# Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture

Revision 1

– September 19 , 2013 Original

– May 27 , 201 1

DOE/NETL

- 2011/1498Carbon Dioxide Capture Sensitivity Analysis



# Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes a ny legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commer cial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of a uthors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.Carbon Dioxide Capture Sensitivity Analysis



# Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture

DOE/NETL

- 2011 / 1498

Revision 1

– September 1 9 , 2013 Original

– May 27 , 2011

NETL Contact:
Kristin Gerdes Office of Program, Planning and Analysis

Prepared by: Research and Development Solutions, LLC (RDS) James B. Black, formerly of Parsons Corporation John L. Haslbeck, formerly of Parsons Corporation Andrew P. Jones , formerly of Science Applications International Corporation Wayne L. Lundberg , formerly of Science Applications International Corporation Vasant Shah, formerly of Parsons Corporation

Updated by: Energy Sector Planning and Analysis (ESPA) Allison Kyle, Booz Allen Hamilton

Eric Lewis, Booz Allen Hamilton

National Energy Technology Laboratory www.netl.doe.govCarbon Dioxide Capture Sensitivity Analysis



# Acknowledgments
This report was initially prepared by Research and Development Solutions, LLC (RDS) for the United States Department of Energy (DOE) National Energy Technology Laboratory (NETL). The report was updated by the Energy Sector Planning and Analysis (ESPA) for DOE NETL . This work was completed
un der DOE NETL Contract Number DE

- FE0004001 . This work was performed under ESPA T ask 410.01.

The authors wish to acknowledge the excellent guidance, contributions, and cooperation of the NETL staff, particularly:

Eric Grol , NETL Technical Monitor



# Revision Control

Revision 1: The Executive Summary and Section 2.7.1 were revised to correct and clarify text that explains the level of technology maturity reflected in the plant level cost estimates.Carbon Dioxide Capture Sensitivity Analysis 

# Table o f Contents
TABLE OF CONTENTS

................................ ................................ ................................ .............. I LIST OF EXHIBITS

................................ ................................ ................................ .................. III LIST OF ACRONYMS AND ABBREVIATIONS

................................ ................................ .... X EXECUTIVE SUMMARY

................................ ................................ ................................ ........... 1 P ULVERIZED 

## C OAL 

## P LANTS



## ................................ ................................ ................................ .......... 1 IGCC P LANTS



## ................................ ................................ ................................ ............................... 3 R ESULTS



## ................................ ................................ ................................ ................................ ....... 6 Performance

................................ ................................ ................................ ................................ ........................ 6 Economics

................................ ................................ ................................ ................................ ............................ 8 Cost and Performance Summary

................................ ................................ ................................ ....................... 14 

## 1. INTRODUCTION

................................ ................................ ................................ ................ 19 1.1 S TUDY 

## B A CKGROUND



## ................................ ................................ ................................ ..... 19 1.2 P ROJECT 

## O BJECTIVES



## ................................ ................................ ................................ ...... 19 2. GENERAL EVALUATION B ASIS

................................ ................................ ................... 21 2.1 S ITE 

## C HARACTERISTICS



## ................................ ................................ ................................ .. 25 2.2 C OAL 

## C HARACTERISTICS AND 

## C OST



## ................................ ................................ ............... 27 2.3 D ESIGN 

## S ORBENT 

## C OMPOSITION



## ................................ ................................ ..................... 31 2.4 E NVIRONMENTAL 

## T ARGETS



## ................................ ................................ ............................ 31 2.4.1 Supercritical PC Plant

................................ ................................ ................................ ........................ 32 2.4.2 GEE IGCC Plant

................................ ................................ ................................ ................................ . 33 2.4.3 Ca rbon Dioxide

................................ ................................ ................................ ................................ ... 33 

## 2.5 C APACITY 

## F ACTOR



## ................................ ................................ ................................ ......... 34 2.6 R AW 

## W ATER 

## W ITHDRAWAL



## ................................ ................................ ........................... 35 2.7 C OST 

## E STIMATING 

## M ETHODOLOGY



## ................................ ................................ ................ 35 2.7.1 Capital Costs

................................ ................................ ................................ ................................ ....... 35 2.7.2 System Code

- of

- Accounts

................................ ................................ ................................ .................... 38 2.7.3 CO 2 

### Removal Plant Maturity

................................ ................................ ................................ .............. 38 2.7.4 Contracting Strategy

................................ ................................ ................................ ........................... 38 2.7.5 Estimate Scope

................................ ................................ ................................ ................................ .... 38 2.7.6 Capital Cost Assumptions

................................ ................................ ................................ ................... 39 2.7.7 Operations and Maintenance Costs

................................ ................................ ................................ .... 45 2.7.8 CO 2 

### Transport, Storage and Monitoring

................................ ................................ ............................. 46 2.7.9 Finance Structure, Discounted Cash Flow Analysis, and COE

................................ .......................... 50 

## 2.8 IGCC S TUDY 

## C OST 

## E STIMATES 

## C OMPARED TO 

## I NDUSTRY 

## E STIMATES



## .......................... 54 3. CASE 1

- SUPERCRITICAL PC WIT H VARIABLE CO 2 

## CAPTURE

........................ 57 3.1 S YSTEM 

## D ESCRIPTIONS



## ................................ ................................ ................................ ... 57 3.1.1 Coal and Sorbent Receiving and Storage

................................ ................................ ............................ 57 3.1.2 Steam Generator and Ancillaries

................................ ................................ ................................ ........ 57 3.1.3 NO x 

### Control System

................................ ................................ ................................ ............................. 60 3.1.4 Particulate Control

................................ ................................ ................................ ............................. 60 3.1.5 Flue Gas Desulfurization

................................ ................................ ................................ .................... 61 3.1.6 Flue Gas System/Stack

................................ ................................ ................................ ........................ 65 3.1.7 Carbon Dioxide Recovery Facility

................................ ................................ ................................ ...... 65 3.1.8 Steam Turbine Generator System

................................ ................................ ................................ ........ 69 3.1.9 Balance of Plant

................................ ................................ ................................ ................................ .. 70 3.1.10 Accessory Electric Plant

................................ ................................ ................................ ..................... 74 3.1.11 Instrumentation and Control

................................ ................................ ................................ ............... 74 

## 3.2 S UPERCRITICAL 

## PC CO 2 

## C APTURE 

## S ENSITIVITY



## ................................ ............................. 74 3.2.1 CO 2 

### Capture with Partial Bypass Performance Results

................................ ................................ ..... 77 3.2.2 Full CO 2 

### Capture Performance Res ults

................................ ................................ ............................ 117 3.2.3 Economic Analysis for the Supercritical PC Cases

................................ ................................ ........... 151



## iCarbon Dioxide Capture Sensitivity Analysis 

### 3.2.4 Capital and Operating Cost Results

................................ ................................ ................................ .. 151 3.2.5 Supercritical PC Cost and Performance Summary

................................ ................................ ........... 187 

## 4. CASE 2

– GEE IGCC WITH VARIAB LE CO 2 

## CAPTURE

................................ ......... 189 4.1 G ASIFIER 

## B ACKGROUND



## ................................ ................................ ............................... 190 4.2 P ROCESS 

## D ESCRIPTION



## ................................ ................................ ................................ . 192 4.2.1 Coal Receiving and Storage

................................ ................................ ................................ .............. 192 4.2.2 Coal Grinding and Slurry Preparation

................................ ................................ ............................. 192 4.2.3 Air Separation Unit (ASU) Choice and Integration

................................ ................................ .......... 193 4.2.4 Gasification

................................ ................................ ................................ ................................ ....... 197 4.2.5 Raw Gas Cooling/Particulate Removal

................................ ................................ ............................ 197 4.2.6 Syngas Scrubber/Sour Water Stripper

................................ ................................ ............................... 198 4.2.7 Water Gas Shift Reactors

................................ ................................ ................................ .................. 198 4.2.8 Mercury Removal

................................ ................................ ................................ .............................. 199 4.2.9 Acid Gas Removal (AGR) Process Selection

................................ ................................ ..................... 200 4.2.10 CO 2 

### Compression and Dehydration

................................ ................................ ................................ .. 208 4.2.11 Sulfur Recovery/Tail Gas Cleanup Process Selection

................................ ................................ ....... 208 4.2.12 Slag Handling

................................ ................................ ................................ ................................ .... 211 4.2.13 Power Island

................................ ................................ ................................ ................................ ..... 212 4.2.14 S team Generation Island

................................ ................................ ................................ ................... 218 4.2.15 Accessory Electric Plant

................................ ................................ ................................ ................... 221 4.2.16 Instrumentation and Control

................................ ................................ ................................ ............. 222 

## 4.3 GEE IGCC CO 2 

## C APTURE 

## S ENSITIVITY



## ................................ ................................ ....... 222 4.3.1 IGCC Design 1

– Without Water Gas Shift

................................ ................................ ....................... 224 4.3.2 IGCC Design 2

– Single Water Gas Shift Reactor

................................ ................................ ............ 257 4.3.3 IGCC Design 3

– Two Water Gas Shift Reactors with Bypass

................................ .......................... 303 4.3.4 IGCC Design 4

– Two Water Gas Shift Reactors Without Bypass

................................ .................... 357 4.3.5 Economic Analysis for the GEE IGCC Cases

................................ ................................ ................... 395 4.3.6 Capital and Operating Cost Results

................................ ................................ ................................ .. 395 4. 3.7 GEE IGCC Cost and Performance Summary

................................ ................................ ................... 467 

## 5. RESULTS

................................ ................................ ................................ ........................... 469 5.2 P ERFORMANCE



## ................................ ................................ ................................ .............. 469 5.2.1 Energy Efficiency

................................ ................................ ................................ .............................. 469 

## 5.3 E CONOMICS



## ................................ ................................ ................................ .................. 471 5.3.1 Total Overnight Cost

................................ ................................ ................................ ......................... 471 5.3.2 Cost of Electricity

................................ ................................ ................................ .............................. 473 5.3.3 CO 2 

### Avoided Costs

................................ ................................ ................................ ............................ 476 

## 5.4 C OST AND 

## P ERFORMANCE 

## S UMMARY



## ................................ ................................ ........... 478 5.4.1 Supercritical PC Cases

................................ ................................ ................................ ..................... 47 8 5.4.2 GEE IGCC Cases

................................ ................................ ................................ .............................. 479 5.4.3 SCPC and IGCC Comparisons

................................ ................................ ................................ ......... 479 

## APPENDIX A

................................ ................................ ................................ ............................. 483 Supercritical PC Cost Algorithms

................................ ................................ ................................ ................... 484 GEE IGCC Cost Algorithms

................................ ................................ ................................ ............................ 489 

## 6. REFERENCES

................................ ................................ ................................ ................... 495

iiCarbon Dioxide Capture Sensitivity Analysis 

# List o f Exhibits
Exhibit ES

- 1 Case 1 Supercritical PC Plant Configuration Summary

................................ .......................... 2 Exhibit ES

- 2 Case 2 GEE IGCC Plant Configuration Summary

................................ ................................ .. 4 Exhibit ES

- 3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO 2 

## Removal with IGCC Design 3

................................ ................................ ................................ ................................ ........ 5 Exhibit ES

- 4 Process Configurations for IGCC D2

................................ ................................ ...................... 5 Exhibit ES

- 5 Process Configurations for IGCC D3

................................ ................................ ...................... 6 Exhibit ES

- 6 Supercritical PC Net Plant Efficiency (HHV)

................................ ................................ ......... 7 Exhibit ES

- 7 IGCC Net Plant Efficiency (HHV)

................................ ................................ .......................... 8 Exhibit ES

- 8 Supercriti cal PC Total Overnight Cost

................................ ................................ .................... 9 Exhibit ES

- 9 IGCC Total Overnight Cost

................................ ................................ ................................ ... 10 Exhibit ES

- 10 Supercritical PC Cost of Electricity

................................ ................................ ..................... 11 Exhibit ES

- 11 IGCC Cost of Electricity

................................ ................................ ................................ ...... 12 Exhibit ES

- 12 Supercritical PC CO 2 

## Avoided Costs

................................ ................................ ................... 13 Exhibit ES

- 13 IGCC CO 2 

## Avoided Costs

................................ ................................ ................................ .... 14 Exhibit ES

- 14 Cost and Performance Results for the Supercritical PC Cases

................................ ............ 16 Exhibit ES

- 15 Cost and Performance Result s for the GEE IGCC Cases

................................ .................... 17 Exhibit 2

- 1 Case 1 Supercritical PC Plant Configuration Summary

................................ ........................... 21 Exhibit 2

- 2 Case 2 GEE IGCC Plant Configuration Summary

................................ ................................ ... 23 Exhibit 2

- 3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO 2 

## Removal with IGCC Design 3

................................ ................................ ................................ ................................ ...... 24 Exhibit 2

- 4 Process Configurations for IGCC D2

................................ ................................ ....................... 24 Exhibit 2

- 5 Process Configurations for IGCC D3

................................ ................................ ....................... 25 Exhibit 2

- 6 Site Ambient Conditions

................................ ................................ ................................ ........... 26 Exhibit 2

- 7 Site Characteristics

................................ ................................ ................................ ................... 26 Exhibit 2

- 8 Design Coal

................................ ................................ ................................ .............................. 27 Exhi bit 2

- 9 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

......................... 30 Exhibit 2

- 10 Sorbent Analysis

................................ ................................ ................................ ..................... 31 Exhibit 2

- 11 Standards of Performance for Electric Utility Steam Generating Units

................................ . 32 Exhibit 2

- 12 Environmental Targets for PC Cases

................................ ................................ ...................... 33 Exhibit 2

- 13 Environmental Targets for IGCC Cases

................................ ................................ ................. 33 Exhibit 2

- 14 Capital Cost Levels and their Elements

................................ ................................ .................. 36 Exhibit 2

- 15 Features of an AACE Class 4 Cost Estimate

................................ ................................ .......... 37 Exhibit 2

- 16 AACE Guidelines for Process Contingency

................................ ................................ ........... 41 Exhibit 2

- 17 TASC/TOC Factors

................................ ................................ ................................ ................. 42 Exhibit 2

- 18 Owner’s Costs Included in TOC

................................ ................................ ............................. 43 Exhibit 2

- 19 CO 2 

## Pipeline Specification

................................ ................................ ................................ ..... 47 Exhibit 2

- 20 Deep, Saline Aquifer Specification

................................ ................................ ........................ 48 Exhibit 2

- 21 Global Economic Assumptions

................................ ................................ .............................. 51 Exhibit 2

- 22 Financial Structure for Investor Owned Utility Hig h Risk Projects

................................ ....... 52 Exhibit 2

- 23 Capital Charge Factors for COE Equation

................................ ................................ ............. 53 Exhibit 3

- 1 Typical B&W Wet FGD Process Flow Diagram

................................ ................................ ..... 62 Exhibit 3

- 2 Wet Scrubber Arrangement

................................ ................................ ................................ ...... 63 Exhibit 3

- 3 Fluor Econamine FG Plus SM 

## Typical Flow Diagram

................................ ............................... 67 Exhibit 3

- 4 CO 2 

## Compressor Interstage Pressures

................................ ................................ ...................... 69 Exhibit 3

- 5 Supercritical PC Combustion Configuration Modeling Assumptions

................................ ...... 76 Exhibit 3

- 6 Cases 1A Through 1D Process Block Flow Diagram, Supercritical PC with CO 2 

## Capture Bypass

................................ ................................ ................................ ................................ ................... 78

iiiCarbon Dioxide Capture Sensitivity Analysis 

## Exhibit 3

- 7 Case 1A Stream Table, Supercritical PC with 30% CO 2 

## Capture

................................ ............ 79 Exhibit 3

- 8 Case 1B Stream Table, Supercritical PC with 50% CO 2 

## Capture

................................ ............ 81 Exhibit 3

- 9 Case 1C Stream Table, Supercritical PC with 70% CO 2 

## Capture

................................ ............ 83 Exhibit 3

- 10 Case 1D Stream Table, Supercritical PC with 85% CO 2 

## Capture

................................ .......... 85 Exhibit 3

- 11 Cases 1A Through 1D Performance Modeling Results

................................ .......................... 87 Exhibit 3

- 12 Cases 1A through 1D Estimated Air Emission Rates

................................ ............................. 90 Exhibit 3

- 13 Cases 1A through 1D Carbon Balance

................................ ................................ ................... 91 Exhibit 3

- 14 Cases 1A through 1D Sulfur Balan ce

................................ ................................ ..................... 91 Exhibit 3

- 15 Case 1A (30%) Water Balance

................................ ................................ ............................... 92 Exhibit 3

- 16 Case 1B (50%) Water Balance

................................ ................................ ............................... 92 Exhibit 3

- 17 Case 1C (70%) Water Balance

................................ ................................ ............................... 93 Exhibit 3

- 18 Case 1D (85%) Water Balance

................................ ................................ ............................... 93 Exhibit 3

- 19 Case 1A (30%) Heat and Mass Balance, Supercritical PC Bo iler and Gas Cleanup Systems 95 Exhibit 3

- 20 Case 1A (30%) Heat and Mass Balance, Power Block Systems

................................ ............ 96 Exhibit 3

- 21 Case 1B (50%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems 97 Exhibit 3

- 22 Case 1B (50%) Heat and Mass Balance, Power Block Systems

................................ ............ 98 Exhibit 3

- 23 Case 1C (70%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems 99 Exhibit 3

- 24 Case 1C (70%) Heat and Mass Balance, Power Block Systems

................................ .......... 100 Exhibit 3

- 25 Case 1D (85%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

................................ ................................ ................................ ................................ ............................. 101 Exhibit 3

- 26 Case 1D (85%) Heat and Mass Balance, Power Block Systems

................................ .......... 102 Exhibit 3

- 27 Case 1A (30%) Energy Balance

................................ ................................ ........................... 103 Exhibit 3

- 28 Case 1B (50%) Energy Balance

................................ ................................ ........................... 104 Exhibit 3

- 29 Case 1C (70%) Energy Balance

................................ ................................ ........................... 105 Exhibit 3

- 30 Case 1D (85%) Energy Balance

................................ ................................ ........................... 106 Exhibit 3

- 31 Case 1A Energy Balan ce Sankey Diagram

................................ ................................ .......... 107 Exhibit 3

- 32 Case 1B Energy Balance Sankey Diagram

................................ ................................ ........... 107 Exhibit 3

- 33 Case 1C Energy Balance Sankey Diagram

................................ ................................ ........... 108 Exhibit 3

- 34 Case 1D Energy Balance Sankey Diagram

................................ ................................ .......... 108 Exhibit 3

- 35 Cases 1E through 1G Process Block Fl ow Diagram, Supercritical PC with CO 2 

## Capture

.. 118 Exhibit 3

- 36 Case 1E Stream Table, Supercritical PC with 90% CO 2 

## Capture

................................ ........ 119 Exhibit 3

- 37 Case 1F Stream Table, Supercritical PC with 95% CO 2 

## Capture

................................ ......... 121 Exhibit 3

- 38 Case 1G Stream Table, Supercritical PC with 99% CO 2 

## Capture

................................ ........ 123 Exhibit 3

- 39 Cases 1E through 1G Performance Modeling Results

................................ ......................... 125 Exhibit 3

- 40 Cases 1E through 1 G Estimated Air Emission Rates

................................ ........................... 128 Exhibit 3

- 41 Cases 1E through 1G Carbon Balance

................................ ................................ .................. 129 Exhibit 3

- 42 Cases 1E through 1G Sulfur Balance

................................ ................................ ................... 129 Exhibit 3

- 43 Case 1E (90%) Water Balance

................................ ................................ ............................. 130 Exhibit 3

- 44 Case 1F (95%) Water Balance

................................ ................................ .............................. 130 Exhibit 3

- 45 Case 1G (99%) Water Balance

................................ ................................ ............................. 131 Exhibit 3

- 46 Case 1E (90%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

................................ ................................ ................................ ................................ ............................. 133 Exhibit 3

- 47 Case 1E (90%) Heat and Mass Balance, Power Block Systems

................................ .......... 134 Exhibit 3

- 48 Case 1F (95%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

................................ ................................ ................................ ................................ ............................. 135 Exhibit 3

- 49 Case 1F (95%) Heat and Mass Balance, Power Block Systems

................................ ........... 136 Exhibit 3

- 50 Case 1G (99%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

................................ ................................ ................................ ................................ ............................. 137

ivCarbon Dioxide Capture Sensitivity Analysis 

## Exhibit 3

- 51 Case 1G (99%) Heat and Mass Balance, Power Block Systems

................................ .......... 138 Exhibit 3

- 52 Case 1E (90%) Energy Balance

................................ ................................ ............................ 139 Exhibit 3

- 53 Case 1F (95%) Energy Bal ance

................................ ................................ ............................ 140 Exhibit 3

- 54 Case 1G (99%) Energy Balance

................................ ................................ ........................... 141 Exhibit 3

- 55 Case 1E Energy Balance Sankey Diagram

................................ ................................ ........... 142 Exhibit 3

- 56 Case 1F Energy Balance Sankey Diagram

................................ ................................ ........... 142 Exhibit 3

- 57 Case 1G Energy Balance Sankey Diagra m

................................ ................................ .......... 143 Exhibit 3

- 58 Case 1A (30%) Capital Costs

................................ ................................ ............................... 152 Exhibit 3

- 59 Case 1A Initial and Annual O&M Expenses

................................ ................................ ........ 156 Exhibit 3

- 60 Case 1B (50%) Capital Costs

................................ ................................ ............................... 157 Exhibit 3

- 61 Case 1B Initial and Annual O&M Expenses

................................ ................................ ........ 161 Exhibit 3

- 62 Case 1C (70%) Capital Costs

................................ ................................ ............................... 162 Exhibit 3

- 63 Case 1C Initial and Annual O&M Expenses

................................ ................................ ........ 166 Exhibit 3

- 64 Case 1D (85%) Capital Costs

................................ ................................ ............................... 167 Exhibit 3

- 65 Case 1D Initial and Annual O&M Expenses

................................ ................................ ........ 171 Exhibit 3

- 66 Case 1E (90%) Capital Costs

................................ ................................ ................................ 172 Exhibit 3

- 67 Case 1E Initial and Annual O&M Expenses

................................ ................................ ........ 176 Exhibit 3

- 68 Case 1F (95%) Capital Costs

................................ ................................ ................................ 177 Exhibit 3

- 69 Case 1F Initial and Annual O&M Expenses

................................ ................................ ......... 181 Exhibit 3

- 70 Case 1G (99%) Capital Costs

................................ ................................ ............................... 182 Exhibit 3

- 71 Case 1G Initial and Annual O&M Expenses

................................ ................................ ........ 186 Exhibit 3

- 72 Cost and Performance Results for the Supercr itical PC Cases

................................ ............. 187 Exhibit 4

- 1 Typical ASU Process Schematic

................................ ................................ ............................ 196 Exhibit 4

- 2 Flow Diagram for a Conventional AGR Unit

................................ ................................ ......... 201 Exhibit 4

- 3 Common Chemical Reagents Used in AGR Processes

................................ .......................... 202 Exhibit 4

- 4 Physical Solvent AGR Proces s Simplified Flow Diagram

................................ ..................... 204 Exhibit 4

- 5 Common Physical Solvents Used in AGR Processes

................................ ............................. 204 Exhibit 4

- 6 Common Mixed Solvents Used in AGR Processes

................................ ................................ 205 Exhibit 4

- 7 Equilibrium Solubility Data on H 2 

## S and CO 2 

## in Various Solvents

................................ ........ 206 Exhibit 4

- 8 Generic Two

- Stage SelexolTM Process Flow Diagram

................................ ............................ 208 Exhibit 4

- 9 Typical Three

- Stage Claus Sulfur Plant

................................ ................................ ................. 210 Exhibit 4

- 10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas

.. 213 Exhibit 4

- 11 Combustion Turbine Typical Scope of Supply

................................ ................................ .... 213 Exhibit 4

- 12 Typical Fuel Specification for F

- Class Machines

................................ ................................ 216 Exhibit 4

- 13 Allowable Gas Fuel Contaminant Level for F

- Class M achines

................................ ........... 217 Exhibit 4

- 14 Case 2 GEE IGCC Plant Configuration Summary

................................ ............................... 224 Exhibit 4

- 15 Case 2 D1A Process Block Flow Diagram, IGCC without WGS (0% CO 2 

## Removal)

........ 226 Exhibit 4

- 16 Case 2 D1A Stream Table, IGCC without CO 2 

## Capture

................................ ...................... 227 Exhibit 4

- 17 Case 2 D1B Process Block Flow Diagram, IGCC without WGS (25% CO 2 

## Removal)

...... 229 Exhibit 4

- 18 Case 2 D1B Stream Table, IGCC with 25% CO 2 

## Capture

................................ ................... 230 Exhibit 4

- 19 Case 2 D1 Performance Modeling Results

................................ ................................ ........... 232 Exhibit 4

- 20 Case 2 D1 Estimated Air Emission Rates

................................ ................................ ............. 234 Exhibit 4

- 21 Case 2 D1 Carbon Balance

................................ ................................ ................................ ... 235 Exhibit 4

- 22 Case 2 D1 Sulf ur Balance

................................ ................................ ................................ ..... 235 Exhibit 4

- 23 Case 2 D1A (0%) Water Balance

................................ ................................ ......................... 236 Exhibit 4

- 24 Case 2 D1B (25%) Water Balance

................................ ................................ ....................... 237 Exhibit 4

- 25 Case 2 D1A (0%) Heat and Mass Balance, GEE Gasifie r and ASU

................................ .... 239 Exhibit 4

- 26 Case 2 D1A (0%) Heat and Mass Balance, Syngas Cleanup

................................ ............... 240

vCarbon Dioxide Capture Sensitivity Analysis 

## Exhibit 4

- 27 Case 2 D1A (0%) Heat and Mass Balance, Power Block

................................ .................... 241 Exhibit 4

- 28 Case 2 D1B (25%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 242 Exhibit 4

- 29 Case 2 D1B (25%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 243 Exhibit 4

- 30 Case 2 D1B (25%) Heat and Mass Balance, Power Block

................................ ................... 244 Exhibit 4

- 31 Case 2 D1A (0%) Energy Balance

................................ ................................ ....................... 245 Exhibit 4

- 32 Case 2 D1B (25%) Energy Balance

................................ ................................ ...................... 246 Exhibit 4

- 33 Case 2 D1A Energ y Balance Sankey Diagram

................................ ................................ ..... 247 Exhibit 4

- 34 Case 2 D1B Energy Balance Sankey Diagram

................................ ................................ ..... 247 Exhibit 4

- 35 Case 2 D2 Process Block Flow Diagram, IGCC with Single WGS Reactor and Bypass

.... 258 Exhibit 4

- 36 Case 2 D2A Stream Table, 25% CO 2 

## Removal with Single WGS Bypass

.......................... 259 Exhibit 4

- 37 Case 2 D2B Stream Table, 45% CO 2 

## Capture with Single WGS Bypass

............................ 261 Exhibit 4

- 38 Case 2 D2C Stream Table, 60% CO 2 

## Capture with Single WGS Bypass

............................ 263 Exhibit 4

- 39 Case 2 D2D Stream Table, 75% CO 2 

## Capture with Single WGS Bypass

............................ 265 Exhibit 4

- 40 Case 2 D2 Performance Modeling Results

................................ ................................ ........... 267 Exhibit 4

- 41 Case 2 D2 Estimated Air Emission Rates

................................ ................................ ............. 270 Exhibit 4

- 42 Case 2 D2 Carbon Balance

................................ ................................ ................................ ... 271 Exhibit 4

- 43 Case 2 D2 Sulfur Balance

................................ ................................ ................................ ..... 271 Exhibit 4

- 44 Case 2 D2A (25%) Water Balance

................................ ................................ ....................... 272 Exhibit 4

- 45 Case 2 D2B (45%) Water Balance

................................ ................................ ....................... 273 Exhibit 4

- 46 Case 2 D2C (60%) Water Balance

................................ ................................ ....................... 274 Exhibit 4

- 47 Case 2 D2D (75%) Water Balance

................................ ................................ ....................... 275 Exhibit 4

- 48 Case 2 D2A (25%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 277 Exhibit 4

- 49 Case 2 D2A (25%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 278 Exhibit 4

- 50 Case 2 D2A (25%) Heat and Mass Balance, Power Block

................................ .................. 279 Exhibit 4

- 51 Case 2 D2B (45%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 280 Exhibit 4

- 52 Case 2 D2B (45%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 281 Exhibit 4

- 53 Case 2 D2B (45%) Heat and Mass Balance, Power Block

................................ ................... 282 Exhibit 4

- 54 Case 2 D2C (60%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 283 Exhibit 4

- 55 Case 2 D2C (60%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 284 Exhibit 4

- 56 Case 2 D2C (60%) Heat and Mass Balance, Power Block

................................ ................... 285 Exhibit 4

- 57 Case 2 D2D (75%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 286 Exhibit 4

- 58 Case 2 D2D (75%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 287 Exhibit 4

- 59 Case 2 D2D (75%) Heat and Mass Balance, Power Block

................................ .................. 288 Exhibit 4

- 60 Case 2 D2A (25%) Energy Balance

................................ ................................ ..................... 289 Exhibit 4

- 61 Case 2 D2B (45%) Energy Balance

................................ ................................ ...................... 290 Exhibit 4

- 62 Case 2 D2C (60%) Energy Balance

................................ ................................ ...................... 291 Exhibit 4

- 63 Case 2 D2D (75%) Energy Balance

................................ ................................ ..................... 292 Exhibit 4

- 64 Case 2 D2A Energy Balance Sankey Diagram

................................ ................................ ..... 293 Exhibit 4

- 65 Case 2 D2B Energy Balance Sankey Diagram

................................ ................................ ..... 293 Exhibit 4

- 66 Case 2 D2C Energy Balance Sankey Diagram

................................ ................................ ..... 294 Exhibit 4

- 67 Case 2 D2D Energy Balance Sankey Diagram

................................ ................................ ..... 294 Exhibit 4

- 68 Case 2 D3 Process Block Flow Diagram, IGCC with Two WGS Reactors and Bypass

..... 304 Exhibit 4

- 69 Case 2 D3A Stream Table, 25% CO 2 

## Removal with Two WGS Bypass

............................. 305 Exhibit 4

- 70 Case 2 D3B Stream Table, 45% CO 2 

## Capture with Two WGS Bypass

............................... 307 Exhibit 4

- 71 Case 2 D3C Stream Table, 60% CO 2 

## Capture with Two WGS Bypass

............................... 309 Exhibit 4

- 72 Case 2 D3D Stream Table, 75% CO 2 

## Capture with Two WGS Bypass

............................... 311 Exhibit 4

- 73 Case 2 D3E Stream Table, 85% CO 2 

## Capture with Two WGS Bypass

............................... 313 Exhibit 4

- 74 Case 2 D3 Performance Modeling Results

................................ ................................ ........... 315

viCarbon Dioxide Capture Sensitivity Analysis 

## Exhibit 4

- 75 Case 2 D3 Estimated Air Emission Rates

................................ ................................ ............. 318 Exhibit 4

- 76 Case 2 D3 Carbon Balance

................................ ................................ ................................ ... 319 Exhibit 4

- 77 Case 2 D3 Sulfur Balance

................................ ................................ ................................ ..... 319 Exhibit 4

- 78 Case 2 D3A (25%) Water Balance

................................ ................................ ....................... 3 20 Exhibit 4

- 79 Case 2 D3B (45%) Water Balance

................................ ................................ ....................... 321 Exhibit 4

- 80 Case 2 D3C (60%) Water Balance

................................ ................................ ....................... 322 Exhibit 4

- 81 Case 2 D3D (75%) Water Balance

................................ ................................ ....................... 323 Exhibit 4

- 82 Case 2 D3E (85%) Water Balance

................................ ................................ ........................ 324 Exhibit 4

- 83 Case 2 D3A (25%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 325 Exhibit 4

- 84 Case 2 D3A (25%) H eat and Mass Balance, Syngas Cleanup

................................ ............. 326 Exhibit 4

- 85 Case 2 D3A (25%) Heat and Mass Balance, Power Block

................................ .................. 327 Exhibit 4

- 86 Case 2 D3B (45%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 328 Exhibit 4

- 87 Case 2 D3B (45%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 329 Exhibit 4

- 88 Case 2 D3B (45%) Heat and Mass Balance, Power Block

................................ ................... 330 Exhibit 4

- 89 Case 2 D3C (60%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 331 Exhibit 4

- 90 Case 2 D3C (60%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 332 Exhibit 4

- 91 Case 2 D3C (60%) Heat and Mass Balance, Power Block

................................ ................... 333 Exhibit 4

- 92 Case 2 D3D (75%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 334 Exhibit 4

- 93 Case 2 D3D (75%) Heat and Mass Balance, Syngas Cleanup

................................ ............. 335 Exhibit 4

- 94 Case 2 D3D ( 75%) Heat and Mass Balance, Power Block

................................ .................. 336 Exhibit 4

- 95 Case 2 D3E (85%) Heat and Mass Balance, GEE Gasifier and ASU

................................ .. 337 Exhibit 4

- 96 Case 2 D3E (85%) Heat and Mass Balance, Syngas Cleanup

................................ .............. 338 Exhibit 4

- 97 Case 2 D3E (85%) Heat and Mass Balance, Power Block

................................ ................... 339 Exhibit 4

- 98 Case 2 D3A (25%) Energy Balance

................................ ................................ ..................... 341 Exhibit 4

- 99 Case 2 D3B (45%) Energy Balance

................................ ................................ ...................... 342 Exhibit 4

- 100 Case 2 D3C (60%) Energy Balance

................................ ................................ .................... 343 Exhibit 4

- 101 Case 2 D3D (75%) Energy Balance

................................ ................................ ................... 344 Exhibit 4

- 102 Case 2 D3E (85%) Energy Balance

................................ ................................ .................... 345 Exhibit 4

- 103 Case 2 D3A Energy Balance Sankey Diagram

................................ ................................ ... 346 Exhibit 4

- 104 Case 2 D3B Energy Balance Sankey Diagram

................................ ................................ ... 346 Exhibit 4

- 105 Case 2 D3C Energy Balance Sankey Diagram

................................ ................................ ... 347 Exhibit 4

- 106 Case 2 D3D Energy Balance Sankey Diagram

................................ ................................ ... 347 Exhibit 4

- 107 Case 2 D3E Energy Balance Sankey Diagram

................................ ................................ ... 348 Exhibit 4

- 108 Case 2 D4 Process Block Flo w Diagram, IGCC with Two WGS Reactors

....................... 358 Exhibit 4

- 109 Case 2 D4A Stream Table, 90% CO 2 

## Removal

................................ ................................ .. 359 Exhibit 4

- 110 Case 2 D4B Stream Table, 95% CO 2 

## Capture

................................ ................................ .... 361 Exhibit 4

- 111 Case 2 D4C Stream Table, 97 % CO 2 

## Capture

................................ ................................ .... 363 Exhibit 4

- 112 Case 2 D4 Performance Modeling Results

................................ ................................ ......... 365 Exhibit 4

- 113 Case 2 D4 Estimated Air Emission Rates

................................ ................................ ........... 368 Exhibit 4

- 114 Case 2 D4 Carbon Balance

................................ ................................ ................................ . 369 Exhibit 4

- 115 Case 2 D4 Sulfur Balance

................................ ................................ ................................ ... 369 Exhibit 4

- 116 Case 2 D4A (90%) Water Balance

................................ ................................ ..................... 370 Exhibit 4

- 117 Case 2 D4B (95%) Water Balance

................................ ................................ ..................... 371 Exhibit 4

- 118 Case 2 D4C (97%) Water Balance

................................ ................................ ..................... 372 Exhibit 4

- 119 Case 2 D4A (90%) Heat and Mass Balance, GEE Gasifier and ASU

................................ 373 Exhibit 4

- 120 Case 2 D4A (90%) Heat and Mass Balance, Syngas Cleanup

................................ ........... 374 Exhibit 4

- 121 Case 2 D4A (90%) Heat and Mass Balance, Power Block

................................ ................ 375 Exhibit 4

- 122 C ase 2 D4B (95%) Heat and Mass Balance, GEE Gasifier and ASU

................................ 376

viiCarbon Dioxide Capture Sensitivity Analysis 

## Exhibit 4

- 123 Case 2 D4B (95%) Heat and Mass Balance, Syngas Clea nup

................................ ........... 377 Exhibit 4

- 124 Case 2 D4B (95%) Heat and Mass Balance, Power Block

................................ ................. 378 Exhibit 4

- 125 Case 2 D4C (97%) Heat and Mass Balance, GEE Gasifier and ASU

................................ 379 Exhibit 4

- 126 Case 2 D4C (97%) Heat and Mass Balance, Syngas Cleanup

................................ ........... 380 Exhibit 4

- 127 Case 2 D4C (97%) Heat and Mass Balance, Power Block

................................ ................. 381 Exhibit 4

- 128 Case 2 D4A (90%) Energy Balance

................................ ................................ ................... 383 Exhibit 4

- 129 Case 2 D4B (95%) Energy Balance

................................ ................................ .................... 384 Exhibit 4

- 130 Case 2 D4 C (97%) Energy Balance

................................ ................................ .................... 385 Exhibit 4

- 131 Case 2 D4A Energy Balance Sankey Diagram

................................ ................................ ... 386 Exhibit 4

- 132 Case 2 D4B Energy Balance Sankey Diagram

................................ ................................ ... 386 Exhibit 4

- 133 Case 2 D4C Energy Balance Sankey Diagram

................................ ................................ ... 387 Exhibit 4

- 134 Case 2 D1A (0%) Capital Costs

................................ ................................ ......................... 396 Exhibit 4

- 135 Case 2 D1A Initial and Annual O&M Expenses

................................ ................................ 400 Exhibit 4

- 136 Case 2 D1B (25%) Capital Costs

................................ ................................ ........................ 401 Exhibit 4

- 137 Case 2 D1B Initial and Annual O&M Expenses

................................ ................................ 405 Exhibit 4

- 138 Case 2 D2A (25%) Capital Costs

................................ ................................ ....................... 406 Exhibit 4

- 139 Case 2 D2A Initial and Annual O&M Expenses

................................ ................................ 410 Exhibit 4

- 140 Case 2 D2B (45%) Capital Costs

................................ ................................ ........................ 411 Exhibit 4

- 141 Case 2 D2B Initial and Annual O&M E xpenses

................................ ................................ 415 Exhibit 4

- 142 Case 2 D2C (60%) Capital Costs

................................ ................................ ........................ 416 Exhibit 4

- 143 Case 2 D2C Initial and Annual O&M Expenses

................................ ................................ 420 Exhibit 4

- 144 Case 2 D2D (75%) Capital Costs

................................ ................................ ....................... 421 Exhibit 4

- 145 Case 2 D2D Initial and Annual O&M E xpenses

................................ ................................ 425 Exhibit 4

- 146 Case 2 D3A (25%) Capital Costs

................................ ................................ ....................... 426 Exhibit 4

- 147 Case 2 D3A Initial and Annual O&M Expenses

................................ ................................ 430 Exhibit 4

- 148 Case 2 D3B (45%) Capital Costs

................................ ................................ ........................ 431 Exhibit 4

- 149 Case 2 D3B Initial and Annual O&M E xpenses

................................ ................................ 435 Exhibit 4

- 150 Case 2 D3C (60%) Capital Costs

................................ ................................ ........................ 436 Exhibit 4

- 151 Case 2 D3C Initial and Annual O&M Expenses

................................ ................................ 440 Exhibit 4

- 152 Case 2 D3D (75%) Capital Costs

................................ ................................ ....................... 441 Exhibit 4

- 153 Case 2 D3D Initial and Annual O&M E xpenses

................................ ................................ 445 Exhibit 4

- 154 Case 2 D3E (85%) Capital Costs

................................ ................................ ........................ 446 Exhibit 4

- 155 Case 2 D3E Initial and Annual O&M Expenses

................................ ................................ 450 Exhibit 4

- 156 Case 2 D4A (90%) Capital Costs

................................ ................................ ....................... 451 Exhibit 4

- 157 Case 2 D4A Initial and Annual O&M E xpenses

................................ ................................ 455 Exhibit 4

- 158 Case 2 D4B (95%) Capital Costs

................................ ................................ ........................ 456 Exhibit 4

- 159 Case 2 D4B Initial and Annual O&M Expenses

................................ ................................ 460 Exhibit 4

- 160 Case 2 D4C (97%) Capital Costs

................................ ................................ ........................ 461 Exhibit 4

- 161 Case 2 D4C Initial and Annual O&M E xpenses

................................ ................................ 465 Exhibit 4

- 162 Cost and Performance Results for the GEE IGCC Cases

................................ ................... 467 Exhibit 5

- 1 Net Plant HHV Efficiency for the Supercritical PC Cases

................................ ..................... 47 0 Exhibit 5

- 2 Net Plant HHV Efficiency for the GEE IGCC Cases

................................ ............................. 471 Exhibit 5

- 3 TOC for the Supercritical PC Cases

................................ ................................ ....................... 472 Exhibit 5

- 4 TOC for the GEE IGCC Cases

................................ ................................ ............................... 473 Exhibit 5

- 5 COE for the Supercritical PC Cases

................................ ................................ ....................... 474 Exhibit 5

- 6 COE for the GEE IGCC Cases

................................ ................................ ............................... 475 Exhibit 5

- 7 CO 2 

## TS&M COE for the Supercritical PC Cases

................................ ................................ ... 475 Exhibit 5

- 8 CO 2 

## TS&M COE for the GEE IGCC Cases

................................ ................................ ........... 476

viiiCarbon Dioxide Capture Sensitivity Analysis 

## Exhibit 5

- 9 CO 2 

## Avoided Costs for the Supercritical PC Cases

................................ ................................ 477 Exhibit 5

- 10 CO 2 

## Avoided Costs for the GE E IGCC Cases

................................ ................................ ...... 478 Exhibit 5

- 11 Cost and Performance Results for the Supercritical PC Cases

................................ ............. 481 Exhibit 5

- 12 Cost and Performance Results for the GEE IGCC Cases

................................ ..................... 482
Appendix A

- 1 Supercritical PC CO 2 

## Capture & Compression Cost, $000

................................ .............. 484 Appendix A

- 2 Supercritical PC CO 2 

## Capture & Compression Cost, $/kW

................................ ............. 484 Appendix A

- 3 Supercritical PC Total Overnight Cost, $000

................................ ................................ ... 485 Appendix A

- 4 Supercrit ical PC Total Overnight Cost, $/kW

................................ ................................ .. 485 Appendix A

- 5 Supercritical PC Incremental Capital Cost, $000

................................ ............................. 486 Appendix A

- 6 Supercritical PC Incremental Capital Cost, $/kW

................................ ............................ 486 Appendix A

- 7 Supercritical PC COE, mills/kWh

................................ ................................ .................... 487 Appendix A

- 8 Supercritical PC Incr emental COE, mills/kWh

................................ ................................ 487 Appendix A

- 9 Supercritical PC Percent Increase in COE

................................ ................................ ........ 488 Appendix A

- 10 Supercritical PC CO 2 

## Capture Avoided Costs

................................ ................................ 488 Appendix A

- 11 GEE IGCC CO 2 

## Capture & Compression Cost, $000

................................ .................... 489 Appendix A

- 12 GEE IGCC CO 2 

## Capture & Compression Cost, $/kW

................................ ................... 489 Appendix A

- 13 GEE IGCC Total Overnight Cost, $000

................................ ................................ ......... 490 Appendix A

- 14 GEE IGCC Total Overnight Cost, $/kW

................................ ................................ ........ 490 Appendix A

- 15 GEE IGCC Incremental Capital Cost, $000

................................ ................................ ... 491 Appendix A

- 16 GEE IGCC Incremental Capital Cost, $/kW

................................ ................................ .. 491 Appendix A

- 17 GEE IGCC COE, mills/kWh

................................ ................................ .......................... 492 Appendix A

- 18 GEE IGCC Incremental COE, mills/kWh

................................ ................................ ...... 492 Appendix A

- 19 GEE IGCC Percent Increase in COE

................................ ................................ .............. 493 Appendix A

- 20 GEE IGCC CO 2 

## Capture Avoided Costs

................................ ................................ ........ 493

ixCarbon Dioxide Capture Sensitivity Analysis



# List o f Acronyms a nd Abbreviations

AACE Association for the Advancement of Cost Engineering acfm Actual cubic foot per minute AEO Annual Energy Outlook AGR Acid gas removal AR As Received ASU Air separation unit BACT Best av ailable control technology BEC Bare erected cost BFD Block flow diagram BFW B oi ler feed water Btu British thermal unit Btu/h British thermal unit per hour Btu/kWh British thermal unit per kilowatt hour Btu/lb British thermal unit per pound CA California CCF Capital Charge Factor CCS Carbon Capture and Sequestration CF Capacity factor CFM Cubic feet per minute CFR Code of Federal Regulations CGE Cold gas efficiency CH 4 

## Methane

cm Centimeter CO 2 

## Carbon dioxide CO 2 e 

## Carbon dioxide equivalent COE Cost of elec tricity CoP ConocoPhillips COS Carbonyl sulfide CRP Conservation Reserve Program CRT Cathode ray tube CT Combustion turbine CTG Combustion Turbine

- Generator CWT Cold water temperature DCS Distributed control system Dia. Diameter DOE Department of Energy EA F Equivalent availability factor E

- Gas TM 

## ConocoPhillips gasifier technology EIA Energy Information Administration EPA Environmental Protection Agency EPC Engineer/Procure/Construct

xCarbon Dioxide Capture Sensitivity Analysis



## EPCM Engineering/Procurement/Construction Management EPRI Electric Power Research Institute FOAK First of a kind ft Foot, Feet GADS Generating Availability Data System gal Gallon GDP Gross domestic product GEE General Electric Energy GHG Greenhouse gas gpm Gallons per minute GT Gas turbine GW Gigawatt GWP Global Warming Potent ial h Hour H 2 

## Hydrogen H 2 

## S Hydrogen sulfide Hg Mercury HHV Higher heating value hp Horsepower HP High pressure HRSG Heat recovery steam generator HVAC Heating, ventilating, and air conditioning IGVs Inlet guide vanes IGCC Integrated gasification combined c ycle IOU Investor

- owned utility IP Intermediate pressure ISO International Standards Organization kg/GJ Kilogram per gigajoule kg/h Kilogram per hour kJ Kilojoules kJ/kg Kilojoules per kilogram KO Knockout kPa Kilopascal absolute kV Kilovolt kW Kilowatt kWe Kilowatts electric kWh Kilowatt

- hour kWt Kilowatts thermal LAER Lowest Achievable Emission Rate lb Pound lb/h Pounds per hour lb/MMBtu Pounds per million British thermal units lb/MWh Pounds per megawatt hour

xiCarbon Dioxide Capture Sensitivity Analysis



## LF Fn 

## Levelization factor for category n fixed operating cost LF Vn 

## Levelization factor for category n variable operating cost LHV Lower heating value LNB Low NOx burner LP Low pressure

m Meters MM$ Millions of Dollars m/min Meters per minute

m 3 

## /min Cubic meter per minute MDEA Methyldiethanolamine MEA Monoethanolamine MHz Megahertz MMBtu Million British thermal units (also shown as 10 6 

## Btu) MMBtu/h Million British thermal units (also shown as 10 6 

## Btu) per hour MPa Megapascals Mpg Miles per gallon MW Megawatt MWe Megawatts electric MWh Megawatt

- hour NAAQS National ambient air quality standard net

- MWh Net m egawatt

- hour NERC North American Electric Reliability Council NETL National Energy Technology Laboratory NGCC Natural gas combined cycle NOAK Nth of a kind NOx Oxides of nitrogen NSPS New Source Per formance Standards NSR New Source Review NREL National Renewable Energy Laboratory O&M Operation and maintenance OC Fn 

## Category n fixed operating cost for the initial year of operation PC Pulverized coal PM Particulate matter PM 10 

## Particulate matter measur ing 10 μm or less POTW Publicly Owned Treatment Works ppm Parts per million ppmd Parts per million, dry ppmv Parts per million, volume PRB Powder River Basin coal region PSD Prevention of Significant Deterioration psia Pounds per square inch absolute psig Pounds per square inch gage R&D Research and Development

xiiCarbon Dioxide Capture Sensitivity Analysis



## RDS Research and Development Solutions, LLC SC Supercritical SCR Selective catalytic reduction SGS Sour gas shift SO 2 

## Sulfur dioxide STG Steam turbine generator SWS Sour water stripper TASC Total As

- Spent Capital TBtu Trillion British thermal unit TGTU Tail gas treating unit TOC Total overnight cost Tonne Metric Ton (1000 kg) TPC Total plant cost TPD Tons per day TPH Tons per hour TPI Total plant investment TS&M Transport, storage and monitoring TWh Terawatt

- hour USDA United States Department of Agriculture vol% Volume percent WGS Water gas shift wt% Weight percent $/AR ton Dollars per As Received ton $/dry ton Dollars per dry ton $/kW Dollars per kilowatt $/MMBtu Dollars per million British thermal units $/MMkJ Dollars per million kilojoule $/MWh Dollars per Megawatt

- hour $/ton Dollars per ton 5

- 10s Fifty hour work weeks (5 days, 10 hours/day)

xiiiCarbon Dioxide Capture Sensitivity Analysis



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xivCarbon Dioxide Capture Sensitivity Analysis



# Executive Summary
The objective of th is study was to establish the cost and performance for a range of carbon dioxide (CO 2 

## ) capture level s for new supercritical (SC) pulverized coal (PC) and integrated gasification combined cycle (IGCC) power plants

. The SC PC cases (Case 1 series ) utilize F luor’s Econamine FG Plus SM 

## process for post

- combustion CO 2 

## capture via temperature swing
a b sorption with a 30 wt% monoethanolamine (MEA) solution as the chemical solvent. The IGCC cases (Case 2 series ) employ a slurry

- fed, entrained

- flow General Electric Energy (GEE) gasifier and leverage UOP’s (formerly Universal Oil Products) two

- stage SelexolTM process for bulk CO 2 

## capture and selective hydrogen sulfide (H 2 

## S) removal via pressure swing a b sorption. The SelexolTM process uses dimethyl ether of polyethylene glycol (DEPG) as a physical solvent for pre

- combustion capture.

The CO 2 

## capture sensitivity analysis includes an evaluation of the cost, performance, and environmental profile of these facilities while operating at 0 feet of elevation (ISO conditions) i n the Illinois coal basin and firing Illinois #6 medium

- sulfur bituminous coal. The study include s compression of the captured CO 2 

## to pipeline pressure of 15.2 MPa ( 2,215 psia) , pipeline transport 80 kilometers (50 miles ), storage in a saline formation at a depth of 1,239 meters (4,055 ft) , and monitoring for 80 years . The site will have appropriate access to rail transportation for delivery of coal. All local coal handling facilities are included in the design and cost e stimation portion of this study. The methodology included performing steady

- state simulations of the technology using the A SPEN Plus ® 

## (Aspen) modeling program. Each configuration was tailored to achieve a specific level of carbon capture.


# Pulverized Coal Plants

An Aspen model for a SC PC power plant, coupled with detailed simulations of the Econamine FG Plus SM 

## process using Optimized Gas Treating’s ProTreatTM, was utilized to evaluate the technical and economic performance of post

- combustion CO 2 

## capture in the following increments: 30, 50, 70, 85 , 90, 95, and 99 percent capture. For control of nitrogen oxides (NO x 

## ) emissions, a combination of low

- NO x 

## burners (LNB) with overfire air (OFA) and a selective catalytic reduction (SCR) system is used. A fabric filter is employed to minimize p articulate matter emissions. A wet limestone flue gas desulfurization (FGD) system , i n conjunction with a sodium hydroxide polishing scrubber, is used to ensure that the flue gas entering the Econamine system has a sulfur dioxide (SO 2 

## ) concentration of 10 ppmv or less. The SC PC descriptions (herein referred to as Case 1) are summarized in Exhibit ES

- 1

.

1Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 1 Case 1 Supercritical PC Plant Configuration Summary

Case CO 2 

### Capture Intended Storage Boiler Steam psig/°F/°F Oxidant NO x 

### Control Sulfur Control
1 A 30%

Saline Formation Wall

- fired, PC 3500/1100/110 0 Air LNB/OFA/SCR 0.07 lb/ MM Btu Wet FGD 0.1 lb/ MM Btu 1B 50% 1C 7 0% 1D 85 % 1E 90% 1F 95% 1G 99%



## Optimized Gas Treating’s rate

- based ProTreatTM software was used to generate performance estimates for the Econamine FG Plus SM 

## process

. Initially, 90 percent CO 2 

## removal was modeled by adjusting three key process parameters: (1) the MEA solution circulatio n rate ; (2) the reboiler steam flow rate; and (3) the height of packing material in the absorption and stripping columns. For higher levels of CO 2 

## removal ( greater than 90 percent ) , the MEA and reboiler steam flow rates were increased, as well as the absorber/stripper column packing height. Recent studies typically focus on 90 percent CO 2 

## capture from coal

- fired power plants, but for the cases in this study that focus on less than 90 percent , two options exist. The first option is to pass the entire f lue gas stream through the amine scrubbing unit, but at reduced solvent circulation rates. The second is to maintain the same high solvent circulation rate and stripping steam requirement, but only treat a portion of the flue gas by bypassing part of the gas stream around the scrubber. A literat ure search was conducted to verify that less than 90 percent CO 2 

## capture is most economical using a “ slip

- stream ” (or bypass) approach. According to multiple peer

- reviewed studies the slip

- stream appro ach is indee d more cost

- effective for lower degrees of capture [ 1 , 2 , 3 ] . The cost of CO 2 

## ca pture with an amine scrubbing process is dependent on the volume of gas being treated , and a reduction in flue gas flow rate will: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of the CO 2 

## absorption columns; and (3) trim the cooling water requirement of the direct contact cooling system

. As a result, the ‘slip

stream’ approach for reduced levels of capture leads to low er capital and operating costs. Due to the range of CO 2 

## capture levels analyzed in Case 1 , the Econamine capital and operating costs vary for the seven cases. While a factored approach that relies on the quantity of CO 2 

## captured for equipment sizing and cost estimation was employed, the cost est imates for the Econamine system were also developed based, in part, on output data from the ProTreatTM simulations. In particular, the ProTreatTM model output provided absorption and stripping column diameters for each case, which were used to determine the required number of absorption trains. For this analysis, it was assumed that the maximum absorption column diameter is 20 meters (66 feet) , bas ed on information released by Fluor [ 4 ]. As a result, cases that i nclude carbon capture up to 70% are based on a single absorption and compression train.

2Carbon Dioxide Capture Sensitivity Analysis



# IGCC Plants
An Aspen model for a GE E IGCC power plant, coupled with analysis of different process
co nfigurations (i.e., water gas shift bypass ratio and SelexolTM CO 2 

## removal efficiency) , was utilized to evaluate the technical and economic performance of pre

- combustion CO 2 

## capture for the following four plant designs:

• Design 1 (D1) has no water gas shift ( WGS ) reactor . T he minimum (0 percent ) and maximum ( 25 percent ) CO 2 

## capture levels for this particular configuration are modeled. The initial concept for D1 was to have a two

- stage SelexolTM unit, and if no capture was desired, “turn off” the second stage (which would be dedicated for CO 2 

## c ontrol ). However d ue to the high degree of integration between the H 2 

## S and CO 2 

## absorbers, it is not feasible to simply disable the second stage. Consequently , D1A (0 percent capture) employs a one

- stage SelexolTM unit f or H 2 

## S control , while D1B (25 percent capture) utilize s a two

- stage SelexolTM unit to maximize CO 2 

## capture from the unshifted syngas

.

• Design 2 (D2) has one

- stage of WGS , with CO 2 

## capture ranging from 25 (upper limit from D 1) to 75 percent ( maximum achievable limit for this particular configuration ). The different levels of CO 2 

## capture were achieved by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

## removal efficiency

. The separation efficiency of a physical solvent

- based system such as the SelexolTM process is directly proportional to the concentration of CO 2 

## in the syngas. Therefore, the level of CO 2 

## capture can be manipulated by varying the extent of the water gas shift reaction . In Design 2, the amount of CO being converted to CO 2 

## is varied by only shifting a portion of the syngas stream. The SelexolTM removal efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system.

• Design 3 (D3) has two

- stage s of WGS with CO 2 

## capture ranging from 25 percent (upper limit from D 1) to the maximum achievable limit for this particular configuration (85 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

## removal efficiency

. The SelexolTM removal efficiency is changed by

v arying the solvent circulation rate, which changes the size and cost of the SelexolTM system.

• Design 4 (D4) has two

- stage s of WGS with no bypass (therefore the entire syngas stream is shifted) with CO 2 

## capture ranging from 90 percent to 9 7 percent

. To achieve greater than 90 percent CO 2 

## removal, the two

- stage SelexolTM CO 2 

## removal efficiency is increased by raising the solvent circulation rate, which increases the size and cost of the SelexolTM system.

The Case 2 IGCC design descriptions are summarized in Exhibit ES

- 2

.

3Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 2 Case 2 GEE IGCC Plant Configuration Summary

Case CO 2 

### Capture CO 2 

### Separation Intended Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur Control D1A 0% N/A N/A

GE E Radiant

Only 1800/1050/ 1050 95 mol%

O 2 

### N/A

Selexol
TM D1B 25%

SelexolTM 2 nd 

### Stage Saline Formation N/A D2A 25% One

Stage with B ypass D2B 45% D2C 60% D2D 75% D3A 25% Two

Stage with B ypass D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% Two

Stage without B ypass D4B 95% D4C 97%



## To determine the process configuration s for less than 90 percent CO 2 

## removal ( IGCC D2 and D3 ) , the WGS bypass ratio and SelexolTM CO 2 

## removal efficiency were varied over a series of Aspen simulations of the entire GEE IGCC power plant to evaluate the impact on WGS and SelexolTM costs and net plant efficiency. As a starting poi nt, the SelexolTM CO 2 

## removal efficiency ( 92

. 4 percent ) used to model 90 percent CO 2 

## removal was fixed [ 5 ], and the WGS bypass ratio was adjusted to achieve the desir ed level of capture. The CO 2 

## removal level was then held constant by decrea sing both the WGS bypass ratio (i.e., routing more syngas through the WGS reactor(s)) and the SelexolTM CO 2 

## removal efficiency. These step changes in the WGS bypass ratio lead to an increase in CO 2 

## partial pressure, which relaxes the CO 2 

## removal required b y the SelexolTM process. As shown in Exhibit ES

- 3 , the cost of the WGS system decreases as the WGS bypass ratio increases since the quantity of s yn gas being shifted declines. The SelexolTM system cost increases with the WGS bypass ratio since a higher solvent circulation rate is required to maintain 60 percent CO 2 

## removal as the CO 2 

## partial pressure decreases. However, the total cost of the WGS and SelexolTM systems, which is dominated by the cost of the SelexolTM system, gradually increases with the WGS bypass ratio. Meanwhile, the net plant HHV efficiency passes through a maximum value over the range of WGS byp ass ratios. As a result, the WGS bypass ratios and SelexolTM CO 2 

## removal efficiencies used to model less than 90 percent CO 2 

## removal in this study (IGCC D2 and D3) correspond to the maximum net plant HHV efficiency.

4Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO 2 

### Removal with IGCC Design 3

34 34.2 34.4 34.6 34.8 35 35.2 35.4 35.6 35.8 36

$0 $20,000 $40,000 $60,000 $80,000 $100,000 $120,000 $140,000 $160,000 $180,000

0 0.1 0.2 0.3 0.4 0.5Net Plant HHV Efficiency, %Capital Cost, $000



## WGS Bypass Ratio Total Cost
Selexol Cost
WGS Cost Efficiency



## This procedure was repeated for each level of total CO 2 

## removal analyzed for IGCC D2 and D3 to determine the optimal WGS bypass ratio and SelexolTM CO 2 

## removal efficiency for these intermediate capture points. Data for these optimal configurations are provided in Exhibit ES

- 4 and Exhibit ES

- 5 for IGCC D2 and D3, respectively. These results indicate that the Se lexolTM CO 2 

## removal efficiency increases with CO 2 

## partial pressure, which is the expected trend with a physical solvent

- based system.

Exhibit ES

- 4 Process Configurations for IGCC D2

Total CO 2 

### Removal (%) WGS WGS Bypass Ratio (%) SelexolTM CO 2 

### Removal (%) P CO2 

### (psia)

25 One

- Stage with Bypass 99 .5 85

. 8 119.4
45 60 8 9 186.3
60 28.75 8 9.5 229.8
75 0 91 265.5



## 5Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 5 Process Configurations for IGCC D3

Total CO 2 

### Removal (%) WGS WGS Bypass Ratio (%) SelexolTM CO 2 

### Removal (%) P CO2 

### (psia)

25

Two

- Stage with Bypass 99.75 86

. 31 119. 7
45 6 9.4 90.04 186. 5
60 45 90.1 230.1
75 21 90.4 26 4.3
85 5 9 0.52 289. 3



## A typical offering from a commercial catalyst vendor is a steam

- to

- dry gas (S:DG) molar ratio of 0.3 at the outlet of the final WGS reactor. However , for lower levels of CO 2 

## removal (IGCC D2 and D3), this study uses a S:DG molar ratio of 0. 25 at the outlet of the final WGS reactor. Operating with a lower S:DG ratio impedes the kinetics of carbon monoxide (CO) to CO 2 

## conversion. Consequently, larger and more costly WGS reactors are required for a similar degree of conversion. Although a reduction in S:DG ratio requires a larger reactor volume (this analys is assumes a catalyst volume increase of 30 percent , and subsequently a 30 percent increase in reactor cost), the re is the benefit of shift steam savings. This steam can then be expanded through the steam turb ine to produce additional power. Thermal input to the IGCC plant is used to fu lly

- load the combustion turbines . Any remaining energy in the combustion turbine exhaust is extracted to the maximum extent possible in a heat recovery steam generator in order to raise steam to generate additi onal power. T he net power for the IGCC cases ranges from 523 to 622 MW. The span in net out put is caused by the wide range of CO 2 

## capture imposed from case

- to

- case. The differences in auxiliary loads are primarily attributed to CO 2 

## compression and the n eed for extraction steam in the WGS reactions, which reduces steam turbine output.



# Results
The major results from the CO 2 

## capture sensitivity analysis are discussed below in the following order:

• Performance (efficiency)

• Economics (total overnight cost, cost of electricity, and CO 2 

## avoided cost)

• Performance and Cost summary


# Performance
Energy Efficiency

The net plant HHV efficiencies for the SC PC and GEE IGCC cases are presented in Exhibit ES

- 6 and Exhibit ES

- 7 , respectively

. As the CO 2 

## capture requirement is increased for eithe r plant type, PC or IGCC, there is an increase in the auxiliary power required to support the

6Carbon Dioxide Capture Sensitivity Analysis



## capture equipment (either Econamine or Selexol TM ) and the CO 2 

## compressor trains. Further, more steam is consumed by the capture equipment, and by the WGS reactor( s) in the IGCC case, making less available for supply to the steam turbine. Both effects (higher auxiliary load and reduced steam supply to the turbine) detract from the net power produced by the plant per unit of coal energy input, as evidenced by the ne t plant HHV efficiency trends v ersu s CO 2 

## capture level

. Exhibit ES

- 6 Supercritical PC Net Plant Efficiency ( HHV )

0 10 20 30 40

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99% 

### 39.3

35.2

32.9 30.6 28.9 28.2 27.5 25.7Net Plant HHV Efficiency, %



### Capture with Bypass Capture without Bypass



## 7Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 7 IGCC Net Plant Efficiency ( HHV )

0 10 20 30 40

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97% 

### 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5Net Plant HHV Efficiency, %



### No WGS Two WGS w/ Bypass One WGS w/ Bypass Two WGS w/o Bypass



# Economics
Total Overnight Cost All capital costs are presented as “overnight costs” expressed in J une 2007 dollars. The c apital costs are presented at the total overnight cost ( TOC ) level, which includes: (1) e quipment (complete with initial c hemical and catalyst loadings); (2) m a terials; (3) labor (direct and indirect); (4) e ngineering and construction management; (5) c ont ingencies (process and project); and (6) owner’s costs

. The owner’s costs, which are summarized in Exhibit 2

- 18 , include preproduction costs, inventory capital, land costs, financing costs, taxes and insurances, and other owner’s costs.

The TOC for the SC PC and GEE IGCC cases are presented in Exhibit ES

- 8 and Exhibit ES

- 9 , respectively. These exhibits categorize the TOC into five categories: (1) bare erected cost; (2) engineering, home office, construction management (CM), and fee s ; (3) project contingency; (4) process contingency; and (5) owner’s costs.

The SC PC total overnight cost estimates apply to facilities designed with a fixed 550 MW net capacity. As the design is equipped for increased CO 2 

## capture, moving from Case 1A through Case 1G, the TOC also increase s as a result of the need for larger power plant components for

8Carbon Dioxide Capture Sensitivity Analysis



## power generation to offset the auxiliary power and steam requirements of the CO 2 

## capture and compression systems . Hence, the increase in installed TOC per net kW delivered.

Exhibit ES

- 8 Supercritical PC T otal O vernight C ost

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99% 

### 2,025 2,541 2,808 3,075 3,400 3,484 3,572 3,744TOC, $/kW 

### Owner's Costs Process Contingency Project Contingency Engr., Home Office, CM, and Fee
Bare Erected Cost

Capture with Bypass Capture without Bypass



## The IGCC total overnight cost estimates apply to facilities designed with a fixed gross combustion turbine capacity of 464 MW (total for two turbines) . As the plant is equipped for increased CO 2 

## capture, moving from Case 2 D1A through Case 2 D4C , the TOC also incr ease s as a result of the need for larger components for power generation , while still maintaining the required gas turbine output . Hence , the increase in installed TOC per net kW delivered.

9Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 9 IGCC T otal O vernight C ost

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

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97% 2,447 2,724 2,726 2,891 3,019 3,161

2,727 2,897 3,024 3,160 3,253 3,335 3,453 3,501TOC, $/kW Owner's Costs

Process Contingency Project Contingency Engr., Home Office, CM, and Fee
Bare Erected Cost



### No WGS Two WGS w/ Bypass One WGS w/ Bypass Two WGS w/o Bypass 

## Cost of Electricity The revenue requirement figure

- of

- merit in this report is the cost of electricity ( COE ) expressed in mills/kWh (numerically equivalent to $ / M Wh). The capital expenditure and operational periods for the SC PC and IGCC po wer plants are 5 and 30 years, respectively

. The costs associated with CO 2 

## transportation, storage, and monitoring (TS&M) are included for all capture
cases. All costs are expressed in June 2007 dollars, and the resulting COE is also expressed in June 2007 year dollars.

The COE for the SC PC and GEE IGCC cases are presented in Exhibit ES

- 10 and Exhibit ES

- 11 , respectively. These exhibits show the COE divided into five categories: (1) capital costs; (2) fixed costs; (3) variable costs; (4) fuel costs; and (5) CO 2 

## TS&M costs.

The COE estimates a re based on capacity factors of 85 percent and 80 percent for the SC PC and GEE IGCC cases, respectively.

10Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 10 Supercritical PC C ost of E lectricity

0 20 40 60 80 100 120 140

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99% 

### 58.9 76.6 84.4 92.8 101.5 104.3 107.0 112.7COE, mills/kWh 

### CO2 TS&M Costs
Fuel Costs
Variable Costs
Fixed Costs Capital Costs

Capture with Bypass Capture without Bypass



## 11Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 11 IGCC C ost of E lectricity

0 20 40 60 80 100 120 140

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97% 

### 76.3 85.3 85.4 90.8 95.2 100.0

85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8COE, mills/kWh 

### CO2 TS&M Costs
Fuel Costs
Variable Costs
Fixed Costs Capital Costs

No WGS Two WGS w/ Bypass One WGS w/ Bypass Two WGS w/o Bypass



## CO 2 

## Avoided Costs

The CO 2 

## avoided cost was calculated as illustrated in Equation 1.

( 1 ) 

# MWh tonnes Emissions CO Emissions CO MWh COE COE Cost Avoided

removal with reference reference removal with 

# / } { / $ } {

2 2 

# − −

=

The CO 2 

## avoided costs for the SC PC and GEE IGCC cases are presented in Exhibit ES

- 12 and Exhibit ES

- 13 , respectively. The SC PC cases use the corresponding non

- capture SC PC reference. The IGCC cases are presented both relative to the equivalent IGCC without carbon capture and SC PC without capture plants. For the SC PC plant, the CO 2 

## avoided costs decrease as the CO 2 

## capture level increases until reaching minimum values at 95 percent capture (Case 1F).

12Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 12 Supercritical PC CO 2 

### Avoided Costs

$0 $20 $40 $60 $80 $100 $120 $140

Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99% 

### 103

79

69 67 66 65 68CO2Avoided Cost, $/tonne



### Capture with Bypass Capture without Bypass



## The CO 2 

## avoided costs for the GEE IGCC cases decrease as the CO 2 

## capture level increases , until reaching minimum values at 85 to 90 percent capture (Case s D3E and D4A ). As a result, this analysis concludes that 85 to 90 percent is the optimal CO 2 

## capture level for a GEE IGCC power plant.

13Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 13 IGCC CO 2 

### Avoided Costs

$0 $20 $40 $60 $80 $100 $120 $140

D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97% 

### 129 128

93

79
71 128

94

80

71 67 66 67 67

49 49 45 43 42 49 45 44 42 42 43 45 46CO2Avoided Cost, $/tonne 

### Relative to SCPC w/o CCS Relative to IGCC w/o CCS

No WGS Two WGS w/ Bypass One WGS w/ Bypass Two WGS w/o Bypass


# Cost and Performance Summary The following conclusions can be drawn from this analysis.

• At all levels of carbon capture considered in this analysis, an IGCC plant will operate more efficiently than a SC PC plant. This high er efficiency result s in lower fuel costs and reduced coal handling costs for the same level of power output

.

• At lower levels of CO 2 

## capture, the COE of a SC PC plant is less than an IGCC plant. However this COE advantage begins to disappear as capture level increases. For CCS greater than approximately 90 percent , IGCC and SC PC have costs of electricity that are nearly equal. This same trend applies to plant capital costs (expres sed in $/kW).

• CO 2 

## avoided costs , using analogous non

- capture plants as reference, are substantially low er for IGCC than for SC PC, for all levels of capture. This is reflective of the relative ly low er cost impact associated with adding CO 2 

## controls to an IGCC plant compared to SC PC. However, the avoided CO 2 

## costs for IGCC capture plants, using the SC PC non

- capture reference plant, are higher due to the higher COE of non

- capture IGCC plants.

14Carbon Dioxide Capture Sensitivity Analysis



## • CO 2 

## avoided costs for SC PC plants are high f or low levels of CCS, and then start to diminish as the capture increases. Gradually, a minimum is reached around 95% CCS, before costs start to rise again slightly. This suggests that if a SC PC plant will lay out the additional capital required to inst all CO 2 

## controls, that equipment could be used most cost

- effectively by capturing as much carbon dioxide as possible (up to about 95%).

• CO 2 

## avoided costs for IGCC (relative to an IGCC non

- capture plant) are less volatile than SC PC over a wide range of cap ture. Although they generally decrease as the level of CCS increases (similar to SC PC), the spread between the high and low values is small relative to SC PC. Since an IGCC system is a more complex process, it better lends itself to optimization than a SC PC plant. To accommodate the specified level of CO 2 

## capture, there were numerous variables that were manipulated simultaneously (including the number of water gas shift reactors, the amount of shift steam required, solvent circulation rate, and the syn gas bypass rate) to minimize the cost and performance impact

. The SC PC plant, although in most cases less expensive than IGCC, is a simpler process and therefore exhibits less potential for optimization. A summary of SC PC and IGCC plant costs and perf ormance are shown in Exhibit ES

- 14 and Exhibit ES

- 15 , respectively.

15Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 14 Cost and Performance Results for the Supercritical PC Cases
Case 0 1A 1B 1C 1D 1E 1F 1G

CO 2 

### Capture, % 0% 30% 50% 70% 85% 90% 95% 99% Gross Power Output, MW e 

### 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6
Net Power Output, MW e 

### 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0 Net Plant Efficiency, % (HHV) 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7 Net Plant Heat Rate, Btu/kWh (HHV) 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269 Coal Flowrate (lb/hr) 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561 Total CO 2 

### Captured, lb/MWh net 

### NA 588 1,057 1,582 2,037 2,213 2,398 2,674 CO 2 

### Capture & Compression Cost, $x1000 NA $ 190,138 $ 266,902 $ 336,794 $ 441,781 $ 463,389 $ 485,273 $ 516,797 Total Plant Cost, $x1000 $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914 Owner’s Costs, $x1000 $ 207,800 $ 258,649 $ 285,448 $ 312,458 $ 344,744 $ 353,249 $ 362,267 $ 380,090 Total Overnight Cost, $x1000 $ 1,113,701 $ 1,397,338 $ 1,544,390 $ 1,691,155 $ 1,870,197 $ 1,916,138 $ 1,964,657 $ 2,059,004 Total Overnight Cost, $/kW $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744
Total As

- Spent Capital, $x1000 $ 1,262,937 $ 1,592,965 $ 1,760,604 $ 1,927,917 $ 2,132,024 $ 2,184,397 $ 2,239,708 $ 2,347,264
Total As

- Spent Capital, $/kW $ 2,296 $ 2,896 $ 3,201 $ 3,505 $ 3,876 $ 3,972 $ 4,072 $ 4,268 CO 2 

### Capital Cost Penalty a 

### , $/kW NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719 Cost of Electricity b 

### , mills/kWh 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65 COE CO 2 

### Penalty a 

### , mills/kWh NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8 Percent increase in COE a 

### , % NA 30.1 43. 3 57. 5 72.3 77. 1 81. 7 91. 3 Cost of CO 2 

### Avoided a 

### , $/tonne NA 102.8 79.1 69.2 67.2 65.9 64.7 68.2 CO 2 

### Emissions, lb/MMBtu 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0 CO 2 

### Emissions, lb/MWh net 

### 1,765 1,385 1,055 687 369 246 126 27 SO 2 

### Emissions, lb/MMBtu 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016 SO 2 

### Emissions, lb/MWh 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170 NO x 

### Emissions, lb/MMBtu 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 NO x 

### Emissions, lb/MWh 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752 PM Emissions, lb/MMBtu 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 PM Emissions, lb/MWh 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140 Hg Emissions, lb/TBtu 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 Hg Emissions, lb/TWh 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3 Raw Water Withdrawal, gpm 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664 Raw Water Consumption, gpm 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961 Raw Water Consumption, gal/MWh net 

### 469 534 593 706 806 846 881 978

a 

### Relative to Case 0 ( SC PC without capture from 2010 Bituminous Baseline study)
b 

### Capacity factor is 85% for the SC PC cases



## 16Carbon Dioxide Capture Sensitivity Analysis



### Exhibit ES

- 15 Cost and Performance Results for the GEE IGCC Cases
Case 2
- D1A 2
- D1B 2
- D2A 2
- D2B 2
- D2C 2
- D2D 2
- D3A 2
- D3B 2
- D3C 2
- D3D 2
- D3E 2
- D4A 2
- D4B 2
- D4C
CO 2 

### Capture, % 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97% Gross Power Output, MW e 

### 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6 Net Power Output, MW e 

### 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9 Net Plant Efficiency, % (HHV) 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5 Net Plant Heat Rate, Btu/kWh (HHV) 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840 Coal Flowrate (lb/hr) 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856 Total CO 2 

### Captured, lb/MWh net 

### NA 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269 CO 2 

### Capture & Compression Cost, $x1000 0 $ 166,439 $ 166,741 $ 193,350 $ 212,092 $ 231,604 $ 167,196 $ 194,185 $ 212,378 $ 230,775 $ 242,919 $ 251,958 $ 264,505 $ 228,358 Total Plant Cost, $x1000 $ 1,235,944 $ 1,345,298 $ 1,346,066 $ 1,389,128 $ 1,419,771 $ 1,449,191 $ 1,346,380 $ 1,390,235 $ 1,419,640 $ 1,447,904 $ 1,465,871 $ 1,472,866 $ 1,483,871 $ 1,488,149 Owner’s Costs, $x1000 $ 286,161 $ 308,679 $ 308,860 $ 319,113 $ 326,535 $ 333,624 $ 308,914 $ 319,358 $ 326,551 $ 333,508 $ 337,972 $ 338,851 $ 341,323 $ 342,287 Total Overnight Cost, $x1000 $ 1,522,105 $ 1,653,977 $ 1,654,925 $ 1,708,241 $ 1,746,306 $ 1,782,815 $ 1,655,294 $ 1,709,592 $ 1,746,192 $ 1,781,411 $ 1,803,843 $ 1,811,717 $ 1,825,194 $ 1,830,436 Total Overnight Cost, $/kW $ 2,447 $ 2,724 $ 2,726 $ 2,891 $ 3,019 $ 3,161 $ 2,727 $ 2,897 $ 3,024 $ 3,160 $ 3,253 $ 3,335 $ 3,453 $ 3,501
Total As

- Spent Capital, $x1000 $ 1,735,200 $ 1,885,534 $ 1,886,615 $ 1,947,394 $ 1,990,789 $ 2,032,409 $ 1,887,035 $ 1,948,935 $ 1,990,658 $ 2,030,809 $ 2,056,381 $ 2,065,358 $ 2,080,721 $ 2,086,697
Total As

- Spent Capital, $/kW $ 2,790 $ 3,105 $ 3,108 $ 3,296 $ 3,442 $ 3,604 $ 3,109 $ 3,303 $ 3,447 $ 3,602 $ 3,709 $ 3,802 $ 3,937 $ 3,991 CO 2 

### Capital Cost Penalty a 

### , $/kW $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054 Cost of Electricity b 

### , mills/kWh 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8 COE CO 2 

### Penalty a 

### , mills/kWh NA 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4 Percent increase in COE a 

### , % NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1% Cost of CO 2 

### Avoided a 

### , $/tonne NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0 CO 2 

### Emissions, lb/MMBtu 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5 CO 2 

### Emi ssions , lb/MWh net 

### 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71 SO 2 

### Emissions, lb/MMBtu 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 SO 2 

### Emissions, lb/MWh 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 NO x 

### Emissions, lb/MMBtu 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049 NO x 

### Emissions, lb/MWh 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382 PM Emissions, lb/MMBtu 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071
PM Emissions, lb/MWh 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056 Hg Emissions, lb/TBtu 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 Hg Emissions, lb/TWh 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48 Raw Water Withdrawal, gpm 4,734 4,692 4,697 5,038 5,300 5,530 4,695 5,040 5,307 5,569 5,748 5,817 5,739 5,707 Raw Water Consumption, gpm 3,755 3,722 3,727 4,033 4,270 4,481 3,725 4,034 4,276 4,514 4,677 4,741 4,679 4,654 Raw Water Consumption, gal/MWh net 

### 362 368 368 410 443 477 368 410 444 480 506 524 531 534

a 

### Relative to Case 2 D1A (0% CO 2 

### capture)
b 

### Capacity factor is 80% for the GEE IGCC cases



## 17Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

18Carbon Dioxide Capture Sensitivity Analysis



# 1. Introduction

1.1 Study Background

Coal

- fired power plants account for approximately 50 percent of the power generation in the United States and approximately 80 percent of the greenhouse gas ( GHG ) emissions produced by the power generation sector [ 6 ]. Because coal

- fired power generation is such a large contributor to both national energy security and overall GHG emissions, it is important to develop methods for reducing the carbon footprint of coal

- fired power plants to mitigate environmental concerns while co ntinuing to reliably satisfy power demand. The e ffects of GHG reduction in the power industry could even be felt in the transportation industry if plug

- in hybrid electric vehicles, fueled by low

- GHG power, play a larger role in the overall transportation fleet

. Levels of CO 2 

## in the atmosphere have shown a steady rise from approximately 300 ppm in 1940 to more than 3 9 0 ppm in 20 10 [ 7 ]. At the same time, various studies have documented noticeabl e changes in the earth’s climate during recent years , and model predictions suggest that CO 2 

## levels play a role in these climate changes [ 8 ]. Given the potential implications surrounding global climate change and increasing concentrations of CO 2 

## in the atmosphere, technology and policy options are being inv estigated for avoiding CO 2 

## emissions. The U.S. Department of Energy (DOE) seeks to develop technology capable of capturing and sequestering 90 percent of the C O 2 

## produced in pulverized coal ( PC ) and integrated gasification combined cycle ( IGCC ) power pla n ts that can achieve a significantly lower cost of electricity relative to the conventional technology components portrayed in this analysis.



# 1.2 Project Objectives
The study objective was to ident ify the optimal CO 2 

## capture leve l at new SC PC and IGCC power plants by employing state

- of

- the

- art control technologies in multiple process configurations. The objective of Case 1 is to evaluate the technical and economic performance of a new SC PC power plant equipped with Econamine FG Plus SM 

## for post

- combu stion CO 2 

## capture in the following increments: 30, 50, 70, 85 , 90, 95, and 99 percent capture. More detailed, predictive acid gas removal (AGR) modeling is utilized to more accurately represent the performance of the CO 2 

## separation process, and to determi ne if an optimum level of control exists. This case also includes verification (via literature search) that less than 90 percent CO 2 

## capture is most economical using a ‘slip

- stream’ approach.

The Case 2 objective is to evaluate the technical and economic performance of four des igns for a
new General Electric Energy ( GEE ) IGCC power plant with pre

- combustion CO 2 

## capture using a physical solvent

- b ased SelexolTM system :

• Design 1 (D1) has no water gas shift ( WGS ) reactor. T he minimum (0 percent ) and maximum ( 25 percent ) CO 2 

## capture levels for this particular configuration are

19Carbon Dioxide Capture Sensitivity Analysis



## modeled. Due to the high level of integration between the H 2 

## S and CO 2 

## absorbers, it was not feasible to model no CO 2 

## capture with a two

- stage SelexolTM system. Consequently, D1A (0 perce nt capture) emplo ys a one

- stage SelexolTM unit for hydrogen sulfide ( H 2 

## S ) control, while D1B (25 percent capture) utilizes a two

- stage SelexolTM unit to maximize CO 2 

## capture from the unshifted syngas. D1 includes a carbonyl sulfide ( COS ) hydrolysis unit to treat the entire syngas stream.

• Design 2 (D2) has one

- stage WGS with CO 2 

## capture ranging from 25 percent (upper limit from D 1) to the maximum achievable limit for this particular configuration (75 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

## removal efficiency

. The SelexolTM removal efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The combined syngas stream (shi fted and unshifted gas) is routed through a COS hy drolysis unit.

• Design 3 (D3) has two

- stage WGS with CO 2 

## capture ranging from 25 percent (upper limit from D 1) to the maximum achievable limit for this particular configuration (85 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

## remo val efficiency

. The SelexolTM removal efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The WGS bypass stream passes through a COS hydrolysis unit.

• Design 4 (D4) has two

- stage WGS and no bypass with CO 2 

## capture ranging from 90 to 97 percent . To achieve greater than 90 percent CO 2 

## removal, the two

- stage SelexolTM CO 2 

## removal efficiency is increased by raising the solvent circulation rate, which increases the size and cost of the SelexolTM s ystem. D4 does not include a COS hydrolysis unit since sufficient COS to H 2 

## S conversion occurs across the two WGS reactors. The facilities will be located in the Illinois coal basin using high

- sulfur bituminous Illinois No. 6 coal as the feedstock to pr oduce electric power. The study include s compression of the captured CO 2 

## to pipeline pressure (2,215 psia) , pipeline transport 80 kilometers (50 miles ), storage in a saline formation at a depth of 1,239 meters (4,055 ft) , and monitoring for 80 years . The site will have appropriate access to rail transportation for delivery of coal. All local coal handling facilities will be included in the design and cost estimation portion of this study.

20Carbon Dioxide Capture Sensitivity Analysis



# 2. General Evaluation Basis

For Case 1, an Aspen model for a SC PC power plant, coupled with detailed simulations of the Econamine FG Plus SM 

## process using Optimized Gas Treating’s ProTreatTM, was utilized to evaluate the technical and economic performance of post

- combustion CO 2 

## captur e in the following increments: 30, 50, 70, 85 , 90, 95, and 99 percent capture. The Case 1 SC PC descriptions are summarized in Exhibit 2

- 1

.
Exhibit 2
- 1 Case 1 Supercritical PC Plant Configuration Summary

Case CO 2 

### Capture Intended Storage Boiler Steam psig/°F/°F Oxidant NO x 

### Control Sulfur Control
1 A 30%

Saline Formation Wall

- fired, PC 3500/1100/110 0 Air LNB/OFA/SCR 0.07 lb/ MM Btu Wet FGD 0.1 lb/ MM Btu 1B 50% 1C 7 0% 1D 85 % 1E 90% 1F 95% 1G 99%



## Optimized Gas Treating’s rate

- based ProTreatTM software was used to generate performance estimates for the Econamine FG Plus SM 

## process . Initially, 90 percent CO 2 

## removal was modeled by adjusting three key process parameters: (1) the circulation rate for th e 30 wt%

m onoethanolamine ( MEA ) solution; (2) the reboiler steam flow rate; and (3) the height of packing material in the absorption and stripping columns. For greater than 90 percent CO 2 

## removal, the MEA and reboiler steam flow rates were increased, while the packing height in the absorption and stripping columns was also raised to model 99 percent CO 2 

## removal.

A literat ure search was conducted to verify that <90 percent CO 2 

## capture is mo st economical using a “ slip

- stream ” (or bypass) approach. Indeed, the slip

- stream approach is more cost

effective for <90 percent CO 2 

## capture than removing reduced CO 2 

## fractions from the entire flue gas stream , according to multiple peer

- reviewed studies [ 1 , 2 , 3 ] . The cost of CO 2 

## ca pture with the Econamine process is dependent on the volume of gas being treated and a reduction in flue gas flow rate will (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of the CO 2 

## absorption columns; (3) trim the cooling water requirement of the direct contact cooling system; and (4) decrease the amount of fan power required to increase flue gas temperature and plume buoyancy. As a result, the ‘slip

- stream’ appr oach for <90 percent CO 2 

## capture leads to low er capital and operating costs. Consequently, less than 90 percent CO 2 

## removal was modeled by bypassing a portion of the flue gas around the Econamine system. Thus, for these cases the inlet flue gas flow rate was adjusted in ProTreatTM, along with the MEA and reboiler steam flow rates, to simulate CO 2 

## removals ranging from 30 percent to 85 percent

.

21Carbon Dioxide Capture Sensitivity Analysis



## For each case, the CO 2 

## removal efficiency and reboiler steam duty obtained from ProTreatTM were incorporated in to the complete SC PC power plant Aspen model to determine the coal feed rate required to maintain a net electric generation capacity of 550 MWe. This approach allows for an equitable comparison of the seven CO 2 

## capture cases. Due to the range of CO 2 

## capt ure levels analyzed in Case 1, the Econamine capital and operating costs vary for the seven cases. While a factored approach that relies on the quantity of CO 2 

## captured for equipment sizing and cost estimation was employed, the cost estimates for the Econ amine system were also developed based, in part, on output data from the ProTreatTM simulations. In particular, the ProTreatTM model output provided absorption and stripping column diameters for each case, which were used to determine the required number of absorption trains. For this analysis, it was assumed that the maximum absorption column diameter is 20 meters, based on information released by Fluor [ 4 ]. As a result, cost estimates for three CO 2 

## capture levels

– 30 percent (1A), 50 percent (1B), and 70 percent (1C)

– are based on a single absorption and compression train. To calculate the capital cost for a single absorption train, it was assumed that the absorption columns represent 40 percent of the total capital cost for a two

- train Econamine system. For Case 2, an Aspen model for a GE E IGCC power plant, coupled with analysis of different process configurations (i.e., water gas shift bypass ratio and SelexolTM CO 2 

## removal efficiency) , was utilized to evaluate the technical and economic performance of pre

- combustion CO 2 

## capture for the fou r plant designs:

• D1 has no WGS reactor. T he minimum (0 percent ) and maximum ( 25 percent ) CO 2 

## capture levels for this particular configuration are modeled. Due to the high level of integration between the H 2 

## S and CO 2 

## absorbers, it is not feasible to mode l no CO 2 

## capture with a two

- stage SelexolTM system. Consequently, D1A (0 percent capture) employs a one

- stage SelexolTM unit for H 2 

## S control, while D1B (25 percent capture) utilizes a two

- stage SelexolTM unit to maximize CO 2 

## capture from the unshif ted syngas . D1 includes a COS hydrolysis unit to treat the entire syngas stream.

• D2 has one

- stage WGS with CO 2 

## capture ranging from 25 percent (upper limit from D 1) to the maximum achievable limit for this particular configuration (75 percent ) by varying the WGS by pass ratio and the two

- stage SelexolTM CO 2 

## removal efficiency

. The SelexolTM removal efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The combined syngas stream (shi fted and unshifted gas) is routed through a COS hydrolysis unit.

• D3 has two

- stage WGS with CO 2 

## capture ranging from 25 percent (upper limit from D 1) to the maximum achievable limit for this particular configuration (85 percent ) by varying the WGS bypass ra tio and the two

- stage SelexolTM CO 2 

## removal efficiency

. The SelexolTM removal efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The WGS bypass stream passes through a COS hydrolysis unit.

• D4 has two

- stage WGS and no bypass with CO 2 

## capture ranging from 90 to 97 percent . To achieve greater than 90 percent CO 2 

## removal, the two

- stage SelexolTM

22Carbon Dioxide Capture Sensitivity Analysis



## CO 2 

## removal efficiency is increased by raising the solvent circulation rate, which increases the siz e and cost of the SelexolTM system. D4 does not include a COS hydrolysis unit since sufficient COS to H 2 

## S conversion occurs across the two WGS reactors.
The Case 2 IGCC design descriptions are summarized in Exhibit 2

- 2

.
Exhibit 2
- 2 Case 2 GEE IGCC Plant Configuration Summary

Case CO 2 

### Capture CO 2 

### Separation Intended Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur Control D1A 0% N/A N/A

GE E Radiant

Only 1800/1050/1050 95 mol% O 2 

### N/A

SelexolTM D1B 25%

SelexolTM 2 nd 

### Stage Saline Formation N/A D2A 25% One

- Stage with bypass D2B 45% D2C 60% D2D 75% D3A 25%

Two

- Stage with bypass D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% Two

- Stage without bypass D4B 95% D4C 97%



## To determine the process configurations for less than 90 percent CO 2 

## removal (IGCC D2 and D3), the WGS bypass ratio and SelexolTM CO 2 

## removal efficiency were varied over a series of Aspen simulations of the entire GEE IGCC power plant to evaluate the impact on WGS and SelexolTM costs and net plant efficiency. As a starting point, the SelexolTM CO 2 

## removal efficiency (92.4 percent ) used to model 90 percent CO 2 

## removal was fixed [ 5 ], and the WGS bypass ratio was adjusted to achieve the desired level of capture. The CO 2 

## removal level was then held constant by decreasing both the WGS bypass ratio (i.e., routing more syngas through the WGS reactor(s)) and the SelexolTM CO 2 

## removal efficiency. These step changes in the WGS bypass ratio lead to an increase in CO 2 

## partial pressure, which relaxes the CO 2 

## removal required by the SelexolTM process.

As shown in Exhibit 2

- 3 , the cost of the WGS system decreases as the WGS bypass ratio in creases since the quantity of s y n gas being shifted declines. The SelexolTM system cost increases with the WGS bypass ratio sinc e a higher solvent circulation rate is required to maintain 60 percent CO 2 

## removal as the CO 2 

## partial pressure at the SelexolTM inlet decreases. However, the total cost of the WGS and SelexolTM systems, which is dominated by the cost of the SelexolTM system, gradually increases with the WGS bypass ratio. Meanwhile, the net plant

23Carbon Dioxide Capture Sensitivity Analysis



## higher heating value ( HHV ) efficiency passes through a maximum value over the range of WGS bypass ratios. As a result, the WGS bypass ratios and SelexolTM CO 2 

## removal efficiencies us ed to model less than 90 percent CO 2 

## removal in this study (IGCC D2 and D3) correspond to the maximum net plant HHV efficiency.

Exhibit 2
- 3 Net Efficiency and Cost as a Function of WGS Bypass Ratio for 60% CO 2 

### Removal with IGCC Design 3

34 34.2 34.4 34.6 34.8 35 35.2 35.4 35.6 35.8 36

$0 $20,000 $40,000 $60,000 $80,000 $100,000 $120,000 $140,000 $160,000 $180,000

0 0.1 0.2 0.3 0.4 0.5Net Plant HHV Efficiency, %Capital Cost, $000



## WGS Bypass Ratio Total Cost
Selexol Cost
WGS Cost Efficiency



## This procedure was repeated for each level of total CO 2 

## removal analyzed for IGCC D2 and D3 to determine the optimal WGS bypass ratio and SelexolTM CO 2 

## removal efficiency for these intermediate capture points. Data for these optimal configurations is provided in Exhibit 2

- 4 and Exhibit 2

- 5 for IGCC D2 and D3, respectively. These results indicate that the SelexolTM CO 2 

## removal efficiency increases with CO 2 

## partial pressure, which is the expected trend with a physical solvent

- based system.

Exhibit 2
- 4 Process Configurations for IGCC D2

Total CO 2 

### Removal (%) WGS WGS Bypass Ratio (%) SelexolTM CO 2 

### Removal (%) P CO2 

### (psia)

25 One

- Stage with Bypass 99 .5 85

. 8 119.4
45 60 8 9 186.3
60 28.75 8 9.5 229.8
75 0 91 265.5



## 24Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 5 Process Configurations for IGCC D3

Total CO 2 

### Removal (%) WGS WGS Bypass Ratio (%) SelexolTM CO 2 

### Removal (%) P CO2 

### (psia)

25

Two

- Stage with Bypass 99.75 86

. 31 119. 7
45 6 9.4 90.04 186.5
60 45 90.1 230.1
75 21 90.4 26 4.3
85 5 9 0.52 289. 3



## A typical offering from a commercial catalyst vendor is a S:DG molar ratio of 0.3 at the outlet of the final WGS reactor. However , for less than 90 percent CO 2 

## capture (IGCC D2 and D3), this study uses a S:DG molar ratio of 0. 25 at the outlet of the final WGS reactor. Operating with a lower S:DG ratio impedes the kinetics of CO to CO 2 

## conversion. Consequently, larger and more costly WGS reactors are required for a similar degree of conversion. A lthough a reduction in S:DG ratio requires a larger reactor volume (this analysis assumes a volume increase of 30 percent , and subsequently a 30 percent increase in reactor cost), the benefit of steam savings

– which can then expanded through the steam tur bine to produce additional power

– is more than adequate to offset the increase in capital cost. Thermal input to the IGCC plant is used to fully

- load the combustion turbines. Any remaining energy in the combustion turbine exhaust is extracted to the ma ximum extent possible in a heat recovery steam generator in order to raise steam to generate additional power. The net power for the IGCC cases ranges from 523 to 622 MW. The range in net output is caused by the wide variance of CO 2 

## capture imposed from case

- to

- case. The differences in auxiliary loads are primarily attributed to CO 2 

## compression and the need for extraction steam in the WGS reactions, which reduces steam turbine output. For each of the plant configurat ions in this study, an Aspen model w as developed and used to generate material and energy balances. The material and energy balances were used as the basis for generating the capital and operating cost estimates. Ultimately a COE was calculated for each of the cases and is reported as the revenue requirement figure

- of

- merit. The balance of this section provides details on the site charac teristics, coal characteristics and costs , the study environmental targets, assumed capacity factor, raw water usage, and the cost estimating methodology

.


# 2.1 S ite Characteristics

The SC PC and GE E IGCC plants are assumed to be located at a generic site in the m idwestern United States . The ambient conditions, consistent with the International Standard Organization (ISO) [ 9 ] , and site characteristics are presented in Exhibit 2

- 6 and Exhibit 2

- 7 , respectively.

25Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 6 Site Ambient Conditions Elevation, ft 0 Barometric Pressure, psia 14.696 Design Ambient Temperature, Dry Bulb, ° F 59 Design Ambient Temperature, Wet Bulb, ° F 51.5 Design Ambient Relative Humidity, % 60

Exhibit 2
- 7 Site Characteristics
Location Greenfield, m idwestern United States 1 

### Topography Level Size, acres 300 Transportation Rail Ash Disposal Off Site Water Municipal (50%) / Groundwater (50%) Access Land locked , having also access by train and highway

CO 2 

### Compressed to 15.3 MPa (2,215 psia), transported 50 miles and sequestered in a saline formation at a depth of 4,055 feet

1 

## Champaign County, Illinois , is assumed for assessment of construction costs. The following design parameters will be considered site

- specific, and will not be quantified for this study. Allowances for normal conditions and constru ction will be included in the cost estimates.

• Flood plain considerations

• Existing soil/site conditions

• Water discharges and reuse

• Rainfall/snowfall criteria

• Seismic design

• Buildings/enclosures

• Fire protection

• Local code height requirements

• Noise regulatio ns

– Impact on site and surrounding area

26Carbon Dioxide Capture Sensitivity Analysis



# 2.2 Coal Characteristics a nd Cost
The design coal char acteristics are presented in Exhibit 2

- 8 . All cases in this study were modeled using Illinois No. 6 bituminous coal.

Exhibit 2
- 8 Design Coal
**Coal seam nomenclature** Herrin (No. 6) **Coal name** Illinois No. 6 **Mine** Old Ben No. 26 **ASTM D388 Rank** High Volatile A Bituminous **Proximate Analysis** As
- Received Dry

Moisture 11.12% 0.00% Volatile Matter 34.99% 39.37% Ash 9.70% 10.91% Fixed Carbon 44.19% 49.72% Total 100.00% 100.00% **Ultimate Analysis** As
- Received Dry

Carbon 63.75% 71.73% Hydrogen 4.50% 5.06% Nitrogen 1.25% 1.41% Sulfur 2.51% 2.82% Chlorine 0.29% 0.33% Ash 9.70% 10.91% Moisture 11.12% 0.00% Oxygen 6.88% 7.74% Total 100.00% 100.00% **Reported Heating Value** As
- Received Dry

HHV (Btu/lb) 11,666 13,126 LHV (Btu/lb) 11,252 12,660 HHV (kJ/kg) 27,135 30,531 LHV (kJ/kg) 26,171 29,447



## 27Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 8 Design Coal (continued) **Typical Ash Mineral Analysis** Silica SiO 2 

### 45.0% Aluminum Oxide Al 2 

### O 3 

### 18.0% Titanium Dioxide TiO 2 

### 1.0% Iron Oxide Fe 2 

### O 3 

### 20.0% Calcium Oxide CaO 7.0% Magnesium Oxide MgO 1.0% Sodium Oxide Na 2 

### O 0.6% Potassium Oxide K 2 

### O 1.9% Phosphorus Pentoxide P 2 

### O 5 

### 0.2% Sulfur Trioxide SO 3 

### 3.5% Undetermined 1.8% Total 100.0% **Typical Ash Fusion Temperatures (°F)**  Reducing Initial

– Limited deformation 1950 oF Softening H=W 2030 oF Hemispherical H=1/2W 2140 oF Fluid 2150 oF Oxidizing Initial

– Limited deformation 2250 oF Softening H=W 2300 oF Hemispherical H=1/2W 2430 oF Fluid 2450 oF **Hardgrove Grindability Index** 60 HGI



## 28Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 8 Design Coal (continued) **Average Trace Element Composition of Coal Shipped by Illinois Mines, Dry basis, ppm** 

Trace Element Arithmetic Mean Standard Deviation Arsenic As 7.5 8.1 Boron B 90 45 Beryllium Be 1.2 0.7 Cadmium Cd 0.5 0.9 Chlorine Cl 1671 1189 Cobalt Co 3.5 1.3 Chromium Cr 14 6 Copper Cu 9.2 2.5 Fluorine F 93 36 Mercury Hg 0.09 0.06 Lithium Li 9.4 7.1 Manganese Mn 38 32 Molybdenum Mo 8.4 5.7 Nickel Ni 14 5 Phosphorus Ph 87 83 Lead Pb 24 21 Tin Sb 0.9 0.7 Selenium Se 1.9 0.9 Thorium Th 1.5 0.4 Uranium Ur 2.2 1.9 Vanadium V 31 16 Zinc Zn 84.4 84.2 Note: Average trace element composition of coal shipped by Illinois mines is based on 34 samples, 2004 Keystone Coal Industry Manual [ 10 ]



## The mercury content in the Illinois No. 6 coal is reported as an arithmetic mean value of 0.09 ppm (dry basis) with standard deviation of 0.06. Hence, as illustrated in Exhibit 2

- 9 , there is a 50 percent probability that the mercury content in the Illinois No. 6 coal would not exceed 0.09 ppm (dry basis), and 99.9 percent probability that the mercury content in th e Illinois No. 6 coal would not exceed 0.28 ppm (dry basis).

29Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 9 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

0.00 ppm Hg 0.05 ppm Hg 0.10 ppm Hg 0.15 ppm Hg 0.20 ppm Hg 0.25 ppm Hg 0.30 ppm Hg Mercury Concentraion in Coal, ppm dbProbability Illinois #6 Sample Will Be At or Below ValueP:\X_GEMSET\0_GEMSET Fuels Price Database\Rev.0 Fuels\[IllinoisNo6 Mercury.xls] Rev. 00 11/21/05 10:

Arithmetic Mean = 0.09 ppm db Standard Deviation = 0.06 ppm db



### Source: 2004 Keystone Coal Industry Manual, Mining Media Publication 

## For the cases in this study, coal mercury content was assumed to be equal to the arithmetic mean mercury concentration plus one standard deviation, or 0.15 ppmd. About 84 percent of the coal samples represented in Exhibit 2

- 9 have a mercury concentration equal to or less than 0.15 ppmd. The coal cost used in this study is $1.55/GJ ($1.64/MMBtu) (2007 cost of coal in June 2007 dollars) . This cost was determined using the following information from the EIA 2008 AEO:

• The 2007 minemouth cost of Illinois No. 6 in 2006 dollars, $32.66/tonne ($29.63/ton), was obtained from Supplemental Table 112 of the EIA’s 2008 AEO for eastern interior hig h

- sulfur bituminous coal.

• The cost of Illinois No. 6 coal was escalated to 2007 dollars using the gross domestic product (GDP) chain

- type price index from AEO 2008, resulting in a price of $33.67/tonne ($30.55/ton) [ 11 ]. Transportation costs for Illinois No. 6 were estimated to be 25 percent of the minemouth cost based on the average transportation rate of the respective coals to the surrounding regions [ 12 ]

. The final delivered costs for Illinois No. 6 coal used in the ca lculations is $42.09/tonne ($38.18/ton) or $1.55/GJ ($1.64/MMBtu). (Note: The Illinois No. 6 coal cost of $1.6366/MMBtu was used in calculations, but only two decimal places are shown in the report.)

30Carbon Dioxide Capture Sensitivity Analysis



# 2.3 Design Sorbent Composition

Limestone from Greer Limestone mine in Morgantown, WV , is assumed as a design sorbent for the SC PC plant [ 13 ]. Sorbent is delivered to plant storage by truck. Limestone analysis is presented in Exhibit 2

- 10

.
Exhibit 2
- 10 Sorbent Analysis
Supplier Greer Industries, Inc. Analysis, %
Calcium Carbonate CaCO 3 

### 80.40 Magnesium Carbonate MgCO 3 

### 3.50 Silica SiO 2 

### 10.32 Aluminum Oxide Al 2 

### O 3 

### 3.16 Iron Oxide Fe 2 

### O 3 

### 1.24 Sodium Oxide Na 2 

### O 0.23 Potassium Oxide K 2 

### O 0.72 Balance 0.43 Total 100 .00



# 2.4 Environmental Targets
In setting the environmental targets , a number of factors were considered, including current emission regulations, regulation trends, results from recent permitting activities, and the status of current best available control technology (BACT). The current federal regulation governing new fos sil

- fuel fired electric utility steam generating units is the New Source Performance Standards (NSPS) as amended in June 2007 and shown in Exhibit 2

- 11

. This represents the minimum level of control that would be required for a new fossil energy plant [ 14 ]

. Stationary combustion turbine emission limits are further defined in 40 CFR Part 60, Subpart KKKK. The new NSPS standards apply to units with the cap acity to generate greater than 73 MW of power by burning fossil fuels, as well as cogeneration units that sell more than 25 MW of power and more than one

- third of their potential output capacity to any utility power distribution system. In cases where bot h an emission limit and a percent reduction are presented, the unit has the option of meeting one or the other. All limits with the unit lb/MWh are based on gross power output.

31Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 11 Standards of Performance for Electric Utility Steam Generating Units Built, Reconstructed, or Modified After February 28, 2005

New Units Reconstructed Units Modified Units

Emission Limit % Reduction Emission Limit (lb/MMBtu) % Reduction Emission Limit (lb/MMBtu) % Reduction

PM 0.015 lb/MMBtu 99.9 0.015 99.9 0.015 99.8

SO 2 

### 1.4 lb/MWh 95 0.15 95 0.15 90

NO x 

### 1.0 lb/MWh N/A 0.11 N/A 0.15 N/A



## Other regulations that could affect emissions limits from a new plant include the New Source Review (NSR) permitting process and Prevention of Significant Deterioration (PSD). The NSR process requires installation of emission control technology meeting ei ther BACT determinations for new sources being located in areas meeting ambient air quality standards (attainment areas), or Lowest Achievable Emission Rate (LAER) technology for sources being located in areas not meeting ambient air quality standards (non

- attainment areas). The Clean Air Act authorizes EPA to establish regulations to prevent significant deterioration of air quality due to emissions of any pollutant for which a national ambient air quality standard (NAAQS) has been promulgated. Environmental area designation varies by county and can be established only for a specific site location. Based on the EPA Green Book Non

- attainment Area Map , relatively few areas in the

m idwestern United States are classified as “non

- attainment”, and th erefore BACT is chosen here rather than LAER [ 15 ]. In addition to federal regulations, state and local jurisdictions can impose even more stringent regulations on a new facility. However, since each new plant has unique environmental requirements, it was necessary to apply some judgment in setting the environmental targets for this study. For the purpose of this study, BACT was assumed to be adequate.



# 2.4.1 Supercritical PC Plant The environmental approach for this study was to evaluate each case on the same r egulatory design basis. A BACT approach was taken and used uniformly throughout the study. The BACT technologies assumed for this study meet the emission requirements of the 2006 NSPS. The emissions controls employed and the environmental targets are sh own in Exhibit 2

- 12

. The environmental target represents the maximum allowable emissions. In some cases actual emissions are less than the target. Fo r example, amine

- based CO 2 

## capture requires a polishing scrubber to reduce SO 2 

## concentrations to less than 10 ppmv. As a result, the SO 2 

## emissions are substantially less than the environmental target.

32Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 12 Environmental Targets for PC Cases Technology Pulverized Coal Boilers Sulfur Control Technology Wet Limestone FGD
Sulfur Limits 98% efficiency or ≤ 0.10 lb SO 2 

### /10 6 

### Btu
NO x 

### Control Technology LNB w/OFA (or OFO) and SCR in air

- based cases NOx Limits 0.07 lb/10 6 

### Btu PM Control Technology Fabric Filter PM Limits 99.8% or ≤ 0.015 lb/10 6 

### Btu Hg Control Technology Co

- benefit capture Hg Limits 90% removal



# 2.4.2 GEE IGCC Plant The IGCC environmental targets were chosen to match the Electric Power Research Institute’s (EPRI) design basis for their CoalFleet for Tomorrow Initiative and are shown in Exhibit 2

- 13 [ 16 ]

. EPRI notes that these are design targets and are not to be used for permitting values.

The BACT emission limits assumed for this study exceed the emission requirements of the NSPS as amended in June 2007 [ 14 ]. It is possible that state and local requirements could supersede NSPS or BACT and impose even more stringent requirements.

Exhibit 2
- 13 Environmental Targets for IGCC Cases

Pollutant Environmental Target NSPS Limit Control Technology

NO x 

### 15 ppm (dry) @ 15% O 2 

### 1.0 lb/MWh Low

- NO x 

### burners and syngas nitrogen dilution
SO 2 

### 0.0128 lb/MMBtu 1.4 lb/MWh SelexolTM or MDEA

Particulate Matter (Filterable) 0.0071 lb/MMBtu 0.015 lb/MMBtu Quench and water scrubber

Mercury > 90% capture 20 x 10

- 6 lb/MWh Carbon bed



# 2.4.3 Carbon Dioxide

CO 2 

## is not currently regulated. However, the possibility exists that carbon limits will be imposed in the future , and this study examines cases that include a reduction in CO 2 

## emissions. Because

33Carbon Dioxide Capture Sensitivity Analysis



## the form of emission limits, should they be imposed, is not kn own, CO 2 

## emissions are reported on both a lb/(gross) MWh and lb/(net) MWh basis in each emissions table.

For the SC PC cases, it is assumed that all of the fuel carbon is converted to CO 2 

## in the flue gas. T his study analyzes a wide range of CO 2 

## removal ef ficiencies by bypassing a portion of the flue gas around the amine

- based Econamine FG Plus SM 

## process. For the IGCC cases, t his study analyzes a wide range of CO 2 

## removal efficiencies, based on carbon input in the coal and excluding carbon that exits with the gasifier slag, by investigating various process configurations. Process parameters manipulated to control the level of total CO 2 

## removal include the number o f WGS reactors employed, WGS bypass ratio, S:DG ratio at the WGS outlet, and the SelexolTM CO 2 

## removal efficiency.



# 2.5 Capacity Factor
This study assumes that each new plant would be dispatched any time it is available and would be capable of generating maxim um capacity when online; therefore, capacity factor and availability are equal. The availability for combustion cases was determined using the Generating Availability Data System (GADS) from the North American Electric Reliability Cou ncil (NERC) [ 17 ]

. Sin ce there are only two operating IGCC plants in North America, the same database was not useful for determining IGCC availability. Rather, input from EPRI and their work on the CoalFleet for Tomorrow Initiative were used to set the IGCC case capacity facto r. NERC defines an equivalent availability factor (EAF) as a measure of the plant capacity factor assuming there is always a demand for the output. The EAF accounts for planned and scheduled derated hours as well as seasonal derated hours. As such, the E AF matches this study’s definition of capacity factor. The average EAF for coal

- fired plants in the 400

– 599 MW size range was 84.9 percent in 2004 and averaged 83.9 percent from 2000 to 2004. Given that many of the plants in this size range are older, the EAF was rounded up to 85 percent and that value was used as the SC PC plant capacity factor.

EPRI examined the historical forced and scheduled outage times for IGCCs and concluded that the reliability factor (which looks at forced or unscheduled outage ti me only) for a single train IGCC (no spares) would be about 90 percent [ 18 ]. To get the availability factor, one has to deduct the scheduled outage time. In reality, t he scheduled outage time s could differ amongst the different gasifier technolog ies. However, the differences are relatively small and would have minimal impact on the capacity factor, so for this study it was assumed to be constant at a 30

- day planned outage per year (or two 15

- day outages)

. The planned outage would amount to 8.2 percent of the year, so the availability factor would be ( 90 percent

- 8.2 percent), or 81. 8 percent

. There are four operating IGCC’s worldwide that use a solid feedstock and are primarily power producers (Polk, Wabash, Buggenum , and Puertollano). A 2006 report by Higman et al. examined the reliability of these IGCC power generation units and concluded that typical annual

34Carbon Dioxide Capture Sensitivity Analysis



## on

- stream times are around 80 percent [ 19 ] . The capacity factor would be somewhat less than the on

- stream tim e since most plants operate at less than full load for some portion of the operating year. Given the results of the EPRI study and the Higman paper, a capacity factor of 80 percent was chosen for IGCC with no spare gasifier required.

The addition of CO 2 

## c apture was assumed not to impact the capacity factor even without redundant pipelines, wells , or subsurface infrastructure . This assumption was made to enable a comparison based on the impact of capital and variable operating costs only. Any reduction in assumed capacity factor would further increase the COE with CO 2 

## capture

.


# 2.6 Raw Water Withdrawal
A water balance was performed for each case on the major water consumers in the process. The total water demand for each subsystem was determined. Internal recycle water available from various sources like boiler feedwater blowdown and condensate from syngas was applied to offset the water demand. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is the water removed fr om the ground or diverted from a surface

- water source for use in the plant. Raw water consumption is also accounted for and is defined as the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not re turned to the water source it was withdrawn from. Raw water withdrawal was assumed to be provided 50 percent by a publicly owned treatment works (POTW) and 50 percent from groundwater. Raw water withdrawal is defined as the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, boiler feedwater makeup, quench system makeup, and slag handling makeup. The difference between withdrawal and process water returned to the source is consumpti on. Consumption represents the overall impact of the process on the water source. The largest consumer of raw water in all cases is cooling tower makeup. The plants included in this study use a conventional wet cooling tower . Boiler feedwater blowdown a nd a portion of the sour water stripper blowdown were assumed to be treated and recycled to the cooling tower. The cooling tower blowdown and the balance of the sour water stripper ( SWS ) blowdown streams were assumed to be treated and 90 percent returned to the water source with the balance sent to the ash ponds for evaporation.



# 2.7 Cost Estimating Methodology
The estimating methodology for capital costs, operations and maintenance costs, and CO 2 

## TS&M costs are described below. The finance structure, basis fo r the discounted cash flow analysis, and first

- year COE cost calculations are also described.

2.7.1 Capital Costs As illustrated in Exhibit 2

- 14 , this study reports capital cost at four levels: Bare Erected Cost ( BEC ) , Total Plant Cost ( TPC ) , Total Overnight Cost ( TOC ) and Total As

- spent Capital ( TASC )

. BEC, TPC and TOC are “overnight” costs and are expressed in “base

- year” dollars. The base

35Carbon Dioxide Capture Sensitivity Analysis



## year is the fi rst year of capital expenditure, which for this study is assumed to be 2007. TASC is expressed in mixed

- year, current

- year dollars over the entire capital expenditure period, which is assumed to last five years for coal plants (2007 to 201 2 ).

Exhibit 2
- 14 Capital Cost Levels and their Elements



## process equipment supporting facilities direct and indirect labor 

# BEC

TPC

TOC
TASC EPC contractor services process contingency project contingency

preproduction costs inventory capital financing costs other owner’s costs

escalation during capital expenditure period interest on debt during capital expenditure period 

# Bare Erected Cost Total Plant Cost Total Overnight Cost Total As

- Spent Cost

BEC, TPC and TOC are all “overnight” costs expressed in base

- year dollars.
TASC is expressed in mixed

- year current dollars, spread over the capital expenditure period.



## The BEC comprises the cost of process equipment, on

- site facilities and infrastructure that support the plant (e.g., shops, offices, labs, road), and the dire ct and indirect labor required for its construction and/or installation. The cost of EPC services and contingencies is not included in BEC. BEC is an overnight cost expressed in base

- year (2007) dollars.

The TPC comprises the BEC plus the cost of service s provided by the engineering, procurement and construction (EPC) contractor and project and process contingencies. EPC services include: detailed design, contractor permitting (i.e., those permits that individual contractors must obtain to perform their scopes of work, as opposed to project permitting, which is not included here), and project/construction management costs. TPC is an overnight cost expressed in base

- year (2007) dollars.

The TOC comprises the TPC plus owner’s costs. TOC is an “overnight” cost, expressed in base

year (2007) dollars and as such does not include escalation during construction or interest during construction. TOC is an overnight cost expressed in base

- year (2007) dollars. The TASC is the sum of all capital expenditures as they are incurred during the capital expenditure period including their escalation. TASC also includes interest during construction.

36Carbon Dioxide Capture Sensitivity Analysis



## Accordingly, TASC is expressed in mixed, current

- year dollars over the capital expenditure period.

Cost Estimate Basis and Classification The TPC and Operation and Maintenance (O&M) costs for each of the cases in the study were estimated by WorleyParsons us ing an in

- house database and conceptual estimating models. Costs were furthe r calibrated using a combination of adjusted vendor

- furnished and actual cost data from recent design projects.

Recommended Practice 18R

- 97 of the Association for the Advancement of Cost Engineering International (AACE) describes a Cost Estimate Classification System as applied in Engineering, Procurement and Construction for the process industries [ 20 ]

. Most techno

- economic studies completed by NETL feature cost estimates intended for the purpose of a “Feasibility Study” (AACE Class 4). Exhibit 2

- 15 describes the characteristics of an AACE Class 4 Cost Estimate. Cost estimates in this stud y have an expected accuracy range of

- 15%/+30%.
Exhibit 2
- 15 Features of an AACE Class 4 Cost Estimate
Project Definition Typical Engineering Completed Expected Accuracy

1 to 15% plant capacity, block schematics, indicated layout, process flow diagrams for main process systems, and preliminary engineered process and utility equipment lists - 15 % to

- 30% on the low side, and + 20% to +50% on the high side



## Cost estimates in this report reflect nth

- of

- a

- kind (NOAK) costs for plants that only contain fully mature technologies which have been widely deployed at commercial scale, e.g., PC and NGCC power plants without CO2 capture. The cost of such plants has dr opped over time due to the "learning by doing" and risk reduction benefits that result from serial deployments as well as from continuing R&D.
Cost estimates in this report reflect the cost of the next commercial offering for plants that include technol ogies that are not yet fully mature and/or which have not yet been serially deployed in a commercial context, e.g., IGCC plants and any plant with CO2 capture. These cost estimates for next commercial offerings do not include the unique cost premiums asso ciated with first

- of

- a

- kind (FOAK) plants that must demonstrate emerging technologies and resolve the cost and performance challenges associated with initial iterations. However, these estimates do utilize currently available cost bases for emerging technolog ies with associated process contingencies applied at the appropriate subsystem levels.
Cost estimates for all of the plants, regardless of technology maturity, are based on many design assumptions that affect costs, including the use of a favorable site with no unusual characteristics that make construc tion more costly. The primary value of this report lies not in the absolute

37Carbon Dioxide Capture Sensitivity Analysis



## accuracy of cost estimates for the individual cases (estimated to be

- 15%/+30%), but in the fact that all cases were evaluated using a common methodology with an internally consis tent set of technical and economic assumptions. This consistency of approach allows meaningful comparisons of relative costs among the cases evaluated.



# 2.7.2 System Code

- of

- Accounts The costs are grouped according to a process/system oriented code of accounts. This type of code

- of

- account structure has the advantage of grouping all reasonably allocable components of a system or process so they are included in the specific system account. (This would not be the case had a facility, area, or commodity account s tructure been chosen instead).



# 2.7.3 Plant Maturity
The post

- combustion CO 2 

## remova l technology for the PC capture cases is immature technology. This technology remains unproven at commercial scale in power generation applications. The pre

- combustion CO 2 

## removal technology for the IGCC capture cases has a stronger commercial experience base. Pre

- combustion CO 2 

## removal from syngas streams has been proven in chemical processes with similar conditions to that in IGCC plants, but has not been demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO 2 

## removal technology in commercial service, there are currently IGCC plants with CO 2 

## capture in the planning stages.



# 2.7.4 Contracting Strategy The estimates are based on an EPCM approach utilizing m ultiple subcontracts. This approach provides the Owner with greater control of the project, while minimizing, if not eliminating most of the risk premiums typically included in an Engineer/Procure/Construct (EPC) contract price. In a traditional lump su m EPC contract, the Contractor assumes all risk for performance, schedule, and cost. However, as a result of current market conditions, EPC contractors appear more reluctant to assume that overall level of risk. Rather, the current trend appears to be a modified EPC approach where much of the risk remains with the Owner. Where Contractors are willing to accept the risk in EPC type lump

- sum arrangements, it is reflected in the project cost. In today’s market, Contractor premiums for accepting these risks , particularly performance risk, can be substantial and increase the overall project costs dramatically. The EPCM approach used as the basis for the estimates here is anticipated to be the most cost effective approach for the Owner. While the Owner reta ins the risks, the risks become reduced with time, as there is better scope definition at the time of contract award(s).



# 2.7.5 Estimate Scope
The estimates represent a complete power plant facility on a generic site

. The plant boundary limit is defined as the total plant facility within the “fence line” including coal receiving and

38Carbon Dioxide Capture Sensitivity Analysis



## water supply system, but terminating at the high voltage side of the main power transformers. TS&M cost is not included in the reported capital cost or O&M costs, but is treated sep arately and added to the COE.



# 2.7.6 Capital Cost Assumptions
WorleyParsons developed the capital cost estimates for each plant using the company’s in

- house database and conceptual estimating models for each of the specific technologies. This database and the re spective models are maintained by WorleyParsons as part of a commercial power plant design base of experience for similar equipment in the company’s range of power and process projects. A reference bottoms

- up estimate for each major component provides the basis for the estimating models. Other key estimate considerations include the following:

• Labor costs are based on Midwest, Merit Shop. The estimating models are based on U.S. Gulf Coast and the labor has been factored to Midwest. The basis for the fa ctors is the PAS, Inc. (PAS) “Merit Shop Wage & Benefit Survey,” which is published annually. Based on the data provided in PAS, WorleyParsons used the weighted average payroll plus fringe rate for a standard craft distribution as developed for the estimating models. PAS presents information for eigh t separate regions. For this study, Region 5 (IL, IN, MI, MN, OH, and WI) was selected

.

• The estimates are based on a competitive bidding environment, with adequate skilled craft labor available locally.

• Labor is based on a 50

- hour work

- week (5

- 10s). No a dditional incentives such as per

diems or bonuses have been included to attract craft labor.

• While not included at this time, labor incentives may ultimately be required to attract and retain skilled labor depending on the amount of competing work in th e region, and the availability of skilled craft in the area at the time the pr ojects proceed to construction.

• The estimates are based on a greenfield site.

• The site is considered to be Seismic Zone 1, relatively level, and free from hazardous materials, archeological artifacts, or excessive rock. Soil conditions are considered adequate for spread footing foundations. The soil bearing capability is assumed adequate such that piling is not needed to support the foundation loads.

• Costs are limited to wit hin the “fence line,” terminating at the high voltage side of the main power transformers with the exception of costs included for TS&M, which are treated as an addition to COE.

• Engineering and Construction Management a re estimated a t 8

- 10 percent of BEC. These costs consist of all home office engineering and procurement services as well as field construction management costs. Site staffing generally includes a construction manager, resident engineer, scheduler, and personnel for project controls, documen t control, materials management, site safety, and field inspection.

39Carbon Dioxide Capture Sensitivity Analysis



## Price Fluctuations During the course of this study, the prices of equipment and bulk materials fluctuated quite substantially. Some reference quotes pre

- dated the 2007 year cost basis wh ile others were received post

- 2007. All vendor quotes used to develop these estimates were adjusted to June 2007 dollars accounting for the price fluctuations. Adjustments of costs pre

- dating 2007 benefitted from a vendor survey of actual and projected p ricing increases from 2004 through mid

- 2007 that WorleyParsons conducted for another project. The results of that survey were used to validate/recalibrate the corresponding escalation factors used in the conceptual estimating models. The more recent econ omic down turn has resulted in a reduction of commodity prices such that many price indices have similar values in January 2010 compared to June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 and 532.9 in January 2010, and the Gross Domestic Product Chain

- type Price Index was 106.7 on July 1, 2007 and 110.0 on January 1, 2010. While these overall indices are nearly constant, it should be noted that the cost of individual equipment types may still deviate from the June 2007 reference point.

Exclusions The capital cost estimate includes all anticipated costs for equipment and materials, installation labor, professional services (Engineering and Construction Management), and contingency. The following items are excluded from the capital costs:

• All taxes, with the exception of payroll and property taxes (property taxes are included with the fixed O&M costs)

• Site specific considerations

– including, but not limited to, seismic zone, accessibility, local regulatory requirem ents, excessive rock, piles, laydown space, etc.

• Labor incentives in excess of 5

- 10s

• Additional premiums associated with an EPC contracting approach

Contingency Process and project contingencies are included in estimates to account for unknown costs tha t are omitted or unforeseen due to a lack of complete project definition and engineering. Contingencies are added because experience has shown that such costs are likely, and expected, to be incurred even though they cannot be explicitly determined at the time the estimate is prepared. Capital cost contingencies do not cover uncertainties or risks associated with :

• scope changes

• changes in labor availability or productivity

• delays in equipment deliveries

• changes in regulatory requirements

• unexpected cost escalation

• performance of the plant after startup (e.g., availability, efficiency)

40Carbon Dioxide Capture Sensitivity Analysis



## Process Contingency Process contingency is intended to compensate for uncertainty in cost estimates caused by performance uncertainties associated with the development status of a technology. Process contingencies are applied to each plant section based on its current technology status. As shown in Exhibit 2

- 16 , AACE International Recommended Practice 16R

- 90 provides guidelines for estimating process contingency based on EPRI philosophy [ 21 ]

. Process contingencies have been applied to the estimates i n this study as follows:

• Slurry Prep and Feed

– 5 percent on all IGCC cases

• Gasifiers and Syngas Coolers

– 15 percent on all IGCC cases

– next

- generation commercial offering and integration with the power island

• Two Stage Selexol

– 20 percent on all IGCC c apture cases

- unproven technology at commercial scale in IGCC service

• Mercury Removal

– 5 percent on all IGCC cases

– minimal commercial scale experience in IGCC applications

• CO 2 Removal System

– 20 percent on all PC cases

- post

- combustion process unproven at commercial scale for power plant applications

• CTG

– 5 percent on all IGCC non

- capture cases

– syngas firing and ASU integration ; 10 percent on all IGCC capture cases

– high hydrogen firing.

• Instrumentation and Controls

– 5 percent on all IGCC accounts and 5 percent on the PC
cases

– integration issues

Exhibit 2
- 16 AACE Guidelines for Process Contingency

Technology Status Process Contingency (% of Associated P rocess Capital)
New concept with limited data 40+ Concept with bench

- scale data 30

- 70



## 41Carbon Dioxide Capture Sensitivity Analysis



### Small pilot plant data 20

- 35

Full

- sized modules have been operated 5

- 20 Process is used commercially 0

- 10 

## Process contingency is typically not applied to costs that are set equal to a research goal or programmatic target since these values presume to reflect the total cost. Project Contingency AACE 16R

- 90 states that project contingency for a “budget

- type” estimate (AACE Class 4 or 5) should be 15 to 30 percent of the sum of BEC, EPC fees and process contingency. This was used as a general guideline, but some project contingency values outside of this range occur based on WorleyParsons’ in

- house experience.

Owner’s Costs

Exhibit 2

- 18 explains the estimation method for owner’s costs. With some exceptions, the estimation method follows guidelines in Sections 12.4.7 to 12.4.12 of AACE International Recommended Practice No. 16R

- 90 [ 21 ] . The Electric Power Research Institute’s “Technical Assessment Guide (TAG®)

– Power Generation and Storage Technology Options” also has guidelines fo r estimating owner’s costs. The EPRI and AACE guidelines are very similar. In instances where they differ, this study has sometimes adopted the EPRI approach

. Interest during construction and escalation during construction are not included as owner’s cos ts but are factored into the COE and are included in TASC. These costs vary based on the capital expenditure period and the financing scenario. Ratios of TASC/TOC determined from the PSFM are used to account for escalation and interest during constructio n. Given TOC, TASC can be determined from the ratios given in Exhibit 2

- 17

.
Exhibit 2
- 17 TASC/TOC Fac tors

Finance Structure High Risk IOU Low Risk IOU Capital Expenditure Period Five Years Five Years

TASC/TOC 1.140 1.134



## 42Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 18 Owner’s Costs Included in TOC


## Owner’s Cost Estimate Basis

Prepaid Royalties Any technology royalties are assumed to be included in the associated equipment cost, and thus are not included as an owner’s cost.

Preproduction (Start

- Up) Costs • 6 months operating labor

• 1 month maintenance materials at full capacity

• 1 month non

- fuel consumables at full capacity

• 1 month waste disposal

• 25% of one month’s fuel cost at full capacity

• 2% of TPC Compared to AACE 16R

- 90, this includes additional costs for operating labor (6 months versus 1 month) to cover the cost of trainin g the plant operators, including their participation in startup, and involving them occasionally during the design and construction. AACE 16R

- 90 and EPRI TAG® differ on the amount of fuel cost to include; this estimate follows EPRI. Working Capital Although inventory capital (see below) is accounted for, no additional costs are included for working capital.

Inventory

Capital • 0.5% of TPC for spare parts

• 60 day supply (at full capacity) of fuel.

• 60 day supply (at full capacity) of non

- fuel consumables (e.g., chemicals and catalysts) that are stored on site. Does not include catalysts and adsorbents that are batch replacements such as WGS, COS, and SCR catalysts and activated carbon. AACE 16R

- 90 does not include an inventory cost for fuel, but EPRI TAG ® does.

Land • $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)

Financing Cost • 2.7% of TPC This financing cost (not included by AACE 16R

- 90) covers the cost of securing financing, including fees and closing costs but not including interest during construction (or AFUDC). The “rule of thumb” estimate (2.7% of TPC) is based on a 2008 private communication with a capital services firm.



## 43Carbon Dioxide Capture Sensitivity Analysis



## Owner’s Cost Estimate Basis

Other Owner’s

Costs • 15% of TPC This additional lumped cost is not included by AACE 16R

- 90 or EPRI TAG®. The “rule of thumb” estimate (15% of TPC) is based on a 2009 private communication with WorleyParsons. Significant deviation from this value is possible as it is very site and owner specific. The lumped cost includes:

- Preliminary feasibility studies, includ ing a Front

- End Engineering Design (FEED) study

- Economic development (costs for incentivizing local collaboration and support)

- Construction and/or improvement of roads and/or railroad spurs outside of site boundary

- Legal fees

- Permitting costs

- Owner’s engin eering (staff paid by owner to give third

- party advice and to help the owner oversee/evaluate the work of the EPC contractor and other contractors)

- Owner’s contingency (Sometimes called “management reserve”, these are funds to cover costs relating to delayed startup, fluctuations in equipment costs, unplanned labor incentives in excess of a five

- day/ten

hour

- per - day work week. Owner’s contingency is NOT a part of project contingency.) This lumped cost does NOT include:

- EPC Risk Premiums (Costs estimat es are based on an Engineering Procurement Construction Management approach utilizing multiple subcontracts, in which the owner assumes project risks for performance, schedule and cost)

- Transmission interconnection: the cost of interconnecting with power transmission infrastructure beyond the plant busbar.

- Taxes on capital costs: all capital costs are assumed to be exempt from state and local taxes.

- Unusual site improvements: normal costs associated with improvements to the plant site are included in the bare erected cost, assuming that the site is level and requires no environmental remediation. Unusual costs associated with the following design parameters are excluded: flood plain considerations, existing soil/site conditions, water discharges and reu se, rainfall/snowfall criteria, seismic design, buildings/enclosures, fire protection, local code height requirements, noise regulations.



## 44Carbon Dioxide Capture Sensitivity Analysis



## 2.7.7 Operations and Maintenance Costs The production costs or operating costs and related maintenance expenses (O&M) pertain to those charges associated with operating and maintaining the power plants over their expected life. These costs include:

• Operating labor

• Maintenance

– material and l abor

• Administrative and support labor

• Consumables

• Fuel

• Waste di sposal

• Co

- p roduct or b y

- p roduct credit (that is, a negative cost for any by

- products sold) There are two components of O&M costs; fixed O&M, which is independent of power generation, and variab le O&M, which is proportional to power generation. Operating Labor Operating labor cost was determined based on of the number of operators required for each specific case. The average base labor rate used to determine annual cost is $3 4.65 / hour . The
as sociated labor burden is estimated at 30 percent of the base labor rate. Taxes and insurance are included as fixed O&M costs totaling 2 percent of the TPC. Maintenance Material and Labor Maintenance cost was evaluated on the basis of relationships of main tenance cost to initial capital cost. This represents a weighted analysis in which the individual cost relationships were considered for each major plant component or section. Administrative and Support Labor Labor administration and overhead charges are assessed at rate of 25 percent of the burdened O&M labor. Consumables The cost of consumables, including fuel, was determined on the basis of individual rates of consumption, the unit cost of each specific consumable commodity, and the plant annual operati ng hours. Quantities for major consumables such as fuel and sorbent were taken from technology

- specific heat and mass balance diagrams developed for each plant application. Other consumables were evaluated on the basis of the quantity required using ref erence data. The quantities for initial fills and daily consumables were calculated on a 100 percent operating capacity basis. The annual cost for the daily consumables was then adjusted to incorporate the annual plant operating basis, or CF

.

45Carbon Dioxide Capture Sensitivity Analysis



## Initial fills of the consumables, fuels and chemicals, are different from the initial chemical loadings , which are included with the equipment pricing in the capital cost. Waste Disposal Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In this study both slag from the IGCC cases and fly ash and bottom ash from the PC cases are considered a waste with a disposal cost of $17.89/tonne ($16.23/ton). The carbon used for mercury control in the IGCC cases is considered a haza rdous waste with disposal cost of $926/tonne ($840/ton). Co

- Products and By

- Products By

- product quantities were also determined similarly to the consumables. However, due to the variable marketability of these by

- products, specifically gypsum and sulfur, no credit was taken for their potential salable value. It should be noted that by

- product credits and/or disposal costs could potentially be an additional determining factor in the choice of technology for some companies and in selecting some sites. A h igh local value of the product can establish whether or not added capital should be included in the plant costs to produce a particular co

- product. Ash and slag are both potential by

- products in certain markets, and in the absence of activated carbon inje ction in the PC cases, the fly ash would remain uncontaminated and have potential marketability. However, as stated above, the ash and slag are considered wastes in this study with a concomitant disposal cost.

2.7.8 CO 2 

## Transport, Storage and Monitoring

T he capital and operating costs for CO 2 

## TS&M were independently estimated by NETL. Those costs were converted to a TS&M COE increment that was added to the plant COE.

CO 2 

## TS&M was modeled based on the following assumptions:

• CO 2 

## is supplied to the pipeline at the plant fence line at a pressure of 15.3 MPa (2,215 psia). The CO 2 

## product gas composition varies in the cases presented, but is expected to meet the specification described in Exhibit 2

- 19 [ 22 ]. A glycol dryer located near the mid

- point of the compress ion train is used to meet the moisture specification.

46Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 19 CO 2 

### Pipeline Specification
Parameter Units Parameter Value
Inlet Pressure MPa (psia) 15.3 (2,215)
Outlet Pressure MPa (psia) 10.4 (1,515) Inlet Temperature °C (°F) 35 (95)
N 2 

### Concentration ppmv < 300
O 2 

### Concentration ppmv < 40
Ar Concentration ppmv < 10
H 2 

### O Concentration ppmv < 150



## • The CO 2 

## is transported 80 km (50 miles) via pipeline to a geologic sequestration field for injection into a saline formation.

• The CO 2 

## is transported and injected as a SC fluid in order to avoid two

- phase flow and achieve maximum efficiency [ 23 ]

. The pipeline is a ssumed to have an outlet pressure (above the SC pressure) of 8

. 3 MPa (1, 200 psia) with no recompression along the way. Accordingly, CO 2 

## flow in the pipeline was modeled to determine the pipe diameter that results in a pressure drop of 6

. 9 MPa ( 1,0 00 psi) over an 80 km (50 mile) pipeline length [ 24 ]

. (Although not explored in this study, the use of boost compressors and a smaller pipeline diameter could possibly reduce capital costs for sufficiently long pipelines.) The diameter of the injection pipe will be of sufficient size that frictional losses during injection are minimal and no booster compression is required at the well

- head in order to achieve an appropriate down

- hole pressure , with hydrostatic head making up the difference between the injection an d reservoir pressure.

• The saline formation is at a depth of 1,23 6 m (4,055 ft) and has a permeability of 22 millidarcy (md) (22 μm 2 

## ) and formation pressure of 8.4 MPa (1,220 psig) [ 22 ]

. This is considered an average storage site and requires roughly one injection well for each 9,360 tonnes (10,320 short tons) of CO 2 

## injected per day [ 22 ]

. The assumed aquifer characteristics are tabulated in Exhibit 2

- 20

. The cost metrics utilized in this study provide a best estimate of TS&M costs for a “ favorable ” sequestration project, and may vary significantly based on variables such as terrain to be crossed by the pipeline, reservoir characteristics, and number of land owners from wh ich sub

- surface rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics found in the literature, escalated to June 2007

- year dollars using appropriate price indices. These costs were then verified against values qu oted by industrial sources where possible. Where regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of underground pore volume, analogous existing policies were used for representative cost scenarios.

47Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 20 Deep, Saline Aquifer Specification
Parameter Units Base Case

Pressure MPa (psi) 8.4 (1,220)

Thickness m (ft) 161 (530)
Depth m (ft) 1,236 (4,055)
Permeability Md 22
Pipeline Distance km (miles) 80 (50)
Injection Rate per Well tonne (ton) CO 2 

### /day 9,360 (10,320)



## The following sections describe the sources and methodology used for each metric. TS&M Captial Costs TS&M capital costs include both a 20 percent process contingency and 30 percent project contingency. In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur over a longer time period, up to 100 years. In these cases a capital fund is established based on the net present value of the cost out lay, and this fund is then levelized similar to the other costs. Transport Costs

CO 2 

## transport costs are broken down into three categories: pipeline costs, related capital expenditures, and O&M costs. Pipeline costs are derived from data published in the O il and Gas Journal’s (O&GJ) annual Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO 2 

## pipeline, as noted in various studie s [ 22 , 23 , 25 ]

. The University of California performed a regression a nalysis to generate cost curves from the O&GJ data: (1) Pipeline Materials, (2) Direct Labor, (3) Indirect Costs, and (4) Right

- of

- way acquisition, with each represented as a function of pipeli ne length and diameter [ 25 ] . These cost curves were escalated to the June 2007 year dollars used in this study. Related capital expenditures were based on the findings of a previous study funded by DOE/NETL, Carbon Dioxide Se questration in Saline Formations

– Engi neering and Economic Assessment [ 22 ]

. This study utilized a similar basis for pipeline costs ( O&GJ Pipeline cost data up to the year 2000) but added a CO 2 

## surge tank and pipeline control system to the project. Transport O&M costs were assessed using metrics published in a second DOE/NETL sponsored report entitled Economic Evaluation of CO 2 

## Stora ge and Sink Enhancement Options [ 23 ]. This

48Carbon Dioxide Capture Sensitivity Analysis



## study was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the other studies mentioned above either (a) do not report operating costs, or (b) report them in absolute terms for one pipeline, as opposed to as a length

- or di ameter

- based metric. Storage Costs Storage costs were divided into five categories: (1) Site Screening and Evaluation, (2) Injection Wells, (3) Injection Equipment, (4) O&M Costs, and (5) Pore Volume Acquisition. With the exception of Pore Volume Acquisi tion, all of the costs were obtained from Economic Evaluation of CO 2 

## Storage and Sink Enhancement Options [ 23 ]

. These costs include all of the costs associated wi th determining, developing, and maintaining a CO 2 

## storage location, including site evaluation, well drilling, and the capital equipment required for distributing and injecting CO 2 

## . Pore Volume Acquisition costs are the costs associated with acquiring righ ts to use the sub

surface volume where the CO 2 

## will be stored, i.e., the pore space in the geologic formation. These costs were based on recent research by Carnegie Mellon University , which examined existing sub

- surface rights acquisition as it pertains t o natural gas storage [ 26 ]

. The regulatory uncertainty in this area combined with unknowns regarding the number and type (private or government) of property owners, require a number of “best engineering judgment” decisions to be made

. In this study it was assumed that long

- term lease rights were acquired from the property owners in the projected CO 2 

## plume growth region for a nominal fee, and that an annual “rent” was paid when the plume reached each individual acre of their property fo r a period of up to 100 years from the injection start date

. The present value of the life cycle pore volume costs
are assessed at a 10 percent discount rate and a capital fund is set up to pay for these costs over the 100 y ear rent scenario. Liability Protection Liability Protection addresses the fact that if damages are caused by injection and long

- term storage of CO 2 

## , the injecting party may bear financial liability. Several types of liability protection schem e s have been suggested for CO 2 

## storage, i ncluding Bonding, Insurance, and Federal Compensation Systems combined with either tort law (as with the Trans

- Alaska Pipeline Fund), or with damage caps and preemption, as is used for nuclear energy under the Price Anderson Act [ 27 ]

. However, a t present, a specific liability regime has yet to be dictated either at a Federal or (to our knowledge) State level. However, certain state governments have enacted legislation , which assigns liability to the injecting party, either in perpetuity (Wyoming) or until ten years after the cessation of injection operations, pending reservoir integrity certification, at which time liability is turned over to the state (North Dakota and Louisiana) [ 28 , 29 , 30 ]

. In the case of Louisiana, a trust fund totaling five million dollar s is established over the first ten years (120 months) of injection operations for each injector . This fund is then used by the state for CO 2 

## monitoring and, in the event of an at

- fault incident, damage payments. Liability costs assume that a bond must be purchased before injection operations are permitted in order to establish the ability and good will of an injector to address damages where they are deemed liable. A figure of five million dollars was used for the bond based on the Louisiana fund level . This b ond level may be conservative ly high , in that the Louisiana fund covers both liability and monitoring, but that fund also pertains to a certified reservoir where injection

49Carbon Dioxide Capture Sensitivity Analysis



## operations have ceased, having a reduced risk compared to active operations . The b ond cost was not escalated. Monitoring Costs Monitoring costs were evaluated based on the methodology set forth in the International Energy Agency ( IEA ) Greenhouse Gas (GHG) R& D Programme’s Overview of Monitoring Projects for Geologic Storage Projects report [ 31 ]

. In this scenario, operational monitoring of the CO 2 

## plume
occurs over 30 years (during plant operation) and closure monitoring occurs for the following fifty years (fo r a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity survey, and periodic seismic survey ; EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after injection ceases.

2.7.9 Finance Structure, Discounted Cash Flow Analysis, and COE The global economic assumptions are listed in Exhibit 2

- 21

. Finance structures were chosen based on the assumed type of developer/owner (investor

- owned utility (IOU) or independent power producer) and the assumed risk profile of the plant being assessed . For this study the owner/developer was assumed to be an IOU

. Cases were considered either high risk , with the inclusion of CO 2 

## capture , or low risk , without CO 2 

## capture

. Exhibit 2

- 22 describes the high

- risk and low

- risk IOU finance structures that w ere assumed for t his study . Th ese finance structure s w ere recommended in a 2008 NETL report based on interviews with project developers/owners, financial organizations and law firms [ 32 ]

.

50Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 21 Global Economic Assumptions

Parameter Value TAXES Income Tax Rate 38% (Effective 34% Federal, 6% State) Capital Depreciation 20 years, 150% declining balance Investment Tax Credit 0% Tax Holiday 0 years CONTRACTING AND FINANCING TERMS
Contracting Strategy Engineering Procurement Construction Management ( owner assumes project risks for performance, schedule and cost) Type of Debt Financing Non

- Recourse (collateral that secures debt is limited to the real assets of the project) Repayment Term of Debt 15 years Grace Period on Debt Repayment 0 years Debt Reserve Fund None ANALYSIS TIME PERIODS Capital Expenditure Period 5 Years Operational Period 30 years Economic Analysis Period (used for IRROE) 35 Years (capital expenditure period plus operational period) TREATMENT OF CAPITAL COSTS Capital Cost Escalation During Capital Expenditure Period (nominal annual rate) 3.6% 1


### Distribution of Total Overnight Capital over the Capital Expenditure Period (before escalation) 5

- Year Period: 10%, 30%, 25%, 20%, 15% Working Capital zero for all parameters
% of Total Overnight Capital that is Depreciated 100% (this assumption introduces a very small error even if a substantial amount of TOC is actually non

- depreciable) ESCALATION OF OPERATING REVENUES AND COSTS Escalation of COE (revenue), O&M Costs, and Fuel Costs (nominal annual rate) 3.0% 2

1 

### A nominal average annual rate of 3.6 percent is assumed for escalation of capital costs during construction. This rate is equivalent to the nominal average annual escalation rate for process plant construction costs between 1947 and 2008 according to the Chemical Engineering Plant Cost Index.
2 

### An average annual inflation rate of 3.0 percent is assumed. This rate is equivalent to the average annual escalation rate between 1947 and 2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the so

called "headline" index of the various Producer Price Indices. (The Producer Price Index for the Electric Power Generation Industry may be more applicable, but that data does not provide a long

- term historical perspective since it only dates back to December 2003.)



## 51Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 2
- 22 Financial Structure for Investor Owned Utility High Risk Projects

Type of Security % of Total Current (Nominal) Dollar Cost Weighted Current (Nominal) Cost After Tax Weighted Cost of Capital

**Low Risk**

Debt 50 4.5% 2.25%
Equity 50 12% 6%

Total 8.25% 7.39%
**High Risk**

Debt 45 5.5% 2.475%
Equity 55 12% 6.6%

Total 9.075% 8.13%



## DCF Analysis and Cost of Electricity
The NETL Power Systems Financial Model (PSFM) , a nominal

- dollar 3 

## (current dollar) discounted cash flow (DCF) analysis tool , was used to calculate COE 4



## . The COE is the revenue received by the generator per net megawatt

- hour during the power plant’s first year of operation, assuming that the COE escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it remains constant in rea l terms over the operational period of the power plant . To calculate the COE, the PSFM was used to determine a “base

- year” (2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3 percent 5 

## , provided the stipulated internal rate of return on equity over the entire economic analysis period (capital expenditure period plus thirty years of operation). Since this analysis assumes that COE

3 

### Since the analysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect the interplay between depreciation and inflation.

4 

### For this calculation, “cost of electricity” is somewhat of a misnomer because from the power plant’s perspective it is actually the “price” received for the electricity generated to achieve the stated IRROE . However, since the price paid for generation is ultimately charged to the end user, from the customer’s perspective it is part of the cost of electr icity.

5 

### This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S. Department of Labor’s Producer Price Index for Finished Goods. This index was used instead of the Producer Price Index for the Electric P ower Generation Industry because the Electric Power Index only dates back to December 2003 and the Producer Price Index is considered the “headline” index for all of the various Producer Price Indices.



## 52Carbon Dioxide Capture Sensitivity Analysis



## increases over the economic analysis period at the nominal annual general inflation rate, i t remains constant in real terms and the first

- year COE is equivalent to the base

- year COE when expressed in base

- year (2007) dollars. Since 2007 is the first year of the capital expenditure period, it is also the base year for the economic analysis. Acc ordingly, it is convenient to report the results of the economic analysis in base

- year (June 2007) dollars

. Estimating COE with Capital Charge Factors For scenarios that adhere to the global economic assumptions listed in Exhibit 2

- 21 and utilize the finance structure listed in Exhibit 2

- 22 , the following simplified equ ation can be used to estimate COE as a function of TOC 6 

## , fixed O&M, variable O&M (including fuel), capacity factor and net output. The equation requires the application of the capital charge factor s (CCF) listed in Ex hibit 2

- 23 . Th ese CCFs are valid only for the global economic assumptions listed in Exhibit 2

- 21 , the stated finance structure, and the stated capital expenditure period.

Exhibit 2
- 23 Capital Charge Factors for COE Equation

Finance
Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Five Years Five Years

Capital Charge Factor (CCF) 0.124 0.116



## All factors in the COE equation are expressed in base

- year dollars. The base year is the first year of capital expenditure, which for this study is assumed to be 2007. As shown in Exhibit 2

- 21 , all factors (COE, O&M and fuel) are assumed to escalate at a nominal annual general inflation rate of 3.0 percent . Accordingly, all first

- year costs (COE and O&M) are equivalent to base

- year costs when expressed in base

- year (2007) dollars.

6 

### Although TOC is used in the simplified COE equation, the CCF that multiplies it accounts for escalation during construction and interest during construction (along with other factors related to the recovery of capital costs).



## 53Carbon Dioxide Capture Sensitivity Analysis



## w here: COE = revenue received by the generator ($/MWh, equivalent to mills/kWh) during the power plant’s first year of operation ( but expressed in base

year dollars ), assuming that the COE escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it remains constant in real terms over the operational period of the power plant. CCF = capital charge factor taken from Exhibit 2

- 23 that matches the applicable finance structure and capital expenditure period TOC = total overnight capital, expressed in base

- year dollars OC FIX 

## = the sum of all fixed annual operating costs, expressed in base

- year dollars OC VAR 

## = the sum of all variable annual operating costs, including fuel at 100 percent capacity factor, expressed in base

- year dollars CF = plant capacity factor, assumed to be constant over the operational period
MWH = annual net me gawatt

- hours of power generated at 100 percent capacity factor

2.8 IGCC STUDY COST ESTI MATES COMPARED TO IN DUSTRY ESTIMATES The estimated TOC for IGCC cases in this study ranges from $2, 447 for IGCC with 0% capture to $ 3,501 /kW for IGCC with 97% capture . Plant size ranges from 523

- 622 MW (net) for 0% and 97% capture plants, respectively

. Within the power industry there are several power producers interested in pursuing construction of an IGCC plant. While these projects are still in the relatively e arly stages of development, some cost estimates have been published. Published estimates tend to be limited in detail, leaving it to the reader to speculate as to what is contained within the estimate. In November 2007, the Indiana Utility Regulatory Com mission approved Duke Energy’s proposal to build an IGCC plant in Edwardsport, Indiana. The estimated cost to build the 630 MW plant is $4,472/kW in June 2007 dollars. Duke expects the plant to begin operation in 2012. Other published estimates for similar proposed non

- CO 2 

## capture gasification plants range from

54Carbon Dioxide Capture Sensitivity Analysis



## $2,483/kW to $3,122/kW in June 2007 dollars. Corresponding plant sizes range form 770

- 600 MW , respectively. Published estimates from similar CO 2 

## capture facilities range from $4,581/kW to $5,408/kW, in June 2007 dollars, with sizes ranging from 400 to 580 MW [ 33 , 34 , 35 , 36 ]. 7



## Differences in Cost Estimates Project Scope For this report, the scope of work is generally limited to work inside the project “fence line”. For outgoing power, the scope stops at the high side terminals of the Generator Step

- up Transformers (GSUs). Some typical examples of items outside the fenceline include:

• New access roads and railroad tracks

• Upgrades to existing roads to accommodate increased traffic

• Makeup water pi pe outside the fenceline

• Landfill for on

- site waste (slag) disposal

• Natural gas line for backup fuel provisions

• Plant switchyard

• Electrical transmission lines & substation Estimates in this report are based on a generic mid

- western greenfield site having “ normal” characteristics. Accordingly, the estimates do not address items such as:

• Piles or caissons

• Rock removal

• Excessive dewatering

• Expansive soil considerations

• Excessive seismic considerations

• Extreme temperature considerations

• Hazardous or contaminat ed soils

• Demolition or relocation of existing structures

• Leasing of offsite land for parking or laydown

• Busing of craft to site

• Costs of offsite storage This report is based on a reasonably “standard” plant. No unusual or extraordinary process equipment is included such as:

• Excessive water treatment equipment

• Air

- cooled condenser

7 

### Costs were adjusted to June 2007 using the Chemical Engineering Plant Cost Inde x



## 55Carbon Dioxide Capture Sensitivity Analysis



## • Automated coal reclaim

• Zero Liquid Discharge equipment

• SCR catalyst (IGCC cases only)
For non

- capture cases, which are likely the most appropriate comparison against industry pub lished estimates, this report is based on plant equipment sized for non

- capture only. None of the equipment is sized to accommodate a future conversion to CO 2 

## capture.

Labor This report is based on Merit Shop (non

- union) labor. If a project is to use Un ion labor, there is a strong likelihood that overall labor costs will be greater than those estimated in this report. This report is based on a 50 hour work week, with an adequate local supply of skilled craft labor. No additional incentives such as per

- diems or bonuses have been included to attract and retain skilled craft labor. Contracting Methodology The estimates in this report are based on a competitively bid, multiple subcontract approach, often referred to as EPCM. Accordingly, the estimates do not include premiums associated with an EPC approach. It is believed that, given current market conditions, the premium charged by an EPC contractor could be as much as 30 percent or more over an EPCM approach.

56Carbon Dioxide Capture Sensitivity Analysis



# 3. Case 1

- Supercritical PC with Variable CO 2 

# Capture

3.1 System Descriptions

The SC PC system descriptions are provided in the subsections below.



# 3.1.1 Coal and Sorbent Receiving and Storage

The function of the coal portion of the Coal and Sorbent Receiving and Storage system is to provide the equipment re quired for unloading, conveying, preparing, and storing the fuel delivered to the plant. The scope of the system is from the coal conveyor receiving hoppers up to the coal storage silos. The system is designed to support short

- term operation at maximum p ower output at the 5 percent over pressure/valves wide open (OP/VWO) condition (16 hours) and long

- term operation of 90 days or more at the maximum continuous rating (MCR). The scope of the sorbent receiving and storage systems includes truck roadways, tur narounds, unloading hoppers, conveyors, and the day storage bin. Operation Description

– The 3" x 0 bituminous Illinois No. 6 coal is delivered to the site by unit trains of 100

- ton rail cars. Each unit train consists of 100, 100

- ton rail cars. The unloading is done by a trestle bottom dumper, which unloads the coal to two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. The 3" x 0 coal from the feeder is discharged onto a belt conveyor (No. 1). The coal is then transferred to a conveyor (No. 2) that transfers the coal to the reclaim area. The conveyor passes under a magnetic plate separator to remove tramp iron, and then to the reclaim pile. Coal from the reclaim pile is fed by two vibratory feeders, located under the pile, onto a belt conveyor (No. 3), which transfers the coal to the coal surge bin located in the crusher tower. The coal is reduced in size to 11⁄4" x 0 by the coal crusher. The coal is then transferred by conveyor (No. 4) to th e transfer tower. In the transfer tower the coal is routed to the tripper that loads the coal into one of the parallel boiler silos.

L ime is delivered to the site using 23 tonne (25 ton) trucks and conveyed to storage. Lime is stored in a bulk storage li me silo. The lime is pneumatically conveyed to a day bin.



# 3.1.2 Steam Generator and Ancillaries The steam ge nerator for the supercritical plant is a once

- through, spiral

- wound, Benson

- boiler, wall

- fired, balanced draft type unit with a water

- cooled dry bottom furnace. It includes a superheater, reheater, economizer, and air heater. It is assumed for the purposes of this study that the power plant is designed to be operated as a base

- loaded unit but with some consideration for daily or weekly cycling, as can be cost effectively included in the base design.

57Carbon Dioxide Capture Sensitivity Analysis



## The combustion systems for superc ritical steam conditions are equipped with low

- NO x 

## burners ( LNBs ) and overfire air ( OFA )

. 3.1.2.1 Scope and General Arrangement The steam generator comprises the following:

• Once

- through type steam generator • Low NOx Coal burners and light oil igniters / warmup system • Startup circuit, including integral separators

• Water

- cooled furnace, dry bottom • Soot blower system • Primary air (PA) fans

• Two

- stage superheater • Air preheaters (Ljungstrom type) • Induced draft (ID) fans

• Reheater • Coal feeders and pulverizers • Forced draft (FD) fans

• Economizer • Spray type desuperheater • Overfire air system The steam generator operates as follows:

3.1.2.2 Feedwater and Steam

Feedwater enters the botto m heade r of the economizer and passes upward through the economizer tube bank , through stringer tubes that support the primary superheater, and discharges to the economizer outlet headers. From the outlet headers, water flows to the furnace hopper inlet headers via external downcomers. Water then flows upward through the furnace hopper and furnace wall tubes. From the furnace, water flows to the steam water separator. During low load operation (operation below the critical point), the water from the separator is returned to the economizer inlet with the boiler recirculating pump. Operation at loads above the critical point is once through. Steam flows from the separator through the furnace roof to the convection pass enclosure walls, primary superheater, throu gh the first stage of water attemperation, to the furnace platens. From the platens, the steam flows through the second stage of attemperation and then to the intermediate superheater. The steam then flows to the final superheater and on to the outlet pi pe terminal. Two stages of spray attemperation are used to provide tight temperature control in all high temperature sections during rapid load changes. Steam returning from the turbine passes through the primary reheater surface, then through crossover p iping containing inter

- stage attemperation. The crossover piping feeds the steam to the final reheater banks and then out to the turbine. Inter

- stage attemperation is used to provide outlet temperature control during load changes.

3.1.2.3 Air and Combustion Products Combustion air from the FD fans is heated in Ljungstrom type air preheaters, recovering heat energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as

58Carbon Dioxide Capture Sensitivity Analysis



## secondary air. Air for conveying pulverized coal to t he burners is supplied by the PA fans. This air is heated in the Ljungstrom type air preheaters to permit drying of the pulverized coal, and a portion of the air from the PA fans bypasses the air preheaters to be used for regulating the outlet coal/air te mperature leaving the mills. The pulverized coal and air mixture flows to the coal nozzles at various elevations of the furnace. The hot combustion products rise to the top of the boiler and pass through the superheater and reheater sections. The gases then pass through the economizer and air preheater. The gases exit the steam generator at this point and flow to the Selective Catalytic Reduction (SCR) reactor, FGD system, fabric filter, ID fan, and stack.

3.1.2.4 Fuel Feed The crushed coal is fed through feed ers to each of the mills (pulverizers), where its size is reduced to approximately 72 percent passing 200 mesh with less than 0.5 percent remaining on 50 mesh [ 37 ]

. The pulverized coal exits each mill via the coal piping and is distributed to the coal nozzles in the furnace walls using air supplied by the PA fans.

3.1.2.5 Ash Removal The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. Th e hoppers are of welded steel construction, lined with refractory. The hopper design incorporates a water

- filled seal trough around the upper periphery for cooling and sealing. Water and ash discharged from the hopper pass through the clinker grinder to an ash sluice system for conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite disposal. The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to break up any clinkers t hat may form. From the clinker grinders the bottom ash is sluiced to hydrobins for dewatering and offsite removal by truck. The steam generator incorporates fly ash hoppers under the economizer outlet and air heater outlet.

3.1.2.6 Burners A boiler of this capac ity employs approximately 24 to 36 coal nozzles arranged at multiple elevations. Each burner is designed as a low

- NO x 

## configuration, with staging of the coal combustion to minimize NO x 

## formation. In addition, overfire air nozzles are provided to further stage combustion and thereby minimize NO x 

## formation.

Oil

- fired pilot torches are provided for each coal burner for ignition, warm

- up and flame stabilization at startup and low loads.

3.1.2.7 Soot Blowers

The soot

- blowing system utilizes an array of 50 to 150 retra ctable nozzles and lances that clean the furnace walls and convection surfaces with jets of high

- pressure steam. The blowers are sequenced to provide an effective cleaning cycle depending on the coal quality and design of the furnace and convection surfac es. Electric motors drive the soot blowers through their cycles.

59Carbon Dioxide Capture Sensitivity Analysis



# 3.1.3 NO x 

# Control System
The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. Two measures are taken to reduce the NO x 

## . The first is a combination of low

- NOx burners and the introduction of staged overfire air in the boiler. The low

- NO x 

## burners and overfire air reduce the emissions to about 0.2 lb/MMBtu. The second measure taken to reduce the NOx emissions is the installation of a SCR system prior to the air heater. SCR uses aqueous ammonia and a catalyst to reduce NO x 

## to N 2 

## and H 2 

## O. The SCR system consists of three subsystems: reactor vessel, ammonia storage and injection, and gas flow control. The SCR system is designed for 65 percent reduction with 2 ppmv ammo nia slip at the end of the catalyst life. This, along with the low

- NO x 

## burners, achieves the emission limit of 0.07 lb/MMBtu. The SCR capital costs are included with the boiler costs, as is the cost for the initial load of catalyst.

Selective non

- catalyti c reduction (SNCR) was considered for this application. However, with the installation of the low

- NO x 

## burners and overfire air system, the boiler exhaust gas contains relatively small amounts of NO x 

## , which makes removal of the quantity of NO x 

## with SNCR to reach the emissions limit of 0.07 lb/MMBtu difficult. SNCR works better in applications that contain medium to high quantities of NO x 

## and require removal efficiencies in the range of 40 to 60 percent. SCR, because of the catalyst used in the reaction, c an achieve higher efficiencies with lower concentrations of NO x 

## . Operation Description

– The reactor vessel is designed to allow proper retention time for the ammonia to contact the NOx 

## in the boiler exhaust gas. Ammonia is injected into the gas immediate ly prior to entering the reactor vessel. The catalyst contained in the reactor vessel enhances the reaction between the ammonia and the NO x 

## in the gas. Catalysts consist of various active materials such as titanium dioxide, vanadium pentoxide, and tungst en trioxide. The operating range for vanadium/titanium

- based catalysts is 260 °C (500 ° F) to 455 °C (850 ° F). The boiler is equipped with economizer bypass to provide flue gas to the reactors at the desired temperature during periods of low flow rate, such as low load operation. Also included with the reactor vessel is soot

- blowing equipment used for cleaning the catalyst. The aqueous ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, dilution air skid, and injection grid. The flue gas flow control consists of ductwork, dampers, and flow straightening devices required to route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass and associated dampers for low load temperature control are also included.



# 3.1.4 Particulate Control A pulse

- jet baghouse with air to cloth ratio of 3.5 ft/min is located after the air heater . The baghouse is provided with a spare compartment for off line cleaning to maintain the opacity at 10

60Carbon Dioxide Capture Sensitivity Analysis



## percent or less. The waste will be pneumatically conveyed to a waste storage silo with a 3

- day storage capacity, which is in accordance with typical utility design. Operation Description

– The bag house is designed to achieve 99.8 percent removal efficien cy and consists of two separate single

- stage, in

- line, and 10

- compartment units. Each unit is a high air

- to

- cloth ratio design with a pulse

- jet on

- line cleaning system. The ash is collected on the outside of the 8 meter long bags, which are supported by steel cages. The dust cake is removed by a pulse of compressed air. The bag material is polyphenylensulfide (PPS) with an intrinsic Teflon (PTFE) coating [ 38 ]. Each compartment contains a number of gas passages with filter bags and heated ash hoppers sup ported by a rigid steel casing. The fabric filter is provided with necessary control devices, inlet gas distribution devices, insulators, inlet and outlet nozzles, expansion joints, and other items as required. T he fabric filter reduces particulate loadi ng in the stack gas to below the required levels.



# 3.1.5 Flue Gas Desulfurization

3.1.5.1 Wet FGD Process

The limestone

- based, forced oxidation flue gas scrubbing system is designed to remove 98 percent of the SO 2 

## from the flue gas. The design incorporates features wh ich have been developed over many years of commercial operation and pilot work in utility flue gas cleaning. Listed below are the major items that comprise the wet FGD portion of the tower systems. 1. Limestone silos with weigh feeders, capable of supplying the required limestone to the slurry handling systems 2. Limestone preparation systems 3. Absorber 4. Cyclone separators, with spares sufficient to meet the requirements of the FGD absorber systems for gypsum slurry primary dewatering 5. Oxidation air compressors 6. Vac uum filter system

Exhibit 3

- 1 sh ows a typical wet FGD process flow diagram.

61Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 1 Typical B&W Wet FGD Process Flow Diagram

Source: B&W Figure



## 62Carbon Dioxide Capture Sensitivity Analysis



## 3.1.5.2 Absorber Tower

Exhibit 3

- 2 shows a typical wet scr ubber absorber tower arrangement . The absorber tower includes two gas distribution devices (trays), two spray headers of countercurrent absorber sprays, and a two

- stag e mist eliminator section. As the flue gas enters the absorber, it turns upward and is evenly distributed across the absorber cross

- section by the absorber tray. Experience has shown that such a gas distribution device is needed to optimize SO 2 

## removal. This experience parallels that of the electrostatic precipitator industry and their need for carefully designed gas distribution plates. In addition to providing an even gas flow for the main spray zone, the absorber tray also provides an area of intimat e contact between the flue gas and limestone slurry

. The gas leaving the absorber tray passes through several countercurrent spray levels, which are supplied with recirculating slurry from the absorber's reaction tank, and continues through two layers of C hevron type mist eliminators for water droplet removal before exiting the absorber tower through the outlet cone and outlet flue.

The in

- situ o xidation system provides oxygen to the absorber reaction tank via an ambient air stream . This oxygen system forc es calcium sulfite (CaSO 3 

## ·1⁄2H 2 

## O ) formed by the SO 2 

## removal process to be oxidized to calcium sulfate (CaSO 4 

## ·2H 2 

## O). Absorber recirculation pumps mounted on modularized base plates provide assemblies for easy installation. The assemblies can be bolted dire ctly to concrete foundations. Four recirculation pumps are supplied. Three are required for operation at the normal operation design point.

Exhibit 3
- 2 Wet Scrubber Arrangement

Normal Liquid Level

3 8 ’

- 0 18’

- 0 h 41’

- 0 w 22’

- 6 h 28’

- 6 w

1 33 ’

-

58’

- 0
Source: B&W Figure



## 63Carbon Dioxide Capture Sensitivity Analysis



## 3.1.5.3 Limestone Preparation System The function of the limestone handling and reagent preparation system is to receive, store, convey, and grind the limestone delivered to the plant. The scope of the system is from the storage pile up to the limestone feed syst em. The system is designed to support continuous baseload operation. Truck roadways, turnarounds, and unloading hoppers are included in this reference plant design. For the purposes of this conceptual design, limestone is assumed to be delivered to the p lant by 25

- ton trucks. The limestone is unloaded onto a storage pile located above vibrating feeders. The limestone is fed onto belt conveyors via vibrating feeders and then to day bins equipped with vent filters. Each day bin supplies a 100 percent cap acity size ball mill via a weigh feeder. The wet ball mill accepts the limestone and grinds the limestone to 90 to 95 percent passing 325 mesh (44 microns). Water is added at the inlet to the ball mill to create limestone slurry. The reduced limestone s lurry is then discharged into a mill slurry tank. Mill recycle pumps, two per tank, pump the limestone water slurry to an assembly of hydrocyclones and distribution boxes. The slurry is classified into several streams, based on suspended solids content a nd size distribution. The hydrocyclone underflow with oversized limestone is directed back to the mill for further grinding. The hydrocyclone overflow with correctly sized limestone is routed to a reagent storage tank. Reagent distribution pumps direct s lurry from the tank to the absorber module.

3.1.5.4 Gypsum Dewatering Gypsum slurry is bled from the absorber by absorber blowdown pumps that feed a primary cyclone separator which concentrates the solids of the gypsum slurry stream. Hydrocyclone overflow is grav ity fed to the back to the absorber. Hydrocyclone underflow is gravity fed to the vacuum filters. Each hydrocyclone is supplied with a valve network which can isolate flow to individual hydrocyclones. To reduce the suspended solids in the system, a smal l volume of the hydrocyclone overflow is pumped by two purge pumps (1 operating, 1 spare) to the wastewater treatment system. Cyclone separator underflow gravity flows to the belt vacuum filters for further dewatering. The gypsum is dewatered to 90 perc ent solids and washed to produce wallboard quality gypsum, which drops from the belt vacuum filters onto a conveying system. The vacuum receiver filtrate pumps pump the filtrate from the belt vacuum filters to the filtrate water tank. The filtrate water is recycled back to the FGD system by means of the filtrate water pumps. One filtrate water tank is provided with minimum storage capacity of 4 hours of water usage by the absorber at full load normal operation. One wash tank for combined use of the mist eliminator wash system with a minimum storage capacity of 15 minutes is provided.

3.1.5.5 Mercury Removal

Removal of 90 percent of the mercury entering with the coal is achieved in a combination of equipment and processes. Since the Illinois No. 6 coal is relativ ely high in chlorine, most of the mercury entering with the coal will leave the boiler in an oxidized form (85

- 90 percent ). The

64Carbon Dioxide Capture Sensitivity Analysis



## SCR system will further promote the oxidation of Hg. Some additional oxidation will occur in the airheater, and a small portio n of the mercury (oxidized and elemental) will be captured with unburned carbon in the baghouse. The majority of the oxidized mercury will be captured in the wet scrubber. An inexpensive additive is injected into the wet scrubber to enhance mercury
remov al and inhibit any re

- emission to achieve the 90 percent removal rate.



# 3.1.6 Flue Gas System/Stack
The flue gas from the air preheater will be sent to the absorbers. The gases enter the baghouse to collect the waste products and the fly ash. Flue gas exits the baghouse and enters the Induced Draft (ID) fan suction.



# 3.1.7 Carbon Dioxide Recovery Facility

The CO 2 

## recovery fac ility consists of the Fluor Econamine FG Plus SM 

## system foll owed by compression and drying

. 3.1.7.1 Econamine FG Plus SM


## A Carbon Dioxide Recovery (CDR) f acility is used to remove 30 to 99 percent of the CO 2 

## in the flue gas exiting the FGD unit, purify it, and compress to a supercritical condition. The CDR is comprised of the flue gas supply, SO 2 

## polishing, CO 2 

## absorption, solvent stripping and reclaiming, and CO 2 

## compression and drying.

The CO 2 

## absorption/stripping/solvents recl aim process is based on the Fluor Econamine FG Plus SM 

## technology [ 39 ]. A typical flow sheet is shown in Exhibit 3

- 3 . The Econamine FG Plus SM 

## process uses a formulation of monethanolamine (MEA ) and a proprietary corrosion inhibitor to recover CO 2 

## from the flue gas. This process is designed to recover high

- purity CO 2 

## from low

- pressure streams that contain oxygen, such as flue gas from coal

- fired power plants, gas turbine exh aust gas, and other waste gases.

SO 2 

## Polishing and Flue Gas Cooling To prevent the accumulation of heat stable salts, the incoming flu e gas must have an SO 2 

## concentration of 10 ppmv or less. Th is is achieved by passing the gas exiting the FGD system through an SO 2 

## polishing step. The polishing step consists of a non

- plugging, low

- differential

pressure, spray

- baffle

- type scrubber using a 20 wt% solution of sodium hydroxide (NaOH). A removal efficiency of 80 to 85 percent is necessary to reduce SO 2 

## emissions from the FGD outlet to 10 ppmv as required by the Econamine process. The polishing scrubber proposed for this application has been demonstrated in numerous industrial applications throughout the world and can achieve removal efficiencies of over 95 percent if necessary.

The polishing scrubber also serves as the flue gas cooling system . Cooling water from the PC plant is used to reduce the temperature and hence moisture content of the saturated flue gas exiting the FGD system. Flue gas is cooled beyond the CO 2 

## absorption process requirements to

65Carbon Dioxide Capture Sensitivity Analysis



## 32 °C (90 °F) to account for the subsequent temperature increase of about 17 °C (30 °F) in the flue gas blower. Downstream from the Polishing Scrubber flue gas pressure is boosted in the Flue Gas Blowers by approximately 0.014 MPa (2 psi) to overcome pressure drop in the CO 2 

## absorber tower.

Circulating Water System

Coolin g water is provided from the PC plant circulating water system and returned to the plant cooling tower. The CDR facility requires a significant amount of cooling water for flue gas cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the lean solvent cooler, and CO 2 

## compression interstage cooling. The cooling water requirements for the CDR facility range from 246 m 3 

## /min (65,000 gpm) to 1,314 m 3 

## /min (347,000 gpm).

CO 2 

## Absorption The cooled flue gas enters the botto m of the CO 2 

## Absorber and flows up through the tower countercurrent to a stream of lean MEA

- based solvent (Econamine FG Plus SM 

## ). Depending on the case, 90 to 99 percent of the CO 2 

## in the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorber section and flows into the water wash section of the tower. The lean solvent enters the top of the absorber, absorbs the CO 2 

## from the flue gases, and leaves the bottom of the absorber with the absorbed CO 2 

## .
Water Wash Section

The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The flue gas from the top of the CO 2 

## Absorption section is contacted with a re circulating stream of water for the removal of most of the lean so lvent. The scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water stream from the bottom of the wash section is collected on a chimney tray. A portion of the water c ollected on the chimney tray spills over to the absorber section as water makeup for the amine with the remainder pumped via the Wash Water Pump and cooled by the Wash Water Cooler, and recirculated to the top of the CO 2 

## Absorber. The wash water level is maintained by water makeup from the Wash Water Makeup Pump.

66Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 3 Fluor Econamine FG Plus SM 

### Typical Flow Diagram



## 67Carbon Dioxide Capture Sensitivity Analysis



## Rich/Lean Amine Heat Exchange System

The rich solvent from the bottom of the CO 2 

## Absorber is preheated by the lean solvent from the Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the Solvent Stripper for removal of the absorbed CO 2 

## . The stripped solvent from the bottom of the Solvent Stripper is pumped via the Hot Lean Solvent Pumps through the Rich Lean Exchanger to the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream of the lean solvent is pumped via the Solvent Filter Feed Pump through the Solvent Filter Package to prevent buildup of contaminants in the solution. From the Solvent Surge Tank the lean solvent is pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler for further cooling, after wh ich the cooled lean solvent is returned to the CO 2 

## Absorber, completing the circulating solvent circuit.

Solvent Stripper The purpose of the Solvent Stripper is to separate the CO 2 

## from the rich solvent feed exiting the bottom of the CO 2 

## Absorber. The ric h solvent is collected on a chimney tray below the bottom packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the rich solvent is heated by steam, stripping the CO 2 

## from the solution. Steam is provided from the LP sec tion of the steam turbine at 0.51 MPa (74 psia) and 292 °C (557 °F). The hot wet vapor from the top of the stripper containing CO 2 

## , steam, and solvent vapor, is partially condensed in the Solvent Stripper Condenser by cross exchanging the hot wet vapor wi th cooling water. The partially condensed stream then flows to the Solvent Stripper Reflux Drum where the vapor and liquid are separated. The uncondensed CO 2 

## - rich gas is then delivered to the CO 2 

## product compressor. The condensed liquid from the Solvent Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a portion of condensed overhead liquid is used as make

- up water for the Water Wash section of the CO 2 

## Absorber. The rest of the pumped liquid is routed back to the Solvent Strippe r as reflux, which aids in limiting the amount of solvent vapors entering the stripper overhead system.

Solvent Stripper Reclaimer A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent Stripper Reclaimer for the re moval of high

- boiling nonvolatile impurities (heat stable salts

- HSS), volatile acids and iron products from the circulating solvent solution. The solvent bound in the HSS is recovered by reaction with caustic and heating with steam. The solvent reclaim er system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank.

Steam Condensate

St eam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler

68Carbon Dioxide Capture Sensitivity Analysis



## Condensate Drum and returned to the steam cycle between boiler feedwater heaters 4 and 5 via the Solvent Reboiler Condensate Pumps. Corrosion Inhibitor System A proprietary corrosion inhibitor is continuously injected into the CO 2 

## Absorber rich so lvent bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. This constant injection is to help control the rate of corrosion throughout the CO 2 

## recovery plant system.
Gas Compression and Drying System In the comp ression section, the CO 2 

## is compressed to 15.3 MPa (2,215 psia) by a six

- stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable power distribution and discharge temperatures across the various stages as shown in Exhibit 3

- 4

.

Exhibit 3
- 4 CO 2 

### Compressor Interstage Pressures

Stage Outlet Pressure, MPa (psia)

1 0.35 (51)

2 0.77 (112)

3 1.69 (245)

4 3.71 (538)

5 8.16 (1,184)

6 15.3 (2,215)



## Power consumption for this large compressor was estimated assuming a polytropic efficiency of 86 percent and mechanical efficiency of 98 percent. During compression to 15.3 MPa (2,215 psia) in the multiple

- stage, intercooled compressor, the CO 2 

## stream is dehydrated to a dewpoint of

- 40 oC (

- 40 °F) with triethylene glycol. The virtually moisture

- free supercritical CO 2 

## stream is delivered to the plant battery limit as seq uestration

- ready. CO 2 

## TS&M costs were estimated and included in COE using the methodology described in Section 2.7

.


# 3.1.8 Steam Turbine Generator System

The steam turbi ne is a tandem compound type, consisting of HP

- IP

- two LP (double flow) sections enclosed in three casings, designed for condensing single reheat operation, and equipped with non

- automatic extractions and four

- flow exhaust. The turbine drives a hydrogen

- co oled generator. The turbine has DC motor

- operated lube oil pumps, and main lube oil pumps, which

69Carbon Dioxide Capture Sensitivity Analysis



## are driven off the turbine shaft [ 40 ]

. The exhaust pressure is 35.6 cm (1.4 in) Hg in the single pressure condenser. The condenser is two

- shell, transverse, single pressure with divided waterbox for each shell. The steam turbine is designed for long

- term operation (90 days or more) at MCR with throttle control valves 95 percent open. It is also capable of a short

- term 5 perce nt OP/VWO condition (16 hours).

T urbine bearings are lubricated by a closed

- loop, water

- cooled pressurized oil system. Turbine shafts are sealed against air in

- leakage or steam blowout using a labyrinth gland arrangement connected to a low

- pressure steam seal system. The generator stato r is cooled with a closed

- loop water system consisting of circulating pumps, shell and tube or plate and frame type heat exchangers, filters, and deionizers, all skid

- mounted. The generator rotor is cooled with a hydrogen gas recirculation system using fa ns mounted on the generator rotor shaft. Operation Description

– The turbine stop valves, control valves, reheat stop valves, and intercept valves are controlled by an electro

- hydraulic control system. Main steam from the boiler passes through the stop valves and control valves and enters the turbine at 24.1 MPa/593 °C (3,500 psig/1,10 0 °F) . The steam initially enters the turbine near the middle of the high

pressure span, flows through the turbine, and returns to the boiler for reheating. The reheat st eam flows through the reheat stop valves and intercept valves and enters the IP section at 593 °C (1,100 °F). After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the two LP sections. The steam divides in to four paths and flows through the LP sections exhausting downward into the condenser. The turbine is designed to operate at constant inlet steam press ure over the entire load range.

3.1.8.1 Supercritical Steam Turbine Cycle

The supercritical steam turb ine is equipped with six non

- automatic steam extractions, which along with the HP and IP section exhausts provide steam for four low pressure feedwater heaters, deaerator, and three high pressure feedwater heaters. All feedwater heaters (except the deaerator) are closed type. The condensate drains from the low pressure heater (#1 through #4) are cascaded to the condenser. The condensate drains from the high pressure heaters (#6 through #8) are cascaded to the deaerator. The deaerator storage tank provides s uction to the boiler feedwater pumps. The deaerator is assumed to be placed at high elevation to assure sufficient Net Positive Suction Head (NPSH) for the feedwater pumps. Heater #7 is on cold reheat extraction and heater #8 is a heater above the reheat point (HARP).



# 3.1.9 Balance of Plant The balance of plant components consist of the condensate, feedwater, main and reheat steam, extraction steam, ash handling, ducting and stack, waste treatment and miscellane ous systems as described below.

3.1.9.1 Condensate

The fun ction of the condensate system is to pump condensate from the condenser hotwell to the deaerator, through the gland steam condenser and through the LP feedwater heaters. Each

70Carbon Dioxide Capture Sensitivity Analysis



## system consists of one main condenser; one variable speed electric motor

- driven vertical condensate pump with a 100 percent in

- line spare ; one gland steam condenser; four LP heaters; and one deaerator with storage tank. Condensate is delivered to a common discharge header through two separate pump discharge lines, each with a check va lve and a gate valve. A common minimum flow recirculation line discharging to the condenser is provided downstream of the gland steam condenser to maintain minimum flow requirements for the gland steam condenser and the condensate pumps.

LP feedwater heat ers 1 through 4 are 50 percent capacity, parallel flow, and are located in the condenser neck. All remaining feedwater heaters are 100 percent capacity shell and U

- tube heat exchangers. Each LP feedwater heater is provided with inlet/outlet isolation val ves and a full capacity bypass. LP feedwater heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the condenser. Pneumatic level control valves control normal drain levels in the heaters. High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Pneumatic level control valves control dump line flow.

3.1.9.2 Feedwater The function of the feedwater system is to pump the feedwater from the deaerator storage tank (s) through the HP feedwater heaters to the economizer. The SC plants have a single deaerator and
use o ne turbine

- driven boiler feedwater pump sized at 100 percent capacity (with a 100 percent spare) to pump feedwater through the HP feedwater heaters. One 25 percent motor

- driven boiler feedwater pump for each application is provided for startup. The pumps are provided with inlet and outlet isolation valves, and individual minimum flow recirculation lines discharging back to the deaerator stor age tank. The recirculation flow is controlled by automatic recirculation valves, which are a combination check valve in the main line and in the bypass, bypass control valve, and flow sensing element. The suction of the boiler feed pump is equipped with startup strainers, which are utilized during initial startup and following major outages or system maintenance. Each HP feedwater heater is provided with inlet/outlet isolation valves and a full capacity bypass. Feedwater heater drains cascade down to th e next lowest extraction pressure heater and finally discharge into the deaerator. Pneumatic level control valves control normal drain level in the heaters. High heater level dump lines discharging to the condenser are provided for each heater for turbin e water induction protection. Dump line flow is controlled by pneumatic level control valves. The deaerator is a horizontal, spray tray type with internal direct contact stainless steel vent condenser and storage tank. The boiler feed pump turbine is dri ven by main steam up to 60 percent plant load. Above 60 percent load, extraction from the IP turbine exhaust provides steam to the boiler feed pump steam turbine.

3.1.9.3 Main and Reheat Steam The function of the main steam system is to convey main steam from the boiler superheater outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from

71Carbon Dioxide Capture Sensitivity Analysis



## the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine stop valves.

Main steam exits the boile r superheater through a motor

- operated stop/check valve and a motor

operated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at approximately 60 percent load. Cold reheat steam exits the HP turbine, flows through a motor

- operated isolation gate valve and a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater through a motor

- operated ga te valve and is routed to the IP turbine.

3.1.9.4 Extraction Steam The function of the extraction steam system is to convey steam from turbine extraction points to the feedwater heaters, deaerator, and CDR facility

. The turbine is protected from overspeed on turbine trip, from flash steam reverse flow from the heaters through the extraction piping to the turbine. This protection is provided by positive closing, balanced disc non

- return valves located in all extraction lines except the lines to the LP feedwate r heaters in the condenser neck. The extraction non

- return valves are located only in horizontal runs of piping and as close to the turbine as possible. The turbine trip signal automatically trips the non

- return valves through relay dumps. The remote man ual control for each heater level control system is used to release the non

- return valves to normal check valve service when required to restart the system.

3.1.9.5 Circulating Water System It is assumed that the plant is serviced by a public water facility and ha s access to groundwater for use as makeup cooling water with minimal pretreatment. All filtration and treatment of the circulating water are conducted on site. A mechanical draft, counter

- flow cooling tower is provided for the circulating water heat sink . Two 50 percent circulating water pumps are provided. The circulating water system provides cooling water to the condenser, the CDR facility, and the auxiliary cooling water system. The auxiliary cooling water system is a closed

- loop system. Plate and frame heat exchangers with circulating water as the cooling medium are provided. This system provides cooling water to the lube oil coolers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers, air release valves, instruments, controls, etc. are included for a complete operable system.

3.1.9.6 Ash Handling System The function of the ash handling system is to provide the equipment required for conveying, preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basis by the boiler. The scope of the system is from the bag house hoppers, air heater hopper collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and truck filling stations (for fly ash). The

72Carbon Dioxide Capture Sensitivity Analysis



## system is designed to support short

- term operation at the 5 percent OP/VWO condition (16 hours) and long

- term operation at the 100 percent guarantee point (90 days or more). The fly ash collected in the bag house and in the air heaters is conveyed to the fly ash storage silo. A pneumatic transport system u sing low

- pressure air from a blower provides the transport mechanism for the fly ash. Fly ash is discharged through a wet unloader, which conditions the fly ash and conveys it through a telescopic unloading chute into a truck for disposal.

The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to hydrobins for dewatering and offsite removal by truck.

Ash from the economizer h oppers and pyrites (rejected from the coal pulverizers) is conveyed by hydraulic means (water) to the economizer/pyrites transfer tank. This material is then sluiced, on a periodic basis, to the hydrobins.

3.1.9.7 Ducting and Stack One stack is provided with a single fiberglass

- reinforced plastic (FRP) liner. The stack is constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate dispersion. The ID fans were sized large enough to allow for additional stack velocity to
overco me the buoyancy losses resulting from colder than normal flue gas temperatures following CO 2 

## capture

. 3.1.9.8 Waste Treatment/Miscellaneous Systems An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash to within the U.S. EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals. Waste treatment equipment is housed in a separate building. The waste treatment system consists of a water collection basin, three raw waste pumps, an acid neutralization syst em, an oxidation system, flocculation, clarification/thickening, and sludge dewatering. The water collection basin is a synthetic

- membrane

- lined earthen basin, which collects rainfall runoff, maintenance cleaning wastes, and backwash flows.

The raw waste is pumped to the treatment system at a controlled rate by the raw waste pumps. The neutralization system neutralizes the acidic wastewater with hydrated lime in a two

- stage system, consisting of a lime storage silo/lime slurry makeup system, dry lime feed er, lime slurry tank, slurry tank mixer, and lime slurry feed pumps. The oxidation system consists of an air compressor, which injects air through a sparger pipe into the second

- stage neutralization tank. The flocculation tank is fiberglass with a variabl e speed agitator. A polymer dilution and feed system is also provided for flocculation. The clarifier is a plate

- type, with the sludge pumped to the dewatering system. The sludge is dewatered in filter presses and disposed offsite. Trucking and disposa l costs are included in the cost estimate. The filtrate from the sludge dewatering is returned to the raw waste sump. Miscellaneous systems consisting of fuel oil, service air, instrument air, and service water are provided. A storage tank provides a sup ply of No. 2 fuel oil used for startup and for a small

73Carbon Dioxide Capture Sensitivity Analysis



## auxiliary boiler. Fuel oil is delivered by truck. All truck roadways and unloading stations inside the fence area are provided.

3.1.9.9 Buildings and Structures Foundations are provided for the support struc tures, pumps, tanks, and other plant components. The following buildings are included in the design basis:

• Steam turbine building • Fuel oil pump house • Guard house

• Boiler building • Coal crusher building • Runoff water pump house

• Administration and service building • Continuous emissions monitoring building • Industrial waste treatment building

• Makeup water and pretreatment building • Pump house and electrical equipment building • FGD system buildings



# 3.1.10 Accessory Electric Plant The accessory electric plan t consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, required foundations, and standby equipment.



# 3.1.11 Instrumentation and Control

An inte grated plant

- wide control and monitoring distributed control system (DCS) is provided

. The DCS is a redundant microprocessor

- based, functionally distributed system. The control room houses an array of multiple video monitor and keyboard units. The monit or/keyboard units are the primary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to provide 99.5 percent availability. The plant equipment and the DCS are designed for automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are implemented as supervised manual, with operator selection of modular automation routines available.



# 3.2 S upercritical P C C O 2 

# Capture Sensitivity
The evaluation scope included developing heat and mass balances and estimating plant performance on a common 550 MWe net output basis while firing bituminous Illinois No. 6 coal. Equipment lists were developed for each design to support plant capital and operating costs estimates.

74Carbon Dioxide Capture Sensitivity Analysis



## The SC PC plants are assumed to be built on a “greenfield” site and utilize recirculating evaporative cooling systems for cycle heat rejection. Major systems for each plant (described in Section 3.1 ) include:
1. Steam Generator 2. Steam Turbine/Generator 3. Particulate control system 4. FGD system 5. SCR system
6. CO 2 

## Recovery
7. Balance of Plant Support facilities include coal handling (receiving, crushing, and storing ), limestone handling (including receiving, crushing, storing, and feeding), solid waste disposal, circulating water system with evaporative mechanical draft cooling towers, wastewater treatment, and other ancillary systems equipment necessary for an efficient, highly available , and completely operable facility. The plant designs are based on using components suitable for a 30

- year life, with provision for periodic maintenance and replacement of critical parts. All equipment is based on compliance with the latest applicable c odes and standards. ASME, ANSI, IEEE, NFPA, CAA, state regulations, and OSHA codes are all adhered to in the design approach. The modeling assumptions that were used to generate the SC PC material and energy balances are summarized in Exhibit 3

- 5

.

75Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 5 Supercritical PC Combustion Configuration Modeling Assumptions
Case 1 A Case 1B Case 1C Case 1D Case 1E Case 1F Case 1G Throttle pressure, psig 3500 3500 3500 3500 3500 3500 3500 Throttle temperature, oF 110 0 110 0 110 0 110 0 110 0 110 0 110 0 Reheat temperature, oF 110 0 110 0 110 0 110 0 110 0 110 0 110 0 Condenser pressure, psia 0.98 0.98 0.98 0.98 0.98 0.98 0.98 Cooling water to condenser, oF 60 60 60 60 60 60 60 Cooling water from condenser, oF 80 80 80 80 80 80 80 Stack temperature saturation saturation saturation saturation saturation saturation saturation Coal HHV ( Illinois No. 6), Btu/lb 11,666 11,666 11,666 11,666 11,666 11,666 11,666 FGD efficiency 98% 98% 98% 98% 98% 98% 98% SOx emissions, lb/MMBtu 0.1 0.1 0.1 0.1 0.1 0.1 0.1 SCR efficiency 86% 86% 86% 86% 86% 86% 86% NOx emissions, lb/MMBtu 0.07 0.07 0.07 0.07 0.07 0.07 0.07 Ammonia slip (end of catalyst life), ppm 2 2 2 2 2 2 2 Baghouse efficiency 99.8% 99.8% 99.8% 99.8% 99.8% 99.8% 99.8% Particulate emissions PM/PM 10 

### , lb/MMBtu 0.015 0.015 0.015 0.015 0.015 0.015 0.015 Mercury removal, % 90 90 90 90 90 90 90 CO 2 

### Capture Efficiency*, % 30 50 70 85 90 95 99 Product CO 2 

### Condition, psia/°F 2215/95 2215/95 2215/95 2215/95 2215/95 2215/95 2215/95 * Percentage of CO 2 

### removed from flue gas



## 76Carbon Dioxide Capture Sensitivity Analysis



# 3.2.1 CO 2 

# Capture with Partial Bypass Performance Results
A process block flow diagram for Cases 1 A through 1D is shown in Exhibit 3

- 6 . These cases represent superc rit ical steam cycles with CO 2 

## capture ranging from 30 to 85 percent

. T he corresponding stream tables are contained in Exhibit 3

- 7 , Exhibit 3

- 8 , Exhibit 3

- 9 , and Exhibit 3

- 10 for 30, 50, 70, and 85 percent CO 2 

## capture, respectively. A series of CO 2 

## capture levels was developed by varying the volume of flue gas that bypasses t he Econamine FG Plus ® 

## system via Stream 18. Further, the MEA solvent circulation rate and reboiler steam flow rate were adjusted to account for the volume of flue gas treated.

A literat ure search was conducted to verify that <90 percent CO 2 

## capture is most economical using a slip

- stream (or bypass) approach. Indeed, the ‘slip

- stream’ approach is more cost

effective for <90 percent CO 2 

## capture than removing reduced CO 2 

## fractions from the entire flue gas stream , according to multiple peer

- reviewed studies [ 1 , 2 , 3 ] . The cost of CO 2 

## capture with the Econamine FG Plus SM 

## process is dependent on the volume of gas being treated and a reduction in flue gas flow rate will (1) decrease the quantity of energy consumed by flue gas blo wers; (2) reduce the size of the CO 2 

## absorption columns; (3) trim the cooling water requirement of the direct contact cooling system; and (4) decrease the amount of fan power required to increase the flue gas temperature and plume buoyancy. As a result, t he slip

- stream approach for <90 percent CO 2 

## capture leads to lower capital and operating costs. Overall performance for Cases 1 A through 1D is summarized in Exhibit 3

- 11 which includes auxiliary power requirements. Material and energy balance information, environmental performance and a major e quipment list are summarized in Sections 3.2.1.1 and 3.2.1.2

.

77Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 6 Cases 1A Through 1D Process Block Flow Diagram, Supercritical PC with CO 2 

### Capture Bypass



## Primary Air Fans Baghouse FGD

ID Fans

Stack gas

Stack Gypsum Limestone

Slurry Oxidation Air Makeup Water

Bottom Ash Coal Feed Infiltration air 8

1 2

Forced Draft Fans 3 4

6 5

7 Fly Ash 10 11 13 14

12 15

Pulverized Coal Boiler SCR
16

Econamine FG + 20

21

22

CO 2 

## Compression 24 25 CO 2 

## Product Reboiler Steam

Condensate Return Steam Turbine

Condenser 9

19

18 17

23 Note : Block Flow Diagram is not in complete material balance

. Only major process streams and equipment are shown

.



## 78Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 7 Case 1A Stream Table, Supercritical PC with 30% CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 0.0000 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 1.0000 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 0.0000 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 53,907 53,907 16,560 16,560 1,409 0 0 76,029 0 76,029 76,029 2,778 10,986 V-L Flowrate (kg/hr) 1,555,598 1,555,598 477,863 477,863 40,669 0 0 2,261,348 0 2,261,348 2,261,348 50,048 197,909 Solids Flowrate (kg/hr) 0 0 0 0 0 207,322 4,021 16,083 16,083 0 0 20,977 0
Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 15 15 Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 0.10 Enthalpy (kJ/kg) A 

### 30.23 34.36 30.23 40.78 30.23

--- --- 335.07

--- 316.66 328.98

--- 62.80 Density (kg/m 3 

### ) 1.2 1.3 1.2 1.3 1.2

--- --- 0.8

--- 0.8 0.8

--- 1,003.1 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743

--- 18.015

V-L Flowrate (lb mol 

### /hr) 118,845 118,845 36,508 36,508 3,107 0 0 167,616 0 167,616 167,616 6,125 24,219 V-L Flowrate (lb/hr) 3,429,506 3,429,506 1,053,508 1,053,508 89,660 0 0 4,985,419 0 4,985,419 4,985,419 110,337 436,316 Solids Flowrate (lb/hr) 0 0 0 0 0 457,066 8,864 35,457 35,457 0 0 46,247 0
Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 59 59 Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 15.0 14.7 Enthalpy (Btu/lb) A 

### 13.0 14.8 13.0 17.5 13.0

--- --- 144.1

--- 136.1 141.4

--- 27.0 Density (lb/ft 3 

### ) 0.076 0.078 0.076 0.081 0.076

--- --- 0.049

--- 0.049 0.051

--- 62.622 A - Reference conditions are 32.02 F & 0.089 PSIA



## 79Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 7 Case 1A Stream Table, Supercritical PC with 30% CO 2 Capture (continued)

14 15 16 17 18 19 20 21 22 23 24 25 V-L Mole Fraction

Ar 0.0092 0.0000 0.0081 0.0081 0.0081 0.0000 0.0000 0.0000 0.0092 0.0089 0.0000 0.0000 CO 2 

### 0.0003 0.0004 0.1347 0.1347 0.1347 0.0000 0.0000 0.0000 0.0161 0.1033 0.9873 1.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.9996 0.1549 0.1549 0.1549 1.0000 1.0000 1.0000 0.1747 0.1204 0.0127 0.0000 N 2 

### 0.7732 0.0000 0.6785 0.6785 0.6785 0.0000 0.0000 0.0000 0.7728 0.7414 0.0000 0.0000 O 2 

### 0.2074 0.0000 0.0238 0.0238 0.0238 0.0000 0.0000 0.0000 0.0271 0.0260 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 859 198 83,056 27,658 55,398 101,180 11,731 11,731 24,280 76,004 3,377 3,334 V-L Flowrate (kg/hr) 24,798 3,570 2,392,952 796,853 1,596,099 1,822,780 211,342 211,342 649,315 2,179,226 147,486 146,714 Solids Flowrate (kg/hr) 0 32,425 0 0 0 0 0 0 0 0 0 0
Temperature (°C) 18 58 58 58 58 593 291 151 32 53 21 35 Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.10 0.16 15.27 Enthalpy (kJ/kg) A 

### 32.81

--- 303.64 303.64 303.64 3,477.66 3,046.14 637.34 87.35 244.64 28.22 -212.35 Density (kg/m 3 

### ) 1.2

--- 1.1 1.1 1.1 69.2 2.0 916.0 1.3 1.1 2.9 794.3 V-L Molecular Weight 28.857

--- 28.811 28.811 28.811 18.015 18.015 18.015 26.743 28.672 43.680 44.010

V-L Flowrate (lb mol 

### /hr) 1,895 437 183,107 60,975 122,132 223,063 25,863 25,863 53,529 167,561 7,444 7,349 V-L Flowrate (lb/hr) 54,671 7,870 5,275,555 1,756,760 3,518,795 4,018,542 465,930 465,930 1,431,495 4,804,370 325,150 323,448 Solids Flowrate (lb/hr) 0 71,485 0 0 0 0 0 0 0 0 0 0
Temperature (°F) 64 136 136 136 136 1,100 556 304 89 127 69 95 Pressure (psia) 15.0 14.8 14.8 14.8 14.8 3,514.7 73.5 133.6 14.8 14.8 23.5 2,214.5 Enthalpy (Btu/lb) A 

### 14.1

--- 130.5 130.5 130.5 1,495.1 1,309.6 274.0 37.6 105.2 12.1 -91.3 Density (lb/ft 3 

### ) 0.077

--- 0.067 0.067 0.067 4.319 0.123 57.184 0.078 0.067 0.183 49.586 A - Reference conditions are 32.02 F & 0.089 PSIA



## 80Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 8 Case 1B Stream Table, Supercritical PC with 50% CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 0.0000 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 1.0000 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 0.0000 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 57,711 57,711 17,728 17,728 1,509 0 0 81,394 0 81,394 81,394 2,958 11,774 V-L Flowrate (kg/hr) 1,665,360 1,665,360 511,581 511,581 43,539 0 0 2,420,907 0 2,420,907 2,420,907 53,296 212,114 Solids Flowrate (kg/hr) 0 0 0 0 0 221,950 4,304 17,218 17,218 0 0 22,456 0
Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 15 15 Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 0.10 Enthalpy (kJ/kg) A 

### 30.23 34.36 30.23 40.78 30.23

--- --- 335.07

--- 316.66 328.98

--- 62.80 Density (kg/m 3 

### ) 1.2 1.3 1.2 1.3 1.2

--- --- 0.8

--- 0.8 0.8

--- 1,003.1 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743

--- 18.015

V-L Flowrate (lb mol 

### /hr) 127,231 127,231 39,084 39,084 3,326 0 0 179,443 0 179,443 179,443 6,522 25,958 V-L Flowrate (lb/hr) 3,671,489 3,671,489 1,127,843 1,127,843 95,987 0 0 5,337,187 0 5,337,187 5,337,187 117,497 467,632 Solids Flowrate (lb/hr) 0 0 0 0 0 489,316 9,490 37,958 37,958 0 0 49,508 0
Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 59 59 Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 15.0 14.7 Enthalpy (Btu/lb) A 

### 13.0 14.8 13.0 17.5 13.0

--- --- 144.1

--- 136.1 141.4

--- 27.0 Density (lb/ft 3 

### ) 0.076 0.078 0.076 0.081 0.076

--- --- 0.049

--- 0.049 0.051

--- 62.622 A - Reference conditions are 32.02 F & 0.089 PSIA



## 81Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 8 Case 1B Stream Table, Supercritical PC with 50% CO 2 Capture (continued)

14 15 16 17 18 19 20 21 22 23 24 25 V-L Mole Fraction

Ar 0.0092 0.0000 0.0081 0.0081 0.0081 0.0000 0.0000 0.0000 0.0092 0.0094 0.0000 0.0000 CO 2 

### 0.0003 0.0004 0.1347 0.1347 0.1347 0.0000 0.0000 0.0000 0.0154 0.0784 0.9874 1.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.9996 0.1550 0.1550 0.1550 1.0000 1.0000 1.0000 0.1749 0.0946 0.0126 0.0000 N 2 

### 0.7732 0.0000 0.6785 0.6785 0.6785 0.0000 0.0000 0.0000 0.7734 0.7900 0.0000 0.0000 O 2 

### 0.2074 0.0000 0.0238 0.0238 0.0238 0.0000 0.0000 0.0000 0.0271 0.0277 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 907 212 88,902 49,429 39,472 108,299 21,169 21,169 43,359 76,353 6,069 5,992 V-L Flowrate (kg/hr) 26,187 3,829 2,561,398 1,424,137 1,137,261 1,951,032 381,357 381,357 1,158,952 2,179,503 265,093 263,713 Solids Flowrate (kg/hr) 0 34,712 0 0 0 0 0 0 0 0 0 0
Temperature (°C) 18 58 58 58 58 593 291 151 32 48 21 35 Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.10 0.16 15.27 Enthalpy (kJ/kg) A 

### 32.81

--- 303.63 303.63 303.63 3,477.66 3,046.14 637.34 87.38 199.38 28.23 -212.35 Density (kg/m 3 

### ) 1.2

--- 1.1 1.1 1.1 69.2 2.0 916.0 1.3 1.1 2.9 794.3 V-L Molecular Weight 28.857

--- 28.812 28.812 28.812 18.015 18.015 18.015 26.729 28.545 43.682 44.010

V-L Flowrate (lb mol 

### /hr) 2,001 468 195,994 108,973 87,021 238,758 46,669 46,669 95,590 168,330 13,379 13,210 V-L Flowrate (lb/hr) 57,733 8,443 5,646,915 3,139,685 2,507,230 4,301,289 840,749 840,749 2,555,051 4,804,981 584,429 581,387 Solids Flowrate (lb/hr) 0 76,527 0 0 0 0 0 0 0 0 0 0
Temperature (°F) 64 136 136 136 136 1,100 556 304 89 118 69 95 Pressure (psia) 15.0 14.8 14.8 14.8 14.8 3,514.7 73.5 133.6 14.8 14.8 23.5 2,214.5 Enthalpy (Btu/lb) A 

### 14.1

--- 130.5 130.5 130.5 1,495.1 1,309.6 274.0 37.6 85.7 12.1 -91.3 Density (lb/ft 3 

### ) 0.077

--- 0.067 0.067 0.067 4.319 0.123 57.184 0.078 0.068 0.183 49.586 A - Reference conditions are 32.02 F & 0.089 PSIA



## 82Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 9 Case 1C Stream Table, Supercritical PC with 70% CO 2 

### C apture

1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 0.0000 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 1.0000 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 0.0000 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 62,010 62,010 19,049 19,049 1,621 0 0 87,457 0 87,457 87,457 3,143 12,662 V-L Flowrate (kg/hr) 1,789,408 1,789,408 549,687 549,687 46,782 0 0 2,601,235 0 2,601,235 2,601,235 56,619 228,115 Solids Flowrate (kg/hr) 0 0 0 0 0 238,483 4,625 18,500 18,500 0 0 24,011 0
Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 15 15 Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 0.10 Enthalpy (kJ/kg) A 

### 30.23 34.36 30.23 40.78 30.23

--- --- 335.07

--- 316.66 328.98

--- 62.80 Density (kg/m 3 

### ) 1.2 1.3 1.2 1.3 1.2

--- --- 0.8

--- 0.8 0.8

--- 1,003.1 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743

--- 18.015

V-L Flowrate (lb mol 

### /hr) 136,708 136,708 41,995 41,995 3,574 0 0 192,809 0 192,809 192,809 6,929 27,916 V-L Flowrate (lb/hr) 3,944,969 3,944,969 1,211,853 1,211,853 103,136 0 0 5,734,741 0 5,734,741 5,734,741 124,823 502,908 Solids Flowrate (lb/hr) 0 0 0 0 0 525,764 10,196 40,786 40,786 0 0 52,935 0
Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 59 59 Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 15.0 14.7 Enthalpy (Btu/lb) A 

### 13.0 14.8 13.0 17.5 13.0

--- --- 144.1

--- 136.1 141.4

--- 27.0 Density (lb/ft 3 

### ) 0.076 0.078 0.076 0.081 0.076

--- --- 0.049

--- 0.049 0.051

--- 62.622 A - Reference conditions are 32.02 F & 0.089 PSIA



## 83Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 9 Case 1C Stream Table, Supercritical PC with 70% CO2 Capture (continued)

14 15 16 17 18 19 20 21 22 23 24 25 V-L Mole Fraction

Ar 0.0092 0.0000 0.0081 0.0081 0.0081 0.0000 0.0000 0.0000 0.0092 0.0101 0.0000 0.0000 CO 2 

### 0.0003 0.0004 0.1347 0.1347 0.1347 0.0000 0.0000 0.0000 0.0160 0.0507 0.9873 1.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.9996 0.1550 0.1550 0.1550 1.0000 1.0000 1.0000 0.1748 0.0668 0.0127 0.0000 N 2 

### 0.7732 0.0000 0.6785 0.6785 0.6785 0.0000 0.0000 0.0000 0.7730 0.8429 0.0000 0.0000 O 2 

### 0.2074 0.0000 0.0238 0.0238 0.0238 0.0000 0.0000 0.0000 0.0271 0.0295 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 984 230 95,534 74,325 21,208 116,344 31,643 31,643 65,239 76,894 9,084 8,969 V-L Flowrate (kg/hr) 28,385 4,140 2,752,462 2,141,416 611,047 2,095,977 570,060 570,060 1,744,469 2,183,416 396,807 394,733 Solids Flowrate (kg/hr) 0 37,179 0 0 0 0 0 0 0 0 0 0
Temperature (°C) 18 58 58 58 58 593 291 151 32 41 21 35 Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.10 0.16 15.27 Enthalpy (kJ/kg) A 

### 32.81

--- 303.63 303.63 303.63 3,477.66 3,046.14 637.34 87.36 148.96 28.22 -212.35 Density (kg/m 3 

### ) 1.2

--- 1.1 1.1 1.1 69.2 2.0 916.0 1.3 1.1 2.9 794.3 V-L Molecular Weight 28.857

--- 28.811 28.811 28.811 18.015 18.015 18.015 26.740 28.395 43.680 44.010

V-L Flowrate (lb mol 

### /hr) 2,169 506 210,616 163,859 46,757 256,495 69,761 69,761 143,826 169,522 20,028 19,774 V-L Flowrate (lb/hr) 62,577 9,128 6,068,141 4,721,014 1,347,127 4,620,838 1,256,768 1,256,768 3,845,896 4,813,608 874,811 870,237 Solids Flowrate (lb/hr) 0 81,967 0 0 0 0 0 0 0 0 0 0
Temperature (°F) 64 136 136 136 136 1,100 556 304 89 107 69 95 Pressure (psia) 15.0 14.8 14.8 14.8 14.8 3,514.7 73.5 133.6 14.8 14.8 23.5 2,214.5 Enthalpy (Btu/lb) A 

### 14.1

--- 130.5 130.5 130.5 1,495.1 1,309.6 274.0 37.6 64.0 12.1 -91.3 Density (lb/ft 3 

### ) 0.077

--- 0.067 0.067 0.067 4.319 0.123 57.184 0.078 0.069 0.183 49.586 A - Reference conditions are 32.02 F & 0.089 PSIA



## 84Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 10 Case 1D Stream Table, Supercritical PC with 85% CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 0.0000 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 1.0000 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 0.0000 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 65,727 65,727 20,191 20,191 1,718 0 0 92,700 0 92,700 92,700 3,389 13,388 V-L Flowrate (kg/hr) 1,896,682 1,896,682 582,641 582,641 49,586 0 0 2,757,177 0 2,757,177 2,757,177 61,050 241,185 Solids Flowrate (kg/hr) 0 0 0 0 0 252,779 4,902 19,609 19,609 0 0 25,555 0
Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 15 15 Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 0.10 Enthalpy (kJ/kg) A 

### 30.23 34.36 30.23 40.78 30.23

--- --- 335.07

--- 316.66 328.98

--- 62.80 Density (kg/m 3 

### ) 1.2 1.3 1.2 1.3 1.2

--- --- 0.8

--- 0.8 0.8

--- 1,003.1 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743

--- 18.015

V-L Flowrate (lb mol 

### /hr) 144,903 144,903 44,513 44,513 3,788 0 0 204,368 0 204,368 204,368 7,471 29,515 V-L Flowrate (lb/hr) 4,181,468 4,181,468 1,284,503 1,284,503 109,319 0 0 6,078,535 0 6,078,535 6,078,535 134,592 531,721 Solids Flowrate (lb/hr) 0 0 0 0 0 557,283 10,808 43,231 43,231 0 0 56,339 0
Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 59 59 Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 15.0 14.7 Enthalpy (Btu/lb) A 

### 13.0 14.8 13.0 17.5 13.0

--- --- 144.1

--- 136.1 141.4

--- 27.0 Density (lb/ft 3 

### ) 0.076 0.078 0.076 0.081 0.076

--- --- 0.049

--- 0.049 0.051

--- 62.622 A - Reference conditions are 32.02 F & 0.089 PSIA



## 85Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 10 Case 1D Stream Table, Supercritical PC with 85% CO2 Capture (continued)

14 15 16 17 18 19 20 21 22 23 24 25 V-L Mole Fraction

Ar 0.0092 0.0000 0.0081 0.0081 0.0081 0.0000 0.0000 0.0000 0.0092 0.0106 0.0000 0.0000 CO 2 

### 0.0003 0.0004 0.1347 0.1347 0.1347 0.0000 0.0000 0.0000 0.0158 0.0270 0.9873 1.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.9996 0.1549 0.1549 0.1549 1.0000 1.0000 1.0000 0.1748 0.0453 0.0127 0.0000 N 2 

### 0.7732 0.0000 0.6785 0.6785 0.6785 0.0000 0.0000 0.0000 0.7731 0.8861 0.0000 0.0000 O 2 

### 0.2074 0.0000 0.0238 0.0238 0.0238 0.0000 0.0000 0.0000 0.0271 0.0311 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 1,047 244 101,266 95,595 5,671 123,302 40,669 40,669 83,895 77,537 11,696 11,548 V-L Flowrate (kg/hr) 30,210 4,400 2,917,608 2,754,222 163,386 2,221,322 732,658 732,658 2,243,114 2,189,783 510,904 508,236 Solids Flowrate (kg/hr) 0 39,513 0 0 0 0 0 0 0 0 0 0
Temperature (°C) 18 58 58 58 58 593 291 151 32 35 21 35 Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.10 0.16 15.27 Enthalpy (kJ/kg) A 

### 32.81

--- 303.64 303.64 303.64 3,477.66 3,046.14 637.34 87.36 107.94 28.22 -212.35 Density (kg/m 3 

### ) 1.2

--- 1.1 1.1 1.1 69.2 2.0 916.0 1.3 1.1 2.9 794.3 V-L Molecular Weight 28.857

--- 28.811 28.811 28.811 18.015 18.015 18.015 26.737 28.242 43.681 44.010

V-L Flowrate (lb mol 

### /hr) 2,308 538 223,253 210,751 12,502 271,835 89,659 89,659 184,958 170,939 25,786 25,460 V-L Flowrate (lb/hr) 66,601 9,700 6,432,224 6,072,019 360,205 4,897,176 1,615,234 1,615,234 4,945,220 4,827,645 1,126,351 1,120,468 Solids Flowrate (lb/hr) 0 87,111 0 0 0 0 0 0 0 0 0 0
Temperature (°F) 64 136 136 136 136 1,100 556 304 89 94 69 95 Pressure (psia) 15.0 14.8 14.8 14.8 14.8 3,514.7 73.5 133.6 14.8 14.8 23.5 2,214.5 Enthalpy (Btu/lb) A 

### 14.1

--- 130.5 130.5 130.5 1,495.1 1,309.6 274.0 37.6 46.4 12.1 -91.3 Density (lb/ft 3 

### ) 0.077

--- 0.067 0.067 0.067 4.319 0.123 57.184 0.078 0.070 0.183 49.586 A - Reference conditions are 32.02 F & 0.089 PSIA



## 86Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 11 Cases 1A Through 1D Performance Modeling Results POWER SUMMARY (Gross Power at Generator Terminals, kWe) Case 1A (30%) Case 1B (50%) Case 1C (70%) Case 1D (85%) Steam Turbine Power 601,500 618,200 637,800 654,800 AUXILIARY LOAD SUMMARY, kWe 1 

### Coal Handling and Conveying 4 6 0 470 490 500 Limestone Handling & Reagent Preparation 1,0 1 0 1,0 8 0 1,160 1,2 3 0 Pulverizers 3, 11 0 3,3 3 0 3,5 8 0 3,7 9 0 Ash Handling 590 6 4 0 680 720 Primary Air Fans 1,4 5 0 1,5 5 0 1,6 7 0 1,7 7 0 Forced Draft Fans 1,8 5 0 1,9 8 0 2,1 3 0 2,2 6 0 Induced Draft Fans 8,020 8, 59 0 9, 23 0 9, 7 80 SCR 20 20 20 20 Baghouse 80 80 90 90 FGD Pumps and Agitators 3, 31 0 3,5 5 0 3, 81 0 4,0 4 0 Econamine FG Plus Auxiliaries 5,500 9, 9 00 14, 8 00 1 9,1 00 CO 2 

### Compression 11, 79 0 21, 200 31, 73 0 40, 86 0 Econamine Condensate Pump 40 7 0 110 140 Miscellaneous Balance of Plant 2 

### 2,000 2,000 2,000 2,000 Steam Turbine Auxiliaries 400 400 400 400 Condensate Pumps 7 2 0 6 8 0 6 3 0 5 9 0 Circulating Water Pumps 5,820 6,710 8,26 0 9,600

Cooling Tower Fans 3, 40 0 3,920 4,820 5,610

Transformer Loss 1,940 2,0 4 0 2,1 5 0 2,2 5 0 TOTAL AUXILIARIES, kWe 51,510 68,210 87,760 104,750 NET POWER, kWe 549,990 549,990 550,040 550,050 Net Plant Efficiency, % (HHV) 35.2 % 32.9% 30.6% 28.9% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 10,229 ( 9,695 ) 10,950 (10,379) 11,765 (11,151) 12,470 (11,819) CONDENSER COOLING DUTY GJ/hr (10 6 

### Btu/hr) 2,164 ( 2,051 ) 2,037 (1,931) 1,900 (1,801) 1,783 (1,690) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 3 

### 20 7,322 (45 7,066 ) 221,950 (489,316) 238,483 (525,764) 252,779 (557,283) Thermal Input, kWt 1,562,693 1,672,956 1,797,570 1,905,333 Raw Water Withdrawal , m 3 

### /min (gpm) 23.6 (6,245) 26.4 (6,987) 31.7 (8,386) 36.4 (9,615) Raw Water Consumption, m 3 

### /min (gpm) 18.5 (4,898) 20.6 (5,433) 24.5 (6,474) 28.0 (7,392) 

### Notes: 1. Boiler feed pumps are turbine driven 2. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 3. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)



## 87Carbon Dioxide Capture Sensitivity Analysis



## 3.2.1.1 Environmental Performance for Cases 1A t hrough 1D Each case was designed to meet presumptive BACT standards utilizing the emissions control processes described in Section 2.4 . A summary of plant air emissions is presented in Exhibit 3

- 12

. SO 2 

## emissions are controlled using a wet limestone forced oxidation FGD that achieves a removal efficiency of 98%. To avoid the formation of heat sta ble salts in the Econamine process, an SO 2 

## polishing step is included to reduce the sulfur content to 10 ppm prior to the CO 2 

## absorber , and the balance of the SO 2 

## is absorbed by the MEA solution resulting in negligible stack emissions. The byproduct calci um sulfate is dewatered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The saturated flue gas exiting the FGD is vented th rough the plant stack. Particulate emissions are controlled using a pulse jet fabric filter (baghouse) which operates at an efficiency of 99.8 percent . It was assumed that 20 percent of the ash exits the boiler as bottom ash and the remaining 80 percent e xits the boiler in the flue gas [ 41 ].

Co

- benefit capture of Hg in the fabric filter and FGD system was assumed to achieve a 90 percent capture rate [ 42 ]. The high chlorine content of the Illinois No. 6 coal and the SCR system will convert most of the Hg in the system to an oxidized state [ 43 ]. An inexpensive FGD system additive can be used to promote Hg capture if necessary, but was not included

. The carbon balance for the four cases is shown in Exhibit 3

- 13

. The carbon input to the plant consists of carbon in the coal, limestone, and combustion and FGD forced oxidation air.

CO 2 

## capture efficiency is calculated as the pounds of CO 2 

## captured di vided by the pounds of CO 2 

## produced. Most of the CO 2 

## produced comes from coal combustion, but a small amount is formed in th e FGD system. The sum of these two sources is the amount produced. (Carbon in Sequestration Product) / (Carbon in the Coal + Net Carbon from Limestone) or 8 8,274 / (2 91,355 + 4, 206 ) *100 = 30% (Case 1A) 15 8,670 / ( 311,913 + 4,502 ) *100 = 50% (Case 1B) 23 7,502 / (33 5,147 + 4,837 ) *100 = 70% (Case 1C) 30 5,794 / (35 5,239 + 5,128 ) *100 = 85% (Case 1D)

Exhibit 3

- 14 shows the sulfur balance for the four cases. Sulfur input comes solely from the sulfur in the coal. Sulfur output is the gypsum sulfur byproduct, and the sulfur emitted in the stack gas. The total sulfur capture is represented by the following fraction: (Sul fur byproduct/Sulfur in the coal) or (11, 227 /11, 456 )*100 = 98.0% (Case 1A) ( 12,019 /12, 264 )*100 = 98.0% (Case 1B) (12, 914 /13, 178 )*100 = 98.0% (Case 1C) (13, 688 /13, 968 )*100 = 98.0% (Case 1D)

88Carbon Dioxide Capture Sensitivity Analysis



## T he overall water balance s for Case 1A, 1B, 1C, and 1D are shown in Exhibit 3

- 15 , Exhibit 3

- 16 , Exhibit 3

- 17 , and Exhibit 3

- 18 , respectively

. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within t he process and that

w ater is re used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawa l less process water discharge.

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 19 t hrough Exhibit 3

- 26

.

• Boiler and flue gas cleanup

• Steam and feedwater An overall plant energy balance is provided in tabular form for Case 1A, 1B, 1C, and 1D in Exhibit 3

- 27 , Exhibit 3

- 28 , Exhibi t 3

- 29 , and Exhibit 3

- 30 , respectively . The power out is the steam turbine power after generator losses. In addition, energy balance Sankey diagrams are provided in Exhibit 3

- 3 1 , Exhibit 3

- 32 , Exhibit 3

- 33 , and Exhibit 3

- 34 for Case 1A, 1B, 1C, and 1D, respectively.

89Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 12 Cases 1A through 1D Estimated Air Emission Rates

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

Case 1A Case 1B Case 1C Case 1D Case 1A Case 1B Case 1C Case 1D Case 1A Case 1B Case 1C Case 1D

SO 2 

### 0.028 (0.064) 0.022 (0.050) 0.0 15 (0.0 36 ) 0.007 (0.017) 1,1 59 (1,27 8 ) 96 4 (1,06 3 ) 740 ( 816 ) 370 (408) 0.259 (0.57 0 ) 0.210 (0.46 0 ) 0. 156 (0. 34 0 ) 0.076 (0.17 0 )

NO X 

### 0.030 (0.070) 0.030 (0.070) 0.030 (0.070) 0.030 (0.070) 1,261 (1,390 ) 1,35 0 (1,4 88 ) 1,45 0 (1, 598 ) 1,537 (1,69 4 ) 0.281 (0.621) 0.293 (0.646) 0.305 (0.673) 0.315 (0.695)

PM 0.006 (0.0130) 0.006 (0.0130) 0.006 (0.0130) 0.006 (0.0130) 234 (258) 251 (27 6 ) 2 69 (297) 28 5 (315) 0.052 (0.115) 0.054 (0.120) 0.057 (0.125) 0.059 (0.129)
Hg 0.49x10 - 6 

### (1.14x10 - 6 

### ) 0.49x10 - 6 

### (1.14x10 - 6 

### ) 0.49x10 - 6 

### (1.14x10 - 6 

### ) 0.49x10 - 6 

### (1.14x10 - 6 

### ) 0.021 (0.023) 0.022 (0.024) 0.024 (0.026) 0.025 (0.028) 4.60x10 - 6 

### (10.1x10 - 6 

### ) 4.79x10 - 6 

### (10.6x10 - 6 

### ) 4.99x10 - 6 

### (11.0x10 - 6 

### ) 5.15x10 - 6 

### (11.3x10 - 6 

### )

CO 2 

### 61.4 (142.9) 43.7 (101.7) 26.5 (61.7) 13.4 (31.2) 2,57 3,010 (2,83 6,258 ) 1,96 0,464 (2,16 1,042 ) 1,27 7,186 (1,40 7,857 ) 684, 813 (75 4,877 ) 574 (1,267) 426 (939) 269 (593) 140 (310)
CO 2 

### net 62 8 (1,38 5 ) 4 79 (1,05 5 ) 312 (68 7 ) 167 (369)



## 90Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 13 Cases 1A through 1D Carbon Balance Carbon In, kg/hr (lb/hr) Case 1A Case 1B Case 1C Case 1D

Coal 132, 157 (291, 355 ) 141, 481 (31 1,913 ) 152, 020 (335, 147 ) 161,1 34 (355, 239 ) Air (CO 2 

### ) 282 (622) 302 (66 6 ) 32 4 (71 5 ) 344 (758)

Limestone 2,1 29 (4,69 3 ) 2,2 79 (5,0 24 ) 2,43 6 (5,37 1 ) 2,59 3 (5,71 7 )

Total 13 4, 568 (29 6, 670 ) 14 4, 062 (31 7,603 ) 154, 780 (341, 233 ) 164, 071 (361,7 14 ) Carbon Out, kg/hr (lb/hr)

Stack Gas 94, 308 (20 7,913 ) 71, 856 (158, 416 ) 46,8 12 (103,2 04 ) 25,10 0 (55,3 37 )

CO 2 

### Product 40,0 41 (88, 274 ) 71,972 (158, 670 ) 107, 729 (237, 502 ) 138,7 06 (305, 794 ) Gypsum 221 (48 7 ) 237 (522) 242 (53 4 ) 267 (5 89 ) Convergence Tolerance* - 2 (

- 4 )

- 3 (

- 5 )

- 3 (

- 7 )

- 2 (

- 6 )

Total 13 4, 568 ( 296, 670 ) 14 4,062 (31 7,603 ) 154,780 (341,233) 164,071 (361,714)

Exhibit 3
- 14 Cases 1A through 1D Sulfur Balance Sulfur In, kg/hr (lb/hr) Case 1A Case 1B Case 1C Case 1D

Coal 5, 196 (11,4 56 ) 5,5 63 (12,2 6 4) 5,9 77 (13,1 78 ) 6,33 6 (13,9 68 )

Total 5, 196 (11, 4 56 ) 5,5 63 (12, 2 6 4) 5,9 77 (13, 1 78 ) 6, 33 6 (13, 9 68 ) Sulfur Out, kg/hr (lb/hr)
Gypsum 5,09 2 (11,2 27 ) 5,4 52 (12,0 1 9) 5,8 58 (12,9 14 ) 6,2 09 (13,6 88 ) Stack Gas 78 (172) 65 (143) 50 ( 110 ) 25 (55)
AGR 26 (57) 46 (102) 70 ( 154 ) 102 (224) Convergence Tolerance* 0 (0) 0 (0)

- 1 (0) 0 ( 1 )

Total 5, 196 (11, 456 ) 5,5 63 (12, 26 4) 5,9 77 (13, 178 ) 6, 336 (13, 968 )



## 91Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 15 Case 1A (30%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge, m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)
Econamine 0.04 (10) 0.0 (0) 0.04 (10) 0.0 (0) 0.04 (10) FGD Makeup 4.14 (1
, 093) 0.0 (0) 4.14 (1
, 093) 0.0 (0) 4.14 (1
, 093) BFW Makeup 0.30 (80) 0.0 (0) 0.30 (80) 0.0 (0) 0.30 (80) Cooling Tower Makeup 22.7 (5,990) 3.51 (928) 19.2 (5,062) 5.10 (1
, 347) 14.06 (3
, 715)

Total 27.2 (7,174) 3.51 (928) 23.6 (6,245) 5.10 (1 , 347) 18.5 (4 , 898) Total, gal/MWh net 

### 783 101 681 147 534

Exhibit 3
- 16 Case 1B (50%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge, m 3 

### /min (gpm) Raw Water Consumption, m 3 

### /min (gpm)
Econamine 0.07 (17) 0.0 (0) 0.07 (17) 0.0 (0) 0.07 (17) FGD Makeup 4.43 (1
, 170) 0.0 (0) 4.43 (1
, 170) 0.0 (0) 4.43 (1
, 170) BFW Makeup 0.33 (86) 0.0 (0) 0.33 (86) 0.0 (0) 0.33 (86) Cooling Tower Makeup 26.2 (6,909) 4.53 (1
, 196) 21.6 (5,713) 5.9 (1
, 554) 15.75 (4
, 159)

Total 31.0 (8,183) 4.53 (1 , 196) 26.4 (6,987) 5.9 (1 , 554) 20. 6 (5 , 433) Total, gal/MWh net 

### 893 130 762 170 593



## 92Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 17 Case 1C (70%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge, m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)
Econamine 0.10 (26) 0.0 (0) 0.10 (26) 0.0 (0) 0.10 (26) FGD Makeup 4.75 (1
, 255) 0.0 (0) 4.75 (1
, 255) 0.0 (0) 4.75 (1
, 255) BFW Makeup 0.35 (92) 0.0 (0) 0.35 (92) 0.0 (0) 0.35 (92) Cooling Tower Makeup 32.2 (8,501) 5.64 (1
, 489) 26.5 (7,012) 7.2 (1
, 912) 19.31 (5
, 101)

Total 37.4 (9,875) 5.64 (1 , 489) 31.7 (8,386) 7.2 (1 , 912) 24.5 (6 , 474) Total, gal/MWh net 

### 1,077 162 915 209 706

Exhibit 3
- 18 Case 1D (85%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge, m 3 

### /min (gpm) Raw Water Consumption, m 3 

### /min (gpm)
Econamine 0.13 (33) 0.0 (0) 0.13 (33) 0.0 (0) 0.13 (33) FGD Makeup 5.04 (1
, 333) 0.0 (0) 5.04 (1
, 333) 0.0 (0) 5.04 (1
, 333) BFW Makeup 0.37 (98) 0.0 (0) 0.37 (98) 0.0 (0) 0.37 (98) Cooling Tower Makeup 37.4 (9,882) 6.55 (1
, 731) 30.9 (8,151) 8.4 (2
, 222) 22.44 (5
, 929)

Total 42.9 (11,346) 6.55 (1 , 731) 36.4 (9,615) 8.4 (2 , 222) 28.0 (7 , 392) Total, gal/MWh net 

### 1,238 189 1,049 242 806



## 93Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

94Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 19 Case 1A (30%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

N OTES : 1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA



### H EAT AND 

### M ATERIAL 

### F LOW 

### D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL 

### Air

Coal / Ash

Water Steam

P AGES 1 OF 2 

### CO 2 

### C APTURE 

### S ENSITIVITY 

### A NALYSIS 

### C ASE 

### 1 A ( 30 %) S UPERCRITICAL 

### P ULVERIZED 

### C OAL 

### B OILER AND 

### G AS 

### C LEANUP 

### S YSTEMS

DWG

. NO

. 

### CCSA

- HMB

- CS

- 1 A

- PG

- 1 

## Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

457 , 066 W

77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 4 , 018 , 542 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H

3 , 273 , 047 W

1 , 100

. 0 T

655

. 8 P 1 , 570

. 6 H

Single Reheat Extraction from

HP Turbine

1 , 053 , 508 W 59

. 0 T 14

. 7 P 13

. 0 H 3 , 429 , 506 W 59

. 0 T 14

. 7 P 13

. 0 H 89 , 660 W

59

. 0 T 14

. 7 P 13

. 0 H 5 , 020 , 876 W 350

. 0 T 14

. 4 P 144

. 1 H

8 , 864 W 35 , 457 W

3 , 273 , 047 W 669

. 0 T 710

. 8 P 1 , 325

. 7 H

4 , 018 , 542 W 545

. 5 T 4 , 185

. 0 P

539

. 7 H 5 5 , 275 , 555 W 135

. 8 T 14

. 8 P 130

. 5 H

3 1 2

4 6

7 19 8 9 ID FANS

16 4 , 985 , 419 W 350

. 0 T 14

. 2 P 136

. 1 H

Gross Plant Power : 602 MWe Auxiliary Load : 52 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 35

. 2 % Net Plant Heat Rate : 9 , 695 BTU / KWe 

### Limestone Slurry Flue Gas OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15 12 14 13

10 11

370

. 7 T 15

. 3 P 141

. 4 H

156 , 584 W 59

. 0 T 15

. 0 P 54 , 671 W 63

. 6 T 15

. 0 P 14

. 1 H 436 , 316 W 59

. 0 T 14

. 7 P

- 19

. 7 H

79 , 355 W 135

. 8 T 14

. 8 P



### DOE / NETL

SC PC P LANT C ASE 1 ASTRIPPERABSORBER FLUE GAS Acid Gas



### ECONAMINE FG +

ECONAMINE CONDENSATE 20

21 65 , 827 W 306

. 3 T 73

. 5 P 1 , 181

. 4 H 465 , 930 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

465 , 930 W

304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE

STEAM 323 , 448 W 95

. 0 T 2 , 214

. 5 P

- 91

. 3 H 325 , 150 W 69

. 0 T 23

. 5 P 12

. 1 H 4 , 804 , 370 W 126

. 6 T 14

. 8 P 105

. 2 H CO 2 COMPRESSION ( INTERSTAGE

COOLING )



### CO 2 

### PRODUCT 

### Baghouse

24 25 23

18 3 , 518 , 795 W

1 , 756 , 760 W 1 , 431 , 495 W 88

. 8 T 14

. 8 P 37

. 6 H

17 22 

### Ammonia

Carbon Dioxide Gypsum



## 95Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 20 Case 1A (30%) Heat and Mass Balance, Power Block Systems

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Water Steam

P AGES 2 OF 2 DWG

. NO

. CCSA

- HMB

- CS

- 1 A

- PG

- 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 A ( 30 %) S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL
To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 4 , 018 , 542 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H2,900.0P

227 , 935 W 803

. 0 T 211

. 9 P 1 , 426

. 5 H 489 , 880 W

665

. 2 T 700

. 8 P 1 , 324

. 1 H Single Reheat Extraction to

Boiler

3 , 273 , 047 W 669

. 0 T 710

. 8 P 1 , 325

. 7 H710.8P1,115.5P

224 , 757 W

763

. 9 T 990

. 5 P 1 , 367

. 9 H710.8P710.8P221.9P75.0P75.0P 298 , 978 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

126

. 1 T 2

. 0 P 1 , 085

. 8 H 1 , 850 , 820 W 101

. 1 T

1

. 0 P 1 , 009

. 9 H

2 , 793 W 212

. 0 T 14

. 7 P 180

. 3 H29.0P11.4P4.5P

101

. 4 T 250

. 0 P 70

. 4 H 2 , 793 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H 2 , 504 , 281 W 101

. 1 T

1

. 0 P 69

. 5 H

2 , 504 , 281 W 102

. 8 T 245

. 0 P 71

. 8 H 2 , 504 , 281 W 123

. 8 T 240

. 0 P 92

. 7 H

308 , 204 W 112

. 8 T

1

. 4 P 81

. 1 H 259 , 980 W

133

. 8 T

2

. 5 P 102

. 0 H 2 , 504 , 281 W 235

. 0 T 225

. 0 P 204

. 0 H

942 , 573 W

321

. 8 T 91

. 9 P 292

. 3 H 2 , 504 , 281 W 190

. 2 T 230

. 0 P 158

. 9 H

714 , 637 W

398

. 7 T 243

. 6 P 373

. 7 H 224 , 757 W

513

. 3 T 765

. 9 P 503

. 8 H 4 , 018 , 542 W 388

. 7 T 4 , 195

. 0 P 368

. 3 H 4 , 018 , 542 W 503

. 3 T 4 , 190

. 0 P 491

. 4 H

DEAERATOR

BOILER FEED PUMPS 4 , 018 , 542 W 545

. 5 T 4 , 185

. 0 P 539

. 7 H 19 3 , 273 , 047 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 6 H

106 , 862 W 200

. 2 T 11

. 6 P 168

. 4 H 198 , 466 W 161

. 0 T

4

. 9 P 129

. 2 H

2 , 504 , 281 W 151

. 0 T 235

. 0 P 119

. 8 H 145 , 944 W

583

. 9 T 70

. 0 P 1 , 323

. 5 H 106 , 862 W 370

. 1 T 25

. 0 P 1 , 224

. 0 H 91 , 603 W 216

. 1 T 10

. 4 P 1 , 154

. 1 H 61 , 514 W 156

. 0 T

4

. 3 P 1 , 117

. 1 H 48 , 224 W 128

. 8 T

2

. 2 P 1 , 054

. 6 H2,900.0P 2 , 918 , 947 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H 2 , 154 , 039 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H2.3P2,900.0P

Steam Turbine Makeup

40 , 185 W

59

. 0 T 14

. 7 P 27

. 5 H

311

. 8 T 4 , 200

. 0 P 289

. 5 H 4 , 018 , 542 W 302

. 9 T 70

. 0 P 272

. 8 H 3 , 301 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

Gross Plant Power : 602 MWe Auxiliary Load : 52 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 35

. 2 % Net Plant Heat Rate : 9 , 695 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

DOE / NETL

SC PC P LANT C ASE 1 A 465 , 930 W

304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE CONDENSATE

21 465 , 930 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H ECONAMINE

STEAM

20



## 96Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 21 Case 1B (50%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

H EAT AND 

### M ATERIAL 

### F LOW 

### D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY

P AGES 1 OF 2 

### CO 2 

### C APTURE 

### S ENSITIVITY 

### A NALYSIS 

### C ASE 

### 1 B ( 50 %) S UPERCRITICAL 

### P ULVERIZED 

### C OAL 

### B OILER AND 

### G AS 

### C LEANUP 

### S YSTEMS

DWG

. NO

. 

### CCSA

- HMB

- CS

- 1 B

- PG

- 1 

## Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

489 , 316 W

77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 4 , 301 , 289 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H

3 , 505 , 512 W

1 , 100

. 0 T

655

. 8 P 1 , 570

. 6 H

Single Reheat Extraction from

HP Turbine

1 , 127 , 843 W 59

. 0 T 14

. 7 P 13

. 0 H 3 , 671 , 489 W 59

. 0 T 14

. 7 P 13

. 0 H 95 , 987 W

59

. 0 T 14

. 7 P 13

. 0 H 5 , 375 , 146 W 350

. 0 T 14

. 4 P 144

. 1 H

9 , 490 W 37 , 958 W

3 , 505 , 512 W 668

. 8 T 710

. 8 P 1 , 325

. 6 H

4 , 301 , 289 W 545

. 5 T 4 , 185

. 0 P

539

. 7 H 5 5 , 646 , 915 W 135

. 8 T 14

. 8 P 130

. 5 H

3 1 2

4 6

7 19 8 9 ID FANS

16 5 , 337 , 187 W 350

. 0 T 14

. 2 P 136

. 1 H

Gross Plant Power : 618 MWe Auxiliary Load : 68 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 32

. 9 % Net Plant Heat Rate : 10 , 379 BTU / KWe OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15 12 14 13

10 11

370

. 7 T 15

. 3 P 141

. 4 H

167 , 004 W 59

. 0 T 15

. 0 P 57 , 733 W 63

. 6 T 15

. 0 P 14

. 1 H 467 , 632 W 59

. 0 T 14

. 7 P 27

. 0 H

84 , 969 W 135

. 8 T 14

. 8 P



### DOE / NETL

SC PC P LANT C ASE 1 BSTRIPPERABSORBER FLUE GAS Acid Gas



### ECONAMINE FG +

ECONAMINE CONDENSATE 20

21 118 , 781 W 306

. 3 T 73

. 5 P 1 , 181

. 4 H 840 , 749 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

840 , 749 W

304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE

STEAM 581 , 387 W 95

. 0 T 2 , 214

. 5 P

- 91

. 3 H 584 , 429 W 69

. 0 T 23

. 5 P 12

. 1 H 4 , 804 , 981 W 118

. 2 T 14

. 8 P 85

. 7 H CO 2 COMPRESSION ( INTERSTAGE

COOLING )



### CO 2 

### PRODUCT 

### Baghouse

24 25 23

18 2 , 507 , 230 W

3 , 139 , 685 W 2 , 555 , 051 W 88

. 8 T 14

. 8 P 37

. 6 H

17 22 N OTES : 1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL 

### Air

Coal / Ash

Water Steam

Limestone Slurry Flue Gas Ammonia

Carbon Dioxide

Gypsum



## 97Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 22 Case 1B (50%) Heat and Mass Balance, Power Block Systems

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Water Steam

P AGES 2 OF 2 DWG

. NO

. CCSA

- HMB

- CS

- 1 B

- PG

- 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 B ( 50 %) S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL
To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 4 , 301 , 289 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H2,900.0P

243 , 973 W 803

. 0 T 211

. 9 P 1 , 426

. 5 H 524 , 348 W

665

. 2 T 700

. 8 P 1 , 324

. 1 H Single Reheat Extraction to

Boiler

3 , 505 , 512 W 668

. 8 T 710

. 8 P 1 , 325

. 6 H710.8P1,115.5P

240 , 571 W

763

. 9 T 990

. 5 P 1 , 367

. 9 H710.8P710.8P221.9P75.0P75.0P 321 , 036 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

126

. 1 T 2

. 0 P 1 , 085

. 8 H 1 , 699 , 649 W 101

. 1 T

1

. 0 P 1 , 009

. 9 H

2 , 793 W 212

. 0 T 14

. 7 P 180

. 3 H29.0P11.4P4.5P

101

. 4 T 250

. 0 P 70

. 4 H 2 , 793 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H 2 , 359 , 988 W 101

. 1 T

1

. 0 P 69

. 5 H

2 , 359 , 988 W 102

. 8 T 245

. 0 P 71

. 8 H 2 , 359 , 988 W 123

. 8 T 240

. 0 P 92

. 7 H

290 , 196 W 112

. 8 T

1

. 4 P 81

. 2 H 244 , 921 W

133

. 8 T

2

. 5 P 102

. 0 H 2 , 359 , 988 W 235

. 0 T 225

. 0 P 204

. 0 H

1 , 008 , 893 W 321

. 8 T 91

. 9 P 292

. 3 H 2 , 359 , 988 W 190

. 2 T 230

. 0 P 158

. 9 H

764 , 920 W

398

. 7 T 243

. 6 P 373

. 7 H 240 , 571 W

513

. 3 T 765

. 9 P 503

. 8 H 4 , 301 , 289 W 388

. 7 T 4 , 195

. 0 P 368

. 3 H 4 , 301 , 289 W 503

. 3 T 4 , 190

. 0 P 491

. 4 H

DEAERATOR

BOILER FEED PUMPS 4 , 301 , 289 W 545

. 5 T 4 , 185

. 0 P 539

. 7 H 19 3 , 505 , 512 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 6 H

100 , 705 W 200

. 2 T 11

. 6 P 168

. 4 H 187 , 031 W 161

. 0 T

4

. 9 P 129

. 2 H

2 , 359 , 988 W 151

. 0 T 235

. 0 P 119

. 8 H 134 , 673 W

586

. 2 T 70

. 0 P 1 , 324

. 6 H 100 , 705 W 370

. 1 T 25

. 0 P 1 , 224

. 0 H 86 , 325 W 216

. 1 T 10

. 4 P 1 , 154

. 1 H 57 , 890 W 156

. 0 T

4

. 3 P 1 , 118

. 4 H 45 , 275 W 128

. 8 T

2

. 2 P 1 , 054

. 6 H2,900.0P 3 , 146 , 645 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H 1 , 984 , 860 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H2.3P2,900.0P

Steam Turbine Makeup

43 , 013 W

59

. 0 T 14

. 7 P 27

. 5 H

311

. 8 T 4 , 200

. 0 P 289

. 5 H 4 , 301 , 289 W 302

. 9 T 70

. 0 P 272

. 8 H 3 , 301 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

Gross Plant Power : 618 MWe Auxiliary Load : 68 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 32

. 9 % Net Plant Heat Rate : 10 , 379 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

DOE / NETL

SC PC P LANT C ASE 1 B 840 , 749 W

304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE CONDENSATE

21 840 , 749 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H ECONAMINE

STEAM

20



## 98Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 23 Case 1C (70%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

H EAT AND 

### M ATERIAL 

### F LOW 

### D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY

P AGES 1 OF 2 

### CO 2 

### C APTURE 

### S ENSITIVITY 

### A NALYSIS 

### C ASE 

### 1 C ( 70 %) S UPERCRITICAL 

### P ULVERIZED 

### C OAL 

### B OILER AND 

### G AS 

### C LEANUP 

### S YSTEMS

DWG

. NO

. 

### CCSA

- HMB

- CS

- 1 C

- PG

- 1 

## Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

525 , 764 W

77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 4 , 620 , 838 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H

3 , 768 , 233 W

1 , 100

. 0 T

655

. 8 P 1 , 570

. 6 H

Single Reheat Extraction from

HP Turbine

1 , 211 , 853 W 59

. 0 T 14

. 7 P 13

. 0 H 3 , 944 , 969 W 59

. 0 T 14

. 7 P 13

. 0 H

103 , 136 W 59

. 0 T 14

. 7 P 13

. 0 H 5 , 775 , 526 W 350

. 0 T 14

. 4 P 144

. 1 H

10 , 196 W 40 , 786 W

3 , 768 , 233 W 668

. 6 T 710

. 8 P 1 , 325

. 5 H

4 , 620 , 838 W 545

. 5 T 4 , 185

. 0 P

539

. 7 H 5 6 , 068 , 141 W 135

. 8 T 14

. 8 P 130

. 5 H

3 1 2

4 6

7 19 8 9 ID FANS

16 5 , 734 , 741 W 350

. 0 T 14

. 2 P 136

. 1 H

Gross Plant Power : 638 MWe Auxiliary Load : 88 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 30

. 6 % Net Plant Heat Rate : 11 , 151 BTU / KWe OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15 12 14 13

10 11

370

. 7 T 15

. 3 P 141

. 4 H

177 , 758 W 59

. 0 T 15

. 0 P 62 , 577 W 63

. 6 T 15

. 0 P 14

. 1 H 502 , 908 W 59

. 0 T 14

. 7 P 27

. 0 H

91 , 095 W 135

. 8 T 14

. 8 P



### DOE / NETL

SC PC P LANT C ASE 1 CSTRIPPERABSORBER FLUE GAS Acid Gas



### ECONAMINE FG +

ECONAMINE CONDENSATE 20

21 177 , 556 W 306

. 3 T 73

. 5 P 1 , 181

. 4 H 1 , 256 , 768 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

1 , 256 , 768 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE

STEAM 870 , 237 W 95

. 0 T 2 , 214

. 5 P

- 91

. 3 H 874 , 811 W 69

. 0 T 23

. 5 P 12

. 1 H 4 , 813 , 608 W 106

. 5 T 14

. 8 P 64

. 0 H CO 2 COMPRESSION ( INTERSTAGE

COOLING )



### CO 2 

### PRODUCT 

### Baghouse

24 25 23

18 1 , 347 , 127 W

4 , 721 , 014 W 3 , 845 , 896 W 88

. 8 T 14

. 8 P 37

. 6 H

17 22 N OTES : 1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL 

### Air

Coal / Ash

Water Steam

Limestone Slurry Flue Gas Ammonia

Carbon Dioxide Gypsum



## 99Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 24 Case 1C (70%) Heat and Mass Balance, Power Block Systems

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Water Steam

P AGES 2 OF 2 DWG

. NO

. CCSA

- HMB

- CS

- 1 C

- PG

- 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 C ( 70 %) S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL
To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 4 , 620 , 838 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H2,900.0P

262 , 098 W 803

. 0 T 211

. 9 P 1 , 426

. 5 H 563 , 303 W

665

. 2 T 700

. 8 P 1 , 324

. 1 H Single Reheat Extraction to

Boiler

3 , 768 , 233 W 668

. 6 T 710

. 8 P 1 , 325

. 5 H710.8P1,115.5P

258 , 444 W

763

. 9 T 990

. 5 P 1 , 367

. 9 H710.8P710.8P221.9P75.0P75.0P 344 , 936 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

126

. 1 T 2

. 0 P 1 , 085

. 8 H 1 , 536 , 049 W 101

. 1 T

1

. 0 P 1 , 009

. 9 H

2 , 793 W 212

. 0 T 14

. 7 P 180

. 3 H29.0P11.4P4.5P

101

. 4 T 250

. 0 P 70

. 4 H 2 , 793 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H 2 , 204 , 019 W 101

. 1 T

1

. 0 P 69

. 5 H

2 , 204 , 019 W 102

. 9 T 245

. 0 P 71

. 9 H 2 , 204 , 019 W 123

. 8 T 240

. 0 P 92

. 7 H

270 , 731 W 112

. 9 T

1

. 4 P 81

. 3 H 228 , 644 W

133

. 8 T

2

. 5 P 102

. 0 H 2 , 204 , 019 W 235

. 0 T 225

. 0 P 204

. 0 H

1 , 083 , 845 W 321

. 8 T 91

. 9 P 292

. 3 H 2 , 204 , 019 W 190

. 2 T 230

. 0 P 158

. 9 H

821 , 746 W

398

. 7 T 243

. 6 P 373

. 7 H 258 , 444 W

513

. 3 T 765

. 9 P 503

. 8 H 4 , 620 , 838 W 388

. 7 T 4 , 195

. 0 P 368

. 3 H 4 , 620 , 838 W 503

. 3 T 4 , 190

. 0 P 491

. 4 H

DEAERATOR

BOILER FEED PUMPS 4 , 620 , 838 W 545

. 5 T 4 , 185

. 0 P 539

. 7 H 19 3 , 768 , 233 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 6 H

94 , 050 W 200

. 2 T 11

. 6 P 168

. 4 H 174 , 670 W 161

. 0 T

4

. 9 P 129

. 2 H

2 , 204 , 019 W 151

. 0 T 235

. 0 P 119

. 8 H 122 , 415 W

589

. 3 T 70

. 0 P 1 , 326

. 1 H 94 , 050 W 370

. 1 T 25

. 0 P 1 , 224

. 0 H 80 , 620 W 216

. 1 T 10

. 4 P 1 , 154

. 1 H 53 , 974 W 156

. 0 T

4

. 3 P 1 , 120

. 1 H 42 , 087 W 128

. 8 T

2

. 2 P 1 , 054

. 6 H2,900.0P 3 , 403 , 499 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H 1 , 801 , 795 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H2.3P2,900.0P

Steam Turbine Makeup

46 , 208 W

59

. 0 T 14

. 7 P 27

. 5 H

311

. 8 T 4 , 200

. 0 P 289

. 5 H 4 , 620 , 838 W 302

. 9 T 70

. 0 P 272

. 8 H 3 , 301 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

Gross Plant Power : 638 MWe Auxiliary Load : 88 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 30

. 6 % Net Plant Heat Rate : 11 , 151 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

DOE / NETL

SC PC P LANT C ASE 1 C 1 , 256 , 768 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE CONDENSATE

21 1 , 256 , 768 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H ECONAMINE

STEAM

20



## 100Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 25 Case 1D (85%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY

P AGES 1 OF 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 D ( 85 %) S UPERCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. CCSA

- HMB

- CS

- 1 D

- PG

- 1 

## Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

557 , 283 W

77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 4 , 897 , 176 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H

3 , 995 , 429 W

1 , 100

. 0 T

655

. 8 P 1 , 570

. 6 H

Single Reheat Extraction from

HP Turbine

1 , 284 , 503 W 59

. 0 T 14

. 7 P 13

. 0 H 4 , 181 , 468 W 59

. 0 T 14

. 7 P 13

. 0 H

109 , 319 W 59

. 0 T 14

. 7 P 13

. 0 H 6 , 121 , 766 W 350

. 0 T 14

. 4 P 144

. 1 H

10 , 808 W 43 , 231 W

3 , 995 , 429 W 668

. 5 T 710

. 8 P 1 , 325

. 4 H

4 , 897 , 176 W 545

. 5 T 4 , 185

. 0 P

539

. 7 H 5 6 , 432 , 224 W 135

. 8 T 14

. 8 P 130

. 5 H

3 1 2

4 6

7 19 8 9 ID FANS

16 6 , 078 , 535 W 350

. 0 T 14

. 2 P 136

. 1 H

Gross Plant Power : 655 MWe Auxiliary Load : 105 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 28

. 9 % Net Plant Heat Rate : 11 , 819 BTU / KWe OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15 12 14 13

10 11

370

. 7 T 15

. 3 P 141

. 4 H

190 , 931 W 59

. 0 T 15

. 0 P 66 , 601 W 63

. 6 T 15

. 0 P 14

. 1 H 531 , 721 W 59

. 0 T 14

. 7 P 27

. 0 H

96 , 811 W 135

. 8 T 14

. 8 P

DOE / NETL

SC PC P LANT C ASE 1 DSTRIPPERABSORBER FLUE GAS Acid Gas

ECONAMINE FG +

ECONAMINE CONDENSATE 20

21 228 , 200 W 306

. 3 T 73

. 5 P 1 , 181

. 4 H 1 , 615 , 234 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

1 , 615 , 234 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE

STEAM 1 , 120 , 468 W 95

. 0 T 2 , 214

. 5 P

- 91

. 3 H 1 , 126 , 351 W 69

. 0 T 23

. 5 P 12

. 1 H 4 , 827 , 645 W 94

. 1 T 14

. 8 P 46

. 4 H CO 2 COMPRESSION ( INTERSTAGE

COOLING )

CO 2 PRODUCT 

### Baghouse

24 25 23

18 360 , 205 W

6 , 072 , 019 W 4 , 945 , 220 W 88

. 8 T 14

. 8 P 37

. 6 H

17 22 N OTES : 1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Coal / Ash

Water Steam

Limestone Slurry Flue Gas Ammonia

Carbon Dioxide Gypsum



## 101Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 26 Case 1D (85%) Heat and Mass Balance, Power Block Systems

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Water Steam

P AGES 2 OF 2 DWG

. NO

. CCSA

- HMB

- CS

- 1 D

- PG

- 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 D ( 85 %) S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL
To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 4 , 897 , 176 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H2,900.0P

277 , 772 W 803

. 0 T 211

. 9 P 1 , 426

. 5 H 596 , 990 W

665

. 2 T 700

. 8 P 1 , 324

. 1 H Single Reheat Extraction to

Boiler

3 , 995 , 429 W 668

. 5 T 710

. 8 P 1 , 325

. 4 H710.8P1,115.5P

273 , 899 W

763

. 9 T 990

. 5 P 1 , 367

. 9 H710.8P710.8P221.9P75.0P75.0P 365 , 495 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

126

. 1 T 2

. 0 P 1 , 085

. 8 H 1 , 395 , 745 W 101

. 1 T

1

. 0 P 1 , 009

. 9 H

2 , 793 W 212

. 0 T 14

. 7 P 180

. 3 H29.0P11.4P4.5P

101

. 4 T 250

. 0 P 70

. 4 H 2 , 793 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H 2 , 070 , 355 W 101

. 1 T

1

. 0 P 69

. 5 H

2 , 070 , 355 W 103

. 0 T 245

. 0 P 72

. 0 H 2 , 070 , 355 W 123

. 8 T 240

. 0 P 92

. 7 H

254 , 050 W 113

. 0 T

1

. 4 P 81

. 4 H 214 , 694 W

133

. 8 T

2

. 5 P 102

. 0 H 2 , 070 , 355 W 235

. 0 T 225

. 0 P 204

. 0 H

1 , 148 , 661 W 321

. 8 T 91

. 9 P 292

. 3 H 2 , 070 , 355 W 190

. 2 T 230

. 0 P 158

. 9 H

870 , 889 W

398

. 7 T 243

. 6 P 373

. 7 H 273 , 899 W

513

. 3 T 765

. 9 P 503

. 8 H 4 , 897 , 176 W 388

. 7 T 4 , 195

. 0 P 368

. 3 H 4 , 897 , 176 W 503

. 3 T 4 , 190

. 0 P 491

. 4 H

DEAERATOR

BOILER FEED PUMPS 4 , 897 , 176 W 545

. 5 T 4 , 185

. 0 P 539

. 7 H 19 3 , 995 , 429 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 6 H

88 , 346 W 200

. 2 T 11

. 6 P 168

. 4 H 164 , 077 W 161

. 0 T

4

. 9 P 129

. 2 H

2 , 070 , 355 W 151

. 0 T 235

. 0 P 119

. 8 H 111 , 897 W

592

. 4 T 70

. 0 P 1 , 327

. 7 H 88 , 346 W 370

. 1 T 25

. 0 P 1 , 224

. 0 H 75 , 731 W 216

. 1 T 10

. 4 P 1 , 154

. 1 H 50 , 617 W 156

. 0 T

4

. 3 P 1 , 121

. 8 H 39 , 355 W 128

. 8 T

2

. 2 P 1 , 054

. 6 H2,900.0P 3 , 625 , 538 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H 1 , 644 , 810 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H2.3P2,900.0P

Steam Turbine Makeup

48 , 972 W

59

. 0 T 14

. 7 P 27

. 5 H

311

. 8 T 4 , 200

. 0 P 289

. 5 H 4 , 897 , 176 W 302

. 9 T 70

. 0 P 272

. 8 H 3 , 301 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

Gross Plant Power : 655 MWe Auxiliary Load : 105 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 28

. 9 % Net Plant Heat Rate : 11 , 819 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

DOE / NETL

SC PC P LANT C ASE 1 D 1 , 615 , 234 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE CONDENSATE

21 1 , 615 , 234 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H ECONAMINE

STEAM

20



## 102Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 27 Case 1A (30%) Energy Balance

HHV Sensible + Latent Power Total
Heat In GJ/hr (MMBtu/hr)

Coal 5,626 (5,332) 4.7 (4.5) 5,630 (5,337) Combustion Air 62.7 (59.4) 62.7 (59.4) Raw Water Makeup 93.1 (88.3) 93.1 (88.3) Limestone 0.46 (0.43) 0.46 (0.43)

Totals 5,626 (5,332) 161.0 (152.6) 0.0 (0.0) 5,787 (5,485)
Heat Out GJ/hr (MMBtu/hr)
Bottom Ash 0.5 (0.5) 0.5 (0.5) Fly Ash + Gypsum 2.0 (1.9) 2.0 (1.9)
Flue Gas 533 (505) 533 (505) CO 2 

### - 31 (

- 30)

- 31 (

- 30)
Cooling Tower * 2,384.4 (2,260.0) 2,384.4 (2,260.0)

Process Losses* * 917.8 (869.9) 917.8 (869.9)

Net Power 1,980 (1,877) 1,980 (1,877)

Totals 0.0 (0.0) 3,807 (3,608) 1,980 (1,877) 5,787 (5,485) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reac tions, gas cooling, and Econamine steam.



## 103Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 28 Case 1B (50%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)

Coal 6,023 (5,708) 5.0 (4.8) 6,028 (5,713) Combustion Air 67.1 (63.6) 67.1 (63.6)
Raw Water Makeup 106.8 (101.3) 106.8 (101.3) Limestone 0.49 (0.46) 0.49 (0.46)

Totals 6,023 (5,708) 179.5 (170.1) 0.0 (0.0) 6,202 (5,878)
Heat Out GJ/hr (MMBtu/hr)
Bottom Ash 0.5 (0.5) 0.5 (0.5) Fly Ash + Gypsum 2.2 (2.1) 2.2 (2.1)
Flue Gas 435 (412) 435 (412) CO 2 

### - 56 (

- 53)

- 56 (

- 53)
Cooling Tower * 2,434.7 (2,307.7) 2,434.7 (2,307.7)

Process Losses* * 1,406.2 (1,332.8) 1,406.2 (1,332.8)

Net Power 1,980 (1,877) 1,980 (1,877)

Totals 0.0 (0.0) 4,222 (4,002) 1,980 (1,877) 6,202 (5,878) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reactions, gas cooling, and Econamine steam.



## 104Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 29 Case 1C (70%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)

Coal 6,471 (6,134) 5.4 (5.1) 6,477 (6,139) Combustion Air 72.1 (68.4) 72.1 (68.4)
Raw Water Makeup 130.3 (123.5) 130.3 (123.5) Limestone 0.52 (0.49) 0.52 (0.49)

Totals 6,471 (6,134) 208.3 (197.4) 0.0 (0.0) 6,680 (6,331)
Heat Out GJ/hr (MMBtu/hr)
Bottom Ash 0.6 (0.6) 0.6 (0.6) Fly Ash + Gypsum 2.4 (2.2) 2.4 (2.2)
Flue Gas 325 (308) 325 (308) CO 2 

### - 84 (

- 79)

- 84 (

- 79)
Cooling Tower * 2,777.1 (2,632.2) 2,777.1 (2,632.2)

Process Losses* * 1,677.9 (1,590.4) 1,677.9 (1,590.4)

Net Power 1,980 (1,877) 1,980 (1,877)

Totals 0.0 (0.0) 4,699 (4,454) 1,980 (1,877) 6,680 (6,331) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reactions, gas cooling, and Econamine steam.



## 105Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 30 Case 1D (85%) Energy Balance

HHV Sensible + Latent Power Total
Heat In GJ/hr (MMBtu/hr)

Coal 6,859 (6,501) 5.7 (5.4) 6,865 (6,507) Combustion Air 76.4 (72.5) 76.4 (72.5)
Raw Water Makeup 150.6 (142.7) 150.6 (142.7) Limestone 0.56 (0.53) 0.56 (0.53)

Totals 6,859 (6,501) 233.3 (221.1) 0 (0) 7,092 (6,722)
Heat Out GJ/hr (MMBtu/hr)
Bottom Ash 0.6 (0.6) 0.6 (0.6) Fly Ash + Gypsum 2.5 (2.4) 2.5 (2.4)
Flue Gas 236 (224) 236 (224) CO 2 

### - 108 (

- 102)

- 108 (

- 102)
Cooling Tower * 3,076.6 (2,916.1) 3,076.6 (2,916.1)

Process Losses* * 1,904.1 (1,804.8) 1,904.1 (1,804.8)

Net Power 1,980 (1,877) 1,980 (1,877)

Totals 5,112 (4,846) 1,980 (1,877) 7,092 (6,722) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reac tions, gas cooling, and Econamine steam.



## 106Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 31 Case 1A Energy Balance Sankey Diagram

Exhibit 3
- 32 Case 1B Energy Balance Sankey Diagram



## 107Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 33 Case 1C Energy Balance Sankey Diagram

Exhibit 3
- 34 Case 1D Energy Balance Sankey Diagram



## 108Carbon Dioxide Capture Sensitivity Analysis



## 3.2.1.2 Major Equipment List for Cases 1A t hrough 1D Major equipment items for the CO 2 

## capture bypass cases are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in t he cost estimates in Section 3.2.4 . In general , the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pu mps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D
1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)
2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0) 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A 1 (0) 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)
6 As

- Received Coal Sampling System Two

- stage N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling Linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 54 tonne (60 ton) 2 (1) 9 Feeder Vibratory 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 200 tonne/hr (220 tph) 209 tonne/hr (230 tph) 2 (1) 10 Conveyor No. 3 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0) 11 Crusher Tower N/A N/A N/A N/A N/A 1 (0)
12 Coal Surge Bin w/ Vent Filter Dual Outlet 172 tonne (190 ton) 181 tonne (200 ton) 200 tonne (220 ton) 209 tonne (230 ton) 2 (0)

13 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 2 (0)

14 As

- Fired Coal Sampling System Swing Hammer N/A N/A N/A N/A 1 (1)
15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0) 16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A 1 (0) 17 Conveyor No. 5 Belt w/tripper 345 tonne/hr (380 tph) 363 tonne/hr (400 tph) 390 tonne/hr (430 tph) 417 tonne/hr (460 tph) 1 (0)
18 Coal Silo w/ Vent Filter and Slide Gates Field Erected 726 tonne (800 ton) 816 tonne (900 ton) 907 tonne (1,000 ton) 907 tonne (1,000 ton) 3 (0)

19 Limestone Truck Unloading Hopper N/A 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 1 (0)
20 Limestone Feeder Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 1 (0) 21 Limestone Conveyor No. L1 Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 1 (0) 22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 18 tonne (20 ton) 18 tonne (20 ton) 18 tonne (20 ton) 1 (0) 23 Limestone Reclaim Feeder Belt 73 tonne/hr (80 tph) 73 tonne/hr (80 tph) 82 tonne/hr (90 tph) 82 tonne/hr (90 tph) 1 (0) 24 Limestone Conveyor No. L2 Belt 73 tonne/hr (80 tph) 73 tonne/hr (80 tph) 82 tonne/hr (90 tph) 82 tonne/hr (90 tph) 1 (0) 25 Limestone Day Bin w/ actuator 281 tonne (310 ton) 299 tonne (330 ton) 318 tonne (350 ton) 336 tonne (370 ton) 2 (0)



## 10 9Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D 1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 36 tonne/hr (40 tph) 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 6 (0) 2 Coal Pulverizer Ball type or eq. 36 tonne/hr (40 tph) 36 tonne/hr (40 tph) 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 6 (0) 3 Limestone Weigh Feeder Gravimetric 23 tonne/hr (25 tph) 24 tonne/hr (27 tph) 26 tonne/hr (29 tph) 2 8 tonne/hr (3 1 tph) 1 (1) 4 Limestone Ball Mill Rotary 23 tonne/hr (25 tph) 24 tonne/hr (27 tph) 26 tonne/hr (29 tph) 2 8 tonne/hr (3 1 tph) 1 (1)
5 Limestone Mill Slurry Tank with Agitator N/A 87,064 liters (23,000 gal) 94,635 liters (25,000 gal) 98,421 liters (26,000 gal) 105,992 liters (28,000 gal) 1 (1)

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1,476 lpm @ 12m H 2 

### O (390 gpm @ 40 ft H 2 

### O) 1,552 lpm @ 12m H 2 

### O (410 gpm @ 40 ft H 2 

### O ) 1,666 lpm @ 12m H 2 

### O (440 gpm @ 40 ft H 2 

### O) 1,779 lpm @ 12m H 2 

### O (470 gpm @ 40 ft H 2 

### O) 1 (1)

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 379 lpm (100 gpm) per cyclone 379 lpm (100 gpm) per cyclone 416 lpm (110 gpm) per cyclone 454 lpm (120 gpm) per cyclone 1 (1)

8 Distribution Box 2

- way N/A N/A N/A N/A 1 (1)
9 Limestone Slurry Storage Tank with Agitator Field erected 499,674 liters (13 2 ,000 gal) 533,743 liters (14 1 ,000 gal) 571,597 liters (151,000 gal) 609,451 liters (1 61 ,000 gal) 1 (1)

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1,022 lpm @ 9m H 2 

### O (270 gpm @ 30 ft H 2 

### O) 1,098 lpm @ 9m H 2 

### O (290 gpm @ 30 ft H 2 

### O ) 1,173 lpm @ 9m H 2 

### O (310 gpm @ 30 ft H 2 

### O) 1,249 lpm @ 9m H 2 

### O (330 gpm @ 30 ft H 2 

### O) 1 (1)



## ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D
1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,20 3,761 liters (31 8 ,000 gal) 1,290,825 liters (341,000 gal) 1,385,461 liters (366,000 gal) 1,468,740 liters (388,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 20,820 lpm @ 213 m H 2 

### O (5,500 gpm @ 700 ft H 2 

### O) 19,684 lpm @ 213 m H 2 

### O (5,200 gpm @ 700 ft H 2 

### O) 18,549 lpm @ 213 m H 2 

### O (4,900 gpm @ 700 ft H 2 

### O) 17,413 lpm @ 213 m H 2 

### O (4,600 gpm @ 700 ft H 2 

### O) 1 (1)

3 Deaerator and Storage Tank Horizontal spray type 2,00 4,878 kg/hr (4,42 0 ,000 lb/hr), 5 min. tank 2,14 5,946 kg/hr (4,73 1 ,000 lb/hr), 5 min. tank 2,30 5,610 kg/hr (5,08 3 ,000 lb/hr), 5 min. tank 2,443 , 502 kg/hr (5,38 7 ,000 lb/hr), 5 min. tank 1 (0)

4 Boiler Feed Pump/Turbine Barrel type, multi

stage, centrifugal 33,690 lpm @ 3,505 m H 2 

### O (8,900 gpm @ 11,500 ft H 2 

### O) 35,961 lpm @ 3,505 m H 2 

### O (9,500 gpm @ 11,500 ft H 2 

### O) 38,611 lpm @ 3,505 m H 2 

### O (10,200 gpm @ 11,500 ft H 2 

### O) 40,882 lpm @ 3,505 m H 2 

### O (10,800 gpm @ 11,500 ft H 2 

### O) 1 (1)

5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multi

stage, centrifugal 9,842 lpm @ 3,505 m H 2 

### O (2, 6 00 gpm @ 11,500 ft H 2 

### O) 10,599 lpm @ 3,505 m H 2 

### O (2,800 gpm @ 11,500 ft H 2 

### O) 11,356 lpm @ 3,505 m H 2 

### O (3,000 gpm @ 11,500 ft H 2 

### O) 12,113 lpm @ 3,505 m H 2 

### O (3,200 gpm @ 11,500 ft H 2 

### O) 1 (0)

6 LP Feedwater Heater 1A/1B Horizontal U

- tube 625,957 kg/hr (1,380,000 lb/hr) 589,670 kg/hr (1,300,000 lb/hr) 548,847 kg/hr (1,210,000 lb/hr) 517,095 kg/hr (1,140,000 lb/hr) 2 (0)

7 LP Feedwater Heater 2A/2B Horizontal U

- tube 625,957 kg/hr (1,380,000 lb/hr) 589,670 kg/hr (1,300,000 lb/hr) 548,847 kg/hr (1,210,000 lb/hr) 517,095 kg/hr (1,140,000 lb/hr) 2 (0)

8 LP Feedwater Heater 3A/3B Horizontal U

- tube 625,957 kg/hr (1,380,000 lb/hr) 589,670 kg/hr (1,300,000 lb/hr) 548,847 kg/hr (1,210,000 lb/hr) 517,095 kg/hr (1,140,000 lb/hr) 2 (0)

9 LP Feedwater Heater 4A/4B Horizontal U

- tube 625,957 kg/hr (1,380,000 lb/hr) 589,670 kg/hr (1,300,000 lb/hr) 548,847 kg/hr (1,210,000 lb/hr) 517,095 kg/hr (1,140,000 lb/hr) 2 (0)

10 HP Feedwater Heater 6 Horizontal U

- tube 2,004,878 kg/hr (4,420,000 lb/hr) 2,1 45,492 kg/hr (4,7 3 0,000 lb/hr) 2,30 4,249 kg/hr (5,0 8 0,000 lb/hr) 2,444,863 kg/hr (5,390,000 lb/hr) 1 (0)

11 HP Feedwater Heater 7 Horizontal U

- tube 2,004,878 kg/hr (4,420,000 lb/hr) 2,1 45,492 kg/hr (4,7 3 0,000 lb/hr) 2,30 4,249 kg/hr (5,0 8 0,000 lb/hr) 2,444,863 kg/hr (5,390,000 lb/hr) 1 (0)

12 HP Feedwater heater 8 Horizontal U

- tube 2,004,878 kg/hr (4,420,000 lb/hr) 2,1 45,492 kg/hr (4,7 3 0,000 lb/hr) 2,30 4,249 kg/hr (5,0 8 0,000 lb/hr) 2,444,863 kg/hr (5,390,000 lb/hr) 1 (0)



## 110Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

13 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1 (0)

15 Service Air Compressors Flooded Screw 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 (1)

16 Instrument Air Dryers Duplex, regenerative 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 2 (1)

17 Closed Cycl e Cooling Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 2 (0)

18 Closed Cycle Cooling Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H 2 

### O (5,500 gpm @ 100 ft H 2 

### O) 20,820 lpm @ 30 m H 2 

### O (5,500 gpm @ 100 ft H 2 

### O) 20,820 lpm @ 30 m H 2 

### O (5,500 gpm @ 100 ft H 2 

### O) 20,820 lpm @ 30 m H 2 

### O (5,500 gpm @ 100 ft H 2 

### O) 2 (1)

19 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 88 m H 2 

### O (1,000 gpm @ 290 ft H 2 

### O) 3,785 lpm @ 88 m H 2 

### O (1,000 gpm @ 290 ft H 2 

### O) 3,785 lpm @ 88 m H 2 

### O (1,000 gpm @ 290 ft H 2 

### O) 3,785 lpm @ 88 m H 2 

### O (1,000 gpm @ 290 ft H 2 

### O) 1 (1)

20 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 64 m H 2 

### O (700 gpm @ 210 ft H 2 

### O) 2,650 lpm @ 64 m H 2 

### O (700 gpm @ 210 ft H 2 

### O) 2,650 lpm @ 64 m H 2 

### O (700 gpm @ 210 ft H 2 

### O) 2,650 lpm @ 64 m H 2 

### O (700 gpm @ 210 ft H 2 

### O) 1 (1)

21 Raw Water Pumps Stainless steel, single suction 12, 870 lpm @ 43 m H 2 

### O (3,4 0 0 gpm @ 140 ft H 2 

### O) 14, 763 lpm @ 43 m H 2 

### O (3,9 0 0 gpm @ 140 ft H 2 

### O) 17,1 48 lpm @ 43 m H 2 

### O (4,5 3 0 gpm @ 140 ft H 2 

### O) 19,268 lpm @ 43 m H 2 

### O (5,090 gpm @ 140 ft H 2 

### O) 2 (1)

22 Filtered Water Pumps Stainless steel, single suction 568 lpm @ 49 m H 2 

### O (150 gpm @ 160 ft H 2 

### O) 644 lpm @ 49 m H 2 

### O (170 gpm @ 160 ft H 2 

### O) 719 lpm @ 49 m H 2 

### O (190 gpm @ 160 ft H 2 

### O) 757 lpm @ 49 m H 2 

### O (200 gpm @ 160 ft H 2 

### O) 2 (1)
23 Filtered Water Tank Vertical, cylindrical 560,241 liter (148,000 gal) 598,095 liter (1 58 ,000 gal) 681,374 liter (180,000 gal) 719,228 liter (190,000 gal) 1 (0)

24 Makeup Water Demineralizer Multi

- media filter, cartridge filter, RO membrane assembly, electrodeionization unit 719 lpm (190 gpm) 795 lpm (210 gpm) 871 lpm (230 gpm) 946 lpm (250 gpm) 1 (1)

25 Liquid Waste Treatment System -- 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



## ACCOUNT 4 BOILER AND ACCESSORIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Boiler Supercritical, drum, wall

- fired, low NOx burners, overfire air 2,004,878 kg/hr steam @ 25.5 MPa/602°C/602°C (4,420,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,145,492 kg/hr steam @ 25.5 MPa/602°C/602°C (4,730,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,304,249 kg/hr steam @ 25.5 MPa/602°C/602°C (5,080,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,444,863 kg/hr steam @ 25.5 MPa/602°C/602°C (5,390,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1 (0)

2 Primary Air Fan Centrifugal 262,630 kg/hr, 3,585 m 3 

### /min @ 123 cm WG (579,000 lb/hr, 126,600 acfm @ 48 in. WG) 281,227 kg/hr, 3,840 m 3 

### /min @ 123 cm WG (620,000 lb/hr, 135,600 acfm @ 48 in. WG) 302,546 kg/hr, 4,126 m 3 

### /min @ 123 cm WG (667,000 lb/hr, 145,700 acfm @ 48 in. WG) 320,236 kg/hr, 4,372 m 3 

### /min @ 123 cm WG (706,000 lb/hr, 154,400 acfm @ 48 in. WG) 2 (0)

3 Forced Draft Fan Centrifugal 855,475 kg/hr, 11,672 m 3 

### /min @ 51 cm WG (1,886,000 lb/hr, 412,200 acfm @ 20 in. WG) 915,803 kg/hr, 12,496 m 3 

### /min @ 51 cm WG (2,019,000 lb/hr, 441,300 acfm @ 20 in. WG) 984,295 kg/hr, 13,425 m 3 

### /min @ 51 cm WG (2,170,000 lb/hr, 474,100 acfm @ 20 in. WG) 1,043,262 kg/hr, 14,232
m 3 

### /min @ 51 cm WG (2,300,000 lb/hr, 502,600 acfm @ 20 in. WG) 2 (0)

4 Induced Draft Fan Centrifugal 1,243,750 kg/hr, 26,618
m 3 

### /min @ 91 cm WG (2,742,000 lb/hr, 940,000 acfm @ 36 in. WG) 1,331,294 kg/hr, 28,495
m 3 

### /min @ 91 cm WG (2,935,000 lb/hr, 1,006,300 acfm @ 36 in. WG) 1,430,630 kg/hr, 30,619
m 3 

### /min @ 91 cm WG (3,154,000 lb/hr, 1,081,300 acfm @ 36 in. WG) 1,516,359 kg/hr, 32,454
m 3 

### /min @ 91 cm WG (3,343,000 lb/hr, 1,146,100 acfm @ 36 in. WG) 2 (0)



## 111Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D
5 SCR Reactor Vessel Space for spare layer 2,485,686 kg/hr (5,480,000 lb/hr) 2,662,587 kg/hr (5,870,000 lb/hr) 2,862,168 kg/hr (6,310,000 lb/hr) 3,034,533 kg/hr (6,690,000 lb/hr) 2 (0)

6 SCR Catalyst

-- -- -- -- -- 3 (0)

7 Dilution Air Blower Centrifugal 45 m 3 

### /min @ 108 cm WG (1,600 acfm @ 42 in. WG) 48 m 3 

### /min @ 108 cm WG (1,700 acfm @ 42 in. WG) 51 m 3 

### /min @ 108 cm WG (1,800 acfm @ 42 in. WG) 54 m 3 

### /min @ 108 cm WG (1,900 acfm @ 42 in. WG) 2 (1)
8 Ammonia Storage Horizontal tank 49,210 liter (13,000 gal) 52,996 liter (14,000 gal) 56,781 liter (15,000 gal) 60,567 liter (16,000 gal) 5 (0)
9 Ammonia Feed Pump Centrifugal 9 lpm @ 91 m H 2 

### O (2 gpm @ 300 ft H 2 

### O) 10 lpm @ 91 m H 2 

### O (3 gpm @ 300 ft H 2 

### O) 11 lpm @ 91 m H 2 

### O (3 gpm @ 300 ft H 2 

### O) 11 lpm @ 91 m H 2 

### O (3 gpm @ 300 ft H 2 

### O) 2 (1)



## ACCOUNT 5 FLUE GAS CLEANUP
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Fabric Filter Single stage, high

- ratio with pulse

- jet online cleaning system 1,243,750 kg/hr (2,742,000 lb/hr) 99.8% efficiency 1,331,294 kg/hr (2,935,000 lb/hr) 99.8% efficiency 1,430,630 kg/hr (3,154,000 lb/hr) 99.8% efficiency 1,516,359 kg/hr (3,343,000 lb/hr) 99.8% efficiency 2 (0)

2 Absorber Module Counter

- current open spray 41,059 m 3 

### /min (1,450,000 acfm) 43,948 m 3 

### /min (1,552,000 acfm) 47,233 m 3 

### /min (1,668,000 acfm) 50,064 m 3 

### /min (1,768,000 acfm) 1 (0)

3 Recirculation Pumps Horizontal centrifugal 143,846 lpm @ 64 m H 2 

### O (38,000 gpm @ 210 ft H 2 

### O) 151,416 lpm @ 64 m H 2 

### O (40,000 gpm @ 210 ft H 2 

### O) 162,773 lpm @ 64 m H 2 

### O (43,000 gpm @ 210 ft H 2 

### O) 174,129 lpm @ 64 m H 2 

### O (46,000 gpm @ 210 ft H 2 

### O) 5 (1)

4 Bleed Pumps Horizontal centrifugal 4,505 lpm (1,190 gpm) at 20 wt% solids 4,807 lpm (1,270 gpm) at 20 wt% solids 5,148 lpm (1,360 gpm) at 20 wt% solids 5,489 lpm (1,450 gpm) at 20 wt% solids 2 (1)

5 Oxidation Air Blowers Centrifugal 184 m 3 

### /min @ 0.3 MPa (6,500 acfm @ 42 psia) 194 m 3 

### /min @ 0.3 MPa (6,860 acfm @ 42 psia) 211 m 3 

### /min @ 0.3 MPa (7,440 acfm @ 42 psia) 224 m 3 

### /min @ 0.3 MPa (7,910 acfm @ 42 psia) 2 (1)
6 Agitators Side entering 50 hp 50 hp 50 hp 50 hp 5 (1)

7 Dewatering Cyclones Radial assembly, 5 units each 1,136 lpm (300 gpm) per cyclone 1,211 lpm (320 gpm) per cyclone 1,287 lpm (340 gpm) per cyclone 1,363 lpm (360 gpm) per cyclone 2 (0)

8 Vacuum Filter Belt Horizontal belt 35 tonne/hr (39 tph) of 50 wt % slurry 38 tonne/hr (42 tph) of 50 wt % slurry 41 tonne/hr (45 tph) of 50 wt % slurry 44 tonne/hr (48 tph) of 50 wt % slurry 2 (1)

9 Filtrate Water Return Pumps Horizontal centrifugal 681 lpm @ 12 m H 2 

### O (180 gpm @ 40 ft H 2 

### O) 719 lpm @ 12 m H 2 

### O (190 gpm @ 40 ft H 2 

### O) 795 lpm @ 12 m H 2 

### O (210 gpm @ 40 ft H 2 

### O) 833 lpm @ 12 m H 2 

### O (220 gpm @ 40 ft H 2 

### O) 1 (1)

10 Filtrate Water Return Storage Tank Vertical, lined 454,249 lpm (120,000 gal) 492,104 lpm (130,000 gal) 529,958 lpm (140,000 gal) 529,958 lpm (140,000 gal) 1 (1)

11 Process Makeup Water Pumps Horizontal centrifugal 454 lpm @ 21 m H 2 

### O (120 gpm @ 70 ft H 2 

### O) 492 lpm @ 21 m H 2 

### O (130 gpm @ 70 ft H 2 

### O) 530 lpm @ 21 m H 2 

### O (140 gpm @ 70 ft H 2 

### O) 568 lpm @ 21 m H 2 

### O (150 gpm @ 70 ft H 2 

### O) 1 (1)



## 112Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 5B CARBON DIOXIDE RECOVERY

Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D*

1 Econamine FG Plus Amine

- based CO 2 

### capture technology 876,340 kg/h (1,932,000 lb/h) 20.6 wt % CO 2 

### concentration 1,566,708 kg/h (3,454,000 lb/h) 20.6 wt % CO 2 

### concentration 2,355,505 kg/h (5,193,000 lb/h) 20.6 wt % CO 2 

### concentration 1,514,999 kg/h (3,340,000 lb/h) 20.6 wt % CO 2 

### concentration 1 (0)

2 Econamine Condensate Pump Centrifugal 3,899 lpm @ 52 m H 2 

### O (1,030 gpm @ 170 ft H 2 

### O) 7,003 lpm @ 52 m H 2 

### O (1,850 gpm @ 170 ft H 2 

### O) 10,448 lpm @ 52 m H 2 

### O (2,760 gpm @ 170 ft H 2 

### O) 13,438 lpm @ 52 m H 2 

### O (3,550 gpm @ 170 ft H 2 

### O) 1 (1)

3 CO 2 

### Compressor Centrifugal 161,385 kg/h @ 15.3 MPa (355,793 lb/h @ 2,215 psia) 290,084 kg/h @ 15.3 MPa (639,526 lb/h @ 2,215 psia) 434,206 kg/h @ 15.3 MPa (957,260 lb/h @ 2,215 psia) 279,530 kg/h @ 15.3 MPa (616,257 lb/h @ 2,215 psia) 1 (0)
* Case 1D is equipped with two operating CO 2 

### absorption and compression trains, which is reflected in the design conditions.



## ACCOUNT 6 COMBU STION TURBINE/ACCESSORIES N/A

ACCOUNT 7 DUCTING AND STACK
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x 5. 7 m (1 9 ft) diameter 152 m (500 ft) high x 5. 6 m (1 9 ft) diameter 152 m (500 ft) high x 5.6 m ( 18 ft) diameter 152 m (500 ft) high x 5.6 m ( 18 ft) diameter 

## 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Steam Turbine Generator Commercially available, advanced steam turbine 633 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 651 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 671 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 689 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 

## 1 (0)

2 Steam Turbine Generator Hydrogen cooled, static excitation 700 M VA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 720 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 750 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 770 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 

## 1 (0)

3 Surface Condenser Single pass, divided waterbox including vacuum pumps 2,384 GJ/hr (2,260 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 2,237 GJ/hr (2,120 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 2,089 GJ/hr (1,980 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,962 GJ/hr (1,860 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 

## 1 (0)



## 113Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D
1 Circulating Water Pumps Vertical, wet pit 583,000 lpm @ 30 m (154,000 gpm @ 100 ft) 673,800 lpm @ 30 m (178,000 gpm @ 100 ft) 829,000 lpm @ 30 m (219,000 gpm @ 100 ft) 965,300 lpm @ 30 m (255,000 gpm @ 100 ft) 2 ( 1 )

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 3260 GJ/hr (3090 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 3756 GJ/hr (3560 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 4621 GJ/hr (4380 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 5370 GJ/hr (5090 MMBtu/hr) heat duty 1 ( 0 )



## ACCOUNT 10 ASH/SPENT SORBENT RECOV ERY AND HANDLING
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 Economizer Hopper (part of boiler scope of supply) -- -- -- -- -- 4 (0)

2 Bottom Ash Hopper (part of boiler scope of supply) -- -- -- -- -- 2 (0)

3 Clinker Grinder

-- 4.5 tonne/hr (5 tph) 4.5 tonne/hr (5 tph) 5.4 tonne/hr (6 tph) 5.4 tonne/hr (6 tph) 1 (1)

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- -- -- -- -- 6 (0)

5 Hydroejectors

-- -- -- -- -- 12 (0) 6 Economizer/Pyrites Transfer Tank

-- -- -- -- -- 1 (0)

7 Ash Sluice Pumps Vertical, wet pit 189 lpm @ 17 m H 2 

### O (50 gpm @ 56 ft H 2 

### O) 189 lpm @ 17 m H 2 

### O (50 gpm @ 56 ft H 2 

### O) 189 lpm @ 17 m H 2 

### O (50 gpm @ 56 ft H 2 

### O) 227 lpm @ 17 m H 2 

### O (60 gpm @ 56 ft H 2 

### O) 1 (1)

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H 2 

### O (2000 gpm @ 28 ft H 2 

### O) 7,571 lpm @ 9 m H 2 

### O (2000 gpm @ 28 ft H 2 

### O) 7,571 lpm @ 9 m H 2 

### O (2000 gpm @ 28 ft H 2 

### O) 7,571 lpm @ 9 m H 2 

### O (2000 gpm @ 28 ft H 2 

### O) 1 (1)
9 Hydrobins

-- 189 lpm (50 gpm) 189 lpm (50 gpm) 189 lpm (50 gpm) 227 lpm (60 gpm) 1 (1)

10 Baghouse Hopper (part of baghouse scope of supply) --

-- -- -- -- 24 (0)

11 Air Heater Hopper (part of boiler scope of supply) --

-- -- -- -- 10 (0)

12 Air Blower

-- 16 m 3 

### /min @ 0.2 MPa (570 scfm @ 24 psi) 17 m 3 

### /min @ 0.2 MPa (610 scfm @ 24 psi) 1 9 m 3 

### /min @ 0.2 MPa (6 6 0 scfm @ 24 psi) 20 m 3 

### /min @ 0.2 MPa (690 scfm @ 24 psi) 1 (1)

13 Fly Ash Silo Reinforced concrete 544 tonne (1,200 ton) 5 90 tonne (1, 3 00 ton) 590 tonne (1,300 ton) 635 tonne (1,400 ton) 2 (0)

14 Slide Gate Valves

-- -- -- -- -- 2 (0) 15 Unloader

-- -- -- -- -- 1 (0) 16 Telescoping Unloading Chute

-- 100 tonne/hr (110 tph) 109 tonne/hr (120 tph) 1 18 tonne/hr (1 3 0 tph) 118 tonne/hr (130 tph) 1 (0)



## 114Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 11 ACCESSORY ELECTRIC PLANT
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D
1 STG Transformer Oil

- filled 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 1 (0)

2 Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 55 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 7 4 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 9 5 MVA, 3

- ph, 60 Hz 24 kV /4.16 kV, 114 MVA, 3

- ph, 60 Hz 1 (1)

3 L ow V oltage Transformer Dry ventilated 4.16 kV/480 V, 8 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 11 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 14 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 17 MVA, 3

- ph, 60 Hz 1 (1)

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

5 Medium Voltage Switchgear Metal Clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1) 6 Low Voltage Switchgear Metal Enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

7 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



## ACCOUNT 12 INSTRUMENTATION AND CONTROL
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1A Case 1B Case 1C Case 1D

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator Stations/Printers and Engineering Stations/Printers Operator Stations/Printers and Engineering Stations/Printers Operator Stations/Printers and Engineering Stations/Printers Operator Stations/Printers and Engineering Stations/Printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A N/A N/A N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)



## 115Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

116Carbon Dioxide Capture Sensitivity Analysis



# 3.2.2 Full CO 2 

# Capture Performance Results
A process block flow diagram for Cases 1 E through 1G is shown in Exhibit 3

- 35 . These cases represent supercritical steam cycles with CO 2 

## capture ranging from 90 percent to 99 percent

. The corresponding stream tables are contained in Exhibit 3

- 36 , Exhibit 3

- 37 , and Exhibit 3

- 38 for 90 percent , 95 percent , and 99 percent CO 2 

## capture, respectively. Overall performance for Cases 1E through 1G is summarized in Exhibit 3

- 39 which includes auxiliary power requirements. Material and energy balance info rmation, environmental performance and a major e quipment list are summarized in Sections 3.2.2.1 and 3.2.2.2

.

117Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 35 Cases 1E through 1G Process Block Flow Diagram, Supercritical PC with CO 2 

### Capture



## Primary Air Fans Baghouse FGD

ID Fans

Stack gas

Stack Gypsum Limestone

Slurry Oxidation Air Makeup Water

Bottom Ash Coal Feed Infiltration air 8

1 2

Forced Draft Fans 3 4

6 5

7 Fly Ash 10 11 13 14

12 15

Pulverized Coal Boiler SCR
16

Econamine FG + 18

19

CO 2 

## Compression 21 22 CO 2 

## Product Reboiler Steam

Condensate Return Steam Turbine

Condenser 9

17

20 Note : Block Flow Diagram is not in complete material balance

. Only major process streams and equipment are shown

.



## 118Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 36 Case 1E Stream Table, Supercritical PC with 90% CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 67,188 67,188 20,639 20,639 1,757 0 0 94,760 0 94,760 94,760 V-L Flowrate (kg/hr) 1,938,845 1,938,845 595,593 595,593 50,689 0 0 2,818,469 0 2,818,469 2,818,469 Solids Flowrate (kg/hr) 0 0 0 0 0 258,399 5,011 20,045 20,045 0 0
Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 Enthalpy (kJ/kg) A 

### 30.23 34.36 30.23 40.78 30.23

--- --- 335.07

--- 316.66 328.98 Density (kg/m 3 

### ) 1.2 1.3 1.2 1.3 1.2

--- --- 0.8

--- 0.8 0.8 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743
V-L Flowrate (lb mol 

### /hr) 148,124 148,124 45,502 45,502 3,873 0 0 208,911 0 208,911 208,911 V-L Flowrate (lb/hr) 4,274,421 4,274,421 1,313,058 1,313,058 111,750 0 0 6,213,660 0 6,213,660 6,213,660 Solids Flowrate (lb/hr) 0 0 0 0 0 569,672 11,048 44,192 44,192 0 0
Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 Enthalpy (Btu/lb) A 

### 13.0 14.8 13.0 17.5 13.0

--- --- 144.1

--- 136.1 141.4 Density (lb/ft 3 

### ) 0.076 0.078 0.076 0.081 0.076

--- --- 0.049

--- 0.049 0.051 A - Reference conditions are 32.02 F & 0.089 PSIA



## 119Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 36 Case 1E Stream Table, Supercritical PC with 90% CO 2 Capture (continued)

12 13 14 15 16 17 18 19 20 21 22 V-L Mole Fraction

Ar 0.0000 0.0000 0.0092 0.0000 0.0081 0.0000 0.0000 0.0000 0.0108 0.0000 0.0000 CO 2 

### 0.0000 0.0000 0.0003 0.0004 0.1347 0.0000 0.0000 0.0000 0.0179 0.9874 1.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 1.0000 1.0000 0.0099 0.9996 0.1549 1.0000 1.0000 1.0000 0.0381 0.0126 0.0000 N 2 

### 0.0000 0.0000 0.7732 0.0000 0.6785 0.0000 0.0000 0.0000 0.9016 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.2074 0.0000 0.0238 0.0000 0.0000 0.0000 0.0316 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 3,416 13,737 1,071 249 103,518 126,037 44,254 44,254 77,899 12,707 12,547 V-L Flowrate (kg/hr) 61,544 247,481 30,902 4,494 2,982,488 2,270,587 797,253 797,253 2,194,649 555,084 552,194 Solids Flowrate (kg/hr) 26,140 0 0 40,408 0 0 0 0 0 0 0
Temperature (°C) 15 15 18 58 58 593 291 151 32 21 35 Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.16 15.27 Enthalpy (kJ/kg) A



### --- 62.80 32.81

--- 303.64 3,477.66 3,046.14 637.34 93.55 28.23 -212.35 Density (kg/m 3 

### )

--- 1,003.1 1.2

--- 1.1 69.2 2.0 916.0 1.1 2.9 794.3 V-L Molecular Weight

--- 18.015 28.857

--- 28.811 18.015 18.015 18.015 28.173 43.682 44.010
V-L Flowrate (lb mol 

### /hr) 7,531 30,286 2,361 550 228,218 277,863 97,564 97,564 171,737 28,015 27,662 V-L Flowrate (lb/hr) 135,681 545,602 68,127 9,907 6,575,262 5,005,788 1,757,642 1,757,642 4,838,373 1,223,750 1,217,380 Solids Flowrate (lb/hr) 57,629 0 0 89,085 0 0 0 0 0 0 0
Temperature (°F) 59 59 64 136 136 1,100 556 304 89 69 95 Pressure (psia) 15.0 14.7 15.0 14.8 14.8 3,514.7 73.5 133.6 14.8 23.5 2,214.5 Enthalpy (Btu/lb) A



### --- 27.0 14.1

--- 130.5 1,495.1 1,309.6 274.0 40.2 12.1 -91.3 Density (lb/ft 3 

### )

--- 62.622 0.077

--- 0.067 4.319 0.123 57.184 0.071 0.183 49.586 A - Reference conditions are 32.02 F & 0.089 PSIA



## 120Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 37 Case 1F Stream Table, Supercritical PC with 95% CO 2 

### C apture

1 2 3 4 5 6 7 8 9 10 11 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 68,946 68,946 21,180 21,180 1,803 0 0 97,240 0 97,240 97,240 V-L Flowrate (kg/hr) 1,989,579 1,989,579 611,178 611,178 52,015 0 0 2,892,220 0 2,892,220 2,892,220 Solids Flowrate (kg/hr) 0 0 0 0 0 265,160 5,142 20,570 20,570 0 0
Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 Enthalpy (kJ/kg) A 

### 30.23 34.36 30.23 40.78 30.23

--- --- 335.07

--- 316.66 328.98 Density (kg/m 3 

### ) 1.2 1.3 1.2 1.3 1.2

--- --- 0.8

--- 0.8 0.8 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743
V-L Flowrate (lb mol 

### /hr) 152,000 152,000 46,693 46,693 3,974 0 0 214,378 0 214,378 214,378 V-L Flowrate (lb/hr) 4,386,271 4,386,271 1,347,417 1,347,417 114,674 0 0 6,376,254 0 6,376,254 6,376,254 Solids Flowrate (lb/hr) 0 0 0 0 0 584,578 11,337 45,348 45,348 0 0
Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 Enthalpy (Btu/lb) A 

### 13.0 14.8 13.0 17.5 13.0

--- --- 144.1

--- 136.1 141.4 Density (lb/ft 3 

### ) 0.076 0.078 0.076 0.081 0.076

--- --- 0.049

--- 0.049 0.051 A - Reference conditions are 32.02 F & 0.089 PSIA



## 121Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 37 Case 1F Stream Table, Supercritical PC with 95% CO 2 Capture (continued)

12 13 14 15 16 17 18 19 20 21 22 V-L Mole Fraction

Ar 0.0000 0.0000 0.0092 0.0000 0.0081 0.0000 0.0000 0.0000 0.0109 0.0000 0.0000 CO 2 

### 0.0000 0.0000 0.0003 0.0004 0.1347 0.0000 0.0000 0.0000 0.0090 0.9880 1.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 1.0000 1.0000 0.0099 0.9996 0.1550 1.0000 1.0000 1.0000 0.0381 0.0120 0.0000 N 2 

### 0.0000 0.0000 0.7732 0.0000 0.6785 0.0000 0.0000 0.0000 0.9101 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.2074 0.0000 0.0238 0.0000 0.0000 0.0000 0.0319 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 3,444 14,163 1,100 256 106,227 129,327 48,990 48,990 79,194 13,755 13,591 V-L Flowrate (kg/hr) 62,046 255,146 31,733 4,612 3,060,557 2,329,868 882,562 882,562 2,220,106 601,089 598,124 Solids Flowrate (kg/hr) 26,844 0 0 41,485 0 0 0 0 0 0 0
Temperature (°C) 15 15 18 58 58 593 291 151 32 21 35 Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.16 15.27 Enthalpy (kJ/kg) A



### --- 62.80 32.81

--- 303.64 3,477.66 3,046.14 637.34 93.94 27.89 -212.35 Density (kg/m 3 

### )

--- 1,003.1 1.2

--- 1.1 69.2 2.0 916.0 1.1 2.9 794.3 V-L Molecular Weight

--- 18.015 28.857

--- 28.811 18.015 18.015 18.015 28.034 43.699 44.010
V-L Flowrate (lb mol 

### /hr) 7,593 31,223 2,424 564 234,191 285,118 108,004 108,004 174,593 30,325 29,962 V-L Flowrate (lb/hr) 136,788 562,500 69,960 10,168 6,747,374 5,136,479 1,945,717 1,945,717 4,894,497 1,325,174 1,318,637 Solids Flowrate (lb/hr) 59,180 0 0 91,460 0 0 0 0 0 0 0
Temperature (°F) 59 59 64 136 136 1,100 556 304 89 69 95 Pressure (psia) 15.0 14.7 15.0 14.8 14.8 3,514.7 73.5 133.6 14.8 23.5 2,214.5 Enthalpy (Btu/lb) A



### --- 27.0 14.1

--- 130.5 1,495.1 1,309.6 274.0 40.4 12.0 -91.3 Density (lb/ft 3 

### )

--- 62.622 0.077

--- 0.067 4.319 0.123 57.184 0.070 0.183 49.586 A - Reference conditions are 32.02 F & 0.089 PSIA



## 122Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 38 Case 1G Stream Table, Supercritical PC with 99% CO 2 

### C apture

1 2 3 4 5 6 7 8 9 10 11 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 73,780 73,780 22,664 22,664 1,929 0 0 104,057 0 104,057 104,057 V-L Flowrate (kg/hr) 2,129,062 2,129,062 654,026 654,026 55,662 0 0 3,094,985 0 3,094,985 3,094,985 Solids Flowrate (kg/hr) 0 0 0 0 0 283,750 5,503 22,012 22,012 0 0
Temperature (°C) 15 19 15 25 15 15 15 177 15 177 188 Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 Enthalpy (kJ/kg) A 

### 30.23 34.36 30.23 40.78 30.23

--- --- 335.07

--- 316.66 328.98 Density (kg/m 3 

### ) 1.2 1.3 1.2 1.3 1.2

--- --- 0.8

--- 0.8 0.8 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743
V-L Flowrate (lb mol 

### /hr) 162,657 162,657 49,966 49,966 4,252 0 0 229,407 0 229,407 229,407 V-L Flowrate (lb/hr) 4,693,779 4,693,779 1,441,880 1,441,880 122,713 0 0 6,823,274 0 6,823,274 6,823,274 Solids Flowrate (lb/hr) 0 0 0 0 0 625,561 12,132 48,528 48,528 0 0
Temperature (°F) 59 66 59 78 59 59 59 350 59 350 371 Pressure (psia) 14.7 15.3 14.7 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.3 Enthalpy (Btu/lb) A 

### 13.0 14.8 13.0 17.5 13.0

--- --- 144.1

--- 136.1 141.4 Density (lb/ft 3 

### ) 0.076 0.078 0.076 0.081 0.076

--- --- 0.049

--- 0.049 0.051 A - Reference conditions are 32.02 F & 0.089 PSIA



## 123Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 38 Case 1G Stream Table, Supercritical PC with 99% CO2 Capture (continued)

12 13 14 15 16 17 18 19 20 21 22 V-L Mole Fraction

Ar 0.0000 0.0000 0.0092 0.0000 0.0081 0.0000 0.0000 0.0000 0.0109 0.0000 0.0000 CO 2 

### 0.0000 0.0000 0.0003 0.0004 0.1347 0.0000 0.0000 0.0000 0.0018 0.9885 1.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 1.0000 1.0000 0.0099 0.9995 0.1550 1.0000 1.0000 1.0000 0.0381 0.0115 0.0000 N 2 

### 0.0000 0.0000 0.7732 0.0000 0.6785 0.0000 0.0000 0.0000 0.9170 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.2074 0.0000 0.0238 0.0000 0.0000 0.0000 0.0321 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 3,668 15,153 1,173 252 113,670 138,374 64,178 64,178 84,106 15,332 15,156 V-L Flowrate (kg/hr) 66,073 272,981 33,851 4,541 3,275,005 2,492,848 1,156,187 1,156,187 2,348,253 670,179 667,006 Solids Flowrate (kg/hr) 28,635 0 0 44,303 0 0 0 0 0 0 0
Temperature (°C) 15 15 18 58 58 593 291 151 32 21 35 Pressure (MPa, abs) 0.10 0.10 0.10 0.10 0.10 24.23 0.51 0.92 0.10 0.16 15.27 Enthalpy (kJ/kg) A



### --- 62.80 32.81

--- 303.63 3,477.66 3,046.14 637.34 94.26 27.39 -212.35 Density (kg/m 3 

### )

--- 1,003.1 1.2

--- 1.1 69.2 2.0 916.0 1.1 2.9 794.3 V-L Molecular Weight

--- 18.015 28.857

--- 28.811 18.015 18.015 18.015 27.920 43.711 44.010
V-L Flowrate (lb mol 

### /hr) 8,086 33,406 2,586 555 250,600 305,063 141,489 141,489 185,421 33,801 33,413 V-L Flowrate (lb/hr) 145,667 601,821 74,628 10,011 7,220,151 5,495,788 2,548,957 2,548,957 5,177,011 1,477,492 1,470,497 Solids Flowrate (lb/hr) 63,129 0 0 97,672 0 0 0 0 0 0 0
Temperature (°F) 59 59 64 136 136 1,100 556 304 89 69 95 Pressure (psia) 15.0 14.7 15.0 14.8 14.8 3,514.7 73.5 133.6 14.8 23.5 2,214.5 Enthalpy (Btu/lb) A



### --- 27.0 14.1

--- 130.5 1,495.1 1,309.6 274.0 40.5 11.8 -91.3 Density (lb/ft 3 

### )

--- 62.622 0.077

--- 0.067 4.319 0.123 57.184 0.070 0.183 49.586 A - Reference conditions are 32.02 F & 0.089 PSIA



## 124Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 39 Cases 1E through 1G Performance Modeling Results POWER SUMMARY (Gross Power at Generator Terminals, kWe) Case 1 E ( 9 0%) Case 1 F ( 95 %) Case 1 G ( 99 %) Steam Turbine Power 661,300 667,900 679,600 AUXILIARY LOAD SUMMARY, kWe 1 

### Coal Handling and Conveying 5 1 0 510 540 Limestone Handling & Reagent Preparation 1,2 6 0 1,290 1,3 8 0 Pulverizers 3,8 7 0 3,9 8 0 4,2 5 0 Ash Handling 7 4 0 7 6 0 8 1 0 Primary Air Fans 1, 81 0 1,8 6 0 1,9 9 0 Forced Draft Fans 2, 31 0 2,3 7 0 2,5 3 0 Induced Draft Fans 10,000 10, 26 0 10, 92 0 SCR 20 20 20 Baghouse 100 100 110 FGD Pumps and Agitators 4, 13 0 4, 24 0 4, 54 0 Econamine FG Plus Auxiliaries 20, 7 00 22, 4 00 2 5,0 00 CO 2 

### Compression 4 4,39 0 48,080 53, 610 Econamine Condensate Pump 160 170 2 3 0 Miscellaneous Balance of Plant 2 

### 2,000 2,000 2,000 Steam Turbine Auxiliaries 400 400 400 Condensate Pumps 5 8 0 5 5 0 4 7 0 Circulating Water Pumps 10,120 10,480 11,620

Cooling Tower Fans 5, 91 0 6,150 6,820

Transformer Loss 2,2 8 0 2,3 2 0 2,3 9 0 TOTAL AUXILIARIES, kWe 111,290 117,940 129,630 NET POWER, kWe 550,010 549,960 549,970 Net Plant Efficiency, % (HHV) 28.2% 27.5% 25.7% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,748 (12,083) 13,083 (12,400) 14,000 (13,269) CONDENSER COOLING DUTY GJ/hr (10 6 

### Btu/hr) 1,735 (1,645) 1,665 (1,578) 1,400 (1,327) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 3 

### 258,399 (569,672) 265,160 (584,578) 283,750 (625,561) Thermal Input, kWt 1,947,689 1,998,654 2,138,774 Raw Water Withdrawal , m 3 

### /min (gpm) 38.2 (10,095) 39.8 (10,512) 44.2 (11,664) Raw Water Consumption
, m 3 

### /min (gpm) 29.3 (7,753) 30.6 (8,074) 33.9 (8,961) 

### Notes: 1. Boiler feed pumps are turbine driven 2. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 3. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)



## 125Carbon Dioxide Capture Sensitivity Analysis



## 3.2.2.1 Environmental Performance for Cases 1E t hrough 1G Each case was designed to meet presumptive BACT standards utilizing the emissions control processes described in Section 2.4 . A summary of plant air emissions for Case 1E (90 percent ), 1F (95 percent ), and 1G (99 percent ) is presented in Exhibit 3

- 40

. SO 2 

## emissions are controlled using a wet limestone forced oxidation FGD that achieves a removal efficiency of 98 percent . To avoid the formation of heat stable salts in the Econamine process, an SO 2 

## polishing step is included to reduce the sulfur content to 10 ppm prior to the CO 2 

## absorber , and the balance of the SO 2 

## is absorbed by the MEA solution resulting in negligible stack emissions. The byproduct calcium sulfate is dew atered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The saturated flue gas exiting the FGD is vented through the plant s tack. Particulate emissions are controlled using a pulse jet fabric filter (baghouse) which operates at an efficiency of 99.8 percent . It was assumed that 20 percent of the ash exits the boiler as bottom ash and the remaining 80 percent exits the boiler i n the flue gas [ 41 ].

Co

- benefit capture of Hg in the fabric filter and FGD system was assumed to achieve a 90 percent capture rate [ 42 ]. The high chlorine content of the Illinois No. 6 coal and the SCR system will convert most of the Hg in the system to an oxidized state [ 43 ] . An inexpensive FGD system additive can be used to promote Hg capture if necessary, but was not included

. The carbon balance for the three cases is shown in Exhibit 3

- 41

. The carbon input to the plant consists of carbon in the coal, limestone, and combustion and FGD forced oxidation air.

CO 2 

## capture efficiency is calculated as the pou nds of CO 2 

## captured divided by the pounds of CO 2 

## produced. Most of the CO 2 

## produced comes from coal combustion, but a small amount is formed in th e FGD system. The sum of these two sources is the amount produced. (Carbon in Sequestration Product) / (Carbon in the Coal + Net Carbon from Limestone) or 3 32,243 / (3 63,136 + 5, 242 ) *100 = 90% (Case 1E) 35 9,878 / (3 72,638 + 5,378 ) *100 = 95% (Case 1F) 401,323 / ( 398,762 + 5,756 ) *10 0 = 99% (Case 1G) Exhibit 3

- 42 shows the sulfur balance for the three cases. Sulfur input comes solely from the sulfur in the coal. Sulfur output is the gypsum sulfur byproduct, and the sulfur emitted in the stack gas. The total sulfur capture is represented by the following fractio n: (Sulfur byproduct/Sulfur in the coal) or (13,993/14,278)*100 = 98.0% (Case 1E) (14,359/14,652)*100 = 98.0% (Case 1F) (15,366/15,679)*100 = 98.0% (Case 1G)

The overall water balance s for Case 1E, 1G, and 1F are shown in Exhibit 3

- 43 , Exhibit 3

- 44 , and Exhibi t 3

- 45 , respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water req uired for a partic ular process. Some water is recovered within t he process and that water is re used as

126Carbon Dioxide Capture Sensitivity Analysis



## internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 46 through Exhibit 3

- 51

.

• Boiler and flue gas cleanup

• Steam and feedwater An overall plant energy balance is provided in tabular form for Case 1E, 1F, and 1G in Exhibit 3

- 52 , Exhibit 3

- 53 , and Exhibit 3

- 54 , respectively. The power out is the steam turbine power after generator losses. In addition, energy balance Sankey diagrams are provided in Exhibit 3

- 5 5 , Exhibit 3

- 56 , and Exhibit 3

- 57 for Case 1E, 1F, and 1G, respectively.

127Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 40 Cases 1E through 1G Estimated Air Emission Rates

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh )

Case 1E Case 1F Case 1G Case 1E Case 1F Case 1G Case 1E Case 1F Case 1G

SO 2 

### 0.007 (0.017) 0.007 (0.016) 0.007 (0.016) 372 (410) 378 (417) 402 (443) 0.076 (0.170) 0.076 (0.170) 0.079 (0.170)

NO X 

### 0.030 (0.070) 0.030 (0.070) 0.030 (0.070) 1,571 (1,732) 1,612 (1,777) 1,725 (1,902) 0.319 (0.703) 0.324 (0.715) 0.341 (0.752)

PM 0.006 (0.013) 0.006 (0.013) 0.006 (0.013) 292 (322) 299 (330) 320 (353) 0.059 (0.131) 0.060 (0.133) 0.063 (0.140)

Hg 0.49x10 - 6 

### (1.14x10 - 6 

### ) 0.49x10 - 6 

### (1.14x10 - 6 

### ) 0.49x10 - 6 

### (1.14x10 - 6 

### ) 0.026 (0.028) 0.026 (0.029) 0.028 (0.031) 5.21x10 - 6 

### (11.5x10 - 6 

### ) 5.29x10 - 6 

### (11.7x10 - 6 

### ) 5.57x10 - 6 

### (12.3x10 - 6 

### )

CO 2 

### 8.8 (20.4) 4.4 (10.2) 0.9 (2.0) 456,848 (503,588) 234,401 (258,383) 50,167 (55,299) 93 (205) 47 (104) 10 (22)
CO 2 

### net 112 (246) 57 (126) 12 (27)



## 128Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 41 Cases 1E through 1G Carbon Balance Carbon In, kg/hr (lb/hr) Case 1E Case 1F Case 1G

Coal 164,716 (363,136) 169,026 (372,638) 180,876 (398,762) Air (CO 2 

### ) 352 (775) 361 (795) 386 (851) Limestone 2,652 (5,848) 2,724 (6,005) 2,906 (6,406)

Total 167,720 (369,759) 172,110 (379,438) 184,168 (406,019) Carbon Out, kg/hr (lb/hr)

Stack Gas 16,745 (36,916) 8,591 (18,941) 1,839 (4,054)

CO 2 

### Product 150,703 (332,243) 163,238 (359,878) 182,037 (401,323) Gypsum 275 (606) 284 (627) 295 (650) Convergence Tolerance* - 3 (

- 6)

- 3 (

- 7)

- 3 (

- 7)

Total 167,720 (369,759) 172,110 (379,438) 184,168 (406,019)

Exhibit 3
- 42 Cases 1E through 1G Sulfur Balance Sulfur In, kg/hr (lb/hr) Case 1E Case 1F Case 1G Coal 6,4 77 (14, 278 ) 6,646 (14,652) 7,112 (15,679)
Total 6,4 77 (14, 278 ) 6, 646 (14, 652 ) 7, 112 (15, 679 ) Sulfur Out, kg/hr (lb/hr) Gypsum 6,347 (13,993) 6,513 (14,359) 6,970 (15,366) Stack Gas 25 (55) 25 (56) 27 (60)
AGR 104 (230) 107 (237) 115 (254) Convergence Tolerance* 1 (0) 1 (0) 0 (

- 1)

Total 6,4 77 (14, 278 ) 6, 646 (14, 652 ) 7, 112 (15, 679 )



## 129Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 43 Case 1E (90%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge, m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)
Econamine 0.14 (36) 0.0 (0) 0.14 (36) 0.0 (0) 0.14 (36) FGD Makeup 5.16 (1,363) 0.0 (0) 5.16 (1,363) 0.0 (0) 5.16 (1,363) BFW Makeup 0.38 (100) 0.0 (0) 0.38 (100) 0.0 (0) 0.38 (100) Cooling Tower Makeup 39.4 (10,415) 6.88 (1,818) 32.5 (8,597) 8.87 (2,342) 23.7 (6,254)

Total 45.1 (11,914) 6.88 (1,818) 38.2 (10,095) 8.87 (2,342) 29.3 (7,753) Total, gal/MWh net 

### 1,300 198 1,101 256 846

Exhibit 3
- 44 Case 1F (95%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge, m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)
Econamine 0.15 (39) 0.0 (0) 0.15 (39) 0.0 (0) 0.15 (39) FGD Makeup 5.29 (1,399) 0.0 (0) 5.29 (1,399) 0.0 (0) 5.29 (1,399) BFW Makeup 0.39 (103) 0.0 (0) 0.39 (103) 0.0 (0) 0.39 (103) Cooling Tower Makeup 41.0 (10,840) 7.07 (1,869) 34.0 (8,971) 9.23 (2,438) 24.7 (6,534)

Total 46.9 (12,380) 7.07 (1,869) 39.8 (10,512) 9.23 (2,438) 30.6 (8,074) Total, gal/MWh net 

### 1,351 204 1,147 266 881



## 130Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 45 Case 1G (99%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge, m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)
Econamine 0.16 (44) 0.0 (0) 0.16 (44) 0.0 (0) 0.16 (44) FGD Makeup 5.66 (1,495) 0.0 (0) 5.66 (1,495) 0.0 (0) 5.66 (1,495) BFW Makeup 0.42 (110) 0.0 (0) 0.42 (110) 0.0 (0) 0.42 (110) Cooling Tower Makeup 45.5 (12,017) 7.58 (2,002) 37.9 (10,016) 10.2 (2,703) 27.7 (7,313)

Total 51.7 (13,666) 7.58 (2,002) 44.2 (11,664) 10.2 (2,703) 33.9 (8,961) Total, gal/MWh net 

### 1,491 218 1,273 295 978



## 131Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank.

132Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 46 Case 1E (90%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY

P AGES 1 OF 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 E ( 90 %) S UPERCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. CCSA

- HMB

- CS

- 1 E

- PG

- 1 

## Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

569 , 672 W

77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 5 , 005 , 788 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H

4 , 084 , 726 W

1 , 100

. 0 T

655

. 8 P 1 , 570

. 6 H

Single Reheat Extraction from

HP Turbine

1 , 313 , 058 W 59

. 0 T 14

. 7 P 13

. 0 H 4 , 274 , 421 W 59

. 0 T 14

. 7 P 13

. 0 H

111 , 750 W 59

. 0 T 14

. 7 P 13

. 0 H 6 , 257 , 852 W 350

. 0 T 14

. 4 P 144

. 1 H

11 , 048 W 44 , 192 W

4 , 084 , 726 W 668

. 5 T 710

. 8 P 1 , 325

. 4 H

5 , 005 , 788 W 545

. 5 T 4 , 185

. 0 P

539

. 7 H 5 6 , 575 , 262 W 135

. 8 T 14

. 8 P 130

. 5 H

3 1 2

4 6

7 17 8 9 ID FANS

16 6 , 213 , 660 W 350

. 0 T 14

. 2 P 136

. 1 H

Gross Plant Power : 661 MWe Auxiliary Load : 111 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 28

. 2 % Net Plant Heat Rate : 12 , 083 BTU / KWe OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15 12 14 13

10 11

370

. 7 T 15

. 3 P 141

. 4 H

193 , 310 W 59

. 0 T 15

. 0 P 68 , 127 W 63

. 6 T 15

. 0 P 14

. 1 H 545 , 602 W 59

. 0 T 14

. 7 P 27

. 0 H

98 , 992 W 135

. 8 T 14

. 8 PSTRIPPERABSORBER FLUE GAS Acid Gas

ECONAMINE FG +

ECONAMINE CONDENSATE 18

19 248 , 320 W 306

. 3 T 73

. 5 P 1 , 181

. 4 H 1 , 757 , 642 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

1 , 757 , 642 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE

STEAM 1 , 217 , 380 W 95

. 0 T 2 , 214

. 5 P

- 91

. 3 H 1 , 223 , 750 W 69

. 0 T 23

. 5 P 12

. 1 H 4 , 838 , 373 W 88

. 8 T 14

. 8 P 40

. 2 H CO 2 COMPRESSION ( INTERSTAGE

COOLING )

CO 2 PRODUCT 

### Baghouse

21 22 20

DOE / NETL

SC PC P LANT C ASE 1 E N OTES : 1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Coal / Ash

Water Steam

Limestone Slurry Flue Gas Ammonia

Carbon Dioxide Gypsum



## 133Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 47 Case 1E (90%) Heat and Mass Balance, Power Block Systems

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Water Steam

P AGES 2 OF 2 DWG

. NO

. CCSA

- HMB

- CS

- 1 E

- PG

- 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 E ( 90 %) S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL
To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 5 , 005 , 788 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H2,900.0P

283 , 933 W 803

. 0 T 211

. 9 P 1 , 426

. 5 H 610 , 230 W

665

. 2 T 700

. 8 P 1 , 324

. 1 H Single Reheat Extraction to

Boiler

4 , 084 , 726 W 668

. 5 T 710

. 8 P 1 , 325

. 4 H710.8P1,115.5P

279 , 974 W

763

. 9 T 990

. 5 P 1 , 367

. 9 H710.8P710.8P221.9P75.0P75.0P 373 , 617 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

126

. 1 T 2

. 0 P 1 , 085

. 8 H 1 , 339 , 314 W 101

. 1 T

1

. 0 P 1 , 009

. 9 H

2 , 793 W 212

. 0 T 14

. 7 P 180

. 3 H29.0P11.4P4.5P

101

. 4 T 250

. 0 P 70

. 4 H 2 , 793 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H 2 , 016 , 400 W 101

. 1 T

1

. 0 P 69

. 5 H

2 , 016 , 400 W 103

. 1 T 245

. 0 P 72

. 1 H 2 , 016 , 400 W 123

. 8 T 240

. 0 P 92

. 7 H

247 , 316 W 113

. 1 T

1

. 4 P 81

. 4 H 209 , 064 W

133

. 8 T

2

. 5 P 102

. 0 H 2 , 016 , 400 W 235

. 0 T 225

. 0 P 204

. 0 H

1 , 174 , 137 W 321

. 8 T 91

. 9 P 292

. 3 H 2 , 016 , 400 W 190

. 2 T 230

. 0 P 158

. 9 H

890 , 204 W

398

. 7 T 243

. 6 P 373

. 7 H 279 , 974 W

513

. 3 T 765

. 9 P 503

. 8 H 5 , 005 , 788 W 388

. 7 T 4 , 195

. 0 P 368

. 3 H 5 , 005 , 788 W 503

. 3 T 4 , 190

. 0 P 491

. 4 H

DEAERATOR

BOILER FEED PUMPS 5 , 005 , 788 W 545

. 5 T 4 , 185

. 0 P 539

. 7 H 17 4 , 084 , 726 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 6 H

86 , 044 W 200

. 2 T 11

. 6 P 168

. 4 H 159 , 801 W 161

. 0 T

4

. 9 P 129

. 2 H

2 , 016 , 400 W 151

. 0 T 235

. 0 P 119

. 8 H 107 , 667 W

593

. 9 T 70

. 0 P 1 , 328

. 4 H 86 , 044 W 370

. 1 T 25

. 0 P 1 , 224

. 0 H 73 , 757 W 216

. 1 T 10

. 4 P 1 , 154

. 1 H 49 , 263 W 156

. 0 T

4

. 3 P 1 , 122

. 6 H 38 , 253 W 128

. 8 T

2

. 2 P 1 , 054

. 6 H2,900.0P 3 , 712 , 905 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H 1 , 581 , 645 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H2.3P2,900.0P

Steam Turbine Makeup

50 , 058 W

59

. 0 T 14

. 7 P 27

. 5 H

311

. 8 T 4 , 200

. 0 P 289

. 5 H 5 , 005 , 788 W 302

. 9 T 70

. 0 P 272

. 8 H 3 , 301 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

Gross Plant Power : 661 MWe Auxiliary Load : 111 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 28

. 2 % Net Plant Heat Rate : 12 , 083 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

DOE / NETL

SC PC P LANT C ASE 1 E 1 , 757 , 642 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE CONDENSATE

19 1 , 757 , 642 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H ECONAMINE

STEAM

18



## 134Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 48 Case 1F (95%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Sy stems

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY

P AGES 1 OF 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 F ( 95 %) S UPERCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. CCSA

- HMB

- CS

- 1 F

- PG

- 1 

## Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

584 , 578 W

77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 5 , 136 , 479 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H

4 , 192 , 175 W

1 , 100

. 0 T

655

. 8 P 1 , 570

. 6 H

Single Reheat Extraction from

HP Turbine

1 , 347 , 417 W 59

. 0 T 14

. 7 P 13

. 0 H 4 , 386 , 271 W 59

. 0 T 14

. 7 P 13

. 0 H

114 , 674 W 59

. 0 T 14

. 7 P 13

. 0 H 6 , 421 , 602 W 350

. 0 T 14

. 4 P 144

. 1 H

11 , 337 W 45 , 348 W

4 , 192 , 175 W 668

. 4 T 710

. 8 P 1 , 325

. 4 H

5 , 136 , 479 W 545

. 5 T 4 , 185

. 0 P

539

. 7 H 5 6 , 747 , 374 W 135

. 8 T 14

. 8 P 130

. 5 H

3 1 2

4 6

7 17 8 9 ID FANS

16 6 , 376 , 254 W 350

. 0 T 14

. 2 P 136

. 1 H

Gross Plant Power : 668 MWe Auxiliary Load : 118 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 27

. 5 % Net Plant Heat Rate : 12 , 400 BTU / KWe OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15 12 14 13

10 11

370

. 7 T 15

. 3 P 141

. 4 H

195 , 968 W 59

. 0 T 15

. 0 P 69 , 960 W 63

. 6 T 15

. 0 P 14

. 1 H 562 , 500 W 59

. 0 T 14

. 7 P 27

. 0 H

101 , 628 W 135

. 8 T 14

. 8 PSTRIPPERABSORBER FLUE GAS Acid Gas

ECONAMINE FG +

ECONAMINE CONDENSATE 18

19 274 , 891 W 306

. 3 T 73

. 5 P 1 , 181

. 4 H 1 , 945 , 717 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

1 , 945 , 717 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE

STEAM 1 , 318 , 637 W 95

. 0 T 2 , 214

. 5 P

- 91

. 3 H 1 , 325 , 174 W 69

. 0 T 23

. 5 P 12

. 0 H 4 , 894 , 497 W 88

. 8 T 14

. 8 P 40

. 4 H CO 2 COMPRESSION ( INTERSTAGE

COOLING )

CO 2 PRODUCT 

### Baghouse

21 22 20

DOE / NETL

SC PC P LANT C ASE 1 F N OTES : 1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Coal / Ash

Water Steam

Limestone Slurry Flue Gas Ammonia

Carbon Dioxide Gypsum



## 135Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 49 Case 1F (95%) Heat and Mass Balance, Power Block Systems

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Water Steam

P AGES 2 OF 2 DWG

. NO

. CCSA

- HMB

- CS

- 1 F

- PG

- 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 F ( 95 %) S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL
To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 5 , 136 , 479 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H2,900.0P

291 , 346 W 803

. 0 T 211

. 9 P 1 , 426

. 5 H 626 , 162 W

665

. 2 T 700

. 8 P 1 , 324

. 1 H Single Reheat Extraction to

Boiler

4 , 192 , 175 W 668

. 4 T 710

. 8 P 1 , 325

. 4 H710.8P1,115.5P

287 , 283 W

763

. 9 T 990

. 5 P 1 , 367

. 9 H710.8P710.8P221.9P75.0P75.0P 383 , 372 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

126

. 1 T 2

. 0 P 1 , 085

. 8 H 1 , 257 , 727 W 101

. 1 T

1

. 0 P 1 , 009

. 9 H

2 , 793 W 212

. 0 T 14

. 7 P 180

. 3 H29.0P11.4P4.5P

101

. 4 T 250

. 0 P 70

. 4 H 2 , 793 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H 1 , 935 , 817 W 101

. 1 T

1

. 0 P 69

. 5 H

1 , 935 , 817 W 103

. 2 T 245

. 0 P 72

. 1 H 1 , 935 , 817 W 123

. 8 T 240

. 0 P 92

. 7 H

237 , 259 W 113

. 2 T

1

. 4 P 81

. 5 H 200 , 654 W

133

. 8 T

2

. 5 P 102

. 0 H 1 , 935 , 817 W 235

. 0 T 225

. 0 P 204

. 0 H

1 , 204 , 791 W 321

. 8 T 91

. 9 P 292

. 3 H 1 , 935 , 817 W 190

. 2 T 230

. 0 P 158

. 9 H

913 , 445 W

398

. 7 T 243

. 6 P 373

. 7 H 287 , 283 W

513

. 3 T 765

. 9 P 503

. 8 H 5 , 136 , 479 W 388

. 7 T 4 , 195

. 0 P 368

. 3 H 5 , 136 , 479 W 503

. 3 T 4 , 190

. 0 P 491

. 4 H

DEAERATOR

BOILER FEED PUMPS 5 , 136 , 479 W 545

. 5 T 4 , 185

. 0 P 539

. 7 H 17 4 , 192 , 175 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 6 H

82 , 605 W 200

. 2 T 11

. 6 P 168

. 4 H 153 , 415 W 161

. 0 T

4

. 9 P 129

. 2 H

1 , 935 , 817 W 151

. 0 T 235

. 0 P 119

. 8 H 101 , 518 W

596

. 2 T 70

. 0 P 1 , 329

. 5 H 82 , 605 W 370

. 1 T 25

. 0 P 1 , 224

. 0 H 70 , 810 W 216

. 1 T 10

. 4 P 1 , 154

. 1 H 47 , 239 W 156

. 0 T

4

. 3 P 1 , 123

. 7 H 36 , 606 W 128

. 8 T

2

. 2 P 1 , 054

. 6 H2,900.0P 3 , 819 , 090 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H 1 , 490 , 002 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H2.3P2,900.0P

Steam Turbine Makeup

51 , 365 W

59

. 0 T 14

. 7 P 27

. 5 H

311

. 8 T 4 , 200

. 0 P 289

. 5 H 5 , 136 , 479 W 302

. 9 T 70

. 0 P 272

. 8 H 3 , 301 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

Gross Plant Power : 668 MWe Auxiliary Load : 118 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 27

. 5 % Net Plant Heat Rate : 12 , 400 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

DOE / NETL

SC PC P LANT C ASE 1 F 1 , 945 , 717 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE CONDENSATE

19 1 , 945 , 717 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H ECONAMINE

STEAM

18



## 136Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 50 Case 1G (99%) Heat and Mass Balance, Supercritical PC Boiler and Gas Cleanup Systems

H EAT AND 

### M ATERIAL 

### F LOW 

### D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY

P AGES 1 OF 2 

### CO 2 

### C APTURE 

### S ENSITIVITY 

### A NALYSIS 

### C ASE 

### 1 G ( 99 %) S UPERCRITICAL 

### P ULVERIZED 

### C OAL 

### B OILER AND 

### G AS 

### C LEANUP 

### S YSTEMS

DWG

. NO

. 

### CCSA

- HMB

- CS

- 1 G

- PG

- 1 

## Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

625 , 561 W

77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 5 , 495 , 788 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H

4 , 487 , 587 W

1 , 100

. 0 T

655

. 8 P 1 , 570

. 6 H

Single Reheat Extraction from

HP Turbine

1 , 441 , 880 W 59

. 0 T 14

. 7 P 13

. 0 H 4 , 693 , 779 W 59

. 0 T 14

. 7 P 13

. 0 H

122 , 713 W 59

. 0 T 14

. 7 P 13

. 0 H 6 , 871 , 802 W 350

. 0 T 14

. 4 P 144

. 1 H

12 , 132 W 48 , 528 W

4 , 487 , 587 W 668

. 3 T 710

. 8 P 1 , 325

. 3 H

5 , 495 , 788 W 545

. 5 T 4 , 185

. 0 P

539

. 7 H 5 7 , 220 , 151 W 135

. 8 T 14

. 8 P 130

. 5 H

3 1 2

4 6

7 17 8 9 ID FANS

16 6 , 823 , 274 W 350

. 0 T 14

. 2 P 136

. 1 H

Gross Plant Power : 680 MWe Auxiliary Load : 130 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 25

. 7 % Net Plant Heat Rate : 13 , 269 BTU / KWe OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15 12 14 13

10 11

370

. 7 T 15

. 3 P 141

. 4 H

208 , 796 W 59

. 0 T 15

. 0 P 74 , 628 W 63

. 6 T 15

. 0 P 14

. 1 H 601 , 821 W 59

. 0 T 14

. 7 P 27

. 0 H

107 , 683 W 135

. 8 T 14

. 8 PSTRIPPERABSORBER FLUE GAS Acid Gas



### ECONAMINE FG +

ECONAMINE CONDENSATE 18

19 360 , 117 W 306

. 3 T 73

. 5 P 1 , 181

. 4 H 2 , 548 , 957 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

2 , 548 , 957 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE

STEAM 1 , 470 , 497 W 95

. 0 T 2 , 214

. 5 P

- 91

. 3 H 1 , 477 , 492 W 69

. 0 T 23

. 5 P 11

. 8 H 5 , 177 , 011 W 88

. 8 T 14

. 8 P 40

. 5 H CO 2 COMPRESSION ( INTERSTAGE

COOLING )



### CO 2 

### PRODUCT 

### Baghouse

21 22 20



### DOE / NETL

SC PC P LANT C ASE 1 G N OTES : 1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL 

### Air

Coal / Ash

Water Steam

Limestone Slurry Flue Gas Ammonia

Carbon Dioxide Gypsum



## 137Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 51 Case 1G (99%) Heat and Mass Balance, Power Block Systems

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Water Steam

P AGES 2 OF 2 DWG

. NO

. CCSA

- HMB

- CS

- 1 G

- PG

- 2 CO 2 C APTURE S ENSITIVITY A NALYSIS C ASE 1 G ( 99 %) S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL
To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 5 , 495 , 788 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 495

. 1 H2,900.0P

311 , 726 W 803

. 0 T 211

. 9 P 1 , 426

. 5 H 669 , 964 W

665

. 2 T 700

. 8 P 1 , 324

. 1 H Single Reheat Extraction to

Boiler

4 , 487 , 587 W 668

. 3 T 710

. 8 P 1 , 325

. 3 H710.8P1,115.5P

307 , 380 W

763

. 9 T 990

. 5 P 1 , 367

. 9 H710.8P710.8P221.9P75.0P75.0P 410 , 390 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

126

. 1 T 2

. 0 P 1 , 085

. 8 H 962 , 587 W

101

. 1 T

1

. 0 P 1 , 009

. 9 H

2 , 793 W 212

. 0 T 14

. 7 P 180

. 3 H29.0P11.4P4.5P

101

. 4 T 250

. 0 P 70

. 4 H 2 , 793 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H 1 , 633 , 566 W 101

. 1 T

1

. 0 P 69

. 5 H

1 , 633 , 566 W 103

. 5 T 245

. 0 P 72

. 5 H 1 , 633 , 566 W 123

. 8 T 240

. 0 P 92

. 7 H

199 , 538 W 113

. 5 T

1

. 4 P 81

. 8 H 169 , 110 W

133

. 8 T

2

. 5 P 102

. 0 H 1 , 633 , 566 W 235

. 0 T 225

. 0 P 204

. 0 H

1 , 289 , 069 W 321

. 8 T 91

. 9 P 292

. 3 H 1 , 633 , 566 W 190

. 2 T 230

. 0 P 158

. 9 H

977 , 343 W

398

. 7 T 243

. 6 P 373

. 7 H 307 , 380 W

513

. 3 T 765

. 9 P 503

. 8 H 5 , 495 , 788 W 388

. 7 T 4 , 195

. 0 P 368

. 3 H 5 , 495 , 788 W 503

. 3 T 4 , 190

. 0 P 491

. 4 H

DEAERATOR

BOILER FEED PUMPS 5 , 495 , 788 W 545

. 5 T 4 , 185

. 0 P 539

. 7 H 17 4 , 487 , 587 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 6 H

69 , 707 W 200

. 2 T 11

. 6 P 168

. 4 H 129 , 461 W 161

. 0 T

4

. 9 P 129

. 2 H

1 , 633 , 566 W 151

. 0 T 235

. 0 P 119

. 8 H 79 , 154 W

607

. 6 T 70

. 0 P 1 , 335

. 2 H 69 , 707 W 370

. 1 T 25

. 0 P 1 , 224

. 0 H 59 , 754 W 216

. 1 T 10

. 4 P 1 , 154

. 1 H 39 , 649 W 157

. 3 T

4

. 3 P 1 , 129

. 3 H 30 , 427 W 128

. 8 T

2

. 2 P 1 , 054

. 6 H2,900.0P 4 , 116 , 486 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H 1 , 157 , 139 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H2.3P2,900.0P

Steam Turbine Makeup

54 , 958 W

59

. 0 T 14

. 7 P 27

. 5 H

311

. 8 T 4 , 200

. 0 P 289

. 5 H 5 , 495 , 788 W 302

. 9 T 70

. 0 P 272

. 8 H 3 , 301 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

Gross Plant Power : 680 MWe Auxiliary Load : 130 MWe Net Plant Power : 550 MWe Net Plant Efficiency
, HHV : 25

. 7 % Net Plant Heat Rate : 13 , 269 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674

. 7 T 75

. 0 P 1 , 368

. 1 H

DOE / NETL

SC PC P LANT C ASE 1 G 2 , 548 , 957 W 304

. 0 T 133

. 6 P 274

. 0 H ECONAMINE CONDENSATE

19 2 , 548 , 957 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H ECONAMINE

STEAM

18



## 138Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 52 Case 1E (90%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)

Coal 7,012 (6,646) 5.9 (5.6) 7,018 (6,651) Combustion Air 78.1 (74.1) 78.1 (74.1)
Raw Water Makeup 158.4 (150.1) 158.4 (150.1) Limestone 0.57 (0.54) 0.57 (0.54)

Totals 7,012 (6,646) 243.0 (230.3) 0.0 (0.0) 7,255 (6,876)
Heat Out GJ/hr (MMBtu/hr)
Bottom Ash 0.6 (0.6) 0.6 (0.6) Fly Ash + Gypsum 2.6 (2.4) 2.6 (2.4)
Flue Gas 205 (195) 205 (195) CO 2 

### - 117 (

- 111)

- 117 (

- 111)
Cooling Tower * 3,187.8 (3,021.4) 3,187.8 (3,021.4)

Process Losses* * 1,995.6 (1,891.5) 1,995.6 (1,891.5)

Net Power 1,980 (1,877) 1,980 (1,877)

Totals 0.0 (0.0) 5,275 (4,999) 1,980 (1,877) 7,255 (6,876) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reactions, gas cooling, and Econamine steam.



## 139Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 53 Case 1F (95%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)

Coal 7,195 (6,820) 6.0 (5.7) 7,201 (6,825) Combustion Air 80.2 (76.0) 80.2 (76.0)
Raw Water Makeup 164.7 (156.1) 164.7 (156.1) Limestone 0.58 (0.55) 0.58 (0.55)

Totals 7,195 (6,820) 251.5 (238.4) 0.0 (0.0) 7,447 (7,058)
Heat Out GJ/hr (MMBtu/hr)
Bottom Ash 0.7 (0.6) 0.7 (0.6) Fly Ash + Gypsum 2.6 (2.5) 2.6 (2.5)
Flue Gas 209 (198) 209 (198) CO 2 

### - 127 (

- 120)

- 127 (

- 120)
Cooling Tower * 3,195.0 (3,028.3) 3,195.0 (3,028.3)

Process Losses* * 2,187.0 (2,072.8) 2,187.0 (2,072.8)

Net Power 1,980 (1,877) 1,980 (1,877)

Totals 0.0 (0.0) 5,467 (5,182) 1,980 (1,877) 7,447 (7,058) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses fr om: steam turbine, combustion reactions, gas cooling, and Econamine steam.



## 140Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 54 Case 1G (99%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)

Coal 7,700 (7,298) 6.4 (6.1) 7,706 (7,304) Combustion Air 85.8 (81.3) 85.8 (81.3)
Raw Water Makeup 182.2 (172.7) 182.2 (172.7) Limestone 0.62 (0.59) 0.62 (0.59)

Totals 7,700 (7,298) 275.1 (260.7) 0.0 (0.0) 7,975 (7,559)
Heat Out GJ/hr (MMBtu/hr)
Bottom Ash 0.7 (0.7) 0.7 (0.7) Fly Ash + Gypsum 2.8 (2.7) 2.8 (2.7)
Flue Gas 221 (210) 221 (210) CO 2 

### - 142 (

- 134)

- 142 (

- 134)
Cooling Tower * 3,125.1 (2,962.1) 3,125.1 (2,962.1)

Process Losses* * 2,786.4 (2,641.0) 2,786.4 (2,641.0)

Net Power 1,980 (1,877) 1,980 (1,877)

Totals 0.0 (0.0) 5,995 (5,682) 1,980 (1,877) 7,975 (7,559) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Cooling Tower includes losses from the Condenser, Cooling Tower Blowdown, and Econamine cooling water. ** Process losses are estimated to match the heat input to the plant. Process losses include losses from: steam turbine, combustion reac tions, gas cooling, and Econamine steam.



## 141Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 55 Case 1E Energy Balance Sankey Diagram

Exhibit 3
- 56 Case 1F Energy Balance Sankey Diagram



## 142Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 57 Case 1G Energy Balance Sankey Diagram



## 143Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

144Carbon Dioxide Capture Sensitivity Analysis



## 3.2.2.2 Major Equipment List for Cases 1E t hrough 1G Major equipment items for the CO 2 

## capture without bypass cases are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in t he cost estimates in Section 3.2.4 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for he ads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING
Equipment No. Description Type Design Condit ion Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Bottom Trestle Dumper with Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0) 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 4 Transfer Tower No. 1 Enclosed N/A N/A N/A 1 (0) 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)

6 As

- Received Coal Sampling System Two

- stage N/A N/A N/A 1 (0)

7 Stacker/Reclaim Traveling Linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 8 Reclaim Hopper N/A 54 tonne (60 ton) 54 tonne (60 ton) 6 4 tonne ( 7 0 ton) 2 (1) 9 Feeder Vibratory 209 tonne/hr (230 tph) 218 tonne/hr (240 tph) 236 tonne/hr (260 tph) 2 (1) 10 Conveyor No. 3 Belt w/tripper 4 26 tonne/hr (4 7 0 tph) 435 tonne/hr (480 tph) 4 72 tonne/hr (5 2 0 tph) 1 (0) 11 Crusher Tower N/A N/A N/A N/A 1 (0) 12 Coal Surge Bin w/ Vent Filter Dual Outlet 209 tonne (230 ton) 218 tonne (240 ton) 236 tonne (260 ton) 2 (0)

13 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 8 cm x 0

- 3 cm x 0 (3 in x 0

- 1

- 1/4 in x 0) 2 (0)

14 As

- Fired Coal Sampling System Swing Hammer N/A N/A N/A 1 (1)

15 Conveyor No. 4 Belt w/tripper 4 26 tonne/hr (4 7 0 tph) 435 tonne/hr (480 tph) 4 72 tonne/hr (5 2 0 tph) 1 (0) 16 Transfer Tower No. 2 Enclosed N/A N/A N/A 1 (0) 17 Conveyor No. 5 Belt w/tripper 4 26 tonne/hr (4 7 0 tph) 435 tonne/hr (480 tph) 4 72 tonne/hr (5 2 0 tph) 1 (0)

18 Coal Silo w/ Vent Filter and Slide Gates Field Erected 907 tonne (1,000 ton) 998 tonne (1,100 ton) 998 tonne (1,100 ton) 3 (0 )

19 Limestone Truck Unloading Hopper N/A 36 tonne (40 ton) 36 tonne (40 ton) 36 tonne (40 ton) 1 (0)

20 Limestone Feeder Belt 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 118 tonne/hr (130 tph) 1 (0) 21 Limestone Conveyor No. L1 Belt 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 118 tonne/hr (130 tph) 1 (0) 22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 18 tonne (20 ton) 27 tonne (30 ton) 1 (0) 23 Limestone Reclaim Feeder Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 1 (0) 24 Limestone Conveyor No. L2 Belt 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 91 tonne/hr (100 tph) 1 (0) 25 Limestone Day Bin w/ actuator 345 tonne (380 ton) 354 tonne (390 ton) 3 81 tonne (4 2 0 ton) 2 (0)



## 145Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G 1 Coal Feeder Gravimetric 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 54 tonne/hr (60 tph) 6 (0) 2 Coal Pulverizer Ball type or eq. 45 tonne/hr (50 tph) 45 tonne/hr (50 tph) 54 tonne/hr (60 tph) 6 (0) 3 Limestone Weigh Feeder Gravimetric 2 9 tonne/hr (3 2 tph) 30 tonne/hr (3 3 tph) 3 2 tonne/hr (3 5 tph) 1 (1) 4 Limestone Ball Mill Rotary 2 9 tonne/hr (3 2 tph) 30 tonne/hr (3 3 tph) 3 2 tonne/hr (3 5 tph) 1 (1)

5 Limestone Mill Slurry Tank with Agitator N/A 109,777 liters (29,000 gal) 113,562 liters (30,000 gal) 121,133 liters (32,000 gal) 1 (1)

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1,855 lpm @ 12m H 2 

### O (490 gpm @ 40 ft H 2 

### O) 1,893 lpm @ 12m H 2 

### O (500 gpm @ 40 ft H 2 

### O) 2,006 lpm @ 12m H 2 

### O (530 gpm @ 40 ft H 2 

### O) 1 (1)

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 454 lpm (120 gpm) per cyclone 492 lpm (130 gpm) per cyclone 492 lpm (130 gpm) per cyclone 1 (1)

8 Distribution Box 2

- way N/A N/A N/A 1 (1)

9 Limestone Slurry Storage Tank with Agitator Field erected 620,808 liters ( 16 4 ,000 gal) 639,735 liters (16 9 ,000 gal) 681,374 liters (1 80 ,000 gal) 1 (1)

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1,287 lpm @ 9m H 2 

### O (340 gpm @ 30 ft H 2 

### O) 1,325 lpm @ 9m H 2 

### O (350 gpm @ 30 ft H 2 

### O) 1,401 lpm @ 9m H 2 

### O (370 gpm @ 30 ft H 2 

### O) 1 (1)



## ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G
1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,499,023 liters (396,000 gal) 1,540,663 liters (407,000 gal) 1,646,654 liters (435,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 17,034 lpm @ 213 m H 2 

### O (4,500 gpm @ 700 ft H 2 

### O) 16,277 lpm @ 213 m H 2 

### O (4,300 gpm @ 700 ft H 2 

### O) 13,627 lpm @ 213 m H 2 

### O (3,600 gpm @ 700 ft H 2 

### O) 1 (1)

3 Deaerator and Storage Tank Horizontal spray type 2,497,480 kg/hr (5,506,000 lb/hr), 5 min. tank 2,562,797 kg/hr (5,650,000 lb/hr), 5 min. tank 2,741,966 kg/hr (6,045,000 lb/hr), 5 min. tank 1 (0)

4 Boiler Feed Pump/Turbine Barrel type, multi

- stage, centrifugal 42,018 lpm @ 3,505 m H 2 

### O (11,100 gpm @ 11,500 ft H 2 

### O) 43,154 lpm @ 3,505 m H 2 

### O (11,400 gpm @ 11,500 ft H 2 

### O) 46,182 lpm @ 3,505 m H 2 

### O (12,200 gpm @ 11,500 ft H 2 

### O) 1 (1)

5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multi

- stage, centrifugal 12,492 lpm @ 3,505 m H 2 

### O (3,300 gpm @ 11,500 ft H 2 

### O) 12,870 lpm @ 3,505 m H 2 

### O (3,400 gpm @ 11,500 ft H 2 

### O) 13,627 lpm @ 3,505 m H 2 

### O (3,600 gpm @ 11,500 ft H 2 

### O) 1 (0)

6 LP Feedwater Heater 1A/1B Horizontal U

- tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

7 LP Feedwater Heater 2A/2B Horizontal U

- tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

8 LP Feedwater Heater 3A/3B Horizontal U

- tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

9 LP Feedwater Heater 4A/4B Horizontal U

- tube 503,488 kg/hr (1,110,000 lb/hr) 480,808 kg/hr (1,060,000 lb/hr) 408,233 kg/hr (900,000 lb/hr) 2 (0)

10 HP Feedwater Heater 6 Horizontal U

- tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)

11 HP Feedwater Heater 7 Horizontal U

- tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)
12 HP Feedwater heater 8 Horizontal U

- tube 2,499,294 kg/hr (5,510,000 lb/hr) 2,562,797 kg/hr (5,650,000 lb/hr) 2,744,234 kg/hr (6,050,000 lb/hr) 1 (0)
13 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)



## 146Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G 14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1,135,624 liter (300,000 gal) 1 (0)
15 Service Air Compressors Flooded Screw 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 (1)
16 Instrument Air Dryers Duplex, regenerative 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 2 (1)
17 Closed Cylce Cooling Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50 MMBtu/hr) each 2 (0)

18 Closed Cycle Cooling Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H 2 

### O (5,500 gpm @ 100 ft H 2 

### O) 20,820 lpm @ 30 m H 2 

### O (5,500 gpm @ 100 ft H 2 

### O) 20,820 lpm @ 30 m H 2 

### O (5,500 gpm @ 100 ft H 2 

### O) 2 (1)

19 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 88 m H 2 

### O (1,000 gpm @ 290 ft H 2 

### O) 3,785 lpm @ 88 m H 2 

### O (1,000 gpm @ 290 ft H 2 

### O) 3,785 lpm @ 88 m H 2 

### O (1,000 gpm @ 290 ft H 2 

### O) 1 (1)

20 Fire Service Booster Pump Two

- s tage horizontal centrifugal 2,650 lpm @ 64 m H 2 

### O (700 gpm @ 210 ft H 2 

### O) 2,650 lpm @ 64 m H 2 

### O (700 gpm @ 210 ft H 2 

### O) 2,650 lpm @ 64 m H 2 

### O (700 gpm @ 210 ft H 2 

### O) 1 (1)

21 Raw Water Pumps Stainless steel, single suction 20,101 lpm @ 43 m H 2 

### O (5,310 gpm @ 140 ft H 2 

### O) 20,933 lpm @ 43 m H 2 

### O (5,530 gpm @ 140 ft H 2 

### O) 23,280 lpm @ 43 m H 2 

### O (6,150 gpm @ 140 ft H 2 

### O) 2 (1)

22 Filtered Water Pumps Stainless steel, single suction 757 lpm @ 49 m H 2 

### O (200 gpm @ 160 ft H 2 

### O) 795 lpm @ 49 m H 2 

### O (210 gpm @ 160 ft H 2 

### O) 871 lpm @ 49 m H 2 

### O (230 gpm @ 160 ft H 2 

### O) 2 (1)
23 Filtered Water Tank Vertical, cyl indrical 738,155 liter (195,000 gal) 760,868 liter (201,000 gal) 817,649 liter (216,000 gal) 1 (0)

24 Makeup Water Demineralizer Multi

- media filter, cartridge filter, RO membrane assembly, electrodeionization unit 984 lpm (260 gpm) 1,022 lpm (270 gpm) 1,098 lpm (290 gpm) 1 (1)

25 Liquid Waste Treatment System -- 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



## ACCOUNT 4 BOILER AND ACCESSORIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Boiler Supercritical, drum, wall

- fired, low NOx burners, overfire air 2,499,294 kg/hr steam @ 25.5 MPa/602°C/602°C (5,510,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,562,797 kg/hr steam @ 25.5 MPa/602°C/602°C (5,650,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 2,744,234 kg/hr steam @ 25.5 MPa/602°C/602°C (6,050,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1 (0)

2 Primary Air Fan Centrifugal 327,494 kg/hr, 4,468 m 3 

### /min @ 123 cm WG (722,000 lb/hr, 157,800 acfm @ 48 in. WG) 336,112 kg/hr, 4,584 m 3 

### /min @ 123 cm WG (741,000 lb/hr, 161,900 acfm @ 48 in. WG) 359,699 kg/hr, 4,907 m 3 

### /min @ 123 cm WG (793,000 lb/hr, 173,300 acfm @ 48 in. WG) 2 (0)

3 Forced Draft Fan Centrifugal 1,066,396 kg/hr, 14,546 m 3 

### /min @ 51 cm WG (2,351,000 lb/hr, 513,700 acfm @ 20 in. WG) 1,094,065 kg/hr, 14,929 m 3 

### /min @ 51 cm WG (2,412,000 lb/hr, 527,200 acfm @ 20 in. WG) 1,171,175 kg/hr, 15,974 m 3 

### /min @ 51 cm WG (2,582,000 lb/hr, 564,100 acfm @ 20 in. WG) 2 (0)

4 Induced Draft Fan Centrifugal 1,550,379 kg/hr, 33,176 m 3 

### /min @ 91 cm WG (3,418,000 lb/hr, 1,171,600 acfm @ 36 in. WG) 1,590,748 kg/hr, 34,045 m 3 

### /min @ 91 cm WG (3,507,000 lb/hr, 1,202,300 acfm @ 36 in. WG) 1,702,332 kg/hr, 36,430 m 3 

### /min @ 91 cm WG (3,753,000 lb/hr, 1,286,500 acfm @ 36 in. WG) 2 (0)

5 SCR Reactor Vessel Space for spare layer 3,102,572 kg/hr (6,840,000 lb/hr) 3,179,683 kg/hr (7,010,000 lb/hr) 3,406,479 kg/hr (7,510,000 lb/hr) 2 (0) 6 SCR Catalyst

-- -- -- -- 3 (0)

7 Dilution Air Blower Centrifugal 57 m 3 

### /min @ 108 cm WG (2,000 acfm @ 42 in. WG) 57 m 3 

### /min @ 108 cm WG (2,000 acfm @ 42 in. WG) 62 m 3 

### /min @ 108 cm WG (2,200 acfm @ 42 in. WG) 2 (1)
8 Ammonia Storage Horizontal tank 60,567 liter (16,000 gal) 64,352 liter (17,000 gal) 68,137 liter (18,000 gal) 5 (0)
9 Ammonia Feed Pump Centrifugal 12 lpm @ 91 m H 2 

### O (3 gpm @ 300 ft H 2 

### O) 12 lpm @ 91 m H 2 

### O (3 gpm @ 300 ft H 2 

### O) 13 lpm @ 91 m H 2 

### O (3 gpm @ 300 ft H 2 

### O) 2 (1)



## 147Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 5 FLUE GAS CLEANUP
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G
1 Fabric Filter Single stage, high

- ratio with pulse

- jet online cleaning system 1,550,379 kg/hr (3,418,000 lb/hr) 99.8% efficiency 1,590,748 kg/hr (3,507,000 lb/hr) 99.8% efficiency 1,702,332 kg/hr (3,753,000 lb/hr) 99.8% efficiency 2 (0)

2 Absorber Module Counter

- current open spray 51,169 m 3 

### /min (1,807,000 acfm) 52,499 m 3 

### /min (1,854,000 acfm) 56,181 m 3 

### /min (1,984,000 acfm) 1 (0)

3 Recirculation Pumps Horizontal centrifugal 177,914 lpm @ 64 m H 2 

### O (47,000 gpm @ 210 ft H 2 

### O) 181,700 lpm @ 64 m H 2 

### O (48,000 gpm @ 210 ft H 2 

### O) 196,841 lpm @ 64 m H 2 

### O (52,000 gpm @ 210 ft H 2 

### O) 5 (1)

4 Bleed Pumps Horizontal centrifugal 5,602 lpm (1,480 gpm) at 20 wt% solids 5,754 lpm (1,520 gpm) at 20 wt% solids 6,170 lpm (1,630 gpm) at 20 wt% solids 2 (1)

5 Oxidation Air Blowers Centrifugal 229 m 3 

### /min @ 0.3 MPa (8,100 acfm @ 42 psia) 235 m 3 

### /min @ 0.3 MPa (8,310 acfm @ 42 psia) 251 m 3 

### /min @ 0.3 MPa (8,870 acfm @ 42 psia) 2 (1)
6 Agitators Side entering 50 hp 50 hp 50 hp 5 (1)

7 Dewatering Cyclones Radial assembly, 5 units each 1,401 lpm (370 gpm) per cyclone 1,438 lpm (380 gpm) per cyclone 1,552 lpm (410 gpm) per cyclone 2 (0)

8 Vacuum Filter Belt Horizontal belt 44 tonne/hr (49 tph) of 50 wt % slurry 45 tonne/hr (50 tph) of 50 wt % slurry 49 tonne/hr (54 tph) of 50 wt % slurry 2 (1)

9 Filtrate Water Return Pumps Horizontal centrifugal 871 lpm @ 12 m H 2 

### O (230 gpm @ 40 ft H 2 

### O) 871 lpm @ 12 m H 2 

### O (230 gpm @ 40 ft H 2 

### O) 946 lpm @ 12 m H 2 

### O (250 gpm @ 40 ft H 2 

### O) 1 (1)

10 Filtrate Water Return Storage Tank Vertical, lined 567,812 lpm (150,000 gal) 567,812 lpm (150,000 gal) 605,666 lpm (160,000 gal) 1 (1)

11 Process Makeup Water Pumps Horizontal centrifugal 568 lpm @ 21 m H 2 

### O (150 gpm @ 70 ft H 2 

### O) 568 lpm @ 21 m H 2 

### O (150 gpm @ 70 ft H 2 

### O) 606 lpm @ 21 m H 2 

### O (160 gpm @ 70 ft H 2 

### O) 1 (1)



## ACCOUNT 5B CARBON DIOXIDE RECOVERY

Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Econamine FG Plus Amine

- based CO 2 

### capture technology 1,640,190 kg/h (3,616,000 lb/h) 20.6 wt % CO 2 

### concentration 1,683,281 kg/h (3,711,000 lb/h) 20.6 wt % CO 2 

### concentration 1,801,215 kg/h (3,971,000 lb/h) 20.6 wt % CO 2 

### concentration 2 (0)

2 Econamine Condensate Pump Centrifugal 14,650 lpm @ 52 m H 2 

### O (3,870 gpm @ 170 ft H 2 

### O) 16,202 lpm @ 52 m H 2 

### O (4,280 gpm @ 170 ft H 2 

### O) 21,236 lpm @ 52 m H 2 

### O (5,610 gpm @ 170 ft H 2 

### O) 1 (1)

3 CO 2 

### Compressor Centrifugal 303,707 kg/h @ 15.3 MPa (669,559 lb/h @ 2,215 psia) 328,968 kg/h @ 15.3 MPa (725,250 lb/h @ 2,215 psia) 366,853 kg/h @ 15.3 MPa (808,773 lb/h @ 2,215 psia) 2 (0)



## ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES N/A

ACCOUNT 7 DUCTING AND STACK

Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G



## 148Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x 5.6 m ( 18 ft) diameter 152 m (500 ft) high x 5.6 m ( 18 ft) diameter 152 m (500 ft) high x 5.8 m ( 19 ft) diameter 

## 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 Steam Turbine Generator Commercially available, advanced steam turbine 696 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 703 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 715 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 

## 1 (0)

2 Steam Turbine Generat or Hydrogen cooled, static excitation 770 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 780 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 790 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 

## 1 (0)

3 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,910 GJ/hr (1,810 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,836 GJ/hr (1,740 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,540 GJ/hr (1,460 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 

## 1 (0)



## ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G
1 Circulating Water Pumps Vertical, wet pit 1,014,500 lpm @ 30 m (268,000 gpm @ 100 ft) 1,056,100 lpm @ 30 m (279,000 gpm @ 100 ft) 1,173,500 lpm @ 30 m (310,000 gpm @ 100 ft) 2 ( 1 )

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 5666 GJ/hr (5370 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 5898 GJ/hr (5590 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 6531 GJ/hr (6190 MMBtu/hr) heat duty 1 ( 0 )



## ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G
1 Economizer Hopper (part of boiler scope of supply) -- -- -- -- 4 (0)

2 Bottom Ash Hopper (part of boiler scope of supply) -- -- -- -- 2 (0)
3 Clinker Grinder

-- 5.4 tonne/hr (6 tph) 5.4 tonne/hr (6 tph) 6.4 tonne/hr (7 tph) 1 (1)

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- -- -- -- 6 (0)

5 Hydroejectors

-- -- -- -- 12 (0) 6 Economizer /Pyrites Transfer Tank

-- -- -- -- 1 (0)

7 Ash Sluice Pumps Vertical, wet pit 227 lpm @ 17 m H 2 

### O (60 gpm @ 56 ft H 2 

### O) 227 lpm @ 17 m H 2 

### O (60 gpm @ 56 ft H 2 

### O) 227 lpm @ 17 m H 2 

### O (60 gpm @ 56 ft H 2 

### O) 1 (1)

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H 2 

### O (2000 gpm @ 28 ft H 2 

### O) 7,571 lpm @ 9 m H 2 

### O (2000 gpm @ 28 ft H 2 

### O) 7,571 lpm @ 9 m H 2 

### O (2000 gpm @ 28 ft H 2 

### O) 1 (1)
9 Hydrobins

-- 227 lpm (60 gpm) 227 lpm (60 gpm) 227 lpm (60 gpm) 1 (1)
10 Baghouse Hopper (part of baghouse scope of supply) -- -- -- -- 24 (0)



## 149Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G
11 Air Heater Hopper (part of boiler scope of supply) -- -- -- -- 10 (0)

12 Air Blower

-- 20 m 3 

### /min @ 0.2 MPa (7 1 0 scfm @ 24 psi) 2 1 m 3 

### /min @ 0.2 MPa (7 3 0 scfm @ 24 psi) 22 m 3 

### /min @ 0.2 MPa (7 8 0 scfm @ 24 psi) 1 (1)

13 Fly Ash Silo Reinforced concrete 6 80 tonne (1, 5 00 ton) 680 tonne (1,500 ton) 726 tonne (1,600 ton) 2 (0)

14 Slide Gate Valves

-- -- -- -- 2 (0) 15 Unloader

-- -- -- -- 1 (0) 16 Telescoping Unloading Chute

-- 1 27 tonne/hr (1 4 0 tph) 127 tonne/hr (140 tph) 136 tonne/hr (150 tph) 1 (0)



## ACCOUNT 11 ACCESSORY ELECTRIC PLANT
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G
1 STG Transformer Oil

- filled 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 1 (0)

2 Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 1 21 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 12 8 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 1 41 MVA, 3

- ph, 60 Hz 1 (1)

3 L ow Voltage Transformer Dry ventilated 4.16 kV/480 V, 18 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 19 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 21 MVA, 3

- ph, 60 Hz 1 (1)

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

5 Medium Voltage Switchgear Metal Clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1) 6 Low Voltage Switchgear Metal Enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

7 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



## ACCOUNT 12 INSTRUMENTATION AND CONTROL
Equipment No. Description Type Design Condition Opr Qty. (Spares) Case 1E Case 1F Case 1G

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator Stations/Printers and Engineering Stations/Printers Operator Stations/Printers and Engineering Stations/Printers Operator Stations/Printers and Engineering Stations/Printers 1 (0)

2 DCS

– Processor Microprocessor with redundant input/output N/A N/A N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)



## 150Carbon Dioxide Capture Sensitivity Analysis



# 3.2.3 Economic Analysis for the Supercritical PC Cases
The capital and operating costs for Cases 1 A through 1G are presented in Section 3.2.4 . A cost and performance summary table ( Exhibit 3

- 72 ) for the SC PC cases is shown in Section 3.2.5

. Due to the range of CO 2 

## capture levels analyzed in Case 1, the Econamine capital and operating costs vary for the seven cases. While a factored approach that relies on the quantity of CO 2 

## captured for equipment sizing and cost estimation was employed, the cost estimates for the Econamine system were also developed based, in part, on output data from the ProTreatTM simulations. In particular, the ProTreatTM model output provided absorption and stripping column diameters for each case, which were used to determine the required numb er of absorption trains. For this analysis, it was assumed that the maximum absorption column diameter is 20 meters, based on information released by Fluor [ 4 ]. As a result, cost estimates for three CO 2 

## capture levels

– 30 percent (1A), 50 percent (1B), and 70 percent (1C)

– are based on a single absorption and compression train. To calculate the capital cost for a single absorption train, it was assumed that the absorption columns represent 40 percent of the total capital cost for a two

- train Econamine system.



# 3.2.4 Capital and Operating Cost Results The capital and operating costs for Cases 1 A through 1G are shown in Exhibit 3

- 58 through Exhibit 3

- 71

. The capital costs for each case include the TPC, the owner’s costs, TOC, and the total as

- spent capital TASC cost. The c apital and operating cost estimating methodology is explained in Sec tion 2.7

.

151Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 58 Case 1A (30%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture x $1, 000 Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload 3,509 0 1,603 0 5,112 8.9% 456 0% 0 15.0% 835 6,404 12 1.2 Coal Stackout & Reclaim 4,535 0 1,028 0 5,563 8.8% 487 0% 0 15.0% 907 6,957 13 1.3 Coal Conveyors & Yd Crus 4,217 0 1,017 0 5,233 8.8% 459 0% 0 15.0% 854 6,546 12 1.4 Other Coal Handling 1,103 0 235 0 1,338 8.7% 117 0% 0 15.0% 218 1,674 3 1.5 Sorbent Receive & Unload 144 0 43 0 188 8.8% 17 0% 0 15.0% 31 235 0 1.6 Sorbent Stackout & Reclaim 2,328 0 427 0 2,755 8.7% 240 0% 0 15.0% 449 3,444 6 1.7 Sorbent Conveyors 831 180 204 0 1,214 8.7% 105 0% 0 15.0% 198 1,517 3 1.8 Other Sorbent Handling 502 118 263 0 883 8.8% 78 0% 0 15.0% 144 1,105 2 1.9 Coal & Sorbent Hnd.Foundations 0 4,315 5,444 0 9,759 9.3% 912 0% 0 15.0% 1,601 12,272 22 SUBTOTAL 1. $17,169 $4,613 $10,263 $0 $32,045 $2,871 $0 $5,237 $40,154 $73 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying 2,015 0 393 0 2,408 8.7% 210 0% 0 15.0% 393 3,011 5 2.2 Prepared Coal Storage & Feed 5,160 0 1,126 0 6,286 8.7% 550 0% 0 15.0% 1,025 7,861 14 2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.5 Sorbent Prep Equipment 3,958 171 822 0 4,951 8.7% 431 0% 0 15.0% 807 6,190 11 2.6 Sorbent Storage & Feed 477 0 183 0 660 8.9% 59 0% 0 15.0% 108 826 2 2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.9 Coal & Sorbent Feed Foundation 0 507 425 0 932 9.2% 86 0% 0 15.0% 153 1,171 2 SUBTOTAL 2. $11,611 $678 $2,949 $0 $15,238 $1,336 $0 $2,486 $19,059 $35 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 18,673 0 6,032 0 24,704 8.8% 2,163 0% 0 15.0% 4,030 30,897 56 3.2 Water Makeup & Pretreating 4,471 0 1,439 0 5,910 9.4% 554 0% 0 20.0% 1,293 7,757 14 3.3 Other Feedwater Subsystems 5,717 0 2,416 0 8,132 8.9% 725 0% 0 15.0% 1,329 10,186 19 3.4 Service Water Systems 876 0 477 0 1,353 9.3% 126 0% 0 20.0% 296 1,775 3 3.5 Other Boiler Plant Systems 7,108 0 7,017 0 14,125 9.4% 1,325 0% 0 15.0% 2,318 17,768 32 3.6 FO Supply Sys & Nat Gas 259 0 324 0 583 9.3% 54 0% 0 15.0% 96 733 1 3.7 Waste Treatment Equipment 4,415 0 2,517 0 6,932 9.7% 671 0% 0 20.0% 1,521 9,124 17 3.8 Misc. Power Plant Equipment 2,750 0 840 0 3,590 9.6% 345 0% 0 20.0% 787 4,722 9 SUBTOTAL 3. $44,268 $0 $21,062 $0 $65,330 $5,963 $0 $11,668 $82,961 $151 4 PC BOILER & ACCESSORIES 4.1 PC Boiler 159,566 0 89,533 0 249,099 9.7% 24,128 0.0% 0 10.0% 27,323 300,549 546 4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 4. $159,566 $0 $89,533 $0 $249,099 $24,128 $0 $27,323 $300,549 $546 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 152Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 58 Case 1A (30%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture x $1, 000 Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 5A FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories 68,203 0 14,683 0 82,886 9.5% 7,845 0% 0 10.0% 9,073 99,804 181 5.2 Other FGD 3,562 0 4,036 0 7,598 9.6% 732 0% 0 10.0% 833 9,163 17 5.3 Bag House & Accessories 17,113 0 10,860 0 27,973 9.6% 2,676 0% 0 10.0% 3,065 33,714 61 5.4 Other Particulate Removal Materials 1,121 0 1,199 0 2,320 9.6% 223 0% 0 10.0% 254 2,798 5 5.5 Gypsum Dewatering System 4,680 0 795 0 5,475 9.4% 517 0% 0 10.0% 599 6,592 12 5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 5A. $94,679 $0 $31,573 $0 $126,252 $11,993 $0 $13,825 $152,070 $276 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System 85,601 0 25,921 0 111,521 9.5% 10,584 20% 22,304 20.0% 28,882 173,291 315 5B.2 CO2 Compression & Drying 9,770 0 3,051 0 12,821 9.5% 1,217 0% 0 20.0% 2,808 16,846 31 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $95,371 $0 $28,972 $0 $124,343 $11,801 $22,304 $31,690 $190,138 $346 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 7.3 Ductwork 8,711 0 5,597 0 14,308 8.7% 1,250 0% 0 15.0% 2,334 17,892 33 7.4 Stack 8,616 0 5,041 0 13,657 9.6% 1,305 0% 0 10.0% 1,496 16,458 30 7.9 HRSG, Duct & Stack Foundations 0 989 1,124 0 2,113 9.3% 197 0% 0 20.0% 462 2,771 5 SUBTOTAL 7. $17,327 $989 $11,762 $0 $30,078 $2,752 $0 $4,292 $37,121 $67 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories 51,572 0 6,843 0 58,415 9.6% 5,593 0% 0 10.0% 6,401 70,409 128 8.2 Turbine Plant Auxiliaries 347 0 744 0 1,091 9.7% 106 0% 0 10.0% 120 1,317 2 8.3 Condenser & Auxiliaries 5,594 0 2,084 0 7,678 9.5% 730 0% 0 10.0% 841 9,248 17 8.4 Steam Piping 16,109 0 7,943 0 24,052 8.3% 2,007 0% 0 15.0% 3,909 29,968 54 8.9 TG Foundations 0 1,093 1,726 0 2,819 9.4% 265 0% 0 20.0% 617 3,701 7 SUBTOTAL 8. $73,622 $1,093 $19,340 $0 $94,055 $8,701 $0 $11,887 $114,643 $208 9 COOLING WATER SYSTEM 9.1 Cooling Towers 9,453 0 2,944 0 12,396 9.5% 1,177 0% 0 10.0% 1,357 14,931 27 9.2 Circulating Water Pumps 1,555 0 119 0 1,674 8.6% 143 0% 0 10.0% 182 1,999 4 9.3 Circ. Water System Auxiliaries 454 0 61 0 515 9.4% 49 0% 0 10.0% 56 619 1 9.4 Circ. Water Piping 0 3,599 3,488 0 7,088 9.2% 653 0% 0 15.0% 1,161 8,902 16 9.5 Make-up Water System 439 0 587 0 1,026 9.5% 97 0% 0 15.0% 168 1,291 2 9.6 Component Cooling Water System 360 0 286 0 646 9.4% 61 0% 0 15.0% 106 812 1 9.9 Circ. Water System Foundations 0 2,226 3,537 0 5,763 9.4% 542 0% 0 20.0% 1,261 7,567 14 SUBTOTAL 9. $12,261 $5,826 $11,022 $0 $29,108 $2,722 $0 $4,292 $36,122 $66 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 153Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 58 Case 1A (30%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture x $1, 000 Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.6 Ash Storage Silos 611 0 1,882 0 2,492 9.7% 243 0% 0 10.0% 273 3,008 5 10.7 Ash Transport & Feed Equipment 3,953 0 4,049 0 8,002 9.5% 757 0% 0 10.0% 876 9,635 18 10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 10.9 Ash/Spent Sorbent Foundation 0 145 171 0 316 9.3% 29 0% 0 20.0% 69 415 1 SUBTOTAL 10. $4,564 $145 $6,102 $0 $10,811 $1,029 $0 $1,219 $13,058 $24 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment 1,601 0 260 0 1,861 9.3% 172 0% 0 7.5% 152 2,186 4 11.2 Station Service Equipment 3,457 0 1,136 0 4,594 9.6% 439 0% 0 7.5% 377 5,410 10 11.3 Switchgear & Motor Control 3,975 0 676 0 4,651 9.3% 431 0% 0 10.0% 508 5,589 10 11.4 Conduit & Cable Tray 0 2,492 8,617 0 11,109 9.6% 1,063 0% 0 15.0% 1,826 13,998 25 11.5 Wire & Cable 0 4,702 9,078 0 13,780 8.4% 1,161 0% 0 15.0% 2,241 17,183 31 11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3 11.7 Standby Equipment 1,278 0 29 0 1,307 9.5% 124 0% 0 10.0% 143 1,574 3 11.8 Main Power Transformers 7,303 0 123 0 7,426 7.6% 564 0% 0 10.0% 799 8,789 16 11.9 Electrical Foundations 0 311 762 0 1,073 9.5% 102 0% 0 20.0% 235 1,410 3 SUBTOTAL 11. $17,875 $7,506 $21,566 $0 $46,947 $4,168 $0 $6,408 $57,523 $105 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 12.3 Steam Turbine Control w/8.1 0 w/8.1 0 0 0% 0 0% 0 0.0% 0 0 0 12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.6 Control Boards, Panels & Racks 464 0 278 0 743 9.6% 71 0% 0 15.0% 122 936 2 12.7 Computer Accessories 4,689 0 819 0 5,508 9.5% 525 0% 0 10.0% 603 6,636 12 12.8 Instrument Wiring & Tubing 2,541 0 5,041 0 7,582 8.5% 646 0% 0 15.0% 1,234 9,462 17 12.9 Other I & C Equipment 1,325 0 3,007 0 4,332 9.7% 422 0% 0 10.0% 475 5,229 10 SUBTOTAL 12. $9,019 $0 $9,145 $0 $18,165 $1,664 $0 $2,435 $22,263 $40 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 52 1,047 0 1,099 9.9% 108 0% 0 20.0% 241 1,449 3 13.2 Site Improvements 0 1,737 2,158 0 3,895 9.8% 382 0% 0 20.0% 855 5,133 9 13.3 Site Facilities 3,113 0 3,070 0 6,184 9.8% 607 0% 0 20.0% 1,358 8,149 15 SUBTOTAL 13. $3,113 $1,790 $6,274 $0 $11,177 $1,098 $0 $2,455 $14,730 $27 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 154Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 58 Case 1A (30%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture x $1, 000 Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Boiler Building 0 8,705 7,655 0 16,360 9.0% 1,469 0% 0 15.0% 2,674 20,504 37 14.2 Turbine Building 0 12,476 11,627 0 24,103 9.0% 2,170 0% 0 15.0% 3,941 30,214 55 14.3 Administration Building 0 623 659 0 1,281 9.1% 116 0% 0 15.0% 210 1,607 3 14.4 Circulation Water Pumphouse 0 106 84 0 191 8.9% 17 0% 0 15.0% 31 239 0 14.5 Water Treatment Buildings 0 585 533 0 1,118 9.0% 100 0% 0 15.0% 183 1,401 3 14.6 Machine Shop 0 417 280 0 696 8.9% 62 0% 0 15.0% 114 872 2 14.7 Warehouse 0 282 283 0 565 9.0% 51 0% 0 15.0% 92 709 1 14.8 Other Buildings & Structures 0 231 196 0 427 9.0% 38 0% 0 15.0% 70 535 1 14.9 Waste Treating Building & Str. 0 437 1,325 0 1,761 9.4% 166 0% 0 15.0% 289 2,217 4 SUBTOTAL 14. $0 $23,861 $22,643 $0 $46,504 $4,190 $0 $7,604 $58,298 $106 Total Cost $560,444 $46,499 $292,207 $0 $899,149 $84,415 $22,304 $132,820 $1,138,688 $2,070
Owner's Costs Preproduction Costs 6 Months All Labor $8,797 $16 1 Month Maintenance Materials $1,124 $2 1 Month Non-fuel Consumables $853 $2 1 Month Waste Disposal $263 $0 25% of 1 Months Fuel Cost at 100% CF $1,593 $3 2% of TPC $22,774 $41
Total $35,403 $64 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,447 $26 0.5% of TPC (spare parts) $5,693 $10
Total $20,140 $37

Initial Cost for Catalyst and Chemicals $658 $1 Land $900 $2 Other Owner's Costs $170,803 $311

Financing Costs $30,745 $56 Total Overnight Costs (TOC) $1,397,338 $2,540.7 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,592,965 $2,896 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 155Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 59 Case 1A Initial and Annual O&M Expenses

Case: Case 1A - Supercritical PC w/ 30% CO2 Capture Plant Size (MWe): 549.99 Heat Rate (Btu/kWh): 9,695 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 85 CO 2 Captured (TPD): 3881

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's etc. 2.0 2.0 TOTAL Operating Jobs 16.3 16.3
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,431,885 $11.695 Maintenance Labor Cost (calc'd) $7,644,005 $13.898 Administrative & Support Labor (calc'd) $3,518,973 $6.398 Property Taxes & Insurance $22,773,764 $41.408 TOTAL FIXED OPERATING COSTS $40,368,627 $73.399 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $11,466,008 0.00280

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 4,707 1.08 $0 $1,577,096 0.00039 Chemicals MU & WT Chem. (lb) 0 22,784 0.17 $0 $1,201,673 0.00029 Limestone (ton) 0 555 21.63 $0 $3,724,204 0.00091 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000 MEA Solvent (ton) 271 0.39 2249.89 $609,715 $272,030 0.00007 Caustic Soda, NaOH (ton) 19 1.91 433.68 $8,305 $257,649 0.00006 Sulfuric acid, H 2 SO 4 (ton) 18 1.83 138.78 $2,536 $78,675 0.00002 Corrosion Inhibitor 0 0 0.00 $37,484 $1,810 0.00000 Activated C, MEA (lb) 0 459 1.05 $0 $149,561 0.00004 Ammonia, 28% soln (ton) 0 17 129.80 $0 $677,925 0.00017 Subtotal Chemicals $658,040 $6,363,527 0.00155 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 SCR Catalyst Replacement ( w/equip. 0.42 5,775.94 $0 $759,439 0.00019 Emission Penalties 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $759,439 0.00019 Waste Disposal Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000 Flyash (ton) 0 425 16.23 $0 $2,142,442 0.00052 Bottom Ash (ton) 0 106 16.23 $0 $535,611 0.00013 Subtotal Solid Waste Disposal $0 $2,678,053 0.00065 By-products & Emissions Gypsum (tons) 0 0 0.00 $0 $0 0.00000 Sulfur (tons) 0 0 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $22,844,123 0.00558 Coal FUEL (tons) 164,544 5,485 38.19 $6,283,126 $64,977,999 0.01587 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 156Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 60 Case 1B (50%) Capital Costs
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture x $1, 000 Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload 3,661 0 1,672 0 5,333 8.9% 476 0% 0 15.0% 871 6,680 12 1.2 Coal Stackout & Reclaim 4,731 0 1,072 0 5,803 8.8% 508 0% 0 15.0% 947 7,258 13 1.3 Coal Conveyors & Yd Crus 4,399 0 1,061 0 5,459 8.8% 479 0% 0 15.0% 891 6,829 12 1.4 Other Coal Handling 1,151 0 245 0 1,396 8.7% 122 0% 0 15.0% 228 1,746 3 1.5 Sorbent Receive & Unload 151 0 45 0 196 8.8% 17 0% 0 15.0% 32 245 0 1.6 Sorbent Stackout & Reclaim 2,432 0 446 0 2,878 8.7% 251 0% 0 15.0% 469 3,598 7 1.7 Sorbent Conveyors 868 188 213 0 1,268 8.7% 110 0% 0 15.0% 207 1,585 3 1.8 Other Sorbent Handling 524 123 275 0 922 8.8% 82 0% 0 15.0% 151 1,154 2 1.9 Coal & Sorbent Hnd.Foundations 0 4,502 5,679 0 10,180 9.3% 952 0% 0 15.0% 1,670 12,802 23 SUBTOTAL 1. $17,916 $4,812 $10,708 $0 $33,436 $2,996 $0 $5,465 $41,896 $76 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying 2,108 0 411 0 2,519 8.7% 220 0% 0 15.0% 411 3,149 6 2.2 Prepared Coal Storage & Feed 5,397 0 1,178 0 6,576 8.7% 575 0% 0 15.0% 1,073 8,223 15 2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.5 Sorbent Prep Equipment 4,138 178 859 0 5,175 8.7% 451 0% 0 15.0% 844 6,470 12 2.6 Sorbent Storage & Feed 499 0 191 0 689 8.9% 61 0% 0 15.0% 113 863 2 2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.9 Coal & Sorbent Feed Foundation 0 529 444 0 974 9.2% 90 0% 0 15.0% 160 1,223 2 SUBTOTAL 2. $12,142 $708 $3,084 $0 $15,933 $1,397 $0 $2,599 $19,929 $36 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 19,570 0 6,321 0 25,891 8.8% 2,267 0% 0 15.0% 4,224 32,382 59 3.2 Water Makeup & Pretreating 4,930 0 1,587 0 6,516 9.4% 611 0% 0 20.0% 1,425 8,553 16 3.3 Other Feedwater Subsystems 5,991 0 2,532 0 8,523 8.9% 760 0% 0 15.0% 1,392 10,675 19 3.4 Service Water Systems 966 0 526 0 1,492 9.3% 138 0% 0 20.0% 326 1,957 4 3.5 Other Boiler Plant Systems 7,480 0 7,385 0 14,864 9.4% 1,394 0% 0 15.0% 2,439 18,697 34 3.6 FO Supply Sys & Nat Gas 264 0 329 0 593 9.3% 55 0% 0 15.0% 97 745 1 3.7 Waste Treatment Equipment 4,493 0 2,561 0 7,055 9.7% 683 0% 0 20.0% 1,548 9,286 17 3.8 Misc. Power Plant Equipment 2,798 0 855 0 3,652 9.6% 351 0% 0 20.0% 801 4,803 9 SUBTOTAL 3. $46,491 $0 $22,096 $0 $68,586 $6,259 $0 $12,252 $87,098 $158 4 PC BOILER & ACCESSORIES 4.1 PC Boiler 167,291 0 93,867 0 261,158 9.7% 25,296 0.0% 0 10.0% 28,645 315,099 573 4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 4. $167,291 $0 $93,867 $0 $261,158 $25,296 $0 $28,645 $315,099 $573 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 157Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 60 Case 1B (50%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture x $1, 000 Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 5A FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories 71,665 0 15,428 0 87,093 9.5% 8,243 0% 0 10.0% 9,534 104,869 191 5.2 Other FGD 3,743 0 4,241 0 7,984 9.6% 769 0% 0 10.0% 875 9,628 18 5.3 Bag House & Accessories 18,048 0 11,453 0 29,501 9.6% 2,822 0% 0 10.0% 3,232 35,555 65 5.4 Other Particulate Removal Materials 1,181 0 1,264 0 2,445 9.6% 235 0% 0 10.0% 268 2,948 5 5.5 Gypsum Dewatering System 4,883 0 829 0 5,712 9.4% 540 0% 0 10.0% 625 6,877 13 5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 5A. $99,519 $0 $33,216 $0 $132,734 $12,609 $0 $14,534 $159,878 $291 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System 120,357 0 36,445 0 156,802 9.5% 14,882 20% 31,360 20.0% 40,609 243,653 443 5B.2 CO2 Compression & Drying 13,483 0 4,211 0 17,695 9.5% 1,680 0% 0 20.0% 3,875 23,249 42 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $133,841 $0 $40,656 $0 $174,497 $16,562 $31,360 $44,484 $266,902 $485 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 7.3 Ductwork 8,940 0 5,744 0 14,684 8.7% 1,282 0% 0 15.0% 2,395 18,361 33 7.4 Stack 8,575 0 5,018 0 13,593 9.6% 1,299 0% 0 10.0% 1,489 16,381 30 7.9 HRSG, Duct & Stack Foundations 0 998 1,134 0 2,132 9.3% 199 0% 0 20.0% 466 2,797 5 SUBTOTAL 7. $17,515 $998 $11,896 $0 $30,409 $2,780 $0 $4,350 $37,540 $68 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories 52,567 0 6,975 0 59,542 9.6% 5,701 0% 0 10.0% 6,524 71,767 130 8.2 Turbine Plant Auxiliaries 354 0 758 0 1,112 9.7% 108 0% 0 10.0% 122 1,342 2 8.3 Condenser & Auxiliaries 5,372 0 2,001 0 7,374 9.5% 701 0% 0 10.0% 807 8,882 16 8.4 Steam Piping 16,894 0 8,330 0 25,224 8.3% 2,105 0% 0 15.0% 4,099 31,429 57 8.9 TG Foundations 0 1,113 1,759 0 2,872 9.4% 270 0% 0 20.0% 628 3,770 7 SUBTOTAL 8. $75,187 $1,113 $19,824 $0 $96,124 $8,885 $0 $12,182 $117,190 $213 9 COOLING WATER SYSTEM 9.1 Cooling Towers 10,446 0 3,253 0 13,698 9.5% 1,300 0% 0 10.0% 1,500 16,499 30 9.2 Circulating Water Pumps 1,758 0 135 0 1,893 8.6% 162 0% 0 10.0% 205 2,260 4 9.3 Circ. Water System Auxiliaries 498 0 66 0 565 9.4% 53 0% 0 10.0% 62 680 1 9.4 Circ. Water Piping 0 3,949 3,827 0 7,777 9.2% 716 0% 0 15.0% 1,274 9,767 18 9.5 Make-up Water System 477 0 637 0 1,114 9.5% 106 0% 0 15.0% 183 1,403 3 9.6 Component Cooling Water System 395 0 314 0 709 9.4% 66 0% 0 15.0% 116 891 2 9.9 Circ. Water System Foundations 0 2,425 3,853 0 6,278 9.4% 591 0% 0 20.0% 1,374 8,243 15 SUBTOTAL 9. $13,574 $6,374 $12,086 $0 $32,034 $2,995 $0 $4,714 $39,743 $72 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 158Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 60 Case 1B (50%) Capital Costs (continued)
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture x $1, 000 Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.6 Ash Storage Silos 634 0 1,955 0 2,589 9.7% 252 0% 0 10.0% 284 3,126 6 10.7 Ash Transport & Feed Equipment 4,107 0 4,207 0 8,314 9.5% 786 0% 0 10.0% 910 10,010 18 10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 10.9 Ash/Spent Sorbent Foundation 0 151 178 0 328 9.3% 31 0% 0 20.0% 72 431 1 SUBTOTAL 10. $4,741 $151 $6,339 $0 $11,231 $1,069 $0 $1,266 $13,566 $25 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment 1,625 0 264 0 1,889 9.3% 175 0% 0 7.5% 155 2,219 4 11.2 Station Service Equipment 3,904 0 1,283 0 5,187 9.6% 496 0% 0 7.5% 426 6,109 11 11.3 Switchgear & Motor Control 4,488 0 763 0 5,251 9.3% 486 0% 0 10.0% 574 6,311 11 11.4 Conduit & Cable Tray 0 2,814 9,730 0 12,544 9.6% 1,200 0% 0 15.0% 2,062 15,806 29 11.5 Wire & Cable 0 5,310 10,250 0 15,560 8.4% 1,311 0% 0 15.0% 2,531 19,401 35 11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3 11.7 Standby Equipment 1,294 0 30 0 1,323 9.5% 125 0% 0 10.0% 145 1,594 3 11.8 Main Power Transformers 7,399 0 125 0 7,524 7.6% 572 0% 0 10.0% 810 8,905 16 11.9 Electrical Foundations 0 317 777 0 1,093 9.5% 104 0% 0 20.0% 239 1,437 3 SUBTOTAL 11. $18,971 $8,440 $24,105 $0 $51,517 $4,581 $0 $7,067 $63,164 $115 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 12.3 Steam Turbine Control w/8.1 0 w/8.1 0 0 0% 0 0% 0 0.0% 0 0 0 12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.6 Control Boards, Panels & Racks 481 0 288 0 770 9.6% 74 0% 0 15.0% 127 970 2 12.7 Computer Accessories 4,860 0 849 0 5,710 9.5% 544 0% 0 10.0% 625 6,879 13 12.8 Instrument Wiring & Tubing 2,634 0 5,226 0 7,860 8.5% 670 0% 0 15.0% 1,279 9,809 18 12.9 Other I & C Equipment 1,373 0 3,117 0 4,490 9.7% 437 0% 0 10.0% 493 5,420 10 SUBTOTAL 12. $9,349 $0 $9,480 $0 $18,830 $1,725 $0 $2,524 $23,078 $42 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 53 1,067 0 1,120 9.9% 110 0% 0 20.0% 246 1,477 3 13.2 Site Improvements 0 1,771 2,200 0 3,971 9.8% 390 0% 0 20.0% 872 5,233 10 13.3 Site Facilities 3,174 0 3,130 0 6,304 9.8% 619 0% 0 20.0% 1,384 8,307 15 SUBTOTAL 13. $3,174 $1,825 $6,396 $0 $11,395 $1,119 $0 $2,503 $15,016 $27 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 159Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 60 Case 1B (50%) Capital Costs (continued)
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture x $1, 000 Plant Size: 549.99 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Boiler Building 0 8,747 7,692 0 16,439 9.0% 1,476 0% 0 15.0% 2,687 20,603 37 14.2 Turbine Building 0 12,572 11,717 0 24,289 9.0% 2,187 0% 0 15.0% 3,971 30,448 55 14.3 Administration Building 0 629 665 0 1,294 9.1% 117 0% 0 15.0% 212 1,623 3 14.4 Circulation Water Pumphouse 0 116 92 0 208 8.9% 19 0% 0 15.0% 34 260 0 14.5 Water Treatment Buildings 0 641 584 0 1,225 9.0% 110 0% 0 15.0% 200 1,534 3 14.6 Machine Shop 0 421 283 0 703 8.9% 62 0% 0 15.0% 115 880 2 14.7 Warehouse 0 285 286 0 571 9.0% 52 0% 0 15.0% 93 716 1 14.8 Other Buildings & Structures 0 233 198 0 431 9.0% 39 0% 0 15.0% 70 540 1 14.9 Waste Treating Building & Str. 0 441 1,338 0 1,778 9.4% 168 0% 0 15.0% 292 2,238 4 SUBTOTAL 14. $0 $24,083 $22,855 $0 $46,938 $4,229 $0 $7,675 $58,842 $107 Total Cost $619,709 $48,505 $316,606 $0 $984,820 $92,501 $31,360 $150,260 $1,258,942 $2,289


### Owner's Costs Preproduction Costs 6 Months All Labor $9,253 $17 1 Month Maintenance Materials $1,231 $2 1 Month Non-fuel Consumables $983 $2 1 Month Waste Disposal $281 $1 25% of 1 Months Fuel Cost at 100% CF $1,705 $3 2% of TPC $25,179 $46
Total $38,632 $70 Inventory Capital 60 day supply of fuel and consumables at 100% CF $15,606 $28 0.5% of TPC (spare parts) $6,295 $11
Total $21,900 $40

Initial Cost for Catalyst and Chemicals $1,183 $2 Land $900 $2 Other Owner's Costs $188,841 $343

Financing Costs $33,991 $62 

### Total Overnight Costs (TOC) $1,544,390 $2,808.0 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $1,760,604 $3,201 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 160Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 61 Case 1B Initial and Annual O&M Expenses

Case: Case 1B - Supercritical PC w/ 50% CO2 Capture Plant Size (MWe): 549.99 Heat Rate (Btu/kWh): 10,379 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 85 CO 2 Captured (TPD): 6977

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's etc. 2.0 2.0 TOTAL Operating Jobs 16.3 16.3
$ $/kW-net Annual Operating Labor Cost (calc'd) 6,431,885 11.69 Maintenance Labor Cost (calc'd) 8,372,328 15.22 Administrative & Support Labor (calc'd) 3,701,053 6.73 Property Taxes & Insurance $25,178,842 $45.781 TOTAL FIXED OPERATING COSTS $43,684,109 $79.427 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $12,558,493 0.00307

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 5,401 1.08 $0 $1,809,702 0.00044 Chemicals MU & WT Chem. (lb) 0 26,144 0.17 $0 $1,378,908 0.00034 Limestone (ton) 0 594 21.63 $0 $3,986,773 0.00097 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000 MEA Solvent (ton) 487 0.70 2249.89 $1,095,943 $488,964 0.00012 Caustic Soda, NaOH (ton) 34 3.44 433.68 $14,927 $463,114 0.00011 Sulfuric acid, H 2 SO 4 (ton) 33 3.28 138.78 $4,558 $141,416 0.00003 Corrosion Inhibitor 0 0 0.00 $67,376 $3,254 0.00000 Activated C, MEA (lb) 0 825 1.05 $0 $268,831 0.00007 Ammonia, 28% soln (ton) 0 18 129.80 $0 $725,759 0.00018 Subtotal Chemicals $1,182,804 $7,457,020 0.00182 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 SCR Catalyst Replacement w/equip. 0.42 5,775.94 $0 $759,439 0.00019 Emission Penalties 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $759,439 0.00019 Waste Disposal Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000 Flyash (ton) 0 456 16.23 $0 $2,293,612 0.00056 Bottom Ash (ton) 0 114 16.23 $0 $573,403 0.00014 Subtotal Solid Waste Disposal $0 $2,867,015 0.00070 By-products & Emissions Gypsum (tons) 0 0 0.00 $0 $0 0.00000 Sulfur (tons) 0 0 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $25,451,668 0.00621 Coal FUEL (tons) 176,154 5,872 38.19 $6,726,460 $69,562,807 0.01699 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 161Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 62 Case 1C (70%) Capital Costs
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture x $1, 000 Plant Size: 550.04 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload 3,828 0 1,748 0 5,576 8.9% 498 0% 0 15.0% 911 6,985 13 1.2 Coal Stackout & Reclaim 4,947 0 1,121 0 6,067 8.8% 531 0% 0 15.0% 990 7,588 14 1.3 Coal Conveyors & Yd Crus 4,599 0 1,109 0 5,708 8.8% 500 0% 0 15.0% 931 7,140 13 1.4 Other Coal Handling 1,203 0 257 0 1,460 8.7% 128 0% 0 15.0% 238 1,826 3 1.5 Sorbent Receive & Unload 157 0 47 0 205 8.8% 18 0% 0 15.0% 33 256 0 1.6 Sorbent Stackout & Reclaim 2,538 0 465 0 3,004 8.7% 262 0% 0 15.0% 490 3,755 7 1.7 Sorbent Conveyors 906 196 222 0 1,324 8.7% 115 0% 0 15.0% 216 1,654 3 1.8 Other Sorbent Handling 547 128 287 0 962 8.8% 85 0% 0 15.0% 157 1,204 2 1.9 Coal & Sorbent Hnd.Foundations 0 4,705 5,936 0 10,641 9.3% 995 0% 0 15.0% 1,745 13,381 24 SUBTOTAL 1. $18,725 $5,030 $11,192 $0 $34,946 $3,131 $0 $5,712 $43,789 $80 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying 2,210 0 431 0 2,641 8.7% 230 0% 0 15.0% 431 3,302 6 2.2 Prepared Coal Storage & Feed 5,659 0 1,235 0 6,895 8.7% 603 0% 0 15.0% 1,125 8,623 16 2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.5 Sorbent Prep Equipment 4,322 186 898 0 5,406 8.7% 471 0% 0 15.0% 881 6,758 12 2.6 Sorbent Storage & Feed 521 0 199 0 720 8.9% 64 0% 0 15.0% 118 902 2 2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.9 Coal & Sorbent Feed Foundation 0 554 465 0 1,019 9.2% 94 0% 0 15.0% 167 1,280 2 SUBTOTAL 2. $12,712 $740 $3,228 $0 $16,681 $1,462 $0 $2,721 $20,864 $38 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 20,561 0 6,642 0 27,203 8.8% 2,382 0% 0 15.0% 4,438 34,023 62 3.2 Water Makeup & Pretreating 5,674 0 1,826 0 7,501 9.4% 703 0% 0 20.0% 1,641 9,845 18 3.3 Other Feedwater Subsystems 6,295 0 2,660 0 8,955 8.9% 798 0% 0 15.0% 1,463 11,216 20 3.4 Service Water Systems 1,112 0 605 0 1,717 9.3% 159 0% 0 20.0% 375 2,252 4 3.5 Other Boiler Plant Systems 7,893 0 7,792 0 15,685 9.4% 1,471 0% 0 15.0% 2,573 19,730 36 3.6 FO Supply Sys & Nat Gas 268 0 335 0 604 9.3% 56 0% 0 15.0% 99 759 1 3.7 Waste Treatment Equipment 4,577 0 2,609 0 7,187 9.7% 696 0% 0 20.0% 1,577 9,460 17 3.8 Misc. Power Plant Equipment 2,848 0 870 0 3,718 9.6% 357 0% 0 20.0% 815 4,890 9 SUBTOTAL 3. $49,229 $0 $23,341 $0 $72,570 $6,623 $0 $12,981 $92,174 $168 4 PC BOILER & ACCESSORIES 4.1 PC Boiler 175,837 0 98,662 0 274,499 9.7% 26,588 0.0% 0 10.0% 30,109 331,196 602 4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 4. $175,837 $0 $98,662 $0 $274,499 $26,588 $0 $30,109 $331,196 $602 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 162Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 62 Case 1C (70%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture x $1, 000 Plant Size: 550.04 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 5A FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories 75,503 0 16,254 0 91,757 9.5% 8,684 0% 0 10.0% 10,044 110,485 201 5.2 Other FGD 3,943 0 4,468 0 8,411 9.6% 810 0% 0 10.0% 922 10,144 18 5.3 Bag House & Accessories 19,088 0 12,114 0 31,201 9.6% 2,984 0% 0 10.0% 3,419 37,604 68 5.4 Other Particulate Removal Materials 1,248 0 1,336 0 2,584 9.6% 249 0% 0 10.0% 283 3,116 6 5.5 Gypsum Dewatering System 5,096 0 866 0 5,961 9.4% 563 0% 0 10.0% 652 7,177 13 5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 5A. $104,877 $0 $35,037 $0 $139,914 $13,291 $0 $15,321 $168,526 $306 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System 152,043 0 46,040 0 198,083 9.5% 18,800 20% 39,617 20.0% 51,300 307,799 560 5B.2 CO2 Compression & Drying 16,816 0 5,252 0 22,068 9.5% 2,095 0% 0 20.0% 4,833 28,996 53 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $168,859 $0 $51,292 $0 $220,151 $20,895 $39,617 $56,132 $336,794 $612 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 7.3 Ductwork 9,187 0 5,903 0 15,090 8.7% 1,318 0% 0 15.0% 2,461 18,870 34 7.4 Stack 8,521 0 4,986 0 13,507 9.6% 1,291 0% 0 10.0% 1,480 16,278 30 7.9 HRSG, Duct & Stack Foundations 0 1,008 1,145 0 2,153 9.3% 201 0% 0 20.0% 471 2,825 5 SUBTOTAL 7. $17,708 $1,008 $12,034 $0 $30,751 $2,809 $0 $4,412 $37,972 $69 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories 53,728 0 7,129 0 60,857 9.6% 5,827 0% 0 10.0% 6,668 73,353 133 8.2 Turbine Plant Auxiliaries 362 0 775 0 1,137 9.7% 110 0% 0 10.0% 125 1,372 2 8.3 Condenser & Auxiliaries 5,127 0 1,910 0 7,037 9.5% 669 0% 0 10.0% 771 8,477 15 8.4 Steam Piping 17,763 0 8,758 0 26,521 8.3% 2,213 0% 0 15.0% 4,310 33,045 60 8.9 TG Foundations 0 1,137 1,796 0 2,933 9.4% 276 0% 0 20.0% 642 3,851 7 SUBTOTAL 8. $76,980 $1,137 $20,369 $0 $98,486 $9,095 $0 $12,516 $120,098 $218 9 COOLING WATER SYSTEM 9.1 Cooling Towers 12,077 0 3,761 0 15,838 9.5% 1,504 0% 0 10.0% 1,734 19,076 35 9.2 Circulating Water Pumps 2,101 0 161 0 2,263 8.6% 193 0% 0 10.0% 246 2,702 5 9.3 Circ. Water System Auxiliaries 570 0 76 0 646 9.4% 61 0% 0 10.0% 71 778 1 9.4 Circ. Water Piping 0 4,519 4,380 0 8,899 9.2% 820 0% 0 15.0% 1,458 11,176 20 9.5 Make-up Water System 537 0 718 0 1,255 9.5% 119 0% 0 15.0% 206 1,580 3 9.6 Component Cooling Water System 452 0 359 0 811 9.4% 76 0% 0 15.0% 133 1,020 2 9.9 Circ. Water System Foundations 0 2,746 4,364 0 7,110 9.4% 669 0% 0 20.0% 1,556 9,335 17 SUBTOTAL 9. $15,738 $7,266 $13,818 $0 $36,821 $3,442 $0 $5,403 $45,666 $83 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 163Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 62 Case 1C (70%) Capital Costs (continued)
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture x $1, 000 Plant Size: 550.04 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.6 Ash Storage Silos 661 0 2,035 0 2,696 9.7% 263 0% 0 10.0% 296 3,254 6 10.7 Ash Transport & Feed Equipment 4,275 0 4,380 0 8,655 9.5% 819 0% 0 10.0% 947 10,421 19 10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 10.9 Ash/Spent Sorbent Foundation 0 157 185 0 342 9.3% 32 0% 0 20.0% 75 448 1 SUBTOTAL 10. $4,936 $157 $6,599 $0 $11,692 $1,113 $0 $1,318 $14,123 $26 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment 1,653 0 268 0 1,922 9.3% 178 0% 0 7.5% 157 2,257 4 11.2 Station Service Equipment 4,353 0 1,430 0 5,784 9.6% 553 0% 0 7.5% 475 6,812 12 11.3 Switchgear & Motor Control 5,005 0 851 0 5,856 9.3% 542 0% 0 10.0% 640 7,038 13 11.4 Conduit & Cable Tray 0 3,138 10,850 0 13,988 9.6% 1,339 0% 0 15.0% 2,299 17,626 32 11.5 Wire & Cable 0 5,921 11,430 0 17,351 8.4% 1,462 0% 0 15.0% 2,822 21,635 39 11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3 11.7 Standby Equipment 1,312 0 30 0 1,342 9.5% 127 0% 0 10.0% 147 1,616 3 11.8 Main Power Transformers 7,541 0 127 0 7,668 7.6% 583 0% 0 10.0% 825 9,076 17 11.9 Electrical Foundations 0 324 793 0 1,117 9.5% 106 0% 0 20.0% 245 1,468 3 SUBTOTAL 11. $20,125 $9,383 $26,665 $0 $56,174 $5,002 $0 $7,736 $68,911 $125 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 12.3 Steam Turbine Control w/8.1 0 w/8.1 0 0 0% 0 0% 0 0.0% 0 0 0 12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.6 Control Boards, Panels & Racks 497 0 298 0 795 9.6% 76 0% 0 15.0% 131 1,002 2 12.7 Computer Accessories 5,019 0 877 0 5,897 9.5% 562 0% 0 10.0% 646 7,104 13 12.8 Instrument Wiring & Tubing 2,721 0 5,397 0 8,118 8.5% 692 0% 0 15.0% 1,321 10,131 18 12.9 Other I & C Equipment 1,418 0 3,219 0 4,637 9.7% 452 0% 0 10.0% 509 5,598 10 SUBTOTAL 12. $9,656 $0 $9,791 $0 $19,447 $1,781 $0 $2,607 $23,835 $43 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 54 1,086 0 1,140 9.9% 112 0% 0 20.0% 251 1,503 3 13.2 Site Improvements 0 1,803 2,239 0 4,042 9.8% 397 0% 0 20.0% 888 5,326 10 13.3 Site Facilities 3,230 0 3,186 0 6,416 9.8% 630 0% 0 20.0% 1,409 8,455 15 SUBTOTAL 13. $3,230 $1,857 $6,510 $0 $11,598 $1,139 $0 $2,547 $15,284 $28 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 164Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 62 Case 1C (70%) Capital Costs (continued)
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture x $1, 000 Plant Size: 550.04 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Boiler Building 0 8,786 7,726 0 16,512 9.0% 1,483 0% 0 15.0% 2,699 20,694 38 14.2 Turbine Building 0 12,661 11,800 0 24,462 9.0% 2,203 0% 0 15.0% 4,000 30,664 56 14.3 Administration Building 0 634 671 0 1,305 9.1% 118 0% 0 15.0% 214 1,637 3 14.4 Circulation Water Pumphouse 0 131 104 0 235 8.9% 21 0% 0 15.0% 38 295 1 14.5 Water Treatment Buildings 0 730 666 0 1,396 9.0% 125 0% 0 15.0% 228 1,749 3 14.6 Machine Shop 0 424 285 0 709 8.9% 63 0% 0 15.0% 116 888 2 14.7 Warehouse 0 288 288 0 576 9.0% 52 0% 0 15.0% 94 722 1 14.8 Other Buildings & Structures 0 235 200 0 435 9.0% 39 0% 0 15.0% 71 545 1 14.9 Waste Treating Building & Str. 0 447 1,356 0 1,803 9.4% 170 0% 0 15.0% 296 2,270 4 SUBTOTAL 14. $0 $24,336 $23,097 $0 $47,433 $4,274 $0 $7,756 $59,463 $108 Total Cost $678,613 $50,913 $341,637 $0 $1,071,164 $100,645 $39,617 $167,271 $1,378,696 $2,507


### Owner's Costs Preproduction Costs 6 Months All Labor $9,711 $18 1 Month Maintenance Materials $1,339 $2 1 Month Non-fuel Consumables $1,150 $2 1 Month Waste Disposal $302 $1 25% of 1 Months Fuel Cost at 100% CF $1,832 $3 2% of TPC $27,574 $50
Total $41,909 $76 Inventory Capital 60 day supply of fuel and consumables at 100% CF $16,956 $31 0.5% of TPC (spare parts) $6,893 $13
Total $23,850 $43

Initial Cost for Catalyst and Chemicals $1,770 $3 Land $900 $2 Other Owner's Costs $206,804 $376

Financing Costs $37,225 $68 

### Total Overnight Costs (TOC) $1,691,155 $3,074.6 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $1,927,917 $3,505 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 165Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 63 Case 1C Initial and Annual O&M Expenses

Case: Case 1C - Supercritical PC w/ 70% CO2 Capture Plant Size (MWe): 550.04 Heat Rate (Btu/kWh): 11,151 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 85 CO 2 Captured (TPD): 10443

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's etc. 2.0 2.0 TOTAL Operating Jobs 16.3 16.3
$ $/kW-net Annual Operating Labor Cost (calc'd) 6,431,885 11.69 Maintenance Labor Cost (calc'd) 9,106,367 16.56 Administrative & Support Labor (calc'd) 3,884,563 7.06 Property Taxes & Insurance $27,573,930 $50.131 TOTAL FIXED OPERATING COSTS $46,996,745 $85.442 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $13,659,550 0.00334

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 6,584 1.08 $0 $2,206,227 0.00054 Chemicals MU & WT Chem. (lb) 0 31,873 0.17 $0 $1,681,041 0.00041 Limestone (ton) 0 635 21.63 $0 $4,262,785 0.00104 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000 MEA Solvent (ton) 729 1.05 2249.89 $1,640,437 $731,895 0.00018 Caustic Soda, NaOH (ton) 52 5.15 433.68 $22,343 $693,202 0.00017 Sulfuric acid, H 2 SO 4 (ton) 49 4.92 138.78 $6,823 $211,676 0.00005 Corrosion Inhibitor 0 0 0.00 $100,851 $4,871 0.00000 Activated C, MEA (lb) 0 1,235 1.05 $0 $402,393 0.00010 Ammonia, 28% soln (ton) 0 19 129.80 $0 $779,819 0.00019 Subtotal Chemicals $1,770,454 $8,767,682 0.00214 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 SCR Catalyst Replacement w/equip. 0.42 5,775.94 $0 $759,439 0.00019 Emission Penalties 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $759,439 0.00019 Waste Disposal Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000 Flyash (ton) 0 489 16.23 $0 $2,464,457 0.00060 Bottom Ash (ton) 0 122 16.23 $0 $616,114 0.00015 Subtotal Solid Waste Disposal $0 $3,080,571 0.00075 By-products & Emissions Gypsum (tons) 0 0 0.00 $0 $0 0.00000 Sulfur (tons) 0 0 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $28,473,469 0.00695 Coal FUEL (tons) 189,275 6,309 38.19 $7,227,497 $74,744,361 0.01825 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 166Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 64 Case 1D (85%) Capital Costs
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture x $1, 000 Plant Size: 550.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload 3,968 0 1,813 0 5,781 8.9% 516 0% 0 15.0% 945 7,241 13 1.2 Coal Stackout & Reclaim 5,128 0 1,162 0 6,290 8.8% 551 0% 0 15.0% 1,026 7,867 14 1.3 Coal Conveyors & Yd Crus 4,768 0 1,150 0 5,918 8.8% 519 0% 0 15.0% 965 7,402 13 1.4 Other Coal Handling 1,247 0 266 0 1,513 8.7% 132 0% 0 15.0% 247 1,893 3 1.5 Sorbent Receive & Unload 164 0 49 0 213 8.8% 19 0% 0 15.0% 35 266 0 1.6 Sorbent Stackout & Reclaim 2,642 0 484 0 3,126 8.7% 272 0% 0 15.0% 510 3,908 7 1.7 Sorbent Conveyors 943 204 231 0 1,378 8.7% 119 0% 0 15.0% 225 1,721 3 1.8 Other Sorbent Handling 569 133 299 0 1,001 8.8% 89 0% 0 15.0% 163 1,253 2 1.9 Coal & Sorbent Hnd.Foundations 0 4,880 6,156 0 11,035 9.3% 1,032 0% 0 15.0% 1,810 13,877 25 SUBTOTAL 1. $19,429 $5,217 $11,609 $0 $36,255 $3,248 $0 $5,925 $45,429 $83 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying 2,297 0 448 0 2,745 8.7% 239 0% 0 15.0% 448 3,432 6 2.2 Prepared Coal Storage & Feed 5,881 0 1,284 0 7,165 8.7% 627 0% 0 15.0% 1,169 8,960 16 2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.5 Sorbent Prep Equipment 4,500 194 935 0 5,629 8.7% 490 0% 0 15.0% 918 7,037 13 2.6 Sorbent Storage & Feed 542 0 208 0 750 8.9% 67 0% 0 15.0% 122 939 2 2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.9 Coal & Sorbent Feed Foundation 0 575 483 0 1,058 9.2% 97 0% 0 15.0% 173 1,329 2 SUBTOTAL 2. $13,221 $769 $3,356 $0 $17,346 $1,520 $0 $2,830 $21,697 $39 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 21,402 0 6,913 0 28,316 8.8% 2,479 0% 0 15.0% 4,619 35,414 64 3.2 Water Makeup & Pretreating 6,289 0 2,024 0 8,313 9.4% 779 0% 0 20.0% 1,818 10,911 20 3.3 Other Feedwater Subsystems 6,552 0 2,769 0 9,321 8.9% 831 0% 0 15.0% 1,523 11,675 21 3.4 Service Water Systems 1,233 0 671 0 1,904 9.3% 177 0% 0 20.0% 416 2,496 5 3.5 Other Boiler Plant Systems 8,244 0 8,139 0 16,383 9.4% 1,537 0% 0 15.0% 2,688 20,608 37 3.6 FO Supply Sys & Nat Gas 272 0 340 0 612 9.3% 57 0% 0 15.0% 100 770 1 3.7 Waste Treatment Equipment 4,656 0 2,654 0 7,311 9.7% 708 0% 0 20.0% 1,604 9,623 17 3.8 Misc. Power Plant Equipment 2,890 0 883 0 3,773 9.6% 362 0% 0 20.0% 827 4,962 9 SUBTOTAL 3. $51,539 $0 $24,394 $0 $75,933 $6,930 $0 $13,596 $96,459 $175 4 PC BOILER & ACCESSORIES 4.1 PC Boiler 183,083 0 102,728 0 285,811 9.7% 27,684 0.0% 0 10.0% 31,349 344,844 627 4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 4. $183,083 $0 $102,728 $0 $285,811 $27,684 $0 $31,349 $344,844 $627 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 167Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 64 Case 1D (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture x $1, 000 Plant Size: 550.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 5A FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories 78,763 0 16,956 0 95,719 9.5% 9,059 0% 0 10.0% 10,478 115,256 210 5.2 Other FGD 4,113 0 4,661 0 8,774 9.6% 845 0% 0 10.0% 962 10,582 19 5.3 Bag House & Accessories 19,975 0 12,676 0 32,651 9.6% 3,123 0% 0 10.0% 3,577 39,351 72 5.4 Other Particulate Removal Materials 1,305 0 1,397 0 2,702 9.6% 260 0% 0 10.0% 296 3,259 6 5.5 Gypsum Dewatering System 5,292 0 899 0 6,191 9.4% 585 0% 0 10.0% 678 7,453 14 5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 5A. $109,448 $0 $36,589 $0 $146,037 $13,873 $0 $15,991 $175,901 $320 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System 195,757 0 59,277 0 255,033 9.5% 24,205 20% 51,007 20.0% 66,049 396,294 720 5B.2 CO2 Compression & Drying 26,380 0 8,239 0 34,619 9.5% 3,287 0% 0 20.0% 7,581 45,487 83 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $222,137 $0 $67,516 $0 $289,653 $27,491 $51,007 $73,630 $441,781 $803 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 7.3 Ductwork 9,393 0 6,035 0 15,428 8.7% 1,347 0% 0 15.0% 2,516 19,292 35 7.4 Stack 8,465 0 4,953 0 13,418 9.6% 1,282 0% 0 10.0% 1,470 16,171 29 7.9 HRSG, Duct & Stack Foundations 0 1,016 1,154 0 2,170 9.3% 202 0% 0 20.0% 475 2,847 5 SUBTOTAL 7. $17,858 $1,016 $12,143 $0 $31,017 $2,832 $0 $4,461 $38,310 $70 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories 54,723 0 7,262 0 61,984 9.6% 5,935 0% 0 10.0% 6,792 74,711 136 8.2 Turbine Plant Auxiliaries 369 0 789 0 1,158 9.7% 112 0% 0 10.0% 127 1,397 3 8.3 Condenser & Auxiliaries 4,913 0 1,830 0 6,743 9.5% 641 0% 0 10.0% 738 8,122 15 8.4 Steam Piping 18,500 0 9,122 0 27,622 8.3% 2,305 0% 0 15.0% 4,489 34,416 63 8.9 TG Foundations 0 1,158 1,829 0 2,986 9.4% 281 0% 0 20.0% 653 3,921 7 SUBTOTAL 8. $78,504 $1,158 $20,831 $0 $100,493 $9,274 $0 $12,800 $122,567 $223 9 COOLING WATER SYSTEM 9.1 Cooling Towers 13,419 0 4,179 0 17,598 9.5% 1,671 0% 0 10.0% 1,927 21,196 39 9.2 Circulating Water Pumps 2,392 0 183 0 2,575 8.6% 220 0% 0 10.0% 280 3,075 6 9.3 Circ. Water System Auxiliaries 629 0 84 0 712 9.4% 67 0% 0 10.0% 78 858 2 9.4 Circ. Water Piping 0 4,984 4,830 0 9,813 9.2% 904 0% 0 15.0% 1,608 12,325 22 9.5 Make-up Water System 586 0 783 0 1,369 9.5% 130 0% 0 15.0% 225 1,723 3 9.6 Component Cooling Water System 498 0 396 0 894 9.4% 84 0% 0 15.0% 147 1,125 2 9.9 Circ. Water System Foundations 0 3,006 4,776 0 7,782 9.4% 732 0% 0 20.0% 1,703 10,217 19 SUBTOTAL 9. $17,524 $7,990 $15,231 $0 $40,744 $3,808 $0 $5,966 $50,518 $92 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 168Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 64 Case 1D (85%) Capital Costs (continued)
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture x $1, 000 Plant Size: 550.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.6 Ash Storage Silos 682 0 2,102 0 2,785 9.7% 271 0% 0 10.0% 306 3,362 6 10.7 Ash Transport & Feed Equipment 4,417 0 4,525 0 8,942 9.5% 846 0% 0 10.0% 979 10,766 20 10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 10.9 Ash/Spent Sorbent Foundation 0 162 191 0 353 9.3% 33 0% 0 20.0% 77 463 1 SUBTOTAL 10. $5,100 $162 $6,818 $0 $12,080 $1,150 $0 $1,362 $14,591 $27 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment 1,677 0 272 0 1,950 9.3% 181 0% 0 7.5% 160 2,290 4 11.2 Station Service Equipment 4,700 0 1,544 0 6,244 9.6% 597 0% 0 7.5% 513 7,354 13 11.3 Switchgear & Motor Control 5,403 0 918 0 6,322 9.3% 585 0% 0 10.0% 691 7,597 14 11.4 Conduit & Cable Tray 0 3,388 11,713 0 15,101 9.6% 1,445 0% 0 15.0% 2,482 19,028 35 11.5 Wire & Cable 0 6,392 12,339 0 18,731 8.4% 1,578 0% 0 15.0% 3,046 23,356 42 11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3 11.7 Standby Equipment 1,328 0 30 0 1,358 9.5% 129 0% 0 10.0% 149 1,635 3 11.8 Main Power Transformers 7,634 0 129 0 7,762 7.6% 590 0% 0 10.0% 835 9,187 17 11.9 Electrical Foundations 0 329 808 0 1,137 9.5% 108 0% 0 20.0% 249 1,494 3 SUBTOTAL 11. $21,002 $10,109 $28,639 $0 $59,750 $5,325 $0 $8,250 $73,326 $133 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 12.3 Steam Turbine Control w/8.1 0 w/8.1 0 0 0% 0 0% 0 0.0% 0 0 0 12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.6 Control Boards, Panels & Racks 509 0 305 0 813 9.6% 78 0% 0 15.0% 134 1,025 2 12.7 Computer Accessories 5,134 0 897 0 6,032 9.5% 574 0% 0 10.0% 661 7,267 13 12.8 Instrument Wiring & Tubing 2,783 0 5,521 0 8,305 8.5% 707 0% 0 15.0% 1,352 10,364 19 12.9 Other I & C Equipment 1,451 0 3,292 0 4,743 9.7% 462 0% 0 10.0% 521 5,726 10 SUBTOTAL 12. $9,877 $0 $10,016 $0 $19,893 $1,822 $0 $2,667 $24,382 $44 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 55 1,107 0 1,163 9.9% 115 0% 0 20.0% 255 1,533 3 13.2 Site Improvements 0 1,838 2,283 0 4,121 9.8% 405 0% 0 20.0% 905 5,430 10 13.3 Site Facilities 3,294 0 3,248 0 6,542 9.8% 642 0% 0 20.0% 1,437 8,620 16 SUBTOTAL 13. $3,294 $1,893 $6,638 $0 $11,825 $1,161 $0 $2,597 $15,583 $28 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 169Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 64 Case 1D (85%) Capital Costs (continued)
Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture x $1, 000 Plant Size: 550.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Boiler Building 0 8,828 7,764 0 16,592 9.0% 1,490 0% 0 15.0% 2,712 20,794 38 14.2 Turbine Building 0 12,760 11,892 0 24,652 9.0% 2,220 0% 0 15.0% 4,031 30,902 56 14.3 Administration Building 0 641 677 0 1,318 9.1% 119 0% 0 15.0% 216 1,653 3 14.4 Circulation Water Pumphouse 0 143 114 0 257 8.9% 23 0% 0 15.0% 42 322 1 14.5 Water Treatment Buildings 0 803 732 0 1,536 9.0% 137 0% 0 15.0% 251 1,924 3 14.6 Machine Shop 0 428 288 0 716 8.9% 64 0% 0 15.0% 117 897 2 14.7 Warehouse 0 290 291 0 582 9.0% 53 0% 0 15.0% 95 729 1 14.8 Other Buildings & Structures 0 237 202 0 439 9.0% 39 0% 0 15.0% 72 550 1 14.9 Waste Treating Building & Str. 0 452 1,370 0 1,822 9.4% 172 0% 0 15.0% 299 2,293 4 SUBTOTAL 14. $0 $24,583 $23,331 $0 $47,914 $4,317 $0 $7,835 $60,065 $109 Total Cost $752,015 $52,896 $369,839 $0 $1,174,751 $110,436 $51,007 $189,260 $1,525,453 $2,773


### Owner's Costs Preproduction Costs 6 Months All Labor $10,262 $19 1 Month Maintenance Materials $1,469 $3 1 Month Non-fuel Consumables $1,299 $2 1 Month Waste Disposal $320 $1 25% of 1 Months Fuel Cost at 100% CF $1,942 $4 2% of TPC $30,509 $55
Total $45,800 $83 Inventory Capital 60 day supply of fuel and consumables at 100% CF $18,132 $33 0.5% of TPC (spare parts) $7,627 $14
Total $25,759 $47

Initial Cost for Catalyst and Chemicals $2,280 $4 Land $900 $2 Other Owner's Costs $228,818 $416

Financing Costs $41,187 $75 

### Total Overnight Costs (TOC) $1,870,197 $3,400.0 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $2,132,024 $3,876 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 170Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 65 Case 1D Initial and Annual O&M Expenses

Case: Case 1D - Supercritical PC w/ 85% CO2 Capture Plant Size (MWe): 550.05 Heat Rate (Btu/kWh): 11,819 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 85 CO 2 Captured (TPD): 13446

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's etc. 2.0 2.0 TOTAL Operating Jobs 16.3 16.3
$ $/kW-net Annual Operating Labor Cost (calc'd) 6,431,885 11.69 Maintenance Labor Cost (calc'd) 9,986,997 18.16 Administrative & Support Labor (calc'd) 4,104,721 7.46 Property Taxes & Insurance $30,509,054 $55.466 TOTAL FIXED OPERATING COSTS $51,032,657 $92.778 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $14,980,495 0.00366

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 7,611 1.08 $0 $2,550,103 0.00062 Chemicals MU & WT Chem. (lb) 0 36,840 0.17 $0 $1,943,058 0.00047 Limestone (ton) 0 676 21.63 $0 $4,536,881 0.00111 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000 MEA Solvent (ton) 939 1.35 2249.89 $2,112,135 $942,347 0.00023 Caustic Soda, NaOH (ton) 66 6.63 433.68 $28,768 $892,528 0.00022 Sulfuric acid, H 2 SO 4 (ton) 63 6.33 138.78 $8,785 $272,542 0.00007 Corrosion Inhibitor 0 0 0.00 $129,850 $6,271 0.00000 Activated C, MEA (lb) 0 1,590 1.05 $0 $518,099 0.00013 Ammonia, 28% soln (ton) 0 21 129.80 $0 $826,568 0.00020 Subtotal Chemicals $2,279,537 $9,938,295 0.00243 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 SCR Catalyst Replacement w/equip. 0.42 5,775.94 $0 $759,439 0.00019 Emission Penalties 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $759,439 0.00019 Waste Disposal Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000 Flyash (ton) 0 519 16.23 $0 $2,612,200 0.00064 Bottom Ash (ton) 0 130 16.23 $0 $653,050 0.00016 Subtotal Solid Waste Disposal $0 $3,265,250 0.00080 By-products & Emissions Gypsum (tons) 0 0 0.00 $0 $0 0.00000 Sulfur (tons) 0 0 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $31,493,582 0.00769 Coal FUEL (tons) 200,622 6,687 38.19 $7,660,781 $79,225,242 0.01934 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 171Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 66 Case 1E (90%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture x $1, 000 Plant Size: 550.01 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload 4,023 0 1,837 0 5,860 8.9% 523 0% 0 15.0% 957 7,341 13 1.2 Coal Stackout & Reclaim 5,199 0 1,178 0 6,377 8.8% 558 0% 0 15.0% 1,040 7,975 14 1.3 Coal Conveyors & Yd Crus 4,833 0 1,165 0 5,999 8.8% 526 0% 0 15.0% 979 7,504 14 1.4 Other Coal Handling 1,265 0 270 0 1,534 8.7% 134 0% 0 15.0% 250 1,919 3 1.5 Sorbent Receive & Unload 166 0 50 0 216 8.8% 19 0% 0 15.0% 35 270 0 1.6 Sorbent Stackout & Reclaim 2,680 0 491 0 3,171 8.7% 276 0% 0 15.0% 517 3,965 7 1.7 Sorbent Conveyors 956 207 235 0 1,398 8.7% 121 0% 0 15.0% 228 1,747 3 1.8 Other Sorbent Handling 578 135 303 0 1,016 8.8% 90 0% 0 15.0% 166 1,272 2 1.9 Coal & Sorbent Hnd.Foundations 0 4,947 6,240 0 11,187 9.3% 1,046 0% 0 15.0% 1,835 14,068 26 SUBTOTAL 1. $19,700 $5,289 $11,769 $0 $36,758 $3,293 $0 $6,008 $46,059 $84 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying 2,331 0 454 0 2,785 8.7% 243 0% 0 15.0% 454 3,482 6 2.2 Prepared Coal Storage & Feed 5,967 0 1,303 0 7,270 8.7% 636 0% 0 15.0% 1,186 9,091 17 2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.5 Sorbent Prep Equipment 4,567 197 949 0 5,713 8.7% 498 0% 0 15.0% 932 7,142 13 2.6 Sorbent Storage & Feed 550 0 211 0 761 8.9% 68 0% 0 15.0% 124 953 2 2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.9 Coal & Sorbent Feed Foundation 0 583 490 0 1,073 9.2% 99 0% 0 15.0% 176 1,347 2 SUBTOTAL 2. $13,415 $780 $3,406 $0 $17,601 $1,543 $0 $2,872 $22,015 $40 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 21,729 0 7,019 0 28,748 8.8% 2,517 0% 0 15.0% 4,690 35,954 65 3.2 Water Makeup & Pretreating 6,520 0 2,099 0 8,618 9.4% 808 0% 0 20.0% 1,885 11,311 21 3.3 Other Feedwater Subsystems 6,652 0 2,811 0 9,463 8.9% 843 0% 0 15.0% 1,546 11,853 22 3.4 Service Water Systems 1,278 0 695 0 1,973 9.3% 183 0% 0 20.0% 431 2,588 5 3.5 Other Boiler Plant Systems 8,381 0 8,274 0 16,655 9.4% 1,562 0% 0 15.0% 2,733 20,950 38 3.6 FO Supply Sys & Nat Gas 274 0 342 0 616 9.3% 57 0% 0 15.0% 101 774 1 3.7 Waste Treatment Equipment 4,687 0 2,672 0 7,358 9.7% 713 0% 0 20.0% 1,614 9,685 18 3.8 Misc. Power Plant Equipment 2,906 0 888 0 3,794 9.6% 364 0% 0 20.0% 832 4,989 9 SUBTOTAL 3. $52,425 $0 $24,800 $0 $77,225 $7,048 $0 $13,832 $98,105 $178 4 PC BOILER & ACCESSORIES 4.1 PC Boiler 185,896 0 104,307 0 290,203 9.7% 28,109 0.0% 0 10.0% 31,831 350,144 637 4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 4. $185,896 $0 $104,307 $0 $290,203 $28,109 $0 $31,831 $350,144 $637 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 172Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 66 Case 1E (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture x $1, 000 Plant Size: 550.01 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 5A FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories 80,030 0 17,229 0 97,259 9.5% 9,205 0% 0 10.0% 10,646 117,111 213 5.2 Other FGD 4,179 0 4,736 0 8,916 9.6% 859 0% 0 10.0% 977 10,752 20 5.3 Bag House & Accessories 20,320 0 12,896 0 33,216 9.6% 3,177 0% 0 10.0% 3,639 40,032 73 5.4 Other Particulate Removal Materials 1,328 0 1,421 0 2,749 9.6% 265 0% 0 10.0% 301 3,315 6 5.5 Gypsum Dewatering System 5,366 0 911 0 6,278 9.4% 593 0% 0 10.0% 687 7,558 14 5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 5A. $111,224 $0 $37,193 $0 $148,417 $14,099 $0 $16,252 $178,767 $325 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System 205,392 0 62,194 0 267,586 9.5% 25,396 20% 53,517 20.0% 69,300 415,800 756 5B.2 CO2 Compression & Drying 27,599 0 8,620 0 36,219 9.5% 3,438 0% 0 20.0% 7,932 47,589 87 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $232,992 $0 $70,814 $0 $303,806 $28,834 $53,517 $77,231 $463,389 $843 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 7.3 Ductwork 9,472 0 6,086 0 15,557 8.7% 1,359 0% 0 15.0% 2,537 19,454 35 7.4 Stack 8,445 0 4,942 0 13,387 9.6% 1,279 0% 0 10.0% 1,467 16,132 29 7.9 HRSG, Duct & Stack Foundations 0 1,019 1,158 0 2,177 9.3% 203 0% 0 20.0% 476 2,856 5 SUBTOTAL 7. $17,917 $1,019 $12,185 $0 $31,121 $2,841 $0 $4,480 $38,442 $70 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories 55,108 0 7,313 0 62,421 9.6% 5,977 0% 0 10.0% 6,840 75,238 137 8.2 Turbine Plant Auxiliaries 371 0 795 0 1,166 9.7% 113 0% 0 10.0% 128 1,407 3 8.3 Condenser & Auxiliaries 4,825 0 1,797 0 6,622 9.5% 629 0% 0 10.0% 725 7,977 15 8.4 Steam Piping 18,786 0 9,263 0 28,049 8.3% 2,341 0% 0 15.0% 4,559 34,949 64 8.9 TG Foundations 0 1,165 1,841 0 3,007 9.4% 283 0% 0 20.0% 658 3,947 7 SUBTOTAL 8. $79,091 $1,165 $21,009 $0 $101,265 $9,343 $0 $12,909 $123,517 $225 9 COOLING WATER SYSTEM 9.1 Cooling Towers 13,922 0 4,335 0 18,257 9.5% 1,733 0% 0 10.0% 1,999 21,989 40 9.2 Circulating Water Pumps 2,502 0 192 0 2,694 8.6% 230 0% 0 10.0% 292 3,217 6 9.3 Circ. Water System Auxiliaries 650 0 87 0 737 9.4% 70 0% 0 10.0% 81 887 2 9.4 Circ. Water Piping 0 5,157 4,998 0 10,154 9.2% 935 0% 0 15.0% 1,663 12,753 23 9.5 Make-up Water System 604 0 807 0 1,411 9.5% 134 0% 0 15.0% 232 1,776 3 9.6 Component Cooling Water System 515 0 410 0 925 9.4% 87 0% 0 15.0% 152 1,164 2 9.9 Circ. Water System Foundations 0 3,102 4,929 0 8,031 9.4% 756 0% 0 20.0% 1,757 10,544 19 SUBTOTAL 9. $18,194 $8,259 $15,757 $0 $42,210 $3,945 $0 $6,176 $52,331 $95 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 173Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 66 Case 1E (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture x $1, 000 Plant Size: 550.01 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.6 Ash Storage Silos 691 0 2,129 0 2,819 9.7% 275 0% 0 10.0% 309 3,403 6 10.7 Ash Transport & Feed Equipment 4,472 0 4,581 0 9,053 9.5% 856 0% 0 10.0% 991 10,900 20 10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 10.9 Ash/Spent Sorbent Foundation 0 164 193 0 357 9.3% 33 0% 0 20.0% 78 469 1 SUBTOTAL 10. $5,163 $164 $6,903 $0 $12,230 $1,164 $0 $1,378 $14,772 $27 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment 1,687 0 274 0 1,961 9.3% 182 0% 0 7.5% 161 2,303 4 11.2 Station Service Equipment 4,824 0 1,585 0 6,410 9.6% 613 0% 0 7.5% 527 7,549 14 11.3 Switchgear & Motor Control 5,547 0 943 0 6,489 9.3% 601 0% 0 10.0% 709 7,799 14 11.4 Conduit & Cable Tray 0 3,477 12,024 0 15,501 9.6% 1,484 0% 0 15.0% 2,548 19,533 36 11.5 Wire & Cable 0 6,562 12,667 0 19,229 8.4% 1,620 0% 0 15.0% 3,127 23,976 44 11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3 11.7 Standby Equipment 1,334 0 30 0 1,364 9.5% 129 0% 0 10.0% 149 1,643 3 11.8 Main Power Transformers 7,634 0 129 0 7,762 7.6% 590 0% 0 10.0% 835 9,187 17 11.9 Electrical Foundations 0 332 813 0 1,145 9.5% 109 0% 0 20.0% 251 1,504 3 SUBTOTAL 11. $21,286 $10,371 $29,350 $0 $61,006 $5,439 $0 $8,432 $74,877 $136 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 12.3 Steam Turbine Control w/8.1 0 w/8.1 0 0 0% 0 0% 0 0.0% 0 0 0 12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.6 Control Boards, Panels & Racks 513 0 307 0 820 9.6% 79 0% 0 15.0% 135 1,033 2 12.7 Computer Accessories 5,174 0 904 0 6,079 9.5% 579 0% 0 10.0% 666 7,323 13 12.8 Instrument Wiring & Tubing 2,805 0 5,564 0 8,369 8.5% 713 0% 0 15.0% 1,362 10,444 19 12.9 Other I & C Equipment 1,462 0 3,318 0 4,780 9.7% 466 0% 0 10.0% 525 5,770 10 SUBTOTAL 12. $9,954 $0 $10,094 $0 $20,048 $1,836 $0 $2,687 $24,571 $45 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 56 1,112 0 1,168 9.9% 115 0% 0 20.0% 257 1,540 3 13.2 Site Improvements 0 1,847 2,294 0 4,140 9.8% 407 0% 0 20.0% 909 5,456 10 13.3 Site Facilities 3,309 0 3,264 0 6,573 9.8% 645 0% 0 20.0% 1,444 8,662 16 SUBTOTAL 13. $3,309 $1,902 $6,669 $0 $11,881 $1,167 $0 $2,610 $15,658 $28 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 174Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 66 Case 1E (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture x $1, 000 Plant Size: 550.01 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Boiler Building 0 8,839 7,773 0 16,612 9.0% 1,492 0% 0 15.0% 2,716 20,819 38 14.2 Turbine Building 0 12,784 11,915 0 24,699 9.0% 2,224 0% 0 15.0% 4,038 30,961 56 14.3 Administration Building 0 642 679 0 1,321 9.1% 120 0% 0 15.0% 216 1,657 3 14.4 Circulation Water Pumphouse 0 148 118 0 266 8.9% 24 0% 0 15.0% 43 333 1 14.5 Water Treatment Buildings 0 831 757 0 1,588 9.0% 142 0% 0 15.0% 260 1,990 4 14.6 Machine Shop 0 429 289 0 718 8.9% 64 0% 0 15.0% 117 899 2 14.7 Warehouse 0 291 292 0 583 9.0% 53 0% 0 15.0% 95 731 1 14.8 Other Buildings & Structures 0 238 202 0 440 9.0% 39 0% 0 15.0% 72 552 1 14.9 Waste Treating Building & Str. 0 453 1,375 0 1,828 9.4% 173 0% 0 15.0% 300 2,301 4 SUBTOTAL 14. $0 $24,655 $23,400 $0 $48,055 $4,330 $0 $7,858 $60,242 $110 Total Cost $770,565 $53,605 $377,655 $0 $1,201,825 $112,991 $53,517 $194,556 $1,562,889 $2,842
Owner's Costs Preproduction Costs 6 Months All Labor $10,406 $19 1 Month Maintenance Materials $1,503 $3 1 Month Non-fuel Consumables $1,356 $2 1 Month Waste Disposal $327 $1 25% of 1 Months Fuel Cost at 100% CF $1,985 $4 2% of TPC $31,258 $57
Total $46,834 $85 Inventory Capital 60 day supply of fuel and consumables at 100% CF $18,592 $34 0.5% of TPC (spare parts) $7,814 $14
Total $26,406 $48

Initial Cost for Catalyst and Chemicals $2,477 $5 Land $900 $2 Other Owner's Costs $234,433 $426

Financing Costs $42,198 $77 Total Overnight Costs (TOC) $1,916,138 $3,483.8 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,184,397 $3,972 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 175Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 67 Case 1E Initial and Annual O&M Expenses

Case: Case 1E - Supercritical PC w/ 90% CO2 Capture Plant Size (MWe): 550.01 Heat Rate (Btu/kWh): 12,083 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 85 CO 2 Captured (TPD): 14609

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's etc. 2.0 2.0 TOTAL Operating Jobs 16.3 16.3
$ $/kW-net Annual Operating Labor Cost (calc'd) 6,431,885 11.69 Maintenance Labor Cost (calc'd) 10,217,164 18.58 Administrative & Support Labor (calc'd) 4,162,262 7.57 Property Taxes & Insurance $31,257,786 $56.831 TOTAL FIXED OPERATING COSTS $52,069,097 $94.669 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $15,325,746 0.00374

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 8,007 1.08 $0 $2,682,853 0.00066 Chemicals MU & WT Chem. (lb) 0 38,758 0.17 $0 $2,044,208 0.00050 Limestone (ton) 0 692 21.63 $0 $4,640,812 0.00113 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000 MEA Solvent (ton) 1,020 1.47 2249.89 $2,294,818 $1,023,853 0.00025 Caustic Soda, NaOH (ton) 72 7.21 433.68 $31,256 $969,725 0.00024 Sulfuric acid, H 2 SO 4 (ton) 69 6.88 138.78 $9,544 $296,115 0.00007 Corrosion Inhibitor 0 0 0.00 $141,081 $6,814 0.00000 Activated C, MEA (lb) 0 1,728 1.05 $0 $562,910 0.00014 Ammonia, 28% soln (ton) 0 21 129.80 $0 $844,943 0.00021 Subtotal Chemicals $2,476,699 $10,389,380 0.00254 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 SCR Catalyst Replacement ( w/equip. 0.42 5,775.94 $0 $759,439 0.00019 Emission Penalties 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $759,439 0.00019 Waste Disposal Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000 Flyash (ton) 0 530 16.23 $0 $2,670,269 0.00065 Bottom Ash (ton) 0 133 16.23 $0 $667,567 0.00016 Subtotal Solid Waste Disposal $0 $3,337,836 0.00082 By-products & Emissions Gypsum (tons) 0 0 0.00 $0 $0 0.00000 Sulfur (tons) 0 0 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $32,495,254 0.00793 Coal FUEL (tons) 205,082 6,836 38.19 $7,831,079 $80,986,412 0.01978 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 176Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 68 Case 1F (95%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture x $1, 000 Plant Size: 549.96 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload 4,088 0 1,867 0 5,955 8.9% 532 0% 0 15.0% 973 7,459 14 1.2 Coal Stackout & Reclaim 5,283 0 1,197 0 6,480 8.8% 567 0% 0 15.0% 1,057 8,104 15 1.3 Coal Conveyors & Yd Crus 4,911 0 1,184 0 6,096 8.8% 534 0% 0 15.0% 995 7,625 14 1.4 Other Coal Handling 1,285 0 274 0 1,559 8.7% 136 0% 0 15.0% 254 1,950 4 1.5 Sorbent Receive & Unload 169 0 51 0 220 8.8% 19 0% 0 15.0% 36 275 0 1.6 Sorbent Stackout & Reclaim 2,726 0 500 0 3,226 8.7% 281 0% 0 15.0% 526 4,033 7 1.7 Sorbent Conveyors 973 210 239 0 1,422 8.7% 123 0% 0 15.0% 232 1,777 3 1.8 Other Sorbent Handling 588 138 308 0 1,033 8.8% 91 0% 0 15.0% 169 1,294 2 1.9 Coal & Sorbent Hnd.Foundations 0 5,027 6,341 0 11,368 9.3% 1,063 0% 0 15.0% 1,865 14,295 26 SUBTOTAL 1. $20,022 $5,375 $11,961 $0 $37,358 $3,347 $0 $6,106 $46,810 $85 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying 2,371 0 462 0 2,833 8.7% 247 0% 0 15.0% 462 3,542 6 2.2 Prepared Coal Storage & Feed 6,070 0 1,325 0 7,395 8.7% 647 0% 0 15.0% 1,206 9,248 17 2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.5 Sorbent Prep Equipment 4,647 200 965 0 5,812 8.7% 506 0% 0 15.0% 948 7,266 13 2.6 Sorbent Storage & Feed 560 0 214 0 774 8.9% 69 0% 0 15.0% 126 969 2 2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.9 Coal & Sorbent Feed Foundation 0 593 498 0 1,091 9.2% 100 0% 0 15.0% 179 1,370 2 SUBTOTAL 2. $13,647 $793 $3,464 $0 $17,904 $1,569 $0 $2,921 $22,394 $41 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 22,119 0 7,145 0 29,263 8.8% 2,562 0% 0 15.0% 4,774 36,599 67 3.2 Water Makeup & Pretreating 6,704 0 2,158 0 8,862 9.4% 831 0% 0 20.0% 1,939 11,631 21 3.3 Other Feedwater Subsystems 6,771 0 2,862 0 9,633 8.9% 859 0% 0 15.0% 1,574 12,065 22 3.4 Service Water Systems 1,314 0 715 0 2,029 9.3% 188 0% 0 20.0% 444 2,661 5 3.5 Other Boiler Plant Systems 8,544 0 8,436 0 16,980 9.4% 1,593 0% 0 15.0% 2,786 21,359 39 3.6 FO Supply Sys & Nat Gas 275 0 344 0 620 9.3% 58 0% 0 15.0% 102 779 1 3.7 Waste Treatment Equipment 4,723 0 2,692 0 7,415 9.7% 718 0% 0 20.0% 1,627 9,760 18 3.8 Misc. Power Plant Equipment 2,925 0 893 0 3,818 9.6% 367 0% 0 20.0% 837 5,022 9 SUBTOTAL 3. $53,376 $0 $25,245 $0 $78,621 $7,175 $0 $14,081 $99,877 $182 4 PC BOILER & ACCESSORIES 4.1 PC Boiler 189,257 0 106,193 0 295,450 9.7% 28,617 0.0% 0 10.0% 32,407 356,474 648 4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 4. $189,257 $0 $106,193 $0 $295,450 $28,617 $0 $32,407 $356,474 $648 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 177Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 68 Case 1F (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture x $1, 000 Plant Size: 549.96 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 5A FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories 81,546 0 17,555 0 99,101 9.5% 9,379 0% 0 10.0% 10,848 119,328 217 5.2 Other FGD 4,259 0 4,826 0 9,084 9.6% 875 0% 0 10.0% 996 10,955 20 5.3 Bag House & Accessories 20,734 0 13,158 0 33,892 9.6% 3,242 0% 0 10.0% 3,713 40,847 74 5.4 Other Particulate Removal Materials 1,354 0 1,449 0 2,804 9.6% 270 0% 0 10.0% 307 3,381 6 5.5 Gypsum Dewatering System 5,455 0 926 0 6,381 9.4% 603 0% 0 10.0% 698 7,683 14 5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 5A. $113,347 $0 $37,915 $0 $151,262 $14,369 $0 $16,563 $182,194 $331 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System 215,143 0 65,147 0 280,290 9.5% 26,602 20% 56,058 20.0% 72,590 435,539 792 5B.2 CO2 Compression & Drying 28,843 0 9,008 0 37,852 9.5% 3,593 0% 0 20.0% 8,289 49,734 90 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $243,986 $0 $74,155 $0 $318,141 $30,195 $56,058 $80,879 $485,273 $882 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 7.3 Ductwork 9,565 0 6,146 0 15,711 8.7% 1,372 0% 0 15.0% 2,562 19,646 36 7.4 Stack 8,512 0 4,981 0 13,494 9.6% 1,289 0% 0 10.0% 1,478 16,261 30 7.9 HRSG, Duct & Stack Foundations 0 1,023 1,162 0 2,184 9.3% 204 0% 0 20.0% 478 2,866 5 SUBTOTAL 7. $18,078 $1,023 $12,289 $0 $31,389 $2,865 $0 $4,518 $38,773 $71 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories 55,493 0 7,364 0 62,857 9.6% 6,018 0% 0 10.0% 6,887 75,762 138 8.2 Turbine Plant Auxiliaries 374 0 800 0 1,174 9.7% 114 0% 0 10.0% 129 1,417 3 8.3 Condenser & Auxiliaries 4,692 0 1,748 0 6,440 9.5% 612 0% 0 10.0% 705 7,757 14 8.4 Steam Piping 19,128 0 9,432 0 28,560 8.3% 2,384 0% 0 15.0% 4,641 35,585 65 8.9 TG Foundations 0 1,173 1,854 0 3,027 9.4% 285 0% 0 20.0% 662 3,974 7 SUBTOTAL 8. $79,687 $1,173 $21,197 $0 $102,058 $9,413 $0 $13,025 $124,496 $226 9 COOLING WATER SYSTEM 9.1 Cooling Towers 14,317 0 4,458 0 18,776 9.5% 1,782 0% 0 10.0% 2,056 22,614 41 9.2 Circulating Water Pumps 2,590 0 199 0 2,789 8.6% 238 0% 0 10.0% 303 3,330 6 9.3 Circ. Water System Auxiliaries 668 0 89 0 757 9.4% 71 0% 0 10.0% 83 911 2 9.4 Circ. Water Piping 0 5,292 5,129 0 10,422 9.2% 960 0% 0 15.0% 1,707 13,089 24 9.5 Make-up Water System 618 0 826 0 1,445 9.5% 137 0% 0 15.0% 237 1,819 3 9.6 Component Cooling Water System 529 0 421 0 950 9.4% 89 0% 0 15.0% 156 1,194 2 9.9 Circ. Water System Foundations 0 3,178 5,049 0 8,226 9.4% 774 0% 0 20.0% 1,800 10,800 20 SUBTOTAL 9. $18,722 $8,470 $16,171 $0 $43,363 $4,053 $0 $6,342 $53,757 $98 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 178Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 68 Case 1F (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture x $1, 000 Plant Size: 549.96 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.6 Ash Storage Silos 701 0 2,160 0 2,860 9.7% 279 0% 0 10.0% 314 3,453 6 10.7 Ash Transport & Feed Equipment 4,537 0 4,648 0 9,185 9.5% 869 0% 0 10.0% 1,005 11,058 20 10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 10.9 Ash/Spent Sorbent Foundation 0 167 196 0 363 9.3% 34 0% 0 20.0% 79 476 1 SUBTOTAL 10. $5,238 $167 $7,003 $0 $12,408 $1,181 $0 $1,399 $14,987 $27 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment 1,696 0 275 0 1,971 9.3% 183 0% 0 7.5% 162 2,315 4 11.2 Station Service Equipment 4,947 0 1,625 0 6,573 9.6% 629 0% 0 7.5% 540 7,741 14 11.3 Switchgear & Motor Control 5,688 0 967 0 6,654 9.3% 616 0% 0 10.0% 727 7,997 15 11.4 Conduit & Cable Tray 0 3,566 12,329 0 15,895 9.6% 1,521 0% 0 15.0% 2,612 20,029 36 11.5 Wire & Cable 0 6,728 12,989 0 19,717 8.4% 1,661 0% 0 15.0% 3,207 24,585 45 11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3 11.7 Standby Equipment 1,340 0 31 0 1,370 9.5% 130 0% 0 10.0% 150 1,650 3 11.8 Main Power Transformers 7,680 0 129 0 7,809 7.6% 593 0% 0 10.0% 840 9,243 17 11.9 Electrical Foundations 0 334 819 0 1,152 9.5% 110 0% 0 20.0% 252 1,514 3 SUBTOTAL 11. $21,610 $10,628 $30,050 $0 $62,288 $5,554 $0 $8,616 $76,459 $139 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 12.3 Steam Turbine Control w/8.1 0 w/8.1 0 0 0% 0 0% 0 0.0% 0 0 0 12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.6 Control Boards, Panels & Racks 516 0 309 0 826 9.6% 79 0% 0 15.0% 136 1,041 2 12.7 Computer Accessories 5,213 0 911 0 6,124 9.5% 583 0% 0 10.0% 671 7,378 13 12.8 Instrument Wiring & Tubing 2,826 0 5,606 0 8,432 8.5% 718 0% 0 15.0% 1,372 10,522 19 12.9 Other I & C Equipment 1,473 0 3,343 0 4,816 9.7% 469 0% 0 10.0% 528 5,813 11 SUBTOTAL 12. $10,028 $0 $10,169 $0 $20,197 $1,850 $0 $2,707 $24,755 $45 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 56 1,118 0 1,174 9.9% 116 0% 0 20.0% 258 1,547 3 13.2 Site Improvements 0 1,856 2,305 0 4,161 9.8% 409 0% 0 20.0% 914 5,483 10 13.3 Site Facilities 3,326 0 3,280 0 6,605 9.8% 648 0% 0 20.0% 1,451 8,704 16 SUBTOTAL 13. $3,326 $1,912 $6,702 $0 $11,940 $1,173 $0 $2,623 $15,735 $29 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 179Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 68 Case 1F (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture x $1, 000 Plant Size: 549.96 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Boiler Building 0 8,850 7,783 0 16,632 9.0% 1,494 0% 0 15.0% 2,719 20,845 38 14.2 Turbine Building 0 12,809 11,938 0 24,748 9.0% 2,228 0% 0 15.0% 4,046 31,022 56 14.3 Administration Building 0 644 681 0 1,324 9.1% 120 0% 0 15.0% 217 1,661 3 14.4 Circulation Water Pumphouse 0 152 120 0 272 8.9% 24 0% 0 15.0% 44 341 1 14.5 Water Treatment Buildings 0 852 777 0 1,630 9.0% 146 0% 0 15.0% 266 2,042 4 14.6 Machine Shop 0 431 289 0 720 8.9% 64 0% 0 15.0% 118 901 2 14.7 Warehouse 0 292 293 0 584 9.0% 53 0% 0 15.0% 96 733 1 14.8 Other Buildings & Structures 0 238 203 0 441 9.0% 40 0% 0 15.0% 72 553 1 14.9 Waste Treating Building & Str. 0 454 1,379 0 1,833 9.4% 173 0% 0 15.0% 301 2,307 4 SUBTOTAL 14. $0 $24,722 $23,463 $0 $48,185 $4,342 $0 $7,879 $60,405 $110 Total Cost $790,324 $54,263 $385,976 $0 $1,230,563 $115,703 $56,058 $200,065 $1,602,389 $2,914
Owner's Costs Preproduction Costs 6 Months All Labor $10,558 $19 1 Month Maintenance Materials $1,538 $3 1 Month Non-fuel Consumables $1,412 $3 1 Month Waste Disposal $336 $1 25% of 1 Months Fuel Cost at 100% CF $2,037 $4 2% of TPC $32,048 $58
Total $47,930 $87 Inventory Capital 60 day supply of fuel and consumables at 100% CF $19,120 $35 0.5% of TPC (spare parts) $8,012 $15
Total $27,132 $49

Initial Cost for Catalyst and Chemicals $2,683 $5 Land $900 $2 Other Owner's Costs $240,358 $437

Financing Costs $43,265 $79 Total Overnight Costs (TOC) $1,964,657 $3,572.4 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,239,708 $4,072 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 180Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 69 Case 1F Initial and Annual O&M Expenses

Case: Case 1F - Supercritical PC w/ 95% CO2 Capture Plant Size (MWe): 549.96 Heat Rate (Btu/kWh): 12,400 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 85 CO 2 Captured (TPD): 15824

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's etc. 2.0 2.0 TOTAL Operating Jobs 16.3 16.3
$ $/kW-net Annual Operating Labor Cost (calc'd) 6,431,885 11.70 Maintenance Labor Cost (calc'd) 10,461,480 19.02 Administrative & Support Labor (calc'd) 4,223,341 7.68 Property Taxes & Insurance $32,047,789 $58.273 TOTAL FIXED OPERATING COSTS $53,164,496 $96.670 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $15,692,221 0.00383

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 8,328 1.08 $0 $2,790,368 0.00068 Chemicals MU & WT Chem. (lb) 0 40,311 0.17 $0 $2,126,129 0.00052 Limestone (ton) 0 710 21.63 $0 $4,765,707 0.00116 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000 MEA Solvent (ton) 1,105 1.59 2249.89 $2,485,693 $1,109,014 0.00027 Caustic Soda, NaOH (ton) 78 7.81 433.68 $33,856 $1,050,384 0.00026 Sulfuric acid, H 2 SO 4 (ton) 74 7.45 138.78 $10,338 $320,744 0.00008 Corrosion Inhibitor 0 0 0.00 $152,815 $7,380 0.00000 Activated C, MEA (lb) 0 1,872 1.05 $0 $609,731 0.00015 Ammonia, 28% soln (ton) 0 22 129.80 $0 $867,053 0.00021 Subtotal Chemicals $2,682,703 $10,856,142 0.00265 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 SCR Catalyst Replacement w/equip. 0.42 5,775.94 $0 $759,439 0.00019 Emission Penalties 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $759,439 0.00019 Waste Disposal Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000 Flyash (ton) 0 544 16.23 $0 $2,740,142 0.00067 Bottom Ash (ton) 0 136 16.23 $0 $685,035 0.00017 Subtotal Solid Waste Disposal $0 $3,425,177 0.00084 By-products & Emissions Gypsum (tons) 0 0 0.00 $0 $0 0.00000 Sulfur (tons) 0 0 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $33,523,348 0.00819 Coal FUEL (tons) 210,448 7,015 38.19 $8,035,996 $83,105,597 0.02029 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 181Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 70 Case 1G (99%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture x $1, 000 Plant Size: 549.97 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload 4,263 0 1,947 0 6,210 8.9% 555 0% 0 15.0% 1,015 7,779 14 1.2 Coal Stackout & Reclaim 5,509 0 1,248 0 6,758 8.8% 592 0% 0 15.0% 1,102 8,451 15 1.3 Coal Conveyors & Yd Crus 5,122 0 1,235 0 6,357 8.8% 557 0% 0 15.0% 1,037 7,952 14 1.4 Other Coal Handling 1,340 0 286 0 1,626 8.7% 142 0% 0 15.0% 265 2,033 4 1.5 Sorbent Receive & Unload 176 0 53 0 229 8.8% 20 0% 0 15.0% 37 287 1 1.6 Sorbent Stackout & Reclaim 2,841 0 521 0 3,362 8.7% 293 0% 0 15.0% 548 4,203 8 1.7 Sorbent Conveyors 1,014 219 249 0 1,482 8.7% 128 0% 0 15.0% 242 1,852 3 1.8 Other Sorbent Handling 612 144 321 0 1,077 8.8% 95 0% 0 15.0% 176 1,348 2 1.9 Coal & Sorbent Hnd.Foundations 0 5,242 6,612 0 11,854 9.3% 1,108 0% 0 15.0% 1,944 14,906 27 SUBTOTAL 1. $20,878 $5,604 $12,472 $0 $38,954 $3,490 $0 $6,367 $48,811 $89 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying 2,479 0 483 0 2,962 8.7% 258 0% 0 15.0% 483 3,704 7 2.2 Prepared Coal Storage & Feed 6,347 0 1,385 0 7,733 8.7% 676 0% 0 15.0% 1,261 9,670 18 2.3 Slurry Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.4 Misc. Coal Prep & Feed 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.5 Sorbent Prep Equipment 4,846 209 1,006 0 6,061 8.7% 528 0% 0 15.0% 988 7,578 14 2.6 Sorbent Storage & Feed 584 0 224 0 807 8.9% 72 0% 0 15.0% 132 1,011 2 2.7 Sorbent Injection System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.8 Booster Air Supply System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 2.9 Coal & Sorbent Feed Foundation 0 619 520 0 1,139 9.2% 105 0% 0 15.0% 187 1,430 3 SUBTOTAL 2. $14,256 $828 $3,618 $0 $18,702 $1,639 $0 $3,051 $23,393 $43 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 23,175 0 7,486 0 30,661 8.8% 2,685 0% 0 15.0% 5,002 38,347 70 3.2 Water Makeup & Pretreating 7,202 0 2,318 0 9,520 9.4% 892 0% 0 20.0% 2,083 12,495 23 3.3 Other Feedwater Subsystems 7,095 0 2,998 0 10,093 8.9% 900 0% 0 15.0% 1,649 12,642 23 3.4 Service Water Systems 1,412 0 768 0 2,180 9.3% 202 0% 0 20.0% 476 2,859 5 3.5 Other Boiler Plant Systems 8,989 0 8,875 0 17,863 9.4% 1,676 0% 0 15.0% 2,931 22,470 41 3.6 FO Supply Sys & Nat Gas 280 0 350 0 630 9.3% 59 0% 0 15.0% 103 792 1 3.7 Waste Treatment Equipment 4,817 0 2,746 0 7,563 9.7% 733 0% 0 20.0% 1,659 9,954 18 3.8 Misc. Power Plant Equipment 2,975 0 909 0 3,883 9.6% 373 0% 0 20.0% 851 5,108 9 SUBTOTAL 3. $55,944 $0 $26,450 $0 $82,394 $7,519 $0 $14,754 $104,667 $190 4 PC BOILER & ACCESSORIES 4.1 PC Boiler 198,367 0 111,304 0 309,671 9.7% 29,995 0.0% 0 10.0% 33,967 373,632 679 4.2 SCR (w/4.1) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.3 Open 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.4 Boiler BoP (w/ID Fans) 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 4.5 Primary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.6 Secondary Air System w/4.1 0 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.7 Major Component Rigging 0 w/4.1 w/4.1 0 0 0% 0 0% 0 0.0% 0 0 0 4.8 PC Foundations 0 w/14.1 w/14.1 0 0 0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 4. $198,367 $0 $111,304 $0 $309,671 $29,995 $0 $33,967 $373,632 $679 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 182Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 70 Case 1G (99%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture x $1, 000 Plant Size: 549.97 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 5A FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories 85,658 0 18,440 0 104,098 9.5% 9,852 0% 0 10.0% 11,395 125,346 228 5.2 Other FGD 4,473 0 5,069 0 9,542 9.6% 919 0% 0 10.0% 1,046 11,508 21 5.3 Bag House & Accessories 21,859 0 13,872 0 35,731 9.6% 3,418 0% 0 10.0% 3,915 43,064 78 5.4 Other Particulate Removal Materials 1,427 0 1,527 0 2,954 9.6% 284 0% 0 10.0% 324 3,562 6 5.5 Gypsum Dewatering System 5,682 0 965 0 6,647 9.4% 628 0% 0 10.0% 728 8,003 15 5.6 Mercury Removal System 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.7 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.8 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 5.9 Open 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 SUBTOTAL 5A. $119,099 $0 $39,874 $0 $158,973 $15,102 $0 $17,407 $191,482 $348 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System 229,196 0 69,402 0 298,598 9.5% 28,339 20% 59,720 20.0% 77,331 463,988 844 5B.2 CO2 Compression & Drying 30,626 0 9,565 0 40,192 9.5% 3,816 0% 0 20.0% 8,801 52,809 96 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $259,822 $0 $78,967 $0 $338,790 $32,155 $59,720 $86,133 $516,797 $940 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.2 Combustion Turbine Accessories 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.3 Compressed Air Piping 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Flue Gas Recycle Heat Exchanger N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 7.2 SCR System 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 7.3 Ductwork 9,815 0 6,306 0 16,121 8.7% 1,408 0% 0 15.0% 2,629 20,158 37 7.4 Stack 8,763 0 5,128 0 13,891 9.6% 1,327 0% 0 10.0% 1,522 16,740 30 7.9 HRSG, Duct & Stack Foundations 0 1,032 1,173 0 2,205 9.3% 205 0% 0 20.0% 482 2,892 5 SUBTOTAL 7. $18,578 $1,032 $12,606 $0 $32,216 $2,941 $0 $4,633 $39,790 $72 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories 56,173 0 7,454 0 63,627 9.6% 6,092 0% 0 10.0% 6,972 76,691 139 8.2 Turbine Plant Auxiliaries 378 0 810 0 1,189 9.7% 115 0% 0 10.0% 130 1,434 3 8.3 Condenser & Auxiliaries 4,179 0 1,557 0 5,735 9.5% 545 0% 0 10.0% 628 6,908 13 8.4 Steam Piping 20,055 0 9,889 0 29,944 8.3% 2,499 0% 0 15.0% 4,866 37,309 68 8.9 TG Foundations 0 1,187 1,876 0 3,063 9.4% 288 0% 0 20.0% 670 4,021 7 SUBTOTAL 8. $80,785 $1,187 $21,585 $0 $103,557 $9,540 $0 $13,267 $126,364 $230 9 COOLING WATER SYSTEM 9.1 Cooling Towers 15,389 0 4,792 0 20,181 9.5% 1,916 0% 0 10.0% 2,210 24,306 44 9.2 Circulating Water Pumps 2,830 0 217 0 3,047 8.6% 261 0% 0 10.0% 331 3,638 7 9.3 Circ. Water System Auxiliaries 714 0 95 0 809 9.4% 76 0% 0 10.0% 89 974 2 9.4 Circ. Water Piping 0 5,659 5,485 0 11,144 9.2% 1,027 0% 0 15.0% 1,826 13,996 25 9.5 Make-up Water System 657 0 878 0 1,535 9.5% 145 0% 0 15.0% 252 1,932 4 9.6 Component Cooling Water System 566 0 450 0 1,015 9.4% 95 0% 0 15.0% 167 1,277 2 9.9 Circ. Water System Foundations 0 3,380 5,371 0 8,751 9.4% 824 0% 0 20.0% 1,915 11,490 21 SUBTOTAL 9. $20,155 $9,040 $17,287 $0 $46,482 $4,344 $0 $6,788 $57,614 $105 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 183Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 70 Case 1G (99%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture x $1, 000 Plant Size: 549.97 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.2 Cyclone Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.3 HGCU Ash Letdown N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.4 High Temperature Ash Piping N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.5 Other Ash Recovery Equipment N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 10.6 Ash Storage Silos 728 0 2,243 0 2,971 9.7% 289 0% 0 10.0% 326 3,586 7 10.7 Ash Transport & Feed Equipment 4,713 0 4,827 0 9,540 9.5% 902 0% 0 10.0% 1,044 11,486 21 10.8 Misc. Ash Handling Equipment 0 0 0 0 0 0.0% 0 0% 0 0.0% 0 0 0 10.9 Ash/Spent Sorbent Foundation 0 173 204 0 377 9.3% 35 0% 0 20.0% 82 494 1 SUBTOTAL 10. $5,441 $173 $7,274 $0 $12,888 $1,227 $0 $1,453 $15,567 $28 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment 1,712 0 278 0 1,990 9.3% 184 0% 0 7.5% 163 2,338 4 11.2 Station Service Equipment 5,153 0 1,693 0 6,847 9.6% 655 0% 0 7.5% 563 8,064 15 11.3 Switchgear & Motor Control 5,925 0 1,007 0 6,932 9.3% 642 0% 0 10.0% 757 8,331 15 11.4 Conduit & Cable Tray 0 3,715 12,844 0 16,558 9.6% 1,585 0% 0 15.0% 2,721 20,865 38 11.5 Wire & Cable 0 7,009 13,531 0 20,540 8.4% 1,731 0% 0 15.0% 3,341 25,611 47 11.6 Protective Equipment 260 0 885 0 1,146 9.8% 112 0% 0 10.0% 126 1,383 3 11.7 Standby Equipment 1,350 0 31 0 1,381 9.5% 131 0% 0 10.0% 151 1,663 3 11.8 Main Power Transformers 7,725 0 130 0 7,856 7.6% 597 0% 0 10.0% 845 9,298 17 11.9 Electrical Foundations 0 338 828 0 1,166 9.5% 111 0% 0 20.0% 255 1,532 3 SUBTOTAL 11. $22,127 $11,062 $31,227 $0 $64,416 $5,746 $0 $8,923 $79,085 $144 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.2 Combustion Turbine Control N/A 0 N/A 0 0 0% 0 0% 0 0.0% 0 0 0 12.3 Steam Turbine Control w/8.1 0 w/8.1 0 0 0% 0 0% 0 0.0% 0 0 0 12.4 Other Major Component Control 0 0 0 0 0 0% 0 0% 0 0.0% 0 0 0 12.5 Signal Processing Equipment W/12.7 0 w/12.7 0 0 0% 0 0% 0 0.0% 0 0 0 12.6 Control Boards, Panels & Racks 523 0 313 0 836 9.6% 80 0% 0 15.0% 137 1,053 2 12.7 Computer Accessories 5,276 0 922 0 6,199 9.5% 590 0% 0 10.0% 679 7,468 14 12.8 Instrument Wiring & Tubing 2,860 0 5,674 0 8,535 8.5% 727 0% 0 15.0% 1,389 10,651 19 12.9 Other I & C Equipment 1,491 0 3,383 0 4,874 9.7% 475 0% 0 10.0% 535 5,884 11 SUBTOTAL 12. $10,150 $0 $10,293 $0 $20,443 $1,872 $0 $2,740 $25,056 $46 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 57 1,129 0 1,185 9.9% 117 0% 0 20.0% 260 1,562 3 13.2 Site Improvements 0 1,874 2,327 0 4,201 9.8% 412 0% 0 20.0% 923 5,536 10 13.3 Site Facilities 3,358 0 3,311 0 6,669 9.8% 655 0% 0 20.0% 1,465 8,788 16 SUBTOTAL 13. $3,358 $1,930 $6,767 $0 $12,054 $1,184 $0 $2,648 $15,886 $29 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 184Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 70 Case 1G (99%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture x $1, 000 Plant Size: 549.97 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.85

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Boiler Building 0 8,871 7,801 0 16,672 9.0% 1,497 0% 0 15.0% 2,725 20,895 38 14.2 Turbine Building 0 12,858 11,984 0 24,842 9.0% 2,237 0% 0 15.0% 4,062 31,141 57 14.3 Administration Building 0 647 684 0 1,331 9.1% 121 0% 0 15.0% 218 1,669 3 14.4 Circulation Water Pumphouse 0 161 128 0 289 8.9% 26 0% 0 15.0% 47 363 1 14.5 Water Treatment Buildings 0 911 831 0 1,742 9.0% 156 0% 0 15.0% 285 2,183 4 14.6 Machine Shop 0 433 291 0 723 8.9% 64 0% 0 15.0% 118 905 2 14.7 Warehouse 0 293 294 0 587 9.0% 53 0% 0 15.0% 96 736 1 14.8 Other Buildings & Structures 0 239 204 0 443 9.0% 40 0% 0 15.0% 72 556 1 14.9 Waste Treating Building & Str. 0 458 1,389 0 1,846 9.4% 174 0% 0 15.0% 303 2,324 4 SUBTOTAL 14. $0 $24,871 $23,605 $0 $48,476 $4,368 $0 $7,927 $60,770 $110 Total Cost $828,959 $55,727 $403,330 $0 $1,288,016 $121,121 $59,720 $210,057 $1,678,914 $3,053
Owner's Costs Preproduction Costs 6 Months All Labor $10,864 $20 1 Month Maintenance Materials $1,610 $3 1 Month Non-fuel Consumables $1,536 $3 1 Month Waste Disposal $359 $1 25% of 1 Months Fuel Cost at 100% CF $2,180 $4 2% of TPC $33,578 $61
Total $50,127 $91 Inventory Capital 60 day supply of fuel and consumables at 100% CF $20,509 $37 0.5% of TPC (spare parts) $8,395 $15
Total $28,903 $53

Initial Cost for Catalyst and Chemicals $2,992 $5 Land $900 $2 Other Owner's Costs $251,837 $458

Financing Costs $45,331 $82 Total Overnight Costs (TOC) $2,059,004 $3,743.8 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,347,264 $4,268 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 185Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 3
- 71 Case 1G Initial and Annual O&M Expenses

Case: Case 1G - Supercritical PC w/ 99% CO2 Capture Plant Size (MWe): 549.97 Heat Rate (Btu/kWh): 13,269 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 85 CO 2 Captured (TPD): 17646

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's etc. 2.0 2.0 TOTAL Operating Jobs 16.3 16.3
$ $/kW-net Annual Operating Labor Cost (calc'd) 6,431,885 11.69 Maintenance Labor Cost (calc'd) 10,949,911 19.91 Administrative & Support Labor (calc'd) 4,345,449 7.90 Property Taxes & Insurance $33,578,281 $61.055 TOTAL FIXED OPERATING COSTS $55,305,527 $100.561 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $16,424,867 0.00401

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 9,212 1.08 $0 $3,086,655 0.00075 Chemicals MU & WT Chem. (lb) 0 44,592 0.17 $0 $2,351,886 0.00057 Limestone (ton) 0 758 21.63 $0 $5,083,719 0.00124 Carbon (Hg Removal) (lb) 0 0 1.05 $0 $0 0.00000 MEA Solvent (ton) 1,232 1.77 2249.89 $2,771,955 $1,236,732 0.00030 Caustic Soda, NaOH (ton) 87 8.71 433.68 $37,755 $1,171,350 0.00029 Sulfuric acid, H 2 SO 4 (ton) 83 8.31 138.78 $11,529 $357,683 0.00009 Corrosion Inhibitor 0 0 0.00 $170,414 $8,230 0.00000 Activated C, MEA (lb) 0 2,087 1.05 $0 $679,951 0.00017 Ammonia, 28% soln (ton) 0 23 129.80 $0 $927,839 0.00023 Subtotal Chemicals $2,991,654 $11,817,390 0.00289 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 SCR Catalyst Replacement w/equip. 0.42 5,775.94 $0 $759,439 0.00019 Emission Penalties 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $759,439 0.00019 Waste Disposal Spent Mercury Catalyst (lb) 0 0 0.31 $0 $0 0.00000 Flyash (ton) 0 582 16.23 $0 $2,932,245 0.00072 Bottom Ash (ton) 0 146 16.23 $0 $733,061 0.00018 Subtotal Solid Waste Disposal $0 $3,665,306 0.00090 By-products & Emissions Gypsum (tons) 0 0 0.00 $0 $0 0.00000 Sulfur (tons) 0 0 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $35,753,658 0.00873 Coal FUEL (tons) 225,202 7,507 38.19 $8,599,376 $88,931,883 0.02172 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 186Carbon Dioxide Capture Sensitivity Analysis



# 3.2.5 Supercritical PC Cost and Performance Summary
A summary of plant costs and performance for the SC PC cases is shown in Exhibit 3

- 72

.
Exhibit 3
- 72 Cost and Performance Results for the Supercritical PC Cases

Case 0 1A 1B 1C 1D 1E 1F 1G

CO 2 Capture, % 

### 0% 30% 50% 70% 85% 90% 95% 99% Gross Power Output, MW e 

### 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6 Net Power Output, MW e 

### 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0 Net Plant Efficiency, % (HHV) 

### 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7 Net Plant Heat Rate, Btu/kWh (HHV) 

### 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269 Coal Flowrate (lb/hr) 

### 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561
Total CO 2 Captured, lb/MWh net 

### NA 588 1,057 1,582 2,037 2,213 2,398 2,674
CO 2 Capture & Compression Cost, $x1000 

### NA $ 190,138 $ 266,902 $ 336,794 $ 441,781 $ 463,389 $ 485,273 $ 516,797 Total Plant Cost, $x1000 

### $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914 Owner’s Costs, $x1000 

### $207,800 $258,649 $285,448 $312,458 $344,744 $353,249 $362,267 $380,090 Total Overnight Cost, $x1000 

### $1,113,701 $1,397,338 $1,544,390 $1,691,155 $1,870,197 $1,916,138 $1,964,657 $2,059,004 Total Overnight Cost, $/kW 

### $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744
Total As

- Spent Capital, $x1000 

### $1,262,937 $1,592,965 $1,760,604 $1,927,917 $2,132,024 $2,184,397 $2,239,708 $2,347,264
Total As

- Spent Capital, $/kW 

### $2,296 $2,896 $3,201 $3,505 $3,876 $3,972 $4,072 $4,268
CO 2 Capital Cost Penalty a , $/kW 

### NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719 Cost of Electricity b , mills/kWh 

### 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65
COE CO 2 Penalty a , mills/kWh 

### NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8
Percent increase in COE a , % 

### NA 30.1 43. 3 57. 5 72.3 77. 1 81. 7 91. 3
Cost of CO 2 Avoided a , $/tonne 

### NA 102.8 79.1 69.2 67.2 65.9 64.7 68.2
CO 2 Emissions, lb/MMBtu 

### 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0
CO 2 Emissions, lb/MWh net 

### 1,765 1,385 1,055 687 369 246 126 27
SO 2 Emissions, lb/MMBtu 

### 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016
SO 2 Emissions, lb/MWh 

### 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170 NOx Emissions, lb/MMBtu 

### 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 NOx Emissions, lb/MWh 

### 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752 PM Emissions, lb/MMBtu 

### 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 PM Emissions, lb/MWh 

### 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140 Hg Emissions, lb/TBtu 

### 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 Hg Emissions, lb/TWh 

### 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3
Raw Water Withdrawal, gpm 

### 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664 Raw Water Consumption, gpm 

### 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961 Raw Water Consumption, gal/MWh net 

### 469 534 593 706 806 846 881 978 

### a Relative to Case 0 ( SC PC without capture from 2010 Bituminous Baseline study) b Capacity factor is 85% for the SC PC cases



## 187Carbon Dioxide Capture Sensitivity Analysis



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188Carbon Dioxide Capture Sensitivity Analysis



# 4. Case 2

– GEE IGCC w ith Variable C O 2 

# Capture
This section evaluates a range of CO 2 

## capture levels for four IGCC plant designs, which are based on the GEE gasifier in the “radiant only” configuration. GEE offers three design configurations [ 44 ]:

• Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of water to quench the temperature to less than 260 °C (500 °F) before entering the syngas scrubber. It is the simplest and lowest capital cost design, but also the least efficient.

• Radiant

- Only: In this configuration, the hot syngas exiting the gasifier pas ses through a radiant syngas cooler where it is cooled from about 1 , 316 °C (2 , 400 °F) to 677 °C (1 , 250 °F), then through a water quench where the syngas is further cooled to about 223 °C (450 °F) prior to entering the syngas scrubber. Relative to the qu en ch configuration, the radiant

- only design offers increased output, higher efficiency, improved reliability/availability, and results in the lowest COE . This configuration was chosen by GEE and Bechtel for the design of their reference plant.

• Radiant

- Conve ctive: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1 , 316 °C ( 2 , 400 °F) to 760 °C (1 , 400 °F), passes over a pool of water where particulate is removed but t he syngas is not quenched, through a convective syngas cooler where the syngas is further cooled to about 371 °C (700 °F) prior to entering additional heat exchangers or the scrubber. This configuration has the highest overall efficiency, but at the expense of highest cap ital cost and the lowest availability. This is the configuration used at Tampa Electric’s Polk Power Station.

Note that the radiant

- only configuration includes a water quench and, based on functionality, would be more appropriately named ra diant

- quench. The term radiant

- only is used to distinguish it from the radiant

- convectiv e configuration. Since radiant

- only is the terminology used by GEE, it will be used throughout this report.

The balance of Section 4 is organized as follows:

• Gasifier Background provides information on the development and status of the GEE gasification technology.

• Process Description provides an overview of the technology operation for IGCC Designs 2 through 4, which include WGS reactor(s) and a two

- stage SelexolTM unit.

• Performance Results provides the main modeling results from Design s 1

– 4 including the performance summary, environmental performance, carbon balance, sulf ur balance, water balance, mass and ene rgy balance diagrams, mass and energy balance tables.

• Equipment List provides an itemized list of major equipment for Design s 1

– 4 with account codes that correspond to the cost accounts in the Cost Estimates section.

189Carbon Dioxide Capture Sensitivity Analysis



## • Cost Estimates details the capital and O&M costs for IGCC Designs 1

– 4



# 4.1 Gasifier Background
Development and Current Status [ 45 ]

– Initial development of the GEE gasification technology (formerly licensed by Texaco and then ChevronTexaco) was conducted in the 1940s at Texaco’s Montebello, California laboratories. From 1946 to 1954 the Montebello pilot plant produced synthesis gas (hydrogen and carbon monoxide) by partial oxidation of a variety of feedstocks, including natural gas, oil, asphalt, coal tar, and coal. From 1956 to 1958, coal was gasified in a 91 tonne/day (100 TPD) Texaco coal gasifier at the Olin Mathieson Chemical Plant in Morgantown, West Virginia, for the production of ammonia. The oil price increases and supply disruptions of the 1970s rene wed interest in the Texaco partial

- oxidation process for gasification of coal or other solid opportunity fuels. Three 14 tonne/day (15 TPD) pilot plants at the Montebello laboratories have been used to test numerous coals. Two larger pilot plants were al so built. The first gasified 150 tonne/day (165 TPD) of coal and was built to test synthesis gas generation by Rührchemie and Rührkohle at Oberhausen, Germany, and included a synthesis gas cooler. The second gasified 172 tonne/day (190 TPD) of coal using a quench

- only gasifier cooler and was built to make hydrogen at an existing TVA ammonia plant at Muscle Shoals, Alabama. These two large

- scale pilot plants successfully operated for several years during the 1980s and tested a number of process variables and numerous coals. The first commercial Texaco coal gasification plant was built for Tennessee Eastman at Kingsport, Tennessee, and started up in 1983. To date, 24 gasifiers have been built in 12 plants for coal and petroleum coke. Several of the plants require a hydrogen

- rich gas and therefore directly water

- quench the raw gas to add the water for shifting the CO to H 2 

## , and have no synthesis gas coolers. The Cool Water plant was the first commercial

- scale Texaco coal gasification project for the electri c utility industry. This facility gasified 907 tonne/day (1,000 TPD) (dry basis) of bituminous coal and generated 120 MW of electricity by IGCC operation. In addition, the plant was the first commercial

- sized Texaco gasifier used with a synthesis gas coo ler. The Cool Water plant operated from 1984 to 1989 and was a success in terms of operability, availability, and environmental performance. The Tampa Electric IGCC Clean Coal Technology Demonstration Project built on the Cool Water experience to demonstrate the use of the Texaco coal gasification process in an IGCC plant. The plant utilizes approximately 2,268 tonne/day (2,500 TPD) of coal in a single Texaco gasifier to generate a net of approximately 250 MW e . The syngas is cooled in a high

temp erature radiant heat exchanger, generating high

- pressure steam, and further cooled in convective heat exchangers (the radiant

- convective configuration). The particles in the cooled gas are removed in a water

- based scrubber. The cleaned gas then enters a hydrolysis reactor where COS is converted to H 2 

## S. After additional cooling, the syngas is sent to a conventional AGR unit, where H 2 

## S is absorbed by reaction with an amine solvent. H 2 

## S is removed from the amine by steam stripping and sent to a sulfuric ac id plant. The cleaned gas is sent to a General Electric MS 7001FA combustion turbine (CT).

190Carbon Dioxide Capture Sensitivity Analysis



## The Delaware Clean Energy Project is a coke gasification and CT repowering of an existing 130 MW coke

- fired boiler cogeneration power plant at the Motiva oil refin ery in Delaware City, Delaware. The Texaco coal gasification process was modified to gasify 1,814 tonne/day (2,000 TPD) of this low

- quality petroleum coke. The plant is designed to use all the fluid petroleum coke generated at Motiva’s Delaware City Plan t and produce a nominal 238,136 kg/h (525,000 lb/h) of 8.6 MPa (1 , 250 psig) steam, and 120,656 kg/h (266,000 lb/h) of 1.2 MPa (175 psig) steam for export to the refinery and the use/sale of 120 MW of electrical power. Environmentally, these new facilities help satisfy tighter NO x 

## and SO 2 

## emission limitations at the Delaware City Plant. Gasifier Capacity

– The largest GEE gasifier is the unit at Tampa Electric, which consists of the radiant

- convective configuration. The daily coal

- handling capacity of this unit is 2,268 tonnes (2,500 tons) of bituminous coal. The dry gas production rate is 0.19 million Nm 3 

## /h (6.7 million scfh) with an energy content of about 1,897 million kJ/h (HHV) (1,800 million Btu/h). This size matches the F Class CTs that are used at Tampa. Distinguishing Characteristics

– A key advantage of the GEE coal gasification technology is the extensive operating experience at full commercial scale. Furthermore, Tampa Electric is an IGCC power generation facility, operated by conventional ele ctric utility staff, and is environmentally one of the cleanest coal

- fired power plants in the world. The GEE gasifier also operates at the highest pressure of the three gasifiers in this study, 5.6 MPa (815 psia) compared to 4.2 MPa (615 psia) for CoP an d Shell.

Entrained

- flow gasifiers have fundamental environmental advantages over fluidized

- bed and moving

- bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert slag. The relatively high H 2 

## /CO ratio and CO 2 

## content of GE E gasification fuel gas helps achieve low nitrogen oxide (NO x 

## ) and CO emissions in even the higher

- temperature advanced CTs. The key disadvantages of the GEE coal gasification technology are the limited refractory life, the relatively high oxygen requireme nts and high waste heat recovery duty (synthesis gas cooler design). As with the other entrained

- flow slagging gasifiers, the GEE process has this disadvantage due to its high operating temperature. The disadvantage is magnified in the single

stage, slur ry feed design. The quench design significantly reduces the capital cost of syngas cooling, while innovative heat integration maintains good overall thermal efficiency although lower than the synthesis gas cooler design. Another disadvantage of the GEE p rocess is the limited ability to economically handle low

- rank coals relative to moving

- bed and fluidized

- bed gasifiers or to entrained

- flow gasifiers with dry feed. For slurry fed entrained gasifiers using low

- rank coals, developers of two

- stage slurry fe d gasifiers claim advantages over single

- stage slurry fed. Important Coal Characteristics

– The slurry feeding system and the recycle of process condensate water as the principal slurrying liquid make low levels of ash and soluble salts desirable coal char acteristics for use in the GEE coal gasification process. High ash levels increase the ratio of water

- to

- carbon in the feed slurry, thereby increasing the oxygen requirements. The slurry feeding also favors the use of high

- rank coals, such as bituminous coal,

191Carbon Dioxide Capture Sensitivity Analysis



## since their low inherent moisture content increases the moisture

- free solids content of the slurry and thereby reduces oxygen requirements.



# 4.2 Process Description
In this section the overall GEE gasification process is described. The system descripti on follows the Designs 2 through 4 block flow diagrams.



# 4.2.1 Coal Receiving and Storage The function of the Coal Receiving and Storage system is to unload, convey, prepare, and store the coal delivered to the plant. The scope of the system is from the trestl e bottom dumper and coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage silos. Coal receiving and storage is identical for all four IGCC plant designs. Operation Description

– The coal is delivered to the site by 100

- car unit trains comprised of 91 tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the coal to either the long

- term storage pile or to the reclaim area. The convey or passes under a magnetic plate separator to remove tramp iron and then to the reclaim pile. The reclaimer loads the coal into two vibratory feeders located in the reclaim hopper under the pile. The feeders transfer the coal onto a belt conveyor that tra nsfers the coal to the coal surge bin located in the crusher tower. The coal is reduced in size to 3 cm x 0 (11⁄4" x 0) by the crusher. A conveyor then transfers the coal to a transfer tower. In the transfer tower the coal is routed to the tripper, which loads the coal into one of three silos. Two sampling systems are supplied: the as

- received sampling system and the as

- fired sampling system. Data from the analyses are used to support the reliable and efficient operation of the plant.



# 4.2.2 Coal Grinding and Slurry Preparation
Coal is fed onto a conveyor by vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of about two ho urs and contains two hopper outlets. Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry water pumps. The coal slurry is discharged through a trommel screen into the rod mill discharge tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62

– 68 percent using bituminous coal [ 46 ]. The coal grinding system is equipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degree of dust suppression required depends on local

192Carbon Dioxide Capture Sensitivity Analysis



## environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal slurry solids suspended. The equipment in the coal grinding and slurry preparatio n system is fabricated of materials appropriate for the abrasive environment present in the system. The tanks and agitators are rubber lined. The pumps are either rubber

- lined or hardened metal to minimize erosion. Piping is fabricated of high

- density p olyethylene (HDPE).



# 4.2.3 Air Separation Unit (ASU) Choice and Integration In order to economically and efficiently support IGCC projects, air separation equipment has been modified and improved in response to production requirements and the consistent need to increase single train output. “Elevated pressure” air separation designs have been implemented that result in distillation column operating pressures that are about twice as high as traditional plants. In this study, the main air compressor discharge pre ssure was set at 1.3 MPa (190 psia) compared to a traditional ASU plant operating pressure of about 0.7 MPa (105 psia) [ 47 ]. For IGCC designs the elevated pressure ASU process minimizes power consumption and decreases the size of some of the equipment item s. When the air supply to the ASU is integrated with the gas turbine, the ASU operates at or near the supply pressure from the gas turbine’s air compressor.
4.2.3.1 Residual Nitrogen Injection The residual nitrogen that is available after gasifier oxygen and nitr ogen requirements have been met is often compressed and sent to the gas turbine. Since all product streams are being compressed, the ASU air feed pressure is optimized to reduce the total power consumption and to provide a good match with available compre ssor frame sizes. Increasing the diluent flow to the gas turbine by injecting residual nitrogen from the ASU can have a number of benefits, depending on the design of the gas turbine:

• Increased diluent increases mass flow through the turbine, thus increasing the power output of the gas turbine while maintaining optimum firing temperatures for syngas operation. This is particularly beneficial for locations where the ambient temperature and/or elevation are high and the gas turbine would normally ope rate at reduced output.

• By mixing with the syngas or by being injected directly into the combustor, the diluent nitrogen lowers the firing temperature (relative to natural gas) and reduces the formation of NOx. In this study, the ASU nitrogen product was u sed as the primary diluent with a design target of reducing the syngas lower heating value (LHV) to 4.5

- 4.8 MJ/Nm 3 

## (120

- 128 Btu/scf). If the amount of available nitrogen was not sufficient to meet this target, additional dilution was provided through syng as humidification, and if still more dilution was required, the third option was steam injection.

193Carbon Dioxide Capture Sensitivity Analysis



## 4.2.3.2 Air Integration Integration between the ASU and the CT can be practiced by extracting some, or all, of the ASU’s air requirement from the gas turbine. Medium Btu syngas streams result in a higher mass flow than natural gas to provide the same heat content to the gas turbine. Some gas turbine designs may need to extract air to maintain stable compressor or turbine operation in response to increased fuel flow r ates. Other gas turbines may balance air extraction against injection of all of the available nitrogen from the ASU. The amount of air extracted can also be varied as the ambient temperature changes at a given site to optimize year

- round performance.

A n important aspect of air

- integrated designs is the need to efficiently recover the heat of compression contained in the air extracted from the gas turbine. Extraction air temperature is normally in the range of 399

– 454 °C (750

– 850 °F), and must be cooled to the last stage main air compressor discharge temperature prior to admission to the ASU. High

- level recovery from the extracted air occurs by transferring heat to the gas turbine nitrogen diluents stream with a gas

- to

gas heat exchanger.

4.2.3.3 Elevated Press ure ASU Experience in Gasification The Buggenum, Netherlands unit built for Demkolec was the first elevated

- pressure, fully integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 TPD) of 95 percent purity oxygen for a S hell coal

- based gasification unit that fuels a Siemens V94.2 gas turbine. In normal operation at the Buggenum plant , the ASU receives all of its air supply from , and sends all residual nitrogen to , the gas turbine. The Polk County, Florida , ASU for the Ta mpa Electric IGCC is also an elevated

- pressure, 95 percent purity oxygen design that provides 1,832 tonnes/day (2,020 TPD) of oxygen to a GEE coal

- based gasification unit, which fuels a General Electric 7FA gas turbine. All of the nitrogen produced in the ASU is used in the gas turbine. The original design did not allow for air extraction from the CT. After a CT air compressor failure in January 2005, a modification was made to allow air extraction which in turn eliminated a bottleneck in ASU capacity an d increased overall power output [ 48 ].

4.2.3.4 ASU Basis For this study, air integration is used for Design 1 only. For Designs 2 through 4 , where higher CO 2 

## removal efficiencies are desired, all of the available combustion air is required to maintain mass flow th rough the turbine and hence maintain power output once the syngas is diluted to the target heating value. The amount of air extracted from the gas turbine in Design 1 is determined through a process that includes the following constraints:

• The CT output mu st be maintained at 232 MW.

• The diluted syngas must meet heating value requirements specified by a CT vendor, which ranged from 4.5

– 4.8 MJ/Nm 3 

## (120

– 128 Btu/scf) (LHV).

194Carbon Dioxide Capture Sensitivity Analysis



## For Design 1, about 4 percent of the pressurized CT air supply was extracted, which accounts for approximately 16.8 percent of the total ASU air requirement. It was not a goal of this project to optimize the integration of the CT and the ASU, although several recent papers have shown that providing 25

- 30 percent of the ASU air from the turbine compressor provides the best balance between maximizing plant output and efficiency without compromising plant availability or reliability [ 49 , 50 ].

4.2.3.5 Air Separation Plant Process Description [ 51 ]

T he ASU is designed to produce 95 mole percent O 2 

## for use in the gasifier. The plant is designed with two production trains, one for each gasifier. The air compressor is powered by an electric motor. Nitrogen is also recovered, compressed, and used as a diluent in the gas turbine combustor. A process schematic of a typical ASU is shown in Exhibit 4

- 1

. The air feed to the ASU is from one or two sources , depending on the plant design. The bulk of the air is supplied from a stand

- alone compressor, while a portion is extracted from the compressor of the gas turbine in Design 1 only. Air to the stand

- alone compressor is first filtered in a suction filter upstream of the compressor. This air filter removes particulate, which may tend to cause compressor wheel erosion and foul intercoolers. The filtered air is then compressed in the centrifugal compressor, with intercooling between each stage.

Air from the stand

- alone compressor is combined with the extraction air in Design 1, and the combined stream is cooled and fed to an adsorbent

- based pre

- purifier system. The adsorbent removes water, CO 2 

## , and C 4 

## + saturated hydrocarbons in the air. After passing throu gh the adsorption beds, the air is filtered with a dust filter to remove any adsorbent fines that may be present. Downstream of the dust filter a small stream of air is withdrawn to supply the instrument air requirements of the ASU. Regeneration of the ad sorbent in the pre

- purifiers is accomplished by passing a hot nitrogen stream through the off

- stream bed(s) in a direction countercurrent to the normal airflow. The nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube heat exchanger. The regeneration nitrogen drives off the adsorbed contaminants. Following regeneration, the heated bed is cooled to near normal operating temperature by passing a cool nitrogen stream through the adsorbent beds. The bed is re

- pressurized with air and placed on stream so that the current on

- stream bed(s) can be regenerated. The air from the pre

- purifier is then split into three streams. About 70 percent of the air is fed directly to the cold box. About 25 percent of the air is compressed in an air booster compressor. This boosted air is then cooled in an aftercooler against cooling water in the first stage and against chilled water in the second stage before it is fed to the cold box. The chiller utilizes low pressure process steam at 0.3 M Pa (50 psia). The remaining 5 percent of the air is fed to a turbine

- driven, single

- stage, centrifugal booster compressor. This stream is cooled in a shell and tube aftercooler against cooling water before it is fed to the cold box.

All three air feeds a re cooled in the cold box to cryogenic temperatures against returning product oxygen and nitrogen streams in plate

- and

- fin heat exchangers. The large air stream is fed directly to the first distillation column to begin the separation process. The second largest air

195Carbon Dioxide Capture Sensitivity Analysis



## stream is liquefied against boiling liquid oxygen before it is fed to the distillation columns. The third, smallest air stream is fed to the cryogenic expander to produce refrigeration to sustain the cryogenic separation process.

Inside the co ld box the air is separated into oxygen and nitrogen products. The oxygen product is withdrawn from the distillation columns as a liquid and is pressurized by a cryogenic pump. The pressurized liquid oxygen is then vaporized against the high

- pressure air feed before being warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the centrifugal compressor with intercooling between each stage of compression. The compressed oxygen is then fed to the gasification unit. Nitrogen is produced from the cold box at two pressure levels. Low

- pressure nitrogen is split into two streams. The majority of the low

- pressure nitrogen is compressed and fed to the gas turbine as diluent nitrogen. A small portion of the nitrogen is used as the re generation gas for the pre

- purifiers and recombined with the diluent nitrogen. A high

- pressure nitrogen stream is also produced from the cold box and is further compressed before it is also supplied to the gas turbine.

Exhibit 4
- 1 Typical ASU Process Schematic

Air Air Filter Main Air Compressor CWS

CWR Steam Cond

.
1st Stage DCA 2nd Stage DCA Prepurifiers Booster Air Compressor

Turbine Air Booster Regen Heater Steam

Cond

. Regeneration Nitrogen

Regen . N2 Blower

Liq . Oxygen Pump Turbine Cryogenic Air Separation Unit

Single Train

GT Nitrogen HP Oxygen Oxygen Compressor

GT Nitrogen Compressor

Chiller Air from Gas Turbine

CWS

CWR

1 2

15 12

10

3 5 7

6

8 9



## 196Carbon Dioxide Capture Sensitivity Analysis



# 4.2.4 Gasification
Each IGCC plant design in this study utilizes two gasification trains to process the Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operates at maximum capacity. Th e largest operating GEE gasifier is the 2,268 tonne/day (2,500 TPD) unit at Polk Power Station. However, that unit operates at about 2.8 MPa (400 psia). The gasifier in this study, which operates at 5.6 MPa (815 psia), will be able to process more coal a nd maintain the same gas residence time. The slurry feed pump takes suction from the slurry run tank, and the discharge is sent to the feed injector of the GEE gasifier. Oxygen from the ASU is vented during preparation for startup and is sent to the feed injector during normal operation. The ASU supplies 95 mole percent oxygen to the GEE gasifiers and the Claus plant. Carbon conversion in the gasifier is assumed to be 98 percent , including a fines recycle stream. The gasifier vessel is a refractory

- lined , high

- pressure combustion chamber. The coal slurry feedstock and oxygen are fed through a fuel injector at the top of the gasifier vessel. The coal slurry and the oxygen react in the gasifier at 5.6 MPa (815 psia) and 1,316 °C (2,400 ° F) to produce syng as. The syngas consists primarily of hydrogen and carbon monoxide, with lesser amounts of water vapor and CO 2 

## , and small amounts of hydrogen sulfide, carbonyl sulfide, methane, argon, and nitrogen. The heat in the gasifier liquefies coal ash. Hot syngas and molten solids from the reactor flow downward into a radiant heat exchanger where the syngas is cooled.



# 4.2.5 Raw Gas Cooling/Particulate Removal Syngas is cooled from 1,316 °C (2,400 °F) to 677 °C (1 , 250 °F) in the radiant synthesis gas cooler and the molten slag solidifies in the process. The solids collect in the water sump at the bottom of the gasifier and are removed periodically using a lock hopper system. The waste heat from this cooling is used to generate high

- pressure saturated steam. Boiler feedw ater in the tubes is saturated, and then steam and water are separated in a steam drum. This steam then forms part of the general heat recovery system that provides steam to the steam turbine. The syngas exiting the radiant cooler is directed downwards by a dip tube into a water sump. Most of the entrained solids are separated from the syngas at the bottom of the dip tube as the syngas goes upwards through the water. The syngas exits the quench chamber saturated at a temperature of 223 °C (450 °F)

. The slag handling system removes solids from the gasification process equipment. These solids consist of a small amount of unconverted carbon and essentially all of the ash contained in the feed coal. These solids are in the form of glass, which fully en capsulates any metals. Solids collected in the water sump below the radiant synthesis gas cooler are removed by gravity and forced circulation of water from the lock hopper circulating pump. The fine solids not removed from the bottom of the quench water sump remain entrained in the water circulating through the quench chamber. In order to limit the amount of solids recycled to the quench chamber, a continuous blowdown stream is removed from the bottom of the syngas quench. The blowdown

197Carbon Dioxide Capture Sensitivity Analysis



## is sent to the v acuum flash drum in the black water flash section. The circulating quench water is pumped by circulating pumps to the quench gasifier.



# 4.2.6 Syngas Scrubber/Sour Water Stripper
Syngas exiting the water quench passes to a syngas scrubber where a water wash is us ed to remove remaining chlorides and particulate. The syngas exits the scrubber still saturated at 206 °C (403 °F). The sour water stripper removes NH 3 

## , SO 2 

## , and other impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from synthesis gas coolers. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from the liquid an d sent to the sulfur recovery unit. Remaining water is sent to wastewater treatment.



# 4.2.7 Water Gas Shift Reactors
In this study, IGCC Designs 2 through 4 include water gas shift (WGS) reactor(s). The WGS reaction convert s most of the syngas carbon monoxide ( CO) to hydrogen and CO 2 

## by reacting the CO with water over a bed of catalyst. A typical offering from a commercial catalyst vendor is a steam

- to

- dry gas (S:DG) molar ratio of 0.3 at the outlet of the final shift reactor. The function of this excess steam is to drive the shift equilibrium toward the products. The reaction consumes one mol of water per mol of CO converted, and releases heat in the process:

H 2 

## O + CO  H 2 

## + CO 2 

## ∆ H rxn 

## = - 17,697 Btu/lb

- mol (1) The WGS reactor(s) can be located either upstream of the AGR system (sour gas shift) or immediately downstream (sweet gas shift). If the WGS is located downstream of the AGR, then the metallurgy of the unit is less stringent but additional equipment must be added to the process. Products from the gasifi er are humidified and contain a portion of the water vapor necessary to meet the water

- to

- gas criteria at the reactor inlet. If the CO converter is located downstream of the AGR, then the gasifier product would first have to be cooled and the free water separated and treated. Then additional steam would have to be generated and re

- injected into the WGS feed to meet the required water

- to

- gas ratio. If the CO converter is located upstream of the AGR, no additional equipme nt is required since the WGS react or(s) also promote carbonyl sulfide (COS) hydrolysis without a separate catalyst bed.

COS + H 2 

## O  H 2 

## S + CO 2 

## ∆ H rxn 

## = - 14,526 Btu/lb

- mol (2)

This reaction converts sulfur to a form (H 2 

## S) that is removed more readily than COS in an AGR system, helping to meet emission specifications. The SelexolTM solvent’s affinity for H 2 

## S is nearly 4 times greater than it is for COS [ 52 ]. Since this physical solvent’s driving force is partial pressure, and sulfur concentrations are relativel y low to begin with, conversion to H 2 

## S (which the SelexolTM solvent can separate more easily) is effective in reducing the size of the SelexolTM process, while achieving the low sulfur levels required by local permitting agencies

198Carbon Dioxide Capture Sensitivity Analysis



## (this analysis assumes 0.012 8 lb SO 2 

## /MMBtu). Therefore , for this study the WGS was located upstream of the AGR and is referred to as sour gas shift (SGS). Depending on the plant design, the SGS consists of either two paths of parallel fixed

- bed reactors arranged in series, or a sing le, parallel fixed

- bed reactor. Cooling is provided between the series of reactors to control the exothermic temperature rise. The parallel set of reactors is required due to the high gas mass flow rate. The heat exchanger after the first SGS reactor is used to vaporize water. The heat exchanger after the second SGS reactor is used to raise IP steam, which then passes through the reheater section of the HRSG in the GEE IGCC plant design. Approximately 96 percent conversion of the CO is achieved in the GEE design. The default S:DG ratio (0.3) represents a typical offering by a commercial catalyst vendor. The WGS and COS hydrolysis reactions occur at locations within the catalyst matrix, referred to as active sites, where water molecules have formed wea k chemical bonds with the catalyst material

. In order for chemical bonding of water molecules to occur on the catalyst surface, diffusion of H 2 

## O through the bulk syngas must first occur. At the base case S:DG ratio, diffusion rates are fast enough such th at there are adequate active catalyst sites on which the reactions can occur. This helps to maintain reasonable reactor sizes and costs. A key portion of this study is devoted to optimizing the WGS step for lower degrees of carbon capture. The three me thods that will be investigated are : ( 1) to bypass a portion of syn gas around the shift reactor(s); ( 2) to use less shift steam (a S :DG ratio of 0.25 will be used); and ( 3) to use one shift reactor instea d of two (D 2). These will be used in combination with one another in order to arrive at the optimum configuration for each level of CO 2 

## capture.



# 4.2.8 Mercury Removal An IGCC power plant has the potential of removing mercury in a more simple and cost

- effective manner than conventional PC plants. This is becau se mercury can be removed from the syngas at elevated pressure and prior to combustion so that syngas volumes are much smaller than flue gas volumes in comparable PC cases. A conceptual design for a carbon bed adsorption system was developed for mercury c ontrol in the IGCC plants being studied. Data on the performance of carbon bed systems were obtained from the Eastman Chemical Company, which uses carbon beds at its syngas facility in Kingsport, Tennessee [ 53 ]. The coal mercury content (0.15 ppm dry) and carbon bed removal efficiency (95 percent) were discussed previously in Sections 2.2 and 2.4 . IGCC

- specific design considerations are discussed below.

Carbon Bed Location

– The packed carbon bed vessels are located upstream of the sulfur recovery unit and syngas enters at a temperature near 35 °C (95 °F). Eastman Chemical also operates their beds ahead of their sulfur recovery unit at a temperature of 30 °C (86 °F) [ 53 ].

Process Parameters

– An empty vessel basi s gas residence time of approximately 20 seconds was used based on Eastman Chemical’s experience [ 53 ]. Allowable gas velocities are limited by considerations of particle entrainment, bed agitation, and pressure drop. One

- foot

- per

- second superficial velocity is in the middle of the range normally encountered and was selected for this application.

199Carbon Dioxide Capture Sensitivity Analysis



## The bed density of 30 lb/ft 3 

## was based on the Calgon Carbon Corpor ation HGR

- P sulfur

impregnated pelletized activated carbon. These parameters determined the size of the vessels and the amount of carbon required. Each gasifier train has one mercury removal bed and there are two gasifier trains in each IGCC case, result ing in two carbon beds per case. Carbon Replacement Time

– Eastman Chemicals replaces its bed every 18 to 24 months [ 53 ]. However, bed replacement is not because of mercury loading, but for other reasons including:

• A buildup in pressure drop

• A buildup of water in the bed

• A buildup of other contaminants For this study, a 24 month carbon replacement cycle was assumed. Under these assumptions, the mercury loading in the bed would build up to 0.6

– 1.1 weight percent (wt%). Mercury capacity of sulfur

- impregnated carbon can be as high as 20 wt%. The mercury

- laden carbon is considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.



# 4.2.9 A cid Gas Removal (AGR) Process Selection Gasification of coal to generate power produces a syngas that must be treated prior to further utilization. A portion of the treatment consists of acid gas removal (AGR) and sulfur recovery. The environmental targe t for these IGCC plant designs is 0.0128 lb SO 2 

## /MMBtu, which requires that the total sulfur content of the syngas be reduced to less than 30 ppmv. This includes all sulfur species, but in particular the total of COS and hydrogen sulfide (H 2 

## S), thereby res ulting in stack gas emissions of less than 4 ppmv SO 2 

## . 4.2.9.1 COS Hydrolysis The use of COS hydrolysis pretreatment in the feed to the AGR process provides a means to reduce the COS concentration. This method was first commercially proven at the Buggenum plant, and was also used at both the Tampa Electric and Wabash River IGCC projects. Several catalyst manufacturers including Haldor Topsoe and Porocel offer a catalyst that promotes the COS hydrolysis reaction. The COS hydrolysis reactor design employed in this study , for IGCC Designs 1 through 3 , is based on information from Porocel. However, the WGS reactor ( s ) also reduce COS to H 2 

## S as discussed in Section 4.2.7

. The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The
rea ction is represented as follows:

COS + H 2 

## O ↔ CO 2 

## + H 2 

## S Since the reaction is exothermic, higher conversion is achieved at lower temperatures. However, at lower temperatures the reaction kinetics are slower. Based on the feed gas for this evaluation, Porocel recommended a temperature of 177 to 204°C (350 to 400°F). Since the exit gas COS concentrat ion is critical to the amount of H 2 

## S that must be removed with the AGR process, a retention time of 50

- 75 seconds was used to achieve 99.5 percent conversion of the COS. The

200Carbon Dioxide Capture Sensitivity Analysis



## Porocel activated alumina

- based catalyst, designated as Hydrocel 640 catalyst, pr omotes the COS hydrolysis reaction without promoting reaction of H 2 

## S and CO to form COS and H 2 

## . Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of
non

- reacting components. Therefore, the reaction is essential ly isothermal. The product gas, now containing less than 4 ppmv of COS, is cooled prior to entering the mercury removal process and the AGR.

4.2.9.2 Sulfur Removal

H 2 

## S removal generally consists of absorption by a regenerable solvent. The most commonly used tec hnique is based on countercurrent contact with the solvent. Acid gas

- rich solution from the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The regenerated lean solution is then cooled and recirculated to the top of the absorber, completing the cycle. Exhibit 4

- 2 is a simplified diagram of the AGR process [ 52 ].

There are well over 30 AGR processes in common commercial use throughout the oil, chemical, and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and planned gasifiers shows that only six AGR processes are represented: Rectisol ® 

## , Sulfinol, methyldiethanolamine (MDEA), SelexolTM, aqueous di

- isoproponal amine (DIPA), and FLEXSORB [ 52 ]. These processes can be separated into three general types: chemical reagents, physical solvents, and hybrid solvents.

Exhibit 4
- 2 Flow Diagram for a Conventional AGR Unit

Treated

Gas

Cooler

Lean Solvent L/R Exchanger

Rich Solvent Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Feed Gas Treated Gas

Cooler

Lean Solvent L/R Exchanger

Rich Solvent Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Feed Gas



## Chemical Solvents Frequently used for AGR, chemical solvents are more suitable than physical or hybrid solvents for applications at lower operating pressures. The chemical nature of acid gas absorption makes solution loading and circulation less dependent on the acid gas partial pressure. Because the

201Carbon Dioxide Capture Sensitivity Analysis



## solution is aqueous, co

- absorption of hydrocarbons is minimal. In a conventional amine unit, the chemical solvent reacts exothermically with the acid gas constituents. They form a weak chemical bond that can be bro ken, releasing the acid gas and regenerating the solvent for reuse. In recent years MDEA, a tertiary amine, has acquired a much larger share of the gas

- treating market. Compared with primary and secondary amines, MDEA has superior capabilities for selecti vely removing H 2 

## S in the presence of CO 2 

## , is resistant to degradation by organic sulfur compounds, has a low tendency for corrosion, has a relatively low circulation rate, and consumes less energy. Several MDEA

- based solvents that are formulated for high H 2 

## S selectivity are commercially

- available. Chemical reagents are used to remove the acid gases by a reversible chemical reaction of the acid gases with an aqueous solution of various alkanolamines or alkaline salts in water. Exhibit 4

- 3 lists commonly used chemical reagents along with principal licensors that use them in their processes. The process consists of an absorber and regenerator, which are connected by a circulation of the chemical reagent aqueous solution. The absorber contacts the lean solution with the main gas stream (at pressure) to remove the acid gases by absorption/ reaction with the chemical solution. The acid

- gas

- rich solution is reduced to low pressure and heated in the stripper to reverse the reactions and strip the acid gas. The acid

- gas

- lean solution leaves the bottom of the regenerator stripper and is cooled, pumped to the required pressure and recirculated back to the absor ber. For some amines, a filter and a separate reclaiming section (not shown) are needed to remove undesirable reaction byproducts.

Exhibit 4
- 3 Common Chemical Reagents Used in AGR Processes
Chemical Reagent Acronym Process Licensors Using the Reagent
Monoethanolamine MEA Dow, Exxon, Lurgi, Union Carbide
Diethanolamine DEA Elf, Lurgi Diglycolamine DGA Texaco, Fluor
Triethanolamine TEA AMOCO Diisopropanolamine DIPA Shell
Methyldiethanolamine MDEA BASF, Dow, Elf, Snamprogetti, Shell, Union Carbide, Coastal Chemical
Hindered amine Exxon

Potassium carbonate “hot pot” Eickmeyer, Exxon, Lurgi, Union Carbide



## Typically, the absorber temperature is 27 to 49 °C (80 to 120 °F) for amine processes, and the regeneration temperature is the boiling point of the solutions, generally 104 to 127 °C (220 to 260 °F). The liquid circulation rates can vary widely, depending on the amount of acid gas being captured. However, the most suitable processes are those that will dissolve 2 to 10 scf acid gas per gallon of solution circulated. Steam consumption can vary widely also: 0.7 to 1.5 pounds per gallon of liquid is typical

.

202Carbon Dioxide Capture Sensitivity Analysis



## The major advantage of these systems is the ability to remove acid gas to low levels a t low to moderate H 2 

## S partial pressures. Physical Solvents Physical solvents involve absorption of acid gases into certain organic solvents that have a high solubility for acid gases. As the name implies, physical solvents involve only the physical solu tion of acid gas

– the acid gas loading in the solvent is proportional to the acid gas partial pressure (Henry’s Law). Physical solvent absorbers are usually operated at lower temperatures than is the case for chemical solvents. The solution step occurs at high pressure and at or below ambient temperature while the regeneration step (dissolution) occurs by pressure letdown and indirect stripping with low

- pressure 0.45 MPa (65 psia) steam. It is generally accepted that physical solvents become increasingl y economical, and eventually superior to amine capture, as the partial pressure of acid gas in the syngas increases. The physical solvents are regenerated by multistage flashing to low pressures. Because the solubility of acid gases increases as the tempe rature decreases, absorption is generally carried out at lower temperatures, and refrigeration is often required. Most physical solvents are capable of removing organic sulfur compounds. Exhibiting higher solubility of H 2 

## S than CO 2 

## , they can be designed f or selective H 2 

## S or total acid gas removal. In applications where CO 2 

## capture is desired the CO 2 

## is flashed off at various pressures, which reduces the compression work and parasitic power load associated with sequestration. Physical solvents co

- absorb he avy hydrocarbons from the feed stream. Since heavy hydrocarbons cannot be recovered by flash regeneration, they are stripped along with the acid gas during heated regeneration. These hydrocarbon losses result in a loss of valuable product and may lead to CO 2 

## contamination. Several physical solvents that use anhydrous organic solvents have been commercialized. They include the SelexolTM process, which uses dimethyl ether of polyethylene glycol as a solvent; Rectisol ® 

## , with methanol as the solvent; Puriso l, which uses N

- methyl

- 2

- pyrrolidone (NMP) as a solvent; and the propylene

- carbonate process.

Exhibit 4

- 4 is a simplified flow diagram for a physical reagent type acid gas removal process [ 52 ]. Common p hysical solvent processes, along with their licensors, are listed in Exhibit 4

- 5

.

203Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 4 Physical Solvent AGR Process Simplified Flow Diagram

Treated

Gas

Cooler

Lean Solvent L/R Exchanger Rich Solvent

Feed Gas Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Flash Gas Treated

Gas

Cooler

Lean Solvent L/R Exchanger Rich Solvent

Feed Gas Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Flash Gas



### Exhibit 4
- 5 Common Physical Solvents Used in AGR Processes



## Solvent Solvent/Process Trade Name Process Licensors Dimethyl ether of poly ethylene glycol SelexolTM UOP

Methanol Rectisol ® 

### Linde AG and Lurgi
Methanol and toluene Rectisol II Linde AG
N

— methyl pyrrolidone Purisol Lurgi Polyethylene glycol and dialkyl ethers Sepasolv MPE BASF
Propylene carbonate Fluor Solvent Fluor Tetrahydrothiophenedioxide Sulfolane Shell Tributyl phosphate Estasolvan Uhde and IFP


## Hybrid Solvents Hybrid solvents combine the high treated

- gas purity offered by chemical solvents with the flash regeneration and lower energy requirements of physical solvents. Some examples of hybrid solvents are Sulfinol, Flexsorb PS, and Ucarsol LE.

204Carbon Dioxide Capture Sensitivity Analysis



## Sulfinol is a mixture of sulfolane (a physical solvent), DIPA or MDEA (chemical solvent), and water. DIPA is used when total acid gas removal is specified, while MDEA p rovides for selective removal of H 2 

## S.

Flexsorb PS is a mixture of a hindered amine and an organic solvent. Physically similar to Sulfinol, Flexsorb PS is very stable and resistant to chemical degradation. High treated

- gas purity, with less than 50 ppmv o f CO 2 

## and 4 ppmv of H 2 

## S, can be achieved. Both Ucarsol LE

701, for selective removal, and LE

- 702, for total acid gas removal, are formulated to remove mercaptans from feed gas. Mixed chemical and physical solvents combine the features of both systems. Th e mixed solvent allows the solution to absorb an appreciable amount of gas at high pressure. The amine portion is effective as a reagent to remove the acid gas to low levels when high purity is desired. Mixed solvent processes generally operate at absorbe r temperatures similar to those of the amine

- type chemical solvents and do not require refrigeration. They also retain some advantages of the lower steam requirements typical of the physical solvents. Common mixed chemical and physical solvent processes, along with their licensors, are listed in Exhibit 4

- 6 . The key advantage of mixed solvent processes is their apparent ability to remove H 2 

## S and, in some cases, COS to meet very stringent purified gas specifications.

Exhibit 4
- 6 Common Mixed Solvents Used in AGR Processes
Solvent/Chemical Reagent Solvent/Process Trade Name Process Licensors
Methanol/MDEA or diethylamine Amisol Lurgi

Sulfolane/MDEA or DIPA Sulfinol Shell
Methanol and toluene Selefining Snamprogetti
(Unspecified) /MDEA FLEXSORB PS Exxon



## Exhibit 4

- 7 shows reported equilibrium solubility data for H 2 

## S and CO 2 

## in various representative solvents [ 52 ]. The solubility is expressed as standard cubic feet of gas per gallon liquid per atmosphere gas partial pressure. The figure illustrates the relative solubilities of CO 2 

## and H 2 

## S in different solvents and the effects of temperature. More importantly, it shows an order of magnitude higher solubility of H 2 

## S over CO 2 

## at a given temperature, which gives rise to the selective absorption of H 2 

## S in physical solvents. It also illustrates that the acid gas solubility in physical solvents increases with lower sol vent temperatures.

205Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 7 Equilibrium Solubility Data on H 2 

### S and CO 2 

### in Various Solvents



## The ability of a process to selectively absorb H 2 

## S may be further enhanced by the relative absorption rates of H 2 

## S and CO 2 

## . Thus, some processes, besides using equilibrium solubility differences, will use absorption rate differences between the two acid gases to achieve selectivity. This is particularly true of the amine processes where the CO 2 

## and H 2 

## S absorptio n rates are very different.

4.2.9.3 SelexolTM System There are numerous commercial AGR processes that could meet the sulfur environmental target of this study. The most frequently used AGR systems (SelexolTM, Sulfinol, MDEA, and Rectisol ® 

## ) have all been used with the GE E gasifier in various applications. For Design 1, a

206Carbon Dioxide Capture Sensitivity Analysis



## single

- stage SelexolTM system was chosen based on the GE E gasifier operating at a high pressure (815 psia), which favors the physical solvent used in the SelexolTM process. For Designs 2 through 4, a two

- stage SelexolTM process was employed for selective H 2 

## S removal and bulk CO 2 

## capture. The two

- stage SelexolTM system was chosen based on the GE E gasifier operating at a high pressure (815 psia), which favors the physical solvent used in the SelexolTM pro cess. A brief process description follows. Untreated syngas enters the first of two absorbers where H 2 

## S is preferentially removed using loaded solvent from the CO 2 

## absorber. The gas exiting the H 2 

## S absorber passes through the second absorber where CO 2 

## is removed using first flash regenerated, chilled solvent followed by thermally regenerated solvent added near the top of the column. The treated gas exits the absorber and is sent either directly to the CT or is partially humidified prior to entering the C T

. A portion of the gas can also be used for coal drying, when required. The amount of hydrogen recovered from the syngas stream is dependent on the SelexolTM process design conditions. In this study, hydrogen recovery is 99.4 percent. The minimal hydrog en slip to the CO 2 

## sequestration stream maximizes the overall plant efficiency. The SelexolTM plant cost estimates are based on a plant designed to recover this high percentage of hydrogen. For model simplification, a nominal recovery of 100 percent was u sed with the assumption that the additional 0.6 percent hydrogen sent to the CT would have a negligible impact on overall system performance.

The CO 2 

## loaded solvent exits the CO 2 

## absorber and a portion is sent to the H 2 

## S absorber, a portion is sent to a re absorber and the remainder is sent to a series of flash drums for regeneration. The CO 2 

## product stream is obtained from the three flash drums, and after flash regeneration the solvent is chilled and returned to the CO 2 

## absorber. The rich solvent exiting t he H 2 

## S absorber is combined with the rich solvent from the reabsorber and the combined stream is heated using the lean solvent from the stripper. The hot, rich solvent enters the H 2 

## S concentrator and partially flashes. The remaining liquid contacts nitro gen from the ASU and a portion of the CO 2 

## along with lesser amounts of H 2 

## S and COS are stripped from the rich solvent. The stripped gases from the H 2 

## S concentrator are sent to the reabsorber where the H 2 

## S and COS that were co

- stripped in the concentrator are transferred to a stream of loaded solvent from the CO 2 

## absorber. The clean gas from the reabsorber is combined with the clean gas from the H 2 

## S absorber and sent to the CT

. The solvent exiting the H 2 

## S concentrator is sent to the stripper where the abso rbed gases are liberated by hot gases flowing up the column from the steam heated reboiler. Water in the overhead vapor from the stripper is condensed and returned as reflux to the stripper or exported as necessary to maintain the proper water content of the lean solvent. The acid gas from the stripper is sent to the Claus plant for further processing. The lean solvent exiting the stripper is first cooled by providing heat to the rich solvent, then further cooled by exchange with the product gas and fina lly chilled in the lean chiller before returning to the top of the CO 2 

## absorber. A Selexol process flow diagram is shown in Exhibit 4

- 8

.

207Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 8 Generic Two
- Stage SelexolTM Process Flow Diagram

Steam Stage 1

H 2 S Absorber

H 2 S Concentrator Rich Flash Drum CO 2 Rich

H 2 S / CO 2 Acid Gas Stripper MP Flash

LP Flash Stage 2

CO 2 Absorber

HP Flash

Treated Gas H 2 S / CO 2 Rich Lean Selexol

CO 2 Rich Semi

- Lean Selexol

Feed Gas Loaded Solvent Chiller

Feed / Product Exchanger

Rich Solvent Pump CO 2 Recycle Cooler CO 2 Recycle Compressor Semi

- Lean Solvent Pump Semi

- Lean Solvent Chiller

Loaded Solvent Pump

LP Lean Solvent Pump Lean Solvent Chiller

Lean / Rich Exchanger

Lean Solvent Cooler HP Lean Solvent Pump

Acid Gas To Claus Plant / ZnO Bed Stripping

Gas Compressor

Combined CO 2 Product

Rich Flash

Gas Compressor



# 4.2.10 CO 2 

# Compression and Dehydration
CO 2 

## from the two

- stage SelexolTM unit in IGCC De signs 2 through 4 is flashed at three pressure levels to separate CO 2 

## and decrease H 2 

## losses to the CO 2 

## pipeline. The HP CO 2 

## stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 

## absorber. The MP CO 2 

## stream is flashed at 1.0 MPa (149.7 psia). The LP CO 2 

## stream, is flashed at 0.1 MPa (16.7 psia), and is compressed to 1.0 MPa (149.5 psia) and combined with the MP CO 2 

## stream. The combined stream is compressed from 2.1 MPa (300 psia) to a supercritical condition at 15.3 MPa (2 , 215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

## stream is dehydrated to a dewpoint of

- 40 oC (

- 40 °F) with triethylene glycol. The raw CO 2 

## stream from the SelexolTM process contains over 99 pe rcent CO 2 

## with the balance primarily hydrogen. The CO 2 

## is transported to the plant fence line and is sequestration ready. CO 2 

## TS&M costs were estimated using the methodology described in Section 2.7

.


# 4.2.11 Sulfur Recovery/Tail Gas Cleanup Process Selection Currently, most of the world’s sulfur is produced from the acid gases coming from gas treating. The Claus process remains the mainstay for sulfur recovery. Conventio nal three

- stage Claus plants, with indirect reheat and feeds with a high H 2 

## S content, can approach 98 percent sulfur recovery efficiency. However, since environmental regulations have become more stringent, sulfur recovery plants are required to recover s ulfur with over 99.8 percent efficiency. To meet these stricter regulations, the Claus process underwent various modifications and add

- ons.

208Carbon Dioxide Capture Sensitivity Analysis



## The add

- on modification to the Claus plant selected for this study can be considered a separate option from the Cla us process. In this context, it is often called a tail gas treating unit (TGTU) process.
4.2.11.1 The Claus Process The Claus process converts H 2 

## S to elemental sulfur via the following reactions:

H 2 

## S + 3/2 O 2 

## ↔ H 2 

## O + SO 2


## 2H 2 

## S + SO 2 

## ↔ 2H 2 

## O + 3S
The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is:

3H 2 

## S + 3/2 O 2 

## ↔ 3H 2 

## O + 3S The sulfur in the vapor phase exists as S 2 

## , S 6 

## , and S 8 

## molecular species, with the S 2 

## predominant at higher temperatures, and S 8 

## predominant at lower temperatu res. A simplified process flow diagram of a typical three

- stage Claus plant is shown in Exhibit 4

- 9 [ 52 ]. One

- third of the H 2 

## S is burned in the furnace with oxygen from the air to give sufficient SO 2 

## to react with the remaining H 2 

## S. Since these reactions are highly exothermic, a waste heat bo iler that recovers this heat to generate high

- pressure steam usually follows the furnace. Sulfur is condensed in a condenser that follows the high

- pressure steam recovery section. Low

- pressure steam is raised in the condenser. The tail gas from the firs t condenser then goes to several catalytic conversion stages, usually 2 to 3, where the remaining sulfur is recovered via the Claus reaction. Each catalytic stage consists of gas preheat, a catalytic reactor, and a sulfur condenser. The liquid sulfur goe s to the sulfur pit, while the tail gas proceeds to the incinerator or for further processing in a TGTU.

4.2.11.2 Claus Plant Sulfur Recovery Efficiency The Claus reaction is equilibrium limited, and sulfur conversion is sensitive to the reaction temperature. The highest sulfur conversion in the thermal zone is limited to about 75 percent. Typical furnace temperatures are in the range from 1 , 093 to 1427 °C (2 , 000 to 2 , 600 °F), and as the temperature decreases, conversion increases dramatically.

209Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 9 Typical Three
- Stage Claus Sulfur Plant



## Claus plant sulfur r ecovery efficiency depends on many factors , including :

• H 2 

## S concentration of the feed gas

• Number of catalytic stages

• Gas reheat method In order to keep Claus plant recovery efficiencies approaching 94 to 96 percent for feed gases that contain about 20 to 50 percent H 2 

## S, a split

- flow design is often used. In this version of the Claus plant, part of the feed gas is bypassed around the furnace to th e first catalytic stage, while the rest of the gas is oxidized in the furnace to mostly SO 2 

## . This results in a more stable temperature in the furnace.

4.2.11.3 Oxygen

- Blown Claus Large diluent streams in the feed to the Claus plant, such as N 2 

## from combustion air, or a high CO 2 

## content in the feed gas, lead to higher cost Claus processes and any add

- on or tail gas units. One way to reduce diluent flows through the Claus plant and to obtain stable temperatures in the furnace for dilute H 2 

## S streams is the oxygen

- blo wn Claus process. The oxygen

- blown Claus process was originally developed to increase capacity at existing conventional Claus plants and to increase flame temperatures of low H 2 

## S content gases. The process has also been used to provide the capacity and op erating flexibility for sulfur plants where the feed gas is variable in flow and composition such as often found in refineries. The application of the process has now been extended to grass roots installations, even for rich H 2 

## S

210Carbon Dioxide Capture Sensitivity Analysis



## feed streams, to provide o perating flexibility at lower costs than would be the case for conventional Claus units. At least four of the recently built gasification plants in Europe use oxygen enriched Claus units. Oxygen enrichment results in higher temperatures in the front

- end f urnace, potentially reaching temperatures as high as 1 , 593 to 1 , 649 °C (2 , 900 to 3 , 000 °F) as the enrichment moves beyond 40 to 70 vol percent O 2 

## in the oxidant feed stream. Although oxygen enrichment has many benefits, its primary benefit for lean H 2 

## S fe eds is a stable furnace temperature. Sulfur recovery is not significantly enhanced by oxygen enrichment. Because the IGCC process already requires an ASU, the oxygen

- blown Claus plant was chosen for all plant designs.

4.2.11.4 Tail Gas Treating In many refinery a nd other conventional Claus applications, tail gas treating involves the removal of the remaining sulfur compounds from gases exiting the sulfur recovery unit. Tail gas from a typical Claus process, whether a conventional Claus or one of the extended vers ions of the process, usually contains small but varying quantities of COS, CS 2 

## , H 2 

## S, SO 2 

## , and elemental sulfur vapors. In addition, there may be H 2 

## , CO, and CO 2 

## in the tail gas. In order to remove the rest of the sulfur compounds from the tail gas, all of the sulfur

- bearing species must first be converted to H 2 

## S. Then, the resulting H 2 

## S is absorbed into a solvent and the clean gas vented or recycled for further processing. The clean gas resulting from the hydrolysis step can undergo further cleanup in a dedicated absorption unit or be integrated with an upstream AGR unit. The latter option is particularly suitable with physical absorption solvents. The approa ch of treating the tail gas in a dedicated amine absorption unit and recycling the resulting acid gas to the Claus plant is the one used by the Shell Claus Off

- gas Treating (SCOT) process. With tail gas treatment, Claus plants can achieve overall removal efficiencies in excess of 99.9 percent. In the case of IGCC applications, the tail gas from the Claus plant can be catalytically hydrogenated and then recycled back into the system with the choice of location being technology dependent, or it can be treate d with a SCOT

- type process. For the GEE gasifier, the Claus plant tail gas is hydrogenated, water is separated, and the tail gas is compressed and returned to the SelexolTM process for further treatment. GEE experience at the Polk Power Station is not rel evant to this study since the acid gas is converted to sulfuric acid rather than sulfur and the tail gas, containing 150

- 250 ppm SO 2 

## , is discharged through a dedicated stack [ 46 ].

4.2.11.5 Flare Stack

A self

- supporting, refractory

- lined, carbon steel flare stack is typically provided to combust and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in each IGCC plant design a flare stack was provided for syngas dumping during startup, shutdown, etc. This flare stack eliminates the need for a separate Claus plant flare.



# 4.2.12 Slag Handling The slag handling system conveys, stores, and disposes of slag removed from the gasification process. Spent material drains from the gasifier bed into a water bath in the bottom of the

211Carbon Dioxide Capture Sensitivity Analysis



## gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into pea

sized fragments. A slag/water slurry that is between 5 and 10 percent solids leaves the GEE gasifier pressure boundary through the use of lockhoppers to a series of dewatering bins. The slag is dewatered, the water is clarifi ed and recycled and the dried slag is transferred to a storage area for disposal. The specifics of slag handling vary among the gasification technologies regarding how the water is separated and the end uses of the water recycle streams. In this study, th e slag bins were sized for a nominal holdup capacity of 72 hours of full

- load operation. At periodic intervals, a convoy of slag

- hauling trucks will transmit the unloading station underneath the hopper and remove a quantity of slag for disposal. Approxim ately ten truckloads per day are required to remove the total quantity of slag produced by the plant operating at nominal rated power. While the slag is suitable for use as a component of road paving mixtures, it was assumed in this study that the slag wo uld be landfilled at a specified cost just as the ash from the PC boiler cases is assumed to be landfilled at the same per ton cost.



# 4.2.13 Power Island
4.2.13.1 Combustion Turbine The gas turbine generator selected for this application is representative of the advanced F Class turbines. This machine is an axial flow, single spool, and constant speed unit, with variable inlet guide vanes. The turbine includes advanced bucket cooling techniques, compressor aerodynamic design and advanced alloys, enabling a higher firing temperature than the previous generation machines. The standard production version of this machine is fired with natural gas and is also commercially offered for use with IGCC derived syngas, although only earlier versions of the turbine are currently ope rating on syngas. For the purposes of this study, it was assumed that the advanced F Class turbine will be commercially available to support a 20 15 startup date on both conventional and high hydrogen content syngas representative of the cases with CO 2 

## cap ture. High H 2 

## fuel combustion issues like flame stability, flashback and NOx formation were assumed to be solved in the time frame needed to support deployment. However, because of the level of design detail , process contingencies were included in the co st estimates as described in Section 2.7 . Performance typical of an advanced F class turbine on natural gas at ISO conditions is presented in Exhibit 4

- 10

.

212Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas
Advanced F Class Firing Temperature Class, °C ( ° F) 1371+ (2500+) Airflow, kg/s (lb/s) 431 (950) Pressure Ratio 18.5 NOx Emissions, ppmv 25 Simple Cycle Output, MW 185 Combined cycle performance Net Output, MW 280 Net Efficiency (LHV), % 57.5 Net Heat Rate (LHV), kJ/kWh (Btu/kWh) 6,256 (5,934)



## In this service, with syngas from an IGCC plant, the machine requires some modifications to the burner and turbine nozzles in order to properly combust the low

- Btu gas and expand the combustion products in the turbine section of the machine.

The modifications to the machine inc lude some redesign of the original can

- annular combustors. A second modification involves increasing the nozzle areas of the turbine to accommodate the mass and volume flow of low

- Btu fuel gas combustion products, which are increased relative to those pro duced when firing natural gas. Other modifications include rearranging the various auxiliary skids that support the machine to accommodate the spatial requirements of the plant general arrangement. The generator is a standard hydrogen

- cooled machine with static exciter.

4.2.13.2 Combustion Turbine Package Scope of Supply The CT is typically supplied in several fully shop

- fabricated modules, complete with all mechanical, electrical and control systems as required for CT operation. Site CT installation involves mod ule inter

- connection, and linking CT modules to the plant systems. The CT package scope of supply for combined cycle applications, while project specific, does not vary much from project

- to

- project. The typical scope of supply is presented in Exhibit 4

- 11

.
Exhibit 4
- 11 Combustion Turbine Typical Scope of Supply
System System Scope

1.0 Engine Assembly Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, Insulation Blankets, Platforms, Stairs and Ladders

1.1 Engine Assembly with Bedplate Variable Inlet Guide, Vane System Compressor, Bleed System, Purge Air System, Bearing Seal Sir System, Combustors, Dual Fuel Nozzles Turbine Rotor Air Cooler

1.2 Walk

- in acoustical enclosure HVAC, Lighting, and Low Pressure CO 2 

### Fire Protection System



## 213Carbon Dioxide Capture Sensitivity Analysis



### System System Scope

2.0 Mechanical Package HVAC and Lighting, Air Compressor for Pneumatic System, Low Pressure CO 2 

### Fire Protection System

2.1 2.2 Lubricating Oil System and Control Oil System Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps DC Emergency Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, Oil Temperature and Pressure Control Valves, Oil Vapor Exhaust Fans and Demister Oil Heaters Oil Interconnect Piping (SS and CS) Oil System Instrumentation Oil for Flushing and First Filling

3.0 Electrical Package HVAC and Lighting, AC and DC Motor Control Centers, Generator Voltage Regulati ng Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, Battery Charger, Digital Control System with Local Control Panel (all control and monitoring functions as well as data logger and sequence of events recorder), Control System Valves and Instrumentation Communication link for interface with plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, Low Pressure CO 2 

### Fire Protection System, Cable Tray and Conduit Provisions for Performance Testing including Test Ports, Thermowells, Instrumentation and DCS interface cards

4.0 Inlet And Exhaust Systems Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning F ilters, Hoist System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and Temperature Ports and Instrumentation
5.0 Fuel Systems

5.1 Fuel Syngas System Gas Valves Including Vent, Throttle and Trip Valves Gas Filter/Separator Gas Supply Instruments and Instrument Panel

5.2 Backup Fuel System Specific to backup fuel type

6.0 Starting System Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch Assembly, Starting Clutch Torque Converter

7.0 Generator Static or Rotating Exciter (Excitation transformer to be included for a static system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge Capacitors, Neutral Cubicle with CT, Neut ral Tie Bus, Grounding Transformer, and Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming Tank, Reservoir, Seal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, and Oil Mist Eliminator), Generator Auxiliaries Control Enclosur e, Generator Breaker, Iso

- Phase bus connecting generator and breaker, Grounding System Connectors

7.1 Generator Cooling TEWAC System (including circulation system, interconnecting piping and controls), or Hydrogen Cooling System (including H 2 

### to Glycol and Glycol to Air heat exchangers, liquid level detector circulation system, interconnecting piping and controls)

8.0 Miscellaneous Interconnecting Pipe, Wire, Tubing and Cable, Instrument Air System Including Air Dryer, On Line and Off Line Wa ter Wash System, LP CO 2 

### Storage Tank, Drain System, Drain Tanks, Coupling, Coupling Cover and Associated Hardware



## 214Carbon Dioxide Capture Sensitivity Analysis



## 4.2.13.3 CT Firing Temperature Control Issue for Low Calorific Value Fuel A gas turbine when fired on low calorific value syngas has the potential to increase power output due to the increase in flow rate through the turbine. The higher turbine flow and moisture content of the combustion products can contribute to overheating o f turbine components, affect rating criteria for the parts lives, and require a reduction in syngas firing temperatures (compared to the natural gas firing) to maintain design metal temperature. [ 54 ] Uncontrolled syngas firing temperature could result in m ore than 50 percent life cycle reduction of stage 1 buckets. Control systems for syngas applications include provisions to compensate for these effects by maintaining virtually constant generation output for the range of the specified ambient conditions. Inlet guide vanes (IGV) and firing temperature are used to maintain the turbine output at the maximum torque rating, producing a flat rating up to the IGV full open position. Beyond the IGV full open position, flat output may be extended to higher ambien t air temperatures by steam/nitrogen injection. In this study, the firing temperature (defined as inlet rotor temperature) with CO 2 

## capture is 1 , 318

– 1 , 327 °C (2 , 405

– 2 , 420° F). A reduction in firing temperature with CO 2 

## capture is done to maintain parts life as the water content of the combustion products increases to 14

– 16 vol%. The decrease in temperature also results in the lower temperature steam cycle with CO 2 

## capture 538 °C/538 °C [1 , 000 °F/1 , 000 °F].

4.2.13.4 Combustion T urbine Syngas Fuel Requirements Typical fuel specifications and contaminant levels for successful CT operation are presented for F Class machines in Exhibit 4

- 12 and Exhibit 4

- 13 [ 55 ]. The vast majority of published CT performance information is specific to natural gas operation. Turbine performanc e using syngas requires vendor input as was obtained for this study.

215Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 12 Typical Fuel Specification for F

- Class Machines
Max Min LHV, kJ/m 3 

### (Btu/scf) None 3.0 (100) Gas Fuel Pressure, MPa (psia) 3.1 (450)
Gas Fuel Temperature, °C ( ° F) (1) Varies with gas pressure (2) Flammability Limit Ratio, Rich

- to

- Lean, Volume Basis (3) 2:2.1

Sulfur (4)

Notes:



## 1. The maximum fuel temperature is defined in reference [ 56 ] 

## 2. To ensure that the fuel gas supply to the gas turbine is 100 percent free of liquids the minimum fuel gas temperature must meet the required superheat over the respective dew point. This requirement is independent of the hydrocarbon and moisture concentration. Superheat calculation shall be performed as described in GEI

- 4140G [ 55 ]. 

## 3. Maximum flammability ratio limit is not defined. Fuel with flammability ratio significantly larger than those of natural gas may require start

- up fuel 

## 4. The quantity of sulfur in syngas is not limited by specification. Experience has shown that fuel sulfur levels up to 1 percent by volume do not significantly affect oxidation/corrosion rates. 

## 4.2.13.5 Normal Operation Inlet air is compressed in a single spool compressor to a pressure ratio of app roximately 16:1. This pressure ratio was vendor specified and less than the 18.5:1 ratio used in natural gas applications. The majority of compressor discharge air remains on

- board the machine and passes to the burner section to support combustion of the syngas. Compressed air is also used in burner, transition, and film cooling services. About 4 percent of the compressor air is extracted and integrated with the air supply of the ASU in Design 1. It may be technically possible to integrate the CT and A SU in CO 2 

## capture cases (Designs 2

– 4) as well; however, in this study integration was considered only for Design 1.

216Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 13 Allowable Gas Fuel Contaminant Level for F

- Class Machines

Turbine Inlet Limit, ppbw Fuel Limit, ppmw **Turbine Inlet Flow/Fuel Flow**
**50 12**  **4**
Lead 20 1.0 0.240 .080
Vanadium 10 0.5 0.120 0.040 Calcium 40 2.0 0.480 0.160 Magnesium 40 2.0 0.480 0.160 Sodium + Potassium Na/K = 28 (1) 20 1.0 0.240 0.080 Na/K = 3 10 0.5 0.120 0.40 Na/K ≤ 1 6 0.3 0.072 0.024 Particulates Total (2) 600 30 7.2 2.4 Above 10 microns 6 0.3 0.072 0.024
Notes: 1. Na/K=28 is nominal sea salt ratio 2. The fuel gas delivery system shall be designed to prevent generation or admittance of solid particulate to the gas turbine gas fuel system 

## Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas dilution is used to limit NOx formation. As described in Section 4.2.3.1 nitrogen from the ASU is used as the primary diluent followed by syngas humidification and finally by steam dilution, if necessary, to achieve an LHV of 4.5

– 4.8 MJ/Nm 3 

## (120

– 128 Btu/scf). The advantages of using nitrogen as the primary diluent include:

• Nitrogen from the ASU is already partially compressed and using it for dilution eliminates wasting the compression energy.

• Limiting the water content reduces the need to de

- rate firing temperature for the high

hydrogen (CO 2 

## capture) cases. There are some disadvantages to using nitrogen as the primary diluent, and these include:

• There is a significant auxiliary power requirement to further compress the large nitrogen flow from the ASU pressures of 0.4 and 1. 3 MPa (56 and 182 psia) to the CT pressure of 3.2 MPa (465 psia).

• The low quality heat used in the syngas humidification process does not provide significant benefit to the process in other applications.

• Nitrogen is not as efficient as water in limiting NO x 

## emissions It is not clear that one dilution method provides a significant advantage over the other. However, in this study nitrogen was chosen as the primary diluent based on suggestions by turbine industry experts during peer review of the report.

217Carbon Dioxide Capture Sensitivity Analysis



## Hot combustion products are expanded in the three

- stage turbine

- expander. Given the assumed ambient conditions, back

- end loss, and HRSG pressure drop, the CT exhaust temperature is nominally 566 °C (1 , 050 °F) with CO 2 

## capture. Gross turbine power, as measur ed prior to the generator terminals, is 232 MW. The CT generator is a standard hydrogen

- cooled machine with static exciter.



# 4.2.14 Steam Generation Island
4.2.14.1 Heat Recovery Steam Generator The heat recovery steam generator (HRSG) is a horizontal gas flow, drum

- type , multi

- pressure design that is matched to the characteristics of the gas turbine exhaust gas when firing medium

Btu gas. High

- temperature flue gas exiting the CT is conveyed through the HRSG to recover the large quantity of thermal energy that remains. Flue gas travels through the HRSG gas path and exits at 132 °C (270 °F) for all four IGCC plant designs. The high pressure (HP) drum produces steam at main steam pressure, while the intermediate pressure (IP) drum produces process steam and turbine dilutio n steam, if required. The HRSG drum pressures are nominally 12.4/2.9 MPa (1 , 800/420 psia) for the HP/IP turbine sections, respectively. In addition to generating and superheating steam, the HRSG performs reheat duty for the cold/hot reheat steam for the steam turbine, provides condensate and feedwater heating, and also provides deaeration of the condensate. Natural circulation of steam is accomplished in the HRSG by utilizing differences in densities due to temperature differences of the steam. The natur al circulation HRSG provides the most cost

- effective and reliable design. The HRSG drums include moisture separators, internal baffles, and piping for feedwater/steam. All tubes, including economizers, superheaters, and headers and drums, are equipped wit h drains. Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe work place. Superheater, boiler, and economizer sections are supported by shop

- assembled structural steel. Inlet and outlet duct is provided to route the gases from the gas turbine outlet to the HRSG inlet and the HRSG outlet to the stack. A diverter valve is included in the inlet duct to bypass the gas when appropriate. Suitable expansion joints are also included.

4.2.14.2 Steam Turbine Generator and Auxiliar ies
The steam turbine consists of an HP section, an IP section, and one double

- flow LP section, all connected to the generator by a common shaft. The HP and IP sections are contained in a single

span, opposed

- flow casing, with the double

- flow LP section i n a separate casing. The LP turbine has a last stage bucket length of 76 cm (30 in).

218Carbon Dioxide Capture Sensitivity Analysis



## Main steam from the HRSG and gasifier island is combined in a header, and then passes through the stop valves and control valves and enters the turbine at 12.4 MPa/538 °C (1 , 800 psig/1 , 000 °F) with CO 2 

## capture. The steam initially enters the turbine near the middle of the high

- pressure span, flows through the turbine, and returns to the HRSG for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP sec tion at 2.6 to 2.9 MPa/538 °C (375 to 420 psig/1 , 000 °F) with CO 2 

## capture. After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the LP section. The steam divides into two paths and flows through the LP s ections, exhausting downward into the condenser. Turbine bearings are lubricated by a closed

- loop, water

- cooled , pressurized oil system. The oil is contained in a reservoir located below the turbine floor. During startup or unit trip an emergency oil pum p mounted on the reservoir pumps the oil. When the turbine reaches 95 percent of synchronous speed, the main pump mounted on the turbine shaft pumps oil. The oil flows through water

- cooled heat exchangers prior to entering the bearings. The oil then flo ws through the bearings and returns by gravity to the lube oil reservoir. Turbine shafts are sealed against air in

- leakage or steam blowout using a modern positive pressure variable clearance shaft sealing design arrangement connected to a low

- pressure ste am seal system. During startup, seal steam is provided from the main steam line. As the unit increases load, HP turbine gland leakage provides the seal steam. Pressure

- regulating valves control the gland header pressure and dump any excess steam to the condenser. A steam packing exhauster maintains a vacuum at the outer gland seals to prevent leakage of steam into the turbine room. Any steam collected is condensed in the packing exhauster and returned to the condensate system. The generator is a hydrog en

- cooled synchronous type, generating power at 24 kV. A static, transformer type exciter is provided. The generator is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft. The heat absorbed by the gas is
remo ved as it passes over finned tube gas coolers mounted in the stator frame. Gas is prevented from escaping at the rotor shafts by a closed

- loop oil seal system. The oil seal system consists of storage tank, pumps, filters, and pressure controls, all skid

- mounted. The steam turbine generator is controlled by a triple

- redundant, microprocessor

- based electro

hydraulic control system. The system provides digital control of the unit in accordance with programmed control algorithms, color CRT operator interfacing, and datalink interfaces to the balance

- of

- plant DCS, and incorporates on

- line repair capability.

4.2.14.3 Condensate System The condensate system transfers condensate from the condenser hotwell to the deaerator, through the gland steam condenser, gasif ier, and the low

- temperature economizer section in the HRSG. The system consists of one main condenser; two 50 percent capacity, motor

- driven, vertical condensate pumps; one gland steam condenser; and a low

- temperature tube bundle in the HRSG. Condensate is delivered to a common discharge header through separate pump discharge lines, each with a check valve and a gate valve. A common minimum flow recirculation line

219Carbon Dioxide Capture Sensitivity Analysis



## discharging to the condenser is provided to maintain minimum flow requirements for the gla nd steam condenser and the condensate pumps.

4.2.14.4 Feedwater System The function of the feedwater system is to pump the various feedwater streams from the deaerator storage tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pum ps are provided for each of three pressure levels, HP, IP, and LP. Each pump is provided with inlet and outlet isolation valves, and outlet check valve. Minimum flow recirculation to prevent overheating and cavitation of the pumps during startup and low loads is provided by an automatic recirculation valve and associated piping that discharges back to the deaerator storage tank. Pneumatic flow control valves control the recirculation flow. The feedwater pumps are supplied with instrumentation to monito r and alarm on low oil pressure, or high bearing temperature. Feedwater pump suction pressure and temperature are also monitored. In addition, the suction of each boiler feed pump is equipped with a startup strainer.

4.2.14.5 Main and Reheat Steam Systems

The fun ction of the main steam system is to convey main steam generated in the synthesis gas cooler and HRSG from the HRSG superheater outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the H RSG reheater, and to the turbine reheat stop valves.

With CO 2 

## capture, main steam at approximately 12.4 MPa/538 °C (1 , 800 psig/1 , 000 °F) exits the HRSG superheater through a motor

- operated stop/check valve and a motor

- operated gate valve, and is routed to the HP turbine. Cold reheat steam at approximately 3.1 to 3.4 MPa/341 °C (450 to 500 psia/645 °F) exits the HP turbine, flows through a motor

- operated isolation gate valve, to the HRSG reheater. Hot reheat steam at approximately 2.9 MPa/538 °C (420 psia/ 1 , 000 °F) exits the HRSG reheater through a motor

- operated gate valve and is routed to the IP turbines. Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for removal of condensate from the steam lines. Condensate collect ed in the drip pots and in low

point drains is discharged to the condenser through the drain system. Steam flow is measured by means of flow nozzles in the steam piping. The flow nozzles are located upstream of any branch connections on the main headers. Safety valves are installed to comply with appropriate codes and to ensure the safety of personnel and equipment.

4.2.14.6 Circulating Water System The circulating water system is a closed

- cycle cooling water system that supplies cooling water to the condenser to c ondense the main turbine exhaust steam. The system also supplies cooling water to the AGR plant as required, and to the auxiliary cooling system. The auxiliary cooling system is a closed

- loop process that utilizes a higher quality water to remove heat fr om

220Carbon Dioxide Capture Sensitivity Analysis



## compressor intercoolers, oil coolers and other ancillary equipment and transfers that heat to the main circulating cooling water system in plate and frame heat exchangers. The heat transferred to the circulating water in the condenser and other applica tions is removed by a mechanical draft cooling tower. The system consists of two 50 percent capacity vertical circulating water pumps, a mechanical draft evaporative cooling tower, and carbon steel cement

- lined interconnecting piping. The pumps are single

- stage vertical pumps. The piping system is equipped with butterfly isolation valves and all required expansion joints. The cooling tower is a multi

- cell wood frame counterflow mechanical draft cooling tower. The condenser is a single

- pass, horizontal ty pe with divided water boxes. There are two separate circulating water circuits in each box. One

- half of the condenser can be removed from service for cleaning or for plugging tubes. This can be done during normal operation at reduced load.

The condenser is equipped with an air extraction system to evacuate the condenser steam space for removal of non

- condensable gases during steam turbine operation and to rapidly reduce the condenser pressure from atmospheric pressure before unit startup and admission of steam to the condenser.

4.2.14.7 Raw Water, Fire Protection, and Cycle Makeup Water Systems The raw water system supplies cooling tower makeup, cycle makeup, service water and potable water requirements. The water source is 50 percent from a POTW and 50 percent f rom groundwater. Booster pumps within the plant boundary provide the necessary pressure. The fire protection system provides water under pressure to the fire hydrants, hose stations, and fixed water suppression system within the buildings and structures. The system consists of pumps, underground and aboveground supply piping, distribution piping, hydrants, hose stations, spray systems, and deluge spray systems. One motor

- operated booster pump is supplied on the intake structure of the cooling tower with a diesel engine backup pump installed on the water inlet line. The cycle makeup water system provides high quality demineralized water for makeup to the HRSG cycle, for steam injection ahead of the water gas shift reactor(s) for appropriate plant designs, and for injection steam to the auxiliary boiler for control of NOx emissions, if required. The cycle makeup system consists of two 100 percent trains, each with a full

- capacity activated carbon filter, primary cation exchanger, primary anion exchanger, mix ed bed exchanger, recycle pump, and regeneration equipment. The equipment is skid

- mounted and includes a control panel and associated piping, valves, and instrumentation.



# 4.2.15 Accessory Electric Plant The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, all required foundations, and standby equipment.

221Carbon Dioxide Capture Sensitivity Analysis



# 4.2.16 Instrumentation and Control An integrated plant

- w ide distributed control system (DCS) is provided. The DCS is a redundant microprocessor

- based, functionally distributed control system. The control room houses an array of multiple video monitor (CRT) and keyboard units. The CRT/keyboard units are the p rimary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to be operational and accessible 99.5 percent of the time it is r equired (99.5 percent availability). The plant equipment and the DCS are designed for automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are manually implemented, with operator selection of modular automati on routines available. The exception to this, and an important facet of the control system for gasification, is the critical controller system, which is a part of the license package from the gasifier supplier and is a dedicated and distinct hardware segm ent of the DCS. This critical controller system is used to control the gasification process. The partial oxidation of the fuel feed and oxygen feed streams to form a syngas product is a stoichiometric, temperature

and pressure

- dependent reaction. The cr itical controller utilizes a redundant microprocessor executing calculations and dynamic controls at 100

- to 200

- millisecond intervals. The enhanced execution speeds as well as evolved predictive controls allow the critical controller to mitigate process upsets and maintain the reactor operation within a stable set of operating parameters.



# 4.3 GEE IGCC C O 2 

# Capture Sensitivity

The evaluation scope included developing heat and mass balances and estimating GE E IGCC power plant performance while gasifying bituminous Illinois No. 6 coal. Equipment lists were developed for each design to support plant capital and operating costs estimates.

The IGCC plants are assumed to be built on a “green

- field” site and utilize recirculating wet evaporative cooling sys tems for cycle heat rejection. Major systems for each plant (described in Section 4.2 ) include:
1. GEE radiant

- only gasifier 2. ASU 3. Water gas shift 4. Acid gas removal 5. CO 2 

## Recovery
6. Balance of Plant Support facilities include coal handling (receiving, crushing, slurry preparation, and storing), solid waste disposal, circulating water system with evaporative mechanical draft cooling towers, wastewater treatment, and other anci llary systems equipment necessary for an efficient, highly available, and completely operable facility.

222Carbon Dioxide Capture Sensitivity Analysis



## The plant designs are based on using components suitable for a 30

- year life, with provision for periodic maintenance and replacement of critical parts. All equipment is based on compliance with the latest applicable codes and standards. ASME, ANSI, IEEE, NFPA, CAA, state regulations, and OSHA codes are all adhered to in the design ap proach. IGCC Plant Designs

The Case 2 IGCC plant designs used to analyze the full range of potential CO 2 

## capture levels are shown in Exhibit 4

- 14

. While each of these plant designs includes the process and ancillary equipment described in Section 4.2 , the designs are unique in te rms of the WGS and AGR sections. In particular, the WGS section, as described below, is different for each plant design.

• D1 has no WGS reactor. T he minimum (0 percent ) and maximum ( 25 percent ) CO 2 

## capture levels for t his particular configuration are modeled. Due to the high level of integration between the H 2 

## S and CO 2 

## absorbers, it is not feasible to model no CO 2 

## capture with a two

- stage SelexolTM system. Consequently, D1A (0 percent capture) employs a one

- stage SelexolTM unit for H 2 

## S control, while D1B (25 percent capture) utilizes a two

- stage SelexolTM unit to maximize CO 2 

## capture from the unshifted syngas. D1 includes a COS hydrolysis unit to treat the entire syngas stream.

• D2 has o ne

- stage WGS with CO 2 

## capture ranging from 25 percent (upper limit from D 1) to the maximum achievable limit for this particular configuration (75 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

## removal efficiency

. The SelexolTM remo val efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The combined syngas stream (shi fted and unshifted gas) is routed through a COS hydrolysis unit.

• D3 has two

- stage WGS with CO 2 

## captur e ranging from 25 percent (upper limit from D 1) to the maximum achievable limit for this particular configuration (85 percent ) by varying the WGS bypass ratio and the two

- stage SelexolTM CO 2 

## removal efficiency

. The SelexolTM removal efficiency is changed by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system. The WGS bypass stream passes through a COS hydrolysis unit.

• D4 has two

- stage WGS and no bypass with CO 2 

## capture ranging from 90 to 97 percent . To achieve great er than 90 percent CO 2 

## removal, the two

- stage SelexolTM CO 2 

## removal efficiency is increased by raising the solvent circulation rate, which increases the size and cost of the SelexolTM system. D4 does not include a COS hydrolysis unit since sufficient COS to H 2 

## S conversion occurs across the two WGS reactors.

223Carbon Dioxide Capture Sensitivity Analysis



### Exhi bit 4
- 14 Case 2 GEE IGCC Plant Configuration Summary

Case CO 2 

### Capture CO 2 

### Separation Intended Storage Gasifier Steam psig/°F/°F Oxidant WGS Sulfur Control
D1A 0% N/A N/A

GE E Radiant

Only 1800/1050/1050 95 mol% O 2 

### N/A

SelexolTM D1B 25%

SelexolTM 2 nd 

### Stage Saline Formation N/A
D2A 25% One

- Stage with bypass D2B 45% D2C 60%
D2D 75% D3A 25%

Two

- Stage with bypass D3B 45% D3C 60% D3D 75% D3E 85%
D4A 90% Two

- Stage without bypass D4B 95% D4C 97%



# 4.3.1 IGCC Design 1

– Without Water Gas Shift Design 1 (D1) represents an IGCC plant without WGS reactors. As a result, the entire syngas stream is passed through a COS hydrolysis unit to ensure that the low sulfur levels required by local permitting agencies (this analysis assumes 0.0128 lb SO 2 

## /MMBtu) are achieved. The Case 2 D1 analysis involves the development of cost and performance estimates for no CO 2 

## capture (D1A) and the maximum level of CO 2 

## removal (25 percent ) that can be achieved without WGS (D1B). Due to the high level of integration between the H 2 

## S and CO 2 

## absorbers in the two

- stage S elexolTM system (see Exhibit 4

- 8 ), it is assumed in this analysis that it is not possible to operate the two stages independently, and therefore is not feasible to model 0 percent CO 2 

## capture with this system. Since the first stage is designed to operate synergistically with the second, some level of CO 2 

## removal is unavoidable. Consequently, D1A (0 percent capture) employs a one

- stage SelexolTM unit for H 2 

## S control, while D1B (25 percent capture) utilizes a two

- stage SelexolTM unit to maximize CO 2 

## capture from the unshifted syngas. The process block flow diagram for Case 2 D1A is shown in Exhibit 4

- 15 . This process results in no CO 2 

## removal since a one

- stage SelexolTM unit is employed exclusively for H 2 

## S removal. Case 2 D1A also includes air integration between the ASU and CT (stream 21) where about 4 percent of the pressurized CT air supply is extracted, accounting for approximately 16.8 percent of the total ASU air requirement. The corresponding stream tables for Case 2 D1A are contained in Exhibit 4

- 16

.

224Carbon Dioxide Capture Sensitivity Analysis



## The process block flow diagram for Case 2 D1B is shown in Exhibit 4

- 17 . To maximize CO 2 

## removal, this process employs a two

- stage SelexolTM unit for selective H 2 

## S removal and bulk CO 2 

## capture. Note that D1B does not include air integration between the ASU and CT , which, along with a different h eat integration scheme, explains the decreased coal feed rate observed for D1B . The corresponding stream tables for Case 2 D1B are contained in Exhibit 4

- 18

. Overall performance for Case 2

- D1 is summarized in Exhibit 4

- 19 which includes auxiliar y power requirements. Material and energy balance information, environmental performance and a major e quipment list are summarized in Sections 4.3.1.1 and 4.3.1.2

.

225Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 15 Case 2 D1A Process Block Flow Diagram, IGCC without WGS (0% CO 2 

### Removal)

G AS T URBINE C OMBUSTOR Q UENCH

A ND S YNGAS S CRUBBER G AS C OOLING BFW H EATING & K NOCKOUT COS H YDROLYSIS

E LEVATED P RESSURE

ASU GEE G ASIFIER S ECTION ( R ADIANT C OOLER ) S OUR W ATER S TRIPPER M ERCURY R EMOVAL O NE
S TAGE S ELEXOL

U NIT C LAUS P LANT

S YNGAS

H / P R EHEAT

HRSG 2 X A DVANCED

F C LASS G AS T URBINE 1 A IR TO ASU

2 3

V ENT G AS 5 6 8

G ASIFIER O XIDANT A S

- R ECEIVED C OAL S LAG 9 10 11 12 13 14 15

17

18

19 4

20 21

T URBINE C OOLING A IR 22 W ATER R ECYCLE TO P ROCESS D EMAND

A MBIENT A IR F LUE G AS S TACK G AS S YNGAS E XPANDER N OTE : W ATER FROM T AIL GAS COOLER MODELED , BUT NOT SHOWN

H YDROGENATION R EACTOR AND G AS C OOLER

16

T AIL G AS R ECYCLE TO S ELEXOL
N OTE : T AIL G AS B OOST C OMPRESSOR M ODELED , BUT NOT SHOWN C LEAN G AS

N ITROGEN D ILUENT

A IR S ULFUR P RODUCT

S YNGAS C LAUS P LANT O XIDANT

23 C LAUS P LANT

O XIDANT

S TEAM T URBINE 24

464 MW e 7

. 5 MW e

276 MW e Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are shown

. S LURRY M IXER

7 S LURRY

W ATER



## 226Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 16 Case 2 D1A Stream Table, IGCC without CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0237 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0099 CH 4 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0012 0.0009 0.0009 0.0013 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3579 0.2825 0.2825 0.4151 CO 2 

### 0.0003 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1366 0.1078 0.1079 0.1586 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3416 0.2696 0.2696 0.3961 H 2 

### O 0.0099 0.2114 0.0000 0.0003 0.0000 0.0000 0.9994 0.0000 0.1358 0.3181 0.3180 0.0012 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0002 0.0000 H 2 

### S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0059 0.0085 N 2 

### 0.7732 0.5553 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0080 0.0063 0.0063 0.0092 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0021 0.0020 0.0020 0.0000 O 2 

### 0.2074 0.2015 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 21,870 1,050 102 19,395 5,297 0 4,829 0 22,210 28,140 28,140 19,152 V-L Flowrate (kg/hr) 631,092 28,469 3,288 544,226 170,471 0 86,993 0 445,994 552,546 552,546 390,561 Solids Flowrate (kg/hr) 0 0 0 0 0 211,765 0 23,234 0 0 0 0
Temperature (°C) 15 20 32 93 32 15 146 1,316 677 223 223 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.48 5.41 5.24 Enthalpy (kJ/kg) A 

### 30.23 36.86 26.67 92.52 26.67

--- 558.58

--- 1,424.13 1,066.72 1,066.62 40.35 Density (kg/m 3 

### ) 1.2 1.6 11.0 24.4 11.0

--- 866.9

--- 13.9 26.7 26.3 41.9 V-L Molecular Weight 28.857 27.117 32.181 28.060 32.181

--- 18.015

--- 20.081 19.636 19.636 20.393

V-L Flowrate (lb mol 

### /hr) 48,214 2,315 225 42,759 11,679 0 10,646 0 48,965 62,037 62,037 42,222 V-L Flowrate (lb/hr) 1,391,319 62,763 7,248 1,199,813 375,823 0 191,787 0 983,248 1,218,155 1,218,155 861,041 Solids Flowrate (lb/hr) 0 0 0 0 0 466,861 0 51,223 0 0 0 0
Temperature (°F) 59 68 90 199 90 59 295 2,400 1,250 433 433 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 795.0 785.0 760.0 Enthalpy (Btu/lb) A 

### 13.0 15.8 11.5 39.8 11.5

--- 240.1

--- 612.3 458.6 458.6 17.3 Density (lb/ft 3 

### ) 0.076 0.098 0.687 1.521 0.687

--- 54.120

--- 0.870 1.665 1.643 2.617 A - Reference conditions are 32.02 F & 0.089 PSIA



## 227Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 16 Case 2 D1A Stream Table, IGCC without CO 2 Capture (continued)

13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction

Ar 0.0097 0.0000 0.0000 0.0040 0.0100 0.0100 0.0100 0.0092 0.0092 0.0089 0.0089 0.0000 CH 4 

### 0.0013 0.0000 0.0000 0.0000 0.0013 0.0013 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.3977 0.0002 0.0000 0.0021 0.4089 0.4089 0.4089 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.1811 0.6125 0.0000 0.6947 0.1562 0.1562 0.1562 0.0003 0.0003 0.0807 0.0807 0.0000 COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.3812 0.0000 0.0000 0.0414 0.3920 0.3920 0.3920 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0012 0.0128 0.0000 0.0018 0.0006 0.0006 0.0006 0.0099 0.0099 0.0638 0.0638 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0086 0.1816 0.0000 0.0111 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0191 0.1905 0.0000 0.2448 0.0309 0.0309 0.0309 0.7732 0.7732 0.7427 0.7427 0.0000 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0023 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1039 0.1039 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 19,990 950 0 839 19,444 19,444 19,444 110,253 4,410 136,896 136,896 35,591 V-L Flowrate (kg/hr) 422,555 36,875 0 31,993 397,017 397,017 397,017 3,181,557 127,262 3,995,539 3,995,539 641,191 Solids Flowrate (kg/hr) 0 0 5,302 0 0 0 0 0 0 0 0 0
Temperature (°C) 35 45 174 38 45 241 196 15 432 589 132 561 Pressure (MPa, abs) 5.21 5.2 0.409 5.512 5.171 5.136 3.172 0.101 1.619 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 36.92 -1.2

--- -5.043 54.552 365.188 296.112 30.227 463.785 741.334 235.099 3,502.568 Density (kg/m 3 

### ) 43.4 95.0 5,288.2 97.7 40.0 24.1 16.4 1.2 7.9 0.4 0.9 35.1 V-L Molecular Weight 21.138 39

--- 38.147 20.419 20.419 20.419 28.857 28.857 29.187 29.187 18.015

V-L Flowrate (lb mol 

### /hr) 44,071 2,095 0 1,849 42,866 42,866 42,866 243,066 9,723 301,803 301,803 78,466 V-L Flowrate (lb/hr) 931,574 81,295 0 70,533 875,273 875,273 875,273 7,014,133 280,565 8,808,656 8,808,656 1,413,583 Solids Flowrate (lb/hr) 0 0 11,688 0 0 0 0 0 0 0 0 0
Temperature (°F) 94 112 345 100 112 465 386 59 810 1,092 270 1,042 Pressure (psia) 755.0 750.0 59.3 799.5 750.0 745.0 460.0 14.7 234.9 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 15.9 -0.5

--- -2.2 23.5 157.0 127.3 13.0 199.4 318.7 101.1 1,505.8 Density (lb/ft 3 

### ) 2.712 6 330.129 6.098 2.499 1.508 1.026 0.076 0.495 0.027 0.057 2.192 A - Reference conditions are 32.02 F & 0.089 PSIA



## 228Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 17 Case 2 D1B Process Block Flow Diagram, IGCC without WGS (25% CO 2 

### Removal)

G AS T URBINE C OMBUSTOR

T URBINE C OOLING A IR Q UENCH AND

S YNGAS S CRUBBER G AS C OOLING BFW H EATING & K NOCKOUT COS H YDROLYSIS

E LEVATED P RESSURE

ASU GEE G ASIFIER S ECTION ( R ADIANT C OOLER ) S OUR W ATER S TRIPPER M ERCURY R EMOVAL T WO

S TAGE S ELEXOL

U NIT

C LAUS P LANT

HRSG

A MBIENT A IR S YNGAS E XPANDER

H YDROGENATION R EACTOR AND G AS C OOLER CO 2 C OMPRESSION

1 5 9 10 11 12 13

16 18

19

20 17

6 8

2 3 4

21 22 23 A IR TO ASU A S

- R ECEIVED C OAL

S LAG W ATER R ECYCLE TO P ROCESS

D EMAND N OTE : W ATER FROM T AIL G AS C OOLER MODELED , BUT NOT SHOWN

N ITROGEN D ILUENT S YNGAS C LEAN G AS CO 2 S TREAMS CO 2 P RODUCT

S ULFUR

T AIL G AS R ECYCLE TO

S ELEXOL N OTE : T AIL G AS B OOST C OMPRESSOR MODELED , BUT NOT SHOWN

F LUE G AS S TACK G AS V ENT G AS C LAUS P LANT O XIDANT

2 X A DVANCED

F C LASS G AS T URBINE S YNGAS H / P R EHEAT

14

15

C LAUS P LANT O XIDANT

S TEAM T URBINE 24 281 MW e 5

. 8 MW e

464 MW e Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are shown

. 20
T AIL G AS R ECYCLE F ROM C LAUS P LANT

S LURRY M IXER

7 S LURRY W ATER



## 229Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 18 Case 2 D1B Stream Table, IGCC with 25% CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0140 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0100 CH 4 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0009 0.0013 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2820 0.2820 0.4151 CO 2 

### 0.0003 0.0044 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.1090 0.1604 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2686 0.2686 0.3954 H 2 

### O 0.0099 0.1107 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3197 0.3195 0.0012 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0002 0.0000 H 2 

### S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0059 0.0086 N 2 

### 0.7732 0.7598 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0055 0.0081 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0016 0.0000 O 2 

### 0.2074 0.1112 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 26,011 1,933 94 18,697 5,251 0 4,786 0 21,971 27,854 27,854 18,924 V-L Flowrate (kg/hr) 750,612 53,323 3,014 524,635 168,970 0 86,227 0 442,069 547,801 547,801 386,853 Solids Flowrate (kg/hr) 0 0 0 0 0 209,901 0 23,030 0 0 0 0
Temperature (°C) 15 17 32 93 32 15 142 1,316 677 212 212 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.48 5.41 5.14 Enthalpy (kJ/kg) A 

### 30.23 35.12 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,049.10 1,049.00 40.01 Density (kg/m 3 

### ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.4 27.0 41.3 V-L Molecular Weight 28.857 27.587 32.181 28.060 32.181

--- 18.015

--- 20.121 19.667 19.667 20.443

V-L Flowrate (lb mol 

### /hr) 57,346 4,261 206 41,220 11,576 0 10,552 0 48,437 61,407 61,407 41,720 V-L Flowrate (lb/hr) 1,654,817 117,556 6,645 1,156,623 372,515 0 190,099 0 974,594 1,207,695 1,207,695 852,865 Solids Flowrate (lb/hr) 0 0 0 0 0 462,752 0 50,772 0 0 0 0
Temperature (°F) 59 63 90 199 90 59 287 2,400 1,250 413 413 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 795.0 785.0 745.0 Enthalpy (Btu/lb) A 

### 13.0 15.1 11.5 39.8 11.5

--- 231.2

--- 612.5 451.0 451.0 17.2 Density (lb/ft 3 

### ) 0.076 0.089 0.687 1.521 0.687

--- 54.440

--- 0.871 1.710 1.688 2.575 A - Reference conditions are 32.02 F & 0.089 PSIA



## 230Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 18 Case 2 D1B Stream Table, IGCC with 25% CO 2 Capture (continued)

13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction

Ar 0.0101 0.0118 0.0118 0.0118 0.0006 0.0037 0.0000 0.0228 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0013 0.0015 0.0015 0.0015 0.0002 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.4114 0.4813 0.4813 0.4813 0.0257 0.1675 0.0000 0.0031 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.1611 0.0260 0.0260 0.0260 0.9648 0.0000 0.0000 0.2380 0.0003 0.0599 0.0599 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.3973 0.4685 0.4685 0.4685 0.0085 0.1031 0.0000 0.6146 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0012 0.0001 0.0001 0.0001 0.0000 0.0310 0.0000 0.0013 0.0099 0.0632 0.0632 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0085 0.0000 0.0000 0.0000 0.0001 0.6923 0.0000 0.0036 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0091 0.0108 0.0108 0.0108 0.0001 0.0016 0.0000 0.1165 0.7732 0.7566 0.7566 0.0000 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1112 0.1112 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 19,096 16,093 16,093 16,093 2,754 235 0 173 110,253 137,400 137,400 35,014 V-L Flowrate (kg/hr) 389,636 263,433 263,433 263,433 119,071 6,868 0 2,783 3,181,557 3,969,626 3,969,626 630,792 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,253 0 0 0 0 0
Temperature (°C) 35 35 241 197 64 48 182 38 15 582 132 554 Pressure (MPa, abs) 5.1 4.999 4.964 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 40.2 54.462 434.577 354.231 -107.672 100.083

--- 59.876 30.227 733.067 235.743 3,484.156 Density (kg/m 3 

### ) 40.9 31.5 18.7 13.1 480.9 1.8 5,270.3 34.5 1.2 0.4 0.9 35.5 V-L Molecular Weight 20 16.370 16.370 16.370 43.231 29.259

--- 16.124 28.857 28.891 28.891 18.015

V-L Flowrate (lb mol 

### /hr) 42,100 35,478 35,478 35,478 6,072 517 0 381 243,066 302,915 302,915 77,193 V-L Flowrate (lb/hr) 859,001 580,771 580,771 580,771 262,506 15,141 0 6,136 7,014,133 8,751,528 8,751,528 1,390,658 Solids Flowrate (lb/hr) 0 0 0 0 0 0 11,581 0 0 0 0 0
Temperature (°F) 95 95 465 387 147 119 360 100 59 1,080 270 1,030 Pressure (psia) 740.0 725.0 720.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 17.3 23.4 186.8 152.3 -46.3 43.0

--- 25.7 13.0 315.2 101.4 1,497.9 Density (lb/ft 3 

### ) 3 1.969 1.166 0.819 30.024 0.112 329.017 2.152 0.076 0.027 0.056 2.218 A - Reference conditions are 32.02 F & 0.089 PSIA



## 231Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 19 Case 2 D1 Performance Modeling Results POWER SUMMARY (Gross Power at Generator Terminals, kWe) D1A (0%) D1B (25%) Gas Turbine Power 464,000 464,000 Sweet Gas Expander Power 7,500 5,800 Steam Turbine Power 276,300 280, 6 00 Total 747,800 750, 4 00 AUXILIARY LOAD SUMMARY, kWe Coal Handling 4 59 4 5 7

Coal Milling 2,1 78 2,1 59 Sour Water Recycle Slurry Pump 18 3 18 1 Slag Handling 1,1 15 1,1 06 Air Separation Unit Auxiliaries 1,000 1, 000 Air Separation Unit Main Air Compressor 53,8 17 64,0 10 Oxygen Compressor 10,25 5 10,1 6 4 Nitrogen Compressors 33,370 31,38 6 CO 2 

### Compressor 0 8,41 0 Boiler Feedwater Pumps 3,9 75 3,9 6 8 Condensate Pump 23 5 2 49 Quench Water Pump 5 19 51 3 Circulating Water Pump 4,20 4 4,1 65

Ground Water Pumps 4 28 4 25 Cooling Tower Fans 2,17 2 2,15 2

Scrubber Pumps 2 16 21 2 Acid Gas Removal 2,5 88 4,8 0 7 Gas Turbine Auxiliaries 1,000 1,000 Steam Turbine Auxiliaries 100 100 Claus Plant/TGTU Auxiliaries 250 250 Claus Plant TG Recycle Compressor 2,08 5 8 2 8

Miscellaneous Balance of Plant 1 

### 3,000 3,000 Transformer Losses 2,6 06 2,6 6 6 TOTAL AUXILIARIES, kWe 125,755 143,208 NET POWER, kWe 622,04 5 60 7,192 Net Plant Efficiency, % (HHV) 39.0 % 38. 4 % Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,238 ( 8,756 ) 9,38 0 ( 8,89 1 ) Condenser Duty, GJ/hr (10 6 

### Btu/hr) 1,540 (1,460) 1,625 (1,540) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 211,765 ( 466,861 ) 209,9 01 ( 462, 752 ) Thermal Input, kW th 2 

### 1, 596,183 1,582, 134 Raw Water Withdrawal , m 3 

### /min (gpm) 17.9 ( 4,734 ) 17.8 ( 4,69 2 ) Raw Water Consumption, m 3 

### /min (gpm) 14.2 (3,755) 14.1 (3,72 2 ) Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)



## 232Carbon Dioxide Capture Sensitivity Analysis



## 4.3.1.1 Environmental Performance for Case 2 D1A and D1B The environmental targets for emissions of Hg, NO x 

## , SO 2 

## , and particulate matter were presented in Section 2.4 . A summary of the plant air emissions for Case 2 D1A and D1B is presented in Exhibit 4

- 20

. For Case 2 D1A and D1B, SO 2 

## emissions are controlled by sulfur capture across the one

- stage and two

- stage SelexolTM AGR processes, respectively. The one

- stage SelexolTM unit removes over 99 percent of the sulfur compounds in the fuel gas down to a lev el of less than 15 ppmv, resulting in a concentration in the flue gas of less than 3 ppmv. For D1B, the clean syngas exiting the two

- stage SelexolTM unit has a sulfur concentration of less than 10 ppmv, resulting in a concentration in the flue gas of less than 2 ppmv. The H 2 

## S

- rich regeneration gas produced in both D1A and D1B is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the SelexolTM unit, thereb y eliminating the need for a tail gas treatment unit. For both D1A and D1B, NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- tem perature AGR process, and ultimately incinerated in the Claus plant burner. This also assists in lowering NOx levels. Particulate discharge to the atmosphere for D1A and D1B is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety

- five percent of the mercury is captured from the syngas by an activated carbon bed.
For D1A, CO 2 

## emissions rep resent the uncontrolled discharge from the process. The carbon balance for D1A is shown in Exhibit 4

- 21 . The carbon input to the plant consists of carbon in the air and coal. Carbon in the air is not neglected here since the Aspen Plus ® 

## model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

## in the wastewater blowdown stream, and as CO 2 

## in the stack gas and ASU vent gas. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance.
Twenty

- five percent of the CO 2 

## from the syngas in D1B is captured in the two

- stage SelexolTM unit and compressed for seq uestration. The carbon balance for D1B is also shown in Exhibit 4

- 21 . The carbon input to the plant consists of carbon in the air and coal. Carbon i n the air is not neg lected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

## in the wastewater blowdown stream, and as CO 2 

## in the stack gas, ASU vent gas, and the ca ptured CO 2 

## product. Carbon in th e wastewater blowdown stream is calculated by difference to close the material balance. The carbon capture efficiency is defined as the pounds of carbon in the CO 2 

## product stream relative to the amount of carbon in the coa l , less carbon contained in the slag , represented by the following fraction: (Carbon in CO 2 

## Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or 72,256/(294,980

- 5,900)*100 = 25.0%

233Carbon Dioxide Capture Sensitivity Analysis



## Exhibit 4

- 22 shows the sulfur balance for Case 2 D1A and D1B. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved SO 2 

## in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The total sulfur capture is represented by the following fraction: (Sulfur byproduct/Sulfur in the coal) or (11,688/11,701)*100 = 99.8% (D1A) (11,581/11,598)*100 = 99.8% (D1B)

The overall water balance s for Case 2 D1A and D1B are shown in Ex hibit 4

- 23 and Exhibit 4

- 24 , respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and that w ater is re used as internal recycle. Raw water withdrawal is t he difference between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawal less process water discharge. Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 25 through Exhibit 4

- 30

.

• Gasifier and ASU

• Syngas Cleanup

• Power Block An overall plant ene rgy balance is provided in tabular form for Case 2 D1A and D1B in Exhibit 4

- 31 and Exhibit 4

- 32 , respectively. The power out is the combined combustion turbine, steam turbine and expander power after generator losses. In addition, energy balance Sankey diagrams are provided for D1A and D1B in Exhibit 4

- 33 and Exhibit 4

- 34 , respectively

.
Exhibit 4
- 20 Case 2 D1 Estimated Air Emission Rates
kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)
D1A D1B D1A D1B D1A D1B SO 2 

### 0.0 02 (0.005 ) 0.0 01 (0.002 ) 84 (93) 37 (40) 0.016 (0.04) 0.007 (0.02)



### NO X 

### 0.0 25 (0.0 59 ) 0.0 24 (0.0 55 ) 1,023 (1,128) 947 (1,044) 0.195 (0.430) 0.180 (0.397)



### P M 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 123 (135) 122 (134) 0.023 (0.052) 0.023 (0.051)


### Hg 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0.010 (0.011) 0.010 (0.011) 1.89 x10 - 6 

### (4.16 x10 - 6 

### ) 1.87 x10 - 6 

### (4.11 x10 - 6 

### ) 

### CO 2 

### 84.6 ( 196.8 ) 63.5 ( 147.8 ) 3,407,608 (3,756,245) 2,53 6,560 (2,796, 079 ) 650 (1,434) 48 2 (1,06 3 )



### CO 2 

### net 782 (1,723) 59 6 (1,31 4 )



## 234Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 21 Case 2 D1 Carbon Balance Carbon In, kg/hr (lb/hr) D1A D1B Coal 134,989 (297,599) 133,8 01 (29 4,980 ) Air (CO 2 

### ) 518 (1,143) 535 (1,179) Total 135,507 (298,742) 134,3 36 (296, 159 ) Carbon Out, kg/hr (lb/hr) Slag 2,700 (5,952) 2,67 6 (5,90 0 ) Stack Gas 132,704 (292,563) 98, 783 (217, 779 ) ASU Vent 103 (227) 102 (225) CO 2 

### Product 0 (0) 32,7 75 (72,2 56 ) Convergence Tolerance 0 (0) 0 (

- 1 ) Total 135,507 ( 298,742 ) 134,336 (296,159)

Exhibit 4
- 22 Case 2 D1 Sulfur Balance Sulfur In, kg/hr (lb/hr) D1A D1B Coal 5,308 (11,701) 5,26 1 (11, 598 )
Total 5,308 (11,701) 5,26 1 (11, 598 ) Sulfur Out, kg/hr (lb/hr) Elemental Sulfur 5,302 (11,688) 5,25 3 (11,58 1 ) Stack Gas 6 (13) 3 (6) CO 2 

### Product 0 (0) 5 (12) Convergence Tolerance 0 (0) 0 (

- 1 ) Total 5,308 (11,701) 5,261 (11,598)



## 235Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 23 Case 2 D1A (0%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.50 (133) 0.50 (133) 0.0 (0) 0.0 (0) 0.0 (0)
Quench/Wash 

### 2.7 (726) 0.90 (237) 1.9 (489) 0.0 (0) 1.9 (489)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (8)

- 0.03 (

- 8) Condenser Makeup 

### 0.2 (54) 0.0 (0) 0.2 (54) 0.0 (0) 0.2 (54)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.20 (54) 0.0 (0) 0.20 (54) Cooling Tower 

### 16.4 (4,321) 0.49 (129) 15.9 (4,191) 3.7 (972) 12.2 (3,220)

BFW Blowdown 

### 0.0 (0) 0.20 (54)

- 0.20 (

- 54)
SWS Blowdown 

### 0.0 (0) 0.29 (75)

- 0.29 (

- 75)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 21.3 (5,617) 3.34 (883) 17.9 (4,734) 3.7 (979) 14.2 (3,755)
Total, gal/MWh net 

### 542 85 457 94 362



## 236Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 24 Case 2 D1B (25%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.7 (719) 0.88 (232) 1.8 (487) 0.0 (0) 1.8 (487)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 0.2 (55) 0.0 (0) 0.2 (55) 0.0 (0) 0.2 (55)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 16.2 (4,280) 0.49 (129) 15.7 (4,150) 3.6 (963) 12.1 (3,188)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.28 (74)

- 0.28 (

- 74)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 21.1 (5,566) 3.31 (874) 17.8 (4,692) 3.7 (970) 14.1 (3,722)
Total, gal/MWh net 

### 550 86 464 96 368



## 237Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

238Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 25 Case 2 D1A (0%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 1 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 1 A ( 0 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 1 A

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe Net Plant Power : 622 MWe Net Plant Efficiency
, HHV : 39

. 0 % Net Plant Heat Rate : 8 , 756 BTU / KWe N 2 to GT Combustor 1 , 391 , 319 W 59

. 0 T 14

. 7 P 13

. 0 H

375 , 823 W 90

. 0 T 125

. 0 P 11

. 5 H

375 , 823 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 7 , 248 W

90

. 0 T 125

. 0 P 11

. 5 H 62 , 763 W 68

. 3 T 16

. 4 P 15

. 8 H

1 , 074 , 227 W 90

. 0 T 56

. 4 P 14

. 2 H

150 , 581 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 466 , 861 W 59

. 0 T 14

. 7 P

191 , 787 W

295

. 0 T 840

. 0 P 240

. 1 H

51 , 223 W 2 , 400

. 0 T

815

. 0 P 1 , 199 , 813 W 389

. 0 T 384

. 0 P 88

. 2 H

658 , 648 W

159

. 7 T 840

. 0 P 2 , 933

. 2 H 1 , 390 , 077 W 100

. 0 T 189

. 5 P 18

. 0 H

6 Air From GT Compressor 280 , 565 W

220

. 0 T 224

. 9 P 50

. 9 H

280 , 565 W 809

. 8 T 234

. 9 P 199

. 4 H 1 , 199 , 813 W 199

. 0 T 384

. 0 P 39

. 8 H 21

HP BFW N 2 to AGR N 2 Boost Compressor 24 , 994 W

199

. 0 T 384

. 0 P 39

. 8 H 24 , 994 W 376

. 3 T 785

. 0 P 84

. 2 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 4

983 , 248 W

1 , 250

. 0 T

805

. 0 P 612

. 3 H 1 , 218 , 155 W 402

. 9 T 800

. 0 P 445

. 7 H

Syngas Quench 1 , 346 , 301 W 450

. 0 T 805

. 0 P 535

. 7 H

8 9 Sour Water

7



## 239Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 26 Case 2 D1A (0%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 218 , 155 W 402

. 9 T 800

. 0 P 457

. 9 H 931 , 574 W 94

. 2 T 755

. 0 P 15

. 9 H 81 , 295 W 112

. 2 T 750

. 0 P 875 , 273 W 385

. 6 T 460

. 0 P 127

. 3 H

11 , 688 W

79 , 709 W 450

. 0 T 58

. 9 P 249

. 6 H 2 , 855 W 234

. 5 T 65

. 0 P 405

. 2 H 7 , 248 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 1 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 1 A ( 0 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 1 A

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe Net Plant Power : 622 MWe Net Plant Efficiency
, HHV : 39

. 0 % Net Plant Heat Rate : 8 , 756 BTU / KWe 15

12

16 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

71 , 385 W 120

. 0 T 56

. 8 P 32

. 0 H 861 , 041 W 95

. 3 T 760

. 0 P 17

. 3 H

9 , 176 W 118

. 2 T 56

. 8 P 44

. 4 H 3

70 , 533 W

100

. 0 T 799

. 5 P Raw Syngas 17 875 , 273 W

112

. 2 T 750

. 0 P 23

. 5 H

Claus Oxygen Preheater 7 , 248 W 450

. 0 T 124

. 5 P 91

. 9 H COS Hydrolysis 1 , 218 , 155 W 432

. 7 T 785

. 0 P 458

. 6 H

COS Hydrolysis

Preheater 1 , 218 , 155 W 432

. 9 T 795

. 0 P 458

. 6 H

10 11 Clean Gas Acid Gas

13



### AGR

- Selexol 14 Fuel Gas Expander Fuel Gas To GT

19

875 , 273 W

465

. 0 T 745

. 0 P 157

. 0 H 18

N 2 to AGR

24 , 994 W

376

. 3 T 785

. 0 P 84

. 2 H



## 240Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 27 Case 2 D1A (0%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

1 , 199 , 813 W 385

. 0 T 389

. 0 P 87

. 2 H

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 581 , 157 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 808 , 656 W 269

. 7 T 15

. 2 P 101

. 1 H

875 , 273 W

385

. 6 T 460

. 0 P 127

. 3 H 8 , 808 , 656 W 1 , 092

. 5 T

15

. 2 P 318

. 7 H From Gasifier Island Preheating

To Claus LP BFW 1 , 413 , 583 W

1 , 042

. 5 T 1 , 814

. 7 P 1 , 505

. 8 H 9 , 644 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 440 , 575 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

26 , 992 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 542 , 232 W 511

. 9 T 65

. 0 P 1 , 288

. 0 H

1 , 581 , 157 W 103

. 2 T 120

. 0 P 71

. 4 H 1 , 581 , 157 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 661

. 7 T 65

. 0 P 1 , 361

. 8 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 1 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 1 A ( 0 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 1 A

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe Net Plant Power : 622 MWe Net Plant Efficiency
, HHV : 39

. 0 % Net Plant Heat Rate : 8 , 756 BTU / KWe 20 22

24

19 23

Flue Gas

HOT WELL CONDENSER Make

- up 27 , 010 W

59

. 0 T 14

. 7 P 27

. 1 H 8 , 823 W 701

. 5 T 501

. 4 P 1 , 357

. 9 H 8 , 315 W 661

. 7 T 65

. 0 P 1 , 361

. 8 H 35 , 555 W

897

. 7 T 280

. 0 P 1 , 472

. 6 H 781 W 1 , 042

. 5 T 1 , 814

. 7 P 1 , 505

. 8 H 1 , 312 W 540

. 5 T 65

. 0 P 1 , 302

. 1 H Air Extraction

280 , 565 W

809

. 8 T 234

. 9 P 199

. 4 H 21



## 241Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 28 Case 2 D1B (25%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 1 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 1 B ( 25 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 1 B

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 891 BTU / KWe 1 , 654 , 817 W 59

. 0 T 14

. 7 P 13

. 0 H

372 , 515 W 90

. 0 T 125

. 0 P 11

. 5 H

372 , 515 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 645 W

90

. 0 T 125

. 0 P 11

. 5 H 117 , 556 W 63

. 4 T 16

. 4 P 15

. 1 H

1 , 007 , 579 W 90

. 0 T 56

. 4 P 14

. 2 H

149 , 043 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 462 , 752 W 59

. 0 T 14

. 7 P

190 , 099 W

287

. 0 T 840

. 0 P 231

. 2 H

50 , 772 W 2 , 400

. 0 T

815

. 0 P 652 , 851 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6

HP BFW

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 974 , 594 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 207 , 695 W 403

. 3 T 800

. 0 P 446

. 7 H

Syngas Quench 1 , 334 , 052 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 Sour Water

7 N 2 to GT Combustor 1 , 156 , 623 W 385

. 0 T 384

. 0 P 87

. 2 H

1 , 156 , 623 W 199

. 0 T 384

. 0 P 39

. 8 H

N 2 to GT Combustor N 2 Boost Compressor 0 W 199

. 0 T 384

. 0 P 39

. 8 H 0 W 385

. 0 T 469

. 0 P 87

. 0 H 4 1 , 156 , 623 W 199

. 0 T 384

. 0 P 39

. 8 H



## 242Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 29 Case 2 D1B (25%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 207 , 695 W 403

. 3 T 800

. 0 P 446

. 7 H 859 , 001 W 94

. 7 T 740

. 0 P 17

. 3 H 15 , 141 W 119

. 0 T 23

. 7 P 580 , 771 W 386

. 9 T 460

. 0 P 152

. 3 H

11 , 581 W

12 , 718 W 450

. 0 T 12

. 3 P 850

. 9 H 2 , 512 W 240

. 3 T 65

. 0 P 445

. 4 H 6 , 645 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 1 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 1 B ( 25 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 1 B

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 891 BTU / KWe 19

12 CO 2
Tailgas

Tail Gas Cleanup Unit 7 , 222 W 120

. 0 T 10

. 6 P 202

. 7 H 852 , 865 W 94

. 8 T 745

. 0 P 17

. 2 H

6 , 582 W 116

. 7 T 10

. 6 P 42

. 7 H 3 6 , 136 W 100

. 0 T 799

. 5 P Raw Syngas 14 580 , 771 W 94

. 7 T 725

. 0 P 23

. 4 H

Claus Oxygen Preheater 6 , 645 W 450

. 0 T 124

. 5 P 91

. 9 H COS Hydrolysis 1 , 207 , 695 W 413

. 2 T 785

. 0 P 451

. 0 H

COS Hydrolysis

Preheater 1 , 207 , 695 W 413

. 3 T 795

. 0 P 451

. 0 H

10 11

13 18 Fuel Gas Expander Fuel Gas To GT

16

580 , 771 W

465

. 0 T 720

. 0 P 186

. 8 H 15

Multistage Intercooled CO 2 Compressor

Interstage Knockout CO 2 Product

17 262 , 506 W 146

. 8 T 2 , 214

. 7 P Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Tail Gas Compressor 20



## 243Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 30 Case 2 D1B (25%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 678 , 735 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 751 , 528 W 269

. 9 T 15

. 2 P 101

. 4 H

580 , 771 W

386

. 9 T 460

. 0 P 152

. 3 H 8 , 751 , 528 W 1 , 079

. 5 T

15

. 2 P 315

. 2 H From Gasifier Island Preheating

To Claus LP BFW 1 , 390 , 658 W

1 , 029

. 5 T 1 , 814

. 7 P 1 , 497

. 9 H 10 , 077 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 418 , 866 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 203 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 639 , 262 W 493

. 0 T 65

. 0 P 1 , 278

. 6 H

1 , 678 , 735 W 103

. 1 T 120

. 0 P 71

. 3 H 1 , 678 , 735 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 649

. 4 T 65

. 0 P 1 , 355

. 7 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 1 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 1 B ( 25 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 1 B

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 891 BTU / KWe 21 22

24

16 23

Flue Gas

HOT WELL CONDENSER Make

- up 27 , 495 W

59

. 0 T 14

. 7 P 27

. 1 H 8 , 875 W 690

. 6 T 501

. 4 P 1 , 351

. 7 H 9 , 579 W 649

. 4 T 65

. 0 P 1 , 355

. 7 H 25 , 433 W

885

. 6 T 280

. 0 P 1 , 466

. 3 H 785 W 1 , 029

. 5 T 1 , 814

. 7 P 1 , 497

. 9 H 1 , 318 W 531

. 1 T 65

. 0 P 1 , 297

. 4 H



## 244Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 31 Case 2 D1A (0%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,746 (5,446) 4.8 (4.6) 0 (0) 5,751 (5,451) ASU Air 0 (0) 19.1 (18.1) 0 (0) 19 (18) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 67.4 (63.9) 0 (0) 67 (64)
Totals 5,746 (5,446) 187.4 (177.7) 0 (0) 5,934 (5,624) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.0 (1.0) 0 (0) 1 (1) Slag 89 (84) 36.3 (34.4) 0 (0) 125 (118) Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47) Gasifier Heat Loss 0 (0) 41.2 (39.0) 0 (0) 41 (39) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60) HRSG Flue Gas 0 (0) 939 (890) 0 (0) 939 (890) Cooling Tower* 0 (0) 1,986 (1,882) 0 (0) 1,986 (1,882) Process Losses* * 0 (0) 489 (464) 0 (0) 489 (464)
Net Power 0 (0) 0.0 (0.0) 2,239 (2,123) 2,239 (2,123)
Totals 138 (130) 3,557 (3,371) 2,239 (2,123) 5,934 (5,624) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extractio n air cooler. ** Calculated by difference to close the energy balance.



## 245Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 32 Case 2 D1B (25%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,696 (5,398) 4.8 (4.5) 0 (0) 5,700 (5,403) ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 66.8 (63.3) 0 (0) 67 (63)
Totals 5,696 (5,398) 190.4 (180.5) 0 (0) 5,886 (5,579) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2) Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117) Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47) CO 2 

### 0 (0)

- 12.8 (

- 12.2) 0 (0)

- 13 (

- 12) Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60) HRSG Flue Gas 0 (0) 936 (887) 0 (0) 936 (887) Cooling Tower* 0 (0) 2,072 (1,964) 0 (0) 2,072 (1,964) Process Losses* * 0 (0) 424 (402) 0 (0) 424 (402)
Net Power 0 (0) 0.0 (0.0) 2,186 (2,072) 2,186 (2,072) Totals 136 (129) 3,564 (3,378) 2,186 (2,072) 5,886 (5,579) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 246Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 33 Case 2 D1A Energy Balance Sankey Diagram

Exhibit 4
- 34 Case 2 D1B Energy Balance Sankey Diagram



## 247Carbon Dioxide Capture Sensitivity Analysis



## 4.3.1.2 Major Equipment List for Case 2 D1 Major equipment items for Case 2 D1A and D1B are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates. In general , the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent con tingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Conditions Opr Qty. (Spares) D1A D1B
1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)
2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0) 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 4 Transfer Tower No. 1 Enclosed N/A N/A 1 (0) 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 6 As

- Received Coal Sampling System Two

- stage N/A N/A 1 (0) 7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 2 (1) 9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 2 (1) 10 Conveyor No. 3 Belt w/ tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0) 11 Crusher Tower N/A N/A N/A 1 (0) 12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 2 (0)
13 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 (0)
14 As

- Fired Coal Sampling System Swing hammer N/A N/A 1 (1) 15 Conveyor No. 4 Belt w/tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0) 16 Transfer Tower No. 2 Enclosed N/A N/A 1 (0) 17 Conveyor No. 5 Belt w/ tripper 354 tonne/hr (390 tph) 345 tonne/hr (380 tph) 1 (0) 18 Coal Silo w/ Vent Filter and Slide Gates Field erected 816 tonne (900 ton) 726 tonne (800 ton) 3 (0)



## 248Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B 1 Feeder Vibratory 82 tonne/h (90 tph) 73 tonne/h (80 tph) 3 (0) 2 Conveyor No. 6 Belt w/tripper 236 tonne/h (260 tph) 227 tonne/h (250 tph) 1 (0) 3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 463 tonne (510 ton) 1 (0) 4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0) 5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)
6 Slurry Water Storage Tank with Agitator Field erected 287,504 liters (75,950 gal) 284,968 liters (75,280 gal) 2 (0)

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 2 (1) 8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 2 (0)
9 Rod Mill Discharge Tank with Agitator Field erected 376,084 liters (99,350 gal) 372,790 liters (98,480 gal) 2 (0)
10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 2 (2)
11 Slurry Storage Tank with Agitator Field erected 1,128,440 liters (298,100 gal) 1,118,220 liters (295,400 gal) 2 (0)
12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 6,057 lpm (1,600 gpm) 2 (2)
13 Slurry Product Pumps Positive displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 2 (2)



## ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B
1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,082,628 liters (286,000 gal) 1,086,413 liters (287,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 6,624 lpm @ 91 m H 2 

### O (1,750 gpm @ 300 ft H 2 

### O) 7,041 lpm @ 91 m H 2 

### O (1,860 gpm @ 300 ft H 2 

### O) 2 (1)

3 Deaerator (integral w/ HRSG) Horizontal spray type 493,508 kg/hr (1,088,000 lb/hr) 483,983 kg/hr (1,067,000 lb/hr) 2 (0)

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 8,366 lpm @ 27 m H 2 

### O (2,210 gpm @ 90 ft H 2 

### O) 8,101 lpm @ 27 m H 2 

### O (2,140 gpm @ 90 ft H 2 

### O) 2 (1)



## 249Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,246 lpm @ 1,859 m H 2 

### O (1,650 gpm @ 6,100 ft H 2 

### O) HP water: 6,132 lpm @ 1,859 m H 2 

### O (1,620 gpm @ 6,100 ft H 2 

### O) 2 ( 1 )

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,060 lpm @ 223 m H 2 

### O (280 gpm @ 730 ft H 2 

### O) IP water: 1,476 lpm @ 223 m H 2 

### O (390 gpm @ 730 ft H 2 

### O) 2 ( 1 )

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

8 Service Air Compressors Flooded Screw 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 ( 1 )
9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 2 ( 1 )
10 Closed Cylce Cooling Heat Exchangers Plate and frame 247 GJ/hr (233.7595997 MMBtu/hr) each 247 GJ/hr (234.1323798 MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 88,579 lpm @ 21 m H 2 

### O (23,400 gpm @ 70 ft H 2 

### O) 88,579 lpm @ 21 m H 2 

### O (23,400 gpm @ 70 ft H 2 

### O) 2 ( 1 )

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 1 ( 1 )

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 1 ( 1 )

14 Raw Water Pumps Stainless steel, single suction 4,618 lpm @ 18 m H 2 

### O (1,220 gpm @ 60 ft H 2 

### O) 4,580 lpm @ 18 m H 2 

### O (1,210 gpm @ 60 ft H 2 

### O) 2 ( 1 )

15 Ground Water Pumps Stainless steel, single suction 3,066 lpm @ 268 m H 2 

### O (810 gpm @ 880 ft H 2 

### O) 3,028 lpm @ 268 m H 2 

### O (800 gpm @ 880 ft H 2 

### O) 3 (1)

16 Filtered Water Pumps Stainless steel, single suction 2,082 lpm @ 49 m H 2 

### O (550 gpm @ 160 ft H 2 

### O) 2,082 lpm @ 49 m H 2 

### O (550 gpm @ 160 ft H 2 

### O) 2 (1)
17 Filtered Water Tank Vertical, cylindrical 1,003,134 liter (265,000 gal) 995,563 liter (263,000 gal) 2 (0)
18 Makeup Water Demineralizer Anion, cation, and mixed bed 303 lpm (80 gpm) 303 lpm (80 gpm) 2 ( 0 )

19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 1 ( 0 )



## 250Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B
1 Gasifier Pressurized slurry

feed, entrained bed 2,812 tonne/day, 5.6 MPa (3,100 tpd, 815 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench chamber 245,393 kg/hr (541,000 lb/hr) 243,126 kg/hr (536,000 lb/hr) 2 (0)

3 Synthesis Gas Cyclone High efficiency 335,658 kg/hr (740,000 lb/hr) Design efficiency 90% 332,937 kg/hr (734,000 lb/hr) Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters metallic filters 2 (0)

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 335,658 kg/hr (740,000 lb/hr) 332,937 kg/hr (734,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with condensate drain 215,910 kg/hr (476,000 lb/hr) 287,578 kg/hr (634,000 lb/hr) 8 (0)

7 Raw Gas Knockout Drum Vertical with mist eliminator 215,456 kg/hr, 35°C, 5.3 MPa (475,000 lb/hr, 95°F, 765 psia) 213,188 kg/hr, 35°C, 5.2 MPa (470,000 lb/hr, 95°F, 750 psia) 2 (0)

8 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 335,658 kg/hr (740,000 lb/hr) syngas 332,937 kg/hr (734,000 lb/hr) syngas 2 (0)

9 ASU Main Air Compressor Centrifugal, multi

stage 4,757 m 3 

### /min @ 1.3 MPa (168,000 scfm @ 190 psia) 5,635 m 3 

### /min @ 1.3 MPa (199,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multi

stage 1,161 m 3 

### /min (41,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 1,133 m 3 

### /min (40,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 2 (0)

12 Primary Nitrogen Compressor Centrifugal, multi

stage 3,766 m 3 

### /min (133,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,540 m 3 

### /min (125,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 (0)



## 251Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

13 Secondary Nitrogen Compressor Centrifugal, single

stage 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 2 (0)

14 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

stage 0 m 3 

### /min (0 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 0 m 3 

### /min (0 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 2 (0)

15 AGR Nitrogen Boost Compressor Centrifugal, single

stage 85 m 3 

### /min (3,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 5.4 MPa (790 psia) N/A 2 (0)

16 Extraction Air Heat Exchanger Gas

- to

- gas, vendor design 69,853 kg/hr, 432°C, 1.6 MPa (154,000 lb/hr, 810°F, 235 psia) N/A 2 (0)



## ACCOUNT 5A SYNGAS CLEANUP
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Mercury Adsorber Sulfated carbon bed 215,003 kg/hr (474,000 lb/hr) 35°C (95°F) 5.2 MPa (760 psia) 212,735 kg/hr (469,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 (0)

2 Sulfur Plant Claus type 140 tonne/day (154 tpd) 139 tonne/day (153 tpd) 1 (0)

3 COS Hydrolysis Reactor Fixed bed, catalytic 303,907 kg/hr (670,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 301,185 kg/hr (664,000 lb/hr) 204°C (400°F) 5.5 MPa (800 psia) 2 (0)

4 Acid Gas Removal Plant Selexol 232,239 kg/hr (512,000 lb/hr) 35°C (94°F) 5.2 MPa (755 psia) 214,096 kg/hr (472,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 2 (0)

5 Hydrogenation Reactor Fixed bed, catalytic 36,155 kg/hr (79,709 lb/hr) 232°C (450°F) 0.4 MPa (58.9 psia) 6,346 kg/hr (13,990 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 (0)

6 Tail Gas Recycle Compressor Centrifugal 31993 kg/hr (70533.3901 lb/hr) 3,062 kg/hr (6,750 lb/hr) 1 (0)



## 252Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 5B CO 2 

## COMPRESSION
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 CO 2 

### Compressor Integrally geared, multi

stage centrifugal N/A 300 m 3 

### /min @ 15.3 MPa (10,600 scfm @ 2,215 psia) 4 (0)



## ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B 1 Gas Turbine Advanced F class 230 MW 230 MW 2 (0)
2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 (0)

3 Syngas Expansion Turbine/Generator Turbo Expander 218,359 kg/h (481,400 lb/h) 5.1 MPa (745 psia) Inlet 3.2 MPa (460 psia) Outlet 144,877 kg/h (319,400 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 2 (0)



## ACCOUNT 7 HRSG, DUCTING , AND STACK
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.4 m (27 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 1 (0)

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 352,655 kg/hr, 12.4 MPa/561°C (777,471 lb/hr, 1,800 psig/1,042°F)

Reheat steam

- 345,662 kg/hr, 3.1 MPa/561°C (762,055 lb/hr, 452 psi g/1,042°F) Main steam

- 346,935 kg/hr, 12.4 MPa/554°C (764,862 lb/hr, 1,800 psig/1,030°F)

Reheat steam

- 346,574 kg/hr, 3.1 MPa/554°C (764,065 lb/hr, 452 psig/1,030°F) 2 (0)



## 253Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 Steam Turbine Commercially available advanced steam turbine 291 MW 12.4 MPa/561°C/561°C (1,800 psig/ 1042°F/1042°F) 295 MW 12.4 MPa/554°C/554°C (1,800 psig/ 1030°F/1030°F) 1 (0)

2 Steam Turbine Generator Hydrogen cooled, static excitation 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 330 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 2 (0)

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,688 GJ/hr (1,600 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,783 GJ/hr (1,690 MMBtu/hr), Inlet water temperature 16°C (60°F), Water tempera ture rise 11°C (20°F) 1 (0)



## ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B
1 Circulating Water Pumps Vertical, wet pit 420,181 lpm @ 30 m (111,000 gpm @ 100 ft) 416,395 lpm @ 30 m (110,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,353 GJ/hr (2,230 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,332 GJ/hr (2,210 MMBtu/hr) heat duty 1 (0)



## ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B 1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 242,266 liters (64,000 gal) 2 (0) 2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0) 3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0) 4 Slag Receiving Tank Horizontal, weir 147,631 liters (39,000 gal) 143,846 liters (38,000 gal) 2 (0)



## 254Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B
5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 64,352 liters (17,000 gal) 2 (0)

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 2 (0)

9 Fine Ash Settling Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 2 (0)

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 2 (2)

11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 64,352 liters (17,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 2 (2)
13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 2 (0) 14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)



## ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B
1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 (0)

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 320 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 330 MVA, 3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 54 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 63 MVA, 3

- ph, 60 Hz 2 (0)

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 29 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 30 MVA, 3

- ph, 60 Hz 1 (1)

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 4 MVA, 3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 2 (0)



## 255Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



## ACCOUNT 12 INSTRUMENTATION AND CONTROL
Equipment No. Description Type Design Condition Opr Qty. (Spares) D1A D1B

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)



## 256Carbon Dioxide Capture Sensitivity Analysis



# 4.3.2 IGCC Design 2

– Single Water Gas Shift Reactor
A proces s block flow diagram for Case 2 Design 2 (D2) is shown in Exhibit 4

- 35 . D2 represents an IGCC plant with a single WGS reactor and bypass stream (stream 13). This IGCC design
uses a S:DG molar ratio of 0.25 at the outlet of the WGS reactor. The WGS bypass ratio and the two

- stage SelexolTM CO 2 

## removal efficiency are adjusted to control the total CO 2 

## capture level. The SelexolTM removal efficiency is altered by varying the solvent circ ulation rate, which changes the size and cost of the SelexolTM system.

The WGS bypass ratio impacts the degree of CO to CO 2 

## and COS to H 2 

## S conversion across the WGS reactor. Consequently, a downstream COS h ydolysis unit is included in this design to
ensure that sulfur emissions are below the limit of 0.0128 lb SO 2 

## /MMBtu.

Four levels of total CO 2 

## removal were modeled for Case 2 D2: 25 percent (D2A), 45 percent (D2B), 60 percent (D2C), and 75 percent (D2D). The corresponding stream tables are contain ed in Exhibit 4

- 36 , Exhibit 4

- 37 , Exhibit 4

- 38 , and Exhibit 4

- 39 , respectively.

Overal l performance for Case 2 D2 is summarized in Exhibit 4

- 40 which includes auxiliary power requirements. Material and energy balance information, environmental performance and a major equipment list are summarized in Sections 4.3.2.1 and 4.3.2.2

.

257Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 35 Case 2 D2 Process Block Flow Diagram, IGCC with Single WGS Reactor and Bypass

G AS T URBINE C OMBUSTOR

T URBINE C OOLING A IR Q UENCH AND

S YNGAS S CRUBBER G AS C OOLING BFW H EATING & K NOCKOUT S HIFT R EACTOR

E LEVATED P RESSURE

ASU GEE G ASIFIER S ECTION ( R ADIANT C OOLER ) S OUR W ATER S TRIPPER M ERCURY R EMOVAL T WO

S TAGE S ELEXOL

U NIT

C LAUS P LANT

HRSG

A MBIENT A IR S YNGAS E XPANDER

H YDROGENATION R EACTOR AND G AS C OOLER CO 2 C OMPRESSION

1 5 9 12 16 17

19 21

22

23 20

6 8

2 3 4

24 25 26 A IR TO ASU A S

- R ECEIVED C OAL

S LAG S HIFT S TEAM

W ATER R ECYCLE TO P ROCESS

D EMAND N OTE : W ATER FROM T AIL G AS C OOLER MODELED , BUT NOT SHOWN

N ITROGEN D ILUENT S YNGAS C LEAN G AS CO 2 S TREAMS CO 2 P RODUCT

S ULFUR

T AIL G AS R ECYCLE TO

S ELEXOL N OTE : T AIL G AS B OOST C OMPRESSOR MODELED , BUT NOT SHOWN

F LUE G AS S TACK G AS V ENT G AS C LAUS P LANT O XIDANT

2 X A DVANCED

F C LASS G AS T URBINE S YNGAS H / P R EHEAT

18

C LAUS P LANT O XIDANT

S TEAM T URBINE 27

464 MW e Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are shown

. 23
T AIL G AS R ECYCLE F ROM C LAUS P LANT

S LURRY M IXER

7 S LURRY W ATER COS H YDROLYSIS 15

11

10 13 14



## 258Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 36 Case 2 D2A Stream Table, 25% CO 2 

### Removal with Single WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0140 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0050 0.0068 0.0068 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007 0.0009 0.0009 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2820 0.0000 0.0283 0.2820 0.2803 CO 2 0.0003 0.0044 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.2588 0.1088 0.1098 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0001 0.0001 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2686 0.0000 0.3761 0.2686 0.2694 H 2 O 0.0099 0.1105 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3197 1.0000 0.3214 0.3197 0.3197 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 0.0002 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0043 0.0057 0.0057 N 2 0.7732 0.7600 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0041 0.0055 0.0055 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0012 0.0016 0.0016 O 2 0.2074 0.1111 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 26,017 1,936 94 18,699 5,252 0 4,788 0 21,976 27,860 50 190 27,721 27,911 V-L Flowrate (kg/hr) 750,784 53,401 3,014 524,689 169,010 0 86,248 0 442,173 547,930 907 3,647 545,190 548,837 Solids Flowrate (kg/hr) 0 0 0 0 0 209,950 0 23,035 0 0 0 0 0 0
Temperature (°C) 15 17 32 93 32 15 142 1,316 677 206 288 408 212 212 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.48 5.48 5.48 Enthalpy (kJ/kg) A 30.23 35.12 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,067.56 2,918.18 1,478.37 1,049.10 1,049.29 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 18.6 27.4 27.4 V-L Molecular Weight 28.857 27.588 32.181 28.060 32.181

--- 18.015

--- 20.121 19.667 18.015 19.228 19.667 19.664

V-L Flowrate (lb mol /hr) 57,359 4,267 206 41,224 11,578 0 10,555 0 48,448 61,422 111 418 61,115 61,533 V-L Flowrate (lb/hr) 1,655,196 117,730 6,644 1,156,741 372,603 0 190,143 0 974,824 1,207,979 2,000 8,040 1,201,939 1,209,979 Solids Flowrate (lb/hr) 0 0 0 0 0 462,861 0 50,784 0 0 0 0 0 0
Temperature (°F) 59 63 90 199 90 59 287 2,400 1,250 403 550 767 413 413 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 795.0 795.0 795.0 Enthalpy (Btu/lb) A 13.0 15.1 11.5 39.8 11.5

--- 231.2

--- 612.5 459.0 1,254.6 635.6 451.0 451.1 Density (lb/ft 3 ) 0.076 0.089 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.162 1.710 1.710 A - Reference conditions are 32.02 F & 0.089 PSIA



## 259Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 36 Case 2 D2A Stream Table, 25% CO 2 Removal with Single WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0068 0.0100 0.0101 0.0118 0.0118 0.0006 0.0037 0.0000 0.0228 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0009 0.0013 0.0013 0.0015 0.0015 0.0002 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.2803 0.4126 0.4089 0.4791 0.4791 0.0253 0.1669 0.0000 0.0031 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.1100 0.1619 0.1626 0.0263 0.0263 0.9653 0.0000 0.0000 0.2373 0.0003 0.0597 0.0597 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.2694 0.3964 0.3984 0.4705 0.4705 0.0085 0.1036 0.0000 0.6154 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.3196 0.0012 0.0012 0.0001 0.0001 0.0000 0.0311 0.0000 0.0013 0.0099 0.0635 0.0635 1.0000 HCl 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0059 0.0086 0.0085 0.0000 0.0000 0.0001 0.6924 0.0000 0.0034 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0055 0.0081 0.0091 0.0108 0.0108 0.0001 0.0016 0.0000 0.1166 0.7732 0.7566 0.7566 0.0000 NH 3 

### 0.0016 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1112 0.1112 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 27,911 18,962 19,135 16,101 16,101 2,784 235 0 172 110,253 137,409 137,409 35,016 V-L Flowrate (kg/hr) 548,837 387,556 390,331 262,829 262,829 120,373 6,864 0 2,775 3,181,557 3,969,076 3,969,076 630,824 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,254 0 0 0 0 0
Temperature (°C) 212 35 35 35 197 64 48 182 38 15 582 132 554 Pressure (MPa, abs) 5.41 5.14 5.10 5.00 3.17 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 1,049.19 40.00 40.14 54.66 355.29 -108.502 100.241

--- 60.056 30.227 733.496 236.187 3,483.972 Density (kg/m 3 

### ) 27.0 41.2 40.9 31.5 13.1 483.1 1.8 5,270.3 34.4 1.2 0.4 0.9 35.5 V-L Molecular Weight 19.664 20.438 20 16.323 16.323 43.239 29.245

--- 16.092 28.857 28.885 28.885 18.015

V-L Flowrate (lb mol 

### /hr) 61,533 41,805 42,185 35,498 35,498 6,137 517 0 380 243,066 302,934 302,934 77,197 V-L Flowrate (lb/hr) 1,209,979 854,415 860,533 579,439 579,439 265,378 15,133 0 6,118 7,014,133 8,750,314 8,750,314 1,390,729 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,583 0 0 0 0 0
Temperature (°F) 413 95 95 95 387 146 119 360 100 59 1,079 270 1,029 Pressure (psia) 785.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 451.1 17.2 17.3 23.5 152.7 -46.6 43.1

--- 25.8 13.0 315.3 101.5 1,497.8 Density (lb/ft 3 

### ) 1.688 2.575 3 1.964 0.817 30.161 0.112 329.017 2.147 0.076 0.027 0.056 2.218 A - Reference conditions are 32.02 F & 0.089 PSIA



## 260Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 37 Case 2 D2B Stream Table, 45% CO 2 

### Capture with Single WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0143 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0061 0.0068 0.0065 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2821 0.0000 0.0615 0.2821 0.1879 CO 2 0.0003 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.2884 0.1088 0.1855 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0001 0.0001 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2687 0.0000 0.4314 0.2687 0.3381 H 2 O 0.0099 0.1135 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3196 1.0000 0.2000 0.3196 0.2685 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0002 0.0002 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0052 0.0057 0.0055 N 2 0.7732 0.7537 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0049 0.0055 0.0053 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0014 0.0016 0.0015 O 2 0.2074 0.1140 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 26,429 1,914 96 19,047 5,334 0 4,863 0 22,320 28,292 1,328 12,644 16,975 29,620 V-L Flowrate (kg/hr) 762,647 52,772 3,082 534,452 171,659 0 87,600 0 449,104 556,426 23,916 246,487 333,856 580,342 Solids Flowrate (kg/hr) 0 0 0 0 0 213,242 0 23,396 0 0 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 415 212 208 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.48 5.48 5.48 Enthalpy (kJ/kg) A 30.23 35.18 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,067.22 2,918.18 1,192.31 1,048.78 939.48 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 18.5 27.4 27.3 V-L Molecular Weight 28.857 27.575 32.181 28.060 32.181

--- 18.015

--- 20.121 19.667 18.015 19.494 19.667 19.593

V-L Flowrate (lb mol /hr) 58,265 4,219 211 41,991 11,760 0 10,720 0 49,208 62,373 2,927 27,876 37,424 65,300 V-L Flowrate (lb/hr) 1,681,348 116,343 6,795 1,178,265 378,444 0 193,124 0 990,106 1,226,710 52,727 543,410 736,026 1,279,436 Solids Flowrate (lb/hr) 0 0 0 0 0 470,117 0 51,580 0 0 0 0 0 0
Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 780 413 407 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 795.0 795.0 795.0 Enthalpy (Btu/lb) A 13.0 15.1 11.5 39.8 11.5

--- 231.2

--- 612.5 458.8 1,254.6 512.6 450.9 403.9 Density (lb/ft 3 ) 0.076 0.090 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.156 1.710 1.706 A - Reference conditions are 32.02 F & 0.089 PSIA



## 261Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 37 Case 2 D2B Stream Table, 45% CO 2 Capture with Single WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0065 0.0089 0.0090 0.0117 0.0117 0.0003 0.0037 0.0000 0.0254 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0009 0.0012 0.0012 0.0015 0.0015 0.0001 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.1879 0.2572 0.2553 0.3319 0.3319 0.0100 0.1184 0.0000 0.0022 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.1856 0.2540 0.2535 0.0363 0.0363 0.9832 0.0000 0.0000 0.1881 0.0003 0.0445 0.0445 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.3381 0.4627 0.4641 0.6079 0.6079 0.0062 0.1370 0.0000 0.6492 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.2684 0.0012 0.0012 0.0001 0.0001 0.0000 0.0357 0.0000 0.0013 0.0099 0.0811 0.0811 1.0000 HCl 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0056 0.0076 0.0076 0.0000 0.0000 0.0000 0.7027 0.0000 0.0037 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0053 0.0072 0.0081 0.0106 0.0106 0.0001 0.0016 0.0000 0.1301 0.7732 0.7555 0.7555 0.0000 NH 3 

### 0.0015 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1097 0.1097 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 29,620 21,644 21,801 16,538 16,538 5,010 235 0 157 110,253 138,067 138,067 34,907 V-L Flowrate (kg/hr) 580,342 436,590 438,860 213,515 213,515 218,355 6,684 0 2,270 3,181,557 3,929,525 3,929,525 628,866 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,337 0 0 0 0 0
Temperature (°C) 208 35 35 35 197 55 48 182 38 15 576 132 548 Pressure (MPa, abs) 5.41 5.14 5.10 5.00 3.17 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 939.40 39.11 39.27 72.72 451.83 -145.215 110.774

--- 69.903 30.227 762.853 267.463 3,469.021 Density (kg/m 3 

### ) 27.0 41.0 40.7 24.8 10.3 587.9 1.7 5,270.3 30.7 1.2 0.4 0.9 35.9 V-L Molecular Weight 19.593 20.172 20 12.911 12.911 43.582 28.392

--- 14.458 28.857 28.461 28.461 18.015

V-L Flowrate (lb mol 

### /hr) 65,300 47,716 48,062 36,460 36,460 11,046 519 0 346 243,066 304,385 304,385 76,958 V-L Flowrate (lb/hr) 1,279,436 962,516 967,522 470,720 470,720 481,390 14,737 0 5,005 7,014,133 8,663,119 8,663,119 1,386,412 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,765 0 0 0 0 0
Temperature (°F) 407 95 95 95 387 130 119 360 100 59 1,069 270 1,019 Pressure (psia) 785.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 403.9 16.8 16.9 31.3 194.3 -62.4 47.6

--- 30.1 13.0 328.0 115.0 1,491.4 Density (lb/ft 3 

### ) 1.684 2.562 3 1.547 0.646 36.702 0.109 329.013 1.916 0.076 0.026 0.055 2.239 A - Reference conditions are 32.02 F & 0.089 PSIA



## 262Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 38 Case 2 D2C Stream Table, 60% CO 2 

### Capture with Single WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0142 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0061 0.0068 0.0063 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0008 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2819 0.0000 0.0616 0.2819 0.1201 CO 2 0.0003 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.2884 0.1088 0.2408 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0001 0.0001 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2685 0.0000 0.4314 0.2685 0.3882 H 2 O 0.0099 0.1129 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3199 1.0000 0.1999 0.3199 0.2317 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0002 0.0002 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0052 0.0057 0.0054 N 2 0.7732 0.7550 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0049 0.0055 0.0051 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0014 0.0016 0.0015 O 2 0.2074 0.1134 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 26,770 1,949 98 19,282 5,402 0 4,925 0 22,606 28,667 2,382 22,807 8,242 31,049 V-L Flowrate (kg/hr) 772,488 53,746 3,141 541,055 173,856 0 88,721 0 454,852 563,787 42,908 444,606 162,089 606,695 Solids Flowrate (kg/hr) 0 0 0 0 0 215,970 0 23,696 0 0 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 416 212 206 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.48 5.48 5.48 Enthalpy (kJ/kg) A 30.23 35.17 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,068.08 2,918.18 1,192.12 1,049.60 860.25 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 18.5 27.4 27.3 V-L Molecular Weight 28.857 27.578 32.181 28.060 32.181

--- 18.015

--- 20.121 19.667 18.015 19.494 19.667 19.540

V-L Flowrate (lb mol /hr) 59,017 4,297 215 42,510 11,910 0 10,858 0 49,837 63,201 5,251 50,281 18,170 68,452 V-L Flowrate (lb/hr) 1,703,045 118,490 6,924 1,192,823 383,287 0 195,596 0 1,002,776 1,242,938 94,595 980,189 357,345 1,337,533 Solids Flowrate (lb/hr) 0 0 0 0 0 476,133 0 52,240 0 0 0 0 0 0
Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 780 413 403 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 795.0 795.0 795.0 Enthalpy (Btu/lb) A 13.0 15.1 11.5 39.8 11.5

--- 231.2

--- 612.5 459.2 1,254.6 512.5 451.2 369.8 Density (lb/ft 3 ) 0.076 0.090 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.156 1.710 1.703 A - Reference conditions are 32.02 F & 0.089 PSIA



## 263Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 38 Case 2 D2C Stream Table, 60% CO2 Capture with Single WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0063 0.0081 0.0083 0.0116 0.0116 0.0002 0.0037 0.0000 0.0280 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0008 0.0011 0.0011 0.0015 0.0015 0.0001 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.1201 0.1564 0.1555 0.2171 0.2171 0.0049 0.0791 0.0000 0.0015 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.2408 0.3137 0.3127 0.0462 0.0462 0.9891 0.0000 0.0000 0.1408 0.0003 0.0326 0.0326 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.3882 0.5057 0.5068 0.7131 0.7131 0.0055 0.1642 0.0000 0.6815 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.2317 0.0012 0.0012 0.0001 0.0001 0.0000 0.0395 0.0000 0.0013 0.0099 0.0954 0.0954 1.0000 HCl 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0054 0.0070 0.0070 0.0000 0.0000 0.0000 0.7110 0.0000 0.0039 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0051 0.0066 0.0075 0.0105 0.0105 0.0000 0.0016 0.0000 0.1431 0.7732 0.7543 0.7543 0.0000 NH 3 

### 0.0015 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1086 0.1086 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 31,049 23,833 23,978 16,933 16,933 6,790 236 0 145 110,253 138,593 138,593 34,560 V-L Flowrate (kg/hr) 606,695 476,637 478,503 174,962 174,962 296,664 6,538 0 1,866 3,181,557 3,897,575 3,897,575 622,616 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,405 0 0 0 0 0
Temperature (°C) 206 35 35 35 198 53 48 182 38 15 571 132 544 Pressure (MPa, abs) 5.41 5.14 5.10 5.00 3.17 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 860.19 38.39 38.56 93.69 567.40 -154.608 119.799

--- 81.238 30.227 787.418 293.271 3,457.191 Density (kg/m 3 

### ) 26.9 40.9 40.5 19.8 8.3 617.1 1.7 5,270.2 27.2 1.2 0.4 0.9 36.1 V-L Molecular Weight 19.540 19.999 20 10.332 10.332 43.694 27.699

--- 12.893 28.857 28.122 28.122 18.015

V-L Flowrate (lb mol 

### /hr) 68,452 52,543 52,862 37,332 37,332 14,968 520 0 319 243,066 305,545 305,545 76,193 V-L Flowrate (lb/hr) 1,337,533 1,050,805 1,054,918 385,725 385,725 654,032 14,413 0 4,113 7,014,133 8,592,683 8,592,683 1,372,633 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,916 0 0 0 0 0
Temperature (°F) 403 95 95 95 388 127 119 360 100 59 1,061 270 1,011 Pressure (psia) 785.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 369.8 16.5 16.6 40.3 243.9 -66.5 51.5

--- 34.9 13.0 338.5 126.1 1,486.3 Density (lb/ft 3 

### ) 1.681 2.554 3 1.236 0.517 38.525 0.106 329.010 1.698 0.076 0.026 0.055 2.257 A - Reference conditions are 32.02 F & 0.089 PSIA



## 264Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 39 Case 2 D2D Stream Table, 75% CO 2 

### Capture with Sin gle WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0152 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0061 0.0000 0.0061 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0000 0.0008 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2819 0.0000 0.0616 0.0000 0.0616 CO 2 0.0003 0.0049 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.2885 0.0000 0.2885 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2685 0.0000 0.4315 0.0000 0.4315 H 2 O 0.0099 0.1226 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3201 1.0000 0.1998 0.0000 0.1998 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0002 0.0000 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0052 0.0000 0.0052 N 2 0.7732 0.7347 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0049 0.0000 0.0049 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0014 0.0000 0.0014 O 2 0.2074 0.1226 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000

V-L Flowrate (kg mol /hr) 27,043 1,813 94 19,635 5,462 0 4,979 0 22,854 28,991 3,368 32,358 0 32,358 V-L Flowrate (kg/hr) 780,370 49,911 3,040 550,960 175,763 0 89,694 0 459,840 570,131 60,671 630,802 0 630,802 Solids Flowrate (kg/hr) 0 0 0 0 0 218,339 0 23,956 0 0 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 415

--- 204 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.48

--- 5.48 Enthalpy (kJ/kg) A 30.23 35.36 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,068.64 2,918.18 1,191.97

--- 791.08 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 18.5

--- 27.2 V-L Molecular Weight 28.857 27.535 32.181 28.060 32.181

--- 18.015

--- 20.121 19.666 18.015 19.494

--- 19.494

V-L Flowrate (lb mol /hr) 59,619 3,996 208 43,288 12,041 0 10,977 0 50,384 63,913 7,425 71,338 0 71,338 V-L Flowrate (lb/hr) 1,720,422 110,034 6,701 1,214,660 387,491 0 197,741 0 1,013,775 1,256,924 133,757 1,390,681 0 1,390,681 Solids Flowrate (lb/hr) 0 0 0 0 0 481,355 0 52,813 0 0 0 0 0 0
Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 780

--- 400 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 795.0

--- 795.0 Enthalpy (Btu/lb) A 13.0 15.2 11.5 39.8 11.5

--- 231.2

--- 612.5 459.4 1,254.6 512.5

--- 340.1 Density (lb/ft 3 ) 0.076 0.090 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.156

--- 1.700 A - Reference conditions are 32.02 F & 0.089 PSIA



## 265Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 39 Case 2 D2D Stream Table, 75% CO 2 Capture with Single WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0061 0.0076 0.0077 0.0115 0.0115 0.0002 0.0028 0.0000 0.0178 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0008 0.0010 0.0010 0.0015 0.0015 0.0001 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0616 0.0770 0.0764 0.1143 0.1143 0.0021 0.0315 0.0000 0.0044 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.2885 0.3608 0.3612 0.0493 0.0493 0.9925 0.2533 0.0000 0.4110 0.0003 0.0207 0.0207 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.4315 0.5396 0.5390 0.8128 0.8128 0.0051 0.1414 0.0000 0.4667 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.1998 0.0012 0.0012 0.0001 0.0001 0.0000 0.0323 0.0000 0.0015 0.0099 0.1087 0.1087 1.0000 HCl 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0053 0.0066 0.0065 0.0000 0.0000 0.0000 0.5369 0.0000 0.0047 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0049 0.0062 0.0069 0.0105 0.0105 0.0000 0.0012 0.0000 0.0940 0.7732 0.7541 0.7541 0.0000 NH 3 

### 0.0014 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1075 0.1075 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 32,358 25,873 26,095 17,195 17,195 8,562 317 0 222 110,253 139,112 139,112 34,199 V-L Flowrate (kg/hr) 630,802 513,914 518,948 133,950 133,950 374,680 9,945 0 5,033 3,181,557 3,866,468 3,866,468 616,113 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,464 0 0 0 0 0
Temperature (°C) 204 35 35 35 198 52 48 181 38 15 567 132 539 Pressure (MPa, abs) 5.41 5.14 5.10 5.00 3.17 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 791.04 37.74 37.69 127.51 753.85 -159.330 97.137

--- 32.253 30.227 810.659 318.046 3,445.333 Density (kg/m 3 

### ) 26.9 40.8 40.6 14.9 6.2 632.2 1.9 5,272.4 50.3 1.2 0.4 0.9 36.4 V-L Molecular Weight 19.494 19.863 20 7.790 7.790 43.760 31.351

--- 22.680 28.857 27.794 27.794 18.015

V-L Flowrate (lb mol 

### /hr) 71,338 57,041 57,530 37,909 37,909 18,877 699 0 489 243,066 306,690 306,690 75,397 V-L Flowrate (lb/hr) 1,390,681 1,132,987 1,144,084 295,309 295,309 826,028 21,926 0 11,097 7,014,133 8,524,103 8,524,103 1,358,296 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 12,047 0 0 0 0 0
Temperature (°F) 400 95 95 95 388 125 119 359 100 59 1,052 270 1,002 Pressure (psia) 785.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 340.1 16.2 16.2 54.8 324.1 -68.5 41.8

--- 13.9 13.0 348.5 136.7 1,481.2 Density (lb/ft 3 

### ) 1.679 2.548 3 0.930 0.390 39.466 0.120 329.147 3.139 0.076 0.026 0.054 2.274 A - Reference conditions are 32.02 F & 0.089 PSIA



## 266Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 40 Case 2 D2 Performance Modeling Results POWER SUMMARY (Gross Power at Generator Terminals, kWe) D2A (25%) D2B (45%) D2C (60%) D2D (75%) Gas Turbine Power 464,000 464,000 464,000 464,000 Sweet Gas Expander Power 5,800 6, 0 00 6, 1 00 6, 2 00 Steam Turbine Power 280, 6 00 276, 9 00 275, 1 00 271,800 Total 750, 4 00 746,900 745, 2 00 742, 0 00 AUXILIARY LOAD SUMMARY, kWe Coal Handling 4 5 7 4 61 46 3 4 66

Coal Milling 2,1 59 2,19 3 2,22 1 2,2 46 Sour Water Recycle Slurry Pump 18 1 18 3 18 5 1 86 Slag Handling 1,1 06 1,12 3 1,1 38 1,150 Air Separation Unit Auxiliaries 1,000 1,000 1,000 1,000 Air Separation Unit Main Air Compressor 64,0 24 65,0 36 65,8 75 66,5 47 Oxygen Compressor 10, 1 6 7 10,3 2 6 10,4 0 4 10,5 18 Nitrogen Compressors 31,38 9 32,02 7 33,0 61 34,2 81 CO 2 

### Compressor 8,4 97 15,0 47 20,3 3 5 25,6 05 Boiler Feedwater Pumps 3,9 70 4,00 1 4,0 35 4,06 2 Condensate Pump 2 5 0 2 5 6 260 26 2 Quench Water Pump 5 1 3 5 18 5 23 5 27 Circulating Water Pump 4, 1 65 4,3 12 4,4 2 0 4,51 3

Ground Water Pumps 4 25 4 56 480 50 1 Cooling Tower Fans 2,1 5 3 2,23 1 2,2 87 2,33 1

Scrubber Pumps 2 1 2 2 16 2 18 220 Acid Gas Removal 4,8 61 8,91 2 12,1 49 15,5 19 Gas Turbine Auxiliaries 1,000 1,000 1,000 1,000 Steam Turbine Auxiliaries 100 100 100 100 Claus Plant/TGTU Auxiliaries 250 250 250 250 Claus Plant TG Recycle Compressor 8 28 7 56 699 1,05 2

Miscellaneous Balance of Plant 1 

### 3,000 3,000 3,000 3,000 Transformer Losses 2,6 6 7 2,69 3 2,7 19 2,74 1 TOTAL AUXILIARIES, kWe 143,374 156,097 166,822 178,077 NET POWER, kWe 60 7,026 590, 803 578, 378 56 3,923 Net Plant Efficiency, % (HHV) 38. 4 % 36. 8 % 35.5 % 34. 3 % Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9, 3 85 (8, 895 ) 9,796 (9,285) 10,13 2 (9,604) 10,50 6 (9,95 8 ) Condenser Duty, GJ/hr (10 6 

### Btu/hr) 1, 625 (1, 54 0) 1,614 (1,530) 1,593 (1,510) 1,561 (1,480) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 209,9 50 ( 462, 86 1 ) 213,2 42 (470,1 17 ) 21 5,970 (476, 133 ) 218,3 39 (481, 355 ) Thermal Input, kW th 2 

### 1, 582, 508 1,607, 315 1,62 7,884 1,64 5,739 Raw Water Withdrawal, m 3 

### /min (gpm) 17. 8 (4, 697 ) 19.1 (5,03 8 ) 20.1 (5,30 0 ) 20.9 (5,53 0 ) Raw Water Consumption, m 3 

### /min (gpm) 14. 1 (3,7 2 7 ) 15.3 (4,03 3 ) 16.2 (4,27 0 ) 17.0 (4,48 1 ) 

### Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)



## 267Carbon Dioxide Capture Sensitivity Analysis



## 4.3.2.1 Environmental Performance for Case 2 D2 The environmental targets for emissions of Hg, NO x 

## , SO 2 

## , and particulate matter were presented in Section 2.4 . A summary of the p lant air emissions for Case 2 D2A, D2 B , D2C, and D2D is presented in Exhibit 4

- 41

. For Case 2 D2, SO 2 

## emissions are controlled by sulfur capture across the two

- stage SelexolTM unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, resulting in a concentration in the flue gas of less than 2 ppmv. The H 2 

## S

- rich regeneration gas produced in Case 2 D2 is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the SelexolTM unit, thereby eliminating the need for a tail gas treatmen t unit.

NO x 

## emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process, and ultimately incinerated in the Claus plant burner. This also assists in lowering NOx levels. Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particul ate emissions represent filterable particulate only. Ninety

- five percent of the mercury is captured from the syngas by an activated carbon bed. For Case 2 D2, varying levels of the CO 2 

## [25 percent (D2A), 45 percent (D2B), 60 percent (D2C), and 75 percent (D2D)] in the syngas are captured in the two

- stage SelexolTM unit and compressed for sequestration. The carbon balance for Case 2 D2 is shown in Exhibit 4

- 42 . The carbon input to the plant consists of carbon in the air and coal. Carbon in the air is not neg lected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

## in the wastewater blowdown stream, and as CO 2 

## in the stack gas, ASU vent gas, and the captured CO 2 

## product. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance. The carbon capture efficiency is defined as the pounds of carbon in the CO 2 

## product stream relative to the amount of carbon in the coal , less carbon contained in the slag , represented by the following fraction:
(Carbon in CO 2 

## Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or 73,037/(295,050

- 5,901)*100=25.3% (D2A) 131,784/(299,675

- 5,993)*100=44.9% (D2B) 178,734/(303,510

- 6,070)*100=60.1% (D2C) 225,516/(306,839

- 6,137)*100=75.0% (D2D)

Exhibit 4

- 43 shows the sulfur balance for Case 2 D2. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved SO 2 

## in the wastewater blowdown stream, and sulfur em itted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The total sulfur capture is represented by the following fraction:

268Carbon Dioxide Capture Sensitivity Analysis



## (Sulfur byproduct/Sulfur in the coal) or

(11, 583 /11, 601 )*100 = 99.8 % (D2 A) (11,76 5 /11,78 3 )*100 = 99.8% (D2B) (11,91 6 /11,93 4 )*100 = 99.8% (D2C) (12,04 7 /12,06 5 )*100 = 99.8% (D2D)

The overall water balance s for Case 2 D2A, D2B, D2C, and D2D are shown i n Exhibit 4

- 44 , Exhibit 4

- 45 , Exhibit 4

- 46 , and Exhibit 4

- 47 , respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within t he process and that water is re used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 48 through Exhibit 4

- 59

.

• Gasifier and ASU

• Syngas Cleanup

• Power Block An overall plant energy balance for Case D2A, D2B, D2C, and D2D is provided in tabular form in Exhibit 4

- 60 , Exhi bit 4

- 61 , Exhibit 4

- 62 , and Exhibit 4

- 63 , respectively. The power out is the combined combustion turbine, s team turbine and expander power after generator losses. In addition, energy balance Sankey diagrams are provided for D2A, D2B, D2C, and D2D in Exhibit 4

- 64 , Exhibit 4

- 65 , Exhibit 4

- 66 , and Exhibit 4

- 67 , respectively.

269Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 41 Case 2 D2 Estimated Air Emission Rates
kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)
D2A D2B D2C D2D D2A D2B D2C D2D D2A D2B D2C D2D
SO 2 

### 0.001 (0.002) 0.001 (0.002) 0.001 (0.002) 0.001 (0.002) 37 (40) 37 (41) 38 (42) 38 (42) 0.007 (0.02) 0.007 (0.02) 0.007 (0.02) 0.007 (0.02)
NO X 

### 0.024 (0.055) 0.023 (0.053) 0.022 (0.051) 0.022 (0.050) 947 (1,044) 926 (1,021) 909 (1,002) 894 (985) 0.180 (0.397) 0.177 (0.390) 0.174 (0.384) 0.172 (0.379)
PM 0.003 (0.0071) 0.003 (0.0071) 0.003 (0.0071) 0.003 (0.0071) 122 (134) 124 (136) 125 (138) 127 (140) 0.023 (0.051) 0.024 (0.052) 0.024 (0.053) 0.024 (0.054) Hg 0.246x10 - 6 

### (0.571x10 - 6 

### ) 0.246x10 - 6 

### (0.571x10 - 6 

### ) 0.246x10 - 6 

### (0.571x10 - 6 

### ) 0.246x10 - 6 

### (0.571x10 - 6 

### ) 0.010 (0.011) 0.010 (0.011) 0.010 (0.011) 0.010 (0.011) 1.87x10 - 6 

### (4.11x10 - 6 

### ) 1.90x10 - 6 

### (4.20x10 - 6 

### ) 1.93x10 - 6 

### (4.26x10 - 6 

### ) 1.96x10 - 6 

### (4.32x10 - 6 

### )
CO 2 

### 63. 3 (147. 3 ) 46.8 (108.8) 33.9 (78.9) 21.4 (49.7) 2,5 2 8,260 (2,7 8 6,929 ) 1,89 6,795 (2,09 0,859 ) 1,393, 730 (1,536, 324 ) 886, 830 (977, 563 ) 48 1 (1,06 0 ) 362 (799) 267 (588) 171 (376)
CO 2 

### net 59 4 (1,31 0 ) 458 (1,010) 344 (758) 224 (495)



## 270Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 42 Case 2 D2 Carbon Balance Carbon In, kg/hr (lb/hr) D2A D2B D2C D2D
Coal 133,8 32 (295,0 50 ) 135,9 30 (299, 675 ) 137,6 70 (303,5 10 ) 139, 180 (306,8 39 ) Air (CO 2 

### ) 535 (1,179) 536 (1,183) 538 (1,18 5 ) 539 (1,188)
Total 13 4,3 67 (29 6,2 29 ) 136,4 66 (300, 858 ) 138,2 08 (304, 695 ) 139,7 19 (308,0 2 7) Carbon Out, kg/hr (lb/hr) Slag 2,677 (5,90 1 ) 2,719 (5,99 3 ) 2,75 3 (6,07 0 ) 2,784 (6,13 7 ) Stack Gas 98, 459 (217, 066 ) 73,8 68 (162,8 51 ) 54,2 77 (119,6 60 ) 34,5 36 (76,1 40 ) ASU Vent 102 (225) 104 (229) 105 (232) 106 (234)
CO 2 

### Product 33, 129 (7 3,037 ) 59,7 76 (131, 784 ) 81,0 72 (178,7 34 ) 102, 292 (225,5 16 ) Convergence Tolerance 0 (0)

- 1 (1) 1 (

- 1) 1 (0)

Total 13 4,367 (29 6,229 ) 136,466 (300,858) 138,208 (304,695) 139,719 (308,027)

Exhibit 4
- 43 Case 2 D2 Sulfur Balance Sulfur In, kg/hr (lb/hr) D2A D2B D2C D2D
Coal 5,26 2 (11,60 1 ) 5,34 5 (11,78 3 ) 5,41 3 (11,93 4 ) 5,47 2 (12,06 5 )
Total 5, 26 2 (11, 60 1 ) 5,34 5 (11,78 3 ) 5,41 3 (11,93 4 ) 5,47 2 (12,06 5 ) Sulfur Out, kg/hr (lb/hr)
Elemental Sulfur 5,25 4 (11,58 3 ) 5,337 (11,76 5 ) 5,40 5 (11,91 6 ) 5,46 4 (12,04 7 ) Stack Gas 3 (6) 3 (6) 3 (6) 3 (6) CO 2 

### Product 5 ( 12 ) 5 (12) 5 (12) 5 (12) Convergence Tolerance* 0 (0) 0 (0) 0 (0) 0 (0)

Total 5, 262 (11, 601 ) 5,345 (11,783) 5,413 (11,934) 5,472 (12,065)



## 271Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 44 Case 2 D2A (25%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.7 (719) 0.88 (233) 1.8 (486) 0.0 (0) 1.8 (486)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 0.2 (59) 0.0 (0) 0.2 (59) 0.0 (0) 0.2 (59)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 0.0 (4) 0.0 (0) 0.0 (4)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 16.2 (4,282) 0.49 (130) 15.7 (4,153) 3.6 (963) 12.1 (3,190)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.28 (75)

- 0.28 (

- 75)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 21.1 (5,572) 3.31 (875) 17.8 (4,697) 3.7 (970) 14.1 (3,727)
Total, gal/MWh net 

### 551 86 464 96 368



## 272Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 45 Case 2 D2B (45%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.51 (134) 0.51 (134) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.8 (730) 0.63 (167) 2.1 (564) 0.0 (0) 2.1 (564)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 0.6 (161) 0.0 (0) 0.6 (161) 0.0 (0) 0.6 (161)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 0.4 (105) 0.0 (0) 0.4 (105)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 16.8 (4,437) 0.47 (124) 16.3 (4,313) 3.8 (998) 12.5 (3,315)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.26 (69)

- 0.26 (

- 69)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 22.1 (5,848) 3.07 (811) 19.1 (5,038) 3.8 (1,005) 15.3 (4,033)
Total, gal/MWh net 

### 594 82 512 102 410



## 273Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 46 Case 2 D2C (60%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.51 (136) 0.51 (136) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.8 (740) 0.43 (113) 2.4 (626) 0.0 (0) 2.4 (626)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6)

- 0.02 (

- 6) Condenser Makeup 

### 0.9 (244) 0.0 (0) 0.9 (244) 0.0 (0) 0.9 (244)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 0.7 (189) 0.0 (0) 0.7 (189)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 17.2 (4,548) 0.45 (119) 16.8 (4,429) 3.9 (1,023) 12.9 (3,406)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.24 (64)

- 0.24 (

- 64)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 22.9 (6,059) 2.87 (759) 20.1 (5,300) 3.9 (1,029) 16.2 (4,270)
Total, gal/MWh net 

### 629 79 550 107 443



## 274Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 47 Case 2 D2D (75%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.52 (137) 0.52 (137) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.8 (748) 0.24 (62) 2.6 (686) 0.0 (0) 2.6 (686)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6)

- 0.02 (

- 6) Condenser Makeup 

### 1.2 (322) 0.0 (0) 1.2 (322) 0.0 (0) 1.2 (322)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 1.0 (268) 0.0 (0) 1.0 (268)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (54) 0.0 (0) 0.21 (54) Cooling Tower 

### 17.6 (4,636) 0.43 (114) 17.1 (4,522) 3.9 (1,043) 13.2 (3,480)

BFW Blowdown 

### 0.0 (0) 0.21 (54)

- 0.21 (

- 54)
SWS Blowdown 

### 0.0 (0) 0.23 (59)

- 0.23 (

- 59)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 23.6 (6,239) 2.68 (709) 20.9 (5,530) 4.0 (1,049) 17.0 (4,481)
Total, gal/MWh net 

### 664 75 588 112 477



## 275Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

276Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 48 Case 2 D2A (25%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 A ( 25 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 A

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 895 BTU / KWe N 2 to GT Combustor 1 , 655 , 196 W 59

. 0 T 14

. 7 P 13

. 0 H

372 , 603 W 90

. 0 T 125

. 0 P 11

. 5 H

372 , 603 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 644 W

90

. 0 T 125

. 0 P 11

. 5 H 117 , 730 W 63

. 4 T 16

. 4 P 15

. 1 H

1 , 007 , 664 W 90

. 0 T 56

. 4 P 14

. 2 H

149 , 078 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 462 , 861 W 59

. 0 T 14

. 7 P

190 , 143 W

287

. 0 T 840

. 0 P 231

. 2 H

50 , 784 W 2 , 400

. 0 T

815

. 0 P 1 , 156 , 741 W 385

. 0 T 384

. 0 P 87

. 2 H

653 , 005 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 1 , 156 , 741 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 0 W 199

. 0 T 384

. 0 P 39

. 8 H 0 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 974 , 824 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 207 , 979 W 403

. 3 T 800

. 0 P 459

. 0 H

Syngas Quench 1 , 334 , 367 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 156 , 741 W 199

. 0 T 384

. 0 P 39

. 8 H



## 277Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 49 Case 2 D2A (25%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 207 , 979 W 403

. 3 T 800

. 0 P 459

. 0 H 860 , 533 W 94

. 7 T 740

. 0 P 17

. 3 H 15 , 133 W 119

. 0 T 23

. 7 P 579 , 439 W 386

. 9 T 460

. 0 P 152

. 7 H

11 , 583 W 12 , 707 W 450

. 0 T 12

. 3 P 852

. 1 H

2 , 514 W 240

. 3 T 65

. 0 P 445

. 8 H 6 , 644 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 A ( 25 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 A

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 895 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

7 , 203 W 120

. 0 T 10

. 6 P 203

. 0 H 854 , 415 W 94

. 8 T 745

. 0 P 17

. 2 H

6 , 589 W 116

. 7 T 10

. 6 P 42

. 7 H 3 6 , 118 W 100

. 0 T 799

. 5 P

Raw Syngas 18 579 , 439 W 94

. 7 T 725

. 0 P 23

. 5 H

Claus Oxygen Preheater 6 , 644 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 579 , 439 W

465

. 0 T 720

. 0 P 187

. 4 H

High Temperature Shift

Shift Steam

11

COS Hydrolysis

Preheater 1 , 207 , 979 W 413

. 3 T 795

. 0 P 451

. 0 H 2 , 000 W 550

. 0 T 800

. 0 P 1 , 254

. 1 H 8 , 040 W 445

. 0 T 795

. 0 P 650

. 9 H

8 , 040 W 766

. 8 T 795

. 0 P 635

. 6 H 400

. 0 T 795

. 0 P 463

. 4 H

1 , 209 , 979 W 413

. 1 T 785

. 0 P 451

. 1 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

265 , 378 W 146

. 4 T 2 , 214

. 7 P COS Hydrolysis

13 15

1 , 201 , 939 W 413

. 3 T 795

. 0 P 451

. 0 H 1 , 209 , 979 W 413

. 2 T 795

. 0 P 451

. 1 H

1 , 209 , 979 W 402

. 7 T 780

. 0 P 446

. 7 H 12 14



## 278Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 50 Case 2 D2A (25%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 680 , 546 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 750 , 314 W 269

. 9 T 15

. 2 P 101

. 5 H

579 , 439 W

386

. 9 T 460

. 0 P 152

. 7 H 8 , 750 , 314 W 1 , 079

. 4 T

15

. 2 P 315

. 3 H From Gasifier Island Preheating

To Claus LP BFW 1 , 390 , 729 W

1 , 029

. 4 T 1 , 814

. 7 P 1 , 497

. 8 H 10 , 077 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 418 , 938 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 205 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 639 , 069 W 492

. 9 T 65

. 0 P 1 , 278

. 5 H

1 , 680 , 546 W 103

. 1 T 120

. 0 P 71

. 3 H 1 , 680 , 546 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 649

. 2 T 65

. 0 P 1 , 355

. 6 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 A ( 25 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 A

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 895 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 29 , 498 W

59

. 0 T 14

. 7 P 27

. 1 H 8 , 876 W 690

. 4 T 501

. 4 P 1 , 351

. 7 H 9 , 579 W 649

. 2 T 65

. 0 P 1 , 355

. 6 H 25 , 447 W

885

. 4 T 280

. 0 P 1 , 466

. 2 H 785 W 1 , 029

. 4 T 1 , 814

. 7 P 1 , 497

. 8 H 1 , 319 W 531

. 0 T 65

. 0 P 1 , 297

. 3 H



## 279Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 51 Case 2 D2B (45%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 B ( 45 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 B

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 747 MWe Auxiliary Load : 156 MWe Net Plant Power : 591 MWe Net Plant Efficiency
, HHV : 36

. 8 % Net Plant Heat Rate : 9 , 283 BTU / KWe N 2 to GT Combustor 1 , 681 , 348 W 59

. 0 T 14

. 7 P 13

. 0 H

378 , 444 W 90

. 0 T 125

. 0 P 11

. 5 H

378 , 444 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 795 W

90

. 0 T 125

. 0 P 11

. 5 H 116 , 343 W 63

. 6 T 16

. 4 P 15

. 1 H

1 , 026 , 832 W 90

. 0 T 56

. 4 P 14

. 2 H

151 , 433 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 470 , 117 W 59

. 0 T 14

. 7 P

193 , 124 W

287

. 0 T 840

. 0 P 231

. 2 H

51 , 580 W 2 , 400

. 0 T

815

. 0 P 1 , 164 , 779 W 385

. 0 T 384

. 0 P 87

. 2 H

663 , 241 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 1 , 164 , 779 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 13 , 485 W

199

. 0 T 384

. 0 P 39

. 8 H 13 , 485 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 990 , 106 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 226 , 710 W 403

. 2 T 800

. 0 P 458

. 8 H

Syngas Quench 1 , 355 , 284 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 178 , 265 W 199

. 0 T 384

. 0 P 39

. 8 H



## 2 80Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 52 Case 2 D2B (45%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 226 , 710 W 403

. 2 T 800

. 0 P 458

. 8 H 967 , 522 W 94

. 7 T 740

. 0 P 16

. 9 H 14 , 737 W 119

. 0 T 23

. 7 P 470 , 720 W 387

. 3 T 460

. 0 P 194

. 3 H

11 , 765 W 12 , 188 W 450

. 0 T 12

. 3 P 910

. 5 H

2 , 422 W 237

. 9 T 65

. 0 P 430

. 1 H 6 , 795 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 B ( 45 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 B

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 747 MWe Auxiliary Load : 156 MWe Net Plant Power : 591 MWe Net Plant Efficiency
, HHV : 36

. 8 % Net Plant Heat Rate : 9 , 283 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

5 , 992 W 120

. 0 T 10

. 6 P 221

. 7 H 962 , 516 W 94

. 8 T 745

. 0 P 16

. 8 H

7 , 183 W 117

. 3 T 10

. 6 P 43

. 3 H 3 5 , 005 W 100

. 0 T 799

. 5 P

Raw Syngas 18 470 , 720 W 94

. 7 T 725

. 0 P 31

. 3 H

Claus Oxygen Preheater 6 , 795 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 470 , 720 W

465

. 0 T 720

. 0 P 238

. 0 H

High Temperature Shift

Shift Steam

11

COS Hydrolysis

Preheater 1 , 226 , 710 W 413

. 2 T 795

. 0 P 450

. 9 H 52 , 727 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 543 , 410 W

425

. 4 T 795

. 0 P 528

. 9 H

543 , 410 W 779

. 9 T 795

. 0 P 512

. 6 H 400

. 0 T 795

. 0 P 340

. 3 H

1 , 279 , 436 W 407

. 0 T 785

. 0 P 403

. 9 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

481 , 390 W 130

. 2 T 2 , 214

. 7 P COS Hydrolysis

13 15

736 , 026 W

413

. 2 T 795

. 0 P 450

. 9 H 1 , 279 , 436 W 407

. 2 T 795

. 0 P 403

. 9 H

1 , 279 , 436 W 397

. 3 T 780

. 0 P 399

. 7 H 12 14



## 281Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 53 Case 2 D2B (45%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 726 , 692 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 663 , 119 W 270

. 1 T 15

. 2 P 115

. 0 H

470 , 720 W

387

. 3 T 460

. 0 P 194

. 3 H 8 , 663 , 119 W 1 , 068

. 9 T

15

. 2 P 328

. 0 H From Gasifier Island Preheating

To Claus LP BFW 1 , 386 , 412 W

1 , 018

. 9 T 1 , 814

. 7 P 1 , 491

. 4 H 10 , 133 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 414 , 787 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 360 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 634 , 321 W 484

. 9 T 65

. 0 P 1 , 274

. 6 H

1 , 726 , 692 W 103

. 0 T 120

. 0 P 71

. 2 H 1 , 726 , 692 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 639

. 2 T 65

. 0 P 1 , 350

. 6 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 B ( 45 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 B

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 747 MWe Auxiliary Load : 156 MWe Net Plant Power : 591 MWe Net Plant Efficiency
, HHV : 36

. 8 % Net Plant Heat Rate : 9 , 283 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 80 , 339 W

59

. 0 T 14

. 7 P 27

. 1 H 8 , 919 W 681

. 6 T 501

. 4 P 1 , 346

. 7 H 9 , 632 W 639

. 2 T 65

. 0 P 1 , 350

. 6 H 25 , 775 W

875

. 6 T 280

. 0 P 1 , 461

. 1 H 789 W 1 , 018

. 9 T 1 , 814

. 7 P 1 , 491

. 4 H 1 , 324 W 523

. 3 T 65

. 0 P 1 , 293

. 6 H



## 282Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 54 Case 2 D2C (60%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 C ( 60 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 C

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 745 MWe Auxiliary Load : 167 MWe Net Plant Power : 578 MWe Net Plant Efficiency
, HHV : 35

. 5 % Net Plant Heat Rate : 9 , 604 BTU / KWe N 2 to GT Combustor 1 , 703 , 045 W 59

. 0 T 14

. 7 P 13

. 0 H

383 , 287 W 90

. 0 T 125

. 0 P 11

. 5 H

383 , 287 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 924 W

90

. 0 T 125

. 0 P 11

. 5 H 118 , 490 W 63

. 6 T 16

. 4 P 15

. 1 H

1 , 039 , 436 W 90

. 0 T 56

. 4 P 14

. 2 H

153 , 387 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 476 , 133 W 59

. 0 T 14

. 7 P

195 , 596 W

287

. 0 T 840

. 0 P 231

. 2 H

52 , 240 W 2 , 400

. 0 T

815

. 0 P 995 , 367 W 385

. 0 T 384

. 0 P 87

. 2 H

671 , 729 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 995 , 367 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 197 , 457 W

199

. 0 T 384

. 0 P 39

. 8 H 197 , 457 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 1 , 002 , 776 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 242 , 938 W 403

. 3 T 800

. 0 P 459

. 2 H

Syngas Quench 1 , 372 , 628 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 192 , 823 W 199

. 0 T 384

. 0 P 39

. 8 H



## 283Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 55 Case 2 D2C (60%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 242 , 938 W 403

. 3 T 800

. 0 P 459

. 2 H 1 , 054 , 918 W 94

. 7 T 740

. 0 P 16

. 6 H 14 , 413 W 119

. 0 T 23

. 7 P 385 , 725 W 387

. 6 T 460

. 0 P 243

. 9 H

11 , 916 W 11 , 783 W 450

. 0 T 12

. 3 P 960

. 8 H

2 , 362 W 235

. 6 T 65

. 0 P 414

. 6 H 6 , 924 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 C ( 60 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 C

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 745 MWe Auxiliary Load : 167 MWe Net Plant Power : 578 MWe Net Plant Efficiency
, HHV : 35

. 5 % Net Plant Heat Rate : 9 , 604 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

5 , 023 W 120

. 0 T 10

. 6 P 243

. 1 H 1 , 050 , 805 W 94

. 9 T 745

. 0 P 16

. 5 H

7 , 670 W 117

. 6 T 10

. 6 P 43

. 7 H 3 4 , 113 W 100

. 0 T 799

. 5 P

Raw Syngas 18 385 , 725 W 94

. 7 T 725

. 0 P 40

. 3 H

Claus Oxygen Preheater 6 , 924 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 385 , 725 W

465

. 0 T 720

. 0 P 298

. 7 H

High Temperature Shift

Shift Steam

11

COS Hydrolysis

Preheater 1 , 242 , 938 W 413

. 3 T 795

. 0 P 451

. 2 H 94 , 595 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 980 , 189 W

425

. 4 T 795

. 0 P 528

. 8 H

980 , 189 W 779

. 9 T 795

. 0 P 512

. 5 H 400

. 0 T 795

. 0 P 340

. 2 H

1 , 337 , 533 W 403

. 1 T 785

. 0 P 369

. 8 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

654 , 032 W 126

. 6 T 2 , 214

. 7 P COS Hydrolysis

13 15

357 , 345 W

413

. 3 T 795

. 0 P 451

. 2 H 1 , 337 , 533 W 403

. 2 T 795

. 0 P 369

. 8 H

1 , 337 , 533 W 393

. 8 T 780

. 0 P 365

. 8 H 12 14



## 284Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 56 Case 2 D2C (60%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 752 , 266 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 592 , 683 W 270

. 0 T 15

. 2 P 126

. 1 H

385 , 725 W

387

. 6 T 460

. 0 P 243

. 9 H 8 , 592 , 683 W 1 , 060

. 7 T

15

. 2 P 338

. 5 H From Gasifier Island Preheating

To Claus LP BFW 1 , 372 , 633 W

1 , 010

. 7 T 1 , 814

. 7 P 1 , 486

. 3 H 10 , 170 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 401 , 100 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 465 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 618 , 169 W 484

. 1 T 65

. 0 P 1 , 274

. 2 H

1 , 752 , 266 W 103

. 0 T 120

. 0 P 71

. 2 H 1 , 752 , 266 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 631

. 2 T 65

. 0 P 1 , 346

. 7 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 C ( 60 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 C

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 745 MWe Auxiliary Load : 167 MWe Net Plant Power : 578 MWe Net Plant Efficiency
, HHV : 35

. 5 % Net Plant Heat Rate : 9 , 604 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 122 , 023 W 59

. 0 T 14

. 7 P 27

. 1 H 8 , 953 W 674

. 7 T 501

. 4 P 1 , 342

. 7 H 9 , 674 W 631

. 2 T 65

. 0 P 1 , 346

. 7 H 26 , 025 W

867

. 9 T 280

. 0 P 1 , 457

. 1 H 792 W 1 , 010

. 7 T 1 , 814

. 7 P 1 , 486

. 3 H 1 , 328 W 517

. 3 T 65

. 0 P 1 , 290

. 6 H



## 285Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 57 Case 2 D2D (75%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 D

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 D ( 75 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 D

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 742 MWe Auxiliary Load : 178 MWe Net Plant Power : 564 MWe Net Plant Efficiency
, HHV : 34

. 3 % Net Plant Heat Rate : 9 , 958 BTU / KWe N 2 to GT Combustor 1 , 720 , 422 W 59

. 0 T 14

. 7 P 13

. 0 H

387 , 491 W 90

. 0 T 125

. 0 P 11

. 5 H

387 , 491 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 701 W

90

. 0 T 125

. 0 P 11

. 5 H 110 , 034 W 64

. 1 T 16

. 4 P 15

. 2 H

1 , 059 , 707 W 90

. 0 T 56

. 4 P 14

. 2 H

154 , 952 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 481 , 355 W 59

. 0 T 14

. 7 P

197 , 741 W

287

. 0 T 840

. 0 P 231

. 2 H

52 , 813 W 2 , 400

. 0 T

815

. 0 P 837 , 375 W 385

. 0 T 384

. 0 P 87

. 2 H

679 , 096 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 837 , 375 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 377 , 285 W

199

. 0 T 384

. 0 P 39

. 8 H 377 , 285 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 1 , 013 , 775 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 256 , 924 W 403

. 4 T 800

. 0 P 459

. 4 H

Syngas Quench 1 , 387 , 683 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 214 , 660 W 199

. 0 T 384

. 0 P 39

. 8 H



## 286Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 58 Case 2 D2D (75%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 256 , 924 W 403

. 4 T 800

. 0 P 459

. 4 H 1 , 144 , 084 W 94

. 8 T 740

. 0 P 16

. 2 H 21 , 926 W 119

. 0 T 23

. 7 P 295 , 309 W 387

. 7 T 460

. 0 P 324

. 1 H

12 , 047 W 18 , 888 W 450

. 0 T 12

. 3 P 720

. 3 H

2 , 307 W 233

. 1 T 65

. 0 P 398

. 0 H 6 , 701 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 D

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 D ( 75 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 D

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 742 MWe Auxiliary Load : 178 MWe Net Plant Power : 564 MWe Net Plant Efficiency
, HHV : 34

. 3 % Net Plant Heat Rate : 9 , 958 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

12 , 492 W 120

. 0 T 10

. 6 P 151

. 9 H 1 , 132 , 987 W 94

. 9 T 745

. 0 P 16

. 2 H

7 , 791 W 116

. 4 T 10

. 6 P 42

. 4 H 3 11 , 097 W

100

. 0 T 799

. 5 P

Raw Syngas 18 295 , 309 W 94

. 8 T 725

. 0 P 54

. 8 H

Claus Oxygen Preheater 6 , 701 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 295 , 309 W

465

. 0 T 720

. 0 P 396

. 7 H

High Temperature Shift

Shift Steam

11

COS Hydrolysis

Preheater 1 , 256 , 924 W 413

. 4 T 795

. 0 P 451

. 5 H 133 , 757 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 1 , 390 , 681 W 425

. 4 T 795

. 0 P 528

. 7 H

1 , 390 , 681 W 779

. 9 T 795

. 0 P 512

. 5 H 400

. 0 T 795

. 0 P 340

. 1 H

1 , 390 , 681 W 399

. 8 T 785

. 0 P 340

. 1 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

826 , 028 W 124

. 8 T 2 , 214

. 7 P COS Hydrolysis

13 15

0 W

--- T

--- P 0

. 0 H 1 , 390 , 681 W 400

. 0 T 795

. 0 P 340

. 1 H

1 , 390 , 681 W 390

. 9 T 780

. 0 P 336

. 1 H 12 14



## 287Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 59 Case 2 D2D (75%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 760 , 818 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 524 , 103 W 270

. 0 T 15

. 2 P 136

. 7 H

295 , 309 W

387

. 7 T 460

. 0 P 324

. 1 H 8 , 524 , 103 W 1 , 052

. 4 T

15

. 2 P 348

. 5 H From Gasifier Island Preheating

To Claus LP BFW 1 , 358 , 296 W

1 , 002

. 4 T 1 , 814

. 7 P 1 , 481

. 2 H 10 , 201 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 386 , 847 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 550 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 587 , 698 W 484

. 0 T 65

. 0 P 1 , 274

. 2 H

1 , 760 , 818 W 103

. 0 T 120

. 0 P 71

. 2 H 1 , 760 , 818 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 623

. 3 T 65

. 0 P 1 , 342

. 8 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 2 D

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 2 D ( 75 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 2 D

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 742 MWe Auxiliary Load : 178 MWe Net Plant Power : 564 MWe Net Plant Efficiency
, HHV : 34

. 3 % Net Plant Heat Rate : 9 , 958 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 161 , 004 W 59

. 0 T 14

. 7 P 27

. 1 H 8 , 989 W 667

. 7 T 501

. 4 P 1 , 338

. 7 H 9 , 716 W 623

. 3 T 65

. 0 P 1 , 342

. 8 H 30 , 139 W

860

. 2 T 280

. 0 P 1 , 453

. 1 H 795 W 1 , 002

. 4 T 1 , 814

. 7 P 1 , 481

. 2 H 1 , 333 W 511

. 3 T 65

. 0 P 1 , 287

. 7 H



## 288Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 60 Case 2 D2A (25%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,697 (5,400) 4.8 (4.5) 0 (0) 5,702 (5,404) ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 66.9 (63.4) 0 (0) 67 (63)
Totals 5,697 (5,400) 190.5 (180.5) 0 (0) 5,888 (5,580) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2) Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117) Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47) CO 2 

### 0 (0)

- 13.1 (

- 12.4) 0 (0)

- 13 (

- 12) Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60) HRSG Flue Gas 0 (0) 937 (889) 0 (0) 937 (889) Cooling Tower* 0 (0) 2,073 (1,965) 0 (0) 2,073 (1,965) Process Losses* * 0 (0) 424 (402) 0 (0) 424 (402)
Net Power 0 (0) 0.0 (0.0) 2,185 (2,071) 2,185 (2,071) Totals 136 (129) 3,566 (3,380) 2,185 (2,071) 5,888 (5,580) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 289Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 61 Case 2 D2B (45%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,786 (5,484) 4.8 (4.6) 0 (0) 5,791 (5,489) ASU Air 0 (0) 23.1 (21.8) 0 (0) 23 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 71.7 (68.0) 0 (0) 72 (68)
Totals 5,786 (5,484) 195.8 (185.5) 0 (0) 5,982 (5,670) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2) Slag 89 (84) 36.5 (34.6) 0 (0) 126 (119) Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47) CO 2 

### 0 (0)

- 31.7 (

- 30.1) 0 (0)

- 32 (

- 30) Gasifier Heat Loss 0 (0) 43.1 (40.8) 0 (0) 43 (41) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60) HRSG Flue Gas 0 (0) 1,051 (996) 0 (0) 1,051 (996) Cooling Tower* 0 (0) 2,113 (2,003) 0 (0) 2,113 (2,003) Process Losses* * 0 (0) 439 (416) 0 (0) 439 (416)
Net Power 0 (0) 0.0 (0.0) 2,127 (2,016) 2,127 (2,016) Totals 139 (131) 3,717 (3,523) 2,127 (2,016) 5,982 (5,670) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 290Carbon Dioxide Capture Sensitivity Analysis



### E xhibit 4
- 62 Case 2 D2C (60%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,860 (5,555) 4.9 (4.6) 0 (0) 5,865 (5,559) ASU Air 0 (0) 23.4 (22.1) 0 (0) 23 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 75.4 (71.5) 0 (0) 75 (71)
Totals 5,860 (5,555) 199.9 (189.4) 0 (0) 6,060 (5,744) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2) Slag 90 (86) 37.0 (35.1) 0 (0) 127 (121) Sulfur 50 (47) 0.6 (0.6) 0 (0) 51 (48) CO 2 

### 0 (0)

- 45.9 (

- 43.5) 0 (0)

- 46 (

- 43) Gasifier Heat Loss 0 (0) 43.6 (41.4) 0 (0) 44 (41) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)
HRSG Flue Gas 0 (0) 1,143 (1,083) 0 (0) 1,143 (1,083) Cooling Tower* 0 (0) 2,139 (2,028) 0 (0) 2,139 (2,028) Process Losses* * 0 (0) 455 (431) 0 (0) 455 (431)
Net Power 0 (0) 0.0 (0.0) 2,082 (1,974) 2,082 (1,974)
Totals 140 (133) 3,838 (3,637) 2,082 (1,974) 6,060 (5,744) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas coole r (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 291Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 6 3 Case 2 D2D (75%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,925 (5,615) 5.0 (4.7) 0 (0) 5,930 (5,620) ASU Air 0 (0) 23.6 (22.4) 0 (0) 24 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 78.7 (74.6) 0 (0) 79 (75)
Totals 5,925 (5,615) 203.4 (192.8) 0 (0) 6,128 (5,808) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2) Slag 91 (86) 37.4 (35.4) 0 (0) 129 (122) Sulfur 51 (48) 0.6 (0.6) 0 (0) 51 (49) CO 2 

### 0 (0)

- 59.7 (

- 56.6) 0 (0)

- 60 (

- 57) Gasifier Heat Loss 0 (0) 44.1 (41.8) 0 (0) 44 (42) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)
HRSG Flue Gas 0 (0) 1,230 (1,166) 0 (0) 1,230 (1,166) Cooling Tower* 0 (0) 2,152 (2,040) 0 (0) 2,152 (2,040) Process Losses* * 0 (0) 486 (461) 0 (0) 486 (461)
Net Power 0 (0) 0.0 (0.0) 2,030 (1,924) 2,030 (1,924)
Totals 142 (134) 3,956 (3,750) 2,030 (1,924) 6,128 (5,808) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 292Carbon Dioxide Capture Sensitivity Analysis



### Exhi bit 4
- 64 Case 2 D2A Energy Balance Sankey Diagram

Exhibit 4
- 65 Case 2 D2B Energy Balance Sankey Diagram



## 293Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 66 Case 2 D2C Energy Balance Sankey Diagram

Exhibit 4
- 67 Case 2 D2D Energy Balance Sankey Diagram



## 294Carbon Dioxide Capture Sensitivity Analysis



## 4.3.2.2 Major Equipment List for Case 2 D2 Major equipment items for Case 2 D2 (single WGS with bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cos t estimate s . In general, the design conditions include a 10 percent contingency for flows and heat d uties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING
Equipment No. Description Type Design Conditions Opr Qty. (Spares) D2A D2B D2C D2D
1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)
2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0) 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A 1 (0) 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)
6 As

- Received Coal Sampling System Two

- stage N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1) 9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1) 10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0) 11 Crusher Tower N/A N/A N/A N/A N/A 1 (0)
12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 (0)

14 As

- Fired Coal Sampling System Swing hammer N/A N/A N/A N/A 1 (1)
15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0) 16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A 1 (0) 17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 1 (0)
18 Coal Silo w/ Vent Filter and Slide Gates Field erected 726 tonne (800 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)



## ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D 1 Feeder Vibratory 73 tonne/h (80 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0) 2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 1 (0) 3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 472 tonne (520 ton) 472 tonne (520 ton) 481 tonne (530 ton) 1 (0) 4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0) 5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)
6 Slurry Water Storage Tank with Agitator Field erected 285,044 liters (75,300 gal) 289,511 liters (76,480 gal) 293,220 liters (77,460 gal) 296,438 liters (78,310 gal) 2 (0)
7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1) 8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 163 tonne/h (180 tph) 172 tonne/h (190 tph) 2 (0)



## 295Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D
9 Rod Mill Discharge Tank with Agitator Field erected 372,866 liters (98,500 gal) 378,696 liters (100,040 gal) 383,541 liters (101,320 gal) 387,781 liters (102,440 gal) 2 (0)
10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 2 (2)
11 Slurry Storage Tank with Agitator Field erected 1,118,598 liters (295,500 gal) 1,136,011 liters (300,100 gal) 1,150,774 liters (304,000 gal) 1,163,266 liters (307,300 gal) 2 (0)
12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)
13 Slurry Product Pumps Positive displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 2 (2)



## ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D
1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,086,413 liters (287,000 gal) 1,090,199 liters (288,000 gal) 1,078,842 liters (285,000 gal) 1,067,486 liters (282,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 7,041 lpm @ 91 m H 2 

### O (1,860 gpm @ 300 ft H 2 

### O) 7,230 lpm @ 91 m H 2 

### O (1,910 gpm @ 300 ft H 2 

### O) 7,344 lpm @ 91 m H 2 

### O (1,940 gpm @ 300 ft H 2 

### O) 7,382 lpm @ 91 m H 2 

### O (1,950 gpm @ 300 ft H 2 

### O) 2 (1)

3 Deaerator (integral w/ HRSG) Horizontal spray type 484,437 kg/hr (1,068,000 lb/hr) 495,323 kg/hr (1,092,000 lb/hr) 501,220 kg/hr (1,105,000 lb/hr) 505,755 kg/hr (1,115,000 lb/hr) 2 (0)

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 8,101 lpm @ 27 m H 2 

### O (2,140 gpm @ 90 ft H 2 

### O) 8,139 lpm @ 27 m H 2 

### O (2,150 gpm @ 90 ft H 2 

### O) 7,912 lpm @ 27 m H 2 

### O (2,090 gpm @ 90 ft H 2 

### O) 7,684 lpm @ 27 m H 2 

### O (2,030 gpm @ 90 ft H 2 

### O) 2 (1)

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,132 lpm @ 1,859 m H 2 

### O (1,620 gpm @ 6,100 ft H 2 

### O) HP water: 6,132 lpm @ 1,859 m H 2 

### O (1,620 gpm @ 6,100 ft H 2 

### O) HP water: 6,057 lpm @ 1,859 m H 2 

### O (1,600 gpm @ 6,100 ft H 2 

### O) HP water: 5,981 lpm @ 1,859 m H 2 

### O (1,580 gpm @ 6,100 ft H 2 

### O) 2 (1)

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,476 lpm @ 223 m H 2 

### O (390 gpm @ 730 ft H 2 

### O) IP water: 1,514 lpm @ 223 m H 2 

### O (400 gpm @ 730 ft H 2 

### O) IP water: 1,628 lpm @ 223 m H 2 

### O (430 gpm @ 730 ft H 2 

### O) IP water: 1,703 lpm @ 223 m H 2 

### O (450 gpm @ 730 ft H 2 

### O) 2 (1)

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

8 Service Air Compressors Flooded Screw 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 (1)
9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 2 (1)
10 Closed Cylce Cooling Heat Exchangers Plate and frame 248 GJ/hr (234.6264965 MMBtu/hr) each 275 GJ/hr (260.9758943 MMBtu/hr) each 299 GJ/hr (283.58088495 MMBtu/hr) each 324 GJ/hr (306.6532524 MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 88,957 lpm @ 21 m H 2 

### O (23,500 gpm @ 70 ft H 2 

### O) 98,799 lpm @ 21 m H 2 

### O (26,100 gpm @ 70 ft H 2 

### O) 107,506 lpm @ 21 m H 2 

### O (28,400 gpm @ 70 ft H 2 

### O) 116,212 lpm @ 21 m H 2 

### O (30,700 gpm @ 70 ft H 2 

### O) 2 (1)

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 1 (1)

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 1 (1)

14 Raw Water Pumps Stainless steel, single suction 4,580 lpm @ 18 m H 2 

### O (1,210 gpm @ 60 ft H 2 

### O) 4,921 lpm @ 18 m H 2 

### O (1,300 gpm @ 60 ft H 2 

### O) 5,186 lpm @ 18 m H 2 

### O (1,370 gpm @ 60 ft H 2 

### O) 5,413 lpm @ 18 m H 2 

### O (1,430 gpm @ 60 ft H 2 

### O) 2 (1)

15 Ground Water Pumps Stainless steel, single suction 3,028 lpm @ 268 m H 2 

### O (800 gpm @ 880 ft H 2 

### O) 3,293 lpm @ 268 m H 2 

### O (870 gpm @ 880 ft H 2 

### O) 2,574 lpm @ 268 m H 2 

### O (680 gpm @ 880 ft H 2 

### O) 2,725 lpm @ 268 m H 2 

### O (720 gpm @ 880 ft H 2 

### O) 3 (1)

16 Filtered Water Pumps Stainless steel, single suction 2,082 lpm @ 49 m H 2 

### O (550 gpm @ 160 ft H 2 

### O) 2,309 lpm @ 49 m H 2 

### O (610 gpm @ 160 ft H 2 

### O) 2,498 lpm @ 49 m H 2 

### O (660 gpm @ 160 ft H 2 

### O) 2,688 lpm @ 49 m H 2 

### O (710 gpm @ 160 ft H 2 

### O) 2 (1)
17 Filtered Water Tank Vertical, cylindrical 999,349 liter (264,000 gal) 1,112,911 liter (294,000 gal) 1,207,546 liter (319,000 gal) 1,290,825 liter (341,000 gal) 2 (0)
18 Makeup Water Demineralizer Anion, cation, and mixed bed 303 lpm (80 gpm) 530 lpm (140 gpm) 681 lpm (180 gpm) 871 lpm (230 gpm) 2 (0)



## 296Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D 19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



## ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D
1 Gasifier Pressurized slurry

feed, entrained bed 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench chamber 243,126 kg/hr (536,000 lb/hr) 247,208 kg/hr (545,000 lb/hr) 250,383 kg/hr (552,000 lb/hr) 253,105 kg/hr (558,000 lb/hr) 2 (0)

3 Synthesis Gas Cyclone High efficiency 332,937 kg/hr (734,000 lb/hr) Design efficiency 90% 337,926 kg/hr (745,000 lb/hr) Design efficiency 90% 342,462 kg/hr (755,000 lb/hr) Design efficiency 90% 346,091 kg/hr (763,000 lb/hr) Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters metallic filters metallic filters metallic filters 2 (0)

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 332,937 kg/hr (734,000 lb/hr) 337,926 kg/hr (745,000 lb/hr) 342,462 kg/hr (755,000 lb/hr) 346,091 kg/hr (763,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with condensate drain 288,031 kg/hr (635,000 lb/hr) 319,329 kg/hr (704,000 lb/hr) 333,844 kg/hr (736,000 lb/hr) 346,998 kg/hr (765,000 lb/hr) 8 (0)

7 Raw Gas Knockout Drum Vertical with mist eliminator 213,642 kg/hr, 35°C, 5.1 MPa (471,000 lb/hr, 95°F, 745 psia) 240,404 kg/hr, 35°C, 5.2 MPa (530,000 lb/hr, 95°F, 750 psia) 262,630 kg/hr, 35°C, 5.1 MPa (579,000 lb/hr, 95°F, 745 psia) 283,042 kg/hr, 35°C, 5.1 MPa (624,000 lb/hr, 95°F, 745 psia) 2 (0)

8 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 332,937 kg/hr (734,000 lb/hr) syngas 337,926 kg/hr (745,000 lb/hr) syngas 342,462 kg/hr (755,000 lb/hr) syngas 346,091 kg/hr (763,000 lb/hr) syngas 2 (0)

9 ASU Main Air Compressor Centrifugal, multi

stage 5,663 m 3 

### /min @ 1.3 MPa (200,000 scfm @ 190 psia) 5,748 m 3 

### /min @ 1.3 MPa (203,000 scfm @ 190 psia) 5,805 m 3 

### /min @ 1.3 MPa (205,000 scfm @ 190 psia) 5,862 m 3 

### /min @ 1.3 MPa (207,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multi

stage 1,133 m 3 

### /min (40,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 1,161 m 3 

### /min (41,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 1,161 m 3 

### /min (41,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 1,189 m 3 

### /min (42,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 2 (0)

12 Primary Nitrogen Compressor Centrifugal, multi

stage 3,540 m 3 

### /min (125,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,596 m 3 

### /min (127,000 scfm) Suction

- 0.4 MPa (60 psia)

Discharge

- 2.7 MPa (390 psia) 3,653 m 3 

### /min (129,000 scfm) Suction

- 0.4 MPa (60 psia)

Discharge

- 2.7 MPa (390 psia) 3,710 m 3 

### /min (131,000 scfm) Suction

- 0.4 MPa (60 psia)

Discharge

- 2.7 MPa (390 psia) 2 (0)

13 Secondary Nitrogen Compressor Centrifugal, single

stage 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discha rge - 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 2 (0)

14 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

stage 0 m 3 

### /min (0 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 57 m 3 

### /min (2,000 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 680 m 3 

### /min (24,000 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 1,331 m 3 

### /min (47,000 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa ( 470 psia) 2 (0)



## 297Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 5A SYNGAS CLEANUP
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Mercury Adsorber Sulfated carbon bed 213,188 kg/hr (470,000 lb/hr)

35°C (95°F) 5.1 MPa (745 psia) 239,950 kg/hr (529,000 lb/hr)

35°C (95°F) 5.1 MPa (745 psia) 262,176 kg/hr (578,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 282,588 kg/hr (623,000 lb/hr)

35°C (95°F) 5.1 MPa (745 psia) 2 (0)

2 Sulfur Plant Claus type 139 tonne/day (153 tpd) 141 tonne/day (155 tpd) 143 tonne/day (157 tpd) 144 tonne/day (159 tpd) 1 (0)

3 Water Gas Shift Reactor Fixed bed, catalytic 1,814 kg/hr (4,000 lb/hr) 232°C (450°F) 5.4 MPa (790 psia) 135,624 kg/hr (299,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 244,486 kg/hr (539,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 346,998 kg/hr (765,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 2 (0)

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 02 GJ/hr (02 MMBtu/hr) Exchanger 2: 6 GJ/hr (6 MMBtu/hr) Exchanger 1: 109 GJ/hr (103 MMBtu/hr) Exchanger 2: 6 GJ/hr (6 MMBtu/hr) Exchanger 1: 196 GJ/hr (186 MMBtu/hr) Exchanger 2: 6 GJ/hr (6 MMBtu/hr) Exchanger 1: 278 GJ/hr (264 MMBtu/hr) Exchanger 2: 6 GJ/hr (6 MMBtu/hr) 2 (0)

5 COS Hydrolysis Reactor Fixed bed, catalytic 301,639 kg/hr (665,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 319,329 kg/hr (704,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 333,844 kg/hr (736,000 lb/hr) 204°C (400°F) 5.4 MPa (790 psia) 346,998 kg/hr (765,000 lb/hr) 204°C (400°F) 5.4 MPa (790 psia) 2 (0)

6 Acid Gas Removal Plant Two

- stage Selexol 214,549 kg/hr (473,000 lb/hr)

35°C (95°F) 5.1 MPa (740 psia) 241,311 kg/hr (532,000 lb/hr)

35°C (95°F) 5.1 MPa (740 psia) 263,084 kg/hr (580,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 285,310 kg/hr (629,000 lb/hr)

35°C (95°F) 5.1 MPa (740 psia) 2 (0)

7 Hydrogenation Reactor Fixed bed, catalytic 6,340 kg/hr (13,978 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 6,081 kg/hr (13,407 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 5,879 kg/hr (12,961 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 9,424 kg/hr (20,776 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 (0)

8 Tail Gas Recycle Compressor Centrifugal 3,053 kg/hr (6,730 lb/hr) 2,497 kg/hr (5,506 lb/hr) 2,052 kg/hr (4,524 lb/hr) 5,537 kg/hr (12,206 lb/hr) 1 (0)



## ACCOUNT 5B CO 2 

## COMPRESSION
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 CO 2 

### Compressor Integrally geared, multi

stage centrifugal 30 3 m 3 

### /min @ 15.3 MPa (10, 7 00 scfm @ 2,215 psia) 544 m 3 

### /min @ 15.3 MPa (19,200 scfm @ 2,215 psia) 736 m 3 

### /min @ 15.3 MPa (26,000 scfm @ 2,215 psia) 929 m 3 

### /min @ 15.3 MPa (32,800 scfm @ 2,215 psia) 4 (0)



## ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D 1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 230 MW 2 (0)
2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 (0)

3 Syngas Expansion Turbine/Generator Turbo Expander 144,560 kg/h (318,700 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 117,435 kg/h (258,900 lb/h) 5.0 MPa (730 psia) Inlet 3.2 MPa (460 psia) Outlet 96,207 kg/h (212,100 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 73,663 kg/h (162,400 lb/h) 5.0 MPa (730 psia) Inlet 3.2 MPa (460 psia) Outlet 2 (0)



## 298Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 7 HRSG, DUCTING , AND STACK
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D
1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 1 (0)

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 346,953 kg/hr, 12.4 MPa/554°C (764,901 lb/hr, 1,800 psig/1,029°F)

Reheat steam

- 346,475 kg/hr, 3.1 MPa/554°C (763,846 lb/hr, 452 psig/1,029°F) Main steam

- 345,876 kg/hr, 12.4 MPa/548°C (762,527 lb/hr, 1,800 psig/1,019°F)

Reheat steam

- 342,768 kg/hr, 3.1 MPa/548°C (755,673 lb/hr, 452 psig/1,019°F) Main steam

- 342,439 kg/hr, 12.4 MPa/544°C (754,948 lb/hr, 1,800 psig/1,011°F)

Reheat steam

- 346,896 kg/hr, 3.1 MPa/544°C (764,776 lb/hr, 452 psig/1,011°F) Main steam

- 338,862 kg/hr, 12.4 MPa/539°C (747,063 lb/hr, 1,800 psig/1,002°F)

Reheat steam

- 350,486 kg/hr, 3.1 MPa/539°C (772,688 lb/hr, 452 psig/1,002°F) 2 (0)



## ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 Steam Turbine Commercially available advanced steam turbine 295 MW 12.4 MPa/554°C/554°C (1,800 psig/ 1029°F/1029°F) 292 MW 12.4 MPa/548°C/548°C (1,800 psig/ 1019°F/1019°F) 290 MW 12.4 MPa/544°C/544°C (1,800 psig/ 1011°F/1 011°F) 286 MW 12.4 MPa/539°C/539°C (1,800 psig/ 1002°F/1002°F) 1 (0)

2 Steam Turbine Generator Hydrogen cooled, static excitation 330 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 2 (0)

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,783 GJ/hr (1,690 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,772 GJ/hr (1,680 MMBtu/hr), Inlet water temperat ure 16°C (60°F), Water temperature rise 11°C (20°F) 1,751 GJ/hr (1,660 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,720 GJ/hr (1,630 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 (0)



## ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D
1 Circulating Water Pumps Vertical, wet pit 416,395 lpm @ 30 m (110,000 gpm @ 100 ft) 431,537 lpm @ 30 m (114,000 gpm @ 100 ft) 442,893 lpm @ 30 m (117,000 gpm @ 100 ft) 450,464 lpm @ 30 m (119,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,332 GJ/hr (2,210 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,416 GJ/hr (2,290 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,469 GJ/hr (2,340 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27° C (80°F) HWT / 2,522 GJ/hr (2,390 MMBtu/hr) heat duty 1 (0)



## ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D 1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 246,052 liters (65,000 gal) 249,837 liters (66,000 gal) 249,837 liters (66,000 gal) 2 (0) 2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0) 3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0) 4 Slag Receiving Tank Horizontal, weir 143,846 liters (38,000 gal) 147,631 liters (39,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)
5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)



## 299Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D
6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 2 (0)

9 Fine Ash Settling Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 211,983 liters (56,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 2 (2)

11 Grey Water Storage Tank Field erected 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 2 (2)
13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 2 (0) 14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)



## ACCOUNT 11 ACCESSORY ELECTRIC PLANT
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D
1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 (0)

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 330 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 320 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 320 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 320 MVA, 3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 63 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 68 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 72 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 76 MVA, 3

- ph, 60 Hz 2 (0)

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 30 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 34 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 38 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 43 MVA, 3

- ph, 60 Hz 1 (1)

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 5 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 6 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 6 MVA, 3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 2 (0)

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



## 300Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 12 INSTRUMENTATION AND CONTROL
Equipment No. Description Type Design Condition Opr Qty. (Spares) D2A D2B D2C D2D

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and
en gineering stations/printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A N/A N/A N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)



## 301Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

302Carbon Dioxide Capture Sensitivity Analysis



# 4.3.3 IGCC Design 3

– Two Water Gas Shift Reactors with Bypass
A proces s block flow diagram for Case 2 Design 3 (D3) is shown in Exhibit 4

- 68 . D3 represents an IGCC plant with two WGS reactors and a bypass stream (stream 13). This IGCC design uses a S:DG molar ratio of 0.25 at the outlet of the second WGS reactor. The WGS bypa ss ratio and the two

- stage SelexolTM CO 2 

## removal efficiency are adjusted to control the total CO 2 

## capture level. The SelexolTM removal efficiency is altered by varying the solvent circulation rate, which changes the size and cost of the SelexolTM system.

The WGS bypass impacts the degree of CO to CO 2 

## and COS to H 2 

## S conversion across the WGS reactor. Consequently, the WGS bypass stream is routed through a COS h ydolysis unit to ensure that sulfur emissions are below the limit of 0.0128 lb SO 2 

## /MMBtu.

Fi ve levels of total CO 2 

## removal were modeled for Case 2 D3: 25 percent (D3A), 45 percent (D3B), 60 percent (D3C), 75 percent (D3D), and 85 percent (D3E). The corresponding stream tables are contained in Exhibit 4

- 69 , Exhibit 4

- 70 , Exhibit 4

- 71 , Exhibit 4

- 72 , and Exhibit 4

- 73 , respectively. Overall performance for Case 2 D3 is summarized in Exhibit 4

- 74 which includes auxiliary power re quirements. Material and energy balance information, environmental performance and a major e quipment list are summarized in Sections 4.3.3.1 and 4.3.3.2

.

303Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 68 Case 2 D3 Process Block Flow Diagram, IGCC with Two WGS Reactors and Bypass

G AS T URBINE C OMBUSTOR

T URBINE C OOLING A IR Q UENCH AND

S YNGAS S CRUBBER G AS C OOLING BFW H EATING & K NOCKOUT S HIFT R EACTORS

E LEVATED P RESSURE

ASU GEE G ASIFIER S ECTION ( R ADIANT C OOLER ) S OUR W ATER S TRIPPER M ERCURY R EMOVAL T WO

S TAGE S ELEXOL

U NIT

C LAUS P LANT

HRSG

A MBIENT A IR S YNGAS E XPANDER

H YDROGENATION R EACTOR AND G AS C OOLER CO 2 C OMPRESSION

1 5 9 12 16 17

19 21

22

23 20

6 8

2 3 4

24 25 26 A IR TO ASU A S

- R ECEIVED C OAL

S LAG S HIFT S TEAM

W ATER R ECYCLE TO P ROCESS

D EMAND N OTE : W ATER FROM T AIL G AS C OOLER MODELED , BUT NOT SHOWN

N ITROGEN D ILUENT S YNGAS C LEAN G AS CO 2 S TREAMS CO 2 P RODUCT

S ULFUR

T AIL G AS R ECYCLE TO

S ELEXOL N OTE : T AIL G AS B OOST C OMPRESSOR MODELED , BUT NOT SHOWN

F LUE G AS S TACK G AS V ENT G AS C LAUS P LANT O XIDANT

2 X A DVANCED

F C LASS G AS T URBINE S YNGAS H / P R EHEAT

18

C LAUS P LANT O XIDANT

S TEAM T URBINE 27

464 MW e Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are shown

. 23
T AIL G AS R ECYCLE F ROM C LAUS P LANT

S LURRY M IXER

7 S LURRY W ATER COS H YDROLYSIS 15

11

10 13 14



## 304Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 69 Case 2 D3A Stream Table, 25% CO 2 

### Removal with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0141 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0068 0.0068 0.0068 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0009 0.0009 0.0009 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2820 0.0000 0.0372 0.2820 0.2820 CO 2 0.0003 0.0044 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.3537 0.1088 0.1090 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0001 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2686 0.0000 0.5133 0.2686 0.2686 H 2 O 0.0099 0.1117 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3197 1.0000 0.0749 0.3197 0.3195 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0002 0.0002 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0058 0.0057 0.0059 N 2 0.7732 0.7576 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0055 0.0055 0.0055 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0016 0.0016 0.0016 O 2 0.2074 0.1122 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 26,013 1,915 94 18,716 5,251 0 4,787 0 21,972 27,856 0 70 27,786 27,786 V-L Flowrate (kg/hr) 750,670 52,828 3,016 525,175 168,981 0 86,233 0 442,098 547,834 0 1,370 546,465 546,465 Solids Flowrate (kg/hr) 0 0 0 0 0 209,915 0 23,031 0 0 0 0 0 0
Temperature (°C) 15 17 32 93 32 15 142 1,316 677 206 288 266 212 212 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 5.48 5.41 Enthalpy (kJ/kg) A 30.23 35.15 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,067.55 2,918.18 621.54 1,049.09 1,048.99 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 23.6 27.4 27.0 V-L Molecular Weight 28.857 27.583 32.181 28.060 32.181

--- 18.015

--- 20.121 19.667 18.015 19.667 19.667 19.667

V-L Flowrate (lb mol /hr) 57,350 4,222 207 41,262 11,576 0 10,553 0 48,440 61,411 0 154 61,257 61,257 V-L Flowrate (lb/hr) 1,654,945 116,465 6,650 1,157,812 372,540 0 190,111 0 974,659 1,207,768 0 3,020 1,204,748 1,204,748 Solids Flowrate (lb/hr) 0 0 0 0 0 462,783 0 50,775 0 0 0 0 0 0
Temperature (°F) 59 63 90 199 90 59 287 2,400 1,250 403 550 510 413 413 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0 Enthalpy (Btu/lb) A 13.0 15.1 11.5 39.8 11.5

--- 231.2

--- 612.5 459.0 1,254.6 267.2 451.0 451.0 Density (lb/ft 3 ) 0.076 0.089 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.471 1.710 1.688 A - Reference conditions are 32.02 F & 0.089 PSIA



## 305Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 69 Case 2 D3A Stream Table, 25% CO 2 Removal with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0068 0.0100 0.0101 0.0118 0.0118 0.0006 0.0037 0.0000 0.0228 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0009 0.0013 0.0013 0.0015 0.0015 0.0002 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.2814 0.4138 0.4101 0.4806 0.4806 0.0254 0.1672 0.0000 0.0031 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.1096 0.1611 0.1618 0.0254 0.0254 0.9652 0.0000 0.0000 0.2378 0.0003 0.0597 0.0597 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.2692 0.3959 0.3979 0.4699 0.4699 0.0085 0.1033 0.0000 0.6144 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.3189 0.0012 0.0012 0.0001 0.0001 0.0000 0.0310 0.0000 0.0013 0.0099 0.0633 0.0633 1.0000 HCl 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0059 0.0086 0.0085 0.0000 0.0000 0.0001 0.6924 0.0000 0.0039 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0055 0.0081 0.0091 0.0108 0.0108 0.0001 0.0016 0.0000 0.1166 0.7732 0.7567 0.7567 0.0000 NH 3 

### 0.0016 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1112 0.1112 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 27,856 18,942 19,115 16,083 16,083 2,782 235 0 172 110,253 137,409 137,409 35,011 V-L Flowrate (kg/hr) 547,834 387,186 389,967 262,538 262,538 120,297 6,868 0 2,781 3,181,557 3,969,271 3,969,271 630,726 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,253 0 0 0 0 0
Temperature (°C) 206 35 35 35 197 64 48 182 38 15 582 132 554 Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 1,037.76 40.00 40.1 54.667 355.129 -108.419 100.144

--- 59.854 30.227 733.224 235.966 3,483.940 Density (kg/m 3 

### ) 27.2 41.3 40.9 31.5 13.1 482.9 1.8 5,270.3 34.5 1.2 0.4 0.9 35.5 V-L Molecular Weight 19.667 20.440 20 16.324 16.324 43.239 29.253

--- 16.127 28.857 28.887 28.887 18.015

V-L Flowrate (lb mol 

### /hr) 61,411 41,760 42,141 35,457 35,457 6,134 518 0 380 243,066 302,935 302,935 77,185 V-L Flowrate (lb/hr) 1,207,768 853,600 859,731 578,797 578,797 265,209 15,141 0 6,131 7,014,133 8,750,744 8,750,744 1,390,513 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,581 0 0 0 0 0
Temperature (°F) 403 95 95 95 387 146 119 360 100 59 1,079 270 1,029 Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 446.2 17.2 17.3 23.5 152.7 -46.6 43.1

--- 25.7 13.0 315.2 101.4 1,497.8 Density (lb/ft 3 

### ) 1.699 2.575 3 1.964 0.817 30.148 0.112 329.017 2.152 0.076 0.027 0.056 2.218 A - Reference conditions are 32.02 F & 0.089 PSIA



## 306Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 70 Case 2 D3B Stream Table, 45% CO 2 

### Capture with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0147 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0057 0.0068 0.0068 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2821 0.0000 0.0082 0.2821 0.2821 CO 2 0.0003 0.0047 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.3199 0.1088 0.1090 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0001 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2687 0.0000 0.4539 0.2687 0.2687 H 2 O 0.0099 0.1176 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3195 1.0000 0.2004 0.3195 0.3194 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 0.0002 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0049 0.0057 0.0059 N 2 0.7732 0.7452 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0046 0.0055 0.0055 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 0.0016 0.0016 O 2 0.2074 0.1178 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 26,413 1,847 96 19,102 5,331 0 4,860 0 22,307 28,275 1,660 10,312 19,623 19,623 V-L Flowrate (kg/hr) 762,207 50,886 3,081 535,999 171,560 0 87,549 0 448,843 556,088 29,897 200,060 385,925 385,925 Solids Flowrate (kg/hr) 0 0 0 0 0 213,118 0 23,383 0 0 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 246 212 212 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 5.48 5.41 Enthalpy (kJ/kg) A 30.23 35.26 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,067.17 2,918.18 878.31 1,048.73 1,048.62 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.5 27.4 27.0 V-L Molecular Weight 28.857 27.557 32.181 28.060 32.181

--- 18.015

--- 20.121 19.667 18.015 19.401 19.667 19.667

V-L Flowrate (lb mol /hr) 58,231 4,071 211 42,113 11,753 0 10,714 0 49,179 62,335 3,659 22,733 43,261 43,261 V-L Flowrate (lb/hr) 1,680,379 112,185 6,793 1,181,676 378,224 0 193,012 0 989,530 1,225,965 65,912 441,057 850,820 850,820 Solids Flowrate (lb/hr) 0 0 0 0 0 469,844 0 51,550 0 0 0 0 0 0
Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 474 413 413 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0 Enthalpy (Btu/lb) A 13.0 15.2 11.5 39.8 11.5

--- 231.2

--- 612.5 458.8 1,254.6 377.6 450.9 450.8 Density (lb/ft 3 ) 0.076 0.090 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.529 1.710 1.688 A - Reference conditions are 32.02 F & 0.089 PSIA



## 307Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 70 Case 2 D3B Stream Table, 45% CO 2 Capture with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0064 0.0089 0.0090 0.0117 0.0117 0.0003 0.0037 0.0000 0.0254 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0008 0.0012 0.0012 0.0015 0.0015 0.0001 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.1877 0.2605 0.2586 0.3364 0.3364 0.0101 0.1196 0.0000 0.0022 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.1817 0.2520 0.2516 0.0330 0.0330 0.9831 0.0000 0.0000 0.1897 0.0003 0.0445 0.0445 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.3325 0.4613 0.4627 0.6066 0.6066 0.0062 0.1363 0.0000 0.6477 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.2784 0.0012 0.0012 0.0001 0.0001 0.0000 0.0356 0.0000 0.0013 0.0099 0.0807 0.0807 1.0000 HCl 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0056 0.0076 0.0076 0.0000 0.0000 0.0000 0.7022 0.0000 0.0039 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0052 0.0072 0.0081 0.0107 0.0107 0.0001 0.0016 0.0000 0.1298 0.7732 0.7559 0.7559 0.0000 NH 3 

### 0.0015 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1098 0.1098 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 29,934 21,574 21,731 16,471 16,471 5,008 235 0 157 110,253 138,060 138,060 34,991 V-L Flowrate (kg/hr) 585,985 435,306 437,592 212,348 212,348 218,254 6,686 0 2,286 3,181,557 3,929,905 3,929,905 630,373 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,332 0 0 0 0 0
Temperature (°C) 218 35 35 35 197 55 48 182 38 15 576 132 548 Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 980.84 39.13 39.3 72.894 451.811 -145.133 110.524

--- 69.469 30.227 761.977 266.773 3,469.035 Density (kg/m 3 

### ) 26.2 41.0 40.7 24.7 10.3 587.7 1.7 5,270.3 30.8 1.2 0.4 0.9 35.9 V-L Molecular Weight 19.576 20.177 20 12.892 12.892 43.582 28.415

--- 14.524 28.857 28.465 28.465 18.015

V-L Flowrate (lb mol 

### /hr) 65,994 47,562 47,909 36,313 36,313 11,041 519 0 347 243,066 304,370 304,370 77,142 V-L Flowrate (lb/hr) 1,291,877 959,686 964,724 468,146 468,146 481,167 14,739 0 5,039 7,014,133 8,663,957 8,663,957 1,389,734 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,754 0 0 0 0 0
Temperature (°F) 425 95 95 95 387 130 119 360 100 59 1,069 270 1,019 Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 421.7 16.8 16.9 31.3 194.2 -62.4 47.5

--- 29.9 13.0 327.6 114.7 1,491.4 Density (lb/ft 3 

### ) 1.637 2.562 3 1.545 0.645 36.688 0.109 329.014 1.925 0.076 0.026 0.055 2.239 A - Reference conditions are 32.02 F & 0.089 PSIA



## 308Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 71 Case 2 D3C Stream Table, 60% CO 2 

### Capture with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0145 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0057 0.0068 0.0068 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2820 0.0000 0.0082 0.2820 0.2820 CO 2 0.0003 0.0046 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.3201 0.1088 0.1089 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0001 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2686 0.0000 0.4542 0.2686 0.2686 H 2 O 0.0099 0.1159 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3199 1.0000 0.2000 0.3199 0.3197 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 0.0002 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0049 0.0057 0.0059 N 2 0.7732 0.7489 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0046 0.0055 0.0055 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 0.0016 0.0016 O 2 0.2074 0.1162 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 26,755 1,898 98 19,321 5,399 0 4,922 0 22,593 28,651 3,003 18,760 12,893 12,893 V-L Flowrate (kg/hr) 772,061 52,330 3,140 542,142 173,759 0 88,671 0 454,598 563,459 54,092 363,995 253,557 253,557 Solids Flowrate (kg/hr) 0 0 0 0 0 215,850 0 23,682 0 0 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 245 212 212 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 5.48 5.41 Enthalpy (kJ/kg) A 30.23 35.23 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,068.03 2,918.18 877.14 1,049.56 1,049.45 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.5 27.4 27.0 V-L Molecular Weight 28.857 27.565 32.181 28.060 32.181

--- 18.015

--- 20.121 19.667 18.015 19.402 19.667 19.667

V-L Flowrate (lb mol /hr) 58,984 4,185 215 42,596 11,904 0 10,851 0 49,809 63,164 6,620 41,360 28,424 28,424 V-L Flowrate (lb/hr) 1,702,103 115,369 6,922 1,195,219 383,073 0 195,486 0 1,002,216 1,242,215 119,253 802,471 558,997 558,997 Solids Flowrate (lb/hr) 0 0 0 0 0 475,867 0 52,211 0 0 0 0 0 0
Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 474 413 413 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0 Enthalpy (Btu/lb) A 13.0 15.1 11.5 39.8 11.5

--- 231.2

--- 612.5 459.2 1,254.6 377.1 451.2 451.2 Density (lb/ft 3 ) 0.076 0.090 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.529 1.710 1.688 A - Reference conditions are 32.02 F & 0.089 PSIA



## 309Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 71 Case 2 D3C Stream Table, 60% CO2 Capture with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0061 0.0082 0.0083 0.0116 0.0116 0.0002 0.0037 0.0000 0.0279 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0008 0.0011 0.0011 0.0015 0.0015 0.0001 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.1197 0.1595 0.1585 0.2214 0.2214 0.0050 0.0804 0.0000 0.0015 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.2341 0.3119 0.3109 0.0436 0.0436 0.9890 0.0000 0.0000 0.1431 0.0003 0.0327 0.0327 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.3786 0.5044 0.5055 0.7114 0.7114 0.0055 0.1634 0.0000 0.6794 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.2488 0.0012 0.0012 0.0001 0.0001 0.0000 0.0394 0.0000 0.0013 0.0099 0.0949 0.0949 1.0000 HCl 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0053 0.0070 0.0070 0.0000 0.0000 0.0000 0.7102 0.0000 0.0043 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0050 0.0067 0.0075 0.0106 0.0106 0.0000 0.0016 0.0000 0.1426 0.7732 0.7547 0.7547 0.0000 NH 3 

### 0.0014 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1086 0.1086 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 31,653 23,756 23,901 16,877 16,877 6,770 236 0 145 110,253 138,580 138,580 34,720 V-L Flowrate (kg/hr) 617,551 475,219 477,104 174,441 174,441 295,786 6,538 0 1,884 3,181,557 3,898,141 3,898,141 625,490 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,399 0 0 0 0 0
Temperature (°C) 227 35 35 35 197 53 48 182 38 15 572 132 544 Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 938.62 38.42 38.6 93.689 566.535 -154.509 119.522

--- 80.508 30.227 786.493 292.348 3,457.373 Density (kg/m 3 

### ) 25.6 40.9 40.6 19.8 8.3 616.8 1.7 5,270.3 27.4 1.2 0.4 0.9 36.1 V-L Molecular Weight 19.510 20.004 20 10.336 10.336 43.693 27.725

--- 12.984 28.857 28.129 28.129 18.015

V-L Flowrate (lb mol 

### /hr) 69,783 52,373 52,693 37,207 37,207 14,924 520 0 320 243,066 305,516 305,516 76,544 V-L Flowrate (lb/hr) 1,361,467 1,047,679 1,051,833 384,577 384,577 652,097 14,414 0 4,154 7,014,133 8,593,931 8,593,931 1,378,969 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,902 0 0 0 0 0
Temperature (°F) 441 95 95 95 387 127 119 360 100 59 1,061 270 1,011 Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 403.5 16.5 16.6 40.3 243.6 -66.4 51.4

--- 34.6 13.0 338.1 125.7 1,486.4 Density (lb/ft 3 

### ) 1.596 2.554 3 1.236 0.517 38.506 0.106 329.011 1.711 0.076 0.026 0.055 2.256 A - Reference conditions are 32.02 F & 0.089 PSIA



## 310Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 72 Case 2 D3D Stream Table, 75% CO 2 

### Capture with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0147 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0057 0.0068 0.0068 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2818 0.0000 0.0082 0.2818 0.2818 CO 2 0.0003 0.0047 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1087 0.0000 0.3200 0.1087 0.1089 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0001 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2684 0.0000 0.4540 0.2684 0.2684 H 2 O 0.0099 0.1173 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3201 1.0000 0.2004 0.3201 0.3200 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 0.0002 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0049 0.0057 0.0059 N 2 0.7732 0.7458 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0046 0.0055 0.0055 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 0.0016 0.0016 O 2 0.2074 0.1175 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 27,079 1,898 97 19,579 5,467 0 4,983 0 22,874 29,018 4,371 27,295 6,094 6,094 V-L Flowrate (kg/hr) 781,417 52,303 3,125 549,373 175,918 0 89,773 0 460,245 570,666 78,736 529,562 119,840 119,840 Solids Flowrate (kg/hr) 0 0 0 0 0 218,531 0 23,977 0 0 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 246 212 212 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 5.48 5.41 Enthalpy (kJ/kg) A 30.23 35.26 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,068.75 2,918.18 878.16 1,050.26 1,050.15 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.5 27.4 27.0 V-L Molecular Weight 28.857 27.559 32.181 28.060 32.181

--- 18.015

--- 20.121 19.666 18.015 19.402 19.666 19.666

V-L Flowrate (lb mol /hr) 59,699 4,184 214 43,164 12,052 0 10,986 0 50,428 63,974 9,635 60,175 13,434 13,434 V-L Flowrate (lb/hr) 1,722,729 115,309 6,889 1,211,160 387,832 0 197,915 0 1,014,666 1,258,103 173,583 1,167,485 264,202 264,202 Solids Flowrate (lb/hr) 0 0 0 0 0 481,779 0 52,859 0 0 0 0 0 0
Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 474 413 413 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0 Enthalpy (Btu/lb) A 13.0 15.2 11.5 39.8 11.5

--- 231.2

--- 612.5 459.5 1,254.6 377.5 451.5 451.5 Density (lb/ft 3 ) 0.076 0.090 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.529 1.710 1.688 A - Reference conditions are 32.02 F & 0.089 PSIA



## 311Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 72 Case 2 D3D Stream Table, 75% CO 2 Capture with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0059 0.0076 0.0077 0.0115 0.0115 0.0002 0.0034 0.0000 0.0251 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0008 0.0010 0.0010 0.0015 0.0015 0.0001 0.0008 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0581 0.0748 0.0744 0.1109 0.1109 0.0020 0.0374 0.0000 0.0022 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.2814 0.3621 0.3612 0.0525 0.0525 0.9925 0.0915 0.0000 0.2188 0.0003 0.0207 0.0207 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.4201 0.5405 0.5410 0.8132 0.8132 0.0051 0.1732 0.0000 0.6180 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.2222 0.0012 0.0012 0.0001 0.0001 0.0000 0.0393 0.0000 0.0013 0.0099 0.1091 0.1091 1.0000 HCl 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0051 0.0065 0.0065 0.0000 0.0000 0.0000 0.6525 0.0000 0.0043 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0048 0.0062 0.0069 0.0104 0.0104 0.0000 0.0015 0.0000 0.1302 0.7732 0.7536 0.7536 0.0000 NH 3 

### 0.0014 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1074 0.1074 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 33,389 25,949 26,110 17,262 17,262 8,567 260 0 161 110,253 139,118 139,118 34,438 V-L Flowrate (kg/hr) 649,402 515,316 517,847 135,159 135,159 374,880 7,436 0 2,531 3,181,557 3,866,090 3,866,090 620,418 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,464 0 0 0 0 0
Temperature (°C) 235 35 35 35 198 52 48 182 38 15 567 132 539 Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 900.98 37.72 37.8 126.739 751.045 -159.378 116.518

--- 62.078 30.227 811.540 318.762 3,445.343 Density (kg/m 3 

### ) 25.0 40.8 40.5 15.0 6.3 632.3 1.8 5,270.9 33.6 1.2 0.4 0.9 36.4 V-L Molecular Weight 19.450 19.859 20 7.830 7.830 43.760 28.585

--- 15.759 28.857 27.790 27.790 18.015

V-L Flowrate (lb mol 

### /hr) 73,609 57,208 57,562 38,056 38,056 18,886 573 0 354 243,066 306,702 306,702 75,924 V-L Flowrate (lb/hr) 1,431,687 1,136,078 1,141,658 297,976 297,976 826,469 16,393 0 5,580 7,014,133 8,523,270 8,523,270 1,367,787 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 12,047 0 0 0 0 0
Temperature (°F) 455 95 95 95 388 125 119 360 100 59 1,052 270 1,002 Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 387.3 16.2 16.3 54.5 322.9 -68.5 50.1

--- 26.7 13.0 348.9 137.0 1,481.2 Density (lb/ft 3 

### ) 1.561 2.548 3 0.935 0.391 39.476 0.110 329.053 2.098 0.076 0.026 0.054 2.274 A - Reference conditions are 32.02 F & 0.089 PSIA



## 312Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 73 Case 2 D3E Stream Table, 85% CO 2 

### Capture with Two WGS Bypass

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0147 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0057 0.0068 0.0068 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0008 0.0009 0.0009 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2821 0.0000 0.0082 0.2821 0.2821 CO 2 0.0003 0.0047 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1088 0.0000 0.3202 0.1088 0.1090 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0001 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2687 0.0000 0.4544 0.2687 0.2687 H 2 O 0.0099 0.1180 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3196 1.0000 0.1997 0.3196 0.3195 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 0.0002 0.0002 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0049 0.0057 0.0059 N 2 0.7732 0.7444 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0046 0.0055 0.0055 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 0.0016 0.0016 O 2 0.2074 0.1182 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 27,303 1,903 97 19,752 5,513 0 5,025 0 23,066 29,240 5,292 33,070 1,462 1,462 V-L Flowrate (kg/hr) 787,883 52,428 3,125 554,227 177,399 0 90,529 0 464,121 575,073 95,335 641,654 28,754 28,754 Solids Flowrate (kg/hr) 0 0 0 0 0 220,372 0 24,179 0 0 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 246 212 212 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 5.48 5.41 Enthalpy (kJ/kg) A 30.23 35.27 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,067.37 2,918.18 876.50 1,048.92 1,048.81 Density (kg/m 3 ) 1.2 1.4 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.5 27.4 27.0 V-L Molecular Weight 28.857 27.556 32.181 28.060 32.181

--- 18.015

--- 20.121 19.667 18.015 19.403 19.667 19.667

V-L Flowrate (lb mol /hr) 60,193 4,195 214 43,545 12,153 0 11,079 0 50,853 64,464 11,667 72,907 3,223 3,223 V-L Flowrate (lb/hr) 1,736,984 115,584 6,889 1,221,862 391,098 0 199,581 0 1,023,211 1,267,818 210,177 1,414,604 63,391 63,391 Solids Flowrate (lb/hr) 0 0 0 0 0 485,836 0 53,304 0 0 0 0 0 0
Temperature (°F) 59 64 90 199 90 59 287 2,400 1,250 403 550 474 413 413 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 795.0 785.0 Enthalpy (Btu/lb) A 13.0 15.2 11.5 39.8 11.5

--- 231.2

--- 612.5 458.9 1,254.6 376.8 451.0 450.9 Density (lb/ft 3 ) 0.076 0.090 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.529 1.710 1.688 A - Reference conditions are 32.02 F & 0.089 PSIA



## 313Carbon Dioxide Capture Sensitivity Analysis



### Case 2 D3E Stream Table, 85% CO 2 Capture with Two WGS Bypass (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0057 0.0072 0.0073 0.0114 0.0114 0.0002 0.0033 0.0000 0.0236 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0008 0.0010 0.0009 0.0015 0.0015 0.0001 0.0008 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0198 0.0249 0.0248 0.0385 0.0385 0.0006 0.0124 0.0000 0.0026 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.3113 0.3917 0.3909 0.0584 0.0584 0.9942 0.1451 0.0000 0.2643 0.0003 0.0126 0.0126 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.4465 0.5618 0.5619 0.8798 0.8798 0.0049 0.1787 0.0000 0.5803 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.2048 0.0012 0.0012 0.0001 0.0001 0.0000 0.0392 0.0000 0.0014 0.0099 0.1188 0.1188 1.0000 HCl 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0050 0.0062 0.0062 0.0000 0.0000 0.0000 0.6187 0.0000 0.0046 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0047 0.0059 0.0066 0.0104 0.0104 0.0000 0.0014 0.0000 0.1233 0.7732 0.7529 0.7529 0.0000 NH 3 

### 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1066 0.1066 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 34,532 27,442 27,613 17,527 17,527 9,788 277 0 171 110,253 139,484 139,484 34,252 V-L Flowrate (kg/hr) 670,407 542,625 545,608 108,540 108,540 428,616 8,057 0 2,982 3,181,557 3,844,326 3,844,326 617,053 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,509 0 0 0 0 0
Temperature (°C) 240 35 35 35 198 51 48 182 38 15 564 132 536 Pressure (MPa, abs) 5.38 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 875.18 37.27 37.4 162.361 952.098 -161.516 114.764

--- 53.244 30.227 828.855 336.978 3,437.205 Density (kg/m 3 

### ) 24.7 40.8 40.5 11.8 5.0 639.2 1.8 5,271.4 37.5 1.2 0.4 0.9 36.6 V-L Molecular Weight 19.414 19.773 20 6.193 6.193 43.791 29.095

--- 17.451 28.857 27.561 27.561 18.015

V-L Flowrate (lb mol 

### /hr) 76,130 60,500 60,877 38,640 38,640 21,578 610 0 377 243,066 307,509 307,509 75,512 V-L Flowrate (lb/hr) 1,477,995 1,196,284 1,202,859 239,291 239,291 944,936 17,762 0 6,575 7,014,133 8,475,287 8,475,287 1,360,368 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 12,146 0 0 0 0 0
Temperature (°F) 463 95 95 95 388 124 119 360 100 59 1,047 270 997 Pressure (psia) 780.0 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 376.3 16.0 16.1 69.8 409.3 -69.4 49.3

--- 22.9 13.0 356.3 144.9 1,477.7 Density (lb/ft 3 

### ) 1.540 2.545 3 0.739 0.310 39.907 0.112 329.081 2.342 0.076 0.026 0.054 2.287 A - Reference conditions are 32.02 F & 0.089 PSIA



## 314Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 74 Case 2 D3 Performance Modeling Results POWER SUMMARY (Gross Power at Generator Terminals, kWe) D3 A (25%) D 3 B (45%) D 3 C (60%) D3D (75%) D 3E ( 8 5%) Gas Turbine Power 464,000 464,000 464,000 464,000 464,000 Sweet Gas Expander Power 5,800 5,900 6, 1 00 6, 2 00 6, 3 00 Steam Turbine Power 280,600 276, 3 00 274, 1 00 271,400 269,500 Total 750,400 746, 2 00 744, 2 00 741, 6 00 739,800 AUXILIARY LOAD SUMMARY, kWe Coal Handling 4 57 460 46 3 4 66 4 68

Coal Milling 2,1 59 2,19 2 2,220 2,2 4 7 2,2 6 6 Sour Water Recycle Slurry Pump 18 1 18 3 1 85 1 87 1 88 Slag Handling 1,1 06 1,12 2 1,1 37 1,15 1 1,16 1 Air Separation Unit Auxiliaries 1,000 1,000 1,000 1,000 1,000 Air Separation Unit Main Air Compressor 64,0 15 64,998 65,8 39 66,6 36 67, 188 Oxygen Compressor 10, 1 6 5 10,32 0 10, 398 10,5 28 10,6 1 6 Nitrogen Compressors 31,4 21 32,1 22 33,1 2 0 34,1 81 34,90 5 CO 2 

### Compressor 8,4 9 2 15,0 38 20,2 75 25,6 16 29,2 6 1 Boiler Feedwater Pumps 3,9 6 8 4,0 0 9 4,05 3 4, 096 4,1 25 Condensate Pump 2 49 2 59 26 4 2 69 27 3 Quench Water Pump 5 1 3 5 19 52 4 5 29 53 3 Circulating Water Pump 4, 1 65 4,3 2 0 4,4 28 4,5 36 4,6 06 Ground Water Pumps 4 25 4 5 6 480 50 4 520 Cooling Tower Fans 2,1 5 3 2,2 3 3 2,29 0 2,34 4 2,38 1

Scrubber Pumps 2 1 2 2 16 2 18 220 22 3 Acid Gas Removal 4,8 5 8 8,9 0 7 12,11 2 15,4 2 5 17,6 76 Gas Turbine Auxiliaries 1,000 1,000 1,000 1,000 1,000 Steam Turbine Auxiliaries 100 100 100 100 100 Claus Plant/TGTU Auxiliaries 250 250 250 250 250 Claus Plant TG Recycle Compressor 8 28 7 58 70 1 77 2 8 19

Miscellaneous Balance of Plant 1 

### 3,000 3,000 3,000 3,000 3,000 Transformer Losses 2,6 6 5 2,69 1 2,7 1 7 2,74 1 2,7 5 7 TOTAL AUXILIARIES, kWe 143,382 156,153 166,774 177,798 185,316 NET POWER, kWe 607,018 590, 047 577, 4 26 563,802 554, 484 Net Plant Efficiency, % (HHV) 38. 4 % 36.7% 35. 5 % 34.2% 33. 4 % Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9, 3 8 4 (8, 894 ) 9, 801 (9,28 9 ) 10,14 3 (9,61 4 ) 10,51 8 (9,96 9 ) 10,78 4 (10,2 22 ) Condenser Duty, GJ/hr (10 6 

### Btu/hr) 1, 625 (1, 54 0) 1,614 (1,530) 1,593 (1,510) 1,572 (1,490) 1,551 (1,470) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 209,9 15 ( 462, 783 ) 213,1 18 (469, 844 ) 215,8 50 (475, 867 ) 218,5 31 (481, 779 ) 220, 372 (485, 836 ) Thermal Input, kW th 2 

### 1, 582, 239 1,606, 380 1,62 6,975 1,647, 185 1,661, 057 Raw Water Withdrawal, m 3 

### /min (gpm) 17. 8 (4, 695 ) 19.1 (5,04 0 ) 20.1 (5,30 7 ) 21.1 (5,5 69 ) 21.8 (5,74 8 ) Raw Water Consumption, m 3 

### /min (gpm) 14. 1 (3,7 2 5 ) 15.3 (4,0 34 ) 16.2 (4,27 6 ) 17.1 (4,51 4 ) 17.7 (4,67 7 ) 

### Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)



## 315Carbon Dioxide Capture Sensitivity Analysis



## 4.3.3.1 Environmental Performance for Case 2 D3 The environmental targets for emissions of Hg, NO x 

## , SO 2 

## , and particulate matter were presented in Section 2.4 . A summary of the p lant air emissions for Case 2 D3A, D3 B , D3C, D3D, and D3E is presented in Exhibit 4

- 75

. For Case 2 D3, SO 2 

## emissions are controlled by sulfur capture across the two

- stage SelexolTM unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, resulting in a concentration in the flue gas of less than 2 ppmv. The H 2 

## S

- rich regeneration gas produced in Case 2 D3 is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the SelexolTM unit, thereby eliminating the need for a tail gas treatmen t unit. NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process, and ultimately incinerated in the Claus plant burner. This also assists in lowering NOx levels. Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety

- five percent of the mercury is captured from the syngas by an activated carbon bed. For Case 2 D3, varying levels of the CO 2 

## [25 percent (D3A), 45 percent (D3B), 60 percent (D3C), 75 per cent (D3D), and 85 percent (D3E)] in the syngas are captured in the two

- stage SelexolTM unit and compressed for sequestration. The carbon balance for Case 2 D3 is shown in Exhibit 4

- 76 . The carbon input to the plant consists of carbon in the air and coal. Carbon in the air is not n eglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

## in the wastewater blowdown stream, and as CO 2 

## in the stack gas, ASU vent gas, and the captured CO 2 

## product. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance. The carbon capture efficiency is defined as the pounds of carbon in the CO 2 

## product stream relative to the amount of carbon in the coal , less carbon contained in the slag , represented by the following fraction:
(Carbon in CO 2 

## Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or 72,992/(295,000

- 5,900)*100=25.2% (D3A) 131,7 28 /(299,5 01

- 5,99 0 )*100=44.9% (D3B) 178,2 10 /(303, 340

- 6,06 7 )*100=59.9% (D 3 C) 225,6 30 /(307,1 08

- 6,14 2 )*100=75.0% (D3D) 257,847 /( 309,695

- 6,1 94 )*100= 8 5.0% (D3 E )

Exhibit 4

- 77 shows the sulf ur balance for Case 2 D3 . Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved SO 2 

## in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by

316Carbon Dioxide Capture Sensitivity Analysis



## difference to close the m aterial balance. The total sulfur capture is represented by the following fraction: (Sulfur byproduct/Sulfur in the coal) or (11, 581 /11, 599 )*100 = 99.8 % (D3 A) (11,75 4 /11,77 6 )*100 = 99.8% (D3B) (11,90 2 /11,9 27 )*100 = 99.8% (D3C) (12,0 47 /12,07 5 )*100 = 99.8% (D3D) (12, 146 /12, 177 )*100 = 99.8% (D3 E )

The overall water balance s for Case 2 D3A, D3B, D3C, D3D, and D3E are shown in Exhibit 4

- 78 , Exhibit 4

- 79 , Exhibit 4

- 80 , Exhibit 4

- 81 , and Exhibit 4

- 82 , respectively

. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within t he process and that water is re used as in ternal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this study. Raw water consumption represents raw water withdrawal less process water discharge.

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 83 through Exhibit 4

- 97

.

• Gasifier and ASU

• Syngas Cleanup

• Power Block An overall plant energy balance for Case D3A, D3B, D3C, D3D, and D3E is provided in tabular form in Exhibit 4

- 98 , Exhibit 4

- 99 , Exhibit 4

- 100 , Exhibit 4

- 101 , and Exhibit 4

- 102 , respectively. The power out is the combined combustion turbine, steam turbine and expander power after generator losses. In addition, energy balance Sankey diagrams are provided for D3A, D3B, D3C, D3D, and D3E in Exhibit 4

- 103 , Exhibit 4

- 104 , Exhibit 4

- 105 , Exhibit 4

- 106 , and Exhibit 4

- 107 , respectively

.

317Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 75 Case 2 D3 Estimated Air Emission Rates
kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)
D3A D3B D3C D3A D3B D3C D3A D3B D3C SO 2 

### 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 37 (40) 37 (41) 38 (42) 0.007 (0.020) 0.007 (0.020) 0.007 (0.020) NO X 

### 0.0 24 (0.0 55 ) 0.0 23 (0.0 53 ) 0.0 22 (0.0 52 ) 947 (1,044) 927 (1,022) 910 (1,003) 0.180 (0.397) 0.177 (0.391) 0.174 (0.385) PM 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 122 (134) 124 (136) 125 (138) 0.023 (0.051) 0.024 (0.052) 0.024 (0.053) Hg 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0.010 (0.011) 0.010 (0.011) 0.010 (0.011) 1.87 x10 - 6 

### ( 4.11 x10 - 6 

### ) 1.90 x10 - 6 

### ( 4.20 x10 - 6 

### ) 1.93 x10 - 6 

### ( 4.26 x10 - 6 

### )
CO 2 

### 63. 3 (147. 3 ) 46.8 (108.8) 34.1 (79.2) 2,5 28, 207 (2, 78 6,871) 1,895, 466 (2,089, 393 ) 1,39 7,892 (1,54 0,913 ) 48 1 (1,06 0 ) 362 (799) 268 (591)

CO 2 

### net 59 4 (1,31 0 ) 458 (1,01 1 ) 345 (762)



### Exhibit 4
- 75 Case 2 D3 Estimated Air Emission Rates (continued)
kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)
D3D D3E D3D D3E D3D D3E
SO 2 

### 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 38 (42) 39 (42) 0.007 (0.020) 0.007 (0.020)

NO X 

### 0.0 21 (0.0 50 ) 0.0 21 (0.0 49 ) 893 (985) 882 (972) 0.172 (0.379) 0.170 (0.375)

PM 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 127 (140) 128 (141) 0.024 (0.054) 0.025 (0.054)
Hg 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0.010 (0.011) 0.010 (0.011) 1.96 x10 - 6 

### ( 4.33 x10 - 6 

### ) 1.99 x10 - 6 

### ( 4.38 x10 - 6 

### )
CO 2 

### 21.4 (49.7) 13.0 (30.1) 888, 578 (979, 489 ) 542, 862 (598, 402 ) 171 (377) 105 (231)

CO 2 

### net 225 (496) 140 (308)



## 318Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 76 Case 2 D3 Carbon Balance Carbon In, kg/hr (lb/hr) D3A D3B D3C D3D D3E
Coal 133,8 10 (295, 000 ) 135,8 51 (299,5 01 ) 137, 593 (303, 340 ) 139,3 02 (307,1 08 ) 140, 475 (309, 695 ) Air (CO 2 

### ) 535 (1,179) 536 (1,182) 538 (1,185) 539 (1,188) 540 (1,190)

Total 13 4,3 45 (29 6, 179 ) 136, 387 (300, 683 ) 138,1 31 (304,5 25 ) 139,8 41 (308, 296 ) 141,0 15 (310, 885 ) Carbon Out, kg/hr (lb/hr) Slag 2,67 6 (5,90 0 ) 2,71 7 (5,99 0 ) 2,752 (6,06 7 ) 2,78 6 (6,14 2 ) 2,810 (6,19 4 ) Stack Gas 98, 4 57 (217, 061 ) 73,8 16 (162,7 37 ) 54,4 39 (120,017 ) 34,6 04 (76, 290 ) 21,14 1 (46,6 08 ) ASU Vent 102 (225) 104 (229) 105 (23 1 ) 106 (234) 107 (236)
CO 2 

### Product 33,1 09 ( 7 2,992 ) 59,7 51 (131,7 28 ) 80,8 35 (178,2 10 ) 102,3 44 (225,6 30 ) 116,9 57 (257, 847 ) Convergence Tolerance 1 ( 1)

- 1 (

- 1 ) 0 ( 0 ) 1 (0) 0 (0)

Total 13 4,345 (29 6,179 ) 136,387 (300,683) 138,131 (304,525) 139,841 (308,296) 141,015 (310,885)

Exhibit 4
- 77 Case 2 D3 Sulfur Balance Sulfur In, kg/hr (lb/hr) D3A D3B D3C D3D D3E
Coal 5,26 1 (11, 599 ) 5,34 2 (11,77 6 ) 5,41 0 (11,9 27 ) 5,47 7 (12,07 5 ) 5,52 3 (12,1 77 )
Total 5, 26 1 (11, 599 ) 5,34 2 (11,77 6 ) 5,41 0 (11,9 27 ) 5,47 7 (12,07 5 ) 5,52 3 (12,1 77 ) Sulfur Out, kg/hr (lb/hr)
Elemental Sulfur 5,25 3 (11,58 1 ) 5,33 2 (11,75 4 ) 5, 399 (11,90 2 ) 5,46 4 (12,0 47 ) 5,5 09 (12,14 6 ) Stack Gas 3 (6) 3 (6) 3 (6) 3 (6) 3 (6) CO 2 

### Product 6 ( 12 ) 7 (16) 9 (19) 10 (22) 11 (25) Convergence Tolerance - 1 (0) 0 (0)

- 1 ( 0 ) 0 (0) 0 (0)

Total 5, 261 (11, 599 ) 5,34 2 (11,77 6 ) 5,41 0 (11,9 27 ) 5,47 7 (12,07 5 ) 5,52 3 (12,1 77 )



## 319Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 78 Case 2 D3A (25%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.50 (132) 0.50 (132) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.7 (719) 0.87 (231) 1.8 (488) 0.0 (0) 1.8 (488)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 0.2 (55) 0.0 (0) 0.2 (55) 0.0 (0) 0.2 (55)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 16.2 (4,282) 0.49 (129) 15.7 (4,152) 3.6 (963) 12.1 (3,190)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.28 (74)

- 0.28 (

- 74)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 21.1 (5,568) 3.30 (872) 17.8 (4,695) 3.7 (970) 14.1 (3,725)
Total, gal/MWh net 

### 550 86 464 96 368



## 320Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 79 Case 2 D3B (45%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.51 (134) 0.51 (134) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.8 (730) 0.72 (191) 2.0 (538) 0.0 (0) 2.0 (538)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 0.7 (187) 0.0 (0) 0.7 (187) 0.0 (0) 0.7 (187)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 0.5 (132) 0.0 (0) 0.5 (132)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 16.8 (4,441) 0.48 (127) 16.3 (4,314) 3.8 (999) 12.6 (3,316)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.27 (71)

- 0.27 (

- 71)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 22.3 (5,878) 3.17 (838) 19.1 (5,040) 3.8 (1,006) 15.3 (4,034)
Total, gal/MWh net 

### 598 85 513 102 410



## 321Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 80 Case 2 D3C (60%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.51 (136) 0.51 (136) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.8 (739) 0.60 (157) 2.2 (582) 0.0 (0) 2.2 (582)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 1.1 (294) 0.0 (0) 1.1 (294) 0.0 (0) 1.1 (294)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 0.9 (239) 0.0 (0) 0.9 (239)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 17.2 (4,555) 0.47 (124) 16.8 (4,431) 3.9 (1,024) 12.9 (3,407)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.26 (68)

- 0.26 (

- 68)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 23.1 (6,115) 3.06 (808) 20.1 (5,307) 3.9 (1,031) 16.2 (4,276)
Total, gal/MWh net 

### 635 84 551 107 444



## 322Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 81 Case 2 D3D (75%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.52 (137) 0.52 (137) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.8 (748) 0.47 (123) 2.4 (625) 0.0 (0) 2.4 (625)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (7)

- 0.02 (

- 7) Condenser Makeup 

### 1.5 (402) 0.0 (0) 1.5 (402) 0.0 (0) 1.5 (402)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 1.3 (347) 0.0 (0) 1.3 (347)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 17.7 (4,663) 0.46 (121) 17.2 (4,542) 4.0 (1,049) 13.2 (3,494)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.25 (66)

- 0.25 (

- 66)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 24.0 (6,347) 2.94 (777) 21.1 (5,569) 4.0 (1,055) 17.1 (4,514)
Total, gal/MWh net 

### 675 83 593 112 480



## 323Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 82 Case 2 D3E (85%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.52 (138) 0.52 (138) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.9 (755) 0.38 (99) 2.5 (655) 0.0 (0) 2.5 (655)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.02 (6)

- 0.02 (

- 6) Condenser Makeup 

### 1.8 (475) 0.0 (0) 1.8 (475) 0.0 (0) 1.8 (475)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 1.6 (420) 0.0 (0) 1.6 (420)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (55) 0.0 (0) 0.21 (55) Cooling Tower 

### 17.9 (4,736) 0.45 (119) 17.5 (4,618) 4.0 (1,065) 13.4 (3,553)

BFW Blowdown 

### 0.0 (0) 0.21 (55)

- 0.21 (

- 55)
SWS Blowdown 

### 0.0 (0) 0.24 (64)

- 0.24 (

- 64)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 24.6 (6,504) 2.86 (756) 21.8 (5,748) 4.1 (1,072) 17.7 (4,677)
Total, gal/MWh net 

### 704 82 622 116 506



## 324Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 83 Case 2 D3A (25%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 A ( 25 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 A

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 894 BTU / KWe N 2 to GT Combustor 1 , 654 , 945 W 59

. 0 T 14

. 7 P 13

. 0 H

372 , 540 W 90

. 0 T 125

. 0 P 11

. 5 H

372 , 540 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 650 W

90

. 0 T 125

. 0 P 11

. 5 H 116 , 465 W 63

. 5 T 16

. 4 P 15

. 1 H

1 , 008 , 757 W 90

. 0 T 56

. 4 P 14

. 2 H

149 , 055 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 462 , 783 W 59

. 0 T 14

. 7 P

190 , 111 W

287

. 0 T 840

. 0 P 231

. 2 H

50 , 775 W 2 , 400

. 0 T

815

. 0 P 1 , 157 , 812 W 385

. 0 T 384

. 0 P 87

. 2 H

652 , 894 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 1 , 157 , 812 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 0 W 199

. 0 T 384

. 0 P 39

. 8 H 0 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 974 , 659 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 207 , 768 W 403

. 3 T 800

. 0 P 459

. 0 H

Syngas Quench 1 , 334 , 140 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 157 , 812 W 199

. 0 T 384

. 0 P 39

. 8 H



## 325Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 84 Case 2 D3A (25%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 207 , 768 W 403

. 3 T 800

. 0 P 459

. 0 H 859 , 731 W 94

. 7 T 740

. 0 P 17

. 3 H 15 , 141 W 119

. 0 T 23

. 7 P 578 , 797 W 386

. 9 T 460

. 0 P 152

. 7 H

11 , 581 W 12 , 720 W 450

. 0 T 12

. 3 P 850

. 9 H

2 , 511 W 240

. 2 T 65

. 0 P 445

. 2 H 6 , 650 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 A ( 25 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 A

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 894 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

7 , 215 W 120

. 0 T 10

. 6 P 202

. 7 H 853 , 600 W 94

. 8 T 745

. 0 P 17

. 2 H

6 , 589 W 116

. 7 T 10

. 6 P 42

. 7 H 3 6 , 131 W 100

. 0 T 799

. 5 P

Raw Syngas 18 578 , 797 W 94

. 7 T 725

. 0 P 23

. 5 H

Claus Oxygen Preheater 6 , 650 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 578 , 797 W

465

. 0 T 720

. 0 P 187

. 3 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam 12

11

COS Hydrolysis

Preheater 1 , 207 , 768 W 413

. 3 T 795

. 0 P 451

. 0 H 0 W 550

. 0 T 800

. 0 P 1 , 254

. 1 H 3 , 020 W 413

. 3 T 795

. 0 P 451

. 1 H

768

. 8 T 795

. 0 P 435

. 3 H 400

. 0 T 795

. 0 P 271

. 8 H 3 , 020 W 510

. 4 T 785

. 0 P 267

. 2 H

1 , 207 , 768 W 403

. 0 T 780

. 0 P 446

. 2 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

265 , 209 W 146

. 4 T 2 , 214

. 7 P COS Hydrolysis

13 14

15 1 , 204 , 748 W 413

. 3 T 795

. 0 P 451

. 0 H 1 , 204 , 748 W 413

. 2 T 785

. 0 P 451

. 0 H
1 , 207 , 768 W 413

. 4 T 785

. 0 P 450

. 5 H



## 326Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 85 Case 2 D3A (25%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 678 , 708 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 750 , 744 W 269

. 9 T 15

. 2 P 101

. 4 H

578 , 797 W

386

. 9 T 460

. 0 P 152

. 7 H 8 , 750 , 744 W 1 , 079

. 4 T

15

. 2 P 315

. 2 H From Gasifier Island Preheating

To Claus LP BFW 1 , 390 , 513 W

1 , 029

. 4 T 1 , 814

. 7 P 1 , 497

. 8 H 10 , 077 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 418 , 721 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 204 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 639 , 233 W 492

. 9 T 65

. 0 P 1 , 278

. 5 H

1 , 678 , 708 W 103

. 1 T 120

. 0 P 71

. 3 H 1 , 678 , 708 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 649

. 2 T 65

. 0 P 1 , 355

. 6 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 A ( 25 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 A

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 750 MWe Auxiliary Load : 143 MWe Net Plant Power : 607 MWe Net Plant Efficiency
, HHV : 38

. 4 % Net Plant Heat Rate : 8 , 894 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 27 , 496 W

59

. 0 T 14

. 7 P 27

. 1 H 8 , 876 W 690

. 4 T 501

. 4 P 1 , 351

. 7 H 9 , 580 W 649

. 2 T 65

. 0 P 1 , 355

. 6 H 25 , 424 W

885

. 4 T 280

. 0 P 1 , 466

. 2 H 785 W 1 , 029

. 4 T 1 , 814

. 7 P 1 , 497

. 8 H 1 , 319 W 531

. 0 T 65

. 0 P 1 , 297

. 3 H



## 327Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 86 Case 2 D3B (45%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 B ( 45 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 B

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 746 MWe Auxiliary Load : 156 MWe Net Plant Power : 590 MWe Net Plant Efficiency
, HHV : 36

. 7 % Net Plant Heat Rate : 9 , 289 BTU / KWe N 2 to GT Combustor 1 , 680 , 379 W 59

. 0 T 14

. 7 P 13

. 0 H

378 , 224 W 90

. 0 T 125

. 0 P 11

. 5 H

378 , 224 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 793 W

90

. 0 T 125

. 0 P 11

. 5 H 112 , 185 W 63

. 8 T 16

. 4 P 15

. 2 H

1 , 030 , 331 W 90

. 0 T 56

. 4 P 14

. 2 H

151 , 346 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 469 , 844 W 59

. 0 T 14

. 7 P

193 , 012 W

287

. 0 T 840

. 0 P 231

. 2 H

51 , 550 W 2 , 400

. 0 T

815

. 0 P 1 , 170 , 481 W 385

. 0 T 384

. 0 P 87

. 2 H

662 , 856 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 1 , 170 , 481 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 11 , 195 W

199

. 0 T 384

. 0 P 39

. 8 H 11 , 195 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 989 , 530 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 225 , 965 W 403

. 2 T 800

. 0 P 458

. 8 H

Syngas Quench 1 , 354 , 496 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 181 , 676 W 199

. 0 T 384

. 0 P 39

. 8 H



## 328Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 87 Case 2 D3B (45%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 225 , 965 W 403

. 2 T 800

. 0 P 458

. 8 H 964 , 724 W 94

. 7 T 740

. 0 P 16

. 9 H 14 , 739 W 119

. 0 T 23

. 7 P 468 , 146 W 387

. 1 T 460

. 0 P 194

. 2 H

11 , 754 W 12 , 234 W 450

. 0 T 12

. 3 P 909

. 1 H

2 , 455 W 239

. 0 T 65

. 0 P 437

. 8 H 6 , 793 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 B ( 45 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 B

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 746 MWe Auxiliary Load : 156 MWe Net Plant Power : 590 MWe Net Plant Efficiency
, HHV : 36

. 7 % Net Plant Heat Rate : 9 , 289 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

6 , 028 W 120

. 0 T 10

. 6 P 220

. 8 H 959 , 686 W 94

. 8 T 745

. 0 P 16

. 8 H

7 , 195 W 117

. 3 T 10

. 6 P 43

. 3 H 3 5 , 039 W 100

. 0 T 799

. 5 P

Raw Syngas 18 468 , 146 W 94

. 7 T 725

. 0 P 31

. 3 H

Claus Oxygen Preheater 6 , 793 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 468 , 146 W

465

. 0 T 720

. 0 P 238

. 1 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam 12

11

COS Hydrolysis

Preheater 1 , 225 , 965 W 413

. 2 T 795

. 0 P 450

. 9 H 65 , 912 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 441 , 057 W

432

. 1 T 795

. 0 P 571

. 0 H

779

. 0 T 795

. 0 P 554

. 9 H 400

. 0 T 795

. 0 P 380

. 9 H 441 , 057 W 474

. 0 T 785

. 0 P 377

. 6 H

1 , 291 , 877 W 425

. 0 T 780

. 0 P 421

. 7 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

481 , 167 W 130

. 3 T 2 , 214

. 7 P COS Hydrolysis

13 14

15 850 , 820 W

413

. 2 T 795

. 0 P 450

. 9 H 850 , 820 W 413

. 1 T 785

. 0 P 450

. 8 H
1 , 291 , 877 W 434

. 6 T 785

. 0 P 425

. 8 H



## 329Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 88 Case 2 D3B (45%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 740 , 783 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 663 , 957 W 270

. 2 T 15

. 2 P 114

. 7 H

468 , 146 W

387

. 1 T 460

. 0 P 194

. 2 H 8 , 663 , 957 W 1 , 068

. 9 T

15

. 2 P 327

. 6 H From Gasifier Island Preheating

To Claus LP BFW 1 , 389 , 734 W

1 , 018

. 9 T 1 , 814

. 7 P 1 , 491

. 4 H 10 , 138 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 418 , 112 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 376 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 635 , 132 W 483

. 4 T 65

. 0 P 1 , 273

. 8 H

1 , 740 , 783 W 103

. 0 T 120

. 0 P 71

. 2 H 1 , 740 , 783 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 639

. 2 T 65

. 0 P 1 , 350

. 6 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 B ( 45 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 B

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 746 MWe Auxiliary Load : 156 MWe Net Plant Power : 590 MWe Net Plant Efficiency
, HHV : 36

. 7 % Net Plant Heat Rate : 9 , 289 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 93 , 619 W

59

. 0 T 14

. 7 P 27

. 1 H 8 , 919 W 681

. 6 T 501

. 4 P 1 , 346

. 7 H 9 , 632 W 639

. 2 T 65

. 0 P 1 , 350

. 6 H 25 , 757 W

875

. 6 T 280

. 0 P 1 , 461

. 1 H 789 W 1 , 018

. 9 T 1 , 814

. 7 P 1 , 491

. 4 H 1 , 324 W 523

. 3 T 65

. 0 P 1 , 293

. 6 H



## 330Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 89 Case 2 D3C (60%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 C ( 60 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 C

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 744 MWe Auxiliary Load : 167 MWe Net Plant Power : 577 MWe Net Plant Efficiency
, HHV : 35

. 5 % Net Plant Heat Rate : 9 , 614 BTU / KWe N 2 to GT Combustor 1 , 702 , 103 W 59

. 0 T 14

. 7 P 13

. 0 H

383 , 073 W 90

. 0 T 125

. 0 P 11

. 5 H

383 , 073 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 922 W

90

. 0 T 125

. 0 P 11

. 5 H 115 , 369 W 63

. 7 T 16

. 4 P 15

. 1 H

1 , 041 , 917 W 90

. 0 T 56

. 4 P 14

. 2 H

153 , 302 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 475 , 867 W 59

. 0 T 14

. 7 P

195 , 486 W

287

. 0 T 840

. 0 P 231

. 2 H

52 , 211 W 2 , 400

. 0 T

815

. 0 P 1 , 001 , 462 W 385

. 0 T 384

. 0 P 87

. 2 H

671 , 354 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 1 , 001 , 462 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 193 , 757 W

199

. 0 T 384

. 0 P 39

. 8 H 193 , 757 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 1 , 002 , 216 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 242 , 215 W 403

. 3 T 800

. 0 P 459

. 2 H

Syngas Quench 1 , 371 , 861 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 195 , 219 W 199

. 0 T 384

. 0 P 39

. 8 H



## 331Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 90 Case 2 D3C (60%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 242 , 215 W 403

. 3 T 800

. 0 P 459

. 2 H 1 , 051 , 833 W 94

. 7 T 740

. 0 P 16

. 6 H 14 , 414 W 119

. 0 T 23

. 7 P 384 , 577 W 387

. 5 T 460

. 0 P 243

. 6 H

11 , 902 W 11 , 854 W 450

. 0 T 12

. 3 P 959

. 2 H

2 , 420 W 237

. 6 T 65

. 0 P 429

. 1 H 6 , 922 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 C ( 60 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 C

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 744 MWe Auxiliary Load : 167 MWe Net Plant Power : 577 MWe Net Plant Efficiency
, HHV : 35

. 5 % Net Plant Heat Rate : 9 , 614 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

5 , 067 W 120

. 0 T 10

. 6 P 241

. 8 H 1 , 047 , 679 W 94

. 9 T 745

. 0 P 16

. 5 H

7 , 700 W 117

. 6 T 10

. 6 P 43

. 7 H 3 4 , 154 W 100

. 0 T 799

. 5 P

Raw Syngas 18 384 , 577 W 94

. 7 T 725

. 0 P 40

. 3 H

Claus Oxygen Preheater 6 , 922 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 384 , 577 W

465

. 0 T 720

. 0 P 298

. 3 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam 12

11

COS Hydrolysis

Preheater 1 , 242 , 215 W 413

. 3 T 795

. 0 P 451

. 2 H 119 , 253 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 802 , 471 W

432

. 1 T 795

. 0 P 570

. 6 H

778

. 6 T 795

. 0 P 554

. 3 H 400

. 0 T 795

. 0 P 380

. 4 H 802 , 471 W 473

. 9 T 785

. 0 P 377

. 1 H

1 , 361 , 467 W 440

. 6 T 780

. 0 P 403

. 5 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

652 , 097 W 126

. 6 T 2 , 214

. 7 P COS Hydrolysis

13 14

15 558 , 997 W

413

. 3 T 795

. 0 P 451

. 2 H 558 , 997 W 413

. 2 T 785

. 0 P 451

. 2 H
1 , 361 , 467 W 449

. 7 T 785

. 0 P 407

. 5 H



## 332Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 91 Case 2 D3C (60%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 779 , 215 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 593 , 931 W 269

. 9 T 15

. 2 P 125

. 7 H

384 , 577 W

387

. 5 T 460

. 0 P 243

. 6 H 8 , 593 , 931 W 1 , 060

. 8 T

15

. 2 P 338

. 1 H From Gasifier Island Preheating

To Claus LP BFW 1 , 378 , 969 W

1 , 010

. 8 T 1 , 814

. 7 P 1 , 486

. 4 H 10 , 184 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 407 , 477 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 503 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 620 , 282 W 481

. 5 T 65

. 0 P 1 , 272

. 9 H

1 , 779 , 215 W 103

. 0 T 120

. 0 P 71

. 2 H 1 , 779 , 215 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 631

. 4 T 65

. 0 P 1 , 346

. 8 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 C ( 60 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 C

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 744 MWe Auxiliary Load : 167 MWe Net Plant Power : 577 MWe Net Plant Efficiency
, HHV : 35

. 5 % Net Plant Heat Rate : 9 , 614 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 146 , 860 W 59

. 0 T 14

. 7 P 27

. 1 H 8 , 953 W 674

. 8 T 501

. 4 P 1 , 342

. 8 H 9 , 673 W 631

. 4 T 65

. 0 P 1 , 346

. 8 H 26 , 009 W

868

. 0 T 280

. 0 P 1 , 457

. 1 H 792 W 1 , 010

. 8 T 1 , 814

. 7 P 1 , 486

. 4 H 1 , 328 W 517

. 4 T 65

. 0 P 1 , 290

. 7 H



## 333Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 92 Case 2 D3D (75%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 D

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 D ( 75 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 D

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 742 MWe Auxiliary Load : 178 MWe Net Plant Power : 564 MWe Net Plant Efficiency
, HHV : 34

. 2 % Net Plant Heat Rate : 9 , 969 BTU / KWe N 2 to GT Combustor 1 , 722 , 729 W 59

. 0 T 14

. 7 P 13

. 0 H

387 , 832 W 90

. 0 T 125

. 0 P 11

. 5 H

387 , 832 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 889 W

90

. 0 T 125

. 0 P 11

. 5 H 115 , 309 W 63

. 8 T 16

. 4 P 15

. 2 H

1 , 056 , 000 W 90

. 0 T 56

. 4 P 14

. 2 H

155 , 160 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 481 , 779 W 59

. 0 T 14

. 7 P

197 , 915 W

287

. 0 T 840

. 0 P 231

. 2 H

52 , 859 W 2 , 400

. 0 T

815

. 0 P 831 , 750 W 385

. 0 T 384

. 0 P 87

. 2 H

679 , 693 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 831 , 750 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 379 , 410 W

199

. 0 T 384

. 0 P 39

. 8 H 379 , 410 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 1 , 014 , 666 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 258 , 103 W 403

. 4 T 800

. 0 P 459

. 5 H

Syngas Quench 1 , 388 , 902 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 211 , 160 W 199

. 0 T 384

. 0 P 39

. 8 H



## 334Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 93 Case 2 D3D (75%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 258 , 103 W 403

. 4 T 800

. 0 P 459

. 5 H 1 , 141 , 658 W 94

. 7 T 740

. 0 P 16

. 3 H 16 , 393 W 119

. 0 T 23

. 7 P 297 , 976 W 387

. 8 T 460

. 0 P 322

. 9 H

12 , 047 W 13 , 625 W 450

. 0 T 12

. 3 P 904

. 3 H

2 , 390 W 236

. 2 T 65

. 0 P 419

. 4 H 6 , 889 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 D

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 D ( 75 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 D

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 742 MWe Auxiliary Load : 178 MWe Net Plant Power : 564 MWe Net Plant Efficiency
, HHV : 34

. 2 % Net Plant Heat Rate : 9 , 969 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

6 , 590 W 120

. 0 T 10

. 6 P 206

. 5 H 1 , 136 , 078 W 94

. 9 T 745

. 0 P 16

. 2 H

8 , 045 W 117

. 5 T 10

. 6 P 43

. 5 H 3 5 , 580 W 100

. 0 T 799

. 5 P

Raw Syngas 18 297 , 976 W 94

. 7 T 725

. 0 P 54

. 5 H

Claus Oxygen Preheater 6 , 889 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 297 , 976 W

465

. 0 T 720

. 0 P 395

. 1 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam 12

11

COS Hydrolysis

Preheater 1 , 258 , 103 W 413

. 4 T 795

. 0 P 451

. 5 H 173 , 583 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 1 , 167 , 485 W 432

. 1 T 795

. 0 P 570

. 9 H

779

. 0 T 795

. 0 P 554

. 8 H 400

. 0 T 795

. 0 P 380

. 8 H 1 , 167 , 485 W 474

. 0 T 785

. 0 P 377

. 5 H

1 , 431 , 687 W 454

. 7 T 780

. 0 P 387

. 3 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

826 , 469 W 124

. 8 T 2 , 214

. 7 P COS Hydrolysis

13 14

15 264 , 202 W

413

. 4 T 795

. 0 P 451

. 5 H 264 , 202 W 413

. 3 T 785

. 0 P 451

. 5 H
1 , 431 , 687 W 463

. 3 T 785

. 0 P 391

. 2 H



## 335Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 94 Case 2 D3D (75%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 813 , 468 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 523 , 270 W 269

. 9 T 15

. 2 P 137

. 0 H

297 , 976 W

387

. 8 T 460

. 0 P 322

. 9 H 8 , 523 , 270 W 1 , 052

. 4 T

15

. 2 P 348

. 9 H From Gasifier Island Preheating

To Claus LP BFW 1 , 367 , 787 W

1 , 002

. 4 T 1 , 814

. 7 P 1 , 481

. 2 H 10 , 229 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 396 , 415 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 629 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 600 , 263 W 479

. 7 T 65

. 0 P 1 , 272

. 0 H

1 , 813 , 468 W 102

. 9 T 120

. 0 P 71

. 1 H 1 , 813 , 468 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 623

. 3 T 65

. 0 P 1 , 342

. 8 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 D

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 D ( 75 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 D

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 742 MWe Auxiliary Load : 178 MWe Net Plant Power : 564 MWe Net Plant Efficiency
, HHV : 34

. 2 % Net Plant Heat Rate : 9 , 969 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 201 , 089 W 59

. 0 T 14

. 7 P 27

. 1 H 8 , 988 W 667

. 7 T 501

. 4 P 1 , 338

. 7 H 9 , 716 W 623

. 3 T 65

. 0 P 1 , 342

. 8 H 27 , 806 W

860

. 2 T 280

. 0 P 1 , 453

. 1 H 795 W 1 , 002

. 4 T 1 , 814

. 7 P 1 , 481

. 2 H 1 , 333 W 511

. 3 T 65

. 0 P 1 , 287

. 6 H



## 336Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 95 Case 2 D3E (85%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 E

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 E ( 85 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 E

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 740 MWe Auxiliary Load : 185 MWe Net Plant Power : 554 MWe Net Plant Efficiency
, HHV : 33

. 4 % Net Plant Heat Rate : 10 , 222 BTU / KWe N 2 to GT Combustor 1 , 736 , 984 W 59

. 0 T 14

. 7 P 13

. 0 H

391 , 098 W 90

. 0 T 125

. 0 P 11

. 5 H

391 , 098 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 889 W

90

. 0 T 125

. 0 P 11

. 5 H 115 , 584 W 63

. 8 T 16

. 4 P 15

. 2 H

1 , 065 , 418 W 90

. 0 T 56

. 4 P 14

. 2 H

156 , 444 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 485 , 836 W 59

. 0 T 14

. 7 P

199 , 581 W

287

. 0 T 840

. 0 P 231

. 2 H

53 , 304 W 2 , 400

. 0 T

815

. 0 P 716 , 301 W 385

. 0 T 384

. 0 P 87

. 2 H

685 , 417 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 716 , 301 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 505 , 561 W

199

. 0 T 384

. 0 P 39

. 8 H 505 , 561 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 1 , 023 , 211 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 267 , 818 W 403

. 3 T 800

. 0 P 458

. 9 H

Syngas Quench 1 , 400 , 599 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 221 , 862 W 199

. 0 T 384

. 0 P 39

. 8 H



## 337Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 96 Case 2 D3E (85%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 267 , 818 W 403

. 3 T 800

. 0 P 458

. 9 H 1 , 202 , 859 W 94

. 8 T 740

. 0 P 16

. 1 H 17 , 762 W 119

. 0 T 23

. 7 P 239 , 291 W 387

. 9 T 460

. 0 P 409

. 3 H

12 , 146 W 14 , 876 W 450

. 0 T 12

. 3 P 870

. 8 H

2 , 371 W 235

. 0 T 65

. 0 P 411

. 8 H 6 , 889 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 E

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 E ( 85 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 E

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 740 MWe Auxiliary Load : 185 MWe Net Plant Power : 554 MWe Net Plant Efficiency
, HHV : 33

. 4 % Net Plant Heat Rate : 10 , 222 BTU / KWe 22

16 23 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

7 , 650 W 120

. 0 T 10

. 6 P 189

. 7 H 1 , 196 , 284 W 94

. 9 T 745

. 0 P 16

. 0 H

8 , 301 W 117

. 4 T 10

. 6 P 43

. 5 H 3 6 , 575 W 100

. 0 T 799

. 5 P

Raw Syngas 18 239 , 291 W 94

. 8 T 725

. 0 P 69

. 8 H

Claus Oxygen Preheater 6 , 889 W 450

. 0 T 124

. 5 P 91

. 9 H 21 Fuel Gas Expander Fuel Gas To GT

19 239 , 291 W

465

. 0 T 720

. 0 P 500

. 6 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam 12

11

COS Hydrolysis

Preheater 1 , 267 , 818 W 413

. 3 T 795

. 0 P 451

. 0 H 210 , 177 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 1 , 414 , 604 W 432

. 0 T 795

. 0 P 570

. 4 H

778

. 9 T 795

. 0 P 554

. 2 H 400

. 0 T 795

. 0 P 380

. 2 H 1 , 414 , 604 W 473

. 9 T 785

. 0 P 376

. 8 H

1 , 477 , 995 W 463

. 2 T 780

. 0 P 376

. 3 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

20

10 17

944 , 936 W 124

. 0 T 2 , 214

. 7 P COS Hydrolysis

13 14

15 63 , 391 W

413

. 3 T 795

. 0 P 451

. 0 H 63 , 391 W 413

. 1 T 785

. 0 P 450

. 9 H
1 , 477 , 995 W 471

. 5 T 785

. 0 P 380

. 0 H



## 338Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 97 Case 2 D3E (85%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 835 , 108 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 475 , 287 W 269

. 9 T 15

. 2 P 144

. 9 H

239 , 291 W

387

. 9 T 460

. 0 P 409

. 3 H 8 , 475 , 287 W 1 , 046

. 8 T

15

. 2 P 356

. 3 H From Gasifier Island Preheating

To Claus LP BFW 1 , 360 , 368 W 996

. 8 T 1 , 814

. 7 P 1 , 477

. 7 H 10 , 261 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 389 , 073 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 719 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 585 , 352 W 478

. 6 T 65

. 0 P 1 , 271

. 5 H

1 , 835 , 108 W 102

. 9 T 120

. 0 P 71

. 1 H 1 , 835 , 108 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 617

. 8 T 65

. 0 P 1 , 340

. 1 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 3 E

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 3 E ( 85 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 3 E

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 740 MWe Auxiliary Load : 185 MWe Net Plant Power : 554 MWe Net Plant Efficiency
, HHV : 33

. 4 % Net Plant Heat Rate : 10 , 222 BTU / KWe 24 25

27

19 26

Flue Gas

HOT WELL CONDENSER Make

- up 237 , 610 W 59

. 0 T 14

. 7 P 27

. 1 H 9 , 013 W 663

. 0 T 501

. 4 P 1 , 336

. 0 H 9 , 746 W 617

. 8 T 65

. 0 P 1 , 340

. 1 H 28 , 912 W

855

. 0 T 280

. 0 P 1 , 450

. 3 H 797 W 996

. 8 T 1 , 814

. 7 P 1 , 477

. 7 H 1 , 336 W 507

. 2 T 65

. 0 P 1 , 285

. 6 H



## 339Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

340Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 98 Case 2 D3A (25%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,696 (5,399) 4.8 (4.5) 0 (0) 5,701 (5,403) ASU Air 0 (0) 22.7 (21.5) 0 (0) 23 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 66.8 (63.3) 0 (0) 67 (63)
Totals 5,696 (5,399) 190.5 (180.5) 0 (0) 5,887 (5,579) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.9 (1.8) 0 (0) 2 (2) Slag 88 (83) 36.0 (34.1) 0 (0) 124 (117) Sulfur 49 (46) 0.6 (0.6) 0 (0) 49 (47) CO 2 

### 0 (0)

- 13.0 (

- 12.4) 0 (0)

- 13 (

- 12) Gasifier Heat Loss 0 (0) 42.4 (40.2) 0 (0) 42 (40) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60) HRSG Flue Gas 0 (0) 937 (888) 0 (0) 937 (888) Cooling Tower* 0 (0) 2,073 (1,965) 0 (0) 2,073 (1,965) Process Losses* * 0 (0) 424 (402) 0 (0) 424 (402)
Net Power 0 (0) 0.0 (0.0) 2,185 (2,071) 2,185 (2,071) Totals 136 (129) 3,565 (3,379) 2,185 (2,071) 5,887 (5,579) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level hea t rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 341Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 99 Case 2 D3B (45%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,783 (5,481) 4.8 (4.6) 0 (0) 5,788 (5,486) ASU Air 0 (0) 23.0 (21.8) 0 (0) 23 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 71.7 (68.0) 0 (0) 72 (68)
Totals 5,783 (5,481) 195.8 (185.6) 0 (0) 5,979 (5,667) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2) Slag 89 (84) 36.5 (34.6) 0 (0) 126 (119) Sulfur 49 (47) 0.6 (0.6) 0 (0) 50 (47) CO 2 

### 0 (0)

- 31.7 (

- 30.0) 0 (0)

- 32 (

- 30) Gasifier Heat Loss 0 (0) 43.1 (40.8) 0 (0) 43 (41) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60) HRSG Flue Gas 0 (0) 1,048 (994) 0 (0) 1,048 (994) Cooling Tower* 0 (0) 2,115 (2,005) 0 (0) 2,115 (2,005) Process Losses* * 0 (0) 439 (416) 0 (0) 439 (416)
Net Power 0 (0) 0.0 (0.0) 2,124 (2,013) 2,124 (2,013) Totals 138 (131) 3,716 (3,522) 2,124 (2,013) 5,979 (5,667) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 342Carbon Dioxide Capture Sensitivity Analysis



### E xhibit 4
- 100 Case 2 D3C (60%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,857 (5,551) 4.9 (4.6) 0 (0) 5,862 (5,556) ASU Air 0 (0) 23.3 (22.1) 0 (0) 23 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 75.5 (71.6) 0 (0) 76 (72)
Totals 5,857 (5,551) 199.9 (189.5) 0 (0) 6,057 (5,741) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2) Slag 90 (86) 37.0 (35.0) 0 (0) 127 (121) Sulfur 50 (47) 0.6 (0.6) 0 (0) 51 (48) CO 2 

### 0 (0)

- 45.7 (

- 43.3) 0 (0)

- 46 (

- 43) Gasifier Heat Loss 0 (0) 43.6 (41.3) 0 (0) 44 (41) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)
HRSG Flue Gas 0 (0) 1,140 (1,080) 0 (0) 1,140 (1,080) Cooling Tower* 0 (0) 2,143 (2,031) 0 (0) 2,143 (2,031) Process Losses* * 0 (0) 455 (431) 0 (0) 455 (431)
Net Power 0 (0) 0.0 (0.0) 2,079 (1,970) 2,079 (1,970)
Totals 140 (133) 3,838 (3,638) 2,079 (1,970) 6,057 (5,741) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas coole r (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 343Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 101 Case 2 D3D (75%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,930 (5,620) 5.0 (4.7) 0 (0) 5,935 (5,625) ASU Air 0 (0) 23.6 (22.4) 0 (0) 24 (22) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 79.3 (75.1) 0 (0) 79 (75)
Totals 5,930 (5,620) 204.0 (193.4) 0 (0) 6,134 (5,814) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.8 (1.7) 0 (0) 2 (2) Slag 91 (87) 37.4 (35.5) 0 (0) 129 (122) Sulfur 51 (48) 0.6 (0.6) 0 (0) 51 (49) CO 2 

### 0 (0)

- 59.7 (

- 56.6) 0 (0)

- 60 (

- 57) Gasifier Heat Loss 0 (0) 44.1 (41.8) 0 (0) 44 (42) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)
HRSG Flue Gas 0 (0) 1,232 (1,168) 0 (0) 1,232 (1,168) Cooling Tower* 0 (0) 2,167 (2,054) 0 (0) 2,167 (2,054) Process Losses* * 0 (0) 476 (451) 0 (0) 476 (451)
Net Power 0 (0) 0.0 (0.0) 2,030 (1,924) 2,030 (1,924)
Totals 142 (135) 3,962 (3,755) 2,030 (1,924) 6,134 (5,814) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 344Carbon Dioxide Capture Sensitivity Analysis



### E xhibit 4
- 102 Case 2 D3E (85%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,980 (5,668) 5.0 (4.7) 0 (0) 5,985 (5,673) ASU Air 0 (0) 23.8 (22.6) 0 (0) 24 (23) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 81.8 (77.6) 0 (0) 82 (78)
Totals 5,980 (5,668) 206.8 (196.0) 0 (0) 6,187 (5,864) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.8 (1.8) 0 (0) 2 (2) Slag 92 (87) 37.7 (35.8) 0 (0) 130 (123) Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49) CO 2 

### 0 (0)

- 69.2 (

- 65.6) 0 (0)

- 69 (

- 66) Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)
HRSG Flue Gas 0 (0) 1,295 (1,228) 0 (0) 1,295 (1,228) Cooling Tower* 0 (0) 2,183 (2,069) 0 (0) 2,183 (2,069) Process Losses* * 0 (0) 490 (465) 0 (0) 490 (465)
Net Power 0 (0) 0.0 (0.0) 1,996 (1,892) 1,996 (1,892)
Totals 143 (136) 4,047 (3,836) 1,996 (1,892) 6,187 (5,864) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas coole r (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 345Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 103 Case 2 D3A Energy Balance Sankey Diagram

Exhibit 4
- 104 Case 2 D3B Energy Balance Sankey Diagram



## 346Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 105 Case 2 D3C Energy Balance Sankey Diagram

Exhibit 4
- 106 Case 2 D3D Energy Balance Sankey Diagram



## 347Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 107 Case 2 D3E Energy Balance Sankey Diagram



## 348Carbon Dioxide Capture Sensitivity Analysis



## 4.3.3.2 Major Equipment List for Case 2 D3 Major equipment items for Case 2 D3 (two WGS with bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cos t estimates. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 2 1 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING
Equipment No. Description Type Design Conditions Opr Qty. (Spares) D3A D3B D3C D3D D3E
1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)
2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0) 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 4 Transfer Tower No. 1 Enclosed N/A N/A N/A N/A N/A 1 (0) 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)
6 As

- Received Coal Sampling System Two

- stage N/A N/A N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1) 9 Feeder Vibratory 172 tonne/hr (190 tph) 172 tonne/hr (190 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1) 10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0) 11 Crusher Tower N/A N/A N/A N/A N/A N/A 1 (0)
12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 172 tonne (190 ton) 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 (0)

14 As

- Fired Coal Sampling System Swing hammer N/A N/A N/A N/A N/A 1 (1)
15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0) 16 Transfer Tower No. 2 Enclosed N/A N/A N/A N/A N/A 1 (0) 17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 354 tonne/hr (390 tph) 354 tonne/hr (390 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)
18 Coal Silo w/ Vent Filter and Slide Gates Field erected 726 tonne (800 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)



## ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Design Condition Opr Qty. (Spares) D3A D3B D3C D3D D3E 1 Feeder Vibratory 73 tonne/h (80 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0) 2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 236 tonne/h (260 tph) 245 tonne/h (270 tph) 1 (0) 3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 472 tonne (520 ton) 472 tonne (520 ton) 481 tonne (530 ton) 481 tonne (530 ton) 1 (0) 4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0) 5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)
6 Slurry Water Storage Tank with Agitator Field erected 284,968 liters (75,280 gal) 289,321 liters (76,430 gal) 293,031 liters (77,410 gal) 296,665 liters (78,370 gal) 299,163 liters (79,030 gal) 2 (0)



## 349Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D3A D3B D3C D3D D3E 7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 795 lpm (210 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1) 8 Trommel Screen Coarse 163 tonne/h (180 tph) 163 tonne/h (180 tph) 163 tonne/h (180 tph) 172 tonne/h (190 tph) 172 tonne/h (190 tph) 2 (0)
9 Rod Mill Discharge Tank with Agitator Field erected 372,790 liters (98,480 gal) 378,506 liters (99,990 gal) 383,352 liters (101,270 gal) 388,121 liters (102,530 gal) 391,377 liters (103,390 gal) 2 (0)
10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)
11 Slurry Storage Tank with Agitator Field erected 1,118,598 liters (295,500 gal) 1,135,633 liters (300,000 gal) 1,150,017 liters (303,800 gal) 1,164,402 liters (307,600 gal) 1,174,244 liters (310,200 gal) 2 (0)
12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)
13 Slurry Product Pumps Positive displacement 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,028 lpm (800 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)



## ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Design Condition Opr Qty. (Spares) D3A D3B D3C D3D D3E
1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,086,413 liters (287,000 gal) 1,097,769 liters (290,000 gal) 1,090,199 liters (288,000 gal) 1,078,842 liters (285,000 gal) 1,075,057 liters (284,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 7,041 lpm @ 91 m H 2 

### O (1,860 gpm @ 300 ft H 2 

### O) 7,306 lpm @ 91 m H 2 

### O (1,930 gpm @ 300 ft H 2 

### O) 7,457 lpm @ 91 m H 2 

### O (1,970 gpm @ 300 ft H 2 

### O) 7,609 lpm @ 91 m H 2 

### O (2,010 gpm @ 300 ft H 2 

### O) 7,684 lpm @ 91 m H 2 

### O (2,030 gpm @ 300 ft H 2 

### O) 2 (1)

3 Deaerator (integral w/ HRSG) Horizontal spray type 483,983 kg/hr (1,067,000 lb/hr) 499,859 kg/hr (1,102,000 lb/hr) 509,384 kg/hr (1,123,000 lb/hr) 518,456 kg/hr (1,143,000 lb/hr) 524,353 kg/hr (1,156,000 lb/hr) 2 (0)

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 8,101 lpm @ 27 m H 2 

### O (2,140 gpm @ 90 ft H 2 

### O) 8,176 lpm @ 27 m H 2 

### O (2,160 gpm @ 90 ft H 2 

### O) 8,025 lpm @ 27 m H 2 

### O (2,120 gpm @ 90 ft H 2 

### O) 7,874 lpm @ 27 m H 2 

### O (2,080 gpm @ 90 ft H 2 

### O) 7, 760 lpm @ 27 m H 2 

### O (2,050 gpm @ 90 ft H 2 

### O) 2 (1)

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,132 lpm @ 1,859 m H 2 

### O (1,620 gpm @ 6,100 ft H 2 

### O) HP water: 6,132 lpm @ 1,859 m H 2 

### O (1,620 gpm @ 6,100 ft H 2 

### O) HP water: 6,095 lpm @ 1,859 m H 2 

### O (1,610 gpm @ 6,100 ft H 2 

### O) HP water: 6,057 lpm @ 1,859 m H 2 

### O (1,600 gpm @ 6,100 ft H 2 

### O) HP water: 6,019 lpm @ 1,859 m H 2 

### O (1,590 gpm @ 6,100 ft H 2 

### O) 2 (1)

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,476 lpm @ 223 m H 2 

### O (390 gpm @ 730 ft H 2 

### O) IP water: 1,514 lpm @ 223 m H 2 

### O (400 gpm @ 730 ft H 2 

### O) IP water: 1,590 lpm @ 223 m H 2 

### O (420 gpm @ 730 ft H 2 

### O) IP water: 1,666 lpm @ 223 m H 2 

### O (440 gpm @ 730 ft H 2 

### O) IP water: 1,741 lpm @ 223 m H 2 

### O (460 gpm @ 730 ft H 2 

### O) 2 (1)

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/h r, 400 psig, 650°F) 1 (0)

8 Service Air Compressors Flooded Screw 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 (1)
9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 2 (1)
10 Closed Cylce Cooling Heat Exchangers Plate and frame 247 GJ/hr (234.44802645 MMBtu/hr) each 277 GJ/hr (262.36186405 MMBtu/hr) each 301 GJ/hr (285.73317245 MMBtu/hr) each 327 GJ/hr (309.64151075 MMBtu/hr) each 345 GJ/hr (326.5623988 MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 88,579 lpm @ 21 m H 2 

### O (23,400 gpm @ 70 ft H 2 

### O) 99,178 lpm @ 21 m H 2 

### O (26,200 gpm @ 70 ft H 2 

### O) 108,263 lpm @ 21 m H 2 

### O (28,600 gpm @ 70 ft H 2 

### O) 117,348 lpm @ 21 m H 2 

### O (31,000 gpm @ 70 ft H 2 

### O) 123,783 lpm @ 21 m H 2 

### O (32,700 gpm @ 70 ft H 2 

### O) 2 (1)

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 1 (1)

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 1 (1)

14 Raw Water Pumps Stainless steel, single suction 4,580 lpm @ 18 m H 2 

### O (1,210 gpm @ 60 ft H 2 

### O) 4,921 lpm @ 18 m H 2 

### O (1,300 gpm @ 60 ft H 2 

### O) 5,186 lpm @ 18 m H 2 

### O (1,370 gpm @ 60 ft H 2 

### O) 5,451 lpm @ 18 m H 2 

### O (1,440 gpm @ 60 ft H 2 

### O) 5,640 lpm @ 18 m H 2 

### O (1,490 gpm @ 60 ft H 2 

### O) 2 (1)

15 Ground Water Pumps Stainless steel, single suction 3,028 lpm @ 268 m H 2 

### O (800 gpm @ 880 ft H 2 

### O) 3,293 lpm @ 268 m H 2 

### O (870 gpm @ 880 ft H 2 

### O) 2,612 lpm @ 268 m H 2 

### O (690 gpm @ 880 ft H 2 

### O) 2,725 lpm @ 268 m H 2 

### O (720 gpm @ 880 ft H 2 

### O) 2,839 lpm @ 268 m H 2 

### O (750 gpm @ 880 ft H 2 

### O) 3 (1)



## 350Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D3A D3B D3C D3D D3E
16 Filtered Water Pumps Stainless steel, single suction 2,082 lpm @ 49 m H 2 

### O (550 gpm @ 160 ft H 2 

### O) 2,385 lpm @ 49 m H 2 

### O (630 gpm @ 160 ft H 2 

### O) 2,612 lpm @ 49 m H 2 

### O (690 gpm @ 160 ft H 2 

### O) 2,877 lpm @ 49 m H 2 

### O (760 gpm @ 160 ft H 2 

### O) 3,028 lpm @ 49 m H 2 

### O (800 gpm @ 160 ft H 2 

### O) 2 (1)

17 Filtered Water Tank Vertical, cylindrical 995,563 liter (263,000 gal) 1,139,409 liter (301,000 gal) 1,256,757 liter (332,000 gal) 1,374,104 liter (363,000 gal) 1,453,598 liter (384,000 gal) 2 (0)

18 Makeup Water Demineralizer Anion, cation, and mixed bed 303 lpm (80 gpm) 568 lpm (150 gpm) 795 lpm (210 gpm) 1,022 lpm (270 gpm) 1,173 lpm (310 gpm) 2 (0)

19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



## ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E
1 Gasifier Pressurized slurry

feed, entrained bed 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,812 tonne/day, 5.6 MPa (3,100 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench chamber 243,126 kg/hr (536,000 lb/hr) 246,754 kg/hr (544,000 lb/hr) 249,929 kg/hr (551,000 lb/hr) 253,105 kg/hr (558,000 lb/hr) 255,373 kg/hr (563,000 lb/hr) 2 (0)

3 Synthesis Gas Cyclone High efficiency 332,937 kg/hr (734,000 lb/hr) Design efficiency 90% 337,926 kg/hr (745,000 lb/hr) Design efficiency 90% 342,462 kg/hr (755,000 lb/hr) Design efficiency 90% 346,545 kg/hr (764,000 lb/hr) Design efficiency 90% 349, 266 kg/hr (77 0 ,000 lb/hr) Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters metallic filters metallic filters metallic filters metallic filters 2 (0)

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 332,937 kg/hr (734,000 lb/hr) 337,926 kg/hr (745,000 lb/hr) 342,462 kg/hr (755,000 lb/hr) 346,545 kg/hr (764,000 lb/hr) 349, 266 kg/hr (77 0 ,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with condensate drain 287,578 kg/hr (634,000 lb/hr) 322,504 kg/hr (711,000 lb/hr) 339,741 kg/hr (749,000 lb/hr) 356,977 kg/hr (787,000 lb/hr) 368,771 kg/hr (813,000 lb/hr) 8 (0)

7 Raw Gas Knockout Drum Vertical with mist eliminator 213,642 kg/hr, 35°C, 5.2 MPa (471,000 lb/hr, 95°F, 750 psia) 239,950 kg/hr, 35°C, 5.2 MPa (529,000 lb/hr, 95°F, 750 psia) 261,723 kg/hr, 35°C, 5.2 MPa (577,000 lb/hr, 95°F, 750 psia) 283,949 kg/hr, 35°C, 5.2 MPa (626,000 lb/hr, 95°F, 750 psia) 298,917 kg/hr, 35°C, 5.2 MPa (659,000 lb/hr, 95°F, 750 psia) 2 (0)

8 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 332,937 kg/hr (734,000 lb/hr) syngas 337,926 kg/hr (745,000 lb/hr) syngas 342,462 kg/hr (755,000 lb/hr) syngas 346,545 kg/hr (764,000 lb/hr) syngas 349, 266 kg/hr (77 0 ,000 lb/hr) syngas 2 (0)

9 ASU Main Air Compressor Centrifugal, multi

stage 5,6 35 m 3 

### /min @ 1.3 MPa ( 199 ,000 scfm @ 190 psia) 5,748 m 3 

### /min @ 1.3 MPa (203,000 scfm @ 190 psia) 5,805 m 3 

### /min @ 1.3 MPa (205,000 scfm @ 190 psia) 5,890 m 3 

### /min @ 1.3 MPa (208,000 scfm @ 190 psia) 5,918 m 3 

### /min @ 1.3 MPa (209,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multi

stage 1,133 m 3 

### /min (40,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 1,161 m 3 

### /min (41,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 1,161 m 3 

### /min (41,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 1,189 m 3 

### /min (42,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 1,189 m 3 

### /min (42,000 scfm) Suction

- 0.9 MPa (130 psia)

Discharge

- 6.5 MPa (940 psia) 2 (0)

12 Primary Nitrogen Compressor Centrifugal, multi

stage 3,540 m 3 

### /min (125,000 scfm) Suction

- 0.4 MPa (60 psia)

Discharge

- 2.7 MPa (390 psia) 3,625 m 3 

### /min (128,000 scfm) Suction

- 0.4 MPa (60 psia)

Discharge

- 2.7 MPa (390 psia) 3,653 m 3 

### /min (129,000 scfm) Suction

- 0.4 MPa (60 psia)

Discharge

- 2.7 MPa (390 psia) 3,710 m 3 

### /min (131,000 scfm) Suction

- 0.4 MPa (60 psia)

Discharge

- 2.7 MPa (390 psia) 3,738 m 3 

### /min (132,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 (0)



## 351Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

13 Secondary Nitrogen Compressor Centrifugal, single

stage 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia)

Discharge

- 2.7 MPa (390 psia) 2 (0)

14 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

stage 0 m 3 

### /min (0 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 28 m 3 

### /min (1,000 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 680 m 3 

### /min (24,000 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 1,331 m 3 

### /min (47,000 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 1 ,784 m 3 

### /min (63,000 scfm) Suction

- 2.6 MPa (380 psia)

Discharge

- 3.2 MPa (470 psia) 2 (0)



## ACCOUNT 5A SYNGAS CLEANUP
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Mercury Adsorber Sulfated carbon bed 212,735 kg/hr (469,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 239,497 kg/hr (528,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 261,269 kg/hr (576,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 283,495 kg/hr (625,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 298,464 kg/hr (658,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 (0)

2 Sulfur Plant Claus type 139 tonne/day (153 tpd) 141 tonne/day (155 tpd) 143 tonne/day (157 tpd) 144 tonne/day (159 tpd) 145 tonne/day (160 tpd) 1 (0)

3 Water Gas Shift Reactors Fixed bed, catalytic 907 kg/hr (2,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 110,223 kg/hr (243,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 200,034 kg/hr (441,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 291,206 kg/hr (642,000 lb/hr) 221°C (430° F) 5.4 MPa (790 psia) 352,895 kg/hr (778,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 4 (0)

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 00 GJ/hr (00 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 45 GJ/hr (42 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 81 GJ/hr (77 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 118 GJ/hr (112 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 143 GJ/hr (135 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 (0)

5 COS Hydrolysis Reactor Fixed bed, catalytic 300,732 kg/hr (663,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 212,281 kg/hr (468,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 139,253 kg/hr (307,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 65,771 kg/hr (145,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 15,876 kg/hr (35,000 lb/hr) 210°C (410°F) 5.4 MPa (790 psia) 2 (0)

6 Acid Gas Removal Plant Two

- stage Selexol 214,549 kg/hr (473,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 240,858 kg/hr (531,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 262,630 kg/hr (579,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 284,856 kg/hr (628,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 300,278 kg/hr (662,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 2 (0)

7 Hydrogenation Reactor Fixed bed, catalytic 6,347 kg/hr (13,992 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 6,104 kg/hr (13,457 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 5,915 kg/hr (13,039 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 6,798 kg/hr (14,988 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 7,423 kg/hr (16 ,364 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 (0)

8 Tail Gas Recycle Compressor Centrifugal 3,059 kg/hr (6,744 lb/hr) 2,514 kg/hr (5,543 lb/hr) 2,073 kg/hr (4,570 lb/hr) 2,784 kg/hr (6,138 lb/hr) 3,281 kg/hr (7,233 lb/hr) 1 (0)



## ACCOUNT 5B CO 2 

## COMPRESSION
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 CO 2 

### Compressor Integrally geared, multi

stage centrifugal 30 3 m 3 

### /min @ 15.3 MPa (10, 7 00 scfm @ 2,215 psia) 544 m 3 

### /min @ 15.3 MPa (19,200 scfm @ 2,215 psia) 736 m 3 

### /min @ 15.3 MPa (26,000 scfm @ 2,215 psia) 9 29 m 3 

### /min @ 15.3 MPa (32, 8 00 scfm @ 2,215 psia) 1,062 m 3 

### /min @ 15.3 MPa (37,500 scfm @ 2,215 psia) 4 (0)



## 352Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E 1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 230 MW 230 MW 2 (0)
2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 (0)

3 Syngas Expansion Turbine/Generator Turbo Expander 144,378 kg/h (318,300 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 116,800 kg/h (257,500 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 95,935 kg/h (211,500 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 74,344 kg/h (163,900 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 59,693 kg/h (131,600 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 2 (0)



## ACCOUNT 7 HRSG, DUCTING , AND STACK
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E
1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.4 m (28 ft) diameter 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 (0)

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 346,899 kg/hr, 12.4 MPa/554°C (764,782 lb/hr, 1,800 psig/1,029°F)

Reheat steam

- 346,477 kg/hr, 3.1 MPa/554°C (763,852 lb/hr, 452 psig/1,029°F) Main steam

- 346,705 kg/hr, 12.4 MPa/548°C (76 4,354 lb/hr, 1,800 psig/1,019°F)

Reheat steam

- 340,285 kg/hr, 3.1 MPa/548°C (750,200 lb/hr, 452 psig/1,019°F) Main steam

- 344,019 kg/hr, 12.4 MPa/544°C (758,433 lb/hr, 1,800 psig/1,011°F)

Reheat steam

- 342,563 kg/hr, 3.1 MPa/544°C (755,223 lb/h r, 452 psig/1,011°F) Main steam

- 341,230 kg/hr, 12.4 MPa/539°C (752,283 lb/hr, 1,800 psig/1,002°F)

Reheat steam

- 344,795 kg/hr, 3.1 MPa/539°C (760,143 lb/hr, 452 psig/1,002°F) Main steam

- 339,379 kg/hr, 12.4 MPa/536°C (748,203

lb/hr, 1,800 psig/99 7°F) Reheat steam

- 346,307 kg/hr, 3.1 MPa/536°C (763,477 lb/hr, 452 psig/997°F) 2 (0)



## ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 Steam Turbine Commercially available advanced steam turbine 295 MW 12.4 MPa/554°C/554°C (1,800 psig/ 1029°F/1029°F) 291 MW 12.4 MPa/548°C/548°C (1,800 psig/ 1019°F/1019°F) 289 MW 12.4 MPa/544°C/544°C (1,800 psig/ 1011°F/1011°F) 286 MW 12.4 MPa/539°C/539°C (1,800 psig/ 1002°F/1002°F) 284 MW 12.4 MPa/536°C/536°C (1,800 psig/ 997°F/997°F) 1 (0)

2 Steam Turbine Generator Hydrogen cooled, static excitation 330 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 2 (0)

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,783 GJ/hr (1,690 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,772 GJ/hr (1,680 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 1 1°C (20°F) 1,751 GJ/hr (1,660 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,730 GJ/hr (1,640 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,709 GJ/hr (1,620 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 (0)



## 353Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E
1 Circulating Water Pumps Vertical, wet pit 416,395 lpm @ 30 m (110,000 gpm @ 100 ft) 431,537 lpm @ 30 m (114,000 gpm @ 100 ft) 442,893 lpm @ 30 m (117,000 gpm @ 100 ft) 454,249 lpm @ 30 m (120,000 gpm @ 100 ft) 461,820 lpm @ 30 m (122,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,332 GJ/hr (2,210 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,416 GJ/hr (2,290 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27° C (80°F) HWT / 2,479 GJ/hr (2,350 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,532 GJ/hr (2,400 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,574 GJ/hr (2,440 MMBtu/hr) he at duty 1 (0)



## ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E 1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 246,052 liters (65,000 gal) 249,837 liters (66,000 gal) 249,837 liters (66,000 gal) 253,623 liters (67,000 gal) 2 (0) 2 Slag Crusher Roll 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0) 3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0) 4 Slag Receiving Tank Horizontal, weir 143,846 liters (38,000 gal) 147,631 liters (39,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)
5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 13 tonne/hr (14 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

9 Fine Ash Settling Tank Vertical, gravity 208,198 liters (55,000 gal) 208,198 liters (55,000 gal) 211,983 liters (56,000 gal) 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 2 (2)

11 Grey Water Storage Tank Field erected 64,352 liters (17,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 2 (2)
13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 907 tonne (1,000 tons) 998 tonne (1,100 tons) 2 (0) 14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)



## 354Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 11 ACCESSORY ELECTRIC PLANT
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E
1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 (0)

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 330 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 320 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 320 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 320 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 320 MVA, 3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 63 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 68 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 72 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 76 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 79 MVA, 3

- ph, 60 Hz 2 (0)

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 30 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 34 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 38 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 42 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 45 MVA, 3

- ph, 60 Hz 1 (1)

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 5 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 6 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 6 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 7 MVA, 3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 2 (0)

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



## ACCOUNT 12 INSTRUMENTATION AND CONTROL
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 3 A D 3 B D 3 C D3D D 3E

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/pri nters and engineering stations/printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A N/A N/A N/A N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)



## 355Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

356Carbon Dioxide Capture Sensitivity Analysis



# 4.3.4 IGCC Design 4

– Two Water Gas Shift Reactors Without Bypass
A proces s block flow diagram for Case 2 Design 4 (D4) is shown in Exhibit 4

- 108 . D4 represents an IGCC plant with two WGS reactors and no bypass stream, which maximizes total CO 2 

## capture. This IGCC design uses a S:D G molar ratio of 0.3 at the outlet of the second WGS reactor. To achieve greater than 90 percent CO 2 

## removal, the two

- stage SelexolTM CO 2 

## removal efficiency is increased by raising the solvent circulation rate, which increases the size and cost of the Sele xolTM system. According to UOP, two

- stage SelexolTM systems have been designed for up to 97 percent CO 2 

## recovery and this level of control was deemed the maximum for this study [ 57 ]. D4 does not include a COS h ydrolysis unit since the entire syngas stream passes th rough two WGS reactors.

Three levels of total CO 2 

## removal were modeled for Case 2 D4: 90 percent (D4A), 95 percent (D4B), and 97 percent (D4C). The corresponding stream tables are contained in Exhibit 4

- 109 , Exhibit 4

- 110 , and Exhibit 4

- 111 , respectively. Overall performance for Case 2 D4 is summarized in Exhibit 4

- 112 which includes auxiliary power requirements. Note that the coal feed rate remains essentially constant at CO 2 

## capture levels of 90 percent and higher , but a small decrease (~0.2 percent ) is observed. This anomaly can be expl ained by a significant increase in the quantity of nitrogen sent to the CT for dilution and temperature control. The excess nitrogen increases the total mass flow to the CT, which lead s to a CT power output greater than 464 MW. As a result, the Aspen model reduce s the coal feed rate slightly to maintain a CT gross power output of 464 MW (based on two turbines) since
an advanced F Class turbine is designed for a gross output of 232 MW

. However, as expected, the net power output and net plant efficiency decrease as the CO 2 

## capture level increases. Material and energy balance information, environmental performance and a major e quipment list are summarized in Sections 4.3.4.1 a nd 4.3.4.2

.

357Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 108 Case 2 D4 Process Block Flow Diagram, IGCC with Two WGS Reactors

G AS T URBINE C OMBUSTOR

T URBINE C OOLING A IR Q UENCH AND

S YNGAS S CRUBBER G AS C OOLING BFW H EATING & K NOCKOUT S HIFT R EACTORS

E LEVATED P RESSURE

ASU GEE G ASIFIER S ECTION ( R ADIANT C OOLER ) S OUR W ATER S TRIPPER M ERCURY R EMOVAL T WO

S TAGE S ELEXOL

U NIT

C LAUS P LANT

HRSG

A MBIENT A IR S YNGAS E XPANDER

H YDROGENATION R EACTOR AND G AS C OOLER CO 2 C OMPRESSION

1 5 9 10 11 12 13 14

16 18

19

20 17

6 8

2 3 4

21 22 23 A IR TO ASU A S

- R ECEIVED C OAL

S LAG S HIFT S TEAM

W ATER R ECYCLE TO P ROCESS

D EMAND N OTE : W ATER FROM T AIL G AS C OOLER MODELED , BUT NOT SHOWN

N ITROGEN D ILUENT S YNGAS C LEAN G AS CO 2 S TREAMS CO 2 P RODUCT

S ULFUR

T AIL G AS R ECYCLE TO

S ELEXOL N OTE : T AIL G AS B OOST C OMPRESSOR MODELED , BUT NOT SHOWN

F LUE G AS S TACK G AS V ENT G AS C LAUS P LANT O XIDANT

2 X A DVANCED

F C LASS G AS T URBINE S YNGAS H / P R EHEAT

15

C LAUS P LANT O XIDANT

S TEAM T URBINE 24

464 MW e Note : Block Flow Diagram is not intended to represent a complete material balance

. Only major process streams and equipment are shown

. 20
T AIL G AS R ECYCLE F ROM C LAUS P LANT

S LURRY M IXER

7 S LURRY W ATER



## 358Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 109 Case 2 D4A Stream Table, 90% CO 2 

### Removal

1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0165 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054 CH 4 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2823 0.0000 0.0060 CO 2 

### 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1089 0.0000 0.3082 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2689 0.0000 0.4366 H 2 

### O 0.0099 0.1356 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3190 1.0000 0.2325 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 H 2 

### S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0047 N 2 

### 0.7732 0.7074 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 O 2 

### 0.2074 0.1350 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 27,374 1,659 98 20,052 5,526 0 5,038 0 23,123 29,287 7,192 36,479 V-L Flowrate (kg/hr) 789,924 45,576 3,158 562,651 177,833 0 90,750 0 465,257 576,023 129,569 705,592 Solids Flowrate (kg/hr) 0 0 0 0 0 220,911 0 24,238 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 240 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 Enthalpy (kJ/kg) A 

### 30.23 35.63 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,065.78 2,918.18 942.21 Density (kg/m 3 

### ) 1.2 1.5 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.8 V-L Molecular Weight 28.857 27.479 32.181 28.060 32.181

--- 18.015

--- 20.121 19.669 18.015 19.343

V-L Flowrate (lb mol 

### /hr) 60,349 3,657 216 44,207 12,183 0 11,106 0 50,977 64,566 15,856 80,422 V-L Flowrate (lb/hr) 1,741,483 100,477 6,963 1,240,434 392,056 0 200,070 0 1,025,716 1,269,913 285,651 1,555,564 Solids Flowrate (lb/hr) 0 0 0 0 0 487,026 0 53,435 0 0 0 0
Temperature (°F) 59 65 90 199 90 59 287 2,400 1,250 403 550 463 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 Enthalpy (Btu/lb) A 

### 13.0 15.3 11.5 39.8 11.5

--- 231.2

--- 612.5 458.2 1,254.6 405.1 Density (lb/ft 3 

### ) 0.076 0.091 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.550 A - Reference conditions are 32.02 F & 0.089 PSIA



## 359Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 109 Case 2 D4A Stream Table, 90% CO 2 Removal (continued)

13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction

Ar 0.0071 0.0071 0.0115 0.0115 0.0002 0.0018 0.0000 0.0106 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0009 0.0009 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0078 0.0077 0.0124 0.0124 0.0002 0.0022 0.0000 0.0060 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.4019 0.4056 0.0502 0.0502 0.9948 0.5215 0.0000 0.6744 0.0003 0.0083 0.0083 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.5692 0.5648 0.9139 0.9139 0.0048 0.1028 0.0000 0.2474 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0012 0.0013 0.0001 0.0001 0.0000 0.0226 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0061 0.0061 0.0000 0.0000 0.0000 0.3477 0.0000 0.0050 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0058 0.0065 0.0105 0.0105 0.0000 0.0008 0.0000 0.0549 0.7732 0.7541 0.7541 0.0000 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 27,979 28,364 17,419 17,419 10,425 497 0 385 110,253 139,656 139,656 34,499 V-L Flowrate (kg/hr) 552,408 564,934 90,173 90,173 456,670 17,684 0 12,527 3,181,557 3,834,382 3,834,382 621,516 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,524 0 0 0 0 0
Temperature (°C) 35 35 35 198 51 48 180 38 15 562 132 534 Pressure (MPa, abs) 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 37.11 36.4 195.466 1,134.797 -162.309 74.861

--- 4.442 30.227 834.702 343.768 3,432.882 Density (kg/m 3 

### ) 40.7 40.9 9.9 4.1 641.8 2.2 5,275.4 79.1 1.2 0.4 0.9 36.7 V-L Molecular Weight 19.744 20 5.177 5.177 43.805 35.589

--- 32.508 28.857 27.456 27.456 18.015

V-L Flowrate (lb mol 

### /hr) 61,683 62,532 38,403 38,403 22,984 1,095 0 850 243,066 307,890 307,890 76,058 V-L Flowrate (lb/hr) 1,217,850 1,245,467 198,798 198,798 1,006,784 38,986 0 27,617 7,014,133 8,453,366 8,453,366 1,370,208 Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,178 0 0 0 0 0
Temperature (°F) 95 95 95 388 124 119 356 100 59 1,044 270 994 Pressure (psia) 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 16.0 15.6 84.0 487.9 -69.8 32.2

--- 1.9 13.0 358.9 147.8 1,475.9 Density (lb/ft 3 

### ) 2.544 3 0.618 0.259 40.069 0.137 329.335 4.938 0.076 0.026 0.053 2.293 A - Reference conditions are 32.02 F & 0.089 PSIA



## 360Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 110 Case 2 D4B Stream Table, 95% CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0264 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054 CH 4 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2818 0.0000 0.0060 CO 2 

### 0.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1087 0.0000 0.3082 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2684 0.0000 0.4366 H 2 

### O 0.0099 0.2316 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3203 1.0000 0.2325 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 H 2 

### S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0047 N 2 

### 0.7732 0.5064 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 O 2 

### 0.2074 0.2264 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 27,345 969 102 20,718 5,516 0 5,029 0 23,082 29,288 7,127 36,415 V-L Flowrate (kg/hr) 789,090 26,226 3,280 581,359 177,521 0 90,591 0 464,438 575,969 128,386 704,355 Solids Flowrate (kg/hr) 0 0 0 0 0 220,522 0 24,195 0 0 0 0
Temperature (°C) 15 21 32 93 32 15 142 1,316 677 206 288 240 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 Enthalpy (kJ/kg) A 

### 30.23 37.59 26.67 92.51 26.67

--- 537.77

--- 1,424.65 1,069.11 2,918.18 942.19 Density (kg/m 3 

### ) 1.2 1.6 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.8 V-L Molecular Weight 28.857 27.062 32.181 28.060 32.181

--- 18.015

--- 20.121 19.666 18.015 19.343

V-L Flowrate (lb mol 

### /hr) 60,285 2,137 225 45,676 12,161 0 11,086 0 50,888 64,569 15,711 80,281 V-L Flowrate (lb/hr) 1,739,646 57,819 7,231 1,281,677 391,366 0 199,718 0 1,023,911 1,269,794 283,043 1,552,837 Solids Flowrate (lb/hr) 0 0 0 0 0 486,169 0 53,341 0 0 0 0
Temperature (°F) 59 70 90 199 90 59 287 2,400 1,250 403 550 463 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 Enthalpy (Btu/lb) A 

### 13.0 16.2 11.5 39.8 11.5

--- 231.2

--- 612.5 459.6 1,254.6 405.1 Density (lb/ft 3 

### ) 0.076 0.100 0.687 1.521 0.687

--- 54.440

--- 0.871 1.698 1.597 1.550 A - Reference conditions are 32.02 F & 0.089 PSIA



## 361Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 110 Case 2 D4B Stream Table, 95% CO 2 Capture (continued)

13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction

Ar 0.0071 0.0070 0.0119 0.0119 0.0002 0.0008 0.0000 0.0043 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0009 0.0009 0.0015 0.0015 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0078 0.0077 0.0131 0.0131 0.0002 0.0010 0.0000 0.0065 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.4019 0.4180 0.0194 0.0194 0.9950 0.7832 0.0000 0.8771 0.0003 0.0043 0.0043 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.5692 0.5527 0.9432 0.9432 0.0045 0.0462 0.0000 0.0851 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0012 0.0013 0.0001 0.0001 0.0000 0.0105 0.0000 0.0019 0.0099 0.1218 0.1218 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0061 0.0060 0.0000 0.0000 0.0000 0.1576 0.0000 0.0035 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0058 0.0063 0.0108 0.0108 0.0000 0.0003 0.0000 0.0216 0.7732 0.7583 0.7583 0.0000 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1065 0.1065 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 27,930 28,911 16,835 16,835 10,949 1,104 0 982 110,253 139,757 139,757 34,339 V-L Flowrate (kg/hr) 551,437 590,590 66,062 66,062 479,736 44,371 0 39,153 3,181,557 3,828,979 3,828,979 618,619 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,514 0 0 0 0 0
Temperature (°C) 35 34 34 197 51 48 178 38 15 561 132 533 Pressure (MPa, abs) 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 37.11 33.6 256.725 1,476.079 -162.700 53.966

--- -15.243 30.227 832.909 343.672 3,429.212 Density (kg/m 3 

### ) 40.7 42.1 7.5 3.1 643.2 2.5 5,279.2 110.1 1.2 0.4 0.9 36.8 V-L Molecular Weight 19.744 20 3.924 3.924 43.815 40.204

--- 39.887 28.857 27.397 27.397 18.015

V-L Flowrate (lb mol 

### /hr) 61,574 63,738 37,115 37,115 24,139 2,433 0 2,164 243,066 308,111 308,111 75,704 V-L Flowrate (lb/hr) 1,215,711 1,302,028 145,641 145,641 1,057,638 97,821 0 86,317 7,014,133 8,441,453 8,441,453 1,363,822 Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,156 0 0 0 0 0
Temperature (°F) 95 94 94 387 124 119 353 100 59 1,041 270 991 Pressure (psia) 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 16.0 14.5 110.4 634.6 -69.9 23.2

--- -6.6 13.0 358.1 147.8 1,474.3 Density (lb/ft 3 

### ) 2.544 3 0.468 0.197 40.153 0.154 329.568 6.873 0.076 0.026 0.053 2.299 A - Reference conditions are 32.02 F & 0.089 PSIA



## 362Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 111 Case 2 D4C Stream Table, 97% CO 2 

### Capture

1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0274 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054 CH 4 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2818 0.0000 0.0060 CO 2 

### 0.0003 0.0096 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1087 0.0000 0.3082 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2684 0.0000 0.4366 H 2 

### O 0.0099 0.2415 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3201 1.0000 0.2325 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 H 2 

### S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0047 N 2 

### 0.7732 0.4856 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 O 2 

### 0.2074 0.2358 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 27,337 929 104 20,752 5,513 0 5,025 0 23,067 29,264 7,127 36,391 V-L Flowrate (kg/hr) 788,869 25,102 3,344 582,313 177,406 0 90,532 0 464,140 575,510 128,391 703,901 Solids Flowrate (kg/hr) 0 0 0 0 0 220,380 0 24,179 0 0 0 0
Temperature (°C) 15 21 32 93 32 15 142 1,316 677 206 288 240 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 Enthalpy (kJ/kg) A 

### 30.23 37.80 26.67 92.51 26.67

--- 537.77

--- 1,424.65 1,068.81 2,918.18 942.20 Density (kg/m 3 

### ) 1.2 1.6 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.8 V-L Molecular Weight 28.857 27.019 32.181 28.060 32.181

--- 18.015

--- 20.121 19.666 18.015 19.343

V-L Flowrate (lb mol 

### /hr) 60,268 2,048 229 45,751 12,154 0 11,079 0 50,855 64,517 15,712 80,229 V-L Flowrate (lb/hr) 1,739,159 55,341 7,372 1,283,780 391,114 0 199,590 0 1,023,253 1,268,783 283,054 1,551,837 Solids Flowrate (lb/hr) 0 0 0 0 0 485,856 0 53,307 0 0 0 0
Temperature (°F) 59 70 90 199 90 59 287 2,400 1,250 403 550 463 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 Enthalpy (Btu/lb) A 

### 13.0 16.2 11.5 39.8 11.5

--- 231.2

--- 612.5 459.5 1,254.6 405.1 Density (lb/ft 3 

### ) 0.076 0.101 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.550 A - Reference conditions are 32.02 F & 0.089 PSIA



## 363Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 111 Case 2 D4C Stream Table, 97% CO2 Capture (continued)

13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction

Ar 0.0071 0.0069 0.0120 0.0120 0.0002 0.0007 0.0000 0.0035 0.0092 0.0091 0.0091 0.0000 CH 4 

### 0.0009 0.0009 0.0015 0.0015 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0078 0.0077 0.0133 0.0133 0.0002 0.0008 0.0000 0.0062 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.4019 0.4231 0.0059 0.0059 0.9951 0.8233 0.0000 0.9044 0.0003 0.0027 0.0027 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.5692 0.5478 0.9561 0.9561 0.0044 0.0376 0.0000 0.0638 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0012 0.0013 0.0001 0.0001 0.0000 0.0087 0.0000 0.0019 0.0099 0.1217 0.1217 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### S 0.0061 0.0060 0.0000 0.0000 0.0000 0.1285 0.0000 0.0030 0.0000 0.0000 0.0000 0.0000 N 2 

### 0.0058 0.0063 0.0110 0.0110 0.0000 0.0003 0.0000 0.0173 0.7732 0.7600 0.7600 0.0000 NH 3 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1065 0.1065 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol 

### /hr) 27,912 29,141 16,593 16,593 11,168 1,356 0 1,229 110,253 139,792 139,792 34,282 V-L Flowrate (kg/hr) 551,082 601,304 56,035 56,035 489,389 55,454 0 50,222 3,181,557 3,826,524 3,826,524 617,598 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,510 0 0 0 0 0
Temperature (°C) 35 34 34 197 51 48 178 38 15 560 132 532 Pressure (MPa, abs) 5.14 5.1 4.999 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 

### 37.11 32.5 297.541 1,704.475 -162.852 51.196

--- -18.172 30.227 832.246 343.704 3,427.800 Density (kg/m 3 

### ) 40.7 42.7 6.5 2.7 643.7 2.5 5,280.0 115.5 1.2 0.4 0.9 36.9 V-L Molecular Weight 19.744 21 3.377 3.377 43.819 40.909

--- 40.864 28.857 27.373 27.373 18.015

V-L Flowrate (lb mol 

### /hr) 61,535 64,244 36,581 36,581 24,622 2,988 0 2,710 243,066 308,188 308,188 75,579 V-L Flowrate (lb/hr) 1,214,928 1,325,649 123,536 123,536 1,078,918 122,254 0 110,721 7,014,133 8,436,041 8,436,041 1,361,570 Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,148 0 0 0 0 0
Temperature (°F) 95 93 93 386 124 119 352 100 59 1,040 270 990 Pressure (psia) 745.0 740.0 725.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 

### 16.0 14.0 127.9 732.8 -70.0 22.0

--- -7.8 13.0 357.8 147.8 1,473.7 Density (lb/ft 3 

### ) 2.544 3 0.403 0.169 40.186 0.157 329.622 7.208 0.076 0.026 0.053 2.301 A - Reference conditions are 32.02 F & 0.089 PSIA



## 364Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 112 Case 2 D4 Performance Modeling Results POWER SUMMARY (Gross Power at Generator Terminals, kWe) D 4 A ( 90 %) D 4 B ( 95 %) D 4 C ( 97 %) Gas Turbine Power 464,000 464,000 464,000 Sweet Gas Expander Power 6, 3 00 6, 0 00 6, 0 00 Steam Turbine Power 263,700 256,600 253,600 Total 734, 0 00 726, 6 00 723, 6 00 AUXILIARY LOAD SUMMARY, kWe Coal Handling 4 69 4 68 4 68

Coal Milling 2, 27 2 2, 2 6 8 2, 2 67 Sour Water Recycle Slurry Pump 1 9 0 1 9 0 1 89 Slag Handling 1,1 6 4 1,1 6 1 1,1 6 1 Air Separation Unit Auxiliaries 1,000 1,000 1,000 Air Separation Unit Main Air Compressor 67,3 62 67, 291 67,2 72 Oxygen Compressor 10, 64 2 10, 6 2 4 10, 6 1 7 Nitrogen Compressors 35,64 5 36,97 5 37,0 84 CO 2 

### Compressor 31,1 6 1 32,7 23 33,3 76 Boiler Feedwater Pumps 4,1 78 4,1 67 4,16 3 Condensate Pump 2 79 2 66 2 6 1 Quench Water Pump 5 38 5 37 5 36 Circulating Water Pump 4, 62 1 4, 55 1 4, 52 1

Ground Water Pumps 5 27 5 19 5 17 Cooling Tower Fans 2, 390 2, 35 2 2, 3 37

Scrubber Pumps 2 26 2 2 1 2 2 1 Acid Gas Removal 19,23 0 21,2 7 3 22,1 25 Gas Turbine Auxiliaries 1,000 1,000 1,000 Steam Turbine Auxiliaries 100 100 100 Claus Plant/TGTU Auxiliaries 250 250 250 Claus Plant TG Recycle Compressor 1,760 4,40 0 5,49 3

Miscellaneous Balance of Plant 1 

### 3,000 3,000 3,000 Transformer Losses 2, 7 5 2 2, 7 5 4 2, 75 1 TOTAL AUXILIARIES, kWe 190,756 198,090 200,709 NET POWER, kWe 543, 244 528, 510 522,891 Net Plant Efficiency, % (HHV) 32.6 % 31.8 % 31.5 % Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,03 5 (10,45 9 ) 11,3 22 (10,7 31 ) 11,43 7 (10,8 40 ) Condenser Duty, GJ/hr (10 6 

### Btu/hr) 1, 519 (1, 44 0) 1, 435 (1, 36 0) 1, 403 (1, 33 0) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 220,9 11 ( 487, 026 ) 220,5 22 ( 486, 169 ) 220, 380 ( 485, 856 ) Thermal Input, kW th 2 

### 1, 665, 125 1, 662, 195 1, 661, 125 Raw Water Withdrawal, m 3 

### /min (gpm) 22.0 ( 5,81 7 ) 21.7 ( 5,7 39 ) 21.6 ( 5,70 7 ) Raw Water Consumption, m 3 

### /min (gpm) 17.9 ( 4,74 1 ) 17.7 ( 4,6 79 ) 17.6 ( 4,65 4 ) 

### Notes: 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads 2. HHV of As Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb)



## 36 5Carbon Dioxide Capture Sensitivity Analysis



## 4.3.4.1 Environmental Performance for Case 2 D4 The environmental targets for emissions of Hg, NOx, SO 2 

## , and particulate matter were presented in Section 2.4 . A summary of the p lant air emissions for Case 2 D4A, D4 B , and D4C is presented in Exhibit 4

- 113

. For Case 2 D4, SO 2 

## emissions are controlled by sulfur capture across the two

- stage SelexolTM unit. The clean syngas exiting the AGR unit has a sulfur concentration of about 10 ppmv, resulting in a concentration in the flue gas of less than 2 ppmv. The H 2 

## S

- rich regeneration gas produced in Case 2 D4 is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the SelexolTM unit, thereby eliminating the need for a tail gas treatmen t unit. NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process, and ultimately incinerated in the Claus plant burner. This also assists in lowering NOx levels. Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particul ate emissions represent filterable particulate only. Ninety

- five percent of the mercury is captured from the syngas by an activated carbon bed. For Case 2 D4, varying levels of the CO 2 

## [90 percent (D4A), 95 percent (D4B), and 97 percent (D4C)] in the syn gas are captured in the two

- stage SelexolTM unit and compressed for sequestration. The carbon balance for Case 2 D4 is shown in Exhibit 4

- 114 . The car bon input to the plant consists of carbon in the air and coal. Carbon in the air is not neg lected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as dissolved CO 2 

## in the wastewate r blowdown stream , and as CO 2 

## in the stack gas, ASU vent gas, and the captured CO 2 

## product. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance. The carbon capture efficiency is defined as the pounds of carb on in the CO 2 

## product stream relative to the amount of carbon in the coal , less carbon contained in the slag , represented by the following fraction:
(Carbon in CO 2 

## Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or 274,684/(310,453

- 6,209)*100=90.3% (D4A) 288,563 /( 309,907

- 6,198 )*100= 95.0 % (D 4 B) 294,371 /( 309,708

- 6, 194 )*100= 97.0 % (D 4 C)

Exhibit 4

- 115 shows the sulfur balance for Case 2 D2. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the pounds of sulfur recovered in the Claus plant, dissolved SO 2 

## in the wastewater blowdown stream, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible, and the sulfur content of the blowdown stream is calculated by difference to close the material balance. The total sulfur capture is repr esented by the following fraction:

366Carbon Dioxide Capture Sensitivity Analysis



## (Sulfur byproduct/Sulfur in the coal) or

(12,178/12,207)*100 = 99.8% (D4A) (12,156/12,185)*100 = 99.8% (D4B) (12,148/12,178)*100 = 99.8% (D4C)

The overall water balance s for Case 2 D4A, D4B, and D4C are shown in Exhibit 4

- 116 , Exhibit 4

- 117 , and Exhibit 4

- 118 , respectively. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular proce ss. Some water is recovered within t he process and that water is re used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Process water discharged from the power plant is also account ed for in this st udy. Raw water consumption represents raw water withdrawal less proce ss water discharge.

Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 119 through Exhibit 4

- 127

.

• Gasifier and ASU

• Syngas Cleanup

• Power Block An overall plant energy balance for Case D4A, D4B, and D4C is provided in tabular form in Exhibit 4

- 128 , Exhibi t 4

- 129 , and Exhibit 4

- 130 , respectively. The power out is the combined combustion turbine, steam turbine and expander power after generator losses. In addition, energy balance Sankey diagrams are provided for D4A, D4B, and D4C in Exhibit 4

- 131 , Exhibit 4

- 132 , and Exhibit 4

- 133 , respectively.

367Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 113 Case 2 D4 Estimated Air Emission Rates
kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh net 

### (lb/MWh net 

### )
D 4 A D 4 B D 4 C D 4 A D 4 B D 4 C D 4 A D 4 B D 4 C SO 2 

### 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 0. 001 (0.0 02 ) 39 (43) 39 (43) 39 (43) 0.008 (0.020) 0.008 (0.020) 0.008 (0.020)
NO X 

### 0.0 21 (0.0 49 ) 0.0 21 (0.0 49 ) 0.0 21 (0.0 49 ) 878 (967) 878 (968) 878 (968) 0.171 (0.376) 0.172 (0.380) 0.173 (0.382)
PM 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 0.00 3 (0.0 071 ) 128 (141) 128 (141) 128 (141) 0.025 (0.055) 0.025 (0.055) 0.025 (0.056) Hg 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0. 246 x10 - 6 

### ( 0.571 x10 - 6 

### ) 0.010 (0.011) 0.010 (0.011) 0.010 (0.011) 2.01 x10 - 6 

### ( 4.42 x10 - 6 

### ) 2.02 x10 - 6 

### ( 4.46 x10 - 6 

### ) 2.03 x10 - 6 

### ( 4.48 x10 - 6 

### )
CO 2 

### 8.5 (19.7) 4.5 (10.4) 2.8 (6.5) 355,4 05 (391, 767 ) 187, 497 (206, 680 ) 117, 588 (129,6 19 ) 69 (152) 37 (81) 23 (51)

CO 2 

### net 93 (206) 51 (112) 32 (71)



## 368Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 114 Case 2 D4 Carbon Balance Carbon In, kg/hr (lb/hr) D4A D4B D4C
Coal 140,8 19 (310, 453 ) 140, 571 (309,9 07 ) 140, 481 (309,7 08 ) Air (CO 2 

### ) 540 (1,191) 540 (1,19 0 ) 540 (1,190)
Total 141,3 59 (311, 644 ) 141,1 11 (311, 097 ) 141,0 21 (310, 898 ) Carbon Out, kg/hr (lb/hr) Slag 2,81 6 (6,2 09 ) 2,81 1 (6, 198 ) 2,810 (6,19 4 ) Stack Gas 13,84 1 (30,5 14 ) 7,30 2 (16, 098 ) 4,5 79 (10,09 6 ) ASU Vent 107 (237) 107 (237) 107 (237)
CO 2 

### Product 124, 595 (274, 684 ) 130, 890 (288, 563 ) 133,5 25 (294, 371 ) Convergence Tolerance 0 (0) 1 ( 1 ) 0 ( 0 )

Total 141,359 (311,644) 141,111 (311,097) 141,021 (310,898)

Exhibit 4
- 115 Case 2 D4 Sulfur Balance Sulfur In, kg/hr (lb/hr) D4A D4B D4C
Coal 5,53 7 (12,2 07 ) 5,52 7 (12,18 5 ) 5,52 4 (12,1 78 ) Total 5,53 7 (12,2 07 ) 5,52 7 (12,18 5 ) 5,52 4 (12,1 78 ) Sulfur Out, kg/hr (lb/hr)
Elemental Sulfur 5,52 4 (12,1 78 ) 5,51 4 (12,15 6 ) 5,51 0 (12,1 48 ) Stack Gas 3 (6) 3 (6) 3 (6) CO 2 

### Product 10 (23) 11 (23) 11 (24) Convergence Tolerance 0 (0)

- 1 (0) 0 (0)

Total 5,53 7 (12,2 07 ) 5,52 7 (12,18 5 ) 5,52 4 (12,1 78 )



## 369Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 116 Case 2 D4A (90%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.53 (139) 0.53 (139) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.9 (757) 0.72 (191) 2.1 (566) 0.0 (0) 2.1 (566)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 2.4 (627) 0.0 (0) 2.4 (627) 0.0 (0) 2.4 (627)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 2.2 (571) 0.0 (0) 2.2 (571)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (56) 0.0 (0) 0.21 (56) Cooling Tower 

### 18.0 (4,753) 0.49 (129) 17.5 (4,625) 4.0 (1,069) 13.5 (3,556)

BFW Blowdown 

### 0.0 (0) 0.21 (56)

- 0.21 (

- 56)
SWS Blowdown 

### 0.0 (0) 0.28 (73)

- 0.28 (

- 73)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 25.3 (6,676) 3.25 (858) 22.0 (5,817) 4.1 (1,076) 17.9 (4,741)
Total, gal/MWh net 

### 737 95 643 119 524



## 370Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 117 Case 2 D4B (95%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.52 (139) 0.52 (139) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.9 (755) 0.71 (189) 2.1 (567) 0.0 (0) 2.1 (567)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 2.4 (622) 0.0 (0) 2.4 (622) 0.0 (0) 2.4 (622)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 2.1 (566) 0.0 (0) 2.1 (566)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (56) 0.0 (0) 0.21 (56) Cooling Tower 

### 17.7 (4,679) 0.49 (128) 17.2 (4,551) 4.0 (1,052) 13.2 (3,498)

BFW Blowdown 

### 0.0 (0) 0.21 (56)

- 0.21 (

- 56)
SWS Blowdown 

### 0.0 (0) 0.28 (73)

- 0.28 (

- 73)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 25.0 (6,594) 3.24 (855) 21.7 (5,739) 4.0 (1,060) 17.7 (4,679)
Total, gal/MWh net 

### 749 97 652 120 531



## 371Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 118 Case 2 D4C (97%) Water Balance

Water Use Water Demand, m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,
m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm) Slag Handling 

### 0.52 (138) 0.52 (138) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 

### 2.9 (755) 0.72 (189) 2.1 (566) 0.0 (0) 2.1 (566)
Humidifier 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup 

### 2.4 (622) 0.0 (0) 2.4 (622) 0.0 (0) 2.4 (622)

Gasifier Steam 

### 0.0 (0) 0.0 (0) 0.0 (0)
Shift Steam 

### 2.1 (566) 0.0 (0) 2.1 (566)
C T Steam Dilution 

### 0.0 (0) 0.0 (0) 0.0 (0) BFW Makeup 

### 0.21 (56) 0.0 (0) 0.21 (56) Cooling Tower 

### 17.6 (4,648) 0.49 (128) 17.1 (4,519) 4.0 (1,045) 13.2 (3,474)

BFW Blowdown 

### 0.0 (0) 0.21 (56)

- 0.21 (

- 56)
SWS Blowdown 

### 0.0 (0) 0.28 (73)

- 0.28 (

- 73)
SWS Excess Water 

### 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier Tower Blowdown 

### 0.0 (0) 0.0 (0) 0.0 (0)

Total 

### 24.8 (6,562) 3.24 (855) 21.6 (5,707) 4.0 (1,052) 17.6 (4,654)
Total, gal/MWh net 

### 753 98 655 121 534



## 372Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 119 Case 2 D4A (90%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 A ( 90 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 A

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe Net Plant Power : 543 MWe Net Plant Efficiency
, HHV : 32

. 6 % Net Plant Heat Rate : 10 , 459 BTU / KWe N 2 to GT Combustor 1 , 741 , 483 W 59

. 0 T 14

. 7 P 13

. 0 H

392 , 056 W 90

. 0 T 125

. 0 P 11

. 5 H

392 , 056 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 963 W

90

. 0 T 125

. 0 P 11

. 5 H 100 , 477 W 64

. 8 T 16

. 4 P 15

. 3 H

1 , 083 , 585 W 90

. 0 T 56

. 4 P 14

. 2 H

156 , 849 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 487 , 026 W 59

. 0 T 14

. 7 P

200 , 070 W

287

. 0 T 840

. 0 P 231

. 2 H

53 , 435 W 2 , 400

. 0 T

815

. 0 P 676 , 733 W 385

. 0 T 384

. 0 P 87

. 2 H

687 , 096 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 676 , 733 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 563 , 700 W

199

. 0 T 384

. 0 P 39

. 8 H 563 , 700 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 1 , 025 , 716 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 269 , 913 W 403

. 1 T 800

. 0 P 458

. 2 H

Syngas Quench 1 , 404 , 029 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 240 , 434 W 199

. 0 T 384

. 0 P 39

. 8 H



## 373Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 120 Case 2 D4A (90%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 269 , 913 W 403

. 1 T 800

. 0 P 458

. 2 H 1 , 245 , 467 W 94

. 6 T 740

. 0 P 15

. 6 H 38 , 986 W 119

. 0 T 23

. 7 P 198 , 798 W 387

. 6 T 460

. 0 P 487

. 9 H

12 , 178 W 36 , 265 W 450

. 0 T 12

. 3 P 463

. 8 H

2 , 495 W 239

. 1 T 65

. 0 P 442

. 0 H 6 , 963 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 A ( 90 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 A

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe Net Plant Power : 543 MWe Net Plant Efficiency
, HHV : 32

. 6 % Net Plant Heat Rate : 10 , 459 BTU / KWe 19

13 20 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

30 , 039 W 120

. 0 T 10

. 6 P 111

. 0 H 1 , 217 , 850 W 94

. 9 T 745

. 0 P 16

. 0 H

8 , 649 W 114

. 4 T 10

. 6 P 40

. 2 H 3 27 , 617 W

100

. 0 T 799

. 5 P

Raw Syngas 15 198 , 798 W 94

. 6 T 725

. 0 P 84

. 0 H

Claus Oxygen Preheater 6 , 963 W 450

. 0 T 124

. 5 P 91

. 9 H 18 Fuel Gas Expander Fuel Gas To GT

16 198 , 798 W

465

. 0 T 720

. 0 P 597

. 0 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam

12 11

COS Hydrolysis

Preheater 1 , 269 , 913 W 413

. 1 T 795

. 0 P 450

. 3 H 285 , 651 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 1 , 555 , 564 W 436

. 4 T 795

. 0 P 598

. 0 H

776

. 2 T 795

. 0 P 582

. 1 H 400

. 0 T 795

. 0 P 408

. 0 H 1 , 555 , 564 W 463

. 4 T 785

. 0 P 405

. 1 H

1 , 555 , 564 W 455

. 6 T 780

. 0 P 401

. 5 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

17

10 14

1 , 006 , 784 W 123

. 8 T 2 , 214

. 7 P



## 374Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 121 Case 2 D4A (90%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 877 , 010 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 453 , 366 W 269

. 9 T 15

. 2 P 147

. 8 H

198 , 798 W

387

. 6 T 460

. 0 P 487

. 9 H 8 , 453 , 366 W 1 , 043

. 8 T

15

. 2 P 358

. 9 H From Gasifier Island Preheating

To Claus LP BFW 1 , 370 , 208 W 993

. 8 T 1 , 814

. 7 P 1 , 475

. 9 H 10 , 303 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 399 , 027 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 835 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 551 , 382 W 474

. 9 T 65

. 0 P 1 , 269

. 6 H

1 , 877 , 010 W 102

. 9 T 120

. 0 P 71

. 1 H 1 , 877 , 010 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 614

. 9 T 65

. 0 P 1 , 338

. 7 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 A

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 A ( 90 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 A

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe Net Plant Power : 543 MWe Net Plant Efficiency
, HHV : 32

. 6 % Net Plant Heat Rate : 10 , 459 BTU / KWe 21 22

24

16 23

Flue Gas

HOT WELL CONDENSER Make

- up 313 , 467 W 59

. 0 T 14

. 7 P 27

. 1 H 9 , 026 W 660

. 5 T 501

. 4 P 1 , 334

. 5 H 9 , 761 W 614

. 9 T 65

. 0 P 1 , 338

. 7 H 32 , 521 W

852

. 1 T 280

. 0 P 1 , 448

. 8 H 798 W 993

. 8 T 1 , 814

. 7 P 1 , 475

. 9 H 1 , 337 W 505

. 0 T 65

. 0 P 1 , 284

. 5 H



## 375Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 122 Case 2 D4B (95%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 B ( 95 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 B

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 727 MWe Auxiliary Load : 198 MWe Net Plant Power : 529 MWe Net Plant Efficiency
, HHV : 31

. 8 % Net Plant Heat Rate : 10 , 731 BTU / KWe N 2 to GT Combustor 1 , 739 , 646 W 59

. 0 T 14

. 7 P 13

. 0 H

391 , 366 W 90

. 0 T 125

. 0 P 11

. 5 H

391 , 366 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 7 , 231 W

90

. 0 T 125

. 0 P 11

. 5 H 57 , 819 W 69

. 5 T 16

. 4 P 16

. 2 H

1 , 124 , 993 W 90

. 0 T 56

. 4 P 14

. 2 H

156 , 684 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 486 , 169 W 59

. 0 T 14

. 7 P

199 , 718 W

287

. 0 T 840

. 0 P 231

. 2 H

53 , 341 W 2 , 400

. 0 T

815

. 0 P 685 , 905 W 385

. 0 T 384

. 0 P 87

. 2 H

685 , 887 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 685 , 905 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 595 , 772 W

199

. 0 T 384

. 0 P 39

. 8 H 595 , 772 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 1 , 023 , 911 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 269 , 794 W 403

. 4 T 800

. 0 P 459

. 6 H

Syngas Quench 1 , 401 , 558 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 281 , 677 W 199

. 0 T 384

. 0 P 39

. 8 H



## 376Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 123 Case 2 D4B (95%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 269 , 794 W 403

. 4 T 800

. 0 P 459

. 6 H 1 , 302 , 028 W 93

. 7 T 740

. 0 P 14

. 5 H 97 , 821 W 119

. 0 T 23

. 7 P 145 , 641 W 386

. 5 T 460

. 0 P 634

. 6 H

12 , 156 W 95 , 382 W 450

. 0 T 12

. 3 P 220

. 8 H

2 , 486 W 239

. 1 T 65

. 0 P 441

. 7 H 7 , 231 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 B ( 95 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 B

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 727 MWe Auxiliary Load : 198 MWe Net Plant Power : 529 MWe Net Plant Efficiency
, HHV : 31

. 8 % Net Plant Heat Rate : 10 , 731 BTU / KWe 19

13 20 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

92 , 487 W 120

. 0 T 10

. 6 P 92

. 6 H 1 , 215 , 711 W 94

. 9 T 745

. 0 P 16

. 0 H

9 , 060 W 106

. 5 T 10

. 6 P 31

. 6 H 3 86 , 317 W

100

. 0 T 799

. 5 P

Raw Syngas 15 145 , 641 W 93

. 7 T 725

. 0 P 110

. 4 H

Claus Oxygen Preheater 7 , 231 W 450

. 0 T 124

. 5 P 91

. 9 H 18 Fuel Gas Expander Fuel Gas To GT

16 145 , 641 W

465

. 0 T 720

. 0 P 778

. 4 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam

12 11

COS Hydrolysis

Preheater 1 , 269 , 794 W 413

. 4 T 795

. 0 P 451

. 7 H 283 , 043 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 1 , 552 , 837 W 436

. 5 T 795

. 0 P 598

. 0 H

776

. 2 T 795

. 0 P 582

. 1 H 400

. 0 T 795

. 0 P 408

. 0 H 1 , 552 , 837 W 463

. 4 T 785

. 0 P 405

. 1 H

1 , 552 , 837 W 455

. 5 T 780

. 0 P 401

. 5 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

17

10 14

1 , 057 , 638 W 123

. 6 T 2 , 214

. 7 P



## 377Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 124 Case 2 D4B (95%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 790 , 237 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 441 , 453 W 269

. 9 T 15

. 2 P 147

. 8 H

145 , 641 W

386

. 5 T 460

. 0 P 634

. 6 H 8 , 441 , 453 W 1 , 041

. 2 T

15

. 2 P 358

. 1 H From Gasifier Island Preheating

To Claus LP BFW 1 , 363 , 822 W 991

. 2 T 1 , 814

. 7 P 1 , 474

. 3 H 10 , 276 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 392 , 587 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 759 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 467 , 229 W 482

. 6 T 65

. 0 P 1 , 273

. 4 H

1 , 790 , 237 W 102

. 9 T 120

. 0 P 71

. 2 H 1 , 790 , 237 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 612

. 4 T 65

. 0 P 1 , 337

. 4 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 B

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 B ( 95 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 B

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 727 MWe Auxiliary Load : 198 MWe Net Plant Power : 529 MWe Net Plant Efficiency
, HHV : 31

. 8 % Net Plant Heat Rate : 10 , 731 BTU / KWe 21 22

24

16 23

Flue Gas

HOT WELL CONDENSER Make

- up 310 , 833 W 59

. 0 T 14

. 7 P 27

. 1 H 9 , 037 W 658

. 4 T 501

. 4 P 1 , 333

. 3 H 9 , 775 W 612

. 4 T 65

. 0 P 1 , 337

. 4 H 36 , 583 W

849

. 7 T 280

. 0 P 1 , 447

. 6 H 799 W 991

. 2 T 1 , 814

. 7 P 1 , 474

. 3 H 1 , 338 W 503

. 2 T 65

. 0 P 1 , 283

. 6 H



## 378Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 125 Case 2 D4C (97%) Heat and Mass Balance, GEE Gasifier and ASU

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 C ( 97 %)

GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 C

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 724 MWe Auxiliary Load : 201 MWe Net Plant Power : 523 MWe Net Plant Efficiency
, HHV : 31

. 5 % Net Plant Heat Rate : 10 , 840 BTU / KWe N 2 to GT Combustor 1 , 739 , 159 W 59

. 0 T 14

. 7 P 13

. 0 H

391 , 114 W 90

. 0 T 125

. 0 P 11

. 5 H

391 , 114 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 7 , 372 W

90

. 0 T 125

. 0 P 11

. 5 H 55 , 341 W 70

. 0 T 16

. 4 P 16

. 2 H

1 , 127 , 140 W 90

. 0 T 56

. 4 P 14

. 2 H

156 , 640 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 485 , 856 W 59

. 0 T 14

. 7 P

199 , 590 W

287

. 0 T 840

. 0 P 231

. 2 H

53 , 307 W 2 , 400

. 0 T

815

. 0 P 674 , 610 W 385

. 0 T 384

. 0 P 87

. 2 H

685 , 445 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 674 , 610 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 609 , 170 W

199

. 0 T 384

. 0 P 39

. 8 H 609 , 170 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 1 , 023 , 253 W 1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 268 , 783 W 403

. 4 T 800

. 0 P 459

. 5 H

Syngas Quench 1 , 400 , 657 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7 4 1 , 283 , 780 W 199

. 0 T 384

. 0 P 39

. 8 H



## 379Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 126 Case 2 D4C (97%) Heat and Mass Balance, Syngas Cleanup

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 268 , 783 W 403

. 4 T 800

. 0 P 459

. 5 H 1 , 325 , 649 W 93

. 3 T 740

. 0 P 14

. 0 H 122 , 254 W 119

. 0 T 23

. 7 P 123 , 536 W 386

. 0 T 460

. 0 P 732

. 8 H

12 , 148 W 119 , 963 W 450

. 0 T 12

. 3 P 192

. 7 H

2 , 485 W 239

. 1 T 65

. 0 P 441

. 9 H 7 , 372 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 C ( 97 %)

GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 C

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 724 MWe Auxiliary Load : 201 MWe Net Plant Power : 523 MWe Net Plant Efficiency
, HHV : 31

. 5 % Net Plant Heat Rate : 10 , 840 BTU / KWe 19

13 20 CO 2
Tailgas

Tail Gas Cleanup Unit Tail Gas Compressor

118 , 438 W 120

. 0 T 10

. 6 P 90

. 7 H 1 , 214 , 928 W 94

. 9 T 745

. 0 P 16

. 0 H

9 , 242 W 103

. 4 T 10

. 6 P 28

. 3 H 3 110 , 721 W

100

. 0 T 799

. 5 P

Raw Syngas 15 123 , 536 W 93

. 3 T 725

. 0 P 127

. 9 H

Claus Oxygen Preheater 7 , 372 W 450

. 0 T 124

. 5 P 91

. 9 H 18 Fuel Gas Expander Fuel Gas To GT

16 123 , 536 W

465

. 0 T 720

. 0 P 899

. 8 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam

12 11

COS Hydrolysis

Preheater 1 , 268 , 783 W 413

. 4 T 795

. 0 P 451

. 6 H 283 , 054 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 1 , 551 , 837 W 436

. 5 T 795

. 0 P 598

. 0 H

776

. 2 T 795

. 0 P 582

. 1 H 400

. 0 T 795

. 0 P 408

. 0 H 1 , 551 , 837 W 463

. 4 T 785

. 0 P 405

. 1 H

1 , 551 , 837 W 455

. 5 T 780

. 0 P 401

. 5 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

17

10 14

1 , 078 , 918 W 123

. 6 T 2 , 214

. 7 P



## 380Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 127 Case 2 D4C (97%) Heat and Mass Balance, Power Block

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H
1 , 754 , 867 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 436 , 041 W 270

. 0 T 15

. 2 P 147

. 8 H

123 , 536 W

386

. 0 T 460

. 0 P 732

. 8 H 8 , 436 , 041 W 1 , 040

. 3 T

15

. 2 P 357

. 8 H From Gasifier Island Preheating

To Claus LP BFW 1 , 361 , 570 W 990

. 3 T 1 , 814

. 7 P 1 , 473

. 7 H 10 , 250 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 390 , 284 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 689 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 431 , 875 W 486

. 0 T 65

. 0 P 1 , 275

. 2 H

1 , 754 , 867 W 103

. 0 T 120

. 0 P 71

. 2 H 1 , 754 , 867 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 611

. 5 T 65

. 0 P 1 , 337

. 0 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL

GEE IGCC P LANT C ASE 2 D 4 C

H EAT AND M ATERIAL F LOW D IAGRAM
CO 2 C APTURE S ENSITIVITY S TUDY C ASE 2 D 4 C ( 97 %)

GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

.

CCSA

- HMB

- CS

- 2

- D 4 C

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 724 MWe Auxiliary Load : 201 MWe Net Plant Power : 523 MWe Net Plant Efficiency
, HHV : 31

. 5 % Net Plant Heat Rate : 10 , 840 BTU / KWe 21 22

24

16 23

Flue Gas

HOT WELL CONDENSER Make

- up 310 , 812 W 59

. 0 T 14

. 7 P 27

. 1 H 9 , 041 W 657

. 6 T 501

. 4 P 1 , 332

. 8 H 9 , 780 W 611

. 5 T 65

. 0 P 1 , 337

. 0 H 38 , 262 W

848

. 8 T 280

. 0 P 1 , 447

. 1 H 800 W 990

. 3 T 1 , 814

. 7 P 1 , 473

. 7 H 1 , 339 W 502

. 5 T 65

. 0 P 1 , 283

. 3 H



## 381Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

382Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 128 Case 2 D4A (90%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,994 (5,682) 5.0 (4.7) 0 (0) 5,999 (5,686) ASU Air 0 (0) 23.9 (22.6) 0 (0) 24 (23) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 82.8 (78.5) 0 (0) 83 (78)
Totals 5,994 (5,682) 207.9 (197.0) 0 (0) 6,202 (5,879) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.6 (1.5) 0 (0) 2 (2) Slag 92 (88) 37.8 (35.9) 0 (0) 130 (123) Sulfur 51 (49) 0.6 (0.6) 0 (0) 52 (49) CO 2 

### 0 (0)

- 74.1 (

- 70.3) 0 (0)

- 74 (

- 70) Gasifier Heat Loss 0 (0) 44.6 (42.3) 0 (0) 45 (42) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)
HRSG Flue Gas 0 (0) 1,318 (1,249) 0 (0) 1,318 (1,249) Cooling Tower* 0 (0) 2,177 (2,063) 0 (0) 2,177 (2,063) Process Losses* * 0 (0) 534 (506) 0 (0) 534 (506)
Net Power 0 (0) 0.0 (0.0) 1,956 (1,854) 1,956 (1,854)
Totals 144 (136) 4,103 (3,889) 1,956 (1,854) 6,202 (5,879) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extractio n air cooler. ** Calculated by difference to close the energy balance.



## 383Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 129 Case 2 D4B (95%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,984 (5,672) 5.0 (4.7) 0 (0) 5,989 (5,676) ASU Air 0 (0) 23.9 (22.6) 0 (0) 24 (23) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 81.7 (77.4) 0 (0) 82 (77)
Totals 5,984 (5,672) 206.7 (195.9) 0 (0) 6,191 (5,868) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 1.0 (0.9) 0 (0) 1 (1) Slag 92 (87) 37.8 (35.8) 0 (0) 130 (123) Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49) CO 2 

### 0 (0)

- 78.1 (

- 74.0) 0 (0)

- 78 (

- 74) Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)
HRSG Flue Gas 0 (0) 1,316 (1,247) 0 (0) 1,316 (1,247) Cooling Tower* 0 (0) 2,121 (2,010) 0 (0) 2,121 (2,010) Process Losses* * 0 (0) 639 (605) 0 (0) 639 (605)
Net Power 0 (0) 0.0 (0.0) 1,903 (1,803) 1,903 (1,803)
Totals 143 (136) 4,145 (3,928) 1,903 (1,803) 6,191 (5,868) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 384Carbon Dioxide Capture Sensitivity Analysis



### E xhibit 4
- 130 Case 2 D4C (97%) Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr)
Coal 5,980 (5,668) 5.0 (4.7) 0 (0) 5,985 (5,673) ASU Air 0 (0) 23.8 (22.6) 0 (0) 24 (23) GT Air 0 (0) 96.2 (91.2) 0 (0) 96 (91) Water 0 (0) 81.2 (77.0) 0 (0) 81 (77)
Totals 5,980 (5,668) 206.2 (195.5) 0 (0) 6,186 (5,863) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0 (0) 0.9 (0.9) 0 (0) 1 (1) Slag 92 (87) 37.8 (35.8) 0 (0) 130 (123) Sulfur 51 (48) 0.6 (0.6) 0 (0) 52 (49) CO 2 

### 0 (0)

- 79.7 (

- 75.5) 0 (0)

- 80 (

- 76) Gasifier Heat Loss 0 (0) 44.5 (42.2) 0 (0) 45 (42) Combustion Turbine Heat Loss 0 (0) 63 (60) 0 (0) 63 (60)
HRSG Flue Gas 0 (0) 1,315 (1,247) 0 (0) 1,315 (1,247) Cooling Tower* 0 (0) 2,097 (1,988) 0 (0) 2,097 (1,988) Process Losses* * 0 (0) 681 (645) 0 (0) 681 (645)
Net Power 0 (0) 0.0 (0.0) 1,882 (1,784) 1,882 (1,784)
Totals 143 (136) 4,161 (3,944) 1,882 (1,784) 6,186 (5,863) Note: Italicized numbers are estimated Reference conditions are 0 °C (32.02 °F) & 0.6 kPa (0.089 psia) * Includes Condenser, Cooling Tower Blowdown, and the following Non

- Condenser Cooling Tower Loads: ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas coole r (low level heat rejection), and extraction air cooler. ** Calculated by difference to close the energy balance.



## 385Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 131 Case 2 D4A Energy Balance Sankey Diagram

Exhibit 4
- 132 Case 2 D4B Energy Balance Sankey Diagram



## 386Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 133 Case 2 D4C Energy Balance Sankey Diagram



## 387Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

388Carbon Dioxide Capture Sensitivity Analysis



## 4.3.4.2 Major Equipment List for Case 2 D4 Major equipment items for Case 2 D4 (two WGS reactors without bypass) are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cos t estimates. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contin gency for heads on pumps and fans.

ACCOUNT 1 COAL HANDLING
Equipment No. Description Type Design Conditions Opr Qty. (Spares) D 4 A D 4 B D 4 C
1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)
2 Feeder Belt 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 572 tonne/hr (630 tph) 2 (0) 3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 4 Transfer Tower No. 1 Enclosed N/A N/A N/A 1 (0) 5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0)
6 As

- Received Coal Sampling System Two

- stage N/A N/A N/A 1 (0)

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr (1,250 tph) 1 (0) 8 Reclaim Hopper N/A 45 tonne (50 ton) 45 tonne (50 ton) 45 tonne (50 ton) 2 (1) 9 Feeder Vibratory 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 181 tonne/hr (200 tph) 2 (1) 10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0) 11 Crusher Tower N/A N/A N/A N/A 1 (0)
12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 181 tonne (200 ton) 181 tonne (200 ton) 2 (0)

13 Crusher Impactor reduction 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 8 cm x 0

- 3 cm x 0 (3" x 0

- 1

- 1/4" x 0) 2 (0)

14 As

- Fired Coal Sampling System Swing hammer N/A N/A N/A 1 (1)
15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0) 16 Transfer Tower No. 2 Enclosed N/A N/A N/A 1 (0) 17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 363 tonne/hr (400 tph) 1 (0)
18 Coal Silo w/ Vent Filter and Slide Gates Field erected 816 tonne (900 ton) 816 tonne (900 ton) 816 tonne (900 ton) 3 (0)



## ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C 1 Feeder Vibratory 82 tonne/h (90 tph) 82 tonne/h (90 tph) 82 tonne/h (90 tph) 3 (0) 2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 245 tonne/h (270 tph) 245 tonne/h (270 tph) 1 (0) 3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 481 tonne (530 ton) 481 tonne (530 ton) 1 (0) 4 Weigh Feeder Belt 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0) 5 Rod Mill Rotary 118 tonne/h (130 tph) 118 tonne/h (130 tph) 118 tonne/h (130 tph) 2 (0)
6 Slurry Water Storage Tank with Agitator Field erected 299,921 liters (79,230 gal) 299,391 liters (79,090 gal) 299,201 liters (79,040 gal) 2 (0)
7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 833 lpm (220 gpm) 833 lpm (220 gpm) 2 (1) 8 Trommel Screen Coarse 172 tonne/h (190 tph) 172 tonne/h (190 tph) 172 tonne/h (190 tph) 2 (0)



## 389Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C
9 Rod Mill Discharge Tank with Agitator Field erected 392,323 liters (103,640 gal) 391,642 liters (103,460 gal) 391,377 liters (103,390 gal) 2 (0)
10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)
11 Slurry Storage Tank with Agitator Field erected 1,176,894 liters (310,900 gal) 1,175,001 liters (310,400 gal) 1,174,244 liters (310,200 gal) 2 (0)
12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 6,435 lpm (1,700 gpm) 2 (2)
13 Slurry Product Pumps Positive displacement 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 3,407 lpm (900 gpm) 2 (2)



## ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C
1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,093,984 liters (289,000 gal) 1,093,984 liters (289,000 gal) 1,093,984 liters (289,000 gal) 2 (0)

2 Condensate Pumps Vertical canned 7,874 lpm @ 91 m H 2 

### O (2,080 gpm @ 300 ft H 2 

### O) 7,495 lpm @ 91 m H 2 

### O (1,980 gpm @ 300 ft H 2 

### O) 7,344 lpm @ 91 m H 2 

### O (1,940 gpm @ 300 ft H 2 

### O) 2 (1)
3 Deaerator (integral w/ HRSG) Horizontal spray type 546,579 kg/hr (1,205,000 lb/hr) 549,754 kg/hr (1,212,000 lb/hr) 551,568 kg/hr (1,216,000 lb/hr) 2 (0)
4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 8,025 lpm @ 27 m H 2 

### O (2,120 gpm @ 90 ft H 2 

### O) 8,063 lpm @ 27 m H 2 

### O (2,130 gpm @ 90 ft H 2 

### O) 8,063 lpm @ 27 m H 2 

### O (2,130 gpm @ 90 ft H 2 

### O) 2 (1)

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,057 lpm @ 1,859 m H 2 

### O (1,600 gpm @ 6,100 ft H 2 

### O) HP water: 6,019 lpm @ 1,859 m H 2 

### O (1,590 gpm @ 6,100 ft H 2 

### O) HP water: 6,019 lpm @ 1,859 m H 2 

### O (1,590 gpm @ 6,100 ft H 2 

### O) 2 (1)

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,703 lpm @ 223 m H 2 

### O (450 gpm @ 730 ft H 2 

### O) IP water: 1,741 lpm @ 223 m H 2 

### O (460 gpm @ 730 ft H 2 

### O) IP water: 1,703 lpm @ 223 m H 2 

### O (450 gpm @ 730 ft H 2 

### O) 2 (1)

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 (0)

8 Service Air Compressors Flooded Screw 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 (1)
9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 28 m 3 

### /min (1,000 scfm) 2 (1)
10 Closed Cylce Cooling Heat Exchangers Plate and frame 362 GJ/hr (343.5076381 MMBtu/hr) each 375 GJ/hr (355.39736925 MMBtu/hr) each 380 GJ/hr (360.46720325 MMBtu/hr) each 2 (0)

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 130,218 lpm @ 21 m H 2 

### O (34,400 gpm @ 70 ft H 2 

### O) 134,382 lpm @ 21 m H 2 

### O (35,500 gpm @ 70 ft H 2 

### O) 136,275 lpm @ 21 m H 2 

### O (36,000 gpm @ 70 ft H 2 

### O) 2 (1)

12 Engine

- Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 3,785 lpm @ 107 m H 2 

### O (1,000 gpm @ 350 ft H 2 

### O) 1 (1)

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 2,650 lpm @ 76 m H 2 

### O (700 gpm @ 250 ft H 2 

### O) 1 (1)

14 Raw Water Pumps Stainless steel, single suction 5,716 lpm @ 18 m H 2 

### O (1,510 gpm @ 60 ft H 2 

### O) 5,640 lpm @ 18 m H 2 

### O (1,490 gpm @ 60 ft H 2 

### O) 5,602 lpm @ 18 m H 2 

### O (1,480 gpm @ 60 ft H 2 

### O) 2 (1)

15 Ground Water Pumps Stainless steel, single suction 2,839 lpm @ 268 m H 2 

### O (750 gpm @ 880 ft H 2 

### O) 2,801 lpm @ 268 m H 2 

### O (740 gpm @ 880 ft H 2 

### O) 2,801 lpm @ 268 m H 2 

### O (740 gpm @ 880 ft H 2 

### O) 3 (1)

16 Filtered Water Pumps Stainless steel, single suction 3,369 lpm @ 49 m H 2 

### O (890 gpm @ 160 ft H 2 

### O) 3,331 lpm @ 49 m H 2 

### O (880 gpm @ 160 ft H 2 

### O) 3,331 lpm @ 49 m H 2 

### O (880 gpm @ 160 ft H 2 

### O) 2 (1)
17 Filtered Water Tank Vertical, cylindrical 1,608,800 liter (425,000 gal) 1,605,015 liter (424,000 gal) 1,601,229 liter (423,000 gal) 2 (0)
18 Makeup Water Demineralizer Anion, cation, and mixed bed 1,476 lpm (390 gpm) 1,476 lpm (390 gpm) 1,476 lpm (390 gpm) 2 (0)
19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 10 years, 24

- hour storm 1 (0)



## 390Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C
1 Gasifier Pressurized slurry

feed, entrained bed 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2 (0)

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench chamber 255,826 kg/hr (564,000 lb/hr) 255,373 kg/hr (563,000 lb/hr) 255,373 kg/hr (563,000 lb/hr) 2 (0)

3 Synthesis Gas Cyclone High efficiency 350,173 kg/hr (772,000 lb/hr) Design efficiency 90% 349,720 kg/hr (771,000 lb/hr) Design efficiency 90% 349,720 kg/hr (771,000 lb/hr) Design efficiency 90% 2 (0)

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters metallic filters metallic filters 2 (0)

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 350,173 kg/hr (772,000 lb/hr) 349,720 kg/hr (771,000 lb/hr) 349,720 kg/hr (771,000 lb/hr) 2 (0)

6 Raw Gas Coolers Shell and tube with condensate drain 388,275 kg/hr (856,000 lb/hr) 387,368 kg/hr (854,000 lb/hr) 387,368 kg/hr (854,000 lb/hr) 8 (0)

7 Raw Gas Knockout Drum Vertical with mist eliminator 304,360 kg/hr, 35°C, 5.2 MPa (671,000 lb/hr, 95°F, 750 psia) 303,907 kg/hr, 35°C, 5.2 MPa (670,000 lb/hr, 95°F, 750 psia) 303,453 kg/hr, 35°C, 5.2 MPa (669,000 lb/hr, 95°F, 750 psia) 2 (0)

8 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 350,173 kg/hr (772,000 lb/hr) syngas 349,720 kg/hr (771,000 lb/hr) syngas 349,720 kg/hr (771,000 lb/hr) syngas 2 (0)

9 ASU Main Air Compressor Centrifugal, multi

stage 5,947 m 3 

### /min @ 1.3 MPa (210,000 scfm @ 190 psia) 5,947 m 3 

### /min @ 1.3 MPa (210,000 scfm @ 190 psia) 5,947 m 3 

### /min @ 1.3 MPa (210,000 scfm @ 190 psia) 2 (0)

10 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 (0)

11 Oxygen Compressor Centrifugal, multi

stage 1,189 m 3 

### /min (42,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 1,189 m 3 

### /min (42,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 1,189 m 3 

### /min (42,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 6.5 MPa (940 psia) 2 (0)

12 Primary Nitrogen Compressor Centrifugal, multi

stage 3,794 m 3 

### /min (134,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,936 m 3 

### /min (139,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,964 m 3 

### /min (140,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 (0)

13 Secondary Nitrogen Compressor Centrifugal, single

stage 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 (0)

14 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

stage 1,982 m 3 

### /min (70,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2,095 m 3 

### /min (74,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2,152 m 3 

### /min (76,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 3.2 MPa (470 psia) 2 (0)



## ACCOUNT 5A SYNGAS CLEANUP
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Mercury Adsorber Sulfated carbon bed 303,907 kg/hr (670,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 303,453 kg/hr (669,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 303,000 kg/hr (668,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 (0)

2 Sulfur Plant Claus type 146 tonne/day (161 tpd) 146 tonne/day (160 tpd) 146 tonne/day (160 tpd) 1 (0)

3 Water Gas Shift Reactors Fixed bed, catalytic 388,275 kg/hr (856,000 lb/hr) 227°C (440°F) 5.4 MPa (790 psia) 387,368 kg/hr (854,000 lb/hr) 227°C (440°F) 5.4 MPa (790 psia) 387,368 kg/hr (854,000 lb/hr) 227°C (440°F) 5.4 MPa (790 psia) 4 (0)



## 391Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) Exchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 (0)

5 Acid Gas Removal Plant Two

- stage Selexol 310,711 kg/hr (685,000 lb/hr) 35°C (95°F) 5.1 MPa (740 psia) 324,772 kg/hr (716,000 lb/hr) 34°C (94°F) 5.1 MPa (740 psia) 330,669 kg/hr (729,000 lb/hr) 34°C (93°F) 5.1 MPa (740 psia) 2 (0)

6 Hydrogenation Reactor Fixed bed, catalytic 18,095 kg/hr (39,892 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 47,591 kg/hr (104,920 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 59,856 kg/hr (131,960 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 (0)

7 Tail Gas Recycle Compressor Centrifugal 13,779 kg/hr (30,378 lb/hr) 43,068 kg/hr (94,949 lb/hr) 55,244 kg/hr (121,793 lb/hr) 1 (0)



## ACCOUNT 5B CO 2 

## COMPRESSION
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 CO 2 

### Compressor Integrally geared, multi

stage centrifugal 1,133 m 3 

### /min @ 15.3 MPa (40,000 scfm @ 2,215 psia) 1,189 m 3 

### /min @ 15.3 MPa (42,000 scfm @ 2,215 psia) 1,212 m 3 

### /min @ 15.3 MPa (42,800 scfm @ 2,215 psia) 4 (0)



## ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C 1 Gas Turbine Advanced F class 230 MW 230 MW 230 MW 2 (0)
2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 (0)

3 Syngas Expansion Turbine/Generator Turbo Expander 49,578 kg/h (109,300 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 36,333 kg/h (80,100 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 30,799 kg/h (67,900 lb/h) 5.0 MPa (720 psia) Inlet 3.2 MPa (460 psia) Outlet 2 (0)



## ACCOUNT 7 HRSG, DUCTING , AND STACK
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C
1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 76 m (250 ft) high x 8.5 m (28 ft) diameter 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 (0)

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 341,834 kg/hr, 12.4 MPa/534°C (753,614

lb/hr, 1,800 psig/994°F) Reheat steam

- 336,639 kg/hr, 3.1 MPa/534°C (742,162 lb/hr, 452 psig/994°F) Main steam

- 340,240 kg/hr, 12.4 MPa/533°C (750,102

lb/hr, 1,800 psig/991°F) Reheat steam

- 335,536 kg/hr, 3.1 MPa/533°C (739,731 lb/hr, 452 psig/991°F) Main steam

- 339,6 79 kg/hr, 12.4 MPa/532°C (748,864

lb/hr, 1,800 psig/990°F) Reheat steam

- 334,930 kg/hr, 3.1 MPa/532°C (738,395 lb/hr, 452 psig/990°F) 2 (0)



## 392Carbon Dioxide Capture Sensitivity Analysis



## ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 Steam Turbine Commercially available advanced steam turbine 278 MW 12.4 MPa/534°C/534°C (1,800 psig/ 994°F/994°F) 270 MW 12.4 MPa/533°C/533°C (1,800 psig/ 991°F/991°F) 267 MW 12.4 MPa/532°C/532°C (1,800 psig/ 990°F/990°F) 1 (0)

2 Steam Turbine Generator Hydrogen cooled, static excitation 310 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 300 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 300 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 50% steam flow @ design steam conditions 2 (0)

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,667 GJ/hr (1,580 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,583 GJ/hr (1,500 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1,540 GJ/hr (1,460 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 (0)



## ACCOUNT 9 COOLING WATER SYSTEM
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C
1 Circulating Water Pumps Vertical, wet pit 461,820 lpm @ 30 m (122,000 gpm @ 100 ft) 458,035 lpm @ 30 m (121,000 gpm @ 100 ft) 454,249 lpm @ 30 m (120,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,585 GJ/hr (2,450 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,543 GJ/hr (2,410 MMBtu/hr) heat duty 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT / 2,532 GJ/hr (2,400 MMBtu/hr) heat duty 1 (0)



## ACCOUNT 10 SLAG RECOVERY AND HANDLING
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C 1 Slag Quench Tank Water bath 253,623 liters (67,000 gal) 253,623 liters (67,000 gal) 253,623 liters (67,000 gal) 2 (0) 2 Slag Crusher Roll 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0) 3 Slag Depressurizer Lock Hopper 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0) 4 Slag Receiving Tank Horizontal, weir 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 151,416 liters (40,000 gal) 2 (0)
5 Black Water Overflow Tank Shop fabricated 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

6 Slag Conveyor Drag chain 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

7 Slag Separation Screen Vibrating 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

8 Coarse Slag Conveyor Belt/bucket 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 14 tonne/hr (15 tph) 2 (0)

9 Fine Ash Settling Tank Vertical, gravity 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 215,768 liters (57,000 gal) 2 (0)

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 2 (2)

11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 68,137 liters (18,000 gal) 2 (0)

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 227 lpm @ 564 m H 2 

### O (60 gpm @ 1,850 ft H 2 

### O) 2 (2)



## 393Carbon Dioxide Capture Sensitivity Analysis



### Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C 13 Slag Storage Bin Vertical, field erected 998 tonne (1,100 tons) 998 tonne (1,100 tons) 998 tonne (1,100 tons) 2 (0) 14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 109 tonne/hr (120 tph) 1 (0)



## ACCOUNT 11 ACCESSORY ELECTRIC PLANT
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C
1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 2 (0)

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 310 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 300 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 300 MVA, 3

- ph, 60 Hz 1 (0)

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 80 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 82 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 82 MVA, 3

- ph, 60 Hz 2 (0)

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 48 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 53 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 55 MVA, 3

- ph, 60 Hz 1 (1)

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 8 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 8 MVA, 3

- ph, 60 Hz 1 (1)

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 2 (0)

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz 1 (0)

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60 Hz 1 (1)

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz 1 (1)

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

- ph, 60 Hz 1 (0)



## ACCOUNT 12 INSTRUMENTATION AND CONTROL
Equipment No. Description Type Design Condition Opr Qty. (Spares) D 4 A D 4 B D 4 C

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/printers Operator stations/printers and engineering stations/ printers 1 (0)

2 DCS

- Processor Microprocessor with redundant input/output N/A N/A N/A 1 (0)

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare Fully redundant, 25% spare Fully redundant, 25% spare 1 (0)



## 394Carbon Dioxide Capture Sensitivity Analysis



# 4.3.5 Economic Analysis for the GEE IGCC Cases
The capital and operating costs for Case 2 Designs 1

- 4 are presented in Section 4.3.6 . A cost and performance summary table ( Exhibit 4

- 162 ) for the GEE IGCC cases is show n in Section 4.3.7

.


# 4.3.6 Capital and Operating Cost Results The capital and operating costs for Case 2 Designs 1

- 4 are shown in E xhibit 4

- 134 through Exhibit 4

- 161

. The capital costs for each case include the total plant cost (TPC), the owner’s costs, the total overnight cost (TOC), and the total as

- spent capital (TASC) cost. The c apital and operating cost estimating methodology is explained in Section 2.7

.

395Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 134 Case 2 D1A (0%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: 1-Jun-07 Project: CO2 Capture Sensitivity Analysis Prepared: 14-Jun-10

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) x $1, 000 Plant Size: 622.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,653 $0 $1,785 0 5,439 9.0% $487 0% 0 20.0% $1,185 7,111 11 1.2 Coal Stackout & Reclaim $4,721 $0 $1,144 0 5,865 8.8% $514 0% 0 20.0% $1,276 7,655 12 1.3 Coal Conveyors & Yd Crus $4,389 $0 $1,132 0 5,522 8.8% $485 0% 0 20.0% $1,201 7,207 12 1.4 Other Coal Handling $1,148 $0 $262 0 1,410 8.8% $123 0% 0 20.0% $307 1,840 3 1.5 Sorbent Receive & Unload $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0 1.7 Sorbent Conveyors $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0 1.8 Other Sorbent Handling $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,585 $6,464 0 9,049 9.6% $867 0% 0 20.0% $1,983 11,900 19 SUBTOTAL 1. $13,912 $2,585 $10,788 $0 $27,285 $2,477 $0 $5,952 $35,714 $57 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/ 2.3 $0 w/ 2.3 0 0 0.0% $0 0% 0 0.0% $0 0 0 2.2 Prepared Coal Storage & Feed $1,558 $373 $244 0 2,175 8.6% $186 0% 0 20.0% $472 2,833 5 2.3 Slurry Prep & Feed $21,299 $0 $9,398 0 30,697 9.1% $2,789 5% $1,535 20.0% $7,004 42,025 68 2.4 Misc. Coal Prep & Feed $857 $623 $1,869 0 3,349 9.2% $308 0% 0 20.0% $731 4,388 7 2.5 Sorbent Prep Equipment $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0 2.6 Sorbent Storage & Feed $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0 2.7 Sorbent Injection System $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0 2.8 Booster Air Supply System $0 $0 $0 0 0 0.0% $0 0% 0 0.0% $0 0 0 2.9 Coal & Sorbent Feed Foundation $0 $3,330 $2,734 0 6,063 9.3% $562 0% 0 20.0% $1,325 7,950 13 SUBTOTAL 2. $23,713 $4,326 $14,245 $0 $42,284 $3,844 $1,535 $9,533 $57,195 $92 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,896 $4,974 $2,626 0 10,496 9.3% $972 0% 0 20.0% 2,294 13,762 22 3.2 Water Makeup & Pretreating $620 $65 $347 0 1,031 9.5% $98 0% 0 30.0% 339 1,469 2 3.3 Other Feedwater Subsystems $1,585 $536 $482 0 2,602 9.0% $234 0% 0 20.0% 567 3,403 5 3.4 Service Water Systems $355 $731 $2,536 0 3,621 9.8% $353 0% 0 30.0% 1,192 5,167 8 3.5 Other Boiler Plant Systems $1,904 $738 $1,829 0 4,471 9.5% $424 0% 0 20.0% 979 5,874 9 3.6 FO Supply Sys & Nat Gas $315 $596 $556 0 1,467 9.6% $141 0% 0 20.0% 322 1,930 3 3.7 Waste Treatment Equipment $867 $0 $529 0 1,395 9.7% $136 0% 0 30.0% 459 1,991 3 3.8 Misc. Power Plant Equipment $1,080 $145 $554 0 1,779 9.7% $172 0% 0 30.0% 585 2,536 4 SUBTOTAL 3. $9,622 $7,783 $9,458 $0 $26,863 $2,531 $0 $6,737 $36,131 $58 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $111,116 $0 $60,871 0 171,987 9.2% $15,755 13.9% $23,878 15.3% $32,445 244,065 392 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/4.1 0 0 0.0% $0 0% 0 0.0% $0 0 0 4.3 ASU/Oxidant Compression $160,703 $0 w/equip. 0 160,703 9.7% $15,577 0% 0 10.0% $17,628 193,908 312 4.4 Scrubber & Low Temperature Cooling $5,873 $4,781 $4,975 0 15,629 9.6% $1,501 0% 0 20.0% $3,426 20,556 33 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 0 0 0.0% $0 0% 0 0.0% $0 0 0 4.6 Other Gasification Equipment $1,791 $0 $1,681 0 3,472 12.0% $417 0% 0 24.4% $948 4,837 8 4.7 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 0 0 0.0% $0 0% 0 0.0% $0 0 0 4.8 Gasification Foundations $0 $6,486 $5,414 0 11,900 9.3% $1,103 0% 0 25.0% $3,251 16,253 26 SUBTOTAL 4. $279,483 $11,266 $72,942 $0 $363,691 $34,352 $23,878 $57,697 $479,618 $771 Project Cont. TOTAL PLANT COST Labor Bare Erected Eng'g CM H.O. & Process Cont. Acct No. Item/Description Equipment Cost Material Cost



## 396Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 134 Case 2 D1A (0%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: 1-Jun-07 Project: CO2 Capture Sensitivity Analysis Prepared: 14-Jun-10

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) x $1, 000 Plant Size: 622.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Single Stage Selexol $41,961 $0 $35,605 0 77,565 9.7% $7,501 0% 0 20.0% 17,013 102,080 164 5A.2 Elemental Sulfur Plant $10,055 $2,004 $12,972 0 25,031 9.7% $2,431 0% 0 20.0% 5,493 32,955 53 5A.3 Mercury Removal $1,057 $0 $804 0 1,862 9.7% $180 5% 93 20.0% 427 2,561 4 5A.4 COS Hydrolysis $3,575 $0 $4,668 0 8,243 9.7% $801 0% 0 20.0% 1,809 10,853 17 5A.5 Particulate Removal $0 $0 $0 0 0 0.0% $0 0% 0 20.0% 0 0 0 5A.6 Blowback Gas Systems $1,310 $0 $248 0 1,558 12.2% $190 0% 0 20.0% 350 2,098 3 5A.7 Fuel Gas Piping $0 $688 $482 0 1,170 9.3% $108 0% 0 20.0% 256 1,534 2 5A.9 HGCU Foundations $0 $1,108 $714 0 1,822 9.2% $167 0% 0 30.0% 597 2,586 4

5.9 Open 0 0 0 0 0 0.0% 0 0% 0 20.0% 0 0 0 SUBTOTAL 5A. $57,957 $3,800 $55,494 $0 $117,251 $11,380 $93 $25,944 $154,668 $249 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System 0 0 0 0 0 10% 0 0% 0 0.0% 0 0 0 5B.2 CO2 Compression & Drying 0 0 0 0 0 10% 0 0% 0 20.0% 0 0 0 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 0 92,021 9.5% $8,724 5% 4,601 10.0% 10,535 115,881 186 6.2 Syngas Expander $5,928 $0 $819 0 6,747 9.5% $641 0% 0 15.0% 1,108 8,496 14 6.3 Compressed Air Piping $0 $0 $0 0 0 0.0% $0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 0 1,868 9.4% $175 0% 0 30.0% 613 2,656 4 SUBTOTAL 6. $91,679 $887 $8,070 $0 $100,636 $9,540 $4,601 $12,256 $127,033 $204 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,357 $0 $5,027 0 40,384 9.5% $3,840 0% 0 10.0% 4,422 48,646 78 7.2 Open $0 $0 $0 0 0 0.0% $0 0% 0 0.0% 0 0 0 7.3 Ductwork $0 $1,706 $1,217 0 2,923 8.8% $256 0% 0 20.0% 636 3,816 6 7.4 Stack $3,329 $0 $1,250 0 4,579 9.6% $439 0% 0 10.0% 502 5,519 9 7.5 HRSG,Duct & Stack Foundations $0 $667 $640 0 1,307 9.3% $122 0% 0 30.0% 429 1,858 3 SUBTOTAL 7. $38,685 $2,373 $8,136 $0 $49,194 $4,657 $0 $5,989 $59,839 $96 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,111 $0 $4,994 0 34,104 9.6% $3,272 0% 0 10.0% 3,738 41,114 66 8.2 Turbine Plant Auxiliaries $202 $0 $463 0 665 9.8% $65 0% 0 10.0% 73 803 1 8.3 Condenser & Auxiliaries $5,053 $0 $1,484 0 6,537 9.6% $625 0% 0 10.0% 716 7,878 13 8.4 Steam Piping $5,117 $0 $3,600 0 8,717 8.6% $749 0% 0 25.0% 2,367 11,833 19 8.5 TG Foundations $0 $1,001 $1,693 0 2,694 9.5% $255 0% 0 30.0% 885 3,835 6 SUBTOTAL 8. $39,483 $1,001 $12,233 $0 $52,718 $4,967 $0 $7,778 $65,462 $105 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,699 $0 $1,219 0 7,918 9.5% $754 0% 0 15.0% 1,301 9,973 16 9.2 Circulating Water Pumps $1,737 $0 $122 0 1,859 8.4% $157 0% 0 15.0% 302 2,318 4 9.3 Circ. Water System Auxiliaries $147 $0 $21 0 168 9.5% $16 0% 0 15.0% 28 211 0 9.4 Circ. Water Piping $0 $6,124 $1,588 0 7,712 9.0% $697 0% 0 20.0% 1,682 10,090 16 9.5 Make-up Water System $343 $0 $490 0 833 9.6% $80 0% 0 20.0% 183 1,096 2 9.6 Component Cooling Water System $723 $865 $615 0 2,203 9.4% $206 0% 0 20.0% 482 2,891 5 9.9 Circ. Water System Foundations $0 $2,248 $3,822 0 6,071 9.5% $576 0% 0 30.0% 1,994 8,640 14 SUBTOTAL 9. $9,649 $9,237 $7,877 $0 $26,763 $2,486 $0 $5,971 $35,220 $57 * Project Cont. TOTAL PLANT COST Labor Bare Erected Eng'g CM H.O. & Process Cont. Acct No. Item/Description Equipment Cost Material Cost



## 397Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 134 Case 2 D1A (0%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: 1-Jun-07 Project: CO2 Capture Sensitivity Analysis Prepared: 14-Jun-10

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) x $1, 000 Plant Size: 622.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,822 $6,519 $13,243 0 31,584 9.7% $3,048 0% 0 10.0% 3,463 38,095 61 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 0 0 0.0% $0 0% 0 0.0% 0 0 0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 0 0 0.0% $0 0% 0 0.0% 0 0 0 10.4 High Temperature Ash Piping $0 $0 $0 0 0 0.0% $0 0% 0 0.0% 0 0 0 10.5 Other Ash Recovery Equipment $0 $0 $0 0 0 0.0% $0 0% 0 0.0% 0 0 0 10.6 Ash Storage Silos $575 $0 $626 0 1,201 9.7% $116 0% 0 15.0% 198 1,515 2 10.7 Ash Transport & Feed Equipment $771 $0 $186 0 957 9.3% $89 0% 0 15.0% 157 1,204 2 10.8 Misc. Ash Handling Equipment $1,191 $1,460 $436 0 3,087 9.5% $294 0% 0 15.0% 507 3,888 6 10.9 Ash/Spent Sorbent Foundation $0 $51 $64 0 115 9.4% $11 0% 0 30.0% 38 163 0 SUBTOTAL 10. $14,359 $8,029 $14,555 $0 $36,943 $3,559 $0 $4,363 $44,864 $72 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $958 $0 $947 0 1,905 9.5% $182 0% 0 10.0% 209 2,296 4 11.2 Station Service Equipment $3,920 $0 $353 0 4,273 9.2% $394 0% 0 10.0% 467 5,134 8 11.3 Switchgear & Motor Control $7,247 $0 $1,318 0 8,565 9.3% $794 0% 0 15.0% 1,404 10,763 17 11.4 Conduit & Cable Tray $0 $3,366 $11,106 0 14,472 9.7% $1,400 0% 0 25.0% 3,968 19,840 32 11.5 Wire & Cable $0 $6,432 $4,226 0 10,658 7.3% $774 0% 0 25.0% 2,858 14,291 23 11.6 Protective Equipment $0 $686 $2,496 0 3,182 9.8% $311 0% 0 15.0% 524 4,017 6 11.7 Standby Equipment $236 $0 $230 0 466 9.5% $44 0% 0 15.0% 77 587 1 11.8 Main Power Transformers $15,862 $0 $146 0 16,008 7.6% $1,211 0% 0 15.0% 2,583 19,801 32 11.9 Electrical Foundations $0 $158 $416 0 574 9.6% $55 0% 0 30.0% 189 818 1 SUBTOTAL 11. $28,222 $10,643 $21,238 $0 $60,103 $5,165 $0 $12,277 $77,546 $125 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 0 0 0.0% $0 0% 0 0.0% 0 0 0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 0 0 0.0% $0 0% 0 0.0% 0 0 0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 0 0 0.0% $0 0% 0 0.0% 0 0 0 12.4 Other Major Component Control $1,012 $0 $676 0 1,687 9.5% $160 5% 84 15.0% 290 2,221 4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 0 0 0.0% $0 0% 0 0.0% 0 0 0 12.6 Control Boards, Panels & Racks $233 $0 $149 0 382 9.5% $36 5% 19 20.0% 87 524 1 12.7 Computer Accessories $5,397 $0 $173 0 5,570 9.2% $511 5% 278 10.0% 636 6,995 11 12.8 Instrument Wiring & Tubing $0 $1,885 $3,854 0 5,739 8.5% $487 5% 287 25.0% 1,628 8,141 13 12.9 Other I & C Equipment $3,608 $0 $1,752 0 5,359 9.4% $504 5% 268 15.0% 920 7,051 11 SUBTOTAL 12. $10,249 $1,885 $6,603 $0 $18,737 $1,698 $937 $3,561 $24,933 $40 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $105 $2,246 0 2,351 9.9% $233 0% 0 30.0% 775 3,360 5 13.2 Site Improvements $0 $1,869 $2,483 0 4,352 9.9% $429 0% 0 30.0% 1,435 6,216 10 13.3 Site Facilities $3,349 $0 $3,534 0 6,883 9.9% $679 0% 0 30.0% 2,268 9,830 16 SUBTOTAL 13. $3,349 $1,974 $8,263 $0 $13,586 $1,341 $0 $4,478 $19,405 $31 Project Cont. TOTAL PLANT COST Labor Bare Erected Eng'g CM H.O. & Process Cont. Acct No. Item/Description Equipment Cost Material Cost



## 398Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 134 Case 2 D1A (0%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: 1-Jun-07 Project: CO2 Capture Sensitivity Analysis Prepared: 27-May-11

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) x $1, 000 Plant Size: 622.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 0 414 8.8% $36 0% 0 20.0% 90 541 1 14.2 Steam Turbine Building $0 $2,446 $3,484 0 5,930 9.2% $546 0% 0 15.0% 971 7,447 12 14.3 Administration Building $0 $845 $613 0 1,459 8.9% $130 0% 0 15.0% 238 1,827 3 14.4 Circulation Water Pumphouse $0 $167 $88 0 255 8.8% $22 0% 0 15.0% 42 319 1 14.5 Water Treatment Buildings $0 $518 $506 0 1,024 9.0% $93 0% 0 15.0% 167 1,284 2 14.6 Machine Shop $0 $433 $296 0 729 8.9% $65 0% 0 15.0% 119 912 1 14.7 Warehouse $0 $699 $451 0 1,149 8.9% $102 0% 0 15.0% 188 1,439 2 14.8 Other Buildings & Structures $0 $418 $326 0 744 8.9% $66 0% 0 20.0% 162 973 2 14.9 Waste Treating Building & Str. $0 $935 $1,787 0 2,723 9.3% $254 0% 0 20.0% 595 3,572 6 SUBTOTAL 14. $0 $6,725 $7,701 $0 $14,427 $1,314 $0 $2,573 $18,313 $29 Total Cost $620,363 $72,516 $257,603 $0 $950,481 $89,310 $31,044 $165,109 $1,235,944 $1,987


### Owner's Costs Preproduction Costs 6 Months All Labor $12,214 $20 1 Month Maintenance Materials $2,742 $4 1 Month Non-fuel Consumables $269 $0 1 Month Waste Disposal $304 $0 25% of 1 Months Fuel Cost at 100% CF $1,627 $3 2% of TPC $24,719 $40
Total $41,874 $67 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,552 $22 0.5% of TPC (spare parts) $6,180 $10
Total $19,732 $32

Initial Cost for Catalyst and Chemicals $4,892 $8 Land $900 $1 Other Owner's Costs $185,392 $298

Financing Costs $33,370 $54 

### Total Overnight Costs (TOC) $1,522,105 $2,446.9 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $1,735,200 $2,790 Acct No. Item/Description Equipment Cost Material Cost Project Cont. TOTAL PLANT COST Labor Bare Erected Eng'g CM H.O. & Process Cont.



## 399Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 135 Case 2 D1A Initial and Annual O&M Expenses

Case: Case 2 D1A - GEE IGCC w/o WGS (0% CO2 Capture) Plant Size (MWe): 622.05 Heat Rate (Btu/kWh): 8,756 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.80 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun-07 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 0

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 15.0 15.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $5,918,913 $9.515 Maintenance Labor Cost (calc'd) $13,622,877 $21.900 Administrative & Support Labor (calc'd) $4,885,447 $7.854 Property Taxes and Insurance $24,718,883 $39.738 TOTAL FIXED OPERATING COSTS $49,146,120 $79.007 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $26,322,759 0.00604

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,409 1.08 $0 $1,076,793 0.00025 Chemicals MU & WT Chem. (lbs) 0 20,311 0.17 $0 $1,026,436 0.00024 Carbon (Mercury Removal) (lb) 54,833 75 1.05 $57,584 $23,034 0.00001 COS Catalyst (m3) 422 0.29 2,397.36 $1,011,578 $202,316 0.00005 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 0.00000 Selexol Solution (gal) 285,358 45 13.40 $3,823,295 $175,961 0.00004 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) w/equip. 1.94 131.27 $0 $74,422 0.00002 Subtotal Chemicals $4,892,457 $1,502,168 0.00034 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0.00 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 75 0.42 $0 $9,148 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 615 16.23 $0 $2,912,403 0.00067 Subtotal Solid Waste Disposal $0 $2,921,551 0.00067 By-products & Emissions Sulfur (tons) 0 140 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 0.00000

TOTAL VARIABLE OPERATING COSTS $31,823,271 0.00730 Coal FUEL (tons) 0 5,603 38.19 $0 $62,471,741 0.01433 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 400Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 136 Case 2 D1B (25%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) x $1, 000 Plant Size: 607.19 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,633 $0 $1,775 $0 $5,408 9.0% $484 0% $0 20.0% $1,179 $7,072 $12 1.2 Coal Stackout & Reclaim $4,695 $0 $1,138 $0 $5,833 8.8% $511 0% $0 20.0% $1,269 $7,613 $13 1.3 Coal Conveyors & Yd Crus $4,365 $0 $1,126 $0 $5,491 8.8% $482 0% $0 20.0% $1,195 $7,168 $12 1.4 Other Coal Handling $1,142 $0 $261 $0 $1,403 8.8% $123 0% $0 20.0% $305 $1,830 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,571 $6,428 $0 $8,999 9.6% $863 0% $0 20.0% $1,972 $11,834 $19 SUBTOTAL 1. $13,835 $2,571 $10,729 $0 $27,134 $2,463 $0 $5,919 $35,516 $58 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,549 $371 $243 $0 $2,162 8.6% 185 0% 0 20.0% $469 $2,816 $5 2.3 Slurry Prep & Feed $21,171 $0 $9,346 $0 $30,517 9.1% 2,773 5% 1,526 20.0% $6,963 $41,778 $69 2.4 Misc. Coal Prep & Feed $852 $620 $1,858 $0 $3,329 9.2% 306 0% 0 20.0% $727 $4,362 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,310 $2,717 $0 $6,027 9.3% 558 0% 0 20.0% $1,317 $7,903 $13 SUBTOTAL 2. $23,571 $4,300 $14,165 $0 $42,035 $3,822 $1,526 $9,477 $56,860 $94 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,865 4,919 2,597 0 10,381 9.3% 962 0% 0 20.0% $2,269 $13,611 $22 3.2 Water Makeup & Pretreating 616 64 344 0 1,024 9.5% 98 0% 0 30.0% $337 $1,459 $2 3.3 Other Feedwater Subsystems 1,567 530 477 0 2,574 9.0% 231 0% 0 20.0% $561 $3,366 $6 3.4 Service Water Systems 352 726 2,519 0 3,597 9.8% 351 0% 0 30.0% $1,184 $5,132 $8 3.5 Other Boiler Plant Systems 1,891 733 1,816 0 4,441 9.5% 421 0% 0 20.0% $972 $5,834 $10 3.6 FO Supply Sys & Nat Gas $311 $588 $549 $0 1,448 9.6% 139 0% 0 20.0% $318 $1,905 $3 3.7 Waste Treatment Equipment 861 0 525 0 1,386 9.7% 135 0% 0 30.0% $456 $1,977 $3 3.8 Misc. Power Plant Equipment $1,107 $148 $569 $0 1,824 9.7% 176 0% 0 30.0% $600 $2,600 $4 SUBTOTAL 3. $9,571 $7,709 $9,395 $0 $26,675 $2,513 $0 $6,697 $35,885 $59 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $109,860 $0 $60,195 $0 $170,055 9.2% $15,578 13.9% $23,600 15.3% $32,083 $241,316 $397 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $186,270 $0 w/equip. $0 $186,270 9.7% $18,055 0% $0 10.0% $20,433 $224,758 $370 4.4 Scrubber & Low Temperature Cooling 5,837 $4,751 $4,944 $0 $15,532 9.6% $1,491 0% $0 20.0% $3,405 $20,428 $34 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,780 $845 $1,671 $0 $4,296 9.6% $414 0% $0 20.0% $942 $5,652 $9 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,258 $5,224 $0 $11,481 9.3% $1,064 0% $0 25.0% $3,136 $15,682 $26 SUBTOTAL 4. $303,747 $11,853 $72,034 $0 $387,634 $36,603 $23,600 $59,998 $507,835 $836 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 401Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 136 Case 2 D1B (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) x $1, 000 Plant Size: 607.19 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $53,610 $0 $45,490 $0 $99,100 9.7% $9,584 20% $19,820 20.0% $25,701 $154,205 $254 5A.2 Elemental Sulfur Plant $9,987 $1,990 $12,884 $0 $24,861 9.7% $2,415 0% $0 20.0% $5,455 $32,732 $54 5A.3 Mercury Removal $1,063 $0 $809 $0 $1,872 9.7% $181 5% $94 20.0% $429 $2,576 $4 5A.4 COS Hydrolysis $3,549 $0 $4,635 $0 $8,184 9.7% $796 0% $0 20.0% $1,796 $10,776 $18 5A.5 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.6 Blowback Gas Systems $1,302 $0 $247 $0 $1,549 12.2% $189 0% $0 20.0% $348 $2,085 $3 5A.7 Fuel Gas Piping $0 $599 $419 $0 $1,018 9.3% $94 0% $0 20.0% $222 $1,335 $2 5A.9 HGCU Foundations $0 $617 $398 $0 $1,015 9.2% $93 0% $0 30.0% $332 $1,440 $2

5.9 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $69,511 $3,206 $64,882 $0 $137,599 $13,352 $19,914 $34,284 $205,149 $338 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $5,766 $0 $3,534 $0 $9,300 9.6% $896 0% $0 20.0% $2,039 $12,235 $20 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $5,766 $0 $3,534 $0 $9,300 $896 $0 $2,039 $12,235 $20 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 213 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 4 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $231 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,760 $0 $4,942 $0 $39,702 9.5% $3,775 0% $0 10.0% $4,348 $47,825 $79 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,711 $1,221 $0 $2,932 8.8% $257 0% $0 20.0% $638 $3,827 $6 7.4 Stack $3,338 $0 $1,254 $0 $4,592 9.6% $440 0% $0 10.0% $503 $5,535 $9 7.9 HRSG, Duct & Stack Foundations $0 $669 $642 $0 $1,311 9.3% $122 0% $0 30.0% $430 $1,863 $3 SUBTOTAL 7. $38,098 $2,380 $8,060 $0 $48,537 $4,594 $0 $5,919 $59,050 $97 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,446 $0 $5,034 $0 $34,480 9.6% $3,308 0% $0 10.0% $3,779 $41,567 $68 8.2 Turbine Plant Auxiliaries $204 $0 $468 $0 $672 9.8% $66 0% $0 10.0% $74 $811 $1 8.3 Condenser & Auxiliaries $5,250 $0 $1,541 $0 $6,792 9.6% $649 0% $0 10.0% $744 $8,185 $13 8.4 Steam Piping $5,058 $0 $3,558 $0 $8,616 8.6% $740 0% $0 25.0% $2,339 $11,696 $19 8.9 TG Foundations $0 $1,012 $1,711 $0 $2,723 9.5% $258 0% $0 30.0% $894 $3,876 $6 SUBTOTAL 8. $39,958 $1,012 $12,313 $0 $53,283 $5,022 $0 $7,830 $66,135 $109 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,657 $0 $1,211 $0 $7,868 9.5% $749 0% $0 15.0% $1,293 $9,910 $16 9.2 Circulating Water Pumps $1,722 $0 $124 $0 $1,847 8.4% $156 0% $0 15.0% $300 $2,303 $4 9.3 Circ. Water System Auxiliaries $146 $0 $21 $0 $167 9.5% $16 0% $0 15.0% $27 $210 $0 9.4 Circ. Water Piping $0 $6,091 $1,579 $0 $7,670 9.0% $693 0% $0 20.0% $1,673 $10,036 $17 9.5 Make-up Water System $341 $0 $488 $0 $829 9.6% $80 0% $0 20.0% $182 $1,090 $2 9.6 Component Cooling Water System $719 $860 $612 $0 $2,191 9.4% $205 0% $0 20.0% $479 $2,875 $5 9.9 Circ. Water System Foundations $0 $2,236 $3,801 $0 $6,036 9.5% $572 0% $0 30.0% $1,983 $8,591 $14 SUBTOTAL 9. $9,586 $9,186 $7,836 $0 $26,608 $2,471 $0 $5,937 $35,015 $58 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 402Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 136 Case 2 D1B (25%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) x $1, 000 Plant Size: 607.19 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,758 $6,483 $13,171 $0 $31,412 9.7% $3,032 0% $0 10.0% $3,444 $37,888 $62 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $572 $0 $622 $0 $1,194 9.7% $116 0% $0 15.0% $197 $1,507 $2 10.7 Ash Transport & Feed Equipment $767 $0 $185 $0 $952 9.3% $89 0% $0 15.0% $156 $1,197 $2 10.8 Misc. Ash Handling Equipment $1,185 $1,452 $434 $0 $3,071 9.5% $292 0% $0 15.0% $504 $3,867 $6 10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $114 9.4% $11 0% $0 30.0% $37 $162 $0 SUBTOTAL 10. $14,282 $7,986 $14,476 $0 $36,744 $3,539 $0 $4,339 $44,622 $73 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $961 $0 $951 $0 $1,912 9.5% $183 0% $0 10.0% $209 $2,303 $4 11.2 Station Service Equipment $4,150 $0 $374 $0 $4,524 9.2% $417 0% $0 10.0% $494 $5,435 $9 11.3 Switchgear & Motor Control $7,672 $0 $1,395 $0 $9,067 9.3% $841 0% $0 15.0% $1,486 $11,394 $19 11.4 Conduit & Cable Tray $0 $3,564 $11,756 $0 $15,320 9.7% $1,482 0% $0 25.0% $4,200 $21,002 $35 11.5 Wire & Cable $0 $6,809 $4,474 $0 $11,283 7.3% $820 0% $0 25.0% $3,026 $15,128 $25 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $236 $0 $231 $0 $467 9.5% $45 0% $0 15.0% $77 $588 $1 11.8 Main Power Transformers $17,787 $0 $146 $0 $17,934 7.6% $1,356 0% $0 15.0% $2,894 $22,184 $37 11.9 Electrical Foundations $0 $159 $417 $0 $577 9.6% $55 0% $0 30.0% $190 $821 $1 SUBTOTAL 11. $30,806 $11,218 $22,240 $0 $64,264 $5,509 $0 $13,099 $82,872 $136 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,045 $0 $698 $0 $1,743 9.5% $165 5% $87 15.0% $299 $2,294 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $240 $0 $154 $0 $394 9.5% $37 5% $20 20.0% $90 $541 $1 12.7 Computer & Accessories $5,574 $0 $178 $0 $5,752 9.2% $528 5% $288 10.0% $657 $7,224 $12 12.8 Instrument Wiring & Tubing $0 $1,947 $3,980 $0 $5,928 8.5% $503 5% $296 25.0% $1,682 $8,408 $14 12.9 Other I & C Equipment $3,726 $0 $1,809 $0 $5,535 9.4% $521 5% $277 15.0% $950 $7,282 $12 SUBTOTAL 12. $10,584 $1,947 $6,820 $0 $19,351 $1,754 $968 $3,678 $25,750 $42 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 108 2,297 0 2,405 9.9% 239 0% 0 30.0% 793 3,436 6 13.2 Site Improvements 0 1,912 2,540 0 4,452 9.9% 439 0% 0 30.0% 1,467 6,358 10 13.3 Site Facilities 3,426 0 3,615 0 7,040 9.9% 694 0% 0 30.0% 2,320 10,054 17 SUBTOTAL 13. $3,426 $2,019 $8,452 $0 $13,897 $1,372 $0 $4,581 $19,849 $33 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 403Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 136 Case 2 D1B (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) x $1, 000 Plant Size: 607.19 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $263 $149 $0 $412 8.8% $36 0% $0 20.0% $90 $539 $1 14.2 Steam Turbine Building $0 $2,361 $3,363 $0 $5,724 9.2% $527 0% $0 15.0% $938 $7,188 $12 14.3 Administration Building $0 $875 $634 $0 $1,509 8.9% $134 0% $0 15.0% $246 $1,890 $3 14.4 Circulation Water Pumphouse $0 $156 $82 $0 $238 8.8% $21 0% $0 15.0% $39 $298 $0 14.5 Water Treatment Buildings $0 $520 $508 $0 $1,028 9.0% $93 0% $0 15.0% $168 $1,289 $2 14.6 Machine Shop $0 $448 $306 $0 $754 8.9% $67 0% $0 15.0% $123 $944 $2 14.7 Warehouse $0 $723 $467 $0 $1,189 8.9% $105 0% $0 15.0% $194 $1,489 $2 14.8 Other Buildings & Structures $0 $433 $337 $0 $770 8.9% $69 0% $0 20.0% $168 $1,006 $2 14.9 Waste Treating Building & Str. $0 $961 $1,837 $0 $2,799 9.3% $261 0% $0 20.0% $612 $3,672 $6 SUBTOTAL 14. $0 $6,739 $7,684 $0 $14,423 $1,313 $0 $2,578 $18,314 $30 Total Cost $670,315 $73,013 $270,950 $0 $1,014,278 $95,346 $55,868 $179,806 $1,345,298 $2,216
Owner's Costs Preproduction Costs 6 Months All Labor $12,712 $21 1 Month Maintenance Materials $2,754 $5 1 Month Non-fuel Consumables $273 $0 1 Month Waste Disposal $302 $0 25% of 1 Months Fuel Cost at 100% CF $1,612 $3 2% of TPC $26,906 $44
Total $44,559 $73 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,445 $22 0.5% of TPC (spare parts) $6,726 $11
Total $20,171 $33

Initial Cost for Catalyst and Chemicals $4,931 $8 Land $900 $1 Other Owner's Costs $201,795 $332

Financing Costs $36,323 $60 Total Overnight Costs (TOC) $1,653,977 $2,724.0 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,885,534 $3,105 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 404Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 137 Case 2 D1B Initial and Annual O&M Expenses

Case: Case 2 D1B - GEE IGCC w/o WGS (25% CO2 Capture) Plant Size (MWe): 607.19 Heat Rate (Btu/kWh): 8,891 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 3,094

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $10.398 Maintenance Labor Cost (calc'd) $14,025,931 $23.100 Administrative & Support Labor (calc'd) $5,084,860 $8.374 Property Taxes & Insurance $26,905,955 $44.312 TOTAL FIXED OPERATING COSTS $52,330,253 $86.184 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $26,440,810 0.00621

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,378 1.08 $0 $1,067,015 0.00025

Chemicals MU & WT Chem. (lbs) 0 20,127 0.17 $0 $1,017,114 0.00024 Carbon (Mercury Removal) (lb) 55,194 95 1.05 $57,963 $29,132 0.00001 COS Catalyst (m3) 418 0.29 2,397.36 $1,001,137 $200,227 0.00005 Water Gas Shift Catalyst (ft3) 0 0.00 498.83 $0 $0 0.00000 Selexol Solution (gal) 289,013 59 13.40 $3,872,261 $230,395 0.00005 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.92 131.27 $0 $73,424 0.00002 Subtotal Chemicals $4,931,362 $1,550,292 0.00036 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 95 0.42 $0 $11,651 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 609 16.23 $0 $2,886,534 0.00068 Subtotal Solid Waste Disposal $0 $2,898,185 $0
By-products & Emissions Sulfur (tons) 0 139 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $31,956,302 0.00751 Coal FUEL (tons) 0 5,553 38.19 $0 $61,916,574 0.01455 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 405Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 138 Case 2 D2A (25%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) x $1, 000 Plant Size: 607.03 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,634 $0 $1,776 $0 $5,409 9.0% $485 0% $0 20.0% $1,179 $7,073 $12 1.2 Coal Stackout & Reclaim $4,695 $0 $1,138 $0 $5,834 8.8% $511 0% $0 20.0% $1,269 $7,614 $13 1.3 Coal Conveyors & Yd Crus $4,365 $0 $1,126 $0 $5,492 8.8% $482 0% $0 20.0% $1,195 $7,169 $12 1.4 Other Coal Handling $1,142 $0 $261 $0 $1,403 8.8% $123 0% $0 20.0% $305 $1,831 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,571 $6,429 $0 $9,001 9.6% $863 0% $0 20.0% $1,973 $11,836 $19 SUBTOTAL 1. $13,837 $2,571 $10,730 $0 $27,138 $2,463 $0 $5,920 $35,522 $59 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,549 $371 $243 $0 $2,162 8.6% 185 0% 0 20.0% $469 $2,817 $5 2.3 Slurry Prep & Feed $21,174 $0 $9,348 $0 $30,522 9.1% 2,773 5% 1,526 20.0% $6,964 $41,785 $69 2.4 Misc. Coal Prep & Feed $852 $620 $1,858 $0 $3,330 9.2% 306 0% 0 20.0% $727 $4,363 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,310 $2,718 $0 $6,028 9.3% 558 0% 0 20.0% $1,317 $7,904 $13 SUBTOTAL 2. $23,574 $4,301 $14,167 $0 $42,042 $3,822 $1,526 $9,478 $56,868 $94 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,865 4,920 2,597 0 10,381 9.3% 962 0% 0 20.0% $2,269 $13,612 $22 3.2 Water Makeup & Pretreating 616 64 345 0 1,025 9.5% 98 0% 0 30.0% $337 $1,460 $2 3.3 Other Feedwater Subsystems 1,567 530 477 0 2,574 9.0% 231 0% 0 20.0% $561 $3,366 $6 3.4 Service Water Systems 353 726 2,521 0 3,600 9.8% 351 0% 0 30.0% $1,185 $5,136 $8 3.5 Other Boiler Plant Systems 1,893 733 1,818 0 4,444 9.5% 422 0% 0 20.0% $973 $5,839 $10 3.6 FO Supply Sys & Nat Gas $311 $588 $549 $0 1,448 9.6% 140 0% 0 20.0% $318 $1,905 $3 3.7 Waste Treatment Equipment 862 0 526 0 1,387 9.7% 135 0% 0 30.0% $457 $1,979 $3 3.8 Misc. Power Plant Equipment $1,107 $148 $569 $0 1,824 9.7% 176 0% 0 30.0% $600 $2,600 $4 SUBTOTAL 3. $9,574 $7,710 $9,399 $0 $26,684 $2,514 $0 $6,699 $35,897 $59 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $109,878 $0 $60,205 $0 $170,083 9.2% $15,581 13.9% $23,604 15.3% $32,088 $241,356 $398 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $186,300 $0 w/equip. $0 $186,300 9.7% $18,058 0% $0 10.0% $20,436 $224,794 $370 4.4 Scrubber & Low Temperature Cooling 5,838 $4,751 $4,945 $0 $15,534 9.6% $1,492 0% $0 20.0% $3,405 $20,431 $34 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,780 $845 $1,671 $0 $4,296 9.6% $414 0% $0 20.0% $942 $5,652 $9 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,259 $5,225 $0 $11,483 9.3% $1,064 0% $0 25.0% $3,137 $15,684 $26 SUBTOTAL 4. $303,796 $11,855 $72,046 $0 $387,697 $36,609 $23,604 $60,008 $507,918 $837 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 406Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 138 Case 2 D2A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) x $1, 000 Plant Size: 607.03 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $53,677 $0 $45,546 $0 $99,223 9.7% $9,596 20% $19,845 20.0% $25,733 $154,396 $254 5A.2 Elemental Sulfur Plant $9,988 $1,991 $12,886 $0 $24,864 9.7% $2,415 0% $0 20.0% $5,456 $32,735 $54 5A.3 Mercury Removal $1,064 $0 $810 $0 $1,874 9.7% $181 5% $94 20.0% $430 $2,579 $4 5A.4 Shift Reactors $156 $0 $63 $0 $219 9.6% $21 0% $0 20.0% $48 $288 $0 5A.5 COS Hydrolysis $3,554 $0 $4,642 $0 $8,196 9.7% $797 0% $0 20.0% $1,799 $10,791 $18 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,302 $0 $247 $0 $1,549 12.2% $189 0% $0 20.0% $348 $2,085 $3 5A.8 Fuel Gas Piping $0 $599 $419 $0 $1,018 9.3% $94 0% $0 20.0% $223 $1,335 $2 5A.9 HGCU Foundations $0 $617 $398 $0 $1,015 9.2% $93 0% $0 30.0% $332 $1,440 $2 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $69,741 $3,206 $65,010 $0 $137,958 $13,387 $19,938 $34,367 $205,650 $339 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $5,818 $0 $3,566 $0 $9,384 9.6% $904 0% $0 20.0% $2,058 $12,346 $20 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $5,818 $0 $3,566 $0 $9,384 $904 $0 $2,058 $12,346 $20 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 213 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 4 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $231 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,760 $0 $4,942 $0 $39,702 9.5% $3,775 0% $0 10.0% $4,348 $47,825 $79 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,711 $1,221 $0 $2,932 8.8% $257 0% $0 20.0% $638 $3,827 $6 7.4 Stack $3,338 $0 $1,254 $0 $4,592 9.6% $440 0% $0 10.0% $503 $5,535 $9 7.9 HRSG, Duct & Stack Foundations $0 $669 $642 $0 $1,311 9.3% $122 0% $0 30.0% $430 $1,863 $3 SUBTOTAL 7. $38,098 $2,380 $8,060 $0 $48,538 $4,594 $0 $5,919 $59,050 $97 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,446 $0 $5,034 $0 $34,480 9.6% $3,308 0% $0 10.0% $3,779 $41,567 $68 8.2 Turbine Plant Auxiliaries $204 $0 $468 $0 $672 9.8% $66 0% $0 10.0% $74 $811 $1 8.3 Condenser & Auxiliaries $5,250 $0 $1,541 $0 $6,792 9.6% $649 0% $0 10.0% $744 $8,185 $13 8.4 Steam Piping $5,058 $0 $3,558 $0 $8,617 8.6% $740 0% $0 25.0% $2,339 $11,696 $19 8.9 TG Foundations $0 $1,012 $1,711 $0 $2,723 9.5% $258 0% $0 30.0% $894 $3,876 $6 SUBTOTAL 8. $39,958 $1,012 $12,313 $0 $53,283 $5,022 $0 $7,830 $66,135 $109 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,657 $0 $1,211 $0 $7,868 9.5% $749 0% $0 15.0% $1,293 $9,910 $16 9.2 Circulating Water Pumps $1,722 $0 $124 $0 $1,847 8.4% $156 0% $0 15.0% $300 $2,303 $4 9.3 Circ. Water System Auxiliaries $146 $0 $21 $0 $167 9.5% $16 0% $0 15.0% $27 $210 $0 9.4 Circ. Water Piping $0 $6,091 $1,579 $0 $7,670 9.0% $693 0% $0 20.0% $1,673 $10,036 $17 9.5 Make-up Water System $341 $0 $488 $0 $829 9.6% $80 0% $0 20.0% $182 $1,091 $2 9.6 Component Cooling Water System $719 $860 $612 $0 $2,191 9.4% $205 0% $0 20.0% $479 $2,875 $5 9.9 Circ. Water System Foundations $0 $2,236 $3,801 $0 $6,036 9.5% $572 0% $0 30.0% $1,983 $8,591 $14 SUBTOTAL 9. $9,586 $9,186 $7,836 $0 $26,608 $2,471 $0 $5,937 $35,016 $58 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 407Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 138 Case 2 D2A (25%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) x $1, 000 Plant Size: 607.03 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,759 $6,484 $13,173 $0 $31,417 9.7% $3,032 0% $0 10.0% $3,445 $37,894 $62 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $572 $0 $623 $0 $1,195 9.7% $116 0% $0 15.0% $197 $1,507 $2 10.7 Ash Transport & Feed Equipment $767 $0 $185 $0 $952 9.3% $89 0% $0 15.0% $156 $1,198 $2 10.8 Misc. Ash Handling Equipment $1,185 $1,452 $434 $0 $3,071 9.5% $292 0% $0 15.0% $505 $3,868 $6 10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $114 9.4% $11 0% $0 30.0% $37 $162 $0 SUBTOTAL 10. $14,284 $7,987 $14,478 $0 $36,749 $3,540 $0 $4,340 $44,629 $74 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $961 $0 $951 $0 $1,912 9.5% $183 0% $0 10.0% $209 $2,303 $4 11.2 Station Service Equipment $4,152 $0 $374 $0 $4,526 9.2% $417 0% $0 10.0% $494 $5,437 $9 11.3 Switchgear & Motor Control $7,675 $0 $1,396 $0 $9,071 9.3% $841 0% $0 15.0% $1,487 $11,400 $19 11.4 Conduit & Cable Tray $0 $3,565 $11,762 $0 $15,328 9.7% $1,483 0% $0 25.0% $4,203 $21,013 $35 11.5 Wire & Cable $0 $6,812 $4,476 $0 $11,289 7.3% $820 0% $0 25.0% $3,027 $15,136 $25 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $236 $0 $231 $0 $467 9.5% $45 0% $0 15.0% $77 $588 $1 11.8 Main Power Transformers $17,787 $0 $146 $0 $17,934 7.6% $1,356 0% $0 15.0% $2,894 $22,184 $37 11.9 Electrical Foundations $0 $159 $417 $0 $577 9.6% $55 0% $0 30.0% $190 $821 $1 SUBTOTAL 11. $30,812 $11,223 $22,249 $0 $64,284 $5,510 $0 $13,104 $82,899 $137 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,045 $0 $698 $0 $1,743 9.5% $165 5% $87 15.0% $299 $2,294 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $240 $0 $154 $0 $394 9.5% $37 5% $20 20.0% $90 $541 $1 12.7 Computer & Accessories $5,575 $0 $178 $0 $5,754 9.2% $528 5% $288 10.0% $657 $7,227 $12 12.8 Instrument Wiring & Tubing $0 $1,948 $3,982 $0 $5,929 8.5% $503 5% $296 25.0% $1,682 $8,411 $14 12.9 Other I & C Equipment $3,727 $0 $1,810 $0 $5,537 9.4% $521 5% $277 15.0% $950 $7,285 $12 SUBTOTAL 12. $10,588 $1,948 $6,822 $0 $19,357 $1,754 $968 $3,679 $25,758 $42 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 108 2,297 0 2,405 9.9% 239 0% 0 30.0% 793 3,437 6 13.2 Site Improvements 0 1,912 2,541 0 4,452 9.9% 439 0% 0 30.0% 1,467 6,359 10 13.3 Site Facilities 3,426 0 3,615 0 7,041 9.9% 694 0% 0 30.0% 2,320 10,055 17 SUBTOTAL 13. $3,426 $2,019 $8,453 $0 $13,898 $1,372 $0 $4,581 $19,851 $33 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 408Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 138 Case 2 D2A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) x $1, 000 Plant Size: 607.03 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $263 $149 $0 $412 8.8% $36 0% $0 20.0% $90 $539 $1 14.2 Steam Turbine Building $0 $2,361 $3,363 $0 $5,724 9.2% $527 0% $0 15.0% $938 $7,188 $12 14.3 Administration Building $0 $875 $634 $0 $1,509 8.9% $134 0% $0 15.0% $247 $1,890 $3 14.4 Circulation Water Pumphouse $0 $156 $82 $0 $238 8.8% $21 0% $0 15.0% $39 $298 $0 14.5 Water Treatment Buildings $0 $521 $508 $0 $1,029 9.0% $93 0% $0 15.0% $168 $1,290 $2 14.6 Machine Shop $0 $448 $306 $0 $754 8.9% $67 0% $0 15.0% $123 $944 $2 14.7 Warehouse $0 $723 $467 $0 $1,189 8.9% $105 0% $0 15.0% $194 $1,489 $2 14.8 Other Buildings & Structures $0 $433 $337 $0 $770 8.9% $69 0% $0 20.0% $168 $1,006 $2 14.9 Waste Treating Building & Str. $0 $962 $1,838 $0 $2,799 9.3% $261 0% $0 20.0% $612 $3,672 $6 SUBTOTAL 14. $0 $6,740 $7,685 $0 $14,425 $1,313 $0 $2,578 $18,316 $30 Total Cost $670,668 $73,026 $271,145 $0 $1,014,840 $95,399 $55,897 $179,930 $1,346,066 $2,217


### Owner's Costs Preproduction Costs 6 Months All Labor $12,717 $21 1 Month Maintenance Materials $2,756 $5 1 Month Non-fuel Consumables $273 $0 1 Month Waste Disposal $302 $0 25% of 1 Months Fuel Cost at 100% CF $1,613 $3 2% of TPC $26,921 $44
Total $44,582 $73 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,449 $22 0.5% of TPC (spare parts) $6,730 $11
Total $20,179 $33

Initial Cost for Catalyst and Chemicals $4,945 $8 Land $900 $1 Other Owner's Costs $201,910 $333

Financing Costs $36,344 $60 

### Total Overnight Costs (TOC) $1,654,925 $2,726.3 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $1,886,615 $3,108 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 409Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 139 Case 2 D2A Initial and Annual O&M Expenses

Case: Case 2 D2A - GEE IGCC w/ one WGS bypass (25% CO2 Capture) Plant Size (MWe): 607.03 Heat Rate (Btu/kWh): 8,895 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 3,129

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $10.401 Maintenance Labor Cost (calc'd) $14,033,692 $23.119 Administrative & Support Labor (calc'd) $5,086,800 $8.380 Property Taxes & Insurance $26,921,314 $44.350 TOTAL FIXED OPERATING COSTS $52,355,313 $86.249 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $26,455,440 0.00622

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,382 1.08 $0 $1,068,152 0.00025

Chemicals MU & WT Chem. (lbs) 0 20,148 0.17 $0 $1,018,198 0.00024 Carbon (Mercury Removal) (lb) 55,299 95 1.05 $58,073 $29,132 0.00001 COS Catalyst (m3) 419 0.29 2,397.36 $1,003,295 $200,659 0.00005 Water Gas Shift Catalyst (ft3) 23 0.02 498.83 $11,473 $2,295 0.00000 Selexol Solution (gal) 289,013 59 13.40 $3,872,261 $230,395 0.00005 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.92 131.27 $0 $73,436 0.00002 Subtotal Chemicals $4,945,103 $1,554,114 0.00037 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 95 0.42 $0 $11,651 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 609 16.23 $0 $2,887,216 0.00068 Subtotal Solid Waste Disposal $0 $2,898,867 $0
By-products & Emissions Sulfur (tons) 0 139 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $31,976,573 0.00752 Coal FUEL (tons) 0 5,554 38.19 $0 $61,931,158 0.01456 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 410Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 140 Case 2 D2B (45%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) x $1, 000 Plant Size: 590.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,669 $0 $1,793 $0 $5,462 9.0% $489 0% $0 20.0% $1,190 $7,141 $12 1.2 Coal Stackout & Reclaim $4,741 $0 $1,149 $0 $5,890 8.8% $516 0% $0 20.0% $1,281 $7,688 $13 1.3 Coal Conveyors & Yd Crus $4,408 $0 $1,137 $0 $5,545 8.8% $487 0% $0 20.0% $1,206 $7,238 $12 1.4 Other Coal Handling $1,153 $0 $263 $0 $1,416 8.8% $124 0% $0 20.0% $308 $1,848 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,596 $6,492 $0 $9,088 9.6% $871 0% $0 20.0% $1,992 $11,951 $20 SUBTOTAL 1. $13,971 $2,596 $10,834 $0 $27,401 $2,487 $0 $5,978 $35,866 $61 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,565 $374 $245 $0 $2,185 8.6% 187 0% 0 20.0% $474 $2,846 $5 2.3 Slurry Prep & Feed $21,396 $0 $9,444 $0 $30,840 9.1% 2,802 5% 1,542 20.0% $7,037 $42,221 $71 2.4 Misc. Coal Prep & Feed $860 $626 $1,877 $0 $3,364 9.2% 309 0% 0 20.0% $735 $4,408 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,345 $2,746 $0 $6,091 9.3% 564 0% 0 20.0% $1,331 $7,986 $14 SUBTOTAL 2. $23,821 $4,345 $14,313 $0 $42,479 $3,862 $1,542 $9,577 $57,460 $97 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,859 4,909 2,592 0 10,360 9.3% 960 0% 0 20.0% $2,264 $13,583 $23 3.2 Water Makeup & Pretreating 648 68 362 0 1,078 9.5% 103 0% 0 30.0% $354 $1,534 $3 3.3 Other Feedwater Subsystems 1,564 529 476 0 2,568 9.0% 231 0% 0 20.0% $560 $3,359 $6 3.4 Service Water Systems 371 763 2,649 0 3,783 9.8% 369 0% 0 30.0% $1,246 $5,398 $9 3.5 Other Boiler Plant Systems 1,989 771 1,910 0 4,671 9.5% 443 0% 0 20.0% $1,023 $6,137 $10 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 1,454 9.6% 140 0% 0 20.0% $319 $1,913 $3 3.7 Waste Treatment Equipment 906 0 552 0 1,458 9.7% 142 0% 0 30.0% $480 $2,080 $4 3.8 Misc. Power Plant Equipment $1,112 $149 $571 $0 1,831 9.7% 177 0% 0 30.0% $602 $2,610 $4 SUBTOTAL 3. $9,761 $7,779 $9,663 $0 $27,203 $2,564 $0 $6,847 $36,614 $62 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $111,081 $0 $60,864 $0 $171,945 9.2% $15,752 13.9% $23,862 15.3% $32,439 $243,998 $413 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $188,356 $0 w/equip. $0 $188,356 9.7% $18,257 0% $0 10.0% $20,661 $227,274 $385 4.4 Scrubber & Low Temperature Cooling 5,901 $4,803 $4,999 $0 $15,704 9.6% $1,508 0% $0 20.0% $3,442 $20,655 $35 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,800 $855 $1,689 $0 $4,343 9.6% $419 0% $0 20.0% $952 $5,714 $10 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,327 $5,282 $0 $11,609 9.3% $1,076 0% $0 25.0% $3,171 $15,856 $27 SUBTOTAL 4. $307,138 $11,985 $72,835 $0 $391,958 $37,011 $23,862 $60,667 $513,498 $869 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 411Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 140 Case 2 D2B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) x $1, 000 Plant Size: 590.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $60,122 $0 $51,015 $0 $111,138 9.7% $10,748 20% $22,228 20.0% $28,823 $172,936 $293 5A.2 Elemental Sulfur Plant $10,093 $2,011 $13,021 $0 $25,125 9.7% $2,441 0% $0 20.0% $5,513 $33,079 $56 5A.3 Mercury Removal $1,161 $0 $884 $0 $2,045 9.7% $197 5% $102 20.0% $469 $2,814 $5 5A.4 Shift Reactors $2,918 $0 $1,175 $0 $4,092 9.6% $392 0% $0 20.0% $897 $5,382 $9 5A.5 COS Hydrolysis $3,705 $0 $4,839 $0 $8,544 9.7% $831 0% $0 20.0% $1,875 $11,250 $19 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,316 $0 $249 $0 $1,566 12.2% $191 0% $0 20.0% $351 $2,108 $4 5A.8 Fuel Gas Piping $0 $611 $428 $0 $1,039 9.3% $96 0% $0 20.0% $227 $1,362 $2 5A.9 HGCU Foundations $0 $625 $403 $0 $1,027 9.2% $94 0% $0 30.0% $337 $1,458 $2 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $79,316 $3,247 $72,013 $0 $154,576 $14,991 $22,330 $38,492 $230,389 $390 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $9,620 $0 $5,897 $0 $15,517 9.6% $1,495 0% $0 20.0% $3,402 $20,414 $35 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $9,620 $0 $5,897 $0 $15,517 $1,495 $0 $3,402 $20,414 $35 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 219 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 4 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $237 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,421 $0 $4,894 $0 $39,315 9.5% $3,738 0% $0 10.0% $4,305 $47,359 $80 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,717 $1,225 $0 $2,942 8.8% $258 0% $0 20.0% $640 $3,840 $7 7.4 Stack $3,350 $0 $1,258 $0 $4,609 9.6% $442 0% $0 10.0% $505 $5,555 $9 7.9 HRSG, Duct & Stack Foundations $0 $671 $645 $0 $1,316 9.3% $122 0% $0 30.0% $431 $1,870 $3 SUBTOTAL 7. $37,771 $2,388 $8,022 $0 $48,182 $4,560 $0 $5,882 $58,624 $99 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,158 $0 $4,985 $0 $34,143 9.6% $3,276 0% $0 10.0% $3,742 $41,161 $70 8.2 Turbine Plant Auxiliaries $202 $0 $463 $0 $665 9.8% $65 0% $0 10.0% $73 $804 $1 8.3 Condenser & Auxiliaries $5,226 $0 $1,534 $0 $6,761 9.6% $646 0% $0 10.0% $741 $8,148 $14 8.4 Steam Piping $5,048 $0 $3,551 $0 $8,598 8.6% $739 0% $0 25.0% $2,334 $11,671 $20 8.9 TG Foundations $0 $1,002 $1,695 $0 $2,697 9.5% $256 0% $0 30.0% $886 $3,838 $6 SUBTOTAL 8. $39,634 $1,002 $12,228 $0 $52,864 $4,982 $0 $7,776 $65,622 $111 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,825 $0 $1,242 $0 $8,067 9.5% $768 0% $0 15.0% $1,325 $10,160 $17 9.2 Circulating Water Pumps $1,767 $0 $128 $0 $1,895 8.4% $160 0% $0 15.0% $308 $2,363 $4 9.3 Circ. Water System Auxiliaries $149 $0 $21 $0 $170 9.5% $16 0% $0 15.0% $28 $215 $0 9.4 Circ. Water Piping $0 $6,223 $1,613 $0 $7,836 9.0% $708 0% $0 20.0% $1,709 $10,253 $17 9.5 Make-up Water System $356 $0 $509 $0 $865 9.6% $83 0% $0 20.0% $190 $1,138 $2 9.6 Component Cooling Water System $735 $879 $625 $0 $2,238 9.4% $210 0% $0 20.0% $490 $2,938 $5 9.9 Circ. Water System Foundations $0 $2,284 $3,883 $0 $6,167 9.5% $585 0% $0 30.0% $2,026 $8,777 $15 SUBTOTAL 9. $9,832 $9,385 $8,021 $0 $27,238 $2,530 $0 $6,075 $35,843 $61 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 412Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 140 Case 2 D2B (45%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) x $1, 000 Plant Size: 590.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,873 $6,547 $13,301 $0 $31,721 9.7% $3,062 0% $0 10.0% $3,478 $38,261 $65 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $577 $0 $628 $0 $1,205 9.7% $117 0% $0 15.0% $198 $1,520 $3 10.7 Ash Transport & Feed Equipment $774 $0 $187 $0 $961 9.3% $90 0% $0 15.0% $158 $1,208 $2 10.8 Misc. Ash Handling Equipment $1,195 $1,465 $438 $0 $3,098 9.5% $295 0% $0 15.0% $509 $3,902 $7 10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $115 9.4% $11 0% $0 30.0% $38 $164 $0 SUBTOTAL 10. $14,420 $8,063 $14,617 $0 $37,100 $3,574 $0 $4,381 $45,055 $76 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $958 $0 $948 $0 $1,906 9.5% $182 0% $0 10.0% $209 $2,296 $4 11.2 Station Service Equipment $4,307 $0 $388 $0 $4,695 9.2% $433 0% $0 10.0% $513 $5,641 $10 11.3 Switchgear & Motor Control $7,963 $0 $1,448 $0 $9,411 9.3% $873 0% $0 15.0% $1,543 $11,826 $20 11.4 Conduit & Cable Tray $0 $3,699 $12,203 $0 $15,902 9.7% $1,538 0% $0 25.0% $4,360 $21,800 $37 11.5 Wire & Cable $0 $7,068 $4,644 $0 $11,711 7.3% $851 0% $0 25.0% $3,141 $15,703 $27 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $236 $0 $230 $0 $466 9.5% $44 0% $0 15.0% $77 $587 $1 11.8 Main Power Transformers $17,725 $0 $146 $0 $17,870 7.6% $1,352 0% $0 15.0% $2,883 $22,105 $37 11.9 Electrical Foundations $0 $159 $416 $0 $574 9.6% $55 0% $0 30.0% $189 $818 $1 SUBTOTAL 11. $31,188 $11,611 $22,918 $0 $65,718 $5,638 $0 $13,437 $84,793 $144 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,069 $0 $713 $0 $1,782 9.5% $169 5% $89 15.0% $306 $2,346 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $246 $0 $157 $0 $403 9.5% $38 5% $20 20.0% $92 $554 $1 12.7 Computer & Accessories $5,700 $0 $182 $0 $5,882 9.2% $540 5% $294 10.0% $672 $7,388 $13 12.8 Instrument Wiring & Tubing $0 $1,991 $4,071 $0 $6,062 8.5% $514 5% $303 25.0% $1,720 $8,599 $15 12.9 Other I & C Equipment $3,810 $0 $1,850 $0 $5,660 9.4% $533 5% $283 15.0% $971 $7,447 $13 SUBTOTAL 12. $10,824 $1,991 $6,974 $0 $19,790 $1,793 $989 $3,761 $26,334 $45 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 108 2,311 0 2,420 9.9% 240 0% 0 30.0% 798 3,458 6 13.2 Site Improvements 0 1,923 2,556 0 4,479 9.9% 442 0% 0 30.0% 1,476 6,398 11 13.3 Site Facilities 3,447 0 3,637 0 7,084 9.9% 698 0% 0 30.0% 2,335 10,117 17 SUBTOTAL 13. $3,447 $2,032 $8,504 $0 $13,983 $1,380 $0 $4,609 $19,972 $34 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 413Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 140 Case 2 D2B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) x $1, 000 Plant Size: 590.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $264 $149 $0 $413 8.8% $36 0% $0 20.0% $90 $539 $1 14.2 Steam Turbine Building $0 $2,367 $3,371 $0 $5,738 9.2% $528 0% $0 15.0% $940 $7,206 $12 14.3 Administration Building $0 $877 $636 $0 $1,514 8.9% $135 0% $0 15.0% $247 $1,896 $3 14.4 Circulation Water Pumphouse $0 $159 $84 $0 $243 8.8% $21 0% $0 15.0% $40 $304 $1 14.5 Water Treatment Buildings $0 $545 $532 $0 $1,077 9.0% $97 0% $0 15.0% $176 $1,351 $2 14.6 Machine Shop $0 $449 $307 $0 $756 8.9% $67 0% $0 15.0% $124 $947 $2 14.7 Warehouse $0 $725 $468 $0 $1,193 8.9% $106 0% $0 15.0% $195 $1,493 $3 14.8 Other Buildings & Structures $0 $434 $338 $0 $772 8.9% $69 0% $0 20.0% $168 $1,010 $2 14.9 Waste Treating Building & Str. $0 $966 $1,847 $0 $2,813 9.3% $262 0% $0 20.0% $615 $3,690 $6 SUBTOTAL 14. $0 $6,786 $7,733 $0 $14,520 $1,322 $0 $2,595 $18,436 $31 Total Cost $688,318 $74,099 $282,905 $0 $1,045,321 $98,313 $58,584 $186,909 $1,389,128 $2,351


### Owner's Costs Preproduction Costs 6 Months All Labor $12,980 $22 1 Month Maintenance Materials $2,839 $5 1 Month Non-fuel Consumables $311 $1 1 Month Waste Disposal $307 $1 25% of 1 Months Fuel Cost at 100% CF $1,638 $3 2% of TPC $27,783 $47
Total $45,857 $78 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,726 $23 0.5% of TPC (spare parts) $6,946 $12
Total $20,672 $35

Initial Cost for Catalyst and Chemicals $5,808 $10 Land $900 $2 Other Owner's Costs $208,369 $353

Financing Costs $37,506 $63 

### Total Overnight Costs (TOC) $1,708,241 $2,891 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $1,947,394 $3,296 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 414Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 141 Case 2 D2B Initial and Annual O&M Expenses

Case: Case 2 D2B - GEE IGCC w/ one WGS bypass (45% CO2 Capture) Plant Size (MWe): 590.80 Heat Rate (Btu/kWh): 9,283 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 5,736

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $10.686 Maintenance Labor Cost (calc'd) $14,455,208 $24.467 Administrative & Support Labor (calc'd) $5,192,179 $8.788 Property Taxes & Insurance $27,782,556 $47.025 TOTAL FIXED OPERATING COSTS $53,743,450 $90.967 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $27,250,055 0.00658

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,627 1.08 $0 $1,145,699 0.00028

Chemicals MU & WT Chem. (lbs) 0 21,611 0.17 $0 $1,092,119 0.00026 Carbon (Mercury Removal) (lb) 62,618 107 1.05 $65,760 $32,812 0.00001 COS Catalyst (m3) 444 0.30 2,397.36 $1,064,667 $212,933 0.00005 Water Gas Shift Catalyst (ft3) 1,535 1.05 498.83 $765,706 $153,141 0.00004 Selexol Solution (gal) 291,937 70 13.40 $3,911,435 $273,860 0.00007 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.95 131.27 $0 $74,590 0.00002 Subtotal Chemicals $5,807,568 $1,839,455 0.00044 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 107 0.42 $0 $13,122 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 619 16.23 $0 $2,932,471 0.00071 Subtotal Solid Waste Disposal $0 $2,945,593 $0
By-products & Emissions Sulfur (tons) 0 141 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $33,180,803 0.00801 Coal FUEL (tons) 0 5,641 38.19 $0 $62,902,016 0.01519 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 415Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 142 Case 2 D2C (60%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) x $1, 000 Plant Size: 578.38 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,698 $0 $1,807 $0 $5,505 9.0% $493 0% $0 20.0% $1,200 $7,198 $12 1.2 Coal Stackout & Reclaim $4,778 $0 $1,158 $0 $5,937 8.8% $520 0% $0 20.0% $1,291 $7,749 $13 1.3 Coal Conveyors & Yd Crus $4,443 $0 $1,146 $0 $5,589 8.8% $491 0% $0 20.0% $1,216 $7,295 $13 1.4 Other Coal Handling $1,162 $0 $265 $0 $1,428 8.8% $125 0% $0 20.0% $310 $1,863 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,617 $6,543 $0 $9,160 9.6% $878 0% $0 20.0% $2,008 $12,045 $21 SUBTOTAL 1. $14,081 $2,617 $10,920 $0 $27,618 $2,507 $0 $6,025 $36,150 $63 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,578 $378 $247 $0 $2,203 8.6% 188 0% 0 20.0% $478 $2,870 $5 2.3 Slurry Prep & Feed $21,579 $0 $9,524 $0 $31,103 9.1% 2,826 5% 1,555 20.0% $7,097 $42,580 $74 2.4 Misc. Coal Prep & Feed $868 $631 $1,893 $0 $3,392 9.2% 312 0% 0 20.0% $741 $4,445 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,373 $2,769 $0 $6,142 9.3% 569 0% 0 20.0% $1,342 $8,053 $14 SUBTOTAL 2. $24,025 $4,382 $14,433 $0 $42,840 $3,895 $1,555 $9,658 $57,948 $100 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,839 4,875 2,573 0 10,287 9.3% 953 0% 0 20.0% $2,248 $13,488 $23 3.2 Water Makeup & Pretreating 672 70 375 0 1,117 9.5% 106 0% 0 30.0% $367 $1,590 $3 3.3 Other Feedwater Subsystems 1,553 525 472 0 2,550 9.0% 229 0% 0 20.0% $556 $3,336 $6 3.4 Service Water Systems 384 791 2,746 0 3,922 9.8% 383 0% 0 30.0% $1,291 $5,596 $10 3.5 Other Boiler Plant Systems 2,062 799 1,980 0 4,842 9.5% 459 0% 0 20.0% $1,060 $6,361 $11 3.6 FO Supply Sys & Nat Gas $314 $592 $553 $0 1,459 9.6% 140 0% 0 20.0% $320 $1,919 $3 3.7 Waste Treatment Equipment 939 0 573 0 1,511 9.7% 147 0% 0 30.0% $498 $2,156 $4 3.8 Misc. Power Plant Equipment $1,115 $149 $573 $0 1,837 9.7% 177 0% 0 30.0% $604 $2,619 $5 SUBTOTAL 3. $9,878 $7,802 $9,846 $0 $27,526 $2,596 $0 $6,944 $37,066 $64 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $112,074 $0 $61,408 $0 $173,483 9.2% $15,892 13.9% $24,076 15.3% $32,729 $246,180 $426 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $190,054 $0 w/equip. $0 $190,054 9.7% $18,422 0% $0 10.0% $20,848 $229,323 $396 4.4 Scrubber & Low Temperature Cooling 5,954 $4,846 $5,044 $0 $15,845 9.6% $1,521 0% $0 20.0% $3,473 $20,839 $36 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,816 $862 $1,704 $0 $4,382 9.6% $422 0% $0 20.0% $961 $5,765 $10 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,384 $5,329 $0 $11,713 9.3% $1,085 0% $0 25.0% $3,200 $15,998 $28 SUBTOTAL 4. $309,898 $12,092 $73,486 $0 $395,476 $37,343 $24,076 $61,211 $518,106 $896 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 416Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 142 Case 2 D2C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) x $1, 000 Plant Size: 578.38 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $64,485 $0 $54,717 $0 $119,201 9.7% $11,528 20% $23,840 20.0% $30,914 $185,484 $321 5A.2 Elemental Sulfur Plant $10,179 $2,029 $13,133 $0 $25,341 9.7% $2,462 0% $0 20.0% $5,561 $33,363 $58 5A.3 Mercury Removal $1,238 $0 $942 $0 $2,180 9.7% $210 5% $109 20.0% $500 $2,999 $5 5A.4 Shift Reactors $4,409 $0 $1,775 $0 $6,184 9.6% $593 0% $0 20.0% $1,355 $8,132 $14 5A.5 COS Hydrolysis $3,830 $0 $5,001 $0 $8,831 9.7% $859 0% $0 20.0% $1,938 $11,627 $20 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,328 $0 $252 $0 $1,580 12.2% $193 0% $0 20.0% $355 $2,127 $4 5A.8 Fuel Gas Piping $0 $621 $435 $0 $1,056 9.3% $98 0% $0 20.0% $231 $1,385 $2 5A.9 HGCU Foundations $0 $631 $407 $0 $1,038 9.2% $95 0% $0 30.0% $340 $1,473 $3 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $85,469 $3,281 $76,661 $0 $165,411 $16,038 $23,949 $41,193 $246,590 $426 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $12,539 $0 $7,686 $0 $20,226 9.6% $1,948 0% $0 20.0% $4,435 $26,609 $46 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $12,539 $0 $7,686 $0 $20,226 $1,948 $0 $4,435 $26,609 $46 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 224 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $242 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,159 $0 $4,857 $0 $39,016 9.5% $3,710 0% $0 10.0% $4,273 $46,999 $81 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,722 $1,228 $0 $2,950 8.8% $259 0% $0 20.0% $642 $3,850 $7 7.4 Stack $3,359 $0 $1,262 $0 $4,620 9.6% $443 0% $0 10.0% $506 $5,569 $10 7.9 HRSG, Duct & Stack Foundations $0 $673 $646 $0 $1,319 9.3% $123 0% $0 30.0% $433 $1,875 $3 SUBTOTAL 7. $37,518 $2,394 $7,993 $0 $47,906 $4,534 $0 $5,853 $58,293 $101 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,018 $0 $4,961 $0 $33,978 9.6% $3,260 0% $0 10.0% $3,724 $40,963 $71 8.2 Turbine Plant Auxiliaries $201 $0 $461 $0 $662 9.8% $65 0% $0 10.0% $73 $800 $1 8.3 Condenser & Auxiliaries $5,178 $0 $1,520 $0 $6,699 9.6% $640 0% $0 10.0% $734 $8,073 $14 8.4 Steam Piping $5,012 $0 $3,526 $0 $8,537 8.6% $733 0% $0 25.0% $2,318 $11,589 $20 8.9 TG Foundations $0 $998 $1,686 $0 $2,684 9.5% $254 0% $0 30.0% $882 $3,820 $7 SUBTOTAL 8. $39,409 $998 $12,154 $0 $52,561 $4,953 $0 $7,730 $65,244 $113 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,929 $0 $1,260 $0 $8,189 9.5% $780 0% $0 15.0% $1,345 $10,315 $18 9.2 Circulating Water Pumps $1,800 $0 $130 $0 $1,931 8.4% $163 0% $0 15.0% $314 $2,408 $4 9.3 Circ. Water System Auxiliaries $151 $0 $22 $0 $173 9.5% $16 0% $0 15.0% $28 $218 $0 9.4 Circ. Water Piping $0 $6,320 $1,639 $0 $7,959 9.0% $719 0% $0 20.0% $1,736 $10,414 $18 9.5 Make-up Water System $367 $0 $525 $0 $892 9.6% $86 0% $0 20.0% $195 $1,173 $2 9.6 Component Cooling Water System $746 $892 $635 $0 $2,273 9.4% $213 0% $0 20.0% $497 $2,984 $5 9.9 Circ. Water System Foundations $0 $2,320 $3,944 $0 $6,264 9.5% $594 0% $0 30.0% $2,057 $8,915 $15 SUBTOTAL 9. $9,994 $9,533 $8,154 $0 $27,681 $2,571 $0 $6,174 $36,426 $63 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 417Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 142 Case 2 D2C (60%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) x $1, 000 Plant Size: 578.38 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,967 $6,599 $13,406 $0 $31,972 9.7% $3,086 0% $0 10.0% $3,506 $38,564 $67 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $581 $0 $632 $0 $1,214 9.7% $118 0% $0 15.0% $200 $1,531 $3 10.7 Ash Transport & Feed Equipment $780 $0 $188 $0 $968 9.3% $90 0% $0 15.0% $159 $1,217 $2 10.8 Misc. Ash Handling Equipment $1,204 $1,475 $441 $0 $3,120 9.5% $297 0% $0 15.0% $513 $3,930 $7 10.9 Ash/Spent Sorbent Foundation $0 $51 $65 $0 $116 9.4% $11 0% $0 30.0% $38 $165 $0 SUBTOTAL 10. $14,532 $8,126 $14,732 $0 $37,390 $3,602 $0 $4,415 $45,406 $79 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $957 $0 $946 $0 $1,903 9.5% $182 0% $0 10.0% $208 $2,293 $4 11.2 Station Service Equipment $4,433 $0 $399 $0 $4,832 9.2% $445 0% $0 10.0% $528 $5,805 $10 11.3 Switchgear & Motor Control $8,195 $0 $1,490 $0 $9,685 9.3% $898 0% $0 15.0% $1,588 $12,171 $21 11.4 Conduit & Cable Tray $0 $3,807 $12,559 $0 $16,365 9.7% $1,583 0% $0 25.0% $4,487 $22,435 $39 11.5 Wire & Cable $0 $7,274 $4,779 $0 $12,053 7.3% $876 0% $0 25.0% $3,232 $16,160 $28 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $235 $0 $230 $0 $465 9.5% $44 0% $0 15.0% $76 $586 $1 11.8 Main Power Transformers $17,694 $0 $146 $0 $17,840 7.6% $1,349 0% $0 15.0% $2,878 $22,067 $38 11.9 Electrical Foundations $0 $158 $415 $0 $573 9.6% $55 0% $0 30.0% $188 $817 $1 SUBTOTAL 11. $31,514 $11,925 $23,460 $0 $66,899 $5,743 $0 $13,710 $86,352 $149 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,087 $0 $726 $0 $1,813 9.5% $172 5% $91 15.0% $311 $2,387 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $250 $0 $160 $0 $410 9.5% $39 5% $21 20.0% $94 $563 $1 12.7 Computer & Accessories $5,799 $0 $186 $0 $5,985 9.2% $549 5% $299 10.0% $683 $7,517 $13 12.8 Instrument Wiring & Tubing $0 $2,026 $4,142 $0 $6,167 8.5% $523 5% $308 25.0% $1,750 $8,749 $15 12.9 Other I & C Equipment $3,877 $0 $1,882 $0 $5,759 9.4% $542 5% $288 15.0% $988 $7,577 $13 SUBTOTAL 12. $11,013 $2,026 $7,096 $0 $20,135 $1,825 $1,007 $3,827 $26,793 $46 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 109 2,321 0 2,430 9.9% 241 0% 0 30.0% 801 3,472 6 13.2 Site Improvements 0 1,932 2,567 0 4,498 9.9% 444 0% 0 30.0% 1,483 6,425 11 13.3 Site Facilities 3,461 0 3,652 0 7,114 9.9% 701 0% 0 30.0% 2,344 10,159 18 SUBTOTAL 13. $3,461 $2,040 $8,540 $0 $14,042 $1,386 $0 $4,628 $20,056 $35 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 418Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 142 Case 2 D2C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) x $1, 000 Plant Size: 578.38 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $264 $149 $0 $414 8.8% $36 0% $0 20.0% $90 $540 $1 14.2 Steam Turbine Building $0 $2,371 $3,377 $0 $5,748 9.2% $529 0% $0 15.0% $941 $7,218 $12 14.3 Administration Building $0 $879 $638 $0 $1,517 8.9% $135 0% $0 15.0% $248 $1,900 $3 14.4 Circulation Water Pumphouse $0 $161 $86 $0 $247 8.8% $22 0% $0 15.0% $40 $309 $1 14.5 Water Treatment Buildings $0 $564 $550 $0 $1,114 9.0% $101 0% $0 15.0% $182 $1,397 $2 14.6 Machine Shop $0 $450 $308 $0 $758 8.9% $67 0% $0 15.0% $124 $949 $2 14.7 Warehouse $0 $726 $469 $0 $1,195 8.9% $106 0% $0 15.0% $195 $1,496 $3 14.8 Other Buildings & Structures $0 $435 $339 $0 $774 8.9% $69 0% $0 20.0% $169 $1,012 $2 14.9 Waste Treating Building & Str. $0 $970 $1,853 $0 $2,823 9.3% $263 0% $0 20.0% $617 $3,703 $6 SUBTOTAL 14. $0 $6,820 $7,769 $0 $14,589 $1,328 $0 $2,607 $18,524 $32 Total Cost $700,906 $74,923 $291,263 $0 $1,067,091 $100,392 $60,448 $191,841 $1,419,771 $2,455


### Owner's Costs Preproduction Costs 6 Months All Labor $13,169 $23 1 Month Maintenance Materials $2,898 $5 1 Month Non-fuel Consumables $341 $1 1 Month Waste Disposal $311 $1 25% of 1 Months Fuel Cost at 100% CF $1,659 $3 2% of TPC $28,395 $49
Total $46,772 $81 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,954 $24 0.5% of TPC (spare parts) $7,099 $12
Total $21,053 $36

Initial Cost for Catalyst and Chemicals $6,510 $11 Land $900 $2 Other Owner's Costs $212,966 $368

Financing Costs $38,334 $66 

### Total Overnight Costs (TOC) $1,746,306 $3,019 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $1,990,789 $3,442 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 419Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 143 Case 2 D2C Initial and Annual O&M Expenses

Case: Case 2 D2C - GEE IGCC w/ one WGS bypass (60% CO2 Capture) Plant Size (MWe): 578.38 Heat Rate (Btu/kWh): 9,604 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 7,820

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $10.916 Maintenance Labor Cost (calc'd) $14,756,256 $25.513 Administrative & Support Labor (calc'd) $5,267,441 $9.107 Property Taxes & Insurance $28,395,426 $49.095 TOTAL FIXED OPERATING COSTS $54,732,630 $94.631 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $27,817,573 0.00686

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,816 1.08 $0 $1,205,281 0.00030

Chemicals MU & WT Chem. (lbs) 0 22,735 0.17 $0 $1,148,914 0.00028 Carbon (Mercury Removal) (lb) 68,570 117 1.05 $72,010 $35,878 0.00001 COS Catalyst (m3) 466 0.32 2,397.36 $1,115,971 $223,194 0.00006 Water Gas Shift Catalyst (ft3) 2,769 1.90 498.83 $1,381,263 $276,253 0.00007 Selexol Solution (gal) 294,129 78 13.40 $3,940,815 $306,332 0.00008 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.97 131.27 $0 $75,548 0.00002 Subtotal Chemicals $6,510,059 $2,066,119 0.00051 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 117 0.42 $0 $14,349 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 627 16.23 $0 $2,969,994 0.00073 Subtotal Solid Waste Disposal $0 $2,984,343 $0
By-products & Emissions Sulfur (tons) 0 143 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $34,073,315 0.00841 Coal FUEL (tons) 0 5,714 38.19 $0 $63,706,962 0.01572 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 420Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 144 Case 2 D2D (75%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) x $1, 000 Plant Size: 563.92 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,723 $0 $1,819 $0 $5,542 9.0% $496 0% $0 20.0% $1,208 $7,246 $13 1.2 Coal Stackout & Reclaim $4,811 $0 $1,166 $0 $5,977 8.8% $524 0% $0 20.0% $1,300 $7,801 $14 1.3 Coal Conveyors & Yd Crus $4,473 $0 $1,154 $0 $5,627 8.8% $494 0% $0 20.0% $1,224 $7,345 $13 1.4 Other Coal Handling $1,170 $0 $267 $0 $1,437 8.8% $126 0% $0 20.0% $313 $1,876 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,634 $6,587 $0 $9,222 9.6% $884 0% $0 20.0% $2,021 $12,127 $22 SUBTOTAL 1. $14,177 $2,634 $10,994 $0 $27,805 $2,524 $0 $6,066 $36,395 $65 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,589 $380 $249 $0 $2,219 8.6% 190 0% 0 20.0% $482 $2,890 $5 2.3 Slurry Prep & Feed $21,737 $0 $9,592 $0 $31,330 9.1% 2,846 5% 1,566 20.0% $7,149 $42,891 $76 2.4 Misc. Coal Prep & Feed $874 $636 $1,907 $0 $3,417 9.2% 314 0% 0 20.0% $746 $4,477 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,397 $2,789 $0 $6,186 9.3% 573 0% 0 20.0% $1,352 $8,111 $14 SUBTOTAL 2. $24,200 $4,414 $14,538 $0 $43,152 $3,923 $1,566 $9,728 $58,370 $104 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,818 4,839 2,555 0 10,212 9.3% 946 0% 0 20.0% $2,232 $13,389 $24 3.2 Water Makeup & Pretreating 692 72 387 0 1,151 9.5% 110 0% 0 30.0% $378 $1,639 $3 3.3 Other Feedwater Subsystems 1,542 521 469 0 2,532 9.0% 228 0% 0 20.0% $552 $3,311 $6 3.4 Service Water Systems 396 816 2,831 0 4,042 9.8% 394 0% 0 30.0% $1,331 $5,768 $10 3.5 Other Boiler Plant Systems 2,125 824 2,041 0 4,990 9.5% 473 0% 0 20.0% $1,093 $6,556 $12 3.6 FO Supply Sys & Nat Gas $315 $594 $554 $0 1,463 9.6% 141 0% 0 20.0% $321 $1,924 $3 3.7 Waste Treatment Equipment 968 0 590 0 1,558 9.7% 152 0% 0 30.0% $513 $2,222 $4 3.8 Misc. Power Plant Equipment $1,118 $150 $574 $0 1,842 9.7% 178 0% 0 30.0% $606 $2,626 $5 SUBTOTAL 3. $9,974 $7,815 $10,000 $0 $27,789 $2,621 $0 $7,025 $37,436 $66 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $112,933 $0 $61,879 $0 $174,812 9.2% $16,014 13.9% $24,260 15.3% $32,980 $248,067 $440 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $191,409 $0 w/equip. $0 $191,409 9.7% $18,553 0% $0 10.0% $20,996 $230,959 $410 4.4 Scrubber & Low Temperature Cooling 6,000 $4,883 $5,083 $0 $15,966 9.6% $1,533 0% $0 20.0% $3,500 $20,999 $37 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,830 $869 $1,717 $0 $4,416 9.6% $426 0% $0 20.0% $968 $5,810 $10 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,433 $5,370 $0 $11,803 9.3% $1,094 0% $0 25.0% $3,224 $16,120 $29 SUBTOTAL 4. $312,172 $12,185 $74,049 $0 $398,406 $37,620 $24,260 $61,669 $521,955 $926 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 421Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 144 Case 2 D2D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) x $1, 000 Plant Size: 563.92 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $69,188 $0 $58,708 $0 $127,896 9.7% $12,369 20% $25,579 20.0% $33,169 $199,013 $353 5A.2 Elemental Sulfur Plant $10,254 $2,044 $13,230 $0 $25,527 9.7% $2,480 0% $0 20.0% $5,601 $33,608 $60 5A.3 Mercury Removal $1,307 $0 $994 $0 $2,301 9.7% $222 5% $115 20.0% $528 $3,166 $6 5A.4 Shift Reactors $5,634 $0 $2,268 $0 $7,902 9.6% $758 0% $0 20.0% $1,732 $10,391 $18 5A.5 COS Hydrolysis $3,942 $0 $5,148 $0 $9,090 9.7% $884 0% $0 20.0% $1,995 $11,968 $21 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,338 $0 $254 $0 $1,592 12.2% $194 0% $0 20.0% $357 $2,143 $4 5A.8 Fuel Gas Piping $0 $628 $440 $0 $1,068 9.3% $99 0% $0 20.0% $233 $1,400 $2 5A.9 HGCU Foundations $0 $636 $410 $0 $1,047 9.2% $96 0% $0 30.0% $343 $1,486 $3 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $91,663 $3,308 $81,451 $0 $176,422 $17,102 $25,694 $43,958 $263,176 $467 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $15,358 $0 $9,414 $0 $24,773 9.6% $2,386 0% $0 20.0% $5,432 $32,591 $58 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $15,358 $0 $9,414 $0 $24,773 $2,386 $0 $5,432 $32,591 $58 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 230 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $249 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,897 $0 $4,820 $0 $38,717 9.5% $3,681 0% $0 10.0% $4,240 $46,638 $83 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,726 $1,231 $0 $2,957 8.8% $259 0% $0 20.0% $643 $3,860 $7 7.4 Stack $3,367 $0 $1,265 $0 $4,632 9.6% $444 0% $0 10.0% $508 $5,584 $10 7.9 HRSG, Duct & Stack Foundations $0 $675 $648 $0 $1,323 9.3% $123 0% $0 30.0% $434 $1,879 $3 SUBTOTAL 7. $37,264 $2,401 $7,964 $0 $47,629 $4,507 $0 $5,824 $57,961 $103 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,760 $0 $4,917 $0 $33,676 9.6% $3,231 0% $0 10.0% $3,691 $40,598 $72 8.2 Turbine Plant Auxiliaries $199 $0 $457 $0 $656 9.8% $64 0% $0 10.0% $72 $793 $1 8.3 Condenser & Auxiliaries $5,106 $0 $1,499 $0 $6,605 9.6% $631 0% $0 10.0% $724 $7,960 $14 8.4 Steam Piping $4,975 $0 $3,499 $0 $8,474 8.6% $728 0% $0 25.0% $2,300 $11,502 $20 8.9 TG Foundations $0 $989 $1,672 $0 $2,661 9.5% $252 0% $0 30.0% $874 $3,787 $7 SUBTOTAL 8. $39,040 $989 $12,044 $0 $52,073 $4,907 $0 $7,661 $64,641 $115 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,032 $0 $1,279 $0 $8,312 9.5% $791 0% $0 15.0% $1,365 $10,469 $19 9.2 Circulating Water Pumps $1,823 $0 $132 $0 $1,954 8.4% $165 0% $0 15.0% $318 $2,437 $4 9.3 Circ. Water System Auxiliaries $153 $0 $22 $0 $175 9.5% $17 0% $0 15.0% $29 $220 $0 9.4 Circ. Water Piping $0 $6,385 $1,655 $0 $8,040 9.0% $727 0% $0 20.0% $1,753 $10,520 $19 9.5 Make-up Water System $376 $0 $538 $0 $915 9.6% $88 0% $0 20.0% $200 $1,203 $2 9.6 Component Cooling Water System $754 $902 $641 $0 $2,297 9.4% $215 0% $0 20.0% $502 $3,014 $5 9.9 Circ. Water System Foundations $0 $2,344 $3,984 $0 $6,328 9.5% $600 0% $0 30.0% $2,078 $9,006 $16 SUBTOTAL 9. $10,138 $9,630 $8,252 $0 $28,020 $2,603 $0 $6,247 $36,870 $65 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 422Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 144 Case 2 D2D (75%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) x $1, 000 Plant Size: 563.92 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,049 $6,644 $13,497 $0 $32,189 9.7% $3,107 0% $0 10.0% $3,530 $38,826 $69 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $585 $0 $636 $0 $1,221 9.7% $118 0% $0 15.0% $201 $1,541 $3 10.7 Ash Transport & Feed Equipment $784 $0 $189 $0 $974 9.3% $91 0% $0 15.0% $160 $1,224 $2 10.8 Misc. Ash Handling Equipment $1,211 $1,484 $443 $0 $3,139 9.5% $299 0% $0 15.0% $516 $3,954 $7 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $166 $0 SUBTOTAL 10. $14,629 $8,180 $14,831 $0 $37,640 $3,626 $0 $4,444 $45,710 $81 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $954 $0 $944 $0 $1,898 9.5% $181 0% $0 10.0% $208 $2,287 $4 11.2 Station Service Equipment $4,560 $0 $411 $0 $4,971 9.2% $458 0% $0 10.0% $543 $5,972 $11 11.3 Switchgear & Motor Control $8,430 $0 $1,533 $0 $9,963 9.3% $924 0% $0 15.0% $1,633 $12,520 $22 11.4 Conduit & Cable Tray $0 $3,916 $12,918 $0 $16,834 9.7% $1,628 0% $0 25.0% $4,616 $23,078 $41 11.5 Wire & Cable $0 $7,482 $4,916 $0 $12,398 7.3% $901 0% $0 25.0% $3,325 $16,623 $29 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $235 $0 $229 $0 $464 9.5% $44 0% $0 15.0% $76 $585 $1 11.8 Main Power Transformers $17,638 $0 $145 $0 $17,783 7.6% $1,345 0% $0 15.0% $2,869 $21,997 $39 11.9 Electrical Foundations $0 $158 $414 $0 $571 9.6% $55 0% $0 30.0% $188 $814 $1 SUBTOTAL 11. $31,816 $12,241 $24,006 $0 $68,063 $5,847 $0 $13,981 $87,892 $156 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,106 $0 $738 $0 $1,844 9.5% $175 5% $92 15.0% $317 $2,428 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $254 $0 $163 $0 $417 9.5% $39 5% $21 20.0% $95 $573 $1 12.7 Computer & Accessories $5,899 $0 $189 $0 $6,087 9.2% $559 5% $304 10.0% $695 $7,646 $14 12.8 Instrument Wiring & Tubing $0 $2,061 $4,212 $0 $6,273 8.5% $532 5% $314 25.0% $1,780 $8,898 $16 12.9 Other I & C Equipment $3,943 $0 $1,915 $0 $5,858 9.4% $551 5% $293 15.0% $1,005 $7,707 $14 SUBTOTAL 12. $11,201 $2,061 $7,217 $0 $20,479 $1,856 $1,024 $3,892 $27,251 $48 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 109 2,330 0 2,439 9.9% 242 0% 0 30.0% 804 3,486 6 13.2 Site Improvements 0 1,939 2,577 0 4,516 9.9% 445 0% 0 30.0% 1,488 6,450 11 13.3 Site Facilities 3,475 0 3,667 0 7,142 9.9% 704 0% 0 30.0% 2,354 10,199 18 SUBTOTAL 13. $3,475 $2,048 $8,574 $0 $14,097 $1,391 $0 $4,647 $20,135 $36 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 423Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 144 Case 2 D2D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) x $1, 000 Plant Size: 563.92 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $264 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $540 $1 14.2 Steam Turbine Building $0 $2,374 $3,382 $0 $5,757 9.2% $530 0% $0 15.0% $943 $7,229 $13 14.3 Administration Building $0 $881 $639 $0 $1,520 8.9% $135 0% $0 15.0% $248 $1,903 $3 14.4 Circulation Water Pumphouse $0 $163 $86 $0 $249 8.8% $22 0% $0 15.0% $41 $312 $1 14.5 Water Treatment Buildings $0 $580 $566 $0 $1,146 9.0% $104 0% $0 15.0% $187 $1,437 $3 14.6 Machine Shop $0 $451 $309 $0 $759 8.9% $67 0% $0 15.0% $124 $951 $2 14.7 Warehouse $0 $728 $470 $0 $1,198 8.9% $106 0% $0 15.0% $196 $1,499 $3 14.8 Other Buildings & Structures $0 $436 $339 $0 $775 8.9% $69 0% $0 20.0% $169 $1,014 $2 14.9 Waste Treating Building & Str. $0 $973 $1,859 $0 $2,831 9.3% $264 0% $0 20.0% $619 $3,714 $7 SUBTOTAL 14. $0 $6,850 $7,800 $0 $14,650 $1,334 $0 $2,617 $18,600 $33 Total Cost $712,683 $75,643 $299,466 $0 $1,087,792 $102,370 $62,406 $196,623 $1,449,191 $2,570
Owner's Costs Preproduction Costs 6 Months All Labor $13,348 $24 1 Month Maintenance Materials $2,954 $5 1 Month Non-fuel Consumables $368 $1 1 Month Waste Disposal $314 $1 25% of 1 Months Fuel Cost at 100% CF $1,677 $3 2% of TPC $28,984 $51
Total $47,645 $84 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,154 $25 0.5% of TPC (spare parts) $7,246 $13
Total $21,400 $38

Initial Cost for Catalyst and Chemicals $7,172 $13 Land $900 $2 Other Owner's Costs $217,379 $385

Financing Costs $39,128 $69 Total Overnight Costs (TOC) $1,782,815 $3,161 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,032,409 $3,604 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 424Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 145 Case 2 D2D Initial and Annual O&M Expenses

Case: Case 2 D2D - GEE IGCC w/ one WGS bypass (75% CO2 Capture) Plant Size (MWe): 563.92 Heat Rate (Btu/kWh): 9,958 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 9,988

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $11.196 Maintenance Labor Cost (calc'd) $15,042,519 $26.675 Administrative & Support Labor (calc'd) $5,339,006 $9.468 Property Taxes & Insurance $28,983,817 $51.397 TOTAL FIXED OPERATING COSTS $55,678,849 $98.735 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $28,357,217 0.00718

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,982 1.08 $0 $1,257,585 0.00032

Chemicals MU & WT Chem. (lbs) 0 23,721 0.17 $0 $1,198,773 0.00030 Carbon (Mercury Removal) (lb) 74,096 127 1.05 $77,813 $38,945 0.00001 COS Catalyst (m3) 485 0.33 2,397.36 $1,163,199 $232,640 0.00006 Water Gas Shift Catalyst (ft3) 3,930 2.69 498.83 $1,960,406 $392,081 0.00010 Selexol Solution (gal) 296,322 87 13.40 $3,970,195 $339,078 0.00009 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.99 131.27 $0 $76,378 0.00002 Subtotal Chemicals $7,171,613 $2,277,894 0.00058 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 127 0.42 $0 $15,575 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 634 16.23 $0 $3,002,571 0.00076 Subtotal Solid Waste Disposal $0 $3,018,146 $0
By-products & Emissions Sulfur (tons) 0 145 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $34,910,843 0.00883 Coal FUEL (tons) 0 5,776 38.19 $0 $64,405,670 0.01630 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 425Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 146 Case 2 D3A (25%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) x $1, 000 Plant Size: 607.02 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,633 $0 $1,775 $0 $5,409 9.0% $484 0% $0 20.0% $1,179 $7,072 $12 1.2 Coal Stackout & Reclaim $4,695 $0 $1,138 $0 $5,833 8.8% $511 0% $0 20.0% $1,269 $7,613 $13 1.3 Coal Conveyors & Yd Crus $4,365 $0 $1,126 $0 $5,491 8.8% $482 0% $0 20.0% $1,195 $7,168 $12 1.4 Other Coal Handling $1,142 $0 $261 $0 $1,403 8.8% $123 0% $0 20.0% $305 $1,830 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,571 $6,429 $0 $9,000 9.6% $863 0% $0 20.0% $1,972 $11,835 $19 SUBTOTAL 1. $13,835 $2,571 $10,729 $0 $27,135 $2,463 $0 $5,920 $35,518 $59 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,549 $371 $243 $0 $2,162 8.6% 185 0% 0 20.0% $469 $2,816 $5 2.3 Slurry Prep & Feed $21,172 $0 $9,347 $0 $30,518 9.1% 2,773 5% 1,526 20.0% $6,963 $41,780 $69 2.4 Misc. Coal Prep & Feed $852 $620 $1,858 $0 $3,329 9.2% 306 0% 0 20.0% $727 $4,362 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,310 $2,718 $0 $6,028 9.3% 558 0% 0 20.0% $1,317 $7,903 $13 SUBTOTAL 2. $23,572 $4,300 $14,165 $0 $42,037 $3,822 $1,526 $9,477 $56,862 $94 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,864 4,919 2,597 0 10,380 9.3% 962 0% 0 20.0% $2,268 $13,610 $22 3.2 Water Makeup & Pretreating 616 64 344 0 1,025 9.5% 98 0% 0 30.0% $337 $1,459 $2 3.3 Other Feedwater Subsystems 1,567 530 477 0 2,573 9.0% 231 0% 0 20.0% $561 $3,366 $6 3.4 Service Water Systems 353 726 2,520 0 3,599 9.8% 351 0% 0 30.0% $1,185 $5,135 $8 3.5 Other Boiler Plant Systems 1,892 733 1,817 0 4,443 9.5% 421 0% 0 20.0% $973 $5,837 $10 3.6 FO Supply Sys & Nat Gas $311 $588 $549 $0 1,448 9.6% 140 0% 0 20.0% $318 $1,905 $3 3.7 Waste Treatment Equipment 861 0 525 0 1,387 9.7% 135 0% 0 30.0% $457 $1,978 $3 3.8 Misc. Power Plant Equipment $1,107 $148 $569 $0 1,824 9.7% 176 0% 0 30.0% $600 $2,600 $4 SUBTOTAL 3. $9,573 $7,709 $9,397 $0 $26,679 $2,514 $0 $6,698 $35,891 $59 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $109,865 $0 $60,198 $0 $170,063 9.2% $15,579 13.9% $23,601 15.3% $32,084 $241,328 $398 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $186,280 $0 w/equip. $0 $186,280 9.7% $18,056 0% $0 10.0% $20,434 $224,770 $370 4.4 Scrubber & Low Temperature Cooling 5,837 $4,751 $4,945 $0 $15,532 9.6% $1,491 0% $0 20.0% $3,405 $20,429 $34 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,780 $845 $1,671 $0 $4,296 9.6% $414 0% $0 20.0% $942 $5,652 $9 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,258 $5,224 $0 $11,482 9.3% $1,064 0% $0 25.0% $3,136 $15,682 $26 SUBTOTAL 4. $303,762 $11,854 $72,037 $0 $387,653 $36,605 $23,601 $60,001 $507,860 $837 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 426Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 146 Case 2 D3A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) x $1, 000 Plant Size: 607.02 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $53,837 $0 $45,682 $0 $99,519 9.7% $9,625 20% $19,904 20.0% $25,809 $154,856 $255 5A.2 Elemental Sulfur Plant $9,987 $1,990 $12,884 $0 $24,861 9.7% $2,415 0% $0 20.0% $5,455 $32,732 $54 5A.3 Mercury Removal $1,064 $0 $809 $0 $1,873 9.7% $181 5% $94 20.0% $430 $2,577 $4 5A.4 Shift Reactors $145 $0 $58 $0 $203 9.6% $19 0% $0 20.0% $44 $267 $0 5A.5 COS Hydrolysis $3,543 $0 $4,627 $0 $8,170 9.7% $794 0% $0 20.0% $1,793 $10,758 $18 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,302 $0 $247 $0 $1,549 12.2% $189 0% $0 20.0% $348 $2,085 $3 5A.8 Fuel Gas Piping $0 $598 $419 $0 $1,018 9.3% $94 0% $0 20.0% $222 $1,334 $2 5A.9 HGCU Foundations $0 $617 $398 $0 $1,015 9.2% $93 0% $0 30.0% $332 $1,440 $2 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $69,877 $3,206 $65,125 $0 $138,207 $13,411 $19,997 $34,434 $206,049 $339 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $5,815 $0 $3,564 $0 $9,379 9.6% $903 0% $0 20.0% $2,057 $12,339 $20 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $5,815 $0 $3,564 $0 $9,379 $903 $0 $2,057 $12,339 $20 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 214 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 4 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $231 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,760 $0 $4,942 $0 $39,702 9.5% $3,775 0% $0 10.0% $4,348 $47,825 $79 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,711 $1,221 $0 $2,932 8.8% $257 0% $0 20.0% $638 $3,827 $6 7.4 Stack $3,338 $0 $1,254 $0 $4,592 9.6% $440 0% $0 10.0% $503 $5,535 $9 7.9 HRSG, Duct & Stack Foundations $0 $669 $642 $0 $1,311 9.3% $122 0% $0 30.0% $430 $1,863 $3 SUBTOTAL 7. $38,098 $2,380 $8,060 $0 $48,538 $4,594 $0 $5,919 $59,050 $97 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,446 $0 $5,034 $0 $34,480 9.6% $3,308 0% $0 10.0% $3,779 $41,567 $68 8.2 Turbine Plant Auxiliaries $204 $0 $468 $0 $672 9.8% $66 0% $0 10.0% $74 $811 $1 8.3 Condenser & Auxiliaries $5,250 $0 $1,541 $0 $6,792 9.6% $649 0% $0 10.0% $744 $8,185 $13 8.4 Steam Piping $5,058 $0 $3,558 $0 $8,616 8.6% $740 0% $0 25.0% $2,339 $11,695 $19 8.9 TG Foundations $0 $1,012 $1,711 $0 $2,723 9.5% $258 0% $0 30.0% $894 $3,876 $6 SUBTOTAL 8. $39,958 $1,012 $12,312 $0 $53,282 $5,022 $0 $7,830 $66,134 $109 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,657 $0 $1,211 $0 $7,868 9.5% $749 0% $0 15.0% $1,293 $9,910 $16 9.2 Circulating Water Pumps $1,722 $0 $124 $0 $1,847 8.4% $156 0% $0 15.0% $300 $2,303 $4 9.3 Circ. Water System Auxiliaries $146 $0 $21 $0 $167 9.5% $16 0% $0 15.0% $27 $210 $0 9.4 Circ. Water Piping $0 $6,091 $1,579 $0 $7,670 9.0% $693 0% $0 20.0% $1,673 $10,036 $17 9.5 Make-up Water System $341 $0 $488 $0 $829 9.6% $80 0% $0 20.0% $182 $1,090 $2 9.6 Component Cooling Water System $719 $860 $612 $0 $2,191 9.4% $205 0% $0 20.0% $479 $2,875 $5 9.9 Circ. Water System Foundations $0 $2,236 $3,801 $0 $6,036 9.5% $572 0% $0 30.0% $1,983 $8,591 $14 SUBTOTAL 9. $9,586 $9,186 $7,836 $0 $26,608 $2,471 $0 $5,937 $35,016 $58 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 427Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 146 Case 2 D3A (25%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) x $1, 000 Plant Size: 607.02 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,758 $6,484 $13,171 $0 $31,413 9.7% $3,032 0% $0 10.0% $3,445 $37,890 $62 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $572 $0 $622 $0 $1,195 9.7% $116 0% $0 15.0% $197 $1,507 $2 10.7 Ash Transport & Feed Equipment $767 $0 $185 $0 $952 9.3% $89 0% $0 15.0% $156 $1,197 $2 10.8 Misc. Ash Handling Equipment $1,185 $1,452 $434 $0 $3,071 9.5% $292 0% $0 15.0% $504 $3,867 $6 10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $114 9.4% $11 0% $0 30.0% $37 $162 $0 SUBTOTAL 10. $14,282 $7,986 $14,476 $0 $36,745 $3,540 $0 $4,339 $44,624 $74 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $961 $0 $951 $0 $1,912 9.5% $183 0% $0 10.0% $209 $2,303 $4 11.2 Station Service Equipment $4,152 $0 $374 $0 $4,526 9.2% $417 0% $0 10.0% $494 $5,437 $9 11.3 Switchgear & Motor Control $7,676 $0 $1,396 $0 $9,071 9.3% $841 0% $0 15.0% $1,487 $11,400 $19 11.4 Conduit & Cable Tray $0 $3,566 $11,763 $0 $15,328 9.7% $1,483 0% $0 25.0% $4,203 $21,013 $35 11.5 Wire & Cable $0 $6,813 $4,476 $0 $11,289 7.3% $820 0% $0 25.0% $3,027 $15,136 $25 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $236 $0 $231 $0 $467 9.5% $45 0% $0 15.0% $77 $588 $1 11.8 Main Power Transformers $17,787 $0 $146 $0 $17,934 7.6% $1,356 0% $0 15.0% $2,894 $22,184 $37 11.9 Electrical Foundations $0 $159 $417 $0 $577 9.6% $55 0% $0 30.0% $190 $821 $1 SUBTOTAL 11. $30,812 $11,223 $22,250 $0 $64,285 $5,511 $0 $13,104 $82,900 $137 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,045 $0 $698 $0 $1,743 9.5% $165 5% $87 15.0% $299 $2,295 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $240 $0 $154 $0 $394 9.5% $37 5% $20 20.0% $90 $541 $1 12.7 Computer & Accessories $5,575 $0 $178 $0 $5,754 9.2% $528 5% $288 10.0% $657 $7,227 $12 12.8 Instrument Wiring & Tubing $0 $1,948 $3,982 $0 $5,929 8.5% $503 5% $296 25.0% $1,682 $8,411 $14 12.9 Other I & C Equipment $3,727 $0 $1,810 $0 $5,537 9.4% $521 5% $277 15.0% $950 $7,285 $12 SUBTOTAL 12. $10,588 $1,948 $6,822 $0 $19,357 $1,754 $968 $3,679 $25,758 $42 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 108 2,297 0 2,405 9.9% 239 0% 0 30.0% 793 3,437 6 13.2 Site Improvements 0 1,912 2,541 0 4,453 9.9% 439 0% 0 30.0% 1,468 6,359 10 13.3 Site Facilities 3,426 0 3,615 0 7,041 9.9% 694 0% 0 30.0% 2,321 10,056 17 SUBTOTAL 13. $3,426 $2,019 $8,453 $0 $13,899 $1,372 $0 $4,581 $19,852 $33 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 428Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 146 Case 2 D3A (25%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) x $1, 000 Plant Size: 607.02 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $263 $149 $0 $412 8.8% $36 0% $0 20.0% $90 $539 $1 14.2 Steam Turbine Building $0 $2,361 $3,363 $0 $5,724 9.2% $527 0% $0 15.0% $938 $7,189 $12 14.3 Administration Building $0 $875 $634 $0 $1,509 8.9% $134 0% $0 15.0% $247 $1,890 $3 14.4 Circulation Water Pumphouse $0 $156 $82 $0 $238 8.8% $21 0% $0 15.0% $39 $298 $0 14.5 Water Treatment Buildings $0 $521 $508 $0 $1,028 9.0% $93 0% $0 15.0% $168 $1,290 $2 14.6 Machine Shop $0 $448 $306 $0 $754 8.9% $67 0% $0 15.0% $123 $944 $2 14.7 Warehouse $0 $723 $467 $0 $1,189 8.9% $105 0% $0 15.0% $194 $1,489 $2 14.8 Other Buildings & Structures $0 $433 $337 $0 $770 8.9% $69 0% $0 20.0% $168 $1,007 $2 14.9 Waste Treating Building & Str. $0 $962 $1,838 $0 $2,799 9.3% $261 0% $0 20.0% $612 $3,672 $6 SUBTOTAL 14. $0 $6,740 $7,685 $0 $14,425 $1,313 $0 $2,578 $18,316 $30 Total Cost $670,759 $73,022 $271,243 $0 $1,015,024 $95,417 $55,953 $179,985 $1,346,380 $2,218
Owner's Costs Preproduction Costs 6 Months All Labor $12,719 $21 1 Month Maintenance Materials $2,756 $5 1 Month Non-fuel Consumables $273 $0 1 Month Waste Disposal $302 $0 25% of 1 Months Fuel Cost at 100% CF $1,613 $3 2% of TPC $26,928 $44
Total $44,590 $73 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,446 $22 0.5% of TPC (spare parts) $6,732 $11
Total $20,178 $33

Initial Cost for Catalyst and Chemicals $4,937 $8 Land $900 $1 Other Owner's Costs $201,957 $333

Financing Costs $36,352 $60 Total Overnight Costs (TOC) $1,655,294 $2,727 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,887,035 $3,109 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 429Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 147 Case 2 D3A Initial and Annual O&M Expenses

Case: Case 2 D3A - GEE IGCC w/ two WGS bypass (25% CO2 Capture) Plant Size (MWe): 607.02 Heat Rate (Btu/kWh): 8,894 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 3,127

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $10.401 Maintenance Labor Cost (calc'd) $14,036,245 $23.123 Administrative & Support Labor (calc'd) $5,087,438 $8.381 Property Taxes & Insurance $26,927,596 $44.360 TOTAL FIXED OPERATING COSTS $52,364,786 $86.266 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $26,460,253 0.00622

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,380 1.08 $0 $1,067,697 0.00025

Chemicals MU & WT Chem. (lbs) 0 20,139 0.17 $0 $1,017,765 0.00024 Carbon (Mercury Removal) (lb) 55,244 95 1.05 $58,016 $29,132 0.00001 COS Catalyst (m3) 417 0.29 2,397.36 $998,740 $199,748 0.00005 Water Gas Shift Catalyst (ft3) 16 0.01 498.83 $7,981 $1,596 0.00000 Selexol Solution (gal) 289,013 59 13.40 $3,872,261 $230,395 0.00005 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.92 131.27 $0 $73,424 0.00002 Subtotal Chemicals $4,936,998 $1,552,059 0.00036 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 95 0.42 $0 $11,651 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 609 16.23 $0 $2,886,704 0.00068 Subtotal Solid Waste Disposal $0 $2,898,355 $0
By-products & Emissions Sulfur (tons) 0 139 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $31,978,364 0.00752 Coal FUEL (tons) 0 5,553 38.19 $0 $61,920,722 0.01456 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 430Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 148 Case 2 D3B (45%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) x $1, 000 Plant Size: 590.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,667 $0 $1,792 $0 $5,460 9.0% $489 0% $0 20.0% $1,190 $7,139 $12 1.2 Coal Stackout & Reclaim $4,739 $0 $1,149 $0 $5,888 8.8% $516 0% $0 20.0% $1,281 $7,685 $13 1.3 Coal Conveyors & Yd Crus $4,406 $0 $1,137 $0 $5,543 8.8% $487 0% $0 20.0% $1,206 $7,236 $12 1.4 Other Coal Handling $1,153 $0 $263 $0 $1,416 8.8% $124 0% $0 20.0% $308 $1,848 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,595 $6,489 $0 $9,084 9.6% $871 0% $0 20.0% $1,991 $11,946 $20 SUBTOTAL 1. $13,966 $2,595 $10,830 $0 $27,391 $2,486 $0 $5,975 $35,853 $61 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,564 $374 $245 $0 $2,184 8.6% 187 0% 0 20.0% $474 $2,845 $5 2.3 Slurry Prep & Feed $21,388 $0 $9,440 $0 $30,828 9.1% 2,801 5% 1,541 20.0% $7,034 $42,204 $72 2.4 Misc. Coal Prep & Feed $860 $626 $1,877 $0 $3,363 9.2% 309 0% 0 20.0% $734 $4,406 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,343 $2,745 $0 $6,088 9.3% 564 0% 0 20.0% $1,330 $7,983 $14 SUBTOTAL 2. $23,812 $4,344 $14,307 $0 $42,463 $3,861 $1,541 $9,573 $57,438 $97 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,864 4,918 2,596 0 10,377 9.3% 961 0% 0 20.0% $2,268 $13,606 $23 3.2 Water Makeup & Pretreating 648 68 362 0 1,078 9.5% 103 0% 0 30.0% $354 $1,535 $3 3.3 Other Feedwater Subsystems 1,567 529 476 0 2,573 9.0% 231 0% 0 20.0% $561 $3,365 $6 3.4 Service Water Systems 371 764 2,650 0 3,785 9.8% 369 0% 0 30.0% $1,246 $5,400 $9 3.5 Other Boiler Plant Systems 1,990 771 1,911 0 4,672 9.5% 443 0% 0 20.0% $1,023 $6,138 $10 3.6 FO Supply Sys & Nat Gas $313 $590 $551 $0 1,454 9.6% 140 0% 0 20.0% $319 $1,913 $3 3.7 Waste Treatment Equipment 906 0 553 0 1,458 9.7% 142 0% 0 30.0% $480 $2,080 $4 3.8 Misc. Power Plant Equipment $1,111 $149 $571 $0 1,831 9.7% 177 0% 0 30.0% $602 $2,610 $4 SUBTOTAL 3. $9,769 $7,789 $9,670 $0 $27,227 $2,566 $0 $6,853 $36,647 $62 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $111,036 $0 $60,840 $0 $171,875 9.2% $15,745 13.9% $23,853 15.3% $32,426 $243,899 $413 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $188,280 $0 w/equip. $0 $188,280 9.7% $18,250 0% $0 10.0% $20,653 $227,183 $385 4.4 Scrubber & Low Temperature Cooling 5,899 $4,801 $4,997 $0 $15,698 9.6% $1,507 0% $0 20.0% $3,441 $20,646 $35 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,799 $854 $1,688 $0 $4,342 9.6% $418 0% $0 20.0% $952 $5,712 $10 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,325 $5,280 $0 $11,604 9.3% $1,075 0% $0 25.0% $3,170 $15,849 $27 SUBTOTAL 4. $307,014 $11,980 $72,805 $0 $391,799 $36,996 $23,853 $60,642 $513,290 $870 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 431Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 148 Case 2 D3B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) x $1, 000 Plant Size: 590.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $60,416 $0 $51,265 $0 $111,681 9.7% $10,801 20% $22,336 20.0% $28,964 $173,782 $295 5A.2 Elemental Sulfur Plant $10,086 $2,010 $13,013 $0 $25,110 9.7% $2,439 0% $0 20.0% $5,510 $33,058 $56 5A.3 Mercury Removal $1,159 $0 $882 $0 $2,041 9.7% $197 5% $102 20.0% $468 $2,808 $5 5A.4 Shift Reactors $4,761 $0 $1,917 $0 $6,677 9.6% $640 0% $0 20.0% $1,464 $8,781 $15 5A.5 COS Hydrolysis $2,778 $0 $3,627 $0 $6,405 9.7% $623 0% $0 20.0% $1,405 $8,433 $14 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,316 $0 $249 $0 $1,565 12.2% $191 0% $0 20.0% $351 $2,107 $4 5A.8 Fuel Gas Piping $0 $609 $427 $0 $1,036 9.3% $96 0% $0 20.0% $226 $1,358 $2 5A.9 HGCU Foundations $0 $624 $402 $0 $1,027 9.2% $94 0% $0 30.0% $336 $1,457 $2 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $80,516 $3,243 $71,782 $0 $155,541 $15,081 $22,438 $38,724 $231,785 $393 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $9,615 $0 $5,894 $0 $15,509 9.6% $1,494 0% $0 20.0% $3,401 $20,403 $35 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $9,615 $0 $5,894 $0 $15,509 $1,494 $0 $3,401 $20,403 $35 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 220 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 13 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $238 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,421 $0 $4,894 $0 $39,315 9.5% $3,738 0% $0 10.0% $4,305 $47,359 $80 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,717 $1,225 $0 $2,943 8.8% $258 0% $0 20.0% $640 $3,841 $7 7.4 Stack $3,350 $0 $1,259 $0 $4,609 9.6% $442 0% $0 10.0% $505 $5,555 $9 7.9 HRSG, Duct & Stack Foundations $0 $671 $645 $0 $1,316 9.3% $123 0% $0 30.0% $432 $1,870 $3 SUBTOTAL 7. $37,771 $2,389 $8,023 $0 $48,182 $4,560 $0 $5,882 $58,625 $99 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,111 $0 $4,977 $0 $34,088 9.6% $3,271 0% $0 10.0% $3,736 $41,095 $70 8.2 Turbine Plant Auxiliaries $202 $0 $463 $0 $664 9.8% $65 0% $0 10.0% $73 $802 $1 8.3 Condenser & Auxiliaries $5,226 $0 $1,534 $0 $6,761 9.6% $646 0% $0 10.0% $741 $8,148 $14 8.4 Steam Piping $5,056 $0 $3,557 $0 $8,613 8.6% $740 0% $0 25.0% $2,338 $11,691 $20 8.9 TG Foundations $0 $1,001 $1,692 $0 $2,693 9.5% $255 0% $0 30.0% $884 $3,832 $6 SUBTOTAL 8. $39,595 $1,001 $12,222 $0 $52,819 $4,977 $0 $7,772 $65,568 $111 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,825 $0 $1,242 $0 $8,067 9.5% $768 0% $0 15.0% $1,325 $10,160 $17 9.2 Circulating Water Pumps $1,767 $0 $128 $0 $1,895 8.4% $160 0% $0 15.0% $308 $2,363 $4 9.3 Circ. Water System Auxiliaries $149 $0 $21 $0 $170 9.5% $16 0% $0 15.0% $28 $215 $0 9.4 Circ. Water Piping $0 $6,223 $1,613 $0 $7,836 9.0% $708 0% $0 20.0% $1,709 $10,253 $17 9.5 Make-up Water System $356 $0 $509 $0 $865 9.6% $83 0% $0 20.0% $190 $1,138 $2 9.6 Component Cooling Water System $735 $879 $625 $0 $2,238 9.4% $210 0% $0 20.0% $490 $2,938 $5 9.9 Circ. Water System Foundations $0 $2,284 $3,883 $0 $6,167 9.5% $585 0% $0 30.0% $2,026 $8,777 $15 SUBTOTAL 9. $9,832 $9,385 $8,021 $0 $27,238 $2,530 $0 $6,075 $35,843 $61 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST

*



## 432Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 148 Ca se 2 D3B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) x $1, 000 Plant Size: 590.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,869 $6,545 $13,296 $0 $31,710 9.7% $3,061 0% $0 10.0% $3,477 $38,247 $65 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $577 $0 $628 $0 $1,205 9.7% $117 0% $0 15.0% $198 $1,520 $3 10.7 Ash Transport & Feed Equipment $774 $0 $187 $0 $961 9.3% $90 0% $0 15.0% $158 $1,208 $2 10.8 Misc. Ash Handling Equipment $1,195 $1,464 $437 $0 $3,097 9.5% $295 0% $0 15.0% $509 $3,900 $7 10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $115 9.4% $11 0% $0 30.0% $38 $164 $0 SUBTOTAL 10. $14,415 $8,060 $14,612 $0 $37,087 $3,573 $0 $4,379 $45,039 $76 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $958 $0 $947 $0 $1,905 9.5% $182 0% $0 10.0% $209 $2,295 $4 11.2 Station Service Equipment $4,308 $0 $388 $0 $4,696 9.2% $433 0% $0 10.0% $513 $5,642 $10 11.3 Switchgear & Motor Control $7,964 $0 $1,448 $0 $9,412 9.3% $873 0% $0 15.0% $1,543 $11,828 $20 11.4 Conduit & Cable Tray $0 $3,700 $12,205 $0 $15,904 9.7% $1,538 0% $0 25.0% $4,361 $21,803 $37 11.5 Wire & Cable $0 $7,069 $4,644 $0 $11,713 7.3% $851 0% $0 25.0% $3,141 $15,705 $27 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $236 $0 $230 $0 $466 9.5% $44 0% $0 15.0% $76 $586 $1 11.8 Main Power Transformers $17,714 $0 $146 $0 $17,860 7.6% $1,351 0% $0 15.0% $2,882 $22,093 $37 11.9 Electrical Foundations $0 $158 $416 $0 $574 9.6% $55 0% $0 30.0% $189 $818 $1 SUBTOTAL 11. $31,180 $11,613 $22,920 $0 $65,712 $5,638 $0 $13,437 $84,787 $144 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,069 $0 $714 $0 $1,782 9.5% $169 5% $89 15.0% $306 $2,346 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $246 $0 $157 $0 $403 9.5% $38 5% $20 20.0% $92 $554 $1 12.7 Computer & Accessories $5,700 $0 $183 $0 $5,883 9.2% $540 5% $294 10.0% $672 $7,389 $13 12.8 Instrument Wiring & Tubing $0 $1,991 $4,071 $0 $6,062 8.5% $514 5% $303 25.0% $1,720 $8,600 $15 12.9 Other I & C Equipment $3,811 $0 $1,850 $0 $5,661 9.4% $533 5% $283 15.0% $971 $7,448 $13 SUBTOTAL 12. $10,825 $1,991 $6,975 $0 $19,791 $1,794 $990 $3,761 $26,336 $45 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 108 2,312 0 2,420 9.9% 240 0% 0 30.0% 798 3,458 6 13.2 Site Improvements 0 1,924 2,556 0 4,480 9.9% 442 0% 0 30.0% 1,477 6,399 11 13.3 Site Facilities 3,447 0 3,638 0 7,085 9.9% 698 0% 0 30.0% 2,335 10,118 17 SUBTOTAL 13. $3,447 $2,032 $8,506 $0 $13,985 $1,380 $0 $4,610 $19,975 $34 Acct No. Item/Description Equipment Cost Material Cost Project Cont. Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST



## 433Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 148 Case 2 D3B (45%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) x $1, 000 Plant Size: 590.05 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $264 $149 $0 $413 8.8% $36 0% $0 20.0% $90 $539 $1 14.2 Steam Turbine Building $0 $2,367 $3,372 $0 $5,738 9.2% $528 0% $0 15.0% $940 $7,206 $12 14.3 Administration Building $0 $877 $636 $0 $1,514 8.9% $135 0% $0 15.0% $247 $1,896 $3 14.4 Circulation Water Pumphouse $0 $159 $84 $0 $243 8.8% $21 0% $0 15.0% $40 $304 $1 14.5 Water Treatment Buildings $0 $546 $532 $0 $1,078 9.0% $97 0% $0 15.0% $176 $1,351 $2 14.6 Machine Shop $0 $449 $307 $0 $756 8.9% $67 0% $0 15.0% $124 $947 $2 14.7 Warehouse $0 $725 $468 $0 $1,193 8.9% $106 0% $0 15.0% $195 $1,493 $3 14.8 Other Buildings & Structures $0 $434 $338 $0 $772 8.9% $69 0% $0 20.0% $168 $1,010 $2 14.9 Waste Treating Building & Str. $0 $966 $1,847 $0 $2,813 9.3% $262 0% $0 20.0% $615 $3,690 $6 SUBTOTAL 14. $0 $6,787 $7,734 $0 $14,521 $1,322 $0 $2,595 $18,437 $31 Total Cost $689,332 $74,096 $282,632 $0 $1,046,059 $98,381 $58,683 $187,111 $1,390,235 $2,356
Owner's Costs Preproduction Costs 6 Months All Labor $12,987 $22 1 Month Maintenance Materials $2,841 $5 1 Month Non-fuel Consumables $311 $1 1 Month Waste Disposal $307 $1 25% of 1 Months Fuel Cost at 100% CF $1,637 $3 2% of TPC $27,805 $47
Total $45,887 $78 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,720 $23 0.5% of TPC (spare parts) $6,951 $12
Total $20,671 $35

Initial Cost for Catalyst and Chemicals $5,828 $10 Land $900 $2 Other Owner's Costs $208,535 $353

Financing Costs $37,536 $64 Total Overnight Costs (TOC) $1,709,592 $2,897 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,948,935 $3,303 Labor Bare Erected Eng'g CM H.O. & Process Cont. TOTAL PLANT COST Acct No. Item/Description Equipment Cost Material Cost Project Cont.



## 434Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 149 Case 2 D3B Initial and Annual O&M Expenses

Case: Case 2 D3B - GEE IGCC w/ two WGS bypass (45% CO2 Capture) Plant Size (MWe): 590.05 Heat Rate (Btu/kWh): 9,289 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 5,732

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $10.700 Maintenance Labor Cost (calc'd) $14,465,416 $24.516 Administrative & Support Labor (calc'd) $5,194,731 $8.804 Property Taxes & Insurance $27,804,693 $47.123 TOTAL FIXED OPERATING COSTS $53,778,347 $91.142 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $27,269,300 0.00659

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,629 1.08 $0 $1,146,154 0.00028

Chemicals MU & WT Chem. (lbs) 0 21,619 0.17 $0 $1,092,552 0.00026 Carbon (Mercury Removal) (lb) 62,427 107 1.05 $65,559 $32,812 0.00001 COS Catalyst (m3) 294 0.20 2,397.36 $705,303 $141,061 0.00003 Water Gas Shift Catalyst (ft3) 2,296 1.57 498.83 $1,145,316 $229,063 0.00006 Selexol Solution (gal) 291,937 70 13.40 $3,911,435 $273,860 0.00007 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.94 131.27 $0 $74,521 0.00002 Subtotal Chemicals $5,827,613 $1,843,868 0.00045 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 107 0.42 $0 $13,122 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 619 16.23 $0 $2,930,765 0.00071 Subtotal Solid Waste Disposal $0 $2,943,888 $0
By-products & Emissions Sulfur (tons) 0 141 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $33,203,210 0.00803 Coal FUEL (tons) 0 5,638 38.19 $0 $62,865,489 0.01520 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 435Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 150 Case 2 D3C (60%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) x $1, 000 Plant Size: 577.43 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,697 $0 $1,806 $0 $5,503 9.0% $493 0% $0 20.0% $1,199 $7,195 $12 1.2 Coal Stackout & Reclaim $4,777 $0 $1,158 $0 $5,935 8.8% $520 0% $0 20.0% $1,291 $7,746 $13 1.3 Coal Conveyors & Yd Crus $4,441 $0 $1,146 $0 $5,587 8.8% $490 0% $0 20.0% $1,215 $7,293 $13 1.4 Other Coal Handling $1,162 $0 $265 $0 $1,427 8.8% $125 0% $0 20.0% $310 $1,862 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,616 $6,541 $0 $9,157 9.6% $878 0% $0 20.0% $2,007 $12,041 $21 SUBTOTAL 1. $14,076 $2,616 $10,916 $0 $27,608 $2,506 $0 $6,023 $36,137 $63 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,577 $377 $247 $0 $2,202 8.6% 188 0% 0 20.0% $478 $2,869 $5 2.3 Slurry Prep & Feed $21,571 $0 $9,520 $0 $31,091 9.1% 2,825 5% 1,555 20.0% $7,094 $42,564 $74 2.4 Misc. Coal Prep & Feed $867 $631 $1,893 $0 $3,391 9.2% 312 0% 0 20.0% $741 $4,443 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,372 $2,768 $0 $6,140 9.3% 569 0% 0 20.0% $1,342 $8,050 $14 SUBTOTAL 2. $24,016 $4,380 $14,428 $0 $42,824 $3,893 $1,555 $9,654 $57,926 $100 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,848 4,891 2,582 0 10,321 9.3% 956 0% 0 20.0% $2,255 $13,533 $23 3.2 Water Makeup & Pretreating 672 70 376 0 1,118 9.5% 106 0% 0 30.0% $367 $1,592 $3 3.3 Other Feedwater Subsystems 1,558 527 474 0 2,559 9.0% 230 0% 0 20.0% $558 $3,346 $6 3.4 Service Water Systems 385 792 2,749 0 3,926 9.8% 383 0% 0 30.0% $1,293 $5,601 $10 3.5 Other Boiler Plant Systems 2,064 800 1,982 0 4,846 9.5% 460 0% 0 20.0% $1,061 $6,367 $11 3.6 FO Supply Sys & Nat Gas $314 $592 $552 $0 1,458 9.6% 140 0% 0 20.0% $320 $1,919 $3 3.7 Waste Treatment Equipment 940 0 573 0 1,513 9.7% 147 0% 0 30.0% $498 $2,158 $4 3.8 Misc. Power Plant Equipment $1,115 $149 $573 $0 1,837 9.7% 177 0% 0 30.0% $604 $2,618 $5 SUBTOTAL 3. $9,896 $7,821 $9,861 $0 $27,578 $2,601 $0 $6,956 $37,135 $64 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $112,030 $0 $61,384 $0 $173,415 9.2% $15,886 13.9% $24,066 15.3% $32,716 $246,084 $426 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $189,980 $0 w/equip. $0 $189,980 9.7% $18,415 0% $0 10.0% $20,839 $229,234 $397 4.4 Scrubber & Low Temperature Cooling 5,952 $4,844 $5,042 $0 $15,838 9.6% $1,521 0% $0 20.0% $3,472 $20,831 $36 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,815 $862 $1,704 $0 $4,381 9.6% $422 0% $0 20.0% $961 $5,763 $10 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,381 $5,327 $0 $11,708 9.3% $1,085 0% $0 25.0% $3,198 $15,991 $28 SUBTOTAL 4. $309,777 $12,088 $73,457 $0 $395,322 $37,329 $24,066 $61,187 $517,904 $897 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 436Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 150 Case 2 D3C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) x $1, 000 Plant Size: 577.43 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $64,608 $0 $54,821 $0 $119,429 9.7% $11,550 20% $23,886 20.0% $30,973 $185,838 $322 5A.2 Elemental Sulfur Plant $10,171 $2,027 $13,123 $0 $25,321 9.7% $2,460 0% $0 20.0% $5,556 $33,337 $58 5A.3 Mercury Removal $1,235 $0 $940 $0 $2,175 9.7% $210 5% $109 20.0% $499 $2,992 $5 5A.4 Shift Reactors $7,237 $0 $2,913 $0 $10,150 9.6% $973 0% $0 20.0% $2,225 $13,348 $23 5A.5 COS Hydrolysis $2,070 $0 $2,703 $0 $4,773 9.7% $464 0% $0 20.0% $1,047 $6,284 $11 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,328 $0 $252 $0 $1,579 12.2% $193 0% $0 20.0% $354 $2,126 $4 5A.8 Fuel Gas Piping $0 $620 $434 $0 $1,054 9.3% $98 0% $0 20.0% $230 $1,382 $2 5A.9 HGCU Foundations $0 $630 $406 $0 $1,037 9.2% $95 0% $0 30.0% $340 $1,472 $3 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $86,648 $3,277 $75,592 $0 $165,518 $16,043 $23,995 $41,224 $246,779 $427 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $12,507 $0 $7,666 $0 $20,173 9.6% $1,943 0% $0 20.0% $4,423 $26,540 $46 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $12,507 $0 $7,666 $0 $20,173 $1,943 $0 $4,423 $26,540 $46 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 224 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $243 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,172 $0 $4,859 $0 $39,031 9.5% $3,711 0% $0 10.0% $4,274 $47,017 $81 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,721 $1,228 $0 $2,949 8.8% $259 0% $0 20.0% $642 $3,850 $7 7.4 Stack $3,358 $0 $1,262 $0 $4,620 9.6% $443 0% $0 10.0% $506 $5,568 $10 7.9 HRSG, Duct & Stack Foundations $0 $673 $646 $0 $1,319 9.3% $123 0% $0 30.0% $433 $1,874 $3 SUBTOTAL 7. $37,530 $2,394 $7,995 $0 $47,919 $4,535 $0 $5,855 $58,309 $101 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,939 $0 $4,947 $0 $33,887 9.6% $3,251 0% $0 10.0% $3,714 $40,852 $71 8.2 Turbine Plant Auxiliaries $201 $0 $460 $0 $661 9.8% $65 0% $0 10.0% $73 $798 $1 8.3 Condenser & Auxiliaries $5,178 $0 $1,520 $0 $6,699 9.6% $640 0% $0 10.0% $734 $8,073 $14 8.4 Steam Piping $5,029 $0 $3,537 $0 $8,566 8.6% $736 0% $0 25.0% $2,325 $11,627 $20 8.9 TG Foundations $0 $995 $1,682 $0 $2,677 9.5% $254 0% $0 30.0% $879 $3,810 $7 SUBTOTAL 8. $39,347 $995 $12,147 $0 $52,489 $4,946 $0 $7,725 $65,160 $113 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,950 $0 $1,264 $0 $8,214 9.5% $782 0% $0 15.0% $1,349 $10,346 $18 9.2 Circulating Water Pumps $1,800 $0 $130 $0 $1,931 8.4% $163 0% $0 15.0% $314 $2,408 $4 9.3 Circ. Water System Auxiliaries $151 $0 $22 $0 $173 9.5% $16 0% $0 15.0% $28 $218 $0 9.4 Circ. Water Piping $0 $6,320 $1,639 $0 $7,959 9.0% $719 0% $0 20.0% $1,736 $10,414 $18 9.5 Make-up Water System $367 $0 $525 $0 $892 9.6% $86 0% $0 20.0% $196 $1,174 $2 9.6 Component Cooling Water System $746 $892 $635 $0 $2,273 9.4% $213 0% $0 20.0% $497 $2,984 $5 9.9 Circ. Water System Foundations $0 $2,320 $3,944 $0 $6,264 9.5% $594 0% $0 30.0% $2,057 $8,915 $15 SUBTOTAL 9. $10,015 $9,533 $8,159 $0 $27,706 $2,573 $0 $6,178 $36,458 $63 * Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 437Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 150 Case 2 D3C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) x $1, 000 Plant Size: 577.43 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,963 $6,597 $13,401 $0 $31,961 9.7% $3,085 0% $0 10.0% $3,505 $38,551 $67 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $581 $0 $632 $0 $1,213 9.7% $118 0% $0 15.0% $200 $1,531 $3 10.7 Ash Transport & Feed Equipment $779 $0 $188 $0 $967 9.3% $90 0% $0 15.0% $159 $1,216 $2 10.8 Misc. Ash Handling Equipment $1,204 $1,475 $441 $0 $3,119 9.5% $297 0% $0 15.0% $512 $3,928 $7 10.9 Ash/Spent Sorbent Foundation $0 $51 $65 $0 $116 9.4% $11 0% $0 30.0% $38 $165 $0 SUBTOTAL 10. $14,527 $8,123 $14,727 $0 $37,377 $3,600 $0 $4,413 $45,391 $79 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $956 $0 $945 $0 $1,901 9.5% $182 0% $0 10.0% $208 $2,291 $4 11.2 Station Service Equipment $4,432 $0 $399 $0 $4,832 9.2% $445 0% $0 10.0% $528 $5,805 $10 11.3 Switchgear & Motor Control $8,194 $0 $1,490 $0 $9,684 9.3% $898 0% $0 15.0% $1,587 $12,170 $21 11.4 Conduit & Cable Tray $0 $3,806 $12,557 $0 $16,363 9.7% $1,583 0% $0 25.0% $4,487 $22,433 $39 11.5 Wire & Cable $0 $7,273 $4,779 $0 $12,051 7.3% $875 0% $0 25.0% $3,232 $16,158 $28 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $235 $0 $230 $0 $465 9.5% $44 0% $0 15.0% $76 $586 $1 11.8 Main Power Transformers $17,677 $0 $145 $0 $17,822 7.6% $1,348 0% $0 15.0% $2,876 $22,046 $38 11.9 Electrical Foundations $0 $158 $415 $0 $573 9.6% $55 0% $0 30.0% $188 $816 $1 SUBTOTAL 11. $31,494 $11,923 $23,456 $0 $66,874 $5,741 $0 $13,706 $86,321 $149 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,087 $0 $726 $0 $1,813 9.5% $172 5% $91 15.0% $311 $2,386 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $250 $0 $160 $0 $410 9.5% $39 5% $21 20.0% $94 $563 $1 12.7 Computer & Accessories $5,799 $0 $186 $0 $5,985 9.2% $549 5% $299 10.0% $683 $7,516 $13 12.8 Instrument Wiring & Tubing $0 $2,026 $4,141 $0 $6,167 8.5% $523 5% $308 25.0% $1,750 $8,748 $15 12.9 Other I & C Equipment $3,876 $0 $1,882 $0 $5,759 9.4% $542 5% $288 15.0% $988 $7,577 $13 SUBTOTAL 12. $11,012 $2,026 $7,095 $0 $20,133 $1,825 $1,007 $3,826 $26,791 $46 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 109 2,321 0 2,430 9.9% 241 0% 0 30.0% 801 3,472 6 13.2 Site Improvements 0 1,931 2,567 0 4,498 9.9% 444 0% 0 30.0% 1,483 6,424 11 13.3 Site Facilities 3,461 0 3,652 0 7,113 9.9% 701 0% 0 30.0% 2,344 10,159 18 SUBTOTAL 13. $3,461 $2,040 $8,540 $0 $14,041 $1,386 $0 $4,628 $20,055 $35 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 438Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 150 Case 2 D3C (60%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) x $1, 000 Plant Size: 577.43 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $264 $149 $0 $414 8.8% $36 0% $0 20.0% $90 $540 $1 14.2 Steam Turbine Building $0 $2,371 $3,377 $0 $5,748 9.2% $529 0% $0 15.0% $941 $7,218 $13 14.3 Administration Building $0 $879 $638 $0 $1,517 8.9% $135 0% $0 15.0% $248 $1,900 $3 14.4 Circulation Water Pumphouse $0 $161 $86 $0 $247 8.8% $22 0% $0 15.0% $40 $309 $1 14.5 Water Treatment Buildings $0 $564 $551 $0 $1,115 9.0% $101 0% $0 15.0% $182 $1,398 $2 14.6 Machine Shop $0 $450 $308 $0 $758 8.9% $67 0% $0 15.0% $124 $949 $2 14.7 Warehouse $0 $726 $469 $0 $1,195 8.9% $106 0% $0 15.0% $195 $1,496 $3 14.8 Other Buildings & Structures $0 $435 $339 $0 $774 8.9% $69 0% $0 20.0% $169 $1,012 $2 14.9 Waste Treating Building & Str. $0 $970 $1,853 $0 $2,823 9.3% $263 0% $0 20.0% $617 $3,704 $6 SUBTOTAL 14. $0 $6,821 $7,770 $0 $14,590 $1,328 $0 $2,607 $18,525 $32 Total Cost $701,883 $74,924 $290,140 $0 $1,066,947 $100,373 $60,483 $191,838 $1,419,640 $2,459
Owner's Costs Preproduction Costs 6 Months All Labor $13,167 $23 1 Month Maintenance Materials $2,897 $5 1 Month Non-fuel Consumables $342 $1 1 Month Waste Disposal $311 $1 25% of 1 Months Fuel Cost at 100% CF $1,658 $3 2% of TPC $28,393 $49
Total $46,768 $81 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,949 $24 0.5% of TPC (spare parts) $7,098 $12
Total $21,047 $36

Initial Cost for Catalyst and Chemicals $6,559 $11 Land $900 $2 Other Owner's Costs $212,946 $369

Financing Costs $38,330 $66 Total Overnight Costs (TOC) $1,746,192 $3,024 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,990,658 $3,447 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected



## 439Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 151 Case 2 D3C Initial and Annual O&M Expenses

Case: Case 2 D3C - GEE IGCC w/ two WGS bypass (60% CO2 Capture) Plant Size (MWe): 577.43 Heat Rate (Btu/kWh): 9,614 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 7,796

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $10.934 Maintenance Labor Cost (calc'd) $14,754,262 $25.552 Administrative & Support Labor (calc'd) $5,266,942 $9.121 Property Taxes & Insurance $28,392,808 $49.171 TOTAL FIXED OPERATING COSTS $54,727,519 $94.778 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $27,813,813 0.00687

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 3,821 1.08 $0 $1,206,873 0.00030

Chemicals MU & WT Chem. (lbs) 0 22,765 0.17 $0 $1,150,432 0.00028 Carbon (Mercury Removal) (lb) 68,360 117 1.05 $71,790 $35,878 0.00001 COS Catalyst (m3) 193 0.13 2,397.36 $463,410 $92,682 0.00002 Water Gas Shift Catalyst (ft3) 4,176 2.86 498.83 $2,083,118 $416,624 0.00010 Selexol Solution (gal) 294,129 78 13.40 $3,940,815 $306,332 0.00008 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.97 131.27 $0 $75,459 0.00002 Subtotal Chemicals $6,559,132 $2,077,406 0.00051 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 117 0.42 $0 $14,349 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 627 16.23 $0 $2,968,345 0.00073 Subtotal Solid Waste Disposal $0 $2,982,694 $0
By-products & Emissions Sulfur (tons) 0 143 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $34,080,786 0.00842 Coal FUEL (tons) 0 5,710 38.19 $0 $63,671,371 0.01573 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 440Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 152 Case 2 D3D (75%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) x $1, 000 Plant Size: 563.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,725 $0 $1,820 $0 $5,545 9.0% $497 0% $0 20.0% $1,208 $7,250 $13 1.2 Coal Stackout & Reclaim $4,813 $0 $1,167 $0 $5,980 8.8% $524 0% $0 20.0% $1,301 $7,805 $14 1.3 Coal Conveyors & Yd Crus $4,475 $0 $1,155 $0 $5,630 8.8% $494 0% $0 20.0% $1,225 $7,349 $13 1.4 Other Coal Handling $1,171 $0 $267 $0 $1,438 8.8% $126 0% $0 20.0% $313 $1,877 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,636 $6,591 $0 $9,227 9.6% $884 0% $0 20.0% $2,022 $12,134 $22 SUBTOTAL 1. $14,184 $2,636 $11,000 $0 $27,820 $2,525 $0 $6,069 $36,415 $65 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,590 $381 $249 $0 $2,220 8.6% 190 0% 0 20.0% $482 $2,892 $5 2.3 Slurry Prep & Feed $21,750 $0 $9,598 $0 $31,348 9.1% 2,848 5% 1,567 20.0% $7,153 $42,916 $76 2.4 Misc. Coal Prep & Feed $874 $636 $1,908 $0 $3,419 9.2% 314 0% 0 20.0% $747 $4,480 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,399 $2,791 $0 $6,190 9.3% 573 0% 0 20.0% $1,353 $8,116 $14 SUBTOTAL 2. $24,215 $4,416 $14,546 $0 $43,177 $3,925 $1,567 $9,734 $58,404 $104 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,832 4,863 2,567 0 10,262 9.3% 951 0% 0 20.0% $2,243 $13,456 $24 3.2 Water Makeup & Pretreating 696 73 389 0 1,157 9.5% 110 0% 0 30.0% $380 $1,647 $3 3.3 Other Feedwater Subsystems 1,549 524 471 0 2,544 9.0% 229 0% 0 20.0% $555 $3,327 $6 3.4 Service Water Systems 398 820 2,845 0 4,062 9.8% 396 0% 0 30.0% $1,338 $5,796 $10 3.5 Other Boiler Plant Systems 2,136 828 2,051 0 5,015 9.5% 476 0% 0 20.0% $1,098 $6,589 $12 3.6 FO Supply Sys & Nat Gas $315 $594 $554 $0 1,463 9.6% 141 0% 0 20.0% $321 $1,925 $3 3.7 Waste Treatment Equipment 972 0 593 0 1,565 9.7% 152 0% 0 30.0% $515 $2,233 $4 3.8 Misc. Power Plant Equipment $1,118 $150 $574 $0 1,842 9.7% 178 0% 0 30.0% $606 $2,626 $5 SUBTOTAL 3. $10,016 $7,851 $10,045 $0 $27,912 $2,633 $0 $7,055 $37,600 $67 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,003 $0 $61,917 $0 $174,920 9.2% $16,024 13.9% $24,275 15.3% $33,000 $248,220 $440 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $191,589 $0 w/equip. $0 $191,589 9.7% $18,571 0% $0 10.0% $21,016 $231,175 $410 4.4 Scrubber & Low Temperature Cooling 6,004 $4,886 $5,086 $0 $15,976 9.6% $1,534 0% $0 20.0% $3,502 $21,012 $37 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,831 $869 $1,718 $0 $4,419 9.6% $426 0% $0 20.0% $969 $5,813 $10 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,437 $5,373 $0 $11,810 9.3% $1,094 0% $0 25.0% $3,226 $16,130 $29 SUBTOTAL 4. $312,426 $12,192 $74,095 $0 $398,713 $37,649 $24,275 $61,713 $522,350 $926 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 441Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 152 Case 2 D3D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) x $1, 000 Plant Size: 563.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $68,896 $0 $58,460 $0 $127,356 9.7% $12,317 20% $25,471 20.0% $33,029 $198,173 $351 5A.2 Elemental Sulfur Plant $10,254 $2,044 $13,230 $0 $25,527 9.7% $2,480 0% $0 20.0% $5,601 $33,608 $60 5A.3 Mercury Removal $1,309 $0 $996 $0 $2,305 9.7% $223 5% $115 20.0% $529 $3,172 $6 5A.4 Shift Reactors $9,410 $0 $3,788 $0 $13,198 9.6% $1,265 0% $0 20.0% $2,893 $17,356 $31 5A.5 COS Hydrolysis $1,225 $0 $1,600 $0 $2,825 9.7% $275 0% $0 20.0% $620 $3,720 $7 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,339 $0 $254 $0 $1,593 12.2% $194 0% $0 20.0% $357 $2,145 $4 5A.8 Fuel Gas Piping $0 $630 $441 $0 $1,071 9.3% $99 0% $0 20.0% $234 $1,404 $2 5A.9 HGCU Foundations $0 $636 $410 $0 $1,047 9.2% $96 0% $0 30.0% $343 $1,486 $3 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $92,433 $3,310 $79,179 $0 $174,922 $16,949 $25,586 $43,606 $261,063 $463 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $15,364 $0 $9,418 $0 $24,782 9.6% $2,387 0% $0 20.0% $5,434 $32,603 $58 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $15,364 $0 $9,418 $0 $24,782 $2,387 $0 $5,434 $32,603 $58 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 230 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $249 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,910 $0 $4,822 $0 $38,732 9.5% $3,683 0% $0 10.0% $4,241 $46,656 $83 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,726 $1,231 $0 $2,957 8.8% $259 0% $0 20.0% $643 $3,860 $7 7.4 Stack $3,367 $0 $1,265 $0 $4,632 9.6% $444 0% $0 10.0% $508 $5,583 $10 7.9 HRSG, Duct & Stack Foundations $0 $675 $648 $0 $1,322 9.3% $123 0% $0 30.0% $434 $1,879 $3 SUBTOTAL 7. $37,277 $2,401 $7,966 $0 $47,643 $4,509 $0 $5,826 $57,978 $103 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,728 $0 $4,911 $0 $33,640 9.6% $3,228 0% $0 10.0% $3,687 $40,554 $72 8.2 Turbine Plant Auxiliaries $199 $0 $457 $0 $656 9.8% $64 0% $0 10.0% $72 $792 $1 8.3 Condenser & Auxiliaries $5,130 $0 $1,506 $0 $6,636 9.6% $634 0% $0 10.0% $727 $7,998 $14 8.4 Steam Piping $5,000 $0 $3,517 $0 $8,517 8.6% $732 0% $0 25.0% $2,312 $11,560 $21 8.9 TG Foundations $0 $988 $1,670 $0 $2,658 9.5% $252 0% $0 30.0% $873 $3,783 $7 SUBTOTAL 8. $39,057 $988 $12,061 $0 $52,106 $4,910 $0 $7,671 $64,687 $115 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,053 $0 $1,283 $0 $8,336 9.5% $794 0% $0 15.0% $1,369 $10,499 $19 9.2 Circulating Water Pumps $1,834 $0 $132 $0 $1,966 8.4% $166 0% $0 15.0% $320 $2,452 $4 9.3 Circ. Water System Auxiliaries $154 $0 $22 $0 $176 9.5% $17 0% $0 15.0% $29 $221 $0 9.4 Circ. Water Piping $0 $6,417 $1,664 $0 $8,081 9.0% $730 0% $0 20.0% $1,762 $10,573 $19 9.5 Make-up Water System $378 $0 $540 $0 $919 9.6% $88 0% $0 20.0% $201 $1,208 $2 9.6 Component Cooling Water System $758 $906 $645 $0 $2,308 9.4% $216 0% $0 20.0% $505 $3,029 $5 9.9 Circ. Water System Foundations $0 $2,356 $4,004 $0 $6,360 9.5% $603 0% $0 30.0% $2,089 $9,052 $16 SUBTOTAL 9. $10,176 $9,679 $8,291 $0 $28,145 $2,614 $0 $6,275 $37,035 $66 * Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 442Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 152 Case 2 D3D (75%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) x $1, 000 Plant Size: 563.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,055 $6,647 $13,504 $0 $32,207 9.7% $3,108 0% $0 10.0% $3,532 $38,847 $69 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $585 $0 $637 $0 $1,222 9.7% $119 0% $0 15.0% $201 $1,541 $3 10.7 Ash Transport & Feed Equipment $785 $0 $189 $0 $974 9.3% $91 0% $0 15.0% $160 $1,225 $2 10.8 Misc. Ash Handling Equipment $1,212 $1,485 $444 $0 $3,141 9.5% $299 0% $0 15.0% $516 $3,956 $7 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $166 $0 SUBTOTAL 10. $14,637 $8,184 $14,839 $0 $37,660 $3,628 $0 $4,447 $45,734 $81 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $954 $0 $943 $0 $1,897 9.5% $181 0% $0 10.0% $208 $2,286 $4 11.2 Station Service Equipment $4,557 $0 $411 $0 $4,967 9.2% $458 0% $0 10.0% $543 $5,968 $11 11.3 Switchgear & Motor Control $8,424 $0 $1,532 $0 $9,956 9.3% $923 0% $0 15.0% $1,632 $12,511 $22 11.4 Conduit & Cable Tray $0 $3,913 $12,910 $0 $16,823 9.7% $1,627 0% $0 25.0% $4,612 $23,062 $41 11.5 Wire & Cable $0 $7,477 $4,913 $0 $12,390 7.3% $900 0% $0 25.0% $3,322 $16,612 $29 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $235 $0 $229 $0 $464 9.5% $44 0% $0 15.0% $76 $585 $1 11.8 Main Power Transformers $17,631 $0 $145 $0 $17,776 7.6% $1,344 0% $0 15.0% $2,868 $21,989 $39 11.9 Electrical Foundations $0 $158 $414 $0 $571 9.6% $55 0% $0 30.0% $188 $814 $1 SUBTOTAL 11. $31,800 $12,234 $23,992 $0 $68,026 $5,844 $0 $13,973 $87,842 $156 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,105 $0 $738 $0 $1,843 9.5% $175 5% $92 15.0% $317 $2,427 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $254 $0 $163 $0 $417 9.5% $39 5% $21 20.0% $95 $573 $1 12.7 Computer & Accessories $5,896 $0 $189 $0 $6,085 9.2% $559 5% $304 10.0% $695 $7,642 $14 12.8 Instrument Wiring & Tubing $0 $2,060 $4,211 $0 $6,271 8.5% $532 5% $314 25.0% $1,779 $8,895 $16 12.9 Other I & C Equipment $3,941 $0 $1,914 $0 $5,855 9.4% $551 5% $293 15.0% $1,005 $7,704 $14 SUBTOTAL 12. $11,197 $2,060 $7,214 $0 $20,471 $1,855 $1,024 $3,891 $27,240 $48 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 109 2,330 0 2,439 9.9% 242 0% 0 30.0% 804 3,485 6 13.2 Site Improvements 0 1,939 2,576 0 4,515 9.9% 445 0% 0 30.0% 1,488 6,449 11 13.3 Site Facilities 3,474 0 3,666 0 7,140 9.9% 704 0% 0 30.0% 2,353 10,197 18 SUBTOTAL 13. $3,474 $2,048 $8,572 $0 $14,095 $1,391 $0 $4,646 $20,132 $36 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 443Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 152 Case 2 D3D (75%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) x $1, 000 Plant Size: 563.80 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $264 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $540 $1 14.2 Steam Turbine Building $0 $2,374 $3,382 $0 $5,756 9.2% $530 0% $0 15.0% $943 $7,229 $13 14.3 Administration Building $0 $881 $639 $0 $1,520 8.9% $135 0% $0 15.0% $248 $1,903 $3 14.4 Circulation Water Pumphouse $0 $164 $87 $0 $251 8.8% $22 0% $0 15.0% $41 $314 $1 14.5 Water Treatment Buildings $0 $583 $568 $0 $1,151 9.0% $104 0% $0 15.0% $188 $1,443 $3 14.6 Machine Shop $0 $451 $308 $0 $759 8.9% $67 0% $0 15.0% $124 $951 $2 14.7 Warehouse $0 $728 $470 $0 $1,198 8.9% $106 0% $0 15.0% $196 $1,499 $3 14.8 Other Buildings & Structures $0 $436 $339 $0 $775 8.9% $69 0% $0 20.0% $169 $1,014 $2 14.9 Waste Treating Building & Str. $0 $973 $1,860 $0 $2,833 9.3% $264 0% $0 20.0% $619 $3,716 $7 SUBTOTAL 14. $0 $6,853 $7,804 $0 $14,657 $1,334 $0 $2,618 $18,609 $33 Total Cost $713,833 $75,738 $297,352 $0 $1,086,924 $102,277 $62,313 $196,390 $1,447,904 $2,568
Owner's Costs Preproduction Costs 6 Months All Labor $13,340 $24 1 Month Maintenance Materials $2,952 $5 1 Month Non-fuel Consumables $373 $1 1 Month Waste Disposal $315 $1 25% of 1 Months Fuel Cost at 100% CF $1,679 $3 2% of TPC $28,958 $51
Total $47,616 $84 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,175 $25 0.5% of TPC (spare parts) $7,240 $13
Total $21,415 $38

Initial Cost for Catalyst and Chemicals $7,298 $13 Land $900 $2 Other Owner's Costs $217,186 $385

Financing Costs $39,093 $69 Total Overnight Costs (TOC) $1,781,411 $3,160 TASC Multiplier (IOU, high risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,030,809 $3,602 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected



## 444Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 153 Case 2 D3D Initial and Annual O&M Expenses

Case: Case 2 D3D - GEE IGCC w/ two WGS bypass (75% CO2 Capture) Plant Size (MWe): 563.80 Heat Rate (Btu/kWh): 9,969 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 9,928

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $11.198 Maintenance Labor Cost (calc'd) $15,030,504 $26.659 Administrative & Support Labor (calc'd) $5,336,003 $9.464 Property Taxes & Insurance $28,958,076 $51.362 TOTAL FIXED OPERATING COSTS $55,638,089 $98.684 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $28,334,568 0.00717

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 4,010 1.08 $0 $1,266,455 0.00032

Chemicals MU & WT Chem. (lbs) 0 23,889 0.17 $0 $1,207,227 0.00031 Carbon (Mercury Removal) (lb) 74,302 127 1.05 $78,030 $38,945 0.00001 COS Catalyst (m3) 91 0.06 2,397.36 $219,119 $43,824 0.00001 Water Gas Shift Catalyst (ft3) 6,076 4.16 498.83 $3,030,897 $606,179 0.00015 Selexol Solution (gal) 296,322 87 13.40 $3,970,195 $339,078 0.00009 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 1.99 131.27 $0 $76,378 0.00002 Subtotal Chemicals $7,298,241 $2,311,631 0.00059 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 127 0.42 $0 $15,575 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 634 16.23 $0 $3,005,186 0.00076 Subtotal Solid Waste Disposal $0 $3,020,761 $0
By-products & Emissions Sulfur (tons) 0 145 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $34,933,414 0.00884 Coal FUEL (tons) 0 5,781 38.19 $0 $64,462,401 0.01631 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 445Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 154 Case 2 D3E (85%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) x $1, 000 Plant Size: 554.48 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,744 $0 $1,830 $0 $5,574 9.0% $499 0% $0 20.0% $1,215 $7,288 $13 1.2 Coal Stackout & Reclaim $4,839 $0 $1,173 $0 $6,012 8.8% $527 0% $0 20.0% $1,308 $7,846 $14 1.3 Coal Conveyors & Yd Crus $4,499 $0 $1,161 $0 $5,659 8.8% $497 0% $0 20.0% $1,231 $7,387 $13 1.4 Other Coal Handling $1,177 $0 $269 $0 $1,446 8.8% $126 0% $0 20.0% $314 $1,886 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,650 $6,625 $0 $9,275 9.6% $889 0% $0 20.0% $2,033 $12,197 $22 SUBTOTAL 1. $14,258 $2,650 $11,057 $0 $27,965 $2,538 $0 $6,101 $36,605 $66 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,599 $383 $251 $0 $2,233 8.6% 191 0% 0 20.0% $485 $2,908 $5 2.3 Slurry Prep & Feed $21,873 $0 $9,651 $0 $31,524 9.1% 2,864 5% 1,576 20.0% $7,193 $43,157 $78 2.4 Misc. Coal Prep & Feed $879 $640 $1,919 $0 $3,438 9.2% 316 0% 0 20.0% $751 $4,505 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,418 $2,806 $0 $6,224 9.3% 576 0% 0 20.0% $1,360 $8,161 $15 SUBTOTAL 2. $24,351 $4,441 $14,627 $0 $43,419 $3,947 $1,576 $9,788 $58,731 $106 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,821 4,845 2,558 0 10,224 9.3% 947 0% 0 20.0% $2,234 $13,405 $24 3.2 Water Makeup & Pretreating 711 74 398 0 1,183 9.5% 113 0% 0 30.0% $389 $1,685 $3 3.3 Other Feedwater Subsystems 1,544 522 469 0 2,535 9.0% 228 0% 0 20.0% $552 $3,315 $6 3.4 Service Water Systems 407 838 2,909 0 4,155 9.8% 405 0% 0 30.0% $1,368 $5,928 $11 3.5 Other Boiler Plant Systems 2,185 847 2,098 0 5,129 9.5% 487 0% 0 20.0% $1,123 $6,739 $12 3.6 FO Supply Sys & Nat Gas $315 $595 $555 $0 1,466 9.6% 141 0% 0 20.0% $321 $1,929 $3 3.7 Waste Treatment Equipment 994 0 607 0 1,601 9.7% 156 0% 0 30.0% $527 $2,284 $4 3.8 Misc. Power Plant Equipment $1,121 $150 $575 $0 1,846 9.7% 178 0% 0 30.0% $607 $2,632 $5 SUBTOTAL 3. $10,098 $7,871 $10,169 $0 $28,139 $2,655 $0 $7,122 $37,916 $68 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,668 $0 $62,282 $0 $175,950 9.2% $16,118 13.9% $24,418 15.3% $33,195 $249,681 $450 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $192,697 $0 w/equip. $0 $192,697 9.7% $18,678 0% $0 10.0% $21,138 $232,513 $419 4.4 Scrubber & Low Temperature Cooling 6,039 $4,915 $5,116 $0 $16,070 9.6% $1,543 0% $0 20.0% $3,523 $21,136 $38 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,842 $874 $1,728 $0 $4,445 9.6% $428 0% $0 20.0% $975 $5,847 $11 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,475 $5,405 $0 $11,879 9.3% $1,101 0% $0 25.0% $3,245 $16,225 $29 SUBTOTAL 4. $314,246 $12,264 $74,531 $0 $401,041 $37,869 $24,418 $62,075 $525,402 $948 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 446Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 154 Case 2 D3E (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) x $1, 000 Plant Size: 554.48 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $71,710 $0 $60,848 $0 $132,558 9.7% $12,820 20% $26,512 20.0% $34,378 $206,267 $372 5A.2 Elemental Sulfur Plant $10,310 $2,055 $13,302 $0 $25,668 9.7% $2,493 0% $0 20.0% $5,632 $33,793 $61 5A.3 Mercury Removal $1,358 $0 $1,034 $0 $2,392 9.7% $231 5% $120 20.0% $549 $3,291 $6 5A.4 Shift Reactors $10,763 $0 $4,333 $0 $15,096 9.6% $1,447 0% $0 20.0% $3,309 $19,851 $36 5A.5 COS Hydrolysis $451 $0 $589 $0 $1,040 9.7% $101 0% $0 20.0% $228 $1,369 $2 5A.6 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.7 Blowback Gas Systems $1,347 $0 $255 $0 $1,602 12.2% $195 0% $0 20.0% $360 $2,157 $4 5A.8 Fuel Gas Piping $0 $637 $446 $0 $1,082 9.3% $100 0% $0 20.0% $237 $1,419 $3 5A.9 HGCU Foundations $0 $641 $413 $0 $1,053 9.2% $97 0% $0 30.0% $345 $1,495 $3 5A.10 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $95,940 $3,332 $81,219 $0 $180,491 $17,485 $26,631 $45,036 $269,644 $486 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $17,272 $0 $10,588 $0 $27,860 9.6% $2,684 0% $0 20.0% $6,109 $36,652 $66 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $17,272 $0 $10,588 $0 $27,860 $2,684 $0 $6,109 $36,652 $66 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 234 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 14 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $253 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,726 $0 $4,795 $0 $38,521 9.5% $3,663 0% $0 10.0% $4,218 $46,402 $84 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,729 $1,234 $0 $2,963 8.8% $260 0% $0 20.0% $645 $3,867 $7 7.4 Stack $3,373 $0 $1,267 $0 $4,641 9.6% $445 0% $0 10.0% $509 $5,594 $10 7.9 HRSG, Duct & Stack Foundations $0 $676 $649 $0 $1,325 9.3% $123 0% $0 30.0% $434 $1,883 $3 SUBTOTAL 7. $37,099 $2,405 $7,945 $0 $47,449 $4,490 $0 $5,806 $57,746 $104 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,579 $0 $4,886 $0 $33,465 9.6% $3,211 0% $0 10.0% $3,668 $40,344 $73 8.2 Turbine Plant Auxiliaries $198 $0 $454 $0 $652 9.8% $64 0% $0 10.0% $72 $788 $1 8.3 Condenser & Auxiliaries $5,082 $0 $1,492 $0 $6,574 9.6% $628 0% $0 10.0% $720 $7,923 $14 8.4 Steam Piping $4,980 $0 $3,503 $0 $8,484 8.6% $729 0% $0 25.0% $2,303 $11,516 $21 8.9 TG Foundations $0 $983 $1,661 $0 $2,644 9.5% $251 0% $0 30.0% $868 $3,763 $7 SUBTOTAL 8. $38,840 $983 $11,997 $0 $51,820 $4,883 $0 $7,631 $64,334 $116 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,135 $0 $1,298 $0 $8,433 9.5% $803 0% $0 15.0% $1,385 $10,621 $19 9.2 Circulating Water Pumps $1,856 $0 $134 $0 $1,990 8.4% $168 0% $0 15.0% $324 $2,481 $4 9.3 Circ. Water System Auxiliaries $155 $0 $22 $0 $177 9.5% $17 0% $0 15.0% $29 $224 $0 9.4 Circ. Water Piping $0 $6,481 $1,680 $0 $8,161 9.0% $738 0% $0 20.0% $1,780 $10,679 $19 9.5 Make-up Water System $385 $0 $551 $0 $936 9.6% $90 0% $0 20.0% $205 $1,231 $2 9.6 Component Cooling Water System $765 $915 $651 $0 $2,331 9.4% $218 0% $0 20.0% $510 $3,060 $6 9.9 Circ. Water System Foundations $0 $2,379 $4,044 $0 $6,423 9.5% $609 0% $0 30.0% $2,110 $9,142 $16 SUBTOTAL 9. $10,296 $9,775 $8,381 $0 $28,452 $2,643 $0 $6,343 $37,438 $68 * Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 447Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 154 Case 2 D3E (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) x $1, 000 Plant Size: 554.48 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,118 $6,682 $13,574 $0 $32,374 9.7% $3,125 0% $0 10.0% $3,550 $39,049 $70 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $588 $0 $640 $0 $1,227 9.7% $119 0% $0 15.0% $202 $1,549 $3 10.7 Ash Transport & Feed Equipment $788 $0 $190 $0 $979 9.3% $91 0% $0 15.0% $160 $1,230 $2 10.8 Misc. Ash Handling Equipment $1,218 $1,492 $446 $0 $3,156 9.5% $300 0% $0 15.0% $518 $3,974 $7 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $167 $0 SUBTOTAL 10. $14,712 $8,226 $14,915 $0 $37,853 $3,646 $0 $4,469 $45,969 $83 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $952 $0 $942 $0 $1,894 9.5% $181 0% $0 10.0% $207 $2,282 $4 11.2 Station Service Equipment $4,639 $0 $418 $0 $5,057 9.2% $466 0% $0 10.0% $552 $6,076 $11 11.3 Switchgear & Motor Control $8,576 $0 $1,560 $0 $10,136 9.3% $940 0% $0 15.0% $1,661 $12,737 $23 11.4 Conduit & Cable Tray $0 $3,984 $13,143 $0 $17,127 9.7% $1,657 0% $0 25.0% $4,696 $23,479 $42 11.5 Wire & Cable $0 $7,612 $5,001 $0 $12,613 7.3% $916 0% $0 25.0% $3,382 $16,912 $31 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $234 $0 $229 $0 $463 9.5% $44 0% $0 15.0% $76 $584 $1 11.8 Main Power Transformers $17,599 $0 $145 $0 $17,744 7.6% $1,342 0% $0 15.0% $2,863 $21,948 $40 11.9 Electrical Foundations $0 $157 $413 $0 $570 9.6% $55 0% $0 30.0% $187 $812 $1 SUBTOTAL 11. $32,000 $12,439 $24,346 $0 $68,786 $5,911 $0 $14,150 $88,847 $160 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,117 $0 $746 $0 $1,863 9.5% $176 5% $93 15.0% $320 $2,453 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $257 $0 $165 $0 $421 9.5% $40 5% $21 20.0% $96 $579 $1 12.7 Computer & Accessories $5,960 $0 $191 $0 $6,151 9.2% $565 5% $308 10.0% $702 $7,725 $14 12.8 Instrument Wiring & Tubing $0 $2,082 $4,256 $0 $6,338 8.5% $538 5% $317 25.0% $1,798 $8,991 $16 12.9 Other I & C Equipment $3,984 $0 $1,935 $0 $5,919 9.4% $557 5% $296 15.0% $1,016 $7,787 $14 SUBTOTAL 12. $11,318 $2,082 $7,292 $0 $20,692 $1,875 $1,035 $3,933 $27,535 $50 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 109 2,335 0 2,445 9.9% 243 0% 0 30.0% 806 3,494 6 13.2 Site Improvements 0 1,943 2,583 0 4,526 9.9% 446 0% 0 30.0% 1,492 6,464 12 13.3 Site Facilities 3,483 0 3,675 0 7,157 9.9% 705 0% 0 30.0% 2,359 10,222 18 SUBTOTAL 13. $3,483 $2,053 $8,593 $0 $14,128 $1,395 $0 $4,657 $20,179 $36 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 448Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 154 Case 2 D3E (85%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) x $1, 000 Plant Size: 554.48 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $541 $1 14.2 Steam Turbine Building $0 $2,376 $3,385 $0 $5,762 9.2% $530 0% $0 15.0% $944 $7,236 $13 14.3 Administration Building $0 $882 $640 $0 $1,521 8.9% $135 0% $0 15.0% $249 $1,905 $3 14.4 Circulation Water Pumphouse $0 $166 $88 $0 $253 8.8% $22 0% $0 15.0% $41 $317 $1 14.5 Water Treatment Buildings $0 $595 $580 $0 $1,175 9.0% $106 0% $0 15.0% $192 $1,474 $3 14.6 Machine Shop $0 $451 $309 $0 $760 8.9% $67 0% $0 15.0% $124 $952 $2 14.7 Warehouse $0 $729 $470 $0 $1,199 8.9% $106 0% $0 15.0% $196 $1,501 $3 14.8 Other Buildings & Structures $0 $436 $340 $0 $776 8.9% $69 0% $0 20.0% $169 $1,015 $2 14.9 Waste Treating Building & Str. $0 $975 $1,864 $0 $2,839 9.3% $265 0% $0 20.0% $621 $3,724 $7 SUBTOTAL 14. $0 $6,875 $7,826 $0 $14,701 $1,338 $0 $2,626 $18,665 $34 Total Cost $721,489 $76,282 $301,818 $0 $1,099,590 $103,483 $63,521 $199,278 $1,465,871 $2,644


### Owner's Costs Preproduction Costs 6 Months All Labor $13,449 $24 1 Month Maintenance Materials $2,986 $5 1 Month Non-fuel Consumables $393 $1 1 Month Waste Disposal $317 $1 25% of 1 Months Fuel Cost at 100% CF $1,693 $3 2% of TPC $29,317 $53
Total $48,156 $87 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,330 $26 0.5% of TPC (spare parts) $7,329 $13
Total $21,659 $39

Initial Cost for Catalyst and Chemicals $7,797 $14 Land $900 $2 Other Owner's Costs $219,881 $397

Financing Costs $39,579 $71 

### Total Overnight Costs (TOC) $1,803,843 $3,253 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $2,056,381 $3,709 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected



## 449Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 155 Case 2 D3E Initial and Annual O&M Expenses

Case: Case 2 D3E - GEE IGCC w/ two WGS bypass (85% CO2 Capture) Plant Size (MWe): 554.48 Heat Rate (Btu/kWh): 10,222 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 11,376

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $11.386 Maintenance Labor Cost (calc'd) $15,205,658 $27.423 Administrative & Support Labor (calc'd) $5,379,791 $9.702 Property Taxes & Insurance $29,317,421 $52.873 TOTAL FIXED OPERATING COSTS $56,216,377 $101.385 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $28,664,758 0.00738

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 4,139 1.08 $0 $1,307,161 0.00034

Chemicals MU & WT Chem. (lbs) 0 24,656 0.17 $0 $1,246,030 0.00032 Carbon (Mercury Removal) (lb) 78,342 134 1.05 $82,272 $41,091 0.00001 COS Catalyst (m3) 22 0.02 2,397.36 $52,502 $10,500 0.00000 Water Gas Shift Catalyst (ft3) 7,362 5.04 498.83 $3,672,394 $734,479 0.00019 Selexol Solution (gal) 297,784 92 13.40 $3,989,782 $360,713 0.00009 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 2.01 131.27 $0 $77,006 0.00002 Subtotal Chemicals $7,796,950 $2,469,819 0.00064 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 134 0.42 $0 $16,434 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 640 16.23 $0 $3,030,485 0.00078 Subtotal Solid Waste Disposal $0 $3,046,919 $0
By-products & Emissions Sulfur (tons) 0 146 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $35,488,657 0.00913 Coal FUEL (tons) 0 5,830 38.19 $0 $65,005,231 0.01673 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 450Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 156 Case 2 D4A (90%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) x $1, 000 Plant Size: 543.24 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,750 $0 $1,833 $0 $5,583 9.0% $500 0% $0 20.0% $1,217 $7,299 $13 1.2 Coal Stackout & Reclaim $4,846 $0 $1,175 $0 $6,021 8.8% $528 0% $0 20.0% $1,310 $7,858 $14 1.3 Coal Conveyors & Yd Crus $4,505 $0 $1,162 $0 $5,668 8.8% $498 0% $0 20.0% $1,233 $7,398 $14 1.4 Other Coal Handling $1,179 $0 $269 $0 $1,448 8.8% $127 0% $0 20.0% $315 $1,889 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,654 $6,635 $0 $9,289 9.6% $890 0% $0 20.0% $2,036 $12,215 $22 SUBTOTAL 1. $14,280 $2,654 $11,074 $0 $28,008 $2,542 $0 $6,110 $36,660 $67 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,602 $383 $251 $0 $2,236 8.6% 191 0% 0 20.0% $485 $2,913 $5 2.3 Slurry Prep & Feed $21,908 $0 $9,667 $0 $31,575 9.1% 2,869 5% 1,579 20.0% $7,205 $43,227 $80 2.4 Misc. Coal Prep & Feed $881 $641 $1,922 $0 $3,443 9.2% 316 0% 0 20.0% $752 $4,512 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,424 $2,811 $0 $6,234 9.3% 577 0% 0 20.0% $1,362 $8,174 $15 SUBTOTAL 2. $24,391 $4,448 $14,651 $0 $43,489 $3,954 $1,579 $9,804 $58,826 $108 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,836 4,870 2,571 0 10,276 9.3% 952 0% 0 20.0% $2,246 $13,474 $25 3.2 Water Makeup & Pretreating 717 75 401 0 1,193 9.5% 114 0% 0 30.0% $392 $1,699 $3 3.3 Other Feedwater Subsystems 1,552 524 472 0 2,548 9.0% 229 0% 0 20.0% $555 $3,332 $6 3.4 Service Water Systems 411 845 2,934 0 4,190 9.8% 409 0% 0 30.0% $1,380 $5,979 $11 3.5 Other Boiler Plant Systems 2,203 854 2,116 0 5,173 9.5% 491 0% 0 20.0% $1,133 $6,796 $13 3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 1,467 9.6% 141 0% 0 20.0% $322 $1,930 $4 3.7 Waste Treatment Equipment 1,003 0 612 0 1,615 9.7% 157 0% 0 30.0% $532 $2,303 $4 3.8 Misc. Power Plant Equipment $1,121 $150 $576 $0 1,847 9.7% 178 0% 0 30.0% $608 $2,634 $5 SUBTOTAL 3. $10,158 $7,914 $10,237 $0 $28,309 $2,671 $0 $7,166 $38,146 $70 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,863 $0 $62,389 $0 $176,251 9.2% $16,146 13.9% $24,460 15.3% $33,252 $250,109 $460 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $193,046 9.7% $18,712 0% $0 10.0% $21,176 $232,934 $429 4.4 Scrubber & Low Temperature Cooling 6,049 $4,924 $5,125 $0 $16,097 9.6% $1,546 0% $0 20.0% $3,529 $21,172 $39 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,845 $876 $1,731 $0 $4,452 9.6% $429 0% $0 20.0% $976 $5,857 $11 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,486 $5,414 $0 $11,900 9.3% $1,103 0% $0 25.0% $3,251 $16,253 $30 SUBTOTAL 4. $314,803 $12,285 $74,659 $0 $401,747 $37,935 $24,460 $62,183 $526,325 $969 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 451Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 156 Case 2 D4A (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) x $1, 000 Plant Size: 543.24 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $74,127 $0 $62,899 $0 $137,025 9.7% $13,252 20% $27,405 20.0% $35,536 $213,219 $392 5A.2 Elemental Sulfur Plant $10,329 $2,059 $13,326 $0 $25,713 9.7% $2,498 0% $0 20.0% $5,642 $33,853 $62 5A.3 Mercury Removal $1,376 $0 $1,047 $0 $2,423 9.7% $234 5% $121 20.0% $556 $3,334 $6 5A.4 Shift Reactors $9,594 $0 $3,862 $0 $13,456 9.7% $1,308 0% $0 20.0% $2,953 $17,718 $33 5A.5 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.6 Blowback Gas Systems $1,349 $0 $256 $0 $1,605 12.2% $196 0% $0 20.0% $360 $2,161 $4 5A.7 Fuel Gas Piping $0 $634 $444 $0 $1,078 9.3% $100 0% $0 20.0% $236 $1,413 $3 5A.9 HGCU Foundations $0 $642 $414 $0 $1,056 9.2% $97 0% $0 30.0% $346 $1,498 $3

5.9 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $96,775 $3,334 $82,247 $0 $182,357 $17,685 $27,526 $45,629 $273,196 $503 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $18,256 $0 $11,190 $0 $29,446 9.6% $2,836 0% $0 20.0% $6,456 $38,739 $71 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $18,256 $0 $11,190 $0 $29,446 $2,836 $0 $6,456 $38,739 $71 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 239 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 15 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $258 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,620 $0 $4,780 $0 $38,401 9.5% $3,651 0% $0 10.0% $4,205 $46,257 $85 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,731 $1,235 $0 $2,965 8.8% $260 0% $0 20.0% $645 $3,870 $7 7.4 Stack $3,376 $0 $1,268 $0 $4,644 9.6% $445 0% $0 10.0% $509 $5,598 $10 7.9 HRSG, Duct & Stack Foundations $0 $676 $650 $0 $1,326 9.3% $123 0% $0 30.0% $435 $1,884 $3 SUBTOTAL 7. $36,996 $2,407 $7,933 $0 $47,336 $4,480 $0 $5,794 $57,610 $106 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,123 $0 $4,808 $0 $32,931 9.6% $3,160 0% $0 10.0% $3,609 $39,699 $73 8.2 Turbine Plant Auxiliaries $195 $0 $447 $0 $642 9.8% $63 0% $0 10.0% $70 $775 $1 8.3 Condenser & Auxiliaries $5,009 $0 $1,471 $0 $6,480 9.6% $619 0% $0 10.0% $710 $7,809 $14 8.4 Steam Piping $5,006 $0 $3,522 $0 $8,528 8.6% $733 0% $0 25.0% $2,315 $11,576 $21 8.9 TG Foundations $0 $967 $1,635 $0 $2,603 9.5% $247 0% $0 30.0% $855 $3,704 $7 SUBTOTAL 8. $38,333 $967 $11,883 $0 $51,183 $4,821 $0 $7,559 $63,564 $117 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,155 $0 $1,302 $0 $8,457 9.5% $805 0% $0 15.0% $1,389 $10,652 $20 9.2 Circulating Water Pumps $1,856 $0 $134 $0 $1,990 8.4% $168 0% $0 15.0% $324 $2,481 $5 9.3 Circ. Water System Auxiliaries $155 $0 $22 $0 $177 9.5% $17 0% $0 15.0% $29 $224 $0 9.4 Circ. Water Piping $0 $6,481 $1,680 $0 $8,161 9.0% $738 0% $0 20.0% $1,780 $10,679 $20 9.5 Make-up Water System $388 $0 $555 $0 $943 9.6% $90 0% $0 20.0% $207 $1,240 $2 9.6 Component Cooling Water System $765 $915 $651 $0 $2,331 9.4% $218 0% $0 20.0% $510 $3,060 $6 9.9 Circ. Water System Foundations $0 $2,379 $4,044 $0 $6,423 9.5% $609 0% $0 30.0% $2,110 $9,142 $17 SUBTOTAL 9. $10,319 $9,775 $8,388 $0 $28,483 $2,646 $0 $6,348 $37,477 $69 * Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 452Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 156 Case 2 D4A (90%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) x $1, 000 Plant Size: 543.24 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,136 $6,692 $13,595 $0 $32,424 9.7% $3,129 0% $0 10.0% $3,555 $39,109 $72 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $589 $0 $641 $0 $1,229 9.7% $119 0% $0 15.0% $202 $1,551 $3 10.7 Ash Transport & Feed Equipment $790 $0 $190 $0 $980 9.3% $91 0% $0 15.0% $161 $1,232 $2 10.8 Misc. Ash Handling Equipment $1,219 $1,494 $446 $0 $3,160 9.5% $301 0% $0 15.0% $519 $3,980 $7 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $39 $167 $0 SUBTOTAL 10. $14,734 $8,239 $14,938 $0 $37,910 $3,652 $0 $4,476 $46,038 $85 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $947 $0 $937 $0 $1,885 9.5% $180 0% $0 10.0% $206 $2,271 $4 11.2 Station Service Equipment $4,697 $0 $423 $0 $5,121 9.2% $472 0% $0 10.0% $559 $6,152 $11 11.3 Switchgear & Motor Control $8,684 $0 $1,579 $0 $10,264 9.3% $952 0% $0 15.0% $1,682 $12,898 $24 11.4 Conduit & Cable Tray $0 $4,034 $13,308 $0 $17,342 9.7% $1,677 0% $0 25.0% $4,755 $23,775 $44 11.5 Wire & Cable $0 $7,708 $5,064 $0 $12,772 7.3% $928 0% $0 25.0% $3,425 $17,125 $32 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $7 11.7 Standby Equipment $234 $0 $228 $0 $462 9.5% $44 0% $0 15.0% $76 $581 $1 11.8 Main Power Transformers $17,500 $0 $144 $0 $17,644 7.6% $1,334 0% $0 15.0% $2,847 $21,825 $40 11.9 Electrical Foundations $0 $156 $410 $0 $567 9.6% $54 0% $0 30.0% $186 $807 $1 SUBTOTAL 11. $32,062 $12,584 $24,591 $0 $69,237 $5,953 $0 $14,261 $89,451 $165 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,126 $0 $752 $0 $1,877 9.5% $178 5% $94 15.0% $322 $2,471 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $259 $0 $166 $0 $425 9.5% $40 5% $21 20.0% $97 $583 $1 12.7 Computer & Accessories $6,005 $0 $192 $0 $6,197 9.2% $569 5% $310 10.0% $708 $7,784 $14 12.8 Instrument Wiring & Tubing $0 $2,098 $4,288 $0 $6,386 8.5% $542 5% $319 25.0% $1,812 $9,059 $17 12.9 Other I & C Equipment $4,014 $0 $1,949 $0 $5,963 9.4% $561 5% $298 15.0% $1,023 $7,846 $14 SUBTOTAL 12. $11,404 $2,098 $7,347 $0 $20,849 $1,889 $1,042 $3,962 $27,743 $51 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 109 2,337 0 2,447 9.9% 243 0% 0 30.0% 807 3,496 6 13.2 Site Improvements 0 1,945 2,585 0 4,530 9.9% 447 0% 0 30.0% 1,493 6,469 12 13.3 Site Facilities 3,485 0 3,678 0 7,163 9.9% 706 0% 0 30.0% 2,361 10,230 19 SUBTOTAL 13. $3,485 $2,054 $8,600 $0 $14,140 $1,396 $0 $4,661 $20,196 $37 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 453Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 156 Case 2 D4A (90%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) x $1, 000 Plant Size: 543.24 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $541 $1 14.2 Steam Turbine Building $0 $2,377 $3,387 $0 $5,764 9.2% $530 0% $0 15.0% $944 $7,238 $13 14.3 Administration Building $0 $882 $640 $0 $1,522 8.9% $136 0% $0 15.0% $249 $1,906 $4 14.4 Circulation Water Pumphouse $0 $166 $88 $0 $253 8.8% $22 0% $0 15.0% $41 $317 $1 14.5 Water Treatment Buildings $0 $600 $585 $0 $1,185 9.0% $107 0% $0 15.0% $194 $1,486 $3 14.6 Machine Shop $0 $452 $309 $0 $761 8.9% $68 0% $0 15.0% $124 $952 $2 14.7 Warehouse $0 $729 $471 $0 $1,200 8.9% $106 0% $0 15.0% $196 $1,502 $3 14.8 Other Buildings & Structures $0 $437 $340 $0 $777 8.9% $69 0% $0 20.0% $169 $1,015 $2 14.9 Waste Treating Building & Str. $0 $976 $1,865 $0 $2,841 9.3% $265 0% $0 20.0% $621 $3,728 $7 SUBTOTAL 14. $0 $6,882 $7,834 $0 $14,716 $1,340 $0 $2,628 $18,684 $34 Total Cost $723,574 $76,529 $303,902 $0 $1,104,005 $103,923 $64,468 $200,471 $1,472,866 $2,711


### Owner's Costs Preproduction Costs 6 Months All Labor $13,488 $25 1 Month Maintenance Materials $2,998 $6 1 Month Non-fuel Consumables $385 $1 1 Month Waste Disposal $318 $1 25% of 1 Months Fuel Cost at 100% CF $1,697 $3 2% of TPC $29,457 $54
Total $48,343 $89 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,346 $26 0.5% of TPC (spare parts) $7,364 $14
Total $21,711 $40

Initial Cost for Catalyst and Chemicals $7,200 $13 Land $900 $2 Other Owner's Costs $220,930 $407

Financing Costs $39,767 $73 

### Total Overnight Costs (TOC) $1,811,717 $3,335 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $2,065,358 $3,802 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected



## 454Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 157 Case 2 D4A Initial and Annual O&M Expenses

Case: Case 2 D4A - GEE IGCC w/ two WGS (90% CO2 Capture) Plant Size (MWe): 543.24 Heat Rate (Btu/kWh): 10,459 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 12,377

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $11.622 Maintenance Labor Cost (calc'd) $15,266,708 $28.103 Administrative & Support Labor (calc'd) $5,395,054 $9.931 Property Taxes & Insurance $29,457,328 $54.225 TOTAL FIXED OPERATING COSTS $56,432,596 $103.881 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $28,779,845 0.00756

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 4,188 1.08 $0 $1,322,853 0.00035

Chemicals MU & WT Chem. (lbs) 0 24,952 0.17 $0 $1,260,988 0.00033 Carbon (Mercury Removal) (lb) 79,788 137 1.05 $83,791 $42,011 0.00001 COS Catalyst (m3) 0 0.00 2,397.36 $0 $0 0.00000 Water Gas Shift Catalyst (ft3) 6,247 4.28 498.83 $3,116,197 $623,239 0.00016 Selexol Solution (gal) 298,515 95 13.40 $3,999,575 $371,667 0.00010 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 2.01 131.27 $0 $77,209 0.00002 Subtotal Chemicals $7,199,564 $2,375,114 0.00062 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 137 0.42 $0 $16,802 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 641 16.23 $0 $3,037,933 0.00080 Subtotal Solid Waste Disposal $0 $3,054,735 $0
By-products & Emissions Sulfur (tons) 0 146 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $35,532,546 0.00933 Coal FUEL (tons) 0 5,844 38.19 $0 $65,164,454 0.01712 INITIAL & ANNUAL O&M EXPENSES

Consumption Annual Costs



## 455Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 158 Case 2 D4B (95%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) x $1, 000 Plant Size: 528.51 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,746 $0 $1,831 $0 $5,577 9.0% $500 0% $0 20.0% $1,215 $7,291 $14 1.2 Coal Stackout & Reclaim $4,841 $0 $1,174 $0 $6,014 8.8% $527 0% $0 20.0% $1,308 $7,849 $15 1.3 Coal Conveyors & Yd Crus $4,500 $0 $1,161 $0 $5,662 8.8% $497 0% $0 20.0% $1,232 $7,390 $14 1.4 Other Coal Handling $1,177 $0 $269 $0 $1,446 8.8% $127 0% $0 20.0% $315 $1,887 $4 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,651 $6,628 $0 $9,279 9.6% $889 0% $0 20.0% $2,034 $12,202 $23 SUBTOTAL 1. $14,264 $2,651 $11,062 $0 $27,977 $2,540 $0 $6,103 $36,620 $69 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,600 $383 $251 $0 $2,234 8.6% 191 0% 0 20.0% $485 $2,909 $6 2.3 Slurry Prep & Feed $21,883 $0 $9,656 $0 $31,538 9.1% 2,865 5% 1,577 20.0% $7,196 $43,177 $82 2.4 Misc. Coal Prep & Feed $880 $640 $1,919 $0 $3,439 9.2% 316 0% 0 20.0% $751 $4,507 $9 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,420 $2,807 $0 $6,227 9.3% 577 0% 0 20.0% $1,361 $8,165 $15 SUBTOTAL 2. $24,362 $4,443 $14,634 $0 $43,438 $3,949 $1,577 $9,793 $58,757 $111 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,826 4,854 2,562 0 10,242 9.3% 949 0% 0 20.0% $2,238 $13,429 $25 3.2 Water Makeup & Pretreating 711 74 397 0 1,182 9.5% 113 0% 0 30.0% $388 $1,683 $3 3.3 Other Feedwater Subsystems 1,546 523 470 0 2,539 9.0% 228 0% 0 20.0% $553 $3,321 $6 3.4 Service Water Systems 407 837 2,906 0 4,150 9.8% 405 0% 0 30.0% $1,366 $5,921 $11 3.5 Other Boiler Plant Systems 2,182 846 2,096 0 5,123 9.5% 486 0% 0 20.0% $1,122 $6,731 $13 3.6 FO Supply Sys & Nat Gas $315 $596 $555 $0 1,466 9.6% 141 0% 0 20.0% $321 $1,929 $4 3.7 Waste Treatment Equipment 993 0 606 0 1,599 9.7% 156 0% 0 30.0% $526 $2,281 $4 3.8 Misc. Power Plant Equipment $1,121 $150 $576 $0 1,847 9.7% 178 0% 0 30.0% $607 $2,632 $5 SUBTOTAL 3. $10,102 $7,879 $10,168 $0 $28,149 $2,656 $0 $7,124 $37,929 $72 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,723 $0 $62,312 $0 $176,034 9.2% $16,126 13.9% $24,430 15.3% $33,211 $249,801 $473 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $192,904 $0 w/equip. $0 $192,904 9.7% $18,698 0% $0 10.0% $21,160 $232,762 $440 4.4 Scrubber & Low Temperature Cooling 6,042 $4,918 $5,118 $0 $16,078 9.6% $1,544 0% $0 20.0% $3,524 $21,146 $40 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,842 $875 $1,729 $0 $4,447 9.6% $429 0% $0 20.0% $975 $5,850 $11 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,478 $5,407 $0 $11,885 9.3% $1,101 0% $0 25.0% $3,247 $16,233 $31 SUBTOTAL 4. $314,511 $12,270 $74,567 $0 $401,347 $37,898 $24,430 $62,117 $525,792 $995 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected



## 456Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 158 Case 2 D4B (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) x $1, 000 Plant Size: 528.51 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $77,897 $0 $66,097 $0 $143,994 9.7% $13,926 20% $28,799 20.0% $37,344 $224,062 $424 5A.2 Elemental Sulfur Plant $10,316 $2,056 $13,310 $0 $25,682 9.7% $2,495 0% $0 20.0% $5,635 $33,812 $64 5A.3 Mercury Removal $1,374 $0 $1,046 $0 $2,420 9.7% $234 5% $121 20.0% $555 $3,330 $6 5A.4 Shift Reactors $9,582 $0 $3,857 $0 $13,440 9.7% $1,307 0% $0 20.0% $2,949 $17,696 $33 5A.5 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.6 Blowback Gas Systems $1,348 $0 $255 $0 $1,603 12.2% $196 0% $0 20.0% $360 $2,158 $4 5A.7 Fuel Gas Piping $0 $619 $433 $0 $1,052 9.3% $97 0% $0 20.0% $230 $1,379 $3 5A.9 HGCU Foundations $0 $641 $413 $0 $1,054 9.2% $97 0% $0 30.0% $345 $1,496 $3

5.9 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $100,517 $3,315 $85,412 $0 $189,245 $18,351 $28,920 $47,418 $283,933 $537 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $19,059 $0 $11,682 $0 $30,741 9.6% $2,961 0% $0 20.0% $6,740 $40,443 $77 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $19,059 $0 $11,682 $0 $30,741 $2,961 $0 $6,740 $40,443 $77 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 245 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 15 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $265 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,515 $0 $4,765 $0 $38,280 9.5% $3,640 0% $0 10.0% $4,192 $46,112 $87 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,731 $1,235 $0 $2,967 8.8% $260 0% $0 20.0% $645 $3,872 $7 7.4 Stack $3,378 $0 $1,269 $0 $4,647 9.6% $445 0% $0 10.0% $509 $5,601 $11 7.9 HRSG, Duct & Stack Foundations $0 $677 $650 $0 $1,327 9.3% $124 0% $0 30.0% $435 $1,885 $4 SUBTOTAL 7. $36,892 $2,408 $7,920 $0 $47,220 $4,469 $0 $5,782 $57,470 $109 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $27,561 $0 $4,712 $0 $32,272 9.6% $3,097 0% $0 10.0% $3,537 $38,906 $74 8.2 Turbine Plant Auxiliaries $191 $0 $438 $0 $629 9.8% $62 0% $0 10.0% $69 $760 $1 8.3 Condenser & Auxiliaries $4,813 $0 $1,413 $0 $6,226 9.6% $595 0% $0 10.0% $682 $7,503 $14 8.4 Steam Piping $4,990 $0 $3,510 $0 $8,500 8.6% $730 0% $0 25.0% $2,307 $11,537 $22 8.9 TG Foundations $0 $948 $1,603 $0 $2,551 9.5% $242 0% $0 30.0% $838 $3,631 $7 SUBTOTAL 8. $37,554 $948 $11,676 $0 $50,178 $4,725 $0 $7,433 $62,337 $118 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,073 $0 $1,287 $0 $8,360 9.5% $796 0% $0 15.0% $1,373 $10,530 $20 9.2 Circulating Water Pumps $1,845 $0 $133 $0 $1,978 8.4% $167 0% $0 15.0% $322 $2,467 $5 9.3 Circ. Water System Auxiliaries $155 $0 $22 $0 $177 9.5% $17 0% $0 15.0% $29 $222 $0 9.4 Circ. Water Piping $0 $6,449 $1,672 $0 $8,121 9.0% $734 0% $0 20.0% $1,771 $10,626 $20 9.5 Make-up Water System $385 $0 $550 $0 $935 9.6% $90 0% $0 20.0% $205 $1,230 $2 9.6 Component Cooling Water System $761 $911 $648 $0 $2,320 9.4% $217 0% $0 20.0% $507 $3,045 $6 9.9 Circ. Water System Foundations $0 $2,367 $4,024 $0 $6,392 9.5% $606 0% $0 30.0% $2,099 $9,097 $17 SUBTOTAL 9. $10,219 $9,727 $8,337 $0 $28,283 $2,627 $0 $6,307 $37,216 $70 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected

*



## 457Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 158 Case 2 D4B (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) x $1, 000 Plant Size: 528.51 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,123 $6,685 $13,580 $0 $32,388 9.7% $3,126 0% $0 10.0% $3,551 $39,066 $74 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $588 $0 $640 $0 $1,228 9.7% $119 0% $0 15.0% $202 $1,549 $3 10.7 Ash Transport & Feed Equipment $789 $0 $190 $0 $979 9.3% $91 0% $0 15.0% $161 $1,231 $2 10.8 Misc. Ash Handling Equipment $1,218 $1,493 $446 $0 $3,157 9.5% $300 0% $0 15.0% $519 $3,976 $8 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $167 $0 SUBTOTAL 10. $14,718 $8,230 $14,922 $0 $37,869 $3,648 $0 $4,471 $45,989 $87 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $942 $0 $931 $0 $1,873 9.5% $179 0% $0 10.0% $205 $2,257 $4 11.2 Station Service Equipment $4,775 $0 $430 $0 $5,205 9.2% $480 0% $0 10.0% $568 $6,253 $12 11.3 Switchgear & Motor Control $8,827 $0 $1,605 $0 $10,432 9.3% $968 0% $0 15.0% $1,710 $13,110 $25 11.4 Conduit & Cable Tray $0 $4,100 $13,527 $0 $17,628 9.7% $1,705 0% $0 25.0% $4,833 $24,166 $46 11.5 Wire & Cable $0 $7,835 $5,148 $0 $12,982 7.3% $943 0% $0 25.0% $3,481 $17,407 $33 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $8 11.7 Standby Equipment $232 $0 $227 $0 $459 9.5% $44 0% $0 15.0% $75 $578 $1 11.8 Main Power Transformers $17,378 $0 $143 $0 $17,521 7.6% $1,325 0% $0 15.0% $2,827 $21,674 $41 11.9 Electrical Foundations $0 $155 $407 $0 $563 9.6% $54 0% $0 30.0% $185 $801 $2 SUBTOTAL 11. $32,154 $12,776 $24,915 $0 $69,845 $6,008 $0 $14,409 $90,263 $171 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,137 $0 $759 $0 $1,896 9.5% $179 5% $95 15.0% $326 $2,496 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $261 $0 $168 $0 $429 9.5% $41 5% $21 20.0% $98 $589 $1 12.7 Computer & Accessories $6,064 $0 $194 $0 $6,258 9.2% $574 5% $313 10.0% $715 $7,860 $15 12.8 Instrument Wiring & Tubing $0 $2,118 $4,331 $0 $6,449 8.5% $547 5% $322 25.0% $1,830 $9,148 $17 12.9 Other I & C Equipment $4,054 $0 $1,968 $0 $6,022 9.4% $567 5% $301 15.0% $1,033 $7,923 $15 SUBTOTAL 12. $11,516 $2,118 $7,420 $0 $21,054 $1,908 $1,053 $4,001 $28,016 $53 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 110 2,340 0 2,450 9.9% 243 0% 0 30.0% 808 3,501 7 13.2 Site Improvements 0 1,947 2,588 0 4,536 9.9% 447 0% 0 30.0% 1,495 6,478 12 13.3 Site Facilities 3,490 0 3,683 0 7,173 9.9% 707 0% 0 30.0% 2,364 10,243 19 SUBTOTAL 13. $3,490 $2,057 $8,611 $0 $14,158 $1,398 $0 $4,667 $20,222 $38 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected



## 458Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 158 Case 2 D4B (95%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) x $1, 000 Plant Size: 528.51 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $541 $1 14.2 Steam Turbine Building $0 $2,378 $3,388 $0 $5,767 9.2% $531 0% $0 15.0% $945 $7,242 $14 14.3 Administration Building $0 $883 $640 $0 $1,523 8.9% $136 0% $0 15.0% $249 $1,907 $4 14.4 Circulation Water Pumphouse $0 $165 $87 $0 $252 8.8% $22 0% $0 15.0% $41 $315 $1 14.5 Water Treatment Buildings $0 $594 $580 $0 $1,174 9.0% $106 0% $0 15.0% $192 $1,472 $3 14.6 Machine Shop $0 $452 $309 $0 $761 8.9% $68 0% $0 15.0% $124 $953 $2 14.7 Warehouse $0 $729 $471 $0 $1,200 8.9% $106 0% $0 15.0% $196 $1,503 $3 14.8 Other Buildings & Structures $0 $437 $340 $0 $777 8.9% $69 0% $0 20.0% $169 $1,016 $2 14.9 Waste Treating Building & Str. $0 $975 $1,864 $0 $2,839 9.3% $265 0% $0 20.0% $621 $3,724 $7 SUBTOTAL 14. $0 $6,878 $7,829 $0 $14,708 $1,339 $0 $2,627 $18,673 $35 Total Cost $726,934 $76,588 $307,485 $0 $1,111,007 $104,599 $65,840 $202,425 $1,483,871 $2,808


### Owner's Costs Preproduction Costs 6 Months All Labor $13,548 $26 1 Month Maintenance Materials $3,017 $6 1 Month Non-fuel Consumables $386 $1 1 Month Waste Disposal $318 $1 25% of 1 Months Fuel Cost at 100% CF $1,694 $3 2% of TPC $29,677 $56
Total $48,640 $92 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,323 $27 0.5% of TPC (spare parts) $7,419 $14
Total $21,742 $41

Initial Cost for Catalyst and Chemicals $7,396 $14 Land $900 $2 Other Owner's Costs $222,581 $421

Financing Costs $40,065 $76 

### Total Overnight Costs (TOC) $1,825,194 $3,453 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $2,080,721 $3,937 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 459Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 159 Case 2 D4B Initial and Annual O&M Expenses

Case: Case 2 D4B - GEE IGCC w/ two WGS (95% CO2 Capture) Plant Size (MWe): 528.51 Heat Rate (Btu/kWh): 10,731 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 13,692

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $11.946 Maintenance Labor Cost (calc'd) $15,363,537 $29.070 Administrative & Support Labor (calc'd) $5,419,261 $10.254 Property Taxes & Insurance $29,677,411 $56.153 TOTAL FIXED OPERATING COSTS $56,773,716 $107.422 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $28,962,382 0.00782

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 4,132 1.08 $0 $1,305,114 0.00035

Chemicals MU & WT Chem. (lbs) 0 24,618 0.17 $0 $1,244,079 0.00034 Carbon (Mercury Removal) (lb) 79,648 136 1.05 $83,644 $41,704 0.00001 COS Catalyst (m3) 0 0.00 2,397.36 $0 $0 0.00000 Water Gas Shift Catalyst (ft3) 6,236 4.27 498.83 $3,110,710 $622,142 0.00017 Selexol Solution (gal) 313,601 105 13.40 $4,201,701 $410,790 0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 2.01 131.27 $0 $77,069 0.00002 Subtotal Chemicals $7,396,055 $2,395,785 0.00065 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 136 0.42 $0 $16,679 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 640 16.23 $0 $3,032,589 0.00082 Subtotal Solid Waste Disposal $0 $3,049,268 $0
By-products & Emissions Sulfur (tons) 0 146 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $35,712,549 0.00964 Coal FUEL (tons) 0 5,834 38.19 $0 $65,049,786 0.01756 INITIAL & ANNUAL O&M EXPENSES

Annual Costs

Consumption



## 460Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 160 Case 2 D4C (97%) Capital Costs

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) x $1, 000 Plant Size: 522.89 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 1 COAL HANDLING SYSTEM 1.1 Coal Receive & Unload $3,744 $0 $1,830 $0 $5,574 9.0% $499 0% $0 20.0% $1,215 $7,288 $14 1.2 Coal Stackout & Reclaim $4,839 $0 $1,173 $0 $6,012 8.8% $527 0% $0 20.0% $1,308 $7,846 $15 1.3 Coal Conveyors & Yd Crus $4,499 $0 $1,161 $0 $5,659 8.8% $497 0% $0 20.0% $1,231 $7,387 $14 1.4 Other Coal Handling $1,177 $0 $269 $0 $1,446 8.8% $126 0% $0 20.0% $314 $1,886 $4 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,650 $6,626 $0 $9,275 9.6% $889 0% $0 20.0% $2,033 $12,197 $23 SUBTOTAL 1. $14,259 $2,650 $11,058 $0 $27,966 $2,539 $0 $6,101 $36,606 $70 2 COAL PREP & FEED SYSTEMS 2.1 Coal Crushing & Drying w/2.3 $0 w2.3 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,599 $383 $251 $0 $2,233 8.6% 191 0% 0 20.0% $485 $2,908 $6 2.3 Slurry Prep & Feed $21,873 $0 $9,652 $0 $31,525 9.1% 2,864 5% 1,576 20.0% $7,193 $43,158 $83 2.4 Misc. Coal Prep & Feed $879 $640 $1,919 $0 $3,438 9.2% 316 0% 0 20.0% $751 $4,505 $9 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 0.0% 0 0% 0 15.0% $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,418 $2,806 $0 $6,224 9.3% 576 0% 0 20.0% $1,360 $8,161 $16 SUBTOTAL 2. $24,352 $4,441 $14,627 $0 $43,420 $3,948 $1,576 $9,789 $58,732 $112 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System 2,823 4,848 2,559 0 10,230 9.3% 948 0% 0 20.0% $2,236 $13,413 $26 3.2 Water Makeup & Pretreating 708 74 396 0 1,177 9.5% 112 0% 0 30.0% $387 $1,676 $3 3.3 Other Feedwater Subsystems 1,545 522 470 0 2,536 9.0% 228 0% 0 20.0% $553 $3,317 $6 3.4 Service Water Systems 405 834 2,895 0 4,134 9.8% 403 0% 0 30.0% $1,361 $5,898 $11 3.5 Other Boiler Plant Systems 2,173 842 2,087 0 5,103 9.5% 484 0% 0 20.0% $1,117 $6,705 $13 3.6 FO Supply Sys & Nat Gas $315 $595 $555 $0 1,466 9.6% 141 0% 0 20.0% $321 $1,929 $4 3.7 Waste Treatment Equipment 989 0 604 0 1,593 9.7% 155 0% 0 30.0% $524 $2,272 $4 3.8 Misc. Power Plant Equipment $1,121 $150 $575 $0 1,846 9.7% 178 0% 0 30.0% $607 $2,632 $5 SUBTOTAL 3. $10,079 $7,865 $10,141 $0 $28,085 $2,650 $0 $7,107 $37,842 $72 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,671 $0 $62,284 $0 $175,955 9.2% $16,119 13.9% $24,419 15.3% $33,196 $249,688 $478 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.3 ASU/Oxidant Compression $192,866 $0 w/equip. $0 $192,866 9.7% $18,694 0% $0 10.0% $21,156 $232,717 $445 4.4 Scrubber & Low Temperature Cooling 6,039 $4,915 $5,116 $0 $16,070 9.6% $1,543 0% $0 20.0% $3,523 $21,136 $40 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.6 Soot Recovery & SARU $1,842 $875 $1,728 $0 $4,445 9.6% $428 0% $0 20.0% $975 $5,848 $11 4.7 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 4.8 Gasification Foundations $0 $6,475 $5,405 $0 $11,880 9.3% $1,101 0% $0 25.0% $3,245 $16,226 $31 SUBTOTAL 4. $314,418 $12,265 $74,533 $0 $401,216 $37,886 $24,419 $62,094 $525,614 $1,005 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected



## 461Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 160 Case 2 D4C (97%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) x $1, 000 Plant Size: 522.89 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $79,390 $0 $67,365 $0 $146,755 9.7% $14,193 20% $29,351 20.0% $38,060 $228,358 $437 5A.2 Elemental Sulfur Plant $10,312 $2,055 $13,304 $0 $25,670 9.7% $2,494 0% $0 20.0% $5,633 $33,797 $65 5A.3 Mercury Removal $1,374 $0 $1,045 $0 $2,419 9.7% $234 5% $121 20.0% $555 $3,328 $6 5A.4 Shift Reactors $9,578 $0 $3,856 $0 $13,434 9.7% $1,306 0% $0 20.0% $2,948 $17,688 $34 5A.5 Particulate Removal $0 $0 $0 $0 $0 0.0% $0 0% $0 10.0% $0 $0 $0 5A.6 Blowback Gas Systems $1,347 $0 $255 $0 $1,602 12.2% $195 0% $0 20.0% $360 $2,157 $4 5A.7 Fuel Gas Piping $0 $612 $429 $0 $1,041 9.3% $96 0% $0 20.0% $227 $1,365 $3 5A.9 HGCU Foundations $0 $641 $413 $0 $1,054 9.2% $97 0% $0 30.0% $345 $1,496 $3

5.9 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 SUBTOTAL 5A. $102,001 $3,308 $86,666 $0 $191,975 $18,615 $29,472 $48,127 $288,189 $551 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 9.6% $0 0% $0 20.0% $0 $0 $0 5B.2 CO2 Compression & Drying $19,393 $0 $11,887 $0 $31,280 9.6% $3,013 0% $0 20.0% $6,859 $41,152 $79 5B.3 CO2 Pipeline 0 0 0 5B.4 CO2 Storage 0 0 0 5B.5 CO2 Monitoring 0 0 0 SUBTOTAL 5B. $19,393 $0 $11,887 $0 $31,280 $3,013 $0 $6,859 $41,152 $79 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $98,609 9.5% 9,348 10% 9,861 10.0% 11,782 129,600 248 6.2 Syngas Expander $5,550 $0 $767 $0 $6,316 9.5% 600 0% 0 15.0% 1,038 7,954 15 6.3 Compressed Air Piping $0 $0 $0 $0 $0 0.0% 0 0% 0 0.0% 0 0 0 6.4 Combustion Turbine Foundations $0 $887 $982 $0 $1,868 9.4% 175 0% 0 30.0% 613 2,656 5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $268 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,462 $0 $4,758 $0 $38,220 9.5% $3,634 0% $0 10.0% $4,185 $46,039 $88 7.2 Open $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 7.3 Ductwork $0 $1,732 $1,236 $0 $2,967 8.8% $260 0% $0 20.0% $646 $3,873 $7 7.4 Stack $3,379 $0 $1,269 $0 $4,648 9.6% $445 0% $0 10.0% $509 $5,602 $11 7.9 HRSG, Duct & Stack Foundations $0 $677 $650 $0 $1,327 9.3% $124 0% $0 30.0% $435 $1,886 $4 SUBTOTAL 7. $36,840 $2,409 $7,913 $0 $47,162 $4,463 $0 $5,775 $57,400 $110 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $27,322 $0 $4,671 $0 $31,993 9.6% $3,070 0% $0 10.0% $3,506 $38,569 $74 8.2 Turbine Plant Auxiliaries $190 $0 $435 $0 $624 9.8% $61 0% $0 10.0% $69 $754 $1 8.3 Condenser & Auxiliaries $4,738 $0 $1,391 $0 $6,129 9.6% $586 0% $0 10.0% $672 $7,387 $14 8.4 Steam Piping $4,984 $0 $3,506 $0 $8,489 8.6% $729 0% $0 25.0% $2,305 $11,523 $22 8.9 TG Foundations $0 $940 $1,589 $0 $2,529 9.5% $240 0% $0 30.0% $831 $3,600 $7 SUBTOTAL 8. $37,233 $940 $11,591 $0 $49,765 $4,686 $0 $7,382 $61,832 $118 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,053 $0 $1,283 $0 $8,336 9.5% $794 0% $0 15.0% $1,369 $10,499 $20 9.2 Circulating Water Pumps $1,834 $0 $132 $0 $1,966 8.4% $166 0% $0 15.0% $320 $2,452 $5 9.3 Circ. Water System Auxiliaries $154 $0 $22 $0 $176 9.5% $17 0% $0 15.0% $29 $221 $0 9.4 Circ. Water Piping $0 $6,417 $1,664 $0 $8,081 9.0% $730 0% $0 20.0% $1,762 $10,573 $20 9.5 Make-up Water System $384 $0 $548 $0 $932 9.6% $89 0% $0 20.0% $204 $1,226 $2 9.6 Component Cooling Water System $758 $906 $645 $0 $2,308 9.4% $216 0% $0 20.0% $505 $3,029 $6 9.9 Circ. Water System Foundations $0 $2,356 $4,004 $0 $6,360 9.5% $603 0% $0 30.0% $2,089 $9,052 $17 SUBTOTAL 9. $10,181 $9,679 $8,299 $0 $28,159 $2,616 $0 $6,278 $37,053 $71 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected

*



## 462Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 160 Case 2 D4C (97%) Capital Costs (continue d)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 14-Jun-10

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) x $1, 000 Plant Size: 522.89 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,118 $6,682 $13,575 $0 $32,376 9.7% $3,125 0% $0 10.0% $3,550 $39,050 $75 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 10.6 Ash Storage Silos $588 $0 $640 $0 $1,228 9.7% $119 0% $0 15.0% $202 $1,549 $3 10.7 Ash Transport & Feed Equipment $788 $0 $190 $0 $979 9.3% $91 0% $0 15.0% $160 $1,230 $2 10.8 Misc. Ash Handling Equipment $1,218 $1,492 $446 $0 $3,156 9.5% $300 0% $0 15.0% $518 $3,974 $8 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $117 9.4% $11 0% $0 30.0% $38 $167 $0 SUBTOTAL 10. $14,712 $8,227 $14,916 $0 $37,855 $3,646 $0 $4,469 $45,971 $88 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $939 $0 $929 $0 $1,868 9.5% $178 0% $0 10.0% $205 $2,251 $4 11.2 Station Service Equipment $4,802 $0 $433 $0 $5,235 9.2% $483 0% $0 10.0% $572 $6,289 $12 11.3 Switchgear & Motor Control $8,877 $0 $1,614 $0 $10,492 9.3% $973 0% $0 15.0% $1,720 $13,185 $25 11.4 Conduit & Cable Tray $0 $4,124 $13,604 $0 $17,728 9.7% $1,715 0% $0 25.0% $4,861 $24,303 $46 11.5 Wire & Cable $0 $7,879 $5,177 $0 $13,056 7.3% $948 0% $0 25.0% $3,501 $17,506 $33 11.6 Protective Equipment $0 $686 $2,496 $0 $3,182 9.8% $311 0% $0 15.0% $524 $4,016 $8 11.7 Standby Equipment $232 $0 $226 $0 $458 9.5% $44 0% $0 15.0% $75 $577 $1 11.8 Main Power Transformers $17,327 $0 $143 $0 $17,470 7.6% $1,321 0% $0 15.0% $2,819 $21,609 $41 11.9 Electrical Foundations $0 $155 $406 $0 $561 9.6% $54 0% $0 30.0% $184 $799 $2 SUBTOTAL 11. $32,177 $12,844 $25,029 $0 $70,050 $6,027 $0 $14,460 $90,536 $173 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.4 Other Major Component Control $1,141 $0 $762 $0 $1,902 9.5% $180 5% $95 15.0% $327 $2,504 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 0.0% $0 0% $0 0.0% $0 $0 $0 12.6 Control Boards,Panels & Racks $262 $0 $168 $0 $430 9.5% $41 5% $22 20.0% $98 $591 $1 12.7 Computer & Accessories $6,085 $0 $195 $0 $6,280 9.2% $576 5% $314 10.0% $717 $7,887 $15 12.8 Instrument Wiring & Tubing $0 $2,126 $4,346 $0 $6,471 8.5% $549 5% $324 25.0% $1,836 $9,180 $18 12.9 Other I & C Equipment $4,067 $0 $1,975 $0 $6,043 9.4% $569 5% $302 15.0% $1,037 $7,950 $15 SUBTOTAL 12. $11,555 $2,126 $7,445 $0 $21,126 $1,915 $1,056 $4,015 $28,112 $54 13 IMPROVEMENTS TO SITE 13.1 Site Preparation 0 110 2,341 0 2,451 9.9% 243 0% 0 30.0% 808 3,503 7 13.2 Site Improvements 0 1,948 2,589 0 4,538 9.9% 448 0% 0 30.0% 1,496 6,481 12 13.3 Site Facilities 3,492 0 3,684 0 7,176 9.9% 707 0% 0 30.0% 2,365 10,248 20 SUBTOTAL 13. $3,492 $2,058 $8,615 $0 $14,165 $1,398 $0 $4,669 $20,232 $39 Acct No. Item/Description Equipment Cost Material Cost Labor Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected



## 463Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 160 Case 2 D4C (97%) Capital Costs (continued)

Department: NETL Office of Systems Analysis and Planning Cost Base: Jun 2007 Project: CO2 Capture Sensitivity Systems Analysis Prepared: 27-May-11

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) x $1, 000 Plant Size: 522.89 MW, net Capital Charge Factor 0.1773 Capacity Factor 0.8

Direct Indirect % Total % Total % Total $ $/kW 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $414 8.8% $36 0% $0 20.0% $90 $541 $1 14.2 Steam Turbine Building $0 $2,379 $3,389 $0 $5,768 9.2% $531 0% $0 15.0% $945 $7,243 $14 14.3 Administration Building $0 $883 $641 $0 $1,523 8.9% $136 0% $0 15.0% $249 $1,908 $4 14.4 Circulation Water Pumphouse $0 $164 $87 $0 $251 8.8% $22 0% $0 15.0% $41 $314 $1 14.5 Water Treatment Buildings $0 $592 $578 $0 $1,170 9.0% $106 0% $0 15.0% $191 $1,467 $3 14.6 Machine Shop $0 $452 $309 $0 $761 8.9% $68 0% $0 15.0% $124 $953 $2 14.7 Warehouse $0 $730 $471 $0 $1,201 8.9% $106 0% $0 15.0% $196 $1,503 $3 14.8 Other Buildings & Structures $0 $437 $340 $0 $777 8.9% $69 0% $0 20.0% $169 $1,016 $2 14.9 Waste Treating Building & Str. $0 $975 $1,863 $0 $2,838 9.3% $265 0% $0 20.0% $620 $3,723 $7 SUBTOTAL 14. $0 $6,876 $7,827 $0 $14,703 $1,338 $0 $2,626 $18,668 $36 Total Cost $728,268 $76,573 $308,878 $0 $1,113,719 $104,861 $66,384 $203,184 $1,488,149 $2,846


### Owner's Costs Preproduction Costs 6 Months All Labor $13,572 $26 1 Month Maintenance Materials $3,024 $6 1 Month Non-fuel Consumables $384 $1 1 Month Waste Disposal $317 $1 25% of 1 Months Fuel Cost at 100% CF $1,693 $3 2% of TPC $29,763 $57
Total $48,754 $93 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,312 $27 0.5% of TPC (spare parts) $7,441 $14
Total $21,753 $42

Initial Cost for Catalyst and Chemicals $7,479 $14 Land $900 $2 Other Owner's Costs $223,222 $427

Financing Costs $40,180 $77 

### Total Overnight Costs (TOC) $1,830,436 $3,501 TASC Multiplier (IOU, high risk, 35 year) 1.140 

### Total As-Spent Cost (TASC) $2,086,697 $3,991 Eng'g CM H.O. & Process Cont. Project Cont. TOTAL PLANT COST Bare Erected Acct No. Item/Description Equipment Cost Material Cost Labor



## 464Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 4
- 161 Case 2 D4C Initial and Annual O&M Expenses

Case: Case 2 D4C - GEE IGCC w/ two WGS (97% CO2 Capture) Plant Size (MWe): 522.89 Heat Rate (Btu/kWh): 10,840 Primary/Secondary Fuel: Illinois #6 Bituminous Coal Fuel Cost ($/MM Btu): 1.64 Design/Construction 5 years Book Life (yrs): 30 TPC (Plant Cost) Year: Jun 2007 TPI Year: 2015 Capacity Factor (%): 80 CO 2 Captured (TPD): 14,240

OPERATING & MAINTENANCE LABOR Operating Labor

Operating Labor Rate (base): $34.65 $/hour Operating Labor Burden: 30.00 % of base Labor Overhead Charge: 25.00 % of labor
Operating Labor Requirements per Shift: units/mod. Total Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's etc. 3.0 3.0 TOTAL Operating Jobs 16.0 16.0
$ $/kW-net Annual Operating Labor Cost (calc'd) $6,313,507 $12.074 Maintenance Labor Cost (calc'd) $15,401,050 $29.454 Administrative & Support Labor (calc'd) $5,428,639 $10.382 Property Taxes & Insurance $29,762,975 $56.920 TOTAL FIXED OPERATING COSTS $56,906,172 $108.830 VARIABLE OPERATING COSTS $ $/kWh-net

Maintenance Material Costs (calc'd) $29,033,099 0.00792

Consumables Unit Initial Initial /Day Cost Cost $ $/kWh-net Water (/1000 gallons) 0 4,109 1.08 $0 $1,297,837 0.00035

Chemicals MU & WT Chem. (lbs) 0 24,480 0.17 $0 $1,237,142 0.00034 Carbon (Mercury Removal) (lb) 79,597 136 1.05 $83,590 $41,704 0.00001 COS Catalyst (m3) 0 0.00 2,397.36 $0 $0 0.00000 Water Gas Shift Catalyst (ft3) 6,232 4.27 498.83 $3,108,715 $621,743 0.00017 Selexol Solution (gal) 319,914 106 13.40 $4,286,284 $414,702 0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 0.00000 Claus Catalyst (ft3) 0 2.01 131.27 $0 $77,019 0.00002 Subtotal Chemicals $7,478,589 $2,392,310 0.00065 Other Supplemental Fuel (MMBtu) 0 0 0.00 $0 $0 0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 0.00000 Subtotal Other $0 $0 0.00000 Waste Disposal Spent Mercury Sorbent (lb) 0 136 0.42 $0 $16,679 0.00000 Flyash (ton) 0 0 0.00 $0 $0 0.00000 Slag (ton) 0 640 16.23 $0 $3,030,656 0.00083 Subtotal Solid Waste Disposal $0 $3,047,335 $0
By-products & Emissions Sulfur (tons) 0 146 0.00 $0 $0 0.00000 Subtotal By-Products $0 $0 $0

TOTAL VARIABLE OPERATING COSTS $35,770,582 0.00976 Coal FUEL (tons) 0 5,830 38.19 $0 $65,007,907 0.01774 INITIAL & ANNUAL O&M EXPENSES

Annual Costs

Consumption



## 465Carbon Dioxide Capture Sensitivity Analysis



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466Carbon Dioxide Capture Sensitivity Analysis



# 4.3.7 GEE IGCC Cost and Performance Summary
A summary of plant costs and performance for the GEE IGCC cases is shown in Exhibit 4

- 162

.
Exhibit 4
- 162 Cost and Performance Results for the GEE IGCC Cases

Case 2
- D1A 2
- D1B 2
- D2A 2
- D2B 2
- D2C 2
- D2D 2
- D3A 2
- D3B 2
- D3C 2
- D3D 2
- D3E 2
- D4A 2
- D4B 2
- D4C
CO 2 Capture, % 

### 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97% Gross Power Output, MW e 

### 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6
Net Power Output, MW e 

### 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9 Net Plant Efficiency, % (HHV) 

### 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5 Net Plant Heat Rate, Btu/kWh (HHV) 

### 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840 Coal Flowrate (lb/hr) 

### 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856
Total CO 2 Captured, lb/MWh net 

### NA 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269
CO 2 Capture & Compression Cost, $x1000 

### 0 $ 166,439 $ 166,741 $ 193,350 $ 212,092 $ 231,604 $ 167,196 $ 194,185 $ 212,378 $ 230,775 $ 242,919 $ 251,958 $ 264,505 $ 228,358 Total Plant Cost, $x1000 

### $ 1,235,944 $ 1,345,298 $ 1,346,066 $ 1,389,128 $ 1,419,771 $ 1,449,191 $ 1,346,380 $ 1,390,235 $ 1,419,640 $ 1,447,904 $ 1,465,871 $ 1,472,866 $ 1,483,871 $ 1,488,149 Owner’s Costs, $x1000 

### $286,161 $308,679 $308,860 $319,113 $326,535 $333,624 $308,914 $319,358 $326,551 $333,508 $337,972 $338,851 $341,323 $342,287 Total Overnight Cost, $x1000 

### $1,522,105 $1,653,977 $1,654,925 $1,708,241 $1,746,306 $1,782,815 $1,655,294 $1,709,592 $1,746,192 $1,781,411 $1,803,843 $1,811,717 $1,825,194 $1,830,436 Total Overnight Cost, $/kW 

### $2,447 $2,724 $2,726 $2,891 $3,019 $3,161 $2,727 $2,897 $3,024 $3,160 $3,253 $3,335 $3,453 $3,501
Total As

- Spent Capital, $x1000 

### $1,735,200 $1,885,534 $1,886,615 $1,947,394 $1,990,789 $2,032,409 $1,887,035 $1,948,935 $1,990,658 $2,030,809 $2,056,381 $2,065,358 $2,080,721 $2,086,697
Total As

- Spent Capital, $/kW 

### $2,790 $3,105 $3,108 $3,296 $3,442 $3,604 $3,109 $3,303 $3,447 $3,602 $3,709 $3,802 $3,937 $3,991
CO 2 Capital Cost Penalty a , $/kW 

### $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054 Cost of Electricity b

, mills /kWh 

### 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8
COE CO 2 Penalty a
, mills /kWh 

### NA 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4
Percent increase in COE a , % 

### NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1%
Cost of CO 2 Avoided a , $/tonne 

### NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0
CO 2 Emissions, lb/MMBtu 

### 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5
CO 2 Emissions, lb/MWh net 

### 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71
SO 2 Emissions, lb/MMBtu 

### 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002
SO 2 Emissions, lb/MWh 

### 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 NOx Emissions, lb/MMBtu 

### 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049 NOx Emissions, lb/MWh 

### 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382 PM Emissions, lb/MMBtu 

### 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 PM Emissions, lb/MWh 

### 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056 Hg Emissions, lb/TBtu 

### 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 Hg Emissions, lb/TWh 

### 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48 Raw Water Withdrawal, gpm 

### 4,734 4,692 4,697 5,038 5,300 5,530 4,695 5,040 5,307 5,569 5,748 5,817 5,739 5,707 Raw Water Consumption, gpm 

### 3,755 3,722 3,727 4,033 4,270 4,481 3,725 4,034 4,276 4,514 4,677 4,741 4,679 4,654 Raw Water Consumption, gal/MWh net 

### 362 368 368 410 443 477 368 410 444 480 506 524 531 534 a Relative to Case 2 D1A ( IGCC 0% CO 2 capture) b Capacity factor is 80% for the GEE IGCC cases



## 467Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

468Carbon Dioxide Capture Sensitivity Analysis



# 5. Results
The objective of this study was to ident ify the optimal CO 2 

## capture level at new SC PC and IGCC power plants by employing state

- of

- the

- art control technologies in multiple process configurations. The SC PC cases (Case 1) utilize Fluor’s Econamine FG Plus SM 

## process for post

- combustion CO 2 

## capture, while t he IGCC cases (Case 2) employ a slurry

- fed, entrained

fl ow GEE gasifier and leverage UOP’s two

- stage SelexolTM process for pre

- combustion CO 2 

## capture

. The major results from the CO 2 

## capture sensitivity analysis are discussed below in the following order:

• Performance (efficiency)

• Econom ics (total overnight cost, cost of electricity, and CO 2 

## avoided cost)

• Performance and Cost summary



# 5.2 Performance

5.2.1 Energy Efficiency The net plant HHV efficiencies for the SC PC and GEE IGCC cases are presented in Exhibit 5

- 1 and Exhibit 5

- 2 , respectively

. As the CO 2 

## capture requirement is increased for either plant type, PC or IGCC, there is an increase in the auxiliary power required to support the capture equipment (either Econamine or Selexol TM ) and the CO 2 

## compressor trains. Further, more steam is consumed by the capture equipment, and by the WGS re actor(s) in the IGCC case, making less available for supply to the steam turbine. Both effects (higher auxiliary load and reduced steam supply to the turbine) detract from the net power produced by the plant per unit of coal energy input, as evidenced by the predicted net plant HHV efficiency trends v ersu s CO 2 

## capture level

.

469Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 1 Net Plant HHV Efficiency for the Supercritical PC Cases

39.3

35.2

32.9 30.6 28.9 28.2

27.5 25.7

0 10 20 30 40 50

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99%Net Plant HHV Efficiency, % Net Plant HHV Efficiency (%)

Capture with Bypass Full Capture



## 470Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 2 Net Plant HHV Efficiency for the GEE IGCC Cases

39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4
32.6 31.8 31.5

0 10 20 30 40 50

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97%Net Plant HHV Efficiency, % Net Plant HHV Efficiency (%)

No WGS Two WGS w/ Bypass One WGS w/ Bypass Two WGS w/o Bypass



# 5.3 Econom ics

5.3.1 Total Overnight Cost All capital costs are presented as “overnight costs” expressed in J une 2007 dollars. The c apital costs are presented at the TOC level, which includes: (1) e quipment (complete with initial
c hemical and catalyst loadings); (2) m a terials; (3) labor (direct and indirect); (4) e ngineering and construction management; (5) c ont ingencies (process and project); and (6) owner’s costs

. The owner’s costs, which are summarized in Exhibit 2

- 18 , include preproduction costs, inventory capital, land costs, financing costs, initial cost for catalysts/chemicals, taxes and insurances, and other owner’s costs.

The TOC for the SC PC and GEE IGCC cases are presented in Exhibit 5

- 3 and Exhibit 5

- 4 , respectively. These exhibits categorized the TOC into five categories: (1) bare erected cost ; (2) engineering, home offi ce, CM , and fee; (3) project contingency; (4) process contingency; and (5) owner’s costs.

471Carbon Dioxide Capture Sensitivity Analysis



## The SC PC Ca se 1 TOC estimates apply to facilities designed with a fixed 550 MW net capacity. As the design is equipped for increased CO 2 

## capture, moving from Case 1A through Case 1G, the TOC also increase s as a result of the need for larger power plant components for power generation to offset the auxiliary power and steam requirements of the CO 2 

## capture and compression systems . Hence , the increase in installed TOC per net kW delivered.

Exhibit 5
- 3 TOC for the Supercritical PC Cases

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99% 

### 2,025 2,541 2,808 3,075 3,400 3,484 3,572 3,744TOC, $/kW 

### Owner's Costs Process Contingency Project Contingency Engr., Home Office, CM, and Fee
Bare Erected Cost

Capture with Bypass Capture without Bypass



## The Ca se 2 GEE IGCC TOC estimates apply to facilities d esigned with a fixed gross combustion turbine capacity of 464 MW . As the plant is equipped for increased CO 2 

## capture, moving from Case 2 D1A through Case 2 D4C , the TOC also increase s as a res ult of the need for larger plant components for power generation to offset the auxiliary power and steam requirements of the WGS reactor(s) and the CO 2 

## capture and compress ion systems . Hence , the increase in installed TOC per net kW delivered.

472Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 4 TOC for the GEE IGCC Cases

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

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97% 2,447 2,724 2,726 2,891 3,019 3,161

2,727 2,897 3,024 3,160 3,253 3,335 3,453 3,501TOC, $/kW Owner's Costs

Process Contingency Project Contingency Engr., Home Office, CM, and Fee
Bare Erected Cost



### No WGS Two WGS w/ Bypass One WGS w/ Bypass Two WGS w/o Bypass



# 5.3.2 Cost of Electricity The revenue requirement figure

- of

- merit in this report is COE expressed in mills/kWh (numerically equivalent to $/MWh). The capital expenditure and operating periods for SC PC and IGCC power plants are 5 and 30 years, respectively. The costs associated with CO 2 

## TS&M are included for all capture cases. All costs a re expressed in June 2007 dollars, and the resulting COE is also expressed in June 2007 year dollars.

The COE for the SC PC and GEE IGCC cases are presented in Exhibit 5

- 5 and Exhibit 5

- 6 , respectively. These exhibits categorized the COE into five categories: (1) capital costs; (2) fixed costs; (3) variable costs; (4) fuel costs; and (5) CO 2 

## TS&M costs.

The COE estimates are based on capacity factors of 85 and 80 percent for the SC PC and GEE IGCC cases, respectively.

473Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 5 COE for the Supercritical PC Cases

0 20 40 60 80 100 120 140

Case 0 0% Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99% 

### 58.9 76.6 84.4 92.8 101.5 104.3 107.0 112.7COE, mills/kWh 

### CO2 TS&M Costs
Fuel Costs
Variable Costs
Fixed Costs Capital Costs

Capture with Bypass Capture without Bypass



## 474Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 6 COE for the GEE IGCC Cases

0 20 40 60 80 100 120 140

D1A 0% D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97% 

### 76.3 85.3 85.4 90.8 95.2 100.0

85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8COE, mills/kWh 

### CO2 TS&M Costs
Fuel Costs
Variable Costs
Fixed Costs Capital Costs

No WGS Two WGS w/ Bypass One WGS w/ Bypass Two WGS w/o Bypass



## The CO 2 

## TS&M cost s were developed using reference data and scaled estimates , as discussed in Section 2.7 . In general, the CO 2 

## TS&M costs account for about two to three percent of the total COE . A breakdown of the CO 2 

## TS&M costs for the SC PC and GEE IGCC cases are shown in Exhibit 5

- 7 and Exhibit 5

- 8 , respectively

.
Exhibit 5
- 7 CO 2 

### TS&M COE for the Supercritical PC Cases

Study Case (CO 2 

### Capture Level) mills /kWh
CO 2 

### Transport CO 2 

### Storage CO 2 

### Monitoring TS&M COE Total COE Case 1A (30%) 1.84 0.77 0.30 2.92 76.64 Case 1B (50%) 2.06 1.04 0.55 3.64 84.38 Case 1C (70%) 2.55 1.38 0.82 4.75 92.75 Case 1D (85%) 2.55 1.64 1.05 5.24 101.49 Case 1E (90%) 2.83 1.74 1.14 5.71 104.29 Case 1F (95%) 2.83 1.84 1.24 5.91 107.00 Case 1G (99%) 2.83 1.99 1.38 6.20 112.65



## 475Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 8 CO 2 

### TS&M COE for the GEE IGCC Cases

Study Case (CO 2 

### Capture Level) mills /kWh
CO 2 

### Transport CO 2 

### Storage CO 2 

### Monitoring TS&M COE Total COE Case 2 D1A (0%) 0.00 0.00 0.00 0.00 76.31 Case 2 D1B (25%) 1.77 0.67 0.23 2.67 85.35 Case 2 D2A (25%) 1.78 0.67 0.23 2.68 85.41 Case 2 D2B (45%) 2.03 0.90 0.43 3.36 90.83 Case 2 D2C (60%) 2.31 1.08 0.59 3.98 95.16 Case 2 D2D (75%) 2.64 1.28 0.76 4.68 99.98 Case 2 D3A (25%) 1.78 0.67 0.23 2.68 85.43 Case 2 D3B (45%) 2.04 0.90 0.43 3.36 90.99 Case 2 D3C (60%) 2.32 1.09 0.59 3.99 95.31 Case 2 D3D (75%) 2.64 1.28 0.76 4.68 99.96 Case 2 D3E (85%) 2.68 1.48 0.89 5.05 103.08 Case 2 D4A (90%) 2.74 1.57 0.96 5.27 105.70 Case 2 D4B (95%) 2.82 1.67 1.04 5.53 109.32 Case 2 D4C (97%) 2.85 1.72 1.07 5.63 110.75



# 5.3.3 CO 2 

# Avoided Costs

The CO 2 

## avoided cost was calculated as illustrated in Equation 1.

( 1 ) 

# MWh tonnes Emissions CO Emissions CO MWh COE COE Cost Avoided

removal with reference reference removal with 

# / } { / $ } {

2 2 

# − −

=

The CO 2 

## avoided costs for the SC PC and GEE IGCC cases are presented in Exhibit 5

- 9 and Exhibit 5

- 10 , respectively. The IGCC cases are presented both relative to the equivalent IGCC without carbon capture and SC PC without capture plants. For the SC PC plant, the CO 2 

## avoided costs decrease as the CO 2 

## capture level increases until reaching minimum values at 95 percent capture (Case 1F).

476Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 9 CO 2 

### Avoided Costs for the Supercritical PC Cases

$0 $20 $40 $60 $80 $100 $120 $140

Case 1A 30% Case 1B 50% Case 1C 70% Case 1D 85% Case 1E 90% Case 1F 95% Case 1G 99% 

### 103

79

69 67 66 65 68CO2Avoided Cost, $/tonne



### Capture with Bypass Capture without Bypass



## The CO 2 

## avoided costs for the GEE IGCC cases decrease as the CO 2 

## capture level increases, until reaching minimum values at 85 to 90 percent capture (Cases D3E and D4A). As a result, this analysis concludes that 85 to 90 percent is the optimal CO 2 

## capture level f or a GEE IGCC power plant.

477Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 10 CO 2 

### Avoided Costs for the GEE IGCC Cases

$0 $20 $40 $60 $80 $100 $120 $140

D1B 25% D2A 25% D2B 45% D2C 60% D2D 75% D3A 25% D3B 45% D3C 60% D3D 75% D3E 85% D4A 90% D4B 95% D4C 97% 

### 129 128

93

79
71 128

94

80

71 67 66 67 67

49 49 45 43 42 49 45 44 42 42 43 45 46CO2Avoided Cost, $/tonne 

### Relative to SCPC w/o CCS Relative to IGCC w/o CCS

No WGS Two WGS w/ Bypass One WGS w/ Bypass Two WGS w/o Bypass



# 5.4 Cost a nd Performance Summary
The following conclusions can be drawn from this analysis.



# 5.4.1 Supercritical PC Cases
 The ‘slip

- stream’ approach is more cost

- effective for <90 percent CO 2 

## capture than removing reduced CO 2 

## fractions from the entire flue gas stream. The cost of CO 2 

## ca pture with the Econamine process is dependent on the volume of gas being treated and a reducti on in flue gas flow rate will: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of the CO 2 

## absorption columns; (3) trim the cooling water requirement of the direct contact cooling system; and (4) decrease the amount of fan power required to increase flue gas temperature and plume buoyancy.
 With partial bypass around the Econamine system, CO 2 

## capture is limited to 85 percent

. To achieve 90 percent or greater CO 2 

## capture, the entire flue gas stream must be treated.
 On a $/ton ne CO 2 

## avoided basis, 95 percent (Case 1F) is the optimal CO 2 

## capture level.

478Carbon Dioxide Capture Sensitivity Analysis



# 5.4.2 GEE IGCC Cases

 For the GEE gasifier, CO 2 

## capture is limited to 25 percent without WGS.
 Due to the high level of integration between the H 2 

## S and CO 2 

## absorbers in the two

- stage SelexolTM system ( see Exhibit 4

- 8 ), it is assumed in this analysis that it is not possible to operate the two stages indepe ndently, and therefore is not feasible to model 0 percent CO 2 

## capture with this system. Since the first stage is designed to operate synergistically with the second, some level of CO 2 

## removal is unavoidable.
 With a S:DG ratio of 0.25, CO 2 

## capture is lim ited to: (1) 75 percent with one

- stage WGS; and (2) 85 percent with two

- stage WGS and five percent WGS bypass.
 For 90 percent or greater CO 2 

## capture, two WGS reactors without bypass and a S:DG ratio of 0.3 are required.
 The performance and cost for interme diate levels of CO 2 

## capture (25 to 75 percent ) are similar with one

- and two

- stage WGS. The two

- stage WGS system requires more shift steam for the two reactors, but the one

- stage WGS system requires a larger COS hydrolysis unit to treat the entire syngas stream, which adds capital cost.
 On a $/ton ne CO 2 

## avoided basis, 85 to 90 percent is the optimal CO 2 

## capture level.



# 5.4.3 SCPC and IGCC Comparisons The following conclusions can be drawn from this analysis.

• At all levels of carbon capture considered in this analysis, an IGCC plant will operate more efficiently than a SC PC plant. This higher efficiency results in lower fuel costs and reduced coal handling costs for the same level of power output.

• At lower levels of CO 2 

## capture, the COE of a SC PC plant is le ss than an IGCC plant. However this COE advantage begins to disappear as capture level increases. For CCS greater than approximately 90 percent, IGCC and SC PC have costs of electricity that are nearly equal. This same trend applies to plant capital cos ts (expressed in $/kW).

• CO 2 

## avoided costs, using analogous non

- capture plants as reference, are substantially lower for IGCC than for SC PC, for all levels of capture. This is reflective of the relatively lower cost impact associated with adding CO 2 

## contr ols to an IGCC plant compared to SC PC. However, the avoided CO 2 

## costs for IGCC capture plants, using the SC PC non

- capture reference plant, are higher due to the higher COE of non

- capture IGCC plants.

• CO 2 

## avoided costs for SC PC plants are high for low levels of CCS, and then start to diminish as the capture increases. Gradually, a minimum is reached around 95% CCS, before costs start to rise again slightly. This suggests that if a SC PC plant will lay out

479Carbon Dioxide Capture Sensitivity Analysis



## the additional capital required to install CO 2 

## controls, that equipment could be used most cost

- effectively by capturing as much carbon dioxide as possible (up to about 95%).

• CO 2 

## avoided costs for IGCC (relative to an IGCC non

- capture plant) are less volatile than SC PC over a wide range of capture. Although they generally decrease as the level of CCS increases (similar to SC PC), the spread between the high and low values is small relative to SC PC. Since an IGCC system is a more complex process, it better lends itself to optimization than a SC PC plant. To accommodate the specified level of CO 2 

## capture, there were numerous variables that were manipulated simultaneously (including the number of water gas shift reactors, the amount of shift steam required, solvent circulation rate, and the syngas by pass rate) to minimize the cost and performance impact. The SC PC plant, although in most cases less expensive than IGCC, is a simpler process and therefore exhibits less potential for optimization. A summary of SC PC and GEE IGCC plant costs and perfor mance are shown in Exhibit 5

- 11 and Exhibit 5

- 12 , resp ectively

.

480Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 11 Cost and Performance Results for the Supercritical PC Cases
Case 0 1A 1B 1C 1D 1E 1F 1G
CO 2 

### Capture, % 0% 30% 50% 70% 85% 90% 95% 99%
Gross Power Output, MW e 

### 580.4 601.5 618.2 637.8 654.8 661.3 667.9 679.6 Net Power Output, MW e 

### 550.0 550.0 550.0 550.0 550.1 550.0 550.0 550.0 Net Plant Efficiency, % (HHV) 39.3 35.2 32.9 30.6 28.9 28.2 27.5 25.7 Net Plant Heat Rate, Btu/kWh (HHV) 8,687 9,695 10,379 11,151 11,819 12,083 12,400 13,269 Coal Flowrate (lb/hr) 409,550 457,066 489,316 525,764 557,283 569,672 584,578 625,561 Total CO 2 

### Captured, lb/MWh net 

### NA 588 1,057 1,582 2,037 2,213 2,398 2,674 CO 2 

### Capture & Compression Cost, $x1000 NA $ 190,138 $ 266,902 $ 336,794 $ 441,781 $ 463,389 $ 485,273 $ 516,797 Total Plant Cost, $x1000 $905,901 $1,138,688 $1,258,942 $1,378,696 $1,525,453 $1,562,889 $1,602,389 $1,678,914 Owner’s Costs, $x1000 $207,800 $258,649 $285,448 $312,458 $344,744 $353,249 $362,267 $380,090 Total Overnight Cost, $x1000 $1,113,701 $1,397,338 $1,544,390 $1,691,155 $1,870,197 $1,916,138 $1,964,657 $2,059,004 Total Overnight Cost, $/kW $2,025 $2,541 $2,808 $3,075 $3,400 $3,484 $3,572 $3,744
Total As

- Spent Capital, $x1000 $1,262,937 $1,592,965 $1,760,604 $1,927,917 $2,132,024 $2,184,397 $2,239,708 $2,347,264
Total As

- Spent Capital, $/kW $2,296 $2,896 $3,201 $3,505 $3,876 $3,972 $4,072 $4,268
CO 2 

### Capital Cost Penalty a 

### , $/kW NA $516 $783 $1,050 $1,375 $1,459 $1,548 $1,719
Cost of Electricity b 

### , mills/kWh 58.90 76.64 84.38 92.75 101.49 104.29 107.00 112.65 COE CO 2 

### Penalty a 

### , mills/kWh NA 17.7 25.5 33.8 42.6 45.4 48.1 53.8 Percent increase in COE a 

### , % NA 30.1 43. 3 57. 5 72.3 77. 1 81. 7 91. 3 Cost of CO 2 

### Avoided a 

### , $/tonne N A 102.8 79.1 69.2 67.2 65.9 64.7 68.2 CO2 Emissions, lb/MMBtu 203.2 142.9 101.7 61.7 31.2 20.4 10.2 2.0 CO 2 

### Emi ssions , lb/MWh net 

### 1,765 1,385 1,055 687 369 246 126 27 SO 2 

### Emissions, lb/MMBtu 0.086 0.064 0.050 0.036 0.017 0.017 0.016 0.016 SO 2 

### Emissions, lb/MWh 0.75 0.570 0.460 0.340 0.170 0.170 0.170 0.170 NOx Emissions, lb/MMBtu 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 NOx Emissions, lb/MWh 0.608 0.621 0.646 0.673 0.695 0.703 0.715 0.752 PM Emissions, lb/MMBtu 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 PM Emissions, lb/MWh 0.113 0.115 0.120 0.125 0.129 0.131 0.133 0.140 Hg Emissions, lb/TBtu 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 Hg Emissions, lb/TWh 9.93 10.1 10.6 11.0 11.3 11.5 11.7 12.3 Raw Water Withdrawal, gpm 5,394 6,245 6,987 8,386 9,615 10,095 10,512 11,664 Raw Water Consumption, gpm 4,301 4,898 5,433 6,474 7,392 7,753 8,074 8,961 Raw Water Consumption, gal/MWh net 

### 469 534 593 706 806 846 881 978

a Relative to Case 0 ( SC PC without capture from 20 10 Bituminous Baseline study) b Capacity factor is 85% for the SC PC cases



## 481Carbon Dioxide Capture Sensitivity Analysis



### Exhibit 5
- 12 Cost and Performance Results for the GEE IGCC Cases
Case 2
- D1A 2
- D1B 2
- D2A 2
- D2B 2
- D2C 2
- D2D 2
- D3A 2
- D3B 2
- D3C 2
- D3D 2
- D3E 2
- D4A 2
- D4B 2
- D4C
CO 2 

### Capture, % 0% 25% 25% 45% 60% 75% 25% 45% 60% 75% 85% 90% 95% 97% Gross Power Output, MW e 

### 747.8 750.4 750.4 746.9 745.2 742.0 750.4 746.2 744.2 741.6 739.8 734.0 726.6 723.6 Net Power Output, MW e 

### 622.0 607.2 607.0 590.8 578.4 563.9 607.0 590.0 577.4 563.8 554.5 543.2 528.5 522.9 Net Plant Efficiency, % (HHV) 39.0 38.4 38.4 36.8 35.5 34.3 38.4 36.7 35.5 34.2 33.4 32.6 31.8 31.5 Net Plant Heat Rate, Btu/kWh (HHV) 8,756 8,891 8,895 9,283 9,604 9,958 8,894 9,289 9,614 9,969 10,222 10,459 10,731 10,840 Coal Flowrate (lb/hr) 466,861 462,752 462,861 470,117 476,133 481,355 462,783 469,844 475,867 481,779 485,836 487,026 486,169 485,856 Total CO 2 

### Captured, lb/MWh net 

### 0 425 430 809 1,127 1,476 429 810 1,125 1,467 1,710 1,899 2,159 2,269 CO 2 

### Capture & Compression Cost, $x1000 0 $166,439 $166,741 $193,350 $212,092 $231,604 $167,196 $194,185 $212,378 $230,775 $242,919 $251,958 $264,505 $228,358 Total Plant Cost, $x1000 $1,235,944 $1,345,298 $1,346,066 $1,389,128 $1,419,771 $1,449,191 $1,346,380 $1,390,235 $1,419,640 $1,447,904 $1,465,871 $1,472,866 $1,483,871 $1,488,149 Owner’s Costs, $x1000 $286,161 $308,679 $308,860 $319,113 $326,535 $333,624 $308,914 $319,358 $326,551 $333,508 $337,972 $338,851 $341,323 $342,287
Total Overnight Cost, $x1000 $1,522,105 $1,653,977 $1,654,925 $1,708,241 $1,746,306 $1,782,815 $1,655,294 $1,709,592 $1,746,192 $1,781,411 $1,803,843 $1,811,717 $1,825,194 $1,830,436 Total Overnight Cost, $/kW $2,447 $2,724 $2,726 $2,891 $3,019 $3,161 $2,727 $2,897 $3,024 $3,160 $3,253 $3,335 $3,453 $3,501
Total As

- Spent Capital, $x1000 $1,735,200 $1,885,534 $1,886,615 $1,947,394 $1,990,789 $2,032,409 $1,887,035 $1,948,935 $1,990,658 $2,030,809 $2,056,381 $2,065,358 $2,080,721 $2,086,697
Total As

- Spent Capital, $/kW $2,790 $3,105 $3,108 $3,296 $3,442 $3,604 $3,109 $3,303 $3,447 $3,602 $3,709 $3,802 $3,937 $3,991
CO 2 

### Capital Cost Penalty a 

### , $/kW $0 $277 $279 $444 $572 $715 $280 $450 $577 $713 $806 $888 $1,007 $1,054 Cost of Electricity b 

### , mills/kWh 76.3 85.3 85.4 90.8 95.2 100.0 85.4 91.0 95.3 100.0 103.1 105.7 109.3 110.8 COE CO 2 

### Penalty a 

### , mills/kWh 0.0 9.0 9.1 14.5 18.9 23.7 9.1 14.7 19.0 23.7 26.8 29.4 33.0 34.4
Percent increase in COE a 

### , % NA 11.8% 11.9% 19.0% 24.7% 31.0% 12.0% 19.2% 24.9% 31.0% 35.1% 38.5% 43.3% 45.1% Cost of CO 2 

### Avoided a 

### , $/tonne NA 48.7 48.6 44.9 43.1 42.5 48.7 45.4 43.6 42.5 41.7 42.7 45.2 46.0 CO2 Emissions, lb/MMBtu 196.8 147.8 147.3 108.8 78.9 49.7 147.3 108.8 79.2 49.7 30.1 19.7 10.4 6.5 CO 2 

### Emi ssions , lb/MWh net 

### 1,723 1,314 1,310 1,010 758 495 1,310 1,011 762 496 308 206 112 71 SO 2 

### Emissions, lb/MMBtu 0.005 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 0.002 SO 2 

### Emissions, lb/MWh 0.040 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 NOx Emissions, lb/MMBtu 0.059 0.055 0.055 0.053 0.051 0.050 0.055 0.053 0.052 0.050 0.049 0.049 0.049 0.049 NOx Emissions, lb/MWh 0.430 0.397 0.397 0.390 0.384 0.379 0.397 0.391 0.385 0.379 0.375 0.376 0.380 0.382 PM Emissions, lb/MMBtu 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 PM Emissions, lb/MWh 0.052 0.051 0.051 0.052 0.053 0.054 0.051 0.052 0.053 0.054 0.054 0.055 0.055 0.056 Hg Emissions, lb/TBtu 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 0.571 Hg Emissions, lb/TWh 4.16 4.11 4.11 4.20 4.26 4.32 4.11 4.20 4.26 4.33 4.38 4.42 4.46 4.48 Raw Water Withdrawal, gpm 4,734 4,697 4,700 5,039 5,301 5,531 4,701 5,048 5,308 5,571 5,749 5,818 5,740 5,708 Raw Water Consumption, gpm 3,755 3,726 3,729 4,034 4,271 4,482 3,729 4,040 4,277 4,515 4,678 4,742 4,680 4,655 Raw Water Consumption, gal/MWh net 

### 362 368 369 410 443 477 369 411 444 480 506 524 531 534

a Relative to Case 0 ( GEE IGCC without capture from 20 10 Bituminous Baseline study) b Capacity factor is 80% for the GEE IGCC cases



## 482Carbon Dioxide Capture Sensitivity Analysis



# Appendix A

483Carbon Dioxide Capture Sensitivity Analysis



## As part of this study, various cost curves and algorithms were generated as a function of the CO 2 

## capture level. The algorithms can be used to estimate and predict the cost of CO 2 

## capture over a full range of removal efficiencies. The following figures present the results of this effort for both the SC PC and GEE IGCC cases.

Supercritical PC Cost Algorithms
Appendix A
- 1 Supercritical PC CO 2 

### Capture & Compression Cost, $000

y = 0.5548x 3

- 84.558x 2 + 8184.8x + 1105.6 R2 = 0.9977



### 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000 500,000 550,000

0 20 40 60 80 100CO2Capture & Compression, $000



### CO 2 

### Removal, %


### Appendix A
- 2 Supercritical PC CO 2 

### Capture & Compression Cost, $/kW

y = 0.001x 3

- 0.1539x 2 + 14.887x + 2.0058 R2 = 0.9977



### 0 100 200 300 400 500 600 700 800 900 1000

0 20 40 60 80 100CO2Capture & Compression, $/kW



### CO 2 

### Removal, %



## 484Carbon Dioxide Capture Sensitivity Analysis



### Appendix A
- 3 Supercritical PC Total Overnight Cost, $000

y = 17.407x 2 

### + 7296.4x + 1E+06 R2 = 0.9942



## 0 500,000 1,000,000 1,500,000 2,000,000 2,500,000

0 20 40 60 80 100TOC, $000



## CO 2 

## Removal, %
Appendix A
- 4 Supercritical PC Total Overnight Cost, $/kW

y = 0.0317x 2 

### + 13.261x + 2052.5 R2 = 0.9941



## 0 500 1000 1500 2000 2500 3000 3500 4000 4500

0 20 40 60 80 100TOC, $/kW



## CO 2 

## Removal, %



## 485Carbon Dioxide Capture Sensitivity Analysis



### Appendix A
- 5 Supercritical PC Incremental Capital Cost, $000

y = 0.9452x 3



### - 122.94x 2 

### + 12335x

- 145.64 R2 = 0.9987



## 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000

0 20 40 60 80 100Incremental Capital Cost, $000



## CO 2 

## Removal, %

Appendix A
- 6 Supercritical PC Incremental Capital Cost, $/kW

y = 0.0017x 3



### - 0.2244x 2 

### + 22.457x

- 0.2821 R2 = 0.9987



## 0 200 400 600 800 1000 1200 1400 1600 1800 2000

0 20 40 60 80 100Incremental Capital Cost, $/kW



## CO 2 

## Removal, %



## 486Carbon Dioxide Capture Sensitivity Analysis



### Appendix A
- 7 Supercritical PC COE , mills/kWh

y = 0.0004x 2 

### + 0.4627x + 59.954 R2 = 0.9916



## 0 20 40 60 80 100 120 140 160 180 200

0 20 40 60 80 100COE, mills/kWh



## CO 2 

## Removal, %
Appendix A
- 8 Supercritical PC Incremental COE , mills/kWh

y = 7E

- 05x 3



### - 0.0093x 2 

### + 0.8136x

- 0.0139 R2 = 0.9988



## 0 10 20 30 40 50 60 70 80

0 20 40 60 80 100Incremental COE, mills/kWh



## CO 2 

## Removal, %



## 487Carbon Dioxide Capture Sensitivity Analysis



### Appendix A
- 9 Supercritical PC Percent Increase in COE

y = 0.0001x 3



### - 0.0159x 2 

### + 1.3813x

- 0.0236 R2 = 0.9988



## 0 20 40 60 80 100

0 20 40 60 80 100% Increase in COE



## CO 2 

## Removal, % Appendix A
- 10 Supercritical PC CO 2 

### Capture Avoided Costs

y = - 9E

- 05x 3 + 0.0288x 2

- 3.0308x + 170.09 R2 = 0.9942

0 20 40 60 80 100 120

0 20 40 60 80 100CO2Avoided Cost, $/tonne

CO 2 Removal, %



## 488Carbon Dioxide Capture Sensitivity Analysis



## GEE IGCC Cost Algorithms
Appendix A
- 11 GEE IGCC CO 2 

### Capture & Compression Cost, $000

y = 0.6512x 3



### - 128.25x 2 

### + 8882.4x + 6245.6 R2 = 0.968



### 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000

0 20 40 60 80 100CO2Capture & Compression, $000



## CO 2 

## Removal, %
Appendix A
- 12 GEE IGCC CO 2 

### Capture & Compression Cost, $/kW

y = 0.0011x 3



### - 0.2113x 2 

### + 14.69x + 9.2348 R2 = 0.9761



## 0 100 200 300 400 500 600

0 20 40 60 80 100CO2Capture & Compression, $/kW



## CO 2 

## Removal, %



## 489Carbon Dioxide Capture Sensitivity Analysis



### Appendix A
- 13 GEE IGCC Total Overnight Cost, $000

y = - 17.934x 2 

### + 4680.4x + 2E+06 R2 = 0.9908



## 0 500,000 1,000,000 1,500,000 2,000,000 2,500,000

0 20 40 60 80 100TOC, $000



## CO 2 

## Removal, %
Appendix A
- 14 GEE IGCC Total Overnight Cost, $/kW

y = 0.0215x 2 

### + 7.7x + 2492.3 R2 = 0.9883



## 0 500 1000 1500 2000 2500 3000 3500 4000 4500

0 20 40 60 80 100TOC, $/kW



## CO 2 

## Removal, %



## 490Carbon Dioxide Capture Sensitivity Analysis



### Appendix A
- 15 GEE IGCC Incremental Capital Cost, $000

y = 0.3375x 3



### - 67.922x 2 

### + 6587.6x + 2094.5 R2 = 0.9987



## 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000

0 20 40 60 80 100Incremental Capital Cost, $000



## CO 2 

## Removal, %

Appendix A
- 16 GEE IGCC Incremental Capital Cost, $/kW

y = 0.0013x 3



### - 0.1731x 2 

### + 15.129x

- 5.4845 R2 = 0.9979



## 0 100 200 300 400 500 600 700 800 900 1000 1100 1200

0 20 40 60 80 100Incremental Capital Cost, $/kW



## CO 2 

## Removal, %



## 491Carbon Dioxide Capture Sensitivity Analysis



### Appendix A
- 17 GEE IGCC COE , mills/kWh

y = 0.0007x 2 

### + 0.2567x + 77.683 R2 = 0.9909



## 0 20 40 60 80 100 120 140 160 180 200

0 20 40 60 80 100COE, mills/kWh



## CO 2 

## Removal, %
Appendix A
- 18 GEE IGCC Incremental COE , mills/kWh

y = 4E

- 05x 3



### - 0.0051x 2 

### + 0.4762x

- 0.1251 R2 = 0.9986



## 0 10 20 30 40 50 60

0 20 40 60 80 100Incremental COE, mills/kWh



## CO 2 

## Removal, %



## 492Carbon Dioxide Capture Sensitivity Analysis



### Appendix A
- 19 GEE IGCC Percent Increase in COE

y = 5E

- 05x 3



### - 0.0066x 2 

### + 0.6241x

- 0.1639 R2 = 0.9986



## 0 10 20 30 40 50

0 20 40 60 80 100% Increase in COE



## CO 2 

## Removal, %
Appendix A
- 20 GEE IGCC CO 2 

### Capture Avoided Costs

y = 0.0152x 2

- 2.6925x + 185.93 R2 = 0.9976

y = 6E

- 05x 3

- 0.0082x 2 + 0.1857x + 48.148 R2 = 0.9607

0 20 40 60 80 100 120 140

0 20 40 60 80 100CO2Avoided Cost, $/tonne

CO 2 Removal, % Relative to SCPC w/o CCS
Relative to IGCC w/o CCS



## 493Carbon Dioxide Capture Sensitivity Analysis



## This page intentionally left blank

494Carbon Dioxide Capture Sensitivity Analysis



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