Arizona Public Service Company 

Four Corners Generating Plant Units 1 through 5 

Best Available Retrofit Technology 

Engineering Analysis 

Black & Veatch Project: 145983 

Black & Veatch File No.: 40.0000 

Issue Date and Revision 

December 4, 2007 Rev. 3 
Arizona Public Service 

Four Corners Units 1 through 5 Contents 

Contents 

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

ES.1 Basis of Analysis....................................................................................ES-1 

ES.2 Technically Feasible Retrofit Emissions Control Technology ..............ES-1 

ES.3 Cost-Effectiveness and Impact Analysis ...............................................ES-4 

ES.4 Engineering Analysis Findings..............................................................ES-4 

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

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

1.2 BART Analysis Methodology ................................................................. 1-1 

1.2.1 Identify All Available Retrofit Control Technologies 

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

1.2.2 Eliminate Technically Infeasible Options (Step 2) ................... 1-3 

1.2.3 Evaluate Control Effectiveness of Feasible Control 

Technologies (Step 3)................................................................ 1-4 

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

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

1.2.6 Selecting the Best Alternative ................................................... 1-5 

2.0 Basis of Analysis.................................................................................................. 2-1 

2.1 Design Basis............................................................................................. 2-1 

2.2 Economic Design Criteria........................................................................ 2-1 

2.2.1 Capital Cost Estimates............................................................... 2-1 

2.2.2 Annual Operations and Maintenance Cost Estimate ................. 2-4 

2.3 Baseline Emissions .................................................................................. 2-6 

2.4 Target Emissions...................................................................................... 2-6 

3.0 Identification of All Available Retrofit Emission Control Technologies 

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

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

3.1.1 Combustion Optimization System............................................. 3-1 

3.1.2 Low NOx Burners...................................................................... 3-2 

3.1.3 Low NOx Burners and Overfire Air System.............................. 3-3 

3.1.4 Mobotec ROFA and ROTAMIX............................................... 3-4 

3.1.5 NOxStar and NOxStar Plus ........................................................ 3-5 

3.1.6 ECOTUBE................................................................................. 3-6 

3.1.7 Induced Flue Gas Recirculation ................................................ 3-7 

3.1.8 Selective Catalytic Reduction (SCR) ........................................ 3-8 

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Four Corners Units 1 through 5 Contents 

Contents (Continued) 

3.1.9 Selective Noncatalytic Reduction (SNCR) ............................. 3-10 

3.1.10 SNCR/SCR Hybrid (Cascade)................................................. 3-12 

3.1.11 LoTOx ...................................................................................... 3-13 

3.1.12 Natural Gas Reburn ................................................................. 3-13 

3.1.13 THERMALONOx Process....................................................... 3-15 

3.1.14 Oxygen Enhanced Combustion ............................................... 3-15 

3.1.15 Biotechnological Denitrification (BioDeNOx) ........................ 3-16 

3.2 Particulate Matter Control Technologies............................................... 3-17 

3.2.1 Electrostatic Precipitator (ESP)............................................... 3-17 

3.2.2 Pulse Jet Fabric Filter (PJFF) .................................................. 3-19 

3.2.3 Compact Hybrid Particulate Collector .................................... 3-21 

3.2.4 GE MAX-9 Hybrid.................................................................. 3-21 

3.2.5 Multiple-Cyclone..................................................................... 3-23 

3.2.6 Wet ESP................................................................................... 3-24 

3.2.7 Particle Agglomeration Upstream of Dry ESP........................ 3-26 

3.3 Emerging Pollution Control Technologies ............................................ 3-27 

3.3.1 PowerSpan............................................................................... 3-28 

3.3.2 EnviroScrub............................................................................. 3-29 

3.3.3 Phenix Clean Coal ................................................................... 3-30 

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

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

4.2 PM Control Technologies........................................................................ 4-1 

4.2.1 Units 4 and 5 PM BART Analysis ............................................ 4-4 

5.0 Evaluation of Technically Feasible Retrofit Emission Control 

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

5.1 NOx Control Technologies....................................................................... 5-1 

5.2 PM Control Technologies........................................................................ 5-1 

6.0 Cost-Effectiveness and Impact Analysis (Step 4)................................................ 6-1 

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

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

6.3 Cost-Effectiveness ................................................................................... 6-3 

6.3.1 NOx Control Technologies ........................................................ 6-3 

6.3.2 PM Control Technologies.......................................................... 6-3 

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Four Corners Units 1 through 5 Contents 

Contents (Continued) 

7.0 Results.................................................................................................................. 7-1 

7.1 Cost-Effectiveness Summary................................................................... 7-1 

7.2 Unit 1 NOx Cost-Effectiveness Summary................................................ 7-2 

7.3 Unit 2 NOx Cost-Effectiveness Summary................................................ 7-3 

7.4 Unit 3 NOx Cost-Effectiveness Summary................................................ 7-3 

7.5 Units 4 and 5 NOx Cost-Effectiveness Summary .................................... 7-4 

7.6 Unit 1 Particulate Matter Cost-Effectiveness Summary.......................... 7-4 

7.7 Unit 2 Particulate Matter Cost-Effectiveness Summary.......................... 7-4 

7.8 Unit 3 Particulate Matter Cost-Effectiveness Summary.......................... 7-5 

7.9 Unit 4 Particulate Matter Cost-Effectiveness Summary.......................... 7-5 

7.10 Unit 5 Particulate Matter Cost-Effectiveness Summary.......................... 7-5 

7.11 BART Engineering Analysis Summary................................................... 7-5 

Appendix A Design Basis 

Appendix B Technology Removal Matrix 

Appendix C Design Concept Definitions 

Appendix D Cost Calculations 

Appendix E Stack Flow Summary Table 

Appendix F Annual Emissions Summary Table 

Tables 

Table ES-1 Four Corners Units 1 through 5 Operational Characteristics.................ES-2 

Table ES-2 Economic Assumptions (2006 Costs)....................................................ES-3 

Table ES-3 Target Emissions for BART Analysis ...................................................ES-3 

Table 1-1 Four Corners Units 1 through 5 Operational Characteristics................... 1-2 

Table 2-1 Economic Assumptions (2006 Costs)...................................................... 2-2 

Table 2-2 Typical Owner’s Cost Categories ............................................................ 2-3 

Table 2-3 Baseline Emissions .................................................................................. 2-6 

Table 2-4 Target Emissions for BART Analysis ..................................................... 2-7 

Table 4-1 Technical Feasibility of NOx Control Technology .................................. 4-2 

Table 4-2 Technical Feasibility of PM Control Technology for Units 1, 2, 

and 3......................................................................................................... 4-3 

Table 5-1 Control Effectiveness for NOx Reduction Technologies--Units 1, 

2, and 3..................................................................................................... 5-2 

Table 5-2 Control Effectiveness for NOx Reduction Technologies--Units 4 

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

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Four Corners Units 1 through 5 Contents 

Contents (Continued) 

Tables (Continued) 

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

Table 6-1 Baseline Emissions .................................................................................. 6-3 

Table 6-2 Unit 1 - NOx Cost-Effectiveness Summary ............................................. 6-5 

Table 6-3 Unit 2 - NOx Cost-Effectiveness Summary ............................................. 6-7 

Table 6-4 Unit 3 - NOx Cost-Effectiveness Summary ............................................. 6-9 

Table 6-5 Units 4 and 5 - NOx Cost-Effectiveness Summary - Values are 

per Unit .................................................................................................. 6-11 

Table 6-6 Unit 1 - PM Cost-Effectiveness Summary............................................. 6-13 

Table 6-7 Unit 2 - PM Cost-Effectiveness Summary............................................. 6-16 

Table 6-8 Unit 3 - PM Cost-Effectiveness Summary............................................. 6-19 

Table 7-1 NOx Cost-Effectiveness Summary........................................................... 7-7 

Figures 

Figure ES-1 Unit 1 - NOx Cost-Effectiveness............................................................ES-5 

Figure ES-2 Unit 2 - NOx Cost-Effectiveness............................................................ES-6 

Figure ES-3 Unit 3 - NOx Cost-Effectiveness............................................................ES-7 

Figure ES-4 Units 4 and 5 - NOx Cost-Effectiveness ................................................ES-8 

Figure 3-1 Staged Combustion of LNBs and OFA System....................................... 3-4 

Figure 3-2 Mobotec ROFA and ROTAMIX Simplified Process Flow 

Diagram.................................................................................................... 3-5 

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

Figure 3-4 Schematic Diagram of a Typical SCR Reactor........................................ 3-9 

Figure 3-5 Schematic of SNCR System with Multiple Injection Levels................. 3-11 

Figure 3-6 Schematic of Gas Reburn System.......................................................... 3-14 

Figure 3-7 Electrostatic Precipitator System (MHI)................................................ 3-18 

Figure 3-8 PJFF Compartment ................................................................................ 3-20 

Figure 3-9 Max-9 Electrostatic Filter ...................................................................... 3-22 

Figure 3-10 Multiclone Particulate Collector............................................................ 3-23 

Figure 3-11 Electrostatic Particle Agglomeration System (Indigo) .......................... 3-24 

Figure 3-12 ECO Process Flow Diagram .................................................................. 3-28 

Figure 3-13 Pahlman Process Simplified Process Flow Diagram............................. 3-29 

Figure 3-14 Phenix Clean Coal Process Flow Diagram ............................................ 3-31 

Figure 6-1 Unit 1 - NOx Cost-Effectiveness.............................................................. 6-6 

Figure 6-2 Unit 2 - NOx Cost-Effectiveness.............................................................. 6-8 

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Four Corners Units 1 through 5 Contents 

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Contents (Continued) 

Figures (Continued) 

Figure 6-3 Unit 3 - NOx Cost-Effectiveness............................................................ 6-10 

Figure 6-4 Units 4 and 5 - NOx Cost-Effectiveness ................................................ 6-12 

Figure 6-5 Unit 1 - Overall View of PM Cost-Effectiveness .................................. 6-14 

Figure 6-6 Unit 1 - Incremental View of PM Cost-Effectiveness........................... 6-15 

Figure 6-7 Unit 2 - Overall View of PM Cost-Effectiveness .................................. 6-17 

Figure 6-8 Unit 2 - Incremental View of PM Cost-Effectiveness........................... 6-18 

Figure 6-9 Unit 3 - Overall View of PM Cost-Effectiveness .................................. 6-20 

Figure 6-10 Unit 3 - Incremental View of PM Cost-Effectiveness........................... 6-21 
Arizona Public Service 

Four Corners Units 1 through 5 Executive Summary 

Executive Summary 

 Arizona Public Service (APS) retained Black & Veatch (B&V) to perform a Best 

Available Retrofit Technology (BART) analysis for its Four Corners Generating Station 

Units 1 through 5. The Environmental Protection Agency (EPA) identified Four Corners 

Units 1 through 5 as subject to BART. A BART review was required to identify the best 

control technology for the reduction of nitrogen oxides (NOx) and particulate matter (PM) 

emissions from Four Corners Units 1 through 5. The BART engineering analysis that 

was performed was based on the EPA’s Guidelines for BART Determinations under the 

Regional Haze Rules (40 CFR Part 51, Appendix Y). 

ES.1 Basis of Analysis 

 Prior to performing the BART engineering analysis, a detailed design basis was 

established for Four Corners Units 1 through 5. The design basis was established on the 

basis of information collected during the site visit, plant operating data, combustion 

calculations performed, and assumptions made for the study. Information on the 

operational characteristics of Four Corners Units 1 through 5 was also used to establish 

the design basis. A summary of the operational characteristics is shown in Table ES-1. 

The design basis is shown in Appendix A. The design basis was then used to create the 

technology removal matrix, establishing the anticipated emissions reduction for each 

applicable technology. The technology removal matrix is included in Appendix B. 

The economic design criteria established for the BART engineering analysis was 

used when estimating the cost of control of the identified technically feasible control 

technologies and when performing the impact analysis to determine the cost-effectiveness 

of these technologies. Data for the economic design criteria were developed with APS to 

best represent the actual operational costs for Four Corners Units 1 through 5. A 

summary of the economic design criteria is shown in Table ES-2. 

 In the BART rule, presumptive levels of emissions are prescribed as emissions 

targets for BART-eligible units. The presumptive levels of emissions are summarized 

and listed in Table ES-3. 

ES.2 Technically Feasible Retrofit Emissions Control 

 Technology 

In Step 1 of the BART methodology, available retrofit emissions control 

technologies that may be practically implemented at the Four Corners Units 1 through 5 

are identified. From this list of available technologies, technically feasible control 

technologies are identified in Step 2. 

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Four Corners Units 1 through 5 Executive Summary 

Table ES-1 

Four Corners Units 1 through 5 Operational Characteristics 

Item Unit 1 Unit 2 Unit 3 Units 4 and 5(1)

Fuel Type Minemouth 

Bituminous 

Minemouth 

Bituminous 

Minemouth 

Bituminous 

Minemouth 

Bituminous 

Heating Value of Fuel, 

Btu/lb 8,776 8,776 8,776 8,776 

Unit Rating, MW 

(gross/net) 185/170 185/170 235/220 790/750 

Net Plant Heat Rate, 

Btu/kWh 10,956 10,956 10,908 9,881 

Boiler Heat Input, 

mmBtu/h 1,863 1,863 2,400 7,806 

Type of 

Boiler/Manufacturer 

Front Wall 

Fired/ 

Tangent-Tube 

Furnace, 

Riley Stoker 

Front Wall 

Fired/ 

Tangent-Tube 

Furnace, Riley 

Stoker 

Front Wall Fired/ 

Membrane-Wall

Furnace, Foster 

Wheeler 

Front and Rear 

Wall Fired/ 

Membrane-Wall 

Furnace, B&W 

Steam Cycle Subcritical Subcritical Subcritical Supercritical 

Draft of Boiler Balanced Balanced Balanced Forced 

Existing Emissions 

Control 

Combustion Controls 

for NOx

Burner 

Modifications. 

(1977) 

LNB (1998) LNB (1990) Unit 4 LNB (1989) 

Unit 5 LNB (1991) 

Particulate Venturi 

Scrubber 

Venturi 

Scrubber Venturi Scrubber Reverse Gas Fabric Filter 

SO2

Venturi 

Scrubber 

Venturi 

Scrubber Venturi Scrubber Wet Lime Scrubber 

(1) Values are per unit. 

B&W - Babcock & Wilcox; LNB - Low NOx Burner 

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Four Corners Units 1 through 5 Executive Summary 

Table ES-2 

Economic Assumptions (2006 Costs) 

Annual Operating Costs 

Units 1, 2, and 3 Bottom Ash Disposal Cost ($/ton) 3.90 

Units 4 and 5 Bottom Ash Disposal Cost ($/ton) 6.30 

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

Urea Cost ($/ton) 420 

Auxiliary Power Cost ($/MWh) 60.00 

Replacement Power Cost ($/kWh) (1) 

Water Cost ($/1,000 gal) 0.002 

Fully Loaded Labor Rate ($/year) 72,800 

Escalation/Inflation (percent) 3 

Notes: 

(1)APS provided this information, which was used during the development of this study. 

However, this information is not being disclosed (according to APS request) due to 

confidentiality considerations. 

Table ES-3 

Target Emissions for BART Analysis 

Presumptive Limit Unit 1 Unit 2 Unit 3 Units 4 and 5(1)

NOx PM(2) NOx PM(2) NOx PM(2) NOx PM(2)

Bituminous Fuel 

(lb/mmBtu) 0.39 N/A 0.39 N/A 0.39 N/A 0.40 N/A 

(1) Units 4 and 5 are classified as having cell burners. 

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

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Four Corners Units 1 through 5 Executive Summary 

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In Step 3, characteristics and features of the technically feasible control 

technologies are determined. Also evaluated in this step are the retrofit requirements for 

the control technology at the existing plant site, which are determined by considering the 

current configuration of the equipment and the situation at the plant site. The design 

parameters and control effectiveness for each control technology are summarized in the 

design concept definitions sheet. The design concept definitions sheets developed for all 

of the identified technically feasible control technologies are included in Appendix C. 

ES.3 Cost-Effectiveness and Impact Analysis 

 To evaluate cost-effectiveness, an impact analysis for each technically feasible 

control technology was performed. The impact analysis considers such issues as the cost 

of compliance, energy impacts, non-air quality impact, and the remaining useful life. 

This is Step 4 of the BART engineering analysis. Upon completion of the impact 

analysis for each control technology, the cost-effectiveness can be calculated. There are 

two types of cost-effectiveness: average cost-effectiveness and incremental costeffectiveness. 

Also performed in this step is the identification of the most cost-effective control 

technologies; these are determined by plotting the total annual cost versus the expected 

emissions reduction. The “least-cost envelope,” as shown on Figures ES-1 through ES-4 

identifies the most cost-effective control technologies for each pollutant. The least-cost 

envelope is defined in the Federal Register outlining the BART process and has been 

shown as the green line on Figures ES-1 through ES-4. It should be noted that the leastcost envelope is a visual aid and is a representation of the data; it is not intended as a 

substitute to the cost-effectiveness and incremental cost-effectiveness calculations on 

which the BART is based. The cost-effectiveness information was then used as one of 

the factors for consideration along with the existing plant condition, retrofit difficulty of 

the control technology, visibility impacts, and operational impacts of the new control 

technologies to determine the best control technologies for BART compliance. 

ES.4 Engineering Analysis Findings 

B&V completed only the engineering portion of the APS Four Corners BART 

analysis, the impact on visibility in federal Class I areas was not part of the scope of this 

study. B&V identifies the engineering portion as the identification of all available retrofit 

control technologies, elimination of the technically infeasible options, evaluation of 

control effectiveness of the remaining control technologies, evaluation cost impacts, and 
Arizona Public Service 

Four Corners Units 1 through 5 

Figure ES-1 

Unit 1 - NOx Cost-Effectiveness 

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Arizona Public Service 

Four Corners Units 1 through 5 

Figure ES-2 

Unit 2 - NOx Cost-Effectiveness 

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Four Corners Units 1 through 5 

Figure ES-3 

Unit 3 - NOx Cost-Effectiveness 

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Arizona Public Service 

Four Corners Units 1 through 5 

Figure ES-4 

Units 4 and 5 - NOx Cost-Effectiveness
Arizona Public Service 

Four Corners Units 1 through 5 Executive Summary 

documentation of the results. The fifth and final step of the BART analysis, the visibility 

modeling, was not performed by B&V. This analysis determined the cost-effectiveness 

on a dollar per ton of pollutant removed. The final selection of BART will be based on 

both the cost-effectiveness study and the results of the visibility analysis. 

Although the combination of OFA and LNB seems to be a cost effective 

alternative for NOx reduction, its feasibility for Units 1 and 2 needs to be confirmed in 

greater technical detail. The history of difficult combustion-related problems on these 

units indicates that implementation of OFA and LNB must be regarded as a high risk and 

potentially complex retrofit. B&V performed investigations during the execution of this 

report, which only support the feasibility of OFA and LNB from the general perspective 

of industry experience. The level of detail required to develop this report did not provide 

enough evidence to confirm with certainty the feasibility of OFA and LNB when the 

specific history of difficult operational performance is considered. Therefore, additional 

investigations will be necessary to positively confirm the viability of the OFA and LNB 

alternative in order to ensure the future reliability and availability of Units 1 and 2. 

Section 7.0 outlines the result of the cost impact analysis, but the final 

determination of the BART technology will be dependent on the cost per deciview 

improvement for the NOx BART. The wet electrostatic precipitator (WESP) offers the 

same PM reduction for a lower annual cost than other PM removal technologies for Units 

1, 2, and 3. Units 4 and 5 currently have fabric filters installed and, therefore, already 

meet BART requirements. 

 B&V has not selected the proposed BART alternative because it has not been 

involved in the modeling process. B&V understands that APS will make the 

determination of the proposed BART technology after considering the visibility results 

from the third-party modeler and the engineering analysis summarized in this report by 

B&V. 

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Four Corners Units 1 through 5 Introduction and Objectives 

1.0 Introduction and Objectives 

 The primary objective of this study was to perform a BART analysis for APS 

Four Corners Units 1 through 5, which have been identified by the EPA as subject to 

BART. The EPA has specified that a BART review be conducted for nitrogen oxide 

(NOx) and PM. This report documents the BART engineering analysis process and 

results obtained. 

1.1 Source Description and Background 

 Four Corners Units 1 through 3 are subcritical, front wall fired boilers burning 

bituminous coal, operating under balanced draft conditions. Four Corners Units 4 and 5 

are supercritical units and fire the same minemouth bituminous coal as Units 1 through 3. 

Units 1, 2, and 3 are equipped with venturi scrubbers for sulfur dioxide (SO2) and PM 

control. Units 4 and 5 are equipped with wet scrubbers for SO2 removal and reverse gas 

fabric filters for particulate emissions control; both wet scrubbers and fabric filters are 

considered Best Available Control Technology (BACT) technologies. Unit 1 had burner 

modifications performed in 1977 for NOx purposes, while Units 3, 4, and 5 are equipped 

with late-1980s vintage LNBs, and Unit 2 had LNBs installed in 1998. A summary of the 

unit configurations and operational characteristics is noted in Table 1-1. 

1.2 BART Analysis Methodology 

 The BART study is used to identify the best method of emissions reduction of 

pollutants that cause visibility impacts in federal Class 1 areas. The BART analysis 

procedure is identified in the EPA’s Guidelines for BART Determinations under the 

Regional Haze Rules (40 CFR Part 51, Appendix Y). To determine the emissions 

reduction methods required by BART, the following issues are given consideration: 

• Technical feasibility. 

• Cost of compliance. 

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

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

• The remaining useful life of the source. 

• Degree of improvement in visibility anticipated. 

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Four Corners Units 1 through 5 Introduction and Objectives 

Table 1-1 

Four Corners Units 1 through 5 Operational Characteristics 

Item Unit 1 Unit 2 Unit 3 Units 4 and 5(1)

Fuel Type Minemouth 

Bituminous 

Minemouth 

Bituminous 

Minemouth 

Bituminous 

Minemouth 

Bituminous 

Heating Value of Fuel, 

Btu/lb 8,776 8,776 8,776 8,776 

Unit Rating, MW 

(gross/net) 185/170 185/170 235/220 790/750 

Net Plant Heat Rate, 

Btu/kWh 10,956 10,957 10,908 9,881 

Boiler Heat Input, 

mmBtu/h 1,863 1,863 2,400 7,806 

Type of 

Boiler/Manufacturer 

Front Wall 

Fired/TangentTube Furnace, 

Riley Stoker 

Front Wall 

Fired/ TangentTube Furnace, 

Riley Stoker 

Front Wall Fired/ 

Membrane-Wall 

Furnace, Foster 

Wheeler 

Front and Rear 

Wall Fired/ 

Membrane-Wall 

Furnace, B&W 

Steam Cycle Subcritical Subcritical Subcritical Supercritical 

Draft of Boiler Balanced Balanced Balanced Forced 

Existing Emissions 

Controls 

Combustion Controls 

for NOx

Burner 

Modifications 

(1977) 

LNB (1998) LNB (1990) Unit 4 LNB (1989) 

Unit 5 LNB (1991) 

Particulate Venturi Scrubber Venturi Scrubber Venturi Scrubber Reverse Gas Fabric 

Filter 

SO2 Venturi Scrubber Venturi Scrubber Venturi Scrubber Wet Lime Scrubber 

(1)Values are per Unit. 

B&W - Babcock & Wilcox 

LNB - Low NOx Burner 

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Four Corners Units 1 through 5 Introduction and Objectives 

 The BART analysis is a five-step process to select the best available method of 

emissions reduction for PM, NOx, and SO2 at the source subject to BART. As mentioned 

previously, the EPA has determined that Four Corners Units 1 through 5 are subject to 

BART for NOx and PM. This B&V study included the following steps: 

(1) Identify all available retrofit control technologies. 

(2) Eliminate technically infeasible options. 

(3) Evaluate control effectiveness of feasible control technologies. 

(4) Evaluate impacts and document the results. 

1.2.1 Identify All Available Retrofit Control Technologies (Step 1) 

 The first step of the BART analysis is the identification of all available retrofit 

emissions control technologies. An emissions control technology is considered an 

available retrofit if it has practical potential for application to the emissions unit. An 

available retrofit can be a system, technology, or change in operational method for the 

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

sources or with similar flue gas characteristics are considered as available. However, 

technologies in the development stage or that have not been applied to full scale 

operations are not considered to be available. If the source is equipped with existing 

control technologies, the BART study will include improvements or optimization of the 

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

BART analysis. 

1.2.2 Eliminate Technically Infeasible Options (Step 2) 

 Next, 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 for the 

type of source under review under similar conditions, on a source of comparable size, or 

the technology can be applied to the source under review. Two terms are used to define 

the technical feasibility of a control technology: available and applicable. Section 4.0 

addresses the requirements of Step 2 of the BART analysis. 

A technology that is being offered commercially by vendors or providers or is in 

commercial demonstration or licensing is deemed an available technology. Technologies 

that are in development and testing stages are classified as not available. 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. 

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Four Corners Units 1 through 5 Introduction and Objectives 

1.2.3 Evaluate Control Effectiveness of Feasible Control Technologies 

 (Step 3) 

 Once all the technically feasible control technology alternatives are identified in 

Step 2, the control effectiveness of each emissions control option is evaluated in Step 3. 

When evaluating the control effectiveness, the common metric of amount of pollutant 

emitted per heat input (lb/mmBtu) is used. Data for the control effectiveness of a 

technology are obtained by considering regulatory decisions and evaluations that have 

been performed on the effectiveness of the technology. Technology performance data 

provided by manufacturers (usually in the form of a performance guarantee), engineering 

estimates, and demonstrated effectiveness of technologies are also used to establish the 

control effectiveness. The most stringent level of control for each technology should be 

considered its control effectiveness, but less stringent levels of control may be considered 

as additional options. Section 5.0 demonstrates the evaluations performed for Step 3 of 

the BART analysis. 

1.2.4 Evaluate Impacts and Document the Results (Step 4) 

 Once the control effectiveness is established in Step 3 for each of the feasible 

technologies identified in Step 2, each control option is evaluated by the impact the 

implementation of the technology would have on the emission unit. These evaluations 

include the following: 

• Costs of compliance. 

• Energy impacts. 

• Non-air quality environmental impacts. 

• Remaining useful life of the unit. 

The cost of compliance analysis is performed to determine the cost to purchase, 

install, and operate each control technology. The capital and operating/annual costs are 

estimated based on established design parameters. Information for the design parameters 

is obtained from established sources and references. However, in the absence of 

references, documented assumptions can be made for the design parameters. The 

estimated cost of control is represented as an annualized cost ($/year) and, along with the 

estimated pollutant reduction (tons/year), the cost-effectiveness ($/tons removed) of the 

control technology is determined. The annualized cost includes capital, installation, and 

indirect cost associated with the equipment retrofit. The capital cost of the retrofit is 

spread out of the 20 year life of the technology according to the guidance in the Office of 

Air Quality Planning and Standards (OAQPS) manual and added to the levelized annual 

cost of the technology. The cost-effectiveness compares the potential technologies on an 

economic basis. Two types of cost-effectiveness are considered in the BART analysis: 

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

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Four Corners Units 1 through 5 Introduction and Objectives 

120407 1-5 

the total annualized cost of control divided by the annual quantity of pollutant removed 

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

cost and performance of one control technology to the next most stringent control 

technology. The incremental cost-effectiveness is used to compare technologies that 

have similar removal efficiencies on a $/incremental ton removed basis. 

 The energy impact of each control technology is evaluated as the energy penalty 

or benefit resulting from the operation of the technology. The two main energy impacts 

are the auxiliary power consumption of the control technology and the increase in 

auxiliary power required by the fans to overcome any additional system resistance of the 

control technology. The cost of these energy impacts is the cost of lost generation caused 

by the control technology and is included in the cost of compliance analysis. 

 Non-air quality environmental impacts are evaluated to determine the cost to 

mitigate environmental impacts that are caused by the operation of a control technology. 

Examples of non-air quality environmental impacts include polluted water discharge and 

solid waste generation. 

 The remaining useful life is considered only when the source has a shorter 

remaining useful life than the expected service life of the control technology. The shorter 

remaining life affects the annualized costs of the retrofit controls for capital recovery. 

Plants in these situations 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. 

1.2.5 Evaluate Visibility Impacts (Step 5) 

 Potential visibility improvement from the addition of each control technology was 

determined from modeling results performed by a third-party modeler. B&V has 

provided the expected emissions improvements, as determined in Step 3, for each of the 

applicable technologies. The third-party modeler then determined the visibility 

improvements over the established baseline. 

1.2.6 Selecting the Best Alternative 

 By summarizing all the analyses performed in the five steps described above, a 

decision on the best alternative of control technology can be made based on the costeffectiveness, impacts, and the resultant visibility improvement. B&V has not selected 

the proposed BART technology because it has not been involved in the modeling process. 

B&V understands that APS will make the determination of proposed BART technology 

after considering the visibility results from the third-party modeler and the engineering 

analysis summarized in this report by B&V. 
Arizona Public Service 

Four Corners Units 1 through 5 Basis of Analysis 

2.0 Basis of Analysis 

2.1 Design Basis 

 A detailed design basis was established for Four Corners Units 1 through 5 based 

on information provided by APS and results from combustion calculations. The 

information in the design basis was used for equipment sizing; performance calculations; 

cost estimates (capital, operating, and maintenance); and resources consumption, 

auxiliary power requirements, and byproduct disposal estimates. The design basis has 

been included as Appendix A. The design basis was then used to create the technology 

removal matrix, establishing the anticipated emissions reduction for each applicable 

technology. The technology removal matrix is included as Appendix B. 

2.2 Economic Design Criteria 

 To perform the economic analysis, capital and annual operating cost estimates 

were developed for each of the emissions control alternatives. The capital cost estimates 

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

data supplied by equipment vendor (budget estimates), estimates from previous in-house 

design/build projects, and projected costs from APS Four Corners Generating Station. 

The annual operating cost estimates were based on operation at full load conditions. The 

annual operating costs covered increases in fan auxiliary power requirements, additional 

labor requirements, water costs, waste product disposal costs, and additional costs for 

consumables. The cost calculations are included in Appendix D. Table 2-1 shows the 

values that B&V used to perform this economic analysis. 

2.2.1 Capital Cost Estimates 

 Capital costs were developed for retrofit control technologies that were identified 

as technically feasible for application at Four Corners Units 1 through 5. Direct costs 

comprise purchased equipment, installation, and miscellaneous costs. The equipment 

costs include the purchase of the control technology equipment from a vendor (including 

taxes and freight). The cost to install the equipment at the source site also takes into 

account issues related to retrofit difficulty, based on the site configuration and condition. 

Finally, miscellaneous costs account for additional items, such as site preparation, 

buildings, and other structures. 

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Four Corners Units 1 through 5 Basis of Analysis 

Table 2-1 

Economic Assumptions (2006 Costs) 

Annual Operating Costs 

Units 1, 2, and 3 Bottom Ash Disposal Cost ($/ton) 3.90 

Units 4 and 5 Bottom Ash Disposal Cost ($/ton) 6.30 

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

Urea Cost ($/ton) 420 

Auxiliary Power Cost ($/MWh) 60.00 

Replacement Power Cost ($/kWh) (1) 

Water Cost ($/1,000 gal) 0.002 

Fully Loaded Labor Rate ($/year) 72,800 

Escalation/Inflation (percent) 3 

Notes: 

(1)APS provided this information, which was used during the development of this study. 

However, this information is not being disclosed (according to APS request) due to 

confidentiality considerations. 

 The direct cost estimates were based on the following assumptions: 

• Regulatory permitting has been authorized. 

• A regular supply of construction craft labor and equipment is available. 

• Normal lead times for equipment deliveries are expected. 

• Construction utilities (power, water, air) are provided by the Owner. 

Indirect costs are not related to the equipment purchased, but are associated with 

any engineering project. The indirect costs considered in this study include engineering, 

construction, and field expenses; contractor fees; and startup and performance tests. 

Included in the indirect costs is contingency, which is meant to be a “catch-all” item to 

account for unpredictable events and costs that may arise. Potential costs included in the 

contingency are possible redesign or modification of equipment; errors in estimation; 

unforeseen weather-related delays; strikes and labor shortages; increases in equipment 

costs; increases in labor costs; delays encountered in startup, etc. Indirect costs included 

in this evaluation include the following: 

• Engineering. 

• Owner’s Cost. 

• Construction and Field Expenses. 

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Arizona Public Service 

Four Corners Units 1 through 5 Basis of Analysis 

• Startup and Spare Parts. 

• Performance Tests. 

• Contingency. 

2.2.1.1 Engineering. Engineering costs include any services provided by an 

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

quality control (AQC) project. 

2.2.1.2 Owner’s Cost. Table 2-2 lists possible Owner’s costs covered by this 

category and identified in the 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 will experience through an air quality control (AQC) retrofit project. 

Table 2-2 

Typical Owner’s Cost Categories 

Project Development: 

• Legal assistance 

• Environmental permitting/offsets 

• Public relations/community 

development 

• Road modifications/upgrades 

Plant Startup/Construction Support: 

• Owner’s site mobilization 

• Operations and Maintenance (O&M) 

staff training 

• Initial test fluids and lubricants 

• Initial inventory of chemicals/reagents 

• Consumables 

• Construction all-risk insurance 

• Auxiliary power purchase 

Financing: 

• Debt service reserve fund 

• Analyst and engineer 

Owner’s Project Management: 

• Internal project management 

• Perform engineering due diligence 

• Prepare bid documents and selection of 

contractor(s) and suppliers 

Taxes/Advisory Fees/Legal: 

• Taxes 

• Market and environmental consultants 

• Owner’s legal expenses: 

- Power Purchase Agreement (PPA) 

- Interconnect agreements 

- Contract--Procurement and 

construction 

- Property transfer 

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Four Corners Units 1 through 5 Basis of Analysis 

2.2.1.3 Construction and Field Expenses. Construction management services 

include field management staff including supporting staff 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. 

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

startup planning and procedure and 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 components spare parts are 

only kept if recommended by the manufacturer and is determined and accounted for on a 

case-by-case basis. 

2.2.1.5 Performance Tests. Performance tests services are commissioned after 

every AQC technology addition to validate the performance of the emissions reduction 

system. Typical performance tests flue gas emissions testing that may be performed at 

various points in the flue gas flow path. The results of the performance test are used to 

ensure compliance with performance guarantees and emissions limits. 

2.2.1.6 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. 

2.2.2 Annual Operations and Maintenance Cost Estimate 

Annual O&M costs consist of the following: 

• Reagent costs. 

• Electric power costs. 

• Makeup water costs. 

• Wastewater and byproduct disposal costs. 

• Operating labor costs. 

• Maintenance materials and labor costs. 

The cost of reagent, electric power, makeup water, wastewater treatment, and 

byproduct disposal are variable costs and are dependent on the amount of pollutant 

removed. O&M materials and labor are fixed costs that are required regardless of the 

amount of time the pollution control is used. Table 2-1 lists the major economic factors 

used to obtain annual O&M costs. 

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Four Corners Units 1 through 5 Basis of Analysis 

2.2.2.1 Reagent Cost. Reagent costs include cost of material and delivery to the 

facility. The additional costs associated with reagent, such as reagent preparation, are not 

included in the reagent cost. Reagent costs depend on the quantity of the reagent used 

and the price of the reagent. The quantity of reagent will depend on the amount of 

pollutant removed and the reagent utilization ratio. 

2.2.2.2 Electric Power Costs. Additional auxiliary power will be required to run the 

new control technology systems. The power requirements of each system will vary 

depending on the type of technology and the complexity of the system. Additional 

auxiliary power will also be required by the induced draft (ID) fan to overcome flue gas 

pressure losses across the new equipment. 

2.2.2.3 Makeup and Service Water Costs. Makeup and service water is required 

for some processes in the new control technology systems. Water is used for ammonia 

solution preparation for SCR and selective noncatalytic reduction (SNCR) processes, and 

for electrode plate washing in a wet ESP. 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.

2.2.2.4 Wastewater and Byproduct Disposal Costs. Some control technologies 

generate wastewater and/or byproduct that will require disposal. This portion of the 

engineering analysis considers only NOx, the main byproduct disposal consideration will 

be the possibility of rendering the fly ash unsaleable due to ammonia (NH3) slip and/or 

high unburned carbon.

2.2.2.5 Operating Labor Costs. Operating labor costs include costs for the number 

of employees that will be required to run the new AQC equipment. This estimation is 

based on industry common practices and is only a suggested quantity. The labor cost is 

based on a fully loaded labor rate, with the basis of a 50 hour per week work schedule. 

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

the following personnel: 

• Supervisor. 

• Control Room Operator. 

• Roving Operator. 

• Relief Operator. 

• Laboratory Technicians. 

• Equipment Operators. 

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. For technologies that replace a similar existing technology in the 

current plant site, a determination of the additional maintenance requirements is 

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Four Corners Units 1 through 5 Basis of Analysis 

performed. If the required maintenance materials and labor are similar to the existing 

technology, no additional maintenance costs are credited for the new control technology. 

The annual maintenance and labor costs were based on guidance from the APS Four 

Corners Generating Station regarding its experience with maintenance costs. Past 

experience has shown the maintenance and labor cost to be approximately 9 percent of 

the project capital cost. The maintenance cost for the selective catalyst reactor, due to its 

large capital cost, was assigned an annual maintenance value of 3 percent of the total 

direct capital costs. 

2.3 Baseline Emissions 

The baseline emissions for NOx and PM are required to be established for this 

BART analysis to compare the impacts of each of the control technologies. Baseline 

emissions are defined to be the current emissions under the existing plant equipment and 

operational configuration conditions at the time this study was conducted. These baseline 

emissions already include the effect of additional emissions control equipment installed 

over the operational life of Units 1 through 5. The baseline emissions are calculated from 

the average of the annual NOx and PM emissions rate from the last 5 years. The annual 

NOx and PM emissions from each of the last 5 years are presented in Appendix F. The 

baseline emissions established for Four Corners Units 1 through 5 are summarized in 

Table 2-3. It should be noted that the Units 4 and 5 values are per unit. 

Table 2-3 

Baseline Emissions 

Unit 1 Unit 2 Unit 3 Units 4 and 5 

NOx PM 

Nitrogen 

Oxide 

(NO) PM NOx PM NOx PM 

Emission Rate 

(lb/mmBtu) 

0.78 0.025 0.64 0.029 0.59 0.029 0.49 0.012 

Annual Emissions 

(ton/yr) 

5,703 180 4,788 220 5,633 285 13,028 313 

2.4 Target Emissions 

 In the final rule of the Regional Haze Regulations and Guidelines for BART 

issued in July 2005, presumptive limits that apply to BART-eligible sources are outlined. 

Since the EPA has specified that the Four Corners facility is subject to BART for NOx

and PM, the presumptive limit for NOx differs according to the boiler design and type of 

coal that is burned. In the case of dry bottom-wall fired, bituminous coal units, such as 

120407 2-6 
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Four Corners Units 1 through 5 Basis of Analysis 

120407 2-7 

Four Corners Units 1 through 3, the presumptive limit for NOx is 0.39 lb/mmBtu. The 

presumptive limit for Units 4 and 5 is 0.40 lb/mmBtu. The BART presumptive limits for 

NOx and PM are summarized in Table 2-4. 

Table 2-4 

Target Emissions for BART Analysis 

Unit 1 Unit 2 Unit 3 Units 4 and 5(1)

Presumptive Limit NOx PM(2) NOx PM(2) NOx PM(2) NOx PM(2)

Bituminous Fuel 

(lb/mmBtu) 

0.39 N/A 0.39 N/A 0.39 N/A 0.40 N/A 

(1)Units 4 and 5 are classified as cell burner boilers. 

(2)PM target emissions are for filterable PM only. 
Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

3.0 Identification of All Available Retrofit Emission Control 

Technologies (Step 1) 

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

have a practical potential for application were identified. The control option can be a 

system, technology, or change in operational method used to control the emission rate of 

a pollutant. In this section, control technologies for NOx reduction are listed with a brief 

description. The design, retrofit considerations, and advantages and disadvantages of 

each technology are also outlined. 

3.1 NOx Control Technologies 

 NOx control technologies that were identified as available for retrofit at Four 

Corners are listed below: 

• Boiler optimization system (upgrade/replace existing Neuco system). 

• LNB with overfire air (OFA). 

• Mobotec ROFA and ROTAMIX. 

• NOxStar and NOxStar Plus. 

• ECOTUBE. 

• Induced flue gas recirculation (IFGR). 

• SCR. 

• SNCR. 

• SCR/SNCR hybrid (Cascade System). 

• LoTOx. 

• Natural gas reburn (includes fuel lean gas reburn [FLGR], amineenhanced fuel lean gas reburn [AE-FLGR]). 

• THERMALONOx Process. 

• Oxygen enhanced combustion. 

• Biotechnological denitrification (BioDeNOx). 

3.1.1 Combustion Optimization System 

For optimum combustion, properly balanced amounts of coal and air should enter 

the furnace through the delivery of each burner and the OFA system, if present. This 

balanced delivery should produce the maximum amount of heat with the minimum 

amount of waste. However, without the ability to continuously monitor air and fuel flow 

entering each burner and the resulting burner performance, conditions typically exist 

where inadequate air is supplied for combustion, creating a fuel rich or air rich area. 

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Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

Both conditions reduce boiler efficiency and result in excess carbon monoxide (CO), fly 

ash loss on ignition (LOI), or NOx emissions. 

In an attempt to prevent or reduce these effects, plants often turn to the procedure 

known as “burner balancing.” This entails the monitoring and adjustment of burners so 

that the fuel/air ratio is equalized across the boiler. Historically, this has not been a 

simple procedure to perform or to maintain across the normal boiler load range. 

Initial attempts at monitoring LNB performance were directed toward measuring 

flue gas constituents leaving the boiler, which provided an indication of the total air to 

fuel ratio and average NOx and CO emissions. This information established the average 

performance of the complete firing system, but the performance status of each individual 

burner was not available. 

Recent advances in flow measurement and flame scanning techniques have shown 

some limited success in monitoring both coal and primary airflow, and also secondary 

airflow to each burner in addition to burner flame patterns. With this additional level of 

online performance data, the secondary airflow and coal mill feeders can be biased to 

continuously maintain burner to burner balance. 

Additionally, recent advances in computer hardware and software technology 

have enabled power generation companies to improve their competitive position by 

implementing cost-effective optimization solutions that decrease emissions and maximize 

plant efficiency. This solution, commonly referred to as boiler optimization or neural 

network systems, provides simultaneous improvements in both fuel efficiency and 

emissions. Neural network computing differs from traditional computing because 

engineering, statistical, and first law principles have been supplemented by complex, time 

varying, nonlinear relationships. Neural network systems use real-time operational data 

extracted from a plant distributed control system (DCS), “learn” solutions from plant 

operational experience, and reduce emissions while improving plant performance by 

continuously adapting to changes in plant operation. 

 Neural network systems also supplement other NOx reduction strategies. Some of 

these include LNBs, OFA, and postcombustion 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 modifications, such as OFA 

modifications. 

3.1.2 Low NOx Burners 

NOx, primarily in the form of NO and NO2, are 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 

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Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

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. 

All LNBs that are offered commercially for application to coal fired boilers 

control the formation and emission of NOx through some form of staged combustion. 

The basic NOx reduction principles for LNBs are to control and balance the fuel and air 

flow 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 takes 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 where it will be 

forced 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, because of this delayed mixing process. This is also one of 

the main reasons why low NOx combustion is normally associated with the potential for 

increased carbon in ash and higher CO emissions, as the combustion process begins to 

encroach on cooled boiler surfaces. This is particularly true for 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. 

3.1.3 Low NOx Burners and Overfire Air System 

In addition to the LNB system, an incremental approach to NOx control is to 

install an OFA system to combine LNBs with OFA. 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, which 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 at which 

CO levels become high and uncontrollable. The point at which this occurs can be 

specific to the boiler and coal type, particularly if a fuel is difficult to burn, and will also 

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Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

depend on the extent to which it is possible to balance flows between the individual 

cyclones or burners. As the OFA amount approaches 10 to 15 percent, the probability for 

individual burners operating under overall fuel rich conditions increases, so that pockets 

of very high CO emissions and unburned carbon will be formed. Similarly, fuel rich 

operation of burners close to the water walls can begin to lead to local slag formation and 

increased tube wastage rates, particularly if slagging is an ongoing problem and the coals 

have a high sulfur content. A fairly high level of unburned material leaving the burner 

zone can be accommodated for, through proper overfire port design where requirements 

call for rapid and complete mixing of the OFA with the boiler flue gases. A diagram 

illustrating the staged combustion of LNBs and OFA is shown on Figure 3-1. 

Overfire 

Air 

Figure 3-1 

Staged Combustion of LNBs and OFA System 

3.1.4 Mobotec ROFA and ROTAMIX 

Mobotec provides a NOx reduction system that combines LNB, OFA, and SNCR 

technologies into an integrated system. The system uses a modified OFA system with 

improved mixing characteristics achieved through adding a rotation to the OFA. This 

system is called ROFA (Rotating Opposed Firing Air). In addition, ROTAMIX, which 

consists of adding urea into the furnace by injection with boosted air, can be added to the 

ROFA system. The extra mixing produced by combining the OFA nozzles with the 

reagent injection results in improved reagent mixing and a more homogeneous 

temperature profile in the boiler. A simplified process flow diagram of the ROFA and 

ROTAMIX system is illustrated on Figure 3-2. 

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Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

Figure 3-2 

Mobotec ROFA and ROTAMIX Simplified Process Flow Diagram 

The NOx reduction system has been commercially proven and has achieved up to 

75 percent NOx reduction. The more homogeneous temperature profile in the boiler will 

optimize combustion and, in turn, will promote a lower carbon content in the fly ash than 

a typical combustion environment would. One main disadvantage of the Mobotec 

system, as it applies to Four Corners Units 1, 2, and 3, is that the furnace arrangement 

does not allow the rotational motion of the flue gas to be established. The main benefit of 

the ROFA system for Units 1, 2, and 3 will be the additional mixing due to the 

introduction of high velocity OFA. Additionally, the ash at Four Corners is highly 

erosive; any ash that migrates into the air heater may cause maintenance issues with the 

ROFA fan. The Mobotec ROFA and ROTAMIX system does not have an equivalent 

application experience on a unit similar in size to Units 4 and 5 and is not considered an 

available technology for those units. 

3.1.5 NOxStar and NOxStar Plus 

NOxStar is the trademarked name for an 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 approximately 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 those 

achievable with a typical SNCR technology. A central premise of the technology is the 

ability to achieve NOx emissions of less than 0.20 lb/mmBtu without the use of a catalyst. 

Although initially targeting high NOx reductions, full-scale demonstrations to date have 

been limited to nominally 50 percent NOx reduction performance. 

NOxStar eliminates solid catalyst and the associated problems of chemical 

poisoning, physical plugging, sintering caused by temperature excursions, pressure drop 

requiring new ID fans, and disposal of a hazardous solid waste. NOxStar operates 

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Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

opportunistically within the confines of the boiler’s convective pass, eliminating the 

necessity to build a huge catalyst reactor and avoiding the associated SCR capital costs, 

economizer modifications, and major outages. The other advantage of the NOxStar 

system is that the conversion of SO2 to sulfur trioxide (SO3) is said to be negligible, thus 

eliminating one of the main drawbacks of the SCR technology. 

NOxStar has a lower NOx reduction efficiency than an SCR system; it also has a 

higher ammonia slippage rate than an SCR system. SO3 in the presence of ammonia will 

form ammonia sulfate, ammonia bisulfate, and other salts in combination with iron and 

aluminum. The deposition temperature of these salts from the flue gas is dependent on 

the relative concentration of ammonia and SO3 in the flue gas. Ammonium bisulfate is a 

sticky substance that can deposit on air heater baskets and other downstream equipment 

surfaces. Resultant particle diameters at the stack are on the order of 1 to 3 microns and, 

thereby could contribute to PM10 emissions. Ammonia salts depositing on air heater 

surfaces could increase the frequency of off-line washes in combination with forced 

outages. 

A significant quantity (up to 80 percent) of the ammonia slip that exits the 

NOxStar system will react with flue gas and fly ash constituents and be collected with the 

fly ash in the particulate removal equipment. The ammonia content of the fly ash can 

affect waste disposal practices and the potential for waste product sales because of 

odorous emissions. 

 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 to achieve advertised levels of NOx reduction. 

3.1.6 ECOTUBE 

The ECOTUBE system is a boiler combustion improvement and NOx reduction 

technology. Retractable lance tubes that penetrate the boiler above the primary burner 

zone 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. 

ECOTUBE is a system that reduces NOx, CO, and volatile organic compounds 

(VOC) while improving thermal efficiency by optimizing the combustion process in 

boilers. The ECOTUBE system is a hybrid of two proven technologies: separated 

overfired air (SOFA) and SNCR. By injecting air, ammonia, or urea through retractable 

lances in the upper furnace, the ECOTUBE utilizes a similar approach as SOFA and 

SNCR. By creating turbulence at the best location in the gas flow, an improved fuel/air 

ratio is achieved through better mixing, along with a lower stoichiometric ratio of O2. An 

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

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Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

Figure 3-3 

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 depositions. ECOTUBE’s 

self-cleaning capability and safety control system allow a safe and continuous operation. 

However, while the ECOTUBE system has been removed from the boiler for cleaning, 

NOx emissions will not be reduced. Unlike many low cost SNCR systems, ECOTUBE’s 

furnace combustion improvements may increase efficiency and reduce fuel usage. At the 

same time, it reduces convection pass, air preheater (APH), precipitator, baghouse, 

ductwork, and stack corrosion and erosion. ECOTUBE is expected to be less than half 

the cost of SCRs and involves less installation downtime and boiler modifications than an 

SCR. The main challenge of the ECOTUBE is the available footprint at a retrofit site for 

the retractable lance and the structural integrity of the lance as the technology is applied 

to larger furnaces. 

3.1.7 Induced Flue Gas Recirculation 

Recirculation of flue gas back to the combustion zone has been an effective 

method of reducing NOx emissions from gas and oil fired boilers since the early 1970s. 

Injection of flue gas into the combustion air is a proven method for controlling NOx

production from gas fired utility boilers. For units not equipped with gas recirculation 

fans, flue gas can be injected into the combustion air by a technique known as induced 

flue gas recirculation (IFGR). 

IFGR acts to reduce NOx formation by reducing peak flame temperatures. In 

conventional applications, the recirculated flue gas is typically extracted from the boiler 

outlet duct upstream of the air heater. The flue gas is then returned through a separate 

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Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

duct and hot gas fan to the combustion air duct that feeds the windbox. The recirculated 

flue gas is mixed with the combustion air via air foils or other mixing devices in the duct. 

This technology is known as windbox flue gas recirculation (WFGR). WFGR systems 

require installation of a separate hot gas flue gas recirculation (FGR) fan to move flue gas 

from the boiler exit to the air supply ducting at the windbox inlet, where mixing of the air 

and flue gas must be uniformly achieved by installation of appropriate mixing devices. 

Although FGR has proven to be very effective on applications involving gaseous 

or liquid fuels, its effectiveness is limited with coal applications because it has a very 

limited capability to control the NOx produced by the nitrogen bound in the fuel. 

Additionally, experience in the industry using FGR for steam temperature control has 

exhibited a considerable amount of O&M problems caused by erosion of the fans and 

dust accumulation in the ductwork. Consequently, the application of this technology to 

coal fired units is virtually nonexistent. Four Corners’ experience with the technology on 

Units 4 and 5 has shown that it is not a viable option for NOx reduction because of 

operational concerns. 

3.1.8 Selective Catalytic Reduction (SCR) 

SCR systems are the most widely used postcombustion NOx control technology 

for achieving significant reductions in NOx emissions. In SCR systems, vaporized 

ammonia injected into the flue gas stream acts as a reducing agent, achieving NOx

emission reductions as low as 0.06 lb/mmBtu 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) with very low ammonia slip (unreacted ammonia 

emissions). A simplified schematic diagram of a typical SCR reactor is illustrated on 

Figure 3-4. 

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 soot blowers. An ammonia 

injection grid is located upstream of the SCR reactor, and the system can be designed 

with or without a flue gas bypass. The SCR reactor is typically elevated above and 

behind the air heater and downstream of emissions control equipment (typically an ESP); 

gas flow direction through the reactor is vertically downward for coal fired applications. 

In a “high dust” SCR arrangement, the reactor is located between the outlet of the 

economizer and the inlet of the air heater. The high dust system is typically the most 

economical and preferred arrangement, where physically possible. 

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Figure 3-4 

Schematic Diagram of a Typical SCR Reactor 

The SCR reaction occurs within the temperature range of 550° to 850° F; the 

extremes are highly dependent on the fuel quality. 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 or the addition of some flue gas treatment system to remove the SO3. 

The ammonia reagent for the SCR systems can be supplied by anhydrous 

ammonia, aqueous ammonia, or by conversion of urea to ammonia. Since the ammonia 

is vaporized prior to contact with the catalyst, the selection of ammonia type does not 

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

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

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

use anhydrous ammonia, but recent safety, environmental, and homeland security 

concerns have reduced the market share of anhydrous ammonia on new SCR 

installations. 

Economizer 

Bypass 

(if required) 

Space for Future Catalyst

and Soot Blower Addition

Gas Flow Distribution

Devices 

Sonic Horns

Vaporized

Ammonia

Flue Gas to

Air Heater

Catalyst

Temperature Grid 

Tuning/Monitoring Grid

Bypass 

Damper

Isolation*

Dampers

Flue Gas 

From 

Economizer 

* Not supplied in new SCR 

for 12 month operation. 
Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

SCR systems have a variety of interfacing system requirements to support 

operations. These requirements predominately relate to draft, auxiliary power, soot 

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

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

performance requirements, draft losses can range from 6 to 12 inches water gauge 

pressure. This can be compensated for by modifying the draft system with the addition of 

ID booster fans. If necessary, ductwork and/or boiler box reinforcement need to be 

considered. In conjunction with the fan modification, the upgrade 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. The other potential danger for the air heater is high concentrations of SO3 in 

the flue gas. If the acid dew point 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 provisions can be made to avoid or correct this 

situation. Most important is the right composition of the catalyst to minimize the SO2 to 

SO3 conversion rate and the proper temperature control of the flue gas entering the 

reactor. 

3.1.9 Selective Noncatalytic Reduction (SNCR) 

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

the steam generator, as illustrated on Figure 3-5. SNCR systems rely solely on reagent 

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

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

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

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

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

2,500° to 3,000° F. 

SNCR systems are capable of achieving an NOx emission reduction as high as 50 

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

flue gas mixing, high baseline NOx conditions, multiple levels of injectors), with 

ammonia slips of 10 to 50 parts per million by dry volume (ppmvd). Lower ammonia 

slip values can be achieved with lower NOx reduction capabilities. Typically, optimum 

conditions are difficult to achieve, resulting in emission reduction levels of 20 to 

40 percent. Potential performance is site-specific and varies with fuel type, steam 

generator size, allowable ammonia slip, furnace CO concentrations, and steam generator 

heat transfer characteristics. 

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Combustion Air

Injection

Level 2

Injection

Level 3

Burners

Steam Generator

Air Heater

Injection Level 1

Flue

 Gas

Ammonia or 

Urea Storage Tank

Figure 3-5 

Schematic of SNCR System with Multiple Injection Levels 

SNCR systems reduce NOx emissions using the same reduction mechanism as 

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

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

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

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

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

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

(MW). 

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 

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 (CFD) and chemical kinetic 

modeling can be performed to establish the optimum ammonia injection locations and 

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flow patterns. For an existing boiler, minor waterwall modifications are necessary to 

accommodate the installation of SNCR injector lances. Steam piping modifications 

would probably be required to achieve optimum performance. 

3.1.10 SNCR/SCR Hybrid (Cascade) 

The SNCR/SCR hybrid system uses components and operating characteristics of 

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

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

reduction potential and low ammonia slip inherent to the catalyst of SCR systems. The 

result is a NOx reduction alternative that can meet initially low NOx reduction 

requirements, but can be upgraded to meet higher reductions at a future date, if required. 

The SNCR component of the hybrid system is identical to the SNCR system 

described previously, except that the hybrid system may have more levels of multiple 

lance nozzles for reagent injection. This will increase the capital cost of the SNCR 

component of the hybrid system. During operation, the SNCR system would be allowed 

to inject higher amounts of reagent into the flue gas. This increased reagent flow has a 

twofold effect: NOx reduction within the boiler is increased, and 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 will use the catalyst simply as an ammonia slip “scrubber” 

with some additional NOx reduction. As with duct systems, the flue gas velocity through 

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

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

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

catalyst requirement of this design can potentially fit all the catalyst in a true in-duct 

arrangement, with no significant ductwork changes, arrangement interference, or 

structural modifications. The second philosophy uses adequate catalyst volume to obtain 

significant levels of additional NOx reduction. The additional reduction is a function of 

the quantity of ammonia slip, catalyst volume, and distribution of ammonia to NOx

within the flue gas. Using ammonia slip produced by the SNCR system is not a high 

efficiency method of introducing reagent, because of the low reagent utilization discussed 

as a part of the SNCR. Therefore, even though the reaction at the catalyst requires 1 ppm 

of ammonia to remove 1 ppm of NOx, the SNCR must inject at least 3 ppm of ammonia 

to generate 1 ppm of ammonia at the catalyst. 

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

ammonia distribution. The effect of catalyst volume on the design of a hybrid system is 

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on the size of the reactor required to hold the catalyst. If multiple levels of catalyst 

operating at low flue gas velocity are required, some modifications will be required to the 

existing ductwork. If widening the ductwork cannot provide adequate catalyst volume, a 

separate reactor is required. The addition of a reactor negates the capital cost advantage 

of a hybrid system. 

3.1.11 LoTOx

The LoTOx technology is the low temperature gas phase oxidation of NOx by 

ozone injection. In this method, ozone is injected into the flue gas upstream of a wet flue 

gas desulfurization (FGD) system. The ozone reacts with the NO and NO2 to form 

nitrogen pentoxide (N2O5). The nitrogen pentoxide formed is soluble in water and can be 

removed from the flue gas using a wet FGD system. 

The LoTOx technology has been demonstrated on several industrial size plants, 

including Abitibi Consolidated (Sheldon, Texas), a paper recycling plant, the Medical 

College of Ohio, and several refinery applications. 

The LoTOx technology offers high NOx removal efficiency with a reported 

potential of 15 to 25 percent savings in capital cost over an SCR. The major drawbacks 

of this system are the lack of experience on larger power generating units, high power 

consumption, and the production of nitrates. 

The high power level resulting from the multiple ozone generators required to 

produce the ozone for the process is expected to be comparable to what is needed for a 

conventional FGD system and is significantly higher than the power consumption from 

an SCR. The nitrate produced from this technology is captured in the FGD waste 

product. Most regulatory agencies are strict about nitrate release into water systems; a 

wastewater treatment plant may be required. 

3.1.12 Natural Gas Reburn 

The natural gas reburning process employs three separate combustion zones to 

reduce NOx emissions as illustrated on Figure 3-6. The first zone consists of the normal 

combustion zone in the lower furnace, which is formed by the existing wall burners. In 

this zone, 75 to 80 percent of the total fuel heat input is introduced. The first zone 

burners are operated with about 10 percent 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. 

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Burnout Zone

•Normal Excess Air

Reburning Zone

•Slightly Fuel Rich

•NOx Reduced to N2

Primary Combustion

Zone

•Reduced Firing Rate

•Low Excess Air

•Lower NOx

Overfire Air

40 to 60% NOx Reduction

10 to 20 % Gas

Fuel Rich

80 to 90% Coal

10% Excess Air

Figure 3-6 

Schematic of Gas Reburn System 

The substoichiometric reburn zone causes NOx produced in the lower furnace 

units to be reduced to molecular nitrogen and oxygen, because the oxygen stripped from 

the NOx molecules is combined with the more active CO molecules to form 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 reduction of 40 to 65 percent. 

 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 furnace 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. In addition, the high cost of natural gas increases the annual operating 

costs and makes them unpredictable because of the high volatility of the natural gas 

prices. 

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3.1.13 THERMALONOx Process 

 THERMALONOx

TM, a two step process for controlling NOx, once showed promise 

as an emerging technology. The first step consists of a gas-phase chemical reaction in 

which NO is converted into NO2 through a compact gas reactor. 

The THERMALONOx

TM process uses direct injection of elemental phosphorus (P4) 

into exhaust gas streams emitted from fossil fuel fired combustion processes, at 121° C 

(250° F) to 280° C (536° F). The P4 reacts simultaneously with oxygen to form ozone (O3), 

which immediately reacts with NO to form NO2 through a chain of chemical reactions. The 

second step incorporates a standard wet FGD scrubber system for removing 90 percent of 

the NO2, which is absorbed and dissolved into the water as nitrates, which are nonhazardous 

and can be recycled as a commercial fertilizer. 

Despite the promising nature of this technology, full-scale testing in 2001 indicated 

that it did not appreciably reduce NOx emissions levels on one of the 375 MW units at the 

AEP Conesville plant. AEP canceled testing, and further demonstration technology has not 

been completed. 

3.1.14 Oxygen Enhanced Combustion 

Praxair, a purified gas supplier, developed this NOx control technology, which 

utilizes oxygen enhanced combustion. The current technology, as applied to coal fired 

boilers, replaces approximately 5 to 10 percent of the stoichiometric combustion air 

requirement with an equivalent amount of pure oxygen. This amount of pure oxygen 

reduces the throughput of combustion gases through the boiler by a slightly smaller 

percentage. For a utility unit, 5 to 10 percent replacement of the combustion air represents 

significant oxygen consumption rates. To support the large quantity of oxygen used in the 

process, an oxygen supply company would likely be contracted to generate the oxygen 

onsite. Companies such as Praxair, Air Products, or BOC have typically built oxygen 

production facilities directly on an industrial customer’s site, based on a lease and 

processing agreement. It is anticipated that Praxair would want to follow this industry 

approach. Praxair is also developing a new oxygen producing technology (called “oxygen 

transport membrane”) that may cut oxygen costs; however, this technology is still in the 

developmental stage. 

Oxygen enhanced staged combustion serves to reduce both NOx and unburned 

carbon through an increase in the local flame temperature for a given stoichiometric ratio. 

The temperature increase reduces NOx by driving the reactions toward the formation of 

nitrogen rather than NOx. The increased temperature, when coupled with higher local 

oxygen inlet concentrations, leads to increased devolatilization rates, which, in turn, lead to 

less residual carbon that must be burned in the second stage, and less unburned carbon in the 

ash. 

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The US Department of Energy reports that the overall cost for this technology may 

be in the range of 50 percent less than that for SCR. However, a report recently completed 

for Seminole Electric by the Electric Power Research Institute (EPRI) (Seminole Electric 

NOx Control Technology Assessment, Final Report, February 2005) indicates that for a 

hypothetical 700 MW unit in which emissions have already been reduced through 

combustion controls, the estimated cost for this technology is in the range of $1,900/ton 

removed. This cost is higher than other recent SCR estimates prepared under the same 

market conditions. The study also reported emissions reductions for the hypothetical unit of 

less than 50 percent removal. 

The most significant drawback of oxygen enhanced technology is the limited 

amount of practical experience. The technology has been demonstrated on the City Utilities 

of Springfield’s St James River Station Unit 3, a 44 MW unit. The technology has been 

licensed to the Northeast Generation Services Company for Mt. Tom’s Plant, a 147 MW 

unit. 

3.1.15 Biotechnological Denitrification (BioDeNOx) 

 Biotechnological denitrification (BioDeNOx) technology is a patented process 

incorporated into an existing FGD scrubber to create the simultaneous removal of SO2

and NOx from the flue gases. The captured nitrogen compounds are converted into 

nitrogen gas by using a biocatalyst that is added to the scrubber liquid. The system 

consists of two main parts: an absorber unit (in addition to the sulfur oxides [SOx] 

scrubber) and a bioreactor. 

NOx is present in the flue gas as NO and NO2. NO2 dissolves easily in water and is 

removed from the flue gas. NO is normally 95 percent of the total NOx and is difficult to 

dissolve in water. In the BioDeNOx process, an iron chelate (FeII[EDTA]2-) is used that 

reacts with NO to form a nitrosyl complex; this enables the NO to dissolve in the water. 

In the BioDeNOx process, the regeneration of the active FeII[EDTA]2- from the 

nitrosyl complex is solved by an inexpensive, simple biological regeneration. The reduction 

of the nitrosyl complex is similar to the processes that occur in denitrifying wastewater 

systems. Ethanol is used as the reducing agent for the regeneration of the FeII[EDTA]2-. 

The regenerated FeII[EDTA]2- is recycled to the scrubber. 

The BioDeNOx process has high capital costs because of an additional bioreactor 

and scrubber. It should be noted that this technology has been implemented on a 

commercial plant with a 70 MW capacity, but has not been installed on commercial 

power plants. 

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3.2 Particulate Matter Control Technologies 

 PM control technologies that were identified as available for retrofit at Four 

Corners are listed below: 

• ESP. 

• Pulse Jet Fabric Filter (PJFF). 

• Compact Hybrid Particulate Collector (COHPAC). 

• GE MAX-9 Hybrid. 

• Multicyclone. 

• Wet ESP. 

• Particle Agglomeration. 

• EnviroScrub. 

• Coal Washing. 

3.2.1 Electrostatic Precipitator (ESP) 

ESPs are the most widely installed utility particulate removal technology. ESPs 

use transformer rectifiers to energize discharge electrodes and produce a high voltage, 

direct current electrical field between the discharge electrodes and grounded collecting 

plates. PM entering the electrical field acquires a negative charge and migrates to the 

grounded collecting plates. This migration can be expressed in engineering terms as an 

empirically determined effective migration velocity, but it takes place in the turbulent 

flow regime, with the particulate entrained within the turbulent gas patterns. Thus, the 

charged particles are actually captured when the combined effect of electrical attraction 

and gas flow patterns moves the PM close enough so that it can attach to the collecting 

surfaces. A layer of collected particles forms on the collecting plates and is removed 

periodically by mechanically rapping the plates. The collected particulate drops into 

hoppers below the precipitator and is removed by the ash handling system. Some 

particulate is also re-entrained and either collected in subsequent electrical fields or 

emitted from the ESP. A picture showing the sections of an ESP is shown on Figure 3-7. 

The required particulate removal efficiency, the expected electrical resistivity of 

the fly ash to be collected, and the expected electrical characteristics of the energization 

system determine the physical size of an ESP. Many parameters determine the ESP’s 

capability for particulate collection including the major items discussed in this 

subsection. 

The first parameter is the specific collection area (SCA). ESP size is often 

measured in terms of SCA. SCA is defined as the total collecting area (ft2

) divided by the 

volumetric flue gas flow rate (1,000 actual cubic feet per minute [acfm]). 

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Figure 3-7 

Electrostatic Precipitator System (MHI) 

Second, the treatment time that the flue gas is within the electric collection fields 

of the ESP is an important aspect of particulate collection. High efficiency ESPs 

typically have treatment times between 7 and 20 seconds. Treatment time is becoming a 

major design parameter, since lower particulate emissions are being mandated. 

Flue gas velocity, which is the speed with which the flue gas moves through the 

ESP, is important in the design and sizing of the ESP. Design gas velocities ranging 

between 3 to 4 feet per second are common. 

The aspect ratio, defined as the treatment length to the collection plate height, is 

an important design parameter of ESPs. As the aspect ratio increases, the re-entrainment 

losses from the ESP are minimized. Many existing ESPs have aspect ratios of around 0.8 

to 1.2. Newer ESPs, especially those meeting new particulate emission limits, have 

aspect ratios around 1.2 to 2.0. 

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The gas distribution for optimum particulate removal requires uniform gas 

velocity throughout the entire ESP treatment volume with minimal gas bypass around the 

discharge electrodes or collecting plates. If flue gas distribution is uneven, the particulate 

removal efficiency will decrease, and re-entrainment losses will increase in high velocity 

areas, reducing overall collection efficiency. Finally, fly ash resistivity is a measure of 

how easily the ash or particulate acquires an electric charge. Typical coal fly ash 

resistivity values range from 1 x 108 ohm-cm to 1 x 1014 ohm-cm. The ideal resistivity 

range for electrostatic precipitation of fly ash is 5 x 109

 to 5 x 1010 ohm-cm. Operating 

resistivity varies with flue gas moisture, SO3 concentration, temperature, and ash 

chemical composition. As a result of fly ash resistivity being sensitive to these 

constituents, ESPs can be significantly affected by changes in fuel or operating 

conditions. 

3.2.2 Pulse Jet Fabric Filter (PJFF) 

Fabric filters are media filters that the flue gas passes through to remove the 

particulate. Cloth filter media 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, which allows 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. Extra compartments 

for maintenance or off-line cleaning increases the reliability at the expense of capital cost 

and real state utilization. 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 3-8. 

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. 

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Figure 3-8 

PJFF Compartment 

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

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

cake from the bag surface. The dust then falls into the hopper. This cleaning may occur 

with the compartment online or off-line. Care must be taken during design to ensure that 

the upward velocity between the bags is minimized so that particulate is not re-entrained 

during the cleaning process. The PJFF cleans bags in sequential, usually staggered, rows. 

During online cleaning, part of the dust cake from the row being cleaned may be captured 

by the adjacent rows. Despite this apparent shortcoming, PJFF have successfully 

implemented online cleaning on many large units. 

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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. 

3.2.3 Compact Hybrid Particulate Collector 

Another technology used for particulate control is a high A/C ratio fabric filter. 

Commonly referred to as a COHPAC, this technology was developed and trademarked 

by the EPRI. If activated carbon is injected upstream of a COHPAC filter, this 

configuration is referred to as TOXECON I and is also trademarked by the EPRI. The 

COHPAC filter typically operates at A/C ratios ranging from 6 to 8 feet per minute 

(ft/min) compared to a conventional fabric filter that typically operates at A/C ratios of 

approximately 4 ft/min. 

For a COHPAC or TOXECON I system, the majority of the particulate is 

collected in the upstream particulate control device. Therefore, the performance 

requirements of a high A/C ratio fabric filter is reduced, allowing installation of this 

technology in a smaller footprint area and with less steel and filtration media. This 

arrangement substantially lowers both capital and operating costs compared to 

conventional fabric filters. 

3.2.4 GE MAX-9 Hybrid 

The Max-9 electrostatic filter is essentially a high efficiency PJFF that combines 

fabric filter and ESP technologies. The Max-9 can be visualized as an ESP using fabric 

filter bags instead of collecting plates. A front and side elevation view of the Max-9 

particulate filter is illustrated on Figure 3-9. When the dust particles are charged, they 

are attracted to the grounded metal cage inside the filter element, just as they would be 

attracted to the collecting plates in an ordinary precipitator. Since the particles are 

charged positively, they repel each other on the surface of the filter, making the collected 

dust cake very porous. This results in a reduction of filter drag at a pressure drop 

approximately 25 percent 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. 

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Figure 3-9 

Max-9 Electrostatic Filter 

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Process gas enters the Max-9 from a hopper inlet duct. The gas then flows 

upward through the filters and out through the top of the filters. The area above the tube 

sheet is a clean gas plenum. Compressed air pulses are used to clean the filters. A brief, 

intense blast of air is fired through the purge air manifold; holes in the blowpipes located 

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

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

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

sparking, and the transformer/rectifier requires no voltage control. 

The Max-9 can be supplied as shop assembled modules that can be erected onsite, 

although the units are usually custom-engineered for each plant site and application to 

make the best use of available space. 

3.2.5 Multiple-Cyclone 

Multiple-cyclone separators, also known as multiclones, consist of a number of 

small diameter cyclones, operating in parallel and having a common gas inlet and outlet, 

as shown on Figure 3-10. Multiclones operate on the same principle as cyclones, creating 

a main downward vortex and an ascending inner vortex. Multiclones are more efficient 

than single cyclones because they are longer and smaller in diameter. The longer length 

provides longer residence time, while the smaller diameter creates greater centrifugal 

force. These two factors result in better separation of dust particulates. The pressure 

drop of multiclone collectors is higher than that of single-cyclone separators. 

Figure 3-10 

Multiclone Particulate Collector 

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Cyclone collectors are centrifugal collectors that rely on the particle density and 

velocity to separate the fly ash from the flue gas. The particulate-laden flue gas enters 

the top or the side of the cyclone. An illustration of the components and working 

principles of a multiclone is shown on Figure 3-11. Vanes impart a rotational velocity to 

the flue gas, driving the fly ash to the edge of the cylinder. The flue gas then exits the 

center of the cyclone out the top, leaving the fly ash to fall out the bottom. At pressures 

near one atmosphere and 2 to 5 inch water gauge (in. wg) pressure differential, this 

technology can effectively remove particles larger than 20 microns in size; particles less 

than 10 microns are usually unaffected and not removed.

Figure 3-11 

Electrostatic Particle Agglomeration System (Indigo) 

3.2.6 Wet ESP 

A wet ESP collects particles on the same theory as a dry ESP: negatively charged 

particles are collected on positively charged surfaces. A wet ESP operates differently 

from a dry ESP. The collecting surfaces are wet instead of dry and are flushed with water 

to remove the particulate. Typically, a wet ESP is installed downstream of an existing 

wet FGD system, where the flue gas is already saturated, so the amount of added water is 

minimized. The particulate collection efficiency is enhanced by preventing the particle 

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re-entrainment after contact with the wet walls (as contrasted with re-entrainment due to 

rapping on a dry ESP). Therefore, the wet ESP is well suited for fine particulate or acid 

mist applications by reducing opacity, sulfuric acid mist (H2SO4), and other aerosols. 

The use of wet ESPs for acid mist collection was one of the earliest applications 

for ESPs. Although there are few applications in the utility industry, this is a mature 

technology with hundreds of industrial installations. The particulate characteristics, 

temperature, and humidity in wet ESPs provide excellent fuel flexibility regarding 

particulate removal. Water chemistry, scaling, and corrosion potential need to be 

carefully investigated. 

The wet ESP collecting fields impart a negative charge to the particles and collect 

them on positively charged collecting electrodes. Each collection field is equipped with 

independent electrical bus sections, each having a dedicated high voltage 

transformer/rectifier and controller. The controllers for each transformer/rectifier are 

located in an environmentally controlled enclosure. Each electrical field has a separate 

discharge electrode support frame suspended by alumina insulators. A heater-blower 

system dedicated to each module supplies warm purge air for each of the insulator 

compartments. The discharge electrode support frames are constructed from Type 304 

stainless steel. The discharge electrodes are suspended from the upper guide frame and 

held in the tube center line. The discharge electrode is a rigid electrode constructed from 

304 stainless steel; it contains split corona generating elements, which are welded to the 

electrode in an opposed orientation. 

A wet ESP can be installed in either horizontal or vertical gas flow orientation. In 

a horizontal gas flow orientation, the wet ESP is very similar to a common dry ESP. The 

collection plates are arranged in parallel horizontal paths with discharge electrodes 

hanging between them. Vertical gas flow wet ESPs are usually of the tubular collection 

plate type. The collection plates are arranged in an array of vertical pipes or channels 

with a discharge electrode hanging down the center of the pipe or channel. Channel 

shapes such as squares or hexagons have more efficient packing densities than circular 

pipes (with a small loss in the maximum voltage that can be applied before sparking) and 

are the more common. Where multiple electrical stages are used (analogous to the 

electrical fields in a horizontal gas flow ESP), the stages are stacked one above the other. 

Two to three fields are common. 

Several major hurdles exist with the use of a wet ESP. First, the flue gas must be 

saturated with moisture prior to entering the ESP to allow the wet ESP to work correctly. 

This requires that a quenching system be installed to add water to the flue gas to reduce 

the flue gas temperature to the saturation point, or the wet ESP needs to be installed 

downstream of an existing wet FGD system. Without the presence of a wet FGD system, 

120407 3-25 
Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

the wet ESP adds additional cost, increases water demand on the plant, and generates a 

visible moisture plume at the stack outlet. The removed particulate would also be 

contained in a wastewater stream that is generated by the wet ESP. In addition to this 

issue, the capital cost of a wet ESP is increased because of the higher cost of the alloy 

materials required. A higher grade of material is required to withstand the highly 

corrosive conditions presented by the wet and acidic flue gas stream. 

Each wet ESP module is cleaned by spraying flush water over the wet ESP 

components. Flush water is sprayed in the wet ESP at different spray levels. Normally, 

each wet ESP module is flushed once per day. Individual electrical sections of each field 

may be flushed online while the power is turned off to the electrical section being 

cleaned. 

The wet ESP system may require continuous injection of dispersant into the 

system to help eliminate scale formation within the module. The dispersant can be stored 

in a small tank and fed into the flush water surge tank, allowing dispersant to enter the 

modules through the spray levels. 

 Additionally, the wet ESP may periodically require out-of-service cleaning of a 

more intense nature. Physical cleaning using high-pressure water jets (“hydro lasers”) or 

chemical flushing using an acid-based solvent to dissolve the scale buildup are two 

options. 

An alternate wet ESP technology reduces the challenges of cleaning the collecting 

plates by continuously washing a membrane surface that acts as the collecting plate. The 

continuous washing prevents the ash from drying out and hardening on the surface, while 

the membrane surface reduces channeling of the washing water and provides a more 

complete coverage of the collecting surface. The other advantage of the membranes is 

they are typically constructed from polypropylene or PolyPhenylene Sulfide (PPS), 

which is resistant to corrosion and typically less expensive than high grade alloys of steel. 

3.2.7 Particle Agglomeration Upstream of Dry ESP 

Electrostatic agglomeration upstream of dry ESP is performed in the high velocity 

ductwork leading to the ESP. An electrostatic charge pretreats the particle laden flue gas 

prior to the ESP causing the finer particles to “agglomerate,” thus increasing the size of 

the particle to be captured. The electrostatic agglomeration technology is effective in 

increasing the dry ESP removal efficiency for finer particles (PM2.5) at a significantly 

lower capital cost than a new ESP or fabric filter. 

120407 3-26 
Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

ESP removal efficiency is severely reduced when the particle size is smaller than 

3 microns. By agglomerating the particles into larger sizes and reducing the number of 

particles to be collected by the ESP, there will be a reduction in the overall PM 

emissions, reduced opacity emissions, higher flue gas flow rate, and a reduced pressure 

drop across the ESP. 

The agglomeration of the particles occurs through two processes. A bipolar 

charger charges half of the dust with a positive charge and half with a negative charge. 

As a result, the oppositely charged particles will be attracted to each other and combine in 

a larger sized particle. The agglomerator device will consist of alternating positive and 

negative parallel passages through which the flue gas with particulate flows. The 

attraction mechanism between the positively and negatively charged particles is enhanced 

by fluidic methods that are specially designed, usually using computational CFD tools, to 

improve the mixing system of the particles in the flue gas stream. A diagram showing the 

working mechanism of the electrostatic agglomerator is illustrated on Figure 3-11. 

 The power consumption of the agglomeration device is typically low at 

2 kilowatts (kW) per 100,000 acfm, with an expected pressure drop of less than 1 inch of 

water. Retrofit and outage issues for this technology are also minimized because this is a 

compact device that is installed in a straight ductwork ahead of dry ESP. There is no 

current industry experience with the agglomerator upstream of a venturi scrubber. 

3.3 Emerging Pollution Control Technologies 

Research is ongoing to develop new and improved technologies for multipollutant 

control. The investigation focuses on adding new sorbents to more effectively adsorb 

mercury and on using new technologies to oxidize and remove mercury. Electrically 

induced oxidation of mercury is a new technology that is also being investigated. The list 

of emerging technologies is numerous; the most promising technologies include the 

PowerSpan ECO, EnviroScrub, and Phenix systems. Several other promising emerging 

technologies, such as the Airborne and BOC LoTOx systems, are in the early stages of 

development, but are not as far along in pilot testing as the others. Since many of these 

technologies are still at the pilot (slipstream) stage of development, they should be 

viewed with caution until more is known and performance guarantees become available. 

Generally, these technologies do not meet the applicability criteria set forth in the BART 

analysis guidelines. 

120407 3-27 
Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

3.3.1 PowerSpan 

 There are several emerging multipollutant technologies that use high electron 

beams or other proprietary processes. One of the most promising technologies that has 

only limited experience and has not been fully tested on full-scale systems is the 

PowerSpan ECO system. The ECO system is located downstream of an existing 

particulate control device, and the process consists of three stages. In the first stage, the 

flue gas passes through a barrier discharge reactor where it is exposed to a high voltage 

discharge, generating high energy electrons. The electrons initiate a chemical reaction 

forming oxygen and hydroxyl radicals, which then oxidize NOx, SO2, and mercury. A 

process flow diagram of the ECO system is illustrated on Figure 3-12. This reaction 

results in the formation of nitric acid, 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 mercury in the downstream wet 

ESP. Scrubber effluents contain dissolved ammonium sulfate nitrate (ASN) salts, along 

with solids and mercury. The ASN solution is sent to a recovery process where the 

mercury is removed via a sulfur impregnated, activated carbon structure. After the 

carbon activated bed becomes saturated with mercury, it is disposed as a hazardous 

waste. The cleaned stream of ASN is converted to a saleable fertilizer. 

Figure 3-12 

ECO Process Flow Diagram 

120407 3-28 
Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

 PowerSpan also offers a mercury-only control technology that uses a 

photochemical oxidation (PCO) process. In this process, mercury is oxidized via an 

ultraviolet (UV) light. The UV lights are placed in the ductwork upstream of particulate 

control device. The PCO technology is in its infancy; because PowerSpan’s PCO process 

has not moved beyond bench-scale testing and has not been pilot tested at a facility 

burning a low sulfur coal, the technology will not be evaluated further. 

3.3.2 EnviroScrub 

EnviroScrub is a multipollution control technology that is capable of removing 

significant amounts of elemental and oxidized mercury, NOx, PM2.5, and SO2. This 

technology is based on the Pahlman process. A sorbent made up of oxides of manganese 

called Pahlmanite sorbent (PS) is injected upstream of the spray dryer absorber (SDA), 

where the flue gas mixes with the PS. This is where the oxidation and adsorption of 

mercury takes place. Other pollutants such as SO2 and NOx are also adsorbed by the PS 

at this stage. Then, the SDA byproducts are separated from the flue gas in the PJFF. 

The fly ash and waste byproduct collected in the PJFF hopper are eventually transported 

to a slurry tank for subsequent PS regeneration in a reactor. A process flow diagram of 

the Pahlman process is illustrated on Figure 3-13. 

Figure 3-13 

Pahlman Process Simplified Process Flow Diagram 

120407 3-29 
Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

The configuration for this technology is as follows: particulate removal (existing 

ESP), SDA, PJFF, sorbent regeneration, and byproduct separation. Although significant 

progress has been made on the sorbent regeneration part of its technology, EnviroScrub is 

not considered a proven, viable technology. Since EnviroScrub’s process has not moved 

beyond pilot scale testing, the technology will not be evaluated further. 

3.3.3 Phenix Clean Coal 

The Clean Combustion System (CCS) is an advanced hybrid coal gasification/ 

combustion process that prevents the formation of NOx and SO2 emissions when coal is 

burned. The only reagent required for pollution control is limestone. Almost all coal 

fired cyclone, wall fired, and tangential power boilers can be retrofitted for full 

compliance with the US NOx and SO2 emission regulations. 

The CCS concept is that of an entrained-flow coal gasifier followed by stages of 

combustion air. The CCS burner is uniquely designed to provide the necessary time, 

temperature, and stoichiometry required for all the chemicals in coal to complete their 

combustion reactions (to reach equilibrium conditions). 

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

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

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

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

temperatures and with limited available oxygen, the carbon aggressively commands 

oxygen to form CO from all sources, including such compounds as water (H2O). 

Nitrogen compounds that may form, such as NOx, HCNs, and NH4, are forced to the 

molecular form (N2) by the aggressive action of carbon for oxygen. In the presence of 

calcium, the sulfur reacts to form calcium sulfide (CaS, a solid “nongaseous” particle). 

The hydrogen (H2) cannot compete with the other elements and remains H2. 

The high combustion temperatures melt together the coal ash (largely silica and 

alumna) and CaS solids to form an inert slag that drains from the bottom of the boiler. 

The very hot gases, high in CO and H2, and nearly free of NOx and sulfur, then exit into 

the boiler furnace. As the gases cool and generate steam, additional OFA is added in 

stages to the furnace to complete the combustion of CO to CO2 and H2 to water. These 

steps prevent the formation of any new (thermal) NOx and complete the combustion with 

excess air. The clean hot gases then enter the boiler superheat section, which is as it was 

before the retrofit. A schematic of the process is shown on Figure 3-14. 

120407 3-30 
Arizona Public Service Identification of All Available Retrofit 

Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

Figure 3-14 

Phenix Clean Coal Process Flow Diagram 

The CCS retrofit modification requires replacing the existing PC coal burners 

with new down fired CCS burners, adding separated OFA to the boiler furnace, and 

powdered limestone to the coal fuel. This is a complex retrofit that involves the 

modification of the boiler pressure parts. Most of the new, off-the-shelf equipment fits 

within the existing boiler space. 

 A CCS repowered boiler will show improved efficiency from more complete coal 

combustion (LOI <1.0 percent), very low NOx (<0.15 lb/mmBtu), and control of SO2

emissions (< 0.5 lb/mmBtu) with either western or midwest coals. Since the CCS 

process has not moved beyond the demonstration stage, the technology will not be 

evaluated further. 

120407 3-31 
Arizona Public Service Technically Feasible Retrofit Emission 

Four Corners Units 1 through 5 Control Technologies (Step 2) 

4.0 Technically Feasible Retrofit Emission Control 

Technologies (Step 2) 

 As stated in Subsection 1.2.2, applicable emission control technologies are 

identified by eliminating technically infeasible options from the available technologies. 

A majority of the technologies outlined in Sections 3.1 and 3.2 were considered available 

technologies at the issue of this report. The available technologies were then screened to 

determine if the technologies are applicable for the BART-eligible plant. The BART 

procedure defines a technology as applicable when it has been used on the same or 

similar source type. Some of the issues that determine the applicability of a technology 

are as follows: 

• Size of the unit. 

• Location of the proposed site. 

• Operating problems after retrofit of technology. 

• Space constraints. 

• Reliability. 

• Adverse effects on the rest of the facility. 

Using the guidelines above, each technology identified as available in Section 3.0 

has been evaluated to determine its technical feasibility at the Four Corners site. The 

relatively large size of the Four Corners Units 4 and 5 reduces the number of applicable 

technologies. 

4.1 NOx Control Technologies 

 A summary showing the results of the evaluation process for the NOx

technologies is detailed in Table 4-1. Table 4-1 also includes the reasons why the 

eliminated control technologies were considered technically infeasible. 

4.2 PM Control Technologies 

 A summary of the results of the evaluation process for the PM technologies 

considered for Units 1, 2, and 3 is detailed in Table 4-2. Units 4 and 5 are addressed 

separately in Subsection 4.2.1, because these units have fabric filters installed for PM 

control. Table 4-2 also includes the reasons why the eliminated control technologies 

were considered technically infeasible. 

120407 4-1 
Arizona Public Service Technically Feas

Four Corners Units 1 through 5 Control 

Table 4-1 

Technical Feasibility of NOx Control Technology 

Technology 

Technically Feasible and Applicable? Reasons for Technical Infeasibility 

Upgraded Boiler Optimization System (Neural Network) 

Yes -- 

LNBs Yes -- OFA Yes -- Mobotec ROFA and ROTAMIX Units 1, 2 

and 3 only. 

ROTAMIX has not been demonstrated on units as Units 4 and 5. 

NOxStar and NOxStar Plus No The technology is not being marketed currently. ECOTUBE No There is no existing installation at similar type/size IFGR No This technology is not applicable for coal fired plaSCR Yes -- SNCR Yes -- SCR/SNCR Hybrid (Cascade System) No There is not available room for the ductwork expan

outlet required for the single layer of Catalyst for UCascade has not been demonstrated on units as largUnits 4 and 5. 

LoTOx No This technology does not have any operational uni

Four Corners. 

Natural Gas Reburn (includes FLGR, AE-FLGR) No Not currently in use at similar type/size source. Up 

produced with natural gas can render this technoloCost-effectiveness is very difficult to predict becaunatural gas prices. 

THERMALONOx Process No Not currently in use at similar type/size source. Te

for this application. No guarantee likely. 

Oxygen Enhanced Combustion No Not currently in use at similar type/size source. Te

for this application. High cost of oxygen separatio

Biotechnological Denitrification (BioDeNOx) No Not currently in use at similar type/size source. Te

for this application. No guarantee likely. 

120407 
Arizona Public Service Technically Feas

Four Corners Units 1 through 5 Control 120407 

Table 4-2 

Technical Feasibility of PM Control Technology for Units 1, 2, and 3 

Technology 

Technically Feasible and Applicable? Reasons for technical infeasibility 

ESP Yes -- PJFF Yes -- COHPAC No COHPAC system is ineffective because of bag blin

fine particulate from the venturi scrubber. 

GE MAX-9 Hybrid No Max-9 Hybrid Electrostatic has full scale demonstr

of these applications are on units of equivalent size APS Four Corners. 

Multicyclone No Venturi scrubbers and multicyclones are not effect

particulate. The addition of a multicyclone is not eadditional PM reduction with the existing venturi s

Particle Agglomeration No Particle agglomeration has no performance data up

scrubber, but has been successful technology upstr

Wet ESP Yes -- 
Arizona Public Service Technically Feasible Retrofit Emission 

Four Corners Units 1 through 5 Control Technologies (Step 2) 

4.2.1 Units 4 and 5 PM BART Analysis 

 As part of the PM BART engineering analysis, the performance of the Units 4 

and 5 fabric filters were studied to verify that the PM emissions rate is reasonably 

consistent with current generation fabric filters. Page 39165 of 40 CFR Part 51, which 

outlines the regulations and guidelines for the BART analysis, states the following in 

regards to existing BACT controls at BART-eligible units. “If you find that a BART 

source has controls already in place which are the most stringent controls available (note 

that this means that all possible improvements to any control devices have been made), 

then it is not necessary to comprehensively complete each following steps of the BART 

analysis in this section. As long as these most stringent controls available are made 

federally enforceable for the purpose of implementing BART for that source, you may 

skip the remaining analyses in this section, including the visibility analysis in Step 5.” 

B&V believes that the fabric filters installed on Units 4 and 5 represent the most stringent 

controls available. The only potential improvement to the Units 4 and 5 fabric filters 

would be the replacement of the existing bags with membrane material bags. However, 

this improvement would mainly affect operations, and the reduction in emissions is not 

quantifiable. The Units 4 and 5 fabric filters at the Four Corners Generating Station are 

equipped with “bad bag detectors” that notify the plant when a bag has torn. The 

compartment is then isolated and the broken bag found and replaced. After review of the 

operation and study of the emissions limits from the Units 4 and 5 fabric filters, B&V 

concluded that the fabric filters are operating in accordance with industry standards for 

fabric filters and should therefore be considered BART. 

120407 4-4 
Arizona Public Service Evaluation of Technically Feasible Retrofit 

Four Corners Units 1 through 5 Emission Control Techniques (Step 3) 

5.0 Evaluation of Technically Feasible Retrofit Emission 

Control Technologies (Step 3) 

Step 3 of the BART determination process is an evaluation of the control 

effectiveness for each of the technically feasible control technologies. The control 

effectiveness is a common metric used to ensure a fair “apples to apples” comparison; it 

is expressed as the amount of pollutant generated per unit of heat input. The control 

effectiveness is then used, along with the capacity factor, to determine the hourly and 

yearly emissions rate based on the total heat input to the source. The emissions rates 

listed for each of the control technologies are what can be achieved on a long term annual 

average basis, including the partial load and upset operating conditions that are 

experienced in a normal operating facility. 

In this section, Table 5-1 indicates the control effectiveness for each group of 

control technologies. The control effectiveness for each technology is also summarized 

in the stack emissions tables included as Appendix E. 

5.1 NOx Control Technologies 

 The expected NOx emissions rate, projected annual emissions, and emission 

reduction are summarized in Tables 5-1 and 5-2 for each of the NOx removal 

technologies designated as feasible in Step 2. Because of the difference in size between 

Units 1, 2, and 3 and Units 4 and 5, the analysis has been broken into two sections. 

Table 5-1 shows the NOx summary information for Units 1, 2, and 3, while Table 5-2 

presents the same analysis for Units 4 and 5. 

5.2 PM Control Technologies 

The expected PM emissions rate, projected annual emissions, and emission 

reduction are summarized in Table 5-3 for each of the particulate removal technologies 

designated as feasible in Step 2. The PM values presented in Table 5-3 represent 

filterable PM/PM10. 

120407 5-1 
Arizona Public Service Evaluation of Technically Feasible Retrofit 

Four Corners Units 1 through 5 Emission Control Techniques (Step 3) 

Table 5-1 

Control Effectiveness for NOx Reduction Technologies--Units 1, 2, and 3 

(lb/mmBtu) (ton/yr) (ton/yr) 

Emitted Emitted Removed 

Unit 1 (Baseline 0.78 lb/mmBtu)

Combustion Optimization System (COS) 0.72 5,247 456 

SNCR 0.56 4,081 1,622 

Mobotec ROTAMIX 0.56 4,081 1,622 

New LNBs 0.43 3,133 2,569 

New LNB, OFA 0.33 2,405 3,298 

New LNBs and SNCR 0.32 2,332 3,371 

New LNBs and ROTAMIX 0.30 2,186 3,517 

Mobotec ROFA 0.28 2,040 3,662 

New LNBs, OFA and SNCR 0.26 1,895 3,808 

New LNBs, OFA and High Energy Reagent 

Technology (HERT) 0.20 1,457 4,245 

Mobotec ROFA and ROTAMIX 0.19 1,385 4,318 

SCR 0.08 568 5,135 

New LNBs and SCR 0.06 437 5,266 

New LNBs, OFA, and SCR 0.06 437 5,266 

Unit 2 (Baseline 0.64 lb/mmBtu) 

COS 0.60 4,486 302 

SNCR 0.46 3,440 1,349 

Mobotec ROTAMIX 0.45 3,365 1,424 

New LNB 0.43 3,215 1,573 

New LNB, OFA 0.33 2,467 2,321 

New LNBs and SNCR 0.32 2,393 2,396 

New LNBs and ROTAMIX 0.30 2,243 2,545 

Mobotec ROFA 0.28 2,094 2,695 

New LNBs, OFA, and SNCR 0.26 1,944 2,844 

New LNBs, OFA, and HERT 0.20 1,495 3,293 

Mobotec ROFA and ROTAMIX 0.19 1,421 3,368 

SCR 0.06 479 4,310 

New LNBs and SCR 0.06 449 4,340 

New LNBs, OFA, and SCR 0.06 449 4,340 

120407 5-2 
Arizona Public Service Evaluation of Technically Feasible Retrofit 

Four Corners Units 1 through 5 Emission Control Techniques (Step 3) 

Table 5-1 (Continued) 

Control Effectiveness for NOx Reduction Technologies--Units 1, 2, and 3 

(lb/mmBtu) (ton/yr) (ton/yr) 

Emitted Emitted Removed 

Unit 3 (Baseline 0.59 lb/mmBtu)

COS 0.56 5,375 257 

SNCR 0.46 4,415 1,217 

Mobotec ROTAMIX 0.45 4,319 1,313 

New LNB 0.43 4,128 1,505 

New LNB, OFA 0.33 3,168 2,465 

New LNBs and SNCR 0.32 3,072 2,561 

New LNBs and ROTAMIX 0.30 2,880 2,753 

Mobotec ROFA 0.28 2,688 2,945 

New LNBs, OFA, and SNCR 0.26 2,496 3,137 

New LNBs, OFA, and HERT 0.20 1,920 3,713 

Mobotec ROFA and ROTAMIX 0.19 1,824 3,809 

SCR 0.06 576 5,057 

New LNBs and SCR 0.06 576 5,057 

New LNBs, OFA, and SCR 0.06 576 5,057 

120407 5-3 
Arizona Public Service Evaluation of Technically Feasible Retrofit 

Four Corners Units 1 through 5 Emission Control Techniques (Step 3) 

120407 5-4 

Table 5-2 

Control Effectiveness for NOx Reduction Technologies--Units 4 and 5 

(lb/mmBtu) (ton/yr) (ton/yr) 

Emitted Emitted Removed 

Units 4 and 5 (Baseline 0.49 lb/mmBtu) - Values are per Unit

COS 0.47 12,395 633 

SNCR 0.38 9,889 3,138 

New LNB 0.45 11,867 1,160 

New LNB, OFA 0.35 9,230 3,798 

New LNBs and SNCR 0.32 8,439 4,589 

New LNBs, OFA, and SNCR 0.26 6,857 6,171 

SCR 0.06 1,582 11,445 

New LNBs and SCR 0.06 1,582 11,445 

New LNBs, OFA, and SCR 0.06 1,582 11,445 

Table 5-3 

Control Effectiveness for PM Reduction Technologies 

(lb/mmBtu) (ton/yr) (ton/yr) 

Emitted Emitted Removed 

Unit 1 (Baseline 0.025 lb/mmBtu)

ESPs Upstream of Current AQC Equipment 0.012 87 94 

PJFF Upstream of Current AQC Equipment 0.012 87 94 

Wet ESP 1 (Metal) Replacement 0.012 87 94 

Wet ESP 2 (Membrane) 0.012 87 94 

Unit 2 (Baseline 0.029 lb/mmBtu)

ESPs Upstream of Current AQC Equipment 0.012 90 129 

PJFF Upstream of Current AQC Equipment 0.012 90 129 

Wet ESP 1 (Metal) Replacement 0.012 90 129 

Wet ESP 2 (Membrane) Replacement 0.012 90 129 

Unit 3 (Baseline 0.029 lb/mmBtu)

ESPs Upstream of Current AQC Equipment 0.012 117 168 

PJFF Upstream of Current AQC Equipment 0.012 117 168 

Wet ESP 1 (Metal) Replacement 0.012 117 168 

Wet ESP 2 (Membrane) Replacement 0.012 117 168 
Arizona Public Service Cost-Effectiveness and 

Four Corners Units 1 through 5 Impact Analysis (Step 4) 

6.0 Cost-Effectiveness and Impact Analysis (Step 4) 

6.1 Types of Impact Analysis 

For all of the technologies considered technically feasible, an impact analysis was 

performed as part of the BART determination process. The purpose of this task 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 costeffectiveness is described in Subsection 1.2.4 of this report. The four types of impact 

analysis performed include the following: 

• Costs of compliance. 

• Energy impacts. 

• Non-air quality environmental impacts. 

• Remaining useful life. 

6.2 Methods of Impact Analysis 

The first step in performing the impact analysis was to define the design 

parameters for each control technology that was identified as technically feasible. The 

design parameter contains all pertinent information on the control technology system for 

specific application to the source. Examples of these design parameters include the 

following: the type of reagent used and consumption rate, type of byproduct produced 

and production rate, flue gas pressure drop across the control technology, furnace type 

and firing pattern, excess O2, burner zone heat release, etc. The information used to 

define the design parameters can be from several of the following sources: 

• Equipment vendors. 

• Background information documents used to support New Source 

Performance Standards (NSPS) development. 

• Control technique guidelines documents. 

• EPA cost manuals. 

• Trade publications. 

• Engineering and performance test data. 

The design parameters for each control technology that has been identified as 

technically feasible for application on Units 1 through 5 were summarized with other 

information in the Design Concept Definitions tables in Appendix C. 

120407 6-1 
Arizona Public Service Cost-Effectiveness and 

Four Corners Units 1 through 5 Impact Analysis (Step 4) 

To obtain an estimate of the costs of compliance, the total capital investment 

(TCI) for each control technology when applied specifically to Units 1 through 5 was 

calculated. The bases for this cost calculation were the following: 

• CUECost Workbook, Version 1.0. 

• EPA Air Pollution Control Cost Manual, Sixth Edition. 

• Budgetary quotes from equipment vendors. 

• References to quotes or cost estimations for previous design/build projects 

or in-house estimates. 

Energy impacts were estimated for each control technology that consumes 

significant amounts of auxiliary energy during its operation. Only direct energy impacts 

were considered, i.e., the auxiliary power consumption of the control technology and the 

additional draft system power consumption to overcome the additional system resistance 

of the control technology in the flue gas flow path. 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. The 

installation of major pollution control equipment, the SCRs in particular, may require 

longer tie-in outages than currently scheduled for plant maintenance. The lost generation 

due to the additional outage time, beyond the typical outage requirements, has been 

considered as an energy impact during the cost-effective analysis. 

The major non-air quality impacts evaluated were the disposal requirements for 

the byproduct and waste generated by each control technology and the lost generation 

due to extended outages. Since the Four Corners site has not been identified as a zero 

water pollutant discharge site, water was not considered as a non-air quality impact. The 

quantity of byproduct or waste generated by each control technology was calculated on a 

yearly basis. The cost of purchasing replacement power was considered only for the 

additional time that the units must remain off-line, in addition to the planned outage, to 

incorporate the pollution control technologies. 

The impact of the remaining useful life of the control technology on its costeffectiveness was considered. For this BART analysis, the remaining useful life of 

Units 1 through 5 was at least 20 years. Based on this determination, there are no costeffectiveness impacts, because the remaining useful life of the unit is longer than the 

economic study period of all the control technologies. 

120407 6-2 
Arizona Public Service Cost-Effectiveness and 

Four Corners Units 1 through 5 Impact Analysis (Step 4) 

6.3 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 described as 

the cost of control per amount of pollutant removed. The cost of control takes into 

account the impact analyses performed. The annual reduction in emissions was 

estimated, from baseline emissions, for each of the pollution control technologies. With 

guidance from APS (refer to Appendix F), it was determined that the emissions reduction 

should be calculated as follows: 

Baseline Emissions

Existing Emission Rate

Existing Emission Rate Proposed Outlet Emission Rate Emission Reduction × − =

The baseline emissions for Units 1 through 5 are shown in Table 6-1. Both the 

baseline emissions and the controlled emission values are documented in the Design 

Concept Definition tables located in Appendix C. It should be noted that the baseline 

emissions shown in Table 6-1 for Units 4 and 5 are per unit. 

Table 6-1 

Baseline Emissions 

Unit 1, 

(tons/yr) 

Unit 2, 

(tons/yr) 

Unit 3, 

(tons/yr) 

Units 4 and 5, 

(tons/yr) 

NOx 5,703 4,788 5,633 13,028 

PM (filterable) 180 220 285 313 

6.3.1 NOx Control Technologies 

 The cost-effectiveness summary for each of the NOx control technologies for 

Units 1 through 5 are shown in Tables 6-2, 6-3, 6-4, and 6-5. Graphical representations 

are presented on Figures 6-1, 6-2, 6-3, and 6-4. 

6.3.2 PM Control Technologies 

 All PM removal technologies considered in the BART analysis are capable of 

reducing the particulate emissions to BACT control levels. Since each technology 

considered had the same emissions rate, the incremental cost-effectiveness is undefined 

for the PM removal technologies. The cost-effectiveness summary for Units 1 through 5 

PM is shown in Tables 6-6 through 6-8. Graphical representations are presented on 

Figures 6-5 to 6-8. Units 4 and 5 are not included in these tables, because the fabric 

filters on the units have been deemed as BART, as explained in Subsection 4.2.1. Two 

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Four Corners Units 1 through 5 Impact Analysis (Step 4) 

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PM cost-effectiveness summary figures have been presented, one showing the total PM 

reduction at Four Corners Units 1, 2, and 3, and one focusing on the incremental 

reduction from the addition of retrofit PM reduction technologies. Each figure is based 

on the same cost-effectiveness data; only the x-axis of the figure has been adjusted to 

show the overall PM reduction picture in one case and the detailed additional reduction in 

the other. Figures 6-5, 6-7, and 6-9 show the overall PM removal, while Figures 6-6, 6-8, 

and 6-10 show the additional PM removal. 
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Four Corners Units 1 through 5 Im

Table 6-2 

Unit 1 - NOx Cost-Effectiveness Summary 

All Feasible Technologies 

Emission 

Performance 

Level 

(lb/mmBtu) 

Expected 

Emissions 

Rate (lb/h) 

Expected 

Emissions 

Reductions 

(tons/yr) 

Capital Costs 

(x $1,000) 

Total 

Annualized 

Cost 

(x $1,000) 

E

Unit 1 NOx (resultant emissions based on current 0.78 lb/mmBtu)COS 0.72 1,341 456 1,429 314 SNCR 0.56 1,043 1,622 5,572 3,123 Mobotec ROTAMIX 0.56 1,043 1,622 7,282 4,277 New LNBs 0.43 801 2,569 3,823 857 New LNB, OFA 0.33 615 3,298 5,354 1,204 New LNBs and SNCR 0.32 596 3,371 8,946 2,777 New LNBs, OFA, and ROTAMIX 0.30 559 3,517 11,105 3,508 Mobotec ROFA 0.28 522 3,662 9,657 2,956 New LNBs, OFA, and SNCR 0.26 484 3,808 10,337 2,746 New LNBs, OFA, and HERT 0.20 373 4,245 10,038 2,679 Mobotec ROFA and ROTAMIX 0.19 354 4,318 13,672 4,223 SCR 0.08 145 5,134 88,235 18,056 New LNBs, and SCR 0.06 112 5,266 89,595 17,800 New LNBs, OFA, and SCR 0.06 112 5,266 90,193 17,750 (1)Incremental cost undefined. (2)Incremental cost compared to COS. (3)Incremental cost compared to LNB. (4)Incremental cost compared to LNB/OFA. (5)Incremental cost compared to LNB and OFA+HERT. (6)Incremental cost compared to Mobotec ROFA/ROTAMIX. 

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Figure 6-1 

Unit 1 - NOx Cost-Effectiveness 

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Table 6-3 

Unit 2 - NOx Cost-Effectiveness Summary 

All Feasible Technologies 

Emission 

Performance 

Level 

(lb/mmBtu) 

Expected 

Emissions 

Rate (lb/h) 

Expected 

Emissions 

Reductions 

(tons/yr) 

Capital Costs 

(x $1,000) 

Total 

Annualized 

Cost 

(x $1,000) 

E

Unit 2 NOx (resultant emissions based on current 0.64 lb/mmBtu)COS 0.60 1,118 302 1,429 314 SNCR 0.46 857 1,349 5,397 2,737 Mobotec ROTAMIX 0.45 838 1,424 7,282 4,277 New LNBs 0.43 801 1,573 3,823 857 New LNB, OFA 0.33 615 2,321 5,355 1,204 New LNBs, OFA, and SNCR 0.32 596 2,396 8,946 2,777 New LNBs, OFA, and ROTAMIX 0.30 559 2,545 11,105 3,508 Mobotec ROFA 0.28 522 2,695 9,657 2,956 New LNBs, OFA, and SNCR 0.26 484 2,844 10,338 2,746 New LNBs, OFA, and HERT 0.20 373 3,293 10,039 2,679 Mobotec ROFA and ROTAMIX 0.19 354 3,368 13,532 4,191 SCR 0.06 119 4,310 94,216 18,966 New LNBs and SCR 0.06 112 4,340 96,450 19,034 New LNBs, OFA, and SCR 0.06 112 4,340 97,045 18,983 (1)Incremental cost undefined. (2)Incremental cost compared to COS. (3)Incremental cost compared to LNB. (4)Incremental cost compared to LNB/OFA. (5)Incremental cost compared to LNB and OFA+HERT. (6)Incremental cost compared to Mobotec ROFA/ROTAMIX. 

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Figure 6-2 

Unit 2 - NOx Cost-Effectiveness 

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Table 6-4 

Unit 3 - NOx Cost-Effectiveness Summary 

All Feasible Technologies 

Emission 

Performance 

Level 

(lb/mmBtu) 

Expected 

Emissions 

Rate (lb/h) 

Expected 

Emissions 

Reductions 

(tons/yr) 

Capital Costs 

(x $1,000) 

Total 

Annualized 

Cost 

(x $1,000) 

E

Unit 3 NOx (resultant emissions based on current 0.59 lb/mmBtu)COS 0.56 1,344 257 1,429 314 SNCR 0.46 1,104 1,217 5,762 3,102 Mobotec ROTAMIX 0.45 1,080 1,313 7,436 4,311 New LNBs 0.43 1,032 1,505 3,777 847 New LNB, OFA 0.33 792 2,465 4,359 979 New LNBs, OFA, and SNCR 0.32 768 2,561 9,285 3,157 New LNBs, OFA, and ROTAMIX 0.30 720 2,753 11,215 3,536 Mobotec ROFA 0.28 672 2,945 10,705 3,406 New LNBs, OFA, and SNCR 0.26 624 3,137 9,700 2,899 New LNBs, OFA, and HERT 0.20 480 3,713 9340 2,818 Mobotec ROFA and ROTAMIX 0.19 456 3,809 13,689 4,858 SCR 0.06 144 5,057 96,690 19,957 New LNBs and SCR 0.06 144 5,057 99,066 20,059 New LNBs, OFA, and SCR 0.06 144 5,057 98,582 19,795 

(1)Incremental cost undefined. (2)Incremental cost compared to COS. (3)Incremental cost compared to LNB. (4)Incremental cost compared to LNB/OFA. (5)Incremental cost compared to LNB and OFA+HERT. (6)Incremental cost compared to Mobotec ROFA/ROTAMIX. 

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Figure 6-3 

Unit 3 - NOx Cost-Effectiveness 

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Table 6-5 

Units 4 and 5 - NOx Cost-Effectiveness Summary - Values are per Unit 

All Feasible Technologies 

Emission 

Performance 

Level 

(lb/mmBtu) 

Expected 

Emissions 

Rate (lb/h) 

Expected 

Emissions 

Reductions 

(tons/yr) 

Capital Costs 

(x $1,000) 

Total 

Annualized 

Cost 

(x $1,000) 

E

Units 4 and 5 NOx (resultant emissions based on current 0.49 lb/mmBtu)COS 0.47 3,669 633 1,557 348 SNCR 0.38 2,927 3,138 11,060 7,331 New LNBs 0.45 3,513 1,160 8,076 1,820 New LNB, OFA 0.35 2,732 3,798 13,320 3,008 New LNBs and SNCR 0.32 2,498 4,589 18,937 8,143 New LNBs, OFA, and SNCR 0.26 2,030 6,171 23,116 7,754 SCR 0.06 468 11,445 242,090 51,487 New LNBs and SCR 0.06 468 11,445 249,857 52,500 New LNBs, OFA, and SCR 0.06 468 11,445 254,313 52,682 (1)Incremental cost undefined. (2)Incremental cost compared to COS. (3)Incremental cost compared to LNB. (4)Incremental cost compared to LNB/OFA. (5)Incremental cost compared to LNB and OFA+SNCR. 

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Figure 6-4 

Units 4 and 5 - NOx Cost-Effectiveness 

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Table 6-6 

Unit 1 - PM Cost-Effectiveness Summary 

All Feasible Technologies 

Emissions 

Performance 

Level 

(lb/mmBtu) 

Expected 

Emissions 

Rate (lb/h) 

Expected 

Emissions 

Reductions 

(tons/yr) 

Capital Costs 

(x $1,000) 

Total 

Annualized 

Cost 

(x $1,000) 

PM (resultant emissions based on current 0.025 lb/mmBtu) ESP Upstream of Current AQC Equipment 

0.012 22 94 37,236 10,169 

PJFF Upstream of Current AQC Equipment 

0.012 22 94 50,515 13,950 

Wet ESP 1 (Metal) Downstream of Venturi Scrubber 

0.012 22 94 32,136 8,781 

Wet ESP 2 (Membrane) Downstream of Venturi Scrubber 

0.012 22 94 23,360 5,652 

Note: Incremental cost-effectiveness is not defined. 

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Figure 6-5 

Unit 1 - Overall View of PM Cost-Effectiveness 

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Figure 6-6 

Unit 1 - Incremental View of PM Cost-Effectiveness 

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Table 6-7 

Unit 2 - PM Cost-Effectiveness Summary 

All Feasible Technologies 

Emission 

Performance 

Level 

(lb/mmBtu) 

Expected 

Emissions 

Rate (lb/h) 

Expected 

Emissions 

Reductions 

(tons/yr) 

Capital Costs 

(x $1,000) 

To

Annu

C

(x $1

PM (resultant emissions based on current 0.029 lb/mmBtu) ESP Upstream of Current AQC Equipment 

0.012 22 129 45,702 11,

PJFF Upstream of Current AQC Equipment 

0.012 22 129 60,992 14,

Wet ESP 1 (Metal) Downstream of Venturi Scrubber 

0.012 22 129 32,879 8,9

Wet ESP 2 (Membrane) Downstream of Venturi Scrubber 

0.012 22 129 23,901 6,6

Note: Incremental cost-effectiveness is not defined. 

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Figure 6-7 

Unit 2 - Overall View of PM Cost-Effectiveness 

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Figure 6-8 

Unit 2 - Incremental View of PM Cost-Effectiveness 

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Table 6-8 

Unit 3 - PM Cost-Effectiveness Summary 

All Feasible Technologies 

Emission 

Performance 

Level 

(lb/mmBtu) 

Expected 

Emissions 

Rate (lb/h) 

Expected 

Emissions 

Reductions 

(tons/yr) 

Capital Costs 

(x $1,000) 

Total 

Annualized 

Cost 

(x $1,000) 

PM (resultant emissions based on current 0.029 lb/mmBtu) ESP Upstream of Current AQC Equipment 

0.012 29 168 40,135 10,925 

PJFF Upstream of Current AQC Equipment 

0.012 29 168 59,594 16,559 

Wet ESP 1 (Metal) Downstream of Venturi Scrubber 

0.012 29 168 59,594 10,309 

Wet ESP 2 (Membrane) Downstream of Venturi Scrubber 

0.012 29 168 26,988 7,557 

Note: Incremental cost-effectiveness is not defined. 

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Figure 6-9 

Unit 3 - Overall View of PM Cost-Effectiveness 

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Figure 6-10 

Unit 3 - Incremental View of PM Cost-Effectiveness 
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Four Corners Units 1 through 5 Results 

120407 7-1 

7.0 Results 

7.1 Cost-Effectiveness Summary 

 The BART engineering analysis determines the cost-effectiveness of each 

technology in two different ways. The average cost-effectiveness (also referred to as 

simply cost-effectiveness) is determined by dividing the annual cost of the pollution 

control technology by the amount of pollutant removed. The cost of each technology is 

meant to represent the full cost of the technology at the plant. The amount of tons 

removed annually is determined from the equation shown in Section 6.3. The costeffectiveness is then expressed in dollars per ton of pollutant removed. The “economic 

optimum” refers to the technology that has the minimum value for the average costeffectiveness. The second method of describing the cost-effectiveness of a BART 

technology is via incremental cost-effectiveness. Incremental cost-effectiveness is used 

to compare a technology to the next most stringent control option.1

 High incremental 

cost-effectiveness may suggest that the additional removal of the next most stringent 

control option may not be practical, considering the large cost increase associated with 

that control option. The technology that removes the greatest amount of pollution before 

the incremental cost-effectiveness makes a large jump when compared to the next most 

stringent technology is referred to as the “incremental threshold.” 

The extreme retrofit difficulty at the Four Corners plant makes the installation of 

new pollution control equipment less cost-effective than most recent AQC retrofits. The 

NOx cost-effectiveness envelope is shown on Figures 6-1, 6-2, 6-3, and 6-4 for Units 1, 2, 

3, and 4 and 5, respectively. Each additional ton of NOx removed is more expensive than 

the previous ton. For example, Figure 6-1 depicts the low cost-low control of the neural 

network relative to the high cost-high control SCR. Following the curve left to right, as it 

bends upward, shows the increasing costs associated with larger emissions reductions 

technologies. 

The PM cost-effectiveness envelope is shown on Figures 6-5, 6-6, and 6-7 for 

Units 1, 2, and 3, respectively. For example, Figure 6-5 depicts wet ESP (membrane) as 

a low-cost control technology relative to the high cost PJFF. 

It is important to note that the results of this engineering analysis are based on 

high-level cost estimates and preliminary budgetary quotations, developed on limited 

design information and a number of assumptions. B&V’s experience with industry 

standards is consistent with the predicted performance of these control technologies; 

however, these quotations may contain optimistic conclusions regarding system 

 1 Federal Register, Wednesday July 6, 2005, 40 CFR Part 51 Regional Haze Regulations and 

Guidelines for Best Available Retrofit Technology (BART) Determinations; Final Rule, Page 39168. 
Arizona Public Service 

Four Corners Units 1 through 5 Results 

performance because the details of the specific retrofit are not taken into account. As a 

result, these vendor quotations are not binding and, typically, guarantees are not offered 

until detailed process calculations have been completed. This information, while 

accurate and honest, is not a guarantee of system performance. Performance-based 

contractual guarantees are established after a more thorough engineering analysis. 

Consequently, B&V recommends basing the results of the BART engineering analysis on 

the selection of a particular technology rather than on a specific ton reduction. B&V 

believes the actual performance can reasonably be expected to be close to the values 

shown in this report, but some variations may occur, and neither APS nor B&V can 

predict such variations at this time. 

7.2 Unit 1 NOx Cost-Effectiveness Summary 

The type of furnace, type of fuel burned, and the existing NOx controls affect the 

cost-effectiveness of the NOx control technologies. Four Corners Units 1 and 2 are front 

wall fired Riley furnaces, which have a relatively small furnace volume compared to 

other wall fired furnaces. The smaller furnace leads to higher furnace temperatures, less 

volume available for combustion staging and potential operational challenges (such as 

slagging) when implementing LNB and/or OFA. The potential SCR retrofit appears 

particularly difficult, because of the horizontal air heater arrangement, and will require 

new forced draft (FD) fans, new air heaters, and new ID fans. This leads to an expensive 

cost, on a dollar per ton of NOx removed basis, for the SCRs on Units 1 and 2. 

Combustion controls are expected to be integral in any NOx solution because of the 

relatively high NOx baseline. However, the plant experience with LNB on Unit 2 

demonstrates that a combustion optimization approach to NOx reduction must be 

cognizant of the challenges posed by the small furnaces. 

The most cost-effective NOx reductions, on a dollar per ton NOx removed basis, 

are available on Unit 1. This is due to the higher baseline emissions on Unit 1 when 

compared to the other units at the Four Corners Station. The inflection point of the leastcost envelope, shown on Figure 6-1, is the LNB, OFA, and HERT system. 

The cost-effectiveness of the LNB, OFA, and HERT system is $631 per ton of 

NOx removed. This reduction represents a NOx emissions reduction of 74 percent 

compared to the NOx baseline. The expected emission rate of 0.20 lb/mmBtu of NOx is 

49 percent below the presumptive NOx limit for the unit. If the presumptive limits are the 

target of the NOx emissions reduction, the implementation of a state-of-the-art LNB is the 

most cost-effective NOx reduction option, at a cost of $334 per ton of NOx removed. 

Conversely, at $3,466 per ton of NOx removed, the SCR is the most expensive NOx

reduction option. 

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Four Corners Units 1 through 5 Results 

7.3 Unit 2 NOx Cost-Effectiveness Summary 

 Much of the discussion in Section 7.2 regarding Unit 1 will apply to Unit 2 as 

well. Units 1 and 2 are sister units and share many characteristics that make NOx retrofits 

challenging. Unit 2, however, presents the further challenge of limited footprint area 

available for retrofits. Located tightly between Units 1 and 3, with a coal conveyor 

running on its north side, the access and available area for Unit 2 is extremely limited. 

The OFA system, which does not require a large footprint, is the least expensive method 

of reducing NOx, while the SCR is the most expensive due to the large capital cost 

associated with the very difficult retrofit. Units 1 and 2 are both Riley wall fired boilers, 

with 170 MW net generation capacity. The main difference between the units is that an 

LNB was installed on Unit 2 in 1998. With a NOx emissions rate of 0.64 lb/mmBtu as 

the Unit 2 baseline, NOx production is about 20 percent lower than Unit 1. Additionally, 

the current LNB on Unit 2 has caused operational issues due to furnace constraints and 

poor combustion. Similar to Unit 1, the Unit 2 SCR system is more expensive than a 

typical SCR installation because of the ductwork arrangement around the air heater. The 

only feasible option for the installation of an SCR system on Units 1 and 2 is the 

demolition of the existing air heaters, the installation of new FD fans, and the 

construction of new air heaters along with the SCR and the corresponding ductwork. 

This effort is both capital and labor intensive, resulting in the high cost for SCR 

implementation. 

 As mentioned previously, the characteristics of the Unit 1 and Unit 2 furnaces 

make the reduction of NOx by combustion methods difficult. The small furnaces do not 

allow for effective combustion staging, and the closely spaced burners reduce the 

effectiveness of LNB. The LNB with OFA, LNB with OFA plus HERT, and SCR reduce 

NOx at a cost of $519, $814, and $4,401 per ton, respectively. 

7.4 Unit 3 NOx Cost-Effectiveness Summary 

 Unit 3 is slightly larger than Units 1 and 2, but the NOx BART analysis is very 

similar for the three units. Unit 3 was also retrofit with LNB and has current NOx

emissions of 0.59 lb/mmBtu. In fact, because of this retrofit, the annual NOx tons emitted 

from Unit 3 are lower than the emissions from Unit 1. Because of the air heater 

arrangement, the construction of an SCR system is not possible without the installation of 

a new air heater and new FD fans. These replacement equipment costs, along with the 

limited area for construction, make the installation of SCR more expensive than a typical 

SCR retrofit. The retrofit of Unit 3 with LNB and OFA represents the economic 

optimum, as defined in Section 7.1, at a cost of $397 per ton of NOx removed. If more 

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Four Corners Units 1 through 5 Results 

aggressive NOx reduction is found to be necessary as a result of modeling the visibility 

impacts, the LNB, OFA, and HERT system appears to be the next most stringent option, 

at a cost of $759 per ton removed. The SCR alternative is the most expensive option, at a 

cost of $3,947 per ton removed. 

7.5 Units 4 and 5 NOx Cost-Effectiveness Summary 

 For the purposes of the BART analysis, Units 4 and 5 were considered to be 

identical units. This assumption was made because the boilers are sister units, and the 

history of NOx modifications is the same for both units. Units 4 and 5 have the same gas 

path and have nearly identical performance and NOx emissions rates. 

 The main difference between the Units 1, 2, and 3 BART analysis and the Units 4 

and 5 BART analysis is that the HERT and Mobotec technologies are not proven on units 

as large as Units 4 and 5. The removal of the intermediate NOx removal options refines 

the analysis in such a way that the results of the modeling will play a key role on the 

determination of the BART technology. 

The LNB and OFA option is capable of reducing NOx at the cost of $792 per ton. 

By contrast, the SCR system is the least cost-effective option for NOx reduction, with 

each ton removed costing $4,499 per ton. This translates to an incremental NOx

reduction cost of $8,099 per ton of NOx removed beyond the capability of the LNB, 

OFA, and SNCR. The SCR retrofit would be extremely complicated and costly because 

of the arrangement of the primary and secondary air heaters and the corresponding 

ductwork. The outage is expected to be significant, with at least 14 weeks of downtime. 

7.6 Unit 1 Particulate Matter Cost-Effectiveness Summary 

 The venturi scrubbers currently control filterable PM to 0.025 lb/mmBtu. The 

five options for additional particulate removal are shown in Table 4-2. Each of the PM 

pollution control devices are expected to control particulate emissions to 0.012 

lb/mmBtu. This would reduce particulate emissions by 94 tons per year at a cost of 

$148,659 and $60,231 per ton for the fabric filter and wet ESP (membrane type), 

respectively. For this case, the BART engineering analysis indicates that wet ESP 

(membrane type) would be the most cost-effective technology. 

7.7 Unit 2 Particulate Matter Cost-Effectiveness Summary 

 Unit 2 has the same existing particulate control equipment as Unit 1. The venturi 

scrubbers currently control filterable PM to 0.029 lb/mmBtu. The resulting emissions 

after the installation of the technology listed on Table 4-2, like Unit 1, would be 

0.012 lb/mmBtu. This would reduce particulate emissions by 129 tons per year at a cost 

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Four Corners Units 1 through 5 Results 

of $111,908 and $51,453 per ton for the fabric filter and wet ESP (membrane type), 

respectively. The site constraints noted in Section 7.3 also affect the construction of 

particulate control equipment, making any retrofit more challenging and costly. It should 

be noted that the Unit 2 baseline is higher than that of Unit 1, inflating the costeffectiveness on a dollars per ton removed basis. The BART engineering analysis 

indicates that wet ESP (membrane type) would be the most cost-effective technology for 

Unit 2. 

7.8 Unit 3 Particulate Matter Cost-Effectiveness Summary 

 Unit 3 has the same existing particulate control equipment as Units 1 and 2. The 

venturi scrubbers currently control filterable PM to 0.029 lb/mmBtu. The resulting 

emissions after the installation of the technology listed on Table 4-2, like Units 1 and 2, 

would be 0.012 lb/mmBtu. This would reduce particulate emissions by 168 tons per year 

at a cost of $98,770 and $45,075 per ton for the fabric filter and wet ESP (membrane 

type), respectively. For Unit 3, the BART engineering analysis indicates that wet ESP 

(membrane type) would be the most cost-effective technology. 

7.9 Unit 4 Particulate Matter Cost-Effectiveness Summary 

 As outlined in Subsection 4.2.1, the fabric filter currently installed on Unit 4 

represents BART; therefore, no cost-effectiveness analysis was performed in accordance 

with the guidance in the Federal Register. 

7.10 Unit 5 Particulate Matter Cost-Effectiveness Summary 

 As outlined in Section 4.2.1, the fabric filter currently installed on Unit 5 

represents BART; therefore, no cost-effectiveness analysis was performed in accordance 

with the guidance in the Federal Register. 

7.11 BART Engineering Analysis Summary 

 Two pollutants were considered as part of the APS Four Corners BART analysis, 

NOx and PM. This engineering analysis is used to determine the cost-effectiveness of 

available pollution control technologies. The engineering analysis was not used to 

determine which pollution control technology would represent BART for any of the five 

units. The determination of the BART technologies cannot be made without knowing the 

impact of pollution reduction on visibility from the Calpuff modeling. However, some 

initial findings can be shared based on the engineering analysis alone. 

The most cost-effective means of reducing PM at the Four Corners site would be 

the installation of membrane type wet ESPs on Units 1, 2, and 3. These retrofits would 

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120407 7-6 

reduce PM emissions from Four Corners at a cost of approximately $50,000 per ton of 

particulate removed. Units 4 and 5 currently have fabric filters installed and, after 

analysis, have been shown to be BART for PM. 

NOx reduction at the Four Corners site is not as straightforward as the PM 

analysis. The available technologies offer a wide range of NOx reduction, with varying 

levels of cost-effectiveness. APS has already implemented NOx reduction projects since 

the construction of Units 1 through 5, which have mixed results. Units 1 and 2 are 

particularly challenging due to the small furnace sizes and air heater arrangements. The 

design of Units 1, 2, and 3 is such that the retrofit of an SCR system is not possible 

without the installation of new air heaters and FD fans, which makes these options much 

more costly, with only incremental benefits in NOx reduction. 

Although the combination of OFA and LNB seems to be a cost effective 

alternative for NOx reduction, its feasibility for Units 1 and 2 needs to be confirmed in 

greater technical detail. The history of difficult combustion-related problems on these 

units indicates that implementation of OFA and LNB must be regarded as a high risk and 

potentially complex retrofit. B&V performed investigations during the execution of this 

report, which only support the feasibility of OFA and LNB from the general perspective 

of industry experience. The level of detail required to develop this report did not provide 

enough evidence to confirm with certainty the feasibility of OFA and LNB when the 

specific history of difficult operational performance is considered. Therefore, additional 

investigations will be necessary to positively confirm the viability of the OFA and LNB 

alternative in order to ensure the future reliability and availability of Units 1 and 2.

Table 7-1 is a summary of the cost-effectiveness and the incremental costeffectiveness for Units 1, 2, 3, 4, and 5. In Table 7-1, three areas of interest for each unit 

are highlighted. The first area is the “economic optimum,” which is explained in 

Section 7.1 and shown in yellow on Table 7-1. The “economic optimum” is the 

technology that represents the mathematical minimum for the cost-effectiveness value for 

the unit. The “incremental threshold,” also explained in Section 7-1, is shown in blue in 

Table 7-1. The “incremental threshold” scenarios represent the NOx removal 

technologies at the inflection points of the cost-effectiveness curves shown on 

Figures 6-1 through 6-4. These technologies include the LNB/OFA/HERT and 

LNB/OFA/SNCR for Units 1, 2, and 3 and Units 4 and 5, respectively. The “maximum 

reduction” case is also the maximum cost technology and is shown in green in Table 7-1. 

The information provided in Table 7-1, along with the modeling analysis, should lead to 

the selection of the suitable BART alternative. 
Arizona Public Service 

Four Corners Units 1 through 5 

Table 7-1 

NOx Cost-Effectiveness Summary 

Unit 1 Unit 2 Unit 3 

All Feasible Technologies 

Cost 

($/ton) 

Incremental 

Cost 

($/ton) 

Cost 

($/ton) 

Incremental 

Cost 

($/ton) 

Cost 

($/ton) 

Incrementa

Cost 

($/ton) 

COS 688 -- 1,039 -- 1,221 -- SNCR 1,925 -- 2,029 -- 2,549 -- Mobotec ROTAMIX 2,637 -- 3,004 -- 3,283 -- New LNBs 334 257 545 427 563 427 New LNB and OFA 365 476 519 464 397 138 New LNBs and SNCR 824 -- 1,159 -- 1,233 -- New LNBs, OFA, and ROTAMIX 998 -- 1,378 -- 1,284 -- Mobotec ROFA 807 -- 1,097 -- 1,157 -- New LNBs, OFA, and SNCR 721 -- 965 -- 924 -- New LNBs, OFA, and HERT 631 1,557 814 1,517 759 1,474 Mobotec ROFA and ROTAMIX 978 21,188 1,244 20,221 1,275 21,253 SCR 3,517 16,949 4,341 15,688 3,947 12,100 New LNBs and SCR 3,380 14,332 4,326 15,270 3,967 12,182 New LNBs, OFA, and SCR 3,371 14,279 4,315 15,218 3,915 11,970 Notes: Economic Optimum Incremental Threshold Maximum Reduction N/A - Technology not applicable to unit. 120407 
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Four Corners Units 1 through 5 Appendix A 

102907 A-1 

Appendix A 

Design Basis 
Ultimate Coal analysis, wet basis Average Minimum Maximum Reference

Carbon, % 51.40 46.66 53.02 APS ProvidedHydrogen, % 3.85 3.15 4.08 APS ProvidedSulfur, % 0.75 0.65 0.95 APS ProvidedNitrogen, % 1.02 0.87 1.05 APS ProvidedOxygen, % 10.16 8.81 10.64 APS ProvidedChlorine, % 0.07 -- -- APS Provided

Ash, % 20.42 20.17 27.58 APS ProvidedMoisture, % 12.33 10.87 13.06 APS Provided

Total, % 100.00 B&V Calculation

Higher Heating Value, Btu/lb 8,776 8,200 9,363 APS Provided

Ash Analysis, % by mass

Silica (SiO2) 63.02 68.43 57.14 APS Provided

Alumina (Al2O3) 23.40 21.23 26.17 APS Provided

Iron Oxide (Fe2O3) 4.49 4.45 4.86 APS Provided

Titania (TiO2) 0.88 0.82 1.03 APS Provided

Phosphorous (P2O5) 0.18 0.16 0.39 APS Provided

Lime (CaO) 2.27 1.67 5.65 APS ProvidedMagnesia (MgO) 0.93 0.68 1.04 APS ProvidedSodium Oxide (Na2O) 1.33 1.25 1.47 APS Provided

Potassium Oxide (K2O) 1.34 0.84 1.57 APS Provided

Sulfur Trioxide (SO3) 1.67 1.23 3.50 APS Provided

Undetermined 0.49 -- -- APS Provided

Total (%) 100.00 B&V Calculation

Unit 1 Unit 2 Unit 3

Unit Characteristics

Unit Rating, Gross MW 185 185 235 APS ProvidedUnit Rating, Net MW 170 170 220 APS ProvidedNet Plant Heat Rate (NPHR), Btu/kWh (HHV) 10,956 10,957 10,908 APS ProvidedFuel Burn Rate (FBR), Mbtu/hr (HHV) 1,863 1,863 2,400 = Gross MW x NPHR / 100Coal Flow Rate, ton/hr 106.1 106.1 136.7 = Coal Flow (lb/hr) / 2000Coal Flow Rate, lb/hr 212,229 212,248 273,446 = FBR x 106 / HHV

Fly Ash Portion of Total Ash, % 80 80 80 APS ProvidedAir Heater Leakage, % 15.0 15.0 15.0 B&V AssumptionExcess O2, % 3.0 3.0 3.0 APS Provided

APS

Four Corners

Design Basis Rev. 1

Units 1, 2 & 3 1 of 6 
APS

Four Corners

Design Basis Rev. 1

Economizer Outlet Conditions 

Flue Gas Temperature, F 670 670 720 APS ProvidedFlue Gas Pressure, in. w.g. -1.2 -1.2 -0.08 APS ProvidedFlue Gas Mass Flow Rate, lb/hr 1,900,096 1,900,096 2,447,788 B&V CalculationVolumetric Flue Gas Flow Rate, acfm 1,092,646 1,092,646 1,464,942 B&V CalculationFlue Gas Composition

Oxygen, % by volume 3.0 3.0 3.0 B&V CalculationCarbon Dioxide, % by volume 13.9 13.9 13.9 B&V CalculationMoisture, % by volume 10.9 10.9 10.9 B&V CalculationSulfur Dioxide, lb/MBtu 1.71 1.71 1.71 = Sulfur (lb/hr) / FBR Sulfur Dioxide, lb/hr 3,181 3,181 4,098 B&V CalculationSulfur Trioxide, lb/hr 9 9 12 = SO3 (lb/Mbtu) x FBR

Sulfur Trioxide, lb/Mbtu 0.005 0.005 0.005 B&V CalculationSulfur Trioxide, ppm 2 2 2 APS ProvidedParticulate Concentration, lb/MBtu 18.6 18.6 18.6 = % ash x % fly ash x 100 / Particulate Mass Rate, lb/hr 34,670 34,673 44,670 = PM (lb/Mbtu) x FBRNOx Concentration, lb/MBtu 0.78 0.64 0.59 APS ProvidedNOx Mass Rate, lb/hr 1,458 1,193 1,408 = NOx lb/Mbtu x FBR

Air Heater Outlet Conditions

Flue Gas Temperature, F 285 285 285 APS ProvidedFlue Gas Pressure, in. w.g. -10.0 -10.0 -10.0 B&V AssumptionFlue Gas Mass Flow Rate, lb/hr 2,185,110 2,185,110 2,814,957 APS ProvidedVolumetric Flue Gas Flow Rate, acfm 853,789 853,789 1,099,889 APS ProvidedFlue Gas Composition

Oxygen, % by volume 5.3 5.3 5.3 APS ProvidedCarbon Dioxide, % by volume 12.0 12.0 12.0 APS ProvidedMoisture, % by volume 9.7 9.7 9.7 APS Provided

Venturi Scrubber Outlet Conditions

Particulate Removal Efficency, % 99.9 99.8 99.8 = (Inlet PM - Outlet PM) / InSO2 Removal Efficency % 91.2 91.2 91.2 = (Inlet SO2 - Outlet SO2) / 

Flue Gas Temperature, F 121 121 121 B&V CalculationFlue Gas Pressure, in. w.g. -22 -22 -22 B&V AssumptionFlue Gas Mass Flow Rate, lb/hr 2,272,284 2,539,000 2,927,258 APS ProvidedVolumetric Flue Gas Flow Rate, acfm 736,790 757,000 949,166 APS ProvidedParticulate Concentration, lb/MBtu 0.025 0.029 0.029 APS ProvidedParticulate Mass Rate, lb/hr 47 54 70 = PM (lb/Mbtu) x FBRSO2 Concentration, lb/MBtu 0.15 0.15 0.15 APS Provided

SO2 Rate, lb/hr 279 279 360 = Inlet SO2 (1- SO2 Remov

Flue Gas Composition

Oxygen, % by volume 5.0 5.0 5.0 APS ProvidedCarbon Dioxide, % by volume 11.3 11.3 11.3 APS ProvidedMoisture, % by volume 15.4 15.4 15.4 APS Provided

Units 1, 2 & 3 2 of 6 
APS

Four Corners

Design Basis Rev. 1

ID Fan Outlet Conditions

Flue Gas Temperature, F 130 130 130 B&V AssumptionFlue Gas Pressure, in. w.g. 2 2 2 B&V AssumptionFlue Gas Mass Flow Rate, lb/hr 2,539,000 2,539,000 3,271,000 APS ProvidedVolumetric Flue Gas Flow Rate, acfm 759,000 759,000 977,000 B&V Calculation

Stack Outlet Emissions

Sulfur Dioxide, lb/MBtu 0.15 0.15 0.15 Venturi Outlet SO2

Sulfur Dioxide, lb/hr 279 279 360 Venturi Outlet SO2Sulfur Trioxide, lb/hr 9 9 12 Venturi Outlet SO3Sulfur Trioxide, lb/MBtu 0.005 0.005 0.005 Venturi Outlet SO3Sulfur Trioxide, ppm 2 2 2 Venturi Oullet SO3Particulate Concentration, lb/MBtu 0.0250 0.0292 0.0292 Venturi Outlet PMParticulate Concentration, lb/hr 47 54 70 Venturi Outlet PMNOx Emission Rate, lb/MBtu 0.78 0.64 0.59 Economizer Outlet NOxNOx Emission Rate, lb/hr 1,458 1,193 1,408 Economizer Outlet NOx

Units 1, 2 & 3 3 of 6 
Ultimate Coal analysis, wet basis Reference

Carbon, % APS ProvidedHydrogen, % APS ProvidedSulfur, % APS ProvidedNitrogen, % APS ProvidedOxygen, % APS ProvidedChlorine, % APS Provided

Ash, % APS ProvidedMoisture, % APS Provided

Total, % B&V Calculation

Higher Heating Value, Btu/lb APS Provided

Ash Analysis, % by mass

Silica (SiO2) APS Provided

Alumina (Al2O3) APS Provided

Iron Oxide (Fe2O3) APS Provided

Titania (TiO2) APS Provided

Phosphorous (P2O5) APS Provided

Lime (CaO) APS ProvidedMagnesia (MgO) APS ProvidedSodium Oxide (Na2O) APS Provided

Potassium Oxide (K2O) APS Provided

Sulfur Trioxide (SO3) APS Provided

Undetermined APS Provided

Total (%) B&V Calculation

Unit Characteristics

Unit Rating, Gross MW APS ProvidedUnit Rating, Net MW APS ProvidedNet Plant Heat Rate (NPHR), Btu/kWh (HHV) APS ProvidedFuel Burn Rate (FBR), Mbtu/hr (HHV) = Gross MW x NPHR / 1000Coal Flow Rate, ton/hr = Coal Flow (lb/hr) / 2000Coal Flow Rate, lb/hr = FBR x 106 / HHV

Fly Ash Portion of Total Ash, % APS ProvidedAir Heater Leakage, % B&V AssumptionExcess O2, % APS Provided

80

15.0

3.0

790765

9,8817,806444.7

889,470

765790

3.0

15.0

80

889,470

444.77,8069,881

Unit 4 Unit 5

1.034.861.471.04

1.33

0.824.45

2.27

13.06

5.650.39

--

3.501.57

26.1757.14

9,363

27.58

--

10.64

46.66

1.054.080.95

53.02

8.810.87

0.93

0.65

10.8720.17

----

1.230.84

100.00

0.491.671.34

3.15

8,200

68.43

1.250.681.670.16

21.23

0.180.88

63.0223.40

4.49

20.4212.33

100.00

APS

Four Corners

Design Basis Rev. 1

Average Minimum Maximum

51.40

3.850.751.02

8,776

10.16

0.07

Units 4 & 5 4 of 6 
APS

Four Corners

Design Basis Rev. 1

Economizer Outlet Conditions 

Flue Gas Temperature, F APS ProvidedFlue Gas Pressure, in. w.g. APS ProvidedFlue Gas Mass Flow Rate, lb/hr B&V CalculationVolumetric Flue Gas Flow Rate, acfm B&V CalculationFlue Gas Composition

Oxygen, % by volume B&V CalculationCarbon Dioxide, % by volume B&V CalculationMoisture, % by volume B&V CalculationSulfur Dioxide, lb/MBtu = Sulfur Dioxide (lb/hr) / FBRSulfur Dioxide, lb/hr B&V CalculationSulfur Trioxide, lb/hr = SO3 (lb/Mbtu) x FBRSulfur Trioxide, lb/Mbtu B&V CalculationSulfur Trioxide, ppm APS ProvidedParticulate Concentration, lb/MBtu = % ash x % fly ash x 100 / coal HHVParticulate Mass Rate, lb/hr = PM (lb/Mbtu) x FBRNOx Concentration, lb/MBtu APS ProvidedNOx Mass Rate, lb/hr = NOx lb/Mbtu x FBR

Air Heater Outlet Conditions

Flue Gas Temperature, F APS ProvidedFlue Gas Pressure, in. w.g. APS ProvidedFlue Gas Mass Flow Rate, lb/hr B&V CalculationVolumetric Flue Gas Flow Rate, acfm B&V CalculationFlue Gas Composition

Oxygen, % by volume B&V CalculationCarbon Dioxide, % by volume B&V CalculationMoisture, % by volume B&V Calculation

Fabric Filter Outlet Conditions

Particulate Removal Efficency, % = (Inlet PM - Outlet PM) / Inlet PMFlue Gas Temperature, F APS ProvidedFlue Gas Pressure, in. w.g. APS ProvidedFlue Gas Mass Flow Rate, lb/hr B&V CalculationVolumetric Flue Gas Flow Rate, acfm B&V CalculationParticulate Concentration1, lb/MBtu APS Provided

Particulate Mass Rate1, lb/hr 74.9 = PM (lb/Mbtu) x FBR

-8.0

8,890,5723,183,689

0.010

99.9%

227

5.3

12.0

9.7

242

1.0

8,890,5723,165,677

0.48

3,7450.005

2

18.6

145,304

10.91.66

12,943

39

4,224,592

3.0

13.9

650

10.0

7,730,932

242

3,165,6778,890,572

1.09.7

12.0

5.3

-8.0

227

99.9%

107.70.014

3,183,6898,890,572

13.9

3.0

39

12,943

1.6610.9

145,304

18.6

2

0.0053,967

0.51

4,224,5927,730,932

10.0

650

Units 4 & 5 5 of 6 
APS

Four Corners

Design Basis Rev. 1

ID Fan Outlet Conditions

Flue Gas Temperature, F B&V AssumptionFlue Gas Pressure, in. w.g. B&V AssumptionFlue Gas Mass Flow Rate, lb/hr B&V CalculationVolumetric Flue Gas Flow Rate, acfm B&V Calculation

Scrubber Outlet Conditions Scrubber removal % = (Inlet SO2 - Outlet SO2) / Inlet SO2

Flue Gas Temperature, F B&V CalculationFlue Gas Pressure, in. w.g. B&V AssumptionFlue Gas Mass Flow Rate, lb/hr B&V CalculationVolumetric Flue Gas Flow Rate, acfm B&V CalculationFlue Gas Composition

Oxygen, % by volume B&V CalculationCarbon Dioxide, % by volume B&V CalculationMoisture, % by volume B&V CalculationSulfur Dioxide, lb/MBtu APS ProvidedSulfur Dioxide, lb/hr = SO2 (lb/Mbtu) x FBR

Stack Outlet Emissions

Sulfur Dioxide, lb/MBtu Scrubber Outlet SO2

Sulfur Dioxide, lb/hr Scrubber Outlet SO2Sulfur Trioxide, lb/hr Economizer Outlet SO3Sulfur Trioxide, lb/MBtu Economizer Outlet SO3Sulfur Trioxide, ppm Economizer Oullet SO3Particulate Concentration1, lb/MBtu Fabric Filter Outlet PM

Particulate Concentration1, lb/hr Fabric Filter Outlet PMNOx Emission Rate, lb/MBtu Economizer Outlet NOxNOx Emission Rate, lb/hr Economizer Outlet NOx

 1) If the BART analysis is expanded to cover particulate the PM emissoins values must be confirmed.Notes:

0.48

3,745

2.0

87.5%

120

2.0

9,138,9252,728,460

0.2

1,618

0.2

1,618

87.5%

120

2.0

9,138,9252,728,460

0.005

0.2

13.811.5

5.1

13.8

0.0096

75

0.2

1,618

39

6

8,890,5723,101,284

238

3,967

0.51

108

0.0138

2.0

0.005

39

1,618

3,101,2848,890,572

6

238

11.5

5.1

Units 4 & 5 6 of 6 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix B 

102907 B-1 

Appendix B 

Technology Removal Matrix 
Arizona Public Service 

Four Corners Units 1 through 5 102907 

APS Four Corners Units 1, 2, 3, 4 and 5Emissions Control Technology Matrix and Maximum1 Removal Efficiency

FuelFuel Case Description or Percentage BlendsUnit rating, MW (gross / net)Boiler heat input, mmBtu/hrType of boilerSteam cycleDraft of boilerExisting emissions controls

BoilerParticulate

BART Baseline Emissions

NOx, ton/yrPM10 Filterable, ton/yr

Outlet conditions ("controlled" based on APS provided data) 

NOx, lb/mmBtuPM10 Filterable, lb/mmBtu

Apply Apply Apply 

tech? NOx PM tech? NOx PM tech? NOx PM 

Current emissions reduction from inlet conditions3 0.78 0.025 0.64 0.029 0.59 0.029 

New emissions control technologies

Particulate Control

Electrostatic Precipitators (ESP) Upstream of Current AQC Equipment Yes 0.012 Yes 0.012 Yes 0.012 Pulse Jet Fabric Filter (PJFF) Upstream of Current AQC Equipment Yes 0.012 Yes 0.012 Yes 0.012 COHPAC Downstream Current AQC Equipment No No No Wet ESP Downstream of Venturi Yes 0.012 Yes 0.012 Yes 0.012 Max 9 Hybrid Particulate Collector No No No Multi-Cyclone No No No Coal Washing No No No 

NOx Control

Combustion Optimization System (COS) Yes 0.72 Yes 0.60 Yes 0.56 Selective Non-Catalytic Reduction (SNCR) Yes 0.56 Yes 0.46 Yes 0.46 Mobotec Rotamix Yes 0.56 Yes 0.45 Yes 0.45 New Low NOx Burners (LNB) Yes 0.43 Yes 0.43 Yes 0.43 New LNB, Overfire Air (OFA) Yes 0.33 Yes 0.33 Yes 0.33 New LNBs and SNCR Yes 0.32 Yes 0.32 Yes 0.32 New LNBs and Rotamix Yes 0.30 Yes 0.30 Yes 0.30 Mobotec Rotating Overfire air (ROFA) Yes 0.28 Yes 0.28 Yes 0.28 New LNBs, OFA and SNCR Yes 0.26 Yes 0.26 Yes 0.26 New LNBs, OFA and High Energy Reagent Technology (HERT) Yes 0.20 Yes 0.20 Yes 0.20 Mobotec ROFA and Rotamix Yes 0.19 Yes 0.19 Yes 0.19 Selective Catalytic Reduction (SCR) Yes 0.08 Yes 0.06 Yes 0.06 New LNBs and SCR Yes 0.06 Yes 0.06 Yes 0.06 New LNBs, OFA and SCR Yes 0.06 Yes 0.06 Yes 0.06 NOxStar and NOxStar Plus No No No ECOTUBE No No No IFGR No No No SNCR/SCR Hybrid (Cascade System) No No No LoTOx No No No Natural Gas Reburn No No No THERMALONOx Process No No No Oxygen Enhanced Combustion No No No Biotechnological Denitrification No No No 

Notes:3) All emission rates are in lb/mmBtu unless otherwise specified.

Emission Rate 3 Emission Rate 3

0.029 

Emission Rate 3 

1) Emission rates shown represent best case scenarios based on industry experience and may not reflect upset operation conditions or the possible deg

over operating cycles.2) Controlled emissions is with current control equipment.

0.59 

285 

5,633 

Venturi Scrubber 

LNB (1990) 

Subcritical 

Balanced 

Front Wall Foster Wheeler 

Membrane Wall

Fro

235 / 220 

2,400 

Mine Mouth Bituminous 

Four Corners 

Unit 3 

3/29/2007

0.78 0.64

0.025 0.029

Venturi Scrubber Venturi Scrubber

4,788

220

5,703

180

Low NOx Burner 

Modifications (1977) LNB (1998)

Balanced Balanced

Subcritical Subcritical

 Front Wall Fired Riley 

Tangential Tube

 Front Wall Fired Riley 

Tangential Tube

Four Corners Four Corners

Mine Mouth Bituminous Mine Mouth Bituminous

Unit 1 Unit 2

1,863 1,863

185 / 170 185 / 170
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-1 

Appendix C 

Design Concept Definitions 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-2 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Upgraded Boiler Optimization System (Neural Network) 

Process Description Upgrade existing boiler optimization system (Neuco neural network system) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.72 

 lb/hr 1,341 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Computer hardware and software for boiler optimization system located in control room near the 

DCS. Dampers and actuators are assumed to be operational and DCS controlled. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Interface with existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

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

No air heater modifications or boiler/duct stiffening included. 

The upgrade/replacement may increase boiler efficiency and cause a slight reduction in operating costs. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-3 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Low NOx Burners and Overfire Air System (OFA) 

Process Description Installation of Low NOx burners and overfire air system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.33 

 lb/hr 615 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other Possible slight increase in LOI, unburned carbon and CO. 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Addition of coal flow monitors in coal pipes leading to burner. Fuel and air balancing 

performed for each burner. Addition of water cannon system to boiler wall. CFD modeling to 

ensure uniform flow pattern, temperature distribution and air balancing for OFA system. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Addition of NOx optimization into combustion monitoring process. 

Fan Modifications None. 

Power Supply/Aux Power Modifications No significant aux power impacts from additional equipments. 

Enclosures Requirements None. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Potential risk of boiler slagging. 

Other Assumptions 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-4 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Selective Catalytic Reduction (SCR) 

Process Description Selective Catalytic Reduction (SCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.08 

 lb/hr 145 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added 8 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Energy TBD kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Not applicable 

 Other 2 ppm ammonia slip (max) 

Location of Major Process Equipment Install SCR reactor north of Unit 1 above new air heater to be installed. 

Install NH3 vaporizers at grade. 

Inlet/Outlet Connections and Interconnecting Ducts Existing secondary air heaters demolished to allow room for ductwork connections. SCR inlet 

connected to old air heater outlet, SCR outlet duct connected to venturi scrubber inlet. 

Reagent Storage Locate urea storage at grade in suitable location and pump through heat traced line to SCR 

location 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume modification or addition of fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume upgrade will be required for aux electric system. 

Enclosures Requirements Analyzer shelters. 

Demolition or Relocation Requirements Existing economizer outlet ductwork including existing air heater. 

Major Constructability Issues Tying the SCR into the existing ductwork after air heater demolition. Crane access should be 

aware of cable raceway on the north side of Unit 1. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning. 

Need to use urea based SCR system due to safety concerns. 

SO3 mitigation system may be required. 

Other Assumptions 

No major impact in plant availability. 

Temperature range of flue gas at economizer inlet is acceptable. 

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

Existing air heater demolition, new air heater installation, flue gas handling systems and urea handling systems included. 

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

Reagent is urea. 

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

Energy consumption includes ID fan power requirements to overcome SCR system resistance. 

No noise abatement costs have been included. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-5 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology LNB and OFA with Selective Catalytic Reduction (SCR) 

Process Description Selective Catalytic Reduction (SCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.06 

 lb/hr 112 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added 8 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Ammonia, Urea) TBD lb/hr 

 Energy TBD kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Not applicable 

 Other 2 ppm ammonia slip (max) 

Location of Major Process Equipment Install SCR reactor on north side of Unit 1along with new air heater. Install urea decomposition 

chamber at grade. Install new burners in the existing burner openings. Install OFA ports to 

support new Low NOx Burners. Fuel and air balancing performed for each burner. Addition of 

coal flow monitors in coal pipes leading to burner. Addition of water cannon system to boiler 

wall. 

Inlet/Outlet Connections and Interconnecting Ducts Existing air heater demolished to allow room for ductwork connections. SCR inlet connected to 

old air heater outlet, SCR outlet duct connected to venturi scrubber inlet. 

Reagent Storage Locate urea storage at grade in suitable location and pump through heat traced line to SCR 

location 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume upgrade will be required for aux electric system. 

Enclosures Requirements Ammonia injection grid area and sonic horns are to be enclosed. 

Demolition or Relocation Requirements Existing economizer outlet ductwork and boiler building wall. 

Major Constructability Issues Tying the SCR into the existing ductwork after air heater demolition. Crane access should be 

aware of cable raceway on the north side of Unit 1. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning and/or washing. 

Need to use urea based SCR system due to safety concerns. 

Other Assumptions 

No major impact in plant availability. 

Temperature range of flue gas at economizer inlet is acceptable over entire design load range. 

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

Existing air heater demolition, new air heater installation, flue gas handling systems and urea handling systems included. 

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

Reagent is urea. 

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

Energy consumption includes booster fan power requirements to overcome SCR system resistance. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-6 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Selective Non-Catalytic Reduction (SNCR) 

Process Description Selective Non-Catalytic Reduction (SNCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.56 

 lb/hr 1,043 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Assumed no impact on ash sales. 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Solution pumped in heat 

traced line to SNCR lances. 

Inlet/Outlet Connections and Interconnecting Ducts Install wall injectors and lance-type injectors for SNCR in the boiler. 

Reagent Storage Urea tank at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning and/or washing. 

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. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-7 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Low NOx Burners and OFA System with SNCR 

Process Description Low NOx Burners (LNBs) with overfire air (OFA) system. Selective Non-Catalytic Reduction (SNCR) system for post-combustion 

reduction of NOx. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.26 

 lb/hr 484 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Fuel and air balancing performed for each burner. Addition of coal flow monitors in 

coal pipes leading to burner. Addition of water cannon system to boiler wall. Injection skid and 

urea tank at grade with truck unloading station. Urea pumped to injection location in heat 

traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Require minor boiler pressure part modification for OFA ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning and/or washing. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-8 

Design Concept Definition

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Low NOx Burners and OFA System with HERT 

Process Description Low NOx Burners (LNBs) with overfire air (OFA) system. High Energy Reagent Technology (HERT) system for post-combustion 

reduction of NOx. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.20 

 lb/hr 373 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Fuel and air balancing performed for each burner. Addition of coal flow monitors in 

coal pipes leading to burner. Addition of water cannon system to boiler wall. Injection skid and 

urea tank at grade with truck unloading station. Urea pumped to injection location in heat 

traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Require minor boiler pressure part modification for OFA ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning and/or washing. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-9 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Mobotec ROTAMIX 

Process Description Installation of Mobotec ROTAMIX system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.56 

 lb/hr 1,043 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Urea pumped to injection 

location in heat traced pipe. 

Inlet/Outlet Connections and Interconnecting Ducts Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for Rotamix ports. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for ROTAMIX is urea. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-10 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology LNB and OFA with Mobotec ROTAMIX 

Process Description Installation of Mobotec ROTAMIX system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.30 

 lb/hr 559 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Addition of coal flow monitors in coal pipes leading to burner. Addition of water 

cannon system to boiler wall. Injection skid and urea tank at grade with truck unloading 

station. Urea pumped to injection location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for Mobotec ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for ROTAMIX is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-11 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Mobotec ROFA 

Process Description Installation of Mobotec rotating overfire air (ROFA) system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.28 

 lb/hr 522 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Mobotec overfire air ports installed on sides of the furnace in locations to be determined by flow 

modeling. 

Inlet/Outlet Connections and Interconnecting Ducts Injection points tied into a new booster fan. Fan inlet connected to pre-combustion air. 

Reagent Storage None. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Auxiliary upgrades expected to power booster fan. 

Enclosures Requirements 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for ROFA ports. Location of the booster fan to be 

determined, new foundations for fan will be required. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-12 

Design Concept Definition 

Site Name Four Corners Unit 1 

Client Name Arizona Public Service Process Technology Mobotec ROFA with ROTAMIX 

Process Description Installation of Mobotec ROFA along with ROTAMIX for post-combustion NOx reduction. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.78 

 lb/hr 1,453 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.19 

 lb/hr 354 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Urea pumped to injection 

location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Auxiliary power systems modifications expected to accommodate new booster fan. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-13 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Upgraded Boiler Optimization System (Neural Network) 

Process Description Upgrade existing boiler optimization system (Neuco neural network system) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.60 

 lb/hr 1,118 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Computer hardware and software for boiler optimization system located in control room near the 

DCS. Dampers and actuators are assumed to be operational and DCS controlled. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Interface with existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

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

No air heater modifications or boiler/duct stiffening included. 

The upgrade/replacement may increase boiler efficiency and cause a slight reduction in operating costs. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-14 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Low NOx Burners and Overfire Air System (OFA) 

Process Description Installation of Low NOx burners and overfire air system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.33 

 lb/hr 615 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other Possible slight increase in LOI, unburned carbon and CO. 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Addition of coal flow monitors in coal pipes leading to burner. Fuel and air balancing 

performed for each burner. Addition of water cannon system to boiler wall. CFD modeling to 

ensure uniform flow pattern, temperature distribution and air balancing for OFA system. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Addition of NOx optimization into combustion monitoring process. 

Fan Modifications None. 

Power Supply/Aux Power Modifications No significant aux power impacts from additional equipments. 

Enclosures Requirements None. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Potential risk of boiler slagging. 

Other Assumptions 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-15 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Selective Catalytic Reduction (SCR) 

Process Description Selective Catalytic Reduction (SCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.06 

 lb/hr 119 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Energy TBD kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Not applicable 

 Other 2 ppm ammonia slip (max) 

Location of Major Process Equipment Final location of SCR not determined. SCR to be installed, along with a new air heater, either 

above the existing compressor building or on the east side of the service road. 

Install NH3 vaporizers at grade. 

Inlet/Outlet Connections and Interconnecting Ducts Existing secondary air heater demolished to allow room for ductwork connections. SCR inlet 

connected to old air heater outlet, new air heater outlet duct connected to venturi scrubber inlet. 

Reagent Storage Locate urea storage at grade in suitable location and pump through heat traced line to SCR 

location 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume modification or addition of fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume upgrade will be required for aux electric system. 

Enclosures Requirements Analyzer shelters. 

Demolition or Relocation Requirements Existing economizer outlet ductwork including existing air heater. 

Major Constructability Issues Tying the SCR into the existing ductwork after air heater demolition. Very limited crane access 

to Unit 2. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning. 

Need to use urea based SCR system due to safety concerns. 

SO3 mitigation system may be required. 

Other Assumptions 

No major impact in plant availability. 

Temperature range of flue gas at economizer inlet is acceptable. 

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

Existing air heater demolition, new air heater installation, flue gas handling systems and urea handling systems included. 

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

Reagent is urea. 

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

Energy consumption includes ID fan power requirements to overcome SCR system resistance. 

No noise abatement costs have been included. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-16 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology LNB and OFA with Selective Catalytic Reduction (SCR) 

Process Description Selective Catalytic Reduction (SCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.06 

 lb/hr 112 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Energy TBD kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Not applicable 

 Other 2 ppm ammonia slip (max) 

Location of Major Process Equipment Final location of SCR not determined. SCR to be installed, along with a new air heater, either 

above the existing compressor building or on the east side of the service road. Install urea 

decomposition chamber at grade. Install new burners in the existing burner openings. Install 

OFA ports to support new Low NOx Burners. Addition of coal flow monitors in coal pipes 

leading to burner. Addition of water cannon system to boiler wall. 

Inlet/Outlet Connections and Interconnecting Ducts Existing air heater demolished to allow room for ductwork connections. SCR inlet connected to 

old air heater outlet, SCR outlet duct connected to venturi scrubber inlet. 

Reagent Storage Locate urea storage at grade in suitable location and pump through heat traced line to SCR 

location 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume upgrade will be required for aux electric system. 

Enclosures Requirements Ammonia injection grid area and sonic horns are to be enclosed. 

Demolition or Relocation Requirements Existing economizer outlet ductwork and boiler building wall. 

Major Constructability Issues Tying the SCR into the existing ductwork after air heater demolition. Very limited crane access 

to Unit 2. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning and/or washing. 

Need to use urea based SCR system due to safety concerns. 

Other Assumptions 

No major impact in plant availability. 

Temperature range of flue gas at economizer inlet is acceptable over entire design load range. 

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

Existing air heater demolition, new air heater installation, flue gas handling systems and urea handling systems included. 

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

Reagent is urea. 

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

Energy consumption includes booster fan power requirements to overcome SCR system resistance. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-17 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Selective Non-Catalytic Reduction (SNCR) 

Process Description Selective Non-Catalytic Reduction (SNCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.46 

 lb/hr 857 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Assumed no impact on ash sales. 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Solution pumped in heat 

traced line to SNCR lances. 

Inlet/Outlet Connections and Interconnecting Ducts Install wall injectors and lance-type injectors for SNCR in the boiler. 

Reagent Storage Urea tank at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning and/or washing. 

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. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-18 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Low NOx Burners and OFA System with SNCR 

Process Description Low NOx Burners (LNBs) with overfire air (OFA) system. Selective Non-Catalytic Reduction (SNCR) system for post-combustion 

reduction of NOx. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.26 

 lb/hr 484 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Fuel and air balancing performed for each burner. Addition of coal flow monitors in 

coal pipes leading to burner. Addition of water cannon system to boiler wall. Injection skid and 

urea tank at grade with truck unloading station. Urea pumped to injection location in heat 

traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Require minor boiler pressure part modification for OFA ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-19 

Design Concept Definition

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Low NOx Burners and OFA System with HERT 

Process Description Low NOx Burners (LNBs) with overfire air (OFA) system. High Energy Reagent Technology (HERT) system for post-combustion 

reduction of NOx. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.20 

 lb/hr 373 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Fuel and air balancing performed for each burner. Addition of coal flow monitors in 

coal pipes leading to burner. Addition of water cannon system to boiler wall. Injection skid and 

urea tank at grade with truck unloading station. Urea pumped to injection location in heat 

traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Require minor boiler pressure part modification for OFA ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-20 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Mobotec ROTAMIX 

Process Description Installation of Mobotec ROTAMIX system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.45 

 lb/hr 838 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Urea pumped to injection 

location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for Rotamix ports. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for ROTAMIX is urea. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-21 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology LNB and Mobotec ROTAMIX 

Process Description Installation of Low NOx Burners and Mobotec ROTAMIX system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.30 

 lb/hr 559 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Addition of coal flow monitors in coal pipes leading to burner. Addition of water 

cannon system to boiler wall. Injection skid and urea tank at grade with truck unloading 

station. Urea pumped to injection location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for Mobotec ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for ROTAMIX is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-22 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Mobotec ROFA 

Process Description Installation of Mobotec rotating overfire air (ROFA) system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.28 

 lb/hr 522 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Mobotec overfire air ports installed on sides of the furnace in locations to be determined by flow 

modeling. 

Inlet/Outlet Connections and Interconnecting Ducts Injection points tied into a new booster fan. Fan inlet connected to pre-combustion air. 

Reagent Storage None. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Auxiliary upgrades expected to power booster fan. 

Enclosures Requirements 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for ROFA ports. Location of the booster fan to be 

determined, new foundations for fan will be required. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-23 

Design Concept Definition 

Site Name Four Corners Unit 2 

Client Name Arizona Public Service Process Technology Mobotec ROFA with ROTAMIX 

Process Description Installation of Mobotec ROFA along with ROTAMIX for post-combustion NOx reduction. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.64 

 lb/hr 1,193 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.19 

 lb/hr 354 

 Inlet Flow Basis, acfm 1,093,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Urea pumped to injection 

location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Auxiliary power systems modifications expected to accommodate new booster fan. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-24 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Upgraded Boiler Optimization System (Neural Network) 

Process Description Upgrade existing boiler optimization system (Neuco neural network system) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.56 

 lb/hr 1,344 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Computer hardware and software for boiler optimization system located in control room near the 

DCS. Dampers and actuators are assumed to be operational and DCS controlled. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Interface with existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

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

No air heater modifications or boiler/duct stiffening included. 

The upgrade/replacement may increase boiler efficiency and cause a slight reduction in operating costs. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-25 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Low NOx Burners and Overfire Air System (OFA) 

Process Description Installation of Low NOx burners and opposed overfire air system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.33 

 lb/hr 792 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other Possible slight increase in LOI, unburned carbon and CO. 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Addition of coal flow monitors in coal pipes leading to burner. Fuel and air balancing 

performed for each burner. Addition of water cannon system to boiler wall. CFD modeling to 

ensure uniform flow pattern, temperature distribution and air balancing for OFA system. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Addition of NOx optimization into combustion monitoring process. 

Fan Modifications None. 

Power Supply/Aux Power Modifications No significant aux power impacts from additional equipments. 

Enclosures Requirements None. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Potential risk of boiler slagging. 

Other Assumptions 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-26 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Selective Catalytic Reduction (SCR) 

Process Description Selective Catalytic Reduction (SCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.06 

 lb/hr 144 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Energy TBD kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Not applicable 

 Other 2 ppm ammonia slip (max) 

Location of Major Process Equipment SCR to be installed on the south side of Unit 3. A new air heater will be installed along with the 

SCR. Install NH3 vaporizers at grade. 

Inlet/Outlet Connections and Interconnecting Ducts Existing secondary air heaters demolished to allow room for ductwork connections. SCR inlet 

connected to old air heater outlet, new air heater outlet duct connected to venturi scrubber inlet. 

Reagent Storage Locate urea storage at grade in suitable location and pump through heat traced line to SCR 

location 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume modification or addition of fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume upgrade will be required for aux electric system. 

Enclosures Requirements Analyzer shelters. 

Demolition or Relocation Requirements Existing economizer outlet ductwork including existing air heater. 

Major Constructability Issues Tying the SCR into the existing ductwork after air heater demolition. Construction may limit 

road access. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning. 

Need to use urea based SCR system due to safety concerns. 

SO3 mitigation system may be required. 

Other Assumptions 

No major impact in plant availability. 

Temperature range of flue gas at economizer inlet is acceptable. 

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

Existing air heater demolition, new air heater installation, flue gas handling systems and urea handling systems included. 

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

Reagent is urea. 

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

Energy consumption includes ID fan power requirements to overcome SCR system resistance. 

No noise abatement costs have been included. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-27 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology LNB and OFA with Selective Catalytic Reduction (SCR) 

Process Description Selective Catalytic Reduction (SCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.06 

 lb/hr 144 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Energy TBD kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Not applicable 

 Other 2 ppm ammonia slip (max) 

Location of Major Process Equipment SCR to be installed on the south side of Unit 3. A new air heater will be installed along with the 

SCR. Install urea decomposition chamber at grade. Install new burners in the existing burner 

openings. Install OFA ports to support new Low NOx Burners. Addition of coal flow monitors in 

coal pipes leading to burner. Addition of water cannon system to boiler wall. 

Inlet/Outlet Connections and Interconnecting Ducts Existing air heater demolished to allow room for ductwork connections. SCR inlet connected to 

old air heater outlet, SCR outlet duct connected to venturi scrubber inlet. 

Reagent Storage Locate urea storage at grade in suitable location and pump through heat traced line to SCR 

location 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume upgrade will be required for aux electric system. 

Enclosures Requirements Ammonia injection grid area and sonic horns are to be enclosed. 

Demolition or Relocation Requirements Existing economizer outlet ductwork and boiler building wall. 

Major Constructability Issues Tying the SCR into the existing ductwork after air heater demolition. Very limited crane access 

to Unit 2. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning and/or washing. 

Need to use urea based SCR system due to safety concerns. 

Other Assumptions 

No major impact in plant availability. 

Temperature range of flue gas at economizer inlet is acceptable over entire design load range. 

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

Existing air heater demolition, new air heater installation, flue gas handling systems and urea handling systems included. 

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

Reagent is urea. 

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

Energy consumption includes booster fan power requirements to overcome SCR system resistance. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-28 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Selective Non-Catalytic Reduction (SNCR) 

Process Description Selective Non-Catalytic Reduction (SNCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.46 

 lb/hr 1,104 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost. 

Byproduct Description Assumed no impact on ash sales. 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Solution pumped in heat 

traced line to SNCR lances. 

Inlet/Outlet Connections and Interconnecting Ducts Install wall injectors and lance-type injectors for SNCR in the boiler. 

Reagent Storage Urea tank at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning and/or washing. 

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. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-29 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Low NOx Burners and OFA System with SNCR 

Process Description Low NOx Burners (LNBs) with opposed overfire air (OFA) system. Selective Non-Catalytic Reduction (SNCR) system for postcombustion reduction of NOx. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.26 

 lb/hr 624 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO, Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Fuel and air balancing performed for each burner. Addition of coal flow monitors in 

coal pipes leading to burner. Addition of water cannon system to boiler wall. Injection skid and 

urea tank at grade with truck unloading station. Urea pumped to injection location in heat 

traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Require minor boiler pressure part modification for OFA ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-30 

Design Concept Definition

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Low NOx Burners and OFA System with HERT 

Process Description Low NOx Burners (LNBs) with opposed overfire air (OFA) system. High Energy Reagent Technology (HERT) system for postcombustion reduction of NOx. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.20 

 lb/hr 480 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO, Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Fuel and air balancing performed for each burner. Addition of coal flow monitors in 

coal pipes leading to burner. Addition of water cannon system to boiler wall. Injection skid and 

urea tank at grade with truck unloading station. Urea pumped to injection location in heat 

traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Require minor boiler pressure part modification for OFA ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-31 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Mobotec ROTAMIX 

Process Description Installation of Mobotec ROTAMIX system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.45 

 lb/hr 1,080 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Urea pumped to injection 

location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for Rotamix ports. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for ROTAMIX is urea. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-32 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology LNB and Mobotec ROTAMIX 

Process Description Installation of Low NOx Burners and Mobotec ROTAMIX system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.30 

 lb/hr 720 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Addition of coal flow monitors in coal pipes leading to burner. Addition of water 

cannon system to boiler wall. Injection skid and urea tank at grade with truck unloading 

station. Urea pumped to injection location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for Mobotec ports. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for ROTAMIX is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-33 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Mobotec ROFA 

Process Description Installation of Mobotec rotating overfire air (ROFA) system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.28 

 lb/hr 672 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Overfire air ports installed on sides of the furnace in locations to be determined by flow 

modeling. 

Inlet/Outlet Connections and Interconnecting Ducts Injection points tied into a new booster fan. Fan inlet connected to pre-combustion air. 

Reagent Storage None. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Auxiliary upgrades expected to power booster fan. 

Enclosures Requirements 

Demolition or Relocation Requirements None. 

Major Constructability Issues Minor modification to boiler pressure parts for ROFA ports. Location of the booster fan to be 

determined, new foundations for fan will be required. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-34 

Design Concept Definition 

Site Name Four Corners Unit 3 

Client Name Arizona Public Service Process Technology Mobotec ROFA with ROTAMIX 

Process Description Installation of Mobotec ROFA along with ROTAMIX for post-combustion NOx reduction. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.59 

 lb/hr 1,408 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.19 

 lb/hr 456 

 Inlet Flow Basis, acfm 1,465,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI, unburned carbon and CO. Assumed no impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Injection skid and urea tank at grade with truck unloading station. Urea pumped to injection 

location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Auxiliary power systems modifications expected to accommodate new booster fan. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales. 

Reagent for SNCR is urea. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-35 

Design Concept Definition 

Site Name Four Corners Units 4 & 5 

Client Name Arizona Public Service Process Technology Upgraded Boiler Optimization System (Neural Network) 

Process Description Upgrade existing boiler optimization system (Neuco neural network system) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.49 

 lb/hr 3,856 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.47 

 lb/hr 3,669 

 Inlet Flow Basis, acfm 4,225,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other None 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Computer hardware and software for boiler optimization system located in control room near the 

DCS. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Interface with existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. 

Other Assumptions 

No major impact in plant availability. 

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

No air heater modifications or boiler/duct stiffening included. 

The upgrade/replacement may increase boiler efficiency and cause a slight reduction in operating costs. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-36 

Design Concept Definition 

Site Name Four Corners Units 4 & 5 

Client Name Arizona Public Service Process Technology Low NOx Burners and Overfire Air System (OFA) 

Process Description Installation of Low NOx burners and opposed overfire air system. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.49 

 lb/hr 3,856 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.35 

 lb/hr 2,732 

 Inlet Flow Basis, acfm 4,225,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent None 

 Energy N/A kW 

 Other Possible slight increase in LOI and CO. 

Byproduct Description None 

 Other N/A 

Location of Major Process Equipment Install new burners in the existing burner openings. Install OFA ports to support new Low NOx 

Burners. Addition of coal flow monitors in coal pipes leading to burner. Addition of water 

cannon system to boiler wall. 

Inlet/Outlet Connections and Interconnecting Ducts None. 

Reagent Storage None. 

Control System Modifications Addition of NOx optimization into combustion monitoring process. 

Fan Modifications None. 

Power Supply/Aux Power Modifications No significant aux power impacts from additional equipments. 

Enclosures Requirements None. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Potential risk of boiler slagging. 

Other Assumptions 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-37 

Design Concept Definition 

Site Name Four Corners Units 4 & 5 

Client Name Arizona Public Service Process Technology Selective Catalytic Reduction (SCR) 

Process Description Selective Catalytic Reduction (SCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.49 

 lb/hr 3,856 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.06 

 lb/hr 468 

 Inlet Flow Basis, acfm 4,225,000 

 Pressure Drop Added 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Energy TBD kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Not applicable 

 Other 2 ppm ammonia slip (max) 

Location of Major Process Equipment SCR to be installed above the ductwork transition from the air heater to the fabric filters. Install 

NH3 vaporizers at grade. 

Inlet/Outlet Connections and Interconnecting Ducts SCR inlet and outlet ducts connected into duct entering the economizer. 

Reagent Storage Locate urea storage at grade in suitable location and pump through heat traced line to SCR 

location 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume modification or addition of fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume upgrade will be required for aux electric system. 

Enclosures Requirements Ammonia injection grid area and sonic horns are to be enclosed. 

Demolition or Relocation Requirements Existing economizer outlet ductwork. 

Major Constructability Issues Tying the SCR into the existing ductwork. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning. 

Urea based SCR system due to safety concerns. 

Other Assumptions 

No major impact in plant availability. 

Temperature range of flue gas at economizer inlet is acceptable. 

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

Existing air heater demolition, new air heater installation, flue gas handling systems and urea handling systems included. 

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

Reagent is urea. 

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

Energy consumption includes ID fan power requirements to overcome SCR system resistance. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-38 

Design Concept Definition 

Site Name Four Corners Units 4 & 5 

Client Name Arizona Public Service Process Technology LNB and OFA with Selective Catalytic Reduction (SCR) 

Process Description Selective Catalytic Reduction (SCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.50 

 lb/hr 3,856 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.06 

 lb/hr 468 

 Inlet Flow Basis, acfm 4,225,000 

 Pressure Drop Added 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Energy TBD kW 

 Catalyst Add and/or replace one catalyst layer every 3 years. 

 Maintenance 3% of direct material cost. 

Byproduct Description Not applicable 

 Other 2 ppm ammonia slip (max) 

Location of Major Process Equipment SCR to be installed above the ductwork transition from the air heater to the fabric filters. Install 

NH3 vaporizers at grade. Install new burners in the existing burner openings. Install OFA ports 

to support new Low NOx Burners. Addition of coal flow monitors in coal pipes leading to burner. 

Addition of water cannon system to boiler wall. 

Inlet/Outlet Connections and Interconnecting Ducts SCR inlet and outlet ducts connected into duct entering the economizer. 

Reagent Storage Locate urea storage at grade in suitable location and pump through heat traced line to SCR 

location 

Control System Modifications Incorporated into existing control system. 

Fan Modifications Assume booster fans and duct stiffening will be required. 

Power Supply/Aux Power Modifications Assume upgrade will be required for aux electric system. 

Enclosures Requirements Ammonia injection grid area and sonic horns are to be enclosed. 

Demolition or Relocation Requirements Existing economizer outlet ductwork. 

Major Constructability Issues Tying the SCR into the existing ductwork. 

Significant Issues or Challenges Ammonia slip in the SCR may cause ammonium bisulfate formation on the air heater and 

require more frequent cleaning. 

Need to use urea based SCR system due to safety concerns. 

Other Assumptions 

No major impact in plant availability. 

Temperature range of flue gas at economizer inlet is acceptable. 

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

Existing air heater demolition, new air heater installation, flue gas handling systems and urea handling systems included. 

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

Reagent is urea. 

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

Energy consumption includes ID fan power requirements to overcome SCR system resistance. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-39 

Design Concept Definition 

Site Name Four Corners Units 4 & 5 

Client Name Arizona Public Service Process Technology Selective Non-Catalytic Reduction (SNCR) 

Process Description Selective Non-Catalytic Reduction (SNCR) 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.49 

 lb/hr 3,856 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.38 

 lb/hr 2,927 

 Inlet Flow Basis, acfm 4,225,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 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 Injection skid and urea tank at grade with truck unloading station. Solution pumped in heat 

traced line to SNCR lances. 

Inlet/Outlet Connections and Interconnecting Ducts Install wall injectors and lance-type injectors for SNCR in the boiler. 

Reagent Storage Urea tank at grade. 

Control System Modifications Incorporated into existing control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements None. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisulfate on the air heater, which may require 

more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included. 

Air heater modifications included in analysis. 

No expected impact on ash sales if ammonia slip is controlled to design condition. 

Reagent is urea. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix C 

102907 C-40 

Design Concept Definition 

Site Name Four Corners Units 4 & 5 

Client Name Arizona Public Service Process Technology Low NOx Burners and OFA System with SNCR 

Process Description Low NOx Burners (LNBs) with opposed overfire air (OFA) system. Selective Non-Catalytic Reduction (SNCR) system for postcombustion reduction of NOx. 

 Pollutant NOx 

 Baseline Emissions 

 lb/mmBtu 0.49 

 lb/hr 3,856 

 Controlled Emissions from Baseline 

 lb/mmBtu 0.26 

 lb/hr 2,030 

 Inlet Flow Basis, acfm 4,225,000 

 Pressure Drop Added NA 

 Coal Type Mine Mouth 

 Capacity factor 91.0% 

Consumables Reagent (Urea) TBD lb/hr 

 Water TBD gpm 

 Energy TBD kW 

 Maintenance 3% of direct material cost for equipment maintenance. 

Byproduct Description Slight increase in LOI and CO, No impact on ash sales 

 Other Up to 5 ppm ammonia slip. 

Location of Major Process Equipment Upgrade existing burners. Location remains the same. Injection skid and urea tank at grade 

with truck unloading station. Urea pumped to injection location in heat traced lines. 

Inlet/Outlet Connections and Interconnecting Ducts Tie-in to existing air duct and coal pipes. Install injectors for SNCR in boiler. 

Reagent Storage Urea tank for SNCR at grade with injection skid. 

Control System Modifications Control of additional equipment incorporated into current control system. 

Fan Modifications None. 

Power Supply/Aux Power Modifications Minimum impact/modifications. 

Enclosures Requirements Enclosed already in existing boiler building. 

Demolition or Relocation Requirements None. 

Major Constructability Issues None. 

Significant Issues or Challenges Keep LOI and CO within acceptable levels. Ammonia slip may cause buildup of ammonium 

bisulfate on the air heater, which may require more frequent cleaning. 

Other Assumptions 

No major impact in plant availability. 

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

No boiler/duct stiffening included and no impact on ash sales if ammonia slip is controlled to design condition. 

Reagent for SNCR is urea. 

Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SNCR because of lower NOx concentration. 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix D 

102907 D-1 

Appendix D 

Cost Calculations 
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 1B

Technology: Combustion Optimization System Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Subtotal capital cost (CC) $470,000 Eng. Estimate

Taxes $47,000 (CC) X 10.0%

Freight $28,200 (CC) X 6.0%

Total purchased equipment cost (PEC) $545,000

Direct installation costs

Air and Fuel Balancing $200,000 Eng. Estimate

Foundation & supports $27,000 (PEC) X 5.0%

Handling & erection $55,000 (PEC) X 10.0%

Electrical $55,000 (PEC) X 10.0%

Piping $16,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $11,000 (PEC) X 2.0%

Relocation $11,000 (PEC) X 2.0%

Taxes $37,500 @10%

Total direct installation costs (DIC) $412,500

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $958,000

Indirect Costs

Engineering $67,000 (DC) X 7.0%

Owners Cost $29,000 (DC) X 3.0%

Construction and field expenses $96,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $144,000 (DC) X 15.0%

Total indirect costs (IC) $471,000

Total Capital Investment (TCI) = (DC) + (IC) $1,429,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $86,000 (DC) X 9.0%

Total fixed annual costs $86,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $86,000

Total direct annual costs $124,811 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $228,000 15% interest rate 

Total indirect annual costs (IDAC) $228,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $314,000

Total Annual Cost with Levelization Factor $352,811
Four Corners BART Analysis - Cost Analysis

Unit: 1

Case Identifier: 2L

Technology: Low NOx Burners (LNB) Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs $1,000,000 Budgetary Quotation

Subtotal capital cost (CC) $1,000,000

Taxes $100,000 (CC) X 10.0%

Freight $60,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,160,000

Direct installation costs

Foundation & supports $0 N/A

Handling, erection and installation $563,000 Budgetary Quotation

Demolition $93,000 (PEC) X 8.0%

Taxes $65,600 @10%

Total direct installation costs (DIC) $721,600

Boiler Modifications $500,000 APS Eng. Estimate

Flame Scanning System $350,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $2,732,000

Indirect Costs

Engineering $191,000 (DC) X 7.0%

Owners Cost $82,000 (DC) X 3.0%

Construction and field expenses $273,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $410,000 (DC) X 15.0%

Total indirect costs (IC) $1,091,000

Total Capital Investment (TCI) = (DC) + (IC) $3,823,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $246,000 (DC) X 9.0%

Total fixed annual costs $246,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $246,000

Total direct annual costs $357,017 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $611,000 15% interest rate 

Total indirect annual costs (IDAC) $611,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $857,000

Total Annual Cost with Levelization Factor $968,017
Four Corners BART Analysis - Cost Analysis

Unit: 1

Case Identifier: 2LO

Technology: Low NOx Burners (LNB) and Overfire Air (OFA) Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs $1,375,000 Budgetary Quotation

Subtotal capital cost (CC) $1,375,000

Taxes $137,500 (CC) X 10.0%

Freight $82,500 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,595,000

Direct installation costs

Foundation & supports $0 N/A

Handling, erection and installation $812,500 Budgetary Quotation

Demolition $128,000 (PEC) X 8.0%

Taxes $94,050 @10%

Total direct installation costs (DIC) $1,034,550

Boiler Modifications $500,000 APS Eng. Estimate

Flow Model $35,000 Eng. Estimate

Flame Scanning System $350,000 Eng. Estimate

Control System and Communication Modification $350,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,865,000

Indirect Costs

Engineering $271,000 (DC) X 7.0%

Owners Cost $116,000 (DC) X 3.0%

Construction and field expenses $387,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $580,000 (DC) X 15.0%

Total indirect costs (IC) $1,489,000

Total Capital Investment (TCI) = (DC) + (IC) $5,354,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $348,000 (DC) X 9.0%

Total fixed annual costs $348,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $348,000

Total direct annual costs $505,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $856,000 15% interest rate 

Total indirect annual costs (IDAC) $856,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,204,000

Total Annual Cost with Levelization Factor $1,361,000
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 3B

Technology: Selective Non-Catalytic Reduction Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $722,000 from CUECost

Initial ammonia inventory $313,000 from CUECost

Air preheater modifications $442,000 from CUECost

Subtotal capital cost (CC) $1,477,000

Taxes $148,000 (CC) X 10.0%

Freight $89,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,714,000

Direct installation costs

Foundation & supports $86,000 (PEC) X 5.0%

Handling & erection $171,000 (PEC) X 10.0%

Electrical $171,000 (PEC) X 10.0%

Piping $51,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $69,000 (PEC) X 4.0%

Relocation $34,000 (PEC) X 2.0%

Taxes $58,200 @10%

Total direct installation costs (DIC) $640,200

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,454,000

Indirect Costs

Engineering $172,000 (DC) X 7.0%

Owners Cost $74,000 (DC) X 3.0%

Construction and field expenses $245,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $74,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $368,000 (DC) X 15.0%

Total indirect costs (IC) $968,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $5,572,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $221,000 (DC) X 9.0%

Total fixed annual costs $321,000

Variable annual costs

Reagent $1,903,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $1,912,000

Total direct annual costs (DAC) $2,233,000

Total direct annual costs $3,241,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $890,000 15% interest rate 

Total indirect annual costs (IDAC) $890,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,123,000

Total Annual Cost with Levelization Factor $4,131,000
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 3L

Technology: Selective Non-Catalytic Reduction with LNB Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $659,000 from CUECost

Initial ammonia inventory $172,000 from CUECost

Air preheater modifications $442,000 from CUECost

Subtotal capital cost (CC) $1,273,000

Taxes $127,000 (CC) X 10.0%

Freight $76,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,476,000

Direct installation costs

Foundation & supports $74,000 (PEC) X 5.0%

Handling & erection $148,000 (PEC) X 10.0%

Electrical $148,000 (PEC) X 10.0%

Piping $44,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $59,000 (PEC) X 4.0%

Relocation $30,000 (PEC) X 2.0%

Taxes $50,300 @10%

Total direct installation costs (DIC) $553,300

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,129,000

Indirect Costs

Engineering $149,000 (DC) X 7.0%

Owners Cost $64,000 (DC) X 3.0%

Construction and field expenses $213,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $64,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $319,000 (DC) X 15.0%

Total indirect costs (IC) $844,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner Capital Investment $3,823,000

Total Capital Investment (TCI) = (DC) + (IC) $8,946,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $192,000 (DC) X 9.0%

Total fixed annual costs $292,000

Variable annual costs

Reagent $1,046,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $1,055,000

Total direct annual costs (DAC) $1,347,000

Total direct annual costs $1,955,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,430,000 15% interest rate 

Total indirect annual costs (IDAC) $1,430,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,777,000

Total Annual Cost with Levelization Factor $3,385,000
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 3LO

Technology: Selective Non-Catalytic Reduction with LNB and OFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $635,000 from CUECost

Initial ammonia inventory $132,000 from CUECost

Air preheater modifications $442,000 from CUECost

Subtotal capital cost (CC) $1,209,000

Taxes $121,000 (CC) X 10.0%

Freight $73,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,403,000

Direct installation costs

Foundation & supports $70,000 (PEC) X 5.0%

Handling & erection $140,000 (PEC) X 10.0%

Electrical $140,000 (PEC) X 10.0%

Piping $42,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $56,000 (PEC) X 4.0%

Relocation $28,000 (PEC) X 2.0%

Taxes $47,600 @10%

Total direct installation costs (DIC) $523,600

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,027,000

Indirect Costs

Engineering $142,000 (DC) X 7.0%

Owners Cost $61,000 (DC) X 3.0%

Construction and field expenses $203,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $61,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $304,000 (DC) X 15.0%

Total indirect costs (IC) $806,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner and Overfire Air Capital Investment $5,354,000

Total Capital Investment (TCI) = (DC) + (IC) $10,337,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $182,000 (DC) X 9.0%

Total fixed annual costs $282,000

Variable annual costs

Reagent $803,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $812,000

Total direct annual costs (DAC) $1,094,000

Total direct annual costs $1,588,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,652,000 15% interest rate 

Total indirect annual costs (IDAC) $1,652,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,746,000

Total Annual Cost with Levelization Factor $3,240,000
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 7LO

Technology: ULNB,OFA & HERT Date: 8/23/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

High energy reagent technology (HERT) $500,000 Budgetary Quotation

Initial ammonia inventory $132,000 from CUECost

Air preheater modifications $442,000 from CUECost

Subtotal capital cost (CC) $1,074,000

Taxes $107,000 (CC) X 10.0%

Freight $64,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,245,000

Direct installation costs

Foundation & supports $62,000 (PEC) X 5.0%

Handling & erection $125,000 (PEC) X 10.0%

Electrical $125,000 (PEC) X 10.0%

Piping $37,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $50,000 (PEC) X 4.0%

Relocation $25,000 (PEC) X 2.0%

Taxes $42,400 @10%

Total direct installation costs (DIC) $466,400

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $1,811,000

Indirect Costs

Engineering $127,000 (DC) X 7.0%

Owners Cost $54,000 (DC) X 3.0%

Construction and field expenses $181,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $54,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $272,000 (DC) X 15.0%

Total indirect costs (IC) $723,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner and Overfire Air Capital Investment $5,354,000

Total Capital Investment (TCI) = (DC) + (IC) $10,038,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $163,000 (DC) X 9.0%

Total fixed annual costs $263,000

Variable annual costs

Reagent $803,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $812,000

Total direct annual costs (DAC) $1,075,000

Total direct annual costs $1,560,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,604,000 15% interest rate 

Total indirect annual costs (IDAC) $1,604,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,679,000

Total Annual Cost with Levelization Factor $3,164,000
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 4B

Technology: Mobotec ROTAMIX Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $2,133,383 Budgetary Quotation

Subtotal (CC) $2,133,383

Instruments and controls $43,000 (CC) X 2.0%

Taxes $213,000 (CC) X 10.0%

Freight $107,000 (CC) X 5.0%

Total Cost (PEC) $2,496,000

Direct installation costs $443,000 Budgetary Quotation

Demolition $100,000 (PEC) X 4.0%

Taxes $54,300 @10%

Total direct installation costs (DIC) $597,300

Chemical Pump Enclosure $100,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,693,000

Indirect Costs

Engineering $259,000 (DC) X 7.0%

Owners Cost $111,000 (DC) X 3.0%

Construction and field expenses $369,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $111,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $554,000 (DC) X 15.0%

Total indirect costs (IC) $1,439,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $7,282,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $332,000 (DC) X 9.0%

Total fixed annual costs $404,000

Variable annual costs

Reagent $2,699,000

Auxiliary and ID fan power $10,000

Total variable annual costs $2,709,000

Total direct annual costs (DAC) $3,113,000

Total direct annual costs $4,518,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,164,000 15% interest rate 

Total indirect annual costs (IDAC) $1,164,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $4,277,000

Total Annual Cost with Levelization Factor $5,682,000
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 4L

Technology: Mobotec ROTAMIX with LNB Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $2,133,383 Budgetary Quotation

Subtotal (CC) $2,133,383

Instruments and controls $43,000 (CC) X 2.0%

Taxes $213,000 (CC) X 10.0%

Freight $107,000 (CC) X 5.0%

Total Cost (PEC) $2,496,000

Direct installation costs $443,000 Budgetary Quotation

Demolition $100,000 (PEC) X 4.0%

Taxes $54,300 @10%

Total direct installation costs (DIC) $597,300

Chemical Pump Enclosure $100,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,693,000

Indirect Costs

Engineering $259,000 (DC) X 7.0%

Owners Cost $111,000 (DC) X 3.0%

Construction and field expenses $369,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $111,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $554,000 (DC) X 15.0%

Total indirect costs (IC) $1,439,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low NOx Burner Capital Investment $3,823,000

Total Capital Investment (TCI) = (DC) + (IC) $11,105,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $332,000 (DC) X 9.0%

Total fixed annual costs $404,000

Variable annual costs

Reagent $1,319,000

Auxiliary and ID fan power $10,000

Total variable annual costs $1,329,000

Total direct annual costs (DAC) $1,733,000

Total direct annual costs $2,515,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,775,000 15% interest rate 

Total indirect annual costs (IDAC) $1,775,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,508,000

Total Annual Cost with Levelization Factor $4,290,000
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 5B

Technology: Mobotec ROFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $4,152,292 Budgetary Quotation

Subtotal (CC) $4,152,292

Instruments and controls $83,000 (CC) X 2.0%

Taxes $415,000 (CC) X 10.0%

Freight $208,000 (CC) X 5.0%

Total Cost (PEC) $4,858,000

Direct installation costs $956,000 Budgetary Quotation

Demolition $194,000 (PEC) X 4.0%

Taxes $115,000 @10%

Total direct installation costs (DIC) $1,265,000

Control System and Communication Modification $350,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $6,973,000

Indirect Costs

Engineering $488,000 (DC) X 7.0%

Owners Cost $209,000 (DC) X 3.0%

Construction and field expenses $697,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $209,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $1,046,000 (DC) X 15.0%

Total indirect costs (IC) $2,684,000

Total Capital Investment (TCI) = (DC) + (IC) $9,657,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 1 Operator

Maintenance labor & materials $628,000 (DC) X 9.0%

Total fixed annual costs $700,000

Variable annual costs

Reagent N/A

Auxiliary and ID fan power $713,000

Total variable annual costs $713,000

Total direct annual costs (DAC) $1,413,000

Total direct annual costs $2,051,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,543,000 15% interest rate 

Total indirect annual costs (IDAC) $1,543,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,956,000

Total Annual Cost with Levelization Factor $3,594,000
Four Corners BART Analysis - Cost Analysis 

Unit: 1

Case Identifier: 4 & 5B

Technology: Mobotec ROTAMIX and ROFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $5,058,342 Budgetary Quotation

Subtotal (CC) $5,058,342

Instruments and controls $101,000 (CC) X 2.0%

Taxes $506,000 (CC) X 10.0%

Freight $253,000 (CC) X 5.0%

Total Cost (PEC) $5,918,000

Direct installation costs $1,399,000 Budgetary Quotation

Demolition $237,000 (PEC) X 4.0%

Taxes $163,600 @10%

Total direct installation costs (DIC) $1,799,600

Chemical Pump Enclosure $100,000 Eng. Estimate

Boiler Modifications $500,000 N/A

Total direct costs (DC) = (PEC) + (DIC) $8,318,000

Indirect Costs

Engineering $582,000 (DC) X 7.0%

Owners Cost $250,000 (DC) X 3.0%

Construction and field expenses $832,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $250,000 (DC) X 3.0%

Performance test $42,000 (DC) X 0.5%

Contingencies $1,248,000 (DC) X 15.0%

Total indirect costs (IC) $3,204,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $13,672,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $749,000 (DC) X 9.0%

Total fixed annual costs $821,000

Variable annual costs

Reagent $911,000

Auxiliary and ID fan power $306,000

Total variable annual costs $1,217,000

Total direct annual costs (DAC) $2,038,000

Total direct annual costs $2,958,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $2,185,000 15% interest rate 

Total indirect annual costs (IDAC) $2,185,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $4,223,000

Total Annual Cost with Levelization Factor $5,143,000
Four Corners BART Analysis - Cost Analysis

Unit: 1

Case Identifier: 6B

Technology: Selective Catalytic Reduction Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,516,000 adjusted from CUECost

Urea handling and injection $2,175,000 adjusted from CUECost

Initial catalyst $1,695,000 from CUECost

Initial Urea $286,000 adjusted from CUECost

Flue gas handling and ductwork $2,475,000 adjusted from CUECost

New Air Preheater $2,100,000 Eng. Estimate

New FD Fans $1,550,000 Eng. Estimate

FD Fan VFD $1,740,000 Eng. Estimate

New ID Fans $2,800,000 Eng. Estimate

ID Fan VFD $2,700,000 Eng. Estimate

New Electrical Substation $1,500,000 Eng. Estimate

Misc. equipment $270,000 from CUECost

Instruments and controls $123,000 from CUECost

Subtotal (CC) $22,930,000

Taxes $2,293,000 (CC) X 10.0%

Freight $1,147,000 (CC) X 5.0%

Total Cost (PEC) $26,370,000

Direct installation costs

Foundation & supports $9,230,000 (PEC) X 35.0%

Handling & erection $6,593,000 (PEC) X 25.0%

Electrical $5,274,000 (PEC) X 20.0%

Piping $659,000 (PEC) X 2.5%

Insulation $2,637,000 (PEC) X 10.0%

Painting $264,000 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $396,000 (PEC) X 1.5%

Taxes $2,655,300 @10%

Total direct installation costs (DIC) $29,208,300

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $58,078,000

Indirect Costs

Engineering $8,712,000 (DC) X 15.0%

Owners Cost $1,742,000 (DC) X 3.0%

Construction and field expenses $5,808,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,742,000 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $8,711,700 (DC) X 15.0%

Total indirect costs (IC) $26,831,000

Unintended Consequences (UC)

Lost Revenue $1,176,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,326,000

Total Capital Investment (TCI) = (DC) + (IC) $88,235,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $68,000 from CUECost

Maintenance labor & materials $1,742,000 (DC) X 3.0%

Total fixed annual costs $1,810,000

Variable annual costs

Reagent $871,000 from CUECost

Auxiliary and ID fan power $442,000 from CUECost

Steam $51,000 from CUECost

Catalyst replacement $565,000 from CUECost

Catalyst disposal $217,000 from CUECost

Total variable annual costs $2,146,000

Total direct annual costs (DAC) $3,956,000

Total direct annual costs $5,741,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $14,100,000 15% interest rate 

Total indirect annual costs (IDAC) $14,100,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $18,056,000

Total Annual Cost with Levelization Factor $19,841,000
Four Corners BART Analysis - Cost Analysis

Unit: 1

Case Identifier: 6L

Technology: Selective Catalytic Reduction with LNB Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,497,000 adjusted from CUECost

Urea handling and injection $1,630,000 adjusted from CUECost

Initial catalyst $1,676,000 from CUECost

Initial Urea $157,000 adjusted from CUECost

Flue gas handling and ductwork $2,475,000 adjusted from CUECost

New Air Preheater $2,100,000 Eng. Estimate

New FD Fans $1,550,000 Eng. Estimate

FD Fan VFD $1,740,000 Eng. Estimate

New ID Fans $2,800,000 Eng. Estimate

ID Fan VFD $2,700,000 Eng. Estimate

New Electrical Substation $1,500,000 Eng. Estimate

Misc. equipment $270,000 from CUECost

Instruments and controls $118,000 from CUECost

Subtotal (CC) $22,213,000

Taxes $2,221,000 (CC) X 10.0%

Freight $1,111,000 (CC) X 5.0%

Total Cost (PEC) $25,545,000

Direct installation costs

Foundation & supports $8,941,000 (PEC) X 35.0%

Handling & erection $6,386,000 (PEC) X 25.0%

Electrical $5,109,000 (PEC) X 20.0%

Piping $639,000 (PEC) X 2.5%

Insulation $2,555,000 (PEC) X 10.0%

Painting $255,000 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $383,000 (PEC) X 1.5%

Taxes $2,576,800 @10%

Total direct installation costs (DIC) $28,344,800

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $56,390,000

Indirect Costs

Engineering $8,459,000 (DC) X 15.0%

Owners Cost $1,692,000 (DC) X 3.0%

Construction and field expenses $5,639,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,692,000 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $8,459,000 (DC) X 15.0%

Total indirect costs (IC) $26,056,000

Unintended Consequences (UC)

Lost Revenue $1,176,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,326,000

SCR Total Capital Investment $85,772,000

LNB TCI $3,823,000

Total Capital Investment (TCI) = (DC) + (IC) $89,595,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $68,000 from CUECost

Maintenance labor & materials $1,692,000 (DC) X 3.0%

Total fixed annual costs $1,760,000

Variable annual costs

Reagent $479,000 from CUECost

Auxiliary and ID fan power $442,000 from CUECost

Steam $28,000 from CUECost

Catalyst replacement $559,000 from CUECost

Catalyst disposal $215,000 from CUECost

Total variable annual costs $1,723,000

Total direct annual costs (DAC) $3,483,000

Total direct annual costs $5,055,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $14,317,000 15% interest rate 

Total indirect annual costs (IDAC) $14,317,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $17,800,000

Total Annual Cost with Levelization Factor $19,372,000
Four Corners BART Analysis - Cost Analysis

Unit: 1

Case Identifier: 6LO

Technology: Selective Catalytic Reduction with LNB and OFA Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,478,000 adjusted from CUECost

Urea handling and injection $1,435,000 adjusted from CUECost

Initial catalyst $1,657,000 from CUECost

Initial Urea $121,000 adjusted from CUECost

Flue gas handling and ductwork $2,475,000 adjusted from CUECost

New Air Preheater $2,100,000 Eng. Estimate

New FD Fans $1,550,000 Eng. Estimate

FD Fan VFD $1,740,000 Eng. Estimate

New ID Fans $2,800,000 Eng. Estimate

ID Fan VFD $2,700,000 Eng. Estimate

New Electrical Substation $1,500,000 Eng. Estimate

Misc. equipment $270,000 from CUECost

Instruments and controls $116,000 from CUECost

Subtotal (CC) $21,942,000

Taxes $2,194,000 (CC) X 10.0%

Freight $1,097,000 (CC) X 5.0%

Total Cost (PEC) $25,233,000

Direct installation costs

Foundation & supports $8,832,000 (PEC) X 35.0%

Handling & erection $6,308,000 (PEC) X 25.0%

Electrical $5,047,000 (PEC) X 20.0%

Piping $631,000 (PEC) X 2.5%

Insulation $2,523,000 (PEC) X 10.0%

Painting $252,000 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $378,000 (PEC) X 1.5%

Taxes $2,547,100 @10%

Total direct installation costs (DIC) $28,018,100

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $55,751,000

Indirect Costs

Engineering $8,363,000 (DC) X 15.0%

Owners Cost $1,673,000 (DC) X 3.0%

Construction and field expenses $5,575,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,673,000 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $8,363,000 (DC) X 15.0%

Total indirect costs (IC) $25,762,000

Unintended Consequences (UC)

Lost Revenue $1,176,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,326,000

SCR Total Capital Investment $84,839,000

LNB TCI $5,354,000

Total Capital Investment (TCI) = (DC) + (IC) $90,193,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $68,000 from CUECost

Maintenance labor & materials $1,673,000 (DC) X 3.0%

Total fixed annual costs $1,741,000

Variable annual costs

Reagent $367,000 from CUECost

Auxiliary and ID fan power $442,000 from CUECost

Steam $22,000 from CUECost

Catalyst replacement $552,000 from CUECost

Catalyst disposal $213,000 from CUECost

Total variable annual costs $1,596,000

Total direct annual costs (DAC) $3,337,000

Total direct annual costs $4,843,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $14,413,000 15% interest rate 

Total indirect annual costs (IDAC) $14,413,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $17,750,000

Total Annual Cost with Levelization Factor $19,256,000
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 1B

Technology: Combustion Optimization System Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Subtotal capital cost (CC) $470,000 Eng. Estimate

Taxes $47,000 (CC) X 10.0%

Freight $28,200 (CC) X 6.0%

Total purchased equipment cost (PEC) $545,000

Direct installation costs

Air and Fuel Balancing $200,000 Eng. Estimate

Foundation & supports $27,000 (PEC) X 5.0%

Handling & erection $55,000 (PEC) X 10.0%

Electrical $55,000 (PEC) X 10.0%

Piping $16,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $11,000 (PEC) X 2.0%

Relocation $11,000 (PEC) X 2.0%

Taxes $37,500 @10%

Total direct installation costs (DIC) $412,500

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $958,000

Indirect Costs

Engineering $67,000 (DC) X 7.0%

Owners Cost $29,000 (DC) X 3.0%

Construction and field expenses $96,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $144,000 (DC) X 15.0%

Total indirect costs (IC) $471,000

Total Capital Investment (TCI) = (DC) + (IC) $1,429,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $86,000 (DC) X 9.0%

Total fixed annual costs $86,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $86,000

Total direct annual costs $125,000 1.45129 Levelization Facto

Indirect Annual Costs

Cost for capital recovery $228,000 15% interest rate 

Total indirect annual costs (IDAC) $228,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $314,000

Total Annual Cost with Levelization Factor $353,000
Four Corners BART Analysis - Cost Analysis

Unit: 2

Case Identifier: 2L

Technology: Low NOx Burners (LNB) Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs $1,000,000 Budgetary Quotation

Subtotal capital cost (CC) $1,000,000

Taxes $100,000 (CC) X 10.0%

Freight $60,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,160,000

Direct installation costs

Foundation & supports $0 N/A

Handling, erection and installation $563,000 Budgetary Quotation

Demolition $93,000 (PEC) X 8.0%

Taxes $65,600 @10%

Total direct installation costs (DIC) $721,600

Boiler Modifications $500,000 APS Eng. Estimate

Flame Scanning System $350,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $2,732,000

Indirect Costs

Engineering $191,000 (DC) X 7.0%

Owners Cost $82,000 (DC) X 3.0%

Construction and field expenses $273,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $410,000 (DC) X 15.0%

Total indirect costs (IC) $1,091,000

Total Capital Investment (TCI) = (DC) + (IC) $3,823,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $246,000 (DC) X 9.0%

Total fixed annual costs $246,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $246,000

Total direct annual costs $357,000 1.45129 Levelization Facto

Indirect Annual Costs

Cost for capital recovery $611,000 15% interest rate 

Total indirect annual costs (IDAC) $611,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $857,000

Total Annual Cost with Levelization Factor $968,000
Four Corners BART Analysis - Cost Analysis

Unit: 2

Case Identifier: 2LO

Technology: Low NOx Burners (LNB) and Overfire Air (OFA) Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs $1,375,000 Budgetary Quotation

Subtotal capital cost (CC) $1,375,000

Taxes $138,000 (CC) X 10.0%

Freight $83,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,596,000

Direct installation costs

Foundation & supports $0 N/A

Handling, erection and installation $813,000 Budgetary Quotation

Demolition $128,000 (PEC) X 8.0%

Taxes $94,100 @10%

Total direct installation costs (DIC) $1,035,100

Boiler Modifications $500,000 APS Eng. Estimate

Flow Model $35,000 N/A

Flame Scanning System $350,000 Eng. Estimate

Control System and Communication Modification $350,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,866,000

Indirect Costs

Engineering $271,000 (DC) X 7.0%

Owners Cost $116,000 (DC) X 3.0%

Construction and field expenses $387,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $580,000 (DC) X 15.0%

Total indirect costs (IC) $1,489,000

Total Capital Investment (TCI) = (DC) + (IC) $5,355,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $348,000 (DC) X 9.0%

Total fixed annual costs $348,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $348,000

Total direct annual costs $505,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $856,000 15% interest rate 

Total indirect annual costs (IDAC) $856,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,204,000

Total Annual Cost with Levelization Factor $1,361,000
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 3B

Technology: Selective Non-Catalytic Reduction Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $699,000 from CUECost

Initial ammonia inventory $256,000 from CUECost

Air preheater modifications $442,000 from CUECost

Subtotal capital cost (CC) $1,397,000

Taxes $140,000 (CC) X 10.0%

Freight $84,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,621,000

Direct installation costs

Foundation & supports $81,000 (PEC) X 5.0%

Handling & erection $162,000 (PEC) X 10.0%

Electrical $162,000 (PEC) X 10.0%

Piping $49,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $65,000 (PEC) X 4.0%

Relocation $32,000 (PEC) X 2.0%

Taxes $55,100 @10%

Total direct installation costs (DIC) $606,100

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,327,000

Indirect Costs

Engineering $163,000 (DC) X 7.0%

Owners Cost $70,000 (DC) X 3.0%

Construction and field expenses $233,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $70,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $349,000 (DC) X 15.0%

Total indirect costs (IC) $920,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $5,397,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $209,000 (DC) X 9.0%

Total fixed annual costs $309,000

Variable annual costs

Reagent $1,557,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $1,566,000

Total direct annual costs (DAC) $1,875,000

Total direct annual costs $2,721,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $862,000 15% interest rate 

Total indirect annual costs (IDAC) $862,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,737,000

Total Annual Cost with Levelization Factor $3,583,000
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 3L

Technology: Selective Non-Catalytic Reduction with LNB Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $659,000 from CUECost

Initial ammonia inventory $172,000 from CUECost

Air preheater modifications $442,000 from CUECost

Subtotal capital cost (CC) $1,273,000

Taxes $127,000 (CC) X 10.0%

Freight $76,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,476,000

Direct installation costs

Foundation & supports $74,000 (PEC) X 5.0%

Handling & erection $148,000 (PEC) X 10.0%

Electrical $148,000 (PEC) X 10.0%

Piping $44,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $59,000 (PEC) X 4.0%

Relocation $30,000 (PEC) X 2.0%

Taxes $50,300 @10%

Total direct installation costs (DIC) $553,300

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,129,000

(Not Including LNB)

Indirect Costs

Engineering $149,000 (DC) X 7.0%

Owners Cost $64,000 (DC) X 3.0%

Construction and field expenses $213,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $64,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $319,000 (DC) X 15.0%

Total indirect costs (IC) $844,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner Capital Investment $3,823,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $8,946,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $192,000 (DC) X 9.0%

Total fixed annual costs $292,000

Variable annual costs

Reagent $1,046,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $1,055,000

Total direct annual costs (DAC) $1,347,000

Total direct annual costs $1,955,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,430,000 15% interest rate 

Total indirect annual costs (IDAC) $1,430,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,777,000

Total Annual Cost with Levelization Factor $3,385,000
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 3LO

Technology: Selective Non-Catalytic Reduction with LNB and OFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $635,000 from CUECost

Initial ammonia inventory $132,000 from CUECost

Air preheater modifications $442,000 from CUECost

Subtotal capital cost (CC) $1,209,000

Taxes $121,000 (CC) X 10.0%

Freight $73,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,403,000

Direct installation costs

Foundation & supports $70,000 (PEC) X 5.0%

Handling & erection $140,000 (PEC) X 10.0%

Electrical $140,000 (PEC) X 10.0%

Piping $42,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $56,000 (PEC) X 4.0%

Relocation $28,000 (PEC) X 2.0%

Taxes $47,600 @10%

Total direct installation costs (DIC) $523,600

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,027,000

(Not Including LNB/OFA)

Indirect Costs

Engineering $142,000 (DC) X 7.0%

Owners Cost $61,000 (DC) X 3.0%

Construction and field expenses $203,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $61,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $304,000 (DC) X 15.0%

Total indirect costs (IC) $806,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner and Overfire Air Capital Investment $5,355,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $10,338,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $182,000 (DC) X 9.0%

Total fixed annual costs $282,000

Variable annual costs

Reagent $803,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $812,000

Total direct annual costs (DAC) $1,094,000

Total direct annual costs $1,588,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,652,000 15% interest rate 

Total indirect annual costs (IDAC) $1,652,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,746,000

Total Annual Cost with Levelization Factor $3,240,000
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 7LO

Technology: LNB, OFA and HERT Date: 7/11/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

High energy reagent technology (HERT) $500,000 Budgetary Quotation

Initial ammonia inventory $132,000 from CUECost

Air preheater modifications $442,000 from CUECost

Subtotal capital cost (CC) $1,074,000

Taxes $107,000 (CC) X 10.0%

Freight $64,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,245,000

Direct installation costs

Foundation & supports $62,000 (PEC) X 5.0%

Handling & erection $125,000 (PEC) X 10.0%

Electrical $125,000 (PEC) X 10.0%

Piping $37,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $50,000 (PEC) X 4.0%

Relocation $25,000 (PEC) X 2.0%

Taxes $42,400 @10%

Total direct installation costs (DIC) $466,400

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $1,811,000

(Not Including LNB/OFA)

Indirect Costs

Engineering $127,000 (DC) X 7.0%

Owners Cost $54,000 (DC) X 3.0%

Construction and field expenses $181,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $54,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $272,000 (DC) X 15.0%

Total indirect costs (IC) $723,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner and Overfire Air Capital Investment $5,355,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $10,039,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $163,000 (DC) X 9.0%

Total fixed annual costs $263,000

Variable annual costs

Reagent $803,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $812,000

Total direct annual costs (DAC) $1,075,000

Total direct annual costs $1,560,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,604,000 15% interest rate 

Total indirect annual costs (IDAC) $1,604,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,679,000

Total Annual Cost with Levelization Factor $3,164,000
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 4B

Technology: Mobotec ROTAMIX Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $2,133,383 Budgetary Quotation

Subtotal (CC) $2,133,383

Instruments and controls $43,000 (CC) X 2.0%

Taxes $213,000 (CC) X 10.0%

Freight $107,000 (CC) X 5.0%

Total Cost (PEC) $2,496,000

Direct installation costs $443,000 Budgetary Quotation

Demolition $100,000 (PEC) X 4.0%

Taxes $54,300 @10%

Total direct installation costs (DIC) $597,300

Chemical Pump Enclosure $100,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,693,000

Indirect Costs

Engineering $259,000 (DC) X 7.0%

Owners Cost $111,000 (DC) X 3.0%

Construction and field expenses $369,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $111,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $554,000 (DC) X 15.0%

Total indirect costs (IC) $1,439,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $7,282,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $332,000 (DC) X 9.0%

Total fixed annual costs $404,000

Variable annual costs

Reagent $2,699,000

Auxiliary and ID fan power $10,000

Total variable annual costs $2,709,000

Total direct annual costs (DAC) $3,113,000

Total direct annual costs $4,518,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,164,000 15% interest rate 

Total indirect annual costs (IDAC) $1,164,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $4,277,000

Total Annual Cost with Levelization Factor $5,682,000
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 4L

Technology: Mobotec ROTAMIX with LNB Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $2,133,383 Budgetary Quotation

Subtotal (CC) $2,133,383

Instruments and controls $42,668 (CC) X 2.0%

Taxes $213,338 (CC) X 10.0%

Freight $107,000 (CC) X 5.0%

Total Cost (PEC) (Not including LNB) $2,496,000

Direct installation costs $443,000 Budgetary Quotation

Demolition $100,000 (PEC) X 4.0%

Taxes $54,300 @10%

Total direct installation costs (DIC) $597,300

Chemical Pump Enclosure $100,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,693,000

Indirect Costs

Engineering $259,000 (DC) X 7.0%

Owners Cost $111,000 (DC) X 3.0%

Construction and field expenses $369,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $111,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $554,000 (DC) X 15.0%

Total indirect costs (IC) $1,439,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low NOx Burner Capital Investment $3,823,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $11,105,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $332,000 (DC) X 9.0%

Total fixed annual costs $404,000

Variable annual costs

Reagent $1,319,000

Auxiliary and ID fan power $10,000

Total variable annual costs $1,329,000

Total direct annual costs (DAC) $1,733,000

Total direct annual costs $2,515,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,775,000 15% interest rate 

Total indirect annual costs (IDAC) $1,775,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,508,000

Total Annual Cost with Levelization Factor $4,290,000
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 5B

Technology: Mobotec ROFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $4,152,292 Budgetary Quotation

Subtotal (CC) $4,152,292

Instruments and controls $83,000 (CC) X 2.0%

Taxes $415,000 (CC) X 10.0%

Freight $208,000 (CC) X 5.0%

Total Cost (PEC) $4,858,000

Direct installation costs $956,000 Budgetary Quotation

Demolition $194,000 (PEC) X 4.0%

Taxes $115,000 @10%

Total direct installation costs (DIC) $1,265,000

Control System and Communication Modification $350,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $6,973,000

Indirect Costs

Engineering $488,000 (DC) X 7.0%

Owners Cost $209,000 (DC) X 3.0%

Construction and field expenses $697,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $209,190 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $1,045,950 (DC) X 15.0%

Total indirect costs (IC) $2,684,000

Total Capital Investment (TCI) = (DC) + (IC) $9,657,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 1 Operator

Maintenance labor & materials $627,570 (DC) X 9.0%

Total fixed annual costs $699,570

Variable annual costs

Reagent N/A

Auxiliary and ID fan power $713,331

Total variable annual costs $713,331

Total direct annual costs (DAC) $1,412,901

Total direct annual costs $2,050,529 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,543,000 15% interest rate 

Total indirect annual costs (IDAC) $1,543,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,956,000

Total Annual Cost with Levelization Factor $3,593,529
Four Corners BART Analysis - Cost Analysis 

Unit: 2

Case Identifier: 4 & 5B

Technology: Mobotec ROTAMIX with ROFA\ Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $5,058,342 Budgetary Quotation

Subtotal (CC) $5,058,342

Instruments and controls $101,167 (CC) X 2.0%

Taxes $505,834 (CC) X 10.0%

Freight $252,917 (CC) X 5.0%

Total Cost (PEC) $5,918,000

Direct installation costs $1,399,000 Budgetary Quotation

Demolition $237,000 (PEC) X 4.0%

Taxes $163,600 @10%

Total direct installation costs (DIC) $1,799,600

Site preparation N/A

Boiler Modifications $500,000 N/A

Total direct costs (DC) = (PEC) + (DIC) $8,218,000

Indirect Costs

Engineering $575,260 (DC) X 7.0%

Owners Cost $246,540 (DC) X 3.0%

Construction and field expenses $821,800 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $246,540 (DC) X 3.0%

Performance test $41,090 (DC) X 0.5%

Contingencies $1,232,700 (DC) X 15.0%

Total indirect costs (IC) $3,164,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $13,532,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $739,620 (DC) X 9.0%

Total fixed annual costs $811,620

Variable annual costs

Reagent $911,000

Auxiliary and ID fan power $305,913

Total variable annual costs $1,216,913

Total direct annual costs (DAC) $2,028,533

Total direct annual costs $2,943,991 1.45129 Levelization Facto

Indirect Annual Costs

Cost for capital recovery $2,162,000 15% interest rate 

Total indirect annual costs (IDAC) $2,162,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $4,191,000

Total Annual Cost with Levelization Factor $5,105,991
Four Corners BART Analysis - Cost Analysis

Unit: 2

Case Identifier: 6B

Technology: Selective Catalytic Reduction Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,515,985 adjusted from CUECost

Urea handling and injection $1,974,794 adjusted from CUECost

Initial catalyst $1,694,772 from CUECost

Initial Urea $234,341 adjusted from CUECost

Flue gas handling and ductwork $4,950,000 adjusted from CUECost

New Air Preheater $2,100,000 Eng. Estimate

New FD Fans $1,550,000 Eng. Estimate

FD Fan VFD $1,740,000 Eng. Estimate

New ID Fans $2,800,000 Eng. Estimate

ID Fan VFD $2,700,000 Eng. Estimate

New Electrical Substation $1,000,000 Eng. Estimate

Misc. equipment $269,646 from CUECost

Instruments and controls $121,477 from CUECost

Subtotal (CC) $24,651,016

Taxes $2,465,102 (CC) X 10.0%

Freight $1,232,551 (CC) X 5.0%

Total Cost (PEC) $28,348,668

Direct installation costs

Foundation & supports $9,922,034 (PEC) X 35.0%

Handling & erection $7,087,167 (PEC) X 25.0%

Electrical $5,669,734 (PEC) X 20.0%

Piping $708,717 (PEC) X 2.5%

Insulation $2,834,867 (PEC) X 10.0%

Painting $283,487 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $425,230 (PEC) X 1.5%

Taxes $2,843,124 @10%

Total direct installation costs (DIC) $31,274,359

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $62,123,000

Indirect Costs

Engineering $9,318,450 (DC) X 15.0%

Owners Cost $1,863,690 (DC) X 3.0%

Construction and field expenses $6,212,300 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,863,690 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $9,318,450 (DC) X 15.0%

Total indirect costs (IC) $28,692,000

Unintended Consequences (UC)

Lost Revenue $1,251,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,401,000

Total Capital Investment (TCI) = (DC) + (IC) $94,216,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $67,581 from CUECost

Maintenance labor & materials $1,863,690 (DC) X 3.0%

Total fixed annual costs $1,931,271

Variable annual costs

Reagent $712,786 from CUECost

Auxiliary and ID fan power $441,773 from CUECost

Steam $42,084 from CUECost

Catalyst replacement $564,924 from CUECost

Catalyst disposal $217,000 from CUECost

Total variable annual costs $1,978,567

Total direct annual costs (DAC) $3,909,838

Total direct annual costs $5,674,311 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $15,056,000 15% interest rate 

Total indirect annual costs (IDAC) $15,056,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $18,966,000

Total Annual Cost with Levelization Factor $20,730,311
Four Corners BART Analysis - Cost Analysis

Unit: 2

Case Identifier: 6L

Technology: Selective Catalytic Reduction with LNB Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,497,198 adjusted from CUECost

Urea handling and injection $1,629,837 adjusted from CUECost

Initial catalyst $1,676,305 from CUECost

Initial Urea $157,349 adjusted from CUECost

Flue gas handling and ductwork $4,950,000 adjusted from CUECost

New Air Preheater $2,100,000 Eng. Estimate

New FD Fans $1,550,000 Eng. Estimate

FD Fan VFD $1,740,000 Eng. Estimate

New ID Fans $2,800,000 Eng. Estimate

ID Fan VFD $2,700,000 Eng. Estimate

New Electrical Substation $1,000,000 Eng. Estimate

Misc. equipment $269,646 from CUECost

Instruments and controls $117,840 from CUECost

Subtotal (CC) $24,188,175

Taxes $2,418,818 (CC) X 10.0%

Freight $1,209,409 (CC) X 5.0%

Total Cost (PEC) (Not including LNB) $27,816,402

Direct installation costs

Foundation & supports $9,735,741 (PEC) X 35.0%

Handling & erection $6,954,100 (PEC) X 25.0%

Electrical $5,563,280 (PEC) X 20.0%

Piping $695,410 (PEC) X 2.5%

Insulation $2,781,640 (PEC) X 10.0%

Painting $278,164 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $417,246 (PEC) X 1.5%

Taxes $2,792,558 @10%

Total direct installation costs (DIC) (wo/ LNB) $30,718,140

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $61,035,000

Indirect Costs

Engineering $9,155,250 (DC) X 15.0%

Owners Cost $1,831,050 (DC) X 3.0%

Construction and field expenses $6,103,500 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,831,050 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $9,155,250 (DC) X 15.0%

Total indirect costs (IC) $28,191,000

Unintended Consequences (UC)

Lost Revenue $1,251,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,401,000

SCR Total Capital Investment (Not Including LNB) $92,627,000

LNB TCI $3,823,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $96,450,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $67,581 from CUECost

Maintenance labor & materials $1,831,050 (DC) X 3.0%

Total fixed annual costs $1,898,631

Variable annual costs

Reagent $478,604 from CUECost

Auxiliary and ID fan power $441,773 from CUECost

Steam $28,240 from CUECost

Catalyst replacement $558,768 from CUECost

Catalyst disposal $215,000 from CUECost

Total variable annual costs $1,722,385

Total direct annual costs (DAC) $3,621,017

Total direct annual costs $5,255,147 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $15,413,000 15% interest rate 

Total indirect annual costs (IDAC) $15,413,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $19,034,000

Total Annual Cost with Levelization Factor $20,668,147
Four Corners BART Analysis - Cost Analysis

Unit: 2

Case Identifier: 6LO

Technology: Selective Catalytic Reduction with LNB and OFA Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,477,624 adjusted from CUECost

Urea handling and injection $1,434,617 adjusted from CUECost

Initial catalyst $1,657,174 from CUECost

Initial Urea $120,756 adjusted from CUECost

Flue gas handling and ductwork $4,950,000 adjusted from CUECost

New Air Preheater $2,100,000 Eng. Estimate

New FD Fans $1,550,000 Eng. Estimate

FD Fan VFD $1,740,000 Eng. Estimate

New ID Fans $2,800,000 Eng. Estimate

ID Fan VFD $2,700,000 Eng. Estimate

New Electrical Substation $1,000,000 Eng. Estimate

Misc. equipment $269,646 from CUECost

Instruments and controls $115,692 from CUECost

Subtotal (CC) $23,915,509

Taxes $2,391,551 (CC) X 10.0%

Freight $1,195,775 (CC) X 5.0%

Total Cost (PEC) (Not including LNB/OFA) $27,502,836

Direct installation costs

Foundation & supports $9,625,992 (PEC) X 35.0%

Handling & erection $6,875,709 (PEC) X 25.0%

Electrical $5,500,567 (PEC) X 20.0%

Piping $687,571 (PEC) X 2.5%

Insulation $2,750,284 (PEC) X 10.0%

Painting $275,028 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $412,543 (PEC) X 1.5%

Taxes $2,762,769 @10%

Total direct installation costs (DIC) (wo/ LNB) $30,390,463

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $60,393,000

Indirect Costs

Engineering $9,058,950 (DC) X 15.0%

Owners Cost $1,811,790 (DC) X 3.0%

Construction and field expenses $6,039,300 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,811,790 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $9,058,950 (DC) X 15.0%

Total indirect costs (IC) $27,896,000

Unintended Consequences (UC)

Lost Revenue $1,251,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,401,000

SCR Total Capital Investment (Not Including LNB/OFA) $91,690,000

LNB TCI $5,355,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $97,045,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $67,581 from CUECost

Maintenance labor & materials $1,811,790 (DC) X 3.0%

Total fixed annual costs $1,879,371

Variable annual costs

Reagent $367,301 from CUECost

Auxiliary and ID fan power $441,773 from CUECost

Steam $21,661 from CUECost

Catalyst replacement $552,391 from CUECost

Catalyst disposal $213,000 from CUECost

Total variable annual costs $1,596,125

Total direct annual costs (DAC) $3,475,497

Total direct annual costs $5,043,955 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $15,508,000 15% interest rate 

Total indirect annual costs (IDAC) $15,508,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $18,983,000

Total Annual Cost with Levelization Factor $20,551,955
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 1B

Technology: Combustion Optimization System Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Subtotal capital cost (CC) $470,000 Eng. Estimate

Taxes $47,000 (CC) X 10.0%

Freight $28,200 (CC) X 6.0%

Total purchased equipment cost (PEC) $545,000

Direct installation costs

Air and Fuel Balancing $200,000 Eng. Estimate

Foundation & supports $27,000 (PEC) X 5.0%

Handling & erection $55,000 (PEC) X 10.0%

Electrical $55,000 (PEC) X 10.0%

Piping $16,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $11,000 (PEC) X 2.0%

Relocation $11,000 (PEC) X 2.0%

Taxes $37,500 @10%

Total direct installation costs (DIC) $412,500

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $958,000

Indirect Costs

Engineering $67,000 (DC) X 7.0%

Owners Cost $29,000 (DC) X 3.0%

Construction and field expenses $96,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $144,000 (DC) X 15.0%

Total indirect costs (IC) $471,000

Total Capital Investment (TCI) = (DC) + (IC) $1,429,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $86,000 (DC) X 9.0%

Total fixed annual costs $86,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $86,000

Total direct annual costs $124,811 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $228,000 15% interest rate 

Total indirect annual costs (IDAC) $228,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $314,000

Total Annual Cost with Levelization Factor $352,811
Four Corners BART Analysis - Cost Analysis

Unit: 3

Case Identifier: 2L

Technology: Low NOx Burners (LNB) Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs $750,000 Budgetary Quotation

Subtotal capital cost (CC) $750,000

Taxes $75,000 (CC) X 10.0%

Freight $45,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $870,000

Direct installation costs

Foundation & supports $0 N/A

Handling, erection and installation $500,000 Budgetary Quotation

Demolition $70,000 (PEC) X 8.0%

Taxes $57,000 @10%

Total direct installation costs (DIC) $627,000

Boiler Modifications $500,000 APS Eng. Estimate

Flame Scanning System $350,000 Eng. Estimate

Control System and Communication Modification $350,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $2,697,000

Indirect Costs

Engineering $189,000 (DC) X 7.0%

Owners Cost $81,000 (DC) X 3.0%

Construction and field expenses $270,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $405,000 (DC) X 15.0%

Total indirect costs (IC) $1,080,000

Total Capital Investment (TCI) = (DC) + (IC) $3,777,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $243,000 (DC) X 9.0%

Total fixed annual costs $243,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $243,000

Total direct annual costs $352,664 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $604,000 15% interest rate 

Total indirect annual costs (IDAC) $604,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $847,000

Total Annual Cost with Levelization Factor $956,664
Four Corners BART Analysis - Cost Analysis

Unit: 3

Case Identifier: 2LO

Technology: Low NOx Burners (LNB) and Overfire Air (OFA) Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs $1,125,000 Budgetary Quotation

Subtotal capital cost (CC) $1,125,000

Taxes $112,500 (CC) X 10.0%

Freight $67,500 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,305,000

Direct installation costs

Foundation & supports $0 N/A

Handling, erection and installation $750,000 Budgetary Quotation

Demolition $104,000 (PEC) X 8.0%

Taxes $85,400 @10%

Total direct installation costs (DIC) $939,400

Boiler Modifications $500,000 APS Eng. Estimate

Flow Model $35,000 N/A

Flame Scanning System $350,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,129,000

Indirect Costs

Engineering $219,000 (DC) X 7.0%

Owners Cost $94,000 (DC) X 3.0%

Construction and field expenses $313,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $469,000 (DC) X 15.0%

Total indirect costs (IC) $1,230,000

Total Capital Investment (TCI) = (DC) + (IC) $4,359,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $282,000 (DC) X 9.0%

Total fixed annual costs $282,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $282,000

Total direct annual costs $409,264 1.45129 Levelization Facto

Indirect Annual Costs

Cost for capital recovery $697,000 15% interest rate 

Total indirect annual costs (IDAC) $697,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $979,000

Total Annual Cost with Levelization Factor $1,106,264
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 3B

Technology: Selective Non-Catalytic Reduction Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $724,000 from CUECost

Initial ammonia inventory $302,000 from CUECost

Air preheater modifications $538,000 from CUECost

Subtotal capital cost (CC) $1,564,000

Taxes $156,000 (CC) X 10.0%

Freight $94,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,814,000

Direct installation costs

Foundation & supports $91,000 (PEC) X 5.0%

Handling & erection $181,000 (PEC) X 10.0%

Electrical $181,000 (PEC) X 10.0%

Piping $54,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $73,000 (PEC) X 4.0%

Relocation $36,000 (PEC) X 2.0%

Taxes $61,600 @10%

Total direct installation costs (DIC) $677,600

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,592,000

Indirect Costs

Engineering $181,000 (DC) X 7.0%

Owners Cost $78,000 (DC) X 3.0%

Construction and field expenses $259,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $78,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $389,000 (DC) X 15.0%

Total indirect costs (IC) $1,020,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $5,762,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $233,000 (DC) X 9.0%

Total fixed annual costs $333,000

Variable annual costs

Reagent $1,839,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $1,848,000

Total direct annual costs (DAC) $2,181,000

Total direct annual costs $3,165,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $921,000 15% interest rate 

Total indirect annual costs (IDAC) $921,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,102,000

Total Annual Cost with Levelization Factor $4,086,000
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 3L

Technology: Selective Non-Catalytic Reduction with LNB Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $689,000 from CUECost

Initial ammonia inventory $221,000 from CUECost

Air preheater modifications $538,000 from CUECost

Subtotal capital cost (CC) $1,448,000

Taxes $145,000 (CC) X 10.0%

Freight $87,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,680,000

Direct installation costs

Foundation & supports $84,000 (PEC) X 5.0%

Handling & erection $168,000 (PEC) X 10.0%

Electrical $168,000 (PEC) X 10.0%

Piping $50,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $67,000 (PEC) X 4.0%

Relocation $34,000 (PEC) X 2.0%

Taxes $57,100 @10%

Total direct installation costs (DIC) $628,100

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,408,000

Indirect Costs

Engineering $169,000 (DC) X 7.0%

Owners Cost $72,000 (DC) X 3.0%

Construction and field expenses $241,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $72,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $361,000 (DC) X 15.0%

Total indirect costs (IC) $950,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner Capital Investment $3,777,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $9,285,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $217,000 (DC) X 9.0%

Total fixed annual costs $317,000

Variable annual costs

Reagent $1,347,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $1,356,000

Total direct annual costs (DAC) $1,673,000

Total direct annual costs $2,428,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,484,000 15% interest rate 

Total indirect annual costs (IDAC) $1,484,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,157,000

Total Annual Cost with Levelization Factor $3,912,000
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 3LO

Technology: Selective Non-Catalytic Reduction with LNB and OFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $663,000 from CUECost

Initial ammonia inventory $170,000 from CUECost

Air preheater modifications $538,000 from CUECost

Subtotal capital cost (CC) $1,371,000

Taxes $137,000 (CC) X 10.0%

Freight $82,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,590,000

Direct installation costs

Foundation & supports $80,000 (PEC) X 5.0%

Handling & erection $159,000 (PEC) X 10.0%

Electrical $159,000 (PEC) X 10.0%

Piping $48,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $64,000 (PEC) X 4.0%

Relocation $32,000 (PEC) X 2.0%

Taxes $54,200 @10%

Total direct installation costs (DIC) $596,200

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,286,000

Indirect Costs

Engineering $160,000 (DC) X 7.0%

Owners Cost $69,000 (DC) X 3.0%

Construction and field expenses $229,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $69,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $343,000 (DC) X 15.0%

Total indirect costs (IC) $905,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner and Overfire Air Capital Investment $4,359,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $9,700,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $206,000 (DC) X 9.0%

Total fixed annual costs $306,000

Variable annual costs

Reagent $1,034,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $1,043,000

Total direct annual costs (DAC) $1,349,000

Total direct annual costs $1,958,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,550,000 15% interest rate 

Total indirect annual costs (IDAC) $1,550,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,899,000

Total Annual Cost with Levelization Factor $3,508,000
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 3LO

Technology: Selective Non-Catalytic Reduction with LNB and OFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

High energy reagent technology (HERT) $500,000 Budgetary Quotation

Initial ammonia inventory $170,000 from CUECost

Air preheater modifications $538,000 from CUECost

Subtotal capital cost (CC) $1,208,000

Taxes $121,000 (CC) X 10.0%

Freight $72,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $1,401,000

Direct installation costs

Foundation & supports $70,000 (PEC) X 5.0%

Handling & erection $140,000 (PEC) X 10.0%

Electrical $140,000 (PEC) X 10.0%

Piping $42,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $56,000 (PEC) X 4.0%

Relocation $28,000 (PEC) X 2.0%

Taxes $47,600 @10%

Total direct installation costs (DIC) $523,600

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $2,025,000

Indirect Costs

Engineering $142,000 (DC) X 7.0%

Owners Cost $61,000 (DC) X 3.0%

Construction and field expenses $203,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $61,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $304,000 (DC) X 15.0%

Total indirect costs (IC) $806,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner and Overfire Air Capital Investment $4,359,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $9,340,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $182,000 (DC) X 9.0%

Total fixed annual costs $282,000

Variable annual costs

Reagent $1,034,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $1,043,000

Total direct annual costs (DAC) $1,325,000

Total direct annual costs $1,923,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,493,000 15% interest rate 

Total indirect annual costs (IDAC) $1,493,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $2,818,000

Total Annual Cost with Levelization Factor $3,416,000
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 4B

Technology: Mobotec ROTAMIX Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $2,211,717 Budgetary Quotation

Subtotal (CC) $2,211,717

Instruments and controls $44,000 (CC) X 2.0%

Taxes $221,000 (CC) X 10.0%

Freight $110,586 (CC) X 5.0%

Total Cost (PEC) $2,587,000

Direct installation costs $459,000 Budgetary Quotation

Demolition $103,000 (PEC) X 4.0%

Taxes $56,200 @10%

Total direct installation costs (DIC) $618,200

Chemical Pump Enclosure $100,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,805,000

Indirect Costs

Engineering $266,000 (DC) X 7.0%

Owners Cost $114,000 (DC) X 3.0%

Construction and field expenses $381,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $114,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $571,000 (DC) X 15.0%

Total indirect costs (IC) $1,481,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $7,436,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $342,000 (DC) X 9.0%

Total fixed annual costs $414,000

Variable annual costs

Reagent $2,699,000

Auxiliary and ID fan power $10,000

Total variable annual costs $2,709,000

Total direct annual costs (DAC) $3,123,000

Total direct annual costs $4,532,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,188,000 15% interest rate 

Total indirect annual costs (IDAC) $1,188,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $4,311,000

Total Annual Cost with Levelization Factor $5,720,000
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 4L

Technology: Mobotec ROTAMIX with LNB Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $2,211,717 Budgetary Quotation

Subtotal (CC) $2,211,717

Instruments and controls $44,000 (CC) X 2.0%

Taxes $221,000 (CC) X 10.0%

Freight $111,000 (CC) X 5.0%

Total Cost (PEC) $2,588,000

Direct installation costs $459,000 Budgetary Quotation

Demolition $104,000 (PEC) X 4.0%

Taxes $56,300 @10%

Total direct installation costs (DIC) $619,300

Chemical Pump Enclosure $100,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $3,807,000

Indirect Costs

Engineering $266,000 (DC) X 7.0%

Owners Cost $114,000 (DC) X 3.0%

Construction and field expenses $381,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $114,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $571,000 (DC) X 15.0%

Total indirect costs (IC) $1,481,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low NOx Burner Capital Investment $3,777,000

Total Capital Investment (TCI) = (DC) + (IC) $11,215,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $343,000 (DC) X 9.0%

Total fixed annual costs $415,000

Variable annual costs

Reagent $1,319,000

Auxiliary and ID fan power $10,000

Total variable annual costs $1,329,000

Total direct annual costs (DAC) $1,744,000

Total direct annual costs $2,531,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,792,000 15% interest rate 

Total indirect annual costs (IDAC) $1,792,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,536,000

Total Annual Cost with Levelization Factor $4,323,000
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 5B

Technology: Mobotec ROFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $4,630,543 Budgetary Quotation

Subtotal (CC) $4,630,543

Instruments and controls $93,000 (CC) X 2.0%

Taxes $463,000 (CC) X 10.0%

Freight $232,000 (CC) X 5.0%

Total Cost (PEC) $5,419,000

Direct installation costs $1,113,000 Budgetary Quotation

Demolition $217,000 (PEC) X 4.0%

Taxes $133,000 @10%

Total direct installation costs (DIC) $1,463,000

Control System and Communication Modification $350,000 Eng. Estimate

Boiler Modifications $500,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $7,732,000

Indirect Costs

Engineering $541,000 (DC) X 7.0%

Owners Cost $232,000 (DC) X 3.0%

Construction and field expenses $773,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $232,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $1,160,000 (DC) X 15.0%

Total indirect costs (IC) $2,973,000

Total Capital Investment (TCI) = (DC) + (IC) $10,705,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 1 Operator

Maintenance labor & materials $696,000 (DC) X 9.0%

Total fixed annual costs $768,000

Variable annual costs

Reagent N/A

Auxiliary and ID fan power $927,000

Total variable annual costs $927,000

Total direct annual costs (DAC) $1,695,000

Total direct annual costs $2,460,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,711,000 15% interest rate 

Total indirect annual costs (IDAC) $1,711,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,406,000

Total Annual Cost with Levelization Factor $4,171,000
Four Corners BART Analysis - Cost Analysis 

Unit: 3

Case Identifier: 4 & 5B

Technology: Mobotec ROTAMIX with ROFA Date: 6/7/2007

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Equipment $5,477,926 Budgetary Quotation

Subtotal (CC) $5,477,926

Instruments and controls $110,000 (CC) X 2.0%

Taxes $548,000 (CC) X 10.0%

Freight $274,000 (CC) X 5.0%

Total Cost (PEC) $6,410,000

Direct installation costs $1,399,000 Budgetary Quotation

Demolition $256,000 (PEC) X 4.0%

Taxes $165,500 @10%

Total direct installation costs (DIC) $1,820,500

Chemical Pump Enclosure $100,000 Eng. Estimate

Buildings N/A

Total direct costs (DC) = (PEC) + (DIC) $8,331,000

Indirect Costs

Engineering $583,000 (DC) X 7.0%

Owners Cost $250,000 (DC) X 3.0%

Construction and field expenses $833,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $250,000 (DC) X 3.0%

Performance test $42,000 (DC) X 0.5%

Contingencies $1,250,000 (DC) X 15.0%

Total indirect costs (IC) $3,208,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $13,689,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $72,000 One Operator

Maintenance labor & materials $750,000 (DC) X 9.0%

Total fixed annual costs $822,000

Variable annual costs

Reagent $911,000

Auxiliary and ID fan power $937,000

Total variable annual costs $1,848,000

Total direct annual costs (DAC) $2,670,000

Total direct annual costs $3,875,000 1.45129 Levelization Fa

Indirect Annual Costs

Cost for capital recovery $2,188,000 15% interest rate 

Total indirect annual costs (IDAC) $2,188,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $4,858,000

Total Annual Cost with Levelization Factor $6,063,000
Four Corners BART Analysis - Cost Analysis

Unit: 3

Case Identifier: 6B

Technology: Selective Catalytic Reduction Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,979,000 adjusted from CUECost

Urea handling and injection $2,139,000 adjusted from CUECost

Initial catalyst $2,182,000 from CUECost

Initial Urea $277,000 adjusted from CUECost

Flue gas handling and ductwork $2,951,000 adjusted from CUECost

New Air Preheater $2,600,000 Eng. Estimate

New FD Fans $1,880,000 Eng. Estimate

FD Fan VFD $1,800,000 Eng. Estimate

New ID Fans $3,360,000 Eng. Estimate

ID Fan VFD $3,240,000 Eng. Estimate

New Electrical Substation $1,000,000 Eng. Estimate

Misc. equipment $297,000 from CUECost

Instruments and controls $140,000 from CUECost

Subtotal (CC) $25,845,000

Taxes $2,585,000 (CC) X 10.0%

Freight $1,292,000 (CC) X 5.0%

Total Cost (PEC) $29,722,000

Direct installation costs

Foundation & supports $10,403,000 (PEC) X 35.0%

Handling & erection $7,431,000 (PEC) X 25.0%

Electrical $5,944,000 (PEC) X 20.0%

Piping $743,000 (PEC) X 2.5%

Insulation $2,972,000 (PEC) X 10.0%

Painting $297,000 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $446,000 (PEC) X 1.5%

Taxes $2,973,600 @10%

Total direct installation costs (DIC) $32,709,600

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $64,932,000

Indirect Costs

Engineering $7,792,000 (DC) X 12.0%

Owners Cost $1,948,000 (DC) X 3.0%

Construction and field expenses $6,493,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,948,000 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $9,740,000 (DC) X 15.0%

Total indirect costs (IC) $28,036,000

Unintended Consequences (UC)

Lost Revenue $1,572,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,722,000

Total Capital Investment (TCI) = (DC) + (IC) $96,690,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $76,000 from CUECost

Maintenance labor & materials $1,948,000 (DC) X 3.0%

Total fixed annual costs $2,024,000

Variable annual costs

Reagent $842,000 from CUECost

Auxiliary and ID fan power $583,000 from CUECost

Steam $50,000 from CUECost

Catalyst replacement $727,000 from CUECost

Catalyst disposal $280,000 from CUECost

Total variable annual costs $2,482,000

Total direct annual costs (DAC) $4,506,000

Total direct annual costs $6,540,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $15,451,000 15% interest rate 

Total indirect annual costs (IDAC) $15,451,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $19,957,000

Total Annual Cost with Levelization Factor $21,991,000
Four Corners BART Analysis - Cost Analysis

Unit: 3

Case Identifier: 6L

Technology: Selective Catalytic Reduction with LNB Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,959,000 adjusted from CUECost

Urea handling and injection $1,842,000 adjusted from CUECost

Initial catalyst $2,160,000 from CUECost

Initial Urea $203,000 adjusted from CUECost

Flue gas handling and ductwork $2,951,000 adjusted from CUECost

New Air Preheater $2,600,000 Eng. Estimate

New FD Fans $1,880,000 Eng. Estimate

FD Fan VFD $1,800,000 Eng. Estimate

New ID Fans $3,360,000 Eng. Estimate

ID Fan VFD $3,240,000 Eng. Estimate

New Electrical Substation $1,000,000 Eng. Estimate

Misc. equipment $297,000 from CUECost

Instruments and controls $137,000 from CUECost

Subtotal (CC) $25,429,000

Taxes $2,543,000 (CC) X 10.0%

Freight $1,271,000 (CC) X 5.0%

Total Cost (PEC) (Without LNB) $29,243,000

Direct installation costs

Foundation & supports $10,235,000 (PEC) X 35.0%

Handling & erection $7,311,000 (PEC) X 25.0%

Electrical $5,849,000 (PEC) X 20.0%

Piping $731,000 (PEC) X 2.5%

Insulation $2,924,000 (PEC) X 10.0%

Painting $292,000 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $439,000 (PEC) X 1.5%

Taxes $2,928,100 @10%

Total direct installation costs (DIC) $32,209,100

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $63,952,000

Indirect Costs

Engineering $7,674,000 (DC) X 12.0%

Owners Cost $1,919,000 (DC) X 3.0%

Construction and field expenses $6,395,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,919,000 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $9,593,000 (DC) X 15.0%

Total indirect costs (IC) $27,615,000

Unintended Consequences (UC)

Lost Revenue $1,572,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,722,000

SCR Total Capital Investment (Without LNB) $95,289,000

LNB TCI $3,777,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $99,066,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $76,000 from CUECost

Maintenance labor & materials $1,919,000 (DC) X 3.0%

Total fixed annual costs $1,995,000

Variable annual costs

Reagent $617,000 from CUECost

Auxiliary and ID fan power $583,000 from CUECost

Steam $36,000 from CUECost

Catalyst replacement $720,000 from CUECost

Catalyst disposal $277,000 from CUECost

Total variable annual costs $2,233,000

Total direct annual costs (DAC) $4,228,000

Total direct annual costs $6,136,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $15,831,000 15% interest rate 

Total indirect annual costs (IDAC) $15,831,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $20,059,000

Total Annual Cost with Levelization Factor $21,967,000
Four Corners BART Analysis - Cost Analysis

Unit: 3

Case Identifier: 6LO

Technology: Selective Catalytic Reduction with LNB and OFA Date: 6/7/2007

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $3,936,000 adjusted from CUECost

Urea handling and injection $1,621,000 adjusted from CUECost

Initial catalyst $2,135,000 from CUECost

Initial Urea $156,000 adjusted from CUECost

Flue gas handling and ductwork $2,951,000 adjusted from CUECost

New Air Preheater $2,600,000 Eng. Estimate

New FD Fans $1,880,000 Eng. Estimate

FD Fan VFD $1,800,000 Eng. Estimate

New ID Fans $3,360,000 Eng. Estimate

ID Fan VFD $3,240,000 Eng. Estimate

New Electrical Substation $1,000,000 Eng. Estimate

Misc. equipment $297,000 from CUECost

Instruments and controls $135,000 from CUECost

Subtotal (CC) $25,111,000

Taxes $2,511,000 (CC) X 10.0%

Freight $1,256,000 (CC) X 5.0%

Total Cost (PEC) (Without LNB/OFA) $28,878,000

Direct installation costs

Foundation & supports $10,107,000 (PEC) X 35.0%

Handling & erection $7,220,000 (PEC) X 25.0%

Electrical $5,776,000 (PEC) X 20.0%

Piping $722,000 (PEC) X 2.5%

Insulation $2,888,000 (PEC) X 10.0%

Painting $289,000 (PEC) X 1.0%

Demolition $1,500,000 Eng. Estimate

Relocation $433,000 (PEC) X 1.5%

Taxes $2,893,500 @10%

Total direct installation costs (DIC) $31,828,500

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $63,207,000

Indirect Costs

Engineering $7,585,000 (DC) X 12.0%

Owners Cost $1,896,000 (DC) X 3.0%

Construction and field expenses $6,321,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $1,896,000 (DC) X 3.0%

Tuning $25,000 Eng. Estimate

Performance test $90,000 Eng. Estimate

Contingencies $9,481,000 (DC) X 15.0%

Total indirect costs (IC) $27,294,000

Unintended Consequences (UC)

Lost Revenue $1,572,000

New CEMS $2,000,000

Rata Test for CEMS $150,000

Total Unintended Consequences (UC) $3,722,000

SCR Total Capital Investment (Without LNB/OFA) $94,223,000

LNB TCI $4,359,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $98,582,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $76,000 from CUECost

Maintenance labor & materials $1,896,000 (DC) X 3.0%

Total fixed annual costs $1,972,000

Variable annual costs

Reagent $473,000 from CUECost

Auxiliary and ID fan power $583,000 from CUECost

Steam $28,000 from CUECost

Catalyst replacement $712,000 from CUECost

Catalyst disposal $274,000 from CUECost

Total variable annual costs $2,070,000

Total direct annual costs (DAC) $4,042,000

Total direct annual costs $5,866,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $15,753,000 15% interest rate 

Total indirect annual costs (IDAC) $15,753,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $19,795,000

Total Annual Cost with Levelization Factor $21,619,000
Four Corners BART Analysis - Cost Analysis 

Unit: 4 & 5

Case Identifier: 1B

Technology: Combustion Optimization System Date: 7/6/2007

Costs are per Unit

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Subtotal capital cost (CC) $470,000 Eng. Estimate

Taxes $47,000 (CC) X 10.0%

Freight $28,200 (CC) X 6.0%

Total purchased equipment cost (PEC) $545,000

Direct installation costs

Air and Fuel Balancing $300,000 Eng. Estimate

Foundation & supports $27,000 (PEC) X 5.0%

Handling & erection $55,000 (PEC) X 10.0%

Electrical $55,000 (PEC) X 10.0%

Piping $16,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $11,000 (PEC) X 2.0%

Relocation $11,000 (PEC) X 2.0%

Taxes $47,500 @10%

Total direct installation costs (DIC) $522,500

Site preparation $0 N/A

Buildings $0 N/A

Total direct costs (DC) = (PEC) + (DIC) $1,068,000

Indirect Costs

Engineering $75,000 (DC) X 7.0%

Owners Cost $32,000 (DC) X 3.0%

Construction and field expenses $107,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $160,000 (DC) X 15.0%

Total indirect costs (IC) $509,000

Total Capital Investment (TCI) = (DC) + (IC) $1,577,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $96,000 (DC) X 9.0%

Total fixed annual costs $96,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $96,000

Total direct annual costs $139,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $252,000 15% interest rate 

Total indirect annual costs (IDAC) $252,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $348,000

Total Annual Cost with Levelization Factor $391,000
Four Corners BART Analysis - Cost Analysis

Unit: 4 & 5

Case Identifier: 2L

Technology: Low NOx Burners (LNB) Date: 7/6/2007

Costs are per Unit

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs $2,438,000 Budgetary Quotation

Subtotal capital cost (CC) $2,438,000

Taxes $244,000 (CC) X 10.0%

Freight $146,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $2,828,000

Direct installation costs

Foundation & supports $0 N/A

Handling, erection and installation $1,688,000 Budgetary Quotation

Demolition $226,000 (PEC) X 8.0%

Taxes $191,400 @10%

Total direct installation costs (DIC) $2,105,400

Boiler Modifications $500,000 APS Eng. Estimate

Flame Scanning System $450,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $5,883,000

Indirect Costs

Engineering $412,000 (DC) X 7.0%

Owners Cost $176,000 (DC) X 3.0%

Construction and field expenses $588,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $882,000 (DC) X 15.0%

Total indirect costs (IC) $2,193,000

Total Capital Investment (TCI) = (DC) + (IC) $8,076,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $529,000 (DC) X 9.0%

Total fixed annual costs $529,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $529,000

Total direct annual costs $768,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,291,000 15% interest rate 

Total indirect annual costs (IDAC) $1,291,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $1,820,000

Total Annual Cost with Levelization Factor $2,059,000
Four Corners BART Analysis - Cost Analysis

Unit: 4 & 5

Case Identifier: 2LO

Technology: Low NOx Burners (LNB) and Overfire Air (OFA) Date: 7/6/2007

Costs are per Unit

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs $4,125,000 Budgetary Quotation

Subtotal capital cost (CC) $4,125,000

Taxes $412,500 (CC) X 10.0%

Freight $247,500 (CC) X 6.0%

Total purchased equipment cost (PEC) $4,785,000

Direct installation costs

Foundation & supports $0 N/A

Handling, erection and installation $3,250,000 Budgetary Quotation

Demolition $383,000 (PEC) X 8.0%

Taxes $363,300 @10%

Total direct installation costs (DIC) $3,996,300

Boiler Modifications $500,000 APS Eng. Estimate

Flow Model $35,000 Eng. Estimate

Flame Scanning System $450,000 Eng. Estimate

Control System and Communication Modification $450,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $9,766,000

Indirect Costs

Engineering $684,000 (DC) X 7.0%

Owners Cost $293,000 (DC) X 3.0%

Construction and field expenses $977,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $100,000 Eng. Estimate

Performance test $35,000 Eng. Estimate

Contingencies $1,465,000 (DC) X 15.0%

Total indirect costs (IC) $3,554,000

Total Capital Investment (TCI) = (DC) + (IC) $13,320,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance labor and materials $879,000 (DC) X 9.0%

Total fixed annual costs $879,000

Variable annual costs

Total variable annual costs N/A

Total direct annual costs (DAC) $879,000

Total direct annual costs $1,276,000 1.45129 Levelization Facto

Indirect Annual Costs

Cost for capital recovery $2,129,000 15% interest rate 

Total indirect annual costs (IDAC) $2,129,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $3,008,000

Total Annual Cost with Levelization Factor $3,405,000
Four Corners BART Analysis - Cost Analysis 

Unit: 4 & 5

Case Identifier: 3B

Technology: Selective Non-Catalytic Reduction Date: 7/6/2007

Costs are per Unit

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $924,000 from CUECost

Initial ammonia inventory $802,000 from CUECost

Air preheater modifications $1,304,000 from CUECost

Subtotal capital cost (CC) $3,030,000

Taxes $303,000 (CC) X 10.0%

Freight $182,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $3,515,000

Direct installation costs

Foundation & supports $176,000 (PEC) X 5.0%

Handling & erection $352,000 (PEC) X 10.0%

Electrical $352,000 (PEC) X 10.0%

Piping $105,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $141,000 (PEC) X 4.0%

Relocation $70,000 (PEC) X 2.0%

Taxes $119,600 @10%

Total direct installation costs (DIC) $1,315,600

Control System and Communication Modification $1,500,000 Eng. Estimate

Chemical Pump Enclosure $100,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $6,431,000

Indirect Costs

Engineering $450,000 (DC) X 7.0%

Owners Cost $193,000 (DC) X 3.0%

Construction and field expenses $643,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $193,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $965,000 (DC) X 15.0%

Total indirect costs (IC) $2,479,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Total Capital Investment (TCI) = (DC) + (IC) $11,060,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $579,000 (DC) X 9.0%

Total fixed annual costs $679,000

Variable annual costs

Reagent $4,876,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $4,885,000

Total direct annual costs (DAC) $5,564,000

Total direct annual costs $8,075,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $1,767,000 15% interest rate 

Total indirect annual costs (IDAC) $1,767,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $7,331,000

Total Annual Cost with Levelization Factor $9,842,000
Four Corners BART Analysis - Cost Analysis 

Unit: 4 & 5

Case Identifier: 3L

Technology: Selective Non-Catalytic Reduction with LNB Date: 7/6/2007

Costs are per Unit

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $907,000 from CUECost

Initial ammonia inventory $730,000 from CUECost

Air preheater modifications $1,304,000 from CUECost

Subtotal capital cost (CC) $2,941,000

Taxes $294,000 (CC) X 10.0%

Freight $176,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $3,411,000

Direct installation costs

Foundation & supports $171,000 (PEC) X 5.0%

Handling & erection $341,000 (PEC) X 10.0%

Electrical $341,000 (PEC) X 10.0%

Piping $102,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $136,000 (PEC) X 4.0%

Relocation $68,000 (PEC) X 2.0%

Taxes $115,900 @10%

Total direct installation costs (DIC) $1,274,900

Control System and Communication Modification $1,500,000 Eng. Estimate

Chemical Pump Enclosure $100,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $6,286,000

Indirect Costs

Engineering $440,000 (DC) X 7.0%

Owners Cost $189,000 (DC) X 3.0%

Construction and field expenses $629,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $189,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $943,000 (DC) X 15.0%

Total indirect costs (IC) $2,425,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner Capital Investment $8,076,000

Total Capital Investment (TCI) = (DC) + (IC) $18,937,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $566,000 (DC) X 9.0%

Total fixed annual costs $666,000

Variable annual costs

Reagent $4,442,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $4,451,000

Total direct annual costs (DAC) $5,117,000

Total direct annual costs $7,426,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $3,026,000 15% interest rate 

Total indirect annual costs (IDAC) $3,026,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $8,143,000

Total Annual Cost with Levelization Factor $10,452,000
Four Corners BART Analysis - Cost Analysis 

Unit: 4 & 5

Case Identifier: 3LO

Technology: Selective Non-Catalytic Reduction with LNB and OFA Date: 7/6/2007

Costs are per Unit

Cost Item $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reagent storage, handling, injection & controls $867,000 from CUECost

Initial ammonia inventory $568,000 from CUECost

Air preheater modifications $1,304,000 from CUECost

Subtotal capital cost (CC) $2,739,000

Taxes $274,000 (CC) X 10.0%

Freight $164,000 (CC) X 6.0%

Total purchased equipment cost (PEC) $3,177,000

Direct installation costs

Foundation & supports $159,000 (PEC) X 5.0%

Handling & erection $318,000 (PEC) X 10.0%

Electrical $318,000 (PEC) X 10.0%

Piping $95,000 (PEC) X 3.0%

Insulation $0 (PEC) X 0.0%

Painting $0 (PEC) X 0.0%

Demolition $127,000 (PEC) X 4.0%

Relocation $64,000 (PEC) X 2.0%

Taxes $108,100 @10%

Total direct installation costs (DIC) $1,189,100

Control System and Communication Modification $1,050,000 Eng. Estimate

Chemical Pump Enclosure $100,000 Eng. Estimate

Total direct costs (DC) = (PEC) + (DIC) $5,516,000

Indirect Costs

Engineering $386,000 (DC) X 7.0%

Owners Cost $165,000 (DC) X 3.0%

Construction and field expenses $552,000 (DC) X 10.0%

Construction indirect Included B&V labor market review

Start-up $165,000 (DC) X 3.0%

Performance test $35,000 Eng. Estimate

Contingencies $827,000 (DC) X 15.0%

Total indirect costs (IC) $2,130,000

Unintended Consequences (UC)

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $2,150,000

Low Nox Burner and Overfire Air Capital Investment $13,320,000

Total Capital Investment (TCI) = (DC) + (IC) $23,116,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $100,000 Estimate

Maintenance labor and materials $496,000 (DC) X 9.0%

Total fixed annual costs $596,000

Variable annual costs

Reagent $3,455,000 from CUECost

Auxiliary Power $5,000 from CUECost

Water $4,000

Total variable annual costs $3,464,000

Total direct annual costs (DAC) $4,060,000

Total direct annual costs $5,892,000 1.45129 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $3,694,000 15% interest rate 

Total indirect annual costs (IDAC) $3,694,000 & 20 year life

Total Annual Cost (TAC) = (DAC) + (IDAC) $7,754,000

Total Annual Cost with Levelization Factor $9,586,000
Four Corners BART Analysis - Cost Analysis

Unit: 4 & 5

Case Identifier: 4B

Technology: Selective Catalytic Reduction Date: 7/6/2007

Costs are per Unit

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing $6,955,000 adjusted from CUECost

Urea handling and injection $9,000,000 Quotation and Estamite

Initial catalyst $6,838,000 from CUECost

Initial Urea $734,000 adjusted from CUECost

Flue gas handling and ductwork $6,542,000 adjusted from CUECost

New Air Preheater $13,000,000 Eng. Estimate

New ID Fans $12,800,000 Eng. Estimate

ID Fan VFD $12,000,000 Eng. Estimate

New Electrical Substation $2,500,000 Eng. Estimate

Misc. equipment $506,000 from CUECost

Instruments and controls $1,150,000 adjusted from CUECost

Subtotal (CC) $72,025,000

Taxes $7,203,000 (CC) X 10.0%

Freight $3,601,000 (CC) X 5.0%

Total Cost (PEC) $82,829,000

Direct installation costs

Foundation & supports $16,566,000 (PEC) X 20.0%

Handling & erection $33,132,000 (PEC) X 40.0%

Electrical $12,424,000 (PEC) X 15.0%

Piping $2,071,000 (PEC) X 2.5%

Insulation $4,141,000 (PEC) X 5.0%

Painting $828,000 (PEC) X 1.0%

Demolition $5,000,000 Eng. Estimate

Relocation $2,071,000 (PEC) X 2.5%

Taxes $7,623,300 @10%

Total direct installation costs (DIC) $83,856,300

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $169,185,000

Indirect Costs

Engineering $8,459,000 (DC) X 5.0%

Owners Cost $5,076,000 (DC) X 3.0%

Construction and field expenses $5,076,000 (DC) X 3.0%

Construction indirect Included B&V labor market review

Start-up $5,076,000 (DC) X 3.0%

Tuning $120,000 Eng. Estimate

Performance test $250,000 Eng. Estimate

Contingencies $25,378,000 (DC) X 15.0%

Total indirect costs (IC) $49,435,000

Unintended Consequences (UC)

Side Effect Mitigation $6,962,000 SO3 Removal

Lost Revenue $14,358,000 Extended Outage

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $23,470,000

Total Capital Investment (TCI) = (DC) + (IC) + (UC) $242,090,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $163,000 from CUECost

Maintenance labor & materials $5,076,000 (DC) X 3.0%

Total fixed annual costs $5,239,000

Variable annual costs

Reagent $2,231,000 from CUECost

Auxiliary and ID fan power $1,823,000 from CUECost

Steam $132,000 from CUECost

Catalyst replacement $2,279,000 from CUECost

Catalyst disposal $877,000 from CUECost

Total variable annual costs $7,342,000

Total direct annual costs (DAC) $12,581,000

Total direct annual costs $18,259,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $38,686,000 15% interest rate 

Total indirect annual costs (IDAC) $38,686,000 & 20 year life

Unintended Consequences (UCAC)

Side Effect Mitigation $220,000

Total Unintended Consequences (UCAC) $220,000

Total Annual Cost (TAC) = (DAC) + (IDAC) + (UCAC) $51,487,000

Total Annual Cost with Levelization Factor $56,945,000

SCR designed for year-round operation, bypass dampers are not included
Four Corners BART Analysis - Cost Analysis

Unit: 4 & 5

Case Identifier: 4L

Technology: Selective Catalytic Reduction with LNB Date: 7/6/2007

Costs are per Unit

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $6,944,000 adjusted from CUECost

Urea handling and injection $9,000,000 Quotation and Estamite

Initial catalyst $6,816,000 from CUECost

Initial Urea $668,000 adjusted from CUECost

Flue gas handling and ductwork $6,542,000 adjusted from CUECost

New Air Preheater $13,000,000 Eng. Estimate

New ID Fans $12,800,000 Eng. Estimate

ID Fan VFD $12,000,000 Eng. Estimate

New Electrical Substation $2,500,000 Eng. Estimate

Misc. equipment $506,000 from CUECost

Instruments and controls $1,143,000 from CUECost

Subtotal (CC) $71,919,000

Taxes $7,191,900 (CC) X 10.0%

Freight $3,595,950 (CC) X 5.0%

Total Cost (PEC) (Without LNB) $82,706,850

Direct installation costs

Foundation & supports $16,541,000 (PEC) X 20.0%

Handling & erection $33,083,000 (PEC) X 40.0%

Electrical $12,406,000 (PEC) X 15.0%

Piping $2,068,000 (PEC) X 2.5%

Insulation $4,135,000 (PEC) X 5.0%

Painting $827,000 (PEC) X 1.0%

Demolition $5,000,000 Eng. Estimate

Relocation $2,068,000 (PEC) X 2.5%

Taxes $7,612,800 @10%

Total direct installation costs (DIC) $83,740,800

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $168,948,000

Indirect Costs

Engineering $8,447,000 (DC) X 5.0%

Owners Cost $5,068,000 (DC) X 3.0%

Construction and field expenses $5,068,000 (DC) X 3.0%

Construction indirect Included B&V labor market review

Start-up $5,068,000 (DC) X 3.0%

Tuning $120,000 Eng. Estimate

Performance test $250,000 Eng. Estimate

Contingencies $25,342,000 (DC) X 15.0%

Total indirect costs (IC) $49,363,000

Unintended Consequences (UC)

Side Effect Mitigation $6,962,000 SO3 Removal

Lost Revenue $14,358,000

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $23,470,000

SCR Total Capital Investment (Without LNB) $241,781,000

LNB TCI $8,076,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $249,857,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $163,000 from CUECost

Maintenance labor & materials $5,068,000 (DC) X 3.0%

Total fixed annual costs $5,231,000

Variable annual costs

Reagent $2,033,000 from CUECost

Auxiliary and ID fan power $1,823,000 from CUECost

Steam $120,000 from CUECost

Catalyst replacement $2,272,000 from CUECost

Catalyst disposal $874,000 from CUECost

Total variable annual costs $7,122,000

Total direct annual costs (DAC) $12,353,000

Total direct annual costs $17,928,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $39,927,000 15% interest rate 

Total indirect annual costs (IDAC) $39,927,000 & 20 year life

Unintended Consequences (UCAC)

Side Effect Mitigation $220,000

Total Unintended Consequences (UCAC) $220,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $52,500,000

Total Annual Cost with Levelization Factor $57,855,000
Four Corners BART Analysis - Cost Analysis

Unit: 4 & 5

Case Identifier: 4LO

Technology: Selective Catalytic Reduction with LNB and OFA Date: 7/6/2007

Costs are per Unit

Cost Item SCR $ Remarks

CAPITAL COST

Direct Costs

Purchased equipment costs

Reactor housing and installation $6,907,000 adjusted from CUECost

Urea handling and injection $9,000,000 Quotation and Estamite

Initial catalyst $6,743,000 from CUECost

Initial Urea $520,000 adjusted from CUECost

Flue gas handling and ductwork $6,542,000 adjusted from CUECost

New Air Preheater $13,000,000 Eng. Estimate

New ID Fans $12,800,000 Eng. Estimate

ID Fan VFD $12,000,000 Eng. Estimate

New Electrical Substation $2,500,000 Eng. Estimate

Misc. equipment $506,000 from CUECost

Instruments and controls $1,127,000 from CUECost

Subtotal (CC) $71,645,000

Taxes $7,165,000 (CC) X 10.0%

Freight $3,582,000 (CC) X 5.0%

Total Cost (PEC) (Without LNB/OFA) $82,392,000

Direct installation costs

Foundation & supports $16,478,000 (PEC) X 20.0%

Handling & erection $32,957,000 (PEC) X 40.0%

Electrical $12,359,000 (PEC) X 15.0%

Piping $2,060,000 (PEC) X 2.5%

Insulation $4,120,000 (PEC) X 5.0%

Painting $824,000 (PEC) X 1.0%

Demolition $5,000,000 Eng. Estimate

Relocation $2,060,000 (PEC) X 2.5%

Taxes $7,585,800 @10%

Total direct installation costs (DIC) $83,443,800

Site preparation $2,000,000 Estimate 

Buildings $500,000 Estimate

Total direct costs (DC) = (PEC) + (DIC) $168,336,000

Indirect Costs

Engineering $8,417,000 (DC) X 5.0%

Owners Cost $5,050,000 (DC) X 3.0%

Construction and field expenses $5,050,000 (DC) X 3.0%

Construction indirect Included B&V labor market review

Start-up $5,050,000 (DC) X 3.0%

Tuning $120,000 Eng. Estimate

Performance test $250,000 Eng. Estimate

Contingencies $25,250,400 (DC) X 15.0%

Total indirect costs (IC) $49,187,000

Unintended Consequences (UC)

Side Effect Mitigation $6,962,000 SO3 Removal

Lost Revenue $14,358,000

New CEMS $2,000,000

Rata for CEMS $150,000

Total Unintended Consequences (UC) $23,470,000

SCR Total Capital Investment (Without LNB/OFA) $240,993,000

LNB TCI $13,320,000

Total Combined Capital Investment (TCI) = (DC) + (IC) $254,313,000

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Operating labor $163,000 from CUECost

Maintenance labor & materials $5,050,000 (DC) X 3.0%

Total fixed annual costs $5,213,000

Variable annual costs

Reagent $1,581,000 from CUECost

Auxiliary and ID fan power $1,823,000 from CUECost

Steam $93,000 from CUECost

Catalyst replacement $2,248,000 from CUECost

Catalyst disposal $865,000 from CUECost

Total variable annual costs $6,610,000

Total direct annual costs (DAC) $11,823,000

Total direct annual costs $17,159,000 1.4512905 Levelization Factor

Indirect Annual Costs

Cost for capital recovery $40,639,000 15% interest rate 

Total indirect annual costs (IDAC) $40,639,000 & 20 year life

Unintended Consequences (UCAC)

Side Effect Mitigation $220,000

Total Unintended Consequences (UCAC) $220,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $52,682,000

Total Annual Cost with Levelization Factor $57,798,000
Arizona Public Service 

Four Corners Units 1 through 5 Appendix E 

102907 E-1 

Appendix E 

Stack Flow Summary Table 
Four Corners - Unit 1

Stack Outlet Conditions

Flow 

(acfm)

Diameter 

(ft)

Velocity 

(ft/s)

Temperature 

(°F)

Rate 

(Lb/MMBTU)

Emission 

(Ton/year)

Redu

(Ton/

Baseline 684,087 15 65 138 0.78 5,703 0 Combustion Optimization System (Neural Network) 684,087 15 65 138 0.72 5,247 45Selective Non-Catalytic Reduction (SNCR) 684,087 15 65 138 0.56 4,081 1,6Mobotec ROTAMIX 684,087 15 65 138 0.56 4,081 1,6Low NOx Burners (LNB) 684,087 15 65 138 0.43 3,133 2,5LNB and Overfire Air (OFA) 684,087 15 65 138 0.33 2,405 3,2LNB and SNCR 684,087 15 65 138 0.32 2,332 3,3LNB and Mobotec ROTAMIX 684,087 15 65 138 0.30 2,186 3,5Mobotec ROFA 684,087 15 65 138 0.28 2,040 3,6LNB and OFA with SNCR 684,087 15 65 138 0.26 1,895 3,8LNB and OFA with HERT 684,087 15 65 138 0.20 1,457 4,2Mobotec ROFA and ROTAMIX 684,087 15 65 138 0.19 1,385 4,3Selective Catalytic Reduction (SCR) 684,087 15 65 138 0.08 568 5,1LNB with SCR 684,087 15 65 138 0.06 437 5,2LNB and OFA with SCR 684,087 15 65 138 0.06 437 5,2

Flow 

(acfm)

Diameter 

(ft)

Velocity 

(ft/s)

Temperature 

(°F)

Rate 

(Lb/MMBTU)

Emission 

(Ton/year)

Redu

(Ton/

Baseline 684,087 15 65 138 0.025 180 0 Fabric Filter (FF) 684,087 15 65 138 0.012 87 9Electrostatic Precipitator (ESP) 684,087 15 65 138 0.012 87 9GE Max 9 Hybrid 684,087 15 65 138 0.012 87 9Wet ESP (Metal Type) 684,087 15 65 138 0.012 87 9Wet ESP (Membrane Type) 684,087 15 65 138 0.012 87 9NOx Existing rate (lb/MMBTU): 0.78

Option

Stack NOx

Option

Stack PM

PM Existing rate (lb/MMBTU): 0.025

1 of 4 
Four Corners - Unit 2

Stack Outlet Conditions

Flow 

(acfm)

Diameter 

(ft)

Velocity 

(ft/s)

Temperature 

(°F)

Rate 

(Lb/MMBTU)

Emission 

(Ton/year)

Redu

(Ton/

Baseline 684,087 15 65 138 0.64 4,788 0 Combustion Optimization System (Neural Network) 684,087 15 65 138 0.60 4,486 30Selective Non-Catalytic Reduction (SNCR) 684,087 15 65 138 0.46 3,440 1,3Mobotec ROTAMIX 684,087 15 65 138 0.45 3,365 1,4Low NOx Burners (LNB) 684,087 15 65 138 0.43 3,215 1,5LNB and Overfire Air (OFA) 684,087 15 65 138 0.33 2,467 2,3LNB and SNCR 684,087 15 65 138 0.32 2,393 2,3LNB and Mobotec ROTAMIX 684,087 15 65 138 0.30 2,243 2,5Mobotec ROFA 684,087 15 65 138 0.28 2,094 2,6LNB and OFA with SNCR 684,087 15 65 138 0.26 1,944 2,8LNB and OFA with HERT 684,087 15 65 138 0.20 1,495 3,2Mobotec ROFA and ROTAMIX 684,087 15 65 138 0.19 1,421 3,3Selective Catalytic Reduction (SCR) 684,087 15 65 138 0.06 479 4,3LNB with SCR 684,087 15 65 138 0.06 449 4,3LNB and OFA with SCR 684,087 15 65 138 0.06 449 4,3

Flow 

(acfm)

Diameter 

(ft)

Velocity 

(ft/s)

Temperature 

(°F)

Rate 

(Lb/MMBTU)

Emission 

(Ton/year)

Redu

(Ton/

Baseline 684,087 15 65 138 0.029 220 0 Fabric Filter (FF) 684,087 15 65 138 0.012 90 12Electrostatic Precipitator (ESP) 684,087 15 65 138 0.012 90 12GE Max 9 Hybrid 684,087 15 65 138 0.012 90 12Wet ESP (Metal Type) 684,087 15 65 138 0.012 90 12Wet ESP (Membrane Type) 684,087 15 65 138 0.012 90 12NOx Existing rate (lb/MMBTU): 0.64

Option

Stack NOx

Option

Stack PM

PM Existing rate (lb/MMBTU): 0.029

2 of 4 
Four Corners - Unit 3

Stack Outlet Conditions

Flow 

(acfm)

Diameter 

(ft)

Velocity 

(ft/s)

Temperature 

(°F)

Rate 

(Lb/MMBTU)

Emission 

(Ton/year)

Redu

(Ton/

Baseline 881,271 15 83 138 0.59 5,633 0 Combustion Optimization System (Neural Network) 881,271 15 83 138 0.56 5,375 25Selective Non-Catalytic Reduction (SNCR) 881,271 15 83 138 0.46 4,415 1,2Mobotec ROTAMIX 881,271 15 83 138 0.45 4,319 1,3Low NOx Burners (LNB) 881,271 15 83 138 0.43 4,128 1,5LNB and Overfire Air (OFA) 881,271 15 83 138 0.33 3,168 2,4LNB and SNCR 881,271 15 83 138 0.32 3,072 2,5LNB and Mobotec ROTAMIX 881,271 15 83 138 0.30 2,880 2,7Mobotec ROFA 881,271 15 83 138 0.28 2,688 2,9LNB and OFA with SNCR 881,271 15 83 138 0.26 2,496 3,1LNB and OFA with HERT 881,271 15 83 138 0.20 1,920 3,7Mobotec ROFA and ROTAMIX 881,271 15 83 138 0.19 1,824 3,8Selective Catalytic Reduction (SCR) 881,271 15 83 138 0.06 576 5,0LNB with SCR 881,271 15 83 138 0.06 576 5,0LNB and OFA with SCR 881,271 15 83 138 0.06 576 5,0

Flow 

(acfm)

Diameter 

(ft)

Velocity 

(ft/s)

Temperature 

(°F)

Rate 

(Lb/MMBTU)

Emission 

(Ton/year)

Redu

(Ton/

Baseline 881,271 15 83 138 0.029 285 0 Fabric Filter (FF) 881,271 15 83 138 0.012 117 16Electrostatic Precipitator (ESP) 881,271 15 83 138 0.012 117 16GE Max 9 Hybrid 881,271 15 83 138 0.012 117 16Wet ESP (Metal Type) 881,271 15 83 138 0.012 117 16Wet ESP (Membrane Type) 881,271 15 83 138 0.012 117 16

NOx

NOx Existing rate (lb/MMBTU): 0.59

Option

Stack 

PM Existing rate (lb/MMBTU): 0.029

Option

Stack PM

3 of 4 
Four Corners - Unit 4 & 5

Stack Outlet Conditions

Flow 

(acfm)

Diameter 

(ft)

Velocity 

(ft/s)

Temperature 

(°F)

Rate 

(Lb/MMBTU)

Emission 

(Ton/year)

Redu

(Ton/

Baseline 2,728,460 28.5 71 120 0.49 13,028 0 Combustion Optimization System (Neural Network) 2,728,460 28.5 71 120 0.47 12,395 63Low NOx Burners (LNB) 2,728,460 28.5 71 120 0.45 11,867 1,1Selective Non-Catalytic Reduction (SNCR) 2,728,460 28.5 71 120 0.38 9,889 3,1LNB and Overfire Air (OFA) 2,728,460 28.5 71 120 0.35 9,230 3,7LNB and SNCR 2,728,460 28.5 71 120 0.32 8,439 4,5LNB and OFA with SNCR 2,728,460 28.5 71 120 0.26 6,857 6,1Selective Catalytic Reduction (SCR) 2,728,460 28.5 71 120 0.06 1,582 11,4LNB with SCR 2,728,460 28.5 71 120 0.06 1,582 11,4LNB and OFA with SCR 2,728,460 28.5 71 120 0.06 1,582 11,4

Note: Emissions are per Unit for the Unit 4 & 5 table.

Option

Stack NOx

NOx Existing rate (lb/MMBTU): 0.49 

4 of 4 
Arizona Public Service 

Four Corners Units 1 through 5 Appendix F 

102907 F-1 

Appendix F 

Annual Emissions Summary Table 
Arizona Public Service 

Four Corners Units 1 through 5 102907 

APS Four Corners Steam Electric Station 

Annual Emissions Summary 

The following tables contain information for annual heat input, capacity factors, SO2 tons, NOx tons, PM10 ton

each unit at Four Corners Steam Electric Station. Heat input (mmBtu), SO2 (tons), NOx (lb/mmBtu), and NO

from CEMS information. The NOx (tons) is calculated using the annual NOx mass emission rate (lb/mmBtu) mu

heat input total (mmBtu). The PM10 (tons) is calculated using the annual total particulate emissions rate t

multiplied by the CEMS heat input (mmBtu). H2SO4 (tons) is calculated using Southern Company’s metho

sulfuric acid emissions from stationary power plants. Most data is provided for the calendar years 2002 through 

Year Unit 

Heat Input 

(mmBtu) 

Capacity Factor

(%) 

SO2

(tons) 

NOx

(lb/mmBtu) 

NOx

(tons) 

PM 

(lb/mmBtu) 

(

2002 1 13,740,127 78.92 N/A 0.767 5,269 0.033 2003 1 14,616,287 87.31 N/A 0.768 5,613 0.023 2004 1 14,986,804 90.19 N/A 0.792 5,935 0.020 2005 1 13,764,408 85.38 879.8 0.782 5,382 0.028 2006 1 15,708,239 96.71 910.9 0.804 6,315 0.021 

Year Unit 

Heat Input 

(mmBtu) 

Capacity Factor

(%) 

SO2

(tons) 

NOx

(lb/mmBtu) 

NOx

(tons) 

PM 

(lb/mmBtu) 

(

2002 2 16,632,804 88.31 N/A 0.614 5,106 0.022 2003 2 14,138,653 85.30 N/A 0.618 4,369 0.027 2004 2 13,261,038 80.66 N/A 0.663 4,396 0.023 2005 2 15,546,054 95.15 1,054.7 0.654 5,084 0.050 2006 2 15,272,703 93.61 901.7 0.653 4,987 0.024 

* Southern Company’s method for estimating total sulfuric acid emissions requires coal heat input information. T

emissions have not been calculated due to the annual coal heat input information not being available at the time o
Arizona Public Service 

Four Corners Units 1 through 5 102907 

Year Unit 

Heat Input 

(mmBtu) 

Capacity Factor

(%) 

SO2

(tons) 

NOx

(lb/mmBtu) 

NOx

(tons) 

PM 

(lb/mmBtu) 

(

2002 3 19,873,581 88.58 N/A 0.570 5,664 0.040 2003 3 17,341,579 76.34 N/A 0.578 5,012 0.026 2004 3 20,819,150 92.59 N/A 0.600 6,246 0.023 2005 3 20,865,668 91.75 1,566.6 0.584 6,093 0.039 2006 3 17,101,624 72.29 1,357.5 0.602 5,148 0.018 

Year Unit 

Heat Input 

(mmBtu) 

Capacity Factor

(%) 

SO2

(tons) 

NOx

(lb/mmBtu) 

NOx

(tons) 

PM 

(lb/mmBtu) 

(

2002 4 57,787,846 88.01 N/A 0.566 16,354 0.015 2003 4 56,712,865 91.76 N/A 0.565 16,021 0.007 2004 4 42,188,456 69.22 N/A 0.464 9,788 0.004 2005 4 54,882,182 89.01 4,538.0 0.458 12,568 0.018 2006 4 56,476,068 90.08 5,901.1 0.488 13,780 0.025 

Year Unit 

Heat Input 

(mmBtu) 

Capacity Factor

(%) 

SO2

(tons) 

NOx

(lb/mmBtu) 

NOx

(tons) 

PM 

(lb/mmBtu) 

(

2002 5 37,592,636 58.19 N/A 0.450 8,458 0.011 2003 5 56,065,980 87.76 N/A 0.484 13,568 0.012 2004 5 56,059,669 94.57 N/A 0.495 13,875 0.004 2005 5 51,267,335 83.14 4,515.3 0.472 12,099 0.012 2006 5 55,280,458 88.64 6,121.2 0.498 13,765 0.009 

* Southern Company’s method for estimating total sulfuric acid emissions requires coal heat input information. 

emissions have not been calculated due to the annual coal heat input information not being available at the time o