Portland General Electric 

Boardman Plant 

Best Available Retrofit Technology (BART) /

Reasonable Progress Analysis 

Revision 3: Boardman 2020 Alternative 

Black & Veatch Project: 144449 

Black & Veatch File No.: 40.0000 

August 27, 2010 
Boardman Plant Table of Contents 

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Table of Contents 

Acronym List ................................................................................................................. AL1 

Executive Summary ........................................................................................................ ES1 

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

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

1.2 BART/Reasonable Progress Analysis Methodology ............................... 1-5 

1.2.1 Identify All Available Retrofit Control Technologies 

(Step 1) ...................................................................................... 1-6 

1.2.2 Eliminate Technically Infeasible Options (Step 2) ................... 1-6 

1.2.3 Evaluate Control Effectiveness of Remaining Control 

Technologies (Step 3) ................................................................ 1-6 

1.2.4 Evaluate Impacts and Document the Results (Step 4) ............... 1-7 

1.2.5 Evaluate Visibility Impacts (Step 5) .......................................... 1-9 

1.2.6 Selecting the Best Alternative ................................................... 1-9 

1.3 Reasonable Progress Analysis Methodology ........................................... 1-9 

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 ................... 2-3 

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

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

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

3.0 Identification of All Available Retrofit Emission Control Technologies 

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

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

3.1.1 Selective Catalytic Reduction .................................................... 3-1 

3.1.2 Selective Noncatalytic Reduction .............................................. 3-4 

3.1.3 SNCR/SCR Hybrid .................................................................... 3-5 

3.1.4 ECOTUBE ................................................................................. 3-7 

3.1.5 LoTOx ....................................................................................... 3-8 

3.1.6 Natural Gas Reburn ................................................................... 3-8 

3.2 SO2 Control Technologies ....................................................................... 3-9 

3.2.1 Wet Flue Gas Desulfurization ................................................. 3-10 

3.2.2 Semi-Dry Flue Gas Desulfurization ........................................ 3-12 

3.2.3 Circulating Dry Scrubber ........................................................ 3-15 

3.2.4 Dry Sorbent Injection .............................................................. 3-16 

3.2.5 Reduced Sulfur Coal Restriction ............................................. 3-17 
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3.3 PM Control Technologies ...................................................................... 3-17

3.3.1 Pulse Jet Fabric Filter .............................................................. 3-18 

3.3.2 Compact Hybrid Particulate Collector .................................... 3-20 

3.3.3 GE MAX-9 Hybrid .................................................................. 3-20 

3.3.4 Multiple-Cyclone Separators ................................................... 3-22 

3.3.5 Wet ESP ................................................................................... 3-22 

3.4 Emerging Pollution Control Technologies ............................................ 3-24 

3.4.1 PowerSpan ............................................................................... 3-25 

3.4.2 Enviroscrub .............................................................................. 3-26 

3.4.3 Phenix Clean Coal ................................................................... 3-27 

3.4.4 J-Power ReACT System .......................................................... 3-29 

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

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

4.1.1 ECOTUBE ................................................................................. 4-1 

4.1.2 LoTOx ....................................................................................... 4-1 

4.1.3 Natural Gas Reburn ................................................................... 4-1 

4.1.4 SNCR/SCR Hybrid .................................................................... 4-2 

4.2 Technically Infeasible SO2 Control Technologies .................................. 4-2 

4.2.1 Dry Flue Gas Desulfurization .................................................... 4-2 

4.2.2 Dry Sorbent Injection ................................................................ 4-2 

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

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

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

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

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

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 ................................................................................................. 4-5 

5.0 Evaluation of Technically Feasible Retrofit Emission Control 

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

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

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

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

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

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

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

6.2.3 Non-Air Quality Environmental Impacts .................................. 6-3 
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6.2.4 Existing Controls ....................................................................... 6-4 

6.2.5 Remaining Useful Life .............................................................. 6-4 

6.2.6 Time Necessary for Compliance ............................................... 6-5 

6.3 Cost-Effectiveness ................................................................................... 6-5 

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

6.4.1 NOx Control Technologies ...................................................... 6-12 

6.4.2 SO2 Control Technologies ....................................................... 6-13 

6.4.3 PM Control Technologies ........................................................ 6-13 

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

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

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

7.3 Control Technologies ............................................................................... 7-4 

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

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

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

8.2 Selection of SO2 BART ........................................................................... 8-2 

8.3 Selection of NOX BART .......................................................................... 8-4 

8.4 Reasonable Progress ................................................................................ 8-5 

8.5 Visibility Improvement for Combined BART Controls .......................... 8-5 

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

Appendix A Design Basis ............................................................................................ A1 

Appendix B Stack Outlet Conditions ........................................................................... B1 

Appendix C Design Concept Definitions .................................................................... C1 

Appendix D Cost Analysis Summary ........................................................................... D1 

Appendix E Visibility Modeling Results ...................................................................... E1 

Appendix F Visibility Modeling Protocol .................................................................... F1 

Appendix G Replacement Power Cost Analysis............................................G1 
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Table of Contents (Continued) 

Tables

Table ES-1 Oregon Regional Haze Plan Requirements for the Boardman 

Plant Boiler ..................................................................................................4 

Table 1-1 Boardman Plant Operational Characteristics ........................................... 1-2 

Table 1-2 Oregon Regional Haze Plan Requirements Applicable to the 

Boardman Plant Boiler ............................................................................. 1-4 

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

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

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

Table 4-1 Technically Feasible NOx Control Technologies .................................... 4-6 

Table 4-2 Technically Feasible SO2 Control Technologies ..................................... 4-7 

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

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

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

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

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

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

Table 6-1 BART/Reasonable Progress Impact Analysis and CostEffectiveness Results ............................................................................... 6-8 

Table 7-1 Visibility Impact and Improvement Summary ........................................ 7-5 

Table 7-2 Hells Canyon and Mount Hood Visibility Improvement Summary ........ 7-7 

Table 8-1 Visibility Impact Summary Boardman Plant BART 

Determination .......................................................................................... 8-6 

Figures

Figure 3-1 Schematic Diagram of a Typical SCR Reactor ........................................ 3-2 

Figure 3-2 Schematic of SNCR System with Multiple Injection Levels ................... 3-5 

Figure 3-3 ECOTUBE Installation in a Boiler .......................................................... 3-7 

Figure 3-4 Schematic of Gas Reburn System ............................................................ 3-9 

Figure 3-5 Process Flow Diagram of a Spray Tower Wet FGD System. ................ 3-10 

Figure 3-6 Cutaway View of a Jet Bubbling Reactor Wet FGD System ................ 3-11 

Figure 3-7 Spray Dryer System ............................................................................... 3-13 

Figure 3-8 SDA FGD System .................................................................................. 3-14 

Figure 3-9 Circulating Dry Scrubber System (Lurgi Lentjes North America) ........ 3-15 

Figure 3-10 Pulse Jet Fabric Filter Compartment (Babcock & Wilcox) ................... 3-19 

Figure 3-11 Max-9 Electrostatic Filter ...................................................................... 3-21 
Boardman Plant Table of Contents 

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Table of Contents (Continued) 

Figures (Continued) 

Figure 3-12 Multiple-Cyclone Particulate Collector ................................................. 3-22

Figure 3-13 ECO Process Flow Diagram (PowerSpan). ........................................... 3-25 

Figure 3-14 Pahlman Process Simplified Process Flow Diagram. ............................ 3-27 

Figure 3-15 Phenix Clean Coal Process Flow Diagram ............................................ 3-28 

Figure 3-16 J-POWER ReACT System .................................................................... 3-30 

Figure 6-1 NOx Control Cost-Effectiveness .............................................................. 6-9 

Figure 6-2 SO2 Control Cost-Effectiveness ............................................................. 6-10 

Figure 6-3 PM Control Cost-Effectiveness ............................................................. 6-11 
Boardman 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 

dv Deciview 

DCS Distributed Control System 

DEQ Department of Environmental Quality 

DSI Dry Sorbent Injection 

EPA Environmental Protection Agency 

EPRI Electric Power Research Institute 

ESP Electrostatic Precipitator 

EPC Engineering Procurement Construction 

FF Fabric Filter 

FGD Flue Gas Desulfurization 

ID Induced Draft 

IFGR Induced Flue Gas Recirculation 

LNB Low NOx Burners 

NLNB/MOFA New Low NOx Burners with Modified Overfire Air 

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

Selective Noncatalytic Reduction 

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

Selective Catalytic Reduction 

Mg(OH)2 Magnesium Hydroxide 

MMBtu or MMBtu Million (106) British Thermal Units 

MW Megawatt 

N2O5 Nitrogen Pentoxide 

NH3 Ammonia 

NOx Nitrogen Oxides 
Boardman Plant Acronym List 

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OFA Overfire Air 

O&M Operating and Maintenance 

PGE Portland General Electric 

PJFF Pulse Jet Fabric Filter 

PM Particulate Matter 

PRB Powder River Basin 

RSCR Reduced Sulfur Coal Restriction 

SCR Selective Catalytic Reduction 

SNCR Selective Noncatalytic Reduction 

Semi-Dry FGD Semi-Dry Flue Gas Desulfurization 

or SD Scrubber or SDFGD 

SO2 Sulfur Dioxide 

VOC Volatile Organic Compounds 

WESP Wet Electrostatic Precipitator 

WFGR Windbox Flue Gas Recirculation 
Boardman Plant Executive Summary 

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Executive Summary 

Introduction

Portland General Electric (PGE) believes that ceasing coal fired operations at the 

Boardman Plant in 2020 remains the best timeframe for achieving significant visibility 

improvements and reducing air pollution at a reasonable cost to our customers while 

maintaining reliable electric service. With that goal in mind, PGE is submitting the 

following BART analysis – our third complete analysis with respect to the Boardman 

Plant – addressing appropriate control technologies as well as areas of special concern 

previously expressed by the Department of Environmental Quality (DEQ) and the 

Environmental Protection Agency (EPA). 

While DEQ does not have the authority to impose a closure date on the Boardman 

Plant or a closure decision on PGE, the agency has the authority and latitude to make 

policy decisions that would allow development and implementation of a reasonable plan 

that combines installation of interim controls with plant closure or cessation of coal 

operations in 2020 to achieve Regional Haze standards. We look forward to working with 

the Department within that framework, and propose the control strategy described below 

as an appropriate, workable, and approvable means to achieve that goal. 

We should not lose sight of the fact that agreement on a responsible 2020 closure 

plan would represent a significant national precedent, defining a reasonable path for 

utilities to transition to non-coal fuel sources where appropriate rather than invest in 

expensive control solutions. We have a chance to create a powerful model of 

collaboration that could have a highly beneficial impact on air pollution in the United 

States, shaping national strategies for power plant emission reductions. 

Unfortunately, while we know that DEQ shares our intention of seeking an 

appropriate alternative to implementation of full controls and continued operation of the 

Boardman Plant through 2040, we believe the agency reached a number of invalid 

conclusions that render unworkable all three of the draft control options outlined by the 

agency on June 28. 

PGE already has a clear path to resolve all current emissions requirements for the

plant (defined in DEQ’s 2009 Regional Haze rule) and continue operation for at least the 

next 30 years. PGE and numerous customer and stakeholder groups agree, however, that 

a better solution for our customers and the environment would be possible if the DEQ 

rules allowed us to meet Regional Haze objectives through a combination of interim 

controls and an early termination of coal-fired operations. 

If an acceptable amendment to the 2009 rules cannot be achieved and the options 

described by DEQ are carried through as drafted in DEQ’s final rule amendments, our 
Boardman Plant Executive Summary 

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best and most responsible course of action remains full implementation of controls and 

continued operation of the plant through at least 2040. While extensive modeling 

confirms that the 2040 path would be a responsible, cost effective course of action to 

serve our customers, it would be unfortunate to lose this opportunity to achieve an even 

better outcome. 

This makes it imperative that DEQ’s final rule include a workable 2020 option. 

While we disagreed with DEQ’s conclusion that the 2020 plan we proposed in April 

could not be approved under EPA Regional Haze standards for Best Available Retrofit 

Technology, we have developed this new 2020 proposal to address the concerns raised by 

EPA and the DEQ in response to that proposal. We conducted additional analysis to 

respond to DEQ’s concerns, and we modified our proposal to capture additional interim 

control benefits, substantially reflecting DEQ’s suggested control options and EPA’s 

concerns about approvability. 

Specifically, our analysis below proposes operation on reduced sulfur coal, lowNOx burners, modified overfire air and selective non-catalytic reduction (SNCR) through 

2020 with a study of Dry Sorbent Injection (DSI) technology. Contingent on the results 

of testing, PGE would commit to meeting a 0.4 lb SO2/MMBtu limit through 2020 using 

DSI. If this option is considered BART, DEQ would need to provide a procedure for 

establishing an alternative SO2 limit based on the testing. The limit would be adjusted if 

PGE’s testing demonstrated that operation of DSI could not reach 0.4 lb SO2/MMBtu,

when operating in conjunction with SNCR and the mercury controls, without resulting in 

an increase in the hourly capacity to emit particulate matter or triggering PSD for PM2.5

(assuming the same level of operation currently reflected in the Boardman Plant’s plant 

site emission limits). 

While this proposal includes a closure requirement in 2020 that is clearly 

enforceable, one of the corollary advantages of the 2020 option is that it also allows 

sufficient time for an evaluation of whether the plant could be efficiently operated using a 

different, non-fossil fuel source. Of course, this would require a new permit, following a 

separate DEQ review.

It is important to emphasize that the BART recommendation below does not 

simply repeat our analysis from April 2010. While we have described all three of the 

draft options prepared by DEQ as unworkable for a variety of reasons, the analysis below 

offers a pragmatic strategy that essentially modifies DEQ’s 2018 option, adopting the 

core technology DEQ endorsed in that option and combining it with our earlier 2020 

proposal. The result will achieve greater SO2 emissions reductions within timeframe that 

allows the additional capital and operating expenditures to be cost effective, while 

allowing the flexibility to avoid unintended and environmentally harmful side effects. 
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The reason for going through this lengthy process is to achieve the best solution 

we can for our customers, one that balances environmental impacts with customer cost 

impacts. If we succeed, PGE will be well positioned to meet our customers’ needs today, 

while at the same time laying the groundwork for better supply options for Oregon’s and 

the nation’s energy future. 

Background

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

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

located near Boardman, Oregon, about 150 miles east of Portland. The plant obtained its 

construction authorization on February 27, 1975 from the Oregon Nuclear and Thermal 

Energy Council (NTEC).

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

Regional Haze Regulations and Guidelines for Performing Best Available Retrofit 

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

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

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

controls, where appropriate, for facilities that were not subject to the new source review 

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

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

existence prior to August 7, 1977. Because the Boardman Plant coal-fired boiler (the 

Boardman Plant boiler) 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.

On November 2, 2007, PGE submitted a BART analysis to DEQ evaluating the 

available NOx, PM and SO2 retrofit controls for the Boardman Plant boiler. This analysis 

assumed that the Boardman Plant boiler would operate for the rest of its physical life, i.e., 

until at least 2040. PGE noted that the analysis would require revision if it was 

determined that a shorter boiler life was appropriate. On December 1, 2008, the DEQ 

published its proposed BART determination for the Boardman Plant boiler. During the 

public comment period, PGE requested that DEQ consider allowing PGE to forego 

certain controls if the company committed to cease operation of the Boardman Plant 

boiler by dates certain.

On June 19, 2009, the Oregon Environmental Quality Commission (EQC) 

adopted the Oregon Regional Haze Plan (Regional Haze Plan). The Regional Haze Plan 

includes new regulations (OAR 340-223-0030) imposing NOx, SO2 and PM limitations 

reflective of BART and applicable to the Boardman Plant boiler. The NOx regulations 
Boardman Plant Executive Summary 

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require compliance by July 1, 2011 and the SO2 and PM regulations require compliance 

by July 1, 2014. The Regional Haze Plan also includes new regulations (OAR 340-223-

0040) imposing additional NOx limits reflective of the “Reasonable Progress” 

requirements of Clean Air Act Section 169A. The Reasonable Progress regulation 

requires compliance by July 1, 2017. These requirements are summarized below in 

Table ES-1.

Table ES-1 

Oregon Regional Haze Plan Requirements for the Boardman Plant Boiler 

Limit (Assumed Control*) 

Installation

Deadline Authority 

0.28 lb NOx/MMBtu - 30 day rolling average 

0.23 lb NOx/MMBtu - Annual average 

(Low-NOx Burners/Overfire Air) ** 

7/1/2011 BART 

0.12 lb SO2/MMBtu - 30 day rolling average 

0.012 lb PM/MMBtu - Average of source test runs 

(Semi-Dry Scrubber) 

7/1/2014 BART 

0.070 lb NOx/MMBtu (SCR) 7/1/2017 Reasonable Progress 

*BART constitutes emission limits and not specific controls. The assumed control is 

provided for illustrative purposes only. 

**If combustion controls do result in a showing of compliance by July 1, 2012 and DEQ 

grants an extension of the compliance deadline to July 1, 2014, the NOx limit changes to 

0.23 lb/MMBtu as a 30 day rolling average. 

In adopting these BART/Reasonable Progress requirements, the EQC and DEQ 

acknowledged PGE’s request for consideration of a compliance option that took into 

account an accelerated boiler shutdown, but stated that early closure would need to be 

addressed in future submittals. In Chapter 10 of the Regional Haze Plan, DEQ 

acknowledged that the cost of future greenhouse gas regulation in context with costs 

associated with the regional haze SO2 and NOx controls for the Boardman Plant boiler 

“could be significant and may require PGE to evaluate cost-benefit factors affecting the 

future of the Boardman Plant, as part of the Oregon Public Utility Commission Integrated 

Resource Plan process.” Regional Haze Plan at p. 155. In Chapter 12, DEQ also stated 

that “should PGE determine that the impact and cost of carbon regulations will require 

the closure of the PGE Boardman Plant, PGE may submit a written request to the 

Department for a rule change.” Regional Haze Plan at p. 202. Thus there was explicit 

recognition that PGE could petition DEQ for reconsideration of the BART and 

Reasonable Progress rules if external factors such as carbon regulation would result in 

early plant closure. 
Boardman Plant Executive Summary 

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On April 2, 2010, PGE petitioned the EQC to amend OAR 340-223-0030 and -

0040 in accordance with the invitation in the Regional Haze Plan. As the Department has 

acknowledged, DEQ has no authority under the BART requirements to require early 

closure of a plant. However, a source does have the ability to offer to accept a federally 

enforceable condition to cease plant operations by a date certain either to avoid BART 

(by the closure date being no later than 5 years after EPA approval of the Regional Haze 

Plan into the SIP) or to be accounted for in the BART determination itself. For example, 

EPA stated in the preamble to the BART implementation rules: 

“With regard to BART-eligible sources not being in operation 

for the duration of the program, a State, in making BART 

determinations, is explicitly directed by the CAA to account 

for the remaining useful life of a source.” 70 Fed. Reg. 39125 

(July 6, 2005) 

The remaining life of the plant is a separate and freestanding criterion as well as a 

component of the economic impacts analysis in the BART determination process. In its 

April 2, 2010 petition, PGE proposed to accept a 2020 plant closure date. PGE 

accompanied the petition with a complete BART analysis that took into account the 2020 

closure proposal and concluded that if the Boardman Plant closed in 2020, BART 

constitutes the use of reduced sulfur coal (for SO2 control) and new low NOx burners 

with modified overfire air (for NOx control). BART for particulate was the continued 

use of the electrostatic precipitator (ESP). 

On June 17, 2010, the EQC denied PGE’s petition and directed the Department to 

commence rulemaking to determine other alternatives to the current BART/RP 

requirements in the Regional Haze Plan. The Department has released a preliminary 

proposal for informal comment that would provide the following three options in addition 

to the existing rules: 

Table ES-2 

DEQ BART Revision Proposal 

 2011 NOx 2014 SO2 2017 NOx Closure Date 

Existing Rules NLNB/MOFA SD Scrubber SCR 2040+ 

DEQ Option 1 NLNB/MOFA/SNCR SD Scrubber --- 2020 

DEQ Option 2 NLNB/MOFA/SNCR DSI --- 2018 

DEQ Option 3 NLNB/MOFA --- --- 5 years after SIP 

approval (2016?) 
Boardman Plant Executive Summary 

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The new alternative options were supported by a draft BART analysis that PGE believes 

contains errors and incorrect assumptions that materially distort its conclusions. For that 

reason, PGE submitted comments by letter dated July 30, 2010 identifying the errors, 

oversights and incorrect assumptions contained in the Department’s BART analysis so 

that the proposed rule that is placed out on formal notice more accurately reflects the 

statutory BART process, EPA guidance and other regulatory requirements. 

This revised BART/Reasonable Progress analysis was undertaken in order to 

ensure that the agency record contains an accurate and comprehensive analysis of the 

BART options under consideration. In light of the significant errors in the Department’s 

BART analysis, PGE believes that it is compelled to submit an accurate BART analysis. 

This analysis agrees with the Department’s analysis in many key regards, but offers more 

comprehensive support for the ultimate conclusion. In other respects, PGE believes that 

the Department has failed to take into account critical costs and regulatory impacts 

associated with the BART options that it has evaluated. This BART analysis identifies 

those oversights and assesses the BART options in light of the full array of costs and 

regulatory impacts. For example, while specific legislation has not yet passed Congress, 

PGE believes that federal regulation of carbon from coal-fired power plants is likely and 

has therefore incorporated carbon costs in evaluating the future of the Boardman Plant in 

its Integrated Resource Plan (IRP) before the Oregon Public Utility Commission 

(OPUC). In addition, the Department’s analysis fails to take into account the impact and 

associated cost of the statutory requirement (ORS 757.020) for PGE to replace the 

generation represented by the Boardman Plant. PGE’s IRP analysis shows that the leastcost, least-risk option for its customers is for the Company to operate the Boardman Plant 

boiler for its full lifetime if the BART and Reasonable Progress controls are all installed. 

In response to requests from IRP stakeholders and OPUC staff, PGE conducted 

additional analysis that suggests that a better option for its customers, in terms of both 

cost and risk, could be to cease operations by the end of 2020. 

This BART analysis reflects the same data reviewed by the OPUC and reaches 

the conclusion that DEQ should revise the BART and Reasonable Progress regulations to 

include an option that contemplates a 2020 closure without the installation of a semi-dry 

scrubber or selective catalytic reduction. This analysis suggests that the options DEQ is 

proposing are not compliant with the BART/Reasonable Progress requirements under the 

Clean Air Act. Therefore, PGE is submitting this revised BART/Reasonable Progress 

analysis to request that DEQ revise the Regional Haze Plan accordingly. 

Basis of Analysis 

This analysis is broken into two sequential stages. First, BART was determined 

based on the Boardman Plant boiler as it currently exists in accordance with the five-step 
Boardman Plant Executive Summary 

082710 ES-7 

process identified in the EPA’s Regional Haze Regulations and Guidelines for 

Performing BART Determinations (40 CFR Part 51, Appendix Y). Second, Reasonable 

Progress controls were analyzed based on the Boardman Plant boiler configuration once 

the boiler is compliant with the BART emission limits. Both analyses were conducted 

assuming that the Boardman Plant boiler will cease operations by the end of 2020. 

The steps followed in the BART and Reasonable Progress analyses were 

consistent with the requirements of Clean Air Act Section 169A. In Step 1, available 

NOx, SO2, and PM retrofit control technologies were identified for the Boardman Plant 

boiler. In Step 2, this list was shortened by eliminating those technologies that are not 

technically feasible. In Step 3, the control effectiveness of each technically feasible 

control technology was evaluated. Based on this evaluation, the technologies were 

ranked in order of effectiveness. In Step 4, the cost, energy, and environmental impacts 

were evaluated for each technically feasible control technology. As mandated by the 

Clean Air Act the remaining life of the plant was considered as a stand-alone factor. The 

Reasonable Progress analysis built upon the BART analysis and added the additional 

analytical step of considering the time necessary for compliance. In the final step of the 

BART analysis, the visibility improvements associated with the top-ranked options were 

evaluated consistent with the modeling protocol approved by DEQ on January 18, 2007 

and amended on August 28, 2007. Visibility improvement is not one of the 

considerations mandated by the Clean Air Act for the Reasonable Progress analysis. 

The conclusions drawn from these analyses are summarized below. 

NOx BART Control Selection 

PGE believes that the BART NOx determination reflected in OAR 340-223-

0030(1)(a) should generally be maintained, although PGE believes there is a reasonable 

basis in light of new information to merit the requirement to install selective non-catalytic 

reduction (SNCR) by July 1, 2014 with a resulting decrease in NOx emissions to 0.19 

lb/MMBtu. PGE is in the process of installing new low NOx burners and a modified 

over-fire air system on the Boardman Plant boiler for NOx control. These controls are 

expected to enable the Boardman Plant boiler to meet the BART NOx limits in OAR 340-

223-0030(1)(a) by July 1, 2011. These technologies are expected to reduce the NOx

emission levels for the Boardman Plant boiler from a baseline level of 0.43 lb 

NOx/MMBtu to 0.23 lb NOx/MMBtu (annual average).

PGE believes that the NOx reductions attributable to SNCR should also be 

considered as a component of the BART requirements. Under the current BART 

regulations, SNCR was considered as an additional interim control measure in the event 

that the combustion controls are not capable of achieving the BART NOx limits currently 
Boardman Plant Executive Summary 

082710 ES-8 

in the Regional Haze Plan. However, if, as anticipated, the combustion controls alone 

reach the current BART NOx limits, then SNCR could potentially enable the Boardman 

Plant to further reduce NOx emissions to as low as 0.19 lbs/MMBtu (annual average). 

Therefore, PGE concluded that if the Boardman Plant operates until 2020 then the NOx 

reductions associated with employing SNCR should be the basis for setting more 

restrictive BART NOx limits in the event that the combustion controls achieve the NOx

limits in OAR 340-223-0030(1)(a). 

In conclusion, PGE suggests that the Department retain the current BART NOx

limits and deadlines in OAR 340-223-0030(1)(a), add the requirement to control NOx to 

0.19 lb/MMBtu (annual average) by July 1, 2014 and add a requirement accelerating the 

Boardman Plant boiler closure date to 2020. 1

SO2 BART Control Selection 

Based on this revised analysis, PGE believes that the BART SO2 requirements 

should be revised to require conditions not considered in the previous BART analysis. 

The Boardman Plant boiler already utilizes exclusively low sulfur coal so as to minimize 

SO2 emissions . The prior BART analysis considered only post-combustion controls, all 

of which carry with them significant impacts. The Regional Haze Plan BART SO2 limits 

are currently based on the 2014 installation of semi-dry scrubbers. No controls beyond 

continued use of low sulfur coal and operation of the scrubbers were considered 

necessary as a result of the Reasonable Progress analysis. PGE has reassessed its BART 

analysis for the Boardman Plant boiler to include coal sulfur limits combined with a pilot 

study of Dry Sorbent Injection (DSI) that could provide additional SO2 emissions 

reductions.

For reasons stated in this report, PGE believes that DSI for SO2 control in a boiler 

of the size and configuration of the Boardman boiler, is not technically feasible as a 

BART control.2 However, PGE recognizes that DSI offers promise as a technology for 

1

 PGE is currently exploring the potential to repower the Boardman Plant boiler utilizing alternative 

fuels. At this time such fundamental changes are still in the conceptual phase and there is no certainty that 

they will be technically feasible. Therefore, the potential to repower the boiler using an alternative fuel 

such as biomass is not addressed in this analysis. However, if such an innovative repowering alternative 

were identified, PGE respectfully requests that the Department be willing to reevaluate its Regional Haze 

plan to enable such an innovative strategy. 

2

 In order for a technology to be considered “technically feasible,” EPA has stated that it must both be 

“available” and “applicable.” 70 Fed. Reg. 39165. A technology is considered available if it has reached 

the licensing and commercial sales stage of development. For example, technologies in the pilot-scale

testing stages of development are not considered available. The fact that a technology is considered 

available is not a sufficient basis for concluding that a technology is applicable, and, therefore, technically 

feasible. That technology must have been used in the same or a substantially similar source type to be 

considered applicable. Because DSI has never been utilized on a boiler of the type and size of the 

Boardman Plant boiler, it cannot be considered “applicable” even if it were considered “available.” 
Boardman Plant Executive Summary 

082710 ES-9 

short-term reductions of SO2. In light of DSI’s status as a potential short-term 

technology, PGE is willing to commit to a pilot study to determine the effectiveness of 

DSI on the removal of SO2 at Boardman. The pilot study would determine the 

effectiveness of the removal as well as the DSI reagent’s impact to mercury control, 

boiler operations, and its ability to be permitted in compliance with all regulatory 

requirements (e.g., New Source Review). 

Consideration of implementation of reduced sulfur coal limits and the DSI pilot 

study beginning in 2014, in conjunction with a requirement to cease operation of the 

Boardman Plant boiler in 2020, presents a compelling alternative to the current BART 

requirements in OAR 340-223-0030(1)(b). For the reasons summarized below, when this 

BART alternative is considered, a BART requirement to meet 0.12 lb/MMBtu SO2 (i.e., 

the addition of semi-dry scrubbers) in 2014 based on operation of the Boardman Plant 

boiler through 2040 cannot be justified. Therefore, the current requirement in OAR 340-

223-0030(1)(b) should be replaced with regulatory language requiring that the Boardman 

Plant boiler reach a SO2 limit of 0.4 lb/MMBtu in 2014 contingent on the successful DSI 

pilot study that will be conducted commencing in late 2011 once the combustion controls 

and mercury controls are operational. If the pilot test shows that the combination of 

reduced sulfur coal and DSI cannot reach a SO2 limit of 0.4 lb/MMBtu while operating in 

conjunction with all other controls, DEQ will provide a procedure for establishing an 

alternative SO2 limit that is no higher than 0.6 lb/MMBtu. Inability to permit the DSI 

system such that the plant can operate at maximum levels without additional particulate 

control equipment would be a basis for resetting the SO2 limit. 

The statutory factors do not support requiring semi-dry scrubbers as BART 

controls if the Boardman Plant boiler is required to reduce its permitted SO2 emissions 

limit by 67 percent in 2014 and also to cease operation no later than December 31, 2020. 

Clean Air Act section 169A(g)(7) requires that in establishing BART, DEQ consider the 

cost of compliance, the energy and non-air quality environmental impacts of compliance, 

the remaining useful life of the source, existing pollution control technology at the source 

and the degree in improvement in visibility which may reasonably be anticipated to result 

from the use of a technology. 

The energy and non-air quality impacts of semi-dry scrubbing support the 

conclusion that the technology should not be required as a BART control. Semi-dry 

scrubbing has impacts that are more severe than those associated with the use of reduced 

sulfur coal alone. Semi-dry scrubbing requires additional fans, pumps and other 

electrical equipment that consume considerable energy, reducing the efficiency of the 

plant. In addition, the non-air quality environmental impacts, including water usage and 

waste disposal, are material. The best means of controlling SO2 emissions is to not emit 

it in the first place. By converting from low sulfur coal to reduced sulfur coal, the 
Boardman Plant Executive Summary 

082710 ES-10 

Boardman Plant boiler is able to eliminate 50 percent of its allowable SO2 emissions 

without creating additional energy or environmental impacts. When this control 

technique is combined with the DSI pilot study and premature closure of the Boardman 

Plant boiler in 2020, there is no sound basis for requiring semi-dry scrubbing as a BART 

control technology. 

The cost of compliance criterion similarly does not support requiring semi-dry 

scrubbing as a BART control in light of PGE’s proposed reduced sulfur coal 

restriction/DSI pilot study/premature closure BART alternative. Semi-dry scrubbing 

would require a capital investment of approximately $270 million and an operating cost 

of approximately $13.9 million per year.3 These costs are based on new site specific data 

developed by Sargent & Lundy (“S&L”) for PGE and previously submitted to the 

Department. S&L’s detailed analysis shows that the costs previously assigned to semidry scrubbing understated the true cost of cost of control by approximately 30 percent. 

Since the SO2 control equipment would only be operated for 6.5 years, cost effectiveness 

values for semi-dry scrubbing would be approximately $14,191 per ton when all of the 

costs associated with this option are considered (e.g., power replacement costs).4

Reducing the SO2 permit limit to 0.4 lb/MMBtu by utilizing reduced sulfur coal and DSI 

(subject to the results of a pilot study) imposes capital and operational costs as well as 

additional risk because of the limited availability of coal mines that offer reduced sulfur 

coals, the substantial projected increase in low sulfur coal demand and the cost associated 

with the DSI reagent. However, these capital and operational costs, while material, are 

significantly lower than the capital and operational costs associated with semi-dry 

scrubbing. Due to the high capital costs for this technology, addition of semi-dry 

scrubbing would require an unreasonable investment in light of the short period that it 

would be operational.5

3

 In the Regional Haze Plan, DEQ already documented its conclusion that for multiple reasons wet 

scrubbing is not an appropriate BART technology for the Boardman Plant. That conclusion is not revisited 

here as nothing about the analysis has changed. 

4

 In Table 12 of the Statement of Need and Fiscal and Economic Impact (“DEQ Impact Statement) 

prepared by the Department and evaluating the cost of its proposed BART rule, the Department identifies 

the hundreds of millions of dollars of replacement power cost associated with each of the alternatives

proposed. Thus the DEQ Impact Statement recognizes the reality that PGE is required by statute to provide 

power to its customers. Therefore, if one asset is closed early, there is a commensurate cost of replacing 

that power using other means. While many means exist, the means evaluated in this analysis and 

referenced in the DEQ Impact Statement assumed that the least cost means of reliably replacing base load 

power would be construction of a combined cycle natural gas fired generating facility. This is also the 

assumption relied upon in the IRP process and that was reviewed by the PUC. 

5

 Because the economic impacts of semi-dry scrubbing are well over $10,000, there is no question that 

it exceeds the cost-effectiveness threshold. However, we note that even if one considers exclusively the 

capital and operating cost, at a $6,523/ton direct cost and $8,929/ton incremental cost, the cost of control is 

still excessive. Although the Department has suggested that $7,300/ton is an appropriate cost-effectiveness 

threshold, this value is not supported by EPA precedent or precedent within any other state. The 

Department attempts to justify an alternative approach that relies on summing the impacts to all Class I 
Boardman Plant Executive Summary 

082710 ES-11 

Consideration of the remaining useful life of the Boardman Plant also supports the 

conclusion that DEQ should not require BART SO2 emission limits more stringent than 

the 67 percent reduction proposed by PGE based on the use of reduced sulfur coal and the 

DSI pilot study. Section 169A of the Clean Air Act mandates that DEQ take into account 

the remaining useful life of the source as a criterion coequal with the other factors (e.g., 

visibility improvement). The EPA Guidelines suggest accounting for remaining useful 

life as a component of the cost of compliance. This has been done in the assessment 

summarized above. However, Congress expressly identified the remaining useful life of 

the plant as a criterion distinct and separate from the cost of compliance criterion. The 

Department recognized in the Regional Haze Plan that it would not be appropriate to 

require costly scrubbers if the Boardman Plant boiler were required to cease operation 

prematurely. See, e.g., Regional Haze Plan at 155-156. This conclusion is even more 

compelling when the proposed 67 percent reduction in allowable SO2 emissions is 

considered. 

Improvement in visibility provides only minimal support for requiring semi-dry or 

wet scrubbing when contrasted to the imposition of a reduced sulfur coal restriction, DSI 

pilot study, and premature closure. Utilization of scrubbers would reduce the 98th 

percentile visibility impacts at Mt. Hood 1.38 deciview (“dv”). Utilization of reduced 

sulfur coal and DSI such that emissions are limited to 0.40 lb/MMBtu will reduce the 

98th percentile visibility impacts at Mt. Hood by 0.89 dv. Closure of the Boardman Plant 

in December 2020 will reduce the 98th percentile visibility impacts by approximately 5.0 

dv. The limited additional improvement in visibility resulting from the use of semi-dry 

scrubbers is insufficient to overcome the other impacts associated with semi-dry 

scrubbers. Even this limited additional improvement associated with semi-dry scrubbers 

pales in comparison to the long term benefits associated with closure of the plant by the 

end of 2020. As noted, if SO2 scrubbers were required, the time necessary to recover the 

cost would likely compel operation of the plant and the scrubbers for their full useful life. 

The marginal benefits of requiring semi-dry scrubbing as opposed to reduced sulfur coal 

and DSI are limited. When those limited benefits are compared to the long term benefit 

of closing the plant early and eliminating visibility impacts on all days after December 

31, 2020, this factor weighs in favor of replacing the current BART SO2 emissions limit 

with a limit based on reduced sulfur coal, DSI pilot study, and closure no later than 

December 31, 2020. 

areas. However, this approach artificially inflates the visibility impact and is inconsistent with how the 

Department evaluates its own performance in reaching the state-wide visibility goals. In that context, DEQ 

evaluates each Class I area separately in relation to that Class I area’s unique rate of progress metric. EPA 

has also previously stated that a $/dv metric is not particularly useful and EPA cautioned the state of 

Nebraska against relying on this metric in preparing a visibility SIP. 
Boardman Plant Executive Summary 

082710 ES-12 

Based on this analysis, scrubbers should not be considered as BART if PGE 

agrees to (1) utilize reduced sulfur coal, (2) initiate a DSI pilot study, and (3) cease 

operation of the Boardman Plant boiler no later than December 31, 2020. 

Particulate (PM) Control Selection 

The Boardman Plant is already fitted with a cold-side ESP, which removes over 

99 percent of PM from the flue gas. Considering the current baseline rate of 0.017 lb 

PM/MMBtu, none of the feasible control technologies were cost effective. Although a 

pulse jet fabric filter (PJFF), a COHPAC system, or a Wet ESP, in combination with the

existing ESP, could achieve the PM emission limit of 0.012 lb/MMBtu currently reflected 

in the Regional Haze Plan, the cost effectiveness for these three technologies is $192,000, 

$186,000, and $350,000 per ton PM, respectively. These cost effectiveness values are 

unreasonably high. Therefore, none of these controls should be the basis for BART or 

Reasonable Progress PM limits more stringent than what is already required in the 

Boardman Plant permit. This conclusion is further supported if the requirement is added 

to the regulations that PGE cease operation of the Boardman Plant boiler no later than 

December 31, 2020. 

Reasonable Progress Analysis 

PGE does not believe that there is any basis for imposing additional controls 

under the Department’s Reasonable Progress authority if a federally enforceable limit is 

added to the Boardman Plant’s Title V permit requiring closure by December 31, 2020. 

The overall benefits of premature closure of the Boardman Plant in assisting Oregon 

reach its Congressionally mandated visibility improvement goals cannot be overstated. 

Congress requires that visibility be restored to natural conditions by 2064. In order to 

ensure that the state complies with the Clean Air Act, EPA requires that Oregon identify 

the baseline visibility conditions, the visibility impacts associated with natural conditions 

and the uniform rate of progress necessary to get from the baseline to natural conditions. 

Oregon must then demonstrate to EPA how it intends to reach the periodic milestones so 

as to ensure compliance. For example, based on the 20 percent worst days, DEQ must 

reduce visibility impacts at Mount Hood from 14.9 dv to 8.4 dv by 2064. The next 

uniform rate of progress milestone is to achieve a reduction of 1.5 dv by 2018. The 

BART requirements that PGE is proposing will result in a 98th percentile reduction in 

visibility impacts at Mount Hood of 1.9 dv by 2014. In other words, the Boardman Plant 

emission reductions alone will achieve 127 percent of the required reduction and do so 

four years ahead of schedule. By committing to close the Boardman Plant, PGE will 

enable Oregon to achieve more than 60 percent of the visibility improvement needed by 
Boardman Plant Executive Summary 

082710 ES-13 

2064. In other words, based on the 98th percentile baseline impacts, closure of the 

Boardman Plant in 2020 by itself will enable Oregon to achieve the visibility 

improvements required to be achieved by 2051 more than 30 years early (i.e., in 2020). 

This analysis confirms that there is no basis for requiring additional controls based on 

Reasonable Progress if the Boardman Plant is required to close by December 31, 2020.
Boardman Plant Introduction and Objectives 

082710 1-1 

1.0 Introduction and Objectives 

 The objective of this report is to provide the technical, regulatory and statutory 

basis for requested revisions to the regulations adopted as part of the Regional Haze Plan, 

in light of changes in critical assumptions that have arisen since the Boardman Plant 

boiler was first assessed. When the Environmental Quality Commission (EQC) adopted 

the Regional Haze Plan in 2009, the Oregon Department of Environmental Quality 

(DEQ) stated that it would reevaluate and resubmit to the EQC its BART/Reasonable 

Progress conclusions if critical assumptions changed and PGE submitted a new 

BART/Reasonable Progress analysis. This document is in response to that agency 

commitment. This report documents the basis for requested changes to the BART 

regulations (OAR 340-223-0030) and Reasonable Progress regulations (OAR 340-223-

0040) currently applicable to the Boardman Plant boiler. 

1.1 Source Description and Background 

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

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

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

Leasing BSC, LLC (15%). The Boardman Plant was issued its construction authorization 

from the Nuclear and Thermal Energy Council on February 27, 1975 and an Air 

Contaminant Discharge Permit from the DEQ on April 6, 1977. As part of the permitting 

process, PGE performed extensive modeling to demonstrate that the plant would operate 

in compliance with the ambient air quality standards. PGE also agreed to implement 

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

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

the use of LNB and OFA to reduce NOx emissions. These control technologies were 

considered Best Available Control Technology (BACT).

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

River Basin (PRB) coal. A summary of the operational characteristics are noted in 

Table 1-1. A detailed design basis of the Boardman Plant is included in Appendix A. 
Boardman Plant Introduction and Objectives 

082710 1-2 

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 5,7936

Type of Boiler/Manufacturer Opposed-wall/Foster Wheeler

Steam Cycle Subcritical 

Draft of Boiler Balanced 

Existing Emissions Controls 

SO2 (Pre-combustion Controls - Coal 

Type)

Low-sulfur coal 

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

PM (Post-combustion Controls) Cold-side ESP 

While 5793 MMBtu/hr is considered the nominal boiler heat input, the maximum boiler heat 

input is roughly 6400 MMBtu/hr, based on an evaluation of CEMS data from 1997 to 2008 for 

the maximum 30-day average heat input value of the boiler.

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

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

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

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

was to require controls, where appropriate, for facilities that were not subject to the new 

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

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

and that were in existence prior to August 7, 1977. 

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

review requirements of the 1977 Clean Air Act Amendments, DEQ 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 

6 While 5793 MMBtu/hr is considered the nominal boiler heat input, the maximum boiler heat input is 

roughly 6400 MMBtu/hr, based on an evaluation of CEMS data from 1997 to 2008 for the maximum 30-

day average heat input value of the boiler.
Boardman Plant Introduction and Objectives 

082710 1-3 

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

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

considered “in existence” if

“the owner or operator has obtained all necessary 

preconstruction approvals or permits required by Federal, 

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

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

continuous program of physical on-site construction of the 

facility or (2) entered into binding agreements or contractual 

obligations, which cannot be cancelled or modified without 

substantial loss to the owner or operator, to undertake a 

program of construction of the facility to be completed in a 

reasonable time.” 40 CFR 51.301 

DEQ determined that the Boardman Plant had obtained all necessary 

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

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

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

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

On November 2, 2007, PGE submitted a BART analysis to DEQ evaluating the 

available NOx, SO2, and PM retrofit controls for the Boardman Plant. This analysis 

assumed that the Boardman Plant would operate for the rest of its physical life, i.e., until 

at least 2040. PGE noted that the analysis would require revision if it was determined 

that a shorter plant life was appropriate. On December 1, 2008, the Department 

published its proposed BART determination for the Boardman Plant. During the public 

comment period, PGE requested that DEQ consider allowing PGE to forego certain 

controls if the company committed to cease operation of the Boardman Plant boiler by 

dates certain.

On June 19, 2009, the EQC adopted the Regional Haze Plan. The Regional Haze 

Plan includes new regulations (OAR 340-223-0030) imposing NOx, SO2 and PM 

limitations reflective of BART and applicable to the Boardman Plant boiler. The NOx

regulations require compliance by July 1, 2011 and the SO2 and PM regulations require 

compliance by July 1, 2014. The Regional Haze Plan also includes new regulations 

(OAR 340-223-0040) imposing additional NOx limits reflective of the “Reasonable 

7

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

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

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

082710 1-4 

Progress” requirements of Clean Air Act Section 169A. These requirements are 

summarized below in Table 1-2.

Table 1-2 

Oregon Regional Haze Plan Requirements Applicable to the 

Boardman Plant Boiler 

Limit (Assumed Control)* 

Installation

Deadline Authority 

0.28 lb NOx/MMBtu—30 day rolling average 

0.23 lb NOx/MMBtu—annual average 

(Low-NOx Burners/Overfire Air) ** 

7/1/2011 BART 

0.12 lb SO2/MMBtu—30 day rolling average 

0.012 lb PM/MMBtu—average of source test runs 

(Semi-Dry Scrubber) 

7/1/2014 BART 

0.070 lb NOx/MMBtu (SCR) 7/1/2017 Reasonable 

Progress

*BART constitutes emission limits and not specific controls. The assumed control is provided 

for illustrative purposes only. 

**If combustion controls do result in a showing of compliance by July 1, 2012 and DEQ 

grants an extension of the compliance deadline to July 1, 2014, the NOx limit changes to 

0.23 lb/MMBtu as a 30 day rolling average. 

In adopting the BART/Reasonable Progress requirements in the Regional Haze 

Plan, the EQC and DEQ acknowledged PGE’s request for consideration of a boiler 

shutdown, but stated that early closure would need to be evaluated in response to future 

submittals. In Chapter 10 of the Regional Haze Plan, DEQ acknowledged that the cost of 

future greenhouse gas regulation in context with costs associated with the regional haze 

SO2 and NOx controls for the Boardman Plant “could be significant and may require PGE 

to evaluate cost-benefit factors affecting the future of the Boardman Plant, as part of the 

Oregon Public Utility Commission Integrated Resource Plan process.” Regional Haze 

Plan at p. 155. In Chapter 12, DEQ also stated that “should PGE determine that the 

impact and cost of carbon regulations will require the closure of the PGE Boardman 

Plant, PGE may submit a written request to the Department for a rule change.” Regional 

Haze Plan at p. 202. Thus there was explicit recognition that PGE could petition DEQ 

for reconsideration of the BART and Reasonable Progress rules if external factors such as 

carbon regulation would result in early plant closure. 

This revised BART/Reasonable Progress analysis was undertaken in response to 

DEQ’s express commitment to consider a change to the BART and Reasonable Progress 

requirements. While specific legislation has not yet passed Congress, PGE believes that 
Boardman Plant Introduction and Objectives 

082710 1-5 

federal regulation of carbon from coal-fired power plants is likely and has therefore 

incorporated carbon costs in evaluating the future of the Boardman Plant in its Integrated 

Resource Plan (IRP) before the Oregon Public Utility Commission (OPUC). PGE’s IRP 

analysis shows that the least-cost least-risk option for its customers is to operate the 

Boardman Plant boiler for its full lifetime if all of the BART and Reasonable Progress 

controls are installed. In response to requests from IRP stakeholders and OPUC staff, 

PGE has recently conducted additional analysis in the IRP that suggests that a better 

option for its customers, in terms of both cost and risk, could be to cease operations by 

the end of 2020; this option would require DEQ to revise the BART and Reasonable 

Progress regulations to allow PGE, as an alternative to the present regulations in OAR 

340-223-0030 and -0040,) to install NLNB/MOFA by July 1, 2011, meet a 0.40 lb 

SO2/MMBtu limit by July 1, 2014 (subject to DSI pilot testing) and cease Boardman 

Plant operations by December 31, 2020. PGE is submitting this revised 

BART/Reasonable Progress analysis to document that this suite of limits meets the 

BART/Reasonable Progress requirements of the Clean Air Act and to request that DEQ 

revise the Regional Haze Plan accordingly. 

The methodology used for this BART and Reasonable Progress analysis follows 

closely that used in the November 2, 2007 submittal. The steps followed are summarized 

below.

1.2 BART/Reasonable Progress Analysis Methodology

In its BART Guidelines, EPA outlined an engineering, economic, and visibility 

modeling analysis to identify the best method of retrofit emission reduction for pollutants 

that cause visibility impacts in federal Class I areas (NOx, SO2, and PM). To identify the 

best method of emission reduction, data are collected through a five step process to arrive 

at a selection of the best methods of emissions reduction of NOx, SO2, and PM at the 

BART source. The five steps followed to develop information for making the BART 

determination are the following: 

1. Identify all available retrofit control technologies. 

2. Eliminate technically infeasible options. 

3. Evaluate control effectiveness of remaining control technologies. 

4. Evaluate impacts and document the results. 

5. Evaluate visibility impacts. 

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

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

for installation at the source. The first four of these steps are shared by the Reasonable 

Progress analysis; the Clean Air Act does not identify visibility impacts as an evaluative 
Boardman Plant Introduction and Objectives 

082710 1-6 

criterion for identifying Reasonable Progress controls. The Clean Air Act identifies an 

additional step, evaluation of the time necessary for compliance, that is not identified for 

BART. Each of these steps is further explained in the following subsections. 

1.2.1 Identify All Available Retrofit Control Technologies (Step 1) 

 The first step of the BART/Reasonable Progress analysis is to identify all 

available retrofit control technologies. A control technology is considered as an available 

retrofit if it has practical potential for application to the BART-eligible source. The 

technology considered can be a method, system, or a combination of both options for 

control of a pollutant. Technologies that have been successfully applied to similar 

sources with similar gas stream characteristics are considered available. However, 

technologies that have not been applied to full scale operations are not considered 

available. Since the Boardman Plant boiler is equipped with existing control 

technologies, the control options evaluated included improvements or optimization of the 

existing control technologies. Section 3.0 addresses the requirements of Step 1 of the 

BART/Reasonable Progress analysis. 

1.2.2 Eliminate Technically Infeasible Options (Step 2) 

 Step 2 of the BART/Reasonable Progress analysis involves the evaluation of all 

the identified available retrofit control technologies to determine technical feasibility. A 

control technology is technically feasible if it has been previously installed and operated 

successfully at a similar type of source or if there is technical agreement that the 

technology can be applied to the source. Two terms, available and applicable, are used to 

define the technical feasibility of a control technology. A technology that is being 

offered commercially by vendors or is in commercial demonstration or licensing is 

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

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

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

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

BART/Reasonable Progress analysis. 

1.2.3 Evaluate Control Effectiveness of Remaining Control Technologies 

(Step 3) 

 Once all the technically feasible control technology alternatives are identified in 

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

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

and expressed both in terms of tons per year of post-control emissions and pounds of 
Boardman Plant Introduction and Objectives 

082710 1-7 

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

obtained by considering regulatory decisions or evaluations that have been performed on 

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

data are technology performance data provided by manufacturers (usually in the form of 

performance guarantees), engineering estimates, and demonstrated effectiveness of the 

technology at existing operating sources. The most stringent level of control 

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

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

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

for Step 3 of the BART/Reasonable Progress analysis.

1.2.4 Evaluate Impacts and Document the Results (Step 4) 

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

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

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

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

The impact analyses performed are: 

x Costs of compliance. 

x Energy impacts. 

x Nonair quality environmental impacts. 

x Existing pollution control technology (BART only). 

x Time necessary for compliance (Reasonable Progress only).

x Remaining useful life. 

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

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

and operating annual costs are estimated based on established design parameters, and 

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

the estimated quantity of pollutant removed (tons/year) to determine the costeffectiveness ($/tons) of each control technology. Establishing cost-effectiveness allows 

the evaluation of different control technologies on an economic basis for potential 

elimination from further consideration. Consistent with the EPA’s directive, two types of 

cost-effectiveness are considered in this BART/Reasonable Progress analysis: average 

and incremental cost-effectiveness. The average cost-effectiveness is defined as the total 

annualized cost of control divided by the annual quantity of pollutant removed for each 

control technology. The incremental cost-effectiveness is a comparison of the cost and 

performance level of a control technology to the next most stringent option. It has a unit 

of $/incremental ton removed. The incremental cost-effectiveness is a good measure 
Boardman Plant Introduction and Objectives 

082710 1-8 

when comparing technologies that have similar removal efficiencies. Consistent with 

EPA guidance issued in relation to Best Available Control Technology determinations, 

cost of compliance is not necessarily evaluated for technologies that are considered 

acceptable to PGE. 

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

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

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

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

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

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

path. The cost of these energy impacts includes additional fuel cost and/or the cost of 

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

implementation of the technology. 

 The third impact analysis evaluates the nonair quality environmental impacts. 

Nonair quality environmental impacts are evaluated to determine whether a particular 

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

positive or negative. An example of a negative nonair quality environmental impact is 

the generation of wastewater discharge and solid waste.

 The fourth impact analysis evaluates the existing pollution control technology. 

This particular factor is identified by the Clean Air Act only in relation to the BART 

analysis. However, the Reasonable Progress analysis is conducted to determine what 

control technologies would be required beyond those resulting from the BART analysis. 

Therefore, the Reasonable Progress analysis starts from a baseline of what is required by 

BART.

The fifth impact analysis evaluates the time necessary for compliance. This 

particular factor is identified by the Clean Air Act only in relation to the Reasonable 

Progress analysis. However, this factor is considered in the BART analysis in relation to 

what constitutes the “expeditiously as possible” deadline for implementation of the 

control technology imposed by BART. 

 The sixth impact analysis required by the Clean Air Act to be considered is the 

remaining useful life of the source subject to BART. In the preliminary analysis, useful 

life is typically considered in relation to the effect on the annualized costs of the retrofit 

controls for capital recovery. This occurs when the source has a shorter remaining useful 

life than the expected service life of the control technology. This would require 

expedited capital recovery, thus affecting the cost-effectiveness of the control technology, 

particularly for technologies that require a large capital expenditure. However, the Clean 

Air Act does not limit consideration of remaining useful life to the economic analysis. 
Boardman Plant Introduction and Objectives 

082710 1-9 

Congress’ choice to include remaining useful life as a factor independent of economic 

impacts evidences a Congressional intent that remaining useful life be more than just a 

component of the economic impacts analysis. 

1.2.5 Evaluate Visibility Impacts (Step 5) 

 Potential visibility improvement from the addition of each control technology is 

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

modeling protocol was previously developed in consultation with, and approval of, DEQ. 

This protocol was also followed in this revised analysis. Items that were considered in 

the modeling protocol include the following: 

x Meteorological and terrain data. 

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

x Pre- and post-control emission rates. 

x Receptor data from appropriate Class 1 areas. 

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

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

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

Consideration of the degree of improvement in visibility is a factor specified by 

the Clean Air Act only in relation to the determination of what constitutes BART. 

Visibility impacts are not identified as a decision criterion for Reasonable Progress. 

However, as the purpose of Reasonable Progress is to achieve the reasonable progress 

goals outlined in the Regional Haze Plan, the goal of reducing visibility impacts is a 

consideration, if not an evaluative criterion, in the Reasonable Progress analysis. 

1.2.6 Selecting the Best Alternative 

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

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

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

best alternative. PGE strove to maintain the existing regulatory limits and determinations 

where possible so as to minimize disruption to the regulations previously adopted by the 

EQC. 

1.3 Reasonable Progress Analysis Methodology 

 Reasonable Progress is an engineering and economic analysis similar, but not 

identical, to the BART analysis, to identify secondary levels of emission reduction for 

pollutants that cause visibility impacts in federal Class I areas (NOx, SO2, and PM). EPA 

has issued no regulatory guidance on how to perform Reasonable Progress analyses and 
Boardman Plant Introduction and Objectives 

082710 1-10 

so the Clean Air Act itself is the sole basis for determining the appropriate means of 

establishing Reasonable Progress limits.8 As noted above, the Reasonable Progress 

analytical criteria stated in the Clean Air Act differ from those for BART. Specifically, 

Reasonable Progress includes a criterion, “the time necessary for compliance,” that is not 

present in the BART criteria. In addition, Reasonable Progress lacks the requirement to 

evaluate “the degree of improvement in visibility,” which is present in the BART 

analytical process. Furthermore, while BART includes consideration of existing controls

as an evaluative criterion, EPA explained that Reasonable Progress is determined using a 

baseline condition reflecting the visibility improvements expected to result from 

implementation of other Clean Air Act requirements—including BART. 40 CFR 

51.308(d)(3)(v). Both BART and Reasonable Progress require consideration of the cost 

of compliance, the energy and nonair quality environmental impacts of compliance and 

the remaining useful life of the source. In evaluating and suggesting revisions to the 

Reasonable Progress NOX limits in OAR 340-223-0040, PGE has followed the process 

outlined above in relation to BART, while respecting the differences required by the 

Clean Air Act when determining Reasonable Progress limits.

8

 EPA issued guidance for the setting of Reasonable Progress goals. Guidance for Setting Reasonable 

Progress Goals Under the Regional Haze Program (June 1, 2007). This guidance notes that Reasonable 

Progress determinations may not be necessary in the first planning period. It also notes that states need not 

reassess Reasonable Progress for sources that have already undergone BART. However, while there is 

cursory mention in the guidance document of the Reasonable Progress evaluation factors mandated by the

Clean Air Act, EPA introduces the document saying that it “is to provide guidance to States in setting

reasonable progress goals...” The purpose of the document was not to identify a comprehensive process 

for establishing Reasonable Progress goals. 
Boardman Plant Basis of Analysis 

082710 2-1 

2.0 Basis of Analysis 

2.1 Design Basis 

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

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

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

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

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

the basis for this BART/Reasonable Progress analysis. The design basis was also 

established for two other coal cases: typical (Buckskin Mine) and maximum (Black Butte 

Mine). Performance calculations were based on the design basis coal.

2.2 Economic Data 

2.2.1 Capital Cost Estimates 

 Capital cost estimates were developed for retrofit control technologies that were 

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

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

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

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

stated in 2010 dollars. The cost estimates are consistent in format with the guidance from 

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

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

preliminary and should only be used for comparative purposes in this BART/Reasonable 

Progress analysis. The capital cost estimates will be refined throughout the upcoming 

preliminary engineering phase until actual equipment and construction contracts are 

procured.

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

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

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

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

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

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

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

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

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

estimates were based on the following assumptions: 

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

082710 2-2 

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

x Normal lead-times for equipment deliveries are expected. 

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

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

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

x Contingency.

x Engineering.

x Owner Costs. 

x Construction management. 

x Startup and spare parts. 

x Performance Tests. 

2.2.1.1 Contingency. Contingency accounts for unpredictable events and costs that 

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

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

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

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

startup, etc.

2.2.1.2 Engineering. Engineering costs include any services provided by an 

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

quality control project.

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

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

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

project.

2.2.1.4 Construction Management. Construction management includes costs for 

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

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

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

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

and liability insurance for equipment and tools. 

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

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

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

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

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

recommendations and owner requirements. 
Boardman Plant Basis of Analysis 

082710 2-3 

Table 2-1 

Typical Owner Costs 

Project Development: 

Legal assistance 

Permitting compliance 

Public relations/community development 

Road modifications/upgrades 

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

Financing:

Debt service reserve fund 

Financial analysis 

Owner’s Project Management: 

Project management 

Engineering due diligence 

Preparation of bid documents and selection 

of contractors and suppliers 

Taxes/Advisory Fees/Legal: 

Taxes

Market and environmental consultants 

Owner’s legal expenses: 

Interconnect agreements 

Contract-procurement and 

construction

Property transfer 

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

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

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

for equipment, basic materials, craft labor and engineering talent.

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

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

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

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

compliance with performance guarantees and emissions limits. 

2.2.2 Annual Operating and Maintenance Cost Estimate 

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

cost categories: 

x Reagent costs. 

x Electric power costs. 
Boardman Plant Basis of Analysis 

082710 2-4 

x Makeup water costs. 

x Wastewater treatment and byproduct disposal costs. 

x Operating labor costs. 

x Maintenance materials and labor costs. 

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

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

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

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

O&M costs. 

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

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

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

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

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

reagents: 

x Limestone. 

x Lime. 

x Anhydrous ammonia. 

x Urea.

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

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

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

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

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

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

equipment. 

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

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

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

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

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

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

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

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

the appropriate water type was included in this cost category.
Boardman Plant Basis of Analysis 

082710 2-5 

Table 2-2 

Economic Evaluation Factors 

Economic Factor Value 

Reagent Cost 

Lime $132/ton 

Limestone $46/ton 

Ammonia (anhydrous) $450/ton 

Urea $315/ton 

Mg(OH)2 $1.20/ton 

SCR Catalyst Cost $6,000/m3

Makeup Water Cost $2/1,000 gal 

Service Water Cost $0.50/1,000 gal 

Wastewater Treatment Cost $0.50/1,000 gal 

Byproduct Disposal Cost $10/ton 

Electric Power Cost $46.04/MWh 

Steam Cost $3.50/1,000 lbs 

Maintenance Cost 3% of cap cost/yr 

Control Technology Economic Life From control equipment startup 

date to plant shutdown date 

Interest Rate 7% 

Present Worth Discount 9.2% 

Capital and O&M Escalation Factor 3% 

Start-up Date for all Combustion NOx Control Systems July 1, 2011 

Start-up Date for all SO2 or PM Control Systems July 1, 2014 

Start-up Date for SCR NOx Control System July 1, 2016 

Start-up Date for SNCR NOx Control System July 1, 2014 

Boiler Shut-Down Date (no later than) December 31, 2020 

Capital Recovery Factor for all Combustion NOx Control 

Systems 

14.76 

Capital Recovery Factor for all SO2 or PM Controls 19.67 

Capital Recovery Factor for SNCR Control System 19.67 

Capital Recovery Factor for SCR Control System 26.67 

Allowance for Funds During Construction (AFDC) 8.99% 

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

082710 2-6 

2.2.2.4 Wastewater and Byproduct Disposal Costs. Some control technologies 

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

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

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

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

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

utilized: 

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

technologies downstream of the existing ESP. 

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

x All wet scrubber equipment effluent requires wastewater treatment prior to 

being discharged to the environment. 

x Ammonia-based NOx reduction systems may affect the salability of fly

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

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

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

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

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

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

the following personnel:

x Supervisor

x Control room operator. 

x Roving operator. 

x Relief operator. 

x Laboratory technicians. 

x Equipment operators. 

x Maintenance technicians. 

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

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

2.2.2.6 Maintenance Materials and Labor Costs. The annual maintenance 

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

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

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

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

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

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

additional maintenance costs are included for the new control technology.
Boardman Plant Basis of Analysis 

082710 2-7 

2.3 Baseline Emissions 

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

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

baseline emissions established for the Boardman Plant for purposes other than visibility 

assessment are summarized in Table 2-3. The emission rates represent the highest rolling 

12 month total between 2003 and 2005. Consistent with EPA’s BART Guidelines, the 

baseline emission rate used for modeling purposes reflects the highest 24-hour average 

actual emission rate. 

Table 2-3 

Baseline Emissions 

Pollutant Emissions Data Source 

NOx 0.43 lb/MMBtu 2003-2005 CEMS Data 

10,349 ton/yr 2003-2005 CEMS Data 

SO2 0.614 lb/MMBtu 2003-2005 CEMS Data 

14,902 ton/yr 2003-2005 CEMS Data 

PM 0.017 lb/MMBtu 2003-2005 CEMS Data 

417 ton/yr 2003-2005 CEMS Data 

 For purposes of the Reasonable Progress analysis, EPA directed in Section 4.1 of 

its Guidance for Setting Reasonable Progress Goals that Reasonable Progress was to 

build upon the emission reductions resulting from other programs, including BART. 

Therefore, the Reasonable Progress analysis used compliance with the recommended 

BART requirements as the baseline emission rate. 

2.4 Project Assumptions 

In performing the BART/Reasonable Progress analysis, several general 

assumptions were made to facilitate the conceptual design of the technically feasible 

control technologies. The following are key project assumptions: 

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

control equipment. However, any changes in plant availability are 

assumed to be insignificant in this analysis. 

x The site will have sufficient area available to accommodate construction 

activities including, but not limited to, offices, lay-down and staging. 
Boardman Plant Basis of Analysis 

082710 2-8 

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

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

in contingency costs. 

x Byproducts produced from the emissions reduction processes will be 

disposed at the available landfill area on-site. 

x When not contaminated with scrubber products, fly ash captured by PM 

control technologies is sold.

x When the scrubber byproducts contaminate the fly ash, such as in the case 

of the semi-dry FGD, disposal costs are included. 

x Design and installation of post-combustion controls will not begin unless 

and until the OPUC acknowledges PGE’s investment in the controls as 

part of an Integrated Resource Plan. 

x BART control requirements will be permittable under DEQ and EPA 

regulations without the need for further control investment. 

2.5 Modeling Baseline Conditions 

 Stack outlet conditions for all the technically feasible control technologies were 

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

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

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

x Flue gas flow rate. 

x Flue gas velocity. 

x Flue gas temperature. 

x Flue gas pressure. 

x SO2 emissions rate. 

x NOx emissions rate. 

x PM emissions rate. 
Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

082710 3-1 

3.0 Identification of All Available Retrofit Emission 

Control Technologies (Step 1) 

 In Step 1 of the BART/Reasonable Progress analysis, all available retrofit control 

technologies that have a practical potential for application at the Boardman Plant were 

identified. These technologies were considered as available technologies. The control 

technology may be a method, system, or combination of reduction technologies for 

control of a pollutant. Sections 3.1 through 3.3 describe the control technologies for the 

three pollutants: NOx, SO2 and PM. Information on the working principle, retrofit 

considerations, and advantages and disadvantages of each technology is also provided. 

3.1 NOx Control Technologies 

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

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

x SCR. 

x SNCR. 

x SNCR/SCR hybrid (Cascade). 

x ECOTUBE. 

x LoTOx. 

x Natural gas reburn.

3.1.1 Selective Catalytic Reduction 

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

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

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

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

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

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

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

utilizing aqueous ammonia injection is illustrated on Figure 3-1. 
Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

082710 3-2 

Figure 3-1 

Schematic Diagram of a Typical SCR Reactor 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

the air preheater to the pulverizer in order to properly dry the coal and maintain 
Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

082710 3-3 

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

to approximately $45 million dollars. 

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

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

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

increases, potentially increasing corrosion in downstream equipment or possibly 

requiring an increase in the air heater gas outlet temperature.

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

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

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

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

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

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

anhydrous ammonia.

SCR systems have a variety of interfacing system requirements to support 

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

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

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

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

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

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

modifications and for ammonia supply system requirements. 

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

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

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

air heater, degrade its performance, and decrease plant efficiency. The other potential 

danger for the air heater is high concentrations of SO3 in the flue gas. If the acid dew 

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

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

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

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

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

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

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

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

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

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

heaters. 
Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

082710 3-4 

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

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

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

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

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

conditions and restrictions. SCR, as stated previously, is located between the economizer 

and the air heater for a high dust arrangement. This is typically a very congested area of 

the plant. Plant equipment (such as fans, boiler support steel, and underground utilities) 

restrict the possible ductwork arrangements as well as increase the complexity of the 

retrofit. SCR performance is highly dependent on having even flow distribution into the 

ammonia injection grid and the catalyst. 

3.1.2 Selective Noncatalytic Reduction 

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

the boiler, as illustrated on Figure 3-2. SNCR systems rely solely on reagent injection, 

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

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

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

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

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

3,000° F.

SNCR systems are capable of achieving a NOx emissions reduction as high as 50 

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

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

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

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

emissions reduction levels of 15 to 25 percent for retrofit applications. Potential 

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

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

characteristics.

SNCR systems reduce NOx emissions using the same reduction mechanism as 

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

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

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

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

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

point. This complicates the application of SNCRs for boilers larger than 100 MW. 
Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

082710 3-5 

Combustion Air

Injection

Level 2

Injection

Level 3

Burners

Steam Generator

Air Heater

Injection Level 1

Flue

 Gas

Ammonia or 

Urea Storage Tank

Figure 3-2 

Schematic of SNCR System with Multiple Injection Levels 

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

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

mixing. For large boilers, the design challenge is to achieve appropriate residence times 

(in excess of 1 second) in the optimum temperature range (1500 to 2200oF). For an 

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

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

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

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

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

higher ammonia slip, which fouls air heater surfaces. 

3.1.3 SNCR/SCR Hybrid 

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

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

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

reduction potential and decreased ammonia slip inherent in the catalyst of SCR systems. 

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

requirements but can be upgraded to meet higher reductions at a future date, if required.
Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

082710 3-6 

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

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

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

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

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

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

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

catalyst.

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

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

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

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

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

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

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

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

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

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

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

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

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

as a part of the SNCR. Therefore, even though the reaction at the catalyst requires 1 ppm 

of ammonia to remove 1 ppm of NOx, the SNCR must inject at least 3 ppm of ammonia 

to generate 1 ppm of ammonia at the catalyst. 

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

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

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

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

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

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

hybrid system. 

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

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

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

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

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

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

challenging and complex modifications to the boiler will be required to lower the gas 
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path temperature to the desired range while still maintaining the air temperature exiting 

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

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

negating the capital cost advantage of a hybrid system.

3.1.4 ECOTUBE 

The ECOTUBE system utilizes retractable lance tubes that penetrate the boiler 

above the primary burner zone and inject high-velocity air as well as reagents. The lance 

tubes work to create turbulent airflow and to increase the residence time for the air/fuel 

mixture. In principle, the OFA and SNCR processes are combined in this technology. 

ECOTUBE is capable of reducing NOx, while improving thermal efficiency, by 

optimizing the combustion process in boilers. An illustration of the ECOTUBE 

installation in a typical boiler is shown on Figure 3-3. 

The water-cooled ECOTUBEs are automatically retracted from the boiler on a 

regular basis and cleaned to remove layers of soot and other deposits. Additional benefits 

have been identified by the supplier in terms of furnace combustion improvements that 

increase efficiency, reduce fuel usage, and reduce corrosion and erosion in the boiler and 

backend equipment. 

Figure 3-3 

ECOTUBE Installation in a Boiler 
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3.1.5 LoTOx 

The LoTOx technology is the low temperature gas-phase oxidation of NOx by 

ozone injection. In this method, ozone is injected into the flue gas upstream of a wet 

FGD system. The ozone reacts with the NO and NO2 to form nitrogen pentoxide (N2O5).

The N2O5 formed is soluble in water and can be removed from the flue gas using a wet 

FGD system. 

The LoTOx technology has been demonstrated on several industrial sized plants. 

In May 2002; the technology was used at Abitibi Consolidated (Sheldon, Texas), a paper 

recycling plant. The Ohio Coal Development Office funded a $6.3 million LoTOx unit at 

the Medical College of Ohio, and there have been several refinery applications. 

The LoTOx technology offers high NOx removal efficiency with a reported 

potential of 15 to 25 percent savings in capital cost over an SCR system. The major 

drawbacks of this system are the lack of experience on larger power generating units, 

high power consumption, and the production of nitrates. 

The high auxiliary power consumption from the multiple ozone generators 

required to produce the ozone for the process is expected to be comparable to what is 

needed for a conventional FGD system and is significantly higher than the power 

consumption from an SCR. The nitrate production from this technology is captured in 

the FGD waste product, possibly requiring the need for a wastewater treatment plant. 

3.1.6 Natural Gas Reburn 

The natural gas reburning process employs three separate combustion zones to 

reduce NOx emissions, as illustrated on Figure 3-4. The first zone consists of the normal 

combustion zone in the lower furnace, which is formed by the existing wall burners. In 

this zone, 75 to 80 percent of the total fuel heat input is introduced. The first zone 

burners are operated with about 10 percent excess air (a 1:10 stoichiometric ratio). A 

second combustion zone (the reburn zone) is created above the lower furnace by 

operating a row of conventional natural gas burners at a stoichiometric ratio less than 1.0. 

This technology also has the potential for increased furnace corrosion (especially with 

higher sulfur fuels) because of the reducing atmosphere in the lower furnace. 

The substoichiometric reburn zone causes NOx produced in the lower furnace 

units to be reduced to molecular nitrogen and oxygen because the oxygen stripped from 

the NOx molecules is combined with the more active CO molecules to form carbon 

dioxide as combustion is completed in the upper furnace. Fuel burnout is completed in 

the third zone (the burnout zone) by the introduction of OFA. Sufficient OFA is 

introduced to complete combustion of the unburned materials in the upper furnace with 

an overall excess air rate for the boiler of 15 to 20 percent. Reburn technology has 

demonstrated NOx reduction of 40 to 65 percent. 
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Burnout Zone

•Normal Excess Air

Reburning Zone

•Slightly Fuel Rich

•NOx Reduced to N2

Primary Combustion

Zone

•Reduced Firing Rate

•Low Excess Air

•Lower NOx

Overfire Air

40 to 60% NOx Reduction

10 to 20 % Gas

Fuel Rich

80 to 90% Coal

10% Excess Air

Figure 3-4 

Schematic of Gas Reburn System 

Sufficient residence time (adequate furnace height) in the reburn and OFA zones 

is a key factor in determining whether the reburning technology can be applied. 

Successful retrofit of this technology requires space within the boiler to allow adequate 

residence time for both the additional burning zone (0.4 to 0.6 second) and the associated 

OFA burnout zone (0.6 to 0.9 second). When this space is available, reburning can be 

highly effective, but a low residence time will limit system performance. Also, the high 

cost of natural gas makes the annual operating costs of this technology prohibitive. 

3.2 SO2 Control Technologies 

 The following SO2 control technologies were identified as available for retrofit at 

the Boardman Plant are summarized in Subsections 3.2.1 through 3.2.4: 

x Wet FGD. 

x Semi-dry FGD. 

x Dry FGD (Circulating Dry Scrubber [CDS]). 

x Dry Sorbent Injection (DSI) 

x Reduced sulfur coal restriction. 
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3.2.1 Wet Flue Gas Desulfurization 

Although wet lime and ammonia FGD systems are available, the wet limestone 

FGD process is the most frequently applied FGD technology in the United States when 

treating flue gas from combustion of medium- and high-sulfur coals (typically greater 

than 1.5 percent sulfur). Wet limestone FGD systems are also applicable for units 

burning low-sulfur bituminous and subbituminous coals. Wet limestone FGD systems 

are capable of achieving slightly higher SO2 removal than other types of FGD systems 

but have not demonstrated significant removal of elemental mercury. A typical wet 

limestone FGD system consists of reagent storage and handling system, FGD spray tower 

absorber, and byproduct dewatering system as illustrated on Figure 3-5. 

Reaction Tank

Recycle

Pumps

Mist

Eliminators

To

Chimney

From

Booster

Fans

Reagent and

Makeup Water

Byproduct

Solids to

Dewatering Oxidation Air

Agitators

Figure 3-5 

Process Flow Diagram of a Spray Tower Wet FGD System. 
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For most wet limestone FGD applications, the absorber module is located 

downstream of the ID fans (or booster ID fans, if required). For a wet FGD system, the 

flue gas enters the absorber and is contacted with a slurry containing reagent and 

byproduct solids. The SO2 is absorbed into the slurry and reacts with the calcium to form 

CaSO3x1/2H2O and CaSO4x2H2O. 

There are several types of absorber modules, and each has characteristic 

advantages and disadvantages. FGD equipment vendors have specific designs for one or 

more types, and all compete on a capital/operating cost and guarantee basis. Depending 

on the process vendor, the absorber may be a co-current or countercurrent spray tower, 

with or without internal packing or trays. Other vendors use a unique absorber where the 

flue gas is bubbled into a reaction tank, as illustrated on Figure 3-6. Regardless of the 

type of absorber used, the flue gas leaving the absorber is saturated with water and the 

stack will have a visible, persistent moisture plume. Generally, wet FGD systems do not 

remove significant quantities of SO3 from the flue gas. Condensed SO3, in the form of 

sulfuric acid mist (H2SO4), can be removed with a WESP, which is discussed in 

Subsection 3.3.6.

Figure 3-6 

Cutaway View of a Jet Bubbling Reactor Wet FGD System 
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Because of the chlorides present in the mist carryover from the absorber and the 

pools of low pH condensate that can develop, the conditions downstream of the absorber 

are highly corrosive to most materials of construction. Highly corrosion-resistant 

materials are required for the downstream ductwork and for the stack flue. Careful 

design of the stack is needed to prevent “rainout” from condensation that occurs in the 

downstream ductwork and stack. 

The reaction byproducts are typically dewatered by a combination of hydrocyclones and vacuum filters. For natural oxidation wet limestone FGD systems, the 

resulting filter cake is suitable for landfill disposal. In some instances, the FGD 

byproduct requires mixing with fly ash and/or lime (fixation) to produce a physically 

stable material. 

If air is bubbled through the reaction tank, practically all of the CaSO3x1/2H2O

can be converted to CaSO4x2H2O, which is commonly known as gypsum. This oxidation 

step is termed “forced oxidation.” Compared to calcium sulfite, gypsum has much 

superior dewatering and physical properties, and forced-oxidized systems tend to have 

few scaling problems in the absorber and mist eliminators. Dewatered gypsum can be 

landfilled without stabilization or fixation. Many wet FGD systems in the United States 

are using the forced-oxidation process to produce commercial grade gypsum that can be 

used in the production of Portland cement or wallboard. Marketing of the gypsum can 

eliminate or greatly reduce the need to landfill FGD byproducts. 

The wet FGD processes are characterized by high efficiency and high reagent 

utilization. The absorber vessels are fabricated from corrosion-resistant materials such as 

epoxy/vinylester-lined carbon steel, rubber-lined carbon steel, stainless steel, or 

fiberglass. The absorbers handle large volumes of abrasive slurries. The reagent 

handling and byproduct dewatering equipment is also relatively complex and expensive. 

These factors result in relatively higher initial capital costs and lower annual operating 

costs compared to the semi-dry FGD alternatives. 

3.2.2 Semi-Dry Flue Gas Desulfurization 

The semi-dry FGD process is based on the spray drying of lime slurry into flue 

gas. This is performed in a spray dryer absorber (SDA). There are numerous SDA FGD 

system installations on boilers using low-sulfur fuels. These installations, primarily 

located in the western United States, use either lignite or subbituminous coals as boiler 

fuel and generally have spray dryer systems designed for a maximum fuel sulfur content 

of less than 2 percent.
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There are several variations of this process, but the most prevalent is the 

installation of one or more spray dry vessels upstream of a supplied particulate control 

device, as shown on Figures 3-7 and 3-8. For new plants, the SDA absorber vessel is 

located between the air heater and the particulate removal device, most commonly a pulse 

jet fabric filter (PJFF). For the Boardman Plant, the SDA absorber vessel and PJFF 

would be located downstream from the existing ID fans. 

Figure 3-7 

Spray Dryer System 

Although either quicklime slurry (CaO) or a sodium carbonate (soda ash) solution 

may be used as the scrubbing reagent, the current generation of SDA FGD processes uses 

primarily quicklime. The quicklime is first slaked with water to form a calcium 

hydroxide (Ca(OH)2) slurry. The lime slurry is combined with the recycled solids from 

the PJFF to form the reagent slurry. The reagent slurry is injected into the absorber using 

either a rotary or dual-fluid atomizer, where the lime reacts with the SO2 in the flue gas. 

Sufficient water is added to the reagent slurry to lower the flue gas temperature to within 

32 to 40°F of the adiabatic saturation temperature. The SO2 is absorbed into the fine 

spray droplets and reacts with the lime slurry to form both calcium sulfite (~1/3) and 

calcium sulfate (~2/3). Before the droplets can reach the wall of the vessel, the heat of 

the flue gas evaporates the droplets to dry particles containing the byproduct solids and 

excess reagent. As the reagent slurry evaporates, a relatively dry powder remains. 
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Figure 3-8 

SDA FGD System 

The byproduct solids and fly ash are collected in the PJFF. The PJFF is always 

supplied as a system along with the SDA. The PJFF is an integral component of the SO2

removal system, since a significant percentage of removal occurs as the flue gas passes 

through the dust cake on the bags. The vendor guarantee is based on the total removal as 

measured at the exit of the PJFF. 

The byproducts and fly ash are conveyed pneumatically to the fly ash silo in the 

conventional manner. These solids are unloaded, conditioned with water, and transported 

to a landfill. Because of the level of free lime in the byproduct solids, the byproduct/fly 

ash mixture attains a very high bearing strength and low permeability in the landfill. 

Unlike a wet limestone FGD system, there is currently no commercial use for the 

byproduct/fly ash. 
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3.2.3 Circulating Dry Scrubber 

CDS is a form of dry FGD for SO2 removal. Hydrated lime (Ca[OH]2) is the 

reagent used; it is introduced as a dry, free flowing powder into the scrubber vessel. Flue 

gas is then flowed through the lime reagent in a circulation pattern for adsorption of SO2

by the lime. A schematic of the process flow of a CDS process is shown on Figure 3-9. 

HYDRATED 

LIME SILO CDS ESP

H2O

FLY

ASH

SILO

FLUE GAS DUCT

TO ID

FANS

TO

LANDFILL

Figure 3-9 

Circulating Dry Scrubber System (Lurgi Lentjes North America) 

Generally, there are no constraints on the maximum fuel sulfur content; the CDS 

can be adjusted to account for the higher SO2 loading by increasing the concentration of 

reagent. However, this flexibility is limited by the cost of the lime reagent. An 

evaluation on the overall reagent cost is important before selecting this technology. Lime 

utilization is improved by cooling the flue gas before it reacts with the lime. Flue gas 

coming into the scrubber vessel is cooled to about 30o F above the adiabatic saturation 

temperature. 

As is the case with the SDA, a downstream particulate collection device is 

required, usually an ESP or FF, for the removal of PM from the ash in the coal and the 

product of the reaction of lime with the SO2 in the flue gas. Because of the relatively 

high velocity of the flue gas through the scrubber vessel (approximately 19 ft/s), the 

treated flue gas carries entrained reagent and reaction products from the module to the 

downstream particulate control device.
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Over 90 percent of the collected solids in the ESP or FF contain unreacted lime. 

Because of abrasion and impacts of the other particles in the flue gas as well as material 

handling dynamics, the “shell” of reaction products on the reagent particles is broken up. 

This material is recycled into the scrubber vessel to further improve lime utilization. This 

solids recirculation also maintains the bed densities needed for contact and removal of 

SO2. Typically, reagent is recirculated 35 to 50 times, providing a residence time of 30 

minutes or more. Collected solids, which are not recirculated, are disposed of. 

The CDS is a small vessel; the associated ESP or FF is in an elevated location 

because flue gas travels upwards in a CDS vessel. This arrangement results in a smaller 

footprint for applications with space constraints. However, depending on the site 

situation, the retrofit of such a system might be costly, especially if there are substantial 

construction and structural difficulties.

Disadvantages of this process include high dust loading at the particulate removal 

system and lack of US utility operating experience in the size range of the Boardman 

Plant. Higher FF pressure drops are encountered because of the flue gas dust loading, 

thus ESPs are preferred for particulate removal. The high particulate loadings make 

sizing of the ESP critical to ensure compliance with particulate emission requirements. 

3.2.4 Dry Sorbent Injection 

Dry Sorbent injection (DSI) systems require a dry reagent such as trona, sodium 

bicarbonate, or hydrated lime to remove SO2. This technology is typically capable of 

removing between 20 to 50 percent of the SO2 in the flue gas, and its removal efficiency 

is highly dependent on the application, primarily the configuration of the existing 

ductwork and the flue gas residence time in the ductwork. 

DSI has been shown to be effective in boilers that are smaller and of a different 

configuration than the Boardman boiler. There is no precedent for DSI on a boiler of the 

size and configuration of the Boardman Plant boiler. A DSI injection rate of at least 4 

tons/hr is estimated to be required for Boardman to achieve an SO2 emission rate of 0.40 

lb/MMBtu. In order to meet the emissions for both SO2 and PM, a sorbent injection 

system is usually coupled with a particulate control device such as a fabric filter or an 

ESP. 

Because of the type of reaction, temperature, percentage reduction rate, and the 

corresponding retention time requirements, a dry reagent such as trona and sodium 

bicarbonate are preferred for injection applications.

Given the absence of experience on a comparable boiler, computational flow 

dynamics (CFD), chemical kinetic modeling, and pilot testing would be necessary to 

determine which reagent is preferred, the preferred location of reagent injection, the 
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amount of SO2 emissions removed, and whether furnace injection, duct injection, or both 

furnace/duct injection systems are required for effective removal. Unit design and 

operational data would be collected for the CFD computer model inputs. This data, 

combined with unit mapping information, will enable the model to develop precise 

injection locations and reagent injection characteristics for each boiler. 

The major components of a typical reagent injection system include air 

compressors, chemical reagent storage tank/silo, heat tracing, controls, injection system 

(e.g., flanges, lances, nozzles, hoses, hardware, etc.), and an injection platform. 

3.2.5 Reduced Sulfur Coal Restriction 

Reduced sulfur coals are available that could reduce SO2 emissions without the 

negative ancillary impacts associated with post-combustion controls. Reduced sulfur 

coal could be used to reduce SO2 emissions but would require coal blending to achieve 

material reductions. Seams within existing Powder River Basin coal mines have different 

sulfur levels. However, only a limited number of mines offer the lowest sulfur coals and 

those coals are facing increased demand. Not all portions of those limited mines contain 

reduced sulfur coal. In addition, seasonal transportation restrictions can limit the 

availability of certain coals at certain times of year. As a result, any significant reduction 

in the Boardman Plant boiler’s SO2 emission limit through the use of lower sulfur coals 

would need to be accomplished through the blending of coals with different sulfur levels. 

Based on those coals that are capable of being transported to the Boardman Plant utilizing 

existing domestic infrastructure, the lowest SO2 emission rate that could be achieved 

consistently over the next ten years as the result of using reduced sulfur coal is 0.60 

lb/MMBtu. 

3.3 PM Control Technologies 

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

the Boardman Plant and are summarized in Subsections 3.3.1 through 3.3.6: 

x PJFF. 

x Compact Hybrid Particulate Collector (COHPAC). 

x GE MAX-9 hybrid. 
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x Multi-cyclone 

x WESP. 

3.3.1 Pulse Jet Fabric Filter 

FFs are media filters that the flue gas passes through to remove particulate. 

Reduced particulate emissions limits and the selection of low-sulfur fuels has promoted 

the use of FFs for the last 15 years. 

 Cloth filter media is typically sewn into cylindrical tubes called bags. Each FF 

unit may have thousands of these filter bags. The filter unit is typically divided into 

compartments that allow online maintenance or bag replacement. The quantity of 

compartments is determined by maximum economic compartment size, total gas volume 

rate, air-to-cloth (A/C) ratio, and cleaning system design. Each compartment includes at 

least one hopper for temporary storage of the collected fly ash. A cut-away view of a 

PJFF compartment is illustrated on Figure 3-10. 

 Fabric bags vary in composition, length, and cross section (diameter or shape). 

Bag selection characteristics vary with cleaning technology, emissions limits, flue gas 

and ash characteristics, desired bag life, capital cost, A/C ratio, and pressure differential. 

Fabric bags are typically guaranteed for 3 years.

In PJFFs, the flue gas typically enters the compartment hopper and passes from 

the outside of the bag to the inside, depositing particulate on the outside of the bag. To 

prevent the collapse of the bag, a metal cage is installed on the inside of the bag. The 

flue gas passes up through the center of the bag into the outlet plenum. The bags and 

cages are suspended from a tube sheet.

Cleaning is performed by initiating a downward pulse of air into the top of the 

bag. The pulse causes a ripple effect along the length of the bag. This releases the dust 

cake from the bag surface. The dust then falls into the hopper. This cleaning may occur 

with the compartment online or offline. Care must be taken during design to ensure that 

the upward velocity between the bags is minimized so that particulate is not re-entrained 

during the cleaning process. The PJFF cleans bags in sequential, usually staggered, rows.

During online cleaning, part of the dust cake from the row being cleaned may be captured 

by the adjacent rows. Online PJFF cleaning has been successfully implemented on many 

large units and is a standard feature of the technology. 
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Figure 3-10 

Pulse Jet Fabric Filter Compartment (Babcock & Wilcox) 
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3.3.2 Compact Hybrid Particulate Collector

Another control technology that is effective in removing particulate is a high A/C 

ratio FF installed after an existing cold-side ESP. Commonly referred to as a COHPAC, 

this technology was developed and trademarked by the Electric Power Research Institute 

(EPRI). The COHPAC filter typically operates at A/C ratios ranging from 6 to 8 ft/min., 

compared to a conventional FF that typically operates at A/C ratios of about 4 ft/min. 

The majority of the particulate is collected in the upstream ESP. Therefore, the 

performance requirements of a high A/C ratio FF is reduced, allowing installation of this 

technology in a smaller footprint area and with less steel and filtration media, which has 

the potential to lower capital and operating costs compared to conventional FFs. 

However, the performance of the FF for a COHPAC system is different than for a regular 

FF system, because the majority of large particulates are removed in the ESP, leaving 

only smaller particles to be collected by the FF. The smaller particles become embedded 

into the bag material. The bags with imbedded particulates are more difficult to clean. 

3.3.3 GE MAX-9 Hybrid 

 The Max-9 electrostatic filter is a hybrid combination of a high-efficiency PJFF 

and an ESP without collecting plates. A front and side elevation view of the Max-9 

particulate filter is illustrated on Figure 3-11. When the dust particles are charged, they 

are attracted to the grounded metal cage inside the filter element, just as they would be 

attracted to the collecting plates in an ordinary precipitator. Since the particles are 

positively charged, they repel each other on the surface of the filter, making the collected 

dust cake very porous. This results in a reduction of filter drag at a pressure drop about 

25 percent of a normal FF. Consequently, the Max-9 can operate at an A/C ratio higher 

than a conventional FF and can treat a significant gas volume with a smaller footprint. 

Process gas enters the Max-9 from a hopper inlet duct. The gas then flows 

upward through the filters and out through the top of the filters. The area above the tube 

sheet is a clean gas plenum. Compressed air pulses are used to clean the filters. A brief, 

intense blast of air is fired through the purge air manifold; holes in the blowpipes located 

above the filters direct the cleaning air pulse down through the filters. The cleaning 

sequence is controlled by timers that trigger solenoids. The high voltage system operates 

at very low current densities and at a steady state. There is no danger of fire caused by 

sparking, and the transformer/rectifier requires no voltage control.

The Max-9 can be supplied as shop-assembled modules that can be erected on 

site, although the units are usually custom-engineered for each plant site and application 

to make the best use of available space. 
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Figure 3-11 

Max-9 Electrostatic Filter 
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3.3.4 Multiple-Cyclone Separators 

Multiple-cyclone separators, also known as multiclones, consist of a number of 

small-diameter cyclones, operating in parallel and having a common gas inlet and outlet, 

as shown on Figure 3-12. Multiclones operate on the same principle as cyclones--

creating a main downward vortex and an ascending inner vortex. Multiclones are more 

efficient than single cyclones because they are longer and smaller in diameter. The 

longer length provides longer residence time, while the smaller diameter creates greater 

centrifugal force. These two factors result in better separation of dust particulates. The 

pressure drop of multiclone collectors is higher than that of single-cyclone separators. 

Cyclone collectors are centrifugal collectors that rely on the particle density and 

velocity to separate the fly ash from the flue gas. The particulate-laden flue gas enters 

the top or the side of the cyclone. An illustration of the components and working 

principles of a multiclone is shown on Figure 3-12. Vanes impart a rotational velocity to 

the flue gas, driving the fly ash to the edge of the cylinder. The flue gas then exits the 

center of the cyclone out the top, leaving the fly ash to fall out the bottom. At pressures 

near one atmosphere and 2 to 5 in. wg pressure differential, this technology can 

effectively remove particles larger than 20 microns in size; particles less than 10 microns 

are usually unaffected and not removed. 

Figure 3-12 

Multiple-Cyclone Particulate Collector 

3.3.5 Wet ESP 

A WESP collects particles on the same theoretical basis as a dry ESP: negatively 

charged particles are collected on positively charged surfaces. The collecting surfaces 

are wet instead of dry and are flushed with water to remove the particulate. Typically, a 

WESP is installed downstream of an existing wet FGD system where the flue gas is 

already saturated, so the amount of added water is minimized. The particulate collection 
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efficiency is enhanced by a lack of re-entrainment after contact with the wet walls (as 

contrasted with re-entrainment due to rapping on a dry ESP). Therefore, the WESP is 

well suited for fine particulate or acid mist applications because it reduces opacity, 

sulfuric acid mist (H2SO4), and other aerosols. 

The use of WESPs for acid mist collection was one of the earliest applications for 

ESPs. Although there are few applications in the utility industry, this is a mature 

technology with hundreds of industrial installations. The particulate characteristics,

temperature, and humidity in WESPs provide excellent fuel flexibility regarding 

particulate removal. However, water chemistry, scaling, and corrosion potential need to 

be carefully investigated. 

The WESP collecting fields impart a negative charge to the particles and collect 

them on positively charged collecting electrodes. Each collection field is equipped with 

independent electrical bus sections, each of which has a dedicated high voltage 

transformer/rectifier and controller. The controllers for each transformer/rectifier are 

located in an environmentally controlled enclosure. Each electrical field has a separate 

discharge electrode support frame suspended by alumina insulators. A heater-blower 

system dedicated to each module supplies warm purge air for each of the insulator 

compartments. The discharge electrode support frames are constructed from Type 304 

stainless steel. The discharge electrodes are suspended from the upper guide frame and 

held in the tube center line. The discharge electrode is a rigid electrode constructed from 

304 stainless steel; it contains split corona-generating elements that are welded to the 

electrode in an opposed orientation. 

A WESP can be installed in either horizontal or vertical gas flow orientation. In a 

horizontal gas flow orientation, a WESP is similar to a common dry ESP. The collection 

plates are arranged in parallel horizontal paths with discharge electrodes hanging between 

them. Vertical gas flow WESPs are usually of the tubular collection plate type. The 

collection plates are arranged in an array of vertical pipes or channels with a discharge 

electrode hanging down the center of the pipe or channel. Channel shapes such as 

squares or hexagons have more efficient packing densities than circular pipes (with a 

small loss in the maximum voltage that can be applied before sparking) and are more 

common. Where multiple electrical stages are used (analogous to the electrical fields in a 

horizontal gas flow ESP), the stages are stacked one above the other. Two to three fields 

are common. 

Several major hurdles exist with the use of a WESP. First, the flue gas must be 

saturated with moisture prior to entering the ESP to allow the WESP to work correctly. 

Therefore, a quenching system must be installed to add water to the flue gas to reduce the 

flue gas temperature to the saturation point or the WESP must be installed downstream of 
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an existing wet FGD system. Without the presence of a wet FGD system, the use of a 

WESP adds additional cost, increases water demand on the plant, and generates a visible 

moisture plume at the stack outlet. The removed particulate would be contained in a 

wastewater stream that is generated by the WESP. In addition to this issue, the capital 

cost of a WESP is high compared to other technologies because of the higher cost of the 

alloy materials required for the WESP. Higher grades of material are required to 

withstand the highly corrosive conditions presented by the wet and acidic flue gas stream 

that will be collected in the wastewater stream. Alternatively, addition of alkaline 

reagents can be used to neutralize the acid in the wastewater stream. 

Each WESP module is cleaned by spraying flush water over the WESP 

components. Flush water is sprayed in the WESP at different spray levels. It is 

anticipated that each WESP module will be flushed once per day. Individual electrical 

sections of each field may be flushed online while the power is turned off to the electrical 

section being cleaned.

If the WESP system is installed downstream of a wet FGD system, there is a 

potential for gypsum scale to form because sulfuric acid and calcium may be carried over 

from the scrubber into the WESP. A continuous injection of dispersant into the system 

can be employed to help eliminate scale formation within the module. The dispersant can 

be stored in a small tank and fed into the flush water surge tank to allow dispersant to 

enter the modules through the spray levels. In addition to this control of the water 

chemistry in the WESP, periodic out-of-service cleaning of a more intense nature might 

be required. Physical cleaning using high-pressure water jets (“hydro lasers”) or 

chemical flushing using an acid based solvent to dissolve the scale buildup are two 

potential options. 

3.4 Emerging Pollution Control Technologies 

Research is ongoing to develop new and improved technologies for multipollutant control. The list of emerging technologies is numerous, and the technologies 

with the most promise include the PowerSpan ECO and Enviroscrub systems. Several 

other promising emerging technologies, such as the Airborne system, are also in the early 

stages of development but are not as far along in pilot testing as the others. Since many 

of these technologies are still at the pilot (slipstream) stage of development, they should 

be viewed with caution until more is known and performance guarantees become 

available. 
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Boardman Plant Emission Control Techniques (Step 1) 

082710 3-25 

3.4.1 PowerSpan 

There are several emerging multi-pollutant technologies that use high electron 

beams or other proprietary processes. The PowerSpan ECO system has only limited 

experience and has not been fully tested on full-scale systems. The ECO system is 

located downstream of an existing particulate control device, and the process consists of 

three stages. In the first stage, the flue gas passes through a barrier discharge reactor 

where it is exposed to a high voltage discharge that generates high energy electrons. The 

electrons initiate a chemical reaction that forms oxygen and hydroxyl radicals, which 

then oxidize NOx, SO2, and mercury. This reaction results in the formation of nitric acid, 

sulfuric acid, and mercuric oxides. A process flow diagram of the ECO system is 

illustrated on Figure 3-13. Stage 2 is the collection of these acids and oxides in a 

downstream ammonia scrubber. The final stage is the collection of acid aerosols, fine 

PM, and oxidized mercury in the downstream WESP. Scrubber effluents contain 

dissolved ammonium sulfate nitrate (ASN) salts along with solids and mercury. The 

ASN solution is sent to a recovery process where the mercury is removed via a sulfurimpregnated activated carbon structure. Once the carbon activated bed becomes 

saturated with mercury, it is disposed of as a hazardous waste. The cleaned stream of 

ASN is converted to a saleable fertilizer.

Figure 3-13 

ECO Process Flow Diagram (PowerSpan). 
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082710 3-26 

PowerSpan also offers a mercury-only control technology that uses a 

photochemical oxidation process. In this process, mercury is oxidized via ultraviolet 

lights. The ultraviolet lights are placed in the ductwork upstream of the particulate 

control device. Photochemical oxidation technology is in its infancy stage, as are most 

mercury reduction technologies. 

The ECO system is under pilot testing at FirstEnergy’s 50 MW Burger Plant and 

has achieved 82, 99, and 85 percent reduction for NOx, SO2, and mercury, respectively, 

while combusting eastern high-sulfur bituminous coal. However, because the ECO 

system has not been pilot tested at a facility burning a low-sulfur (less than 1.5 percent) 

subbituminous coal or within the Boardman Plant size range, this system was not 

evaluated further.

3.4.2 Enviroscrub 

 Enviroscrub is a multi-pollutant control technology that is capable of removing 

significant amounts of elemental and oxidized mercury, NOx, PM2.5, and SO2. This 

technology is based on the Pahlman Process. A sorbent made up of oxides of manganese 

called Pahlmanite sorbent is injected upstream of the SDA, where the flue gas mixes with 

the Pahlmanite sorbent. This is where the oxidation and adsorption of mercury takes 

place. Other pollutants, such as SO2 and NOx, are also adsorbed by the Pahlmanite 

sorbent at this stage. The SDA byproducts are then separated from the flue gas in the 

PJFF. The fly ash and waste byproduct collected in the PJFF hopper is eventually 

transported to a slurry tank for subsequent Pahlmanite sorbent regeneration in a reactor. 

A process flow diagram of the Pahlman Process is illustrated on Figure 3-14. 

The configuration for this technology is as follows: particulate removal (existing 

ESP), SDA, PJFF, sorbent regeneration, and byproduct separation. Currently, 

Enviroscrub is performing slip-stream pilot testing using third-party contractors, and the 

initial results are encouraging (Hammel, Charlie; Enviroscrub Technologies Corp., 

“Pahlman Process Shows Promise,” Power, Vol. 148, Nov. 8, October 2004, pp. 60-63). 

The technology is considered to be developing; but it has not yet moved beyond pilotscale testing and was not evaluated further.
Identification of All Available Retrofit 

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082710 3-27 

Figure 3-14 

Pahlman Process Simplified Process Flow Diagram. 

3.4.3 Phenix Clean Coal 

The Clean Combustion System (CCS) is an advanced hybrid coal 

gasification/combustion process that prevents the formation of NOx and SO2 emissions 

when coal is burned. The only reagent required for pollution control is limestone. 

The CCS concept is that an entrained-flow coal gasifier is followed by stages of 

combustion air. The CCS burner is designed to provide the necessary time, temperature, 

and stoichiometry required for all the chemicals in coal to complete their combustion 

reactions (to reach equilibrium conditions). 

The coal, with limestone added as a source of calcium for sulfur capture, is 

pulverized and introduced to the burner along with a limited amount of hot combustion 

air. The initial high-temperature combustion gasifies and/or releases all the constituents 

of coal into the gas; i.e., carbon, sulfur, nitrogen, and ash compounds. At these high 

temperatures and with limited available oxygen, the carbon aggressively commands 

oxygen to form CO from all sources, including such compounds as water (H2O).

Nitrogen compounds that may form, such as NOx, hydrogen cyanide, and ammonium, are 

simply forced to the molecular form (N2) by the aggressive action of carbon for oxygen. 

In the presence of calcium, the sulfur reacts to form calcium sulfide (CaS), a solid nongaseous particle).
Identification of All Available Retrofit 

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The high combustion temperatures melt the coal ash and CaS solids to form an 

inert slag that drains from the bottom of the boiler. Hot gases, high in CO and H2 and 

nearly free of NOx and sulfur, exit into the boiler furnace. As the gases cool and generate 

steam, additional OFA is added in stages to the furnace to complete the combustion of 

CO to CO2 and H2 to water. This action prevents the formation of any new (thermal) 

NOx and completes the combustion with excess air. The clean hot gases then enter the 

boiler superheat section as before the retrofit. A schematic of the process is shown on 

Figure 3-15.

Figure 3-15 

Phenix Clean Coal Process Flow Diagram 

Retrofits require an annual outage period with a 2 to 3 week extension. The CCS 

retrofit modification requires replacing the existing pulverized coal burners with new 

down-fired CCS burners and adding separated OFA to the boiler furnace and powdered 

limestone to the coal fuel. Most of the new, off-the-shelf equipment fits within the 

existing boiler space. 
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082710 3-29 

The Phenix CCS technology is not in use at a commercial-scale installation with a 

similar-sized boiler as that at the Boardman Plant. Therefore, the technology was not 

considered to be technically feasible for application at the Boardman Plant and was not 

evaluated further. 

3.4.4 J-Power ReACT System 

Japan’s J-POWER is the developer of this enhancement to the original Bergbau 

Forschung activated coke (AC) process. The original and the enhanced versions of the 

technology have been installed at several industrial facilities in Japan, as well as at Isogo 

Unit 101, a 600 MW pulverized coal power plant, and at the Takehara Station, a 350 MW 

atmospheric fluidized bed combustion (AFBC) boiler. Regenerative Activated Coke 

Technology (ReACT) is offered in the United States by J-POWER EnTech, Inc. 

The J-POWER ReACT system consists of an AC process that involves three 

steps: (1) adsorption, (2) regeneration, and (3) byproduct recovery. Figure 3-16 

illustrates the J-POWER ReACT System. The process consists of an adsorber9 located 

after the primary particulate control devices and a sorbent regenerator. In the adsorber, 

the flue gas passes through a bed of AC moving slowly downward at a constant flow rate. 

The adsorber is of a single-stage design. AC pellets are circulated by a conveyor between 

the adsorber and regenerator, and ammonia is injected into the flue gas, typically as it 

enters the adsorber. SO2, SO3, NOx, mercury, and additional particulates (along with 

associated trace metals) are removed in the adsorber in one step, and the pollutant 

saturated AC is regenerated in the regenerator, where it is conveyed through a bucket 

elevator.

The regenerator operates at temperatures in the 750° F to 930° F range. 

Simultaneously, sulfuric acid or ammonium compounds in the AC are decomposed to 

nitrogen (N2), SO2, and water. Mercury is retained in the AC and removed from the unit 

every few years, depending on the mercury concentrations at the inlet of ReACT. After 

cooling, the regenerated AC passes through a vibrating screen to eliminate the 

mechanically degraded AC and captured dust; then, it is returned to the adsorber. The 

degraded AC can be returned to the boiler for burning, but it can also be sold and used in 

other industrial applications, such as dioxin adsorbent. SO2-rich gas from the regenerator 

is converted to a salable product, such as sulfuric acid and gypsum, in the byproduct 

recovery facility. 

9

 The term “adsorption” refers to a surface chemical reaction where the reaction products remain on 

the surface of the solid sorbent material. Because ReACT relies on adsorption of mercury onto activated 

coke, its reaction vessel is termed an “adsorber.” “Absorption” refers to a chemical reaction in which the 

material (the solute) is absorbed into the bulk of the solvent medium. An example is the absorption of SO2

in an alkaline liquid in a wet spray tower, and its reaction vessel is termed an “absorber.” 
Identification of All Available Retrofit 

Boardman Plant Emission Control Techniques (Step 1) 

082710 3-30 

Figure 3-16 

J-POWER ReACT System 

Unlike the original installations of 10 to 20 years ago, this process uses just one 

adsorber for all the pollutants, and the coke pellets have been reformulated to be more 

durable. These upgrades have substantially reduced adsorber size and coke attrition. 

Consequently, they have reduced the capital cost, coke replacement cost, and required 

footprint.

Lastly, slipstream testing has demonstrated 90 percent mercury removal with the 

ReACT system. An EPRI slipstream test of the technology is currently under way at 

North Valmy Station. The ReACT technology is not in use at a commercial-scale 

installation in North America with a similar-sized boiler as that at the Boardman Plant 

burning PRB coal. Therefore, the technology was not considered to be technically 

feasible for application at the Boardman Plant and was not evaluated further. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

082710 4-1 

4.0 Technically Feasible Retrofit Emission Control 

Technologies (Step 2) 

Step 2 of the BART/Reasonable Progress analysis consisted of limiting the list of 

potential control technologies developed in Step 1 by eliminating technically infeasible 

options. In order for a technology identified in Step 1 to be included in the list of 

technically feasible controls developed in Step 2, that technology must be technically 

feasible. The EPA has defined “technically feasible” as meaning that a technology is 

both available and applicable. A technology is considered available if it has reached the 

licensing and commercial sales stage of development. For example, technologies in the 

pilot-scale testing stages of development are not considered available. The fact that a 

technology is considered available is not a sufficient basis for concluding that a 

technology is applicable, and, therefore, technically feasible. That technology must have 

been used in the same or a substantially similar source type to be considered applicable. 

For all the technologies identified as available in Section 3.0, a determination was 

made on the technical feasibility of the technology at the Boardman Plant site according 

to the evaluative process identified by the EPA. 

4.1 Technically Infeasible NOx Control Technologies 

4.1.1 ECOTUBE 

 Since most of the existing installations of the ECOTUBE system are on 

industrial/small-sized boilers firing solid waste, wood, or biomass, this technology is not 

technically feasible for the size range of the Boardman Plant. 

4.1.2 LoTOx 

The LoTOx system has only been demonstrated on small-sized medical waste 

combustors. It is therefore considered as not technically feasible.

4.1.3 Natural Gas Reburn 

 Natural gas reburn in the Boardman Plant boiler is not technically feasible 

because of a lack of sufficient furnace height (i.e., inadequate residence time for NOx

reduction) and because of the lack of installations on boilers in the same size range as the 

boiler at the Boardman Plant.. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

082710 4-2 

4.1.4 SNCR/SCR Hybrid 

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

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

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

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

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

space in the ductwork or with an appropriate temperature or velocity profile for a future 

SCR. Since the SCR catalyst cannot be located in the existing ductwork without 

significant modifications to the boiler to lower the gas path temperature (and velocity) to 

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

the pulverizer in order to properly dry the coal and maintain combustion efficiency, the 

SNCR/SCR hybrid system was considered as not technically feasible.

4.2 Technically Infeasible SO2 Control Technologies 

4.2.1 Dry Flue Gas Desulfurization 

Dry FGD using a CDS or similar technology has been applied only to boilers 

rated up to a maximum of 300 MW. Furthermore, most applications of this technology 

are typically on circulating fluidized bed boilers and not pulverized coal boilers such as 

the boiler at the Boardman Plant. Therefore, this technology was considered as not 

technically feasible. 

4.2.2 Dry Sorbent Injection 

Dry Sorbent injection (DSI) has been applied only to boilers rated less than 220 

MW and never operated for a prolonged period of time on a sub-critical, opposed wall 

fired boiler. Therefore, because DSI does not meet EPA’s definition of an “applicable 

technology,” DSI was not considered a technically feasible technology.

In addition, DSI is not considered a technically feasible technology because there 

are no data to support that the technology is permittable for a boiler the size of the 

Boardman Plant boiler in light of recent regulatory changes. Even if DSI were assumed 

to be able to achieve the SO2 reductions suggested by the Department, the technology is 

not technically feasible if it would be impossible for PGE to obtain a permit to install and 

operate the technology. The EQC recently adopted emergency rules requiring that 

sources evaluate PM2.5 as part of the PSD permitting process. Those rules will take effect 

upon EPA’s withdrawal of its PM10 surrogate policy, which DEQ told the EQC was 

imminent. These rules establish the baseline year for PM2.5 as 2006 or 2007, a 10 

ton/year significant emission rate, a PM2.5 PSD increment and a PM2.5 significant impact 

level. Under these regulations, the installation of DSI would trigger PSD for PM2.5 if it 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

082710 4-3 

resulted in PGE requiring a plant site emission limit (“PSEL”) in excess of its 2006/2007 

actual PM2.5 emission rate by 10 tons per year or more. DSI would require the addition 

of approximately 4 tons/hour of reagent powder into the boiler exhaust upstream of the 

ESP. Assuming 8,000 hours of operation per year, this would equate to 32,000 tons of 

particulate being introduced into the exhaust gas annually. The additional burden 

imposed on the control device could cause it to lose efficiency at collecting the smaller 

particles, thus likely resulting in an increase in PM2.5 emissions in excess of 10 tons per 

year. Preliminary modeling suggests that at the anticipated level of increased PM2.5

emissions associated with DSI, the Boardman Plant would cause a PM2.5 increment 

and/or NAAQS exceedance thus making the DSI technology unpermittable. Because it 

could not be lawfully operated, the DSI technology is not technically feasible. We note 

that this aspect of DSI operation would not have been identified in relation to the smaller 

boilers that have employed the technology for two reasons. First, the smaller boilers 

would have had a proportionately smaller level of PM2.5 emissions. Second, any boiler 

that already has a permit would have obtained it while EPA’s PM10 surrogate policy was 

still in effect. Therefore, these boilers would not have had to evaluate PM2.5 impacts. As 

a result, the previous permitting of the smaller boilers is not a basis for concluding that 

the Boardman Plant boiler could pass permitting review for DSI installation. 

Although DSI cannot be considered technically feasible as a matter of law, PGE is 

considering it as a BART control subject to a pilot test to confirm the achievable control 

efficiency. The facts are that DSI has never been installed on a boiler of the size and 

configuration of the Boardman Plant boiler and there is considerable uncertainty as to the 

level of sorbent injection that can occur and still have the Boardman Plant able to comply 

with the Utility Mercury Rule and to obtain a permit to install DSI. Although these facts 

make DSI technically infeasible as a matter of law, they do not prevent PGE from 

volunteering to install DSI subject to pilot testing to validate that the control technology 

can be operated in compliance with all regulatory requirements, including new source 

review and Oregon’s Utility Mercury Rule. Nonetheless, PGE is prepared to analyze DSI 

as if it were a technically feasible control technology so long as DEQ is prepared to draft 

the BART requirements so as to take into account pilot testing and to provide a means of 

reducing the stringency of the SO2 limit to a value not to exceed 0.60 lb SO2/MMBtu if 

DSI cannot be permitted in conjunction with the existing ESP and maintain compliance 

with mercury regulations and PSD NAAQS/increment. For purposes of this analysis, 

DSI is assumed to achieve 0.40 lb SO2/MMBtu.
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

082710 4-4 

4.3 Technically Infeasible PM Control Technologies 

4.3.1 GE MAX-9 Hybrid 

Current demonstrated GE MAX-9 Hybrid installations are in power boilers that 

are much smaller than that at the Boardman Plant. Therefore, this technology was 

considered as not technically feasible.

4.3.2 Multiple-Cyclone Collector 

 Because of the lower efficiency of multiple-cyclone collectors in reducing PM 

emissions, this technology is not capable of controlling PM emissions better than the 

currently existing ESP. Therefore, this technology was not considered further in the 

analysis.

4.4 Technically Infeasible Emerging Pollution Control 

Technologies

4.4.1 PowerSpan 

As discussed in Subsection 3.4.1, the PowerSpan ECO technology has not been 

pilot tested in a low-sulfur coal burning facility or in a facility similar in size to the 

Boardman Plant. Therefore, the PowerSpan ECO system was not considered as 

technically feasible. 

4.4.2 Enviroscrub 

The Enviroscrub technology is currently in pilot-scale testing, and there are no 

current developments in full-scale implementation. Therefore, the Enviroscrub 

technology is not technically feasible for retrofit at the Boardman Plant. 

4.4.3 Phenix CCS 

The Phenix CCS technology does not have a commercial-scale installation in a 

boiler similar in size to the one at the Boardman Plant. Therefore, this technology was 

not considered technically feasible for application at the Boardman Plant. 

4.4.4 J-Power ReACT System 

The J-Power ReACT system has only undergone slipstream testing in a North 

American plant. Therefore, this technology was not considered technically feasible for 

application at the Boardman Plant. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

082710 4-5 

4.5 Summary of Retrofit Emission Control Technologies 

Technical Feasibility 

A summary of the feasibility evaluation process is detailed in Tables 4-1 to 4-4. 

Also included in the tables are the reasons for the technical infeasibility of the eliminated 

control technologies. 

 Note that Table 4.1 shows new LNBs and MOFA, with either SCR or SNCR. 

Since PGE is planning to install NLNB/MOFA on the Boardman Plant boiler, and these 

technologies were the basis for the existing BART NOx limits which PGE is not 

requesting be modified, SCR and SNCR are evaluated as additional control technologies. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

082710 4-6 

Table 4-1 

Technically Feasible NOx Control Technologies 

Technology

Technically 

Feasible and 

Applicable? Comments 

Existing OFA system operation Yes -- 

Upgraded LNBs Yes -- 

Upgraded LNBs with existing OFA system 

operation

Yes -- 

Upgraded LNBs with existing OFA system 

operation and SNCR 

Yes -- 

New LNBs and modified OFA system Yes -- 

New LNBs with modified OFA system and SNCR Yes -- 

New LNBs with modified OFA system and SCR Yes -- 

SNCR Yes -- 

SNCR/SCR hybrid (Cascade) No Not technically feasible to install catalyst within existing 

ductwork.

Mobotec ROFA and ROTAMIX No ROTAMIX not demonstrated on Boardman sized boilers. 

ROFA system is in the same category as OFA system. 

NOxStar and NOxStar Plus No No existing installation at similar type/size source. 

ECOTUBE No No existing installation at similar type/size source. 

Induced flue gas recirculation (IFGR) No Applicable to low nitrogen content fuel fired boilers only. 

LoTOx No Not commercially available. 

Natural Gas Reburn No No existing installation at similar type/size source. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

082710 4-7 

Table 4-2 

Technically Feasible SO2 Control Technologies 

Technology

Technically 

Feasible and 

Applicable? Comments 

Wet FGD Yes -- 

Semi-Dry FGD (SDA/FF) Yes -- 

Dry FGD (CDS) No No installation at unit larger than 300 MW. 

Dry Sorbent Injection No10 No commercial installation at similarly sized/configured 

source. Pilot study required to determine effectiveness of

control option and level of sorbent injection that could be 

conducted without affecting mercury control and without 

causing PM2.5 NAAQS and/or increment violation. 

Reduced Sulfur Coal Restriction Yes Technically feasible at levels of 0.60 lb/MMBtu or greater 

Table 4-3 

Technically Feasible PM Control Technologies 

Technology

Technically 

Feasible and 

Applicable? Comments 

PJFF Yes -- 

COHPAC Yes -- 

GE MAX-9 Hybrid No No commercial installation at similar sized source. 

10 Although DSI cannot be considered technically feasible as a matter of law, PGE is considering it as a BART control subject to a pilot test to confirm the 

achievable control efficiency. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 2) 

082710 4-8 

Multiple-cyclone collector No Level of emissions control is less effective than currently 

existing ESP. 

WESP Yes -- 

Table 4-4 

Technically Feasible Emerging Pollution Control Technologies 

Technology

Technically 

Feasible and 

Applicable? Comments 

PowerSpan No No commercial installation at similar sized source. 

Enviroscrub No No commercial installation at similar sized source. 

Phenix Clean Coal No No commercial installation at similar sized source. 

J-Power ReACT No Has only been slipstream tested for evaluation before 

commercial installations in North America. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 3) 

082710 5-1

5.0 Evaluation of Technically Feasible Retrofit Emission 

Control Technologies (Step 3) 

 Step 3 of the BART/Reasonable Progress determination process was an 

evaluation of all the technically feasible control technologies for control effectiveness so 

that they could be ranked.

5.1 Control Effectiveness 

The evaluation process in Step 3 determined the control effectiveness of each 

control technology. The control effectiveness was expressed in a common metric based 

on the amount of pollutant generated per unit of heat input (lb/MMBtu). This evaluation 

of the control effectiveness was then translated into a yearly rate (ton/yr) for each 

pollutant according to the highest rolling 12 month data for heat input in the 2003 to 2005 

period. The highest rolling 12 month data for heat input are summarized in Table 5-1. 

The control effectiveness was evaluated according to the sources of information indicated 

in Subsection 1.2.3.

Table 5-1 

Highest Rolling 12 Month Data for Heat Input 

Pollutant Data Period Ending 

Heat Input

(MMBtu/yr)

NOx September 2003 48,630,688 

SO2 August 2005 48,571,330 

PM March 2004 49,093,487 

Tables 5-2 to 5-4 identify the baseline emissions and the control effectiveness for 

each control technology. The tables show the control technology rankings from baseline 

to the most effective control. The control effectiveness for each technology is also 

summarized in the Design Concept Definition sheets in Appendix C. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 3) 

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Table 5-2 

NOx Technologies Control Effectiveness 

Control Technology 

Control Effectiveness 

(at stack) 

lb/MMBtu tons/yr 

Permit Limit 0.70 11,672 

BART 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 

Upgraded LNBs with existing OFA system 

operation and SNCR 

0.24 5,776 

New LNBs and modified OFA system 

(NLNB/MOFA) 

0.23 5,593 

Since New LNBs/MOFA/SNCR is acknowledged as the BART NOx control technology, no 

further assessment of the above NOx control technologies with NOx emissions higher than 0.23 

lb/MMBtu is included in the analysis. 

NLNB/MOFA/SNCR 0.19 4,620 

NLNB/MOFA/SCR 0.07 1,702 

Table 5-3 

SO2 Technologies Control Effectiveness 

Control Technology 

Control Effectiveness 

(at stack) 

lb/MMBtu tons/yr 

Permit Limit 1.2 30,449 

BART Baseline 0.61 14,814 

Reduced Sulfur Coal Restriction (RSCR) 0.60 14,571 

RSCR and Dry Sorbent Injection (DSI)1 0.40 9,714 

Semi-Dry FGD 0.12 2,914 

Wet FGD 0.07 1,700 

(1)Pilot study necessary to establish level of control effectiveness that can be achieved without 

causing or contributing to a NAAQS or increment violation. 
Technically Feasible Retrofit Emission 

Boardman Plant Control Techniques (Step 3) 

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Table 5-4 

PM Technologies Control Effectiveness 

Control Technology 

Control Effectiveness 

(at stack)(1)

lb/MMBtu tons/yr 

Permit Limit 0.040 1,015 

BART Baseline 0.017 417 

PJFF 0.012 295 

COHPAC 0.012 295 

WESP 0.012 295 

(1)Particulate data are filterable values determined by US EPA Method 5. 
Boardman Plant Impact Analysis 

(Step 4) 

082710 6-1 

6.0 Impact Analyses (Step 4) 

6.1 Types of Impact Analyses 

For all the technologies considered, impact analyses were performed as part of the 

BART/Reasonable Progress determination process. The purpose of these analyses was to 

identify factors other than control effectiveness that could affect the choice of the best 

retrofit technology. The following five types of impact analyses were performed in 

evaluating BART technologies: 

x Costs of compliance. 

x Energy impacts. 

x Non-air quality environmental impacts. 

x Existing control technologies. 

x Remaining useful life. 

The following five types of impact analyses were performed in evaluating 

Reasonable Progress technologies: 

x Costs of compliance. 

x Time necessary for compliance. 

x Energy impacts. 

x Non-air quality environmental impacts. 

x Remaining useful life. 

6.2 Methods of Impact Analyses 

The first step in performing the impact analyses was to define the design 

parameters for each control technology that was identified as technically feasible. The 

design parameters contain all pertinent information on the control technology system for 

specific application to the source. Examples of these design parameters include: type of 

reagent used and consumption rate, type of byproduct produced and production rate, flue 

gas pressure drop across the control technology, etc. The information used to define the 

design parameters included the following: 

x Information from equipment vendors. 

x Background information documents used to support New Source 

Performance Standards development. 

x Control technique guidelines document. 

x EPA cost manuals. 

x Trade publications. 

x Engineering and performance test data. 
Boardman Plant Impact Analysis 

(Step 4) 

082710 6-2 

The design parameters for each control technology that has been identified as 

technically feasible for application at the Boardman Plant site are summarized in the 

Design Concept Definition sheets, which can be found in Appendix C.

6.2.1 Costs of Compliance 

The costs of compliance were identified for implementing each technically 

feasible control technology. The total capital investment for each control technology 

when applied specifically to the Boardman Plant site and the annual operating and 

maintenance costs were calculated. These cost calculations were based on the following: 

x CUECost Workbook, Version 1.0. 

x EPA Air Pollution Control Cost Manual - Sixth Edition. 

x Budgetary quotes from equipment vendors. 

x Quotes or cost estimation for previous design/build projects or inhouse engineering estimates. 

In relation to options that included closure of the Boardman Plant in 2020, the cost of 

compliance included the cost of replacement power as ORS 757.020 requires PGE to 

provide its customers adequate service, equipment and facilities at a reasonable cost. 

Because exiting the market or not serving demand is not an option allowed by law, PGE 

is required to account for the cost of replacement power when evaluating the cost of 

closing the Boardman Plant prematurely. 

6.2.2 Energy Impacts 

Energy impacts are estimated for each control technology that has consumption of 

auxiliary energy during its operation. Only direct energy impacts for each control 

technology, such as the auxiliary power consumption of the control technology and the 

additional draft system power consumption to overcome the additional system resistance 

of the control technology in the flue gas flow path, are accounted for. Indirect energy 

impacts, such as the energy to produce raw materials used for the control technology 

system, are not considered. The auxiliary power consumption estimates for each control 

technology are based on the typical power consumption of similar equipment of an 

equivalent size. The additional draft system power consumption calculations are based 

on the volumetric flow rate of the flue gas through the control technology systems and 

the flue gas pressure drops defined in the design parameter of each control technology. 

For NOx emissions, SCR has materially higher energy impacts compared to 

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. 
Boardman Plant Impact Analysis 

(Step 4) 

082710 6-3 

Between the three top-ranked control technologies for SO2 emissions, the energy 

impacts of the wet FGD are significantly higher than those of the semi-dry FGD although 

both scrubbing technologies impose a material energy penalty (parasitic load). The 

imposition of a 0.40 lb/MMBtu SO2 limit based on a reduced sulfur coal restriction 

combined with DSI (assuming a successful pilot study), results in relatively low negative 

energy impacts. 

A COHPAC system consumes more auxiliary energy and ID fan power than a 

fabric filter, a dry ESP, or a wet ESP. Because the COHPAC uses both dry ESP and FF 

technologies, the flue gas pressure drop for a COHPAC system is higher than for either a 

FF or a dry ESP. Similarly, since the COHPAC must operate both ESP and FF, its 

auxiliary energy use is higher than either a dry ESP or FF. In addition, since the 

COHPAC uses two different types of equipment for PM control, the cost factor used for 

maintenance labor and materials is higher for a COHPAC system than for a fabric filter 

or ESP. 

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 disposal requirements for the byproduct 

and waste generated by each control technology. Some of the control technologies 

generate wastes and/or detrimental byproducts, use excessive water, and/or cause 

unsightly plumes. In addition, certain control technologies require the storage of large 

quantities of ammonia and result in the emission of ammonia as slip. These control 

technologies were identified as having negative environmental impacts. 

SCR catalysts must be replaced approximately every 3 years, thus creating a 

potentially hazardous waste stream, and SCRs require the storage and emission of 

significant quantities of anhydrous ammonia (the SNCR system is designed for use of 

urea and less storage is required because of the differences in system use). 

Both an SNCR and an SCR system will have ammonia slip. Although SNCR 

systems typically inject urea, ammonia is produced in the hot injection environment. The 

majority of the ammonia slip will be collected with the fly ash, and may impact the fly 

ash quality. Any ammonia slip not collected with the fly ash will negatively impact 

visibility.

Three of the technically feasible SO2 controls, dry sorbent injection (DSI), wet 

FGD, and semi-dry FGD, each present significant non-air quality environmental impacts. 

All three technologies use a reagent, which generates a waste stream. 

A DSI system requires reagent, which is collected in the existing ESP and would 

likely be disposed of in a landfill. As noted by DEQ in Appendix D to the Regional 
Boardman Plant Impact Analysis 

(Step 4) 

082710 6-4 

Haze Plan, the wet FGD has multiple severe non-air quality environmental impacts, 

including that it generates a visible plume, consumes more water, requires water 

treatment, generates corrosive exhaust gases, and generates a wastewater stream requiring 

disposal. The semi-dry FGD technology also presents non-air quality environmental 

impacts including water consumption in an arid region and the generation of solid 

byproducts for landfill. 

The imposition of a reduced sulfur coal restriction results in no non-air quality 

environmental impacts as the Boardman Plant is already handling coal and the reduced 

sulfur coal would be a direct substitution. 

6.2.4 Existing Controls 

The Boardman Plant has existing controls for NOx, SO2 and PM. At the time the 

Boardman Plant was permitted, the NTEC, working in association with DEQ and the 

public, established emission control requirements reflective of BACT that were imposed 

on the plant. These included the use of low NOx burners for NOx control, low sulfur coal 

for SO2 control and an ESP for PM control. The existence of these controls, which have 

eliminated tens of thousands of tons of visibility impairing emissions since the plant 

commenced operation, must be taken into account in evaluating BART controls. As EPA 

has stated that the Reasonable Progress analysis is intended to take into account SIP 

requirements, these existing controls as well as those control requirements imposed by 

BART are considered as the baseline conditions for the Reasonable Progress control 

analysis. 

6.2.5 Remaining Useful Life 

The Clean Air Act requires that the remaining useful life of a facility be 

considered in determining BART and Reasonable Progress. Remaining useful life is 

most often considered when there is an effect on the annualized costs of the retrofit 

controls for capital recovery. This occurs when the source has a shorter remaining useful 

life than the expected service life of the control technology. However, Clean Air Act § 

169A identifies “remaining useful life” as a separate factor from “costs of compliance” 

and so basic rules of statutory interpretation require that remaining useful life not be 

evaluated solely as an element of the cost of compliance. For this BART/Reasonable 

Progress analysis, the remaining useful life of the controls was defined as the difference 

between the installation date for controls and the shutdown date.

For purposes of this BART/Reasonable Progress evaluation, it is assumed that the 

Boardman Plant boiler will cease operations no later than December 31, 2020. The 

soonest that engineering, procurement and construction (EPC) of SO2 post-combustion 
Boardman Plant Impact Analysis 

(Step 4) 

082710 6-5 

controls could be completed is July 1, 2014. Based on this it is assumed that the start 

date of SO2 controls will be July 1, 2014. Thus, the remaining useful life for all SO2

post-combustion controls and all PM control systems is 6.5 years. The remaining useful 

life of NOx combustion control systems is 9.5 years. The remaining useful life of an SCR 

system and an SNCR system is 3.5 years and 6.5 years, respectively. The remaining 

useful life values of the controls are calculated based on the anticipated dates for startup 

of control equipment and the anticipated shutdown date of the unit. The startup dates for 

controls and the anticipated shut down date are shown in Table 2-2. 

The remaining useful life has a major impact on the annualized costs because the 

capital recovery for installing the equipment is spread over a small number of years. 

Aside from the impact on cost of compliance, the long term environmental and visibility 

benefits from the ceasing operation of the Boardman Plant boiler weigh against the 

installation of additional post-combustion controls.

6.2.6 Time Necessary for Compliance 

The Clean Air Act imposes one additional criterion for determining Reasonable 

Progress controls that is not present in the BART determination process. When 

evaluating what constitutes Reasonable Progress controls, Congress chose to also require 

that DEQ consider the time necessary for compliance. The Clean Air Act imposes a 

deadline for implementing BART, but does not identify the time necessary for 

compliance as a criterion that applies for actually choosing BART. By contrast, the time 

necessary for compliance is expressly stated as a criterion for determining Reasonable 

Progress. As a result, control technologies that take longer to implement are presumably 

less appropriate for Reasonable Progress and the time that it takes to install and bring online a technology must be evaluated as part of the determination process. This is 

particularly relevant where, as here, PGE is proposing to accept federally enforceable 

requirements to implement NLNB/MOFA, a reduced sulfur coal restriction and to close 

the plant by December 31, 2020 if post-combustion controls are not required. 

6.3 Cost-Effectiveness 

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

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

the cost of control per amount of emissions removed. The emissions reduced are 

estimated on an annual basis based on the reduction from baseline emissions. Both the 

baseline emissions and post-control emissions values are documented in the Design 

Concept Definition sheets located in Appendix C.
Boardman Plant Impact Analysis 

(Step 4) 

082710 6-6 

Cost-effectiveness is not evaluated in relation to adoption of a reduced sulfur coal 

restriction. Reduced sulfur coal is more expensive to purchase, and potentially to 

transport, than low sulfur coal because there is less of it, it is located in limited seams and 

demand is high. In addition, the limited availability of reduced sulfur coal introduces a 

supply risk. However, until a contract is negotiated it is difficult to project actual coal 

prices. Therefore, the cost-effectiveness associated with the use of a reduced sulfur coal 

is addressed qualitatively rather than quantitatively. 

Two types of cost-effectiveness are calculated during the BART/Reasonable 

Progress determination: average and incremental cost-effectiveness. The general 

definition of the two types of cost-effectiveness can be found in Subsection 1.2.4. The 

cost-effectiveness values are based on 2010 dollars. Cost impact analyses were 

performed for all the identified technically feasible control technologies. Summaries of 

the calculated cost impact analyses are presented in Appendix D. 

EPA stated that “Although States may in specific cases find that the use of SCR is 

appropriate, we have not determined that SCR is generally cost-effective for BART 

across unit types.” There is no basis at this time for reaching a different conclusion in 

relation to Reasonable Progress.

6.4 Impact Analyses Results 

Table 6-1 was developed for the impact analyses performed. Additionally, the 

expected post-control emissions levels are shown. The cost impact data in the summary 

table was used to produce graphical plots of the total annualized cost versus the expected 

emissions reduction for all control alternatives identified in the BART/Reasonable 

Progress analyses (Figures 6-1, 6-2, and 6-3).

From the graphical plots, a “least-cost envelope” for each group of control 

technologies was identified. Control technologies that lie on this least-cost envelope are 

“dominant controls” that should be the focus for the BART/Reasonable Progress 

determination. Dominant controls are the technologies that have the lowest cost for 

implementation per quantity of pollutant removed. Therefore, these technologies will be 

the top choice as the best method for emissions reduction, barring any additional factors 

or considerations. 

For all the dominant controls, the incremental cost-effectiveness between a 

technology and the next most stringent control technology was also calculated. This 

incremental cost-effectiveness indicates the additional cost to increase the emissions 

reduction when comparing technologies that have different emissions removal capability. 

For easier comparison to the Department’s analyses, PGE has not included the 

generation replacement cost associated with early closure in Table 6-1 or Figures 6-1 
Boardman Plant Impact Analysis 

(Step 4) 

082710 6-7 

through 6-3. Any cost-effectiveness evaluation of options that include premature closure 

of the Boardman Plant boiler must recognize the costs associated with premature 

retirement. These include the incremental replacement costs associated with ceasing 

operations of the Boardman Plant boiler sooner than it would otherwise occur. PGE is 

required by law (ORS 757.020) to ensure that whenever one of its customers needs 

electricity, that power is available and at a reasonable cost. PGE does not have the option 

of telling customers that it is exiting the market and they must find other means of 

satisfying their electricity needs. PGE does not have excess generating capacity and is 

facing potential supply shortages even without the Boardman Plant closing. As a result, 

in deciding whether to operate the boiler until at least 2040 or whether to choose a 

premature closure option, PGE, in association with the OPUC and stakeholders, must 

take into account the cost of finding replacement power. The most likely replacement 

resource would be a natural gas fired power plant. Therefore, in evaluating the cost of 

controls associated with an option that includes plant closure, it is necessary to also 

include the cost associated with accelerating the replacement of the Boardman Plant’s 

power with an alternate baseload resource. This is consistent with the approach outlined 

in the BART Guidelines, specifically in footnote 15 where EPA states that the 

replacement cost of major components must be included in the cost-effectiveness 

analysis. 
Boardman Plant Impact Analysis (Step 4) 

082710 6-8 

Table 6-1 

BART/Reasonable Progress Impact Analysis and Cost-Effectiveness Results 

Emission Expected Expected Total Incremental

Performance Emission Emission Capital Annualized Cost Cost Energy Non-Air

Level Rate Reductions Costs Cost Effectiveness Effectiveness Impacts Impacts

All Feasible Technologies (lb/mmBtu) (tons/yr) (tons/year) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$)

NOx Control Technologies

Baseline 0.43 10,349 -- -- -- -- -- -- --

New LNBs with Modified OFA System 0.23 5,593 4,863 31,585 5,358 1,102 -- -- --

NLNBs, MOFA, and Selective Non-Catalytic Reduction (SNCR) 0.19 4,620 5,836 43,960 11,595 1,987 6,413 74 --

NLNBs, MOFA, and Selective Catalytic Reduction (SCR) 0.07 1,702 8,754 223,651 74,189 8,475 21,452 1,556 --

SO2 Control Technologies

 Baseline SO2 0.61 14,911 -- -- -- -- -- -- --

Reduced Sulfur Coal Restriction (RSCR) 0.60 14,571 340 0 0 0 0 0 0

Dry Sorbent Injection and RSCR 0.40 9,714 5,197 22,932 17,541 3,375 3,611 260 4,059

Semi-Dry FGD (including Fabric Filter) 0.12 2,914 11,997 352,915 78,259 6,523 8,929 2,932 427

Wet FGD (including Fabric Filter) 0.07 1,700 13,211 417,837 101,336 7,670 19,005 6,347 970

PM Control Technologies

Baseline PM 0.017 417 -- -- -- -- -- -- --

Compact Hybrid Particulate Collector (COHPAC) 0.012 295 123 88,310 22,842 186,102 -- 1,330 --

Pulse Jet Fabric Filter (PJFF) 0.012 295 123 100,442 23,505 191,504 Not Applicable 980 --

Wet ESP 0.012 295 123 196,334 42,958 349,994 Not Applicable 611 --

Notes:

1. All costs are in 2010 US$

2. Incremental costs are based on:

a) NLNB, MOFA, and SNCR incremental cost relative to NLNB, MOFA

b) NLNB, MOFA, and SCR incremental cost relative to NLNB, MOFA, SNCR

c) Wet FGD incremental cost relative to Semi-Dry FGD

3. Non-Air Impacts are costs associated with Non- Air Quality Environmental Impacts including generated wastes or detrimental byproducts, and excess water consumed

Table 6-1

Impact Analysis and Cost Effectiveness Results
Boardman Plant Impact Analysis (Step 4) 

082710 6-9 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

New LNBs with Modified OFA System NLNBs, MOFA, and Selective Non-Catalytic Reduction (SNCR)

NLNBs, MOFA, and Selective Catalytic Reduction (SCR) Dominant Controls

Figure 6-1 

NOx Control Cost-Effectiveness 
Boardman Plant Impact Analysis (Step 4) 

082710 6-10 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

Semi-Dry FGD (including Fabric Filter) Wet FGD (including Fabric Filter) Dominant Controls Dry Sorbent Injection

Figure 6-2 

SO2 Control Cost-Effectiveness 
Boardman Plant Impact Analysis (Step 4) 

082710 6-11 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

0 20 40 60 80 100 120 140 160 180 200

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

Pulse Jet Fabric Filter (PJFF) Compact Hybrid Particulate Collector (COHPAC) Wet ESP Dominant Controls

Figure 6-3 

PM Control Cost-Effectiveness 
Boardman Plant Impact Analysis (Step 4) 

082710 6-12 

PGE estimated the replacement power cost as the difference in net present value 

(NPV) between operating PGE’s share of Boardman with the following two cases over 

the time period from 2010 to 2040. 

(1) Compliance with existing Regional Haze Rule (NLNB/MOFA in 2011, semidry scrubber in 2014, and SCR in 2017) and operation through 2040. 

(2) DEQ Option 1 (NLNB/MOFA in 2011, SNCR in 2014, semi-dry scrubber in 

2014, and Boardman Plant boiler ceasing operation in 2020).

The difference in cost per MWh is equal to the fully-allocated cost per MWh of a 

combined-cycle combustion turbine facility, using real levelized fixed costs, minus the 

dispatch cost per MWh of Boardman (i.e., fuel, variable O&M and other variable costs, 

but no fixed costs). This difference in cost per MWh is then multiplied by the change in 

Boardman megawatt-hour output to arrive at the “replacement power cost.” This analysis 

is included in Appendix G. 

This analysis understates the cost to the Boardman Plant as it uses the same 

modeling assumptions (e.g. 30 $/ton CO2 cost, PGE’s ownership share, fuel price 

forecast, etc.) that are used in the IRP process.11 The analysis determined that ceasing 

operation of the Boardman Plant boiler prematurely in 2020 causes a NPV cost difference 

of over $468 million (in 2010$) under the above-described methodology. When this cost 

of accelerating installation of replacement power is considered along with the direct cost 

of the semi-dry scrubber, the direct cost-effectiveness of installing semi-dry scrubbers in 

2014 increases to $14,191/ton. This cost-effectiveness value is clearly in excess of any 

reasonable cost-effectiveness threshold. 

6.4.1 NOx Control Technologies 

In addition to the NLNB/MOFA system being implemented, SNCR and SCR 

were compared to determine their respective improvement to visibility in the Class I 

areas. Of the two, the control package utilizing SCR has significantly greater costs of 

compliance. Both technologies have negative energy impacts and negative non-air 

quality environmental impacts although SNCR results in additional NOX reductions at a 

much lower incremental cost than SCR. Therefore, consistent with the regulations in the 

current Regional Haze Plan, SNCR is appropriate as a supplement to NLNB/MOFA in 

establishing BART limits. 

11 Because the IRP considers only the impact to PGE, and not the remainder of the owners, it does not 

capture the true replacement power cost. However, the “PGE only” values are being relied upon for this 

analysis so as to maintain consistency between what the PUC reviews and what is presented to DEQ for 

review. 
Boardman Plant Impact Analysis (Step 4) 

082710 6-13 

6.4.2 SO2 Control Technologies 

The three technically feasible SO2 post-combustion control technologies as well 

as the most effective technically feasible SO2 pre-combustion control technology were 

evaluated to determine their respective improvement to visibility in the Class I areas. 

The use of a reduced sulfur coal restriction compares favorably to the post-combustion 

control technologies. Of the three post-combustion controls, the costs of compliance and 

the negative non-air quality environmental impacts are greatest for the semi-dry FGD and 

wet FGD control technology. The most effective pre-combustion control technique 

(reduced sulfur coal restriction of 0.60 lb/MMBtu, as emitted SO2) presents none of the 

negative non-air quality environmental impacts presented by the post-combustion 

controls. The imposition of a reduced sulfur coal restriction (RSCR) is consistent with 

the concept of pollution prevention.

Both the wet FGD and semi-dry FGD technologies pose high costs of compliance 

when compared to adoption of a reduced sulfur coal restriction or dry sorbent injection 

and when considered in relation to the proposed date by which PGE must cease operation 

of the Boardman Plant boiler. In addition, the remaining useful life of the existing source 

will be very short if the regulations are modified to impose December 31, 2020 as the 

date by which PGE must cease operation of the Boardman Plant boiler. In light of the 

cost-effectiveness of wet FGD and semi-dry FGD exceeding a reasonable threshold, these 

technologies are eliminated from consideration in light of PGE’s commitment to take a 

federally enforceable condition to cease Boardman Plant boiler operations by December 

31, 2020. The use of reduced sulfur coal (0.60 lb/MMBtu, as emitted SO2, annual 

average) and the implementation of a Dry Sorbent Injection system (subject to a pilot 

study) constitute BART for SO2.

6.4.3 PM Control Technologies 

 A fabric filter has the least expensive direct annual cost, whereas the COHPAC 

system has the least expensive capital cost. The total annualized cost for either a 

COHPAC or a fabric filter system is around $23 million. A wet ESP has significantly 

higher annualized cost. However, all three technologies pose high costs of compliance 

when considered in relation to the existing controls and the proposed date by which PGE 

must cease operation of the Boardman Plant boiler. In addition, the remaining useful life 

of the existing source will be very short if the regulations are modified to impose 

December 31, 2020 as the date by which PGE must cease operation of the Boardman 

Plant boiler. In light of such a commitment, the remaining useful life of the Boardman 

Plant is too short to justify any of the replacement control technologies and the existing 

ESP should be the basis for establishing BART/Reasonable Progress limits. 
Boardman Plant Visibility Impacts (Step 5) 

082710 7-1 

7.0 Visibility Impacts (Step 5) 

Evaluation of visibility impacts is the fifth step required under the BART 

guidelines, but not for the Reasonable Progress process. This step addresses the visibility 

improvements that would result from installation of the top-ranked technology options 

identified in the impact evaluation (Step 4). The visibility improvements are represented 

in terms of the difference between pre-BART controls and the post-BART controls 

analyses. 

Modeling analyses were conducted using CALPUFF (version 6.131). First, 

emissions associated with pre-BART controls were modeled to establish the baseline for 

the pre-BART control analyses. Second, individual post-BART control technologies 

were analyzed for use in selecting final control alternatives. 

The methodology used in this analysis was presented in Protocol for the 

Application of CALPUFF Determination Modeling Pursuant to BART Regulation—PGE 

Boardman Plant (Revised) (Protocol) (CH2M HILL, 2007). The protocol was initially 

approved by DEQ on January 18, 2007. As specified in the protocol, all Class I areas 

within a 300 kilometer (km) radius of the plant were included in the analysis. In addition, 

although not a Class I area, the Columbia River Gorge National Scenic Area (CRGNSA) 

was also modeled. However, CRGNSA was modeled for informational purposes only as 

requested by DEQ. A copy of the protocol and the DEQ approval are provided in 

Appendix F. 

The following sections discuss in greater detail the modeling methodology and 

results. 

7.1 Modeling Methodology 

The EPA-approved CALPUFF modeling system was used to assess the visibility 

impacts as required by the EPA in the BART guideline. CALPUFF is a non-steady-state 

Lagrangian dispersion model that simulates pollutant releases as a continuous series of 

“puffs.” The Lagrangian dispersion capabilities are coupled with cooperative algorithms 

for modeling wet and dry deposition, chemical transformation, and plume fumigation. 

The modeling system is supported by three primary programs: 

x CALMET Version 6.211, Level 060414 

x CALPUFF Version 6.112, Level 060412 

x CALPOST Version 6.131, Level 060410 
Boardman Plant Visibility Impacts (Step 5) 

082710 7-2 

CALMET is used to create three-dimensional wind fields based on geophysical 

and meteorological data. The CALMET data used in CALPUFF was provided by DEQ 

and included meteorological data for 2003, 2004, and 2005. The output of the CALPUFF 

model consists of binary concentration data files. CALPOST post-processes these data on 

the basis of specified input parameters that translate pollutant concentration data into 

visibility impacts. 

CALPUFF was run using the control file settings summarized in the modeling 

protocol. The BART guidelines call for evaluation of the 98th percentile visibility impact 

in a year or modeling period. The 98th percentile translates to the 8th highest day in a 

year or the 22nd highest day in the 3-year modeling period. The higher of the 8th and 

22nd highs represents the highest visibility impact in terms of magnitude. Additionally, 

the number of days where the 24hr change in visibility exceeds 0.5 deciview was 

calculated for each year modeled to address frequency of visibility impacts. 

Fourteen Class I areas and the CRGNSA were evaluated. A figure showing the 

modeling domain covering these areas is included in Appendix F in the modeling 

protocol. The modeling domain was established to encompass the Boardman Plant and 

allow for a 50 km buffer around the Class I areas that were within 300 km of the facility. 

The 14 Class I areas included in the analysis are as follows: 

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 (2009 updated receptors) 

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 

Ottersburg (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 state BART Modeling Protocol and the modeling protocol provided 
Boardman Plant Visibility Impacts (Step 5) 

082710 7-3 

in Appendix F. The ozone data incorporated in the file was compiled from state and 

federal monitors located throughout Washington, Idaho, and Oregon. The ozone.dat file 

is considered an addition to the protocol and accepted for use in BART modeling. 

Acceptance of this approach was documented in a memo from Phil Allen of Oregon DEQ 

to Ray Hendricks of PGE dated August 28, 2007. A copy of the memo is provided in 

Appendix F. 

7.2 Emissions 

Table E-1 summarizes the emission rates and stack parameters that were used for 

the exemption modeling and each BART control scenario. Emission rates and stack 

parameters have been revised since the January 2007 protocol to reflect 2010 design 

information. The PM10 emissions provided included the front half filterable emissions 

only. Other particulate species emissions (elemental carbon, fine PM, coarse PM, 

organic carbon, and inorganic condensables (SO4)) were calculated in accordance with 

National Park Service speciation guidelines for dry-bottom pulverized coal boilers12. As 

such, NPS speciation of PM emissions are a function of coal higher heating value, sulfur 

content, ash content, and boiler heat input rate. These parameters are provided in 

Appendix A. The result of NPS PM speciation are included with all modeled pollutant 

species as follows: 

x Nitrates (NOx).

x Sulfur Dioxide (SO2). 

x Nitric Acid (HNO3) (modeled, not emitted). 

x Total PM/PM10:

- 61.3 % Filterable: 

 1.0 % Elemental Carbon (EC) (< 2.5 microns [ȝm]). 

 26.2% PM Fine (PMF) (< 2.5 ȝm). 

 34.1% PM Coarse (PMC) (2.5 – 10 ȝm). 

- 38.7% PM Condensable: 

 7.7 % Organic Carbon (OC) (secondary organic aerosol 

[SOA]). 

 31.0% Inorganic Aerosol (SO4).

 0.0 % Non-SO4 Inorganic Aerosol (NO3).

12 http://www.nature.nps.gov/air/permits/ect/ectCoalFiredBoiler.cfm. 
Boardman Plant Visibility Impacts (Step 5) 

082710 7-4 

7.3 Control Technologies 

The six post-control technologies evaluated in Step 4 of the BART process were 

evaluated in the visibility impact analysis. Individual PM control technologies were not 

evaluated because of the small contribution PM makes to visibility compared to NOX and 

SO2 in the baseline modeling. The total visibility impact related to PM control 

technologies for the baseline modeling was less than two percent. Furthermore, SO2

control technologies include a PJFF system. 

The control technologies evaluated include three NOX controls, three SO2 controls 

with PJFF, and one combined NOX and SO2 with PJFF control: 

x NOx:

- New LNBs with modified OFA system and SCR 

(NLNB/MOFA/SCR). 

- New LNBs with modified OFA system and SNCR 

(NLNB/MOFA/SNCR).

- New LNBs with modified OFA system (NLNB/MOFA). 

x SO2 and PM: 

- Wet FGD and PJFF (WFGD/PJFF). 

- Semi-Dry FGD and PJFF (SDFGD/PJFF). 

- Dry Sorbent Injection and Reduced Sulfur Coal Restrictions 

(DSI/RSCR).

- Reduced Sulfur Coal Restrictions (RSCR). 

7.4 Modeling Results 

The tables in this section provide a summary of the visibility impacts and 

improvements based on modeling results from the different control technology scenarios. 

A more comprehensive listing of modeling results for each Class I area and the CRGNSA 

by technology is presented in Appendix E. 

Table 7-1 provides a summary of maximum and minimum impacts of all Class I 

areas modeled for each control scenario in terms of delta deciviews and days where 

visibility impacts are greater than 0.5 deciviews. Results of the baseline scenario are 

included in the table for comparison. The RSCR control scenario shows the highest 

impacts out of all of the post-BART control scenarios. However, the maximum impacts 

are statistically similar and vary from 3.25 to 4.64 delta-deciviews. A similar distribution 

is shown for the minimum impacts of each scenario. Additionally, Table 7-1 shows the 

number of days where the change in visibility exceeds 0.5 delta-deciview. Again, 

impacts in terms of days for all other scenarios are statistically similar. 
Boardman Plant Visibility Impacts (Step 5) 

082710 7-5 

Table 7-1 

Visibility Impact and Improvement Summary 

Impacts in Terms of ǻdv (1)

Scenarios Max Impact 

Max 

Improvement Min Impact 

Min

Improvement 

Baseline 5.14 -- 1.15 -- 

NOX Controls 

NLNB/MOFA 3.85 1.29 0.85 0.25 

NLNB/MOFA/SNCR 3.66 1.48 0.83 0.30 

NLNB/MOFA/SCR 3.25 1.89 0.69 0.44

SO2 Controls 

RSCR 4.64 0.50 1.02 0.14 

DSI/RSCR 4.25 0.89 0.90 0.25 

SDFGD/PJFF 3.76 1.38 0.70 0.42 

WFGD/PJFF 3.91 1.23 0.66 0.49

Impacts in Terms of Days > 0.5 ǻdv (2)

Scenarios Max Impact 

Max 

Improvement Min Impact 

Min

Improvement 

Baseline 324 -- 60 -- 

NOX Controls 

NLNB/MOFA 239 103 40 20 

NLNB/MOFA/SNCR 234 111 37 23 

NLNB/MOFA/SCR 212 160 29 31

SO2 Controls 

RSCR 278 46 46 6

DSI/RSCR 243 81 37 21 

SDFGD/PJFF 235 129 28 32 

WFGD/PJFF 233 150 26 34

Highest value of all scenarios presented shown in bold text. 

(1) Based on maximum of annual 8th highest and 3-yr 22nd highest 24-hr impacts. 

(2) Number of days based on the entire 3-year monitoring period. 

Maximum visibility improvements are also provided in Table 7-1 both in terms of 

deciviews and reduction in days with visibility impacts greater than 0.5 delta-deciviews. 

The improvement in deciviews represents the best improvement seen in any Class I area 

when comparing the 98th percentile delta-deciview between the control scenario and 
Boardman Plant Visibility Impacts (Step 5) 

082710 7-6 

baseline. The NLNB/MOFA/SCR and WFGD/PJFF scenarios show the highest 

maximum and highest minimum visibility improvements. 

The baseline model run shows that maximum visibility impacts in terms of 

frequency occur at Hells Canyon Class I area receptors; in terms of magnitude, maximum 

impacts occur at Mount Hood. Therefore, frequency and magnitude of impacts are 

assessed for these two Class I areas and presented in Table 7-2. The NLNB/MOFA/SCR 

scenario produces the best visibility improvements in terms of frequency at Hells Canyon 

and magnitude at Mount Hood. 
Boardman Plant Visibility Impacts (Step 5) 

082710 7-7 

Table 7-2 

Hells Canyon and Mount Hood Visibility Improvement Summary 

Improvement Over Baseline in Terms of ǻdv (1) – Mount Hood 

Scenarios Maximum Improvement 

NOX Controls 

NLNB/MOFA 1.29 [25.0%] 

NLNB/MOFA/SNCR 1.48 [28.8%] 

NLNB/MOFA/SCR 1.89 [36.8%] 

SO2 Controls 

RSCR 0.50 [9.7%] 

DSI/RSCR 0.89 [17.2%] 

SDFGD/PJFF 1.38 [26.8%] 

WFGD/PJFF 1.23 [23.9%] 

Improvement Over Baseline in Terms of Days 

Reduced < 0.5 ǻdv (2) – Hells Canyon 

Scenarios Maximum Improvement 

NOX Controls 

NLNB/MOFA 103 [31.8%] 

NLNB/MOFA/SNCR 111 [34.3%] 

NLNB/MOFA/SCR 160 [49.4%] 

SO2 Controls 

RSCR 46 [14.2%] 

DSI/RSCR 81 [25.0%] 

SDFGD/PJFF 129 [39.8%] 

WFGD/PJFF 150 [46.3%] 

Highest value of all scenarios presented shown in bold text. 

(1) Based on maximum of annual 8th highest and 3-yr 22nd highest 24-hr impacts 

from all Class I receptors. 

(2) Number of days based on entire 3-year monitoring period. 
Boardman Plant Selection of Best Alternative 

082710 8-1 

8.0 Selection of Best Alternative 

The CAA and the Guidelines specify that after gathering the data presented in the 

previous pages of this report, five factors must be applied in order to determine what 

constitutes BART and four factors must be applied in order to determine Reasonable 

Progress. The BART factors, identified in CAA Section 169A(g)(2) and codified in 40 

C.F.R. § 51.308(e)(1)(ii), are: (1) the costs of compliance, (2) the energy and non-air 

quality environmental impacts, (3) any existing pollution control technology in use at the 

source, (4) the remaining useful life, and (5) the degree of improvement in visibility 

which may reasonably be anticipated to result from the use of such technology. The 

Reasonable Progress factors, identified in CAA Section 169A(g)(1) are: (1) the costs of 

compliance, (2) the time necessary for compliance, (3) the energy and non-air quality 

environmental impacts, and (4) the remaining useful life. 

Consistent with the EPA guidelines and the statutory requirements, PGE 

completed its BART and Reasonable Progress analyses. The basis for its BART and 

Reasonable Progress determinations for each of the three BART pollutants is outlined 

below.

8.1 Selection of PM BART 

The three technology options identified in Table 5-4, each offered the same 

degree of control. All of the options have extremely high cost effectiveness values in 

excess of $180,000 per ton PM removed. The COHPAC system is the least cost option, 

however there are several other issues with a COHPAC system that need to be addressed.

The COHPAC system is a less common technology, and limited operating 

experiences are available. Secondly, the removal of large particulates in the cold-side 

ESP will result in maintenance concerns. The filter cake, which forms on the surface of 

the fabric bags, plays an essential role in filtering PM. A filter cake containing both large 

and small particulates is best. Since the ESP in the COHPAC removes larger particles, 

the filter cake will consist primarily of smaller particles, which are less effective at 

filtering PM. Additionally, the filter bags will plug the bag material, since small 

particulates are more likely to become lodged inside the filter membrane. The 

requirement for a custom filter bag may mitigate the above mentioned issues, but these 

custom bags will cost more. 
Boardman Plant Selection of Best Alternative 

082710 8-2 

The Boardman Plant’s existing controls include a highly efficient dry ESP for PM 

control. Since the cost effectiveness of any additional control technology is so high, 

additional PM control technologies cannot be justified as BART . Therefore, continued 

use of the existing ESP is considered BART for particulate control. 

8.2 Selection of SO2 BART 

Due to the Boardman Plant boiler’s short remaining useful life, neither a wet FGD 

nor a semi-dry FGD could be justified for SO2 control. The most economical postcombustion control option for SO2 control is the DSI system (subject to pilot study to 

determine level of control between 0.4 lb/MMBtu and 0.6 lb/MMBtu) with reduced 

sulfur coal with a annualized capital cost of $4.5 million and an annual operating cost of 

$13 million (without considering replacement power costs). The next most economical 

post-combustion control option for SO2 control is a semi-dry FGD with an annualized 

capital cost of $69.4 million and an annual operating cost of $9 million (without 

considering replacement power costs). Due to the short Boardman Plant boiler operating 

life, the annual expense for the semi-dry FGD is over $78 million per year (without 

considering replacement power costs). When replacement power costs are included, as 

they must be for this is a mandatory component of premature closure, the cost per ton of 

SO2 removed rises to $14,191. This amount is far in excess of any reasonable costeffectiveness threshold. The other post-combustion control option, a wet FGD, is 

significantly more expensive than the DSI system and semi-dry FGD, resulting in an 

annual cost of over $101 million per year (without considering replacement power costs). 

Neither of the semi-dry FGD and wet FGD costs are reasonable and therefore excessive 

economic impacts are a basis for not considering either post-combustion control 

technology as appropriate for BART. By contrast, a DSI system and the imposition of a 

reduced sulfur coal limit reducing the allowable SO2 emissions by 67 percent (contingent 

on pilot study) poses a smaller capital investment with an additional fuel cost but at a 

level acceptable to PGE. 

The EPA Guidelines state that it is appropriate to take into account the 

affordability of particular controls as part of the BART analysis where the cost of 

installing and operating the controls is judged to have a severe impact on plant operations 

and plant viability. Since any SO2 control technology would only be used for 6.5 years 

due to the Boardman Plant boiler shutdown in 2020, the plant closing is a key 

consideration in concluding that neither semi-dry FGD nor wet FGD post-combustion 

control technology is viable. However, because installing a DSI system and utilizing 

reduced sulfur coal (pre-combustion controls) involve primarily operating cost and lower 

capital cost, these technologies are not as sensitive to the early shutdown date.
Boardman Plant Selection of Best Alternative 

082710 8-3 

The non-air quality environmental and energy impacts are significant for all postcombustion technologies and nonexistent for the pre-combustion control technology. 

Both the wet FGD and the semi-dry FGD technologies consume significant amounts of 

water (around 300 gallons per minute for semi-dry FGD and over 600 gallons/minute for 

wet FGD). In the arid area of eastern Oregon where the Boardman Plant is located, water 

is a scarce commodity. A water-intensive process such as these could have an 

unnecessary impact on the region’s existing water resources. Finally, the energy impacts 

are significant for both technologies as compared to DSI system with reduced sulfur coal. 

In addition, the adoption of a reduced sulfur coal restriction imposes no non-air quality 

environmental impacts as it relies upon pollution prevention, thereby avoiding the 

potential to shift impacts to different media. Similarly, the use of reduced sulfur coal is 

not anticipated to have any energy impacts, in stark contrast to the post-combustion 

controls.

All three control technologies produce significant improvement in visibility 

impacts, but the marginal improvement attributable to wet FGD and semi-dry FGD, as 

compared to DSI/RSCR are not sufficient to merit their choice as BART. The visibility 

modeling demonstrated that wet and semi-dry FGD result in an approximately 24 and 27 

percent improvement, respectively, over baseline at the Mt. Hood Wilderness Area. 

Adoption of DSI with a reduced sulfur coal restriction would reduce the visibility impacts 

at the Mt. Hood Wilderness Area by 17 percent. Therefore, while the visibility 

improvements attributable to FGD controls are greater than those attributable to the DSI 

system with reduced sulfur coal restriction, the marginal benefits are limited. Were either 

FGD control required as BART, then the Boardman Plant boiler would need to be run 

beyond the proposed closure date in order to ease the cost recovery schedule. By 

contrast, if the DSI system with a reduced sulfur coal restriction is imposed as BART 

then the allowable SO2 emission rate would drop by 67% and the visibility impacts on the 

98th percentile day would improve by 17.2 percent (as compared to 27 percent for the 

semi-dry FGD). The short and long term benefits (e.g., improved visibility, reduced 

greenhouse gases and criteria pollutants and reduced economic impacts to PGE’s 

customers) that arise from employing a DSI system with a reduced sulfur coal restriction 

and imposing a December 31, 2020 deadline for ceasing boiler operation outweigh the 

benefits from operating the Boardman Plant boiler with an FGD system through the end 

of the plant’s lifetime. 

Based on an analysis of all the statutory factors, it was concluded that the pilot 

study of the DSI system and the imposition of a reduced sulfur coal limit that ultimately 

drops the allowable SO2 emissions by 67 percent (contingent on a successful pilot study) 

and the adoption of a requirement to cease Boardman Plant boiler operation by December 
Boardman Plant Selection of Best Alternative 

082710 8-4 

31, 2020 constitutes BART. Neither wet FGD nor semi-dry FGD were viable SO2

control options for the Boardman Plant. Installation of either technology imposes such 

significant costs that the plant would potentially need to delay its planned boiler 

shutdown date of December 31, 2020.13 In addition, the energy and non-air quality 

impacts of utilizing either technology are very costly. By contrast, the installation of the 

DSI system and the imposition of a reduced sulfur coal limit at the most restrictive end of 

the predicted technically feasible range (i.e., 0.40 lb/MMBtu, as emitted SO2, annual 

average) could be implemented by July 1, 2014 following a successful pilot study. 

Finally, consideration of remaining useful life independent of cost supports the concept 

that the interference with plant operations and risk of equipment malfunctions is not 

merited where the boiler will shut down 6.5 years after installation. 

The implementation of a DSI system and reduced sulfur coal cannot be 

accelerated beyond July 1, 2014. No reduction in the SO2 permit limit can be 

implemented until the existing coal supply contracts expire at the end of 2011. Once the 

contracts expire then PGE could begin purchasing reduced sulfur coal to blend with 

existing coal stockpiles. PGE projects that it would take until approximately June 30, 

2014 to consume all of the stockpiled coal. During the interim, PGE will conduct the 

pilot study of the DSI system.14

8.3 Selection of NOX BART 

The application of the statutory factors indicates that the installation of 

NLNB/MOFA in 2011 and SNCR in 2014 constitutes BART. DEQ identified multiple 

reasons in the Regional Haze Plan for why SCR is not an appropriate choice as BART. 

See, Regional Haze Plan at D-29. PGE does not disagree with the Department’s analysis 

in this regard. SNCR is a possible supplemental control that could be considered BART 

if the combustion controls are capable of reaching the limits in OAR 340-223-0030(1)(a). 

Therefore, PGE recommends that BART for NOx be revised to include a limit on NOX

emissions of 0.19 lb/MMBtu (12-month rolling average) in July 2014 and a requirement 

to cease operations of the Boardman Plant boiler no later than December 31, 2020. PGE 

13 Nothing in the Clean Air Act grants DEQ the authority to require cessation of operation of the 

Boardman Plant boiler as BART or Reasonable Progress. However, PGE is free to propose an early 

closure date that is then taken into account in establishing BART and Reasonable Progress controls. If 

DEQ concludes that either BART or Reasonable Progress requires SCR, FGD or upgraded PM controls, 

then PGE expressly withdraws consideration of premature closure of the plant as an element in the analysis. 

14 If the pilot testing shows that the combination of reduced sulfur coal and DSI cannot reach a SO2

limit of 0.4 lb/MMBtu while operating in conjunction with SNCR and mercury controls and without 

hindering compliance with mercury regulations and without causing or contributing a violation of the 

NAAQS or PSD increment for PM2.5 (assuming the same level of operation current reflected in the 

Boardman Plant’s plant site emission limit), DEQ will provide a procedure for establishing an alternative 

SO2 limit that is no higher than 0.6 lb/MMBtu. 
Boardman Plant Selection of Best Alternative 

082710 8-5 

also recommends that the BART regulations be revised to provide a compliance 

extension in the event that the Department fails to issue permits to construct for any 

controls in adequate time to install them by the deadline. 

8.4 Reasonable Progress 

Based on the statutory factors mandated by the Clean Air Act, there is no basis for 

imposition of any Reasonable Progress limit on the Boardman Plant if it closes in 2020. 

The Clean Air Act requires that visibility be restored to natural conditions by 2064. In 

order to ensure that the state complies with the Clean Air Act, EPA requires that Oregon 

identify the baseline visibility conditions, the visibility impacts associated with natural 

conditions and the uniform rate of progress necessary to get from the baseline to natural 

conditions. Oregon must then demonstrate to EPA how it intends to reach the periodic 

milestones so as to ensure compliance. For example, based on the 20 percent worst days, 

DEQ must reduce visibility impacts at Mount Hood from 14.9 dv to 8.4 dv by 2064. The 

next uniform rate of progress milestone is to achieve a reduction of 1.5 dv by 2018. The 

BART requirements that PGE is proposing will result in a 98th percentile reduction in 

visibility impacts at Mount Hood of 1.9 dv by 2014. In other words, the Boardman Plant 

emission reductions alone will achieve 127 percent of the required reduction and do so 

four years ahead of schedule. By committing to close the Boardman Plant, PGE will 

enable Oregon to achieve more than 60 percent of the visibility improvement needed by 

2064. In other words, based on the 98th percentile baseline impacts, closure of the 

Boardman Plant in 2020 by itself will enable Oregon to achieve the visibility 

improvements required to be achieved by 2051 more than 30 years early (i.e., in 2020). 

This analysis confirms that there is no basis for requiring additional controls based on 

Reasonable Progress.

8.5 Visibility Improvement for Combined BART Controls 

As a final step in the evaluation, visibility improvement was evaluated with the 

combination of controls identified as BART for particulate, SO2, and NOx (Table 8-1 and 

Appendix E). The modeling methodology used for this combination of controls 

evaluation was the same as the methodology summarized in Section 7.0. This control 

package includes the DSI system, reduced sulfur coal restriction, and 

NLNB/MOFA/SNCR. While these controls are very expensive to install, implement, and 

operate, they are predicted to result in an average improvement in the plant’s modeled 

visibility impacts across all Class I areas of 55.4 percent and an improvement at the most 

severely impacted Class I area of 51.4 percent. There would be, on average, only 25 days 
Boardman Plant Selection of Best Alternative 

082710 8-6 

per year where the impacts would exceed 1.0 deciview, as compared to 90 days per year 

in the exemption (i.e., baseline) modeling. 

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 (DSI system, reduced sulfur coal 

restriction, and NLNB/MOFA/SNCR). The modeling of the benefits predicted from the 

proposed BART control package show significant improvement in visibility in the 

CRGNSA. 

Table 8-1 summarizes the modeling results for the combination of DSI System, 

reduced sulfur coal restrictions and NLNB/MOFA/SNCR controls. As shown in 

Appendix E, the CRGNSA correlates reasonably well with maximum impacts at any 

Class I area. 

Table 8-1 

Visibility Impact Summary 

Boardman Plant BART Determination 

Combined Control Technologies 

Reduction in Number of Days 

Above 0.5 deciview at Highest 

Frequency Area - Hells Canyon 

Total (Percent Improvement) 

Reduction in Maximum 

Visibility Impact at 

Highest Magnitude Area 

- Mt Hood 

deciviews (Percent 

Improvement ) 

2003 2004 2005 2003-2005(1) 

NLNB/MOFA/SNCR and DSI with 

Reduced Sulfur Coal Restriction 

(Best Available Retrofit 

Technology)

76 

(66.1%) 

62 

 (57.9%) 

76 

 (74.5%) 

2.627 

 (52.7%) 

(1)Based on maximum of annual 8th highest and 3-yr 22nd highest 24-hr impacts. 

NLNB/MOFA/SNCR – New Low NOx Burners with Modified Overfire Air and Selective Non-Catalytic 

Reduction. 

DSI – Dry Sorbent Injection 
Boardman Plant References 

082710 9-1 

9.0 References 

(1) CH2M HILL, Protocol for the Application of CALPUFF Determination Modeling 

Pursuant to BART Regulation—PGE Boardman Plant (Revised), January 2007. 

(2) Federal Land Managers’ Air Quality Related Values Workgroup (FLAG), Phase I 

Report, December 2000. 

(3) Oregon Department of Environmental Quality (DEQ), Modeling Protocol for 

Washington, Oregon, and Idaho: Protocol for the Application of the CALPUFF 

Modeling System Pursuant to the Best Available Retrofit Technology (BART) 

Regulation, October 11, 2006. 

(4) US Environmental Protection Agency (EPA), Interagency Workgroup on Air 

Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations for 

Modeling Long-Range Transport Impacts, EPA-454/R-98-019, December 1998. 

(5) US Environmental Protection Agency (EPA), Guidance for Estimating Natural 

Visibility Conditions under the Regional Haze Rule, EPA-454/B-03-005, 

September 2003. 

(6) US Environmental Protection Agency (EPA), Regional Haze Regulations and 

Guidelines for Best Available Retrofit Technology (BART) Determinations,

Federal Register, Vol. 70, No. 128, pp. 39104–30172, July 6, 2005. 

(7) Columbia River Gorge Air Quality Study Science Summary Report (September 

24, 2007).
Boardman Plant Appendix A 

082710 A-1 

Appendix A 

Design Basis 
Boardman Plant Appendix A 

082710 A-2 
Boardman Plant Appendix A 

082710 A-3 
Boardman Plant Appendix B 

040210 B-1 

Appendix B 

Stack Outlet Conditions 
Boardman Plant Appendix B 

082710 B-2 
Boardman Plant Appendix C 

082710 C-1 

Appendix C 

Design Concept Definitions
Boardman Plant Appendix C 

082710 C-2 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Overfire Air System Operation 

Process Description Operate existing overfire air (OFA) system during normal operation. Existing OFA system currently only used when needed to meet

permit limit due to efficiency impacts. 

 Pollutant NOx

 Emissions 

 lb/MBtu 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MBtu 0.40 

 ton/yr 9,727 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type Wyoming, Subbituminous 

 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 used sparingly to be operational at all times. Boiler area. Addition of coal flow 

monitors in coal pipes leading to burner. Addition of water cannon system to boiler wall. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Addition of NOx optimization into combustion monitoring process. 

Fan Modifications None. 

Power Supply/Aux Power Modifications No significant aux power impacts from additional equipments. 

Enclosures Requirements None. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Boiler Slagging 

Other Assumptions 

Coal flow monitors, water cannon system, NOx optimization and monitoring systems added to overcome boiler slagging issues to allow OFA system operations. 

13% reduction expected. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Equipment is existing at plant but presently not used. 
Boardman Plant Appendix C 

082710 C-3 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Upgraded Low NOx Burners 

Process Description Low NOx Burners (LNB) - Upgrade existing. Modifications of burner tips and burner balancing using CFD modeling, combustion air 

monitoring and coal flow monitoring. 

 Pollutant NOx

 Emissions 

 lb/MBtu 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MBtu 0.38 

 ton/yr 9,241 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type Wyoming, Subbituminous 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other N/A 

Location of Major Process Equipment Upgrade/additional components to existing burners. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. 

Reagent Storage None. 

Control System Modifications None. 

Fan Modifications None. 

Power Supply/Aux Power Modifications None. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

The site has sufficient area available to accommodate construction activities including, but not limited to, offices, laydown, and staging. 

10% reduction expected. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Low NOx Burners already in operation. 
Boardman Plant Appendix C 

082710 C-4 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Upgraded Low NOx Burners with Existing OFA System Operation 

Process Description Upgrade existing Low NOx Burners (LNBs) with existing OFA system. Modifications of burner tips and burner balancing. 

 Pollutant NOx

 Emissions 

 lb/MBtu 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MBtu 0.32 

 ton/yr 7,782 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type Wyoming, Subbituminous 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other N/A 

Location of Major Process Equipment Upgrade existing burners. Location remains the same. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. 

Reagent Storage None. 

Control System Modifications None 

Fan Modifications None. 

Power Supply/Aux Power Modifications None 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

The site has sufficient area available to accommodate construction activities including, but not limited to, offices, laydown, and staging. 

40% reduction expected. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Low NOx Burners already in operation. Existing OFA system would be placed in operation full time. 
Boardman Plant Appendix C 

082710 C-5 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Selective Non-Catalytic Reduction (SNCR) 

Process Description Selective Non-Catalytic Reduction (SNCR) 

 Pollutant NOx

 Emissions 

 lb/MBtu 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MBtu 0.32 

 ton/yr 7,782 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type Wyoming, Subbituminous 

 Capacity factor 85.0% 

Consumables Reagent (Urea) 2,170 lb/hr 

 Water 533 gpm 

 Energy 186 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description No impact on ash sales. 

 Other Up to 10 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. 

Inlet/Outlet Connections and Interconnecting Ducts Install wall injectors and lance-type injectors for SNCR in the boiler. 

Reagent Storage Ammonia tank at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

The site has sufficient area available to accommodate construction activities including, but not limited to, offices, laydown, and staging. 

No boiler/duct stiffening included. 

Air heater modifications included in analysis. 

No impact on potential ash sales. 

Reagent is urea. 

30% reduction expected. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

082710 C-6 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Upgraded Low NOx Burners with Existing OFA System Operation 

and SNCR 

Process Description Upgrade existing Low NOx Burners (LNBs) with existing OFA system. Modifications of burner tips and burner balancing. Selective 

Non-Catalytic Reduction (SNCR) system for post-combustion reduction of NOx.

 Pollutant NOx

 Emissions 

 lb/MBtu 0.32 (Upgraded LNBs + OFA) 

 ton/yr 7782 

 Controlled Emissions 

 lb/MBtu 0.24 

 ton/yr 5,836 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type Wyoming, Subbituminous 

 Capacity factor 85.0% 

Consumables Reagent (Urea) 1630 lb/hr 

 Water 400 gpm 

 Energy 140 kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other Up to 10 ppm ammonia slip. 

Location of Major Process Equipment Upgrade existing burners. Location remains the same. Injection skid and ammonia tank at 

grade with truck unloading station. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Ammonia tank for SNCR at grade with injection skid.

Control System Modifications Control of additional equipment incorporated into current control system.

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

The site has sufficient area available to accommodate construction activities including, but not limited to, offices, laydown, and staging. 

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 

50% reduction expected. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

082710 C-7 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology New Low NOx Burners with Modified OFA System 

Process Description New low NOx burners (LNB), modified overfire air (OFA) system. Install new OFA ports at location to be determined during detailed 

engineering analysis. 

 Pollutant NOx

 Emissions 

 lb/MMBtu 0.426 

 ton/yr 10,349 

 Controlled Emissions 

 lb/MMBtu 0.23 

 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 None 

 Energy N/A kW 

 Other None 

Byproduct Description Slight increase in LOI and CO. No impact on ash sales 

 Other N/A 

Location of Major Process Equipment Install new burners in the existing burner openings. Install new OFA ports at location to be

determined after analysis. 

Inlet/Outlet Connections and Interconnecting Ducts OFA and burners tie-in to existing air duct and coal pipes. 

Reagent Storage None. 

Control System Modifications Existing control system modification to utilize new equipment. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

x Water cannon system, NOx optimization, and monitoring systems added to overcome boiler slagging issues to allow OFA system operations 

x No major impact in plant availability. 

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

x No air heater modifications or boiler/duct stiffening included. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons Replacing older low NOx burners already in operation and modifying OFA system to support current technology low NOx burners is 

common retrofit system. 
Boardman Plant Appendix C 

082710 C-8 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology New Low NOx Burners, Modified Overfire Air and Selective 

Noncatalytic Reduction (SNCR) 

Process Description Selective Noncatalytic Reduction (SNCR) used in conjunction with new low NOx burners and modified overfire air 

 Pollutant NOx

 Emissions 

 lb/MMBtu 0.23 (from NLNB/MOFA) 

 ton/yr 5,593 

 Controlled Emissions 

 lb/MMBtu 0.19 

 ton/yr 4,620 

 Inlet Flow Basis, acfm 3,307,813 

 Pressure Drop Added NA 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Urea) 815 Lb/hr 

 Water 200 gpm 

 Energy 70 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Minimal impact on ash sales. 

 Other Up to 10 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. 

Inlet/Outlet Connections and Interconnecting Ducts Install wall injectors and lance-type injectors for SNCR in the boiler. 

Reagent Storage Storage tank for urea at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions 

x No major impact in plant availability. 

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

x No boiler/duct stiffening included. 

x Air heater modifications included in analysis. 

x No impact on potential ash sales. 

x Reagent used in SNCR process is aqueous urea. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

082710 C-9 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology New Low NOx Burners, Modified Overfire Air and Selective 

Catalytic Reduction (SCR) 

Process Description Install a new SCR system in conjunction with new Low NOx Burners and Modified Overfire Air. 

 Pollutant NOx

 Emissions 

 lb/MMBtu 0.23 (from NLNB/MOFA) 

 ton/yr 5,593 

 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) 364 lb/hr 

 Energy 2,509 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 SCR reactor above space between the boiler and air heater. Install vaporizers at grade. 

Inlet/Outlet Connections and Interconnecting Ducts SCR inlet and outlet ducts connected into duct entering the air heater. 

Reagent Storage Locate NH3 storage at grade in suitable protective structure or remotely to limit risk from leaks. 

Control System Modifications Existing control system modification to utilize new equipment. 

Fan Modifications Assume booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume medium cost expansion will be required for aux electric system. 

Enclosures Requirements Ammonia injection grid area and sonic horns are to be enclosed. 

Demolition or Relocation Requirements Existing economizer outlet ductwork and boiler building wall. 

Major Constructability Issues Finding support steel location under SCR reactor. Tying the SCR into the ductwork 

downstream of the economizer in the ductwork. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning. SO2 to SO3 conversion by the catalyst, causing pluggage and 

corrosion in air heater. 

Other Assumptions 

x No major impact in plant availability. 

x Temperature range of flue gas at economizer outlet is acceptable after modifications of boiler superheater section. 

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

x Air heater modifications, flue gas handling systems and ammonia handling systems included. 

x No boiler/duct stiffening included. 

x Modifications made to boiler heat transfer surface area to optimize boiler flue gas outlet temperature for SCR operations. 

x No impact on potential ash sales and no additional heating i.e. economizer bypass or duct burners required to achieve operating temperature at low loads. 

x Reagent is ammonia and can be anhydrous, aqueous or from urea. Anhydrous ammonia selected as basis. 

x SCR reactor includes three initial catalyst layers and one spare layer (3 + 1 arrangement). 

x Energy consumption includes ID fan power requirements to overcome SCR system resistance. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

082710 C-10 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Wet Flue Gas Desulfurization (FGD) and upstream Fabric Filter 

Process Description Limestone forced oxidation wet flue gas desulfurization process (wet scrubber) with fabric filter upstream of wet scrubber for mercury 

and particulate control. Description is typical for all absorber/scrubber based FGD systems. 

 Pollutant SO2

 Emissions 

 lb/MMBtu 0.614 

 ton/yr 14,902 

 Controlled Emissions 

 lb/MMBtu 0.07 

 ton/yr 1,700 

 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) 6.244 Tph 

 Water 631.4 Gpm 

 Energy 16,188 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Calcium Sulfite (CaSO3x1/2H20), Calcium Sulfate (CaSO4x2H2O) mixture 

 Production Rate 11.5 Tph 

Location of Major Process Equipment Fabric filter and wet FGD absorber module flue gas path location is after ID fans and before

new wet stack. Reagent preparation and byproduct dewatering equipment to be located around 

absorber module, location of new wet stack to be determined later. 

Inlet/Outlet Connections and Interconnecting Ducts Connected to ID fan outlet ducts and discharge to the new stack. 

Reagent Storage Silo for reagent will be required. 

Control System Modifications New stand-alone control system, tie in to plant DCS control system. 

Fan Modifications Assume new booster/ID fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Aux electric system modifications will be required. 

Enclosures Requirements Oxidation air blower building, control building, slaker and slurry tank building, byproduct 

dewatering building. 

Demolition or Relocation Requirements Abandon existing stack in place. 

Major Constructability Issues Construction of new stack with impacts on restricted safety zone possibly limiting or extending 

schedule for construction of ductwork, fabric filter system, ID booster fans and wet FGD system. 

Significant Issues or Challenges Tie-in to the current fan ID outlets during a major planned outage. 

Other Assumptions 

x No modifications to ESP and existing ESP remain in service 

x No impact on potential ash sales since existing ESP remains in operation upstream of new AQC equipment. 

x One FGD absorber is assumed. 

x Fabric filter upstream of wet FGD system is required for mercury and particulate control. 

x New wet chimney included. 

x No major impact on plant availability is assumed. 

x Flue gas handling and ID fan system costs included. 

x 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 

082710 C-11 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Semi-Dry Flue Gas Desulfurization (FGD) 

Process Description Semi-dry lime FGD process using the Spray Dryer Absorber (SDA) with downstream Pulse Jet Fabric Filter (PJFF) 

 Pollutant SO2

 Emissions 

 lb/MMBtu 0.614 

 ton/yr 14,902 

 Controlled Emissions 

 lb/MMBtu 0.12 

 ton/yr 2,913 

 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) 5.3 tph 

 Water 358 gpm 

 Energy 4,355 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Calcium Sulfite (CaSO3x1/2H20), Calcium Sulfate (CaSO4x2H2O) mixture 

 Production Rate 10.6 tph 

Location of Major Process Equipment Spray Dryer Absorber and Pulse Jet Fabric Filter flue gas flow path location is after ID fans and 

before stack. 

Inlet/Outlet Connections and Interconnecting Ducts Connected to ID fan outlet ducts and discharge to the existing stack. 

Reagent Storage Silo for reagent will be required. 

Control System Modifications New stand-alone control system, tie in to plant DCS control system. 

Fan Modifications Assume new booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Aux electric system modifications will be required. 

Enclosures Requirements Compressor building, control building, slaker and slurry tank building. Enclose the top pendant 

areas, the bottom exit and hopper areas of spray dryer and fabric filter. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Tie-in to the current fan ID outlets and stack breaching during a major planned outage. 

Other Assumptions 

x No modifications to ESP and existing ESP remain in service 

x No impact on potential ash sales since existing ESP remains in operation upstream of new AQC equipment. 

x Two x 60% FGD absorbers are assumed. 

x PJFF provided as integral part of scrubber system also provides particulate control. 

x No major impact on plant availability is assumed. 

x Flue gas handling system and ID fans upgrades/addition included. 

x Lime reagent storage and handling system included.

x Existing chimney is acceptable for resulting flue gas.

x The FGD byproducts solids would be collected in the new fabric filter and would require a separate ash transport system and silo (included). 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

082710 C-12 

Design Concept Definition

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Reduced Sulfur Coal Restriction 

Process Description A reduced sulfur coal restriction for the Boardman boiler will reduce sulfur dioxide emissions from the current baseline emission rate.

 Pollutant SO2

 Emissions 

 lb/MMBtu 0.614 

 ton/yr 14,902 

 Controlled Emissions 

 lb/MMBtu 0.6 

 ton/yr 14,562 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 0 

 Coal Source and Type PRB & other coals that will 

result in sulfur dioxide emissions 

below 0.6 lb SO2 / MMBtu 

 Capacity factor 100 % 

Consumables None 

 

Maintenance None 

Byproduct None 

Location of Major Process Equipment No new process equipment 

Inlet/Outlet Connections and Interconnecting Ducts No new connections or ductwork 

Reagent Storage N/A 

Control System Modifications None 

Fan Modifications Low sulfur coals may affect fan power due to changes in coal Btu value 

Power Supply/Aux Power Modifications Low sulfur coals may affect auxiliary power due to changes in coal Btu value 

Enclosures Requirements None 

Demolition or Relocation Requirements None 

Major Constructability Issues None 

Significant Issues or Challenges Coal blending is an option that will require effective coal blending, coal accounting, and coal

management practices. 

Other Assumptions 

x No modifications to ESP and existing ESP remain in service 

x No impact on potential ash sales 

x No major impact on plant availability is assumed. 

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons -- 
Boardman Plant Appendix C 

082710 C-13 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Dry Sorbent Injection and Reduced Sulfur Coal Restriction 

Process Description A Dry Sorbent Injection and reduced sulfur coal restriction for the Boardman boiler will reduce sulfur dioxide emissions from the

current baseline emission rate. 

 Pollutant SO2

 Emissions 

 lb/MMBtu 0.614 

 ton/yr 14,902 

 Controlled Emissions 

 lb/MMBtu 0.4 

 ton/yr 9,714 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 0 

 Coal Source and Type PRB or other coals that will 

result in sulfur dioxide emissions 

below 0.6 lb SO2 / MMBtu 

 Capacity factor 100 % 

Consumables Dry Reagent (Trona, Sodium Bicarbonate or Hydrated Lime) 

Maintenance None 

Byproduct Dry Sorbent injection mixed with Fly ash 

Location of Major Process Equipment Dry sorbent will be injected upstream of the particulate removal device 

Inlet/Outlet Connections and Interconnecting Ducts No new connections or ductwork 

Reagent Storage Chemical storage tank and silo for reagent will be required 

Control System Modifications New stand-alone control system, tie in to plant DCS control system. 

Fan Modifications Low sulfur coals and sorbent injection may affect fan power due to changes in coal Btu value 

Power Supply/Aux Power Modifications Low sulfur coals and sorbent injection may affect auxiliary power due to changes in coal Btu

value

Enclosures Requirements None 

Demolition or Relocation Requirements None 

Major Constructability Issues None 

Significant Issues or Challenges x Coal blending is an option that will require effective coal blending, coal accounting, and 

coal management practices. 

x Potential modifications to existing ESP 

x Impact on ash sales 

x May not comply with New Source Performance Standard for particulate emissions 

Other Assumptions 

x No major impact on plant availability is assumed. 

x Reagent storage and handling system included. 

x Existing chimney is acceptable for resulting flue gas.

State of Availability Commercial. 

Technical Feasibility Not technically feasible. 

Reasons No commercial installation at similarly sized/configured source. Pilot study required to determine effectiveness of control option and 

level of sorbent injection that could be conducted without affecting mercury control and without triggering NSPS and without causing

PM2.5 NAAQS and/or increment violation. See discussion in Section 4.2.2. 
Boardman Plant Appendix C 

082710 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) 6 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy 3,565 kW 

 Maintenance 3% of direct material cost. (Not including bag replacement). 

Byproduct Description None. 

 Other N/A 

Location of Major Process Equipment Replace existing ESP with new Pulse Jet Fabric Filter (PJFF). Flue gas flow path location will be 

after air heater outlet and before existing ID fan inlet. 

Inlet/Outlet Connections and Interconnecting Ducts Ductwork connection after air heater outlet and before existing ID fan inlet.

Reagent Storage None. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume new booster fans or ID fan modifications and duct stiffening will be required. 

Power Supply/Aux Power Modifications Aux electric system modification will be required. 

Enclosures Requirements The top pendent area and bottom hopper area of the fabric filter should be enclosed. 

Demolition or Relocation Requirements None. Existing ESP to be abandoned in place. 

Major Constructability Issues Modification to existing ash handling system. 

Significant Issues or Challenges Installation of new PJFF during a planned major outage. 

Other Assumptions 

x No major impact in plant availability. 

x Collector bag life is 2 years. 

x Existing ash disposal system should be capable of servicing the PJFF. 

x Flue gas handling and ID fan system upgrades/addition included. 

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

State of Availability Commercial. 

Technical Feasibility Technically feasible and applicable. 

Reasons .
Boardman Plant Appendix C 

082710 C-15 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Compact Hybrid Particulate Collector (COHPAC) 

Process Description High A/C Ratio Fabric filter, or known as Compact Hybrid Particulate Collector (COHPAC) 

 Pollutant PM 

 Emissions 

 lb/MMBtu 0.0170 

 ton/yr 417 

 Controlled Emissions 

 lb/MMBtu 0.012 

 ton/yr 295 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 8.0 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent None 

 Energy 4504 kW 

 Maintenance 6% of direct material cost (not including bag costs) 

Byproduct Description None. 

 Other N/A 

Location of Major Process Equipment COHPAC flue gas path location to be downstream of existing ESP. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to flue gas ductwork downstream of existing ESP. 

Reagent Storage None. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume new booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Aux electric system upgrade will be required. 

Enclosures Requirements The top pendant area and the bottom hopper area are enclosed. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Tie-in to the current ID fan outlets during a major planned outage. 

Other Assumptions 

x No major impact in plant availability. 

x Collector bag life is 3 years. 

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

x The existing ESP will be left in place upstream of the fabric filter. The fly ash that is collected in the ESP is handled separately and can be sold. 

x COHPAC might be used as a component for mercury removal systems. 

x 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 

082710 C-16 

Design Concept Definition 

Site Name Boardman Units 1

Client Name Portland General Electric Process Technology Wet ESP 

Process Description Wet Electrostatic Precipitator (WESP or Wet ESP) 

 Pollutant PM 

 Emissions 

 lb/MMBtu 0.0170 

 ton/yr 417 

 Controlled Emissions 

 lb/MMBtu 0.012 

 ton/yr 295 

 Inlet Flow Basis, acfm 2,151,689 

 Pressure Drop Added (in. wc) 4.0 

 Coal Source and Type PRB 

 Capacity factor 85.0% 

Consumables Reagent (Mg(OH)2) 20 lb/hr 

 Water 100 gpm 

 Energy 1,752 kW 

 Maintenance 3% of direct material cost. 

Byproduct Description None. 

 Other N/A 

Location of Major Process Equipment Wet ESP flue gas path location to be downstream of existing ESP. Water treatment system to 

be located next to wet ESP. Additional byproduct disposal system is required. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to flue gas ductwork downstream of existing ESP. 

Reagent Storage (Mg(OH)2) storage at grade as part of water treatment system. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume new booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Substantial aux electric system modification will be required. 

Enclosures Requirements The top pendant area and the bottom hopper area are enclosed. 

Demolition or Relocation Requirements Abandon existing stack in place. 

Major Constructability Issues Construction of new stack with impacts on restricted safety zone possibly limiting or extending 

schedule for construction of other control technology equipment. 

Significant Issues or Challenges Tie-in to the current ID fan outlets during a major planned outage. 

Other Assumptions 

x No major impact in plant availability, however, periodic outages for intense off-line cleanings may be required. 

x Aux electric usage is a major factor if using wet ESP as a polishing filter and for SO3 mitigation. 

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

x The existing ESP will be left in place upstream of the WESP. The fly ash that is collected in the ESP is handled separately and can be sold. 

x Waste water treatment system included. 

State of Availability Commercial. 

Technical Feasibility Technically feasible. 

Reasons .
Boardman Plant Appendix D 

082710 D-1 

Appendix D 

Cost Analysis Summary
Boardman Plant Appendix D 

082710 D-2 

PGE Boardman BART Analysis - Cost Analysis 

Technology: New Low NOx Burners & Modified OFA System Date: August 4 2010

Cost Item Remarks/Cost Basis

CAPITAL COST 2010

Direct Costs

Purchased Material Costs

Low NOx Burners and OFA Equipment $5,452,700 S&L Engineering Estimate

Boiler Cleaning Equipment $1,186,900 S&L Engineering Estimate

CO Monitoring and Burner Management Equipment $2,200,000 S&L Engineering Estimate

Piping and Insulation $70,000 S&L Engineering Estimate

Electrical Equipment $233,700 S&L Engineering Estimate

Controls and Instrumentation $648,000 S&L Engineering Estimate

Direct Costs - Installation Costs

Low NOx Burners and OFA Equipment $5,252,400 S&L Engineering Estimate

Boiler Cleaning Equipment $513,100 S&L Engineering Estimate

CO Monitoring and Burner Management Equipment $865,500 S&L Engineering Estimate

Piping and Insulation $143,600 S&L Engineering Estimate

Electrical Equipment $499,700 S&L Engineering Estimate

Controls and Instrumentation $493,500 S&L Engineering Estimate

Demolition and Relocation $437,000 S&L Engineering Estimate

CFD Analysis & Testing $148,100 S&L Engineering Estimate

Other Direct and Construction Costs $2,783,100 S&L Engineering Estimate

Spare Parts $159,500 S&L Engineering Estimate

Total direct costs (DC) $ 21,086,800 

Indirect Costs

Engineering In owner's cost

Owner's cost $4,509,970 S&L Engineering Estimate

Construction management In owner's cost

Start-up and spare parts In owner's cost

Contingencies $2,557,329 S&L Engineering Estimate

Total indirect costs (IC) $7,067,299

Allowance for Funds Used During Construction (AFDC) $3,101,450 S&L Engineering Estimate

Property Taxes $329,529 S&L Engineering Estimate

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $31,585,078

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $695,000 S&L Engineering Estimate

Total fixed annual costs $695,000

Variable annual costs

N/A $0 No associated annual cost

Total variable annual costs $0

Total direct annual costs (DAC) $695,000

Indirect Annual Costs

Cost for capital recovery $4,662,895 (TCI) X 14.76% CRF at 7.0% interest 

Total indirect annual costs (IDAC) $4,662,895 based on 9.5 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $5,357,895

Rounded TAC $5,358,000
Boardman Plant Appendix D 

082710 D-3 

PGE Boardman BART Analysis - Cost Analysis 

Technology: Selective Non-Catalytic Reduction (SNCR) Date: August 10 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST 2010 dollars

Direct Costs

Purchased equipment costs

Concrete $2,300 S&L Engineering Estimate

Steel $16,300 S&L Engineering Estimate

Mechanical Equipment $2,267,500 S&L Engineering Estimate

Piping and Insulation $126,900 S&L Engineering Estimate

Electrical Equipment $162,400 S&L Engineering Estimate

Controls and Instrumentation $60,000 S&L Engineering Estimate

Total PEC $2,635,400

Direct installation costs

Concrete $6,900 S&L Engineering Estimate

Steel $40,900 S&L Engineering Estimate

Mechanical Equipment $1,960,100 S&L Engineering Estimate

Piping and Insulation $776,200 S&L Engineering Estimate

Electrical Equipment $246,300 S&L Engineering Estimate

Controls and Instrumentation $22,400 S&L Engineering Estimate

Demolition and Relocation $54,600 S&L Engineering Estimate

Civil Work $365,500 S&L Engineering Estimate

Other Direct and Construction Costs $1,268,900 S&L Engineering Estimate

Total direct installation costs (DIC) $4,741,800

Total direct costs (DC) = (PEC) + (DIC) $7,377,200

Indirect Costs

Engineering $590,000 S&L Engineering Estimate

Owner's cost $2,300,000 S&L Engineering Estimate

Construction management $147,500 S&L Engineering Estimate

Commissioning $73,800 S&L Engineering Estimate

Contingencies $1,012,600 S&L Engineering Estimate

Total indirect costs (IC) $4,123,900

Allowance for Funds Used During Construction (AFDC) $840,000 S&L Engineering Estimate

Property Taxes $34,000 S&L Engineering Estimate

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $12,375,100

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance Material $117,000 S&L Engineering Estimate

Maintenance Labor $175,500 S&L Engineering Estimate

Total fixed annual costs $292,500

Variable annual costs

Reagent $2,974,556 S&L Engineering Estimate

Auxiliary and ID fan power $74,500 S&L Engineering Estimate

Water $12,300 S&L Engineering Estimate

Miscellaneous $449,000 S&L Engineering Estimate

Total variable annual costs $3,510,356

Total direct annual costs (DAC) $3,802,856

Indirect Annual Costs

Cost for capital recovery $2,434,519 (TCI) X 19.67% CRF at 7% interest 

Total indirect annual costs (IDAC) $2,434,519 based on 6.5 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $6,237,375

Rounded TAC $6,237,000
Boardman Plant Appendix D 

082710 D-4 

PGE Boardman BART Analysis - Cost Analysis 

Technology: New Low NOx Burners & Modified OFA System & SNCR Date: August 4 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Total Capital Investment (TCI) cost for:

New Low NOx Burners & Modified OFA System $31,585,078 B&V Cost estimate for independent system

Selective Non-Catalytic Reduction System $12,375,100 B&V Cost estimate for independent system

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $43,960,178

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $987,500

Total fixed annual costs $987,500

Variable annual costs

Reagent $2,974,556

Auxiliary and ID fan power $74,500

Water $12,300

Miscellaneous $449,000

Total variable annual costs $3,510,356

Total direct annual costs (DAC) $4,497,856

Indirect Annual Costs

Cost for capital recovery (NLNB/MOFA) $4,662,895 (TCI) X 14.76% CRF at 7% interest 

based on 9.5 year life

Cost for capital recovery (SNCR) $2,434,519 (TCI) X 19.67% CRF at 7% interest 

Total indirect annual costs (IDAC) $7,097,414 based on 6.5 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $11,595,270

$11,595,000
Boardman Plant Appendix D 

082710 D-5 

PGE Boardman BART Analysis - Cost Analysis 

Technology: Selective Catalytic Reduction (SCR) Date: August 4 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST 2010

Direct Costs

Purchased equipment costs

SCR Ductwork $4,129,900 S&L Engineering Estimate

SCR Reactor $5,953,100 S&L Engineering Estimate

SCR Catalyst $5,473,000 S&L Engineering Estimate

SCR Structure $5,012,500 S&L Engineering Estimate

Foundations $1,070,000 S&L Engineering Estimate

Anhydrous Ammonia System $1,590,800 S&L Engineering Estimate

Electrical Equipment $1,114,300 S&L Engineering Estimate

Controls and Instrumentation $820,000 S&L Engineering Estimate

$25,163,600

Total purchased equipment cost (PEC) $25,163,600

Direct installation costs

SCR Ductwork $ 7,194,800 S&L Engineering Estimate

SCR Reactor $ 11,270,000 S&L Engineering Estimate

SCR Catalyst $ 1,915,500 S&L Engineering Estimate

SCR Structure $ 11,053,800 S&L Engineering Estimate

Foundations $ 2,549,200 S&L Engineering Estimate

Anhydrous Ammonia System $ 1,459,300 S&L Engineering Estimate

Electrical Equipment $ 1,123,100 S&L Engineering Estimate

Controls and Instrumentation $ 392,700 S&L Engineering Estimate

PDC Building $ 400,300 S&L Engineering Estimate

Boiler Modifications $ 15,631,600 S&L Engineering Estimate

Total direct installation costs (DIC) $52,990,300

Demolition and Relocation $ 936,700 S&L Engineering Estimate

Other Direct and Construction Costs $ 20,674,500 S&L Engineering Estimate

Spare Parts $ 173,400 S&L Engineering Estimate

Freight, Duties, Etc.

Total direct costs (DC) = (PEC) + (DIC) $99,938,500

Indirect Costs

Engineering $ 6,712,500 S&L Engineering Estimate

Owner's Costs $ 19,469,880 S&L Engineering Estimate

Construction Management $ 4,535,200 S&L Engineering Estimate

Commissioning $ 2,229,800 S&L Engineering Estimate

Contingency $ 11,101,800 S&L Engineering Estimate

Total indirect costs (IC) $44,049,180

Allowance for Funds Used During Construction (AFDC) $ 42,351,736 S&L Engineering Estimate

Property Taxes $ 5,726,665 S&L Engineering Estimate

Total SCR Capital Investment (TCI) $192,066,081

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance Material $ 161,000 S&L Engineering Estimate

Maintenance Labor $ 241,500 S&L Engineering Estimate

Total fixed annual costs $402,500

Variable annual costs

Reagent $ 1,220,400 S&L Engineering Estimate

Catalyst replacement $ 1,264,000 S&L Engineering Estimate

Steam $ 625,500 S&L Engineering Estimate

Auxilliary Power $ 1,556,200 S&L Engineering Estimate

Total variable annual costs $ 4,666,100 

Total direct annual costs (DAC) $5,068,600

Indirect Annual Costs

Cost for capital recovery $63,762,406 (TCI) X 33.20% CRF at 7% interest 

Total indirect annual costs (IDAC) $63,762,406 based on 3.5 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $68,831,006

Rounded TAC $68,831,000
Boardman Plant Appendix D 

082710 D-6 

PGE Boardman BART Analysis - Cost Analysis 

Technology: New Low NOx Burners & Modified OFA System & SCR Date: August 4 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST 2010 dollars

Total Capital Investment (TCI) cost for:

New Low NOx Burners & Modified OFA System $31,585,078 Cost estimate for independent system

Selective Catalytic Reduction System $192,066,081 Cost estimate for independent system

Total Capital Investment (TCI) $223,651,159

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $1,097,500 Combined cost from multiple systems

Total Fixed Annual Costs $ 1,097,500 

Variable annual costs

Reagent $1,220,400 Comined cost from multiple systems

Auxiliary and ID fan power $1,264,000 Comined cost from multiple systems

Water $625,500 Comined cost from multiple systems

Miscellaneous $1,556,200 Comined cost from multiple systems

Total variable annual costs $4,666,100

Total direct annual costs (DAC) $5,763,600

Indirect Annual Costs

Cost for capital recovery (NLNB/MOFA) $4,662,895 (TCI) X 14.76% CRF at 7% interest 

based on 9.5 year life

Cost for capital recovery (SCR) $63,762,406 (TCI) X 33.20% CRF at 7% interest 

Total indirect annual costs (IDAC) $68,425,301 based on 3.5 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $74,188,901

Rounded TAC $74,189,000
Boardman Plant Appendix D 

082710 D-7 

PGE Boardman BART Analysis - Cost Analysis 

Technology: Wet Flue Gas Desulfurization (FGD) with Fabric Filter Date: August 24 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs 2010 dollars

Purchased equipment costs

Reagent feed system: receiving, storage $1,548,000 CUECost estimate

Ball mill & classifier $2,354,000 CUECost estimate

SO2 removal system: tanks, pumps $4,212,000 CUECost estimate

Absorber tower $33,008,000 CUECost estimate

Spray pumps $4,936,000 CUECost estimate

Byproduct handling system $1,898,000 CUECost estimate

Vacuum filter system $1,803,000 from ref. cost

Fabric filter with ash handling system $18,058,000 from ref. cost

Booster fans $5,289,000 B&V Engineering estimate

Electrical system upgrades $4,639,000 from ref. cost

Flue gas handling system $9,616,000 B&V Engineering estimate

Subtotal capital cost (CC) $87,361,000

Instrumentation and controls $4,368,000 (CC) X 5.0%

Freight $4,368,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $96,097,000

Direct installation costs

Foundation & supports $26,427,000 (PEC) X 27.5%

Handling & erection $38,439,000 (PEC) X 40.0%

Electrical $19,219,000 (PEC) X 20.0%

Piping $4,805,000 (PEC) X 5.0%

Insulation $4,805,000 (PEC) X 5.0%

Painting $961,000 (PEC) X 1.0%

Demolition $3,844,000 (PEC) X 4.00%

Relocation $3,844,000 (PEC) X 4.00%

Total direct installation costs (DIC) $102,344,000

Site preparation $219,000 B&V Engineering estimate

Buildings $8,195,000 B&V Engineering estimate

New wet stack $25,133,000 Recent quotes estimate of $23 mil

Waste water treatment system $16,391,000 B&V Engineering estimate

Total direct costs (DC) = (PEC) + (DIC) $248,379,000

Indirect Costs

Engineering $29,805,000 (DC) X 12.0%

Owner's cost $9,935,000 (DC) X 4.0%

Construction management $24,838,000 (DC) X 10.0%

Start-up and spare parts $3,726,000 (DC) X 1.5%

Performance test $219,000 B&V Engineering estimate

Contingencies $37,257,000 (DC) X 15.0%

Total indirect costs (IC) $105,780,000

Allowance for Funds Used During Construction (AFDC) $63,678,000 [(DC)+(IC)8.99% 4 years (project length / 2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $417,837,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $437,000 4 FTE and 100,000 $/year Estimated labor

Maintenance labor and materials $7,451,000 (DC) X 3.0%

Total fixed annual costs $7,888,000

Variable annual costs

Reagent $2,427,000 6.484 tph and 46 $/ton Mass bal. calcs.

Byproduct disposal $970,000 11.9 tph and 10 $/ton Mass bal. calcs.

Auxiliary and ID fan power $6,347,000 16811 kW and 0.046 $/kWh CueCost calcs

Water $640,000 655.7 gpm and 2 $/1,000 gal Mass bal. calcs.

Bag replacement cost $691,000 6,322 bags and 100 $/bag 18,966 total bags

Cage replacement cost $173,000 3,161 cages and 50 $/cage 18,966 total cages

Total variable annual costs $11,248,000

Total direct annual costs (DAC) $19,136,000

Indirect Annual Costs

Cost for capital recovery $82,200,000 (TCI) X 19.67% CRF at 7% interest 

Total indirect annual costs (IDAC) $82,200,000 based on 6.5 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $101,336,000
Boardman Plant Appendix D 

082710 D-8 

PGE Boardman BART Analysis - Cost Analysis 

Technology: Semi-Dry Flue Gas Desulfurization (FGD) Date: August 24 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs 2010

Purchased equipment costs

Dry FGD Mechanical Equipment $31,299,500 S&L Engineering Estimate

Reagent Handling System Equipment $834,500 S&L Engineering Estimate

Foundations $2,068,200 S&L Engineering Estimate

Miscellaneous Buildings $2,054,400 S&L Engineering Estimate

Fabric Filter Mechanical Equipment $13,396,000 S&L Engineering Estimate

Ash Recycle System Equipment $250,000 S&L Engineering Estimate

Ash Handling System Equipment $5,000,000 S&L Engineering Estimate

Structural Supports $2,489,400 S&L Engineering Estimate

Ductwork $5,996,600 S&L Engineering Estimate

Booster ID Fans $3,999,200 S&L Engineering Estimate

Piping Systems $6,536,000 S&L Engineering Estimate

Electrical Equipment $9,964,400 S&L Engineering Estimate

Controls and Instrumentation $3,037,000 S&L Engineering Estimate

Subtotal capital cost (CC) $86,925,200

Total purchased equipment cost (PEC) $86,925,200

Direct installation costs

Dry FGD Mechanical Equipment $27,462,900 S&L Engineering Estimate

Reagent Handling System Equipment $856,800 S&L Engineering Estimate

Foundations $5,777,200 S&L Engineering Estimate

Miscellaneous Buildings $2,588,300 S&L Engineering Estimate

Fabric Filter Mechanical Equipment $11,846,700 S&L Engineering Estimate

Ash Recycle System Equipment $172,300 S&L Engineering Estimate

Ash Handling System Equipment $1,723,200 S&L Engineering Estimate

Structural Supports $3,688,000 S&L Engineering Estimate

Ductwork $9,179,900 S&L Engineering Estimate

Booster ID Fans $1,272,700 S&L Engineering Estimate

Piping Systems $7,588,100 S&L Engineering Estimate

Electrical Equipment $13,999,000 S&L Engineering Estimate

Controls and Instrumentation $1,348,800 S&L Engineering Estimate

Total direct installation costs (DIC) $87,503,900

Demolition and Relocation $120,600 S&L Engineering Estimate

Civil Work $3,861,000 S&L Engineering Estimate

Other Direct and Construction Costs $21,041,800 S&L Engineering Estimate

Spare Parts $1,463,400 S&L Engineering Estimate

Freight, Duties, Etc.

Total direct costs (DC) = (PEC) + (DIC) $200,915,900

Indirect Costs

Engineering $14,064,100 S&L Engineering Estimate

Construction Management $6,117,800 S&L Engineering Estimate

Owner's Costs $21,383,174 S&L Engineering Estimate

Commissioning $5,071,400 S&L Engineering Estimate

Contingency $22,843,100 S&L Engineering Estimate

Total indirect costs (IC) $69,479,574

Allowance for Funds Used During Construction (AFDC) $72,715,165 S&L Engineering Estimate

Property Taxes $9,804,643 S&L Engineering Estimate

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $352,915,282

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $728,000 S&L Engineering Estimate

Maintenance materials $784,000 S&L Engineering Estimate

Maintenance labor $522,000 S&L Engineering Estimate

Total fixed annual costs $2,034,000

Variable annual costs

Reagent $2,433,100 S&L Engineering Estimate

Auxiliary Power $2,932,600 S&L Engineering Estimate

Water $445,900 S&L Engineering Estimate

Waste Disposal $427,000 S&L Engineering Estimate

Bags and Cages $558,000 S&L Engineering Estimate

Total variable annual costs $6,796,600

Total direct annual costs (DAC) $8,830,600

Indirect Annual Costs

Cost for capital recovery $69,428,040 (TCI) X 19.67% CRF at 7% interest 

Total indirect annual costs (IDAC) $69,428,040 based on 6.5 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $78,259,000
Boardman Plant Appendix D 

082710 D-9 

PGE Boardman BART Analysis - Cost Analysis 

Technology: RSCR and DSI System Date: August 4 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs 2010

 Purchased Equipment Costs

Rail Spur $875,000 S&L Engineering Estimate

Dry Sorbent Unloading System $3,286,300 S&L Engineering Estimate

Concrete and Steel $96,000 S&L Engineering Estimate

Dry Sorbent Injection Equipment $2,809,900 S&L Engineering Estimate

Piping and Insulation $92,200 S&L Engineering Estimate

Electrical Equipment $519,000 S&L Engineering Estimate

 Subtotal capital cost (CC) $7,678,400

 Total Purchased Equipment Cost (PEC) $7,678,400

Direct Installation Costs

Rail Spur $422,100 S&L Engineering Estimate

Dry Sorbent Unloading System $1,074,600 S&L Engineering Estimate

Concrete and Steel $234,900 S&L Engineering Estimate

Dry Sorbent Injection Equipment $1,562,700 S&L Engineering Estimate

Piping and Insulation $460,200 S&L Engineering Estimate

Electrical Equipment $888,300 S&L Engineering Estimate

 Total Direct Installation Cost (DIC) $4,642,800

Demolition and Relocation $131,800 S&L Engineering Estimate

Civil Work $302,900 S&L Engineering Estimate

Other Direct and Construction Costs $2,528,400 S&L Engineering Estimate

 Total Direct Cost (DC) = (PEC) + (DIC) $15,284,300

Indirect Costs

Engineering $1,223,000 S&L Engineering Estimate

Owner's Costs $2,300,000 S&L Engineering Estimate

Construction Management $305,700 S&L Engineering Estimate

Commissioning $152,800 S&L Engineering Estimate

Contingency $2,041,800 S&L Engineering Estimate

 Total Indirect Cost (IC) $6,023,300

Allowance for Funds Used During Construction (AFDC) $1,562,000 S&L Engineering Estimate

Property Taxes $63,000 S&L Engineering Estimate

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC + Taxes) $22,932,600

ANNUAL COSTS

Fixed Annual Costs

Operating Labor $249,600 S&L Engineering Estimate

Maintenance Labor and Material $127,600 S&L Engineering Estimate

Administrative Labor $9,000 S&L Engineering Estimate

Total Fixed Annual Cost $386,200

Variable Annual Costs

Reagent $8,324,259 S&L Engineering Estimate

Waste Disposal $4,059,043 S&L Engineering Estimate

Auxiliary Power $260,610 S&L Engineering Estimate

Total Variable Annual Cost $12,643,912

Total Direct Annual Costs (DAC) $13,030,112

Indirect Annual Costs

Cost for Capital Recovery $4,511,466 (TCI) x 19.67% CRF at 7 % interest

Total Indirect Annual Costs (IDAC) $4,511,466 based on 6.5 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $17,541,578
Boardman Plant Appendix D 

082710 D-10 

PGE Boardman BART Analysis - Cost Analysis

Technology: Pulse Jet Fabric Filter (PJFF) Date: August 4 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs 2010 dollars

Purchased equipment costs

Fabric filter system $18,541,000 CUECost estimate

Initial FF bags inventory

Ash handling system $1,322,000 B&V Engineering estimate

Booster fans $5,938,000 B&V Engineering estimate

Electrical system upgrades $2,248,000 B&V Engineering estimate

Flue gas handling system $3,967,000 B&V Engineering estimate

Subtotal capital cost (CC) $32,016,000

Instrumentation and controls $1,601,000 (CC) X 5.0%

Freight $1,601,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $35,218,000

Direct installation costs

Foundation & supports $10,565,000 (PEC) X 30.0%

Handling & erection $10,565,000 (PEC) X 30.0%

Electrical $5,283,000 (PEC) X 15.0%

Piping $880,000 (PEC) X 2.5%

Insulation $704,000 (PEC) X 2.0%

Painting $352,000 (PEC) X 1.0%

Demolition $1,761,000 (PEC) X 5.00%

Relocation $352,000 (PEC) X 1.00%

Total direct installation costs (DIC) $30,462,000

Site preparation $164,000 B&V Engineering estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $65,844,000

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 B&V Engineering estimate

Contingencies $9,039,000 (DC) X 15.0%

Total indirect costs (IC) $26,313,000

Allowance for Funds Used During Construction (AFDC) $8,285,000 [(DC)+(IC)]8.99% 2 years (project time length / 2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $100,442,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $1,975,000 (DC) X 3.0%

Total fixed annual costs $1,975,000

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 $774,000 2,258 kW and 0.046 $/kWh 6" water d.p.

Additional Auxiliary power $206,000 554 kW and 0.05 $/kWh B&V Engineering estimate

Total variable annual costs $1,770,000

Total direct annual costs (DAC) $3,745,000

Indirect Annual Costs

Cost for capital recovery $19,760,000 (TCI) X 19.67% CRF at 7% interest for 6.5 year life

Total indirect annual costs (IDAC) $19,760,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $23,505,000
Boardman Plant Appendix D 

082710 D-11 

PGE Boardman BART Analysis - Cost Analysis

Technology: Compact Hybrid Particulate Collector (COHPAC) Date: August 4 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs 2010 dollars

Purchased equipment costs

Fabric filter system $13,313,000 B&V Engineering Estimate

Initial FF bags inventory

Ash handling system $2,404,000 B&V Engineering Estimate

Booster fans $5,481,000 B&V Engineering Estimate

Electrical system upgrades $2,248,000 B&V Engineering Estimate

Flue gas handling system $7,212,000 B&V Engineering Estimate

Subtotal capital cost (CC) $30,658,000

Instrumentation and controls $1,533,000 (CC) X 5.0%

Freight $1,533,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $33,724,000

Direct installation costs

Foundation & supports $8,431,000 (PEC) X 25.0%

Handling & erection $8,431,000 (PEC) X 25.0%

Electrical $4,216,000 (PEC) X 12.5%

Piping $843,000 (PEC) X 2.5%

Insulation $674,000 (PEC) X 2.0%

Painting $337,000 (PEC) X 1.0%

Demolition $337,000 (PEC) X 1.00%

Relocation $337,000 (PEC) X 1.00%

Total direct installation costs (DIC) $23,606,000

Site preparation $546,000 B&V Engineering Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $57,876,000

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 $109,000 B&V Engineering Estimate

Contingencies $7,945,000 (DC) X 15.0%

Total indirect costs (IC) $23,150,000

Allowance for Funds Used During Construction (AFDC) $7,284,000 [(DC)+(IC)] 8.99% 2 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $88,310,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $3,473,000 (DC) X 6.0%

Total fixed annual costs $3,473,000

Variable annual costs

Filter bag replacement $571,000 5,708 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 $998,000 2,889 kW and 0.046 $/kWh 8" water d.p.

Additional Auxiliary power $332,000 893 kW and 0.05 $/kWh B&V Engineering Estimate

Total variable annual costs $1,996,000

Total direct annual costs (DAC) $5,469,000

Indirect Annual Costs

Cost for capital recovery $17,373,000 (TCI) X 19.67% CRF at 7% interest for 6.5 year life

Total indirect annual costs (IDAC) $17,373,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $22,842,000
Boardman Plant Appendix D 

082710 D-12 

PGE Boardman BART Analysis - Cost Analysis 

Technology: Wet ESP Date: August 4 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST

Direct Costs 2010 dollars

Purchased equipment costs

WESP system includes casing, electrical sys., $34,139,000 B&V Engineering Estimate

penthouse blower & heater, access provisions

Ash handling system $2,644,000 B&V Engineering Estimate

Booster fans $5,024,000 B&V Engineering Estimate

Electrical system upgrades $1,454,000 B&V Engineering Estimate

Flue gas handling system $3,967,000 B&V Engineering Estimate

Subtotal capital cost (CC) $47,228,000

Instrumentation and controls $2,361,000 (CC) X 5.0%

Freight $2,361,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $51,950,000

Direct installation costs

Foundation & supports $15,585,000 (PEC) X 30.0%

Handling & erection $15,585,000 (PEC) X 30.0%

Electrical $7,793,000 (PEC) X 15.0%

Piping $1,299,000 (PEC) X 2.5%

Insulation $1,039,000 (PEC) X 2.0%

Painting $520,000 (PEC) X 1.0%

Demolition $520,000 (PEC) X 1.00%

Relocation $520,000 (PEC) X 1.00%

Total direct installation costs (DIC) $42,861,000

Site preparation $546,000 B&V Engineering Estimate

Buildings $0 N/A

New wet stack $25,133,000 B&V Engineering Estimate

Total direct costs (DC) = (PEC) + (DIC) $120,490,000

Indirect Costs

Engineering $14,459,000 (DC) X 12.0%

Owner's cost $6,025,000 (DC) X 5.0%

Construction management $12,049,000 (DC) X 10.0%

Start-up and spare parts $1,807,000 (DC) X 1.5%

Performance test $100,000 B&V Engineering Estimate

Contingencies $18,074,000 (DC) X 15.0%

Total indirect costs (IC) $52,514,000

Allowance for Funds Used During Construction (AFDC) $23,330,000 [(DC)+(IC)] X 8.99% 3 years (project length / 2)

Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $196,334,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance materials and labor $2,861,000 (DC) X 3.0%

Operating labor $100,000 1 FTE and 100000 $/year Estimated labor

Total fixed annual costs $2,961,000

Variable annual costs

Reagent $179,000 20 lb/hr and 1.20 $/ton Engr. Estimate

Additional Auxiliary power $130,000 350 kW and 0.05 $/kWh Engr. Estimate

ID fan power $481,000 1,402 kW and 0.046 $/kWh 4" water d.p.

Service water $583,000 652 gpm and 2 $/1,000 gal B&V Engineering Estimate

Total variable annual costs $1,373,000

Total direct annual costs (DAC) $4,334,000

Indirect Annual Costs

Cost for capital recovery $38,624,000 (TCI) X 19.67% CRF at 7% interest for 6.5 year life

Total indirect annual costs (IDAC) $38,624,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $42,958,000
Boardman Plant Appendix E 

082710 E-1 

Appendix E 

Visibility Modeling Results
3DJHRI

Table E-1. Stack Parameters and Modeled Emission Rates

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Emission Rates (lb/hr)(1,a) Stack Parameters(1)

SOX PM Exit Exit

Filterable Condensable Height Diameter Velocity Temperature

Scenario NOX SO2

(2) SO4 Total Total EC PMF PMC Total OC (ft) (ft) (ft/s) ( ̊F)

%DVHOLQH              

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Calculations:

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Notes:

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62

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3DJHRI

Table E-2. Visibility Analysis Results - Baseline

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

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Total 27.970 33.562 28.192 31.455 34.126 766 877 748 2,391 401 484 380 1,265

Maximum 4.030 5.136 5.026 4.982 5.136 115 107 102 324 68 73 65 206

Minimum 0.847 1.072 0.593 1.025 1.151 17 27 12 60 3 9 2 24

Average 1.998 2.397 2.014 2.247 2.438 55 63 53 171 29 35 27 90

Class II Areas*

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Modeled Area

Location of Maximum 

(km)

% of Modeled Extinction by 

Species

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

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3DJHRI

Table E-3. Visibility Analysis Results - New LNB with Modified OFA and SCR

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

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Total 17.347 21.787 15.616 18.921 21.938 498 565 426 1,489 195 273 149 617

Maximum 2.476 3.248 2.765 2.814 3.248 69 77 66 212 49 50 42 141

Minimum 0.464 0.690 0.362 0.593 0.690 5 11 4 29 1 6 0 9

Average 1.239 1.556 1.115 1.352 1.567 36 40 30 106 14 20 11 44

Class II Areas*

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Modeled Area

Location of Maximum 

(km)

% of Modeled Extinction by 

Species

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-4. Visibility Analysis Results - New LNB with Modified OFA and SNCR

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

'LDPRQG3HDN                    

(DJOH&DS                    

*ODFLHU3HDN                    

*RDW5RFNV                    

+HOOV&DQ\RQ                    

0W$GDPV                    

0W+RRG                    

0W-HIIHUVRQ                    

0W5DLQLHU                    

0W:DVKLQJWRQ                    

1RUWK&DVFDGHV                    

6WUDZEHUU\0RXQWDLQ                    

7KUHH6LVWHUV                    

Total 20.299 24.231 18.816 21.586 24.547 578 646 527 1,751 246 329 211 786

Maximum 2.865 3.657 3.341 3.356 3.657 78 86 74 234 55 56 47 158

Minimum 0.589 0.833 0.402 0.710 0.833 11 15 4 37 1 7 0 12

Average 1.450 1.731 1.344 1.542 1.753 41 46 38 125 18 24 15 56

Class II Areas*

&ROXPELD5LYHU*RUJH                    

/1% /RZ12;%XUQHU2)$ 2YHUILUH$LU61&5 6HOHFWLYH1RQ&DWDO\WLF5HGXFWLRQ


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

Modeled Area

Location of Maximum 

(km)

% of Modeled Extinction by 

Species

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-5. Visibility Analysis Results - New LNB with Modified OFA

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

'LDPRQG3HDN                    

(DJOH&DS                    

*ODFLHU3HDN                    

*RDW5RFNV                    

+HOOV&DQ\RQ                    

0W$GDPV                    

0W+RRG                    

0W-HIIHUVRQ                    

0W5DLQLHU                    

0W:DVKLQJWRQ                    

1RUWK&DVFDGHV                    

6WUDZEHUU\0RXQWDLQ                    

7KUHH6LVWHUV                    

Total 21.213 25.313 19.861 22.707 25.653 600 670 564 1,834 261 343 234 838

Maximum 3.021 3.850 3.537 3.537 3.850 81 86 77 239 56 57 51 164

Minimum 0.617 0.846 0.423 0.747 0.846 11 19 6 40 1 7 0 13

Average 1.515 1.808 1.419 1.622 1.832 43 48 40 131 19 25 17 60

Class II Areas*

&ROXPELD5LYHU*RUJH                    

/1% /RZ12;%XUQHU2)$ 2YHUILUH$LU


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

Modeled Area

Location of Maximum 

(km)

% of Modeled Extinction by 

Species

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-6. Visibility Analysis Results - Wet FGD and PJFF

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

'LDPRQG3HDN                    

(DJOH&DS                    

*ODFLHU3HDN                    

*RDW5RFNV                    

+HOOV&DQ\RQ                    

0W$GDPV                    

0W+RRG                    

0W-HIIHUVRQ                    

0W5DLQLHU                    

0W:DVKLQJWRQ                    

1RUWK&DVFDGHV                    

6WUDZEHUU\0RXQWDLQ                    

7KUHH6LVWHUV                    

Total 18.685 21.090 19.074 20.479 22.448 471 588 462 1,521 186 254 196 636

Maximum 3.222 3.525 3.910 3.792 3.910 79 82 72 233 52 59 54 165

Minimum 0.454 0.599 0.375 0.522 0.664 7 13 2 26 2 2 0 5

Average 1.335 1.506 1.362 1.463 1.603 34 42 33 109 13 18 14 45

Class II Areas*

&ROXPELD5LYHU*RUJH                    

)*' )OXH*DV'HVXOIXUL]DWLRQ3-)) 3XOVH-HW)DEULF)LOWHU


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

Modeled Area

Location of Maximum 

(km)

% of Modeled Extinction by 

Species

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-7. Visibility Analysis Results - Semi-Dry FGD and PJFF

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

'LDPRQG3HDN                    

(DJOH&DS                    

*ODFLHU3HDN                    

*RDW5RFNV                    

+HOOV&DQ\RQ                    

0W$GDPV                    

0W+RRG                    

0W-HIIHUVRQ                    

0W5DLQLHU                    

0W:DVKLQJWRQ                    

1RUWK&DVFDGHV                    

6WUDZEHUU\0RXQWDLQ                    

7KUHH6LVWHUV                    

Total 18.911 21.704 19.398 20.838 22.744 496 599 485 1,580 203 262 202 667

Maximum 3.205 3.736 3.760 3.736 3.760 79 83 73 235 54 59 55 168

Minimum 0.433 0.631 0.394 0.572 0.699 7 13 3 28 1 2 0 5

Average 1.351 1.550 1.386 1.488 1.625 35 43 35 113 15 19 14 48

Class II Areas*

&ROXPELD5LYHU*RUJH                    

)*' )OXH*DV'HVXOIXUL]DWLRQ3-)) 3XOVH-HW)DEULF)LOWHU


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

Modeled Area

Location of Maximum 

(km)

% of Modeled Extinction by 

Species

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-8. Visibility Analysis Results - DSI and RSCR

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

'LDPRQG3HDN                    

(DJOH&DS                    

*ODFLHU3HDN                    

*RDW5RFNV                    

+HOOV&DQ\RQ                    

0W$GDPV                    

0W+RRG                    

0W-HIIHUVRQ                    

0W5DLQLHU                    

0W:DVKLQJWRQ                    

1RUWK&DVFDGHV                    

6WUDZEHUU\0RXQWDLQ                    

7KUHH6LVWHUV                    

Total 21.509 25.692 22.771 24.456 26.883 599 694 605 1,898 277 332 271 880

Maximum 3.413 4.142 4.251 4.140 4.251 87 86 77 243 58 57 57 172

Minimum 0.609 0.827 0.465 0.767 0.899 9 16 5 37 1 5 0 11

Average 1.536 1.835 1.627 1.747 1.920 43 50 43 136 20 24 19 63

Class II Areas*

&ROXPELD5LYHU*RUJH                    

/1% /RZ12;%XUQHU2)$ 2YHUILUH$LU


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

Modeled Area

Location of Maximum 

(km)

% of Modeled Extinction by 

Species

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-9. Visibility Analysis Results - Reduced Sulfur Coal Restriction

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

'LDPRQG3HDN                    

(DJOH&DS                    

*ODFLHU3HDN                    

*RDW5RFNV                    

+HOOV&DQ\RQ                    

0W$GDPV                    

0W+RRG                    

0W-HIIHUVRQ                    

0W5DLQLHU                    

0W:DVKLQJWRQ                    

1RUWK&DVFDGHV                    

6WUDZEHUU\0RXQWDLQ                    

7KUHH6LVWHUV                    

Total 24.713 29.387 25.375 27.878 30.274 680 785 676 2,141 339 411 325 1,075

Maximum 3.741 4.595 4.638 4.550 4.638 101 93 87 278 64 66 61 191

Minimum 0.719 0.941 0.530 0.901 1.015 14 24 8 46 2 7 0 16

Average 1.765 2.099 1.813 1.991 2.162 49 56 48 153 24 29 23 77

Class II Areas*

&ROXPELD5LYHU*RUJH                    

/1% /RZ12;%XUQHU2)$ 2YHUILUH$LU

Modeled Area

% of Modeled Extinction by 

Species

Location of Maximum 

(km)


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-10. Visibility Analysis Results - New LNB/Modified OFA/SNCR/DSI/RSCR

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview

8

th High by Year 22nd High Maximum Number of Days >0.5 Number of Days >1.0 Date of

2003 2004 2005 2003-2005 Impact 2003 2004 2005 Total 2003 2004 2005 Total SO4 NO3 OC EC X Y Maximum

Class I Areas

$OSLQH/DNHV                    

'LDPRQG3HDN                    

(DJOH&DS                    

*ODFLHU3HDN                    

*RDW5RFNV                    

+HOOV&DQ\RQ                    

0W$GDPV                    

0W+RRG                    

0W-HIIHUVRQ                    

0W5DLQLHU                    

0W:DVKLQJWRQ                    

1RUWK&DVFDGHV                    

6WUDZEHUU\0RXQWDLQ                    

7KUHH6LVWHUV                    

Total 17.002 20.522 16.580 18.747 20.793 486 553 455 1,494 192 248 165 605

Maximum 2.409 3.257 3.068 3.050 3.257 72 79 72 223 51 48 44 143

Minimum 0.487 0.647 0.324 0.591 0.671 6 11 4 30 1 4 0 8

Average 1.214 1.466 1.184 1.339 1.485 35 40 33 107 14 18 12 43

Class II Areas*

&ROXPELD5LYHU*RUJH                    

/1% /RZ12;%XUQHU2)$ 2YHUILUH$LU

Modeled Area

% of Modeled Extinction by 

Species

Location of Maximum 

(km)


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-11. Summary of Visibility Analysis Results and Comparison of Change in Visibility (ǻdv)

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Existing Controls NOX Control Alternatives SO2

 Control Alternatives

Baseline NLNB/MOFA/SCR NLNB/MOFA/SNCR NLNB/MOFA Wet FGD/PJFF Semi-Dry FGD/PJFF DSI and RSCR RSCR

98th %tile 98th %tile Improvement 98th %tile Improvement 98th %tile Improvement 98th %tile Improvement 98th %tile Improvement 98th %tile Improvement 98th %tile Improvement

Modeled Area (ǻdv) (ǻdv) (dv) (%) (ǻdv) (dv) (%) (ǻdv) (dv) (%) (ǻdv) (dv) (%) (ǻdv) (dv) (%) (ǻdv) (dv) (%) (ǻdv) (dv) (%)

Class I Areas

$OSLQH/DNHV                      

'LDPRQG3HDN                      

(DJOH&DS                      

*ODFLHU3HDN                      

*RDW5RFNV                      

+HOOV&DQ\RQ                      

0W$GDPV                      

0W+RRG                      

0W-HIIHUVRQ                      

0W5DLQLHU                      

0W:DVKLQJWRQ                      

1RUWK&DVFDGHV                      

6WUDZEHUU\0RXQWDLQ                      

7KUHH6LVWHUV                      

Total 34.126 21.938 12.188 35.7 24.547 9.579 28.1 25.653 8.473 24.8 22.448 11.678 34.2 22.744 11.382 33.4 26.883 7.243 21.2 30.274 3.852 11.3

Maximum 5.136 3.248 1.888 42.3 3.657 1.479 33.3 3.850 1.286 29.6 3.910 1.226 49.2 3.760 1.376 48.9 4.251 0.885 31.1 4.638 0.498 18.6

Minimum 1.151 0.690 0.437 29.5 0.833 0.298 21.8 0.846 0.254 18.6 0.664 0.487 23.9 0.699 0.419 24.0 0.899 0.252 14.6 1.015 0.136 6.6

Average 2.438 1.567 0.871 35.7 1.753 0.684 28.0 1.832 0.605 24.8 1.603 0.834 36.3 1.625 0.813 35.0 1.920 0.517 22.0 2.162 0.275 11.7

Class II Areas*

&ROXPELD5LYHU*RUJH                      

1/1% 1HZ/RZ12;%XUQHU02)$ 0RGLILHG2YHUILUH$LU6&5 6HOHFWLYH&DWDO\WLF5HGXFWLRQ61&5 6HOHFWLYH1RQ&DWDO\WLF5HGXFWLRQ)*' )OXH*DV'HVXOIXUL]DWLRQ3-)) 3XOVH-HW)DEULF)LOWHU'6, 'U\6RUEHQW,QMHFWLRQ56&5 5HGXFHG6XOIXU&RDO5HVWULFWLRQ


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-12. Summary of Visibility Analysis Results and Comparison of Total Number of Days Above 0.5 Deciview

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Existing Controls NOX Control Alternatives SO2

 Control Alternatives

Baseline NLNB/MOFA/SCR NLNB/MOFA/SNCR NLNB/MOFA Wet FGD/PJFF Semi-Dry FGD/PJFF DSI and RSCR RSCR

Total Days Total Days Improvement Total Days Improvement Total Days Improvement Total Days Improvement Total Days Improvement Total Days Improvement Total Days Improvement

Modeled Area (days) (days) (days) (%) (days) (days) (%) (days) (days) (%) (days) (days) (%) (days) (days) (%) (days) (days) (%) (days) (days) (%)

Class I Areas

$OSLQH/DNHV                      

'LDPRQG3HDN                      

(DJOH&DS                      

*ODFLHU3HDN                      

*RDW5RFNV                      

+HOOV&DQ\RQ                      

0W$GDPV                      

0W+RRG                      

0W-HIIHUVRQ                      

0W5DLQLHU                      

0W:DVKLQJWRQ                      

1RUWK&DVFDGHV                      

6WUDZEHUU\0RXQWDLQ                      

7KUHH6LVWHUV                      

Total 2,391 1,489 902 37.7 1,751 640 26.8 1,834 557 23.3 1,521 870 36.4 1,580 811 33.9 1,898 493 20.6 2,141 250 10.5

Maximum 324 212 160 61.4 234 111 42.2 239 103 34.9 233 150 61.4 235 129 57.8 243 81 38.3 278 46 23.3

Minimum 60 29 31 21.5 37 23 13.3 40 20 11.5 26 34 13.7 28 32 13.0 37 21 10.4 46 6 3.3

Average 171 106 64 39.0 125 46 27.8 131 40 24.1 109 62 38.7 113 58 36.3 136 35 22.2 153 18 11.1

Class II Areas*

&ROXPELD5LYHU*RUJH                      

1/1% 1HZ/RZ12;%XUQHU02)$ 0RGLILHG2YHUILUH$LU6&5 6HOHFWLYH&DWDO\WLF5HGXFWLRQ61&5 6HOHFWLYH1RQ&DWDO\WLF5HGXFWLRQ)*' )OXH*DV'HVXOIXUL]DWLRQ3-)) 3XOVH-HW)DEULF)LOWHU'6, 'U\6RUEHQW,QMHFWLRQ56&5 5HGXFHG6XOIXU&RDO5HVWULFWLRQ


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-13. Summary of Visibility Analysis Results and Comparison of Total Number of Days Above 1.0 Deciview

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Existing Controls NOX Control Alternatives SO2

 Control Alternatives

Baseline NLNB/MOFA/SCR NLNB/MOFA/SNCR NLNB/MOFA Wet FGD/PJFF Semi-Dry FGD/PJFF DSI and RSCR RSCR

Total Days Total Days Improvement Total Days Improvement Total Days Improvement Total Days Improvement Total Days Improvement Total Days Improvement Total Days Improvement

Modeled Area (days) (days) (days) (%) (days) (days) (%) (days) (days) (%) (days) (days) (%) (days) (days) (%) (days) (days) (%) (days) (days) (%)

Class I Areas

$OSLQH/DNHV                      

'LDPRQG3HDN                      

(DJOH&DS                      

*ODFLHU3HDN                      

*RDW5RFNV                      

+HOOV&DQ\RQ                      

0W$GDPV                      

0W+RRG                      

0W-HIIHUVRQ                      

0W5DLQLHU                      

0W:DVKLQJWRQ                      

1RUWK&DVFDGHV                      

6WUDZEHUU\0RXQWDLQ                      

7KUHH6LVWHUV                      

Total 1,265 617 648 51.2 786 479 37.9 838 427 33.8 636 629 49.7 667 598 47.3 880 385 30.4 1,075 190 15.0

Maximum 206 141 98 72.7 158 75 59.7 164 69 54.5 165 102 79.2 168 96 79.2 172 62 61.0 191 29 33.3

Minimum 24 9 14 31.6 12 11 23.3 13 10 20.4 5 17 19.9 5 16 18.4 11 11 16.5 16 6 7.3

Average 90 44 46 53.7 56 34 40.5 60 31 36.2 45 45 54.6 48 43 52.3 63 28 33.9 77 14 17.3

Class II Areas*

&ROXPELD5LYHU*RUJH                      


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

1/1% 1HZ/RZ12;%XUQHU02)$ 0RGLILHG2YHUILUH$LU6&5 6HOHFWLYH&DWDO\WLF5HGXFWLRQ61&5 6HOHFWLYH1RQ&DWDO\WLF5HGXFWLRQ)*' )OXH*DV'HVXOIXUL]DWLRQ3-)) 3XOVH-HW)DEULF)LOWHU'6, 'U\6RUEHQW,QMHFWLRQ56&5 5HGXFHG6XOIXU&RDO5HVWULFWLRQ

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
3DJHRI

Table E-14. Summary of Visibility Analysis Results and Comparison of Combined NOX and SO2 Control

BART/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative

Portland General Electric - Boardman, OR

Change in Visibility Days > 0.5 Deciview Days > 1.0 Deciview

Baseline NLNB/MOFA/DSI/RSCR Baseline NLNB/MOFA/DSI/RSCR Baseline NLNB/MOFA/DSI/RSCR

98th %tile 98th %tile Improvement Total Days Total Days Improvement Total Days Total Days Improvement

Modeled Area (ǻdv) (ǻdv) (dv) (%) (days) (days) (days) (%) (days) (days) (days) (%)

Class I Areas

$OSLQH/DNHV            

'LDPRQG3HDN            

(DJOH&DS            

*ODFLHU3HDN            

*RDW5RFNV            

+HOOV&DQ\RQ            

0W$GDPV            

0W+RRG            

0W-HIIHUVRQ            

0W5DLQLHU            

0W:DVKLQJWRQ            

1RUWK&DVFDGHV            

6WUDZEHUU\0RXQWDLQ            

7KUHH6LVWHUV            

Total 34.126 20.793 13.333 39.1 2,391 1,494 897 37.5 1,265 605 660 52.2

Maximum 5.136 3.257 1.879 42.4 324 223 149 61.4 206 143 98 72.1

Minimum 1.151 0.671 0.480 36.5 60 30 30 17.4 24 8 16 30.6

Average 2.438 1.485 0.952 39.4 171 107 64 39.0 90 43 47 55.5

Class II Areas*

&ROXPELD5LYHU*RUJH            


&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV

1/1% 1HZ/RZ12;%XUQHU02)$ 0RGLILHG2YHUILUH$LU6&5 6HOHFWLYH&DWDO\WLF5HGXFWLRQ61&5 6HOHFWLYH1RQ&DWDO\WLF5HGXFWLRQ)*' )OXH*DV'HVXOIXUL]DWLRQ3-)) 3XO

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJB[OV

0DUFK 6/5,QWHUQDWLRQDO&RUS
Boardman Plant Appendix F 

082710 F-1 

Appendix F

Visibility Modeling Protocol
FINAL 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 effort among Idaho Department of Environmental 

Quality (IDEQ), Oregon Department of Environmental Quality (ODEQ), and Washington 

Department of Ecology (WDOE) to develop an analysis that will be applied consistently to 

Idaho, Washington, and Oregon BART-eligible sources. The U.S. Fish and Wildlife Service, 

National Park Service, U.S. Forest Service, and U.S. EPA Region 10 were consulted during the 

development of this protocol (EPA 2006a, b, c). This protocol adopts the BART Guideline and 

addresses both the BART exemption modeling as well as the BART determination modeling. 

The three agencies are also collaborating on the development of a consistent three-year 

meteorological data set. Collaboration on the protocol and meteorological data set helps ensure 

modeling consistency and the sharing of resources and workload. 

1.2 Objectives

The protocol describes the modeling methodology that will be used for the following purposes: 

x 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 

x 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

x A streamlined and consistent approach in determining which BART-eligible sources are 

subject to BART 

x A clearly delineated modeling methodology 

x A common CALMET/CALPUFF/POSTUTIL/CALPOST modeling configuration 

2. Modeling Approach 

2.1 Bart-Eligible Source List 

BART-eligible source refers to the entire facility that has BART-eligible emission units. 

Oregon, Washington, and Idaho are in the process of finalizing lists of BART-eligible sources. 

Table 1 presents the BART-eligible lists, as of July 21, 2006. Sources may be added/removed as 

additional information is reviewed. 

Table 1. BART-eligible sources. 

Washington Oregon Idaho 

Intalco Aluminum Amalgamated Sugar Amalgamated Sugar – Nampa 

Conoco-Phillips PGE Boardman Amalgamated Sugar – Paul 

Centralia Powerplant (TransAlta) Boise Cascade Amalgamated Sugar – Twin Falls

Longview Fibre Fort James J.R. Simplot Don Siding Plant 

Weyerhaeuser – Longview Pope & Talbot Potlatch Pulp and Paper 

BP Cherry Point Weyerhaeuser Monsanto 

Tesoro NW PGE Beaver NuWest (Agrium) 

Lafarge Georgia Pacific

Georgia Pacific (Fort James) Camas Smurfit 

Port Townsend Paper Kingsford

Simpson Tacoma Kraft 

Shell (Puget Sound Refining Co) 

Graymont Western 

Alcoa-Wenatchee 

Columbia 

2.2 Class I Areas 

The mandatory Class I federal areas in Idaho, Oregon, and Washington, as well as neighboring 

states that could be impacted by BART-eligible sources, are presented in Appendix A. Figure 

A-1 graphically presents the BART-eligible source locations with respect to the Class I areas. 

All federally mandatory Class I areas within 300 kilometers (km) of a BART-eligible source will 

be included in the BART exemption modeling analysis. Section 6.1(c) of the Guideline on Air 

Quality Models states, “It was concluded from these case studies that the CALPUFF dispersion 

model had performed in a reasonable manner, and had no apparent bias toward over or under 
FINAL 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 (SO2), oxides of nitrogen (NOx) and direct 

particulate matter (PM) emissions, including both PM10 and PM2.5 should be included for both 

the BART exemption and BART determination modeling analyses. 

The BART Guideline also discusses the inclusion of volatile organic compound (VOC), 

ammonia and ammonia compounds as visibility impairing pollutants. These pollutants will be 

included in the BART analysis if it is determined that they are reasonably anticipated to cause or 

contribute to visibility impairment. For sources that are selected to evaluate VOC emissions, the 

first criterion is the emission level. The VOC emissions will be included in the BART 

exemption analysis if the greater-than-six-carbon VOC gases exceed 250 tons-per-year. If 

speciation is not known, it will be conservatively assumed that 50% of the gas species within the 

total VOC emissions from a facility have greater than six carbon atoms. Idaho and Oregon have 

determined that there are no significant sources of VOC, ammonia, or ammonia compounds 

which require a full BART exemption analysis. 

2.4 Emissions and Stack Data 

The BART Guideline states, “the emission estimates used in the models are intended to reflect 

steady-state operating conditions during periods of high capacity utilization.” These emissions 

should not generally include start-up, shutdown, or malfunction emissions. The BART 

Guideline recommends that states use the 24-hour average actual emission rate from the highest 

emitting day of the meteorological period modeled. The meteorological period is 2003 – 2005. 

Depending on the availability of emissions data, the following emissions information (listed in 

order of priority) should be used with CALPUFF for BART exemption modeling: 

x 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 

x Allowable emissions (maximum 24-hour allowable). 

States will work with the BART-eligible sources to develop an appropriate emission inventory. 

If plant-wide emissions from all BART eligible units for SO2, NOx, and PM10 are less than the 

significant emission rate (SER) used for Prevention of Significant Deterioration, emissions of 

that pollutant will not be included in the BART exemption modeling. However, if plant-wide 
FINAL 10/11/06 

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emissions from all BART eligible units exceed the SERs for these pollutants, then all emissions 

of that pollutant from individual emission units will be evaluated even if emissions are below the 

SER for an individual emission unit. 

The states have the option of determining how to include small emission units in the BART 

exemption analysis. Fugitive dust sources at a distance greater than 10km from any Class I area 

are exempt from the analysis. Emission units with emissions less than the SER will be 

quantified, if possible, and added to the stack emissions from an emission unit that is already 

being evaluated. Thus, the emissions from these small units will be included in the total from the 

plant, but will not have to be modeled separately. 

2.5 Natural Background 

The natural visibility background is defined as the 20% best days. This definition of natural 

background is consistent with the intent of the BART Guideline (Federal Register Vol. 70, No. 

128, pf 39125). The natural background values for Class I areas used in this protocol are based 

on EPA’s “Guidance for Estimating Natural Visibility Conditions under the Regional Haze 

Rule” (EPA 2003). The natural background for the Columbia River Gorge Scenic Area is based 

on IMPROVE monitoring data, and was supplied by Scott Copeland of CIRA (Cooperative 

Institute for Research in the Atmosphere). These background data for Class I areas and the 

Columbia River Gorge are presented in Appendix B. The option presented in EPA’s guidance for 

refining the default visibility background is not to be used in this protocol. 

2.6 Visibility Calculation 

The CALPUFF modeling techniques presented in this protocol will provide ground level 

concentrations of visibility impairing pollutants. The concentration estimates from CALPUFF 

are used with the current FLAG equation to calculate the extinction coefficient, as shown below.

bext = 3 f(RH) [(NH4)2SO4] + 3 f(RH) [NH4NO3] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + bRay

As described in the IWAQM Phase 2 Report, the change in visibility for the BART exemption 

analysis is compared against background conditions. The delta-deciview, 'dv, value is 

calculated from the source’s contribution to extinction, bext (source), and background extinction, 

bext(bkg), as follows: 

'dv = 10 ln [ ( bext(bkg) + bext (source) ) / ( bext(bkg) ) ] 

2.7 Model Execution 

2.7.1 BART Exemption Analysis 

The BART exemption modeling determines which BART-eligible sources are reasonably 
FINAL 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 whether a source “contributes” to visibility impairment 

should not be higher than 0.5 deciviews. 

In setting a threshold for “contribution,” you should consider the number of emissions sources 

affecting the Class I areas at issue and the magnitude of the individual sources’ impacts. In 

general, a larger number of sources causing impacts in a Class I area may warrant a lower 

contribution threshold. States remain free to use a threshold lower than 0.5 deciviews if they 

conclude that the location of a large number of BART-eligible sources within the State and in 

proximity to a Class I area justify this approach.” 

As a result, this protocol has determined that if a single source causes a 0.5 deciview or greater 

change from natural background, then that source is determined to be reasonably anticipated to 

contribute to any visibility impairment in a Class I area and will be subject to BART. For this 

single source analysis, the BART exemption modeling will not consider the frequency, 

magnitude, and duration of impairment. 

In addition, as suggested by the BART Guideline, if multiple BART-eligible sources impact a 

given Class I area on the same day, then a lower, individual, contribution threshold may be 

considered. For BART-eligible sources in Oregon and Washington, the following steps will be 

used to address this condition: 1) after all BART-eligible sources have completed their 

individual BART exemption modeling, the modeled visibility impairment from all sources will 

be aggregated for each Class I area receptor for each day; 2) if the total for any receptor exceeds 

0.5 deciview, all sources responsible for visibility impairment at that receptor for that day will be 

considered for further evaluation. This evaluation will include an assessment of the magnitude, 

frequency, duration of impairment, and other factors that affect visibility for each of the sources 

in the multi-source group. The inclusion of these qualifying factors in the multi-source analysis 

follows the direction given in the BART Guideline for interpreting the refined modeling results 
FINAL 10/11/06 

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in the determination phase of the BART process and recommendations for sources subject to 

PSD analyses given in the FLAG Phase I Final Report (FLAG 2000). There is no set individual 

source visibility threshold for these multi-source assessments. After the multi-source evaluation, 

a determination will be made as to which sources, if any, from a multi-source group will be 

considered to have contributed to visibility impairment and be subject to BART. 

2.7.2 BART Determination Analysis 

The BART Determination analysis determines the degree of visibility improvement for each 

control option. The BART Guideline states: 

“Assess the visibility improvement based on the modeled change in visibility impacts for the precontrol and post-control emission scenarios. You have the flexibility to assess visibility 

improvement due to BART controls by one or more methods. You may consider the frequency, 

magnitude, and duration components of impairment.” 

In order to quantify the degree of visibility improvement due to BART controls, the modeling 

system is executed in a similar manner as for the BART exemption analysis. Model execution 

and results are needed for both pre-BART control and post-BART control scenarios to allow for 

comparison of CALPOST delta-deciview predictions for both scenarios. The only difference 

between the modeling runs will be modifications to the CALPUFF inputs associated with control 

devices (emissions, stack parameters). In contrast to the BART exemption analysis that predicts 

pre-control impacts from all BART-eligible units at a source together, BART determination 

analyses evaluates each emission unit independently of each other after control options are in 

place. As explained in the BART Guideline, the states may consider the frequency, magnitude, 

and duration of impairment for the determination analysis.

2.7.3 Implementing BART Modeling Analysis 

Each state will implement the BART analysis separately, as follows: 

x 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. 

x Oregon – DEQ will perform the BART exemption analysis and the individual BARTsubject facilities will perform the BART determination analysis. Oregon DEQ will 

perform any cumulative analysis required. 

x 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. 
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3. Visibility Modeling System 

In general, the BART exemption modeling using the CALPUFF suite of programs will follow 

the procedures and recommendations outlined in two documents: the IWAQM (Interagency 

Workgroup on Air Quality Models) and the FLAG (Federal Land Managers Air Quality Related 

Values Workgroup) reports (EPA 1998, FLAG 2000). Exceptions to these procedures are 

explicitly described in the appropriate sections below. Tables listing the modeling parameters 

for each CALPUFF module are located in the Appendices. 

The specific CALPUFF programs and their version numbers that will be used in both the 

exemption modeling and determination modeling (control evaluation) are presented in Table 2. 

The CALMET meteorological domain, as described below, covers the full three-state area. The 

computational domains, which will be unique for each source or group of sources undergoing 

modeling, will be a subset of the meteorological domain. As a result, a consistent 

meteorological data set will be used in all analyses, but the computational domains will be 

tailored to suit the modeling requirements for each individual source and the Class I areas within 

a radius of 300km. 

Table 2. CALPUFF Modeling System 

Program Version Level 

CALMET 6.211 060414 

CALPUFF 6.112 060412 

CALPOST 6.131 060410 

POSTUTIL 1.52 060412 

3.1 CALMET

The dispersion modeling will use CALMET windfields for the three-year period 2003-2005. 

These windfields cover the three-state area of Washington, Oregon, and Idaho, and also extend 

into adjacent states sufficiently to encompass all Class I areas within 300km of any BARTeligible facility included in this analysis (Figure 1). As part of the three-state collaboration on a 

BART protocol, it was decided to support the development of a consistent meteorological data 

set for use in both the BART exemption and determination analyses. Therefore, the states 

contracted with a consulting firm, Geomatrix, to provide this set of meteorological data for use 

in CALPUFF for determining whether a BART-eligible source is reasonably anticipated to cause 

or contribute to haze in a Federal Class I area.

One of the deliverables of that contract is a final CALMET modeling protocol that provides 

details on the methodology used to develop the data sets. Therefore, this BART modeling 

protocol only summarizes the development of the CALMET data set. For additional detail, the 

reader is referred to the “Modeling Protocol for BART CALMET Datasets” in Attachment 1. 
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Figure 1. CALMET Meteorological Domain. 

3.2 Meteorological Data 

3.2.1 Mesoscale Model Data 

It was the judgment of Idaho, Oregon, Washington, and EPA Region 10 that the use of three 

years of MM5 data developed by Western Regional Air Partnership (WRAP) would not 

adequately capture the meteorology in the Pacific Northwest. WRAP had run MM5 using 36-km 

and 12-km grids. The states and EPA Region 10 preferred a 4-km grid as it would more 

adequately capture the meteorology and the influences of complex terrain that characterizes the 

Region 10 area. Furthermore, WRAP had selected some physics options that are more 

appropriate for the dry southwest and not the wet northwest.

As a result, the three states contracted a consulting firm (Geomatrix) to process calendar year 

2003 to 2005 forecast 12-km MM5 output files archived at the University of Washington (UW). 

The 12-km MM5 domain includes all of Idaho, Oregon and Washington. Portions of Montana, 

Wyoming, Utah, Nevada and California are also included in the domain so that BART-eligible 

sources near these state borders that could impact Class I areas outside of Region 10 are 

considered in the analysis.

The MM5 data was evaluated for model performance using the statistical evaluation tool 
FINAL 10/11/06 

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METSTAT. CALMET Version 6.211, including a new over-water algorithm, was used to 

interpolate the 12-km data down to 4-km for the entire domain. The CALMET outputs were also 

evaluated to determine the model performance of the CALMET wind fields. At this time, 

METSTAT is unable to evaluate CALMET files. The statistical benchmarks listed in the WRAP 

Draft Final Report Annual 2002 MM5 Meteorological Modeling to Support Regional Haze 

Modeling of the Western United States ( ENVIRON and UCR, 2005) served as a guide for the 

acceptability of the MM5 data and CALMET output.

CALMET allows the user to adjust the MM5 wind fields in varying degree by the introduction of 

observational data, including surface, over-water, and upper air data (using the so-called 

NOOBS parameter). Idaho, Oregon, and Washington have determined that the observed cloud 

cover should be used, but that observed surface and upper air winds should not be included in 

CALMET as they locally distort the MM5 wind fields and have no significant effect on long 

range transport. As a result, the three states have judged that the MM5 simulations more than 

adequately characterize the regional wind patterns. It should also be noted that CALMET uses 

the finer scale land use and digital elevation model (DEM) data to interpolate the MM5 winds 

down to 4km, which improve the wind flow patterns in complex terrain within the modeling 

domain. 

3.2.2 CALMET Control File Settings 

These CALMET wind fields will be used by all BART-eligible sources within the three states 

for both BART exemption and BART determination modeling. The wind fields have been 

computed by Geomatrix using CALMET Version 6.211. Details of the parameter settings in 

CALMET are provided in Appendix C; however, the major assumptions are summarized below. 

1) The initial-guess fields used the 12-km MM5 outputs, forecast hours 13 – 24 from every 

00Z and 12Z initialization, taken from UW archives, for the three years, January 2003 – 

December, 2005. 

2) Both the BART exemption and determination modeling will utilize the wind fields at 

4km resolution. 

3) The meteorological data was evaluated in two stages using the extensive database of 

surface observations maintained by UW. First, the MM5 12-km data was evaluated prior 

to running CALMM5 using the METSTAT software program and secondly, the wind 

fields generated by CALMET was evaluated using standard statistical evaluation 

techniques.

4) There are 10 vertical layers with face heights of 0, 20, 40, 65, 120, 200, 400, 700, 1200, 

2200, and 4000 meters. 

5) CALMET was run using NOOBS = 1. Upper air, precipitation, and relative humidity 

data were taken from MM5. 
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6) The surface wind observations were ignored by setting the relative weight of surface 

winds to essentially zero (R1 = 1.0E-06). The only surface observation data that was 

effectively used in CALMET is cloud cover. This is essentially a no-observation 

approach. This method is specified in this protocol because previous modeling in the 

Pacific Northwest shows that the radius of influence of a typical surface wind 

observation must be set at a small number because of the presence of local topographic 

features. As a result, the adjustment to or distortion of wind fields by surface 

observations is extremely localized, on the order of 10-15km, and has no effect on long 

range transport to Class I areas. 

7) Precipitation data was obtained from MM5, so MM5NPSTA = -1 

8) No weighting of surface and upper air observations, and BIAS = 0, and ICALM = 0 

9) The terrain scale factor TERRAD = 12 

10) Land use and terrain data were developed using the North American 30-arc-second data 

3.3 CALPUFF

The CALPUFF modeling will use Version 6.112. This protocol generally follows the 

recommendation of the IWAQM and FLAG guidance documents. Details of the parameter 

settings in CALPUFF are provided in Appendix D; however, the major features are summarized 

below:

1) The three-year CALMET input files will be developed by Geomatrix and be provided as 

input-ready to CALPUFF. 

2) The BART exemption modeling will examine the visibility impairment on Class I areas 

within 300km of each single source. Where BART-eligible sources are grouped or where 

their emissions could collectively impair visibility in a Class I area, the exemption 

modeling will also group these sources in order to examine their cumulative impact. The 

computational modeling domain will be sufficient to include all Class I areas within a 

300km radius of a source or sources. 

3) Pasquill-Gifford Dispersion coefficients will be used. 

4) MESOPUFF-II chemistry algorithm will be used. 

5) Building downwash will be ignored for cases with source-to-receptor distances greater 

than 50km, as recommended by the Federal Land Managers (FLMs) (US Fish and 

Wildlife, National Park Service, and U.S. Forest Service) who were consulted for this 

protocol.
FINAL 10/11/06 

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

7) Source elevations that will be entered in CALPUFF will not use actual elevations but will 

be based on the modeled terrain surface used in CALMET for developing wind fields. 

The same algorithm in CALMET that determines the elevations of the observational 

stations will be used to make this calculation. These modified source elevations will be 

provided to the BART eligible sources.

3.3.1 Emissions

Section 2.4 above presents the emissions and stack data that is required from the facilities. This 

section only discusses the emissions estimates needed in CALPUFF. 

Primary emission, species will include the input species PM, SO2, SO4, and NOx; and the 

additional modeled species HNO3 and NO3. Emissions of H2SO4 will be included, if known, and 

used for estimation of SO4 emissions. SO2 emissions will be reviewed to ensure “doublecounting” is avoided. 

The primary PM species will be treated as follows: 

x BART-eligible sources are required to include both filterable and condensable 

fractions of PM.

Filterable:

 Elemental Carbon (EC) (<2.5 ȝm) 

 PM Fine (PMF) (<2.5 ȝm) 

 PM Coarse (PMC) (2.5 – 10 ȝm) 

Condensable:

Organic Carbon (SOA) 

Inorganic Aerosol (SO4)

Non-SO4 inorganic aerosol 

x The condensable fraction will be treated as primary emissions in the CALPUFF input 

file and assumed to be 100% in the PM2.5 fraction (see NPS Web site listed below). 

The states will work with the individual BART-eligible sources to develop appropriate PM 

speciation and size fractions. The following information sources may be used in the 

development of the speciation and fractions: 

x 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

x U.S. EPA – the EPA has developed generic PM speciation for all source categories 
FINAL 10/11/06 

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located at http://www.epa.gov/ttn/chief/emch/speciation/.

x If size fraction is not known, the following default values, based on information in the 

CALPUFF User’s Guide, CALPUFF GUI, and AP-42 will be used: 

Pollutant Mean diameter Standard deviation

SO4, NO3, PMF, SOA, EC 0.50 microns 1.5 

 PMC 5.00 microns 1.5 

3.3.2 Ozone Background 

Due to the number of BART-eligible sources and Class I areas being analyzed, a single value of 

60ppb (parts per billion) is used for all months and all three states. This value was determined 

based on a review of available ozone data for Idaho, Oregon, and Washington. 

3.3.3 Ammonia Background 

As with the ozone background, a single value of 17ppb is used for the ammonia background. 

This value is supported by measurements made in 1996 – 1997 at Abbotsford in the Frazier 

River Valley of British Columbia. This value has also been commonly used as background for 

Prevention of Significant Deterioration modeling in the Pacific Northwest and will ensure that 

for BART exemption modeling, conditions are not ammonia limited. It is recognized that 

ammonia values may be lower in Class I areas; however, the BART analysis must account for 

transport through ammonia-rich areas. 

3.3.4 Receptor Locations 

Visibility impacts will be computed at all Class I areas and the Columbia River Gorge Scenic 

Area if they lie within a 300-km radius of the BART eligible source. The geolocations of the 

receptor points and their elevations for the Class I areas that will be used in the modeling are 

available for download from the National Park Service Web site at 

http://www2.nature.nps.gov/air/Maps/Receptors/index.cfm>.

Receptor points and elevations for the Columbia River Gorge Scenic Area will be provided by 

Oregon and Washington. 

3.4 CALPOST and VISIBILITY POST-PROCESSING 

The following assumptions will be used in CALPOST and POSTUTIL to calculate the visibility 

impairment: 
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1) For the visibility calculation, Method 6 will be employed. This method uses monthly 

average relative humidity and f(RH) values for each Class I area as provided in Appendix 

B, which are based on the EPA Guidance for Regional Haze analysis (EPA 2003). 

2) Particulate species for the visibility analysis will include SO4, NO3, EC, OC, PMF, and 

PMC, as reported in the CALPOST output files. 

3) POSTUTIL will not be used to speciate modeled PM10 concentrations, as PM10 will be 

speciated into its components (PMF, PMC, SOA, EC, SO4) and entered as primary 

emissions in CALPUFF. In addition, HNO3/NO3 partition option in POSTUTIL will not 

be used for ammonia limiting. 

4) Natural background extinction calculations will use the 20% best days for each Class I 

area in the three-state region. The natural background for the 20% best days has been 

refined from that which is in “Guidance for Estimating Natural Visibility Conditions 

Under the Regional Haze Rule” (EPA 2003). The extinction coefficients for the 20% 

best days have been calculated following the approach taken in the Draft Montana BART 

modeling protocol. This procedure uses the haze index (HI) in deciviews at the 10th 

percentile (median of the 20% best days) and an activity factor that is calculated for each 

Class I area. Tables providing the monthly f(RH) and 20% best days coefficients are 

provided in Appendix B, and are based on data from EPA (2003). For the exemption 

modeling, the Rayleigh scattering value will be 10 Mm-1 for all Class I areas. 

x The 98th percentile value will be calculated for all BART-eligible sources at each 

mandatory Class I area. 

5) The CALPOST “LST” output files will be used to determine the 98th percentile of 

visibility impairment for each receptor in CLASS I areas. 

6) The contribution threshold has the implied level of precision equal to the level of 

precision reported by CALPOST. Therefore, the 98th percentile value will be reported to 

three decimal places. 

4. Interpretation of Results 

The change in visibility impairment for the BART exemption modeling is based on the increase 

in HI from a BART-eligible source or sources relative to natural background, defined as the 20% 

best visibility days for each Class I area. This definition of natural background is consistent with 

the intent of the BART guideline (Federal Register Vol. 70, No. 128, pf 39125).

The U.S. EPA recommends using the 98th percentile value from the distribution of values 

containing the highest modeled delta-deciview ('dv) value for each day of the simulation from 

all modeled receptors at a given Class I area. The 98th percentile 'dv value will be determined 
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in the following ways: 

x The 8th highest value for each year modeled 

x The 22nd highest value for the 3-year modeling period 

Both methods will be used and the highest value of the two will be compared to the contribution 

threshold ('dv0.5 dv). If there are more than 7 days with values greater than the contribution 

threshold in any single meteorological year for any Class I area, or more than 21 days in three 

years, then the source is considered Subject-to-BART. 

5. References 

40 CFR Part 51, Appendix W. Guidelines on Air Quality Models

ENVIRON and UCR 2005. Draft Final Report Annual 2002 MM5 Meteorological Modeling to 

Support Regional Haze Modeling of the Western United States. Available at 

http://pah.cert.ucr.edu/aqm/308/reports/mm5/DrftFnl_2002MM5_FinalWRAP_Eval.pdf. 

 ENVIRON International Corporation and University of California Riverside). March, 

2005.

EPA (U.S. Environmental Protection Agency) 1998. Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long 

Range Transport Impacts, EPA-454/R-98-019, December 1998. 

EPA 2003. Guidance for Estimating Natural Visibility Conditions under the Regional Haze 

Rule, EPA-454/B-03-005, September, 2003. 

EPA 2006a. Conference call with Fish and Wildlife and U.S. EPA Region 10, and the states of 

ID, OR and WA. January 17, 2006. 

EPA 2006b. Conference call with the Fish and Wildlife and U.S. EPA Region 10, National Park 

Service, and the states of ID, OR and WA. January 18, 2006. 

EPA 2006c. Conference call with the Fish and Wildlife and U.S. EPA Region 10, and the states 

of ID, OR and WA. January 20, 2006. 

Federal Land Managers’ Air Quality Related Values Workgroup (FLAG) 2000. Phase I Report.

December 2000. 

Federal Register, Vol. 70, No. 128. Regional Haze Regulations and Guidelines for Best 

Available Retrofit Technology (BART) Determinations. pp. 39104 – 30172, July 6, 2005. 
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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.
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Table 1. Federal Mandatory Class I Areas. 

Class I Area Federal Land Manager 

Idaho

Craters of the Moon National Monument Park Service 

Hells Canyon Wilderness Forest Service 

Sawtooth Wilderness Forest Service 

Selway-Bitterroot Wilderness Forest Service 

Yellowstone National Park Park Service 

Oregon

Crater Lake National Park Park Service 

Diamond Peak Wilderness Forest Service 

Eagle Cap Wilderness Forest Service 

Gearhart Mountain Wilderness Forest Service 

Hells Canyon Wilderness Forest Service 

Kalmiopsis Wilderness Forest Service 

Three Sisters Wilderness Forest Service 

Mount Hood Wilderness Forest Service 

Mount Jefferson Wilderness Forest Service 

Mount Washington Wilderness Forest Service 

Mountain Lakes Wilderness Forest Service 

Strawberry Mountain Wilderness Forest Service 

Washington

Alpine Lakes Wilderness Forest Service 

Goat Rocks Wilderness Forest Service 

Glacier Peak Wilderness Forest Service 

Mount Adams Wilderness Forest Service 

Mount Ranier National Park Park Service 

North Cascades National Park Park Service 

Olympic National Park Park Service 

Pasayten Wilderness Forest Service 

Neighboring States

Anaconda-Pintler Wilderness (MT) Forest Service 

Bob Marshall Wilderness (MT) Forest Service 

Cabinet Mountains Wilderness (MT) Forest Service 

Gates of the Mountain Wilderness (MT) Forest Service 

Glacier National Park (MT) Park Service 

Missions Mountain Wilderness (MT) Forest Service 

Scapegoat Wilderness (MT) Forest Service 

Red Rock Lakes Refuge (MT) Fish & Wildlife Service 

Bridger Wilderness (WY) Forest Service 

Fitzpatrick Wilderness (WY) Forest Service 

Grand Teton National Park (WY) Park Service 

North Absaroka Wilderness (WY) Forest Service 

Teton Wilderness (WY) Forest Service 

Washakie Wilderness (WY) Forest Service 

Caribous Wilderness (CA) Forest Service 

Lassen Volcanic National Park (CA) Park Service 
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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.
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Appendix B 

Natural Visibility Background 

and

Monthly Relative Humidity f(RH) 
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Adjustment to speciated particulate (Western States) to reflect 20% Best Visibility Days conditions

 Monthly f(RH) are from Appendix A of Draft Guidance for Estimating Natural Visibility Conditions under the RHR (Sept. 2003 ).

 Background extinction coefficients (20% Best Days) have been calculated using Annual Avg bext, Best 20% bext, and activity factors.

Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec. BKSO4 BKNO3 BKPMC BKOC SOIL BKEC

Class I Area State f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) ug/m3 ug/m3 ug/m3 ug/m3 ug/m3 ug/m3

CaribouWilderness CA 3.69 3.13 2.83 2.45 2.37 2.17 2.07 2.13 2.20 2.38 3.01 3.41 0.048 0.040 1.20 0.188 0.200 0.008

LassenVolcanic CA 3.81 3.19 2.91 2.53 2.42 2.19 2.09 2.14 2.23 2.43 3.13 3.53 0.048 0.040 1.21 0.189 0.201 0.008

Lava Beds NP CA 3.98 3.36 3.07 2.70 2.62 2.43 2.31 2.34 2.42 2.72 3.52 3.81 0.050 0.042 1.26 0.197 0.210 0.008

MarbleMountain CA 4.44 3.79 3.74 3.33 3.37 3.24 3.18 3.19 3.24 3.37 4.12 4.15 0.052 0.043 1.30 0.204 0.217 0.009

RedwoodNP CA 4.42 3.91 4.56 3.91 4.50 4.70 4.86 4.72 4.31 3.66 3.81 3.40 0.054 0.045 1.34 0.210 0.224 0.009

SouthWarner CA 3.62 3.08 2.72 2.35 2.29 2.12 1.90 1.92 1.97 2.30 3.05 3.44 0.048 0.040 1.21 0.190 0.202 0.008

ThousandLakes CA 3.81 3.19 2.91 2.53 2.42 2.19 2.09 2.14 2.23 2.43 3.13 3.53 0.048 0.040 1.21 0.190 0.202 0.008

Yolla Bolly Middle Eel Wildern CA 3.95 3.35 3.14 2.76 2.68 2.47 2.44 2.50 2.56 2.70 3.31 3.62 0.049 0.041 1.24 0.194 0.206 0.008

Craters of the Moon ID 3.13 2.74 2.28 2.02 2.01 1.81 1.43 1.42 1.57 1.97 2.77 3.04 0.046 0.038 1.15 0.180 0.192 0.008

HellsCanyon ID 3.70 3.12 2.51 2.17 2.12 2.00 1.63 1.58 1.79 2.41 3.45 3.87 0.048 0.040 1.21 0.190 0.202 0.008

SawtoothWilderness ID 3.34 2.87 2.32 2.01 2.00 1.84 1.43 1.40 1.50 1.96 2.94 3.31 0.046 0.039 1.16 0.182 0.193 0.008

Selway-BitterrootWilderness ID 3.50 3.02 2.59 2.34 2.36 2.31 1.93 1.86 2.09 2.55 3.30 3.50 0.048 0.040 1.21 0.190 0.202 0.008

Anaconda-PintlerWilderness MT 3.32 2.88 2.54 2.35 2.36 2.31 1.96 1.88 2.10 2.52 3.15 3.29 0.048 0.040 1.20 0.188 0.200 0.008

BobMarshall MT 3.57 3.10 2.77 2.59 2.66 2.70 2.34 2.23 2.58 2.92 3.47 3.54 0.049 0.041 1.22 0.191 0.203 0.008

CabinetMountains MT 3.81 3.27 2.85 2.61 2.66 2.68 2.30 2.18 2.56 2.98 3.70 3.86 0.050 0.041 1.24 0.195 0.207 0.008

Gates of the Mountain MT 2.89 2.57 2.42 2.30 2.30 2.27 2.03 1.94 2.12 2.41 2.75 2.81 0.047 0.039 1.18 0.185 0.197 0.008

GlacierNP MT 4.01 3.47 3.18 3.06 3.24 3.39 2.76 2.60 3.19 3.45 3.82 3.89 0.051 0.043 1.28 0.200 0.213 0.009

MissionMountain MT 3.60 3.13 2.73 2.52 2.60 2.62 2.27 2.19 2.50 2.87 3.51 3.59 0.049 0.041 1.23 0.193 0.205 0.008

RedRock Lakes MT 2.73 2.46 2.28 2.12 2.10 1.91 1.67 1.58 1.77 2.07 2.56 2.68 0.046 0.039 1.16 0.181 0.193 0.008

ScapegoatWilderness MT 3.19 2.81 2.57 2.43 2.45 2.44 2.14 2.04 2.28 2.61 3.08 3.14 0.048 0.040 1.20 0.188 0.200 0.008

Crater Lake NP OR 4.57 3.92 3.68 3.36 3.22 2.99 2.84 2.87 3.05 3.59 4.57 4.56 0.053 0.044 1.32 0.206 0.219 0.009

DiamondPeak OR 4.52 3.96 3.64 3.66 3.16 3.12 2.90 2.93 3.05 3.67 4.55 4.57 0.053 0.044 1.33 0.208 0.222 0.009

Eagle Cap OR 3.77 3.16 2.47 2.10 2.04 1.87 1.61 1.56 1.61 2.25 3.44 3.97 0.049 0.041 1.22 0.191 0.203 0.008

Gearhart Mountain OR 3.96 3.38 3.06 2.75 2.65 2.48 2.28 2.30 2.38 2.84 3.65 3.84 0.050 0.042 1.25 0.196 0.208 0.008

Kalmiopsis Wilderness OR 4.54 3.90 3.83 3.45 3.46 3.32 3.20 3.20 3.29 3.56 4.39 4.32 0.053 0.044 1.32 0.206 0.219 0.009

Mount Hood OR 4.29 3.81 3.46 3.87 2.95 3.15 2.85 3.00 3.10 3.86 4.53 4.55 0.053 0.044 1.33 0.209 0.222 0.009

Mount Jefferson OR 4.41 3.90 3.56 3.74 3.07 3.11 2.89 2.91 3.03 3.78 4.55 4.54 0.054 0.045 1.34 0.210 0.223 0.009

Mountain Lakes OR 4.29 3.62 3.32 2.98 2.86 2.64 2.49 2.50 2.64 3.10 4.12 4.26 0.051 0.043 1.28 0.201 0.214 0.009

MountWashington OR 4.44 3.93 3.58 3.73 3.09 3.11 2.98 2.91 3.02 3.76 4.56 4.56 0.054 0.045 1.36 0.213 0.227 0.009

StrawberryMountain OR 3.89 3.33 2.75 2.93 2.27 2.39 1.98 1.97 1.87 2.63 3.69 4.07 0.050 0.042 1.26 0.197 0.210 0.008

ThreeSisters OR 4.47 3.95 3.61 3.72 3.11 3.11 3.00 2.91 3.03 3.79 4.60 4.57 0.054 0.045 1.35 0.212 0.226 0.009

AlpineLakes WA 4.25 3.79 3.47 3.90 2.93 3.22 2.92 3.12 3.25 3.91 4.47 4.51 0.054 0.045 1.35 0.212 0.225 0.009

GlacierPeak WA 4.16 3.72 3.42 3.75 2.91 3.16 2.88 3.14 3.33 3.90 4.42 4.43 0.054 0.045 1.34 0.210 0.223 0.009

GoatRocks WA 4.25 3.75 3.36 4.24 2.83 3.38 3.03 3.19 3.07 3.77 4.42 4.55 0.054 0.045 1.34 0.210 0.224 0.009

Mount Adams WA 4.29 3.80 3.44 4.40 2.92 3.49 3.12 3.27 3.13 3.86 4.49 4.56 0.053 0.044 1.33 0.209 0.222 0.009

MountRainier WA 4.42 3.96 3.64 4.65 3.06 3.69 3.30 3.50 3.40 4.11 4.66 4.66 0.055 0.045 1.36 0.214 0.227 0.009

NorthCascades NP WA 4.10 3.69 3.43 3.74 2.93 3.20 2.93 3.23 3.45 3.93 4.39 4.38 0.053 0.044 1.33 0.209 0.222 0.009

OlympicNP WA 4.51 4.08 3.82 4.08 3.17 3.46 3.12 3.48 3.71 4.38 4.83 4.75 0.054 0.045 1.36 0.213 0.226 0.009

PasaytenWilderness WA 4.17 3.72 3.41 3.72 2.89 3.16 2.88 3.15 3.32 3.86 4.42 4.46 0.053 0.044 1.33 0.208 0.222 0.009

BridgerWilderness WY 2.52 2.35 2.34 2.19 2.10 1.80 1.50 1.49 1.74 2.00 2.44 2.42 0.046 0.038 1.14 0.178 0.190 0.008

FitzpatrickWilderness WY 2.51 2.33 2.24 2.13 2.09 1.80 1.51 1.46 1.73 1.98 2.39 2.44 0.046 0.038 1.14 0.179 0.190 0.008

Grand Teton NP WY 2.62 2.39 2.24 2.10 2.06 1.79 1.52 1.47 1.72 2.00 2.43 2.55 0.046 0.038 1.14 0.178 0.190 0.008

NorthAbsaroka WY 2.43 2.27 2.24 2.17 2.14 1.93 1.69 1.56 1.76 2.04 2.35 2.40 0.046 0.038 1.14 0.178 0.190 0.008

TetonWilderness WY 2.53 2.35 2.24 2.12 2.10 1.85 1.59 1.51 1.74 2.02 2.40 2.48 0.046 0.038 1.14 0.178 0.190 0.008

WashakieWilderness WY 2.50 2.34 2.23 2.12 2.11 1.84 1.56 1.49 1.75 2.00 2.38 2.46 0.046 0.038 1.14 0.179 0.190 0.008

YellowstoneNP WY 2.54 2.36 2.27 2.16 2.15 1.94 1.69 1.59 1.79 2.08 2.45 2.51 0.046 0.038 1.15 0.180 0.192 0.008

JarbridgeWilderness NV 2.95 2.60 2.08 2.12 2.21 2.17 1.58 1.40 1.35 1.63 2.44 2.80 0.046 0.038 1.14 0.179 0.190 0.008

Columbia River Gorge OR-WA 5.03 5.03 2.59 2.59 2.59 2.11 2.11 2.11 3.51 3.51 3.51 5.03 0.569 0.231 4.85 1.05 0.217 0.205

CALPOST Input Group 2 CALPOST Input Group 2

Monthly extinction coefficients for hygroscopic species (RHFAC) Background extinction coefficients (20% Best Days)
FINAL 10/11/06 

20

Appendix C 

CALMET Parameter Values 
FINAL 10/11/06 

21

Appendix C 

CALMET Parameter Values 

Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input

Group Variable Description Default Value Recommended Value 

0 DIADAT 

 Input file: preprocessed surface temperature data 

(DIAG.DAT) User Defined 

0 GEODAT Input file: Geophysical data (GEO.DAT) User Defined User Define 

0 LCFILES Convert file name to lower case User Defined 

0 METDAT Output file (CALMET.DAT) User Defined 

0 METLST Output file (CALMET.LST) User Defined 

0 MM4DAT Input file: MM4 data (MM4.DAT) User Defined 

0 NOWSTA Input files: Names of NOWSTA overwater stations User Defined 0 

0 NUSTA Number of upper air data sites User Defined 0

0 PACDAT Output file: in Mesopuff II format (PACOUT.DAT) User Defined 

0 PRCDAT Input file: Precipitation data (PRECIP.DAT) User Defined 

0 PRGDAT Input file: CSUMM prognostic wind data (PROG.DAT) User Defined 

0 SEADAT 

 Input files: Names of NOWSTA overwater stations 

(SEAn.DAT) User Defined 

0 SRFDAT Input file: Surface data (SURF.DAT) User Defined 

0 TSTFRD Output file (TEST.FRD) User Defined 

0 TSTKIN Output file (TEST.KIN) User Defined 

0 TSTOUT Output file (TEST.OUT) User Defined 

0 TSTPRT Output file (TEST.PRT) User Defined 

0 TSTSLP Output file (TEST.SLP) User Defined 

0 UPDAT Input files: Names of NUSTA upper air data files (UPn.DAT) UPn.DAT 

0 WTDAT Input file: Terrain weighting factors (WT.DAT) User Defined 

1 CLDDAT Input file: Cloud data (CLOUD.DAT) User Defined Not used 

1 IBDY Beginning day User Defined 

1 IBHR Beginning hour User Defined 

1 IBMO Beginning month User Defined 

1 IBTZ Base time zone User Defined 8

1 IBYR Beginning year User Defined 

1 IRLG Number of hours to simulate User Defined User Define 

1 IRTYPE Output file type to create (must be 1 for CALPUFF) 1 1

1 ITEST Flag to stop run after Setup Phase 2 2

1 LCALGRD Are w-components and temperature needed? T T

2 DATUM WGS-G, NWS-27, NWS-84, ESR-S,... NWS84

2 DGRIDKM Grid spacing User Defined 4

2 IUTMZN UTM Zone User Defined User Define 

2 LLCONF 

 When using Lambert Conformal map coordinates - rotate 

winds from true north to map north? F F

2 NX Number of east-west grid cells User Defined 373

2 NY Number of north-south grid cells User Defined 316

2 NZ Number of vertical layers User Defined 10

2 RLAT0 Latitude used if LLCONF = T User Defined 49.0N

2 RLON0 Longitude used if LLCONF = T User Defined 121.0W

2 XLAT0 Southwest grid cell latitude User Defined User Define 

2 XLAT1 Latitude of 1st standard parallel User Defined 30

2 XLAT2 Latitude of 2nd standard parallel User Defined 60

2 XORIGKM Southwest grid cell X coordinate User Defined -572

2 YLON0 Southwest grid cell longitude User Defined -956

2 YORIGKM Southwest grid cell Y coordinate User Defined User Define 

2 ZFACE Vertical cell face heights (NZ+1 values) User Defined 

0,20,40,65,120,200,400,

700,1200,2200,4000

3 IFORMO Format of unformatted file (1 for CALPUFF) 1 1

3 LSAVE Save met. data fields in an unformatted file? T T

4 ICLOUD Is cloud data to be input as gridded fields? (0 = No) 0 0 

4 IFORMC Format of cloud data (2 = formatted) 2 2

4 IFORMP Format of precipitation data (2 = formatted) 2 2

4 IFORMS Format of surface data (2 = formatted) 2 2
FINAL 10/11/06 

22

Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input

Group Variable Description Default Value Recommended Value 

4 NOOBS Use or non-use of surface, overwater, upper observations 1 

4 NPSTA Number of stations in PRECIP.DAT User Defined -1

4 NSSTA Number of stations in SURF.DAT file User Defined 115

5 ALPHA Empirical factor triggering kinematic effects 0.1 0.1

5 BIAS Surface/upper-air weighting factors (NZ values) NZ*0 NZ*0

5 CRITFN Critical Froude number 1 1

5 DIVLIM Maximum acceptable divergence 5.00E-06 5.00E-06

5 FEXTR2 

 Multiplicative scaling factor for extrap surface obs to uppr 

layrs NZ*0.0 

5 ICALM Extrapolate surface calms to upper layers? (0 = No) 0 0

5 IDIOPT1 Compute temperatures from observations (0 = True) 0 0 

5 IDIOPT2 Compute domain-average lapse rates? (0 = True) 0 0

5 IDIOPT3 Compute internally inital guess winds? (0 = True) 0 0 

5 IDIOPT4 Read surface winds from SURF.DAT? ( 0 = True) 0 0

5 IDIOPT5 Read aloft winds from UPn.DAT? (0 = True) 0 0

5 IEXTRP 

 Extrapolate surface winds to upper layers? (-4 = use 

similarity theory and ignore layer 1 of upper air station data) -4 -1 

5 IFRADJ Adjust winds using Froude number effects? (1 = Yes) 1 1

5 IKINE Adjust winds using kinematic effects? (1 = Yes) 0 0

5 IOBR Use O’Brien procedure for vertical winds? (0 = No) 0 0

5 IPROG Using prognostic or MM-FDDA data? (0 = No) 0 14

5 ISLOPE Compute slope flows? (1 = Yes) 1 1

5 ISTEPPG Timestep (hours) of the prognostic model input data 1 1

5 ISURFT 

 Surface station to use for surface temperature (between 1 

and NSSTA) User Defined 98 

5 IUPT Station for lapse rates (between 1 and NUSTA) User Defined 1

5 IUPWND 

 Upper air station for domain winds (-1 = 1/r**2 interpolation 

of all stations) -1 -1 

5 IWFCOD Generate winds by diagnostic wind module? (1 = Yes) 1 1

5 KBAR Level (1 to NZ) up to which barriers apply NZ 10

5 LLBREZE Use Lake Breeze module F F

5 LVARY Use varying radius to develop surface winds? F F 

5 METBXID Station IDs in the region User Defined 

5 NBAR Number of Barriers to interpolation User Defined 0

5 NBOX Number of Lake Breeze regions User Defined 0

5 NINTR2 Max number of stations for interpolations (NA values) 99 99 

5 NITER Max number of passes in divergence minimization 50 50

5 NLB Number of stations in region User Defined 0

5 NSMTH Number of passes in smoothing (NZ values) 2, 4*(NZ-1) 1,2,2,3,3,4,4,4,4,4 

5 R1 Relative weight at surface of Step 1 field and obs User Defined 1.00E-06

5 R2 Relative weight aloft of Step 1 field and obs User Defined 1.00E-06

5 RMAX1 Max surface over-land extrapolation radius (km) User Defined 200 

5 RMAX2 Max aloft over-land extrapolation radius (km) User Defined 200 

5 RMAX3 Maximum over-water extrapolation radius (km) User Defined 200 

5 RMIN Minimum extrapolation radius (km) 0.1 0.1

5 RMIN2 

 Distance (km) around an upper air site where vertical 

extrapolation is excluded (Set to -1 if IEXTRP = ±4) 4 -1 

5 RPROG Weighting factor for CSUMM prognostic wind data User Defined 0 

5 TERRAD Radius of influence of terrain features (km) User Defined 12

5 XBBAR X coordinate of Beginning of each barrier User Defined 0 

5 XBCST X Point defining the coastline (straight line) User Defined 0 

5 XEBAR X coordinate of Ending of each barrier User Defined 0 

5 XECST X Point User Defined 0

5 XG1 X Grid line 1 defining region of interest User Defined 0

5 XG2 X Grid line 2 User Defined 0

5 YBBAR Y coordinate of Beginning of each barrier User Defined 0 

5 YBCST Y Point User Defined 0

5 YEBAR Y coordinate of Ending of each barrier User Defined 0 

5 YECST Y Point User Defined 0
FINAL 10/11/06 

23

Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input

Group Variable Description Default Value Recommended Value 

5 YG1 Y Grid line 1 User Defined 0

5 YG2 Y Grid Line 2 User Defined 0

5 ZUPT Depth of domain-average lapse rate (m) 200 200

5 ZUPWND Bottom and top of layer for 1st guess winds (m) 1, 1000 1.,1000.

6 CONSTB Neutral mixing height B constant 1.41 1.41

6 CONSTE Convective mixing height E constant 0.15 0.15 

6 CONSTN Stable mixing height N constant 2400 2400

6 CONSTW Over-water mixing height W constant 0.16 0.16 

6 CUTP Minimum cut off precip rate (mm/hr) 0.01 0.01

6 DPTMIN Minimum capping potential temperature lapse rate 0.001 0.001 

6 DSHELF Coastal/shallow water length scale 0 0

6 DZZI Depth for computing capping lapse rate (m) 200 200

6 FCORIOL Absolute value of Coriolis parameter 1.00E-04 1.00E-04

6 HAFANG Half-angle for looking upwind (degrees) 30 30 

6 IAVET Conduct spatial averaging of temperature? (1 = True) 1 1

6 IAVEZI Spatial averaging of mixing heights? (1 = True) 1 1

6 ICOARE Overwater surface fluxes method and parameters 10 10

6 ICOOL COARE cool skin layer computation 0 0

6 ILEVZI Layer to use in upwind averaging (between 1 and NZ) 1 1

6 ILUOC3D Land use category ocean in 3D.DAT datasets 16 16

6 IMIXH Method to compute the convective mixing height 1 1

6 IRAD Form of temperature interpolation (1 = 1/r) 1 1

6 IRHPROG 

3D relative humidity from observations or from prognostic 

data 0 1 

6 ITPROG 3D temps from obs or from prognostic data? 0 2

6 ITWPROG 

Option for overwater lapse rates used in convective mixing 

height growth 0 2 

6 IWARM COARE warm layer computation 0 0

6 JWAT1 Beginning landuse type defining water 999 55

6 JWAT2 Ending landuse type defining water 999 55

6 MNMDAV Max averaging radius (number of grid cells) 1 1

6 NFLAGP Method for precipitation interpolation (2 = 1/r**2) 2 2

6 NUMTS Max number of stations in temperature interpolations 5 10

6 SIGMAP Precip radius for interpolations (km) 100 12

6 TGDEFA Default over-water capping lapse rate (K/m) -0.0045 -0.0045 

6 TGDEFB Default over-water mixed layer lapse rate (K/m) -0.0098 -0.0098 

6 THRESHL 

Threshold buoyancy flux required to sustain convective 

mixing height growth overland 0.05 0.05 

6 THRESHW 

Threshold buoyancy flux required to sustain convective 

mixing height growth overwater 0.05 0.05 

6 TRADKM Radius of temperature interpolation (km) 500 500

6 ZIMAX Maximum over-land mixing height (m) 3000 3000

6 ZIMAXW Maximum over-water mixing height (m) 3000 3000 

6 ZIMIN Minimum over-land mixing height (m) 50 50

6 ZIMINW Minimum over-water mixing height (m) 50 50 
FINAL 10/11/06 

24

Appendix D 

CALPUFF Parameter Values 
FINAL 10/11/06 

25

Appendix D

CALPUFF Parameter Values 

Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input

Group

Group

Description Sequence Variable Description Default Valuea

Recommended

Value

1 Run Control 1 METRUN Do we run all periods (1) or a subset (0)? 0

1 2 IBYR Beginning year User Defined 

1 3 IBMO Beginning month User Defined 

1 4 IBDY Beginning day User Defined 

1 5 IBHR Beginning hour User Defined 

1 5 IRLG Length of run (hours) User Defined 

1 5 NSECDT Length of modeling time step (seconds) 3600 3600

1 6 NSPEC 

Number of species modeled (for MESOPUFF II 

chemistry) 5 

1 7 NSE Number of species emitted 3

1 8 ITEST Flag to stop run after Setup Phase 2

1 9 MRESTART 

Restart options (0 = no restart) allows splitting 

runs into smaller segments 0

1 10 NRESPD Number of periods in Restart 0

1 11 METFM 

Format of input meteorology (1 = CALMET, 2 = 

ISC) 1

1 12 AVET 

Averaging time lateral dispersion parameters 

(minutes) 60 60 

1 13 PGTIME PG Averaging time 60 60

2 Tech Options 1 MGAUSS Near-field vertical distribution (1 = Gaussian) 1 1 

2 2 MCTADJ 

Terrain adjustments to plume path (3 = Plume 

path) 3 3

2 3 MCTSG 

Do we have subgrid hills? (0 = No) allows 

CTDM-like treatment for subgrid scale hills 0 0

2 4 MSLUG Near-field puff treatment (0 = No slugs) 0 0

2 5 MTRANS Model transitional plume rise? (1 = Yes) 1 1

2 6 MTIP Treat stack tip downwash? (1 = Yes) 1 1

2 7 MBDW 

Method to simulate downwash 

(1=ISC,2=PRIME) not used 

2 8 MSHEAR Treat vertical wind shear? (0 = No) 0 0

2 9 MSPLIT Allow puffs to split? (0 = No) 0 0

2 10 MCHEM MESOPUFF-II Chemistry? (1 = Yes) 1 1

2 11 MAQCHEM Aqueous phase transformation 0 0

2 12 MWET Model wet deposition? (1 = Yes) 1 1

2 13 MDRY Model dry deposition? (1 = Yes) 1 1

2 13 MTILT Plume Tilt (gravitational settling) 0 0

2 14 MDISP 

Method for dispersion coefficients 

(2=micromet,3 = PG) 3 3 

2 15 MTURBVW 

Turbulence characterization? (Only if MDISP = 

1 or 5) 3 3 

2 16 MDISP2 Backup coefficients (Only if MDISP = 1 or 5) 3 3

2 16 MTAULY Method for Sigma y Lagrangian timescale 0 0

2 16 MTAUADV 

Method for Advective-Decay timescale for 

Turbulence 0 0 

2 16 MCTURB 

Method to compute sigma v,w using micromet 

variables 1 1 

2 17 MROUGH Adjust PG for surface roughness? (0 = No) 0 0

2 18 MPARTL Model partial plume penetration? (0 = No) 1 1

2 19 MTINV 

Elevated inversion strength (0 = compute from 

data) 0 0 

2 20 MPDF Use PDF for convective dispersion? (0 = No) 0 0

2 21 MSGTIBL 

Use TIBL module? (0 = No) allows treatment of 

 subgrid scale coastal areas 0 0 

2 22 MBCON Boundary conditions modeled 0 0

2 23 MFOG Configure for FOG model output 0 0

2 24 MREG Regulatory default checks? (1 = Yes) 1 1
FINAL 10/11/06 

26

Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input

Group

Group

Description Sequence Variable Description Default Valuea

Recommended

Value

3 Species List 1 CSPECn 

Names of species modeled (for MESOPUFF II 

must be SO2-SO4-NOX-HNO3-NO3) User Defined 

3 2 

Specie

Names Manner species will be modeled User Defined 

3 3 

Specie

Groups Grouping of species if any User Defined 

3 4 CGRUP 

3 5 CGRUP 

4 MapProjection XLAT1 Latitude of 1st standard parallel 

4 XLAT2 Latitude of 2nd standard parallel 

4 DATUM NWS84 

4 1 NX Number of east-west grids of input meteorology User Defined 

4 2 NY 

Number of north-south grids of input 

meteorology User Defined 

4 3 NZ Number of vertical layers of input meteorology User Defined 

4 4 DGRIDKM Meteorology grid spacing (km) User Defined 

4 5 ZFACE Vertical cell face heights of input meteorology User Defined 

4 6 XORIGKM Southwest corner (east-west) of input User 

Defined

meteorology 

4 7 YORIGIM Southwest corner (north-south) of input User 

Defined

meteorology 

4 8 IUTMZN UTM zone User Defined 

4 9 XLAT Latitude of center of meteorology domain User Defined 

4 10 XLONG Longitude of center of meteorology domain User Defined 

4 11 XTZ Base time zone of input meteorology User Defined 

4 12 IBCOMP Southwest X-index of computational domain User Defined 

4 13 JBCOMP Southwest Y-index of computational domain User Defined 

4 14 IECOMP Northeast X-index of computational domain User Defined 

4 15 JECOMP Northeast Y-index of computational domain User Defined 

4 16 LSAMP Use gridded receptors? (T = Yes) F F

4 17 IBSAMP Southwest X-index of receptor grid User Defined 

4 18 JBSAMP Southwest Y-index of receptor grid User Defined 

4 19 IESAMP Northeast X-index of receptor grid User Defined 

4 20 JESAMP Northeast Y-index of receptor grid User Defined 

4 21 MESHDN 

Gridded recpetor spacing = 

DGRIDKM/MESHDN 1 

5 Output Options 1 ICON Output concentrations? (1 = Yes) 1 1

5 2 IDRY Output dry deposition flux? (1 = Yes) 1 1

5 3 IWET Output west deposition flux? (1 = Yes) 1 1

5 4 IT2D 2D Temperature 0 0 

5 5 IRHO 2D Density 0 0 

5 6 IVIS Output RH for visibility calculations (1 = Yes) 1 1

5 7 LCOMPRS Use compression option in output? (T = Yes) T T

5 8 ICPRT Print concentrations? (0 = No) 0 0

5 9 IDPRT Print dry deposition fluxes (0 = No) 0 0

5 10 IWPRT Print wet deposition fluxes (0 = No) 0 0

5 11 ICFRQ Concentration print interval (1 = hourly) 1 24

5 12 IDFRQ Dry deposition flux print interval (1 = hourly) 1 24

5 13 IWFRQ West deposition flux print interval (1 = hourly) 1 24

5 14 IPRTU 

Print output units (1 = g/m**3; g/m**2/s; 3 = 

ug/m3, ug/m2/s) 1 3 

5 15 IMESG Status messages to screen? (1 = Yes) 1 2

5 16 LDEBUG Turn on debug tracking? (F = No) F F

5 16 IPFDEB First puff to track 1 1

5 17 NPFDEB (Number of puffs to track) (1) 1

5 18 NN1 (Met. Period to start output) (1) 1
FINAL 10/11/06 

27

Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input

Group

Group

Description Sequence Variable Description Default Valuea

Recommended

Value

5 19 NN2 (Met. Period to end output) (10) 10

7 Dry Dep Chem Dry Gas Dep 

Chemical parameters of gaseous deposition 

species User Defined defaults 

8 Dry Dep Size Dry Part. Dep 

Chemical parameters of particulate deposition 

species User Defined defaults 

9 Dry Dep Misc 1 RCUTR Reference cuticle resistance (s/cm) 30 30 

9 2 RGR Reference ground resistance (s/cm) 10 10

9 3 REACTR Reference reactivity 8 8

9 4 NINT Number of particle-size intervals 9 9

9 5 IVEG 

Vegetative state (1 = active and unstressed; 

2=active and stressed) 1 1 

10 Wet Dep Wet Dep Wet deposition parameters User Defined defaults 

11 Chemistry 1 MOZ 

Ozone background? (0 = constant background 

value; 1 = read from ozone.dat) 0 0 

11 2 BCKO3 Ozone default (ppb) (Use only for missing data) 80 60

11 3 BCKNH3 Ammonia background (ppb) 10 17

11 4 RNITE1 Nighttime SO2 loss rate (%/hr) 0.2 0.2

11 5 RNITE2 Nighttime NOx loss rate (%/hr) 2 2

11 6 RNITE3 Nighttime HNO3 loss rate (%/hr) 2 2

11 7 MH2O2 H2O2 data input option 1 1

11 8 BCKH2O2 Monthly H2O2 concentrations 1 12*1

 BKPMF Fine particulate concentration 12 * 1.00 not used 

 OFRAC Organic fraction of Fine Particulate 

2*0.15, 9*0.20, 

1*0.15 not used 

 VCNX VOC / NOX ratio 12 * 50.00 not used 

12 Dispersion 1 SYTDEP 

Horizontal size (m) to switch to time 

dependence 550 550 

12 2 MHFTSZ Use Heffter for vertical dispersion? (0 = No) 0 0

12 3 JSUP PG Stability class above mixed layer 5 5

12 4 CONK1 Stable dispersion constant (Eq 2.7-3) 0.01 0.01

12 5 CONK2 Neutral dispersion constant (Eq 2.7-4) 0.1 0.1

12 6 TBD Transition for downwash algorithms (0.5 = ISC) 0.5 0.5

12 7 IURB1 Beginning urban landuse type 10 10

12 8 IURB2 Ending urban landuse type 19 19

12 9 ILANDUIN 

Land use type (20 = Unirrigated agricultural 

land) 20 20 

12 10 ZOIN Roughness length (m) 0.25 0.25

12 11 XLAIIN Leaf area index 3.0 3.0

12 12 ELEVIN Met. Station elevation (m above MSL) 0.0 0.0

12 13 XLATIN Met. Station North latitude (degrees) -999.0 -999.0

12 14 XLONIN Met. Station West longitude (degrees) -999.0 -999.0

12 15 ANEMHT 

Anemometer height of ISC meteorological data 

(m) 10.0 10.0 

12 16 ISIGMAV 

Lateral turbulence (Not used with ISC 

meteorology) 1 1 

12 17 IMIXCTDM Mixing heights (Not used with ISC meteorology) 0 0

12 18 XMXLEN Maximum slug length in units of DGRIDKM 1.0 1

12 19 XSAMLEN 

Maximum puff travel distance per sampling 

step (units of DGRIDKM) 1.0 1 

12 20 MXNEW Maximum number of puffs per hour 99 99

12 21 MXSAM Maximum sampling steps per hour 99 99

12 22 NCOUNT 

Iterations when computing Transport Wind 

(Calmet & Profile Winds) 2 2 

12 23 SYMIN Minimum lateral dispersion of new puff (m) 1.0 1

12 24 SZMIN Minimum vertical dispersion of new puff (m) 1.0 1

12 25 SVMIN Array of minimum lateral turbulence (m/s) 6 * 0.50 6 * 0.50 

12 26 SWMIN Array of minimum vertical turbulence (m/s)

0.20,0.12,0.08,

0.06,0.03,0.01

6
FINAL 10/11/06 

28

Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input

Group

Group

Description Sequence Variable Description Default Valuea

Recommended

Value

12 27 CDIV (1), (2) Divergence criterion for dw/dz (1/s) 0.01 (0.0,0.0) 0.0,0.0 

12 28 WSCALM Minimum non-calm wind speed (m/s) 0.5 0.5

12 29 XMAXZI Maximum mixing height (m) 3000 3000

12 30 XMINZI Minimum mixing height (m) 50 50

12 31 WSCAT Upper bounds 1st 5 wind speed classes (m/s) 

1.54,3.09,5.14,

8. 23,10.8 

1.54,3.09,5.14,8.

23,10.8

12 32 PLX0 Wind speed power-law exponents 

0.07,0.07,0.10,

0.15,0.35,0.55

0.07,0.07,0.10,0.

15,0.35,0.55

12 33 PTGO 

Potential temperature gradients PG E and F 

(deg/km) 0.020,0.035 0.020,0.035 

12 34 PPC Plume path coefficients (only if MCTADJ = 3) 

0.5,0.5,0.5,0.5,

0.35,0.35

0.5,0.5,0.5,0.5,0.

35,0.35

12 35 SL2PF Maximum Sy/puff length 10.0 10.0

12 36 NSPLIT Number of puffs when puffs split 3 3

12 37 IRESPLIT Hours when puff are eligible to split User Defined 

12 38 ZISPLIT Previous hour’s mixing height(minimum)(m) 100.0 100.0

12 39 ROLDMAX 

Previous Max mix ht/current mix ht ratio must 

be less then this value for puff to split 0.25 0.25

12 40 NSPLITH Number of puffs when puffs split horizontally 5 5

12 41 SYSPLITH 

Min sigma-y (grid cell units) of puff before horiz 

split 1.0 1.0 

12 12 42 SHSPLITH 

Min puff elongation rate per hr from wind shear 

before horiz split 2.0 2.0 

12 43 CNSPLITH Min conc g/m3 before puff may split horizontally 1.0E-07 1.0E-07 

12 44 EPSSLUG 

Convergence criterion for slug sampling 

integration 1.00E-04 1.00E-04 

12 45 EPSAREA 

Convergence criterion for area source 

integration 1.00E-06 1.00E-06 

12 46 DSRISE Step length for rise integration 1.0 1.0

12 47 HTMINBC 500.0 500.0 

12 48 RSAMPBC 10.0 10.0 

12 49 MDEPBC 1 1 

13 Point Source 1 NPT1 Number of point sources User Defined 

13 2 IPTU Units of emission rates (1 = g/s) 1

13 3 NSPT1 Number of point source-species combinations 0 

13 4 NPT2 

Number of point sources with fully variable 

emission rates 0 

13 

Point

Sources Point sources characteristics User Defined

14 Area Source Area Sources Area sources characteristics User Defined 

15 Volume Source Volume Volume sources characteristics 

User Defined 

Sources 

16 Line Source Line Sources Buoyant lines source characteristics User Defined 

17 Receptors NREC Number of user defined receptors User Defined 

17 

Receptor

Data Location and elevation (MSL) of receptors User Defined 
FINAL 10/11/06 

29

Appendix E 

CALPOST Parameter Values 
FINAL 10/11/06 

30

Appendix E 

CALPOST Parameter Values 

Table F-1. Recommended CALPOST parameter values chosen by the Region 10 states for use in BART modeling

Input

Group Variable Description Default Value 

Recommended

Value

1 ASPEC Species to process VISIB VISIB

1 ILAYER 

Layer/deposition code (1 = CALPUFF concentrations; -3 = wet+dry 

deposition fluxes) 1 1 

1 LBACK Add Hourly Background Concentrations/Fluxes? F F

1 MFRH Particle growth curve for hygroscopic species 2 2

2 RHMAX Maximum relative humidity (%) used in particle growth curve 98 95

2 LDRING 

Report results by Discrete receptor Ring, if Discrete Receptors used.

(T = true) T

 Modeled species to be included in computing the light extinction 

2 LVSO4 Include SO4? T T

2 LVNO3 Include NO3? T T

2 LVOC Include Organic Carbon? T T

2 LVPMC Include Coarse Particles? T T

2 LVPMF Include Fine Particles? T T

2 LVEC Include Elemental Carbon? T T

 

2 LVBK 

when ranking for TOP-N, TOP-50, and Exceedance tables Include 

BACKGROUND? T T 

2 SPECPMC Species name used for particulates in MODEL.DAT file: COARSE = PMC PMC

2 SPECPMF Species name used for particulates in MODEL.DAT file: FINE = PMF PMF

Extinction Efficiencies (1/Mm per ug/m**3) 

2 EEPMC PM COARSE = 0.6 0.6

2 EEPMF PM FINE = 1.0 1.0

2 EEPMCBK Background PM COARSE 0.6 0.6

2 EESO4 SO4 = 3.0 3.0 

2 EENO3 NO3 = 3.0 3.0 

2 EEOC Organic Carbon = 4.0 4.0

2 EESOIL Soil = 1.0 1.0 

2 EEEC Elemental Carbon = 10.0 10.0

 

2 LAVER Method used for 24-hr avg % change light extinction F F 

2 MVISBK 

Method used for background light extinction (2 = Hourly RH 

adjustment; 6 = FLAG seasonal f(RH)) 2 or 6 6 

2 RHFAC 

Monthly RH adjustment factors from FLAG (unique for each Class I 

area) Yes if 6 EPA 

Background monthly extinction coefficients (FLAG) unique for each 

Class I area 

2 BKSO4 

Assume all hygroscopic species as SO4 (raw extinction value without 

scattering efficiency adjustment) see table 

2 BKNO3 see table 

2 BKPMC see table 

2 BKOC see table 

2 BKSOIL Assume all non-hygroscopic species as Soil see table 

2 BKEC see table 

2 BEXTRAY Extinction due to Rayleigh scattering 10.0 10.0

Averaging time(s) reported 

3 L1PD Averaging period of model output F F

3 L1HR 1-hr averages F F

3 L3HR 3-hr averages F F

3 L24HR 24-hr averages T T

3 LRUNL Run lengtyh (annual) F F

3 LT50 Top 50 table for each averaging time selected T F

3 LTOPN 1 

3 NTOP 1 

3 ITOP 
R e p o r t

Protocol for the Application of 

CALPUFF Determination 

Modeling Pursuant to BART 

Regulation—PGE Boardman 

Plant (Revised)

Prepared for 

Portland General Electric 

January 2007 

Prepared by 
Contents

III

Section Page

1 Introduction and Protocol Objectives ............................................................................. 1-1 

1.1 Background ................................................................................................................ 1-1

1.2 Objectives.................................................................................................................... 1-1

2 Modeling Approach............................................................................................................ 2-1

3 Modeling Methodology..................................................................................................... 3-1

3.1 CALMET ..................................................................................................................... 3-1

3.2 CALPUFF.................................................................................................................... 3-2

3.2.1 Species............................................................................................................... 3-3

3.2.2 Background Values ......................................................................................... 3-3

3.2.3 Receptor Locations.......................................................................................... 3-4

3.3 CALPOST and Visibility Post-Processing.............................................................. 3-4

3.4 Visibility Calculation................................................................................................. 3-5

4 Emissions and Stack Data ................................................................................................. 4-1

5 Presentation of Results ...................................................................................................... 5-1

6 References............................................................................................................................. 6-1

Appendixes

A Class I Federal Areas 

B Natural Visibility Background and Monthly Relative Humidity f(RH) 

C CALMET Parameter Values 

D CALPUFF Parameter Values 

E CALPOST Parameter Values 

F Emission Rates and Stack Parameters 

G Memorandum: Boardman Station Post-Control Emissions Limits 

Table

3-1 CALPUFF Modeling System 

Figure

3-1 CALMET Meteorological Domain 
1-1

SECTION 1 

Introduction and Protocol Objectives 

1.1 Background

The U.S. Environmental Protection Agency (EPA) issued the final Guidelines for Best Available 

Retrofit Technology (BART) Determinations (BART Guideline) as required under the Regional 

Haze rule on July 6, 2006. The BART Guideline was designed to help states do the following: 

(1) identify those sources that must comply with the BART requirement and (2) determine 

the level of control technology that represents BART for each source. The Portland General 

Electric (PGE) coal-fired power plant located in Boardman, Oregon (the Boardman plant) is 

a BART-eligible source for which a BART emission limit evaluation is required. The BART 

Guideline requires a modeling analysis for these types of sources. This document presents 

the protocol for the determination modeling analysis. 

1.2 Objectives

The protocol presented here is based on the combined agency protocol developed by the 

Idaho Department of Environmental Quality (IDEQ), the Oregon Department of 

Environmental Quality (ODEQ), and the Washington Department of Ecology (WDOE) 

(ODEQ, 2006). The objectives of this protocol are as follows: 

x Describe determination modeling approach 

x Present determination modeling methodology 

x Define emissions and stack parameters for all control options to be modeled 

x Define presentation of results 
2-1

SECTION 2 

Modeling Approach 

The modeling analysis will be used to evaluate the visibility improvements of various BART 

control options on Class I areas in Oregon and Washington that could be affected by the 

Boardman plant. These areas are presented in Appendix A. Although not a Class I area, the 

Columbia River Gorge Scenic Area will also be evaluated in the BART determination 

modeling, for informational purposes only. 

Both pre-BART control and post-BART control scenarios will be analyzed to compare 

visibility. Maximum 24-hour past actual emissions will be compared with future 24-hour 

maximum emissions and analyzed on a pollutant-by-pollutant basis. Frequency, magnitude, 

and duration of impairment will be evaluated in the determination analysis. 

Sulfur dioxide (SO2), oxides of nitrogen (NOx), and direct particulate matter (PM) emissions, 

including both PM10 and PM2.5, will be included in the determination modeling analysis, as 

required in the BART Guideline. Volatile organic compound (VOC) and ammonia emissions 

will not be included in the analysis. 

Consistent with the intent of the BART Guideline, the natural visibility background is 

defined as the 20 percent best days. The natural background values for Class I areas will be 

consistent with those provided in the combined agency protocol (ODEQ, 2006). Background 

values for both the Class I areas and the Columbia River Gorge Scenic Area are presented in 

Appendix B. 
3-1

SECTION 3 

Modeling Methodology 

As required by the combined agency protocol (ODEQ, 2006) and supported by the Interagency Workgroup on Air Quality Modeling (EPA, 1998) and the Federal Land Managers’ 

Air Quality Related Values Workgroup (FLAG, 2000), the CALPUFF suite of programs will 

be used for the BART determination modeling. The CALPUFF modules and their version 

numbers that will be used in the determination modeling are presented in Table 3-1. Modeling parameters for each module are described in this section and are presented in the 

appendixes.

TABLE 3-1 

CALPUFF Modeling System 

Program Version Level 

CALMET 6.211 060414 

CALPUFF 6.112 060412 

CALPOST 6.131 060410 

POSTUTIL 1.52 060412 

3.1 CALMET

Details of the parameter settings in CALMET are provided in Appendix C; however, the 

major assumptions are summarized below. These data were provided by ODEQ. 

1. The initial-guess fields used the 12-kilometer (km) MM5 outputs, forecast hours 13 – 24 

from every 00Z and 12Z initialization, taken from University of Washington (UW) 

archives, for the 3 years from January 2003 through December 2005. 

2. BART determination modeling will utilize the wind fields at 4-km resolution. 

3. There are 10 vertical layers with face heights of 0, 20, 40, 65, 120, 200, 400, 700, 1200, 2200, 

and 4000 meters. 

4. CALMET was run using NOOBS = 1. Upper air, precipitation, and relative humidity 

data were taken from MM5. 

5. The surface wind observations were ignored by setting the relative weight of surface 

winds to essentially zero (R1 = 1.0E-06). Cloud cover data were the only surface 

observation data that were effectively used in CALMET. 

6. Precipitation data were obtained from MM5, so MM5NPSTA = -1. 

7. No weighting of surface and upper air observations, and BIAS = 0, and ICALM = 0. 

8. The terrain scale factor TERRAD = 12. 
3-2

9. Land use and terrain data were developed using the North American 30-arc-second 

data.

10. The dispersion modeling will use CALMET wind fields for the 3-year period 2003–2005. 

These data were developed for the three states using CALMET Version 6.211 and were 

provided by ODEQ. This domain is shown in Figure 3-1. 

Figure 3-1 CALMET Meteorological Domain. 

3.2 CALPUFF 

Details of the parameter settings in CALPUFF are provided in Appendix D; however, the 

major features are summarized below. 

1. The BART determination modeling will examine the visibility impairment on Class I 

areas within 300 km of the Boardman plant. The computational modeling domain will 

include all Class I areas within a 300-km radius of PGE Boardman. 
MODELING PROTOCOL 

3-3

2. Pasquill-Gifford Dispersion coefficients will be used. 

3. MESOPUFF-II chemistry algorithm will be used. 

4. Building downwash will be ignored. 

5. Puff splitting will not be used, following the recommendations of the Federal Land 

Managers (FLMs). 

6. Source elevations that will be entered in CALPUFF will not use actual elevations but will 

be based on the modeled terrain surface used in CALMET for developing wind fields. 

The same algorithm in CALMET that determines the elevations of the observational 

stations will be used to make this calculation. The modified source elevation was set at 

225 meters, as determined by CH2M HILL. 

3.2.1 Species

Primary emission species analyzed will include the input species PM, SO2, sulfates (SO4),

and NOx; and the additional modeled species nitric acid (HNO3) and nitrates (NO3). Sulfur 

dioxide emissions will be reviewed to ensure that “double-counting” is avoided. 

Both filterable and condensable fractions of PM will be included in the analysis. The 

condensable fraction will be treated as primary emissions in the CALPUFF input file and 

assumed to be 100 percent in the PM2.5 fraction. The primary PM species will be treated as 

follows:

Filterable:

 Elemental Carbon (EC) (< 2.5 microns [μm]) 

 PM Fine (PMF) (< 2.5 μm) 

 PM Coarse (PMC) (2.5 – 10 μm) 

Condensable: 

 Organic Carbon (OC) (secondary organic aerosol [SOA]) 

 Inorganic Aerosol (SO4)

 Non-SO4 inorganic aerosol 

The primary emission species sizing are presented as follows: 

Pollutant Mean Diameter Standard Deviation 

SO4, NO3, PMF, SOA, EC 0.50 microns 1.5

PMC 5.00 microns 1.5

3.2.2 Background Values 

A single ozone background value of 60 parts per billion (ppb) will be used for all months for 

all Class I areas. 

As with the ozone background, a single value of 17 ppb will be used for the ammonia 

background. This value is supported by measurements made in 1996–1997 at Abbotsford in 

the Fraser River Valley of British Columbia. 
3-4

3.2.3 Receptor Locations 

Visibility impacts will be computed at all Class I areas and the Columbia River Gorge Scenic 

Area if they lie within a 300-km radius of the Boardman plant. The geolocations of the 

receptor points and their elevations for the Class I areas that will be used in the modeling 

are consistent with the ODEQ exemption modeling and were downloaded from the 

National Park Service Web site at 

http://www2.nature.nps.gov/air/Maps/Receptors/index.cfm>.

Receptor points and elevations for the Columbia River Gorge Scenic Area were provided by 

ODEQ.

3.3 CALPOST and Visibility Post-Processing 

Details of the parameter setting in CALPOST are provided in Appendix E. The following 

assumptions will be used in CALPOST and POSTUTIL to calculate the visibility 

impairment:

1. For the visibility calculation, Method 6 will be employed. This method uses monthly 

average relative humidity and f(RH) values for each Class I area as provided in 

Appendix B, which are based on the EPA Guidance for Regional Haze analysis (EPA, 

2003).

2. Particulate species for the visibility analysis will include SO4, NO3, EC, OC, PMF, and 

PMC, as reported in the CALPOST output files. 

3. POSTUTIL will not be used to speciate modeled PM10 concentrations, as PM10 will be 

speciated into its components (PMF, PMC, SOA, EC, SO4) and entered as primary 

emissions in CALPUFF. In addition, HNO3/NO3 partition option in POSTUTIL will not 

be used for ammonia limiting. 

4. Natural background extinction calculations will use the 20 percent best days for each 

Class I area. The natural background for the 20 percent best days has been refined from 

that which is in “Guidance for Estimating Natural Visibility Conditions Under the Regional 

Haze Rule” (EPA, 2003). The extinction coefficients for the 20 percent best days have been 

calculated following the approach taken in the Draft Montana BART modeling protocol. 

This procedure uses the haze index (HI) in deciviews at the 10th percentile (median of 

the 20 percent best days) and an activity factor that is calculated for each Class I area. 

Table B-1, providing the monthly f(RH) and 20 percent best days coefficients, is 

provided in Appendix B and is based on data from EPA (2003). For the exemption 

modeling, the Rayleigh scattering value will be 10 Mm-1 for all Class I areas. 

The 98th percentile value will be calculated for all BART-eligible sources at each 

mandatory Class I area. 

5. The CALPOST “LST” output files will be used to determine the 98th percentile of 

visibility impairment for each receptor in CLASS I areas. 
MODELING PROTOCOL 

3-5

6. The contribution threshold has the implied level of precision equal to the level of 

precision reported by CALPOST. Therefore, the 98th percentile value will be reported to 

three decimal places. 

3.4 Visibility Calculation 

The CALPUFF modeling techniques presented in this section will provide ground-level 

concentrations of visibility-impairing pollutants. The concentration estimates from 

CALPUFF are used with the current FLAG equation to calculate the extinction coefficient, as 

shown below: 

bext= 3 f(RH) [(NH4)2SO4] + 3 f(RH) [NH4NO3] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + bRay

As described in the IWAQM Phase 2 Report (EPA, 1998), the change in visibility for the 

BART exemption analysis is compared against background conditions. The delta-deciview, 

'dv, value is calculated from the source’s contribution to extinction, bext (source), and 

background extinction, bext(bkg), as follows: 

'dv = 10 ln [ ( bext(bkg) + bext (source) ) / ( bext(bkg) ) ] 
4-1

SECTION 4 

Emissions and Stack Data 

Emissions to be modeled for determination modeling will not include startup, shutdown, or 

malfunction emissions. The emissions and stack data used for the determination modeling 

are summarized in Appendix F. Emissions were derived by Black & Veatch for PGE as 

summarized in a memorandum presented in Appendix G. 

The control scenarios being modeled for the determination modeling are listed below: 

1. NOx Controlled Outlet Conditions 

a. Selective Catalytic Reduction 

b. New Low-NOx Burners with Modified Over-Fire Air (OFA) System 

2. SO2 Controlled Outlet Conditions 

a. Wet Flue Gas Desulfurization 

b. Semi-Dry Flue Gas Desulfurization 

Existing emissions of PM are already controlled by an electrostatic precipitator. As a result, 

emissions of SO2 and NOx are each more than 10 times the emissions of particulate. The 

exemption modeling conducted by ODEQ shows the contribution of PM to the highest 

visibility impairment days to be less than 2 percent. Consequently, PM controls will not be 

included in the determination analysis. 

Consistent with the BART guidelines, the required maximum 24-hour emission rates used in 

the modeling will be based on a 30-day rolling average permit limit. Each of the above 

control options will be analyzed for each pollutant to determine the most effective control 

by pollutant. Following that analysis, the model will be run combining the most effective 

controls by pollutants to determine the maximum improvement in visibility.
5-1

SECTION 5 

Presentation of Results 

The improvement in visibility for BART determination is based on the change in HI from 

pre-BART control to post-BART control for PGE relative to natural background for each 

Class I area. Comparison tables for pre-BART control and post-BART control visibility 

impacts will be documented for use in the BART control evaluation. Frequency, magnitude, 

and duration of any visibility impairment will be included in the documentation. 
6-1

SECTION 6 

References

Federal Land Managers’ Air Quality Related Values Workgroup (FLAG). 2000. Phase I 

Report. December 2000. 

Oregon Department of Environmental Quality (ODEQ). 2006. Modeling Protocol for 

Washington, Oregon, and Idaho: Protocol for the Application of the CALPUFF Modeling 

System Pursuant to the Best Available Retrofit Technology (BART) Regulation. October 11, 

2006. 

U.S. Environmental Protection Agency (EPA). 1998. Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long 

Range Transport Impacts. EPA-454/R-98-019. December 1998. 

U.S. Environmental Protection Agency (EPA). 2003. Guidance for Estimating Natural Visibility 

Conditions under the Regional Haze Rule. EPA-454/B-03-005. September 2003. 

U.S. Environmental Protection Agency (EPA). 2005. Regional Haze Regulations and Guidelines 

for Best Available Retrofit Technology (BART) Determinations. Federal Register, Vol. 70, 

No. 128. Pp. 39104–30172. July 6, 2005. 
APPENDIX A

Class I Federal Areas 
Table A-1. Federal Mandatory Class I Areas Evaluated in PGE Boardman Analysis. 

Class I Area Federal Land Manager 

Oregon

Diamond Peak Wilderness Forest Service 

Eagle Cap Wilderness Forest Service 

Hells Canyon Wilderness Forest Service 

Three Sisters Wilderness Forest Service 

Mount Hood Wilderness Forest Service 

Mount Jefferson Wilderness Forest Service 

Mount Washington Wilderness Forest Service 

Strawberry Mountain Wilderness Forest Service 

Washington

Alpine Lakes Wilderness Forest Service 

Goat Rocks Wilderness Forest Service 

Glacier Peak Wilderness Forest Service 

Mount Adams Wilderness Forest Service 

Mount Rainier National Park Park Service 

North Cascades National Park Park Service 
APPENDIX B

Natural Visibility Background and 

Monthly Relative Humidity f(RH) 
Table B-1 Adjustment to speciated particulate (Western States) to reflect 

20% Best Visibility Days conditions 

 Monthly f(RH) are from Appendix A of Draft Guidance for Estimating Natural Visibility 

Conditions under the RHR (Sept. 2003). 

 Background extinction coefficients (20% Best Days) have been calculated using Annual 

Avg bext, Best 20% bext, and activity factors. 

 

 CALPOST Input Group 2 CALPOST Input Group 2 

Monthly extinction coefficients for hygroscopic species (RHFAC) Background extinction coefficients (20% Best Days) 

Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec. BKSO4 BKNO3 BKPMC BKOC SOIL BKEC 

Class I Area State f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) f(RH) ug/m3 ug/m3 ug/m3 ug/m3 ug/m3 ug/m3 

Hells Canyon ID 3.70 3.12 2.51 2.17 2.12 2.00 1.63 1.58 1.79 2.41 3.45 3.87 0.048 0.040 1.21 0.190 0.202 0.008 

Diamond Peak OR 4.52 3.96 3.64 3.66 3.16 3.12 2.90 2.93 3.05 3.67 4.55 4.57 0.053 0.044 1.33 0.208 0.222 0.009 

Eagle Cap OR 3.77 3.16 2.47 2.10 2.04 1.87 1.61 1.56 1.61 2.25 3.44 3.97 0.049 0.041 1.22 0.191 0.203 0.008 

Mount Hood OR 4.29 3.81 3.46 3.87 2.95 3.15 2.85 3.00 3.10 3.86 4.53 4.55 0.053 0.044 1.33 0.209 0.222 0.009 

Mount Jefferson OR 4.41 3.90 3.56 3.74 3.07 3.11 2.89 2.91 3.03 3.78 4.55 4.54 0.054 0.045 1.34 0.210 0.223 0.009 

Mount Washington OR 4.44 3.93 3.58 3.73 3.09 3.11 2.98 2.91 3.02 3.76 4.56 4.56 0.054 0.045 1.36 0.213 0.227 0.009 

Strawberry Mountain OR 3.89 3.33 2.75 2.93 2.27 2.39 1.98 1.97 1.87 2.63 3.69 4.07 0.050 0.042 1.26 0.197 0.210 0.008 

Three Sisters OR 4.47 3.95 3.61 3.72 3.11 3.11 3.00 2.91 3.03 3.79 4.60 4.57 0.054 0.045 1.35 0.212 0.226 0.009 

Alpine Lakes WA 4.25 3.79 3.47 3.90 2.93 3.22 2.92 3.12 3.25 3.91 4.47 4.51 0.054 0.045 1.35 0.212 0.225 0.009 

Glacier Peak WA 4.16 3.72 3.42 3.75 2.91 3.16 2.88 3.14 3.33 3.90 4.42 4.43 0.054 0.045 1.34 0.210 0.223 0.009 

Goat Rocks WA 4.25 3.75 3.36 4.24 2.83 3.38 3.03 3.19 3.07 3.77 4.42 4.55 0.054 0.045 1.34 0.210 0.224 0.009 

Mount Adams WA 4.29 3.80 3.44 4.40 2.92 3.49 3.12 3.27 3.13 3.86 4.49 4.56 0.053 0.044 1.33 0.209 0.222 0.009 

Mount Rainier WA 4.42 3.96 3.64 4.65 3.06 3.69 3.30 3.50 3.40 4.11 4.66 4.66 0.055 0.045 1.36 0.214 0.227 0.009 

North Cascades NP WA 4.10 3.69 3.43 3.74 2.93 3.20 2.93 3.23 3.45 3.93 4.39 4.38 0.053 0.044 1.33 0.209 0.222 0.009 

Columbia River 

Gorge

ORWA 5.03 5.03 2.59 2.59 2.59 2.11 2.11 2.11 3.51 3.51 3.51 5.03 0.569 0.231 4.85 1.05 0.217 0.205 
APPENDIX C

CALMET Parameter Values 
Appendix C 

CALMET Parameter Values 

 Table C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value 

Recommended 

Value

0 DIADAT Input file: preprocessed surface temperature data (DIAG.DAT) User Defined 

0 GEODAT Input file: Geophysical data (GEO.DAT) User Defined User Define 

0 LCFILES Convert file name to lower case User Defined 

0 METDAT Output file (CALMET.DAT) User Defined 

0 METLST Output file (CALMET.LST) User Defined 

0 MM4DAT Input file: MM4 data (MM4.DAT) User Defined 

0 NOWSTA Input files: Names of NOWSTA overwater stations User Defined 0

0 NUSTA Number of upper air data sites User Defined 0

0 PACDAT Output file: in Mesopuff II format (PACOUT.DAT) User Defined 

0 PRCDAT Input file: Precipitation data (PRECIP.DAT) User Defined 

0 PRGDAT Input file: CSUMM prognostic wind data (PROG.DAT) User Defined 

0 SEADAT Input files: Names of NOWSTA overwater stations (SEAn.DAT) User Defined 

0 SRFDAT Input file: Surface data (SURF.DAT) User Defined 

0 TSTFRD Output file (TEST.FRD) User Defined 

0 TSTKIN Output file (TEST.KIN) User Defined 

0 TSTOUT Output file (TEST.OUT) User Defined 

0 TSTPRT Output file (TEST.PRT) User Defined 

0 TSTSLP Output file (TEST.SLP) User Defined 

0 UPDAT Input files: Names of NUSTA upper air data files (UPn.DAT) UPn.DAT 

0 WTDAT Input file: Terrain weighting factors (WT.DAT) User Defined 

1 CLDDAT Input file: Cloud data (CLOUD.DAT) User Defined Not used 

1 IBDY Beginning day User Defined 

1 IBHR Beginning hour User Defined 

1 IBMO Beginning month User Defined 

1 IBTZ Base time zone User Defined 8

1 IBYR Beginning year User Defined 

1 IRLG Number of hours to simulate User Defined User Define 

1 IRTYPE Output file type to create (must be 1 for CALPUFF) 1 1

1 ITEST Flag to stop run after Setup Phase 2 2

1 LCALGRD Are w-components and temperature needed? T T

2 DATUM WGS-G, NWS-27, NWS-84, ESR-S,... NWS84 

2 DGRIDKM Grid spacing User Defined 4

2 IUTMZN UTM Zone User Defined User Define 

2 LLCONF 

 When using Lambert Conformal map coordinates - rotate winds 

from true north to map north? F F 

2 NX Number of east-west grid cells User Defined 373

2 NY Number of north-south grid cells User Defined 316

2 NZ Number of vertical layers User Defined 10

2 RLAT0 Latitude used if LLCONF = T User Defined 49.0N 

2 RLON0 Longitude used if LLCONF = T User Defined 121.0W 

2 XLAT0 Southwest grid cell latitude User Defined User Define 

2 XLAT1 Latitude of 1st standard parallel User Defined 30

2 XLAT2 Latitude of 2nd standard parallel User Defined 60

2 XORIGKM Southwest grid cell X coordinate User Defined -572 

2 YLON0 Southwest grid cell longitude User Defined -956

2 YORIGKM Southwest grid cell Y coordinate User Defined User Define 

2 ZFACE Vertical cell face heights (NZ+1 values) User Defined 

0,20,40,65,120,200,

400,

700,1200,2200,4000

3 IFORMO Format of unformatted file (1 for CALPUFF) 1 1

3 LSAVE Save met. data fields in an unformatted file? T T
 Table C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value 

Recommended 

Value

4 ICLOUD Is cloud data to be input as gridded fields? (0 = No) 0 0 

4 IFORMC Format of cloud data (2 = formatted) 2 2

4 IFORMP Format of precipitation data (2 = formatted) 2 2

4 IFORMS Format of surface data (2 = formatted) 2 2

4 NOOBS Use or non-use of surface, overwater, upper observations 1 

4 NPSTA Number of stations in PRECIP.DAT User Defined -1

4 NSSTA Number of stations in SURF.DAT file User Defined 115

5 ALPHA Empirical factor triggering kinematic effects 0.1 0.1

5 BIAS Surface/upper-air weighting factors (NZ values) NZ*0 NZ*0

5 CRITFN Critical Froude number 1 1

5 DIVLIM Maximum acceptable divergence 5.00E-06 5.00E-06 

5 FEXTR2 Multiplicative scaling factor for extrap surface obs to uppr layrs NZ*0.0 

5 ICALM Extrapolate surface calms to upper layers? (0 = No) 0 0

5 IDIOPT1 Compute temperatures from observations (0 = True) 0 0

5 IDIOPT2 Compute domain-average lapse rates? (0 = True) 0 0

5 IDIOPT3 Compute internally initial guess winds? (0 = True) 0 0

5 IDIOPT4 Read surface winds from SURF.DAT? ( 0 = True) 0 0

5 IDIOPT5 Read aloft winds from UPn.DAT? (0 = True) 0 0

5 IEXTRP 

 Extrapolate surface winds to upper layers? (-4 = use similarity 

theory and ignore layer 1 of upper air station data) -4 -1 

5 IFRADJ Adjust winds using Froude number effects? (1 = Yes) 1 1

5 IKINE Adjust winds using kinematic effects? (1 = Yes) 0 0

5 IOBR Use O’Brien procedure for vertical winds? (0 = No) 0 0

5 IPROG Using prognostic or MM-FDDA data? (0 = No) 0 14 

5 ISLOPE Compute slope flows? (1 = Yes) 1 1

5 ISTEPPG Timestep (hours) of the prognostic model input data 1 1

5 ISURFT 

 Surface station to use for surface temperature (between 1 and 

NSSTA) User Defined 98 

5 IUPT Station for lapse rates (between 1 and NUSTA) User Defined 1

5 IUPWND 

 Upper air station for domain winds (-1 = 1/r**2 interpolation of all 

stations) -1 -1 

5 IWFCOD Generate winds by diagnostic wind module? (1 = Yes) 1 1

5 KBAR Level (1 to NZ) up to which barriers apply NZ 10

5 LLBREZE Use Lake Breeze module F F

5 LVARY Use varying radius to develop surface winds? F F 

5 METBXID Station IDs in the region User Defined 

5 NBAR Number of Barriers to interpolation User Defined 0

5 NBOX Number of Lake Breeze regions User Defined 0 

5 NINTR2 Max number of stations for interpolations (NA values) 99 99 

5 NITER Max number of passes in divergence minimization 50 50

5 NLB Number of stations in region User Defined 0

5 NSMTH Number of passes in smoothing (NZ values) 2, 4*(NZ-1) 1,2,2,3,3,4,4,4,4,4 

5 R1 Relative weight at surface of Step 1 field and obs User Defined 1.00E-06 

5 R2 Relative weight aloft of Step 1 field and obs User Defined 1.00E-06 

5 RMAX1 Max surface over-land extrapolation radius (km) User Defined 200 

5 RMAX2 Max aloft over-land extrapolation radius (km) User Defined 200 

5 RMAX3 Maximum over-water extrapolation radius (km) User Defined 200

5 RMIN Minimum extrapolation radius (km) 0.1 0.1

5 RMIN2 

 Distance (km) around an upper air site where vertical 

extrapolation is excluded (Set to -1 if IEXTRP = ±4) 4 -1 

5 RPROG Weighting factor for CSUMM prognostic wind data User Defined 0 

5 TERRAD Radius of influence of terrain features (km) User Defined 12

5 XBBAR X coordinate of Beginning of each barrier User Defined 0 
 Table C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling 

Input 

Group Variable Description Default Value 

Recommended 

Value

5 XBCST X Point defining the coastline (straight line) User Defined 0 

5 XEBAR X coordinate of Ending of each barrier User Defined 0 

5 XECST X Point User Defined 0

5 XG1 X Grid line 1 defining region of interest User Defined 0

5 XG2 X Grid line 2 User Defined 0

5 YBBAR Y coordinate of Beginning of each barrier User Defined 0 

5 YBCST Y Point User Defined 0

5 YEBAR Y coordinate of Ending of each barrier User Defined 0 

5 YECST Y Point User Defined 0

5 YG1 Y Grid line 1 User Defined 0

5 YG2 Y Grid Line 2 User Defined 0

5 ZUPT Depth of domain-average lapse rate (m) 200 200

5 ZUPWND Bottom and top of layer for 1st guess winds (m) 1, 1000 1.,1000.

6 CONSTB Neutral mixing height B constant 1.41 1.41

6 CONSTE Convective mixing height E constant 0.15 0.15 

6 CONSTN Stable mixing height N constant 2400 2400

6 CONSTW Over-water mixing height W constant 0.16 0.16

6 CUTP Minimum cut off precip rate (mm/hr) 0.01 0.01

6 DPTMIN Minimum capping potential temperature lapse rate 0.001 0.001

6 DSHELF Coastal/shallow water length scale 0 0

6 DZZI Depth for computing capping lapse rate (m) 200 200

6 FCORIOL Absolute value of Coriolis parameter 1.00E-04 1.00E-04 

6 HAFANG Half-angle for looking upwind (degrees) 30 30

6 IAVET Conduct spatial averaging of temperature? (1 = True) 1 1

6 IAVEZI Spatial averaging of mixing heights? (1 = True) 1 1

6 ICOARE Overwater surface fluxes method and parameters 10 10

6 ICOOL COARE cool skin layer computation 0 0

6 ILEVZI Layer to use in upwind averaging (between 1 and NZ) 1 1

6 ILUOC3D Land use category ocean in 3D.DAT datasets 16 16

6 IMIXH Method to compute the convective mixing height 1 1 

6 IRAD Form of temperature interpolation (1 = 1/r) 1 1

6 IRHPROG 3D relative humidity from observations or from prognostic data 0 1 

6 ITPROG 3D temps from obs or from prognostic data? 0 2

6 ITWPROG 

Option for overwater lapse rates used in convective mixing 

height growth 0 2 

6 IWARM COARE warm layer computation 0 0

6 JWAT1 Beginning landuse type defining water 999 55

6 JWAT2 Ending landuse type defining water 999 55

6 MNMDAV Max averaging radius (number of grid cells) 1 1

6 NFLAGP Method for precipitation interpolation (2 = 1/r**2) 2 2

6 NUMTS Max number of stations in temperature interpolations 5 10

6 SIGMAP Precip radius for interpolations (km) 100 12

6 TGDEFA Default over-water capping lapse rate (K/m) -0.0045 -0.0045

6 TGDEFB Default over-water mixed layer lapse rate (K/m) -0.0098 -0.0098

6 THRESHL 

Threshold buoyancy flux required to sustain convective mixing 

height growth overland 0.05 0.05 

6 THRESHW 

Threshold buoyancy flux required to sustain convective mixing 

height growth overwater 0.05 0.05 

6 TRADKM Radius of temperature interpolation (km) 500 500

6 ZIMAX Maximum over-land mixing height (m) 3000 3000

6 ZIMAXW Maximum over-water mixing height (m) 3000 3000 

6 ZIMIN Minimum over-land mixing height (m) 50 50 

6 ZIMINW Minimum over-water mixing height (m) 50 50 
APPENDIX D

CALPUFF Parameter Values 
Appendix D

CALPUFF Parameter Values 

Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea

Recommended 

Value

1 Run Control 1 METRUN Do we run all periods (1) or a subset (0)? 0

1 2 IBYR Beginning year User Defined 

1 3 IBMO Beginning month User Defined 

1 4 IBDY Beginning day User Defined 

1 5 IBHR Beginning hour User Defined 

1 5 IRLG Length of run (hours) User Defined 

1 5 NSECDT Length of modeling time step (seconds) 3600 3600

1 6 NSPEC 

Number of species modeled (for MESOPUFF II 

chemistry) 5 

1 7 NSE Number of species emitted 3

1 8 ITEST Flag to stop run after Setup Phase 2

1 9 MRESTART 

Restart options (0 = no restart) allows splitting 

runs into smaller segments 0

1 10 NRESPD Number of periods in Restart 0

1 11 METFM 

Format of input meteorology (1 = CALMET, 2 = 

ISC) 1

1 12 AVET 

Averaging time lateral dispersion parameters 

(minutes) 60 60 

1 13 PGTIME PG Averaging time 60 60

2 Tech Options 1 MGAUSS Near-field vertical distribution (1 = Gaussian) 1 1

2 2 MCTADJ 

Terrain adjustments to plume path (3 = Plume 

path) 3 3 

2 3 MCTSG 

Do we have subgrid hills? (0 = No) allows 

CTDM-like treatment for subgrid scale hills 0 0

2 4 MSLUG Near-field puff treatment (0 = No slugs) 0 0

2 5 MTRANS Model transitional plume rise? (1 = Yes) 1 1

2 6 MTIP Treat stack tip downwash? (1 = Yes) 1 1

2 7 MBDW 

Method to simulate downwash 

(1=ISC,2=PRIME) not used 

2 8 MSHEAR Treat vertical wind shear? (0 = No) 0 0

2 9 MSPLIT Allow puffs to split? (0 = No) 0 0

2 10 MCHEM MESOPUFF-II Chemistry? (1 = Yes) 1 1

2 11 MAQCHEM Aqueous phase transformation 0 0

2 12 MWET Model wet deposition? (1 = Yes) 1 1

2 13 MDRY Model dry deposition? (1 = Yes) 1 1

2 13 MTILT Plume Tilt (gravitational settling) 0 0

2 14 MDISP 

Method for dispersion coefficients 

(2=micromet,3 = PG) 3 3 

2 15 MTURBVW 

Turbulence characterization? (Only if MDISP = 

1 or 5) 3 3 

2 16 MDISP2 Backup coefficients (Only if MDISP = 1 or 5) 3 3

2 16 MTAULY Method for Sigma y Lagrangian timescale 0 0

2 16 MTAUADV 

Method for Advective-Decay timescale for 

Turbulence 0 0 

2 16 MCTURB 

Method to compute sigma v,w using micromet 

variables 1 1 

2 17 MROUGH Adjust PG for surface roughness? (0 = No) 0 0

2 18 MPARTL Model partial plume penetration? (0 = No) 1 1

2 19 MTINV 

Elevated inversion strength (0 = compute from 

data) 0 0 

2 20 MPDF Use PDF for convective dispersion? (0 = No) 0 0

2 21 MSGTIBL 

Use TIBL module? (0 = No) allows treatment of 

subgrid scale coastal areas 0 0 

2 22 MBCON Boundary conditions modeled 0 0

2 23 MFOG Configure for FOG model output 0 0

2 24 MREG Regulatory default checks? (1 = Yes) 1 1
Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea

Recommended 

Value

3 Species List 1 CSPECn 

Names of species modeled (for MESOPUFF II 

must be SO2-SO4-NOX-HNO3-NO3) User Defined 

3 2 

Specie

Names Manner species will be modeled User Defined 

3 3 

Specie

Groups Grouping of species if any User Defined 

3 4 CGRUP 

3 5 CGRUP 

4 MapProjection XLAT1 Latitude of 1st standard parallel 

4 XLAT2 Latitude of 2nd standard parallel 

4 DATUM NWS84 

4 1 NX Number of east-west grids of input meteorology User Defined 373 

4 2 NY 

Number of north-south grids of input 

meteorology User Defined 316 

4 3 NZ Number of vertical layers of input meteorology User Defined 10 

4 4 DGRIDKM Meteorology grid spacing (km) User Defined 4

4 5 ZFACE Vertical cell face heights of input meteorology User Defined 

0,20,40,65,120,2

00,400,700,1200

,2200,4000

4 6 XORIGKM Southwest corner (east-west) of input User 

Defined

meteorology -572 

4 7 YORIGIM Southwest corner (north-south) of input User 

Defined

meteorology -956

4 8 IUTMZN UTM zone User Defined 

4 9 XLAT Latitude of center of meteorology domain User Defined 

4 10 XLONG Longitude of center of meteorology domain User Defined 

4 11 XTZ Base time zone of input meteorology User Defined 

4 12 IBCOMP Southwest X-index of computational domain User Defined 105 

4 13 JBCOMP Southwest Y-index of computational domain User Defined 79 

4 14 IECOMP Northeast X-index of computational domain User Defined 242 

4 15 JECOMP Northeast Y-index of computational domain User Defined 252 

4 16 LSAMP Use gridded receptors? (T = Yes) F F

4 17 IBSAMP Southwest X-index of receptor grid User Defined 

4 18 JBSAMP Southwest Y-index of receptor grid User Defined 

4 19 IESAMP Northeast X-index of receptor grid User Defined 

4 20 JESAMP Northeast Y-index of receptor grid User Defined 

4 21 MESHDN 

Gridded recpetor spacing = 

DGRIDKM/MESHDN 1

5 Output Options 1 ICON Output concentrations? (1 = Yes) 1 1

5 2 IDRY Output dry deposition flux? (1 = Yes) 1 1

5 3 IWET Output west deposition flux? (1 = Yes) 1 1

5 4 IT2D 2D Temperature 0 0 

5 5 IRHO 2D Density 0 0 

5 6 IVIS Output RH for visibility calculations (1 = Yes) 1 1

5 7 LCOMPRS Use compression option in output? (T = Yes) T T

5 8 ICPRT Print concentrations? (0 = No) 0 0

5 9 IDPRT Print dry deposition fluxes (0 = No) 0 0

5 10 IWPRT Print wet deposition fluxes (0 = No) 0 0

5 11 ICFRQ Concentration print interval (1 = hourly) 1 24

5 12 IDFRQ Dry deposition flux print interval (1 = hourly) 1 24

5 13 IWFRQ West deposition flux print interval (1 = hourly) 1 24

5 14 IPRTU 

Print output units (1 = g/m**3; g/m**2/s; 3 = 

ug/m3, ug/m2/s) 1 3 

5 15 IMESG Status messages to screen? (1 = Yes) 1 2

5 16 LDEBUG Turn on debug tracking? (F = No) F F
Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea

Recommended 

Value

5 16 IPFDEB First puff to track 1 1

5 17 NPFDEB (Number of puffs to track) (1) 1

5 18 NN1 (Met. Period to start output) (1) 1

5 19 NN2 (Met. Period to end output) (10) 10

7 Dry Dep Chem Dry Gas Dep 

Chemical parameters of gaseous deposition 

species User Defined defaults 

8 Dry Dep Size Dry Part. Dep 

Chemical parameters of particulate deposition 

species User Defined defaults 

9 Dry Dep Misc 1 RCUTR Reference cuticle resistance (s/cm) 30 30 

9 2 RGR Reference ground resistance (s/cm) 10 10

9 3 REACTR Reference reactivity 8 8 

9 4 NINT Number of particle-size intervals 9 9

9 5 IVEG 

Vegetative state (1 = active and unstressed; 

2=active and stressed) 1 1 

10 Wet Dep Wet Dep Wet deposition parameters User Defined defaults 

11 Chemistry 1 MOZ 

Ozone background? (0 = constant background 

value; 1 = read from ozone.dat) 0 0 

11 2 BCKO3 Ozone default (ppb) (Use only for missing data) 80 60

11 3 BCKNH3 Ammonia background (ppb) 10 17

11 4 RNITE1 Nighttime SO2 loss rate (%/hr) 0.2 0.2

11 5 RNITE2 Nighttime NOx loss rate (%/hr) 2 2

11 6 RNITE3 Nighttime HNO3 loss rate (%/hr) 2 2

11 7 MH2O2 H2O2 data input option 1 1

11 8 BCKH2O2 Monthly H2O2 concentrations 1 12*1

 BKPMF Fine particulate concentration 12 * 1.00 not used 

 OFRAC Organic fraction of Fine Particulate 

2*0.15, 9*0.20, 

1*0.15 not used 

 VCNX VOC / NOX ratio 12 * 50.00 not used 

12 Dispersion 1 SYTDEP 

Horizontal size (m) to switch to time 

dependence 550 550 

12 2 MHFTSZ Use Heffter for vertical dispersion? (0 = No) 0 0

12 3 JSUP PG Stability class above mixed layer 5 5

12 4 CONK1 Stable dispersion constant (Eq 2.7-3) 0.01 0.01

12 5 CONK2 Neutral dispersion constant (Eq 2.7-4) 0.1 0.1

12 6 TBD Transition for downwash algorithms (0.5 = ISC) 0.5 0.5

12 7 IURB1 Beginning urban landuse type 10 10

12 8 IURB2 Ending urban landuse type 19 19

12 9 ILANDUIN 

Land use type (20 = Unirrigated agricultural 

land) 20 20 

12 10 ZOIN Roughness length (m) 0.25 0.25

12 11 XLAIIN Leaf area index 3.0 3.0

12 12 ELEVIN Met. Station elevation (m above MSL) 0.0 0.0

12 13 XLATIN Met. Station North latitude (degrees) -999.0 -999.0

12 14 XLONIN Met. Station West longitude (degrees) -999.0 -999.0

12 15 ANEMHT 

Anemometer height of ISC meteorological data 

(m) 10.0 10.0 

12 16 ISIGMAV 

Lateral turbulence (Not used with ISC 

meteorology) 1 1 

12 17 IMIXCTDM Mixing heights (Not used with ISC meteorology) 0 0

12 18 XMXLEN Maximum slug length in units of DGRIDKM 1.0 1

12 19 XSAMLEN 

Maximum puff travel distance per sampling 

step (units of DGRIDKM) 1.0 1 

12 20 MXNEW Maximum number of puffs per hour 99 99

12 21 MXSAM Maximum sampling steps per hour 99 99

12 22 NCOUNT 

Iterations when computing Transport Wind 

(Calmet & Profile Winds) 2 2 

12 23 SYMIN Minimum lateral dispersion of new puff (m) 1.0 1

12 24 SZMIN Minimum vertical dispersion of new puff (m) 1.0 1

12 25 SVMIN Array of minimum lateral turbulence (m/s) 6 * 0.50 6 * 0.50 
Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. 

Input 

Group 

Group 

Description Sequence Variable Description Default Valuea

Recommended 

Value

12 26 SWMIN Array of minimum vertical turbulence (m/s)

0.20,0.12,0.08,

0.06,0.03,0.01

6

12 27 CDIV (1), (2) Divergence criterion for dw/dz (1/s) 0.01 (0.0,0.0) 0.0,0.0 

12 28 WSCALM Minimum non-calm wind speed (m/s) 0.5 0.5

12 29 XMAXZI Maximum mixing height (m) 3000 3000

12 30 XMINZI Minimum mixing height (m) 50 50

12 31 WSCAT Upper bounds 1st 5 wind speed classes (m/s) 

1.54,3.09,5.14,

8. 23,10.8 

1.54,3.09,5.14,8. 

23,10.8

12 32 PLX0 Wind speed power-law exponents 

0.07,0.07,0.10,

0.15,0.35,0.55 

0.07,0.07,0.10,0.

15,0.35,0.55

12 33 PTGO 

Potential temperature gradients PG E and F 

(deg/km) 0.020,0.035 0.020,0.035 

12 34 PPC Plume path coefficients (only if MCTADJ = 3) 

0.5,0.5,0.5,0.5,

0.35,0.35

0.5,0.5,0.5,0.5,0.

35,0.35

12 35 SL2PF Maximum Sy/puff length 10.0 10.0

12 36 NSPLIT Number of puffs when puffs split 3 3

12 37 IRESPLIT Hours when puff are eligible to split User Defined 

12 38 ZISPLIT Previous hour’s mixing height(minimum)(m) 100.0 100.0

12 39 ROLDMAX 

Previous Max mix ht/current mix ht ratio must 

be less then this value for puff to split 0.25 0.25

12 40 NSPLITH Number of puffs when puffs split horizontally 5 5

12 41 SYSPLITH 

Min sigma-y (grid cell units) of puff before horiz 

split 1.0 1.0 

12 12 42 SHSPLITH 

Min puff elongation rate per hr from wind shear 

before horiz split 2.0 2.0 

12 43 CNSPLITH Min conc g/m3 before puff may split horizontally 1.0E-07 1.0E-07 

12 44 EPSSLUG 

Convergence criterion for slug sampling 

integration 1.00E-04 1.00E-04 

12 45 EPSAREA 

Convergence criterion for area source 

integration 1.00E-06 1.00E-06 

12 46 DSRISE Step length for rise integration 1.0 1.0

12 47 HTMINBC 500.0 500.0 

12 48 RSAMPBC 10.0 10.0 

12 49 MDEPBC 1 1 

13 Point Source 1 NPT1 Number of point sources User Defined 

13 2 IPTU Units of emission rates (1 = g/s) 1

13 3 NSPT1 Number of point source-species combinations 0 

13 4 NPT2 

Number of point sources with fully variable 

emission rates 0

13 

Point

Sources Point sources characteristics User Defined

14 Area Source Area Sources Area sources characteristics User Defined 

15 Volume Source Volume Volume sources characteristics 

User Defined 

Sources 

16 Line Source Line Sources Buoyant lines source characteristics User Defined 

17 Receptors NREC Number of user defined receptors User Defined 

17 

Receptor

Data Location and elevation (MSL) of receptors User Defined 
APPENDIX E

CALPOST Parameter Values 
Appendix E 

CALPOST Parameter Values 

Table E-1. Recommended CALPOST parameter values chosen by the Region 10 states for use in BART modeling

Input 

Group Variable Description 

Default 

Value 

Recommended 

Value 

1 ASPEC Species to process VISIB VISIB 

1 ILAYER 

Layer/deposition code (1 = CALPUFF concentrations; -3 = wet+dry deposition 

fluxes) 1 1 

1 LBACK Add Hourly Background Concentrations/Fluxes? F F

1 MFRH Particle growth curve for hygroscopic species 2 2

2 RHMAX Maximum relative humidity (%) used in particle growth curve 98 95

2 LDRING Report results by Discrete receptor Ring, if Discrete Receptors used. (T = true) T 

 Modeled species to be included in computing the light extinction 

2 LVSO4 Include SO4? T T 

2 LVNO3 Include NO3? T T 

2 LVOC Include Organic Carbon? T T

2 LVPMC Include Coarse Particles? T T

2 LVPMF Include Fine Particles? T T

2 LVEC Include Elemental Carbon? T T

 

2 LVBK 

when ranking for TOP-N, TOP-50, and Exceedance tables Include 

BACKGROUND? T T

2 SPECPMC Species name used for particulates in MODEL.DAT file: COARSE = PMC PMC 

2 SPECPMF Species name used for particulates in MODEL.DAT file: FINE = PMF PMF 

 Extinction Efficiencies (1/Mm per ug/m**3) 

2 EEPMC PM COARSE = 0.6 0.6 

2 EEPMF PM FINE = 1.0 1.0 

2 EEPMCBK Background PM COARSE 0.6 0.6 

2 EESO4 SO4 = 3.0 3.0 

2 EENO3 NO3 = 3.0 3.0 

2 EEOC Organic Carbon = 4.0 4.0 

2 EESOIL Soil = 1.0 1.0 

2 EEEC Elemental Carbon = 10.0 10.0 

 

2 LAVER Method used for 24-hr avg % change light extinction F F

2 MVISBK 

Method used for background light extinction (2 = Hourly RH adjustment; 6 = 

FLAG seasonal f(RH)) 2 or 6 6 

2 RHFAC Monthly RH adjustment factors from FLAG (unique for each Class I area) Yes if 6 EPA 

Background monthly extinction coefficients (FLAG) unique for each Class I 

area

2 BKSO4 

Assume all hygroscopic species as SO4 (raw extinction value without 

scattering efficiency adjustment) see table 

2 BKNO3 see table 

2 BKPMC see table 

2 BKOC see table 

2 BKSOIL Assume all non-hygroscopic species as Soil see table 

2 BKEC see table 

2 BEXTRAY Extinction due to Rayleigh scattering 10.0 10.0 

 Averaging time(s) reported 

3 L1PD Averaging period of model output F F

3 L1HR 1-hr averages F F

3 L3HR 3-hr averages F F

3 L24HR 24-hr averages T T

3 LRUNL Run lengtyh (annual) F F

3 LT50 Top 50 table for each averaging time selected T F

3 LTOPN 1 

3 NTOP 1 

3 ITOP 
APPENDIX F

Emission Rates and Stack Parameters 
PGE Boardman Unit 1 - Flue Gas Emissions Data PM10 Speciation: 

 ----------------Filterable---------------- --------------Condensable------------ 

Baseline Case - Existing Operation 

Flow 

 (acfm) 

Stack

Velocity

(ft/s)

Temp.

 (°F) 

NOx

 (lb/hr) 

SO2

 (lb/hr) 

PM10

(lb/hour)

Elemental

Carbon

(lb/hour)

PM Fine 

(lb/hour)

PM

Coarse

(lb/hour)

Organic 

Carbon

(lb/hour)

Inorganic

Aerosol

(lb/hour) 

Non-SO2 Inor 

Aersol(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 0.00 

 

NOx Controlled Outlet Conditions 

Flow 

 (acfm) 

Stack

Velocity

(ft/s)

Temp.

 (°F) 

NOx

 (lb/hr) 

SO2

 (lb/hr) 

PM10

(lb/hour)

Elemental

Carbon

(lb/hour)

PM Fine 

(lb/hour)

PM

Coarse

(lb/hour)

Organic 

Carbon

(lb/hour)

Inorganic

Aerosol

(lb/hour) 

Non-SO2 Inor 

Aersol(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 0.00 

2. New Low NOx Burners with Modified 

OFA System 

2,159,900 95 293 1332.4 4943.1 176.20 1.74 45.40 58.90 14.00 56.10 0.00 

SO2 Controlled Outlet Conditions 

Flow 

 (acfm) 

Stack

Velocity

(ft/s)

Temp.

 (°F) 

NOx

 (lb/hr) 

SO2

 (lb/hr) 

PM10

(lb/hour)

Elemental

Carbon

(lb/hour)

PM Fine 

(lb/hour)

PM

Coarse

(lb/hour)

Organic 

Carbon

(lb/hour)

Inorganic

Aerosol

(lb/hour) 

Non-SO2 Inor 

Aersol(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 0.00 

2. 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 0.00 

Notes: 

1) SO2 based on no SO2 to SO3 conversion. 

2) PM speciations derived from spreadsheet prepared by ODEQ. 

3) Stack velocity (except for Wet FGD and Wet ESP) based on existing stack diameter of 22 feet. 

4) Emission rates based on 5,793 mmbtu/hr. 

 
Rick Tetzloff - RE: Revised Protocol 

Don,

The revised protocol for the BART-Determination Calpuff modeling for the PGE Boardman facility, as submitted, includes:

1) A summary of the BART Modeling Protocol for Washington, Oregon, and Idaho (2006), which was developed by the three states 

to cover both the Exemption and Determination phases of the modeling,

2) Engineering data on possible controls, with a proposed set of four controls and their respective emission rates and stack 

parameters that will be evaluated in the Determination modeling.

In that the Calpuff modeling portion of the revised Boardman protocol summarizes and highlights the approved Modeling Protocol 

for Washington, Oregon, and Idaho, the modeling portion of the revised protocol is approved for use in the Determination or control 

evaluation phase of the BART analysis.

Phil

Philip Allen

AQ Division

Oregon DEQ

503.229.6904

allen.philip@deq.state.or.us

-----Original Message----- 

From: Don.Caniparoli@CH2M.com [mailto:Don.Caniparoli@CH2M.com] 

Sent: Wednesday, January 17, 2007 4:44 PM 

To: ALLEN Philip; Mark.Fisher@state.or.us 

Cc: Patty.Jacobs@state.or.us; Ray.Hendricks@pgn.com; Rick.Tetzloff@pgn.com; Steven.Anderson@pgn.com; 

natalie.liljenwall@ch2m.com

Subject: Revised Protocol 

Attached is the revised protocol as we discussed today.

Don

From: "ALLEN Philip" <ALLEN.Philip@deq.state.or.us>

To: <Don.Caniparoli@CH2M.com>, <Mark.Fisher@state.or.us>

Date: 1/18/2007 6:06 PM

Subject: RE: Revised Protocol

CC: <Patty.Jacobs@state.or.us>, <Ray.Hendricks@pgn.com>, <Rick.Tetzloff@pgn.com>,

<Steven.Anderson@pgn.com>, <natalie.liljenwall@ch2m.com>

Message Page 1 of 1

file://C:\Documents and Settings\e65404\Local Settings\Temp\GW}00001.HTM 2/12/2007
From: ALLEN Philip [mailto:ALLEN.Philip@deq.state.or.us] 

Sent: Tuesday, August 28, 2007 12:21 PM 

To: ray.hendricks@pgn.com 

Cc: Caniparoli, Don/PDX; FISHER Mark 

Subject: Use of onzone.dat file for BART

Ray, 

 As you know, an ozone.dat for use in the Calpuff BART Exemption modeling was developed by Eri 

Ottersburg (SLR, International) and Mary Beth Yansura (CH2M Hill), with input and review by Oregon 

DEQ. This file would be used in lieu of the default 60 ppb value that was specified in the three-states 

BART Modeling Protocol. The ozone data incorporated in the file was compiled from state and 

federal ozone monitors in the three state area. After discussions with EPA Region 10, the Federal 

Land Managers (Forest Service, U.S. Fish and Wildlife, and National Park Service), and Washington 

State and Idaho, this ozone.dat file is considered an addition to the protocol and acceptable for use in 

the BART modeling. 

 

 If you have any questions, please don't hesitate to contact me. 

 

Phil 

 

Philip Allen 

AQ Division 

Oregon DEQ 

503.229.6904 

allen.philip@deq.state.or.us
Boardman Plant Appendix G

082710 G-1 

Appendix G

Replacement Power Cost Analysis
Portland General Electric Company

Boardman DEQ 2020 Shutdown Versus 2040 Shutdown - Change in Dispatch Value

(Thousands of Dollars)

Fully-allocated CCCT Market Prices with $30 CO2 Tax

(1) (2) (2) - (1)

DEQ

2040 2020

Shutdown Shutdown Change in

Dispatch Dispatch Dispatch

Value Value Value

2010 80,307 80,307 - 

2011 89,779 89,779 - 

2012 117,887 117,887 - 

2013 106,860 106,860 - 

2014 135,501 134,384 (1,117) 

2015 137,532 135,467 (2,065) 

2016 137,264 135,159 (2,105) 

2017 135,857 135,736 (122) 

2018 135,850 137,303 1,453 

2019 136,360 137,895 1,536 

2020 135,937 137,556 1,620 

2021 132,712 (132,712)

2022 128,282 (128,282)

2023 123,038 (123,038)

2024 118,758 (118,758)

2025 113,335 (113,335)

2026 110,001 (110,001)

2027 105,983 (105,983)

2028 101,454 (101,454)

2029 96,319 (96,319)

2030 91,314 (91,314)

2031 85,621 (85,621)

2032 82,437 (82,437)

2033 79,415 (79,415)

2034 76,281 (76,281)

2035 73,042 (73,042)

2036 69,751 (69,751)

2037 66,069 (66,069)

2038 62,417 (62,417)

2039 58,855 (58,855)

2040 55,453 (55,453)

NPV @ 7.59% (468,273)