000000000001000684

Combined-Cycle Plant OptimizationStudies

Evaluations of Heat Recovery Steam GeneratorDesign, Duct Firing, and Combustion Turbine InletAir Cooling Options

Technical Report

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WARNING:Please read the License Agreementon the back cover before removingthe Wrapping Material.

EPRI Project ManagerD. Grace

EPRI • 3412 Hillview Avenue, Palo Alto, California 94304 • PO Box 10412, Palo Alto, California 94303 • USA800.313.3774 • 650.855.2121 • [email protected] • www.epri.com

Combined Cycle Plant OptimizationStudiesEvaluations of Heat Recovery Steam, GeneratorDesign, Duct Firing and Combustion Turbine InletAir Cooling Options

1000684

Interim Report, December 2000

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ORGANIZATION(S) THAT PREPARED THIS DOCUMENT

EPRIsolutionsPowerhouse Engineering, Ltd.

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Copyright © 2000 Electric Power Research Institute, Inc. All rights reserved.

iii

CITATIONS

This report was prepared by

EPRIsolutions180 N. Wacker Drive, Suite 300Chicago, IL 60606-1603

Principal InvestigatorW.C. Stenzel

Powerhouse Engineering, Ltd.802 N. Harvard AvenueArlington Heights, IL 60004

Principal InvestigatorG.J. Boncimino

This report describes research sponsored by EPRI.

The report is a corporate document that should be cited in the literature in the following manner:

Combined Cycle Plant Optimization Studies: Evaluations of Heat Recovery Steam GeneratorDesign, Duct Firing and Combustion Turbine Inlet Air Cooling Options, EPRI, Palo Alto, CA:2000. 1000684.

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REPORT SUMMARY

To create competitive proposals at a reasonable expense while managing risk, a projectdeveloper must accurately and cost-effectively address the unique circumstances of each projectopportunity—including ambient temperatures, air emissions limits, and fuel, electricity, andconstruction pricing. This report provides several combustion turbine combined-cycle plantevaluation and optimization studies for specific technologies along with improved methods forperforming such studies. The methods permit better replication of difficult simulation tasks, suchas plant cycling and widely varying ambient conditions. Employing these methods will allowdevelopment of operation models that more accurately reflect the true technical requirements andfinancial outcome of today’s plants.

BackgroundCombustion turbine manufacturers, engineering companies, plant owners, and developers oftencite the advantages of a reference design approach for new combined-cycle plants. This mayinvolve consideration of standard designs from the vendor, architect-engineer, or previousprojects. Advantages include reduced engineering time and construction schedules, lower designcosts, and increased purchasing leverage from being able to commit to multi-unit orders.However, fuel costs and electricity revenues dominate the plant life cycle economics. Use ofstandard reference plants can lead to less competitive plant design proposals, and may result innon-optimal fit with the construction and operating requirements. EPRI sponsored this study toquantify the significance of plant design decisions on the performance and economics ofcombined-cycle power plants.

ObjectiveTo provide evaluations of combined-cycle optional plant parameters and equipment selectionsfor optimizing plant return on investment.

ApproachPlant parameter and equipment options selected for evaluation include heat recovery steamgenerator (HRSG) design, HRSG duct firing, inlet cooling via absorption chilling, inlet coolingvia media-type evaporative cooling, and inlet cooling via high pressure fogging. Investigatorsdeveloped the evaluations using two methods. The first—the traditional approach using averageannual electricity prices, fuel costs, ambient temperatures, average capacity factor, and otherparameters—is suitable when plant operations, costs, and electricity sale price are fairly constant.The second evaluation approach involves defining a minimum, but sufficient number of plantoperating cases, then determining plant performance and operating costs for each case. Finally,an equivalent annual case is determined from the operating cases. Wide fluctuations in electricityand major increases in natural gas pricing required case development using the equivalent annualmethod. Investigators developed plant conceptual designs, performance data, capital and O&M

vi

cost estimates, and financial results using EPRI’s SOAPP-CT (State-of-the-Art Power Plant-Combustion Turbine) Combined-Cycle Workstation Software. They defined optimization bycomparing the financial return for two cases—the base design and the design with the parameteror equipment option being considered.

ResultsThe analyses resulted in quantification of the degree to which plant economic performance wasimpacted through implementation of the proposed design optimization technologies. InternalRate of Return (IRR)—sometimes called the Discounted Cash Flow Rate of Return(DCFROR)—serves as the basis of comparison in this report. The IRR is defined as the rate ofreturn that makes the present worth of after-tax cash flow for an investment equal to the presentworth of all after-tax investments. These principles were applied with the objective ofmaximizing plant profitability. Following are key results obtained:

• For HRSG design enhancement of a cycling plant in Chicago, Illinois, implementing a moreexpensive, high efficiency design did not lead to increased IRR. The cost of such changesoutweighed the benefit, with overall IRR decreasing by a small amount. However, for thesame design, but with a higher plant capacity factor, the high efficiency HRSG did result in aslightly improved IRR in two separate evaluations.

• For cycle optimization via combustion inlet air cooling of a cycling plant in Phoenix,Arizona, the technologies of media-type evaporative cooling and high pressure inlet foggingimproved IRR significantly. Alternatively, steam absorption chilling only slightly enhancedoverall IRR.

• For cycle optimization via supplemental firing of a cycling plant in Chicago, implementing awell-designed duct firing system only improved overall IRR marginally. However, sinceoverall IRR of the base design was significantly less than the Phoenix base design, the IRRimprovement represented a much greater return for the Chicago-based plant.

EPRI PerspectiveAlthough there is an inherent simplicity in using reference plant designs for project development,there are financial risks in doing so without considering major design options. Reference designsare generally not optimized for the specific function and/or site. Furthermore, such designs maybe appropriate for base-load plants, but not for peaking or cycling-load plants. Technologyenhancements may dramatically improve project profitability under some conditions, but notothers. EPRI recommends that major equipment options be considered on a site-by-site basis forimproving equity returns and reducing financial risk. This includes examining each plant’sfunctional requirements, then studying technologies to meet those requirements. EPRI softwareproducts—such as the SOAPP-CT Workstation—support such activities and provide thedeveloper with outstanding tools to quickly and accurately explore a variety of plant designs andconfigurations in order to minimize risk and maximize financial returns.

KeywordsCombustion turbinesCombined cyclesHeat recovery equipment

EPRI Licensed Material

vii

ABSTRACT

A properly prepared performance and financial analysis is needed to demonstrate the cost-benefitof proposed combined-cycle plant options. To create competitive proposals at a reasonableexpense while managing risk, a project developer must accurately and cost-effectively addressthe unique circumstances of each project opportunity—including ambient temperatures, airemissions limits, and fuel, electricity, and construction pricing. Combustion turbinemanufacturers, engineering companies, plant owners, and developers often cite the advantages ofa reference design approach for new combined-cycle plants. Advantages include reducedengineering time and construction schedules, lower design costs, and the increased purchasingleverage available from being able to commit to multi-unit orders. However, fuel costs andelectricity revenues dominate the plant life cycle financial picture. Therefore, the best projectfinancial performance—as measured by Internal Rate of Return—can only be determined by aplant design optimization analysis using site-specific parameters.

The objective of this study is to demonstrate the significance of plant design decisions on theperformance and economics of combined-cycle power plants in a competitive market. Plantparameter and equipment options selected for evaluation include heat recovery steam generator(HRSG) design, HRSG duct firing, inlet cooling via absorption chilling, inlet cooling via media-type evaporative cooling, and inlet cooling via high pressure fogging. The analysis—usingEPRI’s SOAPP-CT (State-of-the-Art Power Plant-Combustion Turbine) Combined-CycleWorkstation Software—demonstrates the sensitivity of the results to capacity factor, fuel costs,and electricity prices.


ix

CONTENTS

1 INTRODUCTION.................................................................................................................. 1-1

Overview ............................................................................................................................ 1-1

Plant Evaluation and Optimization ...................................................................................... 1-2

Plant Evaluation Description ............................................................................................... 1-5

Evaluation Methodology ..................................................................................................... 1-6

Plant Definition Overview.................................................................................................... 1-8

Summary of Conclusions.................................................................................................... 1-9

2 HEAT RECOVERY STEAM GENERATOR OPTIMIZATION – CHICAGO AREA................ 2-1

Introduction......................................................................................................................... 2-1

HRSG Performance Optimization - General Concepts........................................................ 2-1

Average Annual Method Optimization Example .................................................................. 2-3

Equivalent Annual Method Optimization Example............................................................... 2-7

3 INLET AIR COOLING – PHOENIX AREA ........................................................................... 3-1

Introduction......................................................................................................................... 3-1

Inlet Air Cooling Technologies Available ............................................................................. 3-1

Evaluation Overview........................................................................................................... 3-1

Case Description ................................................................................................................ 3-2

Site ................................................................................................................................ 3-2

Plant Operation Philosophy............................................................................................ 3-3

Unit Sizing...................................................................................................................... 3-4

Electricity and Gas Pricing ............................................................................................. 3-4

Inlet Air Cooling Technologies Evaluated............................................................................ 3-5

Definition of Cases for Evaluation ....................................................................................... 3-6

Case Analysis and Data Reduction..................................................................................... 3-7

Results ............................................................................................................................... 3-8

Tables of Results ........................................................................................................... 3-8


x

Implication of Results ..................................................................................................... 3-9

Chapter Conclusion .......................................................................................................... 3-10

4 DUCT FIRING – CHICAGO AREA....................................................................................... 4-1

Introduction......................................................................................................................... 4-1

Duct Firing Design .............................................................................................................. 4-1

Evaluation Overview........................................................................................................... 4-2

Case Description ................................................................................................................ 4-2

Site ................................................................................................................................ 4-2

Plant Operation Philosophy............................................................................................ 4-3

Unit Sizing...................................................................................................................... 4-4

Electricity and Gas Pricing ............................................................................................. 4-4

Definition of Cases for Evaluation ....................................................................................... 4-5

Case Analysis and Data Reduction..................................................................................... 4-6

Results ............................................................................................................................... 4-7

Tables of Results ........................................................................................................... 4-7

Implication of Results ..................................................................................................... 4-8

Chapter Conclusion ............................................................................................................ 4-9

A APPENDIX A – SI - ENGLISH UNIT COMPARISON ..........................................................A-1

B APPENDIX B – SUPPORTING DATA – INLET AIR COOLING – PHOENIX AREA ...........B-1

C APPENDIX C – SUPPORTING DATA – DUCT FIRING – CHICAGO AREA ......................C-1

D APPENDIX D – REFERENCES...........................................................................................D-1


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LIST OF FIGURES

Figure 1-1 SOAPP Software Operation ................................................................................... 1-4

Figure 1-2 Electricity Price Fluctuation .................................................................................... 1-6

Figure 1-3 Study Results: IRR Improvement, in Points.......................................................... 1-10

Figure 2-1 Basic HRSG Configuration ..................................................................................... 2-2

Figure 2-2 HRSG Pinch and Approach Temperatures............................................................. 2-2


xiii

LIST OF TABLES

Table 1-1 Proposal Development Steps – Summary ............................................................... 1-3

Table 1-2 Plant Evaluation Descriptions .................................................................................. 1-5

Table 1-3 Equivalent Annual Evaluation Method ..................................................................... 1-7

Table 1-4 Plant Definition Snapshot ........................................................................................ 1-9

Table 2-1 HRSG Design Options............................................................................................. 2-3

Table 2-2 HRSG Evaluation Example − Common Input........................................................... 2-4

Table 2-3 HRSG Cases........................................................................................................... 2-5

Table 2-4 Estimated Capital Costs .......................................................................................... 2-5

Table 2-5 O&M Estimated Costs ............................................................................................. 2-6

Table 2-6 Internal Rate of Return ............................................................................................ 2-6

Table 2-7 Input Using Equivalent Annual Method.................................................................... 2-7

Table 2-8 Summary: HRSG Optimization − Chicago Area..................................................... 2-12

Table 2-9 Incremental Impact: HRSG Optimization − Chicago Area...................................... 2-13

Table 3-1 Phoenix Weather..................................................................................................... 3-3

Table 3-2 Operation Philosophy of Cycling Plant..................................................................... 3-4

Table 3-3 Electricity Prices for Phoenix Site ............................................................................ 3-4

Table 3-4 Gas Prices for Phoenix Site..................................................................................... 3-5

Table 3-5 Operating Cases for Phoenix Case Study ............................................................... 3-7

Table 3-6 Summary: Inlet Air Cooling Study – Phoenix Area................................................... 3-8

Table 3-7 Incremental Impact: Inlet Air Cooling Study – Phoenix Area.................................... 3-9

Table 4-1 Chicago Weather..................................................................................................... 4-3

Table 4-2 Operation Philosophy of Cycling Plant..................................................................... 4-4

Table 4-3 Electricity Prices for Chicago Area........................................................................... 4-4

Table 4-4 Gas Prices for Chicago Area .................................................................................. 4-5

Table 4-5 Operating Cases for Chicago Case Study ............................................................... 4-6

Table 4-6 Summary: Duct Firing Study - Chicago Area ........................................................... 4-7

Table 4-7 Incremental Impact: Duct Firing Study - Chicago Area ............................................ 4-8

Table A-1 Unit Conversions.....................................................................................................A-1

Table B-1 Inlet Air Cooling-Phoenix: SOAPP-CT Case Input Data ..........................................B-2

Table B-2 Inlet Air Cooling-Phoenix: SOAPP-CT Case Results.............................................B-18

Table B-3 Inlet Air Cooling-Phoenix: SOAPP-CT Estimated Costs ........................................B-33


xiv

Table C-1 Duct Firing-Chicago: SOAPP-CT Case Input Data..................................................C-2

Table C-2 Duct Firing-Chicago: SOAPP-CT Case Results ....................................................C-12

Table C-3 Duct Firing-Chicago: SOAPP-CT Estimated Costs ...............................................C-18


1-1

1 INTRODUCTION

Overview

The electric power industry is very competitive, domestically and internationally. Electricitysuppliers often need to aggressively compete for new customers and bid to furnish newgenerating units. In this market, successful projects must satisfy electricity price thresholds(wholesale or retail), project construction schedule and costs, environmental criteria, operatingcosts, reliability, and provide a satisfactory financial return for the project developer/owner.

The site-specific nature of each project and the many possible business and technology scenariosmake it costly for plant developers to optimize unit performance, capital cost, competitivepositioning, and return on investment. Shortening project construction schedules and reducingproposal and final plant design engineering costs is often given top priority. Furthermore, lessthan one project in 50 is ever completed and more than 100 proposals are sometimes submittedfor a potential project.

Standard vendor or architect engineer plant designs are often used in response to pressure toreduce proposal development costs and proposal/project schedules. At times, designs from priorprojects are also utilized. However, following this path can lead to using plant designs that resultin unsuccessful proposals or plant financial results. Examples of these risks are:

• High construction and/or operating (especially fuel) costs result in high electricity costs,which in turn result in either a noncompetitive proposal or low plant profitability.

• Using electricity pricing that is deemed competitive without a corresponding plant designmay result in higher than anticipated construction and/or operating costs resulting in anon-profitable project.

• The variation in construction costs, which can be 40% different between a high and low costlabor area needs to be considered in the capital cost estimate as well as in the plant designoptimization.

• Volatility of fuel pricing is currently a major consideration. Just one year ago, many projectswere planning on natural gas pricing in the $2.50 per MBtu ($2.37 per GJ) gas price rangehowever, current gas pricing can be twice this amount. Therefore, previous standard andreference designs may be out of date.

• Electricity pricing in the past was fairly consistent throughout the year. This past summermost U.S. regions experienced very large variations in electricity pricing.

Increasing plant output and/or efficiency by adding equipment such as inlet air coolers or byincreasing the efficiency and/or capacity of HRSGs, condensers, cooling tower or other


Introduction

1-2

equipment can significantly improve plant financial return. However, additional equipmentrequires additional capital and O&M expenses. A properly prepared performance and financialanalysis is needed to show the cost benefit of plant options. Equipment performance at theapplicable ambient temperatures, and capital, fuel and other O&M costs and other applicablematters for the site ambient temperatures over an average year needs to be included.

To develop competitive proposals at a reasonable expense, while managing risk, the projectdeveloper must be able to quickly, accurately, and cost-effectively address project specific needs,including ambient temperatures, air emissions limits, and fuel, electricity, construction pricing;i.e., the unique requirements of each project opportunity. In the early 1990s, the Electric PowerResearch Institute (EPRI) recognized the need to combine technical and economicdecision-making into one software package to provide quick plant conceptual design informationand accurate cost estimates and financial analysis. In response, EPRI sponsored development ofthe SOAPP (State-of-the-Art Power Plant) suite of software products, created to supportdevelopment of new electric generating plants and the upgrading and repowering of existingunits.

The SOAPP-CT WorkStation was used in developing the analysis provided in this report. TheWorkStation automates plant conceptual design, generating heat and material balances,preliminary equipment sizing, plant reference diagrams and drawings, cost estimates,construction schedules and financial analysis based on user-selected equipment, site,environmental, fuel, and economic criteria. The integration of technical and financial analysisenables the user to make business and technical decisions conjointly, rather than independentlyas in the past. The WorkStation provides the capability of evaluating a range of likely scenarios,striking the best balance between risk and reward. The methodology for developing WorkStationEquivalent Input is a new development and is described in this report.

This report provides the results of analysis for the following plant equipment evaluation casestudies, each with 3 electricity price categories:

1. HRSG Steam/Water Cycle Parameters (4 design cases at 2 capacity factors)

2. Combustion Turbine Inlet Air Cooling (6 ambient cases with 3 different technologies plusbase case)

3. HRSG Inlet Duct Firing (4 ambient cases)

Plant Evaluation and Optimization

Determining the generation and business goals is the most important first step in preparingproposals because this will usually lead to the identification of the most competitive plantconfiguration. Often, there is a tendency to begin these studies with a previous unit or amanufacturer’s design to keep engineering costs low, or because of short schedules. However,this can lead to over looking the best options for optimized efficiency and plant costs, whichleads to higher financial returns.


Introduction

1-3

A very brief summary of typical activities for preparing proposals in the traditional approach andusing the SOAPP software WorkStation optimization approach is provided in the table below:

Table 1-1Proposal Development Steps – Summary

Traditional Activity Optimization Approach (SOAPP) Activity

1. Obtain plant and site data, e.g.,• Ambient temperatures

• Power required

• Fuel availability and costs

• Transmission interconnection

• Environmental regulations

• Site layout

Same

2. Prepare Heat Balances• Determine CT model, cycle configuration, and

plant performance.

• optimization is usually done based on pastexperience and judgment incorporating thenew plant requirements.

Develop Initial WorkStation analysis, including• SOAPP Heat balances - Prepare detailed

heat balances, if necessary.

• Conceptual design

• Capital and O&M cost estimates

• Financial proforma

• Define the target plant and financialperformance.

3. Prepare plant design information – options are:• Use prior or reference design.

• Development new design.

Prepare plant design information• Optimize the plant design for maximum

IRR by varying plant design using theSOAPP WorkStation (e.g., HRSG designconditions or inlet air cooling).

• Prepare optimized plant designinformation. Prior, reference or a newdesign can be used, which incorporatesthe optimization results.

4. Prepare cost estimates and obtain EPC or majorequipment quotations.

Same – using optimized design. Modifyoptimized design if pricing is significantlydifferent than used previously and adjust thecapital, fuel and O&M cost estimates.

5. Prepare the evaluation, financial proforma, orproposal.

Prepare the evaluation, financial pro forma, orproposal.

The two major differences between the Traditional and Optimization Approach ProposalDevelopment Activities; described below:

• The Optimization Approach uses the SOAPP WorkStation to develop initial heat balances,conceptual design, capital and O&M cost estimates and financial proforma at the start of theproposal process.


Introduction

1-4

• The SOAPP WorkStation information is used at the start of the proposal development tooptimize the plant design and to establish the target plant and financial performance.

The SOAPP WorkStation allows the user to define unit configurations, site variations, economicscenarios, and fuel costs. Once selected and associated together as a conceptual design, theprogramming for performance, cost, and financial analyses output are fully automated. The basicfunctionality is shown in the following diagram:

PlantPlant

UnitUnit

FinancialFinancial

SiteSite

ValidateValidateinputsinputs

ConceptualConceptualdesign criteriadesign criteria

PlantPlant

ConceptualConceptualdesign criteriadesign criteria

UnitUnit

FinancialFinancial

SiteSite

ValidateValidateinputsinputs

Heat andHeat andmaterialmaterialbalancesbalances

EstablishEstablishprocessprocessinterfacesinterfaces

EquipmentEquipmentsizingsizing

DrawingsDrawings

Designbasis

selection

Designbasis

selection

CostCostestimatesestimates

EstimateEstimatescheduleschedule

FinancialFinancialanalysisanalysis

ReportsReports

Figure 1-1SOAPP Software Operation

The Unit Data group allows the user to input specific key design attributes of the unit The userstarts with the selection of the combustion turbine (CT) model, selecting from a data base ofcommercially available 50 and 60 Hz models, ranging in size from 20 MW to 220 MW. Simplecycle, combined cycle, and cogeneration cycles can be configured. Next the user configures eachmajor equipment item and selects process design conditions. For example, HRSG steampressures and temperatures, pinch and approach points can be selected. Inlet air cooling can beselected and steam turbine condenser pressure can be defined. Capital, fuel, O&M and other costadjustments can be made. Overall, 400 inputs are provided to allow for proper definition of theplant.

The Site Data Input group consists of ambient conditions (temperature, elevation, etc.),environmental criteria (emissions limits), site conditions (seismic zone, cooling water conditions,etc.), and certain site-specific cost and economic inputs. Cost adjustments can be made forconstruction labor and productivity, makeup water, operator salaries, and combustion turbine andother O&M activities.

The Fuel Data group defines the available fuels and fuel usage. Primary and secondary fuels aredefined, along with a secondary fuel usage factor.


Introduction

1-5

The Economic Data group contains the information required to perform the capital and O&Mcost estimates, and the financial analyses.

Following is a summary of the WorkStation output:

• Design Criteria

• Equipment and Motor Lists

• Performance and Emission Data

• Project Schedule

• Capital Cost Estimates

• Bulk Material Quantities

• O&M Cost Estimates

• Financial ProForma

The WorkStation integrates performance, cost, and financial analysis capabilities into oneproduct, combining them with a flexible data input structure. This allows the user to optimize theplant design to technical and financial criteria, and assess it against project and marketuncertainties. Because so many project-specific site and financial variables interact with thedesign, no single parameter can be used to judge the optimum solution for any particular project.“What if” scenarios can be provided, and are an invaluable tool for evaluating the impacts of keydesign decisions on overall performance and financial return to reduce project risk

Plant Evaluation Description

The plant evaluations presented in this report are summarized below:

Table 1-2Plant Evaluation Descriptions

Chapter Description Discussion

2 HRSG Optimization –Chicago Area

Two evaluations are presented: an average annualevaluation and a equivalent annual evaluation

3 Inlet Air Cooling –Phoenix Area

Evaluation of evaporative cooling, high pressure inletfogging and steam absorption inlet chillers are presentedcompared to a base design plant.

4 Duct Firing –Chicago Area

Evaluation of a plant with increased output using ductfiring compared to a base design plant is presented.


Introduction

1-6

Evaluation Methodology

As stated at the outset, the objective of the evaluations is to identify configurations whichmaximize plant profitability Internal Rate of Return, or After Tax Discounted Cash Flow Rate ofReturn, is a commonly used measure of profitability and is the return on the equity investmentover the project book life. Other financial comparison criteria can be used based on the specificproject, ownership and other reasons.

Two types of evaluation methodologies are used in this report. The first is the traditionalapproach using average annual electricity, fuel, ambient temperatures, average capacity factor aswell as other parameters. This method is suitable when plant operations, costs, etc. are fairlyconstant.

The second evaluation approach involves defining a minimum, but sufficient number of plantoperating cases, which input to an Equivalent Annual Case. The need for the Equivalent Annualevaluation method came about during this study when determining electricity and fuel priceinput to the plant evaluations. A focused analysis, such as the Equivalent Annual or another type,is needed to account for increased electricity and fuel pricing during various types of the year,especially during summer when high ambient temperatures cause a significant reduction incombustion turbine output.

The following graph shows an example of recent extreme electricity price fluctuations for theEast Central Region:

1999 Daily On-Peak Electric PriceVolatility For ECAR Region

0

50

100

150

200

250

Date

1%

95%

99%

Mean

98 ECAR

Figure 1-2Electricity Price Fluctuation


Introduction

1-7

Recent natural gas fuel prices have increased dramatically as outlined below:

• Often Referenced Past Prices

– 1998 = $2.15/MBtu ($2.04/GJ)

– 1999 = $2.55/MBtu ($2.42/GJ)

• Current Situation - Year 2000

– March Futures = $2.80/MBtu ($2.65/GJ)

– June Futures = $4.00/MBtu ($3.79 /GJ)

– September Futures = $5.00/MBtu ($4.74/GJ)

• Some planners currently use $3.80/MBtu ($3.60/GJ) (for long termcontracts - interruptible)

The Equivalent Annual evaluation method used in the report is summarized below:

Table 1-3Equivalent Annual Evaluation Method

Definition Steps: Defining plant requirements and operating modes

1 Type of Plant – Usually a Base Design and an Optional Design are defined.

2 Electricity Pricing Information. Define export and host as applicable

3 Export Steam Requirements are determined, if any.

4 Approximate (Planned) Duct Firing, if any.

5 Fuel Costs. Define type of fuel and base year fuel costs.

6 Average Annual Temperatures (Dry Bulb). Compiled with hours/year to assist definitionof configurations to be analyzed.

7 Operation Philosophy. Define operating strategy during different conditions.

8 Target Output (Approximate). Specify approximate desired electrical output of plantduring each operating condition.

9 Operating Case Definitions. Define operating hours, shutdown hours, case numbers,and operating temperatures.

10 Case Configuration Description. Data is compiled from previous steps into CasesSOAPP-CT input for the Base and Optional Designs.


Introduction

1-8

Table 1-3Equivalent Annual Evaluation Method (Continued)

Analysis Steps: Running SOAPP-CT software analyses for each plant operating case,then iterating to refine analysis and develop a “SOAPP Equivalent Input” case.

11 Generate Case Results. Data from individual SOAPP-CT runs is copied intospreadsheet.

12 Generate SOAPP Equivalent Annual Case. Data from individual cases is compiled intosingle, representative case.

13 Generate SOAPP Equivalent Annual Case Results. Data from SOAPP-CT run is copiedinto spreadsheet.

14 Steps 12, 13, 14 are repeated as necessary until SOAPP Equivalent Annual Case mostprecisely replicates combination of individual cases.

15 Operating data, capital and O&M cost estimates and financial data from the SOAPPEquivalent Annual Case is reviewed. A determination is made if additional cases areneeded to reach the optimization desired. Additional cases are developed if needed.

16 The final results of the optimization are obtained.

Plant Definition Overview

For the purposes of standardized analysis throughout this report, the following plantconfiguration was applied to all designs:


Introduction

1-9

Table 1-4Plant Definition Snapshot

Design/Model Parameter Value

Cycle Type Combined Cycle Cogeneration

Plant Duty Cycling (Capacity Factor = Approximately 60%)

Application (New vs Repowered vs Modified) New

Configuration Two (2) Combustion Turbines (Chap. 2 only)

One (1) Combustion Turbine (Chap 3 and 4)

One (1) Heat Recovery Steam Generator (HRSG)

One (1) Steam Turbine

Combustion Turbine GE PG7241 FA

Single Fuel (natural gas), DLN Combustor

Heat Recovery Steam Generator (HRSG) Three Pressure w/ Reheat, Integral Deaerator,1800 psia HP, 490 psia IP, 60-75 psia LP

Steam Turbine Reheat, 2 Casing, 1 Flow, Axial Exhaust

Heat Rejection System Chicago Sites: Mechanical Draft Cooling Tower;

Phoenix Sites: Air Cooled Condenser

Plant Ownership (Investor Owned Utility vs.Independent Power Producer)

Independent Power Producer

Electricity Pricing Low to Moderate

Electricity Pricing Escalation 2.0%/year

Fuel Costing Moderate

Fuel Cost Escalation 3.5%/year

Plant Book Life 20 years

Plant Tax Life 15 years

Summary of Conclusions

Several key conclusions resulted from the study documented by this report. Below is asummarized graph depicting the level of improvement to plant Internal Rate of Return (IRR),sorted by plant site and plant technology:


Introduction

1-10

0.00

1.84

2.10

0.62

0.00

0.70

0.00

0.50

1.00

1.50

2.00

2.50

Phoenix -Base Case

Phoenix -Evaporative

Cooling

Phoenix -Fogging

Phoenix -Inlet Chilling

Chicago -Base Case

Chicago -Duct Firing

Plant Site & Design Technology

IRR

Impr

ovem

ent (

Poi

nts)

Figure 1-3Study Results: IRR Improvement, in Points

From the above data, the benefit of implementing evaporative cooling technology is shown to besignificant within the area where it was applied - Phoenix. The 0.70 point gain due to duct firingin the Chicago-area plant was significant in that the initial base design had a lower initial IRR;the gain was proportionately more significant to the financial bottom line.


2-1

2 HEAT RECOVERY STEAM GENERATOROPTIMIZATION – CHICAGO AREA

Introduction

Combustion turbine performance has the primary impact on combined cycle plant efficiency.The next most important piece of equipment that impacts efficiency is the heat recovery steamgenerator (HRSG). HRSG performance optimization includes selecting steam pressures,temperatures, flows, pinch points, approach temperatures, and resulting HRSG exit gastemperature.

This chapter presents two evaluation methods. The first uses the Average Annual method and thesecond using the Equivalent Annual Method. These example analyses optimize HRSG operatingpressures, and pinch and approach temperatures. Constant and relatively low gas prices, constantelectricity pricing (including capacity and energy payments), and a single average operatingpoint are incorporated. This is typical input prior to recent experience when gas and electricitypricing, and the concept of lower plant capacity factors have come to the forefront.

HRSG Performance Optimization - General Concepts

Figure 2-1 is a typical cycle for a single pressure HRSG. Multiple pressure HRSGs with ductfiring and other capabilities can become much more complicated. This diagram shows the maingas, steam, and condensate flows, and the typical HRSG surfaces and steam drums. Flue gasfrom the combustion turbine enters the HRSG and is reduced in temperature by the superheater,reheater, drum evaporative surfaces, and economizer before it enters the stack. Condensate fromthe combined cycle condenser enters the deaerator, and flows through the economizer to thedrum. Steam from the drum flows to the superheater and then to the high pressure turbine. Steamfrom the high pressure steam turbine flows through the reheater and then to the intermediatepressure turbine.


Heat Recovery Steam Generator Optimization – Chicago Area

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Figure 2-1Basic HRSG Configuration

Pinch points and approach temperatures are important HRSG design parameters. Reducing thesetemperatures will increase cycle efficiency. However, optimization involves fairly complicatedheat transfer calculations and steam cycle heat balances to avoid operational problems.Figure 2-2 provides a simple diagram showing pinch and approach temperatures:

Figure 2-2HRSG Pinch and Approach Temperatures

The first decision to be made is the choice of gas turbine size. As a general guideline, the gasturbine will represent 66% of the plant’s electrical output assuming that the HRSG does notemploy a duct burner. The remaining output will be supplied by the steam turbine. For example,if the plant’s requirement is 250 MW, then 165 MW would be supplied from the gas turbine and85 MW would be supplied by the steam turbine. 60 Hz gas turbines currently available in the165 MW class range are the GE’s Frame 7FA, Siemens Westinghouse’s 501F, Siemens’V84.3A, and Alstom’s GT24.

If it is desired that the steam turbine supply an additional percentage of the plant’s output, thiscan be increased up to 50% if a duct burner is added. A steam turbine that supplies 50% of the



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output to a combined cycle plant using one of the aforementioned gas turbines would increasethe plant’s overall output from 250 MW to 335 MW.

With the plant’s size and gas turbine choice made, the plant’s heat rate is determined next. Thisbecomes a tradeoff between capital cost and efficiency. The lowest cost option would be a onepressure level, non-reheat HRSG resulting in relatively poor heat rate. To obtain better heat rateswith associated higher costs the following provides a general guide to the ranking of options.

Table 2-1HRSG Design Options

HRSG Costs HRSG Configuration Heat Rate

Low 1 Pressure Level, Non-Reheat Higher

Low to Medium 2 Pressure Levels, Non-Reheat Medium/High

Medium 3 Pressure Levels, Non-Reheat Medium

Medium to High 2 Pressure Levels , Reheat Medium/Lower

High 3 Pressure Levels, Reheat Lower

Optimizing pinch point and approach temperatures follows the selection of the pressure level.Decreasing the pinch point and approach temperature results in higher efficiency, but highercapital cost.

Average Annual Method Optimization Example

The combined cycle plant options addressed in this section are typical process steam supply andelectrical generation cases. The selection of the performance, fuel cost, plant cost and economicparameters are based on a conservative approach. Actual project values may differ considerably.Four cases are developed. The following table shows the common design inputs for the selectedfour cases.



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Table 2-2HRSG Evaluation Example − Common Input

CT Model Number GE PG7241(FA)-60 Hz

Number of CT’s 2

Perf Point Dry Bulb Temp – F (C) 66 (18.9)

Perf Point Wet Bulb Temp – F (C) 57 (13.9)

Capacity Factor - % 85

Book Life 20

Tax Life 20

Commercial Operating Year 2002

Base Year 1999

Capital Costs Esc Rate - %/yr 3.0

O&M Costs Esc Rate - %/yr 3.0

Steam Price Esc Rate - %/yr 3.5

Primary Fuel Type/Cost Natural Gas/$2.80/MBtu($2.65/GJ)

Secondary Fuel Type/Cost No. 2 Fuel Oil/$3.50/MBtu($3.32/GJ)

Primary/Secondary Fuel Esc Rate - %/yr 2.5



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The following shows the selected design cases with different pinch and approach points.

Table 2-3HRSG Cases

Design Cases 1 2 3 4

HP Steam Pressure –psia (kPa)

1400 (9653) 1400 (9653) 1800 (12,411) 1800 (12,411)

HP Pinch Point - F (C) 16 (8.9) 10 (5.6) 16 (8.9) 10 (5.6)

IP Pinch Point - F (C) 16 (8.9) 12 (6.7) 16 (8.9) 12 (6.7)

LP Pinch Point - F (C) 16 (8.9) 14 (7.8) 16 (8.9) 14 (7.8)

HP Evap Approach - F(C)

24 (13.3) 10 (5.6) 24 (13.3) 10 (5.6)

IP Evap Approach - F(C)

24 (13.3) 12 (6.7) 24 (13.3) 12 (6.7)

LP Evap Approach - F(C)

24 (13.3) 14 (7.8) 24 (13.3) 14 (7.8)

Net Plant Output - kW 499,966 501,800 501,360 503,230

Stack Exhaust temp - F(C)

212 (100) 203 (95) 213 (100.6) 204 (95.6)

Net Plant Heat Rate(HHV) 100% Load –Btu/kWh (kJ/kWh)

6,980 (7,365) 6,955 (7,339) 6,961 (7,345) 6,935 (7,317)

Capital costs for these four cases were shown in the following table. Note these costs are for ahigh labor site area.

Table 2-4Estimated Capital Costs

Design Cases – US$ x 1000 1 2 3 4

Combustion Turbines andAccessories

83,497 83,497 83,497 83,497

HRSGs, SCR, and Accessories 29,704 34,588 29,938 35,107

Balance of Plant 85,372 85,752 85,672 86,002

Total Process Capital 198,573 203,837 199,107 204,606

Total Investment (includesland, taxes, engr., escalation,

startup, etc.)

242,778 249,121 243,421 250,047



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Table 2-5 shows operating costs for Cases 1 through 4.

Table 2-5O&M Estimated Costs

Design Cases – US$ x 1000 1 2 3 4

Fuel 73,958 73,958 73,958 73,958

Fixed Operating Expenses 9,856 9,973 9,860 9,982

Variable Operating Expenses 73,958 73,958 73,958 73,958

The resulting Internal Rates of Return (IRR) for the four design cases are shown below: Capacitypayments are $94/kW-yr, and energy payments are $25.50/MWh for the first year of operationwith escalation rate of 3%/yr for subsequent years.

Table 2-6Internal Rate of Return

Scenario No. 1 2

Fuel Price, year 2000 , w/2.5% annual escalation –$US/MBtu ($/GJ)

2.80(2.65)

2.80(2.65)

Capacity Factor – % 85 45

IRR %, Design Case 1 18.34 18.97




Based on the parameters selected, the SOAPP WorkStation IRR results show that the best returnis obtained with the more efficient cycles at the 85% capacity factor and the IRR isapproximately equal for all cases at the 45% capacity factor. This indicates for these parametersthe additional capital cost for the more efficient HRSG and steam turbine cycle is not costjustified at lower capacity factors.

It must also be noted that from a relativistic perspective, the range of IRR results for this case isquite narrow. For this evaluation, the range of rates of return spanned from a minimum of18.34% to a maximum of 19.03%, a bandwidth of just 0.69%. A difference in return of 1.0% ormore between two cases should be considered significant. Differences less than 1.0% reflectmore of a comparative direction than a comparative distinction between designs. As such, therealized difference between designs will be better appreciated by evaluating incremental changesto capital requirements and cash flow to equity.



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Equivalent Annual Method Optimization Example

The combined cycle parameters addressed in this section are similar to the previous section,except for the following:

• A single GE Frame 7 FA combustion turbine, and HRSG is used instead of two CTs andHRSGs.

• Electricity and fuel prices vary during the year and are higher than in the previous example.

• Operating temperatures are based upon period-based case determination, which in turn arecompiled into the Equivalent Annual Case.

The following shows the development of the input for the Equivalent Annual Method evaluation:

Table 2-7Input Using Equivalent Annual Method

StepNo.

1 Define Type of PlantDefine the type of plant to be designed and optimized.Type Cycling, Capacity Factor = 55%, operation is linked to electricity

price/weather.No. of Starts/year 40Equip AvailabilityFactor

0.95 Used in defining Total HoursAvailable

Output Degradation 1.0%Heat RateDegradation

0.5%

2 Electricity Pricing - Target, current, estimate, or other basis.Specify expected electricity pricing.

$/MW hrWinter Spring/Fall Summer

PeakExport $50.00 $60.00 $70.00Host n/a

AverageExport $40.00 $35.00 $45.00Host n/aLow

Export $30.00 $30.00 $35.00Host n/a



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3 Export Steam RequirementsSpecify expected Export Steam flow rate. No export of steam to be

considered for this case.lb/hr

(kg/hr)Winter Spring/Fall Summer

Supply 1 None None NoneAverage

PeakShutdown Steam supply during a shutdown

requires an auxiliarySupply 2 None None None boiler or (additional) duct firing.Average

PeakShutdownSupply 3 None None NoneAverage

PeakShutdown

4 Approximate (Planned) Duct FiringSpecify desired level of duct firing.

Elect. Price Btu/hr(kJ/hr)

No duct firing to be consideredfor this case.

Winter Spring/Fall SummerPeak None None None

Average None None NoneLow None None None

5 Fuel Costs - Base Year - Natural Gas or Fuel OilSpecify expected fuel pricing.Fuel Type Natural Gas Basis: Energy Information

Administration$/MBtu($/GJ)

Natural Gas Monthly, June 2000

Winter Spring/Fall Summer Prices of Nat Gas to ElectricUtilities.

Peak 4.50(4.27)

4.00(3.79)

4.00(3.79)

Average 3.25(3.08)

3.25(3.08)

3.25(3.08)

Low 3.00(2.84)

2.75(2.61)

3.25(3.08)

6 Average Annual Temperatures (Dry Bulb)Specify seasonal temperature data for projected site.Site Chicago, Illinois

Hours Avg.Temp.

TOTALS Basis: Data obtained fromYorkCalc Software

Temp. Range Winter Spring/Fall Summer Data based on Chicago, IL.80 to 100 0 122 431 90 553 Winter=December, January,

February;Spring=March, April, May; etc.

60 to 80 2 1115 1510 70 262740 to 60 176 1883 262 50 23210 to 40 1978 1267 0 20 3245

Total Hours 2156 4387 2203 8746 8746Avg. Temp. 25.96 50.08 71.39



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7 Operation PhilosophySpecify expected operation of plant during each condition. This should be consistent with a

cycling plantElect. Price Operation

Winter Spring/Fall Summer Note: Full = 100% of plantavailability

Peak Full Full Full Part = 30-60% of plantavailability

Average Part Time Part Time Full Shutdown = 0% of plantavailability

Low Shutdown Shutdown Part Time

8 Target Output (Approximate)Specify target electrical output of plant during each condition based on preliminarySOAPP-CT analysis.

Iteration may be necessary.

Net MWWinter Spring/Fall Summer

PeakExport 250 230 230 Need to be revised after first

SOAPP iterations.Host n/a n/a n/aTotal 250 230 230

Average Average and low would be usedwith multiple CTs.

Export 260 250 240Host n/a n/a n/aTotal 260 250 240Low Average and low would be used

with multiple CTs.Export 270 260 250Host n/a n/a n/aTotal 270 260 250



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9 Operating Case DefinitionsDefine operating hrs., shutdown hrs., case number, and case operating temp.

Yearly Averages Hrs./Temp. Wkendhrs.

624

Winter Spring/Fall Summer Holidays 288PEAK

CASE NUMBER – 4x 4y Case 4x: SpringFall Peak ElecPricing

Total Hours 2 122 431 555 0 Case 4y: Summer Peak ElecPricing

Total Hrs. Available 2 116 409 527 Reduced due to Service Factorin Table 1

Percent Hrs.Operating

0% 100% 100%

Operating Hours 0 116 409Temp. Range 60-100 F 80-100 F 80-100 F

Operating Temp. 90.0 90.0Approx. MW Hrs. 0 26,680 94,070

AVERAGECASE NUMBER 3 1 2

Total Hours 2154 2998 1510 6662Total Hrs. Available 2046 2848 1435 6329 Reduced due to Service Factor

in Table 1Percent Operating 60% 60% 100%Operating Hours 1228 1709 1435

Temp. Range 0-60 F 40-80 F 60-80 FOperating Temp. 26.0 50.1 71.4Approx. MW Hrs. 319,280 427,250 344,400

LOWCASE NUMBER – – 1

Total Hours 0 1267 262 1529Total Hrs. Available 0 1204 249 1453 Reduced due to Service Factor

in Table 1Percent Operating 0% 0% 100%Operating Hours 0 0 249

Temp. Range none 0-40 F 0-60 FOperating Temp. – 30.0 50.1Approx. MW Hrs. 0 0 62,250

SHUTDOWNMaintenance

Hours108 219 110 437 Pct Sched/

UnschedTo Change Maint Hrs.: ChangeService Factor in Table 1

Scheduled S/DHrs.

779 2,226 0 3,005 Sched 95% To Change Sched S/D Hrs.:Adjust % at LEFT.

Unscheduled S/DHrs.

41 117 0 158 Unsched 5% To Change Unsched S/D Hrs.:Indirect via Sched S/D %.

TOTALTotal Operating

Hrs.1,228 1,825 2,093 5,146 58.8% Capacity Factor

Total ShutdownHrs.

928 2,562 110 3,600

Total Hours 2156 4387 2203 8746Match Total Hours 2156 4387 2203 8746 From Table 6, Total Hours

Period C.F. 57.0% 41.6% 95.0%Approx. Total MWHrs.

319,280 453,930 500,720 1,273,930



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10 Case Configuration DescriptionBased on above information, build Case Configurations for SOAPP-CT model input:

Units Case Numbers1 2 3 4

Case Name ModerateAverage

HotWarmAverage

ColdAverage

HotWarm Peak

Operating Hours hrs/yr 1,958 1,435 1,228 525 5,146Pct of Total OpHrs.

% 38.0% 27.9% 23.9% 10.2% 100.0%

Perf Pt Dry Bulb F (C) 50.1(10.1)

71.4(21.9)

26.0(-3.3)

90.0 (32.2)

Perf Pt Wet Bulb F (C) 47.0 (8.3) 62.0(16.7)

25.0(-3.9)

74.0 (23.3) From YorkWorks data

CTs 1 1 1 1CT Make/Model GE 7FA GE 7FA GE 7FA GE 7FADuct Firing Y/N no no no noIAC Operation Y/N no no no noIAC Type N/A N/A N/A N/AExport Stm. Y/N no no no noAux. Boiler? Y/N no no no noCT Inlet Pres Drop(w/IAC)

in H2O(kPa)

5.00(1.24)

5.00(1.24)

5.00(1.24)

5.00 (1.24) Inlet Pres Drop WITH EvapCooler installed

CT Inlet Pres Drop(w/o)

in H2O 3.75(0.93)

3.75(0.93)

3.75(0.93)

3.75 (0.93) Inlet Pres Drop WITHOUT EvapCooler installed

CT Exh Pres Drop in H2O 14.0(3.47)

14.0(3.47)

14.0(3.47)

14.0 (3.47)

ST Eff: LP % 91% 91% 91% 91%ST Eff: IP % 89% 89% 89% 89%ST Eff: HP % 87% 87% 87% 87%HRSG: HP PinchPoint

F (C) 10/15(5.6/8.3)

10/15(5.6/8.3)

10/15(5.6/8.3)

10/15 (5.6/8.3)

First Value is High Eff; Secondvalue is Low Eff (base).

HRSG: IP PinchPoint

F (C) 12/15(6.7/8.3)

12/15(6.7/8.3)

12/15(6.7/8.3)

12/15 (6.7/8.3)


HRSG: LP PinchPoint

F (C) 14/15(7.8/8.3)

14/15(7.8/8.3)

14/15(7.8/8.3)

14/15 (7.8/8.3)


HRSG: HPApproach

F (C) 10/20(5.6/11.1)

10/20(5.6/11.1)

10/20(5.6/11.1)

10/20 (5.6/11.1)


HRSG: IPApproach

F (C) 12/20(6.7/11.1)

12/20(6.7/11.1)

12/20(6.7/11.1)

12/20 (6.7/11.1)


HRSG: LPApproach

F (C) 14/20(7.8/11.1)

14/20(7.8/11.1)

14/20(7.8/11.1)

14/20(7.8/11.1)


Equip Avail Factor % 95.0% 95.0% 95.0% 95.0%Service Factor % 60.1% 95.0% 57.0% 94.9%Capacity Factor % 60.1% 95.0% 57.0% 94.9%Max Amb Dry Bulb F (C) 100

(37.8)100

(37.8)100

(37.8)100 (37.8)

Max Amb WetBulb

F (C) 76(24.4)

76(24.4)

76(24.4)

76 (24.4)

Min Amb Dry Bulb F (C) -20(-28.9)

-20(-28.9)

-20(-28.9)

-20 (-28.9)

Elev ft (m) 610(185.9)

610(185.9)

610(185.9)

610 (185.9)

Case 1 2 3 4x 4yCapacity Pmts $/MW-yr 0 0 0 0 0Energy Payments $/MWh 35.00 45.00 40.00 60.00 70.00

67.79Energy Pmt Escal %/yr 3.00 3.00 3.00 3.00

Nat Gas Price $/MBtu($/GJ)

3.25(3.08)

3.25(3.08)

3.25(3.08)

4.00(3.79)

4.00(3.79)

Nat Gas PriceEscal

%/yr 3.50 3.50 3.50 3.50



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The results follow:

Table 2-8Summary: HRSG Optimization − Chicago Area

Overall Summary CHICAGO BASIS: SOAPP EQUIVALENT ANNUAL CASEHigh Efficiency

(Low Pinch)Low Efficiency

(High Pinch)Technical Data

Number of CT’s Operating n/a 1 1Gross CT Generator Output per CT kW 167,442 167,442Net Plant Heat Rate (HHV) at 100%Load

Btu/kWh(kJ/kWh)

6,904 (7,285) 6,924 (7,306)

Net Plant Heat Rate (LHV) at 100%Load

Btu/kWh(kJ/kWh)

6,220 (6,563) 6,238 (6,582)

Stack Exhaust Temperature F (C) 193 (89.4) 198 (92.2)Throttle Steam Flow at ST lb/h (kg/hr) 428,603 (194,413) 414,513 (188,022)Turbine Backpressure in Hg (kPa) 2.24 (7.58) 2.24 (7.58)Gross Plant Output kW 259,444 258,679Auxiliary Power kW 4,516 4,484Net Plant Output kW 254,928 254,195Weighted Capacity Factor % 58.8% 58.8%Total Energy Produced MW-hr 1,299,972 1,296,234Total Fuel Consumed MBtu (GJ) 8,975,007 (9,469,171) 8,975,124 (9,469,294)Financial Data

Total Process Capital $ 101,126,000 99,332,000General Facilities $ 2,022,520 1,986,640Engineering and Home Office Fees $ 3,033,780 2,979,960Project Contingency $ 5,056,300 4,966,600Total Plant Cost $ 111,238,600 109,265,200Total Plant Cost per net kW $/kW 436.35 429.85Total Fixed O&M $ 1,620,213 1,620,778Total Variable O&M $ 2,019,479 2,006,806Total Fixed and Variable O&M $ 3,639,692 3,627,584Fuel Cost $ 31,402,898 31,402,898Internal Rate of Return (IRR) % 13.56 13.88



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Table 2-9Incremental Impact: HRSG Optimization − Chicago Area

Incremental Impact CHICAGO BASIS: SOAPP EQUIVALENT ANNUAL CASETechnology Utilized High Efficiency

(Low Pinch)Low Efficiency

(High Pinch)Incremental Process Capital

Total Process Capital $ 101,126,000 99,332,000Incremental Process Capital $ 1,794,000 0Percent Increase in Process Capital % 1.81% 0.00%Incremental Cash Flow to Equity

Base Year Cash Flow to Equity $ 3,698,755 3,721,709Incremental Cash Flow to Equity $ -22,954 0Percent Increase in Cash Flow to Equity % -0.62% 0.00%Incremental Internal Rate of Return

Internal Rate of Return % 13.56% 13.88%Incremental Internal Rate of Return % -0.32% 0.00%Percent Increase in Int. Rate of Return % -2.31% 0.00%


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3 INLET AIR COOLING – PHOENIX AREA

Introduction

One of the most effective means of improving combined cycle plant performance is to boostcombustion turbine output by means of cooling the inlet combustion air entering the turbine. Theprinciple behind this is that gas turbines are constant volume machines. Air mass flow throughthe turbine is directly defined by its density. As ambient air temperature increases, its densitydecreases, thus permitting less mass flow to enter the turbine. This decreased mass flow impactsthe gas turbine’s power capability dramatically. Typically, power output drops by one percent foreach two degrees Fahrenheit increase in temperature. If the inlet temperature is 20ºF (11.1ºC)above ISO conditions, the gas turbine power drops by approximately 10%.

The concept of inlet air cooling counteracts this condition by simply increasing air density, thusallowing the combustion turbine to regain its power lost. Inlet air cooling also improves aircompression efficiency since at higher temperatures air is more difficult to compress. Byintroducing cooler air to the combustion turbine, more work available at the turbine shaft forconversion into electrical energy.

Inlet Air Cooling Technologies Available

Many different inlet air cooling technologies have been utilized. Traditionally, either mechanicalchillers or media-type evaporative coolers have been used. More recently, high pressure inletfogging has been increasingly used. Further, there is also experimentation with foggingoverspray being tested at varying facilities. A brief description of each of these technologies willfollow in a following section. However, the purpose of this chapter is not upon the technicalmerits of one technology over another. Rather, it is upon the importance of properly evaluatingthe plant application with respect to climate, water treatment cost, economic funding available,project economics, plant operating cycle, and much more. What may seem to be an obviouschoice at the start of project development may not turn out to be the most economic choice overthe life of the plant. Such a situation is a prime reason why advanced analysis software tools,such as SOAPP-CT are needed. It is far less difficult to run a variety of case scenarios throughSOAPP-CT than it is to manually calculate the cost benefit of one technology versus another.

Evaluation Overview

As stated earlier, the intent of running the inlet air cooling evaluation was not to technicallyprove one method over another, but rather to demonstrate that there is great merit in running aneconomically comparative case study in order to ultimately reach the optimal result.


Inlet Air Cooling – Phoenix Area

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Optimization by means of inlet air cooling is not just a matter of reducing inlet air temperature tothe lowest levels possible, it is a combination of technical, economic, regional, and O&Mparameters – all of which are necessary in reaching appropriate conclusions.

For this analysis, the method of developing Equivalent Annual cases was utilized. Discussedearlier in this paper, the concept of the Equivalent Annual case is that the operating needs of aplant may be best simulated by intelligently dividing the operability of the plant into individualperiods, or cases. The periods need not only be divided by months or seasons of the year, butthey can also be divided by operating rationale (full-time vs. stand-by vs. peaking), or byimplementation of advanced technology (i.e. utilizing inlet chilling only at ambient temperaturesabove 80ºF (27ºC)).

Using this methodology, an advanced spreadsheet-based development tool was created to assistin project evaluation. The spreadsheet was designed to capture data directly generated by EPRI’sSOAPP-CT program, reduce it according to rules declared by the user, create the EquivalentAnnual case which would represent the entire annual operation of the plant in a singleSOAPP case, then compile the results from the Equivalent Annual case for analysis, review, andcomparison. In order to model the plant most accurately, consistent HRSG design is imperative.As such, modeling of HRSG heat transfer surface areas was controlled manually by varyingpinch point and approach temperatures for each ambient case within SOAPP-CT. The remainingportions of this chapter are devoted to the results generated by a demonstrative case.

Case Description

Site

Phoenix, Arizona, was chosen as the site for the plant due to its climate, and the vast potential forcycle optimization due to having a hot yet dry environment. The American Society of HeatingRefrigeration and Air Conditioning Engineers (ASHRAE) gives the climate data for summerconditions at Phoenix as 109ºF (43ºF) dry bulb and 71ºF (22ºC) wet bulb; equaled or exceeded1% of summer hours. At such conditions, there exists an amazing 38ºF (21ºC) of capability forevaporative cooling, should this technology be used. However, there also exists the problem thatwater cost in Phoenix is exceedingly high, estimated at 5 to 6 times greater than other parts of theUnited States. The interchange between such factors lent itself to a rather complex evaluationsuch as this.



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Table 3-1Phoenix Weather

AvgTempRange (F)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Twb Hours

115-119 0 0 0 0 0 1 2 0 0 0 0 0 72 3110-114 0 0 0 0 0 12 16 3 0 0 0 0 71 31105-109 0 0 0 0 4 41 69 31 9 0 0 0 71 154100-104 0 0 0 0 18 65 117 89 40 0 0 0 70 32995-99 0 0 0 6 53 90 119 115 70 10 0 0 69 46390-94 0 0 2 22 74 97 135 128 98 36 0 0 67 59285-89 0 1 9 49 86 103 139 146 105 66 5 0 65 70980-84 0 7 31 68 97 103 96 133 121 78 18 1 62 75375-79 4 20 50 84 108 88 42 78 114 89 44 9 59 73070-74 24 46 72 91 101 64 7 18 89 107 65 26 55 71065-69 56 71 91 108 90 37 1 3 47 122 85 48 52 75960-64 80 95 112 112 66 14 0 1 20 111 113 77 49 80155-59 110 117 124 93 35 2 0 0 5 80 134 101 47 80150-54 132 120 122 55 11 0 0 0 1 32 124 128 44 72545-49 128 98 80 26 2 0 0 0 0 10 80 149 41 57340-44 109 62 35 5 0 0 0 0 0 2 39 126 37 37835-39 62 29 12 0 0 0 0 0 0 1 13 62 33 17930-34 32 6 2 0 0 0 0 0 0 0 3 14 28 5725-29 6 0 0 0 0 0 0 0 0 0 0 1 24 720-24 1 0 0 0 0 0 0 0 0 0 0 0 20 115-19 0 0 0 0 0 0 0 0 0 0 0 0 010-14 0 0 0 0 0 0 0 0 0 0 0 0 05-9 0 0 0 0 0 0 0 0 0 0 0 0 00-4 0 0 0 0 0 0 0 0 0 0 0 0 0TotalHours

744 672 742 719 745 717 743 745 719 744 723 742 8760

Note: Hours may not precisely add to 8,760 due to rounding approximations.

Plant Operation Philosophy

The operation philosophy for the subject plant was chosen to be cycling: operating only about60% of the available hours of the year. During the hottest months (when electricity prices wouldbe most likely to spike upward), the plant would be operated full-time. During the coldestmonths, the plant would only be operated part-time, or not at all. The spreadsheet tool/guidedeveloped for this analysis gave the user the ability to declare the desired operating plan for theplant under such varying conditions.



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Table 3-2Operation Philosophy of Cycling Plant

Operation PhilosophySpecify expected operation of plant during each condition. Cycling plant

Elect. Price OperationWinter Spring/Fall Summer Note: Full = 100% of plant availability

Peak Full Full Full Part = 30-60% of plant availabilityAverage Part Time Part Time Full Shutdown = 0% of plant availability

Low Shutdown Shutdown Shutdown

Unit Sizing

For the purposes of this analysis, a chosen demand of 225 to 250MW was stated to be necessaryfor this site. Such a sizing would lend itself easily to a combined-cycle application of one(1) GE PG7241 (FA)-60 Hz combustion turbine with one HRSG and one steam turbine(a 1x1x1 configuration). Although there are certainly many additional merits for discussion inthe area of multiple unit plants (i.e. 2x2x1 or 3x3x1 plants, etc), this was intentionally notincluded as part of the present analysis.

Electricity and Gas Pricing

Although it has certainly been documented (and experienced!) that electricity prices mayperiodically reach spikes of over $1900/MWh under high-demand summer conditions, it wasdecided that the highest level of free market electricity pricing for a single period would be$70/MWh. By doing so, overall project economics were not nearly as impressive, but rathermuch more reasonable. Clearly, operation of the plant during periods of $250/MWh, $500/MWh,or $1000/MWh will greatly improve the already favorable project economics. To maintain aconservative evaluation, moderate to low electricity prices were utilized.

Table 3-3Electricity Prices for Phoenix Site

Electricity Pricing - Target, current, estimate, or other basis.Specify expected electricity pricing.




Export $30.00 $30.00 $35.00Host n/a



3-5

With natural gas prices increasing sharply over the past twelve to eighteen months, plantprofitability has likewise decreased. This is reflected in models which continue to predict a highpriced gas market. Two methods, however, can reduce the impact of such a market: [1] Use of aless conservative gas pricing model, wherein pricing is predicted to return to levels of$2.00/MBtu ($1.90/GJ) to $2.50/MBtu ($2.37/GJ); or [2] Use of more aggressive gas pricefutures purchasing, where better prices are secured through medium to long-term purchasecontracts. For the purposes of this analysis, moderate gas pricing, in the $3.00/MBtu ($2.84/GJ)to $4.50/MBtu ($4.27/GJ) range was utilized.

Table 3-4Gas Prices for Phoenix Site

Fuel Costs - Base Year - Natural Gas or Fuel OilSpecify expected fuel pricing.Fuel Type Natural Gas Basis: Energy Information Administration

$/MBtu ($/GJ) Natural Gas Monthly, June 2000Winter Spring/

FallSummer Prices of Nat Gas to Electric Utilities.

Peak 4.50(4.27)

4.00(3.79)

4.00(3.79)

Same prices used for Phoenix as forChicago.

Average 3.25 (3.08)

3.25(3.08)

3.25(3.08)

Low 3.00(2.84)

2.75(2.61)

3.25(3.08)

For the purposes of this evaluation, only single fueled combustion turbines were used. Dual-fuelcombustion turbine technology is certainly mature, and very reasonable in areas where potentialgas curtailment exists. However, this evaluation just focused on utilization of a single fuel,natural gas.

Inlet Air Cooling Technologies Evaluated

For this evaluation, the following inlet air cooling technologies were evaluated:

• Media-Type Evaporative Cooling: The most common form of inlet air cooling where ahoneycomb-like cellulose fiber material (the medium) is installed across the inlet and wetted.As the air is pulled through, the water evaporates to cool the inlet air. Cooling is limited tothe wet bulb temperature, and is normally only able to recover approximately 85% of thiscooling (85% effectiveness). The equipment is relatively inexpensive, but a substantial ductenlargement is necessary for the required low air velocities. The evaporative cooler addsmoderately to inlet air pressure drop resulting in a decrease in combustion turbineperformance. Therefore, cooler weather plant performance is poorer because of this pressureloss and evaluations must include this decrease to properly evaluate benefits.

• High Pressure Inlet Fogging: A rapidly growing, and becoming more broadly acceptedtechnology. Inlet air is cooled by a very fine water spray using a series of very small nozzles.Demineralized water is pumped to these nozzles at a pressure of 1000 to 3000 psig(6890 to 20680 kPag). Effectiveness is rated at 100% (all available water is evaporated intothe air, thus reaching wet bulb temperature). Inlet air pressure drop is very low. The sprays



3-6

are normally placed downstream of the inlet air filters. This system is very inexpensive, andrequires low operating power.

• Steam Absorption Chilling: Steam absorption chilling is capable of achieving the largesttemperature drops because cooling is not limited to the humidity in the air. Chilling isaccomplished by steam-driven compressors operating similar to standard refrigeration cycles.The drawbacks are high capital cost, and higher operating and maintenance costs. Low inlettemperature is the main advantage of this system.

In addition to the above technologies, a base-model plant was simulated to provide benchmarkvalues for both non-optimized technical performance and base-level economic performance.

Definition of Cases for Evaluation

Based on the operating conditions governing the plant, a total of six cases were developedwherein the entire year’s operation could best be represented. The six cases are profiled in thetable below:



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Table 3-5Operating Cases for Phoenix Case Study

Case Configuration DescriptionBased on above information, build Case Configurations for SOAPP-CT model input:

EVAPORATIVE COOLING Units Case NumbersPHOENIX 1 2 3 4 5 6Case Name Moderate

AverageHotWarm

PeakCold

AverageModerate

PeakCold Peak HotWarm

AverageOperating Hours hrs/yr 1,816 1,758 908 1,116 537 335Pct of Total Op Hrs. % 28.1% 27.2% 14.0% 17.2% 8.3% 5.2%Perf Pt Dry Bulb F (C) 64.0 (17.8) 93.5 (34.2) 48.3 (9.1) 88.9 (31.6) 67.0 (19.4) 74.4 (23.6)Perf Pt Wet Bulb F (C) 50.0 (10) 68.0 (20) 41.0 (5) 66.0 (18.9) 52.0 (11.1) 57.0 (13.9)CTs 1 1 1 1 1 1CT Make/Model GE 7FA GE 7FA GE 7FA GE 7FA GE 7FA GE 7FADuct Firing Y/N no no no no no noIAC Operation Y/N yes yes no yes yes yesIAC Type Evap Cool Evap Cool Evap Cool Evap Cool Evap Cool Evap CoolExport Stm. Y/N no no no no no noAux. Boiler? Y/N no no no no no noCT Inlet Pres Drop (w/IAC) in H2O

(kPa)5.0 (1.24) 5.0 (1.24) 5.0 (1.24) 5.0 (1.24) 5.0 (1.24) 5.0 (1.24)

CT Inlet Pres Drop (w/o) in H2O(kPa)

3.75 (0.93) 3.75 (0.93) 3.75 (0.93) 3.75 (0.93) 3.75 (0.93) 3.75 (0.93)

CT Exh Pres Drop in H2O(kPa)

14.0 (3.47) 14.0 (3.47) 14.0 (3.47) 14.0 (3.47) 14.0 (3.47) 14.0 (3.47)

ST Eff: LP % 91% 91% 91% 91% 91% 91%ST Eff: IP % 89% 89% 89% 89% 89% 89%ST Eff: HP % 87% 87% 87% 87% 87% 87%Equip Avail Factor % 95.0% 95.0% 95.0% 95.0% 95.0% 95.0%Service Factor % 57.0% 95.0% 57.0% 95.0% 95.0% 94.9%Capacity Factor % 57.0% 95.0% 57.0% 95.0% 95.0% 94.9%

Max Amb Dry Bulb F (C) 120 (48.9) 120 (48.9) 120 (48.9) 120 (48.9) 120 (48.9) 120 (48.9)Max Amb Wet Bulb F (C) 72 (22.2) 72 (22.2) 72 (22.2) 72 (22.2) 72 (22.2) 72 (22.2)Min Amb Dry Bulb F (C) 20 (-6.7) 20 (-6.7) 20 (-6.7) 20 (-6.7) 20 (-6.7) 20 (-6.7)Elev ft (m) 1117 (340) 1117 (340) 1117 (340) 1117 (340) 1117 (340) 1117 (340)

Case 1 2 3 4 5 6Capacity Payments $/MW-yr 0 0 0 0 0 0Energy Payments $/MWh 35.00 70.00 40.00 60.00 50.00 45.00

Energy Pmt Escal %/yr 2.00 2.00 2.00 2.00 2.00 2.00


3.25 (3.08) 4.00 (3.79) 3.25 (3.08) 4.00 (3.79) 4.50 (4.27) 3.25 (3.08)

Nat Gas Price Escal %/yr 3.50 3.50 3.50 3.50 3.50 3.50

Case Analysis and Data Reduction

The six cases above, along with their non-inlet cooled counterparts were analyzed usingSOAPP-CT WorkStation.

In order to preserve the greatest level of continuity between cases, specific care was taken tomaintain HRSG surface areas, condenser sizing, and other plant parameters. The net result wasthe production of six cases for each technology, with nearly identical equipment designed oneach one.

The data from each of the six cases was combined using Weighted Averaging in order to producethe Equivalent Annual case for each.



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Results

Tables of Results

The results from the study are depicted in the following Summary Table:

Table 3-6Summary: Inlet Air Cooling Study – Phoenix Area

Overall Summary PHOENIX BASIS: SOAPP EQUIVALENT ANNUAL CASETechnology Utilized Evaporative

CoolingHigh PressureInlet Fogging

SteamAbsorption

Chilling

No Inlet Cooling

Technical Data

Number of CT’s Operating N/A 1 1 1 1Gross CT Generator Output per CT kW 162,017 163,456 163,584 152,784Net Plant Heat Rate (HHV) at 100% Btu/kWh 7,038 7,046 7,082 7,038Net Plant Heat Rate (HHV) at 100% kJ/kWh 7,426 7,435 7,472 7,426Net Plant Heat Rate (LHV) at 100% Btu/kWh 6,340 6,347 6,380 6,341Net Plant Heat Rate (LHV) at 100% kJ/kWh 6,690 6,697 6,731 6,691Stack Exhaust Temperature F 207 208 209 206Stack Exhaust Temperature C 97 98 98 97Gross ST Output kW 85,471 85,467 84,017 83,430Throttle Steam Flow at ST lb/hr 408,061 408,298 410,320 403,832Throttle Steam Flow at ST kg/hr 185,095 185,203 186,120 183,177Turbine Backpressure in Hg 3.59 3.70 3.68 3.83Turbine Backpressure kPa 12.15 12.53 12.46 12.97Gross Plant Output kW 247,488 248,923 247,601 236,214Auxiliary Power kW 4,506 4,524 4,390 4,235Net Plant Output kW 242,982 244,400 243,212 231,979Weighted Capacity Factor % 73.9% 73.9% 73.9% 73.9%Total Energy Produced MW-hr 1,557,248 1,566,335 1,558,709 1,486,734Total Fuel Consumed MBtu 10,959,911 11,036,396 11,038,255 10,463,634Total Fuel Consumed GJ 11,563,364 11,644,060 11,646,021 11,039,762Financial Data

Total Process Capital $ 102,587,000 102,622,000 102,736,000 100,131,000General Facilities $ 2,051,740 2,052,440 2,112,680 2,002,620Engineering and Home Office Fees $ 3,077,610 3,078,660 3,169,020 3,003,930Project Contingency $ 5,129,350 5,131,100 5,281,700 5,006,550Total Plant Cost $ 112,845,700 112,884,200 113,299,400 110,144,100Total Plant Cost per net kW $/kW 464.42 461.88 465.85 474.80Total Fixed O&M $ 1,985,397 1,985,584 1,985,430 1,979,883Total Variable O&M $ 2,395,673 2,411,476 2,324,901 2,292,281Total Fixed and Variable O&M $ 4,381,070 4,397,060 4,310,331 4,272,164Fuel Cost $ 42,490,232 42,785,732 42,795,784 40,570,040Internal Rate of Return (IRR) % 35.21 35.47 33.99 33.37

Also of interest is the incremental impact that each technology brings. The following tabledisplays this in three key parameters: process capital, cash flow to equity (base year only), andoverall internal rate of return.



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Table 3-7Incremental Impact: Inlet Air Cooling Study – Phoenix Area

Incremental Impact PHOENIX BASIS: SOAPP EQUIVALENT ANNUAL CASETechnology Utilized Evaporative

CoolingHigh

Pressure InletFogging

SteamAbsorption

Chilling

No Inlet Cooling

Incremental Process Capital

Total Process Capital $ 102,587,000 102,622,000 102,736,000 100,131,000Incremental Process Capital $ 2,456,000 2,491,000 2,605,000 0Percent Increase in Process Capital % 2.45% 2.49% 2.60% 0.00%Incremental Cash Flow to Equity

Base Year Cash Flow to Equity $ 10,862,607 10,935,230 10,664,286 10,170,401Incremental Cash Flow to Equity $ 692,206 764,829 493,885 0Percent Increase in Cash Flow to Equity % 6.81% 7.52% 4.86% 0.00%Incremental Internal Rate of Return

Internal Rate of Return % 35.21 35.47 33.99 33.37Incremental Internal Rate of Return % 1.84 2.10 0.62 0.00Percent Increase in Int. Rate of Return % 5.51% 6.29% 1.86% 0.00%

Implication of Results

As expected, the base design does indeed result in the case with the lowest Internal Rate ofReturn (IRR). The base design had an IRR of 33.37%, with a total plant cost of $474.80 per netkW. The relatively high IRR is due to the selected electricity pricing and associated operatinghours, which are valid currently. How long this high electricity price market will continue isunknown. This method and the WorkStation provide the capability for additional analyses atlower future electricity prices.

Of the three technologies, we see that the best overall IRR goes to Inlet Fogging, at 35.47%. Thiswas only narrowly better than the 35.21% IRR recorded by the standard Evaporative Coolingplant. One might expect that the IRR of a Fogging-enhanced plant to be significantly better thanevaporative cooling. The reason for the narrow margin is, in fact, more subtle than imagined:The fact that the Fogging-enhanced plant can produce a more powerful combustion turbinemeans that more exhaust is produced, hence more steam is produced. In order to accommodatethe larger flow of steam, a larger HRSG and larger steam turbine is needed. Additionally, alarger water treatment facility is needed in order to process the larger amount of water that willbe necessary to evaporate in the remaining 15% effectiveness domain. In short, the capital savedby using inlet fogging was absorbed by the larger plant required. However, the larger plant wasmore efficient on a $/kW basis, and the larger IRR resulted. Comparing evaporative and sprayinlet cooling on an operational basis, CT manufacturers and operators are concerned that afogging system could result in a decline in CT durability and damage due to overspray.

From the incremental impact table, the incremental cash flow to equity for the inlet fogging case,for the base year, is $760,000. This represents a most significant gain as compared to the basedesign. By spending an additional 2.5% of process capital, a gain of 7.5% in cash flow to equityis realized. This is an efficient use of incremental capital.



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In review of the Inlet Chilling results, they were, as expected, better than the base design, but notnearly as economic as either of the two evaporative cooling designs. The greater initial capitalcost of the Inlet Chilled plant was the primary factor for the marginal IRR improvement.

However, this brings up the noteworthy point that much of the aforementioned study ispredicated on several key parameters, which could vary quite considerably, such as:

• Combustion Turbine Performance (i.e., how much output is lost at higher ambienttemperatures)

• Raw Water Costs

• Operation and Maintenance Costs

• Water Treatment Costs

• Electricity Pricing

• Gas Pricing

• Seasonal Anomalies (such as an exceedingly hot summer)

If the cost of raw water were to be 25 to 30% higher, there is a greater likelihood that inletchilling might be the best choice. This is a factor that must be thoroughly evaluated prior tocommitting to one technology over another.

As stated in Chapter 2, notice must be given to the significance of the differences in IRR thatresult from each analysis. Review of the preceding inlet air cooling study shows that the resultsactually fall into just two categories, separated by approximately two (2) IRR percentage points.Steam absorption chilling and the base design comprise the first category, while evaporativecooling and inlet fogging comprise the other. The significant gain is realized with the two pointgain in IRR; not in the 0.2 to 0.7 point gain within each category.

Chapter Conclusion

The study of Inlet Air Cooling at a site such as Phoenix demonstrated many important factorsone is forced to confront in developing a plan for Combined Cycle Optimization. Factors such asgas pricing, climate conditions, site water costs, and major equipment costs might be ones ofwhich there is not much control. Factors such as electricity pricing can vary widely, even overthe course of just one day. The technologies themselves are under a state of development, andhave varying levels of industry acceptance and availability.

The methodology of developing individual cases, based on known operating periods orconditions, then combining the results to develop a single Equivalent Annual case is one whichhas great merit. Using this technique, along with reliable industry software such as SOAPP-CT,empower the project developer to confidently assess project parameters and establish appropriatelevels of sensitivity to the unknowns. What could only be intuitively predicted (without technicalsubstantiation) or laboriously calculated (at great expense of time and resources) in previoustimes can now be completed with both accuracy and speed. In today’s rapidly changing powermarket, such attributes are critical.


4-1

4 DUCT FIRING – CHICAGO AREA

Introduction

As the drive to design and build combined cycle power plants with greater and greaterefficiencies continues, the need to capture every available energy stream becomes increasinglynecessary. Further, today’s systems need to be able to operate under a wider array of conditions,and to function well throughout the operating range. Although optimization of the HRSG andcooling of the combustion inlet air are both valuable methods of improving performance andeconomic efficiency, the concept of supplementary duct firing provides a flexible yet powerfulmeans of accomplishing many of the plant’s goals – all without adding much additionalequipment to the plant scope of supply.

Combustion turbine exhaust contains a substantial amount of residual heat which has beenwell-captured thermally by the integration of back-end waste heat recovery systems. However,in this exhaust stream there also exists a significant quantity of unused oxygen, which can befurther combusted to produce higher temperature exhaust for steam generation, and ultimatelyelectrical power generation.

The challenge in designing duct fired systems effectively is to create a heat recovery systemwhich can function quite efficiently at 1100ºF (593ºC) up to 1500ºF (816ºC) or 1600ºF (870ºC),while producing steam at three distinct pressure levels. Economically, the challenge is to create asystem which will bring greater financial returns than one with a simpler, unfired heat recoverysystem. Practically speaking, an even greater challenge is to accurately simulate the above withina model which accommodates variation in climate, energy prices, fuel prices, and varying plantoperation philosophies with a reasonable and trustworthy degree of accuracy. It is the goal of thischapter to demonstrate how such a task can be accomplished, using a methodology, which iswell adapted to such a diverse application.

Duct Firing Design

Typically, the exhaust from a combustion turbine has a temperature of 1000ºF (593ºC) to 1200ºF(649ºC), and can have from 9-11% available oxygen still remaining which could be potentiallyignited to further boost the exhaust temperature. Once the hot exhaust leaves the combustionturbine, it is routed through ducting, which can include straightening vanes, then past a burnerplaced within the flow path. Duct burners can be designed to fire a variety of fuels, althoughnatural gas and No. 2 fuel oil are the two most prevalent. Fuel compatibility with the SCR, ifused, is important. The fuel is ignited and regulated according to a specific parameter, most oftenexhaust temperature. Finally, the now-heated exhaust is routed through the HRSG,


Duct Firing – Chicago Area

4-2

past the sections of superheaters, evaporators, and economizers to create steam. The cooledexhaust is normally released into the atmosphere at temperatures of 185ºF (85ºC) to 225ºF(107ºC) when firing natural gas (exhaust temperatures are greater when firing distillate fuels).

The results of such a simple enhancement can be quite large. For one of the design caseswithin the subject evaluation, the unfired exhaust, at 1117ºF (603ºC) and 3,516,000 lb/hr(1,595,000 kg/hr) flow, was able to generate 414,000 lb/hr (188,000 kg/hr) of 1800 psia(12,411 kPaa) steam. That same exhaust flow, when duct fired to 1510ºF (821ºC), was able toproduce 676,000 lb/hr (307,000 kg/hr) of 1800 psia (12,411 kPaa) steam, an increase of 63%.This resulting improvement increased gross steam turbine output by 49.5 MW. Withoutsupplemental duct firing, this additional electrical generation would not have been captured.However, non-duct firing plant efficiency decreases because of exit gas temperature increase.Therefore, the financial benefits during operation with duct firing need to overcome the financialloss during non-duct firing operation.

One of the primary challenges in this study was to create multiple cases, based on the operatingphilosophy of the plant such that the design and size of the HRSG remained consistent from caseto case. This was done within SOAPP-CT by controlling pinch point temperatures and approachtemperatures to reflect performance as actually observed in the field.

Evaluation Overview

Similar to how the inlet air cooled evaluation was performed in the preceding section, the ductfiring evaluation was conducted in much the same way. Representative cases were created todepict the varying operating scenarios the plant would experience, then the results from thesecases were combined to establish a single composite case which we have been calling theEquivalent Annual case. The result from the Equivalent Annual case is stated in a later section ofthis chapter.

As performed previously, the analysis was performed using the SOAPP-CT software program,and results compiled in a customized spreadsheet.

Case Description

Site

Chicago, Illinois, was chosen as the site for the plant due to its moderate, yet seasonal climate.Chicago is also located at an altitude which would be similar to many other potential sites. Withthe cold winters and hot summers, a climate such as Chicago’s would provide many interestingmethods of evaluation for an application such as duct firing. Finally, with Chicago being locatedin a developed area, the availability of water would allow for such standard designs asmechanical draft cooling towers, which were not utilized in the Phoenix analysis.



4-3

Table 4-1Chicago Weather

AvgTempRange(°F)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Twb Hours

95-99 0 0 0 0 0 1 1 2 2 0 0 0 76 690-94 0 0 0 0 2 15 13 19 9 0 0 0 74 5885-89 0 0 0 1 11 41 54 38 18 2 0 0 72 16580-84 0 0 0 5 28 68 100 79 32 12 0 0 70 32475-79 0 0 0 12 50 92 129 126 58 19 1 0 67 48770-74 0 0 2 27 68 122 163 162 96 37 4 0 64 68165-69 0 0 4 36 88 123 152 151 128 66 11 0 61 75960-64 0 1 8 55 94 108 86 96 136 91 24 1 57 70055-59 2 4 17 61 110 75 30 46 102 110 42 5 52 60450-54 4 7 27 90 114 52 10 19 72 117 56 13 47 58145-49 10 14 46 110 96 19 1 5 40 115 89 20 43 56540-44 22 32 81 130 55 4 0 1 20 78 106 43 38 57235-39 77 90 149 108 24 0 0 0 7 54 118 98 34 72530-34 155 171 191 60 3 0 0 0 1 29 109 150 30 86925-29 122 128 101 20 0 0 0 0 0 9 82 127 25 58920-24 93 79 62 5 0 0 0 0 0 2 41 89 21 37115-19 71 52 30 1 0 0 0 0 0 0 20 57 16 23110-14 56 33 14 0 0 0 0 0 0 0 11 50 11 1645-9 51 22 4 0 0 0 0 0 0 0 5 33 6 1150-4 80 39 3 0 0 0 0 0 0 0 4 56 1 182

TotalHours

743 672 739 721 743 720 739 744 721 741 723 742 8760

Note: Hours may not precisely add to 8,760 due to rounding approximations.

Plant Operation Philosophy

Just as was done for the Phoenix plant, the operation philosophy for the subject plant was chosento be cycling: operating only about 60% of the available hours of the year. During the hottestmonths (when electricity prices would be most likely to spike upward), the plant would beoperated full-time. During the coldest months, the plant would only be operated part-time, or notat all. The spreadsheet tool developed for this analysis gave the user the ability to declare thedesired operating plan for the plant under such varying conditions.



4-4

Table 4-2Operation Philosophy of Cycling Plant

Operation PhilosophySpecify expected operation of plant during eachcondition.

Cycling Plant

Elect. Price OperationWinter Spring/Fall Summer Note: Full = 100% of plant availability

Peak Full Full Full Part = 30-60% of plant availabilityAverage Part Time Part Time Full Shutdown = 0% of plant availability

Low Shutdown Shutdown Part Time

Unit Sizing

Mostly for consistency, and for the ability to directly compare the cost and economics of casesacross installation sites, a sizing of 225 to 250 MW was also chosen for this case. Thecombustion turbine utilized was a single (1) GE PG7241FA single-fuel engine in a 1x1x1configuration with a HRSG and steam turbine. As stated before, alternate configurations wereconsidered, but left for future studies.

Electricity and Gas Pricing

Electricity and gas pricing for the Chicago plant were set identically to those established for thePhoenix plant. This is not meant as a means of overlooking very real differences between theareas. Instead, since it was discovered that electricity prices and gas prices do have such asensitivity to the final outcome, it was decided that the best method of establishing consistencywould be to just set them identically.

Table 4-3Electricity Prices for Chicago Area

Electricity Pricing - Target, current, estimate, or other basis.Specify expected electricity pricing.




Export $30.00 $30.00 $35.00Host n/a



4-5

Table 4-4Gas Prices for Chicago Area

Fuel Costs - Base Year - Natural Gas or Fuel OilSpecify expected fuel pricing.Fuel Type Natural Gas Basis: Energy Information Administration

$/MBtu ($/GJ) Natural Gas Monthly, June 2000Winter Spring/Fall Summer Prices of Nat Gas to Electric Utilities.

Peak 4.50(4.27)

4.00(3.79)

4.00(3.79)

Same prices used for Phoenix as forChicago.

Average 3.25(3.08)

3.25(3.08)

3.25(3.08)

Low 3.00(2.84)

2.75(2.61)

3.25(3.08)

Evaluation of the cases for the Chicago site showed that if electricity prices were permitted toreach summer peaks in the $500/MWh range, as they did during the summer of 1999, the overallIRR for the project would be moved well into the 100+% range. Although this is clearly afavorable outcome, it is often viewed with suspicion. Therefore, the analysis contained withinthis study merely utilizes a peak electricity price of $70/MWh. It should also be noted that theanalysis did not add in revenue for capacity charges (i.e. $/MW). All revenue for the subjectplant designs is derived entirely from energy consumption charges (i.e. $/MWh).

The only fuel utilized in the Chicago case study was natural gas. This was utilized for both thecombustion turbine as well as for the duct burner. Dual fuel technology exists, and could alsohave been applied with this methodology if desired.

Definition of Cases for Evaluation

Based on the operating conditions governing the plant, a total of four cases were developedwherein the entire year’s operation could best be operated. This is less than the six used in thePhoenix analysis, but demonstrates that the optimal number of cases need not be entirely static,especially if it is believed that the seasonal operation of the plant can indeed be clearlyrepresented in a fewer number of cases. The four cases are profiled in the table below:



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Table 4-5Operating Cases for Chicago Case Study

Case Configuration DescriptionBased on above information, build Case Configurations for SOAPP-CT model input:DUCT FIRING Units Case NumbersCHICAGO 1 2 3 4Case Name Moderate

AverageHotWarmAverage

Cold Average HotWarm Peak

Operating Hours hrs/yr 1,958 1,435 1,228 525Pct of Total Op Hrs % 38.0% 27.9% 23.9% 10.2%Perf Pt Dry Bulb F (C) 50.1 (10.1) 71.4 (21.9) 26.0 (-3.4) 90.0 (32.2)Perf Pt Wet Bulb F (C) 47.0 (8.3) 62.0 (16.7) 25.0 (-3.9) 74.0 (23.3)CTs 1 1 1 1CT Make/Model GE 7FA GE 7FA GE 7FA GE 7FADuct Firing Y/N yes yes yes YesDuct FiringTemperature

F (C) 1510 (821) 1515 (824) 1497 (814) 1522 (828)

IAC Operation Y/N no no no NoIAC Type none none none NoneExport Stm. Y/N no no no NoAux. Boiler? Y/N no no no No

CT Exh Pres Drop(w/DF)

in H2O(kPa)

15.5 (3.84) 15.5 (3.84) 15.5 (3.84) 15.5 (3.84)

CT Exh Pres Drop (w/oDF)

in H2O(kPa)

14.0 (3.47) 14.0 (3.47) 14.0 (3.47) 14.0 (3.47)

ST Eff: LP % 91% 91% 91% 91%ST Eff: IP % 89% 89% 89% 89%ST Eff: HP % 87% 87% 87% 87%

Equip Avail Factor % 95.0% 95.0% 95.0% 95.0%Service Factor % 60.1% 95.0% 57.0% 94.9%Capacity Factor % 60.1% 95.0% 57.0% 94.9%

Max Amb Dry Bulb F (C) 100 (37.8) 100 (37.8) 100 (37.8) 100 (37.8)Max Amb Wet Bulb F (C) 76 (24.4) 76 (24.4) 76 (24.4) 76 (24.4)Min Amb Dry Bulb F (C) -20 (28.9) -20 (28.9) -20 (28.9) -20 (28.9)

Elev ft (m) 610 (186) 610 (186) 610 (186) 610 (186)

Case 1 2 3 4x 4yCapacity Payments $/MW-yr 0 0 0 0 0Energy Payments $/MWh 35.00 45.00 40.00 60.00 70.00

67.79Energy Pmt Escal %/yr 3.00 3.00 3.00 3.00


3.25 (3.08) 3.25 (3.08) 3.25 (3.08) 4.00 (3.79) 4.00 (3.79)

Nat Gas Price Escal %/yr 3.50 3.50 3.50 3.50

Case Analysis and Data Reduction

The four cases, along with their non-duct fired counterparts were each run through SOAPP-CT.Due to the inherent sensitivities with duct firing and process simulation programs, the designneeded to be converged through careful manipulation of firing temperature, pinch pointtemperatures, approach temperatures, and steam operating pressures. The results ultimatelyprove that all surface areas were brought to within a reasonable range from each other.



4-7

The data from each of the four cases was combined using Weighted Averaging in order toproduce the Equivalent Annual case for each. The final results as shown in the following sectionrepresent the convergence and compilation of many design runs.

Results

Tables of Results

The results from the study are depicted in the following Summary Table:

Table 4-6Summary: Duct Firing Study - Chicago Area

Overall Summary CHICAGO BASIS: SOAPP EQUIVALENT ANNUAL CASETechnology Utilized WITH Duct Firing WITHOUT Duct Firing

Technical Data

Number of CT’s Operating N/A 1 1Gross CT Generator Output per CT kW 167,086 167,442Net Plant Heat Rate (HHV) at 100% Btu/kWh 7,199 6,924Net Plant Heat Rate (HHV) at 100% kJ/kWh 7,596 7,306Net Plant Heat Rate (LHV) at 100% Btu/kWh 6,486 6,238Net Plant Heat Rate (LHV) at 100% kJ/kWh 6,844 6,582Stack Exhaust Temperature F 202 198Stack Exhaust Temperature C 94 92Gross ST Output kW 139,774 91,237Throttle Steam Flow at ST lb/hr 670,557 414,513Throttle Steam Flow at ST kg/hr 304,163 188,022Turbine Backpressure in Hg 2.23 2.24Turbine Backpressure kPa 7.55 7.58Gross Plant Output kW 306,859 258,679Auxiliary Power kW 6,071 4,484Net Plant Output kW 300,788 254,195Weighted Capacity Factor % 58.8% 58.8%Total Energy Produced MW-hr 1,533,831 1,296,234Total Fuel Consumed MBtu 11,042,049 8,975,124Total Fuel Consumed GJ 11,650,025 9,469,295Financial Data

Total Process Capital $ 107,890,000 99,332,000General Facilities $ 2,157,800 1,986,640Engineering and Home Office Fees $ 3,236,700 2,979,960Project Contingency $ 5,394,500 4,966,600Total Plant Cost $ 118,679,000 109,265,200Total Plant Cost per net kW $/kW 394.56 429.85Total Fixed O&M $ 1,647,130 1,620,778Total Variable O&M $ 2,148,360 2,006,806Total Fixed and Variable O&M $ 3,795,490 3,627,584Fuel Cost $ 38,635,220 31,402,898Internal Rate of Return (IRR) % 14.58 13.88



4-8

Table 4-7Incremental Impact: Duct Firing Study - Chicago Area

Incremental Impact CHICAGO BASIS: SOAPP EQUIVALENT ANNUAL CASETechnology Utilized WITH Duct Firing WITHOUT Duct Firing

Incremental Process Capital

Total Process Capital $ 107,890,000 99,332,000Incremental Process Capital $ 8,558,000 0Percent Increase in Process Capital % 8.62% 0.00%Incremental Cash Flow to Equity

Base Year Cash Flow to Equity $ 4,327,585 3,721,709Incremental Cash Flow to Equity $ 605,876 0Percent Increase in Cash Flow toEquity

% 16.28% 0.00%

Incremental Internal Rate of Return

Internal Rate of Return % 14.58% 13.88%Incremental Internal Rate of Return % 0.70% 0.00%Percent Increase in Int. Rate ofReturn

% 5.04% 0.00%

Implication of Results

The results from the preceding tables offer several answers to the viability of duct firing in anapplication such as the cycling plant at hand. First and foremost, the project IRR improves from13.88% in the non-duct fired design, to 14.58% in the duct fired design. This is a moderateimprovement, but upon looking closer, one can clearly see that much had to be done in order toaccomplish this improvement. Most notably, total plant cost had to be increased by over$9 million, from $109.3 million to $118.7 million. This, being a major capital increase, may noteasily be accepted by project funding agencies. For perspective, the inlet cooling cases onlyincreased total plant cost by $2-3 million – a much more reasonable capital increase, with largerfinancial benefits.

However, contributing to the logic in favor of implementing duct firing is the fact that the“per-kW” cost actually decreases below the $400 mark, from $430 per net kW to$395 per net kW. For a financial institution looking for attractive generation costs, the$395 figure represents a substantial gain.

There are other factors which may contribute to the ultimate decision of whether to duct firewhich have not been discussed. One significant factor is that of emissions. By firing natural gas,the risk is run that NOx and CO emissions may exceed governmental limits. Duct burnermanufacturers are being increasingly forced to commit to emission limits within certainoperating ranges. This will be an added concern when firing at temperatures in the1500ºF (816ºC) range.

With regard to plant efficiency, the act of supplemental duct firing actually increases Net PlantHeat Rate (reducing efficiency). This is because duct firing behaves more like an auxiliary boiler



4-9

than an additional combustion turbine. The benefit of implementing duct firing is derived fromthe fact that the HRSG and supporting equipment is already in place, and the only primarychange is increase in size.

The above results were obtained from gas prices in the $3.00 to $4.50 per MBtu ($2.84 to$4.27 per GJ) range. If gas prices return to $1.50 to $2.00 per MBtu ($1.42 to $1.90 per GJ)range, the project economics can improve dramatically. Likewise, increased electricity pricing,especially during the peak summer hours, will improve returns with similar effect.

In contrast to the two point IRR gain shown in Chapter 3 for inlet air cooling, the 0.7 point IRRgain here seems much less significant. However, with rates of return in Chicago being, ingeneral, much less than Phoenix, a 0.7 point gain represents a full 5% improvement in return.Smaller incremental changes in IRR have greater significance when overall rates of return areless from the outset. For this study, an improvement of 0.7 points should be considered asignificant gain.

The incremental impact table shows that the percent increase in process capital is 8.6%, a muchlarger initial cost than any of the inlet cooling technologies discussed in Chapter 3. However, theincrease in cash flow to equity is $606,000 for the initial year, representing a 16.3% increaseover the base design. The cost benefit ratio is less than that realized in the inlet cooling analysis,but still does represent a significant gain to the project. It is imperative that, for capital increaseson this order of magnitude, that the incremental benefit also be clearly stated.

Chapter Conclusion

As in the Inlet Air Cooling study, the Duct Firing study demonstrated that compiling theoperation of a complex set of parameters into a single composite form such as the EquivalentAnnual Case has great promise. The combined effect of a plant running in cycling mode over thecourse of a widely varying climate can be extremely burdensome to quantify. This study haspermitted these factors to become consolidated into a single table, resolving down to simple,easy to understand parameters.

When a plant optimization technology such as duct firing is entertained for a prospective project,some may be deterred by the increased capital cost, and choose to not even investigate itspotential solely due to the large price tag. Alternately, some may also believe that duct firing isalways a sound economic choice, and will include it into every project design being proposed.The significant result of the evaluation performed within this chapter is that it IS possible toconfidently and accurately model technologies such as duct firing into complex applications. Thedeveloper need not rely on intuition or oversimplification. Instead, careful analysis with theproper tools can ultimately reveal the best project plan possible.


A-1

A APPENDIX A – SI - ENGLISH UNIT COMPARISON

Throughout this report units have been reported in both English and Systeme Internationale (SI)units. The following table is provided for assistance in converting between units:

Table A-1Unit Conversions

To Convert From To Multiply By

Btu KJ 1.05506

MBtu GJ 1.05506

Degrees F Degrees C (F-32)/1.8

Diff Degrees F Diff Degrees C 0.55556

$/MBtu $/GJ 0.9478

Btu/kWh kJ/kWh 1.055147

MBtu/hr MW 0.29307

lb/hr kg/hr 2.2046

psia kPa 6.8948

in H2O kPa 0.248

in Hg kPa 3.38565

foot meter 0.3048


B-1

B APPENDIX B – SUPPORTING DATA – INLET AIRCOOLING – PHOENIX AREA


Appendix B – Supporting Data – Inlet Air Cooling – Phoenix Area

B-2

Table B-1Inlet Air Cooling-Phoenix: SOAPP-CT Case Input Data

Site Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix

Technology Base Case Base Case Base Case Base Case Base Case Base Case Base CaseCase 1a Case 2a Case 3a Case 4a Case 5a Case 6a Equivalent-a

Variable Units Value Value Value Value Value Value ValueCT Model Number N/A GE 7FA GE 7FA GE 7FA GE 7FA GE 7FA GE 7FA GE 7FANumber of CT’s N/A 1 1 1 1 1 1 1Cycle Type N/A Combined Cycle

CogenerationCombined CycleCogeneration

Combined CycleCogeneration





Duty Cycle/Mission N/A Cycling Base Load Cycling Base Load Base Load Base Load Base LoadCT NOx Control, Natural Gas N/A Dry Low NOx

CombustorsDry Low NOxCombustors

Dry Low NOxCombustors





CT Natural Gas NOx Limit ppmvd @ 15% O2 9 9 9 9 9 9 9CEM's Included N/A Yes Yes Yes Yes Yes Yes YesInlet Air Filtration N/A Pulse Type Pulse Type Pulse Type Pulse Type Pulse Type Pulse Type Pulse TypeInlet Air Cooling N/A No Cooling No Cooling No Cooling No Cooling No Cooling No Cooling No CoolingInlet Air Cooler Status N/A Not in Use Not in Use Not in Use Not in Use Not in Use Not in Use In UseAir Cooling Discharge Temp F 64.0 93.5 48.3 88.9 67.0 74.4 74.9Air Cooling Discharge Temp C 17.8 34.2 9.0 31.6 19.4 23.6 23.8Evaporative Cooler Effectiveness %CT Pressure Loss Method N/A User-Specified User-Specified User-Specified User-Specified User-Specified User-Specified User-SpecifiedCT Inlet Pressure Loss in H2O 3.8 3.8 3.8 3.8 3.8 3.8 3.8CT Inlet Pressure Loss kPa 0.93 0.93 0.93 0.93 0.93 0.93 0.93CT Exhaust Pressure Loss in H2O 14.0 14.0 14.0 14.0 14.0 14.0 14.0CT Exhaust Pressure Loss kPa 3.47 3.47 3.47 3.47 3.47 3.47 3.47Heater Selection N/A Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate Heater Conden sate HeaterDeaerator Selection N/A Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral DeaeratorNumber of Pressure Levels N/A Three Pressure Three Pressure Three Pressure Three Pressure Three Pressure Three Pressure Three PressureHP Steam Pressure psia 1,800 1,800 1,800 1,800 1,800 1,800 1,800IP Steam Pressure psia 490 490 490 490 490 490 490LP Steam Pressure psia 58 60 58 61 58 58 58Hot Reheat Pressure psia 490 490 490 490 490 490HP Steam Temp F 1,000 1,002 995 1,000 1,000 1,000 1,002IP Steam Temp F 600 600 600 600 600 600 600LP Steam Temp F Use default Use default Use default Use default Use default Use default Use defaultHP Pinch Point F 15 15 15 15 15 15 15IP Pinch Point F 15 13 15 13 15 14 15LP Pinch Point F 10 10 10 10 10 10 10HP Evap Approach F 20 20 20 20 20 20 20IP Evap Approach F 20 18 20 18 18 18 20LP Evap Approach F 13 11 22 10 13 11 13HP Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411 12,411 12,411IP Steam Pressure kPa 3,378 3,378 3,378 3,378 3,378 3,378 3,378LP Steam Pressure kPa 400 414 400 421 400 400 400Hot Reheat Pressure kPa 3,378 3,378 3,378 3,378 3,378 3,378 0HP Steam Temp C 537.8 538.9 535.0 537.8 537.8 537.8 538.9IP Steam Temp C 315.6 315.6 315.6 315.6 315.6 315.6 315.6LP Steam Temp C Use default Use default Use default Use default Use default Use default Use defaultHP Pinch Point C 8.3 8.3 8.3 8.3 8.3 8.3 8.3IP Pinch Point C 8.3 7.2 8.3 7.2 8.3 7.8 8.3LP Pinch Point C 5.6 5.6 5.6 5.6 5.6 5.6 5.6HP Evap Approach C 11.1 11.1 11.1 11.1 11.1 11.1 11.1IP Evap Approach C 11.1 10.0 11.1 10.0 10.0 10.0 11.1LP Evap Approach C 7.2 6.1 12.2 5.6 7.2 6.1 7.2Export All Available Flow N/A no no no no no no noInclude Duct Burners N/A no no no no no no noDuct Burner Performance Calc Method N/ADuct Burner Firing Temperature FDuct Burner Firing Temperature CDuct Burner Use N/A



B-3

Table B-1Inlet Air Cooling-Phoenix: SOAPP-CT Case Input Data (Continued)



Variable Units Value Value Value Value Value Value ValueDuct Burner Fuel Capability N/ASCR Configuration N/A Anhydrous Ammonia

InjectionAnhydrous AmmoniaInjection

Anhydrous AmmoniaInjection





Include CO Oxidation Catalyst N/A No No No No No No NoSteam Turbine Arrangement N/A G-Reheat, 2 Casing, 1

Flow, Direct DriveG-Reheat, 2 Casing, 1Flow, Direct Drive

G-Reheat, 2 Casing, 1Flow, Direct Drive





ST Exhaust Configuration N/A Axial Axial Axial Axial Axial Axial AxialST Sizing Criteria N/A Excluding Max

Exports/ExtractionsExcluding MaxExports/Extractions

Excluding MaxExports/Extractions





Number of ST Extractions N/A 0 0 0 0 0 0 0ST Efficiency Method N/A User-Specified User-Specified User-Specified User-Specified User-Specified User-Specified User-SpecifiedHP ST Efficiency % 87% 87% 87% 87% 87% 87% 87%IP ST Efficiency % 89% 89% 89% 89% 89% 89% 89%LP ST Efficiency % 91% 91% 91% 91% 91% 91% 91%Include a Steam Bypass N/A Yes Yes Yes Yes Yes Yes YesCooling System Type N/A Air-Cooled Condenser Air-Cooled Condenser Air-Cooled Condenser Air-Cooled Condenser Air-Cooled Condenser Air-Cooled Condenser Air-Cooled CondenserCycles of Concentration N/A 0Condenser Pressure Calc Method N/A User-Specified User-Specified User-Specified User-Specified User-Specified User-Specified User-SpecifiedDesign Condenser Pressure in Hg 11.5 11.5 11.5 11.5 11.5 11.5 11.5Design Condenser Pressure kPa 38.93 38.93 38.93 38.93 38.93 38.93 38.93Condenser Tube Material N/A 304 SS 304 SS 304 SS 304 SS 304 SS 304 SS 304 SSCondenser Tube Cleaning N/A None None None None None None NoneCirc Water Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%Include an Auxiliary Boiler N/A no no no no no no noBoiler Feed Pump Sparing N/A 2- 100% 2- 100% 2- 100% 2- 100% 2- 100% 2- 100% 2- 100%Boiler Feed Pump Design N/A HP Pump with IP

TakeoffHP Pump with IPTakeoff

HP Pump with IPTakeoff





Condensate Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%HRSG Enclosures N/A No No No No No No NoPower Block Enclosure N/A Yes Yes Yes Yes Yes Yes YesWater Treatment Enclosure N/A Yes Yes Yes Yes Yes Yes YesWarehouse Included N/A No No No No No No NoInclude Fire Protection System? N/A Yes Yes Yes Yes Yes Yes YesFire Water Source N/A City/Well Water City/Well Water City/Well Water City/Well Water City/Well Water City/Well Water City/Well WaterSubstructure Requirements N/A Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles Steel PilesBypass Stack/Diverter Valve N/A No No No No No No NoMain Stack Height ft 150 150 150 150 150 150 150Main Stack Height m 45.7 45.7 45.7 45.7 45.7 45.7 45.7Switchyard Voltage kV 115 115 115 115 115 115 115Book Life years 20 20 20 20 20 20 20Tax Life years 15 15 15 15 15 15 15Commercial Operating Year N/A 2003 2003 2003 2003 2003 2003 2003Commercial Operating Month N/A January January January January January January JanuaryCapacity Factor % 57% 95% 57% 95% 95% 95% 74%Service Factor % 57% 95% 57% 95% 95% 95% 74%Equivalent Availability Factor % 95% 95% 95% 95% 95% 95% 95%Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5%Number of Starts Per Year N/A 40 40 40 40 40 40 40Tax Depreciation Method N/A MACRS MACRS MACRS MACRS MACRS MACRS MACRSCapital Cost Adders $ Adjust manually



B-4




Variable Units Value Value Value Value Value Value ValueSOAPP-CT Site Data Case 1a Case 2a Case 3a Case 4a Case 5a Case 6a Equivalent-aVariable Units Value Value Value Value Value Value ValueMax Ambient Dry Bulb Temp F 120 120 120 120 120 120 120Max Ambient Wet Bulb Temp F 72 72 72 72 72 72 72Min Ambient Dry Bulb Temp F 20 20 20 20 20 20 20Perf Point Dry Bulb Temp F 64.0 93.5 48.3 88.9 67.0 74.4 74.9Perf Point Wet Bulb Temp F 50.0 68.0 41.0 66.0 52.0 57.0 56.9Site Elevation ft 1117 1117 1117 1117 1117 1117 1117Ambient Air Quality N/A Clean Clean Clean Clean Clean Clean CleanMax Daily Rainfall in/day 3 3 3 3 3 3 3Average Annual Rainfall in/yr 7.5 7.5 7.5 7.5 7.5 7.5 7.5Max Cooling Water Temp F 80 80 80 80 80 80 80Perf Point Cooling Water Temp F 60 60 60 60 60 60 60Max Ambient Dry Bulb Temp C 48.9 48.9 48.9 48.9 48.9 48.9 48.9Max Ambient Wet Bulb Temp C 22.2 22.2 22.2 22.2 22.2 22.2 22.2Min Ambient Dry Bulb Temp C -6.7 -6.7 -6.7 -6.7 -6.7 -6.7 -6.7Perf Point Dry Bulb Temp C 17.8 34.2 9.0 31.6 19.4 23.6 23.8Perf Point Wet Bulb Temp C 10.0 20.0 5.0 18.9 11.1 13.9 13.8Site Elevation m 340.5 340.5 340.5 340.5 340.5 340.5 340.5Max Daily Rainfall cm/day 7.44 7.44 7.44 7.44 7.44 7.44 7.44Average Annual Rainfall cm/yr 18.6 18.6 18.6 18.6 18.6 18.6 18.6Max Cooling Water Temp C 26.7 26.7 26.7 26.7 26.7 26.7 26.7Perf Point Cooling Water Temp C 15.6 15.6 15.6 15.6 15.6 15.6 15.6Heat Rejection Water Source N/A River River River River River River RiverUnit Makeup Water Source N/A Well Water Well Water Well Water Well Water Well Water Well Water Well WaterMakeup Raw Water Consump Charge $US/1,000 gal 3.00 3.00 3.00 3.00 3.00 3.00 Adjust manuallyMakeup Raw Water Consump Charge $US/ m3 0.79 0.79 0.79 0.79 0.79 0.79 Adjust manuallyCirculating Water Thermal Charge $US/MBtu 0.06 0.06 0.06 0.06 0.06 0.06 0.06Circulating Water Thermal Charge $US/GJ 0.057 0.057 0.057 0.057 0.057 0.057 0.057UBC Seismic Zone N/A Zone 0 Zone 0 Zone 0 Zone 0 Zone 0 Zone 0 Zone 0Stack Natural Gas NOx Limit ppmvd @ 15% O2 5 5 5 5 5 5 5Ammonia Emission Limit ppmvd @ 15% O2 5 5 5 5 5 5 5Construction Labor Index Value N/A 1 1 1 1 1 1 1Productivity Multiplier N/A 1 1 1 1 1 1 1General Facilities Capital % 2 2 2 2 2 2 2Eng. & Home Office Fees % 3 3 3 3 3 3 3Project Contingency % 5 5 5 5 5 5 5Process Contingency % 0 0 0 0 0 0 0Land Cost $US/acre 10,000 10,000 10,000 10,000 10,000 10,000 10,000Ammonia (Delivered) $US/ton 180 180 180 180 180 180 180NaOH (Delivered) $US/ton 240 240 240 240 240 240 240H2SO4 (Delivered) $US/ton 300 300 300 300 300 300 300SCR Catalyst (Delivered) $US/ft3 280 280 280 280 280 280 280CO Catalyst (Delivered) $US/ft3 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00Other Waste Disposal $US/ton 12 12 12 12 12 12 12Catalyst Disposal $US/ft3 21 21 21 21 21 21 21Land Cost $US/ha 24,710 24,710 24,710 24,710 24,710 24,710 24,710Ammonia (Delivered) $US/t 198 198 198 198 198 198 198NaOH (Delivered) $US/t 265 265 265 265 265 265 265H2SO4 (Delivered) $US/t 331 331 331 331 331 331 331SCR Catalyst (Delivered) $US/m3 9,888 9,888 9,888 9,888 9,888 9,888 9,888CO Catalyst (Delivered) $US/m3 74,159 74,159 74,159 74,159 74,159 74,159 74,159Other Waste Disposal $US/t 13 13 13 13 13 13 13Catalyst Disposal $US/m3 742 742 742 742 742 742 742



B-5




Variable Units Value Value Value Value Value Value ValueNon-operating Purchased Power Cost $US/MWh 45 45 45 45 45 45 45O&M Cost Method N/A WorkStation Calculated WorkStation Calculated WorkStation Calculated WorkStation Calculated WorkStation Calculated WorkStation Calculated WorkStation CalculatedO&M Labor Index Value N/A 1 1 1 1 1 1 1O&M Labor Productivity Multiplier N/A 1 1 1 1 1 1 1Maintenance Cost Adjustment N/A 1 1 1 1 1 1 1Operating Tax Rates %Insurance Rate % 0.5 0.5 0.5 0.5 0.5 0.5 0.5

SOAPP-CT Economic Data Case 1a Case 2a Case 3a Case 4a Case 5a Case 6a Equivalent-aVariable Units Value Value Value Value Value Value ValueIPP Loan Period years 15 15 15 15 15 15 15Evaluation Basis N/A Current Dollar Analysis Current Dollar Analysis Current Dollar Analysis Current Dollar Analysis Current Dollar Analysis Current Dollar Analysis Current Dollar AnalysisOwnership Type N/A Independent Power

ProducerIndependent PowerProducer

Independent PowerProducer





IPP Analysis Method N/A Solve for Return onEquity

Solve for Return onEquity






IPP Equity Repayment Period years 20 20 20 20 20 20 20IPP Loan Repay Method N/A Mortgage Style Mortgage Style Mortgage Style Mortgage Style Mortgage Style Mortgage Style Mortgage StyleInflation Rate %/yr 2 2 2 2 2 2 2Base Year N/A 2000 2000 2000 2000 2000 2000 2000Const Sched Calc Method N/A Workstation Calculated Workstation Calculated Workstation Calculated Workstation Calculated Workstation Calculated Workstation Calculated Workstation CalculatedCapital Costs Esc Rate %/yr 2 2 2 2 2 2 2O&M Costs Esc Rate %/yr 2 2 2 2 2 2 2Common Equity Fraction N/A 0.2 0.2 0.2 0.2 0.2 0.2 0.2Debt Fraction N/A 0.8 0.8 0.8 0.8 0.8 0.8 0.8Return on Common Equity % 18 18 18 18 18 18 18Return on Debt % 8 8 8 8 8 8 8Return on Debt During Construction % 9 9 9 9 9 9 9Investment Tax Credit Rate % 0 0 0 0 0 0 0Capacity Payments $US/kW-yr 0 0 0 0 0 0 0Energy Payments $US/MWh 35.00 70.00 40.00 60.00 50.00 45.00 51.29Energy Payments Escalation % 2.00 2.00 2.00 2.00 2.00 2.00 2.00

SOAPP-CT Fuel Data Case 1a Case 2a Case 3a Case 4a Case 5a Case 6a Equivalent-aVariable Units Value Value Value Value Value Value ValueFuel Price $US/MBtu 3.25 4.00 3.25 4.00 4.50 3.25 3.69Fuel Price $US/GJ 3.08 3.79 3.08 3.79 4.27 3.08 3.49Fuel Price Escalation % 3.50 3.50 3.50 3.50 3.50 3.50 3.50Natural Gas Supply Pressure psig 500 500 500 500 500 500 500



B-6


Site Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix PhoenixTechnology Evaporative Cooling Evaporative Cooling Evaporative Cooling Evaporative Cooling Evaporative Cooling Evaporative Cooling Eva porative Cooling

Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 EquivalentVariable Units Value Value Value Value Value Value Value

CT Model Number N/A GE 7FA GE 7FA GE 7FA GE 7FA GE 7FA GE 7FA GE 7FANumber of CT’s N/A 1 1 1 1 1 1 1Cycle Type N/A Combined Cycle














CT Natural Gas NOx Limit ppmvd @ 15% O2 9 9 9 9 9 9 9CEM's Included N/A Yes Yes Yes Yes Yes Yes YesInlet Air Filtration N/A Pulse Type Pulse Type Pulse Type Pulse Type Pulse Type Pulse Type Pulse TypeInlet Air Cooling N/A EvapCool Evap Cool EvapCool EvapCool EvapCool EvapCool EvapCoolInlet Air Cooler Status N/A Not in Use In Use Not in Use In Use In Use In Use In UseAir Cooling Discharge Temp F 52.0 71.0 42.0 69.0 53.0 59.0 60.1Air Cooling Discharge Temp C 11.1 21.7 5.6 20.6 11.7 15.0 15.6Evaporative Cooler Effectiveness % 85 85 85 85 85 85 85CT Pressure Loss Method N/A User-Specified User-Specified User-Specified User-Specified User-Specified User-Specified User-SpecifiedCT Inlet Pressure Loss in H2O 5.0 5.0 5.0 5.0 5.0 5.0 5CT Inlet Pressure Loss kPa 1.24 1.24 1.24 1.24 1.24 1.24 1.24CT Exhaust Pressure Loss in H2O 14.0 14.0 14.0 14.0 14.0 14.0 14CT Exhaust Pressure Loss kPa 3.47 3.47 3.47 3.47 3.47 3.47 3.47Heater Selection N/A Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate Heater Conden sate HeaterDeaerator Selection N/A Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral DeaeratorNumber of Pressure Levels N/A Three Pressure Three Pressure Three Pressure Three Pressure Three Pressure Three Pressure Three PressureHP Steam Pressure psia 1,800 1,800 1,800 1,800 1,800 1,800 1,800IP Steam Pressure psia 490 490 490 490 490 490 490LP Steam Pressure psia 60 60 60 57 60 60 60Hot Reheat Pressure psia 490 490 490 490 490 490HP Steam Temp F 1,000 1,000 999 1,000 1,000 1,002 1,000IP Steam Temp F 600 600 600 600 600 600 600LP Steam Temp F Use default Use default Use default Use default Use default Use default Use defaultHP Pinch Point F 15 15 15 15 15 15 15IP Pinch Point F 15 13 15 13 15 14 15LP Pinch Point F 10 10 10 10 10 10 10HP Evap Approach F 20 20 20 20 20 20 20IP Evap Approach F 20 18 20 18 18 18 20LP Evap Approach F 13 13 22 10 13 11 13HP Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411 12,411 12,411IP Steam Pressure kPa 3,378 3,378 3,378 3,378 3,378 3,378 3,378LP Steam Pressure kPa 414 414 414 393 414 414 414Hot Reheat Pressure kPa 3,378 3,378 3,378 3,378 3,378 3,378 0HP Steam Temp C 537.8 537.8 537.2 537.8 537.8 538.9 537.8IP Steam Temp C 315.6 315.6 315.6 315.6 315.6 315.6 315.6LP Steam Temp C Use default Use default Use default Use default Use default Use default Use defaultHP Pinch Point C 8.3 8.3 8.3 8.3 8.3 8.3 8.3IP Pinch Point C 8.3 7.2 8.3 7.2 8.3 7.8 8.3LP Pinch Point C 5.6 5.6 5.6 5.6 5.6 5.6 5.6HP Evap Approach C 11.1 11.1 11.1 11.1 11.1 11.1 11.1IP Evap Approach C 11.1 10.0 11.1 10.0 10.0 10.0 11.1LP Evap Approach C 7.2 7.2 12.2 5.6 7.2 6.1 7.2Export All Available Flow N/A no no no no no no noInclude Duct Burners N/A no no no no no no noDuct Burner Performance Calc Method N/ADuct Burner Firing Temperature FDuct Burner Firing Temperature C



B-7




Duct Burner Use N/ADuct Burner Fuel Capability N/ASCR Configuration N/A Anhydrous Ammonia





















Number of ST Extractions N/A 0 0 0 0 0 0 0ST Efficiency Method N/A User-Specified User-Specified User-Specified User-Specified User-Specified User-Specified User-SpecifiedHP ST Efficiency % 87% 87% 87% 87% 87% 87% 87%IP ST Efficiency % 89% 89% 89% 89% 89% 89% 89%LP ST Efficiency % 91% 91% 91% 91% 91% 91% 91%Include a Steam Bypass N/A Yes Yes Yes Yes Yes Yes YesCooling System Type N/A Air-Cooled Condenser Air-Cooled Condenser Air-Cooled Condenser Air-Cooled Condenser Air-Cooled Condenser Air-Cooled Condenser Air-Cooled CondenserCycles of Concentration N/A 0Condenser Pressure Calc Method N/A User-Specified User-Specified User-Specified User-Specified User-Specified User-Specified User-SpecifiedDesign Condenser Pressure in Hg 11.5 11.5 11.5 11.5 11.5 11.5 11.50Design Condenser Pressure kPa 38.93 38.93 38.93 38.93 38.93 38.93 38.93Condenser Tube Material N/A 304 SS 304 SS 304 SS 304 SS 304 SS 304 SS 304 SSCondenser Tube Cleaning N/A None None None None None None NoneCirc Water Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%Include an Auxiliary Boiler N/A no no no no no no noBoiler Feed Pump Sparing N/A 2 - 100% 2 - 100% 2 - 100% 2 - 100% 2 - 100% 2 - 100% 2 - 100%Boiler Feed Pump Design N/A HP Pump with IP







Condensate Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%HRSG Enclosures N/A No No No No No No NoPower Block Enclosure N/A Yes Yes Yes Yes Yes Yes YesWater Treatment Enclosure N/A Yes Yes Yes Yes Yes Yes YesWarehouse Included N/A No No No No No No NoInclude Fire Protection System? N/A Yes Yes Yes Yes Yes Yes YesFire Water Source N/A City/Well Water City/Well Water City/Well Water City/Well Water City/Well Water City/Well Water City/Well WaterSubstructure Requirements N/A Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles Steel PilesBypass Stack/Diverter Valve N/A No No No No No No NoMain Stack Height ft 150 150 150 150 150 150 150Main Stack Height m 45.7 45.7 45.7 45.7 45.7 45.7 45.7Switchyard Voltage kV 115 115 115 115 115 115 115Book Life years 20 20 20 20 20 20 20Tax Life years 15 15 15 15 15 15 15Commercial Operating Year N/A 2003 2003 2003 2003 2003 2003 2003Commercial Operating Month N/A January January January January January January JanuaryCapacity Factor % 57% 95% 57% 95% 95% 95% 73.9%Service Factor % 57% 95% 57% 95% 95% 95% 73.9%Equivalent Availability Factor % 95% 95% 95% 95% 95% 95% 95%Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5%Number of Starts Per Year N/A 40 40 40 40 40 40 40Tax Depreciation Method N/A MACRS MACRS MACRS MACRS MACRS MACRS MACRSCapital Cost Adders $ Adjust manually



B-8




SOAPP-CT Site Data Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 EquivalentVariable Units Value Value Value Value Value Value ValueMax Ambient Dry Bulb Temp F 120 120 120 120 120 120 120Max Ambient Wet Bulb Temp F 72 72 72 72 72 72 72Min Ambient Dry Bulb Temp F 20 20 20 20 20 20 20Perf Point Dry Bulb Temp F 64.0 93.5 48.3 88.9 67.0 74.4 74.9Perf Point Wet Bulb Temp F 50.0 68.0 41.0 66.0 52.0 57.0 56.9Site Elevation ft 1117 1117 1117 1117 1117 1117 1117Ambient Air Quality N/A Clean Clean Clean Clean Clean Clean CleanMax Daily Rainfall in/day 3 3 3 3 3 3 3.0Average Annual Rainfall in/yr 7.5 7.5 7.5 7.5 7.5 7.5 7.5Max Cooling Water Temp F 80 80 80 80 80 80 80.0Perf Point Cooling Water Temp F 60 60 60 60 60 60 60.0Max Ambient Dry Bulb Temp C 48.9 48.9 48.9 48.9 48.9 48.9 48.9Max Ambient Wet Bulb Temp C 22.2 22.2 22.2 22.2 22.2 22.2 22.2Min Ambient Dry Bulb Temp C -6.7 -6.7 -6.7 -6.7 -6.7 -6.7 -6.7Perf Point Dry Bulb Temp C 17.8 34.2 9.0 31.6 19.4 23.6 23.8Perf Point Wet Bulb Temp C 10.0 20.0 5.0 18.9 11.1 13.9 13.8Site Elevation m 340.5 340.5 340.5 340.5 340.5 340.5 340.5Max Daily Rainfall cm/day 7.44 7.44 7.44 7.44 7.44 7.44 7.44Average Annual Rainfall cm/yr 18.6 18.6 18.6 18.6 18.6 18.6 18.6Max Cooling Water Temp C 26.7 26.7 26.7 26.7 26.7 26.7 26.7Perf Point Cooling Water Temp C 15.6 15.6 15.6 15.6 15.6 15.6 15.6Heat Rejection Water Source N/A River River River River River River RiverUnit Makeup Water Source N/A Well Water Well Water Well Water Well Water Well Water Well Water Well WaterMakeup Raw Water Consump Charge $US/1,000 gal 3.00 3.00 3.00 3.00 3.00 3.00 Adjust manuallyMakeup Raw Water Consump Charge $US/ m3 0.79 0.79 0.79 0.79 0.79 0.79 Adjust manuallyCirculating Water Thermal Charge $US/MBtu 0.06 0.06 0.06 0.06 0.06 0.06 0.06Circulating Water Thermal Charge $US/GJ 0.057 0.057 0.057 0.057 0.057 0.057 0.057UBC Seismic Zone N/A Zone 0 Zone 0 Zone 0 Zone 0 Zone 0 Zone 0 Zone 0Stack Natural Gas NOx Limit ppmvd @ 15% O2 5 5 5 5 5 5 5Ammonia Emission Limit ppmvd @ 15% O2 5 5 5 5 5 5 5Construction Labor Index Value N/A 1 1 1 1 1 1 1Productivity Multiplier N/A 1 1 1 1 1 1 1General Facilities Capital % 2 2 2 2 2 2 2Eng. & Home Office Fees % 3 3 3 3 3 3 3Project Contingency % 5 5 5 5 5 5 5Process Contingency % 0 0 0 0 0 0 0Land Cost $US/acre 10,000 10,000 10,000 10,000 10,000 10,000 10000Ammonia (Delivered) $US/ton 180 180 180 180 180 180 180NaOH (Delivered) $US/ton 240 240 240 240 240 240 240H2SO4 (Delivered) $US/ton 300 300 300 300 300 300 300SCR Catalyst (Delivered) $US/ft3 280 280 280 280 280 280 280CO Catalyst (Delivered) $US/ft3 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00 2100Other Waste Disposal $US/ton 12 12 12 12 12 12 12Catalyst Disposal $US/ft3 21 21 21 21 21 21 21Land Cost $US/ha 24,710 24,710 24,710 24,710 24,710 24,710 24,710Ammonia (Delivered) $US/t 198 198 198 198 198 198 198NaOH (Delivered) $US/t 265 265 265 265 265 265 265H2SO4 (Delivered) $US/t 331 331 331 331 331 331 331SCR Catalyst (Delivered) $US/m3 9,888 9,888 9,888 9,888 9,888 9,888 9,888CO Catalyst (Delivered) $US/m3 74,159 74,159 74,159 74,159 74,159 74,159 74,159Other Waste Disposal $US/t 13 13 13 13 13 13 13Catalyst Disposal $US/m3 742 742 742 742 742 742 742



B-9




Non-operating Purchased Power Cost $US/MWh 45 45 45 45 45 45 45O&M Cost Method N/A WorkStation

CalculatedWorkStationCalculated

WorkStationCalculated





O&M Labor Index Value N/A 1 1 1 1 1 1 1O&M Labor Productivity Multiplier N/A 1 1 1 1 1 1 1Maintenance Cost Adjustment N/A 1 1 1 1 1 1 1Operating Tax Rates %Insurance Rate % 0.5 0.5 0.5 0.5 0.5 0.5 0.5

SOAPP-CT Economic Data Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 EquivalentVariable Units Value Value Value Value Value Value ValueIPP Loan Period years 15 15 15 15 15 15 15Evaluation Basis N/A Current Dollar

AnalysisCurrent DollarAnalysis

Current DollarAnalysis





Ownership Type N/A Independent PowerProducer














IPP Equity Repayment Period years 20 20 20 20 20 20 20IPP Loan Repay Method N/A Mortgage Style Mortgage Style Mortgage Style Mortgage Style Mortgage Style Mortgage Style Mortgage StyleInflation Rate %/yr 2 2 2 2 2 2 2Base Year N/A 2000 2000 2000 2000 2000 2000 2000Const Sched Calc Method N/A Workstation

CalculatedWorkstationCalculated

WorkstationCalculated





Capital Costs Esc Rate %/yr 2 2 2 2 2 2 2O&M Costs Esc Rate %/yr 2 2 2 2 2 2 2Common Equity Fraction N/A 0.2 0.2 0.2 0.2 0.2 0.2 0.2Debt Fraction N/A 0.8 0.8 0.8 0.8 0.8 0.8 0.8Return on Common Equity % 18 18 18 18 18 18 18Return on Debt % 8 8 8 8 8 8 8Return on Debt During Construction % 9 9 9 9 9 9 9Investment Tax Credit Rate % 0 0 0 0 0 0 0Capacity Payments $US/kW-yr 0 0 0 0 0 0 0.0Energy Payments $US/MWh 35.00 70.00 40.00 60.00 50.00 45.00 51.29Energy Payments Escalation % 2.00 2.00 2.00 2.00 2.00 2.00 2.00

SOAPP-CT Fuel Data Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 EquivalentVariable Units Value Value Value Value Value Value ValueFuel Price $US/MBtu 3.25 4.00 3.25 4.00 4.50 3.25 3.69Fuel Price $US/GJ 3.08 3.79 3.08 3.79 4.27 3.08 3.49Fuel Price Escalation % 3.50 3.50 3.50 3.50 3.50 3.50 3.50Natural Gas Supply Pressure psig 500 500 500 500 500 500 500



B-10


Site Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix PhoenixTechnology Inlet Fogging Inlet Fogging Inlet Fogging Inlet Fogging Inlet Fogging Inlet Fogging Inlet Fogging
















CT Natural Gas NOx Limit ppmvd @ 15% O2 9 9 9 9 9 9 9CEM's Included N/A Yes Yes Yes Yes Yes Yes YesInlet Air Filtration N/A Pulse Type Pulse Type Pulse Type Pulse Type Pulse Type Pulse Type Pulse TypeInlet Air Cooling N/A Fogging Fogging Fogging Fogging Fogging Fogging FoggingInlet Air Cooler Status N/A In Use In Use Not In Use In Use In Use In Use In UseAir Cooling Discharge Temp F 50.0 68.0 48.3 66.0 52.0 57.0 56.9Air Cooling Discharge Temp C 10.0 20.0 9.0 18.9 11.1 13.9 13.8Evaporative Cooler Effectiveness % 100 100 100 100 100 100 100CT Pressure Loss Method N/A User-Specified User-Specified User-Specified User-Specified User-Specified User-Specified User-SpecifiedCT Inlet Pressure Loss in H2O 3.8 3.8 3.8 3.8 3.8 3.8 3.8CT Inlet Pressure Loss kPa 0.93 0.93 0.93 0.93 0.93 0.93 0.93CT Exhaust Pressure Loss in H2O 14.0 14.0 14.0 14.0 14.0 14.0 14.0CT Exhaust Pressure Loss kPa 3.47 3.47 3.47 3.47 3.47 3.47 3.47Heater Selection N/A Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate Heater Conden sate HeaterDeaerator Selection N/A Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral DeaeratorNumber of Pressure Levels N/A Three Pressure Three Pressure Three Pressure Three Pressure Three Pressure Three Pressure Three PressureHP Steam Pressure psia 1,800 1,800 1,800 1,800 1,800 1,800 1,800IP Steam Pressure psia 490 490 490 490 490 490 490LP Steam Pressure psia 60 60 60 57 60 60 60Hot Reheat Pressure psia 490 490 490 490 490 490HP Steam Temp F 1,000 1,000 999 1,000 1,000 1,002 1,000IP Steam Temp F 600 600 600 600 600 600 600LP Steam Temp F Use default Use default Use default Use default Use default Use default Use defaultHP Pinch Point F 15 15 15 15 15 15 15IP Pinch Point F 15 13 15 13 15 14 15LP Pinch Point F 10 10 10 10 10 10 10HP Evap Approach F 20 20 20 20 20 20 20IP Evap Approach F 20 18 20 18 18 18 20LP Evap Approach F 13 13 22 10 13 11 13HP Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411 12,411 12,411IP Steam Pressure kPa 3,378 3,378 3,378 3,378 3,378 3,378 3,378LP Steam Pressure kPa 414 414 414 393 414 414 414Hot Reheat Pressure kPa 3,378 3,378 3,378 3,378 3,378 3,378 0HP Steam Temp C 537.8 537.8 537.2 537.8 537.8 538.9 537.8IP Steam Temp C 315.6 315.6 315.6 315.6 315.6 315.6 315.6LP Steam Temp C Use default Use default Use default Use default Use default Use default Use defaultHP Pinch Point C 8.3 8.3 8.3 8.3 8.3 8.3 8.3IP Pinch Point C 8.3 7.2 8.3 7.2 8.3 7.8 8.3LP Pinch Point C 5.6 5.6 5.6 5.6 5.6 5.6 5.6HP Evap Approach C 11.1 11.1 11.1 11.1 11.1 11.1 11.1IP Evap Approach C 11.1 10.0 11.1 10.0 10.0 10.0 11.1LP Evap Approach C 7.2 7.2 12.2 5.6 7.2 6.1 7.2Export All Available Flow N/A no no no no no no noInclude Duct Burners N/A no no no no no no noDuct Burner Performance Calc Method N/ADuct Burner Firing Temperature FDuct Burner Firing Temperature C



B-11
































Condensate Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%HRSG Enclosures N/A No No No No No No NoPower Block Enclosure N/A Yes Yes Yes Yes Yes Yes YesWater Treatment Enclosure N/A Yes Yes Yes Yes Yes Yes YesWarehouse Included N/A No No No No No No NoInclude Fire Protection System? N/A Yes Yes Yes Yes Yes Yes YesFire Water Source N/A City/Well Water City/Well Water City/Well Water City/Well Water City/Well Water City/Well Water City/Well WaterSubstructure Requirements N/A Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles Steel PilesBypass Stack/Diverter Valve N/A No No No No No No NoMain Stack Height ft 150 150 150 150 150 150 150Main Stack Height m 45.7 45.7 45.7 45.7 45.7 45.7 45.7Switchyard Voltage kV 115 115 115 115 115 115 115Book Life years 20 20 20 20 20 20 20Tax Life years 15 15 15 15 15 15 15Commercial Operating Year N/A 2003 2003 2003 2003 2003 2003 2003Commercial Operating Month N/A January January January January January January JanuaryCapacity Factor % 57% 95% 57% 95% 95% 95% 74%Service Factor % 57% 95% 57% 95% 95% 95% 74%Equivalent Availability Factor % 95% 95% 95% 95% 95% 95% 95%Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5%Number of Starts Per Year N/A 40 40 40 40 40 40 40Tax Depreciation Method N/A MACRS MACRS MACRS MACRS MACRS MACRS MACRSCapital Cost Adders $ Adjust manually



B-12




SOAPP-CT Site Data Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 EquivalentVariable Units Value Value Value Value Value Value ValueMax Ambient Dry Bulb Temp F 120 120 120 120 120 120 120Max Ambient Wet Bulb Temp F 72 72 72 72 72 72 72Min Ambient Dry Bulb Temp F 20 20 20 20 20 20 20Perf Point Dry Bulb Temp F 64.0 93.5 48.3 88.9 67.0 74.4 74.9Perf Point Wet Bulb Temp F 50.0 68.0 41.0 66.0 52.0 57.0 56.9Site Elevation ft 1117 1117 1117 1117 1117 1117 1117Ambient Air Quality N/A Clean Clean Clean Clean Clean Clean CleanMax Daily Rainfall in/day 3 3 3 3 3 3 3Average Annual Rainfall in/yr 7.5 7.5 7.5 7.5 7.5 7.5 7.5Max Cooling Water Temp F 80 80 80 80 80 80 80Perf Point Cooling Water Temp F 60 60 60 60 60 60 60Max Ambient Dry Bulb Temp C 48.9 48.9 48.9 48.9 48.9 48.9 48.9Max Ambient Wet Bulb Temp C 22.2 22.2 22.2 22.2 22.2 22.2 22.2Min Ambient Dry Bulb Temp C -6.7 -6.7 -6.7 -6.7 -6.7 -6.7 -6.7Perf Point Dry Bulb Temp C 17.8 34.2 9.0 31.6 19.4 23.6 23.8Perf Point Wet Bulb Temp C 10.0 20.0 5.0 18.9 11.1 13.9 13.8Site Elevation m 340.5 340.5 340.5 340.5 340.5 340.5 340.5Max Daily Rainfall cm/day 7.44 7.44 7.44 7.44 7.44 7.44 7.44Average Annual Rainfall cm/yr 18.6 18.6 18.6 18.6 18.6 18.6 18.6Max Cooling Water Temp C 26.7 26.7 26.7 26.7 26.7 26.7 26.7Perf Point Cooling Water Temp C 15.6 15.6 15.6 15.6 15.6 15.6 15.6Heat Rejection Water Source N/A River River River River River River RiverUnit Makeup Water Source N/A Well Water Well Water Well Water Well Water Well Water Well Water Well WaterMakeup Raw Water Consump Charge $US/1,000 gal 3.00 3.00 3.00 3.00 3.00 3.00 Adjust manuallyMakeup Raw Water Consump Charge $US/ m3 0.79 0.79 0.79 0.79 0.79 0.79 Adjust manuallyCirculating Water Thermal Charge $US/MBtu 0.06 0.06 0.06 0.06 0.06 0.06 0.06Circulating Water Thermal Charge $US/GJ 0.057 0.057 0.057 0.057 0.057 0.057 0.057UBC Seismic Zone N/A Zone 0 Zone 0 Zone 0 Zone 0 Zone 0 Zone 0 Zone 0Stack Natural Gas NOx Limit ppmvd @ 15% O2 5 5 5 5 5 5 5Ammonia Emission Limit ppmvd @ 15% O2 5 5 5 5 5 5 5Construction Labor Index Value N/A 1 1 1 1 1 1 1Productivity Multiplier N/A 1 1 1 1 1 1 1General Facilities Capital % 2 2 2 2 2 2 2Eng. & Home Office Fees % 3 3 3 3 3 3 3Project Contingency % 5 5 5 5 5 5 5Process Contingency % 0 0 0 0 0 0 0Land Cost $US/acre 10,000 10,000 10,000 10,000 10,000 10,000 10,000Ammonia (Delivered) $US/ton 180 180 180 180 180 180 180NaOH (Delivered) $US/ton 240 240 240 240 240 240 240H2SO4 (Delivered) $US/ton 300 300 300 300 300 300 300SCR Catalyst (Delivered) $US/ft3 280 280 280 280 280 280 280CO Catalyst (Delivered) $US/ft3 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00Other Waste Disposal $US/ton 12 12 12 12 12 12 12Catalyst Disposal $US/ft3 21 21 21 21 21 21 21Land Cost $US/ha 24,710 24,710 24,710 24,710 24,710 24,710 24,710Ammonia (Delivered) $US/t 198 198 198 198 198 198 198NaOH (Delivered) $US/t 265 265 265 265 265 265 265H2SO4 (Delivered) $US/t 331 331 331 331 331 331 331SCR Catalyst (Delivered) $US/m3 9,888 9,888 9,888 9,888 9,888 9,888 9,888CO Catalyst (Delivered) $US/m3 74,159 74,159 74,159 74,159 74,159 74,159 74,159Other Waste Disposal $US/t 13 13 13 13 13 13 13Catalyst Disposal $US/m3 742 742 742 742 742 742 742



B-13








































Capital Costs Esc Rate %/yr 2 2 2 2 2 2 2O&M Costs Esc Rate %/yr 2 2 2 2 2 2 2Common Equity Fraction N/A 0.2 0.2 0.2 0.2 0.2 0.2 0.2Debt Fraction N/A 0.8 0.8 0.8 0.8 0.8 0.8 0.8Return on Common Equity % 18 18 18 18 18 18 18Return on Debt % 8 8 8 8 8 8 8Return on Debt During Construction % 9 9 9 9 9 9 9Investment Tax Credit Rate % 0 0 0 0 0 0 0Capacity Payments $US/kW-yr 0 0 0 0 0 0 0Energy Payments $US/MWh 35.00 70.00 40.00 60.00 50.00 45.00 51.29Energy Payments Escalation % 2.00 2.00 2.00 2.00 2.00 2.00 2.00




B-14


Site Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix PhoenixTechnology Inlet Chilling Inlet Chilling Inlet Chilling Inlet Chilling Inlet Chilling Inlet Chilling Inlet Chilling
















CT Natural Gas NOx Limit ppmvd @ 15% O2 9 9 9 9 9 9 9CEM's Included N/A Yes Yes Yes Yes Yes Yes YesInlet Air Filtration N/A Pulse Type Pulse Type Pulse Type Pulse Type Pulse Type Pulse Type Pulse TypeInlet Air Cooling N/A Steam Abs Chillers Steam Abs Chillers Steam Abs Chillers Steam Abs Chillers Steam Abs Chillers Steam Abs Chillers Steam Abs ChillersInlet Air Cooler Status N/A Not in Use In Use Not in Use In Use In Use In Use In UseAir Cooling Discharge Temp F 55.0 55.0 48.3 55.0 55.0 55.0 55.0Air Cooling Discharge Temp C 12.8 12.8 9.0 12.8 12.8 12.8 12.8Evaporative Cooler Effectiveness %CT Pressure Loss Method N/A User-Specified User-Specified User-Specified User-Specified User-Specified User-Specified User-SpecifiedCT Inlet Pressure Loss in H2O 4.75 4.75 4.75 4.75 4.75 4.75 4.75CT Inlet Pressure Loss kPa 1.18 1.18 1.18 1.18 1.18 1.18 1.18CT Exhaust Pressure Loss in H2O 14.0 14.0 14.0 14.0 14.0 14.0 14CT Exhaust Pressure Loss kPa 3.47 3.47 3.47 3.47 3.47 3.47 3.47Heater Selection N/A Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate HeaterDeaerator Selection N/A Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral DeaeratorNumber of Pressure Levels N/A Three Pressure Three Pressure Three Pressure Three Pressure Three Pressure Three Pressure Three PressureHP Steam Pressure psia 1,800 1,800 1,800 1,800 1,800 1,800 1,800IP Steam Pressure psia 490 490 490 490 490 490 490LP Steam Pressure psia 60 60 60 57 60 60 60Hot Reheat Pressure psia 490 490 490 490 490 490HP Steam Temp F 1,000 1,000 999 1,000 1,000 1,002 1,000IP Steam Temp F 600 600 600 600 600 600 600LP Steam Temp F Use default Use default Use default Use default Use default Use default Use defaultHP Pinch Point F 15 15 15 15 15 15 15IP Pinch Point F 15 13 15 13 15 14 15LP Pinch Point F 10 10 10 10 10 10 10HP Evap Approach F 20 20 20 20 20 20 20IP Evap Approach F 20 18 20 18 18 18 20LP Evap Approach F 13 13 22 10 13 11 13HP Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411 12,411 12,411IP Steam Pressure kPa 3,378 3,378 3,378 3,378 3,378 3,378 3,378LP Steam Pressure kPa 414 414 414 393 414 414 414Hot Reheat Pressure kPa 3,378 3,378 3,378 3,378 3,378 3,378 0HP Steam Temp C 537.8 537.8 537.2 537.8 537.8 538.9 537.8IP Steam Temp C 315.6 315.6 315.6 315.6 315.6 315.6 315.6LP Steam Temp C Use default Use default Use default Use default Use default Use default Use defaultHP Pinch Point C 8.3 8.3 8.3 8.3 8.3 8.3 8.3IP Pinch Point C 8.3 7.2 8.3 7.2 8.3 7.8 8.3LP Pinch Point C 5.6 5.6 5.6 5.6 5.6 5.6 5.6HP Evap Approach C 11.1 11.1 11.1 11.1 11.1 11.1 11.1IP Evap Approach C 11.1 10.0 11.1 10.0 10.0 10.0 11.1LP Evap Approach C 7.2 7.2 12.2 5.6 7.2 6.1 7.2Export All Available Flow N/A no no no no no no noInclude Duct Burners N/A no no no no no no noDuct Burner Performance Calc Method N/ADuct Burner Firing Temperature FDuct Burner Firing Temperature C



B-15
































Condensate Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%HRSG Enclosures N/A No No No No No No NoPower Block Enclosure N/A Yes Yes Yes Yes Yes Yes YesWater Treatment Enclosure N/A Yes Yes Yes Yes Yes Yes YesWarehouse Included N/A No No No No No No NoInclude Fire Protection System? N/A Yes Yes Yes Yes Yes Yes YesFire Water Source N/A City/Well Water City/Well Water City/Well Water City/Well Water City/Well Water City/Well Water City/Well WaterSubstructure Requirements N/A Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles Steel PilesBypass Stack/Diverter Valve N/A No No No No No No NoMain Stack Height ft 150 150 150 150 150 150 150Main Stack Height m 45.7 45.7 45.7 45.7 45.7 45.7 45.7Switchyard Voltage kV 115 115 115 115 115 115 115Book Life years 20 20 20 20 20 20 20Tax Life years 15 15 15 15 15 15 15Commercial Operating Year N/A 2003 2003 2003 2003 2003 2003 2003Commercial Operating Month N/A January January January January January January JanuaryCapacity Factor % 57% 95% 57% 95% 95% 95% 73.9%Service Factor % 57% 95% 57% 95% 95% 95% 73.9%Equivalent Availability Factor % 95% 95% 95% 95% 95% 95% 95%Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5%Number of Starts Per Year N/A 40 40 40 40 40 40 40Tax Depreciation Method N/A MACRS MACRS MACRS MACRS MACRS MACRS MACRSCapital Cost Adders $ Deduct $2,898,000 for

IACDeduct $2,898,000 forIAC

Deduct $2,898,000 forIAC







B-16




SOAPP-CT Site Data Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 EquivalentVariable Units Value Value Value Value Value Value ValueMax Ambient Dry Bulb Temp F 120 120 120 120 120 120 120Max Ambient Wet Bulb Temp F 72 72 72 72 72 72 72Min Ambient Dry Bulb Temp F 20 20 20 20 20 20 20Perf Point Dry Bulb Temp F 64.0 93.5 48.3 88.9 67.0 74.4 74.9Perf Point Wet Bulb Temp F 50.0 68.0 41.0 66.0 52.0 57.0 56.9Site Elevation ft 1117 1117 1117 1117 1117 1117 1117Ambient Air Quality N/A Clean Clean Clean Clean Clean Clean CleanMax Daily Rainfall in/day 3 3 3 3 3 3 3.0Average Annual Rainfall in/yr 7.5 7.5 7.5 7.5 7.5 7.5 7.5Max Cooling Water Temp F 80 80 80 80 80 80 80.0Perf Point Cooling Water Temp F 60 60 60 60 60 60 60.0Max Ambient Dry Bulb Temp C 48.9 48.9 48.9 48.9 48.9 48.9 48.9Max Ambient Wet Bulb Temp C 22.2 22.2 22.2 22.2 22.2 22.2 22.2Min Ambient Dry Bulb Temp C -6.7 -6.7 -6.7 -6.7 -6.7 -6.7 -6.7Perf Point Dry Bulb Temp C 17.8 34.2 9.0 31.6 19.4 23.6 23.8Perf Point Wet Bulb Temp C 10.0 20.0 5.0 18.9 11.1 13.9 13.8Site Elevation m 340.5 340.5 340.5 340.5 340.5 340.5 340.5Max Daily Rainfall cm/day 7.44 7.44 7.44 7.44 7.44 7.44 7.44Average Annual Rainfall cm/yr 18.6 18.6 18.6 18.6 18.6 18.6 18.6Max Cooling Water Temp C 26.7 26.7 26.7 26.7 26.7 26.7 26.7Perf Point Cooling Water Temp C 15.6 15.6 15.6 15.6 15.6 15.6 15.6Heat Rejection Water Source N/A River River River River River River RiverUnit Makeup Water Source N/A Well Water Well Water Well Water Well Water Well Water Well Water Well WaterMakeup Raw Water Consump Charge $US/1,000 gal 3.00 3.00 3.00 3.00 3.00 3.00 Adjust manuallyMakeup Raw Water Consump Charge $US/ m3 0.79 0.79 0.79 0.79 0.79 0.79 Adjust manuallyCirculating Water Thermal Charge $US/MBtu 0.06 0.06 0.06 0.06 0.06 0.06 0.06Circulating Water Thermal Charge $US/GJ 0.057 0.057 0.057 0.057 0.057 0.057 0.057UBC Seismic Zone N/A Zone 0 Zone 0 Zone 0 Zone 0 Zone 0 Zone 0 Zone 0Stack Natural Gas NOx Limit ppmvd @ 15% O2 5 5 5 5 5 5 5Ammonia Emission Limit ppmvd @ 15% O2 5 5 5 5 5 5 5Construction Labor Index Value N/A 1 1 1 1 1 1 1Productivity Multiplier N/A 1 1 1 1 1 1 1General Facilities Capital % 2 2 2 2 2 2 2Eng. & Home Office Fees % 3 3 3 3 3 3 3Project Contingency % 5 5 5 5 5 5 5Process Contingency % 0 0 0 0 0 0 0Land Cost $US/acre 10,000 10,000 10,000 10,000 10,000 10,000 10000Ammonia (Delivered) $US/ton 180 180 180 180 180 180 180NaOH (Delivered) $US/ton 240 240 240 240 240 240 240H2SO4 (Delivered) $US/ton 300 300 300 300 300 300 300SCR Catalyst (Delivered) $US/ft3 280 280 280 280 280 280 280CO Catalyst (Delivered) $US/ft3 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00 2,100.00 2100Other Waste Disposal $US/ton 12 12 12 12 12 12 12Catalyst Disposal $US/ft3 21 21 21 21 21 21 21Land Cost $US/ha 24,710 24,710 24,710 24,710 24,710 24,710 24,710Ammonia (Delivered) $US/t 198 198 198 198 198 198 198NaOH (Delivered) $US/t 265 265 265 265 265 265 265H2SO4 (Delivered) $US/t 331 331 331 331 331 331 331SCR Catalyst (Delivered) $US/m3 9,888 9,888 9,888 9,888 9,888 9,888 9,888CO Catalyst (Delivered) $US/m3 74,159 74,159 74,159 74,159 74,159 74,159 74,159Other Waste Disposal $US/t 13 13 13 13 13 13 13Catalyst Disposal $US/m3 742 742 742 742 742 742 742



B-17








































Capital Costs Esc Rate %/yr 2 2 2 2 2 2 2O&M Costs Esc Rate %/yr 2 2 2 2 2 2 2Common Equity Fraction N/A 0.2 0.2 0.2 0.2 0.2 0.2 0.2Debt Fraction N/A 0.8 0.8 0.8 0.8 0.8 0.8 0.8Return on Common Equity % 18 18 18 18 18 18 18Return on Debt % 8 8 8 8 8 8 8Return on Debt During Construction % 9 9 9 9 9 9 9Investment Tax Credit Rate % 0 0 0 0 0 0 0Capacity Payments $US/kW-yr 0 0 0 0 0 0 0.0Energy Payments $US/MWh 35.07 70.07 40.07 60.07 50.07 45.07 51.36Energy Payments Escalation % 2.00 2.00 2.00 2.00 2.00 2.00 2.00




B-18

Table B-2Inlet Air Cooling-Phoenix: SOAPP-CT Case Results

Site Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix PhoenixTechnology Base Case Base Case Base Case Base Case Base Case Base Case Base CaseOperating Percent: 28.1% 27.2% 14.0% 17.2% 8.3% 5.2%

CASE 1 CASE 2 CASE 3 CASE 4 CASE 5 CASE 6 SOAPPEquivalent

PLANT DESIGN BASISAmbient Air Temperature F 64 94 48 89 67 74 75.0Ambient Air Temperature C 17.8 34.4 8.9 31.7 19.4 23.3 23.9Site Elevation Above MSL ft 1,117 1,117 1,117 1,117 1,117 1,117 1,117Site Elevation Above MSL m 340 340 340 340 340 340 340Cycle Type Combined Cycle

CogenerationCombined Cycle






CogenerationPrimary Fuel Type Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural GasCT NOx Control, Natural Gas Dry Low NOx







Inlet Air Cooling System EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

CT Air Precooler Discharge Temperature F 52 71 48 69 54 59 59.0CT Air Precooler Discharge Temperature C 11.1 21.7 8.9 20.6 12.2 15.0 15.0Cooling System Type Air Cooled

CondenserAir CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

SCR Configuration AnhydrousAmmonia Injection

AnhydrousAmmonia Injection






Duct Burner UseCOMBUSTION TURBINE DATACombustion Turbine Model GE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzNumber of CT’s Operating 1 1 1 1 1 1 1CT Gross Output, per CT kW 164,408 154,398 165,821 155,666 163,725 162,015 162,017CT Heat Input (HHV), per CT Mbtu/h 1,731.07 1,651.28 1,742.06 1,661.23 1,725.06 1,710.08 1,710.05CT Heat Input (HHV), per CT MW 507.32 483.94 510.55 486.86 505.56 501.17 501.16CT Exhaust Flow per CT lb/h 3,426,509 3,299,147 3,452,163 3,312,892 3,413,682 3,381,615 3,381,615CT Exhaust Flow per CT kg/hr 1,554,254 1,496,483 1,565,891 1,502,718 1,548,436 1,533,891 1,533,891CT Exhaust Temperature F 1,120 1,134 1,116 1,133 1,122 1,127 1,127CT Exhaust Temperature C 604.4 612.2 602.2 611.7 605.6 608.3 608.3CT NOx Emissions ppmvd @ 15% O2 9 9 9 9 9 9 9HRSG DATA (per HRSG)HRSG Gas Inlet Temperature F 1,117 1,131 1,113 1,130 1,119 1,124 1,124HRSG Gas Inlet Temperature C 602.8 610.6 600.6 610.0 603.9 606.7 606.7HP Steam Flow at HRSG lb/h 406,729 404,037 405,940 404,556 407,129 407,312 408,061HP Steam Flow at HRSG kg/hr 184,491 183,270 184,133 183,505 184,673 184,756 185,095HP Steam Pressure at HRSG psia 1,849 1,849 1,849 1,849 1,849 1,849 1,849HP Steam Pressure at HRSG kPa 12,748 12,748 12,748 12,748 12,748 12,748 12,748HP Steam Temperature at HRSG F 1,005 1,005 1,004 1,005 1,005 1,007 1,005HP Steam Temperature at HRSG C 540.6 540.6 540.0 540.6 540.6 541.7 540.6Duct Burner Heat Input (HHV) MBtu/hDuct Burner Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00



B-19

Table B-2Inlet Air Cooling-Phoenix: SOAPP-CT Case Results (Continued)



HP Export Steam FlowHot Reheat Steam Flow at HRSG lb/h 479,540 472,745 480,037 473,554 479,310 478,642 478,685Hot Reheat Steam Flow at HRSG kg/hr 217,518 214,436 217,743 214,803 217,414 217,111 217,130Hot Reheat Steam Pressure at HRSG psia 504 504 504 504 504 504 504Hot Reheat Steam Pressure at HRSG kPa 3,475 3,475 3,475 3,475 3,475 3,475 3,475Hot Reheat Steam Temperature at HRSG F 1,005 1,005 1,004 1,005 1,005 1,007 1,005Hot Reheat Steam Temperature at HRSG C 540.6 540.6 540.0 540.6 540.6 541.7 540.6IP Steam Flow at HRSG lb/h 72,811 68,707 74,097 68,997 72,181 71,330 70,624IP Steam Flow at HRSG kg/hr 33,027 31,165 33,610 31,297 32,741 32,355 32,035IP Steam Pressure at HRSG psia 514 514 514 514 514 514 514IP Steam Pressure at HRSG kPa 3,544 3,544 3,544 3,544 3,544 3,544 3,544IP Steam Temperature at HRSG F 530 530 530 530 530 530 530IP Steam Temperature at HRSG C 276.7 276.7 276.7 276.7 276.7 276.7 276.7IP Export Steam FlowLP Steam Flow at HRSG lb/h 65,362 59,527 65,156 61,041 64,798 62,991 63,402LP Steam Flow at HRSG kg/hr 29,648 27,001 29,555 27,688 29,392 28,573 28,759LP Steam Pressure at HRSG psia 62 62 62 59 62 62 62LP Steam Pressure at HRSG kPa 427 427 427 407 427 427 427LP Steam Temperature at HRSG F 462 462 462 462 462 462 462LP Steam Temperature at HRSG C 238.9 238.9 238.9 238.9 238.9 238.9 238.9LP Export Steam FlowStack Exhaust Flow lb/h 3,426,509 3,299,147 3,452,163 3,312,892 3,413,682 3,381,615 3,381,615Stack Exhaust Flow kg/hr 1,554,254 1,496,483 1,565,891 1,502,718 1,548,436 1,533,891 1,533,891Stack Exhaust Temperature F 201 218 194 214 203 206 207Stack Exhaust Temperature C 93.9 103.3 90.0 101.1 95.0 96.7 97.2STEAM TURBINE DATAThrottle Steam Flow at ST lb/h 406,729 404,037 405,940 404,556 407,129 407,312 408,061Throttle Steam Flow at ST kg/hr 184,491 183,270 184,133 183,505 184,673 184,756 185,095Throttle Steam Pressure psia 1,800 1,800 1,800 1,800 1,800 1,800 1,800Throttle Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411 12,411 12,411Throttle Steam Temperature F 1,000 1,000 999 1,000 1,000 1,002 1,000Throttle Steam Temperature C 537.8 537.8 537.2 537.8 537.8 538.9 537.8Hot Reheat Steam Flow at ST lb/h 479,540 472,745 480,037 473,554 479,310 478,642 478,685Hot Reheat Steam Flow at ST kg/hr 0 0 0 0 0 0 0

HP ST Efficiency % 87 87 87 87 87 87 87IP ST Efficiency % 89 89 89 89 89 89 89LP ST Efficiency % 91 91 91 91 91 91 91

Turbine Backpressure in Hg 2.68 5.82 1.79 5.17 2.90 3.49 3.59Turbine Backpressure kPa 9.07 19.70 6.06 17.50 9.82 11.82 12.15Gross ST Output kW 88,052 80,248 91,182 81,408 87,351 85,751 85,471PLANT DATAGross Plant Output kW 252,460 234,647 257,002 237,075 251,077 247,766 247,488Auxiliary Power kW 4,530 4,416 4,394 4,429 4,528 4,508 4,506Net Plant Output kW 247,930 230,231 252,608 232,645 246,548 243,258 242,982



B-20




Total Plant Heat Input (HHV) MBtu/h 1,731 1,651 1,742 1,661 1,725 1,710 1,710Total Plant Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00Net Plant Heat Rate (HHV) at 100% Load Btu/kWh 6,982 7,172 6,896 7,141 6,997 7,030 7,038Net Plant Heat Rate (HHV) at 100% Load kJ/kwh 7,367 7,568 7,276 7,535 7,383 7,418 7,426Net Plant Heat Rate (LHV) at 100% Load Btu/kWh 6,290 6,461 6,213 6,433 6,303 6,333 6,340Net Plant Heat Rate (LHV) at 100% Load kJ/kwh 11,185 11,489 11,047 11,439 11,209 11,262 11,274

SOAPP Output Data - KEY DESIGN DATACASE 1 CASE 2 CASE 3 CASE 4 CASE 5 CASE 6 SOAPP

EquivalentHP Pinch Point F 15 15 15 15 15 15 15IP Pinch Point F 15 13 15 13 15 14 15LP Pinch Point F 10 10 10 10 10 10 10HP Evap Approach F 20 20 20 20 20 20 20IP Evap Approach F 20 18 20 18 18 18 20LP Evap Approach F 13 13 22 10 13 11 13HP Pinch Point C 8.3 8.3 8.3 8.3 8.3 8.3 8.3IP Pinch Point C 8.3 7.2 8.3 7.2 8.3 7.8 8.3LP Pinch Point C 5.6 5.6 5.6 5.6 5.6 5.6 5.6HP Evap Approach C 11.1 11.1 11.1 11.1 11.1 11.1 11.1IP Evap Approach C 11.1 10.0 11.1 10.0 10.0 10.0 11.1LP Evap Approach C 7.2 7.2 12.2 5.6 7.2 6.1 7.2Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5%

SOAPP Output Data - SURFACE AREASCASE 1 CASE 2 CASE 3 CASE 4 CASE 5 CASE 6 SOAPP

EquivalentHPECON1 SA ft^2 152,002 154,533 151,157 154,483 152,473 153,841 153,631HPECON2 SA ft^2 131,452 131,750 130,771 132,916 131,821 131,923 132,641HPECON3 SA ft^2 0 0 0 0 0 0 0HPEVAP SA ft^2 324,981 317,008 326,127 317,987 324,333 322,492 322,692HPSHT SA ft^2 141,260 131,720 142,986 132,814 140,067 138,461 137,091IPECON SA ft^2 26,584 26,309 26,942 26,728 26,416 26,698 25,998IPEVAP SA ft^2 185,457 189,522 187,681 190,303 184,327 188,611 181,521IPSHT SA ft^2 3,996 3,769 4,068 3,785 3,961 3,914 3,875LPEVAP SA ft^2 245,154 232,634 247,437 235,387 243,897 240,229 240,765LPSHT SA ft^2 4,530 4,254 4,496 4,379 4,502 4,413 4,430LPECON SA ft^2 241,470 209,490 239,995 211,822 238,784 231,698 231,051REHT SA ft^2 77,565 70,467 78,758 71,046 76,657 75,484 74,471HPECON1 SA m^2 14,121 14,357 14,043 14,352 14,165 14,292 14,273HPECON2 SA m^2 12,212 12,240 12,149 12,348 12,247 12,256 12,323HPECON3 SA m^2 0 0 0 0 0 0 0HPEVAP SA m^2 30,192 29,451 30,298 29,542 30,132 29,960 29,979HPSHT SA m^2 13,123 12,237 13,284 12,339 13,013 12,863 12,736



B-21




IPECON SA m^2 2,470 2,444 2,503 2,483 2,454 2,480 2,415IPEVAP SA m^2 17,230 17,607 17,436 17,680 17,125 17,523 16,864IPSHT SA m^2 371 350 378 352 368 364 360LPEVAP SA m^2 22,776 21,612 22,988 21,868 22,659 22,318 22,368LPSHT SA m^2 421 395 418 407 418 410 412LPECON SA m^2 22,433 19,462 22,296 19,679 22,184 21,525 21,465REHT SA m^2 7,206 6,547 7,317 6,600 7,122 7,013 6,919



B-22


Site Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix PhoenixTechnology Evaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingOperating Percent: 28.1% 27.2% 14.0% 17.2% 8.3% 5.2% 100.0%

















EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers



Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser









60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzNumber of CT’s Operating 1 1 1 1 1 1 1CT Gross Output, per CT kW 164,408 154,398 165,821 155,666 163,725 162,015 162,017CT Heat Input (HHV), per CT Mbtu/h 1,731.07 1,651.28 1,742.06 1,661.23 1,725.06 1,710.08 1,710.05CT Heat Input (HHV), per CT MW 507.32 483.94 510.55 486.86 505.56 501.17 501.16CT Exhaust Flow per CT lb/h 3,426,509 3,299,147 3,452,163 3,312,892 3,413,682 3,381,615 3,381,615CT Exhaust Flow per CT kg/hr 1,554,254 1,496,483 1,565,891 1,502,718 1,548,436 1,533,891 1,533,891CT Exhaust Temperature F 1,120 1,134 1,116 1,133 1,122 1,127 1,127CT Exhaust Temperature C 604.4 612.2 602.2 611.7 605.6 608.3 608.3CT NOx Emissions ppmvd @

15% O29 9 9 9 9 9 9

HRSG DATA (per HRSG)HRSG Gas Inlet Temperature F 1,117 1,131 1,113 1,130 1,119 1,124 1,124HRSG Gas Inlet Temperature C 602.8 610.6 600.6 610.0 603.9 606.7 606.7HP Steam Flow at HRSG lb/h 406,729 404,037 405,940 404,556 407,129 407,312 408,061HP Steam Flow at HRSG kg/hr 184,491 183,270 184,133 183,505 184,673 184,756 185,095HP Steam Pressure at HRSG psia 1,849 1,849 1,849 1,849 1,849 1,849 1,849HP Steam Pressure at HRSG kPa 12,748 12,748 12,748 12,748 12,748 12,748 12,748HP Steam Temperature at HRSG F 1,005 1,005 1,004 1,005 1,005 1,007 1,005HP Steam Temperature at HRSG C 540.6 540.6 540.0 540.6 540.6 541.7 540.6Duct Burner Heat Input (HHV) MBtu/hDuct Burner Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00HP Export Steam Flow



B-23



CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative



Hot Reheat Steam Flow at HRSG lb/h 479,540 472,745 480,037 473,554 479,310 478,642 478,685Hot Reheat Steam Flow at HRSG kg/hr 217,518 214,436 217,743 214,803 217,414 217,111 217,130Hot Reheat Steam Pressure at HRSG psia 504 504 504 504 504 504 504Hot Reheat Steam Pressure at HRSG kPa 3,475 3,475 3,475 3,475 3,475 3,475 3,475Hot Reheat Steam Temperature at HRSG F 1,005 1,005 1,004 1,005 1,005 1,007 1,005Hot Reheat Steam Temperature at HRSG C 540.6 540.6 540.0 540.6 540.6 541.7 540.6IP Steam Flow at HRSG lb/h 72,811 68,707 74,097 68,997 72,181 71,330 70,624IP Steam Flow at HRSG kg/hr 33,027 31,165 33,610 31,297 32,741 32,355 32,035IP Steam Pressure at HRSG psia 514 514 514 514 514 514 514IP Steam Pressure at HRSG kPa 3,544 3,544 3,544 3,544 3,544 3,544 3,544IP Steam Temperature at HRSG F 530 530 530 530 530 530 530IP Steam Temperature at HRSG C 276.7 276.7 276.7 276.7 276.7 276.7 276.7IP Export Steam FlowLP Steam Flow at HRSG lb/h 65,362 59,527 65,156 61,041 64,798 62,991 63,402LP Steam Flow at HRSG kg/hr 29,648 27,001 29,555 27,688 29,392 28,573 28,759LP Steam Pressure at HRSG psia 62 62 62 59 62 62 62LP Steam Pressure at HRSG kPa 427 427 427 407 427 427 427LP Steam Temperature at HRSG F 462 462 462 462 462 462 462LP Steam Temperature at HRSG C 238.9 238.9 238.9 238.9 238.9 238.9 238.9LP Export Steam FlowStack Exhaust Flow lb/h 3,426,509 3,299,147 3,452,163 3,312,892 3,413,682 3,381,615 3,381,615Stack Exhaust Flow kg/hr 1,554,254 1,496,483 1,565,891 1,502,718 1,548,436 1,533,891 1,533,891Stack Exhaust Temperature F 201 218 194 214 203 206 207Stack Exhaust Temperature C 93.9 103.3 90.0 101.1 95.0 96.7 97.2STEAM TURBINE DATAThrottle Steam Flow at ST lb/h 406,729 404,037 405,940 404,556 407,129 407,312 408,061Throttle Steam Flow at ST kg/hr 184,491 183,270 184,133 183,505 184,673 184,756 185,095Throttle Steam Pressure psia 1,800 1,800 1,800 1,800 1,800 1,800 1,800Throttle Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411 12,411 12,411Throttle Steam Temperature F 1,000 1,000 999 1,000 1,000 1,002 1,000Throttle Steam Temperature C 537.8 537.8 537.2 537.8 537.8 538.9 537.8Hot Reheat Steam Flow at ST lb/h 479,540 472,745 480,037 473,554 479,310 478,642 478,685Hot Reheat Steam Flow at ST kg/hr 0 0 0 0 0 0 0


Turbine Backpressure in Hg 2.68 5.82 1.79 5.17 2.90 3.49 3.59Turbine Backpressure kPa 9.07 19.70 6.06 17.50 9.82 11.82 12.15Gross ST Output kW 88,052 80,248 91,182 81,408 87,351 85,751 85,471PLANT DATAGross Plant Output kW 252,460 234,647 257,002 237,075 251,077 247,766 247,488Auxiliary Power kW 4,530 4,416 4,394 4,429 4,528 4,508 4,506Net Plant Output kW 247,930 230,231 252,608 232,645 246,548 243,258 242,982Total Plant Heat Input (HHV) MBtu/h 1,731 1,651 1,742 1,661 1,725 1,710 1,710



B-24



CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative



Total Plant Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00Net Plant Heat Rate (HHV) at 100% Load Btu/kWh 6,982 7,172 6,896 7,141 6,997 7,030 7,038Net Plant Heat Rate (HHV) at 100% Load kJ/kwh 7,367 7,568 7,276 7,535 7,383 7,418 7,426Net Plant Heat Rate (LHV) at 100% Load Btu/kWh 6,290 6,461 6,213 6,433 6,303 6,333 6,340Net Plant Heat Rate (LHV) at 100% Load kJ/kwh 11,185 11,489 11,047 11,439 11,209 11,262 11,274




EquivalentHPECON1 SA ft^2 152,002 154,533 151,157 154,483 152,473 153,841 153,631HPECON2 SA ft^2 131,452 131,750 130,771 132,916 131,821 131,923 132,641HPECON3 SA ft^2 0 0 0 0 0 0 0HPEVAP SA ft^2 324,981 317,008 326,127 317,987 324,333 322,492 322,692HPSHT SA ft^2 141,260 131,720 142,986 132,814 140,067 138,461 137,091IPECON SA ft^2 26,584 26,309 26,942 26,728 26,416 26,698 25,998IPEVAP SA ft^2 185,457 189,522 187,681 190,303 184,327 188,611 181,521IPSHT SA ft^2 3,996 3,769 4,068 3,785 3,961 3,914 3,875LPEVAP SA ft^2 245,154 232,634 247,437 235,387 243,897 240,229 240,765LPSHT SA ft^2 4,530 4,254 4,496 4,379 4,502 4,413 4,430LPECON SA ft^2 241,470 209,490 239,995 211,822 238,784 231,698 231,051REHT SA ft^2 77,565 70,467 78,758 71,046 76,657 75,484 74,471HPECON1 SA m^2 14,121 14,357 14,043 14,352 14,165 14,292 14,273HPECON2 SA m^2 12,212 12,240 12,149 12,348 12,247 12,256 12,323HPECON3 SA m^2 0 0 0 0 0 0 0HPEVAP SA m^2 30,192 29,451 30,298 29,542 30,132 29,960 29,979



B-25



CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative

CoolingEvaporative



HPSHT SA m^2 13,123 12,237 13,284 12,339 13,013 12,863 12,736IPECON SA m^2 2,470 2,444 2,503 2,483 2,454 2,480 2,415IPEVAP SA m^2 17,230 17,607 17,436 17,680 17,125 17,523 16,864IPSHT SA m^2 371 350 378 352 368 364 360LPEVAP SA m^2 22,776 21,612 22,988 21,868 22,659 22,318 22,368LPSHT SA m^2 421 395 418 407 418 410 412LPECON SA m^2 22,433 19,462 22,296 19,679 22,184 21,525 21,465REHT SA m^2 7,206 6,547 7,317 6,600 7,122 7,013 6,919



B-26


Site Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix PhoenixTechnology Inlet Fogging Inlet Fogging Inlet Fogging Inlet Fogging Inlet Fogging Inlet Fogging Inlet FoggingOperating Percent: 28.1% 27.2% 14.0% 17.2% 8.3% 5.2%

















EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers

EvaporativeCoolers



Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser









60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzNumber of CT’s Operating 1 1 1 1 1 1 1CT Gross Output, per CT kW 165,866 157,006 166,624 158,288 165,179 163,456 163,456CT Heat Input (HHV), per CT MBtu/h 1,742.86 1,672.27 1,747.43 1,682.04 1,736.87 1,721.94 1,721.94CT Heat Input (HHV), per CT MW 510.78 490.09 512.12 492.96 509.02 504.65 504.65CT Exhaust Flow per CT lb/h 3,450,398 3,330,441 3,463,266 3,344,230 3,437,530 3,405,359 3,405,359CT Exhaust Flow per CT kg/hr 1,565,090 1,510,678 1,570,927 1,516,933 1,559,253 1,544,661 1,544,661CT Exhaust Temperature F 1,117 1,131 1,115 1,130 1,119 1,124 1,124CT Exhaust Temperature C 602.8 610.6 601.7 610.0 603.9 606.7 606.7CT NOx Emissions ppmvd @

15% O29 9 9 9 9 9 9

HRSG DATA (per HRSG)HRSG Gas Inlet Temperature F 1,114 1,128 1,112 1,127 1,116 1,121 1,121HRSG Gas Inlet Temperature C 601.1 608.9 600.0 608.3 602.2 605.0 605.0HP Steam Flow at HRSG lb/h 406,836 405,432 406,309 405,886 407,264 407,531 408,298HP Steam Flow at HRSG kg/hr 184,540 183,903 184,301 184,109 184,734 184,855 185,203HP Steam Pressure at HRSG psia 1,849 1,849 1,849 1,849 1,849 1,849 1,849HP Steam Pressure at HRSG kPa 12,748 12,748 12,748 12,748 12,748 12,748 12,748HP Steam Temperature at HRSG F 1,005 1,005 1,004 1,005 1,005 1,007 1,005HP Steam Temperature at HRSG C 540.6 540.6 540.0 540.6 540.6 541.7 540.6Duct Burner Heat Input (HHV) MBtu/hDuct Burner Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00HP Export Steam FlowHot Reheat Steam Flow at HRSG lb/h 480,716 475,354 480,830 476,093 480,510 479,919 479,972



B-27




Hot Reheat Steam Flow at HRSG kg/hr 218,051 215,619 218,103 215,954 217,958 217,690 217,714Hot Reheat Steam Pressure at HRSG psia 504 504 504 504 504 504 504Hot Reheat Steam Pressure at HRSG kPa 3,475 3,475 3,475 3,475 3,475 3,475 3,475Hot Reheat Steam Temperature at HRSG F 1,005 1,005 1,004 1,005 1,005 1,007 1,005Hot Reheat Steam Temperature at HRSG C 540.6 540.6 540.0 540.6 540.6 541.7 540.6IP Steam Flow at HRSG lb/h 73,880 69,922 74,521 70,206 73,245 72,388 71,674IP Steam Flow at HRSG kg/hr 33,512 31,716 33,803 31,845 33,224 32,835 32,511IP Steam Pressure at HRSG psia 514 514 514 514 514 514 514IP Steam Pressure at HRSG kPa 3,544 3,544 3,544 3,544 3,544 3,544 3,544IP Steam Temperature at HRSG F 530 530 530 530 530 530 530IP Steam Temperature at HRSG C 276.7 276.7 276.7 276.7 276.7 276.7 276.7IP Export Steam FlowLP Steam Flow at HRSG lb/h 66,315 60,569 65,529 62,099 65,748 63,923 64,342LP Steam Flow at HRSG kg/hr 30,080 27,474 29,724 28,168 29,823 28,995 29,185LP Steam Pressure at HRSG psia 62 62 62 59 62 62 62LP Steam Pressure at HRSG kPa 427 427 427 407 427 427 427LP Steam Temperature at HRSG F 462 462 462 462 462 462 462LP Steam Temperature at HRSG C 238.9 238.9 238.9 238.9 238.9 238.9 238.9LP Export Steam FlowStack Exhaust Flow lb/h 3,450,398 3,330,441 3,463,266 3,344,230 3,437,530 3,405,359 3,405,359Stack Exhaust Flow kg/hr 1,565,090 1,510,678 1,570,927 1,516,933 1,559,253 1,544,661 1,544,661Stack Exhaust Temperature F 202 219 195 215 204 207 208Stack Exhaust Temperature C 94.4 103.9 90.6 101.7 95.6 97.2 97.8STEAM TURBINE DATAThrottle Steam Flow at ST lb/h 406,836 405,432 406,309 405,886 407,264 407,531 408,298Throttle Steam Flow at ST kg/hr 184,540 183,903 184,301 184,109 184,734 184,855 185,203Throttle Steam Pressure psia 1,800 1,800 1,800 1,800 1,800 1,800 1,800Throttle Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411 12,411 12,411Throttle Steam Temperature F 1,000 1,000 999 1,000 1,000 1,002 1,000Throttle Steam Temperature C 537.8 537.8 537.2 537.8 537.8 538.9 537.8Hot Reheat Steam Flow at ST lb/h 480,716 475,354 480,830 476,093 480,510 479,919 479,972Hot Reheat Steam Flow at ST kg/hr 0 0 0 0 0 0 0


Turbine Backpressure in Hg 2.77 5.99 1.8 5.32 3.00 3.60 3.70Turbine Backpressure kPa 9.38 20.28 6.09 18.01 10.16 12.19 12.53Gross ST Output kW 88,035 80,459 91,317 81,611 87,313 85,746 85,467PLANT DATAGross Plant Output kW 253,901 237,465 257,941 239,899 252,492 249,202 248,923Auxiliary Power kW 4,547 4,450 4,403 4,463 4,545 4,526 4,524Net Plant Output kW 249,354 233,015 253,538 235,436 247,947 244,676 244,400Total Plant Heat Input (HHV) MBtu/h 1,743 1,672 1,747 1,682 1,737 1,722 1,722Total Plant Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00Net Plant Heat Rate (HHV) at 100% Load Btu/kWh 6,989 7,177 6,892 7,144 7,005 7,038 7,046



B-28




Net Plant Heat Rate (HHV) at 100% Load kJ/kwh 7,374 7,573 7,272 7,538 7,391 7,426 7,435Net Plant Heat Rate (LHV) at 100% Load Btu/kWh 6,297 6,465 6,209 6,436 6,311 6,340 6,347Net Plant Heat Rate (LHV) at 100% Load kJ/kwh 11,196 11,497 11,041 11,445 11,221 11,273 11,287




EquivalentHPECON1 SA ft^2 151,569 154,583 151,139 154,509 152,048 153,444 153,243HPECON2 SA ft^2 131,134 131,861 130,776 133,005 131,511 131,642 132,449HPECON3 SA ft^2 0 0 0 0 0 0 0HPEVAP SA ft^2 326,513 319,451 326,911 320,395 325,879 324,072 324,284HPSHT SA ft^2 143,336 133,831 143,801 134,731 142,103 140,456 139,144IPECON SA ft^2 26,881 26,681 27,066 27,101 26,713 27,001 26,294IPEVAP SA ft^2 187,464 192,099 188,515 192,866 186,333 190,666 183,520IPSHT SA ft^2 4,055 3,836 4,091 3,852 4,020 3,973 3,933LPEVAP SA ft^2 247,452 235,469 248,416 238,227 246,193 242,516 243,063LPSHT SA ft^2 4,581 4,313 4,517 4,439 4,552 4,463 4,480LPECON SA ft^2 240,544 209,227 240,187 211,534 237,764 230,707 230,069REHT SA ft^2 79,096 71,925 79,333 72,512 78,156 76,950 75,899HPECON1 SA m^2 14,081 14,361 14,041 14,354 14,126 14,255 14,237HPECON2 SA m^2 12,183 12,250 12,149 12,357 12,218 12,230 12,305HPECON3 SA m^2 0 0 0 0 0 0 0HPEVAP SA m^2 30,334 29,678 30,371 29,766 30,275 30,107 30,127HPSHT SA m^2 13,316 12,433 13,360 12,517 13,202 13,049 12,927IPECON SA m^2 2,497 2,479 2,514 2,518 2,482 2,508 2,443



B-29




IPEVAP SA m^2 17,416 17,847 17,514 17,918 17,311 17,713 17,050IPSHT SA m^2 377 356 380 358 373 369 365LPEVAP SA m^2 22,989 21,876 23,079 22,132 22,872 22,530 22,581LPSHT SA m^2 426 401 420 412 423 415 416LPECON SA m^2 22,347 19,438 22,314 19,652 22,089 21,433 21,374REHT SA m^2 7,348 6,682 7,370 6,737 7,261 7,149 7,051



B-30


Site Phoenix Phoenix Phoenix Phoenix Phoenix Phoenix PhoenixTechnology Inlet Chilling Inlet Chilling Inlet Chilling Inlet Chilling Inlet Chilling Inlet Chilling Inlet ChillingOperating Percent: 28.1% 27.2% 14.0% 17.2% 8.3% 5.2%
















Inlet Air Cooling System Stm Abs Chillers Stm Abs Chillers Stm Abs Chillers Stm Abs Chillers Stm Abs Chillers Stm Abs Chillers Stm Abs ChillersCT Air Precooler Discharge Temperature F 55 55 48 55 55 55 55.0CT Air Precooler Discharge Temperature C 12.8 12.8 8.9 12.8 12.8 12.8 12.8Cooling System Type Air Cooled


Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser

Air CooledCondenser









60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzGE PG7241(FA)-

60 HzNumber of CT’s Operating 1 1 1 1 1 1 1CT Gross Output, per CT kW 163,615 163,513 165,981 163,522 163,607 163,580 163,584CT Heat Input (HHV), per CT Mbtu/h 1,721.70 1,723.65 1,743.13 1,723.50 1,721.87 1,722.43 1,722.34CT Heat Input (HHV), per CT MW 504.58 505.15 510.86 505.11 504.63 504.79 504.77CT Exhaust Flow per CT lb/h 3,409,461 3,409,461 3,454,383 3,409,461 3,409,461 3,409,461 3,409,461CT Exhaust Flow per CT kg/hr 1,546,521 1,546,521 1,566,898 1,546,521 1,546,521 1,546,521 1,546,521CT Exhaust Temperature F 1,123 1,123 1,116 1,123 1,123 1,123 1,123CT Exhaust Temperature C 606.1 606.1 602.2 606.1 606.1 606.1 606.1CT NOx Emissions ppmvd @ 15% O2 9 9 9 9 9 9 9HRSG DATA (per HRSG)HRSG Gas Inlet Temperature F 1,120 1,120 1,113 1,120 1,120 1,120 1,120HRSG Gas Inlet Temperature C 604.4 604.4 600.6 604.4 604.4 604.4 604.4HP Steam Flow at HRSG lb/h 408,173 413,958 405,795 413,468 408,757 409,425 410,320HP Steam Flow at HRSG kg/hr 185,146 187,770 184,067 187,548 185,411 185,714 186,120HP Steam Pressure at HRSG psia 1,849 1,849 1,849 1,849 1,849 1,849 1,849HP Steam Pressure at HRSG kPa 12,748 12,748 12,748 12,748 12,748 12,748 12,748HP Steam Temperature at HRSG F 1,005 1,005 1,004 1,005 1,005 1,007 1,005HP Steam Temperature at HRSG C 540.6 540.6 540.0 540.6 540.6 541.7 540.6Duct Burner Heat Input (HHV) MBtu/hDuct Burner Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00HP Export Steam FlowHot Reheat Steam Flow at HRSG lb/h 474,069 460,239 480,199 462,896 472,587 469,181 468,680Hot Reheat Steam Flow at HRSG kg/hr 215,036 208,763 217,817 209,968 214,364 212,819 212,592Hot Reheat Steam Pressure at HRSG psia 504 504 504 504 504 504 504



B-31




Hot Reheat Steam Pressure at HRSG kPa 3,475 3,475 3,475 3,475 3,475 3,475 3,475Hot Reheat Steam Temperature at HRSG F 1,005 1,005 1,004 1,005 1,005 1,007 1,005Hot Reheat Steam Temperature at HRSG C 540.6 540.6 540.0 540.6 540.6 541.7 540.6IP Steam Flow at HRSG lb/h 71,775 71,976 74,404 71,813 71,675 72,206 71,460IP Steam Flow at HRSG kg/hr 32,557 32,648 33,749 32,574 32,512 32,752 32,414IP Steam Pressure at HRSG psia 514 514 514 514 514 514 514IP Steam Pressure at HRSG kPa 3,544 3,544 3,544 3,544 3,544 3,544 3,544IP Steam Temperature at HRSG F 530 530 530 530 530 530 530IP Steam Temperature at HRSG C 276.7 276.7 276.7 276.7 276.7 276.7 276.7IP Export Steam FlowLP Steam Flow at HRSG lb/h 63,449 61,506 64,349 62,837 63,362 62,733 63,128LP Steam Flow at HRSG kg/hr 28,780 27,899 29,189 28,503 28,741 28,456 28,635LP Steam Pressure at HRSG psia 64 64 64 61 64 64 64LP Steam Pressure at HRSG kPa 441 441 441 421 441 441 441LP Steam Temperature at HRSG F 462 462 462 462 462 462 462LP Steam Temperature at HRSG C 238.9 238.9 238.9 238.9 238.9 238.9 238.9LP Export Steam FlowStack Exhaust Flow lb/h 3,409,461 3,409,461 3,454,383 3,409,461 3,409,461 3,409,461 3,409,461Stack Exhaust Flow kg/hr 1,546,521 1,546,521 1,566,898 1,546,521 1,546,521 1,546,521 1,546,521Stack Exhaust Temperature F 203 219 195 215 204 208 209Stack Exhaust Temperature C 95.0 103.9 90.6 101.7 95.6 97.8 98.3STEAM TURBINE DATAThrottle Steam Flow at ST lb/h 408,173 413,958 405,795 413,468 408,757 409,425 410,320Throttle Steam Flow at ST kg/hr 185,146 187,770 184,067 187,548 185,411 185,714 186,120Throttle Steam Pressure psia 1,800 1,800 1,800 1,800 1,800 1,800 1,800Throttle Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411 12,411 12,411Throttle Steam Temperature F 1,000 1,000 999 1,000 1,000 1,002 1,000Throttle Steam Temperature C 537.8 537.8 537.2 537.8 537.8 538.9 537.8Hot Reheat Steam Flow at ST lb/h 474,069 460,239 480,199 462,896 472,587 469,181 468,680Hot Reheat Steam Flow at ST kg/hr 0 0 0 0 0 0 0


Turbine Backpressure in Hg 2.82 5.70 1.79 5.13 3.04 3.59 3.68Turbine Backpressure kPa 9.55 19.30 6.06 17.37 10.29 12.15 12.46Gross ST Output kW 86,834 79,356 91,200 80,583 86,055 84,339 84,017PLANT DATAGross Plant Output kW 250,449 242,869 257,181 244,105 249,662 247,918 247,601Auxiliary Power kW 4,587 4,932 4,399 4,875 4,624 4,702 4,712Net Plant Output kW 245,862 237,937 252,782 239,230 245,038 243,216 242,890Total Plant Heat Input (HHV) MBtu/h 1,722 1,724 1,743 1,724 1,722 1,722 1,722Total Plant Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00 0.00 0.00Net Plant Heat Rate (HHV) at 100% Load Btu/kWh 7,003 7,244 6,896 7,204 7,027 7,082 7,091Net Plant Heat Rate (HHV) at 100% Load kJ/kwh 7,389 7,643 7,276 7,601 7,415 7,473 7,482Net Plant Heat Rate (LHV) at 100% Load Btu/kWh 6,309 6,526 6,212 6,490 6,331 6,380 6,388Net Plant Heat Rate (LHV) at 100% Load kJ/kwh 11,217 11,605 11,046 11,541 11,256 11,345 11,360



B-32







EquivalentHPECON1 SA ft^2 153,253 158,053 151,387 157,295 153,565 154,399 154,280HPECON2 SA ft^2 131,732 133,502 130,057 134,275 131,990 131,893 132,680HPECON3 SA ft^2 0 0 0 0 0 0 0HPEVAP SA ft^2 324,162 326,049 326,222 325,891 324,349 324,616 324,848HPSHT SA ft^2 139,390 140,076 143,221 140,208 139,462 140,943 139,623IPECON SA ft^2 26,100 27,344 26,811 27,586 26,081 26,793 26,081IPEVAP SA ft^2 183,619 197,034 188,123 196,811 183,503 190,451 183,259IPSHT SA ft^2 3,939 3,954 4,088 3,940 3,933 3,963 3,921LPEVAP SA ft^2 241,763 239,566 246,399 241,446 241,680 240,942 241,457LPSHT SA ft^2 4,404 4,326 4,421 4,442 4,400 4,373 4,390LPECON SA ft^2 241,837 217,963 241,483 219,137 239,545 233,858 233,380REHT SA ft^2 75,050 72,060 78,877 72,633 74,719 75,078 73,851HPECON1 SA m^2 14,238 14,684 14,064 14,613 14,267 14,344 14,333HPECON2 SA m^2 12,238 12,403 12,083 12,475 12,262 12,253 12,326HPECON3 SA m^2 0 0 0 0 0 0 0HPEVAP SA m^2 30,116 30,291 30,307 30,276 30,133 30,158 30,179HPSHT SA m^2 12,950 13,013 13,306 13,026 12,956 13,094 12,971IPECON SA m^2 2,425 2,540 2,491 2,563 2,423 2,489 2,423IPEVAP SA m^2 17,059 18,305 17,477 18,284 17,048 17,693 17,025IPSHT SA m^2 366 367 380 366 365 368 364LPEVAP SA m^2 22,461 22,256 22,891 22,431 22,453 22,384 22,432LPSHT SA m^2 409 402 411 413 409 406 408LPECON SA m^2 22,467 20,249 22,435 20,358 22,254 21,726 21,682REHT SA m^2 6,972 6,695 7,328 6,748 6,942 6,975 6,861



B-33

Table B-3Inlet Air Cooling-Phoenix: SOAPP-CT Estimated Costs

Site Phoenix Phoenix Phoenix PhoenixTechnology Base Case Base Case Base Case Base CaseOperating Percentage 28.1% 27.2% 14.0% 17.2%

CASE 1a CASE 2a CASE 3a CASE 4aDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor To talCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 477 66 247 790 448 64 236 748 492 68 252 812 453 64 238 755Inlet Air Precooling SystemElectrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,069 13 307 1,389 921 12 266 1,199 1,082 13 311 1,406 955 12 275 1,242HRSG's & Accessories 8,868 95 1,890 10,853 8,511 92 1,769 10,372 9,072 96 1,954 11,122 8,578 92 1,792 10,462Deaeration System 64 32 75 171 64 31 74 169 64 33 76 173 64 32 74 170Duct Burner SystemPost Combustion Emissions Controls 585 97 107 789 561 94 103 758 597 99 108 804 564 95 103 762Steam Piping 0 550 433 983 0 509 418 927 0 561 432 993 0 514 418 932Electrical Systems - HRSG's 28 33 85 146 28 32 82 142 28 34 87 149 28 32 83 143Steam Turbine & Accessories 10,937 629 2,534 14,100 10,328 606 2,441 13,375 11,234 640 2,577 14,451 10,433 610 2,458 13,501Steam Bypass System 938 46 179 1,163 938 46 178 1,162 938 46 178 1,162 938 46 179 1,163Electrical Systems - Steam Turbine 1,706 805 791 3,302 1,643 799 779 3,221 1,737 808 796 3,341 1,654 800 781 3,235Condenser & Accessories 5,809 904 2,096 8,809 5,809 904 2,096 8,809 5,809 904 2,096 8,809 5,809 904 2,096 8,809Circulating Water SystemWater Treatment System 327 92 525 944 320 90 514 924 329 93 529 951 321 91 516 928Waste Water Treatment System 150 22 84 256 147 21 83 251 151 22 84 257 147 21 83 251Auxiliary Boiler & AccessoriesBoiler Feed System 431 146 219 796 428 137 214 779 432 150 221 803 429 139 215 783Condensate System 50 72 107 229 50 69 104 223 50 74 108 232 50 69 104 223Buildings 0 3,052 3,405 6,457 0 2,573 2,857 5,430 0 3,254 3,635 6,889 0 2,652 2,947 5,599Fire Protection System 493 23 372 888 454 22 342 818 508 23 384 915 460 22 347 829Fuel Systems 103 120 181 404 103 120 181 404 103 120 181 404 103 120 181 404Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 510 199 709 0 501 195 696 0 515 201 716 0 503 196 699Station & Instrument Air System 345 121 114 580 345 112 112 569 345 124 115 584 345 113 112 570Closed Cooling Water System 158 69 136 363 145 68 131 344 163 70 138 371 147 68 132 347Cranes & Hoists 94 93 93 280 92 92 91 275 94 94 93 281 92 92 92 276Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 101 265 551 184 98 251 533 185 102 270 557 184 98 253 535Total Process Capital 74,897 8,776 17,194 100,867 73,599 8,177 16,267 98,043 75,493 9,028 17,576 102,097 73,834 8,274 16,425 98,533

SOAPP Output Data - Financial AnalysisCategory (Values in dollars) TotalTotal Capital Requirements Excluding Escalation and AFUDC or IDC in Base Year (2000) $

TOTAL PROCESS CAPITAL 100,867,000 98,043,000 102,097,000 98,533,000

General Facilities 2,017,340 1,960,860 2,041,940 1,970,660 Engineering and Home Office Fees 3,026,010 2,941,290 3,062,910 2,955,990 Project Contingency 5,043,350 4,902,150 5,104,850 4,926,650 Process Contingency 0 0 0 0

TOTAL PLANT COST 110,953,704 107,847,296 112,306,704 108,386,296 AFUDC or IDC See Capital Outlay Table

TOTAL PLANT INVESTMENT 110,953,704 107,847,296 112,306,704 108,386,296TOTAL PLANT INVESTMENT ($/gross kW) 450.18 493.4 435.54 485.48

Prepaid Royalties 0 0 0 0 Preproduction Costs 3,638,000 3,742,563 3,703,480 3,771,073 Inventory Capital 554,768 539,236 561,533 541,931 Initial Cost - Catalyst and Chemicals 0 0 0 0 Land 87,606 87,471 87,741 87,471 Capital Cost Adders 0 0 0 0

TOTAL CAPITAL REQUIREMENT 115,234,080 112,216,568 116,659,448 112,786,768TOTAL CAPITAL REQUIREMENT ($/gross kW) 467.55 513.38 452.42 505.19O + M and Fuel Costs (in Base Year (2000) $)



B-34

Table B-3Inlet Air Cooling-Phoenix: SOAPP-CT Estimated Costs (Continued)

Site Phoenix Phoenix Phoenix PhoenixTechnology Base Case Base Case Base Case Base CaseOperating Percentage 28.1% 27.2% 14.0% 17.2%

CASE 1a CASE 2a CASE 3a CASE 4aDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor To talFixed O + M Direct Operating Labor 393,271 779,433 393,271 779,433 - Number of Operating Staff 6 13 6 13 Direct Maintenance Labor 330,847 374,544 330,847 374,544 - Number of Maintenance Staff 5 6 5 6 Annual Services, Materials, & Purchased Power - Annual O&M Services & Materials 222,853 212,194 227,328 213,950 - Non-operating Purchased Power 41,777 4,308 43,708 4,400 Indirect Labor Costs - Benefits 211,201 353,822 211,201 353,822 - Home Office Costs 195,595 228,888 195,595 228,888

TOTAL FIXED O+M 1,395,545 1,953,190 1,401,951 1,955,038TOTAL FIXED O+M ($/gross kW) 5.66 8.94 5.44 8.76

Variable O+M Scheduled Maintenance Parts & Materials - CT Inspection/Overhaul 1,212,402 1,995,579 1,212,402 1,995,579 - HRSG Inspection/Refurbish 90,611 143,335 92,584 144,867 - ST Inspection/Overhaul 96,691 151,207 99,401 152,794 - BOP Refurbish 82,165 134,622 82,849 135,022 Scheduled Maintenance Labor - CT Inspection/Overhaul 48,496 79,823 48,496 79,823 - HRSG Inspection/Refurbish 27,183 43,000 27,775 43,460 - ST Inspection/Overhaul 9,669 15,120 9,940 15,279 - BOP Refurbish 17,481 28,564 17,651 28,663 Unscheduled Maintenance Allowance 79,235 129,562 79,555 129,774 Catalyst Replacement - SCR Catalyst Materials & Labor 34,200 53,547 35,255 54,198 - CO Catalyst Materials & Labor 0 0 0 0 Other Consumables - Raw water 22,537 35,914 22,918 36,140 - Circulating water 13,370 20,041 13,906 20,419 - NH3 9,437 14,230 9,886 14,230 - H2SO4 8,080 12,876 8,216 12,957 - NaOH 9,757 15,548 9,922 15,646 - Misc 21,005 33,520 21,436 33,788 Disposal Charges - Spent SCR catalyst 2,137 3,346 2,203 3,387 - Spent CO catalyst 0 0 0 0 - Other disposal 601 1,481 629 1,512 Byproduct Credit 0 0 0 0

Total Variable O+M 1,785,063 2,911,325 1,795,030 2,917,547Total Variable O+M ($/MWh) 1.45 1.6 1.39 1.57

Total Fixed and Variable O+M 3,180,609 4,864,515 3,196,982 4,872,585

Fuel Cost Fuel Cost 28,499,724 53,236,744 29,496,410 54,013,288 Fuel Cost ($/MWh) 23.16 29.27 22.91 29.07



B-35


Site Phoenix Phoenix PhoenixTechnology Base Case Base Case Base CaseOperating Percentage 8.3% 5.2%

CASE 5a CASE 6a SOAPP EQUIVALENT-a CASEDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor TotalCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 474 66 246 786 467 66 243 776 466 66 243 775Inlet Air Precooling SystemElectrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,054 13 303 1,370 1,018 12 293 1,323 1,072 12 308 1,392HRSG's & Accessories 8,825 94 1,876 10,795 8,762 94 1,853 10,709 8,911 95 1,903 10,909Deaeration System 64 32 75 171 64 32 75 171 64 32 75 171Duct Burner SystemPost Combustion Emissions Controls 583 97 106 786 576 96 105 777 575 96 105 776Steam Piping 0 546 432 978 0 534 425 959 0 534 427 961Electrical Systems - HRSG's 28 33 85 146 28 33 84 145 28 34 85 147Steam Turbine & Accessories 10,873 627 2,524 14,024 10,728 621 2,503 13,852 10,712 621 2,501 13,834Steam Bypass System 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163Electrical Systems - Steam Turbine 1,700 804 789 3,293 1,685 803 787 3,275 1,683 803 786 3,272Condenser & Accessories 5,809 904 2,096 8,809 5,809 904 2,096 8,809 5,809 905 2,097 8,811Circulating Water SystemWater Treatment System 326 92 524 942 324 91 522 937 324 91 521 936Waste Water Treatment System 149 22 84 255 149 22 83 254 149 22 83 254Auxiliary Boiler & AccessoriesBoiler Feed System 430 145 218 793 430 143 217 790 429 143 217 789Condensate System 50 72 106 228 50 71 106 227 50 71 106 227Buildings 0 3,002 3,348 6,350 0 2,888 3,218 6,106 0 2,874 3,201 6,075Fire Protection System 489 23 369 881 480 22 362 864 479 22 361 862Fuel Systems 103 120 181 404 103 120 181 404 103 120 181 404Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 510 198 708 0 507 198 705 0 507 197 704Station & Instrument Air System 345 120 114 579 345 118 113 576 345 118 113 576Closed Cooling Water System 156 69 135 360 153 69 134 356 153 69 134 356Cranes & Hoists 94 93 93 280 93 93 92 278 93 93 92 278Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 101 263 549 184 100 260 544 184 100 260 544Total Process Capital 74,755 8,716 17,094 100,565 74,466 8,570 16,879 99,915 74,647 8,559 16,925 100,131

SOAPP Output Data - Financial AnalysisCategory (Values in dollars)Total Capital Requirements Excluding Escalation and AFUDC or IDC in Base Year (2000) $

TOTAL PROCESS CAPITAL 100,565,000 99,915,000 100,131,000

General Facilities 2,011,300 1,998,300 2,002,620 Engineering and Home Office Fees 3,016,950 2,997,450 3,003,930 Project Contingency 5,028,250 4,995,750 5,006,550 Process Contingency 0 0 0

TOTAL PLANT COST 110,621,504 109,906,496 110,144,104 AFUDC or IDC See Capital Outlay Table

TOTAL PLANT INVESTMENT 110,621,504 109,906,496 110,144,104TOTAL PLANT INVESTMENT ($/gross kW) 454.07 463.63 466.29

Prepaid Royalties 0 0 0 Preproduction Costs 4,063,738 3,629,592 3,770,081 Inventory Capital 553,107 549,532 550,720 Initial Cost - Catalyst and Chemicals 0 0 0 Land 87,606 87,606 87,741 Capital Cost Adders 0 0 0

TOTAL CAPITAL REQUIREMENT 115,325,952 114,173,224 114,552,640TOTAL CAPITAL REQUIREMENT ($/gross kW) 473.38 481.63 484.95O + M and Fuel Costs (in Base Year (2000) $)



B-36


Site Phoenix Phoenix PhoenixTechnology Base Case Base Case Base CaseOperating Percentage 8.3% 5.2%

CASE 5a CASE 6a SOAPP EQUIVALENT-a CASEDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor TotalFixed O + M Direct Operating Labor 779,433 779,433 779,433 - Number of Operating Staff 13 13 13 Direct Maintenance Labor 374,544 374,544 374,544 - Number of Maintenance Staff 6 6 6 Annual Services, Materials, & Purchased Power - Annual O&M Services & Materials 221,744 219,213 218,892 - Non-operating Purchased Power 4,801 4,672 24,303 Indirect Labor Costs - Benefits 353,822 353,822 353,822 - Home Office Costs 228,888 228,888 228,888

TOTAL FIXED O+M 1,963,234 1,960,574 1,979,883TOTAL FIXED O+M ($/gross kW) 8.06 8.27 8.38

Variable O+M Scheduled Maintenance Parts & Materials - CT Inspection/Overhaul 1,995,579 1,995,579 1,559,543 - HRSG Inspection/Refurbish 150,129 148,617 118,011 - ST Inspection/Overhaul 159,445 157,251 120,869 - BOP Refurbish 136,721 136,169 105,864 Scheduled Maintenance Labor - CT Inspection/Overhaul 79,823 79,823 62,381 - HRSG Inspection/Refurbish 45,038 44,585 35,403 - ST Inspection/Overhaul 15,944 15,725 12,086 - BOP Refurbish 29,081 28,946 22,502 Unscheduled Maintenance Allowance 130,588 130,334 101,833 Catalyst Replacement - SCR Catalyst Materials & Labor 56,674 55,892 43,377 - CO Catalyst Materials & Labor 0 0 0 Other Consumables - Raw water 37,407 37,041 28,781 - Circulating water 22,056 21,529 16,697 - NH3 15,728 14,979 11,652 - H2SO4 13,411 13,280 10,319 - NaOH 16,195 16,036 12,460 - Misc 34,856 34,508 26,816 Disposal Charges - Spent SCR catalyst 3,542 3,493 2,711 - Spent CO catalyst 0 0 0 - Other disposal 1,650 1,606 968 Byproduct Credit 0 0 0

Total Variable O+M 2,943,876 2,935,402 2,292,281Total Variable O+M ($/MWh) 1.45 1.49 1.50

Total Fixed and Variable O+M 4,907,110 4,895,976 4,272,165

Fuel Cost Fuel Cost 65,183,856 46,082,884 40,570,040 Fuel Cost ($/MWh) 32.15 23.36 26.53



B-37


Site Phoenix Phoenix Phoenix PhoenixTechnology Evaporative Cooling Evaporative Cooling Evaporative Cooling Evaporative CoolingOperating Percentage 28.1% 27.2% 14.0% 17.2%

CASE 1 CASE 2 CASE 3 CASE 4Description (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total

Combustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 486 67 250 803 469 66 244 779 490 68 252 810 471 66 244 781Inlet Air Precooling System 316 56 137 509 338 54 146 538 296 57 129 482 331 55 143 529Electrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,085 13 312 1,410 942 12 272 1,226 1,078 13 310 1,401 952 13 275 1,240HRSG's & Accessories 9,030 96 1,941 11,067 8,856 95 1,874 10,825 9,075 96 1,954 11,125 8,901 95 1,889 10,885Deaeration System 66 33 78 177 66 33 77 176 64 32 75 171 66 33 77 176Duct Burner SystemPost Combustion Emissions Controls 592 98 107 797 578 96 105 779 594 98 107 799 579 96 105 780Steam Piping 0 558 436 994 0 530 424 954 0 563 437 1,000 0 536 428 964Electrical Systems - HRSG's 28 34 86 148 28 33 85 146 28 34 87 149 28 34 85 147Steam Turbine & Accessories 11,037 633 2,549 14,219 10,538 614 2,474 13,626 11,227 639 2,576 14,442 10,610 617 2,485 13,712Steam Bypass System 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163Electrical Systems - Steam Turbine 1,717 806 792 3,315 1,665 801 783 3,249 1,736 808 796 3,340 1,672 802 784 3,258Condenser & Accessories 6,332 929 2,237 9,498 6,332 929 2,237 9,498 5,809 904 2,096 8,809 6,332 930 2,237 9,499Circulating Water SystemWater Treatment System 434 119 692 1,245 501 135 795 1,431 329 93 529 951 485 131 770 1,386Waste Water Treatment System 201 25 103 329 235 27 117 379 150 22 84 256 227 26 113 366Auxiliary Boiler & AccessoriesBoiler Feed System 433 148 221 802 435 143 219 797 431 150 220 801 434 144 219 797Condensate System 51 73 107 231 51 71 106 228 50 74 107 231 51 71 106 228Buildings 0 3,157 3,525 6,682 0 2,846 3,169 6,015 0 3,239 3,618 6,857 0 2,888 3,217 6,105Fire Protection System 501 23 378 902 476 22 359 857 507 23 383 913 480 22 362 864Fuel Systems 103 120 181 404 103 120 181 404 103 120 181 404 103 120 181 404Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 517 201 718 0 516 201 717 0 515 201 716 0 515 201 716Station & Instrument Air System 345 123 114 582 345 117 113 575 345 124 115 584 345 118 113 576Closed Cooling Water System 161 69 137 367 153 69 134 356 163 70 137 370 154 69 134 357Cranes & Hoists 94 94 93 281 93 93 92 278 94 94 93 281 93 93 92 278Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 102 268 555 184 100 259 543 185 102 270 557 184 100 260 544Total Process Capital 76,215 9,024 17,874 103,113 75,406 8,653 17,395 101,454 75,772 9,069 17,686 102,527 75,516 8,705 17,449 101,670










B-38


Site Phoenix Phoenix Phoenix PhoenixTechnology Evaporative Cooling Evaporative Cooling Evaporative Cooling Evaporative CoolingOperating Percentage 28.1% 27.2% 14.0% 17.2%

CASE 1 CASE 2 CASE 3 CASE 4Description (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor To talFixed O + M Direct Operating Labor 393,271 779,433 393,271 779,433 - Number of Operating Staff 6 13 6 13 Direct Maintenance Labor 330,847 374,544 330,847 374,544 - Number of Maintenance Staff 5 6 5 6 Annual Services, Materials, & Purchased Power - Annual O&M Services & Materials 225,184 218,269 226,997 219,203 - Non-operating Purchased Power 42,793 4,624 43,563 4,672 Indirect Labor Costs - Benefits 211,201 353,822 211,201 353,822 - Home Office Costs 195,595 228,888 195,595 228,888








B-39


Site Phoenix Phoenix PhoenixTechnology Evaporative Cooling Evaporative Cooling Evaporative CoolingOperating Percentage 8.3% 5.2%

CASE 5 CASE 6 SOAPP EQUIVALENT CASEDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor TotalCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 485 67 250 802 480 67 248 795 480 67 248 795Inlet Air Precooling System 318 56 138 512 321 56 139 516 324 56 140 520Electrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,073 13 309 1,395 1,041 13 300 1,354 1,038 13 299 1,350HRSG's & Accessories 9,006 96 1,932 11,034 8,994 96 1,926 11,016 8,945 95 1,910 10,950Deaeration System 66 33 78 177 66 33 77 176 66 33 78 177Duct Burner SystemPost Combustion Emissions Controls 591 97 107 795 588 97 107 792 588 97 107 792Steam Piping 0 556 435 991 0 553 436 989 0 551 434 985Electrical Systems - HRSG's 28 34 86 148 28 34 86 148 28 34 86 148Steam Turbine & Accessories 10,993 631 2,542 14,166 10,892 627 2,527 14,046 10,876 627 2,525 14,028Steam Bypass System 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163Electrical Systems - Steam Turbine 1,712 805 792 3,309 1,702 804 790 3,296 1,700 804 789 3,293Condenser & Accessories 6,332 929 2,237 9,498 6,332 929 2,237 9,498 6,332 929 2,237 9,498Circulating Water SystemWater Treatment System 440 120 701 1,261 452 123 719 1,294 458 125 729 1,312Waste Water Treatment System 204 25 104 333 210 25 107 342 213 25 108 346Auxiliary Boiler & AccessoriesBoiler Feed System 433 148 221 802 434 147 220 801 434 147 221 802Condensate System 51 73 107 231 51 73 107 231 51 73 107 231Buildings 0 3,133 3,497 6,630 0 3,074 3,430 6,504 0 3,070 3,425 6,495Fire Protection System 499 23 377 899 494 23 373 890 494 23 373 890Fuel Systems 103 120 181 404 103 120 181 404 103 120 181 404Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 517 201 718 0 516 201 717 0 517 201 718Station & Instrument Air System 345 122 114 581 345 121 114 580 345 121 114 580Closed Cooling Water System 160 69 137 366 159 69 136 364 158 69 136 363Cranes & Hoists 94 94 93 281 94 94 93 281 94 94 93 281Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 102 267 554 185 101 265 551 185 101 265 551Total Process Capital 76,136 8,994 17,835 102,965 75,989 8,926 17,748 102,663 75,930 8,922 17,735 102,587










B-40


Site Phoenix Phoenix PhoenixTechnology Evaporative Cooling Evaporative Cooling Evaporative CoolingOperating Percentage 8.3% 5.2%

CASE 5 CASE 6 SOAPP EQUIVALENT CASEDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor TotalFixed O + M Direct Operating Labor 779,433 779,433 779,433 - Number of Operating Staff 13 13 13 Direct Maintenance Labor 374,544 374,544 374,544 - Number of Maintenance Staff 6 6 6 Annual Services, Materials, & Purchased Power - Annual O&M Services & Materials 224,645 223,340 223,246 - Non-operating Purchased Power 4,948 4,883 25,463 Indirect Labor Costs - Benefits 353,822 353,822 353,822 - Home Office Costs 228,888 228,888 228,888


Variable O+M Scheduled Maintenance Parts & Materials - CT Inspection/Overhaul 1,995,579 1,995,579 1,559,543 - HRSG Inspection/Refurbish 153,165 152,501 118,014 - ST Inspection/Overhaul 161,263 159,733 122,773 - BOP Refurbish 150,294 150,240 116,992 Scheduled Maintenance Labor - CT Inspection/Overhaul 79,823 79,823 62,381 - HRSG Inspection/Refurbish 45,949 45,750 35,404 - ST Inspection/Overhaul 16,126 15,973 12,277 - BOP Refurbish 31,835 31,808 24,767 Unscheduled Maintenance Allowance 131,701 131,570 102,607 Catalyst Replacement - SCR Catalyst Materials & Labor 58,368 57,912 45,049 - CO Catalyst Materials & Labor 0 0 0 Other Consumables - Raw water 77,885 82,667 66,371 - Circulating water 22,754 22,507 17,496 - NH3 15,728 15,728 12,235 - H2SO4 27,924 29,638 23,796 - NaOH 33,719 35,789 28,734 - Misc 52,748 54,674 43,395 Disposal Charges - Spent SCR catalyst 3,648 3,619 2,815 - Spent CO catalyst 0 0 0 - Other disposal 1,701 1,679 1,014 Byproduct Credit 0 0 0






B-41


Site Phoenix Phoenix Phoenix PhoenixTechnology Inlet Fogging Inlet Fogging Inlet Fogging Inlet FoggingOperating Percentage 28.1% 27.2% 14.0% 17.2%

CASE 1 CASE 2 CASE 3 CASE 4Description (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor To talCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 490 67 251 808 473 66 245 784 492 68 252 812 475 66 246 787Inlet Air Precooling System 222 57 141 420 240 55 151 446 205 57 131 393 235 55 148 438Electrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,081 13 311 1,405 940 13 272 1,225 1,079 13 310 1,402 951 13 275 1,239HRSG's & Accessories 9,086 96 1,958 11,140 8,930 95 1,896 10,921 9,100 97 1,962 11,159 8,974 96 1,910 10,980Deaeration System 66 34 78 178 66 33 78 177 64 32 75 171 66 33 78 177Duct Burner SystemPost Combustion Emissions Controls 594 98 107 799 581 96 105 782 595 99 107 801 582 97 106 785Steam Piping 0 560 437 997 0 534 425 959 0 565 438 1,003 0 540 430 970Electrical Systems - HRSG's 28 34 87 149 28 34 86 148 28 34 87 149 28 34 86 148Steam Turbine & Accessories 11,043 633 2,549 14,225 10,563 615 2,478 13,656 11,239 640 2,578 14,457 10,635 618 2,489 13,742Steam Bypass System 938 47 179 1,164 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163Electrical Systems - Steam Turbine 1,717 806 792 3,315 1,668 801 784 3,253 1,738 808 796 3,342 1,675 802 785 3,262Condenser & Accessories 6,332 933 2,240 9,505 6,332 933 2,240 9,505 5,809 904 2,096 8,809 6,332 934 2,240 9,506Circulating Water SystemWater Treatment System 414 123 719 1,256 462 142 837 1,441 329 93 529 951 446 138 809 1,393Waste Water Treatment System 210 25 107 342 249 28 123 400 151 22 84 257 240 27 119 386Auxiliary Boiler & AccessoriesBoiler Feed System 434 149 221 804 436 144 220 800 431 150 221 802 435 145 220 800Condensate System 51 74 107 232 51 71 106 228 50 74 108 232 51 72 106 229Buildings 0 3,130 3,554 6,684 0 2,791 3,225 6,016 0 3,216 3,637 6,853 0 2,831 3,273 6,104Fire Protection System 503 23 380 906 480 22 362 864 508 23 384 915 484 23 365 872Fuel Systems 103 118 181 402 103 116 181 400 103 119 181 403 103 116 181 400Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 520 202 722 0 520 202 722 0 516 201 717 0 519 202 721Station & Instrument Air System 345 123 114 582 345 118 113 576 345 124 115 584 345 119 113 577Closed Cooling Water System 161 70 137 368 154 69 135 358 163 70 138 371 155 69 135 359Cranes & Hoists 94 94 93 281 93 93 92 278 94 94 93 281 93 93 92 278Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 102 268 555 184 100 260 544 185 102 270 557 184 100 262 546Total Process Capital 76,177 9,014 17,963 103,154 75,396 8,620 17,545 101,561 75,726 9,051 17,722 102,499 75,507 8,671 17,599 101,777










B-42


Site Phoenix Phoenix Phoenix PhoenixTechnology Inlet Fogging Inlet Fogging Inlet Fogging Inlet FoggingOperating Percentage 28.1% 27.2% 14.0% 17.2%









B-43


Site Phoenix Phoenix PhoenixTechnology Inlet Fogging Inlet Fogging Inlet FoggingOperating Percentage 8.3% 5.2%

CASE 5 CASE 6 SOAPP EQUIVALENT CASEDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor TotalCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 488 67 251 806 484 67 249 800 484 67 249 800Inlet Air Precooling System 223 56 142 421 226 56 143 425 222 56 145 423Electrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,068 13 307 1,388 1,037 13 299 1,349 1,034 13 298 1,345HRSG's & Accessories 9,061 96 1,949 11,106 9,050 96 1,942 11,088 9,001 96 1,927 11,024Deaeration System 66 33 78 177 66 33 78 177 66 33 78 177Duct Burner SystemPost Combustion Emissions Controls 593 98 107 798 590 98 107 795 590 98 107 795Steam Piping 0 558 436 994 0 555 437 992 0 553 434 987Electrical Systems - HRSG's 28 34 87 149 28 34 87 149 28 34 86 148Steam Turbine & Accessories 10,998 631 2,543 14,172 10,899 628 2,528 14,055 10,883 627 2,526 14,036Steam Bypass System 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163Electrical Systems - Steam Turbine 1,713 805 792 3,310 1,702 805 790 3,297 1,701 804 790 3,295Condenser & Accessories 6,332 933 2,240 9,505 6,332 933 2,240 9,505 6,332 933 2,240 9,505Circulating Water SystemWater Treatment System 420 125 729 1,274 432 128 750 1,310 431 130 761 1,322Waste Water Treatment System 213 25 108 346 220 26 111 357 224 26 112 362Auxiliary Boiler & AccessoriesBoiler Feed System 434 149 221 804 435 148 221 804 435 148 221 804Condensate System 51 73 107 231 51 73 107 231 51 73 107 231Buildings 0 3,105 3,526 6,631 0 3,048 3,459 6,507 0 3,043 3,454 6,497Fire Protection System 501 23 378 902 496 23 375 894 496 23 374 893Fuel Systems 103 118 181 402 103 118 181 402 103 118 181 402Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 520 202 722 0 519 202 721 0 519 202 721Station & Instrument Air System 345 123 114 582 345 122 114 581 345 121 114 580Closed Cooling Water System 161 69 137 367 159 69 136 364 159 69 136 364Cranes & Hoists 94 94 93 281 94 94 93 281 94 94 93 281Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 102 268 555 185 101 266 552 185 101 266 552Total Process Capital 76,095 8,981 17,925 103,001 75,952 8,918 17,844 102,714 75,882 8,910 17,830 102,622










B-44


Site Phoenix Phoenix PhoenixTechnology Inlet Fogging Inlet Fogging Inlet FoggingOperating Percentage 8.3% 5.2%









B-45


Site Phoenix Phoenix Phoenix PhoenixTechnology Inlet Chilling Inlet Chilling Inlet Chilling Inlet ChillingOperating Percentage 28.1% 27.2% 14.0% 17.2%

CASE 1 CASE 2 CASE 3 CASE 4Description (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor To talCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 484 67 249 800 484 67 249 800 490 68 252 810 484 67 249 800Inlet Air Precooling System 1,467 1,181 1,221 3,869 1,467 1,224 1,245 3,936 1,288 998 1,050 3,336 1,467 1,218 1,242 3,927Electrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,087 13 312 1,412 980 13 283 1,276 1,085 13 312 1,410 985 13 284 1,282HRSG's & Accessories 8,974 96 1,924 10,994 9,102 97 1,952 11,151 9,069 96 1,953 11,118 9,115 97 1,957 11,169Deaeration System 67 34 79 180 67 34 79 180 64 32 75 171 67 34 79 180Duct Burner SystemPost Combustion Emissions Controls 590 97 107 794 590 97 107 794 597 98 108 803 590 97 107 794Steam Piping 0 555 435 990 0 541 428 969 0 563 437 1,000 0 546 432 978Electrical Systems - HRSG's 28 34 86 148 28 34 87 149 28 34 87 149 28 34 87 149Steam Turbine & Accessories 10,962 630 2,538 14,130 10,529 614 2,473 13,616 11,229 639 2,576 14,444 10,600 616 2,484 13,700Steam Bypass System 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163Electrical Systems - Steam Turbine 1,709 805 791 3,305 1,664 801 783 3,248 1,737 808 796 3,341 1,671 802 784 3,257Condenser & Accessories 6,332 936 2,242 9,510 6,332 927 2,235 9,494 5,809 903 2,096 8,808 6,332 929 2,236 9,497Circulating Water SystemWater Treatment System 373 104 597 1,074 374 104 599 1,077 374 104 598 1,076 375 104 599 1,078Waste Water Treatment System 154 23 87 264 155 23 88 266 154 23 88 265 155 23 88 266Auxiliary Boiler & AccessoriesBoiler Feed System 433 148 220 801 441 146 223 810 431 150 220 801 440 147 222 809Condensate System 50 73 107 230 51 72 107 230 50 74 107 231 51 72 107 230Buildings 0 3,122 3,484 6,606 0 2,987 3,331 6,318 0 3,242 3,622 6,864 0 3,009 3,356 6,365Fire Protection System 498 23 376 897 487 23 368 878 507 23 383 913 489 23 369 881Fuel Systems 103 120 181 404 103 120 181 404 103 120 181 404 103 120 181 404Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 515 200 715 0 522 203 725 0 515 201 716 0 520 203 723Station & Instrument Air System 345 122 114 581 345 120 114 579 345 124 115 584 345 120 114 579Closed Cooling Water System 160 69 137 366 157 69 136 362 163 70 138 371 157 69 136 362Cranes & Hoists 94 94 93 281 94 93 93 280 94 94 93 281 94 93 93 280Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 102 267 554 185 101 263 549 185 102 270 557 185 101 263 549Total Process Capital 77,113 10,094 18,776 105,983 76,653 9,960 18,556 105,169 76,820 10,024 18,687 105,531 76,751 9,985 18,601 105,337






Prepaid Royalties 0 0 0 0 Preproduction Costs 3,774,544 4,047,206 3,778,047 4,051,000 Inventory Capital 582,906 578,429 580,420 579,353 Initial Cost - Catalyst and Chemicals 0 0 0 0 Land 87,741 87,606 87,606 87,741 Capital Cost Adders -2,898,000 -2,898,000 -2,898,000 -2,898,000




B-46


Site Phoenix Phoenix Phoenix PhoenixTechnology Inlet Chilling Inlet Chilling Inlet Chilling Inlet ChillingOperating Percentage 28.1% 27.2% 14.0% 17.2%









B-47


Site Phoenix Phoenix PhoenixTechnology Inlet Chilling Inlet Chilling Inlet ChillingOperating Percentage 8.3% 5.2%

CASE 5 CASE 6 SOAPP EQUIVALENT CASEDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor TotalCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 484 67 249 800 484 67 249 800 484 67 249 800Inlet Air Precooling System 1,467 1,186 1,225 3,878 1,467 1,197 1,231 3,895 1,467 1,199 1,232 3,898Electrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,076 13 309 1,398 1,051 13 302 1,366 1,049 13 302 1,364HRSG's & Accessories 8,978 96 1,924 10,998 9,039 96 1,940 11,075 8,989 96 1,925 11,010Deaeration System 67 34 79 180 67 34 79 180 67 34 79 180Duct Burner SystemPost Combustion Emissions Controls 590 97 107 794 590 97 107 794 590 97 107 794Steam Piping 0 554 435 989 0 550 433 983 0 548 430 978Electrical Systems - HRSG's 28 34 86 148 28 34 87 149 28 34 86 148Steam Turbine & Accessories 10,917 628 2,531 14,076 10,817 625 2,516 13,958 10,799 624 2,513 13,936Steam Bypass System 938 46 179 1,163 938 46 179 1,163 938 46 179 1,163Electrical Systems - Steam Turbine 1,704 805 790 3,299 1,694 804 788 3,286 1,692 804 788 3,284Condenser & Accessories 6,332 935 2,241 9,508 6,332 932 2,239 9,503 6,332 932 2,239 9,503Circulating Water SystemWater Treatment System 373 104 597 1,074 374 104 598 1,076 374 104 598 1,076Waste Water Treatment System 154 23 87 264 154 23 87 264 154 23 88 265Auxiliary Boiler & AccessoriesBoiler Feed System 434 148 221 803 436 147 221 804 436 147 221 804Condensate System 51 73 107 231 51 73 107 231 51 73 107 231Buildings 0 3,108 3,468 6,576 0 3,077 3,433 6,510 0 3,071 3,426 6,497Fire Protection System 497 23 375 895 494 23 373 890 494 23 373 890Fuel Systems 103 120 181 404 103 120 181 404 103 120 181 404Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 515 201 716 0 517 201 718 0 517 201 718Station & Instrument Air System 345 122 114 581 345 121 114 580 345 121 114 580Closed Cooling Water System 160 69 136 365 159 69 136 364 159 69 136 364Cranes & Hoists 94 94 93 281 94 94 93 281 94 94 93 281Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 101 266 552 185 101 265 551 185 101 265 551Total Process Capital 77,057 10,080 18,751 105,888 76,982 10,049 18,709 105,740 76,910 10,042 18,682 105,634






Prepaid Royalties 0 0 0 Preproduction Costs 4,225,962 3,814,293 3,958,034 Inventory Capital 582,384 581,570 580,987 Initial Cost - Catalyst and Chemicals 0 0 0 Land 87,741 87,741 87,741 Capital Cost Adders -2,898,000 -2,898,000 -2,898,000




B-48


Site Phoenix Phoenix PhoenixTechnology Inlet Chilling Inlet Chilling Inlet ChillingOperating Percentage 8.3% 5.2%








C-1

C APPENDIX C – SUPPORTING DATA – DUCT FIRING –CHICAGO AREA


Appendix C – Supporting Data – Duct Firing – Chicago Area

C-2

Table C-1Duct Firing-Chicago: SOAPP-CT Case Input Data

Site Chicago Chicago Chicago Chicago Chicago

Technology Base Case Base Case Base Case Base Case Base CaseCase 1a Case 2a Case 3a Case 4a Equivalent-a

Variable Units Value Value Value Value ValueCT Model Number N/A GE 7FA GE 7FA GE 7FA GE 7FA GE 7FANumber of CT’s N/A 1 1 1 1 1Cycle Type N/A Combined Cycle





Duty Cycle/Mission N/A Cycling Base Load Cycling Base Load CyclingCT NOx Control, Natural Gas N/A Dry Low NOx





CT Natural Gas NOx Limit ppmvd @ 15%O2

9 9 9 9 9

CEM's Included N/A Yes Yes Yes Yes YesInlet Air Filtration N/A Pulse Type Pulse Type Pulse Type Pulse Type Pulse TypeInlet Air Cooling N/A No Cooling No Cooling No Cooling No Cooling No CoolingInlet Air Cooler Status N/A Not in Use Not in Use Not in Use Not in Use Not in UseAir Cooling Discharge Temp F n/a n/a n/a n/a n/aAir Cooling Discharge Temp C n/a n/a n/a n/a n/aEvaporative Cooler Effectiveness %CT Pressure Loss Method N/A User-Specified User-Specified User-Specified User-Specified User-SpecifiedCT Inlet Pressure Loss in H2O 3.75 3.75 3.75 3.75 3.75CT Inlet Pressure Loss kPa 0.93 0.93 0.93 0.93 0.93CT Exhaust Pressure Loss in H2O 14.00 14.00 14.00 14.00 14.00CT Exhaust Pressure Loss kPa 3.47 3.47 3.47 3.47 3.47Heater Selection N/A Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate HeaterDeaerator Selection N/A Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral DeaeratorNumber of Pressure Levels N/A Three Pressure Three Pressure Three Pressure Three Pressure Three PressureHP Steam Pressure psia 1,800 1,800 1,800 1,800 1,800IP Steam Pressure psia 490 490 490 480 490LP Steam Pressure psia 60 60 60 60 60Hot Reheat Pressure psia 490 490 490 480HP Steam Temp F 1,000 1,000 980 1,017 1,000IP Steam Temp F 600 600 521 600 600LP Steam Temp F Use default Use default Use default 462 Use defaultHP Pinch Point F 15 15 15 15 15IP Pinch Point F 15 13 15 12 15LP Pinch Point F 10 10 13 9 10HP Evap Approach F 20 20 20 19 20IP Evap Approach F 20 18 22 18 20LP Evap Approach F 13 13 17 11 13HP Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411IP Steam Pressure kPa 3,378 3,378 3,378 3,310 3,378LP Steam Pressure kPa 414 414 414 414 414Hot Reheat Pressure kPa 3,378 3,378 3,378 3,310 0HP Steam Temp C 537.8 537.8 526.7 547.2 537.8IP Steam Temp C 315.6 315.6 271.7 315.6 315.6LP Steam Temp C Use default Use default Use default 238.9 Use defaultHP Pinch Point C 8.3 8.3 8.3 8.3 8.3IP Pinch Point C 8.3 7.2 8.3 6.7 8.3



C-3

Table C-1Duct Firing-Chicago: SOAPP-CT Case Input Data (Continued)



Variable Units Value Value Value Value ValueLP Pinch Point C 5.6 5.6 7.2 5.0 5.6HP Evap Approach C 11.1 11.1 11.1 10.6 11.1IP Evap Approach C 11.1 10.0 12.2 10.0 11.1LP Evap Approach C 7.2 7.2 9.4 6.1 7.2Export All Available Flow N/A no no no no noInclude Duct Burners N/A no no no no noDuct Burner Performance Calc Method N/ADuct Burner Firing Temperature FDuct Burner Firing Temperature CDuct Burner Use N/ADuct Burner Fuel Capability N/ASCR Configuration N/A Anhydrous Ammonia





Include CO Oxidation Catalyst N/A No No No No NoSteam Turbine Arrangement N/A G-Reheat, 2 Casing, 1





ST Exhaust Configuration N/A Axial Axial Axial Axial AxialST Sizing Criteria N/A Excluding Max





Number of ST Extractions N/A 0 0 0 0 0ST Efficiency Method N/A User-Specified User-Specified User-Specified User-Specified User-SpecifiedHP ST Efficiency % 87% 87% 87% 87% 87%IP ST Efficiency % 89% 89% 89% 89% 89%LP ST Efficiency % 91% 91% 91% 91% 91%Include a Steam Bypass N/A Yes Yes Yes Yes YesCooling System Type N/A Wet Mech Draft Cooling

TwrWet Mech Draft CoolingTwr

Wet Mech Draft CoolingTwr



Cycles of Concentration N/A 5 5 5 5 5Condenser Pressure Calc Method N/A User-Specified User-Specified User-Specified User-Specified User-SpecifiedDesign Condenser Pressure in Hg 3.10 3.10 3.10 3.10 3.10Design Condenser Pressure kPa 10.50 10.50 10.50 10.50 10.50Condenser Tube Material N/A 304 SS 304 SS 304 SS 304 SS 304 SSCondenser Tube Cleaning N/A None None None None NoneCirc Water Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%Include an Auxiliary Boiler N/A no no no no noBoiler Feed Pump Sparing N/A 2 - 100% 2 - 100% 2 - 100% 2 - 100% 2 - 100%Boiler Feed Pump Design N/A HP Pump with IP





Condensate Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%HRSG Enclosures N/A No No No No NoPower Block Enclosure N/A Yes Yes Yes Yes YesWater Treatment Enclosure N/A Yes Yes Yes Yes YesWarehouse Included N/A No No No No NoInclude Fire Protection System? N/A Yes Yes Yes Yes YesFire Water Source N/A River/Lake River/Lake River/Lake River/Lake River/LakeSubstructure Requirements N/A Steel Piles Steel Piles Steel Piles Steel Piles Steel Piles



C-4




Variable Units Value Value Value Value ValueBypass Stack/Diverter Valve N/A No No No No NoMain Stack Height ft 150 150 150 150 150Main Stack Height m 45.7 45.7 45.7 45.7 45.7Switchyard Voltage kV 115 115 115 115 115Book Life years 20 20 20 20 20Tax Life years 15 15 15 15 15Commercial Operating Year N/A 2003 2003 2003 2003 2003Commercial Operating Month N/A January January January January JanuaryCapacity Factor % 60% 95% 57% 95% 58.8%Service Factor % 60% 95% 57% 95% 58.8%Equivalent Availability Factor % 95% 95% 95% 95% 95%Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5%Number of Starts Per Year N/A 40 40 40 40 40Tax Depreciation Method N/A MACRS MACRS MACRS MACRS MACRSCapital Cost Adders $ Adjust manually

SOAPP-CT Site Data Case 1a Case 2a Case 3a Case 4a Equivalent-aVariable Units Value Value Value Value ValueMax Ambient Dry Bulb Temp F 100 100 100 100 100Max Ambient Wet Bulb Temp F 76 76 76 76 76Min Ambient Dry Bulb Temp F -20 -20 -20 -20 -20Perf Point Dry Bulb Temp F 50.1 71.4 26.0 90.0 54.3Perf Point Wet Bulb Temp F 47.0 62.0 25.0 74.0 48.7Site Elevation ft 610 610 610 610 610Ambient Air Quality N/A Clean Clean Clean Clean CleanMax Daily Rainfall in/day 7 7 7 7 7.0Average Annual Rainfall in/yr 31 31 31 31 31.0Max Cooling Water Temp F 80 80 80 80 80.0Perf Point Cooling Water Temp F 60 60 60 60 60.0Max Ambient Dry Bulb Temp C 37.8 37.8 37.8 37.8 37.8Max Ambient Wet Bulb Temp C 24.4 24.4 24.4 24.4 24.4Min Ambient Dry Bulb Temp C -28.9 -28.9 -28.9 -28.9 -28.9Perf Point Dry Bulb Temp C 10.1 21.9 -3.4 32.2 12.4Perf Point Wet Bulb Temp C 8.3 16.7 -3.9 23.3 9.3Site Elevation m 185.9 185.9 185.9 185.9 185.9Max Daily Rainfall cm/day 17.36 17.36 17.36 17.36 17.36Average Annual Rainfall cm/yr 76.88 76.88 76.88 76.88 76.88Max Cooling Water Temp C 26.7 26.7 26.7 26.7 26.7Perf Point Cooling Water Temp C 15.6 15.6 15.6 15.6 15.6Heat Rejection Water Source N/A Lake Lake Lake Lake LakeUnit Makeup Water Source N/A Lake Lake Lake Lake LakeMakeup Raw Water Consump Charge $US/1,000 gal 0.50 0.50 0.50 0.50 Adjust manuallyMakeup Raw Water Consump Charge $US/ m3 0.13 0.13 0.13 0.13 Adjust manuallyCirculating Water Thermal Charge $US/MBtu 0.06 0.06 0.06 0.06 0.06



C-5




Variable Units Value Value Value Value ValueCirculating Water Thermal Charge $US/GJ 0.057 0.057 0.057 0.057 0.057UBC Seismic Zone N/A Zone 0 Zone 0 Zone 0 Zone 0 Zone 0Stack Natural Gas NOx Limit ppmvd @

15% O25 5 5 5 5

Ammonia Emission Limit ppmvd @15% O2

5 5 5 5 5

Construction Labor Index Value N/A 1 1 1 1 1Productivity Multiplier N/A 1 1 1 1 1General Facilities Capital % 2 2 2 2 2Eng. & Home Office Fees % 3 3 3 3 3Project Contingency % 5 5 5 5 5Process Contingency % 0 0 0 0 0Land Cost $US/acre 10,000 10,000 10,000 10,000 10000Ammonia (Delivered) $US/ton 180 180 180 180 180NaOH (Delivered) $US/ton 240 240 240 240 240H2SO4 (Delivered) $US/ton 300 300 300 300 300SCR Catalyst (Delivered) $US/ft3 280 280 280 280 280CO Catalyst (Delivered) $US/ft3 2,100.00 2,100.00 2,100.00 2,100.00 2100Other Waste Disposal $US/ton 12 12 12 12 12Catalyst Disposal $US/ft3 21 21 21 21 21Land Cost $US/ha 24,710 24,710 24,710 24,710 24,710Ammonia (Delivered) $US/t 198 198 198 198 198NaOH (Delivered) $US/t 265 265 265 265 265H2SO4 (Delivered) $US/t 331 331 331 331 331SCR Catalyst (Delivered) $US/m3 9,888 9,888 9,888 9,888 9,888CO Catalyst (Delivered) $US/m3 74,159 74,159 74,159 74,159 74,159Other Waste Disposal $US/t 13 13 13 13 13Catalyst Disposal $US/m3 742 742 742 742 742Non-operating Purchased Power Cost $US/MWh 45 45 45 45 45O&M Cost Method N/A WorkStation Calculated WorkStation Calculated WorkStation Calculated WorkStation Calculated WorkStation CalculatedO&M Labor Index Value N/A 1 1 1 1 1O&M Labor Productivity Multiplier N/A 1 1 1 1 1.0Maintenance Cost Adjustment N/A 1 1 1 1 1Operating Tax Rates %Insurance Rate % 0.5 0.5 0.5 0.5 0.5

SOAPP-CT Economic Data Case 1a Case 2a Case 3a Case 4a Equivalent-aVariable Units Value Value Value Value ValueIPP Loan Period years 15 15 15 15 15Evaluation Basis N/A Current Dollar Analysis Current Dollar Analysis Current Dollar Analysis Current Dollar Analysis Current Dollar AnalysisOwnership Type N/A Independent Power










IPP Equity Repayment Period years 20 20 20 20 20



C-6




Variable Units Value Value Value Value ValueIPP Loan Repay Method N/A Mortgage Style Mortgage Style Mortgage Style Mortgage Style Mortgage StyleInflation Rate %/yr 2 2 2 2 2Base Year N/A 2000 2000 2000 2000 2000Const Sched Calc Method N/A Workstation Calculated Workstation Calculated Workstation Calculated Workstation Calculated Workstation CalculatedCapital Costs Esc Rate %/yr 2 2 2 2 2O&M Costs Esc Rate %/yr 2 2 2 2 2Common Equity Fraction N/A 0.2 0.2 0.2 0.2 0.2Debt Fraction N/A 0.8 0.8 0.8 0.8 0.8Return on Common Equity % 18 18 18 18 18Return on Debt % 8 8 8 8 8Return on Debt During Construction % 9 9 9 9 9Investment Tax Credit Rate % 0 0 0 0 0Capacity Payments $US/kW-yr 0 0 0 0 0.00Energy Payments $US/MWh 35.00 45.00 40.00 67.79 42.33Energy Payments Escalation % 3.00 3.00 3.00 3.00 3.00

SOAPP-CT Fuel Data Case 1a Case 2a Case 3a Case 4a Equivalent-aVariable Units Value Value Value Value ValueFuel Price $US/MBtu 3.25 3.25 3.25 4.00 3.33Fuel Price $US/GJ 3.08 3.08 3.08 3.79 3.15Fuel Price Escalation % 3.50 3.50 3.50 3.50 3.50Natural Gas Supply Pressure psig 500 500 500 500 500



C-7



Technology Duct Firing Duct Firing Duct Firing Duct Firing Duct FiringCase 1 Case 2 Case 3 Case 4 Equivalent

Variable Units Value Value Value Value ValueCT Model Number N/A GE 7FA GE 7FA GE 7FA GE 7FA GE 7FANumber of CT’s N/A 1 1 1 1 1Cycle Type N/A Combined Cycle





Duty Cycle/Mission N/A Cycling Base Load Cycling Base Load CyclingCT NOx Control, Natural Gas N/A Dry Low NOx Combustors Dry Low NOx Combustors Dry Low NOx Combustors Dry Low NOx Combustors Dry Low NOx CombustorsCT Natural Gas NOx Limit ppmvd @

15% O29 9 9 9 9

CEM's Included N/A Yes Yes Yes Yes YesInlet Air Filtration N/A Pulse Type Pulse Type Pulse Type Pulse Type Pulse TypeInlet Air Cooling N/A none none none none noneInlet Air Cooler Status N/A Not in Use Not in Use Not in Use Not in Use Not in UseAir Cooling Discharge Temp F 47 63.0 25.0 75.0 54.2Air Cooling Discharge Temp C 8.3 17.2 -3.9 23.9 12.3Evaporative Cooler Effectiveness % 85 85 85 85 85CT Pressure Loss Method N/A User-Specified User-Specified User-Specified User-Specified User-SpecifiedCT Inlet Pressure Loss in H2O 3.75 3.75 3.75 3.75 3.75CT Inlet Pressure Loss kPa 0.93 0.93 0.93 0.93 0.93CT Exhaust Pressure Loss in H2O 15.50 15.50 15.50 15.50 15.50CT Exhaust Pressure Loss kPa 3.84 3.84 3.84 3.84 3.84Heater Selection N/A Condensate Heater Condensate Heater Condensate Heater Condensate Heater Condensate HeaterDeaerator Selection N/A Integral Deaerator Integral Deaerator Integral Deaerator Integral Deaerator Integral DeaeratorNumber of Pressure Levels N/A Three Pressure Three Pressure Three Pressure Three Pressure Three PressureHP Steam Pressure psia 1,800 1,800 1,800 1,800 1,766IP Steam Pressure psia 490 490 490 490 490LP Steam Pressure psia 60 60 60 60 60Hot Reheat Pressure psia 490 490 490 490HP Steam Temp F 1,000 1,000 980 1,010 1,000IP Steam Temp F 600 600 521 600 600LP Steam Temp F Use default Use default Use default Use default Use defaultHP Pinch Point F 15 15 15 15 65IP Pinch Point F 15 13 15 13 25LP Pinch Point F 10 10 13 10 15HP Evap Approach F 20 20 20 20 70IP Evap Approach F 20 18 22 20 70LP Evap Approach F 13 13 17 13 20HP Steam Pressure kPa 12,411 12,411 12,411 12,411 12,175IP Steam Pressure kPa 3,378 3,378 3,378 3,378 3,378LP Steam Pressure kPa 414 414 414 414 414Hot Reheat Pressure kPa 3,378 3,378 3,378 3,378 0HP Steam Temp C 537.8 537.8 526.7 543.3 537.8IP Steam Temp C 315.6 315.6 271.7 315.6 315.6LP Steam Temp C Use default Use default Use default Use default Use defaultHP Pinch Point C 8.3 8.3 8.3 8.3 36.1IP Pinch Point C 8.3 7.2 8.3 7.2 13.9LP Pinch Point C 5.6 5.6 7.2 5.6 8.3



C-8




Variable Units Value Value Value Value ValueHP Evap Approach C 11.1 11.1 11.1 11.1 38.9IP Evap Approach C 11.1 10.0 12.2 11.1 38.9LP Evap Approach C 7.2 7.2 9.4 7.2 11.1Export All Available Flow N/A no no no no noInclude Duct Burners N/A yes yes yes yes yesDuct Burner Performance Calc Method N/A Duct Burner HP Stm Flow

IncreaseDuct Burner HP Stm FlowIncrease

Duct Burner HP Stm FlowIncrease



Duct Burner Firing Temperature FDuct Burner Firing Temperature CDuct Burner Use N/A Full Time Full Time Full Time Full Time Full TimeDuct Burner Fuel Capability N/A Primary Fuel Only Primary Fuel Only Primary Fuel Only Primary Fuel Only Primary Fuel OnlySCR Configuration N/A Anhydrous Ammonia





Include CO Oxidation Catalyst N/A No No No No NoSteam Turbine Arrangement N/A G-Reheat, 2 Casing, 1





ST Exhaust Configuration N/A Axial Axial Axial Axial AxialST Sizing Criteria N/A Excluding Max





Number of ST Extractions N/A 0 0 0 0 0ST Efficiency Method N/A User-Specified User-Specified User-Specified User-Specified User-SpecifiedHP ST Efficiency % 87% 87% 87% 87% 87%IP ST Efficiency % 89% 89% 89% 89% 89%LP ST Efficiency % 91% 91% 91% 91% 91%Include a Steam Bypass N/A Yes Yes Yes Yes YesCooling System Type N/A Wet Mech Draft Cooling

TwrWet Mech Draft CoolingTwr




Cycles of Concentration N/A 5 5 5 5 5Condenser Pressure Calc Method N/A User-Specified User-Specified User-Specified User-Specified User-SpecifiedDesign Condenser Pressure in Hg 3.10 3.10 3.10 3.10 3.10Design Condenser Pressure kPa 10.50 10.50 10.50 10.50 10.50Condenser Tube Material N/A 304 SS 304 SS 304 SS 304 SS 304 SSCondenser Tube Cleaning N/A None None None None NoneCirc Water Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%Include an Auxiliary Boiler N/A no no no no noBoiler Feed Pump Sparing N/A 2 - 100% 2 - 100% 2 - 100% 2 - 100% 2 - 100%Boiler Feed Pump Design N/A HP Pump with IP Takeoff HP Pump with IP Takeoff HP Pump with IP Takeoff HP Pump with IP Takeoff HP Pump with IP TakeoffCondensate Pump Sparing N/A 2 - 50% 2 - 50% 2 - 50% 2 - 50% 2 - 50%HRSG Enclosures N/A No No No No NoPower Block Enclosure N/A Yes Yes Yes Yes YesWater Treatment Enclosure N/A Yes Yes Yes Yes YesWarehouse Included N/A No No No No NoInclude Fire Protection System? N/A Yes Yes Yes Yes YesFire Water Source N/A River/Lake River/Lake River/Lake River/Lake River/LakeSubstructure Requirements N/A Steel Piles Steel Piles Steel Piles Steel Piles Steel PilesBypass Stack/Diverter Valve N/A No No No No No



C-9




Variable Units Value Value Value Value ValueMain Stack Height ft 150 150 150 150 150Main Stack Height m 45.7 45.7 45.7 45.7 45.7Switchyard Voltage kV 115 115 115 115 115Book Life years 20 20 20 20 20Tax Life years 15 15 15 15 15Commercial Operating Year N/A 2003 2003 2003 2003 2003Commercial Operating Month N/A January January January January JanuaryCapacity Factor % 60% 95% 57% 95% 58.8%Service Factor % 60% 95% 57% 95% 58.8%Equivalent Availability Factor % 95% 95% 95% 95% 95%Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5%Number of Starts Per Year N/A 40 40 40 40 40Tax Depreciation Method N/A MACRS MACRS MACRS MACRS MACRSCapital Cost Adders $ Adjust manually

SOAPP-CT Site Data Case 1 Case 2 Case 3 Case 4 EquivalentVariable Units Value Value Value Value ValueMax Ambient Dry Bulb Temp F 100 100 100 100 100Max Ambient Wet Bulb Temp F 76 76 76 76 76Min Ambient Dry Bulb Temp F -20 -20 -20 -20 -20Perf Point Dry Bulb Temp F 50.1 71.4 26.0 90.0 54.3Perf Point Wet Bulb Temp F 47.0 62.0 25.0 74.0 48.7Site Elevation ft 610 610 610 610 610Ambient Air Quality N/A Clean Clean Clean Clean CleanMax Daily Rainfall in/day 7 7 7 7 7.0Average Annual Rainfall in/yr 31 31 31 31 31.0Max Cooling Water Temp F 80 80 80 80 80.0Perf Point Cooling Water Temp F 60 60 60 60 60.0Max Ambient Dry Bulb Temp C 37.8 37.8 37.8 37.8 37.8Max Ambient Wet Bulb Temp C 24.4 24.4 24.4 24.4 24.4Min Ambient Dry Bulb Temp C -28.9 -28.9 -28.9 -28.9 -28.9Perf Point Dry Bulb Temp C 10.1 21.9 -3.4 32.2 12.4Perf Point Wet Bulb Temp C 8.3 16.7 -3.9 23.3 9.3Site Elevation m 185.9 185.9 185.9 185.9 185.9Max Daily Rainfall cm/day 17.36 17.36 17.36 17.36 17.36Average Annual Rainfall cm/yr 76.88 76.88 76.88 76.88 76.88Max Cooling Water Temp C 26.7 26.7 26.7 26.7 26.7Perf Point Cooling Water Temp C 15.6 15.6 15.6 15.6 15.6Heat Rejection Water Source N/A Lake Lake Lake Lake LakeUnit Makeup Water Source N/A Lake Lake Lake Lake LakeMakeup Raw Water Consump Charge $US/1,000 gal 0.50 0.50 0.50 0.50 Adjust manuallyMakeup Raw Water Consump Charge $US/ m3 0.13 0.13 0.13 0.13 Adjust manuallyCirculating Water Thermal Charge $US/MBtu 0.06 0.06 0.06 0.06 0.06Circulating Water Thermal Charge $US/GJ 0.057 0.057 0.057 0.057 0.057UBC Seismic Zone N/A Zone 0 Zone 0 Zone 0 Zone 0 Zone 0



C-10




Variable Units Value Value Value Value ValueStack Natural Gas NOx Limit ppmvd @

15% O25 5 5 5 5

Ammonia Emission Limit ppmvd @15% O2

5 5 5 5 5

Construction Labor Index Value N/A 1 1 1 1 1Productivity Multiplier N/A 1 1 1 1 1General Facilities Capital % 2 2 2 2 2Eng. & Home Office Fees % 3 3 3 3 3Project Contingency % 5 5 5 5 5Process Contingency % 0 0 0 0 0Land Cost $US/acre 10,000 10,000 10,000 10,000 10000Ammonia (Delivered) $US/ton 180 180 180 180 180NaOH (Delivered) $US/ton 240 240 240 240 240H2SO4 (Delivered) $US/ton 300 300 300 300 300SCR Catalyst (Delivered) $US/ft3 280 280 280 280 280CO Catalyst (Delivered) $US/ft3 2,100.00 2,100.00 2,100.00 2,100.00 2100Other Waste Disposal $US/ton 12 12 12 12 12Catalyst Disposal $US/ft3 21 21 21 21 21Land Cost $US/ha 24,710 24,710 24,710 24,710 24,710Ammonia (Delivered) $US/t 198 198 198 198 198NaOH (Delivered) $US/t 265 265 265 265 265H2SO4 (Delivered) $US/t 331 331 331 331 331SCR Catalyst (Delivered) $US/m3 9,888 9,888 9,888 9,888 9,888CO Catalyst (Delivered) $US/m3 74,159 74,159 74,159 74,159 74,159Other Waste Disposal $US/t 13 13 13 13 13Catalyst Disposal $US/m3 742 742 742 742 742Non-operating Purchased Power Cost $US/MWh 45 45 45 45 45O&M Cost Method N/A WorkStation Calculated WorkStation Calculated WorkStation Calculated WorkStation Calculated WorkStation CalculatedO&M Labor Index Value N/A 1 1 1 1 1O&M Labor Productivity Multiplier N/A 1 1 1 1 1.2Maintenance Cost Adjustment N/A 1 1 1 1 1Operating Tax Rates %Insurance Rate % 0.5 0.5 0.5 0.5 0.5

SOAPP-CT Economic Data Case 1 Case 2 Case 3 Case 4 EquivalentVariable Units Value Value Value Value ValueIPP Loan Period years 15 15 15 15 15Evaluation Basis N/A Current Dollar Analysis Current Dollar Analysis Current Dollar Analysis Current Dollar Analysis Current Dollar AnalysisOwnership Type N/A Independent Power





IPP Analysis Method N/A Solve for Return on Equity Solve for Return on Equity Solve for Return on Equity Solve for Return on Equity Solve for Return on EquityIPP Equity Repayment Period years 20 20 20 20 20IPP Loan Repay Method N/A Mortgage Style Mortgage Style Mortgage Style Mortgage Style Mortgage StyleInflation Rate %/yr 2 2 2 2 2Base Year N/A 2000 2000 2000 2000 2000Const Sched Calc Method N/A Workstation Calculated Workstation Calculated Workstation Calculated Workstation Calculated Workstation Calculated



C-11




Variable Units Value Value Value Value ValueCapital Costs Esc Rate %/yr 2 2 2 2 2O&M Costs Esc Rate %/yr 2 2 2 2 2Common Equity Fraction N/A 0.2 0.2 0.2 0.2 0.2Debt Fraction N/A 0.8 0.8 0.8 0.8 0.8Return on Common Equity % 18 18 18 18 18Return on Debt % 8 8 8 8 8Return on Debt During Construction % 9 9 9 9 9Investment Tax Credit Rate % 0 0 0 0 0Capacity Payments $US/kW-yr 0 0 0 0 0.00Energy Payments $US/MWh 35.00 45.00 40.00 67.79 42.33Energy Payments Escalation % 3.00 3.00 3.00 3.00 3.00

SOAPP-CT Fuel Data Case 1 Case 2 Case 3 Case 4 EquivalentVariable Units Value Value Value Value ValueFuel Price $US/MBtu 3.25 3.25 3.25 4.00 3.33Fuel Price $US/GJ 3.08 3.08 3.08 3.79 3.15Fuel Price Escalation % 3.50 3.50 3.50 3.50 3.50Natural Gas Supply Pressure psig 500 500 500 500 500



C-12

Table C-2Duct Firing-Chicago: SOAPP-CT Case Results

Site Chicago Chicago Chicago Chicago ChicagoTechnology Base Case Base Case Base Case Base Case Base CaseOperating Percent: 38.0% 27.9% 23.9% 10.2%

CASE 1a CASE 2a CASE 3a CASE 4a SOAPP Equivalent -aPLANT DESIGN BASISAmbient Air Temperature F 50 71 26 90 54.0Ambient Air Temperature C 10.0 21.7 -3.3 32.2 12.2Site Elevation Above MSL ft 610 610 610 610 610Site Elevation Above MSL m 186 186 186 186 186Cycle Type Combined Cycle





CogenerationPrimary Fuel Type Natural Gas Natural Gas Natural Gas Natural Gas Natural GasCT NOx Control, Natural Gas Dry Low NOx





Inlet Air Cooling SystemCT Air Precooler Discharge Temperature F 50 71 26 90 54.0CT Air Precooler Discharge Temperature C 10.0 21.7 -3.3 32.2 12.2Cooling System Type Wet Mech Draft

Cooling TwrWet Mech Draft




Cooling TwrSCR Configuration Anhydrous Ammonia

InjectionAnhydrous Ammonia




InjectionDuct Burner UseCOMBUSTION TURBINE DATACombustion Turbine Model GE PG7241(FA)-60 Hz GE PG7241(FA)-60 Hz GE PG7241(FA)-60 Hz GE PG7241(FA)-60 Hz GE PG7241(FA)-60 HzNumber of CT's Operating 1 1 1 1 1CT Gross Output, per CT kW 168,815 157,952 176,637 145,680 167,442CT Heat Input (HHV), per CT MBtu/h 1,772.76 1,683.92 1,845.13 1,583.95 1,760CT Heat Input (HHV), per CT MW 519.54 493.51 540.75 464.21 515.83CT Exhaust Flow per CT lb/h 3,516,114 3,372,796 3,666,605 3,239,307 3,489,887CT Exhaust Flow per CT kg/hr 1,594,899 1,529,890 1,663,161 1,469,340 1,583,002CT Exhaust Temperature F 1,117 1,133 1,094 1,145 1,121CT Exhaust Temperature C 602.8 611.7 590.0 618.3 605.0CT NOx Emissions ppmvd @

15% O29 9 9 9 9

HRSG DATA (per HRSG)HRSG Gas Inlet Temperature F 1,114 1,130 1,091 1,142 1,118HRSG Gas Inlet Temperature C 601.1 610.0 588.3 616.7 603.3HP Steam Flow at HRSG lb/h 413,748 412,330 412,781 401,682 414,513HP Steam Flow at HRSG kg/hr 187,675 187,032 187,236 182,202 188,022HP Steam Pressure at HRSG psia 1,849 1,849 1,849 1,849 1,849HP Steam Pressure at HRSG kPa 12,748 12,748 12,748 12,748 12,748HP Steam Temperature at HRSG F 1,005 1,005 985 1,022 1,005HP Steam Temperature at HRSG C 540.6 540.6 529.4 550.0 540.6Duct Burner Heat Input (HHV) MBtu/hDuct Burner Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00HP Export Steam FlowHot Reheat Steam Flow at HRSG lb/h 489,852 482,886 496,095 468,741 489,300Hot Reheat Steam Flow at HRSG kg/hr 222,195 219,036 225,027 212,620 221,945Hot Reheat Steam Pressure at HRSG psia 504 504 504 494 504Hot Reheat Steam Pressure at HRSG kPa 3,475 3,475 3,475 3,406 3,475



C-13

Table C-2Duct Firing-Chicago: SOAPP-CT Case Results (Continued)


CASE 1a CASE 2a CASE 3a CASE 4a SOAPP Equivalent -aHot Reheat Steam Temperature at HRSG F 1,005 1,005 985 1,022 1,005Hot Reheat Steam Temperature at HRSG C 540.6 540.6 529.4 550.0 540.6IP Steam Flow at HRSG lb/h 76,104 70,556 83,314 67,059 74,787IP Steam Flow at HRSG kg/hr 34,521 32,004 37,791 30,418 33,923IP Steam Pressure at HRSG psia 514 514 514 504 514IP Steam Pressure at HRSG kPa 3,544 3,544 3,544 3,475 3,544IP Steam Temperature at HRSG F 530 530 523 530 530IP Steam Temperature at HRSG C 276.7 276.7 272.8 276.7 276.7IP Export Steam FlowLP Steam Flow at HRSG lb/h 66,731 60,349 69,507 57,236 65,568LP Steam Flow at HRSG kg/hr 30,269 27,374 31,528 25,962 29,741LP Steam Pressure at HRSG psia 64 64 64 64 64LP Steam Pressure at HRSG kPa 441 441 441 441 441LP Steam Temperature at HRSG F 462 462 462 464 462LP Steam Temperature at HRSG C 238.9 238.9 238.9 240.0 238.9LP Export Steam FlowStack Exhaust Flow lb/h 3,516,114 3,372,796 3,666,605 3,239,307 3,489,887Stack Exhaust Flow kg/hr 1,594,899 1,529,890 1,663,161 1,469,340 1,583,002Stack Exhaust Temperature F 198 200 200 201 198Stack Exhaust Temperature C 92.2 93.3 93.3 93.9 92.2STEAM TURBINE DATAThrottle Steam Flow at ST lb/h 413,748 412,330 412,781 401,682 414,513Throttle Steam Flow at ST kg/hr 187,675 187,032 187,236 182,202 188,022Throttle Steam Pressure psia 1,800 1,800 1,800 1,800 1,800Throttle Steam Pressure kPa 12,411 12,411 12,411 12,411 12,411Throttle Steam Temperature F 1,000 1,000 980 1,017 1,000Throttle Steam Temperature C 537.8 537.8 526.7 547.2 537.8Hot Reheat Steam Flow at ST lb/h 489,852 482,886 496,095 468,741 489,300Hot Reheat Steam Flow at ST kg/hr 0 0 0 0 0HP ST Efficiency % 87 87 87 87 87IP ST Efficiency % 89 89 89 89 89LP ST Efficiency % 91 91 91 91 91Turbine Backpressure in Hg 2.20 2.57 1.83 3.00 2.24Turbine Backpressure kPa 7.45 8.70 6.20 10.16 7.58Gross ST Output kW 91,515 88,748 92,837 86,004 91,237PLANT DATAGross Plant Output kW 260,330 246,700 269,474 231,684 258,679Auxiliary Power kW 4,495 4,387 4,566 4,239 4,484Net Plant Output kW 255,835 242,313 264,908 227,445 254,195Total Plant Heat Input (HHV) MBtu/h 1,773 1,684 1,845 1,584 1,760Total Plant Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00Net Plant Heat Rate (HHV) at 100% Load Btu/kWh 6,929 6,949 6,965 6,964 6,924Net Plant Heat Rate (HHV) at 100% Load kJ/kwh 7,311 7,332 7,349 7,348 7,306Net Plant Heat Rate (LHV) at 100% Load Btu/kWh 6,243 6,261 6,275 6,274 6,238Net Plant Heat Rate (LHV) at 100% Load kJ/kwh 11,100 11,132 11,157 11,156 11,092



C-14



CASE 1a CASE 2a CASE 3a CASE 4a SOAPP Equivalent -aSOAPP Output Data - KEY DESIGN DATA

CASE 1a CASE 2a CASE 3a CASE 4a SOAPP Equivalent -aHP Pinch Point F 15 15 15 15 15IP Pinch Point F 15 13 15 12 15LP Pinch Point F 10 10 13 9 10HP Evap Approach F 20 20 20 19 20IP Evap Approach F 20 18 22 18 20LP Evap Approach F 13 13 17 11 13HP Pinch Point C 8.3 8.3 8.3 8.3 8.3IP Pinch Point C 8.3 7.2 8.3 6.7 8.3LP Pinch Point C 5.6 5.6 7.2 5.0 5.6HP Evap Approach C 11.1 11.1 11.1 10.6 11.1IP Evap Approach C 11.1 10.0 12.2 10.0 11.1LP Evap Approach C 7.2 7.2 9.4 6.1 7.2Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5%

SOAPP Output Data - SURFACE AREASCASE 1a CASE 2a CASE 3a CASE 4a SOAPP Equivalent -a

HPECON1 SA ft^2 153,845 157,529 150,967 162,093 154,776HPECON2 SA ft^2 132,636 133,380 130,285 129,486 133,361HPECON3 SA ft^2 0 0 0 0 0HPEVAP SA ft^2 332,381 323,255 341,024 311,801 330,985HPSHT SA ft^2 145,724 134,597 145,923 136,221 143,206IPECON SA ft^2 27,419 26,870 28,162 26,658 27,071IPEVAP SA ft^2 192,001 194,050 205,195 192,671 189,641IPSHT SA ft^2 4,178 3,871 4,067 3,727 4,105LPEVAP SA ft^2 250,898 236,365 233,908 235,223 248,268LPSHT SA ft^2 4,581 4,263 4,668 4,233 4,522LPECON SA ft^2 254,402 247,125 242,400 249,085 254,049REHT SA ft^2 80,469 72,428 80,687 74,370 78,566HPECON1 SA m^2 14,293 14,635 14,025 15,059 14,379HPECON2 SA m^2 12,322 12,391 12,104 12,030 12,390HPECON3 SA m^2 0 0 0 0 0HPEVAP SA m^2 30,879 30,031 31,682 28,967 30,750HPSHT SA m^2 13,538 12,504 13,557 12,655 13,304IPECON SA m^2 2,547 2,496 2,616 2,477 2,515IPEVAP SA m^2 17,837 18,028 19,063 17,900 17,618IPSHT SA m^2 388 360 378 346 381LPEVAP SA m^2 23,309 21,959 21,731 21,853 23,065LPSHT SA m^2 426 396 434 393 420LPECON SA m^2 23,635 22,959 22,520 23,141 23,602REHT SA m^2 7,476 6,729 7,496 6,909 7,299



C-15


Site Chicago Chicago Chicago Chicago ChicagoTechnology Duct Firing Duct Firing Duct Firing Duct Firing Duct FiringOperating Percent: 38.0% 27.9% 23.9% 10.2%

CASE 1 CASE 2 CASE 3 CASE 4 SOAPP EquivalentPLANT DESIGN BASISAmbient Air Temperature F 50 71 26 90 54.0Ambient Air Temperature C 10.0 21.7 -3.3 32.2 12.2Site Elevation Above MSL ft 610 610 610 610 610Site Elevation Above MSL m 186 186 186 186 186Cycle Type Combined Cycle





CogenerationPrimary Fuel Type Natural Gas Natural Gas Natural Gas Natural Gas Natural GasCT NOx Control, Natural Gas Dry Low NOx Combustors Dry Low NOx Combustors Dry Low NOx Combustors Dry Low NOx Combustors Dry Low NOx CombustorsInlet Air Cooling SystemCT Air Precooler Discharge Temperature F 50 71 26 90 54.0CT Air Precooler Discharge Temperature C 10.0 21.7 -3.3 32.2 12.2Cooling System Type Wet Mech Draft





Cooling TwrSCR Configuration Anhydrous Ammonia





InjectionDuct Burner Use Full-Time Full-Time Full-Time Full-Time Full-TimeCOMBUSTION TURBINE DATACombustion Turbine Model GE PG7241(FA)-60 Hz GE PG7241(FA)-60 Hz GE PG7241(FA)-60 Hz GE PG7241(FA)-60 Hz GE PG7241(FA)-60 HzNumber of CT's Operating 1 1 1 1 1CT Gross Output, per CT kW 168,456 157,616 176,262 145,371 167,086CT Heat Input (HHV), per CT MBtu/h 1,772.66 1,683.83 1,845.03 1,583.87 1,760.01CT Heat Input (HHV), per CT MW 519.51 493.48 540.72 464.18 515.81CT Exhaust Flow per CT lb/h 3,516,114 3,372,796 3,666,605 3,239,307 3,489,887CT Exhaust Flow per CT kg/hr 1,594,899 1,529,890 1,663,161 1,469,340 1,583,002CT Exhaust Temperature F 1,118 1,134 1,096 1,146 1,122CT Exhaust Temperature C 603.3 612.2 591.1 618.9 605.6CT NOx Emissions ppmvd @

15% O29 9 9 9 9

HRSG DATA (per HRSG)HRSG Gas Inlet Temperature F 1,511 1,516 1,497 1,443 1,511HRSG Gas Inlet Temperature C 821.7 824.4 813.9 783.9 821.7HP Steam Flow at HRSG lb/h 675,593 652,557 691,251 684,798 670,557HP Steam Flow at HRSG kg/hr 306,447 295,998 313,549 310,622 304,163HP Steam Pressure at HRSG psia 1,849 1,849 1,849 1,514 1,849HP Steam Pressure at HRSG kPa 12,748 12,748 12,748 10,439 12,748HP Steam Temperature at HRSG F 1,005 1,005 1,005 1,005 1,005HP Steam Temperature at HRSG C 540.6 540.6 540.6 540.6 540.6Duct Burner Heat Input (HHV) MBtu/h 412.42 385 439.03 288.09 405.46Duct Burner Heat Input (HHV) MW 120.87 112.97 128.67 84.43 118.83HP Export Steam FlowHot Reheat Steam Flow at HRSG lb/h 796,943 768,480 819,121 699,301 790,999Hot Reheat Steam Flow at HRSG kg/hr 361,491 348,580 371,551 317,201 358,795Hot Reheat Steam Pressure at HRSG psia 504 504 504 382 504Hot Reheat Steam Pressure at HRSG kPa 3,475 3,475 3,475 2,634 3,475Hot Reheat Steam Temperature at HRSG F 1,005 1,005 1,005 1,005 1,005



C-16



CASE 1 CASE 2 CASE 3 CASE 4 SOAPP EquivalentHot Reheat Steam Temperature at HRSG C 540.6 540.6 540.6 540.6 540.6IP Steam Flow at HRSG lb/h 121,350 115,923 127,871 14,503 120,442IP Steam Flow at HRSG kg/hr 55,044 52,582 58,002 6,579 54,632IP Steam Pressure at HRSG psia 514 514 514 464 514IP Steam Pressure at HRSG kPa 3,544 3,544 3,544 3,199 3,544IP Steam Temperature at HRSG F 580 580 580 528 580IP Steam Temperature at HRSG C 304.4 304.4 304.4 275.6 304.4IP Export Steam FlowLP Steam Flow at HRSG lb/h 0 0 0 982 0LP Steam Flow at HRSG kg/hr 0 0 0 445 0LP Steam Pressure at HRSG psia 88 88 88 79 88LP Steam Pressure at HRSG kPa 607 607 607 545 607LP Steam Temperature at HRSG F 319 319 319 458 319LP Steam Temperature at HRSG C 159.4 159.4 159.4 236.7 159.4LP Export Steam FlowStack Exhaust Flow lb/h 3,535,790 3,391,186 3,687,551 3,253,052 3,509,232Stack Exhaust Flow kg/hr 1,603,824 1,538,232 1,672,662 1,475,575 1,591,777Stack Exhaust Temperature F 201 206 199 170 202Stack Exhaust Temperature C 93.9 96.7 92.8 76.7 94.4STEAM TURBINE DATAThrottle Steam Flow at ST lb/h 675,593 652,557 691,251 684,798 670,557Throttle Steam Flow at ST kg/hr 306,447 295,998 313,549 310,622 304,163Throttle Steam Pressure psia 1,800 1,800 1,800 1,465 1,800Throttle Steam Pressure kPa 12,411 12,411 12,411 10,101 12,411Throttle Steam Temperature F 1,000 1,000 1,000 1,000 1,000Throttle Steam Temperature C 537.8 537.8 537.8 537.8 537.8Hot Reheat Steam Flow at ST lb/h 796,943 768,480 819,121 699,301 790,999Hot Reheat Steam Flow at ST kg/hr 0 0 0 0 0HP ST Efficiency % 87 87 87 87 87IP ST Efficiency % 89 89 89 89 89LP ST Efficiency % 91 91 91 91 91Turbine Backpressure in Hg 2.20 2.57 1.83 2.80 2.23Turbine Backpressure kPa 7.45 8.70 6.20 9.48 7.55Gross ST Output kW 141,022 134,271 146,982 124,088 139,774PLANT DATAGross Plant Output kW 309,479 291,887 323,244 269,459 306,859Auxiliary Power kW 6,104 5,920 6,233 5,410 6,071Net Plant Output kW 303,374 285,967 317,011 264,049 300,788Total Plant Heat Input (HHV) MBtu/h 2,185 2,069 2,284 1,872 2,165Total Plant Heat Input (HHV) MW 0.00 0.00 0.00 0.00 0.00Net Plant Heat Rate (HHV) at 100% Load Btu/kWh 7,203 7,236 7,205 7,089 7,199Net Plant Heat Rate (HHV) at 100% Load kJ/kwh 7,600 7,635 7,602 7,480 7,596Net Plant Heat Rate (LHV) at 100% Load Btu/kWh 6,489 6,519 6,491 6,387 6,486Net Plant Heat Rate (LHV) at 100% Load kJ/kwh 11,538 11,592 11,542 11,357 11,533



C-17



CASE 1 CASE 2 CASE 3 CASE 4 SOAPP EquivalentSOAPP Output Data - KEY DESIGN DATA

CASE 1 CASE 2 CASE 3 CASE 4 SOAPP EquivalentHP Pinch Point F 65 65 65 65 65IP Pinch Point F 25 25 25 25 25LP Pinch Point F 15 15 17 15 15HP Evap Approach F 70 70 70 70 70IP Evap Approach F 70 70 70 70 70LP Evap Approach F 20 20 20 20 20HP Pinch Point C 36.1 36.1 36.1 36.1 36.1IP Pinch Point C 13.9 13.9 13.9 13.9 13.9LP Pinch Point C 8.3 8.3 9.4 8.3 8.3HP Evap Approach C 38.9 38.9 38.9 38.9 38.9IP Evap Approach C 38.9 38.9 38.9 38.9 38.9LP Evap Approach C 11.1 11.1 11.1 11.1 11.1Output Degradation Factor %/yr 1.0% 1.0% 1.0% 1.0% 1.0%Heat Rate Degradation Factor %/yr 0.5% 0.5% 0.5% 0.5% 0.5%

SOAPP Output Data - SURFACE AREASCASE 1 CASE 2 CASE 3 CASE 4 SOAPP Equivalent

HPECON1 SA ft^2 63,869 62,640 63,223 62,054 63,397HPECON2 SA ft^2 544,464 570,272 473,753 633,038 540,547HPECON3 SA ft^2 0 0 0 0 0HPEVAP SA ft^2 253,824 244,462 262,527 235,990 251,930HPSHT SA ft^2 85,011 81,489 88,858 78,096 84,375IPECON SA ft^2 25,712 24,990 25,985 24,503 25,521IPEVAP SA ft^2 195,702 187,400 205,022 179,440 194,237IPSHT SA ft^2 9,660 9,226 10,183 8,801 9,588LPEVAP SA ft^2 90,945 84,034 88,099 75,759 90,255LPSHT SA ft^2 3,338 3,443 3,727 3,455 3,378LPECON SA ft^2 166,518 155,094 172,523 145,063 164,622REHT SA ft^2 40,892 39,098 42,963 37,343 40,586HPECON1 SA m^2 5,934 5,819 5,874 5,765 5,890HPECON2 SA m^2 50,582 52,980 44,013 58,811 50,218HPECON3 SA m^2 0 0 0 0 0HPEVAP SA m^2 23,581 22,711 24,390 21,924 23,405HPSHT SA m^2 7,898 7,571 8,255 7,255 7,839IPECON SA m^2 2,389 2,322 2,414 2,276 2,371IPEVAP SA m^2 18,181 17,410 19,047 16,671 18,045IPSHT SA m^2 897 857 946 818 891LPEVAP SA m^2 8,449 7,807 8,185 7,038 8,385LPSHT SA m^2 310 320 346 321 314LPECON SA m^2 15,470 14,409 16,028 13,477 15,294REHT SA m^2 3,799 3,632 3,991 3,469 3,771



C-18

Table C-3Duct Firing-Chicago: SOAPP-CT Estimated Costs

Site Chicago Chicago Chicago ChicagoTechnology Base Case Base Case Base Case Base CaseOperating Percentage 38.0% 27.9% 23.9% 10.2%

CASE 1a CASE 2a CASE 3aDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor To talCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 499 68 255 822 479 67 248 794 520 70 262 852 461 65 241 767Inlet Air Precooling SystemElectrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 1,143 13 328 1,484 1,110 13 319 1,442 1,089 14 314 1,417 1,119 12 321 1,452HRSG's & Accessories 9,213 98 2,004 11,315 8,982 96 1,929 11,007 9,238 98 2,005 11,341 8,915 95 1,909 10,919Deaeration System 66 33 77 176 66 33 77 176 66 34 78 178 65 32 76 173Duct Burner SystemPost Combustion Emissions Controls 602 106 110 818 587 104 109 800 618 107 112 837 572 102 107 781Steam Piping 0 568 440 1,008 0 547 430 977 0 568 421 989 0 538 444 982Electrical Systems - HRSG's 28 35 88 151 28 34 86 148 28 35 88 151 28 34 86 148Steam Turbine & Accessories 11,261 640 2,581 14,482 11,045 633 2,550 14,228 11,377 644 2,597 14,618 10,821 625 2,517 13,963Steam Bypass System 938 46 179 1,163 938 46 179 1,163 938 46 178 1,162 938 46 180 1,164Electrical Systems - Steam Turbine 1,740 808 796 3,344 1,718 806 792 3,316 1,752 809 798 3,359 1,694 804 788 3,286Condenser & Accessories 1,102 23 290 1,415 1,102 23 290 1,415 1,103 23 290 1,416 1,102 23 290 1,415Circulating Water System 1,332 1,186 1,636 4,154 1,331 1,185 1,635 4,151 1,334 1,187 1,637 4,158 1,330 1,185 1,634 4,149Water Treatment System 332 93 533 958 328 92 527 947 335 94 537 966 323 91 519 933Waste Water Treatment System 152 22 84 258 150 22 84 256 153 22 85 260 148 21 83 252Auxiliary Boiler & AccessoriesBoiler Feed System 443 152 226 821 443 148 224 815 442 155 226 823 441 143 221 805Condensate System 51 75 108 234 51 73 107 231 51 76 109 236 51 71 106 228Buildings 0 3,298 3,686 6,984 0 3,056 3,409 6,465 0 3,462 3,874 7,336 0 2,795 3,112 5,907Fire Protection System 511 23 386 920 493 23 372 888 524 23 396 943 472 22 356 850Fuel Systems 106 122 183 411 106 122 183 411 106 122 183 411 106 122 183 411Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 516 201 717 0 507 197 704 0 528 205 733 0 498 194 692Station & Instrument Air System 346 125 115 586 346 121 114 581 346 128 116 590 346 116 113 575Closed Cooling Water System 164 70 138 372 158 69 136 363 169 70 140 379 151 68 133 352Cranes & Hoists 94 94 93 281 94 93 93 280 95 95 94 284 93 93 92 278Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 185 103 271 559 185 101 265 551 185 104 275 564 184 99 257 540Total Process Capital 72,388 9,402 17,558 99,348 71,820 9,099 17,105 98,024 72,549 9,599 17,770 99,918 71,440 8,785 16,712 96,937










C-19

Table C-3Duct Firing-Chicago: SOAPP-CT Estimated Costs (Continued)

Site Chicago Chicago Chicago ChicagoTechnology Base Case Base Case Base Case Base CaseOperating Percentage 38.0% 27.9% 23.9% 10.2%

CASE 1a CASE 2a CASE 3aDescription (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor To talFixed O + M Direct Operating Labor 393,271 779,433 393,271 779,433 - Number of Operating Staff 6 13 6 13 Direct Maintenance Labor 330,847 374,544 330,847 374,544 - Number of Maintenance Staff 5 6 5 6 Annual Services, Materials, & Purchased Power - Annual O&M Services & Materials 228,311 222,936 231,954 217,148 - Non-operating Purchased Power 41,048 4,862 45,677 4,566 Indirect Labor Costs - Benefits 211,201 353,822 211,201 353,822 - Home Office Costs 195,595 228,888 195,595 228,888


Variable O+M Scheduled Maintenance Parts & Materials - CT Inspection/Overhaul 1,273,811 1,995,579 1,212,402 1,995,579 - HRSG Inspection/Refurbish 99,399 153,380 94,164 152,482 - ST Inspection/Overhaul 104,820 162,048 100,706 158,663 - BOP Refurbish 59,722 93,025 57,675 91,540 Scheduled Maintenance Labor - CT Inspection/Overhaul 50,952 79,823 48,496 79,823 - HRSG Inspection/Refurbish 29,819 46,014 28,249 45,744 - ST Inspection/Overhaul 10,482 16,204 10,070 15,866 - BOP Refurbish 13,100 20,361 12,680 19,995 Unscheduled Maintenance Allowance 82,105 128,321 78,222 127,984 Catalyst Replacement - SCR Catalyst Materials & Labor 37,728 57,390 37,287 55,306 - CO Catalyst Materials & Labor 0 0 0 0 Other Consumables - Raw water 202,791 319,479 193,386 317,846 - Circulating water 0 0 0 0 - NH3 10,406 15,728 10,335 14,979 - H2SO4 8,779 13,567 8,475 13,121 - NaOH 10,601 16,383 10,235 15,845 - Misc 22,593 35,335 21,586 34,894 Disposal Charges - Spent SCR catalyst 2,358 3,586 2,330 3,456 - Spent CO catalyst 0 0 0 0 - Other disposal 703 1,671 657 1,570 Byproduct Credit 0 0 0 0






C-20


Site ChicagoTechnology Base CaseOperating Percentage

SOAPP EQUIVALENT-a CASEDescription (Values in thousands) Equip. Material Labor TotalCombustion Turbine & Accessories 38,250 1,036 2,271 41,557Inlet Filtration System 495 70 253 818Inlet Air Precooling SystemElectrical Systems - Combustion Turbine 2,888 71 333 3,292Condensate Heating System 1,142 13 328 1,483HRSG's & Accessories 9,156 100 1,986 11,242Deaeration System 66 34 77 177Duct Burner SystemPost Combustion Emissions Controls 600 109 110 819Steam Piping 0 566 439 1,005Electrical Systems - HRSG's 28 35 88 151Steam Turbine & Accessories 11,238 649 2,577 14,464Steam Bypass System 938 46 179 1,163Electrical Systems - Steam Turbine 1,738 808 796 3,342Condenser & Accessories 1,102 24 290 1,416Circulating Water System 1,332 1,210 1,636 4,178Water Treatment System 331 96 532 959Waste Water Treatment System 151 22 84 257Auxiliary Boiler & AccessoriesBoiler Feed System 443 152 226 821Condensate System 51 74 108 233Buildings 0 3,367 3,652 7,019Fire Protection System 509 23 385 917Fuel Systems 106 125 183 414Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 517 200 717Station & Instrument Air System 346 125 115 586Closed Cooling Water System 164 70 138 372Cranes & Hoists 94 97 93 284Plant Control System 942 0 146 1,088Continuous Emission Monitoring System 185 103 270 558Total Process Capital 72,295 9,542 17,495 99,332


TOTAL PROCESS CAPITAL 99,332,000

General Facilities 1,986,640 Engineering and Home Office Fees 2,979,960 Project Contingency 4,966,600 Process Contingency 0

TOTAL PLANT COST 109,265,200 AFUDC or IDC See Capital Outlay Table

TOTAL PLANT INVESTMENT 109,265,200TOTAL PLANT INVESTMENT ($/gross kW) 422.4

Prepaid Royalties 0 Preproduction Costs 3,717,411 Inventory Capital 546,326 Initial Cost - Catalyst and Chemicals 0 Land 68,447 Capital Cost Adders 0

TOTAL CAPITAL REQUIREMENT 113,597,384TOTAL CAPITAL REQUIREMENT ($/gross kW) 439.14O + M and Fuel Costs (in Base Year (2000) $)



C-21


Site ChicagoTechnology Base CaseOperating Percentage

SOAPP EQUIVALENT-a CASEDescription (Values in thousands) Equip. Material Labor TotalFixed O + M Direct Operating Labor 476,295 - Number of Operating Staff 8 Direct Maintenance Labor 397,016 - Number of Maintenance Staff 6 Annual Services, Materials, & Purchased Power - Annual O&M Services & Materials 228,639 - Non-operating Purchased Power 42,012 Indirect Labor Costs - Benefits 268,735 - Home Office Costs 208,080

TOTAL FIXED O+M 1,620,778TOTAL FIXED O+M ($/gross kW) 6.27

Variable O+M Scheduled Maintenance Parts & Materials - CT Inspection/Overhaul 1,249,233 - HRSG Inspection/Refurbish 96,862 - ST Inspection/Overhaul 101,157 - BOP Refurbish 58,364 Scheduled Maintenance Labor - CT Inspection/Overhaul 59,963 - HRSG Inspection/Refurbish 34,870 - ST Inspection/Overhaul 12,138 - BOP Refurbish 15,356 Unscheduled Maintenance Allowance 81,397 Catalyst Replacement - SCR Catalyst Materials & Labor 36,691 - CO Catalyst Materials & Labor 0 Other Consumables - Raw water 206,557 - Circulating water 0 - NH3 10,198 - H2SO4 8,577 - NaOH 10,357 - Misc 22,114 Disposal Charges - Spent SCR catalyst 2,293 - Spent CO catalyst 0 - Other disposal 671 Byproduct Credit 0

Total Variable O+M 2,006,806Total Variable O+M ($/MWh) 1.51

Total Fixed and Variable O+M 3,627,585

Fuel Cost Fuel Cost 31,402,898 Fuel Cost ($/MWh) 23.57



C-22


Site Chicago Chicago Chicago ChicagoTechnology Duct Firing Duct Firing Duct Firing Duct FiringOperating Percentage 38.0% 27.9% 23.9% 10.2%

CASE 1 CASE 2 CASE 3 CASE 4Description (Values in thousands) Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor Total Equip. Material Labor To talCombustion Turbine & Accessories 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535 38,250 1,014 2,271 41,535Inlet Filtration System 499 68 255 822 479 67 248 794 520 70 262 852 461 65 241 767Inlet Air Precooling SystemElectrical Systems - Combustion Turbine 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292 2,888 71 333 3,292Condensate Heating System 749 18 223 990 698 17 208 923 776 18 231 1,025 653 16 195 864HRSG's & Accessories 9,539 100 2,062 11,701 9,535 100 2,055 11,690 9,168 97 1,952 11,217 9,803 103 2,133 12,039Deaeration System 74 43 95 212 74 43 95 212 74 43 95 212 75 43 94 212Duct Burner System 413 16 44 473 390 16 43 449 436 16 45 497 374 16 42 432Post Combustion Emissions Controls 662 110 123 895 643 108 120 871 681 111 126 918 629 107 118 854Steam Piping 0 694 530 1,224 0 666 516 1,182 0 711 537 1,248 0 642 507 1,149Electrical Systems - HRSG's 28 36 91 155 28 36 91 155 28 35 88 151 29 37 93 159Steam Turbine & Accessories 14,229 730 2,957 17,916 13,748 717 2,901 17,366 14,644 741 3,005 18,390 13,305 705 2,848 16,858Steam Bypass System 938 44 176 1,158 938 44 176 1,158 938 48 181 1,167 938 44 176 1,158Electrical Systems - Steam Turbine 2,049 835 835 3,719 1,999 831 830 3,660 2,092 839 839 3,770 1,952 826 825 3,603Condenser & Accessories 1,444 23 373 1,840 1,449 23 375 1,847 1,428 23 369 1,820 1,457 23 377 1,857Circulating Water System 1,737 1,394 1,923 5,054 1,743 1,397 1,927 5,067 1,718 1,384 1,910 5,012 1,752 1,401 1,934 5,087Water Treatment System 408 112 651 1,171 401 110 640 1,151 414 114 660 1,188 394 109 629 1,132Waste Water Treatment System 182 24 97 303 179 24 95 298 184 24 98 306 176 23 94 293Auxiliary Boiler & AccessoriesBoiler Feed System 768 209 363 1,340 761 203 358 1,322 772 213 366 1,351 725 193 342 1,260Condensate System 57 83 118 258 57 81 116 254 57 85 119 261 56 78 114 248Buildings 0 4,199 4,716 8,915 0 3,870 4,339 8,209 0 4,462 5,015 9,477 0 3,534 3,956 7,490Fire Protection System 575 25 435 1,035 553 24 418 995 593 25 448 1,066 529 24 399 952Fuel Systems 139 133 216 488 139 133 216 488 139 133 216 488 139 133 216 488Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 520 203 723 0 512 199 711 0 530 206 736 0 503 196 699Station & Instrument Air System 346 139 119 604 346 134 117 597 346 143 120 609 346 129 116 591Closed Cooling Water System 194 92 172 458 185 91 169 445 200 93 174 467 176 90 166 432Cranes & Hoists 97 96 96 289 96 96 95 287 97 97 96 290 95 95 94 284Plant Control System 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088 942 0 146 1,088Continuous Emission Monitoring System 186 108 292 586 185 106 285 576 186 109 297 592 185 104 277 566Total Process Capital 77,393 10,936 19,915 108,244 76,706 10,534 19,382 106,622 77,571 11,249 20,205 109,025 76,329 10,128 18,932 105,389










C-23


Site Chicago Chicago Chicago ChicagoTechnology Duct Firing Duct Firing Duct Firing Duct FiringOperating Percentage 38.0% 27.9% 23.9% 10.2%



Variable O+M Scheduled Maintenance Parts & Materials - CT Inspection/Overhaul 1,273,811 1,995,579 1,212,402 1,995,579 - HRSG Inspection/Refurbish 98,740 155,512 90,671 158,891 - ST Inspection/Overhaul 133,339 203,006 130,559 196,292 - BOP Refurbish 72,510 112,947 69,814 111,158 Scheduled Maintenance Labor - CT Inspection/Overhaul 50,952 79,823 48,496 79,823 - HRSG Inspection/Refurbish 29,622 46,653 27,201 47,667 - ST Inspection/Overhaul 13,333 20,300 13,055 19,629 - BOP Refurbish 15,658 24,345 15,108 23,918 Unscheduled Maintenance Allowance 84,398 131,908 80,365 131,648 Catalyst Replacement - SCR Catalyst Materials & Labor 49,124 74,067 48,583 71,982 - CO Catalyst Materials & Labor 0 0 0 0 Other Consumables - Raw water 275,650 436,605 259,370 437,485 - Circulating water 0 0 0 0 - NH3 16,083 23,967 16,178 23,218 - H2SO4 13,315 20,328 13,030 19,648 - NaOH 16,079 24,547 15,734 23,726 - Misc 26,859 41,700 25,942 40,946 Disposal Charges - Spent SCR catalyst 3,070 4,629 3,036 4,498 - Spent CO catalyst 0 0 0 0 - Other disposal 836 1,978 788 1,854 Byproduct Credit 0 0 0 0






C-24


Site ChicagoTechnology Duct FiringOperating Percentage

SOAPP EQUIVALENT-a CASEDescription (Values in thousands) Equip. Material Labor TotalCombustion Turbine & Accessories 38,250 1,014 2,271 41,535Inlet Filtration System 495 68 253 816Inlet Air Precooling SystemElectrical Systems - Combustion Turbine 2,888 71 333 3,292Condensate Heating System 740 18 221 979HRSG's & Accessories 9,476 100 2,042 11,618Deaeration System 74 43 95 212Duct Burner System 407 16 43 466Post Combustion Emissions Controls 660 110 123 893Steam Piping 0 691 529 1,220Electrical Systems - HRSG's 28 36 90 154Steam Turbine & Accessories 14,144 728 2,948 17,820Steam Bypass System 938 44 176 1,158Electrical Systems - Steam Turbine 2,040 834 834 3,708Condenser & Accessories 1,444 23 373 1,840Circulating Water System 1,737 1,394 1,923 5,054Water Treatment System 406 112 649 1,167Waste Water Treatment System 181 24 96 301Auxiliary Boiler & AccessoriesBoiler Feed System 766 208 362 1,336Condensate System 57 83 118 258Buildings 0 4,150 4,659 8,809Fire Protection System 572 25 432 1,029Fuel Systems 139 133 216 488Fuel Gas Compressor & AccessoriesBypass Stack & Diverter ValveMain Exhaust Stack 0 518 202 720Station & Instrument Air System 346 139 118 603Closed Cooling Water System 192 92 171 455Cranes & Hoists 96 96 95 287Plant Control System 942 0 146 1,088Continuous Emission Monitoring System 186 107 291 584Total Process Capital 77,204 10,877 19,809 107,890


TOTAL PROCESS CAPITAL 107,890,000

General Facilities 2,157,800 Engineering and Home Office Fees 3,236,700 Project Contingency 5,394,500 Process Contingency 0

TOTAL PLANT COST 118,679,000 AFUDC or IDC See Capital Outlay Table

TOTAL PLANT INVESTMENT 118,679,000TOTAL PLANT INVESTMENT ($/gross kW) 386.75

Prepaid Royalties 0 Preproduction Costs 4,184,192 Inventory Capital 593,395 Initial Cost - Catalyst and Chemicals 0 Land 70,024 Capital Cost Adders 0

TOTAL CAPITAL REQUIREMENT 123,526,608TOTAL CAPITAL REQUIREMENT ($/gross kW) 402.55O + M and Fuel Costs (in Base Year (2000) $)



C-25


Site ChicagoTechnology Duct FiringOperating Percentage

SOAPP EQUIVALENT-a CASEDescription (Values in thousands) Equip. Material Labor TotalFixed O + M Direct Operating Labor 476,295 - Number of Operating Staff 8 Direct Maintenance Labor 397,016 - Number of Maintenance Staff 6 Annual Services, Materials, & Purchased Power - Annual O&M Services & Materials 247,165 - Non-operating Purchased Power 49,837 Indirect Labor Costs - Benefits 268,735 - Home Office Costs 208,080

TOTAL FIXED O+M 1,647,130TOTAL FIXED O+M ($/gross kW) 5.37

Variable O+M Scheduled Maintenance Parts & Materials - CT Inspection/Overhaul 1,249,233 - HRSG Inspection/Refurbish 96,100 - ST Inspection/Overhaul 128,160 - BOP Refurbish 70,823 Scheduled Maintenance Labor - CT Inspection/Overhaul 59,963 - HRSG Inspection/Refurbish 34,596 - ST Inspection/Overhaul 15,379 - BOP Refurbish 18,347 Unscheduled Maintenance Allowance 83,630 Catalyst Replacement - SCR Catalyst Materials & Labor 47,779 - CO Catalyst Materials & Labor 0 Other Consumables - Raw water 269,981 - Circulating water 0 - NH3 15,761 - H2SO4 12,951 - NaOH 15,640 - Misc 26,228 Disposal Charges - Spent SCR catalyst 2,986 - Spent CO catalyst 0 - Other disposal 796 Byproduct Credit 0

Total Variable O+M 2,148,360Total Variable O+M ($/MWh) 1.36

Total Fixed and Variable O+M 3,795,490

Fuel Cost Fuel Cost 38,635,220 Fuel Cost ($/MWh) 24.44


D-1

D APPENDIX D – REFERENCES

1. “Combustion Turbine Spray Cooler Guide”, Interim Report, EPRI Report TR-113983,December 1999.

2. Goldlust. B and Grace. D, “Cost and Performance Overview of Capacity EnhancementOptions for Combustion Turbines”, Technical Assessment Guide Study, EPRI Report,October 1999.

3. “Gas Turbine and Combined-Cycle Capacity Enhancement”, Second Interim Report,EPRI Report TR-104612, January 1995.

4. Mee, T. R. III, “Inlet Fogging Augments Power Production”, Power Engineering,February 1999.

5. Mee, T. R. III and Meher-Homji, C. B., “Gas Turbine Power Augmentation By Fogging ofInlet Air”, Presented at 28th Turbomachinery Symposium, 1999.

6. Natural Gas Monthly, Energy Information Administration, June 2000. (for electricity and gasprices)

7. Pasha, A., “Gas Turbine Heat Recovery Systems: Considerations in Operating at Fired andUnfired Modes”, Presented at the Gas Turbine Conference and Exhibit (Houston, TX),March 1985.

8. “Turbines in The Mist”, Power Plant Technology, July/August 2000.

9. York Works Software, Ver. 5.00. (for climate data)

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