Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site

1014510

EPRI Project Manager G. Booras

ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 ▪ PO Box 10412, Palo Alto, California 94303-0813 ▪ USA

800.313.3774 ▪ 650.855.2121 ▪ askepri@epri.com ▪ www.epri.com

Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site 1014510

Technical Update, October 2006

Cosponsor

CPS Energy 145 Navarro San Antonio, TX 78296

Project Manager J. Kosub

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES

THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:

(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR

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ORGANIZATION(S) THAT PREPARED THIS DOCUMENT

Burns & McDonnell Engineering Co. Inc.

This is an EPRI Technical Update report. A Technical Update report is intended as an informal report of continuing research, a meeting, or a topical study. It is not a final EPRI technical report.

NOTE

For further information about EPRI, call the EPRI Customer Assistance Center at 800.313.3774 or e-mail askepri@epri.com.

Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc.

Copyright © 2006 Electric Power Research Institute, Inc. All rights reserved.

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CITATIONS

This report was prepared by

Burns & McDonnell 9400 Ward Parkway Kansas City, MO 64114

Principal Investigator J. Schwarz

This report describes research sponsored by the Electric Power Research Institute (EPRI) and CPS Energy.

This publication is a corporate document that should be cited in the literature in the following manner:

Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site. EPRI, Palo Alto, CA: 2006. 1014510.

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PRODUCT DESCRIPTION

Interest in integrated gasification combined-cycle technology (IGCC) has grown sharply since the passage of the Energy Policy Act in 2005. Many new projects are being planned since the AEP and Duke 600-MW IGCC plants were announced nearly two years ago. This report compares the cost and performance of IGCC with a supercritical pulverized coal plant (SCPC) based on lower-rank Powder River Basin (PRB) coal. IGCC options included 100% PRB and 50/50 PRB/petcoke cases. The addition of CO2 capture equipment also was evaluated as a retrofit for the 100% PRB IGCC and SCPC facilities.

Results & Findings The net plant heat rates for the IGCC and SCPC plants without CO2 capture are similar, with the 100% PRB IGCC case having a slightly worse heat rate while the PRB/petcoke blend IGCC case has a slightly better heat rate than the PRB-fired SCPC. IGCC has an advantage in terms of SO2, PM10, and mercury emissions, with NOx emissions being similar for both technologies. SCR was not included for the IGCC unit due to concerns that ammonium bisulfate (ABS) deposits could plug the finned heat transfer surfaces of the HRSG downstream of the SCR. In addition, IGCC technology consumes less water than SCPC technology.

Capital costs for the IGCC cases are approximately 20% higher than the cost for the SCPC case. There is about a 2.5% capital cost savings for the 50/50 PRB/petcoke IGCC over the 100% PRB IGCC due to the higher heating value of the blended fuel (lower water and ash contents). The 100% PRB SCPC unit has the lowest busbar cost of all alternatives.

Installation of CO2 capture equipment as a retrofit for both technologies results in a very significant decrease in plant output. IGCC net plant output decreases by approximately 25%, and the SCPC decrease in output is 29%. Likewise, the net plant heat rate of the facilities also increases by approximately 39% for the IGCC and 41% for the SCPC. Water consumption also is increased by approximately 23% for IGCC and 34% for SCPC.

All these factors result in an increase of the levelized busbar cost by approximately 45% for the IGCC and 58% for the SCPC post-CO2 capture. SCPC technology still provides the lowest busbar cost after CO2 capture retrofit, although by less of a gap than pre-CO2 capture. The avoided cost of CO2 capture is less for an IGCC, implying that IGCC technology is the more economical choice for retrofit of CO2 capture technology.

Challenges & Objective(s) The Shell gasification process chosen for this application uses a dry-feed system, which has advantages over slurry-feed gasification processes for low-rank coal (for the non-CO2 capture case). However, the Shell gasification process produces syngas with higher concentrations of CO and less H2 than would be produced by a slurry-feed gasifier. When adding CO2 capture

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equipment to the Shell gasification process, more steam is required to convert the CO to CO2 and H2 than would be required for a slurry-feed gasifier. This situation results in less steam available to the steam turbine, which equates to less plant output for the CO2 capture case than may be seen if using a slurry-feed gasifier. If the objective of the owner is to capture CO2, then a slurry-feed gasifier may be a better choice than a dry-feed gasifier. Another option would be a water quench version of the Shell gasifier, which would require some additional development.

Applications, Values & Use In recent years, several factors have caused the cost of power projects to increase at a higher rate than in years past. World demand for many commodities has increased sharply, resulting in a 100-300% cost increase for some commodities, including steel (in particular, stainless or high-alloy steel), concrete, copper, oil, and nickel. The compounding effect of labor productivity, high labor rate escalation, commodity cost escalation, risk mitigation, and contractor markups results in much higher project costs for both IGCC and SCPC than may have been anticipated one or two years ago. It is important that owners who are planning to add new generation have access to the most recent cost and performance estimates.

EPRI Perspective This is the first EPRI study performed that evaluates CO2 capture as a retrofit to existing IGCC and SCPC units. Other EPRI studies have evaluated CO2 capture on new units specifically designed for and incorporating CO2 capture from the start. Additionally, this is the first detailed study performed by EPRI that evaluates IGCC and pulverized coal (PC) technology with CO2 capture when using a lower-rank, higher-moisture PRB coal. Other detailed studies performed by EPRI focused primarily on higher-rank bituminous coals (using slurry-feed gasifiers), where IGCC has been shown to provide a more distinct advantage.

Approach Burns & McDonnell was engaged by CPS Energy and EPRI to perform a feasibility study for a nominal 550-MW (net) IGCC facility to be located at a greenfield site in the Texas Gulf Coast region. The IGCC options were based on Shell coal gasification technology with GE 7FB gas turbines. EPRI’s in-house computer model was used to estimate the performance of the Shell coal gasification process for both fuels. UOP’s SELEXOL system was used as the basis for the IGCC CO2 capture technology, and Fluor’s Econamine FG PlusSM system was used for SCPC CO2 capture technology. This report provides screening-level capital cost, performance, operations and maintenance costs, availability factors, and emission rates for the two IGCC alternatives. The capital costs include many site and owner-specific items that are not normally included in EPRI’s Technical Assessment Guide (TAG®).

Keywords Integrated gasification combined cycle Pulverized coal CO2 capture PRB coal

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CONTENTS

1 EXECUTIVE SUMMARY ........................................................................................................1-1 Overview ...............................................................................................................................1-1 IGCC Options........................................................................................................................1-1 Deliverables...........................................................................................................................1-2 Results ..................................................................................................................................1-2 Current Market Conditions ....................................................................................................1-6 Limitations and Qualifications................................................................................................1-7

2 INTRODUCTION ....................................................................................................................2-1 Background ...........................................................................................................................2-1 Objectives .............................................................................................................................2-1 Status of the Technology.......................................................................................................2-2 Selection of Gasification Technology ....................................................................................2-2 Project Experience ................................................................................................................2-3 Fuel experience.....................................................................................................................2-4 Technical Approach and Data Sources.................................................................................2-4

3 STUDY CRITERIA..................................................................................................................3-1 Site Selection ........................................................................................................................3-1 Gas Turbine Selection...........................................................................................................3-1 Fuel Selection .......................................................................................................................3-1 Plant Capacity Selection .......................................................................................................3-3 Capacity Factor and Availability Factor Targets....................................................................3-4

4 PROCESS DESCRIPTION.....................................................................................................4-1 Gasification System Description............................................................................................4-1

Air Separation Unit (ASU).................................................................................................4-1 Gasifiers ...........................................................................................................................4-4

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Gasifier Performance Estimate by EPRI......................................................................4-5 Slag Handling ...................................................................................................................4-6 Fly Ash System.................................................................................................................4-7 Syngas Wash Towers.......................................................................................................4-7 COS / HCN Hydrolysis .....................................................................................................4-8 Syngas Cooling and Condensation ..................................................................................4-9 Mercury Removal ...........................................................................................................4-10 Acid Gas Removal (AGR)...............................................................................................4-10 Sulfur Recovery and Tail Gas Treating ..........................................................................4-13

Sulfur Recovery Units (SRU) .....................................................................................4-13 Tail Gas Treating Unit (TGTU)...................................................................................4-15 Tail Gas Compression ...............................................................................................4-16 Thermal Oxidizer........................................................................................................4-16

Sour Water Stripping ......................................................................................................4-16 Syngas Saturation ..........................................................................................................4-17

Power Block Description .....................................................................................................4-17 Gas Turbines ..................................................................................................................4-17 Heat Recovery Steam Generators (HRSG)....................................................................4-18 Steam Turbine ................................................................................................................4-18 Steam Condenser...........................................................................................................4-19 Steam System ................................................................................................................4-19 Condensate System .......................................................................................................4-19 Feedwater System..........................................................................................................4-19 Natural Gas System .......................................................................................................4-19

Balance of Plant ..................................................................................................................4-20 Coal Handling .................................................................................................................4-20

100% PRB Option......................................................................................................4-20 50% PRB / 50% Petcoke Option................................................................................4-20

Cooling System ..............................................................................................................4-20 Auxiliary Boiler................................................................................................................4-21 Buildings .........................................................................................................................4-21 Water Treatment.............................................................................................................4-21

Raw Water/Service Water..........................................................................................4-22 Demineralized Water .................................................................................................4-23

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Wastewater ................................................................................................................4-23 Sanitary Drains ..........................................................................................................4-23

Flare ...............................................................................................................................4-23 Fire Protection ................................................................................................................4-23 Plant Drains ....................................................................................................................4-24 Electrical Systems ..........................................................................................................4-24

Auxiliary Power Supply ..............................................................................................4-24 Generator and Excitation ...........................................................................................4-25 Switchyard .................................................................................................................4-25 Essential AC and DC Power Supply ..........................................................................4-26 Freeze Protection ......................................................................................................4-26

5 TERMINAL POINTS ...............................................................................................................5-1 General .................................................................................................................................5-1 Site Access ...........................................................................................................................5-1 Rail Siding .............................................................................................................................5-1 Sanitary Waste......................................................................................................................5-1 Natural Gas ...........................................................................................................................5-1 Raw Water Supply.................................................................................................................5-1 Wastewater Discharge ..........................................................................................................5-2 Electrical Interface.................................................................................................................5-2

6 IGCC PERFORMANCE ESTIMATES ....................................................................................6-1 Performance Estimate Assumptions .....................................................................................6-1 Performance Estimate Results..............................................................................................6-1

7 IGCC CAPITAL COST ESTIMATES......................................................................................7-1 Capital Cost Estimate Assumptions ......................................................................................7-1 Indirect Construction Costs (Included in EPC Cost)..............................................................7-2 Owner Indirect Costs.............................................................................................................7-3 Costs not included.................................................................................................................7-4 Capital Cost Results..............................................................................................................7-4

8 IGCC OPERATIONS AND MAINTENANCE..........................................................................8-1 O&M Assumptions.................................................................................................................8-1 O&M Exclusions....................................................................................................................8-2

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O&M Results .........................................................................................................................8-2

9 IGCC AVAILABILITY .............................................................................................................9-1 General .................................................................................................................................9-1 Assumptions and Clarifications .............................................................................................9-1 Availability Factor ..................................................................................................................9-1

10 IGCC EMISSIONS ESTIMATES ........................................................................................10-1 General ...............................................................................................................................10-1

11 SUPERCRITICAL PC ESTIMATES ...................................................................................11-1 General ...............................................................................................................................11-1 SCPC Capital Cost Assumptions ........................................................................................11-1 SCPC Capital Cost Results.................................................................................................11-2 SCPC Performance Assumptions .......................................................................................11-4 SCPC Performance Estimate Results.................................................................................11-4 SCPC O&M Cost Assumptions ...........................................................................................11-5 SCPC O&M Exclusions.......................................................................................................11-5 SCPC O&M Results ............................................................................................................11-5 SCPC Emission Rates ........................................................................................................11-6 Availability Factor ................................................................................................................11-8

12 ECONOMIC ANALYSIS .....................................................................................................12-1 General ...............................................................................................................................12-1 Assumptions........................................................................................................................12-1 Economic Analysis ..............................................................................................................12-3 Sensitivity Analysis..............................................................................................................12-5

13 CO2 CAPTURE ...................................................................................................................13-1 General ...............................................................................................................................13-1 IGCC CO2 Capture ..............................................................................................................13-3

IGCC Modifications for CO2 Capture ..............................................................................13-4 Sour Shift ...................................................................................................................13-4 Syngas Cooling and Condensation............................................................................13-5 Acid Gas Removal (AGR)..........................................................................................13-5

IGCC Impacts from CO2 Capture....................................................................................13-5

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IGCC Performance – CO2 Capture ............................................................................13-5 IGCC Capital Cost – CO2 Capture .............................................................................13-7 IGCC Operations and Maintenance – CO2 Capture...................................................13-7 IGCC Emissions – CO2 Capture ................................................................................13-9 IGCC Pre-Investment Options for CO2 Capture.......................................................13-10

SCPC CO2 Capture ...........................................................................................................13-10 SCPC Modifications for CO2 Capture ...........................................................................13-12 SCPC Impacts from CO2 Capture.................................................................................13-13

SCPC Performance – CO2 Capture .........................................................................13-13 SCPC Capital Cost – CO2 Capture ..........................................................................13-14 SCPC Operations and Maintenance – CO2 Capture................................................13-15 SCPC Emissions – CO2 Capture .............................................................................13-17 SCPC Pre-Investment Options for CO2 Capture......................................................13-17

CO2 Capture Economics....................................................................................................13-18

14 OTHER CONSIDERATIONS..............................................................................................14-1 Byproduct Sales ..................................................................................................................14-1 Co-Production .....................................................................................................................14-1 Plant Degradation................................................................................................................14-2 Lignite Gasification..............................................................................................................14-2

15 SUMMARY .........................................................................................................................15-1

A PROCESS FLOW DIAGRAMS............................................................................................. A-1

B SITE LAYOUT DRAWINGS.................................................................................................. B-1

C WATER MASS BALANCE DIAGRAMS............................................................................... C-1

D ELECTRICAL ONE-LINE DIAGRAMS................................................................................. D-1

E CAPITAL COST DETAIL ...................................................................................................... E-1

F HEAT BALANCE DIAGRAMS...............................................................................................F-1

G O&M COST DETAIL............................................................................................................. G-1

H SYSTEM OF INTERNATIONAL UNITS CONVERSION TABLE ......................................... H-1

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LIST OF FIGURES

Figure 4-1 Gasification Block Flow Diagram..............................................................................4-1 Figure 4-2 Generic ASU Process Flow Diagram .......................................................................4-4 Figure 4-3 SELEXOL Process Flow Diagram ..........................................................................4-12 Figure 4-4 Block Flow Diagram – Sulfur Recovery and Tail Gas Treating...............................4-13 Figure 12-1 20-Year Levelized Busbar Cost (2006 US Dollars) ..............................................12-3 Figure 12-2 Breakout of 20-Year Levelized Busbar Cost (2006 US Dollars) ...........................12-4 Figure 12-3 Sensitivity Analysis – SCPC Unit – 100% PRB Coal............................................12-5 Figure 12-4 Sensitivity Analysis – IGCC – 50% PRB Coal / 50% Petcoke..............................12-6 Figure 12-5 Sensitivity Analysis – IGCC – 100% PRB Coal ....................................................12-6 Figure 13-1 CO2 Storage Supply Curve for North America......................................................13-3 Figure 13-2 Fluor EFG+ Block Flow Diagram........................................................................13-11 Figure 14-1 Products from Syngas ..........................................................................................14-2

Error! No table of figures entries found

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LIST OF TABLES

Table 1-1 Executive Summary Table (Table 1 of 2) ..................................................................1-3 Table 1-2 Executive Summary Table (Table 2 of 2) ..................................................................1-4 Table 2-1 IGCC Facilities – Past and Current............................................................................2-4 Table 3-1 Fuel Analyses ............................................................................................................3-3 Table 4-1 ASU Material Balances..............................................................................................4-3 Table 4-2 Summary of Gasifier Modeling Results .....................................................................4-6 Table 4-3 Assumed Raw Water Quality..................................................................................4-22 Table 6-1 IGCC Performance Summary....................................................................................6-2 Table 7-1 IGCC Capital Cost Estimate Summary (2006 US Dollars) ........................................7-5 Table 8-1 IGCC O&M Summary (2006 US Dollars)...................................................................8-3 Table 10-1 IGCC Target Emission Rates ................................................................................10-2 Table 11-1 550 MW (Net) SCPC Capital Cost Estimate Summary (2006 US Dollars) ............11-3 Table 11-2 550 MW (Net) SCPC Performance Summary........................................................11-4 Table 11-3 550 MW (Net) SCPC O&M Summary (2006 US Dollars) ......................................11-6 Table 11-4 500 MW (Net) SCPC Emissions Estimates ...........................................................11-8 Table 13-1 CO2 Purity Specification.........................................................................................13-2 Table 13-2 IGCC Performance Impacts from CO2 Capture .....................................................13-6 Table 13-3 IGCC Capital Cost Additions for CO2 Capture Retrofit...........................................13-7 Table 13-4 IGCC O&M Impacts from CO2 Capture..................................................................13-8 Table 13-5 IGCC Emissions Impacts from CO2 Capture .........................................................13-9 Table 13-6 SCPC Performance Impacts from CO2 Capture ..................................................13-14 Table 13-7 SCPC Capital Cost Additions for CO2 Capture Retrofit........................................13-15 Table 13-8 SCPC O&M Impacts from CO2 Capture...............................................................13-16 Table 13-9 SCPC Emissions Impacts from CO2 Capture ......................................................13-17 Table 13-10 CO2 Capture Busbar Costs ...............................................................................13-18 Table 15-1 Summary Table (1 of 2) .........................................................................................15-2 Table 15-2 Summary Table (2 of 2) .........................................................................................15-3

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ACRONYMS, ABBREVIATIONS, AND SYMBOLS

°F degrees Fahrenheit 106 million $ dollars (U.S.) $/kW dollars per kilowatt $/kW-yr dollars per kilowatt-year $/MMBtu dollars per million British thermal unit $/MWh dollars per megawatt-hour $/ton dollars per ton $/yr dollars per year % percent ABS ammonium bisulfate AC alternating current AGR acid gas removal ALPC Air Liquide Process and Construction ASU air separation unit BOP balance of plant Btu British thermal unit Btu/kWh British thermal unit(s) per kilowatt-hour CF capacity factor CIT compressor inlet temperature CO carbon monoxide CO2 carbon dioxide COS carbonyl sulfide CPS CPS Energy DC direct current DCS distributed control system DSF deep saline formations ECBM Enhanced coal bed methane (recovery) EFG+ Econamine FG PlusSM (Fluor CO2 capture system) EOR enhanced oil recovery EPA Environmental Protection Agency EPC engineer-procure-construct EPRI Electric Power Research Institute FGCU Flue Gas Conditioning Unit FGD flue gas desulfurization ft foot (feet) gal gallon(s) GE General Electric GIS geographic information system GSU generator step-up (transformer) GTG gas turbine generator H2 hydrogen H2O water H2S hydrogen sulfide HCN hydrogen cyanide Hg mercury

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HHV higher heating value HP high pressure hr hour HRSG heat recovery steam generator HVAC heating, ventilation, and air conditioning IGCC integrated gasification combined cycle in inch(es) IOU investor owned utility kPa kilopascal(s) kV kilovolt(s) kW kilowatt(s) kWh kilowatt-hour lb pound(s) lb/hr pound per hour lb/MMBtu pound(s) per million British thermal units lb/MWh pound(s) per megawatt-hour LHV lower heating value lit liter(s) LP low pressure LTGC low temperature gas cooling LTSA long term service agreement LV low voltage m3 cubic meters MCC motor control center MEA monoethanolamine (solvent) MHI Mitsubishi Heavy Industries MM million MMBtu million Btu MMcf million cubic feet MP medium pressure Mt metric ton MV medium voltage MW megawatts MWh megawatt-hour N2 nitrogen NAAQS National Ambient Air Quality Standards NaOH Sodium Hydroxide NFPA National Fire Protection Association NH3 ammonia NOx nitrous oxide O&M operations and maintenance PC pulverized coal PCM power control module ppmv part(s) per million by volume ppmvd part(s) per million by volume (dry) ppmvd @ 15% O2 part(s) per million by volume (dry) corrected to 15% oxygen PPT power potential transformer PRB Powder River Basin (coal) psia pound(s) per square inch (atmospheric) psig pound(s) per square inch (gauge) S sulfur SCPC supercritical pulverized coal SCR selective catalytic reduction SO2 sulfur dioxide SO3 sulfur trioxide SRU sulfur recovery unit STG steam turbine generator STPD short tons per day

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SWS sour water stripper TGTU tail gas treatment unit TPD ton(s) per day TTD terminal temperature difference UPS uninterruptible power supply U.S. United States V volt(s) v% percent by volume vol volume wt weight wt% percent by weight yr year(s)

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CERTIFICATION PAGE

Electric Power Research Institute & CPS Energy

Feasibility Study for an Integrated Combined Cycle Facility at a Texas Site

NUMBER DOCUMENT DESCRIPTION OF PAGES Report/Appendices Findings of IGCC Feasibility Study 221

CERTIFICATION(S)

1-1

1 EXECUTIVE SUMMARY

Overview

Integrated gasification combined cycle (IGCC) technology has been the source of much interest in the world of advanced coal-fired generation. IGCC technology provides a bridge between the two mature technologies of coal gasification and combined cycle technology by producing a medium-Btu value syngas from coal or other solid fuel and firing it in a modified conventional gas turbine as part of a combined cycle application.

Burns & McDonnell was engaged by CPS Energy (Owner) and EPRI to perform a feasibility study for IGCC technology to be located at a greenfield Texas Gulf Coast location.

IGCC Options

Due to the availability of petroleum coke (petcoke) and PRB coal in the area, two IGCC options were evaluated:

Option 1 – 100% PRB

Option 2 – 50% PRB / 50% Petcoke (% by weight)

For this evaluation, a 2x1 (two gas turbine/HRSG trains and 1 steam turbine) configuration was selected. The IGCC facility consists of the following major equipment:

• 1 high-pressure air separation unit (ASU) with 2x50% main air compressors and nitrogen compressors, utilizing a portion of air extracted from the gas turbine compressors at lower ambient temperatures (air-side integration).

• 2 Shell gasifiers.

• 1 SELEXOLTM acid gas removal (AGR) system.

• 2 sulfur recovery units (SRU).

• 1 tail gas treating unit (TGTU).

• 2 General Electric (GE) 7FB gas turbine generators (GTG).

Executive Summary

1-2

• 2 heat recovery steam generators (HRSG).

• 1 steam turbine generator (STG).

• Balance of plant (BOP).

Deliverables

This report provides screening level capital cost, performance, operations and maintenance (O&M) costs, availability factors, and emission rates for the two IGCC alternatives defined above. As a part of creating this information Burns & McDonnell also generated process flow diagrams, layout drawings, water mass balances, and electrical one-line diagrams.

Another objective of this study was to compare IGCC technology to supercritical pulverized coal (SCPC) technology using steam conditions of 3500 psig/1050°F/1050°F. Therefore capital cost, performance, O&M costs, availability factors, and emission rates were also developed for a SCPC Unit firing 100% PRB coal with a net output of 550 MW. This information was used to create a 20-year levelized busbar cost to determine the overall cost of generation for the three alternatives.

The addition of CO2 capture equipment was also evaluated as a retrofit for the 100% PRB IGCC and SCPC facilities. UOP’s SELEXOL system was used as the basis for the IGCC CO2 capture technology and Fluor’s Econamine FG PlusSM system was used for SCPC CO2 capture technology. Capital cost, performance, O&M, and emission rates were developed and used to calculate a 20-year levelized busbar cost for both technologies.

Results

A summary table is provided in Table 1-1 and Table 1-2.

Executive Summary

1-3

Table 1-1 Executive Summary Table (Table 1 of 2)

Base Cases CO2 Capture CasesIGCC SCPC IGCC SCPC

Case 100% PRB 50% PRB / 50% Petcoke 100% PRB 100% PRB IGCC 100% PRBFuel

PRB (% wt.) 100% 50% 100% 100% 100%Petcoke (% wt.) 0% 50% 0% 0% 0%PRB (% heat input) 100% 36% 100% 100% 100%Petcoke (% heat input) 0% 64% 0% 0% 0%HHV (Btu/lb) 8,156 11,194 8,156 8,156 8,156

Capital Cost (2006 USD)EPC Capital Cost $1,318,980,000 $1,287,540,000 $1,072,580,000 $179,220,000 (Note 1) $269,430,000 (Note 1)Owner's Costs $155,240,000 $139,500,000 $129,760,000 $17,960,000 (Note 1) $26,570,000 (Note 1)Total Project Cost $1,474,220,000 $1,427,040,000 $1,202,340,000 $197,180,000 (Note 1) $296,000,000 (Note 1)EPC Capital Cost, $/kW (73°F Ambient) $2,390 $2,330 $1,950 $3,630 (Note 1) $3,440 (Note 1)Total Project Cost, $/kW (73°F Ambient) $2,670 $2,580 $2,190 $4,040 (Note 1) $3,840 (Note 1)

Performance43°F Dry Bulb, 40°F Wet Bulb

Gross Plant Output, MW 736.6 734.2 623.3 Not Evaluated Not EvaluatedAuxiliary Load, MW 137.4 137.2 65.4 Not Evaluated Not EvaluatedNet Plant Output, MW 599.2 597.0 557.8 Not Evaluated Not EvaluatedNet Plant Heat Rate, Btu/kWh (HHV) 9,090 8,950 9,030 Not Evaluated Not Evaluated

73°F Dry Bulb, 69°F Wet BulbGross Plant Output, MW 709.9 711.1 614.5 630.1 521.4Auxiliary Load, MW 156.8 158.0 64.5 216.8 131.6Net Plant Output, MW 553.0 553.0 550.0 413.3 389.8Net Plant Heat Rate, Btu/kWh (HHV) 9,220 9,070 9,150 12,800 12,910

93°F Dry Bulb, 77°F Wet BulbGross Plant Output, MW 681.5 682.6 613.2 Not Evaluated Not EvaluatedAuxiliary Load, MW 153.2 154.5 64.4 Not Evaluated Not EvaluatedNet Plant Output, MW 528.4 528.2 548.8 Not Evaluated Not EvaluatedNet Plant Heat Rate, Btu/kWh (HHV) 9,350 9,210 9,170 Not Evaluated Not Evaluated

O&M Cost (2006 USD)Fixed O&M, $/kW-yr $25.19 $25.19 $20.68 $34.74 $31.19Variable O&M, $/MWh $5.95 $5.66 $4.60 $8.55 $6.97Total O&M Cost, $/Year (85% CF) $38,426,700 $37,245,400 $30,209,800 $40,661,400 $32,563,000

Availability Factor 85% 85% 90% Not Evaluated Not Evaluated

Economic AnalysisCapacity Factor 85% 85% 85% N/A N/A20-year levelized busbar cost, $/MWh (2006 Real $) $45.03 $40.89 $39.28 $65.41 $62.00Avoided CO2 Cost, $/Mt CO2 avoided N/A N/A N/A $26.28 $29.64

Notes:1) CO2 Capture capital costs are based on retrofit of the existing IGCC or PC facilities as provided in the base case alternatives. $/kW values reflect total installed cost to date (including original costs provided in the base case) divided by net plant output with CO2 capture.

Executive Summary

1-4

Table 1-2 Executive Summary Table (Table 2 of 2)

Base Cases CO2 Capture CasesIGCC SCPC IGCC SCPC

Case 100% PRB 50% PRB / 50% Petcoke 100% PRB 100% PRB IGCC 100% PRBNOx Emissions

lb/MMBtu (HHV) 0.063 0.062 0.050 0.061 0.045ppmvd @ 15% O2 15 15 N/A 15 N/Alb/MWh (net) 0.581 0.562 0.458 0.781 0.581

SO2 Emissionslb/MMBtu (HHV) 0.019 0.023 0.060 0.004 0.0003lb/MWh (net) 0.173 0.210 0.549 0.051 0.003

PM10 Emissions (front half)lb/MMBtu (HHV) 0.007 0.007 0.015 0.007 0.015lb/MWh (net) 0.065 0.065 0.137 0.090 0.194

COlb/MMBtu (HHV) 0.037 0.036 0.150 0.035 (Note 1) 0.150ppmvd 25 25 N/A 25 (Note 1) N/Alb/MWh (net) 0.337 0.337 1.373 0.448 (Note 1) 1.937

CO2

lb/MMBtu (HHV) 215 213 215 22 22lb/MWh (net) 1,985 1,934 1,967 276 278

Hg% Removal 90% 90% 70% 90% 70%lb/TBtu (HHV) 0.778 0.496 2.315 0.778 2.315lb/MWh (net) 7.17E-06 4.50E-06 2.12E-05 9.96E-06 2.99E-05

Plant Cooling Requirements, MMBtu/hr (@ 73°F) 2,141 2,179 2,490 2,101 3,330Steam Cycle Cooling Requirement, MMBtu/hr 1,480 1,480 2,300 1,120 1,354BOP Auxiliary Cooling Requirement, MMBtu/hr 661 699 190 981 1,976

Total Plant Makeup Water RequirementGPM (@ 73°F) 4,980 5,231 5,800 6,147 7,757Acre-ft/year (@ 85% CF) 6,830 7,170 7,950 8,430 10,640

Notes:1) GE is currently in the process of developing tools to accurately predict CO emissions for high hydrogen fuels. It is estimated that CO emissions will be less than shown for IGCC CO2 capture technology, however to what extent is unknown at this time.

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The capital costs are based on mid-2006 overnight EPC costs. Escalation through a commercial operation date (COD) is not included. Additionally, sales tax, interest during construction, financing fees, and transmission lines or upgrades are not included in the capital cost estimates.

As can be seen SCPC technology provides the lowest capital cost, best efficiency, and lowest O&M when comparing the two 100% PRB options. Additionally, the 100% PRB SCPC unit has the lowest busbar cost of all alternatives.

The heat rate for the fuel blended IGCC case is slightly better than 100% PRB SCPC technology (with the exception of the 93°F case); however firing petcoke in a PC unit is also possible, although not specifically evaluated for this report. Petcoke firing in a conventional PC boiler is typically limited to approximately 20% (by heat input) due to the low volatiles present in the fuel which can create flame stability issues. Firing 20% petcoke in the PC boiler will result in approximately 1% improvement in heat rate over that shown for the PC unit, thus closing the gap, if not eliminating any performance benefit of the IGCC.

IGCC has an advantage in terms of SO2, PM10, and mercury emissions, however using the emissions allowance costs provided in Chapter 8, these lower emissions are not enough to overcome the capital cost and performance differences between the technologies.

The IGCC evaluated has higher NOx emission rates than for the SCPC unit. This is because an SCR was not included for the IGCC unit due to concerns that ammonium bisulfate (ABS) deposits could plug and corrode the heat transfer surfaces of the HRSG downstream of the SCR. Additionally, if an SCR were used, a larger AGR and SRU would be required to lower the sulfur content of the syngas (to reduce particulate formation from the excess ammonia with SO2/SO3 in the flue gas) resulting in increased capital cost. For these reasons, an SCR was not included; however subsequent evaluations should be performed to evaluate the cost/benefit/technological risk tradeoff. If an SCR were used, NOx emissions could be reduced to levels below that provided for the SCPC unit.

IGCC technology consumes less water than SCPC technology. This is primarily due to the steam turbine output of the IGCC being less than half that of the SCPC unit. Although the steam condenser duty is less for the IGCC, the auxiliary cooling requirements of the IGCC are higher than the SCPC unit (primarily due to the ASU cooling requirement), resulting in about a 15% overall lower cooling tower duty and water consumption.

The installation of CO2 capture equipment as a retrofit for both of these technologies results in a very significant decrease in plant output. The IGCC net plant output decreases by approximately 25% and the SCPC decrease in output is 29%. Likewise, the net plant heat rate of the facilities also increases by approximately 39% for the IGCC and 41% for the SCPC. Water consumption is also increased by approximately 23% for IGCC and 34% for SCPC.

All of these factors result in an increase of the 20-year levelized busbar cost by approximately 45% for the IGCC and 58% for the SCPC post CO2 capture. SCPC technology still provides the lowest busbar cost after CO2 capture retrofit, although by less of a gap than pre-CO2 capture. The avoided cost of CO2 capture is less for an IGCC implying that IGCC technology is the more economical choice for retrofit of CO2 capture technology (if you owned both an existing IGCC

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plant and SCPC plant and were going to retrofit only one, you would choose the IGCC), however the lower initial capital cost (pre-capture) of SCPC technology still results in an overall lower busbar cost for SCPC technology.

This is the first EPRI study performed that evaluates CO2 capture as a retrofit to existing IGCC and SCPC units. Other EPRI studies have evaluated CO2 capture on new units specifically designed for and incorporating CO2 capture from the start vs. new units that are not designed with CO2 capture in mind. This study attempts to answer the question of what are the impacts from adding CO2 capture to an existing SCPC or IGCC plant at a later date.

The Shell gasification process chosen for this application utilizes a dry-feed system, which has advantages over slurry-feed gasification processes for low rank coal (for the non-CO2 capture case). The Shell gasifiers produce syngas with higher concentrations of CO and less H2 than would be produced by a slurry-feed gasifier. When adding CO2 capture equipment to the Shell gasification process, more steam is required to convert the CO to CO2 and H2 than would be required for a slurry-feed gasifier. This results in less steam available to the steam turbine, which equates to less plant output for the CO2 capture case than may be seen if using a slurry-feed gasifier. If the objective of the Owner is to capture CO2, then a slurry-feed gasifier may be a better choice than a dry-feed gasifier.

Additionally, this is the first detailed study performed by EPRI that evaluates IGCC and PC technology with CO2 capture when using a lower rank, higher moisture PRB coal. Other detailed studies performed by EPRI focused primarily on higher rank bituminous coals (using slurry-feed gasifiers), where IGCC has been shown to provide a more distinct advantage.

The performance information provided by UOP and Fluor for the CO2 capture equipment is different from data obtained for other recently published studies. A resolution of the differences is outside the scope of this project, however it is anticipated that the differences are related to the CO2 purity that was specified for this project. It should be noted that none of the technologies (IGCC, SCPC, or CO2 capture) evaluated in this study were optimized to provide the best cost-to-benefit ratio (i.e. lowest busbar cost). The designs used as the basis for this evaluation are just one of many possible configurations that should be further optimized in the future.

Changes in market conditions, improvements in IGCC technology, different fuel specifications, or CO2 purity specifications could be enough to swing the economics in favor of IGCC. Therefore, it is recommended that utilities consider IGCC technology for future generation needs. However, based on the results and design basis used in this study, SCPC provides the lowest busbar cost of the three alternatives at this time.

Current Market Conditions

In recent years, several factors have caused the cost of power projects to increase at a higher rate than in years past. Specifically in the Gulf Coast area, the destruction of Hurricane Katrina has resulted in a large labor demand for reconstruction efforts. In order to meet labor requirements, much of the construction labor force has been pulled from out of state, resulting in a construction labor shortage across the country (in an industry that was already in high demand). The high demand for qualified labor has resulted in “job-hopping” for many workers. The result is that

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labor productivity has been very poor compared to that of just a few years ago, yet the cost of construction labor is increasing at a rapid rate.

In addition to Hurricane Katrina rebuilding projects, engineering firms and construction contractors are very busy with new power generation projects and air pollution control projects designed to clean up SO2 and NOx emissions from older coal-fired units. This increased demand results in increased contingency, overhead, and profit levels for contractors. Some clients have even had challenges finding qualified contractors that are willing to bid on their projects.

Beyond labor issues, the world demand for many commodities has also increased sharply, due in large part to China’s economic growth. This high demand has resulted in a 100-300% cost increase for some commodities including steel (in particular stainless or high alloy steel), concrete, copper, oil, and nickel resulting in increased equipment costs and vendor markups.

The compounding effect of labor productivity, high labor rate escalation, commodity cost escalation, risk mitigation, and contractor markups results in much higher project costs than may have been anticipated one or two years ago.

Limitations and Qualifications

The estimates and projections prepared by Burns & McDonnell relating to construction costs, performance, and O&M are based on our experience, qualifications, and judgment as a professional consultant. Since Burns & McDonnell has no control over weather, cost, and availability of labor, materials, and equipment, labor productivity, unavoidable delays, economic conditions, government regulations and laws (including interpretation thereof), competitive bidding and market conditions or other factors affecting such estimates or projections, Burns & McDonnell does not guarantee that actual rates, costs, performance, etc., will not vary from the estimates and projections prepared herein.

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2 INTRODUCTION

Background

CPS Energy, located in San Antonio, Texas, is the nation’s largest municipally owned energy company providing both electricity and natural gas to its customers. In December of 2005, CPS Energy agreed to fund an IGCC study, as part of a settlement during the air permitting process for a new pulverized coal plant. Under the terms of the agreement, the IGCC study scope compares SCPC and IGCC technologies at a generic site in Texas. CPS Energy also agreed to make the report available to the public. This study provides typical decision support input for a power plant investment decision for a generic municipally-owned utility. The study includes generic investment decision information such as, cost of capital, forecasted fuel costs, etc. The study does not include competitive, sensitive CPS Energy power plant investment decision information.

CPS Energy contacted Burns & McDonnell to perform a technical and economic feasibility study for a nominal 550 MW 2x1 IGCC unit.

Objectives

The primary objectives of this study were to provide screening-level information for use in evaluating a 2x1 IGCC facility to be located at a generic Texas Gulf Coast site. This information consists primarily of capital cost, performance, and O&M cost estimates.

To achieve these objectives, Burns & McDonnell provided a conceptual design for the facility, consisting of preliminary process design, overall plant heat balances, preliminary process flow diagrams, preliminary electrical one-line diagrams, and preliminary site layout drawings. This information was then used to establish the plant preliminary capital cost estimate.

Once the conceptual design information was produced, IGCC technology was compared to conventional coal fired SCPC technology in a pro forma economic analysis to determine which technology resulted in the lowest busbar cost of the facility.

Additionally, the impacts of adding CO2 capture as a retrofit to the IGCC and SCPC technologies were evaluated. The impacts for performance, capital cost, O&M, emissions, and levelized busbar cost were determined.

If any of the technologies presented in this report are of interest to the Owner, it is recommended this feasibility study be followed up with more detailed studies to further define the project and

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to tailor the information for a specific site. These follow-on studies should include gasifier and gas turbine manufacturer involvement.

Status of the Technology

Conventional combined cycle technology is a proven technology that has been used for many years in the power industry. Similarly, gasification technology is a proven technology that has been used extensively in the chemical industry to produce products such as ammonia and hydrogen. IGCC technology combines these two proven technologies by producing a medium-Btu value syngas from coal or other solid fuel (petcoke) and firing it in a modified conventional gas turbine as part of a combined cycle application.

When combining these two technologies, high levels of integration between the two processes are often required to increase plant efficiency and to make IGCC competitive with other coal-fired electric power generation technologies. This integration is created by using heat exchangers to capture heat produced in the gasification process and utilizing it to increase the output and efficiency of the steam cycle, yet at the same time increasing the complexity of the plant.

IGCC projects generally utilize conventional equipment (gas turbines, heat exchangers, compressors), that when combined with the complexity of integration into an IGCC facility, has led to less than desirable availability factors and forced outage rates in the past. It has generally been the failure of this “conventional” equipment that has lead to the poor reliability and availability of the existing IGCC facilities. It is anticipated that advancements in IGCC design and increased IGCC operational experience are expected to improve availability and lower the forced outage rates for IGCC technology.

Development of the IGCC technology truly commenced in the 1970’s during the energy crisis. Research and development during this timeframe led to the construction of the Texaco Cool Water facility in California, and the LGTI facility in Louisiana. Both of these facilities have been decommissioned. Experiences and lessons learned from these facilities were brought forward during the 1990’s with the development of the Polk and the Wabash IGCC facilities. Ongoing operation of these two facilities in the United States and the Buggenum and Puertollano facilities in Europe continue to help improve the future generation of IGCC facilities.

Selection of Gasification Technology

Burns & McDonnell was requested to perform a cursory evaluation of the gasification technologies available, and select a technology to be used as a basis for this study. Focus was given only to the major technologies that currently have commercial IGCC offerings in the United States. This consists of GE, ConocoPhillips, and Shell gasification technologies.

GE and ConocoPhillips use slurry-feed gasifiers, whereas Shell uses a dry-feed gasifier. Slurry-feed gasifiers typically work well on high rank bituminous coals. When utilizing PRB as a feedstock, however, the slurry has a lower concentration due to the high inherent moisture content of the PRB coal. As a result of feeding less dense slurry to the gasifier, the cold gas

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efficiency decreases and oxygen consumption increases, typically resulting in decreased performance.

GE has several gasifiers operating in the United States and worldwide. The GE gasification technology is an oxygen-blown slurry-feed entrained flow gasifier. Most of the operating GE gasifiers are the quench design. Their IGCC offering is the radiant design intended to maximize the steam production for power generation. The GE gasification process works well on bituminous coal and/or petcoke, and they are currently working on a design for PRB, with the intention of having a commercial offering toward the end of 2006. GE was approached about participating in this study, and due to their current workload, declined to participate.

ConocoPhillips has an operating, full commercial scale gasifier at the Wabash IGCC facility. Their process is a 2-stage oxygen-blown slurry-feed entrained flow gasifier. At the LGTI IGCC facility, which was decommissioned in 1995, ConocoPhillips gasified over 3.7 million tons of PRB. ConocoPhillips was also approached about participating in this study, and due to their current workload, declined to participate.

Shell currently has three coal gasifiers operating worldwide. Two started up this year in China and the Shell gasifier is used at the NUON IGCC facility in the Netherlands. Eleven other Shell coal gasifiers are currently under construction in China. The Shell coal gasification process is an oxygen-blown dry-feed entrained flow gasifier that is suitable for PRB gasification. The dry-feed system of the Shell gasifier also likely provides some performance benefits over slurry-feed gasifiers when designing for low-rank coals such as PRB. Shell was approached about participating in the study and also declined to participate directly, but agreed to allow EPRI to perform modeling of their gasification system and supply the results to Burns & McDonnell.

Based on the likely performance benefits associated with the Shell process for PRB coal, it was agreed that the Shell gasification process would be used as the basis for this evaluation.

It should be noted that all of the gasification technologies described above perform differently and have different O&M requirements. The GE and ConocoPhillips gasifiers are refractory lined, whereas the Shell gasifier has a steam tube membrane wall. The refractory lined gasifiers require a periodic replacement of the refractory due to wear in the high slag flow areas, whereas the membrane wall tubes require little maintenance. Also, the Shell process is a dry-feed, versus slurry-feed for the GE and ConocoPhillips processes. Due to the higher concentrations of water, the syngas from the GE and ConocoPhillips gasifiers has higher concentrations of CO2 and H2 and the syngas from the Shell process has a higher concentration of CO.

Project Experience

Table 2-1 shows the current and previous IGCC facilities that were developed in the United States and in Europe. All of the United States facilities were developed with funding assistance from the Department of Energy.

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Table 2-1 IGCC Facilities – Past and Current

Facility Owner Capacity (MW)

Commercial Operation

Date

Gasifier Manufacturer

Status

Puertollano Elcogas 321 1998 Prenflo Operating Polk

County Tampa Electric

252 1996 GE Operating

Wabash River PSI Energy 262 1995 Conoco Phillips Operating

Buggenum NUON 254 1994 Shell Operating

Pinon Pine Sierra Pacific

99 1997 KRW Decommissioned

LGTI Dow

Chemical 160 1987 Conoco Phillips Decommissioned

Cool Water Texaco 125 1984 GE Decommissioned

Fuel experience

Within the United States, relatively little IGCC experience exists with PRB as the feedstock. As noted previously, between 1987 and 1995, the LGTI facility gasified over 3.7 million tons of PRB. This represents the majority of the United States operating experience with PRB gasification.

There has been significant operating experience with petcoke. Petcoke lends itself well to gasification due to the higher heating content, low moisture, and low ash. However, petcoke does have significantly higher sulfur content. Due to the trace metals in the petcoke, either a fluxant or coal needs to be blended with the petcoke to enable the ash to flow out of the slagging gasifiers. Currently, the fuel for the Polk IGCC facility is a blend of coal and petcoke, and petcoke is being utilized at the Wabash IGCC facility.

Shell has processed both PRB coal and petcoke during the early 1990s at a 250 tpd demonstration plant at Shell’s Deer Park, TX refinery. Shell has reported a cold gas efficiency of 78.0% with 99.7% carbon conversion and 99.9% sulfur capture during 297 hours of tests on PRB and 78.9% cold gas efficiency with 99.5% carbon conversion and 99.8% sulfur capture during 169 hours of operations on petcoke.

Technical Approach and Data Sources

As noted above, the Shell coal gasification process was selected for this study. EPRI provided the gasifier yield and thermal performance for the gasification plant (up to the wash column inlet). Burns & McDonnell performed the preliminary design of the low temperature gas cooling and scrubbing section, COS/HCN catalyst section, AGR, SRUs, TGTU, power block, and balance of plant. The following vendors were used to provide additional information:

• UOP provided an equipment list and performance information for the SELEXOL unit.

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• Air Liquide Process and Construction (ALPC) provided cost and performance information for the ASU.

• Sud-Chemie provided cost and performance information for the COS/HCN catalyst.

• NUCON provided cost and performance information for the mercury removal bed.

• Fluor provided cost, performance, and emissions information for the Econamine FG Plus

Plant (EFG+) for SCPC CO2 capture.

The information provided herein does not represent a thorough performance or cost optimization. Further optimizations (capital cost investment vs. performance, emissions, or O&M benefits) can be performed that would likely improve the busbar cost of all technologies (SCPC, IGCC, and CO2 capture).

3-1

3 STUDY CRITERIA

Site Selection

The site for this project is based on a generic greenfield site located in the Texas Gulf Coast.

The ambient conditions used as the design basis of this study are the 2% dry bulb (dry bulb temperature is exceeded 2% of the year), average dry bulb, and 95% dry bulb (dry bulb temperature is exceeded 95% of the year)

The ambient conditions are as follows:

• 2% Dry Bulb: 93°F with coincident wet bulb temperature of 77°F.

• Average Dry Bulb: 73°F with coincident wet bulb temperature of 69°F.

• 95% Dry Bulb: 43°F with coincident wet bulb temperature of 40°F.

The finished grade of the site is assumed to be 100 ft. Additional assumptions about the site can be found in Chapter 7.0

Gas Turbine Selection

The gas turbines selected as the basis for this project are GE 7FB gas turbines. EPRI and Burns & McDonnell have access to more readily available information for GE’s 7FB gas turbines than from other manufacturers. Also, GE has much experience with syngas operation, having accumulated over 300,000 hours of operation on syngas; however GE has no operating experience with firing syngas in the 7FB. Although GE has this significant syngas operating experience, other gas turbine manufacturers are able to offer similar gas turbines that should result in a comparable result.

Fuel Selection

PRB fuel is currently utilized by several utilities in Texas. This low-sulfur coal has proven to be an economical choice for generation in Texas.

Additionally, petcoke, a byproduct of the refining process, has proven to be an economical fuel alternative for other generating facilities across the nation. Refineries are typically eager to

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remove this byproduct from their site; therefore petcoke is relatively inexpensive from the refinery. The expense of petcoke is dictated by transportation costs from the refinery to the power plant. The prospect of petcoke firing is typically limited by the following factors:

1) Projects planning to fire petcoke are typically located near refineries that produce coke as a byproduct.

2) The quantity of petcoke is typically only available in sufficient quantities to supply a part of the overall heat input to a large power facility.

3) Firing 100% petcoke in a PC unit is only achievable using a special down-fired boiler. Conventional designed PC units are limited to approximately 20% petcoke firing due to the low volatiles in the coal.

Therefore, petcoke is typically blended with other fuels when used in large scale power generation.

Because this project is located in the Texas Gulf Coast, petcoke should be available as an alternate fuel source from nearby refineries. Therefore, two independent IGCC options were evaluated for this project:

• Option 1 – 100% PRB Coal

• Option 2 – 50% PRB Coal / 50% Petcoke (% by weight)

Fuel analyses are provided in Table 3-1.

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Table 3-1 Fuel Analyses

100% PRB 100% Petcoke 50% PRB / 50% Petcoke

PRB (% wt.) 100% 0% 50%Petcoke (% wt.) 0% 100% 50%PRB (% heat input) 100% 0% 36.40%Petcoke (% heat input) 0% 100% 63.60%HHV (Btu/lb) 8,156 14,231 11,194

Proximate Analysis (% wt.) Moisture 30.24 4.83 17.53 Volatile Matter 31.39 10.60 21.00 Fixed Carbon 33.05 84.44 58.74 Ash 5.32 0.13 2.73

Ultimate Analysis (% wt.) Carbon 48.18 83.62 65.88 Hydrogen 3.31 3.02 3.17 Nitrogen 0.70 0.85 0.78 Chlorine 0.01 0.01 0.01 Sulfur 0.37 6.60 3.49 Oxygen 11.87 0.94 6.41 Ash 5.32 0.13 2.73 Moisture 30.24 4.83 17.53 Total 100.00 100.00 100.00

Mercury (ppm) 0.091 0.05 0.07

Ash Fusion TemperaturesReducing Atmosphere

Initial Deformation 2150°F 2800+°F N/ASoftening 2170°F 2800+°F N/AHemispherical 2190°F 2800+°F N/AFluid 2210°F 2800+°F N/A

Oxidizing AtmosphereInitial Deformation 2220°F 2,505°F N/ASoftening 2240°F 2,597°F N/AHemispherical 2260°F 2,610°F N/AFluid 2280°F 2,611°F N/A

Plant Capacity Selection

The largest IGCC facility that has been constructed in the United States is a 1x1 (one gasification/gas turbine/HRSG train and one steam turbine). Currently, 2x1 IGCC technology is the primary focus of IGCC development by both manufacturers and developers due to improved economies of scale. It is possible to improve the economies of scale of an IGCC facility further by adding an additional gasification/gas turbine/HRSG train (3x1 facility). However due to a general aversion to risk in the industry, it is unlikely that a 3x1 IGCC facility will be developed until 2x1 IGCC technology has been proven successfully in the United States. Therefore, a 2x1 IGCC facility is the basis of this study.

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The plant capacity for this project is dictated by the capacity of the gas turbines coupled with the available energy that can be recovered from the gas turbine and gasification process. For this project, the 2x1 IGCC facility has a nominal net plant output of 550 MW.

Capacity Factor and Availability Factor Targets

Capacity Factor (CF) is defined as the actual MWh produced in a year divided by the maximum possible MWh produced in a year. Generally, capacity factors for units are dictated by economic issues. Lower production cost technologies operate at base load (capacity factors above 70%), whereas higher production cost technologies tend to operate as “peaker” plants or for serving an intermediate load (operating throughout the day and ramping down at night).

The large capital and operating expenditure (yet lower fuel cost) of a coal plant are typically only justified by operating the unit at base load. Due to the increase of natural gas prices and limited base load resources, capacity factors of conventional PC plants are typically at 85% or higher. The O&M estimates and economic evaluation provided in this study assume a capacity factor of 85%, with a 100% load factor (operating 85% of the time at full load and off-line the other 15% of the time).

The Availability Factor (AF) is defined as the sum of service hours and reserved shut down hours divided by the total hours per year. Essentially, it is the percentage of hours in a year that the plant is available to operate.

Some IGCC facilities have been evaluated with a spare gasifier to increase availability factors and allow increased operational flexibility. It was decided that the increased operating and capital expenses of the spare gasifier are not justified for this project at this time. The resulting availability factor is approximately 85% for the IGCC technologies evaluated.

Additional information on plant availability factors can be found in Chapter 9.0.

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4 PROCESS DESCRIPTION

Gasification System Description

For this report, the Gasification System refers to all of the equipment required to make syngas. This includes the ASU, gasifiers, slag handling, candle filters, wash towers, COS/HCN hydrolysis, mercury removal, syngas cooling and condensation, AGR, SRUs, tail gas treatment, sour water stripping, and syngas saturation. Process flow diagrams are included in Appendix A for reference. A block flow diagram is provided in Figure 4-1.

Figure 4-1 Gasification Block Flow Diagram

Air Separation Unit (ASU)

Atmospheric air is dried and then cryogenically distilled in the ASU to produce 95% oxygen and several nitrogen steams. The air separation unit selected for this study is a high-pressure ASU, meaning that the columns all operate at a higher pressure than a conventional low-pressure ASU. The selection of an HP or LP ASU depends primarily on the amount of nitrogen required under

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pressure vs. the oxygen requirement. Because of the large nitrogen requirement, the primary benefit of the HP ASU is the reduced power requirement for N2 compression.

The majority of the oxygen produced in the ASU is supplied at high pressure (780 psia) for use in the gasifiers. A small amount of low pressure oxygen is used as the oxidant in the SRU.

Uses for the nitrogen streams are as follows:

• High pressure (1089 psia) N2 with 0.1% O2 is used for conveying the fuel into the gasifier and other purposes in the gasification block.

• Medium pressure (480 psia) N2 with 2% O2 is used as diluent in the gas turbines for NOx control.

• Low pressure (140 psia) N2 with 2% O2 is used for regeneration of the molecular sieve driers and miscellaneous purges.

Cryogenic pumps are used to supply the high pressure nitrogen and oxygen streams to the gasifier. The cryogenic pumps were chosen because of their lower auxiliary power consumption and lower cost than gas compression. Additionally, pumping liquid O2 is generally viewed to be safer than compression of gaseous O2. The high-pressure liquid oxygen and nitrogen are then vaporized prior to the gasifier. The medium pressure and low pressure nitrogen streams are pressurized by nitrogen compressors.

The ASU scope includes storage of high-pressure, high-purity nitrogen equivalent to 12 hours of production in liquid form. Additionally, 20 minutes of production as gas is available at pressure to provide nitrogen during the period of time that back-up liquid vaporization comes on line. The back-up system is to be designed to deliver high pressure nitrogen within 10 minutes after being activated.

The material balances around the ASU for the 100% PRB cases (43°F and 93°F) are provided in Table 4-1, which are used to set the design requirements of the ASU. Since very little difference exists between the ASU for the 100% PRB case and the 50% PRB / 50% petcoke case, the same ASU design was used for both options. Additionally, Figure 4-2 provides a block flow diagram for a generic ASU.

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Table 4-1 ASU Material Balances

Case 93F PRB Coal<------------------------------------Nitrogen Product Streams----------------------------->

Stream Ambient Air GT Air Total Air In Total Dry Air O2 Product Conveying HP To Process LP Misc Sieve Regen. Remaining N2 to GTlb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr

H2O 1,390 1 1,392 1,392O2 11,057 11 11,068 11,068 10,383 2 4 2 187 490 677N2 41,211 41 41,252 41,252 164 1,930 4,000 1,555 9,164 24,439 33,603Ar 492 0 492 492 383 1.9 4.1 1.6 9 93 102Total 54,150 54 54,204 52,812 10,930 1,934 4,008 1,559 9,360 25,021 35,773% O2 20.4% 20.4% 20.4% 21.0% 95.0% 0.1% 0.1% 0.1% 2.0% 2.0% 1.9%

Temp, F 93 810 382 280 280 56 56 56 453Pres. psia 15 218 760 1068 1068 140 140 140 290Total lb/hr 1,552,965 1,547 1,554,511 1,529,437 352,142 54,206 112,353 43,692 263,066 703,991 992,132

Case 43F PRB Coal<------------------------------------Nitrogen Product Streams----------------------------->

Stream Ambient Air GT Air Total Air In Total Dry Air O2 Product Conveying HP To Process LP Misc Sieve Regen. Remaining N2 to GTlb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr

H2O 253 168 422 422O2 7,281 4,854 12,135 12,135 11,360 2 4 2 187 580 767N2 27,138 18,092 45,230 45,230 179 1,930 4,000 1,555 9,164 28,402 37,566Ar 323 216 539 539 419 1.9 4.1 1.6 9 103 113Total 34,996 23,330 58,326 57,904 11,958 1,934 4,008 1,559 9,360 29,085 38,867% O2 20.8% 20.8% 20.8% 21.0% 95.0% 0.1% 0.1% 0.1% 2.0% 2.0% 2.0%

Temp, F 93 810 382 280 280 56 56 56 453Pres. psia 15 218 760 1068 1068 140 140 140 290Total lb/hr 1,010,697 673,785 1,684,482 1,676,887 385,263 54,206 112,353 43,692 263,066 818,321 1,088,982

Note: The air provided by the GTG (stream 2) is cooled to ambient temperature by heat exchange with steam cycle condensate and auxiliary cooling water prior to being sent to the ASU. The N2 to the gas turbine (stream 11) is heated from ~350°F at the discharge of the final stage of compression to 453°F using IP boiler feedwater as the heat source prior to the gas turbine.

The following major equipment items are included:

• Main air compressor and booster air compressor (2 trains x 50%).

• Nitrogen compressor (2 x 50%).

• Cryogenic oxygen pumps (2 x 100%).

• Cryogenic nitrogen pumps (2 x 100%) for high pressure N2.

• Cold box.

• Switching valves, driers and regeneration heater.

• MV and LV Switchgear and MCC.

• Transformers from 13.8 KV.

• Liquid N2 storage and associated backup vaporizer.

• Electrical / control room.

• Commissioning spares.

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Figure 4-2 Generic ASU Process Flow Diagram

Additionally, heat exchangers are provided to cool the extracted air from the gas turbine to ambient temperature prior to the ASU and to heat the nitrogen from the ASU to the gas turbine. These costs are not included in the ASU cost provided by ALPC, however they are included in the BOP costs.

Gasifiers

The gasification plant for this project is comprised of two Shell oxygen-blown entrained-flow gasifiers, each capable of supplying enough syngas for operation of one gas turbine at full load. Each gasification train is comprised of coal milling and drying equipment, coal pressurization lockhopper, high pressure oxygen and coal feed systems, gasifier vessel, slag removal system, syngas cooling, syngas recycle compressor, and particulate removal systems.

The Shell gasifier uses a dry-coal feed system. This system requires the feedstock moisture content to be reduced to approximately 5% prior to injection to the gasifier. Therefore, coal drying equipment is required which utilizes syngas (or natural gas during startup) to drive off the excess moisture in the fuel. The coal dryer is combined with the coal milling equipment in a vertical roller mill which pulverizes the coal to the required consistency. The dried and pulverized coal is raised above the gasifier operating pressure in a set of lockhoppers and conveyed to the gasifier using high pressure nitrogen. PRB fuel is highly reactive and has a high potential for spontaneous combustion; consequently the oxygen concentration in the milling/drying and coal feeding systems is minimized via the injection of nitrogen at various locations. A detailed evaluation of the operation of the coal dryer relative the PRB fuel was not performed.

Process Description

4-5

The fuel and high pressure oxygen react in the gasifier at high temperatures (2,700 ºF) and approximately 560 psia to produce syngas. The gasifier, operating in an oxygen deficient (reducing) atmosphere, is designed to operate at conditions suitable to promote reactions which produce a synthesis gas (syngas) and slag. The syngas produced in the gasifiers is rich in hydrogen, carbon monoxide, and water. There are also lesser amounts of several components including carbon dioxide, hydrogen sulfide, carbonyl sulfide, methane, argon, and nitrogen.

The gasifier vessel walls are cooled using water-wall membranes that produce medium-pressure (MP) steam at approximately 650 psia. The syngas is quenched by recycle of cooled, particulate-free syngas to ~1,700°F. The syngas then passes to the syngas cooler which also uses medium pressure feedwater as a cooling medium. Heat from the syngas is transferred to the feedwater resulting in the generation of medium pressure saturated steam that is transferred to the HRSG in the power block for superheating and re-introduced to the steam turbine as “hot reheat” steam. After being partially cooled in the syngas cooler, the syngas passes through a candle filter to remove entrained solids from the syngas. Additionally the syngas is passed through a water wash scrubber which is primarily used to remove fine particulate, chlorides, and any other water-soluble compounds (see Syngas Wash Towers section below).

Alternatively, HP steam can be generated in the syngas cooler, however this greatly increases the cost of the syngas cooler and associated piping (alloy materials vs. carbon steel), resulting in ~$60-$70 million increase in total project cost. Shell claims that the use of HP steam generation in the syngas cooler can result in a 1.5% improvement in IGCC efficiency; however this option was viewed as cost prohibitive at this stage of the project. It is recommended that this option be evaluated in more detail at a later developmental stage of the project.

Gasifier Performance Estimate by EPRI

EPRI used its internal IGCC modeling tool, which uses a Gibbs Free Energy Minimization approach to estimating gasifier product composition and temperature. EPRI relied heavily on the performance data Shell published in a 2004 Gasification Technologies Conference paper to set the inputs for the gasifier model. That paper presented performance estimates for the Shell coal gasification process on a generic Powder River Basin coal and on a 50/50 mixture of PRB and petcoke. One difference between the Shell design premises and those used by EPRI was the purity of the oxygen feed stream. Shell assumed it was 99 v% O2, while EPRI chose 95 v% as several engineering studies have shown that to be the optimal value for IGCCs producing power only.

A summary of the main inputs and outputs from the gasifier performance model at the 43°F ambient condition is provided in Table 4-2.

Process Description

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Table 4-2 Summary of Gasifier Modeling Results

100% PRB 50% PRB / 50% Petcoke

Model Inputs O2/coal feed ratio (95v% O2) lb/lb-coal1 0.771 0.881 Steam/coal lb/lb-coal1 0.034 0.104 N2/coal lb/lb-coal1 0.110 0.107 Syngas Exit Pressure psia 574 574 Heat Flux to Gasifier Wall %coal HHV 0.6 1.4 Carbon Conversion % 99.5 99.0 Model Results Syngas Exit Temperature ºF 2732 2913 Gasifier Wall Steam Production MMBtu/hr 32.7 74.8 Syngas Exit Composition CH4 %vol 0.019 0.018 CO %vol 59.91 64.85 CO2 %vol 2.66 1.10 COS %vol 0.013 0.110 H2 %vol 26.78 25.23 H2S %vol 0.168 1.21 H2O %vol 4.13 1.65 HCN %vol 0.005 0.011 NH3 %vol 0.005 0.003 N2 %vol 5.33 4.80 AR %vol 0.97 1.02 O2 Feed Rate lb/hr 377,816 364,983 Steam Feed Rate lb/hr 16,688 42,939 N2 for Coal Conveying lb/hr 54,069 44,371 Coal Feed Rate lb/hr 490,171 414,125 Coal Feed Rate2 MMBtu/hr 5,444.3 5,340.7 Unquenched Syngas Flow Rate lb/hr 901,760 850,367 Syngas Production Rate2 MMBtu/hr 4,561.7 4,453.4 Flyslag (overhead) Production lb/hr 10,084 6,185 Slag (bottom) Production lb/hr 26,900 9,866 Cold Gas Efficiency3 % 83.8 83.4 1 As fed coal basis (dried to 5 wt% H2O) 2 HHV basis 3 As fed coal HHV basis only, energy value of feed steam and dryer fuel not included

Slag Handling

Slag formed in the coal gasification process flows to the bottom of the gasifier. This slag is quenched in a slag bath that is located within the gasifier vessel. Water is circulated through the slag bath to recover the heat from the slag. The hot slag water is cooled with a heat exchanger.

The cooled slag settles to a slag accumulator and lockhopper vessel. Once the slag has settled to the lockhopper vessel, the valves between the slag accumulator and lockhopper vessel are closed. The lockhopper provides a transition between the pressurized gasifier and the atmospheric slag dewatering system. Once isolated from the gasifier, the lockhopper is depressurized and the

Process Description

4-7

valves are opened at the outlet of the lockhopper vessel. The slag and water mixture are then discharged to the slag dewatering system. This lockhopper system operates in batch mode continually to remove slag from the gasifier as it is accumulated.

The slag from the outlet of the lockhopper is dewatered using a submerged scraper conveyor. The slag slurry water from the bottom of the submerged scraper conveyor is pumped to a clarifier where the clean slag slurry water is recycled to the lockhopper and the fines are collected and re-injected into the gasifier. The coarse slag from the outlet of the submerged scraper conveyor is conveyed to a slag storage pile. The coarse slag can then be landfilled or sold to market. The glassy, inert slag produced in the Shell gasifier is very low in carbon content which makes the slag attractive for sale.

Fly Ash System

After the syngas cooler, the syngas passes through first a cyclone and then ceramic candle filters that remove particulate matter (flyash) from the syngas. Similar to removing the slag from the gasifier, the flyash is removed from the cyclone and candle filter vessels with a batch process using lockhoppers. The coarse flyash that was removed by the cyclone can be recycled to the coal mill if it contains a significant amount of unconverted carbon. Otherwise, the coarse flyash along with the finer flyash collected by the candle filters is temporarily stored on site and either landfilled or sold to cement manufacturers or to other markets for flyash.

Syngas Wash Towers

Raw syngas flows from the candle filter to the syngas wash towers where the syngas is washed with water. The purpose of the water wash is twofold: 1) to recover any particulates that pass through the candle filters and 2) to recover chlorides that dissolve in the wash water and remove them from the system at concentration less than 300 ppm (to avoid corrosion of the carbon steel tower and piping). The wash water is primarily fresh demineralized water to which recycled water streams from the saturator water circulation loop (a purge stream) and the sour water stripper bottoms are added.

The water streams from the bottom of the syngas wash towers flow to a common system consisting of several operations:

• The first step is a flash at 7 psia. Liquid from the flash is cooled with make-up demineralized water used for syngas saturation before being filtered and sent to the cooling tower as make-up water.

• Solids recovered from the filtration mentioned above (particulates not removed by the candle filters) are sent to the coal pile. The amount of solids is estimated at only 110 lb/day.

• Vapor from the 7 psia flash is condensed under vacuum using an air cooler.

• Liquid condensed in the air cooler is separated from the small amount of vapor and is pumped to the sour water stripper.

Process Description

4-8

• Vacuum conditions in the condensate drum are maintained by a steam jet ejector. Effluent from the ejector flows to the sour water stripper.

This design was generated by Burns & McDonnell in absence of detailed design information by Shell and does not represent Shell’s standard syngas scrubbing and sour water treatment design. It is recommended that the design of this system be evaluated in detail in conjunction with Shell at a later development stage of the project.

The syngas wash system consists of the following equipment:

• Syngas wash tower (one tower for each of two parallel trains).

• Recovered water flash drum (one common drum for two parallel trains).

• Recovered wash water pumps (one common pump with a full spare for two parallel trains).

• Recovered wash water exchanger (one common exchanger for two parallel trains).

• Recovered wash water filters (one common filter with a full spare for two parallel trains).

• Flashed water condenser (one common air cooler for two parallel trains).

• Flash water condensate drum (one common drum for two parallel trains).

• Flashed water steam ejector (one common ejector for two parallel trains).

• Flashed water condensate pumps (one common pump with a full spare for two parallel trains).

Washed syngas flows to the COS/HCN hydrolysis reactors.

COS / HCN Hydrolysis

The syngas contains trace amounts of carbonyl sulfide (COS) and hydrogen cyanide (HCN) and relatively large amounts of both H2 and H2O. Hydrolysis of COS is required because the AGR removal step (SELEXOL) only removes about 50% of the COS fed to AGR. The quantity of COS present in the raw syngas is such that if not hydrolyzed the concentration of COS alone in the feed to the gas turbines would be 60 ppmv for the 100% PRB case and 480 ppmv for the 50% PRB / 50% petcoke case compared to the required 30 ppmv level for COS plus H2S. The use of catalytic hydrolysis reduces the contribution of COS in the gas turbine feed gas to 1 ppmv and 5 ppmv for the 100% PRB and 50% PRB / 50% petcoke cases, respectively.

Hydrolysis of HCN occurs simultaneously with COS and effectively removes the HCN from the GTG feed gas. Removal of HCN, which is a form of fuel-bound nitrogen, results in less NOx emissions from the gas turbines. The same catalyst is appropriate for both hydrolysis steps.

The COS and HCN are hydrolyzed according to the following reactions:

COS + H2O H2S + CO2

Process Description

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COS + H2 H2S + CO

HCN + 2 H2O NH3 + H2 +CO2

Sud-Chemie provided operating conditions that are expected to result in COS and HCN conversions greater than 99%.

Unconverted H2S along with other components in the tail gas from the TGTU are recycled and mixed with the syngas just upstream of the feed / effluent exchanger associated with the hydrolysis reactor. The feed gas to hydrolysis is further heated with high-pressure boiler feedwater just prior to entering the hydrolysis reactor to raise the temperature to the required level.

The COS and HCN Hydrolysis system consists of the following equipment:

• Hydrolysis interchanger (one exchanger for each of two parallel trains).

• Hydrolysis reactor (one reactor for each of two parallel trains).

After passing through the hydrolysis reactor, the syngas flows to syngas cooling and condensation.

Syngas Cooling and Condensation

The syngas is cooled prior to flowing to mercury removal in a set of three heat exchangers:

• Sweet syngas from AGR provides the heat sink for the first stage.

• Condensate from the surface condenser of the steam turbine provides the heat sink for the second stage.

• Cooling water provides the heat sink for the third stage.

Water condensed from the syngas is separated from the syngas and flows to the sour water stripper. Part of the condensate is recirculated to a point just upstream of the first stage of condensation to assure that the stream entering the condenser is partially liquid.

Primary equipment items included:

• Syngas interchanger (one exchanger for each of two parallel trains).

• First stage syngas condenser (one exchanger for each of two parallel trains).

• Second stage syngas condenser (one exchanger for each of two parallel trains).

• Water knockout drum (one drum for each of two parallel trains).

• Sour water pumps (one pump plus a full spare for each of two parallel trains).

Process Description

4-10

Mercury Removal

It is important that the temperature of the feed gas to mercury removal be above the dew point in order to avoid contamination of the carbon bed with condensed water. For this reason the saturated syngas from syngas cooling and condensation is heated to approximately 5°F above the dew point prior to flowing to the mercury removal beds.

Adsorbent beds are used to remove mercury from the syngas. One bed is provided for each train. Information from NUCON was used as the basis for the study. A mercury removal of 90% or greater is expected. This adsorbent is an activated carbon made from coal.

The mercury removal system consists of the following equipment:

• Mercury removal preheater (one exchanger for each of two parallel trains).

• Mercury adsorbent bed (one vessel for each of two parallel trains).

• Mercury removal aftercooler (one exchanger for each of two parallel trains).

After passing through the mercury removal beds the syngas is cooled with cooling water prior to flowing to AGR.

Acid Gas Removal (AGR)

UOP’s SELEXOL AGR system is generally considered to be the standard for acid gas recovery from IGCC syngas. However, it was felt that the relatively modest sweet syngas sulfur specification (30 ppmv) and the low sulfur content of the PRB-only feed case might allow the use of other technologies. Amine treating was one technology considered. After discussion with UOP it was determined that the 30 ppmv specification benefits both the SELEXOL and amine processes, and that for the operating pressure of this study SELEXOL will at least be competitive with, if not preferred to, amine absorption. Further, the use of SELEXOL lends itself to future CO2 capture while amine treating does not. As a result of this analysis, amine treating was eliminated from further consideration for this study.

Another technology considered for the PRB-only, non-capture case was Sulferox. It was initially anticipated that the small sulfur recovery capacity needed (25 LTPD) would permit the use of a Sulferox unit or similar redox technology in place of a SELEXOL AGR with Claus SRU and SCOT-type TGTU. However, discussions with one vendor suggested that the best use of the redox unit would be as a replacement for the Claus/SCOT units. In this case the SELEXOL unit is still needed for acid gas removal. Another disadvantage of redox sulfur recovery is the relatively poor quality of sulfur product and additional handling and drying steps needed. SELEXOL was subsequently chosen as the AGR technology for both the PRB-only and PRB-PETCOKE cases for this study.

The SELEXOL solvent is a mixture of dimethyl ethers of polyethylene glycol. SELEXOL is a physical solvent, as compared to amines that form chemical complexes and require more energy to regenerate. SELEXOL solvent is chemically inert and is not subject to the same corrosion and degradation problems as amines.

Process Description

4-11

SELEXOL solvent has a higher affinity for H2S than CO2. This allows a SELEXOL system to achieve a very high rejection of H2S from the syngas, to meet the specification of less than 30 ppm of H2S + COS in the treated syngas, while allowing a controlled “slip” of CO2 depending on the design requirements. Slip is defined as the percentage of CO2 that leaves the system with the sweet syngas compared to the CO2 in the feed to SELEXOL. CO2 slip sets the concentration of H2S in the acid gas product from the SELEXOL unit. Very high acid gas concentrations (greater than 50% H2S) require large, costly equipment and solvent circulation rates. Very low concentrations (less than about 25% for an oxygen-blown SRU that is also burning sour water stripper gas) complicate downstream SRU design and operation.

For each of the feed cases, UOP was asked to provide SELEXOL unit material balances and equipment lists for 25% and 50% H2S acid gas products. The information provided by UOP was evaluated and, based on this evaluation, acid gas concentrations of 25% and 50% H2S were selected for the PRB and PRB-PETCOKE cases, respectively. Although these are not completely optimized selections, they are believed to give reasonable estimates of capital and operating costs for the two cases.

SELEXOL consists of absorber and stripper towers, stripper reboiler, rich/lean solvent exchanger and flash drums typical for such systems. A simplified process flow diagram for SELEXOL is presented in Figure 4-3.

Process Description

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Figure 4-3 SELEXOL Process Flow Diagram

The lean SELEXOL solvent is chilled using refrigeration to optimize the solvent circulation rate and energy input. Low pressure steam is used to supply heat to the stripper reboiler.

Primary equipment items included:

(Note: The AGR unit is a single train serving both gasifier trains.)

• H2S absorber.

• H2S stripper with reboiler, condenser, reflux drum and pumps.

• Rich flash coolers and drum.

• Lean / rich exchanger.

• Lean solvent chiller.

• Rich flash compressor.

• Refrigeration package.

Process Description

4-13

Sulfur Recovery and Tail Gas Treating

A block flow diagram of the SRUs and TGTU is shown in Figure 4-4. Acid gases from the AGR unit and from the sour water stripper (SWS) unit are treated in two parallel Claus SRUs to destroy hydrogen sulfide and ammonia. Tail gas from the two SRUs is combined and fed to a single TGTU to convert residual sulfur dioxide from the Claus process back to hydrogen sulfide before it is compressed and recycled to the COS Hydrolysis sections of the gas cooling trains. To minimize the volume of recycle gas all of the oxygen required for SRU operation is supplied at 95% purity by the ASU. A thermal oxidizer is included to handle vent streams from the sulfur pits and truck/rail loading facilities.

Figure 4-4 Block Flow Diagram – Sulfur Recovery and Tail Gas Treating

Approximately 96% of the sulfur in the acid gas feeds is recovered in one pass through the SRUs. By recycling the remaining hydrogen sulfide back through the gas cooling trains overall sulfur recovery from the syngas streams is increased to over 99%.

Sulfur Recovery Units (SRU)

Hydrogen sulfide is destroyed to form sulfur byproduct in Claus-technology SRUs. H2S is converted to sulfur according to the Claus reaction:

2H2S + SO2 ↔ (3/n)Sn + 2H2O

Sulfur dioxide is generated by reacting part of the H2S in the acid gas feed with oxygen in a thermal reactor:

H2S + 1.5O2 ↔ SO2 + H2O

Process Description

4-14

The 2:1 mixture of SO2 and H2S is then passed through a series of catalytic reactor stages to facilitate the Claus reaction. Sulfur is removed after each step by condensing it out of the vapor phase.

Sour water stripper gas is also fed to the SRUs for the purpose of ammonia destruction. Ammonia is destroyed in the thermal reactor by either combustion or dissociation:

2NH3 + 1.5O2 ↔ N2 + 3H2O

2NH3 • N2 + 3H2

To destroy ammonia, the thermal reactor must operate above 2300-2400°F. For the 100% PRB case, the AGR acid gas feed contains only 25% hydrogen sulfide. As a result the heat content of the stream is very low. Part of the AGR acid gas stream must be bypassed around the thermal reactor and the remaining AGR acid gas must be preheated to achieve the high temperature needed for ammonia destruction. This is referred to as a split-flow SRU, and is a common application of the technology. For the 50% PRB / 50% petcoke, the AGR acid gas feed contains 50% hydrogen sulfide. The heat content of the stream is high enough to produce the necessary temperature without bypassing or preheating.

Waste heat boilers downstream of the thermal reactors produce saturated 600 psia steam. Part of the steam is used to heat the feeds to the catalytic reactor stages. The remainder is exported to the steam cycle for power generation. Each SRU has three stages of sulfur condensation, reheat and catalytic reaction. Low-level steam is produced in the sulfur condensers and exported to the steam cycle.

Tail gas from the final sulfur condenser goes to the Tail Gas Treating Unit. Elemental sulfur produced by the SRU is collected in a sulfur pit (sump). From there, the sulfur is pumped to the railcar loadout facility for transportation off-site.

Two 50% SRU trains are included in the estimate. Primary equipment items included for the SRU trains are:

• AGR acid gas knockout drum (one for each train).

• AGR acid gas knockout drum pumps (one operating pump with one full spare for each train).

• AGR feed heater (PRB-only case, one for each train).

• Sour water stripper acid gas knockout drum (one for each train).

• Sour water stripper acid gas knockout drum pumps (one operating pump with one full spare for each train).

• Combustion air startup blower (one for each train).

• Thermal reactor and acid gas burner (one for each train).

• Waste heat boiler (one for each train).

• Sulfur condenser (one for each train).

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4-15

• Reheat exchangers (three for each train).

• Catalytic reactor vessel (one vessel with three compartments for each train).

• Final sulfur condenser (one for each train).

• Low-pressure steam condenser (one for each train).

• Sulfur pit (one for each train).

• Sulfur transfer pumps (one operating pump with one full spare for each train).

• Sulfur railcar loadout facility.

Tail Gas Treating Unit (TGTU)

The TGTU for this study consists of a catalyzed hydrogenation reaction step that converts residual sulfur dioxide back to hydrogen sulfide, followed by gas cooling. There is normally ample hydrogen and carbon monoxide present in the SRU tail gas for the reduction reaction. However, if additional hydrogen is needed to feed the tail gas reactor, syngas can be added upstream of the reactor.

The tail gas reaction is:

SO2 + 3H2 ↔ H2S + 2H2O

Gas cooling includes a waste heat steam generator followed by direct contact with water in a packed quench tower. The small amount of water condensed in the quench tower is exported to the sour water stripper unit.

The amine absorber and regenerator that are typically attached to TGTUs for hydrogen sulfide recovery are not required in this service, since the tail gas is recycled to the gas cooling trains. This eliminates a source of H2S/SO2 emissions and improves recovery of carbon monoxide and hydrogen for power generation.

A single TGTU services both SRUs. The TGTU consists of the following equipment:

• Tail gas feed heater.

• Tail gas hydrogenation reactor.

• TGTU waste heat boiler.

• Quench tower.

• Quench water pumps (one operating pump with one full spare).

• Quench water air cooler.

• Quench water trim cooler.

Process Description

4-16

Tail Gas Compression

Multistage reciprocating compressors are required to boost treated tail gas to the pressure required for recycle to the gas cooling trains. Two full-capacity compressors with interstage knockout drums are provided for reliability.

A net production of carbonyl sulfide is anticipated through the SRUs and TGTU due to reactions of sulfur compounds with carbon monoxide and carbon dioxide. As a result, the tail gas must be recycled to a point upstream of the COS hydrolysis section. A small quantity of sour water is created as the tail gas is compressed. This water is exported to the sour water stripper unit.

Thermal Oxidizer

Purging of sulfur pit vapor spaces and vent recovery from sulfur loading operations will create vent streams containing mixtures of air and hydrogen sulfide. These vent streams are incinerated in the thermal oxidizer.

Sour Water Stripping

The sour water stripper receives feed from four sources:

• Vapor from the steam jet ejector associated with the system for handling the bottoms stream from the water wash towers.

• Condensate from the 7 psia flash of the bottoms stream from the water wash towers.

• Sour water from the knockout drums associated with syngas cooling and condensing.

• Sour water from the TGTU associated with sulfur recovery.

Water from the bottom of the sour water stripper joins the demineralized water and saturator purge water streams and flows to the top of the water wash towers. A pump-around loop with an air cooler provides condensing at the top of the sour water stripper. Low pressure steam serves as the heat source for the reboiler of the sour water stripper. Gas containing primarily H2S and ammonia, with lesser amounts of CO and H2, from the top of the sour water stripper is sent to the SRU.

Primary equipment items included in the sour water stripper are:

• Sour water feed/effluent exchanger (one common exchanger for two parallel trains).

• Sour water stripper (one common tower for two parallel trains).

• Sour water pump around pumps (one common pump with a full spare for two parallel trains).

• Sour water pump around cooler (one common air cooler for two parallel trains).

• Sour water reboiler (one common exchanger for two parallel trains).

Process Description

4-17

Syngas Saturation

Sweet syngas from the AGR, after exchanging heat with the sour syngas in the first condensing stage, flows to the syngas saturators. The purpose of the saturators is to add vaporized water to the syngas to bring the moisture content to 16.5 mole % for NOx reduction, which also results in additional mass flow through the turbine section (i.e. more power). The wet syngas is further preheated with high-pressure (HP) boiler feedwater to raise the temperature to 405°F before serving as fuel for the gas turbines.

Demineralized water, after heat exchange with the recovered water from the water wash towers, is fed to the circulating loops of the syngas saturators in amounts required to achieve the desired moisture content of the syngas. A small purge stream from the circulating loops joins the other water streams that flow to the top of the water wash towers. This avoids buildup of any components in the water that do not vaporize.

Water in the circulation loops is heated with HP boiler feedwater as required to maintain the level in the bottom of the syngas saturators, thus assuring that the water added to the loop is vaporized and added to the syngas.

Primary equipment included for syngas saturation is as follows:

• Syngas saturator (one tower for each of two parallel trains).

• Saturator heater (one exchanger for each of two parallel trains).

• Saturator circulation pumps (one pump plus a spare for each of two parallel trains).

• Sweet syngas heater (one exchanger for each of two parallel trains)

After passing through the syngas saturators, the syngas is ready for use in the power block.

Power Block Description

The power block of the IGCC consists of the gas turbines, HRSGs, steam turbine, condenser, and interconnecting pipe, pumps, etc. as required for the power production duty. The power block of an IGCC is very similar to that of a standard combined cycle.

Gas Turbines

The Project consists of two GE PG7251FB (7FB) gas turbines rated at 232 MW each on syngas. Like a conventional combined cycle or gas turbine plant, ambient conditions (in particular compressor inlet temperature) can greatly affect the performance of an IGCC facility. A gas turbine is a constant volume machine, therefore, lower compressor inlet temperatures result in greater air density, which results in more power output and decreased heat rate. Similarly, higher ambient temperatures result in lower air density, which results in lower output and higher heat rate.

Process Description

4-18

Because of the low heating value of the syngas, the fuel mass flow through the gas turbine is significantly higher than a standard natural gas fired turbine (approximately 4 times greater). This additional mass flow, coupled with the additional nitrogen mass flow for NOx control, increases the gas turbine output over that of a conventional gas turbine firing natural gas. This causes the gas turbine to reach its shaft limit at a higher ambient temperature than it typically would. Therefore, the gas turbine output must be limited to avoid exceeding the shaft limit of the turbine (232 MW for the 7FB). This is accomplished by extracting a portion of the air from the compressor section of the gas turbine for gas turbine compressor inlet temperatures (CIT) below ~70°F. This compressed air is utilized in the ASU, which reduces the additional auxiliary load of compression required by the ASU compression system. At CITs above ~70°F, the air density is low enough that the total mass flow through the turbine does not result in sufficient MW to exceed the shaft limit of the gas turbine. Thus air extraction from the compressor section of the gas turbine is not available for ASU use at CITs above ~70°F. Exporting of air from the GTG to the ASU is referred to as air-side integration.

Since air-side integration improves the efficiency of the IGCC facility, it is beneficial to export as much air as possible to the ASU. Therefore, 85% effective evaporative cooling is included on the inlet to each gas turbine to lower the compressor inlet temperature, resulting in improved mass flow available for the turbine and the ASU.

Alternatively, inlet air chilling could be used to further reduce the CIT. Inlet air chilling has a higher capital cost than evaporative cooling and may not be economically justified since this equipment will not be fully utilized for a significant portion of the year. It is recommended that further studies regarding inlet air cooling methods and tradeoffs be pursued.

Heat Recovery Steam Generators (HRSG)

Two HRSGs are utilized to capture the gas turbine exhaust heat. Triple pressure, natural-circulation HRSGs are utilized to preheat feedwater, generate steam, and superheat both the steam generated within the HRSG and the saturated steam from the gasification process. The HRSGs also utilize a reheat section to further increase steam cycle efficiency.

Alternatively, two-pressure HRSGs could be utilized in lieu of three-pressure HRSGs, thus eliminating the LP evaporator and superheater sections of the HRSG. The loss of the LP section would result in reduced steam flow to the STG (i.e. less output), however since very little LP steam is being generated in the HRSG (particularly for the 100% PRB cases), this increased capital (approximately $5 million), may not be justified. Alternatively, a large amount of LP steam is generated in the CO2 capture case (Chapter 13), which is of great benefit in that scenario. Further analysis into the use of a two-pressure HRSG should be performed in the future.

Steam Turbine

The total steam is expanded in a steam turbine to generate power. The steam turbine consists of three turbine sections (HP, IP, LP), utilizing a dual down flow LP turbine exhaust. The steam from the low pressure turbine exhaust is condensed by the heat rejection system.

Process Description

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The design pressure is 1905 psia with 1050°F main steam and hot reheat temperatures. The turbine will drive a hydrogen-cooled electric generator.

Steam Condenser

The water-cooled steam condenser will be a single, rectangular shell, single pressure, split waterbox, two pass steam condenser. The water-cooled condenser will include an air removal section and baffled steam inlet connections for the 100% steam turbine bypass. Air removal from the condenser’s upper portion will be via two full capacity vacuum pumps. To dissipate the energy in the condensing steam, a circulating water system will supply cooling water from the wet cooling tower to the water-cooled steam condenser. The steam condenser is designed with a 5°F terminal temperature difference (TTD) and a 17°F range at the 73°F ambient condition.

Steam System

The steam system transports main steam (HP), reheat steam, intermediate pressure (IP) steam and low pressure (LP) steam between the HRSGs and steam turbine. A steam turbine bypass system is included to accommodate the steam generated by the HRSG during start-up of the gas turbine before steam turbine admission, as well as during a full-load steam turbine trip.

Condensate System

The condensate system delivers condensate via two, 100% capacity vertical, condensate pumps. These pumps transport condensate from the steam condenser hotwell, through the gland steam condenser to the low pressure HRSG drum.

Feedwater System

The feedwater system provides feedwater to the HP and IP HRSG economizers, gasifier and syngas cooler via two 100% capacity, HP/IP boiler feed pumps per HRSG. This system also supplies desuperheating water requirements for the HRSGs and steam turbine bypass system.

Natural Gas System

The natural gas system provides pipeline quality natural gas to the gasifier and auxiliary boiler for startup and the gas turbine for backup fuel. It is assumed that the natural gas is available at the site boundary at sufficient pressure (~570 psig) to avoid the need for compressors.

Process Description

4-20

Balance of Plant

Coal Handling

Fuel delivery to the site is accomplished by rail. A rotary car dumper is provided for unloading of the coal. The coal handling system provides for the stackout, storage, and reclaim of the solid fuel for this project. Outdoor storage is assumed at this stage of the project. Layout drawings provided in Appendix B help to illustrate these systems.

100% PRB Option

The coal handling system unloads the coal with a rotary car dumper and conveys the coal with a stockout conveyor to the stockout pile. From the stockout pile, coal is moved with mobile equipment to long term storage or to the reclaim system. The reclaim system consists of a hopper, belt feeder, reclaim tunnel, and dust collection. The reclaim system supplies the coal to the inlet of the coal drying and milling equipment supplied with the gasifier.

Because PRB is shipped long distances, 60 days of long term PRB storage is provided to lessen the possibility of fuel interruption.

50% PRB / 50% Petcoke Option

The coal handing system for the fuel blend case is similar in concept to the 100% PRB option. The stockout conveyor has an intermediate transfer tower that allows for stockout into one of two piles. Weight feeders on the reclaim system allows for accurate blending of the fuel prior to the coal drying and milling equipment. Each fuel has its own stockout pile and reclaim system.

Similar to the 100% PRB option, 60 days of long term PRB storage is included. Petcoke is produced locally, thus reducing the potential for supply interruption, thus only 30 days of petcoke storage is provided.

Cooling System

Cooling for the condenser, ASU, and other auxiliary cooling loads is accomplished by a multi-cell, counter flow, mechanical draft, wet cooling tower. Circulating water is transported between the water-cooled steam condenser and cooling tower by two 60% capacity circulating water pumps. Additionally, two 60% capacity auxiliary cooling water pumps are used to supply auxiliary cooling water to the ASU, and other auxiliary cooling loads.

The cooling system is designed with a 2°F recirculation allowance and an 11°F approach (wet bulb minus cold water temperature).

Process Description

4-21

Auxiliary Boiler

A natural gas fired package boiler (approximately 200,000 lb/hr @ 150 psig) is included for preheat of the gasification area heat exchangers and providing steam to the critical systems during plant startup. Since this system is only required during startup sequence procedure, it is anticipated to be used less than 200 hours per year.

Buildings

The IGCC facility has the following major buildings:

• Administration and control room building.

• Water treatment building.

• Warehouse.

• Auxiliary boiler.

• Yard maintenance building.

• Cooling tower chemical building.

Water Treatment

Water mass balances are provided in Appendix C. Consumptive water uses include potable/sanitary water, plant service water, demineralized water, cooling tower make-up, and fire water. Raw water for the site is based on the wells with water quality shown in Table 4-3.

Process Description

4-22

Table 4-3 Assumed Raw Water Quality

Data Type Data Units

Specific Conductance 607 uS/cm2

Hardness 224 mg/L as CaCO3

Calcium 72 mg/L as CaMagnesium 11 mg/L as Mg

Sodium 44 mg/L as NaPotassium 0 mg/L as KChloride 26 mg/L as ClSulfate 15 mg/L as SO4

Silica 36 mg/L as SiO2

pH 7.5Fluoride 0.4 mg/L as Fl

Total Alkalinity 189 meq/L as CaCO3

Raw water supply and wastewater discharge requirements (on a local, state, and federal level) vary greatly from location to location. Once more information is known about that anticipated project site, additional studies should be performed to verify raw water availability and wastewater discharge viability for the project. These issues have the potential to greatly impact the cost and performance of the project.

Raw Water/Service Water

Raw water from the on-site wells is routed to an on-site raw water storage pond that stores 30 days of raw water. This storage pond may not be required if a highly reliable source of water is available, however most Owners of large coal generating stations are incorporating some amount of raw water storage to hedge against potential shortfalls in water availability. From the raw water pond, the water is routed to the raw water treatment where the majority of suspended solids, iron, and manganese will be removed by filtration and sodium hypochlorite injection prior to entering the service water storage tank (which also serves as the firewater storage tank). Service water uses include coal pile dust suppression, gasifier slag quenching, pump seals, equipment wash water, fire water, and other miscellaneous sources.

The raw water also serves as the major source cooling tower make-up (along with demineralizer reject, and Gasifier and HRSG blowdown). The cooling tower requires water treatment chemistry and blowdown to prevent scale and biological formation and corrosion on piping and heat transfer surfaces.

Process Description

4-23

Demineralized Water

Raw water is routed to the demineralizer system that consists of reverse osmosis and electrodeionization (EDI) equipment designed to produce high purity water for various uses in the gasifier and HRSG. Reject from this system is routed to the cooling tower as an additional make-up source. The demineralized water is stored in a demineralized water storage tank.

Wastewater

Blowdown from the cooling tower, coal pile wastewater, reject from the raw water treatment, and clean effluent from the plant drains are routed to a common wastewater collection pond prior to discharge to a nearby river.

Sanitary Drains

Plant sanitary drains are routed to an on-site septic system.

Flare

A flare system is included to burn off syngas produced the by gasifier during startup or in the event of a unit trip or pressure excursion. The flare is located at a safe distance (600 ft. radius) from accessible areas. A perimeter fence is placed around the flare to prevent people and animals from approaching the flare.

A 200 ft. tall guyed flare with a 60 in. flare tip is provided in the estimate. A knockout drum and pumps are included upstream of the flare.

Fire Protection

Fire protection water is supplied from the raw water storage tank with an electric motor driven fire pump, a diesel engine driven fire pump and an electric motor-driven jockey pump. Fire protection and detection systems will be in accordance with NFPA requirements. A fire water loop with sectionalizing valves is included around the plant. Automatic and semi-automatic fire protection systems employing detection and extinguishing equipment and hose stations are included for the generator step-up transformers, steam turbine lube oil system, cooling tower, buildings, Gasification Systems, and coal handling and storage. Fire hydrants, monitors, and fire extinguishers will be strategically positioned throughout the plant for coverage of fuel conditioning equipment, cooling tower fan deck, steam turbine, gas turbine, and gasification-related areas. The gas turbine fire protection system is supplied with the equipment. The fire detection system will provide detection throughout the plant and annunciation in the main plant control room.

Process Description

4-24

Plant Drains

The plant drains system collects liquid waste (non-sanitary) from plant areas and equipment and transfers the waste to the wastewater treatment system. This system includes sumps and two 100% capacity pumps for each sump. Equipment drains will be located adjacent to all equipment requiring intermittent or continuous drainage during operation or shutdown. Plant drains with potential oil contamination will be drained to the oil-water separator.

Electrical Systems

The electrical systems for the IGCC facility consist of the auxiliary power supply, generator feed, switchyard, essential AC and DC power supply, and freeze protection systems.

Auxiliary Power Supply

The auxiliary power system provides electric power for all systems in the plant.

The power distribution for the power block and gasifier plant is supplied from the main 13.8kV distribution switchgear. The main 13.8kV distribution switchgear is supplied from two plant auxiliary power transformers that are connected to the low side of the gas turbine GSU transformers that are connected to the 345kV substation.

The main 13.8kV distribution switchgear supplies the following 4.16kV switchgear lineups located in the power block and throughout the plant. Each of the 4.16kV buses is located in a power control module (PCM) placed in the vicinity of the loads.

• Power block switchgear A.

• Power block switchgear B.

• Coal handling switchgear.

• Gasification switchgear.

• Balance of plant bus.

• Sulfur & slag bus.

Each of the 4.16kV switchgear lineups supplies multiple station service transformers that supply 480V load centers arranged in a main-tie-main configuration. The load centers supply the 480V motor and non-motor loads. The 480V motor loads are supplied from motor control centers (MCC) that are connected to the 480V load centers. The 480V load centers and 480V MCCs are located in the PCM buildings along with the 4.16kV switchgear lineup. The station service transformers are located outside the PCM buildings. The small power loads are supplied from 120/240-volt utility panels located in the PCM.

Process Description

4-25

The power distribution for the ASU is supplied from the ASU 13.8kV distribution switchgear. The ASU 13.8kV distribution switchgear is supplied from two auxiliary power transformers that are connected to a single overhead line from the 345kV substation. Each auxiliary power transformer connects to a 13.8kV switchgear bus that supplies the ASU compressor motors and a 13.8kV to 480V station service transformer. The station service transformers connect to 480V switchgear buses that are interconnected with tie breakers.

A plant emergency generator is connected to the 4160 volt bus. The natural gas engine-generator is sized to start and operate the emergency loads of the facility.

Generator and Excitation

The generator system provides power from the gas turbine and steam turbine generators to the generator step-up transformer.

The generator system consists of the following:

• Auxiliary transformer.

• Isolated phase bus.

• Generator step-up transformer.

• Protection devices.

• Wiring, instrumentation, and controls.

The excitation system provides controlled DC power to the generator field. The exciter system consists of the following:

• Power potential transformer (PPT) that is connected to the generator terminals with an isolated phase bus tap. The power potential transformer steps down the generator voltage for use by the exciter.

• Static exciter system supplied by the turbine manufacturer. The exciter systems convert the AC power for the PPT to a DC power source applied to the generator rotor to establish the generator field. The system controls the generator field current to regulate the generator terminal voltage, power factor, or VAR flow.

Switchyard

The switchyard configuration is a three-bay breaker-and-a-half arrangement consisting of 9 breakers. The switchyard has dedicated positions for each generator step-up transformer, two incoming transmission lines, and on-site transmission to the ASU.

Process Description

4-26

The high-voltage equipment is rated for 345kV nominal operating voltage.

Essential AC and DC Power Supply

The essential AC and DC power system provides highly reliable power to such essential low power loads as DCS, logic systems, annunciators, events recorder, data loggers and computers, communications equipment, intercommunications systems and emergency lighting. Essential power for the gas turbine and its auxiliaries is provided by gas turbine manufacturer as part of the gas turbine package.

Separate plant uninterruptible power supply (UPS) systems are provided for the power block and Gasification System. The equipment for the essential power supply consists of:

• DC chargers and batteries.

• Operator terminals.

• DC switchboard.

• Single phase UPS.

• Electrolytic capacitors.

• Wire, instrumentation, and controls.

Freeze Protection

The freeze protection system maintains temperature above the freezing point in piping and equipment. The freeze protection system consists of

• Heat tracing cable.

• Voltage monitors.

• Thermostats.

• Contactors.

• Control cabinets.

5-1

5 TERMINAL POINTS

General

The following terminal points identify the termination points or interfaces for those services or facilities, which extend beyond the scope of the work included in this report.

Site Access

Site access roads shown on the layout drawings in Appendix B are included in the capital cost estimate. Any roads or road upgrades to the site are not included in the estimate.

Rail Siding

The capital cost estimate includes a 5 mile rail siding to the site plus the track shown on the layout drawings in Appendix B. It is assumed that all large equipment is delivered to the site via rail. Heavy haul costs are included to offload the equipment from the rail to the foundations. Modifications to any existing rail or road infrastructure are not included.

Sanitary Waste

Sanitary waste is disposed of in an on-site septic system.

Natural Gas

The capital cost estimate includes one mile of 12 in. natural gas pipeline to the site for startup and backup fuel. Additionally, Burns & McDonnell’s estimate includes natural gas metering and pressure regulation equipment. It is assumed that natural gas will be supplied by others at sufficient pressure (~570 psig), temperature, quality, and flow to meet the requirements of the IGCC facility without the need for natural gas compression or dew point heating.

Raw Water Supply

Raw water is assumed to be available through on-site wells. The capital cost estimate includes the well water system. If well water is unavailable or other sources of water are required to supplement the well water supply, the costs of these items are by others.

Terminal Points

5-2

Wastewater Discharge

Wastewater is assumed to be discharged to a river through a wastewater pipeline 5 miles in length after being treated in the on-site wastewater treatment pond. The capital cost estimate includes the cost of the wastewater pipeline and on-site wastewater treatment pond. Any other means of wastewater discharge is outside the scope of this estimate.

Electrical Interface

The project capital cost estimate includes the electrical interconnection costs up to and including the plant switchyard. Transmission lines to the site or transmission upgrades are by others.

6-1

6 IGCC PERFORMANCE ESTIMATES

Performance Estimate Assumptions

The following assumptions are used as the basis for the performance estimates:

• Output and heat rate estimates are at new and clean conditions.

• An 85% effective evaporative cooler is included and is on for the 93°F case.

• Performance is based on an elevation of 100 ft.

• Performance is based on the fuel analysis provided in Table 3-1.

• Gas turbine performance and Shell gasification performance estimated by EPRI without vendor involvement.

• Steam turbine consists of three turbine sections (HP, IP, LP) with a dual down flow exhaust. The design throttle conditions are 1905 psia with 1050°F main steam and hot reheat temperatures.

• Air-side integration is used to supplement air flow to the ASU when the gas turbine has reached its shaft limit (for CIT below ~70°F).

• Performance is based on a wet cooling tower.

Performance Estimate Results

The results of the performance analysis are provided in Table 6-1. Heat balance diagrams containing additional information are provided in Appendix F.

IGCC Performance Estimates

6-2

Table 6-1 IGCC Performance Summary

100% PRB 50% PRB / 50% Petcoke

Ambient Dry Bulb Temperature, °F 43 73 93 43 73 93Ambient Wet Bulb Temperature, °F 40 69 77 40 69 77Elevation, ft. 100 100 100 100 100 100Evaporative Cooling, On/Off Off Off On Off Off On

Coal Heat Input, MMBtu/hr (LHV) 5,026 4,705 4,559 5,113 4,800 4,655Coal Heat Input, MMBtu/hr (HHV) 5,447 5,099 4,940 5,343 5,016 4,864

Gas Turbine Gross Output, MW (each) 232.0 224.9 215.6 232.0 226.3 217.0Gas Turbine Gross Output, MW (total) 464.0 449.7 431.2 464.0 452.7 433.9Steam Turbine Gross Output, MW 272.6 260.1 250.4 270.1 258.4 248.7Gross Plant Output, MW 736.6 709.9 681.5 734.2 711.1 682.6

Auxiliary LoadPower Block, MW 22.5 22.0 21.8 22.0 21.9 21.6Material Handling, MW 6.3 5.9 5.8 4.5 4.3 4.1Air Separation Unit, MW 101.3 122.1 119.1 101.1 122.9 120.0Gasifier, MW 2.3 2.1 2.0 2.2 2.1 2.0CO2 Compression 0.0 0.0 0.0 0.0 0.0 0.0Syngas Treatment, MW 5.0 4.7 4.5 7.4 6.9 6.7

Total Plant Auxiliary Load, MW 137.4 156.8 153.2 137.2 158.0 154.5

Net Plant Output, MW 599.2 553.0 528.4 597.0 553.0 528.2Net Plant Heat Rate, Btu/kWh (LHV) 8,390 8,510 8,630 8,560 8,680 8,810Net Plant Heat Rate, Btu/kWh (HHV) 9,090 9,220 9,350 8,950 9,070 9,210

Plant Cooling Requirements, MMBtu/hr (Total) 2,155 2,141 2,159 2,185 2,179 2,206Steam Cycle Cooling Requirement, MMBtu/hr 1,550 1,480 1,450 1,540 1,480 1,460BOP Auxiliary Cooling Requirement, MMBtu/hr 605 661 709 645 699 746

Total Makeup Water RequirementGPM 4,390 4,980 5,580 4,619 5,231 5,800Acre-ft/year (@ 85% CF) 6,830 6,830 6,830 7,170 7,170 7,170

The power block auxiliary load includes gas turbine auxiliary loads, steam turbine auxiliary loads, power block pumping loads, transformer losses, iso-phase bus losses, and miscellaneous BOP auxiliary loads (lighting, HVAC, air compression, etc.). Additionally, the power block auxiliary loads include the cooling water pumps and cooling tower that provide the cooling loads for the entire facility.

Material handling auxiliary loads include the loads associated with coal conveying and coal milling and drying equipment.

Air separation unit auxiliary loads include the main air compressor, booster air compressor, cold box, nitrogen compression, cryogenic pumping, and miscellaneous ASU auxiliary loads.

Gasifier auxiliary loads include recycle quench gas compressor loads and slag handling loads.

Syngas treatment auxiliary loads include AGR, SRU, TGTU, and miscellaneous process loads.

7-1

7 IGCC CAPITAL COST ESTIMATES

Capital Cost Estimate Assumptions

• All estimates are “screening level” in nature and do not reflect guaranteed costs (+/- approximately 30%).

• Project is based on a greenfield site.

• Project cost is based on the terminal points as defined in Chapter 5.0.

• It is assumed that 10 ft. of cut is required for half the site area and 10 ft. of fill is required for the other half of the site area. Other areas may require more cut and fill, however an average cut/fill of 10 ft. is assumed. Additionally, it is assumed there are no existing structures, underground utilities, or hazardous materials on site.

• Project costs are based on a preliminary site layout drawings included in Appendix B.

• Project costs are based on preliminary electrical one-line diagrams included in Appendix D.

• Preliminary foundation design is based on the assumption that shallow, mat-type foundations will be sufficient for all minor foundations. Major structures such as the gas turbines, HRSGs, steam turbine, step up transformers, gasifiers, and the major equipment for the ASU, AGR, SRU, TGTU, and coal reclaim are assumed to require piling.

• The steam turbine, gas turbines, and HRSGs are located outdoors.

• Sufficient area to receive, assemble, and temporarily store construction materials is available.

• The design fuel is based on the information provided in Table 3-1.

• An on-site landfill is included for disposal of flyash and slag. The capital cost estimate includes the initial 5-year cell. The ongoing cost of closing current cells and the addition of future cells is covered in the landfill cost ($/ton) used in the O&M estimate.

• Cooling is achieved through the use of conventional wet cooling towers.

IGCC Capital Cost Estimates

7-2

• Construction costs are based on an engineer, procure and construct (EPC) contracting philosophy. The Owner would have an EPC contract with a single “Global EPC” contractor. It is assumed the Global EPC contractor will contract the ASU, gasification, and syngas treatment as separate EPC contracts (under the Global EPC). The Global EPC contractor is responsible for integration of the construction and design aspects of all EPC contractors and assumes overall risk for schedule, performance, and capital cost.

• Labor rates are based on prevailing wage rates and productivity factors for the Texas Gulf Coast. Labor rates include a $9/hour per diem to account for non-local labor (assumed 90% outside 50 miles).

• All capital cost estimates are in mid-2006 dollars and do not include escalation through the COD, sales tax, interest during construction, financing fees or transmission lines/upgrades.

Indirect Construction Costs (Included in EPC Cost)

The following project indirect costs are included in the EPC capital cost estimate:

• Construction water and power.

• Performance testing and CEMS/stack emissions testing (where applicable).

• Initial fills and consumables, preoperational testing, startup, startup management, and calibration.

• Construction/startup technical service.

• Heavy haul

• Site surveys and studies.

• Engineering and construction management.

• Construction testing.

• Operator training.

• Startup spare parts.

• Performance and payment bond.

• EPC contingency.

• EPC Fee.

IGCC Capital Cost Estimates

7-3

Owner Indirect Costs

In addition to the estimated EPC costs, an estimate of anticipated Owner’s costs was also provided. The Owner’s costs included in the estimate are as follows:

• Project development costs.

• Owner project management and project engineering (including startup).

• Owner’s operations personnel prior to COD.

• Owner’s construction management.

• Owner’s engineer.

• Permitting and licensing fees.

• Land (1,500 acres for accommodation of future expansion to 3 x 550 MW units).

• Political concessions / area development allowance.

• Startup consumables, including fuel.

• Credit for test power sales.

• Initial fuel inventory (60 days PRB, 30 days petcoke).

• Builder’s risk insurance.

• Site security.

• Owner’s legal costs.

• Operating spare parts.

• Permanent plant equipment and furnishings.

• Owner’s contingency (5% of entire project cost).

IGCC Capital Cost Estimates

7-4

Costs not included

The costs not included in the capital costs estimates include, but are not limited to the following:

• Escalation through COD is not included. The EPC and Owner’s costs provided are in overnight 2006 US dollars. This cost does not represent the cost of an EPC contract signed today. It represents the cost of the project assuming zero time value of money. Additional escalation needs to be applied by the Owner as a part of the Owner’s Integrated Resource Plan to determine when the project would fit into the generation needs of the Owner.

• Sales Tax is not included. Because sales tax requirements differ greatly depending on location (even within a state), sales tax has been excluded from this estimate. In some instances, emissions controls equipment have been known to be tax exempt, so it is possible that a large part of the IGCC facility may be tax exempt, if not all. Additionally, some municipalities or utilities are tax exempt. If this project proceeds and a site is chosen, it is recommended that a detailed investigation into sales tax be pursued at that time.

• Interest during construction is not included in the capital cost estimates provided herein. Since the estimates provided are in overnight 2006 US dollars, applying interest during construction is not feasible. However, interest during construction costs are a very significant project cost that must included separately once a desired COD is determined, which will increase the overall capital cost of the project. Interest during construction is included in the 20-year levelized busbar cost ($/MWh) discussed in Chapter 12.

• Financing fees are not included in the capital cost estimates provided herein. However, financing fees are included in the 20-year levelized busbar cost ($/MWh) discussed in Chapter 12.

• Transmission lines to or from the site are not included. Additionally, transmission upgrades, if required, are not included.

Capital Cost Results

The estimated capital costs for the project are provided in Table 7-1. Additional cost detail can be found in Appendix E.

IGCC Capital Cost Estimates

7-5

Table 7-1 IGCC Capital Cost Estimate Summary (2006 US Dollars)

550 MW (Net) IGCC 100% PRB

550 MW (Net) IGCC 50% PRB / 50% Petcoke

ProcurementGas Turbines $ 86,000,000 $ 86,000,000 Steam Turbine $ 22,950,000 $ 22,950,000 HRSGs $ 28,080,000 $ 28,080,000 Other Mechanical $ 46,720,000 $ 47,220,000 Electrical $ 47,820,000 $ 50,320,000 Water & Chemical Treatment $ 2,380,000 $ 2,380,000 Structural $ 1,600,000 $ 1,600,000

ConstructionFurnish and Erect

Material Handling $ 36,660,000 $ 44,300,000 Air Separation Unit and N2 Storage $ 102,400,000 $ 102,400,000 Gasification $ 354,310,000 $ 306,360,000 Syngas Treatment $ 149,990,000 $ 158,150,000

GTG/STG/HRSG Erection $ 20,730,000 $ 20,730,000 Civil / Structural Construction $ 94,740,000 $ 96,290,000 Mechanical Construction $ 42,070,000 $ 42,070,000 Electrical Construction $ 23,030,000 $ 23,480,000 EPC Contractor Indirect CostsConstruction Indirects

Construction Management $ 24,710,000 $ 24,710,000 Pre-operational startup and testing $ 8,230,000 $ 8,230,000 Other $ 4,790,000 $ 4,790,000

Project IndirectsProject Management and Engineering $ 40,000,000 $ 40,000,000 EPC Contingency $ 57,100,000 $ 55,740,000 EPC Fee $ 119,910,000 $ 117,050,000 Other $ 4,760,000 $ 4,690,000

Total EPC Contractor Cost (2006 US $) $ 1,318,980,000 $ 1,287,540,000 Owner Indirect Costs

Owner's Engineer $ 23,000,000 $ 23,000,000 Permitting and Licensing Fees $ 2,910,000 $ 2,910,000 Land $ 7,500,000 $ 7,500,000 Initial Fuel Inventory $ 10,930,000 $ 6,190,000 Operating Spare Parts $ 10,060,000 $ 10,120,000 Permanent Plant Equipment and Furnishings $ 4,600,000 $ 4,600,000 Builder's Risk Insurance $ 5,940,000 $ 5,790,000 Owner Contingency $ 70,200,000 $ 67,950,000 Other $ 20,100,000 $ 11,440,000

Total Owner's Cost (2006 US $) $ 155,240,000 $ 139,500,000 Total Project Cost (2006 US $) $ 1,474,220,000 $ 1,427,040,000

Total EPC Contractor Cost (2006 US $), $/kW (73°F) $ 2,390 $ 2,330 Total Project Cost (2006 US $), $/kW (73°F) $ 2,670 $ 2,580

8-1

8 IGCC OPERATIONS AND MAINTENANCE

O&M Assumptions

The following describes the methodology and major assumptions used in the development of the O&M estimate.

• Fixed costs include such items as plant staffing, office and administration, training, safety, contract staff, annual inspections, standby power energy costs and other miscellaneous fixed costs.

• Variable costs include such items as gas turbine, steam turbine, HRSG, gasifier, and syngas treatment scheduled maintenance, water treatment, wastewater disposal, consumables, landfill costs, balance of plant equipment maintenance and replacements, unplanned maintenance activities, and estimated emissions allowance costs.

• Emissions allowance costs are included in the variable O&M at $3,000/ton of NOx, $1,000/ton of SO2, and $20,000/lb of mercury, based on input from CPS Energy.

• Costs are shown in 2006 US dollars.

• 85% capacity factor (7446 hrs/year at 100% load).

• 2 cold starts per year.

• Additional staff is required above that of a PC unit due to the additional process-related equipment associated with an IGCC project. 126 full time operations and maintenance personnel have been assumed.

• The gas turbine major maintenance costs are based on Long Term Service Agreement (LTSA) contracts with GE executed for similar equipment.

• Other fixed and variable O&M estimates are based on information obtained by Burns & McDonnell from plant operators of similar installations.

• Raw water is available at zero cost (other than treatment costs) and wastewater is discharged to a river at zero costs (other than treatment costs)

IGCC Operations and Maintenance

8-2

• Flyash (the amount not recycled to the gasifier) and slag are landfilled on-site at a cost of $11.29/ton. This cost includes the ongoing cost of closing old landfill cells and expanding the landfill in the future.

• Sulfur produced in the SRU is assumed to be sold at zero cost, thus avoiding any disposal cost.

O&M Exclusions

The costs not included in the O&M estimates include, but are not limited to the following:

• Property taxes.

• Insurance (included in economic analysis).

• Fuel and fuel supply costs (included in economic analysis).

• Initial spare parts (included in capital cost estimate).

O&M Results

The estimated O&M costs for the project are provided in Table 8-1. Additional O&M cost detail can be found in Appendix G.

IGCC Operations and Maintenance

8-3

Table 8-1 IGCC O&M Summary (2006 US Dollars)

100% PRB 50% PRB / 50% Petcoke

Fixed O&MLabor, $/yr $ 11,835,700 $ 11,835,700 Office and Admin, $/yr $ 118,400 $ 118,400 Major Inspections, $/yr $ 400,000 $ 400,000 Standby Power Energy Costs, $/yr $ 98,600 $ 98,600 Other Fixed O&M, $/yr $ 1,479,500 $ 1,479,500 Fixed O&M, $/yr $ 13,932,200 $ 13,932,200

Variable O&M (85% CF)Emissions Allowance Costs, $/yr

NOx Emissions Allowance Cost $ 3,588,300 $ 3,472,900 SO2 Emissions Allowance Cost $ 360,700 $ 429,400 Hg Emissions Allowance Cost $ 590,000 $ 370,600

Major Maintenance Costs, $/yrSteam Turbine / Generator Overhaul $ 260,400 $ 260,400 HRSG Major Replacements $ 200,000 $ 200,000 Gasifier Replacements $ 885,800 $ 765,900 Candle Filter Major Replacements $ 300,000 $ 300,000 Gas Turbine Major Replacements $ 8,148,700 $ 8,148,700 Syngas Treatment Major Replacements $ 375,000 $ 395,000 Air Separation Unit Major Replacements $ 275,000 $ 275,000 Mercury Carbon Bed Replacements $ 530,300 $ 530,300 HCN/COS Hydrolysis Catalyst Replacements $ 640,000 $ 640,000 Shift Catalyst Replacements $ - $ - Demin System Replacements $ 3,600 $ 3,600

Water Treatment, $/yr $ 1,479,100 $ 1,523,700 Fly Ash & Slag Disposal $ 1,560,200 $ 642,100 Other Variable O&M, $/yr $ 5,297,400 $ 5,355,600 Variable O&M, $/yr (85% CF) $ 24,494,500 $ 23,313,200

Fixed O&M, $/kW-yr $ 25.19 $ 25.19 Variable O&M, $/MWh $ 5.95 $ 5.66 Total O&M Cost, $/Year (85% CF) $ 38,426,700 $ 37,245,400

9-1

9 IGCC AVAILABILITY

General

Some IGCC facilities have been evaluated with a spare gasifier to increase availability factors and allow increased operational flexibility. It is anticipated that adding a spare gasifier train will improve the availability factor of the IGCC facility by approximately 5 percentage points. The spare gasifier is typically operated in hot-standby mode which requires natural gas (or syngas if available) to maintain the metal temperatures within the gasification system. This significantly reduces gasifier startup time in the event that one of the gasifiers is forced off-line. The benefits of the spare gasifier, however, come at a large operating and capital expense (approximately 20% capital cost increase). For these reasons, a spare gasifier was not considered for this project.

Assumptions and Clarifications

Plant availability factors are typically determined from historical data of existing plants, which is often a good predictor for the future. Since IGCC technology is relatively new, published availability information is difficult to obtain.

The availability factor is a measure of the amount of the year that the plant or unit is available to operate and produce electricity. It includes the effect of both planned and forced outages.

Past data from existing IGCCs has indicated availability factors of 83-85% for designs that do not utilize a spare gasifier. These existing facilities had first year availabilities of approximately 75%, followed by 80% in the second year, followed by 83-85% in the third year and thereafter. It is expected that improvements in gasifier designs will improve availability factors from previous generation designs.

Availability Factor

For this assessment, an 85% availability factor is assumed for both IGCC options.

The availability factor of an IGCC facility will depend heavily on the structure of the O&M programs and how well they are executed. The most effective IGCC facilities are those that commit to and follow well organized plans.

As previously noted, the membrane wall design of the Shell gasifier will experience less frequent maintenance than the GE and ConocoPhillips refractory lined gasifiers. Refractory lined

IGCC Availability

9-2

gasifiers will require periodic refractory replacement (perhaps every two years). This results in a lower planned outage rate for the Shell gasifier, and therefore a higher availability factor.

10-1

10 IGCC EMISSIONS ESTIMATES

General

The emissions evaluated for this IGCC study are NOx, SO2, PM10, CO, CO2, and mercury. The actual emissions limits and emissions control technology required for a facility are dictated by the air permitting process. The emission rates herein are used to provide the basis of the capital cost, performance, and O&M costs. Actual permitted rates may vary from the emission rates shown below.

CO2 capture was not considered for the two base case options; however Chapter 13 provides additional information regarding the impact to the capital cost, performance, and CO2 emissions from the addition of CO2 capture equipment at a later date.

For purposes of this study, it is assumed the project is located in an attainment area for National Ambient Air Quality Standards (NAAQS) Pollutants as set by the Environmental Protection Agency (EPA).

For SO2 control, the AGR process selected for the basis of this project is SELEXOL. The AGR is sized to achieve a total sulfur content of 30 ppmv in the syngas to the gas turbines (for the non-CO2 capture cases). High levels of sulfur removal are accomplished by first passing the syngas through a COS hydrolysis reactor prior to the SELEXOL scrubber to convert small amounts of COS in the syngas to H2S.

NOx control is achieved through the use of nitrogen injection and syngas saturation into the gas turbine. The nitrogen acts as a diluent (similar to water injection) to control the flame temperature which is a major source of NOx. Additionally fuel-bound nitrogen is effectively eliminated by the removal of HCN and NH3 in the syngas cleanup system.

An SCR was not included at this phase of the project. Some of the ammonia utilized in an SCR will react with SO3 in the exhaust gas to form ammonium bisulfate (ABS) that may plug the heat transfer surfaces in the HRSG. If an SCR were to be used, the sulfur level in the syngas would have to be reduced to approximately 15 ppmv to minimize the potential for ABS formation which would increase the cost of the AGR and SRU. Therefore, the capital cost of the project would increase. Also, the net plant output will be reduced due to the reduction in GTG output (caused by increased exhaust pressure loss) and the additional steam and auxiliary power requirements of the AGR and SRU. The benefit is that NOx emissions will be reduced from 15 ppmvd @ 15% O2 (from the output of the gas turbines) to approximately 3.5 ppmvd @ 15% O2, however particulate emissions will increase. At $3,000/ ton for NOx emissions allowances costs (see Table 8-1), the yearly savings provided by the addition of an SCR may make it an attractive

IGCC Emissions Estimates

10-2

option provided that the technical issues can be overcome. At this stage, SCR was not included due to the technical issues stated above; however additional studies regarding the use of an SCR should be performed in the future.

Particulate control for this project is achieved using candle filters and a water wash scrubber to remove the particulate from the syngas. Beyond the syngas particulate control, there is no additional post-combustion particulate control required.

CO is controlled by the gas turbine combustion system. Additional CO removal is not included.

Mercury control is achieved by using activated carbon adsorbent beds to remove mercury from the syngas prior to combustion and is capable of removing 90+% of the entrained mercury.

The resulting emission rates are shown in Table 10-1.

Table 10-1 IGCC Target Emission Rates

100% PRB 50% PRB / 50% Petcoke

NOx

lb/MMBtu (HHV) 0.063 0.062ppmvd @ 15% O2 15 15lb/MWh (net) 0.581 0.562

SO2

lb/MMBtu (HHV) 0.019 0.023lb/MWh (net) 0.173 0.210

PM10

lb/MMBtu (HHV)1 0.007 0.007

lb/MWh (net)1 0.065 0.065CO

lb/MMBtu (HHV) 0.037 0.036ppmvd 25 25lb/MWh (net) 0.337 0.337

CO2

lb/MMBtu (HHV) 215 213lb/MWh (net) 1,985 1,934

Hg% Removal 90% 90%lb/TBtu (HHV) 0.778 0.496lb/MWh (net) 7.17E-06 4.50E-06

1) Particulate matter emissions rate is for front half only excluding back half condensables, for the concentration of particulate matter less than 10 microns in diameter

11-1

11 SUPERCRITICAL PC ESTIMATES

General

In order to compare IGCC to SCPC technology, Burns & McDonnell estimated the capital costs, performance, O&M, and availability factor of a 550 MW (net) SCPC unit with steam conditions of 3500 psig/1050°F/1050°F. For this assessment, only a 100% PRB fired SCPC was evaluated.

Although much more effort was put into developing IGCC cost estimates than the SCPC estimate for this study, Burns & McDonnell believes the accuracy of the SCPC costs to be equal in accuracy, if not greater than those provided for the IGCC estimates. This is largely due to Burns & McDonnell involvement with other SCPC projects that have been constructed in recent years and the fact that IGCC definitive cost data with vendor input is not available or is considered confidential at this time.

SCPC Capital Cost Assumptions

The majority of the assumptions and exclusions discussed in Chapter 7.0 are applicable to the SCPC capital cost estimates. Additional assumptions are as follows.

• Wet flue gas desulfurization (FGD) is assumed for SO2 control, and SCR for NOx control, and a baghouse for particulate control.

• The physical size of the wet FGD is increased beyond that required at this stage to accommodate additional future SO2 removal as may be required by future environmental regulations. Based on the Fluor EFG+ CO2 capture system (discussed in Chapter 13), approximately 98% SO2 removal is required in the FGD, which is higher than currently required. The design capability for future SO2 removal is integrated into the design of the FGD system absorber by adding additional height to the absorber tower and by allocating space for installation of additional recirculation pumps and spray headers that could be added in the future should it be necessary to minimize SO2 concentrations entering the CO2 capture system. It is estimated that the provision of this additional space within the absorber tower would increase the initial installed cost of the FGD system by about $5,000,000, which is included in the capital cost estimate.

• Preliminary foundation design is based on the assumption that shallow, mat-type foundations will be sufficient for all minor foundations. Major structures such as the boiler, steam turbine, APC equipment, coal reclaim, and step up transformers are assumed to require piling.

Supercritical PC Estimates

11-2

• The boiler, steam turbine, and air pollution control equipment are located outdoors.

• The design fuel is based on 100% PRB fuel as provided in Table 3-1.

• An on-site landfill is included for disposal of flyash, bottom ash, and scrubber sludge. The capital cost estimate includes the initial 5-year cell. The ongoing cost of closing current cells and the addition of future cells is covered in the landfill cost ($/ton) used in the O&M estimate.

SCPC Capital Cost Results

The estimated capital costs for the project are provided in Table 11-1. Additional capital cost detail can be found in Appendix E.

Supercritical PC Estimates

11-3

Table 11-1 550 MW (Net) SCPC Capital Cost Estimate Summary (2006 US Dollars)

550 MW (Net) SCPC 100% PRB

ProcurementBoiler/AQC $ 182,630,000 Steam Turbine $ 40,040,000 Other Mechanical $ 48,370,000 Electrical $ 35,270,000 Water & Chemical Treatment $ 4,560,000 Structural $ 1,970,000

ConstructionFurnish and Erect

Material Handling $ 46,530,000 Chimney $ 15,000,000

Boiler/AQC/STG Erection $ 171,210,000 Civil / Structural Construction $ 156,650,000 Mechanical Construction $ 85,310,000 Electrical Construction $ 61,350,000 EPC Contractor Indirect CostsConstruction Indirects

Construction Management $ 24,710,000 Pre-operational startup and testing $ 8,790,000 Other $ 4,500,000

Project IndirectsProject Management and Engineering $ 38,120,000 EPC Contingency $ 46,430,000 EPC Fee $ 97,510,000 Other $ 3,630,000

Total EPC Contractor Cost (2006 US $) $ 1,072,580,000 Owner Indirect Costs

Owner's Engineer $ 20,000,000 Permitting and Licensing Fees $ 2,910,000 Land $ 7,500,000 Initial Fuel Inventory $ 10,690,000 Operating Spare Parts $ 5,750,000 Permanent Plant Equipment and Furnishings $ 5,780,000 Builder's Risk Insurance $ 4,830,000 Owner Contingency $ 57,250,000 Other $ 15,050,000

Total Owner's Cost (2006 US $) $ 129,760,000 Total Project Cost (2006 US $) $ 1,202,340,000

Total EPC Contractor Cost (2006 US $), $/kW (73°F) $ 1,950 Total Project Cost (2006 US $), $/kW (73°F) $ 2,190

Supercritical PC Estimates

11-4

SCPC Performance Assumptions

The majority of the assumptions discussed in Chapter 6 are applicable to the SCPC performance estimates. Additional assumptions are as follows.

• Performance is based on the 100% PRB fuel as provided in Table 3-1.

• Steam turbine consists of four turbine sections (HP, IP, and 2 LP) with a two dual down flow exhausts. The design throttle conditions are 3500 psia with 1050°F main steam and hot reheat temperatures.

• Performance is based on a wet cooling tower, wet scrubber, and baghouse.

SCPC Performance Estimate Results

The results of the performance analysis are provided in Table 11-2.

Table 11-2 550 MW (Net) SCPC Performance Summary

100% PRB

Ambient Dry Bulb Temperature, °F 43 73 93Ambient Wet Bulb Temperature, °F 40 69 77Elevation, ft. 100 100 100

Coal Heat Input, MMBtu/hr (LHV) 4,648 4,644 4,644Coal Heat Input, MMBtu/hr (HHV) 5,037 5,033 5,033

Gross Plant Output, MW 623.3 614.5 613.2Total Plant Auxiliary Load, MW 65.4 64.5 64.4

Net Plant Output, MW 557.8 550.0 548.8Net Plant Heat Rate, Btu/kWh (LHV) 8,333 8,444 8,462Net Plant Heat Rate, Btu/kWh (HHV) 9,030 9,150 9,170

Plant Cooling Requirements, MMBtu/hr (Total) 2,490 2,490 2,490Steam Cycle Cooling Requirement, MMBtu/hr 2,300 2,300 2,300BOP Auxiliary Cooling Requirement, MMBtu/hr 190 190 190

Total Makeup Water RequirementGPM 5,120 5,800 6,430Acre-ft/year (@ 85% CF) 7,950 7,950 7,950

Supercritical PC Estimates

11-5

SCPC O&M Cost Assumptions

The majority of the assumptions discussed in Chapter 8 are applicable to the SCPC O&M estimates. Additional assumptions are as follows:

• 103 full time operations and maintenance personnel.

• Flyash, bottom ash, and scrubber sludge are landfilled on-site at a cost of $11.29/ton. This cost includes the ongoing cost of closing old landfill cells and expanding the landfill in the future.

• Delivered limestone for wet scrubbing is based on $18/ton.

• Delivered ammonia for SCR use is based on $658/ton for 19% aqueous solution.

SCPC O&M Exclusions

The costs not included in the O&M estimates include, but are not limited to the following:

• Property taxes.

• Insurance (included in economic analysis).

• Fuel and fuel supply costs (included in economic analysis).

• Initial spare parts (included in capital cost estimate).

SCPC O&M Results

The estimated O&M costs for the project are provided in Table 11-3. Additional O&M cost detail can be found in Appendix G.

Supercritical PC Estimates

11-6

Table 11-3 550 MW (Net) SCPC O&M Summary (2006 US Dollars)

100% PRB

Fixed O&MLabor, $/yr $ 9,687,800 Office and Admin, $/yr $ 96,900 Major Inspections, $/yr $ 280,000 Standby Power Energy Costs, $/yr $ 98,600 Other Fixed O&M, $/yr $ 1,211,000 Fixed O&M, $/yr $ 11,374,300

Variable O&M (85% CF)Emissions Allowance Costs, $/yr

NOx Emissions Allowance Cost $ 2,810,100 SO2 Emissions Allowance Cost $ 1,127,900 Hg Emissions Allowance Cost $ 1,734,700

Major Maintenance Costs, $/yrSteam Turbine / Generator Overhaul $ 339,200 Steam Generator Major Replacements $ 893,900 Baghouse Bag Replacement $ 253,400 SCR Catalyst Replacement $ 312,000 Demin System Replacements $ 4,300

Water Treatment, $/yr $ 1,759,500 Consumables/Disposal, $/yr

Limestone Consumption $ 524,700 SCR Ammonia (Anhydrous) $ 1,041,800 Scrubber Sludge Disposal $ 634,700 Fly Ash Disposal $ 1,412,600 Bottom Ash (Sales) / Disposal $ 351,900 Other Chemical Costs $ -

Other Variable O&M, $/yr $ 5,634,800 Variable O&M, $/yr (85% CF) $ 18,835,500

Fixed O&M, $/kW-yr $ 20.68 Variable O&M, $/MWh $ 4.60 Total O&M Cost, $/Year (85% CF) $ 30,209,800

SCPC Emission Rates

A wet scrubber is assumed for SO2 control, an SCR for NOx control, and a baghouse for particulate control.

Supercritical PC Estimates

11-7

The use of SCR is a proven technology on PC units. ABS formation is not as much of a concern on a PC unit as for an IGCC unit. In a PC unit, maximum ammonia slip is designed to be less than 2 ppmvd at the end of a specified operating period (2-3 years). This means the average slip over that period is significantly less. Much of the remaining ammonia after the catalyst is absorbed in the flyash. ABS formation will typically occur in the air preheaters if slip exceeds this maximum point. Additionally, the heat transfer surfaces (except for the air heater) are located upstream of the SCR in a PC boiler, thus limiting downstream cold areas where the ABS can collect. The HRSG, however, has HP, IP, and LP heat transfer surface downstream of the SCR, which can become plugged with the ABS particulate.

Ammonia salt formation is not as much of a concern on a PC unit as for an IGCC unit. In a PC unit much of the remaining ammonia after the catalyst is absorbed in the flyash, thus ammonia salt formation is limited primarily to that formed in the catalyst while in the presence of ammonia. Additionally, the heat transfer surfaces (except for the air heater) are located upstream of the SCR in a PC boiler, thus limiting downstream cold areas where the ammonia salts can collect. An HRSG, however, has HP, IP, and LP heat transfer surface downstream of the SCR, which can become plugged with the ammonia salts.

Approximately 70% mercury removal has been shown with the combination of an SCR, wet scrubber, and baghouse alone. Additional mercury control can be achieved through the use of halogenated carbon injection or activated carbon injection into the flue gas stream. This was not considered for this assessment due to the small amount of test data that is currently available and the potential for contamination of flyash and gypsum.

The estimated emission rates for the SCPC Unit are provided in Table 11-4.

Supercritical PC Estimates

11-8

Table 11-4 500 MW (Net) SCPC Emissions Estimates

100% PRB

NOx

lb/MMBtu (HHV) 0.050lb/MWh (net) 0.458

SO2

lb/MMBtu (HHV) 0.060lb/MWh (net) 0.549

PM10

lb/MMBtu (HHV)1 0.015

lb/MWh (net)1 0.137CO

lb/MMBtu (HHV) 0.150lb/MWh (net) 1.373

CO2

lb/MMBtu (HHV) 215lb/MWh (net) 1,967

Hg% Removal 70%lb/TBtu (HHV) 2.315lb/MWh (net) 2.12E-05

1) Particulate matter emissions rate is for front half only excluding back half condensables, for the concentration of particulate matter less than 10 microns in diameter

Availability Factor

Historic data for SCPC units in the United States is typically from much earlier vintage units (1970’s). Since the 1980’s, the majority of SCPC units have been installed in Europe and Asia. Development of high strength materials has helped to minimize the thermal stresses that caused problems in early units. Additionally, the development of Distributed Control Systems (DCS) has helped make a complex starting sequence much easier to control and minimize tube overheating due to lack of fluid. Additionally, newer units use a particle separator placed into the fluid process during startup to minimize solid particle carryover, which causes erosion of the turbine blades. Therefore, many of the early problems experienced with SCPC units have been corrected.

Historically, an availability factor for subcritical PC units in the United States has been 87%. Newer supercritical units located overseas have maintained availability factor equal to newer subcritical units at approximately 90% or greater. It is estimated that a new SCPC unit will have an availability factor of approximately 90%.

12-1

12 ECONOMIC ANALYSIS

General

A pro forma economic analysis was prepared for the three solid fuel alternatives: an IGCC unit utilizing 100% PRB coal, an IGCC unit utilizing 50% PRB coal and 50% petcoke, and a SCPC unit firing 100% PRB. A 20-year economic analysis was developed based on the estimated capital costs, performance, fuel costs, and operating costs of each alternative. A 20-year levelized busbar cost in real dollars was determined for each alternative using a revenue requirements analysis of debt service (including principal and interest), fixed O&M, variable O&M, and fuel. The economic analysis was conducted on a real basis, and therefore, the analysis does not include escalation for fuel or O&M.

The economic analysis assumes a debt term of 30 years. However, the busbar cost presented is a levelized value for the first 20 years of the Project. There is not a significant difference in the levelized busbar cost when comparing 20-year and 30-year project periods

Other EPRI reports and published papers have assumed a 30-year constant dollar busbar analysis based on typical investor owned utility (IOU) financial assumptions. A municipal utility has access to lower cost financing, through both lower interest rates and higher leverage factors. Additionally, municipal utilities do not have income tax liability, nor an equity financing component, which typically requires a larger rate of return compared to debt financing. As a result, municipal utilities often have a lower cost of capital compared to typical IOU financing.

Burns & McDonnell estimated capital recovery costs based on debt service payments rather than depreciation and interest. The annual capital recovery costs are equal to the cash flow requirements for debt service payments for both principal and interest associated with 100% debt financing of the project capital expenditures.

Assumptions

The following provides the assumptions utilized in the pro forma economic analysis.

• Capital Cost Estimates: Table 7-1 and Chapter 11

• Fuel Cost Assumptions:

PRB Coal Cost (Delivered, 2005$) $1.65/MMBtu

Economic Analysis

12-2

Petcoke Cost (Delivered, 2005$) $1.14/MMBtu

Fuel Cost Escalation Excluded (real basis)

• Operating Assumptions:

Heat Rate Performance Table 6-1 and Chapter 11

Overall Capacity Factor 85%

Fuel Composition

IGCC Unit 100% PRB coal

IGCC Unit 50% PRB coal, 50% petcoke

SCPC Unit 100% PRB coal

• Financing Assumptions:

Interest Rate 3.0%

Permanent Financing Term 30 years

Capital Structure Debt – 100%, Equity – 0%

Construction Financing Fees 0.50%

Permanent Financing Fees 1.00%

Minimum Debt Service Coverage Ratio 1.00

Debt Service Reserve Fund 50% of annual debt service funded at financial closing

• Economic Assumptions:

O&M Inflation Excluded (real basis)

Construction Cost Inflation Excluded (overnight cost)

Discount Rate 3.0% (real discount rate)

• O&M Cost Assumptions:

Fixed O&M Costs Table 8-1 and Chapter 11

Economic Analysis

12-3

Variable O&M Costs Table 8-1 and Chapter 11

Emissions Allowances Included in Variable O&M

Insurance 0.05% of capital cost

Property Taxes Exempt

Economic Analysis

The economic pro forma analyses were used to determine the levelized busbar cost of power in real dollars for each alternative. Figure 12-1 presents a graph of the resulting levelized busbar power costs in real dollars for the solid fuel-fired alternatives over a 20 year planning period covering 2006 through 2025. Figure 12-1 was developed by preparing a project pro forma model for each of the alternatives under consideration. The levelized busbar cost in real dollars represents the fixed energy cost in 2006 US dollars that would be equivalent to the busbar cost over 20 years. The economic analysis does not include escalation for fuel and O&M costs.

$0.00$5.00

$10.00$15.00$20.00$25.00$30.00$35.00$40.00$45.00$50.00

Leve

lized

Bus

bar C

ost

(200

6$/M

Wh,

Rea

l$)

Supercritical PC $39.28IGCC - 50% PRB / 50% Pet Coke $40.89IGCC - 100% PRB $45.03

Alternative

Figure 12-1 20-Year Levelized Busbar Cost (2006 US Dollars)

Economic Analysis

12-4

Figure 12-2 presents a breakout of the components for the 20-year levelized busbar cost in real dollars for the alternatives in 2006 US dollars.

$16.62

$2.91

$4.66

$15.10

$39.28

$19.62

$3.54

$5.71

$12.02

$40.89

$20.27

$3.54

$6.01

$15.21

$45.03

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

$45.00

$50.00

Leve

lized

Bus

bar C

ost (

2006

$/M

Wh,

Rea

l $)

Supercritical PC IGCC - 50% PRB / 50% PetCoke

IGCC - 100% PRB

Alternatives

Fuel Costs

Variable O&M

Fixed O&M

Debt Service

Figure 12-2 Breakout of 20-Year Levelized Busbar Cost (2006 US Dollars)

The SCPC unit is the lowest cost alternative. Since the SCPC unit is less capital intensive than the two IGCC alternatives, the debt service component for the PC unit is considerably lower, as shown in Figure 12-2. Additionally, the SCPC unit has lower operational and maintenance costs, both variable and fixed, compared to the IGCC alternatives, providing a lower overall project cost.

The IGCC alternative utilizing a fuel blend of PRB coal and petcoke has a lower cost than the IGCC alternative utilizing only PRB coal, and is only slightly higher than the SCPC alternative. The IGCC alternative using coal and petcoke has a slightly lower capital cost than the IGCC alternative utilizing 100% coal, therefore the debt service requirements for both IGCC alternatives is nearly equivalent. However, the blended fuel option has a significantly lower heat rate and delivered fuel cost, therefore lowering the project busbar cost relative to the IGCC alternative utilizing 100% coal. The ability to use an opportunity fuel, such as petcoke, allows the overall levelized busbar cost of the IGCC technology to be lower compared to strictly using PRB coal.

Economic Analysis

12-5

Sensitivity Analysis

A sensitivity analysis was preformed for all three alternatives under the following cases:

• Capital Cost ± 10%

• Interest Rate ± 0.5 percentage point

• Capacity Factor ± 5%

• Coal Fuel Cost ± 10%

• O&M Cost ± 10%

The ranges shown above not intended to imply the accuracy of the estimates, but the resulting change in busbar cost for the range shown. It is possible that the capital cost, interest rate, fuel cost, capacity factor, and O&M cost may vary by a larger amount than shown above.

The results of the sensitivity analysis are presented in the tornado diagram in Figures 12-3 through 12-5. The sensitivity analysis results are presented in 2006 US dollars. A tornado diagram illustrates the range of results for each sensitivity case and its impact on the levelized busbar cost in real dollars, and ranks the results from greatest impact to least impact.

Capital Cost -/+ 10% $37.62 $40.94

Fuel Cost -/+ 10% $37.77 $40.80

Interest Rate -/+ 0.5% $38.03 $40.60

Capacity Factor +/- 5% $38.35 $40.31

O&M Cost -/+ 10% $38.53 $40.03

Levelized Power Cost ($/MWh) $39.28$37.62

$38.17

$38.73 $39.8

4

$40.3

9

$40.9

4 Levelized Power Cost ($/MWh) $39.28

Figure 12-3 Sensitivity Analysis – SCPC Unit – 100% PRB Coal

Economic Analysis

12-6

Capital Cost -/+ 10% $38.93 $42.86

Interest Rate -/+ 0.5% $39.42 $42.45

Fuel Cost -/+ 10% $39.69 $42.10

Capacity Factor +/- 5% $39.79 $42.11

O&M Cost -/+ 10% $39.97 $41.82

Levelized Power Cost ($/MWh) $40.89$38.93

$39.59

$40.24 $41.5

5

$42.2

0

$42.8

6 Levelized Power Cost ($/MWh) $40.89

Figure 12-4 Sensitivity Analysis – IGCC – 50% PRB Coal / 50% Petcoke

Capital Cost -/+ 10% $43.01 $47.06

Interest Rate -/+ 0.5% $43.51 $46.64

Fuel Cost -/+ 10% $43.51 $46.56

Capacity Factor +/- 5% $43.90 $46.29

O&M Cost -/+ 10% $44.08 $45.99

Levelized Power Cost ($/MWh) $45.03$43.01

$43.68

$44.36 $45.7

1

$46.3

9

$47.0

6 Levelized Power Cost ($/MWh) $45.03

Figure 12-5 Sensitivity Analysis – IGCC – 100% PRB Coal

Economic Analysis

12-7

The sensitivity analysis indicates that capital cost is the most significant factor affecting the economics of the IGCC alternatives and the SCPC unit. Additionally, the interest rate and fuel cost have the next most significant affects. Since the pro forma analyses assume the project alternatives are financed with 100% debt, changes in the capital cost and interest rate have a significant affect on the economics of the project, due to the large portion of debt service. The cost of fuel is the largest ongoing cost to the project; therefore significant changes in the cost of fuel will affect the economics of the project.

Solid fuel generation resources are capital intensive, and have a construction period that is approximately four years in duration. This results in more capital risk due to interest costs, labor availability and costs, and general inflation. The primary tradeoff for these higher capital risks with a solid fuel generation resource is the long-term stability of solid fuel prices which has few competing uses relative to natural gas that is used by almost all economic sectors including residential heating.

13-1

13 CO2 CAPTURE

General

As a part of this study, Burns & McDonnell was tasked with determining the approximate impacts to performance, cost, O&M, emissions, and levelized busbar cost for the 100% PRB IGCC and 100% PRB SCPC units from adding CO2 capture systems. For this assessment, it was assumed that the plants are existing units with cost and operating characteristics as defined in previous chapters. The CO2 capture systems are added as a plant retrofit at a later date.

A CO2 capture rate of 90% was targeted for both the IGCC and SCPC technologies. For this assessment, it was assumed the CO2 would be compressed into a common carrier CO2 pipeline. The pipeline may serve many purposes including:

• Storage in depleted/disused oil and gas fields.

• Enhanced Oil Recovery (EOR) combined with CO2 storage.

• Enhanced coal bed methane recovery (ECBM) combined with CO2 storage.

• Storage in deep saline aquifers/formations (DSF) – both open and closed structures.

The assumed common carrier pipeline pressure is 2,000 psig. The cost of the CO2 pipeline and/or storage is not included in the estimates.

Table 13-1 provides the assumed CO2 purity required for the common carrier pipeline.

CO2 Capture

13-2

Table 13-1 CO2 Purity Specification

a Minimum miscible pressure concern because the application of the CO2 is potentially for EOR. b Dew point: < -40 °F c Based on limiting H2S partial pressure to 0.3 kPa, above which the pipeline will be classified for sour service. d There will also be a lower limit associated with potential failure of the pipeline but this is not relevant to most of the North American pipelines because of their location.

The potential for CO2 sales exists, which could help offset the costs associated with CO2 capture. In 2005 EPRI evaluated the potential CO2 sales costs for the CO2 storage options listed above (Building the Cost Curve for CO2 Storage: North American Sector, EPRI, Palo Alto, CA: 2005. Report No. 1010167). As a part of this 2005 study, cost curves for each storage option were developed by compiling data on geological reservoirs for CO2 storage and determining the technical storage capacity of these reservoirs. These data, along with baseline study data on CO2 sources, were then analyzed within a purpose-built techno-economic model based upon geographic information system (GIS) technology. The mapping capability of the GIS allowed the presentation of the data base information at both regional and continental scales. The computational portion of the model calculated the distance between each source and accessible candidate storage reservoir and compared characteristics such as CO2 flow rate, remaining storage capacity, depth, and other injection parameters, to estimate the cost for CO2 transmission and storage for each source and reservoir pair. The overall costs for CO2 storage in the USA were modeled to be effectively capped at about $12-15/Mt CO2, with important yet limited resource available below $0/Mt CO2.

The results of the previous EPRI study are summarized in Figure 13-1.

SUBSTANCE LIMIT MAX OR MIN

REASON

CO2 95% Min MMP concern a

N2 4% Max MMP concern Hydrocarbons 5% Max MMP concern H2O b -40 °C (-40 °F) Max Corrosion O2 100 ppm Max Corrosion H2S 25 ppm Max Safety C

CO 0.1% Max Safety Glycol 174 lit/106 m3

(0.3 gal/MMcf) Max Operations

Temperature 50 °C (120 °F) d Max Materials Pressure 13,800 kPa Normal Materials (2,000 psig)

CO2 Capture

13-3

Figure 13-1 CO2 Storage Supply Curve for North America

For purposes of this study, any revenue or cost associated with CO2 disposal were not considered. It is assumed that the captured CO2 is disposed at zero cost.

If a dedicated pipeline for EOR or other designated purpose were to be used rather than the common carrier pipeline assumed for this report, the design of the CO2 capture systems could be significantly different which may produce different results.

There are many legal and regulatory aspects with regard to CO2 storage that have not been evaluated for this study.

The capital cost, O&M, and performance assumptions provided in previous sections are applicable for the CO2 capture cases.

IGCC CO2 Capture

CO2 capture in an IGCC facility is accomplished by removing the CO2 and water from the syngas prior to combustion. This is achieved by first shifting the syngas to convert CO to CO2 and H2 by the addition of water-gas shift reactors. The CO2 is then absorbed in the AGR unit, resulting in a hydrogen rich fuel. For the purposes of this analysis, SELEXOL was used as the solvent for CO2 removal (SELEXOL is discussed in greater detail in Chapter 4).

CO2 capture for an IGCC facility has not been proven commercially, however CO2 capture has been proven commercially at the Dakota Gasification Company’s Great Plains Synfuels Plant, which sends compressed CO2 through a pipeline for Enhanced Oil Recovery (EOR).

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13-4

IGCC Modifications for CO2 Capture

For this study, all major modifications for CO2 capture are downstream of the gasification block. These modifications include:

• Replacement of the COS/HCN hydrolysis reactor with two stages of sour shift reaction to convert carbon monoxide to CO2.

• Additions to the syngas cooling train to incorporate the shift reactors.

• Additions to the SELEXOL AGR to recover CO2 as a separate byproduct.

• Addition of a single CO2 compressor, consisting of four multi-stage centrifugal compressor cases with intercoolers and CO2 product cooler, is included to deliver CO2 at 2,000 psig to the pipeline. Heat recovery from CO2 compression is not included at this stage, but should be evaluated in the future.

The acid gas composition from the SELEXOL unit to the Sulfur Recovery Units was set at 25% H2S as in the non-capture case. The SRU/TGTU design is therefore identical to the non-capture case.

Process flow diagrams for the modified syngas flow train are included in Appendix A. Original equipment that is reused is highlighted in yellow.

Sour Shift

The COS/HCN reactor included in the non-capture case is replaced with two stages of sour shift reaction. The shift reaction converts approximately 95% of the carbon monoxide to CO2, generating hydrogen fuel as a byproduct. The shift reaction is

CO + H2O H2 + CO2

The reactors operate with 1.3 moles of steam feed per mole of dry gas (or 2.1 mole of H2O per mole of CO). IP steam is added upstream of the reactors to replace steam consumed in the reaction. The balance is generated by heating and vaporizing process water.

Cobalt-molybdenum sour shift catalyst is a good COS/HCN hydrolysis catalyst. Both COS and HCN are almost entirely hydrolyzed in the reactors, eliminating the need for a separate reactor.

Since each mole of CO is replaced with a mole of H2, the available syngas chemical energy (MMBtu/hr) on an HHV basis actually increases slightly from the un-shifted syngas due to H2 having a higher HHV heating value than CO. However, since CO does not form water as a byproduct of combustion, the LHV and HHV heating value of CO are identical. Therefore, the LHV energy of the shifted syngas (MMBtu/hr) decreases by approximately 9.7%.

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13-5

Syngas Cooling and Condensation

The exothermic shift reaction and the addition of steam to facilitate the reaction significantly increase the heat load on the syngas cooling train. Several new heat exchangers are required to remove this heat. The additional heat is used to preheat the shift feed and to generate part of the steam feed to the reactors.

Due to the number of heat exchangers and additional pressure drop through the AGR, some increase in the gasifier pressure is required to maintain the needed pressure at the inlet of the gas turbines. This increase can be minimized by appropriate design of the exchangers and is believed to be within the design allowance of the gasifier.

Acid Gas Removal (AGR)

The number of moles, and therefore the volumetric flow rate, of syngas feeding the AGR is about 60% higher than in the non-capture case. Although most of the original non-capture equipment (towers, large heat exchangers and refrigeration equipment) can be reused, significant additions are required to handle the additional volumetric flow and to separate CO2 as a separate byproduct.

The following new equipment is required:

• H2S absorber (in parallel to original absorber).

• H2S stripper with reboiler, condenser, reflux drum, and pumps (in parallel to original stripper).

• H2S concentrator (common to both H2S absorber/stripper trains).

• Rich solvent pumps to feed H2S absorber bottoms to the H2S concentrator.

• New rich flash compressor and coolers to replace original units.

• CO2 absorber.

• Loaded solvent pumps to feed H2S absorbers.

• Solvent regeneration flash drum system (4 drums with CO2 recycle compressor and CO2 vacuum compressor.

• Semi-lean solvent pumps and chiller to feed cold regenerated solvent to CO2 absorber.

• Refrigeration package.

IGCC Impacts from CO2 Capture

IGCC Performance – CO2 Capture

The shift reaction results in a high hydrogen content fuel with a higher heating value (Btu/lb) than for the standard syngas cases. This results in less mass flow through the gas turbines and

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13-6

less gas turbine power as a result. Additionally, more steam is required for the AGR and a large quantity of IP steam (450,000 lb/hr) is required for the water-gas shift reaction resulting in substantially less steam turbine output.

The auxiliary load of the facility also increases substantially due to the CO2 compression (approximately 37.1 MW) and the increased auxiliary loads of the AGR. The net result is approximately a 25% reduction in net plant output and a 39% increase in net plant heat rate.

The cooling load of the facility decreases since a large portion of the steam is extracted for the AGR and water-gas shift reaction. However due to the large amount of steam leaving the cycle, the plant makeup requirement has increased by approximately 23%.

Table 13-2 illustrates the impact of CO2 capture on the IGCC facility.

Table 13-2 IGCC Performance Impacts from CO2 Capture

Base Case (100% PRB)

CO2 Capture (100% PRB)

Ambient Dry Bulb Temperature, °F 73 73Ambient Wet Bulb Temperature, °F 69 69Elevation, ft. 100 100Evaporative Cooling, On/Off Off Off

Coal Heat Input, MMBtu/hr (LHV) 4,705 4,883Coal Heat Input, MMBtu/hr (HHV) 5,099 5,291

Gas Turbine Gross Output, MW (each) 224.9 213.8Gas Turbine Gross Output, MW (total) 449.7 427.5Steam Turbine Gross Output, MW 260.1 202.6Gross Plant Output, MW 709.9 630.1

Auxiliary LoadPower Block, MW 22.0 22.0Material Handling, MW 5.9 6.2Air Separation Unit, MW 122.1 123.4Gasifier, MW 2.1 2.2CO2 Compression 0.0 37.1Syngas Treatment, MW 4.7 26.0

Total Plant Auxiliary Load, MW 156.8 216.8

Net Plant Output, MW 553.0 413.3Net Plant Heat Rate, Btu/kWh (LHV) 8,510 11,810Net Plant Heat Rate, Btu/kWh (HHV) 9,220 12,800

Plant Cooling Requirements, MMBtu/hr (Total) 2,141 2,101Steam Cycle Cooling Requirement, MMBtu/hr 1,480 1,120BOP Auxiliary Cooling Requirement, MMBtu/hr 661 981

Total Makeup Water RequirementGPM 4,980 6,147Acre-ft/year (@ 85% CF) 6,830 8,430

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13-7

IGCC Capital Cost – CO2 Capture

In addition to the revised AGR costs, syngas treatment costs, and CO2 compression costs, the demineralized water treatment and storage system must be upgraded due to the 450,000 lb/hr of IP steam being used for the water-gas shift reaction.

For the CO2 capture case, much more heat load (approximately 300 MMBtu) is transferred to the condensate (See heat exchanger SGT-HTX-110 in Appendix A). This results in significantly more LP steam production than in the Base Case. The LP superheater provided in the Base Case HRSG is undersized to superheat this amount of steam. Therefore, $2,000,000 in HRSG modifications are required to increase the size of the HRSG LP superheaters.

The additional capital cost estimated for CO2 capture retrofit is shown in Table 13-3. The capital cost is provided in overnight mid-2006 US dollars.

Table 13-3 IGCC Capital Cost Additions for CO2 Capture Retrofit

Installed CostsAGR and Syngas Treatment Modifications $ 156,620,000 CO2 Compressors $ 16,600,000 Additional Demineralized Water Treatment & Storage $ 4,000,000 HRSG LP Superheater Modifications $ 2,000,000

Total EPC Retrofit Cost (2006 US $) $ 179,220,000 Owner's Costs $ 17,960,000 Total Retrofit Cost (2006 US $) $ 197,180,000

Total EPC Plant Costs (Including Base Case) $ 1,498,200,000 Total Project Costs (Including Base Case) $ 1,671,400,000

Total EPC Contractor Cost (2006 US $), $/kW (73°F) $ 3,630 Total Project Cost (2006 US $), $/kW (73°F) $ 4,040

The cost of the CO2 pipeline and/or storage is not included in the estimates.

IGCC Operations and Maintenance – CO2 Capture

Due to the increased size and role of the AGR for the CO2 capture case, it is assumed that an additional control room operator is required for each shift, resulting in a plant staff of 130.

Other impacts to O&M are minimal from a $/year perspective, however due to the reduced output of the facility, the O&M increases greatly on a $/kW-yr and $/MWh basis.

The CO2 that is captured is assumed to be sold to the common carrier pipeline at zero cost.

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13-8

The O&M for the IGCC facility with and without CO2 capture is provided in Table 13-4.

Table 13-4 IGCC O&M Impacts from CO2 Capture

Base Case (100% PRB)

CO2 Capture (100% PRB)

Fixed O&MLabor, $/yr $ 11,835,700 $ 12,209,200 Office and Admin, $/yr $ 118,400 $ 122,100 Major Inspections, $/yr $ 400,000 $ 400,000 Standby Power Energy Costs, $/yr $ 98,600 $ 98,600 Other Fixed O&M, $/yr $ 1,479,500 $ 1,526,200 Fixed O&M, $/yr $ 13,932,200 $ 14,356,100

Variable O&M (85% CF)Emissions Allowance Costs, $/yr

NOx Emissions Allowance Cost $ 3,588,300 $ 3,604,800 SO2 Emissions Allowance Cost $ 360,700 $ 78,800 Hg Emissions Allowance Cost $ 590,000 $ 612,000

Major Maintenance Costs, $/yrSteam Turbine / Generator Overhaul $ 260,400 $ 260,400 HRSG Major Replacements $ 200,000 $ 200,000 Gasifier Replacements $ 885,800 $ 885,800 Candle Filter Major Replacements $ 300,000 $ 300,000 Gas Turbine Major Replacements $ 8,148,700 $ 8,148,700 Syngas Treatment Major Replacements $ 375,000 $ 587,500 Air Separation Unit Major Replacements $ 275,000 $ 275,000 Mercury Carbon Bed Replacements $ 530,300 $ 530,300 HCN/COS Hydrolysis Catalyst Replacements $ 640,000 $ - Shift Catalyst Replacements $ - $ 1,020,000 Demin System Replacements $ 3,600 $ 20,100

Water Treatment, $/yr $ 1,479,100 $ 2,066,800 Fly Ash & Slag Disposal $ 1,560,200 $ 1,560,200 Other Variable O&M, $/yr $ 5,297,400 $ 6,154,900 Variable O&M, $/yr (85% CF) $ 24,494,500 $ 26,305,300

Fixed O&M, $/kW-yr $ 25.19 $ 34.74 Variable O&M, $/MWh $ 5.95 $ 8.55 Total O&M Cost, $/Year (85% CF) $ 38,426,700 $ 40,661,400

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IGCC Emissions – CO2 Capture

CO2 emissions are reduced by 90% in the SELEXOL unit. In order to meet the CO2 purity spec provided in Table 13-1, 25 ppm H2S is required at the outlet of the H2S absorber. From the H2S absorber, the low H2S content syngas is then passed through a CO2 absorber where the CO2 is stripped off. Because the low H2S content syngas is again exposed to the SELEXOL solvent in the CO2 stripper, the sulfur content of the syngas is reduced significantly (approximately 1 ppm COS and 1 ppm H2S), resulting in a reduction of SO2 emissions (ton/yr) by approximately 80%.

The resulting emission rates are shown in Table 13-5.

Table 13-5 IGCC Emissions Impacts from CO2 Capture

Base Case (100% PRB)

CO2 Capture (100% PRB)

NOx

lb/MMBtu (HHV) 0.063 0.061ppmvd @ 15% O2 15 15lb/MWh (net) 0.581 0.781

SO2

lb/MMBtu (HHV) 0.019 0.004lb/MWh (net) 0.173 0.051

PM10

lb/MMBtu (HHV)1 0.007 0.007

lb/MWh (net)1 0.065 0.090CO

lb/MMBtu (HHV) 0.037 0.035 (Note 2)ppmvd 25 25 (Note 2)lb/MWh (net) 0.337 0.448 (Note 2)

CO2

lb/MMBtu (HHV) 215 22lb/MWh (net) 1,985 276

Hg% Removal 90% 90%lb/TBtu (HHV) 0.778 0.778lb/MWh (net) 7.17E-06 9.96E-06

1) Particulate matter emissions rate is for front half only excluding back half condensables, for the concentration of particulate matter less than 10 microns in diameter

2) GE is currently in the process of developing tools to accurately predict CO emissions for high hydrogen fuels. It is estimated that CO emissions will be less than shown for IGCC technology, however to what extent is unknown at this time.

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IGCC Pre-Investment Options for CO2 Capture

This study was performed with minimal pre-investment for CO2 capture equipment other than allowing space for future expansion and including SELEXOL in the base case (which may be the AGR of choice without consideration for CO2 capture as discussed in Chapter 4). Other options for pre-investment include:

• Design syngas cooler with a hotter exit temperature, resulting in more water being vaporized in the syngas scrubber and decreasing steam demand upstream of the water-gas shift. This results in lower cost of the syngas cooler and better CO2 capture performance, however it also results in higher heat rate during non-capture operation.

• Supplemental duct firing can be added to the HRSG to make up for loss of steam turbine output.

• Increase size of initial gasification block to allow for additional syngas production to increase output for CO2 capture cases (in particular the cold ambient conditions which are limited on syngas).

SCPC CO2 Capture

Unlike IGCC technology, SCPC technology utilizes post-combustion capture of CO2 using chemical absorption, also capable of achieving 90% removal efficiencies. Different technologies are available that use various solvents. Mitsubishi Heavy Industries (MHI) utilizes a tertiary amine solvent called KS-1; additionally ammonia-based technology is being developed that utilizes aqueous ammonium carbonate to capture CO2 as ammonium bicarbonate.

The technology evaluated for this study is based on Fluor’s Econamine FG PlusSM (EFG+) CO2 capture technology, which is based on a formulation of monoethanolamine (MEA) and proprietary additives for operation in high O2 content gas and for corrosion resistance. A block flow diagram provided by Fluor is provided in Figure 13-2.

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13-11

Figure 13-2 Fluor EFG+ Block Flow Diagram

The purpose of the EFG+ plant is to recover 90% of the carbon dioxide from the flue gas of the existing the FGD. The plant consists of an Absorption section and a Stripper section. This results in a plant with a total capacity of 11,697 ton/day (100% CO2 basis).

The EFG+ plant battery limit for the flue gas feed is at the exit of the FGD. All of the flue gas from the FGD is routed to the EFG+ plant thus resulting in a zero flow of gas through the existing stacks to the atmosphere. The flue gas enters the Flue Gas Conditioning Unit (FGCU) where the gas is cooled by a circulating water stream, and the sulfur content of the gas is lowered from 7 ppmv to 1 ppmv. By lowering the gas temperature, much of the water vapor contained in the flue gas is condensed and separated from the feed gas before entering the Absorber.

The cooled, overhead gas from the FGCU is routed by a Blower to the Absorber. The flue gas enters the bottom of the Absorber and flows upwards counter current to the circulating solvent. The solvent reacts chemically to remove the carbon dioxide in the feed gas. Residue gas, consisting mainly of nitrogen and oxygen, is vented through the top of the Absorber.

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13-12

The rich solvent, containing absorbed carbon dioxide from the Absorber, is routed to the Stripper. The rich solvent enters the Stripper and flows down counter current to stripping stream, which removes carbon dioxide from the rich solvent. Heat for stripping is supplied by low pressure steam via the Reboiler. Lean solvent from the Stripper is routed back to the Absorber. The overhead vapor from the Stripper is routed to the Product CO2 Compressor.

To maintain the highest possible absorption capacity of the solvent, contaminants, such as heat stable salts, are continuously removed in the Reclaimer.

EFG+ technology has not been proven commercially for a full scale PC unit, however commercial experience exists for capturing CO2 from natural gas and fuel oil fired units, primarily for use in the food industry, EOR, and urea plants. Two demo plants have been constructed in Japan firing LPG and an oil/coal mixture. Additionally, Fluor is currently developing two demonstration plants that will fire coal and natural gas.

SCPC Modifications for CO2 Capture

The Econamine FG Plus (EFG+) process for CO2 capture requires that the level of SO2 in the flue gas be minimized. Any SO2 entering the EFG+ CO2 absorber will react with the MEA solvent resulting in formation of waste salts that must be purged from the system. Therefore, approximately 7 ppm (approximately 98% removal with PRB fuel) SO2 is required at the inlet to Fluor’s flue gas conditioning system. To the extent that the SO2 entering the EFG+ process is greater than about 1 ppm, it must be reduced to that level within the EFG+ process upstream of the CO2 absorber. The EFG+ process accomplishes this reduction by scrubbing the flue gas with sodium hydroxide (NaOH).

In order to provide 7 ppm inlet SO2 to the EFG+ process as described above, additional FGD SO2 removal capacity must be installed in the wet FGD. Since the FGD system was initially designed with a space allocation for future SO2/CO2 control, new internal spray headers and the recycle pumps can be installed at this time to reduce the overall inlet SO2 to the 7 ppm required. The installed cost for the FGD internals and recycle pumps is approximately $2.5 million.

Because this analysis is performed from a retrofit standpoint, the following modifications to the existing SCPC unit are required. All major modifications for CO2 capture are downstream of the existing wet FGD. These include:

• Addition of wet FGD upgrades described above.

• Addition of Fluor EFG+ System.

• Addition of a single CO2 compressor, consisting of four multi-stage centrifugal compressor cases with intercoolers and product cooler, is included to deliver CO2 at 2,000 psig to the pipeline. Heat recovery from CO2 compression is not included at this stage, but should be evaluated in the future.

• Although the steam turbine condenser duty is less than before, the EFG+ system requires approximately 1,730 MMBtu/hr of auxiliary cooling, resulting in the need for additional cooling capacity. This is accomplished by the addition of a new cooling tower and circulating water system.

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SCPC Impacts from CO2 Capture

SCPC Performance – CO2 Capture

The SCPC performance adjustments for CO2 capture are as follows:

• Approximately 1.4 million lb/hr of saturated LP steam (45 psig) is required by the EFG+ Reboiler. Steam is taken from the IP steam turbine exhaust to supply this steam. This extraction is approximately 40% of the flow from the IP turbine exhaust, which reduces the steam turbine output by approximately 93 MW. The remaining steam through the steam turbine is sufficient for providing adequate blade cooling.

• Additionally, the EFG+ system has an auxiliary load of approximately 19 MW.

• The additional cooling capacity auxiliary load discussed above is estimated at 3.5 MW.

• Approximately 42.6 MW of CO2 compression is required to compress the CO2 to 2,000 psig.

• Approximately 2 MW for addition of new FGD recycle pumps.

The net result is approximately a 29% reduction in net plant output and a 41% increase in net plant heat rate.

Due to the large auxiliary cooling requirement of the EFG+ system, the plant makeup water requirement increased by approximately 34%.

The resulting performance is show in Table 13-6, both pre and post-CO2 capture.

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Table 13-6 SCPC Performance Impacts from CO2 Capture

Base Case (100% PRB)

CO2 Capture (100% PRB)

Ambient Dry Bulb Temperature, °F 73 73Ambient Wet Bulb Temperature, °F 69 69Elevation, ft. 100 100

Coal Heat Input, MMBtu/hr (LHV) 4,644 4,644Coal Heat Input, MMBtu/hr (HHV) 5,033 5,033

Gross Plant Output, MW 614.5 521.4Total Plant Auxiliary Load, MW 64.5 131.6

Net Plant Output, MW 550.0 389.8Net Plant Heat Rate, Btu/kWh (LHV) 8,440 11,910Net Plant Heat Rate, Btu/kWh (HHV) 9,150 12,910

Plant Cooling Requirements, MMBtu/hr (Total) 2,490 3,330Steam Cycle Cooling Requirement, MMBtu/hr 2,300 1,354BOP Auxiliary Cooling Requirement, MMBtu/hr 190 1,976

Total Makeup Water RequirementGPM 5,800 7,757Acre-ft/year (@ 85% CF) 7,950 10,640

SCPC Capital Cost – CO2 Capture

The additional capital cost encountered once CO2 capture equipment is installed is shown in Table 13-7. The capital cost is provided in overnight mid-2006 US dollars.

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Table 13-7 SCPC Capital Cost Additions for CO2 Capture Retrofit

Installed CostsFluor Econamine FG+ System $ 243,000,000 CO2 Compressors $ 17,530,000 FGD Modifications to Obtain 98% SO2 Removal $ 2,500,000 Additional Cooling Capacity $ 6,400,000

Total EPC Retrofit Cost (2006 US $) $ 269,430,000 Owner's Costs $ 26,570,000 Total Retrofit Cost (2006 US $) $ 296,000,000

Total EPC Plant Costs (Including Base Case) $ 1,342,010,000 Total Project Costs (Including Base Case) $ 1,498,340,000

Total EPC Contractor Cost (2006 US $), $/kW (73°F) $ 3,440 Total Project Cost (2006 US $), $/kW (73°F) $ 3,840

The cost of the CO2 pipeline is not included in the estimates.

SCPC Operations and Maintenance – CO2 Capture

Based on input from Fluor, an additional control room operator and field operator are required (per shift), resulting in a plant staff of 111.

Other impacts to O&M are minimal from a $/year perspective, however due to the reduced output of the facility, the O&M increases greatly on a $/kW-yr and $/MWh basis.

The CO2 that is captured is assumed to be sold to the common carrier pipeline at zero cost.

The O&M for the SCPC facility with and without CO2 capture is provided in Table 13-8.

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Table 13-8 SCPC O&M Impacts from CO2 Capture

Base Case (100% PRB)

CO2 Capture (100% PRB)

Fixed O&MLabor, $/yr $ 9,687,800 $ 10,434,900 Office and Admin, $/yr $ 96,900 $ 104,300 Major Inspections, $/yr $ 280,000 $ 280,000 Standby Power Energy Costs, $/yr $ 98,600 $ 98,600 Other Fixed O&M, $/yr $ 1,211,000 $ 1,304,400 Fixed O&M, $/yr $ 11,374,300 $ 12,222,200

Variable O&M (85% CF)Emissions Allowance Costs, $/yr

NOx Emissions Allowance Cost $ 2,810,100 $ 2,529,400 SO2 Emissions Allowance Cost $ 1,127,900 $ 4,800 Hg Emissions Allowance Cost $ 1,734,700 $ 1,734,900

Major Maintenance Costs, $/yrSteam Turbine / Generator Overhaul $ 339,200 $ 339,200 Steam Generator Major Replacements $ 893,900 $ 893,900 Baghouse Bag Replacement $ 253,400 $ 253,400 SCR Catalyst Replacement $ 312,000 $ 312,000 Demin System Replacements $ 4,300 $ 4,300

Water Treatment, $/yr $ 1,759,500 $ 2,372,900 Consumables/Disposal, $/yr

Limestone Consumption $ 524,700 $ 551,200 SCR Ammonia (Anhydrous) $ 1,041,800 $ 1,042,000 Scrubber Sludge Disposal $ 634,700 $ 666,800 Fly Ash Disposal $ 1,412,600 $ 1,412,800 Bottom Ash (Sales) / Disposal $ 351,900 $ 351,900 Other Chemical Costs $ - $ 2,236,500

Other Variable O&M, $/yr $ 5,634,800 $ 5,634,800 Variable O&M, $/yr (85% CF) $ 18,835,500 $ 20,340,800

Fixed O&M, $/kW-yr $ 20.68 $ 31.19 Variable O&M, $/MWh $ 4.60 $ 6.97 Total O&M Cost, $/Year (85% CF) $ 30,209,800 $ 32,563,000

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SCPC Emissions – CO2 Capture

In addition to removing 90% of CO2 emissions, the outlet SO2 from the EFG+ Absorber is reduced to approximately 0.1 ppm (99.9+% removal) and NOx emissions are reduced by approximately 10%. The resulting emission rates are shown in Table 13-9. Additionally, these reduced emissions are reflected in the O&M costs provided in Table 13-8.

Table 13-9 SCPC Emissions Impacts from CO2 Capture

Base Case (100% PRB)

CO2 Capture(100% PRB)

NOx

lb/MMBtu (HHV) 0.050 0.045lb/MWh (net) 0.458 0.581

SO2

lb/MMBtu (HHV) 0.060 0.0003lb/MWh (net) 0.549 0.003

PM10

lb/MMBtu (HHV)1 0.015 0.015

lb/MWh (net)1 0.137 0.194CO

lb/MMBtu (HHV) 0.150 0.150lb/MWh (net) 1.373 1.937

CO2

lb/MMBtu (HHV) 215 22lb/MWh (net) 1,967 278

Hg% Removal 70% 70%lb/TBtu (HHV) 2.315 2.315lb/MWh (net) 2.12E-05 2.99E-05

1) Particulate matter emissions rate is for front half only excluding back half condensables, for the concentration of particulate matter less than 10 microns in diameter

SCPC Pre-Investment Options for CO2 Capture

This study was performed with minimal pre-investment in CO2 capture equipment. The only pre-investments made were the increase in FGD absorber size, allowing expansion of the FGD to achieve 7 ppm SO2 in the future for the CO2 capture case and the plot space allocation for future CO2 capture equipment. Other options for pre-investment that should be further evaluated in the future are as follows:

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• The use of a deaerating condenser in lieu of a standard deaerator arrangement (open feedwater heater) allows for boiler feedwater to be routed to the CO2 compressor interstages, providing reduced compressor auxiliary load and less steam extraction from the steam cycle.

• Increasing the size of the wet FGD to reduce SO2 emissions to 1 ppm (instead of 7 ppm assumed for this evaluation). This would eliminate the need for the sodium hydroxide scrubber currently included in Fluor’s scope. Although achieving this low of an SO2 emission with a wet FGD is typically cost prohibitive, it is likely more cost effective that the use of the sodium hydroxide scrubber. It should be noted that obtaining SO2 guarantees of 1 ppm from FGD vendors is not likely at this stage.

• Other multi-pollutant flue gas clean-up systems such as J-Power’s ReACTTM system (utilizing regenerated activated carbon) and Powerspan’s ECO® system (utilizing electro-catalytic oxidation) may provide emissions requirements more acceptable for SCPC CO2 capture technology without the need for major modifications.

CO2 Capture Economics

A 20-year levelized busbar cost analysis was performed using the same assumptions as provided in Chapter 12. The resulting busbar costs are provided in Table 13-10.

Table 13-10 CO2 Capture Busbar Costs

Base Case (100% PRB)

CO2 Capture (100% PRB)

% Increase

IGCC 20-year levelized busbar cost (2006 Real $) $45.03 $65.41 45%SCPC 20-year levelized busbar cost (2006 Real $) $39.28 $62.00 58%

The avoided CO2 cost can be determined by dividing the differential busbar cost between the capture and non-capture cases by the differential metric tons/MWh between the capture and non-capture cases.

The resulting avoided CO2 costs are as follows:

• IGCC $26.28 / Mt CO2 avoided

• SCPC $29.64 / Mt CO2 avoided

The results indicate that adding CO2 capture to an existing IGCC is a more efficient means of reducing CO2 emissions than adding CO2 capture equipment to an existing SCPC facility; however the initial busbar cost difference (pre-CO2 capture) between the two technologies still results in PC technology having the lowest post-capture busbar cost.

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A brief analysis was performed to determine what CO2 emissions allowance cost ($/Mt) would be required to justify the expense of the addition of CO2 capture to both technologies (assuming CO2 is sold at zero cost). Approximately $30/Mt for SCPC technology and $26/Mt for IGCC technology were determined to be the break-even points. An allowance cost above these figures may justify the additional expense of installing CO2 capture equipment. Additionally, any CO2 sales above zero cost ($/Mt) would reduce the breakeven point accordingly.

14-1

14 OTHER CONSIDERATIONS

Byproduct Sales

The two major byproducts from the IGCC process are slag and sulfur. The slag coming off of the bottom of the gasifier is vitrified, has low bulk density, high shear strength, and good leachability characteristics. As such, IGCC slag has the ability to be utilized as a feedstock to a number of different industries.

Identified markets for IGCC slag include: • Construction structural backfill • Asphalt paving aggregate • Portland cement aggregate • Asphalt shingle roofing granules • Pipe bedding material • Blasting grit • Mineral filler • Road drainage media • Water filtering medium • Water-jet cutting

The sulfur in the syngas is removed in the AGR and then generally either sent to a Claus unit to convert it to elemental sulfur or to a sulfuric acid plant for to make sulfuric acid. The sulfur or sulfuric acid is also utilized in a number of industries, including asphalt, and agriculture.

A smaller potential by-product is the flyash. The flyash produced by the Shell gasifier has very low carbon content and therefore has attractive qualities for use in cement manufacturing.

Co-Production

One advantage of the IGCC technology is the capability of producing a variety of chemicals in addition to the production of electricity, especially during the times of the year when it may not be economically attractive to produce power.

The properties of the syngas produced by the coal gasification process can be adjusted to allow a range of hydrogen to carbon monoxide molar rations, and stand alone gasification plants have been operating for years with refinery waste streams to produce syngas for chemical production. Various options for downstream integration correspond to a range of value added products. Figure 14-1 identifies some of the possible products resulting from coal gasification.

Other Considerations

14-2

Figure 14-1 Products from Syngas

Plant Degradation

Plant degradation has not been included in the performance estimates or economic analysis. It should be noted that gas turbine degradation (and consequently steam turbine performance reduction) can be significant over time. This may result in 4-5% average degradation over the life of the plant depending on frequency of water wash and gas turbine maintenance (compared to ~2% for a PC Unit).

Lignite Gasification

Another potential lower cost feedstock for an IGCC in Texas would be lignite. While lignite is an abundant resource in Texas, the combination of its high ash content and high moisture content, makes it unattractive to be transported to power plants. Instead, lignite-based power plants are typically located at the “mine mouth”. In the present study, the site location is not near a lignite resource and therefore lignite was not evaluated as a fuel.

However, if a mine-mouth site was used, it might be an economic option. Mine-mouth lignite’s lower fuel cost must be balanced against some undesirable impacts on the IGCC design. Compared to PRB coal, Texas lignite has more ash, more sulfur, and more moisture. Each of these has a negative impact on thermal efficiency while increasing the capital cost of the design.

Since the Shell gasification technology, a dry coal-feed gasifier, is used here, lignite may be used and still produce plant efficiency in the upper 30’s. The off-set is the increase in coal drying energy required. The use of coal drying processes that utilize low level energy, such as the RWE Vapour Compression cycle, may make use of the abundant low-level energy in the IGCC cycle that is currently going unused. The use of lignite in slurry-feed gasifiers will likely result in energy penalties too severe to produce economic benefits, even at low fuel costs.

CoalGasification

PowerGeneration

Hydrogen

SyntheticNatural Gas

CO2

Methanol Fisher-TropesLiquids

Synthesis Gas

-Ammonia-Fertilizers- Urea

- Enhanced oil recovery

- Acetate products- Acetic Acid- Ethylene / Propylene

- Gasoline- Diesel- Jet Fuel

15-1

15 SUMMARY

A summary of the information provided in previous chapters is provided in Table 15-1 and Table 15-2.

Summary

15-2

Table 15-1 Summary Table (1 of 2)

Base Cases CO2 Capture CasesIGCC SCPC IGCC SCPC

Case 100% PRB 50% PRB / 50% Petcoke 100% PRB 100% PRB IGCC 100% PRBFuel

PRB (% wt.) 100% 50% 100% 100% 100%Petcoke (% wt.) 0% 50% 0% 0% 0%PRB (% heat input) 100% 36% 100% 100% 100%Petcoke (% heat input) 0% 64% 0% 0% 0%HHV (Btu/lb) 8,156 11,194 8,156 8,156 8,156

Capital Cost (2006 USD)EPC Capital Cost $1,318,980,000 $1,287,540,000 $1,072,580,000 $179,220,000 (Note 1) $269,430,000 (Note 1)Owner's Costs $155,240,000 $139,500,000 $129,760,000 $17,960,000 (Note 1) $26,570,000 (Note 1)Total Project Cost $1,474,220,000 $1,427,040,000 $1,202,340,000 $197,180,000 (Note 1) $296,000,000 (Note 1)EPC Capital Cost, $/kW (73°F Ambient) $2,390 $2,330 $1,950 $3,630 (Note 1) $3,440 (Note 1)Total Project Cost, $/kW (73°F Ambient) $2,670 $2,580 $2,190 $4,040 (Note 1) $3,840 (Note 1)

Performance43°F Dry Bulb, 40°F Wet Bulb

Gross Plant Output, MW 736.6 734.2 623.3 Not Evaluated Not EvaluatedAuxiliary Load, MW 137.4 137.2 65.4 Not Evaluated Not EvaluatedNet Plant Output, MW 599.2 597.0 557.8 Not Evaluated Not EvaluatedNet Plant Heat Rate, Btu/kWh (HHV) 9,090 8,950 9,030 Not Evaluated Not Evaluated

73°F Dry Bulb, 69°F Wet BulbGross Plant Output, MW 709.9 711.1 614.5 630.1 521.4Auxiliary Load, MW 156.8 158.0 64.5 216.8 131.6Net Plant Output, MW 553.0 553.0 550.0 413.3 389.8Net Plant Heat Rate, Btu/kWh (HHV) 9,220 9,070 9,150 12,800 12,910

93°F Dry Bulb, 77°F Wet BulbGross Plant Output, MW 681.5 682.6 613.2 Not Evaluated Not EvaluatedAuxiliary Load, MW 153.2 154.5 64.4 Not Evaluated Not EvaluatedNet Plant Output, MW 528.4 528.2 548.8 Not Evaluated Not EvaluatedNet Plant Heat Rate, Btu/kWh (HHV) 9,350 9,210 9,170 Not Evaluated Not Evaluated

O&M Cost (2006 USD)Fixed O&M, $/kW-yr $25.19 $25.19 $20.68 $34.74 $31.19Variable O&M, $/MWh $5.95 $5.66 $4.60 $8.55 $6.97Total O&M Cost, $/Year (85% CF) $38,426,700 $37,245,400 $30,209,800 $40,661,400 $32,563,000

Availability Factor 85% 85% 90% Not Evaluated Not Evaluated

Economic AnalysisCapacity Factor 85% 85% 85% N/A N/A20-year levelized busbar cost, $/MWh (2006 Real $) $45.03 $40.89 $39.28 $65.41 $62.00Avoided CO2 Cost, $/Mt CO2 avoided N/A N/A N/A $26.28 $29.64

Notes:1) CO2 Capture capital costs are based on retrofit of the existing IGCC or PC facilities as provided in the base case alternatives. $/kW values reflect total installed cost to date (including original costs provided in the base case) divided by net plant output with CO2 capture.

Summary

15-3

Table 15-2 Summary Table (2 of 2)

Base Cases CO2 Capture CasesIGCC SCPC IGCC SCPC

Case 100% PRB 50% PRB / 50% Petcoke 100% PRB 100% PRB IGCC 100% PRBNOx Emissions

lb/MMBtu (HHV) 0.063 0.062 0.050 0.061 0.045ppmvd @ 15% O2 15 15 N/A 15 N/Alb/MWh (net) 0.581 0.562 0.458 0.781 0.581

SO2 Emissionslb/MMBtu (HHV) 0.019 0.023 0.060 0.004 0.0003lb/MWh (net) 0.173 0.210 0.549 0.051 0.003

PM10 Emissions (front half)lb/MMBtu (HHV) 0.007 0.007 0.015 0.007 0.015lb/MWh (net) 0.065 0.065 0.137 0.090 0.194

COlb/MMBtu (HHV) 0.037 0.036 0.150 0.035 (Note 1) 0.150ppmvd 25 25 N/A 25 (Note 1) N/Alb/MWh (net) 0.337 0.337 1.373 0.448 (Note 1) 1.937

CO2

lb/MMBtu (HHV) 215 213 215 22 22lb/MWh (net) 1,985 1,934 1,967 276 278

Hg% Removal 90% 90% 70% 90% 70%lb/TBtu (HHV) 0.778 0.496 2.315 0.778 2.315lb/MWh (net) 7.17E-06 4.50E-06 2.12E-05 9.96E-06 2.99E-05

Plant Cooling Requirements, MMBtu/hr (@ 73°F) 2,141 2,179 2,490 2,101 3,330Steam Cycle Cooling Requirement, MMBtu/hr 1,480 1,480 2,300 1,120 1,354BOP Auxiliary Cooling Requirement, MMBtu/hr 661 699 190 981 1,976

Total Plant Makeup Water RequirementGPM (@ 73°F) 4,980 5,231 5,800 6,147 7,757Acre-ft/year (@ 85% CF) 6,830 7,170 7,950 8,430 10,640

Notes:1) GE is currently in the process of developing tools to accurately predict CO emissions for high hydrogen fuels. It is estimated that CO emissions will be less than shown for IGCC CO2 capture technology, however to what extent is unknown at this time.

Summary

15-4

Of the three alternatives evaluated, SCPC technology provides the lowest busbar cost based on this analysis. SCPC technology provides a $5.75/MWh (approximately 13%) lower busbar cost than a comparable IGCC unit when operating on 100% PRB fuel. The 100% PRB SCPC also provides a $1.61/MWh (approximately 4%) lower busbar cost than the IGCC operating on 50% PRB / 50% petcoke. Of the two IGCC alternatives, the fuel blend case provides the lowest busbar cost, provided that a long-term petcoke supply that meets plant specifications can be found for the project at a reasonable cost.

The SCPC Unit provides a lower capital cost, lower O&M, better performance, and higher availability factor than the IGCC. Although the heat rate for the 50% PRB / 50% petcoke IGCC option is better than the 100% PRB SCPC option (except at 93°F ambient), this difference could likely be overcome by specifying a fuel blend for the SCPC option.

IGCC has an advantage in terms of SO2, PM10, and mercury emissions, however using the emissions allowance costs provided in Chapter 8, these lower emissions are not enough to overcome the disadvantages discussed above.

In an effort to reduce greenhouse gases, some form of CO2 legislation may be passed in the future. At this point in time, it is uncertain what form this legislation will take, but it is logical to assume that CO2 regulations would provide an incentive for CO2 reduction from power plants.

The installation of CO2 capture equipment as a retrofit for both of these technologies results in a very significant decrease in net plant output, a significant increase in net plant heat rate, and a significant increase in water consumption. All of these factors result in an increase of the 20-year levelized busbar cost by approximately 45% for the IGCC and 58% for the SCPC post CO2 capture.

SCPC technology still provides the lowest busbar cost after CO2 capture retrofit, although by less of a gap than pre-CO2 capture. The avoided cost of CO2 capture is less for an IGCC implying that IGCC technology is the more economical choice for retrofit of CO2 capture technology, however the lower initial capital cost (pre-capture) of SCPC technology still results in an overall lower busbar cost for SCPC technology.

It is recommended that additional studies be performed if IGCC, SCPC, or CO2 capture technology is of interest to the Owner:

• SCR for IGCC technology.

• Two-pressure vs. three-pressure HRSG for IGCC technology.

• Other multi-pollutant flue gas clean-up systems such as J-Power’s ReACT system and Powerspan’s ECO system for SCPC technology.

• More efficient steam cycle for SCPC technology.

Summary

15-5

• Inlet air cooling methods (chilling vs. evaporative cooling) in conjunction with evaluation of air-side integration for IGCC technology.

• IGCC and SCPC CO2 capture pre-investment options.

• Other SCPC CO2 capture technologies such as MHI’s KS-1 process.

• Evaluation of gasifiers from other manufacturers that that may be better suited for CO2 capture.

• Heat recovery from CO2 compression.

• Raw water availability study, which may result in different water treatment requirements.

• More detailed studies incorporating gasifier and gas turbine vendor involvement.

Changes in market conditions, improvements in IGCC technology, different fuel specifications, or CO2 purity specifications could be enough to swing the economics in favor of IGCC. Therefore it is recommended that utilities consider IGCC technology for future generation needs.

A-1

A PROCESS FLOW DIAGRAMS

NO. DATE BY REVISION

date

07-JUN-06

detailed

CPS / EPRI IGCC FEASIBILITYSTUDY

PROCESS FLOW DIAGRAMGAS COOLING AND TREATMENT

project42127

contract

designed

T_McCALL

checked

drawing rev

GCT-PFD-1 E

SYNGAS FROMGASIFIER

NOTES:1.2.

SYNGASCOOLER

40-1&2-SGT-TNK-001SYNGAS WASH

TOWERS 40-1&2-SGT-HTX-002HYDROLYSIS

INTERCHANGERS

40-1&2-SGT-TNK-004COS/HCN HYDROLYSIS

REACTORS

40-1&2-SGT-HTX-003HYDROLYSISPREHEATERS

40-1&2-SGT-HTX-004SYNGAS

INTERCHANGERS

40-1&2-SGT-HTX-005FIRST STAGE

SYNGAS CONDENSORS

40-1&2-SGT-HTX-006SECOND STAGE

SYNGAS CONDENSORS

40-1&2-SGT-TNK-005WATER KNOCKOUT

DRUMS

40-1&2-SGT-PMP-001A/BSOUR WATER PUMPS

SELEXOLAGR

SYNGAS TOCOAL/COKE DRYING

CONDENSATE

CONDENSATE

CIRC. WATER

CIRC. WATER

DEMINERALIZEDWATER

504 SOUR WATERSTRIPPER PURGE

SATURATOR PURGE

TO RECOVERED WATERFLASH DRUM

302

306

401

HP BFWHP BFW

303

A 6/7/06 JAJ INTERNAL REVIEW

B 6/16/06 JAJ INTERNAL REVIEW

SRU / TGTU

GCT-PFD-2

SYNGAS SATURATORMAKEUP

102100

611

GCT-PFD-2 104

400

402

GCT-PFD-2403

SYNGAS TOSATURATOR

SULFUR

GCT-PFD-2

SW TO SOURWATER STRIPPER

OXYGENTO SRU

GCT-PFD-2SOUR WATERTO EFFLUENT

HEAT EXCHANGER

204

GCT-PFD-2

GCT-PFD-2

103

605

101

313IP STEAM

CONDENSATE

GCT-PFD-2

FROM SOURWATER STRIPPER

502

HP STEAM

HP BFW

LP STEAM

CONDENSATE

IP BFW

IP STEAM

309

311

C 7/24/06 JAJ INTERNAL REVIEW

201

205

107105

310

206

D 7/31/06 JAJ INTERNAL REVIEW

40-1&2-SGT-HTX-001MERCURY REMOVAL

PREHEATERS

IP BFW

IP B

FW

40-1&2-SGT-TNK-002MERCURY ABSORBENT

BEDS

40-1&2-SGT-HTX-015MERCURY REMOVAL

AFTERCOOLERS

CIR

C. W

ATE

R

CIRC. WATER

312

301

307

305

308

314

315

316

304

E 8/11/06 JAJ FINAL

NO. DATE BY REVISION

date

07-JUN-06

detailed

JAJ

CPS / EPRI IGCC FEASIBILITYSTUDY

PROCESS FLOW DIAGRAMGAS COOLING AND TREATMENT

project42127

contract

designed

T_McCALL

checked

drawing rev

GCT-PFD-2 E

40-1&2-SGT-TNK-006SYNGAS SATURATOR

40-1&2-SGT-PMP-002A/BSATURATOR CIRCULATION

PUMPS

40-1&2-SGT-HTX-008SATURATOR

HEATER

HP BFW

40-1&2-SGT-HTX-007SWEET SYNGAS

HEATER

HP BFW

SYNGAS TOGAS TURBINES

HP BFW

SATURATOR PURGETO SYNGAS WASH

TOWER

HP BFW

607

601

602

608

40-0-SGT-TNK-007SOUR WATER

STRIPPER

40-0-SGT-HTX-009SOUR WATER

FEED / EFFLUENTEXCHANGER

40-0-SGT-PMP-004A/BSOUR WATER STRIPPER

BOTTOM PUMPS

TO SYNGASWASH TOWER

GCT-PFD-1

TO SULFURRECOVERY UNIT

40-0-SGT-PMP-003A/BSOUR WATER PUMP

AROUND PUMPS

40-0-SGT-HTX-010SOUR WATER PUMPAROUND COOLER

40-0-SGT-HTX-011SOUR WATER

REBOILER

LP STEAM

CONDENSATE

A 6/7/06 JAJ INTERNAL REVIEW

B 6/16/06 JAJ INTERNAL REVIEW

GCT-PFD-1

DEMINERALIZEDWATER

GCT-PFD-1

GCT-PFD-1

SYNGAS FROMINTERCHANGERS

40-0-SGT-JET-1FLASHED WATERSTEAM EJECTOR

40-0-SGT-TNK-009FLASH WATER

CONDENSATE DRUM

40-0-SGT-PMP-006A/BFLASHED WATER

CONDENSATE PUMP

503

IP STEAM

40-0-SGT-TNK-008RECOVERED WATER

FLASH DRUM

40-0-SGT-PMP-005A/BRECOVERED WASH

WATER PUMPS

GCT-PFD-140-0-SGT-HTX-012

RECOVERED WASHWATER EXCHANGER

40-0-SGT-FLT-001RECOVERED WASH

WATER FILTER

TO COOLING TOWER

610

502

506

505

GCT-PFD-1

FROM SYNGASWASH TOWERS

FROM SOURWATER PUMPS

104

709

702 703

704 712

611

308

GCT-PFD-1 504

707

706

605

606604603

GCT-PFD-1

SW FROMTGTU

SOLIDS TOLANDFILL

711

501

710

708311

403

40-0-SGT-HTX-013FLASHED WATER

CONDENSER

701

705

C 7/24/06 JAJ INTERNAL REVIEW

D 7/31/06 JAJ INTERNAL REVIEW

E 8/11/06 JAJ FINAL

40-1&2-SGT-TNK-1011ST STAGE SOUR GAS

SHIFT REACTORS

NO. DATE BY REVISION

date

07-JUN-06

detailed

CPS / EPRI IGCC FEASIBILITYSTUDY

PROCESS FLOW DIAGRAMGAS COOLING AND TREATMENT - CO2 CAPTURE

project42127

contract

designed

T_McCALL

checked

drawing rev

SYNGAS FROMGASIFIER SYNGAS

COOLER

40-1&2-SGT-TNK-001SYNGAS WASH

TOWERS

40-1&2-SGT-HTX-1021ST STAGE SOUR GAS

SHIFT OUTLETINTERCHANGERS

COND

ENSA

TE

CONDENSATE

CIRC

. WAT

ER

CIRC. WATER

DEMINERALIZEDWATER

A 6/7/06 JAJ INTERNAL REVIEW

104

HP NITROGEN

101

40-1&2-SGT-HTX-1032ND STAGE SOUR GAS

SHIFT OUTLETINTERCHANGERS

105

40-1&2-SGT-HTX-1011ST STAGE SOUR GAS

SHIFT INLETINTERCHANGERS

40-1&2-SGT-TNK-103WATER FLASH

DRUMS

40-1&2-SGT-TNK-1022ND STAGE SOUR GAS

SHIFT REACTORS

40-1&2-SGT-HTX-114RECYCLE STEAM

GENERATORS

HP BFW

HP BFW

IP STEAM

40-1&2-SGT-HTX-104SATURATOR HEATERS

40-1&2-SGT-HTX-1051ST SOUR GAS CONDENSERS

40-1&2-SGT-HTX-1073RD SOUR GASCONDENSERS

40-1&2-SGT-HTX-1095TH SOUR GASCONDENSERS

40-1&2-SGT-HTX-1106TH SOUR GASCONDENSERS

40-1&2-SGT-HTX-1117TH SOUR GAS CONDENSERS

40-1&2-SGT-PMP-101A/BKNOCKOUT WATER PUMPS

40-0-SGT-HTX-012WASTEWATER

INTERCHANGER

40-1&2-SGT-TNK-002MERCURY ADSORBENT

BEDS

40-1&2-SGT-HTX-015MERCURY REMOVAL

AFERCOOLERS

SELEXOL AGR SRU / TGTU

40-0-SGT-CMP-101A/B/C/DCO2 COMPRESSOR W / INTERCOOLERS

CO2 TO PIPELINE

SYNGAS TO COAL/COKE DRYING

301

302

306

307

312

OXYGEN

CIRC. WATER

CIRC. WATER

313

B 8/11/06 JAJ

206

205

319

40-1&2-SGT-HTX-1201ST STAGE SOUR GASSHIFT PREHEATERS

204

HP BFW203

HP BFW

317

- DENOTES ORIGINAL EQUIPMENT REUSED FOR CO2 CAPTURE.

C 8/28/06 JAJ INTERNAL REVIEW

INTERNAL REVIEW

322

320

GCT-PFD-4

SW TO SOUR WATER STRIPPER

416OXYGENTO SRU

407406

414

SULFUR417

413

615

304

303

613

614

HP NITROGEN TOSATURATOR.

SATURATOR PURGE

GCT-PFD-4 605

SOUR WATERSTRIPPER PURGE

GCT-PFD-4 504

100

103

102

TO RECOVERED WATERFLASH DRUM

GCT-PFD-4

40-1&2-SGT-TNK-005WATER KNOCKOUT

DRUMS

308

311

316

GCT-PFD-3

TAIL GAS TOSHIFT REACTORS

GCT-PFD-3

208

106

405

201

40-1&2-SGT-HTX-1062ND SOUR GASCONDENSERS

305

209

202

405

321

207

RECIRC WATERFROM SATURATOR

GCT-PFD-4

SYNGAS TOSATURATOR

GCT-PFD-4

GCT-PFD-4

RECIRC WATERTO SATURATOR

GCT-PFD-4608

616

403

318

606

323

404314

401

402

400

GCT-PFD-4

SW TO SOUR WATER STRIPPER

TAIL GASFROM TGTU

D 9/14/06 TMA FINAL

DEMIN. WATERTO HTX-012

GCT-PFD-4

DEMIN. WATERFROM HTX-012

GCT-PFD-4

40-1&2-SGT-HTX-1084TH SOUR GASCONDENSERS

609610

611

607

315

309

NO. DATE BY REVISION

date

07-JUN-06

detailed

JAJ

CPS / EPRI IGCC FEASIBILITYSTUDY

PROCESS FLOW DIAGRAMGAS COOLING AND TREATMENT

project42127

contract

designed

T_McCALL

checked

drawing rev

SAT. PURGE TOWASH TOWER

40-0-SGT-TNK-007SOUR WATER

STRIPPER

40-0-SGT-HTX-009SOUR WATER

FEED / EFFLUENTEXCHANGER

40-0-SGT-PMP-004A/BSOUR WATER STRIPPER

BOTTOM PUMPS

TO SYNGASWASH TOWER

GCT-PFD-3

TO SULFURRECOVERY UNIT

40-0-SGT-PMP-003A/BSOUR WATER PUMP

AROUND PUMPS

40-0-SGT-HTX-010SOUR WATER PUMP AROUND COOLER

40-0-SGT-HTX-011SOUR WATER

REBOILER

LP STEAM

CONDENSATE

A 9/14/06 TMA FINAL

GCT-PFD-3

DEMIN. WATER

GCT-PFD-3

GCT-PFD-3

SYNGAS FROMINTERCHANGERS

40-0-SGT-JET-1FLASHED WATERSTEAM EJECTOR

40-0-SGT-TNK-009FLASH WATER

CONDENSATE DRUM

40-0-SGT-PMP-006A/BFLASHED WATER

CONDENSATE PUMP

503

IP STEAM

40-0-SGT-TNK-008RECOVERED WATER

FLASH DRUM

40-1&2-SGT-PMP-005A/BRECOVERED WASH

WATER PUMPS

GCT-PFD-340-0-SGT-HTX-012

RECOVERED WASHWATER EXCHANGER TO COOLING TOWER

502

506

505

FROM SYNGASWASH TOWERS

702 703

GCT-PFD-3 504

707

706

GCT-PFD-3

SW FROMTGTU

SOLIDS TOCOAL PILE

501

710

708416

40-0-SGT-HTX-013FLASHED WATER

CONDENSER

70140-1&2-SGT-TNK-006

SYNGAS SATURATORS

40-1&2-SGT-PMP-002A/BSATURATOR CIRCULATION

PUMPS

40-1&2-SGT-HTX-006SWEET SYNGAS

HEATERS

HP BFW

SYNGAS TO GAS TURBINES

HP BFW

602

SOUR WATERFROM TNK-005

709

616

40-1&2-SGT-FLT-101A/BWASH WATER FILTERS

RECIRC WATER TO HTX-104GCT-PFD-3

GCT-PFD-3

GCT-PFD-3 310

712704

711

GCT-PFD-3

DEMIN. WATERTO HTX-108

705

HP NITROGENFROM HTX-106

GCT-PFD-3

RECIRC WATERFROM HTX-104

611

608

603606

605

604

601403

104

610

SYNGAS TREATING AREA43F PRB

Table 1Component Balance

9/14/2006Project No: 42127

Stream Number 100 101 102 103 104 105 107 201 204Stream Description Total Makeup

Demineralized Water

Raw Syngas Demin Water to Wash Tower

Water to Wash Tower

Wash Tower Bottoms Stream

Wash Tower Overhead Vapor

Hydrolysis Reactor Feed

(prior to preheat)

Hydrolysis Reactor Feed (after preheat)

Hydrolysis Reactor Feed

Overall PropertiesPressure, psia 60 540 500 480 520 519 519 518 517Temperature, °F 100 450 100 135 280 260 260 350 425Mass Flow, lb/hr 254,865 901,724 117,000 203,773 172,170 933,327 943,246 943,246 943,246Mole Flow, lbmole/hr 14,147 42,556 6,495 11,311 9,555 44,313 44,588 44,588 44,588

Component lb-moles/hrCH4 0.0 8.3 0.0 0.0 0.0 8.3 8.3 8.3 8.3CO 0.0 25,497.0 0.0 0.0 2.1 25,495.0 25,506.6 25,506.6 25,506.6CO2 0.0 1,133.3 0.0 0.0 1.2 1,132.2 1,341.0 1,341.0 1,341.0COS 0.0 5.5 0.0 0.0 0.0 5.5 5.5 5.5 5.5H2 0.0 11,397.9 0.0 0.0 1.1 11,396.8 11,440.3 11,440.3 11,440.3H2O 14,147.3 1,758.4 6,494.6 11,310.9 9,549.5 3,519.9 3,522.5 3,522.5 3,522.5H2S 0.0 71.5 0.0 0.0 0.3 71.2 74.6 74.6 74.6HCN 0.0 2.0 0.0 0.0 0.1 1.9 1.9 1.9 1.9NH3 0.0 1.9 0.0 0.1 0.4 1.6 1.6 1.6 1.6N2 0.0 2,268.0 0.0 0.0 0.2 2,267.8 2,273.3 2,273.3 2,273.3O2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0NO2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0SO2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0AR 0.0 412.5 0.0 0.0 0.0 412.5 412.5 412.5 412.5Sulfur 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Vapor Phase PropertiesMole Flow, lbmole/hr --- 42,556 --- --- --- 44,313 44,588 44,588 44,588Mass Flow, lb/hr --- 901,724 --- --- --- 933,327 943,246 943,246 943,246Actual Volumetric Flow, ACFM --- 12,945 --- --- --- 10,955 11,026 12,499 13,721Density, lb/ft3 --- 1.16 --- --- --- 1.42 1.43 1.26 1.15Viscosity, cP --- 0.023 --- --- --- 0.020 0.020 0.021 0.023Heat Capacity, Btu/lb-F --- 0.347 --- --- --- 0.352 0.351 0.350 0.351Thermal Conductivity, Btu/hr-ft-F --- 0.039 --- --- --- 0.033 0.032 0.035 0.038Molecular Weight --- 21.19 --- --- --- 21.06 21.15 21.15 21.15

Liquid Phase PropertiesMole Flow, lbmole/hr 14,147 --- 6,495 11,311 9,555 --- --- --- ---Mass Flow, lb/hr 254,865 --- 117,000 203,773 172,170 --- --- --- ---Actual Volumetric Flow, USGPM 510 --- 234 414 375 --- --- --- ---Density, lb/ft3 62.30 --- 62.35 61.42 57.22 --- --- --- ---Viscosity, cP 0.684 --- 0.680 0.485 0.199 --- --- --- ---Heat Capacity, Btu/lb-F 1.031 --- 1.030 1.032 1.076 --- --- --- ---Thermal Conductivity, Btu/hr-ft-F 0.363 --- 0.363 0.376 0.397 --- --- --- ---Molecular Weight 18.0 --- 18.0 18.0 18.0 --- --- --- ---

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 1 of 7

SYNGAS TREATING AREA43F PRB

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

205 206 301 302 303 304 305 306 307Hyfdrolysis

Reactor EffluentHydrolysis

Reactor Effluent (after heat exchange)

Sour Syngas to Interchanger

Sour Syngas from Interchanger

Syngas from First Stage

Condensation

Syngas from Second Stage Condensation

Syngas to Mercury Removal

Preheat

Sour Water from Sour Syngas Condensation

Sour Water Recycle to

Syngas Condensation

507 506 506 505 502 501 501 501 521425 335 273 248 110 100 100 100 100

943,246 943,246 963,246 963,246 963,246 963,246 881,735 81,511 20,00044,588 44,588 45,698 45,698 45,698 45,698 41,176 4,522 1,110

8.3 8.3 8.3 8.3 8.3 8.3 8.3 0.0 0.025,506.6 25,506.6 25,506.6 25,506.6 25,506.6 25,506.6 25,506.4 0.2 0.0

1,348.0 1,348.0 1,348.4 1,348.4 1,348.4 1,348.4 1,346.8 1.6 0.40.3 0.3 0.3 0.3 0.3 0.3 0.3 0.0 0.0

11,442.1 11,442.1 11,442.1 11,442.1 11,442.1 11,442.1 11,442.1 0.1 0.03,513.6 3,513.6 4,621.9 4,621.9 4,621.9 4,621.9 104.9 4,517.0 1,108.3

79.9 79.9 79.9 79.9 79.9 79.9 79.6 0.3 0.10.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.03.4 3.4 4.1 4.1 4.1 4.1 1.4 2.6 0.6

2,273.3 2,273.3 2,273.4 2,273.4 2,273.4 2,273.4 2,273.3 0.1 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

412.5 412.5 412.5 412.5 412.5 412.5 412.5 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

44,588 44,588 45,634 44,031 41,210 41,176 41,176 0 ---943,246 943,246 962,092 933,209 882,362 881,735 881,735 0 ---13,995 12,551 11,754 11,017 8,353 8,209 8,209 0 ---

1.12 1.25 1.36 1.41 1.76 1.79 1.79 1.79 ---0.023 0.021 0.020 0.019 0.017 0.017 0.017 0.017 ---0.351 0.350 0.354 0.349 0.340 0.340 0.340 0.340 ---0.038 0.035 0.033 0.032 0.028 0.028 0.028 0.028 ---21.15 21.15 21.08 21.19 21.41 21.41 21.41 21.41 ---

--- --- 64 1,667 4,487 4,522 --- 4,522 1,110--- --- 1,153 30,036 80,884 81,511 --- 81,511 20,000--- --- 3 64 162 163 --- 163 40--- --- 57.44 58.19 62.07 62.33 --- 62.33 62.33--- --- 0.205 0.230 0.652 0.718 --- 0.718 0.718--- --- 1.072 1.061 1.030 1.029 --- 1.029 1.029--- --- 0.397 0.397 0.367 0.363 --- 0.363 0.363--- --- 18.0 18.0 18.0 18.0 --- 18.0 18.0

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 2 of 7

SYNGAS TREATING AREA43F PRB

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

308 309 310 311 312 313 314 315 316Sour Water to Elluent Heat Exchange

Sour Gas to Sulrur Recovery

Unit (SRU)

Recycle Gas from SRU

Sour Water from Tail Gas Treating (TGTU) to Sour Water Stripper

Sulfur Product Oxygen to SRU Syngas to Mercury Removal

Syngas from Mercury Removal

Syngas to AGR

519 40 556 66 100 100 500 498 497100 100 303 104 100 100 105 105 100

61,511 10,316 9,919 1,155 2,293 1,568 881,735 881,735 881,7353,412 315 275 64 72 49 41,176 41,176 41,176

0.0 0.0 0.0 0.0 0.0 0.0 8.3 8.3 8.30.1 127.5 11.6 0.0 0.0 0.0 25,506.4 25,506.4 25,506.41.2 80.8 208.8 0.0 0.0 0.0 1,346.8 1,346.8 1,346.80.0 0.1 0.0 0.0 0.0 0.0 0.3 0.3 0.30.1 12.1 43.5 0.0 0.0 0.0 11,442.1 11,442.1 11,442.1

3,408.7 0.0 2.6 64.1 0.0 0.0 104.9 104.9 104.90.2 78.6 3.4 0.0 0.0 0.0 79.6 79.6 79.60.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.02.0 0.0 0.0 0.0 0.0 0.0 1.4 1.4 1.40.1 14.3 5.5 0.0 0.0 13.2 2,273.3 2,273.3 2,273.30.0 0.0 0.0 0.0 0.0 46.8 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 1.9 0.0 0.0 0.0 0.0 412.5 412.5 412.50.0 0.0 0.0 0.0 71.5 0.0 0.0 0.0 0.0

0 315 275 0 --- 49 41,176 41,176 41,1760 10,316 9,919 0 --- 1,568 881,735 881,735 881,7350 784 65 0 --- 49 8,303 8,336 8,275

1.79 0.22 2.54 0.06 --- 0.53 1.77 1.76 1.780.017 0.016 0.023 0.009 --- 0.022 0.017 0.017 0.0170.340 0.242 0.278 1.354 --- 0.223 0.340 0.340 0.3400.028 0.014 0.024 0.086 --- 0.016 0.028 0.028 0.02821.41 32.70 36.02 5.17 --- 31.80 21.41 21.41 21.41

3,412 --- --- 64 --- --- --- ---61,511 --- --- 1,155 --- --- --- ---

123 --- --- 2 --- --- --- ---62.33 --- --- 62.18 --- --- --- ---0.718 --- --- 0.651 --- --- --- ---1.029 --- --- 1.031 --- --- --- ---0.363 --- --- 0.365 --- --- --- ---18.0 --- --- 18.0 32.1 --- --- --- ---

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 3 of 7

SYNGAS TREATING AREA43F PRB

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

400 401 402 403 501 502 503 504 505Sweet Syngas from Selexol

Sweet Syngas to Syngas

Interchanger

Sweet Syngas to Coal Drying

Sweet Syngas to Saturator

Primary Sour Water Stripper

Feed

Sopur Water Stripper

Overhead Vapor to SRU

Recovered Water from Sour Water Stripper to heat

exchange

Recovered Water from Sour Water Stripper to Wash

Tower

Pump Around from SWS to Air

Cooler

490 490 490 489 500 30 481 480 480100 100 100 227 200 184 253 178 203

871,419 813,369 58,050 813,369 61,511 292 81,367 81,367 81,36740,860 38,138 2,722 38,138 3,412 12 4,517 4,517 4,517

8.3 7.7 0.6 7.7 0.0 0.0 0.0 0.0 0.025,378.9 23,688.3 1,690.6 23,688.3 0.1 2.2 0.0 0.0 0.0

1,266.0 1,181.7 84.3 1,181.7 1.2 2.4 0.0 0.0 0.00.2 0.1 0.0 0.1 0.0 0.0 0.0 0.0 0.0

11,430.0 10,668.5 761.4 10,668.5 0.1 1.2 0.0 0.0 0.0104.9 97.9 7.0 97.9 3,408.7 3.2 4,516.5 4,516.5 4,516.5

1.0 0.9 0.1 0.9 0.2 0.5 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.1 0.0 0.0 0.01.4 1.3 0.1 1.3 2.0 2.2 0.1 0.1 0.1

2,259.0 2,108.5 150.5 2,108.5 0.1 0.2 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

410.6 383.3 27.4 383.3 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

40,860 38,138 2,722 38,138 --- 12 --- --- ---871,419 813,369 58,050 813,369 --- 292 --- --- ---

8,331 7,776 555 9,639 --- 46 --- --- ---1.74 1.74 1.74 1.41 --- 0.11 --- --- ---

0.017 0.017 0.017 0.020 --- 0.013 --- --- ---0.341 0.341 0.341 0.338 --- 0.341 --- --- ---0.028 0.028 0.028 0.033 --- 0.019 --- --- ---21.33 21.33 21.33 21.33 --- 24.29 --- --- ---

--- --- --- --- 3,412 --- 4,517 4,517 4,517--- --- --- --- 61,511 --- 81,367 81,367 81,367--- --- --- --- 129 --- 175 168 168--- --- --- --- 59.59 --- 58.05 60.22 60.22--- --- --- --- 0.301 --- 0.224 0.345 0.345--- --- --- --- 1.044 --- 1.064 1.040 1.040--- --- --- --- 0.392 --- 0.397 0.388 0.388--- --- --- --- 18.0 --- 18.0 18.0 18.0

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 4 of 7

SYNGAS TREATING AREA43F PRB

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

506 601 602 603 604 605 606 607 608Pump Around

from Air Cooler to SWS

Saturator Overhead Vapor

Syngas to Gas Turbines

Saturator Bottoms Liquid

Saturator Bottoms Pump

Discharge

Saturator Liquid Purge to Wash

Tower

Saturetor Bottms Circulation after

Purge

Saturator Circulation Liquid

after Make-up

Saturator Circulation Liquid

after Satiratpr Heater

480 480 479 481 516 516 516 500 490178 303 405 223 223 223 223 217 335

81,367 947,014 947,014 1,125,907 1,125,907 5,406 1,120,501 1,258,366 1,258,3664,517 45,557 45,557 62,483 62,483 300 62,183 69,836 69,836

0.0 7.7 7.7 0.0 0.0 0.0 0.0 0.0 0.00.0 23,688.2 23,688.2 8.2 8.2 0.0 8.1 8.1 8.10.0 1,181.6 1,181.6 9.4 9.4 0.0 9.3 9.3 9.30.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.00.0 10,668.5 10,668.5 4.1 4.1 0.0 4.1 4.1 4.1

4,516.5 7,517.7 7,517.7 62,459.2 62,459.2 299.9 62,159.3 69,812.0 69,812.00.0 0.9 0.9 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.1 0.0 0.0 1.3 1.3 0.0 1.3 1.3 1.30.0 2,108.5 2,108.5 0.9 0.9 0.0 0.9 0.9 0.90.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 383.3 383.3 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

--- 45,557 45,557 --- --- --- --- --- ------ 947,014 947,014 --- --- --- --- --- ------ 12,805 14,659 --- --- --- --- --- ------ 1.23 1.08 --- --- --- --- --- ------ 0.020 0.021 --- --- --- --- --- ------ 0.365 0.365 --- --- --- --- --- ------ 0.033 0.036 --- --- --- --- --- ------ 20.79 20.79 --- --- --- --- --- ---

4,517 --- --- 62,483 62,483 300 62,183 69,836 69,83681,367 --- --- 1,125,907 1,125,907 5,406 1,120,501 1,258,366 1,258,366

168 --- --- 2,382 2,382 11 2,371 2,654 2,83060.22 --- --- 58.93 58.93 58.93 58.93 59.11 55.430.345 --- --- 0.262 0.262 0.262 0.262 0.271 0.1601.040 --- --- 1.052 1.052 1.052 1.052 1.050 1.1110.388 --- --- 0.395 0.395 0.395 0.395 0.394 0.39418.0 --- --- 18.0 18.0 18.0 18.0 18.0 18.0

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 5 of 7

SYNGAS TREATING AREA43F PRB

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

610 611 701 702 703 704 705 706 707Demin Water Make-up to

Saturator (after heat exchange)

Demin Water Make-up to

Saturator (before heat exchange)

Flashed Vapor from Wash

Tower Bottoms Flash

Flashed Liquid from Wash

Tower Bottoms Flash

Recovered Wash Water from Flash

Cooled Recovered Water

from Flash

Recovered Wash Water from Flash after Air Cooler

Vapors to Jet Ejector

Steam to Jet Ejector

500 500 7 7 62 62 7 7 615165 100 177 177 177 118 150 150 491

137,865 137,865 19,082 153,088 153,088 153,088 19,082 227 5007,653 7,653 1,057 8,498 8,498 8,498 1,057 10 28

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 2.1 0.0 0.0 0.0 2.1 2.1 0.00.0 0.0 1.2 0.0 0.0 0.0 1.2 1.1 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 1.1 0.0 0.0 0.0 1.1 1.1 0.0

7,652.7 7,652.7 1,051.8 8,497.6 8,497.6 8,497.6 1,051.8 5.6 27.80.0 0.0 0.3 0.0 0.0 0.0 0.3 0.2 0.00.0 0.0 0.1 0.0 0.0 0.0 0.1 0.0 0.00.0 0.0 0.3 0.1 0.1 0.1 0.3 0.0 0.00.0 0.0 0.2 0.0 0.0 0.0 0.2 0.2 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

--- --- 1,057 0 --- --- 10 10 28--- --- 19,082 0 --- --- 227 227 500--- --- 17,105 0 --- --- 165 165 6--- --- 0.02 0.02 --- --- 0.02 0.02 1.29--- --- 0.009 0.009 --- --- 0.011 0.011 0.018--- --- 0.451 0.451 --- --- 0.363 0.363 0.580--- --- 0.013 0.013 --- --- 0.018 0.018 0.029--- --- 18.05 18.05 --- --- 21.75 21.75 18.02

7,653 7,653 --- 8,498 8,498 8,498 1,047 --- ---137,865 137,865 --- 153,088 153,088 153,088 18,855 --- ---

284 276 --- 317 317 309 39 --- ---60.58 62.35 --- 60.19 60.19 61.81 60.92 --- ---0.379 0.680 --- 0.349 0.349 0.565 0.426 --- ---1.037 1.030 --- 1.041 1.041 1.032 1.036 --- ---0.385 0.363 --- 0.387 0.387 0.370 0.381 --- ---18.0 18.0 --- 18.0 18.0 18.0 18.0 --- ---

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 6 of 7

SYNGAS TREATING AREA43F PRB

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

708 709 710 711 712Jet Ejector

Effluent Vapor to SWS

Condensate Recovered from Vacuum Flash

Recovered Condensate to

SWS

Solids from Candle Filers Recovered in Wash Tower

Recovered Wash Water to Disposal

7 7 47 62326 150 150 118727 18,855 18,855 153,08838 1,047 1,047 8,498

0.0 0.0 0.0 0.02.1 0.0 0.0 0.01.1 0.0 0.0 0.00.0 0.0 0.0 0.01.1 0.0 0.0 0.0

33.4 1,046.2 1,046.2 8,497.60.2 0.0 0.0 0.00.0 0.1 0.1 0.00.0 0.3 0.3 0.10.2 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.0

38 0 --- ---727 0 --- ---776 0 --- ---0.02 0.02 --- ---

0.012 0.011 --- ---0.433 0.363 --- ---0.019 0.018 --- ---19.04 21.75 --- ---

--- 1,047 1,047 8,498--- 18,855 18,855 153,088--- 39 39 309--- 60.92 60.93 61.81--- 0.426 0.426 0.565--- 1.036 1.036 1.032--- 0.381 0.381 0.370--- 18.0 18.0 18.0

Approximately 110 lb/day of solids will be

removed by the filters and sent to

the coal pile.

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 7 of 7

SYNGAS TREATING AREA43F PRB + PETCOKE

Table 1Component Balance

9/14/2006Project No: 42127

Stream Number 100 101 102 103 104 105 107 201 204Stream Description Total Makeup

Demineralized Water

Raw Syngas Demin Water to Wash Tower

Water to Wash Tower

Wash Tower Bottoms Stream

Wash Tower Overhead Vapor

Hydrolysis Reactor Feed

(prior to preheat)

Hydrolysis Reactor Feed (after preheat)

Hydrolysis Reactor Feed

Overall PropertiesPressure, psia 60 540 500 480 510 509 509 508 507Temperature, °F 100 450 100 130 266 245 246 350 425Mass Flow, lb/hr 251,395 850,323 117,000 182,132 146,731 885,724 909,315 909,315 909,315Mole Flow, lbmole/hr 13,955 39,203 6,495 10,110 8,142 41,171 41,858 41,858 41,858

Component lb-moles/hrCH4 0.0 7.2 0.0 0.0 0.0 7.2 7.2 7.2 7.2CO 0.0 25,424.2 0.0 0.0 1.7 25,422.6 25,436.1 25,436.1 25,436.1CO2 0.0 430.6 0.0 0.0 0.4 430.2 923.5 923.5 923.5COS 0.0 43.0 0.0 0.0 0.0 43.0 43.0 43.0 43.0H2 0.0 9,891.7 0.0 0.0 0.8 9,890.9 10,030.0 10,030.0 10,030.0H2O 13,954.7 646.0 6,494.6 10,109.7 8,137.2 2,618.5 2,624.8 2,624.8 2,624.8H2S 0.0 476.1 0.0 0.0 1.5 474.6 492.5 492.5 492.5HCN 0.0 4.6 0.0 0.0 0.3 4.3 4.3 4.3 4.3NH3 0.0 1.5 0.0 0.2 0.4 1.3 1.3 1.3 1.3N2 0.0 1,880.1 0.0 0.0 0.1 1,880.0 1,897.8 1,897.8 1,897.8O2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0NO2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0SO2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0AR 0.0 398.0 0.0 0.0 0.0 398.0 398.0 398.0 398.0Sulfur 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Vapor Phase PropertiesMole Flow, lbmole/hr --- 39,203 --- --- --- 41,171 41,858 41,858 41,858Mass Flow, lb/hr --- 850,323 --- --- --- 885,724 909,315 909,315 909,315Actual Volumetric Flow, ACFM --- 11,948 --- --- --- 10,183 10,365 11,982 13,149Density, lb/ft3 --- 1.19 --- --- --- 1.45 1.46 1.26 1.15Viscosity, cP --- 0.024 --- --- --- 0.020 0.020 0.022 0.023Heat Capacity, Btu/lb-F --- 0.335 --- --- --- 0.342 0.340 0.339 0.340Thermal Conductivity, Btu/hr-ft-F --- 0.038 --- --- --- 0.031 0.031 0.034 0.037Molecular Weight --- 21.69 --- --- --- 21.51 21.72 21.72 21.72

Liquid Phase PropertiesMole Flow, lbmole/hr 13,955 --- 6,495 10,110 8,142 --- --- --- ---Mass Flow, lb/hr 251,395 --- 117,000 182,132 146,731 --- --- --- ---Actual Volumetric Flow, USGPM 503 --- 234 369 317 --- --- --- ---Density, lb/ft3 62.30 --- 62.35 61.56 57.64 --- --- --- ---Viscosity, cP 0.684 --- 0.680 0.508 0.211 --- --- --- ---Heat Capacity, Btu/lb-F 1.031 --- 1.030 1.032 1.069 --- --- --- ---Thermal Conductivity, Btu/hr-ft-F 0.363 --- 0.363 0.374 0.397 --- --- --- ---Molecular Weight 18.0 --- 18.0 18.0 18.0 --- --- --- ---

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 1 of 7

SYNGAS TREATING AREA43F PRB + PETCOKE

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

205 206 301 302 303 304 305 306 307Hyfdrolysis

Reactor EffluentHydrolysis

Reactor Effluent (after heat exchange)

Sour Syngas to Interchanger

Sour Syngas from Interchanger

Syngas from First Stage

Condensation

Syngas from Second Stage Condensation

Syngas to Mercury Removal

Preheat

Sour Water from Sour Syngas Condensation

Sour Water Recycle to

Syngas Condensation

505 504 504 503 500 499 499 499 519427 324 261 243 110 100 100 100 100

909,315 909,315 929,315 929,315 929,315 929,315 864,614 64,701 20,00041,858 41,858 42,968 42,968 42,968 42,968 39,379 3,589 1,109

7.2 7.2 7.2 7.2 7.2 7.2 7.2 0.0 0.025,436.1 25,436.1 25,436.1 25,436.1 25,436.1 25,436.1 25,436.0 0.2 0.0

968.5 968.5 968.8 968.8 968.8 968.8 967.9 1.0 0.32.1 2.1 2.1 2.1 2.1 2.1 2.1 0.0 0.0

10,034.3 10,034.3 10,034.3 10,034.3 10,034.3 10,034.3 10,034.2 0.0 0.02,575.6 2,575.6 3,682.7 3,682.7 3,682.7 3,682.7 101.1 3,581.6 1,107.1

533.3 533.3 533.8 533.8 533.8 533.8 532.1 1.7 0.50.1 0.1 0.1 0.1 0.1 0.1 0.1 0.0 0.05.5 5.5 6.7 6.7 6.7 6.7 2.7 4.0 1.2

1,897.8 1,897.8 1,897.8 1,897.8 1,897.8 1,897.8 1,897.7 0.1 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

398.0 398.0 398.0 398.0 398.0 398.0 398.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

41,858 41,858 42,838 41,875 39,413 39,379 39,379 0 ---909,315 909,315 926,984 909,616 865,222 864,614 864,614 0 ---13,238 11,671 10,908 10,442 8,014 7,875 7,875 0 ---

1.14 1.30 1.42 1.45 1.80 1.83 1.83 1.83 ---0.023 0.021 0.020 0.020 0.018 0.017 0.017 0.017 ---0.340 0.339 0.343 0.340 0.332 0.332 0.332 0.332 ---0.037 0.033 0.031 0.031 0.027 0.027 0.027 0.027 ---21.72 21.72 21.64 21.72 21.95 21.96 21.96 21.96 ---

--- --- 129 1,093 3,555 3,589 --- 3,589 1,109--- --- 2,331 19,699 64,093 64,701 --- 64,701 20,000--- --- 5 42 129 129 --- 129 40--- --- 57.80 58.33 62.04 62.30 --- 62.30 62.31--- --- 0.216 0.236 0.650 0.716 --- 0.716 0.716--- --- 1.066 1.059 1.029 1.029 --- 1.029 1.029--- --- 0.397 0.396 0.367 0.363 --- 0.363 0.363--- --- 18.0 18.0 18.0 18.0 --- 18.0 18.0

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 2 of 7

SYNGAS TREATING AREA43F PRB + PETCOKE

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

308 309 310 311 312 313 314 315 316Sour Water to Elluent Heat Exchange

Sour Gas to Sulrur Recovery

Unit (SRU)

Recycle Gas from SRU

Sour Water from Tail Gas Treating (TGTU) to Sour Water Stripper

Sulfur Product Oxygen to SRU Syngas to Mercury Removal

Syngas from Mercury Removal

Syngas to AGR

519 40 556 66 100 100 498 497 496100 100 303 104 100 100 105 105 100

44,701 39,244 23,591 1,155 15,263 7,387 864,568 864,568 864,5682,479 1,072 688 64 476 232 39,376 39,376 39,376

0.0 0.0 0.0 0.0 0.0 0.0 7.2 7.2 7.20.1 127.2 13.5 0.0 0.0 0.0 25,436.0 25,436.0 25,436.00.7 387.1 493.3 0.0 0.0 0.0 967.9 967.9 967.90.0 1.7 0.0 0.0 0.0 0.0 2.1 2.1 2.10.0 10.6 139.1 0.0 0.0 0.0 10,034.2 10,034.2 10,034.2

2,474.5 0.0 6.3 64.1 0.0 0.0 101.1 101.1 101.11.2 531.5 17.9 0.0 0.0 0.0 532.1 532.1 532.10.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.12.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 12.0 17.8 0.0 0.0 13.2 1,897.7 1,897.7 1,897.70.0 0.0 0.0 0.0 0.0 220.7 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 1.8 0.0 0.0 0.0 0.0 398.0 398.0 398.00.0 0.0 0.0 0.0 476.0 0.0 0.0 0.0 0.0

0 1,072 688 0 --- 232 39,376 39,376 39,3760 39,244 23,591 0 --- 7,387 864,568 864,568 864,5680 2,648 163 0 --- 231 7,965 7,981 7,922

1.83 0.25 2.41 0.06 --- 0.53 1.81 1.81 1.820.017 0.014 0.023 0.009 --- 0.022 0.017 0.017 0.0170.332 0.233 0.287 1.354 --- 0.223 0.332 0.332 0.3320.027 0.011 0.027 0.086 --- 0.016 0.027 0.027 0.02721.96 36.61 34.29 5.17 --- 31.80 21.96 21.96 21.96

2,479 --- --- 64 --- --- --- ---44,701 --- --- 1,155 --- --- --- ---

89 --- --- 2 --- --- --- ---62.30 --- --- 62.18 --- --- --- ---0.716 --- --- 0.651 --- --- --- ---1.029 --- --- 1.031 --- --- --- ---0.363 --- --- 0.365 --- --- --- ---18.0 --- --- 18.0 32.1 --- --- --- ---

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 3 of 7

SYNGAS TREATING AREA43F PRB + PETCOKE

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

400 401 402 403 501 502 503 504 505Sweet Syngas from Selexol

Sweet Syngas to Syngas

Interchanger

Sweet Syngas to Coal Drying

Sweet Syngas to Saturator

Primary Sour Water Stripper

Feed

Sopur Water Stripper

Overhead Vapor to SRU

Recovered Water from Sour Water Stripper to heat

exchange

Recovered Water from Sour Water Stripper to Wash

Tower

Pump Around from SWS to Air

Cooler

490 490 490 489 498 30 481 480 480100 100 100 181 200 169 253 179 203

825,324 800,717 24,607 800,717 44,701 296 59,727 59,727 59,72738,304 37,162 1,142 37,162 2,479 12 3,315 3,315 3,315

7.2 7.0 0.2 7.0 0.0 0.0 0.0 0.0 0.025,308.8 24,554.2 754.6 24,554.2 0.1 1.8 0.0 0.0 0.0

580.7 563.4 17.3 563.4 0.7 1.1 0.0 0.0 0.00.4 0.4 0.0 0.4 0.0 0.0 0.0 0.0 0.0

10,023.6 9,724.7 298.9 9,724.7 0.0 0.8 0.0 0.0 0.0101.1 98.1 3.0 98.1 2,474.5 2.3 3,315.2 3,315.2 3,315.2

0.5 0.5 0.0 0.5 1.2 2.7 0.0 0.0 0.00.1 0.1 0.0 0.1 0.0 0.3 0.0 0.0 0.00.0 0.0 0.0 0.0 2.8 2.9 0.1 0.1 0.1

1,885.8 1,829.6 56.2 1,829.6 0.0 0.2 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

396.2 384.4 11.8 384.4 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

38,302 37,160 1,142 37,162 --- 12 --- --- ---825,287 800,681 24,606 800,717 --- 296 --- --- ---

7,816 7,583 233 8,750 --- 45 --- --- ---1.76 1.76 1.76 1.53 --- 0.11 --- --- ---

0.017 0.017 0.017 0.019 --- 0.013 --- --- ---0.336 0.336 0.336 0.333 --- 0.336 --- --- ---0.027 0.027 0.027 0.030 --- 0.017 --- --- ---21.55 21.55 21.55 21.55 --- 24.70 --- --- ---

2 2 0 --- 2,479 --- 3,315 3,315 3,31536 35 1 --- 44,701 --- 59,727 59,727 59,7270 0 0 --- 94 --- 128 124 124

62.35 62.35 62.35 --- 59.56 --- 58.05 60.20 60.200.680 0.680 0.680 --- 0.301 --- 0.224 0.343 0.3431.029 1.029 1.029 --- 1.044 --- 1.064 1.040 1.0400.363 0.363 0.363 --- 0.392 --- 0.397 0.388 0.38818.0 18.0 18.0 --- 18.0 --- 18.0 18.0 18.0

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 4 of 7

SYNGAS TREATING AREA43F PRB + PETCOKE

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

506 601 602 603 604 605 606 607 608Pump Around

from Air Cooler to SWS

Saturator Overhead Vapor

Syngas to Gas Turbines

Saturator Bottoms Liquid

Saturator Bottoms Pump

Discharge

Saturator Liquid Purge to Wash

Tower

Saturetor Bottms Circulation after

Purge

Saturator Circulation Liquid

after Make-up

Saturator Circulation Liquid

after Saturator Heater

480 480 479 481 516 516 516 500 490179 303 405 215 215 215 215 209 335

59,727 930,842 930,842 1,117,687 1,117,687 5,405 1,112,282 1,246,677 1,246,6773,315 44,386 44,386 62,033 62,033 300 61,733 69,193 69,193

0.0 7.0 7.0 0.0 0.0 0.0 0.0 0.0 0.00.0 24,554.2 24,554.2 8.0 8.0 0.0 8.0 8.0 8.00.0 563.4 563.4 4.7 4.7 0.0 4.7 4.7 4.70.0 0.4 0.4 0.0 0.0 0.0 0.0 0.0 0.00.0 9,724.7 9,724.7 3.5 3.5 0.0 3.5 3.5 3.5

3,315.2 7,321.3 7,321.3 62,016.0 62,016.0 299.9 61,716.0 69,176.2 69,176.20.0 0.5 0.5 0.0 0.0 0.0 0.0 0.0 0.00.0 0.1 0.1 0.1 0.1 0.0 0.1 0.1 0.10.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 1,829.6 1,829.6 0.8 0.8 0.0 0.8 0.8 0.80.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 384.4 384.4 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

--- 44,386 44,386 --- --- --- --- --- ------ 930,842 930,842 --- --- --- --- --- ------ 12,479 14,286 --- --- --- --- --- ------ 1.24 1.09 --- --- --- --- --- ------ 0.020 0.022 --- --- --- --- --- ------ 0.360 0.359 --- --- --- --- --- ------ 0.032 0.035 --- --- --- --- --- ------ 20.97 20.97 --- --- --- --- --- ---

3,315 --- --- 62,033 62,033 300 61,733 69,193 69,19359,727 --- --- 1,117,687 1,117,687 5,405 1,112,282 1,246,677 1,246,677

124 --- --- 2,355 2,355 11 2,344 2,619 2,80460.20 --- --- 59.16 59.17 59.17 59.17 59.34 55.430.343 --- --- 0.274 0.274 0.274 0.274 0.284 0.1601.040 --- --- 1.049 1.049 1.049 1.049 1.047 1.1110.388 --- --- 0.394 0.394 0.394 0.394 0.393 0.39418.0 --- --- 18.0 18.0 18.0 18.0 18.0 18.0

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 5 of 7

SYNGAS TREATING AREA43F PRB + PETCOKE

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

610 611 701 702 703 704 705 706 707Demin Water Make-up to

Saturator (after heat exchange)

Demin Water Make-up to

Saturator (before heat exchange)

Flashed Vapor from Wash

Tower Bottoms Flash

Flashed Liquid from Wash

Tower Bottoms Flash

Recovered Wash Water from Flash

Cooled Recovered Water

from Flash

Recovered Wash Water from Flash after Air Cooler

Vapors to Jet Ejector

Steam to Jet Ejector

500 500 7 7 62 62 7 7 615158 100 177 177 177 118 150 150 491

134,395 134,395 14,128 132,603 132,603 132,603 14,128 224 5007,460 7,460 782 7,361 7,361 7,361 782 10 28

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 1.7 0.0 0.0 0.0 1.7 1.7 0.00.0 0.0 0.4 0.0 0.0 0.0 0.4 0.4 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.8 0.0 0.0 0.0 0.8 0.8 0.0

7,460.1 7,460.1 776.7 7,360.5 7,360.5 7,360.5 776.7 5.4 27.80.0 0.0 1.5 0.0 0.0 0.0 1.5 1.5 0.00.0 0.0 0.3 0.0 0.0 0.0 0.3 0.1 0.00.0 0.0 0.2 0.1 0.1 0.1 0.2 0.0 0.00.0 0.0 0.1 0.0 0.0 0.0 0.1 0.1 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

--- --- 782 0 --- --- 10 10 28--- --- 14,128 0 --- --- 224 224 500--- --- 12,649 0 --- --- 158 158 6--- --- 0.02 0.02 --- --- 0.02 0.02 1.29--- --- 0.009 0.009 --- --- 0.011 0.011 0.018--- --- 0.450 0.450 --- --- 0.355 0.355 0.580--- --- 0.013 0.013 --- --- 0.016 0.016 0.029--- --- 18.07 18.07 --- --- 22.29 22.29 18.02

7,460 7,460 --- 7,361 7,361 7,361 772 --- ---134,395 134,395 --- 132,603 132,603 132,603 13,904 --- ---

276 269 --- 275 275 267 28 --- ---60.79 62.35 --- 60.19 60.20 61.81 60.91 --- ---0.400 0.680 --- 0.350 0.349 0.565 0.426 --- ---1.036 1.030 --- 1.041 1.041 1.032 1.036 --- ---0.383 0.363 --- 0.387 0.387 0.370 0.381 --- ---18.0 18.0 --- 18.0 18.0 18.0 18.0 --- ---

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 6 of 7

SYNGAS TREATING AREA43F PRB + PETCOKE

Table 1Component Balance

9/14/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

708 709 710 711 712Jet Ejector

Effluent Vapor to SWS

Condensate Recovered from Vacuum Flash

Recovered Condensate to

SWS

Solids from Candle Filers Recovered in Wash Tower

Recovered Wash Water to Disposal

7 7 47 62327 150 150 118724 13,904 13,904 132,60338 772 772 7,361

0.0 0.0 0.0 0.01.7 0.0 0.0 0.00.4 0.0 0.0 0.00.0 0.0 0.0 0.00.8 0.0 0.0 0.0

33.2 771.3 771.3 7,360.51.5 0.0 0.0 0.00.1 0.1 0.1 0.00.0 0.2 0.2 0.10.1 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.0

38 0 --- ---724 0 --- ---770 0 --- ---0.02 0.02 --- ---

0.012 0.011 --- ---0.431 0.355 --- ---0.018 0.016 --- ---19.15 22.29 --- ---

--- 772 772 7,361--- 13,904 13,904 132,603--- 28 28 267--- 60.91 60.92 61.81--- 0.426 0.426 0.565--- 1.036 1.036 1.032--- 0.381 0.381 0.370--- 18.0 18.0 18.0

Approximately 110 lb/day of solids will be

removed by the filters and sent to

the coal pile.

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 7 of 7

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream Number 100 101 102 103 104 105 106 201 202 203Stream Description Total Makeup

Demineralized Water

Raw Syngas Demin Water to Wash Tower

Water to Wash Tower

Wash Tower Bottoms Stream

Wash Tower Overhead Vapor

Preheated Wash Tower Overhead

Vapor

IP Steam to Sour Gas Shift

Sour Gas Shift Feed to

Interchangers HTX-101

Sour Gas Shift Feed to

Preheater HTX-120

Overall PropertiesPressure, psia 60 540 530 31 531 530 529 599 529 528Temperature, °F 100 450 100 139 281 261 359 488 417 496Mass Flow, lb/hr 246,266 901,381 104,848 204,243 172,687 932,937 932,937 450,378 1,849,109 1,849,109Mole Flow, lbmole/hr 13,670 42,540 5,820 11,337 9,583 44,293 44,293 25,000 94,586 94,586

Component lb-moles/hrCH4 0.0 8.3 0.0 0.0 0.0 8.3 8.3 0.0 8.3 8.3CO 0.0 25,486.7 0.0 0.0 2.1 25,484.5 25,484.5 0.0 25,496.2 25,496.2CO2 0.0 1,133.3 0.0 0.0 1.2 1,132.2 1,132.2 0.0 1,540.8 1,540.8COS 0.0 5.5 0.0 0.0 0.0 5.5 5.5 0.0 5.5 5.5H2 0.0 11,393.3 0.0 0.1 1.2 11,392.2 11,392.2 0.0 11,437.0 11,437.0H2O 13,670.0 1,757.7 5,820.0 11,337.1 9,577.9 3,516.9 3,516.9 25,000.0 53,316.8 53,316.8H2S 0.0 71.5 0.0 0.0 0.3 71.2 71.2 0.0 76.5 76.5HCN 0.0 2.0 0.0 0.0 0.1 1.9 1.9 0.0 1.9 1.9NH3 0.0 1.9 0.0 0.1 0.4 1.6 1.6 0.0 17.7 17.7N2 0.0 2,267.1 0.0 0.0 0.2 2,266.9 2,266.9 0.0 2,272.9 2,272.9O2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0NO2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0SO2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0AR 0.0 412.3 0.0 0.0 0.0 412.3 412.3 0.0 412.3 412.3Sulfur 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Vapor Phase PropertiesMole Flow, lbmole/hr --- 42,540 --- --- --- 44,293 44,293 25,000 94,586 94,586Mass Flow, lb/hr --- 901,381 --- --- --- 932,937 932,937 450,378 1,849,109 1,849,109Actual Volumetric Flow, ACFM --- 12,940 --- --- --- 10,740 12,298 5,999 26,333 29,278Density, lb/ft3 --- 1.16 --- --- --- 1.45 1.26 1.25 1.17 1.05Viscosity, cP --- 0.023 --- --- --- 0.020 0.021 0.018 0.018 0.019Heat Capacity, Btu/lb-F --- 0.347 --- --- --- 0.352 0.351 0.577 0.442 0.438Thermal Conductivity, Btu/hr-ft-F --- 0.039 --- --- --- 0.033 0.036 0.029 0.030 0.032Molecular Weight --- 21.19 --- --- --- 21.06 21.06 18.02 19.55 19.55

Liquid Phase PropertiesMole Flow, lbmole/hr 13,670 --- 5,820 11,337 9,583 --- --- --- --- ---Mass Flow, lb/hr 246,266 --- 104,848 204,243 172,687 --- --- --- --- ---Actual Volumetric Flow, USGPM 493 --- 210 416 376 --- --- --- --- ---Density, lb/ft3 62.30 --- 62.35 61.25 57.19 --- --- --- --- ---Viscosity, cP 0.684 --- 0.680 0.468 0.198 --- --- --- --- ---Heat Capacity, Btu/lb-F 1.031 --- 1.030 1.034 1.076 --- --- --- --- ---Thermal Conductivity, Btu/hr-ft-F 0.363 --- 0.363 0.377 0.397 --- --- --- --- ---Molecular Weight 18.0 --- 18.0 18.0 18.0 --- --- --- --- ---

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 1 of 9

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

204 205 206 207 208 209 301 302 303 3041st Stage Sour Gas Shift Inlet

1st Stage Sour Gas Shift Outlet

2nd Stage Sour Gas Shift Inlet

2nd Stage Sour Gas Shift Outlet to HTX-103

Shifted Syngas to Interchanger

HTX-101

Shifted Syngas to Condensing

Train

Sour Syngas from Saturator

Heater

Sour Syngas from 1st Stage

Condenser

Sour Syngas from 2nd Stage

Condenser

Sour Syngas from 3rd Stage

Condenser

527 517 516 506 505 504 503 502 501 500572 962 550 629 591 514 368 342 335 334

1,849,109 1,849,110 1,849,110 1,849,110 1,849,110 1,849,110 1,849,110 1,849,110 1,849,110 1,849,11094,586 94,589 94,589 94,589 94,589 94,589 94,589 94,589 94,589 94,589

8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.325,496.2 5,403.7 5,403.7 1,383.2 1,383.2 1,383.2 1,383.2 1,383.2 1,383.2 1,383.21,540.8 21,639.7 21,639.7 25,660.8 25,660.8 25,660.8 25,660.8 25,660.8 25,660.8 25,660.8

5.5 0.9 0.9 0.3 0.3 0.3 0.3 0.3 0.3 0.311,437.0 31,534.3 31,534.3 35,555.5 35,555.5 35,555.5 35,555.5 35,555.5 35,555.5 35,555.553,316.8 33,216.0 33,216.0 29,194.9 29,194.9 29,194.9 29,194.9 29,194.9 29,194.9 29,194.9

76.5 81.0 81.0 81.7 81.7 81.7 81.7 81.7 81.7 81.71.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

17.7 19.6 19.6 19.6 19.6 19.6 19.6 19.6 19.6 19.62,272.9 2,272.9 2,272.9 2,272.9 2,272.9 2,272.9 2,272.9 2,272.9 2,272.9 2,272.9

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

412.3 412.3 412.3 412.3 412.3 412.3 412.3 412.3 412.3 412.30.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

94,586 94,589 94,589 94,589 94,589 94,589 94,589 89,275 86,611 86,3811,849,109 1,849,110 1,849,110 1,849,110 1,849,110 1,849,110 1,849,110 1,753,210 1,705,117 1,700,966

32,056 46,535 32,572 36,115 34,840 32,154 26,939 24,709 23,863 23,8300.96 0.66 0.95 0.85 0.88 0.96 1.14 1.18 1.19 1.190.021 0.027 0.021 0.023 0.022 0.021 0.018 0.018 0.018 0.0180.438 0.469 0.449 0.455 0.453 0.449 0.446 0.441 0.439 0.4380.034 0.065 0.048 0.055 0.054 0.050 0.044 0.044 0.044 0.04419.55 19.55 19.55 19.55 19.55 19.55 19.55 19.64 19.69 19.69

--- --- --- --- --- --- --- 5,314 7,979 8,209--- --- --- --- --- --- --- 95,900 143,993 148,144--- --- --- --- --- --- --- 217 324 333--- --- --- --- --- --- --- 55.18 55.42 55.44--- --- --- --- --- --- --- 0.090 0.090 0.090--- --- --- --- --- --- --- 1.115 1.110 1.109--- --- --- --- --- --- --- 0.394 0.395 0.395--- --- --- --- --- --- --- 18.0 18.0 18.0

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 2 of 9

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

305 306 307 308 309 310 311 312 313 314Sour Syngas

from 4th Stage Condenser

Sour Syngas from 5th Stage

Condenser

Sour Syngas from 6th Stage

Condenser

Sour Syngas from 7th Stage

Condenser

Water from Syngas Knockout

Drum

Sour Water Stripper Feed

Syngas to Interchanger

HTX-109

Syngas to Mercury Removal

Syngas from Mercury Removal

Syngas To Acid Gas Removal

499 498 497 496 496 496 496 495 493 492330 330 200 100 100 100 114 120 120 100

1,849,110 1,849,110 1,849,110 1,849,110 704,916 74,886 1,319,923 1,319,923 1,319,923 1,319,92394,589 94,589 94,589 94,589 38,885 4,131 65,459 65,459 65,459 65,459

8.3 8.3 8.3 8.3 0.0 0.0 8.3 8.3 8.3 8.31,383.2 1,383.2 1,383.2 1,383.2 0.1 0.0 1,383.2 1,383.2 1,383.2 1,383.2

25,660.8 25,660.8 25,660.8 25,660.8 169.5 18.0 25,491.8 25,491.8 25,491.8 25,491.80.3 0.3 0.3 0.3 0.0 0.0 0.3 0.3 0.3 0.3

35,555.5 35,555.5 35,555.5 35,555.5 1.2 0.1 35,554.3 35,554.3 35,554.3 35,554.329,194.9 29,194.9 29,194.9 29,194.9 38,691.7 4,110.4 255.4 255.4 255.4 255.4

81.7 81.7 81.7 81.7 1.7 0.2 79.9 79.9 79.9 79.90.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

19.6 19.6 19.6 19.6 20.2 2.1 0.7 0.7 0.7 0.72,272.9 2,272.9 2,272.9 2,272.9 0.5 0.1 2,272.5 2,272.5 2,272.5 2,272.5

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

412.3 412.3 412.3 412.3 0.0 0.0 412.3 412.3 412.3 412.30.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

85,128 84,970 67,226 65,418 --- --- 65,459 65,459 65,459 65,3741,678,342 1,675,505 1,354,669 1,320,283 --- --- 1,319,923 1,319,923 1,319,923 1,318,393

23,446 23,436 15,731 12,876 --- --- 13,251 13,420 13,474 12,9751.19 1.19 1.44 1.71 --- --- 1.66 1.64 1.63 1.690.018 0.018 0.017 0.015 --- --- 0.016 0.016 0.016 0.0150.437 0.437 0.411 0.407 --- --- 0.407 0.407 0.407 0.4070.045 0.045 0.045 0.040 --- --- 0.041 0.041 0.041 0.04019.72 19.72 20.15 20.18 --- --- 20.16 20.16 20.16 20.17

9,462 9,619 27,363 29,171 38,885 4,131 --- --- --- 84170,768 173,605 494,440 528,827 704,916 74,886 --- --- --- 1,531

383 389 1,034 1,056 1,408 150 --- --- --- 355.57 55.59 59.62 62.43 62.43 62.43 --- --- --- 62.440.090 0.089 0.300 0.710 0.710 0.710 --- --- --- 0.7111.106 1.106 1.042 1.023 1.023 1.023 --- --- --- 1.0230.395 0.395 0.391 0.360 0.360 0.360 --- --- --- 0.36018.0 18.0 18.1 18.1 18.1 18.1 --- --- --- 18.1

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 3 of 9

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

315 316 317 318 319 320 321 322 323 400Recycle Water Pump Suction

Recycle Water to Interchanger

HTX-012

Recycle Water to 1st Stage

Condenser

Recycle Water to Shift Outlet

Interchanger HTX-102

Recycle Water to Steam Generator

HTX-114

Recycle Water to Flash Drum

Flash Steam to Sour Shift Reactors

Water Flash Drum Purge

Recycle TGTU Tail Gas

Sweet Syngas from AGR

496 536 535 534 533 532 532 532 531 482100 100 198 351 474 474 474 474 151 131

630,030 630,010 630,010 630,010 630,010 630,010 454,280 175,730 175,730 272,79734,754 34,754 34,754 34,754 34,754 34,754 25,000 9,754 9,754 41,973

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 8.20.1 0.1 0.1 0.1 0.1 0.1 0.1 0.0 0.0 1,376.2

151.5 150.6 150.6 150.6 150.6 150.6 150.2 0.4 0.4 1,019.70.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.11.1 1.1 1.1 1.1 1.1 1.1 1.1 0.0 0.0 35,461.8

34,581.3 34,584.8 34,584.8 34,584.8 34,584.8 34,584.8 24,832.6 9,752.2 9,752.2 229.81.6 1.6 1.6 1.6 1.6 1.6 1.5 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

18.1 15.4 15.4 15.4 15.4 15.4 14.1 1.3 1.3 0.00.4 0.4 0.4 0.4 0.4 0.4 0.4 0.0 0.0 3,442.60.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 24.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 410.50.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

--- --- --- 39 19,008 25,000 25,000 0 --- 41,973--- --- --- 1,372 346,319 454,280 454,280 0 --- 272,797--- --- --- 10 5,134 6,765 6,765 0 --- 9,283--- --- --- 2.37 1.12 1.12 1.12 1.12 --- 0.49--- --- --- 0.019 0.014 0.014 0.014 0.014 --- 0.011--- --- --- 0.300 0.557 0.558 0.558 0.558 --- 1.071--- --- --- 0.019 0.025 0.025 0.025 0.025 --- 0.080--- --- --- 35.58 18.22 18.17 18.17 18.17 --- 6.50

34,754 34,754 34,754 34,715 15,746 9,754 --- 9,754 9,754 ---630,030 630,010 630,010 628,638 283,691 175,730 --- 175,730 175,730 ---1,258 1,258 1,315 1,428 708 438 --- 438 359 ---62.43 62.43 59.74 54.89 49.97 49.97 --- 49.97 60.98 ---0.710 0.710 0.305 0.090 0.109 0.109 --- 0.109 0.423 ---1.023 1.023 1.038 1.120 1.295 1.295 --- 1.295 1.034 ---0.360 0.360 0.389 0.391 0.359 0.359 --- 0.359 0.381 ---18.1 18.1 18.1 18.1 18.0 18.0 --- 18.0 18.0 ---

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 4 of 9

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

401 402 403 404 405 406 407 413 414 416Syngas to 2nd

Stage CondenserSyngas to

Coal/Coke DryingSyngas to Saturator

AGR Acid Gas to Sulfur Recovery

Recycle TGTU Tail Gas

LP CO2 to Compressor

MP CO2 to Compressor

Compressed CO2 to Pipeline

Oxygen to SRU TGTU Sour Water Purge

482 482 481 75 556 17.7 75 2000 100 66131 131 305 50 303 41 50 294 100 104

254,794 18,003 254,794 12,891 10,667 352,422 715,524 1,067,947 1,602 57639,203 2,770 39,203 327 292 8,038 16,321 24,359 49 32

7.7 0.5 7.7 0.0 0.0 0.0 0.0 0.1 0.0 0.01,285.4 90.8 1,285.4 0.0 11.6 2.3 4.6 6.9 0.0 0.0

952.4 67.3 952.4 220.2 225.8 8,003.1 16,248.7 24,251.8 0.0 0.00.1 0.0 0.1 0.0 0.0 0.1 0.1 0.2 0.0 0.0

33,121.5 2,340.3 33,121.5 0.0 43.5 30.5 61.9 92.4 0.0 0.0214.7 15.2 214.7 25.5 2.6 0.0 0.0 0.0 0.0 32.0

0.0 0.0 0.0 79.5 3.4 0.1 0.3 0.4 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.7 0.0 0.0 0.0 0.0 0.0 0.0

3,215.4 227.2 3,215.4 0.6 5.5 1.7 3.5 5.3 0.0 0.022.4 1.6 22.4 0.0 0.0 0.0 0.0 0.0 46.6 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.5 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

383.4 27.1 383.4 0.0 0.0 0.6 1.2 1.9 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

39,203 2,770 39,203 301 292 8,038 16,321 24,359 49 ---254,794 18,003 254,794 12,434 10,667 352,422 715,524 1,067,947 1,602 ---8,670 613 11,259 353 69 40,368 19,174 1,329 49 ---0.49 0.49 0.38 0.59 2.57 0.15 0.62 13.39 0.55 ---0.011 0.011 0.013 0.013 0.023 0.014 0.014 0.028 0.021 ---1.071 1.071 1.078 0.221 0.276 0.207 0.213 0.340 0.220 ---0.080 0.080 0.097 0.009 0.024 0.009 0.009 0.022 0.015 ---6.50 6.50 6.50 41.26 36.48 43.84 43.84 43.84 32.70 ---

--- --- --- 25 --- --- --- --- --- 32--- --- --- 457 --- --- --- --- --- 576--- --- --- 0.9 --- --- --- --- --- 1.2--- --- --- 63.21 --- --- --- --- --- 62.19--- --- --- 1.183 --- --- --- --- --- 0.651--- --- --- 1.026 --- --- --- --- --- 1.030--- --- --- 0.337 --- --- --- --- --- 0.365--- --- --- 18.1 --- --- --- --- --- 18.0

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 5 of 9

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

417 501 502 503 504 505 506 601 602 603Molten Sulfur Heated Sour

Water Stripper Feed

Sour Water Stripper Gas to

SRU

Stripper Bottoms to Feed/Effluent

Exchanger

Cooled Stripper Bottoms to

Syngas Wash Tower

Stripper Pumparound to

Cooler

Stripper Pumparound

Return

Syngas Saturator Overhead Vapor

Diluted Syngas to Combustion

Turbines

Saturator Bottoms Stream

100 496 30 31 31 30 25 480 479 481260 200 185 252 174 233 182 306 405 242

2,405 74,886 1,152 94,151 94,151 81,284 81,284 390,691 627,987 1,199,28975 4,131 36 5,226 5,226 4,515 4,515 46,747 55,194 66,573

0.0 0.0 0.0 0.0 0.0 0.0 0.0 7.7 7.7 0.00.0 0.0 2.1 0.0 0.0 0.0 0.0 1,284.8 1,284.8 0.50.0 18.0 19.2 0.0 0.0 0.2 0.2 952.4 952.4 7.50.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.00.0 0.1 1.3 0.0 0.0 0.0 0.0 33,122.1 33,122.1 15.90.0 4,110.4 10.0 5,226.1 5,226.1 4,454.0 4,454.0 7,759.2 7,759.2 66,548.00.0 0.2 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.1 0.0 0.0 0.4 0.4 0.0 0.0 0.00.0 2.1 2.3 0.1 0.1 60.2 60.2 0.0 0.0 0.00.0 0.1 0.2 0.0 0.0 0.0 0.0 3,215.4 11,493.4 1.50.0 0.0 0.0 0.0 0.0 0.0 0.0 22.4 191.4 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 383.4 383.4 0.0

75.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

--- 0 36 --- --- --- --- 46,747 55,194 ------ 0 1,152 --- --- --- --- 390,691 627,987 ------ 0 136 --- --- --- --- 13,284 17,847 ------ 2.74 0.14 --- --- --- --- 0.49 0.59 ------ 0.020 0.014 --- --- --- --- 0.013 0.016 ------ 0.276 0.277 --- --- --- --- 0.877 0.646 ------ 0.020 0.015 --- --- --- --- 0.078 0.070 ------ 36.45 32.25 --- --- --- --- 8.36 11.38 ---

--- 4,131 --- 5,226 5,226 4,515 4,515 --- --- 66,573--- 74,886 --- 94,151 94,151 81,284 81,284 --- --- 1,199,289--- 156 --- 202 195 175 170 --- --- 2,562--- 59.66 --- 57.98 60.27 58.06 59.57 --- --- 58.35--- 0.299 --- 0.225 0.356 0.227 0.343 --- --- 0.237--- 1.039 --- 1.065 1.040 1.061 1.045 --- --- 1.059--- 0.389 --- 0.397 0.387 0.393 0.386 --- --- 0.396--- 18.1 --- 18.0 18.0 18.0 18.0 --- --- 18.0

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 6 of 9

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

604 605 606 607 608 609 610 611 613 614Saturator Btms

Pump DischargeSaturator Purge to Syngas Wash

Tower

Saturator Recirculation

Water

Saturator Recirc/Makeup to Heater HTX-104

Hot Recirculation Water to Top of

Saturator

Heated Saturator Makeup Water

Saturator Makeup Water to

4th Stage Condenser

Saturator Makeup Water to

HTX-012

Nitrogen to AGR and Syngas

Dilution

Nitrogen to AGR

540 540 540 529 528 528 530 530 500 500242 242 242 250 334 334 162 100 237 237

1,199,289 5,404 1,193,885 1,335,304 1,335,304 1,335,304 141,419 141,419 271,008 33,71166,573 300 66,273 74,123 74,123 74,123 7,850 7,850 9,647 1,200

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.5 0.0 0.5 0.5 0.5 0.5 0.0 0.0 0.0 0.07.5 0.0 7.5 7.5 7.5 7.5 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

15.9 0.1 15.8 15.8 15.8 15.8 0.0 0.0 0.0 0.066,548.0 299.9 66,248.1 74,098.1 74,098.1 74,098.1 7,850.0 7,850.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.01.5 0.0 1.4 1.4 1.4 1.4 0.0 0.0 9,454.0 1,176.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 192.9 24.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

--- --- --- --- --- --- --- --- 9,647 1,200--- --- --- --- --- --- --- --- 271,008 33,711--- --- --- --- --- --- --- --- 2,416 301--- --- --- --- --- --- --- --- 1.87 1.87--- --- --- --- --- --- --- --- 0.023 0.023--- --- --- --- --- --- --- --- 0.260 0.260--- --- --- --- --- --- --- --- 0.019 0.019--- --- --- --- --- --- --- --- 28.09 28.09

66,573 300 66,273 74,123 74,123 74,123 7,850 7,850 --- ---1,199,289 5,404 1,193,885 1,335,304 1,335,304 1,335,304 141,419 141,419 --- ---

2,562 12 2,550 2,864 3,001 3,001 291 283 --- ---58.36 58.36 58.36 58.13 55.48 55.48 60.69 62.35 --- ---0.237 0.237 0.237 0.228 0.161 0.161 0.389 0.680 --- ---1.059 1.059 1.059 1.062 1.110 1.110 1.036 1.030 --- ---0.396 0.396 0.396 0.397 0.394 0.394 0.384 0.363 --- ---18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 --- ---

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 7 of 9

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

615 616 701 702 703 704 705 706 707 708Dilution Nitrogen

to 3rd Stage Condenser

Hot Dilution Nitrogen

Flash Vapor from Wash Tower

Bottoms Flash

Flash Liquid from Wash Tower

Bottoms Flash

Recovered Wash Water from Flash

Cooled Recovered Water

from Flash

Cooled Flash Vapor

Vapors to Jet Ejector

Steam to Jet Ejector

Jet Ejector Effluent Vapor to

Sour Water Stripper

500 499 7 7 62 57 7 7 615 7237 306 177 177 177 120 150 150 491 325

237,297 237,297 19,341 153,346 153,346 153,346 19,341 231 500 7318,447 8,447 1,071 8,512 8,512 8,512 1,071 11 28 38

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 2.1 0.0 0.0 0.0 2.1 2.1 0.0 2.10.0 0.0 1.2 0.0 0.0 0.0 1.2 1.2 0.0 1.20.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 1.2 0.0 0.0 0.0 1.2 1.2 0.0 1.20.0 0.0 1,066.0 8,511.9 8,511.9 8,511.9 1,066.0 5.6 27.8 33.40.0 0.0 0.3 0.0 0.0 0.0 0.3 0.2 0.0 0.20.0 0.0 0.1 0.0 0.0 0.0 0.1 0.0 0.0 0.00.0 0.0 0.3 0.1 0.1 0.1 0.3 0.0 0.0 0.0

8,278.0 8,278.0 0.2 0.0 0.0 0.0 0.2 0.2 0.0 0.2168.9 168.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

8,447 8,447 1,071 0 --- --- 11 11 28 38237,297 237,297 19,341 0 --- --- 231 231 500 7312,115 2,337 17,337 0 --- --- 164 164 6 7671.87 1.69 0.02 0.02 --- --- 0.02 0.02 1.29 0.020.023 0.024 0.009 0.009 --- --- 0.012 0.012 0.018 0.0120.260 0.260 0.451 0.451 --- --- 0.362 0.362 0.580 0.4330.019 0.020 0.013 0.013 --- --- 0.018 0.018 0.029 0.01928.09 28.09 18.05 18.05 --- --- 21.78 21.78 18.02 19.06

--- --- --- 8,512 8,512 8,512 1,061 --- --- ------ --- --- 153,346 153,346 153,346 19,110 --- --- ------ --- --- 318 318 310 39 --- --- ------ --- --- 60.19 60.19 61.75 60.92 --- --- ------ --- --- 0.349 0.349 0.555 0.426 --- --- ------ --- --- 1.041 1.041 1.032 1.036 --- --- ------ --- --- 0.387 0.387 0.371 0.381 --- --- ------ --- --- 18.0 18.0 18.0 18.0 --- --- ---

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 8 of 9

SYNGAS TREATING AREA43F PRB CO2 CAPTURE CASE

Table 1Component Balance

9/15/2006Project No: 42127

Stream NumberStream Description

Overall PropertiesPressure, psiaTemperature, °FMass Flow, lb/hrMole Flow, lbmole/hr

Component lb-moles/hrCH4COCO2COSH2H2OH2SHCNNH3N2O2NO2SO2ARSulfur

Vapor Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, ACFMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

Liquid Phase PropertiesMole Flow, lbmole/hrMass Flow, lb/hrActual Volumetric Flow, USGPMDensity, lb/ft3Viscosity, cPHeat Capacity, Btu/lb-FThermal Conductivity, Btu/hr-ft-FMolecular Weight

709 710 711 712Vacuum Flash Condensate

Vacuum Flash Condensate to

Sour Water Stripper

Particulate Solids Removed from Wash Tower

Bottoms

Recovered Wash Water

7 47 47150 150 150

19,110 19,110 19,1101,061 1,061 1,061

0.0 0.0 0.00.0 0.0 0.00.0 0.0 0.00.0 0.0 0.00.0 0.0 0.0

1,060.4 1,060.4 1,060.40.0 0.0 0.00.1 0.1 0.10.3 0.3 0.30.0 0.0 0.00.0 0.0 0.00.0 0.0 0.00.0 0.0 0.00.0 0.0 0.00.0 0.0 0.0

0 --- --- ---0 --- --- ---0 --- --- ---

0.02 --- --- ---0.012 --- --- ---0.362 --- --- ---0.018 --- --- ---21.78 --- --- ---

1,061 1,061 1,061 1,06119,110 19,110 19,110 19,110

39 39 39 3960.92 60.93 60.93 60.930.426 0.426 0.426 0.4261.036 1.036 1.036 1.0360.381 0.381 0.381 0.38118.0 18.0 18.0 18.0

Approximately 110 lb/day is

removed from the Wash Tower Bottoms stream.

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 9 of 9

B-1

B SITE LAYOUT DRAWINGS

42127

JUNE 12, 2006

SK-CS1

R. SEDLACEK

R. SEDLACEK

550MW (NET) 2X1 IGCC UNIT 1 OF 3

OPTION 1 - 100% PRB

CURRENT

FUTURE

25

21

54

21

78 9

20

2422

26

26��ÿ

KEY NOTES:

1

2

3

4

5

6

7

8

9

YARD MAINTENANCE BLDG.

CONSTRUCTION OFFICES

CONSTRUCTION PARKING

20

21

CONTROL ROOM/ADMIN. BLDG.

GAS TURBINE

HEAT RECOVERY STEAM GENERATOR

STEAM TURBINE

COOLING TOWER

AIR SEPARATION PLANT

ACID GAS SEPARATION

GAS CLEANUP

WATER TREATMENT

WAREHOUSE

COAL CONVEYOR

PLANT PARKING

SWITCHYARD

22

23

24

25

26

27

23

6

3

0’

SCALE IN FEET

300’300’ 600’

XXXXXXXXXXXXXX

WASTE WATER TREATMENT

SLAG & FINES LANDFILL

28 GAS METERING STATION

XX

28

29

30

ACCESS SPUR

LOOP TRACK

ROTARY DUMPER

SULFUR LOAD-OUT SIDING

6

PROPERTY LINE

31

32

33

31

32

33

FLARE

AUXILIARY BOILER

SULFUR PRODUCTION

COAL GRINDING AND DRYING

SLAG HANDLING

29

WASTE WATER POND

27

TAIL GAS TREATMENT UNIT

COAL PILE (60 DAYS)

COAL STOCKOUT

15

11

12

13

14

GASIFICATION

19

18

17

16

15

14

13

12

11

10

18

17

30

19

16

34 WATER STORAGE POND (30 DAYS)

34

10

35 SULFUR LOADOUT

35

Scale

Fo

r M

icro

film

ing

Inches

Mil

lim

ete

rs

1

A

B

C

D

E

F

G

H

I

J

K

L

M

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

no. date by

date detailed

checkeddesigned

ofsheet sheets

project contract

rev.drawing

file

ckd description

1

2

24

16

19

28

29

32

31

14

14

28

19

17

18

17

18

2

16

29

15

37

37

15

40

40

31

32

1

42

41

43

44

47

4546

41

43

46

47

44

45

42

48

49

12

12

10

294.75’

1

2

24

16

19

28

29

32

31

14

14

28

19

17

18

17

18

2

16

29

15

37

37

15

40

40

31

32

1

42

41

43

44

47

4546

41

43

46

47

44

45

42

48

49

12

12

10

1

2

24

16

19

28

29

32

31

14

14

28

19

17

18

17

18

2

16

29

15

37

37

15

40

40

31

32

1

42

41

43

44

47

4546

41

43

46

47

44

45

42

48

49

12

12

10

42127

JUNE 12, 2006

SK-CS2

R. SEDLACEK

R. SEDLACEK

550MW (NET) 2X1 IGCC UNIT 1 OF 3

OPTION 2 - 50% PRB/50% PET COKE

CURRENT

FUTURE

1

2

24

16

19

28

29

32

31

14

14

28

19

17

18

17

18

2

16

29

15

37

37

15

40

40

31

32

1

36

42

41

43

44

47

4546

41

43

46

47

44

45

42

50

48

49

12

12

10

Scale

Fo

r M

icro

film

ing

Inches

Mil

lim

ete

rs

1

A

B

C

D

E

F

G

H

I

J

K

L

M

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

no. date by

date detailed

checkeddesigned

ofsheet sheets

project contract

rev.drawing

file

ckd description

1

2

24

16

19

28

29

32

31

14

14

28

19

17

18

17

18

2

16

29

15

37

37

15

40

40

31

32

1

36

42

41

43

44

47

4546

41

43

46

47

44

45

42

50

48

49

12

12

10

294.75’

25

21

54

21

78 9

20

2422

26

26��ÿ

KEY NOTES:

1

2

3

4

5

6

7

8

9

YARD MAINTENANCE BLDG.

CONSTRUCTION OFFICES

CONSTRUCTION PARKING

20

21

CONTROL ROOM/ADMIN. BLDG.

GAS TURBINE

HEAT RECOVERY STEAM GENERATOR

STEAM TURBINE

COOLING TOWER

AIR SEPARATION PLANT

ACID GAS SEPARATION

GAS CLEANUP

WATER TREATMENT

WAREHOUSE

PLANT PARKING

SWITCHYARD

22

23

24

25

26

27

23

6

3

0’

SCALE IN FEET

300’300’ 600’

XXXXXXXXXXXXXX

WASTE WATER TREATMENT

SLAG & FINES LANDFILL

28 GAS METERING STATION

XX

28

29

30

ACCESS SPUR

LOOP TRACK

ROTARY DUMPER

SULFUR LOAD-OUT SIDING

6

PROPERTY LINE

31

32

33

31

32

33

FLARE

AUXILIARY BOILER

SULFUR PRODUCTION

COAL GRINDING AND DRYING

SLAG HANDLING

29

WASTE WATER POND

27

TAIL GAS TREATMENT UNIT

COAL PILE (60 DAYS)

COAL STOCKOUT

11

13

GASIFICATION

19

18

17

16

15

14

13

12

11

10

30

16

34 WATER STORAGE POND (30 DAYS)

34

10

35 SULFUR LOADOUT

35

COAL CONVEYORS

36 PET COKE PILE (30 DAYS)

36

19

18

17

14

15

12

1

2

24

16

19

28

29

32

31

14

14

28

19

17

18

17

18

2

16

29

15

37

37

15

40

40

31

32

1

36

42

41

43

44

47

4546

41

43

46

47

44

45

42

50

48

49

12

12

10

C-1

C WATER MASS BALANCE DIAGRAMS

no. | date | by | chd | description A | 6/23/06 | mab | | B | 6/29/06 | mab | bdh |

4,391 4,379 4,289 3,597 3,796(2,194,622) (2,188,624) (2,143,642) (1,797,781) (1,897,241)

Raw WaterInfluent

3(1,499) 90 692 199 8 12

(44,982) (345,862) (99,460) (3,998) (5,998) NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN ROUNDED TO THE NEAREST GALLON.2. FLOWS ARE BASED ON AVERAGE DAILY

74 54 CONDITIONS.(36,985) (26,989) 44 3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

(21,991) PER HOUR ROUNDED TO THE NEAREST20 POUND.

3 493 (9,996)(1,499) (246,401)

234 38(116,953) (18,992) 3,808

(1,903,238)

16 20(7,997) (9,996)

188(93,962)

18(8,996)

733 (3,499)

9 (16,493)(4,498)

11278 (5,498)

16 20 (138,944)(7,997) (9,996)

4,097(2,047,681)

3,135(1,566,873)

36(17,993) 962 date detailed

(480,808)

designed checked

998(498,800)

1,007(503,299)

project contract

drawing rev.--- B

sheet 1 of 2 sheetsfile

Revise Raw H2OInitial Issue

WMB-1.1

550 MW (net) IGCC

42127 CPS IGCC WMB Rev B.xls

6/29/2006

100% PRB @ 43 F Ambient DryWater Balance Diagram

M. Boyd

M. Boyd B. Hansen

Gulf Coast, Texas

42127

Bulb Temp. & 40 F Ambient Wet Bulb Temp.

Non-recoverable Losses

PRELIMINARY

ServiceWater

Storage

CoalStorage

Area

Oil/WaterSeparator

DemineralizerSystem (RO/EDI)

DemineralizedWater

StorageCondenser

HRSG Units

CoolingTower

ProcessWastewater

Storage

On-site Septic System

PotableWater

Treatment

F

S

X

W

IE

O

V

D

CartridgeFiltration

Y

K

L M

N

U

P

Q

R

AJ

Wastewater Discharge to

Outfall

J

Slag Quench(Non-recoverable)

B

GAK

A

H

Syngas Treatment AA

AB

Syngas Saturation (Non-Recoverable)

AC

Gasifier Units

AD

AE

Non-recoverable Losses

Sour Water Condensate Recycle

AF

Z

Evaporation & Drift

T

Syngas Burner (Non-Recoverable) AG

AH

C

AI

no. | date | by | chd | description A | 6/23/06 | mab | | B | 6/29/06 | mab | bdh |

4,983 4,969 4,879 4,208 4,401(2,490,503) (2,483,506) (2,438,524) (2,103,158) (2,199,620)

Raw WaterInfluent

3(1,499) 90 671 193 7 11

(44,982) (335,366) (96,461) (3,499) (5,498) NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN ROUNDED TO THE NEAREST GALLON.2. FLOWS ARE BASED ON AVERAGE DAILY

74 54 CONDITIONS.(36,985) (26,989) 44 3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

(21,991) PER HOUR ROUNDED TO THE NEAREST18 POUND.

3 478 (8,996)(1,499) (238,904)

234 36(116,953) (17,993) 4,412

(2,205,118)

16 20(7,997) (9,996)

177(88,465)

18(8,996)

731 (3,499)

11 (15,494)(5,498)

11278 (5,498)

16 20 (138,944)(7,997) (9,996)

4,701(2,349,560)

3,595(1,796,781)

36(17,993) 1,106 date detailed

(552,779)

designed checked

1,142(570,772)

1,153(576,269)

project contract

drawing rev.--- B

sheet 1 of 2 sheetsfile

Revise Raw H2OInitial Issue

WMB-1.2

550 MW (net) IGCC

42127 CPS IGCC WMB Rev B.xls

6/29/2006

100 % PRB @ 73 F Ambient DryWater Balance Diagram

M. Boyd

M. Boyd B. Hansen

Gulf Coast, Texas

42127

Bulb Temp. & 69 F Ambient Wet Bulb Temp.

Non-recoverable Losses

PRELIMINARY

ServiceWater

Storage

CoalStorage

Area

Oil/WaterSeparator

DemineralizerSystem (RO/EDI)

DemineralizedWater

StorageCondenser

HRSG Units

CoolingTower

ProcessWastewater

Storage

On-site Septic System

PotableWater

Treatment

F

S

X

W

IE

O

V

D

CartridgeFiltration

Y

K

L M

N

U

P

Q

R

AJ

Wastewater Discharge to

Outfall

J

Slag Quench(Non-recoverable)

B

GAK

A

H

Syngas Treatment AA

AB

Syngas Saturation (Non-Recoverable)

AC

Gasifier Units

AD

AE

Non-recoverable Losses

Sour Water Condensate Recycle

AF

Z

Evaporation & Drift

T

Syngas Burner (Non-Recoverable) AG

AH

C

AI

no. | date | by | chd | description A | 6/23/06 | mab | | B | 6/29/06 | mab | bdh |

5,580 5,565 5,475 4,814 5,004(2,788,884) (2,781,387) (2,736,405) (2,406,037) (2,500,999)

Raw WaterInfluent

3(1,499) 90 661 190 7 11

(44,982) (330,368) (94,962) (3,499) (5,498) NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN ROUNDED TO THE NEAREST GALLON.2. FLOWS ARE BASED ON AVERAGE DAILY

74 54 CONDITIONS.(36,985) (26,989) 44 3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

(21,991) PER HOUR ROUNDED TO THE NEAREST18 POUND.

3 471 (8,996)(1,499) (235,406)

234 36(116,953) (17,993) 5,015

(2,506,497)

16 20(7,997) (9,996)

171(85,466)

18(8,996)

730 (3,499)

12 (14,994)(5,998)

11278 (5,498)

16 20 (138,944)(7,997) (9,996)

5,304(2,650,939)

4,055(2,026,689)

36(17,993) 1,249 date detailed

(624,250)

designed checked

1,285(642,243)

1,297(648,241)

project contract

drawing rev.--- B

sheet 1 of 2 sheetsfile

Revise Raw H2OInitial Issue

WMB-1.3

550 MW (net) IGCC

42127 CPS IGCC WMB Rev B.xls

6/29/2006

100% PRB @ 93 Ambient DryWater Balance Diagram

M. Boyd

M. Boyd B. Hansen

Gulf Coast, Texas

42127

Bulb Temp. & 77 F Ambient Wet Bulb Temp.

Non-recoverable Losses

PRELIMINARY

ServiceWater

Storage

CoalStorage

Area

Oil/WaterSeparator

DemineralizerSystem (RO/EDI)

DemineralizedWater

StorageCondenser

HRSG Units

CoolingTower

ProcessWastewater

Storage

On-site Septic System

PotableWater

Treatment

F

S

X

W

IE

O

V

D

CartridgeFiltration

Y

K

L M

N

U

P

Q

R

AJ

Wastewater Discharge to

Outfall

J

Slag Quench(Non-recoverable)

B

GAK

A

H

Syngas Treatment AA

AB

Syngas Saturation (Non-Recoverable)

AC

Gasifier Units

AD

AE

Non-recoverable Losses

Sour Water Condensate Recycle

AF

Z

Evaporation & Drift

T

Syngas Burner (Non-Recoverable) AG

AH

C

AI

no. | date | by | chd | description A | 6/23/06 | mab | | B | 6/29/06 | mab | bdh |

4,619 4,606 4,516 3,689 3,927(2,308,576) (2,302,079) (2,257,097) (1,843,762) (1,962,715)

Raw WaterInfluent

3(1,499) 90 827 238 8 12

(44,982) (413,335) (118,952) (3,998) (5,998) NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN ROUNDED TO THE NEAREST GALLON.2. FLOWS ARE BASED ON AVERAGE DAILY

74 54 CONDITIONS.(36,985) (26,989) 44 3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

(21,991) PER HOUR ROUNDED TO THE NEAREST20 POUND.

3 589 (9,996)(1,499) (294,382)

234 38(116,953) (18,992) 3,939

(1,968,712)

16 20(7,997) (9,996)

231(115,454)

18(8,996)

786 (3,499)

10 (42,983)(4,998)

11278 (5,498)

16 20 (138,944)(7,997) (9,996)

4,228(2,113,154)

3,235(1,616,853)

36(17,993) 993 date detailed

(496,301)

designed checked

1,029(514,294)

1,039(519,292)

project contract

drawing rev.--- B

sheet 1 of 2 sheetsfile

Revise Raw H2OInitial Issue

WMB-2.1

550 MW (net) IGCC

42127 CPS IGCC WMB Rev B.xls

6/29/2006

50% PRB / 50% Pet Coke @ 43 F Ambient DryWater Balance Diagram

M. Boyd

M. Boyd B. Hansen

Gulf Coast, Texas

42127

Bulb Temp. & 40F Ambient Wet Bulb Temp.

Non-recoverable Losses

PRELIMINARY

ServiceWater

Storage

CoalStorage

Area

Oil/WaterSeparator

DemineralizerSystem (RO/EDI)

DemineralizedWater

StorageCondenser

HRSG Units

CoolingTower

ProcessWastewater

Storage

On-site Septic System

PotableWater

Treatment

F

S

X

W

IE

O

V

D

CartridgeFiltration

Y

K

L M

N

U

P

Q

R

AJ

Wastewater Discharge to

Outfall

J

Slag Quench(Non-recoverable)

B

GAK

A

H

Syngas Treatment AA

AB

Syngas Saturation (Non-Recoverable)

AC

Gasifier Units

AD

AE

Non-recoverable Losses

Sour Water Condensate Recycle

AF

Z

Evaporation & Drift

T

Syngas Burner (Non-Recoverable) AG

AH

C

AI

no. | date | by | chd | description A | 6/23/06 | mab | | B | 6/29/06 | mab | bdh |

5,231 5,217 5,127 4,328 4,558(2,614,454) (2,607,457) (2,562,475) (2,163,134) (2,278,088)

Raw WaterInfluent

3(1,499) 90 799 230 8 11

(44,982) (399,340) (114,954) (3,998) (5,498) NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN ROUNDED TO THE NEAREST GALLON.2. FLOWS ARE BASED ON AVERAGE DAILY

74 54 CONDITIONS.(36,985) (26,989) 44 3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

(21,991) PER HOUR ROUNDED TO THE NEAREST19 POUND.

3 569 (9,496)(1,499) (284,386)

234 37(116,953) (18,493) 4,569

(2,283,586)

16 20(7,997) (9,996)

217(108,457)

18(8,996)

781 (3,499)

11 (40,484)(5,498)

11278 (5,498)

16 20 (138,944)(7,997) (9,996)

4,858(2,428,028)

3,715(1,856,757)

36(17,993) 1,143 date detailed

(571,271)

designed checked

1,179(589,264)

1,190(594,762)

project contract

drawing rev.--- B

sheet 1 of 2 sheetsfile

Revise Raw H2OInitial Issue

WMB-2.2

550 MW (net) IGCC

42127 CPS IGCC WMB Rev B.xls

6/29/2006

50% PRB / 50% Pet Coke @ 73 F Ambient DryWater Balance Diagram

M. Boyd

M. Boyd B. Hansen

Gulf Coast, Texas

42127

Bulb Temp. & 69 F Ambient Wet Bulb Temp.

Non-recoverable Losses

PRELIMINARY

ServiceWater

Storage

CoalStorage

Area

Oil/WaterSeparator

DemineralizerSystem (RO/EDI)

DemineralizedWater

StorageCondenser

HRSG Units

CoolingTower

ProcessWastewater

Storage

On-site Septic System

PotableWater

Treatment

F

S

X

W

IE

O

V

D

CartridgeFiltration

Y

K

L M

N

U

P

Q

R

AJ

Wastewater Discharge to

Outfall

J

Slag Quench(Non-recoverable)

B

GAK

A

H

Syngas Treatment AA

AB

Syngas Saturation (Non-Recoverable)

AC

Gasifier Units

AD

AE

Non-recoverable Losses

Sour Water Condensate Recycle

AF

Z

Evaporation & Drift

T

Syngas Burner (Non-Recoverable) AG

AH

C

AI

no. | date | by | chd | description A | 6/23/06 | mab | | B | 6/29/06 | mab | bdh |

5,800 5,785 5,695 4,910 5,136(2,898,840) (2,891,343) (2,846,361) (2,454,018) (2,566,973)

Raw WaterInfluent

3(1,499) 90 785 226 7 11

(44,982) (392,343) (112,955) (3,499) (5,498) NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN ROUNDED TO THE NEAREST GALLON.2. FLOWS ARE BASED ON AVERAGE DAILY

74 54 CONDITIONS.(36,985) (26,989) 44 3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

(21,991) PER HOUR ROUNDED TO THE NEAREST18 POUND.

3 559 (8,996)(1,499) (279,388)

234 36(116,953) (17,993) 5,147

(2,572,471)

16 20(7,997) (9,996)

211(105,458)

18(8,996)

778 (3,499)

12 (38,984)(5,998)

11278 (5,498)

16 20 (138,944)(7,997) (9,996)

5,436(2,716,913)

4,155(2,076,669)

36(17,993) 1,281 date detailed

(640,244)

designed checked

1,317(658,237)

1,329(664,234)

project contract

drawing rev.--- B

sheet 1 of 2 sheetsfile

Revise Raw H2OInitial Issue

WMB-2.3

550 MW (net) IGCC

42127 CPS IGCC WMB Rev B.xls

6/29/2006

50% PRB / 50% Pet Coke @ 93 F Ambient DryWater Balance Diagram

M. Boyd

M. Boyd B. Hansen

Gulf Coast, Texas

42127

Bulb Temp. & 77 F Ambient Wet Bulb Temp.

Non-recoverable Losses

PRELIMINARY

ServiceWater

Storage

CoalStorage

Area

Oil/WaterSeparator

DemineralizerSystem (RO/EDI)

DemineralizedWater

StorageCondenser

HRSG Units

CoolingTower

ProcessWastewater

Storage

On-site Septic System

PotableWater

Treatment

F

S

X

W

IE

O

V

D

CartridgeFiltration

Y

K

L M

N

U

P

Q

R

AJ

Wastewater Discharge to

Outfall

J

Slag Quench(Non-recoverable)

B

GAK

A

H

Syngas Treatment AA

AB

Syngas Saturation (Non-Recoverable)

AC

Gasifier Units

AD

AE

Non-recoverable Losses

Sour Water Condensate Recycle

AF

Z

Evaporation & Drift

T

Syngas Burner (Non-Recoverable) AG

AH

C

AI

43°F 73°F 93°F 43°F 73°F 93°F

Flow Path Flow DescriptionFlowrate (GPM)

Flowrate (GPM)

Flowrate (GPM)

Flowrate (GPM)

Flowrate (GPM)

Flowrate (GPM)

A Water Supply 4391 4983 5580 4619 5231 5800

B Filter Reject to Outfall 9 11 12 10 11 12

D Service Water 90 90 90 90 90 90

E Service Water for Coal Storage 16 16 16 16 16 16

H Service Water to Slag Quench 54 54 54 54 54 54

M Demin. Reject 199 193 190 238 230 226

O Demin Storage Influent 493 478 471 589 569 559

P Condenser Influent 38 36 36 38 37 36

T HRSG Blowdown 11 11 11 11 11 11

V CT Evaporation & Drift 3135 3595 4055 3235 3715 4155

Z Wastewater w/ Filter Reject to Outfall 1007 1153 1297 1039 1190 1329

AA Demin Water to Syngas Scrubber 234 234 234 234 234 234

AB Syngas Scrubber Effluent 278 278 278 278 278 278

AC Demin Water for Syngas Saturation 188 177 171 231 217 211

AD Gasifier Blowdown 12 11 11 12 11 11

AG Water for Syngas Burner 33 31 30 86 81 78

AH Combined CT Make-up 4097 4701 5304 4228 4858 5436

AJ Raw Water Influent to Potable Water Treatment 3 3 3 3 3 3

AK Effluent to on-site Septic System 3 3 3 3 3 3

PRB 50-50 PRB-Petcoke

D-1

D ELECTRICAL ONE-LINE DIAGRAMS

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EE001

V. VERMILLION

OVERALL

ONE-LINE DIAGRAM

A

--

-

STG CTG 2 CTG 1

G

EE005

I

EE006

C

EE003

A

EE002

K

EE013

E

EE004

F

EE004

L

EE013

B

EE002

D

EE003

J

EE006

H

EE005

LINE #2 LINE #1

TO BOP

SWGR

TO GASIFICATION

SWGR

TO COAL

HANDLING SWGR

TO POWER

BLOCK SWGR B

TO POWER

BLOCK SWGR A

TO POWER

BLOCK SWGR A

TO POWER

BLOCK SWGR B

TO COAL

HANDLING SWGR

TO GASIFICATION

SWGR

TO BOP

SWGR

TO SULFUR &

SLAG SWGR

TO SULFUR &

SLAG SWGR

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE001.DGN 8-03-2006 15:23 V_VERMIL

42127EE001.DGN

JUNE 28, 2006

R. MAHALEY

153/204/255MVA

345-22kV

153/204/255MVA

345-22kV

320MVA

22KV

45/60/75

22-13.8KV

255MVA

22KV

255MVA

22KV

45/60/75

22-13.8KV

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

2000/2666KVA

13,800-480V

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

2000/2666KVA

13,800-480V

BAC

COMPR. 2

NITROGEN

AIR

COMPR. 2

12,000

BAC

COMPR. 1

NITROGEN

AIR

COMPR. 1

12,000

2000/2666KVA

13,800-480V

2000/2666KVA

13,800-480V

40,000

60MVA

345-13.8kV

08/04/06 RDM -A ISSUED FOR

APPROVAL

192/256/320MVA

345-22kV

40,000 40,000

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

40,000

60MVA

345-13.8kV

MAC

COMPR. 1

MAC

COMPR. 2

120MVA

345-13.8kV

120MVA

345-13.8kV

Scale

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project contract

rev.drawing

file

ckd description

42127

EPRI / CPS IGCC STUDY

BU

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' 2006

EE002 A

--

-

GASIFICATION

13.8KV SWGR

EE001

A

N

EE001

B

12501250

M

13,800 GASIFICATION SWGR

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE002.DGN 8-03-2006 15:25 V_VERMIL

JUNE 28, 2006

R. MAHALEY

V. VERMILLION

42127EE002.DGN

2000/2666KVA

13,800-480V

2000/2666KVA

13,800-480V

08/04/06 RDM -A ISSUED FOR

APPROVAL

480V

GASIFICATION MCCs

480V

GASIFICATION MCCs

13.8KV

GASIFICATION

LOADS B

13.8KV

GASIFICATION

LOADS A

Scale

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rev.drawing

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ckd description

42127

EPRI / CPS IGCC STUDY

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EE003 A

--

-

EE001

C

EE001

D

20002000

4160V COAL HANDLING SWGR

COAL HANDLING

4160V SWGR

GRINDING

MILL 1

GRINDING

MILL 2

P

480V COAL HANDLING SWGR

250

RECLAIM

CONV.

250

STOCKOUT

CONV.

EE009

COAL HANDLING

& GRINDING

MCC A

150

RECLAIM DUST

COLLECTION

200

UNLDG.

CONV.

TRANSFER

CONVEYOR

Q

150

JUNE 28, 2006

R. MAHALEY

V. VERMILLION

42127EE003.DGN

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE003.DGN 8-03-2006 15:30 V_VERMIL

RDM -A ISSUED FOR

APPROVAL

2000/2666KVA

4160-480V

2000/2666KVA

4160-480V

08/04/06

OTHER COAL

HANDLING & GRINDING

Scale

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rev.drawing

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ckd description

42127

EPRI / CPS IGCC STUDY

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EE004

42127EE004.DGN

A

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-

EE001

E

S

EE001

F

V. VEMILLION

4160V SULFUR & SLAG SWGR

R

JUNE 28, 2006

R. MAHALEY

SULFUR & SLAG

4160V SWGR

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE004.DGN 8-03-2006 15:37 V_VERMIL

RDM -A ISSUED FOR

APPROVAL

2000/2666KVA

4160-480V

2000/2666KVA

4160-480V

08/04/06

4160V

SULFUR & SLAG

LOADS 1A

TO SLAG & SULFUR

480V MCCs

TO SLAG & SULFUR

480V MCCs

4160V

SULFUR & SLAG

LOADS 1B

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ckd description

42127

EPRI / CPS IGCC STUDY

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EE005

V. VERMILLION

42127EE005.DGN

A

--

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POWER BLOCK

SWITCHGEAR A

EE001

G

WELL

PP1A

CTG 1

ATOMIZING

AIR

HP/IP

FEEDWATER

PUMP 1A

HP/IP

FEEDWATER

PUMP 2A

WELL

PP1B

CTG 2

ATOMIZING

AIR

HP/IP

FEEDWATER

PUMP 1B

HP/IP

FEEDWATER

PUMP 2B

EE001

H

4160V POWER BLOCK SWGR. A

480V POWER BLOCK SWGR. A

DDGGBB

PWR BLK

MCC CTG 1

WATER

INJ PP

CCEE JJHH

IIFF

CTG 2

WATER

INJ PP

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE005.DGN 8-03-2006 15:39 V_VERMIL

JUNE 28, 2006

R. MAHALEY

200 200

1000250025007503502500

CIRC.

WATER

PUMP

3507502500 2500 500

CONDENSATE

PUMP

AUX. COOLING

WATER PUMP 1A

1000

AUX. COOLING

WATER PUMP 1B

RDM -A ISSUED FOR

APPROVAL

CTG 1

STATION SERVICE

TRANSF. 1A

2000/2666KVA

4160-480V

CTG 2

STATION SERVICE

TRANSF. 2A

2000/2666KVA

4160-480V

08/04/06

CTG 2

MCC

CTG 1

MCC

CTG 1

MCC

CTG 2

MCC

CTG 1

MCC

CTG 2

MCC

STG

MCC

EMERGENCY

GENERATOR

EMERGENCY

MCCs

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ckd description

42127

EPRI / CPS IGCC STUDY

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EE006

42127EE006.DGN

A

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POWER BLOCK

SWITCHGEAR B

EE001

I

CTG 1

ATOMIZING

AIR

WELL

PP1C

EE001

J

KKMM LLNN

4160V POWER BLOCK SWGR B

480V SWGR. B

PP

COOLING

TOWER

MCC 18

CLOSED

COOLING

WATER

PUMP 1A

CIRCULATING

WATER

PUMP 1C

CONDENSATE

PUMP 1A

CONDENSATE

PUMP 1B

CLOSED

COOLING WATER

PUMP 1B

CIRCULATING

WATER

PUMP 1B

QQ

COOLING

TOWER

MCC 28

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE006.DGN 8-03-2006 15:43 V_VERMIL

JUNE 28, 2006 V. VERMILLION

R. MAHALEY

1000 750 2500 500 500 2500 1000 350

CTG 1

STATION SERVICE

TRANSF. 1B

2000/2666KVA

4160-480V

CTG 2

STATION SERVICE

TRANSF. 2B

2000/2666KVA

4160-480V

RDM -A ISSUED FOR

APPROVAL

08/04/06

HRSG 1

MCC

STG 1A

MCC

HRSG 2

MCC

STG 1B

MCC

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42127

EPRI / CPS IGCC STUDY

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V. VERMILLION

A

--

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NOTES:

1.

2.

3.

NEMA 1 ENCLOSURE.

INCOMING MAIN POWER CABLES ARE TOP ENTRY.

FOR GENERAL SYMBOLS AND LEGENDS, REFER TO DWG. E001.

1 3 3

30 305

CONDENSATE TRANSFER

PUMP 1

CONDENSATE TRANSFER

PUMP 2

RR

FLARE KO DRUM PUMP

CONTROL RM/

ADMIN BLDG

PNL

K

EE001

L

EE001

FIRE PUMP

SKID

WAREHOUSE

PNL

BALANCE OF PLANT

480V SWITCHGEAR & MCC

BOP MCC A BOP MCC B

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE007.DGN 8-03-2006 16:04 V_VERMIL

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R. MAHALEY

40A

WELL PUMP

HOUSE #1 PANEL

480-208/120V

30KVA 3 PH,

DRY TYPE

40A

WELL PUMP

HOUSE #2 PANEL

480-208/120V

30KVA 3 PH,

DRY TYPE

1

25

WELL PUMP 4

POTABLE WATER

10WWW-PMP4

3A

RDM -A ISSUED FOR

APPROVAL

EE007

42127EE007.DGN

08/04/06

WATER TREATMENT

MCC

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42127

EPRI / CPS IGCC STUDY

E-1

E CAPITAL COST DETAIL

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Project Desc: 550 MW (Net) 2x1 7FB IGCC - 100% PRB Client: EPRI / CPS Energy Date: 07/20/06

Project #: 42127 Estimate By: J. Schwarz Revision: 0

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

PROCUREMENT

Major Equipment100 Gas Turbine - Generator 86,000,000 - - - - 86,000,000$ 101 Steam Turbine - Generator 22,950,840 - - - - 22,950,840$ 102 Steam Generator / Heat Recovery Steam Generator 28,080,000 - - - - 28,080,000$ 103 Flue Gas Desulfurization System - - - - - -$ 104 Particulate Removal (Baghouse or Precip) - - - - - -$ 105 SCR / CO Catalyst - - - - - -$ 106 Bypass Stack - - - - - -$ 107 Stack - - - - - -$ 108 Surface Condenser & Air Removal Equipment 4,138,000 - - - - 4,138,000$ 109 Cooling Tower - - - 10,133,333 - 10,133,333$ FLA Flare - - - 6,102,434 - 6,102,434$

- - - - - -$ Mechanical Procurement - - - - - -$

110 Boiler Feed Pumps 3,169,814 - - - - 3,169,814$ 111 Condensate Pumps 367,500 - - - - 367,500$ 112 Circulating Water Pumps 819,052 - - - - 819,052$

112A Aux Cooling Water Pumps 649,251 - - - - 649,251$ 113 Miscellaneous Pumps 250,000 - - - - 250,000$ 114 Compressed Air Equipment 330,000 - - - - 330,000$ 115 Deaerator - - - - - -$ 116 Closed Feedwater Heaters - - - - - -$ 117 Auxiliary Boiler 1,896,000 - - - - 1,896,000$ 118 Heat Exchangers - - - - - -$

- - - - - -$ Electrical & Control Procurement - - - - - -$

1201 GSU Transformers 18,000,000 - - - - 18,000,000$ 1202 Auxiliary Transformers 4,160,000 - - - - 4,160,000$ 121 Generator Breakers 1,200,000 - - - - 1,200,000$ 122 Iso Phase Bus Duct 5,390,000 - - - - 5,390,000$ 123 Small (480 V & 5 kV) Power Transformers - - - - - -$ 124 Emergency Diesel Generator - - - - - -$ 125 Medium Voltage Metal-Clad Switchgear 7,915,000 - - - - 7,915,000$ 126 480 V Switchgear & Transformers 6,905,000 - - - - 6,905,000$ 127 480 V Motor Control Center - - - - - -$ 128 Electrical Control Boards - - - - - -$ 129 Battery & UPS System 620,000 - - - - 620,000$ 130 Freeze Protection System - - - - - -$ 131 Relay & Metering Panels 1,075,000 - - - - 1,075,000$

Account / Contract

LaborDescription

Burns McDonnellConfidential 1 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - - -$ 135 Distributed Control System 1,366,075 - - - - 1,366,075$ 136 Continuous Emission Monitors 572,900 - - - - 572,900$ 137 Instrumentation 611,725 - - - - 611,725$

- - - - - -$ Natural Gas Equipment Procurement - - - - - -$

140 Gas Compressors - - - - - -$ 141 Fuel Gas Filter/Separator 214,864 - - - - 214,864$ 142 Fuel Gas Dewpoint Heater - - - - - -$ 143 Fuel Gas Efficiency Heater - - - - - -$ 144 Fuel Flow Measurement / Monitoring Equipment - - - - - -$

- - - - - -$ Material Handling - - - - - -$

145 Coal Handling Equipment 59,000 - - 31,600,000 - 31,659,000$ 146 Ash Handling Equipment - - - 5,000,000 - 5,000,000$ 147 Limestone / Lime Handling Equipment - - - - - -$

- - - - - -$ Water Treatment & Chemical Storage - - - - - -$

150 Raw Water Treatment 982,500 - - - - 982,500$ 151 RO/EDI or Demineralizer 754,000 - - - - 754,000$ 152 Condensate Polisher - - - - - -$ 153 Chemical Feed Equipment (Boiler Cycle) 146,462 - - - - 146,462$ 154 Ammonia Supply & Storage - - - - - -$ 155 CO2 Supply & Storage 20,000 - - - - 20,000$ 156 Chemical Feed Equipment 270,000 - - - - 270,000$ 157 Sample Analysis Panel 200,000 - - - - 200,000$ 158 Wastewater Treatment Equipment 12,000 - - - - 12,000$

- - - - - -$ Misc Mechanical - - - - - -$

160 Critical Pipe 7,425,524 - - - - 7,425,524$ 161 Balance of Plant Pipe - - - - - -$ 162 Pipe Supports 532,000 - - - - 532,000$ 163 Circulating Water Pipe 3,591,000 - - - - 3,591,000$ 170 High Pressure Valves 165,000 - - - - 165,000$ 171 Low Pressure Valves 1,151,500 - - - - 1,151,500$ 172 Large Butterfly Valves (>24") 300,000 - - - - 300,000$ 173 Control Valves 626,360 - - - - 626,360$ 174 Steam Turbine Bypass Valves 630,000 - - - - 630,000$ 180 Shop Fabricated Tanks 205,000 - - - - 205,000$ 181 Oil/Water Separator 58,000 - - - - 58,000$ 182 Closed Cooling Water Heat Exchanger 2,228,100 - - - - 2,228,100$ 183 Piping Specials 165,500 - - - - 165,500$

- - - - - -$ Fire Protection - - - - - -$

190 Fire Protection System 1,357,960 - - - - 1,357,960$ 191 Fire Pumps 216,300 - - - - 216,300$ 192 Flammable/Combustible Storage Enclosure - - - - - -$

- - - - - -$ Structural Procurement - - - - - -$

195 Bridge Crane - - - - - -$ 196 Structural Steel 1,485,138 - - - - 1,485,138$ 197 Fixators 117,000 - - - - 117,000$

Burns McDonnellConfidential 2 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - - -$ CONSTRUCTION - - - - - -$

-$ Sub-EPC Packages - - - - - -$

ASU Air Separation Unit and N2 Storage - - - 102,400,000 - 102,400,000$ GAS Gasification - - - 354,306,139 - 354,306,139$ SGT Syngas Treatment - - - 149,993,742 - 149,993,742$

- -$ Major Equipment Erection - - - - - -$

200 Combustion Turbine Generator Erection 7,488 72,651 3,324,536 17,000 1,773,346 5,122,369$ 201 Steam Turbine - Generator Erection - 31,875 1,458,605 - 778,037 2,236,642$ 202 Steam Generator / HRSG Erection - 165,750 8,825,957 500,000 4,045,792 13,371,748$ 203 FGD System Erection - - - - - -$ 204 Particulate Removal (Baghouse or Precip) Erection - - - - - -$ 205 SCR / CO Catalyst Erection - - - - - -$ 206 Chimney - - - - - -$

- - - - - -$ Civil / Structural Construction - - - - - -$

210 Site Preparation 3,154,045 297,345 12,717,757 40,313,746 - 56,185,548$ 211 Piling - - - 3,301,520 - 3,301,520$ 212 Substructures - - - - - -$ 213 Underground Utilities - - - - - -$ 214 Yard Structures - - - - - -$ 215 Foundations 4,068,872 188,696 8,601,390 189,900 - 12,860,162$ 216 Railroad - - - 10,040,500 - 10,040,500$ 220 Structural Steel 338,331 24,831 1,097,378 - - 1,435,708$ 221 Power Plant Structures - - - 6,783,360 - 6,783,360$ 222 Pre-engineered Buildings - - - - - -$ 223 Sanitary Drains / Treatment - - - - - -$

- - - - - -$ 290 Final Painting 988,000 18,896 840,172 1,170,000 182,817 3,180,990$ 291 Final Paving, Landscaping & Cleanup 486,405 1,695 72,487 389,928 - 948,819$ 299 Demolition - - - - - -$

- - - - - -$ Mechanical Construction - - - - - -$

2301 Misc Mechanical Equipment Erection - 63,463 2,904,083 - 1,549,071 4,453,154$ 2310 Below Grade Piping 373,650 73,953 3,288,263 1,071,134 1,805,122 6,538,169$ 231 Above Grade Piping 6,475,923 247,098 10,986,993 1,373,690 6,031,409 24,868,015$ 232 Insulation and Lagging 760,000 36,210 1,656,923 765,000 773,415 3,955,338$ 260 Field Erected Tanks - - - 2,260,000 - 2,260,000$

- - - - - -$ Electrical Construction - - - - - -$

2401 Electrical Equipment Erection 250,000 69,459 3,179,171 - 1,097,335 4,526,506$ 2402 Wire / Cable 2,223,970 47,350 2,167,145 - 1,405,157 5,796,271$ 2403 Grounding - - - - - -$ 2404 Raceway 230,285 14,216 650,680 - 281,909 1,162,874$ 2405 Lighting - - - - - -$ 2406 Heat Tracing - - - - - -$ 2407 Instrumentation 57,124 9,410 430,586 10,000 156,067 653,777$ 2408 Switchyard - - - 10,890,000 - 10,890,000$

- - - - - -$ - - - - - -$

Burns McDonnellConfidential 3 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

EPC CONTRACTOR INDIRECT COSTS - - - - - -$ - - - - - -$

Construction Indirects - - - - - -$ 5000 Construction Management - - - 24,714,000 - 24,714,000$ 5001 Field Office Expense - - - - - -$ 5002 Temporary Facilities - - - - - -$ 5003 Temporary Utilities - - - 2,954,590 - 2,954,590$ 5004 Construction Equipment / Operators - - - - - -$ 5005 Heavy Haul - - - 1,331,911 - 1,331,911$ 5006 Small Tools & Consumables - - - - - -$ 5012 Labor Per Diem & Benefits - - - - - -$ 5007 Site Services - - - - - -$ 5008 Construction Testing - - - 500,000 - 500,000$ 5009 Preoperational Testing, Startup, & Calibration 146,400 1,530 70,011 8,016,000 - 8,232,411$ 5010 Safety - - - - - -$ 5011 Miscellaneous Construction Indirects - - - - - -$

- - - - - -$ Project Indirects - - - - - -$

5050 Site Surveys/Studies - - - 700,000 - 700,000$ 5051 Performance Testing - - - 600,000 - 600,000$ 5052 Project Management & Engineering 40,000,000 - - - - 40,000,000$ 5053 Training - - - 500,000 - 500,000$ 5064 Warranty - - - - - -$ 5054 Operating Spare Parts - - - - - -$ 5055 Project Insurance - - - - - -$ 5056 Project Bonds - - - 2,961,450 - 2,961,450$ 5057 Escalation - - - - - -$ 5058 Sales Tax - - - - - -$ 5059 EPC Contingency - - - 57,099,042 - 57,099,042$ 5060 EPC Fee - - - 119,907,989 - 119,907,989$

TOTAL EPC PROJECT COST 278,939,856 1,364,428 62,272,136 957,896,409 19,879,477 1,318,987,878

Burns McDonnellConfidential 4 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - -$ 6000 Owner Indirects - - - - -$ 6001 Project Development - - - 3,000,000 3,000,000$ 6002 Owner Personnel - - - 7,200,000 7,200,000$ 6003 Owners OE - - - 23,000,000 23,000,000$ 6004 Owners Legal Council - - - 2,000,000 2,000,000$ 6005 Owner Startup Engineering - - - - -$ 6006 Permitting & License Fees - - - 2,910,000 2,910,000$ 6007 Land - - - 7,500,000 7,500,000$ 6008 Water Rights - - - - -$ 6009 Political Concessions / Area Development Fees / Labor Camps - - - 1,000,000 1,000,000$ 6010 Startup/Testing - - - 5,186,487 5,186,487$ 6011 Initial Fuel Inventory - - - 10,927,224 10,927,224$ 6012 Site Surveys/Studies - - - - -$ 6013 Site Security - - - 1,728,000 1,728,000$ 6014 Transmission Interconnection / Upgrades - - - - -$ 6015 Operating Spare Parts 10,055,869 - - - 10,055,869$ 6016 Permanent Plant Equipment & Furnishings 4,600,000 - - - 4,600,000$ 6017 Builder's Risk Insurance - - - 5,935,445 5,935,445$ 6018 Escalation Owner's Indirects - - - - -$ 6019 Sales Tax & Duties - - - - -$ 6020 Owner Contingency - - - 70,201,545 70,201,545$ 6021 Financing Fees - - - - -$ 6022 Interest During Construction - - - - -$

TOTAL OWNER COST 14,655,869 - - 140,588,702 - 155,244,571

TOTAL EPC PROJECT COST 278,939,856$ 1,364,428 62,272,136$ 957,896,409$ 19,879,477$ 1,318,987,878$ TOTAL OWNER'S COST 14,655,869$ - -$ 140,588,702$ -$ 155,244,571$

PROJECT TOTAL 293,595,725$ 1,364,428 62,272,136$ 1,098,485,111$ 19,879,477$ 1,474,232,449$

Burns McDonnellConfidential 5 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Project Desc: 550 MW (Net) 2x1 7FB IGCC - 50% PRB/50% Petcoke Client: EPRI / CPS Energy Date: 07/20/06

Project #: 42127 Estimate By: J. Schwarz Revision: 0

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

PROCUREMENT

Major Equipment100 Gas Turbine - Generator 86,000,000 - - - - 86,000,000$ 101 Steam Turbine - Generator 22,950,840 - - - - 22,950,840$ 102 Steam Generator / Heat Recovery Steam Generator 28,080,000 - - - - 28,080,000$ 103 Flue Gas Desulfurization System - - - - - -$ 104 Particulate Removal (Baghouse or Precip) - - - - - -$ 105 SCR / CO Catalyst - - - - - -$ 106 Bypass Stack - - - - - -$ 107 Stack - - - - - -$ 108 Surface Condenser & Air Removal Equipment 4,138,000 - - - - 4,138,000$ 109 Cooling Tower - - - 10,133,333 - 10,133,333$ FLA Flare - - - 6,102,434 - 6,102,434$

- - - - - -$ Mechanical Procurement - - - - - -$

110 Boiler Feed Pumps 3,169,814 - - - - 3,169,814$ 111 Condensate Pumps 367,500 - - - - 367,500$ 112 Circulating Water Pumps 819,052 - - - - 819,052$

112A Aux Cooling Water Pumps 649,251 - - - - 649,251$ 113 Miscellaneous Pumps 250,000 - - - - 250,000$ 114 Compressed Air Equipment 330,000 - - - - 330,000$ 115 Deaerator - - - - - -$ 116 Closed Feedwater Heaters - - - - - -$ 117 Auxiliary Boiler 1,896,000 - - - - 1,896,000$ 118 Heat Exchangers - - - - - -$

- - - - - -$ Electrical & Control Procurement - - - - - -$

1201 GSU Transformers 18,000,000 - - - - 18,000,000$ 1202 Auxiliary Transformers 4,160,000 - - - - 4,160,000$ 121 Generator Breakers 1,200,000 - - - - 1,200,000$ 122 Iso Phase Bus Duct 5,820,000 - - - - 5,820,000$ 123 Small (480 V & 5 kV) Power Transformers - - - - - -$ 124 Emergency Diesel Generator - - - - - -$ 125 Medium Voltage Metal-Clad Switchgear 8,465,000 - - - - 8,465,000$ 126 480 V Switchgear & Transformers 8,355,000 - - - - 8,355,000$ 127 480 V Motor Control Center - - - - - -$ 128 Electrical Control Boards - - - - - -$ 129 Battery & UPS System 620,000 - - - - 620,000$ 130 Freeze Protection System - - - - - -$ 131 Relay & Metering Panels 1,075,000 - - - - 1,075,000$

Account / Contract

LaborDescription

Burns McDonnellConfidential 1 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - - -$ 135 Distributed Control System 1,391,075 - - - - 1,391,075$ 136 Continuous Emission Monitors 572,900 - - - - 572,900$ 137 Instrumentation 662,725 - - - - 662,725$

- - - - - -$ Natural Gas Equipment Procurement - - - - - -$

140 Gas Compressors - - - - - -$ 141 Fuel Gas Filter/Separator 214,864 - - - - 214,864$ 142 Fuel Gas Dewpoint Heater - - - - - -$ 143 Fuel Gas Efficiency Heater - - - - - -$ 144 Fuel Flow Measurement / Monitoring Equipment - - - - - -$

- - - - - -$ Material Handling - - - - - -$

145 Coal Handling Equipment 118,000 - - 41,100,000 - 41,218,000$ 146 Ash Handling Equipment - - - 3,077,861 - 3,077,861$ 147 Limestone / Lime Handling Equipment - - - - - -$

- - - - - -$ Water Treatment & Chemical Storage - - - - - -$

150 Raw Water Treatment 982,500 - - - - 982,500$ 151 RO/EDI or Demineralizer 754,000 - - - - 754,000$ 152 Condensate Polisher - - - - - -$ 153 Chemical Feed Equipment (Boiler Cycle) 146,462 - - - - 146,462$ 154 Ammonia Supply & Storage - - - - - -$ 155 CO2 Supply & Storage 20,000 - - - - 20,000$ 156 Chemical Feed Equipment 270,000 - - - - 270,000$ 157 Sample Analysis Panel 200,000 - - - - 200,000$ 158 Wastewater Treatment Equipment 12,000 - - - - 12,000$

- - - - - -$ Misc Mechanical - - - - - -$

160 Critical Pipe 7,425,524 - - - - 7,425,524$ 161 Balance of Plant Pipe - - - - - -$ 162 Pipe Supports 532,000 - - - - 532,000$ 163 Circulating Water Pipe 3,591,000 - - - - 3,591,000$ 170 High Pressure Valves 165,000 - - - - 165,000$ 171 Low Pressure Valves 1,151,500 - - - - 1,151,500$ 172 Large Butterfly Valves (>24") 300,000 - - - - 300,000$ 173 Control Valves 626,360 - - - - 626,360$ 174 Steam Turbine Bypass Valves 630,000 - - - - 630,000$ 180 Shop Fabricated Tanks 205,000 - - - - 205,000$ 181 Oil/Water Separator 58,000 - - - - 58,000$ 182 Closed Cooling Water Heat Exchanger 2,228,100 - - - - 2,228,100$ 183 Piping Specials 165,500 - - - - 165,500$

- - - - - -$ Fire Protection - - - - - -$

190 Fire Protection System 1,857,960 - - - - 1,857,960$ 191 Fire Pumps 216,300 - - - - 216,300$ 192 Flammable/Combustible Storage Enclosure - - - - - -$

- - - - - -$ Structural Procurement - - - - - -$

195 Bridge Crane - - - - - -$ 196 Structural Steel 1,485,138 - - - - 1,485,138$ 197 Fixators 117,000 - - - - 117,000$

Burns McDonnellConfidential 2 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - - -$ CONSTRUCTION - - - - - -$

-$ Sub-EPC Packages - - - - - -$

ASU Air Separation Unit and N2 Storage - - - 102,400,000 - 102,400,000$ GAS Gasification - - - 306,357,314 - 306,357,314$ SGT Syngas Treatment - - - 158,147,910 - 158,147,910$

- -$ Major Equipment Erection - - - - - -$

200 Combustion Turbine Generator Erection 7,488 72,651 3,324,536 17,000 1,773,346 5,122,369$ 201 Steam Turbine - Generator Erection - 31,875 1,458,605 - 778,037 2,236,642$ 202 Steam Generator / HRSG Erection - 165,750 8,825,957 500,000 4,045,792 13,371,748$ 203 FGD System Erection - - - - - -$ 204 Particulate Removal (Baghouse or Precip) Erection - - - - - -$ 205 SCR / CO Catalyst Erection - - - - - -$ 206 Chimney - - - - - -$

- - - - - -$ Civil / Structural Construction - - - - - -$

210 Site Preparation 3,121,355 296,428 12,678,548 40,009,951 - 55,809,853$ 211 Piling - - - 3,499,160 - 3,499,160$ 212 Substructures - - - - - -$ 213 Underground Utilities - - - - - -$ 214 Yard Structures - - - - - -$ 215 Foundations 4,417,676 218,646 9,966,627 204,460 - 14,588,763$ 216 Railroad - - - 10,040,500 - 10,040,500$ 220 Structural Steel 338,331 24,831 1,097,378 - - 1,435,708$ 221 Power Plant Structures - - - 6,783,360 - 6,783,360$ 222 Pre-engineered Buildings - - - - - -$ 223 Sanitary Drains / Treatment - - - - - -$

- - - - - -$ 290 Final Painting 988,000 18,896 840,172 1,170,000 182,817 3,180,990$ 291 Final Paving, Landscaping & Cleanup 486,405 1,695 72,487 389,928 - 948,819$ 299 Demolition - - - - - -$

- - - - - -$ Mechanical Construction - - - - - -$

2301 Misc Mechanical Equipment Erection - 63,463 2,904,083 - 1,549,071 4,453,154$ 2310 Below Grade Piping 373,650 73,953 3,288,263 1,071,134 1,805,122 6,538,169$ 231 Above Grade Piping 6,475,923 247,098 10,986,993 1,373,690 6,031,409 24,868,015$ 232 Insulation and Lagging 760,000 36,210 1,656,923 765,000 773,415 3,955,338$ 260 Field Erected Tanks - - - 2,260,000 - 2,260,000$

- - - - - -$ Electrical Construction - - - - - -$

2401 Electrical Equipment Erection 250,000 76,018 3,479,360 - 1,193,395 4,922,755$ 2402 Wire / Cable 2,223,970 47,350 2,167,145 - 1,405,157 5,796,271$ 2403 Grounding - - - - - -$ 2404 Raceway 230,285 14,216 650,680 - 281,909 1,162,874$ 2405 Lighting - - - - - -$ 2406 Heat Tracing - - - - - -$ 2407 Instrumentation 57,124 10,152 464,542 20,000 166,933 708,598$ 2408 Switchyard - - - 10,890,000 - 10,890,000$

- - - - - -$ - - - - - -$

Burns McDonnellConfidential 3 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

EPC CONTRACTOR INDIRECT COSTS - - - - - -$ - - - - - -$

Construction Indirects - - - - - -$ 5000 Construction Management - - - 24,714,000 - 24,714,000$ 5001 Field Office Expense - - - - - -$ 5002 Temporary Facilities - - - - - -$ 5003 Temporary Utilities - - - 2,954,590 - 2,954,590$ 5004 Construction Equipment / Operators - - - - - -$ 5005 Heavy Haul - - - 1,331,911 - 1,331,911$ 5006 Small Tools & Consumables - - - - - -$ 5012 Labor Per Diem & Benefits - - - - - -$ 5007 Site Services - - - - - -$ 5008 Construction Testing - - - 500,000 - 500,000$ 5009 Preoperational Testing, Startup, & Calibration 146,400 1,530 70,011 8,016,000 - 8,232,411$ 5010 Safety - - - - - -$ 5011 Miscellaneous Construction Indirects - - - - - -$

- - - - - -$ Project Indirects - - - - - -$

5050 Site Surveys/Studies - - - 700,000 - 700,000$ 5051 Performance Testing - - - 600,000 - 600,000$ 5052 Project Management & Engineering 40,000,000 - - - - 40,000,000$ 5053 Training - - - 500,000 - 500,000$ 5064 Warranty - - - - - -$ 5054 Operating Spare Parts - - - - - -$ 5055 Project Insurance - - - - - -$ 5056 Project Bonds - - - 2,890,860 - 2,890,860$ 5057 Escalation - - - - - -$ 5058 Sales Tax - - - - - -$ 5059 EPC Contingency - - - 55,738,004 - 55,738,004$ 5060 EPC Fee - - - 117,049,808 - 117,049,808$

TOTAL EPC PROJECT COST 282,320,970 1,400,762 63,932,307 921,308,208 19,986,403 1,287,547,889

Burns McDonnellConfidential 4 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - -$ 6000 Owner Indirects - - - - -$ 6001 Project Development - - - 3,000,000 3,000,000$ 6002 Owner Personnel - - - 7,200,000 7,200,000$ 6003 Owners OE - - - 23,000,000 23,000,000$ 6004 Owners Legal Council - - - 2,000,000 2,000,000$ 6005 Owner Startup Engineering - - - - -$ 6006 Permitting & License Fees - - - 2,910,000 2,910,000$ 6007 Land - - - 7,500,000 7,500,000$ 6008 Water Rights - - - - -$ 6009 Political Concessions / Area Development Fees / Labor Camps - - - 1,000,000 1,000,000$ 6010 Startup/Testing - - - (3,499,854) (3,499,854)$ 6011 Initial Fuel Inventory - - - 6,191,274 6,191,274$ 6012 Site Surveys/Studies - - - - -$ 6013 Site Security - - - 1,728,000 1,728,000$ 6014 Transmission Interconnection / Upgrades - - - - -$ 6015 Operating Spare Parts 10,123,491 - - - 10,123,491$ 6016 Permanent Plant Equipment & Furnishings 4,600,000 - - - 4,600,000$ 6017 Builder's Risk Insurance - - - 5,793,965 5,793,965$ 6018 Escalation Owner's Indirects - - - - -$ 6019 Sales Tax & Duties - - - - -$ 6020 Owner Contingency - - - 67,954,738 67,954,738$ 6021 Financing Fees - - - - -$ 6022 Interest During Construction - - - - -$

TOTAL OWNER COST 14,723,491 - - 124,778,124 - 139,501,616

TOTAL EPC PROJECT COST 282,320,970$ 1,400,762 63,932,307$ 921,308,208$ 19,986,403$ 1,287,547,889$ TOTAL OWNER'S COST 14,723,491$ - -$ 124,778,124$ -$ 139,501,616$

PROJECT TOTAL 297,044,462$ 1,400,762 63,932,307$ 1,046,086,333$ 19,986,403$ 1,427,049,505$

Burns McDonnellConfidential 5 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

Project Desc: 550 MW (Net) Supercritical PC - 100% PRB Client: EPRI / CPS Energy Date: 07/20/06

Project #: 42127 Estimate By: J. Schwarz Revision: 0

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

PROCUREMENT

Major Equipment100 Gas Turbine - Generator - - - - - -$ 101 Steam Turbine - Generator 40,043,000 - - - - 40,043,000$ 102 Steam Generator / Heat Recovery Steam Generator 182,631,579 - - - - 182,631,579$ 103 Flue Gas Desulfurization System - - - - - -$ 104 Particulate Removal (Baghouse or Precip) - - - - - -$ 105 SCR / CO Catalyst - - - - - -$ 106 Bypass Stack - - - - - -$ 107 Stack - - - - - -$ 108 Surface Condenser & Air Removal Equipment 5,800,000 - - - - 5,800,000$ 109 Cooling Tower - - - 10,000,000 - 10,000,000$

- - - - - -$ Mechanical Procurement - - - - - -$

110 Boiler Feed Pumps 3,275,768 - - - - 3,275,768$ 111 Condensate Pumps 420,000 - - - - 420,000$ 112 Circulating Water Pumps 1,300,000 - - - - 1,300,000$ 113 Miscellaneous Pumps 800,600 - - - - 800,600$ 114 Compressed Air Equipment 990,000 - - - - 990,000$ 115 Deaerator 362,887 - - - - 362,887$ 116 Closed Feedwater Heaters 2,854,904 - - - - 2,854,904$ 117 Auxiliary Boiler - - - - - -$ 118 Heat Exchangers 270,000 - - - - 270,000$

- - - - - -$ Electrical & Control Procurement - - - - - -$

1201 GSU Transformers 9,450,000 - - - - 9,450,000$ 1202 Auxiliary Transformers 3,100,000 - - - - 3,100,000$ 121 Generator Breakers - - - - - -$ 122 Iso Phase Bus Duct 2,035,000 - - - - 2,035,000$ 123 Small (480 V & 5 kV) Power Transformers - - - - - -$ 124 Emergency Diesel Generator - - - - - -$ 125 Medium Voltage Metal-Clad Switchgear 6,295,000 - - - - 6,295,000$ 126 480 V Switchgear & Transformers 3,965,000 - - - - 3,965,000$ 127 480 V Motor Control Center 1,785,000 - - - - 1,785,000$ 128 Electrical Control Boards 115,836 - - - - 115,836$ 129 Battery & UPS System 1,105,000 - - - - 1,105,000$ 130 Freeze Protection System - - - - - -$ 131 Relay & Metering Panels 405,000 - - - - 405,000$

Account / Contract

LaborDescription

Burns McDonnellConfidential 1 of 5 550MW Super PC Cost Estimate - Greenfield.xls

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - - -$ 135 Distributed Control System 5,301,000 - - - - 5,301,000$ 136 Continuous Emission Monitors 600,000 - - - - 600,000$ 137 Instrumentation 1,108,310 - - - - 1,108,310$

- - - - - -$ Natural Gas Equipment Procurement - - - - - -$

140 Gas Compressors - - - - - -$ 141 Fuel Gas Filter/Separator - - - - - -$ 142 Fuel Gas Dewpoint Heater - - - - - -$ 143 Fuel Gas Efficiency Heater - - - - - -$ 144 Fuel Flow Measurement / Monitoring Equipment - - - - - -$

- - - - - -$ Material Handling - - - - - -$

145 Coal Handling Equipment - - - 32,000,000 - 32,000,000$ 146 Ash Handling Equipment - - - 10,630,000 - 10,630,000$ 147 Limestone Handling Equipment - - - 3,899,000 - 3,899,000$

- - - - - -$ Water Treatment & Chemical Storage - - - - - -$

150 Raw Water Treatment 792,500 - - - - 792,500$ 151 RO/EDI or Demineralizer 754,000 - - - - 754,000$ 152 Condensate Polisher 2,225,309 - - - - 2,225,309$ 153 Chemical Feed Equipment (Boiler Cycle) 190,000 - - - - 190,000$ 154 Ammonia Supply & Storage 301,899 - - - - 301,899$ 155 CO2 Supply & Storage 30,200 - - - - 30,200$ 156 Chemical Feed Equipment (Cooling Tower) - - - - - -$ 157 Sample Analysis Panel 250,000 - - - - 250,000$ 158 Wastewater Treatment Equipment 12,000 - - - - 12,000$

- - - - - -$

Misc Mechanical - - - - - -$ 160 Critical Pipe 6,857,723 - - - - 6,857,723$ 161 Balance of Plant Pipe - - - - - -$ 162 Pipe Supports 542,190 - - - - 542,190$ 163 Circulating Water Pipe 3,195,000 - - - - 3,195,000$ 170 High Pressure Valves 1,633,159 - - - - 1,633,159$ 171 Low Pressure Valves 3,287,242 - - - - 3,287,242$ 172 Large Butterfly Valves (>24") - - - - - -$ 173 Control Valves 792,000 - - - - 792,000$ 174 Steam Turbine Bypass Valves 1,266,411 - - - - 1,266,411$ 180 Shop Fabricated Tanks 206,000 - - - - 206,000$ 181 Oil/Water Separator 101,500 - - - - 101,500$ 182 Closed Cooling Water Heat Exchanger - - - - - -$ 183 Piping Specials 1,584,920 - - - - 1,584,920$

- - - - - -$ Fire Protection - - - - - -$

190 Fire Protection System - - - 2,500,000 - 2,500,000$ 191 Fire Pumps 325,000 - - - - 325,000$ 192 Flammable/Combustible Storage Enclosure - - - - - -$

- - - - - -$ Structural Procurement - - - - - -$

195 Bridge Crane - - - - - -$ 196 Structural Steel 1,967,360 - - - - 1,967,360$ 197 Fixators - - - - - -$

Burns McDonnellConfidential 2 of 5 550MW Super PC Cost Estimate - Greenfield.xls

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - - -$ CONSTRUCTION - - - - - -$

- - - - - -$ Major Equipment Erection - - - - - -$

200 Combustion Turbine Generator Erection - - - - - -$ 201 Steam Turbine - Generator Erection - 83,105 4,091,681 720,000 2,028,498 6,840,179$ 202 Steam Generator / HRSG Erection - - - 164,368,421 - 164,368,421$ 203 FGD System Erection - - - - - -$ 204 Particulate Removal (Baghouse or Precip) Erection - - - - - -$ 205 SCR / CO Catalyst Erection - - - - - -$ 206 Chimney - - - 15,000,000 - 15,000,000$

- - - - - -$ Civil / Structural Construction - - - - - -$

210 Site Preparation 3,208,315 335,390 15,065,704 40,392,509 1,827,402 60,493,929$ 211 Piling - - - 10,000,000 - 10,000,000$ 212 Substructures - - - - - -$ 213 Underground Utilities - - - - - -$ 214 Yard Structures - - - - - -$ 215 Foundations 10,409,116 491,846 20,694,597 - 3,110,371 34,214,084$ 216 Railroad - - - 10,040,500 - 10,040,500$ 220 Structural Steel 1,172,632 47,801 2,286,786 70,000 345,942 3,875,360$ 221 Power Plant Structures 12,544,401 180,063 8,614,204 10,556,140 2,115,861 33,830,606$ 222 Pre-engineered Buildings - - - - - -$ 223 Sanitary Drains / Treatment - - - - - -$

- - - - - -$ 290 Final Painting 520,000 9,945 546,580 1,500,000 106,658 2,673,238$ 291 Final Paving, Landscaping & Cleanup 886,405 2,320 104,192 435,928 99,060 1,525,585$ 299 Demolition - - - - - -$

- - - - - -$ Mechanical Construction - - - - - -$

2301 Misc Mechanical Equipment Erection - 131,127 6,883,668 600,000 3,200,676 10,684,344$ 2310 Below Grade Piping 457,718 52,729 2,854,928 - 1,287,064 4,599,709$ 231 Above Grade Piping 19,432,376 504,760 27,741,082 - 12,320,685 59,494,143$ 232 Insulation and Lagging 781,708 116,243 5,410,223 - 2,837,370 9,029,301$ 260 Field Erected Tanks - - - 1,499,100 - 1,499,100$

- - - - - -$ Electrical Construction - - - - - -$

2401 Electrical Equipment Erection - 63,342 3,117,057 83,100 997,458 4,197,616$ 2402 Wire / Cable 6,627,351 354,129 17,426,660 - 7,697,284 31,751,294$ 2403 Grounding 345,613 19,187 944,212 - 412,744 1,702,569$ 2404 Raceway 1,788,353 193,824 9,538,073 - 3,624,456 14,950,883$ 2405 Lighting 311,520 16,245 799,429 - 355,504 1,466,452$ 2406 Heat Tracing 700,000 9,563 470,570 - 374,582 1,545,152$ 2407 Instrumentation - 13,868 682,463 - 218,388 900,852$ 2408 Switchyard - - - 4,840,000 - 4,840,000$

- - - - - -$ - - - - - -$

Burns McDonnellConfidential 3 of 5 550MW Super PC Cost Estimate - Greenfield.xls

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

EPC CONTRACTOR INDIRECT COSTS - - - - - -$ - - - - - -$

Construction Indirects - - - - - -$ 5000 Construction Management - - - 24,712,644 - 24,712,644$ 5001 Field Office Expense - - - - - -$ 5002 Temporary Facilities - - - - - -$ 5003 Temporary Utilities - - - 2,754,590 - 2,754,590$ 5004 Construction Equipment / Operators - - - - - -$ 5005 Heavy Haul - - - 1,250,000 - 1,250,000$ 5006 Small Tools & Consumables - - - - - -$ 5007 Site Services - - - - - -$ 5008 Construction Testing - - - 500,000 - 500,000$ 5009 Preoperational Testing, Startup, & Calibration - - - 8,786,000 - 8,786,000$ 5010 Safety - - - - - -$ 5011 Miscellaneous Construction Indirects - - - - - -$

- - - - - -$ Project Indirects - - - - - -$

5050 Site Surveys/Studies - - - 700,000 - 700,000$ 5051 Performance Testing - - - 300,000 - 300,000$ 5052 Project Management & Engineering - - - 38,115,000 - 38,115,000$ 5053 Training - - - 225,000 - 225,000$ 5054 Operating Spare Parts - - - - - -$ 5055 Project Insurance - - - - - -$ 5056 Project Bonds - - - 2,408,182 - 2,408,182$ 5057 Escalation - - - - - -$ 5058 Sales Tax - - - - - -$ 5059 EPC Contingency - - - 46,431,601 - 46,431,601$ 5060 EPC Fee - - - 97,506,363 - 97,506,363$

TOTAL EPC PROJECT COST 359,513,804 2,625,486 127,272,110 542,824,078 42,960,002 1,072,569,994

Burns McDonnellConfidential 4 of 5 550MW Super PC Cost Estimate - Greenfield.xls

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

Material Subcontract Subcontract Total

Dollars Manhours Dollars Dollars Indirect $ Dollars

Account / Contract

LaborDescription

- - - - -$ 6000 Owner Indirects - - - - -$ 6001 Project Development - - - 2,000,000 2,000,000$ 6002 Owner Operations Personnel - - - 7,200,000 7,200,000$ 6003 Owners OE - - - 20,000,000 20,000,000$ 6004 Owners Legal Council - - - 2,000,000 2,000,000$ 6005 Owner Startup Engineering - - - - -$ 6006 Permitting & License Fees - - - 2,910,000 2,910,000$ 6007 Land - - - 7,500,000 7,500,000$ 6008 Water Rights - - - - -$ 6009 Political Concessions / Area Development Fees / Labor Camps - - - 1,000,000 1,000,000$ 6010 Startup/Testing - - - 1,114,760 1,114,760$ 6011 Initial Fuel Inventory - - - 10,692,000 10,692,000$ 6012 Site Surveys/Studies - - - - -$ 6013 Site Security - - - 1,728,000 1,728,000$ 6014 Transmission Interconnection / Upgrades - - - - -$ 6015 Operating Spare Parts 5,752,221 - - - 5,752,221$ 6016 Permanent Plant Equipment & Furnishings 5,780,000 - - - 5,780,000$ 6017 Builder's Risk Insurance - - - 4,826,565 4,826,565$ 6018 Escalation Owner's Indirects - - - - -$ 6019 Sales Tax & Duties - - - - -$ 6020 Owner Contingency - - - 57,253,677 57,253,677$ 6021 Financing Fees - - - - -$ 6022 Interest During Construction - - - - -$

TOTAL OWNER COST 11,532,221 - - 118,225,002 - 129,757,223

TOTAL EPC PROJECT COST 359,513,804$ 2,625,486 127,272,110$ 542,824,078$ 42,960,002$ 1,072,569,994$ TOTAL OWNER'S COST 11,532,221$ - -$ 118,225,002$ -$ 129,757,223$

PROJECT TOTAL 371,046,025$ 2,625,486 127,272,110$ 661,049,080$ 42,960,002$ 1,202,327,217$

Burns McDonnellConfidential 5 of 5 550MW Super PC Cost Estimate - Greenfield.xls

F-1

F HEAT BALANCE DIAGRAMS

LEGEND COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THEM- Mass Flow, pph ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.T- Temperature, FP- Pressure, psiaH- Enthalpy, Btu/lb T

TSYNGAS

MTP

FROM HRSG 2 H

M FROM HRSG 2TP

FROM HRSG 2 H TO HRSG 2

M MT TP PH H

Syngas Condensing& GTG Air Cooling205 MMBTU/hr

MTP Aux Cooling Water ReturnH M

TTO HRSG 2

COOLING TOWER 2267 MMBTU/hr

MTPH

MT

M ST LEAKS HT

Aux Cooling Water Supply

DATE MODEL REV.GSC

G HCN Hydrolysis Preheater and Saturator Pump Around Heater 312,172 97.4

52.1E

75

65

B

C 404.1494,039

Fuel Gas Heater

Stream IGCC Process Requirements Flow Out (lb/hr)

1,533575

1,652,9901,026

1,363

213

1,038

826,495

1,499

588

358,332

1630276 M

160,767 14.25

ASU, Selexol, Sour Water Reboiler Water Consumption

58,872

Syngas Cooler and SRU IP Steam Production

630109

1,535

1,031

232,009

2,174

GASIFICATION BLOCK AUX POWER, kW

GTG2 HEAT CONS, MMBTU/h (HHV)

2,174

GTG1 HEAT RATE, BTU/kWh (HHV)

279

POWER BLOCK AUX LOAD, kW 22,465

DESIGNED: J. SCHWARZ

100% PRB @ 43DB

182

1,800,033

EPRI / CPS Energy

114,911

07/21/2006

HEAT BALANCE DIAGRAM

599,224

NET CYCLE EFFICIENCY

2x1 7FB IGCC - Shell Gasification Process

9,085

38%

RELATIVE HUMIDITY, %

ELEVATION, FT

9,369

100

GTG2 OUTPUT, kW

STG OUTPUT, kW

232,009

GTG2 HEAT RATE, BTU/kWh (HHV)

272,581

PERFORMANCE SUMMARY

GTG1 OUTPUT, kW

GROSS PLANT OUTPUT, kW 736,599

DRY BULB TEMP, °F

WET BULB TEMP, °F 40

78%

43

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET PLANT OUTPUT, kW

TOTAL AUX POWER, kW 137,376

5,444TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

9,369

405

2,001

Hg Removal Preheater & Diluent N2 Heater70,866,496

1,272 2.05

F

TGTU HP Steam Requirements

26,370 25.4

Selexol and ASU IP Steam

D

716,6641,0301,9031,497

672,307724

SRU and TGTU LP Steam Production

BMCD PROJECT 42127

70,866,496

A

1559 MMBTU/hrProcess Duty (MMBtu/hr)

1,223 1.11

634

1.42 in HgA90 T655

4,381

BFP

D

LPSTHPST IPST

COMP TURB

STA

CK

HPS

HTR

HPE

VAP

RH

TR

HPE

CO

N

RH

TR

HPS

HTR

IPSH

TR

LPSH

TR

IPEV

AP

HPE

CO

N

IPEC

ON

LPEV

AP

PRH

TR

A

D C B

J

K D M

K

H

L

J

M

N

C A B

N

I

I

F

E

L H

E F

G

G

LEGEND COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THEM- Mass Flow, pph ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.T- Temperature, FP- Pressure, psiaH- Enthalpy, Btu/lb T

TSYNGAS

MTP

FROM HRSG 2 H

M FROM HRSG 2TP

FROM HRSG 2 H TO HRSG 2

M MT TP PH H

Syngas Condensing& GTG Air Cooling91 MMBTU/hr

MTP Aux Cooling Water ReturnH M

TTO HRSG 2

COOLING TOWER 2130 MMBTU/hr

MTPH

MT

M ST LEAKS HT

Aux Cooling Water Supply

DATE MODEL REV.GSC

G HCN Hydrolysis Preheater and Saturator Pump Around Heater 296,062 91.3

50.1E

75

65

B

C 378.2452,803

Fuel Gas Heater

Stream IGCC Process Requirements Flow Out (lb/hr)

1,548550

1,562,6441,053

1,369

165

1,060

781,322

1,513

562

355,475

1536088 M

151,738 13.35

ASU, Selexol, Sour Water Reboiler Water Consumption

55,337

Syngas Cooler and SRU IP Steam Production

65383

1,551

1,058

224,869

2,037

GASIFICATION BLOCK AUX POWER, kW

GTG2 HEAT CONS, MMBTU/h (HHV)

2,037

GTG1 HEAT RATE, BTU/kWh (HHV)

245

POWER BLOCK AUX LOAD, kW 21,952

DESIGNED: J. SCHWARZ

100% PRB @ 73DB

133

1,698,067

EPRI / CPS Energy

134,861

07/21/2006

HEAT BALANCE DIAGRAM

553,059

NET CYCLE EFFICIENCY

2x1 7FB IGCC - Shell Gasification Process

9,222

37%

RELATIVE HUMIDITY, %

ELEVATION, FT

9,057

100

GTG2 OUTPUT, kW

STG OUTPUT, kW

224,869

GTG2 HEAT RATE, BTU/kWh (HHV)

260,134

PERFORMANCE SUMMARY

GTG1 OUTPUT, kW

GROSS PLANT OUTPUT, kW 709,872

DRY BULB TEMP, °F

WET BULB TEMP, °F 69

82%

73

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET PLANT OUTPUT, kW

TOTAL AUX POWER, kW 156,813

5,100TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

9,057

405

2,003

Hg Removal Preheater & Diluent N2 Heater70,866,496

1,192 1.91

F

TGTU HP Steam Requirements

26,370 25.4

Selexol and ASU IP Steam

D

710,9641,0531,9041,511

667,745732

SRU and TGTU LP Steam Production

BMCD PROJECT 42127

70,866,496

A

1471 MMBTU/hrProcess Duty (MMBtu/hr)

1,118 1.04

607

2.18 in HgA104 T655

1,118

BFP

D

LPSTHPST IPST

COMP TURB

STA

CK

HPS

HTR

HPE

VAP

RH

TR

HPE

CO

N

RH

TR

HPS

HTR

IPSH

TR

LPSH

TR

IPEV

AP

HPE

CO

N

IPEC

ON

LPEV

AP

PRH

TR

A

D C B

J

K D M

K

H

L

J

M

N

C A B

N

I

I

F

E

L H

E F

G

G

LEGEND COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THEM- Mass Flow, pph ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.T- Temperature, FP- Pressure, psiaH- Enthalpy, Btu/lb T

TSYNGAS

MTP

FROM HRSG 2 H

M FROM HRSG 2TP

FROM HRSG 2 H TO HRSG 2

M MT TP PH H

Syngas Condensing& GTG Air Cooling88 MMBTU/hr

MTP Aux Cooling Water ReturnH M

TTO HRSG 2

COOLING TOWER 2156 MMBTU/hr

MTPH

MT

M ST LEAKS HT

Aux Cooling Water Supply

DATE MODEL REV.GSC

G HCN Hydrolysis Preheater and Saturator Pump Around Heater 291,102 88.4

48.7E

75

65

B

C 366.3438,696

Fuel Gas Heater

Stream IGCC Process Requirements Flow Out (lb/hr)

1,548539

1,531,8611,052

1,369

169

1,057

765,930

1,512

551

345,697

1505624 M

146,920 12.93

ASU, Selexol, Sour Water Reboiler Water Consumption

53,707

Syngas Cooler and SRU IP Steam Production

64982

1,550

1,056

215,584

1,972

GASIFICATION BLOCK AUX POWER, kW

GTG2 HEAT CONS, MMBTU/h (HHV)

1,972

GTG1 HEAT RATE, BTU/kWh (HHV)

247

POWER BLOCK AUX LOAD, kW 21,763

DESIGNED: J. SCHWARZ

100% PRB @ 93DB

137

1,663,191

EPRI / CPS Energy

131,381

07/21/2006

HEAT BALANCE DIAGRAM

528,398

NET CYCLE EFFICIENCY

2x1 7FB IGCC - Shell Gasification Process

9,348

37%

RELATIVE HUMIDITY, %

ELEVATION, FT

9,149

100

GTG2 OUTPUT, kW

STG OUTPUT, kW

215,584

GTG2 HEAT RATE, BTU/kWh (HHV)

250,374

PERFORMANCE SUMMARY

GTG1 OUTPUT, kW

GROSS PLANT OUTPUT, kW 681,542

DRY BULB TEMP, °F

WET BULB TEMP, °F 77

49%

93

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET PLANT OUTPUT, kW

TOTAL AUX POWER, kW 153,144

4,940TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

9,149

405

1,948

Hg Removal Preheater & Diluent N2 Heater70,866,496

1,154 1.86

F

TGTU HP Steam Requirements

26,370 25.4

Selexol and ASU IP Steam

D

691,3511,0501,8531,511

649,198731

SRU and TGTU LP Steam Production

BMCD PROJECT 42127

70,866,496

A

1448 MMBTU/hrProcess Duty (MMBtu/hr)

1,087 1.01

594

2.53 in HgA109 T650

1,087

BFP

D

LPSTHPST IPST

COMP TURB

STA

CK

HPS

HTR

HPE

VAP

RH

TR

HPE

CO

N

RH

TR

HPS

HTR

IPSH

TR

LPSH

TR

IPEV

AP

HPE

CO

N

IPEC

ON

LPEV

AP

PRH

TR

A

D C B

J

K D M

K

H

L

J

M

N

C A B

N

I

I

F

E

L H

E F

G

G

LEGEND COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THEM- Mass Flow, pph ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.T- Temperature, FP- Pressure, psiaH- Enthalpy, Btu/lb T

TSYNGAS

MTP

FROM HRSG 2 H

M FROM HRSG 2TP

FROM HRSG 2 H TO HRSG 2

M MT TP PH H

Syngas Condensing& GTG Air Cooling196 MMBTU/hr

MTP Aux Cooling Water ReturnH M

TTO HRSG 2

COOLING TOWER 2186 MMBTU/hr

MTPH

MT

M ST LEAKS HT

Aux Cooling Water Supply

DATE MODEL REV.GSC

G HCN Hydrolysis Preheater and Saturator Pump Around Heater 311,661 96.5

86.0E

75

65

B

C 417.9501,323

Fuel Gas Heater

Stream IGCC Process Requirements Flow Out (lb/hr)

1,535570

1,632,8621,030

1,362

208

1,038

816,431

1,499

582

350,827

1624996 M

161,899 14.25

ASU, Selexol, Sour Water Reboiler Water Consumption

95,654

Syngas Cooler and SRU IP Steam Production

49386

1,537

1,034

232,018

2,162

GASIFICATION BLOCK AUX POWER, kW

GTG2 HEAT CONS, MMBTU/h (HHV)

2,162

GTG1 HEAT RATE, BTU/kWh (HHV)

267

POWER BLOCK AUX LOAD, kW 22,026

DESIGNED: J. SCHWARZ

50% PRB 50% PET COKE @ 43DB

177

1,848,329

EPRI / CPS Energy

115,159

07/21/2006

HEAT BALANCE DIAGRAM

596,993

NET CYCLE EFFICIENCY

2x1 7FB IGCC - Shell Gasification Process

8,946

38%

RELATIVE HUMIDITY, %

ELEVATION, FT

9,319

100

GTG2 OUTPUT, kW

STG OUTPUT, kW

232,018

GTG2 HEAT RATE, BTU/kWh (HHV)

270,141

PERFORMANCE SUMMARY

GTG1 OUTPUT, kW

GROSS PLANT OUTPUT, kW 734,177

DRY BULB TEMP, °F

WET BULB TEMP, °F 40

78%

43

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET PLANT OUTPUT, kW

TOTAL AUX POWER, kW 137,185

5,341TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

9,319

405

2,002

Hg Removal Preheater & Diluent N2 Heater70,866,496

4,175 6.71

F

TGTU HP Steam Requirements

26,370 25.4

Selexol and ASU IP Steam

D

701,6661,0311,9031,497

657,519721

SRU and TGTU LP Steam Production

BMCD PROJECT 42127

70,866,496

A

1556 MMBTU/hrProcess Duty (MMBtu/hr)

6,007 5.52

627

1.37 in HgA89 T652

27,822

BFP

D

LPSTHPST IPST

COMP TURB

STA

CK

HPS

HTR

HPE

VAP

RH

TR

HPE

CO

N

RH

TR

HPS

HTR

IPSH

TR

LPSH

TR

IPEV

AP

HPE

CO

N

IPEC

ON

LPEV

AP

PRH

TR

A

D C B

J

K D M

K

H

L

J

M

N

C A B

N

I

I

F

E

L H

E F

G

G

LEGEND COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THEM- Mass Flow, pph ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.T- Temperature, FP- Pressure, psiaH- Enthalpy, Btu/lb T

TSYNGAS

MTP

FROM HRSG 2 H

M FROM HRSG 2TP

FROM HRSG 2 H TO HRSG 2

M MT TP PH H

Syngas Condensing& GTG Air Cooling83 MMBTU/hr

MTP Aux Cooling Water ReturnH M

TTO HRSG 2

COOLING TOWER 2164 MMBTU/hr

MTPH

MT

M ST LEAKS HT

Aux Cooling Water Supply

DATE MODEL REV.GSC

G HCN Hydrolysis Preheater and Saturator Pump Around Heater 296,225 90.7

81.4E

75

65

B

C 392.5462,743

Fuel Gas Heater

Stream IGCC Process Requirements Flow Out (lb/hr)

1,550550

1,552,6561,057

1,369

163

1,061

776,328

1,513

561

349,246

1531101 M

152,890 13.38

ASU, Selexol, Sour Water Reboiler Water Consumption

90,058

Syngas Cooler and SRU IP Steam Production

53783

1,552

1,061

226,335

2,030

GASIFICATION BLOCK AUX POWER, kW

GTG2 HEAT CONS, MMBTU/h (HHV)

2,030

GTG1 HEAT RATE, BTU/kWh (HHV)

237

POWER BLOCK AUX LOAD, kW 21,867

DESIGNED: J. SCHWARZ

50% PRB 50% PET COKE @ 73DB

131

1,741,828

EPRI / CPS Energy

136,178

07/21/2006

HEAT BALANCE DIAGRAM

553,022

NET CYCLE EFFICIENCY

2x1 7FB IGCC - Shell Gasification Process

9,070

38%

RELATIVE HUMIDITY, %

ELEVATION, FT

8,971

100

GTG2 OUTPUT, kW

STG OUTPUT, kW

226,335

GTG2 HEAT RATE, BTU/kWh (HHV)

258,397

PERFORMANCE SUMMARY

GTG1 OUTPUT, kW

GROSS PLANT OUTPUT, kW 711,067

DRY BULB TEMP, °F

WET BULB TEMP, °F 69

82%

73

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET PLANT OUTPUT, kW

TOTAL AUX POWER, kW 158,045

5,016TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

8,971

405

2,004

Hg Removal Preheater & Diluent N2 Heater70,866,496

3,921 6.28

F

TGTU HP Steam Requirements

26,370 25.4

Selexol and ASU IP Steam

D

698,4921,0531,9041,511

655,324731

SRU and TGTU LP Steam Production

BMCD PROJECT 42127

70,866,496

A

1467 MMBTU/hrProcess Duty (MMBtu/hr)

5,512 5.18

605

2.18 in HgA104 T652

18,499

BFP

D

LPSTHPST IPST

COMP TURB

STA

CK

HPS

HTR

HPE

VAP

RH

TR

HPE

CO

N

RH

TR

HPS

HTR

IPSH

TR

LPSH

TR

IPEV

AP

HPE

CO

N

IPEC

ON

LPEV

AP

PRH

TR

A

D C B

J

K D M

K

H

L

J

M

N

C A B

N

I

I

F

E

L H

E F

G

G

LEGEND COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THEM- Mass Flow, pph ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.T- Temperature, FP- Pressure, psiaH- Enthalpy, Btu/lb T

TSYNGAS

MTP

FROM HRSG 2 H

M FROM HRSG 2TP

FROM HRSG 2 H TO HRSG 2

M MT TP PH H

Syngas Condensing& GTG Air Cooling80 MMBTU/hr

MTP Aux Cooling Water ReturnH M

TTO HRSG 2

COOLING TOWER 2195 MMBTU/hr

MTPH

MT

M ST LEAKS HT

Aux Cooling Water Supply

DATE MODEL REV.GSC

G HCN Hydrolysis Preheater and Saturator Pump Around Heater 292,901 87.9

79.1E

75

65

B

C 380.6449,026

Fuel Gas Heater

Stream IGCC Process Requirements Flow Out (lb/hr)

1,548540

1,527,9071,052

1,371

166

1,057

763,953

1,513

551

336,158

1508008 M

148,275 12.98

ASU, Selexol, Sour Water Reboiler Water Consumption

87,441

Syngas Cooler and SRU IP Steam Production

52781

1,550

1,056

216,963

1,969

GASIFICATION BLOCK AUX POWER, kW

GTG2 HEAT CONS, MMBTU/h (HHV)

1,969

GTG1 HEAT RATE, BTU/kWh (HHV)

238

POWER BLOCK AUX LOAD, kW 21,649

DESIGNED: J. SCHWARZ

50% PRB 50% PET COKE @ 93DB

135

1,713,230

EPRI / CPS Energy

132,813

07/21/2006

HEAT BALANCE DIAGRAM

528,165

NET CYCLE EFFICIENCY

2x1 7FB IGCC - Shell Gasification Process

9,209

37%

RELATIVE HUMIDITY, %

ELEVATION, FT

9,075

100

GTG2 OUTPUT, kW

STG OUTPUT, kW

216,963

GTG2 HEAT RATE, BTU/kWh (HHV)

248,701

PERFORMANCE SUMMARY

GTG1 OUTPUT, kW

GROSS PLANT OUTPUT, kW 682,628

DRY BULB TEMP, °F

WET BULB TEMP, °F 77

49%

93

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET PLANT OUTPUT, kW

TOTAL AUX POWER, kW 154,462

4,864TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

9,075

405

1,932

Hg Removal Preheater & Diluent N2 Heater70,866,496

3,802 6.12

F

TGTU HP Steam Requirements

26,370 25.4

Selexol and ASU IP Steam

D

672,3271,0501,8351,511

630,470733

SRU and TGTU LP Steam Production

BMCD PROJECT 42127

70,866,496

A

1450 MMBTU/hrProcess Duty (MMBtu/hr)

5,355 5.03

593

2.52 in HgA109 T646

18,876

BFP

D

LPSTHPST IPST

COMP TURB

STA

CK

HPS

HTR

HPE

VAP

RH

TR

HPE

CO

N

RH

TR

HPS

HTR

IPSH

TR

LPSH

TR

IPEV

AP

HPE

CO

N

IPEC

ON

LPEV

AP

PRH

TR

A

D C B

J

K D M

K

H

L

J

M

N

C A B

N

I

I

F

E

L H

E F

G

G

G-1

G O&M COST DETAIL

EPRI / CPS Energy2x1 7FB IGCC

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 2x1 7FB IGCC - 100% PRB2x1 7FB IGCC - 50% PRB / 50%

Pet CokeGreenfield \ Brownfield Greenfield GreenfieldBasis Year 2006 2006Plant Capacity Factor 85.0% 85.0%Hours per Year 7446 7446

Number of Gasifiers 2 2Number of Steam Turbines 1 1Boiler Output, (Net kW Each) 250,000 250,000

Normal OperationGross Gas Turbine Output, kW (Each) 224,869 226,335 Gross Steam Turbine Output, kW (Each) 260,134 258,397 Auxiliary Load, % 22.09% 22.23%Margin, % 0.00% 0.00%Net Unit Output, kW 553,072 553,022 Net Unit Heat Rate, Btu/kWh 9,220 9,069 Unit Fuel Consumption, MMBtu/hr 5,100 5,015

Net Facility Output, kW (Avg Ambient Conditions) 553,072 553,022 Net Facility Heat Rate, Btu/kWh 9,220 9,069

Net Annual Output, MWh (Total Facility) 4,118,174 4,117,804 Annual Fuel Consumption, MMBtu (Total Facility) 37,971,622 37,343,289

Coal Type EPRI UDBS PRB 50% PRB / 50% Pet Coke (by wt%)Boiler Technology IGCC IGCCType of Boiler Subcritical SubcriticalType of Feedwater Pump Drive Motor MotorType of NOx Control N2 Injection N2 InjectionType of SO2 Control Selexol SelexolType of Particulate Control N/A N/A

Type of Mercury Control Carbon Bed Carbon Bed Cooling Tower Materials of Construction Fiberglass FiberglassType of Sidestream Treatment None NoneFly Ash Disposal Landfill LandfillSlag Disposal Landfill Landfill

IGCC O&M.XLS Rev 3 1/28/05 Page 1 of 6 BURNS MCDONNELL

EPRI / CPS Energy2x1 7FB IGCC

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 2x1 7FB IGCC - 100% PRB2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

Fixed O&MLabor

# of People 126 People 126 PeopleAverage Salary $93,934/ Person $93,934/ PersonTotal Labor 11,835,700$ 11,835,700$

Office & Admin 118,400$ 118,400$ Other Fixed O&M 1,479,500$ 1,479,500$

Employee Expenses \ TrainingContract LaborEnvironmental ExpensesSafety ExpensesBuildings, Grounds, and PaintingOther Supplies & ExpensesCommunicationControl Room \ Lab Expenses

Annual Steam Turbine Inspections 100,000$ 100,000$ Annual Gasifier Inspections 100,000$ 100,000$ Annual Syngas Cooling and Treatment Inspections 200,000$ 200,000$

Start-up power demand charge -$ -$ $/kW-Mo -$ -$ kW 8,000 8,000

Water supply demand charge -$ -$ $/acre-ft -$ -$ acre-ft 6,832 7,172

Water discharge demand charge -$ -$ $/acre-ft -$ -$ acre-ft 1,581 1,632

Standby Power Energy Costs 98,600$ 98,600$ $/kWh 0.025$ 0.025$ kWh 3,942,000 3,942,000

Standby Power Service Fee -$ -$ $/Month -$ -$ Months 12 12

Property Taxes & Insurance By Owner By OwnerTotal Fixed O&M Annual Cost 13,932,200$ 13,932,200$

IGCC O&M.XLS Rev 3 1/28/05 Page 2 of 6 BURNS MCDONNELL

EPRI / CPS Energy2x1 7FB IGCC

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 2x1 7FB IGCC - 100% PRB2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

Emissions Allowance Costs - Included in Variable O&M

Emissions RatesNOx , lb/MMBtu 0.063 0.062SOx , lb/MMBtu 0.019 0.023CO2, lb/MMBtu 215 213HG, lb/MMBtu 7.769E-07 4.962E-07

Emissions - TPYNOx , TPY 1,196 1,158 SOx , TPY 361 429 CO2, TPY 4,086,517 3,980,767 HG, lb/year 29.50 18.53

Emissions Allowance CostsNOx Allowance, $/ton-yr $3,000 $3,000SOx Allowance, $/ton-yr $1,000 $1,000CO2 Allowance, $/ton-yr $0 $0HG Allowance, $/lb-yr $20,000 $20,000

Total Emissions Allowance Costs, $/yrNOx Allowance Cost 3,588,300$ 3,472,900$ SOx Allowance Cost 360,700$ 429,400$ CO2 Allowance Cost -$ -$ HG Allowance Cost 590,000$ 370,600$

Total Annual Emissions Allowance Costs 4,539,000$ 4,272,900$

IGCC O&M.XLS Rev 3 1/28/05 Page 3 of 6 BURNS MCDONNELL

EPRI / CPS Energy2x1 7FB IGCC

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 2x1 7FB IGCC - 100% PRB2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

Major Maintenance Costs - Included in Variable O&MSteam Turbine / Generator Overhaul 260,400$ 260,400$

Operating Hours 7446 7446$/Turbine Hour 35$ 35$

HRSG Major Replacements 200,000$ 200,000$ $/Boiler - Yr $100,000 $100,000# of Boilers 2 2

Gasifier Major Replacements 885,800$ 765,900$ $/Replacement $885,765 $765,893Replacement Interval, years 1 1

Candle Filter Major Replacements 300,000$ 300,000$ $/Replacement $1,500,000 $1,500,000Replacement Interval, years 5 5

Gas Turbine Major Replacements 8,148,685$ 8,148,685$ $/Replacement $885,765 $765,893$/Gas Turbine Hour 547 547

Syngas Treatment Major Replacements 375,000$ 395,000$ $/Replacement $375,000 $395,000Replacement Interval, years 1 1

Air Separation Unit 275,000$ 275,000$ $/Replacement $275,000 $275,000Replacement Interval, years 1 1

Mercury Carbon Bed Replacements 530,300$ 530,300$ $/Replacement $1,060,666 $1,060,666Replacement Interval, years 2 2

COS Hydrolysis Catalyst 320,000$ 320,000$ $/Catalyst $960,000 $960,000Catalyst Life, years 3 3

HCN Hydrolysis Catalyst 320,000$ 320,000$ $/Catalyst $960,000 $960,000Catalyst Life, years 3 3

Shift Catalyst -$ -$ $/Catalyst $0 $0Catalyst Life, years 3 3

Demin Water Treatment System Replacements 3,600$ 3,600$

Total Annual Major Maintenance Costs 11,618,785$ 11,518,885$

IGCC O&M.XLS Rev 3 1/28/05 Page 4 of 6 BURNS MCDONNELL

EPRI / CPS Energy2x1 7FB IGCC

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 2x1 7FB IGCC - 100% PRB2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

Other Variable O&MWater Consumption, MMGal/yr

Raw Water Makeup, MMGal/yr 2,226 2,337Raw Water Makeup Treatment, MMGal/yr 2,226 2,337Zero Liquid Discharge Treatment, MMGal/yr 0 0Potable Water, MMGal/yr 1 1Wastewater Discharge, MMGal/yr 515.11 531.64Cooling Tower Makeup, MMGal/yr 2,100 2,170Demin Water Makeup Treatment, MMGal/yr 38 38Boiler Treatment Makeup Treatment, MMGal/yr 20 20

Water Consumable \ Treatment Costs, $/kGalRaw Water, $/kGal $0.04 $0.04Raw Water Makeup Treatment, $/kGal $0.01 $0.01Zero Liquid Discharge Treatment, $/kGal $0.00 $0.00Potable Water, $/kGal $1.00 $1.00Wastewater Discharge, $/kGal $0.05 $0.05Cooling Tower Makeup, $/kGal $0.55 $0.55Demin Water Treatment, $/kGal $1.05 $1.05Boiler Treatment Chemicals, $/kGal $7.4500 $7.4500

Total Water Related CostsRaw Water 92,000$ 96,500$ Raw Water Make-up Treatment 11,100$ 11,700$ Zero Liquid Discharge Treatment Chemicals -$ -$ Potable Water 1,500$ 1,500$ Water Discharge 25,800$ 26,600$ Cooling Tower Treatment Chemicals 1,159,300$ 1,198,000$ Demin Water Treatment 39,700$ 39,700$ Boiler Treatment Chemicals 149,700$ 149,700$

Maintenance & Consumables (lube oil, nitrogen, hydrogen, etc.)ZLD System General Maintenance

Membrane Replacements, $/yr $0 $0General Maintenance, $/yr

Water Treatment System General Maintenance, $/yr $60,100 $60,100Cooling Tower System General Maintenance, $/unit-yr $45,100 $44,800Other Variable O&M (Electronics, Controls, BOP Electrical, Steam Generators, Misc.) $5,192,238 $5,250,717

IGCC O&M.XLS Rev 3 1/28/05 Page 5 of 6 BURNS MCDONNELL

EPRI / CPS Energy2x1 7FB IGCC

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 2x1 7FB IGCC - 100% PRB2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

Other Variable O&M - (Cont.)

Consumable Consumption \ Disposal RatesSCR Ammonia (Anhydrous), TPY 0 0Sulfur, TPY 8,390 58,728Fly Ash / Slag Sales, TPY 0 0Fly Ash / Slag Disposal, TPY 138,213 56,884

Consumable \ Disposal Unit CostsSCR Ammonia (Anhydrous), $/ton $657.89 $657.89Sulfur, $/ton $0.00 $0.00Fly Ash / Slag Sales, $/ton $0.00 $0.00Fly Ash / Slag Disposal, $/ton $11.29 $11.29

Total Consumable \ Disposal CostsSCR Ammonia (Anhydrous) -$ -$ Sulfur Sales / Disposal -$ -$ Fly Ash / Slag Sales -$ -$ Fly Ash / Slag Disposal 1,560,200$ 642,100$

Total Other Variable O&M 8,336,738$ 7,521,417$

Total Fixed O&M Cost$/year 13,932,200$ 13,932,200$ $/kW-yr 25.19$ 25.19$

Total Variable O&M Cost$/year 24,494,523$ 23,313,202$ $/MWh 5.95$ 5.66$

IGCC O&M.XLS Rev 3 1/28/05 Page 6 of 6 BURNS MCDONNELL

EPRI / CPS Energy550 MW Supercritical PC - 100% PRB

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 550 PC-Wet Tower / Wet Scrubber - GreenfieldGreenfield \ Brownfield GreenfieldBasis Year 2006Plant Capacity Factor 85.0%Hours per Year 7446

Number of Boilers 1Number of Steam Turbines 1Boiler Output, (Net kW Each) 550,000Steam Turbine Output, (Net kW Each) 550,000Net Facility Output, kW 550,000

Normal OperationGross Steam Turbine Output, kW (Each) 614,525 Gross Steam Turbine Heat Rate 6,986 Auxiliary Load, % 10.50%Margin, % 0.00%Net Unit Output, kW 550,000 Net Unit Heat Rate, Btu/kWh 9,149 Unit Fuel Consumption, MMBtu/hr 5,032

Net Facility Output, kW (Avg Ambient Conditions) 550,000 Net Facility Heat Rate, Btu/kWh 9,149

Net Annual Output, MWh (Total Facility) 4,095,300 Annual Fuel Consumption, MMBtu (Total Facility) 37,468,109

Coal Type EPRI UDBS PRBBoiler Technology Pulverized CoalType of Boiler SupercriticalType of Feedwater Pump Drive MotorType of NOx Control SCRType of SO2 Control WetType of Particulate Control Fabric Filter

Type of Mercury Control Fabric Filter / Wet Scrubber Cooling Tower Materials of Construction FiberglassType of Sidestream Treatment NoneFly Ash Disposal LandfillGypsum Disposal LandfillBottom Ash Disposal Landfill

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05 Page 1 of 5 BURNS MCDONNELL

EPRI / CPS Energy550 MW Supercritical PC - 100% PRB

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 550 PC-Wet Tower / Wet Scrubber - Greenfield

Fixed O&MLabor

# of People 103 PeopleAverage Salary $94,056/ PersonTotal Labor 9,687,800$

Office & Admin 96,900$ Other Fixed O&M 1,211,000$

Employee Expenses \ TrainingContract LaborEnvironmental ExpensesSafety ExpensesBuildings, Grounds, and PaintingOther Supplies & ExpensesCommunicationControl Room \ Lab Expenses

Annual Steam Turbine Inspections 100,000$ Annual Boiler Inspections 80,000$ Annual APC Inspections 100,000$

Start-up power demand charge -$ $/kW-Mo -$ kW 64,200

Water supply demand charge -$ $/acre-ft -$ acre-ft 7,541

Water discharge demand charge -$ $/acre-ft -$ acre-ft 1,632

Standby Power Energy Costs 98,600$ $/kWh 0.025$ kWh 3,942,000

Standby Power Service Fee -$ $/Month -$ Months 12

Property Taxes & Insurance By OwnerTotal Fixed O&M Annual Cost 11,374,300$

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05 Page 2 of 5 BURNS MCDONNELL

EPRI / CPS Energy550 MW Supercritical PC - 100% PRB

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 550 PC-Wet Tower / Wet Scrubber - Greenfield

Emissions Allowance Costs - Included in Variable O&M

Emissions RatesNOx , lb/MMBtu 0.050SOx , lb/MMBtu 0.060CO2, lb/MMBtu 213.5HG, lb/MMBtu 2.315E-06

Emissions - TPYNOx , TPY 937 SOx , TPY 1,128 CO2, TPY 3,998,878 HG, lb/year 86.73

Emissions Allowance CostsNOx Allowance, $/ton-yr $3,000SOx Allowance, $/ton-yr $1,000CO2 Allowance, $/ton-yr $0HG Allowance, $/lb-yr $20,000

Total Emissions Allowance Costs, $/yrNOx Allowance Cost 2,810,100$ SOx Allowance Cost 1,127,900$ CO2 Allowance Cost -$ HG Allowance Cost 1,734,700$

Total Annual Emissions Allowance Costs 5,672,700$

Major Maintenance Costs - Included in Variable O&MSteam Turbine / Generator Overhaul 339,200$

Operating Hours 7446$/Turbine Hour 46$

Steam Generator Major Replacements 893,900$ $/Boiler - Yr $893,900# of Boilers 1

Baghouse Bag Replacement 253,400$ $/Replacement $1,266,900Replacement Interval, years 5

SCR Catalyst Replacement 312,000$ $/Catalyst $936,100Catalyst Life, years 3

Demin Water Treatment System Replacements 4,300$

Total Annual Major Maintenance Costs 1,802,800$

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05 Page 3 of 5 BURNS MCDONNELL

EPRI / CPS Energy550 MW Supercritical PC - 100% PRB

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 550 PC-Wet Tower / Wet Scrubber - Greenfield

Other Variable O&MWater Consumption, MMGal/yr

Raw Water Makeup, MMGal/yr 2,457Raw Water Makeup Treatment, MMGal/yr 2,457Zero Liquid Discharge Treatment, MMGal/yr 0Potable Water, MMGal/yr 1Wastewater Discharge, MMGal/yr 532Cooling Tower Makeup, MMGal/yr 2,170Demin Water Makeup Treatment, MMGal/yr 61Boiler Treatment Makeup Treatment, MMGal/yr 43

Water Consumable \ Treatment Costs, $/kGalRaw Water, $/kGal $0.041Raw Water Makeup Treatment, $/kGal $0.005Zero Liquid Discharge Treatment, $/kGal $0.000Potable Water, $/kGal $1.000Wastewater Discharge, $/kGal $0.050Cooling Tower Makeup, $/kGal $0.642Demin Water Treatment, $/kGal $1.050Boiler Treatment Chemicals, $/kGal $3.730

Total Water Related CostsRaw Water 101,500$ Raw Water Make-up Treatment 12,300$ Zero Liquid Discharge Treatment Chemicals -$ Potable Water 1,500$ Water Discharge 26,600$ Cooling Tower Treatment Chemicals 1,393,400$ Demin Water Treatment 63,600$ Boiler Treatment Chemicals 160,600$

Maintenance & Consumables (lube oil, nitrogen, hydrogen, etc.)ZLD System General Maintenance

Membrane Replacements, $/yr $0General Maintenance, $/yr

SCR System General MaintenanceGeneral Maintenance, $./unit-yr $64,200

Scrubber System General MaintenanceAbsorber, Dewatering & Accessories, $/unit-yr $120,700Limestone Preparation, $/yr $342,400

Water Treatment System General Maintenance, $/yr $59,800Cooling Tower System General Maintenance, $/unit-yr $47,700Other Variable O&M (Electronics, Controls, BOP Electrical, Steam Generators, Misc.) $5,000,000

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05 Page 4 of 5 BURNS MCDONNELL

EPRI / CPS Energy550 MW Supercritical PC - 100% PRB

Operations and Maintenance EstimatesBMcD Project: 42127

Operating Assumptions 550 PC-Wet Tower / Wet Scrubber - Greenfield

Other Variable O&M - (Cont.)

Consumable Consumption \ Disposal RatesLime Consumption, TPY - Limestone Consumption, TPY 29,150SCR Ammonia (Anhydrous), TPY 1,584Halogenated Carbon Injection, TPY 0

Scrubber Sludge (Sales) / Disposal, TPY 56,228Fly Ash Sales, TPY 0Fly Ash Disposal, TPY 125,137Bottom Ash (Sales) / Disposal, TPY 31,172

Consumable \ Disposal Unit CostsLime Consumption, $/ton $86.00Limestone Consumption, $/ton $18.00SCR Ammonia (Anhydrous), $/ton $658Halogenated Carbon Injection, $/ton $1,545

Scrubber Sludge (Sales) / Disposal, $/ton $11.29Fly Ash Sales, $/ton $0.00Fly Ash Disposal, $/ton $11.29Bottom Ash (Sales) / Disposal, $/ton $11.29

Total Consumable \ Disposal CostsLime Consumption -$ Limestone Consumption 524,700$ SCR Ammonia (Anhydrous) 1,041,800$ Halogenated Carbon Injection -

Scrubber Sludge (Sales) / Disposal 634,700$ Fly Ash Sales -$ Fly Ash Disposal 1,412,600$ Bottom Ash (Sales) / Disposal 351,900$

Total Other Variable O&M 11,360,000$

Total Fixed O&M Cost$/year 11,374,300$ $/kW-yr 20.68$

Total Variable O&M Cost$/year 18,835,500$ $/MWh 4.60$

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05 Page 5 of 5 BURNS MCDONNELL

H-1

H SYSTEM OF INTERNATIONAL UNITS CONVERSION TABLE

The heat and material balances included in this report are shown in British (English) units. The following table can be used for conversion to SI units.

British Unit Metric Equivalent P, absolute pressure, psia, multiply by 6.895 x10-3 = MPa (megapascals) °F, temperature, (F minus 32) divided by 1.8 = °C (Centigrade) H, enthalpy, Btu/lb, multiply H by 2.3260 = kJ/kg (kilojoules/kilogram) W, total mass flow, lb/h, multiply W by 0.4536 = kg/h (kilogram/hour) Heat rate, Btu/kWh, multiply Btu/kWh by 1.0551 = kJ/kWh (kilojoules/kilowatt-hour) Air emissions, lb/MMBtu, multiply by 429.9 = kg/GJ (kilogram/gigajoule) Flow, gal/minute, multiply by 0.06309 = l/s (liters/second)

ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 • PO Box 10412, Palo Alto, California 94303-0813 • USA

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Access to and use of EPRI Intellectual Property is granted with the specific understanding and requirement that responsibility for ensuring full compliance with all applicable U.S. and foreign export laws and regulations is being undertaken by you and your company. This includes an obligation to ensure that any individual receiving access hereunder who is not a U.S. citizen or permanent U.S. resident is permitted access under applicable U.S. and foreign export laws and regulations. In the event you are uncertain whether you or your company may lawfully obtain access to this EPRI Intellectual Property, you acknowledge that it is your obligation to consult with your company’s legal counsel to determine whether this access is lawful. Although EPRI may make available on a case-by-case basis an informal assessment of the applicable U.S. export classification for specific EPRI Intellectual Property, you and your company acknowledge that this assessment is solely for informational purposes and not for reliance purposes. You and your company acknowledge that it is still the obligation of you and your company to make your own assessment of the applicable U.S. export classification and ensure compliance accordingly. You and your company understand and acknowledge your obligations to make a prompt report to EPRI and the appropriate authorities regarding any access to or use of EPRI Intellectual Property hereunder that may be in violation of applicable U.S. or foreign export laws or regulations.

The Electric Power Research Institute (EPRI)

The Electric Power Research Institute (EPRI), with major locations in Palo Alto, California, and Charlotte, North Carolina, was established in 1973 as an independent, nonprofit center for public interest energy and environmental research. EPRI brings together members, participants, the Institute’s scientists and engineers, and other leading experts to work collaboratively on solutions to the challenges of electric power. These solutions span nearly every area of electricity generation, delivery, and use, including health, safety, and environment. EPRI’s members represent over 90% of the electricity generated in the United States. International participation represents nearly 15% of EPRI’s total research, development, and demonstration program.

Together…Shaping the Future of Electricity

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