### EXHIBIT B

340-223-0030
BART Requirements for the Foster-Wheeler Boiler at the Boardman Coal-Fi red Power Plant (Federal Acid Rain Program Facility ORISPL Code 6106) (1) Emissions limits:
(a) On and after July 1, 2011, nitrogen oxides emissions must not exceed 0.28 lb/mmBtu heat input as a 30-day rolling average and 0.23 lb/mmBtu heat input as a 12-month rolling avera ge. (A) If it is demonstrated by July 1, 2012 that the emission limits in (a) cannot be achieved with combustion controls, the Department may grant an extension of compliance to July 1, 2014.
(B) If an extension is granted, the nitrogen oxides emissions must not exceed 0.23 lb/mm Btu heat input as a 30-day rolling average on and after July 1, 2014.
(b) On and after July 1, 2014, sulfur diox ide emissions must not exceed 0.12 lb/mmBtu heat input as a 30

- day rolling average.
(b) On and after January 1, 2012, sulfur dioxide emissions must not exceed 0.96 lb/mmBtu heat input as a 12-month rolling average.
(c) On and after July 1, 2014, sulfur dioxide emissions must not exceed 0.60 lb/mmBtu heat input as a 12-month rolling average.
( c d) On and after July 1, 2014, particulate matter emissions must not exceed 0.012 0.040 lb/mmBtu heat input as determined by compliance source testing.
( d e ) The emission limits in (a) through ( c d) above do not apply during periods of startup or shutdown.
(2) Compliance demonstration. Using the procedures specified in section (3) of this rul e: (a) Compliance with a 30-day rolling average limit must be demonstrated within 180 days of the compliance date specified in section (1) of this rule.
(b) Compliance with a 12-month rolling average must be demonstrated within 12 13 months of the compliance date specified in section (1) of this rule.
(3) Compliance Monitoring and Testing

### (a) Compliance with the emissions limits in (1)(a) , (b) and (b c ) must be determined with a

continuous emissions monitoring system (CEMS) installed, operated, calibrated, and maintained in accordance with the acid rain monitoring requirements in 40 CFR Part 75 a s in effect on June 19, 2009 August 18, 2010

. (A) The hourly emission rate in terms of lb/mmBtu heat input must be recorded ea ch operating hour, including periods of startup and shutdown.
(B) The daily average emission rate must be determined for each boiler operating day using the hourly emission rates recorded in (A), excluding periods of startup and shutdown.
(C) 30-day rolling averages must be determined using all daily average emissions rates recorded in (B) whether or not the days are consecutive.
(D) 12-month rolling averages must be determined using calendar month averages base d on all daily averages during the calendar month.
(b) Compliance with the particulate matter emissions limit in (1)( c d) must be determined by EPA Methods 5 and 19 as in effect on June 19, 2009 August 18, 2010

. (A) An initial test must be conducted by January 1, 2015.
(B) Subsequent tests must be conducted in accordance with a schedule specified in the Oregon Title V Operating Permit, but not less than once every 5 years.
(C) All testing must be performed in accordance with the Department’s Sour ce Sampling Manual as in effect on August 18, 2010 June 19, 2009

. (4) Notifications and Reports
(a) The Department must be notified in writing within 7 days after any control equipment (including combustion controls) used to comply with emissions limits in section (1) be gin operation.
(b) For NOx and SO2 limits based on a 30-day rolling average, a compliance status report, including CEMS data, must be submitted within 180 days of the compliance dates specifi ed in section (1).
(c) If applicable, a compliance status report for the 12-month rolling average NOx limit in section (1)(a) must be submitted by August 1, 2012.
(d) For sulfur dioxide limits a compliance status report for the 12-month rolling avera ge SO 2 

### limit in section (1)(b), must be submitted by February 1, 2013 and a compliance status r eport for the 12-month rolling average sulfur dioxide limit in section (1)(c), must be submitte d by August 1, 2015.

### ( d e ) For particulate matter, a compliance status report, including a source test re port, must be

submitted within 60 days of completing the initial compliance test specified in se ction (3)(b).

340-223-0040

Additional NOx Requirements for the Foster-Wheeler Boiler at the Boardman Coal-Fired Power Plant (Federal Acid Rain Program Facility ORISPL Code 6106)

On and after July December 3 1, 20 17 20 , the Foster-Wheeler Boiler at the Boardman Coal-Fired Power Plant (Federal Acid Rain Program Facility ORISPL Code 6106) must c ease operations.
nitrogen oxides emissions must not exceed 0.0 70 lb/mmBtu heat input , excluding periods of startup and shutdown.
(1) Compliance with the NOx emissions limit must be determined with a continuous emissions monitoring system in accordance with OAR 340

- 223

- 0030(2) and (3).
( 1 2 ) The Department must be notified in writing within 7 days after the boiler ceases operation. any control equipment used to comply with the emission limit begins operation.
(3) A compliance status report, including CEMS data, must be submitted by January 1, 2018.

# EXHIBIT C

BEST AVAILABLE RETROFIT TECHNOLOGY/ REASONABLE PROGRESS ANALYSIS

## Portland General Electric

Boardman Plant

Best Available Retrofit Technology (BART) / Reasonable Progress Analysis Revision 2: Boardman 2020 Alternative

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

April 2, 2010Boardman Plant Table of Contents

040210 TC-1 

### Table of Contents

Acronym List ................................................................................................................ AL-1 Executive Summary .......................................................................................................ES-1 1.0 Introduction and Objectives ................................................................................. 1-1 1.1 Source Description and Background ............. .......................................... 1-1 1.2 BART/Reasonable Progress Analysis Methodology ............................... 1-5 1.2.1 Identify All Available Retrofit Control Technologi es (Step 1) ...................................................................................... 1-6 1.2.2 Eliminate Technically Infeasible Options (Step 2) ................... 1-6 1.2.3 Evaluate Control Effectiveness of Remaining Contro l Technologies (Step 3) ............................... ................................. 1-6 1.2.4 Evaluate Impacts and Document the Results (Ste p 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 Estimat e ................... 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 NO x

### 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 SO 2 

### 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 Furnace/Duct Reagent Injection ............... ............................... 3-16 3.2.5 Reduced Sulfur Coal Restriction ............................................. 3-17Boardman Plant Table of Contents

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### Table of Contents (Continued)

3.3 PM Control Technologies ........................ .............................................. 3-18 3.3.1 Pulse Jet Fabric Filter .............................................................. 3-19 3.3.2 Compact Hybrid Particulate Collector ............ ........................ 3-21 3.3.3 GE MAX-9 Hybrid .................................................................. 3-21 3.3.4 Multiple-Cyclone Separators .................. ................................. 3-23 3.3.5 Wet ESP ...................................... ............................................. 3-23 3.4 Emerging Pollution Control Technologies .......... .................................. 3-25 3.4.1 PowerSpan ............................................................................... 3-26 3.4.2 Enviroscrub .............................................................................. 3-27 3.4.3 Phenix Clean Coal ................................................................... 3-28 3.4.4 J-Power ReACT System .......................... ................................ 3-30 4.0 Technically Feasible Retrofit Emission Control Technologies (Step 2) ............. 4-1 4.1 Technically Infeasible NO x

### 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 SO 2 

### Control Technologies ............................... ... 4-2 4.2.1 Dry Flue Gas Desulfurization .................................................... 4-2 4.2.2 Furnace/Duct Reagent Injection ............... ................................. 4-2 4.3 Technically Infeasible PM Control Technologies ............................ ....... 4-2 4.3.1 GE MAX-9 Hybrid .................................................................... 4-2 4.3.2 Multiple-Cyclone Collector ................... .................................... 4-2 4.4 Technically Infeasible Emerging Pollution Control Technologies .......... 4-3 4.4.1 PowerSpan ................................................................................. 4-3 4.4.2 Enviroscrub ................................................................................ 4-3 4.4.3 Phenix CCS ............................................................................... 4-3 4.4.4 J-Power ReACT System .......................... .................................. 4-3 4.5 Summary of Retrofit Emission Control Technologies Technical Feasibility ................................................................................................. 4-3 5.0 Evaluation of Technically Feasible Retrofit EmissionControl Technologies (Step 3) ...............................

................................................... ........ 5-1 5.1 Control Effectiveness ............................................................................... 5-1Boardman Plant Table of Contents

040210 TC-3 

### Table of Contents (Continued)

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 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 NO x

### Control Technologies ............................... ....................... 6-11 6.4.2 SO 2 

### Control Technologies ....................................................... 6-11 6.4.3 PM Control Technologies ...................... .................................. 6-12 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/Reasonable Progress....... ................................... 8-1 8.2 Selection of SO 2 

### BART/Reasonable Progress ......................... ................ 8-2 8.3 Selection of NO X

### BART/Reasonable Progress ........................................ 8-4 8.4 Visibility Improvement for Combined BART Control s .......................... 8-6 9.0 References ............................................................................................................ 9-1

Appendix A Design Basis Appendix B Stack Outlet Conditions Appendix C Design Concept Definitions Appendix D Cost Analysis Summary Appendix E Visibility Modeling Results Appendix F Visibility Modeling ProtocolBoardman Plant Table of Contents

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### Table of Contents (Continued)

Tables

Table ES-1 Oregon Regional Haze Plan Requirements for the B oardman

Plant Boiler ............................................................................................ES-2 Table 1-1 Boardman Plant Operational Characteristics ........................................... 1-2 Table 1-2 Oregon Regional Haze Plan Requirements Ap plicable 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 NO x

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

### Control Technologies ..................................... 4-5 Table 4-3 Technically Feasible PM Control Technologies ......................... ............. 4-5 Table 4-4 Technically Feasible Emerging Pollution Control Technologies ............ 4-6 Table 5-1 Highest Rolling 12 Month Data for Heat Input ....................................... 5-1 Table 5-2 NO x

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

### Technologies Control Effectiveness ................................................. 5-2 Table 5-4 PM Technologies Control Effectiveness ....... .......................................... 5-3Table 6-1 BART/Reasonable Progress Impact Analysis and CostEffectiveness Results ............................................................................... 6-7 Table 7-1 Visibility Impact and Improvement Summary . ....................................... 7-5 Table 7-2 Hells Canyon and Mount Hood Visibility Improveme nt Summary ........ 7-7 Table 8-1 Visibility Impact Summary Boardman Plant BART

Determination .....................................

................................................... .. 8-7

Figures

Figure 3-1 Schematic Diagram of a Typical SCR Reactor ........................................ 3-2 Figure 3-2 Schematic of SNCR System with Multiple Injectio n 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 We t FGD System. ................ 3-10 Figure 3-6 Cutaway View of a Jet Bubbling Reactor W et 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) ................... 3-20 Figure 3-11 Max-9 Electrostatic Filter ...............

................................................... .... 3-22Boardman Plant Table of Contents

040210 TC-5 

### Table of Contents (Continued) Figures (Continued)

Figure 3-12 Multiple-Cyclone Particulate Collector ... .............................................. 3-23 Figure 3-13 ECO Process Flow Diagram (PowerSpan). ...... ..................................... 3-26 Figure 3-14 Pahlman Process Simplified Process Flow Dia gram. ............................ 3-28 Figure 3-15 Phenix Clean Coal Process Flow Diagram ............................................ 3-29 Figure 3-16 J-POWER ReACT System .................................................................... 3-31 Figure 6-1 NO x

### Control Cost-Effectiveness ......................... ..................................... 6-8 Figure 6-2 SO 2 

### Control Cost-Effectiveness ............................................................... 6-9 Figure 6-3 PM Control Cost-Effectiveness ............................................................. 6-10Boardman Plant Acronym List

040210 AL-1 

## Acronym List

A/C Air-to-Cloth AFDC Allowance for Funds During Construction ASN Ammonium Sulfate Nitrate BART Best Available Retrofit Technology Btu or Btu British Thermal Unit CaS Calcium Sulfide CCS Clean Combustion System CDS Circulating Dry Scrubber CO Carbon Monoxide CRGNSA Columbia River Gorge National Scenic Area CUECost Coal Utility Environmental Cost DCS Distributed Control System DEQ Department of Environmental Quality EPA Environmental Protection Agency EPRI Electric Power Research Institute ESP Electrostatic Precipitator FF Fabric Filter FGD Flue Gas Desulfurization ID Induced Draft IFGR Induced Flue Gas Recirculation LNB Low NO x

### Burners LNB/MOFA Low NO x

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

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

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

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

### ) British Thermal Units MW Megawatt N 2 

### O 5 

### Nitrogen Pentoxide NH 3 

### Ammonia NO x

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

040210 AL-2 

### 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 SO 2 

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

040210 ES-1 

## Executive Summary

The Boardman Plant is a 584 megawatt (MW) net pulve rized 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 fro m the Oregon Nuclear and Thermal Energy Council (NTEC). On July 6, 2005, the Environmental Protection Agenc y (EPA) issued its final Regional Haze Regulations and Guidelines for Performi ng Best Available Retrofit Technology (BART) Determinations . These rules/guidelines established a procedure f or identifying those sources that must retrofit their e xisting facilities with BART and for determining what constitutes BART. The purpose of the BART program is to require controls, where appropriate, for facilities that we re 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 enume rated source categories that were in existence prior to August 7, 1977. Because the Boar dman 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 define d by EPA) before August 7, 1977, it was identified by the Oregon Department of Environmenta l Quality (DEQ) as a BART

source. On November 2, 2007, PGE submitted a BART analysis to DEQ evaluating the available NO x 

### , PM and SO 2 

### retrofit controls for the Boardman Plant boiler. T his analysis assumed that the Boardman Plant boiler would operat e for the rest of its physical life, i.e., until at least 2040. PGE noted that the analysis w ould require revision if it was determined that a shorter boiler life was appropriat e. On December 1, 2008, the DEQ published its proposed BART determination for the B oardman Plant boiler. During the public comment period, PGE requested that DEQ consider allowing PGE to forego certain controls if the company committed to cease o peration 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 Haz e Plan). The Regional Haze Plan includes new regulations (OAR 340-223-0030) imposing NO x 

### , SO 2 

### and PM limitations reflective of BART and applicable to the Boardman Plant boiler. The NO x

### regulations require compliance by July 1, 2011 and the SO 2 

### and PM regulations require compliance by July 1, 2014. The Regional Haze Plan also inclu des new regulations (OAR 340-223- 0040) imposing additional NO x

### limits reflective of the “Reasonable Progress” requirements of Clean Air Act Section 169A. The Re asonable Progress regulation requires compliance by July 1, 2017. These require ments are summarized below in Table ES-1.Boardman Plant Executive Summary

040210 ES-2 

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

Limit (Assumed Control) Installation Deadline Authority 0.28 lb NO x/MMBtu - 30 day rolling average 0.23 lb NO x/MMBtu - Annual average (Low-NO xBurners/Overfire Air) * 7/1/2011 BART

0.12 lb SO 2 /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 NO x/MMBtu (SCR) 7/1/2017 Reasonable Progress
*If combustion controls do result in a showing of c ompliance by July 1, 2012 and DEQ grants an extension of the compliance deadline to July 1, 2014, the NO xlimit changes to 0.23 lb/MMBtu as a 30 day rolling average.


### In adopting these BART/Reasonable Progress requirem ents, the EQC and DEQ acknowledged PGE’s request for consideration of a b oiler shutdown, but stated that early closure would need to be addressed in future submitt als. 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 SO 2 

### and NO x

### controls for the Boardman Plant boiler “could be significant and mayrequire PGE to evaluate costbenefit 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 determ ine 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 chan ge.” 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 th e BART and Reasonable Progress requirements. While specific legislation has not y et 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). PGE’s IRP analysis shows that the least-cost, least-risk option for its custom ers is for the CompanyBoardman Plant Executive Summary

040210 ES-3 

### to operate the Boardman Plant boiler for its full lif etime if the BART and Reasonable Progress controls are all installed. In response to requests from IRP s takeholders and OPUC staff, PGE has recently 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 option would require DEQ to revise the BART and Reasonable Progress regulations to delete OAR 340-223-0030(1)(b) and (1 )(c) and OAR 340-223-0040(1). Therefore, PGE is submitting this revised BART/Reas onable 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 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 confi guration once the boiler is compliant with the BART emission limit s. Both analyses were conducted assuming that the Boardman Plant boiler will cease ope rations by the end of 2020. The steps followed in the BART and Reasonable Progre ss analyses were consistent with the requirements of Clean Air Act S ection 169A. In Step 1, available NO x 

### , SO 2 

### , 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 effec tiveness of each technically feasible control technology was evaluated. Based on this ev aluation, the technologies were ranked in order of effectiveness. In Step 4, the c ost, 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 c onsidered as a stand-alone factor. The Reasonable Progress analysis built upon the BART an alysis and added the additional analytical step of considering the time necessary f or compliance. In the final step of the BART analysis, the visibility improvements associat ed with the top-ranked options were evaluated consistent with the modeling protocol app roved by DEQ on January 18, 2007 and amended on August 28, 2007. Visibility improvem ent 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 be low.Boardman Plant Executive Summary

040210 ES-4 

## NO x

## Control Selection BART NO

x 

### Control Analysis PGE does not believe that any change to the BART NO x

### determination reflected in OAR 340-223-0030(1)(a) is merited. PGE is in the process of installing new low NO x 

### burners and a modified over-fire air system on the Boardman Plant boiler for NO x 

### control. These controls are expected to enable the Boardman Plant boiler to meet the BART NO x

### limits in OAR 340-223-0030(1)(a) by July 1, 2011. These technologies are expected to reduce the NO x

### emission levels for the Boardman Plant boiler from a baselin e level of 0.43 lb NO x

### /MMBtu to 0.23 lb NO x

### /MMBtu (annual average). Selective non-catalytic reduction (SNCR) equipment is planned as a contingency in the event that combustion controls cannot meet th e BART NO x

### limits and a compliance extension is requested. SNCR was considered as an additionalinterim control measure in the event that the combustion co ntrols are capable of achieving the BART NO x

### limits currently in the Regional Haze Plan. If the combustion controls alone reached the BART NO x

### limits, then SNCR could potentially enable the Boardman Plant to further reduce NO x

### emissions to as low as 0.19 lbs/MMBtu (annual aver age). However, in light of the negative impacts identifie d by the Department in relation to SNCR (e.g., ammonia storage concerns, impacts assoc iated with ammonia slip, slag impacts and additional water consumption), PGE conc luded that SNCR should not be the basis for setting more restrictive BART NO x

### limits in the event that the combustion controls achieve the NO x

### limits in OAR 340-223-0030(1)(a). In conclusion, PGE suggests that the Department ret ain the current BART NO x 

### limits and deadlines in OAR 340-223-0030(1)(a) as nothing changes in the prior analysis as a result of accelerating the Boardman Plant boiler closur e date to 2020.
Reasonable Progress NO x 

### Control Analysis Based on the revised analysis, PGE believes that th e Reasonable Progress NO x 

### requirements should be revised. The Regional Haze Plan BART NO x

### limits are currently based on the 2011 installation of new low NO x

### burners (NLNB) and a modified over-fire air system (MOFA). The Reasonable Progress NO x

### limits are based on the 2017 installation of SCR. For the reasons stated below, and contingent on the addition of a requirement to OAR 340-223-0040 requiring that the Boardman Plant boiler cease operating no later than December 31, 2020, a Reason able Progress requirement to meet 0.070 lb/MMBtu NO x

### (i.e., the addition SCR) in 2017 cannot be justifi ed. Therefore, the current requirement in OAR 340-223-0040 should be r eplaced with regulatory languageBoardman Plant Executive Summary

040210 ES-5 

### requiring that the Boardman Plant boiler cease oper ation no later than December 31, 2020. 1 

### PGE believes that the Reasonable Progress limits es tablished in OAR 340-223- 0040 should be replaced with a requirement that the Boardman Plant boiler cease operation by December 31, 2020. The factors mandate d by the Clean Air Act do not justify establishing Reasonable Progress limits more stringent than those established through BART in light of the premature closure of the Boardman Plant boiler. The only technologies identified during the available contro l analysis that could be added to supplement the BART controls through Reasonable Pro gress are SNCR and SCR. 2 

### Both technologies were evaluated against the statutory f actors mandated for determining Reasonable Progress controls and neither was found app ropriate. The energy and nonair quality impacts of SNCR and S CR support a conclusion that neither technology should be required as a Rea sonable Progress control. Both SNCR and SCR have impacts that are more severe than thos e associated with combustion controls alone. Both technologies include additiona l fans, pumps and other electrical equipment that consume considerable energy, reducin g the efficiency of the plant. In addition, the nonair quality environmental impacts, including ammonia slip, ammonia storage, and hazardous material disposal during SCR catalyst replacement, are significant. A direct impact of employing SCR is that the cost is so high that it would likely require utilization of the post-combustion c ontrols for their full life (until approximately 2040) in order to achieve a reasonabl e cost recovery period. Operating the plant until 2040 would result in considerable addit ional emissions of greenhouse gases which are believed to contribute to climate change. By substituting closure in 2020 for installation of post-combustion NO x

### controls, PGE would achieve the significant non-ai r quality environmental benefit of eliminating approx imately 5,000,000 million tons of carbon dioxide emissions annually. These factors s upport the conclusion that neither SNCR nor SCR is an appropriate Reasonable Progress control t echnology. The cost of compliance criterion similarly fails to support selecting SNCR or SCR as a Reasonable Progress control. The economic impa cts associated with SCR are considerable—much higher than the cost of complianc e associated with the BART NO x 

### limits in the Regional Haze Plan. The planned NLNB /MOFA are estimated to have

1 PGE is currently exploring the potential to repowe r the Boardman Plant boiler utilizing alternative fuels. At this time such fundamental changes are s till in the conceptual phase and there is no certai nty that they will be technically feasible. Therefore, the potential to repower the boiler using an alternativ e 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 H aze plan to enable such an innovative strategy. 2 This analysis assumes that the Boardman Plant is a ble to comply with the BART NO xlimits without the need for supplementary controls. If that is not the case, then SNCR (o r comparable innovative controls) would already be installed pursuant to BART.Boardman Plant Executive Summary

040210 ES-6 

### capital costs of $35.7 million. The total capital cost associated with adding SCR to the (then) existing NLNB/MOFA system is approximately $ 192 million. Operating costs associated with SCR are similarly much higher than the operating costs associated with maintaining the NLNB/MOFA system required by BART. ($6.1 million per year for NLNB/MOFA/SCR as opposed to $0.7 million per year f or NLNB/MOFA). As a result, the cost of imposing SCR as Reasonable Progress equ ates to over $14,500 per ton of NO x 

### controlled. This is well outside the cost of compli ance associated with Reasonable Progress determinations in other states and well outside the range of what is a reasonable cost. While the costs associated with SNCR are consi derably lower than those associated with SCR, they still contribute to the overall conc lusion that SNCR should not be considered a Reasonable Progress control. Consideration of the remaining useful life of the B oardman Plant boiler also supports the conclusion that Reasonable Progress sh ould not require NO x

### limits more stringent than those reflecting combustion controls. 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 c omponent of the cost of compliance. This has been done in the assessment summarized abo ve. However, Congress expressly identified the remaining useful life of the plant a s a criterion distinct and separate from the cost of compliance criterion. The Department re cognized in the Regional Haze Plan that it might not be appropriate to require costly post-combustion controls if the Boardman Plant boiler were required to cease operat ion prematurely. See, e.g., Regional Haze Plan at 155-156. Consistent with these statem ents, SCR was appropriately not considered as BART and should not be considered as Reasonable Progress if PGE agrees to a regulatory requirement that the Boardman Plant boiler cease operations no later than December 31, 2020. Similarly, SNCR should not be r equired as a Reasonable Progress control if the combustion controls alone are capable of atta ining the BART limits. Visibility improvement is not a Reasonable Progress criterion, but even if it was considered it would offer only marginal support for requiring SCR or SNCR as a Reasonable Progress control. The addition of eithe r SNCR or SCR would result in additional NO x

### reductions beyond those achieved by the BART NO x

### controls. 3 

### Computer modeling indicates that these supplementary reducti ons would result in slightly improved visibility. However, while the BART controls will improve visibility in Mt. Hood and Hells Canyon ( ǻ dv) by 25.0 percent, the addition of SNCR will only increase that

3 This evaluation assumes that the combustion contro ls will be adequate to meet the BART NO xlimits and that the contingency provisions of OAR 340-223- 0030(1)(a)(A) and (B) will not be triggered. If th is is not the case, the Boardman Plant boiler will presum ably already be employing SNCR as a BART control and it can be eliminated from consideration under Reasonable Progress.Boardman Plant Executive Summary

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### improvement to 28.8 percent and the addition of SCR will only increase that improvement to 36.8 percent. Also, as EPA recogniz ed in the 2005 preamble, the modeling system required for evaluating visibility impacts magnifies and overstates those improvements. Therefore, the incremental improveme nt achieved between the combustion NO x

### controls (BART) and the NO x

### controls incorporating SNCR or SCR (Reasonable Progress) is not, by itself, determinat ive. Furthermore, the Clean Air Act is explicit as to what criteria must be considered in de termining Reasonable Progress controls and the degree of improvement in visibility is not one of the enumerated criteria. As a result, visibility improvement is not an adequ ate basis for overcoming the conclusion reached when considering the statutory R easonable Progress factors that SCR and SNCR are not Reasonable Progress controls. Therefore, PGE proposes that the Department revise the Regional Haze Plan to replace the Reasonable Progress NO x

### limits in OAR 340-223-0040 with a requirement that PGE cease operating the Boardman Plant boiler no later than December 31, 2020. 4 

### This approach is consistent with the statutory crit eria and will enable DEQ to rely on plant closure as part of its long term strategy to achieve its Reasonable Progress goals.



## SO 2 

## Control Selection SO 2 

### BART Control Analysis Based on this revised analysis, PGE believes that the BART SO 2 

### requirements should be revised to require conditions not conside red in the previous BART analysis. The Boardman Plant boiler already utilizes exclusiv ely low sulfur coal so as to minimize SO 2 

### emissions resulting in a modeling baseline SO 2 

### emission rate of 0.81 lb/MMBtu. The prior BART analysis considered only post-combus tion controls, all of which carry with them significant impacts. The Regional Haze P lan BART SO 2 

### limits are currently based on the 2014 installation of semi-dry scrubber s. No controls beyond continued use of low sulfur coal and operation of the scrubbers we re considered necessary as a result of the Reasonable Progress analysis. PGE has reassessed its BART analysis for the Boardman Plant boiler to include interim coal sulfur limits that could provide additional SO 2 

### emissions reductions in lieu of post-combustion co ntrols. Consideration of implementation of stepwise reduced sulfur coal limi ts in 2011 and 2014, in conjunction with a requirement to cease operation of the Boardman Plant boiler in 2020, presents a

4 Nothing in the Clean Air Act grants DEQ the author ity to require cessation of operation of the Boardman Plant boiler as a BART or Reasonable Progr ess control technology. However, PGE may propose an early closure date that is then taken into account in establishing BART and Reasonable Prog ress controls. This revised analysis assumes that PGE i s willing to accept a requirement that it cease ope ration of the Boardman Plant boiler by December 31, 2020. However, if DEQ concludes that either BART or Reasonable Progress requires SCR, FGD or upgraded P M controls, then PGE expressly withdraws this analysis and any consideration of premature closure of the plant as an element of this analysis.Boardman Plant Executive Summary

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### compelling alternative to the current BART requireme nts in OAR 340-223-0030(1)(b). For the reasons summarized below, when this BART al ternative is considered, a BART requirement to meet 0.12 lb/MMBtu SO 2 

### (i.e., the addition of semi-dry scrubbers) in 2014 based on operation of the Boardman Plant boile r through 2040 cannot be justified. Therefore, the current requirement in OAR 340-223-0 030(1)(b) should be replaced with regulatory language requiring that the Boardman Plant boiler use coal with an annual average sulfur dioxide emissions not to exceed 0.96 lb/MMBtu (annual average) by December 31, 2011 and 0.60 lb/MMBtu (annual average ) starting on July 1, 2014 and requiring that the Boardman Plant boiler cease oper ation no later than December 31, 2020. No additional Reasonable Progress requirements are justified. This BART determination will require that PGE reduce the allo wable level of sulfur dioxide emissions by 20 percent in 2011 and 50 percent in 2014. The statutory factors do not support requiring semi-dry scrubbers as BART controls if the Boardman Plant boiler is required to reduce its SO 2 

### emissions limit by 20 percent in 2011 and 50 percent by July 1, 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 nonair quality environmental impacts of compliance, the remaining u seful 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 Clean Air Act requires consideration of existingcontrol technologies. When the Boardman Plant boiler was initially permitted, NTEC and DEQ evaluated the best available control technology available to the plant for controlling SO 2 

### emissions. 5 

### NTEC and DEQ concluded that this was the use of low sulfur coal—a practice that is still required by permit today. The boiler was according ly designed to accommodate the unique firing characteristics of low sulfur coals. PGE is proposing that this existing control technique be relied upon in establishing BA RT by increasing the stringency of the SO 2 

### emission restriction from 1.2 lb/MMBtu to 0.96 lb/MMBtu and, ultimately, to 0.60 lb/MMBtu. This substantial (50 percent) decrease i n allowable SO 2 

### emissions recognizes the existing control technique while ultimately dec reasing the allowable sulfur content in the coal combusted in the Boardman Plant boiler. T he proposed dates are the most expeditious dates by which the transition to reduce d sulfur coal can be accomplished in light of the existing stock of coal at the plant (a pproximately 500,000 tons) and the current coal contracts in force through 2011. While semi-dry scrubbing might be

5 Although the Boardman Plant predated the federal N ew Source Review (PSD) program, the structure of the impending program was known at the time of permitting and so the NTEC, working in association with DEQ, required the use of Best Avai lable Control Technology (BACT) and required that PGE demonstrate through modeling that the Boardman Plant would not result in emissions impacts exceeding 10 percent of the ambient air quality standards.Boardman Plant Executive Summary

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### appropriate for a coal-fired plant using higher sul fur coal, the addition of scrubbing is not appropriate for a plant prepared to expeditiously c onvert to reduced sulfur coal and that would only be operating for a limited period of time prior to closure. The energy and nonair quality impacts of semi-dry s crubbing support the conclusion that the technology should not be requir ed as a BART control. Semi-dry scrubbing has impacts that are more severe than thos e associated with the use of reduced sulfur coal alone. Semi-dry scrubbing requires add itional fans, pumps and other electrical equipment that consume considerable ener gy, reducing the efficiency of the plant. In addition, the nonair quality environmenta l impacts, including water usage and waste disposal, are material. The best means of co ntrolling SO 2 

### emissions is to not emit it in the first place. By converting from low sulf ur coal to reduced sulfur coal, the Boardman Plant boiler is able to eliminate 50 percent of its allowable SO 2 

### emissions without creating additional energy or environmental impacts. When this control technique is combined with premature closure of the Boardman Plant boiler in 2020, there is no sound basis for requiring semi-dry scru bbing 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 propo sed reduced sulfur coal restriction/premature closure BART alternative. Se mi-dry scrubbing would require a capital investment of approximately $270 million an d an operating cost of approximately $13.9 million per year. 6 

### Since the SO 2 

### control equipment would only be operated for 6.5 years, cost effectiveness values for semi-dry scrub bing would be approximately $5,600 per ton. Reducing the SO 2 

### permit limit by 50 percent imposes operational cos ts as well as additional risk because of the limited availabil ity of coal mines that offer reduced sulfur coals and the substantial projected increase in demand. However, these operational costs, while material, are significantly lower than the capital and operational costs associated with semi-dry scrubbing. Due to the hig h capital costs for this technology, addition of semi-dry scrubbing would require an unr easonable investment in light of the short period that it would be operational. Consideration of the remaining useful life of the Boar dman Plant also supports the conclusion that DEQ should not require BART SO 2 

### emission limits more stringent than the 20 percent increasing to 50 percent reduction p roposed by PGE based on the use of reduced sulfur coal. 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 Gu idelines suggest accounting for remaining useful life as a component of the cost of compliance. This has been done in

6 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 revisi ted here as nothing about the analysis has changed.Boardman Plant Executive Summary

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### the assessment summarized above. However, Congress expressly identified the remaining useful life of the plant as a criterion d istinct 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 50 percent reduction in allowable SO 2 

### emissions is considered. Improvement in visibility provides only minimal sup port for requiring postcombustion SO 2 

### controls when contrasted to the imposition of a re duced sulfur coal restriction and premature closure. Utilization of scrubbers would reduce the 98th percentile visibility impacts at Mt. Hood and Hells Canyon by a little over 1 deciview. Utilization of reduced sulfur coal such that emissi ons are limited to 0.60 lb/MMBtu will reduce the 98th percentile visibility impacts at Mt . Hood by 0.5 dv. The limited additional improvement in visibility resulting from the use of post-combustion controls (i.e. scrubbers) is insufficient to overcome the other impacts associated with postcombustion controls. Even this limited additional improvement associated with semi-dry scrubbers pales in comparison to the long term bene fits associated with closure of the plant by the end of 2020. As noted, if SO 2 

### 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 are limited. When those limite d 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 r eplacing the current BART SO 2 

### emissions limit with a limit based on reduced sulfur coal and closure no later than December 31, 2020. Based on this analysis, scrubbers should not be con sidered as BART if PGE agrees to (1) limit SO 2 

### emissions to 0.96 lb/MMBtu (annual average) no later than December 31, 2011, (2) limit SO 2 

### emissions to 0.60 lb/MMBtu (annual average) commencing July 1, 2014, and (3) cease operation of the Boardman Plant boiler no later than December 31, 2020.

SO 2 

### Reasonable Progress Control Analysis There is no basis for concluding that the SO 2 

### reduction technologies eliminated from consideration as BART controls would be approp riate as Reasonable Progress controls. For the reasons stated above, PGE believes that the factors specified in the Clean Air Act support the conclusion that semi-dry scrubbing should not be required as an SO 2 

### BART control if PGE will decrease the Boardman Plant boiler’s allowable SO 2 

### emissions by 50 percent (20 percent by the end of 2 011 and then by the full 50 percent byBoardman Plant Executive Summary

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### mid-2014) and the Boardman Plant boiler will not op erate beyond December 31, 2020. There is nothing about the Reasonable Progress analys is that merits a different conclusion.


## Particulate (PM) Control Selection The Boardman Plant is already fitted with a cold-si de ESP, which removes over 99 percent of PM from the flue gas. Considering th e 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 fo r these three technologies is $192,000, $187,000, 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.Boardman Plant Introduction and Objectives

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## 1.0 Introduction and Objectives

The objective of this report is to provide the tec hnical, regulatory and statutory basis for revisions to the regulations adopted as p art of the Regional Haze Plan in light of changes in critical assumptions that have arisen sin ce the Boardman Plant boiler was first assessed. When the Environmental Quality Commissio n (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/R easonable Progress conclusions if critical assumptions changed and PGE submitted a ne w BART/Reasonable Progress analysis. This document is in response to that age ncy commitment. This report documents the basis for requested changes to the BA RT 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 st eam 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 Resour ces Cooperative (10%) and BA Leasing BSC, LLC (15%). The Boardman Plant was iss ued its construction authorization from the Nuclear and Thermal Energy Council on Febr uary 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 demons trate that the plant would operate in compliance with the ambient air quality standards . PGE also agreed to implement various controls to reduce air emissions, includingthe use of a cold-side ESP to reduce particulate emissions, the exclusive use of low sul fur coal to reduce SO 2 

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

### 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 operation al 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

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### Table 1-1 Boardman Plant Operational Characteristics

Item Unit 1 Fuel Type Subbituminous Heating Value of Fuel, Btu/lb (HHV) 8,020 – 9,800 Unit Rating, MW (gross/net) 617 / 584 Net Plant Heat Rate, Btu/kWh 9,841 Boiler Heat Input, MMBtu/hr 5,793 7 

### Type of Boiler/Manufacturer Opposed-wall/Foster Wheeler Steam Cycle Subcritical Draft of Boiler Balanced Existing Emissions Controls SO 2 

### (Pre-combustion Controls - Coal Type) Low-sulfur coal

NO x

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

### generation) PM (Post-combustion Controls) Cold-side ESP
While 5793 MMBtu/hr is considered the nominal boile r heat input, the maximum boiler heat input is roughly 6400 MMBtu/hr, based on an evaluat ion 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 r etrofit their existing facilities with BART and for determining what constitutes BART. Th e purpose of the BART program was to require controls, where appropriate, for fac ilities 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 P lant is a steam electric plant of more than 250 MMBtu per hour heat input, it is in one of the BART eligible source categories.

7 While 5793 MMBtu/hr is considered the nominal boile r heat input, the maximum boiler heat input is roughly 6400 MMBtu/hr, based on an evaluation of CE MS data from 1997 to 2008 for the maximum 30- day average heat input value of the boiler.Boardman Plant Introduction and Objectives

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### 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 qua lity laws or regulations and either has (1) begun, or caused to begin, a continuous program of physical on-site constructionof the facility or (2) entered into binding agreements or c ontractual 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 comple ted in a reasonable time.” 40 CFR 51.301

DEQ determined that the Boardman Plant had obtained all necessary preconstruction approvals or permits required by Fe deral, 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 h ad commenced prior to August 7, 1977, the Boardman Plant was identified by DEQ a s a BART source. 8 

### On November 2, 2007, PGE submitted a BART analysis to DEQ evaluating the available NO x 

### , SO 2 

### , 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 r equire revision if it was determined that a shorter plant life was appropriate. On Dece mber 1, 2008, the Department published its proposed BART determination for the B oardman Plant. During the public comment period, PGE requested that DEQ consider all owing PGE to forego certain controls if the company committed to cease operationof the Boardman Plant boiler by dates certain. On June 19, 2009, the EQC adopted the Regional Haz e Plan. The Regional Haze Plan includes new regulations (OAR 340-223-0030) imposing NO x 

### , SO 2 

### and PM limitations reflective of BART and applicable to th e Boardman Plant boiler. The NO x 

### regulations require compliance by July 1, 2011 and the SO 2 

### and PM regulations require compliance by July 1, 2014. The Regional Haze Plan also includes new regulations (OAR 340-223-0040) imposing additional NO x

### limits reflective of the “Reasonable

8 For the same reasons that the Boardman Plant is considered a BART source, the p lant was necessarily determined to have 1978 “actual emissio ns,” as that term is defined in the Oregon Plant Site Emission Limit rules, equal to the plant’s potentia l to emit.Boardman Plant Introduction and Objectives

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### 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 th e

Boardman Plant Boiler

Limit (Assumed Control) Installation Deadline Authority 0.28 lb NO x/MMBtu—30 day rolling average 0.23 lb NO x/MMBtu—annual average (Low-NO xBurners/Overfire Air) * 7/1/2011 BART

0.12 lb SO 2 /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 NO x/MMBtu (SCR) 7/1/2017 Reasonable Progress
*If combustion controls do result in a showing of c ompliance by July 1, 2012 and DEQ grants an extension of the compliance deadline to July 1, 2014, the NO xlimit changes to 0.23 lb/MMBtu as a 30 day rolling average.


### In adopting the BART/Reasonable Progress requirement s 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 co sts associated with the regional haze SO 2 

### and NO x

### controls for the Boardman Plant “could be signific ant and may require PGE to evaluate cost-benefit factors affecting the futur e of the Boardman Plant, as part of the Oregon Public Utility Commission Integrated Resourc e 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 recog nition that PGE could petition DEQ for reconsideration of the BART and Reasonable Prog ress 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 th e BART and Reasonable Progress requirements. While specific legislation has not y et passed Congress, PGE believes thatBoardman Plant Introduction and Objectives

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### 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 optio n for its customers is to operate the Boardman Plant boiler for its full lifetime if all of the BART and Reasonabl e Progress controls are installed. In response to requests fro m 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 delete the current OAR 340- 223-0030(1)(b) and (1)(c) and OAR 340-223-0040(1). In their place, PGE proposes that DEQ impose a requirement that ultimately restricts the Boardman Plant boiler SO 2 

### emissions to 0.60 lb/MMBtu (half the current limit) and requires that the Boardman Plant boiler cease operation no later than December 31, 2020. PGE is submitting this revised BART/Reasonable Progress analysis to request that DEQ revise the Regional Haze Plan accordingly

. The methodology used for this BART and Reasonable Pr ogress 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 re trofit emission reduction for pollutants that cause visibility impacts in federal Class I are as (NO x 

### , SO 2 

### , and PM). To identify the best method of emission reduction, data are collect ed through a five step process to arrive at a selection of the best methods of emissions reduction of NO x 

### , SO 2 

### , and PM at the BART source. The five steps followed to develop in formation 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 contro l technologies. 4. Evaluate impacts and document the results. 5. Evaluate visibility impacts. These steps generate data that are used to evaluat e the costs and benefits of various control technologies and, ultimately, ident ify 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 ident ify visibility impacts as an evaluative criterion for identifying Reasonable Progress contr ols. The Clean Air Act identifies anBoardman Plant Introduction and Objectives

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### additional step, evaluation of the time necessary f or 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 Techn ologies (Step 1) The first step of the BART/Reasonable Progress anal ysis is to identify all available retrofit control technologies. A controltechnology is considered as an available retrofit if it has practical potential for application to the BART-eligible s ource. The technology considered can be a method, system, or acombination of both options for control of a pollutant. Technologies that have bee n successfully applied to similar sources with similar gas stream characteristics are considered available. However, technologies that have not been applied to full sca le operations are not considered available. Since the Boardman Plant boiler is equi pped with existing control technologies, the control options evaluated include d improvements or optimization of the existing control technologies. Section 3.0 address es 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 technolog ies to determine technical feasibility. A control technology is technically feasible if it ha s been previously installed and operated successfully at a similar type of source or if ther e 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 av ailable technology is applicable if it has been previously installed and operated at a simi lar type of source, or a source with similar gas stream characteristics. Section 4.0 ad dresses the requirements of Step 2 of the BART/Reasonable Progress analysis.
1.2.3 Evaluate Control Effectiveness of Remaining C ontrol Technologies (Step 3) Once all the technically feasible control technolo gy alternatives are identified in Step 2, the control effectiveness of each control t echnology 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 pos t-control emissions and pounds of emissions per MMBtu heat input. Data for the contr ol effectiveness of a technology wereBoardman Plant Introduction and Objectives

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### obtained by considering regulatory decisions or eva luations that have been performed on the effectiveness of the technology. Other referen ce 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 c ontrol 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 S tep 3 for all the feasible control technologies identified in Step 2, additional evalu ations of each technology are performed in Step 4. The impacts of utilizing the control te chnology at the Boardman Plant are evaluated. The evaluation of the impacts (impact an alyses) 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 co mpliance. This analysis is performed to indicate the cost to install and operat e the control technology. The capital and operating annual costs are estimated based on e stablished design parameters, and then the annualized cost is determined. The annuali zed cost ($/year) is then divided by the estimated quantity of pollutant removed (tons/y ear) to determine the costeffectiveness ($/tons) of each control technology. Establishing cost-effectiveness allows the evaluation of different control technologies onan economic basis for potential elimination from further consideration. Consistent with the EPA’s directive, two types of cost-effectiveness are considered in this BART/Reas onable 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-effective ness is a comparison of the cost and performance level of a control technology to the ne xt most stringent option. It has a unit of $/incremental ton removed. The incremental cost -effectiveness is a good measure when comparing technologies that have similar remova l efficiencies. Consistent withBoardman Plant Introduction and Objectives

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### EPA guidance issued in relation to Best Available C ontrol Technology determinations, cost of compliance is not necessarily evaluated for technologies that are considered acceptable to PGE. The second impact analysis evaluates the energy im pacts of a particular control technology. The energy impact of each evaluated co ntrol 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 auxil iary 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 ad ditional fuel cost and/or the cost of lost generation that would need to be purchased fro m another source because of implementation of the technology. The third impact analysis evaluates the nonair qua lity environmental impacts. Nonair quality environmental impacts are evaluated to determine whether a particular control technology has any environmental impacts no t related to air quality – either positive or negative. An example of a negative nona ir 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 A ir 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 necess ary for compliance. This particular factor is identified by the Clean Air Ac t only in relation to the Reasonable Progress analysis. However, this factor is conside red in the BART analysis in relation to what constitutes the “expeditiously as possible” de adline for implementation of the control technology imposed by BART. The sixth impact analysis required by the Clean Ai r 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 eff ect on the annualized costs of the retrofit controls for capital recovery. This occurs when th e 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. How ever, the Clean Air Act does not limit consideration of remaining u seful life to the economic analysis. Congress’ choice to include remaining useful life a s a factor independent of economicBoardman Plant Introduction and Objectives

040210 1-9 

### impacts evidences a Congressional intent that remai ning 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 additionof each control technology is determined from modeling results using the CALPUFF dispersion modeling system. A modeling protocol was previously developed in consu ltation with, and approval of, DEQ. This protocol was also followed in this revised anal ysis. 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 mad e. The visibility improvement was determined by comparing the 98 th

### percentile days at pre- and post-control emission rates. Consideration of the degree of improvement in visib ility is a factor specified by the Clean Air Act only in relation to the determinat ion of what constitutes BART. Visibility impacts are not identified as a decisioncriterion for Reasonable Progress. However, as the purpose of Reasonable Progress is t o 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 Reaso nable Progress analysis.
1.2.6 Selecting the Best Alternative From the analyses performed in the five steps desc ribed above, tables were prepared assessing the merits and demerits of the c ontrol technology options, with the focus on the top-ranked technologies. These factor s were then evaluated to select the best alternative. PGE strove to maintain the exist ing 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 second ary levels of emission reduction for pollutants that cause visibility impacts in federal Class I areas (NO x 

### , SO 2 

### , and PM). EPA has issued no regulatory guidance on how to perform Reasonable Progress analyses and so the Clean Air Act itself is the sole basis for de termining the appropriate means ofBoardman Plant Introduction and Objectives

040210 1-10 

### establishing Reasonable Progress limits. 9 

### As noted above, the Reasonable Progress analytical criteria stated in the Clean Air Act diffe r 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, Reasonab le 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 Reas onable Progress is determined using a baseline condition reflecting the visibility improv ements expected to result from implementation of other Clean Air Act requirements— including BART. 40 CFR 51.308(d)(3)(v). Both BART and Reasonable Progres s 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 NO X

### limits in OAR 340-223-0040, PGE has followed the p rocess outlined above in relation to BART, while respectin g the differences required by the Clean Air Act when determining Reasonable Progress limits.

9 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 Reasonabl e 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 Rea sonable 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 doc ument was not to identify a comprehensive process for establishing Reasonable Progress goals.Boardman Plant Basis of Analysis

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## 2.0 Basis of Analysis

2.1 Design Basis A detailed design basis was established for the Bo ardman Plant. The information in the design basis was used for equipment sizing, performance calculations, cost estimates (capital, operating, and maintenance), an d estimating resources consumption, auxiliary power requirements, and byproduct disposa l. The complete design basis is shown in Appendix A. The design basis with the ori ginal design coal case was used as the basis for this BART/Reasonable Progress analysi s. The design basis was also established for two other coal cases: typical (Bucks kin 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 BoardmanPlant. The capital cost estimates were based on the Coal Utility Environmental Cost (CUECo st) generated estimates, cost data supplied by equipment vendors (budget estimates), and estimates from in-house design/build projects. The capital cost estimates in clude direct and indirect costs and are stated in 2010 dollars. The cost estimates are con sistent in format with the guidance from the EPA’s Office of Air Quality Planning and Standards Cost M anual . The capital cost accuracy is expected to be +/- 30 percent. The cost s 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, insta llation, and miscellaneous costs. The purchased equipment costs are the costs for pur chasing the control technology equipment from equipment vendors (including freight ). An itemized list of major components of the direct capital cost is included f or each feasible control technology in Appendix D. The installation costs include constru ction costs for installing the new controls and also take into account the retrofit di fficulty that can be expected from the existing site configuration and the installation requirements of the control s. Finally, miscellaneous costs include the costs for additional i tems such as site preparation, buildings, and other site structures needed to supp ort the controls. The direct cost estimates were based on the following assumptions:

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

040210 2-2 

### x Ample supply of craft labor and construction equipment is av ailable.

x Normal lead-times for equipment deliveries are expe cted. Indirect costs are costs that are not related to th e equipment purchased but are associated with any engineering project, such as th e 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 deve lopment 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 b y 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 th e costs are not applicable to all of the evaluated technologies but are representative of the typical expenditures that the owner(s) will experience thro ugh 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 d irectcost construction contracts, safety and medical services, guards and other security services, insurance premiums, other required labor-re lated 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 co mmissioning of the newly installed control technology. Also inclu ded 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 acase-by-case basis from manufacturer recommendations and owner requirements.Boardman Plant Basis of Analysis

040210 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 escalation s 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. T his 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 installatio n of the control technologies to validate the performance of the emissions reduction systems. Typical performance tests are flue gas emissions te sting 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 li mits.
2.2.2 Annual Operating and Maintenance Cost Estimate Annual operating and maintenance (O&M) costs typically con sist of the following cost categories:

x Reagent costs.

x Electric power costs.Boardman Plant Basis of Analysis

040210 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 depende nt on the specific control technology. Operating and maintenance materials and labor are f ixed annual costs that do not vary with these factors. Table 2-2 lists the major econ omic 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 th e 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 cos ts 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 fo r 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 incl ude 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 technologi es include water to support reagent preparation for limestone-forced oxidation or lime- based scrubbers, ammonia solution preparation from urea for SCR and selective noncata lytic reduction (SNCR) processes and for electrode plate washing in a WESP. Addition al costs might be incurred for water treatment to obtain the required water quality. Fo r 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 categor y.Boardman Plant Basis of Analysis

040210 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/m 3 Makeup Water Cost $2/1,000 gal Service Water Cost $0.50/1,000 gal Wastewater Treatment Cost $0.50/1,000 gal Byproduct Disposal Cost $10/ton Electric Power Cost $50/MWh Steam Cost $3.50/1,000 lbs Maintenance Cost 3% of cap cost/yr Control Technology Economic Life From control equip ment 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 NO xControl Systems July 1, 2011 Start-up Date for all SO 2 or PM Control Systems July 1, 2014 Start-up Date for SCR NO xControl System July 1, 2016 Start-up Date for SNCR NO xControl System July 1, 2014 Boiler Shut-Down Date (no later than) December 31, 2020 Capital Recovery Factor for all Combustion NO xControl Systems 14.76

Capital Recovery Factor for all SO 2 or PM Controls 19.67 Capital Recovery Factor for SNCR Control System 19. 67 Capital Recovery Factor for SCR Control System 26.6 7 Allowance for Funds During Construction (AFDC) 8.99 % Fully Loaded Operating Labor Cost, per person $100, 000/yearBoardman Plant Basis of Analysis

040210 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 dispos al. For example, a wet FGD system generates a blowdown wast ewater stream to regulate the level of chlorides in the slurry recirculation syst em. Also, a wet FGD system forms calcium sulfate and calcium sulfite byproducts when the limestone reacts with SO 2 

### . For wastewater treatment and byproduct disposal cost, the following key assumptions were utilized:

x Sales of fly ash captured in the existing ESP is una ffected 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 wastew ater treatment prior to being discharged to the environment.

x Ammonia-based NO x

### reduction systems may affect the salability of fly ash. However, for this analysis, the impacts were as sumed 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 requi red to run the new control equipment. These estimates are based on industry common practi ces. 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 wi ll 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 operatin g labor required is identified. 2.2.2.6 Maintenance Materials and Labor Costs. The annual maintenance materials and labor costs are estimated as a percent age of the total equipment costs of the system. On the basis of typical utility industry e xperience, maintenance materials are estimated to be between 1 and 5 percent of the tota l 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 maint enance requirements was performed. If the required maintenance materials and labor are si milar to the existing technology, no additional maintenance costs are included for the n ew control technology.Boardman Plant Basis of Analysis

040210 2-7 

## 2.3 Baseline Emissions For this revised BART analysis, the baseline emissi ons for NO x 

### , SO 2 

### , 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 emissi on rates represent the highest rolling 12 month total between 2003 and 2005. Consistent w ith 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 NO x0.43 lb/MMBtu 2003-2005 CEMS Data

10,349 ton/yr 2003-2005 CEMS Data
SO 2 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 o ther programs, including BART. Therefore, the Reasonable Progress analysis used co mpliance 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 de sign of the technically feasible control technologies. The following are key project assumpti ons:

x Plant availability will potentially be affected by th e 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 acc ommodate construction activities including, but not limited to, offices, lay-down and staging.Boardman Plant Basis of Analysis

040210 2-8 

### x Any repairs, rehabilitation, and/or ductwork stiffe ning of the existing boiler and ductwork equipment are assumed to be mino r and are included in contingency costs.

x Byproducts produced from the emissions reduction pr ocesses will be disposed at the available landfill area on-site.

x When not contaminated with scrubber products, fly a sh captured by PM control technologies is sold.

x When the scrubber byproducts contaminate the fly as h, 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 inthe controls as part of an Integrated Resource Plan.


## 2.5 Modeling Baseline Conditions Stack outlet conditions for all the technically fea sible 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 include d are the following:

x Flue gas flow rate.

x Flue gas velocity.

x Flue gas temperature.

x Flue gas pressure.

x SO 2 

### emissions rate.

x NO x

### emissions rate.

x PM emissions rate.Identification of All Available Retrofit

Boardman Plant Emission Control Techniques (Step 1 )

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## 3.0 Identification of All Available Retrofit Emis sion

Control Technologies (Step 1)

In Step 1 of the BART/Reasonable Progress analysis , all available retrofit control technologies that have a practical potential for ap plication at the Boardman Plant were identified. These technologies were considered as available technologies. The control technology may be a method, system, or combination of reduction technologies for control of a pollutant. Sections 3.1 through 3.3 describe the control technologies for the three pollutants: NO x 

### , SO 2 

### and PM. Information on the working principle, retrofit considerations, and advantages and disadvantages of each t echnology is also provided.



## 3.1 NO x

## Control Technologies The following NO x

### 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-comb ustion reductions in NO x 

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

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

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

### and ammonia reagent react to form nitrogen and water vapor. The reaction mechanisms are very efficient, with a reagent stoichiometry of approximately 1.05 (on a NO x

### reduction basis) and with low ammonia slip (unreacted ammonia). A simplified schematic d iagram of a typical SCR reactor utilizing aqueous ammonia injection is illustrated o n Figure 3-1.Identification of All Available Retrofit

Boardman Plant Emission Control Techniques (Step 1 )

040210 3-2 

### Figure 3-1 Schematic Diagram of a Typical SCR Reactor
The SCR reactor is the housing for the catalyst. T he 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 S CR reactor. The SCR reactor is typically elevated above and upstream of the air he ater 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 ai r 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 BoardmanPlant 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 w ill be required to lower the gas path temperature to the desired range while still ma intaining the air temperature exiting the air preheater to the pulverizer in order to properly dry the coal and m aintainIdentification of All Available Retrofit

Boardman Plant Emission Control Techniques (Step 1 )

040210 3-3 

### combustion efficiency. The costs of such modificat ions are expected to be substantial, up to approximately $45 million dollars. The oxidation of SO 2 

### to SO 3 

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

### concentration. As the SO 3 

### concentration increases, the acid dew point of the flue gas increases, potentially increasing corrosion in down stream equipment or possibly requiring an increase in the air heater gas outlet temperature. The ammonia reagent for the SCR systems can be supp lied by anhydrous ammonia, aqueous ammonia, or by conversion of urea to ammonia. Since the ammonia is vaporized prior to contact with the catalyst, th e selection of ammonia type does not influence the catalyst performance. However, the s election of ammonia type does affect other subsystem components, including reagent stora ge, vaporization, injection control, and balance-of-plant requirements. The vast majori ty of worldwide installations use anhydrous ammonia. SCR systems have a variety of interfacing system re quirements to support operations. These requirements predominantly relat e 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. De pending on arrangement and performance requirements, draft losses can range fr om 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 cau se an increase in the pressure drop of the air heater, degrade its performance, and decrease p lant efficiency. The other potential danger for the air heater is high concentrations of SO 3 

### in the flue gas. If the acid dew point temperature has been increased to more than the exhaust temperature, a significant amount of acid gases will condense in the air heate r 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 S O 2 

### to SO 3 

### conversion rate. The effectiveness of the SCR system in a high-dust application is limited by ash fouling of the catalyst. Continuous heavy soot blo wer 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 maintai n NO x

### reduction levels. This results in an increased amount of ammonia slip and ammonia bisulfate fouling of the ai r heaters.Identification of All Available Retrofit

Boardman Plant Emission Control Techniques (Step 1 )

040210 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 designe d for an optimum SCR arrangement. On an existing unit however, the ability to install an “optimum” arrangement for an SCR is limited by the e xisting plant and unit specific conditions and restrictions. SCR, as stated previo usly, is located between the economizer and the air heater for a high dust arrangement. Th is is typically a very congested area of the plant. Plant equipment (such as fans, boiler s upport steel, and underground utilities) restrict the possible ductwork arrangements as well as increase the complexity of the retrofit. SCR performance is highly dependent on h aving even flow distribution into the ammonia injection grid and the catalyst.
3.1.2 Selective Noncatalytic Reduction SNCR systems reduce NO x

### emissions by injecting a reagent at multiple levels in the boiler, as illustrated on Figure 3-2. SNCR sys tems 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 NO x

### 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 rang es 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 NO x

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

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

### reduction capabilities. Typically, optimum conditions ar e difficult to achieve, resulting in emissions reduction levels of 15 to 25 percent for r etrofit applications. Potential performance is very site-specific and varies with f uel type, steam generator size, allowable ammonia slip, furnace CO concentrations, and steam generator heat transfer characteristics. SNCR systems reduce NO x

### emissions using the same reduction mechanism as SCR systems. Most of the undesirable chemical reac tions occur when reagent is injected at temperatures above or below the optimum range. A t best, these undesired reactions consume reagent with no reduction in NO x

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

### . Accordingly, NO x

### reductions and overall reaction stoichiometry are very sensitive to the 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 )

040210 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 Le vels

The NO x

### reduction potential of SNCR systems is limited by bo iler geometry and temperature profiles (which vary as a function of lo ad) 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 2200 o 

### F). For an existing boiler, waterwall and steam piping modific ations would be necessary to accommodate the installation of SNCR reagent injectors. Mu ltiple 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 NO x 

### 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 deve loped to combine the low capital cost and high ammonia slip associated with S NCR systems with the high reduction potential and decreased ammonia slip inhe rent in the catalyst of SCR systems. The result is a NO x

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

### reduction requirements but can be upgraded to meet higher reductions at a future date, if required.Identification of All Available Retrofit

Boardman Plant Emission Control Techniques (Step 1 )

040210 3-6 

### The SNCR component of the hybrid system is identica l to the SNCR system described previously, except that the hybrid system may have more levels of multiple lance nozzles for reagent injection. This will incr ease 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 g as. This increased reagent flow has a twofold effect: NO x

### reduction within the boiler is increased while amm onia 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 ex cess ammonia slip. The most conservative hybrid systems use the catalyst simplyas an ammonia slip “scrubber” with some additional NO x

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

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

### reduction is realized at the catalyst, the relativ ely small catalyst requirement of this design can potentiallyallow 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 NO x

### reduction. The additional reduction is a function of the quantity of ammonia slip, catalyst volume, and distribution of ammonia to NO x

### within the flue gas. Using ammonia slip produced by the SNCR system is not a high efficiency method of introducing reagent, because o f 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 NO x 

### , 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 NO x

### reduction required and the ammonia distribution. The impact of catalyst volume on the design of ahybrid system is on the size of the reactor required to hold the cat alyst. If multiple levels of catalyst operating at low flue gas velocity are required, so me 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 pr eheater. 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 BoardmanPlant 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 w ill be required to lower the gasIdentification of All Available Retrofit

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040210 3-7 

### path temperature to the desired range while still ma intaining the air temperature exiting the air preheater to the pulverizer in order to properly dry the coal and m aintain combustion efficiency. The costs of such modificat ions 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-veloc ity air as well as reagents. The lance tubes work to create turbulent airflow and to incre ase the residence time for the air/fuel mixture. In principle, the OFA and SNCR processes are comb ined in this technology. ECOTUBE is capable of reducing NO x 

### , while improving thermal efficiency, by optimizing the combustion process in boilers. An i llustration of the ECOTUBE installation in a typical boiler is shown on Figure 3-3. The water-cooled ECOTUBEs are automatically retract ed 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 erosionin the boiler and backend equipment.

Figure 3-3 ECOTUBE Installation in a BoilerIdentification of All Available Retrofit

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### 3.1.5 LoTOx The LoTOx technology is the low temperature gas-phase oxidation of NO x

### 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 NO 2 

### to form nitrogen pentoxide (N 2 

### O 5 

### ). The N 2 

### O 5 

### formed is soluble in water and can be removed from the flue gas using a wet FGD system. The LoTOx technology has been demonstrated on sever al industrial sized plants. In May 2002; the technology was used at Abitibi Con solidated (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 NO x

### removal efficiency with a reported potential of 15 to 25 percent savings in capital co st 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 multip le 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 signific antly higher than the power consumption from an SCR. The nitrate production fr om this technology is captured in the FGD waste product, possibly requiring the need for a wastewater treatment p lant.

3.1.6 Natural Gas Reburn The natural gas reburning process employs three sep arate combustion zones to reduce NO x

### emissions, as illustrated on Figure 3-4. The firs t zone consists of the normal combustion zone in the lower furnace, which is form ed by the existing wall burners. In this zone, 75 to 80 percent of the total fuel heat i nput is introduced. The first zone burners are operated with about 10 percent excess a ir (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 increase d furnace corrosion (especially with higher sulfur fuels) because of the reducing atmosphere in the lower furnace. The substoichiometric reburn zone causes NO x

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

### molecules is combined with the more active CO molec ules to form carbon dioxide as combustion is completed in the upper furn ace. Fuel burnout is completed in the third zone (the burnout zone) by the introducti on 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 NO x

### reduction of 40 to 65 percent.Identification of All Available Retrofit

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### Burnout Zone •Normal Excess Air
Reburning Zone •Slightly Fuel Rich •NOx Reduced to N 2



### Primary Combustion Zone •Reduced Firing Rate •Low Excess Air •Lower NOx Overfire Air

40 to 60% NOx Reduction 10 to 20 % Gas Fuel Rich

80 to 90% Coal 10% Excess Air

Figure 3-4

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 reburnin g 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 spac e is available, reburning can be highly effective, but a low residence time will lim it system performance. Also, the high cost of natural gas makes the annual operating costs of this technology prohibitive.



## 3.2 SO 2 

## Control Technologies The following SO 2 

### 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 Furnace/duct reagent injection.

x Reduced sulfur coal restriction.Identification of All Available Retrofit

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### 3.2.1 Wet Flue Gas Desulfurization Although wet lime and ammonia FGD systems are avail able, the wet limestone FGD process is the most frequently applied FGD technology in the Unite d States when treating flue gas from combustion of medium- and hi gh-sulfur coals (typically greater than 1.5 percent sulfur). Wet limestone FGD systems are also applicable for units burning low-sulfur bituminous and subbituminous coa ls. Wet limestone FGD systems are capable of achieving slightly higher SO 2 

### removal than other types of FGD systems but have not demonstrated significant removal of el emental mercury. A typical wet limestone FGD system consists of reagent storage an d handling system, FGD spray tower absorber, and byproduct dewatering system as illustrat ed 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 Syste m.Identification of All Available Retrofit

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### For most wet limestone FGD applications, the absorbe r module is located downstream of the ID fans (or booster ID fans, if r equired). For a wet FGD system, the flue gas enters the absorber and is contacted with aslurry containing reagent and byproduct solids. The SO 2 

### is absorbed into the slurry and reacts with the ca lcium to form CaSO 3 

### x 1/2H 2 

### O and CaSO 4 

### x 2H 2 

### O. There are several types of absorber modules, and ea ch has characteristic advantages and disadvantages. FGD equipment vendor s have specific designs for one or more types, and all compete on a capital/operating c ost 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 v endors 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 abs orber is saturated with water and the stack will have a visible, persistent moisture plume . Generally, wet FGD systems do not remove significant quantities of SO 3 

### from the flue gas. Condensed SO 3 

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

### SO 4 

### ), can be removed with a WESP, which is discussed i n Subsection 3.3.6.

Figure 3-6

Cutaway View of a Jet Bubbling Reactor Wet FGD Syst emIdentification of All Available Retrofit

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### Because of the chlorides present in the mist carryo ver 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 constructi on. 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 oc curs in the downstream ductwork and stack. The reaction byproducts are typically dewatered by a combination of hydrocyclones and vacuum filters. For natural oxidationwet limestone FGD systems, the resulting filter cake is suitable for landfill dispo sal. 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, practi cally all of the CaSO 3 

### x 1/2H 2 

### O can be converted to CaSO 4 

### x 2H 2 

### O, which is commonly known as gypsum. This oxidati on step is termed “forced oxidation.” Compared to calc ium sulfite, gypsum has much superior dewatering and physical properties, and forced-oxidized systems ten d to have few scaling problems in the absorber and mist elimi nators. Dewatered gypsum can be landfilled without stabilization or fixation. Manywet FGD systems in the United States are using the forced-oxidation process to produce c ommercial grade gypsum that can be used in the production of Portland cement or wallbo ard. Marketing of the gypsum can eliminate or greatly reduce the need to landfill FG D byproducts. The wet FGD processes are characterized by high efficiency and high reagent utilization. The absorber vessels are fabricated f rom 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 c apital 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 dryi ng 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 fu els. These installations, primarily located in the western United States, use either li gnite or subbituminous coals as boiler fuel and generally have spray dryer systems designed for a maxim um fuel sulfur content of less than 2 percent.Identification of All Available Retrofit

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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 upstr eam 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 r emoval device, most commonly a pulse jet fabric filter (PJFF). For the Boardman Plant, the SDA absorber ve ssel 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 recyc led solids from the PJFF to form the reagent slurry. The reagent s lurry is injected into the absorber using either a rotary or dual-fluid atomizer, where the l ime reacts with the SO 2 

### 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 SO 2 

### is absorbed into the fine spray droplets and reacts with the lime slurry to f orm both calcium sulfite (~1/3) and calcium sulfate (~2/3). Before the droplets can re ach the wall of the vessel, the heat of the flue gas evaporates the droplets to dry particl es containing the byproduct solids and excess reagent. As the reagent slurry evaporates, a relat ively dry powder remains.Identification of All Available Retrofit

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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 SO 2 

### removal system, since a significant percentage of r emoval 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 pneumatical ly to the fly ash silo in the conventional manner. These solids are unloaded, co nditioned with water, and transported to a landfill. Because of the level of free lime i n the byproduct solids, the byproduct/fly ash mixture attains a very high bearing strength an d low permeability in the landfill. Unlike a wet limestone FGD system, there is current ly no commercial use for the byproduct/fly ash.Identification of All Available Retrofit

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

### removal. Hydrated lime (Ca[OH] 2 

### ) is the reagent used; it is introduced as a dry, free flowi ng powder into the scrubber vessel. Flue gas is then flowed through the lime reagent in a ci rculation pattern for adsorption of SO 2 

### 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 Nort h America)
Generally, there are no constraints on the maximum fuel sulfur content; the CDS can be adjusted to account for the higher SO 2 

### loading by increasing the concentration of reagent. However, this flexibility is limited by th e 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 bef ore it reacts with the lime. Flue gas coming into the scrubber vessel is cooled to about 30 o 

### 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 SO 2 

### 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 reac tion products from the module to the downstream particulate control device.Identification of All Available Retrofit

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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 partic les 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 densiti es needed for contact and removal of SO 2 

### . Typically, reagent is recirculated 35 to 50 time s, providing a residence time of 30 minutes or more. Collected solids, which are not reci rculated, 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 c ostly, especially if there are substantial construction and structural difficulties. Disadvantages of this process include high dust loa ding 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 be cause of the flue gas dust loading, thus ESPs are preferred for particulate removal. T he high particulate loadings make sizing of the ESP critical to ensure compliance withparticulate emission requirements.
3.2.4 Furnace/Duct Reagent Injection Furnace and duct reagent injection systems require e ither a wet or dry reagent such as sodium bicarbonate, powdered lime, hydrated lime, lime slurry, limestone or Mg(OH) 2 

### to remove SO 2 

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

### in the flue gas, and its removal efficiency is hig hly dependent on the application, primarily the configuration of the existing ductwork and the flue gas residence time in the ductwork. Because of the type of reaction, temperature, perce ntage reduction rate, and the corresponding retention time requirements, a dry reagent such as powdered lime and hydrated lime are preferred for furnace injection a pplications. A wet reagent, such as lime slurry, sodium bicarbonate, or Mg(OH) 2, 

### is typically preferred for duct injection applications because of the removal requirements and the flue gas properties. The use of a wet reagent for duct injection is pref erred over a dry reagent because of the elevated gas temperatures that exist during normal operating conditions. The use of a wet reagent upstream of an existing ESP will he lp reduce the gas temperature, improve ESP performance for opacity and particulate control, and eliminate the need for additional ID booster fans for additional draft control.Identification of All Available Retrofit

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### CFD and chemical kinetic modeling may be necessary to determine which reagent is preferred; the preferred location of reagent inj ection; the amount of SO 2 

### emissions removed; and whether furnace injection, duct inject ion, or both furnace/duct injection systems are required for effective removal. Unit d esign and operational data will be collected for the CFD computer model inputs. This data, combined with unit mapping information, will enable the model to develop preci se injection locations and reagent injection characteristics for each boiler. The major components of a typical reagent injectionsystem include an air compressor, chemical storage tank, heat tracing, controls, injection system (e.g., flanges, lances, nozzles, hoses, hardware, etc.), injection plat form, and slurry pump. Furnace injection can reduce or eliminate fireside slagging, fouling, corrosion, and erosion problems in the furnace. Other benefit s of various efficiency improvements include savings through greater heat transfer clean liness, reduction of periodic air heater replacement, increase in overall unit reliability, reduction of boiler cleaning costs, and, ultimately, the extension of unit runs to the point where only scheduled outages are taken.

3.2.5 Reduced Sulfur Coal Restriction Reduced sulfur coals are available that could reduc e SO 2 

### emissions without the negative ancillary impacts associated with post-com bustion controls. Reduced sulfur coal could be used to reduce SO 2 

### emissions but would require coal blending to achiev e material reductions. Seams within existing Powder Riv er Basin coal mines have different sulfur levels. However, only a limited number of mi nes offer the lowest sulfur coals and those coals are facing increasing demand. Not all p ortions of those limited mines contain reduced sulfur coal. In addition, seasonal transpo rtation restrictions can limit the availability of certain coals at certain times of y ear. As a result, any significant reduction in the Boardman Plant boiler’s SO 2 

### emission limit through the use of lower sulfur coa ls would need to be accomplished through the blending of coals with different sulfur levels. PGE could reasonably lower its SO 2 

### emission limit to 0.96 lb/MMBtu (a 20 percent reduction from the present SO 2 

### emissions limit) by December 31, 2011. The Boardman Plant has contractual commitments for fuel supply in place through December 31, 2011. These contractual commitments allow the v endor to provide coal with SO 2 

### emissions up to 1.2 lb/MMBtu. PGE cannot breach the se contracts without severe long term ramifications and so cannot decrease its SO 2 

### emissions limit until those contracts expire on December 31, 2011. Once new contracts are in effect, PGE can begin purchasing reduced sulfur coals.Identification of All Available Retrofit

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### However, the Boardman Plant has an existing stockpi le of approximately 500,000 tons of coal provided under contracts that allowed up to 1.2 lb/MMBtu SO2 (as emitted) consistent with the current permit limit. The stockp iled coal would need to be blended in with the coal provided under the new contracts. The coal in the stockpile has a mineral composition that creates a destructive slagging and fouling if burned in large percentages. In order to avoid damage to the boiler , the Boardman Plant only burns a limited percentage of this stockpiled coal at any o ne time. Based on the estimated maximum reasonable firing rate for the stockpiled co al and the use of reduced sulfur coals contracted for starting on January 1, 2012, the Boardman Plant boiler could decrease its SO 2 

### emissions limit by 20 percent (i.e., to 0.96 lb/MM Btu). Any lower value would prolong the time period necessary to consume the stockpiled coal. At a maximum reasonable firing rate and taking into account proj ected outage periods, the Boardman Plant boiler would require through June 30, 2014 to consume the existing fuel stockpile without material risk of damage to the boiler. Onc e that stockpiled coal is fully consumed, the SO 2 

### emissions limit could be further reduced. PGE could reasonably lower its SO 2 

### emission limit to 0.60 lb/MMBtu (a 50 percent reduction from the present SO 2 

### emissions limit) starting on July 1, 2014. Once the stockpiled coal is consumed, the Boardman Plant boiler can begin blending exclusively reduced sulfur coals. Based on an asse ssment of the mines with reasonable transportation accessibility and taking into account the need for maintaining a reliable supply through 2020, it would be reasonable to redu ce the SO 2 

### emissions limit to as low as 0.60 lb/MMBtu. Compliance with this SO 2 

### emissions limit could be accomplished by using a blend of the coal supplies that are reasonably projected to be available in adequate quantities and are compatible with the Boar dman Plant boiler. Trying to consistently attain an SO 2 

### emission limit lower than 0.60 lb/MMBtu would impos e excessive availability, risk and cost burdens on the plant and so is not considered feasible. Both the 0.96 lb/MMBtu and the 0.60 lb/MMBtu SO 2 

### emissions limits would need to apply on an annual average basis. Any shorter term averaging period would require higher limits to account for natural variation in su pply and sulfur content.


## 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.Identification of All Available Retrofit

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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 select ion of low-sulfur fuels has promoted the use of FFs for the last 15 years. Cloth filter media is typically sewn into cylindri cal 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 re placement. The quantity of compartments is determined by maximum economic compartment size, total gas volume rate, air-to-cloth (A/C) ratio, and cleaning systemdesign. 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 te chnology, 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 in stalled 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 puls e of air into the top of the bag. The pulse causes a ripple effect along the le ngth 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 s o 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 bee n successfully implemented on many large units and is a standard feature of the technology.Identification of All Available Retrofit

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### Figure 3-10 Pulse Jet Fabric Filter Compartment (Babcock & Wilc ox)Identification of All Available Retrofit

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### 3.3.2 Compact Hybrid Particulate Collector Another control technology that is effective in rem oving 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 operate s 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 les s 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 sys tem is different than for a regular FF system, because the majority of large particulat es 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 parti culates are more difficult to clean.
3.3.3 GE MAX-9 Hybrid The Max-9 electrostatic filter is a hybrid combinat ion 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 p recipitator. Since the particles are positively charged, they repel each other on the sur face 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 g as volume with a smaller footprint. Process gas enters the Max-9 from a hopper inlet du ct. 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 soleno ids. 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 vo ltage control. The Max-9 can be supplied as shop-assembled modules that can be erected on site, although the units are usually custom-enginee red for each plant site and application to make the best use of available space.Identification of All Available Retrofit

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### Figure 3-11 Max-9 Electrostatic FilterIdentification of All Available Retrofit

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### 3.3.4 Multiple-Cyclone Separators Multiple-cyclone separators, also known as multiclo nes, 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 lon ger and smaller in diameter. The longer length provides longer residence time, while the smaller diameter creates greater centrifugal force. These two factors result in bett er separation of dust particulates. The pressure drop of multiclone collectors is higher than that of s ingle-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 illustratio n 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 th e 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 diff erential, 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 b asis as a dry ESP: negatively charged particles are collected on positively charge d surfaces. The collecting surfaces are wet instead of dry and are flushed with water t o 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 collectionIdentification of All Available Retrofit

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### efficiency is enhanced by a lack of re-entrainment a fter 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 appli cations because it reduces opacity, sulfuric acid mist (H 2 

### SO 4 

### ), and other aerosols. The use of WESPs for acid mist collection was one o f 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 excellentfuel flexibility regarding particulate removal. However, water chemistry, sca ling, 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 controll ers for each transformer/rectifier are located in an environmentally controlled enclosure. Each electrical field has a separate discharge electrode support frame suspended by alum ina insulators. A heater-blower system dedicated to each module supplies warm purge air for each of the insulator compartments. The discharge electrode support frame s are constructed from Type 304 stainless steel. The discharge electrodes are susp ended from the upper guide frame and held in the tube center line. The discharge electr ode is a rigid electrode constructed from 304 stainless steel; it contains split corona-gener ating 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 wi th 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 verti cal pipes or channels with a discharge electrode hanging down the center of the pipe or ch annel. Channel shapes such as squares or hexagons have more efficient packing dens ities 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 on e 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 a dd water to the flue gas to reduce the flue gas temperature to the saturation point or the WESP must be install ed downstream ofIdentification of All Available Retrofit

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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 o n the plant, and generates a visible moisture plume at the stack outlet. The removed particulate would b e contained in a wastewater stream that is generated by the WESP. I n addition to this issue, the capital cost of a WESP is high compared to other technologie s because of the higher cost of the alloy materials required for the WESP. Higher grad es 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. A lternatively, addition of alkaline reagents can be used to neutralize the acid in the wastew ater 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 o nce 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 inje ction of dispersant into the system can be employed to help eliminate scale formation w ithin the module. The dispersant can be stored in a small tank and fed into the flush wat er surge tank to allow dispersant to enter the modules through the spray levels. In add ition 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 di ssolve the scale buildup are two potential options.


## 3.4 Emerging Pollution Control Technologies Research is ongoing to develop new and improved tec hnologies for multipollutant control. The list of emerging technologi es 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 p ilot testing as the others. Since many of these technologies are still at the pilot (slips tream) stage of development, they should be viewed with caution until more is known and perfo rmance guarantees become available.Identification of All Available Retrofit

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### 3.4.1 PowerSpan There are several emerging multi-pollutant technolog ies 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-sc ale systems. The ECO system is located downstream of an existing particulate contr ol device, and the process consists of three stages. In the first stage, the flue gas pas ses 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 radica ls, which then oxidize NO x 

### , SO 2 

### , and mercury. This reaction results in the format ion of nitric acid, sulfuric acid, and mercuric oxides. A process flowdiagram of the ECO system is illustrated on Figure 3-13. Stage 2 is the collecti on 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. S crubber effluents contain dissolved ammonium sulfate nitrate (ASN) salts alon g with solids and mercury. The ASN solution is sent to a recovery process where th e mercury is removed via a sulfurimpregnated activated carbon structure. Once the c arbon 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).Identification of All Available Retrofit

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### PowerSpan also offers a mercury-only control techno logy that uses a photochemical oxidation process. In this process, mercury is oxidized via ultraviolet lights. The ultraviolet lights are placed in the d uctwork upstream of the particulate control device. Photochemical oxidation technologyis in its infancy stage, as are most mercury reduction technologies. The ECO system is under pilot testing at FirstEnerg y’s 50 MW Burger Plant and has achieved 82, 99, and 85 percent reduction for NO x 

### , SO 2 

### , and mercury, respectively, while combusting eastern high-sulfur bituminous coa l. However, because the ECO system has not been pilot tested at a facility burn ing a low-sulfur (less than 1.5 percent) subbituminous coal or within the Boardman Plant siz e range, this system was not evaluated further.

3.4.2 Enviroscrub Enviroscrub is a multi-pollutant control technologythat is capable of removing significant amounts of elemental and oxidized mercury, NO x 

### , PM 2.5 

### , and SO 2 

### . This technology is based on the Pahlman Process. A sorb ent made up of oxides of manganese called Pahlmanite sorbent is injected upstream of th e SDA, where the flue gas mixes with the Pahlmanite sorbent. This is where the oxidationand adsorption of mercury takes place. Other pollutants, such as SO 2 

### and NO x 

### , are also adsorbed by the Pahlmanite sorbent at this stage. The SDA byproducts are then separated from the flue gas in the PJFF. The fly ash and waste byproduct collected inthe PJFF hopper is eventually transported to a slurry tank for subsequent Pahlman ite 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. Curre ntly, Enviroscrub is performing slip-stream pilot testingusing third-party contractors, and the initial results are encouraging (Hammel, Charlie; E nviroscrub 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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### 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 NO x

### and SO 2 

### emissions when coal is burned. The only reagent required for pollutio n control is limestone. The CCS concept is that an entrained-flow coal gasi fier is followed by stages of combustion air. The CCS burner is designed to prov ide the necessary time, temperature, and stoichiometry required for all the chemicals incoal to complete their combustion reactions (to reach equilibrium conditions). The coal, with limestone added as a source of calci um for sulfur capture, is pulverized and introduced to the burner along with a limited amount of hot combustion air. The initial high-temperature combustion gasif ies and/or releases all the constituents of coal into the gas; i.e., carbon, sulfur, nitroge n, and ash compounds. At these high temperatures and with limited available oxygen, the carbon aggressively commands oxygen to form CO from all sources, including such compounds as water (H 2 

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

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

### ) by the aggressive action of carbon for oxygen. In the presence of calcium, the sulfur reacts to fo rm 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 boile r. Hot gases, high in CO and H 2 

### and nearly free of NO x

### and sulfur, exit into the boiler furnace. As the gases cool and generate steam, additional OFA is added in stages to the furnace to complete the combustion of CO to CO 2 

### and H 2 

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

### and completes the combustion with excess air. The clean hot gases then enter the boiler superheat section as before the retrofit. Aschematic 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.Identification of All Available Retrofit

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### 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 applicati on 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 origina l and the enhanced versions of the technology have been installed at several industria l 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 adsorber 10

### located after the primary particulate control devices and asorbent regenerator. In the adsorber, the flue gas passes through a bed of AC moving slow ly 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 inject ed into the flue gas, typically as it enters the adsorber. SO 2 

### , SO 3 

### , NO x 

### , mercury, and additional particulates (along with associated trace metals) are removed in the adsorbe r in one step, and the pollutant saturated AC is regenerated in the regenerator, whe re it is conveyed through a bucket elevator. The regenerator operates at temperatures in the 750° F to 930° F range. Simultaneously, sulfuric acid or ammonium compounds in the AC are decomposed to nitrogen (N 2 

### ), SO 2 

### , and water. Mercury is retained in the AC and removed from the unit every few years, depending on the mercury concentrations at the inlet of ReACT. After cooling, the regenerated AC passes through a vibrat ing screen to eliminate the mechanically degraded AC and captured dust; then, i t 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 adsor bent. SO 2 

### -rich gas from the regenerator is converted to a salable product, such as sulfuric acid and gypsum, in the byproduct recovery facility.

10 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 activat ed coke, its reaction vessel is termed an “adsorber.” “Absorption” refers to a chemical reaction in whic h the material (the solute) is absorbed into the bulk of the solvent medium. An example is the absorption o f SO 2 in an alkaline liquid in a wet spray tower, and its reaction vessel is termed an “absorber.”Identification of All Available Retrofit

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### 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 pelle ts have been reformulated to be more durable. These upgrades have substantially reduced adsorber size and coke attrition. Consequently, they have reduced the capital cost, c oke replacement cost, and required footprint. Lastly, slipstream testing has demonstrated 90 perc ent mercury removal with the ReACT system. An EPRI slipstream test of the techn ology 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 b oiler as that at the Boardman Plant burning PRB coal. Therefore, the technology was no t considered to be technically feasible for application at the Boardman Plant and w as not evaluated further.Technically Feasible Retrofit Emission

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## 4.0 Technically Feasible Retrofit Emission Contro l

Technologies (Step 2)

Step 2 of the BART/Reasonable Progress analysis con sisted of limiting the list of potential control technologies developed in Step 1 by eliminating technically infeasible options. In order for a technology identified in S tep 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 feasibl e” 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 co nsidered available. The fact that a technology is considered available is not a suffici ent basis for concluding that a technology is applicable, and, therefore, technical ly feasible. That technology must have been used in the same or a substantially similar source typ e to be considered applicable. For all the technologies identified as available inSection 3.0, a determination was made on the technical feasibility of the technologyat the Boardman Plant site according to the evaluative process identified by the EPA.


## 4.1 Technically Infeasible NO x

## Control Technologies 4.1.1 ECOTUBE Since most of the existing installations of the ECO TUBE 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 smal l-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 NO x 

### 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

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### 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 pr eheater. 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 BoardmanPlant boiler was not designed with space in the ductwork or with an appropriate temper ature 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 th e gas path temperature (and velocity) to the desired range while still maintaining the air t emperature exiting the air preheater to the pulverizer in order to properly dry the coal an d maintain combustion efficiency, the SNCR/SCR hybrid system was considered as not technically feasible.


## 4.2 Technically Infeasible SO 2 

## Control Technologies 4.2.1 Dry Flue Gas Desulfurization Dry FGD using a CDS or similar technology has been applied only to boilers rated up to a maximum of 300 MW. Furthermore, most applications of this technology are typically on circulating fluidized bed boilers and not pulverized coal boilers such as the boiler at the Boardman Plant. Therefore, this technology was considered as not technically feasible.
4.2.2 Furnace/Duct Reagent Injection Furnace or duct reagent injection is considered as n ot technically feasible because of the lack of installations on boilers in the same size range as the boiler at the Boardman Plant.


## 4.3 Technically Infeasible PM Control Technologie s 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. T herefore, this technology was considered as not technically feasible.
4.3.2 Multiple-Cyclone Collector Because of the lower efficiency of multiple-cyclon e collectors in reducing PM emissions, this technology is not capable of contro lling PM emissions better than the currently existing ESP. Therefore, this technologywas not considered further in the analysis.Technically Feasible Retrofit Emission

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## 4.4 Technically Infeasible Emerging Pollution Con trol 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 syste m was not considered as technically feasible.

4.4.2 Enviroscrub The Enviroscrub technology is currently in pilot-sc ale 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 commercia l-scale installation in a boiler similar in size to the one at the Boardman P lant. 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 slipstr eam testing in a North American plant. Therefore, this technology was not considered technically feasible for application at the Boardman Plant.


## 4.5 Summary of Retrofit Emission Control Technolo gies 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 B oardman Plant boiler, and these technologies were the basis for the existing BART NO x

### limits which PGE is not requesting be modified, SCR and SNCR are evaluated as additional control technologies.Technically Feasible Retrofit Emission

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### Table 4-1 Technically Feasible NO x

### Control Technologies

Technology Technically Feasible and Applicable? Reasons for Technical Infeasibility 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 feasibl e 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. NO x 

### Star and NO x 

### Star Plus No No existing installation at similar ty pe/size source. ECOTUBE No No existing installation at similar type/size so urce. 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 s imilar type/size source.Technically Feasible Retrofit Emission

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### Table 4-2 Technically Feasible SO 2 

### Control Technologies

Technology Technically Feasible and Applicable? Reasons for Technical Infeasibility Wet FGD Yes -- Semi-Dry FGD (SDA/FF) Yes -- Dry FGD (CDS) No No installation at unit larger than 300 MW. Furnace/Duct Reagent Injection Reduced Sulfur Coal Restriction No Yes No existing installation at similar type/size sourc e.

Technically feasible at levels of 0.60 lb/MMBtu or great er (as emitted—annual average) after June 30, 2014

Table 4-3 Technically Feasible PM Control Technologies

Technology Technically Feasible and Applicable? Reasons for Technical Infeasibility PJFF Yes -- COHPAC Yes -- GE MAX-9 Hybrid No No commercial installation at si milar sized source. Multiple-cyclone collector No Level of emissions control is less effective than currently existing ESP. WESP Yes --Technically Feasible Retrofit Emission

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### Table 4-4 Technically Feasible Emerging Pollution Control Technolo gies

Technology Technically Feasible and Applicable? Reasons for Technical Infeasibility PowerSpan No No commercial installation at similar sized sour ce. Enviroscrub No No commercial installation at similar sized sourc e. Phenix Clean Coal No No commercial installation at sim ilar sized source. J-Power ReACT No Has only been slipstream tested for evaluation before commercial installations in North America.Technically Feasible Retrofit Emission

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## 5.0 Evaluation of Technically Feasible Retrofit E mission

Control Technologies (Step 3)

Step 3 of the BART/Reasonable Progress determinati on 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 he at 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 monthdata 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) NO x

### September 2003 48,630,688 SO 2 

### August 2005 48,571,330 PM March 2004 49,093,487

Tables 5-2 to 5-4 identify the baseline emissions and the control effecti veness for each control technology. The tables show the contr ol 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

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### Table 5-2 NO x

### 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

Since New LNBs/MOFA is acknowledged as the BART NO xcontrol technology, no further assessment of the above NO xcontrol technologies with NO xemissions higher than 0.23 lb/MMBtu is included in the analysis. New LNBs/MOFA 0.23 5,593 New LNBs/MOFA/SNCR 0.19 4,620 New LNBs/MOFA/SCR 0.07 1,702



### Table 5-3 SO 2 

### 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 0.60 14,571 Semi-Dry FGD 0.12 2,914 Wet FGD 0.07 1,700Technically Feasible Retrofit Emission

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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 b y US EPA Method 5.Boardman Plant Impact Analysis (Step 4)

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## 6.0 Impact Analyses (Step 4)

6.1 Types of Impact Analyses For all the technologies considered, impact analyse s were performed as part of the BART/Reasonable Progress determination process. Th e 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 i mpact 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 pe rformed 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 techni cally feasible. The design parameters contain all pertinent informationon the control technology system for specific application to the source. Examples of th ese design parameters include: type of reagent used and consumption rate, type of byproduc t produced and production rate, flue gas pressure drop across the control technology, et c. The information used to define the design parameters included the following:

x Information from equipment vendors.

x Background information documents used to support Ne w 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)

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### The design parameters for each control technology that has been identified as technically feasible for application at the BoardmanPlant 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 inv estment for each control technology when applied specifically to the Boardman Plant sit e and the annual operating and maintenance costs were calculated. These cost calc ulations 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 in-house engineering estimates.

6.2.2 Energy Impacts Energy impacts are estimated for each control techn ology that has consumption of auxiliary energy during its operation. Only direct energy impacts for each control technology, such as the auxiliary power consumptionof the control technology and the additional draft system power consumption to overco me the additional system resistance of the control technology in the flue gas flow path, are accounted fo r. Indirect energy impacts, such as the energy to produce raw material s used for the control technology system, are not considered. The auxiliary power co nsumption estimates for each control technology are based on the typical power consumpti on 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 NO x 

### emissions, SCR has materially higher energy impacts compared to SNCR. The use of an SCR creates additional back pr essure that the SNCR system does not cause; additional energy consumption is require d to overcome the additional system resistance of an SCR. Between the three top-ranked control technologies f or SO 2 

### 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 energ y penalty (parasitic load). The imposition of a reduced sulfur coal restriction results in no negative energy impacts.Boardman Plant Impact Analysis (Step 4)

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### A COHPAC system consumes more auxiliary energy and ID fan power than a fabric filter, a dry ESP, or a wet ESP. Because th e COHPAC uses both dry ESP and FF technologies, the flue gas pressure drop for a COHP AC system is higher than for either a FF or a dry ESP. Similarly, since the COHPAC must o perate 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 PMcontrol, the cost factor used for maintenance labor and materials is higher for a COH PAC 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 dispos al requirements for the byproduct and waste generated by each control technology. Som e of the control technologies generate wastes and/or detrimental byproducts, use excessive water, and/or cause unsightly plumes. In addition, certain control tec hnologies 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 environme ntal impacts. SCR catalysts must be replaced approximately every 3 years, thus creating a potentially hazardous waste stream, and SCRs requir e 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 differ ences in system use). Both an SNCR and an SCR system will have ammonia sl ip. Although SNCR systems typically inject urea, ammonia is produced in the hot injection environment. The majority of the ammonia slip will be collected withthe fly ash, and may impact the fly ash quality. Any ammonia slip not collected with the fly ash will negatively impact visibility. In Appendix D to the 2009 Oregon Regio nal Haze Plan, DEQ rejected SNCR as an emission control technology due to reagent st orage and handling safety concerns, the ammonia slip, and the additional water required to keep the boiler system free of slag (App. D; p. D-29). Similar concerns were expressed in relation to SCR, in addition to concerns regarding ammonium bisulfate formation that could damage the air preheater and the impacts associated with disposal of the spe nt catalyst. These non-air quality environmental impacts associated with SNCR and SCR are equally of concern today and support rejection of either technology as BART. Both wet and semi-dry FGD present significant non-a ir quality environmental impacts. As noted by DEQ in Appendix D to the Regi onal Haze Plan, the wet FGD has multiple severe non-air quality environmental impac ts, including that it generates a visible plume, consumes more water, requires water treatment, generates corrosiveBoardman Plant Impact Analysis (Step 4)

040210 6-4 

### exhaust gases, and generates a wastewater stream requiring disposal. The s emi-dry FGD technology also presents non-air quality environmental impacts including water consumption in an arid region and the generation of solid byp roducts for landfill. The imposition of a reduced sulfur coal restriction results in no non-air quality environmental impacts as the Boardman Plant is alre ady handling coal and the reduced sulfur coal would be a direct substitution.
6.2.4 Existing Controls The Boardman Plant has existing controls for NO x 

### , SO 2 

### and PM. At the time the Boardman Plant was permitted, the NTEC, working in association with DEQ and the public, established emission control requirements r eflective of BACT that were imposed on the plant. These included the use of low NO x

### burners for NO x

### control, low sulfur coal for SO 2 

### 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 th ose 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 usefu l life of a facility be considered in determining BART and Reasonable Progr ess. Remaining useful life is most often considered when there is an effect on th e annualized costs of the retrofit controls for capital recovery. This occurs when th e 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 requ ire that remaining useful life not be evaluated solely as an element of the cost of compl iance. 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 s hutdown date. Ceasing operation of the Boardman Plant boiler is s et as no later than December 31, 2020. Thus, the remaining useful life for all S O 2 

### post-combustion controls and all PM control systems is 6.5 years. The remaining usefullife of NO x

### combustion control systems is 9.5 years. The remaining useful life of an SCR system and an SNCR system is 4.5 years and 6.5 years, respectively. The remaini ng useful life values of the controls are calculated based on the anticipated dates for start up of control equipment and theBoardman Plant Impact Analysis (Step 4)

040210 6-5 

### 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 sp read over a small number of years. Aside from the impact on cost of compliance, the lo ng term environmental and visibility benefits from the ceasing operation of the BoardmanPlant 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 d etermination 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 identi fy 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 cr iterion for determining Reasonable Progress. As a result, control technologies that t ake longer to implement are presumably less appropriate for Reasonable Progress and the ti me 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 propos ing to accept federally enforceable requirements to implement LNB/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 reductionfrom baseline emissions. Both the baseline emissions and post-control emissions value s are documented in the Design Concept Definition sheets located in Appendix C. 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 le ss of it, it is located in limited seams and demand is high. In addition, the limited availabil ity of reduced sulfur coal introduces a supply risk. However, until a contract is negotiat ed it is difficult to project actual coal prices. Therefore, the cost-effectiveness associat ed with the use of a reduced sulfur coal is addressed qualitatively rather than quantitative ly.Boardman Plant Impact Analysis (Step 4)

040210 6-6 

### Two types of cost-effectiveness are calculated duri ng the BART/Reasonable Progress determination: average and incremental co st-effectiveness. The general definition of the two types of cost-effectiveness c an 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 feasib le control technologies. Summaries of the calculated cost impact analyses are presented in Append ix D. EPA stated that “Although States may in specific ca ses find that the use of SCR is appropriate, we have not determined that SCR is gen erally 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 to tal annualized cost versus the expected emissions reduction for all control alternatives id entified in the BART/Reasonable Progress analyses (Figures 6-1, 6-2, and 6-3). From the graphical plots, a “least-cost envelope” f or 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 th e BART/Reasonable Progress determination. Dominant controls are the technolog ies 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 red uction, 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 additi onal cost to increase the emissions reduction when comparing technologies that have different e missions removal capability. For NO x 

### , the evaluation generates the same results as thos e in DEQ’s BART analysis incorporated into the Regional Haze Plan. However, NO x

### was also evaluated in relation to Reasonable Progress. In that instance, the NLNB/MOFA would be part of the baseline evaluation. Therefore, the additional cos ts associated with adding SCR or SNCR to NLNB/MOFA would be evaluated in relation to the additional air quality benefits achieved by adding SCR or SNCR to NLNB/MOFA.Boardman Plant Impact Analysis (Step 4)

040210 6-7 

### Table 6-1 BART/Reasonable Progress Impact Analysis and Cost-Effe ctiveness Results

Emission Expected Expected Total Incremental Performance Emission Emission Capital Annualized Cost Cos t Energy Non-Air Level Rate Reductions Costs Cost Effectiveness Effectiven ess Impacts Impacts All Feasible Technologies (lb/mmBtu) (tons/yr) (tons/year) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$) NO xControl Technologies Baseline 0.43 10,349 -- -- -- -- -- -- -- New LNBs with Modified OFA System 0.23 5,593 4,863 35,683 5,963 1,226 -- 26 -- NLNBs, MOFA, and Selective Non-Catalytic Reduction (SNCR) 0.19 4,620 5,836 50,366 10,401 1,782 4,563 26 -- NLNBs, MOFA, and Selective Catalytic Reduction (SCR ) 0.07 1,702 8,754 227,375 62,512 7,141 17,859 934 1

SO 2 Control Technologies Baseline SO2 0.61 14,911 -- -- -- -- -- -- -- Reduced Sulfur Coal Restriction 0.60 14,571 340 0 -- -- -- -- -- Semi-Dry FGD (including Fabric Filter) 0.12 2,914 11,997 270,218 67,032 5,587 -- 1,621 790 Wet FGD (including Fabric Filter) 0.07 1,700 13,211 417,837 101,828 7,708 28,656 6,610 939
PM Control Technologies Blaseline PM 0.017 417 -- -- -- -- -- -- -- Compact Hybrid Particulate Collector (COHPAC) 0.012 2 95 123 88,310 22,920 186,738 -- 1,408 -- Pulse Jet Fabric Filter (PJFF) 0.012 295 123 100,442 23,572 192,050 Not Applicable 1,047 -

- Wet ESP 0.012 295 123 196,334 42,999 350,329 Not Applicable 652 --

Notes:
1. All costs are in 2010 US$ 2. Incremental costs are based on: a) NLNB, MOFA, and SNCR incremental cost relative t o NLNB, MOFA b) NLNB, MOFA, and SCR incremental cost relative to NLNB, MOFA, SNCR c) Wet FGD incremental cost relative to Semi-Dry FG D 3. Non-Air Impacts are costs associated with Non- A ir Quality Environmental Impacts including generate d wastes or detrimental byproducts, and excess wate r consumedBoardman Plant Impact Analysis (Step 4)

040210 6-8

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 NO x

### Control Cost-EffectivenessBoardman Plant Impact Analysis (Step 4)

040210 6-9

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 

### Figure 6-2 SO 2

### Control Cost-EffectivenessBoardman Plant Impact Analysis (Step 4)

040210 6-10

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-EffectivenessBoardman Plant Impact Analysis (Step 4)

040210 6-11 

### For SO 2 

### , the qualitative consideration of reduced sulfur c oal generates a very different result from that incorporated into the Regiona l Haze Plan. With the introduction of an option that reduces the allowable SO 2 

### emission rate by 50 percent by July 1, 2014, presents no energy or non-air quality impacts, and presents acceptable economic impacts, the analysis for SO 2 

### BART profoundly changes.

6.4.1 NO

x 

### Control Technologies In addition to the NLNB/MOFA system being implement ed, SNCR and SCR were compared to determine their respective improvem ent to visibility in the Class I areas. Of the two, the control package utilizing S CR has significantly greater costs of compliance. Both technologies have negative energy impacts and negative non-air quality environmental impacts. Therefore, consiste nt with the regulations in the current Regional Haze Plan, neither SCR nor SNCR are approp riate as supplements to NLNB/MOFA in establishing BART/Reasonable Progress limit s.

6.4.2 SO 2



### Control Technologies Both technically feasible SO 2 

### post-combustion control technologies as well as the most effective technically feasible SO 2 

### 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 compare s favorably to the post-combustion control technologies. Of the two post-combustion c ontrols, the costs of compliance and the negative non-air quality environmental impacts are greater for the wet FGD control technology. The most effective pre-combustion contr ol technique (reduced sulfur coal restriction of 0.60 lb/MMBtu, as emitted SO 2 

### ) presents none of the negative non-air quality environmental impacts presented by the post -combustion controls. Instead, the imposition of a reduced sulfur coal restriction is consistent with the concept of pollution prevention and avoids the potential to shift the po llutant to another media. Both postcombustion control technologies pose high costs of compliance when compared to adoption of a reduced sulfur coal restriction 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 existingsource will be very short if the regulations are modified to impose December 31, 202 0 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 boiler becomes a controlling criterion. The use of reduced sulfur coal (0.60 lb/MMBtu, as emitt ed SO 2 

### , annual average) should constitute BART for SO 2 

### , particularly if a December 31, 2020 deadline for ceasing operation of the Boardman Plant boiler is added to the rules.Boardman Plant Impact Analysis (Step 4)

040210 6-12 

### 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 t otal annualized cost for either a COHPAC or a fabric filter system is around $23 mill ion. A wet ESP has significantly higher annualized cost. However, all three technologies pose high costs of compliance when considered in relation to the existing control s 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 reg ulations are modified to impose December 31, 2020 as the date by which PGE must cea se operation of the Boardman Plant boiler. In light of such a commitment, the r emaining 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/Reaso nable Progress limits.Boardman Plant Visibility Impacts (Step 5)

040210 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 pro cess. 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 control s and the post-BART controls analyses. Modeling analyses were conducted using CALPUFF (ver sion 6.131). First, emissions associated with pre-BART controls were mo deled to establish the baseline for the pre-BART control analyses. Second, individual post-BART control technologies were analyzed for use in selecting final control alternative s. The methodology used in this analysis was presented in Protocol for the Application of CALPUFF Determination Modeling Pursu ant to BART Regulation—PGE Boardman Plant (Revised) (Protocol) (CH2M HILL, 200 7). The protocol was initially approved by DEQ on January 18, 2007. As specified i n the protocol, all Class I areas within a 300 kilometer (km) radius of the plant wer e included in the analysis. In addition, although not a Class I area, the Columbia River Gor ge 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 DE Q approval are provided in Appendix F. The following sections discuss in greater detail th e 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 trans formation, and plume fumigation. The modeling system is supported by three primary p rograms:

x CALMET Version 6.211, Level 060414

x CALPUFF Version 6.112, Level 060412

x CALPOST Version 6.131, Level 060410Boardman Plant Visibility Impacts (Step 5)

040210 7-2 

### CALMET is used to create three-dimensional wind fie lds based on geophysical and meteorological data. The CALMET data used in CALPUFF was provided by DEQ and included meteorological data for 2003, 2004, an d 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 o f 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 visibil ity exceeds 0.5 deciview was calculated for each year modeled to address frequency of v isibility impacts. Fourteen Class I areas and the CRGNSA were evaluate d. A figure showing the modeling domain covering these areas is included inAppendix F in the modeling protocol. The modeling domain was established to en compass 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 a s 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 pe riod was developed by Eri Ottersburg (SLR International) and Mary Beth Yansur a (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 Protocoland the modeling protocol providedBoardman Plant Visibility Impacts (Step 5)

040210 7-3 

### in Appendix F. The ozone data incorporated in the f ile 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 accep ted for use in BART modeling. Acceptance of this approach was documented in a mem o from Phil Allen of Oregon DEQ to Ray Hendricks of PGE dated August 28, 2007. A c opy 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 scenar io. Emission rates and stack parameters have been revised since the January 2007 protocol to reflect 2010 design information. The PM 10 

### emissions provided included the front half filterable emissions only. Other particulate species emissions (element al carbon, fine PM, coarse PM, organic carbon, and inorganic condensables (SO 4 

### )) were calculated in accordance with National Park Service speciation guidelines for dry -bottom pulverized coal boilers 11 

### . As such, NPS speciation of PM emissions are a functionof 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 in cluded with all modeled pollutant species as follows:

x Nitrates (NO x 

### ).

x Sulfur Dioxide (SO 2 

### ).

x Nitric Acid (HNO 3 

### ) (modeled, not emitted).

x Total PM/PM 10 

### :

- 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 (SO 4 

### ).

 0.0 % Non-SO 4 

### Inorganic Aerosol (NO 3 

### ).

11 http://www.nature.nps.gov/air/permits/ect/ectCoalF iredBoiler.cfm.Boardman Plant Visibility Impacts (Step 5)

040210 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. Indiv idual PM control technologies were not evaluated because of the small contribution PM make s to visibility compared to NO X

### and SO 2 

### in the baseline modeling. The total visibility imp act related to PM control technologies for the baseline modeling was less than two percent. Furthermore, SO 2 

### control technologies include a PJFF system. The control technologies evaluated include three NO X

### controls, three SO 2 

### controls with PJFF, and one combined NO X

### and SO 2 

### with PJFF control:

x NO x 

### :

- 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 SO 2 

### and PM:

- Wet FGD and PJFF (WFGD/PJFF).

- Semi-Dry FGD and PJFF (SDFGD/PJFF).

- 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 dif ferent 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 i mpacts 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 contr ol scenario shows the highest impacts out of all of the post-BART control scenari os. However, the maximum impacts are statistically similar and between 3 to 4 delta- deciviews. A similar distribution is shown for the minimum impacts of each scenario. Ad ditionally, Table 7-1 shows the number of days where the change in visibility exceed s 0.5 delta-deciview. Again, impacts in terms of days for all other scenarios are statistically similar.Boardman Plant Visibility Impacts (Step 5)

040210 7-5 

### Table 7-1 Visibility Impact and Improvement Summary

Impacts in Terms of ǻ dv(1)

Scenarios Max Impact Max Improvement Min Impact Min Improvement Baseline 5.14 -- 1.15 --
NO XControls NLNB/MOFA 3.85 1.29 [29.6%] 0.85 0.25 [18.6%] NLNB/MOFA/SNCR 3.66 1.48 [33.3%] 0.83 0.30 [21.8%] NLNB/MOFA/SCR 3.25 1.89 [42.3%] 0.69 0.44 [29.5%] SO 2 Controls
RSCR 4.64 0.50 [18.6%] 1.02 0.14 [6.6%] SDFGD/PJFF 3.76 1.38 [48.9%] 0.70 0.42 [24.0%] WFGD/PJFF 3.91 1.23 [49.2%] 0.66 0.49 [23.9%] Impacts in Terms of Days > 0.5 ǻ dv (2)

Scenarios Max Impact Max Improvement Min Impact Min Improvement Baseline 324 -- 60 --
NO XControls NLNB/MOFA 239 103 [34.9%] 40 20 [11.5%] NLNB/MOFA/SNCR 234 111 [42.2%] 37 23 [13.3%] NLNB/MOFA/SCR 212 160 [61.4%] 29 31 [21.5%] SO 2 Controls
RSCR 278 46 [23.3%] 46 6 [3.3%] SDFGD/PJFF 235 129 [57.8%] 28 32 [13.0%] WFGD/PJFF 233 150 [61.4%] 26 34 [13.7%]
Highest value of all scenarios presented shown in boldtext. (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 the entire 3-year monito ring period.Boardman Plant Visibility Impacts (Step 5)

040210 7-6 

### Maximum visibility improvements are also provided i n Table 7-1 both in terms of deciviews and reduction in days with visibility imp acts greater than 0.5 delta-deciviews. The improvement in deciviews represents the best im provement seen in any Class I area when comparing the 98 th

### percentile delta-deciview between the control scen ario and 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 recept ors; 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)

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### Table 7-2 Hells Canyon and Mount Hood Visibility Improvement Summa ry
Improvement Over Baseline in Terms of ǻ dv(1) – Mount Hood Scenarios Maximum Improvement NO XControls NLNB/MOFA 1.29 [25.0%] NLNB/MOFA/SNCR 1.48 [28.8%] NLNB/MOFA/SCR 1.89 [36.8%] SO 2 Controls RSCR 0.50 [9.7%] SDFGD/PJFF 1.38 [26.8%] WFGD/PJFF 1.23 [23.9%]

Improvement Over Baseline in Terms of Days Reduced < 0.5 ǻ dv(2) – Hells Canyon Scenarios Maximum Improvement NO XControls NLNB/MOFA 103 [31.8%] NLNB/MOFA/SNCR 111 [34.3%] NLNB/MOFA/SCR 160 [49.4%] SO 2 Controls RSCR 46 [14.2%] SDFGD/PJFF 129 [39.8%] WFGD/PJFF 150 [46.3%]
Highest value of all scenarios presented shown in boldtext. (1) Based on maximum of annual 8 thhighest and 3-yr 22 nd 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

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## 8.0 Selection of Best Alternative

The CAA and the Guidelines specify that after gathe ring 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 Re asonable Progress. The BART factors, identified in CAA Sect ion 169A(g)(2) and codified in 40 C.F.R. § 51.308(e)(1)(ii), are: (1) the costs of c ompliance, (2) the energy and non-air quality environmental impacts, (3) any existing pol lution 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 Sect ion 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 li fe. Consistent with the EPA guidelines and the statutor y 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/Reasonable Progress The three technology options identified in Table 5-4, each offered the sam e degree of control. All of the options have extreme ly 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 systemthat need to be addressed. The COHPAC system is a less common technology, and limited operating experiences are available. Secondly, the removal o f 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 filteri ng 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 p articles, which are less effective at filtering PM. Additionally, the filter bags will p lug 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 th e above mentioned issues, but these custom bags will cost more.Boardman Plant Selection of Best Alternative

040210 8-2 

### The Boardman Plant’s existing controls include a hi ghly efficient dry ESP for PM control. Since the cost effectiveness of any addit ional control technology is so high, additional PM control technologies cannot be justif ied as either BART or Reasonable Progress. Therefore, continued use of the existing ESP is considered BART/Reasonable Progress for particulate control.



## 8.2 Selection of SO 2 

## BART/Reasonable Progress Due to the Boardman Plant boiler’s short remaining u seful life, neither a wet FGD nor a semi-dry FGD could be justified for SO 2 

### control. The most economical postcombustion control option for SO 2 

### control is the semi-dry FGD with a capital cost of $270 million and an annual operating cost of $13.8 million. Due to the short Boardman Plant boiler operating life, the annual expense for the semi-dry FGD is over $67 million per year. The other post-combustion control option, a Wet FGD, is significantly more expensive than the semi-dry FGD, resulting in an annual cost of nearly $86 million per year. Neither of these costs are reasonable and th erefore excessive economic impacts are a basis for not considering either post-combustion control technology as appropriate for BART or Reasonable Progress. By contrast, the impo sition of a reduced sulfur coal limit reducing the allowable SO 2 

### emissions by 50 percent poses additional fuel costs 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/Reasonable Progress analysis where the cost of installing and operating the controls is judged to have a severe impact on plant operations and plant viability. Since anySO 2 

### 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 post-combustion control technology is viable. However, because pre-combustion controls i nvolve primarily operating cost and limited capital cost, this technology is not as sensitive t o the early shutdown date. The non-air quality environmental and energy impact s are significant for both post-combustion 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 F GD and over 600 gallons/minute for wet FGD). In the arid area of eastern Oregon where the Boardman Plant is lo cated, water is a scarce commodity. A water-intensive process s uch as these could have an unnecessary impact on the regions existing water resources. Finally, the energy impacts are significant for both technologies, semi-dry FGD using 4,355 kW and a wet FGD consuming 16,249 kW. By contrast, the adoption of a reduced sulfur coal restriction imposes no non-air quality environmental impacts as it relies upon pollution prevention,Boardman Plant Selection of Best Alternative

040210 8-3 

### 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 are not sufficient to merit their choice as BART. The visibility modeling demonstrated that both wet and semi-dry FGD result in an approximatel y 18-20 percent reduction in the number of days at the Mt. Hood Wilderness Area with impacts greater than 1 deciview. Adoption of a reduced sulfur coal restriction would reduce the number of days at the Mt. Hood Wilderness Area with impacts greater than 1 de ciview by approximately 7 percent. Therefore, while the visibility improvements attrib utable to post-combustion controls are greater than those attributable to the imposition o f a reduced sulfur coal restriction, the marginal benefits are limited. Were either post-co mbustion control required as BART or Reasonable Progress, then the Boardman Plant boiler would need to be run beyond the proposed closure date in order to ease the cost rec overy schedule. By contrast, if the reduced sulfur coal restriction is imposed as BART then the allowable SO 2 

### emission rate would drop by half and the visibility impacts on th e 98th percentile day would improve by 11 percent (as compared to 27 percent for the se mi-dry FGD). The short and long term benefits (e.g., improved visibility, reduced g reenhouse gases and criteria pollutants and reduced economic impacts to PGE’s customers) th at arise from employing 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 imposition of a reduced sulfur coal limit that ulti mately drops the allowable SO 2 

### emissions by 50 percent (20 percent in 2011 and 50 percent in 2014) and the adoption of a requirement to cease Boardman Plant boiler operati on by December 31, 2020 constitutes BART. Neither wet FGD nor semi-dry FGD were viable SO 2 

### control options for the Boardman Plant. Installation of either technology imposes su ch significant costs that the plant would potentially need to delay its planned boiler shutdown date of December 31, 2020. 12 

### In addition, the energy and non-air quality impact s of utilizing either technology are very costly. By contrast, the imposition of a reduced sulfur coal limit at the most restrictive end of the technicallyfeasible range (i.e., 0.60 lb/MMBtu, as

12 Nothing in the Clean Air Act grants DEQ the author ity to require cessation of operation of the Boardman Plant boiler as BART or Reasonable Progres s. However, PGE is free to propose an early closure date that is then taken into account in est ablishing BART and Reasonable Progress controls. I f DEQ concludes that either BART or Reasonable Progre ss requires SCR, FGD or upgraded PM controls, then PGE expressly withdraws consideration of premature closure of the plant as an element in the anal ysis.Boardman Plant Selection of Best Alternative

040210 8-4 

### emitted SO 2 

### , annual average) could be implemented by July 1, 2 014. Finally, consideration of remaining useful life independent of cost supports the concept that the interference with plant operations and risk of equi pment malfunctions is not merited where the boiler will shut down 6.5 years after inst allation. The implementation of reduced sulfur coal cannot be accelerated beyond July 1, 2014. No reduction in the SO 2 

### 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. During the interim period where the Boardman Plant was consumi ng the stockpiled coal, PGE could accept an SO 2 

### emission limit of 0.96 lb/MMBtu (annual average). This limit would reduce the allowable SO 2 

### emission rate by 20 percent two and one half years in advance of the current BART SO 2 

### limit taking effect. PGE projects that it would t ake until approximately June 30, 2014 to consume all of the s tockpiled coal. After that point, PGE believes that the BART SO 2 

### limit should be established as 0.60 lb/MMBtu (a 50 percent reduction from the current limit) through closure at the end of 2020.



## 8.3 Selection of NO X

## BART/Reasonable Progress The application of the statutory factors indicates that, because of the planned NLNB/MOFA system, no additional BART NO x

### controls are necessary or justified. 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). However, the env ironmental impacts associated with this technology support a conclusion that it is not appropriately considered BART. Therefore, this supplemental BART analysis reaches the same conclusion previously reached by DEQ and adopted by the EQC, namely that NLNB/MOFA is BART for the Boardman Plant boiler. Based on the statutory factors mandated by the Clean Air Act, the Reasonable Progress limit in OAR 340-223-0040 should be replac ed with a requirement that PGE cease operations of the Boardman Plant boiler no later than December 31, 2020. The Clean Air Act specifies that the cost of compliance, the time necessary for complianc e, the energy and nonair quality environmental impacts , and the remaining useful life of the existing source must be taken into consideration whe n determining Reasonable Progress. Consistent with the statute, it is appropriate to t ake into account the economic impact of particular controls in determining Reasonable Progr ess. The economic impacts associated with SCR are considerable—much higher th an the cost of complianceBoardman Plant Selection of Best Alternative

040210 8-5 

### associated with the BART NO x

### limits in the Regional Haze Plan. The capital cos t of the NLNB/MOFA is estimated as $35.7 million. The capit al cost associated with adding SCR to the (then) existing NLNB/MOFA system is appr oximately $192 million. Operating costs associated with SCR are similarly m uch higher than the operating costs associated with maintaining the NLNB/MOFA system required by BART. ($6.1 million per year for NLNB/MOFA/SCR as opposed to $0.7 milli on per year for NLNB/MOFA). As a result, the cost of imposing SCR as Reasonable Progress equates to over $14,500 per ton of NO x

### controlled. This is well outside the cost of compl iance associated with Reasonable Progress determinations in other states and well outside the range of what is a reasonable cost. Evaluation of the energy and non-air quality enviro nmental impacts also strongly support the conclusion that SCR is not an appropriate choice for Reasonable Progress. The energy consumption of SCR is 2,509 kW. The hig h level of SCR energy consumption is a result of the fan auxiliary power needed to overcome additional system resistance. The increased energy consumption result s in less electricity being available for distribution to the grid, thus decreasing plant efficiency. The non-air quality environmental impacts associated with the use of ei ther SCR are significant. 364 pounds per hour of anhydrous ammonia are injected into the exhaust for SCR. For a system the size of the Boardman Plant, this results in substantial ammonia slip emissions to the atmosphere which result in significant deposition an d visibility impacts. The Department has already indicated that the ammonia slip is a se rious concern. The amount of ammonia slip associated with an SCR system of the s cale needed for the Boardman Plant results in excessive non-air quality environmental impacts. In addition, if SCR is installed the plant will need to operate beyond Dec ember 31, 2020 in order to have a reasonable cost-recovery period. That means that adirect result of a requirement to install SCR is the emission of tens of millions of tons of carbon dioxide. As carbon dioxide is widely considered to contribute to climate change, the climate change impacts directly resulting from a requirement to install SC R must be considered. Therefore, the reduction of greenhouse gas emissions is a consider able nonair quality benefit resulting from not requiring that PGE install SCR to control NO x 

### . The remaining useful life of the Boardman Plant als o supports the conclusion that Reasonable Progress should not require NO x

### limits more stringent than those reflecting combustion controls. 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 Gu idelines suggest accounting for remaining useful life as a component of the cost of compliance. However, Congress expressly identified the remaining useful life of the plant as a criterion distinct andBoardman Plant Selection of Best Alternative

040210 8-6 

### separate from the cost of compliance criterion. Cons istent with these statements, DEQ and the EQC have already concluded that SCR is not considered BART. For the same reasons, SCR should not be considered as Reasonable Progress for NO x

### if PGE agrees to a fixed date being added to the regulations requirin g that PGE cease operation of the Boardman Plant boiler no later than December 31, 2020. As a result of the excessive economic, energy and non-air qua lity environmental impacts, as well as consideration of the time necess ary for compliance and the remaining useful life of the Boardman Plant, SCR does not constitute Re asonable Progress. PGE proposes that DEQ and the EQC revise the Regional Haze Plan to incorporate regulations mandating that PGE cease operation of the Boardman coal fired boiler no later than December 31, 2020 and remove the Reasonable Progres s NO x

### limits in OAR 340-223- 0040. PGE has no objection to and supports the Department retaining the current B ART NO x

### limits and deadlines in OAR 340-223-0030.


## 8.4 Visibility Improvement for Combined BART Cont rols As a final step in the evaluation, visibility impro vement was evaluated with the combination of controls identified as BART for particulate, SO 2 

### , and NO x

### (Table 8-1 and Appendix E). The modeling methodology used for this combination of controls evaluation was the same as the methodology summariz ed in Section 7.0. This control package includes the reduced sulfur coal restrictio n and NLNB/MOFA. 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 vis ibility impacts across all Class I areas of 39.4 percent and an improvement at the most severely impacted Class I area of 36.6 percent. There would be, on average, only 43 days 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 (reduced sulfur coal restriction and NLNB/MOFA). The modeling of the benefits predicted from the proposed BART control package show significant improvement in visibi lity in the CRGNSA. Table 8-1 summarizes the modeling results for the c ombination of reduced sulfur coal restrictions and NLNB/MOFA controls. As shownin Appendix E, the CRGNSA correlates reasonably well with maximum impacts at any Class I area.Boardman Plant Selection of Best Alternative

040210 8-7 

### Table 8-1 Visibility Impact Summary Boardman Plant BART Determination

Reduction in Number of Days Above 0.5 deciview at Highest Frequency Area - Hells Canyon Total (Percent Improvement) Reduction in Maximum Visibility Impact at Highset Magnitude Area - Mt Hood deciviews (Percent Improvement ) Combined Control Technologies 2003 2004 2005 2003-2005 (1)
NLNB/MOFA and Reduced Sulfur Coal Restriction (Best Available Retrofit Technology) 49 (42.6%) 50

(46.7%) 50

(49.0%) 1.879

(36.6%)

(1) Based on maximum of annual 8 thhighest and 3-yr 22 nd highest 24-hr impacts. NLNB/MOFA – New Low NO xBurners with Modified Overfire Air.Boardman Plant References

040210 9-1 

## 9.0 References

(1) CH2M HILL, Protocol for the Application of CALPU FF 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 Ap plication of the CALPUFF Modeling System Pursuant to the Best Available Retrofit Technology (BART) Regulation, October 11, 2006. (4) US Environmental Protection Agency (EPA), Intera gency 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 (B ART) Determinations , Federal Register , Vol. 70, No. 128, pp. 39104–30172, July 6, 2005. (7) Columbia River Gorge Air Quality Study Science Summ ary Report (September 24, 2007).Boardman Plant Appendix A

040210 A-1 

## Appendix A Design BasisBoardman Plant Appendix A

040210 A-2Boardman Plant Appendix A

040210 A-3Boardman Plant Appendix B

040210 B-1 

## Appendix B Stack Outlet ConditionsBoardman Plant Appendix B

040210 B-2Boardman Plant Appendix C

040210 C-1 

## Appendix C Design Concept DefinitionsBoardman Plant Appendix C

040210 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 n ormal operation. Existing OFA system currently onl y used when needed to meet permit limit due to efficiency impacts.

Pollutant NO x 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. Bo iler 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 NO xoptimization into combustion monitoring process.
Fan Modifications None. Power Supply/Aux Power Modifications No significantaux 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, NO xoptimization and monitoring systems added to overc ome boiler slagging issues to allow OFA system oper ations. 13% reduction expected.

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

Reasons Equipment is existing at plant but presently not us ed.Boardman Plant Appendix C

040210 C-3 

### Design Concept Definition
Site Name Boardman Units 1 Client Name Portland General Electric Process Technology Upgraded Low NO xBurners

Process Description Low NO xBurners (LNB) - Upgrade existing. Modifications o f burner tips and burner balancing using CFD modeli ng, combustion air monitoring and coal flow monitoring.

Pollutant NO x 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 impac t on ash sales Other N/A

Location of Major Process Equipment Upgrade/additio nal 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 wi thin acceptable levels. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construction activities including, but not limit ed to, offices, laydown, and staging. 10% reduction expected.

State of Availability Commercial. Technical Feasibility Technically feasible and applicable.
Reasons Low NO xBurners already in operation.Boardman Plant Appendix C

040210 C-4 

### Design Concept Definition
Site Name Boardman Units 1 Client Name Portland General Electric Process Technology Upgraded Low NO xBurners with Existing OFA System Operation

Process Description Upgrade existing Low NO xBurners (LNBs) with existing OFA system. Modifica tions of burner tips and burner balancing.

Pollutant NO x 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 impac t on ash sales Other N/A

Location of Major Process Equipment Upgrade existin g 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 wi thin acceptable levels. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construction activities including, but not limit ed to, offices, laydown, and staging. 40% reduction expected.

State of Availability Commercial. Technical Feasibility Technically feasible and applicable.
Reasons Low NO xBurners already in operation. Existing OFA system would be placed in operation full time.Boardman Plant Appendix C

040210 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 NO x 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 exis ting 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 c ause buildup of ammonium bisulfate on the air heate r, 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 limit ed 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

040210 C-6 

### Design Concept Definition
Site Name Boardman Units 1 Client Name Portland General Electric Process Technology Upgraded Low NO xBurners with Existing OFA System Operation and SNCR

Process Description Upgrade existing Low NO xBurners (LNBs) with existing OFA system. Modifica tions of burner tips and burner balancing. Selecti ve Non-Catalytic Reduction (SNCR) system for post-comb ustion reduction of NO x .

Pollutant NO x 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 equipme nt maintenance. Byproduct Description Slight increase in LOI and CO, No impac t on ash sales Other Up to 10 ppm ammonia slip.

Location of Major Process Equipment Upgrade existin g burners. Location remains the same. Injection s kid and ammonia tank at grade with truck unloading station. Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Instal l 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 wi thin acceptable levels. Ammonia slip may cause bui ldup 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 limit ed to, offices, laydown, and staging. No boiler/duct stiffening included and no impact onash sales. Reagent for SNCR is urea. Upgraded Low NO xBurners and OFA system operation reduces reagent c onsumption for SNCR because of lower NO xconcentration. 50% reduction expected.

State of Availability Commercial. Technical Feasibility Technically feasible and applicable.
Reasons --Boardman Plant Appendix C

040210 C-7 

### Design Concept Definition
Site Name Boardman Units 1 Client Name Portland General Electric Process Technology New Low NO xBurners with Modified OFA System

Process Description New low NO xburners (LNB), modified overfire air (OFA) system. Install new OFA ports at location to be determine d during detailed engineering analysis.

Pollutant NO x Emissions lb/MMBtu 0.426 ton/yr 10,349 Controlled Emissions lb/MMBtu 0.23 ton/yr 5,593 Inlet Flow Basis, acfm 3,307,813 Pressure Drop Added NA Coal Source and Type PRB Capacity factor 85.0%

Consumables Reagent None Energy N/A kW Other None Byproduct Description Slight increase in LOI and CO. No impac t on ash sales Other N/A

Location of Major Process Equipment Install new bur ners 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 coa l pipes. Reagent Storage None. Control System Modifications Existing control syste m 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 wi thin acceptable levels. Other Assumptions

x Water cannon system, NO xoptimization, and monitoring systems added to over come boiler slagging issues to allow OFA system ope rations

x No major impact in plant availability.

x The site has sufficient area available to accommod ate construction activities including, but not limi ted to, offices, lay-down, and staging.

x No air heater modifications or boiler/duct stiffen ing included.

State of Availability Commercial. Technical Feasibility Technically feasible and applicable.
Reasons Replacing older low NO xburners already in operation and modifying OFA sys tem to support current technology low NO xburners is common retrofit system.Boardman Plant Appendix C

040210 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 Sele ctive Noncatalytic Reduction (SNCR)

Process Description Selective Noncatalytic Reduction (SNCR) used in con junction with new low NOx burners and modified over fire air

Pollutant NO x 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 exis ting 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 c ause buildup of ammonium bisulfate on the air heate r, which may require more frequent cleaning. Other Assumptions

x No major impact in plant availability.

x The site has sufficient area available to accommod ate construction activities including, but not limi ted 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

040210 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 Sele ctive Catalytic Reduction (SCR)

Process Description Install a new SCR system in conjunction with new Lo w NOx Burners and Modified Overfire Air. Pollutant NO x 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 eve ry 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 rea ctor 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 ente ring 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 syste m modification to utilize new equipment. Fan Modifications Assume booster fans and duct stiffening will be req uired. Power Supply/Aux Power Modifications Assume medium cost expansion will be required for aux electric sy stem. Enclosures Requirements Ammonia injection grid area and sonic horns are to be enclosed. Demolition or Relocation Requirements Existing econ omizer outlet ductwork and boiler building wall. Major Constructability Issues Finding support steel location under SCR reactor. Tying the SCR into th e ductwork downstream of the economizer in the ductwork. Significant Issues or Challenges Ammonia slip in th e SCR may cause ammonium bisulfate formation on the air heater and require more frequent cleaning. SO 2 to SO 3 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 outletis acceptable after modifications of boiler superh eater section.

x The site has sufficient area available to accommod ate construction activities including, but not limi ted to, offices, lay-down, and staging.

x Air heater modifications, flue gas handling system s 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 temperatur e for SCR operations.

x No impact on potential ash sales and no additional heating i.e. economizer bypass or duct burners req uired to achieve operating temperature at low loads

. x Reagent is ammonia and can be anhydrous, aqueous o r 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 requireme nts to overcome SCR system resistance.

State of Availability Commercial. Technical Feasibility Technically feasible and applicable.
Reasons --Boardman Plant Appendix C

040210 C-10 

### Design Concept Definition
Site Name Boardman Units 1 Client Name Portland General Electric Process Technology Wet Flue Gas Desulfurization (FGD) and upstream Fab ric Filter

Process Description Limestone forced oxidation wet flue gas desulfuriza tion process (wet scrubber) with fabric filter upst ream of wet scrubber for mercury and particulate control. Description is typical fo r all absorber/scrubber based FGD systems. Pollutant SO 2 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 (CaSO 3 x 1/2H 2 0), Calcium Sulfate (CaSO 4 x 2H 2 O) mixture Production Rate 11.5 Tph

Location of Major Process Equipment Fabric filter a nd wet FGD absorber module flue gas path location i s after ID fans and before new wet stack. Reagent preparation and byproduct de watering equipment to be located around absorber module, location of new wet stack to be de termined later. Inlet/Outlet Connections and Interconnecting Ducts Connected to ID fan outlet ducts and discharge to t he new stack. Reagent Storage Silo for reagent will be required. Control System Modifications New stand-alone contro l system, tie in to plant DCS control system.
Fan Modifications Assume new booster/ID fans and duct stiffening will be required. Power Supply/Aux Power Modifications Aux electric s ystem modifications will be required. Enclosures Requirements Oxidation air blower building, control building, sl aker and slurry tank building, byproduct dewatering building. Demolition or Relocation Requirements Abandon exist ing stack in place. Major Constructability Issues Construction of new s tack with impacts on restricted safety zone possibl y limiting or extending schedule for construction of ductwork, fabric filte r system, ID booster fans and wet FGD system. Significant Issues or Challenges Tie-in to the curr ent 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 ES P remains in operation upstream of new AQC equipmen t.

x One FGD absorber is assumed.

x Fabric filter upstream of wet FGD system is requir ed 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 di sposal in a landfill.

State of Availability Commercial. Technical Feasibility Technically feasible and applicable.
Reasons --Boardman Plant Appendix C

040210 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 Abs orber (SDA) with downstream Pulse Jet Fabric Filter (PJFF) Pollutant SO 2 Emissions lb/MMBtu 0.614 ton/yr 14,902 Controlled Emissions lb/MMBtu 0.12 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 (CaSO 3 x 1/2H 2 0), Calcium Sulfate (CaSO 4 x 2H 2 O) mixture Production Rate 10.6 tph

Location of Major Process Equipment Spray Dryer Abs orber and Pulse Jet Fabric Filter flue gas flow pat h location is after ID fans and before stack. Inlet/Outlet Connections and Interconnecting Ducts Connected to ID fan outlet ducts and discharge to t he existing stack. Reagent Storage Silo for reagent will be required. Control System Modifications New stand-alone contro l system, tie in to plant DCS control system.
Fan Modifications Assume new booster fans and duct stiffening will be required. Power Supply/Aux Power Modifications Aux electric s ystem modifications will be required. Enclosures Requirements Compressor building, control building, slaker and s lurry 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 curr ent fan ID outlets and stack breaching during a maj or planned outage. Other Assumptions

x No modifications to ESP and existing ESP remain in service

x No impact on potential ash sales since existing ES P remains in operation upstream of new AQC equipmen t.

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/addi tion 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 th e new fabric filter and would require a separate as h transport system and silo (included).

State of Availability Commercial. Technical Feasibility Technically feasible and applicable.
Reasons --Boardman Plant Appendix C

040210 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 th e current baseline emission rate. Pollutant SO 2 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 change s in coal Btu value Power Supply/Aux Power Modifications Low sulfur coa ls may affect auxiliary power due to changes in coa l Btu value Enclosures Requirements None Demolition or Relocation Requirements None Major Constructability Issues None Significant Issues or Challenges Coal blending is a n 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

040210 C-13 

### 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 inclu ding bag replacement). Byproduct Description None. Other N/A

Location of Major Process Equipment Replace existin g 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 exis ting 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 s ystem modification will be required. Enclosures Requirements The top pendent area and bo ttom hopper area of the fabric filter should be enc losed. Demolition or Relocation Requirements None. Existin g ESP to be abandoned in place. Major Constructability Issues Modification to exist ing ash handling system. Significant Issues or Challenges Installation of ne w 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/addit ion included.

x The site has sufficient area available to accommod ate construction activities including, but not limi ted to, offices, lay-down, and staging.

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

.Boardman Plant Appendix C

040210 C-14 

### 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 H ybrid 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 includ ing 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 exis ting control system.
Fan Modifications Assume new booster fans and duct stiffening will be required. Power Supply/Aux Power Modifications Aux electric s ystem 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 curr ent 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 accommod ate construction activities including, but not limi ted 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 re moval systems.

x Additional ash handling system.

State of Availability Commercial. Technical Feasibility Technically feasible.
Reasons COHPAC can function as a polishing filter for addit ional particulate removal and may be used as a comp onent for mercury removal systems.Boardman Plant Appendix C

040210 C-15 

### 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 ga s path location to be downstream of existing ESP. W ater treatment system to be located next to wet ESP. Additional byproduct di sposal 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 syste m. Control System Modifications Incorporated into exis ting control system.
Fan Modifications Assume new booster fans and duct stiffening will be required. Power Supply/Aux Power Modifications Substantial au x electric system modification will be required. Enclosures Requirements The top pendant area and the bottom hopper area are enclosed. Demolition or Relocation Requirements Abandon exist ing stack in place. Major Constructability Issues Construction of new s tack with impacts on restricted safety zone possibl y limiting or extending schedule for construction of other control technolo gy equipment. Significant Issues or Challenges Tie-in to the curr ent ID fan outlets during a major planned outage. Other Assumptions

x No major impact in plant availability, however, pe riodic outages for intense off-line cleanings may b e required.

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

x The site has sufficient area available to accommod ate construction activities including, but not limi ted 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 ES P 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

040210 D-1 

## Appendix D Cost Analysis SummaryBoardman Plant Appendix D

040210 D-2 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: New Low NOx Burners & Modified OFA System Date: Jan 14, '10

Cost Item Remarks/Cost Basis

CAPITAL COST 2010 Direct Costs Purchased equipment costs New Low NOx Burners with new secondary air $5,019,00 0 from vendor quote, 06/30/06 registers (8) OFA ports and (4) wing ports with tube throat $2 ,179,000 from vendor quote, 06/30/06 openings Neural network system for NOx optimization $378,000 B &V cost estimate NOx monitoring equipment $199,000 B&V cost estimate Water cannon system $1,587,000 B&V cost estimate Dynamic classifier for coal pulverizers $1,923,000 B& V cost estimate Coal/air flow instrument for burners $1,022,000 B&V c ost estimate Modulating orifice for burners $308,000 B&V cost esti mate Subtotal capital cost (CC) $12,615,000 Freight $631,000 (CC) X 5.0% Total purchased equipment cost (PEC) $13,246,000

Direct installation costs Foundation & supports $0 (PEC) X 0.0% Handling & erection $6,623,000 (PEC) X 50.0% Electrical $1,325,000 (PEC) X 10.0% Piping $662,000 (PEC) X 5.0% Insulation $0 (PEC) X 0.0% Painting $0 (PEC) X 0.0% Demolition $662,000 (PEC) X 5.0% Relocation $662,000 (PEC) X 5.0% Total direct installation costs (DIC) $9,934,000
Site preparation $0 N/A Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $23,180,000

Indirect Costs Engineering $2,782,000 (DC) X 12.0% Owner's cost $464,000 (DC) X 2.0% Construction management $1,159,000 (DC) X 5.0% Start-up and spare parts $464,000 (DC) X 2.0% Performance test $55,000 Engineering estimate Contingencies $4,636,000 (DC) X 20.0% Total indirect costs (IC) $9,560,000
Allowance for Funds Used During Construction (AFDC) $2,943,000 [(DC)+(IC)] X 8.99% 2 years (project time /2 )
Total Capital Investment (TCI) = (DC) + (IC) + (AFDC) $35,683,000

ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance labor and materials $695,000 (DC) X 3.0% 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 $5,268,000 (TCI) X 14.8% CRF at 7.0% interest

Total indirect annual costs (IDAC) $5,268,000 based o n 9.5 year life
Total Annual Cost (TAC) = (DAC) + (IDAC) $5,963,000Boardman Plant Appendix D

040210 D-3 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: Selective Non-Catalytic Reduction (SNCR) Date: Jan. 20 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST 2010 dollars Direct Costs Purchased equipment costs Reagent storage, handling, injection & controls $3,5 97,241 CUECost estimate Initial urea inventory $180,056 150,000 gal. urea initial inventory Air preheater modifications $3,098,000 CUECost estima te Subtotal capital cost (CC) $6,875,297 Freight $413,000 (CC) X 6.0% Total purchased equipment cost (PEC) $7,288,000

Direct installation costs Foundation & supports $364,000 (PEC) X 5.0% Handling & erection $729,000 (PEC) X 10.0% Electrical $729,000 (PEC) X 10.0% Piping $219,000 (PEC) X 3.0% Insulation $0 (PEC) X 0.0% Painting $0 (PEC) X 0.0% Demolition $146,000 (PEC) X 2.0% Relocation $146,000 (PEC) X 2.0% Total direct installation costs (DIC) $2,333,000
Site preparation $0 N/A Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $9,621,000

Indirect Costs Engineering $1,155,000 (DC) X 12.0% Owner's cost $481,000 (DC) X 5.0% Construction management $962,000 (DC) X 10.0% Start-up and spare parts $289,000 (DC) X 3.0% Performance test $100,000 Engineering estimate Contingencies $1,443,000 (DC) X 15.0% Total indirect costs (IC) $4,430,000
Allowance for Funds Used During Construction (AFDC) $632,000 [(DC)+(IC)] X 8.99% 1 year (project length / 2 )
Total Capital Investment (TCI) = (DC) + (IC) + (AFD C) $14,683,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $100,000 1 FTE and 100,000 $/year Estimate Labor Maintenance labor and materials $289,000 (DC) X 3.0% Total fixed annual costs $389,000

Variable annual costs Reagent $955,000 815 lb/hr and 315 $/ton Enginr estim. Auxiliary and ID fan power $26,000 70 kW and 0.05 $/kWh E nginr estim. Water $179,000 200 gpm and 2 $/1,000 gal Enginr estim. Total variable annual costs $1,160,000 Total direct annual costs (DAC) $1,549,000

Indirect Annual Costs Cost for capital recovery $2,889,000 (TCI) X 19.67% CRF at 7% interest

Total indirect annual costs (IDAC) $2,889,000 based o n 6.5 year life
Total Annual Cost (TAC) = (DAC) + (IDAC) $4,438,000Boardman Plant Appendix D

040210 D-4 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: New Low NOx Burners & Modified OFA System & SNCR Date: Jan 20 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST
Total Capital Investment (TCI) cost for: New Low NOx Burners & Modified OFA System $35,683,00 0 Cost estimate for independent system Selective Non-Catalytic Reduction System $14,683,000 Cost estimate for independent system
Total Capital Investment (TCI) = (DC) + (IC) + (AFD C) $50,366,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $100,000 1 FTE and 100,000 $/year Estim. manpower Maintenance labor and materials $984,000 (DC) X 3.0% Total fixed annual costs $1,084,000

Variable annual costs Reagent $955,000 815 lb/hr and 315 $/ton Engineering estimate Auxiliary and ID fan power $26,000 70 kW and 0.05 $/kWh E ngineering estimate Water $179,000 200 gpm and 2 $/1,000 gal Engineering estimate Total variable annual costs $1,160,000 Total direct annual costs (DAC) $2,244,000

Indirect Annual Costs Cost for capital recovery (NLNB/MOFA) $5,268,000 (TCI ) X 14.76% CRF at 7% interest based on 9.5 year life Cost for capital recovery (SNCR) $2,889,000 (TCI) X 19.67% CRF at 7% interest

Total indirect annual costs (IDAC) $8,157,000 based o n 6.5 year life
Total Annual Cost (TAC) = (DAC) + (IDAC) $10,401,000Boardman Plant Appendix D

040210 D-5 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: Selective Catalytic Reduction (SCR) Date: 2/23/2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST 2010 dollars Direct Costs Purchased equipment costs Reactor housing $6,097,000 CUECost estimate Ammonia handling and injection $1,560,272 CUECost est imate Initial catalyst and ammonia $2,863,414 CUECost estim ate Electrical system modification $2,471,000 from ref. c ost ID fans $3,997,000 from ref. cost Flue gas handling system $7,103,000 from ref. cost Air preheater modifications $3,098,000 CUECost estima te Ash handling system $3,398,000 CUECost estimate Subtotal capital cost (CC) $30,587,686 Instruments and controls $3,059,000 (CC) X 10.0% Freight $1,529,000 (CC) X 5.0% Total purchased equipment cost (PEC) $35,176,000

Direct installation costs Foundation & supports $13,367,000 (PEC) X 38.0% Handling & erection $13,015,000 (PEC) X 37.0% Electrical $8,794,000 (PEC) X 25.0% Piping $2,638,000 (PEC) X 7.5% Insulation $3,518,000 (PEC) X 10.0% Painting $352,000 (PEC) X 1.0% Demolition $5,980,000 (PEC) X 17.0% Relocation $4,221,000 (PEC) X 12.0% Total direct installation costs (DIC) $51,885,000
Site preparation $2,185,000 Engineering estimate Buildings $546,000 Engineering estimate

Total direct costs (DC) = (PEC) + (DIC) $89,792,000

Indirect Costs Engineering $10,775,000 (DC) X 12.0% Owner's cost $4,490,000 (DC) X 5.0% Construction management $8,979,000 (DC) X 10.0% Start-up and spare parts $2,694,000 (DC) X 3.0% Performance test $200,000 Engineering estimate Contingencies $13,469,000 (DC) X 15.0% Total indirect costs (IC) $40,607,000
Allowance for Funds Used During Construction (AFDC) $17,584,000 [(DC)+(IC)] 8.99% 3 years (project length / 2) Boiler Heat Transfer Surface Area Replacement $43,70 9,000 B&V estimate to reduce SCR inlet FG temperatur e Total SCR Capital Investment (TCI) $191,692,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $100,000 1 FTE and 100,000 $/year Estimated labor Maintenance labor & materials $2,694,000 (DC) X 3.0% Yearly emissions testing $27,000 Engineering estimate Catalyst activity testing $5,000 Engineering estimate Fly ash sampling and analysis $22,000 Engineering est imate Total fixed annual costs $2,848,000

Variable annual costs Reagent $610,000 364 lb/hr and 450 $/ton Enginr. Estimate Auxiliary and ID fan power $934,000 2,509 kW and 0.05 $/ kWh Enginr. Estimate Catalyst replacement $1,035,000 173 m3 and 6,000 $/m3 3 y r replacement Catalyst disposal $1,000 292,483 lb and 10 $/ton 4 yr replacement Total variable annual costs $2,580,000 Total direct annual costs (DAC) $5,428,000

Indirect Annual Costs Cost for capital recovery $51,121,000 (TCI) X 26.67% CR F at 7% interest

Total indirect annual costs (IDAC) $51,121,000 based on 4.5 year life
Total Annual Cost (TAC) = (DAC) + (IDAC) $56,549,000Boardman Plant Appendix D

040210 D-6 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: New Low NOx Burners & Modified OFA System & SCR Date: Feb 23 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST 2010 dollars
Total Capital Investment (TCI) cost for: New Low NOx Burners & Modified OFA System $35,683,00 0 Cost estimate for independent system Selective Catalytic Reduction System $191,692,000 Cos t estimate for independent system
Total Capital Investment (TCI) $227,375,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $100,000 1 FTE and 100,000 $/year Estim. manpower Maintenance labor and materials $3,389,000 (DC) X 3.0% Yearly emissions testing $27,000 Engineering estimate Catalyst activity testing $5,000 Engineering estimate Fly ash sampling and analysis $22,000 Engineering est imate Total fixed annual costs $3,543,000

Variable annual costs Reagent $610,000 364 lb/hr and 450 $/ton Engineering estimate Auxiliary and ID fan power $934,000 2509 kW and 0.05 $/k Wh Engineering estimate Catalyst replacement $1,035,000 173 m3 and 6,000 $/m3 3 y r replacement Catalyst disposal $1,000 292,483 lb and 10 $/ton 4 yr replacement Total variable annual costs $2,580,000 Total direct annual costs (DAC) $6,123,000

Indirect Annual Costs Cost for capital recovery (NLNB/MOFA) $5,268,000 (TCI ) X 14.76% CRF at 7% interest based on 9.5 year life Cost for capital recovery (SCR) $51,121,000 (TCI) X 26 .67% CRF at 7% interest

Total indirect annual costs (IDAC) $56,389,000 based on 4.5 year life
Total Annual Cost (TAC) = (DAC) + (IDAC) $62,512,000Boardman Plant Appendix D

040210 D-7 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: Wet Flue Gas Desulfurization (FGD) with Fabric Filt er Date: Jan. 14, 2010

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs 2010 dollars Purchased equipment costs Reagent feed system: receiving, storage $1,548,000 CU ECost estimate Ball mill & classifier $2,354,000 CUECost estimate SO2 removal system: tanks, pumps $4,212,000 CUECost e stimate 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 fr om ref. cost Booster fans $5,289,000 Engineering estimate Electrical system upgrades $4,639,000 from ref. cost Flue gas handling system $9,616,000 Engineering estim ate 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 Engineering estimate Buildings $8,195,000 Engineering estimate New wet stack $25,133,000 Recent quotes estimate of $23 mil Waste water treatment system $16,391,000 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 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) + (AFD C) $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 $6,839,000 16811 kW and 0.05 $/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 $11,740,000 Total direct annual costs (DAC) $19,628,000

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) $101,828,000Boardman Plant Appendix D

040210 D-8 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: Semi-Dry Flue Gas Desulfurization (FGD) Date: Dec 17 2009

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs 2010 dollars Purchased equipment costs Reagent feed: receiving, storage, grinding $3,646,00 0 CUECost estimate SO2 removal system: tanks, pumps $3,457,000 CUECost e stimate Spray dryers and fabric filter $45,008,000 CUECost es timate Ash handling system $2,185,000 from ref. cost Booster fans $5,289,000 Engineering estimate Electrical system upgrades $3,125,000 from ref. cost Flue gas handling system $9,616,000 CUECost estimate Subtotal capital cost (CC) $72,326,000 Instrumentation and controls $1,447,000 (CC) X 2.0% Freight $3,616,000 (CC) X 5.0% Total purchased equipment cost (PEC) $77,389,000

Direct installation costs Foundation & supports $21,282,000 (PEC) X 27.5% Handling & erection $30,956,000 (PEC) X 40.0% Electrical $15,478,000 (PEC) X 20.0% Piping $3,869,000 (PEC) X 5.0% Insulation $3,869,000 (PEC) X 5.0% Painting $774,000 (PEC) X 1.0% Demolition $3,096,000 (PEC) X 4.0% Relocation $3,096,000 (PEC) X 4.0% Total direct installation costs (DIC) $82,420,000
Site preparation $219,000 Engineering estimate Buildings $546,000 Engineering estimate

Total direct costs (DC) = (PEC) + (DIC) $160,574,000

Indirect Costs Engineering $19,269,000 (DC) X 12.0% Owner's cost $6,423,000 (DC) X 4.0% Construction management $16,057,000 (DC) X 10.0% Start-up and spare parts $2,409,000 (DC) X 1.5% Performance test $219,000 Engineering estimate Contingencies $24,086,000 (DC) X 15.0% Total indirect costs (IC) $68,463,000
Allowance for Funds Used During Construction (AFDC) $41,181,000 [(DC)+(IC)] X 8.99% 4 years (project length / 2)
Total Capital Investment (TCI) = (DC) + (IC) + (AFD C) $270,218,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $300,000 3 FTE and 100,000 $/year Estimated labor Maintenance labor and materials $4,817,000 (DC) X 3.0% Total fixed annual costs $5,117,000

Variable annual costs Reagent $5,235,000 5.3 tph and 132 $/ton Mass bal. calcs. Byproduct disposal $790,000 10.6 tph and 10 $/ton Mass bal. calcs. Bag replacement cost $632,000 6,322 bags and 100 $/bag 18,966 total bags Cage replacement cost $158,000 3,161 cages and 50 $/cage 18,966 total bags Auxiliary and ID fan power $1,621,000 4,355 kW and 0.05 $/kWh CueCost calcs Water $320,000 358 gpm and 2 $/1,000 gal Mass bal. calcs. Total variable annual costs $8,756,000 Total direct annual costs (DAC) $13,873,000

Indirect Annual Costs Cost for capital recovery $53,159,000 (TCI) X 19.67% CRF at 7% interest

Total indirect annual costs (IDAC) $53,159,000 based on 6.5 year life
Total Annual Cost (TAC) = (DAC) + (IDAC) $67,032,000Boardman Plant Appendix D

040210 D-9 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: Pulse Jet Fabric Filter (PJFF) Date: Dec 21 2009

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 Engineering estimate Booster fans $5,938,000 Engineering estimate Electrical system upgrades $2,248,000 from ref. cost Flue gas handling system $3,967,000 Engineering estim ate 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 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 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) + (AFD C) $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 $841,000 2,258 kW and 0.05 $/kWh 6" water d.p. Additional Auxiliary power $206,000 554 kW and 0.05 $/kW h Engineering estimate Total variable annual costs $1,837,000 Total direct annual costs (DAC) $3,812,000

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) $23,572,000Boardman Plant Appendix D

040210 D-10 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: Compact Hybrid Particulate Collector (COHPAC) Date: Dec 21 2009

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs 2010 dollars Purchased equipment costs Fabric filter system $13,313,000 from ref. cost Initial FF bags inventory Ash handling system $2,404,000 from ref. cost Booster fans $5,481,000 Engineering estimate Electrical system upgrades $2,248,000 from ref. cost Flue gas handling system $7,212,000 Engineering estim ate 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 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 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) + (AFD C) $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 $1,076,000 2,889 kW and 0.05 $/kWh 8" water d.p. Additional Auxiliary power $332,000 893 kW and 0.05 $/kW h Engineering estimate Total variable annual costs $2,074,000 Total direct annual costs (DAC) $5,547,000

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) $22,920,000Boardman Plant Appendix D

040210 D-11 PGE Boardman BART Analysis - Cost Analysis (Draft)
Technology: Wet ESP Date: Dec 21 2009

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs 2010 dollars Purchased equipment costs WESP system includes casing, electrical sys., $34,1 39,000 from ref. cost penthouse blower & heater, access provisions Ash handling system $2,644,000 from ref. cost Booster fans $5,024,000 Engineering estimate Electrical system upgrades $1,454,000 from ref. cost Flue gas handling system $3,967,000 Engineering estim ate 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 Engineering estimate Buildings $0 N/A New wet stack $25,133,000 Recent quotes estimate of $23 mil

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 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) + (AFD C) $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 $/kW h Engr. Estimate ID fan power $522,000 1,402 kW and 0.05 $/kWh 4" water d.p. Service water $583,000 652 gpm and 2 $/1,000 gal Engr. Estimate Total variable annual costs $1,414,000 Total direct annual costs (DAC) $4,375,000

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) $42,999,000Boardman Plant Appendix E

040210 E-1 

## Appendix E Visibility Modeling Results3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-1. Stack Parameters and Modeled Emission Ra tes BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR
Emission Rates (lb/hr) (1,a) Stack Parameters (1) SO X PM Exit Exit Filterable Condensable Height Diameter Velocity Temperat ure Scenario NO X SO 2 (2) SO 4 Total Total EC PMF PMC Total OC (ft) (ft) (ft/s) ( Û) %DVHOLQH                1HZ/1%ZLWK0RGLILHG2)$DQG6&5                1HZ/1%ZLWK0RGLILHG2)$DQG61&5                1HZ/1%ZLWK0RGLILHG2)$                :HW)*'DQG3-))                6HPL'U\)*'DQG3-))               5HGXFHG6XOIXU&RDO5HVWULFWLRQ                1HZ/1%ZLWK0RGLILHG2)$DQG56&5               

Calculations: D(PLVVLRQ5DWHRI306SHFLHVOEKU >(PLVVLRQ 5DWHRI7RWDO30OEKU@[>)UDFWLRQ@ )UDFWLRQRI7RWDO30IRU'U\%RWWRP3XOYHUL]HG&RDO %RLOHUZLWK(63 )LOWHUDEOH30   )LQH(OHPHQWDO&DUERQ(&   )LQH6RLO30)   &RDUVH3DUWLFXODWH30&   &RQGHQVDEOH30   ,QRUJDQLF$HURVRO62     2UJDQLF&DUERQ2&  

Notes: 3URYLGHGE\3*(UHYLVHG 62  EDVHGRQQR62  WR62  FRQYHUVLRQ )URP%$57$QDO\VLVUHSRUWFRQVLVWHQWZLWK PRGHOLQJILOHVSURYLGHGE\2UHJRQ'(4RQ)HEUXDU\ 
/1% /RZ12;%XUQHU2)$ 2YHUILUH$LU6&5 6HO HFWLYH&DWDO\WLF5HGXFWLRQ61&5 6HOHFWLYH1RQ&D WDO\WLF5HGXFWLRQ)*' )OXH*DV'HVXOIXUL]DWLRQ 3-)) 3XOVH-HW)DEULF)LOWHU56&5 5HGXFHG6XOI XU&RDO5HVWULFWLRQ3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-2. Visibility Analysis Results - Baseline BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview 8 th High by Year 22 nd 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 200 4 2005 Total SO 4 NO 3 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 27.970 33.562 28.192 31.455 34.126 766 877 748 2,391 40 1 484 380 1,265

Maximum 4.030 5.136 5.026 4.982 5.136 115 107 102 324 68 73 65 2 06

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* &ROXPELD5LYHU*RUJH                     

&ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV Modeled Area Location of Maximum (km) % of Modeled Extinction by

Species3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-3. Visibility Analysis Results - New LNB w ith Modified OFA and SCR BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview 8 th High by Year 22 nd 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 200 4 2005 Total SO 4 NO 3 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 17.347 21.787 15.616 18.921 21.938 498 565 426 1,489 19 5 273 149 617

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* &ROXPELD5LYHU*RUJH                     

/1% /RZ12;%XUQHU2)$ 2YHUILUH$LU6&5 6HO HFWLYH&DWDO\WLF5HGXFWLRQ &ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV Modeled Area Location of Maximum (km) % of Modeled Extinction by

Species3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-4. Visibility Analysis Results - New LNB w ith Modified OFA and SNCR BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview 8 th High by Year 22 nd 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 200 4 2005 Total SO 4 NO 3 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 24 6 329 211 786

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 6H OHFWLYH1RQ&DWDO\WLF5HGXFWLRQ &ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV Modeled Area Location of Maximum (km) % of Modeled Extinction by

Species3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-5. Visibility Analysis Results - New LNB w ith Modified OFA BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview 8 th High by Year 22 nd 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 200 4 2005 Total SO 4 NO 3 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 26 1 343 234 838

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

Species3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-6. Visibility Analysis Results - Wet FGD a nd PJFF BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview 8 th High by Year 22 nd 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 200 4 2005 Total SO 4 NO 3 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 18 6 254 196 636

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)D EULF)LOWHU &ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV Modeled Area Location of Maximum (km) % of Modeled Extinction by

Species3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-7. Visibility Analysis Results - Semi-Dry FGD and PJFF BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview 8 th High by Year 22 nd 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 200 4 2005 Total SO 4 NO 3 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 20 3 262 202 667

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)D EULF)LOWHU &ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV Modeled Area Location of Maximum (km) % of Modeled Extinction by

Species3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-8. Visibility Analysis Results - Reduced S ulfur Coal Restriction (3475.8 lb/hr) BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview 8 th High by Year 22 nd 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 200 4 2005 Total SO 4 NO 3 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 33 9 411 325 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,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-9. Visibility Analysis Results - New LNB w ith Modified OFA and RSCR (3475.8 lb/hr) BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR

Delta Deciview 8 th High by Year 22 nd 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 200 4 2005 Total SO 4 NO 3 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 19 2 248 165 605

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,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS 7DEOH(6XPPDU\RI9LVLELOLW\$QDO\VLV5HVXOWV DQG&RPSDULVRQRI&KDQJHLQ9LVLELOLW\ǻGY

BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR
Existing Controls NO XControl Alternatives SO 2 Control Alternatives Combined NO Xand SO 2 Baseline NLNB/MOFA/SCR NLNB/MOFA/SNCR NLNB/MOFA Wet FGD/PJFF Sem i-Dry FGD/PJFF RSCR NLNB/MOFA/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 ǻGY ǻGY (dv) (%) ǻGY (dv) (%) ǻGY (dv) (%) ǻGY (dv) (%) ǻGY (dv) (%) ǻGY (dv) (%) ǻGY (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 8.4 73 24.8 22.448 11.678 34.2 22.744 11.382 33.4 30.274 3.852 11 .3 20.793 13.333 39.1

Maximum 5.136 3.248 1.888 42.3 3.657 1.479 33.3 3.850 1.286 2 9.6 3.910 1.226 49.2 3.760 1.376 48.9 4.638 0.498 18.6 3.257 1 .879 42.4

Minimum 1.151 0.690 0.437 29.5 0.833 0.298 21.8 0.846 0.254 1 8.6 0.664 0.487 23.9 0.699 0.419 24.0 1.015 0.136 6.6 0.671 0. 480 36.5
Average 2.438 1.567 0.871 35.7 1.753 0.684 28.0 1.832 0.605 2 4.8 1.603 0.834 36.3 1.625 0.813 35.0 2.162 0.275 11.7 1.485 0 .952 39.4
Class II Areas* &ROXPELD5LYHU*RUJH                       

1/1% 1HZ/RZ12;%XUQHU02)$ 0RGLILHG2YHUILUH $LU6&5 6HOHFWLYH&DWDO\WLF5HGXFWLRQ61&5 6 HOHFWLYH1RQ&DWDO\WLF5HGXFWLRQ)*' )OXH*DV'H VXOIXUL]DWLRQ3-)) 3XOVH-HW)DEULF)LOWHU56&5 5HGXFHG6XOIXU&RDO5HVWULFWLRQ &ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-11. Summary of Visibility Analysis Results and Comparison of Total Number of Days Above 0.5 D eciview

BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR
Existing Controls NO XControl Alternatives SO 2 Control Alternatives Combined NO Xand SO 2 Baseline NLNB/MOFA/SCR NLNB/MOFA/SNCR NLNB/MOFA Wet FGD/PJFF Sem i-Dry FGD/PJFF RSCR NLNB/MOFA/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) (%) (da ys) (days) (%) (days) (days) (%) (days) (days) (%) (days) (da ys) (%) (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 2,141 250 10.5 1,494 897 37.5

Maximum 324 212 160 61.4 234 111 42.2 239 103 34.9 233 150 61.4 2 35 129 57.8 278 46 23.3 223 149 61.4

Minimum 60 29 31 21.5 37 23 13.3 40 20 11.5 26 34 13.7 28 32 13.0 46 6 3.3 30 30 17.4
Average 171 106 64 39.0 125 46 27.8 131 40 24.1 109 62 38.7 113 58 36.3 153 18 11.1 107 64 39.0
Class II Areas* &ROXPELD5LYHU*RUJH                      

1/1% 1HZ/RZ12;%XUQHU02)$ 0RGLILHG2YHUILUH $LU6&5 6HOHFWLYH&DWDO\WLF5HGXFWLRQ61&5 6 HOHFWLYH1RQ&DWDO\WLF5HGXFWLRQ)*' )OXH*DV'H VXOIXUL]DWLRQ3-)) 3XOVH-HW)DEULF)LOWHU56&5 5HGXFHG6XOIXU&RDO5HVWULFWLRQ &ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHV3DJHRI

3?3*(?%RDUGPDQ%$57?%RDUGPDQ%$570RGHOLQJ B[OV 0DUFK 6/5,QWHUQDWLRQDO&RUS Table E-12. Summary of Visibility Analysis Results and Comparison of Total Number of Days Above 1.0 D eciview

BART/Reasonable Progress Analysis Revision 2: Board man 2020 Alternative

Portland General Electric - Boardman, OR
Existing Controls NO XControl Alternatives SO 2 Control Alternatives Combined NO Xand SO 2 Baseline NLNB/MOFA/SCR NLNB/MOFA/SNCR NLNB/MOFA Wet FGD/PJFF Sem i-Dry FGD/PJFF RSCR NLNB/MOFA/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) (%) (da ys) (days) (%) (days) (days) (%) (days) (days) (%) (days) (da ys) (%) (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 6 67 598 47.3 1,075 190 15.0 605 660 52.2

Maximum 206 141 98 72.7 158 75 59.7 164 69 54.5 165 102 79.2 168 9 6 79.2 191 29 33.3 143 98 72.1

Minimum 24 9 14 31.6 12 11 23.3 13 10 20.4 5 17 19.9 5 16 18.4 16 6 7. 3 8 16 30.6
Average 90 44 46 53.7 56 34 40.5 60 31 36.2 45 45 54.6 48 43 52.3 77 14 17.3 43 47 55.5
Class II Areas* &ROXPELD5LYHU*RUJH                      

1/1% 1HZ/RZ12;%XUQHU02)$ 0RGLILHG2YHUILUH $LU6&5 6HOHFWLYH&DWDO\WLF5HGXFWLRQ61&5 6 HOHFWLYH1RQ&DWDO\WLF5HGXFWLRQ)*' )OXH*DV'H VXOIXUL]DWLRQ3-)) 3XOVH-HW)DEULF)LOWHU56&5 5HGXFHG6XOIXU&RDO5HVWULFWLRQ &ODVV,,DUHDPRGHOHGIRULQIRUPDWLRQDOSXUSRVHVBoardman Plant Appendix F

040210 F-1 

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

1 

### Modeling Protocol for Washington, Oregon, and Idaho: Protocol for the Application of the CALPUFF Modeling System Pursuant to the Best Available Retrofit Technology (BART) Regulatio n



## 1. Introduction and Protocol Objective

1.1 Background
Under the Regional Haze Regulations, the U.S. Environmenta l Protection Agency (EPA) issued the final Guidelines for Best Available Retrofit Technolog y (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 guideli nes is optional for states establishing BART emission limitations for other BART-eli gible sources. However, according to EPA, the BART Guideline was designed to help states and oth ers do the following: (1) identify those sources that must comply with the BART requir ement, and (2) determine the level of control technology that represents BART for each source.
This modeling protocol is a cooperative effort among Idaho D epartment of Environmental Quality (IDEQ), Oregon Department of Environmental Quality (ODEQ), and Washington Department of Ecology (WDOE) to develop an analysis that wil l 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 Re gion 10 were consulted during the development of this protocol (EPA 2006a, b, c). This protoc ol adopts the BART Guideline and addresses both the BART exemption modeling as well as the BAR T 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 workl oad.



## 1.2 Objectives
The protocol describes the modeling methodology that will b e 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 whichBART-eligible sources are subject to BART

x A clearly delineated modeling methodology

x A common CALMET/CALPUFF/POSTUTIL/CALPOST modeling confi guration 

## 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 finalizi ng 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 – N ampa Conoco-Phillips PGE Boardman Amalgamated Sugar – Paul Centralia Powerplant (TransAlta) Boise Cascade Amalgam ated Sugar – Twin Falls Longview Fibre Fort James J.R. Simplot Don Siding Plant Weyerhaeuser – Longview Pope & Talbot Potlatch Pulp and Pa per 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 Was hington, 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 locatio ns with respect to the Class I areas.
All federally mandatory Class I areas within 300 kilometer s (km) of a BART-eligible source will be included in the BART exemption modeling analysis. Sectio n 6.1(c) of the Guideline on Air Quality Models states, “It was concluded from these case stu dies that the CALPUFF dispersion model had performed in a reasonable manner, and had no appare nt bias toward over or underFINAL 10/11/06

3 

### prediction, so long as the transport distance was limited to less than 300km” (40 CFR 51, Appendix W). If the 300km extends into a neighboring state, v isibility impairment shall also be quantified at those Class I areas. Furthermore, if it lies wi thin the 300km radius, visibility impairment at the Columbia River Gorge Scenic Area will also be quantified for information purposes only.


## 2.3 Pollutants to Consider
The BART Guideline specifies that sulfur dioxide (SO 2 

### ), oxides of nitrogen (NO x 

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

### and PM 2.5 

### should be included for both the BART exemption and BART determination modeling analyse s.

The BART Guideline also discusses the inclusion of volatile organic compound (VOC), ammonia and ammonia compounds as visibility impairing poll utants. These pollutants will be included in the BART analysis if it is determined that they ar e reasonably anticipated to cause or contribute to visibility impairment. For sources that are s elected to evaluate VOC emissions, the first criterion is the emission level. The VOC emissions wil l be included in the BART exemption analysis if the greater-than-six-carbon VOC gas es 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 car bon atoms. Idaho and Oregon have determined that there are no significant sources of VOC, amm onia, 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 ref lect steady-state operating conditions during periods of high c apacity utilization.”These emissions should not generally include start-up, shutdown, or malfun ction emissions. The BART Guideline recommends that states use the 24-hour average ac tual emission rate from the highest emitting day of the meteorological period modeled. The mete orological period is 2003 – 2005.
Depending on the availability of emissions data, the follow ing emissions information (listed in order of priority) should be used with CALPUFF for BART exemp tion modeling:

x 24-hour average actual emission rate from the highest emitt ing day within the modeling period (2003 – 2005) (preferred). Actual emissions may be ca lculated using emission factors specified in Title V permits or representative stac k 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 SO 2 

### , NO x 

### , and PM 10 

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

4 

### emissions from all BART eligible units exceed the SERs for th ese pollutants, then all emissions of that pollutant from individual emission units will be eva luated even if emissions are below the SER for an individual emission unit.
The states have the option of determining how to include smal l emission units in the BART exemption analysis. Fugitive dust sources at a distance gre ater 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 fr om 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 Guidel ine (Federal Register Vol. 70, No. 128, pf 39125). The natural background values for Class I are as used in this protocol are based on EPA’s “Guidance for Estimating Natural Visibility Condi tions under the Regional Haze Rule” (EPA 2003). The natural background for the Columbia Ri ver 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 backgroun d data for Class I areas and the Columbia River Gorge are presented in Appendix B. The optionpresented 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 co ncentration estimates from CALPUFF are used with the current FLAG equation to calculate the exti nction coefficient, as shown below.

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

### As described in the IWAQM Phase 2 Report, the change in visibi lity for the BART exemption analysis is compared against background conditions. The de lta-deciview, ' dv, value is calculated from the source’s contribution to extinction, b ext (source) 

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

### , as follows:

' dv = 10 ln [ ( b ext(bkg) 

### + b ext (source) 

### ) / ( b ext(bkg) 

### ) ]



## 2.7 Model Execution

2.7.1 BART Exemption Analysis
The BART exemption modeling determines which BART-eligibl e sources are reasonablyFINAL 10/11/06

5 

### anticipated to cause or contribute to visibility impairment at any Class I area. This protocol adopts Option 1 in Section III of the BART Guideline. This opt ion is the Individual Source Attribution Approach. With this approach, each BART-eligi ble 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 recommendat ions in the BART Guideline are followed to assess whether a BART-eligible source is reason ably anticipated to cause or contribute to any visibility impairment in a Class I area. Ac cording 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 th an a 1.0 deciview change may still contribute to visibility impairment and thus be subject to B ART... As a general matter, any threshold that you used for determining whether a source “co ntributes” to visibility impairment should not be higher than 0.5 deciviews. In setting a threshold for “contribution,” you should consi der the number of emissions sources affecting the Class I areas at issue and the magnitude of the i ndividual 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 thresho ld 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 determi ned 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 no t 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, c ontribution threshold may be considered. For BART-eligible sources in Oregon and Washin gton, the following steps will be used to address this condition: 1) after all BART-eligible s ources 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) i f the total for any receptor exceeds 0.5 deciview, all sources responsible for visibility impai rment at that receptor for that day will be considered for further evaluation. This evaluation will in clude an assessment of the magnitude, frequency, duration of impairment, and other factors that a ffect visibility for each of the sources in the multi-source group. The inclusion of these qualifyin g factors in the multi-source analysis follows the direction given in the BART Guideline for interp reting the refined modeling resultsFINAL 10/11/06

6 

### in the determination phase of the BART process and recommend ations 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 assessm ents. 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 an d be subject to BART.



### 2.7.2 BART Determination Analysis
The BART Determination analysis determines the degree of vi sibility improvement for each control option. The BART Guideline states:
“Assess the visibility improvement based on the modeled cha nge in visibility impacts for the precontrol and post-control emission scenarios. You have the f lexibility to assess visibility improvement due to BART controls by one or more methods. You m ay consider the frequency, magnitude, and duration components of impairment.”
In order to quantify the degree of visibility improvement du e to BART controls, the modeling system is executed in a similar manner as for the BART exempti on analysis. Model execution and results are needed for both pre-BART control and post-BA RT control scenarios to allow for comparison of CALPOST delta-deciview predictions for bothscenarios. The only difference between the modeling runs will be modifications to the CALP UFF inputs associated with control devices (emissions, stack parameters). In contrast to the B ART exemption analysis that predicts pre-control impacts from all BART-eligible units at a sourc e together, BART determination analyses evaluates each emission unit independently of eac h other after control options are in place. As explained in the BART Guideline, the states may con sider 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 f ollows:

x Idaho – DEQ will perform both the BART exemption and BART dete rmination modeling, working closely with the facilities and providin g 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 ana lysis. Oregon DEQ will perform any cumulative analysis required.

x Washington – The Washington BART-eligible sources will con duct the BART exemption modeling and the BART determination analysis. Ec ology and EPA will conduct any cumulative analysis required.FINAL 10/11/06

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## 3. Visibility Modeling System

In general, the BART exemption modeling using the CALPUFF su ite 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 M anagers Air Quality Related Values Workgroup) reports (EPA 1998, FLAG 2000). Exception s 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 ev aluation) are presented in Table 2.
The CALMET meteorological domain, as described below, cove rs 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 aresult, 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 individ ual 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 p art of the three-state collaboration on a BART protocol, it was decided to support the development of aconsistent meteorological data set for use in both the BART exemption and determination anal yses. 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 i s 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 mo deling protocol that provides details on the methodology used to develop the data sets. The refore, this BART modeling protocol only summarizes the development of the CALMET dataset. For additional detail, the reader is referred to the “ Modeling Protocol for BART CALMET Datasets” in Attachment 1.FINAL 10/11/06

8 

### Figure 1. CALMET Meteorological Domain.


## 3.2 Meteorological Data

3.2.1 Mesoscale Model Data
It was the judgment of Idaho, Oregon, Washington, and EPA Reg ion 10 that the use of three years of MM5 data developed by Western Regional Air Partners hip (WRAP) would not adequately capture the meteorology in the Pacific Northwes t. 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 co mplex 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 (G eomatrix) 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 Washin gton. Portions of Montana, Wyoming, Utah, Nevada and California are also included in th e 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 st atistical evaluation toolFINAL 10/11/06

9 

### METSTAT. CALMET Version 6.211, including a new over-water a lgorithm, 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 w ind 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 Modelingto 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 varyin g degree by the introduction of observational data, including surface, over-water, and up per 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 ai r winds should not be included in CALMET as they locally distort the MM5 wind fields and have n o significant effect on long range transport. As a result, the three states have judged th at the MM5 simulations more than adequately characterize the regional wind patterns. It sho uld 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 t errain within the modeling domain.



### 3.2.2 CALMET Control File Settings
These CALMET wind fields will be used by all BART-eligible so urces within the three states for both BART exemption and BART determination modeling. Th e wind fields have been computed by Geomatrix using CALMET Version 6.211. Details o f the parameter settings in CALMET are provided in Appendix C; however, the major assump tions are summarized below.

1) The initial-guess fields used the 12-km MM5 outputs, forec ast 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 ut ilize 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 sec ondly, the wind fields generated by CALMET was evaluated using standard st atistical evaluation techniques.
4) There are 10 vertical layers with face heights of 0, 20, 40, 6 5, 120, 200, 400, 700, 1200, 2200, and 4000 meters.
5) CALMET was run using NOOBS = 1. Upper air, precipitation, an d relative humidity data were taken from MM5.FINAL 10/11/06

10 

### 6) The surface wind observations were ignored by setting the r elative weight of surface winds to essentially zero (R1 = 1.0E-06). The only surface ob servation data that was effectively used in CALMET is cloud cover. This is essential ly 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 typ ical surface wind observation must be set at a small number because of the prese nce of local topographic features. As a result, the adjustment to or distortion of win d 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 BIA S = 0, and ICALM = 0
9) The terrain scale factor TERRAD = 12
10) Land use and terrain data were developed using the North Ame rican 30-arc-second data



## 3.3 CALPUFF

The CALPUFF modeling will use Version 6.112. This protocol g enerally follows the recommendation of the IWAQM and FLAG guidance documents. De tails 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 Geo matrix and be provided as input-ready to CALPUFF.
2) The BART exemption modeling will examine the visibility im pairment 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 C lass I area, the exemption modeling will also group these sources in order to examine th eir cumulative impact. The computational modeling domain will be sufficient to includ e 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 recommendat ions of the FLMs.
7) Source elevations that will be entered in CALPUFF will not us e actual elevations but will be based on the modeled terrain surface used in CALMET for dev eloping wind fields. The same algorithm in CALMET that determines the elevations of the observational stations will be used to make this calculation. These modifi ed 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 CA LPUFF. Primary emission, species will include the input species PM , SO 2 

### , SO 4 

### , and NO x 

### ; and the additional modeled species HNO 3 

### and NO 3 

### . Emissions of H 2 

### SO 4 

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

### emissions. SO 2 

### emissions will be reviewed to ensure “doublecounting” is avoided.
The primary PM species will be treated as follows:

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 (SO 4 

### ) Non-SO 4 

### inorganic aerosol

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

### fraction (see NPS Web site listed below).
The states will work with the individual BART-eligible sour ces to develop appropriate PM speciation and size fractions. The following information s ources may be used in the development of the speciation and fractions:

x U.S. National Park Service (NPS) – the NPS has developed bothPM speciation and size fractions for several source categories. The informat ion is located at http://www2.nature.nps.gov/air/Permits/ect/index.cf m

x U.S. EPA – the EPA has developed generic PM speciation for all source categoriesFINAL 10/11/06

12 

### located at http://www.epa.gov/ttn/chief/emch/speciation/

.

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 SO 4 

### , NO 3 

### , PMF, SOA, EC 0.50 microns 1.5 PMC 5.00 microns 1.5



### 3.3.2 Ozone Background
Due to the number of BART-eligible sources and Class I areas b eing 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 f or 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 co mmonly used as background for Prevention of Significant Deterioration modeling in the Pa cific Northwest and will ensure that for BART exemption modeling, conditions are not ammonia lim ited. It is recognized that ammonia values may be lower in Class I areas; however, the BAR T 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 so urce. The geolocations of the receptor points and their elevations for the Class I areas th at will be used in the modeling are available for download from the National Park Service Web si te 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 POSTUT IL to calculate the visibility impairment:FINAL 10/11/06

13 

### 1) For the visibility calculation, Method 6 will be employed. This method uses monthly average relative humidity and f(RH) values for each Class I area as provided in Appendix B, which are based on the EPA Guidance for Regional Haze analy sis (EPA 2003).
2) Particulate species for the visibility analysis will incl ude SO 4 

### , NO 3 

### , EC, OC, PMF, and PMC, as reported in the CALPOST output files.
3) POSTUTIL will not be used to speciate modeled PM 10 

### concentrations, as PM 10 

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

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

### /NO 3 

### partition option in POSTUTIL will not be used for ammonia limiting.
4) Natural background extinction calculations will use the 2 0% 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 Natur al Visibility Conditions Under the Regional Haze Rule” (EPA 2003). The extinction coe fficients for the 20% best days have been calculated following the approach takenin the Draft Montana BART modeling protocol. This procedure uses the haze index (HI) i n deciviews at the 10th percentile (median of the 20% best days) and an activity fact or that is calculated for each Class I area. Tables providing the monthly f(RH) and 20% bes t 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 a ll Class I areas.

x The 98 th

### percentile value will be calculated for all BART-eligible so urces at each mandatory Class I area.
5) The CALPOST “LST” output files will be used to determine the 98 th

### percentile of visibility impairment for each receptor in CLASS I areas.
6) The contribution threshold has the implied level of precis ion equal to the level of precision reported by CALPOST. Therefore, the 98 th

### percentile value will be reported to three decimal places.



## 4. Interpretation of Results

The change in visibility impairment for the BART exemption m odeling 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, N o. 128, pf 39125).
The U.S. EPA recommends using the 98 th

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

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

14 

### in the following ways:

x The 8 th

### highest value for each year modeled

x The 22 nd

### highest value for the 3-year modeling period
Both methods will be used and the highest value of the two wil l be compared to the contribution threshold ( ' dv  0.5 dv). If there are more than 7 days with values greater thanthe 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 Met eorological 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 Calif ornia Riverside). March, 2005.
EPA (U.S. Environmental Protection Agency) 1998. Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendation s for Modeling Long Range Transport Impacts , EPA-454/R-98-019, December 1998.

EPA 2003. Guidance for Estimating Natural Visibility Conditions und er the Regional Haze Rule , EPA-454/B-03-005, September, 2003.

EPA 2006a. Conference call with Fish and Wildlife and U.S. EP A 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 Workgrou p (FLAG) 2000. Phase I Report

. December 2000.
Federal Register, Vol. 70, No. 128. Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations . pp. 39104 – 30172, July 6, 2005.FINAL 10/11/06

15 

### Appendix A
Mandatory Class I Federal Areas

and
Columbia River Gorge Scenic Area

Figure A-1
Map of BART-Eligible Sources and Class I Areas
Posted on Idaho DEQ’s Regional Haze BART Website http://www.deq.idaho.gov/air/prog_issues/pollutants /haze_bart.cfm

.FINAL 10/11/06

16 

### Table 1. Federal Mandatory Class I Areas.

Class I Area Federal Land Manager Idaho Craters of the Moon National Monument Park Service Hells Canyon Wilderness Forest Service Sawtooth Wilderness Forest Service Selway-Bitterroot Wilderness Forest Service Yellowstone National Park Park Service Oregon Crater Lake National Park Park Service Diamond Peak Wilderness Forest Service Eagle Cap Wilderness Forest Service Gearhart Mountain Wilderness Forest Service Hells Canyon Wilderness Forest Service Kalmiopsis Wilderness Forest Service Three Sisters Wilderness Forest Service Mount Hood Wilderness Forest Service Mount Jefferson Wilderness Forest Service Mount Washington Wilderness Forest Service Mountain Lakes Wilderness Forest Service Strawberry Mountain Wilderness Forest Service Washington Alpine Lakes Wilderness Forest Service Goat Rocks Wilderness Forest Service Glacier Peak Wilderness Forest Service Mount Adams Wilderness Forest Service Mount Ranier National Park Park Service North Cascades National Park Park Service Olympic National Park Park Service Pasayten Wilderness Forest Service Neighboring States Anaconda-Pintler Wilderness (MT) Forest Service Bob Marshall Wilderness (MT) Forest Service Cabinet Mountains Wilderness (MT) Forest Service Gates of the Mountain Wilderness (MT) Forest Service Glacier National Park (MT) Park Service Missions Mountain Wilderness (MT) Forest Service Scapegoat Wilderness (MT) Forest Service Red Rock Lakes Refuge (MT) Fish & Wildlife Service Bridger Wilderness (WY) Forest Service Fitzpatrick Wilderness (WY) Forest Service Grand Teton National Park (WY) Park Service North Absaroka Wilderness (WY) Forest Service Teton Wilderness (WY) Forest Service Washakie Wilderness (WY) Forest Service Caribous Wilderness (CA) Forest Service Lassen Volcanic National Park (CA) Park ServiceFINAL 10/11/06

17 

### Table 1. Federal Mandatory Class I Areas.

Class I Area Federal Land Manager Lava Beds National Monument (CA) Park Service Marble Mountain Wilderness (CA) Forest Service Redwood National Park (CA) Park Service South Warner Wilderness (CA) Forest Service Thousand Lakes Wilderness (CA) Forest Service Yolla Bolly-Middle Eel Wilderness (CA) Forest Service Jarbridge Wilderness (NV) Forest Service Hells Canyon is located in Idaho and Oregon. Yellowstone is located in Idaho, Montana and Wyoming.FINAL 10/11/06

18 

### Appendix B
Natural Visibility Background

and
Monthly Relative Humidity f(RH)FINAL 10/11/06

19 Adj ustment to s p eciated p articulate ( Western States ) to reflect 20% Best Visibility Da ys conditions Monthly f(RH) are from Appendix A of Draft Guidance for Estimating Natural Visibilit y Conditions under the RHR ( Sept. 200 3 )

. Background extinction coefficients (20% Bes t Days) have been calculated using Annual Avg bext, Best 20% bext, and activity factors.

Jan. Feb. Mar. Apr. Ma y June Jul y 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 2.2 3 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 3.2 4 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 SouthWarne r 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 Wilder n 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 1.4 0 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 2.3 1 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 3.0 5 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 3.8 6 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 2.6 4 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 1.9 7 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 3.1 5 3.32 3.86 4.42 4.46 0.053 0.044 1.33 0.208 0.222 0.009 BridgerWilderness W Y 2.52 2.35 2.34 2.19 2.10 1.80 1.50 1.49 1.74 2.00 2.44 2.42 0.0 46 0.038 1.14 0.178 0.190 0.008 FitzpatrickWilderness W Y 2.51 2.33 2.24 2.13 2.09 1.80 1.51 1.46 1.73 1.98 2.39 2.44 0.0 46 0.038 1.14 0.179 0.190 0.008 Grand Teton NP W Y 2.62 2.39 2.24 2.10 2.06 1.79 1.52 1.47 1.72 2.00 2.43 2.55 0.0 46 0.038 1.14 0.178 0.190 0.008 NorthAbsaroka W Y 2.43 2.27 2.24 2.17 2.14 1.93 1.69 1.56 1.76 2.04 2.35 2.40 0.0 46 0.038 1.14 0.178 0.190 0.008 TetonWilderness W Y 2.53 2.35 2.24 2.12 2.10 1.85 1.59 1.51 1.74 2.02 2.40 2.48 0.0 46 0.038 1.14 0.178 0.190 0.008 WashakieWilderness W Y 2.50 2.34 2.23 2.12 2.11 1.84 1.56 1.49 1.75 2.00 2.38 2.46 0.0 46 0.038 1.14 0.179 0.190 0.008 YellowstoneNP W Y 2.54 2.36 2.27 2.16 2.15 1.94 1.69 1.59 1.79 2.08 2.45 2.51 0.0 46 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 spe cies (RHFAC) Background extinction coefficients (20% Best Days)FINAL 10/11/06

20 

### Appendix C

CALMET Parameter ValuesFINAL 10/11/06

21 

### Appendix C CALMET Parameter Values

Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling Input Group Variable Description Default Value Recommend ed Value

0 DIADAT Input file: preprocessed surface temperature data (DIAG.DAT) User Defined 0 GEODAT Input file: Geophysical data (GEO.DAT) U ser Defined User Define 0 LCFILES Convert file name to lower case User De fined 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 Defi ned 0 NOWSTA Input files: Names of NOWSTA overwater st ations User Defined 0 0 NUSTA Number of upper air data sites User Defi ned 0 0 PACDAT Output file: in Mesopuff II format (PACOU T.DAT) User Defined 0 PRCDAT Input file: Precipitation data (PRECIP.DA T) User Defined 0 PRGDAT Input file: CSUMM prognostic wind data (P ROG.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 - rot ate 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 Define d 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 Def ined 30 2 XLAT2 Latitude of 2nd standard parallel User Def ined 60 2 XORIGKM Southwest grid cell X coordinate User D efined -572 2 YLON0 Southwest grid cell longitude User Defined -956 2 YORIGKM Southwest grid cell Y coordinate User D efined 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 fi le? T T 4 ICLOUD Is cloud data to be input as gridded fiel ds? (0 = No) 0 0 4 IFORMC Format of cloud data (2 = formatted) 2 2 4 IFORMP Format of precipitation data (2 = formatt ed) 2 2 4 IFORMS Format of surface data (2 = formatted) 2 2FINAL 10/11/06

22 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling Input Group Variable Description Default Value Recommend ed Value 4 NOOBS Use or non-use of surface, overwater, upper observations 1 4 NPSTA Number of stations in PRECIP.DAT User Def ined -1 4 NSSTA Number of stations in SURF.DAT file User Defined 115 5 ALPHA Empirical factor triggering kinematic effe cts 0.1 0.1 5 BIAS Surface/upper-air weighting factors (NZ val ues) 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 o bs 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 = u se similarity theory and ignore layer 1 of upper air s tation 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 (be tween 1 and NSSTA) User Defined 98 5 IUPT Station for lapse rates (between 1 and NUST A) User Defined 1

5 IUPWND Upper air station for domain winds (-1 = 1/r**2 in terpolation 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 N Z 10 5 LLBREZE Use Lake Breeze module F F 5 LVARY Use varying radius to develop surface wind s? F F 5 METBXID Station IDs in the region User Defined 5 NBAR Number of Barriers to interpolation User D efined 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 minimiz ation 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 an d 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 (k m) User Defined 200 5 RMIN Minimum extrapolation radius (km) 0.1 0.1

5 RMIN2 Distance (km) around an upper air site where verti cal 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 li ne) User Defined 0 5 XEBAR X coordinate of Ending of each barrier Us er Defined 0 5 XECST X Point User Defined 0 5 XG1 X Grid line 1 defining region of interest Us er 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 Us er Defined 0 5 YECST Y Point User Defined 0FINAL 10/11/06

23 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling Input Group Variable Description Default Value Recommend ed 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 win ds (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 lap se 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 1.0 0E-04 1.00E-04 6 HAFANG Half-angle for looking upwind (degrees) 3 0 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 parame ters 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 dataset s 16 16 6 IMIXH Method to compute the convective mixing hei ght 1 1 6 IRAD Form of temperature interpolation (1 = 1/r) 1 1

6 IRHPROG 3D relative humidity from observations or from prog nostic 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 cell s) 1 1 6 NFLAGP Method for precipitation interpolation (2 = 1/r**2) 2 2 6 NUMTS Max number of stations in temperature inte rpolations 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 convect ive mixing height growth overland 0.05 0.05

6 THRESHW Threshold buoyancy flux required to sustain convect ive 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 3 000 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 5 0FINAL 10/11/06

24 

### Appendix D

CALPUFF Parameter ValuesFINAL 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 V alue a Recommended Value 1 Run Control 1 METRUN Do we run all periods (1) o r 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 distrib ution (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 timescal e 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 1FINAL 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 V alue a Recommended Value

3 Species List 1 CSPECn Names of species modeled (for MESOPUFF II must be SO2-SO4-NOX-HNO3-NO3) User Defined

3 2 Specie Names Manner species will be modeled User Defined

3 3 Specie Groups Grouping of species if any User Defined 3 4 CGRUP 3 5 CGRUP

4 MapProjection XLAT1 Latitude of 1st standard par allel 4 XLAT2 Latitude of 2nd standard parallel 4 DATUM NWS84 4 1 NX Number of east-west grids of input meteorol ogy User Defined

4 2 NY Number of north-south grids of input meteorology User Defined 4 3 NZ Number of vertical layers of input meteorol ogy User Defined 4 4 DGRIDKM Meteorology grid spacing (km) User D efined 4 5 ZFACE Vertical cell face heights of input met eorology User Defined

4 6 XORIGKM Southwest corner (east-west) of input User Defined meteorology

4 7 YORIGIM Southwest corner (north-south) of inp ut 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 doma in User Defined 4 11 XTZ Base time zone of input meteorology User Defined 4 12 IBCOMP Southwest X-index of computational dom ain User Defined 4 13 JBCOMP Southwest Y-index of computational dom ain User Defined 4 14 IECOMP Northeast X-index of computational dom ain User Defined 4 15 JECOMP Northeast Y-index of computational dom ain User Defined 4 16 LSAMP Use gridded receptors? (T = Yes) F F 4 17 IBSAMP Southwest X-index of receptor grid Us er Defined 4 18 JBSAMP Southwest Y-index of receptor grid Us er Defined 4 19 IESAMP Northeast X-index of receptor grid Us er Defined 4 20 JESAMP Northeast Y-index of receptor grid Us er 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 = hourl y) 1 24 5 12 IDFRQ Dry deposition flux print interval (1 = hourly) 1 24 5 13 IWFRQ West deposition flux print interval (1 = hourly) 1 24

5 14 IPRTU Print output units (1 = g/m**3; g/m**2/s; 3 = ug/m3, ug/m2/s) 1 3 5 15 IMESG Status messages to screen? (1 = Yes) 1 2 5 16 LDEBUG Turn on debug tracking? (F = No) F F 5 16 IPFDEB First puff to track 1 1 5 17 NPFDEB (Number of puffs to track) (1) 1 5 18 NN1 (Met. Period to start output) (1) 1FINAL 10/11/06

27 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. Input Group Group

Description Sequence Variable Description Default V alue a Recommended Value 5 19 NN2 (Met. Period to end output) (10) 10

7 Dry Dep Chem Dry Gas Dep Chemical parameters of gaseous deposition species User Defined defaults

8 Dry Dep Size Dry Part. Dep Chemical parameters of particulate deposition species User Defined defaults

9 Dry Dep Misc 1 RCUTR Reference 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 missi ng 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 n ot 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 m eteorology) 0 0 12 18 XMXLEN Maximum slug length in units of DGRID KM 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 9 9 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 puf f (m) 1.0 1 12 25 SVMIN Array of minimum lateral turbulence (m /s) 6 * 0.50 6 * 0.50

12 26 SWMIN Array of minimum vertical turbulence ( m/s) 0.20,0.12,0.08, 0.06,0.03,0.01 6FINAL 10/11/06

28 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. Input Group Group

Description Sequence Variable Description Default V alue a Recommended Value 12 27 CDIV (1), (2) Divergence criterion for dw/dz (1/s) 0.01 (0.0,0.0) 0.0,0.0 12 28 WSCALM Minimum non-calm wind speed (m/s) 0. 5 0.5 12 29 XMAXZI Maximum mixing height (m) 3000 3000 12 30 XMINZI Minimum mixing height (m) 50 50

12 31 WSCAT Upper bounds 1st 5 wind speed classes (m/s) 1.54,3.09,5.14, 8. 23,10.8 1.54,3.09,5.14,8.

23,10.8

12 32 PLX0 Wind speed power-law exponents 0.07,0.07,0.10, 0.15,0.35,0.55 0.07,0.07,0.10,0.

15,0.35,0.55

12 33 PTGO Potential temperature gradients PG E and F (deg/km) 0.020,0.035 0.020,0.035

12 34 PPC Plume path coefficients (only if MCTADJ = 3) 0.5,0.5,0.5,0.5, 0.35,0.35 0.5,0.5,0.5,0.5,0.

35,0.35 12 35 SL2PF Maximum Sy/puff length 10.0 10.0 12 36 NSPLIT Number of puffs when puffs split 3 3 12 37 IRESPLIT Hours when puff are eligible to spl it User Defined 12 38 ZISPLIT Previous hour’s mixing height(minimu m)(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 hor izontally 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 splithorizontally 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 Use r Defined 13 2 IPTU Units of emission rates (1 = g/s) 1 13 3 NSPT1 Number of point source-species combinat ions 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 character istics User Defined

15 Volume Source Volume Volume sources characterist ics User Defined Sources 16 Line Source Line Sources Buoyant lines source c haracteristics User Defined 17 Receptors NREC Number of user defined receptors User Defined

17 Receptor Data Location and elevation (MSL) of receptors Use r DefinedFINAL 10/11/06

29 

### Appendix E

CALPOST Parameter ValuesFINAL 10/11/06

30 

### Appendix E CALPOST Parameter Values

Table F-1. Recommended CALPOST parameter values chosen by the Region 10 states for use in BART modeling Input Group Variable Description Default Value Recommended Value 1 ASPEC Species to process VISIB VISIB

1 ILAYER Layer/deposition code (1 = 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 specie s 2 2 2 RHMAX Maximum relative humidity (%) used in parti cle growth curve 98 95

2 LDRING Report results by Discrete receptor Ring, if Discre te Receptors used. (T = true) T Modeled species to be included in computing the l ight 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 tabl es Include BACKGROUND? T T 2 SPECPMC Species name used for particulates in MOD EL.DAT file: COARSE = PMC PMC 2 SPECPMF Species name used for particulates in MOD EL.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 ex tinction F F

2 MVISBK Method used for background light extinction (2 = Ho urly 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) u nique for each Class I area

2 BKSO4 Assume all hygroscopic species as SO4 (raw extincti on 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 selecte d 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 Relativ e 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 Emissio ns Limits

Table 3-1 CALPUFF Modeling System Figure 3-1 CALMET Meteorological Domain1-1

SECTION 1 

# Introduction and Protocol Objectives

1.1 Background The U.S. Environmental Protection Agency (EPA) issu ed 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 d esigned to help states do the following: (1) identify those sources that must comply with th e BART requirement and (2) determine the level of control technology that represents BAR T for each source. The Portland General Electric (PGE) coal-fired power plant located in Bo ardman, Oregon (the Boardman plant) is a BART-eligible source for which a BART emission li mit evaluation is required. The BART Guideline requires a modeling analysis for these ty pes of sources. This document presents the protocol for the determination modeling analysi s. 

# 1.2 Objectives The protocol presented here is based on the combine d agency protocol developed by the Idaho Department of Environmental Quality (IDEQ), t he Oregon Department of Environmental Quality (ODEQ), and the Washington De partment of Ecology (WDOE) (ODEQ, 2006). The objectives of this protocol are a s follows:

x Describe determination modeling approach

x Present determination modeling methodology

x Define emissions and stack parameters for all contr ol options to be modeled

x Define presentation of results2-1

SECTION 2 

# Modeling Approach

The modeling analysis will be used to evaluate the visibility improvements of various BART control options on Class I areas in Oregon and Wash ington that could be affected by the Boardman plant. These areas are presented in Append ix A. Although not a Class I area, the Columbia River Gorge Scenic Area will also be evalu ated in the BART determination modeling, for informational purposes only. Both pre-BART control and post-BART control scenari os will be analyzed to compare visibility. Maximum 24-hour past actual emissions w ill be compared with future 24-hour maximum emissions and analyzed on a pollutant-by-po llutant basis. Frequency, magnitude, and duration of impairment will be evaluated in the determination analysis. Sulfur dioxide (SO 2 ), oxides of nitrogen (NO x ), and direct particulate matter (PM) emissions, including both PM 10 and PM 2.5, will be included in the determination modeling ana lysis, as required in the BART Guideline. Volatile organic co mpound (VOC) and ammonia emissions will not be included in the analysis. Consistent with the intent of the BART Guideline, t he natural visibility background is defined as the 20 percent best days. The natural ba ckground values for Class I areas will be consistent with those provided in the combined agen cy 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 CA LPUFF modules and their version numbers that will be used in the determination mode ling are presented in Table 3-1. Modeling parameters for each module are described in thi s 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 pro vided 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 (k m) MM5 outputs, forecast hours 13 – 24 from every 00Z and 12Z initialization, taken from U niversity of Washington (UW) archives, for the 3 years from January 2003 throughDecember 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, precip itation, and relative humidity data were taken from MM5. 5. The surface wind observations were ignored by set ting the relative weight of surface winds to essentially zero (R1 = 1.0E-06). Cloud cov er data were the only surface observation data that were effectively used in CALM ET. 6. Precipitation data were obtained from MM5, so MM5 NPSTA = -1. 7. No weighting of surface and upper air observation s, and BIAS = 0, and ICALM = 0.
8. The terrain scale factor TERRAD = 12.3-2

9. Land use and terrain data were developed using th e North American 30-arc-second data. 10. The dispersion modeling will use CALMET wind fie lds for the 3-year period 2003–2005. These data were developed for the three states usin g 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 pr ovided 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 comp utational 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 re commendations 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 CAL MET for developing wind fields. The same algorithm in CALMET that determines the el evations 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, SO 2 , sulfates (SO 4 ), and NO x ; and the additional modeled species nitric acid (H NO 3 ) and nitrates (NO 3 ). Sulfur dioxide emissions will be reviewed to ensure that “ double-counting” is avoided.
Both filterable and condensable fractions of PM wil l be included in the analysis. The condensable fraction will be treated as primary emi ssions in the CALPUFF input file and assumed to be 100 percent in the PM 2.5 fraction. The primary PM species will be treated a s 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 [SO A]) Inorganic Aerosol (SO 4 ) Non-SO 4 inorganic aerosol The primary emission species sizing are presented a s follows:

Pollutant Mean Diameter Standard Deviation
SO 4 , NO 3 , PMF, SOA, EC 0.50 microns 1.5
PMC 5.00 microns 1.5



## 3.2.2 Background Values A single ozone background value of 60 parts per bil lion (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 Boar dman 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 Riv er Gorge Scenic Area were provided by ODEQ. 

# 3.3 CALPOST and Visibility Post-Processing Details of the parameter setting in CALPOST are pro vided 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 eachClass I area as provided in Appendix B, which are based on the EPA Guidance forRegional Haze analysis (EPA, 2003). 2. Particulate species for the visibility analysis w ill include SO 4 , NO 3 , EC, OC, PMF, and PMC, as reported in the CALPOST output files. 3. POSTUTIL will not be used to speciate modeled PM 10concentrations, as PM 10will be speciated into its components (PMF, PMC, SOA, EC, S O 4 ) and entered as primary emissions in CALPUFF. In addition, HNO 3 /NO 3 partition option in POSTUTIL will not be used for ammonia limiting. 4. Natural background extinction calculations will u se the 20 percent best days for each Class I area. The natural background for the 20 per cent best days has been refined from that which is in “ Guidance for Estimating Natural Visibility Conditio ns 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 deciview s at the 10th percentile (median of the 20 percent best days) and an activity factor th at is calculated for each Class I area. Table B-1, providing the monthly f(RH) and 20 perce nt best days coefficients, is provided in Appendix B and is based on data from EP A (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 al l BART-eligible sources at each mandatory Class I area. 5. The CALPOST “LST” output files will be used to de termine 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 s ection will provide ground-level concentrations of visibility-impairing pollutants. The concentration estimates from CALPUFF are used with the current FLAG equation to calculate the extinction coefficient, as shown below:
b ext = 3 f(RH) [(NH 4 ) 2SO 4 ] + 3 f(RH) [NH 4 NO 3 ] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + b Ray As described in the IWAQM Phase 2 Report (EPA, 1998 ), the change in visibility for the BART exemption analysis is compared against backgro und conditions. The delta-deciview, ' dv, value is calculated from the source’s contribut ion to extinction, b ext (source) , and background extinction, b ext(bkg) , as follows:
' dv = 10 ln [ ( b ext(bkg) + b ext (source) ) / ( b ext(bkg) ) ]4-1

SECTION 4 

# Emissions and Stack Data

Emissions to be modeled for determination 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 derive d by Black & Veatch for PGE as summarized in a memorandum presented in Appendix G. The control scenarios being modeled for the determi nation modeling are listed below:
1. NO xControlled Outlet Conditions a. Selective Catalytic Reduction b. New Low-NO xBurners with Modified Over-Fire Air (OFA) System
2. SO 2Controlled Outlet Conditions
a. Wet Flue Gas Desulfurization b. Semi-Dry Flue Gas Desulfurization Existing emissions of PM are already controlled by an electrostatic precipitator. As a result, emissions of SO 2and NO xare each more than 10 times the emissions of parti culate. The exemption modeling conducted by ODEQ shows the cont ribution of PM to the highest visibility impairment days to be less than 2 percen t. Consequently, PM controls will not be included in the determination analysis. Consistent with the BART guidelines, the required m aximum 24-hour emission rates used in the modeling will be based on a 30-day rolling aver age permit limit. Each of the above control options will be analyzed for each pollutantto determine the most effective control by pollutant. Following that analysis, the model wi ll be run combining the most effective controls by pollutants to determine the maximum imp rovement in visibility.5-1

SECTION 5 

# Presentation of Results

The improvement in visibility for BART determinatio n is based on the change in HI from pre-BART control to post-BART control for PGE relat ive to natural background for each Class I area. Comparison tables for pre-BART control and post-BART cont rol visibility impacts will be documented for use in the BART cont rol evaluation. Frequency, magnitude, and duration of any visibility impairment will be i ncluded in the documentation.6-1

SECTION 6 

# References

Federal Land Managers’ Air Quality Related Values W orkgroup (FLAG). 2000. Phase I Report . December 2000. Oregon Department of Environmental Quality (ODEQ ) . 2006. Modeling Protocol for Washington, Oregon, and Idaho: Protocol for the App lication of the CALPUFF Modeling System Pursuant to the Best Available Retrofit Tech nology (BART) Regulation. October 11, 2006. U.S. Environmental Protection Agency (EPA). 1998. Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recomme ndations for Modeling Long Range Transport Impacts . EPA-454/R-98-019. December 1998. U.S. Environmental Protection Agency (EPA). 2003. Guidance for Estimating Natural Visibility Conditions under the Regional Haze Rule . EPA-454/B-03-005. September 2003. U.S. Environmental Protection Agency (EPA). 2005. Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations . Federal Register, Vol. 70, No. 128. Pp. 39104–30172. July 6, 2005.

## A PPENDIX 

## A 

# Class I Federal AreasTable A-1. Federal Mandatory Class I Areas Evaluated in PGE Bo ardman Analysis. Class I Area Federal Land Manager Oregon Diamond Peak Wilderness Forest Service Eagle Cap Wilderness Forest Service Hells Canyon Wilderness Forest Service Three Sisters Wilderness Forest Service Mount Hood Wilderness Forest Service Mount Jefferson Wilderness Forest Service Mount Washington Wilderness Forest Service Strawberry Mountain Wilderness Forest Service Washington Alpine Lakes Wilderness Forest Service Goat Rocks Wilderness Forest Service Glacier Peak Wilderness Forest Service Mount Adams Wilderness Forest Service Mount Rainier National Park Park Service North Cascades National Park Park Service

## A PPENDIX 

## B



# Natural Visibility Background and Monthly Relative Humidity f(RH)Table B-1 Adjustment to speciated particulate (West ern 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 spe cies (RHFAC) Background extinction coefficients (20 % Best Days) Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec. BKSO4 BKNO3 BKPM C 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 0.2 22 0.009 Eagle Cap OR 3.77 3.16 2.47 2.10 2.04 1.87 1.61 1.5 6 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 2.3 9 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 0.2 25 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 0.2 23 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 0.22 2 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 3.5 1 3.51 5.03 0.569 0.231 4.85 1.05 0.217 0.205

## A PPENDIX 

## C



# CALMET Parameter ValuesAppendix C CALMET Parameter Values

Table C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling Input Group Variable Description Default Value Recommended Value 0 DIADAT Input file: preprocessed surface temperat ure data (DIAG.DAT) User Defined 0 GEODAT Input file: Geophysical data (GEO.DAT) U ser Defined User Define 0 LCFILES Convert file name to lower case User De fined 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 Defi ned 0 NOWSTA Input files: Names of NOWSTA overwater st ations User Defined 0 0 NUSTA Number of upper air data sites User Defined 0 0 PACDAT Output file: in Mesopuff II format (PACOU T.DAT) User Defined 0 PRCDAT Input file: Precipitation data (PRECIP.DA T) User Defined 0 PRGDAT Input file: CSUMM prognostic wind data (P ROG.DAT) User Defined 0 SEADAT Input files: Names of NOWSTA overwater st ations (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 - rot ate 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 Define d 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 Def ined 30 2 XLAT2 Latitude of 2nd standard parallel User Def ined 60 2 XORIGKM Southwest grid cell X coordinate User D efined -572 2 YLON0 Southwest grid cell longitude User Defined -956 2 YORIGKM Southwest grid cell Y coordinate User D efined 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 fi le? T TTable C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling

Input Group Variable Description Default Value Recommended Value 4 ICLOUD Is cloud data to be input as gridded fiel ds? (0 = No) 0 0 4 IFORMC Format of cloud data (2 = formatted) 2 2 4 IFORMP Format of precipitation data (2 = formatt ed) 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 Def ined -1 4 NSSTA Number of stations in SURF.DAT file User Defined 115 5 ALPHA Empirical factor triggering kinematic effe cts 0.1 0.1 5 BIAS Surface/upper-air weighting factors (NZ val ues) 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 = u se 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 (be tween 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 in terpolation 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 N Z 10 5 LLBREZE Use Lake Breeze module F F 5 LVARY Use varying radius to develop surface wind s? F F 5 METBXID Station IDs in the region User Defined 5 NBAR Number of Barriers to interpolation User D efined 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 minimiz ation 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 an d 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 (k m) User Defined 200 5 RMIN Minimum extrapolation radius (km) 0.1 0.1

5 RMIN2 Distance (km) around an upper air site where verti cal 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 0Table C-1 Recommended CALMET parameters chosen by the Region 10 states for use in BART modeling

Input Group Variable Description Default Value Recommended Value 5 XBCST X Point defining the coastline (straight li ne) User Defined 0 5 XEBAR X coordinate of Ending of each barrier Us er Defined 0 5 XECST X Point User Defined 0 5 XG1 X Grid line 1 defining region of interest Us er 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 Us er 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 win ds (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 lap se 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 1.0 0E-04 1.00E-04 6 HAFANG Half-angle for looking upwind (degrees) 3 0 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 parame ters 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 dataset s 16 16 6 IMIXH Method to compute the convective mixing hei ght 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 cell s) 1 1 6 NFLAGP Method for precipitation interpolation (2 = 1/r**2) 2 2 6 NUMTS Max number of stations in temperature inte rpolations 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 convect ive mixing height growth overland 0.05 0.05

6 THRESHW Threshold buoyancy flux required to sustain convect ive 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 3 000 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 5 0

## A PPENDIX 

## D



# CALPUFF Parameter ValuesAppendix D CALPUFF Parameter Values

Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling. Input Group Group

Description Sequence Variable Description Default Value a Recommended Value 1 Run Control 1 METRUN Do we run all periods (1) o r 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 distrib ution (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 timescal e 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 1Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling.

Input Group Group

Description Sequence Variable Description Default Value a Recommended Value

3 Species List 1 CSPECn Names of species modeled (for MESOPUFF II must be SO2-SO4-NOX-HNO3-NO3) User Defined

3 2 Specie Names Manner species will be modeled User Defined

3 3 Specie Groups Grouping of species if any User Defined 3 4 CGRUP 3 5 CGRUP

4 MapProjection XLAT1 Latitude of 1st standard par allel 4 XLAT2 Latitude of 2nd standard parallel 4 DATUM NWS84 4 1 NX Number of east-west grids of input meteorol ogy 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 meteorol ogy User Defined 10 4 4 DGRIDKM Meteorology grid spacing (km) User D efined 4

4 5 ZFACE Vertical cell face heights of input met eorology 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 inp ut 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 dom ain User Defined 105 4 13 JBCOMP Southwest Y-index of computational domain User Defined 79 4 14 IECOMP Northeast X-index of computational dom ain User Defined 242 4 15 JECOMP Northeast Y-index of computational dom ain User Defined 252 4 16 LSAMP Use gridded receptors? (T = Yes) F F 4 17 IBSAMP Southwest X-index of receptor grid Us er Defined 4 18 JBSAMP Southwest Y-index of receptor grid Us er Defined 4 19 IESAMP Northeast X-index of receptor grid Us er Defined 4 20 JESAMP Northeast Y-index of receptor grid Us er 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 = hourl y) 1 24 5 12 IDFRQ Dry deposition flux print interval (1 = hourly) 1 24 5 13 IWFRQ West deposition flux print interval (1 = hourly) 1 24

5 14 IPRTU Print output units (1 = g/m**3; g/m**2/s; 3 = ug/m3, ug/m2/s) 1 3 5 15 IMESG Status messages to screen? (1 = Yes) 1 2 5 16 LDEBUG Turn on debug tracking? (F = No) F FTable D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling.

Input Group Group

Description Sequence Variable Description Default Value a Recommended Value 5 16 IPFDEB First puff to track 1 1 5 17 NPFDEB (Number of puffs to track) (1) 1 5 18 NN1 (Met. Period to start output) (1) 1 5 19 NN2 (Met. Period to end output) (10) 10

7 Dry Dep Chem Dry Gas Dep Chemical parameters of gaseous deposition species User Defined defaults

8 Dry Dep Size Dry Part. Dep Chemical parameters of particulate deposition species User Defined defaults

9 Dry Dep Misc 1 RCUTR Reference 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 missi ng 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 n ot 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 m eteorology) 0 0 12 18 XMXLEN Maximum slug length in units of DGRID KM 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 9 9 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 puf f (m) 1.0 1 12 25 SVMIN Array of minimum lateral turbulence (m /s) 6 * 0.50 6 * 0.50Table D-1 Recommended CALPUFF Parameters chosen by EPA Region 10 states for use in BART modeling.

Input Group Group

Description Sequence Variable Description Default Value a Recommended Value

12 26 SWMIN Array of minimum vertical turbulence ( m/s) 0.20,0.12,0.08, 0.06,0.03,0.01 6 12 27 CDIV (1), (2) Divergence criterion for dw/dz (1/s) 0.01 (0.0,0.0) 0.0,0.0 12 28 WSCALM Minimum non-calm wind speed (m/s) 0. 5 0.5 12 29 XMAXZI Maximum mixing height (m) 3000 3000 12 30 XMINZI Minimum mixing height (m) 50 50

12 31 WSCAT Upper bounds 1st 5 wind speed classes (m/s) 1.54,3.09,5.14, 8. 23,10.8 1.54,3.09,5.14,8.

23,10.8

12 32 PLX0 Wind speed power-law exponents 0.07,0.07,0.10, 0.15,0.35,0.55 0.07,0.07,0.10,0.

15,0.35,0.55

12 33 PTGO Potential temperature gradients PG E and F (deg/km) 0.020,0.035 0.020,0.035

12 34 PPC Plume path coefficients (only if MCTADJ = 3) 0.5,0.5,0.5,0.5, 0.35,0.35 0.5,0.5,0.5,0.5,0.

35,0.35 12 35 SL2PF Maximum Sy/puff length 10.0 10.0 12 36 NSPLIT Number of puffs when puffs split 3 3 12 37 IRESPLIT Hours when puff are eligible to spl it User Defined 12 38 ZISPLIT Previous hour’s mixing height(minimu m)(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 hor izontally 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 splithorizontally 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 Use r Defined 13 2 IPTU Units of emission rates (1 = g/s) 1 13 3 NSPT1 Number of point source-species combinat ions 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 character istics User Defined

15 Volume Source Volume Volume sources characteris tics User Defined Sources 16 Line Source Line Sources Buoyant lines source c haracteristics User Defined 17 Receptors NREC Number of user defined receptors User Defined

17 Receptor Data Location and elevation (MSL) of receptors User Def ined

## A PPENDIX 

## E



# CALPOST Parameter ValuesAppendix E CALPOST Parameter Values

Table E-1. Recommended CALPOST parameter values chosen by the Region 10 states for use in BART modeling Input Group Variable Description Default Value Recommended

Value 1 ASPEC Species to process VISIB VISIB

1 ILAYER Layer/deposition code (1 = CALPUFF concentrations; -3 = wet+dry deposition

fluxes) 1 1 1 LBACK Add Hourly Background Concentrations/Fluxes ? F F 1 MFRH Particle growth curve for hygroscopic specie s 2 2 2 RHMAX Maximum relative humidity (%) used in parti cle 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 l ight 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 tabl es Include

BACKGROUND? T T 2 SPECPMC Species name used for particulates in MOD EL.DAT file: COARSE = PMC PMC 2 SPECPMF Species name used for particulates in MOD EL.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 ex tinction F F

2 MVISBK Method used for background light extinction (2 = Ho urly RH adjustment; 6 =

FLAG seasonal f(RH)) 2 or 6 6 2 RHFAC Monthly RH adjustment factors from FLAG (un ique for each Class I area) Yes if 6 EPA

Background monthly extinction coefficients (FLAG) u nique for each Class I area
2 BKSO4 Assume all hygroscopic species as SO4 (raw extincti on 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 selecte d T F 3 LTOPN 1 3 NTOP 1 3 ITOP

## A PPENDIX 

## F



# Emission Rates and Stack ParametersPGE Boardman Unit 1 - Flue Gas Emissions Data PM 10 Speciation: ----------------Filterable---------------- -------- ------Condensable------------ Baseline Case - Existing Operation Flow (acfm) Stack

Velocity (ft/s) Temp.

(°F) NO x (lb/hr) SO 2

(lb/hr) PM 10

(lb/hour) Elemental

Carbon (lb/hour) PM Fine

(lb/hour) PM

Coarse (lb/hour) Organic

Carbon (lb/hour) Inorganic

Aerosol (lb/hour) Non-SO 2 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

NO xControlled Outlet Conditions

Flow (acfm) Stack

Velocity (ft/s) Temp.

(°F) NO x (lb/hr) SO 2

(lb/hr) PM 10

(lb/hour) Elemental

Carbon (lb/hour) PM Fine

(lb/hour) PM

Coarse (lb/hour) Organic

Carbon (lb/hour) Inorganic

Aerosol (lb/hour) Non-SO 2 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 NO xBurners 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

SO 2 Controlled Outlet Conditions

Flow (acfm) Stack

Velocity (ft/s) Temp.

(°F) NO x (lb/hr) SO 2

(lb/hr) PM 10

(lb/hour) Elemental

Carbon (lb/hour) PM Fine

(lb/hour) PM

Coarse (lb/hour) Organic

Carbon (lb/hour) Inorganic

Aerosol (lb/hour) Non-SO 2 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) SO 2 based on no SO 2 to SO 3 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 Cal puff modeling for the PGE Boardman facility, as sub mitted, includes:
1) A summary of the BART Modeling Protocol for Was hington, Oregon, and Idaho (2006), which was developed by the three states to cover both the Exemption and Determination phase s of the modeling, 2) Engineering data on possible controls, with a p roposed set of four controls and their respective e mission rates and stack parameters that will be evaluated in the Determinat ion modeling.
In that the Calpuff modeling portion of the revised Boardman protocol summarizes and highlights the ap proved Modeling Protocol for Washington, Oregon, and Idaho , the modeling portion of the revised protocol is a pproved for use in the Determination or control evaluation phase of the BART analysis.

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

-----Original Message----- From: Don.Caniparoli@CH2M.com [mailto:Don.Caniparoli@CH2 M.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; R ick.Tetzloff@pgn.com; Steven.Anderson@pgn.com; natalie.liljenwall@ch2m.com Subject: Revised Protocol
Attached is the revised protocol as we discussed to day.

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 Subj ect: RE: Revised Protocol CC: <Patty.Jacobs@state.or.us>, <Ray.Hendricks@pgn.com>, <Rick.Tetzloff@pgn.com>,

<Steven.Anderson @p g n.com>, <natalie.lil j enwall @ ch2m.com> Page 1 of 1 Message

2/12/2007 file://C:\Documents and Settin g s\e65404\Local Settin g s\Temp \GW } 00001.HTMFrom: ALLEN Philip [mailto:ALLEN.Philip@deq.state.or.us]

Sent: Tuesday, August 28, 2007 12:21 PM To: ray.hendricks@pgn.com Cc: Caniparoli, Don/PDX; FISHER Mark Subject: Use of onzone.dat file for BART Ray, As you know, an ozone.dat for use in the Calpuf f BART Exemption modeling was developed by Eri Ottersburg (SLR, International) and Mary Beth Yansu ra (CH2M Hill), with input and review by Oregon DEQ. This file would be used in lieu of the defaul t 60 ppb value that was specified in the three-stat es BART Modeling Protocol. The ozone data incorporate d in the file was compiled from state and federal ozone monitors in the three state area. Af ter discussions with EPA Region 10, the Federal Land Managers (Forest Service, U.S. Fish and Wildli fe, and National Park Service), and Washington State and Idaho, this ozone.dat file is considered an addition to the protocol and acceptable for use in the BART modeling. If you have any questions, please don't hesitat e to contact me.

Phil Philip Allen AQ Division Oregon DEQ 503.229.6904 allen.philip@deq.state.or.us