## Portland General Electric

Boardman Plant

Best Available Retrofit Technology (BART) Analysis

Black & Veatch Project: 144449 Black & Veatch File No.: 40.0000

November 2, 2007Boardman 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 Re trofit Emission Control Technologies (Step 1)................................................................................................................. 3-1
3.1 NO x 

### Control Technologies....................................................................... 3-1 3.1.1 Overfire Air System Operation ................................................. 3-1 3.1.2 Upgraded Low NO x 

### Burners ..................................................... 3-3 3.1.3 Upgraded Low NO x 

### Burners and Existing OFA System Operation ................................................................................... 3-4 3.1.4 Upgraded Low NO x 

### Burners and Existing OFA System Operation and Selective N on-Catalytic Reduction.................... 3-4
3.1.5 New Low NO x 

### Burners and Modified OFA System................. 3-5 3.1.6 New Low NOx Burners, Modified OFA, and Selective Non-Catalytic Reduction........................................................... 3-5Boardman Plant Contents

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### 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 NO x 

### Star and NO x 

### Star 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 SO 2 

### 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 Emissi on Control Technologies (Step 2) ............. 4-1 4.1 Technically Infeasible NO x 

### Control Technologies.................................. 4-1
4.1.1 Mobotec ROFA and ROTAMIX............................................... 4-1
4.1.2 NO x 

### Star and NO x 

### Star 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 SO 2 

### Control Technologies .................................. 4-3Boardman Plant Contents

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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 Feas ible 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 NO x 

### Control Technologies ...................................................... 6-10
6.4.2 SO 2 

### 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 SO 2 

### BART ........................................................................... 8-2Boardman Plant Contents

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### 8.3 Selection of NO X 

### 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 NO x 

### Control Technologies .................................... 4-5 Table 4-2 Technically Feasible SO 2 

### Control Technologies ..................................... 4-6 Table 4-3 Technically Feasible PM Control Technologies...................................... 4-7 Table 4-4 Technically Feasible Emergi ng Pollution Control Technologies ............ 4-8 Table 5-1 Highest Rolling 12 Mont h Data for Heat Input ....................................... 5-1
Table 5-2 NO x 

### Technologies Control Effectiveness ................................................ 5-2
Table 5-3 SO 2 

### 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 NO x 

### 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................... 3-9Boardman Plant Contents

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### Figure 3-4 Mobotec ROFA and ROTA MIX Simplified Process Flow Diagram (Mobotec USA)....................................................................... 3-12 Figure 3-5 ECOTUBE Insta llation 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 Syst em (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 Simplif ied 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 NO x 

### Control Cost-Effectiveness.............................................................. 6-7 Figure 6-2 SO 2 

### Control Cost-Effectiveness............................................................... 6-8 Figure 6-3 PM Control Cost-Effectiveness ............................................................... 6-9Boardman Plant Acronym List

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## 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 NO x 

### Burners
LNB/MOFA Low NO x 

### Burners with Modified Overfire Air
NLNB/MOFA/SNCR New Low NO x 

### Burners with Modified Overfire Air and Selective Noncatalytic Reduction
NLNB/MOFA/SCR New Low NO x 

### Burners with Modified Overfire Air and Selective Catalytic Reduction Mg(OH) 2 

### Magnesium Hydroxide MMBtu or MMBTU Million (10 6 

### ) British Thermal Units MW Megawatt
N 2 

### O 5 

### Nitrogen Pentoxide
NH 3 

### Ammonia
NO x 

### Nitrogen Oxides
OFA Overfire Air O&M Operating and Maintenance
PGE Portland General ElectricBoardman Plant Acronym List

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### 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
SO 2 

### Sulfur Dioxide VOC Volatile Organic Compounds WESP Wet Electrostatic Precipitator
WFGR Windbox Flue Gas RecirculationBoardman Plant Executive Summary

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## Executive Summary

The Boardman Plant is a 584 megawatt (M W) net pulverized coal fired steam electric plant of more than 250 million Br itish thermal unit (MMBTU) per hour heat input located near Boardman, Oregon, about 150 miles east of Portland. The plant was
issued its construction au thorization 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 es tablished a procedure for identifying those sources that must retrofit their existing facilities with BART and for determining what constitutes BART. The pur pose 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 sour ces within one of the enumer ated 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 (P GE) 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 contro l technologies for the reduction of nitrogen oxides (NO x 

### ), sulfur dioxide (SO 2 

### ), 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 NO x 

### , SO 2 

### , and PM retrofit control t echnologies were identified for the Boardman Plant. In Step 2, this list was shortened by eliminating those technologies that are not considered techni cally feasible. In Step 3, the control
effectiveness of each technical ly feasible control technology was evaluated and, based on this evaluation, the technologies were ranked in order of effec tiveness. In Step 4, the cost, energy, and environmental impacts were evaluated for each technically feasible control technology. In the final step, the visi bility improvements asso ciated 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

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### NO x 

### Control Selection After all of the statutory f actors were considered, the NO x 

### controls combination of
new low NO x 

### burners with modified overfire air and selective noncatalytic reduction (NLNB/MOFA/SNCR) was identified as the Best Available Retrofit Technology for NO x 

### control. This NO x 

### control combination results in significant modeled visibility improvement at the Class 1 areas for Boardman Plant impacts.
An alternative NO x 

### 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 considerati on as BART. The controls combination of new LNBs with modified OFA and SCR (N LNB/MOFA/SCR) would result in greater
NO x 

### reductions and slightly better mode led visibility improvements than NLNB/MOFA/SNCR. However, as EPA rec ognized in the 2005 preamble, the modeling system required for evaluating visibility impacts magnifies and overstates those impacts. Therefore, the small incremental improvement between the NO x 

### controls incorporating
SNCR and the NO x 

### controls incorporating SCR is not , by itself, determinative. In addition, the use of the NO x 

### controls incorporating SCR ha s other impacts that are more
severe than new LNBs with modified OFA system and SNCR. Specifically, the non-air quality environmental impacts (i.e., hazardo us material disposal during catalyst replacement) and the energy impacts (i.e., significant fan auxiliar y power to overcome additional system resistance) associated with NLNB/MOFA/SCR are higher than for
NLNB/MOFA/SNCR. The economic impacts also support se lecting NLNB/MOFA/SNCR as BART. The economic impacts associated with the NLNB/MOFA/SCR alternative are considerably higher than the economic imp acts associated with the NLNB/MOFA/SNCR alternative. The total capital cost of the NO x 

### controls incorporating SNCR is approximately $50 million while the total capital cost associated with the NO x 

### controls including SCR is approximately $223 million. Operating costs are similarly much higher
with the SCR alternative than the SNCR alternative ($5.7 m illion per year as opposed to $2.4 million per year). However, the visibili ty improvements associated with the NO x 

### controls incorporating SCR are not commen surate with the additional $173 million in capital cost (as compared to the NO x 

### controls incorporating SNCR). Even if the plant were assumed to operate at its highest dail y emission rate for every day of the year (something that never occu rs), the use of the NO x 

### control package with SCR as opposed to that with SNCR, would result in only 7 fewer days per year wh ere Mt Hood Wilderness Area visibility impacts exceeded 0.5 deciviews. The additional $173 million capital cost and $3.3 million per year of opera ting cost associated with the SCR controlBoardman Plant Executive Summary

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### package is not justified by the minimal benefit. This limited benefit carries across all of the Class I areas. The average 98 th 

### percentile impact level acros s 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 NO x 

### controls with SNCR to the NO x 

### 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 vi sibility associated with the NO x 

### 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 NO x 

### 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 NO x 

### 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 wh ere 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 thr oughout the year. The imposition of SCR as BART, on top of the $300 million in air poll ution control capital investments being proposed, could possibly require an investment in excess of what the plant can support.
Under such circumstances the EPA Guidelines st ate that it is appropriate to consider the non-affordability of SCR and to therefore conc lude 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 addi tional consideration lends further support to
the conclusion that BART for NO x 

### constitutes the control package with SNCR. From a design standpoint, since the Boardm an boiler was not designed with space in the ductwork or with an appropriate temp erature profile for utilization of SCR, very challenging and complex modifications to the bo iler 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 factor s strongly supports
NLNB/MOFA/SNCR as the best alternative.Boardman Plant Executive Summary

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### SO 2 

### 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 SO 2 

### control. The two top SO 2 

### control technologies (wet FGD and semidry FGD) were modeled as having essentially th e same level of visibility improvement at the Class I areas. However, the non-air qua lity environmental impacts and negative energy impacts are significantly greater for the wet FGD control technology, since it generates a visible plume, consumes more wa ter, generates a wastewater stream requiring treatment and disposal, generates slightly mo re solid byproducts for landfill, and because the wet FGD requires significantly more auxi liary 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 syst em would be consider ably higher with a total capital cost of approximately $382 milli on and operating costs of approximately $16 million per year. As a result, the cost eff ectiveness of the wet FGD control option is significantly higher than the range ($400 to $2000/ton) c onsidered to be reasonable in EPA’s BART guidelines. Give n that wet FGD does not perform materially better than semi-dry FGD, there is no basis for spendi ng 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
SO 2 

### control.

Particulate (PM) Control Selection After all of the statutory factors were cons idered, 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, s upports the choice of PJFF as BART.

Best Control Combination Selection The package of the selected controls (NLNB/MOFA/SNCR for NO x 

### and semi-dry FGD including PJFF for SO 2 

### and PM) constitutes BART for the Boardman Plant. This also constitutes the most effective packag e for integration with the controls beingBoardman Plant Executive Summary

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### designed for the Boardman Plant to meet th e 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 impr ovements are shown by the model from the use of a control package that includes S CR, these improvements are not considered significant. This conclusion was i ndependently verified in the draft Columbia River Gorge Air Quality Study Science Summary Report (September 27, 2 007) prepared by DEQ in conjunction with other state and fe deral governmental authorities. The report authors compared CRGNSA visibility as a re sult 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., comple te shutdown of the pl ant). As the report notes, “practically zero” addi tional visibility benefit is achieved by reducing plant emissions from those achieved by the propos ed BART control package all the way to zero plant emissions. That assessment serves as independent verification of the conclusion that no material visibility benefit w ould be gained by controlling NO x 

### 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 pack age, 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
NO x 

### control, there is no technically sound basi s for requiring SCR as part of the BART control package. PGE’s implementation of the suite of BART controls iden tified through this report will cost more than $297 million dollars to install and approximately $15 million per year to operate. While this poses a si gnificant economic impact to the Boardman Plant and to Northwest electric utility custom ers, 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 wo rst-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 suppor ting data for the BART analysis described in this report:Boardman Plant Executive Summary

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### • 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

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## 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 id entified as a BART source under the EPA’s Regional Haze Rules (40 CFR Part 51). Three pollutants: NO x 

### , SO 2 

### , and PM, were identified as having a potential impact on visi bility 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 generati ng 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 Nucl ear 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 stan dards. 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 SO 2 

### emissions, and the use of
LNB and OFA to reduce NO x 

### emissions.The Boardman Plant’s steam generator consists of a subcritical, opposed wallfired boiler that operates on bala nced 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 de tailed 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, fo r 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 on e of the enumerated source categories and that were in existence prior to August 7, 1977.Boardman Plant Introduction and Objectives

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### Although the Boardman Plant did go thr ough all the substantive new source review requirements of the 1977 Clean Air Ac t 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 BA RT 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 bi nding 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 Plan t 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

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### 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

SO 2 

### (Precombustion Controls - Coal Type) Low-sulfur coal

NO x 

### (Combustion Controls) LNB, OFA (1 st 

### 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 (NO x 

### , SO 2 

### , 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 NO x 

### , SO 2 

### , and PM at the BART source. The five steps followed to develop information fo r 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 t echnology appropriate for installation at the source. Each of these steps is further explained in the following
subsections.Boardman Plant Introduction and Objectives

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### 1.2.1 Identify All Available Retrof it 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 retr ofit if it has practical potential for application to the BART-eligible source. The technol ogy considered can be a method, system, or a combination of both options for control of a pollutant. Technologies that have been successfully a pplied to similar sources with similar gas
stream characteristics are considered availabl e. However, technologies that have not been applied to full scale operations are not considered available. Since the Boardman Plant is equipped with exis ting 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 feasibi lity. A control technology is technically feasible if it ha s been previously installed and operated successfully at a similar type of source or if there is t echnical agreement that the technology can be applied to the source. Two terms, availabl e and applicable, are used to define the technical feasibility of a control technol ogy. A technology that is being offered commercially by vendors or is in commercial de monstration or licensing is deemed an available technology. Technologi es that are in developmen t and testing stages are classified as not available. A commercially available technology is applicable if it has been previously installed and ope rated at a similar type of s ource, or a source with similar gas stream characteristics. Section 4.0 addr esses the requirements of Step 2 of the BART analysis.

1.2.3 Evaluate Control Effectiven ess of Remaining Control Technologies (Step 3) Once all the technically feasible contro l technology alternatives are identified in Step 2, the control effectiveness of each cont rol technology is evaluate d in Step 3, and the technologies are ranked. The control eff ectiveness 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 inpu t. Data for the control e ffectiveness of a technology were obtained by considering regulatory de cisions or evaluations that have been performed on the effectiveness of the technology. Other reference sources for control
effectiveness data are technol ogy performance data provided by manufacturers (usually in the form of performance guarantees), engineering estimates, and demonstratedBoardman Plant Introduction and Objectives

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### effectiveness of the technology at existing operating sources. The most stringent level of control demonstrated for each technology was us ed for its control effectiveness. For purposes of comparison, the technologies were ranked in order of effectiveness, from the
current controls to the most effective cont rol. Section 5.0 desc ribes the evaluations performed for Step 3 of the BART analysis.

1.2.4 Evaluate Impacts and Do cument 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 co ntrol 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 co sts 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 annua lized cost ($/year) is then divided by the estimated quantity of pollutant removed (t ons/year) to determine the cost-effectiveness ($/tons) of each control technology. Esta blishing cost-effectiveness allows the comparison of the different c ontrol 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 cont rol 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 cont rol technology to the next most stringent option. It has a unit of $/incremental ton re moved. 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 sy stem power consumption to overcome the additional system resistance (pre ssure loss) of the control te chnology in the flue gas flow path. The cost of these energy impacts includes additional fuel cost and/or the cost ofBoardman Plant Introduction and Objectives

110207 1-6 

### lost generation that would need to be pu rchased 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 envi ronmental impacts not relate d to air quality – either positive or negative. An example of a positiv e 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 capit al 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, particul arly for technologies that require a large capital expenditure.

1.2.5 Evaluate Visibili ty Impacts (Step 5) Potential visibility improvement from the addition of each control technology is determined from modeling results using th e CALPUFF dispersion modeling system. A modeling protocol has been developed in cons ultation with, and approval of, DEQ. Items
that were considered in the mode ling 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 98 th 

### percentile days at pre- and pos t-control emission rates.

1.2.6 Selecting the Best Alternative From the analyses performed in the fi ve steps described above, tables were prepared assessing the merits and demerits of the control technol ogy options, with the focus on the top-ranked technologies. These f actors were then evaluated to select the
best alternative.Boardman Plant Basis of Analysis

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## 2.0 Basis of Analysis

2.1 Design Basis
A detailed design basis was established fo r the Boardman Plant. The information in the design basis was used for equipment sizing, performance calculations, cost estimates (capital, operating, and maintenan ce), and estimating resources consumption, auxiliary power requirements, and byproduct di sposal. 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 desi gn basis was also established for two other coal cases: typical (Buckski n Mine) and maximum (Black Butte Mine). Performance
calculations were based on th e design basis coal.



## 2.2 Economic Data 2.2.1 Capital Cost Estimates Capital cost estimates were developed fo r retrofit control tec hnologies that were identified as technically feasible for the Boar dman 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 estima tes 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 comp arative purposes in the BART analysis. The capital cost estimates will be re fined throughout the upcoming preliminary engineering phase until actual equipment and constructi on contracts are procured. Direct costs consist of purchased equipmen t, installation, and mi scellaneous costs. The purchased equipment costs are the co sts for purchasing the control technology equipment from equipment vendors (including freight). An itemized list of major components of the direct capital cost is incl uded for each feasible control technology in Appendix D. The installation costs includ e construction costs fo r installing the new
controls and also take into account the retrof it difficulty that can be expected from the existing site configuration a nd 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

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### • Ample supply of craft labor and cons truction equipment is available.

• Normal lead-times for equipment deliveries are expected.
Indirect costs are costs th at 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 unpred ictable 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 cate gory are items such as possible redesign and equipment modifications, unforeseen weather-re lated delays, strikes and labor shortages, escalation increases in equipmen t costs, increases in labor co sts, 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 co sts. Some of the costs are not applicable to all of the evaluated technologi es but are representa tive 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, projec t 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 require d 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 pr ocedure and training of pers onnel 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 determin ed on a case-by-base basis from manufacturer recommendations and owner requirements.Boardman Plant Basis of Analysis

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### 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 num ber 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. Th e trend is concurrent with global competition for infrastructure improvements in China, India and the Third World. Most suppliers are at, or beyond, thei r resource capacity t oday and conditions are not expected to improve. Suppliers’ expect ations 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 ma rket 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 conduc ted after installation of the control technologies to validat e 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 pat h. The results of the performa nce tests are used to ensure compliance with performance guarantees and emissions limits.Boardman Plant Basis of Analysis

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### 2.2.2 Annual Operating and Maintenance Cost Estimate Annual operating and maintenance (O&M) co sts 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 cost s that do not vary
with these factors. Table 2-2 lists the ma jor 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 prep aration. Reagent costs are a function of the quantity of the reagent used and the mark et price of the reagent. The quantity of reagent used will vary with the qua ntity 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 evalua ted for the Boardman Plant. The power requirements of each system vary depending on the type of technology and the complexity of the system. El ectric power costs include incr eases in induced draft (ID) fan power consumption caused by the flue gas pressure losses through the new equipment.Boardman Plant Basis of Analysis

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### 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/m 3 

### 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 (t o annualize capital cost) 9.44% Allowance for Funds During Construction (AFDC) 8.99% Fully Loaded Operating Labor Cost, per person $100,000/yearBoardman Plant Basis of Analysis

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### 2.2.2.3 Makeup and Service Water Costs. Makeup water or service water is required for some of the control technology sy stems evaluated for the Boardman Plant. Examples of water consumption in control technologies include wa ter to support reagent preparation for limestone-forced oxidation or lime-based scrubbers, ammonia solution preparation from urea for SCR and selectiv e 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 qualit y. For the cost estimations, two types of water quality were considered: makeup and se rvice water. Dependi ng on the process, the appropriate water type was incl uded in this cost category. 2.2.2.4 Wastewater and By product Disposal Costs. Some control technologies generate wastewater and/or byproduct that will require trea tment and/or disposal. For example, a wet FGD system generates a bl owdown wastewater stream to regulate the
level of chlorides in the sl urry recirculation system. Also, a wet FGD system forms calcium sulfate and calcium sulfite byproduc ts when the limestone reacts with SO 2 

### . 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 ex isting ESP fly ash) are landfilled.

• All wet scrubber equipment effluent re quires wastewater treatment prior to being discharged to the environment.

• Ammonia-based NO x 

### reduction systems may affect the saleability of fly ash. However, for this analysis, the impacts were assumed to be minimal. 2.2.2.5 Operat ing Labor Costs. Operating labor costs are developed by estimating the number and type of employees that will be required to run the ne w 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 t echnology 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 Ma terials and Labor Costs. The annual maintenance materials and labor costs are estimated as a pe rcentage of the total equipment costs of the system. On the basis of typical utility i ndustry 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 exis ting technology at the plant site, a determination of the additional maintenance requirements was performed. If the required maintenance ma terials and labor are simila r to the existing technology, no
additional maintenance costs are incl uded for the new control technology.



## 2.3 Baseline Emissions
For this BART analysis, the baseline emissions for NO x 

### , SO 2 

### , and PM were established for the comparisons of the various control tec hnology options. The baseline
emissions established for the Boardman Pl ant are summarized in Table 2-3. The emission rates used represent the highest rolling 12 month tota l between 2003 and 2005.

Table 2-3 Baseline Emissions

Pollutant Emissions Data Source

0.426 lb/MMBTU 2003-2005 CEMS Data NO x 

### 10,348.8 ton/yr 2003-2005 CEMS Data

0.614 lb/MMBTU 2003-2005 CEMS Data SO 2 

### 14,901.8 ton/yr 2003-2005 CEMS Data

0.017 lb/MMBTU 2003-2005 CEMS Data PM 417.3 ton/yr 2003-2005 CEMS Data



## 2.4 Project Assumptions
In performing the BART analysis, severa l general assumptions were made to facilitate the conceptual design of the tec hnically feasible cont rol technologies. The following are key project assumptions:

• Plant availability will potentially be affected by the installation of new control equipment. However, any change s 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 assume d 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 th e 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, techno logy control effectiveness, and design parameters. The types of stack outle t data included are the following:

• Flue gas flow rate.

• Flue gas velocity.

• Flue gas temperature.

• Flue gas pressure.

• SO 2 

### emissions rate.

• NO x 

### emissions rate.

• PM emissions rate.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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## 3.0 Identification of All Available Retrofit Emission Control Technologies (Step 1)

In Step 1 of the BART analysis, all av ailable 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: NO x 

### , SO 2 

### and PM. Information on the working pr inciple, retrofit considerations, and advantages and disadvantages of each technology is also provided.



## 3.1 NO x 

## Control Technologies
The following NO x 

### control technologies were identifie d 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.

• NO x 

### Star and NO x 

### Star 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 th e burner zone, thereby enhancing the combustion staging effect and reducing NO x 

### emissions. Any resi dual 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 NO x 

### control, the performance from a given OFA system depends
on a number of factors. As the amount of OFA is increased, the stoichiometry in theIdentification 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 balan ce 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. Simila rly, 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, w ith rapid and complete mixing of the OFA with the boiler flue gases. Aggressively staging combustion to reduce NO x 

### emissions creates a reducing environment in the boiler and can damage the boiler waterwall tubes. The reducing
environment attacks the iron oxides in the t ube 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 re sulting in an increa se 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 ex isting OFA ports. However, because of extensive slagging issues and poor operability, these OFA ports are only opened on an asneeded basis. To overcome the slaggi ng problems when operating the OFA ports,
addition of a NO x 

### combustion controls system with monitors and installation of a water cannon system to replace the existing soot blower s 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 loca ting 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 eval uate the areas of reduced heat transfer in the furnace and provide an effective cleanin g procedure, using high- pressure water, to remove deposits while minimizing the therma l shock effects of temperature gradients created during the cleaning process.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### The systems use several heat flux sens ors 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 au tomatic and are controlled with a programmable microprocessor-based control system. The programmable control system communicates to the plant’s distributed contro l system (DCS) via a data link. Water for the cannons is typically supplied by the service water or the plan t’s cooling water system. A total boiler cleaning system incorporat ing sensors, soot blowers, water cannons, and intelligent algorithms for interpreting and optimizing cleaning systems can improve boiler performance and potentiall y increase boiler efficiency.

3.1.2 Upgraded Low NO x



### Burners

LNBs are available to control the formation and emission of NO x 

### through staged
combustion in the boiler. The basic NO x 

### 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 z one so that fuel devolatizat ion 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 in itial 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 mi nimize 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 molecu lar nitrogen, rather than be oxidized to
NO x 

### . Any nitrogen escaping the initial fuel-rich region has a greater opportunity to be
converted to NO x 

### as the combustion process is completed. The net result of staged combustion is usually longer and/or wider flam es 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 maximu m use of the available burner zone volume.
There have been advances in LNB tec hnology 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 NO x 

### reduction capability. In addition to these modifications, proper balance of fuel and air flow to the
burners is critical. The reduction in NO x 

### 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)

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### By balancing the fuel and air flows to the burners, an important step is achieved in controlling the flame characteristics and im proving 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 NO x 

### control system as opposed to individual burners. Low-load stability is also questionable w ith 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 fo r 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 balance d. 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 tim e data for tuning of the burners and maximizing perfor mance of the combustion system. Air flow systems measure primary air flow , bulk secondary air, total secondary air flow, and OFA flow distributi on. One specific system uses a derivative of the multipoint, self-averaging Pitot principle to measur e the total and static pressure components
of air flow. Pulverized fuel flow is dete rmined by measuring the mass flow distribution and transport velocity of the fuel in the pipe lines from the mill to the individual burners. The precise technology used for the measur ements varies depending on the specific
vendor. Air and coal monitoring equipment can be in tegrated 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 in dividual burner stoichiometry through a combination of manual tuning adjustments and automatic fuel flow and air flow adjustments.

3.1.3 Upgraded Low NO x



### Burners and Existing OFA System Operation

NO x 

### reduction can be increased by combining upgrades to the LNBs and operating the OFA system. These technologi es are described in Subsections 3.1.1
and 3.1.2.

3.1.4 Upgraded Low NO x



### 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 NO x 

### emissions. These technologies ar e 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)

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### 3.1.5 New Low NO x



### Burners and Modified OFA System

This alternative includes the additi on of new LNBs with modified OFA technologies close-coupled to provide an overall performance and emissions reduction better than those of the upgr aded 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 bur ners using rotating classifiers in the pulverizers; enhanced fu el 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 NO x 

### Burners and Overfire Air System

3.1.6 New Low NO x 

### Burners, Modified OFA, and Selective Non-Catalytic Reduction New LNBs, OFA, and SNCR technologies can be combined to provide an overall
reduction in NO x 

### emissions. These technologies ar e described in Subsections 3.1.5 and 3.1.8, respectively. When combined with ne w LNBs and OFA, the effectiveness of SNCRs at reducing NO x 

### is diminished to approximately 20 percent. 

## Overfire AirIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### 3.1.7 New Low NO x 

### Burners, Modified OFA, and Selective Catalytic Reduction The new LNBs and modified OFA syst em are described in Subsection 3.1.5. SCR systems are widely used for achi eving post-combustion reductions in NO x 

### emissions. In SCR systems, vaporized ammonia (NH 3 

### ) injected into the flue gas stream acts as a reducing agent, achieving NO x 

### emission reductions when passed over an appropriate amount of catalyst. The NO x 

### 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 NO x 

### reduction basis) and with low ammonia slip (unreacted ammonia). A simplified sc hematic diagram of a typical SCR reactor utilizing aqueous ammonia injection is illustrated on Figure 3-2. The SCR reactor is the housing for the ca talyst. 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 dire ction 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 economi zer and the inlet of the air heater. The high-dust system is typically the most economical and preferre d arrangement where physically possible. From a design standpoint, the SCR am monia-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 ex iting the boiler before entry to the air preheater is well in ex cess of 800o F. The Boardman bo iler was not designed with space in the ductwork or with an appropriate temp erature 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 orde r to properly dry the coal and maintain combustion efficiency. The costs of such modifi cations are expected to be substantial, up to approximately $40 million dollars.
The oxidation of SO 2 

### to SO 3 

### could also require moderate air heater modifications since the acid dew point temperature of the flue gas is directly related to SO 3 

### concentration. As the SO 3 

### concentration increases, the acid dew point of the flue gas increases, potentially increasing corrosi on in downstream equipment or possibly requiring an increase in the air h eater gas outlet temperature.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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 conversio n of urea to ammonia. Since the ammonia is vaporized prior to contact with the catalys t, the selection of am monia 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 interf acing system requirements to support operations. These requirements predominantl y relate to draft, auxiliary power, soot blowing steam, gas temperature, controls, ductw ork, reactor footprint, and air heater. The SCR system will affect the boiler draf t 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 modifi cations 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 th e 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 decr ease plant efficiency. The other potentialIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### danger for the air heater is high concentrations of SO 3 

### 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 condens e in the air heater and lead to pluggage and corrosion.
Several measures can be taken to avoid or co rrect this situation. Most important is the right composition of the cat alyst to minimize the SO 2 

### to SO 3 

### 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 bo iler. It can also er ode 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 NO x 

### reduction levels. This
results in an increased amount of ammonia s lip and ammonia bisulfate fouling of the air
heaters. For many units, the use of NLNB/MOFA al ong 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 ca n also be designed for an optimum SCR arrangement. On an exis ting unit however, the ab ility to install an “optimum” arrangement for an SCR is limited by the existing plant and unit specific
conditions and restrictions. SCRs as st ated 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 equipm ent (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 NO x 

### . The use of NLNB/MOFA howev er will minimize SCR out of
control conditions and reduce the amount of ammonia inje ction (not ammonia slip) while basically achieving the same outlet emission rate for the Boardman unit.

3.1.8 Selective Non catalytic Reduction SNCR systems reduce NO x 

### 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 re agent injection temperat ure, good reagent/gas mixing, and adequate reaction time to achieve NO x 

### reductions. SNCR systems can use either ammonia or urea as the reagent. A mmonia or urea is injected into areas of the steam generator where the flue gas temp erature ranges from 1,500 to 2,200° F. The furnace of a pulverized coal fired boiler ope rates at temperatures between 2,500 to 3,000° F.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### SNCR systems are capable of achieving a NO x 

### emissions reduction as high as 50 to 60 percent in optimum conditions (adequate reaction time, temperature, and reagent/ flue gas mixing, high baseline NO x 

### conditions, multiple levels of injectors) with ammonia slips of 10 to 50 ppmvd. Lower ammonia s lip values can be achieved with lower NO x 

### reduction capabilities. Typicall y, 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 vari es with fuel type, steam generator size, allowable ammonia slip, furnace CO concentrat ions, and steam generator heat transfer
characteristics. SNCR systems reduce NO x 

### 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 NO x 

### emissions, while, at worst, the oxidation of ammonia can actually generate NO x 

### . Accordingly, NO x 

### reductions and overall reaction stoichiometry are very sensitive to the temperat ure 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 NO x 

### 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 timesIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### (in excess of 1 second) in the opt imum temperature range (1500 to 2200 o 

### F). For an existing boiler, waterwall and steam pipi ng modifications would be necessary to accommodate the installation of SNCR reagent inj ectors. Multiple levels of steam-cooled reagent injectors or lances would be require d. For existing boilers, the convection pass is very congested for optimum SNCR system operation. Without extensive modifications,
this could lead to limited NO x 

### 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 compone nts and operating characteristics of both SNCR and SCR systems. Hybrid syst ems were developed to combine the low capital cost and high ammonia slip associ ated with SNCR systems with the high reduction n potential and low ammo nia slip inherent in the catalyst of SCR systems. The
result is a NO x 

### reduction alternative that can meet initially low NO x 

### 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 ope ration, the SNCR system would be allowed to inject higher amounts of reagent into the fl ue gas. This increased reagent flow has a
twofold effect: NO x 

### reduction within the boiler is increased while ammonia slip also increases. The ammonia that slips from th e SNCR is then used as the reagent for the catalyst. There are two design philosophies for usi ng this excess ammonia slip. The most conservative hybrid systems use the catalyst si mply as an ammonia slip “scrubber” with
some additional NO x 

### reduction. As with in-duct systems, the flue gas velocity through the catalyst is an important factor in desi gn. Operating in this mode allows maximum
NO x 

### reduction within the boiler by the SNCR, while minimizing the catalyst volume requirement. While some NO x 

### 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 phi losophy uses adequate catalyst volume to obtain significant levels of additional NO x 

### reduction. The addi tional reduction is a function of the quantity of ammonia slip, cata lyst volume, and distri bution of ammonia to
NO x 

### within the flue gas. Using ammonia slip produced by the SNCR system is not a high efficiency method of introducing reagent, becau se of the low reagent utilization discussed as a part of the SNCR. Therefore, even though the reaction at the catalyst requires 1 ppmIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### of ammonia to remove 1 ppm of NO x 

### , the SNCR must inject at least 3 ppm of ammonia to generate 1 ppm of a mmonia at the catalyst. Catalyst volume is strongly influenced by the NO x 

### 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 veloci ty are required, some modificati ons will be required to the existing ductwork. If widening the ductwork cannot provide adequa te catalyst volume, then a separate reactor is required, which quick ly 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 su ch, 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 ex iting the boiler before entry to the air preheater is well in ex cess of 800o F. The Boardman boiler was not designed with space in the ductwork or with an appropriate temp erature 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 orde r to properly dry the coal and maintain combustion efficiency. The costs of such modi fications are expected to be substantial, negating the capital cost a dvantage of a hybrid system.

3.1.10 Mobotec ROFA and ROTAMIX Mobotec provides a NO x 

### 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 NO x 

### reduction because of a homogeneous temperature profile in the boiler. A simplified proce ss flow diagram of the ROFA and ROTAMIX system is illustrated on Figure 3-4.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### Figure 3-4 Mobotec ROFA and ROTAMIX Simplified Pr ocess Flow Diagram (Mobotec USA).

3.1.11 NO x 

### Star and NO x 

### Star Plus

NO x 

### Star is the trademarked name for a NO x 

### 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 NO x 

### . The ammonia reduces
NO x 

### through an SNCR reaction with the hy drocarbon; this reaction minimizes the ammonia slip. This arrangement enable s higher reagent injection rates for NO x 

### reductions than achievable with a typical SNCR technology. The technology supplier claims the ability to achieve NO x 

### emissions of less than 0.20 lb/MMBTU without the use of a catalyst and large SCR reactor. Although initially targeting high NO x 

### reductions, full
scale demonstrations to date have been limited to nominally 50 percent NO x 

### reduction performance.
NO x 

### Star 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 h azardous solid waste. The other advantage of the NO x 

### Star system is that the conversion of SO 2 

### to SO 3 

### is said to be negligible, thus eliminating one of the main drawbacks of the SCR technology. The major consideration for the NO x 

### Star 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 (NO x 

### Star Plus) to achieve the advertised levels of NO x 

### 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 a nd inject high-velocity air as well as reagents. The lanceIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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 pr ocesses are combined in this technology. ECOTUBE is capable of reducing NO x 

### , while improving thermal efficiency, by optimizing the combustion pr ocess in boilers. An illustration of the ECOTUBE installation in a typical boile r is shown on Figure 3-5.
The water-cooled ECOTUBEs are automati cally 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 te rms of furnace combustion improvements that increase efficiency, reduce fuel usage, and reduce corrosion and eros ion 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 combusti on air is a proven me thod for controlling
NO x 

### production from gas-fired utility boile rs. 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 NO x 

### formation by reducing peak flame temperatures. In conventional applications, the recirculated flue gas is typically extr acted from the boiler outlet duct upstream of the air heater. The fl ue gas is then returned through a separate duct and hot gas fan to the combustion air duc t that feeds the windbox. The recirculated flue gas is mixed with the com bustion air via air foils or othe r mixing devices in the duct. This technology is known as windbox FG R (WFGR). WFGR systems require installation of a separate hot gas FGR fan to move flue gas from the boiler exit to the airIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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 a ppropriate mixing devices.

3.1.14 LoTOx The LoTOx technology is the low te mperature gas-phase oxidation of NO x 

### by ozone injection. In this met hod, ozone is injected into th e flue gas upstream of a wet FGD system. The ozone reacts with the NO and NO 2 

### to form nitrogen pentoxide (N 2 

### O 5 

### ).
The N 2 

### O 5 

### 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 Abi tibi Consolidated (She ldon, 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 ha ve been several refinery applications. The LoTOx technology offers high NO x 

### removal efficiency with a reported potential of 15 to 25 percent savings in cap ital cost over an SCR system. The major drawbacks of this system ar e 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 produc tion from this technology is captured in the FGD waste product, possibly requiring the need for a wa stewater treatment plant.

3.1.15 Natural Gas Reburn The natural gas reburning process employs three separate combustion zones to
reduce NO x 

### 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 ex cess air (a 1:10 stoichiometric ratio). A second combustion zone (the reburn zone) is created above th e 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 corro sion (especially with higher sulfur fuels) becaus e of the reducing atmosphere in the lower furnace.
The substoichiometric reburn zone causes NO x 

### produced in the lower furnace units to be reduced to molecular nitrogen and oxygen because the oxygen stripped from
the NO x 

### molecules is combined with the mo re 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 isIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

110207 3-15 

### introduced to complete combustion of the unbur ned materials in the upper furnace with
an overall excess air rate for the boiler of 15 to 20 percent. Reburn technology has
demonstrated NO x 

### reduction of 40 to 65 percent. Sufficient residence time (adequate furn ace height) in the reburn and OFA zones is a key factor in determining whethe r the reburning technology can be applied. Successful retrofit of this technology requi res 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 opera ting costs of this technology prohibitive.



### Burnout Zone •Normal Excess Air

Reburning Zone •Slightly Fuel Rich •NOx Reduced to N 2



### 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

NO x 

### reduction can be increased by comb ining new LNBs, modified OFA, and SNCR. The new LNBs, modifi ed OFA, and SNCR are descri bed in Subsections 3.1.5
and 3.1.11.



## 3.2 SO 2 

## Control Technologies
The following SO 2 

### control technologies were identifie d as available for retrofit at
the Boardman Plant are summarized in Subsections 3.2.1 through 3.2.4:

• Wet FGD.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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 system s 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 FG D systems are also applicable for units burning low-sulfur bituminous and subbituminous coals. Wet limestone FGD systems are capable of achieving slightly higher SO 2 

### removal than other types of FGD systems but have not demonstrated significant rem oval of elemental mercury. A typical wet limestone FGD system consists of reagent storage and handling system, FGD spray tower absorber, and byproduct dewatering sy stem as illustrated on Figure 3-7.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

110207 3-17 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 applicati ons, 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 cont acted with a slurry containing reagent and byproduct solids. The SO 2 

### is absorbed into the slurry a nd reacts with the calcium to form
CaSO 3 

### • 1/2H 2 

### O and CaSO 4 

### • 2H 2 

### O. There are several types of absorber modules, and each has characteristic advantages and disadvantages. FGD equipmen t 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 re action tank, as illustra ted on Figure 3-8. Regardless of theIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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 moistu re plume. Generally, wet FGD systems do not remove significant quantities of SO 3 

### from the flue gas. Condensed SO 3 

### , in the form of sulfuric acid mist (H 2 

### SO 4 

### ), 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 duc twork and for the stack flue. Careful design of the stack is needed to prevent “rainout” from conde nsation that oc curs in the
downstream ductwork and stack.The reaction byproducts are typically dewatered by a combination of hydrocyclones and vacuum filters. For natura l oxidation wet limestone FGD systems, the resulting filter cake is suitable for landfil l disposal. In some instances, the FGD byproduct requires mixing with fly ash and/or lime (fixation) to produce a physically
stable material.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### If air is bubbled through the reacti on tank, practically all of the CaSO 3 

### • 1/2H 2 

### O
can be converted to CaSO 4 

### • 2H 2 

### O, which is commonly known as gypsum. This oxidation step is termed “forced oxidation.” Compar ed to calcium sulfite, gypsum has much superior dewatering and physic al properties, and forced-oxi dized systems tend to have few scaling problems in the absorber and mi st 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 fabricat ed from corrosion-resistant materials such as epoxy/vinylester-lined carbon st eel, rubber-lined carbon stee l, stainless steel, or fiberglass. The absorbers handle large volum es of abrasive slurries. The reagent handling and byproduct dewatering equipment is al so relatively complex and expensive. These factors result in relatively higher in itial 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 eith er 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 pr ocess, 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. Fo r new plants, the SDA absorber vessel is located between the air heater and the par ticulate removal device, most commonly a PJFF. For the Boardman Plant, the SDA ab sorber vessel and PJ FF 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 SD A 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 reagen t slurry is injected into the absorber using either a rotary or dual-fluid atomi zer, where the lime reacts with the SO 2 

### in the flue gas. Sufficient water is added to the reagent slurry to lower the flue gas temperature to withinIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### 32 to 40°F of the adiabatic saturation temperature. The SO 2 

### 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 c ontaining the byproduct solids and excess reagent. As the reagent slurry eva porates, 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. Th e PJFF is an integral component of the SO 2 

### 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 pneum atically to the fly ash silo in the
conventional manner. These solids are unloade d, conditioned with water, and transported
to a landfill. Because of the level of fr ee 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.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### Figure 3-10 SDA FGD System

3.2.3 Circulating Dry Scrubber CDS is a form of dry FGD for SO 2 

### 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 SO 2 

### by the lime. A schematic of the process flow of a CDS process is shown on Figure 3-11. Generally, there are no cons traints on the maximum fuel sulfur content; the CDS can be adjusted to account for the higher SO 2 

### loading by increasing the concentration of reagent. However, this flexibility is lim ited by the cost of th e lime reagent. An evaluation on the overall reagent cost is impor tant before selecting this technology. Lime utilization is improved by cooli ng the flue gas before it reacts with the lime. Flue gas coming into the scrubber vesse l is cooled to about 30 o 

### F above the adiabatic saturation temperature.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

110207 3-22 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 remova l of PM from the ash in the coal and the product of the reaction of lime with the SO 2 

### in the flue gas. Because of the relatively high velocity of the flue gas through the scrubber vessel (approxi mately 19 ft/s), the treated flue gas carries entrained reagent and reaction pr oducts 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 pa rticles in the flue gas as well as material handling dynamics, the “shell” of reaction products on the reagen t particles is broken up. This material is recycled into the scrubber vessel to further im prove lime utilization. This
solids recirculation also main tains the bed densities needed for contact and removal of
SO 2 

### . 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 vesse l. This arrangement results in a smaller footprint for applications with space constr aints. However, depending on the site situation, the retrofit of such a system might be costly, es pecially if ther e are substantial
construction and structural difficulties. Disadvantages of this pro cess include high dust loading at the particulate removal system and lack of US utility operating ex perience in the size range of the BoardmanIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### Plant. Higher FF pressure drops are encount ered because of the flue gas dust loading, thus ESPs are preferred for particulate rem oval. The high particulate loadings make sizing of the ESP critical to ensure complian ce 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 SO 2 

### . This technology is typically capable of removing between 20 to 50 percent of the SO 2 

### 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 r eaction, temperature, percenta ge reduction rate, and the corresponding retention time requirements, a dry reagent such as powdered lime and hydrated lime are preferred for furnace injecti on 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 requi rements and the flue gas properties. The use of a wet reagent for duct injecti on is preferred over a dry reagent because of the elevated gas temperat ures that exist during normal operating conditions. The use of a wet reagent upstream of an existing E SP will help reduce the gas temperature, improve ESP performance for opacity and partic ulate 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 SO 2 

### 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 deve lop precise injection locations and reagent injection characteristics for each boiler. The major components of a typical reag ent 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 be nefits of various efficiency improvements include savings through greater heat transfer cleanliness, reduction of periodic air heater replacement, increase in overall unit reliab ility, reduction of boiler cleaning costs, and, ultimately, the extension of unit runs to the po int where only scheduled outages are taken.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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## 3.3 PM Control Technologies
The following PM control technologies were identified as availabl e 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 Oper ational 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 slight ly 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 pa sses through to remove the particulate. Reduced particulate emissions limits and the se lection 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 maintenan ce 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 clea ning 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.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### Figure 3-12 Pulse Jet Fabric Filter Comp artment (Babco ck & Wilcox)Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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 ba g, 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 in itiating 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 minimi zed so that particulate is not re-entrained during the cleaning process. The PJFF cleans ba gs 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 standa rd feature of the technology.

3.3.3 Compact Hybrid Particulate Collector Another control technology that is effec tive 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 trademarke d 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 ope rates at A/C ratios of about 4 ft/min. The majority of the particulate is collect ed 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 wi th less steel and filtration media, which substantially lowers both capital and opera ting costs compared to conventional FFs.

3.3.4 GE MAX-9 Hybrid The Max-9 electrostatic filter is a hybrid co mbination of a high-efficiency PJFF and an ESP without collecting plates. A front and si de elevation view of the Max-9 particulate filter is illustrated on Figure 3- 13. When the dust particles ar e charged, they are attracted to the grounded metal cage inside the filter elem ent, 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 th e surface of the filter, maki ng 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.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### Figure 3-13 Max-9 Electrostatic FilterIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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 pul ses 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 throug h 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 da nger of fire caused by sparking, and the transformer/rectifie r requires no voltage control. The Max-9 can be supplied as shop-asse mbled modules that can be erected on site, although the units are usua lly 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 paralle l 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 vorte x and an ascending inner vorte x. Multiclones are more efficient than single cyclones because they are l onger 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 dus t particulates. The pressure drop of multiclone collectors is higher than that of single-cyclone separators. Cyclone collectors are centrifugal collector s 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 as h to the edge of the cylinder. The flue gas then exits the center of the cyclone out the top, leaving the fl y 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 micr ons in size; particles less than 10 microns are usually unaffected and not removed.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### Figure 3-14 Multiple-Cyclone Particulate Collector

3.3.6 Wet ESP A WESP collects particles on the same theore tical basis as a dr y ESP: negatively charged particles are collected on positively charged surfaces. The collecting surfaces are wet instead of dry and are flushed with wa ter 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 wate r is minimized. The particulate collection efficiency is enhanced by a lack of re-ent rainment after contact with the wet walls (as contrasted with re-entrainment due to rappi ng on a dry ESP). Therefore, the WESP is well suited for fine particulate or acid mi st applications becau se it reduces opacity, sulfuric acid mist (H 2 

### SO 4 

### ), 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 indus trial installations. The pa rticulate char acteristics, temperature, and humidity in WESPs provi de excellent fuel flexibility regarding particulate removal. However, water chemis try, scaling, and corrosi on potential need to be carefully investigated. The WESP collecting fields impart a negati ve 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 cont roller. The controllers for each transformer/rectifier are located in an environmentally controlled enclos ure. Each electrical field has a separate discharge electrode support frame suspended by alumina insulators. A heater-blower system dedicated to each module supplies wa rm purge air for each of the insulator compartments. The discharge electrode s upport frames are constructed from Type 304Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### stainless steel. The discha rge electrodes are suspended fr om the upper guide frame and
held in the tube center line. The discharge electrode is a ri gid electrode constructed from 304 stainless steel; it contains split corona-generating el ements 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 si milar to a common dry ESP. The collection plates are arranged in parallel horizontal pa ths with discharge elec trodes hanging between them. Vertical gas flow WE SPs 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 installe d to add water to the flue gas to reduce the flue gas temperature to the sa turation point or the WESP must be installed downstream of an existing wet FGD system. Without the pr esence 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 re moved particulate would be contained in a wastewater stream that is generated by the WE SP. In addition to th is issue, the capital cost of a WESP is high compared to other tech nologies because of the higher cost of the alloy materials required for the WESP. Hi gher grades of materi al are required to withstand the highly corrosive conditions presen ted by the wet and acidic flue gas stream
that will be collected in th e wastewater stream. Altern atively, addition of alkaline reagents can be used to neutralize th e acid in the wastewater stream. Each WESP module is cleaned by sp raying flush water over the WESP components. Flush water is sprayed in th e WESP at different sp ray levels. It is anticipated that each WESP m odule will be flushed once per day. Individual electrical sections of each field may be flushed online whil e 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 su lfuric 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 forma tion within the module. The dispersant canIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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-servi ce 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 solv ent 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 PowerSpa n 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 p ilot testing as the ot hers. 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 generate s high energy electrons. The
electrons initiate a chemi cal reaction that forms oxygen and hydroxyl radicals, which
then oxidize NO x 

### , SO 2 

### , and mercury. This reaction results in the formation of nitric acid, sulfuric acid, and mercuric oxides. A pro cess 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 downstr eam WESP. Scrubber effluents contain
dissolved ammonium sulfate nitrate (ASN) salts along with solids and mercury. The
ASN solution is sent to a re covery 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 sa leable fertilizer.Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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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 pr ocess, mercury is oxi dized via ultraviolet lights. The ultraviolet lights are placed in the ductwork upstream of the particulate
control device. Photochemical oxidation techno logy is in its infancy stage, as are most mercury reduction technologies. The ECO system is under pilo t testing at FirstEnergy’s 50 MW Burger Plant and has achieved 82, 99, and 85 percent reduction for NO x 

### , SO 2 

### , 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 cap able of removing significant amounts of elemen tal and oxidized mercury, NO x 

### , PM 2.5 

### , and SO 2 

### . 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 wher e the oxidation and adso rption of mercury takes place. Other pollutants, such as SO 2 

### and NO x 

### , are also adsorbed by the Pahlmanite sorbent at this stage. The SDA byproducts ar e then separated from the flue gas in the PJFF. The fly ash and waste byproduct co llected in the PJFF hopper is eventuallyIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### transported to a slurry tank for subsequent Pahlmanite sorbent regeneration in a reactor. A process flow diagram of the Pahlma n 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 regenerati on, and byproduct separa tion. Currently, Enviroscrub is performing slip-stream pilot te sting using third-party contractors, and the initial results are encourag ing (Hammel, Charlie; Envi roscrub 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 NO x 

### and SO 2 

### emissions when coal is burned. The only reagent requ ired for pollution cont rol 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 chemi cals in coal to complete their combustion reactions (to reach equilibrium conditions).Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### The coal, with limestone added as a sour ce of calcium for sulfur capture, is pulverized and introduced to the burner al ong with a limited amount of hot combustion air. The initial high-temperature combustion ga sifies 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 (H 2 

### O). Nitrogen compounds that may form, such as NO x 

### , hydrogen cyanide, and ammonium, are simply forced to the molecular form (N 2 

### ) 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 H 2 

### and nearly free of NO x 

### 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 CO 2 

### and H 2 

### to water. This action prevents the formation of any new (thermal)
NO x 

### and completes the combustion with excess ai r. 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 DiagramIdentification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### Retrofits require an annual outage period with a 2 to 3 week extension. The CCS retrofit modification requires replacing th e existing pulverized coal burners with new down-fired CCS burners and adding separate d 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 a pplication 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 f acilities 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 Unite d States by J-POWER EnTech, Inc. The J-POWER ReACT system consists of an AC process that involves three steps: (1) adsorption, (2) rege neration, and (3) byproduct recovery

. 

### Figure 3-18 illustrates the J-POWER ReACT System. The process consists of an adsorber 2 

### located after the primary particulate control devices an d a sorbent regenerator. In the adsorber, the flue gas passes through a be d 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. SO 2 

### , SO 3 

### , NO x 

### , mercury, and additional pa rticulates (along with associated trace metals) are removed in the adsorber in one step, and the pollutant saturated AC is regenerated in the regene rator, 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 (N 2 

### ), SO 2 

### , and water. Mercury is retained in the AC and removed from the unit every few years, depending on the mercury con centrations 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 mate rial. Because ReACT relies on adso rption of mercury onto activated coke, its reaction vessel is termed an “adsorber.” “Abs orption” 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 SO 2 in an alkaline liquid in a wet spray tower, and its reaction vessel is termed an “absorber.”Identification of All Available Retrofit Boardman Plant Emission Control Techniques (Step 1)

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### mechanically degraded AC and captured dust; th en, 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, su ch as dioxin adsorbent. SO 2 

### -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 re duced adsorber size and coke attrition. Consequently, they have reduced the capital cost, coke replacement cost, and required footprint. Lastly, slipstream testing has demonstrat ed 90 percent mercury removal with the ReACT system. An EPRI slipstream test of the technology is currently under way at North Valmy Station. The Re ACT 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 technolog y was not considered to be technically feasible for application at the Boardman Plant and was not evaluated further.Technically Feasible Retrofit Emission Boardman Plant Control Techniques (Step 2)

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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 eliminatin g technically infeasible options. In order for a technology identified in Step 1 to be include d in the list of te chnically 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 av ailable if it has reac hed the licensing and commercial sales stage of development. Fo r 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 ba sis for concluding that a technology is applicable, and, therefore, tec hnically feasible. That techno logy must have been used in the same or a substantially similar sour ce type to be considered applicable. For all the technologies identified as avai lable in Section 3.0, a determination was made on the technical feasibility of the tec hnology at the Boardman Plant site according to the evaluative process identified by the EPA.



## 4.1 Technically Infeasible NO x 

## Control Technologies

4.1.1 Mobotec ROFA and ROTAMIX Mobotec’s ROTAMIX technology is not co nsidered as technically feasible because there are no current installations at pu lverized coal fired boilers of equivalent
size to the Boardman Plant. The ROFA technol ogy is a variant of the OFA system that is already being considered in this BART analysis. Theref ore, to avoid duplication of technologies, it was not ev aluated independently.

4.1.2 NO x



### Star and NO x



### Star Plus

The NO x 

### Star technology is dependent on usin g natural gas as a reaction catalyst
for NO x 

### 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.Technically Feasible Retrofit Emission Boardman Plant Control Techniques (Step 2)

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### 4.1.3 ECOTUBE Since most of the existing installa tions of the ECOTUBE system are on
industrial/small-sized boilers fi ring solid waste, wood, or biomass, this technology is not technically feasible for the size ra nge 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 boile rs, such as oil or na tural gas boilers. Therefore, IFGR is not technically feasible.

4.1.5 LoTOx The LoTOx system has only been demons trated on small-sized medical waste
combustors. It is therefore consider ed as not technically feasible.

4.1.6 Natural Gas Reburn Natural gas reburn in the Boardman Pl ant boiler is not technically feasible because of a lack of sufficient furnace heig ht (i.e., inadequate residence time for NO x 

### reduction) and because of the absence of a natu ral 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 su ch, 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 ex iting the boiler before entry to the air preheater is well in ex cess of 800o F. The Boardman boiler was not designed with space in the ductwork or with an appropriate temp erature profile for a future SCR. Since the SCR catalyst cannot be located in the existing ductwork wit hout significant modifications to the boiler to lower the gas path temperatur e to the desired range while still maintaining the air temperature exiting the air preheater to the pulverizer in orde r to properly dry the coal and maintain combustion efficiency, th e SNCR/SCR hybrid system was considered as not technically feasible.Technically Feasible Retrofit Emission Boardman Plant Control Techniques (Step 2)

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## 4.2 Technically Infeasible SO 2 

## Control Technologies 4.2.1 Dry Flue Gas Desulfurization Dry FGD using a CDS or similar technol ogy has been applied only to boilers rated up to a maximum of 300 MW. Furthermor e, most applications of this technology are typically on circulating fluidized bed boile rs and not pulverized coal boilers such as
the boiler at the Boardman Plant. Therefor e, this technology wa s considered as not technically feasible.

4.2.2 Furnace/Duct Reagent Injection Furnace or duct reagent injection is consid ered 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 Infeasibl e PM Control Technologies 4.3.1 GE MAX-9 Hybrid Current demonstrated GE MAX-9 Hybrid in stallations 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 mu ltiple-cyclone collectors in reducing PM emissions, this technology is not capable of controlling PM emissions better than the currently existing ESP. Ther efore, 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 co al burning facility or in a facility similar in size to the Boardman Plant. Therefore, the PowerS pan ECO system was not considered as technically feasible.Technically Feasible Retrofit Emission Boardman Plant Control Techniques (Step 2)

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### 4.4.2 Enviroscrub The Enviroscrub technology is currently in pilot-scale testing, and there are no current developments in full-scale impl ementation. 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 impl ementations. 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 pro cess is detailed in Tables 4-1 to 4-4.
Also included in the tables are the reasons fo r the technical infeasibility of the eliminated control technologies.Technically Feasible Retrofit EmissionBoardman PlantControl Techniques (Step 2)1102074-5Table 4-1Technically Feasible NOxControl TechnologiesPollutant TechnologyTechnicallyFeasible andApplicable? Reasons forTechnical InfeasibilityNOxExisting OFA system operation Yes --Upgraded LNBs Yes --Upgraded LNBs with existing OFA systemoperationYes --Upgraded LNBs with existing OFA systemoperation and SNCRYes --New LNBs and modified OFA system Yes --New LNBs with modified OFA system andSNCRYes --New LNBs with modified OFA system andSCRYes --SNCR Yes --SNCR/SCR hybrid (Cascade) No Not technicallyfeasible to install catalyst withinexisting ductwork.Mobotec ROFA and ROTAMIX No ROTAMIXnot demonstrated on Boardman sizedboilers. ROFA system is in the same category as OFAsystem.NOxStar and NOxStar Plus No No existing natural gas pipeline to Boardman site.ECOTUBE No No existing installation at similar type/size source.Induced flue gas recirculation (IFGR) No Applicable to low nitrogen content fuel fired boilersonly.Technically Feasible Retrofit EmissionBoardman PlantControl Techniques (Step 2)1102074-6Table 4-1Technically Feasible NOxControl TechnologiesPollutant TechnologyTechnicallyFeasible andApplicable? Reasons forTechnical InfeasibilityLoTOx No Not commercially available.Natural Gas Reburn No No existing natural gas pipeline to Boardman site.Table 4-2Technically Feasible SO2Control TechnologiesPollutant TechnologyTechnicallyFeasible andApplicable? Reasons forTechnical InfeasibilitySO2Wet FGD Yes --Semi-Dry FGD (SDA/FF) Yes --Dry FGD (CDS) No No installation at unit larger than 300 MW.Furnace/Duct Reagent Injection No No existing installation at similar type/size source.Technically Feasible Retrofit EmissionBoardman PlantControl Techniques (Step 2)1102074-7Table 4-3Technically Feasible PM Control TechnologiesPollutant TechnologyTechnicallyFeasible andApplicable? Reasons for Technical InfeasibilityPM Existing ESP with operational restrictions(1)Yes --PJFF Yes --COHPAC Yes --GE MAX-9 Hybrid No No commercialinstallation at similar sized source.Multiple-cyclone collector No Level of emissions control is less effective thancurrently existing ESP.WESP Yes --Notes:(1)Existing ESP with operational restrictions isestimated to have similar impact analysisand cost-effectiveness results as existingESP, therefore it will not be evaluated in those sections.Technically Feasible Retrofit EmissionBoardman PlantControl Techniques (Step 2)1102074-8Table 4-4Technically Feasible EmergingPollution Control TechnologiesPollutant Philosophy TechnologyTechnicallyFeasible andApplicable? Reasons for Technical InfeasibilityMulti-Pollutants Control technologies PowerSpan No No commercial installation at similarsized source.Enviroscrub No No commercial installation at similarsized source.Phenix Clean Coal No No commercial installation at similarsized source.J-Power ReACT No Currently in slipstream testing forevaluation before commercialinstallations in North America.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 eff ectiveness so that they could be ranked.



## 5.1 Control Effectiveness
The evaluation process in Step 3 determ ined the control effectiveness of each control technology. The control effectiveness was expre ssed 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 da ta for heat input are summarized in
Table 5-1. The control effectiveness wa s 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)

NO x 

### September 2003 48,630,688.4

SO 2 

### August 2005 48,571,330.3
PM March 2004 49,093,487.4

Tables 5-2 to 5-4 identify the baseline emissions and th e control effectiveness for each control technology. The tables show th e control technology rankings from baseline
to the most effective control. The cont rol 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 NO x 

### 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 SO 2 

### 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 2,429Evaluation 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 va lues 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 an alyses 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 th e choice of the best re trofit 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 wa s identified as technically feasible. The design parameters contain all pertinent info rmation on the contro l 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 c ontrol 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 t echnology that has been identified as technically feasible for application at the Boardman Plant site are summarized in the Design Concept Definition sheets, whic h 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 identif ied 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 cont rol technology that has consumption of auxiliary energy during its operation. Only direct energy impacts for each control technology, such as the auxiliary power cons umption 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 fo r. 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 c onsumption 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 de sign parameter of each control technology. Between the two top-ranked control technologies for NO x 

### 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 SO 2 

### 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 Environm ental Quality Commission adopted among the most stringent restrictions on mercury from co al fired power plants in the country. TheBoardman Plant Impact Analysis (Step 4)

110207 6-3 

### stated purpose of these restri ctions was to decrease the am ount of mercury in bodies of water. PGE is currently investigating controls to greatly enhance co llection of mercury in the Boardman Plant exhaust gases to ensure compliance with these requirements. Certain BART control technologies also enhance the ab ility 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 contro l 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 NO x 

### , the new LNBs with modified OFA system and SCR have higher n on-air quality environmental impacts than the new LNBs with modified OFA system a nd SNCR. SCR catalysts must be replaced approximately every 3 years, thus creati ng 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 c ontrol technologies for SO 2 

### , 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 e nhanced 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 capit al 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 re maining useful life of the controls was defined as 20 years, and the remaining usef ul life of the source was defined as longer than 20 years. These assumptions could obvi ously 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 f actor. If the ultimate BART determination were to vary materially from the conclusions st ated in this report, th is 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 reduce d. The cost-effectiveness is described as the cost of control per amount of emissi ons removed. The emissions reduced are
estimated on an annual basis based on the re duction from baseline emissions. Both the baseline emissions and post-control emissi ons values are documented in the Design Concept Definition sheets located in Appendix C. Two types of cost-effectiveness ar e calculated during the BART determination: average and incremental cost-e ffectiveness. The general definition of the two types of cost-effectiveness can be f ound in Subsection 1.2.4. The cost-effectiveness values are based on 2007 dollars. Cost imp act analyses were performed for all the identified technically feasible control tec hnologies. 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 NO x 

### and SO 2 

### as follows:

• $400 to $2000 per ton of SO 2 

### removed.

• $100 to $1000 per ton of NO x 

### removed.
For SO 2 

### 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 NO x 

### controls, EPA stated that its presumptive NO x 

### “limits...are based on the use of current combustion control technology. Current combustion control technology is genera lly, 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 th e 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 NO x 

### and SO 2 

### control technologies analyzed for Boardman are generally cons istent 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 develope d 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 gr aphical plots of the total annualized costBoardman 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-c ost envelope” for each group of control technologies was identified. C ontrol technologies that lie on this least-cost envelope are
“dominant controls” that should be the focu s for the BART determination. Dominant controls are the technologies that have the lo west cost for implementation per quantity of pollutant removed. Therefore, these technolo gies 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 ha ve different emissions removal capability.Boardman PlantImpact Analysis (Step 4)1102076-6Table 6-1Impact Analysis and Cost-Effectiveness ResultsEmission Expected Expected Total IncrementalPerformanceEmission Emission Capital Annualized Cost Cost Energy Non-AirLevel Rate Reductions Costs Cost Effectiveness Effectiveness Impacts ImpactsAll Feasible Technologies (lb/mmBtu) (tons/yr) (tons/year) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$)NOxControl TechnologiesOverfire Air (OFA) System Operation 0.40 9,726 623 4,022 1,007 1,617 -- 540 --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 -- 26 --Upgraded LNB with Existing OFA System Operation 0.32 7,781 2,568 14,198 2,190 853 671 540 --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 -- 566 --New LNB with Modified OFA System and SNCR 0.23 5,593 4,756 50,080 7,117 1,496 2,796 26 --New LNB with Modified OFA System and Selective Catalytic Reduction 0.07 1,702 8,647 223,510 26,772 3,096 5,052 944 1SO2Control TechnologiesSemi-Dry FGD 0.15 3,643 11,259 247,29336,322 3,226 -- 1,522 742Wet FGD0.10 2,429 12,473 382,37751,815 4,154 12,759 5,679 806PM Control TechnologiesExisting ESP with Operational Restrictions 0.012 295 123 0 0 0 -- -- --Pulse Jet Fabric Filter (PJFF) 0.012 295 123 94,35312,836 104,580 -- 1,331 --Compact Hybrid Particulate Collector (COHPAC) 0.012 295 123 82,95110,907 88,863 -- 1,011 --Wet ESP0.012 295 123 179,29021,057 171,559 -- 652 --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 FGDBoardman PlantImpact Analysis (Step 4)1102076-703,0006,0009,00012,00015,00018,00021,00024,00027,00030,0000 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)Overfire Air (OFA) System OperationUpgraded Low NOx Burners (LNB)Selective Non-Catalytic Reduction (SNCR)Upgraded LNB with Existing OFA System OperationNew LNB with Modified OFA SystemUpgraded LNB with Existing OFA System Operation and SNCRNew LNB with Modified OFA System and SNCRNew LNB with Modified OFA System and Selective Catalytic ReductionDominant ControlsFigure 6-1NOxControl Cost-EffectivenessBoardman PlantImpact Analysis (Step 4)1102076-805,00010,00015,00020,00025,00030,00035,00040,00045,00050,00055,0000 1,500 3,000 4,500 6,000 7,500 9,000 10,500 12,000 13,500 15,000Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)Semi-Dry FGDWet FGDDominant ControlsFigure 6-2SO2Control Cost-EffectivenessBoardman PlantImpact Analysis (Step 4)1102076-902,0004,0006,0008,00010,00012,00014,00016,00018,00020,00022,0000 20 40 60 80 100 120 140 160 180 200Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)Pulse Jet Fabric Filter (PJFF)Compact Hybrid Particulate Collector (COHPAC)Wet ESPDominant ControlsExisting ESP with Operational RestrictionsFigure 6-3PM Control Cost-EffectivenessBoardman Plant Impact Analysis (Step 4)

110207 6-10 

### 6.4.1 NO x



### 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 NO x 

### 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 cont rol option. Two of the six technologies (NLNB/ MOFA/SNCR and NLNB/MOFA/SCR) also represent the
two most effective NO x 

### control technologies and were evaluated to determine their respective improvement to visibility in the Cl ass I areas. Of the two, the control package utilizing SCR has significantly greater costs of compliance, negative energy impacts, and negative non-air qu ality environmental impacts.

6.4.2 SO 2



### Control Technologies

As observed on the SO 2 

### cost-effectiveness graphica l plot (Figure 6-2), both technically feasible SO 2 

### control technologies are dominant controls and therefore, were evaluated to determine their resp ective improvement to visibility in the Class I areas. Of the two, the costs of complia nce and the negative non-air qu ality 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 wa s shown on the least-cost envelope as the most cost-effective PM control technology. Th e other technically feasible PM control technologies have the same expected emi ssions reduction but have a higher total annualized cost. However, since the SO 2 

### 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 visi bility improvements that would result from installation of the top-ranked technology op tions identified in the impact evaluation (Step 4). The visibility improvements are th e differences between th e 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 establis h the baseline for the pre-BART control analyses. Second, individual post-BART contro l 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 speci fied in the protocol , all Class I areas within a 300 kilometer (km) radius of the plan t were included in the analysis. In addition, although not a Class I area, the Columbia Ri ver 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 gr eater 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 pollu tant removal caused by wet scavenging and dry deposition, chemical transformation, and pl ume fumigation. It is supported by two primary programs, CALMET and CALPOST. Ve rsion 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-di mensional wind fields based on multiple sources of geophysical and meteorological da ta. The CALMET data used in CALPUFF was provided by DEQ and included meteor ological data for 2003, 2004, and 2005. TheBoardman Plant Visibility Impacts (Step 5)

110207 7-2 

### output of the CALPUFF model consists of bi nary 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 98 th 

### percentile visibility impact, which
translates to the 8 th 

### highest day in a year or the 22 nd 

### highest day in a 3-year period. Therefore, change in visibi lity was calculated for the 8 th 

### highest day for each year
modeled and for the 22 nd 

### 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 Bo ardman 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 federa l 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 me mo 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 (NO x 

### ).

• SO 2.



### • Nitric Acid (HNO 3 

### ).

• 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 (SO 4 

### ).

- Non-SO 4 

### inorganic aerosol.
Table E-1 summarizes the emission rates an d stack parameters th at were used for the exemption modeling and BART contro l modeling. Emission rates and stack parameters have been revised since the Janua ry 2007 protocol to reflect current design
information. The PM 10 

### 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 sele cted to cover the range of effectiveness
of the individual control t echnologies evaluated in St ep 4. Retrofit PM control technologies were not evaluated because of th e small contribution PM makes to visibility compared to NO x 

### and SO 2 

### in the exemption modeling and based on the SO 2 

### control technologies including PJFF syst ems in the analyses. The pe rcent 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 NO x 

### and two SO 2 

### controls:

• NO x



### - New LNBs with modified OFA system and SCR.

- New LNBs with modified OFA system and SNCR.

• SO 2



### - 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 th e visibility improvements for the Class I area with the highest impacts, Mount H ood 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 visib ility 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 Cla ss I area and the CRGNSA by t echnology are presented in Appendix E. A comparison of the modeled visibility improvements between the two
combinations of NO x 

### control technologies shows that in all Class I ar eas, 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 NO x 

### 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 NO x 

### controls using SNCR. For the SO 2 

### control technologies, the wet FGD and semi-dry F GD options have roughly equivalent modeled visibility improvements. The semi-dry FG D 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 Casc ades are slightly better for the wet FGD option. For all Class I areas, the differences between the two cont rol 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)

NO x NLNB/MOFA/SCR 51 (45%) 49 (46%) 58 (57%) 1.84 (40%)
NLNB/MOFA/SNCR 33 (29%) 38 (36%) 31 (30%) 1.20 (26%)

SO 2 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 NO x Burners with Modified Overfire Air and Selective Catalytic Reduction. NLNB/MOFA/SNCR – New Low NO x 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 ap plied in order to determine what constitutes BART. These factors, identifie d in CAA Section 169A(g )(7) and codified in 40 C.F.R. § 51.308(e)(1)(ii), are: (1) the cost s of compliance, (2) the energy and non-air quality environmental impacts, (3) any existi ng 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 cont rol technology) is not relevant to this facility in the analysis. The fourth factor (r emaining useful life) is not relevant in this analysis to the extent that the recommende d controls are considered BART. If the NO x 

### 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 NO x 

### constitutes the control package with SNCR, this viability analysis was not incorporated into th is report. Were serious consideration given
to the NO x 

### controls package incorporating SCR notwithstanding their limited benefits and substantial capital and opera ting 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 simplif y the report, the third and fourth factors are not considered at
this time and the evaluation focuses on the firs t, second and fifth f actor. Based on these three factors, the control technologie s constituting BART are identified. Consistent with the EPA guidelines and th e 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 po llutants 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 Ta ble 5-4, each of the f our offered the same degree of control. Of the four, the PJFF op tion (in combination with the existing ESP) offered the additional non-air quality bene fit 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 SO 2 

## BART

In the evaluation of the SO 2 

### controls, the two top-ra nked technologies share essentially the same degree of improvement in modeled visibility which may reasonably be anticipated to result from the use of su ch 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 intosignificantly better visibility improvements. The Boardman Plant currently relies on lowsulfur coal for SO 2 

### control. As a result, the installa tion of either wet FGD or semi-dry FGD results in decreases of approximate ly 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 comp aratively insignificant. That, combined with the differences in emissions parameters associated with the wet versus semi-dry technologies means that the improvements in visi bility are very similar. For example, the maximum modeled impact (98 th 

### percentile over the three year period) average across all fourteen Class 1 areas for the two FGD opti ons 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 visibi lity which may reasonably be anticipated to result from the use of such technology) for choosing one SO 2 

### control technology over
another.
Evaluation of the second factor clear ly indicates that the preferred SO 2 

### control technology is semi-dry FGD. The non-air qua lity environmental and energy impacts are significantly greater for the wet FGD contro l technology than for the semi-dry FGD control technology. A key non-ai r quality environmental impact of the wet FGD versus semi-dry FGD technology is that the wet FG D 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 wo uld 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 FG D 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, pr oducing 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 wi th the semi-dry FGD. The average costeffectiveness of semi-dry FGD and we t FGD are $3,226 per ton and $4,154 per ton, respectively (see Table 6-1). The incremen tal 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 c ontrol option is signifi cantly higher than the upper end of the range ($400 to $2000/ton) cons idered to be reasona ble in EPA’s BART guidelines. The incremental cost-effectiven ess of moving from the semi-dry to the wet technology far exceeds the r easonableness threshold. Based on an analysis of all the statutory factors, it was concl uded that the best
alternative for SO 2 

### 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 imp acts of utilizing the wet technology are extreme. Therefore, BART for SO 2 

### for the Boardman Plant is semi-dry FGD.



## 8.3 Selection of NO X 

## BART
The application of the statutory factors i ndicates that the best choice for BART
for NO x 

### is new LNBs with modified OFA syst em and SNCR. Each of the top two NO x 

### control options involve the in stallation of new LNBs with a modified OFA system. The top two options differ in terms of whethe r they utilize SNCR or SCR for additional control. While the option in corporating SCR results in lower emissions than the option incorporating SNCR (a reduction of 12,000 t ons/year at the maximum modeled emission rate v. 8,000 tons/year), the visibility improve ments 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 resu lts in significant visibility improvement, although not nearly as drama tic as the improvements created by SO 2 

### control. The NO x 

### control option incorporating S CR appears to generate better improvements in visibility, but the incremen tal 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 resu lts in an average of 85 days per year at the Mount HoodBoardman 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 NO x 

### control option that incorporates SNCR reduces the average number of days with modeled impacts over 0.5 deciviews to 73. Utilizing the NO x 

### control that incorporates SCR onl y reduces the numbe r 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 NO x 

### control option incorporating SNCR will reduce the 98 th 

### percentile impacts over the three year period
from 4.6 deciviews to 3.4 decivi ews—a material decrease in th e peak impacts, but not as significant as that achieved with the SO 2 

### controls. However, utilization of the NO x 

### control technology that incorporates SCR will only reduce the 98 th 

### percentile impact by
an additional 0.6 deciviews. As EPA stated in the July 2006 preambl e, “the simplified chemistry in the model tends to magnify the act ual 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 di fference 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, wh ile the modeling suggests that the use of the
NO x 

### control option incorporating SCR results in lower impacts than the NO x 

### control option incorporating SNCR, th ey are not substantially lo wer enough to constitute a significant difference. Evaluation of the energy and non-air qua lity environmental impacts factor
indicates that the use of the NO x 

### control option incorporati ng SNCR is the appropriate choice for BART. Based on energy consumption, the NO x 

### controls incorporating SNCR are clearly preferable. The energy consumption of the NO x 

### controls incorporating SCR is 36 times greater than the en ergy consumption of the NO x 

### controls incorporating SNCR (2,537 kW v. 70 kW) as a result of the fan a uxiliary 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 NO x 

### controls incorporating SNCR over the NO x 

### controls incorporating SCR. The SCR system generates hazardous material as a result of catalyst replaceme nt, 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. Relate d to this concern, the SCR system must store larger amounts of anhydrous ammonia on si te due to the differences in operating scenarios between the controls incorporati ng 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 strongl y support selecting the NO x 

### controls incorporating
SNCR as BART. The economic impacts associated with the NO x 

### controls incorporating SCR are considerably higher (by an order of magnitude) than the economic impacts
associated with the NO x 

### controls incorporating SNCR. The economic impacts of the NO x 

### controls incorporating SNCR are substantial, with a capital cost of approximately $50 million and annual operating costs of approxima tely $2.4 million. This equates to an
annualized cost for the NO x 

### controls with SNCR of over $7 million per year and approximately $1,500 per ton of NO x 

### controlled (Table 6-1). This cost effectiveness is significantly higher than the ra nge ($100 to $1000/ton) consid ered reasonable in EPA’s BART guidelines. The costs of installing and operating NO x 

### controls inco rporating 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 NO x 

### controls with SCR of nearly $27 million per year an d approximately $3,100 per ton of NO x 

### controlled (Table 6-1). Therefore, whether the contro ls 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 NO x 

### controls utilizing SCR as compared to the NO x 

### controls with SNCR is $5,052 per ton NO x 

### removed. The incremental cost effectiveness of moving from the NO x 

### controls with
SNCR to the NO x 

### controls with SCR far exceeds EPA’s reasonableness threshold. The
incremental cost effectiveness associated wi th visibility improvement reaches a similar result. The average 98 th 

### percentile impact le vel across all the Cla ss I areas is only 0.27
deciviews better with the NO x 

### control option incorporating SCR than the NO x 

### control option incorporating SNCR. This equates to an incremental annualized control cost associated with moving from the NO x 

### controls with SNCR to the NO x 

### 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 NO x 

### controls with S CR 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 conclu ding that BART for NO x 

### 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 imp act on plant operations and plant viability. That would be the case he re 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 possi bly 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-afford ability of the controls and to therefore not require SCR. Based on the discussion within th is report there is no need to rely on this
factor to conclude that BART does not include SCR. However, this additional
consideration lends furt her support to the conclusion that BART for NO x 

### constitutes the control package with SNCR.
Based on the EPA Guidelines the econom ic impacts associated with the NO x 

### controls incorporating SCR ar e significant both on an average and an incremental basis and support the conclusion that the best alternative for NO x 

### 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, visibi lity improvement was evaluated with the
combination of controls identifi ed as BART for particulate, SO 2 

### , and NO x 

### (Table 8-1 and Appendix E). The modeling methodology used for this combination of controls evaluation was the same as the methodology su mmarized 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 resu lt 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 ex ceed 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 SN CR. That control package resulted in slightly lower impacts then the control packag e with SNCR, but not dramatically so. For example, the average number of days wh ere the impacts would exceed 1.0 deciview drops from 30 days when modeled with the curr ent controls to 5.0 with SNCR to 1.3 with
SCR. The 98 th 

### percentile impact (in deciviews) over the three year period drops from
2.22 when modeled with the current contro ls 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 packag e, it is important to recognize that such differences may not be meaningful. As not ed above, EPA recognized that the CALPUFFBoardman Plant Selection of Best Alternative

110207 8-7 

### model exaggerates the impacts. Therefore, diffe rences of a few tenths of a deciview are not considered significant. The improvements when the entire multipollutant control package is considered are lower with S CR 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 uti lizing SCR. Requiring such a large additional expenditure calls into question the viability of the pl ant 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 be nefits predicted from the proposed BART control package show significant improvement in visibility in the CRGNSA. While slightly greater improvements are shown by th e model from the use of a control package that includes SCR, these incremental improve ments are not considered significant. This conclusion was independent ly verified in the draft Columbia River Gorge Air Quality Study Science Summary Report prepared by DEQ in c onjunction with other state and federal governmenta l 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, th e report analyzed visibility improvements
associated with the emission levels achieve d using new LNBs with modified OFA and
SNCR for NO x 

### control, semi-dry FGD (including PJFF) for SO 2 

### and PM control. The report then compared these impacts to the m odeled visibility improvements if Boardman emissions were reduced to “0” (i.e., comple te shutdown of the pl ant). As the report notes, “practically zero” addi tional visibility benefit is achieved by reducing plant emissions from those achieved by the propos ed 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 NO x 

### 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 genera tes “practically zero ” additional benefit as compared to the proposed BART contro l package, the much smaller incremental benefit achieved by requiring SCR rather than SNCR would be imma terial. Given the
extreme incremental costs asso ciated with the use of new LNBs with modified OFA and
SCR for NO x 

### control, there is no tec hnically 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 (inclu ding 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 imp acts 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 real ized and does not justify the expense and additional impacts associated w ith 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 NO x Burners with Modified Overfire Air and Selective Noncatalytic Reduction NLNB/MOFA/SCR – New Low NO x 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 Applica tion of CALPUFF Determination Modeling Pursuant to BART Regulation—PGE Bo ardman Plant (Revised), January 2007

(2) Federal Land Managers’ Air Qualit y Related Values Workgroup (FLAG), Phase I Report, December 2000.

(3) Oregon Department of Environmental Qu ality (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 Summ ary Report and Recommendations for Modeling Long-Range Transport Imp acts, 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 Qualit y Study Science Summary Report (September 24, 2007).Boardman Plant Appendix A

110207 A-1 

## Appendix A Design BasisBoardman 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

RangeBoardman 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. 2Boardman Plant Appendix B

110207 B-1 

## Appendix B Stack Outlet ConditionsBoardman PlantAppendix B110207B-2Heat Input (HHV) =5,793 MBtu/hrStack Outlet ConditionsFlow(acfm)Stack Velocity(ft/s)Temperature(°F)Pressure(in, wg)SO2(lb/MBtu)SO2(lb/hr)NOx(lb/MBtu)NOx(lb/hr)PM(lb/MBtu)PM(lb/hr)Baseline Case1. Existing Operation2,159,900 95 293 0.50 0.85 4,943 0.54 3,152 0.018 106NOx Controlled Outlet Conditions1. New Low NOx Burners with Modified OFA System and SelectiveCatalytic Reduction or SCR 2,098,800 92 270 0.50 0.85 4,943 0.07 406 0.018 1062. New Low NOx Burners with Modified OFA System and SNCR 2,160,500 95 293 0.500.85 4,943 0.23 1,332 0.018 1063. Upgraded Low NOx Burners with Existing OFA SystemOperation and SNCR 2,161,300 95 293 0.50 0.85 4,943 0.27 1,564 0.018 1064. New Low NOx Burners with Modified OFASystem 2,159,900 95 293 0.50 0.85 4,943 0.28 1,622 0.018 1065. Upgraded Low NOx Burners with Existing OFA SystemOperation 2,159,900 95 293 0.500.85 4,943 0.32 1,854 0.018 1066. Selective Non-Catalytic Reduction (SNCR) 2,162,600 95 293 0.50 0.854,943 0.32 1,854 0.018 1067. Upgraded Low NOx Burners 2,159,90095 293 0.50 0.85 4,943 0.38 2,201 0.018 1068. Overfire Air System Operation 2,159,900 95 293 0.50 0.85 4,943 0.40 2,317 0.018 106SO2 Controlled Outlet Conditions1. Wet Flue Gas Desulfurization (FGD) 1,823,200 60 136 0.50 0.10 579 0.54 3,152 0.012 702. Semi-Dry Flue Gas Desulfurization (FGD) 1,901,700 83 170 0.50 0.15 869 0.54 3,152 0.012 70PM Controlled Outlet Conditions1. Pulse Jet Fabric Filter (PJFF)2,159,900 95 293 0.50 0.85 4,943 0.54 3,152 0.012 702. Compact Hybrid Particulate Collector (COHPAC) 2,159,900 95 293 0.50 0.85 4,943 0.54 3,152 0.012 703. Wet ESP1,823,200 60 136 0.50 0.85 4,943 0.54 3,152 0.012 704. Existing ESP with Operational Restrictions 2,159,900 95 293 0.50 0.854,943 0.54 3,152 0.012 70Composite Controlled Outlet Conditions1. New Low NOx Burners with Modified OFA Systemand SNCRand Semi-Dry FGD1,902,200 83 170 0.50 0.15 869 0.23 1,332 0.012 702. New Low NOx Burners with Modified OFA Systemand SCRand Semi-Dry FGD1,905,800 84 170 0.50 0.15 869 0.07 406 0.012 70Notes1. SO2based upon no SO2to SO3conversion.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 1Best Available Retrofit Technology (BART) Engineering AnalysisStack Outlet Data for Visibility ModelingBoardman Plant Appendix C

110207 C-1 

## Appendix C Design Concept DefinitionsBoardman 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 sy stem currently only used when needed to mee t permit limit due to boiler efficiency impac ts, slagging issues, and poor operability.

Pollutant NO x 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 NO x 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 NO x optimization into combus tion monitoring process.

Fan Modifications None.
Power Supply/Aux Power Modificati ons No significant aux power im pacts 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, NO x 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 NO x Burners

Process Description Low NO x Burners (LNB) - Upgrade existing. M odifications of burner tips and burner balanc ing using CFD modeling, combustion air monitoring, and coal flow monitoring.

Pollutant NO x 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 Upgr ade/additional components to existing burners.
Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing ai r duct and coal pipes.
Reagent Storage None.
Control System Modifications None.

Fan Modifications None.
Power Supply/Aux Power Modifications None.
Enclosures Requirements Enclosed al ready 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 acti vities including, but not limited to, offices, lay-down , and staging.

State of Availability Commercial.
Technical Feasibility Technically feasible and applicable.

Reasons Low NO x 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 NO x Burners with Existing OFA System Operation

Process Description Upgrade existing Low NO x Burners (LNBs) with existing OFA system. M odifications of burner ti ps and burner balancing.

Pollutant NO x 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 ex isting burners. Location remains the same.
Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing ai r duct and coal pipes.
Reagent Storage None.
Control System Modifications None

Fan Modifications None.
Power Supply/Aux Power Modifications None
Enclosures Requirements Enclosed al ready 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 acti vities including, but not limited to, offices, lay-down , and staging.

State of Availability Commercial.
Technical Feasibility Technically feasible and applicable.

Reasons Low NO x burners already in operation. Existing OF A 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 NO x Burners with Modified OFA System

Process Description New low NO x burners (LNB), modified overfire air (OFA) system. Insta ll new OFA ports at location to be determined during detailed engineering analysis.

Pollutant NO x 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 t he 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 existi ng air duct and coal pipes.
Reagent Storage None.
Control System Modifications Existing contro l system modification to utilize new equipment.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed 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 acti vities 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 NO x burners already in operation and modifying OFA system to support current technology low NO x 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 NO x 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 an d urea tank at grade with truck unloading station.
Inlet/Outlet Connections and Interconnecting Ducts Install wall in jectors and lance-type injectors for SNCR in the boiler.
Reagent Storage Storage tank for urea at grade.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate 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 acti vities 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 NO x Burners with Existing OFA System Operation and SNCR

Process Description Upgrade existing Low NO x Burners (LNBs) with existing OFA system. Modifica tions of burner tips and bur ner balancing. Selective Noncatalytic Reduction (SNCR) system for postcombustion reduction of NO x .

Pollutant NO x 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 exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Keep LOI and CO within accept able 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 acti vities 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 NO x burners and OFA system operation reduces reagent consumption for SNCR because of lower NO x 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 NO x Burners with Modified OFA System and SNCR

Process Description New low NO x burners (LNB), modified overfire air (OFA) system. Inst all new OFA ports at locations determined during detailed engineering analysis. A new SNCR system shall be installed into upper boiler level.

Pollutant NO x 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 t he 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 contro l system modification to utilize new equipment.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Keep LOI and CO within accept able 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 acti vities 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 NO x burners already in operation and modifying OFA system to support new technology low NO x 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 NO x Burners with Modified OFA System and Selective Catalytic Reduction (SCR)

Process Description New low NO x burners (LNB), modified overfire air (OFA) system complementing new SCR system.
Pollutant NO x 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 t he 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 protec tive structure or away from unit to limit risk from leaks. Control System Modifications Existing contro l system modification to utilize new equipment.

Fan Modifications Assume booster fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume medium co st expansion will be required for aux electric system.
Enclosures Requirements Ammonia injection grid area and soni c horns are to be enclosed. Burner and OFA systems are enclosed in boiler building. Demolition or Relocation Requirements Existing ec onomizer 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 Ammoni a slip in the SCR may cause ammonium bisulfate formation on the air heater and require more frequent cleaning. SO 2 to SO 3 conversion by the cata lyst, causing pluggage and corrosion in air heater. Other Assumptions

• No major impact in plant availability.

• Temperature range of flue gas at economizer outlet is acc eptable after modifications of boiler superheater section.

• The site has sufficient area available to accommodate construction acti vities including, but not limited to, offices, lay-down , and staging.

• Air heater modifications, flue gas handling sy stems and ammonia handling systems included.

• No boiler/duct stiffening included.

• Modifications made to boiler heat transfer surface area to opt imize boiler flue gas outlet temperature for SCR operations.

• No impact on potential ash sales and no additional heating i.e. ec onomizer bypass or duct burners required to achieve operatin g temperature at low loads.

• Reagent is ammonia and can be anhydrous, aqueous or fr om 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 requi rements 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 des ulfurization process (wet scrubber) with fabric filter upstream of wet scrubber for mercury and particulate control. Description is typica l for all absorber/scrubber based FGD systems.
Pollutant SO 2 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 (CaSO 3 • 1/2H 2 0), Calcium Sulfate (CaSO 4 • 2H 2 O) 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 befor e 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 contro l 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 elec tric system modifications will be required.
Enclosures Requirements Oxidation air bl ower 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 ductwor k, 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 rema ins 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 SO 2 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 (CaSO 3 • 1/2H 2 0), Calcium Sulfate (CaSO 4 • 2H 2 O) mixture Production Rate 10.0 tph

Location of Major Process Equipment Spray Dryer Absorber and Puls e Jet Fabric Filter flue gas flow path location is after ID fa ns 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 contro l 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 elec tric system modifications will be required.
Enclosures Requirements Compressor buildi ng, 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 rema ins 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 a nd 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 acceptabl e 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 si lo (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 precipitat or (ESP) with operational restri ctions (such as more limitati ons 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 in creased 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 w ill be after air heater outlet and before existing ID fan inlet. Inlet/Outlet Connections and Interconnecting Ducts Ductwork connecti on after air heater outlet and before existing ID fan inlet

. Reagent Storage None.
Control System Modifications Incorpor ated 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 elec tric 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 Modifi cation to existing ash handling system.
Significant Issues or Challenges Installati on 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 shou ld 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 acti vities 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 Co mpact 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 ga s 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 Incorpor ated 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 acti vities including, but not limited to, offices, lay-down , and staging.

• The existing ESP will be left in place upstream of the fabric f ilter. The fly ash that is collected in the ESP is handled sep arately 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 bypr oduct 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 Incorpor ated 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 z one 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, perio dic outages for intense off-li ne cleanings may be required.

• Aux electric usage is a major factor if using wet ESP as a polishing filter and for SO 3 mitigation.

• The site has sufficient area available to accommodate construction acti vities 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 a nd 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 SummaryBoardman 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) $1,007,000Boardman 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) $1,211,000Boardman 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) $2,190,000Boardman 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) $3,718,000Boardman 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 ga l Engineering 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) $5,386,000Boardman 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 ga l Engineering 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) $7,117,000Boardman 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 ga l Engineering 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) $6,914,000Boardman 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) $26,772,000Boardman 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 ga l 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 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) $51,815,000Boardman 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) $36,322,000Boardman 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) $12,836,000Boardman 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) $10,907,000Boardman 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 ga l Engineering 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) $21,057,000Boardman Plant Appendix E

110207 E-1 

## Appendix E Visibility Modeling Results----------------Filterable---------------- --------------Condensable------------ScenarioFlow (acfm)StackVelocity(ft/s)Temp.(°F)NOx(lb/hour)SO2(lb/hour)PM10 Total(lb/hour)ElementalCarbon(lb/hour)PM Fine(lb/hour)PM Coarse(lb/hour)OrganicCarbon(lb/hour)InorganicAerosol(lb/hour)Non-SO2 InorAersol(lb/hour)Exemption Modeling 2,159,900 95 293 3152.0 4943.1 176.20 1.74 45.40 58.90 14.00 56.10 0.00New Low NOx Burners (NLNB) with ModifiedOFA (MOFA) and Selective CatalyticReduction (SCR)2,173,000 95 293 405.51 4943.1 176.20 1.74 45.40 58.90 14.00 56.10 0.00NLNB/MOFA and Selective Non-catalyticReduction (SNCR)2,159,900 95 293 1332.4 4943.1 176.20 1.74 45.40 58.90 14.00 56.10 0.00Wet Flue Gas Desulfurization (Wet FGD)1,823,200 60 136 3152.0 579.3 115.45 1.14 29.80 38.60 9.20 36.80 0.00Semi-Dry Flue Gas Desulfurization (Semi-DryFGD)1,901,700 83 170 3152.0 869.0 115.45 1.14 29.80 38.60 9.20 36.80 0.00NLNB/MOFA/SCR with Semi-Dry FGD1,905,800 84 170 405.51 869.00 115.45 1.14 29.80 38.60 9.2036.80 0.00NLNB/MOFA/SNCR with Semi-Dry FGD1,901,700 83 170 1332.4 869.00 115.45 1.14 29.80 38.60 9.20 36.80 0.00Notes: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 metersIndividual SO2/PM Control AlternativesIndividual NOx Control AlternativesCombined NOx and SO2/PM Control AlternativesTable E-1Stack Parameters and Emission Rates for All CALPUFF Model RunsBoardman Plant RH BART DeterminationExisting Controls22nd High(deciviews)2003 20042005 2003-20052003 20042005 2003 20042005Alpine Lakes Wilderness Area 1.758 2.235 2.371 2.235 18 35 38 40 53 59Diamond Peak Wilderness Area 1.061 1.368 0.589 1.029 10 12 2 17 31 12Eagle Cap Wilderness Area 2.227 2.541 1.778 2.227 49 40 33 100 86 79Glacier Peak Wilderness Area 1.079 1.574 1.624 1.399 8 16 21 27 39 50Goat Rocks Wilderness Area 1.893 2.495 2.459 2.383 24 33 34 51 53 51Hells Canyon Wilderness Area 1.979 1.950 1.780 1.950 50 52 33 114 107 102Mount Adams Wilderness Area 1.809 2.751 2.862 2.688 29 38 34 61 63 58Mount Hood Wilderness Area 3.923 4.996 4.917 4.598 66 65 59 85 92 78Mount Jefferson Wilderness 3.178 3.346 1.891 3.123 44 49 32 60 75 55Mount Rainier National Park 1.662 1.953 2.092 1.990 16 27 26 45 49 48Mount Washington Wilderness Area 2.436 2.373 1.615 2.348 28 31 18 42 61 32North Cascades National Park 0.845 1.069 1.152 1.055 3 9 12 17 27 39Strawberry Mountain Wilderness Area 1.579 2.239 1.170 1.718 28 35 14 53 72 47Three Sisters Wilderness Area 2.424 2.420 1.761 2.290 27 33 18 47 62 28Maximum 3.92 5.00 4.92 4.60 66 65 59 114 107 102Minimum 0.85 1.07 0.59 1.03 3 9 2 17 27 12Average1.99 2.38 2.00 2.22 29 34 27 54 62 53Columbia Gorge National Scenic Area*3.050 3.239 4.761 3.708 61 57 56 92 90 83*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.Number of DaysAbove 0.5 deciviewTable E-2Exemption (Existing Controls) Modeling ResultsBoardman Plant RH BART Determination8th Highest Impact by Year(deciviews)Number of DaysAbove 1.0 deciviewClass I Area22nd High(deciviews)2003 20042005 2003-20052003 20042005 2003 20042005Alpine Lakes Wilderness Area 1.059 1.382 1.369 1.278 9 17 15 23 37 41Diamond Peak Wilderness Area 0.657 0.931 0.365 0.629 3 6 0 10 15 4Eagle Cap Wilderness Area 1.403 1.459 1.047 1.378 21 23 9 69 50 38Glacier Peak Wilderness Area 0.580 1.065 0.890 0.788 2 8 7 15 24 27Goat Rocks Wilderness Area 1.097 1.738 1.313 1.368 12 21 15 34 38 34Hells Canyon Wilderness Area 1.208 1.238 0.889 1.174 18 16 5 63 58 44Mount Adams Wilderness Area 1.064 1.855 1.389 1.563 8 26 13 40 45 35Mount Hood Wilderness Area 2.351 3.076 2.531 2.757 45 46 34 67 72 59Mount Jefferson Wilderness 2.123 2.270 1.068 2.071 26 30 12 47 55 36Mount Rainier National Park 1.028 1.491 1.231 1.287 8 15 12 24 34 27Mount Washington Wilderness Area 1.611 1.496 0.965 1.474 18 20 6 35 41 19North Cascades National Park 0.469 0.680 0.629 0.5931 6 3 6 11 15Strawberry Mountain Wilderness Area 0.965 1.301 0.705 1.001 6 13 3 31 36 18Three Sisters Wilderness Area 1.604 1.561 0.985 1.405 17 18 7 34 40 20Maximum 2.35 3.08 2.53 2.76 45 46 34 69 72 59Minimum 0.47 0.68 0.37 0.591 6 0 6 11 4Average1.23 1.54 1.10 1.34 14 19 10 36 40 30Columbia Gorge National Scenic Area*1.538 2.174 2.507 2.219 31 34 40 68 65 58*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.Number of DaysAbove 0.5 deciviewTable E-3New Low NOx Burners with Modified Overfire Air and Selective Catalytic Reduction (NLNB/MOFA/SCR) Modeling ResultsBoardman Plant RH BART Determination8th Highest Impact by Year(deciviews)Number of DaysAbove 1.0 deciviewClass I Area22nd High(deciviews)2003 20042005 2003-20052003 20042005 2003 20042005Alpine Lakes Wilderness Area 1.354 1.683 1.753 1.569 13 22 27 31 44 49Diamond Peak Wilderness Area 0.778 1.116 0.425 0.776 6 8 0 13 21 6Eagle Cap Wilderness Area 1.619 1.819 1.231 1.611 33 30 16 76 61 57Glacier Peak Wilderness Area 0.829 1.144 1.147 1.005 3 8 11 22 29 39Goat Rocks Wilderness Area 1.521 1.842 1.655 1.685 14 27 20 42 46 41Hells Canyon Wilderness Area 1.487 1.438 1.222 1.436 25 29 15 81 69 71Mount Adams Wilderness Area 1.258 2.243 2.074 1.952 17 28 25 47 48 51Mount Hood Wilderness Area 2.931 3.626 3.401 3.401 53 52 45 70 81 67Mount Jefferson Wilderness 2.442 2.499 1.269 2.352 31 39 21 51 63 46Mount Rainier National Park 1.339 1.445 1.462 1.445 10 20 19 32 37 32Mount Washington Wilderness Area 1.908 1.801 1.221 1.707 21 24 11 38 47 22North Cascades National Park 0.611 0.841 0.804 0.748 1 7 5 11 19 24Strawberry Mountain Wilderness Area 1.173 1.641 0.840 1.282 11 19 5 40 50 29Three Sisters Wilderness Area 1.885 1.800 1.360 1.623 20 24 12 38 47 21Maximum 2.93 3.63 3.40 3.40 53 52 45 81 81 71Minimum 0.61 0.84 0.43 0.75 1 7 0 11 19 6Average1.51 1.78 1.42 1.61 18 24 17 42 47 40Columbia Gorge National Scenic Area*2.051 2.455 3.232 2.786 46 41 46 76 77 69*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.Number of DaysAbove 0.5 deciviewTable E-4Low NOxBurners with Modified Overfire Air and Selective Non-catalytic Reduction (NLNB/MOFA/SNCR) Modeling ResultsBoardman Plant RH BART Determination8th Highest Impact by Year(deciviews)Number of DaysAbove 1.0 deciviewClass I Area22nd High(deciviews)2003 2004 2005 2003-20052003 2004 2005 2003 2004 2005Alpine Lakes Wilderness Area 1.064 1.439 1.440 1.385 11 17 23 20 39 39Diamond Peak Wilderness Area 0.718 0.619 0.378 0.555 4 2 0 10 15 5Eagle Cap Wilderness Area 1.619 1.551 1.160 1.442 22 18 10 65 53 51Glacier Peak Wilderness Area 0.591 1.060 0.990 0.886 2 8 7 12 24 25Goat Rocks Wilderness Area 1.116 1.598 1.747 1.581 11 21 19 29 39 36Hells Canyon Wilderness Area 1.202 1.210 1.095 1.207 14 14 9 61 67 51Mount Adams Wilderness Area 1.333 2.083 1.986 1.965 14 26 21 34 51 39Mount Hood Wilderness Area 3.184 3.437 3.813 3.716 47 52 49 73 79 69Mount Jefferson Wilderness 2.607 2.462 1.588 2.222 25 30 14 49 58 42Mount Rainier National Park 1.022 1.334 1.483 1.36 8 13 18 25 33 35Mount Washington Wilderness Area 1.759 1.490 1.007 1.464 15 15 8 32 43 25North Cascades National Park 0.472 0.686 0.682 0.6432 3 2 7 14 14Strawberry Mountain Wilderness Area 0.898 1.185 0.848 1.025 3 15 5 26 39 17Three Sisters Wilderness Area 1.480 1.387 1.042 1.353 17 19 10 34 42 25Maximum 3.18 3.44 3.81 3.72 47 52 49 73 79 69Minimum 0.47 0.62 0.38 0.562 2 0 7 14 5Average1.36 1.54 1.38 1.49 14 18 14 34 43 34Columbia Gorge National Scenic Area*2.460 2.748 4.124 3.282 48 51 53 73 76 76*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.Number of DaysAbove 0.5 deciviewTable E-5Wet Flue Gas Desulfurization Modeling ResultsBoardman Plant RH BART Determination8th Highest Impact by Year(deciviews)Number of DaysAbove 1.0 deciviewClass I Area22nd High(deciviews)2003 20042005 2003-20052003 20042005 2003 20042005Alpine Lakes Wilderness Area 1.139 1.407 1.558 1.458 9 17 23 24 40 43Diamond Peak Wilderness Area 0.718 0.659 0.406 0.59 3 2 0 10 17 4Eagle Cap Wilderness Area 1.524 1.479 1.099 1.425 23 20 8 69 53 49Glacier Peak Wilderness Area 0.717 0.855 0.996 0.855 2 7 7 13 25 29Goat Rocks Wilderness Area 1.117 1.684 1.805 1.609 13 22 21 32 43 41Hells Canyon Wilderness Area 1.281 1.304 1.277 1.295 14 16 13 69 74 60Mount Adams Wilderness Area 1.488 2.233 1.887 2.029 17 26 22 37 47 42Mount Hood Wilderness Area 3.241 3.629 3.682 3.629 50 49 51 75 74 69Mount Jefferson Wilderness 2.570 2.436 1.474 2.199 27 32 12 51 60 44Mount Rainier National Park 1.020 1.390 1.610 1.376 9 12 18 25 34 36Mount Washington Wilderness Area 1.708 1.580 1.104 1.572 17 16 9 32 42 23North Cascades National Park 0.447 0.757 0.744 0.701 1 4 3 7 15 16Strawberry Mountain Wilderness Area 0.885 1.227 0.823 1.037 6 15 4 31 39 17Three Sisters Wilderness Area 1.477 1.423 1.225 1.416 19 20 10 33 44 22Maximum 3.24 3.63 3.68 3.63 50 49 51 75 74 69Minimum 0.45 0.66 0.41 0.59 1 2 0 7 15 4Average1.38 1.58 1.41 1.51 15 18 14 36 43 35Columbia Gorge National Scenic Area*2.380 2.629 4.034 3.160 49 49 51 77 76 77*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.Number of DaysAbove 0.5 deciviewTable E-6Semi-Dry Flue Gas Desulfurization Modeling ResultsBoardman Plant RH BART Determination8th Highest Impact by Year(deciviews)Number of DaysAbove 1.0 deciviewClass I Area22nd High(deciviews)2003 20042005 2003-20052003 20042005 2003 20042005Alpine Lakes Wilderness Area 0.301 0.408 0.404 0.394000164Diamond Peak Wilderness Area 0.203 0.193 0.114 0.172000100Eagle Cap Wilderness Area 0.394 0.416 0.308 0.394001553Glacier Peak Wilderness Area 0.184 0.297 0.262 0.253000022Goat Rocks Wilderness Area 0.325 0.529 0.496 0.466022297Hells Canyon Wilderness Area 0.369 0.370 0.315 0.368000221Mount Adams Wilderness 0.402 0.685 0.448 0.5510 3 2 4 16 6Mount Hood Wilderness Area 0.881 1.096 1.123 1.064 6 9 11 32 32 29Mount Jefferson Wilderness 0.786 0.711 0.421 0.655 2 3 1 15 19 5Mount Rainier National Park 0.318 0.461 0.449 0.397000155Mount Washington Wilderness Area 0.555 0.478 0.315 0.436120872North Cascades National Park 0.134 0.252 0.185 0.178000001Strawberry Mountain Wilderness Area 0.287 0.415 0.223 0.315010120Three Sisters Wilderness Area 0.464 0.439 0.347 0.439010662Maximum 0.88 1.10 1.12 1.06 6 9 11 32 32 29Minimum 0.13 0.19 0.11 0.17000000Average0.40 0.48 0.39 0.43121685Columbia Gorge National Scenic Area*0.670 0.784 1.117 0.881 2 2 12 23 28 31*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.Table E-7SCR Alternative Combination: NLNB/OFA/SCR with Semi-Dry FGD Modeling ResultsBoardman Plant RH BART DeterminationClass I Area8th Highest Impact by Year(deciviews)Number of DaysAbove 1.0 deciviewNumber of DaysAbove 0.5 deciview22nd High(deciviews)2003 20042005 2003-20052003 20042005 2003 20042005Alpine Lakes Wilderness Area 0.583 0.782 0.800 0.757 0 3 4 10 21 26Diamond Peak Wilderness Area 0.372 0.349 0.210 0.291100330Eagle Cap Wilderness Area 0.817 0.785 0.574 0.746 5 6 2 28 23 9Glacier Peak Wilderness Area 0.362 0.479 0.525 0.472011379Goat Rocks Wilderness Area 0.579 0.930 0.979 0.879 1 5 7 15 24 22Hells Canyon Wilderness Area 0.686 0.659 0.625 0.659 3 1 0 19 20 14Mount Adams Wilderness 0.787 1.218 0.947 1.062 4 13 7 20 26 22Mount Hood Wilderness Area 1.776 2.091 2.019 2.014 26 29 26 52 52 54Mount Jefferson Wilderness 1.418 1.312 0.777 1.223 14 12 5 29 36 13Mount Rainier National Park 0.543 0.786 0.824 0.726 1 4 5 10 18 18Mount Washington Wilderness Area 0.930 0.850 0.562 0.781 7 4 1 17 17 9North Cascades National Park 0.236 0.424 0.399 0.347000143Strawberry Mountain Wilderness Area 0.490 0.716 0.402 0.5721 1 0 7 17 4Three Sisters Wilderness Area 0.804 0.781 0.645 0.778 5 4 1 19 24 10Maximum 1.78 2.09 2.02 2.01 26 29 26 52 52 54Minimum 0.24 0.35 0.21 0.29000130Average0.74 0.87 0.73 0.81 5 6 4 17 21 15Columbia Gorge National Scenic Area*1.273 1.442 2.187 1.662 21 23 28 49 52 52*The Columbia River Gorge National Scenic Area is not a Class I area. The data shown is for informational purposes only.Number of DaysAbove 0.5 deciviewTable E-8Best Selection Combination: NLNB/OFA/SNCR with Semi-Dry FGD Modeling ResultsBoardman Plant RH BART Determination8th Highest Impact by Year(deciviews)Class I AreaNumber of DaysAbove 1.0 deciview2003 2004 2005 2003-2005 2003-2005 2003 2004 2005 2003 2004 2005Exemption Modeling1.99 2.38 2.00 2.22--- ---4.60--- ---29 34 27 54 62 53NLNB/MOFA/SCR 1.23 1.54 1.10 1.34 0.88 40% 2.76 1.84 40% 14 19 10 36 40 30NLNB/MOFA/SNCR 1.51 1.78 1.42 1.61 0.60 27% 3.40 1.20 26% 18 24 17 42 47 40Wet FGD 1.36 1.54 1.38 1.49 0.73 33% 3.72 0.88 19% 14 18 14 34 43 34Semi-Dry FGD 1.38 1.58 1.41 1.51 0.70 32% 3.63 0.97 21% 15 18 14 36 43 35NLNB/MOFA/SCRwith Semi-Dry FGD0.40 0.48 0.39 0.43 1.78 80% 1.06 3.53 77%121685NLNB/MOFA/SNCRwith Semi-Dry FGD0.74 0.87 0.73 0.81 1.41 64% 2.01 2.58 56% 5 6 4 17 21 15Modeling Results Summary for All Class 1 AreasIndividual NOx Control AlternativesExisting ControlsCombined NOx and SO2/PM Control AlternativesIndividual SO2/PM Control AlternativesTable E-98th Highest Impactby Year Avg 22nd High AvgAvg Number ofDays Above 0.5deciviewCase22nd High MaxAvg Number ofDays Above 1.0deciviewImprovement ImprovementBoardman Plant RH BART DeterminationExemption Modeling4.60--- ---114 107 102--- --- --- --- --- ---NLNB/MOFA/SCR 2.76 1.84 40% 63 58 44 51 45% 49 46% 58 57%NLNB/MOFA/SNCR 3.40 1.20 26% 81 69 71 33 29% 38 36% 31 30%Wet FGD 3.72 0.88 19% 61 67 51 53 46% 40 37% 51 50%Semi-Dry FGD 3.63 0.97 21% 69 74 60 45 39% 33 31% 42 41%NLNB/MOFA/SCR withSemi-Dry FGD1.06 3.53 77% 2 2 1 112 98% 105 98% 101 99%NLNB/MOFA/SNCRwith Semi-Dry FGD2.01 2.58 56% 19 20 14 95 83% 87 81% 88 86%Combined NOx and SO2/PM Control Alternatives2003-2005 2003 2004 2005CaseIndividual SO2/PM Control Alternatives2005Existing ControlsIndividual NOx Control Alternatives22nd High Max (Mount Hood)Table E-10Modeling Results Summary: Mount Hood (Visibility Impact) and Hells Canyon ( Number of Days)Boardman Plant RH BART DeterminationAvg Number of Days Above 0.5 deciview (Hells Canyon)ImprovementImprovement2003-2005 2003 2004Boardman Plant Appendix F

110207 F-1 

## Appendix F Visibility Modeling ProtocolFINAL 10/11/06

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 effo rt among Idaho Department of Environmental Quality (IDEQ), Oregon Department of Envi ronmental 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 prot ocol 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:FINAL 10/11/06

2 

### • 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/C ALPOST 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 N uWest (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 underFINAL 10/11/06

3 

### 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 (SO 2 

### ), oxides of nitrogen (NO x 

### ) and direct particulate matter (PM) emissions, including both PM 10 

### and PM 2.5 

### 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 th at 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, shut down, 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 SO 2 

### , NO x 

### , and PM 10 

### are less than the significant emission rate (SER) used for Preven tion of Significant Deterioration, emissions of that pollutant will not be included in the BART exemption modeling. However, if plant-wideFINAL 10/11/06

4 

### 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.

b ext = 3 f(RH) [(NH 4 ) 2 SO 4 ] + 3 f(RH) [NH 4 NO 3 ] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + b Ray


### 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, Δ dv, value is calculated from the source’s contribution to extinction, b ext (source) 

### , and background extinction, b ext(bkg) 

### , as follows:

Δ dv = 10 ln [ ( b ext(bkg) 

### + b ext (source) 

### ) / ( b ext(bkg) 

### ) ]



## 2.7 Model Execution

2.7.1 BART Exemption Analysis

The BART exemption modeling determines which BART-eligible sources are reasonablyFINAL 10/11/06

5 

### 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 whethe r 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 factor s 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 resultsFINAL 10/11/06

6 

### 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 m odeled 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 de termination 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

7 

## 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 extendinto 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 deve lopment 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.FINAL 10/11/06

8 

### 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 Re gional 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 toolFINAL 10/11/06

9 

### 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

10 

### 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

11 

### 6) Puff splitting will not be used, following the recommendations of the FLMs.

7) Source elevations that will be entered in CA LPUFF 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, SO 2 

### , SO 4 

### , and NO x 

### ; and the additional modeled species HNO 3 

### and NO 3 

### . Emissions of H 2 

### SO 4 

### will be included, if known, and used for estimation of SO 4 

### emissions. SO 2 

### 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 μ m) PM Fine (PMF) (<2.5 μ m) PM Coarse (PMC) (2.5 – 10 μ m) Condensable: Organic Carbon (SOA) Inorganic Aerosol (SO 4 

### ) Non-SO 4 

### inorganic aerosol

• The condensable fraction will be treated as primary emissions in the CALPUFF input file and assumed to be 100% in the PM 2.5 

### 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 categoriesFINAL 10/11/06

12 

### 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 SO 4 

### , NO 3 

### , 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 BA RT 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 CALP OST and POSTUTIL to calculate the visibility impairment:FINAL 10/11/06

13 

### 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 SO 4 

### , NO 3 

### , EC, OC, PMF, and PMC, as reported in the CALPOST output files.

3) POSTUTIL will not be used to speciate modeled PM 10 

### concentrations, as PM 10 

### will be speciated into its components (PMF, PMC, SOA, EC, SO 4 

### ) and entered as primary emissions in CALPUFF. In addition, HNO 3 

### /NO 3 

### 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 98 th 

### 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 98 th 

### 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 98 th 

### 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 98 th 

### percentile value from the distribution of values containing the highest modeled delta-deciview ( Δ dv) value for each day of the simulation from all modeled receptors at a given Class I area. The 98 th 

### percentile Δ dv value will be determinedFINAL 10/11/06

14 

### in the following ways:

• The 8 th 

### highest value for each year modeled

• The 22 nd 

### 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 ( Δ dv ≥ 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 Univ ersity 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 ServiceFINAL 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 10/11/0619Adjustment to speciatedparticulate(Western States)to reflect 20% Best VisibilityDays conditionsMonthly f(RH) are fromAppendix A of Draft Guidance for Estimating Natural VisibilityConditions 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. MayJune JulyAug. Sep. Oct. Nov. Dec. BKSO4 BKNO3 BKPMC BKOC SOIL BKECClass 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/m3 ug/m3 ug/m3 ug/m3CaribouWilderness 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 1.20 0.188 0.200 0.008LassenVolcanic 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 1.21 0.189 0.201 0.008Lava 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 1.26 0.197 0.210 0.008MarbleMountain 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 1.30 0.204 0.217 0.009RedwoodNP 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 1.34 0.210 0.224 0.009SouthWarnerCA 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 1.21 0.190 0.202 0.008ThousandLakes 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 1.21 0.190 0.202 0.008Yolla Bolly Middle Eel WildernCA 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 1.24 0.194 0.206 0.008Craters 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 1.15 0.180 0.192 0.008HellsCanyon 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 1.21 0.190 0.202 0.008SawtoothWilderness 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 1.16 0.182 0.193 0.008Selway-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 1.21 0.190 0.202 0.008Anaconda-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 1.20 0.188 0.200 0.008BobMarshall 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 1.22 0.191 0.203 0.008CabinetMountains 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 1.24 0.195 0.207 0.008Gates 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 1.18 0.185 0.197 0.008GlacierNP 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 1.28 0.200 0.213 0.009MissionMountain 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 1.23 0.193 0.205 0.008RedRock 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 1.16 0.181 0.193 0.008ScapegoatWilderness 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 1.20 0.188 0.200 0.008Crater 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 1.32 0.206 0.219 0.009DiamondPeak 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 1.33 0.208 0.222 0.009Eagle 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 1.22 0.191 0.203 0.008Gearhart 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 1.25 0.196 0.208 0.008Kalmiopsis 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 1.32 0.206 0.219 0.009Mount 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 1.33 0.209 0.222 0.009Mount 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 1.34 0.210 0.223 0.009Mountain 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 1.28 0.201 0.214 0.009MountWashington 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 1.36 0.213 0.227 0.009StrawberryMountain 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 1.26 0.197 0.210 0.008ThreeSisters 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 1.35 0.212 0.226 0.009AlpineLakes 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 1.35 0.212 0.225 0.009GlacierPeak 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 1.34 0.210 0.223 0.009GoatRocks 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 1.34 0.210 0.224 0.009Mount 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 1.33 0.209 0.222 0.009MountRainier 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 1.36 0.214 0.227 0.009NorthCascades 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 1.33 0.209 0.222 0.009OlympicNP 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 1.36 0.213 0.226 0.009PasaytenWilderness 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 1.33 0.208 0.222 0.009BridgerWilderness WY2.52 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 1.14 0.178 0.190 0.008FitzpatrickWilderness WY2.51 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 1.14 0.179 0.190 0.008Grand Teton NP WY2.62 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 1.14 0.178 0.190 0.008NorthAbsaroka WY2.43 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 1.14 0.178 0.190 0.008TetonWilderness WY2.53 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 1.14 0.178 0.190 0.008WashakieWilderness WY2.50 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 1.14 0.179 0.190 0.008YellowstoneNP WY2.54 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 1.15 0.180 0.192 0.008JarbridgeWilderness 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 1.14 0.179 0.190 0.008Columbia 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 4.85 1.05 0.217 0.205CALPOST Input Group 2 CALPOST Input Group 2Monthly extinction coefficients for hygroscopic species (RHFAC) Background extinction coefficients (20% Best Days)FINAL 10/11/06

20 

### Appendix C

CALMET Parameter ValuesFINAL 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 NOWS TA 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 c oordinate User Defined User Define

2 ZFACE Vertical cell face hei ghts (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 2FINAL 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 in ital 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 fo r 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 Breez e 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 St ep 1 field and obs User Defined 1.00E-06 5 RMAX1 Max surface over-land extrapol ation radius (km) User Defined 200 5 RMAX2 Max aloft over-land extrapolat ion radius (km) User Defined 200 5 RMAX3 Maximum over-water extrapol ation radius (km) User Defined 200 5 RMIN Minimum extrapolat ion 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 CSU MM prognostic wind data User Defined 0 5 TERRAD Radius of influence of terra in features (km) User Defined 12 5 XBBAR X coordinate of Beginning of each barrier User Defined 0 5 XBCST X Point defining the coastli ne (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 0FINAL 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 mixi ng height E constant 0.15 0.15 6 CONSTN Stable mixing height N constant 2400 2400 6 CONSTW Over-water mixi ng 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 rate s 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 fo r interpolations (km) 100 12 6 TGDEFA Default over-water c apping 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 requir ed to sustain convective mixing height growth overland 0.05 0.05

6 THRESHW Threshold buoyancy flux requir ed 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-w ater mixing height (m) 3000 3000
6 ZIMIN Minimum over-l and mixing height (m) 50 50
6 ZIMINW Minimum over-w ater mixing height (m) 50 50FINAL 10/11/06

24 

### Appendix D

CALPUFF Parameter ValuesFINAL 10/11/06

25 

### Appendix D CALPUFF Parameter Values

Recommended CALPUFF Parameters chosen by EPA R egion 10 states for use in BART modeling. Input Group Group Description Sequence Variable Description Default Value a 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 vert ical 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 convecti ve 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 1FINAL 10/11/06

26 Recommended CALPUFF Parameters chosen by EPA R egion 10 states for use in BART modeling. Input Group Group Description Sequence Variable Description Default Value a Recommended Value

3 Species List 1 CSPECn Names of species modeled (for MESOPUFF II must be SO2-SO4-NOX-HNO 3-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 height s 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 co mputational domain User Defined 4 15 JECOMP Northeast Y-index of co mputational 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) 1FINAL 10/11/06

27 Recommended CALPUFF Parameters chosen by EPA R egion 10 states for use in BART modeling. Input Group Group Description Sequence Variable Description Default Value a 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 cu ticle 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 vertic al dispersion? (0 = No) 0 0 12 3 JSUP PG Stability class above mixed layer 5 5 12 4 CONK1 Stable dispersion c onstant (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 di spersion 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 6FINAL 10/11/06

28 Recommended CALPUFF Parameters chosen by EPA R egion 10 states for use in BART modeling. Input Group Group Description Sequence Variable Description Default Value a 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 mi xing height(minimum)(m) 100.0 100.0

12 39 ROLDMAX Previous Max mix ht/curr ent 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 charac teristics User Defined

14 Area Source Area Sources Area sour ces characteristics User Defined

15 Volume Source Volume Volu me 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 DefinedFINAL 10/11/06

29 

### Appendix E

CALPOST Parameter ValuesFINAL 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 = CALPU FF 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 av g % 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 coe fficients (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-hygr oscopic 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 Domain1-1 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 Guidelin e) 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 emissi on 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 Wash ington 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 results2-1 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 A ppendix 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 emi ssions will be compared with future 24-hour maximum emissions and analyzed on a pollutant-b y-pollutant basis. Frequency, magnitude, and duration of impairment will be ev aluated in the determination analysis. Sulfur dioxide (SO 2 ), oxides of nitrogen (NO x ), and direct particulate matter (PM) emissions, including both PM 10 and PM 2.5, 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 Guid eline, 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 combin ed agency protocol (ODEQ, 2006). Background values for both the Class I area s and the Columbia River Gorge Scenic Area are presented in Appendix B.3-1 SECTION 3 

# Modeling Methodology

As required by the combined agency protoc ol (ODEQ, 2006) and supported by the Interagency Workgroup on Air Quality Modeling (EPA, 1998) and the Federal Land Managers’ Air Quality Related Values Workgroup (FLA G, 2000), the CALPUFF suite of programs will be used for the BART determination modelin g. The CALPUFF modules and their version numbers that will be used in the determinatio n modeling are presented in Table 3-1. Modeling parameters for each module are describe d 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-kilomete r (km) MM5 outputs, forecast hours 13 – 24 from every 00Z and 12Z initialization, take n from University of Washington (UW) archives, for the 3 years from J anuary 2003 through December 2005.

2. BART determination modeling will utilize th e 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 obtain ed 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 examin e 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 CA LPUFF 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 determ ines the elevations of the observational stations will be used to make this calculatio n. The modified source elevation was set at 225 meters, as determined by CH2M HILL.



## 3.2.1 Species Primary emission species analyzed w ill include the input species PM, SO 2 , sulfates (SO 4 ), and NO x ; and the additional modele d species nitric acid (HNO 3 ) and nitrates (NO 3 ). Sulfur dioxide emissions will be reviewed to ensu re 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 prim ary emissions in the CALPUFF input file and assumed to be 100 percent in the PM 2.5 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 (SO 4 ) Non-SO 4 inorganic aerosol The primary emission species si zing are presented as follows:

Pollutant Mean Diameter Standard Deviation

SO 4 , NO 3 , 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 va lue of 17 ppb will be used for the ammonia background. This value is suppo rted 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 Cla ss 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 Cl ass 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 w ill 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 Gu idance for Regional Haze analysis (EPA, 2003).

2. Particulate species for the vi sibility analysis will include SO 4 , NO 3 , EC, OC, PMF, and PMC, as reported in the CALPOST output files.

3. POSTUTIL will not be used to speciate modeled PM 10 concentrations, as PM 10 will be speciated into its components (PMF, PMC, SOA, EC, SO 4 ) and entered as primary emissions in CALPUFF. In addition, HNO 3 /NO 3 partition option in POSTUTIL will not be used for ammonia limiting.

4. Natural background extinction calculations w ill 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 de civiews at the 10th percentile (median of the 20 percent best days) and an activity fact or 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, th e 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 pollu tants. The concentration estimates from CALPUFF are used with the current FLAG equation to calculate the extinc tion coefficient, as shown below:

b ext = 3 f(RH) [(NH 4 ) 2 SO 4 ] + 3 f(RH) [NH 4 NO 3 ] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + b Ray 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, Δ dv, value is calculated from the sour ce’s contribution to extinction, b ext (source) , and background extinction, b ext(bkg) , as follows:

Δ dv = 10 ln [ ( b ext(bkg) + b ext (source) ) / ( b ext(bkg) ) ]4-1 SECTION 4 

# Emissions and Stack Data

Emissions to be modeled for determination mo deling will not include startup, shutdown, or malfunction emissions. The emissions and stack data used for the determination modeling are summarized in Appendix F. Emissions we re derived by Black & Veatch for PGE as summarized in a memorandum presented in Appendix G. The control scenarios being modeled for th e determination modeling are listed below:

1. NO x Controlled Outlet Conditions

a. Selective Catalytic Reduction b. New Low-NO x Burners with Modified Over-Fire Air (OFA) System

2. SO 2 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 SO 2 and NO x 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 pe rcent. Consequently, PM controls will not be included in the determination analysis. Consistent with the BART guidelines, the requ ired 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 pollut ant to determine the most effective control by pollutant. Following that analysis, the mo del 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 determ ination is based on the change in HI from pre-BART control to post-BART control for PG E relative to natural background for each Class I area. Comparison tables for pre-BA RT control and post-BART control visibility impacts will be documented for use in the BA RT 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 Re lated 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.

## A PPENDIX 

## A 

# Class I Federal AreasTable A-1. Federal Mandatory Class I Areas Eval uated 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

## A PPENDIX 

## B 

# Natural Visibility Background and Monthly Relative Humidity f(RH)8Table B-1 Adjustment to speciated particulate (Western States) to reflect20% Best Visibility Days conditionsMonthly f(RH) are fromAppendix A of Draft Guidance for Estimating Natural VisibilityConditions under the RHR (Sept. 2003).Background extinction coefficients (20% BestDays) have been calculated using AnnualAvg bext, Best 20% bext, and activity factors.CALPOST Input Group 2 CALPOST Input Group 2Monthly extinction coefficients for hygroscopic species (RHFAC) Background extinction coefficients (20% Best Days)Jan. Feb. Mar. Apr. MayJune July Aug. Sep. Oct. Nov. Dec. BKSO4 BKNO3 BKPMC BKOC SOIL BKECClass 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/m3 ug/m3 ug/m3 ug/m3Hells 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 1.21 0.190 0.202 0.008Diamond 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 1.33 0.208 0.222 0.009Eagle Cap OR 3.77 3.16 2.47 2.102.04 1.87 1.61 1.56 1.612.25 3.44 3.97 0.049 0.041 1.22 0.191 0.203 0.008Mount Hood OR 4.29 3.813.46 3.87 2.95 3.15 2.85 3.00 3.10 3.86 4.53 4.55 0.0530.044 1.33 0.209 0.222 0.009Mount Jefferson OR 4.41 3.90 3.563.74 3.07 3.11 2.89 2.913.03 3.78 4.55 4.54 0.0540.045 1.34 0.210 0.223 0.009Mount Washington OR 4.44 3.93 3.58 3.73 3.09 3.11 2.98 2.913.02 3.76 4.56 4.56 0.0540.045 1.36 0.213 0.227 0.009Strawberry Mountain OR 3.89 3.332.75 2.93 2.27 2.39 1.98 1.97 1.87 2.63 3.69 4.07 0.0500.042 1.26 0.197 0.210 0.008Three Sisters OR 4.47 3.95 3.613.72 3.11 3.11 3.00 2.913.03 3.79 4.60 4.57 0.0540.045 1.35 0.212 0.226 0.009Alpine 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 1.35 0.212 0.225 0.009Glacier Peak WA 4.16 3.72 3.423.75 2.91 3.16 2.88 3.143.33 3.90 4.42 4.43 0.0540.045 1.34 0.210 0.223 0.009Goat 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 1.34 0.210 0.224 0.009Mount 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 1.33 0.209 0.222 0.009Mount Rainier WA 4.42 3.96 3.644.65 3.06 3.69 3.30 3.503.40 4.11 4.66 4.66 0.0550.045 1.36 0.214 0.227 0.009North Cascades NP WA 4.10 3.69 3.43 3.74 2.93 3.20 2.93 3.233.45 3.93 4.39 4.38 0.0530.044 1.33 0.209 0.222 0.009Columbia RiverGorgeORWA 5.03 5.03 2.59 2.59 2.59 2.11 2.11 2.11 3.51 3.513.51 5.03 0.569 0.2314.85 1.05 0.217 0.205

## A PPENDIX 

## C 

# CALMET Parameter ValuesAppendix 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 dat a (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 ov erwater 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 m ap 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 co ordinate User Defined User Define

2 ZFACE Vertical cell face hei ghts (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 TTable 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 Breez e 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 St ep 1 field and obs User Defined 1.00E-06 5 RMAX1 Max surface over-land extrapol ation radius (km) User Defined 200 5 RMAX2 Max aloft over-land extrapol ation radius (km) User Defined 200 5 RMAX3 Maximum over-water extrapol ation radius (km) User Defined 200 5 RMIN Minimum extrapolat ion 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 terra in features (km) User Defined 12 5 XBBAR X coordinate of Beginning of each barrier User Defined 0Table 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 coastli ne (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 mixi ng 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 ob servations or from prognostic data 0 1 6 ITPROG 3D temps from obs or from prognostic data? 0 2

6 ITWPROG Option for overwater lapse rate s 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 fo r interpolations (km) 100 12 6 TGDEFA Default over-water c apping 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-w ater mixing height (m) 3000 3000
6 ZIMIN Minimum over-l and mixing height (m) 50 50
6 ZIMINW Minimum over-w ater mixing height (m) 50 50

## A PPENDIX 

## D 

# CALPUFF Parameter ValuesAppendix 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 Value a 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 c onditions modeled 0 0 2 23 MFOG Configure for FOG model output 0 0 2 24 MREG Regulatory default checks? (1 = Yes) 1 1Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. Input Group Group Description Sequence Variable Description Default Value a 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 height s 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 co mputational 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 FTable D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. Input Group Group Description Sequence Variable Description Default Value a 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 cu ticle 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 vertic al dispersion? (0 = No) 0 0 12 3 JSUP PG Stability class above mixed layer 5 5 12 4 CONK1 Stable dispersion c onstant (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 * 0.50Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. Input Group Group Description Sequence Variable Description Default Value a 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 mi xing height(minimum)(m) 100.0 100.0

12 39 ROLDMAX Previous Max mix ht/curr ent 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 s ource-species combinations 0

13 4 NPT2 Number of point sources with fully variable emission rates 0

13 Point Sources Point sources charac teristics User Defined

14 Area Source Area Sources Area sour ces characteristics User Defined

15 Volume Source Volume Volu me 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

## A PPENDIX 

## E 

# CALPOST Parameter ValuesAppendix 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 conc entrations; -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 Ri ng, 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 extincti on (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 coeffici ents (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

## A PPENDIX 

## F 

# Emission Rates and Stack ParametersPGE Boardman Unit 1 - Flue Gas Emissions Data PM10Speciation:----------------Filterable------------------------------Condensable------------Baseline Case - Existing OperationFlow(acfm)StackVelocity(ft/s)Temp.(°F)NOx(lb/hr)SO2(lb/hr)PM10(lb/hour)ElementalCarbon(lb/hour)PM Fine(lb/hour)PMCoarse(lb/hour)OrganicCarbon(lb/hour)InorganicAerosol(lb/hour)Non-SO2InorAersol(lb/hour)1. Existing Operation 2,159,900 95 293 3152.0 4943.1 176.20 1.74 45.40 58.90 14.00 56.10 0.00NOxControlled Outlet ConditionsFlow(acfm)StackVelocity(ft/s)Temp.(°F)NOx(lb/hr)SO2(lb/hr)PM10(lb/hour)ElementalCarbon(lb/hour)PM Fine(lb/hour)PMCoarse(lb/hour)OrganicCarbon(lb/hour)InorganicAerosol(lb/hour)Non-SO2InorAersol(lb/hour)1. Selective Catalytic Reduction (SCR) 2,173,000 95 293 869.0 4943.1 176.20 1.74 45.40 58.90 14.00 56.10 0.002. New Low NOxBurners with ModifiedOFA System2,159,900 95 293 1332.4 4943.1 176.20 1.74 45.40 58.90 14.00 56.10 0.00SO2Controlled Outlet ConditionsFlow(acfm)StackVelocity(ft/s)Temp.(°F)NOx(lb/hr)SO2(lb/hr)PM10(lb/hour)ElementalCarbon(lb/hour)PM Fine(lb/hour)PMCoarse(lb/hour)OrganicCarbon(lb/hour)InorganicAerosol(lb/hour)Non-SO2InorAersol(lb/hour)1. Wet Flue Gas Desulfurization (FGD) 1,823,200 60 136 3152.0 579.3 115.45 1.14 29.80 38.60 9.20 36.80 0.002. Semi-Dry Flue Gas Desulfurization(FGD)1,901,700 83 170 3152.0 869.0 115.45 1.14 29.80 38.60 9.20 36.80 0.00Notes:1) SO2based on no SO2to SO3conversion.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 Calpuf f modeling for the PGE Boardman fa cility, as submitted, includes:

1) A summary of the BART Modeling Prot ocol 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 resp ective 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 revi sed protocol is approved for use in the Determination or control evaluation phase of the BART analysis.

Phil

Philip Allen A Q Division Oregon DEQ 503.229.6904 allen.philip@deq.state.or.us

-----Original Message----- From: Don.Caniparoli@CH2M.com [ma ilto: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.He ndricks@pgn.com; Rick.Tetzloff@pgn.com; Steven.Anderson@pgn.com; natalie.liljenwall@ch2m.com Subject: Revised Protocol

Attached is the revised protoc ol 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 Sub j ect: RE: Revised Protocol CC: <Patty.Jacobs@state.or.us>, <Ray.Hendr icks@pgn.com>, <Ric k.Tetzloff@pgn.com>, <Steven.Anderson @ p g n.com>, <natalie.lil j enwall @ ch2m.com> Page 1 of 1 Message

2/12/2007 file://C:\Documents and Settin g s\e65404\Local Settin g s\Tem p \GW } 00001.HTMFrom: 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 Calpuf f BART Exemption modeling was developed by Eri Ottersburg (SLR, International) and Mary Beth Yansu ra (CH2M Hill), with input and review by Oregon DEQ. This file would be used in lieu of the defaul t 60 ppb value that was specified in the three-stat es BART Modeling Protocol. The ozone data incorporate d in the file was compiled from state and federal ozone monitors in the three state area. Af ter discussions with EPA Region 10, the Federal Land Managers (Forest Service, U.S. Fish and Wildli fe, 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 hesitat e to contact me.

Phil

Philip Allen AQ Division Oregon DEQ 503.229.6904 allen.philip@deq.state.or.usBoardman Plant Appendix G

110207 G-1 

## Appendix G Emissions Performance Analysis MemoBLACK & 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) a nalysis 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 thr ee criteria pollutants, Nitrogen Oxides (NO x ), Sulfur Dioxide (SO 2 ) and Particulate Matter (PM). Portland General Electric (PGE) has retained Black & Veatch (B&V) to perform the BART engineer ing analysis for this purpose.

The EPA guidelines for BART analyses outline presumpt ive limits of criteria pollutant emissions. The NO x presumptive limit applicable to such units is 0.23 lb/MMBTU and the SO 2 presumptive limit is 0.15 lb/MMBTU.

To support the selection of a feasible technol ogy, an evaluation of act ual continuous emissions monitoring system (CEMS) emissions data was pe rformed on plants with pollution controls for NO x and SO 2 . The emissions data were reported to the Environmental Protection Agency (EPA) by electric generator operators. This memora ndum 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/Selectiv e 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 per iods was performed for selected units. The evaluation was performed on NO x and SO 2 emissions data only since PM emission levels are typically not monitored continuously. Data per iods when the unit is in an outage, startup and shutdown were omitted from this analysis. Fo r 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 averageBLACK & VEATCH

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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 Hawt horne 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 fr om 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 aver aging period were provided.

A general summary of the differences and trend s observed from the evaluated CEMS data is provided below.

LNB The highest NO x 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 NO x 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 NO x 24-hour rolling average emissions ranged fr om 0.56 lb/MMBTU at Craig 3 to 0.27 lb/MMBTU at Springerville 1 and Monticello 3.

The NO x 30-day rolling average emissions ranged fr om 0.45 lb/MMBTU at Craig 3 to 0.16 lb/MMBTU at Bridgeport 3.BLACK & VEATCH

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The wide range of NOx emissions data observed in LNB/OFA performance is attributed to the type of boiler technology (wall-fired versus t angential) and also the vintage of the combustion technology installed at each unit. Tangential-fi red 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 NO x 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 Hawt horne 5 at 0.09 lb/MMBTU.

The highest NO x 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 oz one 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 fo r 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 NO x emission values. From the review, the 30-day rolling averages for WA Pa rish are all slightly lower than 0.05 lb/MMBTU, while for Springerville, the highest 30-day rolling av erage is 0.08 lb/MMBTU. While this data set was very limited (only 3 months), it shoul d be taken into account when developing the performance emission levels for the SCR option in the BART analysis.

SDA The highest SO 2 24-hour rolling average em issions were observed fo r 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

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However, the highest SO 2 30-day rolling average emissions do not follow the same trend with Craig 3, Holcomb 1 and Laramie River 3 regist ering maximum averages of 0.14, 0.16 and 0.21 lb/MMBTU, respectively. On the high-end, the Sp ringerville 1 maximu m average is 0.57 lb/MMBTU.

From the information on the vintage of technolog y, 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 availabl e at Craig 3 and Laramie River 3 provided by Babcock & Wilcox (B&W) have horizontal flow re actors with horizontal reagent slurry spray systems. Most current generation SDAs as in Ha wthorne 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 em issions 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 init ial 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 (f or each year; 2003, 2004, 2005, and 2006). Theresultant 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 se t was very limited (only 3 months), analysis of the 30-day rolling average data for this unit indi cated that the SDA with PJFF system was capable of controlling SO 2 emissions to below 0.12 lb/MMBTU dur ing the evaluated period. One of the factors that impacts SO 2 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 SO 2 emissions at a consistent level.

WFGD The highest SO 2 24-hour rolling average emissions ranged from 0.41 lb/MMBTU at Navajo 1 to 0.10 lb/MMBTU at Centralia 1.

The highest SO 2 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. Ther efore, the WFGD data for Laramie River 1 do not represent a true indication on the performance capabilit y of current WFGD technology.BLACK & VEATCH

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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 limit s for Boardman 1, CEMS data for pre-BART (i.e., current) operations at Boardman 1 were anal yzed 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 oper ations 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 re latively equivalent control technology equipment as the cases that are being analyzed in the BART process and the existing operational characteristics of Boardman 1, the recommend ed 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. Thes e quotations included expected post-BART NO x emissions levels for the LNB and LNB/OFA technol ogies. 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 NO x 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 averagesBLACK & VEATCH

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for LNB installations by B&W and Alstom in wall-fire d 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 Sp ringerville 1 have a max 30-day average of 0.16 and 0.21 lb/MMBTU, respectively. However, sinc e 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 NO x limits. The recommended 30- day limit for this combination is 0.23 lb/MMBTU.

The recommended 30-day NO x emission limit for the SCR case was based on the demonstrated performance of SCRs at the evaluated plants wi thin this memorandum. As evaluated, the sustainable outlet emission rate varies betwee n the plants. Only one unit maintains emissions below 0.07 lb/MMBTU. The limit recommended fo r Boardman 1 was based on the consideration that the SCR at Boardman will be a retrofit and a ll retrofit projects require operating margin on emission limits.

Lastly, for the FGD technologies, a comparison wi th 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 re commended 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 sm all degree of flexibility was added as owner’s margin to the general industry standard guar anteed emissions levels provided by equipment vendors. This was the primary reason why the typical control technology vendor performance guarantees for similar installations were not re commended 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 85Plant Pollutant Technologies OEM YearAir Permit Limit Averaging Period Contract Values/Boiler Max 1-hour Max 3-hour Max 24-hour Max 30-day 12-month % Increase CEMS Data Period (lb/MBtu) (lb/MBtu)Block Rolling Rolling Rolling Block 24-hr over 30-dayAnalyzedNOx 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 12 month average --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 30-day rolling avg --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 30-day rolling avg --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, SCR0.07 30-day rolling avg 0.07Plum Point NOx LNB, OFA, SCR0.09 24-hour rolling avg 0.07Holcomb Expansion NOx LNB, OFA, SCR0.07 3-hour rolling avg 0.06Big Stone 2 NOx LNB, OFA, SCR0.07 30-day rolling avg 0.05JK Spruce 2 NOx LNB, OFA, SCR0.05 30-day rolling avg 0.04SO2 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 FGD0.095 30-day rolling avg 0.095Plum Point SO2 Dry FGD0.16 3-hour rolling avg 0.1Holcomb Expansion SO2 Dry FGD0.10 3-hour rolling avg 0.09SO2 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 FGD0.10 30-day rolling avg 0.08JK Spruce 2 SO2 Wet FGD0.06 30-day rolling avg 0.06PM 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 n/a n/aOPPD Nebraska City 2 PM FF0.018 Test method avg 0.018Plum Point PM FF0.018 Test method avg 0.018Holcomb Expansion PM FF0.012 3-test run avg 0.011Big Stone 2 PM ???0.03 3-test run avg 0.015JK Spruce 2 PM FF0.022 3-test run avg 0.02CEMS Data (lb/MBtu)