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, Final 
PNM San Juan Generating Station Contents 

060607 TC-1 

Contents 

Acronyms......................................................................................................................AC-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 Retrofit Emissions Control Technologies ......... 3-1 

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

3.1.1 Low NOx 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 NOxStar.................................................................................... 3-12 

3.1.8 ECOTUBE............................................................................... 3-12 

Contents (Continued) 
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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 Control 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 Consent Decree Technology Selection .................... 4-1 

4.1 NOx Consent Decree Control Technologies ............................................ 4-1 

4.1.1 Description of NOx Consent Decree Upgrades ......................... 4-1 

4.1.2 NOx Consent Decree Upgrades Control Effectiveness ............. 4-1 

4.1.3 NOx Consent Decree Upgrades Cost-Effectiveness.................. 4-2 

4.1.4 Summary of NOx Consent Decree Upgrades ............................ 4-2 

4.2 Particulate Matter Consent Decree 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 Technology Alternatives............... 5-1 

5.1 Technically Infeasible Additional NOx 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 NOxStar ..................................................................................... 5-3 

5.1.5 ECOTUBE................................................................................. 5-3 
PNM 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 Additional 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-Effectiveness 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..................................... 8-6 
PNM San Juan Generating Station Contents 

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Contents (Continued) 

8.5.4 Precipitation Data Stations 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 Conditions for Visibility Modeling 

Appendix E CALPUFF Modeling Support Documents 

Tables 

Table ES-1 Control and Cost-Effectiveness Results of Consent Decree 

Upgrades ................................................................................................ES-2 

Table ES-2 Impact Analysis and Cost-Effectiveness Results for Additional 

NOx Control Technology Alternatives...................................................ES-5 

Table ES-3 Visibility Improvement Cost-Effectiveness Summary ..........................ES-6 

Table 1-1 SJGS Characteristics Pre-Consent Decree Operation.............................. 1-3 
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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 Technologies Control Effectiveness (Annual 

Average Emissions Rates) ....................................................................... 4-3 

Table 4-2 Control and Cost-Effectiveness Results of Consent Decree 

Upgrades .................................................................................................. 4-4 

Table 4-3 Coal Properties Comparison .................................................................... 4-5 

Table 5-1 Technically Feasible Additional NOx Control Technology 

Alternatives.............................................................................................. 5-5 

Table 5-2 Technically Feasible Additional PM Control Technology 

Alternatives.............................................................................................. 5-6 

Table 6-1 NOx Control Effectiveness for Additional Control Technology 

Alternatives (Annual Average Emissions Rates)..................................... 6-2 

Table 7-1 Impact Analysis and Cost-Effectiveness Results of Additional 

NOx Control Technologies....................................................................... 7-4 

Table 8-1 Class I Areas ............................................................................................ 8-2 

Table 8-2 Model Versions........................................................................................ 8-4 

Table 8-3 CALPUFF Modeling Stack Parameters................................................. 8-15 

Table 8-4 Consent Decree Baseline CALPUFF Modeling Emission Rates .......... 8-16 

Table 8-5 NOx 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 Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-22 

Table 8-11 Unit 1 SCR Visibility Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-23 

Table 8-12 Unit 2 SCR Visibility Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-24 

Table 8-13 Unit 3 SCR Visibility Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-25 

Table 8-14 Unit 4 SCR Visibility Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-26 
PNM San Juan Generating Station Contents 

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Contents (Continued) 

Tables (Continued) 

Table 8-15 Unit 1 Hybrid Visibility Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-27 

Table 8-16 Unit 2 Hybrid Visibility Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-28 

Table 8-17 Unit 3 Hybrid Visibility Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-29 

Table 8-18 Unit 4 Hybrid Visibility Modeling Results 98th Percentile Impact 

for Each Year (dv) ................................................................................. 8-30 

Table 8-19 WRAP RMC Baseline Modeling 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 ROTAMIX Simplified Process Flow 

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

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

Figure 3-6 ECO Process Flow Diagram (Source: PowerSpan)............................... 3-14 

Figure 3-7 Phenix Clean Coal Process Flow Diagram. (Source: Phenix) ............... 3-15 

Figure 3-8 e-SCRUB Process 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 Filter (Source: GE Environmental) ....................... 3-22 

Figure 7-1 SJGS Unit 1 Additional NOx Control Technology CostEffectiveness............................................................................................ 7-5 

Figure 7-2 SJGS Unit 2 Additional NOx Control Technology CostEffectiveness............................................................................................ 7-6 

Figure 7-3 SJGS Unit 3 Additional NOx Control Technology CostEffectiveness............................................................................................ 7-7 

Figure 7-4 SJGS Unit 3 Additional NOx Control Technology CostEffectiveness............................................................................................ 7-8 

Figure 8-1 Location of SJGS and the Class I Areas .................................................. 8-3 
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Figure 8-2 Geophysical and Meteorological 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 Computational Domain ....................................................... 8-12 
PNM San Juan Generating Station Acronyms 

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Acronyms 

A/C Air-to-Cloth 

AQC Air Quality Control 

ASN Ammonium Sulfate Nitrate 

B&W Babcock & Wilcox 

BACT Best Available 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 

H2SO4 Sulfuric Acid Mist 

Hg Mercury 

HHV Higher Heating Value 

IWAQM Interagency Workgroup on Air Quality Modeling 

LCC Lambert Conformal Conic 

LNB Low NOx Burners 

MBtu Million British Thermal Unit 

HNO3 Nitric Acid 

NH3 Ammonia 

NH4 Ammonium

NMED New Mexico Environment Department 

NN Neural Network 

NO3 Nitrates 

NOx Nitrogen Oxides 

NPS National Park Service 

NSPS New Source Performance Standards 

NWS National Weather Service 
PNM 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 

SO2 Sulfur Dioxide 

SO3 Sulfur Trioxide 

SO4 Sulfate 

TAC Total Annualized Cost 

TCI Total Capital Investment 

WRAP Western Regional Air Partnership 
PNM 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 Generating 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, Appendix Y). A BART review was required 

to identify the best control technology for the reduction of nitrogen oxides (NOx), sulfur 

dioxide (SO2), and particulate matter (PM) emissions. However, because the state of 

New Mexico will participate in the Western Regional Air Partnership (WRAP) SO2

emissions trading program, SO2 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 alleged violations of the Clean Air Act. 

Installation of state-of-the-art new low-NOx burners (LNB) with overfire air (OFA) ports 

and a neural network (NN) system to reduce NOx 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 that 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 technologies, 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 NOx limit is 0.23 lb/MBtu 

(subbituminous coal for a dry-bottom, wall-fired boiler). The NOx presumptive limit was 

established based on the type of coal burned and the boiler design. It should be noted that 

the presumptive limit of 0.23 lb/MBtu is achievable for Powder River Basin (PRB) coal 

fired, dry-bottom, wall-fired boilers, using state-of-the-art combustion control 

technologies, but SJGS does not burn PRB coal. For a similarly configured boiler firing 

bituminous coal, the presumptive limit for NOx 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 performed 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. Table ES-1 lists control and cost-effectiveness 

data for the consent decree technologies. The evaluation of the consent decree control 

technologies indicates that the new LNB, OFA, and NN installed for NOx emissions 

represent a state-of-the-art combustion control technology, and the PJFFs installed for 

PM emissions are the most stringent control technology for PM emissions control. The 

consent decree control technologies should be considered BART for SJGS. 

Table ES-1 

Control and Cost-Effectiveness Results 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 Basis).

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 analysis, 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 the most stringent technology available, no 

additional PM control technologies alternatives were evaluated. For NOx emissions, the 

selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR)/SCR 

hybrid technologies were identified as feasible additional NOx control technology 

alternatives. The BART analysis of these technologies is presented in Sections 5.0 to 7.0. 

The results of the control and cost-effectiveness evaluation are summarized in Table ES2. 

The last step of the BART analysis involved performing visibility modeling for 

the two stage of the BART analysis. The visibility modeling was performed in 

accordance with the modeling protocol submitted to the NMED. Meteorological data for 

the years 2001 through 2003 was obtained from 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 control technology modeled, the visibility data 

was analyzed for the 98th percentile modeled visibility and 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 

NOx 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], consent decree technologies, and additional NOx

control technology alternatives), the average modeled visibility 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 emissions reductions achieved by the PJFF. 

Therefore, the PJFF is considered BART for this project for each SJGS unit. 

The BART analysis for NOx emissions control concludes that the LNB, OFA, and 

NN should be considered BART for the SJGS units. Another factor to consider is that 

the presumptive limit for dry-bottom, wall-fired boilers burning subbituminous 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 NOx control. This similarity to bituminous coal is due to the lower 

volatility, lower moisture, and lower oxygen content of the coal burned at SJGS. These 

characteristics result in higher NOx emissions from the SJGS units than from the same 

type of boiler with the same combustion controls and burning PRB coal. The LNB, OFA, 

and NN being installed in the SJGS units are classified as state-of-the-art technologies 
PNM San Juan Generating Station Executive Summary 

060607 ES-4 

and are equivalent to the BART technology used to establish the 0.23lb/MBtu 

presumptive limit. 

The SCR and SNCR/SCR Hybrid systems would require significant capital 

expenditure and modifications that will impact many areas of the plant, including boiler 

draft systems, air heater performance, SO3 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 Unit 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 effectiveness is 155 million $/dv for SCR and 369 million 

$/dv for SNCR/SCR Hybrid. These minimal visibility improvements do not merit the 

large capital expenditure required to install SCR or SNCR/SCR Hybrid. 

Therefore, LNB, OFA, and NN combustion controls should be considered BART 

for SJGS. 
PNM San Juan Generating Station 

060607 

Table ES-2 

Impact Analysis and Cost-Effectiveness Results for Additional NOx Control Technology Altern

Total Total

Emission Expected Expected Expected Capital Annualized Increm

Performance Emission Emission Emission Investment Cost Cost Co

Level Rate Rate Reduction (TCI) (TAC) Effectiveness Effectiv

All Feasible Technologies (lb/MBtu) (lb/h) (ton/yr) (ton/yr) (1,000$) (1,000$) ($/ton) ($/to

SJGS Unit 1

Selective Catalytic Reduction (SCR) 0.07 259.5 966 3,174 156,805 20,525 6,466 2,84SNCR/SCR Hybrid 0.18 667.3 2,484 1,656 104,436 16,207 9,786 -- 

SJGS Unit 2

Selective Catalytic Reduction (SCR) 0.07 258.2 961 3,158 169,251 21,891 6,932 3,45SNCR/SCR Hybrid 0.18 663.8 2,471 1,648 108,628 16,670 10,117 -- 

SJGS Unit 3

Selective Catalytic Reduction (SCR) 0.07 403.1 1,501 4,931 215,568 28,359 5,752 1,16SNCR/SCR Hybrid 0.18 1,036.4 3,859 2,572 168,507 25,606 9,954 -- 

SJGS Unit 4

Selective Catalytic Reduction (SCR) 0.07 395.4 1,472 4,837 199,558 26,592 5,497 75SNCR/SCR Hybrid 0.18 1,016.8 3,786 2,524 161,572 24,849 9,846 -- 

Notes: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 identified as BART-eligible 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 modeling performed by the 

WRAP RMC. 

Three major pollutants, NOx, SO2, and PM, were identified as having an impact 

on visibility at Federal Class I areas. However, for this BART analysis, SO2 emissions 

reductions will not be taken into account for BART consideration, because New Mexico 

will participate in the WRAP SO2 emissions trading program. This report documents the 

BART engineering analysis process and the results obtained, as well as the recommended 

best control alternative for NOx 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 Clean Air Act violations at SJGS. PNM is 

required by the consent decree to reduce emissions levels of PM at each unit to 

0.015 lb/MBtu (measured using EPA reference Method 5), with a corresponding opacity 

limit of 20 percent over a 6 minute average period. For NOx, each unit at SJGS shall not 

exceed 0.30 lb/MBtu on a 30 day rolling average period. PNM is also required to reduce 

SO2 and mercury emissions. 

 The consent decree compliance deadlines for the reduced emissions levels vary 

for all four units at SJGS. The earliest required startup date for PM and NOx controls is 

October 31, 2007 for SJGS Unit 4. The last required startup date for PM and NOx

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 NOx and PM, PNM is 

installing state-of-the-art LNB with OFA ports, and an NN system on each boiler to 

reduce NOx emissions. For PM emissions control, a full-sized PJFF will be installed 

upstream of the limestone flue gas desulfurization (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 reducing mercury (Hg) emissions. 

 The installation of the controls associated 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 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 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 coal 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 value (HHV), lower moisture content, higher 

sulfur content, and lower volatility than PRB coal. A detailed comparison of the 

difference in fuel characteristics 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 subcritical, wall-fired boilers that operate in a 

forced draft mode. For emissions reduction, the units are equipped with Western 

Precipitator hot-side ESPs for PM control and Babcock & Wilcox (B&W) wet limestone 

FGD systems for SO2 control. SJGS Unit 1 has LNBs. 

 SJGS Units 3 and 4 each have a unit capacity of 544 MW and are equipped with 

B&W subcritical, opposed wall-fired boilers that operate in a forced draft mode. For 

emissions reduction, the units are equipped with 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 

060607 1-3 

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 Subcritical Subcritical Subcritical 

Draft of Boiler Forced Forced Forced Forced 

Existing Emissions 

Controls 

 

PM Hot-side ESP Hot-side ESP Hot-side ESP Hot-side ESP 

SO2 Wet FGD Wet FGD Wet FGD Wet FGD 

NOx Low-NOx

burners 

N/A Low-NOx

burners 

Low-NOx

burners 

1.3 BART Analysis Methodology 

 The BART analysis is the engineering and modeling analysis method used to 

identify the best method or technology to achieve 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 regulations 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 following five steps to arrive at a selection of 

the best methods of emissions reduction for NOx 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 

060607 1-4 

(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 BART analysis required a unique approach 

because of the consent decree. The station was established as a BART-eligible source 

prior to the installation of technologies associated with the consent decree. Therefore, the 

pre-consent decree operating conditions, as described 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 scenario (presented in Section 4.0 of this 

report). Additional control technology alternatives were then evaluated as potential 

BART compliance scenarios presented in Sections 5.0 to 7.0. 

 

1.3.1 Identify All Available Retrofit Control Technologies (Step 1) 

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

retrofit control technologies. An emissions control technology is considered an available 

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

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. Technologies that have been successfully applied to similar sources or with 

similar gas stream characteristics are considered as available. However, technologies that 

have not been applied to commercial-scale operations are considered not available. Since 

the SJGS units are equipped with existing control technologies, control options including 

improvements or optimization of the existing 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 their technical feasibility. A control technology 

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

similar type of source or if there is technical agreement between the provider and user 

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

used to define the technical feasibility of a control technology. A technology is deemed 

an available technology if it is being offered commercially by vendors or is in 

commercial demonstration or licensing. The 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 and 
PNM San Juan Generating Station Introduction and Objectives 

060607 1-5 

testing stages are classified as not available. Section 4.0 provides details of Step 2 of the 

BART analysis. 

1.3.3 Evaluate Control Effectiveness of Remaining Control Technologies 

(Step 3) 

 Once all the technically feasible control technology alternatives are identified in 

Step 2, the control effectiveness of each control technology is evaluated in Step 3. 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 effectiveness of a technology 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 performance guarantees), engineering estimates, 

and demonstrated effectiveness of the technology at another source. The most stringent 

level of control proven for each technology was used for its control effectiveness, but less 

stringent levels of control were also considered as additional options. The results for 

Step 3 of the BART analysis are described in Section 5.0. 

1.3.4 Evaluate Impacts and Document the Results (Step 4) 

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

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

as part of the BART determination. These evaluations, labeled as “Impact Analyses,” are 

included in Section 6.0. The impact analyses 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 costs of compliance. This analysis is 

performed to indicate the cost to purchase, retrofit, and install the control technology. 

The capital and operating/annual costs are estimated based on established design 

parameters. The design parameters are established in the Design Concept Definitions in 

Appendix B. The estimated cost of control is represented as an annualized cost ($/year). 

The annualized cost in conjunction with the estimated quantity of pollutant removed 

(tons/year) allows the cost-effectiveness ($/tons) of the control technology to be 

determined. The cost-effectiveness compares the potential technologies on an economic 

basis. Two types of cost-effectiveness are considered in a BART analysis: average and 

incremental. The average cost-effectiveness is defined as the total annualized cost of 
PNM San Juan Generating Station Introduction and Objectives 

060607 1-6 

control divided by the annual quantity of pollutant removed for each control technology. 

The incremental cost-effectiveness is a comparison of the cost and performance level of a 

control technology to the next most stringent option. 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 control 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 additional 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 purchased 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 NOx, SO2, sulfur trioxide (SO3), 

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 considered only when there would be an 

effect on the annualized costs of the retrofit controls for capital recovery. This occurs 

when the source has a shorter remaining useful life than the expected service life of the 

control technology. This would require an expedited pace for capital recovery, thus 

affecting the cost-effectiveness of the control technology, particularly for technologies 

that require a large capital expenditure. 

1.3.5 Evaluate Visibility 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 NOx, SO2, and PM emissions. A modeling protocol 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 emissions rates of pollutants. 

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

060607 1-7 

After model runs were completed, a determination of the visibility improvement 

was made. The visibility improvements for the initial BART compliance scenario 

involving the consent decree technologies and the additional BART compliance scenario 

with additional control technology alternatives were determined by comparing the 98th 

percentile modeled visibility values. The visibility improvement is quantified in units of 

deciview, which are defined as a visibility index that linearly scales perceived visual 

(visibility) changes (Interagency Monitoring of Protected Visual Environments 

Newsletter, April 1993). A detailed description 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). This 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 the five steps described above, a decision on 

the best alternative control technology can be made based on the cost-effectiveness, 

impacts, and the resultant visibility improvement. 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 pollutants. While separately the technologies 

may not be the best selection for the control 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 NOx

reduction. In addition, the potential of a selected technology to control future regulated 

pollutants, such as the use of a PJFF for Hg control, is considered when selecting the best 

alternative. 
PNM San Juan Generating Station Basis of Analysis 

060607 2-1 

2.0 Basis of Analysis 

2.1 Design Basis 

 A detailed design basis was established for the SJGS. The information in the 

design basis was used for equipment sizing, performance calculations, 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 configuration after the consent decree 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 the design basis coal to determine the flue 

gas flow characteristics for use in equipment sizing and cost estimation. 

2.2 Economic Data 

2.2.1 Capital Cost Estimates 

 Capital cost estimates were developed for retrofit control technologies 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 equipment, installation, and miscellaneous costs. 

The purchased equipment costs are the costs for purchasing the equipment, including 

taxes and freight. An itemized list of key components of the direct capital cost is 

included in Appendix C for each feasible control technology. The installation costs 

include construction costs for installing the new controls. The installation costs take into 

account the retrofit difficulty of the existing site configuration and condition and the 

installation requirements of the evaluated technology. Finally, the costs of miscellaneous 

items such as purchase of additional water rights, site preparation, buildings, and other 

site structures needed to implement the control technology are included. 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 

060607 2-2 

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

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

(AQC) technology. Indirect costs addressed in this evaluation 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 category are items such as possible redesign and 

equipment modifications, errors in estimation, unforeseen weather-related delays, strikes 

and labor shortages, escalation increases in equipment costs, increases in labor costs, 

delays encountered in startup, etc. 

2.2.1.2 Engineering. Engineering costs include any services provided by an 

architect/engineer or other consultant for support, design, and procurement of the 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 representative of the typical expenditures that 

an Owner would experience as part of an AQC retrofit project. 

2.2.1.4 Construction Management. Construction management services include 

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

inspection and quality assurance, project control, technical direction, and management of 

startup. It also includes cleanup expense for the portion not included in the direct-cost 

construction contracts, safety and medical services, guards and other security services, 

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

liability insurance for equipment and tools. 

2.2.1.5 Startup and Spare Parts. Startup services include the management of the 

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

newly installed AQC technology. Also included 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 

060607 2-3 

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 the performance of the emissions reduction 

system. The results of the performance tests 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 longer than the 7 week major outage or 3 week minor 

outage that have been planned for each unit, an estimate is made for the loss of 

generation. For each retrofit scenario analyzed in this 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, based on the net generation 

and capacity factor as shown in the design basis in Appendix A. 
PNM San Juan Generating Station Basis of Analysis 

060607 2-4 

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 Reduction (SCR) Catalyst Cost $6,500/m3

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 Electric 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 annualize 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-hour 
PNM San Juan Generating Station Basis of Analysis 

060607 2-5 

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 dependent on the specific control technology. 

O&M materials and labor are fixed annual costs. 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 costs for the material, delivery of 

the reagent to the facility, and reagent preparation. 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 removed. 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 systems. 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 power 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 new 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 process, the appropriate 

water type was included in this cost category. 
PNM San Juan Generating Station Basis of Analysis 

060607 2-6 

2.2.2.4 Wastewater and Byproduct Disposal Costs. Some control technologies 

generate wastewater and/or byproduct that will require treatment 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 technology reaction byproducts that are 

collected will be landfilled in the coal mine. 

• Ammonia-based NOx 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 Operating 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 practices. The labor cost was based on a 

fully loaded labor rate and 40 hours per work week. 

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

the following personnel: 

• Supervisor. 

• Control Room Operator. 

• Roving Operator. 

• Relief Operator. 

• Laboratory Technicians. 

• Equipment Operators. 

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 Materials 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 electrical 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 site, a determination of the additional 

maintenance requirements was performed. If the required maintenance materials and 

labor were similar to the existing technology, no additional maintenance costs were 

credited for the new control technology. 
PNM San Juan Generating Station Basis of Analysis 

060607 2-7 

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 NOx and SO2. The 

BART NOx presumptive limits vary according to the type of coal burned and the boiler 

design. For all units at SJGS, the NOx 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 NOx 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 type bituminous coal. A discussion of the 

differences between the New Mexico subbituminous coal burned at SJGS and PRB coal 

is included in Subsection 4.1.4. 

As previously noted, New Mexico is participating in the WRAP SO2 emissions 

trading program and, therefore, the presumptive limits for SO2 were not used for this 

study. For PM emissions control, the BART analysis methodology is similar to that for 

NOx. 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 and BACT determinations for the pollutants 

in this BART analysis is presented in Table 2-3. 

Table 2-3 

Target Emissions 

 NOx 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)NOx 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 

060607 2-8 

2.4 Project Assumptions 

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

facilitate the conceptual design activities of the technically feasible control technologies 

that are being evaluated. The following are key project assumptions: 

• No significant change will occur in plant 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 technically feasible control 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. 

• NOx emissions rate. 

• SO2 emissions rate. 

• Filterable PM emissions rate. 

• SO3 emissions rate. 
Identification of All 

 Available Retrofit Emissions 

PNM San Juan Generating Station Control Technologies 

060607 3-1 

3.0 Identification of All Available Retrofit Emissions 

Control Technologies 

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

have a practical potential for application at SJGS were identified. 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. Control technologies for the two major pollutants, 

NOx and PM, and a description of the technology are presented in this section. 

Information on the working principle, retrofit considerations, advantages, and 

disadvantages of the technology are provided in the descriptions contained in 

Sections 3.1 through 3.2. 

3.1 NOx Control Technologies 

There are two approaches to achieving a reduction in NOx emissions: combustion 

control and post-combustion control. Combustion control methods seek to suppress NOx

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 consist of SNCR and 

SCR systems. SNCR and SCR are flue gas treatment technologies that reduce NOx after 

its formation. The SNCR and SCR NOx reduction technologies use either urea or 

ammonia as a reagent. SCR technology also uses multiple layers of reduction catalyst. 

Other NOx reduction techniques were also identified, including emerging technologies. 

 NOx control technologies that were identified 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. 

• NOxStar. 
Identification of All 

 Available Retrofit Emissions 

PNM San Juan Generating Station Control Technologies 

060607 3-2 

• ECOTUBE. 

• PowerSpan. 

• Phenix Clean Combustion. 

• e-SCRUB. 

3.1.1 Low NOx Burners, Overfire Air with Neural Network 

3.1.1.1 Low NOx Burners. NOx, primarily in the form of NO and NO2, is formed 

during combustion by two primary mechanisms: thermal NOx and fuel NOx. Thermal 

NOx results from the dissociation and oxidation of nitrogen in the combustion air. The 

rate and degree of thermal NOx formation is dependent on oxygen availability during the 

combustion process and is exponentially dependent on combustion temperature. Fuel 

NOx, on the other hand, results from the oxidation of nitrogen organically bound in the 

fuel. This is the dominant NOx producing mechanism in the combustion of pulverized 

coal, and typically accounts for 75 to 80 percent of total NOx. 

All LNBs offered commercially for application to coal fired boilers control the 

formation and emissions of NOx through some form of staged combustion. The basic 

NOx reduction principles for LNBs are to control and balance the fuel and airflow to each 

burner and to control the amount and position of secondary air in the burner zone so that 

fuel devolatization and high temperature zones are not oxygen rich. In this process, the 

mixing of the fuel and the air by the burner is controlled in such a way that ignition and 

initial combustion of the coal take place under oxygen deficient conditions, while the 

mixing of a portion of the combustion air is delayed along the length of the flame. 

 The objective of this process is to drive the fuel-bound nitrogen out of the coal as 

quickly as possible, under conditions where no oxygen is present, and force it to form 

molecular nitrogen rather than be oxidized to NOx. Any nitrogen escaping the initial 

fuel-rich region has a greater opportunity to be converted to NOx as the combustion 

process is completed. The net result of staged combustion is usually longer and/or wider 

flames due to this delayed mixing process. Staged combustion may increase the potential 

for higher levels of unburned carbon in ash and 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 available burner zone volume. 

 For LNBs to reach their maximum benefit, the proper balance of fuel and airflow 

to the burners (and from burner to burner) is critical. NOx 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. 
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By balancing the fuel and airflow to the burners, an important step is achieved in 

controlling the flame characteristics and improving the overall combustion process. 

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

This allows the burners to operate as a NOx 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 NOx

emissions. Any residual unburned material, such as CO and unburned carbon that 

inevitably escapes the main burner zone, is subsequently oxidized as the OFA is added. 

As with primary NOx control, the performance that can be expected from a given 

OFA system depends on a number of factors. As the amount of OFA 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 make fuels more difficult to burn. It will 

also depend on the balance of flows between individual burners and the fuel fineness. As 

the OFA amount approaches 10 to 15 percent, the probability for individual 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 formation 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 NOx emissions creates a reducing 

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

environment attacks the iron oxides in the tube metal and can lead to 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 power generation companies to implement cost-effective 

optimization solutions that decrease emissions and maximize plant efficiency. This 

solution, commonly referred to as the boiler optimization or NN system, may provide 

improvements in the heat rate of the boiler and reduce combustion-related emissions. NN 

computing differs from traditional computing in that engineering, statistical, and first-law 

principles have been replaced by complex, time-varying, nonlinear relationships. NN 
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systems use real-time operational data extracted from a plant DCS, “learn” solutions from 

plant operational experience, and achieve reductions in the emissions produced, while 

possibly improving the heat rate of the plant. 

NN systems also supplement other NOx reduction strategies. Some of these 

include LNB, OFA, and post-combustion controls such as SCR and SNCR. These 

systems are also used to help boiler manufacturers 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 performance of combustion system. 

Airflow systems measure primary airflow, bulk secondary air, total secondary 

airflow, and OFA flow distribution. One specific system uses a pitot derivative of the 

multi-point, self-averaging pitot principle to measure the total and static pressure 

components of airflow. Pulverized fuel flow is determined by measuring the mass flow 

distribution and transport velocity of the fuel in the pipelines from the mill to the 

individual burners. The precise technology used for the measurements varies depending 

on the specific vendor. 

3.1.2 Selective Non-Catalytic Reduction 

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

the steam generator, as illustrated on Figure 3-1. SNCR systems rely solely on reagent 

injection (rather than a catalyst) and an appropriate reagent injection temperature, good 

reagent/gas mixing, and adequate reaction time to achieve NOx reductions. SNCR 

systems can use either ammonia or urea as the reagent. Ammonia or urea is injected into 

areas of the steam generator where the flue gas temperature ranges from 1,500 to 

2,200° F. The furnace of a pulverized coal fired boiler operates at temperatures between 

2,500 to 3,000° F. 

SNCR systems are capable of reducing NOx emissions by as much as 50 to 

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

gas mixing; high baseline NOx conditions; multiple levels of injectors). Ammonia slip is 

the ammonia that does not react with NOx and instead “slips” past the boiler as ammonia. 

High levels of ammonia slip cause several negative operational impacts. First, ammonia 

will react with SO3 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 ash 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 ammonia slip be maintained below 5 ppmvd. 
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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, NOx 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 concentrations, and steam generator heat transfer 

characteristics. 

Figure 3-1 

Schematic of SNCR System with Multiple Injection Levels 

SNCR systems reduce NOx emissions using the same reduction mechanism as 

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

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

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

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

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

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

of the large boiler size/volume associated with such boilers. 

Reagent injection lances are usually located between the boiler soot blowers in the 

pendent superheat section. Optimum injector location is mainly a function of temperature and residence time. To accommodate SNCR reaction temperature and boiler 

turndown requirements, several levels of injection lances are normally installed. 

Typically, four to five levels of multiple lance nozzles are installed if sufficient boiler 
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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 NOx reduction levels even under less 

than ideal mixing conditions. Computational fluid dynamics and chemical kinetic 

modeling can be performed to establish the 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 NOx control technology 

for achieving significant NOx emissions reduction. In SCR systems, vaporized ammonia 

(NH3) injected into the flue gas stream acts as a reducing agent when passed over an 

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

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

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

(unreacted ammonia emissions). A simplified 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. Some SCR systems are built without a bypass. 

However, a unit that uses fuel oil for startup 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 catalyst 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-side ESP. This reduces the cost of an SCR as 

compared to the high dust SCR since the catalyst volume can be smaller. It should be 

noted that an SCR located after a de-energized 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 heat 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 catalyst. The reactor is basically a 

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

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

catalyst oxidizes a portion of the SO2 in the flue gas to SO3. The oxidation of SO2 to SO3

could also require moderate air heater modifications, since the acid dew point 

temperature of the flue gas is directly related to SO3 concentration. As the SO3

concentration increases, the acid dew point of the flue gas increases, potentially 

increasing corrosion in downstream equipment or possibly requiring an increase in the air 

heater gas outlet temperature. 

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 catalyst, the selection of ammonia type does not 

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

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

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

anhydrous ammonia. 
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SCR systems have a variety of interfacing system requirements to support 

operations. These requirements include fan draft power, auxiliary power, soot blowing 

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

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

requirements, draft losses can range from 4 to 10 in. wg, which would require additional 

fan power. If necessary, ductwork and/or boiler box reinforcement may also be required. 

In conjunction with the fan modification, an expansion of the auxiliary power system 

might be necessary. Auxiliary power modifications 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 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 decreasing plant efficiency. The other potential 

concern for the air heater is the tendency for high SO3 concentrations in the flue gas to 

form sulfuric acid vapor. If the acid dew point temperature has been increased to more 

than the air heater exit temperature, a significant amount of acid gases will condense in 

the air heater and lead to pluggage and corrosion. Several measures can be taken to avoid 

or correct this situation. Most important is the right composition of the catalyst to 

minimize the SO2 to SO3 conversion rate. Ammonia slip must also be minimized. Air 

heater basket modifications are often necessary to minimize these harmful effects. 

3.1.4 SNCR/SCR Hybrid 

The SNCR/SCR hybrid systems use components and operating characteristics of 

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

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

reduction potential and low ammonia slip inherent 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 would 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: NOx reduction within the boiler is increased, while ammonia 

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

the catalyst. 

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

conservative hybrid systems use the catalyst simply as an ammonia slip “scrubber” with 
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some additional NOx reduction. As with in-duct systems, the flue gas velocity through 

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

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

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

catalyst requirement of this design 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 levels of additional NOx

reduction. However, this philosophy is usually not economically advantageous when 

compared to SCR. As a result, hybrid systems are usually designed using the first 

philosophy. The additional reduction is a function of the quantity of ammonia slip, 

catalyst volume, and distribution of ammonia to NOx within the flue gas. Using ammonia 

slip produced by the SNCR system is not an efficient method to introduce reagent, 

because of the low reagent utilization discussed as a part of the SNCR. Therefore, even 

though the reaction at the catalyst requires 1 ppm of ammonia to remove 1 ppm of NOx, 

the SNCR must inject at least 3 ppm of ammonia to generate 1 ppm of ammonia at the 

catalyst. 

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

ammonia distribution. If multiple levels of catalyst operating at low flue gas velocity are 

required, some modifications will be required to the existing ductwork. If widening the 

existing ductwork cannot provide adequate catalyst volume, then a separate reactor is 

required, thus eliminating much of the capital 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 decreasing plant efficiency. The other potential 

concern for the air heater is high concentrations of SO3 in the flue gas. If the acid dew 

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

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

Several measures can be taken to avoid or correct this situation. 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 NOx 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 zone 
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burners are operated with about 10 percent excess air (a 1:10 stoichiometric ratio). A 

second combustion zone (the reburn zone) is created above the lower furnace by 

operating a row of conventional natural gas burners at a stoichiometric ratio of less than 

1.0. This technology also has the potential for increased furnace corrosion (especially 

with higher sulfur fuels) because of the reducing atmosphere in the lower furnace. 

The sub-stoichiometric reburn zone causes NOx produced in the lower furnace to 

be reduced to molecular nitrogen and oxygen. This happens because the oxygen stripped 

from the NOx molecules is combined with the more active CO molecules to form CO2 as 

combustion is completed in the upper furnace. Fuel burnout is completed in the third 

zone (the burnout zone) by the introduction of OFA. Sufficient OFA is introduced to 

complete combustion of the unburned materials in the upper furnace, with an overall 

excess air rate for the boiler of 15 to 20 percent. Reburn technology has demonstrated 

NOx reductions of 40 to 65 percent. 

Burnout Zone

•Normal Excess Air

Reburning Zone

•Slightly Fuel Rich

•NOx Reduced to N2

Primary Combustion

Zone

•Reduced Firing Rate

•Low Excess Air

•Lower NOx

Overfire Air

40 to 60% NOx Reduction

10 to 20 % Gas

Fuel Rich

80 to 90% Coal

10% Excess Air

Figure 3-3 

Schematic of Gas Reburn System 

Sufficient residence time (adequate furnace height) in the reburn and OFA zones 

is a key factor in determining whether the reburning technology can be applied. 

Successful retrofit of this technology requires space within the boiler to allow adequate 

residence time for both the additional burning zone (0.4 to 0.6 second) and the associated 

OFA burnout zone (0.6 to 0.9 second). When this space is available, reburning can be 

highly effective, but a low residence time will limit system performance. Also, the high 

cost of natural gas makes the annual operating costs of this technology prohibitive. 
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A variation to gas reburn is fuel lean gas reburn (FLGR), which can reduce NOx

emissions from coal fired boilers by 30 to 45 percent. FLGR requires a lower natural gas 

input than in a conventional gas reburn system and does not require an OFA system to 

achieve CO burnout. The FLGR technology requires 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 NOx 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 incorporating a urea-based 

SNCR system into the gas reburn system. This 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 NOx removal efficiency than the basic gas reburn and 

FLGR systems. An amine-enhanced system is capable of reducing NOx emissions by 50 

to 70 percent. 

3.1.6 Mobotec ROFA and ROTAMIX 

Mobotec provides a NOx 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 booster fan is used to direct combustion air 

away from the primary combustion zone and 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 NOx production, and improved 

boiler efficiency. 

In addition, ROTAMIX can be added to the 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 NOx reduction because 

of a homogeneous temperature profile in the boiler. The ROTAMIX system adapts to 

changes in load and temperature in the furnace and preferentially introduces ammonia 

where the temperature is most favorable for NOx reduction. This approach reduces 

chemical consumption considerably and lowers ammonia slip by increasing 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 NOx reduction in addition to the ROFA NOx reduction. 

Although the Mobotec system may offer significant advantages over conventional 

scrubbing, impacts such as the increased volumes of particulate that would need to be 

collected, expected additional costs for sorbent, and the limited large-scale installed 
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experience with the system should be considered. A simplified process flow diagram of 

the ROFA and ROTAMIX system is illustrated on Figure 3-4. 

3.1.7 NOxStar 

 NOxStar is the trademarked name for a NOx control technology that involves the 

injection of ammonia and a hydrocarbon (typically natural gas) into the flue gas path of a 

coal fired boiler at around 1,600 to 1,800° F for the reduction of NOx. The ammonia 

reduces NOx through an SNCR reaction, with the hydrocarbon minimizing the ammonia 

slip. This enables higher reagent injection rates for NOx reductions than are achievable 

with a typical SNCR technology. The technology supplier states that the technology has 

the ability to achieve NOx emissions of less than 0.20 lb/MBtu without the use of a 

catalyst and large SCR reactor. Although initially targeting high NOx reductions, fullscale demonstrations to date have been limited to nominally 50 percent NOx reduction 

performance. 

Figure 3-4 

Mobotec ROFA and ROTAMIX Simplified Process Flow Diagram (Mobotec USA) 

3.1.8 ECOTUBE 

The ECOTUBE system utilizes retractable lance tubes that penetrate the boiler 

above the primary burner zone and inject high-velocity air as well as reagents. The lance 

tubes work to create turbulent airflow and to increase the residence time for the air/fuel 

mixture. In principle, the OFA and SNCR processes are combined in this technology. 

ECOTUBE is capable of reducing NOx, CO, and volatile organic compounds, 

while improving thermal efficiency, by optimizing the combustion process in boilers. An 

illustration of the ECOTUBE installation in a typical boiler is shown on Figure 3-5. 
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Figure 3-5 

ECOTUBE Installation in a Boiler 

The water-cooled ECOTUBEs are automatically retracted from the boiler on a 

regular basis and cleaned to remove layers of soot and other deposits. Additional benefits 

have been identified by the supplier, including furnace combustion improvements that 

increase efficiency, reduce fuel usage, and reduce corrosion and erosion 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 commercial operation. The ECO system is 

located downstream of an existing particulate control 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 passes 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 NOx, SO2, and Hg. This process results in the formation of nitric acid (HNO3), 

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 ESP. Scrubber effluents contain dissolved 

ammonium sulfate nitrate (ASN) salts along with solids and 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 carbon bed becomes saturated with Hg, it is 
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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 NOx, SO2, and Hg, 

respectively. 

Figure 3-6 

ECO Process Flow Diagram (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 NOx and SO2 emissions 

when burning coal. The only reagent required 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 chemicals in coal to complete their combustion 

reactions (to reach equilibrium conditions). 

The coal, with limestone added as a source of calcium for sulfur capture, is 

pulverized and introduced to the burner along with a limited amount of hot combustion 

air. The initial high temperature combustion gasifies and/or releases all the constituents 

of coal into the gas; i.e., carbon, sulfur, nitrogen, and ash compounds. At these high 

temperatures, and with limited available oxygen, the carbon aggressively commands 

oxygen to form CO from all sources, including such compounds as water. Nitrogen 

compounds that may form, such as NOx, hydrogen cyanide, and ammonium (NH4), are 

forced to the molecular form (N2) by the aggressive action of carbon for oxygen. In the 
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presence of calcium, the sulfur reacts to form 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 bottom of the boiler. The hot flue gas, with high 

concentrations of CO and H2 and low concentrations of NOx 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 CO2 and H2 to water. This prevents 

the formation of any new (thermal) NOx and completes the combustion with excess air. 

The clean hot gases then enter the boiler superheat section as 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 requires replacing the existing 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) 
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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 NOx (< 0.15 lb/MBtu), and 

control of SO2 emissions (< 0.5 lb/MBtu) with 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 gas. However, there are some variations in 

the oxidation energy source and byproduct recovery systems. A process flow diagram is 

shown on Figure 3-8. The process consists of the following: 

• e-Beam Chamber--This process uses a high-energy electron beam in a 

chamber, the e-Beam chamber, to oxidize SO2 to SO3 and NOx to a 

combination of N2, HNO3, and NO2. 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 sulfate 
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((NH4)2SO4)/ammonium nitrate (NH4NO3) 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 SO2 and NOx 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 been applied commercially on a 200 MW 

facility in China. 
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3.2 Particulate Matter Control Technologies 

 PM control technologies that were identified 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 included 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 Conditioning 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 lower concentration of high conductivity ionic sulfur oxide 

molecules in the flue gas. The high fly ash resistivity is not optimal for fly ash capture in 

an ESP and also limits the boiler fuel flexibility, 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 SO3, 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 the most effective method of determining the 

optimal injection rate of the flue gas conditioning agent. 

 The equipment needed for injection of the flue gas conditioning agent is usually 

skid-based. If SO3 is chosen as the flue gas conditioning agent, it is usually produced 

onsite through oxidation of SO2 in a catalytic converter. Dry or molten sulfur feedstock 

may be used; the feedstock is burned to produce SO2. Alternatively, ammonia can be 

used as an agent; ammonia is usually vaporized 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 the particulate. The 

success of fabric filters is predominantly due to their ability to economically meet the low 

particulate emissions limits for a wide range of particulate and fuel characteristics. 

Proper application of the fabric filter technology can result in clear stack discharges 
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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 current technology of choice when 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 the future addition of activated carbon injection 

to enhance gas-phase elemental Hg removal from 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 filter bags. The filter unit is typically divided 

into compartments that allow online maintenance or bag replacement. The quantity of 

compartments is determined by maximum economic compartment size, total gas volume 

rate, air-to-cloth (A/C) ratio, and cleaning system design. Each compartment includes at 

least one hopper for temporary storage of the collected fly ash. A cutaway view of a 

PJFF compartment is illustrated on Figure 3-9. 

Fabric bags vary in composition, length, and cross section (diameter or shape). 

Bag selection characteristics vary with cleaning technology, emissions limits, flue gas 

and ash characteristics, desired bag life, capital cost, A/C ratio, and pressure differential. 

Fabric bags are typically guaranteed for 3 years 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 bag, a metal cage is installed on the inside of the bag. The 

flue gas passes up through the center of the bag into the outlet plenum. The bags and 

cages are suspended from a tubesheet. 

Cleaning is performed by initiating a downward pulse of air into the top of the 

bag. The pulse causes a ripple effect along the length of the bag. This releases the dust 

cake from the bag surface, 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 standard feature of the technology. 
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Figure 3-9 

Pulse Jet Fabric Filter 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 materials also allow the PJFF to operate at a 

much higher cloth velocity, which significantly reduces the size of the unit and the space 

required for installation. 
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3.2.3 Compact Hybrid Particulate Collector 

A variant of the PJFF is the compact hybrid particulate collector (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 remove PM to meet the required 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 technology in a smaller footprint area, with less steel and filtration 

media; both capital and operating costs are lower than those of conventional fabric filters. 

3.2.4 Max-9 Electrostatic Fabric Filter 

The Max-9 electrostatic filter is essentially a high-efficiency 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 particles 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. Consequently, 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 manifold; holes in the blowpipes 

located above the filters direct the cleaning air pulse down through the filters. The 

cleaning sequence is controlled by timers that trigger solenoids. The high voltage system 

operates at very low current densities and at a steady state. There is no danger of fire 

caused by sparking, and the transformer/rectifier requires no voltage control. 
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Figure 3-10 

Max-9 Electrostatic Filter (Source: GE Environmental) 

The Max-9 can be supplied as shop assembled 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. 
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3.3 Draft System Impacts 

 The addition of an SCR or hybrid SCR/SNCR would result in additional pressure 

requirements beyond the capabilities of the current fans on the SJGS units. To provide 

for this additional pressure drop, three alternatives are available. These alternatives are 

discussed in the following subsections. 

3.3.1 New Booster Fans 

 The existing booster fans are currently being retrofitted with larger rotors to allow 

compliance with the upcoming consent decree upgrades. Further modifications to the 

booster fans are not possible within the existing housing. 

 New booster fans would be a possible option. Typically, the new fans would be 

installed near the current ones and the ductwork rerouted to save outage time. This 

alternative would not change the furnace operating 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 rerouted. 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 fan, the boiler and ductwork may need to be 

stiffened to handle the increased boiler pressure. The increased pressure would increase 

the leakage of hot flue gas and ash out of the boiler and ductwork, resulting in increased 

maintenance requirements. This leakage would cause increased housekeeping 

requirements around the boiler area and an unpleasant working environment for plant 

personnel. 

3.3.3 Balanced Draft Conversion 

 Conversion to balanced draft operation would move the balance point (zero 

relative pressure) inside the furnace. SJGS currently operates with the balance point just 

before the booster fans. The following modifications would be necessary for the 

balanced draft conversion: 

• New induced draft fans and motors. 
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• Potentially, new motors for the existing forced draft fans to improve fan 

efficiency. 

• Boiler wall stiffening to operate 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 would have significantly less ash and soot leakage around 

the boiler working area and would experience higher unit availability. 

 Previous studies have shown that the benefits of this alternative offset the costs in 

the majority of cases. Based on the previous analyses, costs for the SCR or hybrid 

installations included in later sections will include the cost of a balanced draft conversion. 
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4.0 BART Implications of the 

Consent Decree Technology Selection 

As previously discussed in Section 1.1, PNM was required, under a consent 

decree action, to implement environmental system upgrades at SJGS. The environmental 

upgrade process is currently in progress with the installation of state-of-the-art LNBs 

with OFA ports and an NN system for NOx control. For SO2 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 SO2 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 flue gas. Other balance-of-plant system 

upgrades are also being performed to support 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 NOx and PM control technologies are included in the 

BART emissions control scenario, since the state of New Mexico will participate in the 

WRAP SO2 trading program. 

4.1 NOx Consent Decree Control Technologies 

4.1.1 Description of NOx Consent Decree Upgrades 

B&W will retrofit all four units with state-of-the-art integrated low-NOx

combustion systems. The systems for all units will include LNB (Model DRB-4Z), new 

dual-zone NOx ports, and an NN system. To accommodate 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 NOx Consent Decree Upgrades Control Effectiveness 

 B&W provided an emissions performance guarantee for the installation of consent 

decree controls for NOx reduction. NOx 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 NOx emission limit can be achieved. The 

control effectiveness used for the consent decree NOx upgrades, which is defined as the 
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controlled emissions level in terms of the amount of pollutant generated per unit of heat 

input (lb/MBtu) is the guaranteed level of 0.293 lb/MBtu. 

The pre-consent decree operation emissions 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 and the design basis heat input. Compared 

to the pre-consent decree operation emissions 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 1,794 ton/yr at 

Unit 1 to 2,572 ton/yr at Unit 3. These results are detailed in Table 4-2. 

4.1.3 NOx 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 capital 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 emissions reduction from the new 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 NOx consent decree upgrades ranges 

from 482 $/ton for Unit 3 to 793 $/ton for Unit 1. 

4.1.4 Summary of NOx Consent Decree Upgrades 

The NOx emissions control being installed at SJGS as a result of the consent 

decree are state-of-the-art combustion controls with a manufacturer’s performance 

guarantee of 0.293 lb/MBtu. Although 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 NOx limit. 

 SJGS fires a local New Mexico coal. The coal burned at SJGS has been referred 

to as both a subbituminous coal and a bituminous 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, the ASTM D388 classification would place the 

SJGS coal in either of the bituminous Group 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 NOx 
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 Table 4-1 

Consent Decree Technologies Control Effectiveness (Annual Average Emissions Rates) 

Unit SJGS 1 SJGS 2 SJGS 3 Design Basis Heat Input Data, MBtu/h 

3,707 3,688 5,758 

NOx Emissions Cases 

lb/MBtu lb/h ton/yr lb/MBtu lb/h ton/yr lb/MBtu lb/h ton/yr lb/MB

Pre-Consent Decree Operation 

0.43 1,592.0 5,394 0.45 1,649.3 6,179 0.42 2,405.5 9,004 0.4

Consent Decree Upgrades (LNB/OFA/NN) 

0.30 1,112.1 4,140 0.30 1,106.4 4,119 0.30 1,727.4 6,431 0.3

PM Emissions Cases 

lb/MBtu lb/h ton/yr lb/MBtu lb/h ton/yr lb/MBtu lb/h ton/yr lb/MB

Pre-Consent Decree Operation 

0.050 185.4 690 0.050 184.4 687 0.050 287.9 1,072 0.05

Consent Decree Upgrades (PJFF) 

0.015 55.6 207 0.015 55.3 206 0.015 86.4 322 0.01

Notes: 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 were annual 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. 
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Table 4-2 

Control and Cost-Effectiveness Results 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 Basis).

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 fundamental understanding of the variation in 

NOx formation from different types of US coals explains why the expected NOx 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 volatile and has a lower oxygen and moisture 

content than PRB coals. The greater volatility and higher oxygen and moisture content 

found in PRB fuels are key to the lower NOx emissions seen in boilers combusting PRB 

coal. The high volatility in PRB coals reduces 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 flame temperature and, therefore, reduces the 

formation of thermal NOx. The nitrogen content in the fuel affects NOx generation 

because of the oxidation of fuel-bound nitrogen. As it relates to the amount of NOx

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 subbituminous 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. 
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Table 4-3 

Coal Properties Comparison 

Another factor affecting the potential for NOx 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 NOx emissions reduction because a smaller volume boiler 

will operate hotter, thus increasing thermal NOx formation. Additionally, SJGS Units 1 

and 2 have limited flame length because of the high heat input burners on the front wall 

of the boiler. This reduces the effectiveness of the overfire air from the OFA ports. 

4.2 Particulate Matter Consent 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 decree. The PJFFs will be installed downstream 

of the existing hot-side ESPs and air heaters. After the commissioning of the PJFF, the 

hot-side ESP will be de-energized. 

 As previously noted, Hg emissions are not being considered in the BART 

analysis. However, it is important to note that the PJFF will also serve as a component of 

the Hg control system. Activated carbon will be injected into the flue gas downstream of 

Typical SJGS Typical

Subbituminous New Mexico Low-Sulfur

PRB Subbituminous Bituminous

Ultimate 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 matter is referenced from SJGS consent decree

 Environmental Project Design Criteria, Sargent & Lundy, June 15, 2006.
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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 necessitate modifications to the existing booster 

fans to handle the additional pressure requirements. 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 pressure, 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 performance guarantee that the total filterable 

particulate matter (PM10) will be controlled to 0.015 lb/MBtu 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 ton/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 amount of total emissions reduction, the costeffectiveness of the new PJFF is very high, 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 emissions control, SJGS will have the most 

stringent control technology available for limiting the emissions of PM10. 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 PM10 and 

represents a BACT level of pollution control. Therefore, the new PJFF equipment at 

SJGS should be considered as BART for PM emissions reduction. 
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4.3 Summary of Consent Decree Control Technologies 

The evaluation of the consent decree control technologies currently being 

implemented at SJGS for the BART analysis indicates that the new LNB, OFA, and NN 

installed for NOx emissions represent the state-of-the-art combustion control technology, 

and the PJFF installed for PM emissions is the most stringent control technology for PM 

emissions control. 
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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 technically infeasible options. This section 

describes how the technical feasibility of a control technology is defined by the EPA in 

the BART guidelines. The technologies identified 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. However, to provide additional 

support for that determination, the BART analysis 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 showing that the technology is commercially 

unavailable and/or there are insurmountable technical difficulties with applying the 

technology to the applicable unit. Other factors 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 rest of the facility. 

• Adverse community impacts. 

Additionally, a technology is technically infeasible if its level of emissions control 

does not achieve the required permit emissions 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 procedure allows for the consideration of the less 

costly control technology, therefore eliminating the need to evaluate higher cost 

technologies. 

For all the technologies identified as available in Section 3.0, a determination was 

made regarding the technical feasibility of the technology at the SJGS site on the basis of 

the criteria highlighted above. 
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5.1 Technically Infeasible Additional NOx Control Technology 

Alternatives 

5.1.1 Selective Non-Catalytic Reduction 

 SNCR was determined to be technically infeasible because the controlled NOx

emissions do not meet the required presumptive emissions limits. A budgetary 

performance evaluation from an SNCR vendor indicated that the controlled NOx

emissions level would be 0.24 lb/MBtu for all four units at SJGS. A lower controlled 

NOx emissions level of 0.23 lb/MBtu, which would meet the presumptive limit, could be 

achieved if the ammonia slip limit is raised from 5 ppm to 10 ppm. However, the higher 

ammonia slip will significantly increase the risk for blinding fabric filter bags and 

shortening bag life. The risk is also high for air heater pluggage from ammonium 

bisulfate. Air heater pluggage degrades air heater performance and directly impacts plant 

efficiency. Therefore, the 10 ppm ammonia slip cannot be tolerated, thus rendering the 

SNCR infeasible as an additional control technology alternative. 

5.1.2 Natural Gas Reburn 

 Natural gas reburn in the SJGS boilers is not technically feasible because of the 

lack of space in the boiler for sufficient residence 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 height is limited. In addition, a new natural 

gas supply line would be required, since the 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 NOx control technology. 

5.1.3 Mobotec ROFA and ROTAMIX 

Mobotec’s ROTAMIX technology is not considered technically 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 variant of the OFA system that is already being 

added as a result of the consent decree. Although the Mobotec system may offer 

advantages over conventional scrubbing, the increased volumes of particulate that would 

need to be collected, the expected additional costs for sorbent, and the limited large-scale 

experience with the system are significant factors that make it infeasible for this 

application. 
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5.1.4 NOxStar 

 The major consideration for the NOxStar technology is that it currently has only 

one major installation in the United States and may require the installation of a single 

layer of in-duct catalyst (NOxStar Plus) to achieve the advertised levels of NOx reduction. 

Availability of natural gas is a factor that must be considered when assessing the 

technical feasibility of this technology. There is no natural gas supply at SJGS. In 

addition, through recent discussions, the supplier has identified limited ability and 

willingness to market the commercial technology. 

5.1.5 ECOTUBE 

 This technology has been demonstrated in installations on industrial/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 proven 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 been pilot tested at a 

facility burning a low sulfur (< 1.5 percent) subbituminous coal or in a large, 

commercial-scale system. Therefore, it is considered not technically feasible for retrofit 

at SJGS. It should be noted that the first 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 demonstration 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 appears to offer significant advantages, it 

is still an experimental system with little proven operational data and only one known 

medium utility-scale installation. 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 Additional PM Control Technology 

Alternatives 

5.2.1 Flue Gas Conditioning with Hot-Side ESP 

Flue gas conditioning improves the operability 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 evaluated as applicable for SJGS. 

5.2.2 Compact Hybrid Particulate Collector 

The COHPAC system currently available 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 consent decree. Because of this consideration, 

the COHPAC was not evaluated as a technically feasible control 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 screening process (Step 2 of the BART 

determination), the following technologies were identified as feasible upgrades to the 

ongoing consent decree environmental upgrades at SJGS for NOx reduction: 

• SCR. 

• SNCR/SCR hybrid. 

There were no additional PM control technologies 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 F

PNM San Juan Generating Station Control Te060607 

Table 5-1 

Technically Feasible Additional NOx Control Technology Alternatives 

Pollutant Philosophy Technology 

Technically Feasible and Applicable? Reasons for Technical Infea

NOx Control technologies: SNCR No Emissions control does not a

presumptive limit. 

 SCR Yes --  SNCR/SCR Hybrid Yes --  Gas Reburn No Boiler not suitable for natura

due to lack of residence time

 Mobotec ROFA and ROTAMIX No ROTAMIX technology not d

scale boiler systems. ROFA an OFA variant. 

 ECOTUBE No Not applied to SJGS scale b PowerSpan No In early commercial applicat

to SJGS scale boiler systems

 Phenix Clean Combustion No Still in demonstration and te

applied to SJGS scale boiler 

 e-SCRUB No Still in demonstration and te

applied to SJGS scale boiler 
Technical F

PNM San Juan Generating Station Control Te060607 

Table 5-2 

Technically Feasible Additional PM Control Technology Alternatives 

Pollutant Philosophy Technology 

Technically Feasible and Applicable? Reasons for Technical Infea

PM Control Technologies: Flue Gas Conditioning with HotSide ESP No Level of emissions control d

expected level of control wi

 Compact Hybrid Particulate 

Collector 

No Level of emissions control d

expected level of control wi

 Max-9 Electrostatic Fabric Filter No Not applied to SJGS scale b
 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 effectiveness evaluation of technically feasible 

additional control technology alternatives for controlling NOx emissions beyond that 

achieved by technologies that will be installed for the consent decree. 

6.1 Control Effectiveness 

The evaluation process in Step 3 determines the control effectiveness of the 

additional NOx control technologies. Control effectiveness is expressed in a common 

metric based on the amount of pollutant generated per unit of heat input (lb/MBtu). The 

evaluation of the control effectiveness was translated into an hourly rate (lb/h) for each 

pollutant, according to the design basis heat input data for each SJGS unit. The 

evaluation of control effectiveness was based on information indicated in Subsection 

1.2.3. 

Table 6-1 indicates the control effectiveness of each additional NOx control 

technology. This control effectiveness was calculated from the consent decree values 

discussed in Section 4.0. 

The control effectiveness for each technology is also summarized in the Design 

Concept Definition tables in Appendix B. 
Evaluation of Technica

PNM San Juan Generating Station Control T060607  Table 6-1 

NOx Control Effectiveness for Additional Control Technology Alternatives (Annual Average Emiss

Unit SJGS 1 SJGS 2 SJGS 3 Design Basis Heat Input Data, MBtu/h 

3,707 3,688 5,758 

NOx Emissions Cases 

lb/MBtu lb/h ton/yr lb/MBtu lb/h ton/yr lb/MBtu lb/h ton/yr lb/M

Consent Decree Upgrades (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.

SCR 0.07 259.5 966 0.07 258.2 961 0.07 403.1 1,501 0.0SNCR/SCR Hybrid 0.18 667.3 2,484 0.18 663.8 2,471 0.18 1,036.4 3,859 0.Notes: 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 NOx control technologies that are being considered, an 

impact analysis was performed as part of the 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-effectiveness of each technology could be made. The definition 

of cost-effectiveness is provided in Subsection 1.2.4 of this report. In summary, the four 

types of impact analyses performed 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 define the design 

parameters for each additional NOx control technology that was identified as technically 

feasible. The design parameters contain all pertinent information on the control 

technology system for specific application to the source. Examples of these design 

parameters include type of reagent used and consumption rate, type of byproduct 

produced and production rate, flue gas pressure drop across the control technology, etc. 

The information used to define the design 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 technology that was identified as technically 

feasible for application at the SJGS site are 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 control 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 estimation 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 consumption 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 estimated on the basis of the typical power 

consumption of similar equipment of an equivalent 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 evaluated were the water consumption and 

disposal requirements for the byproduct and waste generated by each control technology. 

All quantities of water consumption and byproduct 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 useful 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. Therefore, 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 technology 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 removed. 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 calculated during the BART determination: 

average and incremental cost-effectiveness. The general definition of the average and 

incremental cost-effectiveness 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 all the identified technically feasible 

control technologies. A summary of the calculated impact analysis is presented in 

Appendix C. 

For all the additional NOx control technologies evaluated, a summary table was 

developed for the impact analysis performed and the resultant 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 each group of control 

technologies was identified. Control technologies that lie on this least-cost envelope are 

“dominant controls” that should be the focus for the BART determination. Dominant 

controls are the technologies that have the lowest cost for implementation per quantity of 

pollutant removed. Therefore, these technologies are considered more cost effective for 

emissions reduction, barring any additional factors or considerations. 

For all the dominant controls, the incremental cost-effectiveness between a 

technology and the next most stringent control technology was also calculated. This 

incremental cost-effectiveness indicates the additional cost to increase the removal of 

pollutant when comparing technologies that have different emissions removal 

capabilities. 
Impact Analysis and 

PNM San Juan Generating Station Additional Control Te060607 

Table 7-1 

Impact Analysis and Cost-Effectiveness Results of Additional NOx Control Technologies 

Total Total

Emission Expected Expected Expected Capital Annualized Increm

Performance Emission Emission Emission Investment Cost Cost Co

Level Rate Rate Reduction (TCI) (TAC) Effectiveness Effectiv

All Feasible Technologies (lb/MBtu) (lb/h) (ton/yr) (ton/yr) (1,000$) (1,000$) ($/ton) ($/to

SJGS Unit 1

Selective Catalytic Reduction (SCR) 0.07 259.5 966 3,174 156,805 20,525 6,466 2,84SNCR/SCR Hybrid 0.18 667.3 2,484 1,656 104,436 16,207 9,786 -- 

SJGS Unit 2

Selective Catalytic Reduction (SCR) 0.07 258.2 961 3,158 169,251 21,891 6,932 3,45SNCR/SCR Hybrid 0.18 663.8 2,471 1,648 108,628 16,670 10,117 -- 

SJGS Unit 3

Selective Catalytic Reduction (SCR) 0.07 403.1 1,501 4,931 215,568 28,359 5,752 1,16SNCR/SCR Hybrid 0.18 1,036.4 3,859 2,572 168,507 25,606 9,954 -- 

SJGS Unit 4

Selective Catalytic Reduction (SCR) 0.07 395.4 1,472 4,837 199,558 26,592 5,497 75SNCR/SCR Hybrid 0.18 1,016.8 3,786 2,524 161,572 24,849 9,846 -- 

Notes: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 

PNM San Juan Generating Station Additional Control Te060607 

16,00016,50017,00017,50018,00018,50019,00019,50020,00020,50021,000

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

SNCR/SCR Hybrid Selective Catalytic Reduction (SCR) Dominant Controls

Figure 7-1 

SJGS Unit 1 Additional NOx Control Technology Cost-Effectiveness 
Impact Analysis and 

PNM San Juan Generating Station Additional Control Te060607 

16,50017,00017,50018,00018,50019,00019,50020,00020,50021,00021,50022,000

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

SNCR/SCR Hybrid Selective Catalytic Reduction (SCR) Dominant Controls

Figure 7-2 

SJGS Unit 2 Additional NOx Control Technology Cost-Effectiveness 
Impact Analysis and 

PNM San Juan Generating Station Additional Control Te060607 

25,00025,50026,00026,50027,00027,50028,00028,50029,00029,50030,000

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

SNCR/SCR Hybrid Selective Catalytic Reduction (SCR) Dominant Controls

Figure 7-3 

SJGS Unit 3 Additional NOx Control Technology Cost-Effectiveness 
Impact Analysis and 

PNM San Juan Generating Station Additional Control Te060607 

24,50024,75025,00025,25025,50025,75026,00026,25026,50026,75027,000

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

Expected Emissions Reduction (ton/yr)

Total Annualized Cost (1,000$/yr)

SNCR/SCR Hybrid Selective Catalytic Reduction (SCR) Dominant Controls

Figure 7-4 

SJGS Unit 3 Additional NOx Control Technology Cost-Effectiveness
 Impact 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 NOx control technologies evaluated lie on the least-cost 

envelope and are dominant control technologies for the additional reduction of NOx

emissions than that currently expected after the completion of the consent decree 

upgrades. 

These dominant control technologies were modeled to determine the visibility 

change or improvement. The modeled visibility change or improvement was used for 

determining the NOx 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 for the hybrid technology (refer to Table 7-1) can be 

attributed to the high TAC, which was just slightly lower than that of the SCR 

technology. Another factor that affects the cost-effectiveness 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 required 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 Station Visibility Impacts 

060607 8-1 

8.0 Visibility Impacts 

 Visibility impact is the fifth step to consider 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 consisted of the technologies and unit 

operations associated with the consent degree. Second model runs were conducted for 

the control technologies identified for each unit 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 meteorology modeled. The difference in the 

averages between the first and second phases is the expected degree of improvement in 

visibility. The following sections discuss the modeling methodology in greater detail. 

8.1 Introduction 

 The objective of this modeling analysis is to evaluate visibility impacts for the 

control technologies selected using the first four steps of the BART analysis (as discussed 

in the previous sections) for PNM’s SJGS Units 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 identified as BART-applicable sources by the 

NMED in January of 2007 under the Regional Haze and BART rule guidelines. 

 The air dispersion modeling analyses presented in this report were conducted in 

accordance with the CALMET/CALPUFF Protocol for BART Exemption Screening 

Analysis for Class I Areas in the Western United States dated August 15, 2006, 

(hereinafter referred to as the WRAP Protocol) 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 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), and the results are not known. Therefore, it is not known 

how these errors have affected the previously described WRAP modeling or the modeling 

conducted for this report. 
PNM San Juan Generating Station Visibility Impacts 

060607 8-2 

8.2 Source Description 

 The SJGS facility is located in Farmington, New Mexico, within San Juan 

County. It has four pulverized coal units that 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 units 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 addressed 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 Park 
PNM San Juan Generating Station 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

0

Y 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 CALPUFF modeling system includes three main 

components: CALMET, CALPUFF, CALPOST. The system also includes a large set of 

preprocessing programs designed to interface with the model to process standard, 

routinely available meteorological and geophysical data sets. In the simplest terms, 

CALMET is a meteorological model that develops hourly wind and temperature fields on 

a three- dimensional gridded modeling domain. Associated fields, such as mixing height, 

surface characteristics, and dispersion properties, are also included in the file produced by 

CALMET. CALPUFF is a transport and dispersion 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 simpler, not gridded meteorological data much 
PNM San Juan Generating Station Visibility Impacts 

060607 8-4 

like existing plume models. Temporal and spatial variations in the meteorological fields 

selected are explicitly incorporated into the resulting distribution of puffs throughout a 

simulation period. The primary output files from CALPUFF contain either hourly 

concentrations or hourly deposition fluxes evaluated at selected 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 extinction coefficients and related measures 

of visibility, reporting these for a 24 hour averaging period at selected locations. 

 The geophysical and meteorological data 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 system suggested in the WRAP protocol 

and used by the WRAP RMC for the initial 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 modeling. Based on what was provided, it did 

not appear that the WRAP RMC speciated the PM/PM10 emissions; therefore, the use of 

POSTUTIL and CALSUM would 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 domain established in the provided 

GEO.DAT file. The origin coordinates of the domain was Latitude 40.0 N, Longitude 

97.0 W; these coordinates were assigned as the 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 measured 864 km in the east-west (X) and north-south (Y) 
PNM San Juan Generating Station 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

-100

Y 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 Meteorological Modeling Domain 

8.5 Geophysical and Meteorological Data 

 As previously noted, all the geophysical and meteorological data necessary to 

conduct the Class I visibility modeling were provided by the WRAP RMC and were 

downloaded from its Web site for use in the aforementioned analyses. 
PNM San Juan Generating Station Visibility Impacts 

060607 8-6 

8.5.1 Mesoscale Model Data 

 Pennsylvania State University in conjunction with the National Center for 

Atmospheric Research Assessment Laboratory have developed mesoscale eteorological 

data sets of prognostic wind fields, 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 meteorological data. The daily MM5 meteorological 

data files provided by the WRAP RMC for the years 2001, 2002, and 2003 were utilized 

as input into CALMET. 

 The MM5 data sets used to simulate atmospheric variables within the modeling 

domain in CALMET, although advanced, lack the fine detail of specific temporal and 

spatial meteorological variables and geophysical data. These variables were processed 

into the appropriate format and introduced 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 Station and Processing 

 The surface station data for the CALPUFF analysis consisted of data from 

National Weather Service (NWS) stations or Federal Aviation Administration (FAA) 

flight service stations within the CALMET domain. Figure 8-3 provides an illustration of 

the location of the surface stations 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 precipitation code that was based on current 

weather conditions. 

 The surface data were preprocessed 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 and did not supplement it with additional upper air data. 

Because of this, the modeling conducted for this report followed these procedures and did 

not include any additional upper 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 precipitation recording stations within the CALMET domain. 

Figure 8-4 provides an illustration of the location of the precipitation stations used. 
PNM San Juan Generating Station 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

100

Y LCC (km)

PNM

SJGS

2001 Surface Stations

2002 Surface Stations

2003 Surface Stations

Figure 8-3 

Surface Stations 
PNM San Juan Generating Station 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

100

Y 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 precipitation data files were downloaded from 

the WRAP RMC Web site for use in the modeling analyses. A list of the precipitation 

stations is provided in Appendix E, Section 2. 
PNM San Juan Generating Station 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.DAT file was downloaded from the WRAP 

RMC Web site for use in the analyses. Figure 8-5 depicts the terrain 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

-100

Y 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 Plot 
PNM San Juan Generating Station Visibility Impacts 

060607 8-10 

-1300 -1200 -1100 -1000 -900 -800 -700 -600

X LCC (km)

-800

-700

-600

-500

-400

-300

-200

-100

Y 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 geographical and meteorological files provided by WRAP 

RMC to create the CALMET.DAT for use in CALPUFF. 

8.6 CALPUFF 

 The CALPUFF modeling system is recommended as the preferred modeling 

approach for use in BART analyses. CALPUFF and its meteorological model, 

CALMET, are designed to handle the complexities posed by complex terrain, large 

source-receptor distances, chemical transformation and deposition, as well as other issues 

related to Class I visibility impacts. The CALPUFF modeling system has been adopted 

by the EPA as a guideline model for source-receptor distances greater than 50 km and for 

use on a case-by-case basis in complex flow situations for shorter distances 
PNM San Juan Generating Station Visibility Impacts 

060607 8-11 

(68 FR 18440-18482). CALPUFF is recommended for Class I impact assessments by the 

Federal Land Managers Workgroup (FLAG 2000) and the Interagency Workgroup on Air 

Quality Modeling (IWAQM) (EPA 1998). The final BART guidance recommends 

CALPUFF as “the best modeling application available for predicting a singe source’s 

contribution to visibility impairment” (70 FR 39122). 

 CALPUFF is a non-steady-state, Lagrangian, puff transport and dispersion model 

that advects Gaussian puffs of multiple pollutants from modeled sources. CALPUFF’s 

algorithms have been designed to be applicable on spatial scales from a few tens of 

meters to hundreds of kilometers from a source. It includes algorithms 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 contains an option to allow puff splitting in 

the horizontal and vertical directions, which extends the distance range of the model. The 

primary outputs from CALPUFF are hourly concentrations and hourly deposition fluxes 

evaluated at user-specified receptor locations. 

 CALPUFF (Version 6.112, Level 060412) was 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 create a single yearly concentration file 

for use in CALPOST. 

8.6.1 CALPUFF Domain and Variables 

 The WRAP RMC computational domain covered an extensive area, specifically, 

New Mexico, eastern Arizona, southeastern Utah, and southern Colorado. To reduce the 

computational requirements of the model, the CALPUFF computational domain was 

reduced to a subset of the WRAP RMC CALMET 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 receptors with receptor 

elevations for the Class I areas, which were created and distributed by the National Park 

Service (NPS). Specifically, the array consisted of receptors spaced to cover the extent of 

the Class I areas. Receptor elevations were included in the 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 Station Visibility Impacts 

060607 8-12 

-1300 -1200 -1100 -1000 -900 -800 -700 -600

X LCC (km)

-800

-700

-600

-500

-400

-300

-200

-100

Y 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 modeling analyses. Stack 

tip downwash, a phenomenon different from building-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 this, stack tip downwash 

was used for the analyses. 
PNM San Juan Generating Station Visibility Impacts 

060607 8-13 

8.6.4 Ozone Concentrations 

Background ozone concentrations are important for the photochemical conversion 

of SO2 and NOx to SO4 and NO3, 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 method) to represent the 

background ozone concentrations within the domain. 

The hourly ozone concentrations files that 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 the WRAP RMC Web site. In addition to the 

hourly ozone data, the same monthly average 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 using the same fixed background ammonia 

level of 1 ppb that was used for the initial modeling performed by WRAP RMC. 

8.6.6 Unit-Specific Source Data 

As previously presented in Sections 3 through 6 of this report, various emissions 

control strategies and technologies have been evaluated for SJGS Units 1, 2, 3, and 4. 

The baseline emissions for PM, NOx, and SO2 were based on emissions limits established 

as part of the consent decree between PNM and NMED. Additionally, emissions of SO4

were included in the analyses. The emissions were composed of the relative fraction of 

fine and course particles obtained by using speciation profiles available from the Federal 

Land Managers through the NPS (http://www2.nature.nps.gov/air/permits/ect/index.cfm). 

For this analysis, condensable PM10 was subdivided into inorganic and organic 

compounds using the NPS speciation spreadsheets. The inorganic portion was by default 

assumed to be H2SO4 and was modeled as SO4. 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 technologies and/or control levels can then be 

factored into the technology evaluation process to reach a BART determination. 

Because New Mexico participates in an SO2 trading program, an SO2 BART 

analysis was not evaluated in Steps 1 though 4, and was not modeled as a separate 

feasible control technology option. However, SO2 emissions were included as a modeled 

pollutant as part of both the baseline and post-baseline controlled scenarios. Therefore, 

NOx and PM10 are the only pollutants subject to BART analyses. However, as previously 
PNM San Juan Generating Station 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 further evaluation was undertaken. PM10 emissions 

were assumed the as consent decree (baseline) limits and speciated as described in the 

baseline modeling section. NOx was the only pollutant evaluated in this analysis. 

As specified in Section 7.0, additional NOx control was proposed for the BART 

control scenario. The aforementioned approach consisted of the potential addition of 

SCR or SNCR/SCR hybrid on all four units for additional NOx control. For NOx

technologies with a catalyst, an additional 1 percent SO2 to SO3 conversion based on 

design basis economizer outlet SO2 and zero removal in the PJFF was accounted for and 

added to the NPS speciation spreadsheet SO4 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) was used to process the CALPUFF 

outputs by producing tabulations summarizing the results of the simulations and 

identifying, for example, the highest and second-highest hourly average 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 deciviews) and reports these for a 24 hour averaging time. 

8.7.1 Light Extinction 

Light extinction must be computed to calculate visibility. CALPOST has seven 

methods for computing light extinction. As recommended by the WRAP RMC protocol, 

this BART technology analysis used Method 6, which computes extinction from 

speciated PM with monthly Class I area-specific 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 humidity. This BART analysis used 

relative humidity correction factors [f(RH)s], obtained from Table A-3 of the EPA’s 

Guidance for Estimating Natural Visibility Conditions under the Regional Haze Rule

(EPA, 2003), to determine sulfate and nitrate concentrations outputs from CALPUFF. 

The f(RH) values for the Class I areas that were assessed are provided in Table 8-6. The 

default Rayleigh scatter value (bray) of 10 Mm-1 was also used. The light extinction 

equation is as follows: 

bext = 3 * f(RH) * [(NH4)2SO4] + 3* f(RH) * [NH4NO3] + 4*[OC] + 1* [PMf] 

+ 0.6*[PMc] + 10* [EC] + bray 
PNM San Juan Generating Station 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 Station Visibility Impacts 

060607 8-16 

Table 8-4 

Consent Decree Baseline 

CALPUFF Modeling Emission Rates 

Primary Particle Speciation(b) 

Unit 

SO2 

Emission 

Rate 

(lb/h) 

NOx

(a) 

Emission 

Rate 

(lb/h) 

EC 

(lb/h) 

Fine PM 

(lb/h) 

Course 

PM 

(lb/h) 

H2SO4

(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 NOx emission rate is based on an assumed 24 hour rolling averaging basis versus 

the 30 day rolling average basis for each unit from the consent decree. 

(b)Primary particulate speciated into the following categories using the NPS Speciation 

Spreadsheet: Elemental Carbon (EC), Fine PM, Course PM, and SO4. Refer to Appendix E, 

Section 4. 

(c)H2SO4 assumed to be 100 percent of the SO4 emissions calculated by the NPS Speciation 

Spreadsheet. 
PNM San Juan Generating Station Visibility Impacts 

060607 8-17 

Table 8-5 

NOx BART Control Technologies 

CALPUFF Modeling Emission Rates 

Primary Particle Speciation(a,c)

Unit 

SO2 

Emission 

Rate 

(lb/h) 

NOx 

Emission 

Rate 

(lb/h) 

EC 

(lb/h) 

Fine PM 

(lb/h) 

Course 

PM 

(lb/h) 

H2SO4

(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 following categories using the NPS Speciation 

Spreadsheet: Elemental Carbon (EC), Fine PM, Course PM, and SO4. Refer to Appendix E, 

Section 4. 

(b)H2SO4 assumed to be 100 percent of the SO4 emissions calculated by the NPS Speciation 

Spreadsheet and for the NOx control technologies with catalyst accounts for an additional 

1.0 percent SO2 to SO3 conversion based on design basis economizer outlet SO2 levels and 

0 percent removal in the PJFF. 

(c)Ammonia slip from the pollution control process has not been included in the modeling 

analysis. 
PNM San Juan Generating Station 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 Rule 
PNM San Juan Generating Station 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 Conditions 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 (μg/m3

) 

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 methodology outlined in the previous sections, 

the CALPUFF-modeled visibility impacts from Units 1, 2, 3, and 4 for each NOx 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 exemption guideline value of 0.5 dv, subjecting 

the units to the aforementioned BART engineering and refined modeling analysis. 
PNM San Juan Generating Station 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 impacts of the entire 

plant, assuming that the same control technology (SCR or hybrid) is installed on each of 

the four units. Tables 8-12 through 8-18 illustrate the resultant visibility impacts of each 

control technology on a unit-by-unit basis. 
PNM San Juan Generating Station 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 6.565 
PNM San Juan Generating Station 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 7.721 
PNM San Juan Generating Station 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 1.748 
PNM San Juan Generating Station 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 1.740 
PNM San Juan Generating Station 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 2.516 
PNM San Juan Generating Station 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 2.455 
PNM San Juan Generating Station 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 2.385 
PNM San Juan Generating Station 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 2.374 
PNM San Juan Generating Station 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 2.892 
PNM San Juan Generating Station 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 3.164 
PNM San Juan Generating Station Visibility Impacts 

060607 8-31 

8.8.3 WRAP RMC Baseline Scenario 

 The results of the WRAP RMC baseline 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), and 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 results of the analysis conducted by the WRAP RMC. These 

tables summarize the scenarios and the maximum visibility (deciview) improvement seen 

at any of the 16 Class I areas at any time over the 2001 to 2003 period. The expected 

degree of visibility improvement for each control scenario for each unit analyzed was 

determined by the difference in the average visibility 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 the SJGS's baseline case for 

the purposes of this analysis. 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 analysis, the total average amount of visibility improvement 

at all 16 Class I areas, assuming that all units installed the same control technology, was 

compared to the total average visibility improvement from the consent decree baseline. 

These visibility improvements for the three cases range from 0.2 dv to 0.6 dv of expected 

visibility improvement above the consent decree technology baseline case, which is less 

than or equal to the visibility improvement 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 control options, and methodologies 

can yield variations between the WRAP modeling and SJGS BART modeling. In the 
PNM San Juan Generating Station Visibility Impacts 

060607 8-32 

case of the visibility impacts at Mesa Verde Class I area, WRAP’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, shown in Table 8-8 or the additional control 

scenarios for SCR or hybrid control technology options, shown 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 consent decree technology baselinescenario (Table 8-

8) or the SCR and Hybrid control technology scenarios (Table 8-9 and 8-10). 
PNM San Juan Generating Station 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 difference between the average baseline scenario and 

average control technology scenario. 

8.9 Visibility Improvement Cost-Effectiveness 

The visibility improvement cost-effectiveness 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 alternatives shown in Table 7-1. The maximum 

and average modeled visibility impacts at the 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 visibility improvement cost effectiveness 

summary in Table 8-21: 

• Pre-consent decree to consent decree. 

• Consent decree to additional NOx control technology alternatives scenario. 

• Pre-consent decree to additional NOx control technology alternatives 

scenario. 

The pre-consent decree visibility impact was based on the visibility modeling 

performed by the RMC for WRAP for the determination of BART eligibility. 
PNM San Juan Generating Station 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 performed in two stages. First, a BART analysis was 

performed for the consent decree technologies. 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 evaluated for visibility improvement at the affected 

Federal Class I areas. The visibility improvement modeling is summarized in Section 8.0 

of this report. 

The recommended BART control for SJGS is LNB, OFA, and a NN for NOx

control and PJFF for PM control. The recommended BART control scenario was based 

on an evaluation of the most cost-effective technology. This evaluation was performed as 

detailed in Sections 3.0 to 7.0 of this report. For PM emissions control, the addition of 

the PJFF to meet the consent decree requirements represents BACT for similar units. No 

other technologies have been identified that exceed the emissions reductions achieved by 

the PJFF. Therefore, the PJFF is considered BART for this project. 

For NOx 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 subbituminous coal fired at SJGS are very similar to 

those of bituminous coal. The low volatility, 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”. These characteristics result in higher NOx

emissions than on a PRB-fired unit with the 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 equivalent to the BART technology used to establish the 

presumptive NOx limit. 

The visibility improvements modeled for the BART control scenario (as described 

in Section 8.0) indicate an average visibility improvement of 0.614 dv based on the preconsent decree visibility modeled by WRAP’s RMC for all identified Federal Class I 

areas. 

Based on the visibility improvement modeled and the total annual cost evaluated 

in the impact analysis stage, the cost-effectiveness for visibility improvement (annual 

cost per improvement in visibility, $/dv), was 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 systems would require significant capital 

expenditure and modifications that will impact many areas of the plant including boiler 

draft systems, air heater performance, SO3 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 range of 290 $/kW on Unit 1 to 310 $/kW on Unit 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 effectiveness is 155 million $/dv for SCR 

and 369 million $/dv for SNCR/SCR Hybrid. These minimal visibility improvements do 

not merit the large capital expenditure required 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 that LNB, OFA and NN should be considered BART for the 

SJGS units. The LNB, OFA and NN systems being 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 NOx. Therefore, LNB, OFA and 

NN should be considered BART for NOx control on the SJGS units. 
PNM San Juan Generating Station Appendix A 

060607 A-1 

Appendix A 

Design Basis 
PNM San Juan Generating Station 

060607 

Best Available Retrofit Technology (BART) Engineering Analysis

Design Basis Rev. 3

SJGS SJGS SJGS Unit 1 Reference Unit 2 Reference Unit 3 Reference 

Ultimate Coal analysis, wet basis

Carbon, % 54.52 Ref 1 54.52 Ref 1 54.52 Ref 1 Hydrogen, % 4.24 Ref 1 4.24 Ref 1 4.24 Ref 1 Sulfur, % 0.77 Ref 1 0.77 Ref 1 0.77 Ref 1 Nitrogen, % 1.08 Ref 1 1.08 Ref 1 1.08 Ref 1 Oxygen, % 9.38 Ref 1 9.38 Ref 1 9.38 Ref 1 Chlorine, % NA Ref 1 NA Ref 1 NA Ref 1 

Ash, % 21.29 Ref 1 21.29 Ref 1 21.29 Ref 1 

Moisture, % 8.72 Ref 1 8.72 Ref 1 8.72 Ref 1 

Total, % 100.00 Ref 1 100.00 Ref 1 100.00 Ref 1 

Higher Heating Value, Btu/lb 9,692 Ref 1 9,692 Ref 1 9,692 Ref 1 

Unit Characteristics

Unit Rating, Gross MW 360 Ref 2 350 Ref 2 544 Ref 2 Boiler Type Wall-Fired Ref 2 Wall-Fired Ref 2 Opposed Wall-Fired Ref 2 

Boiler Heat Input, MBtu/h (HHV) 3,707 Ref 3 3,688 Ref 3 5,758 Ref 3 Coal Flow Rate, lb/h 382,480 Calculated 380,520 Calculated 594,098 Calculated 

Capacity Factor, % 85 Note 5 85 Note 5 85 Note 5 

Fly Ash Portion of Total Ash, % 80 Ref 4 80 Ref 4 80 Ref 4 

Air Heater Leakage, % 15 Note 5 15 Note 5 15 Note 5 

Excess Air, % 20 Ref 5 20 Ref 5 20 Ref 5 

Emission Summary

Nitrogen Oxides (NOx), lb/MBtu 0.43 Ref 4 0.45 Ref 4 0.42 Ref 4 

Nitrogen Oxides (NOx), lb/h 1,592.0 Calculated 1,649.3 Calculated 2,405.5 Calculated 

Sulfur Dioxide (SO2), lb/MBtu 0.24 Ref 4 0.23 Ref 4 0.28 Ref 4 

Sulfur Dioxide (SO2), lb/MBtu 877.8 Calculated 844.0 Calculated 1,591.1 Calculated 

Particulate Matter (PM), lb/MBtu 0.050 Ref 4 0.050 Ref 4 0.050 Ref 4 Particulate Matter (PM), lb/h 185.4 Calculated 184.4 Calculated 287.9 Calculated 

Economizer Outlet Conditions 

Flue Gas Temperature, °F 707 Ref 6 710 Ref 7 720 Ref 8 Flue Gas Pressure, in. wg 12.0 Ref 6 11.0 Ref 7 19.0 Ref 8 Flue Gas Mass Flow Rate, lb/h 3,674,408 Ref 6 3,655,575 Ref 7 5,707,376 Ref 8 

Volumetric Flue Gas Flow Rate, acfm 2,082,166 Ref 6 2,082,819 Ref 7 3,205,572 Ref 8 

Public Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS)

PRE-CONSENT DECREE OPERATION CONDITIONS

CONSENT DECREE UPGRADES CONDITIONS
PNM San Juan Generating Station 

060607 

Flue Gas Composition

Oxygen (O2), % by volume 3.2 Ref 6 3.2 Ref 7 3.2 Ref 8 

Carbon Dioxide (CO2), % by volume 13.7 Ref 6 13.7 Ref 7 13.7 Ref 8 

Moisture (H2O), % by volume 9.7 Ref 6 9.7 Ref 7 9.7 Ref 8 

Sulfur Dioxide (SO2), % by volume 0.07 Ref 6 0.07 Ref 7 0.07 Ref 8 

Sulfur Dioxide (SO2), lb/MBtu 1.59 Calculated 1.59 Calculated 1.59 Calculated Sulfur Dioxide (SO2), lb/h 5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 

Sulfur Trioxide (SO3), lb/h 74 Note 1 73 Note 1 114 Note 1 

Sulfur Trioxide (SO3), lb/MBtu 0.020 Calculated 0.020 Calculated 0.020 Calculated 

Particulate Matter (PM), lb/MBtu 17.6 Calculated 17.6 Calculated 17.6 Calculated Particulate Matter (PM), lb/h 65,144 Ref 6 64,810 Ref 7 101,187 Ref 8 Nitrogen Oxides (NOx), lb/MBtu 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10 Nitrogen Oxides (NOx), lb/h 1,112 Calculated 1,106 Calculated 1,727 Calculated 

De-Energized Hot-Side ESP Outlet Conditions 

Flue Gas Temperature, °F 695 Ref 6 698 Ref 7 640 Ref 8 Flue Gas Pressure, in. wg 6.5 Ref 6 6.5 Ref 7 8.2 Ref 8 Flue Gas Mass Flow Rate, lb/h 3,674,408 Ref 6 3,655,575 Ref 7 5,707,376 Ref 8 

Volumetric Flue Gas Flow Rate, acfm 2,093,930 Ref 6 2,088,609 Ref 7 3,082,239 Ref 8 Flue Gas Composition

Oxygen (O2), % by volume 3.2 Ref 6 3.2 Ref 7 3.2 Ref 8 

Carbon Dioxide (CO2), % by volume 13.7 Ref 6 13.7 Ref 7 13.7 Ref 8 

Moisture (H2O), % by volume 9.7 Ref 6 9.7 Ref 7 9.7 Ref 8 

Sulfur Dioxide (SO2), % by volume 0.07 Ref 6 0.07 Ref 7 0.07 Ref 8 

Sulfur Dioxide (SO2), lb/MBtu 1.59 Calculated 1.59 Calculated 1.59 Calculated Sulfur Dioxide (SO2), lb/h 5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 

Sulfur Trioxide (SO3), lb/h 74 Note 1 73 Note 1 114 Note 1 

Sulfur Trioxide (SO3), lb/MBtu 0.020 Calculated 0.020 Calculated 0.020 Calculated 

Particulate Matter (PM), lb/MBtu 8.79 Calculated 8.79 Calculated 8.79 Calculated Particulate Matter (PM), lb/h 32,572 Note 3 32,405 Note 3 50,593 Note 3 Nitrogen Oxides (NOx), lb/MBtu 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10 Nitrogen Oxides (NOx), lb/h 1,112 Calculated 1,106 Calculated 1,727 Calculated 

Air Heater Outlet Conditions 

Flue Gas Temperature, °F 277 Ref 6 277 Ref 7 277 Ref 8 

Flue Gas Pressure, in. wg 0.0 Ref 6 0.0 Ref 7 0.0 Ref 8 Flue Gas Mass Flow Rate, lb/h 4,225,569 Ref 6 4,203,912 Ref 7 6,563,482 Ref 8 

Volumetric Flue Gas Flow Rate, acfm 1,571,717 Ref 6 1,563,662 Ref 7 2,441,313 Ref 8 
PNM San Juan Generating Station 

060607 

Flue Gas Composition

Oxygen (O2), % by volume 5.5 Ref 6 5.5 Ref 7 5.5 Ref 8 

Carbon Dioxide (CO2), % by volume 11.9 Ref 6 11.9 Ref 7 11.9 Ref 8 

Moisture (H2O), % by volume 8.7 Ref 6 8.7 Ref 7 8.7 Ref 8 

Sulfur Dioxide (SO2), % by volume 0.06 Ref 6 0.06 Ref 7 0.06 Ref 8 

Sulfur Dioxide (SO2), lb/MBtu 1.59 Calculated 1.59 Calculated 1.59 Calculated Sulfur Dioxide (SO2), lb/h 5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 

Particulate Matter (PM), lb/MBtu 8.79 Calculated 8.79 Calculated 8.79 Calculated Particulate Matter (PM), lb/h 32,572 Note 3 32,405 Note 3 50,593 Note 3 Nitrogen Oxides (NOx), lb/MBtu 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10 Nitrogen Oxides (NOx), lb/h 1,112 Calculated 1,106 Calculated 1,727 Calculated 

Fabric Filter Outlet Conditions

Fabric Filter Particulate Matter Removal, percent 99.86% Calculated 99.86% Calculated 99.86% Calculated 

Flue Gas Temperature, °F 277 Ref 6 277 Ref 7 277 Ref 8 Flue Gas Pressure, in. wg -10 Ref 6 -10 Ref 7 -10.0 Ref 8 Flue Gas Mass Flow Rate, lb/h 4,225,569 Ref 6 4,203,912 Ref 7 6,563,482 Ref 8 

Volumetric Flue Gas Flow Rate, acfm 1,620,055 Ref 6 1,611,752 Ref 7 2,516,395 Ref 8 Flue Gas Composition

Sulfur Dioxide (SO2), lb/MBtu 1.59 Calculated 1.59 Calculated 1.59 Calculated 

Sulfur Dioxide (SO2), lb/h 5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 

Particulate Matter (PM), lb/MBtu 0.012 Ref 5 0.012 Ref 5 0.012 Ref 5 Particulate Matter (PM), lb/h 44 Calculated 44 Calculated 69 Calculated 

FGD Booster Fan Outlet Conditions

Flue Gas Temperature, °F 290 Ref 6 290 Ref 7 290 Ref 8 

Flue Gas Pressure, in. wg 10 Ref 6 9 Ref 7 14.2 Ref 8 Flue Gas Mass Flow Rate, lb/h 4,225,569 Ref 6 4,203,912 Ref 7 6,563,482 Ref 8 

Volumetric Flue Gas Flow Rate, acfm 1,553,101 Ref 6 1,549,630 Ref 7 2,383,394 Ref 8 Flue Gas Composition

Sulfur Dioxide (SO2), lb/MBtu 1.59 Calculated 1.59 Calculated 1.59 Calculated 

Sulfur Dioxide (SO2), lb/h 5,884 Ref 6 5,854 Ref 7 9,140 Ref 8 

Scrubber Outlet Conditions

Scrubber SO2 Removal, percent 90% Note 4 90% Note 4 90% Note 4 

Flue Gas Temperature, °F 121 Ref 6 121 Ref 7 121 Ref 8 Flue Gas Pressure, in. wg 1.0 Ref 6 1.0 Ref 7 1.0 Ref 8 Flue Gas Mass Flow Rate, lb/h 4,396,972 Ref 6 4,374,435 Ref 7 6,829,718 Ref 8 

Volumetric Flue Gas Flow Rate, acfm 1,319,596 Ref 6 1,312,832 Ref 7 2,049,699 Ref 8 Flue Gas Composition

Sulfur Dioxide (SO2), lb/MBtu 0.16 Calculated 0.16 Calculated 0.16 Calculated 

Sulfur Dioxide (SO2), lb/h 588 Calculated 585 Calculated 914 Calculated 
PNM San Juan Generating Station 

060607 

Stack Outlet Conditions

Flue Gas Temperature, °F 121 Ref 6 121 Ref 7 121 Ref 8 

Flue Gas Pressure, in. wg 0.01 Ref 6 0.01 Ref 7 0.01 Ref 8 Flue Gas Mass Flow Rate, lb/h 4,396,972 Ref 6 4,374,435 Ref 7 6,829,718 Ref 8 

Volumetric Flue Gas Flow Rate, acfm 1,323,494 Ref 6 1,316,710 Ref 7 2,055,753 Ref 8 

Stack Height, m 121.92 Ref 11 121.92 Ref 11 121.92 Ref 11 

Stack Diameter, m 6.10 Ref 11 6.10 Ref 11 8.53 Ref 11 

Flue Gas Exit Velocity, ft/s 70 Calculated 70 Calculated 56 Calculated Flue Gas Composition 

Sulfur Dioxide (SO2), lb/MBtu 0.16 Calculated 0.16 Calculated 0.16 Calculated 

Sulfur Dioxide (SO2), lb/h 588 Calculated 585 Calculated 914 Calculated 

H2SO4 Emissons, lb/h 21.6 Ref 12 21.5 Ref 12 33.6 Ref 12 

Particulate Matter (PM), lb/MBtu 0.015 Ref 5 0.015 Ref 5 0.015 Ref 5 Particulate Matter (PM), lb/h 56 Calculated 55 Calculated 86 Calculated 

Nitrogen Oxides (NOx), lb/MBtu 0.30 Ref 10 0.30 Ref 10 0.30 Ref 10 Nitrogen Oxides (NOx), lb/h 1,112 Calculated 1,106 Calculated 1,727 Calculated 

Notes:

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. SO2 post-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 for SJGS Unit 1, K. Whitehead, 03/09/2007.7. M10 Combustion Calculation for SJGS Unit 2, K. Whitehead, 03/09/2007.8. M10 Combustion Calculation for SJGS Unit 3, K. Whitehead, 03/09/2007.9. M10 Combustion Calculation for SJGS Unit 4, K. Whitehead, 03/09/2007.10.Post-consent decree NOx emission limit.

11.SJGS boiler stack exit parameters.

12.San Juan Generating Station BART SO 4 Emission Comparison (National Park Service spreadsheet calculation for April 2003 to January 2007), K. Lucas, 04/12/2007.

Revision History

Rev Date Purpose

0 2/21/2007 Initial issue to client

1 3/9/2007 Revision to address comments on air heater outlet conditions and hot-ESP particulate drop-

2 4/18/2007 Revision to include H2SO4 emissions data

3 5/24/2007 Revision to update references and table layout
PNM San Juan Generating Station Appendix B 

060607 B-1 

Appendix B 

Design Concept Definitions 
PNM 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 (SNCR) process into boiler pendant superheat section. 

 Pollutant NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 circulation 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, cooling 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 Modifications 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 Routing of SNCR reagent supply lines. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning, air heater modifications included. 

Other Assumptions: 

• No major impact in plant availability. 

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

• No boiler/duct stiffening included. 

• Air heater modifications included in analysis. 

• No impact on potential ash sales. 

• Reagent is urea solution. 

State of Availability Availability. 

State of Applicability Not applicable. 

Technical Feasibility Not technically feasible. Controlled NOx level does not presumptive NOx 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 injection and reactor downstream of de-energized hot-side ESP. 

 Pollutant NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 high-dust configuration, downstream of de-energized hot-side ESP and

upstream of existing air heaters. Ammonia injection location will be upstream of the reactor. 

Install ammonia vaporizers at grade. 

Inlet/Outlet Connections and Interconnecting Ducts SCR inlet and outlet ducts connected into duct 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 protective 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, requiring balanced draft conversion. 

Power Supply/Aux Power Modifications Aux electric system upgrade will be required for additional fan capacity, ammonia preparation 

and delivery system, and reactor catalyst cleaning system. 

Enclosures Requirements Ammonia injection grid 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 reactor and location of piling for steel support. Crane access for 

constructing SCR reactor for SJGS units 2 and 3. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning, air heater modifications included. 

Other Assumptions: 

• No major impact in plant availability. 

• Temperature range of flue gas at de-energized hot-side ESP outlet is acceptable and no additional heating required at low loads. 

• The site has sufficient area available to accommodate construction 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 systems, 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 Locations 
PNM 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 – Consent Decree Modifications 

Green = Induced Draft Fan Locations 
PNM 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 NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 circulation 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 downstream of de-energized hot-side ESP. 

Inlet/Outlet Connections and Interconnecting Ducts Catalyst inlet 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 controls interfaced into existing control system. 

Fan Modifications Assume additional fan capacity will be required, requiring balanced draft conversion. 

Power Supply/Aux Power Modifications Aux electric system upgrade will be required for additional fan capacity, ammonia preparation 

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 between de-energized hot-side ESP outlet and air heater inlet. Penetrations 

into boiler wall for injectors and MNL, access platforms. 

Major Constructability Issues Support steel design for SCR reactor and location of piling for steel support. Crane access for 

constructing SCR reactor for SJGS units 2 and 3. Routing of SNCR reagent supply lines. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning, air heater modifications included. 

Other Assumptions: 

• No major impact in plant availability. 

• Temperature range of flue gas at de-energized hot-side ESP outlet is acceptable and no additional heating required at low loads. 

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

to Units 2 and 3 might be limited. 

• Air heater modifications, flue gas handling systems, 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 reburn, fuel lean gas reburn (FLGR) and amine-enhanced fuel lean gas 

reburn (AE-FLGR). 

 Pollutant NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minor aux electric system modifications required for natural gas handling system. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements Penetrations into boiler wall. 

Major Constructability Issues None. 

Significant Issues or Challenges Potential for increased furnace 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 data 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 NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 ports above existing close coupled overfire air ports. 

Injection skid and reagent tank at grade with truck unloading station. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct. 

Reagent Storage 50,000 gallon tank at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements Penetrations into boiler wall. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. Up to 5 ppm ammonia slip. 

Other Assumptions: 

• No major impact in plant availability. 

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

• No 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 feasible (not demonstrated on similar 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 NOxStar 

Process Description NOxStar (injection of natural gas and ammonia mixture into boiler) and NOxStar Plus (with in-duct catalyst) 

 Pollutant NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 NOxStar 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 and 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 Incorporated into existing control system. 

Fan Modifications Fan modifications required if to account for in-duct catalyst for NOxStar Plus (if installed). 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed 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 NOxStar Plus (if 

installed). 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions: 

• No major impact in plant availability. 

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

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

• No impact on potential ash sales. 

• Reagent is ammonia and natural gas. If NOxStar 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 marked 

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. Ammonia/urea can be added into air for additional NOx reduction. 

 Pollutant NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 and urea tank at grade with truck unloading station. 

Install water-cooled, retractable lances at to be determined location in boiler. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct. 

Reagent Storage Tank at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements Penetrations into boiler wall. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions: 

• No major impact in plant availability. 

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

• No 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 (NOx, SO2, Hg). Process is based on oxidation and capture of 

pollutants in flue gas stream. 

 Pollutant NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 equipment 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 Incorporated into existing control system. 

Fan Modifications Assume additional fan capacity will be required. 

Power Supply/Aux Power Modifications Aux electric system upgrade will be required for additional fan capacity, ECO reactor 

operations, ammonia preparation and delivery system, scrubber operation and wet ESP 

operation. 

Enclosures Requirements Enclosures for ammonia 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 reagent preparation and byproduct 

processing equipment. 

Significant Issues or Challenges Recovered byproduct cannot be landfilled. Fertilizer material to be used by nearby agriculture 

industry. 

Other Assumptions: 

• No major impact in plant availability. 

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

• 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 the Phenix Clean Combustion System (CCS). Process is based on gasification of coal 

upstream of the regular boiler combustion system. 

 Pollutant NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 into 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 gasification control system integrated into boiler combustion control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Aux electric system upgrade will be required for the limestone preparation system and slag

removal system. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements Reconfiguration of existing boiler required to integrate gasification process equipment. 

Downstream AQC equipment left in place for contingency purpose. 

Major Constructability Issues Access to boiler building and modifications 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 activities 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 (NOx, SO2, 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 NOx (Unit 1) NOx (Unit 2) NOx (Unit 3) NOx (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 particulate collector system for byproduct drying located upstream of 

actual e-SCRUB process. e-Beam building 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 Incorporated into existing control system. 

Fan Modifications Assume additional fan capacity will be required. 

Power Supply/Aux Power Modifications Aux electric system upgrade will be required for additional fan capacity, e-Beam operations, 

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 new equipment train and associated reagent preparation and byproduct 

processing equipment. 

Significant Issues or Challenges Recovered byproduct cannot be landfilled. Fertilizer material to be used by nearby agriculture 

industry. 

Other Assumptions: 

• No major impact in plant availability. 

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

• 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 upstream of existing hot-side ESP. Process is based on addition of ammonia or SO3 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 (NH3/SO3) 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 Ducts Ductwork connection upstream of ESP. 

Reagent Storage Reagent preparation and storage for flue gas conditioning at grade. 

Control System Modifications New stand-alone control system, tie in to plant DCS control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minor aux electric system modification required for reagent preparation and delivery systems. 

Enclosures Requirements No additional enclosures required. 

Demolition or Relocation Requirements Demolition of ductwork upstream of ESP for retrofit. 

Major Constructability Issues None. 

Significant Issues or Challenges Planned 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 activities 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 emissions level. Undeveloped data fields 

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 connection downstream of air heater outlet and upstream of FGD booster fans. 

Reagent Storage None. 

Control System Modifications New stand-alone control system, tie in to plant DCS control system. 

Fan Modifications FGD booster fan modifications required to overcome additional pressure drop. 

Power Supply/Aux Power Modifications Aux electric system modification required 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 Site access to construction site. 

Significant Issues or Challenges Planned major outage required for retrofit project. 

Other Assumptions 

• No major impact in plant availability. 

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

• 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 emissions level. Undeveloped data fields 

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 Filter (ESFF) system into flue gas path, upstream of wet FGD. Existing hot-side ESP will 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 connection downstream of air heater outlet and upstream of FGD booster fans. 

Reagent Storage None. 

Control System Modifications New stand-alone control system, tie in to plant DCS control system. 

Fan Modifications FGD booster fan modifications required to overcome additional pressure drop. 

Power Supply/Aux Power Modifications Aux electric system modification required for bag cleaning system, FGD booster fan 

modifications, and ash handling system. 

Enclosures Requirements Max-9 designed with penthouse. 

Demolition or Relocation Requirements Replace existing ductwork with connections to Max-9. 

Major Constructability Issues Site access to construction site. 

Significant Issues or Challenges Planned major outage required for retrofit project. 

Other Assumptions 

• No major impact in plant availability. 

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

• 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 applications on SJGS sized flue gas system. Undeveloped data fields will 

be marked as “NA.” 
PNM San Juan Generating Station Appendix C 

060607 C-1 

Appendix C 

Cost Analysis Summary 
PNM San Juan Generating Station Appendix C 

060607 C-2 

Low NOx 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) $1,422,000
PNM 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) $1,378,000
PNM 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) $1,240,000
PNM 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) $1,256,000
PNM 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. H2O 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) $10,427,000
PNM 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. H2O 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) $10,764,000
PNM 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. H2O 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) $12,454,000
PNM 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. H2O 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) $12,527,000
PNM 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 m3

 and 6,500 $/m3 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) $20,525,000
PNM 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 $440,000 B&V cost estimate

Electrical System Upgrade $372,000 B&V cost estimate

Instrumentation and Control System $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 (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) + (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 m3

 and 6,500 $/m3 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) $21,891,000
PNM 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 $440,000 B&V cost estimate

Electrical System Upgrade $484,000 B&V cost estimate

Instrumentation and Control System $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 (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) + (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 m3

 and 6,500 $/m3 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) $28,359,000
PNM 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 $440,000 B&V cost estimate

Electrical System Upgrade $484,000 B&V cost estimate

Instrumentation and Control System $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 (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) + (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 m3

 and 6,500 $/m3 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) $26,592,000
PNM 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) $16,207,000
PNM 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) $16,670,000
PNM 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) $25,606,000
PNM 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) $24,849,000
PNM San Juan Generating Station Appendix D 

060607 D-1 

Appendix D 

Stack Outlet Conditions for Visibility Modeling 
PNM San Juan Generating Station 

060607 

SJGS Unit 1, Heat Input (HHV) = 3,707 MBtu/hrStack Outlet Conditions Flow (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) 

Pre-Consent Decree Operation 0.43 1,592.0 0.24 877.8 0.050 Visibility 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 With additional NOx Control Technologies

1. Selective Catalytic Reduction (SCR) 1,325,998 70 121.42 0.01 0.07 259.5 0.18 667.3 0.015 2. SNCR/SCR Hybrid 1,324,112 70 121.42 0.01 0.18 667.3 0.18 667.3 0.015 Notes1. 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 SO3 emissions are reported as Sulfuric Acid Mist (H2SO4).

9. SO3 emissions for the pre- and post-consent decree cases are determined using the National Park Service calculation formula.

10. SO3 emissions for the additional NOx control technologies with catalyst accounts for an additional 1.0% SO2 to SO3 conversion (based on design basis economizer outlet SO2 levels) and 0% SO3 removal 

Revision History

Rev Date Purpose

0 4/25/2007 Initial issue to client1 5/2/2007 Revision to incorporate PNM comments2 5/24/2007 Final revision

Public Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS) Unit 1

Best Available Retrofit Technology (BART) Engineering Analysis

Stack Outlet Conditions for Visibility Modeling (24-hour Average Emission Rates) Rev. 2
PNM San Juan Generating Station 

060607 

SJGS Unit 2, Heat Input (HHV) = 3,688 MBtu/hrStack Outlet Conditions Flow (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) 

Pre-Consent Decree Operation 0.45 1,649.3 0.23 844.0 0.050 Visibility 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 With additional NOx Control Technologies

1. Selective Catalytic Reduction (SCR) 1,319,201 70 121.42 0.01 0.07 258.2 0.18 663.8 0.015 2. SNCR/SCR Hybrid 1,317,328 70 121.42 0.01 0.18 663.8 0.18 663.8 0.015 Notes1. 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 SO3 emissions are reported as Sulfuric Acid Mist (H2SO4).

9. SO3 emissions for the pre- and post-consent decree cases are determined using the National Park Service calculation formula.

10. SO3 emissions for the additional NOx control technologies with catalyst accounts for an additional 1.0% SO2 to SO3 conversion (based on design basis economizer outlet SO2 levels) and 0% SO3 removal 

Revision History

Rev Date Purpose

0 4/25/2007 Initial issue to client1 5/2/2007 Revision to incorporate PNM comments2 5/24/2007 Final revision

Public Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS) Unit 2

Best Available Retrofit Technology (BART) Engineering Analysis

Stack Outlet Conditions for Visibility Modeling (24-hour Average Emission Rates) Rev. 2
PNM San Juan Generating Station 

060607 

SJGS Unit 3, Heat Input (HHV) = 5,758 MBtu/hrStack Outlet Conditions Flow (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) 

Pre-Consent Decree Operation 0.42 2,405.5 0.28 1,591.1 0.050 Visibility 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 With additional NOx Control Technologies

1. Selective Catalytic Reduction (SCR) 2,059,643 56 121.42 0.01 0.07 403.1 0.18 1,036.4 0.015 2. SNCR/SCR Hybrid 2,056,712 56 121.42 0.01 0.18 1,036.4 0.18 1,036.4 0.015 Notes1. 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 SO3 emissions are reported as Sulfuric Acid Mist (H2SO4).

9. SO3 emissions for the pre- and post-consent decree cases are determined using the National Park Service calculation formula.

10. SO3 emissions for the additional NOx control technologies with catalyst accounts for an additional 1.0% SO2 to SO3 conversion (based on design basis economizer outlet SO2 levels) and 0% SO3 removal 

Revision History

Rev Date Purpose

0 4/25/2007 Initial issue to client1 5/2/2007 Revision to incorporate PNM comments2 5/24/2007 Final revision

Public Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS) Unit 3

Best Available Retrofit Technology (BART) Engineering Analysis

Stack Outlet Conditions for Visibility Modeling (24-hour Average Emission Rates) Rev. 2
PNM San Juan Generating Station 

060607 

SJGS Unit 4, Heat Input (HHV) = 5,649 MBtu/hrStack Outlet Conditions Flow (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) 

Pre-Consent Decree Operation 0.42 2,399.6 0.29 1,662.4 0.050 Visibility 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 With additional NOx Control Technologies

1. Selective Catalytic Reduction (SCR) 2,020,653 55 121.42 0.01 0.07 395.4 0.18 1,016.8 0.015 2. SNCR/SCR Hybrid 2,017,796 55 121.42 0.01 0.18 1,016.8 0.18 1,016.8 0.015 Notes1. 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 SO3 emissions are reported as Sulfuric Acid Mist (H2SO4).

9. SO3 emissions for the pre- and post-consent decree cases are determined using the National Park Service calculation formula.

10. SO3 emissions for the additional NOx control technologies with catalyst accounts for an additional 1.0% SO2 to SO3 conversion (based on design basis economizer outlet SO2 levels) and 0% SO3 removal 

Revision History

Rev Date Purpose

0 4/25/2007 Initial issue to client1 5/2/2007 Revision to incorporate PNM comments2 5/24/2007 Final revision

Public Service Company of New Mexico (PNM) - San Juan Generating Station (SJGS) Unit 4

Best Available Retrofit Technology (BART) Engineering Analysis

Stack Outlet Conditions for Visibility Modeling (24-hour Average Emission Rates) Rev. 2
PNM San Juan Generating Station Appendix E 

060607 E-1 

Appendix E 

CALPUFF Modeling Support Documents