# Public Service Company of New Mexico

San Juan Generating Station

Best Available Retrofit Technology Analysis

Black & Veatch Project: 146646 Black & Veatch File No.: 41.1402

Issue Date and Revision June 6, 2007, FinalPNM San Juan Generating Station Contents

060607 TC-1 

### Contents

Acronyms......................................................................................................................A C-1

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

1.0 Introduction and Objectives................................................................................. 1-1 1.1 Introduction to the SJGS Consent Decree ............................................... 1-1 1.2 Source Description and Background ....................................................... 1-2 1.3 BART Analysis Methodology ................................................................. 1-3 1.3.1 Identify All Available Retrofit Control Technologies (Step 1) ...................................................................................... 1-4 1.3.2 Eliminate Technically Infeasible Options (Step 2) ................... 1-4 1.3.3 Evaluate Control Effectiveness of Remaining Control Technologies (Step 3)................................................................ 1-5 1.3.4 Evaluate Impacts and Document the Results (Step 4)............... 1-5 1.3.5 Evaluate Visibility Impacts (Step 5).......................................... 1-6 1.3.6 Select the Best Alternative ........................................................ 1-7

2.0 Basis of Analysis.................................................................................................. 2-1 2.1 Design Basis............................................................................................. 2-1 2.2 Economic Data......................................................................................... 2-1 2.2.1 Capital Cost Estimates............................................................... 2-1 2.2.2 Annual Operating and Maintenance Cost Estimate................... 2-5 2.3 Target Emissions...................................................................................... 2-7 2.4 Project Assumptions ................................................................................ 2-8 2.5 Modeling Baseline Conditions................................................................. 2-8

3.0 Identification of All Available Retrof it Emissions Control Technologies ......... 3-1 3.1 NO x 

### Control Technologies....................................................................... 3-1 3.1.1 Low NO x 

### Burners, Overfire Air with Neural Network ............. 3-2 3.1.2 Selective Non-Catalytic Reduction ........................................... 3-4 3.1.3 Selective Catalytic Reduction.................................................... 3-6 3.1.4 SNCR/SCR Hybrid.................................................................... 3-8 3.1.5 Gas Reburn ................................................................................ 3-9 3.1.6 Mobotec ROFA and ROTAMIX............................................. 3-11 3.1.7 NO x 

### Star.................................................................................... 3-12 3.1.8 ECOTUBE............................................................................... 3-12 Contents (Continued)PNM San Juan Generating Station Contents

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### 3.1.9 PowerSpan............................................................................... 3-13 3.1.10 Phenix Clean Coal Combustion System.................................. 3-14 3.1.11 e-SCRUB................................................................................. 3-16 3.2 Particulate Matter C ontrol Technologies............................................... 3-18 3.2.1 Flue Gas Conditioning with Hot-Side ESP ............................. 3-18 3.2.2 Pulse Jet Fabric Filter .............................................................. 3-18 3.2.3 Compact Hybrid Particulate Collector .................................... 3-21 3.2.4 Max-9 Electrostatic Fabric Filter............................................. 3-21 3.3 Draft System Impacts............................................................................. 3-23 3.3.1 New Booster Fans.................................................................... 3-23 3.3.2 New Forced Draft Fans ........................................................... 3-23 3.3.3 Balanced Draft Conversion ..................................................... 3-23

4.0 BART Implications of the Cons ent Decree Technology Selection .................... 4-1 4.1 NO x 

### Consent Decree Control Technologies ............................................ 4-1 4.1.1 Description of NO x 

### Consent Decree Upgrades ......................... 4-1 4.1.2 NO x 

### Consent Decree Upgrades Control Effectiveness ............. 4-1 4.1.3 NO x 

### Consent Decree Upgrades Cost-Effectiveness.................. 4-2 4.1.4 Summary of NO x 

### Consent Decree Upgrades ............................ 4-2 4.2 Particulate Matter Consent D ecree Control Technologies....................... 4-5 4.2.1 Description of PM Consent Decree Upgrades........................... 4-5 4.2.2 PM Consent Decree Upgrades Control Effectiveness............... 4-6 4.2.3 PM Consent Decree Upgrades Cost-Effectiveness ................... 4-6 4.2.4 Summary of PM Consent Decree Upgrades.............................. 4-6 4.3 Summary of Consent Decree Control Technologies ............................... 4-7

5.0 Technical Feasibility of Additional Control Te chnology Alternatives............... 5-1 5.1 Technically Infeasible Additional NO x 

### Control Technology Alternatives.............................................................................................. 5-2 5.1.1 Selective Non-Catalytic Reduction ........................................... 5-2 5.1.2 Natural Gas Reburn ................................................................... 5-2 5.1.3 Mobotec ROFA and ROTAMIX............................................... 5-2 5.1.4 NO x 

### Star ..................................................................................... 5-3 5.1.5 ECOTUBE................................................................................. 5-3PNM San Juan Generating Station Contents

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### Contents (Continued)

5.1.6 PowerSpan................................................................................. 5-3 5.1.7 Phenix Clean Combustion ......................................................... 5-3 5.1.8 e-SCRUB................................................................................... 5-3 5.2 Technically Infeasible A dditional PM Control Technology Alternatives.............................................................................................. 5-4 5.2.1 Flue Gas Conditioning with Hot-Side ESP ............................... 5-4 5.2.2 Compact Hybrid Particulate Collector ...................................... 5-4 5.2.3 Max-9 Electrostatic Fabric Filter............................................... 5-4 5.3 Technical Feasibility Summary ............................................................... 5-4

6.0 Evaluation of Technically Feasible Additional Control Technology Alternatives.......................................................................................................... 6-1 6.1 Control Effectiveness............................................................................... 6-1

7.0 Impact Analysis and Cost-Eff ectiveness of Additional Control Technology Alternatives...................................................................................... 7-1 7.1 Types of Impact Analyses........................................................................ 7-1 7.2 Methods of Impact Analysis .................................................................... 7-1 7.2.1 Cost of Compliance ................................................................... 7-2 7.2.2 Energy Impacts.......................................................................... 7-2 7.2.3 Non-Air Quality Environmental Impacts .................................. 7-2 7.2.4 Remaining Useful Life .............................................................. 7-2 7.3 Cost-Effectiveness ................................................................................... 7-3 7.4 Impact Analysis and Cost-Effectiveness Results..................................... 7-3 7.4.1 Dominant Control Technologies ............................................... 7-9 7.4.2 Cost-Effectiveness Comparison ................................................ 7-9

8.0 Visibility Impacts................................................................................................. 8-1 8.1 Introduction.............................................................................................. 8-1 8.2 Source Description................................................................................... 8-2 8.3 Location of Sources Versus Relevant Class I Areas................................ 8-2 8.4 Model Processing..................................................................................... 8-3 8.4.1 Modeling Domain...................................................................... 8-4 8.5 Geophysical and Meteorological Data..................................................... 8-5 8.5.1 Mesoscale Model Data .............................................................. 8-6 8.5.2 Surface Data Station and Processing......................................... 8-6 8.5.3 Upper Air Data Station and Processing..................................... 8-6PNM San Juan Generating Station Contents

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### Contents (Continued)

8.5.4 Precipitation Data Statio ns and Processing ............................... 8-6 8.5.5 Geophysical Data Processing (Terrain and Land Use).............. 8-9 8.5.6 CALMET................................................................................. 8-10 8.6 CALPUFF.............................................................................................. 8-10 8.6.1 CALPUFF Domain and Variables........................................... 8-11 8.6.2 Receptors ................................................................................. 8-11 8.6.3 Downwash ............................................................................... 8-12 8.6.4 Ozone Concentrations ............................................................. 8-13 8.6.5 Ammonia Concentrations........................................................ 8-13 8.6.6 Unit-Specific Source Data....................................................... 8-13 8.7 CALPOST.............................................................................................. 8-14 8.7.1 Light Extinction....................................................................... 8-14 8.7.2 Natural Background................................................................. 8-19 8.8 Modeling Results ................................................................................... 8-19 8.8.1 Consent Decree Baseline Scenario.......................................... 8-19 8.8.2 BART Control Technology Scenario ...................................... 8-20 8.8.3 WRAP RMC Baseline Scenario.............................................. 8-31 8.8.4 Summary.................................................................................. 8-31 8.9 Visibility Improvement Cost-Effectiveness........................................... 8-33

9.0 Conclusions.......................................................................................................... 9-1

Appendix A Design Basis Appendix B Design Concept Definitions Appendix C Cost Analysis Summary Appendix D Stack Outlet Conditi ons for Visibility Modeling Appendix E CALPUFF Modeling Support Documents

Tables

Table ES-1 Control and Cost-Effect iveness Results of Consent Decree Upgrades ................................................................................................ES-2 Table ES-2 Impact Analysis and Cost-Effectiveness Results for Additional NO x 

### Control Technology Alternatives...................................................ES-5 Table ES-3 Visibility Improvement Cost-Effectiveness Summary ..........................ES-6 Table 1-1 SJGS Characteristics Pr e-Consent Decree Operation.............................. 1-3PNM San Juan Generating Station Contents

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### Contents (Continued)

Tables (Continued)

Table 2-1 Typical Owner’s Cost Categories ............................................................ 2-3 Table 2-2 Economic Evaluation Factors .................................................................. 2-4 Table 2-3 Target Emissions...................................................................................... 2-7 Table 4-1 Consent Decree Technologi es Control Effectiveness (Annual Average Emissions Rates) ....................................................................... 4-3 Table 4-2 Control and Cost-Effectiv eness Results of Consent Decree Upgrades .................................................................................................. 4-4 Table 4-3 Coal Properties Comparison .................................................................... 4-5 Table 5-1 Technically Feasible Additional NO x 

### Control Technology Alternatives.............................................................................................. 5-5 Table 5-2 Technically Feasible Additional PM Control Technology Alternatives.............................................................................................. 5-6 Table 6-1 NO x 

### Control Effectiveness for Additional Control Technology Alternatives (Annual Average Emissions Rates)..................................... 6-2 Table 7-1 Impact Analysis and Cost -Effectiveness Results of Additional NO x 

### Control Technologies....................................................................... 7-4 Table 8-1 Class I Areas ............................................................................................ 8-2 Table 8-2 Model Versions........................................................................................ 8-4 Table 8-3 CALPUFF Modeli ng Stack Parameters................................................. 8-15 Table 8-4 Consent Decree Baseline CALPUFF Modeling Emission Rates .......... 8-16 Table 8-5 NO x 

### BART Control Technologies CALPUFF Modeling Emission Rates....................................................................................................... 8-17 Table 8-6 Monthly Relative Humidity Factors ...................................................... 8-18 Table 8-7 Average Annual Natural Background Levels........................................ 8-19 Table 8-8 Baseline (Consent Decree) Visibility Modeling Results 98th Percentile for Each Year (dv) ........................................................ 8-20 Table 8-9 SCR Visibility Modeling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-21 Table 8-10 Hybrid Visibility Mode ling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-22 Table 8-11 Unit 1 SCR Visibility Mode ling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-23 Table 8-12 Unit 2 SCR Visibility Mode ling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-24 Table 8-13 Unit 3 SCR Visibility Mode ling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-25 Table 8-14 Unit 4 SCR Visibility Mode ling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-26PNM San Juan Generating Station Contents

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### Contents (Continued)

Tables (Continued)

Table 8-15 Unit 1 Hybrid Visibility M odeling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-27 Table 8-16 Unit 2 Hybrid Visibility M odeling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-28 Table 8-17 Unit 3 Hybrid Visibility M odeling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-29 Table 8-18 Unit 4 Hybrid Visibility M odeling Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-30 Table 8-19 WRAP RMC Baseline Modeli ng Results 98th Percentile Impact for Each Year (dv) ................................................................................. 8-32 Table 8-20 Average Change in Visibility Improvement.......................................... 8-33 Table 8-21 Visibility Improvement Cost-Effectiveness Summary .......................... 8-34

Figures

Figure 3-1 Schematic of SNCR System with Multiple Injection Levels................... 3-5 Figure 3-2 Schematic Diagram of a Typical SCR Reactor........................................ 3-7 Figure 3-3 Schematic of Gas Reburn System.......................................................... 3-10 Figure 3-4 Mobotec ROFA and ROTA MIX Simplified Process Flow Diagram (Mobotec USA)....................................................................... 3-12 Figure 3-5 ECOTUBE Insta llation in a Boiler ........................................................ 3-13 Figure 3-6 ECO Process Flow Di agram (Source: PowerSpan)............................... 3-14 Figure 3-7 Phenix Clean Coal Process Fl ow Diagram. (Source: Phenix) ............... 3-15 Figure 3-8 e-SCRUB Proce ss Flow Diagram (Source: http://www.escrub.com/escrubprocess.htm).......................................... 3-16 Figure 3-9 Pulse Jet Fabric Filter Compartment (Source: Babcock & Wilcox) .................................................................................................. 3-20 Figure 3-10 Max-9 Electrostatic Filt er (Source: GE Environmental) ....................... 3-22 Figure 7-1 SJGS Unit 1 Additional NO x 

### Control Technology CostEffectiveness............................................................................................ 7-5 Figure 7-2 SJGS Unit 2 Additional NO x 

### Control Technology CostEffectiveness............................................................................................ 7-6 Figure 7-3 SJGS Unit 3 Additional NO x 

### Control Technology CostEffectiveness............................................................................................ 7-7 Figure 7-4 SJGS Unit 3 Additional NO x 

### Control Technology CostEffectiveness............................................................................................ 7-8 Figure 8-1 Location of SJGS and the Class I Areas .................................................. 8-3PNM San Juan Generating Station Contents

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### Figure 8-2 Geophysical and Meteor ological Modeling Domain............................... 8-5 Figure 8-3 Surface Stations ....................................................................................... 8-7 Figure 8-4 Precipitation Stations ............................................................................... 8-8 Figure 8-5 Terrain Elevation Plot.............................................................................. 8-9 Figure 8-6 Land Use Plot......................................................................................... 8-10 Figure 8-7 CALPUFF Com putational Domain ....................................................... 8-12PNM San Juan Generating Station Acronyms

060607 AC-1 

## Acronyms

A/C Air-to-Cloth AQC Air Quality Control
ASN Ammonium Sulfate Nitrate
B&W Babcock & Wilcox
BACT Best Availabl e Control Technology
BART Best Available Retrofit Technology
CaS Calcium Sulfide CCS Clean Combustion System COHPAC Compact Hybrid Particulate Collector CUECost Coal Utility Environmental Cost
DBA Dibasic Acid DCS Distributed Control System EPA Environmental Protection Agency
EPRI Electric Power Research Institute ESP Electrostatic Precipitator
FAA Federal Aviation Administration FLAG Federal Land Managers Workgroup
FLGR Fuel Lean Gas Reburn
H 2 

### SO 4 

### Sulfuric Acid Mist Hg Mercury HHV Higher Heating Value IWAQM Interagency Workgroup on Air Quality Modeling
LCC Lambert Conformal Conic
LNB Low NO x 

### Burners MBtu Million British Thermal Unit
HNO 3 

### Nitric Acid
NH 3 

### Ammonia
NH 4 

### Ammonium NMED New Mexico Environment Department
NN Neural Network
NO 3 

### Nitrates
NO x 

### Nitrogen Oxides
NPS National Park Service
NSPS New Source Performance Standards
NWS National Weather ServicePNM San Juan Generating Station Acronyms

060607 AC-2 

### OFA Overfire Air
PJFF Pulse Jet Fabric Filter
PM Particulate Matter
PRB Powder River Basin RMC Regional Modeling Center SCR Selective Catalytic Reduction SJGS San Juan Generating Station SNCR Selective Non-Catalytic Reduction SOA Secondary Organic Aerosol
SO 2 

### Sulfur Dioxide
SO 3 

### Sulfur Trioxide
SO 4 

### Sulfate
TAC Total Annualized Cost TCI Total Capital Investment WRAP Western Regional Air PartnershipPNM San Juan Generating Station Executive Summary

060607 ES-1 

## Executive Summary

The New Mexico Environment Department (NMED) identified the Public Service of New Mexico’s (PNM’s) San Juan Genera ting Station (SJGS) as a Best Available Retrofit Technology (BART)-eligible source, which required a BART engineering and modeling analysis for reducing visibility impacts in accordance with the US Environmental Protection Agency’s (EPA’s) Guidelines for BART Determinations under the Regional Haze Rules (40 CFR Part 51, A ppendix Y). A BART review was required to identify the best control technology for the reduction of nitrogen oxides (NO x 

### ), sulfur dioxide (SO 2 

### ), and particulate matter (PM) emissions. However, because the state of New Mexico will participate in the West ern Regional Air Partnership (WRAP) SO 2 

### emissions trading program, SO 2 

### emissions reduction will not be analyzed for BART. SJGS consists of four units: Units 1, 2, 3, and 4.
PNM entered into a consent decree with the Grand Canyon Trust, Sierra Club, and NMED on March 10, 2005, to settle allege d violations of the Clean Air Act.
Installation of state- of-the-art new low-NO x 

### burners (LNB) with ove rfire air (OFA) ports and a neural network (NN) system to reduce NO x 

### emissions, and a full-sized pulse jet fabric filter (PJFF) to reduce PM emissions is currently under way at SJGS to meet the requirements of the consent decree. All four units will have these controls installed by the spring of 2009. However, since the NMED determined th at the four units at SJGS was BARTeligible based on the currently installed technology (pre-consent decree) and not the technologies being installed for consent decree compliance, it was important to perform the BART analysis on the consent decree techno logies, as well as other technologies that
could be added to the units. In the BART rule, presumptive levels of emissions are prescribed as emissions targets for BART-eligible units. For SJGS, the presumptive NO x 

### limit is 0.23 lb/MBtu (subbituminous coal for a dry-botto m, wall-fired boiler). The NO x 

### presumptive limit was established based on the type of coal burned a nd the boiler design. It should be noted that the presumptive limit of 0.23 lb/MBtu is achiev able for Powder River Basin (PRB) coal fired, dry-bottom, wall-fired boilers, us ing state-of-the-art combustion control technologies, but SJGS does not burn PRB coal . For a similarly c onfigured boiler firing bituminous coal, the presumptive limit for NO x 

### is 0.39 lb/MBtu. There is not a presumptive limit for PM.PNM San Juan Generating Station Executive Summary

060607 ES-2 

### The five basic steps of a BART analysis are:

• Identify all available retrofit control technologies.

• Eliminate technically infeasible options.

• Evaluate control effectiveness of remaining control technologies.

• Evaluate impacts and document the results.

• Evaluate visibility impacts. The BART analysis was perf ormed in two stages. First, a BART analysis was performed for the consent decree technologies currently being implemented at SJGS. This analysis is presented in Section 4.0. Ta ble ES-1 lists control and cost-effectiveness data for the consent decree technologies. Th e evaluation of the consent decree control technologies indicates that the new LNB, OFA, and NN installed for NO x 

### emissions represent a state-of-the-art combustion control technology, and the PJFFs installed for PM emissions are the most stringent contro l technology for PM emissions control. The consent decree control technologies shoul d be considered BART for SJGS.

Table ES-1 Control and Cost-Effectiveness Resu lts of Consent Decree Upgrades

Total Total Emission Expected Expected Expected Capital Annualized Performance Emission Emission Emission Investment Cost Cost Consent Decree Level Rate Rate Reduction (TCI) (TAC) Effectiveness Upgrades Scenario (lb/MBtu) (lb/h) (ton/yr) (ton/yr) (1,000$) (1,000$) ($/ton) NOx Reduction - LNB/OFA/NN

SJGS 1 0.30 1,112.1 4,140 1,794 14,580 1,422 793 SJGS 2 0.30 1,106.4 4,119 2,060 14,126 1,378 669 SJGS 3 0.30 1,727.4 6,431 2,572 12,715 1,240 482 SJGS 4 0.30 1,694.7 6,309 2,524 12,870 1,256 498

PM Reduction - PJFF

SJGS 1 0.015 55.6 207 483 67,072 10,427 21,586 SJGS 2 0.015 55.3 206 481 69,840 10,764 22,399 SJGS 3 0.015 86.4 322 750 72,696 12,454 16,599 SJGS 4 0.015 84.7 315 736 73,328 12,527 17,018

Notes:

1. All costs are in 2007$. 2. Expected emission rates (ton/yr) calculations were based on 85 percent unit capacity factor (refer to Appendix A Design Bas is). 3. Expected emission reduction (ton/yr) calculations were based on the pre-consent decree upgrades control effectiveness

as shown in Table 4-1. 4. TCI and TAC are referenced from Appendix C Cost Analysis Summary. 5. Cost-effectiveness ($/ton) is defined as ratio of TAC over expected emission reduction (ton/yr). 6. Expected emission reduction is based on annual emission reduction from pre-consent decree operation emission levels.PNM San Juan Generating Station Executive Summary

060607 ES-3 

### In the second stage of the BART an alysis, additional control technology alternatives to the consent decree technologies were identified by evaluating the feasibility of the technologies identified as available in Section 3.0. Since the PJFFs being installed for the consent decree are th e most stringent tec hnology available, no additional PM control technologies a lternatives were evaluated. For NO x 

### emissions, the selective catalytic re duction (SCR) and sele ctive non-catalytic re duction (SNCR)/SCR hybrid technologies were identifi ed as feasible additional NO x 

### control technology alternatives. The BART analys is of these technologies is pr esented in Sec tions 5.0 to 7.0. The results of the control and cost-effectiven ess evaluation are summarized in Table ES2. The last step of the BART analysis i nvolved performing visibility modeling for the two stage of the BART analysis. Th e visibility modeling was performed in accordance with the modeling protocol submitted to the NMED. Meteorological data for the years 2001 through 2003 was obtained fr om the WRAP Regional Modeling Center (RMC) for use in modeling. The WRAP RMC conducted the initial modeling that identified the four SJGS units as causing or contributing to visibility impairment in sixteen Federal Class I areas. For each contro l technology modeled, the visibility data was analyzed for the 98th perc entile modeled visibility a nd reported as a visibility impairment value in deciview (dv) at the 16 Federal Class I areas. Based on the total annual cost for the consent decree technologies, the additional NO x 

### control technology alternatives, and the modeled visibility impacts, the visibility improvement cost-effectiveness was calculated. For all three visibility scenarios (i.e., pre-consent decree [modeling by RMC], cons ent decree technologies, and additional NO x 

### control technology alternatives), the average modeled visibili ty impacts were used to calculate the visibility improvement cost effectiveness ($/dv). A summary of the visibility improvement cost effectiveness is shown in Table ES-3. In conclusion, for PM emissions control, the PJFFs being added to meet the consent decree requirements represent BACT for similar units. No other technologies have been identified that exceed the em issions reductions achieved by the PJFF. Therefore, the PJFF is considered BART for this project for each SJGS unit. The BART analysis for NO x 

### emissions control conclude s that the LNB, OFA, and NN should be considered BART for the SJGS un its. Another factor to consider is that the presumptive limit for dry-bottom, wall-fire d boilers burning subb ituminous coal is based on the installation of LNB and OFA as indicated in the BART guidelines. The subbituminous coal fired at SJGS is similar to bituminous coal than PRB subbituminous coal with respect to NO x 

### control. This similarity to bituminous coal is due to the lower volatility, lower moisture, and lower oxygen cont ent of the coal burned at SJGS. These characteristics result in higher NO x 

### emissions from the SJGS units than from the same type of boiler with the same combustion controls and burni ng PRB coal. The LNB, OFA, and NN being installed in the SJGS units are cl assified as state-of-the-art technologiesPNM San Juan Generating Station Executive Summary

060607 ES-4 

### and are equivalent to the BART technol ogy used to estab lish the 0.23lb/MBtu presumptive limit. The SCR and SNCR/SCR Hybrid system s would require significant capital expenditure and modifications that will impact many areas of the plant, including boiler draft systems, air heater performance, SO 3 

### emissions, and ash handling. The capital cost for SCR ranged from $157 million on Unit 1 to $216 million on Unit 3. This represents a cost of 436 $/kW on Unit 1 to 396 $/kW on Unit 3. For SNCR/SCR Hybrid, the capital cost ranged from $104 million on Unit 1 to $ 169 million on Unit 3. This represents a cost of 290 $/kW on Unit 1 to 310 $/kW on Un it 3. In addition, the average visibility improvement from these systems is only 0.627 dv for SCR and 0.226 for the hybrid. The visibility improvement cost effectivene ss is 155 million $/dv for SCR and 369 million $/dv for SNCR/SCR Hybrid. These minimal vi sibility improvements do not merit the large capital expenditure required to install SCR or SNCR/SCR Hybrid. Therefore, LNB, OFA, and NN combustion controls s hould be considered BART for SJGS.PNM San Juan Generating StationExecutive Summary060607ES-5Table ES-2Impact Analysis and Cost-Effectiveness Results for Additional NOxControl Technology AlternativesTotal TotalEmission Expected Expected Expected Capital Annualized IncrementalPerformance Emission Emission Emission Investment Cost Cost Cost Energy Non-AirLevel Rate Rate Reduction (TCI) (TAC) Effectiveness Effectiveness Impacts ImpactsAll Feasible Technologies (lb/MBtu) (lb/h) (ton/yr) (ton/yr) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$)SJGS Unit 1Selective Catalytic Reduction (SCR) 0.07 259.5 966 3,174 156,805 20,525 6,466 2,844 1,496 --SNCR/SCR Hybrid 0.18 667.3 2,484 1,656 104,436 16,207 9,786 -- 706 1,762SJGS Unit 2Selective Catalytic Reduction (SCR) 0.07 258.2 961 3,158 169,251 21,891 6,932 3,457 1,492 --SNCR/SCR Hybrid 0.18 663.8 2,471 1,648 108,628 16,670 10,117 -- 346 1,762SJGS Unit 3Selective Catalytic Reduction (SCR) 0.07 403.1 1,501 4,931 215,568 28,359 5,752 1,167 2,194 --SNCR/SCR Hybrid 0.18 1,036.4 3,859 2,572 168,507 25,606 9,954 -- 507 2,658SJGS Unit 4Selective Catalytic Reduction (SCR) 0.07 395.4 1,472 4,837 199,558 26,592 5,497 753 2,215 --SNCR/SCR Hybrid 0.18 1,016.8 3,786 2,524 161,572 24,849 9,846 -- 507 2,658Notes:1. All costs are in 2007$.2. Expected emission rates (ton/yr) calculations were based on 85 percent unit capacity factor (referer to Appendix A Design Basis).3. Expected emission reduction (ton/yr) calculations were based on the consent decree upgrades control effectiveness as shown in Table 4-1.4. TCI and TAC are referenced from Appendix C Cost Analysis Summary.5. Cost-effectiveness ($/ton) is defined as ratio of TAC over Expected Emission Reduction (ton/yr).6. Expected emission reduction is based on annual emission reduction from consent decree upgrade emission levels (Table 4-1).7. Incremental cost effectiveness are based on increments in expected emission reduction (ton/yr)PNM San Juan Generating Station Executive Summary

060607 ES-6 

### Table ES-3 Visibility Improvement Cost-Effectiveness Summary

Total Scenario Annualized Average Cost Deciview Average (TAC) Change Improvement Visibilitiy Scenario (1,000$) (dv) ($/dv) Consent Decree Scenario

Pre-consent decree to consent decree 51,468 0.614 83,824,104

Additional Control Technology Alternative

Consent decree to SCR 97,367 0.627 155,290,271 Consent decree to Hybrid 83,332 0.226 368,725,664

Pre-consent decree to SCR 148,835 1.241 119,931,507 Pre-consent decree to Hybrid 134,800 0.840 160,476,190

Notes:

1. All costs are in 2007$. 2. Pre-consent decree visibility impact from WRAP RMC model, April 2007. 3. Total annualized costs and cost effectiveness ($/ton) are referenced from Table 4-3 and 7-1. 4. Deciview change assumes all four units on the same control technology.PNM San Juan Generating Station Introduction and Objectives

060607 1-1 

## 1.0 Introduction and Objectives

The objective of this study was to perform a BART analysis for the PNM SJGS Units 1, 2, 3, and 4. These units were id entified as BART-eligibl e sources by the NMED because they cause visibility impairment in 16 Federal Class I areas that are within a 300 km radius, as identified in accordance with the Regional Haze and BART Rule guidelines that were published by the US EPA on July 6, 2005 (70 FR 39104). The NMED determined SJGS’s BART eligibility based on the visibility mode ling performed by the
WRAP RMC. Three major pollutants, NO x 

### , SO 2 

### , and PM, were identified as having an impact on visibility at Federal Class I areas. However, for this BART analysis, SO 2 

### emissions
reductions will not be taken into account fo r BART consideration, because New Mexico will participate in the WRAP SO 2 

### emissions trading program. This report documents the BART engineering analysis process and the re sults obtained, as well as the recommended
best control alternative for NO x 

### and PM.



## 1.1 Introduction to the SJGS Consent Decree On March 10, 2005, PNM entered into a consent decree with the Grand Canyon Trust, the Sierra Club, and the NMED. The consent decree became effective May 10, 2005. The decree is a settlement of alleged Cl ean Air Act violations at SJGS. PNM is required by the consent decree to reduce em issions levels of PM at each unit to 0.015 lb/MBtu (measured using EPA referen ce Method 5), with a corresponding opacity limit of 20 percent over a 6 minute average period. For NO x 

### , each unit at SJGS shall not exceed 0.30 lb/MBtu on a 30 day rolling average period. PNM is also required to reduce
SO 2 

### and mercury emissions. The consent decree compliance deadlines for the reduced emissions levels vary
for all four units at SJGS. The earlie st required startup date for PM and NO x 

### controls is October 31, 2007 for SJGS Unit 4. The last required startup da te for PM and NO x 

### controls is March 31, 2009 for SJGS Unit 2. The startup schedule for SJGS Units 3 is April 30, 2008, and Unit 1 is October 31, 2008.PNM San Juan Generating Station Introduction and Objectives

060607 1-2 

### To meet the requirements of the consent decree for NO x 

### and PM, PNM is installing state-of-the-art LNB with OFA ports, and an NN system on each boiler to
reduce NO x 

### emissions. For PM emissions control, a full-sized PJFF will be installed upstream of the limestone flue gas desulfuriz ation (FGD) on each unit. The existing hotside ESP will be de-energized. The PJFF is also a component, along with activated carbon injection (ACI), for reduc ing mercury (Hg) emissions.
The installation of the controls associat ed with the consent decree is currently under way. However, since the NMED determined that the four units at SJGS units are BART-eligible based on the currently insta lled technology (pre-cons ent decree) and not the technologies being installed for consent decree compliance, it was important to perform the BART analysis on the consent decr ee technologies, as well as any additional technologies that could be added to the units.



## 1.2 Source Description and Background SJGS is a minemouth facility burning co al from the San Juan Mine. Although the coal is classified as subbituminous, it is not a PRB subbituminous coal. The fuel combusted at SJGS has a higher heating valu e (HHV), lower moisture content, higher sulfur content, and lower volatility than PRB coal. A detailed comparison of the
difference in fuel characteris tics is presented in Section 2.3. SJGS Units 1 and 2 have a unit capacity of 350 and 360 MW, respectively. The units are equipped with Foster Wheeler subcr itical, wall-fired boilers that operate in a
forced draft mode. For emissions reducti on, the units are equipped with Western Precipitator hot-side ESPs for PM control and Babcock & Wilcox (B&W) wet limestone FGD systems for SO 2 

### control. SJGS Unit 1 has LNBs. SJGS Units 3 and 4 each have a unit cap acity of 544 MW and are equipped with B&W subcritical, opposed wall-fired boilers th at operate in a for ced draft mode. For emissions reduction, the units are equipped w ith Research-Cottrell hot-side ESPs, LNBs, and B&W wet limestone FGD systems. A summary of the pre-consent decree operational characteristics is presented in Table 1-1.PNM San Juan Generating Station Introduction and Objectives

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### Table 1-1 SJGS Characteristics Pre-Consent Decree Operation

Item SJGS 1 SJGS 2 SJGS 3 SJGS 4 Fuel Type Subbituminous Subbituminous Subbituminous Subbituminous
HHV of Fuel, Btu/lb 9,692 9,692 9,692 9,692 Unit Rating, MW (gross) 360 350 544 544 Boiler Heat Input, MBtu/h 3,707 3,688 5,758 5,649 Type of Boiler/Manufacturer Wall-fired/ Foster Wheeler Wall-fired/ Foster Wheeler Opposed wallfired/B&W Opposed wallfired/B&W Steam Cycle Subcritical Subcr itical Subcritical Subcritical

Draft of Boiler Forced Forced Forced Forced Existing Emissions Controls

PM Hot-side ESP Hot-side E SP Hot-side ESP Hot-side ESP

SO 2 Wet FGD Wet FGD Wet FGD Wet FGD

NO x Low-NO x burners N/A Low-NO x burners Low-NO x burners



## 1.3 BART Analysis Methodology The BART analysis is the engineeri ng and modeling analysis method used to identify the best method or technology to ach ieve emissions reduction for pollutants from BART-eligible sources that cause visibility impacts in Federal Class I areas. The BART analysis is defined in the regional haze re gulations and guidelines in 40 CFR Part 51. The following factors are considered when identifying the best method of emissions
reduction:

• Technical feasibility.

• Cost of compliance.

• Energy and non-air quality environmental impacts of compliance.

• Existing pollution control equipment in use or installed at the source.

• Remaining useful life of the source.

• Degree of anticipated improvement in visibility. The BART analysis consists of the followi ng five steps to arrive at a selection of
the best methods of emissions reduction for NO x 

### and PM at the BART-eligible source: (1) Identify all available retrofit control technologies. (2) Eliminate technically infeasible options.PNM San Juan Generating Station Introduction and Objectives

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### (3) Evaluate control effectiveness of remaining control technologies. (4) Evaluate impacts and document the results. (5) Evaluate visibility impacts.
It should be noted that the SJGS BA RT analysis required a unique approach
because of the consent decree. The station was established as a BART-eligible source prior to the installation of tec hnologies associated with the c onsent decree. Therefore, the pre-consent decree operating conditions, as desc ribed in Section 1.2, represent the initial baseline for this BART analysis. As a result, this analysis examines the consent decree technologies as an initial BART compliance sc enario (presented in Section 4.0 of this report). Additional control technology altern atives were then evaluated as potential BART compliance scenarios pres ented in Sections 5.0 to 7.0.

1.3.1 Identify All Available Retr ofit Control Technologies (Step 1) The first step of the BART analysis methodology is to identify all available retrofit control technologies. An emissions c ontrol technology is considered an available retrofit option if it has practic al potential for application to the BART-eligible source. The technology considered could be a change in plant operation method,
addition/modification of emissi ons control system, or a co mbination for control of a pollutant. Technologies that ha ve been successfully applied to simila r sources or with similar gas stream characteristics are considered as available. Howe ver, technologies that have not been applied to comme rcial-scale operations are consid ered not available. Since the SJGS units are equipped with existing co ntrol technologies, cont rol options including improvements or optimization of the existin g control technologies were evaluated. Section 3.0 provides details of Step 1 of the BART analysis.

1.3.2 Eliminate Technically Infeasible Options (Step 2) Step 2 of the BART analysis involves the evaluation of all the identified available retrofit control technologies to determine th eir technical feasibilit y. A control technology is technically feasible if it has been previously installed and operated successfully at a similar type of source or if there is tec hnical agreement between the provider and user that the technology can be applie d to the source. Two terms, available and applicable, are
used to define the technical feasibility of a control technol ogy. A technology is deemed an available technology if it is being offered commercially by vendors or is in commercial demonstration or licensing. Th e commercially available technology is applicable if it has been previously installed and operated at a similar type of source, or a source with similar gas stream characteristics. Technologies that are in development andPNM San Juan Generating Station Introduction and Objectives

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### testing stages are classified as not available. Section 4.0 provides de tails of Step 2 of the BART analysis.

1.3.3 Evaluate Control Effectiven ess of Remaining Control Technologies (Step 3) Once all the technically feasible contro l technology alternatives are identified in Step 2, the control effectiveness of each control technology is evaluated in Step 3. The control effectiveness is determined using a metric of average steady-state pollutant emissions. For this study, the metric used is the quantity of pollutant mass emissions per unit heat input (lb/MBtu). The control e ffectiveness of a tec hnology was determined by considering the regulatory decisions and/or evaluations addressing the effectiveness of the technology. Other reference sources included performance data provided by manufacturers (usually in the form of perf ormance guarantees), engineering estimates,
and demonstrated effectiveness of the technol ogy at another source. The most stringent level of control proven for each technology was us ed for its control effectiveness, but less stringent levels of c ontrol were also considered as a dditional options. The results for Step 3 of the BART analysis are described in Section 5.0.

1.3.4 Evaluate Impacts and Do cument the Results (Step 4) Once the control effectiveness is established in Step 3 for all the feasible control technologies identified in Step 2, additional evaluations of each technology are performed as part of the BART determination. These ev aluations, labeled as “I mpact Analyses,” are included in Section 6.0. The impact anal yses performed include the following:

• Costs of compliance.

• Energy impacts.

• Air quality environmental impacts.

• Non-air quality environmental impacts.

• Remaining useful life. The first impact analysis evaluated the co sts of compliance. This analysis is performed to indicate the cost to purchase, retrofit, and install th e control technology. The capital and operating/annual costs are estimated based on established design parameters. The design parameters are esta blished in the Design C oncept Definitions in Appendix B . The estimated cost of control is repr esented as an annualized cost ($/year). The annualized cost in conjunction with th e estimated quantity of pollutant removed (tons/year) allows the cost-effectiveness ($/tons) of the cont rol technology to be determined. The cost-effectiveness compares the potential technologies on an economic basis. Two types of cost-eff ectiveness are considered in a BART analysis: average and incremental. The average cost-effectiveness is defined as the total annualized cost ofPNM San Juan Generating Station Introduction and Objectives

060607 1-6 

### control divided by the annual quantity of pollu tant removed for each control technology. The incremental cost-effectiveness is a compar ison of the cost and performance level of a control technology to the next most stringent option. Incremental cost-effectiveness is expressed as dollars ($)/incremental ton removed and is a useful measurement for comparing technologies that have similar removal efficiencies. The energy impact of each evaluated c ontrol technology is the energy penalty or benefit resulting from the operation of the control technology at the source. Direct energy impacts, such as the auxiliary power consumption of the control technology and the power consumption to overcome the addition al system pressure loss, were evaluated. The costs of these energy impacts included additional fuel costs and/or the cost of replacement power that would have to be pur chased to implement the control technology. Air quality environmental impacts were evaluated. Some technologies will result in an increase or decrease in other air pollutants such as NO x 

### , SO 2 

### , sulfur trioxide (SO 3 

### ), or PM. The total emissions of all pollutants will affect the control scenario used for the visibility model. Non-air quality environmental impacts were evaluated to determine the cost to mitigate environmental impacts caused by the operation of a control technology. Examples of non-air quality environmental impacts include water consumption, polluted water discharge, and solids/waste generation. Finally, the remaining useful life was c onsidered only when there would be an effect on the annualized costs of the retrofit contro ls for capital recove ry. This occurs when the source has a shorter remaining useful life than the expected service life of the control technology. This would require an expedited pace for capital recovery, thus affecting the cost-effectiveness of the cont rol technology, particularly for technologies that require a large capital expenditure.

1.3.5 Evaluate Visibili ty Impacts (Step 5) Potential visibility improvements from the addition of each control technology were determined from the modeling results using CALPUFF. The parameters modeled
were NO x 

### , SO 2 

### , and PM emissions. A modeling pr otocol has been developed by the WRAP RMC and was used as a template for the modeling protocol for the SJGS modeling analysis (located in Appendix E ). Items that were considered in the modeling protocol include the following:

• Meteorological and terrain data.

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

• Pre- and post-control emissi ons rates of pollutants.

• Receptor data from appropriate Class I areas.PNM San Juan Generating Station Introduction and Objectives

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### After model runs were completed, a determ ination of the visibility improvement was made. The visibility improvements for the initial BART compliance scenario involving the consent decree t echnologies and the additional BART compliance scenario
with additional control tec hnology alternatives were determined by comparing the 98th percentile modeled visib ility values. The visibility improve ment is quantified in units of deciview, which are defined as a visibility index that linearly scales perceived visual (visibility) changes (Interagency Monitori ng of Protected Visual Environments Newsletter, April 1993). A detailed descri ption of the BART modeling for these scenarios has been included in Section 7.0 of this report. Using the modeled visibility improvement and the annualized cost ($/year), a visibility improvement cost-effectiveness measure can be defined as the cost for a deciview of improvement ($/deciview). Th is cost-effectiveness metric was used to compare the cost impact of each technology and the resulting visibility improvement.

1.3.6 Select the Best Alternative By evaluating all of the results from th e five steps described above, a decision on
the best alternative control technology can be made base d on the cost-effectiveness, impacts, and the resultant visibility improve ment. Another factor to consider when selecting the best alternative is the effectiveness of the combination of two or more technologies for the control of multiple pollu tants. While separa tely the technologies may not be the best selection for the contro l of a single pollutant, when combined, they may be very effective in controlling multiple pollutants. An example of such a synergistic approach is the use of LNB and OFA systems in combustion control for NO x 

### reduction. In addition, the potential of a sel ected technology to control future regulated pollutants, such as the use of a PJFF for Hg c ontrol, is considered when selecting the best
alternative.PNM San Juan Generating Station Basis of Analysis

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## 2.0 Basis of Analysis

2.1 Design Basis A detailed design basis wa s established for the SJGS. The information in the design basis was used for equipment sizing, performance calculati ons, cost estimates (capital, operating and maintenance [O&M]) , resource consumption estimates, auxiliary power requirements, and byproduct disposal. The design basis was established with
consideration of the unit conf iguration after the consent de cree technologies have been installed. This approach was selected so that the information in the design basis could be
used for the evaluation of the additional control technology alternatives for BART consideration. The design basis is shown in Appendix A . The design basis was also developed using the properties of a representative coal typically combusted at SJGS. Combustion calculations were performed using th e design basis coal to determine the flue gas flow characteristics for use in eq uipment sizing and cost estimation.



## 2.2 Economic Data 2.2.1 Capital Cost Estimates Capital cost estimates were developed for retrofit control t echnologies identified as technically feasible for the SJGS units. The capital cost estimates were based on the Coal Utility Environmental Cost (CUECost) estimates, cost data supplied by equipment vendors (budget estimates), and estimates from previous in-house design/build projects. The capital cost estimates include direct and indirect costs and are stated in 2007 dollars. The capital cost accuracy is ± 30 percent. Direct costs consist of purchased equipmen t, installation, and mi scellaneous costs. The purchased equipment costs are the cost s for purchasing the equipment, including taxes and freight. An itemized list of ke y components of the dire ct capital cost is included in Appendix C for each feasible control t echnology. The installation costs include construction costs for installing the new controls. The installation costs take into account the retrofit difficulty of the existi ng site configuration and condition and the installation requirements of the evaluated tec hnology. Finally, the co sts of miscellaneous items such as purchase of additional water ri ghts, site preparati on, buildings, and other site structures needed to implement the cont rol technology are include d. The direct cost estimates were based on the following assumptions:

• Costs for regulatory permitting were not included.

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

• Normal lead-times for equipment deliveries are expected.PNM San Juan Generating Station Basis of Analysis

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### Indirect costs are those costs that are not related to the equipment purchased but are associated with any engineer ing project, such as the retrofit of an air quality control (AQC) technology. Indirect cost s addressed in this evalua tion include the following:

• Contingency.

• Engineering.

• Owner’s Cost.

• Construction Management.

• Startup and Spare Parts.

• Performance Tests.

• Loss of Generation for Construction Outage. 2.2.1.1 Contingency. Contingency accounts for unpredictable events and costs that could not be anticipated during the normal cost development of a project. Costs assumed to be included in the contingency cost cate gory are items such as possible redesign and equipment modifications, errors in estimati on, unforeseen weather-re lated delays, strikes and labor shortages, es calation increases in equipment costs, increases in labor costs, delays encountered in startup, etc. 2.2.1.2 Engineering. Engineering costs include any services provided by an architect/engineer or other consultant for support, design, and procurement of the AQC project. 2.2.1.3 Owner’s Cost. Table 2-1 lists possible Owner’s costs for this category. The
Owner’s costs are identified as indirect costs. Some of the categories are not applicable to all of the evaluated technologies, but are re presentative of the typi cal expenditures that an Owner would experience as part of an AQC retrofit project. 2.2.1.4 Construction Management. Construction manageme nt services include field management staff such as support perso nnel, field contract administration, field inspection and quality assurance, project contro l, technical direction, and management of startup. It also includes cleanup expense fo r the portion not included in the direct-cost construction contracts, safety and medical se rvices, guards and othe r security services, insurance premiums, other required labor -related insurance, performance bond, and liability insurance for eq uipment and tools. 2.2.1.5 Startup and Spare Parts. Startup services include the management of the startup planning and procedure and the training of personnel for the commissioning of the newly installed AQC technology. Also includ ed are the general low-cost spare parts required for each AQC technology system. High- cost critical spare part components are kept only if recommended by the manufacturer ; they are determined and accounted for on a case-by-case basis.PNM San Juan Generating Station Basis of Analysis

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### Table 2-1 Typical Owner’s Cost Categories

Project Development: Legal assistance Environmental permitting/offsets Public relations/community development Road modifications/upgrades

Financing:
Debt service reserve fund Analyst and engineer 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 Auxiliary power purchase

Owner’s Project Management: Provide project management Perform engineering due diligence Prepare bid documents and select contractors and suppliers Taxes/Advisory Fees/Legal:
Taxes Market and environmental consultants Owner’s legal expenses:

• Power purchase agreement

• Interconnect agreements

• Contract--procurement and construction

• Property transfer



### 2.2.1.6 Performance Tests. Performance test services are typically required after every AQC technology addition to validate th e performance of the emissions reduction system. The results of the performance te sts are used to ensure compliance with performance guarantees and emissions limits. 2.2.1.7 Loss of Generation for Construction Outage. For retrofit projects that require a construction outage l onger than the 7 week majo r outage or 3 week minor outage that have been planned for each unit, an estimate is made for the loss of generation. For each re trofit scenario analyzed in th is BART study, an estimate of the required outage for construction was made. The replacement electric energy cost listed in
Table 2-2 was used to calculate the cost of loss generation, base d on the net generation and capacity factor as shown in the design basis in Appendix A

.PNM San Juan Generating Station Basis of Analysis

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### Table 2-2 Economic Evaluation Factors

Reagent Cost Ammonia (anhydrous) $700/ton Dry Granular Urea $420/ton Dibasic Acid (DBA) $0.67/lb (dry) Selective Catalytic Reducti on (SCR) Catalyst Cost $6,500/m 3 

### Makeup Water Cost $15.57/1,000 gal Service/Treated Water Cost $15.67/1,000 gal Byproduct Disposal Cost $0.99/ton Auxiliary and Replacement El ectric Power Cost $60.95/MWh Lost Fly Ash Sales $6.00/ton Maintenance Cost 3% of cap cost/yr Plant and Control Technology Economic Life 20 years Gross Receipt Tax Rate 6.1875% Present Worth Discount 7.41% (20 years) 7.56% (25+ years) Capital and O&M Escalation Factor 3.00% Capital Recovery Factor (to annua lize capital cost) 9.74% (20 years) Interest During Construction 7.41% (20 years) Contingency Cost 20% of installed cost Fully Loaded Operating Labor Cost (union) $60.03/man-hourPNM San Juan Generating Station Basis of Analysis

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### 2.2.2 Annual Operating and Maintenance Cost Estimate Annual O&M costs typically consist of the following cost categories:

• Reagent costs.

• Electric power costs.

• Makeup water costs.

• Wastewater treatment and byproduct disposal costs.

• Operating labor costs.

• Maintenance materials and labor costs. The costs of reagent, electric power , makeup water, wastewater, and byproduct disposal are variable annual costs and are de pendent on the specific control technology. O&M materials and labor are fixed annual co sts. Table 2-2 lists the major economic factors used to obtain the annual O&M costs. 2.2.2.1 Reagent Costs. Reagent costs include the cost s for the material, delivery of the reagent to the facility, and reagent prep aration. Reagent costs are a function of the quantity of the reagent used and the price of the reagent. The quantity of reagent used will vary with the quantity of pollutant re moved. Reagent costs were defined for the following reagents:

• Anhydrous ammonia.

• Dry granular urea. 2.2.2.2 Electric Power Costs. Additional auxiliary power will be required to run some of the new control technology system s. The power requirements of each system vary, depending on the type of technology and the complexity of the system. Electric power costs include an increase in fan pow er caused by the flue gas pressure losses through the new equipment. The additional fan power was estimated with a basis of 90 percent fan efficiency and 80 percent motor efficiency. 2.2.2.3 Makeup and Service Water Costs. Makeup water or service water is required for some of the processes in the ne w control technology systems. Examples of water consumption include water to support ammonia solution preparation from urea for SCR and SNCR processes. Additional costs might be incurred for water treatment to obtain the required water quality. For the cost estimations, two types of water quality were considered: makeup and service water. Depending on the proce ss, the appropriate water type was included in this cost category.PNM San Juan Generating Station Basis of Analysis

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### 2.2.2.4 Wastewater and By product Disposal Costs. Some control technologies generate wastewater and/or byproduct that will require tr eatment or disposal. For wastewater treatment and byproduct disposal costs, the following key assumptions were
utilized:

• Fly ash will not be sold after the implementation of the consent decree technologies. Fly ash collected in de-energized hot-side ESPs and PJFFs will be landfilled in the coal mine.

• Other emissions reduction techno logy reaction byproducts that are collected will be landfilled in the coal mine.

• Ammonia-based NO x 

### reduction systems would not impact the fly ash characteristics so that additional handling and storage requirements that increase the fly ash disposal cost would be required. 2.2.2.5 Operat ing Labor Costs. Operating labor costs are developed by estimating the number and type of employees that will be required to run the new AQC equipment. This estimate was based on common industry pr actices. The labor cost was based on a fully loaded labor rate and 40 hours per work week. Typically, a complex emissions control t echnology will require a combination of the following personnel:

• Supervisor.

• Control Room Operator.

• Roving Operator.

• Relief Operator.

• Laboratory Technicians.

• Equipment Operators. In the evaluation of direct annual costs for each control technology considered in Appendix C , the operating labor required for each technology is identified. 2.2.2.6 Maintenance Ma terials and Labor Costs. The annual maintenance materials and labor costs are typically estimated as a percentage of the total equipment costs of the system. Based on typical electric al utility industry experience, maintenance
materials were estimated to be between 1 and 5 percent of the total direct capital costs. Some initial recommended spare parts were included in the capital costs. An annual maintenance value of 3 percent of the total direct capital costs was used as the basis for the yearly maintenance materials and labor cost . For technologies that replace a similar existing technology at the current plant si te, a determination of the additional maintenance requirements was performed. If the required maintenance materials and
labor were similar to the existing technology, no additiona l maintenance costs were credited for the new control technology.PNM San Juan Generating Station Basis of Analysis

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## 2.3 Target Emissions The final Regional Haze and BART Rule guidelines issued in July 2005 outline the presumptive limits that apply to BART-eligible coal plants for NO x 

### and SO 2 

### . The
BART NO x 

### presumptive limits vary according to th e type of coal burned and the boiler design. For all units at SJGS, the NO x 

### presumptive limit for a dry-bottom wall-fired, subbituminous coal burning unit is 0.23 lb/MBtu. For a similarly configured boiler firing bituminous coal, the presumptive limit for NO x 

### is 0.39 lb/MBtu. The presumptive limit of 0.23 lb/MBtu was determined to be achievable for the majority of dry-bottom, wall-fired boilers firing subbituminous coals and using current combustion control technologies. It should be noted that the presumptive limit is more representative for a boiler firing PRB t ype bituminous coal. A discussion of the
differences between the New Mexico subbitumi nous coal burned at SJGS and PRB coal
is included in Subsection 4.1.4. As previously noted, New Mexico is participating in the WRAP SO 2 

### emissions trading program and, therefore, the presumptive limits for SO 2 

### were not used for this study. For PM emissions control, the BART analysis methodology is similar to that for
NO x 

### . However, the BART guidelines do not specify a presumptive limit for PM. In addition to this presumptive limit, the BART analysis procedure requires control technologies that are considered as BACT to be included as a control alternative. A summary of the BART presumptive limits an d BACT determinations for the pollutants in this BART analysis is presented in Table 2-3.

Table 2-3 Target Emissions

NO x 

### PM (1)


### BART Presumptive Limits (2) 

### (for subbituminous fuel) 0.23 lb/MBtu N/A

BART Presumptive Limits (2) 

### (for bituminous fuel) 0.39 lb/MBtu N/A

BACT Determination (3) 

### 0.07 lb/MBtu 0.012 lb/MBtu
Notes:

(1) 

### PM target emissions are for filterable PM only. (2) 

### NO x 

### BART presumptive limits are for dry bottom, wall-fired coal fired units. (3) 

### BACT limits are referenced from the EPA BACT/LAER Clearinghouse.PNM San Juan Generating Station Basis of Analysis

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## 2.4 Project Assumptions In performing the BART analysis, severa l general assumptions were made to facilitate the conceptual desi gn activities of the t echnically feasible control technologies that are being evaluated. The fo llowing are key project assumptions:

• No significant change will occur in pl ant availability after the installation of new AQC equipment.

• The site will have sufficient area available to accommodate construction activities including, but not limited to, offices, lay-down areas, and staging.

• Byproducts produced from the emissions reduction processes will be
landfilled in the coal mine.



## 2.5 Modeling Baseline Conditions Emissions rates of pollutants are required as input data for visibility modeling.
Stack outlet conditions for all the technica lly feasible contro l technologies were calculated and are presented in Appendix D . The outlet conditions were calculated based on the design basis data, technology control effectiveness, and design parameters. The following stack outlet data are included:

• Flue gas flow rate.

• Flue gas stack exit velocity.

• Flue gas temperature.

• Flue gas pressure.

• NO x 

### emissions rate.

• SO 2 

### emissions rate.

• Filterable PM emissions rate.

• SO 3 

### emissions rate.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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## 3.0 Identification of All Available Retrofit Emissions Control Technologies

In Step 1 of the BART analysis, all av ailable retrofit control technologies that have a practical potential for ap plication at SJGS were identi fied. These technologies are considered as available technologies. The technology considered could be a change in plant operation method, addition/modification of emissions control system, or a combination for control of a pollutant. Cont rol technologies for the two major pollutants,
NO x 

### and PM, and a description of the tec hnology are presented in this section. Information on the working principle, re trofit considerations, advantages, and disadvantages of the technology are provi ded in the descriptions contained in Sections 3.1 through 3.2.



## 3.1 NO x 

## Control Technologies There are two approaches to achieving a reduction in NO x 

### emissions: combustion control and post-combustion control. Com bustion control methods seek to suppress NO x 

### formation during the combustion process by controlling the flame temperature and fuel/oxygen ratio. Combustion control methods include LNBs, OFA, and NN combustion optimization systems. The post- combustion controls c onsist of SNCR and SCR systems. SNCR and SCR are flue ga s treatment technologies that reduce NO x 

### after
its formation. The SNCR and SCR NO x 

### reduction technologies use either urea or ammonia as a reagent. SCR technology also us es multiple layers of reduction catalyst.
Other NO x 

### reduction techniques were also identifie d, including emerging technologies.
NO x 

### control technologies that were identifie d as available for retrofit at SJGS are listed below. A short description of each technology is included in the following subsections:

• LNB, OFA with NN.

• SNCR.

• SCR.

• SNCR/SCR Hybrid.

• LNB, OFA, NN and SNCR.

• LNB, OFA, NN and SCR.

• LNB, OFA, NN and Hybrid.

• Gas Reburn.

• Mobotec ROFA and ROTAMIX.

• NO x 

### Star.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### • ECOTUBE.

• PowerSpan.

• Phenix Clean Combustion.

• e-SCRUB.

3.1.1 Low NO x



### Burners, Overfire Air with Neural Network 3.1.1.1 Low NO x



### Burners. NO x 

### , primarily in the form of NO and NO 2, 

### is formed during combustion by two primary mechanisms: thermal NO x 

### and fuel NO x 

### . Thermal NO x 

### results from the dissociation and oxidation of nitrogen in the combustion air. The rate and degree of thermal NO x 

### formation is dependent on oxygen availability during the combustion process and is exponentially depe ndent on combustion temperature. Fuel NO x 

### , on the other hand, results from the oxidation of nitrogen organically bound in the fuel. This is the dominant NO x 

### producing mechanism in the combustion of pulverized coal, and typically accounts for 75 to 80 percent of total NO x 

### . All LNBs offered commercially for appli cation to coal fired boilers control the formation and emissions of NO x 

### through some form of staged combustion. The basic NO x 

### reduction principles for LNBs are to control and balance the fuel and airflow to each burner and to control the amount and position of secondary air in the burner z one so that fuel devolatization and high temperature zones are not oxygen rich. In this process, the mixing of the fuel and the air by the burner is controlled in such a way that ignition and initial combustion of the coal take pl ace under oxygen deficient conditions, while the mixing of a portion of the combustion air is delayed along the length of the flame. The objective of this process is to driv e the fuel-bound nitrogen out of the coal as quickly as possible, under conditions where no oxygen is present, and force it to form molecular nitrogen rather than be oxidized to NO x 

### . Any nitrogen es caping the initial fuel-rich region has a greater oppor tunity to be converted to NO x 

### as the combustion process is completed. The net result of stag ed combustion is usually longer and/or wider flames due to this delayed mixing process. Staged combustion may increase the potential for higher levels of unburned carbon in ash a nd higher carbon monoxide (CO) emissions. This is particularly true of wall-fired boiler systems where, compared to tangential firing, the combustion process must be confined to well-defined flame zones and is less able to make maximum use of the av ailable burner zone volume. For LNBs to reach their maximum benefit, the proper balance of fuel and airflow to the burners (and from burne r to burner) is critical. NO x 

### reduction is achieved from the ability to control the location of the flame, the length of the flame, and, to a certain extent, the time of combustion.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### By balancing the fuel and airflow to the bur ners, an important step is achieved in controlling the flame characteristics and im proving the overall combustion process.
Balanced fuel flow ensures that each burner is operated with a similar air-to-fuel ratio. This allows the burners to operate as a NO x 

### control system rather than as individual
burners. 3.1.1.2 Overfire Air System. OFA works by reducing the excess air in the burner zone, thereby enhancing the combustion staging effect and further reducing NO x 

### emissions. Any residual unburned material , such as CO and unburned carbon that inevitably escapes the main burner zone, is s ubsequently oxidized as the OFA is added. As with primary NO x 

### control, the performance that can be expected from a given OFA system depends on a number of factors. As the amount of OF A is increased, the stoichiometry in the burner zone decreases, and a point is reached where CO emissions reach high levels and become uncontrollable. The point at which this occurs varies, particularly if the fuel has characteristics that make it difficult to burn. For example, low volatility, low oxygen, or high moisture content ma ke fuels more difficult to burn. It will also depend on the balance of fl ows between individual burners and the fuel fineness. As the OFA amount approaches 10 to 15 percent, th e probability for indivi dual burners to be operating under fuel-rich conditions increases so that pockets of very high CO emissions and unburned carbon will be formed. Similarly, fuel-rich operation at burners close to the waterwalls can lead to local slag fo rmation and increased tube wastage rates, particularly if slagging is an ongoing problem . A fairly high level of unburned material leaving the burner zone can be accommodated by proper overfire port design, where requirements call for rapid and complete mixing of the OFA with the boiler flue gases. Aggressively staging combustion to reduce NO x 

### emissions creates a reducing environment in the boiler and can damage the boiler waterwall tubes. The reducing
environment attacks the iron oxides in the t ube metal and can lead to pinholes in the boiler tubes. This phenomenon is referred to as tube wastage. Poor staging in the boiler could lead to tube wastage, an increase in the amount of maintenance, and, in the worstcase scenario, may require a forced outage to repair the tubes. 3.1.1.3 Neural Network Systems. Advances in computer hardware and software technology have enabled pow er generation companies to implement cost-effective optimization solutions that decrease emissi ons and maximize plant efficiency. This solution, commonly referred to as the boile r optimization or NN system, may provide improvements in the heat rate of the boile r and reduce combustion-related emissions. NN computing differs from traditional computing in that engineering, stat istical, and first-law principles have been replaced by complex, time-varying, nonlinear relationships. NNIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### systems use real-time operational data extracte d from a plant DCS, “l earn” solutions from plant operational experience, and achieve re ductions in the emissions produced, while possibly improving the heat rate of the plant. NN systems also supplement other NO x 

### reduction strategies. Some of these include LNB, OFA, and post-combustion co ntrols such as SCR and SNCR. These systems are also used to help boiler manuf acturers tune boilers with poor combustion characteristics or after an LNB retrofit or other boiler enhancements, such as OFA addition. A system for monitoring the air and coal flows provides real-time data for tuning the burners and maximizing perf ormance of combustion system. Airflow systems measure primary airflow, bulk secondary air, total secondary airflow, and OFA flow distribut ion. One specific system us es a pitot derivative of the multi-point, self-averaging pitot principle to measure the total and static pressure components of airflow. Pulverized fuel fl ow is determined by measuring the mass flow distribution and transport velocity of the fu el in the pipelines from the mill to the individual burners. The pr ecise technology used for the me asurements varies depending on the specific vendor.

3.1.2 Selective Non-Catalytic Reduction SNCR systems reduce NO x 

### emissions by injecting a reagent at multiple levels in the steam generator, as illustrated on Figur e 3-1. SNCR systems rely solely on reagent injection (rather than a catalyst) and an a ppropriate reagent inject ion 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. Amm onia or urea is injected into areas of the steam generator where the fl ue gas temperature ranges from 1,500 to 2,200° F. The furnace of a pulverized coal fi red boiler operates at temperatures between 2,500 to 3,000° F. SNCR systems are capable of reducing NO x 

### emissions by as much as 50 to 60 percent in optimum conditions (adequate re action time, temperature, and reagent/flue gas mixing; high baseline NO x 

### conditions; multiple levels of injectors). Ammonia slip is the ammonia that does not react with NO x 

### and instead “slips” past the boiler as ammonia. High levels of ammonia slip cause several ne gative operational impacts. First, ammonia will react with SO 3 

### in the flue gas to form ammonium bisulfate and condense on the air heater surface, degrading its performance and decreasing plant efficiency. Another concern with high ammonia slip arises when SNCR is installed upstream of a fabric filter. The ammonia will condense on the fly as h and land on the fabric filter bags. This will cause bag blinding and require early replacement of fabric filter bags. For this reason, it is recommended that the ammoni a slip be maintained below 5 ppmvd.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### However, to achieve these high levels of removal efficiency, high levels of ammonia slip (10 to 50 ppmvd) must be allowed. Typically, to maintain a 5 ppmvd ammonia slip limit, NO x 

### emissions reduction levels of 20 to 40 percent can be achieved. Potential performance is very site-specific and varies with fuel type , steam generator size, allowable ammonia slip, furnace CO concentrat ions, and steam generator heat transfer characteristics.

Figure 3-1 Schematic of SNCR System with Multiple Injection Levels

SNCR systems reduce NO x 

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

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

### . Accordingly, NO x 

### reductions and overall reaction stoichiometry are very sensitive to the temperat ure of the flue gas at the reagent injection point. This complicates the application of SNCR for boilers larger than 100 MW because of the large boiler size/volume a ssociated with such boilers. Reagent injection lances are usually located between the boiler soot blowers in the pendent superheat section. Optimum injectorlocation is mainly a function of temperature and residence time. To accommodate SNCR reaction temperature and boiler turndown requirements, several levels of in jection lances are no rmally installed. Typically, four to five levels of multiple la nce nozzles are installed if sufficient boilerIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-6 

### height and residence time is available. A flue gas residence time of at least 0.3 second in the optimum temperature range is desired to ensure adequate SNCR performance. Residence times in excess of 1 second yield high NO x 

### reduction levels even under less than ideal mixing conditions. Computati onal fluid dynamics and chemical kinetic modeling can be performed to establish th e optimum ammonia injection locations and flow patterns. For an existing boiler, minor waterwall reconfigurations are necessary to
accommodate installation of SNCR injector lances. A re-examination of the boiler steam piping would probably be required to achieve optimum performance.

3.1.3 Selective Catalytic Reduction SCR systems are the most widely used post-combustion NO x 

### control technology for achieving significant NO x 

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

### ) injected into the flue gas stream acts as a reducing agent 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 a low ammonia slip (unreacted ammonia emissions). A simplif ied schematic diagram of a typical SCR reactor is illustrated on Figure 3-2. However, most modern SCR systems use sonic horns in place of steam or air soot blowers. So me SCR systems are built without a bypass. However, a unit that uses fuel oil for st artup should have a bypass to avoid getting unburned fuel on the catalyst during startup. SCR in coal fired operation can be placed in one of three locations. The most common is a high dust SCR. With a high dust SCR, the cat alyst is located downstream of the economizer and upstream of a boiler. The second option is a low-dust SCR where the catalyst is located downstream of a hot-sid e ESP. This reduces the cost of an SCR as compared to the high dust SCR since the cata lyst volume can be smaller. It should be noted that an SCR located after a de-energi zed hot-side ESP should be designed and sized as a high dust SCR. The third option is a tail end SCR where the reactor is located downstream of an FGD system. This requires a smaller reactor than the other options but also requires a regenerative he at exchanger to heat the catalyst above the minimum ammonia injection temperature. In selecting a location for the SCR, specific plant issues
need to be assessed to determine the most economical solution. The SCR reactor is the housing for the ca talyst. The reactor is basically a widened section of ductwork modified by the addition of gas flow distribution devices, catalyst, catalyst support structures, access doors, and sonic horns/soot blowers. AnIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-7 

### ammonia injection grid is located upstream of the SCR reactor. The SCR reactor is elevated above and upstream of the air heater. The SCR reaction occurs within the temperature range of 550 to 850 °F, where the extremes are highly dependent on the fuel quality. Along with the NO x 

### reaction, the catalyst oxidizes a portion of the SO 2 

### in the flue gas to SO 3 

### . 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 downstream equipment or possibly requiring an increase in the air heater gas outlet temperature.

Figure 3-2 Schematic Diagram of a Typical SCR Reactor

The ammonia reagent for SCR systems can be supplied by anhydrous ammonia, aqueous ammonia, or by conversion of urea to ammonia. Since the ammonia is vaporized prior to contact with the catalys t, the selection of ammonia type does not influence the catalyst performance. However, the selection of ammonia type does affect other subsystem components, including reagent storage, vaporization, injection control, and balance-of-plant requirements. The vast majority of installations worldwide use anhydrous ammonia.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### SCR systems have a variety of interf acing system requirements to support operations. These requirements include fan draft power, auxiliary power, soot blowing steam, gas temperature, controls, ductwork, r eactor footprint, and air heater. The SCR system will affect the boiler draft system. Depending on arrangement and performance requirements, draft losses can range from 4 to 10 in. wg, which would require additional fan power. If necessary, ductwork and/or boile r box reinforcement may also be required. In conjunction with the fan modification, an expansion of the auxiliary power system might be necessary. Auxiliary power modifi cations may also be necessary for ammonia supply system requirements. The major impact of the SCR system can be seen at the air heater, where there are
two areas of concern. One concern is th e formation and deposition of ammonium
bisulfate on the air heater surface. This will cause an increase in the pressure drop of the air heater, degrading its performance and decr easing plant efficiency. The other potential concern for the air heater is the tendency for high SO 3 

### concentrations in the flue gas to form sulfuric acid vapor. If the acid dew poi nt temperature has been increased to more than the air heater exit temperature, a si gnificant amount of acid gases will condense in the air heater and lead to pluggage and corrosi on. Several measures can be taken to avoid or correct this situation. Most important is the right composition of the catalyst to
minimize the SO 2 

### to SO 3 

### conversion rate. Ammonia slip must also be minimized. Air
heater basket modifications are often nece ssary to minimize these harmful effects.

3.1.4 SNCR/SCR Hybrid The SNCR/SCR hybrid systems use compone nts and operating characteristics of both SNCR and SCR systems. Hybrid syst ems were developed to combine the low capital cost and high ammonia slip associ ated with SNCR systems with the high reduction potential and low ammonia slip inhe rent in the catalyst of SCR systems. The SNCR component of the hybrid system is identical to the SNCR system described previously, except that the hybrid system may have more levels of multiple injection lances. This will increase the capital cost of the SNCR component of the hybrid system. During operation, the SNCR system w ould be allowed to inject higher amounts of reagent into the flue gas compared to conventional SNCR. This increased reagent
flow has a two-fold effect: NO x 

### reduction within the boiler is increased, while ammonia slip also increases. The ammonia that slips fr om the SNCR is then used as the reagent for the catalyst. There are two design philosophies for usi ng this excess ammonia slip. The most conservative hybrid systems use the catalyst si mply as an ammonia slip “scrubber” withIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-9 

### some additional NO x 

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

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

### reduction is realized at the catalyst, the relatively small catalyst requirement of this design allows 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 le vels of additional NO x 

### reduction. However, this philosophy is us ually not economically advantageous when compared to SCR. As a result, hybrid sy stems are usually designed using the first philosophy. The additional reduction is a f unction 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 an efficient method to introduce reagent, because of the low reagent util ization 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 ammo nia to generate 1 ppm of ammonia at the catalyst. Catalyst volume is strongly influenced by the NO x 

### reduction required and the ammonia distribution. If multiple levels of cat alyst operating at low flue gas velocity are required, some modifications wi ll be required to the exis ting ductwork. If widening the existing ductwork cannot provide adequate catalyst volume, then a separate reactor is required, thus eliminating much of the cap ital cost advantage of a hybrid system. The major impact of the hybrid system can be seen at the air heater, where there are two areas of concern. One concern is the formation and deposition of ammonium
bisulfate on the air heater surface. This will cause an increase in the pressure drop of the air heater, degrading its performance and decr easing plant efficiency. The other potential concern for the air heater is high concentrations of SO 3 

### in the flue gas. If the acid dew point temperature has been increased to more than the exhaust temperature, a significant amount of acid gases will condens e in the air heater and lead to pluggage and corrosion.
Several measures can be taken to avoid or corr ect this situation. Modifications to the air heater baskets can help to minimize these adverse effects.

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

### emissions, as illustrated on Figure 3-3. The first zone consists of the normal combustion zone in the lower furnace, which is formed by the existing wall burners. In this zone, 75 to 80 percent of the total fuel heat input is introduced . The first zoneIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### burners are operated with about 10 percent ex cess air (a 1:10 stoichiometric ratio). A second combustion zone (the reburn zone) is created above th e lower furnace by operating a row of conventional natural gas burn ers at a stoichiometric ratio of less than 1.0. This technology also has the potential for increased furnace corrosion (especially with higher sulfur fuels) b ecause of the reducing atmos phere in the lower furnace.
The sub-stoichiometric reburn zone causes NO x 

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

### molecules is combined with the mo re active CO molecules to form CO 2 

### as combustion is completed in the upper furnace. Fuel burnout is completed in the third zone (the burnout zone) by the introduction of OFA. Sufficient OFA is introduced to complete combustion of the unburned material s in the upper furnace, with an overall excess air rate for the boiler of 15 to 20 pe rcent. Reburn technology has demonstrated
NO x 

### reductions of 40 to 65 percent.

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 3-3 Schematic of Gas Reburn System

Sufficient residence time (adequate furn ace height) in the reburn and OFA zones is a key factor in determining whethe r the reburning technol ogy can be applied. Successful retrofit of this technology requi res space within the boiler to allow adequate residence time for both the additional burning zone (0.4 to 0.6 second) and the associated OFA burnout zone (0.6 to 0.9 second). When this space is available, reburning can be highly effective, but a low residence time will limit system performance. Also, the high cost of natural gas makes the annual opera ting costs of this technology prohibitive.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### A variation to gas reburn is fuel lean gas reburn (FLGR), which can reduce NO x 

### emissions from coal fired boilers by 30 to 45 percent. FLGR requires a lower natural gas input than in a conventional gas reburn syst em and does not require an OFA system to achieve CO burnout. The FLGR technology re quires low natural gas flow rates to maintain an overall lean fuel condition (of approximately half the amount required for a conventional reburn system). Mixing between the injected gas and furnace gas is the key to effective NO x 

### removal. CO burnout is achieved by the excess oxygen that is available in the overall fuel lean furnace gas. A newer development of the FLGR system consists of incorpor ating a urea-based SNCR system into the gas reburn system. Th is technology involves injecting natural gas and urea; the system is called amine-enhanced fuel lean gas reburn (AE-FLGR). This technology is capable of a higher NO x 

### removal efficiency than the basic gas reburn and FLGR systems. An amine-enhanced system is capable of reducing NO x 

### emissions by 50 to 70 percent.

3.1.6 Mobotec ROFA and ROTAMIX Mobotec provides a NO x 

### reduction system that combines LNBs, OFA, and SNCR technologies into an integrated system. The system uses a modified OFA system with mixing characteristics achieved by adding a rotation to the OFA. This system is called ROFA, or Rotating Opposed Firing Air. A boost er fan is used to direct combustion air away from the primary combustion zone a nd to the upper portion of the furnace. Air nozzles are strategically placed so that the gas flow inside the furnace rotates, causing turbulent mixing. The ROFA system has the potential to provide improved combustion, which results in lower unburned carbon, lower CO and NO x 

### production, and improved boiler efficiency. In addition, ROTAMIX can be added to th e system, which consists of injecting urea or ammonia into the ROFA air nozzles . The extra mixing produced by combining the OFA nozzles with the reagent injection can achieve additional NO x 

### reduction because of a homogeneous temperature profile in th e boiler. The ROTAMIX system adapts to changes in load and temperature in the fu rnace and preferentially introduces ammonia where the temperature is most favorable for NO x 

### reduction. This approach reduces chemical consumption considerably and lowe rs ammonia slip by in creasing the reaction efficiency through mixing. Chemical consumption for a ROTAMIX system can be up to 50 percent less than other SNCR technologies. ROTAMIX installations have yielded up to 60 percent NO x 

### reduction in addition to the ROFA NO x 

### reduction. Although the Mobotec system may offer si gnificant advantages over conventional scrubbing, impacts such as the increased volumes of particul ate that would need to be collected, expected additional costs for sorbent, and the limited large-scale installedIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-12 

### experience with the system should be consider ed. A simplified process flow diagram of the ROFA and ROTAMIX system is illustrated on Figure 3-4.

3.1.7 NO x 

### Star
NO x 

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

### control technology that involves the injection of ammonia and a hydrocarbon (typically natural gas) into the flue gas path of a coal fired boiler at around 1,600 to 1,800° F for the reduction of NO x 

### . The ammonia
reduces NO x 

### through an SNCR reaction, with the hydrocarbon minimizing the ammonia slip. This enables higher reagent injection rates for NO x 

### reductions than are achievable with a typical SNCR technology. The technology supplier states that the technology has the ability to achieve NO x 

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

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

### reduction performance.

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

3.1.8 ECOTUBE The ECOTUBE system utilizes retractable lance tubes that penetrate the boiler above the primary burner zone a nd inject high-velocity air as well as reagents. The lance
tubes work to create turbulent airflow and to increase the residence time for the air/fuel mixture. In principle, the OFA and SNCR pr ocesses are combined in this technology. ECOTUBE is capable of reducing NO x 

### , CO, and volatile organic compounds, while improving thermal efficiency, by optimizi ng the combustion process in boilers. An
illustration of the ECOTUBE installation in a typical boiler is shown on Figure 3-5.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### Figure 3-5 ECOTUBE Installation in a Boiler

The water-cooled ECOTUBEs are automati cally retracted from the boiler on a regular basis and cleaned to remove layers of soot and other deposits. Additional benefits have been identified by the supplier, including furnace combustion improvements that increase efficiency, reduce fuel usage, and reduce corrosion and eros ion in the boiler and back-end equipment.

3.1.9 PowerSpan There are several emerging multi-pollutant technologies that use high electron beams or other proprietary processes. The PowerSpan ECO system has only limited experience and is beginning small-scale co mmercial operation. The ECO system is located downstream of an existing particulate co ntrol device; the process consists of three stages. A process flow diagram of the ECO system is illustrated on Figure 3-6. In the first stage, the flue gas passe s through a dielectric barrier discharge reactor, where it is exposed to a nonthermal plasma discharge, which generates high energy electrons. The
electrons initiate a chemical reaction to form oxygen and hydroxyl radicals, which then
oxidize NO x 

### , SO 2 

### , and Hg. This process results in the formation of nitric acid (HNO 3 

### ), sulfuric acid, and mercuric oxides. Stage 2 is the collection of these acids and oxides in a downstream ammonia scrubber. The final stage is the collection of acid aerosols, fine PM, and oxidized Hg in the downstream wet ES P. Scrubber effluents contain dissolved ammonium sulfate nitrate (ASN ) salts along with solids an d Hg. The ASN solution is sent to a recovery process where the Hg is removed via a sulfur-impregnated activated
carbon structure. Once the activated car bon bed becomes saturated with Hg, it isIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### disposed of as a hazardous waste. The cleaned stream of ASN is converted to a saleable
fertilizer. The ECO system has been tested on a 1 to 2 MW slipstream unit at FirstEnergy’s Burger Plant and has achieved 82, 99, and 85 percent reduction for NO x 

### , SO 2 

### , and Hg, respectively.

Figure 3-6 ECO Process Flow Diagra m (Source: PowerSpan)

3.1.10 Phenix Clean Coal Combustion System The Phenix Clean Combustion System (CCS) is an advanced hybrid coal gasification/combustion process that prevents the formation of NO x 

### and SO 2 

### emissions when burning coal. The only reagent requi red for pollution control is limestone. The CCS consists of an entrained-flow coal gasifier, followed by stages of combustion air. The CCS burner is designed to provide the necessary time, temperature, and stoichiometry required for all the chemi cals in coal to complete their combustion reactions (to reach equilibrium conditions). The coal, with limestone added as a sour ce of calcium for sulfur capture, is pulverized and introduced to the burner al ong with a limited amount of hot combustion air. The initial high temperature combustion ga sifies and/or releases all the constituents of coal into the gas; i.e ., carbon, sulfur, nitrogen, and ash compounds. At these high temperatures, and with limited available oxygen, the carbon aggressively commands oxygen to form CO from all sources, incl uding such compounds as water. Nitrogen compounds that may form, such as NO x 

### , hydrogen cyanide, and ammonium (NH 4 

### ), are forced to the molecular form (N 2 

### ) by the aggressive action of carbon for oxygen. In theIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### presence of calcium, the sulfur reacts to fo rm calcium sulfide (CaS, a solid non-gaseous particle). The high combustion temperatures melt the coal ash and calcium sulfide solids to form an inert slag that drains from the botto m of the boiler. The hot flue gas, with high concentrations of CO and H 2 

### and low concentrations of NO x 

### and sulfur, exits 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 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 they did before the retrofit. A schematic of the process is shown on Figure 3-7. Retrofits require an annual outage period with a 2 to 3 week extension, for a total of 8 weeks. The CCS retrofit modification re quires replacing the ex isting pulverized coal burners with new down-fired CCS burners and adding 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.

Figure 3-7 Phenix Clean Coal Process Flow Diagram. (Source: Phenix)Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### A CCS repowered boiler will show improved efficiency from more complete coal combustion (loss on ignition of < 1.0 percent), very low NO x 

### (< 0.15 lb/MBtu), and control of SO 2 

### emissions (< 0.5 lb/MBtu) w ith lower sulfur coals.

3.1.11 e-SCRUB The e-SCRUB process is similar to the PowerSpan technology in that it uses an energy source to oxidize pollutants in the flue ga s. However, there are some variations in the oxidation energy source and by product recovery systems. A process flow diagram is shown on Figure 3-8. The proce ss consists of the following:

• e-Beam Chamber--This process uses a high-energy electron beam in a chamber, the e-Beam chamber, to oxidize SO 2 

### to SO 3 

### and NO x 

### to a combination of N 2 

### , HNO 3 

### , and NO 2 

### . Ammonia is injected upstream of the chamber and reacts with the oxidized compounds to form ammonium sulfate and ammonium nitrate.

Figure 3-8 e-SCRUB Process Flow Diagram (Source: http://www.escrub.com/escrubprocess.htm)

• Wet ESP--The ammonium sulfate and ammonium nitrate are precipitated and collected as brine. The brine is then sent to an upstream spray dryer absorber and dry ESP.

• Spray Dryer Absorber--The brine from a downstream wet ESP is fed into a spray dryer absorber, which forms a dry ammonium sulfateIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### ((NH 4 

### ) 2 

### SO 4 

### )/ammonium nitrate (NH 4 

### NO 3 

### ) product that can be used as a fertilizer. The temperature of the flue gas is reduced in the spray dryer to an ideal reaction temperature prior to entering the e-Beam chamber.

• Dry ESP--The dry ESP functions as a secondary byproduct collector and is located directly downstream of the spray dryer absorber. According to pilot data, the vendor estimates that SO 2 

### and NO x 

### removals of 98 and 90 percent, respectively, are achievable. To make this system cost-effective, it is important to locate a company to supply the ammonia reagent and remove the fertilizer byproduct. The e-SCRUB technology has b een applied commercially on a 200 MW facility in China.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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## 3.2 Particulate Matter Control Technologies PM control technologies that were identifie d as available for retrofit at SJGS are listed below. Only post-combustion control is available for PM control. A short summary of each technology is includ ed in the following sub-sections:

• Flue Gas Conditioning with Hot-Side ESP.

• Pulse Jet Fabric Filter.

• Compact Hybrid Particulate Collector.

• Max-9 Electrostatic Fabric Filter.

3.2.1 Flue Gas Condi tioning with Hot-Side ESP For most subbituminous coal fired power boilers, the low sulfur content in the coal causes the fly ash produced to have high resistivity. The reason for the higher fly ash resistivity is the lowe r concentration of high conduc tivity ionic sulfur oxide molecules in the flue gas. The high fly ash re sistivity is not optimal for fly ash capture in an ESP and also limits the boiler fuel flex ibility, since the ESP design is based on a defined range of fly ash characteristics. To improve the capture of the particulate in the ESP, the flue gas leaving the air heater into the ESP can be conditioned by the addition of ionic compounds such as SO 3 

### , ammonia, or both. These compounds combine with the moisture in the flue gas and are deposited on the surface of the fly ash particles. This will increase the conductivity of the fly ash and, therefore, make it suitable for capture. The effectiveness of a flue gas conditioning system can be determined by evaluating the ESP performance as flue gas conditioning agents are introduced in the flue gas stream ahead of the ESP. This is th e most effective method of determining the optimal injection rate of the fl ue gas conditioning agent. The equipment needed for injection of the flue gas conditioning agen t is usually skid-based. If SO 3 

### is chosen as the flue gas conditioning agent, it is usually produced onsite through oxidation of SO 2 

### in a catalytic converter. Dr y or molten sulfur feedstock may be used; the feedstoc k is burned to produce SO 2 

### . Alternatively, ammonia can be used as an agent; ammonia is usually vapori zed and injected into the flue gas stream using a standard pump skid.

3.2.2 Pulse Jet Fabric Filter
Fabric filters have been used for more than 20 years on existing and new coal fired boilers. Flue gas passes through media filters to remove th e particulate. The success of fabric filters is pr edominantly due to their abilit y to economically meet the low particulate emissions limits for a wide range of particulate and fuel characteristics. Proper application of the fabric filter tec hnology can result in cl ear stack dischargesIdentification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

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### (generally less than 5 percent opacity) for a full range of operations. In addition, the fabric filter is relatively insensitive to ash loadings and various ash types, offering superb coal flexibility.
Fabric filters are the curre nt technology of choice wh en low outlet particulate emissions or Hg reduction is required for coal fired applications. Fabric filters collect particle sizes ranging from submicron to 100 microns in diameter at high removal
efficiencies. Provisions can be made for th e future addition of ac tivated carbon injection to enhance gas-phase elemental Hg removal fr om coal fired plants. A few types of fly ash filter cakes will also absorb some elemental Hg. The cloth filter medium is typically sewn into cylindrical tubes called bags. Each fabric filter may have thousands of these filte r bags. The filter unit is typically divided into compartments that allow online mainte nance or bag replacement. The quantity of compartments is determined by maximum economic compartment size, total gas volume rate, air-to-cloth (A/C) ratio, and cleaning system design. Each compartment includes at least one hopper for temporary storage of the collected fly ash. A cutaway view of a PJFF compartment is illustrated on Figure 3-9. Fabric bags vary in composition, length, a nd cross section (diameter or shape). Bag selection characteristics vary with clea ning technology, emissions limits, flue gas and ash characteristics, desired bag life, capital cost, A/C ratio, and pressure differential. Fabric bags are typically guara nteed for 3 years but frequently last 5 years or more. In PJFFs, the flue gas typically enters the compartment hopper and passes from the outside of the bag to the inside, depositing particulate on the outside of the bag. To prevent the collapse of the ba g, a metal cage is installed on the inside of the bag. The flue gas passes up through the center of the bag into the outlet plenum. The bags and cages are suspended from a tubesheet. Cleaning is performed by in itiating a downward pulse of air into the top of the bag. The pulse causes a ripple effect along the length of the bag. This releases the dust cake from the bag surface, and the dust falls into the hopper. Cleaning may occur with the compartment online or offline. Care must be taken during design to ensure that the upward velocity between the bags is minimized so that PM is not re-entrained during the cleaning process. The PJFF cleans bags in sequential, and usually staggered, rows. During online cleaning, part of the dust cake from the row being cleaned may be captured by the adjacent rows. Online cleaning has been successfully implemented on PJFF on many large units and is a standa rd feature of the technology.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-20 

### Figure 3-9 Pulse Jet Fabric Filte r Compartment (Source: Babcock & Wilcox)

The PJFF bags are typically made of felted materials that do not rely as heavily on the dust cake’s filtering capability as woven fiberglass bags. This allows the PJFF bags to be cleaned more vigorously. The felted mate rials also allow the PJFF to operate at a much higher cloth velocity, which significantl y reduces the size of the unit and the space required for installation.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-21 

### 3.2.3 Compact Hybrid Particulate Collector A variant of the PJFF is the compact hybrid particulate co llector (COHPAC). This is a high A/C ratio fabric filter installed downstream of existing particulate collection devices where the majority of PM has been removed. The COHPAC acts as a polishing filter to further re move PM to meet the requir ed emissions rate. 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 (6:1 to 8:1), compared to a conventional fabric filter that typically operates at A/C ratios of about 4 ft/min (4:1). Since the majority of the particulate is collected in the upstream ESP, the performance requirements of a high A/C ratio fabric filter is reduced, which allows
installation of this t echnology in a smaller footprint area, with less steel and filtration media; both capital and operating costs are lowe r than those of conventional fabric filters.

3.2.4 Max-9 Electrostatic Fabric Filter The Max-9 electrostatic filter is essent ially a high-efficien cy PJFF utilizing a discharge electrode as in an ESP. However, there are no collector plates. When the dust particles are charged, they are attracted to the grounded metal cage inside the filter element, just as they would be attracted to the collecting plates in an ordinary precipitator. A front and side elevation view of the Max-9 particulate filter is illustrated on Figure 3-10. Since the partic les are charged positively, they repel each other on the surface of the filter, making the collected dust cake very porous. The porous dust cake layer on the surface of the bags results in a pressure drop of about 25 percent compared to that of a normal fabric filter. Consequentl y, the Max-9 can operate at an A/C ratio higher than a conventional fabric filter and can treat a significant gas volume with a smaller footprint. Process gas enters the Max-9 from a hopper inlet duct. The gas then flows upward through the filters and out through the top of the filters. The area above the tubesheet 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 mani fold; holes in the blowpipes
located above the filters direct the clean ing air pulse down thr ough the filters. The cleaning sequence is controlled by timers that trigger solenoids. The high voltage system operates at very low current densities and at a steady state. There is no danger of fire caused by sparking, and the transformer/r ectifier requires no voltage control.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-22 

### Figure 3-10 Max-9 Electrostatic Filter (Source: GE Environmental)

The Max-9 can be supplied as shop assemb led modules that can be erected onsite, although the units are usually custom-engineered for each plant site and application to make the best use of available space.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-23 

## 3.3 Draft System Impacts The addition of an SCR or hybrid SCR/SN CR would result in additional pressure requirements beyond the capabilities of the curr ent fans on the SJGS units. To provide for this additional pressure dr op, three alternatives are availa ble. These alternatives are discussed in the following subsections.

3.3.1 New Booster Fans The existing booster fans are currently bei ng retrofitted with larg er rotors to allow compliance with the upcoming consent decree upgrades. Further modifications to the booster fans are not possible w ithin the existing housing. New booster fans would be a possible op tion. Typically, the new fans would be
installed near the current ones and the ductwo rk rerouted to save outage time. This alternative would not change the furnace ope rating pressure; however, depending on the final design, equipment downstream of the convection pass may operate under a negative

pressure.

3.3.2 New Forced Draft Fans It is unlikely that each unit’s current forced draft fan could accommodate a new rotor capable of a 20 to 30 percent increase in total pressure; it is expected that an entirely new forced draft fan would be required. To reduce outage time, the new fans are typically installed close to the current ones and the ductwork rerout ed. The limited space
available at the SJGS could result in long combustion air duct runs, which would complicate this alternative.
In addition to the new forced draft fa n, the boiler and ductwork may need to be stiffened to handle the increased boiler pressu re. The increased pressure would increase the leakage of hot flue gas and ash out of th e boiler and ductwork, re sulting in increased maintenance requirements. This leak age would cause increased housekeeping requirements around the boiler area and an unpleasant working e nvironment for plant personnel.

3.3.3 Balanced Draft Conversion Conversion to balanced draft operati on would move the balance point (zero relative pressure) inside the furnace. SJGS cu rrently operates with th e balance point just before the booster fans. The following mo difications would be necessary for the balanced draft conversion:

• New induced draft fans and motors.Identification of All Available Retrofit Emissions PNM San Juan Generating Station Control Technologies

060607 3-24 

### • Potentially, new motors for the existi ng forced draft fans to improve fan efficiency.

• Boiler wall stiffening to opera te under a negative pressure.

• Ductwork stiffening to operate under a negative pressure.

• Control system modifications.

• Increased power requirements. These modifications would require an approximate 12 week unit outage to perform.
A balanced draft unit woul d have significantly less as h and soot leakage around the boiler working area and would expe rience higher unit availability.
Previous studies have shown that the benefits of this alternative offset the costs in the majority of cases. Base d on the previous analyses, costs for the SCR or hybrid
installations included in later sections will include the cost of a balanced draft conversion.BART Implications of the Consent PNM San Juan Generating Station Decree Technology Selection

060607 4-1 

## 4.0 BART Implications of the Consent Decree Technology Selection

As previously discussed in Sectio n 1.1, PNM was required, under a consent decree action, to implement environmental sy stem upgrades at SJGS. The environmental upgrade process is currently in progress with the installati on of state-of-the-art LNBs with OFA ports and an NN system for NO x 

### control. For SO 2 

### emissions reduction, the wet limestone scrubber is being modified to eliminate flue gas bypass, and DBA is being added to the scrubber process to improve SO 2 

### removal. The new PJFF’s that are being
added for PM emissions control will also serve as a component for reducing Hg emissions through activated carbon addition into fl ue gas. Other balance-of-plant system upgrades are also being performed to s upport these additional AQC systems. In this section of the report, the emission reductions from these environmental upgrades and the costs for compliance are quantified for evaluation as emissions control scenarios for BART. Only the NO x 

### and PM control technologies are included in the BART emissions control scenario, since the st ate of New Mexico will participate in the
WRAP SO 2 

### trading program.



## 4.1 NO x 

## Consent Decree Control Technologies 4.1.1 Description of NO x



### Consent Decree Upgrades B&W will retrofit all four units with state-of-the-art integrated low-NO x 

### combustion systems. The systems for all units will include LNB (Model DRB-4Z), new
dual-zone NO x 

### ports, and an NN system. To acco mmodate the new combustion system, work will be performed on the boiler wind box plenum, secondary air feeder ducts, waterwall panel, access platforms. Efforts will also be made to improve fuel/air balancing. In addition, underfire air ports will be installed on Units 1 and 2 on the bottom two rows of the wall opposite to the burners . These ports will serve to break up the reducing atmosphere on the boiler wall to protect the tubes from degradation.

4.1.2 NO x



### Consent Decree Upgrad es Control Effectiveness B&W provided an emissions performance guarantee for the installation of consent
decree controls for NO x 

### reduction. NO x 

### emissions are guaranteed to a level of 0.293 lb/MBtu on a 30 day rolling average basis for each unit. There will be a year long
test on each unit to determined if a lower NO x 

### emission limit can be achieved. The
control effectiveness used for the consent decree NO x 

### upgrades, which is defined as theBART Implications of the Consent PNM San Juan Generating Station Decree Technology Selection

060607 4-2 

### controlled emissions level in terms of the amou nt of pollutant genera ted per unit of heat input (lb/MBtu) is the guaranteed level of 0.293 lb/MBtu. The pre-consent decree operation emissi ons levels (lb/MBtu) were based on annual averages from 2001 to 2003. This information was obtained from the 40 CFR Part 75 Electronic Data Reports for all four units. The hourly emissions rates were determined according to the emissions level an d the design basis heat input. Compared to the pre-consent decree operation emissi ons levels at SJGS, which are shown in Table 4-1, the consent decree upgrade control effectiveness from the environmental upgrade work will result in a yearly emi ssions reduction ranging from 1,794 ton/yr at Unit 1 to 2,572 ton/yr at Unit 3. Thes e results are deta iled in Table 4-2.

4.1.3 NO x



### Consent Decree Upgrades Cost-Effectiveness Cost estimates for the consent decree work were provided by PNM and are
summarized in Appendix C . A snapshot of the total capit al investment (TCI) and total annualized cost (TAC) for each unit is provided in Table 4-2. From the total cost for the upgrades and the expected em issions reduction from the ne w LNB, OFA ports, and an NN system, the cost-effectiveness, defined as the cost of control per amount of pollutant removed in $/ton, was estimated for each unit. These values are also shown in Table 4-2. In summary, the cost-effectiveness of the NO x 

### consent decree upgrades ranges from 482 $/ton for Unit 3 to 793 $/ton for Unit 1.

4.1.4 Summary of NO x



### Consent Decree Upgrades
The NO x 

### emissions control being installed at SJGS as a result of the consent
decree are state-of-the-art combustion cont rols with a manufacturer’s performance guarantee of 0.293 lb/MBtu. Alth ough the guaranteed emission level is higher than the BART presumptive limit of 0.23lb/MBtu, the presumptive limit was developed for a dry bottom wall, fired boiler with LNBs and OFA burning a PRB subbituminous coal. The LNBs, OFA, and NN being installed on each of the SJGS units are equivalent to the BART technology used to develop the 0.23 lb/MBtu presumptive NO x 

### limit.
SJGS fires a local New Mexico coal. Th e coal burned at SJGS has been referred
to as both a subbituminous coal and a bitumi nous coal, since it possesses qualities that place it in a “gray area” between the bituminous and the subbituminous categories of coal. Based on these characteristics, th e ASTM D388 classification would place the
SJGS coal in either of the bituminous Gr oup C or subbituminous Group A coal category. The difference between these two groups is not relevant, but the fact that the SJGS coal cannot be categorized as subbituminous Group C is very important in that subbituminous Group C includes PRB coals, which are known to produce very low NO xBART Implications of the ConsentPNM San Juan Generating Station Decree Technology Selection0606074-3Table 4-1Consent Decree Technologies Control Effectiveness (Annual Average Emissions Rates)UnitSJGS 1 SJGS 2 SJGS 3 SJGS 4Design Basis HeatInput Data, MBtu/h3,707 3,688 5,758 5,649NOxEmissionsCaseslb/MBtulb/hton/yrlb/MBtulb/hton/yrlb/MBtulb/hton/yrlb/MBtulb/hton/yrPre-Consent DecreeOperation0.43 1,592.0 5,394 0.45 1,649.3 6,179 0.42 2,405.5 9,004 0.42 2,399.6 8,833Consent DecreeUpgrades(LNB/OFA/NN)0.30 1,112.1 4,140 0.30 1,106.4 4,119 0.30 1,727.4 6,431 0.30 1,694.7 6,309PM EmissionsCaseslb/MBtulb/hton/yrlb/MBtulb/hton/yrlb/MBtulb/hton/yrlb/MBtulb/hton/yrPre-Consent DecreeOperation0.050 185.4 690 0.050 184.4 687 0.050 287.9 1,072 0.050 282.5 1,052Consent DecreeUpgrades(PJFF)0.015 55.6 207 0.015 55.3 206 0.015 86.4 322 0.015 84.7 315Notes:1.Emissions levels (lb/MBtu) shown are on an annual average basis.2.Emissions (lb/h) calculations were based on the emissions level (lb/MBtu) and design basis heat input.3.Pre-consent decree operation emissions wereannual averages from the years 2001 to 2003.4.Emissions levels listed were based on performance guarantees provided by the equipment vendor.5.Yearly emissions (ton/yr) calculations were based on an annual unit capacity of 85 percent.BART Implications of the Consent PNM San Juan Generating Station Decree Technology Selection

060607 4-4 

### Table 4-2 Control and Cost-Effectiveness Resu lts of Consent Decree Upgrades

Total Total Emission Expected Expected Expected Capital Annualized Performance Emission Emission Emission Investment Cost Cost Consent Decree Level Rate Rate Reduction (TCI) (TAC) Effectiveness Upgrades Scenario (lb/MBtu) (lb/h) (ton/yr) (ton/yr) (1,000$) (1,000$) ($/ton) NOx Reduction - LNB/OFA/NN

SJGS 1 0.30 1,112.1 4,140 1,794 14,580 1,422 793 SJGS 2 0.30 1,106.4 4,119 2,060 14,126 1,378 669 SJGS 3 0.30 1,727.4 6,431 2,572 12,715 1,240 482 SJGS 4 0.30 1,694.7 6,309 2,524 12,870 1,256 498

PM Reduction - PJFF

SJGS 1 0.015 55.6 207 483 67,072 10,427 21,586 SJGS 2 0.015 55.3 206 481 69,840 10,764 22,399 SJGS 3 0.015 86.4 322 750 72,696 12,454 16,599 SJGS 4 0.015 84.7 315 736 73,328 12,527 17,018

Notes:

1. All costs are in 2007$. 2. Expected emission rates (ton/yr) calculations were based on 85 percent unit capacity factor (refer to Appendix A Design Bas is). 3. Expected emission reduction (ton/yr) calculations were based on the pre-consent decree upgrades control effectiveness

as shown in Table 4-1. 4. TCI and TAC are referenced from Appendix C Cost Analysis Summary. 5. Cost-effectiveness ($/ton) is defined as ratio of TAC over expected emission reduction (ton/yr). 6. Expected emission reduction is based on annual emission reduction from pre-consent decree operation emission levels.



### emissions when fired in utility boilers. Table 4-3 compares the fuel fired at SJGS to typical bituminous and PRB fuels. This f undamental understanding of the variation in
NO x 

### formation from different types of US coals explains why the expected NO x 

### rates of boilers burning the coal fired at SJGS cannot be as low as boilers firing PRB
subbituminous coals.
The coal burned at SJGS is less vola tile and has a lower oxygen and moisture content than PRB coals. The greater volat ility and higher oxygen and moisture content found in PRB fuels are key to the lower NO x 

### emissions seen in boilers combusting PRB coal. The high volatility in PRB coals reduc es combustion time. The higher fuel oxygen
content reduces the amount of additional air (i.e., nitrogen) required for combustion; the higher fuel moisture content reduces the fl ame temperature and, therefore, reduces the
formation of thermal NO x 

### . The nitrogen content in the fuel affects NO x 

### generation
because of the oxidation of fuel-bound n itrogen. As it relates to the amount of NO x 

### generated from combustion, the coal burned at SJGS is more similar to the low-sulfur
bituminous coal than it is to PRB subbituminous coal. A comparison of the New Mexico subbitumi nous coal burned at SJGS to a typical subbituminous PRB (Bucksin, WY mine) and a typical low-sulfur bituminous coal (Twentymile, CO mine) is shown in Table 4-3.BART Implications of the Consent PNM San Juan Generating Station Decree Technology Selection

060607 4-5 

### Table 4-3 Coal Properties Comparison

Another factor affecting the potential for NO x 

### reduction at SJGS is the boiler design. Because of the HHV of the coal, the SJGS boilers are smaller in size (effective boiler volume) than similar output capacity boilers combusting PRB coal. This has a negative effect on potential NO x 

### emissions reduction because a smaller volume boiler will operate hotter, thus increasing thermal NO x 

### formation. Additionally, SJGS Units 1 and 2 have limited flame length because of the high heat input bur ners on the front wall
of the boiler. This reduces the effectiven ess of the overfire ai r from the OFA ports.



## 4.2 Particulate Matter Consen t Decree Control Technologies 4.2.1 Description of PM Consent Decree Upgrades For PM emissions reduction, a PJFF system will be installed on each of the four units at SJGS in response to the consent d ecree. The PJFFs will be installed downstream of the existing hot-side ESPs and air heater s. After the commissi oning of the PJFF, the hot-side ESP will be de-energized. As previously noted, Hg emissions ar e not being consider ed in the BART analysis. However, it is important to note th at the PJFF will also serve as a component of the Hg control system. Activat ed carbon will be in jected into the flue gas downstream of Typical SJGS Typical Subbituminous New Mexico Low-Sulfu r PRB Subbituminous Bituminous 

### U ltimate coal analysis, as received

Carbon, % 49.00 54.52 64.05 Hydrogen, % 3.24 4.24 4.53 Sulfur, % 0.35 0.77 0.50 Nitrogen, % 0.63 1.08 1.63 Oxygen, % 11.68 9.38 10.09 Ash, % 5.15 21.29 9.80 Moisture, % 29.95 8.72 9.40

Total, % 100.00 100.00 100.00 Higher Heating Value, Btu/lb (as received) 8,400 9,692 11,400 Volatile matter, % (as received) 30.25 34.3 35.8 Volatile matter, % (dry) 43.18 37.6 39.5

Notes: 1. Typical subbituminous PRB analysis was based on Buckskin Mine (Wyoming). 2. Low-sulfur bituminous analysis was based on Twentymile Mine (Colorado). 3. SJGS New Mexico subbituminous analysis was based on BART analysis design basis. 4. SJGS New Mexico subbituminous volatile ma tter is referenced from SJGS consent decree Environmental Project Design Criteria, Sargent & Lundy, June 15, 2006.BART Implications of the Consent PNM San Juan Generating Station Decree Technology Selection

060607 4-6 

### the air heater for adsorption of Hg in the flue gas. The PJFF is used to capture the Hgladen activated carbon and other PM.
The PJFF installation will also necessita te modifications to the existing booster fans to handle the additional pressure requireme nts. Larger rotors will be installed into the existing booster fan housings. The units will continue to have positive pressure furnaces, but cannot be classified as truly forced draft or truly balanced draft. The boiler itself will continue to operate at a positive pres sure, but there will be points in the flue gas path where the flue gas will have a negative pressure.

4.2.2 PM Consent Decree Upgrades Control Effectiveness For each unit, B&W will provide a performa nce guarantee that the total filterable particulate matter (PM 10 

### ) will be controlled to 0.015 lb/M Btu at the stack. The PJFF is installed primarily to reduce opacity spikes during upset unit operating conditions and also as a component for Hg control as described above. In comparison to the pre-consent decree operation emission levels at SJGS, which are shown in Table 4-1, the consent decree upgrade control effectiveness from the environmental upgrade work will result in a yearly emissions reduction ranging from 481 ton/yr at Unit 2 to 750 t on/yr at Unit 3. This result is detailed in Table 4-2.

4.2.3 PM Consent Decree Upgrades Cost-Effectiveness A cost estimate for the new PJFF was provided by PNM and is summarized in Appendix C . From the total cost for the upgrades and the expected emissions reduction from the new PJFF equipment, the cost-effectiveness in $/ton was estimated and is shown
in Table 4-2. Because of the small amountof total emissions reduction, the costeffectiveness of the new PJFF is very hi gh, ranging from 16,599 $/ton at Unit 3 to 22,399 $/ton for Unit 2.

4.2.4 Summary of PM Consent Decree Upgrades
With the addition of PJFFs for PM emissi ons control, SJGS will have the most stringent control technology availa ble for limiting the emissions of PM 10 

### . The performance guarantee from the equipment vendor is typical of most new PJFF systems. It meets the New Source Performance Standards (NSPS) emissions level for PM 10 

### and represents a BACT level of pollution contro l. Therefore, the new PJFF equipment at
SJGS should be considered as BART for PM emissions reduction.BART Implications of the Consent PNM San Juan Generating Station Decree Technology Selection

060607 4-7 

## 4.3 Summary of Consent Decree Control Technologies

The evaluation of the consent decree c ontrol technologies currently being implemented at SJGS for the BART analysis indicates that the new LNB, OFA, and NN
installed for NO x 

### emissions represent the state-of-t he-art combustion control technology,
and the PJFF installed for PM emissions is the most stringent c ontrol technology for PM
emissions control.Technical Feasibility of Additional PNM San Juan Generating Station Control Technology Alternatives

060607 5-1 

## 5.0 Technical Feasibility of Additional Control Technology Alternatives

As stated in Subsection 1.2.2, technically feasible retrofit emissions control technologies are identified by eliminating tech nically infeasible opt ions. This section describes how the technical feasibility of a control technology is defined by the EPA in the BART guidelines. The technologies identif ied in Step 1 (Section 3.0) are considered available technologies at the time of issue of this report. Section 4.0 describes the BART analysis that was performed for the consent decree control technologies. The analysis in Section 4.0 shows that the consent decree control technologies should be considered as BART. Howe ver, to provide additional support for that determination, the BART an alysis process was applied for additional control technology alternatives to the consent decree technologies. In the process of eliminating technically infeasible alternatives, it is necessary to demonstrate that a technology is not applicable or not available for application at the source. This demonstration is made by s howing that the technol ogy is commercially
unavailable and/or there are insurmountable technical difficulties with applying the technology to the applicable unit. Other factor s that are considered when determining the technical feasibility of a technology include the following:

• Size of the unit.

• Location of the proposed technology.

• Operating problems after retrofit of technology.

• Space constraints.

• Reliability.

• Adverse effects on the re st of the facility.

• Adverse community impacts. Additionally, a technology is technically inf easible if its level of emissions control does not achieve the required permit emissi ons limit applied to the source by the regulating agency. Finally, if there are multiple control technologies that have an equivalent level of control, the BART proce dure allows for the cons ideration of the less costly control technology, th erefore eliminating the need to evaluate higher cost technologies. For all the technologies identified as avai lable in Section 3.0, a determination was made regarding the technical feasibility of th e technology at the SJGS site on the basis of the criteria highlighted above.Technical Feasibility of Additional PNM San Juan Generating Station Control Technology Alternatives

060607 5-2 

## 5.1 Technically Infeasible Additional NO x 

## Control Technology Alternatives 5.1.1 Selective Non-Catalytic Reduction SNCR was determined to be technically infeasible because the controlled NO x 

### emissions do not meet the required presumptive emissions limits. A budgetary performance evaluation from an SNCR vendor indicated that the controlled NO x 

### emissions level would be 0.24 lb/MBtu for all four units at SJGS. A lower controlled
NO x 

### emissions level of 0.23 lb/MBtu, which woul d meet the presumptive limit, could be achieved if the ammonia slip limit is raised fr om 5 ppm to 10 ppm. However, the higher ammonia slip will significantly increase th e risk for blinding fabric filter bags and shortening bag life. The risk is also hi gh for air heater pluggage from ammonium bisulfate. Air heater pluggage degrades air heater performa nce and directly impacts plant efficiency. Therefore, the 10 ppm ammonia slip cannot be tolerated, thus rendering the
SNCR infeasible as an additional co ntrol technology alternative.

5.1.2 Natural Gas Reburn Natural gas reburn in the SJ GS boilers is not technically feasible because of the lack of space in the boiler for sufficient resi dence time for the natural gas reburn zone. The ongoing environmental upgrades at each boiler include the addition of new OFA ports, which will limit the physical space on the boiler wall for a natural gas reburn system, especially on Units 1 and 2 where heig ht is limited. In addition, a new natural gas supply line would be required, since th e existing natural gas line was abandoned. The exposure to the volatility of natural gas prices is also a negative factor when considering natural gas reburn as a NO x 

### control technology.

5.1.3 Mobotec ROFA and ROTAMIX Mobotec’s ROTAMIX technology is not considered techni cally feasible, because there are no current installations at pulverized coal fired boilers of the equivalent size to that of SJGS. The ROFA technology is a vari ant of the OFA system that is already being
added as a result of the consent decr ee. Although the Mobotec system may offer advantages over conventional scrubbing, the in creased volumes of pa rticulate that would need to be collected, the expected additional costs for sorbent, and the limited large-scale experience with the system are significant fa ctors that make it infeasible for this application.Technical Feasibility of Additional PNM San Juan Generating Station Control Technology Alternatives

060607 5-3 

### 5.1.4 NO x



### Star The major consideration for the NO x 

### Star technology is that it currently has only one major installation in the United States and may require the installation of a single layer of in-duct catalyst (NO x 

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

### reduction. Availability of natural gas is a factor th at must be considered when assessing the technical feasibility of this technology. Th ere is no natural gas supply at SJGS. In addition, through recent discussions, the s upplier has identified limited ability and willingness to market the commercial technology.

5.1.5 ECOTUBE This technology has been demonstrated in installations on i ndustrial/small-sized boilers firing solid waste, wood, or biomass. It is not technically feasible to apply this technology to boilers of the size as those at SJGS.

5.1.6 PowerSpan The PowerSpan process has only been pr oven on a small scale and has not been applied at large-size commercial systems such as SJGS. Therefore, this process is not applicable for retrofit at SJGS. In addition, the ECO system has not be en pilot tested at a facility burning a low sulfur (< 1.5 percen t) subbituminous coal or in a large, commercial-scale system. Therefore, it is cons idered not technically feasible for retrofit
at SJGS. It should be noted that the firs t full-scale commercial unit using this process will be installed in FirstEnergy’s Burger plant. After it is installed, a better evaluation of the technical feasibility can be made.

5.1.7 Phenix Clean Combustion This technology is still in the demonstr ation and testing stage. There are no
commercial retrofits at facilities similar to SJGS. Therefore, this technology is not considered to be applicable for retrofit at SJGS.

5.1.8 e-SCRUB Although the e-SCRUB process system app ears to offer significant advantages, it is still an experimental sy stem with little proven opera tional data and only one known medium utility-scale installati on. Therefore, the e-SCRUB process is not considered applicable for retrofit at SJGS.Technical Feasibility of Additional PNM San Juan Generating Station Control Technology Alternatives

060607 5-4 

## 5.2 Technically Infeasible Addi tional PM Control Technology Alternatives 5.2.1 Flue Gas Condi tioning with Hot-Side ESP Flue gas conditioning improves the operabi lity of the ESP but does not increase the level of emissions control to a higher level than the required emissions limit for SJGS
after the retrofit of the PJFF. Therefore, it was not evaluate d as applicable for SJGS.

5.2.2 Compact Hybrid Particulate Collector The COHPAC system currently availabl e in the industry does not provide a performance guarantee better than the expected performance of the new PJFFs that are currently being installed at SJGS for the cons ent decree. Because of this consideration,
the COHPAC was not evaluated as a tech nically feasible co ntrol technology.

5.2.3 Max-9 Electrostatic Fabric Filter The GE Max-9 Hybrid has been recently installed commercially in a smallersized utility boiler. However, there are no current commercial installations in similarsized units as SJGS. Therefore, the GE Max- 9 was not considered as technically feasible when evaluated as part of the BART procedures.



## 5.3 Technical Feasibility Summary After the completion of the screen ing process (Step 2 of the BART determination), the following technologies were identified as feasib le upgrades to the ongoing consent decree environmen tal upgrades at SJGS for NO x 

### reduction:

• SCR.

• SNCR/SCR hybrid.
There were no additional PM control te chnologies identified that would have
better emissions reduction than the PJFFs that are being retrofitted at SJGS for PM and Hg reduction. A summary result of the evaluation process is detailed in Tables 5-1 and 5-2.
Also included in the tables are the reasons for technical infeasibility of the eliminated control technologies.Technical Feasibility of AdditionalPNM San Juan Generating StationControl Technology Alternatives0606075-5Table 5-1Technically Feasible Additional NOxControl Technology AlternativesPollutant Philosophy TechnologyTechnicallyFeasible andApplicable? Reasons for Technical InfeasibilityNOxControl technologies: SNCR No Emissions control does not achieve requiredpresumptive limit.SCR Yes --SNCR/SCR Hybrid Yes --Gas Reburn No Boiler not suitable for natural gas reburn processdue to lack of residence time.Mobotec ROFA and ROTAMIX No ROTAMIXtechnology not demonstrated at SJGSscale boiler systems. ROFA will be considered asan OFA variant.ECOTUBE No Not applied to SJGS scale boiler systems.PowerSpan No In early commercial application stage. Not appliedto SJGS scale boiler systems.Phenix Clean Combustion No Still in demonstration and testing stage. Notapplied to SJGS scale boiler systems.e-SCRUB No Still in demonstration and testing stage. Notapplied to SJGS scale boiler systems.Technical Feasibility of AdditionalPNM San Juan Generating StationControl Technology Alternatives0606075-6Table 5-2Technically Feasible Additional PMControl Technology AlternativesPollutant Philosophy TechnologyTechnicallyFeasible andApplicable?Reasons for Technical InfeasibilityPM Control Technologies: Flue Gas Conditioning with HotSide ESPNo Level of emissions control does not exceedexpected level of control with new PJFF retrofit.Compact Hybrid ParticulateCollectorNo Level of emissions control does not exceedexpected level of control with new PJFF retrofit.Max-9 Electrostatic Fabric Filter No Not applied to SJGS scale boiler systems.Evaluation of Technically Feasible Additional Control PNM San Juan Generating Station Technology Alternatives

060607 6-1 

## 6.0 Evaluation of Technically Feasible Additional Control Technology Alternatives

This section discusses the control effec tiveness evaluation of technically feasible additional control technology al ternatives for controlling NO x 

### emissions beyond that achieved by technologies that will be inst alled for the consent decree.



## 6.1 Control Effectiveness The evaluation process in Step 3 determines the control effectiveness of the
additional NO x 

### control technologies. Control effectiveness is expressed in a common metric based on the amount of pollutant genera ted per unit of heat i nput (lb/MBtu). The
evaluation of the control effectiveness was tran slated into an hourly rate (lb/h) for each pollutant, according to the design basis he at input data for ea ch SJGS unit. The
evaluation of control effectiveness was ba sed on information indicated in Subsection
1.2.3.
Table 6-1 indicates the control e ffectiveness of each additional NO x 

### control technology. This control effectiveness was ca lculated from the consent decree values
discussed in Section 4.0.
The control effectiveness for each technol ogy is also summarized in the Design Concept Definition tables in Appendix B

.Evaluation of Technically Feasible AdditionalPNM San Juan Generating StationControl Technology Alternatives0606076-2Table 6-1NOxControl Effectiveness for Additional Control Technology Alternatives(Annual Average Emissions Rates)UnitSJGS 1 SJGS 2 SJGS 3 SJGS 4Design Basis HeatInput Data, MBtu/h3,707 3,688 5,758 5,649NOxEmissionsCaseslb/MBtulb/hton/yrlb/MBtulb/hton/yrlb/MBtulb/hton/yrlb/MBtulb/hton/yrConsent DecreeUpgrades(LNB/OFA/NN)0.30 1,112.1 4,140 0.30 1,106.4 4,119 0.30 1,727.4 6,431 0.30 1,694.7 6,309SCR0.07 259.5 966 0.07 258.2 961 0.07 403.1 1,501 0.07 395.4 1,472SNCR/SCR Hybrid0.18 667.3 2,484 0.18 663.8 2,471 0.18 1,036.4 3,859 0.18 1,016.8 3,786Notes:1.Emissions levels (lb/MBtu) shown are on an annual average basis.2.Emissions (lb/h) calculations were based on the emissions level (lb/MBtu) and design basis heat input.3.Emissions levels listed were based on performance guarantees provided by the equipment vendor.4.Yearly emissions (ton/yr) calculations were based on an annual unit capacity of 85 percent.Impact Analysis and Cost- Effectiveness of Additional Control PNM San Juan Generating Station Technology Alternatives

060607 7-1 

## 7.0 Impact Analysis and Cost-Effectiveness of Additional Control Technology Alternatives

This section discusses the impact analysis and cost-effectiveness for SCR and SNCR/SCR hybrid technologies.



## 7.1 Types of Impact Analyses

For all the additional NO x 

### control technologies that are being considered, an impact analysis was performed as part of th e BART determination process. The purpose of this exercise was to quantify the cost of applying the technology at the source, so that a comparison of the cost-effec tiveness of each technology coul d be made. The definition of cost-effectiveness is provided in Subsecti on 1.2.4 of this report. In summary, the four types of impact analyses perfor med consisted of the following:

• Costs of compliance.

• Energy impacts.

• Non-air quality environmental impacts.

• Remaining useful life.



## 7.2 Methods of Impact Analysis The first step in performing the impact analysis was to de fine the design parameters for each additional NO x 

### control technology that was identified as technically feasible. The design parameters contai n all pertinent information on the control technology system for specific application to the source. Examples of these design parameters include type of reagent used and consumption rate, type of byproduct produced and production rate, flue gas pressu re drop across the control technology, etc.
The information used to define the de sign parameter included the following:

• Information from equipment vendors.

• Background information documents used to support NSPS development.

• Control technique guidelines document.

• EPA cost manuals.

• Trade publications.

• Engineering and performance test data. Design parameters for each control technol ogy that was identified as technically feasible for application at the SJGS site ar e summarized in the Design Concept Definition tables ( Appendix B ).Impact Analysis and Cost- Effectiveness of Additional Control PNM San Juan Generating Station Technology Alternatives

060607 7-2 

### 7.2.1 Cost of Compliance Black & Veatch developed the cost of compliance based on the requirements for implementing each technically feasible cont rol technology. The TCI for each control technology when applied specifically to the SJGS site and the annual O&M costs were
calculated. The basis for this cost calculation was as follows:

• CUECost workbook, Version 1.0.

• EPA Air Pollution Control Cost Manual - Sixth Edition.

• Budgetary quotes from equipment vendors.

• References to quotes or cost estimati on for previous design/build projects or in-house engineering estimates.

7.2.2 Energy Impacts Energy impacts were estimated for each control technology that consumes auxiliary energy during its operation. Only direct energy impacts for each control technology, such as the auxiliary power cons umption of the control technology and the additional draft system power consumption to overcome the additional system resistance, were accounted for. Indirect energy impacts, such as the energy to produce raw materials used for the control technology system, were not considered. The auxiliary power consumption of the control technology was es timated on the basis of the typical power consumption of similar equipment of an equi valent size. The additional draft system power consumption was calculated on the basis of the volumetric flow rate of the flue gas through the control technology system and the flue gas pressure drop defined in the design parameter of the control technology.

7.2.3 Non-Air Quality Environmental Impacts The major non-air quality impacts evalua ted were the water consumption and disposal requirements for the byproduct and waste generated by each control technology. All quantities of water consumption and bypr oduct or waste generated by each control technology were calculated on a yearly basis.

7.2.4 Remaining Useful Life Finally, the impact of the remaining usef ul life of the control technology on its
cost-effectiveness was considered. For this BART analysis, the remaining useful life of the controls was defined as 20 years. Theref ore, there was no additional life impact cost for the additional control technologies.Impact Analysis and Cost- Effectiveness of Additional Control PNM San Juan Generating Station Technology Alternatives

060607 7-3 

## 7.3 Cost-Effectiveness

The cost-effectiveness of each control tec hnology was calculated from the cost of compliance and the amount of pollutant reduced . The cost-effectiveness is defined as the cost of control per amount of pollutant rem oved. The cost of control takes into account the impact analyses performed. The reduced emissions were estimated on a yearly basis according to the reduction from the consent decree emissions level shown in Table 6-1.
Both the consent decree emissions level and the additional control technology alternative
emissions level are documented in Table 6-1 and in the Design Concept Definition tables ( Appendix B ). Two types of cost-effectiveness were cal culated during the BART determination: average and incremental cost-effectiveness. The general definition of the average and
incremental cost-effectivene ss can be found in Subsection 1.3.4. The cost-effectiveness
values were based on 2007 dollars.



## 7.4 Impact Analysis and Cost-Effectiveness Results An impact analysis was performed for a ll the identified technically feasible control technologies. A summary of the calcu lated impact analysis is presented in Appendix C

. For all the additional NO x 

### control technologies eval uated, a summary table was developed for the impact anal ysis performed and the resu ltant cost-effectiveness. Table 7-1 presents the final evaluations for all four units. The expected after-control
emissions levels are also included in the table. The data in the summary table were used to produce a graphical plot of the TAC versus the expected emissions reduction (ton/yr). The plots are shown on Figures 7-1 to 7-4. From the graphical plot, a “least-cost envelope” for eac h group of control technologies was identified. C ontrol technologies that lie on this least-cost envelope are
“dominant controls” that should be the focu s for the BART determination. Dominant controls are the technologies that have the lo west cost for implementation per quantity of pollutant removed. Therefore, these technologies are considered more cost effective for emissions reduction, barring any additi onal factors or considerations. For all the dominant controls, the incremental cost-effectiveness between a technology and the next most stringent control technology was also calculated. This
incremental cost-effectiveness indicates the additional cost to increase the removal of pollutant when comparing technologies th at have different emissions removal capabilities.Impact Analysis and Cost-Effectiveness ofPNM San Juan Generating Station Additional Control Technology Alternatives0606077-4Table 7-1Impact Analysis and Cost-Effectiveness Results of Additional NOxControl TechnologiesTotal TotalEmission Expected Expected Expected Capital Annualized IncrementalPerformance Emission Emission Emission Investment Cost Cost Cost Energy Non-AirLevel Rate Rate Reduction (TCI) (TAC) Effectiveness Effectiveness Impacts ImpactsAll Feasible Technologies (lb/MBtu) (lb/h) (ton/yr) (ton/yr) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$)SJGS Unit 1Selective Catalytic Reduction (SCR) 0.07 259.5 966 3,174 156,805 20,525 6,466 2,844 1,496 --SNCR/SCR Hybrid 0.18 667.3 2,484 1,656 104,436 16,207 9,786 -- 706 1,762SJGS Unit 2Selective Catalytic Reduction (SCR) 0.07 258.2 961 3,158 169,251 21,891 6,932 3,457 1,492 --SNCR/SCR Hybrid 0.18 663.8 2,471 1,648 108,628 16,670 10,117 -- 346 1,762SJGS Unit 3Selective Catalytic Reduction (SCR) 0.07 403.1 1,501 4,931 215,568 28,359 5,752 1,167 2,194 --SNCR/SCR Hybrid 0.18 1,036.4 3,859 2,572 168,507 25,606 9,954 -- 507 2,658SJGS Unit 4Selective Catalytic Reduction (SCR) 0.07 395.4 1,472 4,837 199,558 26,592 5,497 753 2,215 --SNCR/SCR Hybrid 0.18 1,016.8 3,786 2,524 161,572 24,849 9,846 -- 507 2,658Notes:1. All costs are in 2007$.2. Expected emission rates (ton/yr) calculations were based on 85 percent unit capacity factor (referer to Appendix A Design Basis).3. Expected emission reduction (ton/yr) calculations were based on the consent decree upgrades control effectiveness as shown in Table 4-1.4. TCI and TAC are referenced from Appendix C Cost Analysis Summary.5. Cost-effectiveness ($/ton) is defined as ratio of TAC over Expected Emission Reduction (ton/yr).6. Expected emission reduction is based on annual emission reduction from consent decree upgrade emission levels (Table 4-1).7. Incremental cost effectiveness are based on increments in expected emission reduction (ton/yr)Impact Analysis and Cost-Effectiveness ofPNM San Juan Generating Station Additional Control Technology Alternatives0606077-516,00016,50017,00017,50018,00018,50019,00019,50020,00020,50021,0000 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)SNCR/SCR HybridSelective Catalytic Reduction (SCR)Dominant ControlsFigure 7-1SJGS Unit 1 Additional NOxControl Technology Cost-EffectivenessImpact Analysis and Cost-Effectiveness ofPNM San Juan Generating Station Additional Control Technology Alternatives0606077-616,50017,00017,50018,00018,50019,00019,50020,00020,50021,00021,50022,0000 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)SNCR/SCR HybridSelective Catalytic Reduction (SCR)Dominant ControlsFigure 7-2SJGS Unit 2 Additional NOxControl Technology Cost-EffectivenessImpact Analysis and Cost-Effectiveness ofPNM San Juan Generating Station Additional Control Technology Alternatives0606077-725,00025,50026,00026,50027,00027,50028,00028,50029,00029,50030,0000 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)SNCR/SCR HybridSelective Catalytic Reduction (SCR)Dominant ControlsFigure 7-3SJGS Unit 3 Additional NOxControl Technology Cost-EffectivenessImpact Analysis and Cost-Effectiveness ofPNM San Juan Generating Station Additional Control Technology Alternatives0606077-824,50024,75025,00025,25025,50025,75026,00026,25026,50026,75027,0000 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)SNCR/SCR HybridSelective Catalytic Reduction (SCR)Dominant ControlsFigure 7-4SJGS Unit 3 Additional NOxControl Technology Cost-EffectivenessImpact Analysis and Cost- Effectiveness of Additional Control PNM San Juan Generating Station Technology Alternatives

060607 7-9 

### 7.4.1 Dominant Control Technologies After completing the evaluation of the impacts and cost-effectiveness, it was
determined that all additional NO x 

### control technologies evaluated lie on the least-cost envelope and are dominant control technologies for the additional reduction of NO x 

### emissions than that currently expected af ter the completion of the consent decree upgrades. These dominant control technologies were modeled to determin e the visibility change or improvement. The modeled visibi lity change or improvement was used for determining the NO x 

### BART control technology.

7.4.2 Cost-Effectiveness Comparison The higher cost-effectiveness observed for all four units was the hybrid technology, ranging from 8,776 to 9,102 $/ton. The cost-effectiveness for the SCR technology ranged from 4,426 to 5,198 $/ton. The high cost-effectiveness fo r the hybrid technology (refe r to Table 7-1) can be attributed to the high TAC, which was just slightly lower than that of the SCR technology. Another factor th at affects the cost-effectiv eness value for the hybrid technology is the lower expected emissions reduction (ton/yr) when compared to that for
SCR. Unit 2 costs are higher than Unit 1, and Unit 3 costs are higher than Unit 4. This difference is due to the additional cost require d for the installation of these technologies on Units 2 and 3. Accessibility to Units 2 and 3 is limited by the plant layout and the presence of other balance-of-plant equipment, such as the coal conveyor. The reduced accessibility means that the SCR system or hybrid system will need to be built in smaller pieces, thus increasing construction costs as compared to their sister units.PNM San Juan Generating St ation Visibility Impacts

060607 8-1 

## 8.0 Visibility Impacts

Visibility impact is the fifth step to c onsider in the engineering analysis required under the EPA BART guidelines. This step addresses the degree of improvement in visibility that may reasonably be anticipated to result from the use of the ‘‘best control technology’’ for sources subject to BART. Visibility impact analysis is achieved through a two phase process. First, the model was run using the pre-BART conditions to
establish a baseline. For this analysis, the baseline consiste d of the technologies and unit operations associated with the consent degr ee. Second model runs were conducted for the control technologies identified for each uni t during the BART engineering analysis.
The model results were then tabulated for the pre-BART and post-BART control scenarios over the time period of the me teorology modeled. The difference in the averages between the first and second phases is the expected degree of improvement in visibility. The following s ections discuss the modeling methodology in greater detail.



## 8.1 Introduction The objective of this mode ling analysis is to evaluate visibility impacts for the control technologies selected using the first f our steps of the BART analysis (as discussed in the previous sections) for PNM’s SJGS Un its 1, 2, 3, and 4. Based on air dispersion modeling analyses conducted by the WRAP RMC and published as a draft report November 8, 2006, these units were identif ied as BART-applicable sources by the NMED in January of 2007 under the Regi onal Haze and BART rule guidelines. The air dispersion modeling analyses presen ted in this report were conducted in
accordance with the CALMET/CALPUFF Protocol fo r BART Exemption Screening Analysis for Class I Areas in the Western United States dated August 15, 2006, (hereinafter referred to as the WRAP Protoc ol) and the protocol submitted to NMED on April 13, 2007. The protocol can be found in Appendix E , Sections 1 and 2. It should be noted that corresponde nce between NMED and the WRAP on April 2, 2007, indicated an e rror(s) in the original BART modeling conducted by WRAP in 2006. The error(s) was corre cted, and WRAP has since rerun the previous BART modeling; however, at the tim e of this report, the exte nt of the error(s), their corresponding correction(s), a nd the results are not known. Therefore, it is not known how these errors have affected the previous ly described WRAP modeling or the modeling conducted for this report.PNM San Juan Generating St ation Visibility Impacts

060607 8-2 

## 8.2 Source Description The SJGS facility is located in Fa rmington, New Mexico, within San Juan County. It has four pulverized coal units th at are BART-eligible: Units 1, 2, 3, and 4. Units 1 and 2 are single, wall-fired Foster Wheeler boilers rated at 360 and 350 MW gross, respectively. Each unit is equipped with primary and secondary preheaters, an ESP, and a wet FGD system. Units 3 and 4 are opposed, wall-fired B&W boilers, each rated at 544 MW gross. Each of these uni ts is equipped with primary and secondary preheaters, an ESP, and a wet FGD system. Units 1, 3, and 4 are also equipped with LNBs. The plant currently burns local coal from the San Juan Mine. A detailed description of the units is included in Section 2.0.



## 8.3 Location of Sources Versus Relevant Class I Areas Modeling conducted by the WRAP RMC has determined that the 16 Class I areas
within 300 km of SJGS listed in Table 8-1 must be addres sed in Step 5 of the BART analysis. The location of these 16 Class I areas are shown in Table 8-1 and are illustrated on Figure 8-1.

Table 8-1 Class I Areas

1. Mesa Verde National Park
2. Weminuche Wilderness 3. San Pedro Parks Wilderness
4. La Garita Wilderness 5. Canyonlands National Park
6. Black Canyon of the Gunnison National Park
7. Bandelier National Monument 8. Petrified Forest National Park 9. West Elk Wilderness 10. Arches National Park
11. Capitol Reef National Park
12. Pecos Wilderness 13. Wheeler Peak Wilderness
14. Great Sand Dunes National Park 15. Maroon Bells-Snowmass Wilderness 16. Grand Canyon National ParkPNM San Juan Generating St ation Visibility Impacts

060607 8-3 -1500 -1400 -1300 -1200 -1100 -1000 -900 -800 -700 -600 X LCC (km) -700 -600 -500 -400 -300 -200 -100 0Y LCC (km)

Petrified Forest Grand Canyon Capitol

Reef Canyonlands Arches
Black Canyon of the Gunnison West Elk Maroon Bells Snowmass

Mesa Verde Weminuche La Garita

Great Sand Dunes

San Pedro

Parks

Bandelier Pecos Wheeler

Peak PNM SJGS



### Figure 8-1 Location of SJGS and the Class I Areas


## 8.4 Model Processing The CALPUFF modeling system is the recommended model for conducting BART visibility impact analyses. The CA LPUFF modeling system includes three main components: CALMET, CALPUFF, CALPOST. The system also includes a large set of preprocessing programs designed to interf ace with the model to process standard, routinely available meteorological and geophysi cal data sets. In the simplest terms, CALMET is a meteorological model that deve lops hourly wind and temperature fields on a three- dimensional gridded m odeling domain. Associated fi elds, such as mixing height, surface characteristics, and dispersion propertie s, are also included in the file produced by CALMET. CALPUFF is a transport and di spersion model that advects “puffs” or material emitted from modeled sources, simulating the dispersion and chemical transformation process along the way. In doing so, it typically uses the fields generated by CALMET, or as an option, it might use simp ler, not gridded meteorological data muchPNM San Juan Generating St ation Visibility Impacts

060607 8-4 

### like existing plume models. Temporal and spa tial variations in the meteorological fields selected are explicitly incorporated into the resulting distribution of puffs throughout a simulation period. The primary output file s from CALPUFF contain either hourly concentrations or hourly depos ition fluxes evaluated at sele cted receptor locations. CALPOST is used to process these files and produce tabulations that summarize the results of the simulation. When performing visibility-related modeling, CALPOST uses concentrations from CALPUFF to compute ex tinction coefficients and related measures of visibility, reporting these for a 24 hour averaging period at selected locations. The geophysical and meteorological da ta necessary to conduct the Class I visibility modeling was provided by the WRAP RMC on its Web site ( http://pah.cert.ucr. edu/aqm/308/bart.shtml ). All applicable files were downloaded for use in the aforementioned analyses. The versions of the CALPUFF modeling sy stem suggested in the WRAP protocol and used by the WRAP RMC for the initia l modeling were used for the PNM modeling analyses and are summarized in Table 8-2. It should be noted that the WRAP RMC provided limited information on its BART mo deling. Based on what was provided, it did not appear that the WRAP RMC speciated the PM/PM 10 

### emissions; therefore, the use of
POSTUTIL and CALSUM w ould not be required.

Table 8-2 Model Versions

WRAP Protocol PNM Analyses Program Version Level Version Level
CALMET 6.211 060414 6.211 060414
CALPUFF 6.112 060412 6.112 060412
POSTUTIL N/A N/A 1.52 060412
CALSUM N/A N/A 1.33 051122
CALPOST 6.131 060410 6.131 060410

8.4.1 Modeling Domain The modeling domain was the same do main established in the provided GEO.DAT file. The origin coordinates of the domain was Latit ude 40.0 N, Longitude 97.0 W; these coordinates were assigned as th e 0, 0 reference point of the domain. The southwest corner of the modeling domain was Latitude 30.9 N, Longitude 111.3 W, which translates to -1,368.0 km (X) and -900.0 (Y) in Lambert Conformal Conic (LCC)
coordinates. The domain m easured 864 km in the east-we st (X) and north-south (Y)PNM San Juan Generating St ation Visibility Impacts

060607 8-5 

### direction. At a refined grid spacing of 4 km, the number of X grid cells and the number of the Y grid cells was 216. The modeling domain is shown on Figure 8-2.

-1300 -1200 -1100 -1000 -900 -800 -700 -600 X LCC (km) -800 -700 -600 -500 -400 -300 -200 -100Y LCC (km)

Petrified Forest Grand Canyon Capitol

Reef Canyonlands Arches Black Canyon of the Gunnison West Elk

Maroon Bells Snowmass

Mesa Verde Weminuche La Garita

Great Sand Dunes

San Pedro Parks

Bandelier Pecos Wheeler

Peak PNM SJGS



### Figure 8-2 Geophysical and Meteorol ogical Modeling Domain


## 8.5 Geophysical and Meteorological Data As previously noted, all the geophysical and meteorological data necessary to
conduct the Class I visibil ity modeling were provided by the WRAP RMC and were downloaded from its Web site for use in the aforementioned analyses.PNM San Juan Generating St ation Visibility Impacts

060607 8-6 

### 8.5.1 Mesoscale Model Data Pennsylvania State University in conj unction with the National Center for Atmospheric Research Assessment Laboratory have developed meso scale eteorological data sets of prognostic wind fi elds, or “guess” fields, for the United States. The hourly meteorological variables used to create these data sets are extensive and are used to initialize the modeling domain with meteorol ogical data. The daily MM5 meteorological data files provided by the WRAP RMC for the years 2001, 2002, and 2 003 were utilized as input into CALMET. The MM5 data sets used to simulate atmospheric variables within the modeling domain in CALMET, although advanced, lack th e fine detail of specific temporal and spatial meteorological variables and geophysical data. These variables were processed into the appropriate format and intr oduced into the CALMET model through the utilization of additional meteorological data files. These ancillary data files are described in more detail in the following subsections.

8.5.2 Surface Data St ation and Processing
The surface station data for the CALP UFF analysis consis ted of data from National Weather Service (NWS) stations or Federal Aviation Administration (FAA) flight service stations within the CALMET do main. Figure 8-3 provide s an illustration of
the location of the surface sta tions used. The surface station parameters included wind speed, wind direction, cloud ceiling height, opaque cloud cover, dry bulb temperature, relative humidity, station pressure, and a pr ecipitation code that was based on current
weather conditions. The surface data were preprocesse d by the WRAP RMC to create CALMETready SURF.DAT files. The CALMET-ready surface station data files were downloaded
from the WRAP RMC Web site for use in the modeling analyses. A listing of the surface stations is provided in Appendix E , Section 2.

8.5.3 Upper Air Data Station and Processing The WRAP RMC used the upper air data contained in the MM5 files for the necessary upper air data an d did not supplement it with additional upper air data. Because of this, the modeling conducted for th is report followed these procedures and did not include any additional uppe r air data other than that contained in the MM5 files.

8.5.4 Precipitation Data Stations and Processing Precipitation data was processed from a network of hourly precipitation data files collected from NWS precipita tion recording stations wi thin the CALMET domain. Figure 8-4 provides an illustration of the lo cation of the precipita tion stations used.PNM San Juan Generating St ation Visibility Impacts

060607 8-7 -1500 -1400 -1300 -1200 -1100 -1000 -900 -800 -700 -600 -500 -400 X LCC (km) -1000

-900 -800 -700 -600 -500 -400 -300 -200 -100 0 100Y LCC (km) PNM SJGS

2001 Surface Stations

2002 Surface Stations

2003 Surface Stations



### Figure 8-3 Surface StationsPNM San Juan Generating St ation Visibility Impacts

060607 8-8 -1500 -1400 -1300 -1200 -1100 -1000 -900 -800 -700 -600 -500 -400 X LCC (km) -1000

-900 -800 -700 -600 -500 -400 -300 -200 -100 0 100Y LCC (km) PNM SJGS

2001 Precipitation Stations
2002 Precipitation Stations

2003 Precipitation Stations



### Figure 8-4 Precipitation Stations

The precipitation data were preprocessed by WRAP to create CALMET-ready PRECIP.DAT files. The CALMET-ready precip itation data files were downloaded from
the WRAP RMC Web site for use in the mode ling analyses. A list of the precipitation stations is provided in Appendix E , Section 2.PNM San Juan Generating St ation Visibility Impacts

060607 8-9 

### 8.5.5 Geophysical Data Processing (Terrain and Land Use) Terrain and land use data were preprocessed by the WRAP RMC to create a CALMET-ready GEO.DAT file. This GEO.DA T file was downloaded from the WRAP RMC Web site for use in the analyses. Figur e 8-5 depicts the terrai n elevations in the domain; Figure 8-6 shows the land use of the domain.

-1300 -1200 -1100 -1000 -900 -800 -700 -600 X LCC (km) -800 -700 -600 -500 -400 -300 -200 -100Y LCC (km)

200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000

PNM SJGS



### Figure 8-5 Terrain Elevation PlotPNM San Juan Generating St ation Visibility Impacts

060607 8-10 -1300 -1200 -1100 -1000 -900 -800 -700 -600 X LCC (km) -800 -700 -600 -500 -400 -300 -200 -100Y LCC (km)

10 to 17 Urban 20 to 24 Agricultural 30 to 33 Rangeland 40 to 43 Forest Land 50 to 55 Water 60 to 62 Wetland 71 to 77 Barren Land Land Use Categories:

PNM SJGS



### Figure 8-6 Land Use Plot

8.5.6 CALMET CALMET (Version 6.211, Level 060414) was run using the aforementioned preprocessed CALMET-ready geog raphical and meteorological files provided by WRAP
RMC to create the CALMET.DAT for use in CALPUFF.



## 8.6 CALPUFF The CALPUFF modeling system is re commended as the preferred modeling approach for use in BART analyses. CALPUFF and its meteorological model, CALMET, are designed to handle the comple xities posed by complex terrain, large source-receptor distances, chem ical transformation and deposi tion, as well as other issues related to Class I visibility impacts. Th e CALPUFF modeling system has been adopted by the EPA as a guideline model for source-rece ptor distances greater than 50 km and for use on a case-by-case basis in complex fl ow situations for shorter distancesPNM San Juan Generating St ation Visibility Impacts

060607 8-11 

### (68 FR 18440-18482). CALPUFF is recommended for Class I impact assessments by the Federal Land Managers Workgroup (FLAG 200 0) and the Interagency Workgroup on Air Quality Modeling (IWAQM) (EPA 1998). Th e final BART guidance recommends
CALPUFF as “the best mode ling application available fo r predicting a singe source’s contribution to visibility impairment” (70 FR 39122). CALPUFF is a non-steady-state, Lagrangi an, puff transport and dispersion model that advects Gaussian puffs of multiple pollutants from modeled sources. CALPUFF’s algorithms have been designed to be appli cable on spatial scales from a few tens of
meters to hundreds of kilometers from a sour ce. It includes algo rithms for near-field effects such as building downwash, stack tip downwash, and transitional plume rise, as well as processes important in the far-field, such as chemical transformation, wet deposition, and dry deposition. CALPUFF contai ns an option to allow puff splitting in
the horizontal and vertical dir ections, which extends the distan ce range of the model. The primary outputs from CALPUFF are hourly co ncentrations and hourly deposition fluxes evaluated at user-specified receptor locations. CALPUFF (Version 6.112, Level 060412) wa s used to calculate the hourly concentrations at each Class I receptor from SJGS Units 1, 2, 3, and 4. Each CALPUFF run contained 12 monthly CALMET.DAT files to cr eate a single yearly concentration file
for use in CALPOST.

8.6.1 CALPUFF Domain and Variables The WRAP RMC computational domain c overed an extensive area, specifically, New Mexico, eastern Arizona, southeastern Ut ah, and southern Colorado. To reduce the computational requirements of the mode l, the CALPUFF computational domain was
reduced to a subset of the WRAP RMC CA LMET domain established to encompass the SJGS and the applicable 16 Class I areas . The CALPUFF computational domain is shown on Figure 8-7.

8.6.2 Receptors The CALPUFF analyses used an array of discrete receptor s with receptor elevations for the Class I areas, which were created and distribute d by the National Park Service (NPS). Specifically, the array consisted of receptors spaced to cover the extent of the Class I areas. Receptor elev ations were included in th e same NPS-provided receptor
files. Appendix E , Section 2, provides illustrations of the receptors that were used in the modeling analysis for each Class I area.PNM San Juan Generating St ation Visibility Impacts

060607 8-12 -1300 -1200 -1100 -1000 -900 -800 -700 -600 X LCC (km) -800 -700 -600 -500 -400 -300 -200 -100Y LCC (km)

Petrified Forest Grand Canyon Capitol Reef Canyonlands Arches Black Canyon of the Gunnison West Elk

Maroon Bells Snowmass

Mesa Verde Weminuche La Garita

Great Sand Dunes

San Pedro

Parks

Bandelier Pecos Wheeler

Peak PNM SJGS

CALPUFF Computational Domain

CALMET Computational Domain



### Figure 8-7 CALPUFF Computational Domain

8.6.3 Downwash Because the modeling conducted for BART is concerned with long-range transport, not localized impacts, data about building heights and widths that are used to calculate building-induced downwash were not included in the modeli ng analyses. Stack tip downwash, a phenomenon different from bu ilding-induced downwash, is additionally a regulatory default option (i.e., to turn stack tip downwash off, the user must also change the variable to skip regulatory checks of the model). Because of th is, stack tip downwash was used for the analyses.PNM San Juan Generating St ation Visibility Impacts

060607 8-13 

### 8.6.4 Ozone Concentrations Background ozone concentrations are impor tant for the photochemical conversion
of SO 2 

### and NO x 

### to SO 4 

### and NO 3 

### , respectively. CALPUFF allows the use of a single background ozone value, monthly background ozone values, or spatial, hourly ozone data from one or more ozone monitoring stations (the preferred met hod) to represent the background ozone concentrations within the domain. The hourly ozone concentrations files th at were used by the WRAP RMC in the initial modeling were used for the BART technology evaluation. These hourly ozone data files were obtained directly from th e WRAP RMC Web site. In addition to the hourly ozone data, the same monthly averag e background ozone value of 80 ppb as used in the initial modeling was used in this modeling for times when hourly ozone data were
not available.

8.6.5 Ammonia Concentrations The BART modeling was performed usi ng the same fixed background ammonia level of 1 ppb that was used for the in itial modeling performed by WRAP RMC.

8.6.6 Unit-Specific Source Data As previously presented in Sections 3 th rough 6 of this repor t, various emissions control strategies and technologies have been evaluated for SJGS Units 1, 2, 3, and 4. The baseline emissions for PM, NO x 

### , and SO 2 

### were based on emissions limits established as part of the consent decree between PNM and NMED. Additionally, emissions of SO 4 

### were included in the analyses. The emissions were composed of the relative fraction of fine and course particles obtai ned by using speciation profile s available from the Federal Land Managers through the NPS ( http://www2.nature.nps.gov/air/ permits/ect/index.cfm). For this analysis, condensable PM 10 

### was subdivided into inorganic and organic compounds using the NPS speciation spreadshee ts. The inorganic portion was by default
assumed to be H 2 

### SO 4 

### and was modeled as SO 4 

### . The organic portion was modeled as secondary organic aerosols (SOA). As required by EPA BART guidance, each technically feasible BART control technology must be assessed to determine the potential degree of visibility improvement. These relative improvements from various technol ogies and/or control levels can then be factored into the technology evaluation pro cess to reach a BART determination. Because New Mexico participates in an SO 2 

### trading program, an SO 2 

### BART analysis was not evaluated in Steps 1 t hough 4, and was not modeled as a separate
feasible control technol ogy option. However, SO 2 

### emissions were included as a modeled pollutant as part of both the baseline and post-baseline controlled scenarios. Therefore,
NO x 

### and PM 10 

### are the only pollutants subject to BART analyses. However, as previouslyPNM San Juan Generating St ation Visibility Impacts

060607 8-14 

### determined in Subsection 4.2.4, the addition of the PJFF technology for PM control is considered BART technology and no fu rther evaluation was undertaken. PM 10 

### emissions were assumed the as consent decree (baseline) limits and speciated as described in the baseline modeling section. NO x 

### was the only pollutant evalua ted in this analysis. As specified in Section 7.0, additional NO x 

### control was proposed for the BART control scenario. The aforementioned appro ach consisted of the potential addition of SCR or SNCR/SCR hybrid on all four units for additional NO x 

### control. For NO x 

### technologies with a catalyst, an additional 1 percent SO 2 

### to SO 3 

### conversion based on design basis economizer outlet SO 2 

### and zero removal in the PJFF was accounted for and added to the NPS speciation spreadsheet SO 4 

### values. The baseline and BART control scenarios stack parameters are presented in Table 8-3. The baseline and BART control scenario emissions are presented in Tables 8-4 and 8-5, respectively.



## 8.7 CALPOST CALPOST (Version 6.131, Level 060410) wa s used to process the CALPUFF outputs by producing tabulations summarizi ng the results of the simulations and identifying, for example, the highest and sec ond-highest hourly averag e concentrations at each receptor. When performing visibility-related modeling, CALPOST uses concentrations from CALPUFF to compute light extinction and related measures of visibility (haze index in d eciviews) and reports these for a 24 hour averaging time.

8.7.1 Light Extinction Light extinction must be computed to cal culate visibility. CALPOST has seven methods for computing light extinction. As recommended by the WRAP RMC protocol, this BART technology analysis used Me thod 6, which computes extinction from speciated PM with monthly Class I area-speci fic relative humidity adjustment factors. Relative humidity is an important factor in determining light extinction (and therefore visibility) because sulfate and nitrate aerosols, which absorb moisture from the air, have greater extinction efficiencies with greater relative humidit y. This BART analysis used relative humidity correction factors [f(RH)s ], obtained from Tabl e A-3 of the EPA’s Guidance for Estimating Natura l Visibility Conditions unde r the Regional Haze Rule (EPA, 2003), to determine sulfate and nitrat e concentrations out puts from CALPUFF. The f(RH) values for the Class I areas that were assessed are provide d in Table 8-6. The default Rayleigh scatter value (bray) of 10 Mm-1 was also used. The light extinction equation is as follows:

b ext 

### = 3 * f(RH) * [(NH 4 

### ) 2 

### SO 4 

### ] + 3* f(RH) * [NH 4 

### NO 3 

### ] + 4*[OC] + 1* [PM f 

### ] + 0.6*[PM c 

### ] + 10* [EC] + b rayPNM San Juan Generating St ation Visibility Impacts

060607 8-15 

### Table 8-3 CALPUFF Modeling Stack Parameters

Baseline

Stack Location (a)

Unit LCC East (km) LCC North (km) Stack Height (b) (m) Base Elevation (b) (m) Stack Diameter (b) (m) Stack Exit Velocity (b) (m/s) Stack Exit Temperature (b) (K)

SJGS 1 -1010.859 -290.127 121.92 1615.44 6.0960 21.34 322.83

SJGS 2 -1010.859 -290.127 121.92 1615.44 6.0960 21.34 322.83

SJGS 3 -1010.859 -290.127 121.92 1615.44 8.5344 17.07 322.83

SJGS 4 -1010.859 -290.127 121.92 1615.44 8.5344 16.76 322.83

BART Controls

SJGS 1 -1010.859 -290.127 121.92 1615.44 6.0960 21.34 322.83

SJGS 2 -1010.859 -290.127 121.92 1615.44 6.0960 21.34 322.83

SJGS 3 -1010.859 -290.127 121.92 1615.44 8.5344 17.07 322.83

SJGS 4 -1010.859 -290.127 121.92 1615.44 8.5344 16.76 322.83

(a) Stack Coordinates in Lambert format included in the CALPUFF modeling. (b) Stack parameters from engineering analysis. Refer to Appendix D.PNM San Juan Generating St ation Visibility Impacts

060607 8-16 

### Table 8-4 Consent Decree Baseline CALPUFF Modeling Emission Rates

Primary Particle Speciation (b)

Unit SO 2 Emission Rate (lb/h) NO x (a) Emission Rate (lb/h) EC (lb/h) Fine PM (lb/h) Course PM (lb/h) H 2 SO 4 (c) (lb/h) SOA (lb/h)
SJGS 1 667.3 1,223.3 1.03 31.11 23.57 40.50 10.10
SJGS 2 663.8 1,217.0 1.03 30.79 23.49 40.30 10.10
SJGS 3 1,900.1 1,036.4 1.59 48.18 36.37 62.90 15.70
SJGS 4 1,016.8 1,864.2 1.58 47.38 35.95 61.7 15.4

(a) The modeled NO x emission rate is based on an assumed 24 hour rolling averaging basis versus the 30 day rolling average basis fo r each unit from the consent decree. (b) Primary particulate speciated into the fo llowing categories using the NPS Speciation Spreadsheet: Elemental Carbon (EC), Fine PM, Course PM, and SO 4 . Refer to Appendix E, Section 4. (c) H 2 SO 4 assumed to be 100 percent of the SO 4 emissions calculated by the NPS Speciation Spreadsheet.PNM San Juan Generating St ation Visibility Impacts

060607 8-17 

### Table 8-5 NO x 

### BART Control Technologies CALPUFF Modeling Emission Rates

Primary Particle Speciation (a,c)

Unit SO 2 Emission Rate (lb/h) NO x Emission Rate (lb/h) EC (lb/h) Fine PM (lb/h) Course PM (lb/h) H 2 SO 4 (b) (lb/h) SOA (lb/h)

SCR

SJGS 1 667.3 222.4 1.03 31.11 23.57 114.2 10.10

SJGS 2 663.8 221.3 1.03 30.79 23.49 113.6 10.10
SJGS 3 1,036.4 345.5 1.59 48.18 36.37 177.3 15.70
SJGS 4 1,016.8 338.9 1.58 47.38 35.95 174.0 15.4 SNCR/SCR Hybrid

SJGS 1 667.3 667.3 1.03 31.11 23.57 114.2 10.10

SJGS 2 663.8 663.8 1.03 30.79 23.49 113.6 10.10
SJGS 3 1,036.4 1,036.4 1.59 48.18 36.37 177.3 15.70
SJGS 4 1,016.8 1,016.8 1.58 47.38 35.95 174.0 15.4

(a) Primary particulate speciated into the fo llowing categories using the NPS Speciation Spreadsheet: Elemental Carbon (EC), Fine PM, Course PM, and SO 4 . Refer to Appendix E, Section 4. (b) H 2 SO 4 assumed to be 100 percent of the SO 4 emissions calculated by the NPS Speciation Spreadsheet and for the NO x control technologies with catalyst accounts for an additional 1.0 percent SO 2 to SO 3 conversion based on design basis economizer outlet SO 2 levels and 0 percent removal in the PJFF. (c) Ammonia slip from the pollution control pro cess has not been included in the modeling analysis.PNM San Juan Generating St ation Visibility Impacts

060607 8-18 

### Table 8-6 Monthly Relative Humidity Factors (a)

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Arches 2.6 2.3 1.8 1.6 1.6 1.3 1.4 1.5 1.6 1.6 2.0 2.3

Bandelier 2.2 2.1 1.8 1.6 1.6 1.4 1.7 2.1 1.9 1.7 2.0 2.3 Black Canyon of the Gunnison 2.4 2.2 1.9 1.9 1.9 1.6 1.7 1.9 2.0 1.8 2.1 2.3

Canyonlands 2.6 2.3 1.7 1.6 1.5 1.2 1.3 1.5 1.6 1.6 2.0 2.3 Capitol Reef 2.7 2.4 2.0 1.7 1.6 1.4 1.4 1.6 1.6 1.7 2.1 2.5 Grand Canyon 2.4 2.3 1.9 1.5 1.4 1.2 1.4 1.7 1.6 1.6 1.9 2.3

Great Sand Dunes 2.4 2.3 2.0 1.9 1.9 1.8 1.9 2.3 2.2 1.9 2.4 2.4

La Garita 2.3 2.2 1.9 1.8 1.8 1.6 1.7 2.1 2.0 1.8 2.2 2.3

Maroon Bells Snowmass 2.2 2.1 2.0 2.0 2.1 1.7 1.9 2.2 2.1 1.8 2.1 2.1

Mesa Verde 2.5 2.3 1.9 1.5 1.5 1.3 1.6 2.0 1.9 1.7 2.1 2.3

Pecos 2.3 2.1 1.8 1.7 1.7 1.5 1.8 2.1 2.0 1.7 2.0 2.2

Petrified Forest 2.4 2.2 1.7 1.4 1.3 1.2 1.5 1.8 1.7 1.6 1.9 2.3

San Pedro Parks 2.3 2.1 1.8 1.6 1.6 1.4 1.7 2.0 1.9 1.7 2.1 2.2

West Elk 2.3 2.2 1.9 1.9 1.9 1.7 1.8 2.1 2.0 1.8 2.1 2.2

Weminuche 2.4 2.2 1.9 1.7 1.7 1.5 1.6 2.0 1.9 1.7 2.1 2.3

Wheeler Peak 2.3 2.2 1.9 1.8 1.8 1.6 1.8 2.2 2.1 1.8 2.2 2.3

(a) Table A-3 of the EPA’s Guidance for Estimating Natural Visibility Conditions under the Regional Haze RulePNM San Juan Generating St ation Visibility Impacts

060607 8-19 

### 8.7.2 Natural Background The EPA’s default average annual aerosol concentrations for the eastern and
western halves of the United States , included in Table 2-1 of EPA’s Guidance for Estimating Natural Visibility Condi tions Under Regional Haze Program , was used to determine the natural background at each of the Class I areas. The values are provided in
Table 8-7.

Table 8-7 Average Annual Natural Background Levels (a)



### Component Average Annual Natural Background ( μ g/m 3 

### )

Ammonium Sulfate 0.12
Ammonium Nitrate 0.10 Organic Carbon Mass 0.47
Elemental Carbon 0.02
Soil 0.50

Coarse Mass 3.0

(a) 

### Table 2-1 of the EPA’s Guidance for Estimating Natural Visibility Conditions under the Regional Haze Rule

. 

## 8.8 Modeling Results From the air dispersion modeling methodol ogy outlined in the previous sections, the CALPUFF-modeled visibility impacts from Units 1, 2, 3, and 4 for each NO x 

### control technology option were determined. Visibility impairment is based on the 98th percentile modeled value. Over an annual period, this implies the 8th highest 24 hour value. A DVD of all electronic files is provided in Appendix E , Section 5.

8.8.1 Consent Decree Baseline Scenario
The results of the consent decree baseline modeling are presented in Table 8-8. The consent decree baseline impacts were used to establish a comparison for the BART control technology impacts. As Table 8-8 illustrates, the combined visibility impacts for the SJGS BART sources (assuming control technology and emissions levels from the consent decree) exceed the recommended exem ption guideline value of 0.5 dv, subjecting
the units to the aforementioned BART e ngineering and refine d modeling analysis.PNM San Juan Generating St ation Visibility Impacts

060607 8-20 

### Table 8-8 Baseline (Consent Decree) Visibility Modeling Results 98th Percentile for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 3.828 2.934 2.808 3.190 3.828

Bandelier 1.345 2.326 2.312 1.994 2.326 Black Canyon 1.529 1.585 1.815 1.643 1.815 Canyonlands 4.944 3.362 3.125 3.810 4.944 Capitol Reef 2.922 0.929 1.394 1.748 2.922 Grand Canyon 1.505 1.001 0.730 1.079 1.505

Great Sand Dunes 0.920 0.798 0.710 0.809 0.920

La Garita 1.090 1.145 1.163 1.133 1.163

Maroon Bells 0.703 0.668 0.654 0.675 0.703

Mesa Verde 7.355 7.853 6.759 7.322 7.853

Pecos 1.232 1.570 1.693 1.498 1.693

Petrified Forest 1.045 0.676 0.644 0.788 1.045

San Pedro 2.711 3.356 3.021 3.029 3.356

West Elk 1.116 1.170 1.144 1.143 1.170

Weminuche 1.635 2.147 1.806 1.863 2.147

Wheeler Peak 1.042 1.062 1.164 1.089 1.164
Overall 2.051 7.853



### 8.8.2 BART Control Technology Scenario The results of the modeling for the BART emissions control option are presented in Tables 8-9 through 8-20. Tables 8-9 and 8-10 show the visibility im pacts of the entire plant, assuming that the same control techno logy (SCR or hybrid) is installed on each of
the four units. Tables 8-12 th rough 8-18 illustrate the resultan t visibility impacts of each control technology on a unit-by-unit basis.PNM San Juan Generating St ation Visibility Impacts

060607 8-21 

### Table 8-9 SCR Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 2.279 1.600 1.665 1.848 2.279

Bandelier 1.006 1.403 1.401 1.270 1.403 Black Canyon 0.949 0.848 1.061 0.953 1.061 Canyonlands 2.876 1.922 2.339 2.379 2.876 Capitol Reef 1.734 0.744 1.094 1.191 1.734 Grand Canyon 0.806 0.625 0.625 0.685 0.806

Great Sand Dunes 0.596 0.549 0.489 0.545 0.596

La Garita 0.626 0.678 0.717 0.674 0.717

Maroon Bells 0.440 0.428 0.367 0.412 0.440

Mesa Verde 6.404 6.011 6.565 6.327 6.565

Pecos 0.895 1.019 1.068 0.994 1.068

Petrified Forest 0.738 0.523 0.573 0.611 0.738

San Pedro 1.875 2.139 1.994 2.003 2.139

West Elk 0.654 0.661 0.679 0.665 0.679

Weminuche 1.249 1.733 1.556 1.513 1.733

Wheeler Peak 0.776 0.658 0.708 0.714 0.776
Overall 1.424 6.565PNM San Juan Generating St ation Visibility Impacts

060607 8-22 

### Table 8-10 Hybrid Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 3.201 2.382 2.327 2.637 3.201

Bandelier 1.222 1.939 1.911 1.691 1.939 Black Canyon 1.292 1.276 1.411 1.326 1.411 Canyonlands 4.025 2.759 2.875 3.220 4.025 Capitol Reef 2.288 0.783 1.324 1.465 2.288 Grand Canyon 1.153 0.841 0.700 0.898 1.153

Great Sand Dunes 0.776 0.770 0.614 0.720 0.776

La Garita 0.863 1.010 0.997 0.957 1.010

Maroon Bells 0.614 0.615 0.535 0.588 0.615

Mesa Verde 6.974 7.721 7.491 7.395 7.721

Pecos 1.190 1.466 1.409 1.355 1.466

Petrified Forest 0.898 0.627 0.607 0.711 0.898

San Pedro 2.240 3.008 2.573 2.607 3.008

West Elk 0.848 1.010 0.935 0.931 1.010

Weminuche 1.388 2.197 1.843 1.809 2.197

Wheeler Peak 0.899 0.833 0.942 0.891 0.942
Overall 1.825 7.721PNM San Juan Generating St ation Visibility Impacts

060607 8-23 

### Table 8-11 Unit 1 SCR Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 0.486 0.378 0.410 0.425 0.486

Bandelier 0.211 0.325 0.273 0.270 0.325 Black Canyon 0.194 0.195 0.203 0.197 0.203 Canyonlands 0.673 0.468 0.511 0.551 0.673 Capitol Reef 0.401 0.155 0.248 0.268 0.401 Grand Canyon 0.176 0.134 0.129 0.146 0.176

Great Sand Dunes 0.117 0.103 0.098 0.106 0.117

La Garita 0.135 0.139 0.144 0.139 0.144

Maroon Bells 0.092 0.084 0.075 0.084 0.092

Mesa Verde 1.442 1.748 1.720 1.637 1.748

Pecos 0.179 0.224 0.220 0.208 0.224

Petrified Forest 0.145 0.110 0.116 0.124 0.145

San Pedro 0.381 0.506 0.438 0.442 0.506

West Elk 0.135 0.139 0.135 0.136 0.139

Weminuche 0.261 0.407 0.325 0.331 0.407

Wheeler Peak 0.157 0.136 0.164 0.152 0.164
Overall 0.326 1.748PNM San Juan Generating St ation Visibility Impacts

060607 8-24 

### Table 8-12 Unit 2 SCR Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 0.483 0.376 0.408 0.422 0.483

Bandelier 0.210 0.323 0.271 0.268 0.323 Black Canyon 0.193 0.194 0.202 0.196 0.202 Canyonlands 0.670 0.465 0.508 0.548 0.670 Capitol Reef 0.399 0.154 0.247 0.267 0.399 Grand Canyon 0.175 0.134 0.128 0.146 0.175

Great Sand Dunes 0.117 0.102 0.098 0.106 0.117

La Garita 0.134 0.138 0.143 0.138 0.143

Maroon Bells 0.091 0.083 0.075 0.083 0.091

Mesa Verde 1.435 1.740 1.712 1.629 1.740

Pecos 0.178 0.223 0.219 0.207 0.223

Petrified Forest 0.144 0.109 0.115 0.123 0.144

San Pedro 0.380 0.503 0.436 0.440 0.503

West Elk 0.134 0.138 0.134 0.135 0.138

Weminuche 0.260 0.405 0.323 0.329 0.405

Wheeler Peak 0.156 0.135 0.163 0.151 0.163
Overall 0.324 1.740PNM San Juan Generating St ation Visibility Impacts

060607 8-25 

### Table 8-13 Unit 3 SCR Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 0.734 0.440 0.561 0.578 0.734

Bandelier 0.316 0.383 0.470 0.390 0.470 Black Canyon 0.305 0.246 0.331 0.294 0.331 Canyonlands 0.918 0.563 0.674 0.718 0.918 Capitol Reef 0.542 0.219 0.323 0.361 0.542 Grand Canyon 0.241 0.176 0.193 0.203 0.241

Great Sand Dunes 0.185 0.165 0.153 0.168 0.185

La Garita 0.227 0.201 0.235 0.221 0.235

Maroon Bells 0.133 0.125 0.113 0.124 0.133

Mesa Verde 2.312 1.776 2.516 2.201 2.516

Pecos 0.288 0.279 0.362 0.310 0.362

Petrified Forest 0.237 0.155 0.179 0.190 0.237

San Pedro 0.631 0.592 0.640 0.621 0.640

West Elk 0.202 0.190 0.192 0.195 0.202

Weminuche 0.424 0.453 0.563 0.480 0.563

Wheeler Peak 0.246 0.182 0.216 0.215 0.246
Overall 0.454 2.516PNM San Juan Generating St ation Visibility Impacts

060607 8-26 

### Table 8-14 Unit 4 SCR Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 0.718 0.517 0.532 0.589 0.718

Bandelier 0.311 0.446 0.459 0.405 0.459 Black Canyon 0.297 0.284 0.328 0.303 0.328 Canyonlands 0.931 0.655 0.678 0.755 0.931 Capitol Reef 0.530 0.237 0.319 0.362 0.530 Grand Canyon 0.238 0.195 0.190 0.208 0.238

Great Sand Dunes 0.183 0.183 0.150 0.172 0.183

La Garita 0.224 0.223 0.219 0.222 0.224

Maroon Bells 0.131 0.153 0.114 0.133 0.153

Mesa Verde 2.304 2.234 2.455 2.331 2.455

Pecos 0.280 0.336 0.353 0.323 0.353

Petrified Forest 0.233 0.162 0.175 0.190 0.233

San Pedro 0.618 0.706 0.631 0.652 0.706

West Elk 0.199 0.219 0.192 0.203 0.219

Weminuche 0.412 0.547 0.549 0.503 0.549

Wheeler Peak 0.240 0.206 0.213 0.220 0.240
Overall 0.473 2.455PNM San Juan Generating St ation Visibility Impacts

060607 8-27 

### Table 8-15 Unit 1 Hybrid Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 0.731 0.560 0.601 0.631 0.731

Bandelier 0.277 0.437 0.384 0.366 0.437 Black Canyon 0.274 0.269 0.297 0.280 0.297 Canyonlands 1.002 0.691 0.677 0.790 1.002 Capitol Reef 0.558 0.186 0.286 0.343 0.558 Grand Canyon 0.269 0.170 0.148 0.196 0.269

Great Sand Dunes 0.162 0.153 0.128 0.148 0.162

La Garita 0.189 0.199 0.203 0.197 0.203

Maroon Bells 0.130 0.113 0.105 0.116 0.130

Mesa Verde 2.076 2.385 2.135 2.199 2.385

Pecos 0.250 0.309 0.288 0.282 0.309

Petrified Forest 0.183 0.122 0.129 0.145 0.183

San Pedro 0.494 0.708 0.608 0.603 0.708

West Elk 0.199 0.201 0.195 0.198 0.201

Weminuche 0.307 0.497 0.413 0.406 0.497

Wheeler Peak 0.194 0.164 0.202 0.187 0.202
Overall 0.443 2.385PNM San Juan Generating St ation Visibility Impacts

060607 8-28 

### Table 8-16 Unit 2 Hybrid Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 0.728 0.558 0.598 0.628 0.728

Bandelier 0.276 0.435 0.382 0.364 0.435 Black Canyon 0.273 0.268 0.296 0.279 0.296 Canyonlands 0.997 0.687 0.673 0.786 0.997 Capitol Reef 0.555 0.185 0.285 0.342 0.555 Grand Canyon 0.268 0.169 0.148 0.195 0.268

Great Sand Dunes 0.162 0.152 0.127 0.147 0.162

La Garita 0.188 0.198 0.201 0.196 0.201

Maroon Bells 0.130 0.112 0.104 0.115 0.130

Mesa Verde 2.067 2.374 2.125 2.189 2.374

Pecos 0.249 0.308 0.287 0.281 0.308

Petrified Forest 0.182 0.121 0.128 0.144 0.182

San Pedro 0.492 0.705 0.605 0.601 0.705

West Elk 0.198 0.200 0.194 0.197 0.200

Weminuche 0.305 0.495 0.411 0.404 0.495

Wheeler Peak 0.193 0.164 0.201 0.186 0.201
Overall 0.441 2.374PNM San Juan Generating St ation Visibility Impacts

060607 8-29 

### Table 8-17 Unit 3 Hybrid Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 1.018 0.774 0.669 0.820 1.018

Bandelier 0.349 0.631 0.612 0.531 0.631 Black Canyon 0.382 0.412 0.474 0.423 0.474 Canyonlands 1.237 0.924 0.856 1.006 1.237 Capitol Reef 0.702 0.248 0.377 0.442 0.702 Grand Canyon 0.322 0.267 0.201 0.263 0.322

Great Sand Dunes 0.229 0.248 0.180 0.219 0.248

La Garita 0.299 0.328 0.306 0.311 0.328

Maroon Bells 0.171 0.202 0.158 0.177 0.202

Mesa Verde 2.430 2.892 2.558 2.627 2.892

Pecos 0.341 0.469 0.433 0.414 0.469

Petrified Forest 0.272 0.204 0.176 0.217 0.272

San Pedro 0.709 0.984 0.772 0.822 0.984

West Elk 0.254 0.335 0.275 0.288 0.335

Weminuche 0.422 0.755 0.551 0.576 0.755

Wheeler Peak 0.263 0.281 0.253 0.266 0.281
Overall 0.588 2.892PNM San Juan Generating St ation Visibility Impacts

060607 8-30 

### Table 8-18 Unit 4 Hybrid Visibility Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 1.102 0.755 0.740 0.866 1.102

Bandelier 0.411 0.616 0.672 0.566 0.672 Black Canyon 0.426 0.407 0.510 0.448 0.510 Canyonlands 1.369 0.919 1.002 1.097 1.369 Capitol Reef 0.754 0.243 0.412 0.470 0.754 Grand Canyon 0.344 0.262 0.221 0.276 0.344

Great Sand Dunes 0.251 0.240 0.194 0.228 0.251

La Garita 0.329 0.323 0.319 0.324 0.329

Maroon Bells 0.196 0.197 0.170 0.188 0.197

Mesa Verde 3.006 2.845 3.164 3.005 3.164

Pecos 0.383 0.461 0.467 0.437 0.467

Petrified Forest 0.290 0.199 0.192 0.227 0.290

San Pedro 0.777 0.963 0.864 0.868 0.963

West Elk 0.275 0.328 0.283 0.295 0.328

Weminuche 0.496 0.733 0.697 0.642 0.733

Wheeler Peak 0.289 0.275 0.290 0.285 0.290
Overall 0.639 3.164PNM San Juan Generating St ation Visibility Impacts

060607 8-31 

### 8.8.3 WRAP RMC Baseline Scenario
The results of the WRAP RMC ba seline modeling from April 21, 2007, are presented in Table 8-19. As previously noted, correspondence between NMED and the WRAP on April 2, 2007, indicated an error(s) in the original BART modeling conducted by WRAP in 2006. The error(s) was corrected, and WRAP has since rerun the previous BART modeling; however, at the time of this report, the extent of the error(s), their corresponding correction(s), a nd the results are not known. Therefore, it is not known
how these errors have affected the previously described WRAP modeling.

8.8.4 Summary As previously described, the SJGS BART modeling for the BART emissions control options are presented in Tables 8- 9 through 8-20. Tables 8-9 and 8-10 show the results, assuming that the same control technology is installed on all four units. Table 8-19 presents the resu lts of the analysis conducted by the WRAP RMC. These
tables summarize the scenarios and the maxi mum visibility (deciview) improvement seen at any of the 16 Class I areas at any tim e over the 2001 to 2003 period. The expected degree of visibility improvement for each co ntrol scenario for each unit analyzed was determined by the difference in the average vi sibility improvement for each receptor at each of the sixteen Class I areas. However, it is important to note that the control technology associated with the consent decree formulated th e SJGS's baseline case for the purposes of this analys is. Therefore, using the WRAP RMC's April 2007 modeling
results and the SJGS's consent decree baseline results, the average visibility improvement
is 0.6 dv. Similar calculations for the SCR and hybrid control technology options were also conducted. To simplify this an alysis, the total average amount of visibility improvement at all 16 Class I areas, assuming that all un its installed the same control technology, was compared to the total average visibility im provement from the consent decree baseline. These visibility improvements for the three cas es range from 0.2 dv to 0.6 dv of expected visibility improvement above the consent decr ee technology baseline case, which is less than or equal to the visibility improve ment gained by going from the WRAP RMC's baseline case to the consent decree technology baseline case. For Mesa Verde, the average number of days that exceed the recommended exemption guideline value of 0.5 dv is higher for the SCR and hybrid control technology options than the consent decree technology baseline. Table 8-20 illustrates the average change in visibility improvement. Additionally, differences in data processing, model contro l options, and methodologies can yield variations between the WRAP m odeling and SJGS BART modeling. In thePNM San Juan Generating St ation Visibility Impacts

060607 8-32 

### case of the visibility impacts at Mesa Verde Class I area, WR AP’s visibility impacts from April 2007, shown in Table 8-19 are less than those presented in this report for the consent decree technology baseline scenario, sh own in Table 8-8 or the additional control scenarios for SCR or hybrid control technology options, sh own in Table 8-9 and 8-10, respectively.

Table 8-19 WRAP RMC Baseline Modeling Results 98th Percentile Impact for Each Year (dv)

Class I Area 2001 2002 2003 Average Maximum

Arches 4.06 3.71 3.59 3.787 4.060

Bandelier 2.47 2.90 3.08 2.817 3.080 Black Canyon 2.38 2.27 2.43 2.360 2.430 Canyonlands 6.21 4.33 4.44 4.993 6.210 Capitol Reef 4.00 2.02 2.35 2.790 4.000 Grand Canyon 2.12 1.50 1.18 1.600 2.120

Great Sand Dunes 1.47 1.59 1.74 1.600 1.740

La Garita 1.63 1.82 1.77 1.740 1.820

Maroon Bells 1.19 1.27 1.15 1.203 1.270

Mesa Verde (a) 5.54 5.34 5.30 5.393 5.540

Pecos 2.17 2.63 2.81 2.537 2.810

Petrified Forest 1.62 1.27 1.03 1.307 1.620

San Pedro 3.80 4.07 4.14 4.003 4.140

West Elk 2.24 2.99 2.41 2.547 2.990

Weminuche 2.14 1.90 2.20 2.080 2.200

Wheeler Peak 1.94 1.73 1.97 1.880 1.970
Overall 2.665 6.210

(a) Differences in data processing, model control options, and methodologies can yield variations between the WRAP modeling and SJGS BART modeling. In the case of the visibility impacts at Mesa Verde Class I area, WRAP’s visibility impacts from April 2007 are less than those presented for the consen t decree technology baselinescenario (Table 8- 8) or the SCR and Hybrid control tech nology scenarios (Table 8-9 and 8-10).PNM San Juan Generating St ation Visibility Impacts

060607 8-33 

### Table 8-20 Average Change in Visibility Improvement (a)

Visibility Scenario Baseline Average Impact

(dv) Control Technology Average Impact (dv) Scenario Average Deciview Change (b) (dv)

WRAP RMC to Consent Decree 2.665 2.051 0.614

Consent Decree to SCR 2.051 1.424 0.627 Consent Decree to Hybrid 2.051 1.825 0.226

(a) Average impact is the average impact from all 16 Class I Areas at all receptors for the period 2001-2003. (b) Scenario average deciview change is the diffe rence between the average baseline scenario and average control technology scenario.



## 8.9 Visibility Impr ovement Cost-Effectiveness The visibility improvement cost-effec tiveness defined in Subsection 1.2.5 was determined according to the TAC for the consent decree upgrades shown in Table 4-2 and for the additional control technology altern atives shown in Table 7-1. The maximum and average modeled visibility impacts at th e 16 Federal Class I areas were used for the determination of the visibility improvement cost-effectiveness in $/deciview ($/dv). Three major scenarios are shown in the vi sibility improvement cost effectiveness summary in Table 8-21:

• Pre-consent decree to consent decree.

• Consent decree to additional NO x 

### control technology a lternatives scenario.

• Pre-consent decree to additional NO x 

### control technology alternatives
scenario. The pre-consent decree visibility impact was based on the vi sibility modeling performed by the RMC for WRAP for the determination of BART eligibility.PNM San Juan Generating St ation Visibility Impacts

060607 8-34 

### Table 8-21 Visibility Improvement Cost-Effectiveness Summary

Total Scenario Annualized Average Cost Deciview Average (TAC) Change Improvement Visibilitiy Scenario (1,000$) (dv) ($/dv) Consent Decree Scenario

Pre-consent decree to consent decree 51,468 0.614 83,824,104

Additional Control Technology Alternative

Consent decree to SCR 97,367 0.627 155,290,271 Consent decree to Hybrid 83,332 0.226 368,725,664

Pre-consent decree to SCR 148,835 1.241 119,931,507 Pre-consent decree to Hybrid 134,800 0.840 160,476,190

Notes:

1. All costs are in 2007$. 2. Pre-consent decree visibility impact from WRAP RMC model, April 2007. 3. Total annualized costs and cost effectiveness ($/ton) are referenced from Table 4-3 and 7-1. 4. Deciview change assumes all four units on the same control technology.PNM San Juan Generating Station Conclusions

060607 9-1 

## 9.0 Conclusions

The BART analysis was perf ormed in two stages. First, a BART analysis was performed for the consent decree technologi es. Then, additional control technology
alternatives were examined through the BART process. After completing all five steps of the BART analysis, feasible technologies for all
four units at SJGS were selected and evaluate d for visibility improvement at the affected Federal Class I areas. The visibility improve ment modeling is summarized in Section 8.0 of this report. The recommended BART control for SJGS is LNB, OFA, and a NN for NO x 

### control and PJFF for PM control. The reco mmended BART control scenario was based
on an evaluation of the most cost-effective technology. This evalua tion was performed as
detailed in Sections 3.0 to 7.0 of this report. For PM emi ssions control, the addition of the PJFF to meet the consent decree requirement s represents BACT for similar units. No other technologies have been identified that exceed the em issions reductions achieved by the PJFF. Therefore, the PJFF is considered BART for this project.
For NO x 

### emissions control, the LNB, OFA, and NN should be considered BART for the SJGS units. The presumptive limit for subbituminous units is based on the
installation of state-of-the-art combustion control (i.e. LNB and OFA) on a PRB-fired
unit. The fuel characteristics of the subbitumi nous coal fired at SJGS are very similar to
those of bituminous coal. The low volatilit y, low moisture, and low oxygen content of the coal burned at SJGS distinguishes it from other fuels, such as PRB fuels, included in the same category of “subbituminous”. Th ese characteristics re sult in higher NO x 

### emissions than on a PRB-fired unit with th e same control technology. The LNB, OFA, and NN technologies being installed at the SJGS units are classified as state-of-the-art technologies and are equiva lent to the BART technol ogy used to establish the presumptive NO x 

### limit. The visibility improvements modeled for th e BART control scenario (as described in Section 8.0) indicate an average visibi lity improvement of 0.614 dv based on the preconsent decree visibility m odeled by WRAP’s RMC for all identified Federal Class I

areas. Based on the visibility improvement mode led and the total annual cost evaluated in the impact analysis stage, the cost-eff ectiveness for visibility improvement (annual cost per improvement in visibility, $/dv), wa s determined for SJGS. The total annual cost for the implementation of LNB, OFA, NN, and PJFF technologies is approximately $51.5 million/yr, and the visibility improvement cost-effectiveness is 83.8 million $/dv.PNM San Juan Generating Station Conclusions

060607 9-2 

### The SCR and SNCR/SCR Hybrid system s would require significant capital expenditure and modifications that will imp act many areas of the plant including boiler draft systems, air heater performance, SO 3 

### emissions, and ash handling. The capital costs for SCR ranged from $157 million on Unit 1 to $216 million on Unit 3. This represents a cost range of 436 $/kW on Unit 1 to 396 $/kW on Unit 3. For SNCR/SCR Hybrid, the capital costs ranged from $104 million on Unit 1 to $169 million on Unit 3. This represents a cost ra nge of 290 $/kW on Unit 1 to 310 $/kW on Unit 3. In addition, the average visibility improvement from th ese systems is only 0.627 dv for SCR and 0.226 for the hybrid. The visibility improvement cost effectiveness is 155 million $/dv for SCR and 369 million $/dv for SNCR/S CR Hybrid. These minimal visibility improvements do not merit the large capital expenditure require d to install SCR or SNCR/SCR Hybrid. In addition to the prohibitive cost associated with SCR and SNCR/SCR Hybrid, there is another important reason th at LNB, OFA and NN should be considered BART for the SJGS units. The LNB, OFA and NN systems be ing installed to meet the consent decree
are state-of-the-art combustion controls. The LNB, OFA and NN technologies were used to form the basis for the BART presumptive limits for NO x 

### . Therefore, LNB, OFA and
NN should be considered BART for NO x 

### control on the SJGS units.PNM San Juan Generating Station Appendix A

060607 A-1 

## Appendix A Design BasisPNM San Juan Generating StationAppendix A060607A-2Best Available Retrofit Technology (BART) Engineering AnalysisDesign Basis Rev. 3SJGS SJGS SJGS SJGSUnit 1 Reference Unit 2 ReferenceUnit 3 Reference Unit 4 ReferenceUltimate Coal analysis, wet basisCarbon, % 54.52 Ref 1 54.52 Ref 1 54.52 Ref 1 54.52 Ref 1Hydrogen, % 4.24 Ref 1 4.24 Ref 1 4.24 Ref 1 4.24 Ref 1Sulfur, % 0.77 Ref 1 0.77 Ref 1 0.77 Ref 1 0.77 Ref 1Nitrogen, % 1.08 Ref 1 1.08 Ref 1 1.08 Ref 1 1.08 Ref 1Oxygen, % 9.38 Ref 1 9.38 Ref 1 9.38 Ref 1 9.38 Ref 1Chlorine, % NARef 1 NARef 1 NARef 1 NA Ref 1Ash, % 21.29 Ref 1 21.29 Ref 1 21.29 Ref 1 21.29 Ref 1Moisture, % 8.72 Ref 1 8.72 Ref 1 8.72 Ref 1 8.72 Ref 1Total, % 100.00 Ref 1 100.00 Ref 1 100.00 Ref 1 100.00 Ref 1Higher Heating Value, Btu/lb 9,692 Ref 1 9,692 Ref 1 9,692 Ref 1 9,692 Ref 1Unit CharacteristicsUnit Rating, Gross MW 360 Ref 2 350Ref 2 544 Ref 2 544 Ref 2Boiler TypeWall-Fired Ref 2 Wall-Fired Ref 2 Opposed Wall-FiredRef 2 Opposed Wall-FiredRef 2Boiler Heat Input, MBtu/h (HHV) 3,707 Ref 3 3,688 Ref 3 5,758 Ref 3 5,649 Ref 3Coal Flow Rate, lb/h 382,480 Calculated 380,520 Calculated 594,098 Calculated 582,852 CalculatedCapacity Factor, % 85Note 5 85 Note 5 85 Note 5 85 Note 5Fly Ash Portion of Total Ash, % 80Ref 4 80 Ref 4 80 Ref 4 80 Ref 4Air Heater Leakage, % 15Note 5 15 Note 5 15 Note 5 15 Note 5Excess Air, % 20Ref 5 20 Ref 5 20 Ref 5 20 Ref 5Emission SummaryNitrogen Oxides (NOx), lb/MBtu0.43 Ref 4 0.45 Ref 4 0.42 Ref 4 0.42 Ref 4Nitrogen Oxides (NOx), lb/h1,592.0 Calculated 1,649.3 Calculated 2,405.5Calculated 2,399.6 CalculatedSulfur Dioxide (SO2), lb/MBtu0.24 Ref 4 0.23 Ref 4 0.28 Ref 4 0.29 Ref 4Sulfur Dioxide (SO2), lb/MBtu877.8 Calculated 844.0 Calculated 1,591.1Calculated 1,662.4 CalculatedParticulate Matter (PM), lb/MBtu 0.050Ref 4 0.050 Ref 4 0.050 Ref 4 0.050 Ref 4Particulate Matter (PM), lb/h 185.4 Calculated184.4 Calculated 287.9 Calculated 282.5 CalculatedEconomizer Outlet ConditionsFlue Gas Temperature, °F 707 Ref 6 710Ref 7 720 Ref 8 720 Ref 9Flue Gas Pressure, in. wg 12.0 Ref6 11.0 Ref 7 19.0 Ref 8 19.0 Ref 9Flue Gas Mass Flow Rate, lb/h 3,674,408 Ref 6 3,655,575 Ref 7 5,707,376Ref 8 5,599,334 Ref 9Volumetric Flue Gas Flow Rate, acfm 2,082,166 Ref 6 2,082,819 Ref 7 3,205,572 Ref 8 3,144,890 Ref 9Public Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS)PRE-CONSENT DECREE OPERATION CONDITIONSCONSENT DECREE UPGRADES CONDITIONSPNM San Juan Generating StationAppendix A060607A-3Flue Gas CompositionOxygen (O2), % by volume3.2 Ref 6 3.2 Ref 7 3.2 Ref 8 3.2 Ref 9Carbon Dioxide (CO2), % by volume13.7 Ref 6 13.7 Ref 7 13.7 Ref 8 13.7 Ref 9Moisture (H2O), % by volume9.7 Ref 6 9.7 Ref 7 9.7 Ref 8 9.7 Ref 9Sulfur Dioxide (SO2), % by volume0.07 Ref 6 0.07 Ref 7 0.07 Ref 8 0.07 Ref 9Sulfur Dioxide (SO2), lb/MBtu1.59 Calculated 1.59 Calculated1.59 Calculated 1.59 CalculatedSulfur Dioxide (SO2), lb/h5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 8,967 Ref 9Sulfur Trioxide (SO3), lb/h74Note 1 73 Note 1 114 Note 1 112 Note 1Sulfur Trioxide (SO3), lb/MBtu0.020 Calculated 0.020 Calculated0.020 Calculated 0.020 CalculatedParticulate Matter (PM), lb/MBtu 17.6 Calculated 17.6 Calculated 17.6 Calculated 17.57 CalculatedParticulate Matter (PM), lb/h 65,144 Ref 6 64,810 Ref 7 101,187 Ref 8 99,271 Ref 9Nitrogen Oxides (NOx), lb/MBtu 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10Nitrogen Oxides (NOx), lb/h 1,112 Calculated1,106 Calculated 1,727 Calculated 1,695 CalculatedDe-Energized Hot-SideESP Outlet ConditionsFlue Gas Temperature, °F 695 Ref 6 698Ref 7 640 Ref 8 673 Ref 9Flue Gas Pressure, in. wg 6.5 Ref 6 6.5 Ref 7 8.2 Ref 8 8.2 Ref 9Flue Gas Mass Flow Rate, lb/h 3,674,408 Ref 6 3,655,575 Ref 7 5,707,376Ref 8 5,599,334 Ref 9Volumetric Flue Gas Flow Rate, acfm 2,093,930 Ref 6 2,088,609 Ref 7 3,082,239 Ref 8 3,114,609 Ref 9Flue Gas CompositionOxygen (O2), % by volume3.2 Ref 6 3.2 Ref 7 3.2 Ref 8 3.2 Ref 9Carbon Dioxide (CO2), % by volume13.7 Ref 6 13.7 Ref 7 13.7 Ref 8 13.7 Ref 9Moisture (H2O), % by volume9.7 Ref 6 9.7 Ref 7 9.7 Ref 8 9.7 Ref 9Sulfur Dioxide (SO2), % by volume0.07 Ref 6 0.07 Ref 7 0.07 Ref 8 0.07 Ref 9Sulfur Dioxide (SO2), lb/MBtu1.59 Calculated 1.59 Calculated1.59 Calculated 1.59 CalculatedSulfur Dioxide (SO2), lb/h5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 8,967 Ref 9Sulfur Trioxide (SO3), lb/h74Note 1 73 Note 1 114 Note 1 112 Note 1Sulfur Trioxide (SO3), lb/MBtu0.020 Calculated 0.020 Calculated0.020 Calculated 0.020 CalculatedParticulate Matter (PM), lb/MBtu 8.79 Calculated 8.79 Calculated 8.79 Calculated 8.79 CalculatedParticulate Matter (PM), lb/h 32,572 Note3 32,405 Note 3 50,593 Note 3 49,636 Note 3Nitrogen Oxides (NOx), lb/MBtu 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10Nitrogen Oxides (NOx), lb/h 1,112 Calculated1,106 Calculated 1,727 Calculated 1,695 CalculatedAir Heater Outlet ConditionsFlue Gas Temperature, °F 277 Ref 6 277Ref 7 277 Ref 8 277 Ref 9Flue Gas Pressure, in. wg 0.0 Ref 6 0.0 Ref 7 0.0 Ref 8 0.0 Ref 9Flue Gas Mass Flow Rate, lb/h 4,225,569 Ref 6 4,203,912 Ref 7 6,563,482Ref 8 6,439,234 Ref 9Volumetric Flue Gas Flow Rate, acfm 1,571,717 Ref 6 1,563,662 Ref 7 2,441,313 Ref 8 2,395,099 Ref 9PNM San Juan Generating StationAppendix A060607A-4Flue Gas CompositionOxygen (O2), % by volume5.5 Ref 6 5.5 Ref 7 5.5 Ref 8 5.5 Ref 9Carbon Dioxide (CO2), % by volume11.9 Ref 6 11.9 Ref 7 11.9 Ref 8 11.9 Ref 9Moisture (H2O), % by volume8.7 Ref 6 8.7 Ref 7 8.7 Ref 8 8.7 Ref 9Sulfur Dioxide (SO2), % by volume0.06 Ref 6 0.06 Ref 7 0.06 Ref 8 0.06 Ref 9Sulfur Dioxide (SO2), lb/MBtu1.59 Calculated 1.59 Calculated1.59 Calculated 1.59 CalculatedSulfur Dioxide (SO2), lb/h5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 8,967 Ref 9Particulate Matter (PM), lb/MBtu 8.79 Calculated 8.79 Calculated 8.79 Calculated 8.79 CalculatedParticulate Matter (PM), lb/h 32,572 Note3 32,405 Note 3 50,593 Note 3 49,636 Note 3Nitrogen Oxides (NOx), lb/MBtu 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10Nitrogen Oxides (NOx), lb/h 1,112 Calculated1,106 Calculated 1,727 Calculated 1,695 CalculatedFabric Filter Outlet ConditionsFabric Filter Particulate Matter Removal, percent 99.86% Calculated 99.86% Calculated 99.86%Calculated 99.86% CalculatedFlue Gas Temperature, °F 277 Ref 6 277Ref 7 277 Ref 8 277 Ref 9Flue Gas Pressure, in. wg -10Ref 6 -10 Ref 7 -10.0 Ref 8 -10.0 Ref 9Flue Gas Mass Flow Rate, lb/h 4,225,569 Ref 6 4,203,912 Ref 7 6,563,482Ref 8 6,439,234 Ref 9Volumetric Flue Gas Flow Rate, acfm 1,620,055 Ref 6 1,611,752 Ref 7 2,516,395 Ref 8 2,468,760 Ref 9Flue Gas CompositionSulfur Dioxide (SO2), lb/MBtu1.59 Calculated 1.59 Calculated1.59 Calculated 1.59 CalculatedSulfur Dioxide (SO2), lb/h5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 8,967 Ref 9Particulate Matter (PM), lb/MBtu 0.012Ref 5 0.012 Ref 5 0.012 Ref 5 0.012 Ref 5Particulate Matter (PM), lb/h 44Calculated 44 Calculated 69 Calculated 68 CalculatedFGD Booster Fan Outlet ConditionsFlue Gas Temperature, °F 290 Ref 6 290Ref 7 290 Ref 8 290 Ref 9Flue Gas Pressure, in. wg 10Ref 6 9 Ref 7 14.2 Ref 8 14.2 Ref 9Flue Gas Mass Flow Rate, lb/h 4,225,569 Ref 6 4,203,912 Ref 7 6,563,482Ref 8 6,439,234 Ref 9Volumetric Flue Gas Flow Rate, acfm 1,553,101 Ref 6 1,549,630 Ref 7 2,383,394 Ref 8 2,338,276 Ref 9Flue Gas CompositionSulfur Dioxide (SO2), lb/MBtu1.59 Calculated 1.59 Calculated1.59 Calculated 1.59 CalculatedSulfur Dioxide (SO2), lb/h5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 8,967 Ref 9Scrubber Outlet ConditionsScrubber SO2Removal, percent90% Note 4 90% Note 4 90%Note 4 90% Note 4Flue Gas Temperature, °F 121 Ref 6 121Ref 7 121 Ref 8 121 Ref 9Flue Gas Pressure, in. wg 1.0 Ref 6 1.0 Ref 7 1.0 Ref 8 1.0 Ref 9Flue Gas Mass Flow Rate, lb/h 4,396,972 Ref 6 4,374,435 Ref 7 6,829,718Ref 8 6,700,430 Ref 9Volumetric Flue Gas Flow Rate, acfm 1,319,596 Ref 6 1,312,832 Ref 7 2,049,699 Ref 8 2,010,898 Ref 9Flue Gas CompositionSulfur Dioxide (SO2), lb/MBtu0.16 Calculated 0.16 Calculated0.16 Calculated 0.16 CalculatedSulfur Dioxide (SO2), lb/h588 Calculated 585Calculated 914 Calculated 897 CalculatedPNM San Juan Generating StationAppendix A060607A-5Stack Outlet ConditionsFlue Gas Temperature, °F 121Ref 6 121 Ref 7 121 Ref 8 121 Ref 9Flue Gas Pressure, in. wg0.01 Ref 6 0.01 Ref 7 0.01 Ref 8 0.01 Ref 9Flue Gas Mass Flow Rate, lb/h 4,396,972 Ref 6 4,374,435 Ref 7 6,829,718Ref 8 6,700,430 Ref 9Volumetric Flue Gas Flow Rate, acfm1,323,494 Ref 6 1,316,710 Ref 7 2,055,753 Ref 8 2,016,837 Ref 9Stack Height, m121.92 Ref 11 121.92 Ref 11 121.92 Ref 11 121.92 Ref 11Stack Diameter, m6.10 Ref 11 6.10 Ref 11 8.53 Ref 11 8.53 Ref 11Flue Gas Exit Velocity, ft/s 70 Calculated 70 Calculated 56 Calculated 55 CalculatedFlue Gas CompositionSulfur Dioxide (SO2), lb/MBtu0.16 Calculated 0.16 Calculated0.16 Calculated 0.16 CalculatedSulfur Dioxide (SO2), lb/h588Calculated 585 Calculated 914 Calculated 897 CalculatedH2SO4Emissons, lb/h21.6 Ref 12 21.5 Ref 1233.6 Ref 12 33.0 Ref 12Particulate Matter (PM), lb/MBtu 0.015Ref 5 0.015 Ref 5 0.015 Ref 5 0.015 Ref 5Particulate Matter (PM), lb/h56 Calculated 55 Calculated 86 Calculated 85 CalculatedNitrogen Oxides (NOx), lb/MBtu 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10Nitrogen Oxides (NOx), lb/h1,112 Calculated 1,106 Calculated1,727 Calculated 1,695 CalculatedNotes:1. Sulfur dioxide to sulfur trioxide conversion is assumed to be 1% across the boiler.2. The particulate matter concentrations listed are filterable particulate matter only.3. 50% total particulate matter drop-out expected through de-energized hot ESP, N. Norem, 03/02/2007.4. SO2post-consent decree emission limits is a minimum of 90% removal.5. Assumptions verified in weekly phone conference, 03/08/2007.References1. Composite delivery sample analysis representing November 2005 (642,775 tons).2. Section 3.2 Design Criteria for PNM SJGS Environmental Project.3. Environmental Upgrades "6% plus" Permitting Heat Input Basis.4. Study project basis information.5. B&W LNB and AQCS Performance Guarantee, Page 2 of 14.6. M10 Combustion Calculation forSJGS Unit 1, K. Whitehead, 03/09/2007.7. M10 Combustion Calculation forSJGS Unit 2, K. Whitehead, 03/09/2007.8. M10 Combustion Calculation forSJGS Unit 3, K. Whitehead, 03/09/2007.9. M10 Combustion Calculation forSJGS Unit 4, K. Whitehead, 03/09/2007.10.Post-consent decree NOxemission limit.11.SJGS boiler stack exit parameters.12.San Juan Generating Station BART SO4Emission Comparison (National Park Service spreadsheet calculation for April 2003 to January 2007), K. Lucas, 04/12/2007.Revision HistoryRevDate Purpose02/21/2007 Initial issue to client13/9/2007 Revision to address comments on air heater outlet conditions and hot-ESP particulate drop-out rate24/18/2007Revision to include H2SO4emissions data35/24/2007 Revision to update references and table layoutPNM San Juan Generating Station Appendix B

060607 B-1 

## Appendix B Design Concept DefinitionsPNM San Juan Generating Station Appendix B

060607 B-2 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology Selective Non-Catalytic Reduction

Process Description Addition of Selective Non-Catalytic Reduction (SN CR) process into boiler pendant superheat section.

Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu 0.24 0.24 0.24 0.24 lb/h NA NA NA NA Inlet Flow Basis, acfm 2,082,166 2,082,819 3,205,572 3,144,890 Pressure Drop Added, in. wg None Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Urea), lb/h NA NA NA NA Water, gpm NA NA NA NA Energy, kW NA NA NA NA
Maintenance 3% of direct material cost. Byproduct Description No impact on ash sales. Other Up to 5 ppm ammonia slip.

Location of Major Process Equipment Truck- filled reagent storage tank, reagent circulat ion unit in enclosure with metering and distribution module, wall-injectors and multi- nozzle lances (MNL) in boiler penetrations. Inlet/Outlet Connections and Interconnecting Ducts Dilution water to metering module, atomizing air to injectors and MNL, cooli ng water for MNL.
Reagent Storage Reagent tank at grade.
Control System Modifications SNCR controls interfaced into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Injection equipment enclosed in existing boiler building, enclosure for reagent circulation unit.
Demolition or Relocation Requirements Penetrations into boiler wall for injectors and MNL, access platforms.
Major Constructability Issues R outing of SNCR reagent supply lines.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning, air heat er modifications included. Other Assumptions:

• No major impact in plant availability.

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

• No boiler/duct stiffening included.

• Air heater modifications included in analysis.

• No impact on potential ash sales.

• Reagent is urea solution.

State of Availability Availability.
State of Applicability Not applicable.
Technical Feasibility Not technically feasible. Controlled NO x level does not presumptive NO x limits. Undeveloped data fields will be marked as “NA”.PNM San Juan Generating Station Appendix B

060607 B-3 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology Selective Catalytic Reduction

Process Description Install Selective Catalytic Reduction (SCR) ammonia inject ion and reactor downstream of de-energized hot-side ESP.
Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu 0.07 0.07 0.07 0.07 lb/h 259.5 258.2 403.1 395.4 Inlet Flow Basis, acfm 2,093,930 2,088,609 3,082,239 3,114,609 Pressure Drop Added, in. wg 10 Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Ammonia), lb/h 350 348 543 533 Energy, kW 3,296 3,287 4,835 4,881 Catalyst Add and/or replace one catalyst layer every 2 years. Maintenance 3% of direct material cost. Byproduct Description No impact on ash sales. Other 2 ppm ammonia slip (max)

Location of Major Process Equipment Install SCR reactor as hi gh-dust configuration, downstream of de-energized hot-side ESP and upstream of existing air heaters. Ammonia inject ion location will be upstream of the reactor. Install ammonia vaporizers at grade. Inlet/Outlet Connections and Interconnecting Ducts SCR inlet and ou tlet ducts connected into duc t exiting de-energized hot-side ESP and entering air heater, dilution water and atomizing air for reagent preparation and delivery. Reagent Storage Locate ammonia storage at grade in suitable pr otective structure or away from unit to limit risk from ammonia leakage. Control System Modifications SCR controls interfaced into existing control system.

Fan Modifications Assume additional fan capacity will be required, re quiring balanced draft conversion.
Power Supply/Aux Power Modifications Aux electric system upgr ade will be required for additional fan capacity, ammonia preparat ion and delivery system, and reactor catalyst cleaning system. Enclosures Requirements Ammonia injection gr id area and sonic horns are to be enclosed.
Demolition or Relocation Requirements Existing ductwork between de-energized hot-side ESP outlet and air heater inlet.
Major Constructability Issues Support steel design for SCR r eactor and location of piling for steel support. Crane access for constructing SCR reactor for SJGS units 2 and 3. Significant Issues or Challenges Ammoni a slip in the SCR may cause ammonium bisulfate formation on the air heater and require more frequent cleaning, ai r heater modifications included. Other Assumptions:

• No major impact in plant availability.

• Temperature range of flue gas at de-ene rgized hot-side ESP outlet is acceptable and no additional heating required at low load s.

• The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. Crane access to Units 2 and 3 might be limited (see attached plant layout).

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

• SCR bypass included to allow the SCR to be bypassed during startup on fuel oil.

• SCR reactor includes three initial catalyst layers and one spare layer (3 + 1 arrangement).

State of Availability Availability.
State of Applicability Applicable.
Technical Feasibility Technically feasible.PNM San Juan Generating Station Appendix B

060607 B-4 

### SJGS Unit 1 and 2 Proposed SCR Layout Plan

Legend: Blue = SCR Reactor Red = Structural Steel Supports Orange = PJFF Location – Consent Decree Modifications Green = Induced Draft Fan LocationsPNM San Juan Generating Station Appendix B

060607 B-5 

### SJGS Unit 3 and 4 Proposed SCR Layout Plan

Legend: Blue = SCR Reactor Red = Structural Steel Supports Orange = PJFF Location – Consen t Decree Modifications Green = Induced Draft Fan LocationsPNM San Juan Generating Station Appendix B

060607 B-6 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology SNCR/SCR Hybrid

Process Description Install SNCR/SCR hybrid system. Single layer catalyst added in ductwork downstream of de-energized hot-side ESP outlet.
Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu 0.18 0.18 0.18 0.18 lb/h 667.3 663.8 1,036.4 1,061.8 Inlet Flow Basis, acfm 2,082,166 2,082,819 3,205,572 3,144,890 Pressure Drop Added, in. wg 6 Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Urea), lb/h 1,089 1,089 1,689 1,689 Water, gpm 252 252 380 380 Energy, kW 1,477 1,477 2,197 2,197 Catalyst Replace catalyst layer every 2 years. Maintenance 3% of direct material cost. Byproduct Description No impact on ash sales. Other 5 ppm ammonia slip (max)

Location of Major Process Equipment Truck- filled reagent storage tank, reagent circulat ion unit in enclosure with metering and distribution module, wall-injectors and multi-nozzle lances (MNL) in boiler penetrations. Single layer catalyst is added in ductwork do wnstream of de-energized hot-side ESP. Inlet/Outlet Connections and Interconnecting Ducts Catalyst inle t and outlet ducts connected into duct exiting de-energized hot -side ESP and entering air heater. Increase duct size to include as much catalyst as possible. Reagent Storage Reagent tank at grade.
Control System Modifications SNCR/SCR hybrid c ontrols interfaced into existing control system.

Fan Modifications Assume additional fan capacity will be required, re quiring balanced draft conversion.
Power Supply/Aux Power Modifications Aux electric system upgr ade will be required for additional fan capacity, ammonia preparat ion and delivery system, and reactor catalyst cleaning system. Enclosures Requirements Injection equipment enclosed in existing boiler building, enclosure for reagent circulation unit.
Demolition or Relocation Requirements Existing ductwork betwe en de-energized hot-side ESP outlet and air heater inlet. Penetrat ions into boiler wall for injectors and MNL, access platforms. Major Constructability Issues Support steel design for SCR r eactor and location of piling for steel support. Crane access for constructing SCR reactor for SJ GS units 2 and 3. Routing of SNCR reagent supply lines. Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning, air heat er modifications included. Other Assumptions:

• No major impact in plant availability.

• Temperature range of flue gas at de-ene rgized hot-side ESP outlet is acceptable and no additional heating required at low load s.

• The site has sufficient area available to accommodate construction activities includi ng, but not limited to, offices, laydown, and staging. Crane access to Units 2 and 3 might be limited.

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

• Reagent is urea solution.

State of Availability Availability.
State of Applicability Applicable.
Technical Feasibility Technically feasible.PNM San Juan Generating Station Appendix B

060607 B-7 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology Gas Reburn

Process Description Natural gas reburn in boiler. Includes; standard natural gas rebu rn, fuel lean gas reburn (FLGR) and amine-enhanced fuel lean g as reburn (AE-FLGR).
Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 2,082,166 2,082,819 3,205,572 3,144,890 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Natural gas) NA lb/h Energy NA kW Maintenance 3% of direct material cost. Byproduct Description Not applicable Other None.

Location of Major Process Equipment Additional natural gas reburn levels to be installed in boiler wall. Inlet/Outlet Connections and Interconnecting Ducts Natural gas supply line required. Reagent Storage None.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modifications Minor aux electric system modifications r equired for natural gas handling system.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements Penetrations into boiler wall.
Major Constructability Issues None.
Significant Issues or Challenges Potential for increased furnac e corrosion issues due to reducing atmosphere at lower furnace.
Other Assumptions

• Gas required is typically 7% of total heat input.

State of Availability Available.
State of Applicability Not applicable.
Technical Feasibility Boiler not suitable for reburn due to current modifications to add OFA, not sufficient residence time for natural gas reburn. Not technically feasible. Undeveloped dat a fields will be marked as “NA”.PNM San Juan Generating Station Appendix B

060607 B-8 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology Mobotec ROFA and ROTAMIX

Process Description Mobotec ROFA and ROTAMIX

Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 2,082,166 2,082,819 3,205,572 3,144,890 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent NA lb/h Energy NA kW Maintenance 3% of direct material cost. Byproduct Description No impact on ash sales. Other 5ppm ammonia slip (if ROTAMIX).

Location of Major Process Equipment Install ROFA por ts above existing close coupl ed overfire air ports. Injection skid and reagent tank at grade with truck unloading station. Inlet/Outlet Connections and Interconnecti ng Ducts Tie-in to existing air duct.
Reagent Storage 50,000 gallon tank at grade.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements Penetrations into boiler wall.
Major Constructability Issues None.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning. Up to 5 ppm ammonia slip. Other Assumptions:

• No major impact in plant availability.

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

• No air heater modifications. Boiler/duct penetrations included.

• Minimal impact on potential ash sales.

State of Availability Available.
State of Applicability Applicable (ROFA only).
Technical Feasibility ROFA is technically feasible. ROTAMIX is not technically f easible (not demonstrated on sim ilar sized boilers as SJGS). Undeveloped data fields will be marked as “NA.”PNM San Juan Generating Station Appendix B

060607 B-9 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology NO x Star

Process Description NO x Star (injection of natural gas and ammonia mixture into boiler) and NO x Star Plus (with in-duct catalyst)

Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 2,082,166 2,082,819 3,205,572 3,144,890 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Ammonia) NA lb/h Reagent (Natural gas) NA lb/h Energy NA kW Catalyst Add and/or replace one catalyst layer every 3 years (if NO x Star Plus). Maintenance 3% of direct material cost. Byproduct Description No impact on ash sales. Other 5ppm ammonia slip.

Location of Major Process Equipment Injection skid an d ammonia tank at grade with truck unloading station. Install in-duct catalyst between economizer outlet and air heater inlet. Inlet/Outlet Connections and Interconnecting Ducts Catalyst inlet and outlet ducts connected into duct exiting the de-energized hot-side ESP. Natural gas supply line connection into injection system. Reagent Storage 50,000 gallon tank at grade.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications Fan modifica tions required if to account for in-duct catalyst for NO x Star Plus (if installed).
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements Penetrations into boiler wall.
Major Constructability Issues Economizer outlet ductwork modifications required to house in-duct catalyst for NO x Star Plus (if installed). Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning. Other Assumptions:

• No major impact in plant availability.

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

• No air heater modifications or boiler/duct stiffening included.

• No impact on potential ash sales.

• Reagent is ammonia and natural gas. If NO x Star Plus, only single layer in-duct catalyst installed.

State of Availability Available.
State of Applicability Not applicable.
Technical Feasibility No commercial deployment of technology. Only proven at one site . Not technically feasible. Undeveloped data fields will be mar ked as “NA.”PNM San Juan Generating Station Appendix B

060607 B-10 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology ECOTUBE

Process Description Injection of high-velocity air into boiler. A mmonia/urea can be added into air for additional NO x reduction.

Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 2,082,166 2,082,819 3,205,572 3,144,890 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Ammonia or Urea) NA lb/h Energy NA kW Maintenance 3% of direct material cost. Byproduct Description No impact on ash sales. Other 5ppm ammonia slip.

Location of Major Process Equipment Injection skid an d urea tank at grade with truck unloading station. Install water-cooled, retractable lances at to be determined location in boiler. Inlet/Outlet Connections and Interconnecti ng Ducts Tie-in to existing air duct.
Reagent Storage Tank at grade.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements Penetrations into boiler wall.
Major Constructability Issues None.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning. Other Assumptions:

• No major impact in plant availability.

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

• No air heater modifications or boiler/duct stiffening included.

• No impact on potential ash sales.

• Reagent is ammonia or urea.

State of Availability Available. State of Applicability Not applicable. Largest coal boiler application of 175 MW. Technical Feasibility Not technically feasible due to applicability. Undeveloped data fields will be marked as “NA.”PNM San Juan Generating Station Appendix B

060607 B-11 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology PowerSpan

Process Description Install PowerSpan process equipment train for multi-pollutant control (NO x , SO 2 , Hg). Process is based on oxidation and capture of pollutants in flue gas stream.

Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 1,620,055 1,611,752 2,516,395 2,468,760 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Ammonia) NA lb/h Water NA gpm Energy NA kW Maintenance 3% of direct material cost. Byproduct Description Commercial grade fertilizer (ammonium sulfate). Other None.

Location of Major Process Equipment ECO reactor and ammonia scrubber with wet ESP located downstream of PJFF. Ammonia reagent preparation and byproduct processing equi pment located in a dedicated building. Inlet/Outlet Connections and Interconnecting Ducts Equipment train connected to booster fan discharge downstream of PJFF. Reagent Storage Ammonia storage and preparation system required
Control System Modifications Incorpor ated into existing control system.

Fan Modifications Assume additional fan capacity will be required.
Power Supply/Aux Power Modifications Aux electric system upgr ade will be required for additional fan capacity, ECO reactor operations, ammonia preparation and deliver y system, scrubber operation and wet ESP operation. Enclosures Requirements Enclosures for amm onia reagent preparation and byproduct processing.
Demolition or Relocation Requirements Remove existing wet FGD, reroute ductwork to new equipment train.
Major Constructability Issues Site area availability for new equipment train and associated r eagent preparation and byproduct processing equipment. Significant Issues or Challenges Recover ed byproduct cannot be landfilled. Fertilizer material to be used by nearby agricultur e industry. Other Assumptions:

• No major impact in plant availability.

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

• Assumed byproduct can be disposed to nearby agriculture industry.

• Reagent is ammonia.

State of Availability Available.
State of Applicability Not applicable. Small-scale testing recently completed. First small-scale commercial implementation in progress.
Technical Feasibility Not technically feasible. Undeveloped data fields will be marked as “NA.”PNM San Juan Generating Station Appendix B

060607 B-12 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology Phenix Clean Combustion System

Process Description Boiler combustion system conversion to t he Phenix Clean Combustion System (CCS). Process is based on gasification of coal upstream of the regular boiler combustion system.

Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 2,082,166 2,082,819 3,205,572 3,144,890 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Urea) NA lb/h Water NA gpm Energy NA kW Maintenance 3% of direct material cost. Byproduct Description Combustion byproduct (slag). Other None

Location of Major Process Equipment Coal gasification process equipment integrated in to boiler combustion system. Limestone preparation and delivery system located at coal gasification process zone. Inlet/Outlet Connections and Interconnecting Ducts Connection to boiler combustion equipment. Reagent Storage None.
Control System Modifications Coal gas ification control system integrated into boiler combustion control system.

Fan Modifications None.
Power Supply/Aux Power Modifications Aux electric system upgrad e will be required for the limestone preparation system and slag removal system. Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements Reconfiguration of exis ting boiler required to integrat e gasification process equipment. Downstream AQC equipment left in place for contingency purpose. Major Constructability Issues Access to boiler building and modi fications of boiler combustion systems to retrofit coal gasification process equipment. Significant Issues or Challenges None.
Other Assumptions:

• No major impact in plant availability.

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

• No air heater modifications or included.

• No fly ash produced. Ash sales will be impacted.

State of Availability Available.
State of Applicability Not applicable. Still in development stage, no full-scale commercial implementation yet.
Technical Feasibility Not technically feasible. Undeveloped data fields will be marked as “NA.”PNM San Juan Generating Station Appendix B

060607 B-13 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology e-SCRUB

Process Description Install e-SCRUB process equipment train for multi-pollutant control (NO x , SO 2 , Hg). Process is based on oxidation and capture of pollutants in flue gas stream. Byproduct is processed using spray dryer and particulate collector system.

Pollutant NO x (Unit 1) NO x (Unit 2) NO x (Unit 3) NO x (Unit 4) Emissions lb/MBtu 0.30 0.30 0.30 0.30 lb/h 1,112 1,106 1,727 1,695 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 1,620,055 1,611,752 2,516,395 2,468,760 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (Ammonia) NA lb/h Water NA gpm Energy NA kW Maintenance 3% of direct material cost. Byproduct Description Commercial grade fertilizer (ammonium sulfate). Other None.

Location of Major Process Equipment Spray dryer absorber and parti culate collector system for byproduct drying located upstream of actual e-SCRUB process. e-Beam buildi ng and wet ESP located downstream of PJFF. Ammonia reagent preparation and delivery system is upstream of the e-Beam building. Inlet/Outlet Connections and Interconnecting Ducts Process equipment is located after booster fans downstream of PJFF. Reagent Storage Ammonia storage and preparation system required
Control System Modifications Incorpor ated into existing control system.

Fan Modifications Assume additional fan capacity will be required.
Power Supply/Aux Power Modifications Aux electric system upgrad e will be required for additional fan capacity, e-Beam operation s, ammonia preparation and delivery system, scrubber operation and wet ESP operation. Enclosures Requirements Enclosures for ammonia reagent preparation.
Demolition or Relocation Requirements Remove existing wet FGD, reroute ductwork to new equipment train.
Major Constructability Issues Site area availability for ne w equipment train and associated reagent preparation and byproduct processing equipment. Significant Issues or Challenges Recover ed byproduct cannot be landfilled. Fertilizer material to be used by nearby agricultur e industry. Other Assumptions:

• No major impact in plant availability.

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

• Assumed byproduct can be disposed to nearby agriculture industry.

• Reagent is ammonia.

State of Availability Available.
State of Applicability Not applicable. Still in development stage, no full-scale commercial implementation yet.
Technical Feasibility Not technically feasible. Undeveloped data fields will be marked as “NA.”PNM San Juan Generating Station Appendix B

060607 B-14 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology Flue Gas Conditioning with Hot-side ESP

Process Description Install flue gas conditioning system upstr eam of existing hot-side ESP. Process is based on addition of ammonia or SO 3 into flue gas upstream of hot-side ESP to augment fly ash resistivity.

Pollutant PM (Unit 1) PM (Unit 2) PM (Unit 3) PM (Unit 4) Emissions lb/MBtu 17.6 17.6 17.6 17.6 lb/h 65,144 64,810 101,187 99,271 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 2,082,166 2,082,819 3,205,572 3,144,890 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent (NH 3 /SO 3 ) NA lb/h Energy NA kW Maintenance 3% of direct material cost. Byproduct Description No impact on ash sales. Other None.

Location of Major Process Equipment Flue gas conditioning reagent delivery system in ductwork upstream of ESP.
Inlet/Outlet Connections and Interconnecting Du cts Ductwork connection upstream of ESP.
Reagent Storage Reagent preparation and stor age for flue gas conditioning at grade.
Control System Modifications New stand-alone contro l system, tie in to plant DCS control system.

Fan Modifications None.
Power Supply/Aux Power Modifications Minor aux electric system modification requi red for reagent preparation and delivery syste ms. Enclosures Requirements No addi tional enclosures required.
Demolition or Relocation Requirements Demolition of ductwork upstream of ESP for retrofit.
Major Constructability Issues None.
Significant Issues or Challenges Pl anned outage required for retrofit project.
Other Assumptions

• No major impact on plant availability.

• Determination of type of reagent and quantity of injection based on further study and trial of flue gas conditioning agents.

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

State of Availability Available.
State of Applicability Not applicable.
Technical Feasibility Not technically feasible because new PJFF retrofit capable of achieving similar controlled em issions level. Undeveloped data fi elds will be marked as “NA.”PNM San Juan Generating Station Appendix B

060607 B-15 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology Compact Hybrid Particulate Collector

Process Description Add a high air-to-cloth ratio fabric filter (COHPAC) as a polishing filter downstream of existing ESP.

Pollutant PM (Unit 1) PM (Unit 2) PM (Unit 3) PM (Unit 4) Emissions lb/MBtu 8.8 8.8 8.8 8.8 lb/h 32,572 32,405 50,593 49,636 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 1,518,669 1,517,269 2,267,380 2,224,459 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent None Energy NA kW Maintenance 3% of direct material cost (not including fabric filter bag and cage replacement) Byproduct Description Fly ash. Other N/A.

Location of Major Process Equipment COHPAC located downstream of air heater and upstream of FGD booster fans. New ash handling system also installed. Inlet/Outlet Connections and Interconnecting Ducts Ductwork connec tion downstream of air heater outlet and upstream of FGD boos ter fans.
Reagent Storage None.
Control System Modifications New stand-alone contro l system, tie in to plant DCS control system.

Fan Modifications FGD booster fan modifications required to over come additional pressure drop.
Power Supply/Aux Power Modifications Au x electric system modification requir ed for bag cleaning system, FGD booster fan modifications, and ash handling system. Enclosures Requirements COHPAC designed with penthouse.
Demolition or Relocation Requirements Replace existing ductwork with connections to COHPAC.
Major Constructability Issues Si te access to construction site.
Significant Issues or Challenges Planned ma jor outage required for retrofit project.
Other Assumptions

• No major impact in plant availability.

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

• Fabric filter bag life is 3 years. Fabric filter cage life is 6 years.

• COHPAC can be used as a component for Hg removal systems.

State of Availability Available.
State of Applicability Not applicable.
Technical Feasibility Not technically feasible because new PJFF retrofit capable of achieving similar controlled em issions level. Undeveloped data fi elds will be marked as “NA.”PNM San Juan Generating Station Appendix B

060607 B-16 

### Design Concept Definition

Site Name San Juan Generating Station Units 1, 2, 3, 4 Client Name PNM Process Technology Max-9 Electrostatic Fabric Filter

Process Description Retrofit new Max-9 Electrostatic Fabric F ilter (ESFF) system into flue gas path, upstream of wet FGD. Existing hot-side ESP wi ll be de-energized and left in place.

Pollutant PM (Unit 1) PM (Unit 2) PM (Unit 3) PM (Unit 4) Emissions lb/MBtu 8.8 8.8 8.8 8.8 lb/h 32,572 32,405 50,593 49,636 Controlled Emissions lb/MBtu NA NA NA NA lb/h NA NA NA NA Inlet Flow Basis, acfm 1,518,669 1,517,269 2,267,380 2,224,459 Pressure Drop Added, in. wg NA Coal Source and Type New Mexico, Subbituminous Capacity Factor 85.0%

Consumables Reagent None Energy NA kW Maintenance 3% of direct material cost (not including fabric filter bag and cage replacement). Byproduct Description Fly ash. Other None.

Location of Major Process Equipment Max-9 located downstream of air heater and upstream of FGD booster fans. New ash handling system also installed. Inlet/Outlet Connections and Interconnecting Ducts Ductwork connec tion downstream of air heater outlet and upstream of FGD boos ter fans.
Reagent Storage None.
Control System Modifications New stand-alone contro l system, tie in to plant DCS control system.

Fan Modifications FGD booster fan modifications required to over come additional pressure drop.
Power Supply/Aux Power Modifications Au x electric system modification requir ed for bag cleaning system, FGD booster fan modifications, and ash handling system. Enclosures Requirements Ma x-9 designed with penthouse.
Demolition or Relocation Requirements Replace existing ductwork with connections to Max-9.
Major Constructability Issues Si te access to construction site.
Significant Issues or Challenges Planned ma jor outage required for retrofit project.
Other Assumptions

• No major impact in plant availability.

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

• Fabric filter bag life is 3 years. Fabric filter cage life is 6 years.

• Max-9 can be used as a component for Hg removal systems.

State of Availability Available.
State of Applicability Not applicable.
Technical Feasibility Not technically feasible because there are no commercial applic ations on SJGS sized flue gas system. Undeveloped data fields wi ll be marked as “NA.”PNM San Juan Generating Station Appendix C

060607 C-1 

## Appendix C Cost Analysis SummaryPNM San Juan Generating Station Appendix C

060607 C-2 

## Low NO x 

## Burners (LNB) and Overfire Air (OFA)PNM San Juan Generating Station Appendix C

060607 C-3 Technology: Low NOx Burners & OFA - SJGS Unit 1 Date: 4/25/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs LNB-OFA system scope: $5,639,000 PNM environmental upgrade cost Low NOx Burners Dual Zone NOx Ports Boiler Modifications Ductwork Access Platforms CFD Modeling Control System Modificatons Balance of plant modificatons $689,000 PNM environmental upgrade cost Subtotal capital cost (CC) $6,328,000 Gross Receipt Tax $665,000 PNM environmental upgrade cost Total purchased equipment cost (PEC) $6,993,000

Direct installation costs Project construction costs $4,946,000 PNM environmental upgrade cost Total direct installation costs (DIC) $4,946,000

Total direct costs (DC) = (PEC) + (DIC) $11,939,000

Indirect Costs Engineering $149,000 PNM environmental upgrade cost Owner's cost $345,000 PNM environmental upgrade cost Construction management $597,000 (DC) X 5.0% Start-up and spare parts $239,000 (DC) X 2.0% Performance test $50,000 Engineering estimate Contingencies $740,000 PNM environmental upgrade cost Total indirect costs (IC) $2,120,000

Interest During Construction (IDC) $521,000 [(DC)+(IC)] X 7.41% 1 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) $14,580,000

ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance labor $2,000 B&V estimate, 1 man week/yr Total fixed annual costs $2,000

Variable annual costs N/A $0 No associated annual cost Total variable annual costs $0

Total direct annual costs (DAC) $2,000

Indirect Annual Costs Cost for capital recovery $1,420,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $1,420,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,422,000PNM San Juan Generating Station Appendix C

060607 C-4 Technology: Low NOx Burners & OFA - SJGS Unit 2 Date: 4/25/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs LNB-OFA system scope: $5,184,000 PNM environmental upgrade cost Low NOx Burners Dual Zone NOx Ports Boiler Modifications Ductwork Access Platforms CFD Modeling Control System Modificatons Balance of plant modificatons $742,000 PNM environmental upgrade cost Subtotal capital cost (CC) $5,926,000 Gross Receipt Tax $645,000 PNM environmental upgrade cost Total purchased equipment cost (PEC) $6,571,000

Direct installation costs Project construction costs $5,014,000 PNM environmental upgrade cost Total direct installation costs (DIC) $5,014,000

Total direct costs (DC) = (PEC) + (DIC) $11,585,000

Indirect Costs Engineering $141,000 PNM environmental upgrade cost Owner's cost $334,000 PNM environmental upgrade cost Construction management $579,000 (DC) X 5.0% Start-up and spare parts $232,000 (DC) X 2.0% Performance test $50,000 Engineering estimate Contingencies $700,000 PNM environmental upgrade cost Total indirect costs (IC) $2,036,000

Interest During Construction (IDC) $505,000 [(DC)+(IC)] X 7.41% 1 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) $14,126,000

ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance labor $2,000 B&V estimate, 1 man week/yr Total fixed annual costs $2,000

Variable annual costs N/A $0 No associated annual cost Total variable annual costs $0

Total direct annual costs (DAC) $2,000

Indirect Annual Costs Cost for capital recovery $1,376,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $1,376,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,378,000PNM San Juan Generating Station Appendix C

060607 C-5 Technology: Low NOx Burners & OFA - SJGS Unit 3 Date: 4/25/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs LNB-OFA system scope: $4,431,000 PNM environmental upgrade cost Low NOx Burners Dual Zone NOx Ports Boiler Modifications Ductwork Access Platforms CFD Modeling Control System Modificatons Balance of plant modificatons $658,000 PNM environmental upgrade cost Subtotal capital cost (CC) $5,089,000 Gross Receipt Tax $597,000 PNM environmental upgrade cost Total purchased equipment cost (PEC) $5,686,000

Direct installation costs Project construction costs $5,035,000 PNM environmental upgrade cost Total direct installation costs (DIC) $5,035,000

Total direct costs (DC) = (PEC) + (DIC) $10,721,000

Indirect Costs Engineering $177,000 PNM environmental upgrade cost Owner's cost $311,000 PNM environmental upgrade cost Construction management $536,000 (DC) X 5.0% Start-up and spare parts $214,000 (DC) X 2.0% Performance test $50,000 Engineering estimate Contingencies $252,000 PNM environmental upgrade cost Total indirect costs (IC) $1,540,000

Interest During Construction (IDC) $454,000 [(DC)+(IC)] X 7.41% 1 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) $12,715,000

ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance labor $2,000 B&V estimate, 1 man week/yr Total fixed annual costs $2,000

Variable annual costs N/A $0 No associated annual cost Total variable annual costs $0

Total direct annual costs (DAC) $2,000

Indirect Annual Costs Cost for capital recovery $1,238,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $1,238,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,240,000PNM San Juan Generating Station Appendix C

060607 C-6 Technology: Low NOx Burners & OFA - SJGS Unit 4 Date: 4/25/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs LNB-OFA system scope: $4,663,000 PNM environmental upgrade cost Low NOx Burners Dual Zone NOx Ports Boiler Modifications Ductwork Access Platforms CFD Modeling Control System Modificatons Balance of plant modificatons $753,000 PNM environmental upgrade cost Subtotal capital cost (CC) $5,416,000 Gross Receipt Tax $605,000 PNM environmental upgrade cost Total purchased equipment cost (PEC) $6,021,000

Direct installation costs Project construction costs $4,836,000 PNM environmental upgrade cost Total direct installation costs (DIC) $4,836,000

Total direct costs (DC) = (PEC) + (DIC) $10,857,000

Indirect Costs Engineering $177,000 PNM environmental upgrade cost Owner's cost $314,000 PNM environmental upgrade cost Construction management $543,000 (DC) X 5.0% Start-up and spare parts $217,000 (DC) X 2.0% Performance test $50,000 Engineering estimate Contingencies $252,000 PNM environmental upgrade cost Total indirect costs (IC) $1,553,000

Interest During Construction (IDC) $460,000 [(DC)+(IC)] X 7.41% 1 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) $12,870,000

ANNUAL COST Direct Annual Costs Fixed annual costs Maintenance labor $2,000 B&V estimate, 1 man week/yr Total fixed annual costs $2,000

Variable annual costs N/A $0 No associated annual cost Total variable annual costs $0

Total direct annual costs (DAC) $2,000

Indirect Annual Costs Cost for capital recovery $1,254,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $1,254,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,256,000PNM San Juan Generating Station Appendix C

060607 C-7 

## Pulse Jet Fabric Filter (PJFF)PNM San Juan Generating Station Appendix C

060607 C-8 Technology: Pulse Jet Fabric Filter - SJGS Unit 1 Date: 4/25/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs

Purchased equipment costs

PJFF system scope $9,020,000 PNM environmental upgrade cost Ductwork $812,000 PNM environmental upgrade cost Ash handling system scope $1,155,000 PNM environmental upgrade cost Booster fan modifications $3,434,000 PNM environmental upgrade cost Balance of plant modifications $3,938,000 PNM environmental upgrade cost

Subtotal capital cost (CC) $18,359,000 Gross Receipt Tax $2,855,000 PNM environmental upgrade cost

Total purchased equipment cost (PEC) $21,214,000

Direct installation costs

PJFF construction cost $7,543,000 PNM environmental upgrade cost Ductwork construction cost $10,958,000 PNM environmental upgrade cost Ash handling construction cost $475,000 PNM environmental upgrade cost Booster fan construction cost $1,283,000 PNM environmental upgrade cost Balance of plant construction cost $8,099,000 PNM environmental upgrade cost

Total direct installation costs (DIC) $28,358,000

Total direct costs (DC) = (PEC) + (DIC) $49,572,000

Indirect Costs

Engineering $2,304,000 PNM environmental upgrade cost Owner's cost $1,479,000 PNM environmental upgrade cost Construction management $4,957,000 (DC) X 10.0% Start-up and spare parts $744,000 (DC) X 1.5% Performance test $100,000 Engineering estimate Contingencies $3,289,000 PNM environmental upgrade cost

Total indirect costs (IC) $12,873,000

Interest During Construction (IDC) $4,627,000 [(DC)+(IC)] X 7.41% 2 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) $67,072,000

ANNUAL COST Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $1,487,000 (DC) X 3.0%

Total fixed annual costs $1,487,000

Variable annual costs Bag replacement cost $296,000 2,957 bags and 100 $/bag B&W bag offerings, 3 yr replacements Cage replacement cost $74,000 1,478 cages and 50 $/cage B&W cage offerings, 6 yr replacements ID fan power $1,828,000 4,028 kW and 0.06095 $/kWh B&W guarantees, 15 in. H 2 O d.p. Auxiliary power $209,000 460 kW and 0.06095 $/kWh Engineering estimate

Total variable annual costs $2,407,000

Total direct annual costs (DAC) $3,894,000

Indirect Annual Costs

Cost for capital recovery $6,533,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $6,533,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $10,427,000PNM San Juan Generating Station Appendix C

060607 C-9 Technology: Pulse Jet Fabric Filter - SJGS Unit 2 Date: 4/25/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs

Purchased equipment costs

PJFF system scope $8,658,000 PNM environmental upgrade cost Ductwork $904,000 PNM environmental upgrade cost Ash handling system scope $1,155,000 PNM environmental upgrade cost Booster fan modifications $3,434,000 PNM environmental upgrade cost Balance of plant modifications $4,072,000 PNM environmental upgrade cost

Subtotal capital cost (CC) $18,223,000 Gross Receipt Tax $2,977,000 PNM environmental upgrade cost

Total purchased equipment cost (PEC) $21,200,000

Direct installation costs

PJFF construction cost $7,412,000 PNM environmental upgrade cost Ductwork construction cost $13,335,000 PNM environmental upgrade cost Ash handling construction cost $472,000 PNM environmental upgrade cost Booster fan construction cost $1,283,000 PNM environmental upgrade cost Balance of plant construction cost $8,139,000 PNM environmental upgrade cost

Total direct installation costs (DIC) $30,641,000

Total direct costs (DC) = (PEC) + (DIC) $51,841,000

Indirect Costs

Engineering $2,238,000 PNM environmental upgrade cost Owner's cost $1,541,000 PNM environmental upgrade cost Construction management $5,184,000 (DC) X 10.0% Start-up and spare parts $778,000 (DC) X 1.5% Performance test $100,000 Engineering estimate Contingencies $3,340,000 PNM environmental upgrade cost

Total indirect costs (IC) $13,181,000

Interest During Construction (IDC) $4,818,000 [(DC)+(IC)] X 7.41% 2 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) $69,840,000

ANNUAL COST Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $1,555,000 (DC) X 3.0%

Total fixed annual costs $1,555,000

Variable annual costs Bag replacement cost $296,000 2,957 bags and 100 $/bag B&W bag offerings, 3 yr replacements Cage replacement cost $74,000 1,478 cages and 50 $/cage B&W cage offerings, 6 yr replacements ID fan power $1,828,000 4,028 kW and 0.06095 $/kWh B&W guarantees, 15 in. H 2 O d.p. Auxiliary power $209,000 460 kW and 0.06095 $/kWh Engineering estimate

Total variable annual costs $2,407,000

Total direct annual costs (DAC) $3,962,000

Indirect Annual Costs

Cost for capital recovery $6,802,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $6,802,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $10,764,000PNM San Juan Generating Station Appendix C

060607 C-10 Technology: Pulse Jet Fabric Filter - SJGS Unit 3 Date: 4/25/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs

Purchased equipment costs

PJFF system scope $10,901,000 PNM environmental upgrade cost Ductwork $1,364,000 PNM environmental upgrade cost Ash handling system scope $977,000 PNM environmental upgrade cost Booster fan modifications $2,871,000 PNM environmental upgrade cost Balance of plant modifications $4,733,000 PNM environmental upgrade cost

Subtotal capital cost (CC) $20,846,000 Gross Receipt Tax $3,183,000 PNM environmental upgrade cost

Total purchased equipment cost (PEC) $24,029,000

Direct installation costs

PJFF construction cost $11,089,000 PNM environmental upgrade cost Ductwork construction cost $9,007,000 PNM environmental upgrade cost Ash handling construction cost $706,000 PNM environmental upgrade cost Booster fan construction cost $1,403,000 PNM environmental upgrade cost Balance of plant construction cost $9,286,000 PNM environmental upgrade cost

Total direct installation costs (DIC) $31,491,000

Total direct costs (DC) = (PEC) + (DIC) $55,520,000

Indirect Costs

Engineering $2,535,000 PNM environmental upgrade cost Owner's cost $1,655,000 PNM environmental upgrade cost Construction management $5,552,000 (DC) X 10.0% Start-up and spare parts $833,000 (DC) X 1.5% Performance test $100,000 Engineering estimate Contingencies $1,486,000 PNM environmental upgrade cost

Total indirect costs (IC) $12,161,000

Interest During Construction (IDC) $5,015,000 [(DC)+(IC)] X 7.41% 2 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) $72,696,000

ANNUAL COST Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $1,666,000 (DC) X 3.0%

Total fixed annual costs $1,666,000

Variable annual costs Bag replacement cost $462,000 4,620 bags and 100 $/bag B&W bag offerings, 3 yr replacements Cage replacement cost $116,000 2,310 cages and 50 $/cage B&W cage offerings, 6 yr replacements ID fan power $2,856,000 6,294 kW and 0.06095 $/kWh B&W guarantees, 15 in. H 2 O d.p. Auxiliary power $273,000 601 kW and 0.06095 $/kWh Engineering estimate

Total variable annual costs $3,707,000

Total direct annual costs (DAC) $5,373,000

Indirect Annual Costs

Cost for capital recovery $7,081,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $7,081,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $12,454,000PNM San Juan Generating Station Appendix C

060607 C-11 Technology: Pulse Jet Fabric Filter - SJGS Unit 4 Date: 4/25/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs

Purchased equipment costs

PJFF system scope $12,572,000 PNM environmental upgrade cost Ductwork $1,479,000 PNM environmental upgrade cost Ash handling system scope $932,000 PNM environmental upgrade cost Booster fan modifications $2,870,000 PNM environmental upgrade cost Balance of plant modifications $5,040,000 PNM environmental upgrade cost

Subtotal capital cost (CC) $22,893,000 Gross Receipt Tax $3,212,000 PNM environmental upgrade cost

Total purchased equipment cost (PEC) $26,105,000

Direct installation costs

PJFF construction cost $10,937,000 PNM environmental upgrade cost Ductwork construction cost $7,946,000 PNM environmental upgrade cost Ash handling construction cost $685,000 PNM environmental upgrade cost Booster fan construction cost $1,406,000 PNM environmental upgrade cost Balance of plant construction cost $8,856,000 PNM environmental upgrade cost

Total direct installation costs (DIC) $29,830,000

Total direct costs (DC) = (PEC) + (DIC) $55,935,000

Indirect Costs

Engineering $2,645,000 PNM environmental upgrade cost Owner's cost $1,670,000 PNM environmental upgrade cost Construction management $5,594,000 (DC) X 10.0% Start-up and spare parts $839,000 (DC) X 1.5% Performance test $100,000 Engineering estimate Contingencies $1,486,000 PNM environmental upgrade cost

Total indirect costs (IC) $12,334,000

Interest During Construction (IDC) $5,059,000 [(DC)+(IC)] X 7.41% 2 years (project time length X 1/2)

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) $73,328,000

ANNUAL COST Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $1,678,000 (DC) X 3.0%

Total fixed annual costs $1,678,000

Variable annual costs Bag replacement cost $462,000 4,620 bags and 100 $/bag B&W bag offerings, 3 yr replacements Cage replacement cost $116,000 2,310 cages and 50 $/cage B&W cage offerings, 6 yr replacements ID fan power $2,856,000 6,294 kW and 0.06095 $/kWh B&W guarantees, 15 in. H 2 O d.p. Auxiliary power $273,000 601 kW and 0.06095 $/kWh Engineering estimate

Total variable annual costs $3,707,000

Total direct annual costs (DAC) $5,385,000

Indirect Annual Costs

Cost for capital recovery $7,142,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $7,142,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $12,527,000PNM San Juan Generating Station Appendix C

060607 C-12 

## Selective Catalytic Reduction (SCR)PNM San Juan Generating Station Appendix C

060607 C-13 Technology: Selective Catalytic Reduction - SJGS Unit 1 Date: 5/31/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs

Anhydrous Ammonia Injection System $437,000 B&V cost estimate Anhydrous Ammonia Vaporization System $436,000 B&V cost estimate Reactor Box, Breeching and Ductwork $4,451,000 B&V cost estimate Ductwork Expansion Joints $294,000 B&V cost estimate Catalyst $2,557,000 B&V cost estimate Sonic Horns $188,000 B&V cost estimate Elevator $1,236,000 B&V cost estimate Structural Steel $4,881,000 B&V cost estimate SCR Bypass $10,000,000 B&V cost estimate NOx Monitoring System $440,000 B&V cost estimate Electrical System Upgrade $378,000 B&V cost estimate Instrumentation and Control System $279,000 B&V cost estimate Subtotal capital cost (CC) $25,577,000 Gross Receipt Tax $1,583,000 (CC) X 6.2% Freight $1,279,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $28,439,000

Direct installation costs Foundation & supports $8,532,000 (PEC) X 30.0% Handling & erection $8,532,000 (PEC) X 30.0% Electrical $4,266,000 (PEC) X 15.0% Piping $711,000 (PEC) X 2.5% Insulation $2,844,000 (PEC) X 10.0% Painting $284,000 (PEC) X 1.0% Demolition $2,844,000 (PEC) X 10.0% Relocation $1,422,000 (PEC) X 5.0%

Total direct installation costs (DIC) $29,435,000

Air preheater modifications $1,071,000 B&V cost estimate Balanced draft conversion $13,366,000 B&V cost estimate Site preparation $2,000,000 Engineering estimate Buildings & enclosures $500,000 Engineering estimate Total direct costs (DC) = (PEC) + (DIC) $74,811,000

Indirect Costs Engineering $5,237,000 (DC) X 7.0% Owner's cost $3,741,000 (DC) X 5.0% Construction management $7,481,000 (DC) X 10.0% Construction indirect $18,344,000 B&V labor market review Start-up and spare parts $2,244,000 (DC) X 3.0% Performance test $200,000 Engineering estimate Contingencies $14,962,000 (DC) X 20.0% Total indirect costs (IC) $52,209,000

Interest During Construction (IDC) $14,118,000 [(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) Loss Generation during Outage (GEN) $15,667,000 5 weeks and 0.06095 $/kWh 12 weeks required for BDC, 7 weeks major outage available

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) + (GEN) $156,805,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $125,000 1 FTE and 124,862 $/year Estimated manpower level Maintenance labor & materials $2,244,000 (DC) X 3.0% Yearly emissions testing $25,000 Engineering estimate Catalyst activity testing $5,000 Engineering estimate Fly ash sampling and analysis $20,000 Engineering estimate

Total fixed annual costs $2,419,000

Variable annual costs Reagent $911,000 350 lb/hr and 700 $/ton B&V Calculated Auxiliary and ID fan power $1,496,000 3,296 kW and 0.06095 $/kWh B&V Calculated Catalyst replacement $426,000 66 m 3 and 6,500 $/m 3 2 yr catalyst replacement rate Total variable annual costs $2,833,000

Total direct annual costs (DAC) $5,252,000

Indirect Annual Costs Cost for capital recovery $15,273,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $15,273,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $20,525,000PNM San Juan Generating Station Appendix C

060607 C-14 Technology: Selective Catalytic Reduction - SJGS Unit 2 Date: 5/31/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs

Anhydrous Ammonia Injection System $429,000 B&V cost estimate Anhydrous Ammonia Vaporization System $429,000 B&V cost estimate Reactor Box, Breeching and Ductwork $4,444,000 B&V cost estimate Ductwork Expansion Joints $294,000 B&V cost estimate Catalyst $2,553,000 B&V cost estimate Sonic Horns $188,000 B&V cost estimate Elevator $1,236,000 B&V cost estimate Structural Steel $5,998,000 B&V cost estimate SCR Bypass $10,000,000 B&V cost estimate NOx Monitoring System $44 0,000 B&V cost estimate Electrical System Upgrade $372,000 B&V cost estimate Instrumentation and Control Sy stem $278,000 B&V cost estimate Subtotal capital cost (CC) $26,661,000 Gross Receipt Tax $1,650,000 (CC) X 6.2% Freight $1,333,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $29,644,000

Direct installation costs Foundation & supports $8,893,000 (PEC) X 30.0% Handling & erection $11,858,000 (PEC) X 40.0% Electrical $4,447,000 (PEC) X 15.0% Piping $741,000 (PEC) X 2.5% Insulation $2,964,000 (PEC) X 10.0% Painting $296,000 (PEC) X 1.0% Demolition $2,964,000 (PEC) X 10.0% Relocation $1,482,000 (PEC) X 5.0%

Total direct installation costs (DIC) $33,645,000

Air preheater modifications $1,071,000 B&V cost estimate Balanced draft conversion $13,366,000 B&V cost estimate Site preparation $2,000,000 Engineering estimate Buildings & enclosures $500,000 Engineering estimate Total direct costs (DC) = (PEC) + (DIC) $80,226,000

Indirect Costs Engineering $5,616,000 (DC) X 7.0% Owner's cost $4,011,000 (DC) X 5.0% Construction management $8,023,000 (DC) X 10.0% Construction indirect $22,085,000 B&V labor market review Start-up and spare parts $2,407,000 (DC) X 3.0% Performance test $200,000 Engineering estimate Contingencies $16,045,000 (DC) X 20.0% Total indirect costs (IC) $58,387,000

Interest During Construction (IDC) $15,407,000 [(DC)+( IC)] X 7.41% 3 years (proje ct time length X 1/2) Loss Generation during Outage (GEN) $15,231,000 5 w eeks and 0.06095 $/kWh 12 weeks required for BDC, 7 weeks major outage available

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) + (GEN) $169,251,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $125,000 1 FTE and 124,862 $/year Estimated manpower level Maintenance labor & materials $2,407,000 (DC) X 3.0% Yearly emissions testing $25,000 Engineering estimate Catalyst activity testing $5,000 Engineering estimate Fly ash sampling and analysis $20,000 Engineering estimate

Total fixed annual costs $2,582,000

Variable annual costs Reagent $906,000 348 lb/hr and 700 $/ton B&V Calculated Auxiliary and ID fan power $1,492,000 3,287 kW and 0.06095 $/kWh B&V Calculated Catalyst replacement $426,000 65 m 3 and 6,500 $/m 3 2 yr catalyst replacement rate Total variable annual costs $2,824,000

Total direct annual costs (DAC) $5,406,000

Indirect Annual Costs Cost for capital recovery $16,485,000 (TCI) X 9 .74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $16,485,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $21,891,000PNM San Juan Generating Station Appendix C

060607 C-15 Technology: Selective Catalytic Reduction - SJGS Unit 3 Date: 5/31/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs

Anhydrous Ammonia Injection System $559,000 B&V cost estimate Anhydrous Ammonia Vaporization System $559,000 B&V cost estimate Reactor Box, Breeching and Ductwork $5,613,000 B&V cost estimate Ductwork Expansion Joints $371,000 B&V cost estimate Catalyst $3,225,000 B&V cost estimate Sonic Horns $188,000 B&V cost estimate Elevator $1,236,000 B&V cost estimate SCR Bypass $10,000,000 B&V cost estimate Structural Steel $7,816,000 B&V cost estimate NOx Monitoring System $44 0,000 B&V cost estimate Electrical System Upgrade $484,000 B&V cost estimate Instrumentation and Control Sy stem $291,000 B&V cost estimate Subtotal capital cost (CC) $30,782,000 Gross Receipt Tax $1,905,000 (CC) X 6.2% Freight $1,539,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $34,226,000

Direct installation costs Foundation & supports $10,268,000 (PEC) X 30.0% Handling & erection $13,690,000 (PEC) X 40.0% Electrical $5,134,000 (PEC) X 15.0% Piping $856,000 (PEC) X 2.5% Insulation $3,423,000 (PEC) X 10.0% Painting $342,000 (PEC) X 1.0% Demolition $3,423,000 (PEC) X 10.0% Relocation $1,711,000 (PEC) X 5.0%

Total direct installation costs (DIC) $38,847,000

Air preheater modifications $8,685,000 B&V cost estimate Balanced draft conversion $17,122,000 B&V cost estimate Site preparation $2,000,000 Engineering estimate Buildings & enclosures $500,000 Engineering estimate Total direct costs (DC) = (PEC) + (DIC) $101,380,000

Indirect Costs Engineering $7,097,000 (DC) X 7.0% Owner's cost $5,069,000 (DC) X 5.0% Construction management $10,138,000 (DC) X 10.0% Construction indirect $25,498,000 B&V labor market review Start-up and spare parts $3,041,000 (DC) X 3.0% Performance test $200,000 Engineering estimate Contingencies $20,276,000 (DC) X 20.0% Total indirect costs (IC) $71,319,000

Interest During Construction (IDC) $19,195,000 [(DC)+( IC)] X 7.41% 3 years (proje ct time length X 1/2) Loss Generation during Outage (GEN) $23,674,000 5 w eeks and 0.06095 $/kWh 12 weeks required for BDC, 7 weeks major outage available

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) + (GEN) $215,568,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $125,000 1 FTE and 124,862 $/year Estimated manpower level Maintenance labor & materials $3,041,000 (DC) X 3.0% Yearly emissions testing $25,000 Engineering estimate Catalyst activity testing $5,000 Engineering estimate Fly ash sampling and analysis $20,000 Engineering estimate

Total fixed annual costs $3,216,000

Variable annual costs Reagent $1,415,000 543 lb/hr and 700 $/ton B&V Calculated Auxiliary and ID fan power $2,194,000 4,835 kW and 0.06095 $/kWh B&V Calculated Catalyst replacement $538,000 83 m 3 and 6,500 $/m 3 2 yr catalyst replacement rate Total variable annual costs $4,147,000

Total direct annual costs (DAC) $7,363,000

Indirect Annual Costs Cost for capital recovery $20,996,000 (TCI) X 9 .74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $20,996,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $28,359,000PNM San Juan Generating Station Appendix C

060607 C-16 Technology: Selective Catalytic Reduction - SJGS Unit 4 Date: 5/31/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs

Anhydrous Ammonia Injection System $559,000 B&V cost estimate Anhydrous Ammonia Vaporization System $559,000 B&V cost estimate Reactor Box, Breeching and Ductwork $5,648,000 B&V cost estimate Ductwork Expansion Joints $373,000 B&V cost estimate Catalyst $3,245,000 B&V cost estimate Sonic Horns $188,000 B&V cost estimate Elevator $1,236,000 B&V cost estimate Structural Steel $6,252,000 B&V cost estimate SCR Bypass $10,000,000 B&V cost estimate NOx Monitoring System $44 0,000 B&V cost estimate Electrical System Upgrade $484,000 B&V cost estimate Instrumentation and Control Sy stem $291,000 B&V cost estimate Subtotal capital cost (CC) $29,275,000 Gross Receipt Tax $1,811,000 (CC) X 6.2% Freight $1,464,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $32,550,000

Direct installation costs Foundation & supports $9,765,000 (PEC) X 30.0% Handling & erection $9,765,000 (PEC) X 30.0% Electrical $4,883,000 (PEC) X 15.0% Piping $814,000 (PEC) X 2.5% Insulation $3,255,000 (PEC) X 10.0% Painting $326,000 (PEC) X 1.0% Demolition $3,255,000 (PEC) X 10.0% Relocation $1,628,000 (PEC) X 5.0%

Total direct installation costs (DIC) $33,691,000

Air preheater modifications $8,685,000 B&V cost estimate Balanced draft conversion $17,122,000 B&V cost estimate Site preparation $2,000,000 Engineering estimate Buildings & enclosures $500,000 Engineering estimate Total direct costs (DC) = (PEC) + (DIC) $94,548,000

Indirect Costs Engineering $6,618,000 (DC) X 7.0% Owner's cost $4,727,000 (DC) X 5.0% Construction management $9,455,000 (DC) X 10.0% Construction indirect $20,996,000 B&V labor market review Start-up and spare parts $2,836,000 (DC) X 3.0% Performance test $200,000 Engineering estimate Contingencies $18,910,000 (DC) X 20.0% Total indirect costs (IC) $63,742,000

Interest During Construction (IDC) $17,594,000 [(DC)+( IC)] X 7.41% 3 years (proje ct time length X 1/2) Loss Generation during Outage (GEN) $23,674,000 5 w eeks and 0.06095 $/kWh 12 weeks required for BDC, 7 weeks major outage available

Total Capital Investment (TCI) = (DC) + (IC) + (IDC) + (GEN) $199,558,000

ANNUAL COST Direct Annual Costs Fixed annual costs Operating labor $125,000 1 FTE and 124,862 $/year Estimated manpower level Maintenance labor & materials $2,836,000 (DC) X 3.0% Yearly emissions testing $25,000 Engineering estimate Catalyst activity testing $5,000 Engineering estimate Fly ash sampling and analysis $20,000 Engineering estimate

Total fixed annual costs $3,011,000

Variable annual costs Reagent $1,388,000 533 lb/hr and 700 $/ton B&V Calculated Auxiliary and ID fan power $2,215,000 4,881 kW and 0.06095 $/kWh B&V Calculated Catalyst replacement $541,000 83 m 3 and 6,500 $/m 3 2 yr catalyst replacement rate Total variable annual costs $4,144,000

Total direct annual costs (DAC) $7,155,000

Indirect Annual Costs Cost for capital recovery $19,437,000 (TCI) X 9 .74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $19,437,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $26,592,000PNM San Juan Generating Station Appendix C

060607 C-17 

## SNCR/SCR Hybrid (Hybrid)PNM San Juan Generating Station Appendix C

060607 C-18 Technology: SNCR/SCR Hybrid - SJGS Unit 1 Date: 5/31/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs Hybrid system scope: $15,753,000 B&V cost development from vendor quote Reagent delivery system Wall injectors and multiple nozzle lances Automatic injector and lance retract system Flue gas temperature, NOx monitors Reagent storage tank Single layer catalyst SCR system Ductwork modifications Electrical system upgrades $378,000 Similar scope to SCR modifications Instrumentation and control system $279,000 Similar scope to SCR modifications

Subtotal capital cost (CC) $16,410,000 Gross Receipt Tax $1,015,000 (CC) X 6.2% Freight $821,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $18,246,000

Direct installation costs Foundation & supports $3,649,000 (PEC) X 20.0% Handling & erection $5,474,000 (PEC) X 30.0% Electrical $2,737,000 (PEC) X 15.0% Piping $456,000 (PEC) X 2.5% Insulation $1,825,000 (PEC) X 10.0% Painting $182,000 (PEC) X 1.0% Demolition $1,825,000 (PEC) X 10.0% Relocation $912,000 (PEC) X 5.0%

Total direct installation costs (DIC) $17,060,000

Air preheater modifications $1,071,000 B&V cost estimate Balanced draft conversion $13,366,000 B&V cost estimate Site preparation $1,000,000 Engineering estimate Buildings $200,000 Engineering estimate Total direct costs (DC) = (PEC) + (DIC) $50,943,000

Indirect Costs Engineering $3,566,000 (DC) X 7.0% Owner's cost $2,547,000 (DC) X 5.0% Construction management $5,094,000 (DC) X 10.0% Construction indirect $11,222,000 B&V labor market review Start-up and spare parts $1,528,000 (DC) X 3.0% Performance test $509,000 (DC) X 1.0% Contingencies $10,189,000 (DC) X 20.0%

Total indirect costs (IC) $34,655,000

Interest During Construction (IDC) $3,171,000 [(DC)+(IC)] X 7.41% 1 years (project time length X 1/2) Loss Generation during Outage (GEN) $15,667,000 5 weeks and 0.06095 $/kWh 12 weeks required for BDC, 7 weeks major outage available

Total Capital Investment (TCI) = (DC) + (IC) + (GEN) $104,436,000

ANNUAL COST Direct Annual Costs Fixed annual costs

Operating labor $125,000 1 FTE and 124,862 $/year Estimated manpower level Maintenance labor & materials $1,528,000 (DC) X 3.0%

Total fixed annual costs $1,653,000

Variable annual costs Urea $1,703,000 1,089 lb/hr and 420 $/ton Engineering estimate Water $1,762,000 252 gpm and 15.67 $/1,000 gal Engineering estimate Catalyst replacement $215,000 33 m3 and 6,500 $/m3 2 yr catalyst replacement rate Auxiliary power $32,000 70 kW and 0.06095 $/kWh Engineering estimate ID fan power $670,000 1,477 kW and 0.06095 $/kWh Engineering estimate

Total variable annual costs $4,382,000

Total direct annual costs (DAC) $6,035,000

Indirect Annual Costs

Cost for capital recovery $10,172,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $10,172,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $16,207,000PNM San Juan Generating Station Appendix C

060607 C-19 Technology: SNCR/SCR Hybrid - SJGS Unit 2 Date: 5/31/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs Hybrid system scope: $15,753,000 B&V cost development from vendor quote Reagent delivery system Wall injectors and multiple nozzle lances Automatic injector and lance retract system Flue gas temperature, NOx monitors Reagent storage tank Single layer catalyst SCR system Ductwork modifications Electrical system upgrades $372,000 Similar scope to SCR modifications Instrumentation and control system $278,000 Similar scope to SCR modifications

Subtotal capital cost (CC) $16,403,000 Gross Receipt Tax $1,015,000 (CC) X 6.2% Freight $820,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $18,238,000

Direct installation costs Foundation & supports $3,648,000 (PEC) X 20.0% Handling & erection $7,295,000 (PEC) X 40.0% Electrical $2,736,000 (PEC) X 15.0% Piping $456,000 (PEC) X 2.5% Insulation $1,824,000 (PEC) X 10.0% Painting $182,000 (PEC) X 1.0% Demolition $1,824,000 (PEC) X 10.0% Relocation $912,000 (PEC) X 5.0%

Total direct installation costs (DIC) $18,877,000

Air preheater modifications $1,071,000 B&V cost estimate Balanced draft conversion $13,366,000 B&V cost estimate Site preparation $1,000,000 Engineering estimate Buildings $200,000 Engineering estimate Total direct costs (DC) = (PEC) + (DIC) $52,752,000

Indirect Costs Engineering $3,693,000 (DC) X 7.0% Owner's cost $2,638,000 (DC) X 5.0% Construction management $5,275,000 (DC) X 10.0% Construction indirect $13,041,000 B&V labor market review Start-up and spare parts $1,583,000 (DC) X 3.0% Performance test $528,000 (DC) X 1.0% Contingencies $10,550,000 (DC) X 20.0%

Total indirect costs (IC) $37,308,000

Interest During Construction (IDC) $3,337,000 [(DC)+(IC)] X 7.41% 1 years (project time length X 1/2) Loss Generation during Outage (GEN) $15,231,000 5 weeks and 0.06095 $/kWh 12 weeks required for BDC, 7 weeks major outage available

Total Capital Investment (TCI) = (DC) + (IC) + (GEN) $108,628,000

ANNUAL COST Direct Annual Costs Fixed annual costs

Operating labor $125,000 1 FTE and 124,862 $/year Estimated manpower level Maintenance labor & materials $1,583,000 (DC) X 3.0%

Total fixed annual costs $1,708,000

Variable annual costs Urea $1,703,000 1,089 lb/hr and 420 $/ton Engineering estimate Water $1,762,000 252 gpm and 15.67 $/1,000 gal Engineering estimate Catalyst replacement $215,000 33 m3 and 6,500 $/m3 2 yr catalyst replacement rate Auxiliary power $32,000 70 kW and 0.06095 $/kWh Engineering estimate ID fan power $670,000 1,477 kW and 0.06095 $/kWh Engineering estimate

Total variable annual costs $4,382,000

Total direct annual costs (DAC) $6,090,000

Indirect Annual Costs

Cost for capital recovery $10,580,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $10,580,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $16,670,000PNM San Juan Generating Station Appendix C

060607 C-20 Technology: SNCR/SCR Hybrid - SJGS Unit 3 Date: 5/31/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs Hybrid system scope: $23,680,000 B&V cost development from vendor quote Reagent delivery system Wall injectors and multiple nozzle lances Automatic injector and lance retract system Flue gas temperature, NOx monitors Reagent storage tank Single layer catalyst SCR system Ductwork modifications Electrical system upgrades $484,000 Similar scope to SCR modifications Instrumentation and control system $291,000 Similar scope to SCR modifications

Subtotal capital cost (CC) $24,455,000 Gross Receipt Tax $1,513,000 (CC) X 6.2% Freight $1,223,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $27,191,000

Direct installation costs Foundation & supports $5,438,000 (PEC) X 20.0% Handling & erection $10,876,000 (PEC) X 40.0% Electrical $4,079,000 (PEC) X 15.0% Piping $680,000 (PEC) X 2.5% Insulation $2,719,000 (PEC) X 10.0% Painting $272,000 (PEC) X 1.0% Demolition $2,719,000 (PEC) X 10.0% Relocation $1,360,000 (PEC) X 5.0%

Total direct installation costs (DIC) $28,143,000

Air preheater modifications $8,685,000 B&V cost estimate Balanced draft conversion $17,122,000 B&V cost estimate Site preparation $1,000,000 Engineering estimate Buildings $200,000 Engineering estimate Total direct costs (DC) = (PEC) + (DIC) $82,341,000

Indirect Costs Engineering $5,764,000 (DC) X 7.0% Owner's cost $4,117,000 (DC) X 5.0% Construction management $8,234,000 (DC) X 10.0% Construction indirect $19,442,000 B&V labor market review Start-up and spare parts $2,470,000 (DC) X 3.0% Performance test $823,000 (DC) X 1.0% Contingencies $16,468,000 (DC) X 20.0%

Total indirect costs (IC) $57,318,000

Interest During Construction (IDC) $5,174,000 [(DC)+(IC)] X 7.41% 1 years (project time length X 1/2) Loss Generation during Outage (GEN) $23,674,000 5 weeks and 0.06095 $/kWh 12 weeks required for BDC, 7 weeks major outage available

Total Capital Investment (TCI) = (DC) + (IC) + (GEN) $168,507,000

ANNUAL COST Direct Annual Costs Fixed annual costs

Operating labor $125,000 1 FTE and 124,862 $/year Estimated manpower level Maintenance labor & materials $2,470,000 (DC) X 3.0%

Total fixed annual costs $2,595,000

Variable annual costs Urea $2,641,000 1,689 lb/hr and 420 $/ton Engineering estimate Water $2,658,000 380 gpm and 15.67 $/1,000 gal Engineering estimate Catalyst replacement $270,000 42 m3 and 6,500 $/m3 2 yr catalyst replacement rate Auxiliary power $32,000 70 kW and 0.06095 $/kWh Engineering estimate ID fan power $997,000 2,197 kW and 0.06095 $/kWh Engineering estimate

Total variable annual costs $6,598,000

Total direct annual costs (DAC) $9,193,000

Indirect Annual Costs

Cost for capital recovery $16,413,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $16,413,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $25,606,000PNM San Juan Generating Station Appendix C

060607 C-21 Technology: SNCR/SCR Hybrid - SJGS Unit 4 Date: 5/31/2007

Cost Item $ Remarks/Cost Basis

CAPITAL COST Direct Costs Purchased equipment costs Hybrid system scope: $23,680,000 B&V cost development from vendor quote Reagent delivery system Wall injectors and multiple nozzle lances Automatic injector and lance retract system Flue gas temperature, NOx monitors Reagent storage tank Single layer catalyst SCR system Ductwork modifications Electrical system upgrades $484,000 Similar scope to SCR modifications Instrumentation and control system $291,000 Similar scope to SCR modifications

Subtotal capital cost (CC) $24,455,000 Gross Receipt Tax $1,513,000 (CC) X 6.2% Freight $1,223,000 (CC) X 5.0%

Total purchased equipment cost (PEC) $27,191,000

Direct installation costs Foundation & supports $5,438,000 (PEC) X 20.0% Handling & erection $8,157,000 (PEC) X 30.0% Electrical $4,079,000 (PEC) X 15.0% Piping $680,000 (PEC) X 2.5% Insulation $2,719,000 (PEC) X 10.0% Painting $272,000 (PEC) X 1.0% Demolition $2,719,000 (PEC) X 10.0% Relocation $1,360,000 (PEC) X 5.0%

Total direct installation costs (DIC) $25,424,000

Air preheater modifications $8,685,000 B&V cost estimate Balanced draft conversion $17,122,000 B&V cost estimate Site preparation $1,000,000 Engineering estimate Buildings $200,000 Engineering estimate Total direct costs (DC) = (PEC) + (DIC) $79,622,000

Indirect Costs Engineering $5,574,000 (DC) X 7.0% Owner's cost $3,981,000 (DC) X 5.0% Construction management $7,962,000 (DC) X 10.0% Construction indirect $16,723,000 B&V labor market review Start-up and spare parts $2,389,000 (DC) X 3.0% Performance test $796,000 (DC) X 1.0% Contingencies $15,924,000 (DC) X 20.0%

Total indirect costs (IC) $53,349,000

Interest During Construction (IDC) $4,927,000 [(DC)+(IC)] X 7.41% 1 years (project time length X 1/2) Loss Generation during Outage (GEN) $23,674,000 5 weeks and 0.06095 $/kWh 12 weeks required for BDC, 7 weeks major outage available

Total Capital Investment (TCI) = (DC) + (IC) + (GEN) $161,572,000

ANNUAL COST Direct Annual Costs Fixed annual costs

Operating labor $125,000 1 FTE and 124,862 $/year Estimated manpower level Maintenance labor & materials $2,389,000 (DC) X 3.0%

Total fixed annual costs $2,514,000

Variable annual costs Urea $2,641,000 1,689 lb/hr and 420 $/ton Engineering estimate Water $2,658,000 380 gpm and 15.67 $/1,000 gal Engineering estimate Catalyst replacement $270,000 42 m3 and 6,500 $/m3 2 yr catalyst replacement rate Auxiliary power $32,000 70 kW and 0.06095 $/kWh Engineering estimate ID fan power $997,000 2,197 kW and 0.06095 $/kWh Engineering estimate

Total variable annual costs $6,598,000

Total direct annual costs (DAC) $9,112,000

Indirect Annual Costs

Cost for capital recovery $15,737,000 (TCI) X 9.74% CRF at 7.41% interest & 20 year life Total indirect annual costs (IDAC) $15,737,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $24,849,000PNM San Juan Generating Station Appendix D

060607 D-1 

## Appendix D Stack Outlet Conditions for Visibility ModelingPNM San Juan Generating StationAppendix D060607D-2SJGS Unit 1, Heat Input (HHV) = 3,707 MBtu/hrStack Outlet ConditionsFlow(acfm)Stack Velocity(ft/s)Temperature(°F)Pressure(in, wg)NOx(lb/MBtu)NOx(lb/hr)SO2(lb/MBtu)SO2(lb/hr)PM(lb/MBtu)PM(lb/hr)SO3(lb/MBtu)SO3(lb/hr)Pre-Consent Decree Operation0.43 1,592.0 0.24 877.8 0.050 185.4 0.013 50.0Visibility Modeling Baseline CasePost-Consent Decree Upgrades (LNB/OFA, PJFF) 1,323,494 70 121.42 0.01 0.33 1,223.3 0.18 667.3 0.015 55.6 0.011 40.5With additional NOxControl Technologies1. Selective Catalytic Reduction (SCR) 1,325,998 70 121.42 0.01 0.07 259.5 0.18 667.3 0.015 55.6 0.031 114.22. SNCR/SCR Hybrid 1,324,112 70 121.42 0.01 0.18 667.3 0.18 667.3 0.015 55.6 0.031 114.2Notes1. Emission levels (lb/MBtu) shown are on a 24-hour average basis.2. Emission in (lb/hr) is calculated based on the emission level (lb/MBtu) and design basis heat input.3. Emission levels on a 24-hour average basis are assumed to be similar to the annual average basis.4. Pre-consent decree operation emission level (lb/MBtu) are based on annual averages from year 2001 to 2003.5. Post-consent decree upgrades emissions for visibility modeling purpose are based on information provided by PNM, 4/19/2007.6. Stack velocity is calculated based upon volumetric flowrate and 6.10 m stack diameter.7. All flow conditions are based on the coal as shown in the Design Basis document.8. All SO3emissions are reported as Sulfuric Acid Mist (H2SO4).9. SO3emissions for the pre- and post-consent decree cases are determined using the National Park Service calculation formula.10. SO3emissions for the additional NOxcontrol technologies with catalyst accounts for an additional 1.0% SO2to SO3conversion (based on design basis economizer outlet SO2levels) and 0% SO3removal in PJFF.Revision HistoryRev Date Purpose0 4/25/2007 Initial issue to client1 5/2/2007 Revision to incorporate PNM comments2 5/24/2007 Final revisionPublic Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS) Unit 1Best Available Retrofit Technology (BART) Engineering AnalysisStack Outlet Conditions for Visibility Modeling (24-hour Average Emission Rates) Rev. 2PNM San Juan Generating StationAppendix D060607D-3SJGS Unit 2, Heat Input (HHV) = 3,688 MBtu/hrStack Outlet ConditionsFlow(acfm)Stack Velocity(ft/s)Temperature(°F)Pressure(in, wg)NOx(lb/MBtu)NOx(lb/hr)SO2(lb/MBtu)SO2(lb/hr)PM(lb/MBtu)PM(lb/hr)SO3(lb/MBtu)SO3(lb/hr)Pre-Consent Decree Operation0.45 1,649.3 0.23 844.0 0.050 184.4 0.013 49.7Visibility Modeling Baseline CasePost-Consent Decree Upgrades (LNB/OFA, PJFF) 1,316,710 70 121.42 0.01 0.33 1,217.0 0.18 663.8 0.015 55.3 0.011 40.3With additional NOxControl Technologies1. Selective Catalytic Reduction (SCR) 1,319,201 70 121.42 0.01 0.07 258.2 0.18 663.8 0.015 55.3 0.031 113.62. SNCR/SCR Hybrid 1,317,328 70 121.42 0.01 0.18 663.8 0.18 663.8 0.015 55.3 0.031 113.6Notes1. Emission levels (lb/MBtu) shown are on a 24-hour average basis.2. Emission in (lb/hr) is calculated based on the emission level (lb/MBtu) and design basis heat input.3. Emission levels on a 24-hour average basis are assumed to be similar to the annual average basis.4. Pre-consent decree operation emission level (lb/MBtu) are based on annual averages from year 2001 to 2003.5. Post-consent decree upgrades emissions for visibility modeling purpose are based on information provided by PNM, 4/19/2007.6. Stack velocity is calculated based upon volumetric flowrate and 6.10 m stack diameter.7. All flow conditions are based on the coal as shown in the Design Basis document.8. All SO3emissions are reported as Sulfuric Acid Mist (H2SO4).9. SO3emissions for the pre- and post-consent decree cases are determined using the National Park Service calculation formula.10. SO3emissions for the additional NOxcontrol technologies with catalyst accounts for an additional 1.0% SO2to SO3conversion (based on design basis economizer outlet SO2levels) and 0% SO3removal in PJFF.Revision HistoryRev Date Purpose0 4/25/2007 Initial issue to client1 5/2/2007 Revision to incorporate PNM comments2 5/24/2007 Final revisionPublic Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS) Unit 2Best Available Retrofit Technology (BART) Engineering AnalysisStack Outlet Conditions for Visibility Modeling (24-hour Average Emission Rates) Rev. 2PNM San Juan Generating StationAppendix D060607D-4SJGS Unit 3, Heat Input (HHV) = 5,758 MBtu/hrStack Outlet ConditionsFlow(acfm)Stack Velocity(ft/s)Temperature(°F)Pressure(in, wg)NOx(lb/MBtu)NOx(lb/hr)SO2(lb/MBtu)SO2(lb/hr)PM(lb/MBtu)PM(lb/hr)SO3(lb/MBtu)SO3(lb/hr)Pre-Consent Decree Operation0.42 2,405.5 0.28 1,591.1 0.050 287.9 0.013 77.7Visibility Modeling Baseline CasePost-Consent Decree Upgrades (LNB/OFA, PJFF) 2,055,753 56 121.42 0.01 0.33 1,900.1 0.18 1,036.4 0.015 86.4 0.011 62.9With additional NOxControl Technologies1. Selective Catalytic Reduction (SCR) 2,059,643 56 121.42 0.01 0.07 403.1 0.18 1,036.4 0.015 86.4 0.031 177.32. SNCR/SCR Hybrid 2,056,712 56 121.42 0.01 0.18 1,036.4 0.18 1,036.4 0.015 86.4 0.031 177.3Notes1. Emission levels (lb/MBtu) shown are on a 24-hour average basis.2. Emission in (lb/hr) is calculated based on the emission level (lb/MBtu) and design basis heat input.3. Emission levels on a 24-hour average basis are assumed to be similar to the annual average basis.4. Pre-consent decree operation emission level (lb/MBtu) are based on annual averages from year 2001 to 2003.5. Post-consent decree upgrades emissions for visibility modeling purpose are based on information provided by PNM, 4/19/2007.6. Stack velocity is calculated based upon volumetric flowrate and 6.10 m stack diameter.7. All flow conditions are based on the coal as shown in the Design Basis document.8. All SO3emissions are reported as Sulfuric Acid Mist (H2SO4).9. SO3emissions for the pre- and post-consent decree cases are determined using the National Park Service calculation formula.10. SO3emissions for the additional NOxcontrol technologies with catalyst accounts for an additional 1.0% SO2to SO3conversion (based on design basis economizer outlet SO2levels) and 0% SO3removal in PJFF.Revision HistoryRev Date Purpose0 4/25/2007 Initial issue to client1 5/2/2007 Revision to incorporate PNM comments2 5/24/2007 Final revisionPublic Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS) Unit 3Best Available Retrofit Technology (BART) Engineering AnalysisStack Outlet Conditions for Visibility Modeling (24-hour Average Emission Rates) Rev. 2PNM San Juan Generating StationAppendix D060607D-5SJGS Unit 4, Heat Input (HHV) = 5,649 MBtu/hrStack Outlet ConditionsFlow(acfm)Stack Velocity(ft/s)Temperature(°F)Pressure(in, wg)NOx(lb/MBtu)NOx(lb/hr)SO2(lb/MBtu)SO2(lb/hr)PM(lb/MBtu)PM(lb/hr)SO3(lb/MBtu)SO3(lb/hr)Pre-Consent Decree Operation0.42 2,399.6 0.29 1,662.4 0.050 282.5 0.013 76.2Visibility Modeling Baseline CasePost-Consent Decree Upgrades (LNB/OFA, PJFF) 2,016,837 55 121.42 0.01 0.33 1,864.2 0.18 1,016.8 0.015 84.7 0.011 61.7With additional NOxControl Technologies1. Selective Catalytic Reduction (SCR) 2,020,653 55 121.42 0.01 0.07 395.4 0.18 1,016.8 0.015 84.7 0.031 174.02. SNCR/SCR Hybrid 2,017,796 55 121.42 0.01 0.18 1,016.8 0.18 1,016.8 0.015 84.7 0.031 174.0Notes1. Emission levels (lb/MBtu) shown are on a 24-hour average basis.2. Emission in (lb/hr) is calculated based on the emission level (lb/MBtu) and design basis heat input.3. Emission levels on a 24-hour average basis are assumed to be similar to the annual average basis.4. Pre-consent decree operation emission level (lb/MBtu) are based on annual averages from year 2001 to 2003.5. Post-consent decree upgrades emissions for visibility modeling purpose are based on information provided by PNM, 4/19/2007.6. Stack velocity is calculated based upon volumetric flowrate and 6.10 m stack diameter.7. All flow conditions are based on the coal as shown in the Design Basis document.8. All SO3emissions are reported as Sulfuric Acid Mist (H2SO4).9. SO3emissions for the pre- and post-consent decree cases are determined using the National Park Service calculation formula.10. SO3emissions for the additional NOxcontrol technologies with catalyst accounts for an additional 1.0% SO2to SO3conversion (based on design basis economizer outlet SO2levels) and 0% SO3removal in PJFF.Revision HistoryRev Date Purpose0 4/25/2007 Initial issue to client1 5/2/2007 Revision to incorporate PNM comments2 5/24/2007 Final revisionPublic Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS) Unit 4Best Available Retrofit Technology (BART) Engineering AnalysisStack Outlet Conditions for Visibility Modeling (24-hour Average Emission Rates) Rev. 2PNM San Juan Generating Station Appendix E

060607 E-1 

## Appendix E CALPUFF Modeling Support Documents