate

Subtotal capital cost (CC) $1,979,000

Freight $99,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $2,078,000

Direct installation costs

Foundation & supports $0 (PEC) X 0.0%

Handling & erection $416,000 (PEC) X 20.0%

Electrical $312,000 (PEC) X 15.0%

Piping $42,000 (PEC) X 2.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $52,000 (PEC) X 2.5%

Relocation $0 (PEC) X 0.0%

Total direct installation costs (DIC) $822,000

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,900,000

Indirect Costs

Engineering $348,000 (DC) X 12.0%

Owner's cost $58,000 (DC) X 2.0%

Construction management $145,000 (DC) X 5.0%

Start-up and spare parts $58,000 (DC) X 2.0%

Performance test $50,000 Engineering estimate

Contingencies $290,000 (DC) X 10.0%

Total indirect costs (IC) $949,000

Allowance for Funds Used During Construction (AFDC) $173,000 [(DC)+(IC)] 8.99% 1 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $4,022,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $87,000 (DC) X 3.0%

Total fixed annual costs $87,000

Variable annual costs

Replacement power due to efficiency hit $540,000 Engineering estimates, 0.2% efficiency drop, and 0.05 $/kWh

Total variable annual costs $540,000

Total direct annual costs (DAC) $627,000

Indirect Annual Costs

Cost for capital recovery $380,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $380,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,007,000
Boardman Plant Appendix D 

110207 D-3 

Technology: Upgraded Low NOx Burners Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

New coal elbow, nozzle with air vane, fuel injector $2,753,000 from vendor quote, 06/30/06

barrel, air zone swirler and coal piping

Dynamic classifier for coal pulverizers $1,760,000 B&V cost estimate

Coal/air flow instrument for burners $935,000 B&V cost estimate

Subtotal capital cost (CC) $5,448,000

Freight $272,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $5,720,000

Direct installation costs

Foundation & supports $0 (PEC) X 0.0%

Handling & erection $1,144,000 (PEC) X 20.0%

Electrical $572,000 (PEC) X 10.0%

Piping $0 (PEC) X 0.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $143,000 (PEC) X 2.5%

Relocation $0 (PEC) X 0.0%

Total direct installation costs (DIC) $1,859,000

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $7,579,000

Indirect Costs

Engineering $909,000 (DC) X 12.0%

Owner's cost $152,000 (DC) X 2.0%

Construction management $379,000 (DC) X 5.0%

Start-up and spare parts $152,000 (DC) X 2.0%

Performance test $50,000 Engineering estimate

Contingencies $758,000 (DC) X 10.0%

Total indirect costs (IC) $2,400,000

Allowance for Funds Used During Construction (AFDC) $449,000 [(DC)+(IC)] 8.99% 1 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $10,428,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $227,000 (DC) X 3.0%

Total fixed annual costs $227,000

Variable annual costs

N/A $0 Similar annual costs as current LNB

Total variable annual costs $0

Total direct annual costs (DAC) $227,000

Indirect Annual Costs

Cost for capital recovery $984,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $984,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,211,000
Boardman Plant Appendix D 

110207 D-4 

Technology: Upgraded LNB with existing OFA System operation Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

New coal elbow, nozzle with air vane, fuel injector $2,753,000 from vendor quote, 06/30/06

barrel, air zone swirler and coal piping

Dynamic classifier for coal pulverizers $1,760,000 B&V cost estimate

Coal/air flow instrument for burners $935,000 B&V cost estimate

Neural network system for NOx optimization $345,000 B&V cost estimate

NOx monitoring equipment $182,000 B&V cost estimate

Water cannon system $1,452,000 B&V cost estimate

Subtotal capital cost (CC) $7,427,000

Freight $371,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $7,798,000

Direct installation costs

Foundation & supports $0 (PEC) X 0.0%

Handling & erection $1,560,000 (PEC) X 20.0%

Electrical $780,000 (PEC) X 10.0%

Piping $0 (PEC) X 0.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $195,000 (PEC) X 2.5%

Relocation $0 (PEC) X 0.0%

Total direct installation costs (DIC) $2,535,000

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $10,333,000

Indirect Costs

Engineering $1,240,000 (DC) X 12.0%

Owner's cost $207,000 (DC) X 2.0%

Construction management $517,000 (DC) X 5.0%

Start-up and spare parts $207,000 (DC) X 2.0%

Performance test $50,000 Engineering estimate

Contingencies $1,033,000 (DC) X 10.0%

Total indirect costs (IC) $3,254,000

Allowance for Funds Used During Construction (AFDC) $611,000 [(DC)+(IC)] 8.99% 1 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $14,198,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $310,000 (DC) X 3.0%

Total fixed annual costs $310,000

Variable annual costs

Replacement power due to efficiency hit $540,000 Engineering estimates, 0.2% efficiency drop, and 0.05 $/kWh

Total variable annual costs $540,000

Total direct annual costs (DAC) $850,000

Indirect Annual Costs

Cost for capital recovery $1,340,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $1,340,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,190,000
Boardman Plant Appendix D 

110207 D-5 

Technology: New Low NOx Burners & Modified OFA System Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

New Low NOx Burners with new secondary air $4,593,000 from vendor quote, 06/30/06

registers

(8) OFA ports and (4) wing ports with tube throat $1,994,000 from vendor quote, 06/30/06

openings

Neural network system for NOx optimization $346,000 B&V cost estimate

NOx monitoring equipment $182,000 B&V cost estimate

Water cannon system $1,452,000 B&V cost estimate

Dynamic classifier for coal pulverizers $1,760,000 B&V cost estimate

Coal/air flow instrument for burners $935,000 B&V cost estimate

Modulating orifice for burners $282,000 B&V cost estimate

Subtotal capital cost (CC) $11,544,000

Freight $577,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $12,121,000

Direct installation costs

Foundation & supports $0 (PEC) X 0.0%

Handling & erection $6,061,000 (PEC) X 50.0%

Electrical $1,212,000 (PEC) X 10.0%

Piping $606,000 (PEC) X 5.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $606,000 (PEC) X 5.0%

Relocation $606,000 (PEC) X 5.0%

Total direct installation costs (DIC) $9,091,000

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $21,212,000

Indirect Costs

Engineering $2,545,000 (DC) X 12.0%

Owner's cost $424,000 (DC) X 2.0%

Construction management $1,061,000 (DC) X 5.0%

Start-up and spare parts $424,000 (DC) X 2.0%

Performance test $50,000 Engineering estimate

Contingencies $4,242,000 (DC) X 20.0%

Total indirect costs (IC) $8,746,000

Allowance for Funds Used During Construction (AFDC) $2,693,000 [(DC)+(IC)] 8.99% 2 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $32,651,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $636,000 (DC) X 3.0%

Total fixed annual costs $636,000

Variable annual costs

N/A $0 No associated annual cost

Total variable annual costs $0

Total direct annual costs (DAC) $636,000

Indirect Annual Costs

Cost for capital recovery $3,082,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $3,082,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,718,000
Boardman Plant Appendix D 

110207 D-6 

Technology: Selective Non-Catalytic Reduction Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $5,083,000 CUECost estimate

Initial urea inventory $255,000 150,000 gal. urea initial inventory

Air preheater modifications $2,835,000 CUECost estimate

Subtotal capital cost (CC) $8,173,000

Freight $490,380 (CC) X 6.0%

Total purchased equipment cost (PEC) $8,663,000

Direct installation costs

Foundation & supports $433,000 (PEC) X 5.0%

Handling & erection $866,000 (PEC) X 10.0%

Electrical $866,000 (PEC) X 10.0%

Piping $260,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $173,000 (PEC) X 2.0%

Relocation $173,000 (PEC) X 2.0%

Total direct installation costs (DIC) $2,771,000

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $11,434,000

Indirect Costs

Engineering $1,372,000 (DC) X 12.0%

Owner's cost $572,000 (DC) X 5.0%

Construction management $1,143,000 (DC) X 10.0%

Start-up and spare parts $343,000 (DC) X 3.0%

Performance test $100,000 Engineering estimate

Contingencies $1,715,000 (DC) X 15.0%

Total indirect costs (IC) $5,245,000

Allowance for Funds Used During Construction (AFDC) $750,000 [(DC)+(IC)] 8.99% 1 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $17,429,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 1 FTE and 100,000 $/year Estimated manpower

Maintenance labor and materials $343,000 (DC) X 3.0%

Total fixed annual costs $443,000

Variable annual costs

Reagent $3,093,000 2,637 lb/hr and 315 $/ton Engineering estimate

Auxiliary and ID fan power $26,000 70 kW and 0.05 $/kWh Engineering estimate

Water $179,000 200 gpm and 2 $/1,000 galEngineering estimate

Total variable annual costs $3,298,000

Total direct annual costs (DAC) $3,741,000

Indirect Annual Costs

Cost for capital recovery $1,645,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $1,645,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $5,386,000
Boardman Plant Appendix D 

110207 D-7 

Technology: New Low NOx Burners & Modified OFA System & SNCR Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Total Capital Investment (TCI) cost for:

New Low NOx Burners & Modified OFA System $32,651,000 Cost estimate for independent system

Selective Non-Catalytic Reduction System $17,429,000 Cost estimate for independent system

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $50,080,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 1 FTE and 100,000 $/year Estimated manpower

Maintenance labor and materials $979,000 (DC) X 3.0%

Total fixed annual costs $1,079,000

Variable annual costs

Reagent $1,105,000 942 lb/hr and 315 $/ton Engineering estimate

Auxiliary and ID fan power $26,000 70 kW and 0.05 $/kWh Engineering estimate

Water $179,000 200 gpm and 2 $/1,000 galEngineering estimate

Total variable annual costs $1,310,000

Total direct annual costs (DAC) $2,389,000

Indirect Annual Costs

Cost for capital recovery $4,728,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $4,728,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $7,117,000
Boardman Plant Appendix D 

110207 D-8 

Technology: Upgraded Low NOx Burners with existing OFA and SNCR Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Total Capital Investment (TCI) cost for:

Upgraded Low NOx Burners with existing OFA System $14,198,000 Cost estimate for independent system

Selective Non-Catalytic Reduction System $17,429,000 Cost estimate for independent system

Total Capital Investment (TCI) = $31,627,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 1 FTE and 100,000 $/year Estimated manpower

Maintenance materials and labor $653,000 (DC) X 3.0%

Total fixed annual costs $753,000

Variable annual costs

Replacement power due to efficiency hit $540,000 Engineering estimates, 0.2% efficiency drop, and 0.05 $/kWh

Reagent $2,430,000 2,072 lb/hr and 315 $/ton Engineering estimate

Auxiliary power $26,000 70 kW and 0.05 $/kWh Engineering estimate

Water $179,000 200 gpm and 2 $/1,000 galEngineering estimate

Total variable annual costs $3,175,000

Total direct annual costs (DAC) $3,928,000

Indirect Annual Costs

Cost for capital recovery $2,986,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $2,986,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $6,914,000
Boardman Plant Appendix D 

110207 D-9 

Technology: New Low NOx Burners & Modified OFA System & SCR Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing $5,580,000 CUECost estimate

Ammonia handling and injection $2,589,000 CUECost estimate

Initial catalyst and ammonia $4,750,000 CUECost estimate

Electrical system modification $2,261,000 from ref. cost

ID fans $3,658,000 from ref. cost

Flue gas handling system $6,500,000 from ref. cost

Air preheater modifications $2,835,000 CUECost estimate

Ash handling system $3,110,000 CUECost estimate

Subtotal capital cost (CC) $31,283,000

Instruments and controls $3,128,000 (CC) X 10.0%

Freight $1,564,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $35,975,000

Direct installation costs

Foundation & supports $13,671,000 (PEC) X 38.0%

Handling & erection $13,311,000 (PEC) X 37.0%

Electrical $8,994,000 (PEC) X 25.0%

Piping $2,698,000 (PEC) X 7.5%

Insulation $3,598,000 (PEC) X 10.0%

Painting $360,000 (PEC) X 1.0%

Demolition $6,116,000 (PEC) X 17.0%

Relocation $4,317,000 (PEC) X 12.0%

Total direct installation costs (DIC) $53,065,000

Site preparation $2,000,000 Engineering estimate

Buildings $500,000 Engineering estimate

Total direct costs (DC) = (PEC) + (DIC) $91,540,000

Indirect Costs

Engineering $10,985,000 (DC) X 12.0%

Owner's cost $4,577,000 (DC) X 5.0%

Construction management $9,154,000 (DC) X 10.0%

Start-up and spare parts $2,746,000 (DC) X 3.0%

Performance test $200,000 Engineering estimate

Contingencies $13,731,000 (DC) X 15.0%

Total indirect costs (IC) $41,393,000

Allowance for Funds Used During Construction (AFDC) $17,926,000 [(DC)+(IC)] 8.99% 3 years (project time length X 1/2)

Boiler Heat Transfer Surface Area Replacement $40,000,000 B&V estimate to reduce SCR inlet FG temperature

Total SCR Capital Investment (TCI) $190,859,000

Total Capital Investment (TCI) cost for:

New Low NOx Burners & Modified OFA System $32,651,000 Cost estimate for independent system

Total Capital Investment (TCI) for LNB/OFA and SCR $223,510,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 1 FTE and 100,000 $/year Estimated manpower

Maintenance labor & materials $2,746,000 (DC) X 3.0%

Yearly emissions testing $25,000 Engineering estimate

Catalyst activity testing $5,000 Engineering estimate

Fly ash sampling and analysis $20,000 Engineering estimate

Total fixed annual costs $2,896,000

Variable annual costs

Reagent $797,000 475 lb/hr and 450 $/ton Engineering estimate

Auxiliary and ID fan power $944,000 2,537 kW and 0.05 $/kWh Engineering estimate

Catalyst replacement $1,035,000 173 m3 and 6,000 $/m3 3 yr replacement rate

Catalyst disposal $1,000 292,483 lb and 10 $/ton 3 yr replacement rate

Total variable annual costs $2,777,000

Total direct annual costs (DAC) $5,673,000

Indirect Annual Costs

Cost for capital recovery $21,099,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $21,099,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $26,772,000
Boardman Plant Appendix D 

110207 D-10 

Technology: Wet Flue Gas Desulfurization (FGD) Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent feed system: receiving, storage $1,417,000 CUECost estimate

Ball mill & classifier $2,154,000 CUECost estimate

SO2 removal system: tanks, pumps $3,855,000 CUECost estimate

Absorber tower $30,207,000 CUECost estimate

Spray pumps $4,517,000 CUECost estimate

Byproduct handling system $1,737,000 CUECost estimate

Vacuum filter system $1,650,000 from ref. cost

Fabric filter with ash handling system $16,526,000 from ref. cost

Booster fans $4,840,000 Engineering estimate

Electrical system upgrades $4,245,491 from ref. cost

Flue gas handling system $8,800,000 Engineering estimate

Subtotal capital cost (CC) $79,948,491

Instrumentation and controls $3,997,000 (CC) X 5.0%

Freight $3,997,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $87,942,000

Direct installation costs

Foundation & supports $24,184,000 (PEC) X 27.5%

Handling & erection $35,177,000 (PEC) X 40.0%

Electrical $17,588,000 (PEC) X 20.0%

Piping $4,397,000 (PEC) X 5.0%

Insulation $4,397,000 (PEC) X 5.0%

Painting $879,000 (PEC) X 1.0%

Demolition $3,518,000 (PEC) X 4.00%

Relocation $3,518,000 (PEC) X 4.00%

Total direct installation costs (DIC) $93,658,000

Site preparation $200,000 Engineering estimate

Buildings $7,500,000 Engineering estimate

New wet stack $23,000,000 Recent quotes estimate of $23 mil

Waste water treatment system $15,000,000 Engineering estimate

Total direct costs (DC) = (PEC) + (DIC) $227,300,000

Indirect Costs

Engineering $27,276,000 (DC) X 12.0%

Owner's cost $9,092,000 (DC) X 4.0%

Construction management $22,730,000 (DC) X 10.0%

Start-up and spare parts $3,410,000 (DC) X 1.5%

Performance test $200,000 Engineering estimate

Contingencies $34,095,000 (DC) X 15.0%

Total indirect costs (IC) $96,803,000

Allowance for Funds Used During Construction (AFDC) $58,274,000 [(DC)+(IC)] 8.99% 4 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $382,377,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $400,000 4 FTE and 100,000 $/year Estimated manpower

Maintenance labor and materials $6,819,000 (DC) X 3.0%

Total fixed annual costs $7,219,000

Variable annual costs

Reagent $2,015,000 5.9 tph and 46 $/ton Mass bal. calcs.

Byproduct disposal $806,000 10.8 tph and 10 $/ton Mass bal. calcs.

Auxiliary and ID fan power $5,679,000 15,254 kW and 0.05 $/kWh CueCost calculations

Water $532,000 595 gpm and 2 $/1,000 galMass bal. calcs.

Bag replacement cost $632,000 6,322 bags and 100 $/bag 18,966 total bags

Cage replacement cost $158,000 3,161 cages and 50 $/cage 18,966 total cages

Total variable annual costs $8,500,000

Total direct annual costs (DAC) $15,719,000

Indirect Annual Costs

Cost for capital recovery $36,096,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $36,096,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $51,815,000
Boardman Plant Appendix D 

110207 D-11 

Technology: Semi-Dry Flue Gas Desulfurization (FGD) Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent feed: receiving, storage, grinding $3,337,000 CUECost estimate

SO2 removal system: tanks, pumps $3,164,000 CUECost estimate

Spray dryers and fabric filter $41,189,000 CUECost estimate

Ash handling system $2,000,000 from ref. cost

Booster fans $4,840,000 Engineering estimate

Electrical system upgrades $2,860,000 from ref. cost

Flue gas handling system $8,800,000 CUECost estimate

Subtotal capital cost (CC) $66,190,000

Instrumentation and controls $1,324,000 (CC) X 2.0%

Freight $3,310,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $70,824,000

Direct installation costs

Foundation & supports $19,477,000 (PEC) X 27.5%

Handling & erection $28,330,000 (PEC) X 40.0%

Electrical $14,165,000 (PEC) X 20.0%

Piping $3,541,000 (PEC) X 5.0%

Insulation $3,541,000 (PEC) X 5.0%

Painting $708,000 (PEC) X 1.0%

Demolition $2,833,000 (PEC) X 4.0%

Relocation $2,833,000 (PEC) X 4.0%

Total direct installation costs (DIC) $75,428,000

Site preparation $200,000 Engineering estimate

Buildings $500,000 Engineering estimate

Total direct costs (DC) = (PEC) + (DIC) $146,952,000

Indirect Costs

Engineering $17,634,000 (DC) X 12.0%

Owner's cost $5,878,000 (DC) X 4.0%

Construction management $14,695,000 (DC) X 10.0%

Start-up and spare parts $2,204,000 (DC) X 1.5%

Performance test $200,000 Engineering estimate

Contingencies $22,043,000 (DC) X 15.0%

Total indirect costs (IC) $62,654,000

Allowance for Funds Used During Construction (AFDC) $37,687,000 [(DC)+(IC)] X 8.99% 4 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $247,293,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $300,000 3 FTE and 100,000 $/year Estimated manpower

Maintenance labor and materials $4,409,000 (DC) X 3.0%

Total fixed annual costs $4,709,000

Variable annual costs

Reagent $4,915,000 5.0 tph and 132 $/ton Mass bal. calcs.

Byproduct disposal $742,000 10.0 tph and 10 $/ton Mass bal. calcs.

Bag replacement cost $632,000 6,322 bags and 100 $/bag 18,966 total bags

Cage replacement cost $158,000 3,161 cages and 50 $/cage 18,966 total bags

Auxiliary and ID fan power $1,522,000 4,088 kW and 0.05 $/kWh CueCost calculations

Water $300,000 336 gpm and 2 $/1,000 gal Mass bal. calcs.

Total variable annual costs $8,269,000

Total direct annual costs (DAC) $12,978,000

Indirect Annual Costs

Cost for capital recovery $23,344,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $23,344,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $36,322,000
Boardman Plant Appendix D 

110207 D-12 

Technology: Pulse Jet Fabric Filter (PJFF) Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

Fabric filter system $16,968,000 CUECost estimate

Initial FF bags inventory included

Ash handling system $1,210,000 Engineering estimate

Booster fans $5,434,000 Engineering estimate

Electrical system upgrades $2,057,000 from ref. cost

Flue gas handling system $3,630,000 Engineering estimate

Subtotal capital cost (CC) $29,299,000

Instrumentation and controls $1,465,000 (CC) X 5.0%

Freight $1,465,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $32,229,000

Direct installation costs

Foundation & supports $9,669,000 (PEC) X 30.0%

Handling & erection $9,669,000 (PEC) X 30.0%

Electrical $4,834,000 (PEC) X 15.0%

Piping $806,000 (PEC) X 2.5%

Insulation $645,000 (PEC) X 2.0%

Painting $322,000 (PEC) X 1.0%

Demolition $1,611,000 (PEC) X 5.00%

Relocation $322,000 (PEC) X 1.00%

Total direct installation costs (DIC) $27,878,000

Site preparation $150,000 Engineering estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $60,257,000

Indirect Costs

Engineering $7,231,000 (DC) X 12.0%

Owner's cost $3,013,000 (DC) X 5.0%

Construction management $6,026,000 (DC) X 10.0%

Start-up and spare parts $904,000 (DC) X 1.5%

Performance test $100,000 Engineering estimate

Contingencies $9,039,000 (DC) X 15.0%

Total indirect costs (IC) $26,313,000

Allowance for Funds Used During Construction (AFDC) $7,783,000 [(DC)+(IC)] 8.99% 2 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $94,353,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $1,808,000 (DC) X 3.0%

Total fixed annual costs $1,808,000

Variable annual costs

Bag replacement cost $632,000 6,322 bags and 100 $/bag 18,966 total bags

Cage replacement cost $158,000 3,161 cages and 50 $/cage 18,966 total cages

ID fan power $1,121,000 3,011 kW and 0.05 $/kWh 8" water d.p.

Auxiliary power $210,000 563 kW and 0.05 $/kWh Engineering estimate

Total variable annual costs $2,121,000

Total direct annual costs (DAC) $3,929,000

Indirect Annual Costs

Cost for capital recovery $8,907,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $8,907,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $12,836,000
Boardman Plant Appendix D 

110207 D-13 

Technology: Compact Hybrid Particulate Collector (COHPAC) Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

Fabric filter system $12,183,000 from ref. cost

Initial FF bags inventory included

Ash handling system $2,200,000 from ref. cost

Booster fans $5,016,000 Engineering estimate

Electrical system upgrades $2,057,000 from ref. cost

Flue gas handling system $6,600,000 Engineering estimate

Subtotal capital cost (CC) $28,056,000

Instrumentation and controls $1,403,000 (CC) X 5.0%

Freight $1,403,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $30,862,000

Direct installation costs

Foundation & supports $7,716,000 (PEC) X 25.0%

Handling & erection $7,716,000 (PEC) X 25.0%

Electrical $3,858,000 (PEC) X 12.5%

Piping $772,000 (PEC) X 2.5%

Insulation $617,000 (PEC) X 2.0%

Painting $309,000 (PEC) X 1.0%

Demolition $309,000 (PEC) X 1.00%

Relocation $309,000 (PEC) X 1.00%

Total direct installation costs (DIC) $21,606,000

Site preparation $500,000 Engineering estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $52,968,000

Indirect Costs

Engineering $6,356,000 (DC) X 12.0%

Owner's cost $2,648,000 (DC) X 5.0%

Construction management $5,297,000 (DC) X 10.0%

Start-up and spare parts $795,000 (DC) X 1.5%

Performance test $100,000 Engineering estimate

Contingencies $7,945,000 (DC) X 15.0%

Total indirect costs (IC) $23,141,000

Allowance for Funds Used During Construction (AFDC) $6,842,000 [(DC)+(IC)] 8.99% 2 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $82,951,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $1,589,000 (DC) X 3.0%

Total fixed annual costs $1,589,000

Variable annual costs

Filter bag replacement $381,000 3,805 bags and 100 $/bag 11,415 total bags

Cage replacement $95,000 1,903 cages and 50 $/cage 11,415 total cages

ID fan power $807,000 2,167 kW and 0.05 $/kWh 6" water d.p.

Auxiliary power $204,000 549 kW and 0.05 $/kWh Engineering estimate

Total variable annual costs $1,487,000

Total direct annual costs (DAC) $3,076,000

Indirect Annual Costs

Cost for capital recovery $7,831,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $7,831,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $10,907,000
Boardman Plant Appendix D 

110207 D-14 

Technology: Wet ESP Date: 10/11/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs

Purchased equipment costs

WESP system includes casing, electrical sys., $31,242,000 from ref. cost

penthouse blower & heater, access provisions

Ash handling system $2,420,000 from ref. cost

Booster fans $4,598,000 Engineering estimate

Electrical system upgrades $1,331,000 from ref. cost

Flue gas handling system $3,630,000 Engineering estimate

Subtotal capital cost (CC) $43,221,000

Instrumentation and controls $2,161,000 (CC) X 5.0%

Freight $2,161,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $47,543,000

Direct installation costs

Foundation & supports $14,263,000 (PEC) X 30.0%

Handling & erection $14,263,000 (PEC) X 30.0%

Electrical $7,131,000 (PEC) X 15.0%

Piping $1,189,000 (PEC) X 2.5%

Insulation $951,000 (PEC) X 2.0%

Painting $475,000 (PEC) X 1.0%

Demolition $475,000 (PEC) X 1.00%

Relocation $475,000 (PEC) X 1.00%

Total direct installation costs (DIC) $39,222,000

Site preparation $500,000 Engineering estimate

Buildings $0 N/A

New wet stack $23,000,000 Recent quotes estimate of $23 mil

Total direct costs (DC) = (PEC) + (DIC) $110,265,000

Indirect Costs

Engineering $13,232,000 (DC) X 12.0%

Owner's cost $5,513,000 (DC) X 5.0%

Construction management $11,027,000 (DC) X 10.0%

Start-up and spare parts $1,309,000 (DC) X 1.5%

Performance test $100,000 Engineering estimate

Contingencies $16,540,000 (DC) X 15.0%

Total indirect costs (IC) $47,721,000

Allowance for Funds Used During Construction (AFDC) $21,304,000 [(DC)+(IC)] 8.99% 3 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $179,290,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance materials and labor $2,618,000 (DC) X 3.0%

Operating labor $100,000 1 FTE and 100000 $/year Estimated manpower

Total fixed annual costs $2,718,000

Variable annual costs

Reagent $179,000 20 lb/hr and 1.20 $/ton Engineering estimate

Auxiliary power $130,000 350 kW and 0.05 $/kWh Engineering estimate

ID fan power $522,000 1,402 kW and 0.05 $/kWh 4" water d.p.

Service water $583,000 652 gpm and 2 $/1,000 galEngineering estimate

Total variable annual costs $1,414,000

Total direct annual costs (DAC) $4,132,000

Indirect Annual Costs

Cost for capital recovery $16,925,000 (TCI) X 9.44% CRF at 7% interest & 20 year life

Total indirect annual costs (IDAC) $16,925,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $21,057,000
Boardman Plant Appendix E 

110207 E-1 

Appendix E 

Visibility Modeling Results
----------------Filterable---------------- -----------

Scenario Flow (acfm)

Stack 

Velocity 

(ft/s)

Temp. 

(°F)

NOx 

(lb/hour)

SO2 

(lb/hour)

PM10 Total 

(lb/hour)

Elemental 

Carbon 

(lb/hour)

PM Fine 

(lb/hour)

PM Coarse 

(lb/hour)

Organ

Carbo

(lb/hou

Exemption Modeling 2,159,900 95 293 3152.0 4943.1 176.20 1.74 45.40 58.90 14.00 New Low NOx Burners (NLNB) with Modified OFA (MOFA) and Selective Catalytic Reduction (SCR) 2,173,000 95 293 405.51 4943.1 176.20 1.74 45.40 58.90 14.00 NLNB/MOFA and Selective Non-catalytic Reduction (SNCR) 2,159,900 95 293 1332.4 4943.1 176.20 1.74 45.40 58.90 14.00 Wet Flue Gas Desulfurization (Wet FGD) 1,823,200 60 136 3152.0 579.3 115.45 1.14 29.80 38.60 9.20 Semi-Dry Flue Gas Desulfurization (Semi-Dry FGD) 1,901,700 83 170 3152.0 869.0 115.45 1.14 29.80 38.60 9.20 NLNB/MOFA/SCR with Semi-Dry FGD 1,905,800 84 170 405.51 869.00 115.45 1.14 29.80 38.60 9.20 

NLNB/MOFA/SNCR with Semi-Dry FGD 1,901,700 83 170 1332.4 869.00 115.45 1.14 29.80 38.60 9.20 Notes:1) SO2 based upon no SO2 to SO3 conversion.2) PM speciations were derived from NPS prepared spreadsheet3) Stack velocity (except for Wet FGD) based upon existing stack diameter of 22 ft.4) Stack diameter for Wet FGD 24.5 feet4) Emission rates based on 5,793 MMBTU/hr (HHV)5) Stack Height is 200 meters

Individual SO2/PM Control Alternatives

Individual NOx Control Alternatives

Combined NOx and SO2/PM Control Alternatives

Table E-1 

Stack Parameters and Emission Rates for All CALPUFF Model Runs

Boardman Plant RH BART Determination 

Existing Controls
22nd High 

(deciviews)

2003 2004 2005 2003-2005 2003 2004 2005 20

Alpine Lakes Wilderness Area 1.758 2.235 2.371 2.235 18 35 38 4Diamond Peak Wilderness Area 1.061 1.368 0.589 1.029 10 12 2 1Eagle Cap Wilderness Area 2.227 2.541 1.778 2.227 49 40 33 10Glacier Peak Wilderness Area 1.079 1.574 1.624 1.399 8 16 21 2Goat Rocks Wilderness Area 1.893 2.495 2.459 2.383 24 33 34 5Hells Canyon Wilderness Area 1.979 1.950 1.780 1.950 50 52 33 11Mount Adams Wilderness Area 1.809 2.751 2.862 2.688 29 38 34 6Mount Hood Wilderness Area 3.923 4.996 4.917 4.598 66 65 59 8Mount Jefferson Wilderness 3.178 3.346 1.891 3.123 44 49 32 6Mount Rainier National Park 1.662 1.953 2.092 1.990 16 27 26 4Mount Washington Wilderness Area 2.436 2.373 1.615 2.348 28 31 18 4North Cascades National Park 0.845 1.069 1.152 1.055 3 9 12 1Strawberry Mountain Wilderness Area 1.579 2.239 1.170 1.718 28 35 14 5Three Sisters Wilderness Area 2.424 2.420 1.761 2.290 27 33 18 4

Maximum 3.92 5.00 4.92 4.60 66 65 59 11

Minimum 0.85 1.07 0.59 1.03 3 9 2 1

Average 1.99 2.38 2.00 2.22 29 34 27 5

Columbia Gorge National Scenic Area* 3.050 3.239 4.761 3.708 61 57 56 9

*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.

Table E-2

Exemption (Existing Controls) Modeling Results

Boardman Plant RH BART Determination 

8th Highest Impact by Year 

(deciviews)

Number of Days 

Above 1.0 deciview

Class I Area
22nd High 

(deciviews)

2003 2004 2005 2003-2005 2003 2004 2005 20

Alpine Lakes Wilderness Area 1.059 1.382 1.369 1.278 9 17 15 2Diamond Peak Wilderness Area 0.657 0.931 0.365 0.629 3 6 0 Eagle Cap Wilderness Area 1.403 1.459 1.047 1.378 21 23 9 6Glacier Peak Wilderness Area 0.580 1.065 0.890 0.788 2 8 7 Goat Rocks Wilderness Area 1.097 1.738 1.313 1.368 12 21 15 3Hells Canyon Wilderness Area 1.208 1.238 0.889 1.174 18 16 5 6Mount Adams Wilderness Area 1.064 1.855 1.389 1.563 8 26 13 4Mount Hood Wilderness Area 2.351 3.076 2.531 2.757 45 46 34 6Mount Jefferson Wilderness 2.123 2.270 1.068 2.071 26 30 12 4Mount Rainier National Park 1.028 1.491 1.231 1.287 8 15 12 2Mount Washington Wilderness Area 1.611 1.496 0.965 1.474 18 20 6 3North Cascades National Park 0.469 0.680 0.629 0.593 1 6 3 Strawberry Mountain Wilderness Area 0.965 1.301 0.705 1.001 6 13 3 3Three Sisters Wilderness Area 1.604 1.561 0.985 1.405 17 18 7 3

Maximum 2.35 3.08 2.53 2.76 45 46 34 6

Minimum 0.47 0.68 0.37 0.59 1 6 0 

Average 1.23 1.54 1.10 1.34 14 19 10 3

Columbia Gorge National Scenic Area* 1.538 2.174 2.507 2.219 31 34 40 6

*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.

Table E-3

New Low NOx Burners with Modified Overfire Air and Selective Catalytic Reduction (NLNB/MOFA/SCR) Mod

Boardman Plant RH BART Determination 

8th Highest Impact by Year 

(deciviews)

Number of Days 

Above 1.0 deciview

Class I Area
22nd High 

(deciviews)

2003 2004 2005 2003-2005 2003 2004 2005 20

Alpine Lakes Wilderness Area 1.354 1.683 1.753 1.569 13 22 27 3Diamond Peak Wilderness Area 0.778 1.116 0.425 0.776 6 8 0 1Eagle Cap Wilderness Area 1.619 1.819 1.231 1.611 33 30 16 7Glacier Peak Wilderness Area 0.829 1.144 1.147 1.005 3 8 11 2Goat Rocks Wilderness Area 1.521 1.842 1.655 1.685 14 27 20 4Hells Canyon Wilderness Area 1.487 1.438 1.222 1.436 25 29 15 8Mount Adams Wilderness Area 1.258 2.243 2.074 1.952 17 28 25 4Mount Hood Wilderness Area 2.931 3.626 3.401 3.401 53 52 45 7Mount Jefferson Wilderness 2.442 2.499 1.269 2.352 31 39 21 5Mount Rainier National Park 1.339 1.445 1.462 1.445 10 20 19 3Mount Washington Wilderness Area 1.908 1.801 1.221 1.707 21 24 11 3North Cascades National Park 0.611 0.841 0.804 0.748 1 7 5 1Strawberry Mountain Wilderness Area 1.173 1.641 0.840 1.282 11 19 5 4Three Sisters Wilderness Area 1.885 1.800 1.360 1.623 20 24 12 3

Maximum 2.93 3.63 3.40 3.40 53 52 45 8

Minimum 0.61 0.84 0.43 0.75 1 7 0 1

Average 1.51 1.78 1.42 1.61 18 24 17 4

Columbia Gorge National Scenic Area* 2.051 2.455 3.232 2.786 46 41 46 7

*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.

Table E-4

Low NOx Burners with Modified Overfire Air and Selective Non-catalytic Reduction (NLNB/MOFA/SNCR) Mod

Boardman Plant RH BART Determination 

8th Highest Impact by Year 

(deciviews)

Number of Days 

Above 1.0 deciview

Class I Area
22nd High 

(deciviews)

2003 2004 2005 2003-2005 2003 2004 2005 20

Alpine Lakes Wilderness Area 1.064 1.439 1.440 1.385 11 17 23 2Diamond Peak Wilderness Area 0.718 0.619 0.378 0.555 4 2 0 1Eagle Cap Wilderness Area 1.619 1.551 1.160 1.442 22 18 10 6Glacier Peak Wilderness Area 0.591 1.060 0.990 0.886 2 8 7 1Goat Rocks Wilderness Area 1.116 1.598 1.747 1.581 11 21 19 2Hells Canyon Wilderness Area 1.202 1.210 1.095 1.207 14 14 9 6Mount Adams Wilderness Area 1.333 2.083 1.986 1.965 14 26 21 3Mount Hood Wilderness Area 3.184 3.437 3.813 3.716 47 52 49 7Mount Jefferson Wilderness 2.607 2.462 1.588 2.222 25 30 14 4Mount Rainier National Park 1.022 1.334 1.483 1.36 8 13 18 2Mount Washington Wilderness Area 1.759 1.490 1.007 1.464 15 15 8 3North Cascades National Park 0.472 0.686 0.682 0.643 2 3 2 Strawberry Mountain Wilderness Area 0.898 1.185 0.848 1.025 3 15 5 2Three Sisters Wilderness Area 1.480 1.387 1.042 1.353 17 19 10 3

Maximum 3.18 3.44 3.81 3.72 47 52 49 7

Minimum 0.47 0.62 0.38 0.56 2 2 0 

Average 1.36 1.54 1.38 1.49 14 18 14 3

Columbia Gorge National Scenic Area* 2.460 2.748 4.124 3.282 48 51 53 7

*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.

Table E-5

Wet Flue Gas Desulfurization Modeling Results

Boardman Plant RH BART Determination 

8th Highest Impact by Year 

(deciviews)

Number of Days 

Above 1.0 deciview

Class I Area
22nd High 

(deciviews)

2003 2004 2005 2003-2005 2003 2004 2005 20

Alpine Lakes Wilderness Area 1.139 1.407 1.558 1.458 9 17 23 2Diamond Peak Wilderness Area 0.718 0.659 0.406 0.59 3 2 0 1Eagle Cap Wilderness Area 1.524 1.479 1.099 1.425 23 20 8 6Glacier Peak Wilderness Area 0.717 0.855 0.996 0.855 2 7 7 1Goat Rocks Wilderness Area 1.117 1.684 1.805 1.609 13 22 21 3Hells Canyon Wilderness Area 1.281 1.304 1.277 1.295 14 16 13 6Mount Adams Wilderness Area 1.488 2.233 1.887 2.029 17 26 22 3Mount Hood Wilderness Area 3.241 3.629 3.682 3.629 50 49 51 7Mount Jefferson Wilderness 2.570 2.436 1.474 2.199 27 32 12 5Mount Rainier National Park 1.020 1.390 1.610 1.376 9 12 18 2Mount Washington Wilderness Area 1.708 1.580 1.104 1.572 17 16 9 3North Cascades National Park 0.447 0.757 0.744 0.701 1 4 3 Strawberry Mountain Wilderness Area 0.885 1.227 0.823 1.037 6 15 4 3Three Sisters Wilderness Area 1.477 1.423 1.225 1.416 19 20 10 3

Maximum 3.24 3.63 3.68 3.63 50 49 51 7

Minimum 0.45 0.66 0.41 0.59 1 2 0 7 

Average 1.38 1.58 1.41 1.51 15 18 14 3

Columbia Gorge National Scenic Area* 2.380 2.629 4.034 3.160 49 49 51 7

*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.

Table E-6

Semi-Dry Flue Gas Desulfurization Modeling Results

Boardman Plant RH BART Determination 

8th Highest Impact by Year 

(deciviews)

Number of Days 

Above 1.0 deciview

Class I Area
22nd High 

(deciviews)

2003 2004 2005 2003-2005 2003 2004 2005 20

Alpine Lakes Wilderness Area 0.301 0.408 0.404 0.394 000

Diamond Peak Wilderness Area 0.203 0.193 0.114 0.172 000

Eagle Cap Wilderness Area 0.394 0.416 0.308 0.394 001

Glacier Peak Wilderness Area 0.184 0.297 0.262 0.253 000

Goat Rocks Wilderness Area 0.325 0.529 0.496 0.466 022

Hells Canyon Wilderness Area 0.369 0.370 0.315 0.368 000

Mount Adams Wilderness 0.402 0.685 0.448 0.551 0 3 2 

Mount Hood Wilderness Area 0.881 1.096 1.123 1.064 6 9 11 3

Mount Jefferson Wilderness 0.786 0.711 0.421 0.655 2 3 1 1

Mount Rainier National Park 0.318 0.461 0.449 0.397 000

Mount Washington Wilderness Area 0.555 0.478 0.315 0.436 120

North Cascades National Park 0.134 0.252 0.185 0.178 000

Strawberry Mountain Wilderness Area 0.287 0.415 0.223 0.315 010

Three Sisters Wilderness Area 0.464 0.439 0.347 0.439 010

Maximum 0.88 1.10 1.12 1.06 6 9 11 3

Minimum 0.13 0.19 0.11 0.17 000

Average 0.40 0.48 0.39 0.43 121

Columbia Gorge National Scenic Area* 0.670 0.784 1.117 0.881 2 2 12 2

*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.

Table E-7

SCR Alternative Combination: NLNB/OFA/SCR with Semi-Dry FGD Modeling Results

Boardman Plant RH BART Determination 

Class I Area

8th Highest Impact by Year 

(deciviews)

Number of Days 

Above 1.0 deciview
22nd High 

(deciviews)

2003 2004 2005 2003-2005 2003 2004 2005 20

Alpine Lakes Wilderness Area 0.583 0.782 0.800 0.757 0 3 4 1

Diamond Peak Wilderness Area 0.372 0.349 0.210 0.291 100

Eagle Cap Wilderness Area 0.817 0.785 0.574 0.746 5 6 2 2

Glacier Peak Wilderness Area 0.362 0.479 0.525 0.472 011

Goat Rocks Wilderness Area 0.579 0.930 0.979 0.879 1 5 7 1

Hells Canyon Wilderness Area 0.686 0.659 0.625 0.659 3 1 0 1

Mount Adams Wilderness 0.787 1.218 0.947 1.062 4 13 7 2

Mount Hood Wilderness Area 1.776 2.091 2.019 2.014 26 29 26 5

Mount Jefferson Wilderness 1.418 1.312 0.777 1.223 14 12 5 2

Mount Rainier National Park 0.543 0.786 0.824 0.726 1 4 5 1

Mount Washington Wilderness Area 0.930 0.850 0.562 0.781 7 4 1 1

North Cascades National Park 0.236 0.424 0.399 0.347 000

Strawberry Mountain Wilderness Area 0.490 0.716 0.402 0.572 1 1 0 

Three Sisters Wilderness Area 0.804 0.781 0.645 0.778 5 4 1 1

Maximum 1.78 2.09 2.02 2.01 26 29 26 5

Minimum 0.24 0.35 0.21 0.29 000

Average 0.74 0.87 0.73 0.81 5 6 4 1

Columbia Gorge National Scenic Area* 1.273 1.442 2.187 1.662 21 23 28 4

*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.

Table E-8

Best Selection Combination: NLNB/OFA/SNCR with Semi-Dry FGD Modeling Results

Boardman Plant RH BART Determination 

8th Highest Impact by Year 

(deciviews)

Class I Area

Number of Days 

Above 1.0 deciview
2003 2004 2005 2003-2005 2003-2005 2003 2004 2005 

Exemption Modeling 1.99 2.38 2.00 2.22 --- --- 4.60 --- --- 29 34 27 

NLNB/MOFA/SCR 1.23 1.54 1.10 1.34 0.88 40% 2.76 1.84 40% 14 19 10 NLNB/MOFA/SNCR 1.51 1.78 1.42 1.61 0.60 27% 3.40 1.20 26% 18 24 17 Wet FGD 1.36 1.54 1.38 1.49 0.73 33% 3.72 0.88 19% 14 18 14 Semi-Dry FGD 1.38 1.58 1.41 1.51 0.70 32% 3.63 0.97 21% 15 18 14 NLNB/MOFA/SCR with Semi-Dry FGD 0.40 0.48 0.39 0.43 1.78 80% 1.06 3.53 77% 121NLNB/MOFA/SNCR with Semi-Dry FGD 0.74 0.87 0.73 0.81 1.41 64% 2.01 2.58 56% 5 6 4 

Modeling Results Summary for All Class 1 Areas

Individual NOx Control Alternatives

Existing Controls

Combined NOx and SO2/PM Control Alternatives

Individual SO2/PM Control Alternatives

Table E-9

8th Highest Impact 

by Year Avg 22nd High Avg

Case

22nd High Max

Avg Number of 

Days Above 1.0 

deciview

Improvement Improvement

Boardman Plant RH BART Determination 
Exemption Modeling 4.60 --- --- 114 107 102 --- --- --- 

NLNB/MOFA/SCR 2.76 1.84 40% 63 58 44 51 45% 49 NLNB/MOFA/SNCR 3.40 1.20 26% 81 69 71 33 29% 38 Wet FGD 3.72 0.88 19% 61 67 51 53 46% 40 Semi-Dry FGD 3.63 0.97 21% 69 74 60 45 39% 33 NLNB/MOFA/SCR with Semi-Dry FGD 1.06 3.53 77% 2 2 1 112 98% 105 NLNB/MOFA/SNCR with Semi-Dry FGD 2.01 2.58 56% 19 20 14 95 83% 87 

Combined NOx and SO2/PM Control Alternatives

Case 2003-2005 2003 2004 2005

Individual SO2/PM Control Alternatives

Existing Controls

Individual NOx Control Alternatives

22nd High Max (Mount Hood)

Table E-10

Modeling Results Summary: Mount Hood (Visibility Impact) and Hells Canyon ( Number of D

Boardman Plant RH BART Determination 

Avg Number of Days Above 0.5 deciview 

Improvement Improve

2003-2005 2003 200
Boardman Plant Appendix F 

110207 F-1 

Appendix F 

Visibility Modeling Protocol
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1 

Modeling Protocol for 

Washington, Oregon, and Idaho: 

Protocol for the Application of the CALPUFF Modeling System Pursuant 

to the Best Available Retrofit Technology (BART) Regulation

1. Introduction and Protocol Objective 

1.1 Background 

Under the Regional Haze Regulations, the U.S. Environmental Protection Agency (EPA) issued 

the final Guidelines for Best Available Retrofit Technology (BART) Determinations (July 6, 

2005) (BART Guideline). According to the Regional Haze Rule, States are required to use these 

guidelines for establishing BART emission limitations for fossil fuel fired power plants having a 

capacity in excess of 750 megawatts. The use of these guidelines is optional for states 

establishing BART emission limitations for other BART-eligible sources. However, according 

to EPA, the BART Guideline was designed to help states and others do the following: (1) 

identify those sources that must comply with the BART requirement, and (2) determine the level 

of control technology that represents BART for each source. 

This modeling protocol is a cooperative effort among Idaho Department of Environmental 

Quality (IDEQ), Oregon Department of Environmental Quality (ODEQ), and Washington 

Department of Ecology (WDOE) to develop an analysis that will be applied consistently to 

Idaho, Washington, and Oregon BART-eligible sources. The U.S. Fish and Wildlife Service, 

National Park Service, U.S. Forest Service, and U.S. EPA Region 10 were consulted during the 

development of this protocol (EPA 2006a, b, c). This protocol adopts the BART Guideline and 

addresses both the BART exemption modeling as well as the BART determination modeling. 

The three agencies are also collaborating on the development of a consistent three-year 

meteorological data set. Collaboration on the protocol and meteorological data set helps ensure 

modeling consistency and the sharing of resources and workload. 

1.2 Objectives 

The protocol describes the modeling methodology that will be used for the following purposes: 

• BART Exemption modeling – Evaluating whether a BART-eligible source is exempt 

from BART controls because it is not reasonably anticipated to cause or contribute to 

impairment of visibility in Class I areas 

• BART Determination modeling – Quantifying the visibility improvements of BART 

control options 

The objectives of this protocol are to provide the following: 
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• A streamlined and consistent approach in determining which BART-eligible sources are 

subject to BART 

• A clearly delineated modeling methodology 

• A common CALMET/CALPUFF/POSTUTIL/CALPOST modeling configuration 

2. Modeling Approach 

2.1 Bart-Eligible Source List 

BART-eligible source refers to the entire facility that has BART-eligible emission units. 

Oregon, Washington, and Idaho are in the process of finalizing lists of BART-eligible sources. 

Table 1 presents the BART-eligible lists, as of July 21, 2006. Sources may be added/removed as 

additional information is reviewed. 

Table 1. BART-eligible sources. 

Washington Oregon Idaho 

Intalco Aluminum Amalgamated Sugar Amalgamated Sugar – Nampa 

Conoco-Phillips PGE Boardman Amalgamated Sugar – Paul 

Centralia Powerplant (TransAlta) Boise Cascade Amalgamated Sugar – Twin Falls

Longview Fibre Fort James J.R. Simplot Don Siding Plant 

Weyerhaeuser – Longview Pope & Talbot Potlatch Pulp and Paper 

BP Cherry Point Weyerhaeuser Monsanto 

Tesoro NW PGE Beaver NuWest (Agrium) 

Lafarge Georgia Pacific 

Georgia Pacific (Fort James) Camas Smurfit 

Port Townsend Paper Kingsford 

Simpson Tacoma Kraft 

Shell (Puget Sound Refining Co) 

Graymont Western 

Alcoa-Wenatchee 

Columbia 

2.2 Class I Areas 

The mandatory Class I federal areas in Idaho, Oregon, and Washington, as well as neighboring 

states that could be impacted by BART-eligible sources, are presented in Appendix A. Figure 

A-1 graphically presents the BART-eligible source locations with respect to the Class I areas. 

All federally mandatory Class I areas within 300 kilometers (km) of a BART-eligible source will 

be included in the BART exemption modeling analysis. Section 6.1(c) of the Guideline on Air 

Quality Models states, “It was concluded from these case studies that the CALPUFF dispersion 

model had performed in a reasonable manner, and had no apparent bias toward over or under 
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prediction, so long as the transport distance was limited to less than 300km” (40 CFR 51, 

Appendix W). If the 300km extends into a neighboring state, visibility impairment shall also be 

quantified at those Class I areas. Furthermore, if it lies within the 300km radius, visibility 

impairment at the Columbia River Gorge Scenic Area will also be quantified for information 

purposes only. 

2.3 Pollutants to Consider 

The BART Guideline specifies that sulfur dioxide (SO2), oxides of nitrogen (NOx) and direct 

particulate matter (PM) emissions, including both PM10 and PM2.5 should be included for both 

the BART exemption and BART determination modeling analyses. 

The BART Guideline also discusses the inclusion of volatile organic compound (VOC), 

ammonia and ammonia compounds as visibility impairing pollutants. These pollutants will be 

included in the BART analysis if it is determined that they are reasonably anticipated to cause or 

contribute to visibility impairment. For sources that are selected to evaluate VOC emissions, the 

first criterion is the emission level. The VOC emissions will be included in the BART 

exemption analysis if the greater-than-six-carbon VOC gases exceed 250 tons-per-year. If 

speciation is not known, it will be conservatively assumed that 50% of the gas species within the 

total VOC emissions from a facility have greater than six carbon atoms. Idaho and Oregon have 

determined that there are no significant sources of VOC, ammonia, or ammonia compounds 

which require a full BART exemption analysis. 

2.4 Emissions and Stack Data 

The BART Guideline states, “the emission estimates used in the models are intended to reflect 

steady-state operating conditions during periods of high capacity utilization.” These emissions 

should not generally include start-up, shutdown, or malfunction emissions. The BART 

Guideline recommends that states use the 24-hour average actual emission rate from the highest 

emitting day of the meteorological period modeled. The meteorological period is 2003 – 2005. 

Depending on the availability of emissions data, the following emissions information (listed in 

order of priority) should be used with CALPUFF for BART exemption modeling: 

• 24-hour average actual emission rate from the highest emitting day within the modeling 

period (2003 – 2005) (preferred). Actual emissions may be calculated using emission 

factors specified in Title V permits or representative stack test; or 

• Allowable emissions (maximum 24-hour allowable). 

States will work with the BART-eligible sources to develop an appropriate emission inventory. 

If plant-wide emissions from all BART eligible units for SO2, NOx, and PM10 are less than the 

significant emission rate (SER) used for Prevention of Significant Deterioration, emissions of 

that pollutant will not be included in the BART exemption modeling. However, if plant-wide 
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emissions from all BART eligible units exceed the SERs for these pollutants, then all emissions 

of that pollutant from individual emission units will be evaluated even if emissions are below the 

SER for an individual emission unit. 

The states have the option of determining how to include small emission units in the BART 

exemption analysis. Fugitive dust sources at a distance greater than 10km from any Class I area 

are exempt from the analysis. Emission units with emissions less than the SER will be 

quantified, if possible, and added to the stack emissions from an emission unit that is already 

being evaluated. Thus, the emissions from these small units will be included in the total from the 

plant, but will not have to be modeled separately. 

2.5 Natural Background 

The natural visibility background is defined as the 20% best days. This definition of natural 

background is consistent with the intent of the BART Guideline (Federal Register Vol. 70, No. 

128, pf 39125). The natural background values for Class I areas used in this protocol are based 

on EPA’s “Guidance for Estimating Natural Visibility Conditions under the Regional Haze 

Rule” (EPA 2003). The natural background for the Columbia River Gorge Scenic Area is based 

on IMPROVE monitoring data, and was supplied by Scott Copeland of CIRA (Cooperative 

Institute for Research in the Atmosphere). These background data for Class I areas and the 

Columbia River Gorge are presented in Appendix B. The option presented in EPA’s guidance for 

refining the default visibility background is not to be used in this protocol. 

2.6 Visibility Calculation 

The CALPUFF modeling techniques presented in this protocol will provide ground level 

concentrations of visibility impairing pollutants. The concentration estimates from CALPUFF 

are used with the current FLAG equation to calculate the extinction coefficient, as shown below. 

bext = 3 f(RH) [(NH4)2SO4] + 3 f(RH) [NH4NO3] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + bRay

As described in the IWAQM Phase 2 Report, the change in visibility for the BART exemption 

analysis is compared against background conditions. The delta-deciview, Δdv, value is 

calculated from the source’s contribution to extinction, bext (source), and background extinction, 

bext(bkg), as follows: 

Δdv = 10 ln [ ( bext(bkg) + bext (source) ) / ( bext(bkg) ) ] 

2.7 Model Execution 

2.7.1 BART Exemption Analysis 

The BART exemption modeling determines which BART-eligible sources are reasonably 
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anticipated to cause or contribute to visibility impairment at any Class I area. This protocol 

adopts Option 1 in Section III of the BART Guideline. This option is the Individual Source 

Attribution Approach. With this approach, each BART-eligible source is modeled separately 

and the impact on visibility impairment in any Class I area is determined. However, this 

protocol also allows the state or other authority to include all BART-eligible sources in a single 

analysis and determine whether or not all sources together are exempt from BART if the total 

impact on visibility impairment at any Class I area is below the “contribute” threshold. 

Sources, or in some cases groups of sources, that exceed the threshold will be considered subject 

to BART. Sources or groups of sources with modeled impairment below the threshold will be 

exempt and excused from further analyses. 

For determining the visibility threshold, the recommendations in the BART Guideline are 

followed to assess whether a BART-eligible source is reasonably anticipated to cause or 

contribute to any visibility impairment in a Class I area. According to the BART Guideline: 

“A single source that is responsible for a 1.0 deciview change or more should be considered to 

“cause” visibility impairment; a source that causes less than a 1.0 deciview change may still 

contribute to visibility impairment and thus be subject to BART... As a general matter, any 

threshold that you used for determining whether a source “contributes” to visibility impairment 

should not be higher than 0.5 deciviews. 

In setting a threshold for “contribution,” you should consider the number of emissions sources 

affecting the Class I areas at issue and the magnitude of the individual sources’ impacts. In 

general, a larger number of sources causing impacts in a Class I area may warrant a lower 

contribution threshold. States remain free to use a threshold lower than 0.5 deciviews if they 

conclude that the location of a large number of BART-eligible sources within the State and in 

proximity to a Class I area justify this approach.” 

As a result, this protocol has determined that if a single source causes a 0.5 deciview or greater 

change from natural background, then that source is determined to be reasonably anticipated to 

contribute to any visibility impairment in a Class I area and will be subject to BART. For this 

single source analysis, the BART exemption modeling will not consider the frequency, 

magnitude, and duration of impairment. 

In addition, as suggested by the BART Guideline, if multiple BART-eligible sources impact a 

given Class I area on the same day, then a lower, individual, contribution threshold may be 

considered. For BART-eligible sources in Oregon and Washington, the following steps will be 

used to address this condition: 1) after all BART-eligible sources have completed their 

individual BART exemption modeling, the modeled visibility impairment from all sources will 

be aggregated for each Class I area receptor for each day; 2) if the total for any receptor exceeds 

0.5 deciview, all sources responsible for visibility impairment at that receptor for that day will be 

considered for further evaluation. This evaluation will include an assessment of the magnitude, 

frequency, duration of impairment, and other factors that affect visibility for each of the sources 

in the multi-source group. The inclusion of these qualifying factors in the multi-source analysis 

follows the direction given in the BART Guideline for interpreting the refined modeling results 
FINAL 10/11/06 

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in the determination phase of the BART process and recommendations for sources subject to 

PSD analyses given in the FLAG Phase I Final Report (FLAG 2000). There is no set individual 

source visibility threshold for these multi-source assessments. After the multi-source evaluation, 

a determination will be made as to which sources, if any, from a multi-source group will be 

considered to have contributed to visibility impairment and be subject to BART. 

2.7.2 BART Determination Analysis 

The BART Determination analysis determines the degree of visibility improvement for each 

control option. The BART Guideline states: 

“Assess the visibility improvement based on the modeled change in visibility impacts for the precontrol and post-control emission scenarios. You have the flexibility to assess visibility 

improvement due to BART controls by one or more methods. You may consider the frequency, 

magnitude, and duration components of impairment.” 

In order to quantify the degree of visibility improvement due to BART controls, the modeling 

system is executed in a similar manner as for the BART exemption analysis. Model execution 

and results are needed for both pre-BART control and post-BART control scenarios to allow for 

comparison of CALPOST delta-deciview predictions for both scenarios. The only difference 

between the modeling runs will be modifications to the CALPUFF inputs associated with control 

devices (emissions, stack parameters). In contrast to the BART exemption analysis that predicts 

pre-control impacts from all BART-eligible units at a source together, BART determination 

analyses evaluates each emission unit independently of each other after control options are in 

place. As explained in the BART Guideline, the states may consider the frequency, magnitude, 

and duration of impairment for the determination analysis. 

2.7.3 Implementing BART Modeling Analysis 

Each state will implement the BART analysis separately, as follows: 

• Idaho – DEQ will perform both the BART exemption and BART determination 

modeling, working closely with the facilities and providing the facilities with the 

modeling analysis if they too want to perform the analysis. 

• Oregon – DEQ will perform the BART exemption analysis and the individual BARTsubject facilities will perform the BART determination analysis. Oregon DEQ will 

perform any cumulative analysis required. 

• Washington – The Washington BART-eligible sources will conduct the BART 

exemption modeling and the BART determination analysis. Ecology and EPA will 

conduct any cumulative analysis required. 
FINAL 10/11/06 

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3. Visibility Modeling System 

In general, the BART exemption modeling using the CALPUFF suite of programs will follow 

the procedures and recommendations outlined in two documents: the IWAQM (Interagency 

Workgroup on Air Quality Models) and the FLAG (Federal Land Managers Air Quality Related 

Values Workgroup) reports (EPA 1998, FLAG 2000). Exceptions to these procedures are 

explicitly described in the appropriate sections below. Tables listing the modeling parameters 

for each CALPUFF module are located in the Appendices. 

The specific CALPUFF programs and their version numbers that will be used in both the 

exemption modeling and determination modeling (control evaluation) are presented in Table 2. 

The CALMET meteorological domain, as described below, covers the full three-state area. The 

computational domains, which will be unique for each source or group of sources undergoing 

modeling, will be a subset of the meteorological domain. As a result, a consistent 

meteorological data set will be used in all analyses, but the computational domains will be 

tailored to suit the modeling requirements for each individual source and the Class I areas within 

a radius of 300km. 

Table 2. CALPUFF Modeling System 

Program Version Level 

CALMET 6.211 060414 

CALPUFF 6.112 060412 

CALPOST 6.131 060410 

POSTUTIL 1.52 060412 

3.1 CALMET 

The dispersion modeling will use CALMET windfields for the three-year period 2003-2005. 

These windfields cover the three-state area of Washington, Oregon, and Idaho, and also extend 

into adjacent states sufficiently to encompass all Class I areas within 300km of any BARTeligible facility included in this analysis (Figure 1). As part of the three-state collaboration on a 

BART protocol, it was decided to support the development of a consistent meteorological data 

set for use in both the BART exemption and determination analyses. Therefore, the states 

contracted with a consulting firm, Geomatrix, to provide this set of meteorological data for use 

in CALPUFF for determining whether a BART-eligible source is reasonably anticipated to cause 

or contribute to haze in a Federal Class I area. 

One of the deliverables of that contract is a final CALMET modeling protocol that provides 

details on the methodology used to develop the data sets. Therefore, this BART modeling 

protocol only summarizes the development of the CALMET data set. For additional detail, the 

reader is referred to the “Modeling Protocol for BART CALMET Datasets” in Attachment 1. 
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Figure 1. CALMET Meteorological Domain. 

3.2 Meteorological Data 

3.2.1 Mesoscale Model Data 

It was the judgment of Idaho, Oregon, Washington, and EPA Region 10 that the use of three 

years of MM5 data developed by Western Regional Air Partnership (WRAP) would not 

adequately capture the meteorology in the Pacific Northwest. WRAP had run MM5 using 36-km 

and 12-km grids. The states and EPA Region 10 preferred a 4-km grid as it would more 

adequately capture the meteorology and the influences of complex terrain that characterizes the 

Region 10 area. Furthermore, WRAP had selected some physics options that are more 

appropriate for the dry southwest and not the wet northwest. 

As a result, the three states contracted a consulting firm (Geomatrix) to process calendar year 

2003 to 2005 forecast 12-km MM5 output files archived at the University of Washington (UW). 

The 12-km MM5 domain includes all of Idaho, Oregon and Washington. Portions of Montana, 

Wyoming, Utah, Nevada and California are also included in the domain so that BART-eligible 

sources near these state borders that could impact Class I areas outside of Region 10 are 

considered in the analysis. 

The MM5 data was evaluated for model performance using the statistical evaluation tool 
FINAL 10/11/06 

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METSTAT. CALMET Version 6.211, including a new over-water algorithm, was used to 

interpolate the 12-km data down to 4-km for the entire domain. The CALMET outputs were also 

evaluated to determine the model performance of the CALMET wind fields. At this time, 

METSTAT is unable to evaluate CALMET files. The statistical benchmarks listed in the WRAP 

Draft Final Report Annual 2002 MM5 Meteorological Modeling to Support Regional Haze 

Modeling of the Western United States ( ENVIRON and UCR, 2005) served as a guide for the 

acceptability of the MM5 data and CALMET output. 

CALMET allows the user to adjust the MM5 wind fields in varying degree by the introduction of 

observational data, including surface, over-water, and upper air data (using the so-called 

NOOBS parameter). Idaho, Oregon, and Washington have determined that the observed cloud 

cover should be used, but that observed surface and upper air winds should not be included in 

CALMET as they locally distort the MM5 wind fields and have no significant effect on long 

range transport. As a result, the three states have judged that the MM5 simulations more than 

adequately characterize the regional wind patterns. It should also be noted that CALMET uses 

the finer scale land use and digital elevation model (DEM) data to interpolate the MM5 winds 

down to 4km, which improve the wind flow patterns in complex terrain within the modeling 

domain. 

3.2.2 CALMET Control File Settings 

These CALMET wind fields will be used by all BART-eligible sources within the three states 

for both BART exemption and BART determination modeling. The wind fields have been 

computed by Geomatrix using CALMET Version 6.211. Details of the parameter settings in 

CALMET are provided in Appendix C; however, the major assumptions are summarized below. 

 

1) The initial-guess fields used the 12-km MM5 outputs, forecast hours 13 – 24 from every 

00Z and 12Z initialization, taken from UW archives, for the three years, January 2003 – 

December, 2005. 

2) Both the BART exemption and determination modeling will utilize the wind fields at 

4km resolution. 

3) The meteorological data was evaluated in two stages using the extensive database of 

surface observations maintained by UW. First, the MM5 12-km data was evaluated prior 

to running CALMM5 using the METSTAT software program and secondly, the wind 

fields generated by CALMET was evaluated using standard statistical evaluation 

techniques. 

4) There are 10 vertical layers with face heights of 0, 20, 40, 65, 120, 200, 400, 700, 1200, 

2200, and 4000 meters. 

5) CALMET was run using NOOBS = 1. Upper air, precipitation, and relative humidity 

data were taken from MM5. 
FINAL 10/11/06 

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6) The surface wind observations were ignored by setting the relative weight of surface 

winds to essentially zero (R1 = 1.0E-06). The only surface observation data that was 

effectively used in CALMET is cloud cover. This is essentially a no-observation 

approach. This method is specified in this protocol because previous modeling in the 

Pacific Northwest shows that the radius of influence of a typical surface wind 

observation must be set at a small number because of the presence of local topographic 

features. As a result, the adjustment to or distortion of wind fields by surface 

observations is extremely localized, on the order of 10-15km, and has no effect on long 

range transport to Class I areas. 

7) Precipitation data was obtained from MM5, so MM5NPSTA = -1 

8) No weighting of surface and upper air observations, and BIAS = 0, and ICALM = 0 

9) The terrain scale factor TERRAD = 12 

10) Land use and terrain data were developed using the North American 30-arc-second data 

3.3 CALPUFF

The CALPUFF modeling will use Version 6.112. This protocol generally follows the 

recommendation of the IWAQM and FLAG guidance documents. Details of the parameter 

settings in CALPUFF are provided in Appendix D; however, the major features are summarized 

below: 

1) The three-year CALMET input files will be developed by Geomatrix and be provided as 

input-ready to CALPUFF. 

2) The BART exemption modeling will examine the visibility impairment on Class I areas 

within 300km of each single source. Where BART-eligible sources are grouped or where 

their emissions could collectively impair visibility in a Class I area, the exemption 

modeling will also group these sources in order to examine their cumulative impact. The 

computational modeling domain will be sufficient to include all Class I areas within a 

300km radius of a source or sources. 

3) Pasquill-Gifford Dispersion coefficients will be used. 

4) MESOPUFF-II chemistry algorithm will be used. 

5) Building downwash will be ignored for cases with source-to-receptor distances greater 

than 50km, as recommended by the Federal Land Managers (FLMs) (US Fish and 

Wildlife, National Park Service, and U.S. Forest Service) who were consulted for this 

protocol. 
FINAL 10/11/06 

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6) Puff splitting will not be used, following the recommendations of the FLMs. 

7) Source elevations that will be entered in CALPUFF will not use actual elevations but will 

be based on the modeled terrain surface used in CALMET for developing wind fields. 

The same algorithm in CALMET that determines the elevations of the observational 

stations will be used to make this calculation. These modified source elevations will be 

provided to the BART eligible sources.

3.3.1 Emissions 

Section 2.4 above presents the emissions and stack data that is required from the facilities. This 

section only discusses the emissions estimates needed in CALPUFF. 

Primary emission, species will include the input species PM, SO2, SO4, and NOx; and the 

additional modeled species HNO3 and NO3. Emissions of H2SO4 will be included, if known, and 

used for estimation of SO4 emissions. SO2 emissions will be reviewed to ensure “doublecounting” is avoided. 

The primary PM species will be treated as follows: 

• BART-eligible sources are required to include both filterable and condensable 

fractions of PM. 

Filterable: 

 Elemental Carbon (EC) (<2.5 μm) 

 PM Fine (PMF) (<2.5 μm) 

 PM Coarse (PMC) (2.5 – 10 μm) 

Condensable: 

Organic Carbon (SOA) 

Inorganic Aerosol (SO4) 

Non-SO4 inorganic aerosol 

• The condensable fraction will be treated as primary emissions in the CALPUFF input 

file and assumed to be 100% in the PM2.5 fraction (see NPS Web site listed below). 

The states will work with the individual BART-eligible sources to develop appropriate PM 

speciation and size fractions. The following information sources may be used in the 

development of the speciation and fractions: 

 

• U.S. National Park Service (NPS) – the NPS has developed both PM speciation and 

size fractions for several source categories. The information is located at 

http://www2.nature.nps.gov/air/Permits/ect/index.cfm

• U.S. EPA – the EPA has developed generic PM speciation for all source categories 
FINAL 10/11/06 

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located at http://www.epa.gov/ttn/chief/emch/speciation/. 

• If size fraction is not known, the following default values, based on information in the 

CALPUFF User’s Guide, CALPUFF GUI, and AP-42 will be used: 

Pollutant Mean diameter Standard deviation

SO4, NO3, PMF, SOA, EC 0.50 microns 1.5 

 PMC 5.00 microns 1.5 

3.3.2 Ozone Background 

Due to the number of BART-eligible sources and Class I areas being analyzed, a single value of 

60ppb (parts per billion) is used for all months and all three states. This value was determined 

based on a review of available ozone data for Idaho, Oregon, and Washington. 

3.3.3 Ammonia Background 

As with the ozone background, a single value of 17ppb is used for the ammonia background. 

This value is supported by measurements made in 1996 – 1997 at Abbotsford in the Frazier 

River Valley of British Columbia. This value has also been commonly used as background for 

Prevention of Significant Deterioration modeling in the Pacific Northwest and will ensure that 

for BART exemption modeling, conditions are not ammonia limited. It is recognized that 

ammonia values may be lower in Class I areas; however, the BART analysis must account for 

transport through ammonia-rich areas. 

3.3.4 Receptor Locations 

Visibility impacts will be computed at all Class I areas and the Columbia River Gorge Scenic 

Area if they lie within a 300-km radius of the BART eligible source. The geolocations of the 

receptor points and their elevations for the Class I areas that will be used in the modeling are 

available for download from the National Park Service Web site at 

http://www2.nature.nps.gov/air/Maps/Receptors/index.cfm>. 

Receptor points and elevations for the Columbia River Gorge Scenic Area will be provided by 

Oregon and Washington. 

3.4 CALPOST and VISIBILITY POST-PROCESSING 

The following assumptions will be used in CALPOST and POSTUTIL to calculate the visibility 

impairment: 
FINAL 10/11/06 

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1) For the visibility calculation, Method 6 will be employed. This method uses monthly 

average relative humidity and f(RH) values for each Class I area as provided in Appendix 

B, which are based on the EPA Guidance for Regional Haze analysis (EPA 2003). 

2) Particulate species for the visibility analysis will include SO4, NO3, EC, OC, PMF, and 

PMC, as reported in the CALPOST output files. 

3) POSTUTIL will not be used to speciate modeled PM10 concentrations, as PM10 will be 

speciated into its components (PMF, PMC, SOA, EC, SO4) and entered as primary 

emissions in CALPUFF. In addition, HNO3/NO3 partition option in POSTUTIL will not 

be used for ammonia limiting. 

4) Natural background extinction calculations will use the 20% best days for each Class I 

area in the three-state region. The natural background for the 20% best days has been 

refined from that which is in “Guidance for Estimating Natural Visibility Conditions 

Under the Regional Haze Rule” (EPA 2003). The extinction coefficients for the 20% 

best days have been calculated following the approach taken in the Draft Montana BART 

modeling protocol. This procedure uses the haze index (HI) in deciviews at the 10th 

percentile (median of the 20% best days) and an activity factor that is calculated for each 

Class I area. Tables providing the monthly f(RH) and 20% best days coefficients are 

provided in Appendix B, and are based on data from EPA (2003). For the exemption 

modeling, the Rayleigh scattering value will be 10 Mm-1 for all Class I areas. 

• The 98th percentile value will be calculated for all BART-eligible sources at each 

mandatory Class I area. 

5) The CALPOST “LST” output files will be used to determine the 98th percentile of 

visibility impairment for each receptor in CLASS I areas. 

6) The contribution threshold has the implied level of precision equal to the level of 

precision reported by CALPOST. Therefore, the 98th percentile value will be reported to 

three decimal places. 

4. Interpretation of Results 

The change in visibility impairment for the BART exemption modeling is based on the increase 

in HI from a BART-eligible source or sources relative to natural background, defined as the 20% 

best visibility days for each Class I area. This definition of natural background is consistent with 

the intent of the BART guideline (Federal Register Vol. 70, No. 128, pf 39125). 

The U.S. EPA recommends using the 98th percentile value from the distribution of values 

containing the highest modeled delta-deciview (Δdv) value for each day of the simulation from 

all modeled receptors at a given Class I area. The 98th percentile Δdv value will be determined 
FINAL 10/11/06 

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in the following ways: 

• The 8th highest value for each year modeled 

• The 22nd highest value for the 3-year modeling period 

Both methods will be used and the highest value of the two will be compared to the contribution 

threshold (Δdv≥0.5 dv). If there are more than 7 days with values greater than the contribution 

threshold in any single meteorological year for any Class I area, or more than 21 days in three 

years, then the source is considered Subject-to-BART. 

5. References 

40 CFR Part 51, Appendix W. Guidelines on Air Quality Models

ENVIRON and UCR 2005. Draft Final Report Annual 2002 MM5 Meteorological Modeling to 

Support Regional Haze Modeling of the Western United States. Available at 

http://pah.cert.ucr.edu/aqm/308/reports/mm5/DrftFnl_2002MM5_FinalWRAP_Eval.pdf. 

 ENVIRON International Corporation and University of California Riverside). March, 

2005. 

EPA (U.S. Environmental Protection Agency) 1998. Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long 

Range Transport Impacts, EPA-454/R-98-019, December 1998. 

EPA 2003. Guidance for Estimating Natural Visibility Conditions under the Regional Haze 

Rule, EPA-454/B-03-005, September, 2003. 

EPA 2006a. Conference call with Fish and Wildlife and U.S. EPA Region 10, and the states of 

ID, OR and WA. January 17, 2006. 

EPA 2006b. Conference call with the Fish and Wildlife and U.S. EPA Region 10, National Park 

Service, and the states of ID, OR and WA. January 18, 2006. 

EPA 2006c. Conference call with the Fish and Wildlife and U.S. EPA Region 10, and the states 

of ID, OR and WA. January 20, 2006. 

Federal Land Managers’ Air Quality Related Values Workgroup (FLAG) 2000. Phase I Report. 

December 2000. 

Federal Register, Vol. 70, No. 128. Regional Haze Regulations and Guidelines for Best 

Available Retrofit Technology (BART) Determinations. pp. 39104 – 30172, July 6, 2005. 
FINAL 10/11/06 

15 

Appendix A 

Mandatory Class I Federal Areas 

and 

Columbia River Gorge Scenic Area 

Figure A-1 

Map of BART-Eligible Sources and Class I Areas 

Posted on Idaho DEQ’s Regional Haze BART Website 

http://www.deq.idaho.gov/air/prog_issues/pollutants/haze_bart.cfm. 
FINAL 10/11/06 

16 

Table 1. Federal Mandatory Class I Areas. 

Class I Area Federal Land Manager 

Idaho 

Craters of the Moon National Monument Park Service 

Hells Canyon Wilderness Forest Service 

Sawtooth Wilderness Forest Service 

Selway-Bitterroot Wilderness Forest Service 

Yellowstone National Park Park Service 

Oregon 

Crater Lake National Park Park Service 

Diamond Peak Wilderness Forest Service 

Eagle Cap Wilderness Forest Service 

Gearhart Mountain Wilderness Forest Service 

Hells Canyon Wilderness Forest Service 

Kalmiopsis Wilderness Forest Service 

Three Sisters Wilderness Forest Service 

Mount Hood Wilderness Forest Service 

Mount Jefferson Wilderness Forest Service 

Mount Washington Wilderness Forest Service 

Mountain Lakes Wilderness Forest Service 

Strawberry Mountain Wilderness Forest Service 

Washington 

Alpine Lakes Wilderness Forest Service 

Goat Rocks Wilderness Forest Service 

Glacier Peak Wilderness Forest Service 

Mount Adams Wilderness Forest Service 

Mount Ranier National Park Park Service 

North Cascades National Park Park Service 

Olympic National Park Park Service 

Pasayten Wilderness Forest Service 

Neighboring States

Anaconda-Pintler Wilderness (MT) Forest Service 

Bob Marshall Wilderness (MT) Forest Service 

Cabinet Mountains Wilderness (MT) Forest Service 

Gates of the Mountain Wilderness (MT) Forest Service 

Glacier National Park (MT) Park Service 

Missions Mountain Wilderness (MT) Forest Service 

Scapegoat Wilderness (MT) Forest Service 

Red Rock Lakes Refuge (MT) Fish & Wildlife Service 

Bridger Wilderness (WY) Forest Service 

Fitzpatrick Wilderness (WY) Forest Service 

Grand Teton National Park (WY) Park Service 

North Absaroka Wilderness (WY) Forest Service 

Teton Wilderness (WY) Forest Service 

Washakie Wilderness (WY) Forest Service 

Caribous Wilderness (CA) Forest Service 

Lassen Volcanic National Park (CA) Park Service 
FINAL 10/11/06 

17 

Table 1. Federal Mandatory Class I Areas. 

Class I Area Federal Land Manager 

Lava Beds National Monument (CA) Park Service 

Marble Mountain Wilderness (CA) Forest Service 

Redwood National Park (CA) Park Service 

South Warner Wilderness (CA) Forest Service 

Thousand Lakes Wilderness (CA) Forest Service 

Yolla Bolly-Middle Eel Wilderness (CA) Forest Service 

Jarbridge Wilderness (NV) Forest Service 

Hells Canyon is located in Idaho and Oregon. 

Yellowstone is located in Idaho, Montana and Wyoming.
FINAL 10/11/06 

18 

Appendix B 

Natural Visibility Background 

and 

Monthly Relative Humidity f(RH) 
FINAL 10/11/06 

19 

Adjustment to speciated particulate (Western States) to reflect 20% Best Visibility Days conditions

 Monthly f(RH) are from Appendix A of Draft Guidance for Estimating Natural Visibility Conditions under the RHR (Sept. 2003 ).

 Background extinction coefficients (20% Best Days) have been calculated using Annual Avg bext, Best 20% bext, and activity factors.

Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec. BKSO4 BKNO3 BKP

Class I Area State f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) ug/m3 ug/m3 ug/CaribouWilderness CA 3.69 3.13 2.83 2.45 2.37 2.17 2.07 2.13 2.20 2.38 3.01 3.41 0.048 0.040 1.LassenVolcanic CA 3.81 3.19 2.91 2.53 2.42 2.19 2.09 2.14 2.23 2.43 3.13 3.53 0.048 0.040 1.Lava Beds NP CA 3.98 3.36 3.07 2.70 2.62 2.43 2.31 2.34 2.42 2.72 3.52 3.81 0.050 0.042 1.MarbleMountain CA 4.44 3.79 3.74 3.33 3.37 3.24 3.18 3.19 3.24 3.37 4.12 4.15 0.052 0.043 1.RedwoodNP CA 4.42 3.91 4.56 3.91 4.50 4.70 4.86 4.72 4.31 3.66 3.81 3.40 0.054 0.045 1.SouthWarner CA 3.62 3.08 2.72 2.35 2.29 2.12 1.90 1.92 1.97 2.30 3.05 3.44 0.048 0.040 1.

ThousandLakes CA 3.81 3.19 2.91 2.53 2.42 2.19 2.09 2.14 2.23 2.43 3.13 3.53 0.048 0.040 1.Yolla Bolly Middle Eel Wildern CA 3.95 3.35 3.14 2.76 2.68 2.47 2.44 2.50 2.56 2.70 3.31 3.62 0.049 0.041 1.Craters of the Moon ID 3.13 2.74 2.28 2.02 2.01 1.81 1.43 1.42 1.57 1.97 2.77 3.04 0.046 0.038 1.HellsCanyon ID 3.70 3.12 2.51 2.17 2.12 2.00 1.63 1.58 1.79 2.41 3.45 3.87 0.048 0.040 1.SawtoothWilderness ID 3.34 2.87 2.32 2.01 2.00 1.84 1.43 1.40 1.50 1.96 2.94 3.31 0.046 0.039 1.Selway-BitterrootWilderness ID 3.50 3.02 2.59 2.34 2.36 2.31 1.93 1.86 2.09 2.55 3.30 3.50 0.048 0.040 1.Anaconda-PintlerWilderness MT 3.32 2.88 2.54 2.35 2.36 2.31 1.96 1.88 2.10 2.52 3.15 3.29 0.048 0.040 1.BobMarshall MT 3.57 3.10 2.77 2.59 2.66 2.70 2.34 2.23 2.58 2.92 3.47 3.54 0.049 0.041 1.CabinetMountains MT 3.81 3.27 2.85 2.61 2.66 2.68 2.30 2.18 2.56 2.98 3.70 3.86 0.050 0.041 1.Gates of the Mountain MT 2.89 2.57 2.42 2.30 2.30 2.27 2.03 1.94 2.12 2.41 2.75 2.81 0.047 0.039 1.GlacierNP MT 4.01 3.47 3.18 3.06 3.24 3.39 2.76 2.60 3.19 3.45 3.82 3.89 0.051 0.043 1.MissionMountain MT 3.60 3.13 2.73 2.52 2.60 2.62 2.27 2.19 2.50 2.87 3.51 3.59 0.049 0.041 1.RedRock Lakes MT 2.73 2.46 2.28 2.12 2.10 1.91 1.67 1.58 1.77 2.07 2.56 2.68 0.046 0.039 1.ScapegoatWilderness MT 3.19 2.81 2.57 2.43 2.45 2.44 2.14 2.04 2.28 2.61 3.08 3.14 0.048 0.040 1.Crater Lake NP OR 4.57 3.92 3.68 3.36 3.22 2.99 2.84 2.87 3.05 3.59 4.57 4.56 0.053 0.044 1.DiamondPeak OR 4.52 3.96 3.64 3.66 3.16 3.12 2.90 2.93 3.05 3.67 4.55 4.57 0.053 0.044 1.Eagle Cap OR 3.77 3.16 2.47 2.10 2.04 1.87 1.61 1.56 1.61 2.25 3.44 3.97 0.049 0.041 1.Gearhart Mountain OR 3.96 3.38 3.06 2.75 2.65 2.48 2.28 2.30 2.38 2.84 3.65 3.84 0.050 0.042 1.Kalmiopsis Wilderness OR 4.54 3.90 3.83 3.45 3.46 3.32 3.20 3.20 3.29 3.56 4.39 4.32 0.053 0.044 1.Mount Hood OR 4.29 3.81 3.46 3.87 2.95 3.15 2.85 3.00 3.10 3.86 4.53 4.55 0.053 0.044 1.Mount Jefferson OR 4.41 3.90 3.56 3.74 3.07 3.11 2.89 2.91 3.03 3.78 4.55 4.54 0.054 0.045 1.Mountain Lakes OR 4.29 3.62 3.32 2.98 2.86 2.64 2.49 2.50 2.64 3.10 4.12 4.26 0.051 0.043 1.MountWashington OR 4.44 3.93 3.58 3.73 3.09 3.11 2.98 2.91 3.02 3.76 4.56 4.56 0.054 0.045 1.StrawberryMountain OR 3.89 3.33 2.75 2.93 2.27 2.39 1.98 1.97 1.87 2.63 3.69 4.07 0.050 0.042 1.ThreeSisters OR 4.47 3.95 3.61 3.72 3.11 3.11 3.00 2.91 3.03 3.79 4.60 4.57 0.054 0.045 1.AlpineLakes WA 4.25 3.79 3.47 3.90 2.93 3.22 2.92 3.12 3.25 3.91 4.47 4.51 0.054 0.045 1.GlacierPeak WA 4.16 3.72 3.42 3.75 2.91 3.16 2.88 3.14 3.33 3.90 4.42 4.43 0.054 0.045 1.GoatRocks WA 4.25 3.75 3.36 4.24 2.83 3.38 3.03 3.19 3.07 3.77 4.42 4.55 0.054 0.045 1.Mount Adams WA 4.29 3.80 3.44 4.40 2.92 3.49 3.12 3.27 3.13 3.86 4.49 4.56 0.053 0.044 1.MountRainier WA 4.42 3.96 3.64 4.65 3.06 3.69 3.30 3.50 3.40 4.11 4.66 4.66 0.055 0.045 1.NorthCascades NP WA 4.10 3.69 3.43 3.74 2.93 3.20 2.93 3.23 3.45 3.93 4.39 4.38 0.053 0.044 1.OlympicNP WA 4.51 4.08 3.82 4.08 3.17 3.46 3.12 3.48 3.71 4.38 4.83 4.75 0.054 0.045 1.PasaytenWilderness WA 4.17 3.72 3.41 3.72 2.89 3.16 2.88 3.15 3.32 3.86 4.42 4.46 0.053 0.044 1.BridgerWilderness WY 2.52 2.35 2.34 2.19 2.10 1.80 1.50 1.49 1.74 2.00 2.44 2.42 0.046 0.038 1.

FitzpatrickWilderness WY 2.51 2.33 2.24 2.13 2.09 1.80 1.51 1.46 1.73 1.98 2.39 2.44 0.046 0.038 1.Grand Teton NP WY 2.62 2.39 2.24 2.10 2.06 1.79 1.52 1.47 1.72 2.00 2.43 2.55 0.046 0.038 1.NorthAbsaroka WY 2.43 2.27 2.24 2.17 2.14 1.93 1.69 1.56 1.76 2.04 2.35 2.40 0.046 0.038 1.TetonWilderness WY 2.53 2.35 2.24 2.12 2.10 1.85 1.59 1.51 1.74 2.02 2.40 2.48 0.046 0.038 1.WashakieWilderness WY 2.50 2.34 2.23 2.12 2.11 1.84 1.56 1.49 1.75 2.00 2.38 2.46 0.046 0.038 1.YellowstoneNP WY 2.54 2.36 2.27 2.16 2.15 1.94 1.69 1.59 1.79 2.08 2.45 2.51 0.046 0.038 1.JarbridgeWilderness NV 2.95 2.60 2.08 2.12 2.21 2.17 1.58 1.40 1.35 1.63 2.44 2.80 0.046 0.038 1.Columbia River Gorge OR-WA 5.03 5.03 2.59 2.59 2.59 2.11 2.11 2.11 3.51 3.51 3.51 5.03 0.569 0.231 4.

CALPOST Input Group 2 CALPO

Monthly extinction coefficients for hygroscopic species (RHFAC) Background extinctio
FINAL 10/11/06 

20 

Appendix C 

CALMET Parameter Values 
FINAL 10/11/06 

21 

Appendix C 

CALMET Parameter Values 

Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value Recommended Value 

0 DIADAT 

 Input file: preprocessed surface temperature data 

(DIAG.DAT) User Defined 

0 GEODAT Input file: Geophysical data (GEO.DAT) User Defined User Define 

0 LCFILES Convert file name to lower case User Defined 

0 METDAT Output file (CALMET.DAT) User Defined 

0 METLST Output file (CALMET.LST) User Defined 

0 MM4DAT Input file: MM4 data (MM4.DAT) User Defined 

0 NOWSTA Input files: Names of NOWSTA overwater stations User Defined 0 

0 NUSTA Number of upper air data sites User Defined 0 

0 PACDAT Output file: in Mesopuff II format (PACOUT.DAT) User Defined 

0 PRCDAT Input file: Precipitation data (PRECIP.DAT) User Defined 

0 PRGDAT Input file: CSUMM prognostic wind data (PROG.DAT) User Defined 

0 SEADAT 

 Input files: Names of NOWSTA overwater stations 

(SEAn.DAT) User Defined 

0 SRFDAT Input file: Surface data (SURF.DAT) User Defined 

0 TSTFRD Output file (TEST.FRD) User Defined 

0 TSTKIN Output file (TEST.KIN) User Defined 

0 TSTOUT Output file (TEST.OUT) User Defined 

0 TSTPRT Output file (TEST.PRT) User Defined 

0 TSTSLP Output file (TEST.SLP) User Defined 

0 UPDAT Input files: Names of NUSTA upper air data files (UPn.DAT) UPn.DAT 

0 WTDAT Input file: Terrain weighting factors (WT.DAT) User Defined 

1 CLDDAT Input file: Cloud data (CLOUD.DAT) User Defined Not used 

1 IBDY Beginning day User Defined 

1 IBHR Beginning hour User Defined 

1 IBMO Beginning month User Defined 

1 IBTZ Base time zone User Defined 8 

1 IBYR Beginning year User Defined 

1 IRLG Number of hours to simulate User Defined User Define 

1 IRTYPE Output file type to create (must be 1 for CALPUFF) 1 1 

1 ITEST Flag to stop run after Setup Phase 2 2 

1 LCALGRD Are w-components and temperature needed? T T 

2 DATUM WGS-G, NWS-27, NWS-84, ESR-S,... NWS84 

2 DGRIDKM Grid spacing User Defined 4 

2 IUTMZN UTM Zone User Defined User Define 

2 LLCONF 

 When using Lambert Conformal map coordinates - rotate 

winds from true north to map north? F F 

2 NX Number of east-west grid cells User Defined 373 

2 NY Number of north-south grid cells User Defined 316 

2 NZ Number of vertical layers User Defined 10 

2 RLAT0 Latitude used if LLCONF = T User Defined 49.0N 

2 RLON0 Longitude used if LLCONF = T User Defined 121.0W 

2 XLAT0 Southwest grid cell latitude User Defined User Define 

2 XLAT1 Latitude of 1st standard parallel User Defined 30 

2 XLAT2 Latitude of 2nd standard parallel User Defined 60 

2 XORIGKM Southwest grid cell X coordinate User Defined -572 

2 YLON0 Southwest grid cell longitude User Defined -956 

2 YORIGKM Southwest grid cell Y coordinate User Defined User Define 

2 ZFACE Vertical cell face heights (NZ+1 values) User Defined 

0,20,40,65,120,200,400, 

700,1200,2200,4000 

3 IFORMO Format of unformatted file (1 for CALPUFF) 1 1 

3 LSAVE Save met. data fields in an unformatted file? T T 

4 ICLOUD Is cloud data to be input as gridded fields? (0 = No) 0 0 

4 IFORMC Format of cloud data (2 = formatted) 2 2 

4 IFORMP Format of precipitation data (2 = formatted) 2 2 

4 IFORMS Format of surface data (2 = formatted) 2 2 
FINAL 10/11/06 

22 

Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value Recommended Value 

4 NOOBS Use or non-use of surface, overwater, upper observations 1 

4 NPSTA Number of stations in PRECIP.DAT User Defined -1 

4 NSSTA Number of stations in SURF.DAT file User Defined 115 

5 ALPHA Empirical factor triggering kinematic effects 0.1 0.1 

5 BIAS Surface/upper-air weighting factors (NZ values) NZ*0 NZ*0 

5 CRITFN Critical Froude number 1 1 

5 DIVLIM Maximum acceptable divergence 5.00E-06 5.00E-06 

5 FEXTR2 

 Multiplicative scaling factor for extrap surface obs to uppr 

layrs NZ*0.0 

5 ICALM Extrapolate surface calms to upper layers? (0 = No) 0 0 

5 IDIOPT1 Compute temperatures from observations (0 = True) 0 0 

5 IDIOPT2 Compute domain-average lapse rates? (0 = True) 0 0 

5 IDIOPT3 Compute internally inital guess winds? (0 = True) 0 0 

5 IDIOPT4 Read surface winds from SURF.DAT? ( 0 = True) 0 0 

5 IDIOPT5 Read aloft winds from UPn.DAT? (0 = True) 0 0 

5 IEXTRP 

 Extrapolate surface winds to upper layers? (-4 = use 

similarity theory and ignore layer 1 of upper air station data) -4 -1 

5 IFRADJ Adjust winds using Froude number effects? (1 = Yes) 1 1 

5 IKINE Adjust winds using kinematic effects? (1 = Yes) 0 0 

5 IOBR Use O’Brien procedure for vertical winds? (0 = No) 0 0 

5 IPROG Using prognostic or MM-FDDA data? (0 = No) 0 14 

5 ISLOPE Compute slope flows? (1 = Yes) 1 1 

5 ISTEPPG Timestep (hours) of the prognostic model input data 1 1 

5 ISURFT 

 Surface station to use for surface temperature (between 1 

and NSSTA) User Defined 98 

5 IUPT Station for lapse rates (between 1 and NUSTA) User Defined 1 

5 IUPWND 

 Upper air station for domain winds (-1 = 1/r**2 interpolation 

of all stations) -1 -1 

5 IWFCOD Generate winds by diagnostic wind module? (1 = Yes) 1 1 

5 KBAR Level (1 to NZ) up to which barriers apply NZ 10 

5 LLBREZE Use Lake Breeze module F F 

5 LVARY Use varying radius to develop surface winds? F F 

5 METBXID Station IDs in the region User Defined 

5 NBAR Number of Barriers to interpolation User Defined 0 

5 NBOX Number of Lake Breeze regions User Defined 0 

5 NINTR2 Max number of stations for interpolations (NA values) 99 99 

5 NITER Max number of passes in divergence minimization 50 50 

5 NLB Number of stations in region User Defined 0 

5 NSMTH Number of passes in smoothing (NZ values) 2, 4*(NZ-1) 1,2,2,3,3,4,4,4,4,4 

5 R1 Relative weight at surface of Step 1 field and obs User Defined 1.00E-06 

5 R2 Relative weight aloft of Step 1 field and obs User Defined 1.00E-06 

5 RMAX1 Max surface over-land extrapolation radius (km) User Defined 200 

5 RMAX2 Max aloft over-land extrapolation radius (km) User Defined 200 

5 RMAX3 Maximum over-water extrapolation radius (km) User Defined 200 

5 RMIN Minimum extrapolation radius (km) 0.1 0.1 

5 RMIN2 

 Distance (km) around an upper air site where vertical 

extrapolation is excluded (Set to -1 if IEXTRP = ±4) 4 -1 

5 RPROG Weighting factor for CSUMM prognostic wind data User Defined 0 

5 TERRAD Radius of influence of terrain features (km) User Defined 12 

5 XBBAR X coordinate of Beginning of each barrier User Defined 0 

5 XBCST X Point defining the coastline (straight line) User Defined 0 

5 XEBAR X coordinate of Ending of each barrier User Defined 0 

5 XECST X Point User Defined 0 

5 XG1 X Grid line 1 defining region of interest User Defined 0 

5 XG2 X Grid line 2 User Defined 0 

5 YBBAR Y coordinate of Beginning of each barrier User Defined 0 

5 YBCST Y Point User Defined 0 

5 YEBAR Y coordinate of Ending of each barrier User Defined 0 

5 YECST Y Point User Defined 0 
FINAL 10/11/06 

23 

Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value Recommended Value 

5 YG1 Y Grid line 1 User Defined 0 

5 YG2 Y Grid Line 2 User Defined 0 

5 ZUPT Depth of domain-average lapse rate (m) 200 200 

5 ZUPWND Bottom and top of layer for 1st guess winds (m) 1, 1000 1.,1000. 

6 CONSTB Neutral mixing height B constant 1.41 1.41 

6 CONSTE Convective mixing height E constant 0.15 0.15 

6 CONSTN Stable mixing height N constant 2400 2400 

6 CONSTW Over-water mixing height W constant 0.16 0.16 

6 CUTP Minimum cut off precip rate (mm/hr) 0.01 0.01 

6 DPTMIN Minimum capping potential temperature lapse rate 0.001 0.001 

6 DSHELF Coastal/shallow water length scale 0 0 

6 DZZI Depth for computing capping lapse rate (m) 200 200 

6 FCORIOL Absolute value of Coriolis parameter 1.00E-04 1.00E-04 

6 HAFANG Half-angle for looking upwind (degrees) 30 30 

6 IAVET Conduct spatial averaging of temperature? (1 = True) 1 1 

6 IAVEZI Spatial averaging of mixing heights? (1 = True) 1 1 

6 ICOARE Overwater surface fluxes method and parameters 10 10 

6 ICOOL COARE cool skin layer computation 0 0 

6 ILEVZI Layer to use in upwind averaging (between 1 and NZ) 1 1 

6 ILUOC3D Land use category ocean in 3D.DAT datasets 16 16 

6 IMIXH Method to compute the convective mixing height 1 1 

6 IRAD Form of temperature interpolation (1 = 1/r) 1 1 

6 IRHPROG 

3D relative humidity from observations or from prognostic 

data 0 1 

6 ITPROG 3D temps from obs or from prognostic data? 0 2 

6 ITWPROG 

Option for overwater lapse rates used in convective mixing 

height growth 0 2 

6 IWARM COARE warm layer computation 0 0 

6 JWAT1 Beginning landuse type defining water 999 55 

6 JWAT2 Ending landuse type defining water 999 55 

6 MNMDAV Max averaging radius (number of grid cells) 1 1 

6 NFLAGP Method for precipitation interpolation (2 = 1/r**2) 2 2 

6 NUMTS Max number of stations in temperature interpolations 5 10 

6 SIGMAP Precip radius for interpolations (km) 100 12 

6 TGDEFA Default over-water capping lapse rate (K/m) -0.0045 -0.0045 

6 TGDEFB Default over-water mixed layer lapse rate (K/m) -0.0098 -0.0098 

6 THRESHL 

Threshold buoyancy flux required to sustain convective 

mixing height growth overland 0.05 0.05 

6 THRESHW 

Threshold buoyancy flux required to sustain convective 

mixing height growth overwater 0.05 0.05 

6 TRADKM Radius of temperature interpolation (km) 500 500 

6 ZIMAX Maximum over-land mixing height (m) 3000 3000 

6 ZIMAXW Maximum over-water mixing height (m) 3000 3000 

6 ZIMIN Minimum over-land mixing height (m) 50 50 

6 ZIMINW Minimum over-water mixing height (m) 50 50 
FINAL 10/11/06 

24 

Appendix D 

CALPUFF Parameter Values 
FINAL 10/11/06 

25 

Appendix D

CALPUFF Parameter Values 

Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea 

Recommended 

Value 

1 Run Control 1 METRUN Do we run all periods (1) or a subset (0)? 0 

1 2 IBYR Beginning year User Defined 

1 3 IBMO Beginning month User Defined 

1 4 IBDY Beginning day User Defined 

1 5 IBHR Beginning hour User Defined 

1 5 IRLG Length of run (hours) User Defined 

1 5 NSECDT Length of modeling time step (seconds) 3600 3600 

1 6 NSPEC 

Number of species modeled (for MESOPUFF II 

chemistry) 5 

1 7 NSE Number of species emitted 3 

1 8 ITEST Flag to stop run after Setup Phase 2 

1 9 MRESTART 

Restart options (0 = no restart) allows splitting 

runs into smaller segments 0 

1 10 NRESPD Number of periods in Restart 0 

1 11 METFM 

Format of input meteorology (1 = CALMET, 2 = 

ISC) 1 

1 12 AVET 

Averaging time lateral dispersion parameters 

(minutes) 60 60 

1 13 PGTIME PG Averaging time 60 60 

2 Tech Options 1 MGAUSS Near-field vertical distribution (1 = Gaussian) 1 1 

2 2 MCTADJ 

Terrain adjustments to plume path (3 = Plume 

path) 3 3 

2 3 MCTSG 

Do we have subgrid hills? (0 = No) allows 

CTDM-like treatment for subgrid scale hills 0 0 

2 4 MSLUG Near-field puff treatment (0 = No slugs) 0 0 

2 5 MTRANS Model transitional plume rise? (1 = Yes) 1 1 

2 6 MTIP Treat stack tip downwash? (1 = Yes) 1 1 

2 7 MBDW 

Method to simulate downwash 

(1=ISC,2=PRIME) not used 

2 8 MSHEAR Treat vertical wind shear? (0 = No) 0 0 

2 9 MSPLIT Allow puffs to split? (0 = No) 0 0 

2 10 MCHEM MESOPUFF-II Chemistry? (1 = Yes) 1 1 

2 11 MAQCHEM Aqueous phase transformation 0 0 

2 12 MWET Model wet deposition? (1 = Yes) 1 1 

2 13 MDRY Model dry deposition? (1 = Yes) 1 1 

2 13 MTILT Plume Tilt (gravitational settling) 0 0 

2 14 MDISP 

Method for dispersion coefficients 

(2=micromet,3 = PG) 3 3 

2 15 MTURBVW 

Turbulence characterization? (Only if MDISP = 

1 or 5) 3 3 

2 16 MDISP2 Backup coefficients (Only if MDISP = 1 or 5) 3 3 

2 16 MTAULY Method for Sigma y Lagrangian timescale 0 0 

2 16 MTAUADV 

Method for Advective-Decay timescale for 

Turbulence 0 0 

2 16 MCTURB 

Method to compute sigma v,w using micromet 

variables 1 1 

2 17 MROUGH Adjust PG for surface roughness? (0 = No) 0 0 

2 18 MPARTL Model partial plume penetration? (0 = No) 1 1 

2 19 MTINV 

Elevated inversion strength (0 = compute from 

data) 0 0 

2 20 MPDF Use PDF for convective dispersion? (0 = No) 0 0 

2 21 MSGTIBL 

Use TIBL module? (0 = No) allows treatment of 

 subgrid scale coastal areas 0 0 

2 22 MBCON Boundary conditions modeled 0 0 

2 23 MFOG Configure for FOG model output 0 0 

2 24 MREG Regulatory default checks? (1 = Yes) 1 1 
FINAL 10/11/06 

26 

Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea 

Recommended 

Value 

3 Species List 1 CSPECn 

Names of species modeled (for MESOPUFF II 

must be SO2-SO4-NOX-HNO3-NO3) User Defined 

3 2 

Specie 

Names Manner species will be modeled User Defined 

3 3 

Specie 

Groups Grouping of species if any User Defined 

3 4 CGRUP 

3 5 CGRUP 

4 MapProjection XLAT1 Latitude of 1st standard parallel 

4 XLAT2 Latitude of 2nd standard parallel 

4 DATUM NWS84 

4 1 NX Number of east-west grids of input meteorology User Defined 

4 2 NY 

Number of north-south grids of input 

meteorology User Defined 

4 3 NZ Number of vertical layers of input meteorology User Defined 

4 4 DGRIDKM Meteorology grid spacing (km) User Defined 

4 5 ZFACE Vertical cell face heights of input meteorology User Defined 

4 6 XORIGKM Southwest corner (east-west) of input User 

Defined 

meteorology 

4 7 YORIGIM Southwest corner (north-south) of input User 

Defined 

meteorology 

4 8 IUTMZN UTM zone User Defined 

4 9 XLAT Latitude of center of meteorology domain User Defined 

4 10 XLONG Longitude of center of meteorology domain User Defined 

4 11 XTZ Base time zone of input meteorology User Defined 

4 12 IBCOMP Southwest X-index of computational domain User Defined 

4 13 JBCOMP Southwest Y-index of computational domain User Defined 

4 14 IECOMP Northeast X-index of computational domain User Defined 

4 15 JECOMP Northeast Y-index of computational domain User Defined 

4 16 LSAMP Use gridded receptors? (T = Yes) F F 

4 17 IBSAMP Southwest X-index of receptor grid User Defined 

4 18 JBSAMP Southwest Y-index of receptor grid User Defined 

4 19 IESAMP Northeast X-index of receptor grid User Defined 

4 20 JESAMP Northeast Y-index of receptor grid User Defined 

4 21 MESHDN 

Gridded recpetor spacing = 

DGRIDKM/MESHDN 1 

5 Output Options 1 ICON Output concentrations? (1 = Yes) 1 1 

5 2 IDRY Output dry deposition flux? (1 = Yes) 1 1 

5 3 IWET Output west deposition flux? (1 = Yes) 1 1 

5 4 IT2D 2D Temperature 0 0 

5 5 IRHO 2D Density 0 0 

5 6 IVIS Output RH for visibility calculations (1 = Yes) 1 1 

5 7 LCOMPRS Use compression option in output? (T = Yes) T T 

5 8 ICPRT Print concentrations? (0 = No) 0 0 

5 9 IDPRT Print dry deposition fluxes (0 = No) 0 0 

5 10 IWPRT Print wet deposition fluxes (0 = No) 0 0 

5 11 ICFRQ Concentration print interval (1 = hourly) 1 24 

5 12 IDFRQ Dry deposition flux print interval (1 = hourly) 1 24 

5 13 IWFRQ West deposition flux print interval (1 = hourly) 1 24 

5 14 IPRTU 

Print output units (1 = g/m**3; g/m**2/s; 3 = 

ug/m3, ug/m2/s) 1 3 

5 15 IMESG Status messages to screen? (1 = Yes) 1 2 

5 16 LDEBUG Turn on debug tracking? (F = No) F F 

5 16 IPFDEB First puff to track 1 1 

5 17 NPFDEB (Number of puffs to track) (1) 1 

5 18 NN1 (Met. Period to start output) (1) 1 
FINAL 10/11/06 

27 

Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea 

Recommended 

Value 

5 19 NN2 (Met. Period to end output) (10) 10 

7 Dry Dep Chem Dry Gas Dep 

Chemical parameters of gaseous deposition 

species User Defined defaults 

8 Dry Dep Size Dry Part. Dep 

Chemical parameters of particulate deposition 

species User Defined defaults 

9 Dry Dep Misc 1 RCUTR Reference cuticle resistance (s/cm) 30 30 

9 2 RGR Reference ground resistance (s/cm) 10 10 

9 3 REACTR Reference reactivity 8 8 

9 4 NINT Number of particle-size intervals 9 9 

9 5 IVEG 

Vegetative state (1 = active and unstressed; 

2=active and stressed) 1 1 

10 Wet Dep Wet Dep Wet deposition parameters User Defined defaults 

11 Chemistry 1 MOZ 

Ozone background? (0 = constant background 

value; 1 = read from ozone.dat) 0 0 

11 2 BCKO3 Ozone default (ppb) (Use only for missing data) 80 60 

11 3 BCKNH3 Ammonia background (ppb) 10 17 

11 4 RNITE1 Nighttime SO2 loss rate (%/hr) 0.2 0.2 

11 5 RNITE2 Nighttime NOx loss rate (%/hr) 2 2 

11 6 RNITE3 Nighttime HNO3 loss rate (%/hr) 2 2 

11 7 MH2O2 H2O2 data input option 1 1 

11 8 BCKH2O2 Monthly H2O2 concentrations 1 12*1 

 BKPMF Fine particulate concentration 12 * 1.00 not used 

 OFRAC Organic fraction of Fine Particulate 

2*0.15, 9*0.20, 

1*0.15 not used 

 VCNX VOC / NOX ratio 12 * 50.00 not used 

12 Dispersion 1 SYTDEP 

Horizontal size (m) to switch to time 

dependence 550 550 

12 2 MHFTSZ Use Heffter for vertical dispersion? (0 = No) 0 0 

12 3 JSUP PG Stability class above mixed layer 5 5 

12 4 CONK1 Stable dispersion constant (Eq 2.7-3) 0.01 0.01 

12 5 CONK2 Neutral dispersion constant (Eq 2.7-4) 0.1 0.1 

12 6 TBD Transition for downwash algorithms (0.5 = ISC) 0.5 0.5 

12 7 IURB1 Beginning urban landuse type 10 10 

12 8 IURB2 Ending urban landuse type 19 19 

12 9 ILANDUIN 

Land use type (20 = Unirrigated agricultural 

land) 20 20 

12 10 ZOIN Roughness length (m) 0.25 0.25 

12 11 XLAIIN Leaf area index 3.0 3.0 

12 12 ELEVIN Met. Station elevation (m above MSL) 0.0 0.0 

12 13 XLATIN Met. Station North latitude (degrees) -999.0 -999.0 

12 14 XLONIN Met. Station West longitude (degrees) -999.0 -999.0 

12 15 ANEMHT 

Anemometer height of ISC meteorological data 

(m) 10.0 10.0 

12 16 ISIGMAV 

Lateral turbulence (Not used with ISC 

meteorology) 1 1 

12 17 IMIXCTDM Mixing heights (Not used with ISC meteorology) 0 0 

12 18 XMXLEN Maximum slug length in units of DGRIDKM 1.0 1 

12 19 XSAMLEN 

Maximum puff travel distance per sampling 

step (units of DGRIDKM) 1.0 1 

12 20 MXNEW Maximum number of puffs per hour 99 99 

12 21 MXSAM Maximum sampling steps per hour 99 99 

12 22 NCOUNT 

Iterations when computing Transport Wind 

(Calmet & Profile Winds) 2 2 

12 23 SYMIN Minimum lateral dispersion of new puff (m) 1.0 1 

12 24 SZMIN Minimum vertical dispersion of new puff (m) 1.0 1 

12 25 SVMIN Array of minimum lateral turbulence (m/s) 6 * 0.50 6 * 0.50 

12 26 SWMIN Array of minimum vertical turbulence (m/s) 

0.20,0.12,0.08,

0.06,0.03,0.01

6 
FINAL 10/11/06 

28 

Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea 

Recommended 

Value 

12 27 CDIV (1), (2) Divergence criterion for dw/dz (1/s) 0.01 (0.0,0.0) 0.0,0.0 

12 28 WSCALM Minimum non-calm wind speed (m/s) 0.5 0.5 

12 29 XMAXZI Maximum mixing height (m) 3000 3000 

12 30 XMINZI Minimum mixing height (m) 50 50 

12 31 WSCAT Upper bounds 1st 5 wind speed classes (m/s) 

1.54,3.09,5.14,

8. 23,10.8 

1.54,3.09,5.14,8. 

23,10.8 

12 32 PLX0 Wind speed power-law exponents 

0.07,0.07,0.10,

0.15,0.35,0.55 

0.07,0.07,0.10,0.

15,0.35,0.55 

12 33 PTGO 

Potential temperature gradients PG E and F 

(deg/km) 0.020,0.035 0.020,0.035 

12 34 PPC Plume path coefficients (only if MCTADJ = 3) 

0.5,0.5,0.5,0.5,

0.35,0.35 

0.5,0.5,0.5,0.5,0.

35,0.35 

12 35 SL2PF Maximum Sy/puff length 10.0 10.0 

12 36 NSPLIT Number of puffs when puffs split 3 3 

12 37 IRESPLIT Hours when puff are eligible to split User Defined 

12 38 ZISPLIT Previous hour’s mixing height(minimum)(m) 100.0 100.0 

12 39 ROLDMAX 

Previous Max mix ht/current mix ht ratio must 

be less then this value for puff to split 0.25 0.25 

12 40 NSPLITH Number of puffs when puffs split horizontally 5 5 

12 41 SYSPLITH 

Min sigma-y (grid cell units) of puff before horiz 

split 1.0 1.0 

12 12 42 SHSPLITH 

Min puff elongation rate per hr from wind shear 

before horiz split 2.0 2.0 

12 43 CNSPLITH Min conc g/m3 before puff may split horizontally 1.0E-07 1.0E-07 

12 44 EPSSLUG 

Convergence criterion for slug sampling 

integration 1.00E-04 1.00E-04 

12 45 EPSAREA 

Convergence criterion for area source 

integration 1.00E-06 1.00E-06 

12 46 DSRISE Step length for rise integration 1.0 1.0 

12 47 HTMINBC 500.0 500.0 

12 48 RSAMPBC 10.0 10.0 

12 49 MDEPBC 1 1 

13 Point Source 1 NPT1 Number of point sources User Defined 

13 2 IPTU Units of emission rates (1 = g/s) 1 

13 3 NSPT1 Number of point source-species combinations 0 

13 4 NPT2 

Number of point sources with fully variable 

emission rates 0 

13 

Point 

Sources Point sources characteristics User Defined 

14 Area Source Area Sources Area sources characteristics User Defined 

15 Volume Source Volume Volume sources characteristics 

User Defined 

Sources 

16 Line Source Line Sources Buoyant lines source characteristics User Defined 

17 Receptors NREC Number of user defined receptors User Defined 

17 

Receptor 

Data Location and elevation (MSL) of receptors User Defined 
FINAL 10/11/06 

29 

Appendix E 

CALPOST Parameter Values 
FINAL 10/11/06 

30 

Appendix E 

CALPOST Parameter Values 

Table F-1. Recommended CALPOST parameter values chosen by the Region 10 states for use in BART modeling

Input 

Group Variable Description Default Value 

Recommended 

Value 

1 ASPEC Species to process VISIB VISIB 

1 ILAYER 

Layer/deposition code (1 = CALPUFF concentrations; -3 = wet+dry 

deposition fluxes) 1 1 

1 LBACK Add Hourly Background Concentrations/Fluxes? F F 

1 MFRH Particle growth curve for hygroscopic species 2 2 

2 RHMAX Maximum relative humidity (%) used in particle growth curve 98 95 

2 LDRING 

Report results by Discrete receptor Ring, if Discrete Receptors used. 

(T = true) T 

 Modeled species to be included in computing the light extinction 

2 LVSO4 Include SO4? T T 

2 LVNO3 Include NO3? T T 

2 LVOC Include Organic Carbon? T T 

2 LVPMC Include Coarse Particles? T T 

2 LVPMF Include Fine Particles? T T 

2 LVEC Include Elemental Carbon? T T 

 

2 LVBK 

when ranking for TOP-N, TOP-50, and Exceedance tables Include 

BACKGROUND? T T 

2 SPECPMC Species name used for particulates in MODEL.DAT file: COARSE = PMC PMC 

2 SPECPMF Species name used for particulates in MODEL.DAT file: FINE = PMF PMF 

 Extinction Efficiencies (1/Mm per ug/m**3) 

2 EEPMC PM COARSE = 0.6 0.6 

2 EEPMF PM FINE = 1.0 1.0 

2 EEPMCBK Background PM COARSE 0.6 0.6 

2 EESO4 SO4 = 3.0 3.0 

2 EENO3 NO3 = 3.0 3.0 

2 EEOC Organic Carbon = 4.0 4.0 

2 EESOIL Soil = 1.0 1.0 

2 EEEC Elemental Carbon = 10.0 10.0 

 

2 LAVER Method used for 24-hr avg % change light extinction F F 

2 MVISBK 

Method used for background light extinction (2 = Hourly RH 

adjustment; 6 = FLAG seasonal f(RH)) 2 or 6 6 

2 RHFAC 

Monthly RH adjustment factors from FLAG (unique for each Class I 

area) Yes if 6 EPA 

 

Background monthly extinction coefficients (FLAG) unique for each 

Class I area 

2 BKSO4 

Assume all hygroscopic species as SO4 (raw extinction value without 

scattering efficiency adjustment) see table 

2 BKNO3 see table 

2 BKPMC see table 

2 BKOC see table 

2 BKSOIL Assume all non-hygroscopic species as Soil see table 

2 BKEC see table 

2 BEXTRAY Extinction due to Rayleigh scattering 10.0 10.0 

 Averaging time(s) reported 

3 L1PD Averaging period of model output F F 

3 L1HR 1-hr averages F F 

3 L3HR 3-hr averages F F 

3 L24HR 24-hr averages T T 

3 LRUNL Run lengtyh (annual) F F 

3 LT50 Top 50 table for each averaging time selected T F 

3 LTOPN 1 

3 NTOP 1 

3 ITOP 
Report 

Protocol for the Application of 

CALPUFF Determination 

Modeling Pursuant to BART 

Regulation—PGE Boardman 

Plant (Revised)

Prepared for 

Portland General Electric 

January 2007 

Prepared by 

Contents 

III 

Section Page 

1 Introduction and Protocol Objectives ............................................................................. 1-1 

1.1 Background ................................................................................................................ 1-1

1.2 Objectives.................................................................................................................... 1-1

2 Modeling Approach............................................................................................................ 2-1

3 Modeling Methodology..................................................................................................... 3-1

3.1 CALMET ..................................................................................................................... 3-1

3.2 CALPUFF.................................................................................................................... 3-2

3.2.1 Species............................................................................................................... 3-3

3.2.2 Background Values ......................................................................................... 3-3

3.2.3 Receptor Locations.......................................................................................... 3-4

3.3 CALPOST and Visibility Post-Processing.............................................................. 3-4

3.4 Visibility Calculation................................................................................................. 3-5

4 Emissions and Stack Data ................................................................................................. 4-1

5 Presentation of Results ...................................................................................................... 5-1

6 References............................................................................................................................. 6-1

Appendixes 

A Class I Federal Areas 

B Natural Visibility Background and Monthly Relative Humidity f(RH) 

C CALMET Parameter Values 

D CALPUFF Parameter Values 

E CALPOST Parameter Values 

F Emission Rates and Stack Parameters 

G Memorandum: Boardman Station Post-Control Emissions Limits 

Table 

3-1 CALPUFF Modeling System 

Figure 

3-1 CALMET Meteorological Domain 

1-1 

SECTION 1 

Introduction and Protocol Objectives 

1.1 Background 

The U.S. Environmental Protection Agency (EPA) issued the final Guidelines for Best Available 

Retrofit Technology (BART) Determinations (BART Guideline) as required under the Regional 

Haze rule on July 6, 2006. The BART Guideline was designed to help states do the following: 

(1) identify those sources that must comply with the BART requirement and (2) determine 

the level of control technology that represents BART for each source. The Portland General 

Electric (PGE) coal-fired power plant located in Boardman, Oregon (the Boardman plant) is 

a BART-eligible source for which a BART emission limit evaluation is required. The BART 

Guideline requires a modeling analysis for these types of sources. This document presents 

the protocol for the determination modeling analysis. 

1.2 Objectives 

The protocol presented here is based on the combined agency protocol developed by the 

Idaho Department of Environmental Quality (IDEQ), the Oregon Department of 

Environmental Quality (ODEQ), and the Washington Department of Ecology (WDOE) 

(ODEQ, 2006). The objectives of this protocol are as follows: 

• Describe determination modeling approach 

• Present determination modeling methodology 

• Define emissions and stack parameters for all control options to be modeled 

• Define presentation of results 

2-1 

SECTION 2 

Modeling Approach 

The modeling analysis will be used to evaluate the visibility improvements of various BART 

control options on Class I areas in Oregon and Washington that could be affected by the 

Boardman plant. These areas are presented in Appendix A. Although not a Class I area, the 

Columbia River Gorge Scenic Area will also be evaluated in the BART determination 

modeling, for informational purposes only. 

Both pre-BART control and post-BART control scenarios will be analyzed to compare 

visibility. Maximum 24-hour past actual emissions will be compared with future 24-hour 

maximum emissions and analyzed on a pollutant-by-pollutant basis. Frequency, magnitude, 

and duration of impairment will be evaluated in the determination analysis. 

Sulfur dioxide (SO2), oxides of nitrogen (NOx), and direct particulate matter (PM) emissions, 

including both PM10 and PM2.5, will be included in the determination modeling analysis, as 

required in the BART Guideline. Volatile organic compound (VOC) and ammonia emissions 

will not be included in the analysis. 

Consistent with the intent of the BART Guideline, the natural visibility background is 

defined as the 20 percent best days. The natural background values for Class I areas will be 

consistent with those provided in the combined agency protocol (ODEQ, 2006). Background 

values for both the Class I areas and the Columbia River Gorge Scenic Area are presented in 

Appendix B. 

3-1 

SECTION 3 

Modeling Methodology 

As required by the combined agency protocol (ODEQ, 2006) and supported by the Interagency Workgroup on Air Quality Modeling (EPA, 1998) and the Federal Land Managers’ 

Air Quality Related Values Workgroup (FLAG, 2000), the CALPUFF suite of programs will 

be used for the BART determination modeling. The CALPUFF modules and their version 

numbers that will be used in the determination modeling are presented in Table 3-1. Modeling parameters for each module are described in this section and are presented in the 

appendixes. 

TABLE 3-1 

CALPUFF Modeling System 

Program Version Level 

CALMET 6.211 060414 

CALPUFF 6.112 060412 

CALPOST 6.131 060410 

POSTUTIL 1.52 060412 

3.1 CALMET 

Details of the parameter settings in CALMET are provided in Appendix C; however, the 

major assumptions are summarized below. These data were provided by ODEQ. 

1. The initial-guess fields used the 12-kilometer (km) MM5 outputs, forecast hours 13 – 24 

from every 00Z and 12Z initialization, taken from University of Washington (UW) 

archives, for the 3 years from January 2003 through December 2005. 

2. BART determination modeling will utilize the wind fields at 4-km resolution. 

3. There are 10 vertical layers with face heights of 0, 20, 40, 65, 120, 200, 400, 700, 1200, 2200, 

and 4000 meters. 

4. CALMET was run using NOOBS = 1. Upper air, precipitation, and relative humidity 

data were taken from MM5. 

5. The surface wind observations were ignored by setting the relative weight of surface 

winds to essentially zero (R1 = 1.0E-06). Cloud cover data were the only surface 

observation data that were effectively used in CALMET. 

6. Precipitation data were obtained from MM5, so MM5NPSTA = -1. 

7. No weighting of surface and upper air observations, and BIAS = 0, and ICALM = 0. 

8. The terrain scale factor TERRAD = 12. 
 

3-2 

9. Land use and terrain data were developed using the North American 30-arc-second 

data. 

10. The dispersion modeling will use CALMET wind fields for the 3-year period 2003–2005. 

These data were developed for the three states using CALMET Version 6.211 and were 

provided by ODEQ. This domain is shown in Figure 3-1. 

Figure 3-1 CALMET Meteorological Domain. 

3.2 CALPUFF 

Details of the parameter settings in CALPUFF are provided in Appendix D; however, the 

major features are summarized below. 

1. The BART determination modeling will examine the visibility impairment on Class I 

areas within 300 km of the Boardman plant. The computational modeling domain will 

include all Class I areas within a 300-km radius of PGE Boardman. 
MODELING PROTOCOL 

3-3 

2. Pasquill-Gifford Dispersion coefficients will be used. 

3. MESOPUFF-II chemistry algorithm will be used. 

4. Building downwash will be ignored. 

5. Puff splitting will not be used, following the recommendations of the Federal Land 

Managers (FLMs). 

6. Source elevations that will be entered in CALPUFF will not use actual elevations but will 

be based on the modeled terrain surface used in CALMET for developing wind fields. 

The same algorithm in CALMET that determines the elevations of the observational 

stations will be used to make this calculation. The modified source elevation was set at 

225 meters, as determined by CH2M HILL. 

3.2.1 Species 

Primary emission species analyzed will include the input species PM, SO2, sulfates (SO4), 

and NOx; and the additional modeled species nitric acid (HNO3) and nitrates (NO3). Sulfur 

dioxide emissions will be reviewed to ensure that “double-counting” is avoided. 

Both filterable and condensable fractions of PM will be included in the analysis. The 

condensable fraction will be treated as primary emissions in the CALPUFF input file and 

assumed to be 100 percent in the PM2.5 fraction. The primary PM species will be treated as 

follows: 

Filterable: 

 Elemental Carbon (EC) (< 2.5 microns [μm]) 

 PM Fine (PMF) (< 2.5 μm) 

 PM Coarse (PMC) (2.5 – 10 μm) 

Condensable: 

 Organic Carbon (OC) (secondary organic aerosol [SOA]) 

 Inorganic Aerosol (SO4) 

 Non-SO4 inorganic aerosol 

The primary emission species sizing are presented as follows: 

Pollutant Mean Diameter Standard Deviation 

SO4, NO3, PMF, SOA, EC 0.50 microns 1.5 

PMC 5.00 microns 1.5 

3.2.2 Background Values 

A single ozone background value of 60 parts per billion (ppb) will be used for all months for 

all Class I areas. 

As with the ozone background, a single value of 17 ppb will be used for the ammonia 

background. This value is supported by measurements made in 1996–1997 at Abbotsford in 

the Fraser River Valley of British Columbia. 
 

3-4 

3.2.3 Receptor Locations 

Visibility impacts will be computed at all Class I areas and the Columbia River Gorge Scenic 

Area if they lie within a 300-km radius of the Boardman plant. The geolocations of the 

receptor points and their elevations for the Class I areas that will be used in the modeling 

are consistent with the ODEQ exemption modeling and were downloaded from the 

National Park Service Web site at 

http://www2.nature.nps.gov/air/Maps/Receptors/index.cfm>.

Receptor points and elevations for the Columbia River Gorge Scenic Area were provided by 

ODEQ. 

3.3 CALPOST and Visibility Post-Processing 

Details of the parameter setting in CALPOST are provided in Appendix E. The following 

assumptions will be used in CALPOST and POSTUTIL to calculate the visibility 

impairment: 

1. For the visibility calculation, Method 6 will be employed. This method uses monthly 

average relative humidity and f(RH) values for each Class I area as provided in 

Appendix B, which are based on the EPA Guidance for Regional Haze analysis (EPA, 

2003). 

2. Particulate species for the visibility analysis will include SO4, NO3, EC, OC, PMF, and 

PMC, as reported in the CALPOST output files. 

3. POSTUTIL will not be used to speciate modeled PM10 concentrations, as PM10 will be 

speciated into its components (PMF, PMC, SOA, EC, SO4) and entered as primary 

emissions in CALPUFF. In addition, HNO3/NO3 partition option in POSTUTIL will not 

be used for ammonia limiting. 

4. Natural background extinction calculations will use the 20 percent best days for each 

Class I area. The natural background for the 20 percent best days has been refined from 

that which is in “Guidance for Estimating Natural Visibility Conditions Under the Regional 

Haze Rule” (EPA, 2003). The extinction coefficients for the 20 percent best days have been 

calculated following the approach taken in the Draft Montana BART modeling protocol. 

This procedure uses the haze index (HI) in deciviews at the 10th percentile (median of 

the 20 percent best days) and an activity factor that is calculated for each Class I area. 

Table B-1, providing the monthly f(RH) and 20 percent best days coefficients, is 

provided in Appendix B and is based on data from EPA (2003). For the exemption 

modeling, the Rayleigh scattering value will be 10 Mm-1 for all Class I areas. 

The 98th percentile value will be calculated for all BART-eligible sources at each 

mandatory Class I area. 

5. The CALPOST “LST” output files will be used to determine the 98th percentile of 

visibility impairment for each receptor in CLASS I areas. 
MODELING PROTOCOL 

3-5 

6. The contribution threshold has the implied level of precision equal to the level of 

precision reported by CALPOST. Therefore, the 98th percentile value will be reported to 

three decimal places. 

3.4 Visibility Calculation 

The CALPUFF modeling techniques presented in this section will provide ground-level 

concentrations of visibility-impairing pollutants. The concentration estimates from 

CALPUFF are used with the current FLAG equation to calculate the extinction coefficient, as 

shown below: 

bext = 3 f(RH) [(NH4)2SO4] + 3 f(RH) [NH4NO3] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + bRay

As described in the IWAQM Phase 2 Report (EPA, 1998), the change in visibility for the 

BART exemption analysis is compared against background conditions. The delta-deciview, 

Δdv, value is calculated from the source’s contribution to extinction, bext (source), and 

background extinction, bext(bkg), as follows: 

Δdv = 10 ln [ ( bext(bkg) + bext (source) ) / ( bext(bkg) ) ] 

4-1 

SECTION 4 

Emissions and Stack Data 

Emissions to be modeled for determination modeling will not include startup, shutdown, or 

malfunction emissions. The emissions and stack data used for the determination modeling 

are summarized in Appendix F. Emissions were derived by Black & Veatch for PGE as 

summarized in a memorandum presented in Appendix G. 

The control scenarios being modeled for the determination modeling are listed below: 

1. NOx Controlled Outlet Conditions 

a. Selective Catalytic Reduction 

b. New Low-NOx Burners with Modified Over-Fire Air (OFA) System 

2. SO2 Controlled Outlet Conditions 

a. Wet Flue Gas Desulfurization 

b. Semi-Dry Flue Gas Desulfurization 

Existing emissions of PM are already controlled by an electrostatic precipitator. As a result, 

emissions of SO2 and NOx are each more than 10 times the emissions of particulate. The 

exemption modeling conducted by ODEQ shows the contribution of PM to the highest 

visibility impairment days to be less than 2 percent. Consequently, PM controls will not be 

included in the determination analysis. 

Consistent with the BART guidelines, the required maximum 24-hour emission rates used in 

the modeling will be based on a 30-day rolling average permit limit. Each of the above 

control options will be analyzed for each pollutant to determine the most effective control 

by pollutant. Following that analysis, the model will be run combining the most effective 

controls by pollutants to determine the maximum improvement in visibility.

5-1 

SECTION 5 

Presentation of Results 

The improvement in visibility for BART determination is based on the change in HI from 

pre-BART control to post-BART control for PGE relative to natural background for each 

Class I area. Comparison tables for pre-BART control and post-BART control visibility 

impacts will be documented for use in the BART control evaluation. Frequency, magnitude, 

and duration of any visibility impairment will be included in the documentation. 

6-1 

SECTION 6 

References 

Federal Land Managers’ Air Quality Related Values Workgroup (FLAG). 2000. Phase I 

Report. December 2000. 

Oregon Department of Environmental Quality (ODEQ). 2006. Modeling Protocol for 

Washington, Oregon, and Idaho: Protocol for the Application of the CALPUFF Modeling 

System Pursuant to the Best Available Retrofit Technology (BART) Regulation. October 11, 

2006. 

U.S. Environmental Protection Agency (EPA). 1998. Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long 

Range Transport Impacts. EPA-454/R-98-019. December 1998. 

U.S. Environmental Protection Agency (EPA). 2003. Guidance for Estimating Natural Visibility 

Conditions under the Regional Haze Rule. EPA-454/B-03-005. September 2003. 

U.S. Environmental Protection Agency (EPA). 2005. Regional Haze Regulations and Guidelines 

for Best Available Retrofit Technology (BART) Determinations. Federal Register, Vol. 70, 

No. 128. Pp. 39104–30172. July 6, 2005. 

APPENDIX A 

Class I Federal Areas 

Table A-1. Federal Mandatory Class I Areas Evaluated in PGE Boardman Analysis. 

Class I Area Federal Land Manager 

Oregon 

Diamond Peak Wilderness Forest Service 

Eagle Cap Wilderness Forest Service 

Hells Canyon Wilderness Forest Service 

Three Sisters Wilderness Forest Service 

Mount Hood Wilderness Forest Service 

Mount Jefferson Wilderness Forest Service 

Mount Washington Wilderness Forest Service 

Strawberry Mountain Wilderness Forest Service 

Washington 

Alpine Lakes Wilderness Forest Service 

Goat Rocks Wilderness Forest Service 

Glacier Peak Wilderness Forest Service 

Mount Adams Wilderness Forest Service 

Mount Rainier National Park Park Service 

North Cascades National Park Park Service 
 
APPENDIX B 

Natural Visibility Background and 

Monthly Relative Humidity f(RH) 
 

8 
Table B-1 Adjustment to speciated particulate (Western States) to reflect 

20% Best Visibility Days conditions  Monthly f(RH) are from Appendix A of Draft Guidance for Estimating Natural Visibility Conditions under the RHR (Sept. 2003).

 Background extinction coefficients (20% Best Days) have been calculated using Annual Avg bext, Best 20% bext, and activity factors. 

CALPOST Input Group 2 

Monthly extinction coefficients for hygroscopic species (RHFAC) Background 

 Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec. BKSO4 BKNO3 Class I Area State f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) ug/m3 ug/m3 Hells Canyon ID 3.70 3.12 2.51 2.17 2.12 2.00 1.63 1.58 1.79 2.41 3.45 3.87 0.048 0.040 Diamond Peak OR 4.52 3.96 3.64 3.66 3.16 3.12 2.90 2.93 3.05 3.67 4.55 4.57 0.053 0.044 Eagle Cap OR 3.77 3.16 2.47 2.10 2.04 1.87 1.61 1.56 1.61 2.25 3.44 3.97 0.049 0.041 Mount Hood OR 4.29 3.81 3.46 3.87 2.95 3.15 2.85 3.00 3.10 3.86 4.53 4.55 0.053 0.044 Mount Jefferson OR 4.41 3.90 3.56 3.74 3.07 3.11 2.89 2.91 3.03 3.78 4.55 4.54 0.054 0.045 Mount Washington OR 4.44 3.93 3.58 3.73 3.09 3.11 2.98 2.91 3.02 3.76 4.56 4.56 0.054 0.045 Strawberry Mountain OR 3.89 3.33 2.75 2.93 2.27 2.39 1.98 1.97 1.87 2.63 3.69 4.07 0.050 0.042 Three Sisters OR 4.47 3.95 3.61 3.72 3.11 3.11 3.00 2.91 3.03 3.79 4.60 4.57 0.054 0.045 Alpine Lakes WA 4.25 3.79 3.47 3.90 2.93 3.22 2.92 3.12 3.25 3.91 4.47 4.51 0.054 0.045 Glacier Peak WA 4.16 3.72 3.42 3.75 2.91 3.16 2.88 3.14 3.33 3.90 4.42 4.43 0.054 0.045 Goat Rocks WA 4.25 3.75 3.36 4.24 2.83 3.38 3.03 3.19 3.07 3.77 4.42 4.55 0.054 0.045 Mount Adams WA 4.29 3.80 3.44 4.40 2.92 3.49 3.12 3.27 3.13 3.86 4.49 4.56 0.053 0.044 Mount Rainier WA 4.42 3.96 3.64 4.65 3.06 3.69 3.30 3.50 3.40 4.11 4.66 4.66 0.055 0.045 North Cascades NP WA 4.10 3.69 3.43 3.74 2.93 3.20 2.93 3.23 3.45 3.93 4.39 4.38 0.053 0.044 Columbia River Gorge 

ORWA 5.03 5.03 2.59 2.59 2.59 2.11 2.11 2.11 3.51 3.51 3.51 5.03 0.569 0.231 

APPENDIX C 

CALMET Parameter Values 

Appendix C 

CALMET Parameter Values 

 Table C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value 

Recommended 

Value 

0 DIADAT Input file: preprocessed surface temperature data (DIAG.DAT) User Defined 

0 GEODAT Input file: Geophysical data (GEO.DAT) User Defined User Define 

0 LCFILES Convert file name to lower case User Defined 

0 METDAT Output file (CALMET.DAT) User Defined 

0 METLST Output file (CALMET.LST) User Defined 

0 MM4DAT Input file: MM4 data (MM4.DAT) User Defined 

0 NOWSTA Input files: Names of NOWSTA overwater stations User Defined 0 

0 NUSTA Number of upper air data sites User Defined 0 

0 PACDAT Output file: in Mesopuff II format (PACOUT.DAT) User Defined 

0 PRCDAT Input file: Precipitation data (PRECIP.DAT) User Defined 

0 PRGDAT Input file: CSUMM prognostic wind data (PROG.DAT) User Defined 

0 SEADAT Input files: Names of NOWSTA overwater stations (SEAn.DAT) User Defined 

0 SRFDAT Input file: Surface data (SURF.DAT) User Defined 

0 TSTFRD Output file (TEST.FRD) User Defined 

0 TSTKIN Output file (TEST.KIN) User Defined 

0 TSTOUT Output file (TEST.OUT) User Defined 

0 TSTPRT Output file (TEST.PRT) User Defined 

0 TSTSLP Output file (TEST.SLP) User Defined 

0 UPDAT Input files: Names of NUSTA upper air data files (UPn.DAT) UPn.DAT 

0 WTDAT Input file: Terrain weighting factors (WT.DAT) User Defined 

1 CLDDAT Input file: Cloud data (CLOUD.DAT) User Defined Not used 

1 IBDY Beginning day User Defined 

1 IBHR Beginning hour User Defined 

1 IBMO Beginning month User Defined 

1 IBTZ Base time zone User Defined 8 

1 IBYR Beginning year User Defined 

1 IRLG Number of hours to simulate User Defined User Define 

1 IRTYPE Output file type to create (must be 1 for CALPUFF) 1 1 

1 ITEST Flag to stop run after Setup Phase 2 2 

1 LCALGRD Are w-components and temperature needed? T T 

2 DATUM WGS-G, NWS-27, NWS-84, ESR-S,... NWS84 

2 DGRIDKM Grid spacing User Defined 4 

2 IUTMZN UTM Zone User Defined User Define 

2 LLCONF 

 When using Lambert Conformal map coordinates - rotate winds 

from true north to map north? F F 

2 NX Number of east-west grid cells User Defined 373 

2 NY Number of north-south grid cells User Defined 316 

2 NZ Number of vertical layers User Defined 10 

2 RLAT0 Latitude used if LLCONF = T User Defined 49.0N 

2 RLON0 Longitude used if LLCONF = T User Defined 121.0W 

2 XLAT0 Southwest grid cell latitude User Defined User Define 

2 XLAT1 Latitude of 1st standard parallel User Defined 30 

2 XLAT2 Latitude of 2nd standard parallel User Defined 60 

2 XORIGKM Southwest grid cell X coordinate User Defined -572 

2 YLON0 Southwest grid cell longitude User Defined -956 

2 YORIGKM Southwest grid cell Y coordinate User Defined User Define 

2 ZFACE Vertical cell face heights (NZ+1 values) User Defined 

0,20,40,65,120,200,

400, 

700,1200,2200,4000

3 IFORMO Format of unformatted file (1 for CALPUFF) 1 1 

3 LSAVE Save met. data fields in an unformatted file? T T 
 Table C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value 

Recommended 

Value 

4 ICLOUD Is cloud data to be input as gridded fields? (0 = No) 0 0 

4 IFORMC Format of cloud data (2 = formatted) 2 2 

4 IFORMP Format of precipitation data (2 = formatted) 2 2 

4 IFORMS Format of surface data (2 = formatted) 2 2 

4 NOOBS Use or non-use of surface, overwater, upper observations 1 

4 NPSTA Number of stations in PRECIP.DAT User Defined -1 

4 NSSTA Number of stations in SURF.DAT file User Defined 115 

5 ALPHA Empirical factor triggering kinematic effects 0.1 0.1 

5 BIAS Surface/upper-air weighting factors (NZ values) NZ*0 NZ*0 

5 CRITFN Critical Froude number 1 1 

5 DIVLIM Maximum acceptable divergence 5.00E-06 5.00E-06 

5 FEXTR2 Multiplicative scaling factor for extrap surface obs to uppr layrs NZ*0.0 

5 ICALM Extrapolate surface calms to upper layers? (0 = No) 0 0 

5 IDIOPT1 Compute temperatures from observations (0 = True) 0 0 

5 IDIOPT2 Compute domain-average lapse rates? (0 = True) 0 0 

5 IDIOPT3 Compute internally initial guess winds? (0 = True) 0 0 

5 IDIOPT4 Read surface winds from SURF.DAT? ( 0 = True) 0 0 

5 IDIOPT5 Read aloft winds from UPn.DAT? (0 = True) 0 0 

5 IEXTRP 

 Extrapolate surface winds to upper layers? (-4 = use similarity 

theory and ignore layer 1 of upper air station data) -4 -1 

5 IFRADJ Adjust winds using Froude number effects? (1 = Yes) 1 1 

5 IKINE Adjust winds using kinematic effects? (1 = Yes) 0 0 

5 IOBR Use O’Brien procedure for vertical winds? (0 = No) 0 0 

5 IPROG Using prognostic or MM-FDDA data? (0 = No) 0 14 

5 ISLOPE Compute slope flows? (1 = Yes) 1 1 

5 ISTEPPG Timestep (hours) of the prognostic model input data 1 1 

5 ISURFT 

 Surface station to use for surface temperature (between 1 and 

NSSTA) User Defined 98 

5 IUPT Station for lapse rates (between 1 and NUSTA) User Defined 1 

5 IUPWND 

 Upper air station for domain winds (-1 = 1/r**2 interpolation of all 

stations) -1 -1 

5 IWFCOD Generate winds by diagnostic wind module? (1 = Yes) 1 1 

5 KBAR Level (1 to NZ) up to which barriers apply NZ 10 

5 LLBREZE Use Lake Breeze module F F 

5 LVARY Use varying radius to develop surface winds? F F 

5 METBXID Station IDs in the region User Defined 

5 NBAR Number of Barriers to interpolation User Defined 0 

5 NBOX Number of Lake Breeze regions User Defined 0 

5 NINTR2 Max number of stations for interpolations (NA values) 99 99 

5 NITER Max number of passes in divergence minimization 50 50 

5 NLB Number of stations in region User Defined 0 

5 NSMTH Number of passes in smoothing (NZ values) 2, 4*(NZ-1) 1,2,2,3,3,4,4,4,4,4 

5 R1 Relative weight at surface of Step 1 field and obs User Defined 1.00E-06 

5 R2 Relative weight aloft of Step 1 field and obs User Defined 1.00E-06 

5 RMAX1 Max surface over-land extrapolation radius (km) User Defined 200 

5 RMAX2 Max aloft over-land extrapolation radius (km) User Defined 200 

5 RMAX3 Maximum over-water extrapolation radius (km) User Defined 200 

5 RMIN Minimum extrapolation radius (km) 0.1 0.1 

5 RMIN2 

 Distance (km) around an upper air site where vertical 

extrapolation is excluded (Set to -1 if IEXTRP = ±4) 4 -1 

5 RPROG Weighting factor for CSUMM prognostic wind data User Defined 0 

5 TERRAD Radius of influence of terrain features (km) User Defined 12 

5 XBBAR X coordinate of Beginning of each barrier User Defined 0 
 Table C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value 

Recommended 

Value 

5 XBCST X Point defining the coastline (straight line) User Defined 0 

5 XEBAR X coordinate of Ending of each barrier User Defined 0 

5 XECST X Point User Defined 0 

5 XG1 X Grid line 1 defining region of interest User Defined 0 

5 XG2 X Grid line 2 User Defined 0 

5 YBBAR Y coordinate of Beginning of each barrier User Defined 0 

5 YBCST Y Point User Defined 0 

5 YEBAR Y coordinate of Ending of each barrier User Defined 0 

5 YECST Y Point User Defined 0 

5 YG1 Y Grid line 1 User Defined 0 

5 YG2 Y Grid Line 2 User Defined 0 

5 ZUPT Depth of domain-average lapse rate (m) 200 200 

5 ZUPWND Bottom and top of layer for 1st guess winds (m) 1, 1000 1.,1000. 

6 CONSTB Neutral mixing height B constant 1.41 1.41 

6 CONSTE Convective mixing height E constant 0.15 0.15 

6 CONSTN Stable mixing height N constant 2400 2400 

6 CONSTW Over-water mixing height W constant 0.16 0.16 

6 CUTP Minimum cut off precip rate (mm/hr) 0.01 0.01 

6 DPTMIN Minimum capping potential temperature lapse rate 0.001 0.001 

6 DSHELF Coastal/shallow water length scale 0 0 

6 DZZI Depth for computing capping lapse rate (m) 200 200 

6 FCORIOL Absolute value of Coriolis parameter 1.00E-04 1.00E-04 

6 HAFANG Half-angle for looking upwind (degrees) 30 30 

6 IAVET Conduct spatial averaging of temperature? (1 = True) 1 1 

6 IAVEZI Spatial averaging of mixing heights? (1 = True) 1 1 

6 ICOARE Overwater surface fluxes method and parameters 10 10 

6 ICOOL COARE cool skin layer computation 0 0 

6 ILEVZI Layer to use in upwind averaging (between 1 and NZ) 1 1 

6 ILUOC3D Land use category ocean in 3D.DAT datasets 16 16 

6 IMIXH Method to compute the convective mixing height 1 1 

6 IRAD Form of temperature interpolation (1 = 1/r) 1 1 

6 IRHPROG 3D relative humidity from observations or from prognostic data 0 1 

6 ITPROG 3D temps from obs or from prognostic data? 0 2 

6 ITWPROG 

Option for overwater lapse rates used in convective mixing 

height growth 0 2 

6 IWARM COARE warm layer computation 0 0 

6 JWAT1 Beginning landuse type defining water 999 55 

6 JWAT2 Ending landuse type defining water 999 55 

6 MNMDAV Max averaging radius (number of grid cells) 1 1 

6 NFLAGP Method for precipitation interpolation (2 = 1/r**2) 2 2 

6 NUMTS Max number of stations in temperature interpolations 5 10 

6 SIGMAP Precip radius for interpolations (km) 100 12 

6 TGDEFA Default over-water capping lapse rate (K/m) -0.0045 -0.0045 

6 TGDEFB Default over-water mixed layer lapse rate (K/m) -0.0098 -0.0098 

6 THRESHL 

Threshold buoyancy flux required to sustain convective mixing 

height growth overland 0.05 0.05 

6 THRESHW 

Threshold buoyancy flux required to sustain convective mixing 

height growth overwater 0.05 0.05 

6 TRADKM Radius of temperature interpolation (km) 500 500 

6 ZIMAX Maximum over-land mixing height (m) 3000 3000 

6 ZIMAXW Maximum over-water mixing height (m) 3000 3000 

6 ZIMIN Minimum over-land mixing height (m) 50 50 

6 ZIMINW Minimum over-water mixing height (m) 50 50 

APPENDIX D 

CALPUFF Parameter Values 

Appendix D

CALPUFF Parameter Values 

Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea 

Recommended 

Value 

1 Run Control 1 METRUN Do we run all periods (1) or a subset (0)? 0 

1 2 IBYR Beginning year User Defined 

1 3 IBMO Beginning month User Defined 

1 4 IBDY Beginning day User Defined 

1 5 IBHR Beginning hour User Defined 

1 5 IRLG Length of run (hours) User Defined 

1 5 NSECDT Length of modeling time step (seconds) 3600 3600 

1 6 NSPEC 

Number of species modeled (for MESOPUFF II 

chemistry) 5 

1 7 NSE Number of species emitted 3 

1 8 ITEST Flag to stop run after Setup Phase 2 

1 9 MRESTART 

Restart options (0 = no restart) allows splitting 

runs into smaller segments 0 

1 10 NRESPD Number of periods in Restart 0 

1 11 METFM 

Format of input meteorology (1 = CALMET, 2 = 

ISC) 1 

1 12 AVET 

Averaging time lateral dispersion parameters 

(minutes) 60 60 

1 13 PGTIME PG Averaging time 60 60 

2 Tech Options 1 MGAUSS Near-field vertical distribution (1 = Gaussian) 1 1 

2 2 MCTADJ 

Terrain adjustments to plume path (3 = Plume 

path) 3 3 

2 3 MCTSG 

Do we have subgrid hills? (0 = No) allows 

CTDM-like treatment for subgrid scale hills 0 0 

2 4 MSLUG Near-field puff treatment (0 = No slugs) 0 0 

2 5 MTRANS Model transitional plume rise? (1 = Yes) 1 1 

2 6 MTIP Treat stack tip downwash? (1 = Yes) 1 1 

2 7 MBDW 

Method to simulate downwash 

(1=ISC,2=PRIME) not used 

2 8 MSHEAR Treat vertical wind shear? (0 = No) 0 0 

2 9 MSPLIT Allow puffs to split? (0 = No) 0 0 

2 10 MCHEM MESOPUFF-II Chemistry? (1 = Yes) 1 1 

2 11 MAQCHEM Aqueous phase transformation 0 0 

2 12 MWET Model wet deposition? (1 = Yes) 1 1 

2 13 MDRY Model dry deposition? (1 = Yes) 1 1 

2 13 MTILT Plume Tilt (gravitational settling) 0 0 

2 14 MDISP 

Method for dispersion coefficients 

(2=micromet,3 = PG) 3 3 

2 15 MTURBVW 

Turbulence characterization? (Only if MDISP = 

1 or 5) 3 3 

2 16 MDISP2 Backup coefficients (Only if MDISP = 1 or 5) 3 3 

2 16 MTAULY Method for Sigma y Lagrangian timescale 0 0 

2 16 MTAUADV 

Method for Advective-Decay timescale for 

Turbulence 0 0 

2 16 MCTURB 

Method to compute sigma v,w using micromet 

variables 1 1 

2 17 MROUGH Adjust PG for surface roughness? (0 = No) 0 0 

2 18 MPARTL Model partial plume penetration? (0 = No) 1 1 

2 19 MTINV 

Elevated inversion strength (0 = compute from 

data) 0 0 

2 20 MPDF Use PDF for convective dispersion? (0 = No) 0 0 

2 21 MSGTIBL 

Use TIBL module? (0 = No) allows treatment of 

subgrid scale coastal areas 0 0 

2 22 MBCON Boundary conditions modeled 0 0 

2 23 MFOG Configure for FOG model output 0 0 

2 24 MREG Regulatory default checks? (1 = Yes) 1 1 
Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea 

Recommended 

Value 

3 Species List 1 CSPECn 

Names of species modeled (for MESOPUFF II 

must be SO2-SO4-NOX-HNO3-NO3) User Defined 

3 2 

Specie 

Names Manner species will be modeled User Defined 

3 3 

Specie 

Groups Grouping of species if any User Defined 

3 4 CGRUP 

3 5 CGRUP 

4 MapProjection XLAT1 Latitude of 1st standard parallel 

4 XLAT2 Latitude of 2nd standard parallel 

4 DATUM NWS84 

4 1 NX Number of east-west grids of input meteorology User Defined 373 

4 2 NY 

Number of north-south grids of input 

meteorology User Defined 316 

4 3 NZ Number of vertical layers of input meteorology User Defined 10 

4 4 DGRIDKM Meteorology grid spacing (km) User Defined 4 

4 5 ZFACE Vertical cell face heights of input meteorology User Defined 

0,20,40,65,120,2

00,400,700,1200

,2200,4000 

4 6 XORIGKM Southwest corner (east-west) of input User 

Defined 

meteorology -572 

4 7 YORIGIM Southwest corner (north-south) of input User 

Defined 

meteorology -956 

4 8 IUTMZN UTM zone User Defined 

4 9 XLAT Latitude of center of meteorology domain User Defined 

4 10 XLONG Longitude of center of meteorology domain User Defined 

4 11 XTZ Base time zone of input meteorology User Defined 

4 12 IBCOMP Southwest X-index of computational domain User Defined 105 

4 13 JBCOMP Southwest Y-index of computational domain User Defined 79 

4 14 IECOMP Northeast X-index of computational domain User Defined 242 

4 15 JECOMP Northeast Y-index of computational domain User Defined 252 

4 16 LSAMP Use gridded receptors? (T = Yes) F F 

4 17 IBSAMP Southwest X-index of receptor grid User Defined 

4 18 JBSAMP Southwest Y-index of receptor grid User Defined 

4 19 IESAMP Northeast X-index of receptor grid User Defined 

4 20 JESAMP Northeast Y-index of receptor grid User Defined 

4 21 MESHDN 

Gridded recpetor spacing = 

DGRIDKM/MESHDN 1 

5 Output Options 1 ICON Output concentrations? (1 = Yes) 1 1 

5 2 IDRY Output dry deposition flux? (1 = Yes) 1 1 

5 3 IWET Output west deposition flux? (1 = Yes) 1 1 

5 4 IT2D 2D Temperature 0 0 

5 5 IRHO 2D Density 0 0 

5 6 IVIS Output RH for visibility calculations (1 = Yes) 1 1 

5 7 LCOMPRS Use compression option in output? (T = Yes) T T 

5 8 ICPRT Print concentrations? (0 = No) 0 0 

5 9 IDPRT Print dry deposition fluxes (0 = No) 0 0 

5 10 IWPRT Print wet deposition fluxes (0 = No) 0 0 

5 11 ICFRQ Concentration print interval (1 = hourly) 1 24 

5 12 IDFRQ Dry deposition flux print interval (1 = hourly) 1 24 

5 13 IWFRQ West deposition flux print interval (1 = hourly) 1 24 

5 14 IPRTU 

Print output units (1 = g/m**3; g/m**2/s; 3 = 

ug/m3, ug/m2/s) 1 3 

5 15 IMESG Status messages to screen? (1 = Yes) 1 2 

5 16 LDEBUG Turn on debug tracking? (F = No) F F 
Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea 

Recommended 

Value 

5 16 IPFDEB First puff to track 1 1 

5 17 NPFDEB (Number of puffs to track) (1) 1 

5 18 NN1 (Met. Period to start output) (1) 1 

5 19 NN2 (Met. Period to end output) (10) 10 

7 Dry Dep Chem Dry Gas Dep 

Chemical parameters of gaseous deposition 

species User Defined defaults 

8 Dry Dep Size Dry Part. Dep 

Chemical parameters of particulate deposition 

species User Defined defaults 

9 Dry Dep Misc 1 RCUTR Reference cuticle resistance (s/cm) 30 30 

9 2 RGR Reference ground resistance (s/cm) 10 10 

9 3 REACTR Reference reactivity 8 8 

9 4 NINT Number of particle-size intervals 9 9 

9 5 IVEG 

Vegetative state (1 = active and unstressed; 

2=active and stressed) 1 1 

10 Wet Dep Wet Dep Wet deposition parameters User Defined defaults 

11 Chemistry 1 MOZ 

Ozone background? (0 = constant background 

value; 1 = read from ozone.dat) 0 0 

11 2 BCKO3 Ozone default (ppb) (Use only for missing data) 80 60 

11 3 BCKNH3 Ammonia background (ppb) 10 17 

11 4 RNITE1 Nighttime SO2 loss rate (%/hr) 0.2 0.2 

11 5 RNITE2 Nighttime NOx loss rate (%/hr) 2 2 

11 6 RNITE3 Nighttime HNO3 loss rate (%/hr) 2 2 

11 7 MH2O2 H2O2 data input option 1 1 

11 8 BCKH2O2 Monthly H2O2 concentrations 1 12*1 

 BKPMF Fine particulate concentration 12 * 1.00 not used 

 OFRAC Organic fraction of Fine Particulate 

2*0.15, 9*0.20, 

1*0.15 not used 

 VCNX VOC / NOX ratio 12 * 50.00 not used 

12 Dispersion 1 SYTDEP 

Horizontal size (m) to switch to time 

dependence 550 550 

12 2 MHFTSZ Use Heffter for vertical dispersion? (0 = No) 0 0 

12 3 JSUP PG Stability class above mixed layer 5 5 

12 4 CONK1 Stable dispersion constant (Eq 2.7-3) 0.01 0.01 

12 5 CONK2 Neutral dispersion constant (Eq 2.7-4) 0.1 0.1 

12 6 TBD Transition for downwash algorithms (0.5 = ISC) 0.5 0.5 

12 7 IURB1 Beginning urban landuse type 10 10 

12 8 IURB2 Ending urban landuse type 19 19 

12 9 ILANDUIN 

Land use type (20 = Unirrigated agricultural 

land) 20 20 

12 10 ZOIN Roughness length (m) 0.25 0.25 

12 11 XLAIIN Leaf area index 3.0 3.0 

12 12 ELEVIN Met. Station elevation (m above MSL) 0.0 0.0 

12 13 XLATIN Met. Station North latitude (degrees) -999.0 -999.0 

12 14 XLONIN Met. Station West longitude (degrees) -999.0 -999.0 

12 15 ANEMHT 

Anemometer height of ISC meteorological data 

(m) 10.0 10.0 

12 16 ISIGMAV 

Lateral turbulence (Not used with ISC 

meteorology) 1 1 

12 17 IMIXCTDM Mixing heights (Not used with ISC meteorology) 0 0 

12 18 XMXLEN Maximum slug length in units of DGRIDKM 1.0 1 

12 19 XSAMLEN 

Maximum puff travel distance per sampling 

step (units of DGRIDKM) 1.0 1 

12 20 MXNEW Maximum number of puffs per hour 99 99 

12 21 MXSAM Maximum sampling steps per hour 99 99 

12 22 NCOUNT 

Iterations when computing Transport Wind 

(Calmet & Profile Winds) 2 2 

12 23 SYMIN Minimum lateral dispersion of new puff (m) 1.0 1 

12 24 SZMIN Minimum vertical dispersion of new puff (m) 1.0 1 

12 25 SVMIN Array of minimum lateral turbulence (m/s) 6 * 0.50 6 * 0.50 
Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea 

Recommended 

Value 

12 26 SWMIN Array of minimum vertical turbulence (m/s) 

0.20,0.12,0.08,

0.06,0.03,0.01

6 

12 27 CDIV (1), (2) Divergence criterion for dw/dz (1/s) 0.01 (0.0,0.0) 0.0,0.0 

12 28 WSCALM Minimum non-calm wind speed (m/s) 0.5 0.5 

12 29 XMAXZI Maximum mixing height (m) 3000 3000 

12 30 XMINZI Minimum mixing height (m) 50 50 

12 31 WSCAT Upper bounds 1st 5 wind speed classes (m/s) 

1.54,3.09,5.14,

8. 23,10.8 

1.54,3.09,5.14,8. 

23,10.8 

12 32 PLX0 Wind speed power-law exponents 

0.07,0.07,0.10,

0.15,0.35,0.55 

0.07,0.07,0.10,0.

15,0.35,0.55 

12 33 PTGO 

Potential temperature gradients PG E and F 

(deg/km) 0.020,0.035 0.020,0.035 

12 34 PPC Plume path coefficients (only if MCTADJ = 3) 

0.5,0.5,0.5,0.5,

0.35,0.35 

0.5,0.5,0.5,0.5,0.

35,0.35 

12 35 SL2PF Maximum Sy/puff length 10.0 10.0 

12 36 NSPLIT Number of puffs when puffs split 3 3 

12 37 IRESPLIT Hours when puff are eligible to split User Defined 

12 38 ZISPLIT Previous hour’s mixing height(minimum)(m) 100.0 100.0 

12 39 ROLDMAX 

Previous Max mix ht/current mix ht ratio must 

be less then this value for puff to split 0.25 0.25 

12 40 NSPLITH Number of puffs when puffs split horizontally 5 5 

12 41 SYSPLITH 

Min sigma-y (grid cell units) of puff before horiz 

split 1.0 1.0 

12 12 42 SHSPLITH 

Min puff elongation rate per hr from wind shear 

before horiz split 2.0 2.0 

12 43 CNSPLITH Min conc g/m3 before puff may split horizontally 1.0E-07 1.0E-07 

12 44 EPSSLUG 

Convergence criterion for slug sampling 

integration 1.00E-04 1.00E-04 

12 45 EPSAREA 

Convergence criterion for area source 

integration 1.00E-06 1.00E-06 

12 46 DSRISE Step length for rise integration 1.0 1.0 

12 47 HTMINBC 500.0 500.0 

12 48 RSAMPBC 10.0 10.0 

12 49 MDEPBC 1 1 

13 Point Source 1 NPT1 Number of point sources User Defined 

13 2 IPTU Units of emission rates (1 = g/s) 1 

13 3 NSPT1 Number of point source-species combinations 0 

13 4 NPT2 

Number of point sources with fully variable 

emission rates 0 

13 

Point 

Sources Point sources characteristics User Defined 

14 Area Source Area Sources Area sources characteristics User Defined 

15 Volume Source Volume Volume sources characteristics 

User Defined 

Sources 

16 Line Source Line Sources Buoyant lines source characteristics User Defined 

17 Receptors NREC Number of user defined receptors User Defined 

17 

Receptor 

Data Location and elevation (MSL) of receptors User Defined 
APPENDIX E 

CALPOST Parameter Values 

 

Appendix E 

CALPOST Parameter Values 

Table E-1. Recommended CALPOST parameter values chosen by the Region 10 states for use in BART modeling

Input 

Group Variable Description 

Default 

Value 

Recommended 

Value 

1 ASPEC Species to process VISIB VISIB 

1 ILAYER 

Layer/deposition code (1 = CALPUFF concentrations; -3 = wet+dry deposition 

fluxes) 1 1 

1 LBACK Add Hourly Background Concentrations/Fluxes? F F 

1 MFRH Particle growth curve for hygroscopic species 2 2 

2 RHMAX Maximum relative humidity (%) used in particle growth curve 98 95 

2 LDRING Report results by Discrete receptor Ring, if Discrete Receptors used. (T = true) T 

 Modeled species to be included in computing the light extinction 

2 LVSO4 Include SO4? T T 

2 LVNO3 Include NO3? T T 

2 LVOC Include Organic Carbon? T T 

2 LVPMC Include Coarse Particles? T T 

2 LVPMF Include Fine Particles? T T 

2 LVEC Include Elemental Carbon? T T 

 

2 LVBK 

when ranking for TOP-N, TOP-50, and Exceedance tables Include 

BACKGROUND? T T 

2 SPECPMC Species name used for particulates in MODEL.DAT file: COARSE = PMC PMC 

2 SPECPMF Species name used for particulates in MODEL.DAT file: FINE = PMF PMF 

 Extinction Efficiencies (1/Mm per ug/m**3) 

2 EEPMC PM COARSE = 0.6 0.6 

2 EEPMF PM FINE = 1.0 1.0 

2 EEPMCBK Background PM COARSE 0.6 0.6 

2 EESO4 SO4 = 3.0 3.0 

2 EENO3 NO3 = 3.0 3.0 

2 EEOC Organic Carbon = 4.0 4.0 

2 EESOIL Soil = 1.0 1.0 

2 EEEC Elemental Carbon = 10.0 10.0 

 

2 LAVER Method used for 24-hr avg % change light extinction F F 

2 MVISBK 

Method used for background light extinction (2 = Hourly RH adjustment; 6 = 

FLAG seasonal f(RH)) 2 or 6 6 

2 RHFAC Monthly RH adjustment factors from FLAG (unique for each Class I area) Yes if 6 EPA 

 

Background monthly extinction coefficients (FLAG) unique for each Class I 

area 

2 BKSO4 

Assume all hygroscopic species as SO4 (raw extinction value without 

scattering efficiency adjustment) see table 

2 BKNO3 see table 

2 BKPMC see table 

2 BKOC see table 

2 BKSOIL Assume all non-hygroscopic species as Soil see table 

2 BKEC see table 

2 BEXTRAY Extinction due to Rayleigh scattering 10.0 10.0 

 Averaging time(s) reported 

3 L1PD Averaging period of model output F F 

3 L1HR 1-hr averages F F 

3 L3HR 3-hr averages F F 

3 L24HR 24-hr averages T T 

3 LRUNL Run lengtyh (annual) F F 

3 LT50 Top 50 table for each averaging time selected T F 

3 LTOPN 1 

3 NTOP 1 

3 ITOP 

 

APPENDIX F 

Emission Rates and Stack Parameters 

PGE Boardman Unit 1 - Flue Gas Emissions Data PM10 Speciation: 

----------------Filterable---------------- -----

Baseline Case - Existing Operation 

Flow 

 (acfm) 

Stack 

Velocity

(ft/s) 

Temp.

 (°F) 

NOx

 (lb/hr) 

SO2

 (lb/hr) 

PM10

(lb/hour) 

Elemental 

Carbon 

(lb/hour) 

PM Fine 

(lb/hour) 

PM 

Coarse 

(lb/hour) 

Org

Ca

(lb/

1. Existing Operation 2,159,900 95 293 3152.0 4943.1 176.20 1.74 45.40 58.90 14

NOx Controlled Outlet Conditions 

Flow 

 (acfm) 

Stack 

Velocity

(ft/s) 

Temp.

 (°F) 

NOx

 (lb/hr) 

SO2

 (lb/hr) 

PM10

(lb/hour) 

Elemental 

Carbon 

(lb/hour) 

PM Fine 

(lb/hour) 

PM 

Coarse 

(lb/hour) 

Org

Ca

(lb/

1. Selective Catalytic Reduction (SCR) 2,173,000 95 293 869.0 4943.1 176.20 1.74 45.40 58.90 142. New Low NOx Burners with Modified 

OFA System 

2,159,900 95 293 1332.4 4943.1 176.20 1.74 45.40 58.90 14

SO2 Controlled Outlet Conditions 

Flow 

 (acfm) 

Stack 

Velocity

(ft/s) 

Temp.

 (°F) 

NOx

 (lb/hr) 

SO2

 (lb/hr) 

PM10

(lb/hour) 

Elemental 

Carbon 

(lb/hour) 

PM Fine 

(lb/hour) 

PM 

Coarse 

(lb/hour) 

Org

Ca

(lb/

1. Wet Flue Gas Desulfurization (FGD) 1,823,200 60 136 3152.0 579.3 115.45 1.14 29.80 38.60 92. Semi-Dry Flue Gas Desulfurization 

(FGD) 

1,901,700 83 170 3152.0 869.0 115.45 1.14 29.80 38.60 9

Notes: 1) SO2 based on no SO2 to SO3 conversion. 

2) PM speciations derived from spreadsheet prepared by ODEQ. 3) Stack velocity (except for Wet FGD and Wet ESP) based on existing stack diameter of 22 feet. 4) Emission rates based on 5,793 mmbtu/hr. 

Rick Tetzloff - RE: Revised Protocol 

 

Don,

 The revised protocol for the BART-Determination Calpuff modeling for the PGE Boardman facility, as submitted, includes:

 

1) A summary of the BART Modeling Protocol for Washington, Oregon, and Idaho (2006), which was developed by the three states 

to cover both the Exemption and Determination phases of the modeling,

2) Engineering data on possible controls, with a proposed set of four controls and their respective emission rates and stack 

parameters that will be evaluated in the Determination modeling.

 

 In that the Calpuff modeling portion of the revised Boardman protocol summarizes and highlights the approved Modeling Protocol 

for Washington, Oregon, and Idaho, the modeling portion of the revised protocol is approved for use in the Determination or control 

evaluation phase of the BART analysis.

 

Phil

 

Philip Allen

AQ Division

Oregon DEQ

503.229.6904

allen.philip@deq.state.or.us

 

 

-----Original Message----- 

From: Don.Caniparoli@CH2M.com [mailto:Don.Caniparoli@CH2M.com] 

Sent: Wednesday, January 17, 2007 4:44 PM 

To: ALLEN Philip; Mark.Fisher@state.or.us 

Cc: Patty.Jacobs@state.or.us; Ray.Hendricks@pgn.com; Rick.Tetzloff@pgn.com; Steven.Anderson@pgn.com; 

natalie.liljenwall@ch2m.com 

Subject: Revised Protocol 

Attached is the revised protocol as we discussed today.

 

Don

From: "ALLEN Philip" <ALLEN.Philip@deq.state.or.us>

To: <Don.Caniparoli@CH2M.com>, <Mark.Fisher@state.or.us>

Date: 1/18/2007 6:06 PM

Subject: RE: Revised Protocol

CC: <Patty.Jacobs@state.or.us>, <Ray.Hendricks@pgn.com>, <Rick.Tetzloff@pgn.com>, 

<Steven.Anderson@pgn.com>, <natalie.liljenwall@ch2m.com>

Message Page 1 of 1

file://C:\Documents and Settings\e65404\Local Settings\Temp\GW}00001.HTM 2/12/2007
From: ALLEN Philip [mailto:ALLEN.Philip@deq.state.or.us] 

Sent: Tuesday, August 28, 2007 12:21 PM 

To: ray.hendricks@pgn.com 

Cc: Caniparoli, Don/PDX; FISHER Mark 

Subject: Use of onzone.dat file for BART

Ray, 

 As you know, an ozone.dat for use in the Calpuff BART Exemption modeling was developed by Eri 

Ottersburg (SLR, International) and Mary Beth Yansura (CH2M Hill), with input and review by Oregon 

DEQ. This file would be used in lieu of the default 60 ppb value that was specified in the three-states 

BART Modeling Protocol. The ozone data incorporated in the file was compiled from state and 

federal ozone monitors in the three state area. After discussions with EPA Region 10, the Federal 

Land Managers (Forest Service, U.S. Fish and Wildlife, and National Park Service), and Washington 

State and Idaho, this ozone.dat file is considered an addition to the protocol and acceptable for use in 

the BART modeling. 

 

 If you have any questions, please don't hesitate to contact me. 

 

Phil 

 

Philip Allen 

AQ Division 

Oregon DEQ 

503.229.6904 

allen.philip@deq.state.or.us
Boardman Plant Appendix G 

110207 G-1 

Appendix G 

Emissions Performance Analysis Memo 
BLACK & VEATCH 

MEMORANDUM 

Portland General Electric B&V Project 144449 

Boardman Station BART Analysis B&V File 15.1300 

Boardman Station Post-BART Emissions Limit 9/30/2007 

Introduction

A Best Available Retrofit Technology (BART) analysis is currently being performed for Boardman 

Station Unit 1 located in Boardman, Oregon to support the development of the Oregon 

Department of Environmental Quality (ODEQ) Regional Haze Plan. Boardman 1 has been 

identified as a BART-eligible source for three criteria pollutants, Nitrogen Oxides (NOx), Sulfur 

Dioxide (SO2) and Particulate Matter (PM). Portland General Electric (PGE) has retained Black & 

Veatch (B&V) to perform the BART engineering analysis for this purpose. 

The EPA guidelines for BART analyses outline presumptive limits of criteria pollutant emissions. 

The NOx presumptive limit applicable to such units is 0.23 lb/MMBTU and the SO2 presumptive 

limit is 0.15 lb/MMBTU. 

To support the selection of a feasible technology, an evaluation of actual continuous emissions 

monitoring system (CEMS) emissions data was performed on plants with pollution controls for 

NOx and SO2. The emissions data were reported to the Environmental Protection Agency (EPA) 

by electric generator operators. This memorandum summarizes the results of this evaluation and 

identifies achieveable performance emissions limits for the specific control technologies to be 

incorporated into the BART analysis for Boardman. 

The proposed BART control technologies evaluated were: 

1. Low NOx Burners (LNB) 

2. Overfire Air (OFA) 

3. Combination of LNB/OFA 

4. Combination of LNB/OFA/Selective Non-Catalytic Reduction (SNCR) 

5. Selective Catalytic Reduction (SCR) 

6. Spray Dryer Absorber (SDA) with Particulate Control Device 

7. Wet Flue Gas Desulfurization (WFGD) 

CEMS Data Analysis Methodology

A 12-month CEMS data period was utilized for this evaluation. Hourly CEMS data was obtained 

for the period between 3/1/2005 to 2/28/2006. An update to this memorandum with additional 

data evaluation of CEMS data for other time periods was performed for selected units. The 

evaluation was performed on NOx and SO2 emissions data only since PM emission levels are 

typically not monitored continuously. Data periods when the unit is in an outage, startup and 

shutdown were omitted from this analysis. For CEMS data relating to the operation of an SCR, 

only data periods when the SCR was operated during the ozone-season were considered. 

For each criteria pollutant, the following emissions data were computed from the reported CEMS 

data: 

1. 1-hour block average 

2. 3-hour rolling average 

3. 24-hour rolling average 

4. Daily block average 

5. 30-day rolling average 

6. 12-month block average 
BLACK & VEATCH 

MEMORANDUM Page 2 

Portland General Electric B&V Project 144449 

Boardman Station BART Analysis 9/30/2007 

Boardman Station Post-BART Emissions Limits 

CEMS Data Evaluation Results

For each control technology category identified, CEMS data indicating the controlled emissions 

level when operating the control technology were obtained. Below is a summary list of the CEMS 

data source for each control technology category: 

Tech. LNB LNB/OFA SCR SDA WFGD 

South Oak 5 Centralia 1 Hawthorne 5 Hawthorne 5 Centralia 1 

Meramec 4 Bridgeport 3 Michigan City 

12 

Holcomb 1 Laramie River 

1 

North Omaha 5 Colstrip 1 New Madrid 1 Craig 3 Craig 1, 2 

Laramie River 

1, 3 

Craig 1, 2, 3 Paradise 1 Laramie River 

3 

Stanton 2 

 Monticello 3 Stanton 2 Springerville 1 Navajo 1 

 Springerville 1 Springerville 3 Springerville 3 Paradise 1 

CEMS 

Data 

Source 

 WA Parish 5-8 

LNB = Low NOx Burners 

LNB/OFA = Low NOx Burners with Overfire Air 

SCR = Selective Catalytic Reduction 

SDA = Spray Dryer Absorber (semi-dry scrubber) 

WFGD = Wet Flue Gas Desulfurization (wet scrubber) 

A summary table of the emissions data produced from the evaluation of the CEMS data is shown 

in the attached CEMS Data Analysis Summary Table. For each unit and its control technology, 

information on the type of fuel combusted, control technology manufacturer and vintage, 

operating air permit limit and averaging period were provided. 

A general summary of the differences and trends observed from the evaluated CEMS data is 

provided below. 

LNB

The highest NOx 24-hour rolling average emissions was observed for North Omaha 5 at 0.41 

lb/MMBTU, followed by Laramie 3 at 0.33 lb/MMBTU, Laramie 1 at 0.32 lb/MMBTU, Meramec 4 

at 0.32 lb/MMBTU, and South Oak 5 at 0.24 lb/MMBTU. 

The highest NOx 30-day rolling average emissions followed a similar trend with data ranging from 

0.37 to 0.18 lb/MMBTU. 

All five plants are equipped with wall-fired boilers from either Foster Wheeler or Babcock & 

Wilcox. South Oak 5 burns bituminous coal while the others burn sub-bituminous coal. 

LNB/OFA

The NOx 24-hour rolling average emissions ranged from 0.56 lb/MMBTU at Craig 3 to 0.27 

lb/MMBTU at Springerville 1 and Monticello 3. 

The NOx 30-day rolling average emissions ranged from 0.45 lb/MMBTU at Craig 3 to 0.16 

lb/MMBTU at Bridgeport 3. 
BLACK & VEATCH 

MEMORANDUM Page 3 

Portland General Electric B&V Project 144449 

Boardman Station BART Analysis 9/30/2007 

Boardman Station Post-BART Emissions Limits 

The wide range of NOx emissions data observed in LNB/OFA performance is attributed to the 

type of boiler technology (wall-fired versus tangential) and also the vintage of the combustion 

technology installed at each unit. Tangential-fired boilers are inherently lower in NOx emissions 

than wall-fired boilers. Developments in combustion control technologies have resulted in 

technology vendors providing lower emission levels as performance guarantees. The type of fuel 

combusted at the eight evaluated units also varies. 

LNB/OFA/SNCR

No data points were established for the use of SNCR. However, demonstrated tests and 

manufacturer data indicate that SNCR should be able to achieve between 20 to 25 percent 

reduction after a LNB/OFA installation with a maximum ammonia slip of 10 ppm. 

SCR

The highest NOx 24-hour rolling average emissions was observed for New Madrid 1 at 0.30 

lb/MMBTU, followed by Paradise 1 at 0.23 lb/MMBTU, Stanton 2 at 0.19 lb/MMBTU, Michigan 

City 12 at 0.13 lb/MMBTU and Hawthorne 5 at 0.09 lb/MMBTU. 

The highest NOx 30-day rolling average emissions follows a different trend with data for Stanton 2 

at 0.17, New Madrid 1 at 0.12, Paradise 1 and Michigan City 12 at 0.09 and Hawthorne 5 at 0.07 

lb/MMBTU, respectively. 

CEMS data obtained for SCR operation at New Madrid 1, Paradise 1 and Michigan City 12 

indicate that the SCRs are operated during ozone season only. The data evaluated for New 

Madrid 1 was from 4/30/05 to 8/17/05, Paradise 1 from 4/30/05 to 9/30/05, while for Michigan 

City 12 the data period was 5/12/05 to 10/1/05. 

The observed range in NOx average emissions can be attributed to the combustion NOx 

technologies that are available at each unit. For Hawthorne 5, the SCR is coupled with LNB/OFA 

technologies. In Michigan City 12 and Paradise 1, the SCR is coupled with OFA, while the SCR 

is the only NOx control technology in New Madrid 1. Stanton 2 is equipped with a LNB and SCR. 

Therefore, the highest 24-hour rolling data most probably indicates upset operating conditions in 

the SCR resulting in controlled NOx emissions by the combustion control technologies. 

Further analysis of CEMS data was performed for plants operating an SCR while also equipped 

with LNB and OFA technologies. The 2007 first quarter CEMS data from the WA Parish (Unit 5 

to 8) and Springerville 3 were evaluated to determine the average NOx emission values. From 

the review, the 30-day rolling averages for WA Parish are all slightly lower than 0.05 lb/MMBTU, 

while for Springerville, the highest 30-day rolling average is 0.08 lb/MMBTU. While this data set 

was very limited (only 3 months), it should be taken into account when developing the 

performance emission levels for the SCR option in the BART analysis. 

SDA

The highest SO2 24-hour rolling average emissions were observed for Springerville 1 at 0.60 

lb/MMBTU, followed by Laramie River 3 at 0.42 lb/MMBTU, Holcomb 1 at 0.38 lb/MMBTU and 

Craig 3 at 0.31 lb/MMBTU. 
BLACK & VEATCH 

MEMORANDUM Page 4 

Portland General Electric B&V Project 144449 

Boardman Station BART Analysis 9/30/2007 

Boardman Station Post-BART Emissions Limits 

However, the highest SO2 30-day rolling average emissions do not follow the same trend with 

Craig 3, Holcomb 1 and Laramie River 3 registering maximum averages of 0.14, 0.16 and 0.21 

lb/MMBTU, respectively. On the high-end, the Springerville 1 maximum average is 0.57 

lb/MMBTU. 

From the information on the vintage of technology, the SDA system at Hawthorne 5 is of the 

current generation, while the SDA technology at Holcomb 1, Craig 3 and Laramie River 3 are of 

older designs. Also, the SDA system available at Craig 3 and Laramie River 3 provided by 

Babcock & Wilcox (B&W) have horizontal flow reactors with horizontal reagent slurry spray 

systems. Most current generation SDAs as in Hawthorne 5 utilize a rotary atomizer or dual-fluid 

nozzle system. It should also be noted that operational problems were reported for the SDA 

system installed at Springerville 1. Therefore, the higher emissions averages analyzed for 

Springerville 1 may not be indicative of the long-term performance of the SDA system. 

Also based on this, an analysis on long-term SDA operation was performed for Hawthorne 5. 

The time period selected was from August 2002 through June 2007 based on reported CEMS 

data. The analysis shows that the maximum 30-day rolling average for the five year was at 0.18 

lb/MMBtu. The high average was due to initial problems with operating the SDA system. 

Alternate analyses were performed to discount the problematic operating period by selecting 

other start dates for the analyzed time period (for each year; 2003, 2004, 2005, and 2006). The 

resultant analysis indicates that with experience in operating the SDA and also the troubleshooting of the initial problems, the highest 30-day rolling average decreases to the 0.14 

lb/MMBtu level. 

Additional analysis on a new operating SDA system at Springerville 3 was performed based on 

2007 first quarter CEMS data. While this data set was very limited (only 3 months), analysis of 

the 30-day rolling average data for this unit indicated that the SDA with PJFF system was capable 

of controlling SO2 emissions to below 0.12 lb/MMBTU during the evaluated period. One of the 

factors that impacts SO2 removal is the lime reagent stoichiometric ratio and this information is 

not obtainable from the CEMS data. However, the results of this evaluation indicate the capability 

of the SDA system to control SO2 emissions at a consistent level. 

WFGD

The highest SO2 24-hour rolling average emissions ranged from 0.41 lb/MMBTU at Navajo 1 to 

0.10 lb/MMBTU at Centralia 1. 

The highest SO2 30-day rolling average emissions ranged from 0.19 lb/MMBTU at Laramie River 

1 and Stanton 2 to 0.05 lb/MMBTU at Navajo 1. 

It should be noted that Laramie River 1 operates with a WFGD bypass to reheat the flue gas 

exiting the stack. Therefore, the WFGD data for Laramie River 1 do not represent a true 

indication on the performance capability of current WFGD technology. 
BLACK & VEATCH 

MEMORANDUM Page 5 

Portland General Electric B&V Project 144449 

Boardman Station BART Analysis 9/30/2007 

Boardman Station Post-BART Emissions Limits 

It is also important to note the different fuels combusted in these plants. Laramie River 1 and 

Craig 1 and 2 burn low-sulfur sub-bituminous coal, while Paradise 1, Centralia 1, Stanton 2 and 

Navajo 1 burn higher-sulfur bituminous coal. 

Recommended Boardman Post-BART Emissions Limits

To develop recommended post-BART emissions limits for Boardman 1, CEMS data for pre-BART 

(i.e., current) operations at Boardman 1 were analyzed with the same methodology as described 

above. A 24-month data period was analyzed for pre-BART operations using CEMS data from 

11/1/2003 to 10/31/2005. CEMS data from the year 2006 was not utilized as a long plant outage 

was observed beginning October 2005 through May 2006. 

The analyzed CEMS data indicated stable pre-BART operations as detailed in the following table: 

Pollutant Max 24-hour 

Rolling Average 

Max 30-day 

Rolling Average 

NOx 0.49 lb/MMBTU 0.46 lb/MMBTU 

SO2 0.80 lb/MMBTU 0.68 lb/MMBTU 

Based on the evaluation of similar units with relatively equivalent control technology equipment as 

the cases that are being analyzed in the BART process and the existing operational 

characteristics of Boardman 1, the recommended post-BART emissions limits are as follows: 

Control Technology 

Recommended Emissions 

Limits (lb/MMBTU) 

 30-day Rolling Average 

LNB 0.38 

LNB/OFA 0.28 

LNB/OFA/SNCR 0.23 with 10 ppm NH3 slip 

(max) 

LNB/OFA/SCR 0.07 with 5 ppm NH3 slip (max) 

SDA 0.15 

WFGD 0.10 

The recommended emissions limits were based on the best achievable emissions levels 

demonstrated by the evaluated units that have the most applicable or similar characteristics to 

that of Boardman 1 while allowing for operational margin. 

When developing the costs for control technology options for this BART analysis, combustion 

control vendor quotations were obtained. These quotations included expected post-BART NOx

emissions levels for the LNB and LNB/OFA technologies. These expected emissions levels were 

factored in when developing the recommended post-BART emissions limits for these 2 categories 

of control technology. 

In addition to the expected post-BART NOx emissions levels provided by the vendors, the 30-day 

emission limit for the LNB technology was also developed from a range of max 30-day averages 
BLACK & VEATCH 

MEMORANDUM Page 6 

Portland General Electric B&V Project 144449 

Boardman Station BART Analysis 9/30/2007 

Boardman Station Post-BART Emissions Limits 

for LNB installations by B&W and Alstom in wall-fired boilers of various sizes that ranges from a 

low of 0.18 lb/MMBTU for South Oak 5 to 0.37 lb/MMBTU for North Omaha 5. For the LNB/OFA 

case, it was observed that Bridgeport 3 and Springerville 1 have a max 30-day average of 0.16 

and 0.21 lb/MMBTU, respectively. However, since both units are tangential-fired boilers, the 

recommended LNB/OFA 30-day emission limit for Boardman is higher for a wall-fired boiler while 

maintaining no increase in CO emissions. 

The use of LNB/OFA with SNCR will reach BART presumptive NOx limits. The recommended 30-

day limit for this combination is 0.23 lb/MMBTU. 

The recommended 30-day NOx emission limit for the SCR case was based on the demonstrated 

performance of SCRs at the evaluated plants within this memorandum. As evaluated, the 

sustainable outlet emission rate varies between the plants. Only one unit maintains emissions 

below 0.07 lb/MMBTU. The limit recommended for Boardman 1 was based on the consideration 

that the SCR at Boardman will be a retrofit and all retrofit projects require operating margin on 

emission limits. 

Lastly, for the FGD technologies, a comparison with the current performance of modern FGD 

technology at similar PRB-fueled units such as Springerville 3 (0.12 lb/MMBTU), Hawthorne 5 

(0.14 lb/MMBTU) and Holcomb 1 (0.16 lb/MMBTU) for the SDA and Craig 1 (0.09 lb/MMBTU) for 

the WFGD was performed to determine the recommended post-BART emissions level of 0.15 

lb/MMBTU for SDA and 0.10 lb/MMBTU for WFGD. 

In addition to considering the performance of existing control technology systems when 

developing the recommended emissions limits, a small degree of flexibility was added as owner’s 

margin to the general industry standard guaranteed emissions levels provided by equipment 

vendors. This was the primary reason why the typical control technology vendor performance 

guarantees for similar installations were not recommended as the post-BART emissions limits. 

The recommended emissions limits as presented above translate into an estimated removal 

efficiency (based on the 30-day rolling average data) for each control technology as: 

Control Technology Estimated Removal Efficiency (%) 

LNB 17 

LNB/OFA 39 

LNB/OFA/SNCR 50 

LNB/OFA/SCR 85 

SDA 78 

WFGD 85 

 
Plant Pollutant Technologies OEM Year Air Permit Lim

/Boiler Max 1-hour Max 3-hour Max 24-hour Max 30-day 12-month % Increase CEMS Data Period (lb/MBtu) 

Block Rolling Rolling Rolling Block 24-hr over 30-

day

Analyzed

NOx Controls - Low NOx Burners (LNB) and/or Overfire Air (OFA)AS King 1, MN NOx OFA B&W (T) 1958 1.26 1.18 1.14 0.90 0.76 27% Mar 05 to Feb 06 -- Navajo 1, AZ NOx OFA ABB-CE (T) 1974 0.46 0.45 0.43 0.39 0.36 13% Mar 05 to Feb 06South Oak 5, WI NOx LNB Alstom (W) ? 0.41 0.41 0.24 0.18 0.17 35% Mar 05 to Feb 06Holcomb 1, KS NOx LNB B&W (W) 1983 0.42 0.40 0.38 0.34 0.32 12% Mar 05 to Feb 06 0.08 Laramie River 1, WY NOx LNB B&W (W) 1980 0.35 0.33 0.32 0.28 0.27 14% Mar 05 to Feb 06 -- Laramie River 3, WY NOx LNB B&W (W) 1982 0.36 0.35 0.33 0.27 0.26 21% Mar 05 to Feb 06 -- Meramec 4, MO NOx LNB Alstom (W) 2001 0.99 0.75 0.32 0.21 0.19 48% Mar 05 to Feb 06North Omaha 5, NE NOx LNB Alstom (W) 1999 0.52 0.45 0.41 0.37 0.33 13% Mar 05 to Feb 06Centralia 1, WA NOx LNB, OFA ABB (Alstom) (T) 1971 0.39 0.37 0.35 0.29 0.27 20% Mar 05 to Feb 06 0.30 Bridgeport 3, CT NOx LNB, OFA Alstom (T) 1994 0.37 0.35 0.32 0.16 0.13 99% Mar 05 to Feb 06 -- Colstrip 1, MT NOx LNB, OFA CE (T) 1975 0.86 0.85 0.47 0.38 0.35 24% Mar 05 to Feb 06 -- Craig 1, CO NOx LNB, OFA B&W (W) 2003 0.36 0.36 0.34 0.30 0.28 11% Mar 05 to Feb 06Craig 2, CO NOx LNB, OFA B&W (W) 2004 0.36 0.35 0.33 0.29 0.28 12% Mar 05 to Feb 06Craig 3, CO NOx LNB, OFA B&W (W) 2005 0.59 0.58 0.56 0.45 0.40 26% Mar 05 to Feb 06 -- Monticello 3, TX NOx LNB, OFA Alstom (W) ? 0.40 0.30 0.27 0.24 0.21 15% Mar 05 to Feb 06Springerville 1, AZ NOx LNB, OFA Alstom (T) 2005 0.39 0.36 0.27 0.21 0.19 29% Mar 05 to Feb 06NOx Controls - Selective Catalytic Conversion (SCR)Hawthorne 5, MO NOx LNB, OFA, SCR B&W 2001 0.51 0.22 0.09 0.07 0.07 22% Mar 05 to Feb 06 0.08 Michigan City 12, IN NOx OFA, SCR B&V 2003 0.48 0.41 0.13 0.09 0.08 51% Mar 05 to Feb 06 -- New Madrid 1, MO NOx SCR B&V 2000 1.29 0.92 0.30 0.12 0.12 138% Mar 05 to Feb 06 -- Stanton 2, FL NOx LNB, SCR B&W/Noell 1996 0.34 0.34 0.19 0.17 0.16 16% Mar 05 to Feb 06Paradise 1, KY NOx OFA, SCR Alstom 2001 0.85 0.75 0.23 0.09 0.08 159% Mar 05 to Feb 06Springerville 3, AZ NOx SCR - 2006 0.28 0.24 0.14 0.08 - 75% 2007H1 0.152 WA Parish 5, TX NOx SCR - 2003/4 0.28 0.22 0.09 0.05 - 80% 2007H1 WA Parish 6, TX NOx SCR - 2003/4 0.34 0.33 0.10 0.04 - 150% 2007H1 WA Parish 7, TX NOx SCR - 2003/4 0.29 0.21 0.07 0.04 - 75% 2007H1 WA Parish 8, TX NOx SCR - 2003/4 0.31 0.23 0.07 0.04 - 75% 2007H1 OPPD Nebraska City 2 NOx LNB, OFA, SCR 0.07 Plum Point NOx LNB, OFA, SCR 0.09 Holcomb Expansion NOx LNB, OFA, SCR 0.07 Big Stone 2 NOx LNB, OFA, SCR 0.07 JK Spruce 2 NOx LNB, OFA, SCR 0.05 SO2 Controls - Semi-Dry Flue Gas Desulfurization (FGD - i.e., Dry Scrubber)Hawthorne 5, MO SO2 Dry FGD B&W 2001 0.74 0.70 0.46 0.18 - 156% 0.12 Holcomb 1, KS SO2 Dry FGD B&W 1983 0.87 0.75 0.38 0.16 0.12 145% 0.12 Craig 3, CO SO2 Dry FGD B&W 2005 0.77 0.68 0.31 0.14 0.13 121% -- Laramie River 3, WY SO2 Dry FGD B&W 1982 0.59 0.58 0.42 0.21 0.18 101% 0.20 Springerville 1, AZ SO2 DFGD B&W 2004 0.84 0.77 0.60 0.57 0.25 5%Springerville 3, AZ SO2 Dry FGD - 2006 0.41 0.40 0.25 0.10 - 150% 2007H1 OPPD Nebraska City 2 SO2 Dry FGD 0.095 Plum Point SO2 Dry FGD 0.16 Holcomb Expansion SO2 Dry FGD 0.10 SO2 Controls - Wet Flue Gas Desulfurization (FGD - i.e., Wet Scrubber)Centralia 1, WA SO2 Wet FGD Alstom 2002 0.20 0.15 0.10 0.09 0.04 13% -- Craig 1, CO SO2 WFGD Alstom/Wheelabrator 2005 0.32 0.30 0.20 0.09 0.05 130%Craig 2, CO SO2 WFGD Alstom/Wheelabrator 2005 0.22 0.21 0.18 0.07 0.05 167%Laramie River 1, WY SO2 Wet FGD Research-Cottrell 1980 0.22 0.21 0.20 0.19 0.17 7% 0.20 Stanton 2, FL SO2 WFGD ABB-Alstom 1996 0.48 0.48 0.30 0.19 0.17 60%Paradise 1, KY SO2 WFGD GE/Marsulex 1983 n/a n/a n/a n/a n/a n/a Ozone season only:Navajo 1, AZ SO2 WFGD ABB/Alstom 1998 0.87 0.87 0.41 0.05 0.04 665%Big Stone 2 SO2 Wet FGD 0.10 JK Spruce 2 SO2 Wet FGD 0.06 PM ControlsHawthorne 5, MO PM FF B&W 2001 n/a n/a n/a n/a n/a n/a 0.018 Holcomb 1, KS PM FF Western Precip. 1983 n/a n/a n/a n/a n/a n/a 0.018 Bridgeport 3, CT PM ESP Research-Cottrell 1968 n/a n/a n/a n/a n/a n/a -- Colstrip 1, MT PM ESP -- -- n/a n/a n/a n/a n/a n/a 0.03 Laramie River 1, WY PM ESP B&W 1980 n/a n/a n/a n/a n/a n/a 0.10 Laramie River 3, WY PM ESP B&W 1982 n/a n/a n/a n/a n/a n/a 0.10 Springerville 3, AZ PM FF n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a OPPD Nebraska City 2 PM FF 0.018 Plum Point PM FF 0.018 Holcomb Expansion PM FF 0.012 Big Stone 2 PM ??? 0.03 JK Spruce 2 PM FF 0.022 

CEMS Data (lb/MBtu)