# 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 Re trofit Emission Control Technologies (Step 1)................................................................................................................. 3-1
3.1 NO x 

# Control Technologies....................................................................... 3-1 3.1.1 Combustion Optimization System............................................. 3-1
3.1.2 Low NO x 

# Burners...................................................................... 3-2
3.1.3 Low NO x 

# Burners and Overfire Air System.............................. 3-3
3.1.4 Mobotec ROFA and ROTAMIX............................................... 3-4
3.1.5 NO x 

# Star and NO x 

# Star 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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## Arizona Public Service 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 LoTO x 

# ...................................................................................... 3-13
3.1.12 Natural Gas Reburn ................................................................. 3-13
3.1.13 THERMALONO x 

# Process....................................................... 3-15 3.1.14 Oxygen Enhanced Combustion ............................................... 3-15 3.1.15 Biotechnological Den itrification (BioDeNO x 

# ) ........................ 3-16
3.2 Particulate Matter C ontrol 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 Up stream 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 Emissi on Control Technologies (Step 2) ............. 4-1
4.1 NO x 

# 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 NO x 

# 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 NO x 

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

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## Arizona Public Service 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 NO x 

# Cost-Effectiveness Summary................................................ 7-2
7.3 Unit 2 NO x 

# Cost-Effectiveness Summary................................................ 7-3
7.4 Unit 3 NO x 

# Cost-Effectiveness Summary................................................ 7-3
7.5 Units 4 and 5 NO x 

# Cost-Effectiveness Summary .................................... 7-4
7.6 Unit 1 Particulate Matter Co st-Effectiveness Summary.......................... 7-4
7.7 Unit 2 Particulate Matter Co st-Effectiveness Summary.......................... 7-4
7.8 Unit 3 Particulate Matter Co st-Effectiveness Summary.......................... 7-5
7.9 Unit 4 Particulate Matter Co st-Effectiveness Summary.......................... 7-5
7.10 Unit 5 Particulate Matter Co st-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 thr ough 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 thr ough 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 NO x 

# 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 NO x 

# Reduction Technologies--Units 1, 2, and 3..................................................................................................... 5-2
Table 5-2 Control Effectiveness for NO x 

# Reduction Technologies--Units 4 and 5......................................................................................................... 5-4

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## Arizona Public Service 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 - NO x 

# Cost-Effectiveness Summary ............................................. 6-5
Table 6-3 Unit 2 - NO x 

# Cost-Effectiveness Summary ............................................. 6-7
Table 6-4 Unit 3 - NO x 

# Cost-Effectiveness Summary ............................................. 6-9
Table 6-5 Units 4 and 5 - NO x 

# 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 NO x 

# Cost-Effectiveness Summary........................................................... 7-7

Figures

Figure ES-1 Unit 1 - NO x 

# Cost-Effectiveness............................................................ES-5 Figure ES-2 Unit 2 - NO x 

# Cost-Effectiveness............................................................ES-6 Figure ES-3 Unit 3 - NO x 

# Cost-Effectiveness............................................................ES-7 Figure ES-4 Units 4 and 5 - NO x 

# Cost-Effectiveness ................................................ES-8 Figure 3-1 Staged Combustion of LNBs and OFA System....................................... 3-4 Figure 3-2 Mobotec ROFA and ROTA MIX Simplified Process Flow Diagram.................................................................................................... 3-5 Figure 3-3 ECOTUBE Insta llation 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 Pa rticulate 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 Simplif ied Process Flow Diagram............................. 3-29 Figure 3-14 Phenix Clean Coal Process Flow Diagram ............................................ 3-31 Figure 6-1 Unit 1 - NO x 

# Cost-Effectiveness.............................................................. 6-6 Figure 6-2 Unit 2 - NO x 

# Cost-Effectiveness.............................................................. 6-8

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## Arizona Public Service Four Corners Units 1 through 5 Contents

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# Contents (Continued) Figures (Continued)

Figure 6-3 Unit 3 - NO x 

# Cost-Effectiveness............................................................ 6-10 Figure 6-4 Units 4 and 5 - NO x 

# 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 (B ART) analysis for its Four Corners Generating Station Units 1 through 5. The Environmental Protect ion 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 reduc tion of nitrogen oxides (NO x 

# ) and particulate matter (PM) emissions from Four Corners Units 1 through 5. The BART engine ering 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 engineeri ng analysis, a detailed design basis was established for Four Corners Units 1 through 5. The design basis wa s established on the basis of information collected during the si te visit, plant operating data, combustion calculations performed, and assumptions made for the study. Information on the operational characteristics of F our Corners Units 1 through 5 was also used to establish the design basis. A summary of the operationa l characteristics is shown in Table ES-1. The design basis is shown in Appendix A. Th e design basis was then used to create the technology removal matrix, establishing the anticipated emissions reduction for each applicable technology. The t echnology 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 an alysis to determine the cost-effectiveness of these technologies. Data for the economic design criteria were de veloped with APS to best represent the actual operational cost s 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 presum ptive 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, av ailable retrofit emissions control technologies that may be prac tically implemented at the Fo ur Corners Units 1 through 5
are identified. From this lis t of available technologies, t echnically feasible control technologies are identified in Step 2.

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## Arizona Public Service 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 Subcriti cal Subcritical Supercritical

Draft of Boiler Balanced Ba lanced Balanced Forced Existing Emissions Control

Combustion Controls for NO x 

## 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

SO 2 

## Venturi Scrubber Venturi Scrubber Venturi Scrubber Wet Lime Scrubber (1) Values are per unit. B&W - Babcock & Wilcox; LNB - Low NO x 

## Burner

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## Arizona Public Service 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 ($/m 3 

## ) 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 u sed during the development of this study. However, this information is not being di sclosed (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)



## NO x 

## PM (2) 

## NO x 

## PM (2) 

## NO x 

## PM (2) 

## NO x 

## 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 ar e for filterable PM only.

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## Arizona Public Service Four Corners Units 1 through 5 Executive Summary

120407 ES-4 

# 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 s ite, which are determined by considering the current configuration of the equipment and th e situation at the pl ant site. The design parameters and control effectiveness for each control technology are summarized in the design concept definitions sheet. The design co ncept definitions sheets developed for all of the identified technically feasible contro l technologies are include d 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 consider s 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: averag e 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 tec hnologies 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 s hould be noted that the leastcost envelope is a visual aid and is a repres entation of the data; it is not intended as a
substitute to the cost-effectiveness and in cremental 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 ex isting plant condition, retrofit difficulty of the control technology, visibi lity impacts, and operational impacts of the new control technologies to determine the best contro l technologies for BART compliance.



# ES.4 Engineering Analysis Findings B&V completed only the engineering por tion of the APS Four Corners BART analysis, the impact on visibility in federal Cl ass I areas was not part of the scope of this study. B&V identifies the engineering portion as the identification of a ll available retrofit control technologies, elimination of the tec hnically infeasible opt ions, evaluation of control effectiveness of the remaining contro l technologies, evaluation cost impacts, andArizona Public ServiceFour Corners Units 1 through 5Executive SummaryFigure ES-1Unit 1 - NOxCost-Effectiveness120407ES-5Arizona Public ServiceFour Corners Units 1 through 5Executive SummaryFigure ES-2Cost-EUnit 2 - NOxffectiveness120407ES-6Arizona Public ServiceFour Corners Units 1 through 5Executive SummaryFigure ES-3Cost-EUnit 3 - NOxffectiveness120407ES-7120407ES-8Arizona Public ServiceFour Corners Units 1 through 5Executive SummaryFigure ES-4Units 4 and 5 - NOxCost-Effectiveness

## Arizona Public Service Four Corners Units 1 through 5 Executive Summary



# documentation of the results. The fifth and fina l step of the BART analysis, the visibility modeling, was not performed by B&V. This an alysis determined the cost-effectiveness on a dollar per ton of pollutant removed. Th e final selection of BART will be based on both the cost-effectiveness study and the re sults of the visib ility analysis. Although the combination of OFA and LN B 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 a nd 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 leve l of detail required to develop this repo rt did not provide enough evidence to confirm with certainty the feasibility of OFA and LNB when the specific history of difficult operational performance is consid ered. Therefore, additional investigations will be necessary to positivel y 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 NO x 

# BART. The wet electrostatic precipitator (WESP) offers the
same PM reduction for a lower annual cost th an other PM removal te chnologies for Units 1, 2, and 3. Units 4 and 5 currently have fabr ic filters installed a nd, 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 consid ering the visibility results from the third-party modeler a nd the engineering analysis su mmarized in this report by
B&V.

120407 ES-9

## Arizona Public Service Four Corners Units 1 through 5 Introduction and Objectives



# 1.0 In troduction 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 (NO x 

# ) and PM. This report documents the BA RT engineering analysis process and
results obtained.



# 1.1 Source Description and Background Four Corners Units 1 through 3 are subc ritical, front wall fired boilers burning bituminous coal, operating under balanced draf t 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 vent uri scrubbers for sulfur dioxide (SO 2 

# ) and PM control. Units 4 and 5 are equipped with wet scrubbers for SO 2 

# removal and reverse gas fabric filters for particulate emissions contro l; both wet scrubbers and fabric filters are
considered Best Available Control Technol ogy (BACT) technologies. Unit 1 had burner modifications performed in 1977 for NO x 

# purposes, while Units 3, 4, and 5 are equipped with late-1980s vintage LNBs, and Unit 2 ha d LNBs installed in 1998. A summary of the unit configurations and operational char acteristics is noted in Table 1-1.



# 1.2 BART Analysis Methodology The BART study is used to identify th e 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 follo wing issues are given consideration:

• Technical feasibility.

• Cost of compliance.

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

• Other existing pollution cont rol 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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## Arizona Public Service 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 WallFired/TangentTube Furnace, Riley Stoker Front WallFired/ 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 Subcriti cal Subcritical Supercritical
Draft of Boiler Balanced Ba lanced Balanced Forced Existing Emissions Controls

Combustion Controls for NO x 

## 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
SO 2 

## Venturi Scrubber Venturi Scrubber Venturi Scrubber Wet Lime Scrubber

(1)Values are per Unit. B&W - Babcock & Wilcox LNB - Low NO x 

## Burner

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## Arizona Public Service Four Corners Units 1 through 5 Introduction and Objectives



# The BART analysis is a five-step proce ss to select the best available method of emissions reduction for PM, NO x 

# , and SO 2 

# 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 NO x 

# 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 Retrof it Control Technologies (Step 1) The first step of the BART analysis is the identification of all available retrofit emissions control technologies. An emi ssions control technology is considered an available retrofit if it has pr actical potential for applicatio n to the emissions unit. An available retrofit can be a system, technol ogy, or change in operational method for the control of a pollutant. Tec hnologies that have been succ essfully applied to similar sources or with similar flue gas characterist ics are considered as available. However, technologies in the development stage or th at have not been applied to full scale operations are not considered to be available. If the sour ce is equipped with existing control technologies, the BART study will incl ude improvements or optimization of the existing control technologies. Section 3.0 a ddresses the requirements of Step 1 of the BART analysis.

1.2.2 Eliminate Technically Infeasible Options (Step 2) Next, the BART analysis involves the ev aluation of all the identified available retrofit control technologies to determine th eir technical feasibilit y. A control technology is technically feasible if it has been previously installed and operated successfully for the type of source under review under similar condi tions, on a source of comparable size, or the technology can be applied to the source und er 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 commer cially by vendors or pr oviders or is in commercial demonstration or licensing is deem ed 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 prev iously installed and operated at a similar type of source, or a source with similar gas stream characteristics.

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## Arizona Public Service 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 contro l technology alternatives are identified in Step 2, the control effectiveness of each emissi ons 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 consid ering regulatory decisions and evaluations that have been performed on the effec tiveness 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 st ringent 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 Do cument the Results (Step 4)
Once the control effectiveness is establis hed in Step 3 for each of the feasible technologies identified in Step 2, each cont rol 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 re ferences. 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 determine d. The annualized cost includ es capital, installation, and indirect cost associated with the equipment re trofit. 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 Sta ndards (OAQPS) manual and adde d to the levelized annual cost of the technology. The cost-effectivene ss compares the potential technologies on an economic basis. Two types of cost-effectiven ess are considered in the BART analysis: average and incremental cost-effectiveness. The average cost-effectiveness is defined as

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## Arizona Public Service 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 technol ogy 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 tec hnology 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 th e control technology and the increase in auxiliary power required by the fans to overc ome any additional system resistance of the control technology. The cost of these energy impacts is the co st of lost generation caused by the control technology and is included in the cost of compliance analysis. Non-air quality environmental impacts ar e 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 consider ed only when the source has a shorter remaining useful life than the expected servic e 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 cont rol technology, particularly for technologies that require a large capital expenditure.

1.2.5 Evaluate Visibili ty Impacts (Step 5) Potential visibility improvement from the addition of each control technology was determined from modeling results perfor med 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 determin ed the visibility improvements over the established baseline.

1.2.6 Selecting the Best Alternative By summarizing all the analyses perform ed in the five steps described above, a
decision on the best alternative of contro l technology can be made based on the costeffectiveness, impacts, and the resultant vi sibility improvement. B&V has not selected the proposed BART technology because it has not been involved in th e modeling process.
B&V understands that APS will make the de termination of proposed BART technology after considering the vi sibility 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 Ba sis 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 result s from combustion calculations. The information in the design basis was used fo r 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 basi s was then used to create the technology removal matrix, establishing the anticipated emissions reduction for each applicable technology. The technology removal matr ix is included as Appendix B.



# 2.2 Economic Design Criteria To perform the economic analysis, capit al and annual operating cost estimates were developed for each of the emissions contro l alternatives. The cap ital cost estimates were based on the Coal Utility Environmenta l Cost (CUECost) generated estimates, cost data supplied by equipment ve ndor (budget estimates), estima tes from previous in-house design/build projects, and projected costs from APS Four Corners Generating Station. The annual operating cost estimates were base d on operation at full load conditions. The annual operating costs covered increases in fa n auxiliary power requirements, additional labor requirements, water costs, waste produc t 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 pe rform this economic analysis.

2.2.1 Capital Cost Estimates Capital costs were developed for retrofit control technologies th at were identified as technically feasible for application at F our Corners Units 1 thr ough 5. Direct costs comprise purchased equipment, installation, and miscellaneous costs. The equipment costs include the purchase of the control technology equipmen t 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 si te configuration and condition. Finally, miscellaneous costs account for addi tional items, such as site preparation, buildings, and other structures.

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## Arizona Public Service 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 ($/m 3 

## ) 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 u sed during the development of this study. However, this information is not being di sclosed (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, wate r, air) are provided by the Owner.
Indirect costs are not relate d 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 redesi gn or modification of equipm ent; errors in estimation;
unforeseen weather-related dela ys; strikes and labor shortage s; increases in equipment costs; increases in labor costs; delays encounter ed 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 te chnologies, 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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## Arizona Public Service Four Corners Units 1 through 5 Basis of Analysis


# 2.2.1.3 Construction and Field Expenses. Construction management services include field management st aff including supporting staff personnel, field contract administration, field inspection and quality assu rance, project control, technical direction, and management of startup. It also include s cleanup expense for the portion not included in the direct-cost construction contracts, sa fety and medical services, guards and other security services, insurance premiums, ot her 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 includ ed 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 th e 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. Th e results of the performance test are used to ensure compliance with performance guarantees and emissions limits. 2.2.1.6 Contingency. Contingency accounts for unpred ictable events and costs that could not be anticipated during the normal cost development of a project. Costs assumed to be included in the contingency cost cate gory are items such as possible redesign and equipment modifications, errors in estimati on, unforeseen weather-re lated delays, strikes and labor shortages, es calation increases in equipment costs, increases in labor costs, delays encountered in startup, etc.

2.2.2 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, ma keup water, wastewater treatment, and byproduct disposal are variable costs and ar e dependent on the amount of pollutant
removed. O&M materials and la bor 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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## Arizona Public Service 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 a ssociated with reagent, such as reagent preparation, are not included in the reagent cost. Reagent cost s depend on the quantity of the reagent used and the price of the reagent. The quantit y of reagent will de pend on the amount of pollutant removed and the reagent utilization ratio. 2.2.2.2 Electric Power Costs. Additional auxiliary power wi ll 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 in duced draft (ID) fan to overcome flue gas pressure losses across the new equipment. 2.2.2.3 Makeup and Se rvice Water Costs. Makeup and service water is required for some processes in the new control technol ogy systems. Water is used for ammonia solution preparation for SCR and selective nonc atalytic 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 servic e water. Depending on the process, the appropriate water type was in cluded in this cost category. 2.2.2.4 Wastewater and By product Disposal Costs. Some control technologies generate wastewater and/or byp roduct that will require di sposal. This portion of the engineering analysis considers only NO x 

# , the main byproduct disposal consideration will be the possibility of rendering the fly ash unsaleable du e to ammonia (NH 3 

# ) 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 qua ntity. The labor cost is based on a fully loaded labor rate, with the ba sis of a 50 hour per week work schedule. Typically, a complex emissions control te chnology 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 Mate rials 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 th at replace a similar existing technology in the current plant site, a determination of th e additional maintenance requirements is

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## Arizona Public Service 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 we re based on guidance from the APS Four Corners Generating Station regarding its ex perience with maintenance costs. Past experience has shown the maintenance and labo r 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 ma intenance value of 3 percent of the total direct capital costs.



# 2.3 Baseline Emissions

The baseline emissions for NO x 

# and PM are required to be established for this BART analysis to compare the impacts of each of the control t echnologies. Baseline
emissions are defined to be the current em issions under the existing plant equipment and operational configuration conditi ons at the time this study wa s conducted. These baseline emissions already include the effect of add itional emissions control equipment installed over the operational life of Units 1 through 5. The baseline emissions are calculated from the average of the annual NO x 

# and PM emissions rate from the last 5 years. The annual
NO x 

# and PM emissions from each of the last 5 years are presented in Appendix F. The
baseline emissions established for Four Co rners Units 1 through 5 are summarized in
Table 2-3. It should be not ed 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

NO x 

## PM Nitrogen Oxide (NO) PM NO x 

## PM NO x 

## 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 H aze Regulations and Guidelines for BART issued in July 2005, presumptive limits that apply to BART-elig ible sources are outlined. Since the EPA has specified that the Four Co rners facility is subject to BART for NO x 

# and PM, the presumptive limit for NO x 

# differs according to the boiler design and type of coal that is burned. In the case of dry bo ttom-wall fired, bituminous coal units, such as

120407 2-6

## Arizona Public Service Four Corners Units 1 through 5 Basis of Analysis

120407 2-7 

# Four Corners Units 1 through 3, the presumptive limit for NO x 

# is 0.39 lb/mmBtu. The presumptive limit for Units 4 and 5 is 0.40 lb /mmBtu. The BART presumptive limits for
NO x 

# 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 NO x 

## PM (2) 

## NO x 

## PM (2) 

## NO x 

## PM (2) 

## NO x 

## 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 Id entification of All Available Retrofit Emission Control Technologies (Step 1)

In Step 1 of the BART analysis, all av ailable 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 secti on, control technologies for NO x 

# reduction are listed with a brief description. The design, retrofit considera tions, and advantages and disadvantages of each technology are also outlined.



# 3.1 NO x 

# Control Technologies

NO x 

# control technologies that were identifi ed 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.

• NO x 

# Star and NO x 

# Star Plus.

• ECOTUBE.

• Induced flue gas recirculation (IFGR).

• SCR.

• SNCR.

• SCR/SNCR hybrid (Cascade System).

• LoTO x 

# .

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

• THERMALONO x 

# Process.

• Oxygen enhanced combustion.

• Biotechnological deni trification (BioDeNO x 

# ).

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 maxi mum amount of heat with the minimum amount of waste. However, w ithout 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 combusti on, 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 a nd result in excess carbon monoxide (CO), fly ash loss on ignition (LOI), or NO x 

# emissions. In an attempt to prevent or reduce these e ffects, plants often tu rn to the procedure known as “burner balancing.” Th is entails the mon itoring and adjustme nt 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 main tain across the normal boiler load range. Initial attempts at monitoring LNB perfor mance were directed toward measuring flue gas constituents leaving the boiler, whic h provided an indication of the total air to fuel ratio and average NO x 

# 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 a nd 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 fl ame patterns. With this additional level of online performance data, the secondary airflo w and coal mill feeders can be biased to continuously maintain burner to burner balance. Additionally, recent advan ces in computer hardware and software technology have enabled power generation companies to improve their competitive position by implementing cost-effective optimization soluti ons that decrease emissions and maximize plant efficiency. This solution, commonly re ferred to as boiler opt imization or neural network systems, provides simultaneous im provements in both fuel efficiency and emissions. Neural network computing di ffers from traditional computing because engineering, statistical, and first law principles have b een supplemented by complex, time varying, nonlinear relationships . Neural network systems us e real-time operational data extracted from a plant distributed control system (DCS), “learn” solutions from plant operational experience, and reduce emissi ons while improving plant performance by continuously adapting to changes in plant operation. Neural network systems also supplement other NO x 

# reduction strategies. Some of these include LNBs, OFA, and postcombustion controls such as SCR and SNCR. These systems are also used to help boiler manuf acturers tune boilers with poor combustion characteristics, or after an LNB retrofit or other boiler modifications, such as OFA
modifications.

3.1.2 Low NO x



# Burners
NO x 

# , primarily in the form of NO and NO 2 

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

# and fuel NO x 

# . Thermal NO x 

# results from the
dissociation and oxidation of n itrogen 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 NO x 

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

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

# -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 NO x 

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

# 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 devolatiza tion and high temperature zones ar e not oxygen ric h. 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 n itrogen 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 NO x 

# . Any nitrogen escaping the initial fuel rich region has a greater opportunity to be converted to NO x 

# as the combustion process is completed. The ne t result of staged combustion is usually longer and/or wider flames, because of this de layed mixing process. This is also one of the main reasons why low NO x 

# combustion is normally associated with the potential for increased carbon in ash and higher CO emissi ons, as the combustion process begins to encroach on cooled boiler surfaces. This is pa rticularly 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 NO x



# Burners and Overfi re Air System In addition to the LNB system, an incremental approach to NO x 

# 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 NO x 

# emissions. Any residual unburned ma terial, such as CO and unburned carbon, which inevitably escapes the main burne r zone, is subsequently oxidized as the OFA is added. As with primary NO x 

# control, the performance that can be expected from a given OFA system depends on a number of factors. As the amount of 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 t ype, 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 carb on 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 OF A 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 NO x 

# reduction system that combines LNB, OFA, and SNCR technologies into an integrated system. The system uses a modified OFA system with improved mixing characteristic s achieved through adding a ro tation to the OFA. This system is called ROFA (Rotating Opposed Firing Air). In addi tion, ROTAMIX, which consists of adding urea into the furnace by inj ection 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 simplif ied process flow diagram of the ROFA and ROTAMIX system is illustrated on Figure 3-2.

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## Arizona Public Service Identification of All Available Retrofit Four Corners Units 1 through 5 Emission Control Technologies (Step 1)



# Figure 3-2 Mobotec ROFA and ROTAMIX Simp lified Process Flow Diagram

The NO x 

# reduction system has been commerci ally proven and has achieved up to 75 percent NO x 

# 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 moti on of the flue gas to be established. The main benefit of the ROFA system for Units 1, 2, and 3 w ill be the additional mixing due to the introduction of high velocity OFA. Additi onally, 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 NO x 

# Star and NO x 

# Star Plus
NO x 

# Star is the trademarked name for an NO x 

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

# . The
ammonia reduces NO x 

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

# reductions than those achievable with a typical SN CR technology. A central premis e of the technology is the ability to achieve NO x 

# emissions of less than 0.20 lb/mmBtu without the use of a catalyst. Although initially targeting high NO x 

# reductions, full-scale demons trations to date have been limited to nominally 50 percent NO x 

# reduction performance.
NO x 

# Star 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. NO x 

# Star 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 c onfines of the boiler’s conv ective pass, eliminating the necessity to build a huge catal yst reactor and avoiding the as sociated SCR capital costs, economizer modifications, and major outag es. The other advantage of the NO x 

# Star system is that the conversion of SO 2 

# to sulfur trioxide (SO 3 

# ) is said to be negligible, thus eliminating one of the main dr awbacks of the SCR technology.
NO x 

# Star has a lower NO x 

# reduction efficiency than an SCR system; it also has a higher ammonia slippage rate than an SCR system. SO 3 

# 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 SO 3 

# in the flue gas. Ammonium bisulfate is a sticky substance that can deposit on air heat er baskets and other downstream equipment surfaces. Resultant particle di ameters at the stack are on the order of 1 to 3 microns and, thereby could contribute to PM 10 

# 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
NO x 

# Star 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 NO x 

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

# reduction.

3.1.6 ECOTUBE The ECOTUBE system is a boiler combustion improvement and NO x 

# reduction technology. Retractable lance tubes that penetrate the bo iler 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 NO x 

# , 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 u tilizes a similar approach as SOFA and SNCR. By creating turbulence at the best location in the ga s flow, an improved fuel/air ratio is achieved through better mixing, along with a lower stoichiometric ratio of O 2 

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

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## Arizona Public Service Identification of All Available Retrofit Four Corners Units 1 through 5 Emission Control Technologies (Step 1)



# Figure 3-3 ECOTUBE Installation in a Boiler

The water-cooled ECOTUBEs are automati cally retracted from the boiler on a regular basis and cleaned to remove layers of soot and other depositions. ECOTUBE’s self-cleaning capability and safe ty control system allow a safe and continuous operation. However, while the ECOTUBE system has be en removed from the boiler for cleaning,
NO x 

# 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 a nd erosion. ECOTUBE is expect ed to be less than half
the cost of SCRs and involves less installa tion downtime and boiler m odifications than an SCR. The main challenge of the ECOTUBE is th e available footprint at a retrofit site for the retractable lance and the structural integr ity of the lance as th e 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 NO x 

# emissions from gas and oil fired boilers since the early 1970s. Injection of flue gas into the combusti on air is a proven method for controlling NO x 

# production from gas fired utility boilers. Fo r units not equipped with gas recirculation fans, flue gas can be injected into the co mbustion air by a technique known as induced flue gas recirculation (IFGR).
IFGR acts to reduce NO x 

# formation by reducing peak flame temperatures. In conventional applications, the recirculated flue gas is typically extr acted from the boiler outlet duct upstream of the air heater. The fl ue 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 duc t that feeds the windbox. The recirculated flue gas is mixed with the com bustion air via air foils or othe r mixing devices in the duct. This technology is known as windbox flue ga s recirculation (WFG R). WFGR systems require installation of a separate hot gas flue gas recircul ation (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 eff ective on applications involving gaseous or liquid fuels, its effectiveness is limited w ith coal applications because it has a very limited capability to control the NO x 

# produced by the nitrogen bound in the fuel. Additionally, experience in the industry usi ng FGR for steam temperature control has exhibited a considerable amount of O&M pr oblems caused by erosion of the fans and dust accumulation in the ductwork. Consequent ly, the application of this tec hnology to coal fired units is virtually none xistent. Four Corners’ expe rience with the technology on
Units 4 and 5 has shown that it is not a viable option for NO x 

# reduction because of operational concerns.

3.1.8 Selective Cataly tic Reduction (SCR) SCR systems are the most widely used postcombustion NO x 

# control technology for achieving significant reductions in NO x 

# emissions. In SCR systems, vaporized ammonia injected into the flue gas str eam acts as a reducing agent, achieving NO x 

# emission reductions as low as 0.06 lb/mmBtu when passed over an appropriate amount of catalyst. The NO x 

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

# 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 ca talyst. The reactor is basically a widened section of ductwork modified by the addition of gas flow distribution devices, catalyst, catalyst support structures, access doors, and soot blowers. An ammonia injection grid is located ups tream of the SCR reactor, and the system can be designed with or without a flue gas bypass. The SC R reactor is typically elevated above and
behind the air heater and downstream of emi ssions control equipmen t (typically an ESP); gas flow direction through the reactor is ver tically downward for coal fired applications. In a “high dust” SCR arrangement, the react or 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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## Arizona Public Service Identification of All Available Retrofit Four Corners Units 1 through 5 Emission Control Technologies (Step 1)

120407 3-9 

# 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 SO 2 

# to SO 3 

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

# concentration. As the SO 3 

# concentration increases, the acid dew point of the flue gas increa ses, 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 SO 3


# . The ammonia reagent for the SCR systems can be supplied by anhydrous ammonia, aqueous ammonia, or by conversio n of urea to ammonia. Since the ammonia is vaporized prior to contact with the catalys t, the selection of am monia 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 re quirements. The vast major ity of worldwide installations use anhydrous ammonia, but recent safet y, 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 I solation* 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 interf acing system requirements to support operations. These requirements predominatel y relate to draft, auxiliary power, soot blowing steam, gas temperature, controls, ductw ork, reactor footprint, and air heater. The SCR system will affect the boiler draf t 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 modi fying the draft system with the addition of ID booster fans. If necessary, ductwork and/ or boiler box reinforc ement need to be considered. In conjunction with the fan modi fication, the upgrade of the auxiliary power system might be necessary. Auxiliary powermodifications may also be necessary for ammonia supply system requirements. The major impact of the SCR system can be seen at the air heater, where there are
two areas of concern. One concern is th e formation and deposition of ammonium
bisulfate on the air heater surface. This will cause an increase in the pressure drop of the air heater. The other potential danger for the air heater is high concentrations of SO 3 

# in the flue gas. If the acid dew point has been increased to more than the exhaust temperature, a significant amount of acid gases w ill 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 co mposition of the catalyst to minimize the SO 2 

# to SO 3 

# conversion rate and the proper temperatur e control of the flue gas entering the

reactor.

3.1.9 Selective Noncat alytic Reduction (SNCR) SNCR systems reduce NO x 

# emissions by injecting a reagent at multiple levels in the steam generator, as illustrated on Figur e 3-5. SNCR systems rely solely on reagent injection rather than a catal yst and an appropriate reagen t injection temperature, good reagent/gas mixing, and adequate reaction time to achieve NO x 

# reductions. SNCR systems can use either ammonia or urea as the reagent. Amm onia or urea is injected into areas of the steam generato r where the flue gas temper ature ranges from 1,500° to 2,200° F. The furnace of a pulverized coal fi red boiler operates at temperatures between 2,500° to 3,000° F. SNCR systems are capable of achieving an NO x 

# emission reduction as high as 50 to 60 percent in optimum conditions (adequate reaction time, temperature, and reagent/ flue gas mixing, hi gh baseline NO x 

# conditions, multiple levels of injectors), with ammonia slips of 10 to 50 parts per milli on by dry volume (ppmvd). Lower ammonia slip values can be achieved with lower NO x 

# reduction capabilities. Typically, optimum conditions are difficult to achieve, resultin g in emission reduction levels of 20 to 40 percent. Potential performance is site-s pecific and varies with fuel type, steam generator size, allowable ammonia slip, furn ace 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 NO x 

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

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

# . Accordingly, NO x 

# reductions and overall reaction stoichiometry are sensitive to the temperatur e of the flue gas at the reagent injection point. This complicates the application of SNCR for boile rs larger than 100 megawatts (MW). Reagent injection lances are usually located between the boiler soot blowers in the pendent superheat section. Optimum injectorlocation is mainly a function of temperature and residence time. To accommodate SNCR reaction temperature and boiler turndown requirements, several levels of in jection lances are no rmally installed. Typically, four to five levels of multiple la nce nozzles are installed if sufficient boiler height and residence time is av ailable. A flue gas residence time of at least 0.3 second in the optimum temperature range is desired to ensure adequate SNCR performance. Residence times in excess of 1 second yield high NO x 

# reduction levels even under less than ideal mixing conditions. Computational fluid dynamics (CFD) and chemical kinetic modeling can be performed to establish th e optimum ammonia injection locations and

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# flow patterns. For an existing boiler, minor waterwall modificati ons are necessary to accommodate the installation of SNCR inject or 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 compone nts and operating characteristics of both SNCR and SCR systems. Hybrid syst ems were developed to combine the low capital cost and high ammonia slip associ ated with SNCR systems with the high reduction potential and low ammoni a slip inherent to the cata lyst of SCR systems. The
result is a NO x 

# reduction alternative that can meet initially low NO x 

# reduction requirements, but can be upgraded to meet highe r 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 ope ration, the SNCR system would be allowed to inject higher amounts of reagent into the fl ue gas. This increased reagent flow has a
twofold effect: NO x 

# reduction within the boiler is in creased, and ammonia slip also increases. The ammonia that slips from th e SNCR is then used as the reagent for the catalyst. There are two design philosophies for usi ng this excess ammonia slip. The most conservative hybrid systems will use the catalys t simply as an ammonia slip “scrubber”
with some additional NO x 

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

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

# reduction is realized at the catalyst, the relatively small catalyst requirement of this design can poten tially fit all the catalyst in a true in-duct arrangement, with no significant ductwork changes, arrangement interference, or structural modifications. The second philosoph y uses adequate catalyst volume to obtain significant levels of additional NO x 

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

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

# , the SNCR must inject at least 3 ppm of ammonia to generate 1 ppm of a mmonia at the catalyst. Catalyst volume is strongly influenced by the NO x 

# 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 veloci ty are required, some modificati ons 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 LoTO x 

# The LoTO x 

# technology is the low temper ature gas phase oxidation of NO x 

# 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 NO 2 

# to form nitrogen pentoxide (N 2 

# O 5 

# ). The nitrogen pentoxide formed is soluble in water and can be removed from the flue gas using a wet FGD system.
The LoTO x 

# technology has been demonstrated on several industrial size plants, including Abitibi Consolidated (Sheldon, Texa s), a paper recycling plant, the Medical College of Ohio, and severa l refinery applications.
The LoTO x 

# technology offers high NO x 

# 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 gene rating 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 significantl y higher than the power consumption from an SCR. The nitrate produced from this technology is captured in the FGD waste product. Most regulatory agenci es 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 NO x 

# 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 ex cess air (a 1:10 stoichiometric ratio). A second combustion zone (the reburn zone) is created above th e lower furnace by operating a row of conventional natural gas burn ers at a stoichiometric ratio of less than 1.0. This technology also has the potential for increased furnace corrosion (especially with higher sulfur fuels) b ecause of the reducing atmos phere in the lower furnace.

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# Burnout Zone •Normal Excess Air

Reburning Zone •Slightly Fuel Rich •NOx Reduced to N 2



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

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

80 to 90% Coal 10% Excess Air

Figure 3-6 Schematic of Gas Reburn System

The substoichiometric reburn zone causes NO x 

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

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

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

# reduction of 40 to 65 percent. Sufficient residence time (adequate furn ace height) in the reburn and OFA zones is a key factor in determining whethe r the reburning technology can be applied. Successful retrofit of this technology requi res space within the boiler furnace to allow adequate residence time for both the additiona l burning zone (0.4 to 0.6 second) and the associated OFA burnout zone (0.6 to 0.9 se cond). When this sp ace 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 THERMALONO x



# Process
THERMALONO x TM 

# , a two step proce ss for controlling NO x, 

# once showed promise as an emerging technology. The first step co nsists of a gas-phase chemical reaction in
which NO is converted into NO 2 

# through a compac t gas reactor. The THERMALONO x TM 

# process uses direct injec tion of elemental phosphorus (P 4 

# ) into exhaust gas streams emitte d from fossil fuel fired comb ustion processes, at 121° C (250° F) to 280° C (536° F). The P 4 

# reacts simultaneously with oxygen to form ozone (O 3 

# ), which immediately reacts with NO to form NO 2 

# through a chain of ch emical reactions. The second step incorporates a stan dard wet FGD scrubber system for removing 90 percent of
the NO 2 

# , which is absorbed and dissolved into the water as nitrates, which are nonhazardous and can be recycl ed as a commer cial fertilizer. Despite the promising nature of this technology, full-scal e testing in 2001 indicated that it did not appreciably reduce NO x 

# emissions levels on one of the 375 MW units at the AEP Conesville plant. AEP canceled testing, and further demonstrat ion technology has not been completed.

3.1.14 Oxygen Enhanced Combustion Praxair, a purified gas su pplier, developed this NO x 

# control technology, which utilizes oxygen enhanced combustion. The cu rrent technology, as applied to coal fired boilers, replaces approximately 5 to 10 percent of the st oichiometric combustion air requirement with an equivalent amount of pure oxygen. This amount of pure oxygen reduces the throughput of co mbustion gases through the bo iler by a slig htly 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 lik ely be contracted to generate the oxygen onsite. Companies such as Praxair, Air Products, or BOC have typically built oxygen production facilities directly on an industr ial 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 ne w oxygen producing tech nology (called “oxygen transport membrane”) th at may cut oxygen costs; however, th is technology is still in the developmental stage. Oxygen enhanced staged combus tion serves to reduce both NO x 

# and unburned carbon through an increase in the local flame te mperature for a given stoichiometric ratio. The temperature in crease reduces NO x 

# by driving the reactions toward the formation of nitrogen rather than NO x 

# . The increased temperature, when coupled with higher local oxygen inlet concentrations, lead s to increased devolatilization ra tes, which, in turn, lead to
less residual carbon that must be burned in th e 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. Howeve r, a report recently completed for Seminole Electric by the El ectric Power Research Institute (EPRI) (Seminole Electric
NO x 

# Control Technology Assessment, Final Repor t, February 2005) in dicates that for a hypothetical 700 MW unit in which emissi ons have already been reduced through combustion controls, the estimate d cost for this technology is in the range of $1,900/ton removed. This cost is higher than other re cent SCR estimates prepared under the same market conditions. The study also reported em issions 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 De nitrification (BioDeNO x



# ) Biotechnological deni trification (BioDeNO x 

# ) technology is a patented process incorporated into an existing FGD scrubbe r to create the simultaneous removal of SO 2 

# and NO x 

# 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 [SO x 

# ] scrubber) and a bioreactor.
NO x 

# is present in the flue gas as NO and NO 2 

# . NO 2 

# dissolves easily in water and is removed from the flue ga s. NO is normally 95 percent of the total NO x 

# and is difficult to
dissolve in water. In the BioDeNO x 

# process, an iron chelate (F eII[EDTA]2-) is used that
reacts with NO to form a nitrosyl complex; this enables th e NO to dissolve in the water.
In the BioDeNO x 

# process, the regeneration of th e active FeII[EDTA]2- from the nitrosyl complex is solved by an inexpensive, simple biolog ical regeneration. The reduction of the nitrosyl complex is similar to the processes that occur in denitrifying wastewater systems. Ethanol is used as the reducing ag ent for the regeneration of the FeII[EDTA]2-. The regenerated FeII[EDTA]2- is recycled to the scrubber.
The BioDeNO x 

# process has high capital costs b ecause 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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## Arizona Public Service Identification of All Available Retrofit Four Corners Units 1 through 5 Emission Control Technologies (Step 1) 

# 3.2 Particulate Matter Control Technologies PM control technologies that were identi fied 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 di scharge electrodes and produce a high voltage,
direct current electrical field between the discharge electrodes and grounded collecting plates. PM entering the electrical field acqui res a negative charge and migrates to the grounded collecting plates. This migration can be expressed in engineering terms as an empirically determined effective migration ve locity, but it takes place in the turbulent flow regime, with the particul ate entrained within the turbulent gas patterns. Thus, the charged particles are actually ca ptured when the combined effect of electrical attraction and gas flow patterns moves the PM close eno ugh so that it can att ach to the collecting surfaces. A layer of collected particles fo rms on the collecting plates and is removed periodically by mechanically rapping the plates. The collect ed particulate drops into hoppers below the precipitator and is remo ved 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 characterist ics of the energization system determine the physical size of an ESP. Many parameters determine the ESP’s capability for particulate collection includi ng the major items discussed in this
subsection. The first parameter is the specific colle ction area (SCA). ESP size is often
measured in terms of SCA. SCA is defined as the total collecting area (ft 2 

# ) divided by the volumetric flue gas flow rate (1,000 act ual cubic feet per minute [acfm]).

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# Figure 3-7 Electrostatic Precipitator System (MHI)

Second, the treatment time that the flue ga s is within the elect ric collection fields of the ESP is an important aspect of pa rticulate collection. High efficiency ESPs typically have treatment times between 7 and 20 seconds. Treatment time is becoming a major design parameter, since lower part iculate emissions are being mandated. Flue gas velocity, which is the speed w ith 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 increas es, the re-entrainment losses from the ESP are minimized. Many exis ting ESPs have aspect ratios of around 0.8 to 1.2. Newer ESPs, especially those mee ting new particulate emission limits, have aspect ratios around 1.2 to 2.0.

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# The gas distribution for optimum part iculate removal requires uniform gas velocity throughout th e entire ESP treatment volume w ith 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 10 8 

# ohm-cm to 1 x 10 14 

# ohm-cm. The ideal resistivity range for electrostatic precip itation of fly ash is 5 x 10 9 

# to 5 x 10 10 

# ohm-cm. Operating resistivity varies with flue gas moisture, SO 3 

# concentration, temperature, and ash chemical composition. As a result of fly ash resistivity being sensitive to these constituents, ESPs can be significantly a ffected by changes in fuel or operating
conditions.

3.2.2 Pulse Jet Fabric Filter (PJFF)
Fabric filters are media filters that th e flue gas passes through to remove the particulate. Cloth filter media is typically se wn into cylindrical tubes called bags. Each fabric filter may have thousands of these filte r bags. The filter unit is typically divided into compartments, which allows online maintenance or bag replacement. The quantity of compartments is determined by maxi mum economic compartment size, total gas volume rate, air-to-cloth (A/C) ratio, and cl eaning system design. Extra compartments for maintenance or off-line cleaning increases the reliability at the expense of capital cost
and real state utilizat ion. Each compartment includes at least one hopper for temporary storage of the collected fly ash. A cutaway vi ew 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 clea ning technology, emissions limits, flue gas and ash characteristics, desired bag life, capital cost, A/C ratio, and pressure differential. Fabric bags are typically guara nteed for 3 years, but frequent ly last 5 years or more. In PJFFs, the flue gas typically enters the compartment hopper and passes from the outside of the bag to the inside, depositing particulate on the outside of the bag. To prevent the collapse of the ba g, a metal cage is installed on the inside of the bag. The flue gas passes up through the center of the bag into the outlet plenum. The bags and cages are suspended from a tubesheet.

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# Figure 3-8 PJFF Compartment

Cleaning is performed by in itiating a downward pulse of air into the top of the bag. The pulse causes a ripple effect along the length of the bag. This releases the dust cake from the bag surface. 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 minimi zed so that particulate is not re-entrained during the cleaning process. The PJFF cleans ba gs 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 appare nt shortcoming, PJFF have successfully implemented online cleaning on many large units.

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## Arizona Public Service Identification of All Available Retrofit Four Corners Units 1 through 5 Emission Control Technologies (Step 1)



# The PJFF bags are typically made of felted materials that do not rely as heavily on the dust cake’s filtering capabi lity as woven fiberglass bags. This allows the PJFF bags to be cleaned more vigorously. The felted mate rials also allow the PJFF to operate at a much higher cloth velocity, which significantl y reduces the size of the unit and the space required for installation.

3.2.3 Compact Hybrid Particulate Collector Another technology used for particulate cont rol 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 referr ed to as TOXECON I and is also trademarked by the EPRI. The COHPAC filter typically operates at A/C ra tios ranging from 6 to 8 feet per minute (ft/min) compared to a conventional fabric filt er that typically operates at A/C ratios of approximately 4 ft/min. For a COHPAC or TOXECON I system, th e majority of the particulate is collected in the upstream particulate cont rol 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 filtra tion media. This arrangement substantially lowers both cap ital and operating costs compared to
conventional fabric filters.

3.2.4 GE MAX-9 Hybrid
The Max-9 electrostatic filter is essentia lly a high efficiency PJFF that combines fabric filter and ESP technologi es. The Max-9 can be visuali zed 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 ordi nary precipitator. Since the particles are charged positively, they repel each other on th e 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 fi lter. Consequently, the Max-9 can operate at an A/C ratio higher than a conventional fa bric filter and can tr eat 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 pul ses 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 throug h 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 da nger of fire caused by sparking, and the transformer/rectifie r requires no voltage control. The Max-9 can be supplied as shop assemb led modules that can be erected onsite, although the units are usually custom-engineered for each plant site and application to make the best use of available space.

3.2.5 Multiple-Cyclone Multiple-cyclone separators, also known as multiclones, consist of a number of small diameter cyclones, operating in parall el 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 inne r 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 se paration of dust particul ates. The pressure drop of multiclone collectors is higher th an that of single-cyclone separators.

Figure 3-10 Multiclone Particulate Collector

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# Cyclone collectors are centrifugal collector s 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 as h to the edge of the cylinder. The flue gas then exits the center of the cyclone out the top, leaving the fl y 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 micr ons in size; particles less than 10 microns are usually unaffected and not removed.

Figure 3-11 Electrostatic Particle Aggl omeration System (Indigo)

3.2.6 Wet ESP A wet ESP collects particles on the same theo ry 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 alrea dy saturated, so the amount of added water is minimized. The particulate collection efficien cy 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). Therefor e, the wet ESP is well suited for fine particulate or acid mist applications by reducing opacity, sulfuric acid mist (H 2 

# SO 4 

# ), 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 indus trial installations. The pa rticulate char acteristics, temperature, and humidity in wet ESPs provide excellent fuel flexibility regarding particulate removal. Water chemistry, s caling, and corrosion potential need to be carefully investigated. The wet ESP collecting fields impart a nega tive 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 cont roller. The controllers for each transformer/rectifier are located in an environmentally controlled enclos ure. Each electrical field has a separate discharge electrode support frame suspended by alumina insulators. A heater-blower system dedicated to each module supplies wa rm purge air for each of the insulator compartments. The discharge electrode s upport frames are constructed from Type 304
stainless steel. The discha rge electrodes are suspended fr om the upper guide frame and
held in the tube center line. The discharge electrode is a ri gid electrode constructed from 304 stainless steel; it contains split corona generating elemen ts, which are welded to the electrode in an opposed orientation.
A wet ESP can be installed in either horizonta l or vertical gas flow orientation. In a horizontal gas flow orientati on, the wet ESP is very simila r 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 dens ities 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 inst alled 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,

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## 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 ge nerated by the wet ESP. In addition to this issue, the capital cost of a wet ESP is increa sed because of the higher cost of the alloy materials required. A higher grade of material is requi red to withstand the highly corrosive conditions presented by the wet and acidic flue gas stream. Each wet ESP module is cleaned by sp raying flush water over the wet ESP components. Flush water is sprayed in the we t ESP at different spray levels. Normally, each wet ESP module is flushed once per day. In dividual electrical se ctions of each field may be flushed online while the power is tu rned 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 solv ent to dissolve the scale buildup are two options. An alternate wet ESP technology reduces th e 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 dr ying 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 construc ted from polypropylene or PolyPhenylene Sulfide (PPS), which is resistant to corrosion and typically le ss expensive than high gr ade alloys of steel.

3.2.7 Particle Agglomerat ion Upstream of Dry ESP Electrostatic agglomeration upstream of dr y ESP is performed in the high velocity ductwork leading to the ESP. An electrostatic charge pretreat s 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 technol ogy is effective in increasing the dry ESP removal effi ciency for finer particles (PM 2.5 

# ) at a significantly lower capital cost than a new ESP or fabric filter.

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## 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 in to larger sizes and reducing the number of particles to be collected by the ESP, th ere will be a reduction in the overall PM emissions, reduced opacity emissions, higher fl ue gas flow rate, and a reduced pressure drop across the ESP. The agglomeration of the particles occu rs through two proce sses. A bipolar charger charges half of the dus t with a positive charge and half with a negative charge. As a result, the oppositely charged particles wi ll 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 th e flue gas with particulate flows. The attraction mechanism between the positively and negatively charged particles is enhanced by fluidic methods that are sp ecially designed, usua lly 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 ag glomerator is illust rated on Figure 3-11. The power consumption of the agglom eration device is typically low at 2 kilowatts (kW) per 100,000 acfm, with an expect ed pressure drop of less than 1 inch of water. Retrofit and outage issues for this te chnology 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 aggl omerator 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 ox idize and remove me rcury. Electrically induced oxidation of mercury is a new technolog y that is also being investigated. The list of emerging technologies is numerous; the most promising technologies include the PowerSpan ECO, EnviroScrub, and Phenix sy stems. 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 pilo t testing as the others . Since many of these technologies are still at the pilot (slipstream) st age of development, they should be
viewed with caution until more is known and performance guarantees become available. Generally, these technologies do not meet the ap plicability criteria se t 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 ha s 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 th e process consists of three stag es. In the first stage, the flue gas passes through a barrie r 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 radi cals, which then oxidize NO x 

# , SO 2 

# , 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, sulfur ic acid, and mercuric oxides. Stage 2 is the
collection of these acids and oxides in a dow nstream ammonia scrubber. The final stage
is the collection of acid aeros ols, fine PM, and oxidized mercury in the downstream wet
ESP. Scrubber effluents cont ain dissolved ammonium sulfate nitrate (ASN) salts, along with solids and mercury. The ASN solution is sent to a recove ry process where the mercury is removed via a sulfur impregnate d, 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

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## 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 th is process, mercury is oxidized via an ultraviolet (UV) light. The UV lights are pl aced in the ductwork upstream of particulate
control device. The PCO tec hnology is in its infancy; be cause PowerSpan’s PCO process has not moved beyond bench-scale testing and ha s not been pilot test ed at a facility burning a low sulfur coal, the techno logy will not be evaluated further.

3.3.2 EnviroScrub EnviroScrub is a multipollution control t echnology that is capable of removing significant amounts of elemen tal and oxidized mercury, NO x 

# , PM 2.5 

# , and SO 2 

# . This technology is based on the Pahl man 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. Th is is where the oxidation and adsorption of mercury takes place. Other pollutants such as SO 2 

# and NO x 

# are also adsorbed by the PS at this stage. Then, the S DA byproducts are separated from th e flue gas in the PJFF. The fly ash and waste byproduct collected in the PJFF hopper are even tually transported to a slurry tank for subsequent PS regeneration in a reactor. A process flow diagram of the Pahlman process is ill ustrated on Figure 3-13.

Figure 3-13 Pahlman Process Simplified Process Flow Diagram

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## 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, a nd byproduct separation. Although significant progress has been made on the sorbent regenera tion part of its tec hnology, EnviroScrub is not considered a proven, viab le technology. Since EnviroSc rub’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 prev ents the formation of NO x 

# and SO 2 

# emissions when coal is burned. The only reagent require d 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 NO x 

# and SO 2 

# 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 al l the chemicals in coal to complete their combustion reactions (to reach equilibrium conditions). The coal, with limestone added as a sour ce of calcium for sulfur capture, is pulverized and introduced to the burner al ong with a limited amount of hot combustion air. The initial high temperat ure 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 (H 2 

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

# , HCNs, and NH 4 

# , are forced to the molecular form (N 2 

# ) by the aggressive action of carbon for oxygen. In the presence of calcium, the sulfur reacts to form calcium su lfide (CaS, a solid “nong aseous” particle). The hydrogen (H 2 

# ) cannot compete with the other elements and remains H 2


# . The high combustion temperatures melt toge ther 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 H 2 

# , and nearly free of NO x 

# 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 CO 2 

# and H 2 

# to water. These steps prevent the formation of any new (thermal) NO x 

# and complete the combustion with excess air. The clean hot gases then enter th e boiler superheat section, which is as it was
before the retrofit. A schematic of the process is shown on Figure 3-14.

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## 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 re placing 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. Mo st 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 NO x 

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

# emissions (< 0.5 lb/mmBtu) with either we stern or midwest coals. Since the CCS process has not moved beyond the demonstra tion stage, the tec hnology will not be
evaluated further.

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## Arizona Public Service Technicall y Feasible Retrofit Emission Four Corners Units 1 through 5 Control Technologies (Step 2)



# 4.0 Te chnically Feasible Retrofit Emission Control Technologies (Step 2)

As stated in Subsection 1.2.2, applicab le emission control technologies are identified by eliminating technically infeasib le options from the av ailable 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 technol ogies 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 th at determine the appli cability 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 re st 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 NO x 

# Control Technologies A summary showing the results of the evaluation process for the NO x 

# 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 eval uation 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 un its have fabric filters installed for PM
control. Table 4-2 also in cludes the reasons why the elim inated control technologies were considered technically infeasible.

120407 4-1Arizona Public ServiceTechnically Feasible Retrofit EmissionFour Corners Units 1 through 5Control Technologies (Step 2)Table 4-1Technical Feasibility of NOxControl TechnologyTechnologyTechnicallyFeasible andApplicable?Reasons for Technical InfeasibilityUpgraded Boiler Optimization System (NeuralNetwork)Yes--LNBsYes--OFAYes--Mobotec ROFA and ROTAMIXUnits 1, 2and 3 only.ROTAMIX has not been demonstrated on units as large as Four CornersUnits 4 and 5.NOxStar and NOxStar PlusNoThe technology is not being marketed currently.ECOTUBENoThere is no existing installation at similar type/size source.IFGRNoThis technology is not applicable for coal fired plants.SCRYes--SNCRYes--SCR/SNCR Hybrid (Cascade System)NoThere is not available room for the ductwork expansion at the economizeroutlet required for the single layer of Catalyst for Units 1, 2, and 3.Cascade has not been demonstrated on units as large as Four CornersUnits 4 and 5.LoTOxNoThis technology does not have any operational units on plants as large asFour Corners.Natural Gas Reburn (includes FLGR, AE-FLGR)NoNot currently in use at similar type/size source. Up to 15 percent of loadproduced with natural gas can render this technology cost prohibitive.Cost-effectiveness is very difficult topredict because of the volatility ofnatural gas prices.THERMALONOx ProcessNoNot currently in use at similar type/size source. Technology is unprovenfor this application. No guarantee likely.Oxygen Enhanced CombustionNoNot currently in useat similar type/size source. Technology is unprovenfor this application. High cost of oxygen separation is cost prohibitive.Biotechnological Denitrification (BioDeNOx)NoNot currentlyin use at similar type/size source. Technology is unprovenfor this application. No guarantee likely.1204074-2Arizona Public ServiceTechnically Feasible Retrofit EmissionFour Corners Units 1 through 5Control Technologies (Step 2)1204074-3Table 4-2Technical Feasibility of PM Control Technology for Units 1, 2, and 3TechnologyTechnicallyFeasible andApplicable?Reasons for technical infeasibilityESPYes--PJFFYes--COHPACNoCOHPAC system is ineffective because of bag blinding caused by thefine particulate from the venturi scrubber.GE MAX-9 HybridNoMax-9 Hybrid Electrostatic has full scale demonstration; however, noneof these applications are on units of equivalent size to that of the units atAPS Four Corners.MulticycloneNoVenturi scrubbers and multicyclones are not effective at removing fineparticulate. The addition of a multicyclone is not expected to provideadditional PM reduction withthe existing venturi scrubbers.Particle AgglomerationNoParticle agglomeration has no performance data upstream of venturiscrubber, but has been successfultechnology upstream of cold ESP.Wet ESPYes--

## Arizona Public Service Technicall y 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 f ilters. Page 39165 of 40 CFR Part 51, which outlines the regulations and guidelines for th e 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 improvement s 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, in cluding 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 operati ons, and the reduction in emissions is not quantifiable. The Units 4 and 5 fabric filter s at the Four Corners Generating Station are equipped with “bad bag detectors” that no tify 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 f ilters are operating in accordance with industry standards for
fabric filters and should ther efore be considered BART.

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## Arizona Public Service Evaluation of Technically Feasible Retrofit Four Corners Units 1 through 5 Emission Control Techniques (Step 3)



# 5.0 Ev aluation of Technically Feasible Retrofit Emission Control Technologies (Step 3)

Step 3 of the BART determination pro cess is an evaluation of the control effectiveness for each of the technically f easible control technologies. The control
effectiveness is a common metric used to ensu re a fair “apples to apples” comparison; it is expressed as the amount of pollutant ge nerated 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 th e control effectiveness for each group of control technologies. The control effectiven ess for each technology is also summarized
in the stack emissions tabl es included as Appendix E.



# 5.1 NO x 

# Control Technologies The expected NO x 

# emissions rate, pr ojected annual emissions, and emission
reduction are summarized in Tables 5-1 and 5-2 for each of the NO x 

# removal technologies designated as feasible in Step 2. Because of the diffe rence in size between Units 1, 2, and 3 and Units 4 and 5, the analys is has been broken into two sections. Table 5-1 shows the NOx summary informati on 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, proj ected annual emissions, and emission
reduction are summarized in Table 5-3 for each of the particulate removal technologies designated as feasible in St ep 2. The PM values presented in Table 5-3 represent
filterable PM/PM 10


# .

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## 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 NO x 

# 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 NO x 

# 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 NO x 

# 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 Co st-Effectiveness and Imp act Analysis (Step 4)

6.1 Types of Impact Analysis For all of the technologies considered tec hnically 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 coul d 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 de fine the design parameters for each control technology that wa s identified as technically feasible. The design parameter contains all pertinent info rmation on the control technology system for specific application to the source. Exampl es of these design parameters include the following: the type of reagent used and c onsumption rate, type of byproduct produced and production rate, flue gas pressure drop across the control technology, furnace type and firing pattern, excess O 2 

# , burner zone heat release, etc. The information used to define the design paramete rs 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 t echnology that has been identified as technically feasible for a pplication 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 tec hnology when applied specifica lly 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 estimati ons 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 di rect 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 thr ough the control technology system and the flue gas pressure drop defined in the design parameter of the c ontrol 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 th e typical outage requirements, has been considered as an energy impact during the cost-effective analysis. The major non-air quality im pacts evaluated were the disposal requirements for the byproduct and waste generated by each co ntrol technology and the lost generation due to extended outages. Sinc e 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 re placement power was considered only for the
additional time that the units must remain of f-line, in addition to the planned outage, to incorporate the polluti on 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 ofUnits 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 wa s determined that the emissions reduction
should be calculated as follows:

Emissions Baseline Rate Emission Existing Rate Emission Outlet Proposed Rate Emission Existing Reduction Emission × −

=



# The baseline emissions for Units 1 through 5 are shown in Table 6-1. Both the
baseline emissions and the controlled emi ssion 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)

NO x 

# 5,703 4,788 5,633 13,028 PM (filterable) 180 220 285 313

6.3.1 NO x



# Control Technologies The cost-effectiveness summary for each of the NO x 

# 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. Si nce each technology considered had the same emissions rate, th e incremental cost-eff ectiveness 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 repr esentations are presented on Figures 6-5 to 6-8. Units 4 a nd 5 are not included in thes e tables, because the fabric
filters on the units have been deemed as BART, as explained in Subsection 4.2.1. Two

120407 6-3

## Arizona Public Service Cost-Effectiveness and Four Corners Units 1 through 5 Impact Analysis (Step 4)

120407 6-4 

# 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 re duction 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 th e overall PM removal, while Figures 6-6, 6-8,
and 6-10 show the additional PM removal.Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Table 6-2Unit 1 - NOxCost-Effectiveness SummaryAll Feasible TechnologiesEmissionPerformanceLevel(lb/mmBtu)ExpectedEmissionsRate (lb/h)ExpectedEmissionsReductions(tons/yr)Capital Costs(x $1,000)TotalAnnualizedCost(x $1,000)CostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)Unit 1 NOx(resultant emissions based on current 0.78 lb/mmBtu)COS0.721,3414561,429314688--(1)SNCR0.561,0431,6225,5723,1231,925--(1)Mobotec ROTAMIX0.561,0431,6227,2824,2772,637--(1)New LNBs0.438012,5693,823857334257(2)New LNB, OFA0.336153,2985,3541,204365476(3)New LNBs and SNCR0.325963,3718,9462,777824--(1)New LNBs, OFA, and ROTAMIX0.305593,51711,1053,508998--(1)Mobotec ROFA0.285223,6629,6572,956807--(1)New LNBs, OFA, and SNCR0.264843,80810,3372,746721--(1)New LNBs, OFA, and HERT0.203734,24510,0382,6796311,557(4)Mobotec ROFA and ROTAMIX0.193544,31813,6724,22397821,188(5)SCR0.081455,13488,23518,0563,51716,949(6)New LNBs, and SCR0.061125,26689,59517,8003,38014,332(6)New LNBs, OFA, and SCR0.061125,26690,19317,7503,37114,279(6)(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.1204076-5Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-1Unit 1 - NOxCost-Effectiveness1204076-6Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Table 6-3Unit 2 - NOxCost-Effectiveness SummaryAll Feasible TechnologiesEmissionPerformanceLevel(lb/mmBtu)ExpectedEmissionsRate (lb/h)ExpectedEmissionsReductions(tons/yr)Capital Costs(x $1,000)TotalAnnualizedCost(x $1,000)CostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)Unit 2 NOx(resultant emissions based on current 0.64 lb/mmBtu)COS0.601,1183021,4293141,039--(1)SNCR0.468571,3495,3972,7372,029--(1)Mobotec ROTAMIX0.458381,4247,2824,2773,004--(1)New LNBs0.438011,5733,823857545427(2)New LNB, OFA0.336152,3215,3551,204519464(3)New LNBs, OFA, and SNCR0.325962,3968,9462,7771,159--(1)New LNBs, OFA, and ROTAMIX0.305592,54511,1053,5081,378--(1)Mobotec ROFA0.285222,6959,6572,9561,097--(1)New LNBs, OFA, and SNCR0.264842,84410,3382,746965--(1)New LNBs, OFA, and HERT0.203733,29310,0392,6798141,517(4)Mobotec ROFA and ROTAMIX0.193543,36813,5324,1911,24420,221(5)SCR0.061194,31094,21618,9664,40115,688(6)New LNBs and SCR0.061124,34096,45019,0344,38615,270(6)New LNBs, OFA, and SCR0.061124,34097,04518,9834,37415,218(6)(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.1204076-7Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-2Unit 2 - NOxCost-Effectiveness1204076-8Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Table 6-4Unit 3 - NOxCost-Effectiveness SummaryAll Feasible TechnologiesEmissionPerformanceLevel(lb/mmBtu)ExpectedEmissionsRate (lb/h)ExpectedEmissionsReductions(tons/yr)Capital Costs(x $1,000)TotalAnnualizedCost(x $1,000)CostEffectiveness($/ton)IncrementalCost -Effectiveness($/ton)Unit 3 NOx(resultant emissions based on current 0.59 lb/mmBtu)COS0.561,3442571,4293141,221--(1)SNCR0.461,1041,2175,7623,1022,549--(1)Mobotec ROTAMIX0.451,0801,3137,4364,3113,283--(1)New LNBs0.431,0321,5053,777847563427(2)New LNB, OFA0.337922,4654,359979397138(3)New LNBs, OFA, and SNCR0.327682,5619,2853,1571,233--(1)New LNBs, OFA, and ROTAMIX0.307202,75311,2153,5361,284--(1)Mobotec ROFA0.286722,94510,7053,4061,157--(1)New LNBs, OFA, and SNCR0.266243,1379,7002,899924--(1)New LNBs, OFA, and HERT0.204803,71393402,8187591,474(4)Mobotec ROFA and ROTAMIX0.194563,80913,6894,8581,27521,253(5)SCR0.061445,05796,69019,9573,94712,100(6)New LNBs and SCR0.061445,05799,06620,0593,96712,182(6)New LNBs, OFA, and SCR0.061445,05798,58219,7953,91511,970(6)(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.1204076-9Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-3Unit 3 - NOxCost-Effectiveness1204076-10Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Table 6-5Units 4 and 5 - NOxCost-Effectiveness Summary - Values are per UnitAll Feasible TechnologiesEmissionPerformanceLevel(lb/mmBtu)ExpectedEmissionsRate (lb/h)ExpectedEmissionsReductions(tons/yr)Capital Costs(x $1,000)TotalAnnualizedCost(x $1,000)CostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)Units 4 and 5 NOx(resultant emissions based on current 0.49 lb/mmBtu)COS0.473,6696331,557348550--(1)SNCR0.382,9273,13811,0607,3312,336--(1)New LNBs0.453,5131,1608,0761,8201,5682,791(2)New LNB, OFA0.352,7323,79813,3203,008792450(3)New LNBs and SNCR0.322,4984,58918,9378,1431,775--(1)New LNBs, OFA, and SNCR0.262,0306,17123,1167,7541,2572,000(4)SCR0.0646811,445242,09051,4874,4998,292(5)New LNBs and SCR0.0646811,445249,85752,5004,5878,484(5)New LNBs, OFA, and SCR0.0646811,445254,31352,6824,6038,518(5)(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.1204076-11Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-4Units 4 and 5 - NOxCost-Effectiveness1204076-12Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Table 6-6Unit 1 - PM Cost-Effectiveness SummaryAll Feasible TechnologiesEmissionsPerformanceLevel(lb/mmBtu)ExpectedEmissionsRate (lb/h)ExpectedEmissionsReductions(tons/yr)Capital Costs(x $1,000)TotalAnnualizedCost(x $1,000)CostEffectiveness($/ton)PM (resultant emissions based on current 0.025 lb/mmBtu)ESP Upstream of Current AQCEquipment0.012229437,23610,169108,370PJFF Upstream of Current AQCEquipment0.012229450,51513,950148,659Wet ESP 1 (Metal) Downstreamof Venturi Scrubber0.012229432,1368,78193,571Wet ESP 2 (Membrane)Downstream of Venturi Scrubber0.012229423,3605,65260,231Note: Incremental cost-effectiveness is not defined.1204076-13Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-5Unit 1 - Overall View ofPM Cost-Effectiveness1204076-14Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-6Unit 1 - Incremental Viewof PM Cost-Effectiveness1204076-15Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Table 6-7Unit 2 - PM Cost-Effectiveness SummaryAll Feasible TechnologiesEmissionPerformanceLevel(lb/mmBtu)ExpectedEmissionsRate (lb/h)ExpectedEmissionsReductions(tons/yr)Capital Costs(x $1,000)TotalAnnualizedCost(x $1,000)CostEffectiveness($/ton)PM (resultant emissions based on current 0.029 lb/mmBtu)ESP Upstream of Current AQCEquipment0.0122212945,70211,01185,092PJFF Upstream of Current AQCEquipment0.0122212960,99214,481111,908Wet ESP 1 (Metal) Downstream ofVenturi Scrubber0.0122212932,8798,97269,335Wet ESP 2 (Membrane)Downstream of Venturi Scrubber0.0122212923,9016,65851,453Note: Incremental cost-effectiveness is not defined.1204076-16Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-7Unit 2 - Overall View ofPM Cost-Effectiveness1204076-17Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-8Unit 2 - Incremental Viewof PM Cost-Effectiveness1204076-18Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Table 6-8Unit 3 - PM Cost-Effectiveness SummaryAll Feasible TechnologiesEmissionPerformanceLevel(lb/mmBtu)ExpectedEmissionsRate (lb/h)ExpectedEmissionsReductions(tons/yr)Capital Costs(x $1,000)TotalAnnualizedCost(x $1,000)CostEffectiveness($/ton)PM (resultant emissions based on current 0.029 lb/mmBtu)ESP Upstream of Current AQCEquipment0.0122916840,13510,92565,164PJFF Upstream of Current AQCEquipment0.0122916859,59416,55998,770Wet ESP 1 (Metal) Downstream ofVenturi Scrubber0.0122916859,59410,30961,490Wet ESP 2 (Membrane)Downstream of Venturi Scrubber0.0122916826,9887,55745,075Note: Incremental cost-effectiveness is not defined.1204076-19Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)Figure 6-9Unit 3 - Overall View ofPM Cost-Effectiveness1204076-20Arizona Public ServiceCost-Effectiveness andFour Corners Units 1 through 5Impact Analysis (Step 4)1204076-21Figure 6-10Unit 3 - Incremental Viewof PM Cost-Effectiveness

## Arizona Public Service Four Corners Units 1 through 5 Results

120407 7-1 

# 7.0 Re sults

7.1 Cost-Effectiveness Summary The BART engineering analysis dete rmines the cost-effectiveness of each technology in two different ways. The averag e 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 ha s the minimum value for the average costeffectiveness. The second method of de scribing the cost-effec tiveness of a BART technology is via incremental co st-effectiveness. Incrementa l 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 prac tical, considering the large cost increase associated with that control option. The technology that rem oves the greatest amount of pollution before the incremental cost-effectiveness makes a larg e 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-effect ive than most recent AQC retrofits. The
NO x 

# 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 NO x 

# removed is more expensive than the previous ton. For example, Figure 6-1 de picts the low cost-low control of the neural network relative to the high cost-high control S CR. Following the curve left to right, as it bends upward, shows the increasing costs asso ciated 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 rela tive 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 assumpti ons. B&V’s experience with industry
standards is consistent with the predicted performance of these control technologies; however, these quotations may contain opti mistic conclusions regarding system

1 Federal Register , Wednesday July 6, 2005, 40 CFR Pa rt 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 specifi c 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 sy stem performance. Performance-based contractual guarantees are es tablished after a more thor ough engineering analysis. Consequently, B&V recommends basing the resu lts 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 NO x 

# Cost-Effectiveness Summary The type of furnace, type of fuel burned, and the existing NO x 

# controls affect the
cost-effectiveness of the NO x 

# control technologies. Four Corners Units 1 and 2 are front wall fired Riley furnaces, which have a re latively 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 OF A. 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, a nd new ID fans. This leads to an expensive cost, on a dollar per ton of NO x 

# removed basis, for the SCRs on Units 1 and 2. Combustion controls are expected to be integral in any NO x 

# solution because of the relatively high NO x 

# baseline. However, the plan t experience with LNB on Unit 2
demonstrates that a combusti on optimization approach to NO x 

# reduction must be cognizant of the challenges posed by the small furnaces.
The most cost-effective NO x 

# reductions, on a dollar per ton NO x 

# removed basis,
are available on Unit 1. This is due to the higher baseline emi ssions on Unit 1 when compared to the other units at the Four Corn ers 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
NO x 

# removed. This reduction represents a NO x 

# emissions reduction of 74 percent compared to the NO x 

# baseline. The expected emission rate of 0.20 lb/mmBtu of NO x 

# is 49 percent below the presumptive NO x 

# limit for the unit. If the presumptive limits are the target of the NO x 

# emissions reduction, the implementati on of a state-of-the -art LNB is the
most cost-effective NO x 

# reduction option, at a cost of $334 per ton of NO x 

# removed. Conversely, at $3,466 per ton of NO x 

# removed, the SCR is the most expensive NO x 

# reduction option.

120407 7-2

## Arizona Public Service Four Corners Units 1 through 5 Results



# 7.3 Unit 2 NO x 

# 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 NO x 

# retrofits challenging. Unit 2, however, presents the fu rther challenge of lim ited footprint area available for retrofits. Located tightly be tween Units 1 and 3, with a coal conveyor running on its north side, the access and available area for Un it 2 is extremely limited. The OFA system, which does not require a larg e footprint, is the least expensive method of reducing NO x 

# , 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 NO x 

# emissions rate of 0.64 lb/mmBtu as the Unit 2 baseline, NO x 

# production is about 20 percent lower than Unit 1. Additionally,
the current LNB on Unit 2 has cau sed 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 NO x 

# by combustion methods difficult. The small furnaces do not allow for effective combustion staging, a nd the closely spaced burners reduce the effectiveness of LNB. The LNB with OFA, LNB with OFA plus HERT, and SCR reduce
NO x 

# at a cost of $519, $814, and $4,401 per ton, respectively.



# 7.4 Unit 3 NO x 

# Cost-Effectiveness Summary Unit 3 is slightly larger than Units 1 and 2, but the NO x 

# BART analysis is very
similar for the three units. Unit 3 was al so retrofit with LN B and has current NO x 

# emissions of 0.59 lb/mmBtu. In fact, because of this retrofit, the annual NO x 

# tons emitted
from Unit 3 are lower than the emissions fr om 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 installa tion of SCR more expe nsive than a typical
SCR retrofit. The retrofit of Unit 3 w ith LNB and OFA represents the economic optimum, as defined in Section 7.1, at a cost of $397 per ton of NO x 

# removed. If more

120407 7-3

## Arizona Public Service Four Corners Units 1 through 5 Results



# aggressive NO x 

# reduction is found to be necessary as a result of modeling the visibility impacts, the LNB, OFA, and HERT system app ears to be the next mo st stringent option, at a cost of $759 per ton removed. The SCR al ternative is the most expensive option, at a cost of $3,947 per ton removed.



# 7.5 Units 4 and 5 NO x 

# Cost-Effectiveness Summary For the purposes of the BART analysis, Units 4 and 5 were considered to be identical units. This assumption was made b ecause the boilers are sister units, and the history of NO x 

# modifications is the same for both un its. Units 4 and 5 have the same gas path and have nearly identical performance and NO x 

# 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 ar e not proven on units as large as Units 4 and 5. The removal of the intermediate NO x 

# 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 NO x 

# at the cost of $792 per ton. By contrast, the SCR system is the least cost-effective option for NO x 

# reduction, with each ton removed costing $4,499 per ton. This translates to an incremental NO x 

# reduction cost of $8,099 per ton of NO x 

# 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 s econdary air heaters and the corresponding ductwork. The outage is expected to be signifi cant, with at least 14 weeks of downtime.



# 7.6 Unit 1 Particulate M atter Cost-Effectiveness Summary The venturi scrubbers currently contro l 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 ar e expected to c ontrol particulate emissions to 0.012 lb/mmBtu. This would reduce particulate emi ssions by 94 tons per year at a cost of $148,659 and $60,231 per ton for the fabric f ilter and wet ESP (membrane type), respectively. For this case, the BART e ngineering analysis indicates that wet ESP (membrane type) would be the mo st cost-effective technology.



# 7.7 Unit 2 Particulate M atter 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 Tabl e 4-2, like Unit 1, would be 0.012 lb/mmBtu. This would reduce particulate emissions by 129 tons per year at a cost

120407 7-4

## Arizona Public Service 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 a nd costly. It should
be noted that the Unit 2 base line 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) woul d be the most cost-e ffective technology for
Unit 2.



# 7.8 Unit 3 Particulate M atter Cost-Effectiveness Summary Unit 3 has the same existing particulate control equipment as Units 1 and 2. The venturi scrubbers currently control filte rable PM to 0.029 lb/mmBtu. The resulting
emissions after the installati on 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 mo st cost-effective technology.



# 7.9 Unit 4 Particulate M atter Cost-Effectiveness Summary
As outlined in Subsection 4.2.1, the fabric filter currently installed on Unit 4 represents BART; therefore, no cost-effectiv eness 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 curre ntly installed on Unit 5 represents BART; therefore, no cost-effectiv eness analysis was performed in accordance with the guidance in the Federal Register

.


# 7.11 BART Engineering Analysis Summary Two pollutants were consider ed as part of the APS Four Corners BART analysis,
NO x 

# and PM. This engineering analysis is used to determine the cost-effectiveness of available pollution control technologies. Th e engineering analysis was not used to determine which pollution control technology w ould represent BART for any of the five
units. The determination of the BART tec hnologies 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

120407 7-5

## Arizona Public Service Four Corners Units 1 through 5 Results

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 currentl y have fabric filters installed and, after analysis, have been shown to be BART for PM.
NO x 

# reduction at the Four Corners site is not as straightfo rward as the PM analysis. The available technol ogies offer a wide range of NO x 

# reduction, with varying levels of cost-effectiveness. APS has already implemented NO x 

# reduction projects since the construction of Units 1 through 5, whic h have mixed results. Units 1 and 2 are particularly challenging due to the small furn ace sizes and air heater arrangements. The design of Units 1, 2, and 3 is su ch that the retrofit of an SCR system is not possible
without the installation of ne w air heaters and FD fans, wh ich makes these options much more costly, with only incremental benefits in NO x 

# reduction. Although the combination of OFA and LN B 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 a nd 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 leve l of detail required to develop this repo rt did not provide enough evidence to confirm with certainty the feasibility of OFA and LNB when the specific history of difficult operational performance is consid ered. Therefore, additional investigations will be necessary to positivel y 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 “ec onomic optimum,” which is explained in Section 7.1 and shown in yellow on Tabl e 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 ex plained in Section 7-1, is shown in blue in
Table 7-1. The “incremental thre shold” scenarios represent the NO x 

# removal technologies at the inflecti on 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 tech nology 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 ServiceFour Corners Units 1 through 5ResultsTable 7-1NOxCost-Effectiveness SummaryUnit 1Unit 2Unit 3Units 4 and 5 (per Unit)All Feasible TechnologiesCost($/ton)IncrementalCost($/ton)Cost($/ton)IncrementalCost($/ton)Cost($/ton)IncrementalCost($/ton)Cost($/ton)IncrementalCost($/ton)COS688--1,039--1,221--550--SNCR1,925--2,029--2,549--2,336--MobotecROTAMIX2,637--3,004--3,283--N/AN/ANew LNBs3342575454275634271,5682,791New LNB and OFA365476519464397138792450NewLNBsandSNCR824--1,159--1,233--1,775--New LNBs, OFA, and ROTAMIX998--1,378--1,284--N/AN/AMobotecROFA807--1,097--1,157--N/AN/ANewLNBs,OFA,andSNCR721--965--924--1,2572,000New LNBs, OFA, and HERT6311,5578141,5177591,474N/AN/AMobotec ROFA and ROTAMIX97821,1881,24420,2211,27521,253N/AN/ASCR3,51716,9494,34115,6883,94712,1004,4998,292New LNBs and SCR3,38014,3324,32615,2703,96712,1824,5878,484New LNBs, OFA, and SCR3,37114,2794,31515,2183,91511,9704,6038,518Notes:Economic Optimum Incremental Threshold Maximum ReductionN/A - Technology not applicable to unit.1204077-7

## Arizona Public Service Four Corners Units 1 through 5 Appendix A

102907 A-1 

# Appendix A Design BasisPrint Date: 9/14/2007Ultimate Coal analysis, wet basis Average Minimum Maximum ReferenceCarbon, % 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 ProvidedAsh, % 20.42 20.17 27.58 APS ProvidedMoisture, % 12.33 10.87 13.06 APS ProvidedTotal, % 100.00B&V CalculationHigher Heating Value, Btu/lb 8,776 8,200 9,363 APS ProvidedAsh Analysis, % by massSilica (SiO2)63.02 68.43 57.14 APS ProvidedAlumina (Al2O3)23.40 21.23 26.17 APS ProvidedIron Oxide (Fe2O3)4.49 4.45 4.86 APS ProvidedTitania (TiO2)0.88 0.82 1.03 APS ProvidedPhosphorous (P2O5)0.18 0.16 0.39 APS ProvidedLime (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 ProvidedPotassium Oxide (K2O)1.34 0.84 1.57 APS ProvidedSulfur Trioxide (SO3)1.67 1.23 3.50 APS ProvidedUndetermined 0.49 -- -- APS ProvidedTotal (%) 100.00B&V CalculationUnit 1 Unit 2 Unit 3Unit CharacteristicsUnit 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 / 1000Coal 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/ HHVFly 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 ProvidedAPSFour CornersDesign Basis Rev. 1Units 1, 2 & 31 of 6Design Basis BART R1 05.08.07.xlsPrint Date: 9/14/2007APSFour CornersDesign Basis Rev. 1Economizer Outlet ConditionsFlue 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 CompositionOxygen, % 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) / FBRSulfur Dioxide, lb/hr 3,181 3,181 4,098 B&V CalculationSulfur Trioxide, lb/hr9 9 12 = SO3 (lb/Mbtu) x FBRSulfur 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 / coal HHVParticulate 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 FBRAir Heater Outlet ConditionsFlue 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 CompositionOxygen, % 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 ProvidedVenturi Scrubber Outlet ConditionsParticulate Removal Efficency, % 99.9 99.8 99.8 = (Inlet PM - Outlet PM) / Inlet PMSO2Removal Efficency %91.2 91.2 91.2= (Inlet SO2- Outlet SO2) / Inlet SO2Flue 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 FBRSO2Concentration, lb/MBtu0.15 0.15 0.15 APS ProvidedSO2Rate, lb/hr279 279 360 = Inlet SO2 (1- SO2 Removal %)Flue Gas CompositionOxygen, % 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 ProvidedUnits 1, 2 & 32 of 6Design Basis BART R1 05.08.07.xlsPrint Date: 9/14/2007APSFour CornersDesign Basis Rev. 1ID Fan Outlet ConditionsFlue 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 CalculationStack Outlet EmissionsSulfur Dioxide, lb/MBtu 0.15 0.15 0.15Venturi Outlet SO2Sulfur Dioxide, lb/hr 279 279 360Venturi Outlet SO2Sulfur Trioxide, lb/hr 9 9 12Venturi Outlet SO3Sulfur Trioxide, lb/MBtu 0.005 0.005 0.005Venturi Outlet SO3Sulfur Trioxide, ppm 2 2 2Venturi 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 NOxUnits 1, 2 & 33 of 6Design Basis BART R1 05.08.07.xlsDesign Basis BART R1 05.08.07.xlsUltimate Coal analysis, wet basisReferenceCarbon, %APS ProvidedHydrogen, %APS ProvidedSulfur, %APS ProvidedNitrogen, %APS ProvidedOxygen, %APS ProvidedChlorine, %APS ProvidedAsh, %APS ProvidedMoisture, %APS ProvidedTotal, %B&V CalculationHigher Heating Value, Btu/lbAPS ProvidedAsh Analysis, % by massSilica (SiO2)APS ProvidedAlumina (Al2O3)APS ProvidedIron Oxide (Fe2O3)APS ProvidedTitania (TiO2)APS ProvidedPhosphorous (P2O5)APS ProvidedLime (CaO)APS ProvidedMagnesia (MgO)APS ProvidedSodium Oxide (Na2O)APS ProvidedPotassium Oxide (K2O)APS ProvidedSulfur Trioxide (SO3)APS ProvidedUndeterminedAPS ProvidedTotal (%)B&V CalculationUnit CharacteristicsUnit Rating, Gross MWAPS ProvidedUnit Rating, Net MWAPS 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/ HHVFly Ash Portion of Total Ash, %APS ProvidedAir Heater Leakage, %B&V AssumptionExcess O2, %APS Provided8015.03.07907659,8817,806444.7889,4707657903.015.080889,470444.77,8069,881Unit 4 Unit 51.034.861.471.041.330.824.452.2713.065.650.39--3.501.5726.1757.149,36327.58--10.6446.661.054.080.9553.028.810.870.930.6510.8720.17----1.230.84100.000.491.671.343.158,20068.431.250.681.670.1621.230.180.8863.0223.404.4920.4212.33100.00APSFour CornersDesign Basis Rev. 1Average Minimum Maximum51.403.850.751.028,77610.160.07Units 4 & 54 of 6Print Date: 9/14/2007Design Basis BART R1 05.08.07.xlsAPSFour CornersDesign Basis Rev. 1Economizer Outlet ConditionsFlue Gas Temperature, FAPS ProvidedFlue Gas Pressure, in. w.g.APS ProvidedFlue Gas Mass Flow Rate, lb/hrB&V CalculationVolumetric Flue Gas Flow Rate, acfmB&V CalculationFlue Gas CompositionOxygen, % by volumeB&V CalculationCarbon Dioxide, % by volumeB&V CalculationMoisture, % by volumeB&V CalculationSulfur Dioxide, lb/MBtu= Sulfur Dioxide (lb/hr) / FBRSulfur Dioxide, lb/hrB&V CalculationSulfur Trioxide, lb/hr= SO3 (lb/Mbtu) x FBRSulfur Trioxide, lb/MbtuB&V CalculationSulfur Trioxide, ppmAPS ProvidedParticulate Concentration, lb/MBtu= % ash x % fly ash x 100 / coal HHVParticulate Mass Rate, lb/hr= PM (lb/Mbtu) x FBRNOx Concentration, lb/MBtuAPS ProvidedNOx Mass Rate, lb/hr= NOx lb/Mbtu x FBRAir Heater Outlet ConditionsFlue Gas Temperature, FAPS ProvidedFlue Gas Pressure, in. w.g.APS ProvidedFlue Gas Mass Flow Rate, lb/hrB&V CalculationVolumetric Flue Gas Flow Rate, acfmB&V CalculationFlue Gas CompositionOxygen, % by volumeB&V CalculationCarbon Dioxide, % by volumeB&V CalculationMoisture, % by volumeB&V CalculationFabric Filter Outlet ConditionsParticulate Removal Efficency, %= (Inlet PM - Outlet PM) / Inlet PMFlue Gas Temperature, FAPS ProvidedFlue Gas Pressure, in. w.g.APS ProvidedFlue Gas Mass Flow Rate, lb/hrB&V CalculationVolumetric Flue Gas Flow Rate, acfmB&V CalculationParticulate Concentration1, lb/MBtuAPS ProvidedParticulate Mass Rate1, lb/hr= PM (lb/Mbtu) x FBR74.9-8.08,890,5723,183,6890.01099.9%2275.312.09.72421.08,890,5723,165,6770.483,7450.005218.6145,30410.91.6612,943394,224,5923.013.965010.07,730,9322423,165,6778,890,5721.09.712.05.3-8.022799.9%107.70.0143,183,6898,890,57213.93.03912,9431.6610.9145,30418.620.0053,9670.514,224,5927,730,93210.0650Units 4 & 55 of 6Print Date: 9/14/2007Design Basis BART R1 05.08.07.xlsAPSFour CornersDesign Basis Rev. 1ID Fan Outlet ConditionsFlue Gas Temperature, FB&V AssumptionFlue Gas Pressure, in. w.g.B&V AssumptionFlue Gas Mass Flow Rate, lb/hrB&V CalculationVolumetric Flue Gas Flow Rate, acfmB&V CalculationScrubber Outlet ConditionsScrubber removal %= (Inlet SO2- Outlet SO2) / Inlet SO2Flue Gas Temperature, FB&V CalculationFlue Gas Pressure, in. w.g.B&V AssumptionFlue Gas Mass Flow Rate, lb/hrB&V CalculationVolumetric Flue Gas Flow Rate, acfmB&V CalculationFlue Gas CompositionOxygen, % by volumeB&V CalculationCarbon Dioxide, % by volumeB&V CalculationMoisture, % by volumeB&V CalculationSulfur Dioxide, lb/MBtuAPS ProvidedSulfur Dioxide, lb/hr= SO2(lb/Mbtu) x FBRStack Outlet EmissionsSulfur Dioxide, lb/MBtuScrubber Outlet SO2Sulfur Dioxide, lb/hrScrubber Outlet SO2Sulfur Trioxide, lb/hrEconomizer Outlet SO3Sulfur Trioxide, lb/MBtuEconomizer Outlet SO3Sulfur Trioxide, ppmEconomizer Oullet SO3Particulate Concentration1, lb/MBtuFabric Filter Outlet PMParticulate Concentration1, lb/hrFabric Filter Outlet PMNOx Emission Rate, lb/MBtuEconomizer Outlet NOxNOx Emission Rate, lb/hrEconomizer Outlet NOx1) If the BART analysis is expanded to cover particulate the PM emissoins values must be confirmed.Notes:0.483,7452.087.5%1202.09,138,9252,728,4600.21,6180.21,61887.5%1202.09,138,9252,728,4600.0050.213.811.55.113.80.0096750.21,6183968,890,5723,101,2842383,9670.511080.01382.00.005391,6183,101,2848,890,572623811.55.1Units 4 & 56 of 6Print Date: 9/14/2007

## Arizona Public Service Four Corners Units 1 through 5 Appendix B

102907 B-1 

# Appendix B Technology Removal MatrixArizona Public ServiceFour Corners Units 1 through 5Appendix B102907B-1APS Four Corners Units 1, 2, 3, 4 and 5Emissions Control Technology Matrix and Maximum1Removal EfficiencyFuelFuel Case Description or Percentage BlendsUnit rating, MW (gross / net)Boiler heat input, mmBtu/hrType of boilerSteam cycleDraft of boilerExisting emissions controlsBoilerParticulateBART Baseline EmissionsNOx, ton/yrPM10 Filterable, ton/yrOutlet conditions ("controlled" based on APSprovided data)NOx, lb/mmBtuPM10 Filterable, lb/mmBtuApply Apply Apply Applytech? NOx PM tech? NOx PM tech? NOx PM tech? NOx PMCurrent emissions reduction from inlet conditions30.78 0.025 0.64 0.029 0.59 0.029 0.49 0.012New emissions control technologiesParticulate ControlElectrostatic Precipitators (ESP) Upstream of Current AQC EquipmentYes 0.012 Yes 0.012 Yes 0.012 NoPulse Jet Fabric Filter (PJFF) Upstream of Current AQC EquipmentYes 0.012 Yes 0.012 Yes 0.012 NoCOHPAC Downstream Current AQC EquipmentNo No No NoWet ESP Downstream of VenturiYes 0.012 Yes 0.012 Yes 0.012 NoMax 9 Hybrid Particulate CollectorNo No No NoMulti-CycloneNo No No NoCoal WashingNo No No NoNOx ControlCombustion Optimization System (COS)Yes 0.72 Yes 0.60 Yes 0.56 Yes 0.47Selective Non-Catalytic Reduction (SNCR)Yes 0.56 Yes 0.46 Yes 0.46 Yes 0.38Mobotec RotamixYes 0.56 Yes 0.45 Yes 0.45 NoNew Low NOx Burners (LNB)Yes 0.43 Yes 0.43 Yes 0.43 Yes 0.45New LNB, Overfire Air (OFA)Yes 0.33 Yes 0.33 Yes 0.33 Yes 0.35New LNBs and SNCRYes 0.32 Yes 0.32 Yes 0.32 Yes 0.32New LNBs and RotamixYes 0.30 Yes 0.30 Yes 0.30 NoMobotec Rotating Overfire air (ROFA)Yes 0.28 Yes 0.28 Yes 0.28 NoNew LNBs, OFA and SNCRYes 0.26 Yes 0.26 Yes 0.26 Yes 0.26New LNBs, OFA and High Energy Reagent Technology (HERT)Yes 0.20 Yes 0.20 Yes 0.20 NoMobotec ROFA and RotamixYes 0.19 Yes 0.19 Yes 0.19 NoSelective Catalytic Reduction (SCR)Yes 0.08 Yes 0.06 Yes 0.06 Yes 0.06New LNBs and SCRYes 0.06 Yes 0.06 Yes 0.06 Yes 0.06New LNBs, OFA and SCRYes 0.06 Yes 0.06 Yes 0.06 Yes 0.06NOxStar and NOxStar PlusNo No No NoECOTUBENo No No NoIFGRNo No No NoSNCR/SCR Hybrid (Cascade System)No No No NoLoTOxNo No No NoNatural Gas ReburnNo No No NoTHERMALONOx ProcessNo No No NoOxygen Enhanced CombustionNo No No NoBiotechnological DenitrificationNo No No NoNotes:3) All emission rates are in lb/mmBtu unless otherwise specified.Emission Rate3Emission Rate30.029 0.012Emission Rate3Emission Rate31) Emission rates shown represent best case scenarios based on industry experienceand may not reflect upset operation conditions or the possible degradation of equipmentover operating cycles.2) Controlled emissions is with current control equipment.0.59 0.49285 3135,633 13,028Venturi Scrubber Reverse Gas Fabric FilterLNB (1990)Unit 4 LNB (1989)Unit 5 LNB (1991)Subcritical SupercriticalBalanced ForcedFront Wall Foster WheelerMembrane WallFront Wall Foster Wheeler MembraneWall235 / 220 790 / 7502,400 7,806Mine Mouth Bituminous Mine Mouth BituminousFour Corners Four CornersUnit 3 Units 4 & 5 (per Unit)3/29/20070.78 0.640.025 0.029Venturi Scrubber Venturi Scrubber4,7882205,703180Low NOx BurnerModifications (1977)LNB (1998)Balanced BalancedSubcritical SubcriticalFront Wall Fired RileyTangential TubeFront Wall Fired RileyTangential TubeFour Corners Four CornersMine Mouth Bituminous Mine Mouth BituminousUnit 1 Unit 21,863 1,863185 / 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 Interf ace with existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements 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 construc tion 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 increas e in LOI, unburned carbon and CO. Byproduct Description None Other N/A

Location of Major Process Equipment Install new burners in t he existing burner openings. Install OFA ports to support new Low NOx Burners. Addition of coal flow monitors in c oal 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 di stribution and air balancing for OFA system. Inlet/Outlet Connections and Interconnecting Ducts None.
Reagent Storage None.
Control System Modifications A ddition of NOx optimization into combustion monitoring process.

Fan Modifications None.
Power Supply/Aux Power Modificati ons No significant aux power im pacts 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 nor th of Unit 1 above new air heater to be installed. Install NH3 vaporizers at grade. Inlet/Outlet Connections and Interconnecting Ducts Existing secondar y air heaters demolished to allow room for ductwork connect ions. SCR inlet connected to old air heater outlet, SCR outle t 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 Incorpor ated into existing control system.

Fan Modifications Assume modification or additi on of fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume upgr ade will be required for aux electric system.
Enclosures Requirements Analyzer shelters.
Demolition or Relocation Requirements Existing econom izer 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 Ammoni a 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. SO 3 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 construc tion activities including, but not limited to, offices, laydown, and staging. Existing air heater demolition, new air heat er installation, flue gas handling systems and urea handling systems included. No impact on potential ash sales and no add itional 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 requi rements 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 nort h side of Unit 1along with new air heater. Install urea decompo sition 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 pi pes leading to burner. Addition of water cannon system to boiler wall. Inlet/Outlet Connections and Interconnecting Ducts Existing air heat er 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 Incorpor ated into existing control system.

Fan Modifications Assume booster fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume upgr ade will be required for aux electric system.
Enclosures Requirements Ammonia injection gr id area and sonic horns are to be enclosed.
Demolition or Relocation Requirements Existing ec onomizer 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 Ammoni a 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 in let is acceptable over entire design load range. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. Existing air heater demolition, new air heat er installation, flue gas handling systems and urea handling systems included. No impact on potential ash sales and no add itional 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 re quirements 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 hea t traced line to SNCR lances. Inlet/Outlet Connections and Interconnecting Ducts Install wall in jectors and lance-type injectors for SNCR in the boiler.
Reagent Storage Urea tank at grade.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning and/or washing. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion 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. Se lective Non-Catalytic Reduction (S NCR) 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Fuel and air balancing performed for eac h 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 exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Require minor bo iler pressure part modification for OFA ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for SNCR is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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. Hi gh 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Fuel and air balancing performed for eac h 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 exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Require minor bo iler pressure part modification for OFA ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for SNCR is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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 injecti on location in heat traced pipe. Inlet/Outlet Connections and Interconnecting Duct s 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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Mi nor modification to boiler pre ssure parts for Rotamix ports.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Addition of coal flow monitors in coal pipes leading to burne r. 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 Duct s 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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Mi nor modification to boiler pre ssure parts for Mobotec ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for ROTAMIX is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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-co mbustion 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 modifi cation 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 LO I and CO within acceptable levels.
Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 injecti on location in heat traced lines. Inlet/Outlet Connections and Interconnecting Ducts Tie-in to exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 system s modifications expected to accommodate new booster fan.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 Interf ace with existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements 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 construc tion 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 increas e in LOI, unburned carbon and CO. Byproduct Description None Other N/A

Location of Major Process Equipment Install new burners in t he existing burner openings. Install OFA ports to support new Low NOx Burners. Addition of coal flow monitors in c oal 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 di stribution and air balancing for OFA system. Inlet/Outlet Connections and Interconnecting Ducts None.
Reagent Storage None.
Control System Modifications A ddition of NOx optimization into combustion monitoring process.

Fan Modifications None.
Power Supply/Aux Power Modificati ons No significant aux power im pacts 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, ei ther 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 secondar y air heater demolished to allow room for ductwork connecti ons. 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 Incorpor ated into existing control system.

Fan Modifications Assume modification or additi on of fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume upgr ade will be required for aux electric system.
Enclosures Requirements Analyzer shelters.
Demolition or Relocation Requirements Existing econom izer 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 Ammoni a 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. SO 3 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 construc tion activities including, but not limited to, offices, laydown, and staging. Existing air heater demolition, new air heat er installation, flue gas handling systems and urea handling systems included. No impact on potential ash sales and no add itional 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 requi rements 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, ei ther above the existing compressor building or on the east side of the service road. Install urea decomposition chamber at grade. Install new bu rners in the existing burner openings. Install OFA ports to support new Low NOx Burners. Addi tion of coal flow moni tors in coal pipes leading to burner. Addition of water cannon system to boiler wall. Inlet/Outlet Connections and Interconnecting Ducts Existing air heat er 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 Incorpor ated into existing control system.

Fan Modifications Assume booster fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume upgr ade will be required for aux electric system.
Enclosures Requirements Ammonia injection gr id area and sonic horns are to be enclosed.
Demolition or Relocation Requirements Existing ec onomizer 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 Ammoni a 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 in let is acceptable over entire design load range. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. Existing air heater demolition, new air heat er installation, flue gas handling systems and urea handling systems included. No impact on potential ash sales and no add itional 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 re quirements 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 hea t traced line to SNCR lances. Inlet/Outlet Connections and Interconnecting Ducts Install wall in jectors and lance-type injectors for SNCR in the boiler.
Reagent Storage Urea tank at grade.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning and/or washing. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion 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. Se lective Non-Catalytic Reduction (S NCR) 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Fuel and air balancing performed for eac h 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 exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Require minor bo iler pressure part modification for OFA ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for SNCR is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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. Hi gh 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Fuel and air balancing performed for eac h 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 exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Require minor bo iler pressure part modification for OFA ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for SNCR is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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 injecti on location in heat traced lines. Inlet/Outlet Connections and Interconnecting Duct s 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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Mi nor modification to boiler pre ssure parts for Rotamix ports.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Addition of coal flow monitors in coal pipes leading to burne r. 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 Duct s 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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Mi nor modification to boiler pre ssure parts for Mobotec ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for ROTAMIX is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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-co mbustion 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 modifi cation 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 LO I and CO within acceptable levels.
Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 injecti on location in heat traced lines. Inlet/Outlet Connections and Interconnecting Ducts Tie-in to exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 system s modifications expected to accommodate new booster fan.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 Interf ace with existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements 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 construc tion 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 increas e in LOI, unburned carbon and CO. Byproduct Description None Other N/A

Location of Major Process Equipment Install new burners in t he existing burner openings. Install OFA ports to support new Low NOx Burners. Addition of coal flow monitors in c oal 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 di stribution and air balancing for OFA system. Inlet/Outlet Connections and Interconnecting Ducts None.
Reagent Storage None.
Control System Modifications A ddition of NOx optimization into combustion monitoring process.

Fan Modifications None.
Power Supply/Aux Power Modificati ons No significant aux power im pacts 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 secondar y air heaters demolished to allow room for ductwork connect ions. 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 Incorpor ated into existing control system.

Fan Modifications Assume modification or additi on of fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume upgr ade will be required for aux electric system.
Enclosures Requirements Analyzer shelters.
Demolition or Relocation Requirements Existing econom izer outlet ductwork including existing air heater.
Major Constructability Issues Tying the S CR into the existing ductwork after air h eater demolition. Construction may limit road access. Significant Issues or Challenges Ammoni a 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. SO 3 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 construc tion activities including, but not limited to, offices, laydown, and staging. Existing air heater demolition, new air heat er installation, flue gas handling systems and urea handling systems included. No impact on potential ash sales and no add itional 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 requi rements 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 burne r. Addition of water cannon system to boiler wall. Inlet/Outlet Connections and Interconnecting Ducts Existing air heat er 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 Incorpor ated into existing control system.

Fan Modifications Assume booster fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume upgr ade will be required for aux electric system.
Enclosures Requirements Ammonia injection gr id area and sonic horns are to be enclosed.
Demolition or Relocation Requirements Existing ec onomizer 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 Ammoni a 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 in let is acceptable over entire design load range. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. Existing air heater demolition, new air heat er installation, flue gas handling systems and urea handling systems included. No impact on potential ash sales and no add itional 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 re quirements 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 hea t traced line to SNCR lances. Inlet/Outlet Connections and Interconnecting Ducts Install wall in jectors and lance-type injectors for SNCR in the boiler.
Reagent Storage Urea tank at grade.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning and/or washing. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion 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) syst em. 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Fuel and air balancing performed for eac h 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 exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Require minor bo iler pressure part modification for OFA ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for SNCR is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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) syst em. 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Fuel and air balancing performed for eac h 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 exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Require minor bo iler pressure part modification for OFA ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for SNCR is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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 injecti on location in heat traced lines. Inlet/Outlet Connections and Interconnecting Duct s 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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Mi nor modification to boiler pre ssure parts for Rotamix ports.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Addition of coal flow monitors in coal pipes leading to burne r. 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 Duct s 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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues Mi nor modification to boiler pre ssure parts for Mobotec ports.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d and no impact on ash sales. Reagent for ROTAMIX is urea. Upgraded Low NOx Burners and OFA system operation reduces reagent consumption for SN CR 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 fur nace 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-co mbustion 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 modifi cation 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 LO I and CO within acceptable levels.
Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 injecti on location in heat traced lines. Inlet/Outlet Connections and Interconnecting Ducts Tie-in to exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 system s modifications expected to accommodate new booster fan.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening include d 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 Interf ace with existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclos ed in existing boiler building.
Demolition or Relocation Requirements 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 construc tion 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 t he existing burner openings. Install OFA ports to support new Low NOx Burners. Addition of coal flow monitors in coal pipes leading to burne r. Addition of water cannon system to boiler wall. Inlet/Outlet Connections and Interconnecting Ducts None.
Reagent Storage None.
Control System Modifications A ddition of NOx optimization into combustion monitoring process.

Fan Modifications None.
Power Supply/Aux Power Modificati ons No significant aux power im pacts 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 Incorpor ated into existing control system.

Fan Modifications Assume modification or additi on of fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume upgr ade will be required for aux electric system.
Enclosures Requirements Ammonia injection gr id area and sonic horns are to be enclosed.
Demolition or Relocation Requirements Existing economizer outlet ductwork.
Major Constructability Issues Tying t he SCR into the existing ductwork.
Significant Issues or Challenges Ammoni a 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 construc tion activities including, but not limited to, offices, laydown, and staging. Existing air heater demolition, new air heat er installation, flue gas handling systems and urea handling systems included. No impact on potential ash sales and no add itional 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 requi rements 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 fl ow monitors in coal pi pes 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 Incorpor ated into existing control system.

Fan Modifications Assume booster fans and duct stiffening will be required.
Power Supply/Aux Power Modifications Assume upgr ade will be required for aux electric system.
Enclosures Requirements Ammonia injection gr id 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 Ammoni a 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 construc tion activities including, but not limited to, offices, laydown, and staging. Existing air heater demolition, new air heat er installation, flue gas handling systems and urea handling systems included. No impact on potential ash sales and no add itional 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 requi rements 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 hea t traced line to SNCR lances. Inlet/Outlet Connections and Interconnecting Ducts Install wall in jectors and lance-type injectors for SNCR in the boiler.
Reagent Storage Urea tank at grade.
Control System Modifications Incorpor ated into existing control system.

Fan Modifications None.
Power Supply/Aux Power Modificati ons Minimum impact/modifications.
Enclosures Requirements None.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Ammonia slip may cause buildup of ammonium bisu lfate on the air heater, which may require more frequent cleaning. Other Assumptions No major impact in plant availability. The site has sufficient area available to accommodate construc tion 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 ammoni a 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) syst em. 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 sa me. Injection skid and urea tank at grad e with truck unloading station. Urea pumped to injection location in heat traced lines. Inlet/Outlet Connections and Interconnecting Ducts Tie-in to exis ting air duct and coal pipes. Install injectors for SNCR in b oiler.
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 Modificati ons Minimum impact/modifications.
Enclosures Requirements Enclosed al ready in existing boiler building.
Demolition or Relocation Requirements None.
Major Constructability Issues None.
Significant Issues or Challenges Keep LOI and CO within accept able 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 construc tion activities including, but not limited to, offices, laydown, and staging. No boiler/duct stiffening included and no impact on ash sale s 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 SN CR 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 $3,164,000Four 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 $5,682,000Four 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 $4,290,000Four 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 $5,143,000Four 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 $19,841,000Four 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 $19,372,000Four 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 Fact o

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 Fact o

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 Facto r

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 $3,164,000Four 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 $5,682,000Four 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 $4,290,000Four 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 $5,105,991Four 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 $20,730,311Four 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 $20,668,147Four 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 Facto r

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 Facto r

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 $3,416,000Four 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 $5,720,000Four 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 $4,323,000Four 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 revie w 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 F a

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 $6,063,000Four 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 $21,991,000Four 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 $21,967,000Four 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 lif e

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) $13,320,00 0

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 Fact o

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 $9,586,000Four 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 ) $83,856,30 0

Site preparation $2,000,000 Estimate Buildings $500,000 Estimate Total direct costs (DC) = (PEC) + (DIC ) $169,185,00 0

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 ) $49,435,00 0

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 ) $12,581,00 0 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 ) $38,686,00 0 & 20 year lif e

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 includedFour 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 $57,855,000Four 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 TableStack Flow Summary Re 09.11.07.xlsFour Corners - Unit 1Stack Outlet ConditionsFlow(acfm)Diameter(ft)Velocity(ft/s)Temperature(°F)Rate(Lb/MMBTU)Emission(Ton/year)Reduction(Ton/year)PercentReductionBaseline 684,087 15 65 138 0.78 5,703 0 0%Combustion Optimization System (Neural Network) 684,087 15 65 138 0.72 5,247 456 8%Selective Non-Catalytic Reduction (SNCR) 684,087 15 65 138 0.56 4,081 1,622 28%Mobotec ROTAMIX 684,087 15 65 138 0.56 4,081 1,622 28%Low NOx Burners (LNB) 684,087 15 65 138 0.43 3,133 2,569 45%LNB and Overfire Air (OFA) 684,087 15 65 138 0.33 2,405 3,298 58%LNB and SNCR 684,087 15 65 138 0.32 2,332 3,371 59%LNB and Mobotec ROTAMIX 684,087 15 65 138 0.30 2,186 3,517 62%Mobotec ROFA 684,087 15 65 138 0.28 2,040 3,662 64%LNB and OFA with SNCR 684,087 15 65 138 0.26 1,895 3,808 67%LNB and OFA with HERT 684,087 15 65 138 0.20 1,457 4,245 74%Mobotec ROFA and ROTAMIX 684,087 15 65 138 0.19 1,385 4,318 76%Selective Catalytic Reduction (SCR) 684,087 15 65 138 0.08 568 5,134 90%LNB with SCR 684,087 15 65 138 0.06 437 5,266 92%LNB and OFA with SCR 684,087 15 65 138 0.06 437 5,266 92%Flow(acfm)Diameter(ft)Velocity(ft/s)Temperature(°F)Rate(Lb/MMBTU)Emission(Ton/year)Reduction(Ton/year)PercentReductionBaseline 684,087 15 65 138 0.025 180 0 0%Fabric Filter (FF) 684,087 15 65 138 0.012 87 94 52%Electrostatic Precipitator (ESP) 684,087 15 65 138 0.012 87 94 52%GE Max 9 Hybrid 684,087 15 65 138 0.012 87 94 52%Wet ESP (Metal Type) 684,087 15 65 138 0.012 87 94 52%Wet ESP (Membrane Type) 684,087 15 65 138 0.012 87 94 52%NOxExisting rate (lb/MMBTU): 0.78OptionNOxStackOptionStack PMPMExisting rate (lb/MMBTU): 0.0251 of 4Print Date: 9/14/2007Stack Flow Summary Re 09.11.07.xlsFour Corners - Unit 2Stack Outlet ConditionsFlow(acfm)Diameter(ft)Velocity(ft/s)Temperature(°F)Rate(Lb/MMBTU)Emission(Ton/year)Reduction(Ton/year)PercentReductionBaseline 684,087 15 65 138 0.64 4,788 0 0%Combustion Optimization System (Neural Network) 684,087 15 65 138 0.60 4,486 302 6%Selective Non-Catalytic Reduction (SNCR) 684,087 15 65 138 0.46 3,440 1,349 28%Mobotec ROTAMIX 684,087 15 65 138 0.45 3,365 1,424 30%Low NOx Burners (LNB) 684,087 15 65 138 0.43 3,215 1,573 33%LNB and Overfire Air (OFA) 684,087 15 65 138 0.33 2,467 2,321 48%LNB and SNCR 684,087 15 65 138 0.32 2,393 2,396 50%LNB and Mobotec ROTAMIX 684,087 15 65 138 0.30 2,243 2,545 53%Mobotec ROFA 684,087 15 65 138 0.28 2,094 2,695 56%LNB and OFA with SNCR 684,087 15 65 138 0.26 1,944 2,844 59%LNB and OFA with HERT 684,087 15 65 138 0.20 1,495 3,293 69%Mobotec ROFA and ROTAMIX 684,087 15 65 138 0.19 1,421 3,368 70%Selective Catalytic Reduction (SCR) 684,087 15 65 138 0.06 479 4,310 90%LNB with SCR 684,087 15 65 138 0.06 449 4,340 91%LNB and OFA with SCR 684,087 15 65 138 0.06 449 4,340 91%Flow(acfm)Diameter(ft)Velocity(ft/s)Temperature(°F)Rate(Lb/MMBTU)Emission(Ton/year)Reduction(Ton/year)PercentReductionBaseline 684,087 15 65 138 0.029 220 0 0%Fabric Filter (FF) 684,087 15 65 138 0.012 90 129 59%Electrostatic Precipitator (ESP) 684,087 15 65 138 0.012 90 129 59%GE Max 9 Hybrid 684,087 15 65 138 0.012 90 129 59%Wet ESP (Metal Type) 684,087 15 65 138 0.012 90 129 59%Wet ESP (Membrane Type) 684,087 15 65 138 0.012 90 129 59%NOxExisting rate (lb/MMBTU): 0.64OptionStack NOxOptionStack PMPMExisting rate (lb/MMBTU): 0.0292 of 4Print Date: 9/14/2007Stack Flow Summary Re 09.11.07.xlsFour Corners - Unit 3Stack Outlet ConditionsFlow(acfm)Diameter(ft)Velocity(ft/s)Temperature(°F)Rate(Lb/MMBTU)Emission(Ton/year)Reduction(Ton/year)PercentReductionBaseline 881,271 15 83 138 0.59 5,633 0 0%Combustion Optimization System (Neural Network) 881,271 15 83 138 0.56 5,375 257 5%Selective Non-Catalytic Reduction (SNCR) 881,271 15 83 138 0.46 4,415 1,217 22%Mobotec ROTAMIX 881,271 15 83 138 0.45 4,319 1,313 23%Low NOx Burners (LNB) 881,271 15 83 138 0.43 4,128 1,505 27%LNB and Overfire Air (OFA) 881,271 15 83 138 0.33 3,168 2,465 44%LNB and SNCR 881,271 15 83 138 0.32 3,072 2,561 45%LNB and Mobotec ROTAMIX 881,271 15 83 138 0.30 2,880 2,753 49%Mobotec ROFA 881,271 15 83 138 0.28 2,688 2,945 52%LNB and OFA with SNCR 881,271 15 83 138 0.26 2,496 3,137 56%LNB and OFA with HERT 881,271 15 83 138 0.20 1,920 3,713 66%Mobotec ROFA and ROTAMIX 881,271 15 83 138 0.19 1,824 3,809 68%Selective Catalytic Reduction (SCR) 881,271 15 83 138 0.06 576 5,057 90%LNB with SCR 881,271 15 83 138 0.06 576 5,057 90%LNB and OFA with SCR 881,271 15 83 138 0.06 576 5,057 90%Flow(acfm)Diameter(ft)Velocity(ft/s)Temperature(°F)Rate(Lb/MMBTU)Emission(Ton/year)Reduction(Ton/year)PercentReductionBaseline 881,271 15 83 138 0.029 285 0 0%Fabric Filter (FF) 881,271 15 83 138 0.012 117 168 59%Electrostatic Precipitator (ESP) 881,271 15 83 138 0.012 117 168 59%GE Max 9 Hybrid 881,271 15 83 138 0.012 117 168 59%Wet ESP (Metal Type) 881,271 15 83 138 0.012 117 168 59%Wet ESP (Membrane Type) 881,271 15 83 138 0.012 117 168 59%NOxNOxExisting rate (lb/MMBTU): 0.59OptionStackPMExisting rate (lb/MMBTU): 0.029OptionStack PM3 of 4Print Date: 9/14/2007Stack Flow Summary Re 09.11.07.xlsFour Corners - Unit 4 & 5Stack Outlet ConditionsFlow(acfm)Diameter(ft)Velocity(ft/s)Temperature(°F)Rate(Lb/MMBTU)Emission(Ton/year)Reduction(Ton/year)PercentReductionBaseline 2,728,460 28.5 71 120 0.49 13,028 0 0%Combustion Optimization System (Neural Network) 2,728,460 28.5 71 120 0.47 12,395 633 5%Low NOx Burners (LNB) 2,728,460 28.5 71 120 0.45 11,867 1,160 9%Selective Non-Catalytic Reduction (SNCR) 2,728,460 28.5 71 120 0.38 9,889 3,138 24%LNB and Overfire Air (OFA) 2,728,460 28.5 71 120 0.35 9,230 3,798 29%LNB and SNCR 2,728,460 28.5 71 120 0.32 8,439 4,589 35%LNB and OFA with SNCR 2,728,460 28.5 71 120 0.26 6,857 6,171 47%Selective Catalytic Reduction (SCR) 2,728,460 28.5 71 120 0.06 1,582 11,445 88%LNB with SCR 2,728,460 28.5 71 120 0.06 1,582 11,445 88%LNB and OFA with SCR 2,728,460 28.5 71 120 0.06 1,582 11,445 88%Note: Emissions are per Unit for the Unit 4 & 5 table.OptionStack NOxNOxExisting rate (lb/MMBTU): 0.494 of 4Print Date: 9/14/2007

## Arizona Public Service Four Corners Units 1 through 5 Appendix F

102907 F-1 

# Appendix F Annual Emissions Summary TableArizona Public ServiceFour Corners Units 1 through 5Appendix F102907F-2APS Four Corners SteamElectric StationAnnual Emissions SummaryThe following tables contain information for annual heat input, capacity factors, SO2tons, NOxtons, PM10tons, and H2SO4tons foreach unit at Four Corners Steam Electric Station. Heat input (mmBtu), SO2(tons), NOx(lb/mmBtu), and NOx(tons) are obtainedfrom CEMS information. The NOx(tons) is calculatedusing the annual NOxmass emission rate (lb/mmBtu) multiplied by the annualheat input total (mmBtu). The PM10(tons) is calculated using theannual total particulate emissionsrate test result (lb/mmBtu)multiplied by the CEMS heat input (mmBtu). H2SO4(tons) is calculated using Southern Company’s method for estimating totalsulfuric acid emissions from stationary power plants.Most data is provided for the calendar years 2002 through 2006.Year UnitHeat Input(mmBtu)Capacity Factor(%)SO2(tons)NOx(lb/mmBtu)NOx(tons)PM(lb/mmBtu)PM10(tons)H2SO4(tons)2002 1 13,740,127 78.92 N/A 0.767 5,269 0.033 226.7 3.52003 1 14,616,287 87.31 N/A 0.768 5,613 0.023 168.1 4.02004 1 14,986,804 90.19 N/A 0.792 5,935 0.020 149.9 4.22005 1 13,764,408 85.38 879.8 0.782 5,382 0.028 192.7 4.12006 1 15,708,239 96.71 910.9 0.804 6,315 0.021 164.9*Year UnitHeat Input(mmBtu)Capacity Factor(%)SO2(tons)NOx(lb/mmBtu)NOx(tons)PM(lb/mmBtu)PM10(tons)H2SO4(tons)2002 2 16,632,804 88.31 N/A 0.614 5,106 0.022 183.0 3.92003 2 14,138,653 85.30 N/A 0.618 4,369 0.027 190.9 3.82004 2 13,261,038 80.66 N/A 0.663 4,396 0.023 152.5 3.72005 2 15,546,054 95.15 1,054.7 0.654 5,084 0.050 388.7 4.62006 2 15,272,703 93.61 901.7 0.653 4,987 0.024 183.3** Southern Company’s method for estimating total sulfuric acidemissions requires coal heat input information. Therefore, H2SO4emissions have not been calculated due tothe annual coal heat input information not being availableat the time of this report.Arizona Public ServiceFour Corners Units 1 through 5Appendix F102907F-3Year UnitHeat Input(mmBtu)Capacity Factor(%)SO2(tons)NOx(lb/mmBtu)NOx(tons)PM(lb/mmBtu)PM10(tons)H2SO4(tons)2002 3 19,873,581 88.58 N/A 0.570 5,664 0.040 397.5 5.02003 3 17,341,579 76.34 N/A 0.578 5,012 0.026 225.4 4.42004 3 20,819,150 92.59 N/A 0.600 6,246 0.023 239.4 5.42005 3 20,865,668 91.75 1,566.6 0.584 6,093 0.039 406.9 5.82006 3 17,101,624 72.29 1,357.5 0.602 5,148 0.018 153.9*Year UnitHeat Input(mmBtu)Capacity Factor(%)SO2(tons)NOx(lb/mmBtu)NOx(tons)PM(lb/mmBtu)PM10(tons)H2SO4(tons)2002 4 57,787,846 88.01 N/A 0.566 16,354 0.015 433.4 1.22003 4 56,712,865 91.76 N/A 0.565 16,021 0.007 198.5 1.32004 4 42,188,456 69.22 N/A 0.464 9,788 0.004 84.4 1.02005 4 54,882,182 89.01 4,538.0 0.458 12,568 0.018 493.9 1.82006 4 56,476,068 90.08 5,901.1 0.488 13,780 0.025 706.0*Year UnitHeat Input(mmBtu)Capacity Factor(%)SO2(tons)NOx(lb/mmBtu)NOx(tons)PM(lb/mmBtu)PM10(tons)H2SO4(tons)2002 5 37,592,636 58.19 N/A 0.450 8,458 0.011 206.8 0.82003 5 56,065,980 87.76 N/A 0.484 13,568 0.012 336.4 1.22004 5 56,059,669 94.57 N/A 0.495 13,875 0.004 112.1 1.42005 5 51,267,335 83.14 4,515.3 0.472 12,099 0.012 307.6 1.72006 5 55,280,458 88.64 6,121.2 0.498 13,765 0.009 248.8** Southern Company’s method for estimating total sulfuric acidemissions requires coal heat input information. Therefore, H2SO4emissions have not been calculated due tothe annual coal heat input information not being availableat the time of this report.