# Cost and Performance Baseline for Fossil Energy Plants
Volume 3a: Low Rank Coal to Electricity: IGCC Cases

M ay 2011

D OE/NETL

- 2010/1399

# 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 any legal liability or r esponsibility 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 commercial 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 authors expressed therei n do not necessarily state or reflect those of the United States Government or any agency thereof.

## COST AND PERFORMANCE BASELINE FOR FOSSIL ENERGY PL ANTS VOLUME 3 a : LOW RANK COAL TO E LECTRICITY: IGCC CASES

DOE/NETL

- 2010/1399

Final Report

Ma y 201 1

NETL Contact:

James B. Black

Office of Program Planning & Analysis, Performance Division

National Energy Technology Laboratory www.netl.doe.gov

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)


# NETL Viewpoint
Background

The goal of Fossil Energy Research, Development, and Demonstration (RD&D) is to ensure the availability of ultra

- clean (“zero” emissions), abundant, low

- cost, domestic electricity and energy (including hydrogen) to fuel economic prosperity and strengthen energ y security. A broad portfolio of technologies is being developed within the Clean Coal Program to accomplish this objective. Ever increasing technological enhancements are in various stages of the research “pipeline,” and multiple paths are being pursued to create a portfolio of promising technologies for development, demonstration, and eventual deployment. The technological progress of recent years has created a remarkable new opportunity for coal . Advances in technology are making it possible to gener ate power from fossil fuels with great improvements in the effi ciency of energy

use while at the same time significantly reducing the impact on the environment, including the long

- term impact of fossil energy use on the Earth’s climate. The objective of t he Clean Coal RD&D Program is to build on these advances and bring these building blocks together into a new, revolutionary concept for future coal

- based power and energy production. 

### Objective To establish baseline performance and cost estimates for today ’s fossil energy plants, it is necessary to look at the current state of technology. Such a baseline can be used to benchmark the progress of the Fossil Energy RD&D portfolio. This study provides an accurate, independent assessment of the cost and perfor mance for Integrated Gasification Combined Cycle (IGCC) plants with and without carbon dioxide (CO 2 

### ) capture and sequestration using both Powder River Basin (PRB) and North Dakota lignite (NDL) coals. 

### Approach The power plant configurations analyzed in t his study were modeled using the ASPEN Plus® (Aspen) modeling program. Performance and process limits were based upon published reports, information obtained from vendors and users of the technology, cost and performance data from design/build utility pro jects, and/or best engineering judgment. Capital and operating costs were estimated by WorleyParsons based on simulation results and through a combination of existing vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. O peration and maintenance (O&M) costs and the cost for transporting, storing, and monitoring (TS&M) carbon dioxide (CO 2 

### ) in the cases with carbon capture were also estimated based on reference data and scaled estimates. The cost of electricity (COE) was determined for all plants assuming investor

- owned utility (IOU) financing. The initial results of this analysis were subjected to a significant peer review by industry experts, academia and government research and regulatory agencies. Based on the feedback from these experts, the report was updated both in terms of technical content and revised costs. Fossil Energy RD&D aims at improving the performance and cost of clean coal power systems including the development of new approaches to capture a nd sequester greenhouse gases (GHGs). Improved efficiencies and reduced costs are required to improve the competitiveness of these systems in today’s market and regulatory environment as well as in a carbon constrained scenario. The results of this analy sis provide a starting point from which to measure the progress of RD&D achievements.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)



### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

III 

# Table of Contents

TABLE OF CONTENTS

................................ ................................ ................................ ........... III LIST OF EXHIBITS

................................ ................................ ................................ .................... V PREPARED BY

................................ ................................ ................................ .......................... XI LIST OF ACRONYMS AND ABBREVIATIONS

................................ ............................... XIII EXECUTIVE SUMMARY

................................ ................................ ................................ ........... 1 Energy Efficiency

................................ ................................ ................................ ................................ ................. 3 Water Use

................................ ................................ ................................ ................................ ............................. 3 Cost Results

................................ ................................ ................................ ................................ .......................... 7 Cost of Electricity

................................ ................................ ................................ ................................ ................. 8 Cost of CO 2 Avoided

................................ ................................ ................................ ................................ ........... 12 

### 1. INTRODUCTION

................................ ................................ ................................ ................ 19 2. GENERAL EVALU ATION BASIS

................................ ................................ ................... 23 2.1 S ITE 

### C HARACTERISTICS



### ................................ ................................ ................................ .. 23 2.2 C OAL 

### C HARACTERISTICS



### ................................ ................................ ................................ 25 2.3 E NVI RONMENTAL 

### T ARGETS



### ................................ ................................ ............................ 28 2.4 C APACITY 

### F ACTOR



### ................................ ................................ ................................ ......... 31 2.5 R AW 

### W ATER 

### W ITHDRAWAL AND CONSUM PTION



### ................................ ............................ 31 2.6 C OST 

### E STIMATING 

### M ETHODOLOGY



### ................................ ................................ ................ 33 2.6.1 Capital Costs

................................ ................................ ................................ ................................ ....... 33 2.6.2 Operations and Maintenance Costs

................................ ................................ ................................ ..... 42 2.6.3 CO 2 Transport, Storage and Monitoring

................................ ................................ ............................. 43 2.6.4 Finance Structure, Discounted Cash Flow Analysis, and COE

................................ ........................... 47 

### 2.7 IGCC S TUDY 

### C OST 

### E STIMATES 

### C OMPARED TO 

### I NDUSTRY 

### E STIMATES



### .......................... 54 3. IGCC POWER PLANTS

................................ ................................ ................................ .... 57 3.1 IGCC C OMMON 

### P ROCESS 

### A REAS



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

................................ ................................ ................................ ................ 57 3.1.2 Coal Drying

................................ ................................ ................................ ................................ ......... 58 3.1.3 Gasifier Modeling

................................ ................................ ................................ ................................ 62 3.1.4 ASU Choice and Integration

................................ ................................ ................................ ................ 62 3.1.5 High Temperature Syngas Cooling

................................ ................................ ................................ ...... 66 3.1.6 Water Gas Shift Reactors

................................ ................................ ................................ ..................... 67 3.1.7 COS Hydrolysis

................................ ................................ ................................ ................................ ... 67 3.1.8 Mercury Removal

................................ ................................ ................................ ................................ . 68 3.1.9 Acid Gas Removal Process Selection

................................ ................................ ................................ ... 69 3.1.10 Sulfur Recovery/Tail Gas Cleanup Process Selection

................................ ................................ ......... 77 3.1.11 Slag and Ash Handling

................................ ................................ ................................ ........................ 80 3.1.12 Power Island

................................ ................................ ................................ ................................ ........ 81 3.1.13 Steam Generation Island

................................ ................................ ................................ ..................... 85 3. 1.14 Accessory Electric Plant

................................ ................................ ................................ ...................... 88 3.1.15 Instrumentation and Control

................................ ................................ ................................ ................ 89 

### 3.2 S HELL 

### C OAL 

### G ASIFICATION 

### P ROCESS 

### IGCC C ASES



### ................................ ....................... 90 3.2.1 Gasifier Background

................................ ................................ ................................ ............................ 90 3.2.2 Key System Assumptions

................................ ................................ ................................ ...................... 93 3.2.3 Sparing Philosophy

................................ ................................ ................................ .............................. 95 3.2.4 SCGP IGCC Non

- Capture Case (S1A and L1A) Process Description

................................ ................ 95 3.2.5 Case S1A and L1A Performance Results

................................ ................................ ........................... 104 3.2.6 Case S1A and L1A Equipment Lists

................................ ................................ ................................ ... 118 3.2.7 Case S1A and L1A Cost Estimating

................................ ................................ ................................ ... 132 3.2.8 SCGP IGCC CO 2 Capture Cases (S1B and L1B) Process Description

................................ ............. 145Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

IV 3.2.9 Case S1B and L1B Performance Results

................................ ................................ ........................... 152 3.2.10 Case S1B and L1B Equipment List

................................ ................................ ................................ .... 166 3.2.11 Case S1B and L1B Cost Estimating

................................ ................................ ................................ ... 182 

### 3.3 TRIG TM IGCC C ASES



### ................................ ................................ ................................ ... 195 3.3.1 Gasifier Background

................................ ................................ ................................ .......................... 195 3.3.2 Key System Assumptions

................................ ................................ ................................ .................... 198 3.3.3 Sparing Philosophy

................................ ................................ ................................ ............................ 200 3.3.4 TRIG TM IGCC Non

- Capture Case (S2A) Process Description

................................ .......................... 200 3.3.5 Case S2A Performance Results

................................ ................................ ................................ .......... 207 3.3.6 Case S2A Equipment Lists

................................ ................................ ................................ ................. 217 3.3.7 Case S2A Cost Estimating

................................ ................................ ................................ ................. 229 3.3.8 TRIG TM IGCC CO 2 Capture Cases (S2B) Process Description

................................ ........................ 236 3.3.9 Case S2B Performance Results

................................ ................................ ................................ .......... 241 3.3.10 Case S2B Equipment List

................................ ................................ ................................ ................... 251 3.3.11 Case S2B Cost Estimating

................................ ................................ ................................ ................. 264 

### 3.4 S IEMENS 

### F UEL 

### G ASIFIER 

### IGCC C ASES



### ................................ ................................ ......... 271 3.4.1 Gasifier Background

................................ ................................ ................................ .......................... 271 3.4.2 Key System Assumptions

................................ ................................ ................................ .................... 273 3.4.3 Sparing Philosophy

................................ ................................ ................................ ............................ 275 3.4.4 SFG IGCC Non

- Capture Case (S3A and L3A) Process Description

................................ ................. 275 3.4.5 Case S3A and L3A Performance Results

................................ ................................ ........................... 284 3.4.6 Case S3A and L3A Equipment Lists

................................ ................................ ................................ ... 298 3.4.7 Case S3A and L3A Cost Estimating

................................ ................................ ................................ ... 311 3.4.8 SFG IGCC CO 2 Capture Cases (S3B and L3B) Process Description

................................ ............... 324 3.4.9 Case S3B and L3B Performance Results

................................ ................................ ........................... 331 3.4.10 Case S3B and L3B Equipment List

................................ ................................ ................................ .... 344 3.4.11 Case S3B and L3B Cost Estimating

................................ ................................ ................................ ... 359 

### 3.5 C O 

### P E

- G AS 

### TM IGCC C ASES



### ................................ ................................ ......................... 372 3.5.1 Gasifier Background

................................ ................................ ................................ .......................... 372 3.5.2 Key System Assumptions

................................ ................................ ................................ .................... 374 3.5.3 Sparing Philosophy

................................ ................................ ................................ ............................ 377 3.5.4 CoP E

- Gas TM IGCC Non

- Capture Case (S4A) Process Description

................................ ................ 377 3.5.5 Case S4A Performance Results

................................ ................................ ................................ .......... 384 3.5.6 Case S4A Equipment Lists

................................ ................................ ................................ ................. 393 3.5.7 Case S4A Cost Estimating

................................ ................................ ................................ ................. 40 6 3.5.8 CoP E

- Gas TM IGCC CO 2 Capture Cases (S4B) Process Description

................................ ............... 413 3.5.9 Case S4B Performance Results

................................ ................................ ................................ .......... 418 3.5.10 Case S4B Equipment List

................................ ................................ ................................ ................... 429 3.5.11 Case S4B Co st Estimating

................................ ................................ ................................ ................. 442 

### 3.6 IGCC C ASE 

### S UMMARY



### ................................ ................................ ................................ . 449 4. REFEREN CES

................................ ................................ ................................ ................... 461Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

V 

# List of Exhibits

Exhibit ES

- 1 Case Descriptions

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

- 2 Cost and Performance Summary and Environmental Profile for IGCC Cases

........ 4 Exhibit ES

- 3 Net Plant Efficiency

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

- 4 Raw Water Withdrawal and Consumption

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

- 5 Plant Capital Costs

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

- 6 Economic Parameters Used to Calculate COE

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

- 7 COE by Cost Component

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

- 8 COE Sensitivity to Fuel Costs

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

- 9 COE Sensitivity to Capacity Factor

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

- 10 CO 2 

### Avoided Costs

................................ ................................ .............................. 15 Exhibit ES

- 11 Study Environmental Targets

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

- 12 SO 2 

### , NOx and Particulate Emission Rates

................................ ........................... 17 Exhibit ES

- 13 Mercury Emission Rates

................................ ................................ ...................... 18 Exhibit 1

- 1 IGCC Case Descriptions

................................ ................................ ........................... 20 Exhibit 2

- 1 Montana Site Ambient Conditions for PRB Coal Cases

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

- 2 North Dakota Site Ambient Conditions for Lignite Coal Cases

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

- 3 Site Characteristics

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

- 4 Montana Rosebud PRB, Area D, Western Energy Co. Mine, Subbituminous Design Coal Analysis

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

- 5 North Dakota Beulah

- Zap Lignite, Freedom, ND Mine, Lignite Design Coal Analysis

................................ ................................ ................................ ................................ . 27 Exhibit 2

- 6 Standards of Performance for Electric Utility Steam Generating Units Built, Reconstructed, or Modified After February 28, 2005

................................ ........................... 28 Exhibit 2

- 7 NSPS Mercury Emission Limits

................................ ................................ ............... 29 Exhibit 2

- 8 IGCC Environmental Targets

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

- 9 Capital Cost Levels and their Elements

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

- 10 Features of an AACE Class 4 Cost Estimate

................................ .......................... 34 Exhibit 2

- 11 AACE Guidelines for Process Contingency

................................ ........................... 39 Exhibit 2

- 12 TASC/TOC Fac tors

................................ ................................ ................................ 39 Exhibit 2

- 13 Owner’s Costs Included in TOC

................................ ................................ ............. 40 Exhibit 2

- 14 CO 2 

### Pipeline Specification

................................ ................................ ..................... 44 Exhibit 2

- 15 Deep, Saline Aquifer Specification

................................ ................................ ........ 44 Exhibit 2

- 16 Global Economic Assumptions

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

- 17 Financial Structure for Investor Owned Utility High and Low Risk Projects

........ 48 Exhibit 2

- 18 Illustration of COE Solutions using DCF Analysis

................................ ................ 50 Exhibit 2

- 19 PC with CCS in Current 2007 Dollars

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

- 20 Capital Charge Factors for COE Equ ation

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

- 21 COE and LCOE Summary

................................ ................................ ...................... 53 Exhibit 2

- 22 Baseline SC PC Results for CO 2 

### Cost Calculation

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

- 1 SCGP Lignite Coal Drying Options

................................ ................................ ......... 60 Exhibit 3

- 2 WTA Process Schematic

................................ ................................ .......................... 61 Exhibit 3

- 3 Air Extracted from the Combustion Turbine and Supplied to the ASU i n Non

Carbon Capture Case

................................ ................................ ................................ ............ 64 Exhibit 3

- 4 Typical ASU Process Schematic

................................ ................................ .............. 65Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

VI 

### Exhibit 3

- 5 Flow Diagram for a Conventional AGR Unit

................................ ........................... 70 Exhibit 3

- 6 Summary of Common AGR Processes

................................ ................................ ..... 71 Exhibit 3

- 7 Common Chemical Reagents Used in AGR Processes

................................ ............ 72 Exhibit 3

- 8 Physical Solvent AGR Process Simplified Flow Diagram

................................ ....... 74 Exhibit 3

- 9 Common Physical Solvents Used in AGR Processes

................................ ............... 74 Exhibit 3

- 10 Common Mixed Solvents Used in AGR Processes

................................ ................ 75 Exhibit 3

- 11 Equilibrium Solubility Data on H 2 

### S and CO 2 

### in Various Solvents

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

- 12 Typical Thre e

- Stage Claus Sulfur Plant

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

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

................................ ................................ ................................ ................................ ........ 82 Exhibit 3

- 14 Typical Fuel Specification for F

- Class Machines

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

- 15 Allowable Gas Fuel Contaminant Level for F

- Class Machines

............................. 84 Exhibit 3

- 16 Case S1A/L1A and S1B/L1B Plant Study Configuration Matrix

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

- 17 Balance of Plant Assumptions

................................ ................................ ................ 94 Exhibit 3

- 18 Case S1A and L1A Process Flow Diagram

................................ ............................ 99 Exhibit 3

- 19 Case S1A Stream Table

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

- 20 Case L1A Stream Table

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

- 21 Case S1A and L1A Plant Performance Summary

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

- 22 Cases S1A and L1A Air Emissions

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

- 23 Case S1A and L1A Carbon Balance

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

- 24 Cases S1A and L1A Sulfur Balance

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

- 25 Case S1A and L1A Water Balance

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

- 26 Case S1A Heat and Mass Balance

................................ ................................ ........ 111 Exhibit 3

- 27 Case L1A Heat and Mass Balance

................................ ................................ ........ 114 Exhibit 3

- 28 Cases S1A and L1A Energy Balance

................................ ................................ ... 117 Exhibit 3

- 29 Case S1A Total Plant Cost Summary

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

- 30 Case S1A Total Plant Cost Details

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

- 31 Case S1A Owner’s Costs

................................ ................................ ...................... 137 Exhibit 3

- 32 Case S1A Initial and Annual O&M Costs

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

- 33 Case L1A Total Plant Cost Summary

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

- 34 Case L1A Total Plant Cost Details

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

- 35 Case L1A Owner’s Costs

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

- 36 Case L1A Initial and Annual O&M Costs

................................ ............................ 144 Exhibit 3

- 37 Case S1B and L1B Process Flow Diagram

................................ .......................... 147 Exhibit 3

- 38 Case S1B Stream Table

................................ ................................ ........................ 148 Exhibit 3

- 39 Case L1B Stream Table

................................ ................................ ........................ 150 Exhibit 3

- 40 Case S1B and L1B Plant Performance Summary

................................ ................. 153 Exhibit 3

- 41 Case S1B and L1B Air Emissions

................................ ................................ ........ 154 Exhibit 3

- 42 Cases S1B and L1B Carbon Balance

................................ ................................ .... 155 Exhibit 3

- 43 Cases S1B and L1B Sulfur Balance

................................ ................................ ..... 155 Exhibit 3

- 44 Cases S1B and L1B Water Balance

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

- 45 Case S1B Heat and Mass Bal ance

................................ ................................ ........ 159 Exhibit 3

- 46 Case L1B Heat and Mass Balance

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

- 47 Cases S1B and L1B Energy Balance

................................ ................................ .... 165 Exhibit 3

- 48 Case S1B Total Plant Cost Summary

................................ ................................ ... 183 Exhibit 3

- 49 Case S1B Total Plant Cost Summary Details

................................ ....................... 184Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

VII 

### Exhibit 3

- 50 Case S1B Owner’s Costs

................................ ................................ ...................... 187 Exhibit 3

- 51 Case S1B Initial and Annual O&M Costs

................................ ............................ 188 Exhibit 3

- 52 Case L1B Total Plant Cost Summary

................................ ................................ ... 189 Exhibit 3

- 53 Case L1B Total Plant Cost Summary Details

................................ ....................... 190 Exhibit 3

- 54 Case L1B Owner’s Costs

................................ ................................ ...................... 193 Exhibit 3

- 55 Case L1B Initial and Annual O&M Costs

................................ ............................ 194 Exhibit 3

- 56 Case S2A and S2B Plant Study Configuration Matrix

................................ ......... 198 Exhibit 3

- 57 Balance of Plant Assumptions

................................ ................................ .............. 199 Exhibit 3

- 58 Case S2A Process Flow Diagram

................................ ................................ ......... 204 Exhibit 3

- 59 Case S2A Stream Table

................................ ................................ ........................ 205 Exhibit 3

- 60 Case S2A Plant Performance Summary

................................ ............................... 208 Exhibit 3

- 61 Cases S2A Air Emissions

................................ ................................ ..................... 209 Exhibit 3

- 62 Case S2A Carbon Balance

................................ ................................ .................... 210 Exhibit 3

- 63 Case S2A Sulfur Balance

................................ ................................ ...................... 21 0 Exhibit 3

- 64 Case S2A Water Balance

................................ ................................ ...................... 211 Exhibit 3

- 65 Case S2A Heat and Mass Balance

................................ ................................ ........ 213 Exhibit 3

- 66 Case S2A Energy Balance

................................ ................................ .................... 217 Exhibit 3

- 67 Case S2A Total Plant Cost Summary

................................ ................................ ... 230 Exhibit 3

- 68 Case S2A Total Plant Cost Details

................................ ................................ ....... 231 Exhibit 3

- 69 Case S2A Owner’s Costs

................................ ................................ ...................... 234 Exhibit 3

- 70 Case S2A Initial and Annual O&M Costs

................................ ............................ 235 Exhibit 3

- 71 Case S2B Process Flow Diagram

................................ ................................ ......... 238 Exhibit 3

- 72 Case S2B Stream Table

................................ ................................ ........................ 239 Exhibit 3

- 73 Case S2B Plant Performance Summary

................................ ................................ 242 Exhibit 3

- 74 Case S2B Air Emissions

................................ ................................ ....................... 243 Exhibit 3

- 75 Case S2B Carbon Balance

................................ ................................ .................... 244 Exhibit 3

- 76 Case S2B Sulfur Balance

................................ ................................ ...................... 244 Exhibit 3

- 77 Case S2B Water Balance

................................ ................................ ...................... 245 Exhibit 3

- 78 Case S2B Heat and Mass Balance

................................ ................................ ........ 247 Exhibit 3

- 79 Case S2B Energy Balance

................................ ................................ .................... 251 Exhibit 3

- 80 Case S2B Total Plant Cost Summary

................................ ................................ ... 265 Exhibit 3

- 81 Case S2B Total Plant Cost Summary Details

................................ ....................... 266 Exhibit 3

- 82 Case S2B Owner’s Costs

................................ ................................ ...................... 269 Exhibit 3

- 83 Case S2B Initial and Annual O&M Costs

................................ ............................ 270 Exhibit 3

- 84 Case S3A/L3A and S3B/L3B Plant Study Configuration Matrix

........................ 273 Exhibit 3

- 85 Balance of Plant Assumptions

................................ ................................ .............. 274 Exhibit 3

- 86 Case S3A and L3A Process Flow Diagram

................................ .......................... 279 Exhibit 3

- 87 Case S3A Stream Table

................................ ................................ ........................ 280 Exhibit 3

- 88 Case L3A Stream Table

................................ ................................ ........................ 282 Exhibit 3

- 89 Case S3A and L3A Plant Performance Summary

................................ ................ 285 Exhibit 3

- 90 Cases S3A and L3A Air Emissions

................................ ................................ ...... 286 Exhibit 3

- 91 Case S3A and L3A Carbon Balance

................................ ................................ ..... 287 Exhibit 3

- 92 Cases S3A and L3A Sulfur Balance

................................ ................................ ..... 287 Exhibit 3

- 93 Case S3A and L3A Water Balance

................................ ................................ ....... 288 Exhibit 3

- 94 Case S3A Heat and Mass Balance

................................ ................................ ........ 291 Exhibit 3

- 95 Case L3A Heat and Mass Balance

................................ ................................ ........ 294Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

VIII 

### Exhibit 3

- 96 Cases S3A and L3A Energy Balance

................................ ................................ ... 297 Exhibit 3

- 97 Case S3A Total Plant Cost Summary

................................ ................................ ... 312 Exhibit 3

- 98 Case S3A Total Plant Cost Details

................................ ................................ ....... 313 Exhibit 3

- 99 Case S3A Owner’s Costs

................................ ................................ ...................... 316 Exhibit 3

- 100 Case S3A Initial and Annual O&M Costs

................................ .......................... 317 Exhibit 3

- 101 Case L3A Total Plant Cost Summary

................................ ................................ . 318 Exhibit 3

- 102 Case L3A Total Plant Cost Details

................................ ................................ ..... 319 Exhibit 3

- 103 Case L3A Owner’s Costs

................................ ................................ .................... 322 Exhibit 3

- 104 Case L3A Initial and Annual O&M Costs

................................ .......................... 323 Exhibit 3

- 105 Case S3B and L3B Process Flow Diagram

................................ ........................ 326 Exhibit 3

- 106 Case S3B Stream Table

................................ ................................ ...................... 327 Exhibit 3

- 107 Case L3B Stream Table

................................ ................................ ...................... 329 Exhibit 3

- 108 Case S3B and L3B Plant Performance Summary

................................ ............... 332 Exhibit 3

- 109 Case S3B and L3B Air Emissions

................................ ................................ ...... 333 Exhibit 3

- 110 Cases S3B and L3B Carbon Balance

................................ ................................ .. 334 Exhibit 3

- 111 Cases S3B and L3B Sulfur Balance

................................ ................................ ... 334 Exhibit 3

- 112 Cases S3B and L3B Water Balance

................................ ................................ .... 335 Exhibit 3

- 113 Case S3B Heat and Mas s Balance

................................ ................................ ...... 337 Exhibit 3

- 114 Case L3B Heat and Mass Balance

................................ ................................ ...... 340 Exhibit 3

- 115 Cases S3B and L3B Energy Balance

................................ ................................ .. 343 Exhibit 3

- 116 Case S3B Total Plant Cost Summary

................................ ................................ . 360 Exhibit 3

- 117 Case S3B Total Plant Cost Summary Details

................................ ..................... 361 Exhibit 3

- 118 Case S3B Owner’s Costs

................................ ................................ .................... 364 Exhibit 3

- 119 Case S3B Initial and Annual O&M Costs

................................ .......................... 365 Exhibit 3

- 120 Case L3B Total Plant Cost Summary

................................ ................................ . 366 Exhibit 3

- 121 Case L3B Total Plant Cost Summary Details

................................ ..................... 367 Exhibit 3

- 122 Case L3B Owner’s Costs

................................ ................................ .................... 370 Exhibit 3

- 123 Case L3B Initial and Annual O&M Costs

................................ .......................... 371 Exhibit 3

- 124 Case S4A and S4B Plant Study Configuration Matrix

................................ ....... 375 Exhibit 3

- 125 Balance of Plant Assumptions

................................ ................................ ............ 376 Exhibit 3

- 126 Case S4A Process Flow Diagram

................................ ................................ ....... 381 Exhibit 3

- 127 Case S4A Stream Table

................................ ................................ ...................... 382 Exhibit 3

- 128 Case S4A Plant Performance Summary

................................ ............................. 385 Exhibit 3

- 129 Cases S4A Air Emissions

................................ ................................ ................... 386 Exhibit 3

- 130 Case S4A Carbon Balance

................................ ................................ .................. 387 Exhibit 3

- 131 Case S4A Sulfur Balance

................................ ................................ .................... 387 Exhibit 3

- 132 Case S4A Water Balance

................................ ................................ .................... 388 Exhibit 3

- 133 Case S4A Heat and Mass Balance

................................ ................................ ...... 389 Exhibit 3

- 134 Case S4A Energy Balance

................................ ................................ .................. 393 Exhibit 3

- 135 Case S4A Total Plant Cost Summary

................................ ................................ . 407 Exhibit 3

- 136 Case S4A Total Plant Cost Details

................................ ................................ ..... 408 Exhibit 3

- 137 Case S4A Owner’s Costs

................................ ................................ .................... 411 Exhibit 3

- 138 Case S4A Initial and Annual O&M Costs

................................ .......................... 412 Exhibit 3

- 139 Case S4B Process Flow Diagram

................................ ................................ ....... 415 Exhibit 3

- 140 Case S4B Stream Table

................................ ................................ ...................... 416 Exhibit 3

- 141 Case S4B Plant Performance Summary

................................ .............................. 419Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

IX 

### Exhibit 3

- 142 Case S4B Air Emissions

................................ ................................ ..................... 420 Exhibit 3

- 143 Case S4B Carbon Balance

................................ ................................ .................. 421 Exhibit 3

- 144 Case S4B Sulfur Balance

................................ ................................ .................... 421 Exhibit 3

- 145 Case S4B Water Balance

................................ ................................ .................... 422 Exhibit 3

- 146 Case S4B Heat and Mass Balance

................................ ................................ ...... 425 Exhibit 3

- 147 Case S4B Energy Balance

................................ ................................ .................. 429 Exhibit 3

- 148 Case S4B Total Plant Cost Summary

................................ ................................ . 443 Exhibit 3

- 149 Case S4B Total Plant Cost Summary Details

................................ ..................... 444 Exhibit 3

- 150 Case S4B Owner’s Costs

................................ ................................ .................... 447 Exhibit 3

- 151 Case S4B Initial and Annual O&M Costs

................................ .......................... 448 Exhibit 3

- 152 Estimated Performance and Cost Results for IGCC Cases

................................ . 450 Exhibit 3

- 153 Plant Capital Costs

................................ ................................ .............................. 451 Exhibit 3

- 154 COE by Cost Component

................................ ................................ ................... 452 Exhibit 3

- 155 COE Sensitivity to Fuel Costs

................................ ................................ ............ 453 Exhibit 3

- 156 COE Sensitivity to Capacity Factor

................................ ................................ .... 455 Exhibit 3

- 157 Cost of CO 2 

### Avoided in IGCC Cases

................................ ................................ . 456 Exhibit 3

- 158 Normalized Water Usage in IGCC Cases

................................ ........................... 457 Exhibit 3

- 159 Emissions Profile for IGCC Cases

................................ ................................ ...... 459 Exhibit 3

- 160 Mercury Emission for IGCC Cases

................................ ................................ .... 460Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

X 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

XI 

## PREPARED BY :
Research and Development Solutions, LLC (RDS)

UPDATED BY :
Energy Sector Planning and Analysis (ESPA)

Vincent H. Chou Booz Allen Hamilton

John L. Haslbeck formerly Booz Allen Hamilton

Norma J. Kuehn Booz Allen Hamilton

Lora L. Pinkerton

WorleyParsons Elsy Varghese WorleyParsons

Mark C. Woods Booz Allen Hamilton

DOE Contract # DE

- FE0004001Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

XII 

# Acknowledgments

This report was initially prepared by Research and Development Solutions, LLC (RDS) for the United States Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) under DOE NETL Contract Number DE

- AM26

- 04NT41817 ; Subtask 41817

- 401.01.14A. The report was updated by Booz Allen Hamilton Inc. under DOE NETL Contract Number DE

FE0004001, Energy Sector Planning and Analysis.

The authors wish to acknowledge the excellent guidance, contributions, an d cooperation of the NETL staff and other past co ntributors, particularly:

John Wimer, Director of Office of Program Planning & Analysis

James Black

Kristin Gerdes

Eric Grol

Jeffrey Hoffmann

Robert James

Lawrence Rath

Robert Brasington formerly of Parsons CorporationCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

XIII 

### LIST OF ACRONYMS AND ABBREVIATIONS

AACE Association for the Advancement of Cost Engineering ADIP Aqueous di

- isoproponal AEO Annual Energy Outlook AFUDC Allowance for f unds u sed d uring c onstruction AGR Acid gas removal Aspen Aspen Plus ® ASU Air separation unit BACT Best available control tec hnology BEC Bare erected cost BFD Block flow diagram BFW Boiler feedwater BFP Boiler feed pump BLS Bureau of Labor Statistics Btu British thermal unit Btu/h r British thermal unit per hour Btu/kWh British thermal unit per kilowatt hour Btu/lb British thermal unit per pound Btu/scf British thermal unit per standard cubic foot CAMR Clean Air Mercury Rule CCF Capital Charge Factor CCPI Clean Coal Power Initiative CCS Carbon capture and storage CF Capacity factor CFB Circulating fluidized bed CGE Cold gas efficiency CL Closed

- loop

cm Centimeter CO Carbon monoxide CO 2 

### Carbon dioxide COE Cost of electricity CoP Conoco Phillips COS Carbonyl sulfide CRT Cathode ray tube CS Carbon steel CT Combustion turbine CTG Combustion Turbine

- Generator CWP C irculating water pump CWT Cold water temperature DCS Distributed control system DEA Diethanolamine DI De

- ionized DIPA DiisopropanolamineCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

XIV 

### DOE Department of Energy EIA Energy Information Administration EPA Environmental Protection Agency EPC Engineer/Procure/Construct EPCM Engineering/Procurement/Construction Management EPRI Electric Power Research Institute FBG Fluidized bed gasifier FGD Flue gas desulfurization FEED Front

- End Engineering Design FOAK First

- of

- a

- kind FW Feedwater ft Foot, f eet GDP Gross domestic product GEE GE Energy GHG Greenhouse gas GJ gigajoules GJ/hr Gigajoules per hour GPD Gallons per day
gpm Gallons per minute GRE Great River Energy GT Gas turbine GTC Gasification Technology Conference h r Hour Hg Mercury H 2 

### Hydrogen HDPE High density polyethylene HHV Higher heating value hp Horsepower HP High pressure HRSG Heat

- recovery steam generator HVAC Heating, ventilating, and air conditioning HWT Hot water temperature Hz Hertz ICR Information Collection Request IEA International Energy Agency IEEE Institute of E lectrical and Electronics Engineers IGCC Integrated gasification combined cycle IGVs Inlet guide vanes IOU Investor

- owned utility IP Intermediate pressure ISO International Standards Organization KBR Kellogg Brown and Root kg/h r Kilogram per hourCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

XV 

### kJ/kg Kil ojoules per kilogram kJ/kWh Kilojoules per kilowatt hour kJ/Nm 3 

### Kilojoules per normal cubic meter km kilometer KO Knockout kV Kilovolt kW Kilowatt kWe Kilowatts electric kWh Kilowatt

- hour kWt Kilowatt

- ton LAER Lowest Achievable Emission Rate lb Pound lb/h r Pounds per hour lb/MMBtu Pounds per million British thermal units lb/MWh Pounds per megawatt hour LCOE Levelized cost of electricity LHV Lower heating value LNB Low NOx burner LP Low pressure lpm Liters per minute

m Meters

m 3 

### /min Cubic meter per minute MDEA Methyldiethanolamine MJ/Nm 3 

### Megajoule per normal cubic meter MMBtu Million British thermal units (also shown as 10 6 

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

### Btu) per hour MMkJ/h r Million kilojoules (also shown as 10 6 

### kJ) per hour MNQC Multi Nozzle Quiet Combustor MPa Megapascals MVA Mega volt

- amps MWe Megawatts electric MWh Megawatt

- hour MWt h Megawatts thermal N/A Not applicable NDL North Dakota lignite NETL National Energy Technology Laboratory NGCC Natural gas combined cycle Nm 3 

### /h r Normal cubic meter per hour NMP N

- methyl

- 2

- pyrrolidone NOAK N th



### - of

- a

- kind NOx Oxides of nitrogen NSPS New Source Performance Standards NSR New Source ReviewCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

XVI 

### N 2 

### Nitrogen O&M Operation and maintenance OC Fn 

### Category n fixed operating cost for the initial year of operation OC Vnq 

### Category n variable operating cost for the initial year of operation O 2 

### Oxygen PC Pulverized coal ph Phase PM Particulate matter PO P urchase order POTW Publicly Owned Treatment Works ppbw Parts Per billion by w eight
ppm Parts per million
ppmv Parts per million volume ppmvd Parts per million volume, dry
ppmw Parts per million by weight PRB Powder River Basin coal region PSD Prevention of Significant Deterioration PSDF Power Systems Development Facility PSFM Power Systems Financial Model
p si Pounds per square inch psia Pounds per square inch absolute psig Pounds per square inch gage RDS Research and Development Solutions, LLC RH Reheater SC Supercritical scf Standard cubic feet scfh Standard cubic feet per hour scfm Standard cubic feet per minute SCGP Shell Coal Gasification Process SCOT Shell Claus Off

- gas Treating SEP Samenwerkende Electriciteits

- Productiebedrijven NV SFG Siemens Fuel Gasifier SGC Synthesis gas cooler SGS Sour gas shift SO 2 

### Sulfur dioxide SRU Sulfur recovery unit SS Stainless steel STG Steam turbine generator Syngas Synthesis gas TASC Total as

- spent cost TEWAC Totally Enclosed Water

- to

- Air Cooled TGTU Tail gas treating unit TOC Total overnight cost Tonne Metric Ton (1000 kg)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

XVII 

### TPC Total plant cost tpd Tons per day TPH Tons per hour TRIG TM Transport Reactor Integrated Gasification TS&M Transport, storage
, and monitoring vol% Volume percent WB Wet bulb WGS Water gas shift wt% Weight percent $/MMBtu Dollars per million British thermal units $/MWh dollars per megawatt hour °C Degrees Celsius

**°** F Degrees Fahrenheit 5

- 10s 50

- hour work

- weekCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

XVIII 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

1 

### EXECUTIVE SUMMARY The objective of this report is to present an independent assessment of the cost and perfo rmance of low rank coal

- fired power systems, specifically integrated gasification combined cycle (IGCC) plants, using a consistent technical and economic approach that accurately reflects
current or near term market conditions. This document is Volume 3a of the Low Rank Coal Baseline Reports, which are part of a four volume series consist ing of the following:

**•** Volume 1: Bituminous Coal and Natural Gas to Electricity

**•** Volume 2: Coal to Synthetic Natural Gas and Ammonia (Various Coal Ranks)

**•** Volume 3: Low Rank Coal and Natural Gas to Electricity

**•** Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture The cost and performance of the various fossil fuel

- based technologies will most likely determine which combination of technologies will be utilized to meet t he demands of the power market. Selection of new generation technologies will depend on many factors, including:

**•** Capital and operating costs

**•** Environmental issues and performance

**•** Overall energy efficiency

**•** Fuel prices

**•** Cost of electricity (COE)

**•** Availability

, reliability , and environmental performance

**•** Current and potential regulation of air, water, and solid waste discharges from fossil

fueled power plants

**•** Market penetration of c lean coal technologies that have matured and improved as a result of commercial

- scale demonstrations under the Department of Energy’s ( DOE ) Clean Coal Programs

As listed in Exhibit ES

- 1
, 12 IGCC power plant configurations were analyzed based on the Shell Coal Gasification Process (SCGP), Transport Integrated Gasification ( TRIG TM ) gasifier , Siemens Fuel Gasifier (SFG), and Conoco Phillips (CoP) E

- GasTM gasifier . The list includes eight cases firing Rosebud Powder River Basin ( PRB ) coal at the high elevation Montana site and four cases firing North Dakota l ignite (NDL) at the mid elevation North Dakota site

, with and without carbon dioxide ( CO 2 

### ) capture. The methodology included performing steady

- state simulations of the various technologies using the Aspen Plus ® (Aspen) modeling program. The resulting mass and energy balance data from the Aspen model were used to size major pieces of equipment. These equipment sizes fo rmed the basis for cost estimating. Performance and process limits were based upon published reports, information obtained from vendors and users of the technology, performance data from design/build utility projects, and/or best engineering judgment. Ca pital and operating costs were estimated based on simulation results and through a combination of vendor quotes, scaledCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

2 

### estimates from previous design projects, or a combination of the two. Baseline fuel costs for this analysis were determined using data from the Energy Information Administration’s (EIA) 2008 Annual Energy Outlook (AEO). The 2007 delivered costs used are $0.84/ gigajoule ( GJ ) ($0.89/ million British thermal unit [ MMBtu ] ) for rail delivered Powder River Basin (PRB) coal and $0.79/GJ ($0.83/M MBtu) for minemouth North Dakota lignite (NDL) , both on a higher heating value (HHV) basis and in June 2007 United States ( U.S. ) dollars.

Exhibit ES

- 1 Case Descriptions

Case Coal Type Coal Drying Process Gasifier/Boiler Technology ASU Integration H 2 S Separation/ Removal CO 2 Separation CO 2 Capture

S1A S WTA Shell SCGP Yes Sulfinol

- M

S1B S WTA Shell SCGP No Selexol Selexol 2 nd stage 90%

L1A L WTA Shell SCGP Yes Sulfinol

- M

L1B L WTA Shell SCGP No Selexol Selexol 2 nd stage 90%

S2A S Flash Pulverizer TRIG TM Yes Sulfinol

- M

S2B S Flash Pulverizer TRIG TM No Selexol Selexol 2 nd stage 83%

S3A S WTA Siemens SFG Yes Sulfinol

- M

S3B S WTA Siemens SFG No Selexol Selexol 2 nd stage 90%

L3A L WTA Siemens SFG Yes Sulfinol

- M

L3B L WTA Siemens SFG No Selexol Selexol 2 nd stage 90%

S4A S None CoP E

- Gas TM Yes MDEA

S4B S None CoP E

- Gas TM No Selexol Selexol 2 nd stage 90% Coal Type S= Subbituminous, L= Lignite 

### All plant configurations were evaluated based on installation at a greenfield site (Montana , 3400 ft elevation, for PRB cases and North Dakota , 1900 ft elevation, for lignite cases). To compare the plants on an equivalent basis, it was assumed that these plants would be dispatched an y time they are available. T he study capacity factor (CF) wa s chosen to reflect the maximum availability demonstrated for the specific plant type ( e. g., 8 0 percent for IGCC configurations )

. Since variations in fuel costs and other factors can influence d ispatch order and CF , sensitivity of cost of electricity ( COE) to CF wa s evaluated and presented later in this Executive Summary ( Exhibit ES

- 9 ). The gross and net output varies among the IGCC cases because of the gas turbine (GT) size constraint. The advanced F

- class turbine used to model these cases comes in a standard size of 232 megawatt ( MW ) when operated on synthesis gas (syngas) at International Standards Organization ( ISO ) conditions. Each case uses two combustion turbines (CTs) for a combined potential gross output of 464 MW. Because these cases were operated at elevations higher than sea level, the output wa s reduced from the turbine’s ISO condition potential. In the combinedCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

3 

### cycle

, a heat recovery steam generator (HRSG) extracts heat from the CT exhaust to power a steam turbine. However, the CO 2 

### capture cases consume more extraction steam than the non

capture cases, thus reducing the steam

- turbine output. In addition, the CO 2 

### capture cases have a higher auxiliary load requirement than non

- capture cases, which serves to further reduce net plant o utput.
Exhibit ES

- 2 shows the cost, performance, and environmental profile summary for all cases discussed below.

Energy Efficiency

The net plant efficiency (HHV basis ) for all 12 cases is shown in Exhibit ES

- 3 . The following primary conclusions can be drawn:

**•** The Shell case with no CO 2 

### capture firing PRB coal at the Montana site ha s the highest plant efficiency of the technologies modeled in this study, with an efficiency of 42.0 percent.

**•** The Shell case with CO 2 

### capture firing PRB coal at the Montana site has the highest efficiency among all of the capture technologies modeled in this study, with an efficiency of 32.1 percent.

**•** The CO 2 

### capture results in an efficiency penalty of 6 to 10 absolute percent, relative to the analogous non

- capture case, while noting that the TRIGTM case only captures 83 percent of the overall carbon.

**•** The PRB coal cases at 3,400 ft of elevation have higher efficiency than the corresponding lignite coal cases at 1,900 ft of elevation. The negative efficiency impact of coal quality is greater than the negative efficiency impacts caused by the elevation differences and associated combustion turbine derate.

Water Use

Three water values are presented for each technology in Exhibit ES

- 4 : raw water with drawal, process discharge, and raw water consumption. Each value is normalized by net output. Raw water withdrawal is the difference between demand and internal recycle. Demand is the amount of water required to satisfy a particular process (cooling tow er makeup, quench makeup, slag handling, etc.) and internal recycle is water available within the process. Raw water withdrawal is the water removed from the ground or diverted from a surface

- water source for use in the plant. Raw water consumption is th e portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source it was withdrawn from. Raw water consumption is the difference between withdrawal and process discharge, and it r epresents the overall impact of the process on the water source, which in this study is considered to be 50 percent from groundwater (wells) and 50 percent from a municipal

source.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

4 

### Exhibit ES

- 2 Cost and Perf ormance Summary and Environmental Profile for IGCC Cases

PERFORMANCE S1A L1A S1B L1B S2A S2B S3A L3A S3B L3B S4A S4B
CO 2 Capture No No Yes Yes No Yes No No Yes Yes No Yes Gross Power Output (kW e ) 696,700 752,600 663,400 713,300 652,700 621,300 622,200 678,800 634,700 676,900 738,300 727,200 Auxiliary Power Requirement (kW e ) 124,020 135,900 191,790 213,240 107,280 160,450 117,480 135,680 189,410 210,390 133,460 212,130 Net Power Output (kW e ) 572,680 616,700 471,610 500,060 545,420 460,850 504,720 543,120 445,290 466,510 604,840 515,070 Coal Flowrate (lb/hr) 542,713 760,093 585,970 814,029 545,197 577,946 531,119 743,918 579,796 801,651 656,228 675,058 HHV Thermal Input (kW th ) 1,362,134 1,474,011 1,470,704 1,578,608 1,368,368 1,450,564 1,333,034 1,442,644 1,455,207 1,554,603 1,647,041 1,694,303 Net Plant HHV Efficiency (%) 42.0% 41.8% 32.1% 31.7% 39.9% 31.8% 37.9% 37.6% 30.6% 30.0% 36.7% 30.4% Net Plant HHV Heat Rate (Btu/kWh) 8,116 8,156 10,641 10,772 8,560 10,740 9,012 9,063 11,151 11,371 9,292 11,224 Raw Water Withdrawal (gpm/MW net ) 3.1 3.0 7.2 7.8 3.7 6.5 4.5 4.0 9.0 8.9 5.4 8.4 Process Water Discharge (gpm/MW net ) 0.8 0.8 1.4 1.6 0.8 1.0 1.1 1.1 1.6 1.7 1.1 1.5 Raw Water Consumption (gpm/MW net ) 2.3 2.2 5.9 6.2 2.9 5.5 3.4 2.9 7.4 7.2 4.3 6.9
CO 2 Emissions (lb/MMBtu) 214 219 22 22 211 36 214 219 22 22 213 22
CO 2 Emissions (lb/MWh gross ) 1,426 1,461 165 170 1,507 287 1,563 1,585 172 175 1,620 174
CO 2 Emissions (lb/MWh net ) 1,735 1,783 233 242 1,803 386 1,927 1,981 246 255 1,977 245
SO 2 Emissions (lb/MMBtu) 0.0023 0.0023 0.0009 0.0010 0.0019 0.0009 0.0039 0.0021 0.0009 0.0010 0.0016 0.0009
SO 2 Emissions (lb/MWh gross ) 0.015 0.015 0.007 0.007 0.013 0.007 0.029 0.016 0.007 0.008 0.012 0.007 NOx Emissions (lb/MMBtu) 0.062 0.063 0.050 0.049 0.059 0.049 0.061 0.061 0.051 0.050 0.052 0.044 NOx Emissions (lb/MWh gross ) 0.412 0.418 0.381 0.371 0.422 0.390 0.444 0.445 0.397 0.391 0.398 0.348 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 PM Emissions (lb/MWh gross ) 0.047 0.047 0.054 0.054 0.051 0.057 0.052 0.051 0.056 0.056 0.054 0.056 Hg Emissions (lb/TBtu) 0.351 0.560 0.351 0.560 0.351 0.351 0.351 0.560 0.351 0.560 0.351 0.351 Hg Emissions (lb/MWh gross ) 2.34E-06 3.74E-06 2.66E-06 4.23E-06 2.51E-06 2.80E-06 2.57E-06 4.06E-06 2.75E-06 4.39E-06 2.67E-06 2.79E-06
COST Total Plant Cost (2007$/kW) 2,506 2,539 3,480 3,584 2,236 3,019 2,610 2,656 3,533 3,626 2,265 3,144 Total Overnight Cost (2007$/kW) 3,056 3,094 4,253 4,378 2,728 3,691 3,185 3,239 4,318 4,430 2,771 3,851
**Bare Erected Cost** 1,914 1,941 2,610 2,692 1,692 2,228 2,006 2,044 2,654 2,730 1,737 2,357 **Home Office Expenses** 177 179 242 250 157 207 186 189 247 254 162 221 **Project Contingency** 343 349 486 502 305 421 359 367 493 508 306 431 **Process Contingency** 72 69 142 141 83 164 60 56 139 135 60 135
**Owner's Costs** 550 556 773 794 492 672 575 583 785 804 505 706 Total Overnight Cost (2007$x1,000) 1,750,189 1,908,200 2,005,883 2,189,363 1,488,063 1,701,132 1,607,607 1,759,016 1,922,741 2,066,464 1,675,790 1,983,369 Total As Spent Capital (2007$/kW) 3,484 3,527 4,849 4,991 3,110 4,208 3,631 3,692 4,922 5,050 3,159 4,390 COE (mills/kWh, 2007$) 1 83.2 83.5 119.7 121.9 74.5 105.2 86.8 87.3 121.7 123.7 78.7 112.3
**CO 2**  **TS&M Costs** 0.0 0.0 6.0 5.7 0.0 5.9 0.0 0.0 6.3 6.2 0.0 5.8
**Fuel Costs** 7.2 6.7 9.5 8.9 7.6 9.5 8.0 7.5 9.9 9.4 8.3 10.0
**Variable Costs** 8.0 8.2 10.6 11.1 6.8 8.8 8.2 8.4 10.6 11.1 8.3 10.9
**Fixed Costs** 13.7 13.6 18.3 18.6 11.8 15.5 14.1 14.0 18.4 18.6 13.0 17.4 **Capital Costs** 54.2 54.9 75.4 77.6 48.4 65.4 56.5 57.4 76.6 78.5 49.1 68.3 LCOE (mills/kWh, 2007$) 1 105.4 105.8 151.8 154.5 94.5 133.3 110.0 110.7 154.3 156.9 99.8 142.4 Shell IGCC Cases TRIG IGCC Cases Siemens IGCC Cases CoP IGCC Cases

1 COE and Levelized COE are defined in Section 2.6Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

5 

### Exhibit ES

- 3 Net Plant Efficiency

42.0%

32.1% 39.9%

31.8% 37.9%

30.6% 36.7%

30.4% 41.8%

31.7% 37.6%

30.0%

0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50%

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensEfficiency, % (HHV Basis) North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

6 

### Exhibit ES

- 4 Raw Water Withdrawal and Consumption

3.1 7.2

3.7 6.5

4.5 9.0

5.4 8.4

3.0 7.8

4.0 8.9

2.3 5.9

2.9 5.5

3.4 7.4

4.3 6.9

2.2 6.2

2.9 7.2

0 2 4 6 8 10 12 14

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensWater, gpm/MWnet Raw Water Withdrawal

Process Water Discharge

Raw Water Consumption North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

7 

### The largest consumer of raw water in all cases is cooling tower makeup. Since plants located in the Western U.S. need to consider limited water supplies, a parallel wet/dry condenser was chosen for all plant configurations. In a parallel cooling system half of the turbine exhaust steam is condensed in an air

- cooled condenser and half in a water

- cooled condenser. T he cooling water is provided by a mechanical draft, evaporative cooling tower

. The primary conclusions that can be drawn are:

**•** The raw water usage is lower in the lignite coal cases because of its higher moisture content, and a significant amount of the co al moisture is recovered in the drying process for dry feed cases and used as internal recycle. Thus, while the water demand is nearly equal in the Montana PRB and North Dakota lignite cases, the water usage is significantly lower when using lignite coal.

**•** The use of the parallel wet/dry cooling system reduces water demand by 36

- 47 percent in the non

- capture cases and by 24

- 30 percent in the CO 2 

### capture cases relative to using a purely wet cooling system. The water savings is less in the CO 2 

### capture cases because a significant amount of extraction steam is used in the shift reaction and therefore not condensed in the surface condenser.

**•** The water demand is significantly greater in the CO 2 

### capture cases because one

- half of the condenser load represents a smaller percentage of the total water requirement

, again due primarily to the high shift steam requirement.

Cost Results The Total Plant Cost (TPC) for each technology was determined throug h a combination of vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. TPC includes all equipment (complete with initial chemical and catalyst loadings), materials, labor (direct and indirect), engineering and construction management, and contingencies (process and project). Owner’s costs, including preproduction costs, inventory capital, initial cost for catalyst and chemicals, land, financing costs and other owner’s costs were added to TPC to generate total overnight cost (TOC). Property taxes and insurance were included in the fixed operating costs as an additional owner’s cost. Escalation and interest on debt during the capital expenditure period were estimated and added to the TOC to provide the Total As

- Spent Cost (TASC). The cost estimates carry an accuracy of

- 15/+ 30 % , consistent with a “feasibility study ” level of design engineering applied to the various cases in this study. The value of the study lies not in the absolute accuracy of the individual case results

, but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful relative comparisons among the cases evaluated. Project contingencies were added to the Engineering/Procurement/Construction Management (EPCM) capital accounts to cover project uncertainty and the cost of any additional equipment that would result from a detailed design. The contingencies represent costs that are expected to occur. Each ba re erected cost (BEC) account was evaluated against the level of estimate detail and field experience to determine project contingency. Process contingency was added to costCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

8 

### account items that were deemed to be first

- of

- a

- kind (FOAK) or posed significant risk due to lack of operating experience. The cost accounts that received a process contingency include:

**•** Gasifiers and Syngas Coolers : 15

– 20 percent on all IGCC cases , with next

- generation commercial offering and integration with the power island.

**•** Two

- St age Selexol : 20 percent on all IGCC capture cases , with lack of operating experience at commercial scale in IGCC service.

**•** Mercury Removal : 5 percent on all IGCC cases , with minimal commercial scale experience in IGCC applications.

**•** Combustion Turbine Gene rator (CTG) : 5 percent on all IGCC non

- capture cases , with syngas firing and ASU integration; 10 percent on all IGCC capture cases , with high hydrogen firing.

**•** Instrumentation and Controls : 5 percent on all IGCC accounts , with integration issues.

The no rmalized components of TOC and overall TASC are shown for each plant configuration in Exhibit ES

- 5

. The TOC
, which is used for COE calculations, is the TPC plus owner’s costs. The following conclusions can be drawn:

**•** The T O C is higher for the North Dakota elevation lignite coal cases as compared to the Montana elevation PRB coal cases by approximately 9 percent.

**•** The T O C increase to add CO 2 

### capture is approximately 3 8 percent.

**•** The TASC is approximately 15% greater than the TOC based on the study assumptions.
Cost of Electricity

Th e cost metric used in this study is the COE, which 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 inf lation rate, i.e., that it remains constant in real terms over the operational period of the power plant . To calculate the COE, the Power Systems Financial Model ( PSFM ) [ 2 ] was used to determine a “base

- year” (2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3 percent 1 

### , provided the stipulated internal rate of return on equi ty over the entire economic analysis period (capital expenditure period plus thirty years of operation). The first year capital charge factor (CCF) shown in Exhibit ES

- 6 , which was derived using the PSFM, can also be used to calculate COE using a simplified equation as detailed in Section 2.6.4

.

1 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 Power Ge neration 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.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

9 

### Exhibit ES

- 5 Plant Capital Costs

3,056 4,253

2,728 3,691

3,185 4,318

2,771 3,851

3,094 4,378

3,239 4,430

3,484 4,849

3,110 4,208

3,631 4,922

3,159 4,390

3,527 4,991

3,692 5,050

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/CapTOC or TASC ($/kW) TASC
Owner's Cost Process Contingency Project Contingency Home Office Expense
Bare Erected Cost North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ft

Note: TOC expressed in 2007 dollars. TASC expressed in mixed

- year 2007 to 2011 year dollars.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

10 

### The project financial structure varies depending on the type of project (high or low risk). All cases were assumed to be undertaken at investor owned utilities (IOUs). High risk projects are those in which commercial scale operating experience is limited. All IGCC cases (with and without CO 2 

### capture) were considered to be high risk. All cases were assumed to have a 5 year capital expenditure period. The current

- dollar, 30

- year levelized cost of electricity (LCOE) was also calculated and is shown in Exhibit ES

- 2 , but the primary metric used in the balance of this study is COE. A more detailed discussion of the two metrics is provided in Section 2.6

. Exhibit ES

- 6 Economic Parameters Used to Calculate COE

High Risk (5 year capital

expenditure period) Low Risk (5 year capital

expenditure period)

First Year Capital Charge Factor 0.1 243 0.11 65

Commodity prices fluctuate over time based on overall economic activity and general supply and demand curves. While the cost basis for this study is June 2007, many price indices had 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. Hence the June 2007 dollar cost base used in this study is expected to be representative of January 201 0 costs.

The COE results are shown in Exhibit ES

- 7 with the capital cost, fixed operating cost, variable operating cost, and fuel cost shown separately. In the capture cases, the CO 2 

### transport, storage, and monitoring (TS&M) costs are also shown as a separate bar segment. The following conclusions can be drawn:

**•** The COEs for the Shell and Siemens systems are higher than TRIG TM and CoP for both capture and non

- capt ure cases. Note that TRIGTM and CoP were only studied for PRB coal and TRIGTM with capture only achieved 83 percent carbon capture.

**•** TRIG TM is the only technolog y evaluated that has not been demonstrated at commercial scale. For this reason, TRIG TM COEs are s ubject to a greater level of uncertainty than the other technologies in the gr oup.

**•** T he COE is dominated by capital charges in all cases. The capital cost component of COE ranges from 61 to 66 percent for IGCC cases.

**•** The fuel cost component is relatively m inor in all cases, ranging from 7 to 10 percent of the COE for IGCC cases.

**•** The CO 2 

### TS&M component adds approximately 5 percent to the COE.

**•** The COE increases by 40 to 46% percent for IGCC plants when CO 2 

### capture is added.

**•** The COE is generally lower for Mo ntana PRB cases compared to the North Dakota lignite cases.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

11 

### Exhibit ES

- 7 COE by Cost Component

54.2 75.4

48.4 65.4
56.5 76.6

49.1 68.3

54.9 77.6

57.4 78.5 13.7 18.3

11.8 15.5

14.1 18.4

13.0 17.4

13.6 18.6

14.0 18.6

8.0 10.6

6.8 8.8

8.2 10.6

8.3 10.9

8.2 11.1

8.4 11.1

7.2 9.5

7.6 9.5

8.0 9.9

8.3 10.0

6.7 8.9

7.5 9.4 6.0

5.9 6.3

5.8 5.7 6.2

83.2 119.7

74.5 105.2

86.8 121.7

78.7 112.3

83.5 121.9

87.3 123.7

0 20 40 60 80 100 120 140

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensCOE (2007 mills/kWh) CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital Costs North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

12 

### Exhibit ES

- 8 shows the COE sensitivity to fuel c osts. The solid lines are the COE of non

capture cases. The dotted lines are the capture cases. As expected, all cases show a linear decrease in COE with the decrease in coal prices. A s the price for PRB coal decreases from $0.89 to $ 0/MMBtu, the average COE decreases from 81 to 73 tenths of a cent per kilowatt hour ( mills/kWh ) for the non

- capture PRB cases and from 115 to 105 mills/kWh for the PRB captur e

cases

. As the price for ND lignite coal decreases from $0.8 3 to $0/MMBtu, the average COE decreases from 8 5 to 78 tenths of a cent per kilowatt hour (mills/kWh) for the non

- capture lignite cases and from 12 3 to 113 mills/kWh for the lignite capture cases

. The sensitivity of COE to CF is shown in Exhibit ES

- 9

. CF is equal to availability since it was assumed that the plants are able to operate at 100 per cent capacity whenever power production is needed. The solid lines are the COE of non

- capture cases. The dotted lines are the capture

cases. All cases show a decrease in COE with the increase in CF

. As the CF increa ses from 80 to 100 percent, the avera ge COE decreases from 81 to 66 mills/kWh for the non

- capture PRB cases and from 115 to 94 mills/kWh for the CO 2 

### capture PRB cases

. The average COE decreases from 8 5 to 7 0 mills/kWh for the non

- capture lignite cases and from 12 3 to 10 0 mills/kWh for the lignite capture cases.

Cost of CO 2 

### Avoided

The CO 2 

### emissions per megawatt

- hour (MWh) are dependent on the chosen technology and configuration , and they are higher for the North Dakota lignite cases compared to the Montana PRB cases. The first year cost of CO 2 

### avoided is calculated using the equation :



### MWh tons Emissions CO Emissions CO MWh COE COE Cost Avoided

removal with reference reference removal with 

### / } { / $ } {

2 2 

### − **−**

**=**

The COE with CO 2 

### removal includes the costs of capture and compression, as well as TS&M costs. The resulting avoided costs are shown in Exhibit ES

- 10 f or each of the CO 2 

### capture technologies modeled. The cost of CO 2 

### avoided compared to the analogous non

- capture design averages $ 45 /ton, with a range of $ 40 /ton

– $ 5 3 /ton. The cost of CO 2 

### avo ided, compared to the baseline Supercritical ( SC ) PC non

- capture design, was determined using results shown in Exhibit 2

- 22 and averages $ 7 0 /ton, with a range of $ 63 /t on

- $ 77 /ton. The analogous CO 2 

### avoided costs are lower for the Montana PRB coal than the North Dakota lignite cases , mainly because of
t he capital cost increase due to the low energy density lignite fuel

. The cost of CO 2 

### avoided, compared to the baseline SC PC plant, follows the same general trend as the COE for each of the cases after accounting for the overall carbon removal efficiency

. The comparison of the analogous Shell designs is affected by the change from a wate r quench in the CO 2 

### capture case to high temperature syngas heat recovery in the non

- capture case. This increase s efficiency when high water concentrations are not required for the WGS reaction , as is the case for non

- capture cases, at the expense of incl uding h igh temperature heat exchangers, thus increasing the cost of avoiding CO 2 

### emissions for the semi

- analogous Shell cases.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

13 

### Exhibit ES

- 8 COE Sensitivity to Fuel Costs

0 20 40 60 80 100 120 140 160

0.0 0.5 1.0 1.5 2.0 2.5COE (2007 mills/kWh)

Coal Price ($/MMBtu) Siemens Lignite w/Capture Shell Lignite w/Capture

Siemens PRB w/Capture

Shell PRB w/Capture CoP PRB w/Capture

TRIG PRB w/Capture

Siemens Lignite

Siemens PRB

Shell Lignite

Shell PRB

CoP PRB

TRIG PRB Capacity Factor = 85% for all cases Study Coal Costs: Lignite = $0.83/MMBtu PRB = $0.89/MMBtuCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

14 

### Exhibit ES

- 9 COE Sensitivity to Capacity Factor

0 50 100 150 200 250 300 350

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%COE (2007 mills/kWh)

Capacity Factor (%) Siemens Lignite w/Capture Shell Lignite w/Capture

Siemens PRB w/Capture
Shell PRB w/Capture CoP PRB w/Capture

TRIG PRB w/Capture

Siemens Lignite

Siemens PRB

Shell Lignite

Shell PRB

CoP PRB

TRIG PRB Study Capacity Factor is 80% for all casesCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

15 

### Exhibit ES

- 10 CO 2 

### Avoided Costs

48.6

43.28 41.6 40.2 52.7

42.2 74.6

62.90 77.6

66.2 67.5 70.6

0 10 20 30 40 50 60 70 80 90 100

Shell PRB w/Capture TRIG PRB w/Capture Siemens PRB w/Capture CoP PRB w/Capture Shell Lignite w/Capture Siemens Lignite w/Capture

PRB LigniteFirst Year CO2Avoided Cost (2007$/ton) Avoided Cost (Analogous Technology w/o Capture Reference)
Avoided Cost (SC PC w/o Capture Reference)

North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

16 

### Environmental Performance

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 i n Exhibit ES

- 11

. Emission rates of sulfur dioxide (SO 2 

### ), nitrogen oxides ( NOx), and particulate matter (PM) are shown graphically in Exhibit ES

- 12 , and emission rates of mercury (Hg) are shown separately in Exhibit ES

- 13 because of the orders of magnitude difference in emission rate values.

Exhibit ES

- 11 Study Environmental Targets

Pollutant Environmental Target Control Technology

NOx 15 ppmv (dry) @ 15% O 2 

### Low NOx burners and syngas nitrogen dilution

SO 2 

### 0.0128 lb/MMBtu Selexol, MDEA or Sulfinol (depending on

gasifier technology)

Particulate Matter (Filterable) 0.0071 lb/MMBtu Quench, water scrubber, and/or cyclones and candle filters (depending

on gasifier technology) Mercury > 90% capture Carbon bed
The following observations can be made:

**•** Emissions of SO 2 

### are uniformly extremely low. The same environmental target was used as in the bituminous coal cases of Volume 1 of this study, and because the coal sulfur content is significantly lower in the design coals of this study, the resulting SO 2 

### emissions are a lso significantly lower.

**•** Particulate emissions are the same for each case because it was a study assumption that the combination of cyclones and candle filters would exactly meet the environmental target of 0.0071 lb/MMBtu.

**•** NOx emissions were assumed to be 15 ppmv at 15 percent oxygen in all cases. The resulting emissions on a lb/MMBtu basis vary slightly because of the variable coal feed rates and flue gas volumes generated among cases.

**•** Mercury emissions are constant for each coal type and significantly b elow the NSPS limit of 20 x 10 - 6 

### lb/MWh for IGCC systems. The emissions shown in Exhibit ES

- 13 a re equivalent to 3.7

– 4.4 x 10 - 6 

### lb/MWh for the four lignite cases (w hich have the higher Hg concentration of the two coal types) , or a minimum of 78 percent less than NSPS.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

17 

### Exhibit ES

- 12 SO 2 

### , NOx and Particulate Emission Rates

0.002 0.001 0.002 0.001 0.004

0.001 0.002 0.001 0.002 0.001 0.002 0.001 0.062

0.050 0.059

0.049 0.061

0.051 0.052

0.044 0.063

0.049 0.061

0.050

0.007

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensEmissions, lb/MMBtu SO2

NOx

Particulate North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

18 

### Exhibit ES

- 13 Mercury Emission Rates

0.351 0.351 0.351 0.351 0.351 0.351 0.351 0.351 0.560 0.560 0.560 0.560

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensMercury Emissions, lb/TBtu North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

19 

### 1. INTRODUCTION The objective of this report is to present an accurate, independent assessment of the cost and performance of fossil energy power systems

— specifically

, the Shell Coal Gasification Process (SCGP) , TR IGTM, Siemens Fuel Gasifier (SFG) , and CoP E

- GasTM gasifiers using low rank Rosebud PRB and ND Lignite coal s

— in a consistent technical and economic manner that accurately reflects current market conditions for plants starting operation in the near term

. Thi s document is Volume 3a of the Low Rank Coal Baseline Reports, which are part of a four volume series consist ing of the following:

**•** Volume 1: Bituminous Coal and Natural Gas to Electricity

**•** Volume 2: Coal to Synthetic Natural Gas and Ammonia (Various Coal Ranks)

**•** Volume 3: Low Rank Coal and Natural Gas to Electricity

**•** Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture

Twelve IGCC case s are modeled and analyzed. Eight cases use PRB subbituminous coal at the high elevation Montana site , and four cas es use North Dakota Lignite coal at the mid elevation North Dakota site , with and without CO 2 

### capture . The different IGCC configurations considered in this study are displayed in Exhibit 1

- 1

. While input was sought from various technology vendors, the final assessment of performance and cost was determined independently, and may not represent the views of the technology vendors. More detailed engineering for specific project applications must be considered with the appropriate technology vendors to determine the preferred designs

, based on project details and current state of the art. This study’s main use should be to identify important parameters that could be optim ized for different project goals or specific operating conditions and to help quantify the tradeoffs of different pow er generation configurations. Generating Unit Configurations The gross and net output varies among the IGCC cases because of the GT size co nstraint. The advanced F

- class turbine used to model these cases comes in a standard size of 232 MW when operated on syngas at ISO conditions. Each case uses two CTs for a combined potential gross output of 464 MW. Because these cases are operated at el evations greater than sea level, the output is reduced from the turbine’s ISO condition potential. In the combined cycle, a HRSG extracts heat from the CT exhaust to power a steam turbine. However, the CO 2 

### capture cases consume more extraction steam than the non

- capture cases, thus reducing the steam turbine output. In addition, the capture cases have a higher auxiliary load requirement than non

- capture cases, which serves to further reduce net plant output. Thus, the overall combined cycle gross output ranges from 621 to 7 53 MW, which results in a range of net output from 445 to 6 17 MW. The coal feed rate required to achieve the gross power output is also different between the cases, ranging from 240, 912 to 36 9
, 244 kilogram per hour (kg/h r ) (531,119 to 8 14
, 029 pounds per hour [lb/h r ]). The large range of coal feed rates is due to the different gasifier performance, coal types, and the addition of CO 2 

### capture.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

20 

### Exhibit 1

- 1 IGCC Case Descriptions

Case Unit Cycle Steam Cycle, psig/ **°** F/ **°** F Coal Type Coal Drying Process Combustion Turbine Gasifier/Boiler Technology Oxidant ASU Integration H 2 S Separation/ Removal Sulfur Removal/ Recovery CO 2 Separation CO 2 Capture

S1A IGCC 1800/1050/1050 S WTA 2 x Advanced F

- class Shell SCGP 95 mol% O 2 Yes Sulfinol

- M Claus Plant

S1B IGCC 1800/1000/1000 S WTA 2 x Advanced F

- class Shell SCGP 95 mol% O 2 No Selexol Claus Plant Selexol 2 nd stage 90%

L1A IGCC 1800/1050/1050 L WTA 2 x Advanced F

- class Shell SCGP 95 mol% O 2 Yes Sulfinol

- M Claus Plant

L1B IGCC 1800/1000/1000 L WTA 2 x Advanced F

- class Shell SCGP 95 mol% O 2 No Selexol Claus Plant Selexol 2 nd stage 90%

S2A IGCC 1800/1050/1050 S Flash Pulverizer 2 x Advanced F

- class TRIGTM 95 mol% O 2 Yes Sulfinol

- M Claus Plant

S2B IGCC 1800/1000/1000 S Flash Pulverizer 2 x Advanced F

- class TRIGTM 95 mol% O 2 No Selexol Claus Plant Selexol 2 nd stage 83% 1

S3A IGCC 1800/1050/1050 S WTA 2 x Advanced F

- class Siemens SFG 95 mol% O 2 Yes Sulfinol

- M Claus Plant

S3B IGCC 1800/1000/1000 S WTA 2 x Advanced F

- class Siemens SFG 95 mol% O 2 No Selexol Claus Plant Selexol 2 nd stage 90%

L3A IGCC 1800/1050/1050 L WTA 2 x Advanced F

- class Siemens SFG 95 mol% O 2 Yes Sulfinol

- M Claus Plant

L3B IGCC 1800/1000/1000 L WTA 2 x Advanced F

- class Siemens SFG 95 mol% O 2 No Selexol Claus Plant Selexol 2 nd stage 90%

S4A IGCC 1800/1050/1050 S None 2 x Advanced F

- class CoP E

- GasTM 95 mol% O 2 Yes MDEA Claus Plant

S4B IGCC 1800/1000/1000 S None 2 x Advanced F

- class CoP E

- GasTM 95 mol% O 2 No Selexol Claus Plant Selexol 2 nd stage 90%

1 

### Li mited due to syngas methane contentCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

21 

### Report Structure The balance of this report is organized as follows:

**•** Chapter 2 provides the basis for technical, environmental

, and cost evaluations.

**•** Chapter 3 provides the results of the different IGCC configurations.

**•** Chapter 4 contains the reference list.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

22 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

23 

### 2. GENERAL EVALUATION B ASIS

For each of the plant configurations in this study

, an Aspen model was developed and used to generate material and energy balances, which

, in turn

, were used to provide a design basis for items in the major equipment list. The equipment list and material balances were used as the basis for generating the capital and operating cost estimates. Performance and process limits were based upon published reports, information obtained from vendors and users of the technology, performance data from design projects, and/or best engineering judgment. Capital and op erating costs were estimated by WorleyParsons based on simulation results and through a combination of vendor quotes, scaled estimates from previous design/buil d projects, or a combination of the two. Ultimately

, a FY COE was calculated for each of the ca ses and is reported as the revenue requirement figure

- of

- merit.

The balance of this chapter documents the design basis, environmental targets and cost assumptions used in the study.

2.1 SITE CHARACTERISTICS

The plants are located at two different generic plant sites. Plants using PRB coal are assumed to be located in Montana. Plants using lignite coal are assumed to be located at a minemouth site in North Dakota. The ambient conditions for the two sites are shown in Exhibit 2

- 1 and Exhibit 2

- 2

.

Exhibit 2

- 1 Montana Site Ambient Conditions for PRB Coal Cases
Elevation, m (ft) 1,036 (3,400) Barometric Pressure, MPa (psia) 0.09 (13.0) Design Ambient Temperature, Dry Bulb, °C ( **°** F) 5.6 (42) Design Ambient Temperature, Wet Bulb, °C ( **°** F) 2.8 (37) Design Ambient Relative Humidity, % 62

Exhibit 2

- 2 North Dakota Site Ambient Conditions for Lignite Coal Cases
Elevation, m (ft) 579 (1,900) Barometric Pressure, MPa (psia) 0.10 (13.8) Design Ambient Temperature, Dry Bulb, °C ( **°** F) 4.4 (40) Design Ambient Temperature, Wet Bulb, °C ( **°** F) 2.2 (36) Design Ambient Relative Humidity, % 68

The site characteristics are assumed to be the same for both plant locations as shown i n Exhibit 2

- 3

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

24 

### Exhibit 2

- 3 Site Characteristics

Location Greenfield Topography Level Size, acres 300 Transportation Rail Ash/Slag Disposal Off Site

Water Municipal (50%) / Groundwater (50%)

Access Landlocked , having access by rai l and highway

CO 2 

### Storage Compressed to 15.3 MPa (2,215 psia), transported 80 kilometers (50 miles) and sequestered in a saline formation at a depth of 1,239 meters (4,055 feet)

The land area for all cases assumes 30 acres are required for the plant proper

, and the balance provides a buffer of approximately 0.25 miles to the fence line. The extra land could also provide for a rail loop if required.

In all cases it was assumed that the steam turbine is enclosed in a turbine building

, but the gasifier is not enclosed.

The following design parameters are considered site

- specific, and are not quantified for this study. Allowances for normal conditions and construction are included in the cost estimates.

**•** Flood plain considerations

**•** Existing soil/site conditions

**•** W ater discharges and reuse

**•** Rainfall/snowfall criteria

**•** Seismic design

**•** Buildings/enclosures

**•** Fire protection

**•** Local code height requirements

**•** Noise regulations

– Impact on site and surrounding areaCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

25 

### 2.2 COAL CHARACTERISTICS

There are two design coals : a subbituminous PRB coal from Montana and lignite coal from North Dakota. The coal properties are from National Energy Technology Laboratory’s ( NETL ) Coal Quality Guidelines and are shown in Exhibit 2

- 4 and Exhibit 2

- 5 [ 1 ]

. The Power Systems Financial Model (PSFM) was used to derive the first year capital charge factor for this study [ 2 ]. The PSFM requires that all cost inputs have a consistent cost year basis. Because the capital and operating cost estimates are in June 2007 dollars, the fuel costs must also be in June 2007 dollars.

The cost of coal used in this study is $0.84/GJ ($0.89/MMBtu) for PRB coal and $0.78/GJ ($0.83/MMBtu) for NDL coal (20 07 cost of coal in June 2007 dollars). All coal costs are based on HHV. These costs were determined using the following information from the EIA 2008 AEO:

**•** The 20 07 minemouth cost of PRB coal in 2006 dollars, $13.02/ metric ton ( tonne ) ($11.81/ton), was obtained from Supplemental Table 112 of the EIA’s 2008 AEO for western Montana medium

- sulfur subbituminous coal. The 20 07 minemouth cost of NDL coal in 2006 dollars, $11.67/tonne ($10.59/ton), was obtained from the same source.

**•** The 20 07 cost of PRB coal was escalated to June 2007 dollars using the gross domestic product (GDP) chain

- type price index from AEO 2008, resulting i n a price of $13.42/tonne ($12.17/ton) [ 3 ]

. Similarly, the 20 07 cost of NDL coal in June 2007 dollars is $12.04/tonne ($10.92/ton) or $0.79/GJ ($0.83/MMBtu).

**•** Transportation costs for PRB coal were estimated to be 25 percent of the minemouth cost based o n the average transportation rate for medium subbituminous coal from the western Montana region d elivered to the mountain region [ 4 ]

. The final delivered cost of PRB coal used in the calculations is $16.78/tonne ($15.22/ton) or $0.85/GJ ($0.89/MMBtu).

**•** No te: The PRB coal cost conversion of $15.22/ton to dollars per million Btu results in $0.8884/MMBtu

, which was used in calculations, but only two decimal places are shown in the report. Similarly, the NDL fuel cost converts to $0.8251/MMBtu

, which was used in calculations, but only two decimal places are shown.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

26 

### Exhibit 2

- 4 Montana Rosebud PRB, Area D, Western Energy Co. Mine
, 

### Subbituminous Design Coal Analysis

Proximate Analysis Dry Basis, % As Received, % Moisture 0.0 25.77 Ash 11.04 8.19 Volatile Matter 40.87 30.34 Fixed Carbon 48.09 35.70 Total 100.0 100.0 Ultimate Analysis Dry Basis, % As Received, % Carbon 67.45 50.07 Hydrogen 4.56 3.38 Nitrogen 0.96 0.71 Sulfur 0.98 0.73 Chlorine 0.01 0.01 Ash 11.03 8.19 Moisture 0.00 25.77 Oxygen 1 15.01 11.14 Total 100.0 100.0 Heating Value Dry Basis As Received

HHV, kJ/kg 26,787 19,920 HHV, Btu/lb 11,516 8,564 LHV, kJ/kg 25,810 19,195 LHV, Btu/lb 11,096 8,252 Hardgrove Grindability Index 57 Ash Mineral Analysis % Silica SiO 2 38.09 Aluminum Oxide Al 2 O 3 16.73 Iron Oxide Fe 2 O 3 6.46 Titanium Dioxide TiO 2 0.72 Calcium Oxide CaO 16.56 Magnesium Oxide MgO 4.25 Sodium Oxide Na 2 O 0.54 Potassium Oxide K 2 O 0.38 Sulfur Trioxide SO 3 15.08 Phosphorous Pentoxide P 2 O 5 0.35 Barium Oxide Ba 2 O 0.00 Strontium Oxide SrO 0.00 Unknown

--- 0.84 Total 100.0 Trace Components ppmd Mercury 2 Hg 0.081

1 By d ifference
2 Mercury value is the mean plus one standard deviation using EPA’s ICR dataCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

27 

### Exhibit 2

- 5 North Dakota Beulah

- Zap Lignite, Freedom, ND Mine
, 

### Lignite Design Coal Analysis

Proximate Analysis Dry Basis, % As Received, % Moisture 0.0 36.08 Ash 15.43 9.86 Volatile Matter 41.49 26.52 Fixed Carbon 43.09 27.54 Total 100.0 100.0 Ultimate Analysis Dry Basis, % As Received, % Carbon 61.88 39.55 Hydrogen 4.29 2.74 Nitrogen 0.98 0.63 Sulfur 0.98 0.63 Chlorine 0.00 0.00 Ash 15.43 9.86 Moisture 0.00 36.08 Oxygen 1 16.44 10.51 Total 100.0 100.0 Heating Value Dry Basis As Received

HHV, kJ/kg 24,254 15,391 HHV, Btu/lb 10,427 6,617 LHV, kJ/kg 23,335 14,804 LHV, Btu/lb 10,032 6,364 Hardgrove Grindability Index Not applicable Ash Mineral Analysis % Silica SiO 2 35.06 Aluminum Oxide Al 2 O 3 12.29 Iron Oxide Fe 2 O 3 5.12 Titanium Dioxide TiO 2 0.58 Calcium Oxide CaO 14.39 Magnesium Oxide MgO 6.61 Sodium Oxide Na 2 O 5.18 Potassium Oxide K 2 O 0.64 Sulfur Trioxide SO 3 16.27 Barium Oxide Ba 2 O 0.56 Strontium Oxide SrO 0.27 Manganese Dioxide MnO 2 0.02 Unknown

--- 3.00 Total 100.0 Trace Components ppmd

Mercury 2 Hg 0.116

1 By Difference
2 Mercury value is the mean plus one standard deviation using EPA’s ICR dataCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

28 

### 2.3 ENVIRONMENTAL TARGET S

The environmental targets for the study were considered on a technology

- and fuel

- specific basis. 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 fossil

- fuel fired electric utility steam generating units is the New Source Performance Standards (NSPS) as amended in June 200 7 [ 5 ] and shown in Exhibit 2

- 6 , which represents the minimum level of control that would be required for a new fossil energy plant.

The NSPS standards apply to units with the capacity to generate greater than 73 MW of power by burning fossil fuels, as well as cogeneration uni ts that sell more than 25 MW of power and more than one

- third of their potential output capacity to any utility power distribution system. The rule also applies to combined cycle, including IGCC plants, and combined heat and power CT s that burn 75 percent or more synthetic

- coal gas. In cases where both 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 pounds per megawatt hour ( lb/MWh ) are based on gross power output.

Exhibit 2

- 6 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

NOx 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). Environmental area designation varies by county and can be established only for a specific site location. Based on the Environmental Protection Agency (EPA) Green Book Non

- attainment Area Map relatively fewCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

29 

### areas in the W estern U.S. a re classified as “non

- attainment” so the plant site for this study was

assu med to be in an attainment area [ 6 ]

. 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.

Mercury

The Clean Air Mercury Rule (CAMR)

, issued on March 15, 2005

, established NSPS limits for mercury ( Hg ) emissions from new power plants. These rules were vacated by court action on February 8, 2008 and the final resolution of these rules is unknown at this time . Even though the rules are vacated, the CAMR emission limits are included for reference only. The NSPS limits for IGCC plants , based on gross output, are shown in Exhibit 2

- 7 . The applicable limit in this study is 20 x 10 - 6 

### lb/MWh.

Exhibit 2

- 7 NSPS Mercury Emission Limits

Coal Type / Technology Hg Emission Limit

Bituminous 20 x 10 - 6 

### lb/MWh Subbituminous (wet units) 66 x 10 - 6 

### lb/MWh Subbituminous (dry units) 97 x 10 - 6 

### lb/MWh Lignite 175 x 10 - 6 

### lb/MWh

Coal refuse 16 x 10 - 6 

### lb/MWh

IGCC 20 x 10 - 6 

### lb/MWh

The coal Hg concentration used for this study did not come from NETL’s Coal Quality Guidelines, but rather was determined from the EPA ’s ICR database. The ICR database has 137 records of Montana Rosebud subbituminous coal with an average Hg concentration of 0.056 parts per million ( ppm ) (dry) and a standard deviation of 0.025 ppm. There are 266 records for ND L from the Beulah seam with an average Hg con centration of 0.081 ppm (dry) and a standard deviation of 0.035 ppm. The mercury values in Exhibit 2

- 4 and Exhibit 2

- 5 are the mean plus one standard deviation, or 0.081 ppm (dry) for PRB coal and 0.116 p pm (dry) for ND L [ 7 ]

. It was further assumed that all of the coal Hg enters the gas phase and none leaves with the bottom ash or slag.

Design Targets

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

- 8 [ 8 ]

. D esign targets were established specifically for bituminous coal, but are applied to the subbituminous and lignite cases as well. Because of the lower coal sulfur content in the low rankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

30 

### coals, actual sulfur dioxide ( SO 2 

### ) emissions are substantially lower than the environmental target. EPRI notes that these are design targets and are not to be used for permitting values.

Exhibit 2

- 8 IGCC Environmental Targets

Pollutant Environmental Target NSPS Limit Control Technology

NOx 15 ppmv (dry) @ 15% O 2 

### 1.0 lb/MWh Low NOx burners and syngas nitrogen dilution

SO 2 

### 0.0128 lb/MMBtu 1.4 lb/MWh Selexol, MDEA or Sulfinol (depending on

gasifier technology)

Particulate Matter (Filterable) 0.0071 lb/MMBtu 0.015 lb/MMBtu Quench, water scrubber, and/or cyclones and candle filters (depending

on gasifier technology) Mercury > 90% capture 20 x 10 - 6 

### lb/MWh Carbon bed
Based on published vendor literature, it was assumed that LNB s and nitrogen dilution can achieve 15 ppmv (dry) at 15 percent O 2 

### , and that va lue was used for all IGCC cases [ 9
, 10 ]

. To achieve an environmental target of 0.0128 lb/MMBtu of SO 2 

### requires approximately 12 ppmv sulfur in the sweet syngas. The acid gas removal (AGR) process required a sulfur capture efficiency of about 99.7 percent to reach the environmental target using PRB with a sulfur content of 0.73 percent. Vendor data on the AGR processes used in th is study indicate that this level of sulfur removal is possible. When s imilar AGR technologies to the Volume 1 IGCC

cases of this study are used

, SO 2 

### emissions are substantially lower because of the lower coal sulfur content. In the CO 2 

### capture cases, the two

- stage Selexol process results in a sulfur capture of greater than 99.7 percent, hence lower sulfur emissions in the CO 2 

### capture cases.

The ash portion of the coal is largely removed from the gasifier as slag for higher temperature slagging gasifiers

. The ash that remains entrained in the syngas is captured in the downstream equipment, including the syngas scrubber and a c yclone and either ceramic or metallic candle filters. The amount of entrained ash is dependent on the ash content in the coal and the specific gasifier technology. The environmental target of 0.0071 lb/MMBtu filterable particulates can be achieved with t h e combination of particulate control devices employed by each gasifier technology so that it was assumed the environmental target was met exactly.

The environmental target for mercury capture is greater than 90 percent. Based on experience at the Eastman Chemical plant, where syngas from a GE Energy (GEE) gasifier is treated, the actual mercury removal efficiency used is 95 percent. Sulfur

- impregnated activated carbon is used by Eastman as the adsorbent in the packed beds operated at 30°C (86°F) and 6.2 MPa (900 pounds per square inch gage [ psig ] ). Mercury removal between 90 and 95 percent has been reported with a bed life of 18 to 24 months. Removal efficiencies may be even higher, but at 95 percent the measurement precision limit was reached. Eastman has yet to experience any

mercu ry contamination in its product [ 11 ]

. Mercu ry removals of greater than 99 percent can beCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

31 

### achieved by the use of dual beds, i.e., two beds in series. However, this study assumes that the use of sulfur

- impregnated carbon in a single carbon bed achieves 95 percent reduction of mercury emissions

, which meets the environmental target and NSPS limits in all cases.

Carbon Dioxide

CO 2 

### is not currently regulated nationally . 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. CO 2 

### emissions are reported on both a pound ( lb ) /(gross) MWh and lb/(net) MWh basis in each capture case emissions table.

For the IGCC cases that have CO 2 

### capture, the basis is a nominal 90 percent removal based on carbon input from the coal and excluding carbon that exits the gasifier with the slag. The maximum removal is limited by the amount of carbon that is fully oxidized to CO 2 

### , either through the ga sification or WG S reaction. Lower temperature gasifiers tend to produce more methane, which, unless reformed into CO 2 

### , cannot be removed effectively and lowers the maximum removal. The H 2 

### O:CO molar ratio is adjusted as necessary (with a minimum of 0.25

o utlet steam:dry gas ratio) to achieve 90 percent overall CO 2 

### removal, when possible

.

2.4 CAPACITY FACTOR

This study assumes that each new plant would be dispatched any time it is available and would be capable of generating maximum capacity when online. There fore

, CF and availability are equal. I nput from EPRI and their work on the CoalFleet f or Tomorrow Initiative w ere used to set the IGCC case CF

.
There are five operating IGCC plants worldwide that use a solid feedstock and are primarily power producers (Po lk, Wabash, Buggenum

, Puertollano , and Nakoso ). Higman et al. examined the reliability of these IGCC power generation units and concluded that typical annual on

- stream times are around 80 percent [ 12 ]. The CF would be somewhat less than the on

- stream time since most plants operate at less than full load for some portion of the operating year. Given the results of Higman et al. and others [ 13 ], a CF of 80 percent was chosen for IGCC with no spare gasifier requi red.

The addition of carbon capture and storage ( CCS ) to each technology was assumed not
to impact the CF

. This assumption was made to enable a comparison based on the impact of capital and variable operating costs only. Any reduction in assumed CF would further increase the COE for the CO 2 

### capture cases.

2.5 RAW WATER WITHDRAWAL AND CONSUMPTION

A water balance was performed for each case on the major water consumers in the process. The total water demand for each major subsystem was determined and internal recycle water available from various sources like boiler feedwater (BFW) 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 from the ground or diverted from a surface

- water source for use in th e plant. Raw water consumption is also accounted for asCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

32 

### the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source it was withdrawn from.

Raw water makeup 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, BFW makeup, slurry preparation makeup, ash handling makeup, syngas humidification, and quench system makeup. The difference between withdrawal and process water returned to the source is consumption. Consumption represents the net impact of the process on the water source.

BFW blowdown and 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 system ( SWS ) blowdown streams were assum ed to be treated and 90 percent returned to the water source with the balance sent to the ash ponds for evaporation.

The largest consumer of raw water in all cases is cooling tower makeup. Since plants located in the Western United States (U.S.) need to c onsider limited water supplies, a parallel wet/dry steam condenser was chosen for all plant configurations similar to the system recently installed
at the Comanche 3 plant

. In a parallel cooling system half of the turbine exhaust steam is condensed in an air

- cooled condenser and half in a water

- cooled condenser. The cooling water is provided by a mechanical draft, evaporative cooling tower, and all process blowdown streams were assumed to be treated and recycled to the cooling tower

. The design ambient w et bulb temperature of 3°C (37°F) at the Montana site and 2°C (36°F) at the NDL site ( Exhibit 2

- 1 and Exhibit 2

- 2 ) was used to achieve a cooling water temperature of 9°C (48°F) and 8°C (47°F), respectively at the two sites using an approach of 6°C (11°F). The cooling water range was assumed to be 11°C (20°F). The cooling tower ma keup rate was determined using the following [ 14 ] :

**•** Evaporative losses = 0.8 percent of the circulating water flow rate per 10°F of range

**•** Drift losses = 0.001 percent of the circulating water flow rate

**•** Blowdown losses = Evaporative Losses / (Cycles of Concentration

- 1) Where cycles of concentration are a measure of water quality, and a mid

- range value of 4 was chosen for this study. Typical design conditions for air

- cooled condensers include an initial temperature difference (ITD ) of 40

- 55°F [ 15 ]. The ITD is the temperature difference between saturated steam at the steam turbine generator (STG) exhaust and the inlet dry bulb cooling air temperature

. The ITDs at the two locations in this study are 48 and 50°F. The fan power requirement is estimated at 3.5 times the power required for a wet cooling tower with equivalent heat duty [ 16 ].

The water balances presented in subsequent sections include the water demand of the major water consumers within the process, the amount provided by internal recycle, the a mount of raw water withdrawal by difference, the amount of process water returned to the source and the raw water consumption, again by difference.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

33 

### 2.6 COST ESTIMATING METH ODOLOGY

The estimating methodology for capital costs, operations and maintenance costs, and CO 2 

### TS&M costs are described below. The finance structure, basis for the discounted cash flow analysis, and first

- year COE cost calculations are also described.

2.6.1 Capital Costs

As illustrated in Exhibit 2

- 9 , 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 year is the first 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

- 9 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

- sit e facilities and infrastructure that support the plant (e.g., shops, offices, labs, road), and the direct 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 o vernight cost expressed in base

- year (2007) dollars.

The TPC comprises the BEC plus the cost of services provided by the engineering, procurement and construction (EPC) contractor and project and process contingencies. EPC services include:Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

34 

### detailed desi gn, 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 expr essed 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.

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. Accordingly, TASC is expressed in mixed, current

- year dollars over the capital expend iture 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 further calib rated 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 Sy stem as applied in Engineering, Procurement and Construction for the process industries [ 17 ]

. Most techno

- economic studies completed by NETL feature cost estimates intended for the purpose of a “Feasibility Study” (AACE Class 4). Exhibit 2

- 10 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

- 10 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

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 structure been c hosen instead).Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

35 

### Non

- CO 2 

### Capture Plant Maturity

The non

- capture IGCC cases are based on commercial offerings, however, there have been very limited sales of these units so far. These non

- CO 2 

### - capture IGCC plant costs are less mature in the learning curve than PC or NGCC plants , and the costs listed reflect the “next commercial offering” level of cost rather than mature n th



### - of

- a

- kind (NOAK) cost. Thus, each of these cases reflects the expected cost for the next commercial sale of each of these respective technologies.

CO 2 

### Removal Maturity The pre

- combustion CO 2 

### removal technology for the IGCC capture cases has a stronger commercial experience base than for PC or NGCC plants . Pre

- combustion CO 2 

### removal from syngas streams has been proven in chemical pro cesses 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 well along in the planning stages. Contracting Strategy The estimates are based on an EPCM approach utilizing multiple 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 sum EPC contract, the Contractor assumes all risk for performance, schedule, and cost. A s a result of current market conditions, EPC contractors appear more reluctant to assume that overall level of risk. T he 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 ant icipated to be the most cost effective approach for the Owner. While the Owner retains the risks and absorbs higher project management costs , the risks become reduced with time, as there is better scope definition at the time of contract award(s). 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 water supply system, but terminating at the hig h 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 separately and added to the COE. 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 respective 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.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

36 

### Other key estimate consi derations include the following:

**•** Labor costs are based on Midwest, Merit Shop using factors from PAS, Inc [ 18 ]

. PAS presents information for eight separate regions. Volume 1 of this study used a generic Midwestern site, typical of Region 5 (IL, IN, MI, MN , OH, and WI). The weighted average rate for Region 8 (CO, MT, ND, SD, UT, and WY) is within less than one

- half of one percent of that for Region 5. The difference is inconsequential so the same rates used in Volume 1 were maintained in this study. Cost s would need to be re

- evaluated for projects employing union labor.

**•** 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 additional 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 the region, and the

ava ilability 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 artifac ts, 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 within 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 s a percent age 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, document control, materials management, site safety, and field inspection.

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 while others were recei ved 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 pricing 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 economic down turn has re sulted 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 Domest ic 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, itCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

37 

### should be noted that the cost of individual equipment types may still deviate from the June 2007 reference point.

Cross

- comparisons In all technology comparison studies, the relative differences in costs are often more significant than the absolute level of TPC. This requires cross

- account comparison between technologies to review the consistency of the direction of the costs.

In pe rforming such a comparison, it is important to reference the technical parameters for each specific item, as these are the basis for establishing the costs. Scope or assumption differences can quickly explain any apparent anomalies. There are a number of cases where differences in design philosophy occur. Some key examples are:

**•** The CTs for the IGCC capture cases include an additional cost for firing a high hydrogen content fuel.

**•** Lower overall carbon removal for TRIGTM CO 2 

### capture case due to high methane
content.

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 requirements, 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 that 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 requirementsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

38 

### • unexpected cost escalation

**•** performance of the plant after startup (e.g., availability, efficiency)

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. 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

- 11 , AACE International Recommended Practice 16R

- 90 provides guidelines for estimating process contingency based on EPRI philosophy [ 19 ]

. Process contingencie s have been applied to the estimates in this study as follows:

**•** 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 capture cases

- unproven technology at commercial scale in IGCC service

**•** Mercury Removal

– 5 percent on all IGCC cases

– minimal commercial scale experience in IGCC 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

– integration issuesCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

39 

### Exhibit 2

- 11 AACE Guidelines for Process Contingency

Technology Status Process Contingency (% of Associated Process Capital)

New concept with limited data 40+

Concept with bench

- scale data 30

- 70

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.

Owner’s Costs

Exhibit 2

- 13 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 [ 19 ] . The Electric Power Research Institute’s “Technical Assessment Guide (TAG®)

– Power Generation and Storage Technology Options” also has guidelines for estimating owner’s costs. The EPRI an d 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 costs 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 construction. Given TOC, TASC can be determined fr om the ratios given in Exhibit 2

- 12

.

Exhibit 2

- 12 TASC/TOC Factors

Finance Structure IOU High Risk IOU Low Ris k

TASC/TOC 1.140 1.134Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

40 

### Exhibit 2

- 13 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 training 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. Not applicable for natural gas.

**•** 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 )

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 priva te communication with a capital services firm.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

41 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, including 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 engineering (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/te n

- 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 estimates are based on an Engineering Procurement Construction Management approach utilizing multiple subcontr acts, 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 ass umed 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 reuse, rainfall/snowfall criteria, seismic design, buildings/enclosures, fire protection, local code heigh t requirements, noise regulations.

Initial Cost for Catalysts and

Chemicals **•** All initial fills not included in BEC

Taxes & Insurance **•** 2% of TPC (Fixed O&M Cost )Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

42 

### 2.6.2 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 labor

**•** 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 varia ble 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 $34.65/hour. The associated 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 ma intenance 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 ar e 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
opera ting hours.

Quantities for major consumables such as fuel 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 reference dat a.
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

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

43 

### Initial fills of t he consumables, fuels and chemicals

, are different from the initial chemical loadings (such as reactor catalyst) , which are included with the equipment pricing in the capital
cost. Waste Disposal Waste quantities and disposal costs were determined similarly to the consumables. In this study slag from the IGCC cases is considered a non

- hazardous waste with a disposal cost of $17.89/tonne ($16.23/ton). The carbon used for mercury control is conside red a hazardous 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 sulfur, no credit was taken for 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 high loc al value of the product can establish whether or not added capital should be included in the plant costs to produce a particular co

- product. S lag is a potential by

- product in certain markets. However, as stated above, the slag is considered a non

- hazardo us w aste in this study with a concomitant disposal cost.

2.6.3 CO 2 

### Transport, Storage and Monitoring

For those cases that feature carbon sequestration, the 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 1 5.3 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

- 14 [ 20 ]. A g lycol dryer located near the mid

- point of the compression train is used to meet the moisture specification.

**•** 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 [ 21 ]. The pipeline is assumed to have an outlet pressure (above the SC pressure) of 8

. 3 MPa (1, 200 psia) with no recompression along the way. According ly, 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 [ 22 ]. ( 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 du ring injection are minimal and no booster compression is required at the well

- head in order toCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

44 

### achieve an appropriate down

- hole pressure , with hydrostatic head making up the difference between the injection and reservoir pressure.

Exhibit 2

- 14 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 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) [ 23 ]. 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 [ 23 ]

. The assumed aq uifer characteristics are tabulated in Exhibit 2

- 15

. Exhibit 2

- 15 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 m d (μm 2 

### ) 22 ( 22 )

Pipeline Distance km (miles) 80 (50)

Injection Rate per Well tonne (ton) CO 2 

### /day 9,360 (10,320)

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 which sub

- surf ace 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 quoted by indu strial sources where possible. Where regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition ofCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

45 

### underground pore volume, analogous existing policies were used for representative cost scenarios.

The following secti ons describe the sources and methodology used for each metric.

TS&M Capital 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 Liabi lity, 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 outlay, 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 Oil 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 studies [ 21
, 23
, 24 ]. The University of California performed a regression analysis to generate cost curves fr om 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 [ 24 ] . 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 Sequestration in Saline Formations

– Engi neering and Economic Assessment [ 23 ]

. This study utilized a similar basis for pipeline costs ( O&GJ Pipeline cost data up to the year 2000) but added a CO 2 

### s urge 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 [ 21 ]. This 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 the m in absolute terms for one pipeline, as opposed to as a length

- or diameter

- 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 Acquisition, all of the costs were obtained from Economic Evaluation of CO 2 

### Storage and Sink Enhancement Options [ 21 ]

. These costs include all of the costs associated with determining, developing, and maintaining a CO 2 

### storage location, including site evaluation, well drilling, and the capital equipment required for distributing and inject ing CO 2


### .Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

46 

### Pore Volume Acquisition costs are the costs associated with acquiring rights 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 to natural gas storage [ 25 ]. 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 wh en the plume reached each individual acre of their property for 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 liabili ty protection schem e s have been suggested for CO 2 

### storage, including 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 [ 26 ]

. 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 ) [ 27
, 28
, 29 ]. In the case of Louisiana, a trust fund totaling five mil lion dollars 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 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 St orage Projects report [ 30 ]

. 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 (for a total of eighty years). Monitoring is via electromagneti c (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.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

47 

### 2.6.4 Finance Structure, Discounted Cash Flow Analysis, and COE The global economic assumptions are listed in Exhibit 2

- 16

. 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

ass essed (low

- risk or high

- risk). For this study the owner/developer was assumed to be an IOU. All IGCC cases were considered high risk.

Exhibit 2

- 17 describes the low

- risk IOU (for reference) and high

- risk IOU finance structures that were assumed for this study. These finance structures were recommended in a 2008 NETL report based on interviews with project developers/owners, financial organizations and law firms [ 31 ]

.

Exhibit 2

- 16 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 Coal Plants: 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% 2

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

2 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.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

48 

### Parameter Value

% 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% 3



### Exhibit 2

- 17 Financial Structure for Investor Owned Utility High and Low 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) is a nominal

- dollar 4 

### (current dollar) discounted cash flow (DCF) analysis tool. As explained below, the PSFM was used to calculate COE 5 

### in two ways: a COE and a levelized COE (LCOE). To illustrate how the two are related, COE solutions are shown in Exhibit 2

- 18 for a generic pulverized coal (PC) power plant and a generic natural gas combined cycle (NGCC) power plant , each with carbon capture and sequestration installed

.

3 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.)

4 Since the analysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect the interplay between depreciation and inflation.

5 For this calculation, “cost of electricity” is somewhat of a misnomer because from the power plant’s pers pective 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 electricit y.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

49 

### • 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 real 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 6 

### , provided the stipulated internal rate of return on equity over the entire economic analysis period (capital expenditure period plus thirty years o f operation). The COE solutions are shown as curved lines in the upper portion of Exhibit 2

- 18 for a PC power plant and a NGCC power plant. Since thi s analysis assumes that COE increases over the economic analysis period at the nominal annual general inflation rate, it remains constant in real terms and the first

- year COE is equivalent to the base

- year COE when expressed in base

- year (2007) dollars.

**•** The LEVELIZED 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 of 0 percent , i.e., that it remains constant in nominal terms over the operational period of the power plant. This study reports LCOE on a current

- dollar basis over thirty years. “Current dollar” refers to the fact that levelization is done on a nominal, rather than a real, basis 7 

### . “Thirty

- years” refers to t he length of the operational period assumed for the economic analysis. To calculate the LCOE, the PSFM was used to calculate a base

- year COE that, when escalated at a nominal annual rate of 0 percent , provided the stipulated return on equity over the enti re economic analysis period. For the example PC and NGCC power plant cases, the LCOE solutions are shown as horizontal lines in the upper portion of Exhibit 2

- 18

. Exhibit 2

- 18 also illustrates the relationship between COE and the assumed developme ntal and operational timelines for the power plants. As shown in the lower portion of Exhibit 2

- 18
, the capital expenditure period is assumed to start in 2007 for all cases in this report. All capital costs included in this analysis, including project development and construction costs, are assumed to be incurred during the capital expenditure period. Coal

- fueled plants are assumed to have a capital e xpenditure period of five years and natural gas

- fueled plants are assumed to have a capital expenditure period of three years. Since both types of plants begin expending capital in the base year (2007), this means that the analysis assumes that they begin operating in different years: 2012 for coal plants (see Volume 3b for cost and performance of combustion based plants) and 2010 for natural gas plants in this study (see Volume 3c for cost and performance of NGCC plants)

. Note that, according to the Che mical Engineering Plant Cost Index, June

- 2007 dollars are nearly equivalent to January

- 2010 dollars.

6 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 Powe r 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.

7 For this current

- dollar analysis, the LCOE is uniform i n current dollars over the analysis period. In contrast, a
constant

- dollar analysis would yield an LCOE that is uniform in constant dollars over the analysis period.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

50 

### Exhibit 2

- 18 Illustration of COE Solutions using DCF Analysis

In addition to the capital expenditure period, the economic analysis considers thirty years of operation.

Since 2007 is the first year of the capital expenditure period, it is also the base year for the economic analysis. Accordingly, it is convenient to report the results of the economic anal ysis in base

- year (June 2007) dollars, except for TASC, which is expressed in mixed

- year, current dollars over the capital expenditure period.

Consistent with our nominal

- dollar discounted cash flow methodology, the COEs shown on Ex hibit 2

- 18 are expressed in current dollars. However, they can also be expressed in constant, base year dollars (June 2007) as shown in Exhibit 2

- 19 by adjusting them with the assumed nominal annual general inflation rate (3 percent ).

Exhibit 2

- 19 illustrates the same information as in Exhibit 2

- 18 for a PC plant with CCS only on a constant 2007 d ollar basis. With an assumed nominal COE escalation rate equal to the rate of inflation, the COE line now becomes horizontal and the LCOE decreases at a rate of 3 percent per year.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

51 

### Exhibit 2

- 19 PC with CCS in Current 2007 Dollars

Estimating COE with Capital Charge Factors For scenarios that adhere to the global economic assumptions listed in Exhibit 2

- 16 and utilize one of the finance structures listed in Exhibit 2

- 17 , the following simplified equation ca n be used to estimate COE as a function of TOC 8 

### , fixed O&M, variable O&M (including fuel), capacity factor and net output. The equation requires the application of one of the capital charge factors (CCF) listed in Exhibit 2

- 20 . These CCFs are valid only for the global economic assumptions listed in Exhibit 2

- 16 , the stated finance structure, and the stated capital expenditure period.

Exhibit 2

- 20 Capital Charge Factors for COE Equation

Finance Structure High Risk IOU Low Risk IOU

Capital Charge Factor (CCF) 0.124 3 0.116 5

8 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).Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

52 

### 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

- 16 , 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.

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

- 20 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 oper ating 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 megawatt

- hours of power generated at 100 percent capacity factor

The primary cost metric in this study is the COE, which is the base

- year cost presented in base

year dollars. Ex X presents this cost metric along with the COE escalated to the first year of operation (2012 for coal cases) using the average annual inflation rate of 3 percent. Similarly, the LCOE is presented in both base

- year dollars and first year of operation dollars. Using a similar methodology, the reader m ay generate either metric in the desired cost year basis.

The cost of avoiding CO 2 

### was calculated in two ways: the cost of CO 2 

### avoided compared to the analogous non

- capture design and the cost of CO 2 

### avoided compared to a baseline SC PC boiler plant firing the same coal at the same design conditions, using the equation below :Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

53 

### MWh tons Emissions CO Emissions CO MWh COE COE Cost Avoided

removal with reference reference removal with 

### / } { / $ } {

2 2 

### − **−**

**=**

Exhibit 2

- 21 COE and LCOE Summary

Case COE LCOE

Base

- Year First Operational Year Base

- Year First Operational Year

2007$ 2012$ 2007$ 2012$



### S1A 83. 2 96.4 105.4 122.2
S1B 1 19

. 7 138.8 151.8 175.9
L1A 8 3

. 5 96.8 105.8 122.7
L1B 1 2 1

. 9 141.3 154.5 179.1
S 2 A 74

. 5 86.4 94.5 109.5
S 2 B 10 5

. 2 122.0 133.4 154.6
S 3A 86

. 8 100.6 110.0 127.5
S 3B 1 21

. 7 141.1 154.3 178.9
L3 A 87

. 3 101.2 110.7 128.3
L3 B 1 23 .7 143.5 156.9 181.9
S4 A 78

. 7 91.3 99.8 115.7
S4 B 1 12

. 3 130.2 142.4 165.1

The baseline SC PC boiler plant is a 550MW plant with the results presented in Exhibit 2

- 22
, below, and in the combustion portion of this report volume. The COE in the CO 2 

### capture cases includes TS&M

, as well as capture and compression.

Exhibit 2

- 22 Baseline SC PC Results for CO 2 

### Cost Calculation

PRB (S12A) Lignite (L12A)
Net Output (MW) 550 550 COE (mills/kWh) 57.80 62. 19 Emissions (lb/ net

- M Wh) 1
, 89 2 1
, 99 6Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

54 

### 2.7 IGCC STUDY COST ESTI MATES COMPARED TO IN DUSTRY ESTIMATES

The estimated TOC for IGCC cases in this study ranges f rom $2

, 728 to $ 3
, 239 /kW for non

- CO 2 

### capture cases and $ 3
, 691 /kW to $ 4
, 430 /kW for capture cases. Plant size ranges from 504

- 617 MW (net) for non

- capture cases and 445

- 5 15 MW (net) for capture cases.

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 early stages of development, some cost estimates have been pub lished. 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 Commission approved Duke Energy’s proposal to build an IGCC plan t 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 $ 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 5 80 MW [ 32
, 33
, 34
, 35 ]. 9



### 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 Transfor mers (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 pipe 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 greenfield site having “normal” characteristics. Accordingly, the estimates do not address items such as:

**•** Piles or caissons

**•** Rock removal

**•** Excessive dewatering

9 Costs were adjusted to Jun e 2007 using the Chemical Engineering Plant Cost IndexCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

55 

### • Expansive soil considerations

**•** Excessive seismic considerations

**•** Extreme temperature considerations

**•** Hazardous or contaminated soils

**•** Demolition or relocation of existing structures

**•** Leasing of offsite lan d 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

**•** Automated coal reclaim

**•** Zero Liquid Discharge equipment

**•** SCR catalyst

For non

- capture cases, which are likely the most appropriate comparison against industry published estimates, this report is based on plant equipment sized for non

- capture only. None of
t he 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 Union 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 ade quate 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 bi d, 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 mu ch as 30 percent or more over an EPCM approach.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

56 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

57 

### 3. IGCC POWER PLANTS

Twelve IGCC power plant configurations were evaluated and the results are presented in this section. Each design is based on a market

- ready technology th at is assumed to be commercially available to support startup in the near term

.
The six cases are based on the Shell Coal Gasification Process, TRIGTM gasifier , Siemens Fuel Gasifier and CoP E

- GasTM gasifier, each with and without CO 2 

### capture. As discussed in Section 1, the net output for the twelve cases varies because of the constraint imposed by the fixed GT output and the high auxiliary loads imparted by the CO 2 

### capture process. The TRIGTM gasifier development has focused more on air

- blown gasification f or power generation, for characterizing the gasifier performance on a range of coals, so only PRB coal was considered as a starting point for comparison to other potential configurations. The CoP E

- GasTM gasifier feed has an upper limit for coal slurry con centration, which becomes a concern for lower rank coals, so to err on the side of more proven feedstocks, only PRB coal was considered for CoP cases.

The CT is based on an advanced F

- class design. The HRSG/steam turbine cycle is nominally 12.4 MPa/566°C/ 566°C (1800 psig/1050°F/1050°F) for all of the non

- CO 2 

### capture cases and nominally 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) for all of the CO 2 

### capture cases. The capture cases have a lower main and reheat steam temperature primarily because the turb ine firing temperature is reduced to allow for a parts life equivalent to NGCC operation with a high

hydrogen content fuel, which results in a lower turbine exhaust temperature.

The evaluation scope included developing heat and mass balances and estimatin g plant performance. Equipment lists were developed for each design to support plant capital and operating cost estimates. The evaluation basis details, including site ambient conditions, fuel composition and environmental targets, were provided in Secti on 2 . Section 3.1 covers general information that is common to all IGCC cases, and case specific inform ation is subsequently presented in the gasifier background sections

.

3.1 IGCC COMMON PROCESS AREAS

The IGCC cases have process areas

, which are common to each plant configuration such as coal receiving and storage, coal drying, oxygen supply, gas cleanup, powe r generation, etc. As detailed descriptions of these process areas for each case would be burdensome and repetitious, they are presented in this section for general background information. Where there is case

specific performance information, the perform ance features are presented in the relevant case sections.

3.1.1 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 trestle bottom dumper and coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage silos

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

58 

### Operation Description

– The coal is delivered to the site by 100

- car unit trains comprised of 91 tonne (100 ton) rail cars f or PRB cases. The lignite cases are located at a minemouth location

. 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 centimeters ( 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 conveyor 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 transfers 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 th e 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.

3.1.2 C oal Drying

Reduction in coal moisture content can improve the efficiency of dry

- feed gasifiers, with a corresponding increase in auxiliaries and drying equipment costs . Coal moisture consists of two components, surface moisture and inherent moisture. Low rank coals have higher inherent moisture content and total moisture content than bituminous and other high rank coals. Depending on the size of the coal fed to the gasifier, it may be necessary to reduce most, if not all, of the surface moisture for coal transport properties to be acceptable. It should be noted that fluidization tests would need to be performed for the specific coals, in conjunction with the gasifier vendors, to ensure that the coal drying scheme results in the required coal transportation properties.

Dry feed gasifiers utilize coal drying schemes as described below. This reduces the amount of diluent fed to the gasifier, balanced out by the auxiliaries required to vaporize the coal moisture, generally prov iding a net increase to efficiency while introducing additional cost and complexity to the feed system. The slurry feed system is described in the individual technology section for the CoP E

- GasTM IGCC cases.

In a Gasification Technology Conference ( GTC ) p aper [ 36 ]
, Shell indicated for its entrained flow gasifier feeding coal in the size range of 50

– 100 microns that it would dry lignite coal from 53 to 12 percent and subbituminous coal from 30 to 6 percent. The presentation indicated the coal would be dri ed using the fine grain WTA (fluidized bed drying technology with built

- in waste heat recovery) process , which dries coal at a particle size of about 1 millimeter ( mm ) (1,000 microns). Consequently

, the coal must be run through a pulverizer after drying b efore being fed to the gasifier.

In personal correspondence with Shell, they indicated the moisture content of the coal after drying should be 3

- 14 percent depending on coal type [ 37 ]. EPRI and IEA recently performed studies that included the Shell gasifie r using lignite coal that used a design moisture content of 5 percent entering the gasifier [ 38
, 39 ].Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

59 

### Publications by Southern Company Services indicate for their transport gasifier that coal with a top size of 700 microns [ 40 ] would be dried to a moisture l evel of 18 weight percent (wt%) [ 41 ]

. Consequently, for the dry

- feed entrained flow gasifiers in this study it is assumed that the subbituminous coal is dried to 6 percent moisture and the lignite to 12 percent moisture. For the transport gasifiers in this study, the coal will be dried to 18 percent moisture. In more detailed designs, coal fluidization tests would be performed to fine tune the coal feeding process.

The coal drying process selected for a specific IGCC system is a function of the drying
requ irement. The options considered for coal drying include:

**•** Option 1: Use conventional IGCC coal drying methods

, which consist of deriving heat from the combustion of natural gas and/or syngas and using the flue gas

, either directly or indirectly ( by heatin g a nitrogen stream ), for use in drying the coal. Some examples include the following:

o At the Buggenum facility bituminous coal is ground in a conventional roller mill and simultaneously dried using a heated inert recycle gas stream that carries the
evap orated water from the system as it sweeps the PC through an internal, rotating classifier. The inert gas generator is fueled by the in

- line combustion of treated syngas. Excess gas is vented on pressure control [ 42 ]

.

o At the Puertollano facility, coal is ground in mills using nitrogen for drying from 10 percent to less than 2 percent moisture. The drying circuit is heated to about 250°C (482°F) by intermediate pressure ( IP )

- steam and additional burning of natural gas. The report notes that a dual drying circuit using only natural gas and the produced syngas could be studied [ 43 ].

**•** Option 2: Use a conventional drying method with the warm gas exiting the HRSG used as the heat source. The HRSG exit gas is typically aroun d 270°F and contains 10

- 11 percent oxygen. The high oxygen concentration is a concern with low rank coals and self ignition levels in the drying circuit, for the specific coals, should be studied and addressed in a more detailed design.

**•** Option 3: Dry th e coal using a scheme similar to the Great River Energy (GRE) Clean Coal Power Initiative ( CCPI ) project approach. In the case of gasification where the drying requirements are greater than in PC plants, higher grade heat than is available from the coolin g water exiting the condenser will be required. However, there are many sources of low

- level waste heat in an IGCC plant and integration of this heat into the drying circuit is possible. Because of the tendency for low rank coals to spontaneously combust after the moisture is removed, it may be necessary to fluidize the coal bed with something other than air. Depending on the source of the fluidization gas, the process could become cost prohibitive.

**•** Option 4: Use the WTA process (German acronym for “fluidized bed dryer with integrated waste heat recovery” ) [ 44 ] proposed by RWE Power AG , which consists of a fluid bed dryer utilizing a heat pump

- type cycle with recovered coal moisture used forCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

60 

### fluidizing the coal bed and used as the working fluid [ 45 ]. This is the option presented by Shell at the 2005 GTC Conference

, as mentioned above.

**•** Option 5: Use a process similar to the Integrated Drying and Gasification Combined Cycle (IDGCC) being developed in Australia.

**•** Option 6: Use a drying configuration pr acticed by Southern Company Services [ 46 ] where coal is dried in a closed

- loop (CL) including a roll mill pulverizer, flash dryer, gas cooler to condense water vapor, and heater to heat the gas for drying. The oxygen concentration of the CL gas is monitored and nitrogen is fed as necessary to maintain an oxygen concentration below 11.3 percent for safety reasons. The source of heat is waste heat or IP steam. The water removed from the coal is collected in the cooler, treated, and used in the process.

Conve ntional coal drying methods would be suitable for this study, but there is an efficiency penalty involved with burning either syngas or natural gas as a heat source and there are additional CO 2 

### emissions generated by the process. Using steam as the heat s ource also impacts overall efficiency.

The GRE process has potential because of the many sources of low

- grade heat in the IGCC process. However, the fluidization gas source would have to be identified assuming ambient air cannot be used because of the com bustion tendencies of dried, low rank coals. One possibility would be using the HRSG exhaust gas

, which contains 10

- 11 percent oxygen.

The RWE process has the advantage of using steam and coal moisture as the fluidizing medium thus eliminating the spontaneous combustion concerns. However, the vapor compressor imposes a significant auxiliary load. In Shell’s GTC presentation the relative power and steam use are compared for three different technologies [ 47 ]. The results shown in Exhibit 3

- 1 assume 350 ton per hour ( TPH ) of as

- received lignite coal with 53 percent moisture dried to 12 percent.

Exhibit 3

- 1 SCGP Li gnite Coal Drying Options

Coal Feed, “dried” basis Power Use, kW Steam Use, lb/h r Water Product, lb/h r Conventional drying (rotary kiln) 3,180 449,000 0

Fluid bed simple 4,670 411,000 0

Fluid bed with WTA
process 15,890 64,000 261,700

The IDGCC process is being commercialized by HRL Ltd. HRL has been trying to develop a project in Australia since 2002, originally at a scale of 400 MW and more recently at a scale of 600 MW [ 48 ]. The process utilizes hot syngas from an air blown fluidize d bed gasifier (FBG) to dry brown coal prior to entering the gasif i er . Sulfur is captured in the fluid bed and particulates are removed in a downstream candle filter. The warm, humidified syngas is then burned in a GT [ 49 ].Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

61 

### The technology is being develop ed for an air

- blown FBG and has features that make it less attractive in the case of an entrained

- flow, oxygen

- blown gasifier like the Shell process. The coal is crushed to 10 mm top size and pressurized to 2.5 MPa (363 pounds per square inch [ psi ] ) throu gh a lock hopper system. The FBG can accept 10 mm coal, and at that size and high moisture content the coal will still flow through the lock hoppers. However, in the case of the Shell gasifier, the coal top size is significantly smaller (Shell does not s pecify the size

, but states that conventional coal pulverizers are used

, which likely results in an average coal size of 50

- 100 μm) and the coal must be dried prior to pressurizing to avoid lock hopper flow problems.

Where applicable, the WTA coal drying s ystem was chosen for the traditional dry feed gasifiers largely because of its ability to recover the water from the coal in liquid state for use in the process and the fact that syngas is not used to provide heat for drying. In conventional dryers, the w ater is mixed with the heating gas and discharged to atmosphere as vapor. Recovery of the coal moisture in a liquid state results in a sizable electric auxiliary load.

The ‘closed’ WTA process has been demonstrated at pilot scale. Plans for a commercial demonstration of an ‘open’ version of the process have been delayed. In spite of the uncertainty of the commercial demonstration, the potential benefit of the technology was viewed to be significant enough to use the ‘closed version’ of the process in thi s study. A process schematic is shown in Exhibit 3

- 2 , reprinted from Kakaras, Emm. et al

. [ 50 ].

Exhibit 3

- 2 WTA Process SchematicCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

62 

### An effort was made to apply the WTA process to the TRIG TM IGCC c ases. The PRB coal as received contains 26 percent moisture, and must only be dried to 18 percent moisture for the transport gasifier cases . Because of the low moisture delta (8 percent), there is a reduced amount of moisture available to provide the wor king fluid for the heat pump cycle requiring excessively high steam compressor discharge pressures (and subsequently temperatures) to produce the heat necessary to both vaporize the water and sensibly heat the coal. Consequently, the WTA process
was not u sed for the TRIG TM cases , but rather the Southern Company Services system described in Option 6 above was paired with the associated transport gasifier technology

.
For the TRIG TM IGCC systems, fluidized

- bed roller mills simultaneously dr y and crush the coal to 700 μm by a combination of flash drying and in bed heating, utilizing waste heat where possible

.

3.1.3 Gasifier Modeling

Gasifier performance was modeled at the boundaries of the gasifier operation as an equilibrium reactor. Many literatu re references support this modeling strategy [ 44
, 51
, 52 ]. Gasifier vendors’ input were used to determine the inputs to the gasifier

, as well as the typical or desir ed configuration of the gasifier, high temperature heat recovery, and syngas cleaning processes. The boundaries of the gasifier model and the syngas compositions were generally provided or refined with estimates from the vendors and the temperature approa ches to equilibrium were adjusted to match the syngas exiting these boundary conditions.

3.1.4 ASU Choice and Integration

In order to economically and efficiently support IGCC projects, air separation equipment has been modified and improved in response to pro duction 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 t his study, the main air compressor discharge pressure was set at 1.3 MPa (190 psia) compared to a traditional ASU plant operating pressure of about 0.7 MPa (105 psia) [ 53 ]. For IGCC designs the elevated pressure ASU process minimizes power consumption and decreases the size of some of the equipment items. When the air supply to the ASU is integrated with the GT , the ASU operates at or near the supply pressure from the GT ’s air compressor. Residual Nitrogen Injection The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been met is compressed and sent to the GT . Since all product streams are being compressed, the ASU air feed pressure is optimized to reduce the total power.

Increasing the diluent flow to the GT by inje cting residual nitrogen from the ASU can have a number of benefits, depending on the design of the GT :

**•** Increased diluent increases mass flow through the turbine, thus increasing the power output of the GT while maintaining optimum firing temperatures for syngas operation.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

63 

### • 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 thermal NOx.

In this study, the ASU nitrogen product was used as the primary diluent with a design target of reducing the syngas lower heating value (LHV) to 4. 2 to 4.8 megajoule per normal cubic meter ( MJ/Nm 3 

### ) (1 15

- 1 32 British thermal unit per standard cubic foot [ Btu/scf ] ). If the amount of available nitr ogen was not sufficient to meet this target, additional dilution was provided through syngas humidification, and if still more dilution was required, the third option was steam injection. Air Integration Integration between the ASU and the CT can be practi ced by extracting some, or all, of the ASU’s air requirement from the GT . Medium Btu syngas streams result in a higher mass flow than natural gas to provide the same heat content to the GT . Some GT designs may need to extract air to maintain stable compr essor or turbine operation in response to increased fuel flow rates. Other GT s 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 a t a given site to optimize year

- round performance.

An important aspect of air

- integrated designs is the need to efficiently recover the heat of compression contained in the air extracted from the GT . Extraction air temperature is normally in the range 399 to 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 heat recovery from the extracted air occurs by tran sferring heat to the nitrogen stream to be injected into the GT with
a gas

- to

- gas heat exchanger. Elevated Pressure ASU Experience in Gasification The Buggenum, Netherlands unit built for Demkolec , now owned by NUON, was the first elevated

- pressure, fully integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 tons per day [ tpd ] ) of 95 percent purity oxygen for a Shell coal

- based gasification unit that fuels a Siemens V94.2 GT . In normal operation at the Buggenum plant t he ASU receives all of its air supply from and sends all residual nitrogen to the GT

. The Polk County, Florida ASU for the Tampa Electric IGCC is also an elevated

- pressure, 95 percent purity oxygen design that provides 1,832 tonnes/day (2,020 tpd ) of oxyge n to a GEE coal

- based gasification unit, which fuels a General Electric 7FA GT . All of the nitrogen produced in the ASU is used in the GT . 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 and increased overall power output [ 54 ].

ASU Basis For this study, air integration is used for the non

- carbon ca pture cases only. In the CO 2 

### capture cases, once the syngas is diluted to the target heating value, all of the available combustion air is required to maintain mass flow through the turbine and hence maintain power output.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

64 

### The amount of air extracted from the GT in the non

- capture cases is determined through a process that includes the following constraints:

**•** The CT must be fully loaded; i.e., sufficient gas mass flow is supplied to maximize the turbine power output at the given elevation

.

**•** The diluted synga s must meet heating value requirements specified by a CT vendor, which ranged from 4. 2

- 4.8 MJ/Nm 3 

### (1 15

- 1 32 Btu/scf) (LHV).

The air extraction for the non

- CO 2 

### capture case is shown in Exhibit 3

- 3 . 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 t he best balance between maximizing plant output and efficiency without compromising plant availability or reliability [ 55
, 56 ].

Exhibit 3

- 3 Air Extracted from the Combustion Turbine and Supplied to the ASU in Non

Carbon Capture Case

Case No. S1A L1A S2A S3A L3A S4A

Air Extracted from GT , % 2.5 6.0 0.7 2.8 3.2 6.0 Air Provided to ASU, % of ASU Total 11.0 26.0 3.9 13.3 13.6 18.7

Air Separation Plant Process Description [ 57 ] The air separation plant 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 dilution in the GT combustor. A process schematic of a typical ASU is shown in Exhibit 3

- 4

.
The air feed to the ASU can be supplied from two sources. A portion of the air can be extracted from the compressor of the GT (non

- CO 2 

### capture cases only). The remaining air is supplied from a stand

- alone compressor. Air to the stand

- alone compressor is first filtered in a suction filter upstream of the compressor. This air filter remov es 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 extra ction air, 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 through 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 adsorbent 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. FollowingCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

65 

### 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.

Exhibit 3

- 4 Typical ASU Process Schematic

Cryogenic Air Separation Unit

Single Train Oxygen Compressor

HP Oxygen

Nitrogen Compressor

HP Nitrogen Regen Heater

Cond

. Steam Regeneration

Nitrogen

Prepurifiers

Two Stage

DCA Booster Air Compressor

Air Main Air Compressor Air Filter CWR CWS Chiller CWS

CWR Steam Cond Regen

. N 2

Blower

Liq

. Oxygen Pump Turbine Turbine Air Booster



### 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 per cent 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 lo w pressure (LP) process steam at 0.45 MPa (65 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 are 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 beg in the separation process. The second largest air 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
cryo genic separation process.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

66 

### Inside the cold 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 HP 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 gas ification unit.

Nitrogen is produced from the cold box at two pressure levels. Both streams are compressed for

use as CT diluent nitrogen. Some of the nitrogen stream is compressed further for use as transport gas in lockhoppers in dry feed systems

.

3.1.5 High Temperature Syngas Cooling

The main configurations considered in this study for high temperature syngas cooling were determined from commercial or near commercial offerings by the different gasifier vendors and include: syngas coolers, syngas recycle que nch, and water quench. High temperature syngas coolers are the most aggressive heat recovery approach, where high quality sensible heat is recovered from syngas. This increases plant efficiency at the cost of expensive heat exchangers requiring special m aterials of construction to resist corrosion and the high syngas temperatures.

The high temperature syngas cooling equipment varied by technology vendor with one utilizing waterwall heat exchangers and two others utilizing less expensive firetube heat exc hangers. The fourth technology vendor chose not to include any high temperature heat exchanger.

Systems using high temperature syngas coolers can also utilize other syngas cooling methods to minimize the disadvantages of using these heat exchangers. The syngas recycle quench method returns a portion of cooled syngas to reduce the temperature of the raw syngas entering the syngas coolers. This approach reduces the temperatures entering the syngas coolers, potentially reducing costs by allowing for cheaper materials of construction. A similar amount of heat is recovered, which is a result of a proportional increase in the size of the syngas stream, which offsets the lower inlet temperatures to the syngas coolers. Extra equipment required for this configur ation includes compressors, piping, and headers required to recycle the syngas.

Another option considered for lowering the inlet temperature to the syngas coolers is a water quench. This is a more reliable and less costly option as it relies on spraying w ater into the syngas to reduce its temperature entering the heat exchangers. A disadvantage is that the latent heat of vaporization of the quench water can only be recovered at low temperatures, which means in many cases that it goes to waste, reducing th e efficiency of the plant. A water quench reduces the temperature entering the heat exchangers, similar to the syngas recycle quench, and can also be designed to help reduce corrosion and fouling in the heat exchangers by removing some of the particulates and acid gases exiting the gasifier. For CO 2 

### capture cases, the water added to the syngas is an additional benefit as it is required for the WGS reaction, which would otherwise be extracted from the steam cycle if it was not directly raised by the syngas . The individual chosen syngas cooling schemes are enumerated in the specific technology process descriptions.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

67 

### 3.1.6 Water Gas Shift Reactors

Selection of Technology

- In the cases with CO 2 

### separation and capture, the gasifier product must be converted to hydro gen

- rich syngas. The first step is to convert most of the syngas CO to hydrogen and CO 2 

### by reacting the CO with water over a bed of catalyst. The H 2 

### O:CO molar ratio in the shift reaction, shown bel ow, is adjusted to prevent deposition on the catalyst by the addition of steam to the syngas stream to push the equilibrium towards a high conversion of CO. The H 2 

### O:CO molar ratio is adjusted as necessary ( with a minimum of 0. 25 outlet steam:dry gas ratio) to achieve 90 percent overall CO 2 

### removal , if possi ble . In the cases without CO 2 

### separation and capture, CO shift convertors are not required.

Water Gas Shift: CO + H 2 

### O ↔ CO 2 

### + H 2



### The CO shift converter can be located either upstream of the AGR step (sour gas shift [SGS] ) or immediately downstream (s weet gas shift). If the CO converter is located downstream of the AGR , then the metallurgy of the unit is less stringent

, but additional equipment must be added to the process , such as c arbonyl sulfide ( COS ) hydrolysis unit . Products from the gasifier ar e quenched with water and contain a portion of the water vapor necessary to meet the water

- to

- gas criteria at the reactor outlet . If the CO converter is located downstream of the AGR , then the gasifier product would first have to be cooled, reducing the w ater content of the syngas . Then additional steam would have to be generated and re

- injected into the shift reactor feed and the stream would have to be reheated to the catalyst operating temperature to encourage th e WGS reaction . If the shift reactor is located upstream of the AGR step, these steps are avoided, but the choice of shift catalyst must consider its sulfur tolerance. Therefore, for this study the CO converter was located upstream of the AGR unit and is referred to as SGS , which also hydrolyzes the COS to H 2 

### S for removal in the AGR

. Process Description

- The SGS consists of two parallel paths of fixed

- bed reactors . Each parallel path consists of two or three reactor stages in series to achieve a sufficient conversion to meet the CO 2 

### c apture target, if possible

. 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 s after the first SGS reactor are us ed to superheat shift steam . The heat exchanger after the second SGS reactor is a gas

- gas exchanger used to preheat the syngas prior to the first SGS reactor.

3.1.7 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 Topso e and Porocel offer a catalyst that promotes the COS hydrolysis reaction. The non

- carbon capture COS hydrolysis reactor designs are based on information from Porocel. In cases with CO 2 

### capture, the SGS reactors reduce COS to H 2 

### S as discussed in Section 3.1.6

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

68 

### The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The reaction 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. Since the exit gas COS concentration is critical to the amount of H 2 

### S that must be removed with the AGR proces s, a retention time of 50

- 75 seconds was used to achieve 99.5 percent conversion of the COS. The Porocel activated alumina

- based catalyst, designated as Hydrocel 640 catalyst, promotes the COS hydrolysis reaction without promoting reaction of H 2 

### S and CO t o 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 essentially isothermal. The product gas, now containing less than 4 ppmv of COS, is c ooled prior to entering the mercury removal process and the AGR.

3.1.8 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 because 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 control 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 [ 11 ]. The coal mercury content (0. 081 ppm dry for PRB and 0.116 ppm dry for lignite ) and carbon bed removal efficiency (95 percent) were discussed previously in Section 2.3 . IGCC

- specific design considerations are discussed below.

Carbon Bed Location

– The packed carbon bed vessels are located upstream of the AGR
process and syngas enters at a temperature near 38°C (100° F). Consideration was given to locating the beds further upstream before the COS hydrolysis unit (in non

- CO 2 

### capture cases) at a temperature near 204°C (400°F). However, while the mercury removal efficiency of carbon has been found to be relatively insen sitive to pressure variations, temperature adversely affects the removal efficiency [ 58 ]. Eastman Chemical also operates their beds ahead of their sulfur recovery unit (SRU) at a temperature of 30°C (86°F) [ 11 ].

Consideration was also given to locating the beds downstream of the AGR . However, it was felt that removing the mercury and other contaminants before the AGR unit would enhance the perfo rmance of both the AGR and SRU and increase the life of the various solvents.

Process Parameters

– A superficial gas residence time of approximately 20 seconds was used based on Eastman Chemical’s experience [ 11 ]. 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 no rmally encountered [ 58 ] and was selected for this application.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

69 

### The bed density of 30 pounds per cubic foot ( lb/ft 3 

### ) was based on the Calgon Carb on Corporation HGR

- P sulfur

- impregnated pelletized activated carbon [ 59 ]. 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, resulting in two carbon beds per case.

Carbon Replacement Time

– Eastman Chemicals replaces its bed every 18 to 24 months [ 11 ]. However, b ed 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 assumpt ions, the mercury loading in the bed would build up to 0.6 4 wt%. Mercury capacity of sulfur

impregnated carbon can be as high as 20 wt% [ 60 ]. The mercury laden carbon is considered to be a hazardous waste, and the disposal cost estimate reflects this cat egorization.

3.1.9 Acid Gas Removal 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 AGR and sulfur recovery. The environmental target for these IGCC cases, 0.0128 lb sulfur dioxide per million British thermal units , is based on the EPRI CoalFleet values for bituminous coal [ 8 ] and 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 H 2 

### S, thereby resulting in stack gas emissions of less than 4 ppmv SO 2 

### . Because the low rank western coa ls have substantially less sulfur than eastern bituminous coal, the resulting sulfur emissions are significantly below the environmental target.

Sulfur Removal Hydrogen sulfide removal generally consists of absorption by a regenerable solvent. The most

co mmonly used technique 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 recirculate d to the top of the absorber, completing the cycle. Exhibit 3

- 5 is a simplified diagram of the AGR process [ 61 ].

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, methyldiethanol amine (MDEA), Selexol, aqueous di

- isoproponal (ADIP) amine and FLEXSORB [ 66 ]. These processes can be separated into three general types: chemical reagents, physical solvents, and hybrid solvents. A summary of these common AGR processes is shown in Exhibit 3

- 6 . The optimum technology choice for a particular IG CC plant depends on many factors such as gasifier operating pressure, availability of low/medium pressure steam, AGR requirements, and capital cost.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

70 

### Exhibit 3

- 5 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



### One process with potential in low

- sulfur coal applications is CrystaSulf®, which is a nonaqueous process that effectively treats gas with too much H 2 

### S to use a scavenger system but too little to use an amine/Claus approach. The niche market for CrystaSulf ® is reported as 0.2

- 30 long tons per day (LTPD) [ 62 ]. According to the CrystaSulf® literature, the total treating costs for H 2 

### S removal become greater than for amine systems above 30 LTPD [ 63 ]. CrystaSulf® was the proposed AGR technology for the cancelled Orlando Gasification CCPI Project. The estimated sulfur production rate for that project was 9.1 LTPD, which is well within the optimum range of the technology [ 64 ].

The sulfur production rate s for the Low Rank IGCC cases are on the order of 50 LTPD. Since these values are significantly greater than the upper range established by CrystaTech, CrystaSulf® was not further considered for this study. The different classes of AGR processes are described generally below.

Chemical Solvents Frequently u sed 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 press ure. Because the 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 broken, releasing the aci d gas and regenerating the solvent for reuse.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

71 

### Exhibit 3

- 6 Summary of Common AGR Processes

Solvent

Type Process H 2 

### S Selectivity Solvent

Circulation Heat Input Capital Cost Pressure Sensitive High Removal

Physical Rectisol, Selexol Good High, decreases with increased
pressure Low High Yes Yes, at high acid gas partial
pressures

Mixed Sulfinol, FLEXSORB Good but more complicated to achieve Intermediate Intermediate Intermediate Yes, but to a lesser extent than physical solvents only Yes, at optimum operating conditions

Chemical Amines (MEA, DEA, MDEA) Varies depending on amine selected, highest for

MDEA Low High Low No Yes, but with refrigerationCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

72 

### 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 selectively removing H 2 

### S in the presence of CO 2 

### , is resistant to degradation by organic sulfur
comp ounds, has a low tendency for corrosion, has a relatively low circulation rate, and consumes less energy. Commercially available are several MDEA

- based solvents that are formulated for high H 2 

### S selectivity.

Chemical reagents are used to remove the acid ga ses by a reversible chemical reaction of the acid gases with an aqueous solution of various alkanolamines or alkaline salts in water. Exhibit 3

- 7 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 circulati on 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 er pressu re 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 absorber. For some amines, a filter and a separate reclaiming section are needed to remove undesirable reaction byproducts.

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, g enerally 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 standard cubic feet (scf) acid gas per gallo n of solution circulated. Steam consumption can vary widely also: 0.7 to 1.5 pounds per gallon of liquid is typical, with 0.8 to 0.9 being a typical “good” value.

The major advantage of these systems is the ability to remove acid gas to low levels at low to moderate H 2 

### S partial pressures.

Exhibit 3

- 7 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 CarbideCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

73 

### 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 inv olve only the physical solution 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 (HP) and at or below ambient temperature while the regeneration step (dissolution) occurs by pressure letdown and indirect stripping with LP 0.45 MPa (65 psia) steam. It is generally accepted that physical solve nts become increasingly 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 temperature 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 for 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 heavy 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 p roduct and may lead to CO 2 

### contamination.

Several physical solvents that use anhydrous organic solvents have been commercialized. They include the Selexol process, which uses dimethyl ether of polyethylene glycol as a solvent; Rectisol, with methanol as the solvent; Purisol, which uses N

- methyl

- 2

- pyrrolidone (NMP) as a solvent; and the propylene

- carbonate process.

Exhibit 3

- 8 is a simplified flow diag ram for a physical reagent type AGR process [ 61 ]. Common physical solvent processes, along with their licensors, are listed in Exhibit 3

- 9

. 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 Ucar sol LE.

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 provides for selective removal of H 2 

### S.

Flexsorb PS is a mixture of a hindered a mine 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 of CO 2 

### and 4 ppmv of H 2 

### S, can be achieved.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

74 

### Exhibit 3

- 8 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 3

- 9 Common Physical Solvents Used in AGR Processes

Solvent Solvent/Process Trade Name Process Licensors Dimethyl ether of poly

ethylene glycol Selexol 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

Mixed chemical and physical solvents combine the features of both systems. The 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 absorber temperatures similar to those of the amine

- type chemical solvents and do not req uire refrigeration. They also retain some advantages of the lower steam requirements typical of the physical solvents. Common mixed chemical andCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

75 

### physical solvent processes, along with their licensors, are listed in Exhibit 3

- 10 . 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 purif ied gas specifications.

Exhibit 3

- 10 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 3

- 11 shows reported equilibrium solubility data for H 2 

### S and CO 2 

### in various representative solvents [ 61 ]. The solubility is expressed as scf of gas per gallon liquid per atmosphere gas partial pressure.

The figure illustrates the relative solubility of CO 2 

### and H 2 

### S in different solvents and the effects of temperature. More importantly, it s hows 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 solve nt temperatures.

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 betwe en the two acid gases to achieve selectivity. This is particularly true of the amine processes where the CO 2 

### and H 2 

### S absorption rates are very different.

CO 2 

### Capture

A two

- stage Selexol process is used for CO 2 

### capture cases in th is study as a common basis for

c omparison of these technologies and configurations. This decision was guided the design of current commercial chemical plants, mainly producing ammonia, that use the S elexol process to remove CO 2 

### in the process . A brief proc ess 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 firs t 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 CT

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

76 

### Exhibit 3

- 11 Equilibrium Solubility Data on H 2 

### S and CO 2 

### in Various Solvents

The amount of hydrogen remaining in the syngas stream is dependent on the Selexol process design conditions. In this study, hydrogen recovery is 99.4 percent. The minimal hydrogen slip to the CO 2 

### sequestration stream maximizes the overall plant efficiency. The Selexol plant cost estimates are based on a plant designed to recover this high percentage of hydrogen. The balance of the hydrogen i s co

- sequestered with the CO 2 

### , destroyed in the Claus plant burner, or recycled upstream of the AGR.

The CO 2 

### loaded solvent exits the CO 2 

### absorber and a portion is sent to the H 2 

### S absorber and the remainder is sent to a series of flash drums for regenerati on. Flash gas from the first flash drum is fed to a compressor and recycled to the CO 2 

### absorber. The CO 2 

### product stream is obtained from the remaining flash drums, and after flash regeneration the solvent is chilled and returned to the CO 2 

### absorber.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

77 

### The rich solvent exiting the 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 nitrogen 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

- strippe d 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 absorbed 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 p roper 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 t he product gas and finally chilled in the lean chiller before returning to the top of the CO 2 

### absorber.

AGR/Gasifier Pairings There are numerous commercial AGR processes that could meet the sulfur environmental target of this study. The most frequently u sed AGR systems (Selexol, Sulfinol, MDEA, and Rectisol) have all been used in various precombustion applications. To maintain comparability between designs of other volumes of this study and to mimic commercial offerings as much as is practical, the Sulfi nol

- M process was chosen for all cases except the CoP design, in order to be consistent with the non

- capture cases in th e NETL Bituminous Baseline Study [ 65 ]. Previous vendor performance estimates for Sulfinol systems showed high removals for H 2 

### S (99.77 percent ) and CO 2 

### (97.5 percent ). With the higher CO 2 

### and lower H 2 

### S concentrations in the raw gas for the lower rank coals, it is necessary for the AGR to slip a significant amount of CO 2 

### . The high slip is necessary to reduce the volume and increase the H 2 

### S concentration of the acid gas stream to the Claus plant for adequate performance and minim um capital cost. The literature indicates that Sulfinol systems with very high CO 2 

### slips have been designed , but e fforts to obtain an updated Sulfinol performance estimate from Shell have been unsuccessful to date.

The two

- stage Selexol process is used in all cases that require CO 2 

### capture. Selexol was also used for CO 2 

### capture cases in the NETL Bituminous Baseline Study [ 65 ]. According to the previously referenced SFA Pacific report, “For future IGCC with CO 2 

### removal for sequestration,
a two

- stage Selexol process presently appears to be the preferred AGR process

– as indicated by ongoing engineering studies at EPRI and various engineering firms with IGCC interests.” [ 66 ]

.

3.1.10 Sulfur Recovery/Tail Gas Cleanup Proces s Selection

The Claus process is the main process used for gas treating and sulfur recovery. Conventional 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, a tail gas treating unit (TGTU) must be added to the conventional Claus process to recover sulfur with over 99.8 percent efficiency

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

78 

### 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 temperatures.

A simplified process flow diagram of a typical three

- stage Claus plant is shown in Exhibit 3

- 12 [ 66 ]. 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 boiler that recovers this heat to generate HP steam usually follows the furnace. Sulfur is condensed in a condenser that follows the HP steam r ecovery section. LP steam is raised in the condenser. The tail gas from the first 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 o f gas preheat, a catalytic reactor, and a sulfur condenser. The liquid sulfur goes to the sulfur pit, while the tail gas proceeds to the incinerator or for further processing in a TGTU. Claus Plant Sulfur Recovery Efficiency The Claus reaction is equilibr ium 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 1093 to 1427°C (2000 to 2600°F), and as the temperature decreases, conversion increases dramatically.

Claus plant sulfur recovery efficiency depends on many factors:

**•** 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 the 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.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

79 

### Exhibit 3

- 12 Typical Three

- Stage Claus Sulfur Plant

Oxygen

- Blown Claus Large diluent streams in the feed to the Claus plant, such as nitrogen ( N 2 

### ) from combustion air, or a high CO 2 

### content in the feed gas, lead to higher cost of the Claus process 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

- blown 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 operating flexibility for sulfur plants where the feed gas is variable in flow and composition such as often found in refineries. The application of the pro cess has now been extended to grass roots installations, even for rich H 2 

### S feed streams, to provide operating 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 furnace, potentially reaching temperatures as high as 1593 to 1649°C (2900 to 3000°F) as the enrichment moves beyond 40 to 70 vol ume percent (vol%) O 2 

### in th e oxidant feed stream. Although oxygen enrichment has many benefits, its primary benefit for lean H 2 

### S feeds 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 cases.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

80 

### Tail Gas Treating In many refinery and other conventional Claus applications, tail gas treating involves the removal of the remaining sulfur compounds from gases exiting the SRU . Tail gas from a typical Claus process, whether a conventional Claus or one of the extended versions of the process, usually contains small

, but varying quantities of COS, C S 4 

### , H 2 

### S, SO 2 

### , and elemental sulfur vapors. In addition, there may be H 2 

### , CO, and CO 2 

### in the tail g as. 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 approach 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 i n 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 treated with a SCOT

- type process. All cases in this study use a catalytic hydrogenation step with tail gas recycle to just upstream of the AGR

. T he Shell Puertollano plant treats the tail gas in a similar manner, but the recycle endpoint is not specified [ 43 ].

Flare Stack

A self

- supporting, refractory

- lined, carbon steel (CS) flare stack is typically provided to combust and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in all IGCC cases a flare stack was provided for syngas dumping during startup, shutdown, etc. This flare stack eliminates the need for a separate Claus plant flare.

3.1.11 Slag and Ash Handling

The s lag handling system for slagging gasifiers, operatin g above the ash fusion temperature, is discussed in this section, specifically the Shell SCGP , Siemens SFG , and CoP gasification technologies. The non

- slagging TRIG TM gasifier operates below the ash fusion temperature and most of the entrained ash is captu red by a disengager and cyclone and recycled back to the gasifier to increase overall carbon conversion. Any remaining ash is removed by a high temperature high pressure barrier filter and continuously cooled and removed for possible reuse or disposal. O nce the ash is separated and processed, the material handling is similar to that described for slagging gasifiers below.

The slag handling system conveys, stores, and disposes of slag removed from the gasification process. Spent material drains from the g asifier bed into a water bath in the bottom of the 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 gasifier
pressur e boundary , generally through the use of lockhoppers

, to a series of dewatering bins.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

81 

### The general aspects of slag handling are the same for all slagging gasifier technologies. The slag is dewatered, the water is clarified and recycled and the dried slag i s transferred to a storage area for disposal. The specifics of slag handling vary among different gasification technologies regarding how the water is separated and the end uses of the water recycle streams.

In this study the slag bins were sized for a no minal holdup capacity of 72 hours of full

- load operation. At periodic intervals, a convoy of slag

- hauling trucks will enter the unloading station underneath the hopper and remove a quantity of slag for disposal. Approximately ten truckloads per day are r equired 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 would be landfilled at a specified c ost.

3.1.12 Power Island

Combustion Turbine

The GT 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 (IGVs) . 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 natura l gas and is also commercially offered for use with IGCC derived syngas, although only earlier versions of the turbine are currently operating on syngas. For the purposes of this study, it was assumed that the advanced F Class turbine will be commercially available to support a near term startup date on both conventional and high hydrogen content syngas representative of the cases with CO 2 

### capture. High H 2 

### fuel combustion issues like flame stability, flashback and NOx formation were assumed to be solved i n the time frame needed to support deployment. However, because these are FOAK applications, process contingencies were included in the cost estimates as described in Section 2.6 . Performance typical of an advanced F class turbine on natural gas at ISO conditions is presented in Exhibit 3

- 13

. 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 sectio n of the machine.

The modifications to the machine include 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 combusti on products, which are increased relative to those produced 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. Th e generator is a standard hydrogen

- cooled machine with static exciter.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

82 

### Exhibit 3

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

Advanced F Class Firing Temperature Cl ass, °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) 6,2 5 6 (5,9 3 4 )

Combustion Turbine Package scope of Supply The CT is typically supplied in several fully sh op fabricated modules, complete with mechanical, electrical and control systems as required for CT operation. Site CT installation involves module interconnection, and linking CT modules to the plant systems. CT Firing Temperature Control Issue for Low Calorific Value Fuel

A C T when fi red on low calorific value (LCV) 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 of turbine compo nents, 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 [ 67 ]. Uncontrolled syngas firing temperature could result in more than 50 per cent 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. 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 a mbient air temperatures by nitrogen injection. Combustion Turbine Syngas Fuel Requirements Typical fuel specifications and contaminant levels for successful CT operation are provided in reference [ 68 ] and presented for F Class machines in Exhibit 3

- 1 4 and Exhibit 3

- 15 . The vast majority of published CT performance information is spec ific to natural gas operation. Turbine performance using syngas requires vendor input as was obtained for th ese cases

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

83 

### Exhibit 3

- 14 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 [ 69 ]. 2. To ensure that the fuel gas supply to the CT 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 [ 68 ]. 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.

Normal Operation Inlet air is compressed in a single spool compressor to a pressure ratio of approximately 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 6 percent of the compressor air is extracted and integrated with the air supply of the ASU in non

- carbon capture cases. It may be technically possible to integrate the CT and ASU in CO 2 

### capture cases as well; however, in this study integration was not recommended by the CT vendor and is considered only for non

- carbon capture cases.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

84 

### Exh ibit 3

- 15 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

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 C T gas fuel system

A high level analysis on the alkalinity of the coals, particularly the high sodium lignite coal, indicated that if all the sodium and potassium in the coal was partitioned to the gas phase and passed through the gas cleanup, the fuel would not meet the specified limits for the CT . For plants firing high alkali coals, quench cooling is preferab le to syngas coolers to avoid any potential fouling problems. Sodium, in the form of sodium hydroxide, is converted mainly into sodium chloride or sodium carbonate when leaving the reactor, and can cause fouling on heat exchangers until the syngas is cool ed below the respective melting points of 800 o 

### C and 850 o 

### C. The highly soluble species, such as the alkali salts, are removed in any water scrubbing or knockout (KO) drums and should not cause any limitations on the CT

.

Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas dilution is used to limit NOx formation. As described in Section 3.1.4 nit rogen 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. 2

- 4.8 MJ/Nm 3 

### (1 15

- 1 32 Btu/scf). In the cases discussed in this report, nitrogen dilution alone was suff icient for all cases except S2B, which required humidification

. 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.

**•** Lim iting the water content reduces the need to de

- rate firing temperature, particularly in the high

- hydrogen (CO 2 

### capture) cases.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

85 

### D isadvantages to using nitrogen as the primary diluent include:

**•** S ignificant auxiliary power is still require d to further compress the large nitrogen flow from the ASU pressure to the GT pressure

.

**•** The low quality heat

, which is saved from avoiding the syngas humidification process

, does not provide significant benefit to the process in other applications.

**•** Nitrogen is not as efficient as water in limiting NOx 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

ex perts during peer review of Volume 1 of this series of report s

. 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 593°C (1,100°F) for non

- CO 2 

### capture cases and 566°C (1

, 050°F) for capture cases.

Gross turbine power, as measured prior to the generator terminals, is 232 MW at ISO conditions

. Turbine output is reduced at the elevated sites for this study because the c ompressor capacity on a mass flow basis is reduced because of the reduced ambient air density

. The CT generator is a standard hydrogen

- cooled machine with static exciter.

3.1.13 Steam Generation Island Heat Recovery Steam Generator The HRSG is a horizontal flow, drum

- type, multi

- pressure design that is matched to the characteristics of the CT exhaust when firing medium

- Btu syngas . 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) in all IGCC cases.

The HP drum produces steam at main steam pressure, while the IP drum produces process steam and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/2.9 MPa (1800/420 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 con densate and FW 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 natural circulation HRSG provides the m ost cost

- effective and reliable design.

The HRSG drums include moisture separators, internal baffles, and piping for FW /steam. All tubes, including economizers, superheaters, and headers and drums, are equipped with drains.

Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe work place.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

86 

### Superheater, boiler, and economizer sections are supported by shop

- assembled structural steel. Inlet and outlet duct is provided to route the gases from the CT 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.

Steam Turbine Generator and Auxiliaries

The steam turbine consists of an HP sect ion, 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 in a separate casing.

Main steam from the HRS G and gasifier island is combined in a header, and then passes through the stop valves and control valves and nominally enters the turbine at either 12.4 MPa/566°C (1800 psig/1050°F) for the non

- carbon capture cases, or 12.4 MPa/538°C (1800 psig/1000°F) fo r the carbon capture cases. The steam initially enters the turbine near the middle of the HP 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 section at 3

. 2 MPa/566°C (4 67 psi a /1050°F) for the non

- carbon capture cases or 3

. 2 MPa/538°C (4 67 psi a /1000°F) for the carbon capture cases. 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 sections, exhausting downward into the condenser.

Turbine bearings are lubricated by a CL , water

- cooled, pressurized oil system. The oil is contained in a reservoir located below the turb ine floor. During startup or unit trip an emergency oil pump 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 flows 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 shaf t sealing design arrangement connected to a LP steam 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 t o the condensate system.

The generator is a hydrogen

- cooled synchronous type, generating power at 24 kilovolt ( 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 removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is prevented from escaping at the rotor shafts by a CL oil seal system. The oil seal system consists of storage ta nk, pumps, filters, and pressure controls, all skid

- mounted.

The STG is controlled by a triple

- redundant, microprocessor

- based electro

- hydraulic control system. The system provides digital control of the unit in accordance with programmed controlCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

87 

### algorith ms, operator display interfacing, and datalink interfaces to the balance

- of

- plant distributed control system ( DCS ) , and incorporates on

- line repair capability. Condensate System The function of the condensate system is to pump condensate from both the air

- cooled and
water

- cooled condenser s to the deaerator, through the gland steam condenser and the low

temperature economizer section in the HRSG

. Feedwater System

The function of the FW system is to pump the various FW streams from the deaerator storage tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pumps (BFPs) 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. Minim um 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 c ontrol the recirculation flow.

The FW pumps are supplied with instrumentation to monitor and alarm on low oil pressure, or high bearing temperature. FW pump suction pressure and temperature are also monitored. In addition, the suction of each BFP is eq uipped with a startup strainer. Cooling Systems Exhaust steam from the steam turbine is split 50/50 to a surface condenser cooled with cooling water and to an air

- cooled condenser us ing ambient air and forced convection. A decision to use a parallel wet/d ry cooling system to reduce the plant water requirement was based primarily on the recently completed Xcel Energy Comanche 3 PC plant , which uses such a system . Parallel cooling has less of a performance impact on combined cycle systems than on PC systems ; and with the relatively low ambient temperature, the performance impact from the parallel cooling, as compared to wet cooling, is minor. The major impact of parallel cooling is a significant reduction in water requirement when compared to a wet cooling s ystem. This impact is included in the water balance presented later in this report.

With this cooling system and the specific ambient temperature, a condenser pressure of 0.005 MPa (0.698 psia) (condensing temperature of 32°C [90°F]) is used in the model as compared to 0.007 MPa ( 0.983 psia ) (condensing temperature of 38°C [101°F]) used in Volume 1 of this series

. The circulating water system is a closed

- cycle cooling water system that supplies cooling water to the surface condenser to condense one

- half of 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 CL process that utilizes a higher quality water to remove heat from compressor in tercoolers, 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 surface condenser and other applications is removed by a mechanical draft cooling tower.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

88 

### The system consists of two 50 percent capacity vertical circulating water pumps ( CWP ) , a mechanical draft evaporative cooling tower, and CS cement

- lined interconnecting piping. The pumps are single

- stage verti cal 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 water

- cooled surface condenser is a single

- pass, horizontal type 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 air

- cooled condenser utilizes ambient air and forced convection across tube bundles to condense the balance of the turbine exhaust steam.

Both condenser s are equipped with an air extraction system to evacuate the condenser steam space for removal of n on

- 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. 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 from groundwater. Booster pumps within the plant boundary provide the necessary pressure.

The fir e 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, hy drants, 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 WGS reactors in CO 2 

### capture cases, and for injection steam to the auxiliary boiler for control of NOx emissions, if requi red.

The cycle makeup system consists of two 100 percent trains , for redundancy , each with a full

capacity activated carbon filter, primary cation exchanger, primary anion exchanger, mixed bed exchanger, recycle pump, and regeneration equipment. The equip ment is skid

- mounted and includes a control panel and associated piping, valves, and instrumentation.

3.1.14 Accessory Electric Plant

The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, condui t and cable trays, and wire and cable. It also includes the main power transformer, all required foundations, and standby equipment.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

89 

### 3.1.15 Instrumentation and Control

An integrated plant

- wide distributed control system (DCS) is provided. The DCS is a redundant microprocessor

- based, functionally DCS . The control room houses an array of multiple video monitor and keyboard units. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The plant equipment and the DCS are de signed for automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are manually implemented, with operator selection of modular automation 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 segment of the DCS.

This critical controller system is used to control the gasif ication 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 critical controller utilizes a high speed redundant microprocessor to execut e calculations and dynamic controls. 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.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

90 

### 3.2 SHELL COAL G ASIFICATION PROCESS IGCC CASES

This section contains an evaluation of plant designs for Cases S 1 A, S 1 B , L 1 A, and L 1 B
, which are based on the SCGP

. The non

- capture (A) and CO 2 

### capture (B) cases are very similar in terms of process, equipment, scope and arrangement, except that CO 2 

### capture cases include SGS reactors, CO 2 

### absorption/regeneration and compression/transport systems.

Section 3.2.4 covers the results for the S 1 A and L 1 A non

- capture case using PRB and l ignite coal and Section 3.2.8 covers the S 1 B and L 1 B CO 2 

### - capture case s . The sections are organized analogously as follows:

**•** Process and System Description provides an overview of the specific technolog y’s operation.

**•** Block flow diagram (BFD) and stream table display results for major processes and
streams

**•** Performance Results provides the main modeling results, including the performance summary, environmental performance, carbon balance, sulfur balance, water balance, mass and energy balance diagrams

, and mass and energy balance tables.

**•** Equipmen t List provides an itemized list of major equipment with account codes that correspond to the cost accounts in the Cost Estimates section.

**•** Cost Estimates provides a summary of capital and operating costs.

Process and System Description, Performance Results , Equipment List and Cost Estimates are repeated for the CO 2 

### capture cases in Section 3.2.8 . If the information is identical to that presented for the non

- capture cases, a reference is made to the earlier section rather than repeating the information.

3.2.1 Gasifier Background

Development and Current Status

– Development of the Shell gasification process for partial oxidation of oil and gas began in the early 1950s. Mor e than 75 commercial Shell partial

oxidation plants have been built worldwide to convert a variety of hydrocarbon liquids and gases to carbon monoxide and hydrogen.

Shell Internationale Petroleum Maatschappij B.V. began work on coal gasification in 1972. The coal gasifier is significantly different than the oil and gas gasifiers developed earlier. A pressurized, entrained

- flow, slagging coal gasifier was built at Shell’s Amsterdam laboratories. This 5 tonnes/day (6 tpd ) process development unit has oper ated for approximately 12,000 hrs since 1976. A larger 150 tonnes/day (165 tpd ) pilot plant was built at Shell’s Hamburg refinery in Hamburg, Germany. This larger unit operated for approximately 6,000 hrs from 1978 to 1983, and successfully gasified over 27,2 00 tonnes (30,000 tons) of coal.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

91 

### Based on the experience it gained with the Hamburg unit, Shell built a demonstration unit at its oil refinery and chemical complex in Deer Park, Texas, near Houston. This new unit, commonly called SCGP

- 1 (for Shell Co al Gasification Plant

- 1), was designed to gasify bituminous coal at the rate of 2 30 tonnes/day (250 tpd ) and to gasify high

- moisture, high

- ash lignite at the rate of 36 0 tonnes/day (400 tpd ). The relatively small difference in size between the Hamburg and Deer Park units reflects design changes and improvements.

The Deer Park demonstration plant operated successfully after startup in July 1987. Before the end of the program in 1991, after 15,000 hours of operation, 18 different feedstocks were gasified at the plant, including domestic coals ranging from lignite to high

- sulfur bituminous, three widely traded foreign coals, and petroleum coke. The Deer Park unit produced superheated HP steam in the waste heat recovery boiler. The plant also had facilities for extensive environmental monitoring and for sidestream testing of several AGR processes, including Sulfinol

- D, Sulfinol

- M, highly loaded MDEA, and various wastewater treatment schemes.

In spring 1989, Shell announced that its technology had been selected for the large commercial

scale Demkolec B.V. IGCC plant at Buggenum, near Roermond, in The Netherlands. This plant generates 250 MW of IGCC electricity with a single Shell gasifier consuming 1,8 00 tonnes/day (2,000 tpd ) (dry basis) of coal. The plant was originally owned and operated by Samenwerkende Electriciteits

- Productiebedrijven NV (SEP), a consortium of Dutch utilities, and began operation in 1994. In 2000 the plant was purchased by Nuon. Shell was extensively involved in the design,
star tup, and initial operation of this plant. A key feature of this IGCC design is the use of extraction air from the CT air compressor to feed the oxygen plant.

Gasifier Capacity

– The large gasifier operating at the Buggenum plant in the Netherlands has a bituminous coal

- handling capacity o f 1,63 0 tonnes/day (1,800 tpd ) and produces dry gas at a rate of 158,5 80 normal cubic meter per hour ( Nm 3 

### /h r ) (5.6 million standard cubic feet per hour [ scf / h r ] ) with an energy content of about 1,79 0 million kilojoules per hour ( MMkJ/h r ) (1,700 million British thermal units per hour [ MMBtu/h r ] ) (HHV). This gasifier was sized to match the fuel gas requirements for the Siemens/Kraftwerk Union V

- 94.2 CT and could easily be scaled up to match advanced F Class turbine requir ements, requiring one gasifier for each C T

. Distinguishing Characteristics

– The SCGP uses a dry feed, entrained flow, slagging, single stage, up

- flow gasifier to produce syngas at HPs and temperatures. The gasifier uses a membrane wall design to control the reactor vessel wall temperature, increa sing operational flexibility. The dry feeding system helps achieve high carbon conversion and higher cold gas efficiencies compared to slurry fed systems. Multiple burner design allows a wider range of gasifier scalability. The syngas outlet is separated from the slag outlet allowing the application of higher ash coals proven with up to 30 percent ash content in the burner feed. The Shell process also uses a gas quench at the gasifier outlet to further mitigate problems associated with any remaining sticky fly ash/slag particulates.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

92 

### Entrained

- flow slagging gasifiers have fundamental environmental advantages over fluidized

bed and moving

- bed gasifiers without a slagging area. They produce no hydrocarbon liquids, and the only solid waste is an inert slag. The dry feed entrained

- flow gasifiers also have minor environmental advantages over the slurry feed entrained

- flow gasifiers. They produce a higher H 2 

### S/CO 2 

### ratio acid gas, which improves sulfur recovery and lessens some of the gray water processing and the fixed

- salts blowdown problems associated with slurry feeding.

The ability to feed dry solids minimizes the oxygen requirement and makes the Shell gasifier somewhat more efficient than entrained flow gasifiers employing slurry feed systems. The penalty paid for this increase in efficiency is a coal feed system that is more costly and operationall y more complex. The SCGP produces a high temperature syngas, with very little methane, and uses high temperature synthesis gas coolers (SGC) to recover a large amount of this heat. The high gasification temperatures improve operational reliability by red ucing the
amount of tars exiting the gasifier. The high operating temperature produced by all entrained

flow slagging processes can result in relatively high capital and maintenance costs, but can be partially avoided by adding different syngas cooling sc hemes such as a water quench, as in the CO 2 

### capture cases, where the reduction in heat recovery is mitigated by the shift steam requirement downstream. Shell's gasifier also employs a cooled membrane wall to help control gasifier temperature, which requir es fewer changeouts than an uncooled refractory. Buggenum operating experience has confirmed that one yearly maintenance turnaround is sufficient to achieve hi gh reliability plant operation.

Important Coal Characteristics

– One main consideration for coal

- fired in the Shell gasifier is the ash characteristics. The ash content has to be minimum 8 wt% on burner feed and can be adjusted using slag and ash recycle or fresh ash (as needed). The syngas outlet is separated from slag outlet allowing application of higher ash coals

- up to 30 percent ash cont ent in burner feed is proven. A wide variety of different coals have been tested on the Shell gasifier, including lignite. High

- ash fusion

- temperature coals may require flux addition for optimal gasifier
ope ration. The ash content, fusion temperature, and composition affect the required gasifier operating temperature level, oxygen requirements, slag and ash management. Solids handling requirements (coal, slag and ash) impact maintenance needs

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

93 

### 3.2.2 Key System Assumptions System assumptions for Cases S 1 A and L 1 A and S 1 B and L 1 B, SCGP IGCC using PRB and lignite coal with and without CO 2 

### capture, are compiled in Exhibit 3

- 16

. Exhibit 3

- 16 Case S 1 A/L 1 A and S 1 B /L 1 B Plant Study Configuration Matrix

Case S 1 A / L 1 A S 1 B / L 1 B Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0. 780 / 0. 736 0. 773 / 0. 736 Carbon Conversion, % 99.5 99.5 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

### (Btu/scf) 10
, 389 ( 279 ) / 9
, 384 ( 252 ) 10
, 476 ( 281 ) / 9
, 397 ( 252 )

Nominal Steam Cycle, MPa/°C/°C (psig/ **°** F/ **°** F) 12.4/566/566 (1800/1050/1050) 12.4/538/538 (1800/1000/1000) Condenser Pressure, mm Hg (in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine 2x Advanced F Class (Nominal 232 MW output each, reduced by elevation considerations) 2x Advanced F Class (Nominal 232 MW output each, reduced by elevation considerations) Gasifier Technology Shell (SCGP) Shell (SCGP)

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Subbituminous / Lignite Subbituminous / Lignite Coal Feed Moisture Content, % 6 / 12 6 / 12 COS Hydrolysis Yes Yes (Part of WGS)

Water Gas Shift No Yes

H 2 

### S Separation Sulfinol

- M Selexol (1 st 

### Stage) Sulfur Removal, % 99. 9 99. 7

CO 2 

### Separation None Selexol (2 nd 

### Stage)

CO 2 

### Removal, % N/A 90

Sulfur Recovery Claus Plant with Tail Gas Treatment / Elemental Sulfur Claus Plant with Tail Gas Treatment / Elemental Sulfur

Particulate Control Cyclone, Candle Filter, Scrubber, and AGR Absorber Cyclone, Candle Filter, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N 2 

### Dilution MNQC (LNB) and N 2 

### DilutionCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

94 

### Balance of Plant

– All Cases The balance of plant assumptions are common to all cases and are presented in Exhibit 3

- 17

.

Exhibit 3

- 17 Balance of Plant Assumptions
Cooling water system Recirculating Wet Cooling Tower Fuel and Other storage Coal 30 days Slag 30 days Sulfur 30 days Sorbent 30 days Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt

Motors between 250 hp and 5,000 hp 4,160 volt
Motors above 5,000 hp 13,800 volt Steam and CT Generators 24,000 volt Grid Interconnection Voltage 345 kV Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW and 50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup requirements. Makeup for potable, process, and de

- ionized (DI) water is drawn from municipal sources

.

Process Wastewater Water associated with gasification activity and storm water that contacts equipment surfaces is collected and treated for discharge through a permitted discharge.

Sanitary Waste Disposal Design includes a packaged domestic sewage
treatm ent plant with effluent discharged to the industrial wastewater treatment system. Sludge is hauled off site. Packaged plant was sized for 5.68 cubic meters per day (1,500 gallons per day)

Water Discharge Most of the process wastewater is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and discharged.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

95 

### 3.2.3 Sparing Philosophy

The sparing philosophy is provided below. Single trains are utilized throughout with exceptions where equipment capacity requires an additional train . There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

**•** Two ASU s (2 x 50%).

**•** Two trains of coal drying and dry feed systems (2 x 50%).

**•** Two trains of gasification, including gasi fier, SGC , cyclone, and barrier filter ( 2 x 50 %).

**•** Two trains of syngas clean

- up process (2 x 50%).

**•** Two t rains of Sulfinol

- M acid gas removal in non

- capture cases and two trains of two

stage Selexol in CO 2 

### capture cases (2 x 50%).

**•** One train of Claus

- bas ed sulfur recovery (1 x 100%).

**•** Two CT /HRSG tandems (2 x 50%).

**•** One steam turbine (1 x 100%).

3.2.4 SCGP IGCC Non

- Capture Case ( S1 A and L1 A ) Process Description

In this section the overall SCGP for Case S1 A and L1 A is described. The process does not change with fuel type so a single description is provided. The system description follows the BFD in Exhibit 3

- 18 and stream numb ers reference the same e xhibit. The tables in Exhibit 3

- 19 and Exhibit 3

- 20 provide process data for the numbered streams in the BFD

. Coal Preparation and Feed Systems Coal receiving and handling is common to all cases and was covered in Section 3.1.1 . The receiving and handling subsystem ends at the coal silo. The Shell process uses a dry feed system which is sensitive to the coal moisture content. Coal moisture consists of two parts, surface moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the surface moisture must be removed. The PRB coal used in this study contains 25.77 percent total moisture on an as

- received basis and the NDL contains 36.08 per cent moisture. It was assumed that the PRB coal must be dried to 6 percent moisture and the lignite to 12 percent to allow for smooth flow through the dry fee d system; however, fluidization tests would need to be completed on actual coal samples for actua l design and operation

. The raw coal is crushed in the coal mill then delivered to a surge hopper with an approximate 2

- hour capacity, which in turn delivers the coal to the coal pre

- heater. The WTA coal drying process includes a water

- heated, horizontal

, rotary

- kiln coal pre

- heater, a fluidized be d coal dryer and a water

- cooled, horizontal , rotary

- kiln coal cooler. The moisture driven from the coal in the fluid bed dryer passes through a baghouse for particulate removal and then is split into twoCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

96 

### streams . The smaller of the two streams is compressed and used as the fluidizing medium in the coal dryer. The bulk of the removed moisture is compressed and the high temperature vapor passes through internal coils in the dryer to provide the heat to drive off the coal moisture and then exits the dryer as liquid water. The warm water is used in the coal pre

- heater before being used as cooling tower makeup water . The vapor compressor consumes the vast majority of the WTA process auxiliary load.

The coal is draw n from the surge hoppers and fed through a pressurization lock hopper system to a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the gasifiers.

Gasifier

There are two Shell dry feed, pressurized, up flow , entrained, slagging gasifiers, operating at 4.24 MPa (615 psia) and processing a total of 5,908 tonne/day (6,513 tpd) of as

- re ceived coal in the PRB case and 8,274 tonne/day (9,121 tpd) in the lignite case. Coal reacts with oxygen in a reducing environment to produce principally hydrogen and carbon monoxide wit h little CO 2 

### formed

. Raw Gas Cooling/Particulate Removal High

- temperature heat recovery in each gasifier train is accomplished in three steps, including the gasifier membrane wall , which maintains a prot ective ash layer over the membrane wall and thus permits the reaction temperature of roughly 1400 ° C (2 ,5 5 0 °F). The product gas from the gasifier is cooled using a syngas recycle quench to lower the temperature below the ash melting point. Syngas then goe s through a raw gas cooler, which lowers the gas temperature to a minimum of 2 30 °C ( 450 °F), and contributes to the produc tion of HP ste am for use in the steam cycle.

The solids are removed as slag and as ash. Liquid slag is solidified in a water bath and removed via a lock hopper system. Ash carried over with the syngas is removed in a ceramic candle filter. The ash is removed similarly via a lock hopper system. Cyclones can be implemented in specific designs depending on plant size and coal operating c haracteristics. The syngas scrubber removes
any possibility of remaining PM passing the candle filter further downstream , by protecting against leakage from the filter seals or any undetected candle breakage that would allow large particulates into the sc rubber

. Syngas Scrubber/Sour Water Stripper The raw synthesis gas exiting the ceramic particulate filter enters the scrubber for removal of chlorides and any remaining particulate s . The quench scrubber washes the syngas in a counter

current flow in two pa cked beds. The quench scrubber removes essentially all traces of entrained particles, principally unconverted carbon, slag, and metals. The bottoms from the scrubber are sent to the slag removal and handling system for processing.

The sour water stripper removes ammonia, sulfur , and other impurities from the waste stream of the scrubber. The sour gas stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from SGC s. Sour water from the drum flows to the sour str ipper, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from theCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

97 

### liquid and sent to the SRU

. Part of the stripper water is sent to wastewater treatment , avoiding accumulation of salts, to be reused in the scrubber sect ion. COS Hydrolysis, Mercury Removal and AGR

H 2 

### S and COS are at significant concentrations, requiring removal for the power plant to achieve the low design level of SO 2 

### emissions. H 2 

### S is removed in an AGR process; however, because COS is not readily remov ed, it is first catalytically converted to H 2 

### S in a COS hydrolysis unit.

Following the water scrubber, the gas is fed to the COS hydrolysis reactor at above 177 **°** C ( 350 **°** F). The COS in the sour gas is hydrolyzed with steam over a catalyst bed to H 2 

### S, which is more easily removed by the AGR solvent. Before the raw fuel gas can be t reated in the AGR
process , it must be cooled to about 35 **°** C ( 95 **°** F). During this cooling through a series of heat exchangers, part of the water vapor condenses. This water, which c ontains some NH 3 

### , is sent to the sour water stripper. The coole d syngas then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.8 ).

The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a mixture of amines and a physical solvent. The solvent consists of an aqueous amine and sulfolane. Sulfinol

- D uses DIPA , while Sulfinol

- M uses MDEA. The mix ed solvents allow for better solvent loadings at high acid gas partial pressures and higher solubility of COS and organic sulfur compounds than straight aqueous amines. Sulfinol

- M was selected for the Shell

non

- CO 2 

### capture applications.

The sour syngas i s fed directly into an HP contactor. The HP contactor is an absorption column in which the H 2 

### S, COS, CO 2 

### , and small amounts of H 2 

### and CO are removed from the gas by the Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with w ater in the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with lean solvent to remove H 2 

### S and COS. The overhead from the LP contactor is flashed in the LP KO drum. This gas can be used as a utility fuel gas, consisting primarily of H 2 

### and CO, at 0.8 MPa (118 psia) and 38 **°** C (10 1 **°** F). The solvent from the bottom of the LP contactor is returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before entering the stripper. The stripper strips the H 2 

### S, COS, a nd CO 2 

### from the solvent at LP with heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is recovered as the flash gas from the stripper accumulator. The lean solvent from the bottom of the stripper is cooled in the lean/rich solvent ex changer and the lean solvent cooler. Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP contactor.

The Sulfinol process removes about 15 percent of the CO 2 

### along with the H 2 

### S and COS. The acid gas is fed to the SRU

. T he residual CO 2 

### passes through the SRU, the hydrogenation reactor and is recycled to the AGR . However, the costs of the sulfur recovery/tail gas cleanup are higher than for a sulfur removal process producing an acid gas stream with a higher sulfur
concent ration.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

98 

### Claus Unit

The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus p lant produces molten sulfur by converting approximately one third of the H 2 

### S in the feed to SO 2 

### , then reacting the H 2 

### S and SO 2 

### to sulfur and water. The comb ination of Claus technology and tail gas recycle result s in an overall sulfur recovery exceeding 99 percent , producing 43 tonne/day (47 tpd) of sulfur in t he PRB case and 52 tonne/day (57 tpd) in the lignite case

. Utilizing oxygen instead of air in the C laus plant reduces the overall cost of the sulfur recovery plant. Feed for each case consists of acid gas from both the acid gas cleanup unit and a vent stream from the sour water stripper in the gasifier section.

In the furnace waste heat boiler steam is generated. This steam is used to satisfy all Claus process preheating and reheating requirements

, as well as to provide some steam to the medium

pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header.

Powe r Block Clean synga s exiting the Sulfinol absorber is reheated , dilu ted with nitrogen from the ASU , and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and a portion of t he air requirement for the ASU . The exhaust gas exits the CT around 5 93 °C (1, 10 0 °F) and enters the HRSG where additional heat is recovered until the flue gas e xits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam raised in the HRSG is used to power an ad vanced, commercially available steam turbine using a nominal 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) steam cycle. Air Separation Unit The ASU is designed to produce approximately 3,653 tonne/day (4,026 tpd) in the PRB case and 4,150 tonne/day (4,574 tpd) in the lignite case of 95 mole percent (mol%) O 2 

### for use in the gasifier and SRU . The plant is designed with two production trains. The air compressor is powered by an electric motor. N itrogen is also recovered, compressed, and used as diluent in the CT combustor or as a coal transport fluid. Air extraction is taken from the CT compressor to reduce the size of the main air compressor

. Balance of Plant Balance of plant items were covered in Sections 3.1.12
, 3.1.13
, 3.1.14
, and 3.1.15

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

99 

### Exhibit 3

- 18 Case S 1 A and L1A Process Flow DiagramCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

100 

### Exhibit 3

- 19 Case S 1 A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction

Ar 0.0093 0.0093 0.0291 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0104 0.0104 0.0104
CH 4 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 0.0000
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5994 0.5994 0.5994
CO 2 0.0003 0.0003 0.0102 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0335 0.0335 0.0335
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 0.0005 0.0005 0.0005
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 0.2593 0.2593 0.2593

H 2 O 0.0064 0.0064 0.1937 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.0309 0.0309 0.0309

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0030 0.0030

N 2 0.7759 0.7759 0.5163 0.0178 0.9920 0.9920 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0607 0.0607 0.0607

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 0.0022 0.0022 0.0022
O 2 0.2081 0.2081 0.2507 0.9504 0.0054 0.0054 0.9504 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 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 20,415 2,522 736 46 16,606 866 4,684 0 0 2,874 0 0 16,119 7,423 16,119 V-L Flowrate (kg/hr) 589,886 72,887 20,300 1,466 465,982 24,300 150,725 0 0 51,774 0 0 348,649 160,563 348,649 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 246,170 0 194,396 20,772 0 0 0

Temperature (°C) 6 411 21 32 196 195 32

--- 6 33 71 1,454 1,454 245 232 Pressure (MPa, abs) 0.09 1.43 0.11 0.86 2.65 5.62 0.86

--- 0.09 0.55 0.09 4.24 4.24 4.24 3.96 Enthalpy (kJ/kg) A 15.26 434.33 40.10 26.67 202.63 199.69 26.67

--- --- 140.14

--- --- 2,292.13 400.31 382.35 Density (kg/m 3 ) 1.1 7.2 1.6 11.0 18.9 39.8 11.0

--- --- 985.3

--- --- 6.3 21.0 20.1 V-L Molecular Weight 28.895 28.895 27.587 32.181 28.061 28.061 32.181

--- --- 18.015

--- --- 21.630 21.630 21.630

V-L Flowrate (lb mol /hr) 45,007 5,561 1,622 100 36,610 1,909 10,326 0 0 6,336 0 0 35,537 16,366 35,536 V-L Flowrate (lb/hr) 1,300,475 160,689 44,754 3,232 1,027,315 53,571 332,292 0 0 114,143 0 0 768,639 353,981 768,639 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 542,713 0 428,570 45,794 0 0 0

Temperature (°F) 42 771 70 90 385 383 90

--- 42 92 160 2,650 2,650 473 450 Pressure (psia) 13.0 207.6 16.4 125.0 385.0 815.0 125.0

--- 13.0 80.1 12.7 614.7 614.7 615.0 574.7 Enthalpy (Btu/lb) A 6.6 186.7 17.2 11.5 87.1 85.9 11.5

--- --- 60.2

--- --- 985.4 172.1 164.4 Density (lb/ft 3 ) 0.070 0.452 0.097 0.687 1.183 2.485 0.687

--- --- 61.510

--- --- 0.396 1.311 1.257 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

101 

### Exhibit 3

- 19 Case S1A Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 V-L Mole Fraction

Ar 0.0098 0.0108 0.0091 0.0107 0.0008 0.0000 0.0063 0.0109 0.0109 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000
CH 4 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 0.0000 0.0000
CO 0.5639 0.6178 0.0027 0.6103 0.0299 0.0000 0.0649 0.6182 0.6182 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.0319 0.0350 0.4801 0.0406 0.4222 0.0000 0.2729 0.0354 0.0354 0.0003 0.0832 0.0832 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000
H 2 0.2440 0.2673 0.1276 0.2656 0.0142 0.0000 0.0298 0.2690 0.2690 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0879 0.0030 0.0323 0.0030 0.0224 0.0000 0.3822 0.0028 0.0028 0.0064 0.0396 0.0396 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0033 0.0036 0.0041 0.0036 0.2650 0.0000 0.0014 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0571 0.0625 0.3441 0.0661 0.2455 0.0000 0.2410 0.0637 0.0637 0.7759 0.7583 0.7583 0.0000 0.0000 0.0000 0.0000

NH 3 0.0021 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 0.0000
O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1098 0.1098 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 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 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 17,135 15,640 200 15,834 213 0 285 15,621 15,621 100,352 123,127 123,127 34,784 18,472 18,472 37,460 V-L Flowrate (kg/hr) 366,944 340,056 6,431 346,380 7,634 0 7,966 338,746 338,746 2,899,687 3,631,528 3,631,528 626,641 332,787 332,787 674,848 Solids Flowrate (kg/hr) 0 0 0 0 0 1,788 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 177 35 49 37 40 176 138 42 196 6 589 132 561 32 32 33 Pressure (MPa, abs) 3.79 3.69 0.32 3.62 0.4 0.370 0.370 3.597 3.563 0.090 0.093 0.090 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 426.53 45.20 93.62 44.60 54.4

--- 780.053 55.279 271.387 15.260 694.591 195.610 3,502.487 2,306.994 2,306.994 140.562 Density (kg/m 3 ) 21.6 31.3 3.9 30.8 5.8 5,284.2 3.0 29.7 19.6 1.1 0.4 0.8 35.1 0.04 0.04 995.0 V-L Molecular Weight 21.415 21.742 32.185 21.876 36

--- 27.918 21.686 21.686 28.895 29.494 29.494 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 37,775 34,481 440 34,908 470 0 629 34,438 34,438 221,239 271,449 271,449 76,685 40,725 40,725 82,585 V-L Flowrate (lb/hr) 808,973 749,695 14,177 763,637 16,829 0 17,561 746,808 746,808 6,392,716 8,006,150 8,006,150 1,381,506 733,670 733,670 1,487,785 Solids Flowrate (lb/hr) 0 0 0 0 0 3,943 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 351 95 120 98 104 348 280 108 385 42 1,092 270 1,042 90 90 92 Pressure (psia) 549.7 534.7 46.5 524.7 60.0 53.6 53.6 521.7 516.7 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 183.4 19.4 40.3 19.2 23.4

--- 335.4 23.8 116.7 6.6 298.6 84.1 1,505.8 991.8 991.8 60.4 Density (lb/ft 3 ) 1.345 1.952 0.242 1.920 0.362 329.882 0.190 1.853 1.221 0.070 0.024 0.049 2.192 0.002 0.002 62.115Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

102 

### Exhibit 3

- 20 Case L 1 A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction

Ar 0.0093 0.0093 0.0293 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0100 0.0100 0.0100
CH 4 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 0.0000
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5272 0.5272 0.5272
CO 2 0.0003 0.0003 0.0103 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0643 0.0643 0.0643
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 0.0004 0.0004 0.0004
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 0.2477 0.2477 0.2477

H 2 O 0.0062 0.0062 0.1878 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.0801 0.0801 0.0801

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0032 0.0032

N 2 0.7761 0.7761 0.5200 0.0178 0.9920 0.9920 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0658 0.0658 0.0658

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 0.0014 0.0014 0.0014
O 2 0.2082 0.2082 0.2525 0.9504 0.0054 0.0054 0.9504 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 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 20,814 5,237 830 38 18,733 1,116 5,335 0 0 5,237 0 0 19,089 6,742 19,089 V-L Flowrate (kg/hr) 601,490 151,347 22,953 1,225 525,667 31,304 171,673 0 0 94,342 0 0 418,721 147,880 418,721 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 344,772 0 250,430 34,686 0 0 0

Temperature (°C) 4 408 21 32 196 195 32

--- 4 32 71 1,371 1,371 245 232 Pressure (MPa, abs) 0.10 1.52 0.11 0.86 2.65 5.62 0.86

--- 0.10 0.34 0.09 4.24 4.24 4.24 3.96 Enthalpy (kJ/kg) A 13.75 431.19 40.37 26.67 202.62 199.68 26.67

--- --- 135.07

--- --- 2,286.86 499.79 482.15 Density (kg/m 3 ) 1.2 7.7 1.5 11.0 18.9 39.8 11.0

--- --- 986.5

--- --- 6.8 21.4 20.5 V-L Molecular Weight 28.898 28.898 27.657 32.181 28.061 28.061 32.181

--- --- 18.015

--- --- 21.935 21.935 21.935

V-L Flowrate (lb mol /hr) 45,888 11,546 1,830 84 41,299 2,459 11,761 0 0 11,545 0 0 42,084 14,863 42,084 V-L Flowrate (lb/hr) 1,326,060 333,663 50,603 2,700 1,158,897 69,013 378,475 0 0 207,989 0 0 923,122 326,020 923,122 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 760,093 0 552,104 76,470 0 0 0

Temperature (°F) 40 767 70 90 385 383 90

--- 40 90 160 2,500 2,500 472 450 Pressure (psia) 13.8 220.4 16.4 125.0 385.0 815.0 125.0

--- 13.8 50.0 13.5 614.7 614.7 615.0 574.7 Enthalpy (Btu/lb) A 5.9 185.4 17.4 11.5 87.1 85.8 11.5

--- --- 58.1

--- --- 983.2 214.9 207.3 Density (lb/ft 3 ) 0.074 0.482 0.097 0.687 1.183 2.485 0.687

--- --- 61.584

--- --- 0.422 1.335 1.280 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

103 

### Exhibit 3

- 20 Case L1A Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 V-L Mole Fraction

Ar 0.0097 0.0109 0.0045 0.0108 0.0005 0.0000 0.0038 0.0110 0.0110 0.0093 0.0090 0.0090 0.0000 0.0000 0.0000 0.0000
CH 4 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 0.0000 0.0000
CO 0.5068 0.5728 0.0060 0.5620 0.0181 0.0000 0.0774 0.5734 0.5734 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.0621 0.0702 0.6341 0.0813 0.5955 0.0000 0.4628 0.0706 0.0706 0.0003 0.0868 0.0868 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000
H 2 0.2381 0.2691 0.0982 0.2659 0.0093 0.0000 0.0161 0.2713 0.2713 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.1153 0.0016 0.0323 0.0016 0.0079 0.0000 0.2502 0.0015 0.0015 0.0062 0.0415 0.0415 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0034 0.0038 0.0041 0.0038 0.1869 0.0000 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0633 0.0715 0.2208 0.0745 0.1817 0.0000 0.1864 0.0722 0.0722 0.7761 0.7565 0.7565 0.0000 0.0000 0.0000 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 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 0.2082 0.1062 0.1062 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0018 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 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 19,855 17,568 352 17,910 367 0 417 17,543 17,543 106,961 130,591 130,591 39,860 19,306 19,306 39,167 V-L Flowrate (kg/hr) 432,511 391,337 12,445 403,595 14,075 0 13,601 389,520 389,520 3,090,914 3,854,769 3,854,769 718,096 347,804 347,804 705,610 Solids Flowrate (kg/hr) 0 0 0 0 0 2,157 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 177 35 49 35 40 176 138 42 196 4 589 132 561 32 32 33 Pressure (MPa, abs) 3.79 3.69 0.32 3.62 0.4 0.370 0.370 3.597 3.563 0.095 0.099 0.095 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 477.51 40.71 86.59 39.57 42.3

--- 490.944 51.058 265.393 13.748 697.962 198.353 3,502.136 2,321.555 2,321.555 140.358 Density (kg/m 3 ) 22.0 32.1 4.3 32.0 6.2 5,283.3 3.6 30.5 20.0 1.2 0.4 0.8 35.1 0.04 0.04 995.0 V-L Molecular Weight 21.784 22.276 35.359 22.535 38

--- 32.625 22.204 22.204 28.898 29.518 29.518 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 43,772 38,731 776 39,484 809 0 919 38,675 38,675 235,808 287,903 287,903 87,877 42,563 42,563 86,349 V-L Flowrate (lb/hr) 953,523 862,751 27,437 889,774 31,030 0 29,986 858,744 858,744 6,814,298 8,498,311 8,498,311 1,583,131 766,778 766,778 1,555,604 Solids Flowrate (lb/hr) 0 0 0 0 0 4,756 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 350 95 120 94 104 349 280 108 385 40 1,092 270 1,042 90 90 92 Pressure (psia) 549.7 534.7 46.5 524.7 60.0 53.6 53.6 521.7 516.7 13.8 14.3 13.8 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 205.3 17.5 37.2 17.0 18.2

--- 211.1 22.0 114.1 5.9 300.1 85.3 1,505.6 998.1 998.1 60.3 Density (lb/ft 3 ) 1.374 2.006 0.266 1.996 0.386 329.828 0.222 1.902 1.251 0.074 0.025 0.052 2.192 0.002 0.002 62.116Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

104 

### 3.2.5 Case S 1 A and L 1 A Performance Results

The non

- capture SCGP IGCC plant using PRB coal at the Montana site (elevation 3,400 ft) produces a net output of 5 7 3 megawatt electric ( MWe ) at a net plant efficiency of 4 2

. 0 percent (HHV basis). The same plant configuration using lignite coal at the North Dakota site ( elevation 1,900 ft) produces a net output of 617 MWe at a net plant efficiency of 4 1

. 8 percent (HHV ba sis). Overall performance for the pl ant is summarized in Exhibit 3

- 21
, which includes auxiliary power requirements. The ASU accounts for approximate ly 7 4 percent of the total auxiliary load, distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. C oal handling and drying account for approximately 1 0 percent of the auxiliary load. The cooling water system, including the CWP s and cooling tower fan, and the air

- cooled condenser account for about 5 percent of the auxiliary load. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

105 

### Exhibit 3

- 21 Case S 1 A and L 1 A Plant Performance Summary
POWER SUMMARY (Gross Power at Generator Terminals, kWe) S 1 A L 1 A

Gas Turbine Power 423,900 449,400 Steam Turbine Power 272,800 303,200 TOTAL POWER, kWe 696,700 752,600 AUXILIARY LOAD SUMMARY, kWe Coal Handling 500 600 Coal Milling 2,530 3,550 Slag Handling 540 900 WTA Coal Dryer Compressor 8,680 12,120 WTA Coal Dryer Auxiliaries 570 800 Air Separation Unit Auxiliaries 1,000 1,000 Air Separation Unit Main Air Compressor 52,530 52,190 Oxygen Compressor 8,250 9,400 Nitrogen Compressors 30,220 34,460 Boiler Feedwater Pumps 3,890 4,450 Condensate Pump 220 230 Syngas Recycle Compressor 840 760 Circulating Water Pump 1,970 2,230 Ground Water Pumps 160 170 Cooling Tower Fans 1,280 1,370 Air Cooled Condenser Fans 3,230 3,210 Scrubber Pumps 10 90 Acid Gas Removal 260 450 Gas Turbine Auxiliaries 1,000 1,000 Steam Turbine Auxiliaries 100 100 Claus Plant/TGTU Auxiliaries 250 250 Claus Plant TG Recycle Compressor 540 920 Miscellaneous Balance of Plant 1 

### 3,000 3,000 Transformer Losses 2,450 2,650 TOTAL AUXILIARIES, kWe 124,020 135 , 900 NET POWER, kWe 572,680 616,700 Net Plant Efficiency, % (HHV) 42.0% 41.8% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,563 (8,116) 8,605 (8,156) CONDENSER COOLING DUTY GJ/hr (10 6 

### Btu/hr) 1,445 (1,370) 1,519 (1,440) CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 246,170 (542,713) 344,772 (760,093) Thermal Input, kWt 1,362,134 1,474,011 Raw Water Withdrawal , m 3 

### /min (gpm) 6.8 (1,792) 7

. 1 (1, 879 ) Raw Water Consumption, m 3 

### /min (gpm) 5.1 (1,336) 5

. 2 (1, 362 )

1 Includes plant control systems, lighting, HVAC and miscellaneous low voltage loadsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

10 6 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for the non

- capture cases is presented in Exhibit 3

- 22

.

Exhibit 3

- 22 Cases S 1 A and L 1 A Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

S 1 A L 1 A S 1 A L 1 A S 1 A L 1 A

SO 2 

### 0.001 (0.002) 0.001 (0.002) 33 (37) 37 (40) 0.007 ( 0 .0 15 ) 0.007 ( 0 .0 15 )

NO X 

### 0.027 (0.062) 0.027 (0.063) 912 (1,005) 1,001 (1,103) 0.187 ( 0 .412) 0.190 ( 0 .418)

Particulates 0.003 (0.0071) 0.003 (0.0071) 105 (116) 114 (125) 0.021 ( 0 .047) 0.022 ( 0 .047)

Hg 1.51E

- 7 (3.51E

- 7) 2.41E

- 7 (5.60E

- 7) 0.005 (0.006) 0.009 (0.010) 1.06E

- 6 (2.34E

- 6) 1.70E

- 6 (3.74E

- 6)

CO 2 

### gross 91.9 (213.8) 94.0 (218.6) 3,158,977 (3,482,176) 3,494,523 (3,852,052) 647 (1,426) 663 (1,461)

CO 2 

### net 787 (1,735) 809 (1,783)

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the Sulfinol

- M AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 5 ppmv in both cases . This results in a concentration i n the flue gas of less than 1 ppmv. The H 2 

### S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated and recycled upstream of the AGR to capture most of the remaining su lfur. Because the environmental target was set based on higher sulfur bituminous coal, the resulting SO 2 

### emissions with lower sulfur western coals are substantially less than the environmental target.

NO x emissions are limited to 15 parts per million volume, dr y ( ppmvd ) (as NO 2 

### @ 15 percent O 2 

### ) by the use of low NOx burners and nitrogen dilution of the fuel gas . Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and destroyed in the Claus plant burner. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter 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.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

107 

### CO 2 

### emissions represent the uncontrolled discharge from the process.

The carbon balance for the two cases is shown in Exhibit 3

- 23

. The carbon input to the plant consists of carbon in the air in a ddition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components thr oughout. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

### in the stack gas and ASU vent gas.

Exhibit 3

- 23 Case S 1 A and L 1 A Carbon Balance
Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)
S 1 A L 1 A S 1 A L 1 A

Coal 123,253 (271,726) 136,370 (300,645) Slag 616 (1,359) 682 (1,503)

Air (CO 2 

### ) 476 (1,049) 503 (1,110) Stack Gas 123,022 (271,217) 136,089 (300,025)

ASU Vent 90 (199) 103 (226)

Total 123,729 (272,775) 136,874 (301,755) Total 123,729 (272,775) 136,874 (301,755)

Exhibit 3

- 24 shows the sulfur balance for the non

- capture case . Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted i n the stack gas. Sulfur in the slag is considered to be negligible

.

Exhibit 3

- 24 Cases S 1 A and L 1 A Sulfur Balance
Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)
S1A L1A S1A L1A

Coal 1,791 (3,948) 2,160 (4,761) Elemental Sulfur 1,788 (3,943) 2,157 (4,756)

Stack Gas 2 (5) 3 (6)

Total 1,791 (3,948) 2,160 (4,761) Total 1,791 (3,948) 2,160 (4,761)

Exhibit 3

- 25 shows the overall water balance for the plant. 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 wit hin the process, primarily as coal moisture from the drying process and syngas condensate, and that water is re

- used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Some water is discharge d from the process to a permitted outfall. The difference between the withdrawal and discharge is the consumption.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

108 

### Exhibit 3

- 25 Case S1 A and L1 A 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 m3/min (gpm)

S1A L1A S1A L1A S1A L1A S1A L1A S1A L1A
Slag Handling 0.45 (119) 0.75 (199) 0.4 (112) 0.7 (179) 0.03 (7) 0.08 (20) 0 (0) 0 (0) 0.03 (7) 0.08 (20)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0.00 (1.1) 0.01 (1.8) 0.00 (

- 1.1)

- 0.01 (

- 1.8)

Condenser Makeup 0.15 (41) 0.17 (44) 0 (0) 0 (0) 0.15 (41) 0.17 (44) 0 (0) 0 (0) 0.15 (41) 0.17 (44)

BFW Makeup 0.15 (41) 0.17 (44) 0.15 (41) 0.17 (44)

Cooling Tower 7.66 (2,024) 8.68 (2,293) 1.1 (280) 1.8 (478) 6.60 (1,744) 6.87 (1,815) 1.72 (455) 1.95 (516) 4.88 (1,289) 4.92 (1,300) Water from Coal Drying 0.9 (228) 1.6 (416)

- 0.86 (

- 228)

- 1.57 (

- 416)

BFW Blowdown 0.2 (41) 0.2 (44)

- 0.15 (

- 41)

- 0.17 (

- 44)

SWS Blowdown 0.0 (11) 0.1 (18)

- 0.04 (

- 11)

- 0.07 (

- 18)

Total 8.3 (2,184) 9.6 (2,536) 1. 5 (392) 2. 5 ( 657) 6.8 (1,792) 7.1 (1,879) 1.73 (456) 1.96 (518) 5.06 (1,336) 5.16 (1,362)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

109 

### Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 26 and Exhibit 3

- 27 :

**•** Coal gasification and ASU

**•** Syngas cleanup

**•** Combined cycle power generation

An overall plant energy balance is provided in tabular form in Exhibit 3

- 28 for the two cases. The power out is the combined CT and steam turbine power after generator losses.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

110 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

111 

### Exhibit 3

- 26 Case S1A Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

112 

### Exhibit 3

- 26 Case S1A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

113 

### Exhibit 3

- 26 Case S1A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

114 

### Exhibit 3

- 27 Case L1A Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

115 

### Exhibit 3

- 27 Case L1A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

116 

### Exhibit 3

- 27 Case L1A Heat and Mass Balance (Cont inued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

117 

### Exhibit 3

- 28 Cases S 1 A and L 1 A Energy Balance

HHV Sensible + Latent Power Total S1A L1A S1A L1A S1A L1A S1A L1A Heat In GJ/hr (MMBtu/hr)

Coal 4,904 (4,648) 5,306 (5,030) 2.5 (2.4) 3.1 (2.9) 0 (0) 0 (0) 4,906 (4,650) 5,310 (5,032)
ASU Air 0 (0) 0 (0) 9.0 (8.5) 8.3 (7.8) 0 (0) 0 (0) 9 (9) 8 (8)
GT Air 0 (0) 0 (0) 44.2 (41.9) 42.5 (40.3) 0 (0) 0 (0) 44 (42) 42 (40)
R aw Water Makeup 0 (0) 0 (0) 9.4 (8.9) 7.9 (7.5) 0 (0) 0 (0) 9 (9) 8 (8) Auxiliary Power 0 (0) 0 (0) 0 ( 0 ) 0 ( 0 ) 446 (423) 489 (464) 446 (423) 489 (464)

T otals 4,904 (4,648) 5, 306 ( 5,030 ) 65.2 (61.8) 61.7 (58.5) 446 (423) 489 (464) 5,415 (5,133) 5,857 (5,552) Heat Out GJ/hr (MMBtu/hr) ASU Intercoolers 0 (0) 0 (0) 190 (181) 198 (188) 0 (0) 0 (0) 190 (181) 198 (188)
ASU Vent 0 (0) 0 (0) 0.8 (0.8) 0.9 (0.9) 0 (0) 0 (0) 1 (1) 1 (1) Slag 20 (19) 22 (21) 36.0 (34.1) 55.5 (52.6) 0 (0) 0 (0) 56 (53) 78 (74)
Sulfur 17 (16) 20 (19) 0.2 (0.2) 0.2 (0.2) 0 (0) 0 (0) 17 (16) 20 (19) Cooling Tower Blowdown 0 (0) 0 (0) 9.6 (9.1) 10.6 (10.0) 0 (0) 0 (0) 10 (9) 11 (10)

HRSG Flue Gas 0 (0) 0 (0) 710 (673) 765 (725) 0 (0) 0 (0) 710 (673) 765 (725)

Condenser 0 (0) 0 (0) 1,44 5 (1,369) 1,520 (1,441) 0 (0) 0 (0) 1,445 (1,369) 1,520 (1,441) Auxiliary Cooling Load 0 (0) 0 (0) 25 (24) 86 (81) 0 (0) 0 (0) 25 (24) 86 (81)
P rocess Losses 0 (0) 0 (0) 453 ( 429 ) 470 (445) 0 (0) 0 (0) 453 (429) 470 (445)

Power 0 (0) 0 (0) 0 ( 0 ) 0 ( 0 ) 2,508 (2,377) 2,709 (2,568) 2,508 (2,377) 2,709 (2,568)

Totals 37 (35) 4 2 (40 ) 2,870 (2,721) 3,106 (2,944) 2,508 (2,377) 2,709 (2,568) 5,415 (5,133) 5,857 (5,552)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

118 

### 3.2.6 Case S 1 A and L 1 A Equipment Lists

Major equipment items for the SCGP with no CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.2.7 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

119 

### ACCOUNT 1 COAL HANDLING Equ ipment No. Description Type S 1 A Design Conditions L 1 A Design Condition Operating Qty Spares

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 54 tonne (60 ton) 73 tonne (80 ton) 2 1
9 Feeder Vibratory 200 tonne/hr (220 tph) 281 tonne/hr (310 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 408 tonne/hr (450 tph) 572 tonne/hr (630 tph) 1 0
11 Crusher Tower N/A N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 200 tonne (220 ton) 281 tonne (310 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 408 tonne/hr (450 tph) 572 tonne/hr (630 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A N/A 1 0
17 Conveyor No. 5 Belt w/ tripper 408 tonne/hr (450 tph) 572 tonne/hr (630 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 907 tonne (1,000 ton) 1,270 tonne (1,400 ton) 3 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

120 

### ACCOUNT 2 COAL PREPARATION AND FEED Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Feeder Vibratory 91 tonne/hr (100 tph) 127 tonne/hr (140 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 272 tonne/hr (300 tph) 381 tonne/hr (420 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 544 tonne (600 ton) 762 tonne (840 ton) 1 0

4 Weigh Feeder Belt 136 tonne/hr (150 tph) 191 tonne/hr (210 tph) 2 0
5 Pulverizer Rotary 136 tonne/hr (150 tph) 191 tonne/hr (210 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 272 tonne (300 ton) 381 tonne (420 ton) 2 0

7 Coal Preheater Water Heated Horizontal Rotary Kiln Coal feed: 272 tonne/hr (300 tph) Heat duty: 30.1 GJ/hr (28.6 MMBtu/hr) Coal feed: 381 tonne/hr (420 tph) Heat duty: 47 GJ/hr (44 MMBtu/hr) 1 0

8 Coal Dryer Fluidized Bed with Internal Coils Coal feed: 136 tonne/hr (150 tph) Heat duty: 75.8 GJ/hr (71.8 MMBtu/hr) Bed diameter: 11.9 m (39 ft) Coal feed: 191 tonne/hr (210 tph) Heat duty: 136 GJ/hr (129 MMBtu/hr) Bed diameter: 14.0 m (46 ft) 2 0

9 Steam Compressor Reciprocating, Multi

Stage 567 m 3 

### /min (20,040 scfm) Suction

- 0.09 MPa (13 psia) Discharge

- 0.72 MPa (105 psia) 1034 m 3 

### /min (36,510 scfm) Suction

- 0.10 MPa (13.8 psia) Discharge

- 0.52 MPa (75 psia) 2 0

10 Dryer Exhaust Filter Hot Baghouse Steam

- 28,486 kg/hr (62,800 lb/hr) Temperature

- 107°C (225°F) Steam

- 51,891 kg/hr (114,400 lb/hr) Temperature

- 107°C (225°F) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

121 

### Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

11 Dry Coal Cooler Water Cooled Horizontal Rotary Kiln 214 tonne/hr (236 tph) Heat duty

- 12 GJ/hr (12 MMBtu/hr) 275 tonne/hr (304 tph) Heat duty

- 17 GJ/hr (16 MMBtu/hr) 1 0

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 594,310 liters (157,000 gal) 639,735 liters (169,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,208 lpm @ 91 m H 2 

### O (1,640 gpm @ 300 ft H 2 

### O) 6,511 lpm @ 91 m H 2 

### O (1,720 gpm @ 300 ft H 2 

### O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 412,769 kg/hr (910,000 lb/hr) 441,345 kg/hr (973,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 1,022 lpm @ 27 m H 2 

### O (270 gpm @ 90 ft H 2 

### O) 568 lpm @ 27 m H 2 

### O (150 gpm @ 90 ft H 2 

### O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 6,095 lpm @ 1,890 m H 2 

### O (1,610 gpm @ 6,200 ft H 2 

### O) HP water: 7,003 lpm @ 1,890 m H 2 

### O (1,850 gpm @ 6,200 ft H 2 

### O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,514 lpm @ 223 m H 2 

### O (400 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) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

122 

### Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

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 Cycle Cooling Heat Exchangers Plate and frame 133 GJ/hr (126 MMBtu/hr) each 171 GJ/hr (162 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 47,696 lpm @ 21 m H 2 

### O (12,600 gpm @ 70 ft H 2 

### O) 61,324 lpm @ 21 m H 2 

### O (16,200 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 1,893 lpm @ 18 m H 2 

### O (500 gpm @ 60 ft H 2 

### O) 2,006 lpm @ 18 m H 2 

### O (530 gpm @ 60 ft H 2 

### O) 2 1

15 Ground Water Pumps Stainless steel, single suction 3,823 lpm @ 268 m H 2 

### O (1,010 gpm @ 880 ft H 2 

### O) 4,013 lpm @ 268 m H 2 

### O (1,060 gpm @ 880 ft H 2 

### O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 416 lpm @ 49 m H 2 

### O (110 gpm @ 160 ft H 2 

### O) 606 lpm @ 49 m H 2 

### O (160 gpm @ 160 ft H 2 

### O) 2 1

17 Filtered Water Tank Vertical, cylindrical 196,841 liter (52,000 gal) 283,906 liter (75,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 151 lpm (40 gpm) 189 lpm (50 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

123 

### ACCOUNT 4 GASIFIER, ASU , AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Gasifier Pressurized dry

feed, entrained bed 3,266 tonne/day, 4.2 MPa (3,600 tpd, 61 5 psia) 4,536 tonne/day, 4.2 MPa (5,000 tpd, 61 5 psia) 2 0

2 Synthesis Gas Cooler Convective spiral

wound tube boiler 279,866 kg/hr (617,000 lb/hr) Heat duty: 510 GJ/hr (484 MMBtu/hr) 311,618 kg/hr (687,000 lb/hr) Heat duty: 577 GJ/hr (547 MMBtu/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 279,866 kg/hr (617,000 lb/hr) Design efficiency 90% 311,618 kg/hr (687,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning ceramic filters ceramic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical up flow 191,870 kg/hr (423,000 lb/hr) 230,425 kg/hr (508,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 187,334 kg/hr (413,000 lb/hr) 215,910 kg/hr (476,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 186,880 kg/hr, 35°C, 3.6 MPa (412,000 lb/hr, 95°F, 525 psia) 215,456 kg/hr, 35°C, 3.6 MPa (475,000 lb/hr, 95°F, 525 psia) 2 0

8 Synthesis Gas Reheater Shell and tube 186,426 kg/hr (411,000 lb/hr) 214,096 kg/hr (472,000 lb/hr) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

124 

### Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

9 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 191,870 kg/hr (423,000 lb/hr) syngas 230,425 kg/hr (508,000 lb/hr) syngas 2 0

10 ASU Main Air Compressor Centrifugal, multi

stage 4,446 m 3 

### /min @ 1.3 MPa (157,000 scfm

@ 190 psia) 4,531 m 3 

### /min @ 1.3 MPa (160,000 scfm

@ 190 psia) 2 0

11 Cold Box Vendor design 1,996 tonne/day (2,200 tpd) of 95% purity oxygen 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2 0

12 Oxygen Compressor Centrifugal, multi

stage 1,019 m 3 

### /min (36,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 1,161 m 3 

### /min (41,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 2 0

13 Primary Nitrogen Compressor Centrifugal, multi

stage 3,341 m 3 

### /min (118,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,794 m 3 

### /min (134,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

125 

### Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

14 Secondary Nitrogen Compressor Centrifugal, single

stage 453 m 3 

### /min (16,000 scfm) Suction

- 2.7 MPa (390 psia) Discharge

- 5.7 MPa (820 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 2.7 MPa (390 psia) Discharge

- 5.7 MPa (820 psia) 2 0

15 Transport Nitrogen Boost Compressor Centrifugal, single

stage 187 m 3 

### /min (6,600 scfm) Suction

- 2.7 MPa (389 psia) Discharge

- 5.6 MPa (815 psia) 244 m 3 

### /min (8,600 scfm) Suction

- 2.7 MPa (389 psia) Discharge

- 5.6 MPa (815 psia) 2 0

16 Extraction Air Heat Exchanger Gas

- to

- gas, vendor design 39,916 kg/hr, 411°C, 1.4 MPa (88,000 lb/hr, 771°F, 208 psia) 83,461 kg/hr, 408°C, 1.5 MPa (184,000 lb/hr, 767°F, 220 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

126 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed 186,880 kg/hr (412,000 lb/hr)

35°C (95°F) 3.7 MPa (535 psia) 215,456 kg/hr (475,000 lb/hr)

35°C (95°F) 3.7 MPa (535 psia) 2 0

2 Sulfur Plant Claus type 47 tonne/day (52 tpd) 57 tonne/day (63 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 201,849 kg/hr (445,000 lb/hr) 177°C (350°F) 3.9 MPa (560 psia) 237,682 kg/hr (524,000 lb/hr) 177°C (350°F) 3.9 MPa (560 psia) 2 0

4 Acid Gas Removal Plant Sulfinol 190,509 kg/hr (420,000 lb/hr)

37°C (98°F) 3.6 MPa (525 psia) 221,807 kg/hr (489,000 lb/hr)

35°C (94°F) 3.6 MPa (525 psia) 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 7,966 kg/hr (17,561 lb/hr) 232°C (450°F) 0.3 MPa (48.6 psia) 13,601 kg/hr (29,986 lb/hr) 232°C (450°F) 0.3 MPa (48.6 psia) 1 0

6 Tail Gas Recycle Compressor Centrifugal 6
, 344 kg/hr (13986 lb/hr) 12
, 257 kg/hr (27023 lb/hr) 1 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No. Description Type S1 A Design Condition L1 A Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 210 MW 225 MW 2 0

2 Gas Turbine Generator TEWAC 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 250 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

127 

### ACCOUNT 7 HRSG, DUCTING AND STACK Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.6 m (2 0 ft) diameter 76 m (250 ft) high x 8.6 m (2 0 ft) diameter 2 0

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 344,652 kg/hr, 12.4 MPa/561°C

(759,828 lb/hr, 1,800 psig/1,042°F) Reheat steam

- 337,721 kg/hr, 3.1 MPa/561°C

(744,547 lb/hr, 452 psig/1,042°F) Main steam

- 394,953 kg/hr, 12.4 MPa/561°C

(870,722 lb/hr, 1,800 psig/1,042°F) Reheat steam

- 387,959 kg/hr, 3.1 MPa/561°C

(855,304 lb/hr, 452 psig/1,042°F) 2 0

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Steam Turbine Commercially available 287 MW 12.4 MPa/561°C/561°C (1

, 800 psig/ 1,042°F/1,042°F) 319 MW 12.4 MPa/561°C/561°C (1

, 800 psig/ 1,042°F/1,042°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 350 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided waterbox including vacuum
pumps 791 GJ/hr (750 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 833 GJ/hr (790 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Wa ter temperature rise 11°C (20°F) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

128 

### Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

4 Air

- cooled Condenser --- 791 GJ/hr (750 MMBtu/hr), Condensing temperature

32°C (90°F), Ambient temperature 6°C (42°F) 833 GJ/hr (790 MMBtu/hr), Condensing temperature

32°C (90°F), Ambient temperature 4°C (40°F) 1 0

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Circulating Water Pumps Vertical, wet pit 196,841 lpm @ 30 m (52,000 gpm @ 100 ft) 223,339 lpm @ 30 m (59,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) wet bulb / 9°C (48°F) CWT / 20°C (68°F) HWT / 1

, 097 GJ/hr (1

, 040 MMBtu/hr) heat duty 2°C (36°F) wet bulb / 8°C (47°F) CWT / 19°C (67°F) HWT / 1

, 245 GJ/hr (1

, 180 MMBtu/hr) heat duty 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

129 

### ACCOUNT 10 SLAG /ASH RECOVERY AND HANDLING

Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 219,554 liters (58,000 gal) 363,400 liters (96,000 gal) 2 0
2 Slag Crusher Roll 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0
3 Slag Depressurizer Proprietary 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 132,489 liters (35,000 gal) 219,554 liters (58,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 60,567 liters (16,000 gal) 98,421 liters (26,000 gal) 2

6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 19 tonne/hr (21 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 185,485 liters (49,000 gal) 310,404 liters (82,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 76 lpm @ 14 m H 2 

### O (20 gpm @ 46 ft H 2 

### O) 2 2

11 Grey Water Storage Tank Field erected 60,567 liters (16,000 gal) 98,421 liters (26,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H 2 

### O (60 gpm @ 1,420 ft H 2 

### O) 341 lpm @ 433 m H 2 

### O (90 gpm @ 1,420 ft H 2 

### O) 2 2

13 Slag Storage Bin Vertical, field erected 816 tonne (900 tons) 1,361 tonne (1,500 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 163 tonne/hr (180 tph) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

130 

### ACCOUNT 11 ACCES S ORY ELECTRIC PLANT

Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 230 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 250 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, 350 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 55 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 60 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 24 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 28 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

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 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

131 

### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type S1A Design Conditions L1A Design Condition Operating Qty Spares

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 0

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

132 

### 3.2.7 Case S 1 A an d L 1 A Cost Estimating

Costs Results The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 29 shows the TPC summary organized by cost account for the PRB coal case (S1A) and Exhibit 3

- 33 shows the same information for the lignite coal case (L1A). A more detailed breakdown of the capital costs is shown in Exhibit 3

- 30 for S1A and Exhibit 3

- 34 for L1A. Exhibit 3

- 31 and Exhibit 3

- 35 show the addition of owner’s costs to determine the TOC , used to calculate COE. Exhibit 3

- 32 shows the initial and annual O&M costs for Case S1A and Exhibit 3

- 36 shows the same information for Case L1A.

The estimated T O C of the SCGP with no CO 2 

### capture using PRB coal is $ 3
, 05 6 /kW and using lignite coal is $ 3
, 094 /kW. Process contingency represents abo ut 2 percent , project contingency represents 1 1 percent , and owner’s costs represent 18 percent of TOC for the two cases. The C OE is 83.2 mills/kWh in the PRB case and 8 3

. 5 mills/kWh in the lignite case.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

133 

### Exhibit 3

- 29 Case S1 A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S1A - Shell IGCC w/o CO2 Plant Size: 572.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $15,272 $2,838 $11,843 $0 $0 $29,953 $2,719 $0 $6,534 $39,206 $68

2 COAL & SORBENT PREP & FEED $114,839 $9,569 $19,594 $0 $0 $144,001 $12,493 $0 $31,299 $187,793 $328

3 FEEDWATER & MISC. BOP SYSTEMS $7,631 $6,907 $6,754 $0 $0 $21,292 $1,996 $0 $5,177 $28,466 $50

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $177,839 $0 $76,848 $0 $0 $254,687 $22,725 $35,634 $47,895 $360,940 $630 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $149,195 $0 w/equip. $0 $0 $149,195 $14,461 $0 $16,366 $180,022 $314 4.4-4.9 Other Gasification Equipment $15,912 $9,909 $11,552 $0 $0 $37,373 $3,560 $0 $8,957 $49,890 $87 SUBTOTAL 4 $342,946 $9,909 $88,401 $0 $0 $441,256 $40,746 $35,634 $73,217 $590,853 $1,032

5A GAS CLEANUP & PIPING $44,251 $2,654 $40,865 $0 $0 $87,771 $8,483 $81 $19,398 $115,732 $202

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $202 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $207

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,735 $0 $4,655 $0 $0 $37,390 $3,555 $0 $4,094 $45,039 $79 7.2-7.9 SCR System, Ductwork and Stack $3,449 $2,459 $3,253 $0 $0 $9,162 $850 $0 $1,630 $11,642 $20 SUBTOTAL 7 $36,185 $2,459 $7,908 $0 $0 $46,552 $4,405 $0 $5,725 $56,681 $99

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,830 $0 $4,943 $0 $0 $33,773 $3,241 $0 $3,701 $40,715 $71 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $35,457 $992 $12,090 $0 $0 $48,540 $4,701 $0 $10,904 $64,145 $112 SUBTOTAL 8 $64,287 $992 $17,034 $0 $0 $82,313 $7,941 $0 $14,605 $104,860 $183

9 COOLING WATER SYSTEM $5,692 $5,857 $4,875 $0 $0 $16,424 $1,525 $0 $3,692 $21,640 $38

10 ASH/SPENT SORBENT HANDLING SYS $18,383 $1,419 $9,122 $0 $0 $28,924 $2,775 $0 $3,463 $35,163 $61

11 ACCESSORY ELECTRIC PLANT $27,278 $10,483 $20,837 $0 $0 $58,598 $5,040 $0 $12,002 $75,640 $132

12 INSTRUMENTATION & CONTROL $10,120 $1,862 $6,520 $0 $0 $18,501 $1,677 $925 $3,516 $24,619 $43

13 IMPROVEMENTS TO SITE $3,238 $1,909 $7,990 $0 $0 $13,137 $1,297 $0 $4,330 $18,764 $33

14 BUILDINGS & STRUCTURES $0 $6,373 $7,345 $0 $0 $13,718 $1,249 $0 $2,453 $17,420 $30

TOTAL COST $775,873 $64,038 $256,248 $0 $0 $1,096,159 $101,228 $41,241 $196,504 $1,435,132 $2,506 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

134 

### Exhibit 3

- 30 Case S1 A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S1A - Shell IGCC w/o CO2 Plant Size: 572.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,010 $0 $1,960 $0 $0 $5,970 $535 $0 $1,301 $7,806 $14 1.2 Coal Stackout & Reclaim $5,182 $0 $1,256 $0 $0 $6,439 $564 $0 $1,401 $8,404 $15 1.3 Coal Conveyors & Yd Crush $4,818 $0 $1,243 $0 $0 $6,061 $532 $0 $1,319 $7,912 $14
1.4 Other Coal Handling $1,261 $0 $288 $0 $0 $1,548 $135 $0 $337 $2,020 $4 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $2,838 $7,096 $0 $0 $9,934 $952 $0 $2,177 $13,064 $23 SUBTOTAL 1. $15,272 $2,838 $11,843 $0 $0 $29,953 $2,719 $0 $6,534 $39,206 $68
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $46,233 $2,777 $6,737 $0 $0 $55,747 $4,810 $0 $12,111 $72,669 $127 2.2 Prepared Coal Storage & Feed $1,988 $476 $312 $0 $0 $2,775 $237 $0 $602 $3,615 $6 2.3 Dry Coal Injection System $65,414 $759 $6,075 $0 $0 $72,248 $6,223 $0 $15,694 $94,165 $164 2.4 Misc.Coal Prep & Feed $1,204 $876 $2,627 $0 $0 $4,708 $433 $0 $1,028 $6,169 $11 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $4,681 $3,843 $0 $0 $8,523 $789 $0 $1,863 $11,175 $20 SUBTOTAL 2. $114,839 $9,569 $19,594 $0 $0 $144,001 $12,493 $0 $31,299 $187,793 $328 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,854 $4,900 $2,587 $0 $0 $10,341 $958 $0 $2,260 $13,559 $24 3.2 Water Makeup & Pretreating $311 $32 $174 $0 $0 $517 $49 $0 $170 $736 $1 3.3 Other Feedwater Subsystems $1,561 $528 $475 $0 $0 $2,564 $230 $0 $559 $3,353 $6 3.4 Service Water Systems $178 $366 $1,272 $0 $0 $1,816 $177 $0 $598 $2,591 $5 3.5 Other Boiler Plant Systems $955 $370 $917 $0 $0 $2,242 $213 $0 $491 $2,945 $5 3.6 FO Supply Sys & Nat Gas $303 $571 $533 $0 $0 $1,407 $136 $0 $308 $1,851 $3 3.7 Waste Treatment Equipment $435 $0 $265 $0 $0 $700 $68 $0 $230 $998 $2 3.8 Misc. Power Plant Equipment $1,036 $139 $532 $0 $0 $1,706 $165 $0 $561 $2,432 $4 SUBTOTAL 3. $7,631 $6,907 $6,754 $0 $0 $21,292 $1,996 $0 $5,177 $28,466 $50
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $177,839 $0 $76,848 $0 $0 $254,687 $22,725 $35,634 $47,895 $360,940 $630 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $149,195 $0 w/equip. $0 $0 $149,195 $14,461 $0 $16,366 $180,022 $314
4.4 LT Heat Recovery & FG Saturation $15,912 $0 $6,049 $0 $0 $21,961 $2,143 $0 $4,821 $28,925 $51 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $921 $375 $0 $0 $1,296 $124 $0 $284 $1,704 $3 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $8,988 $5,129 $0 $0 $14,117 $1,292 $0 $3,852 $19,261 $34 SUBTOTAL 4. $342,946 $9,909 $88,401 $0 $0 $441,256 $40,746 $35,634 $73,217 $590,853 $1,032 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

135 

### Exhibit 3

- 30 Case S1A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S1A - Shell IGCC w/o CO2 Plant Size: 572.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Sulfinol System $34,171 $0 $28,995 $0 $0 $63,165 $6,109 $0 $13,855 $83,129 $145 5A.2 Elemental Sulfur Plant $4,852 $967 $6,260 $0 $0 $12,078 $1,173 $0 $2,650 $15,902 $28 5A.3 Mercury Removal $920 $0 $700 $0 $0 $1,620 $156 $81 $371 $2,229 $4 5A.4 COS Hydrolysis $2,912 $0 $3,802 $0 $0 $6,714 $653 $0 $1,473 $8,840 $15 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,397 $235 $132 $0 $0 $1,765 $167 $0 $386 $2,318 $4 5A.7 Fuel Gas Piping $0 $722 $505 $0 $0 $1,227 $114 $0 $268 $1,609 $3 5A.9 HGCU Foundations $0 $731 $471 $0 $0 $1,202 $110 $0 $394 $1,706 $3 SUBTOTAL 5A. $44,251 $2,654 $40,865 $0 $0 $87,771 $8,483 $81 $19,398 $115,732 $202 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $202 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $207
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,735 $0 $4,655 $0 $0 $37,390 $3,555 $0 $4,094 $45,039 $79 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,768 $1,294 $0 $0 $3,062 $269 $0 $666 $3,997 $7
7.4 Stack $3,449 $0 $1,296 $0 $0 $4,745 $455 $0 $520 $5,720 $10 7.9 HRSG,Duct & Stack Foundations $0 $691 $664 $0 $0 $1,355 $126 $0 $444 $1,925 $3 SUBTOTAL 7. $36,185 $2,459 $7,908 $0 $0 $46,552 $4,405 $0 $5,725 $56,681 $99 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,830 $0 $4,943 $0 $0 $33,773 $3,241 $0 $3,701 $40,715 $71 8.2 Turbine Plant Auxiliaries $200 $0 $459 $0 $0 $659 $64 $0 $72 $795 $1 8.3a Condenser & Auxiliaries $2,973 $0 $950 $0 $0 $3,923 $375 $0 $430 $4,728 $8 8.3b Air Cooled Condenser $27,249 $0 $5,463 $0 $0 $32,711 $3,271 $0 $7,197 $43,179 $75 8.4 Steam Piping $5,035 $0 $3,542 $0 $0 $8,577 $737 $0 $2,329 $11,643 $20 8.9 TG Foundations $0 $992 $1,677 $0 $0 $2,669 $253 $0 $877 $3,799 $7 SUBTOTAL 8. $64,287 $992 $17,034 $0 $0 $82,313 $7,941 $0 $14,605 $104,860 $183
9 COOLING WATER SYSTEM 9.1 Cooling Towers $3,928 $0 $714 $0 $0 $4,642 $442 $0 $763 $5,847 $10 9.2 Circulating Water Pumps $1,021 $0 $57 $0 $0 $1,079 $91 $0 $175 $1,345 $2 9.3 Circ.Water System Auxiliaries $93 $0 $13 $0 $0 $106 $10 $0 $17 $134 $0 9.4 Circ.Water Piping $0 $3,885 $1,007 $0 $0 $4,893 $442 $0 $1,067 $6,402 $11 9.5 Make-up Water System $191 $0 $274 $0 $0 $465 $45 $0 $102 $612 $1 9.6 Component Cooling Water Sys $459 $549 $390 $0 $0 $1,398 $131 $0 $306 $1,834 $3 9.9 Circ.Water System Foundations $0 $1,423 $2,419 $0 $0 $3,841 $364 $0 $1,262 $5,467 $10 SUBTOTAL 9. $5,692 $5,857 $4,875 $0 $0 $16,424 $1,525 $0 $3,692 $21,640 $38 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

136 

### Exhibit 3

- 30 Case S1A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S1A - Shell IGCC w/o CO2 Plant Size: 572.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $15,999 $0 $7,890 $0 $0 $23,888 $2,295 $0 $2,618 $28,802 $50 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $540 $0 $588 $0 $0 $1,128 $109 $0 $186 $1,423 $2 10.7 Ash Transport & Feed Equipment $725 $0 $175 $0 $0 $900 $84 $0 $148 $1,131 $2 10.8 Misc. Ash Handling Equipment $1,119 $1,372 $410 $0 $0 $2,901 $276 $0 $476 $3,653 $6 10.9 Ash/Spent Sorbent Foundation $0 $48 $60 $0 $0 $108 $10 $0 $35 $153 $0 SUBTOTAL 10. $18,383 $1,419 $9,122 $0 $0 $28,924 $2,775 $0 $3,463 $35,163 $61
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $919 $0 $909 $0 $0 $1,828 $175 $0 $200 $2,203 $4 11.2 Station Service Equipment $3,872 $0 $349 $0 $0 $4,221 $389 $0 $461 $5,071 $9 11.3 Switchgear & Motor Control $7,159 $0 $1,302 $0 $0 $8,460 $785 $0 $1,387 $10,632 $19
11.4 Conduit & Cable Tray $0 $3,325 $10,970 $0 $0 $14,296 $1,383 $0 $3,920 $19,598 $34 11.5 Wire & Cable $0 $6,354 $4,175 $0 $0 $10,528 $765 $0 $2,823 $14,117 $25 11.6 Protective Equipment $0 $653 $2,375 $0 $0 $3,028 $296 $0 $499 $3,822 $7
11.7 Standby Equipment $228 $0 $222 $0 $0 $450 $43 $0 $74 $567 $1 11.8 Main Power Transformers $15,101 $0 $139 $0 $0 $15,239 $1,153 $0 $2,459 $18,851 $33 11.9 Electrical Foundations $0 $151 $396 $0 $0 $546 $52 $0 $180 $778 $1 SUBTOTAL 11. $27,278 $10,483 $20,837 $0 $0 $58,598 $5,040 $0 $12,002 $75,640 $132
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $999 $0 $667 $0 $0 $1,666 $158 $83 $286 $2,193 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $230 $0 $147 $0 $0 $377 $36 $19 $86 $518 $1 12.7 Computer & Accessories $5,329 $0 $171 $0 $0 $5,500 $505 $275 $628 $6,907 $12 12.8 Instrument Wiring & Tubing $0 $1,862 $3,806 $0 $0 $5,667 $481 $283 $1,608 $8,039 $14 12.9 Other I & C Equipment $3,562 $0 $1,730 $0 $0 $5,292 $498 $265 $908 $6,963 $12 SUBTOTAL 12. $10,120 $1,862 $6,520 $0 $0 $18,501 $1,677 $925 $3,516 $24,619 $43 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $102 $2,171 $0 $0 $2,273 $226 $0 $750 $3,248 $6 13.2 Site Improvements $0 $1,807 $2,401 $0 $0 $4,208 $415 $0 $1,387 $6,011 $10 13.3 Site Facilities $3,238 $0 $3,417 $0 $0 $6,655 $656 $0 $2,193 $9,505 $17 SUBTOTAL 13. $3,238 $1,909 $7,990 $0 $0 $13,137 $1,297 $0 $4,330 $18,764 $33
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,427 $3,458 $0 $0 $5,885 $541 $0 $964 $7,390 $13 14.3 Administration Building $0 $828 $601 $0 $0 $1,429 $127 $0 $233 $1,790 $3
14.4 Circulation Water Pumphouse $0 $163 $86 $0 $0 $249 $22 $0 $41 $311 $1 14.5 Water Treatment Buildings $0 $260 $254 $0 $0 $513 $46 $0 $84 $644 $1 14.6 Machine Shop $0 $424 $290 $0 $0 $714 $63 $0 $117 $894 $2
14.7 Warehouse $0 $684 $442 $0 $0 $1,126 $100 $0 $184 $1,410 $2 14.8 Other Buildings & Structures $0 $409 $318 $0 $0 $727 $65 $0 $158 $950 $2 14.9 Waste Treating Building & Str. $0 $914 $1,746 $0 $0 $2,660 $248 $0 $582 $3,489 $6 SUBTOTAL 14. $0 $6,373 $7,345 $0 $0 $13,718 $1,249 $0 $2,453 $17,420 $30

TOTAL COST $775,873 $64,038 $256,248 $0 $0 $1,096,159 $101,228 $41,241 $196,504 $1,435,132 $2,506 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

137 

### Exhibit 3

- 31 Case S1A Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $13,195 $23 1 Month Variable O&M $3,363 $6 25% of 1 Months Fuel Cost at 100% CF $754 $1 2% of TPC $28,703 $50 Total $46,014 $80

Inventory Capital 60 day supply of consumables at 100% CF $6,151 $11 0.5% of TPC (spare parts) $7,176 $13 Total $13,326 $23

Initial Cost for Catalyst and Chemicals $799 $1 Land $900 $2 Other Owner's Costs $215,270 $376 Financing Costs $38,749 $68

Total Owner's Costs $315,058 $550 Total Overnight Cost (TOC) $1,750,189 $3,056 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $1,995,216 $3,484Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

138 

### Exhibit 3

- 32 Case S1 A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case S1A - Shell IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8115 MWe-net: 573 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $10.335 Maintenance Labor Cost $15,192,490 $26.529 Administrative & Support Labor $5,277,851 $9.216 Property Taxes and Insurance $28,702,632 $50.120 TOTAL FIXED OPERATING COSTS $55,091,886 $96.200 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $28,677,180 $0.00715

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 1,290 1.08 $0 $407,294 $0.00010

Chemicals

MU & WT Chem.(lbs) 0 7,683 0.17 $0 $388,246 $0.00010 Carbon (Mercury Removal) (lb) 64,000 88 1.05 $67,211 $26,884 $0.00001 COS Catalyst (m3) 257 0.18 2,397.36 $616,357 $123,271 $0.00003 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Sulfinol Solution (gal) 11,507 8 10.05 $115,630 $22,945 $0.00001 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.72 131.27 $0 $27,465 $0.00001 Subtotal Chemicals $799,198 $588,813 $0.00015

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 88 0.42 $0 $10,677 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 550 16.23 $0 $2,603,499 $0.00065 Subtotal Waste Disposal $0 $2,614,176 $0.00065

By-products & Emissions

Sulfur (tons) 0 47 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $799,198 $32,287,462 $0.00805

Fuel (ton) 0 6,513 15.22 $0 $28,937,267 $0.00721Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

139 

### Exhibit 3

- 33 Case L1 A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-20 Project: Low Rank Western Coal Baseline Study

Case: Case L1A - Shell IGCC w/o CO2 Plant Size: 616.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $18,819 $3,497 $14,594 $0 $0 $36,910 $3,350 $0 $8,052 $48,312 $78

2 COAL & SORBENT PREP & FEED $140,634 $11,900 $24,207 $0 $0 $176,741 $15,335 $0 $38,415 $230,491 $374

3 FEEDWATER & MISC. BOP SYSTEMS $8,213 $7,525 $7,209 $0 $0 $22,947 $2,150 $0 $5,559 $30,656 $50

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (S $183,394 $0 $79,368 $0 $0 $262,762 $23,441 $36,845 $49,395 $372,443 $604 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $161,830 $0 w/equip. $0 $0 $161,830 $15,686 $0 $17,752 $195,268 $317 4.4-4.9 Other Gasification Equipment $17,853 $11,411 $13,127 $0 $0 $42,390 $4,036 $0 $10,174 $56,600 $92 SUBTOTAL 4 $363,076 $11,411 $92,495 $0 $0 $466,982 $43,163 $36,845 $77,321 $624,311 $1,012

5A GAS CLEANUP & PIPING $49,333 $2,938 $45,661 $0 $0 $97,932 $9,465 $88 $21,641 $129,126 $209

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $188 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $192

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,161 $0 $4,857 $0 $0 $39,019 $3,710 $0 $4,273 $47,001 $76 7.2-7.9 SCR System, Ductwork and Stack $3,447 $2,457 $3,250 $0 $0 $9,154 $849 $0 $1,629 $11,632 $19 SUBTOTAL 7 $37,608 $2,457 $8,108 $0 $0 $48,173 $4,559 $0 $5,902 $58,633 $95

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $31,044 $0 $5,379 $0 $0 $36,423 $3,495 $0 $3,992 $43,910 $71 8.2-8.9 Turbine Plant Auxiliaries and Steam Pip $37,097 $1,072 $12,854 $0 $0 $51,022 $4,935 $0 $11,495 $67,452 $109 SUBTOTAL 8 $68,140 $1,072 $18,233 $0 $0 $87,445 $8,430 $0 $15,487 $111,362 $181

9 COOLING WATER SYSTEM $6,199 $6,318 $5,258 $0 $0 $17,774 $1,650 $0 $3,991 $23,415 $38

10 ASH/SPENT SORBENT HANDLING S $25,382 $1,887 $12,592 $0 $0 $39,861 $3,824 $0 $4,759 $48,444 $79

11 ACCESSORY ELECTRIC PLANT $28,874 $10,987 $21,847 $0 $0 $61,708 $5,304 $0 $12,626 $79,638 $129

12 INSTRUMENTATION & CONTROL $10,381 $1,910 $6,688 $0 $0 $18,979 $1,720 $949 $3,607 $25,255 $41

13 IMPROVEMENTS TO SITE $3,359 $1,980 $8,288 $0 $0 $13,627 $1,345 $0 $4,492 $19,464 $32

14 BUILDINGS & STRUCTURES $0 $6,624 $7,665 $0 $0 $14,289 $1,302 $0 $2,551 $18,142 $29

TOTAL COST $845,770 $71,311 $280,008 $0 $0 $1,197,089 $110,482 $42,483 $215,494 $1,565,547 $2,539 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

140 

### Exhibit 3

- 34 Case L1 A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Jan-20 Project: Low Rank Western Coal Baseline Study

Case: Case L1A - Shell IGCC w/o CO2 Plant Size: 616.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,942 $0 $2,415 $0 $0 $7,357 $659 $0 $1,603 $9,619 $16 1.2 Coal Stackout & Reclaim $6,386 $0 $1,548 $0 $0 $7,934 $695 $0 $1,726 $10,356 $17 1.3 Coal Conveyors & Yd Crush $5,937 $0 $1,532 $0 $0 $7,469 $656 $0 $1,625 $9,750 $16
1.4 Other Coal Handling $1,553 $0 $354 $0 $0 $1,908 $167 $0 $415 $2,490 $4 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $3,497 $8,744 $0 $0 $12,242 $1,173 $0 $2,683 $16,098 $26 SUBTOTAL 1. $18,819 $3,497 $14,594 $0 $0 $36,910 $3,350 $0 $8,052 $48,312 $78
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $57,744 $3,469 $8,414 $0 $0 $69,627 $6,008 $0 $15,127 $90,762 $147 2.2 Prepared Coal Storage & Feed $2,400 $574 $376 $0 $0 $3,351 $287 $0 $727 $4,365 $7 2.3 Dry Coal Injection System $78,986 $917 $7,335 $0 $0 $87,238 $7,514 $0 $18,950 $113,702 $184 2.4 Misc.Coal Prep & Feed $1,504 $1,094 $3,282 $0 $0 $5,880 $540 $0 $1,284 $7,705 $12 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $5,846 $4,800 $0 $0 $10,646 $986 $0 $2,326 $13,958 $23 SUBTOTAL 2. $140,634 $11,900 $24,207 $0 $0 $176,741 $15,335 $0 $38,415 $230,491 $374 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $3,147 $5,404 $2,853 $0 $0 $11,404 $1,057 $0 $2,492 $14,953 $24 3.2 Water Makeup & Pretreating $322 $34 $180 $0 $0 $535 $51 $0 $176 $762 $1 3.3 Other Feedwater Subsystems $1,722 $582 $524 $0 $0 $2,827 $254 $0 $616 $3,698 $6 3.4 Service Water Systems $184 $379 $1,316 $0 $0 $1,879 $183 $0 $619 $2,681 $4 3.5 Other Boiler Plant Systems $988 $383 $949 $0 $0 $2,319 $220 $0 $508 $3,047 $5 3.6 FO Supply Sys & Nat Gas $317 $598 $558 $0 $0 $1,472 $142 $0 $323 $1,937 $3 3.7 Waste Treatment Equipment $450 $0 $274 $0 $0 $724 $71 $0 $238 $1,033 $2 3.8 Misc. Power Plant Equipment $1,084 $145 $557 $0 $0 $1,786 $172 $0 $587 $2,545 $4 SUBTOTAL 3. $8,213 $7,525 $7,209 $0 $0 $22,947 $2,150 $0 $5,559 $30,656 $50
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (S $183,394 $0 $79,368 $0 $0 $262,762 $23,441 $36,845 $49,395 $372,443 $604 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $161,830 $0 w/equip. $0 $0 $161,830 $15,686 $0 $17,752 $195,268 $317
4.4 LT Heat Recovery & FG Saturation $17,853 $0 $6,787 $0 $0 $24,639 $2,405 $0 $5,409 $32,453 $53 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,042 $424 $0 $0 $1,467 $141 $0 $321 $1,929 $3 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $10,368 $5,916 $0 $0 $16,284 $1,491 $0 $4,444 $22,219 $36 SUBTOTAL 4. $363,076 $11,411 $92,495 $0 $0 $466,982 $43,163 $36,845 $77,321 $624,311 $1,012 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

141 

### Exhibit 3

- 34 Case L1A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2010-Jan-20 Project: Low Rank Western Coal Baseline Study

Case: Case L1A - Shell IGCC w/o CO2 Plant Size: 616.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Sulfinol System $38,030 $0 $32,269 $0 $0 $70,300 $6,799 $0 $15,420 $92,518 $150 5A.2 Elemental Sulfur Plant $5,501 $1,096 $7,097 $0 $0 $13,695 $1,330 $0 $3,005 $18,030 $29 5A.3 Mercury Removal $996 $0 $758 $0 $0 $1,754 $169 $88 $402 $2,413 $4 5A.4 COS Hydrolysis $3,312 $0 $4,326 $0 $0 $7,638 $743 $0 $1,676 $10,057 $16 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,494 $251 $141 $0 $0 $1,886 $179 $0 $413 $2,478 $4 5A.7 Fuel Gas Piping $0 $790 $553 $0 $0 $1,344 $125 $0 $294 $1,762 $3 5A.9 HGCU Foundations $0 $800 $516 $0 $0 $1,316 $121 $0 $431 $1,868 $3 SUBTOTAL 5A. $49,333 $2,938 $45,661 $0 $0 $97,932 $9,465 $88 $21,641 $129,126 $209
6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $188 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $192
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,161 $0 $4,857 $0 $0 $39,019 $3,710 $0 $4,273 $47,001 $76 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,767 $1,292 $0 $0 $3,059 $269 $0 $666 $3,993 $6
7.4 Stack $3,447 $0 $1,295 $0 $0 $4,741 $454 $0 $520 $5,715 $9 7.9 HRSG,Duct & Stack Foundations $0 $691 $663 $0 $0 $1,354 $126 $0 $444 $1,924 $3 SUBTOTAL 7. $37,608 $2,457 $8,108 $0 $0 $48,173 $4,559 $0 $5,902 $58,633 $95 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $31,044 $0 $5,379 $0 $0 $36,423 $3,495 $0 $3,992 $43,910 $71 8.2 Turbine Plant Auxiliaries $216 $0 $495 $0 $0 $711 $70 $0 $78 $859 $1 8.3a Condenser & Auxiliaries $3,083 $0 $985 $0 $0 $4,068 $389 $0 $446 $4,903 $8 8.3b Air Cooled Condenser $28,258 $0 $5,665 $0 $0 $33,923 $3,392 $0 $7,463 $44,779 $73 8.4 Steam Piping $5,539 $0 $3,896 $0 $0 $9,436 $811 $0 $2,562 $12,808 $21 8.9 TG Foundations $0 $1,072 $1,812 $0 $0 $2,883 $273 $0 $947 $4,104 $7 SUBTOTAL 8. $68,140 $1,072 $18,233 $0 $0 $87,445 $8,430 $0 $15,487 $111,362 $181
9 COOLING WATER SYSTEM 9.1 Cooling Towers $4,291 $0 $780 $0 $0 $5,071 $483 $0 $833 $6,387 $10 9.2 Circulating Water Pumps $1,116 $0 $65 $0 $0 $1,181 $99 $0 $192 $1,472 $2 9.3 Circ.Water System Auxiliaries $100 $0 $14 $0 $0 $115 $11 $0 $19 $145 $0 9.4 Circ.Water Piping $0 $4,191 $1,087 $0 $0 $5,278 $477 $0 $1,151 $6,906 $11 9.5 Make-up Water System $197 $0 $282 $0 $0 $479 $46 $0 $105 $630 $1 9.6 Component Cooling Water Sys $495 $592 $421 $0 $0 $1,508 $141 $0 $330 $1,979 $3 9.9 Circ.Water System Foundations $0 $1,535 $2,609 $0 $0 $4,144 $393 $0 $1,361 $5,898 $10 SUBTOTAL 9. $6,199 $6,318 $5,258 $0 $0 $17,774 $1,650 $0 $3,991 $23,415 $38 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

142 

### Exhibit 3

- 34 Case L1A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2010-Jan-20 Project: Low Rank Western Coal Baseline Study

Case: Case L1A - Shell IGCC w/o CO2 Plant Size: 616.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $22,213 $0 $10,954 $0 $0 $33,167 $3,187 $0 $3,635 $39,989 $65 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $718 $0 $782 $0 $0 $1,500 $145 $0 $247 $1,892 $3 10.7 Ash Transport & Feed Equipment $963 $0 $232 $0 $0 $1,196 $112 $0 $196 $1,503 $2 10.8 Misc. Ash Handling Equipment $1,488 $1,823 $545 $0 $0 $3,855 $367 $0 $633 $4,856 $8 10.9 Ash/Spent Sorbent Foundation $0 $64 $80 $0 $0 $143 $13 $0 $47 $204 $0 SUBTOTAL 10. $25,382 $1,887 $12,592 $0 $0 $39,861 $3,824 $0 $4,759 $48,444 $79
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $961 $0 $951 $0 $0 $1,912 $183 $0 $209 $2,304 $4 11.2 Station Service Equipment $4,056 $0 $366 $0 $0 $4,422 $408 $0 $483 $5,312 $9 11.3 Switchgear & Motor Control $7,499 $0 $1,364 $0 $0 $8,863 $822 $0 $1,453 $11,137 $18
11.4 Conduit & Cable Tray $0 $3,483 $11,492 $0 $0 $14,975 $1,448 $0 $4,106 $20,529 $33 11.5 Wire & Cable $0 $6,656 $4,373 $0 $0 $11,029 $801 $0 $2,958 $14,788 $24 11.6 Protective Equipment $0 $689 $2,507 $0 $0 $3,196 $312 $0 $526 $4,035 $7
11.7 Standby Equipment $236 $0 $231 $0 $0 $467 $45 $0 $77 $588 $1 11.8 Main Power Transformers $16,121 $0 $147 $0 $0 $16,268 $1,231 $0 $2,625 $20,123 $33 11.9 Electrical Foundations $0 $159 $418 $0 $0 $577 $55 $0 $190 $822 $1 SUBTOTAL 11. $28,874 $10,987 $21,847 $0 $0 $61,708 $5,304 $0 $12,626 $79,638 $129
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,025 $0 $684 $0 $0 $1,709 $162 $85 $293 $2,250 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards, Panels & Racks $236 $0 $151 $0 $0 $387 $37 $19 $88 $531 $1 12.7 Computer & Accessories $5,466 $0 $175 $0 $0 $5,641 $518 $282 $644 $7,085 $11 12.8 Instrument Wiring & Tubing $0 $1,910 $3,904 $0 $0 $5,814 $493 $291 $1,649 $8,247 $13 12.9 Other I & C Equipment $3,654 $0 $1,774 $0 $0 $5,428 $511 $271 $932 $7,142 $12 SUBTOTAL 12. $10,381 $1,910 $6,688 $0 $0 $18,979 $1,720 $949 $3,607 $25,255 $41 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $105 $2,253 $0 $0 $2,358 $234 $0 $778 $3,370 $5 13.2 Site Improvements $0 $1,875 $2,491 $0 $0 $4,366 $431 $0 $1,439 $6,235 $10 13.3 Site Facilities $3,359 $0 $3,545 $0 $0 $6,904 $681 $0 $2,275 $9,860 $16 SUBTOTAL 13. $3,359 $1,980 $8,288 $0 $0 $13,627 $1,345 $0 $4,492 $19,464 $32
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,586 $3,684 $0 $0 $6,270 $577 $0 $1,027 $7,874 $13 14.3 Administration Building $0 $847 $615 $0 $0 $1,462 $130 $0 $239 $1,831 $3
14.4 Circulation Water Pumphouse $0 $167 $88 $0 $0 $255 $22 $0 $42 $319 $1 14.5 Water Treatment Buildings $0 $269 $262 $0 $0 $531 $48 $0 $87 $666 $1 14.6 Machine Shop $0 $434 $297 $0 $0 $730 $65 $0 $119 $914 $1
14.7 Warehouse $0 $700 $452 $0 $0 $1,152 $102 $0 $188 $1,442 $2 14.8 Other Buildings & Structures $0 $419 $326 $0 $0 $746 $67 $0 $162 $975 $2 14.9 Waste Treating Building & Str. $0 $937 $1,791 $0 $0 $2,729 $254 $0 $597 $3,580 $6 SUBTOTAL 14. $0 $6,624 $7,665 $0 $0 $14,289 $1,302 $0 $2,551 $18,142 $29

TOTAL COST $845,770 $71,311 $280,008 $0 $0 $1,197,089 $110,482 $42,483 $215,494 $1,565,547 $2,539 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

143 

### Exhibit 3

- 35 Case L1A Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $13,821 $22 1 Month Variable O&M $3,711 $6 25% of 1 Months Fuel Cost at 100% CF $757 $1 2% of TPC $31,311 $51 Total $49,601 $80

Inventory Capital 60 day supply of consumables at 100% CF $6,199 $10 0.5% of TPC (spare parts) $7,828 $13 Total $14,027 $23

Initial Cost for Catalyst and Chemicals $1,024 $2 Land $900 $1 Other Owner's Costs $234,832 $381 Financing Costs $42,270 $69

Total Owner's Costs $342,653 $556 Total Overnight Cost (TOC) $1,908,200 $3,094 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $2,175,349 $3,527Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

144 

### Exhibit 3

- 36 Case L1 A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case L1A - Shell IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8156 MWe-net: 617 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $9.598 Maintenance Labor Cost $16,194,989 $26.261 Administrative & Support Labor $5,528,476 $8.965 Property Taxes and Insurance $31,310,940 $50.772 TOTAL FIXED OPERATING COSTS $58,953,318 $95.595 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $30,180,929 $0.00698

Consumables Consumption Unit Initial Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 1,353 1.08 $0 $427,306 $0.00010

Chemicals

MU & WT Chem.(lbs) 0 8,060 0.17 $0 $407,323 $0.00009 Carbon (Mercury Removal) (lb) 71,689 98 1.05 $75,286 $30,114 $0.00001 COS Catalyst (m3) 298 0.20 2,397.36 $714,200 $142,840 $0.00003 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Sulfinol Solution (gal) 23,349 16 10.05 $234,627 $46,573 $0.00001 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.85 131.27 $0 $32,615 $0.00001 Subtotal Chemicals $1,024,112 $659,465 $0.00015

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 98 0.42 $0 $11,960 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 918 16.23 $0 $4,347,545 $0.00101 Subtotal Waste Disposal $0 $4,359,504 $0.00101

By-products & Emissions

Sulfur (tons) 0 57 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,024,112 $35,627,205 $0.00824

Fuel (ton) 0 9,121 10.92 $0 $29,082,622 $0.00673Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

145 

### 3.2.8 SCGP IGCC CO 2 

### Capture Cases ( S1 B and L1 B ) Process Description

Cases S1 B and L1 B are configured to produce electric power with CO 2 

### capture. The plant configurations are similar to Cases S1 A and L1 A with the major differences being the addition of WGS, the use of a two

- stage Selexol AGR plant inst ead of Sulfinol and subsequent compression of the captured CO 2 

### stream. The gross power output is constrained by the capacity of the two CT s, and since the CO 2 

### capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Cases S1 A and L1 A.

The process description for Cases S1 B and L1 B is similar to Cases S1 A and L1 A with several notable exceptions to accommodate CO 2 

### capture. A BFD for the CO 2 

### capture case is shown in Exhibit 3

- 37 and stream tables are shown in Exhibit 3

- 38 . Instead of repeating the entire process description, only differences from the non

- capture cases are reported here. Coal Preparation and Feed Systems

No differences from non

- capture cases.

Gasification The gasification process is the same as the non

- capture cases except the coal feed (as

- received) to the gasifiers is 6,379 tonne/day (7,032 tpd) for the PRB case and 8,861 tonne/day (9,768 tpd) for the lignite case

. Raw Gas Cooling/Particulate Removal Specifically for the Shell technology for switching to carbon capture, t he high temperature section of the raw gas cooler is replaced by a direct contact water quench, which cools the gas to 363°C (685°F), simultaneously increas ing the water content of the syngas for the downstream WGS reaction. Sour Water Stripper

No differences from non

- capture cases

. SGS The SGS process was described in Section 3.1.6

. The water concentration in the syngas is controlled by varying the exit temperature of the water scrubber upstream of the shift reactors and is augmented by injection of shift steam. The hot syngas exiting the first stage of SGS is used t o superheat steam. One more stage of SGS (for a total of two) results in approximately 9 7 percent overall conversion of CO to CO 2 

### . The warm syngas from the second stage of SGS is cooled to preheat the syngas prior to the first stage of SGS. The SGS cata lyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds. Mercury Removal and AGR Mercury removal is the same as in the non

- capture cases

. The AGR process in the CO 2 

### capture cases is a two stage Selexol process where H 2 

### S is removed in the first stage and CO 2 

### in the second stage of absorption. The process results in three pro duct streams, the clean syngas , a CO 2 

### - rich stream and an ac id gas feed to the Claus plant . The acidCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

146 

### gas contains about 1 7 percent H 2 

### S and 6 6 percent CO 2 

### with the balance primarily H 2 

### . The CO 2 

### - rich stream is discussed further in the CO 2 

### compression section.

CO 2 

### Compression and Dehydration

CO 2 

### from the AGR process is generated at two pressure levels. The LP stream is compressed from 0.12 MPa (17 psia) to 1.0 MPa (150 psia) and then combined with the HP stream. The combined stream is further compressed to a SC condition at 15.3 MPa (2215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

### stream is dehydrated to a dew point of

- 40oC (

- 40°F) using a thermal swing adsorptive dryer. The raw CO 2 

### stream from the Selexol process contains over 99 percent CO 2 

### . The dehydrated CO 2 

### is transported to the plant fence line and is sequestration ready.

Claus Unit The Claus plant is the same as the non

- capture cases except 46 tonne/day (51 tpd) of sulfur are produced in the PRB case and 55 tonne/day (61 tpd) in th e lignite case.

Power Block

C lean syngas from the AGR plant is reheated to 196°C (385°F) using HP BFW , diluted with nitrogen , and then enters the CT burner . The exhaust gas exits the CT at a nominal 566°C (1,050°F) and enters the HRSG where additional heat is recovered. The flue gas e xits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a nominal 12.4 MPa/538°C/538°C (1800 psig/1000 °F/1000°F) steam cycle. There is no air integration between the CT and the ASU in either capture case.

ASU The same elevated pressure ASU is used as in non

- capture cases except the output is 3,933 tonne/day (4,335 tpd) of 95 mol % oxygen to the gasifier an d Claus plant for the PRB case and 4,447 tonne/day (4,902 tpd) for the lignite case

Balance of Plant

Balance of plant items were covered in Sections 3.1.12
, 3.1.13
, 3.1.14
, and 3.1.15

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

147 

### Exhibit 3

- 37 Case S1 B and L1 B Process Flow DiagramCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

148 

### Exhibit 3

- 38 Case S1 B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 V-L Mole Fraction

Ar 0.0093 0.0160 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0104 0.0060 0.0000 0.0060 0.0000 0.0051
CH 4 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 0.0000 0.0000 0.0000
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.6016 0.3470 0.0000 0.3470 0.0000 0.2969
CO 2 0.0003 0.0051 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0318 0.0183 0.0000 0.0183 0.0000 0.0157
COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0003 0.0000 0.0003 0.0000 0.0003
H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2616 0.1508 0.0000 0.1508 0.0000 0.1291

H 2 O 0.0064 0.0975 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.0279 0.4386 0.9981 0.4386 1.0000 0.5196

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0017 0.0000 0.0017 0.0000 0.0015

N 2 0.7759 0.7523 0.0178 0.9920 0.9920 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0604 0.0348 0.0000 0.0348 0.0000 0.0298

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0029 0.0024 0.0019 0.0024 0.0000 0.0021
O 2 0.2081 0.1291 0.9504 0.0054 0.0054 0.9504 0.0000 0.0000 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 0.0000 0.0000 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 24,697 1,577 78 17,093 935 5,014 0 0 3,103 0 0 17,390 6,685 12,763 30,153 4,420 35,237 V-L Flowrate (kg/hr) 713,612 43,868 2,517 479,643 26,236 161,348 0 0 55,901 0 0 375,047 134,128 229,913 604,961 79,634 696,534 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 265,792 0 209,891 22,427 0 0 0 0 0 0

Temperature (°C) 6 18 32 196 197 32

--- 6 33 71 1,427 1,427 246 170 232 288 232 Pressure (MPa, abs) 0.09 0.11 0.86 2.65 5.62 0.86

--- 0.09 0.55 0.09 4.24 4.24 4.24 0.79 3.93 4.14 3.79 Enthalpy (kJ/kg) A 15.26 36.45 26.67 202.64 201.76 26.67

--- --- 139.92

--- --- 2,242.88 1,346.50 668.41 1,325.51 2,956.19 1,527.21 Density (kg/m 3 ) 1.1 1.4 11.0 18.9 39.6 11.0

--- --- 985.3

--- --- 6.4 20.3 838.4 19.3 18.2 18.6 V-L Molecular Weight 28.895 27.826 32.181 28.061 28.061 32.181

--- --- 18.015

--- --- 21.567 20.063 18.013 20.063 18.015 19.767

V-L Flowrate (lb mol /hr) 54,447 3,476 172 37,684 2,061 11,054 0 0 6,841 0 0 38,338 14,739 28,139 66,477 9,745 77,683 V-L Flowrate (lb/hr) 1,573,246 96,713 5,550 1,057,431 57,841 355,711 0 0 123,241 0 0 826,838 295,701 506,872 1,333,710 175,564 1,535,594 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 585,970 0 462,730 49,444 0 0 0 0 0 0

Temperature (°F) 42 64 90 385 387 90

--- 42 92 160 2,600 2,600 474 338 450 550 449 Pressure (psia) 13.0 16.4 125.0 384.0 815.0 125.0

--- 13.0 80.0 13.0 614.7 614.7 615.0 115.0 569.7 600.0 549.7 Enthalpy (Btu/lb) A 6.6 15.7 11.5 87.1 86.7 11.5

--- --- 60.2

--- --- 964.3 578.9 287.4 569.9 1,270.9 656.6 Density (lb/ft 3 ) 0.070 0.089 0.687 1.180 2.475 0.687

--- --- 61.513

--- --- 0.401 1.265 52.337 1.205 1.135 1.160 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

149 

### Exhibit 3

- 38 Case S1B Stream Table (Continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 V-L Mole Fraction

Ar 0.0066 0.0094 0.0067 0.0022 0.0000 0.0071 0.0002 0.0002 0.0106 0.0106 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000
CH 4 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 0.0000 0.0000 0.0000
CO 0.0097 0.0035 0.0096 0.0035 0.0000 0.0403 0.0002 0.0002 0.0153 0.0153 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.3970 0.6359 0.4011 0.6588 0.0000 0.4434 0.9919 0.9948 0.0490 0.0490 0.0003 0.0089 0.0089 0.0000 0.0000 0.0000 0.0000
COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
H 2 0.5440 0.1223 0.5391 0.1254 0.0000 0.0549 0.0046 0.0046 0.8617 0.8617 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0017 0.1381 0.0017 0.0382 0.0000 0.3856 0.0029 0.0000 0.0001 0.0001 0.0064 0.1208 0.1208 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0022 0.0065 0.0023 0.1657 0.0000 0.0048 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0387 0.0843 0.0395 0.0060 0.0000 0.0638 0.0002 0.0002 0.0632 0.0632 0.7759 0.7549 0.7549 0.0000 0.0000 0.0000 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 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 0.0000 0.2081 0.1062 0.1062 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 0.0000 0.0000 0.0000
Total 1.0000 1.0000 1.0000 1.0000 0.0000 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) 27,106 390 27,442 376 0 515 10,004 9,975 17,062 17,062 100,352 127,026 127,026 25,110 17,107 17,107 39,134 V-L Flowrate (kg/hr) 550,130 13,168 562,339 13,525 0 15,427 437,535 437,012 111,279 111,279 2,899,687 3,490,609 3,490,609 452,359 308,189 308,189 705,016 Solids Flowrate (kg/hr) 0 0 0 0 1,928 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 49 34 48 176 232 16 72 31 196 6 561 132 533 32 32 33 Pressure (MPa, abs) 3.43 0.07 3.36 0.16 0.1 0.085 1.032 15.270 3.238 3.203 0.090 0.093 0.090 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 43.64 234.02 42.61 94.11

--- 861.747 5.232 -95.273 135.215 893.518 15.260 830.526 341.308 3,430.159 2,284.211 2,284.211 140.266 Density (kg/m 3 ) 27.8 0.9 27.5 2.2 5,284.6 0.6 20.1 461.3 8.3 5.3 1.1 0.4 0.7 36.8 0.04 0.04 995.0 V-L Molecular Weight 20.296 33.776 20.492 35.946

--- 29.941 43.735 43.809 6.522 6.522 28.895 27.479 27.479 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 59,758 859 60,500 830 0 1,136 22,056 21,992 37,615 37,615 221,239 280,045 280,045 55,358 37,715 37,715 86,276 V-L Flowrate (lb/hr) 1,212,830 29,030 1,239,745 29,817 0 34,010 964,599 963,447 245,329 245,329 6,392,716 7,695,476 7,695,476 997,281 679,441 679,441 1,554,294 Solids Flowrate (lb/hr) 0 0 0 0 4,251 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 120 94 119 348 450 60 162 87 385 42 1,042 270 992 90 90 92 Pressure (psia) 497.6 10.6 487.6 23.7 17.3 12.3 149.7 2,214.7 469.6 464.6 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 18.8 100.6 18.3 40.5

--- 370.5 2.2 -41.0 58.1 384.1 6.6 357.1 146.7 1,474.7 982.0 982.0 60.3 Density (lb/ft 3 ) 1.733 0.058 1.718 0.138 330 0.038 1.254 28.796 0.515 0.330 0.070 0.023 0.046 2.297 0.002 0.002 62.116Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

150 

### Exhibit 3

- 39 Case L1 B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 V-L Mole Fraction

Ar 0.0093 0.0093 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0100 0.0058 0.0000 0.0058 0.0000 0.0055
CH 4 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 0.0000 0.0000 0.0000
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5271 0.3057 0.0000 0.3057 0.0000 0.2869
CO 2 0.0003 0.0025 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0643 0.0373 0.0000 0.0373 0.0000 0.0350
COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0004 0.0002 0.0000 0.0002 0.0000 0.0002
H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2477 0.1436 0.0000 0.1436 0.0000 0.1348

H 2 O 0.0062 0.0466 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.0802 0.4666 1.0000 0.4666 1.0000 0.4993

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0018 0.0000 0.0018 0.0000 0.0017

N 2 0.7761 0.8746 0.0178 0.9922 0.9922 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0658 0.0382 0.0000 0.0382 0.0000 0.0358

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0014 0.0008 0.0000 0.0008 0.0000 0.0007
O 2 0.2082 0.0670 0.9504 0.0053 0.0053 0.9504 0.0000 0.0000 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 0.0000 0.0000 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 27,921 3,603 44 17,365 1,195 5,714 0 0 5,608 0 0 20,444 6,518 14,814 35,257 1,619 37,556 V-L Flowrate (kg/hr) 806,854 100,755 1,429 487,271 33,525 183,875 0 0 101,037 0 0 448,453 132,242 266,870 715,323 29,158 756,739 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 369,238 0 268,201 37,148 0 0 0 0 0 0

Temperature (°C) 4 16 32 196 197 32

--- 4 32 71 1,371 1,371 245 171 232 288 233 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 5.62 0.86

--- 0.10 0.34 0.09 4.24 4.24 4.24 0.79 3.93 4.14 3.79 Enthalpy (kJ/kg) A 13.75 34.65 26.67 202.62 201.73 26.67

--- --- 134.94

--- --- 2,286.87 1,394.66 674.27 1,374.03 2,956.19 1,457.26 Density (kg/m 3 ) 1.2 1.4 11.0 18.9 39.6 11.0

--- --- 986.5

--- --- 6.8 20.6 838.7 19.6 18.2 18.9 V-L Molecular Weight 28.898 27.966 32.181 28.060 28.060 32.181

--- --- 18.015

--- --- 21.936 20.289 18.015 20.289 18.015 20.150

V-L Flowrate (lb mol /hr) 61,555 7,943 98 38,284 2,634 12,597 0 0 12,364 0 0 45,071 14,370 32,658 77,729 3,568 82,797 V-L Flowrate (lb/hr) 1,778,809 222,127 3,150 1,074,248 73,910 405,375 0 0 222,748 0 0 988,670 291,544 588,347 1,577,017 64,283 1,668,325 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 814,029 0 591,281 81,896 0 0 0 0 0 0

Temperature (°F) 40 61 90 385 387 90

--- 40 90 160 2,500 2,500 474 339 450 550 451 Pressure (psia) 13.8 16.4 125.0 384.0 815.0 125.0

--- 13.8 50.0 13.5 614.7 614.7 615.0 115.0 569.7 600.0 549.7 Enthalpy (Btu/lb) A 5.9 14.9 11.5 87.1 86.7 11.5

--- --- 58.0

--- --- 983.2 599.6 289.9 590.7 1,270.9 626.5 Density (lb/ft 3 ) 0.074 0.085 0.687 1.179 2.475 0.687

--- --- 61.586

--- --- 0.422 1.287 52.359 1.225 1.135 1.177 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

151 

### Exhibit 3

- 39 Case L1B Stream Table (Continued)

18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 V-L Mole Fraction

Ar 0.0070 0.0060 0.0070 0.0022 0.0000 0.0049 0.0002 0.0002 0.0112 0.0112 0.0093 0.0092 0.0092 0.0000 0.0000 0.0000 0.0000
CH 4 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 0.0000 0.0000 0.0000
CO 0.0101 0.0060 0.0100 0.0036 0.0000 0.0790 0.0002 0.0002 0.0161 0.0161 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.4026 0.6471 0.4068 0.6513 0.0000 0.4546 0.9920 0.9949 0.0502 0.0502 0.0003 0.0093 0.0093 0.0000 0.0000 0.0000 0.0000
COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
H 2 0.5302 0.1626 0.5261 0.1193 0.0000 0.0588 0.0044 0.0044 0.8484 0.8484 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0017 0.1381 0.0017 0.0382 0.0000 0.3698 0.0029 0.0000 0.0001 0.0001 0.0062 0.1201 0.1201 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0024 0.0068 0.0025 0.1784 0.0000 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0459 0.0334 0.0458 0.0068 0.0000 0.0273 0.0002 0.0002 0.0740 0.0740 0.7761 0.7541 0.7541 0.0000 0.0000 0.0000 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 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 0.0000 0.2082 0.1073 0.1073 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 0.0000 0.0000 0.0000
Total 1.0000 1.0000 1.0000 1.0000 0.0000 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) 29,315 419 29,676 417 0 512 10,972 10,940 18,287 18,287 106,961 134,709 134,709 26,245 18,526 18,526 39,107 V-L Flowrate (kg/hr) 608,290 13,763 621,022 15,053 0 15,448 479,908 479,329 126,060 126,060 3,090,914 3,704,245 3,704,245 472,820 333,743 333,743 704,530 Solids Flowrate (kg/hr) 0 0 0 0 2,307 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 49 35 48 177 232 16 72 31 216 4 560 132 532 32 32 33 Pressure (MPa, abs) 3.43 0.07 3.36 0.16 0.1 0.085 0.931 15.270 3.238 3.234 0.095 0.099 0.095 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 42.51 240.64 41.58 93.85

--- 832.551 6.361 -95.603 127.658 930.527 13.748 827.700 339.845 3,427.809 2,290.992 2,290.992 140.266 Density (kg/m 3 ) 28.4 0.9 28.1 2.2 5,282.6 0.6 18.0 462.1 8.7 5.4 1.2 0.4 0.8 36.9 0.04 0.04 995.0 V-L Molecular Weight 20.750 32.869 20.927 36.063

--- 30.157 43.740 43.816 6.893 6.893 28.898 27.498 27.498 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 64,628 923 65,425 920 0 1,129 24,189 24,118 40,316 40,316 235,808 296,983 296,983 57,861 40,842 40,842 86,217 V-L Flowrate (lb/hr) 1,341,049 30,342 1,369,120 33,187 0 34,057 1,058,017 1,056,739 277,916 277,916 6,814,298 8,166,462 8,166,462 1,042,389 735,778 735,778 1,553,224 Solids Flowrate (lb/hr) 0 0 0 0 5,086 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 120 94 119 350 450 60 161 87 420 40 1,040 270 990 90 90 92 Pressure (psia) 497.6 10.6 487.6 23.7 17.3 12.3 135.0 2,214.7 469.6 469.0 13.8 14.3 13.8 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 18.3 103.5 17.9 40.3

--- 357.9 2.7 -41.1 54.9 400.1 5.9 355.8 146.1 1,473.7 984.9 984.9 60.3 Density (lb/ft 3 ) 1.774 0.056 1.756 0.138 330 0.038 1.123 28.851 0.545 0.339 0.074 0.024 0.048 2.301 0.002 0.002 62.116Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

152 

### 3.2.9 Case S1 B and L1 B Performance Results

The Case S1 B and L1 B modeling assumptions were presented previously in Exhibit 3

- 16

.
The SCGP IGCC plant with CO 2 

### capture and using PRB coal at the Montana site (elevation 3,400 ft) produces a net output of 472 MWe at a net plant efficiency of 32

. 1 percent (HHV basis). The same plant configuration using lignite coal at the NDL site (elevation 1,900 ft) produces a net output of 500 MWe at a net plant efficiency of 31

. 7 percent (HHV basis). Overall performance for the plant s is summarized in Exhibit 3

- 40
, which includes auxiliary power requirements

. The ASU accounts for approximately 55 percent of the total auxiliary load in both cases, dis tributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The co al drying process accounts for approximately 6 percent

. CO 2 

### co mpression accounts for about 1 7 percent and the AGR process accounts for ab out 9. 6 percent of the auxiliary load in both cases. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

153 

### Exhibit 3

- 40 Case S1 B and L1 B Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) S1 B L1 B

Gas Turbine Power 430,900 456,600 Steam Turbine Power 232,500 256,700 TOTAL POWER, kWe 663,400 713,300 AUXILIARY LOAD SUMMARY, kWe Coal Handling 510 620 Coal Milling 2,730 3,800 Slag Handling 580 970 WTA Coal Dryer Compressor 9,370 12,980 WTA Coal Dryer Auxiliaries 620 850 Air Separation Unit Auxiliaries 1,000 1,000 Air Separation Unit Main Air Compressor 63,550 70,010 Oxygen Compressor 8,830 10,070 Nitrogen Compressors 33,340 34,630
CO 2 Compressor 31,560 35,250 Boiler Feedwater Pumps 3,260 3,300 Condensate Pump 230 230 Quench Water Pump 760 880 Syngas Recycle Compressor 820 800 Circulating Water Pump 2,730 3,410 Ground Water Pumps 310 350 Cooling Tower Fans 1,780 2,090
Air Cooled Condenser Fans 2,960 3,040 Scrubber Pumps 20 30
Acid Gas Removal 18,400 20,180
Gas Turbine Auxiliaries 1,000 1,000
Steam Turbine Auxiliaries 100 100
Claus Plant/TGTU Auxiliaries 250 250 Claus Plant TG Recycle Compressor 1,530 1,640
Miscellaneous Balance of Plant 1 3,000 3,000
Transformer Losses 2,550 2,760 TOTAL AUXILIARIES, kWe 191,790 213,240 NET POWER, kWe 471,610 500,060 Net Plant Efficiency, % (HHV) 32.1% 31.7% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,227 (10,641) 11,365 (10,772) CONDENSER COOLING DUTY GJ/hr (10 6 Btu/hr) 1,319 (1,250) 1,435 (1,360)
CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 265,792 (585,970) 369,238 (814,029) Thermal Input, kWt 1,470,704 1,578,608
Raw Water Withdrawal , m 3 /min (gpm) 12.9 (3,404) 14.8 (3,917)
Raw Water Consumption , m 3 /min (gpm) 10

. 5 ( 2,767 ) 1 1 .8 ( 3
, 124 )

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

154 

### Environmental Performance The environmental targets for emissions of Hg, NOx , SO 2 

### , CO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air em issions for the CO 2 

### capture cases is presented in Exhibit 3

- 41

.

Exhibi t 3

- 41 Case S1 B and L1 B Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

S1 B L1 B S1 B L1 B S1 B L1 B

SO 2 

### 0.000 (0.001) 0.000 (0.001) 14 (15) 17 (18) 0.003 ( 0 .0 07 ) 0.003 ( 0 .0 07 )

NO X 

### 0.022 (0.050) 0.021 (0.049) 802 (885) 841 (927) 0.173 ( 0 .381) 0.168 ( 0 .371)

Particulates 0.003 (0.0071) 0.003 (0.0071) 113 (125) 122 (134) 0.024 ( 0 .054) 0.024 ( 0 .054)

Hg 1.51E

- 7 (3.51E

- 7) 2.41E

- 7 (5.60E

- 7) 0.006 (0.006) 0.010 (0.011) 1.20E

- 6 (2.66E

- 6) 1.92E

- 6 (4.23E

- 6)

CO 2 

### gross 9.4 (21.9) 9.7 (22.5) 348,874 (384,567) 384,547 (423,890) 75 (165) 77 (170)

CO 2 

### net 106 (233) 110 (242)

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the two

- stage Selexol AGR process. Just as in the non

- capture cases, the SO 2 

### emission are significantly less than the environmental targets of Section 2.3 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 2 ppmv. This results in a concentration in the flue gas of less than 0. 3 ppmv. The H 2 

### S

- rich regenerati on gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The tail gas is hydrogenated and recycled upstream of the AGR

.

NO x emissions are limited to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ) by the use of low NOx burners and nitrogen diluti on of the fuel gas . Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and subsequently destroyed in the Claus plant burner. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is li mited to extremely low values by the use of a cyclone and a barrier filter 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 mercury i s captured from the syngas by an activated carbon bed.

Slightly greater than 9 2 percent of the CO 2 

### from the syngas is captured in the AGR system and compressed for sequestration. The carbon balance for the plant is shown in Exhibit 3

- 42

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the carbonCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

155 

### capture equation below, but it is not neglected in the balance since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag

, CO 2 

### in the stack gas and ASU vent gas
, and the captured CO 2 

### product

. The carbon capture efficiency is defined a s the amount 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 Product for Sequestration)/[(Carbon in the Coal)

- (Carbon in Slag)] or 90 pe rcent (both cases S1 B and L1 B)

Exhibit 3

- 42 Cases S1 B and L1 B Carbon Balance
Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)
S1 B L1 B S1 B L1 B

Coal 133,077 (293,384) 146,047 (321,979) Slag 665 (1,467) 730 (1,610)

Air (CO 2 

### ) 492 (1,086) 531 (1,171) Stack Gas 13,586 (29,953) 14,976 (33,016)
ASU Vent 97 (214) 110 (242)

CO 2 

### Product 119,220 (262,836) 130,763 (288,282)

Total 133,569 (294,470) 146,578 (323,150) Total 133,569 (294,470) 146,578 (323,150)

Exhibit 3

- 43 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack ga s , and sulfur that is sequestered with the CO 2 

### product . Sulfur in the slag is considered negligible

. Exhibit 3

- 43 Cases S1 B and L1 B Sulfur Balance
Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)
S1 B L1 B S1 B L1 B

Coal 1,934 (4,263) 2,313 (5,099) Elemental Sulfur 1,928 (4,251) 2,307 (5,086)

Stack Gas 1 (2) 1 (3)

CO 2 

### Product 4 (9) 5 (11) Convergence

Tolerance 1 

### 0 (0) 0 (0)

Total 1,934 (4,263) 2,313 (5,099) Total 1,934 (4,263) 2,313 (5,099)

Exhibit 3

- 44 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percen t). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily from the coal drying process and as syngas condensate, and that water is re

used as internal recycle. Raw wate r withdrawal is the difference between water demand andCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

156 

### internal recycle. Some water is discharged from the process to a permitted outfall. The difference between the withdrawal and discharge is the consumption. Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 45 and Exhibit 3

- 46 :

**•** Coal gasification and ASU

**•** Syngas cleanup

**•** Combined cycle power generation

An overall plant energy balance is provided in tabular form in Exhibit 3

- 47 for the two cases. The power out is the combined CT and steam turbine power after generator losses.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

157 

### Exhibit 3

- 44 Cases S1 B and L1 B Water Balanc e

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)

S1B L1B S1B L1B S1B L1B S1B L1B S1B L1B
Slag Handling 0.49 (128) 0.81 (213) 0.49 (128) 0.81 (213) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Quench/Wash 3.84 (1014) 4.45 (1177) 1.74 (460) 1.45 (383) 2.10 (554) 3.01 (794) 0 (0) 0 (0) 2.10 (554) 3.01 (794)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0.02 (6) 0.02 (6)

- 0.02 (

- 6)

- 0.02 (

- 6)
Condenser Makeup 1.48 (391) 0.62 (163) 0 (0) 0 (0) 1.48 (391) 0.62 (163) 0 (0) 0 (0) 1.48 (391) 0.62 (163)

Shift Steam 1.33 (351) 0.49 (129) 1.33 (351) 0.49 (129)
BFW Makeup 0.15 (40) 0.13 (35) 0.15 (40) 0.13 (35)

Cooling Tower 10.62 (2,804) 13.25 (3,500) 1.31 (345) 2.04 (540) 9.31 (2,459) 11.20 (2,960) 2.39 (631) 2.98 (787) 6.92 (1,828) 8.22 (2,173) Water from Coal Drying 0.93 (246) 1.69 (445) - 0.93 (

- 246) - 1.69 (

- 445)
BFW Blowdown 0.15 (40) 0.13 (35)

- 0.15 (

- 40)

- 0.13 (

- 35)

SWS Blowdown 0.22 (59) 0.23 (60)

- 0.22 (

- 59)

- 0.23 (

- 60)

Total 16.4 (4,338) 19.1 (5,052) 3.5 (934) 4.30 (1135) 12.9 (3,404) 14.83 (3,917) 2.4 (637) 3.00 (793) 10.5 (2,767) 11.83 (3,124)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

158 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

159 

### Exhibit 3

- 45 Case S1B Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

160 

### Exhibit 3

- 45 Case S1B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

161 

### Exhibit 3

- 45 Case S1B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

162 

### Exhib it 3

- 46 Case L1B Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

163 

### Exhibit 3

- 46 Case L1B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

164 

### Exhibit 3

- 46 Case L1B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

165 

### Exhibit 3

- 47 Cases S1 B and L1 B Energy Bala nce

HHV Sensible + Latent Power Total S1 B L1 B S1 B L1 B S1 B L1 B S1 B L1 B
Heat In GJ/hr (MMBtu/hr)

Coal 5,29 5 (5,018) 5,683 (5,386) 2.7 (2.6) 3.3 (3.1) 0 (0) 0 (0) 5,29 7 (5,02 1 ) 5,686 (5,390)

ASU Air 0 (0) 0 (0) 10.9 (10.3) 11.1 (10.5) 0 (0) 0 (0) 11 (10) 11 (11)
GT Air 0 (0) 0 (0) 44.2 (41.9) 42.5 (40.3) 0 (0) 0 (0) 44 (42) 42 (40) Raw Water Makeup 0 (0) 0 (0) 17.9 (17.0) 16.5 (15.6) 0 (0) 0 (0) 18 (17) 16 (16) Auxiliary Power 0 (0) 0 (0) 0 ( 0 ) 0 ( 0 ) 69 0 (65 4 ) 768 (728) 69 0 (65 4 ) 768 (728)

Totals 5,29 5 (5,0 18 ) 5,683 (5,386) 75.8 (71.8) 73.4 (69.5) 69 0 (65 4 ) 768 (728) 6,06 1 (5,74 4 ) 6,524 (6,184)

Heat Out GJ/hr (MMBtu/hr) ASU Intercoolers 0 (0) 0 (0) 217 (206) 231 (219) 0 (0) 0 (0) 217 (206) 231 (219)
ASU Vent 0 (0) 0 (0) 1.6 (1.5) 3.5 (3.3) 0 (0) 0 (0) 2 (1) 3 (3) Slag 22 (21) 24 (23) 37.9 (35.9) 59.5 (56.4) 0 (0) 0 (0) 60 (57) 83 (79)
Sulfur 18 (17) 21 (20) 0.2 (0.2) 0.3 (0.2) 0 (0) 0 (0) 18 (17) 22 (21)
CO 2 0 (0) 0 (0)

- 41. 6 (

- 39.5)

- 45.8 (

- 43.4) 0 (0) 0 (0)

- 42 (

- 39 )

- 46 (

- 43)
CO 2 Comp Intercoolers 0 (0) 0 (0) 153. 3 (145. 3 ) 170.5 (161.6) 0 (0) 0 (0) 153 (145) 170 (162) Cooling Tower Blowdown 0 (0) 0 (0) 13.3 (12.6) 16.1 (15.3) 0 (0) 0 (0) 13 (13) 16 (15)

HRSG Flue Gas 0 (0) 0 (0) 1,19 1 (1,1 29 ) 1,259 (1,193) 0 (0) 0 (0) 1,19 1 (1,1 29 ) 1,259 (1,193)
Condenser 0 (0) 0 (0) 1,31 6 (1,24 8 ) 1,436 (1,361) 0 (0) 0 (0) 1,31 6 (1,24 8 ) 1,436 (1,361) Auxiliary Cooling Load 0 (0) 0 (0) 162 (154) 399 (378) 0 (0) 0 (0) 162 (154) 399 (378)
Process Losses 0 (0) 0 (0) 58 1 (55 1 ) 382 (362) 0 (0) 0 (0) 58 1 (55 1 ) 382 (362)

Power 0 (0) 0 (0) 0 (0 ) 0 (0) 2,38 8 (2,26 4 ) 2,568 (2,434) 2,38 8 (2,26 4 ) 2,568 (2,434)

Totals 40 (38) 45 (43) 3,63 3 (3,44 3 ) 3,911 (3,707) 2,388 (2,264) 2,568 (2,434) 6,061 (5,744) 6,524 (6,184)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

166 

### 3.2.10 Case S1 B and L1 B Equipment List

Major equipment items for the SCGP with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.2.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

167 

### ACCOUNT 1 COAL HANDLING Equipment No. Description Type S1 B Design Conditions L1 B Design Condition Operating Qty Spares

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 54 tonne (60 ton) 73 tonne (80 ton) 2 1
9 Feeder Vibratory 218 tonne/hr (240 tph) 308 tonne/hr (340 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 435 tonne/hr (480 tph) 608 tonne/hr (670 tph) 1 0

11 Crusher Tower N/A N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 218 tonne (240 ton) 308 tonne (340 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 435 tonne/hr (480 tph) 608 tonne/hr (670 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A N/A 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

168 

### Equipment No. Description Type S1 B Design Conditions L1 B Design Condition Operating Qty Spares

17 Conveyor No. 5 Belt w/ tripper 435 tonne/hr (480 tph) 608 tonne/hr (670 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 998 tonne (1,100 ton) 1,361 tonne (1,500 ton) 3 0

ACCOUNT 2 COAL PREPARATION AND FEED Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Feeder Vibratory 100 tonne/hr (110 tph) 136 tonne/hr (150 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 290 tonne/hr (320 tph) 408 tonne/hr (450 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 581 tonne (640 ton) 816 tonne (900 ton) 1 0

4 Weigh Feeder Belt 145 tonne/hr (160 tph) 200 tonne/hr (220 tph) 2 0
5 Pulverizer Rotary 145 tonne/hr (160 tph) 200 tonne/hr (220 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 290 tonne (320 ton) 408 tonne (450 ton) 2 0

7 Coal Preheater Water Heated Horizontal Rotary Kiln Coal feed: 290 tonne/hr (320 tph) Heat duty: 32.5 GJ/hr (30.8 MMBtu/hr) Coal feed: 408 tonne/hr (450 tph) Heat duty: 50 GJ/hr (48 MMBtu/hr) 1 0

8 Coal Dryer Fluidized Bed with Internal Coils Coal feed: 145 tonne/hr (160 tph) Heat duty: 81.8 GJ/hr (77.6 MMBtu/hr) Bed diameter: 12.5 m (41 ft) Coal feed: 200 tonne/hr (220 tph) Heat duty: 146 GJ/hr (138 MMBtu/hr) Bed diameter: 14.6 m (48 ft) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

169 

### Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

9 Steam Compressor Reciprocating, Multi

Stage 612 m 3 

### /min (21,630 scfm) Suction

- 0.09 MPa (13 psia) Discharge

- 0.72 MPa (105.0 psia) 1107 m 3 

### /min (39,100 scfm) Suction

- 0.10 MPa (13.8 psia) Discharge

- 0.52 MPa (75 psia) 2 0

10 Dryer Exhaust Filter Hot Baghouse Steam

- 30,754 kg/hr (67,800 lb/hr) Temperature

- 107°C (225°F) Steam

- 55,565 kg/hr (122,500 lb/hr) Temperature

- 107°C (225°F) 2 0

11 Dry Coal Cooler Water Cooled Horizontal Rotary Kiln 231 tonne/hr (255 tph) Heat duty

- 13 GJ/hr (13 MMBtu/hr) 295 tonne/hr (325 tph) Heat duty

- 18 GJ/hr (18 MMBtu/hr) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

170 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 582,953 liters (154,000 gal) 507,245 liters (134,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,511 lpm @ 91 m H 2 

### O (1,720 gpm @ 300 ft H 2 

### O) 6,511 lpm @ 91 m H 2 

### O (1,720 gpm @ 300 ft H 2 

### O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 467,200 kg/hr (1,030,000 lb/hr) 479,447 kg/hr (1,057,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 1,590 lpm @ 27 m H 2 

### O (420 gpm @ 90 ft H 2 

### O) 1,476 lpm @ 27 m H 2 

### O (390 gpm @ 90 ft H 2 

### O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

- stage, centrifugal HP water: 4,429 lpm @ 1,890 m H 2 

### O (1,170 gpm @ 6,200 ft H 2 

### O) HP water: 4,618 lpm @ 1,890 m H 2 

### O (1,220 gpm @ 6,200 ft H 2 

### O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

- stage, centrifugal IP water: 2,423 lpm @ 223 m H 2 

### O (640 gpm @ 730 ft H 2 

### O) IP water: 1,249 lpm @ 223 m H 2 

### O (330 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 Cy cl e Cooling Heat Exchangers Plate and frame 308 GJ/hr (29 2 MMBtu/hr) each 455 GJ/hr (431 MMBtu/hr) each 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

171 

### Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 110,155 lpm @ 21 m H 2 

### O (29,100 gpm @ 70 ft H 2 

### O) 163,151 lpm @ 21 m H 2 

### O (43,100 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 3,596 lpm @ 18 m H 2 

### O (950 gpm @ 60 ft H 2 

### O) 4,126 lpm @ 18 m H 2 

### O (1,090 gpm @ 60 ft H 2 

### O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,385 lpm @ 268 m H 2 

### O (630 gpm @ 880 ft H 2 

### O) 2,763 lpm @ 268 m H 2 

### O (730 gpm @ 880 ft H 2 

### O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 3,255 lpm @ 49 m H 2 

### O (860 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 1,570,946 liter (415,000 gal) 1,593,658 liter (421,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 908 lpm (240 gpm) 416 lpm (110 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

172 

### ACCOUNT 4 GASIFIER, ASU , AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Gasifier Pressurized dry

feed, entrained bed 3,538 tonne/day, 4.2 MPa (3,900 tpd, 61 5 psia) 4,899 tonne/ day, 4.2 MPa (5,400 tpd, 615 psia) 2 0

2 Quench Vertical with water mist spray nozzles Raw Gas

- 28,096 m 3 

### /hr @ 4.2 MPa (992,210 cuft/hr

@ 610 psia) Water

- 114,957 kg/hr (253,436 lb/hr) Raw Gas

- 31,598 m 3 

### /hr @ 4.2 MPa (1,115,882 cuft/hr @ 610 psia) Water

- 133,435 kg/hr (294,174 lb/hr) 2 0

3 Synthesis Gas Cooler Convective spiral

wound tube boiler 406,419 kg/hr (896,000 lb/hr) Heat duty: 165 GJ/hr (157 MMBtu/hr) 466,293 kg/hr (1,028,000 lb/hr) Heat duty: 191 GJ/hr (181 MMBtu/hr) 2 0

4 Synthesis Gas Cyclone High efficiency 406,419 kg/hr (896,000 lb/hr) Design efficiency 90% 466,293 kg/hr (1,028,000 lb/hr) Design efficiency 90% 2 0

6 Syngas Scrubber Including Sour Water Stripper Vertical up flow 332,937 kg/hr (734,000 lb/hr) 393,265 kg/hr (867,000 lb/hr) 2 0

7 Raw Gas Coolers Shell and tube with condensate drain 346,998 kg/hr (765,000 lb/hr) 416,398 kg/hr (918,000 lb/hr) 8 0

8 Raw Gas Knockout Drum Vertical with mist eliminator 303,000 kg/hr, 35°C, 3.5 MPa (668,000 lb/hr, 95°F, 503 psia) 334,751 kg/hr, 35°C, 3.5 MPa (738,000 lb/hr, 95°F, 503 psia) 2 0

10 Synthesis Gas Reheater Shell and tube 61,235 kg/hr (135,000 lb/hr) 69,400 kg/hr (153,000 lb/hr) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

173 

### Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

11 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 332,937 kg/hr (734,000 lb/hr) syngas 393,265 kg/hr (867,000 lb/hr) syngas 2 0

12 ASU Main Air Compressor Centrifugal, multi

stage 5,352 m 3 

### /min @ 1.3 MPa (189,000 scfm

@ 190 psia) 6,060 m 3 

### /min @ 1.3 MPa (214,000 scfm

@ 190 psia) 2 0

13 Cold Box Vendor design 2,177 tonne/day (2,400 tpd) of 95% purity oxygen 2,449 tonne/day (2,700 tpd) of 95% purity oxygen 2 0

14 Oxygen Compressor Centrifugal, multi

stage 1,076 m 3 

### /min (38,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 1,246 m 3 

### /min (44,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 2 0

15 Primary Nitrogen Compressor Centrifugal, multi

stage 3,426 m 3 

### /min (121,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 3,455 m 3 

### /min (122,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0

16 Secondary Nitrogen Compressor Centrifugal, single

stage 510 m 3 

### /min (18,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 5.7 MPa (820 psia) 566 m 3 

### /min (20,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 5.7 MPa (820 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

174 

### Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

17 Transport Nitrogen Boost Compressor Centrifugal, single

stage 204 m 3 

### /min (7,200 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 5.6 MPa (815 psia) 261 m 3 

### /min (9,200 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 5.6 MPa (815 psia) 2 0

18 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

stage 1,478 m 3 

### /min (52,200 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 3.2 MPa (469 psia) 1,781 m 3 

### /min (62,900 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 3.2 MPa (469 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

175 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed 302,546 kg/hr (667,000 lb/hr) 35°C (95°F) 3.4 MPa (498 psia) 334,751 kg/hr (738,000 lb/hr) 35°C (95°F) 3.4 MPa (498 psia) 2 0

2 Sulfur Plant Claus type 51 tonne/day (56 tpd) 61 tonne/day (67 tpd) 1 0

3 WGS Reactors Fixed bed, catalytic 383,286 kg/hr (845,000 lb/hr) 232°C (450°F) 3.8 MPa (550 psia) 416,398 kg/hr (918,000 lb/hr) 232°C (450°F) 3.8 MPa (550 psia) 4 0

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 197 GJ/hr (187 MMBtu/hr) Exchanger 1: 204 GJ/hr (193 MMBtu/hr) 4 0

5 AGR Plant Two

- stage Selexol 309,350 kg/hr (682,000 lb/hr) 34°C (94°F) 3.4 MPa (488 psia) 341,555 kg/hr (753,000 lb/hr) 35°C (94°F) 3.4 MPa (488 psia) 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 16,970 kg/hr (37,411 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 16,993 kg/hr (37,463 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 13,441 kg/hr (29,633 lb/hr) 14,019 kg/hr (30,906 lb/hr) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

176 

### ACCOUNT 5B CO 2 

### COMPRESSION

Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 CO 2 

### Compressor Integrally geared, multi

- stage centrifugal 1,082 m 3 

### /min @ 15.3 MPa (38,200 scfm @ 2,215 psia) 1,186 m 3 

### /min @ 15.3 MPa (41,900 scfm @ 2,215 psia) 4 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 215 MW 230 MW 2 0

2 Gas Turbine Generator TEWAC 240 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

ACCOUNT 7 HRSG, DUCTING AND STACK Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.7 m (2 0 ft) diameter 76 m (250 ft) high x 8.7 m (2 0 ft) diameter 2 0

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 248,798 kg/hr, 12.4 MPa/533°C

(548,505 lb/hr, 1,800 psig/992°F) Reheat steam

- 312,480 kg/hr, 3.1 MPa/533°C

(688,900 lb/hr, 452 psig/992°F) Main steam

- 260,051 kg/hr, 12.4 MPa/532°C

(573,314 lb/hr, 1,800 psig/990°F) Reheat steam

- 358,821 kg/hr, 3.1 MPa/532°C

(791,066 lb/hr, 452 psig/990°F) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

177 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Steam Turbine Commercially available 245 MW 12.4 MPa/533°C/533°C (1

, 800 psig/ 992°F/992°F) 270 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 270 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 Surface Condenser Single pass, divided waterbox including vacuum
pumps 728 GJ/hr (690 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 791 GJ/hr (750 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C ( 20°F) 1 0

4 Air

- cooled Condenser --- 728 GJ/hr (690 MMBtu/hr), Condensing temperature

32°C (90°F), Ambient temperature 6°C (42°F) 791 GJ/hr (750 MMBtu/hr), Condensing temperature

32°C (90°F), Ambient temperature 4°C (40°F) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

178 

### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Circulating Water Pumps Vertical, wet pit 272,550 lpm @ 30 m (72,000 gpm @ 100 ft) 340,687 lpm @ 30 m (90,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) wet bulb / 9°C (48°F) CWT / 20°C (68°F) HWT / 1530 GJ/hr (1450

MMBtu/hr) heat duty 2°C (36°F) wet bulb / 8°C (47°F) CWT / 19°C (67°F) HWT / 1899 GJ/hr (1800

MMBtu/hr) heat duty 1 0

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 234,696 liters (62,000 gal) 389,897 liters (103,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0
3 Slag Depressurizer Proprietary 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 140,060 liters (37,000 gal) 234,696 liters (62,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 105,992 liters (28,000 gal) 2

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 21 tonne/hr (23 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 200,627 liters (53,000 gal) 333,116 liters (88,000 gal) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

179 

### Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 76 lpm @ 14 m H 2 

### O (20 gpm @ 46 ft H 2 

### O) 2 2

11 Grey Water Storage Tank Field erected 64,352 liters (17,000 gal) 105,992 liters (28,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H 2 

### O (60 gpm @ 1,420 ft H 2 

### O) 379 lpm @ 433 m H 2 

### O (100 gpm @ 1,420 ft H 2 

### O) 2 2

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 1,451 tonne (1,600 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 172 tonne/hr (190 tph) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

180 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 240 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, 270 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, 81 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 91 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 47 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 53 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 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

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 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

181 

### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type S1 B Design Condition L1 B Design Condition Operating Qty Spares

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 0

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

182 

### 3.2.11 Case S1 B and L1 B Cost Estimating

Costs Results The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 48 shows the TPC summary organized by cost account for the PRB coal case ( S1B) and Exhibit 3

- 52 shows the same information for the lignite coal case (L1B). A more detailed breakdown of the capital costs is shown in Exhibit 3

- 49 for S1B and Exhibit 3

- 53 for L1B. Exhibit 3

- 50 and Exhibit 3

- 54 show the calculation and addition of owner’s costs to determine the TOC , used to calculate COE. Exhibit 3

- 51 shows the initial and annual O&M costs for Case S1B and Exhibit 3

- 55 shows the same in formation for Case L1B.

The estimated T O C of SCGP with CO 2 

### capture using PRB coal is $ 4
, 25 3 /kW and using lignite coal is $ 4
, 378 /kW. Process contingency represents about 3 percent
, project contingency 1 2 percent , and owner’s costs 18 percent of TOC for bot h cases. The COE is 119.7 mills/kWh in the PRB case and 12 1

. 9 mills/kWh in the lignite case.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

183 

### Exhibit 3

- 48 Case S1 B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S1B - Shell IGCC w/ CO2 Plant Size: 471.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $16,015 $2,976 $12,420 $0 $0 $31,412 $2,851 $0 $6,853 $41,115 $87

2 COAL & SORBENT PREP & FEED $120,801 $10,066 $20,611 $0 $0 $151,477 $13,141 $0 $32,924 $197,542 $419

3 FEEDWATER & MISC. BOP SYSTEMS $7,824 $6,231 $7,649 $0 $0 $21,705 $2,046 $0 $5,466 $29,217 $62

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $154,035 $0 $65,678 $0 $0 $219,713 $19,628 $30,204 $41,437 $310,981 $659 4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $182,062 $0 w/equip. $0 $0 $182,062 $17,647 $0 $19,971 $219,680 $466 4.4-4.9 Other Gasification Equipment $24,921 $10,768 $15,384 $0 $0 $51,072 $4,892 $0 $11,994 $67,958 $144 SUBTOTAL 4 $361,019 $10,768 $81,062 $0 $0 $452,848 $42,168 $30,204 $73,401 $598,620 $1,269

5A GAS CLEANUP & PIPING $85,262 $3,037 $70,594 $0 $0 $158,893 $15,346 $25,676 $40,132 $240,047 $509

5B CO2 COMPRESSION $18,189 $0 $10,541 $0 $0 $28,730 $2,766 $0 $6,299 $37,795 $80

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $275 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $280

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $31,403 $0 $4,465 $0 $0 $35,869 $3,410 $0 $3,928 $43,207 $92 7.2-7.9 SCR System, Ductwork and Stack $3,524 $2,513 $3,324 $0 $0 $9,361 $868 $0 $1,666 $11,895 $25 SUBTOTAL 7 $34,928 $2,513 $7,789 $0 $0 $45,230 $4,279 $0 $5,594 $55,102 $117

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $25,807 $0 $4,350 $0 $0 $30,157 $2,893 $0 $3,305 $36,355 $77 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $32,695 $883 $10,769 $0 $0 $44,347 $4,309 $0 $9,892 $58,547 $124 SUBTOTAL 8 $58,502 $883 $15,119 $0 $0 $74,504 $7,202 $0 $13,197 $94,903 $201

9 COOLING WATER SYSTEM $7,191 $7,127 $6,051 $0 $0 $20,369 $1,892 $0 $4,564 $26,824 $57

10 ASH/SPENT SORBENT HANDLING SYS $19,291 $1,481 $9,573 $0 $0 $30,345 $2,911 $0 $3,632 $36,888 $78

11 ACCESSORY ELECTRIC PLANT $31,184 $12,483 $24,269 $0 $0 $67,936 $5,844 $0 $14,034 $87,815 $186

12 INSTRUMENTATION & CONTROL $10,989 $2,022 $7,081 $0 $0 $20,092 $1,821 $1,005 $3,818 $26,736 $57

13 IMPROVEMENTS TO SITE $3,322 $1,958 $8,196 $0 $0 $13,476 $1,331 $0 $4,442 $19,249 $41

14 BUILDINGS & STRUCTURES $0 $6,408 $7,287 $0 $0 $13,694 $1,246 $0 $2,455 $17,396 $37

TOTAL COST $866,544 $68,758 $295,716 $0 $0 $1,231,019 $114,350 $66,745 $229,150 $1,641,264 $3,480 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

184 

### Exhibit 3

- 49 Case S1 B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S1B - Shell IGCC w/ CO2 Plant Size: 471.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,206 $0 $2,055 $0 $0 $6,261 $561 $0 $1,364 $8,186 $17 1.2 Coal Stackout & Reclaim $5,435 $0 $1,318 $0 $0 $6,752 $592 $0 $1,469 $8,813 $19 1.3 Coal Conveyors & Yd Crush $5,053 $0 $1,304 $0 $0 $6,357 $558 $0 $1,383 $8,298 $18
1.4 Other Coal Handling $1,322 $0 $302 $0 $0 $1,624 $142 $0 $353 $2,119 $4 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $2,976 $7,442 $0 $0 $10,418 $999 $0 $2,283 $13,700 $29 SUBTOTAL 1. $16,015 $2,976 $12,420 $0 $0 $31,412 $2,851 $0 $6,853 $41,115 $87
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $48,633 $2,922 $7,086 $0 $0 $58,641 $5,060 $0 $12,740 $76,442 $162 2.2 Prepared Coal Storage & Feed $2,091 $500 $328 $0 $0 $2,919 $250 $0 $634 $3,802 $8 2.3 Dry Coal Injection System $68,810 $799 $6,390 $0 $0 $75,999 $6,546 $0 $16,509 $99,054 $210 2.4 Misc.Coal Prep & Feed $1,267 $922 $2,764 $0 $0 $4,952 $455 $0 $1,081 $6,489 $14 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $4,924 $4,042 $0 $0 $8,966 $830 $0 $1,959 $11,756 $25 SUBTOTAL 2. $120,801 $10,066 $20,611 $0 $0 $151,477 $13,141 $0 $32,924 $197,542 $419 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,263 $3,887 $2,052 $0 $0 $8,203 $760 $0 $1,792 $10,755 $23 3.2 Water Makeup & Pretreating $491 $51 $274 $0 $0 $816 $78 $0 $268 $1,162 $2 3.3 Other Feedwater Subsystems $1,238 $418 $377 $0 $0 $2,034 $183 $0 $443 $2,660 $6 3.4 Service Water Systems $281 $578 $2,006 $0 $0 $2,865 $279 $0 $943 $4,088 $9 3.5 Other Boiler Plant Systems $1,506 $584 $1,447 $0 $0 $3,537 $335 $0 $774 $4,647 $10 3.6 FO Supply Sys & Nat Gas $303 $571 $533 $0 $0 $1,407 $136 $0 $308 $1,851 $4 3.7 Waste Treatment Equipment $686 $0 $418 $0 $0 $1,104 $108 $0 $363 $1,575 $3 3.8 Misc. Power Plant Equipment $1,057 $141 $542 $0 $0 $1,740 $168 $0 $573 $2,481 $5 SUBTOTAL 3. $7,824 $6,231 $7,649 $0 $0 $21,705 $2,046 $0 $5,466 $29,217 $62
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $154,035 $0 $65,678 $0 $0 $219,713 $19,628 $30,204 $41,437 $310,981 $659 4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $182,062 $0 w/equip. $0 $0 $182,062 $17,647 $0 $19,971 $219,680 $466
4.4 LT Heat Recovery & FG Saturation $24,921 $0 $9,474 $0 $0 $34,395 $3,357 $0 $7,550 $45,302 $96 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,428 $581 $0 $0 $2,009 $193 $0 $440 $2,642 $6 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $9,340 $5,329 $0 $0 $14,669 $1,343 $0 $4,003 $20,014 $42 SUBTOTAL 4. $361,019 $10,768 $81,062 $0 $0 $452,848 $42,168 $30,204 $73,401 $598,620 $1,269 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

185 

### Exhibit 3

- 49 Case S1B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S1B - Shell IGCC w/ CO2 Plant Size: 471.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $69,120 $0 $58,650 $0 $0 $127,770 $12,357 $25,554 $33,136 $198,817 $422 5A.2 Elemental Sulfur Plant $5,103 $1,017 $6,584 $0 $0 $12,704 $1,234 $0 $2,788 $16,725 $35 5A.3 Mercury Removal $1,388 $0 $1,056 $0 $0 $2,444 $236 $122 $560 $3,362 $7 5A.4 Shift Reactors $7,422 $0 $2,988 $0 $0 $10,410 $998 $0 $2,282 $13,690 $29 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $2,228 $375 $211 $0 $0 $2,815 $267 $0 $616 $3,698 $8 5A.6 Fuel Gas Piping $0 $817 $572 $0 $0 $1,390 $129 $0 $304 $1,822 $4 5A.9 HGCU Foundations $0 $828 $534 $0 $0 $1,361 $125 $0 $446 $1,932 $4 SUBTOTAL 5A. $85,262 $3,037 $70,594 $0 $0 $158,893 $15,346 $25,676 $40,132 $240,047 $509 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $18,189 $0 $10,541 $0 $0 $28,730 $2,766 $0 $6,299 $37,795 $80 SUBTOTAL 5B. $18,189 $0 $10,541 $0 $0 $28,730 $2,766 $0 $6,299 $37,795 $80
6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $275 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $280
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $31,403 $0 $4,465 $0 $0 $35,869 $3,410 $0 $3,928 $43,207 $92 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,807 $1,322 $0 $0 $3,128 $275 $0 $681 $4,084 $9
7.4 Stack $3,524 $0 $1,324 $0 $0 $4,849 $465 $0 $531 $5,844 $12 7.9 HRSG,Duct & Stack Foundations $0 $706 $678 $0 $0 $1,384 $129 $0 $454 $1,967 $4 SUBTOTAL 7. $34,928 $2,513 $7,789 $0 $0 $45,230 $4,279 $0 $5,594 $55,102 $117 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $25,807 $0 $4,350 $0 $0 $30,157 $2,893 $0 $3,305 $36,355 $77 8.2 Turbine Plant Auxiliaries $178 $0 $408 $0 $0 $586 $57 $0 $64 $708 $2 8.3a Condenser & Auxiliaries $2,805 $0 $896 $0 $0 $3,701 $354 $0 $405 $4,460 $9 8.3b Air Cooled Condenser $25,704 $0 $5,153 $0 $0 $30,857 $3,086 $0 $6,788 $40,731 $86 8.4 Steam Piping $4,008 $0 $2,820 $0 $0 $6,828 $587 $0 $1,854 $9,268 $20 8.9 TG Foundations $0 $883 $1,492 $0 $0 $2,375 $225 $0 $780 $3,381 $7 SUBTOTAL 8. $58,502 $883 $15,119 $0 $0 $74,504 $7,202 $0 $13,197 $94,903 $201
9 COOLING WATER SYSTEM 9.1 Cooling Towers $4,957 $0 $902 $0 $0 $5,858 $558 $0 $962 $7,378 $16 9.2 Circulating Water Pumps $1,283 $0 $79 $0 $0 $1,362 $115 $0 $222 $1,698 $4 9.3 Circ.Water System Auxiliaries $113 $0 $16 $0 $0 $129 $12 $0 $21 $163 $0 9.4 Circ.Water Piping $0 $4,723 $1,224 $0 $0 $5,948 $538 $0 $1,297 $7,782 $17 9.5 Make-up Water System $281 $0 $402 $0 $0 $684 $66 $0 $150 $899 $2 9.6 Component Cooling Water Sys $558 $667 $474 $0 $0 $1,699 $159 $0 $372 $2,230 $5 9.9 Circ.Water System Foundations $0 $1,737 $2,952 $0 $0 $4,689 $445 $0 $1,540 $6,674 $14 SUBTOTAL 9. $7,191 $7,127 $6,051 $0 $0 $20,369 $1,892 $0 $4,564 $26,824 $57 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

186 

### Exhibit 3

- 49 Case S1B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S1B - Shell IGCC w/ CO2 Plant Size: 471.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $16,803 $0 $8,287 $0 $0 $25,090 $2,411 $0 $2,750 $30,251 $64 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $564 $0 $614 $0 $0 $1,177 $114 $0 $194 $1,485 $3 10.7 Ash Transport & Feed Equipment $756 $0 $182 $0 $0 $939 $88 $0 $154 $1,180 $3 10.8 Misc. Ash Handling Equipment $1,168 $1,431 $428 $0 $0 $3,027 $288 $0 $497 $3,812 $8 10.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $112 $11 $0 $37 $160 $0 SUBTOTAL 10. $19,291 $1,481 $9,573 $0 $0 $30,345 $2,911 $0 $3,632 $36,888 $78
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $893 $0 $883 $0 $0 $1,776 $170 $0 $195 $2,140 $5 11.2 Station Service Equipment $4,675 $0 $421 $0 $0 $5,096 $470 $0 $557 $6,122 $13 11.3 Switchgear & Motor Control $8,642 $0 $1,572 $0 $0 $10,214 $947 $0 $1,674 $12,835 $27
11.4 Conduit & Cable Tray $0 $4,015 $13,244 $0 $0 $17,258 $1,669 $0 $4,732 $23,659 $50 11.5 Wire & Cable $0 $7,670 $5,040 $0 $0 $12,710 $923 $0 $3,408 $17,042 $36 11.6 Protective Equipment $0 $653 $2,375 $0 $0 $3,028 $296 $0 $499 $3,822 $8
11.7 Standby Equipment $223 $0 $217 $0 $0 $440 $42 $0 $72 $554 $1 11.8 Main Power Transformers $16,752 $0 $134 $0 $0 $16,886 $1,277 $0 $2,724 $20,887 $44 11.9 Electrical Foundations $0 $146 $382 $0 $0 $528 $51 $0 $174 $752 $2 SUBTOTAL 11. $31,184 $12,483 $24,269 $0 $0 $67,936 $5,844 $0 $14,034 $87,815 $186
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,085 $0 $724 $0 $0 $1,809 $171 $90 $311 $2,382 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $249 $0 $160 $0 $0 $409 $39 $20 $94 $562 $1 12.7 Computer & Accessories $5,787 $0 $185 $0 $0 $5,972 $548 $299 $682 $7,501 $16 12.8 Instrument Wiring & Tubing $0 $2,022 $4,133 $0 $0 $6,154 $522 $308 $1,746 $8,730 $19 12.9 Other I & C Equipment $3,868 $0 $1,878 $0 $0 $5,747 $541 $287 $986 $7,561 $16 SUBTOTAL 12. $10,989 $2,022 $7,081 $0 $0 $20,092 $1,821 $1,005 $3,818 $26,736 $57 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $104 $2,228 $0 $0 $2,332 $232 $0 $769 $3,332 $7 13.2 Site Improvements $0 $1,854 $2,463 $0 $0 $4,317 $426 $0 $1,423 $6,166 $13 13.3 Site Facilities $3,322 $0 $3,505 $0 $0 $6,827 $673 $0 $2,250 $9,750 $21 SUBTOTAL 13. $3,322 $1,958 $8,196 $0 $0 $13,476 $1,331 $0 $4,442 $19,249 $41
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,205 $3,142 $0 $0 $5,347 $492 $0 $876 $6,714 $14 14.3 Administration Building $0 $856 $621 $0 $0 $1,477 $132 $0 $241 $1,850 $4
14.4 Circulation Water Pumphouse $0 $160 $85 $0 $0 $245 $21 $0 $40 $306 $1 14.5 Water Treatment Buildings $0 $410 $400 $0 $0 $810 $73 $0 $132 $1,016 $2 14.6 Machine Shop $0 $438 $300 $0 $0 $738 $66 $0 $121 $924 $2
14.7 Warehouse $0 $707 $457 $0 $0 $1,164 $103 $0 $190 $1,457 $3 14.8 Other Buildings & Structures $0 $422 $329 $0 $0 $751 $67 $0 $164 $982 $2 14.9 Waste Treating Building & Str. $0 $944 $1,804 $0 $0 $2,748 $256 $0 $601 $3,605 $8 SUBTOTAL 14. $0 $6,408 $7,287 $0 $0 $13,694 $1,246 $0 $2,455 $17,396 $37

TOTAL COST $866,544 $68,758 $295,716 $0 $0 $1,231,019 $114,350 $66,745 $229,150 $1,641,264 $3,480 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

187 

### Exhibit 3

- 50 Case S1B Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $13,825 $29 1 Month Variable O&M $3,642 $8 25% of 1 Months Fuel Cost at 100% CF $814 $2 2% of TPC $32,825 $70 Total $51,106 $108

Inventory Capital 60 day supply of consumables at 100% CF $6,943 $15 0.5% of TPC (spare parts) $8,206 $17 Total $15,150 $32

Initial Cost for Catalyst and Chemicals $6,959 $15 Land $900 $2 Other Owner's Costs $246,190 $522 Financing Costs $44,314 $94

Total Owner's Costs $364,619 $773 Total Overnight Cost (TOC) $2,005,883 $4,253 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $2,286,707 $4,849Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

188 

### Exhibit 3

- 51 Case S1 B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case S1B - Shell IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10641 MWe-net: 472 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $13.387 Maintenance Labor Cost $15,805,936 $33.515 Administrative & Support Labor $5,529,861 $11.725 Property Taxes and Insurance $32,825,287 $69.603 TOTAL FIXED OPERATING COSTS $60,474,591 $128.230 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $29,588,685 $0.00895

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 2,451 1.08 $0 $774,109 $0.00023

Chemicals

MU & WT Chem.(lbs) 0 14,602 0.17 $0 $737,906 $0.00022 Carbon (Mercury Removal) (lb) 116,627 160 1.05 $122,478 $48,991 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,034 4.13 498.83 $3,009,845 $601,969 $0.00018 Selexol Solution (gal) 285,640 91 13.40 $3,827,073 $355,483 $0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.77 131.27 $0 $29,430 $0.00001 Subtotal Chemicals $6,959,397 $1,773,780 $0.00054

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 160 0.42 $0 $19,457 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 593 16.23 $0 $2,811,013 $0.00085 Subtotal Waste Disposal $0 $2,830,470 $0.00086

By-products & Emissions

Sulfur (tons) 0 51 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $6,959,397 $34,967,044 $0.01058

Fuel (ton) 0 7,032 15.22 $0 $31,243,745 $0.00945Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

189 

### Exhibit 3

- 52 Case L1 B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-20 Project: Low Rank Western Coal Baseline Study

Case: Case L1B - Shell IGCC w/ CO2 Plant Size: 500.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $19,636 $3,649 $15,228 $0 $0 $38,513 $3,496 $0 $8,402 $50,410 $101

2 COAL & SORBENT PREP & FEED $147,143 $12,451 $25,327 $0 $0 $184,922 $16,045 $0 $40,193 $241,160 $482

3 FEEDWATER & MISC. BOP SYSTEMS $8,297 $6,517 $8,203 $0 $0 $23,016 $2,171 $0 $5,817 $31,004 $62

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $162,263 $0 $69,450 $0 $0 $231,713 $20,694 $32,004 $43,666 $328,076 $656 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $198,128 $0 w/equip. $0 $0 $198,128 $19,204 $0 $21,733 $239,066 $478 4.4-4.9 Other Gasification Equipment $26,410 $12,329 $16,813 $0 $0 $55,552 $5,316 $0 $13,093 $73,961 $148 SUBTOTAL 4 $386,801 $12,329 $86,263 $0 $0 $485,393 $45,214 $32,004 $78,493 $641,103 $1,282

5A GAS CLEANUP & PIPING $91,544 $3,296 $75,944 $0 $0 $170,784 $16,495 $27,522 $43,117 $257,918 $516

5B CO2 COMPRESSION $20,109 $0 $11,415 $0 $0 $31,524 $3,034 $0 $6,912 $41,470 $83

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $259 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $264

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,673 $0 $4,646 $0 $0 $37,319 $3,548 $0 $4,087 $44,954 $90 7.2-7.9 SCR System, Ductwork and Stack $3,522 $2,511 $3,322 $0 $0 $9,355 $867 $0 $1,665 $11,887 $24 SUBTOTAL 7 $36,195 $2,511 $7,967 $0 $0 $46,673 $4,416 $0 $5,751 $56,840 $114

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $27,623 $0 $4,708 $0 $0 $32,332 $3,102 $0 $3,543 $38,977 $78 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $34,547 $949 $11,364 $0 $0 $46,860 $4,555 $0 $10,446 $61,862 $124 SUBTOTAL 8 $62,171 $949 $16,072 $0 $0 $79,192 $7,657 $0 $13,989 $100,839 $202

9 COOLING WATER SYSTEM $8,339 $8,139 $6,908 $0 $0 $23,386 $2,172 $0 $5,228 $30,786 $62

10 ASH/SPENT SORBENT HANDLING SYS $26,501 $1,960 $13,147 $0 $0 $41,608 $3,992 $0 $4,965 $50,565 $101

11 ACCESSORY ELECTRIC PLANT $33,167 $13,157 $25,566 $0 $0 $71,890 $6,181 $0 $14,839 $92,909 $186

12 INSTRUMENTATION & CONTROL $11,243 $2,068 $7,244 $0 $0 $20,556 $1,863 $1,028 $3,907 $27,353 $55

13 IMPROVEMENTS TO SITE $3,438 $2,027 $8,484 $0 $0 $13,949 $1,377 $0 $4,598 $19,924 $40

14 BUILDINGS & STRUCTURES $0 $6,664 $7,603 $0 $0 $14,267 $1,299 $0 $2,553 $18,120 $36

TOTAL COST $946,611 $76,524 $322,846 $0 $0 $1,345,980 $124,918 $70,414 $251,103 $1,792,415 $3,584 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

190 

### Exhibit 3

- 53 Case L1 B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2010-Jan-20 Project: Low Rank Western Coal Baseline Study

Case: Case L1B - Shell IGCC w/ CO2 Plant Size: 500.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $5,157 $0 $2,520 $0 $0 $7,676 $688 $0 $1,673 $10,037 $20 1.2 Coal Stackout & Reclaim $6,663 $0 $1,615 $0 $0 $8,279 $726 $0 $1,801 $10,805 $22 1.3 Coal Conveyors & Yd Crush $6,195 $0 $1,598 $0 $0 $7,794 $684 $0 $1,696 $10,173 $20
1.4 Other Coal Handling $1,621 $0 $370 $0 $0 $1,991 $174 $0 $433 $2,598 $5 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $3,649 $9,124 $0 $0 $12,773 $1,224 $0 $2,799 $16,797 $34 SUBTOTAL 1. $19,636 $3,649 $15,228 $0 $0 $38,513 $3,496 $0 $8,402 $50,410 $101
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $60,417 $3,629 $8,803 $0 $0 $72,849 $6,286 $0 $15,827 $94,963 $190 2.2 Prepared Coal Storage & Feed $2,511 $601 $394 $0 $0 $3,506 $300 $0 $761 $4,567 $9 2.3 Dry Coal Injection System $82,642 $959 $7,675 $0 $0 $91,276 $7,861 $0 $19,828 $118,965 $238 2.4 Misc.Coal Prep & Feed $1,574 $1,145 $3,433 $0 $0 $6,152 $565 $0 $1,344 $8,061 $16 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $6,117 $5,022 $0 $0 $11,138 $1,032 $0 $2,434 $14,604 $29 SUBTOTAL 2. $147,143 $12,451 $25,327 $0 $0 $184,922 $16,045 $0 $40,193 $241,160 $482 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,329 $4,000 $2,112 $0 $0 $8,441 $782 $0 $1,845 $11,068 $22 3.2 Water Makeup & Pretreating $542 $57 $303 $0 $0 $901 $86 $0 $296 $1,284 $3 3.3 Other Feedwater Subsystems $1,274 $431 $388 $0 $0 $2,093 $188 $0 $456 $2,737 $5 3.4 Service Water Systems $310 $639 $2,216 $0 $0 $3,165 $309 $0 $1,042 $4,516 $9 3.5 Other Boiler Plant Systems $1,664 $645 $1,598 $0 $0 $3,907 $371 $0 $856 $5,134 $10 3.6 FO Supply Sys & Nat Gas $317 $598 $558 $0 $0 $1,472 $142 $0 $323 $1,937 $4 3.7 Waste Treatment Equipment $758 $0 $462 $0 $0 $1,220 $119 $0 $402 $1,740 $3 3.8 Misc. Power Plant Equipment $1,103 $148 $566 $0 $0 $1,817 $175 $0 $598 $2,589 $5 SUBTOTAL 3. $8,297 $6,517 $8,203 $0 $0 $23,016 $2,171 $0 $5,817 $31,004 $62
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $162,263 $0 $69,450 $0 $0 $231,713 $20,694 $32,004 $43,666 $328,076 $656 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $198,128 $0 w/equip. $0 $0 $198,128 $19,204 $0 $21,733 $239,066 $478
4.4 LT Heat Recovery & FG Saturation $26,410 $0 $10,040 $0 $0 $36,450 $3,557 $0 $8,001 $48,008 $96 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,599 $651 $0 $0 $2,250 $216 $0 $493 $2,959 $6 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $10,730 $6,122 $0 $0 $16,852 $1,543 $0 $4,599 $22,993 $46 SUBTOTAL 4. $386,801 $12,329 $86,263 $0 $0 $485,393 $45,214 $32,004 $78,493 $641,103 $1,282 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

191 

### Exhibit 3

- 53 Case L1B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2010-Jan-20 Project: Low Rank Western Coal Baseline Study

Case: Case L1B - Shell IGCC w/ CO2 Plant Size: 500.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $74,094 $0 $62,870 $0 $0 $136,964 $13,246 $27,393 $35,521 $213,123 $426 5A.2 Elemental Sulfur Plant $5,754 $1,147 $7,423 $0 $0 $14,324 $1,391 $0 $3,143 $18,858 $38 5A.3 Mercury Removal $1,465 $0 $1,115 $0 $0 $2,580 $249 $129 $592 $3,549 $7 5A.4 Shift Reactors $7,788 $0 $3,135 $0 $0 $10,923 $1,047 $0 $2,394 $14,364 $29 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $2,444 $411 $232 $0 $0 $3,086 $293 $0 $676 $4,055 $8 5A.6 Fuel Gas Piping $0 $864 $605 $0 $0 $1,469 $136 $0 $321 $1,926 $4 5A.9 HGCU Foundations $0 $875 $564 $0 $0 $1,439 $132 $0 $471 $2,042 $4 SUBTOTAL 5A. $91,544 $3,296 $75,944 $0 $0 $170,784 $16,495 $27,522 $43,117 $257,918 $516 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $20,109 $0 $11,415 $0 $0 $31,524 $3,034 $0 $6,912 $41,470 $83 SUBTOTAL 5B. $20,109 $0 $11,415 $0 $0 $31,524 $3,034 $0 $6,912 $41,470 $83
6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $259 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $264
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,673 $0 $4,646 $0 $0 $37,319 $3,548 $0 $4,087 $44,954 $90 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,805 $1,321 $0 $0 $3,126 $275 $0 $680 $4,081 $8
7.4 Stack $3,522 $0 $1,323 $0 $0 $4,845 $464 $0 $531 $5,840 $12 7.9 HRSG,Duct & Stack Foundations $0 $706 $678 $0 $0 $1,383 $129 $0 $454 $1,966 $4 SUBTOTAL 7. $36,195 $2,511 $7,967 $0 $0 $46,673 $4,416 $0 $5,751 $56,840 $114 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $27,623 $0 $4,708 $0 $0 $32,332 $3,102 $0 $3,543 $38,977 $78 8.2 Turbine Plant Auxiliaries $191 $0 $439 $0 $0 $630 $62 $0 $69 $761 $2 8.3a Condenser & Auxiliaries $2,973 $0 $950 $0 $0 $3,923 $375 $0 $430 $4,728 $9 8.3b Air Cooled Condenser $27,249 $0 $5,463 $0 $0 $32,711 $3,271 $0 $7,197 $43,179 $86 8.4 Steam Piping $4,134 $0 $2,908 $0 $0 $7,043 $605 $0 $1,912 $9,559 $19 8.9 TG Foundations $0 $949 $1,604 $0 $0 $2,553 $242 $0 $839 $3,634 $7 SUBTOTAL 8. $62,171 $949 $16,072 $0 $0 $79,192 $7,657 $0 $13,989 $100,839 $202
9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,766 $0 $1,049 $0 $0 $6,815 $649 $0 $1,120 $8,584 $17 9.2 Circulating Water Pumps $1,500 $0 $99 $0 $0 $1,599 $135 $0 $260 $1,993 $4 9.3 Circ.Water System Auxiliaries $129 $0 $18 $0 $0 $148 $14 $0 $24 $186 $0 9.4 Circ.Water Piping $0 $5,400 $1,400 $0 $0 $6,800 $615 $0 $1,483 $8,897 $18 9.5 Make-up Water System $306 $0 $438 $0 $0 $744 $71 $0 $163 $978 $2 9.6 Component Cooling Water Sys $637 $762 $542 $0 $0 $1,942 $182 $0 $425 $2,549 $5 9.9 Circ.Water System Foundations $0 $1,977 $3,361 $0 $0 $5,339 $506 $0 $1,753 $7,598 $15 SUBTOTAL 9. $8,339 $8,139 $6,908 $0 $0 $23,386 $2,172 $0 $5,228 $30,786 $62 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

192 

### Exhibit 3

- 53 Case L1B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2010-Jan-20 Project: Low Rank Western Coal Baseline Study

Case: Case L1B - Shell IGCC w/ CO2 Plant Size: 500.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $23,209 $0 $11,445 $0 $0 $34,654 $3,330 $0 $3,798 $41,782 $84 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $746 $0 $812 $0 $0 $1,558 $151 $0 $256 $1,965 $4 10.7 Ash Transport & Feed Equipment $1,001 $0 $241 $0 $0 $1,242 $116 $0 $204 $1,562 $3 10.8 Misc. Ash Handling Equipment $1,545 $1,894 $566 $0 $0 $4,005 $381 $0 $658 $5,044 $10 10.9 Ash/Spent Sorbent Foundation $0 $66 $83 $0 $0 $149 $14 $0 $49 $212 $0 SUBTOTAL 10. $26,501 $1,960 $13,147 $0 $0 $41,608 $3,992 $0 $4,965 $50,565 $101
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $932 $0 $922 $0 $0 $1,853 $177 $0 $203 $2,233 $4 11.2 Station Service Equipment $4,926 $0 $444 $0 $0 $5,370 $495 $0 $587 $6,452 $13 11.3 Switchgear & Motor Control $9,108 $0 $1,656 $0 $0 $10,764 $998 $0 $1,764 $13,527 $27
11.4 Conduit & Cable Tray $0 $4,231 $13,957 $0 $0 $18,188 $1,759 $0 $4,987 $24,934 $50 11.5 Wire & Cable $0 $8,084 $5,311 $0 $0 $13,395 $973 $0 $3,592 $17,960 $36 11.6 Protective Equipment $0 $689 $2,507 $0 $0 $3,196 $312 $0 $526 $4,035 $8
11.7 Standby Equipment $230 $0 $225 $0 $0 $455 $43 $0 $75 $574 $1 11.8 Main Power Transformers $17,971 $0 $141 $0 $0 $18,112 $1,370 $0 $2,922 $22,404 $45 11.9 Electrical Foundations $0 $153 $402 $0 $0 $555 $53 $0 $183 $791 $2 SUBTOTAL 11. $33,167 $13,157 $25,566 $0 $0 $71,890 $6,181 $0 $14,839 $92,909 $186
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,110 $0 $741 $0 $0 $1,851 $175 $93 $318 $2,437 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $255 $0 $164 $0 $0 $419 $40 $21 $96 $575 $1 12.7 Computer & Accessories $5,921 $0 $190 $0 $0 $6,110 $561 $306 $698 $7,674 $15 12.8 Instrument Wiring & Tubing $0 $2,068 $4,228 $0 $0 $6,296 $534 $315 $1,786 $8,932 $18 12.9 Other I & C Equipment $3,958 $0 $1,922 $0 $0 $5,879 $553 $294 $1,009 $7,736 $15 SUBTOTAL 12. $11,243 $2,068 $7,244 $0 $0 $20,556 $1,863 $1,028 $3,907 $27,353 $55 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $108 $2,306 $0 $0 $2,414 $240 $0 $796 $3,449 $7 13.2 Site Improvements $0 $1,919 $2,550 $0 $0 $4,469 $441 $0 $1,473 $6,382 $13 13.3 Site Facilities $3,438 $0 $3,628 $0 $0 $7,067 $697 $0 $2,329 $10,092 $20 SUBTOTAL 13. $3,438 $2,027 $8,484 $0 $0 $13,949 $1,377 $0 $4,598 $19,924 $40
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,340 $3,334 $0 $0 $5,674 $522 $0 $929 $7,125 $14 14.3 Administration Building $0 $874 $634 $0 $0 $1,508 $134 $0 $246 $1,888 $4
14.4 Circulation Water Pumphouse $0 $164 $87 $0 $0 $251 $22 $0 $41 $314 $1 14.5 Water Treatment Buildings $0 $453 $442 $0 $0 $895 $81 $0 $146 $1,122 $2 14.6 Machine Shop $0 $447 $306 $0 $0 $753 $67 $0 $123 $943 $2
14.7 Warehouse $0 $722 $466 $0 $0 $1,188 $105 $0 $194 $1,488 $3 14.8 Other Buildings & Structures $0 $433 $337 $0 $0 $769 $69 $0 $168 $1,006 $2 14.9 Waste Treating Building & Str. $0 $967 $1,848 $0 $0 $2,815 $262 $0 $615 $3,693 $7 SUBTOTAL 14. $0 $6,664 $7,603 $0 $0 $14,267 $1,299 $0 $2,553 $18,120 $36

TOTAL COST $946,611 $76,524 $322,846 $0 $0 $1,345,980 $124,918 $70,414 $251,103 $1,792,415 $3,584 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

193 

### E xhibit 3

- 54 Case L1B Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $14,586 $29 1 Month Variable O&M $4,058 $8 25% of 1 Months Fuel Cost at 100% CF $811 $2 2% of TPC $35,848 $72 Total $55,303 $111

Inventory Capital 60 day supply of consumables at 100% CF $6,987 $14 0.5% of TPC (spare parts) $8,962 $18 Total $15,949 $32

Initial Cost for Catalyst and Chemicals $7,538 $15 Land $900 $2 Other Owner's Costs $268,862 $538 Financing Costs $48,395 $97

Total Owner's Costs $396,948 $794 Total Overnight Cost (TOC) $2,189,363 $4,378 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $2,495,874 $4,991Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

194 

### Exhibit 3

- 55 Case L1 B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case L1B - Shell IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,772 MWe-net: 500 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $12.625 Maintenance Labor Cost $17,024,604 $34.045 Administrative & Support Labor $5,834,528 $11.668 Property Taxes and Insurance $35,848,299 $71.688 TOTAL FIXED OPERATING COSTS $65,020,938 $130.026 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $31,416,690 $0.00896

Consumables Consumption Unit Initial Initial Fill /Day Cost Cost

Water (/1000 gallons) 0 2,820 1.08 $0 $890,771 $0.00025

Chemicals

MU & WT Chem.(lbs) 0 16,802 0.17 $0 $849,113 $0.00024 Carbon (Mercury Removal) (lb) 126,002 173 1.05 $132,324 $52,930 $0.00002 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,431 4.40 498.83 $3,207,993 $641,599 $0.00018 Selexol Solution (gal) 313,293 100 13.40 $4,197,575 $389,897 $0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.90 131.27 $0 $34,681 $0.00001 Subtotal Chemicals $7,537,892 $1,968,219 $0.00056

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 173 0.42 $0 $21,021 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 983 16.23 $0 $4,656,048 $0.00133 Subtotal Waste Disposal $0 $4,677,069 $0.00133

By-products & Emissions

Sulfur (tons) 0 61 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,537,892 $38,952,749 $0.01112

Fuel (ton) 0 9,768 10.92 $0 $31,146,334 $0.00889Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

195 

### 3.3 TRIG TM IGCC CASES

This section contains an evaluation of plant designs for Cases S2A and S2B

, which are based on the TRIG TM transport gasifier, developed by Kellog g Brown and Root (KBR) and Southern Company. Cases S2A and S2B are very similar in terms of process, equipment, scope and arrangement, e xcept that Case S2B includes SGS reactors, CO 2 

### absorption/regeneration and compression/transport systems.

Section 3.3.4 covers the results for the S2A non

- captur e case using PRB coal and Section 3.3.8 covers the S2B CO 2 

### - capture case using PRB coal. The sections are organized analogously as follows:

**•** Process and System Description provides an overview of the specific technolog y’s operation.

**•** BF D and stream table display results for major processes and streams

**•** Performance Results provides the main modeling results, including the performance summary, environmental performance, carbon balance, sulfur balance, water balance, mass and energy balance diagrams

, and mass and energy balance tables.

**•** Equipment List provides an itemized list of major equipment with account codes that correspond to the cost accounts in the Cos t Estimates section.

**•** Cost Estimates provides a summary of capital and operating costs.

Process and System Description, Performance Results, Equipment List and Cost Estimates are repeated for Case S2B in Section 3.3.8 . If the information is identical to that presented for the

non

- capture cases, a reference is made to the earlier section rather than repeating the information.

3.3.1 Gasifier Background

Development and Curren t Status

– The Transport Gasifier for IGCC applications is based on technology developed by KBR for fluid catalytic cracking for refineries. First deployed commercially in the late 1930’s in the petroleum refining industry, the transport gasifier has unde rgone major development, particularly coal applications for IGCC power generation at the Power Systems Development Facility (PSDF), near Willsonville, Alabama. The large scale pilot facility was established in 1995 to reduce the capital cost and increase the efficiency of advanced coal

- based power generation, while meeting strict environmental standards and providing data for commercial scale up.

With the collaboration of the U

. S

. D epartment o f E nergy (DOE) , EPRI, Southern Company, KBR, Siemens

- Westinghou se, and Peabody Holding company, the TRIGTM gasifier at the PSDF has been operat ed for over 1 5 ,000 hours, testing multiple fuels, including PRB and lignite coals, in both air blown and oxygen blown operation. Gasification was carried out under conditions o f 871 °C (1,600°F) to 982°C (1,800°F), pressures of up to 1.72 MPa g 

### (250 psig) and at coal feed rates from 1,13 0 kg/hr (2,500 lb/hr) to 2,2 70 kg/hr (5,000 lb/hr).Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

196 

### Based on the experience from the PSDF, Southern Company was prepared to construct an air

bl own, 275 MW Orlando Gasification Project firing PRB coal with co

- funding from the DOE CCPI

- 2 Program. All major contracts with the plant owners and partners were signed by January 2006 and the FEED and updated costs were completed in March 2007, with an e stimated startup in 2010. The project was converted to a natural gas feed during the construction phase because of uncertainty surrounding possible greenhouse gas (GHG) regulation for the state of Florida.

Current projects utilizing this technology include the Mississippi air

- blown IGCC owned by the Mississippi Power Company, proposed to generate 582 MW firing Mississippi lignite coal, with $133 million ( M ) of federal tax credits under the Energy Policy Act of 2005. Co

- funding from the cancelled DOE CCPI

- 2 project in Orlando was transferred to this project. The FEED and updated cost estimate was prepared by Southern Company and KBR with planned commercial operation in June 2013.

Gasifier Capacity

– Commercial scale units are in the design and cons truction phases, and the largest current TRIGTM installation is at the PSDF run by Southern Company, processing up to 50 tonne/day (55 tpd) of coal. The FEED work

, which was completed for the cancelled Orlando Gasification Project

, indicated gasification o f 2,99 0 tonne/day (3,300 tpd) of PRB coal that would have been used to fire a GE 7FA CT . This scale up is consistent with the size of the two gasifiers used for each of the TRIGTM cases in this study

. Distinguishing Characteristics

– The TRIGTM gasifier is a dry feed, fast CFB , non

- slagging, single stage gasifier producing syngas at moderate temperatures. The entire gasifier is constructed from refractory lined piping and vessels. Advantages of the TRIGTM coal gasification technology is it’s a small footpr int with a high thermal throughput, the ability to process a variety of high ash, high melting point coals, and its relatively high overall carbon conversion. The transport gasifier operates at higher circulation rates, velocities, and riser densities tha n a conventional circulating bed, resulting in higher throughput, mixing, heat and mass transfer. The dry feed non

- slagging gasifier allows the firing of high moisture and ash fuels such as sub

- bituminous and lignite coals.

The high circulation rates of t he transport gasifier results in a lower per pass carbon conversion compared to other gasifier technologies, but the unreacted carbon, along with the ash, is separated and recirculated to increase the overall carbon conversion. Larger coal particle sizes (up to 0.75” top size) are acceptable because of the high recirculation rate, which reduces the necessary coal preparation compared to other dry feed gasifier technologies. Ash removal is controlled to maintain a constant gasifier bed inventory, which aid s in transport, and is removed at the gasifier pressure, flowing through an ash cooler, then though a proprietary continuous pressure let

- down system. The ash is then moisturized with stripped water from the SWS to minimize dust emissions while it is bein g landfilled. Because of the non

- slagging design and dust removal, no black or gray water systems are required for transporting or disposing of theseCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

197 

### wastes. Due to the thorough mixing in the gasifier, the opportunity exists for in

- situ sulfur capture by injecting limestone du ring the gasification process , although that was not considered in this study

. The high efficiency of the TRIGTM gasifier, associated with the lower gasification temperature, helps reduce the operating cost of the gasifier, but crea tes more methane when compared to other gasifiers. Higher methane content increases the heating value of the fuel and is associated with high cold gas efficiencies, but can become a problem if high CO 2 

### removal is required. Because of this, the TRIGTM CO 2 

### capture case achieves less than 90 percent overall carbon capture.

Important Coal Characteristics

– The TRIGTM gasifier is able to fire lower rank coals with high moisture and ash content and high ash fusion temperatures because of its non

- slagging ash

remo val system. Dry feeding also reduces the negative effects of high ash content relative to slurry feed gasifiers, which are limited by solids content in the slurry.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

198 

### 3.3.2 Key System Assumptions

System assumptions for Cases S2A and S2B TRIG TM IGCC using PRB coal , with and without CO 2 

### capture, are compiled in Exhibit 3

- 56

. Exhibit 3

- 56 Case S2A and S2B Plant Study Configuration Matrix

Case S2A S2B Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0.654 0.661 Carbon Conversion, % 98.0 98.0 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

### (Btu/scf) 9,490 (255) 9,460 (254)

Nominal Steam Cycle, MPa/°C/°C (psig/ **°** F/ **°** F) 12.4/566/566 (1,800/1,050/1,050) 12.4/538/538 (1,800/1,000/1,000) Condenser Pressure, mm Hg (in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine 2x Advanced F Class (Nominal 232 MW output each, reduced by elevation considerations) 2x Advanced F Class (Nominal 232 MW output each, reduced by elevation considerations) Gasifier Technology TRIG TM TRIG TM
Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Subbituminous Subbituminous Coal Feed Moisture Content, % 18 18 COS Hydrolysis Yes Yes (Part of WGS)

Water Gas Shift No Yes

H 2 

### S Separation Sulfinol

- M Selexol (1 st 

### Stage) Sulfur Removal, % 99.9 99.8

CO 2 

### Separation None Selexol (2 nd 

### Stage)

CO 2 

### Removal, % N/A 83

Sulfur Recovery Claus Plant with Tail Gas Treatment / Elemental Sulfur Claus Plant with Tail Gas Treatment / Elemental Sulfur

Particulate Control Cyclone, Candle Filter, and AGR Absorber Cyclone, Candle Filter, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N 2 

### Dilution MNQC (LNB) and N 2 

### DilutionCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

199 

### Balance of Plant

– All Cases The balance of plant assumptions are common to all cases and are presented in Exhibit 3

- 57

.

Exhibit 3

- 57 Balance of Plant Assumptions
Cooling water system Recirculating Wet Cooling Tower Fuel and Other storage Coal 30 days Slag 30 days Sulfur 30 days Sorbent 30 days Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt

Motors between 250 hp and 5,000 hp 4,160 volt
Motors above 5,000 hp 13,800 volt Steam and CT Generators 24,000 volt Grid Interconnection Voltage 345 kV Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW and 50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup requirements. Makeup for potable, process, and DI water is drawn from municipal sources

Process Wastewater Water associated with gasification activity and storm water that contacts equipment surfaces is collected and treated for discharge through a permitted discharge.

Sanitary Waste Disposal Design includes a packaged domestic sewage treatment plant with effluent discharged to the industrial wastewater treatment system. Sludge is hauled off site. Packaged plant was sized for 5.68 cubic meters per day (1,500 GPD )

Wate r Discharge Most of the process wastewater is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and discharged.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

200 

### 3.3.3 Sparing Philosophy

The sparing philosophy for Cases S2A and S2B is provided below. Single trains are utilized throughout with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

**•** Two ASU s (2 x 50%).

**•** Two trains of coal drying and dry feed systems (2 x 50%).

**•** Two trains of gasification, including gasifier, SGC , cyclone, and barrier filter (2 x 50%).

**•** Two trains of syngas clean

- up process (2 x 50%).

**•** Two trains of Sulfinol

- M acid gas removal in non

- capture cases and two trains of two

stage Selexol in CO 2 

### capture cases (2 x 50%).

**•** One train of Claus

- based sulfur recovery (1 x 100%).

**•** Two CT /HRSG tandems (2 x 50%).

**•** One steam turbine (1 x 100%).

3.3.4 TRIG TM IGCC Non

- Capture Case (S2A) Process Description

In this section the overall TRIG TM gasification process for Case S2A is described. The system description follows the BFD in Exhibit 3

- 58 , and t he tables in Exhibit 3

- 59 provide process data for the numbered streams. Coal Preparation and Feed Systems Coal receiving and handling is common to all cases and generally described in Section 3.1.1

. The TRIG TM gasifier drying process described for the Orlando Gasification Project [ 70 ] utilizes flash dryers with the pulverizers. A closed loop of gas

, con taining less than 11.3 percent oxygen [ 71 ] to meet fire code standards

, is heated, preferably with medium pressure steam, to provide the heat to dry the coal. While the Orlando Project paper [ 46 ] does not indicate coal moisture levels, the study paper [ 71 ] indicates the PRB coal is dried from 28 to 18 percent. After the coal and drying gas are separated, the gas is cooled below its dew point to remove moisture before being reheated. The cond ensed water is treated and used in the process.

The main motivation to dry the coal is to enable transport into the gasifier . The TRIG TM gasifier accommodates a larger coal particle (700 micron top side) than the dry

- feed, entrained

- flow gasifier (approxim ately 70 micron), enabling the transport of coal with 18 percent moisture. For these reasons, and to be consistent with plans for the Orlando project, it was decided to dry the PRB coal to 18 percent and not use the WTA process, but rather use a system lik e thatCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

201 

### described for the Orlando project to realize some of the coal handling and gasification benefits of the transport gasifier.

Gasifier There are two parallel TRIG TM dry feed, pressurized, up flow , transport gasifiers, operating at 4.2 MPa (615 psia) an d processing a total of 5,935 tonne/day (6,542 tpd) of as

- received PRB Coal that reacts with oxygen and steam in a reducing environment at a temperature of 982°C (1,800°F) to produce principally hydrogen and carbon monoxide along with comparatively high

co ncentrations of methane (~5 vol%) due to the low gasification temperatures. Raw Gas Cooling/Particulate Removal High

- temperature heat recovery in each gasifier train is performed by raw gas coolers in three sections, a superheater, an evaporator, and an economizer, which lower the raw gas temperature from 982°C (1,800°F) to 343°C (650°F). Particulates are removed using high temperature, HP rigid, barrier

- type filter elements and pulsed with recycled syngas to clean the filters of the trapped ash. The co llected particulates are cooled and depressurized using a continuous fine ash removal system and conveyed to the ash silo for disposal. The syngas is further cooled to 260°C (500°F) before entering further gas treatment, with much of the heat recovered by indirect cooling by BFW

. Sour Water Stripper Water condensed during the cooling of the raw gas, along with all other sour water from the plant are sent to the sour water stripper, which removes NH 3 

### , SO 2 

### , and other impurities from the waste stream. The sour gas stripper consists of a sour drum that accumulates sour water that flows to the sour stripper, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from the liquid and sent to the SRU . Remaining water is sent to wastewater
treatment. COS Hydrolysis, Mercury Removal and Acid Gas Removal

H 2 

### S and COS are at significant concentrations, requiring removal for the power plant to achieve the low design level of SO 2 

### emission s. H 2 

### S is removed in an AGR process; however, because COS is not readily removed, it is first catalytically converted to H 2 

### S in a COS hydrolysis unit.

The cooled raw gas is fed to the COS hydrolysis reactor where the COS in the sour gas is hydrolyzed with steam, over a catalyst bed, into H 2 

### S, which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the AGR process, it must be cooled to about 35 **°** C ( 95 **°** F). During this cooling through a series of heat exchangers, part of th e water vapor condenses. This water, which contains some NH 3 

### , is sent to the sour water stripper. The cooled syngas then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.8 ).

The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a mixture of amines and a physical solvent. The solvent consists of an aqueous amine and sulfolane. Sulfinol

- D uses DIPA, w hile Sulfinol

- M uses MDEA. The mixed solvents allow for better solvent loadings at high acid gas partial pressures and higher solubility of COS and organic sulfur compounds than straight aqueous amines. Sulfinol

- M was selected for the non

CO 2 

### capture app lications.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

202 

### The sour syngas is fed directly into a HP contactor. The HP contactor is an absorption column in which the H 2 

### S, COS, CO 2 

### , and small amounts of H 2 

### and CO are removed from the gas by the Sulfinol solvent. The overhead gas stream from the HP con tactor is then washed with water in the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with lean solvent to remove H 2 

### S and COS. The overhead from the LP contactor is flashed in the LP KO drum. This gas can be used as a utility fuel gas, consisting primarily of H 2 

### and CO, at 0.8 MPa (118 psia) and 38 **°** C (101 **°** F). The solvent from the bottom of the LP contactor is returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before entering the stripper. The stripper strips the H 2 

### S, COS, and CO 2 

### from the rich solvent at LP with heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is recovered as the flash gas from the stripper accumulator. The lean solvent from the bottom of the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP
contactor.

The Sulfinol process removes about 15 percent of the CO 2 

### along with the H 2 

### S and COS. The acid gas is fed to the SRU

. The residual CO 2 

### passes through the SRU, the hydrogenation reactor and is recycled upstream of the AGR system.

Claus Unit The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus plant produces molten sulfur by converting approximately one third of the H 2 

### S in the feed to SO 2 

### , then reacting the H 2 

### S and SO 2 

### to sulfur and water. The combination s of Claus technology and tail gas recycle

res ult s in an overall sulfur recovery exceeding 99 percent , producing 43 tonne/day (48 tpd) of sulfur

. Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery plant. Feed for each case consists of acid gas from bo th the acid gas cleanup unit and a vent stream from the sour water stripper in the gasifier section.

In the furnace waste heat boiler steam is generated. This steam is used to satisfy all Claus process preheating and reheating requirements

, as well as to provide some steam to the medium

pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header.

Power Block Clean syngas exiting the Sulfinol absorber reheated and diluted with nitrogen from the ASU, and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and a portion of the air requirements for the ASU. The exhaust gas exits the CT at 586°C (1,087°F) and enters the HRSG where additional heat is recovered until the flue gas exits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam generated in theCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

203 

### HRSG is used to power a steam turbine using a nominal 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050° F) steam cycle. Air Separation Unit

The ASU is desi gned to produce approximately 3,098 tonne/day (3,415 tpd) of 95 mol % O 2 

### for use in the gasifier and SRU . The plant is designed with two production trains. The air compressor is powered by an electric mot or. N itrogen is also recovered, compressed, and used as dilution in the CT combustor or as a coal transport fluid. Air extraction is taken from the CT compressor to reduce the size of the main air compressor.

Balance of Plant Balance of plant items were covered in Sections 3.1.12
, 3.1.13
, 3.1.14
, and 3.1.15

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

204 

### Exhibit 3

- 58 Case S2A Process Flow DiagramCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

205 

### Exhibit 3

- 59 Case S2A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction

Ar 0.0093 0.0093 0.0291 0.0360 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0079 0.0093
CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0532 0.0628
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3426 0.4051
CO 2 0.0003 0.0003 0.0102 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1618 0.1915
COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 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 0.2712 0.3206

H 2 O 0.0064 0.0064 0.1937 0.0000 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 0.1518 0.0016

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0029 0.0037

N 2 0.7759 0.7759 0.5163 0.0140 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0046 0.0055

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0039 0.0000
O 2 0.2081 0.2081 0.2507 0.9500 0.0054 0.9500 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
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 18,706 750 624 55 13,225 3,951 3,355 0 1,349 0 0 18,112 15,320 V-L Flowrate (kg/hr) 540,510 21,680 17,220 1,769 371,104 127,326 60,443 0 24,303 0 0 388,909 338,660 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 247,297 0 223,864 22,724 0 0

Temperature (°C) 6 411 21 32 196 32 343 6 16 71 982 260 35 Pressure (MPa, abs) 0.09 1.43 0.11 0.86 2.65 0.86 5.10 0.09 0.10 0.10 4.24 4.02 3.81 Enthalpy (kJ/kg) A 15.26 434.33 40.10 26.59 202.64 26.59 3,062.93

--- 67.41

--- --- 705.74 38.93 Density (kg/m 3 ) 1.1 7.2 1.6 11.0 18.9 11.0 20.1

--- 1,002.0

--- --- 19.4 33.3 V-L Molecular Weight 28.895 28.895 27.587 32.229 28.061 32.229 18.015

--- 18.015

--- --- 21.472 22.106

V-L Flowrate (lb mol /hr) 41,240 1,654 1,376 121 29,156 8,710 7,397 0 2,974 0 0 39,931 33,774 V-L Flowrate (lb/hr) 1,191,622 47,797 37,963 3,900 818,144 280,705 133,255 0 53,579 0 0 857,398 746,618 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 545,197 0 493,536 50,098 0 0

Temperature (°F) 42 771 70 90 385 90 650 42 61 160 1,800 500 95 Pressure (psia) 13.0 207.6 16.4 125.0 384.0 125.0 740.0 13.0 14.5 14.6 615.0 582.5 552.5 Enthalpy (Btu/lb) A 6.6 186.7 17.2 11.4 87.1 11.4 1,316.8

--- 29.0

--- --- 303.4 16.7 Density (lb/ft 3 ) 0.070 0.452 0.097 0.688 1.180 0.688 1.257

--- 62.556

--- --- 1.212 2.082 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

206 

### Exhibit 3

- 59 Case S2A Stream Table (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0003 0.0000 0.0031 0.0032 0.0094 0.0094 0.0093 0.0090 0.0090 0.0000 0.0000 0.0000 0.0000
CH 4 0.0024 0.0000 0.0012 0.0000 0.0627 0.0627 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 0.0074 0.0000 0.0578 0.0061 0.4047 0.4047 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.8648 0.0000 0.6575 0.7300 0.1914 0.1914 0.0003 0.0824 0.0824 0.0000 0.0000 0.0000 0.0000
COS 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
H 2 0.0065 0.0000 0.0122 0.0680 0.3230 0.3230 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0046 0.0000 0.2151 0.1381 0.0015 0.0015 0.0064 0.0613 0.0613 1.0000 1.0000 1.0000 1.0000

H 2 S 0.1033 0.0000 0.0007 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0107 0.0000 0.0513 0.0527 0.0073 0.0073 0.7759 0.7385 0.7385 0.0000 0.0000 0.0000 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 0.0000
O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1089 0.1089 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0009 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
Total 1.0000 0.0000 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) 553 0 675 657 15,335 15,335 100,835 123,065 123,065 34,631 15,671 15,671 35,201 V-L Flowrate (kg/hr) 23,339 0 24,382 24,042 337,748 337,748 2,913,623 3,600,794 3,600,794 623,885 282,309 282,309 634,155 Solids Flowrate (kg/hr) 0 1,797 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 48 174 232 49 31 196 6 588 132 560 32 32 33 Pressure (MPa, abs) 0.16 0.1 0.085 0.073 3.238 3.203 0.090 0.093 0.090 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 45.44

--- 512.471 217.046 34.170 283.546 15.260 734.275 230.852 3,498.933 2,301.992 2,301.992 140.856 Density (kg/m 3 ) 2.6

--- 0.7 1.0 28.6 17.9 1.1 0.4 0.8 35.2 0.04 0.04 995.0 V-L Molecular Weight 42.235

--- 36.126 36.591 22.025 22.025 28.895 29.259 29.259 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 1,218 0 1,488 1,449 33,807 33,807 222,302 271,312 271,312 76,348 34,548 34,548 77,605 V-L Flowrate (lb/hr) 51,453 0 53,754 53,003 744,606 744,606 6,423,439 7,938,393 7,938,393 1,375,430 622,384 622,384 1,398,073 Solids Flowrate (lb/hr) 0 3,962 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 119 344 450 120 87 385 42 1,090 270 1,040 90 90 92 Pressure (psia) 23.7 17.3 12.3 10.6 469.6 464.6 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 19.5

--- 220.3 93.3 14.7 121.9 6.6 315.7 99.2 1,504.3 989.7 989.7 60.6 Density (lb/ft 3 ) 0.162

--- 0.046 0.063 1.787 1.120 0.070 0.024 0.050 2.197 0.002 0.002 62.114Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

207 

### 3.3.5 Case S2A Performance Results

The non

- capture TRIG TM IGCC plant using PRB coal at the Montana site (elevation 3,400 ft) produces a net output of 54 5 MWe at a net plant efficiency of 39. 9 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3

- 60
, which includes auxiliary power requirements. The ASU accounts for approximate ly 7 6 percent of the total auxiliary load, distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The cooling water system, including the CWP s and cooling tower fan, and the air

- cooled condenser a ccount for about 5 percent of the auxiliary load, the coal drying process accounts for 3 percent of the auxiliary load, and the BFW pumps account for an additional 4 percent. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

208 

### Exhib it 3

- 60 Case S2A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

### S 2A

Gas Turbine Power 419,100 Steam Turbine Power 233,600 TOTAL POWER, kWe 652,700 AUXILIARY LOAD SUMMARY, kWe Coal Handling 500 Coal Crushing 690 Ash Handling 590 Coal Dryer Circulation Blower 2,420 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 48,130 Oxygen Compressor 6,160 Nitrogen Compressors 26,380 Boiler Feedwater Pumps 3,840 Condensate Pump 210 Syngas Recycle Compressors 1,440 Circulating Water Pump 1,920 Ground Water Pumps 190 Cooling Tower Fans 1,250 Air Cooled Condenser Fans 2,730 Acid Gas Removal 740 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 2,470 Miscellaneous Balance of Plant 1 

### 3,000 Transformer Losses 2,270 TOTAL AUXILIARIES, kWe 107,280 NET POWER, kWe 545,420 Net Plant Efficiency, % (HHV) 39.9% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,032 (8,560) CONDENSER COOLING DUTY GJ/hr (10 6 

### Btu/hr) 1,224 (1,160) CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 247,297 (545,197) Thermal Input, kWt 1,368,368 Raw Water Withdrawal , m 3 

### /min (gpm) 7 .7 (2,045) Raw Water Consumption , m 3 

### /min (gpm) 6

. 0 (1,598 )

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

209 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for Case S2A is presented in Exhibit 3

- 61

.

Exhibit 3

- 61 Cases S2A Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.001 (0.002) 28 (31) 0.006 ( 0 .01 3 )

NO X 

### 0.025 (0.059) 875 (965) 0.191 ( 0 .422)

Particulates 0.003 (0.0071) 105 (116) 0.023 ( 0 .051) Hg 1.51E

- 7 (3.51E

- 7) 0.005 (0.006) 1.14E

- 6 (2.51E

- 6)

CO 2 

### gross 90.5 (210.6) 3,125,929 (3,445,747) 683 (1,507)

CO 2 

### net 818 (1,803)

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the Sulfinol

- M AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 5 ppmv in both cases. This results in a concentratio n in the flue gas of less than 1 ppmv. The H 2 

### S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated and recycled to the AGR to capture most of the remaining sulfur. Becau se the environmental target was set based on higher sulfur bituminous coal, the resulting SO 2 

### emissions with lower sulfur western coals are substantially less than the environmental target.

NO x emissions are limited to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ) by the use of low NOx burners and nitrogen dilution of the fuel gas . Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and destroyed in the Claus plant burner. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter 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.

CO 2 

### emissions represent the uncontrolled discharge from the process.

The carbon balance for this case is shown in Exhibit 3

- 62

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the ash and as CO 2 

### in the stack gas and ASU vent gas.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

210 

### Exhibit 3

- 62 Case S2A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 123,817 (272,970) Slag/Ash 2,476 (5,459)

Air (CO 2 

### ) 471 (1,038) Stack Gas 121,735 (268,379)

ASU Vent 77 (169)

Total 124,288 (274,008) Total 124,288 (274,008)

Exhibit 3

- 63 shows the sulfur balance for the non capture case. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted i n the stack gas. Sulfur in the ash is considered to be negligible.

Exhibit 3

- 63 Case S2A Sulfur Balance
Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 1,799 (3,966) Elemental Sulfur 1,797 (3,962)

Stack Gas 2 (4)

Total 1,799 (3,966) Total 1,799 (3,966)

Exhibit 3

- 64 shows the overall water balance for the plant. 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, primarily as coal moisture from the drying process and syngas condensate, and that water is re

- used as internal recycle

. Raw water withdrawal is the difference between water demand and internal recycle. Some water is discharged from the process to a permitted outfall. The difference between the withdrawal and discharge is the consumption.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

211 

### Exhibit 3

- 64 Case S2A Water Balance

W ater 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)

S2A S2A S2A S2A S2A
Slag Handling 0.49 (130) 0.49 (130) 0 (0) 0 (0) 0 (0)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0.01 (2)

- 0.01 (

- 2)
Condenser Makeup 1.16 (307) 0 (0) 1.16 (307) 0 (0) 1.16 (307)

Gasifier Steam 1.01 (267) 1.01 (267)
BFW Makeup 0.15 (40) 0.15 (40)
Cooling Tower Makeup 7.49 (1,978) 0.91 (240) 6.58 (1,738) 1.68 (445) 4.89 (1,293)

Coal Drying 0.41 (107)

- 0.41 (

- 107)

BFW Blowdown 0.15 (40)

- 0.15 (

- 40)

SWS Blowdown 0.08 (20)

- 0.08 (

- 20)

SWS Excess Water 0.28 (73)

- 0.28 (

- 73)

Total 9.1 (2,415) 1.4 (370) 7.7 (2,045) 1.7 (447) 6.1 (1,598)



### Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 65 :

**•** Coal gasification and ASU

**•** Syngas cleanup

**•** Power block

An overall plant energy balance is provided in tabular form in Exhibit 3

- 66 based on 0°C (32°F) reference conditions. The power out is the combined CT and steam turbi ne power after generator losses.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

212 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

213 

### Exhibit 3

- 65 Case S2A Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

214 

### Exhibit 3

- 65 Case S2A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

215 

### Exhibit 3

- 65 Case S2A Heat and Mass Balance (Continue d)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

216 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

217 

### Exhibit 3

- 66 Case S2A Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)
Coal 4,926 (4,669) 2.5 (2.4) 0 (0) 4,929 (4,671)


### ASU Air 0 (0) 8.2 (7.8) 0 (0) 8 (8)



### GT Air 0 (0) 44.5 (42.1) 0 (0) 44 (42) 

### Raw Water Makeup 0 (0) 10.8 (10.2) 0 (0) 11 (10) 

### Auxiliary Power 0 (0) 0 ( 0 ) 386 (366) 386 (366)



### Totals 4,926 (4,669) 66.0 (62.6) 386 (366) 5,378 (5,098)
Heat Out GJ/hr (MMBtu/hr)


### ASU Intercoolers 0 (0) 170 (161) 0 (0) 170 (161)



### ASU Vent 0 (0) 0.7 (0.7) 0 (0) 1 (1) 

### Slag 81 (77) 23.6 (22.4) 0 (0) 105 (99)



### Sulfur 17 (16) 0.2 (0.2) 0 (0) 17 (16) 

### Cooling Tower Blowdown 0 (0) 9.4 (8.9) 0 (0) 9 (9)



### HRSG Flue Gas 0 (0) 831 (788) 0 (0) 831 (788)



### Condenser 0 (0) 1,219 (1,155) 0 (0) 1,219 (1,155)


### Auxiliary Cooling Load 0 (0) 67 (64) 0 (0) 67 (64)



### Electrical Generator Loss 0 (0) 0 (0) 36 (34) 36 (34)



### Process Losses 0 (0) 574 (544) 0 (0) 574 (544)



### Power 0 (0) 0 (0) 2,350 (2,227) 2,350 (2,227)



### Totals 98 (93) 2,895 (2,744) 2,386 (2,261) 5,378 (5,098)



### 3.3.6 Case S2A Equipment Lists

Major equipment items for the TRIG TM gasifier with no CO 2 

### capture using PRB coal are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.3.7 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

218 

### ACCOUNT 1 COAL HANDLING

Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As

- Received Coal Sampling System Two

- stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 54 tonne (60 ton) 2 1

9 Feeder Vibratory 200 tonne/hr (220 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 408 tonne/hr (450 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 200 tonne (220 ton) 2 0

13 Crusher Impactor reduction 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 1 1

15 Conveyor No. 4 Belt w/tripper 408 tonne/hr (450 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 408 tonne/hr (450 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 907 tonne (1,000 ton) 3 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

219 

### ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Feeder Vibratory 45 tonne/hr (50 tph) 6 0

2 Coal Mill Hydraulic Unit Hot gas (350F) enters the bottom of the mill for drying and conveying 272 tonne (300 ton) 2 0

3 Cyclonic Baghouse Gas Recycled to Dryer, Coal to Feeder Coal

- 91 tonne (100 ton) Recycle Gas

- 226,687 kg/hr (499,760 lb/hr) 6 0

4 Discharge Feeder Rotary 45 tonne/hr (50 tph) 6 0

5 Coal Feed Storage Bin Vertical Hopper 45 tonne/hr (50 tph) 6 0

6 Coal Feed Lock Vessel Vertical Hopper 45 tonne/hr (50 tph) 6 0

7 Coal Feed Conveyor Vertical Hopper 91 tonne (100 ton) 6 0

8 Drying Recycle Cooler Water cooled shell and tube 226,687 kg/hr (499,760 lb/hr) 6 0

9 Moisture Separator Drum Cyclonic 226,687 kg/hr (499,760 lb/hr) 6 0

10 Baghouse Exhaust Blower Centrifugal Recycle Gas

- 226,687 kg/hr (499,760 lb/hr)

2,420 kWe 6 0

11 Drying Heater Steam heated shell and tube Recycle Gas

- 226,687 kg/hr (499,760 lb/hr) 110 MMBtu/hr 6 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

220 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 586,739 liters (155,000 gal) 2 0

2 Condensate Pumps Vertical canned 5,867 lpm @ 91 m H 2 

### O (1,550 gpm @ 300 ft H 2 

### O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 435,449 kg/hr (960,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 1,363 lpm @ 27 m H 2 

### O (360 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 @ 1,890 m H 2 

### O (1,600 gpm @ 6,200 ft H 2 

### O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

- stage, centrifugal IP water: 1,022 lpm @ 223 m H 2 

### O (270 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) 1 0

8 Service Air Compressors Flooded Screw 28 m 3 

### /min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

221 

### Equipment No. Description Type S2A Design Condition Operating Qty Spares

9 Instrument Air Dryers Duplex, regenerative 28 m 3 

### /min (1,000 scfm) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 145 GJ/hr (137 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 51,860 lpm @ 21 m H 2 

### O (13,700 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) 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) 1 1

14 Raw Water Pumps Stainless steel, single suction 2,158 lpm @ 18 m H 2 

### O (570 gpm @ 60 ft H 2 

### O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,158 lpm @ 268 m H 2 

### O (570 gpm @ 880 ft H 2 

### O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 984 lpm @ 49 m H 2 

### O (260 gpm @ 160 ft H 2 

### O) 2 1

17 Filtered Water Tank Vertical, cylindrical 476,962 liter (126,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 151 lpm (40 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24

- hour storm 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

222 

### ACCOUNT 4 GASIFIER, ASU , AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Gasifier TRIG TM dry feed, circulating fast

fluidized bed 3,266 tonne/day, 4.2 MPa (3,600 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Vertical down flow heat exchanger with evaporator, superheater, and economizer stages 281,681 kg/hr (621,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 281,681 kg/hr (621,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical up flow 285,310 kg/hr (629,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 186,426 kg/hr (411,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 186,426 kg/hr, 35°C, 3.8 MPa (411,000 lb/hr, 95°F, 553 psia) 2 0

11 Synthesis Gas Reheater Shell and tube 185,973 kg/hr (410,000 lb/hr) 2 0

12 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 285,310 kg/hr (629,000 lb/hr)
syngas 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

223 

### Equipment No. Description Type S2A Design Condition Operating Qty Spares

13 ASU Main Air Compressor Centrifugal, multi

- stage 4,049 m 3 

### /min @ 1.3 MPa (143,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 1,724 tonne/day (1,900 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi

- stage 850 m 3 

### /min (30,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 4.3 MPa (620 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi

- stage 2,832 m 3 

### /min (100,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single

- stage 396 m 3 

### /min (14,000 scfm) Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0

18 Extraction Air Heat Exchanger Gas

- to

- gas, vendor design 11,793 kg/hr, 411°C, 1.4 MPa (26,000 lb/hr, 771°F, 208 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

224 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed 186,426 kg/hr (411,000 lb/hr) 35°C (95°F) 3.8 MPa (553 psia) 2 0

2 Sulfur Plant Claus type 47 tonne/day (52 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 214,096 kg/hr (472,000 lb/hr) 260°C (500°F) 4.0 MPa (580 psia) 2 0

4 Acid Gas Removal Plant Sulfinol 198,673 kg/hr (438,000 lb/hr) 246°C (476°F) 3.7 MPa (543 psia) 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 24,382 kg/hr (53,754 lb/hr) 232°C (450°F) 0.1 MPa (12. 3 psia) 1 0

6 Tail Gas Recycle Compressor Centrifugal 22,446 kg/hr (49,485 lb/hr) 1 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 210 MW 2 0

2 Gas Turbine Generator TEWAC 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

225 

### ACCOUNT 7 HRSG, DUCTING AND STACK Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.4 m (2 0 ft) diameter 2 0

2 Heat Recovery Steam Generator Drum, multi

- pressure with economizer section and integral deaerator Main steam

- 343,137 kg/hr, 12.4 MPa/560°C (756,486 lb/hr, 1,800 psig/1,040°F) Reheat steam

- 302,892 kg/hr, 3.1 MPa/560°C (667,763 lb/hr, 452 psig/1,040°F) 2 0

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Steam Turbine Commercially available 246 MW 12.4 MPa/56 0°C/560°C (1

, 800 psig/ 1
, 040 °F/1

, 0 40 °F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 270 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided waterbox including
vacuum pumps 675 GJ/hr (640 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 1 0

4 Air

- cooled Condenser --- 675 GJ/hr (640 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

226 

### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Circulating Water Pumps Vertical, wet pit 193,056 lpm @ 30 m (51,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) WB / 9°C (48°F) CWT / 20°C (68°F) HWT / 1

, 076 GJ/hr (1

, 020 MMBtu/hr) heat duty 1 0

ACCOUNT 10 ASH RECOVERY AND HANDLING

Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 Coarse Ash Depressurization and Cooling Proprietary Fine Ash

- 3 tonne/h r (3 tph) 2 0

2 Makeup Solids Storage Bin Vertical, shop fabricated 30 tonnes (33 tons) 2 0

3 Makeup Solids Storage Bin Vent Filter Pulsed Fabric Filter 180 Nm 3 

### /h r (106 scfm) 2 0

4 Coarse Ash Conveyor Dense Phase 3 tonne/h r (3 tph) 2 0

5 Fine Ash Depressurization and Cooling Proprietary Coarse Ash

- 10 tonne/h r (11 tph) 2 0

6 Ash Storage Silo Reinforced
concrete 2,999 tonne (3,306 tons) 1 0

7 Ash Silo Vent Filter Pulsed Fabric Filter 2,883 Nm 3 

### /h r (1,696 scfm) 1 0

8 Storage Silo Discharge Feeder Rotary 300 tonne/h r (331 tph) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

227 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 230 MVA, 3

- ph, 60 Hz 2 0

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 270 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 46 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 24 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 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 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

228 

### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type S2A Design Condition Operating Qty Spares

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 0

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

229 

### 3.3.7 Case S2A Cost Estimating

Costs Results The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 67 shows the TPC summary organized by cost account for the Case S2A. A more detailed breakdown of the capital costs is shown in Exhibit 3

- 68

. Exhibit 3

- 69 shows the calculation and addition of owner’s costs to determine the TOC , used to calculate COE. Exhibit 3

- 70 shows the initial and annual O&M costs for Case S2A.

The estimated T O C of the TRIG TM IGCC plant with no CO 2 

### capture using PRB coal is $2, 72 8 /kW. Process contingency represents 3 percent , project contingency 1 1 percent , and owner’s costs 18 percent of the TOC . The COE is 74

. 5 mills/kWh.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

230 

### Exhibit 3

- 67 Case S2A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-15 Project: Low Rank Western Coal Baseline Study

Case: Case S2A - TRIG IGCC w/o CO2 Plant Size: 545.4 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $15,315 $2,846 $11,877 $0 $0 $30,038 $2,727 $0 $6,553 $39,317 $72

2 COAL & SORBENT PREP & FEED $74,930 $6,218 $12,637 $0 $0 $93,784 $8,134 $0 $20,384 $122,302 $224

3 FEEDWATER & MISC. BOP SYSTEMS $7,748 $6,933 $6,960 $0 $0 $21,641 $2,030 $0 $5,280 $28,950 $53

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (TRIG) $121,159 $0 $51,615 $0 $0 $172,774 $15,430 $39,698 $34,951 $262,852 $482 4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $128,334 $0 w/equip. $0 $0 $128,334 $12,439 $0 $14,077 $154,850 $284 4.4-4.9 Flare Stack System $6,797 $10,047 $8,147 $0 $0 $24,990 $2,351 $0 $6,240 $33,581 $62 SUBTOTAL 4 $256,290 $10,047 $59,761 $0 $0 $326,097 $30,220 $39,698 $55,268 $451,284 $827

5A GAS CLEANUP & PIPING $45,807 $2,736 $42,230 $0 $0 $90,773 $8,773 $77 $20,060 $119,683 $219

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,022 $8,724 $4,601 $10,535 $115,882 $212 6.2-6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $217

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,744 $0 $4,656 $0 $0 $37,399 $3,556 $0 $4,096 $45,051 $83 7.2-7.9 Ductwork, Stack and Foundations $3,358 $2,394 $3,135 $0 $0 $8,886 $824 $0 $1,580 $11,290 $21 SUBTOTAL 7 $36,101 $2,394 $7,791 $0 $0 $46,286 $4,380 $0 $5,676 $56,341 $103

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $25,881 $0 $4,366 $0 $0 $30,247 $2,902 $0 $3,315 $36,464 $67 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $32,245 $886 $11,177 $0 $0 $44,307 $4,281 $0 $9,994 $58,583 $107 SUBTOTAL 8 $58,125 $886 $15,543 $0 $0 $74,554 $7,183 $0 $13,309 $95,046 $174

9 COOLING WATER SYSTEM $5,635 $5,789 $4,842 $0 $0 $16,266 $1,510 $0 $3,657 $21,434 $39

10 ASH/SPENT SORBENT HANDLING SYS $19,451 $1,492 $9,652 $0 $0 $30,596 $2,935 $0 $3,662 $37,192 $68

11 ACCESSORY ELECTRIC PLANT $25,693 $9,805 $19,553 $0 $0 $55,052 $4,734 $0 $11,261 $71,046 $130

12 INSTRUMENTATION & CONTROL $9,819 $1,806 $6,326 $0 $0 $17,951 $1,627 $898 $3,412 $23,887 $44

13 IMPROVEMENTS TO SITE $3,139 $1,850 $7,746 $0 $0 $12,736 $1,257 $0 $4,198 $18,191 $33

14 BUILDINGS & STRUCTURES $0 $6,105 $6,984 $0 $0 $13,089 $1,192 $0 $2,346 $16,626 $30

TOTAL COST $643,805 $59,713 $219,065 $0 $0 $922,584 $85,586 $45,274 $166,155 $1,219,598 $2,236 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

231 

### Exhibit 3

- 68 Case S2A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-15 Project: Low Rank Western Coal Baseline Study

Case: Case S2A - TRIG IGCC w/o CO2 Plant Size: 545.4 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,022 $0 $1,965 $0 $0 $5,987 $536 $0 $1,305 $7,828 $14 1.2 Coal Stackout & Reclaim $5,197 $0 $1,260 $0 $0 $6,457 $566 $0 $1,405 $8,428 $15 1.3 Coal Conveyors & Yd Crush $4,832 $0 $1,247 $0 $0 $6,079 $534 $0 $1,322 $7,935 $15
1.4 Other Coal Handling $1,264 $0 $288 $0 $0 $1,553 $136 $0 $338 $2,026 $4 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $2,846 $7,116 $0 $0 $9,962 $955 $0 $2,183 $13,101 $24 SUBTOTAL 1. $15,315 $2,846 $11,877 $0 $0 $30,038 $2,727 $0 $6,553 $39,317 $72
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $30,142 $1,811 $4,392 $0 $0 $36,345 $3,136 $0 $7,896 $47,377 $87 2.2 Prepared Coal Storage & Feed $1,428 $342 $224 $0 $0 $1,993 $170 $0 $433 $2,596 $5 2.3 Dry Coal Injection System $42,648 $495 $3,961 $0 $0 $47,103 $4,057 $0 $10,232 $61,392 $113 2.4 Misc.Coal Prep & Feed $713 $519 $1,555 $0 $0 $2,786 $256 $0 $608 $3,650 $7 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $3,052 $2,505 $0 $0 $5,557 $515 $0 $1,214 $7,286 $13 SUBTOTAL 2. $74,930 $6,218 $12,637 $0 $0 $93,784 $8,134 $0 $20,384 $122,302 $224 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,842 $4,880 $2,576 $0 $0 $10,297 $954 $0 $2,250 $13,502 $25 3.2 Water Makeup & Pretreating $342 $36 $191 $0 $0 $568 $54 $0 $187 $809 $1 3.3 Other Feedwater Subsystems $1,555 $525 $473 $0 $0 $2,553 $229 $0 $556 $3,339 $6 3.4 Service Water Systems $195 $403 $1,397 $0 $0 $1,995 $195 $0 $657 $2,847 $5 3.5 Other Boiler Plant Systems $1,049 $407 $1,007 $0 $0 $2,463 $234 $0 $539 $3,236 $6 3.6 FO Supply Sys & Nat Gas $291 $550 $513 $0 $0 $1,354 $130 $0 $297 $1,781 $3 3.7 Waste Treatment Equipment $478 $0 $291 $0 $0 $769 $75 $0 $253 $1,097 $2 3.8 Misc. Power Plant Equipment $997 $133 $512 $0 $0 $1,642 $159 $0 $540 $2,340 $4 SUBTOTAL 3. $7,748 $6,933 $6,960 $0 $0 $21,641 $2,030 $0 $5,280 $28,950 $53
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (TRIG) $121,159 $0 $51,615 $0 $0 $172,774 $15,430 $39,698 $34,951 $262,852 $482 4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $128,334 $0 w/equip. $0 $0 $128,334 $12,439 $0 $14,077 $154,850 $284
4.4 LT Heat Recovery & FG Saturation $6,797 $0 $2,584 $0 $0 $9,380 $915 $0 $2,059 $12,355 $23 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,038 $422 $0 $0 $1,460 $140 $0 $320 $1,920 $4 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $9,009 $5,140 $0 $0 $14,149 $1,295 $0 $3,861 $19,305 $35 SUBTOTAL 4. $256,290 $10,047 $59,761 $0 $0 $326,097 $30,220 $39,698 $55,268 $451,284 $827 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

232 

### Exhibit 3

- 68 Case S2A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-15 Project: Low Rank Western Coal Baseline Study

Case: Case S2A - TRIG IGCC w/o CO2 Plant Size: 545.4 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Sulfinol System $35,180 $0 $29,851 $0 $0 $65,031 $6,289 $0 $14,264 $85,584 $157 5A.2 Elemental Sulfur Plant $4,867 $970 $6,280 $0 $0 $12,117 $1,177 $0 $2,659 $15,953 $29 5A.3 Mercury Removal $879 $0 $669 $0 $0 $1,548 $150 $77 $355 $2,130 $4 5A.4 COS Hydrolysis $3,272 $0 $4,272 $0 $0 $7,544 $734 $0 $1,656 $9,933 $18 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $1,609 $271 $152 $0 $0 $2,032 $193 $0 $445 $2,669 $5 5A.6 Fuel Gas Piping $0 $743 $520 $0 $0 $1,263 $117 $0 $276 $1,657 $3 5A.9 HGCU Foundations $0 $752 $485 $0 $0 $1,237 $114 $0 $405 $1,757 $3 SUBTOTAL 5A. $45,807 $2,736 $42,230 $0 $0 $90,773 $8,773 $77 $20,060 $119,683 $219 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $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 $0 $92,022 $8,724 $4,601 $10,535 $115,882 $212 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $217
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,744 $0 $4,656 $0 $0 $37,399 $3,556 $0 $4,096 $45,051 $83 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,721 $1,228 $0 $0 $2,949 $259 $0 $642 $3,849 $7
7.4 Stack $3,358 $0 $1,261 $0 $0 $4,619 $443 $0 $506 $5,567 $10 7.9 HRSG,Duct & Stack Foundations $0 $673 $646 $0 $0 $1,319 $123 $0 $432 $1,874 $3 SUBTOTAL 7. $36,101 $2,394 $7,791 $0 $0 $46,286 $4,380 $0 $5,676 $56,341 $103 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $25,881 $0 $4,366 $0 $0 $30,247 $2,902 $0 $3,315 $36,464 $67 8.2 Turbine Plant Auxiliaries $179 $0 $409 $0 $0 $588 $58 $0 $65 $710 $1 8.3a Condenser & Auxiliaries $2,661 $0 $850 $0 $0 $3,511 $336 $0 $385 $4,231 $8 8.3b Air Cooled Condenser $24,385 $0 $4,889 $0 $0 $29,274 $2,927 $0 $6,440 $38,642 $71 8.4 Steam Piping $5,020 $0 $3,531 $0 $0 $8,551 $735 $0 $2,321 $11,607 $21 8.9 TG Foundations $0 $886 $1,498 $0 $0 $2,383 $226 $0 $783 $3,392 $6 SUBTOTAL 8. $58,125 $886 $15,543 $0 $0 $74,554 $7,183 $0 $13,309 $95,046 $174
9 COOLING WATER SYSTEM 9.1 Cooling Towers $3,875 $0 $705 $0 $0 $4,580 $436 $0 $752 $5,768 $11 9.2 Circulating Water Pumps $1,008 $0 $56 $0 $0 $1,064 $90 $0 $173 $1,326 $2 9.3 Circ.Water System Auxiliaries $92 $0 $13 $0 $0 $105 $10 $0 $17 $132 $0 9.4 Circ.Water Piping $0 $3,840 $996 $0 $0 $4,836 $437 $0 $1,055 $6,328 $12 9.5 Make-up Water System $207 $0 $296 $0 $0 $504 $48 $0 $110 $662 $1 9.6 Component Cooling Water Sys $453 $542 $386 $0 $0 $1,381 $129 $0 $302 $1,813 $3 9.9 Circ.Water System Foundations $0 $1,406 $2,391 $0 $0 $3,797 $360 $0 $1,247 $5,404 $10 SUBTOTAL 9. $5,635 $5,789 $4,842 $0 $0 $16,266 $1,510 $0 $3,657 $21,434 $39 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

233 

### Exhibit 3

- 68 Case S2A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-15 Project: Low Rank Western Coal Baseline Study

Case: Case S2A - TRIG IGCC w/o CO2 Plant Size: 545.4 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $16,945 $0 $8,357 $0 $0 $25,302 $2,431 $0 $2,773 $30,506 $56 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $568 $0 $618 $0 $0 $1,186 $115 $0 $195 $1,496 $3 10.7 Ash Transport & Feed Equipment $762 $0 $184 $0 $0 $946 $88 $0 $155 $1,189 $2 10.8 Misc. Ash Handling Equipment $1,176 $1,442 $431 $0 $0 $3,049 $290 $0 $501 $3,840 $7 10.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $113 $11 $0 $37 $161 $0 SUBTOTAL 10. $19,451 $1,492 $9,652 $0 $0 $30,596 $2,935 $0 $3,662 $37,192 $68
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $885 $0 $875 $0 $0 $1,759 $168 $0 $193 $2,120 $4 11.2 Station Service Equipment $3,616 $0 $326 $0 $0 $3,941 $363 $0 $430 $4,735 $9 11.3 Switchgear & Motor Control $6,684 $0 $1,216 $0 $0 $7,900 $733 $0 $1,295 $9,927 $18
11.4 Conduit & Cable Tray $0 $3,105 $10,243 $0 $0 $13,348 $1,291 $0 $3,660 $18,299 $34 11.5 Wire & Cable $0 $5,933 $3,898 $0 $0 $9,831 $714 $0 $2,636 $13,181 $24 11.6 Protective Equipment $0 $624 $2,269 $0 $0 $2,893 $283 $0 $476 $3,652 $7
11.7 Standby Equipment $221 $0 $216 $0 $0 $436 $42 $0 $72 $550 $1 11.8 Main Power Transformers $14,288 $0 $133 $0 $0 $14,420 $1,091 $0 $2,327 $17,838 $33 11.9 Electrical Foundations $0 $144 $378 $0 $0 $522 $50 $0 $172 $744 $1 SUBTOTAL 11. $25,693 $9,805 $19,553 $0 $0 $55,052 $4,734 $0 $11,261 $71,046 $130
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $969 $0 $647 $0 $0 $1,616 $153 $81 $278 $2,128 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $223 $0 $143 $0 $0 $366 $35 $18 $84 $502 $1 12.7 Computer & Accessories $5,170 $0 $166 $0 $0 $5,336 $490 $267 $609 $6,702 $12 12.8 Instrument Wiring & Tubing $0 $1,806 $3,692 $0 $0 $5,499 $466 $275 $1,560 $7,800 $14 12.9 Other I & C Equipment $3,456 $0 $1,678 $0 $0 $5,134 $483 $257 $881 $6,755 $12 SUBTOTAL 12. $9,819 $1,806 $6,326 $0 $0 $17,951 $1,627 $898 $3,412 $23,887 $44 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $99 $2,105 $0 $0 $2,204 $219 $0 $727 $3,149 $6 13.2 Site Improvements $0 $1,752 $2,328 $0 $0 $4,080 $403 $0 $1,345 $5,827 $11 13.3 Site Facilities $3,139 $0 $3,313 $0 $0 $6,452 $636 $0 $2,126 $9,215 $17 SUBTOTAL 13. $3,139 $1,850 $7,746 $0 $0 $12,736 $1,257 $0 $4,198 $18,191 $33
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,211 $3,150 $0 $0 $5,362 $493 $0 $878 $6,733 $12 14.3 Administration Building $0 $808 $586 $0 $0 $1,395 $124 $0 $228 $1,746 $3
14.4 Circulation Water Pumphouse $0 $159 $84 $0 $0 $244 $21 $0 $40 $305 $1 14.5 Water Treatment Buildings $0 $286 $279 $0 $0 $564 $51 $0 $92 $707 $1 14.6 Machine Shop $0 $414 $283 $0 $0 $697 $62 $0 $114 $872 $2
14.7 Warehouse $0 $668 $431 $0 $0 $1,099 $97 $0 $179 $1,376 $3 14.8 Other Buildings & Structures $0 $400 $312 $0 $0 $712 $64 $0 $155 $930 $2 14.9 Waste Treating Building & Str. $0 $894 $1,709 $0 $0 $2,603 $243 $0 $569 $3,415 $6 SUBTOTAL 14. $0 $6,105 $6,984 $0 $0 $13,089 $1,192 $0 $2,346 $16,626 $30

TOTAL COST $643,805 $59,713 $219,065 $0 $0 $922,584 $85,586 $45,274 $166,155 $1,219,598 $2,236 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

234 

### Exhibit 3

- 69 Case S2A Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $10,339 $19 1 Month Variable O&M $2,696 $5 25% of 1 Months Fuel Cost at 100% CF $757 $1 2% of TPC $24,392 $45 Total $38,184 $70

Inventory Capital 60 day supply of consumables at 100% CF $6,218 $11 0.5% of TPC (spare parts) $6,098 $11 Total $12,316 $23

Initial Cost for Catalyst and Chemicals $1,197 $2 Land $900 $2 Other Owner's Costs $182,940 $335 Financing Costs $32,929 $60

Total Owner's Costs $268,466 $492 Total Overnight Cost (TOC) $1,488,063 $2,728 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $1,696,392 $3,110Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

235 

### Exhibit 3

- 70 Case S2A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (June) 2007 Case S2A - TRIG IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8560 MWe-net: 545 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $10.852 Maintenance Labor Cost $10,623,062 $19.477 Administrative & Support Labor $4,135,494 $7.582 Property Taxes and Insurance $24,391,958 $44.721 TOTAL FIXED OPERATING COSTS $45,069,427 $82.633 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $21,823,035 $0.00571

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 1,472 1.08 $0 $465,056 $0.00012

Chemicals

MU & WT Chem. (lb) 0 8,772 0.17 $0 $443,307 $0.00012 Carbon (Mercury Removal) (lb) 89,744 123 1.05 $94,246 $37,698 $0.00001 COS Catalyst (m3) 272 0.19 2,397.36 $651,525 $130,305 $0.00003 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Sulfinol Solution (gal) 44,892 31 10.05 $451,105 $89,526 $0.00002 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.72 131.27 $0 $27,586 $0.00001 Subtotal Chemicals $1,196,876 $728,423 $0.00019

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 123 0.42 $0 $14,972 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 601 16.23 $0 $2,848,202 $0.00075 Subtotal Waste Disposal $0 $2,863,174 $0.00075

By-products & Emissions

Sulfur (tons) 0 48 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,196,876 $25,879,688 $0.00677

Fuel (ton) 0 6,542 15.22 $0 $29,069,719 $0.00761Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

236 

### 3.3.8 TRIG TM IGCC CO 2 

### Capture Cases (S2B) Process Description

Case S2B is configured to produce electric power with CO 2 

### capture. The plant configurations are similar to Cases S2A with the major differences being the addi tion of WGS, the use of a two

stage Selexol AGR plant instead of Sulfinol and subsequent compression of the captured CO 2 

### stream. The gross power output is constrained by the capacity of the two CT s, and since the CO 2 

### capture and compression process increa ses the auxiliary load on the plant, the net output is significantly reduced relative to Case S2A.

The process description for Case S2B is similar to Case S2A with several notable exceptions to accommodate CO 2 

### capture. A BFD for the CO 2 

### capture case is shown in Exhibit 3

- 71 and stream tables are shown in Exhibit 3

- 72 . Instead of repeating the entire process description, only differences from Cases S2A are reported here. Coal Preparation and Feed Systems

No differences from Case S2A.

Gasification The gasification process is the same as Case S2A except the coal feed (as

- received) to the two gasifiers is 6,292 tonne/day (6,935 tpd). Raw Gas Cooling/Particulate Removal

No differences from Case S2A. Sour Water Stripper

No differences from Case S2A.

Sou r Gas Shift The SGS process was described in Section 3.1.6 . In Case S2B steam is added to the cooled raw gas to drive the equilibrium . The hot syngas between shif t stages is used to superheat the added steam. Three total stages of SGS results in 98.7 percent overall conversion of the CO to CO 2


### . The warm syngas from the last stage of SGS is cooled to maintain the inlet syngas temperature to the first stage of SGS. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the last stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds. Mercury Removal and AGR

Mercur y removal is the same as in Case S2A.

The AGR process in Case S2B is a two

- stage Selexol process where H 2 

### S is removed in the first stage and CO 2 

### in the second stage of absorption. The process results in three product streams, the clean syngas, a CO 2 

### - rich stream and an acid gas feed to the Claus plant. The acid gas contains about 18 percent H 2 

### S and 65 percent CO 2 

### with the balance primarily H 2 

### . The CO 2 

### - rich stream is discussed further in the CO 2 

### compression section.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

237 

### CO 2 

### Compression and Dehydration

CO 2 

### fro m the AGR process is generated at two pressure levels. The LP stream is compressed from 0.12 MPa (17 psia) to 1.0 MPa (150 psia) and then combined with the HP stream. The combined stream is further compressed to a SC condition at 15.3 MPa (2

, 215 psia) us ing a multiple

- stage, intercooled compressor. During compression, the CO 2 

### stream is dehydrated to a dew point of

- 40oC (

- 40°F) using a thermal swing adsorptive dryer. The raw CO 2 

### stream from the Selexol process contains over 99 percent CO 2 

### . The dehydrat ed 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 2.6

. Claus Unit The Claus plant is the same as Cases S2A except 46 tonne/day (50 tpd) of sulfur are produced.

Power Block Clean syngas from the AGR plant is saturated and then reheated to 196°C (385°F) using HP BFW . The conditioned syngas is humidified and then diluted with nitrogen before it enters the CT burner. The exhaust gas exits the CT at 562°C (1,044°F) and enters the HRSG where additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam produ ced in the HRSG is used to power a steam turbine with a nominal 12.4MPa/538°C/538°C (1,800 psig/1,000°F/1,000°F) steam cycle. There is no air integration between the CT and the ASU in the capture case.

ASU The same elevated pressure ASU is used as in Case s S2A except the output is 3,324 tonne/day (3,664 tpd) of 95 mol % oxygen.
Balance of Plant Balance of plant items were covered in Sections 3.1.12
, 3.1.13
, 3.1.14
, and 3.1.15

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

238 

### Exhibit 3

- 71 Case S2B Process Flow DiagramCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

239 

### Exhibit 3

- 72 Case S2B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0093 0.0237 0.0318 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0052 0.0067 0.0067
CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0336 0.0436 0.0429
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2242 0.0038 0.0039
CO 2 0.0003 0.0081 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1049 0.4228 0.4261
COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000
H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1761 0.5150 0.5109

H 2 O 0.0064 0.1540 0.0000 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 0.4484 0.0016 0.0016

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0019 0.0026 0.0026

N 2 0.7759 0.6137 0.0178 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0039 0.0052

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0025 0.0000 0.0000
O 2 0.2081 0.2005 0.9504 0.0054 0.9500 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 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 20,872 843 66 14,034 4,231 3,557 0 1,455 0 0 10,253 29,511 22,771 23,132 V-L Flowrate (kg/hr) 603,087 23,325 2,117 393,817 136,368 64,074 0 26,217 0 0 184,714 598,379 476,930 488,394 Solids Flowrate (kg/hr) 0 0 0 0 0 0 262,152 0 237,311 24,089 0 0 0 0

Temperature (°C) 6 20 32 196 32 343 6 16 71 982 288 230 35 35 Pressure (MPa, abs) 0.09 0.11 0.86 2.62 0.86 5.10 0.09 0.10 0.10 4.24 4.14 4.02 3.73 3.66 Enthalpy (kJ/kg) A 15.26 38.58 26.67 202.66 26.59 3,062.93

--- 65.08

--- --- 2,955.16 1,341.87 39.70 39.05 Density (kg/m 3 ) 1.1 1.5 11.0 18.7 11.0 20.1

--- 1,002.6

--- --- 18.2 20.2 31.4 31.1 V-L Molecular Weight 28.895 27.685 32.181 28.061 32.229 18.015

--- 18.015

--- --- 18.015 20.276 20.945 21.113

V-L Flowrate (lb mol /hr) 46,014 1,857 145 30,941 9,328 7,841 0 3,208 0 0 22,604 65,062 50,202 50,998 V-L Flowrate (lb/hr) 1,329,580 51,423 4,668 868,218 300,640 141,259 0 57,798 0 0 407,225 1,319,200 1,051,450 1,076,726 Solids Flowrate (lb/hr) 0 0 0 0 0 0 577,946 0 523,182 53,107 0 0 0 0

Temperature (°F) 42 68 90 385 90 650 42 60 160 1,800 550 446 95 94 Pressure (psia) 13.0 16.4 125.0 380.0 125.0 740.0 13.0 14.5 14.6 615.0 600.0 582.5 540.4 530.4 Enthalpy (Btu/lb) A 6.6 16.6 11.5 87.1 11.4 1,316.8

--- 28.0

--- --- 1,270.5 576.9 17.1 16.8 Density (lb/ft 3 ) 0.070 0.093 0.687 1.167 0.688 1.257

--- 62.589

--- --- 1.135 1.260 1.958 1.939 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

240 

### Exhibit 3

- 72 Case S2B Stream Table (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 V-L Mole Fraction

Ar 0.0020 0.0000 0.0063 0.0074 0.0111 0.0085 0.0093 0.0088 0.0088 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001
CH 4 0.0239 0.0000 0.0055 0.0000 0.0698 0.0538 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0022 0.0022
CO 0.0013 0.0000 0.1128 0.0076 0.0064 0.0049 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001
CO 2 0.6511 0.0000 0.3578 0.5528 0.0542 0.0418 0.0003 0.0145 0.0145 0.0000 0.0000 0.0000 0.0000 0.9908 0.9935
COS 0.0001 0.0000 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 0.1105 0.0000 0.0590 0.2189 0.8497 0.6545 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0041 0.0041

H 2 O 0.0350 0.0000 0.3947 0.1381 0.0001 0.2298 0.0064 0.1454 0.1454 1.0000 1.0000 1.0000 1.0000 0.0027 0.0000

H 2 S 0.1753 0.0000 0.0008 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0007 0.0000 0.0625 0.0735 0.0087 0.0067 0.7759 0.7272 0.7272 0.0000 0.0000 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000
O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1041 0.1041 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0004 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 0.0000 1.0000 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) 341 0 492 418 13,822 17,944 100,835 126,897 126,897 32,509 12,936 12,936 40,195 8,969 8,945 V-L Flowrate (kg/hr) 12,277 0 13,917 12,493 84,121 158,381 2,913,623 3,465,821 3,465,821 585,655 233,055 233,055 724,125 391,997 391,563 Solids Flowrate (kg/hr) 0 1,903 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 48 177 232 49 31 196 6 562 132 534 32 32 33 16 72 Pressure (MPa, abs) 0.16 0.12 0.1 0.073 3.309 3.216 0.090 0.093 0.090 12.512 0.005 0.005 0.827 1.032 15.270 Enthalpy (kJ/kg) A 90.08

--- 919.2 263.386 145.239 1,851.859 15.260 881.971 384.653 3,432.690 2,295.131 2,295.131 140.154 5.022 -94.557 Density (kg/m 3 ) 2.2

--- 0.6 0.8 7.9 7.3 1.1 0.4 0.8 36.7 0.04 0.04 995.0 20.1 459.1 V-L Molecular Weight 36.008

--- 28 29.884 6.086 8.826 28.895 27.312 27.312 18.015 18.015 18.015 18.015 43.706 43.775

V-L Flowrate (lb mol /hr) 752 0 1,084 922 30,473 39,560 222,302 279,760 279,760 71,670 28,520 28,520 88,615 19,773 19,720 V-L Flowrate (lb/hr) 27,066 0 30,682 27,543 185,455 349,170 6,423,439 7,640,828 7,640,828 1,291,148 513,797 513,797 1,596,423 864,205 863,250 Solids Flowrate (lb/hr) 0 4,196 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 119 350 450 120 87 385 42 1,044 270 994 90 90 92 60 162 Pressure (psia) 23.7 17.3 12.3 10.6 480.0 466.4 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 149.7 2,214.7 Enthalpy (Btu/lb) A 38.7

--- 395.2 113.2 62.4 796.2 6.6 379.2 165.4 1,475.8 986.7 986.7 60.3 2.2 -40.7 Density (lb/ft 3 ) 0.138

--- 0.036 0.051 0.492 0.454 0.070 0.023 0.047 2.293 0.002 0.002 62.117 1.253 28.658Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

241 

### 3.3.9 Case S2B Performance Results

The Case S2B modeling assumptions were presented previously in Exhibit 3

- 56

.
The TRIG TM IGCC plant with CO 2 

### capture and using PRB coal at the Montana site (elev ation 3,400 ft) produces a net output of 46 1 MWe at a net plant efficiency of 31.8 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3

- 73
, which includes auxiliary power requirements. The ASU accounts for approximately 57 percent of the total auxiliary load, distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. CO 2 

### compression ac counts for about 1 8 percent and the AGR process about 10 percent of the auxiliary load. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

242 

### Exhibit 3

- 73 Case S2B Plant Performance S ummary POWER SUMMARY (Gross Power at Generator Terminals, kWe) S2 B

Gas Turbine Power 426,400 Steam Turbine Power 194,900 TOTAL POWER, kWe 621,300 AUXILIARY LOAD SUMMARY, kWe Coal Handling 510 Coal Crushing 730 Ash Handling 630 Coal Dryer Circulation Blower 2,560 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 53,710 Oxygen Compressor 6,600 Nitrogen Compressors 30,060 CO 2 

### Compressor 28,290 Boiler Feedwater Pumps 3,960 Condensate Pump 240 Syngas Recycle Compressors 1,550 Circulating Water Pump 2,020 Ground Water Pumps 280 Cooling Tower Fans 1,320 Air Cooled Condenser Fans 2,230 Acid Gas Removal 16,480 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 1,600 Miscellaneous Balance of Plant 1 

### 3,000 Transformer Losses 2,330 TOTAL AUXILIARIES, kWe 160,450 NET POWER, kWe 460,850 Net Plant Efficiency, % (HHV) 31.8% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,331 (10,740) CONDENSER COOLING DUTY GJ/hr (10 6 

### Btu/hr) 992 (940) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 262,152 (577,946) Thermal Input, kWt 1,450,564 Raw Water Withdrawal , m 3 

### /min (gpm) 11.3 (2,989) Raw Water Consumption , m 3 

### /min (gpm) 9

. 5 (2, 517 )

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

243 

### Environmental Performance The environmental targets for emissions of Hg, NOx , SO 2 

### , CO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for Case S2B is presented in Exhibit 3

- 74

.

Exhibit 3

- 74 Case S2B Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.000 (0.001) 13 (15) 0.003 ( 0 .0 07 )

NO X 

### 0.021 (0.049) 770 (849) 0.177 ( 0 .390)

Particulates 0.003 (0.0071) 112 (123) 0.026 ( 0 .057)
Hg 1.51E

- 7 (3.51E

- 7) 0.006 (0.006) 1.27E

- 6 (2.80E

- 6)

CO 2 

### gross 15.5 (36.0) 566,135 (624,057) 130 (287)

CO 2 

### net 175 (386)

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the two

- stage Selexol AGR process. Just as in the non

- capture cases, the SO 2 

### emission are significantly less than the environmental targets of Section 2.3 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 2 ppmv. This results in a concentration in the flue gas of less than 0.3 ppmv. The H 2 

### S

- rich regeneration gas fro m the AGR system is fed to a Claus plant, producing elemental sulfur. The tail gas is hydrogenated and recycled to the gasifier.

NO x emissions are limited to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ) by the use of humidification and nitrogen dilution of the fuel gas and low NOx burners . Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and subsequently destroyed in the Claus plant burner. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter 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 merc ury is captured from the syngas by an activated carbon bed.

More than 9 2 percent of the CO 2 

### from the syngas is captured in the AGR system and compressed for sequestration. In the TRIG TM case, because of the considerable methane content, which is
not removed by the AGR, and because not all the CO is converted to CO 2 

### in the shift reactors, the overall CO 2 

### removal is less than the target 90 percent. The high methane concentrations are a result of the lower gasification temperatures

, which result in a hi gher cold gas efficiency (CGE) , which is particularly important for power generation applications. It is technologically possible to remove the last marginal amounts of carbon to achieve 90% overall capture, though these approaches are either unjustifiabl y detrimental to the performance of the plant, or outsideCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

244 

### the parameters of this study. These possibilities include steam reforming of the methane, increasing the solvent circulation rate in the Selexol AGR to increase its CO 2 

### removal, although with dimin ishing returns, or co

- sequestering CO 2 

### and sulfur, using different AGR solvents that can achieve higher CO 2 

### removals. The carbon balance for the plant is shown in Exhibit 3

- 75

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the carbon capture equation below, but it is not neglected in the balance since the Aspen model accounts for air com ponents throughout. Carbon leaves the plant as unburned carbon in the ash, CO 2 

### in the stack gas and ASU vent gas, and the captured CO 2 

### product. The carbon capture efficiency is defined as the amount of carbon in the CO 2 

### product stream relative to the amo unt of carbon in the coal less carbon contained in the slag , represented by the following fraction:
(Carbon in Product for Sequestration)/[(Carbon in the Coal)

- (Carbon in Slag)] or 83.2 percent

Exhibit 3

- 75 Case S2B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 131,255 (289,367) Slag/Ash 2,625 (5,787)

Air (CO 2 

### ) 479 (1,057) Stack Gas 22,047 (48,606)

ASU Vent 82 (181)

CO 2 

### Product 106,980 (235,850)

Total 131,734 (290,424) Total 131,734 (290,424)

Exhibit 3

- 76 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack ga s and sulfur that is co

- sequestered with the CO 2 

### product. Sulfur in t he ash is considered negligible

. Exhibit 3

- 76 Case S2B Sulfur Balance
Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 1,9 07 (4,2 04 ) Elemental Sulfur 1,90 3 (4, 196 )

Stack Gas 1 (2)

CO 2 

### Product 3 ( 6 )

Total 1,907 (4,204) Total 1,907 (4,204)

Exhibit 3

- 77 shows the overall water balance for the plant. 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, primarily from the coal drying process and as syngas condensate, and that water i s re

-Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

245 

### used as internal recycle. Raw water withdrawal is the difference between water demand an d internal recycle. Some water is discharged from the process to a permitted outfall. The difference between the withdrawal and discharge is the consumption.

Exhibit 3

- 77 Case S2B 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)

S2B S2B S2B S2B S2B
Slag Handling 0.52 (138) 0.5 (138) 0 (0) 0 (0) 0 (0)

Humidifier 1.28 (337) 1.3 (337) 0 (0) 0 (0) 0 (0)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0.02 (5)

- 0.02 (

- 5)
Condenser Makeup 4.31 (1,138) 0 (0) 4.31 (1,138) 0 (0) 4.31 (1,138)

Gasifier Steam 1.07 (283) 1.07 (283)

Shift Steam 3.08 (814) 3.08 (814)
BFW Makeup 0.15 (41) 0.15 (41)
Cooling Tower Makeup 7.86 (2,077) 0.85 (225) 7.01 (1,852) 1.77 (467) 5.24 (1,384)

Coal Drying 0.44 (116)

- 0.44 (

- 116)

BFW Blowdown 0.15 (41)

- 0.15 (

- 41)

SWS Blowdown 0.19 (49)

- 0.19 (

- 49)

SWS Excess Water 0.07 (20)

- 0.07 (

- 20)

Total 14.0 (3,690) 2.7 (700) 11.3 (2,989) 1.8 (472) 9.5 (2,517)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

246 

### Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subs ystems in Exhibit 3

- 78 :

**•** Coal gasification and ASU

**•** Syngas cleanup

**•** Power block An overall plant energy balance is provided in tabular form in Exhibit 3

- 79 based on 0°C (32°F) reference conditions. The power out is the combined CT and steam turbine power after generator losses.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

247 

### Exhibit 3

- 78 Case S2B Heat and Mass Balan ceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

248 

### Exhibit 3

- 78 Case S2B Heat and Mass Balance ( Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

249 

### Exhibit 3

- 78 Case S2B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

250 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

251 

### Exhibit 3

- 79 Case S2B Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)
Coal 5,222 (4,950) 2.7 (2.5) 0 (0) 5,225 (4,952)
ASU Air 0 (0) 9.2 (8.7) 0 (0) 9 (9)
GT Air 0 (0) 44.5 (42.1) 0 (0) 44 (42) Raw Water Makeup 0 (0) 15.7 (14.9) 0 (0) 16 (15) Auxiliary Power 0 (0) 0 ( 0 ) 578 (547) 578 (547)

Totals 5,222 (4,950) 72.1 (68.3) 578 (547) 5,872 (5,565) Heat Out GJ/hr (MMBtu/hr)

ASU Intercoolers 0 (0) 185 (176) 0 (0) 185 (176)

ASU Vent 0 (0) 0.9 (0.9) 0 (0) 1 (1)
Slag 86 (82) 25.0 (23.7) 0 (0) 111 (105)

Sulfur 18 (17) 0.2 (0.2) 0 (0) 18 (17)

CO 2 

### 0 (0)

- 37.0 (

- 35.1) 0 (0)

- 37 (

- 35)

CO 2 

### Comp Intercoolers 0 (0) 137.0 (129.9) 0 (0) 137 (130)
Cooling Tower Blowdown 0 (0) 9.9 (9.3) 0 (0) 10 (9)

HRSG Flue Gas 0 (0) 1,333 (1,264) 0 (0) 1,333 (1,264)

Condenser 0 (0) 989 (937) 0 (0) 989 (937)
Auxiliary Cooling 0 (0) 32 (30) 0 (0) 32 (30)

Electrical Generator Loss 0 (0) 0 (0) 34 (32) 34 (32)

Process Losses 0 (0) 822 (779) 0 (0) 822 (779)

Power 0 (0) 0 (0) 2,237 (2,120) 2,237 (2,120)

Totals 104 (98) 3,497 (3,315) 2,271 (2,152) 5,872 (5,565)

3.3.10 Case S2B Equipment List

Major equipment items for the TRIG TM gasifier with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.3.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

252 

### ACCOUNT 1 COAL HANDLING

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As

- Received Coal Sampling System Two

- stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 54 tonne (60 ton) 2 1
9 Feeder Vibratory 218 tonne/hr (240 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 435 tonne/hr (480 tph) 1 0
11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 218 tonne (240 ton) 2 0

13 Crusher Impactor reduction 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 1 1

15 Conveyor No. 4 Belt w/tripper 435 tonne/hr (480 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0
17 Conveyor No. 5 Belt w/ tripper 435 tonne/hr (480 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 998 tonne (1,100 ton) 3 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

253 

### ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Feeder Vibratory 45 tonne/hr (50 tph) 6 0

2 Coal Mill Hydraulic Unit Hot gas 177°C (350°F) enters the bottom of the mill for drying and conveying 290 tonne (320 ton) 2 0

3 Cyclonic Baghouse Gas Recycled to Dryer, Coal to Feeder Coal

- 100 tonne (110 ton) Recycle Gas

- 240
, 304 kg/hr (529,780 lb/hr) 6 0

4 Discharge Feeder Rotary 45 tonne/hr (50 tph) 6 0
5 Coal Feed Storage Bin Vertical Hopper 45 tonne/hr (50 tph) 6 0

6 Coal Feed Lock Vessel Vertical Hopper 45 tonne/hr (50 tph) 6 0

7 Coal Feed Conveyor Vertical Hopper 100 tonne (110 ton) 6 0

8 Drying Recycle Cooler Water cooled shell and tube 240
, 304 kg/hr (529,780 lb/hr) 6 0

9 Moisture Separator Drum Cyclonic 240
, 304 kg/hr (529,780 lb/hr) 6 0

10 Baghouse Exhaust Blower Centrifugal Recycle Gas

- 240
, 304 kg/hr (529,780 lb/hr)

2,560 kWe 6 0

11 Drying Heater Steam heated shell and tube Recycle Gas

- 240
, 304 kg/hr (529,780 lb/hr) 120 MMBtu/ hr 6 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

254 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 594,310 liters (157,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,700 lpm @ 91 m H 2 

### O (1,770 gpm @ 300 ft H 2 

### O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 498,044 kg/hr (1,098,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 1,060 lpm @ 27 m H 2 

### O (280 gpm @ 90 ft H 2 

### O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 5,716 lpm @ 1,890 m H 2 

### O (1,510 gpm @ 6,200 ft H 2 

### O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,817 lpm @ 223 m H 2 

### O (480 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) 1 0

8 Service Air Compressors Flooded Screw 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) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 210 GJ/hr (19 9 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 74,951 lpm @ 21 m H 2 

### O (19,800 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) 1 1Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

255 

### Equipment No. Description Type S2B Design Condition Operating Qty Spares

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 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 3,142 lpm @ 18 m H 2 

### O (830 gpm @ 60 ft H 2 

### O) 2 1

15 Ground Water Pumps Stainless steel, single suction 3,142 lpm @ 268 m H 2 

### O (830 gpm @ 880 ft H 2 

### O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 3,445 lpm @ 49 m H 2 

### O (910 gpm @ 160 ft H 2 

### O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,650,440 liter (436,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 1,855 lpm (490 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24

- hour storm 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

256 

### ACCOUNT 4 GASIFIER, ASU , AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Gasifier TRIG TM dry feed, circulating fast

fluidized bed 3,447 tonne/day, 4.2 MPa (3,800 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Vertical down flow heat exchanger with evaporator, superheater, and economizer stages 299,825 kg/hr (661,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 299,825 kg/hr (661,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical up flow 227,703 kg/hr (502,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 262,630 kg/hr (579,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 262,176 kg/hr, 35°C, 3.7 MPa (578,000 lb/hr, 95°F, 540 psia) 2 0

8 Saturation Water Economizers Shell and tube 262,630 kg/hr (579,000 lb/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 87,090 kg/hr, 239°C, 3.3 MPa (192,000 lb/hr, 462°F, 480 psia) 2 0

10 Saturator Water Pump Centrifugal 1,893 lpm @ 12 m H 2 

### O (500 gpm @ 40 ft H 2 

### O) 2 2Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

257 

### Equipment No. Description Type S2B Design Condition Operating Qty Spares

11 Synthesis Gas Reheater Shell and tube 46,266 kg/hr (102,000 lb/hr) 2 0

12 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 227,703 kg/hr (502,000 lb/hr)
syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi

- stage 4,531 m 3 

### /min @ 1.3 MPa (160,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 1,814 tonne/day (2,000 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi

- stage 934 m 3 

### /min ( 33 ,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 4.3 MPa (620 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi

- stage 2,010 m 3 

### /min (71,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.6 MPa (380 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single

- stage 368 m 3 

### /min (13,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 5.7 MPa (820 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

258 

### ACCOUNT 5 SYNGAS CLEANUP

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed 262,176 kg/hr (578,000 lb/hr) 35°C (95°F) 3.7 MPa (540 psia) 2 0

2 Sulfur Plant Claus type 50 tonne/day (55 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 329,308 kg/hr (726,000 lb/hr) 232°C (450°F) 4.0 MPa (580 psia) 4 0

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 131 GJ/hr (124 MMBtu/hr) Exchanger 2: 19 GJ/hr (18 MMBtu/hr) 4 0

5 Acid Gas Removal Plant Two

- stage Selexol 268,527 kg/hr (592,000 lb/hr) 35°C (94°F) 3.7 MPa (530 psia) 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 15,309 kg/hr (33,750 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 12,626 kg/hr (27,835 lb/hr) 1 0

ACCOUNT 5B CO 2 

### COMPRESSION

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 CO 2 

### Compressor Integrally geared, multi

- stage centrifugal 971 m 3 

### /min @ 15.3 MPa (34,300 scfm @ 2,215 psia) 4 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

259 

### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 215 MW 2 0

2 Gas Turbine Generator TEWAC 240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 0

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.6 m (2 0 ft) diameter 2 0

2 Heat Recovery Steam Generator Drum, multi

- pressure with economizer section and integral deaerator Main steam

- 322,110 kg/hr, 12.4 MPa/534°C (710,131 lb/hr, 1,800 psig/994°F) Reheat steam

- 279,722 kg/hr, 3.1 MPa/534°C (616,681 lb/hr, 452 psig/994°F) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

260 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Steam Turbine Commercially available 205 MW 12.4 MPa/534°C/534°C (1

, 800 psig/ 994°F/994°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided waterbox including
vacuum pumps 549 GJ/hr (520 MMBtu/hr), Condensing temperature 32°C (90°F),

Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 1 0

4 Air

- cooled Condenser --- 549 GJ/hr (520 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 1 0

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Circulating Water Pumps Vertical, wet pit 200,627 lpm @ 30 m (53,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) WB / 9°C (48°F) CWT / 20°C (68°F) HWT / 1

, 129 GJ/hr

(1

, 070 MMBtu/hr) heat duty 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

261 

### ACCOUNT 10 ASH RECOVERY AND HANDLING

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 Coarse Ash Depressurization and Cooling Proprietary Fine Ash

- 3 tonne/h r (3 tph) 2 0

2 Makeup Solids Storage Bin Vertical, shop fabricated 32 tonnes (35 tons) 2 0

3 Makeup Solids Storage Bin Vent Filter Pulsed Fabric Filter 190 Nm 3 

### /h r (112 scfm) 2 0

4 Coarse Ash Conveyor Dense Phase 3 tonne/h r (3 tph) 2 0

5 Fine Ash Depressurization and Cooling Proprietary Coarse Ash

- 11 tonne/h r (12 tph) 2 0

6 Ash Storage Silo Reinforced concrete 3,180 tonne (3,505 tons) 1 0

7 Ash Silo Vent Filter Pulsed Fabric Filter 3,055 Nm 3 

### /h r (1,797 scfm) 1 0

8 Storage Silo Discharge Feeder Rotary 318 tonne/h r (351 tph) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

262 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 240 MVA, 3

- ph, 60 Hz 2 0

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 230 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 67 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 41 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 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 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

263 

### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type S2B Design Condition Operating Qty Spares

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 0

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

264 

### 3.3.11 Case S2B Cost Estimating

Costs Results The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 80 shows the TPC summary organized by cost account with a more detailed breakdown of the capital costs shown in Exhibit 3

- 81

. Exhibit 3

- 82 shows the calculation and addition of owner’s costs to determine the TOC , used to calculate COE. Exhibit 3

- 8 3 shows the initial and annual O&M costs for Case S2B.

The estimated T O C of the TRIG TM IGCC plant with CO 2 

### capture using PRB coal is $3, 6 91 /kW. Process contingency represents 4 percent , project contingency 1 1 percent , and owner’s costs 18 percent of the TOC . The COE is 105.2 mills/kWh.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

265 

### Exhibit 3

- 80 Case S2B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-15 Project: Low Rank Western Coal Baseline Study

Case: Case S2B - TRIG IGCC w/ CO2 Plant Size: 460.9 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $15,879 $2,951 $12,314 $0 $0 $31,144 $2,827 $0 $6,794 $40,765 $88

2 COAL & SORBENT PREP & FEED $77,809 $6,484 $13,276 $0 $0 $97,568 $8,464 $0 $21,207 $127,239 $276

3 FEEDWATER & MISC. BOP SYSTEMS $8,217 $6,965 $7,732 $0 $0 $22,915 $2,154 $0 $5,676 $30,746 $67

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $125,998 $0 $53,847 $0 $0 $179,845 $16,058 $41,465 $36,371 $273,739 $594 4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $128,018 $0 w/equip. $0 $0 $128,018 $12,409 $0 $14,043 $154,470 $335 4.4-4.9 Other Gasification Equipment $9,189 $10,292 $9,200 $0 $0 $28,681 $2,709 $0 $7,073 $38,463 $83 SUBTOTAL 4 $263,206 $10,292 $63,047 $0 $0 $336,544 $31,175 $41,465 $57,487 $466,672 $1,013

5A GAS CLEANUP & PIPING $76,834 $2,672 $64,176 $0 $0 $143,682 $13,879 $23,255 $36,288 $217,105 $471

5B CO2 REMOVAL & COMPRESSION $16,750 $0 $9,707 $0 $0 $26,457 $2,547 $0 $5,801 $34,805 $76

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $281 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $286

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $31,608 $0 $4,494 $0 $0 $36,103 $3,433 $0 $3,954 $43,489 $94 7.2-7.9 Ductwork and Stack $3,430 $2,445 $3,203 $0 $0 $9,078 $842 $0 $1,614 $11,534 $25 SUBTOTAL 7 $35,038 $2,445 $7,697 $0 $0 $45,181 $4,274 $0 $5,568 $55,023 $119

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $22,780 $0 $3,777 $0 $0 $26,557 $2,548 $0 $2,911 $32,016 $69 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $28,346 $776 $10,012 $0 $0 $39,134 $3,773 $0 $8,865 $51,772 $112 SUBTOTAL 8 $51,126 $776 $13,789 $0 $0 $65,691 $6,321 $0 $11,776 $83,788 $182

9 COOLING WATER SYSTEM $5,860 $5,932 $5,047 $0 $0 $16,839 $1,564 $0 $3,784 $22,187 $48

10 ASH/SPENT SORBENT HANDLING SYS $20,179 $1,541 $10,013 $0 $0 $31,732 $3,044 $0 $3,796 $38,573 $84

11 ACCESSORY ELECTRIC PLANT $28,954 $11,504 $22,461 $0 $0 $62,920 $5,413 $0 $12,976 $81,309 $176

12 INSTRUMENTATION & CONTROL $10,732 $1,974 $6,915 $0 $0 $19,621 $1,778 $981 $3,729 $26,110 $57

13 IMPROVEMENTS TO SITE $3,220 $1,898 $7,945 $0 $0 $13,063 $1,290 $0 $4,306 $18,659 $40

14 BUILDINGS & STRUCTURES $0 $6,068 $6,854 $0 $0 $12,922 $1,176 $0 $2,324 $16,423 $36

TOTAL COST $705,833 $62,309 $258,448 $0 $0 $1,026,590 $95,414 $75,563 $193,851 $1,391,417 $3,019 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

266 

### Exhibit 3

- 81 Case S2B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-15 Project: Low Rank Western Coal Baseline Study

Case: Case S2B - TRIG IGCC w/ CO2 Plant Size: 460.9 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,170 $0 $2,038 $0 $0 $6,208 $556 $0 $1,353 $8,117 $18 1.2 Coal Stackout & Reclaim $5,389 $0 $1,306 $0 $0 $6,695 $587 $0 $1,456 $8,738 $19 1.3 Coal Conveyors & Yd Crush $5,010 $0 $1,293 $0 $0 $6,302 $553 $0 $1,371 $8,227 $18
1.4 Other Coal Handling $1,311 $0 $299 $0 $0 $1,610 $141 $0 $350 $2,101 $5 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $2,951 $7,378 $0 $0 $10,329 $990 $0 $2,264 $13,583 $29 SUBTOTAL 1. $15,879 $2,951 $12,314 $0 $0 $31,144 $2,827 $0 $6,794 $40,765 $88
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $31,325 $1,882 $4,564 $0 $0 $37,771 $3,259 $0 $8,206 $49,237 $107 2.2 Prepared Coal Storage & Feed $1,347 $322 $211 $0 $0 $1,880 $161 $0 $408 $2,449 $5 2.3 Dry Coal Injection System $44,321 $514 $4,116 $0 $0 $48,952 $4,216 $0 $10,634 $63,802 $138 2.4 Misc.Coal Prep & Feed $816 $594 $1,780 $0 $0 $3,190 $293 $0 $697 $4,180 $9 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $3,171 $2,604 $0 $0 $5,775 $535 $0 $1,262 $7,572 $16 SUBTOTAL 2. $77,809 $6,484 $13,276 $0 $0 $97,568 $8,464 $0 $21,207 $127,239 $276 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,720 $4,671 $2,466 $0 $0 $9,856 $913 $0 $2,154 $12,923 $28 3.2 Water Makeup & Pretreating $447 $47 $250 $0 $0 $744 $71 $0 $244 $1,059 $2 3.3 Other Feedwater Subsystems $1,488 $503 $453 $0 $0 $2,443 $220 $0 $533 $3,196 $7 3.4 Service Water Systems $256 $527 $1,829 $0 $0 $2,612 $255 $0 $860 $3,727 $8 3.5 Other Boiler Plant Systems $1,374 $532 $1,319 $0 $0 $3,225 $306 $0 $706 $4,237 $9 3.6 FO Supply Sys & Nat Gas $291 $550 $513 $0 $0 $1,354 $130 $0 $297 $1,781 $4 3.7 Waste Treatment Equipment $625 $0 $381 $0 $0 $1,007 $98 $0 $331 $1,436 $3 3.8 Misc. Power Plant Equipment $1,016 $136 $522 $0 $0 $1,674 $162 $0 $551 $2,387 $5 SUBTOTAL 3. $8,217 $6,965 $7,732 $0 $0 $22,915 $2,154 $0 $5,676 $30,746 $67
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (TRIG) $125,998 $0 $53,847 $0 $0 $179,845 $16,058 $41,465 $36,371 $273,739 $594 4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $128,018 $0 w/equip. $0 $0 $128,018 $12,409 $0 $14,043 $154,470 $335
4.4 LT Heat Recovery & FG Saturation $9,189 $0 $3,493 $0 $0 $12,683 $1,238 $0 $2,784 $16,705 $36 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,017 $414 $0 $0 $1,431 $137 $0 $314 $1,881 $4 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $9,275 $5,292 $0 $0 $14,568 $1,334 $0 $3,975 $19,877 $43 SUBTOTAL 4. $263,206 $10,292 $63,047 $0 $0 $336,544 $31,175 $41,465 $57,487 $466,672 $1,013 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

267 

### Exhibit 3

- 81 Case S2B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-15 Project: Low Rank Western Coal Baseline Study

Case: Case S2B - TRIG IGCC w/ CO2 Plant Size: 460.9 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $62,625 $0 $53,138 $0 $0 $115,763 $11,196 $23,153 $30,022 $180,134 $391 5A.2 Elemental Sulfur Plant $5,058 $1,008 $6,526 $0 $0 $12,592 $1,223 $0 $2,763 $16,578 $36 5A.3 Mercury Removal $1,167 $0 $888 $0 $0 $2,054 $198 $103 $471 $2,827 $6 5A.4 Shift Reactors $6,301 $0 $2,536 $0 $0 $8,837 $847 $0 $1,937 $11,621 $25 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $1,684 $283 $160 $0 $0 $2,127 $202 $0 $466 $2,795 $6 5A.6 Fuel Gas Piping $0 $686 $480 $0 $0 $1,166 $108 $0 $255 $1,529 $3 5A.9 HGCU Foundations $0 $695 $448 $0 $0 $1,142 $105 $0 $374 $1,622 $4 SUBTOTAL 5A. $76,834 $2,672 $64,176 $0 $0 $143,682 $13,879 $23,255 $36,288 $217,105 $471 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $16,750 $0 $9,707 $0 $0 $26,457 $2,547 $0 $5,801 $34,805 $76 SUBTOTAL 5B. $16,750 $0 $9,707 $0 $0 $26,457 $2,547 $0 $5,801 $34,805 $76
6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $281 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $286
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $31,608 $0 $4,494 $0 $0 $36,103 $3,433 $0 $3,954 $43,489 $94 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,758 $1,254 $0 $0 $3,012 $264 $0 $655 $3,932 $9
7.4 Stack $3,430 $0 $1,288 $0 $0 $4,718 $452 $0 $517 $5,687 $12 7.9 HRSG,Duct & Stack Foundations $0 $687 $660 $0 $0 $1,347 $125 $0 $442 $1,914 $4 SUBTOTAL 7. $35,038 $2,445 $7,697 $0 $0 $45,181 $4,274 $0 $5,568 $55,023 $119 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $22,780 $0 $3,777 $0 $0 $26,557 $2,548 $0 $2,911 $32,016 $69 8.2 Turbine Plant Auxiliaries $157 $0 $359 $0 $0 $515 $50 $0 $57 $622 $1 8.3a Condenser & Auxiliaries $2,301 $0 $735 $0 $0 $3,036 $290 $0 $333 $3,659 $8 8.3b Air Cooled Condenser $21,086 $0 $4,227 $0 $0 $25,314 $2,531 $0 $5,569 $33,414 $73 8.4 Steam Piping $4,802 $0 $3,378 $0 $0 $8,181 $703 $0 $2,221 $11,104 $24 8.9 TG Foundations $0 $776 $1,312 $0 $0 $2,088 $198 $0 $686 $2,972 $6 SUBTOTAL 8. $51,126 $776 $13,789 $0 $0 $65,691 $6,321 $0 $11,776 $83,788 $182
9 COOLING WATER SYSTEM 9.1 Cooling Towers $4,007 $0 $729 $0 $0 $4,736 $451 $0 $778 $5,964 $13 9.2 Circulating Water Pumps $1,035 $0 $58 $0 $0 $1,093 $92 $0 $178 $1,363 $3 9.3 Circ.Water System Auxiliaries $94 $0 $13 $0 $0 $108 $10 $0 $18 $136 $0 9.4 Circ.Water Piping $0 $3,930 $1,019 $0 $0 $4,949 $447 $0 $1,079 $6,475 $14 9.5 Make-up Water System $260 $0 $372 $0 $0 $632 $61 $0 $139 $832 $2 9.6 Component Cooling Water Sys $464 $555 $395 $0 $0 $1,414 $132 $0 $309 $1,855 $4 9.9 Circ.Water System Foundations $0 $1,447 $2,460 $0 $0 $3,907 $370 $0 $1,283 $5,561 $12 SUBTOTAL 9. $5,860 $5,932 $5,047 $0 $0 $16,839 $1,564 $0 $3,784 $22,187 $48 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

268 

### Exhibit 3

- 81 Case S2B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-15 Project: Low Rank Western Coal Baseline Study

Case: Case S2B - TRIG IGCC w/ CO2 Plant Size: 460.9 MW,net Estimate Type: Conceptual Cost Base (June) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $17,590 $0 $8,674 $0 $0 $26,264 $2,524 $0 $2,879 $31,667 $69 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $587 $0 $638 $0 $0 $1,225 $119 $0 $202 $1,545 $3 10.7 Ash Transport & Feed Equipment $787 $0 $190 $0 $0 $977 $91 $0 $160 $1,228 $3 10.8 Misc. Ash Handling Equipment $1,215 $1,489 $445 $0 $0 $3,149 $300 $0 $517 $3,966 $9 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $0 $117 $11 $0 $38 $166 $0 SUBTOTAL 10. $20,179 $1,541 $10,013 $0 $0 $31,732 $3,044 $0 $3,796 $38,573 $84
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $859 $0 $850 $0 $0 $1,709 $163 $0 $187 $2,060 $4 11.2 Station Service Equipment $4,297 $0 $387 $0 $0 $4,684 $432 $0 $512 $5,628 $12 11.3 Switchgear & Motor Control $7,944 $0 $1,445 $0 $0 $9,388 $871 $0 $1,539 $11,798 $26
11.4 Conduit & Cable Tray $0 $3,690 $12,174 $0 $0 $15,864 $1,534 $0 $4,350 $21,748 $47 11.5 Wire & Cable $0 $7,051 $4,633 $0 $0 $11,683 $849 $0 $3,133 $15,665 $34 11.6 Protective Equipment $0 $624 $2,269 $0 $0 $2,893 $283 $0 $476 $3,652 $8
11.7 Standby Equipment $216 $0 $211 $0 $0 $426 $41 $0 $70 $537 $1 11.8 Main Power Transformers $15,639 $0 $128 $0 $0 $15,767 $1,192 $0 $2,544 $19,503 $42 11.9 Electrical Foundations $0 $139 $365 $0 $0 $504 $48 $0 $166 $718 $2 SUBTOTAL 11. $28,954 $11,504 $22,461 $0 $0 $62,920 $5,413 $0 $12,976 $81,309 $176
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,059 $0 $707 $0 $0 $1,767 $167 $88 $303 $2,326 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $243 $0 $156 $0 $0 $400 $38 $20 $91 $549 $1 12.7 Computer & Accessories $5,652 $0 $181 $0 $0 $5,832 $535 $292 $666 $7,325 $16 12.8 Instrument Wiring & Tubing $0 $1,974 $4,036 $0 $0 $6,010 $510 $301 $1,705 $8,526 $19 12.9 Other I & C Equipment $3,778 $0 $1,834 $0 $0 $5,612 $528 $281 $963 $7,384 $16 SUBTOTAL 12. $10,732 $1,974 $6,915 $0 $0 $19,621 $1,778 $981 $3,729 $26,110 $57 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $101 $2,159 $0 $0 $2,260 $224 $0 $745 $3,230 $7 13.2 Site Improvements $0 $1,797 $2,388 $0 $0 $4,185 $413 $0 $1,379 $5,977 $13 13.3 Site Facilities $3,220 $0 $3,398 $0 $0 $6,618 $652 $0 $2,181 $9,451 $21 SUBTOTAL 13. $3,220 $1,898 $7,945 $0 $0 $13,063 $1,290 $0 $4,306 $18,659 $40
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $1,984 $2,826 $0 $0 $4,810 $443 $0 $788 $6,040 $13 14.3 Administration Building $0 $835 $606 $0 $0 $1,441 $128 $0 $235 $1,804 $4
14.4 Circulation Water Pumphouse $0 $157 $83 $0 $0 $240 $21 $0 $39 $300 $1 14.5 Water Treatment Buildings $0 $374 $365 $0 $0 $739 $67 $0 $121 $926 $2 14.6 Machine Shop $0 $427 $292 $0 $0 $720 $64 $0 $118 $901 $2
14.7 Warehouse $0 $690 $445 $0 $0 $1,135 $101 $0 $185 $1,421 $3 14.8 Other Buildings & Structures $0 $413 $322 $0 $0 $735 $66 $0 $160 $961 $2 14.9 Waste Treating Building & Str. $0 $924 $1,765 $0 $0 $2,689 $251 $0 $588 $3,528 $8 SUBTOTAL 14. $0 $6,068 $6,854 $0 $0 $12,922 $1,176 $0 $2,324 $16,423 $36

TOTAL COST $705,833 $62,309 $258,448 $0 $0 $1,026,590 $95,414 $75,563 $193,851 $1,391,417 $3,019 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

269 

### Exhibit 3

- 82 Case S2B Owner’s Cos ts

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $11,155 $24 1 Month Variable O&M $2,962 $6 25% of 1 Months Fuel Cost at 100% CF $802 $2 2% of TPC $27,828 $60 Total $42,748 $93

Inventory Capital 60 day supply of consumables at 100% CF $6,787 $15 0.5% of TPC (spare parts) $6,957 $15 Total $13,745 $30

Initial Cost for Catalyst and Chemicals $6,042 $13 Land $900 $2 Other Owner's Costs $208,713 $453 Financing Costs $37,568 $82

Total Owner's Costs $309,715 $672 Total Overnight Cost (TOC) $1,701,132 $3,691 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $1,939,291 $4,208Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

270 

### Exhibit 3

- 83 Case S2B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (June): 2007 Case S2B - TRIG IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10740 MWe-net: 461 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $13.700 Maintenance Labor Cost $11,535,125 $25.030 Administrative & Support Labor $4,462,158 $9.682 Property Taxes and Insurance $27,828,342 $60.385 TOTAL FIXED OPERATING COSTS $50,139,132 $108.797 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $23,182,469 $0.00718

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 2,152 1.08 $0 $679,733 $0.00021

Chemicals

MU & WT Chem. (lb) 0 12,821 0.17 $0 $647,944 $0.00020 Carbon (Mercury Removal) (lb) 89,518 123 1.05 $94,009 $37,604 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 5,053 3.46 498.83 $2,520,820 $504,164 $0.00016 Selexol Solution (gal) 255,792 81 13.40 $3,427,162 $318,336 $0.00010 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.76 131.27 $0 $29,076 $0.00001 Subtotal Chemicals $6,041,991 $1,537,124 $0.00048

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 123 0.42 $0 $14,934 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 637 16.23 $0 $3,019,289 $0.00093 Subtotal Waste Disposal $0 $3,034,224 $0.00094

By-products & Emissions

Sulfur (tons) 0 50 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $6,041,991 $28,433,550 $0.00880

Fuel (ton) 0 6,935 15.22 $0 $30,815,893 $0.00954Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

271 

### 3.4 S IEMENS FUEL GASIFIER IGCC CASES

This section contains an evaluation of plant designs for Cases S3A, S3B, L3A, and L3B

, which are based on the SFG . The non

- capture (A) and CO 2 

### capture (B) cases are very similar in terms of process, equipment, scope and arrangement, except that CO 2 

### capture cases includes SGS reactors, CO 2 

### absorption/regeneration and compression/transport s ystems.

Section 3.4.4 covers the results for the S3A and L3A non

- capture case using PRB and Lignite coal and Section 3.4.8 covers the S3B and L3B CO 2 

### - capture cases. The sections are organized analogously as follows:

**•** Process and System Description provides an overview of the specific technolog y’s operation.

**•** BF D and stream table display results for major processes and streams

.

**•** Performance Results provides the main modeling results, including the performance summary, environmental performance, carbon balance, sulfur balance, water balance, mass and energy balance diagrams

, and mass and energy balance tables.

**•** Equipment List provides an itemized list of major equipment with account codes that correspond to the cost accounts in the Cost Estimates section.

**•** Cost Estimates provides a summary of capital and operating cost s.
Process and System Description, Performance Results, Equipment List and Cost Estimates are repeated for the CO 2 

### capture cases in Section 3.4.8 . If the informat ion is identical to that presented for the non

- capture cases, a reference is made to the earlier section rather than repeating the information.

3.4.1 Gasifier Background

Development and Current Status

– The SFG process for IGCC applications is based on the Noell process, also known under the name GSP, developed by Deutsches Brennstoffinstitut Freiberg in 1975 for the gasification of German domestic brown coal and other solid fuels. The Noell Group acquired the technology in 1991 and did further development to ga sify waste materials and liquid residues. The gasifier was marketed under the Future Energy GmbH company and was sold to Siemens in 2006. The first gasifier of this type was a 200 megawatt thermal ( MWth ) thermal unit built at Schwarze Pumpe, Germany in 1 984, firing high sodium lignite. It was converted to process natural gas and waste liquids in 1990. Other installations include a 5 MWth test plant in Freiberg, Germany where alternative feed testing is ongoing and a 175 MWth autothermal oil conversion p lant in the Czech Republic, commissioned in 2008. Current gasifier projects include the Shanxi Lanhua Coal 1,000 MWth coal to ammonia plant, which is in its engineering phase, and the Shenhua Ningxia Coal Based Polypropylene Project with capacity of 2

, 500 MWth of coal to polypropylene production, due to enter commercial operation in mid 2011 . Siemens SFG

- 500 Gasifiers are also planned for the Secure Energy, Coal to SNG project in IL slated to be commissioned in 201 3

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

272 

### In this study, three parallel Siemens dry feed, pressurized, down flow , entrained, slagging gasifiers are used to power two advanced F

- class turbines. The Siemens gasifiers have a

‘ cooling screen ’ (heat exchanger tubes) on the inside surface of the gasifier

, which eliminates the need for ref ractory inside the gasifier. This cooling screen also raises a small amount of LP steam that is used inside the gasification island to heat the O 2 

### before entering the gasifier. A full quench in the bottom of the gasifier helps remove the slag and also co ols the syngas for further downstream cleanup and heat recovery.

Gasifier Capacity

– At the outset of this study, t he largest commercial offering from Siemens wa s a nominal 500 MW thermal input gasifier. The largest current commercial offering is a nomina l 1,200 MW thermal input gasifier. Based on vendor input and assuming a 500 MW thermal gasifier , less than 3 gasifiers are required to run the plant at full capacity except the lignite CCS case

, which requires 3.2 gasifiers due to the low quality coal and high auxiliary requirements. For consistency and comparability, all the cases were costed as three gasifiers, while accounting for the differences in gas flow.

Distinguishing Characteristics

– The Siemens gasifier is a dry feed, entrained flow, slagging, single stage, down

- flow gasifier producing syngas at high pressures and temperatures. The gasifier uses a cooling screen design to control the reactor vessel wall temperature. The gasifier temperature is controlled above the slag fluid temperature to assure the creat ion of a protective slag layer on the inside of the cooling screen while LP steam is generated in the cooling screen . This approach helps minimize the risk of slag attack that occurs with refractory lining and helps improves the lifetime

a nd maintenance

, as well as start

- up and shutdown times. The more complex dry feeding system helps achieve high conversion rates, lower oxygen consumption and higher efficiencies

co mpared to slurry fed systems.

The gasifier unit also contains a built in qu ench section below the reaction section where both the hot raw syngas and liquid slag are discharged and the raw gas is cooled and saturated by injection of water. Molten slag is cooled and granulated in a water bath at the bottom of the quench vessel. T his mode of operation helps improve the reliability of the gasifier by simplifying the raw gas quench and slag removal steps, at the expense of adding moisture to the syngas. The high temperature in the gasifier ensure s that no tars or other hydrocarbon l iquids are formed, and the quench section helps reduce the syngas exit temperature. This built in quench can be a competitive alternative to high temperature syngas cooling, especially for CO 2 

### capture and chemical synthesis applications where H 2 

### and CO 2 

### i s preferable to CO production, as it uses the sensible heat of the syngas to directly raise steam for the WGS reaction, avoiding extracting steam from the steam cycle and the cost of the necessary heat exchangers.

Important Coal Characteristics

– The Sie mens gasifier is generally able to fire most types of coal, petcoke, or mixed feeds. The gasifier temperature can be controlled to use a wid e range of feeds, which Siemens can characterize at their test facility, in order to develop specific operating
par ameters for each fuel and ash type.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

273 

### 3.4.2 Key System Assumptions System assumptions for Cases S3A and L3A and S3B and L3B, SFG IGCC using PRB and lignite coal with and without CO 2 

### capture, are compiled in Exhibit 3

- 84

. Exhibit 3

- 84 Case S3A/L3A and S3B/L3B Plant Study Configuration Matrix
Case S3A / L3A S3B / L3B Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0. 758 / 0.7 20 0. 767 / 0. 719 Carbon Conversion, % 99.5 99.5 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

### (Btu/scf) 4
, 824 ( 130 ) / 4
, 437 ( 119 ) 4
, 834 ( 130 ) / 4
, 651 ( 125 )

Nominal Steam Cycle, MPa/°C/°C (psig/ **°** F/ **°** F) 12.4/566/566 (1800/1050/1050) 12.4/538/538 (1800/1000/1000) Condenser Pressure, mm Hg (in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine 2x Advanced F Class (Nominal 232 MW output each, reduced by elevation considerations) 2x Advanced F Class (Nominal 232 MW output each, reduced by elevation considerations) Gasifier Technology Siemens (SFG) Siemens (SFG)

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Subbituminous / Lignite Subbituminous / Lignite Coal Feed Moisture Content, % 6 / 12 6 / 12 COS Hydrolysis Yes Yes (Part of WGS)

Water Gas Shift No Yes

H 2 

### S Separation Sulfinol

- M Selexol (1 st 

### Stage) Sulfur Removal, % 99. 8 99. 7

CO 2 

### Separation None Selexol (2 nd 

### Stage)

CO 2 

### Removal, % N/A 90

Sulfur Recovery Claus Plant with Tail Gas Treatment / Elemental Sulfur Claus Plant with Tail Gas Treatment / Elemental Sulfur

Particulate Control Cyclone , Scrubber, and AGR Absorber Cyclone

, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N 2 

### Dilution MNQC (LNB) and N 2 

### DilutionCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

274 

### Balance of Plant

– All Cases The balance of plant assumptions are common to all cases and are presented in Exhibit 3

- 85

.

Exhibit 3

- 85 Balance of Plant Assumptions
Cooling water system Recirculating Wet Cooling Tower Fuel and Other storage Coal 30 days Slag 30 days Sulfur 30 days Sorbent 30 days Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt

Motors between 250 hp and 5,000 hp 4,160 volt
Motors above 5,000 hp 13,800 volt Steam and CT Generators 24,000 volt Grid Interconnection Voltage 345 kV Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW and 50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup requirements. Makeup for potable, process, and DI water is drawn from municipal sources

Process Wastewater Water associated with gasification activity and storm water that contacts equipment surfaces is collected and treated for discharge through a permitted discharge.

Sanitary Waste Disposal Design includes a packaged domestic sewage treatment plant with effluent discharged to the industrial wastewater treatment system. Sludge is hauled off site. Packaged plant was sized for 5.68

m 3 

### /d (1,500 GPD )

Water Discharge Most of the process wastewater is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and discharged.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

2 75 

### 3.4.3 Sparing Philosophy

The sparing philosophy is provided below. Single trains are utilized throughout with exceptions where eq uipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

**•** Two ASU s (2 x 50%).

**•** Two trains of coal drying and dry feed systems (2 x 50%).

**•** Three trains of gasification, including gasifier, SGC , cyclone, and barrier filter ( 3 x 33 %).

**•** Two trains of syngas clean

- up process (2 x 50%).

**•** Two t rains of Sulfinol

- M acid gas removal in non

- capture cases and two trains of two

stage Selexol in CO 2 

### capture cases (2 x 50%).

**•** One train of Claus

- based sulfur recovery (1 x 100%).

**•** Two CT /HRSG tandems (2 x 50%).

**•** One steam turbine (1 x 100%).

3.4.4 SFG IGCC Non

- Capture Case (S3A and L3A) Process Description

In this section the overall SFG process for Case S3A and L3A is described. The process does not change with fuel type so a single description is provided. The system description follows the BFD in Exhibit 3

- 86 and stream numbers reference the same exhibit. The tables in Exhibit 3

- 87 and E xhibit 3

- 88 provide process data for the numbered streams in the BFD. Coal Preparation and Feed Systems Coal receiving and handling is common to all cases and was covered in Section 3.1.1 . The receiving and handling subsystem ends at the coal silo. The SFG uses a dry feed system

, which is sensitive to the coal moisture content. Coal moisture consis ts of two parts, surface moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the surface moisture must be removed. The PRB coal used in this study contains 25.77 percent total moisture on an

as

- received basis and the NDL c ontains 36.08 percent moisture. It was assumed that the PRB coal must be dried to 6 percent moisture and the lignite to 12 percent to allow for smooth flow through the dry feed system.

The raw coal is crushed in the coal mill then delivered to a surge hop per with an approximate 2

- hour capacity, which in turn delivers the coal to the coal pre

- heater. The WTA coal drying process includes a water

- heated, horizontal , rotary

- kiln coal pre

- heater, a fluidized be d coal dryer and a water

- cooled, horizontal , rotar y

- kiln coal cooler. The moisture driven from the coal in the fluid bed dryer passes through a baghouse for particulate removal and then is split into two streams. The smaller of the two streams is compressed and used as the fluidizing medium in theCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

276 

### coal dryer. The bulk of the removed moisture is compressed and the high temperature vapor passes through internal coils in the dryer to provide the heat to drive off the coal moisture and then exits the dryer as liquid water. The warm water is used in the coa l pre

- heater before being used as cooling tower makeup water. The vapor compressor consumes the vast majority of the WTA process auxiliary load.

The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the gasifiers.

Gasifier

There are three Siemens dry feed, pressurized, down

- flow, entrained, slagging gasifiers, operating at 4.24 MPa (615 psia) and processing a total of 5,782 tonne/day (6,373 tpd) of as

rec eived coal in the PRB case and 8,098 tonne/day (8,927 tpd) in the lignite case. Coal reacts with oxygen in a reducing environment to produce principally hydrogen and carbon monoxide with little CO 2 

### formed. The hot raw syngas and the liquid slag flow down into the quench chamber of the gasifier and the raw gas is cooled and saturated by injecting water. The slag is cooled and granulated in a water bath at the bottom of the quench vessel. Syngas Scrubber /Particulate Rem oval A raw gas ventur i scrubber system thoroughly mixes the raw syngas with water to ensure wetting of fine ash and soot particles. Cyclones are used to separate the water and particulates from the
raw gas. Syn gas scrubbers are employed and use gas conde nsate from the downstream gas cooling processes. The fine particulates are removed in a partial condenser, which continues cooling the gas, downstream of the scrubber unit. The particulates act as condensation cores and are caught by the condensed drople ts in the partial condenser and are recycled to the gasifier quench chamber

. Sour Water Stripper The sour water stripper removes ammonia, sulfur, and other impurities from the waste stream of the scrubber. The sour gas stripper consists of a sour drum tha t accumulates sour water from various plant sources . 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 and sent to the SRU . Remaining water is sent t o wastewater treatment. COS Hydrolysis, Mercury Removal and AGR

H 2 

### S and COS are at significant concentrations, requiring removal for the power plant to achieve the low design level of SO 2 

### emissions. H 2 

### S is removed in an AGR process; however, because COS i s not readily removed, it is first catalytically converted to H 2 

### S in a COS hydrolysis unit.

The cooled raw gas is fed to the COS hydrolysis reactor where the COS in the sour gas is hydrolyzed with steam, over a catalyst bed, into H 2 

### S, which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the AGR process, it must be cooled to about 35 **°** C ( 95 **°** F). During this cooling through a series of heat exchangers, part of the water vapor condenses. This water, which contains some NH 3 

### , is sent to the sour water stripper. The cooled syngas then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.8 ).Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

277 

### The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a mixture of amines and a physical solvent. The solvent consists of an aqueous amine and sulfolane. Sulfinol

- D uses DIPA, while Sulfinol

- M uses MDEA. The mixed solvents allow for better solvent loadings at high acid gas partial pressures and higher solubility of COS and organic sulfur compounds than straight aqueous amines. Sulfinol

- M was selected for the Siemens non

- CO 2 

### capture applications.

The sour syngas is fed directly into an HP contactor. The HP contactor is an absorption column in which the H 2 

### S, COS, CO 2 

### , and small amounts of H 2 

### and CO are removed from the gas by the Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in the sweet ga s scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in th e LP contactor with lean solvent to remove H 2 

### S and COS. The overhead from the LP contactor is flashed in the LP KO drum. This gas can be used as a utility fuel gas, consisting primarily of H 2 

### and CO, at 0.8 MPa (118 psia) and 38 **°** C (101 **°** F). The solvent f rom the bottom of the LP contactor is returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before entering the stripper. The stripper strips the H 2 

### S, COS, and CO 2 

### from the solv ent at low pressure with heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is recovered as the flash gas from the stripper accumulator. The lean solvent from the bottom of the stripper is cooled in the l ean/rich solvent exchanger and the lean solvent cooler. Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP
contactor.

The Sulfinol process removes about 15 percent of the CO 2 

### along with the H 2 

### S and COS. The acid gas is fed to the SRU

. The residual CO 2 

### passes through the SRU, the hydrogenation reactor and is recycled to the gasifier. However, the costs of the sulfur recovery/tail gas cleanup are higher than for a sulfur removal process producing an acid gas stream with a higher sulfur concentration.

Cl aus Unit

The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus plant produces molten sulfur by converting approximately one third of the H 2 

### S in the feed to SO 2 

### , then reacting the H 2 

### S and SO 2 

### to sulfur and water. The combination of Claus technology and tail gas recycle results in an overall sulfur recovery exceeding 99 percent , producing 42 tonne/day (46 tpd) of sulfur in the PRB case and 51 tonne/day (56 tpd) in the lignite case

. Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery plant. Feed for each case consists of acid gas from both the acid gas cleanup unit and a vent stream from the sour water stripper in the gasifier section.

In the furnace waste heat boiler steam is generated . This steam is used to satisfy all Claus process preheating and reheating requirements

, as well as to provide some steam to the medium

-Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

278 

### pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header.

Power Block

Cl ean syngas exiting the Sulfinol absorber is reheated, diluted with nitrogen from the ASU, and enters the advanced F Cl ass CT burner. The CT compressor provides combustion air to the burner and also a portion of the air requirement for the ASU. The exhaus t gas exits the CT around 566°C (1,050°F) and enters the HRSG where additional heat is recovered until the flue gas exits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, comme rcially available steam turbine using a nominal 12.4 MPa/566°C/566°C (1800 psig/1050°F/1050°F) steam cycle. Air Separation Unit The ASU is designed to produce approximately 3,468 tonne/day (3,823 tpd) in the PRB case and 3,979 tonne/day (4,386 tpd) in the lignite case of 95 mole percent O 2 

### for use in the gasifier and SRU . The plant is designed with two production trains. The air compressor is powered by an electric motor. Nitrogen is also recovered, compressed, and used as dilution in the CT combustor or as a coal transport fluid. Air extraction is taken from the CT compressor to reduce the size of the main air compressor.

Balance of Plant Balance of plant items were covered in Sections 3.1.12
, 3.1.13
, 3.1.14
, and 3.1.15

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

279 

### Exhibit 3

- 86 Case S3A and L3A Process Flow DiagramCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

280 

### Exhibit 3

- 87 Case S3A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction

Ar 0.0093 0.0093 0.0291 0.0318 0.0023 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0046 0.0000 0.0046
CH 4 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 0.0000
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2649 0.0000 0.2649
CO 2 0.0003 0.0003 0.0102 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0230 0.0000 0.0231
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 0.0001 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 0.1332 0.0000 0.1332

H 2 O 0.0064 0.0064 0.1937 0.0000 0.0002 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 0.5443 0.9998 0.5442

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0014 0.0000 0.0016

N 2 0.7759 0.7759 0.5163 0.0178 0.9920 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0278 0.0000 0.0278

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 0.0007 0.0002 0.0007
O 2 0.2081 0.2081 0.2507 0.9504 0.0054 0.0054 0.9500 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 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 18,872 2,907 699 35 14,895 1,695 4,449 1,162 0 2,813 0 0 34,856 17,564 34,856 V-L Flowrate (kg/hr) 545,309 83,991 19,275 1,134 417,964 47,561 143,382 20,927 0 50,668 0 0 680,934 316,426 680,934 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 240,911 0 190,243 20,328 0 0 0

Temperature (°C) 6 411 21 32 196 125 32 343 6 33 71 260 214 175 214 Pressure (MPa, abs) 0.09 1.43 0.11 0.86 2.65 5.62 0.86 5.10 0.09 0.55 0.09 4.17 4.10 8.27 4.03 Enthalpy (kJ/kg) A 15.26 434.33 40.10 26.67 202.63 123.73 26.59 3,062.93

--- 140.13

--- --- 1,567.59 699.71 1,567.49 Density (kg/m 3 ) 1.1 7.2 1.6 11.0 18.9 47.0 11.0 20.1

--- 985.3

--- --- 20.9 833.2 20.5 V-L Molecular Weight 28.895 28.895 27.587 32.181 28.061 28.061 32.229 18.015

--- 18.015

--- --- 19.536 18.015 19.536

V-L Flowrate (lb mol /hr) 41,606 6,408 1,540 78 32,838 3,737 9,808 2,561 0 6,201 0 0 76,844 38,722 76,844 V-L Flowrate (lb/hr) 1,202,201 185,168 42,494 2,500 921,453 104,854 316,103 46,136 0 111,704 0 0 1,501,202 697,601 1,501,202 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 531,119 0 419,414 44,815 0 0 0

Temperature (°F) 42 771 70 90 385 257 90 650 42 92 160 500 418 347 417 Pressure (psia) 13.0 207.6 16.4 125.0 385.0 815.0 125.0 740.0 13.0 80.1 12.7 604.7 594.7 1,200.0 584.7 Enthalpy (Btu/lb) A 6.6 186.7 17.2 11.5 87.1 53.2 11.4 1,316.8

--- 60.2

--- --- 673.9 300.8 673.9 Density (lb/ft 3 ) 0.070 0.452 0.097 0.687 1.183 2.937 0.688 1.257

--- 61.510

--- --- 1.304 52.017 1.282 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

281 

### Exhibit 3

- 87 Case S3A Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 V-L Mole Fraction

Ar 0.0101 0.0057 0.0101 0.0006 0.0000 0.0041 0.0102 0.0102 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000
CH 4 0.0001 0.0000 0.0001 0.0000 0.0000 0.0000 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 0.5812 0.0026 0.5715 0.0213 0.0000 0.0457 0.5814 0.5814 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.0506 0.5462 0.0592 0.5013 0.0000 0.3467 0.0512 0.0512 0.0003 0.0814 0.0814 0.0000 0.0000 0.0000 0.0000
COS 0.0000 0.0002 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
H 2 0.2922 0.0996 0.2890 0.0118 0.0000 0.0274 0.2940 0.2940 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0015 0.0324 0.0016 0.0089 0.0000 0.3519 0.0014 0.0014 0.0064 0.0431 0.0431 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0034 0.0916 0.0049 0.2762 0.0000 0.0654 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0609 0.2217 0.0637 0.1799 0.0000 0.1585 0.0616 0.0616 0.7759 0.7540 0.7540 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000
O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1125 0.1125 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 0.0000
Total 1.0000 1.0000 1.0000 1.0000 0.0000 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) 15,882 278 16,153 286 0 389 15,793 15,793 102,359 123,228 123,228 21,819 18,972 18,972 39,649 V-L Flowrate (kg/hr) 339,066 9,598 348,526 10,670 0 11,596 336,292 336,292 2,957,681 3,627,946 3,627,946 393,078 341,794 341,794 714,297 Solids Flowrate (kg/hr) 0 0 0 0 1,748 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 49 35 51 181 138 51 196 6 587 134 559 32 32 33 Pressure (MPa, abs) 3.93 0.32 3.86 0.4 0.370 0.370 3.597 3.563 0.090 0.093 0.090 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 42.64 88.47 41.65 55.0

--- 689.453 66.652 275.179 15.260 698.571 202.573 3,496.917 2,248.547 2,248.547 140.297 Density (kg/m 3 ) 32.7 4.2 32.6 5.8

--- 3.3 28.3 19.2 1.1 0.4 0.8 35.2 0.04 0.04 995.0 V-L Molecular Weight 21.349 34.468 21.577 37

--- 29.783 21.293 21.293 28.895 29.441 29.441 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 35,014 614 35,610 630 0 858 34,818 34,818 225,664 271,670 271,670 48,103 41,827 41,827 87,412 V-L Flowrate (lb/hr) 747,513 21,161 768,368 23,524 0 25,566 741,397 741,397 6,520,570 7,998,253 7,998,253 866,588 753,527 753,527 1,574,754 Solids Flowrate (lb/hr) 0 0 0 0 3,855 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 120 94 124 358 280 124 385 42 1,088 272 1,038 90 90 92 Pressure (psia) 569.7 46.5 559.7 60.0 53.6 53.6 521.7 516.7 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 18.3 38.0 17.9 23.7

--- 296.4 28.7 118.3 6.6 300.3 87.1 1,503.4 966.7 966.7 60.3 Density (lb/ft 3 ) 2.042 0.260 2.032 0.363

--- 0.203 1.767 1.199 0.070 0.024 0.049 2.200 0.002 0.002 62.116Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

282 

### Exhibit 3

- 88 Case L3A Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction

Ar 0.0093 0.0093 0.0293 0.0318 0.0023 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0046 0.0000 0.0046
CH 4 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 0.0000
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2484 0.0000 0.2484
CO 2 0.0003 0.0003 0.0103 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0268 0.0000 0.0269
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 0.0001 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 0.1176 0.0000 0.1176

H 2 O 0.0062 0.0062 0.1878 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000 1.0000 0.0000 0.0000 0.5677 1.0000 0.5675

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0015 0.0000 0.0016

N 2 0.7761 0.7761 0.5200 0.0178 0.9920 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0328 0.0000 0.0328

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 0.0005 0.0000 0.0005
O 2 0.2082 0.2082 0.2525 0.9504 0.0054 0.0054 0.9500 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 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 21,582 3,397 796 44 16,673 2,358 5,100 0 0 5,125 0 0 40,317 20,979 40,317 V-L Flowrate (kg/hr) 623,675 98,158 22,008 1,406 467,870 66,177 164,371 0 0 92,335 0 0 797,136 377,958 797,136 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 337,436 0 245,101 33,948 0 0 0

Temperature (°C) 4 408 21 32 196 125 32

--- 4 32 71 260 217 175 216 Pressure (MPa, abs) 0.10 1.52 0.11 0.86 2.65 5.62 0.86

--- 0.10 0.34 0.09 4.17 4.10 8.27 4.03 Enthalpy (kJ/kg) A 13.75 431.19 40.37 26.67 202.62 123.72 26.59

--- --- 135.07

--- --- 1,604.74 700.03 1,604.63 Density (kg/m 3 ) 1.2 7.7 1.5 11.0 18.9 47.0 11.0

--- --- 986.5

--- --- 21.1 833.3 20.8 V-L Molecular Weight 28.898 28.898 27.657 32.181 28.061 28.061 32.229

--- --- 18.015

--- --- 19.771 18.016 19.771

V-L Flowrate (lb mol /hr) 47,581 7,489 1,754 96 36,759 5,199 11,244 0 0 11,299 0 0 88,885 46,252 88,885 V-L Flowrate (lb/hr) 1,374,968 216,401 48,519 3,100 1,031,478 145,896 362,377 0 0 203,563 0 0 1,757,383 833,254 1,757,383 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 743,918 0 540,355 74,843 0 0 0

Temperature (°F) 40 767 70 90 385 257 90

--- 40 90 160 500 422 347 421 Pressure (psia) 13.8 220.4 16.4 125.0 385.0 815.0 125.0

--- 13.8 50.0 13.5 604.7 594.7 1,200.0 584.7 Enthalpy (Btu/lb) A 5.9 185.4 17.4 11.5 87.1 53.2 11.4

--- --- 58.1

--- --- 689.9 301.0 689.9 Density (lb/ft 3 ) 0.074 0.482 0.097 0.687 1.183 2.937 0.688

--- --- 61.584

--- --- 1.320 52.024 1.298 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

283 

### Exhibit 3

- 88 Case L3A Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 V-L Mole Fraction

Ar 0.0106 0.0062 0.0105 0.0005 0.0000 0.0041 0.0107 0.0107 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000
CH 4 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 0.0000
CO 0.5744 0.0014 0.5645 0.0193 0.0000 0.0365 0.5753 0.5753 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.0621 0.6432 0.0725 0.5621 0.0000 0.3896 0.0628 0.0628 0.0003 0.0852 0.0852 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000
H 2 0.2718 0.0587 0.2681 0.0100 0.0000 0.0179 0.2732 0.2732 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0015 0.0324 0.0016 0.0080 0.0000 0.3813 0.0014 0.0014 0.0062 0.0415 0.0415 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0037 0.0095 0.0038 0.1960 0.0000 0.0012 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0758 0.2486 0.0790 0.2041 0.0000 0.1644 0.0765 0.0765 0.7761 0.7544 0.7544 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000
O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2082 0.1098 0.1098 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0048 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 0.0000 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) 17,434 317 17,741 343 0 479 17,326 17,326 106,961 130,213 130,213 23,023 21,431 21,431 43,503 V-L Flowrate (kg/hr) 384,801 11,581 396,212 12,995 0 14,462 381,626 381,626 3,090,914 3,842,252 3,842,252 414,769 386,093 386,093 783,714 Solids Flowrate (kg/hr) 0 0 0 0 2,111 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 49 35 51 174 138 51 196 4 588 132 560 32 32 33 Pressure (MPa, abs) 3.89 0.32 3.82 0.4 0.370 0.370 3.597 3.563 0.095 0.099 0.095 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 40.72 83.74 39.48 53.4

--- 724.869 63.973 266.790 13.748 697.002 197.901 3,500.312 2,248.933 2,248.933 139.912 Density (kg/m 3 ) 33.6 4.4 33.5 5.9

--- 3.3 29.3 19.9 1.2 0.4 0.8 35.2 0.04 0.04 995.0 V-L Molecular Weight 22.072 36.583 22.333 38

--- 30.205 22.027 22.027 28.898 29.508 29.508 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 38,435 698 39,113 757 0 1,056 38,197 38,197 235,808 287,070 287,070 50,757 47,248 47,248 95,907 V-L Flowrate (lb/hr) 848,340 25,533 873,497 28,650 0 31,884 841,341 841,341 6,814,298 8,470,716 8,470,716 914,408 851,189 851,189 1,727,793 Solids Flowrate (lb/hr) 0 0 0 0 4,654 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 120 94 124 345 280 124 385 40 1,091 269 1,041 90 90 92 Pressure (psia) 564.7 46.5 554.7 60.0 53.6 53.6 521.7 516.7 13.8 14.3 13.8 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 17.5 36.0 17.0 23.0

--- 311.6 27.5 114.7 5.9 299.7 85.1 1,504.9 966.9 966.9 60.2 Density (lb/ft 3 ) 2.097 0.276 2.090 0.368

--- 0.206 1.831 1.240 0.074 0.025 0.052 2.195 0.002 0.002 62.118Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

284 

### 3.4.5 Case S3A and L3A Performance Results

The non

- capture SFG IGCC plant using PRB coal at the Montana site (elevation 3,400 ft) produces a net output of 505 MWe at a net plant efficiency of 37.9 percent (HHV basis). The same plant configuration using lignite coal at the NDL site (elevation 1,900 ft) produces a net output of 543 MWe at a ne t plant efficiency of 37.6 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3

- 89
, which includes auxiliary power requirements. The AS U accounts for approximately 7 4 percent of the total auxiliary load, distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The coal handling and drying account for approximately 1 0 percent of the auxiliary load. The cooling water system, including the CWP s and cooling tower fan, and the air

- cooled condenser account for about 6 percent of the auxiliary load. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

285 

### Exhibit 3

- 89 Case S3A and L3A Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) S3A L3A

Gas Turbine Power 415,100 446,500 Steam Turbine Power 207,100 232,300 TOTAL POWER, kWe 622,200 678,800 AUXILIARY LOAD SUMMARY, kWe Coal Handling 490 590 Coal Milling 2,480 3,470 Slag Handling 530 880 WTA Coal Dryer Compressor 8,490 11,860 WTA Coal Dryer Auxiliaries 560 780 Air Separation Unit Auxiliaries 1,000 1,000 Air Separation Unit Main Air Compressor 48,560 54,120 Oxygen Compressor 7,850 9,000 Nitrogen Compressors 29,220 33,820 Boiler Feedwater Pumps 2,490 2,710 Condensate Pump 230 260 Circulating Water Pump 2,320 2,480 Ground Water Pumps 200 200 Cooling Tower Fans 1,510 1,520 Air Cooled Condenser Fans 3,240 3,450 Quench / Scrubber Pumps 640 1,490 Acid Gas Removal 380 420 Gas Turbine Auxiliaries 1,000 1,000 Steam Turbine Auxiliaries 100 100 Claus Plant/TGTU Auxiliaries 250 250 Claus Plant TG Recycle Compressor 7 3 0 850 Miscellaneous Balance of Plant 1 3,000 3,000 Transformer Losses 2,210 2,430 TOTAL AUXILIARIES, kWe 117,4 8 0 135,680 NET POWER, kWe 504,7 2 0 543,120 Net Plant Efficiency, % (HHV) 37.9% 37.6% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,508 (9,01 2 ) 9,562 (9,063) CONDENSER COOLING DUTY GJ/hr (10 6 Btu/hr) 1,445 (1,370) 1,635 (1,550)
CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 240, 911 (531, 119 ) 337,436 (743,918) Thermal Input, kWt 1,33 3
, 034 1,442,644
Raw Water Withdrawal , m 3 /min (gpm) 8.6 (2,259) 8.3 (2,190)
Raw Water Consumption , m 3 /min (gpm) 6

. 5 ( 1
, 711 ) 6

. 1 ( 1
, 601 )

1 Includes plant control systems, lighting, HVAC

, and miscellaneous low voltage loadsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

286 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for the non

- capture cases is presented in Exhibit 3

- 90

.

Exhibit 3

- 90 Cases S3A and L3A Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

S3A L3A S3A L3A S3A L3A

SO 2 

### 0.002 (0.004) 0.001 (0.002) 57 (63) 34 (37) 0.013 ( 0 .0 29 ) 0.007 ( 0 .0 16 )

NO X 

### 0.026 (0.061) 0.026 (0.061) 878 (968) 960 (1,058) 0.201 ( 0 .444) 0.202 ( 0 .445)

Particulates 0.003 (0.0071) 0.003 (0.0071) 103 (113) 111 (122) 0.024 ( 0 .052) 0.023 ( 0 .051)

Hg 1.51E

- 7 (3.51E

- 7) 2.41E

- 7 (5.60E

- 7) 0.005 (0.006) 0.009 (0.010) 1.16E

- 6 (2.57E

- 6) 1.84E

- 6 (4.06E

- 6)

CO 2 

### gross 91.9 (213.8) 94.0 (218.6) 3,091,870 (3,408,203) 3,420,559 (3,770,521) 709 (1,563) 719 (1,585)

CO 2 

### net 874 (1,927) 899 (1,981)

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the Sulfinol

- M AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 5 ppmv in both cases. This results in a concentration in the flue gas of less than 1 ppmv. The H 2 

### S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated and recycled upstream of the AGR to capture most of th e remaining sulfur. Because the environmental target was set based on higher sulfur bituminous coal, the resulting SO 2 

### emissions with lower sulfur western coals are substantially less than the environmental target.

NO x emissions are limited to 15 ppmvd (a s NO 2 

### @ 15 percent O 2 

### ) by the use of low NOx burners and nitrogen dilution of the fuel gas . Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and destroyed in the Claus plant burner. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a ventur i scrubber and cyclone in addition to the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate o nly.

Ninety five percent of the mercury is captured from the syngas by an activated carbon bed.

CO 2 

### emissions represent the uncontrolled discharge from the process.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

287 

### The carbon balance for the two cases is shown in Exhibit 3

- 91

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components through out. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

### in the stack gas and ASU vent gas. Carbon that is not accounted for is shown as convergence tolerance.

Exhibit 3

- 91 Case S3A and L3A Carbon Balance
Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)
S3A L3A S3A L3A

Coal 120,620 (265,921) 133,468 (294,247) Slag 603 (1,330) 667 (1,471)

Air (CO 2 

### ) 477 (1,053) 506 (1,116) Stack Gas 120,408 (265,455) 133,209 (293,675)
ASU Vent 86 (189) 98 (217)

Total 121,097 (266,974) 133,975 (295,363) Total 121,097 (266,974) 133,975 (295,363)

Exhibit 3

- 92 shows the sulfur balance for the non

- capture case. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted i n the stack gas. Sulfur in the slag is considered to be negligible

.

Exhibit 3

- 92 Cases S3A and L3A Sulfur Balance
Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)
S3A L3A S3A L3A
Coal 1,753 (3,864) 2,114 (4,660) Elemental Sulfur 1,748 (3,855) 2,112 (4,655)
Stack Gas 4 (9) 2 (5)

Total 1,753 (3,864) 2,114 (4,660) Total 1,753 (3,864) 2,114 (4,660)

Exhibit 3

- 93 shows the overall water balance for the plant. 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, primarily as coal moisture from the drying process and syngas condensate, and that water is re

- used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Some water is discharged from the process to a permitted outfall. The difference between the withdrawal a nd discharge is the consumption

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

288 

### Exhibit 3

- 93 Case S3A and L3A 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)

S3A L3A S3A L3A S3A L3A S3A L3A S3A L3A
Slag Handling 0.44 (116) 0.74 (194) 0.44 (116) 0.74 (194) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Quench / Scrubber 5.28 (1395) 6.31 (1667) 4.72 (1248) 5.49 (1451) 0.56 (147) 0.82 (216) 0 (0) 0 (0) 0.56 (147) 0.82 (216)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0.05 (14) 0.06 (16)

- 0.05 (

- 14)

- 0.06 (

- 16)
Condenser Makeup 0.51 (135) 0.19 (51) 0 (0) 0 (0) 0.51 (135) 0.19 (51) 0 (0) 0 (0) 0.51 (135) 0.19 (51)

Gasifier Steam 0.35 (92) 0.35 (92)
BFW Makeup 0.16 (43) 0.19 (51) 0.16 (43) 0.19 (51)

Cooling Tower 9.01 (2,380) 9.64 (2,546) 1.53 (403) 2.36 (622) 7.49 (1,977) 7.28 (1,923) 2.03 (535) 2.17 (573) 5.46 (1442) 5.11 (1,351) Water from Coal Drying 0.85 (223) 1.54 (407) - 0.85 (

- 223) - 1.54 (

- 407)
BFW Blowdown 0.16 (43) 0.19 (51)

- 0.16 (

- 43)

- 0.19 (

- 51)

SWS Blowdown 0.52 (136) 0.62 (165) - 0.52 (

- 136) - 0.62 (

- 165)

Total 15.2 (4,027) 16.9 (4,458) 6. 7 (1,767) 8. 6 (2 , 267) 8.6 (2,2 59 ) 8.3 (2,190) 2. 1 (549) 2.2 (589) 6. 5 (1,711) 6. 1 (1,601)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

289 

### Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 94 and Exhibit 3

- 95 :

**•** Coal gasification and ASU

**•** Syngas cleanup

**•** Combined cycle power generation

An overall plant energy balance is provided in tabular form in Exhibit 3

- 96 for the two cases. The power out is the combined CT and steam turbine power after ge nerator losses.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

290 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

291 

### Exhibit 3

- 94 Case S3A Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

292 

### Exhibit 3

- 94 Case S3A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

293 

### Exhibit 3

- 94 Case S3A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

294 

### Exhibit 3

- 95 Case L 3A Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

295 

### Exhibit 3

- 95 Case L3A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

296 

### Exhibit 3

- 95 Case L3A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

297 

### Exhibit 3

- 96 Cases S3A and L3A Energy Balance

HHV Sensible + Latent Power Total
S3A L3A S3A L3A S3A L3A S3A L3A Heat In GJ/hr (MMBtu/hr)

Coal 4,799 (4,549) 5,194 (4,923) 2.5 (2.3) 3.0 (2.8) 0 (0) 0 (0) 4,801 (4,551) 5,197 (4,925)
ASU Air 0 (0) 0 (0) 8.3 (7.9) 8.6 (8.1) 0 (0) 0 (0) 8 (8) 9 (8)
G T Air 0 (0) 0 (0) 45.1 (42.8) 42.5 (40.3) 0 (0) 0 (0) 45 (43) 42 (40) Raw Water Makeup 0 (0) 0 (0) 11.9 (11.3) 9.2 (8.7) 0 (0) 0 (0) 12 (11) 9 (9)
A uxiliary Power 0 (0) 0 (0) 0 (0) 0 (0) 423 (401) 488 (463) 423 (401) 488 (463)

Totals 4,799 (4,549) 5,194 (4,923) 67.8 (64.3) 63.3 (60.0) 423 (401) 488 (463) 5,290 (5,014) 5,745 (5,445) Heat Out GJ/hr (MMBtu/hr)
ASU Intercoolers 0 (0) 0 (0) 178 (169) 199 (189) 0 (0) 0 (0) 178 (169) 199 (189)
ASU Vent 0 (0) 0 (0) 0.8 (0.7) 0.9 (0.8) 0 (0) 0 (0) 1 (1) 1 (1) Slag 20 (19) 22 (21) 4.4 (4.2) 7.4 (7.0) 0 (0) 0 (0) 24 (23) 29 (28)
S ulfur 16 (15) 20 (19) 0.2 (0.2) 0.2 (0.2) 0 (0) 0 (0) 16 (16) 20 (19)
C ooling Tower Blowdown 0 (0) 0 (0) 11.3 (10.7) 11.7 (11.1) 0 (0) 0 (0) 11 (11) 12 (11)

H RSG Flue Gas 0 (0) 0 (0) 735 (697) 760 (721) 0 (0) 0 (0) 735 (697) 760 (721)

Condenser 0 (0) 0 (0) 1,442 (1,367) 1,631 (1,546) 0 (0) 0 (0) 1,443 (1,368) 1,631 (1,546)
A uxiliary Cooling Load 0 (0) 0 (0) 197 (187) 158 (150) 0 (0) 0 (0) 197 (187) 158 (150)
E lectrical Generator Loss 0 (0) 0 (0) 0 (0) 0 (0) 34 (32) 37 (35) 34 (32) 37 (35)

Process Losses 0 (0) 0 (0) 411 (390) 454 (430) 411 (3 90 ) 454 (430)

Power 0 (0) 0 (0) 0 (0) 0 (0) 2,240 (2,123) 2,444 (2,316) 2,240 (2,123) 2,444 (2,316)

Totals 36 (34) 41 (39) 2,980 (2,824) 3,223 (3,055) 2,274 (2,155) 2,481 (2,351) 5,290 (5,014) 5,745 (5,445)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

298 

### 3.4.6 Case S3A and L3A Equipment Lists

Major equipment items for the SFG with no CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspo nd to the account numbers used in the cost estimates in Section 3.4.7 . In general, the design conditions include a 10 percent contingency for flows and heat dutie s and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

299 

### ACCOUNT 1 COAL HANDLING Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

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 54 tonne (60 ton) 73 tonne (80 ton) 2 1
9 Feeder Vibratory 200 tonne/hr (220 tph) 281 tonne/hr (310 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 399 tonne/hr (440 tph) 553 tonne/hr (610 tph) 1 0
11 Crusher Tower N/A N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 200 tonne (220 ton) 281 tonne (310 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 399 tonne/hr (440 tph) 553 tonne/hr (610 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A N/A 1 0
17 Conveyor No. 5 Belt w/ tripper 399 tonne/hr (440 tph) 553 tonne/hr (610 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 907 tonne (1,000 ton) 1,270 tonne (1,400 ton) 3 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

300 

### ACCOUNT 2 COAL PREPARATION AND FEED Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Feeder Vibratory 91 tonne/hr (100 tph) 127 tonne/hr (140 tph) 3 0
2 Conveyor No. 6 Belt w/tripper 263 tonne/hr (290 tph) 372 tonne/hr (410 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 526 tonne (580 ton) 744 tonne (820 ton) 1 0

4 Weigh Feeder Belt 136 tonne/hr (150 tph) 181 tonne/hr (200 tph) 2 0
5 Pulverizer Rotary 136 tonne/hr (150 tph) 181 tonne/hr (200 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 263 tonne (290 ton) 372 tonne (410 ton) 2 0

7 Coal Preheater Water Heated Horizontal Rotary Kiln Coal feed: 263 tonne/hr (290 tph) Heat duty: 29.5 GJ/hr (28.0 MMBtu/hr) Coal feed: 372 tonne/hr (410 tph) Heat duty: 45.8 GJ/hr (43.4 MMBtu/hr) 1 0

8 Coal Dryer Fluidized Bed with Internal Coils Coal feed: 136 tonne/hr (150 tph) Heat duty: 74.2 GJ/hr (70.3 MMBtu/hr) Bed diameter: 11.9 m (39 ft) Coal feed: 181 tonne/hr (200 tph) Heat duty: 133.0 GJ/hr (126.1 MMBtu/hr) Bed diameter: 14.0 m (46 ft) 2 0

9 Steam Compressor Reciprocating, Multi

Stage 555 m 3 

### /min (19,610 scfm) Suction

- 0.09 MPa (13 psia) Discharge

- 0.72 MPa (105 psia) 1012 m 3 

### /min (35,730 scfm) Suction

- 0.10 MPa (13.8 psia) Discharge

- 0.52 MPa (75 psia) 2 0

10 Dryer Exhaust Filter Hot Baghouse Steam

- 27,851 kg/hr (61,400 lb/hr) Temperature

- 107°C (225°F) Steam

- 50,802 kg/hr (112,000 lb/hr) Temperature

- 107°C (225°F) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

301 

### Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

11 Dry Coal Cooler Water Cooled Horizontal Rotary Kiln 209 tonne/hr (231 tph) Heat duty

- 12 GJ/hr (11 MMBtu/hr) 270 tonne/hr (297 tph) Heat duty

- 17 GJ/hr (16 MMBtu/hr) 1 0

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 635,949 liters (168,000 gal) 749,512 liters (198,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,587 lpm @ 91 m H 2 

### O (1,740 gpm @ 300 ft H 2 

### O) 7,230 lpm @ 91 m H 2 

### O (1,910 gpm @ 300 ft H 2 

### O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 469,015 kg/hr (1,034,000 lb/hr) 511,652 kg/hr (1,128,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 4,240 lpm @ 27 m H 2 

### O (1,120 gpm @ 90 ft H 2 

### O) 4,732 lpm @ 27 m H 2 

### O (1,250 gpm @ 90 ft H 2 

### O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 3,823 lpm @ 1,890 m H 2 

### O (1,010 gpm @ 6,200 ft H 2 

### O) HP water: 4,050 lpm @ 1,890 m H 2 

### O (1,070 gpm @ 6,200 ft H 2 

### O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 1,098 lpm @ 223 m H 2 

### O (290 gpm @ 730 ft H 2 

### O) IP water: 2,006 lpm @ 223 m H 2 

### O (530 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 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

302 

### Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

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 Cycle Cooling Heat Exchangers Plate and frame 221 GJ/hr (209 MMBtu/hr) each 211 GJ/hr (200 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 79,115 lpm @ 21 m H 2 

### O (20,900 gpm @ 70 ft H 2 

### O) 75,708 lpm @ 21 m H 2 

### O (20,000 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) 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 2,385 lpm @ 18 m H 2 

### O (630 gpm @ 60 ft H 2 

### O) 2,347 lpm @ 18 m H 2 

### O (620 gpm @ 60 ft H 2 

### O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,385 lpm @ 268 m H 2 

### O (630 gpm @ 880 ft H 2 

### O) 2,347 lpm @ 268 m H 2 

### O (620 gpm @ 880 ft H 2 

### O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 3,520 lpm @ 49 m H 2 

### O (930 gpm @ 160 ft H 2 

### O) 4,088 lpm @ 49 m H 2 

### O (1,080 gpm @ 160 ft H 2 

### O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,684,508 liter (445,000 gal) 1,957,058 liter (517,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 189 lpm (50 gpm) 189 lpm (50 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

303 

### ACCOUNT 4 GASIFIER, ASU , AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Gasifier Pressurized dry

feed, entrained bed 2,087 tonne/day, 4.2 MPa (2,300 tpd, 605 psia) 2,994 tonne/day, 4.2 MPa (3,300 tpd, 605 psia) 3 0

2 Synthesis Gas Cyclone High efficiency 247,661 kg/hr (546,000 lb/hr) Design efficiency 90% 288,938 kg/hr (637,000 lb/hr) Design efficiency 90% 3 0

3 Syngas Scrubber Including Sour Water Stripper Vertical up flow 247,661 kg/hr (546,000 lb/hr) 288,938 kg/hr (637,000 lb/hr) 3 0

4 Raw Gas Coolers Shell and tube with condensate drain 224,982 kg/hr (496,000 lb/hr) 244,033 kg/hr (538,000 lb/hr) 8 0

5 Raw Gas Knockout Drum Vertical with mist eliminator 185,973 kg/hr, 51°C, 3.6 MPa (410,000 lb/hr, 124°F, 522 psia) 211,828 kg/hr, 35°C, 3.8 MPa (467,000 lb/hr, 95°F, 555 psia) 2 0

6 Synthesis Gas Reheater Shell and tube 185,066 kg/hr (408,000 lb/hr) 210,013 kg/hr (463,000 lb/hr) 2 0

7 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 371,946 kg/hr (820,000 lb/hr) syngas 433,634 kg/hr (956,000 lb/hr) syngas 2 0

8 ASU Main Air Compressor Centrifugal, multi

stage 4,106 m 3 

### /min @ 1.3 MPa (145,000 scfm

@ 190 psia) 4,701 m 3 

### /min @ 1.3 MPa (166,000 scfm

@ 190 psia) 2 0

9 Cold Box Vendor design 1,905 tonne/day (2,100 tpd) of 95% purity oxygen 2,177 tonne/day (2,400 tpd) of 95% purity oxygen 2 2Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

304 

### Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

10 Oxygen Compressor Centrifugal, multi

stage 963 m 3 

### /min (34,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 1,104 m 3 

### /min (39,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 2 0

11 Primary Nitrogen Compressor Centrifugal, multi

stage 3,171 m 3 

### /min (112,000 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) 2 0

12 Secondary Nitrogen Compressor Centrifugal, single

stage 453 m 3 

### /min (16,000 scfm) Suction

- 2.7 MPa (390 psia) Discharge

- 5.7 MPa (820 psia) 510 m 3 

### /min (18,000 scfm) Suction

- 2.7 MPa (390 psia) Discharge

- 5.7 MPa (820 psia) 2 0

13 Extraction Air Heat Exchanger Gas

- to

- gas, vendor design 46,266 kg/hr, 411°C, 1.4 MPa (102,000 lb/hr, 771°F, 208 psia) 53,978 kg/hr, 408°C, 1.5 MPa (119,000 lb/hr, 767°F, 220 psia) 2 0

14 Transport Nitrogen Boost Compressor Centrifugal, multi

stage 368 m 3 

### /min (13,000 scfm) Suction

- 2.7 MPa (389 psia) Discharge

- 5.6 MPa (815 psia) 513 m 3 

### /min (18,100 scfm) Suction

- 2.7 MPa (389 psia) Discharge

- 5.6 MPa (815 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

305 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed 186,426 kg/hr (411,000 lb/hr)

35°C (95°F) 3.9 MPa (570 psia) 211,828 kg/hr (467,000 lb/hr)

35°C (95°F) 3.9 MPa (565 psia) 2 0

2 Sulfur Plant Claus type 46 tonne/day (51 tpd) 56 tonne/day (61 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 374,667 kg/hr (826,000 lb/hr) 216°C (420°F) 4.1 MPa (590 psia) 438,624 kg/hr (967,000 lb/hr) 216°C (420°F) 4.1 MPa (590 psia) 2 0

4 Acid Gas Removal Plant Sulfinol 191,870 kg/hr (423,000 lb/hr)

35°C (94°F) 3.9 MPa (560 psia) 217,724 kg/hr (480,000 lb/hr)

35°C (94°F) 3.8 MPa (555 psia) 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 11,596 kg/hr (25,566 lb/hr) 232°C (450°F) 0.3 MPa (48.6 psia) 14,462 kg/hr (31,884 lb/hr) 232°C (450°F) 0.3 MPa (48.6 psia) 1 0

6 Tail Gas Recycle Compressor Centrifugal 9
, 551 kg/hr (21

, 05 6 lb/hr) 11
, 411 kg/hr (25

, 157 lb/hr) 1 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No. Description Type S3A Design Condition L3A Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 210 MW 225 MW 2 0

2 Gas Turbine Generator TEWAC 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 250 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

306 

### ACCOUNT 7 HRSG, DUCTING AND STACK Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.6 m (2 0 ft) diameter 76 m (250 ft) high x 8.6 m (2 0 ft) diameter 2 0

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 216,193 kg/hr, 12.4 MPa/559°C

(476,623 lb/hr, 1,800 psig/1,038°F) Reheat steam

- 199,389 kg/hr, 3.1 MPa/559°C

(439,577 lb/hr, 452 psig/1,038°F) Main steam

- 228,123 kg/hr, 12.4 MPa/560°C

(502,924 lb/hr, 1,800 psig/1,041°F) Reheat steam

- 221,125 kg/hr, 3 .1 MPa/560°C

(487,498 lb/hr, 452 psig/1,041°F) 2 0

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Steam Turbine Commercially available 218 MW 12.4 MPa/559°C/559°C (1

, 800 psig/ 1,038°F/1,038°F) 244 MW 12.4 MPa/560°C/560°C (1

, 800 psig/ 1,041°F/1,041°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 270 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided waterbox including vacuum
pumps 791 GJ/hr (750 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 897 GJ/hr (850 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

307 

### Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

4 Air

- cooled Condenser --- 791 GJ/hr (750 MMBtu/hr), Condensing temperature

32°C (90°F), Ambient temperature 6°C (42°F) 897 GJ/hr (850 MMBtu/hr), Condensing temperature

32°C (90°F), Ambient temperature 4°C (40°F) 1 0

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Circulating Water Pumps Vertical, wet pit 230,910 lpm @ 30 m (61,000 gpm @ 100 ft) 249,837 lpm @ 30 m (66,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) WB / 9°C (48°F) CWT / 20°C (68°F) HWT / 1
, 298 GJ/hr (1

, 230 MMBtu/hr) heat duty 2°C (36°F) WB / 8°C (47°F) CWT / 19°C (67°F) HWT / 1
, 382 GJ/hr (1

, 310 MMBtu/hr) heat duty 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

308 

### ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 143,846 liters (38,000 gal) 238,481 liters (63,000 gal) 3 0
2 Slag Crusher Roll 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0
3 Slag Depressurizer Proprietary 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

4 Slag Receiving Tank Horizontal, weir 87,064 liters (23,000 gal) 143,846 liters (38,000 gal) 3 0

5 Black Water Overflow Tank Shop fabricated 37,854 liters (10,000 gal) 64,352 liters (17,000 gal) 3

6 Slag Conveyor Drag chain 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

7 Slag Separation Screen Vibrating 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

8 Coarse Slag Conveyor Belt/bucket 7 tonne/hr (8 tph) 13 tonne/hr (14 tph) 3 0

9 Fine Ash Settling Tank Vertical, gravity 121,133 liters (32,000 gal) 204,412 liters (54,000 gal) 3 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) 3 2

11 Grey Water Storage Tank Field erected 37,854 liters (10,000 gal) 64,352 liters (17,000 gal) 3 0

12 Grey Water Pumps Centrifugal 151 lpm @ 424 m H 2 

### O (40 gpm @ 1,390 ft H 2 

### O) 227 lpm @ 424 m H 2 

### O (60 gpm @ 1,390 ft H 2 

### O) 3 3

13 Slag Storage Bin Vertical, field erected 544 tonne (600 tons) 907 tonne (1,000 tons) 3 0

14 Unloading Equipment Telescoping chute 91 tonne/hr (100 tph) 154 tonne/hr (170 tph) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

309 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 230 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 250 MVA, 3

- ph, 60 Hz 2 0

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 240 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 270 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 52 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 60 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 24 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 27 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

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 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

310 

### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type S3A Design Conditions L3A Design Condition Operating Qty Spares

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 0

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

311 

### 3.4.7 Case S3A and L3A Cost Estimating

Costs Results The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 97 shows the total capital cost summary organized by cost account for the PRB coal case (S3A) and Exhibit 3

- 101 shows the same information for the NDL coal case (L3A). A more detailed breakdow n of the capital costs is shown in Exhibit 3

- 98 for S3A and Exhibit 3

- 102 for L3A. Exhibit 3

- 99 and Exhibit 3

- 103 show the calculation and addition of owner’s costs to determine the TOC , used to calculate COE. Exhibit 3

- 100 shows the initial and annual O&M costs for Case S3A and Exhibit 3

- 104 shows the same information for Case L3A.

The estimated T O C of the SFG with no CO 2 

### capture using PRB coal is $ 3
, 18 5 /kW and using lignite coal is $ 3
, 2 39 / kW. Process contingency represents 2 percen t, project contingency represents 1 1 percent , and owner’s costs represent 18 percent of TOC in both cases. The COE is 86.8 mills/kWh in the PRB case and 87.3 mills/kWh in the lignite case.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

312 

### Exhibit 3

- 97 Case S3A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S3A - Siemens 504 MW IGCC w/o CO2 Plant Size: 504.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $15,069 $2,800 $11,686 $0 $0 $29,555 $2,683 $0 $6,447 $38,685 $77

2 COAL & SORBENT PREP & FEED $113,213 $9,434 $19,316 $0 $0 $141,963 $12,316 $0 $30,856 $185,135 $367

3 FEEDWATER & MISC. BOP SYSTEMS $6,625 $5,455 $6,288 $0 $0 $18,368 $1,730 $0 $4,587 $24,684 $49

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $465 4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $147,856 $0 w/equip. $0 $0 $147,856 $14,332 $0 $16,219 $178,406 $353 4.4-4.9 Other Gasification Equipment $27,422 $12,190 $17,132 $0 $0 $56,744 $5,433 $0 $13,350 $75,527 $150 SUBTOTAL 4 $287,637 $12,190 $69,616 $0 $0 $369,443 $34,410 $24,727 $60,201 $488,782 $968

5A Gas Cleanup & Piping $44,796 $2,573 $43,329 $0 $0 $90,698 $8,770 $79 $20,056 $119,603 $237

5B CO 2 REMOVAL & COMPRESSION $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $230 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $234

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,576 $0 $4,632 $0 $0 $37,208 $3,538 $0 $4,075 $44,820 $89 7.2-7.9 Ductwork and Stack $3,459 $2,466 $3,262 $0 $0 $9,187 $852 $0 $1,635 $11,674 $23 SUBTOTAL 7 $36,035 $2,466 $7,894 $0 $0 $46,394 $4,390 $0 $5,709 $56,494 $112

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,782 $0 $3,965 $0 $0 $27,747 $2,662 $0 $3,041 $33,450 $66 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $34,018 $811 $10,715 $0 $0 $45,544 $4,438 $0 $10,082 $60,065 $119 SUBTOTAL 8 $57,800 $811 $14,680 $0 $0 $73,292 $7,100 $0 $13,123 $93,515 $185

9 COOLING WATER SYSTEM $6,387 $6,453 $5,413 $0 $0 $18,252 $1,695 $0 $4,097 $24,044 $48

10 ASH/SPENT SORBENT HANDLING SYS $20,248 $1,402 $10,041 $0 $0 $31,692 $3,041 $0 $3,763 $38,496 $76

11 ACCESSORY ELECTRIC PLANT $25,991 $10,114 $20,028 $0 $0 $56,133 $4,830 $0 $11,520 $72,483 $144

12 INSTRUMENTATION & CONTROL $9,586 $1,763 $6,176 $0 $0 $17,526 $1,588 $876 $3,331 $23,321 $46

13 IMPROVEMENTS TO SITE $3,069 $1,809 $7,572 $0 $0 $12,450 $1,229 $0 $4,104 $17,782 $35

14 BUILDINGS & STRUCTURES $0 $5,974 $6,769 $0 $0 $12,743 $1,160 $0 $2,286 $16,188 $32

TOTAL COST $712,207 $64,051 $235,970 $0 $0 $1,012,228 $93,824 $30,283 $181,172 $1,317,507 $2,610 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

313 

### Exhibit 3

- 98 Case S3A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S3A - Siemens 504 MW IGCC w/o CO2 Plant Size: 504.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,957 $0 $1,934 $0 $0 $5,891 $528 $0 $1,284 $7,702 $15 1.2 Coal Stackout & Reclaim $5,114 $0 $1,240 $0 $0 $6,353 $557 $0 $1,382 $8,292 $16 1.3 Coal Conveyors & Yd Crush $4,754 $0 $1,227 $0 $0 $5,981 $525 $0 $1,301 $7,807 $15
1.4 Other Coal Handling $1,244 $0 $284 $0 $0 $1,528 $134 $0 $332 $1,994 $4 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $2,800 $7,002 $0 $0 $9,802 $939 $0 $2,148 $12,890 $26 SUBTOTAL 1. $15,069 $2,800 $11,686 $0 $0 $29,555 $2,683 $0 $6,447 $38,685 $77
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $45,578 $2,738 $6,641 $0 $0 $54,958 $4,742 $0 $11,940 $71,640 $142 2.2 Prepared Coal Storage & Feed $1,959 $469 $307 $0 $0 $2,736 $234 $0 $594 $3,564 $7 2.3 Dry Coal Injection System $64,488 $748 $5,989 $0 $0 $71,226 $6,135 $0 $15,472 $92,833 $184 2.4 Misc.Coal Prep & Feed $1,187 $864 $2,590 $0 $0 $4,641 $427 $0 $1,014 $6,081 $12 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $4,614 $3,788 $0 $0 $8,403 $778 $0 $1,836 $11,017 $22 SUBTOTAL 2. $113,213 $9,434 $19,316 $0 $0 $141,963 $12,316 $0 $30,856 $185,135 $367 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,038 $3,501 $1,848 $0 $0 $7,387 $684 $0 $1,614 $9,686 $19 3.2 Water Makeup & Pretreating $367 $38 $205 $0 $0 $610 $58 $0 $200 $869 $2 3.3 Other Feedwater Subsystems $1,115 $377 $339 $0 $0 $1,831 $165 $0 $399 $2,395 $5 3.4 Service Water Systems $210 $432 $1,500 $0 $0 $2,142 $209 $0 $705 $3,056 $6 3.5 Other Boiler Plant Systems $1,126 $436 $1,082 $0 $0 $2,644 $251 $0 $579 $3,474 $7 3.6 FO Supply Sys & Nat Gas $286 $541 $504 $0 $0 $1,332 $128 $0 $292 $1,752 $3 3.7 Waste Treatment Equipment $513 $0 $313 $0 $0 $825 $80 $0 $272 $1,177 $2 3.8 Misc. Power Plant Equipment $969 $130 $497 $0 $0 $1,596 $154 $0 $525 $2,275 $5 SUBTOTAL 3. $6,625 $5,455 $6,288 $0 $0 $18,368 $1,730 $0 $4,587 $24,684 $49
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemens $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $465 4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $147,856 $0 w/equip. $0 $0 $147,856 $14,332 $0 $16,219 $178,406 $353
4.4 LT Heat Recovery & FG Saturation $27,422 $0 $10,425 $0 $0 $37,847 $3,694 $0 $8,308 $49,849 $99 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,519 $618 $0 $0 $2,137 $205 $0 $468 $2,810 $6 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $10,671 $6,089 $0 $0 $16,761 $1,534 $0 $4,574 $22,869 $45 SUBTOTAL 4. $287,637 $12,190 $69,616 $0 $0 $369,443 $34,410 $24,727 $60,201 $488,782 $968 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

314 

### Exhibit 3

- 98 Case S3A Tota l Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S3A - Siemens 504 MW IGCC w/o CO2 Plant Size: 504.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Sulfinol System $34,319 $0 $29,120 $0 $0 $63,439 $6,135 $0 $13,915 $83,489 $165 5A.2 Elemental Sulfur Plant $4,779 $952 $6,166 $0 $0 $11,897 $1,156 $0 $2,611 $15,663 $31 5A.3 Mercury Removal $896 $0 $682 $0 $0 $1,577 $152 $79 $362 $2,170 $4 5A.4 COS Hydrolysis $4,802 $0 $6,271 $0 $0 $11,074 $1,077 $0 $2,430 $14,581 $29 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.7 Fuel Gas Piping $0 $805 $564 $0 $0 $1,369 $127 $0 $299 $1,796 $4 5A.9 HGCU Foundations $0 $816 $526 $0 $0 $1,341 $123 $0 $439 $1,904 $4 SUBTOTAL 5A. $44,796 $2,573 $43,329 $0 $0 $90,698 $8,770 $79 $20,056 $119,603 $237 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $230 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $234
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,576 $0 $4,632 $0 $0 $37,208 $3,538 $0 $4,075 $44,820 $89 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,773 $1,297 $0 $0 $3,070 $270 $0 $668 $4,008 $8
7.4 Stack $3,459 $0 $1,299 $0 $0 $4,758 $456 $0 $521 $5,736 $11 7.9 HRSG,Duct & Stack Foundations $0 $693 $666 $0 $0 $1,359 $126 $0 $445 $1,930 $4 SUBTOTAL 7. $36,035 $2,466 $7,894 $0 $0 $46,394 $4,390 $0 $5,709 $56,494 $112 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,782 $0 $3,965 $0 $0 $27,747 $2,662 $0 $3,041 $33,450 $66 8.2 Turbine Plant Auxiliaries $164 $0 $375 $0 $0 $539 $53 $0 $59 $650 $1 8.3a Condenser & Auxiliaries $2,973 $0 $950 $0 $0 $3,923 $375 $0 $430 $4,728 $9 8.3b Air Cooled Condenser $27,249 $0 $5,463 $0 $0 $32,711 $3,271 $0 $7,197 $43,179 $86 8.4 Steam Piping $3,633 $0 $2,556 $0 $0 $6,188 $532 $0 $1,680 $8,400 $17 8.9 TG Foundations $0 $811 $1,372 $0 $0 $2,183 $207 $0 $717 $3,107 $6 SUBTOTAL 8. $57,800 $811 $14,680 $0 $0 $73,292 $7,100 $0 $13,123 $93,515 $185
9 COOLING WATER SYSTEM 9.1 Cooling Towers $4,417 $0 $803 $0 $0 $5,221 $497 $0 $858 $6,575 $13 9.2 Circulating Water Pumps $1,142 $0 $67 $0 $0 $1,209 $102 $0 $197 $1,508 $3 9.3 Circ.Water System Auxiliaries $102 $0 $15 $0 $0 $117 $11 $0 $19 $147 $0 9.4 Circ.Water Piping $0 $4,276 $1,109 $0 $0 $5,384 $487 $0 $1,174 $7,045 $14 9.5 Make-up Water System $220 $0 $315 $0 $0 $535 $51 $0 $117 $703 $1 9.6 Component Cooling Water Sys $505 $604 $430 $0 $0 $1,538 $144 $0 $336 $2,019 $4 9.9 Circ.Water System Foundations $0 $1,573 $2,675 $0 $0 $4,248 $403 $0 $1,395 $6,046 $12 SUBTOTAL 9. $6,387 $6,453 $5,413 $0 $0 $18,252 $1,695 $0 $4,097 $24,044 $48 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

315 

### Exhibit 3

- 98 Case S3A Total Plant Cost Details (Co ntinued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S3A - Siemens 504 MW IGCC w/o CO2 Plant Size: 504.7 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $17,892 $0 $8,824 $0 $0 $26,716 $2,567 $0 $2,928 $32,211 $64 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $534 $0 $581 $0 $0 $1,115 $108 $0 $183 $1,406 $3 10.7 Ash Transport & Feed Equipment $716 $0 $173 $0 $0 $889 $83 $0 $146 $1,118 $2 10.8 Misc. Ash Handling Equipment $1,106 $1,355 $405 $0 $0 $2,866 $273 $0 $471 $3,610 $7 10.9 Ash/Spent Sorbent Foundation $0 $47 $59 $0 $0 $107 $10 $0 $35 $151 $0 SUBTOTAL 10. $20,248 $1,402 $10,041 $0 $0 $31,692 $3,041 $0 $3,763 $38,496 $76
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $860 $0 $851 $0 $0 $1,711 $163 $0 $187 $2,062 $4 11.2 Station Service Equipment $3,746 $0 $338 $0 $0 $4,083 $376 $0 $446 $4,906 $10 11.3 Switchgear & Motor Control $6,925 $0 $1,259 $0 $0 $8,184 $759 $0 $1,341 $10,285 $20
11.4 Conduit & Cable Tray $0 $3,217 $10,612 $0 $0 $13,829 $1,338 $0 $3,792 $18,958 $38 11.5 Wire & Cable $0 $6,146 $4,038 $0 $0 $10,185 $740 $0 $2,731 $13,656 $27 11.6 Protective Equipment $0 $611 $2,225 $0 $0 $2,837 $277 $0 $467 $3,581 $7
11.7 Standby Equipment $216 $0 $211 $0 $0 $427 $41 $0 $70 $537 $1 11.8 Main Power Transformers $14,245 $0 $128 $0 $0 $14,373 $1,087 $0 $2,319 $17,779 $35 11.9 Electrical Foundations $0 $139 $365 $0 $0 $505 $48 $0 $166 $719 $1 SUBTOTAL 11. $25,991 $10,114 $20,028 $0 $0 $56,133 $4,830 $0 $11,520 $72,483 $144
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $946 $0 $632 $0 $0 $1,578 $149 $79 $271 $2,077 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $217 $0 $139 $0 $0 $357 $34 $18 $82 $490 $1 12.7 Computer & Accessories $5,048 $0 $162 $0 $0 $5,210 $478 $260 $595 $6,543 $13 12.8 Instrument Wiring & Tubing $0 $1,763 $3,605 $0 $0 $5,368 $455 $268 $1,523 $7,615 $15 12.9 Other I & C Equipment $3,374 $0 $1,639 $0 $0 $5,013 $472 $251 $860 $6,595 $13 SUBTOTAL 12. $9,586 $1,763 $6,176 $0 $0 $17,526 $1,588 $876 $3,331 $23,321 $46 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $96 $2,058 $0 $0 $2,154 $214 $0 $710 $3,079 $6 13.2 Site Improvements $0 $1,713 $2,276 $0 $0 $3,988 $394 $0 $1,315 $5,696 $11 13.3 Site Facilities $3,069 $0 $3,238 $0 $0 $6,307 $622 $0 $2,079 $9,008 $18 SUBTOTAL 13. $3,069 $1,809 $7,572 $0 $0 $12,450 $1,229 $0 $4,104 $17,782 $35
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,057 $2,931 $0 $0 $4,988 $459 $0 $817 $6,264 $12 14.3 Administration Building $0 $819 $594 $0 $0 $1,413 $126 $0 $231 $1,769 $4
14.4 Circulation Water Pumphouse $0 $157 $83 $0 $0 $240 $21 $0 $39 $300 $1 14.5 Water Treatment Buildings $0 $307 $299 $0 $0 $606 $55 $0 $99 $759 $2 14.6 Machine Shop $0 $419 $287 $0 $0 $706 $63 $0 $115 $884 $2
14.7 Warehouse $0 $677 $437 $0 $0 $1,113 $99 $0 $182 $1,394 $3 14.8 Other Buildings & Structures $0 $394 $307 $0 $0 $700 $63 $0 $153 $916 $2 14.9 Waste Treating Building & Str. $0 $880 $1,682 $0 $0 $2,562 $239 $0 $560 $3,362 $7 SUBTOTAL 14. $0 $5,974 $6,769 $0 $0 $12,743 $1,160 $0 $2,286 $16,188 $32

TOTAL COST $712,207 $64,051 $235,970 $0 $0 $1,012,228 $93,824 $30,283 $181,172 $1,317,507 $2,610 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

316 

### Exhibit 3

- 99 Case S3A Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $11,711 $23 1 Month Variable O&M $3,023 $6 25% of 1 Months Fuel Cost at 100% CF $737 $1 2% of TPC $26,350 $52 Total $41,821 $83

Inventory Capital 60 day supply of consumables at 100% CF $6,095 $12 0.5% of TPC (spare parts) $6,588 $13 Total $12,682 $25

Initial Cost for Catalyst and Chemicals $1,498 $3 Land $900 $2 Other Owner's Costs $197,626 $392 Financing Costs $35,573 $70

Total Owner's Costs $290,100 $575 Total Overnight Cost (TOC) $1,607,607 $3,185 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $1,832,672 $3,631Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

317 

### Exhibit 3

- 100 Case S3A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case S3A - Siemens 504 MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 9,011 MWe-net: 505 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate (base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $11.727 Maintenance Labor Cost $12,818,175 $25.397 Administrative & Support Labor $4,684,272 $9.281 Property Taxes and Insurance $26,350,141 $52.208 TOTAL FIXED OPERATING COSTS $49,771,501 $98.614 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $25,115,707 $0.00710

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 1,627 1.08 $0 $513,950 $0.00015

Chemicals

MU & WT Chem.(lbs) 0 9,694 0.17 $0 $489,914 $0.00014 Carbon (Mercury Removal) (lb) 61,010 84 1.05 $64,071 $25,628 $0.00001 COS Catalyst (m3) 523 0.36 2,397.36 $1,253,811 $250,762 $0.00007 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Sulfinol Solution (gal) 17,905 12 10.05 $179,922 $35,705 $0.00001 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.70 131.27 $0 $26,903 $0.00001 Subtotal Chemicals $1,497,803 $828,913 $0.00023

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 84 0.42 $0 $10,178 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 538 16.23 $0 $2,547,879 $0.00072 Subtotal Waste Disposal $0 $2,558,058 $0.00072

By-products & Emissions

Sulfur (tons) 0 46 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,497,803 $29,016,628 $0.00820

Fuel (ton) 0 6,373 15.22 $0 $28,319,073 $0.00801Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

318 

### Exhibit 3

- 101 Case L3A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L3A - Siemens 543 MW IGCC w/o CO2 Plant Size: 543.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $18,570 $3,451 $14,401 $0 $0 $36,421 $3,306 $0 $7,945 $47,672 $88

2 COAL & SORBENT PREP & FEED $138,652 $11,733 $23,866 $0 $0 $174,250 $15,119 $0 $37,874 $227,242 $418

3 FEEDWATER & MISC. BOP SYSTEMS $6,771 $5,627 $6,359 $0 $0 $18,757 $1,766 $0 $4,673 $25,196 $46

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemen $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $432 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $163,595 $0 w/equip. $0 $0 $163,595 $15,857 $0 $17,945 $197,397 $363 4.4-4.9 Other Gasification Equipment $30,620 $14,004 $19,354 $0 $0 $63,977 $6,123 $0 $15,075 $85,175 $157 SUBTOTAL 4 $306,574 $14,004 $71,838 $0 $0 $392,415 $36,626 $24,727 $63,653 $517,421 $953

5A GAS CLEANUP & PIPING $49,303 $2,824 $47,777 $0 $0 $99,904 $9,661 $85 $22,087 $131,737 $243

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $213 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $218

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,059 $0 $4,843 $0 $0 $38,902 $3,699 $0 $4,260 $46,861 $86 7.2-7.9 SCR System, Ductwork and Stack $3,437 $2,450 $3,241 $0 $0 $9,128 $847 $0 $1,624 $11,599 $21 SUBTOTAL 7 $37,496 $2,450 $8,084 $0 $0 $48,031 $4,545 $0 $5,885 $58,461 $108

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $25,733 $0 $4,347 $0 $0 $30,080 $2,886 $0 $3,297 $36,263 $67 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $36,939 $882 $11,553 $0 $0 $49,374 $4,815 $0 $10,913 $65,102 $120 SUBTOTAL 8 $62,673 $882 $15,899 $0 $0 $79,454 $7,701 $0 $14,210 $101,365 $187

9 COOLING WATER SYSTEM $6,676 $6,750 $5,627 $0 $0 $19,053 $1,769 $0 $4,272 $25,094 $46

10 ASH/SPENT SORBENT HANDLING SYS $27,975 $1,864 $13,870 $0 $0 $43,710 $4,194 $0 $5,176 $53,079 $98

11 ACCESSORY ELECTRIC PLANT $27,937 $10,833 $21,400 $0 $0 $60,169 $5,175 $0 $12,351 $77,695 $143

12 INSTRUMENTATION & CONTROL $9,866 $1,815 $6,357 $0 $0 $18,037 $1,635 $902 $3,428 $24,001 $44

13 IMPROVEMENTS TO SITE $3,198 $1,885 $7,892 $0 $0 $12,975 $1,281 $0 $4,277 $18,533 $34

14 BUILDINGS & STRUCTURES $0 $6,155 $7,032 $0 $0 $13,187 $1,201 $0 $2,364 $16,752 $31

TOTAL COST $781,441 $71,079 $257,562 $0 $0 $1,110,083 $102,860 $30,314 $199,286 $1,442,543 $2,656 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

319 

### Exhibit 3

- 102 Case L3A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L3A - Siemens 543 MW IGCC w/o CO2 Plant Size: 543.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,877 $0 $2,383 $0 $0 $7,260 $650 $0 $1,582 $9,492 $17 1.2 Coal Stackout & Reclaim $6,302 $0 $1,528 $0 $0 $7,829 $686 $0 $1,703 $10,218 $19 1.3 Coal Conveyors & Yd Crush $5,859 $0 $1,512 $0 $0 $7,370 $647 $0 $1,603 $9,621 $18
1.4 Other Coal Handling $1,533 $0 $350 $0 $0 $1,883 $165 $0 $409 $2,457 $5 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $3,451 $8,629 $0 $0 $12,079 $1,158 $0 $2,647 $15,885 $29 SUBTOTAL 1. $18,570 $3,451 $14,401 $0 $0 $36,421 $3,306 $0 $7,945 $47,672 $88
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $56,930 $3,420 $8,295 $0 $0 $68,645 $5,924 $0 $14,914 $89,482 $165 2.2 Prepared Coal Storage & Feed $2,366 $566 $371 $0 $0 $3,303 $282 $0 $717 $4,303 $8 2.3 Dry Coal Injection System $77,873 $904 $7,232 $0 $0 $86,009 $7,408 $0 $18,683 $112,100 $206 2.4 Misc.Coal Prep & Feed $1,483 $1,079 $3,235 $0 $0 $5,797 $533 $0 $1,266 $7,596 $14 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $5,764 $4,732 $0 $0 $10,496 $972 $0 $2,294 $13,761 $25 SUBTOTAL 2. $138,652 $11,733 $23,866 $0 $0 $174,250 $15,119 $0 $37,874 $227,242 $418 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,125 $3,648 $1,926 $0 $0 $7,699 $713 $0 $1,682 $10,095 $19 3.2 Water Makeup & Pretreating $359 $37 $200 $0 $0 $597 $57 $0 $196 $849 $2 3.3 Other Feedwater Subsystems $1,162 $393 $353 $0 $0 $1,909 $172 $0 $416 $2,496 $5 3.4 Service Water Systems $205 $423 $1,467 $0 $0 $2,095 $204 $0 $690 $2,989 $6 3.5 Other Boiler Plant Systems $1,101 $427 $1,058 $0 $0 $2,586 $245 $0 $566 $3,397 $6 3.6 FO Supply Sys & Nat Gas $298 $563 $525 $0 $0 $1,385 $133 $0 $304 $1,823 $3 3.7 Waste Treatment Equipment $501 $0 $306 $0 $0 $807 $79 $0 $266 $1,151 $2 3.8 Misc. Power Plant Equipment $1,020 $137 $524 $0 $0 $1,680 $162 $0 $553 $2,395 $4 SUBTOTAL 3. $6,771 $5,627 $6,359 $0 $0 $18,757 $1,766 $0 $4,673 $25,196 $46
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemen $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $432 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $163,595 $0 w/equip. $0 $0 $163,595 $15,857 $0 $17,945 $197,397 $363
4.4 LT Heat Recovery & FG Saturation $30,620 $0 $11,640 $0 $0 $42,260 $4,124 $0 $9,277 $55,661 $102 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,693 $689 $0 $0 $2,382 $228 $0 $522 $3,133 $6 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $12,310 $7,024 $0 $0 $19,335 $1,770 $0 $5,276 $26,381 $49 SUBTOTAL 4. $306,574 $14,004 $71,838 $0 $0 $392,415 $36,626 $24,727 $63,653 $517,421 $953 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

320 

### Exhibit 3

- 102 Case L3A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L3A - Siemens 543 MW IGCC w/o CO2 Plant Size: 543.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Sulfinol System $37,542 $0 $31,855 $0 $0 $69,397 $6,711 $0 $15,222 $91,330 $168 5A.2 Elemental Sulfur Plant $5,422 $1,081 $6,995 $0 $0 $13,498 $1,311 $0 $2,962 $17,771 $33 5A.3 Mercury Removal $961 $0 $731 $0 $0 $1,692 $163 $85 $388 $2,328 $4 5A.4 COS Hydrolysis $5,378 $0 $7,023 $0 $0 $12,401 $1,206 $0 $2,721 $16,329 $30 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.7 Fuel Gas Piping $0 $866 $607 $0 $0 $1,473 $137 $0 $322 $1,931 $4 5A.9 HGCU Foundations $0 $877 $566 $0 $0 $1,443 $133 $0 $473 $2,048 $4 SUBTOTAL 5A. $49,303 $2,824 $47,777 $0 $0 $99,904 $9,661 $85 $22,087 $131,737 $243 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $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 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $213 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $218
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $34,059 $0 $4,843 $0 $0 $38,902 $3,699 $0 $4,260 $46,861 $86 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,762 $1,289 $0 $0 $3,051 $268 $0 $664 $3,982 $7
7.4 Stack $3,437 $0 $1,291 $0 $0 $4,728 $453 $0 $518 $5,699 $10 7.9 HRSG,Duct & Stack Foundations $0 $689 $661 $0 $0 $1,350 $126 $0 $443 $1,918 $4 SUBTOTAL 7. $37,496 $2,450 $8,084 $0 $0 $48,031 $4,545 $0 $5,885 $58,461 $108 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $25,733 $0 $4,347 $0 $0 $30,080 $2,886 $0 $3,297 $36,263 $67 8.2 Turbine Plant Auxiliaries $178 $0 $408 $0 $0 $586 $57 $0 $64 $707 $1 8.3a Condenser & Auxiliaries $3,246 $0 $1,037 $0 $0 $4,282 $410 $0 $469 $5,161 $10 8.3b Air Cooled Condenser $29,744 $0 $5,963 $0 $0 $35,707 $3,571 $0 $7,855 $47,133 $87 8.4 Steam Piping $3,772 $0 $2,653 $0 $0 $6,425 $552 $0 $1,744 $8,722 $16 8.9 TG Foundations $0 $882 $1,491 $0 $0 $2,374 $225 $0 $780 $3,378 $6 SUBTOTAL 8. $62,673 $882 $15,899 $0 $0 $79,454 $7,701 $0 $14,210 $101,365 $187
9 COOLING WATER SYSTEM 9.1 Cooling Towers $4,616 $0 $840 $0 $0 $5,456 $520 $0 $896 $6,872 $13 9.2 Circulating Water Pumps $1,207 $0 $73 $0 $0 $1,280 $108 $0 $208 $1,595 $3 9.3 Circ.Water System Auxiliaries $107 $0 $15 $0 $0 $123 $12 $0 $20 $155 $0 9.4 Circ.Water Piping $0 $4,483 $1,162 $0 $0 $5,645 $510 $0 $1,231 $7,386 $14 9.5 Make-up Water System $216 $0 $309 $0 $0 $525 $50 $0 $115 $690 $1 9.6 Component Cooling Water Sys $529 $633 $450 $0 $0 $1,613 $151 $0 $353 $2,116 $4 9.9 Circ.Water System Foundations $0 $1,634 $2,778 $0 $0 $4,412 $418 $0 $1,449 $6,279 $12 SUBTOTAL 9. $6,676 $6,750 $5,627 $0 $0 $19,053 $1,769 $0 $4,272 $25,094 $46 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

321 

### Exhibit 3

- 102 Case L3A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L3A - Siemens 543 MW IGCC w/o CO2 Plant Size: 543.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $24,843 $0 $12,251 $0 $0 $37,095 $3,564 $0 $4,066 $44,725 $82 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $710 $0 $772 $0 $0 $1,482 $144 $0 $244 $1,870 $3 10.7 Ash Transport & Feed Equipment $952 $0 $230 $0 $0 $1,182 $110 $0 $194 $1,486 $3 10.8 Misc. Ash Handling Equipment $1,470 $1,802 $538 $0 $0 $3,810 $363 $0 $626 $4,798 $9 10.9 Ash/Spent Sorbent Foundation $0 $63 $79 $0 $0 $142 $13 $0 $46 $201 $0 SUBTOTAL 10. $27,975 $1,864 $13,870 $0 $0 $43,710 $4,194 $0 $5,176 $53,079 $98
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $905 $0 $895 $0 $0 $1,800 $172 $0 $197 $2,169 $4 11.2 Station Service Equipment $4,018 $0 $362 $0 $0 $4,380 $404 $0 $478 $5,262 $10 11.3 Switchgear & Motor Control $7,428 $0 $1,351 $0 $0 $8,779 $814 $0 $1,439 $11,032 $20
11.4 Conduit & Cable Tray $0 $3,451 $11,383 $0 $0 $14,834 $1,435 $0 $4,067 $20,336 $37 11.5 Wire & Cable $0 $6,593 $4,332 $0 $0 $10,925 $794 $0 $2,930 $14,648 $27 11.6 Protective Equipment $0 $641 $2,332 $0 $0 $2,973 $290 $0 $490 $3,753 $7
11.7 Standby Equipment $225 $0 $220 $0 $0 $445 $42 $0 $73 $560 $1 11.8 Main Power Transformers $15,361 $0 $136 $0 $0 $15,497 $1,172 $0 $2,500 $19,170 $35 11.9 Electrical Foundations $0 $148 $388 $0 $0 $537 $51 $0 $176 $764 $1 SUBTOTAL 11. $27,937 $10,833 $21,400 $0 $0 $60,169 $5,175 $0 $12,351 $77,695 $143
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $974 $0 $650 $0 $0 $1,624 $154 $81 $279 $2,138 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $224 $0 $144 $0 $0 $367 $35 $18 $84 $505 $1 12.7 Computer & Accessories $5,195 $0 $166 $0 $0 $5,361 $492 $268 $612 $6,734 $12 12.8 Instrument Wiring & Tubing $0 $1,815 $3,710 $0 $0 $5,525 $469 $276 $1,567 $7,837 $14 12.9 Other I & C Equipment $3,473 $0 $1,686 $0 $0 $5,159 $485 $258 $885 $6,788 $12 SUBTOTAL 12. $9,866 $1,815 $6,357 $0 $0 $18,037 $1,635 $902 $3,428 $24,001 $44 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $100 $2,145 $0 $0 $2,245 $223 $0 $740 $3,209 $6 13.2 Site Improvements $0 $1,785 $2,372 $0 $0 $4,157 $410 $0 $1,370 $5,937 $11 13.3 Site Facilities $3,198 $0 $3,375 $0 $0 $6,573 $648 $0 $2,166 $9,388 $17 SUBTOTAL 13. $3,198 $1,885 $7,892 $0 $0 $12,975 $1,281 $0 $4,277 $18,533 $34
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,204 $3,140 $0 $0 $5,344 $492 $0 $875 $6,711 $12 14.3 Administration Building $0 $819 $594 $0 $0 $1,413 $126 $0 $231 $1,769 $3
14.4 Circulation Water Pumphouse $0 $161 $85 $0 $0 $247 $22 $0 $40 $309 $1 14.5 Water Treatment Buildings $0 $300 $292 $0 $0 $592 $54 $0 $97 $743 $1 14.6 Machine Shop $0 $419 $287 $0 $0 $706 $63 $0 $115 $884 $2
14.7 Warehouse $0 $677 $437 $0 $0 $1,113 $99 $0 $182 $1,394 $3 14.8 Other Buildings & Structures $0 $405 $316 $0 $0 $721 $64 $0 $157 $942 $2 14.9 Waste Treating Building & Str. $0 $906 $1,731 $0 $0 $2,637 $246 $0 $577 $3,460 $6 SUBTOTAL 14. $0 $6,155 $7,032 $0 $0 $13,187 $1,201 $0 $2,364 $16,752 $31

TOTAL COST $781,441 $71,079 $257,562 $0 $0 $1,110,083 $102,860 $30,314 $199,286 $1,442,543 $2,656 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

322 

### Exhibit 3

- 103 Case L3A Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $12,238 $23 1 Month Variable O&M $3,335 $6 25% of 1 Months Fuel Cost at 100% CF $741 $1 2% of TPC $28,851 $53 Total $45,164 $83

Inventory Capital 60 day supply of consumables at 100% CF $6,129 $11 0.5% of TPC (spare parts) $7,213 $13 Total $13,342 $25

Initial Cost for Catalyst and Chemicals $1,737 $3 Land $900 $2 Other Owner's Costs $216,381 $398 Financing Costs $38,949 $72

Total Owner's Costs $316,473 $583 Total Overnight Cost (TOC) $1,759,016 $3,239 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $2,005,278 $3,692Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

323 

### Exhibit 3

- 104 Case L3 A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case L3A - Siemens 543 MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 9,063 MWe-net: 543 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $10.898 Maintenance Labor Cost $13,661,375 $25.154 Administrative & Support Labor $4,895,072 $9.013 Property Taxes and Insurance $28,850,854 $53.121 TOTAL FIXED OPERATING COSTS $53,326,213 $98.185 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $26,380,507 $0.00693

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 1,577 1.08 $0 $498,031 $0.00013

Chemicals

MU & WT Chem.(lbs) 0 9,394 0.17 $0 $474,740 $0.00012 Carbon (Mercury Removal) (lb) 67,428 92 1.05 $70,811 $28,325 $0.00001 COS Catalyst (m3) 605 0.41 2,397.36 $1,450,277 $290,055 $0.00008 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Sulfinol Solution (gal) 21,466 15 10.05 $215,705 $42,794 $0.00001 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.83 131.27 $0 $31,975 $0.00001 Subtotal Chemicals $1,736,794 $867,889 $0.00023

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 92 0.42 $0 $11,249 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 898 16.23 $0 $4,255,027 $0.00112 Subtotal Waste Disposal $0 $4,266,277 $0.00112

By-products & Emissions

Sulfur (tons) 0 56 0.00 $0 $0 $0.00000 Subtotal-By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,736,794 $32,012,704 $0.00841

Fuel (ton) 0 8,927 10.92 $0 $28,463,735 $0.00748Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

324 

### 3.4.8 SFG IGCC CO 2 

### Capture Cases (S3B and L3B) Process Description

Cases S3B and L3B are configured to produce electric power with CO 2 

### capture. The plant configurations are similar to Cases S3A and L3A with the major differences being the addition of WGS, the use of a two

- stage Selexol AGR plant instead of Sulfinol and subsequent compression of the captured CO 2 

### stream. The gross power output is constrained by the capacity of the two CT s, and since the C O 2 

### capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Cases S3A and L3A.

The process description for Cases S3B and L3B is similar to Cases S3A and L3A with several notable exceptions to accommodate CO 2 

### capture. A BFD for the CO 2 

### capture case s is shown in Exhibit 3

- 105 and stream tables are shown in Exhibit 3

- 106 and Exhibit 3

- 107 . Instead of repeating the entire process description, only differences from the non

- capture cases are reported here. Coal Preparation and Feed Systems

No differences from non

- capture cases.

Gasification The gasification process is the same as the non

- capture cases except the coal feed (a s

- received) to the gasifiers is 6,312 tonne/day (6,958 tpd) for the PRB case and 8,727 tonne/day (9,620 tpd) for the lignite case. Raw Gas Cooling/Particulate Removal

No differences from non

- capture cases. Sour Water Stripper

No differences from non

- capture cases.

Sour Gas Shift The SGS process was desc ribed in Section 3.1.6 . The water concentration in the syngas is controlled by varying the exit temperature of the water scrubber upstream of the shift reactors. The hot syngas exiting the first stage of SGS is used to superheat steam. One more stage of SGS (for a total of two) results in approximately 97 percent overall conversion of CO to CO 2 

### . The warm syngas from the second stage of SGS is cooled to preheat th e syngas prior to the first stage of SGS. The SGS catalyst also serves to hydrolyze COS

, thus eliminating the need for a separate COS hydrolysis reactor. Following the second stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

. Mercury Removal and AGR Mercury removal is the same as in the non

- capture cases.

The AGR process in the CO 2 

### capture cases is a two stage Selexol process where H 2 

### S is removed in the first stage and CO 2 

### in the second stage of absorption. The process results in three product streams, the clean syngas, a CO 2 

### - rich stream and an acid gas feed to the Claus plant. The acid gas contains about 17 percent H 2 

### S and 6 5 percent CO 2 

### with the balance primarily H 2 

### . The CO 2 

### - rich stream is discussed further i n the CO 2 

### compression section.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

325 

### CO 2 

### Compression and Dehydration

CO 2 

### from the AGR process is generated at two pressure levels. The LP stream is compressed from 0.12 MPa (17 psia) to 1.0 MPa (150 psia) and then combined with the HP stream. The combined st ream is further compressed to a SC condition at 15.3 MPa (2215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

### stream is dehydrated to a dew point of

- 40oC (

- 40°F) using a thermal swing adsorptive dryer. The raw CO 2 

### stream from the Selexol process contains over 99 percent CO 2 

### . The dehydrated 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 2.6

. Claus Unit The Claus plant is the same as the non

- capture cases except 46 tonne/day (51 tpd) of sulfur are produced in the PRB case and 55 tonne/day (60 tpd) in the lignite case.

Power Block Clean syngas from the AGR plant is reheated to 196°C (385°F) using HP BFW , diluted with nitrogen, and then enters the CT burner. The exhaust gas exits the CT at a nominal 566°C (1,050°F) and enters the HRSG where additional heat is recovered. The flue g as exits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a nominal 12.4 MPa/538°C/538°C (1

, 800 psig/1

, 000°F/1

, 000°F) steam cycle. Th ere is no air integration between the CT and the ASU in either capture case.

ASU The same elevated pressure ASU is used as in non

- captu re cases except the output is 3,837 tonne/day (4,229 tpd) of 95 mol % oxygen to the gasifier and Cla us plant for the PRB c ase and 4,286 tonne/day (4,725 tpd) for the lignite case

Balance of Plant

Balance of plant items were covered in Sections 3.1.12
, 3.1.13
, 3.1.14
, and 3.1.15

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

326 

### Exhibit 3

- 105 Case S3B and L3B Process Flow DiagramCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

327 

### Exhibit 3

- 106 Case S3B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction

Ar 0.0093 0.0254 0.0318 0.0023 0.0023 0.0360 0.0000 0.0000 0.0000 0.0000 0.0000 0.0051 0.0000 0.0051 0.0064
CH 4 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 0.0000
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2832 0.0000 0.2832 0.0101
CO 2 0.0003 0.0088 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0257 0.0000 0.0257 0.3809
COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0001 0.0000
H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1456 0.0000 0.1456 0.5325

H 2 O 0.0064 0.1664 0.0000 0.0002 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 0.4854 1.0000 0.4854 0.0016

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0015 0.0000 0.0015 0.0021

N 2 0.7759 0.5832 0.0178 0.9920 0.9920 0.0140 0.0000 0.0000 0.0000 0.0000 0.0000 0.0524 0.0000 0.0524 0.0663

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0000 0.0008 0.0000
O 2 0.2081 0.2162 0.9504 0.0054 0.0054 0.9500 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 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 24,095 900 47 16,376 1,850 4,914 1,268 0 3,070 0 0 35,328 0 35,328 27,923 V-L Flowrate (kg/hr) 696,213 24,890 1,497 459,533 51,920 158,373 22,845 0 55,312 0 0 701,295 0 701,295 567,855 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 262,991 0 207,679 22,191 0 0 0 0

Temperature (°C) 6 20 32 196 197 32 343 6 33 71 260 208 288 232 35 Pressure (MPa, abs) 0.09 0.11 0.86 2.65 5.62 0.86 5.10 0.09 0.55 0.09 4.17 4.07 4.14 4.00 3.60 Enthalpy (kJ/kg) A 15.26 39.05 26.67 202.64 201.76 26.59 3,062.93

--- 139.92

--- --- 1,401.25 2,955.16 1,444.76 43.22 Density (kg/m 3 ) 1.1 1.5 11.0 18.9 39.6 11.0 20.1

--- 985.3

--- --- 21.1 18.2 19.6 29.2 V-L Molecular Weight 28.895 27.654 32.181 28.061 28.061 32.229 18.015

--- 18.015

--- --- 19.851 18.015 19.851 20.336

V-L Flowrate (lb mol /hr) 53,119 1,984 103 36,104 4,079 10,833 2,796 0 6,769 0 0 77,885 0 77,885 61,561 V-L Flowrate (lb/hr) 1,534,887 54,874 3,300 1,013,098 114,463 349,152 50,364 0 121,942 0 0 1,546,091 0 1,546,091 1,251,906 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 579,796 0 457,854 48,923 0 0 0 0

Temperature (°F) 42 68 90 385 387 90 650 42 92 160 500 407 550 450 95 Pressure (psia) 13.0 16.4 125.0 384.0 815.0 125.0 740.0 13.0 80.0 12.7 604.7 589.7 600.0 579.7 522.6 Enthalpy (Btu/lb) A 6.6 16.8 11.5 87.1 86.7 11.4 1,316.8

--- 60.2

--- --- 602.4 1,270.5 621.1 18.6 Density (lb/ft 3 ) 0.070 0.094 0.687 1.180 2.475 0.688 1.257

--- 61.513

--- --- 1.318 1.135 1.223 1.823 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

328 

### Exhibit 3

- 106 Case S3B Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 V-L Mole Fraction

Ar 0.0067 0.0064 0.0022 0.0000 0.0056 0.0002 0.0002 0.0100 0.0100 0.0093 0.0090 0.0090 0.0000 0.0000 0.0000 0.0000
CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 0.0060 0.0101 0.0038 0.0000 0.0760 0.0003 0.0003 0.0156 0.0156 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.6603 0.3853 0.6540 0.0000 0.4865 0.9916 0.9945 0.0460 0.0460 0.0003 0.0089 0.0089 0.0000 0.0000 0.0000 0.0000
COS 0.0000 0.0000 0.0001 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
H 2 0.1409 0.5283 0.1270 0.0000 0.0574 0.0047 0.0047 0.8248 0.8248 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.1381 0.0016 0.0394 0.0000 0.3338 0.0030 0.0000 0.0001 0.0001 0.0064 0.1204 0.1204 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0052 0.0022 0.1632 0.0000 0.0011 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0429 0.0661 0.0104 0.0000 0.0362 0.0003 0.0003 0.1034 0.1034 0.7759 0.7553 0.7553 0.0000 0.0000 0.0000 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 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 0.2081 0.1064 0.1064 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0000 0.0000 0.0031 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 0.0000 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) 374 28,247 375 0 443 9,895 9,865 17,977 17,747 100,352 127,019 127,019 17,949 17,444 17,444 36,575 V-L Flowrate (kg/hr) 12,597 579,530 13,417 0 13,813 432,659 432,123 133,455 131,748 2,899,687 3,490,969 3,490,969 323,355 314,255 314,255 658,912 Solids Flowrate (kg/hr) 0 0 0 1,908 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 49 35 48 175 232 16 72 31 216 6 561 132 533 32 32 33 Pressure (MPa, abs) 0.07 3.53 0.16 0.1 0.085 0.931 15.270 3.238 3.203 0.090 0.093 0.090 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 235.23 42.11 95.90

--- 755.306 6.442 -94.805 118.187 862.962 15.260 829.552 340.436 3,430.204 2,255.058 2,255.058 140.571 Density (kg/m 3 ) 0.9 29.0 2.2

--- 0.6 18.0 460.0 9.4 5.8 1.1 0.4 0.7 36.8 0.04 0.04 995.0 V-L Molecular Weight 33.644 20.517 35.800

--- 31.159 43.725 43.803 7.424 7.424 28.895 27.484 27.484 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 825 62,273 826 0 977 21,815 21,749 39,632 39,126 221,239 280,028 280,028 39,571 38,457 38,457 80,634 V-L Flowrate (lb/hr) 27,771 1,277,645 29,579 0 30,452 953,849 952,667 294,217 290,454 6,392,716 7,696,268 7,696,268 712,876 692,813 692,813 1,452,653 Solids Flowrate (lb/hr) 0 0 0 4,206 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 120 94 119 347 450 60 162 87 420 42 1,042 270 992 90 90 92 Pressure (psia) 10.6 512.6 23.7 17.3 12.3 135.0 2,214.7 469.6 464.6 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 101.1 18.1 41.2

--- 324.7 2.8 -40.8 50.8 371.0 6.6 356.6 146.4 1,474.7 969.5 969.5 60.4 Density (lb/ft 3 ) 0.058 1.808 0.137

--- 0.039 1.123 28.720 0.587 0.361 0.070 0.023 0.046 2.297 0.002 0.002 62.115Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

329 

### Exhibit 3

- 107 Case L3B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction

Ar 0.0093 0.0170 0.0318 0.0023 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0054 0.0000 0.0054 0.0068
CH 4 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 0.0000
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2889 0.0000 0.2889 0.0103
CO 2 0.0003 0.0055 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0304 0.0000 0.0304 0.3960
COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0002 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 0.1415 0.0000 0.1415 0.5371

H 2 O 0.0062 0.1013 0.0000 0.0002 0.0002 0.0000 1.0000 0.0000 1.0000 0.0000 0.0000 0.4950 1.0000 0.4950 0.0016

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0017 0.0000 0.0017 0.0024

N 2 0.7761 0.7372 0.0178 0.9920 0.9920 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0360 0.0000 0.0360 0.0457

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0010 0.0000 0.0010 0.0000
O 2 0.2082 0.1389 0.9504 0.0054 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 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 26,909 1,591 56 17,415 2,353 5,493 0 0 5,523 0 0 37,348 0 37,348 29,362 V-L Flowrate (kg/hr) 777,605 44,312 1,814 488,676 66,031 176,772 0 0 99,501 0 0 744,717 0 744,717 600,885 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 363,623 0 264,122 36,583 0 0 0 0

Temperature (°C) 4 18 32 196 197 32 343 4 32 71 260 209 288 226 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 5.62 0.86 5.10 0.10 0.34 0.09 4.17 4.10 4.14 4.03 3.60 Enthalpy (kJ/kg) A 13.75 36.85 26.67 202.62 201.75 26.67 3,062.93

--- 134.94

--- --- 1,418.72 2,955.16 1,448.03 42.49 Density (kg/m 3 ) 1.2 1.4 11.0 18.9 39.6 11.0 20.1

--- 986.5

--- --- 21.4 18.2 20.2 29.4 V-L Molecular Weight 28.898 27.846 32.181 28.061 28.061 32.181 18.015

--- 18.015

--- --- 19.940 18.015 19.940 20.465

V-L Flowrate (lb mol /hr) 59,324 3,508 124 38,393 5,188 12,110 0 0 12,176 0 0 82,338 0 82,338 64,732 V-L Flowrate (lb/hr) 1,714,325 97,692 4,000 1,077,346 145,573 389,715 0 0 219,362 0 0 1,641,820 0 1,641,820 1,324,726 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 801,651 0 582,290 80,651 0 0 0 0

Temperature (°F) 40 64 90 385 387 90 650 40 90 160 500 409 550 438 95 Pressure (psia) 13.8 16.4 125.0 384.0 815.0 125.0 740.0 13.8 50.0 13.5 604.7 594.7 600.0 584.7 522.6 Enthalpy (Btu/lb) A 5.9 15.8 11.5 87.1 86.7 11.5 1,316.8

--- 58.0

--- --- 609.9 1,270.5 622.5 18.3 Density (lb/ft 3 ) 0.074 0.089 0.687 1.180 2.475 0.687 1.257

--- 61.586

--- --- 1.335 1.135 1.261 1.837 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

330 

### Exhibit 3

- 107 Case L3B Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 V-L Mole Fraction

Ar 0.0073 0.0068 0.0022 0.0000 0.0056 0.0002 0.0002 0.0108 0.0108 0.0093 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000
CH 4 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 0.0000 0.0000
CO 0.0043 0.0103 0.0037 0.0000 0.0683 0.0003 0.0003 0.0162 0.0162 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.6625 0.4004 0.6492 0.0000 0.4464 0.9920 0.9948 0.0489 0.0489 0.0003 0.0091 0.0091 0.0000 0.0000 0.0000 0.0000
COS 0.0000 0.0000 0.0001 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
H 2 0.1371 0.5326 0.1223 0.0000 0.0549 0.0045 0.0045 0.8506 0.8506 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.1381 0.0016 0.0371 0.0000 0.3856 0.0029 0.0000 0.0001 0.0001 0.0062 0.1201 0.1201 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0077 0.0025 0.1784 0.0000 0.0010 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0429 0.0458 0.0069 0.0000 0.0332 0.0002 0.0002 0.0733 0.0733 0.7761 0.7544 0.7544 0.0000 0.0000 0.0000 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 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 0.2082 0.1073 0.1073 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0000 0.0000 0.0047 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 0.0000 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) 404 29,711 413 0 523 10,810 10,779 18,237 18,237 106,961 134,708 134,708 18,759 18,905 18,905 38,261 V-L Flowrate (kg/hr) 13,661 613,551 14,837 0 15,765 472,792 472,236 124,209 124,209 3,090,914 3,703,790 3,703,790 337,956 340,584 340,584 689,276 Solids Flowrate (kg/hr) 0 0 0 2,272 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 49 35 48 175 232 16 72 31 216 4 560 133 532 32 32 33 Pressure (MPa, abs) 0.07 3.53 0.16 0.1 0.085 0.931 15.270 3.238 3.234 0.095 0.099 0.095 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 234.19 41.51 92.67

--- 857.472 6.283 -95.297 129.249 941.449 13.748 827.741 340.637 3,427.815 2,254.480 2,254.480 140.362 Density (kg/m 3 ) 0.9 29.2 2.2

--- 0.6 18.0 461.3 8.6 5.4 1.2 0.4 0.8 36.9 0.04 0.04 995.0 V-L Molecular Weight 33.799 20.651 35.961

--- 30.119 43.737 43.811 6.811 6.811 28.898 27.495 27.495 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 891 65,502 910 0 1,154 23,832 23,764 40,206 40,206 235,808 296,981 296,981 41,357 41,679 41,679 84,350 V-L Flowrate (lb/hr) 30,116 1,352,649 32,709 0 34,756 1,042,328 1,041,102 273,833 273,833 6,814,298 8,165,460 8,165,460 745,066 750,859 750,859 1,519,593 Solids Flowrate (lb/hr) 0 0 0 5,008 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 120 94 119 347 450 60 162 87 420 40 1,040 271 990 90 90 92 Pressure (psia) 10.6 512.6 23.7 17.3 12.3 135.0 2,214.7 469.6 469.0 13.8 14.3 13.8 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 100.7 17.8 39.8

--- 368.6 2.7 -41.0 55.6 404.8 5.9 355.9 146.4 1,473.7 969.3 969.3 60.3 Density (lb/ft 3 ) 0.058 1.822 0.138

--- 0.038 1.123 28.800 0.538 0.335 0.074 0.024 0.048 2.301 0.002 0.002 62.116Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

331 

### 3.4.9 Case S3B and L3B Performance Results

The Case S3B and L3B modeling assumptions were presented previously in Exhibit 3

- 84

.
The SFG IGCC plant with CO 2 

### capture and using PRB coal at the Montana site (elevation 3,400 ft) produces a net output of 445 MWe at a net plant efficiency of 30

. 6 percent (HHV basis). The same plant configuration using lignite coal at the North Dakota site (elevation 1,900 ft) produces a net output of 4 6 7 MWe at a net plant efficiency of 30 .0 percent (HHV basis). Overall performance for the plants is summarized i n Exhibit 3

- 108
, which includes auxiliary power requirements The ASU accounts for approximately 5 6 percent of the total auxiliary load in both cases, distributed betwe en the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The coal drying process accounts for approximately 7 percent of the auxiliary load. CO 2 

### compression accounts for about 17 percent and the AGR process
account s for about 10 percent of the auxiliary load. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

332 

### Exhibit 3

- 108 Case S3B and L3B Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) S3B L3B

Gas Turbine Power 430,900 456,600 Steam Turbine Power 203,800 220,300 TOTAL POWER, kWe 634,700 676,900 AUXILIARY LOAD SUMMARY, kWe Coal Handling 510 620 Coal Milling 2,700 3,740 Slag Handling 580 950 WTA Coal Dryer Compressor 9,270 12,780 WTA Coal Dryer Auxiliaries 600 840 Air Separation Unit Auxiliaries 1,000 1,000 Air Separation Unit Main Air Compressor 62,000 67,470 Oxygen Compressor 8,670 9,680 Nitrogen Compressors 34,640 37,800
CO 2 Compressor 31,220 34,730 Boiler Feedwater Pumps 2,330 2,440 Condensate Pump 220 230 Quench Water Pump 10 10 Circulating Water Pump 3,090 3,380 Ground Water Pumps 360 380 Cooling Tower Fans 2,020 2,070 Air Cooled Condenser Fans 2,990 3,050 Scrubber Pumps 750 740 Acid Gas Removal 18,190 19,910 Gas Turbine Auxiliaries 1,000 1,000 Steam Turbine Auxiliaries 100 100 Claus Plant/TGTU Auxiliaries 250 250 Claus Plant TG Recycle Compressor 1,460 1,580 Miscellaneous Balance of Plant 1 3,000 3,000 Transformer Losses 2,450 2,640 TOTAL AUXILIARIES, kWe 189,410 210,390 NET POWER, kWe 445,290 466,510 Net Plant Efficiency, % (HHV) 30.6% 30.0% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,765 (11,151) 11,997 (11,371) CONDENSER COOLING DUTY GJ/hr (10 6 Btu/hr) 1,329 (1,260) 1,445 (1,370)
CONSUMABLES
As

- Received Coal Feed, kg/hr (lb/hr) 262,991 (579,796) 363,623 (801,651) Thermal Input, kWt 1,455,207 1,554,603 Raw Water Withdrawal , m 3 /min (gpm) 15.2 (4,025) 15.8 (4,165) Raw Water Consumption , m 3 /min (gpm) 1 2

. 5 ( 3
, 304 ) 12.8 (3

, 379 )

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

333 

### Environmental Performance The environmental targets for emissions of Hg, NOx , SO 2 

### , CO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for the CO 2 

### capture cases is presented in Exhibit 3

- 109

.

Exhibit 3

- 109 Case S3B and L3B Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

S3B L3B S3B L3B S3B L3B

SO 2 

### 0.000 (0.001) 0.000 (0.001) 14 (15) 16 (18) 0.003 ( 0 .0 07 ) 0.003 ( 0 .0 08 )

NO X 

### 0.022 (0.051) 0.021 (0.050) 802 (884) 841 (927) 0.180 ( 0 .397) 0.177 ( 0 .391)

Particulates 0.003 (0.0071) 0.003 (0.0071) 112 (124) 120 (132) 0.025 ( 0 .056) 0.025 ( 0 .056)

Hg 1.51E

- 7 (3.51E

- 7) 2.41E

- 7 (5.60E

- 7) 0.006 (0.006) 0.009 (0.010) 1.25E

- 6 (2.75E

- 6) 1.99E

- 6 (4.39E

- 6)

CO 2 

### gross 9.5 (22.0) 9.6 (22.4) 347,578 (383,140) 377,494 (416,116) 78 (172) 80 (175)

CO 2 

### net 111 (246) 115 (255)

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the two

- stage Selexol AGR process. Just as in the non

- capture cases, the SO 2 

### emission are significantly less than the environmental targets of Section 2.3 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 2 ppmv. This results in a concentration in the flue gas of less than 0.3 ppmv. The H 2 

### S

- rich regeneration gas fro m the AGR system is fed to a Claus plant, producing elemental sulfur. The tail gas is hydrogenated and recycled upstream of the AGR.

NO x emissions are limited to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ) by the use of low NOx burners and nitrogen dilution of the fuel gas . Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and subsequently destroyed in the Claus plant burner. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is limited to e xtremely low values by the use of a cyclone and a barrier filter 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 mercury is captured from the syngas by an activated carbon bed.

Slightly greater than 9 2 percent of the CO 2 

### from the syngas is captured in the AGR system and compressed for sequestration. The carbon balance for the plant is shown in Exhibit 3

- 110

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in theCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

334 

### carbon capture equation below, but it is not neglected i n the balance since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, CO 2 

### in the stack gas and ASU vent gas, and the captured CO 2 

### product

. The carbon capture efficiency is defined as the amoun t 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 Product for Sequestration)/[(Carbon in the Coal)

- (Carbon in Slag)] or 90 percent (both cases S3B and L3B)

Exhibit 3

- 110 Cases S3B and L3B Carbon Balance
Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)
S3B L3B S3B L3B

Coal 131,675 (290,293) 143,826 (317,083) Slag 658 (1,451) 719 (1,585)

Air (CO 2 

### ) 490 (1,081) 527 (1,163) Stack Gas 13,536 (29,842) 14,701 (32,410)
ASU Vent 95 (209) 106 (234)

CO 2 

### Product 117,876 (259,871) 128,827 (284,016)

Total 132,165 (291,374) 144,354 (318,245) Total 132,165 (291,374) 144,354 (318,245)

Exhibit 3

- 111 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack ga s and sulfur that is co

- sequestered with the CO 2 

### product. Sulfur in th e slag is considered negligible

.

Exhibit 3

- 111 Cases S3B and L3B Sulfur Balance
Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)
S3B L3B S3B L3B

Coal 1,913 (4,218) 2,278 (5,022) Elemental Sulfur 1,908 (4,206) 2,272 (5,008)

Stack Gas 1 (2) 1 (3)

CO 2 

### Product 4 (9) 5 (11)

Total 1,913 (4,218) 2,278 (5,022) Total 1,913 (4,218) 2,278 (5,022)

Exhibit 3

- 112 shows the overall water balance for the plant. 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, primarily from the coal drying process and as syngas condensate, and that water is re

used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Some water is discharged from the process to a permitted outfall. The difference between the withdrawal and discharge is the consumption

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

335 

### Exhibit 3

- 112 Cases S3B and L3B 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)

S3B L3B S3B L3B S3B L3B S3B L3B S3B L3B
Slag Handling 0.48 (127) 0.79 (210) 0.5 (127) 0.8 (210) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Quench/Wash 5.56 (1469) 5.98 (1580) 1.6 (426) 1.5 (386) 3.95 (1043) 4.52 (1194) 0 (0) 0 (0) 3.95 (1043) 4.52 (1194)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) 0.02 (6) 0.02 (6)

- 0.02 (

- 6)

- 0.02 (

- 6)
Condenser Makeup 0.51 (134) 0.14 (36) 0 (0) 0 (0) 0.51 (134) 0.14 (36) 0 (0) 0 (0) 0.51 (134) 0.14 (36)

Shift Steam 0.38 (101) 0.38 (101)
BFW Makeup 0.13 (33) 0.14 (36) 0.13 (33) 0.14 (36)

Cooling Tower 12.04 (3,180) 13.13 (3,469) 1.3 (333) 2.0 (534) 10.78 (2,848) 11.11 (2,935) 2.71 (715) 2.95 (780) 8.07 (2,132) 8.16 (2,155) Water from Coal Drying 0.9 (244) 1.7 (439) - 0.92 (

- 244) - 1.66 (

- 439)
BFW Blowdown 0.1 (33) 0.1 (36)

- 0.13 (

- 33)

- 0.14 (

- 36)

SWS Blowdown 0.2 (55) 0.2 (60)

- 0.21 (

- 55)

- 0.23 (

- 60)

Total 18.6 (4,911) 20.0 (5,294) 3.4 (886) 4.3 (1,130) 15.2 (4,025) 15.8 (4,165) 2.7 (721) 3.0 (786) 12.5 (3,304) 12.8 (3,379)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

336 

### Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 113 and Exhibit 3

- 114 :

**•** Coal gasification and ASU

**•** Syngas cleanup

**•** Combined cycle power generation

An overall plant energy balance is provided in tabular form in Exhibit 3

- 115 for the two cases. The power out is the combined CT and steam turbine power after generator losses.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

337 

### Exhibit 3

- 113 Case S3B Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

338 

### Exhibit 3

- 113 Case S3B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

339 

### Exhibit 3

- 113 Case S3B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

340 

### Exhibit 3

- 114 Case L3B Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

341 

### Exhibit 3

- 114 Case L3B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

342 

### Exhibit 3

- 114 Case L3B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

343 

### Exhibit 3

- 115 Cases S3B and L3B Energy Balance

HHV Sensible + Latent Power Total S3B L3B S3B L3B S3B L3B S3B L3B Heat In GJ/hr (MMBtu/hr)

Coal 5,239 (4,965) 5,597 (5,305) 2.7 (2.6) 3.2 (3.1) 0 (0) 0 (0) 5,241 (4,968) 5,600 (5,308)

ASU Air 0 (0) 0 (0) 10.6 (10.1) 10.7 (10.1) 0 (0) 0 (0) 11 (10) 11 (10) GT Air 0 (0) 0 (0) 44.2 (41.9) 42.5 (40.3) 0 (0) 0 (0) 44 (42) 42 (40) Raw Water Makeup 0 (0) 0 (0) 21.2 (20.1) 17.5 (16.6) 0 (0) 0 (0) 21 (20) 18 (17) Auxiliary Power 0 (0) 0 (0) 0 (0) 0 (0) 682 (646) 757 (718) 682 (646) 757 (718)

Totals 5,239 (4,965) 5,597 (5,305) 78.8 (74.6) 74.0 (70.1) 682 (646) 757 (718) 5,999 (5,686) 6,428 (6,093)
Heat Out GJ/hr (MMBtu/hr) ASU Intercoolers 0 (0) 0 (0) 215 (204) 232 (220) 0 (0) 0 (0) 215 (204) 232 (220) ASU Vent 0 (0) 0 (0) 1.0 (0.9) 1.6 (1.5) 0 (0) 0 (0) 1 (1) 2 (2) Slag 22 (20) 24 (22) 4.8 (4.6) 7.9 (7.5) 0 (0) 0 (0) 26 (25) 32 (30) Sulfur 18 (17) 21 (20) 0.2 (0.2) 0.3 (0.2) 0 (0) 0 (0) 18 (17) 21 (20) CO 2 0 (0) 0 (0)

- 41.0 (

- 38.8)

- 45.0 (

- 42.7) 0 (0) 0 (0)

- 41 (

- 39)

- 45 (

- 43) CO 2 Comp Intercoolers 0 (0) 0 (0) 151.4 (143.5) 167.8 (159.0) 0 (0) 0 (0) 151 (144) 168 (159) Cooling Tower Blowdown 0 (0) 0 (0) 15.1 (14.3) 16.0 (15.2) 0 (0) 0 (0) 15 (14) 16 (15)

HRSG Flue Gas 0 (0) 0 (0) 1,188 (1,126) 1,262 (1,196) 0 (0) 0 (0) 1,188 (1,126) 1,262 (1,196) Condenser 0 (0) 0 (0) 1,330 (1,260) 1,443 (1,368) 0 (0) 0 (0) 1,330 (1,260) 1,443 (1,368) Auxiliary Cooling Loads 0 (0) 0 (0) 348 (329) 385 (365) 0 (0) 0 (0) 348 (329) 385 (365)

Generator Loss 0 (0) 0 (0) 0 (0) 0 (0) 35 (33) 37 (35) 35 (33) 37 (35)
Process Losses 0 (0) 0 (0) 4 28 (4 06 ) 4 39 (4 16 ) 0 (0) 0 (0) 4 28 (4 06 ) 4 39 (4 16 )

Power 0 (0) 0 (0) 0 (0) 0 (0) 2,285 (2,166) 2,437 (2,310) 2,285 (2,166) 2,437 (2,310)

Totals 39 (37) 45 (42) 3,6 40 (3,4 50 ) 3,9 09 (3,7 05 ) 2,320 (2,199) 2,474 (2,345) 5 , 999 (5, 686 ) 6,4 28 (6, 093 )Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

344 

### 3.4.10 Case S3B and L3B Equipment List

Major equipment items for the SFG with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.4.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

345 

### ACCOUNT 1 COAL HANDLING Equipment No. Description Type S3B Design Conditions L3B Design Condition Operating Qty Spares

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 54 tonne (60 ton) 73 tonne (80 ton) 2 1
9 Feeder Vibratory 218 tonne/hr (240 tph) 299 tonne/hr (330 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 435 tonne/hr (480 tph) 599 tonne/hr (660 tph) 1 0

11 Crusher Tower N/A N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 218 tonne (240 ton) 299 tonne (330 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 435 tonne/hr (480 tph) 599 tonne/hr (660 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A N/A 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

346 

### Equipment No. Description Type S3B Design Conditions L3B Design Condition Operating Qty Spares

17 Conveyor No. 5 Belt w/ tripper 435 tonne/hr (480 tph) 599 tonne/hr (660 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 998 tonne (1,100 ton) 1,361 tonne (1,500 ton) 3 0

ACCOUNT 2 COAL PREPARATION AND FEED
Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Feeder Vibratory 100 tonne/hr (110 tph) 136 tonne/hr (150 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 290 tonne/hr (320 tph) 399 tonne/hr (440 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 581 tonne (640 ton) 798 tonne (880 ton) 1 0

4 Weigh Feeder Belt 145 tonne/hr (160 tph) 200 tonne/hr (220 tph) 2 0

5 Pulverizer Rotary 145 tonne/hr (160 tph) 200 tonne/hr (220 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 290 tonne (320 ton) 399 tonne (440 ton) 2 0

7 Coal Preheater Water Heated Horizontal Rotary Kiln Coal feed: 290 tonne/hr (320 tph) Heat duty: 32.2 GJ/hr (30.5 MMBtu/hr) Coal feed: 399 tonne/hr (440 tph) Heat duty: 49.4 GJ/hr (46.8 MMBtu/hr) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

347 

### Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

8 Coal Dryer Fluidized Bed with Internal Coils Coal feed: 145 tonne/hr (160 tph) Heat duty: 81.0 GJ/hr (76.7 MMBtu/hr) Bed diameter: 12.5 m (41 ft) Coal feed: 200 tonne/hr (220 tph) Heat duty: 143.3 GJ/hr (135.8 MMBtu/hr) Bed diameter: 14.6 m (48 ft) 2 0

9 Steam Compressor Reciprocating, Multi

Stage 606 m 3 

### /min (21,400 scfm) Suction

- 0.09 MPa (13 psia) Discharge

- 0.72 MPa (105 psia) 1
, 090 m 3 

### /min (38,500 scfm) Suction

- 0.10 MPa (13.8 psia) Discharge

- 0.52 MPa (75 psia) 2 0

10 Dryer Exhaust Filter Hot Baghouse Steam

- 30,436 kg/hr (67,100 lb/hr) Temperature

- 107°C (225°F) Steam

- 54,703 kg/hr (120,600 lb/hr) Temperature

- 107°C (225°F) 2 0

11 Dry Coal Cooler Water Cooled Horizontal Rotary Kiln 228 tonne/hr (252 tph) Heat duty

- 13 GJ/hr (13 MMBtu/hr) 291 tonne/hr (320 tph) Heat duty

- 18 GJ/hr (17 MMBtu/hr) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

348 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 488,318 liters (129,000 gal) 526,172 liters (139,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,095 lpm @ 91 m H 2 

### O (1,610 gpm @ 300 ft H 2 

### O) 6,359 lpm @ 91 m H 2 

### O (1,680 gpm @ 300 ft H 2 

### O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 441,345 kg/hr (973,000 lb/hr) 466,747 kg/hr (1,029,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2,801 lpm @ 27 m H 2 

### O (740 gpm @ 90 ft H 2 

### O) 3,066 lpm @ 27 m H 2 

### O (810 gpm @ 90 ft H 2 

### O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

- stage, centrifugal HP water: 3,142 lpm @ 1,890 m H 2 

### O (830 gpm @ 6,200 ft H 2 

### O) HP water: 3,293 lpm @ 1,890 m H 2 

### O (870 gpm @ 6,200 ft H 2 

### O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

- stage, centrifugal IP water: 1,136 lpm @ 223 m H 2 

### O (300 gpm @ 730 ft H 2 

### O) IP water: 1,249 lpm @ 223 m H 2 

### O (330 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 Cycl e Cooling Heat Exchangers Plate and frame 4 07 GJ/hr (386 MMBtu/hr) each 446 GJ/hr (422 MMBtu/hr) each 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

349 

### Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 146,117 lpm @ 21 m H 2 

### O (38,600 gpm @ 70 ft H 2 

### O) 159,744 lpm @ 21 m H 2 

### O (42,200 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 4,240 lpm @ 18 m H 2 

### O (1,120 gpm @ 60 ft H 2 

### O) 4,391 lpm @ 18 m H 2 

### O (1,160 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) 2,915 lpm @ 268 m H 2 

### O (770 gpm @ 880 ft H 2 

### O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 3,710 lpm @ 49 m H 2 

### O (980 gpm @ 160 ft H 2 

### O) 3,899 lpm @ 49 m H 2 

### O (1,030 gpm @ 160 ft H 2 

### O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,775,358 liter (469,000 gal) 1,866,208 liter (493,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 151 lpm (40 gpm) 151 lpm (40 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24

- hour storm 10 years, 24

- hour storm 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

350 

### ACCOUNT 4 GASIFIER, ASU , AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Gasifier Pressurized dry

feed, entrained bed 2,359 tonne/day, 4.2 MPa (2,600 tpd, 60 5 psia) 3,175 tonne/day, 4.2 MPa (3,500 tpd, 60 5 psia) 3 0

2 Synthesis Gas Cyclone High efficiency 285,310 kg/hr (629,000 lb/hr) Design efficiency 90% 303,453 kg/hr (669,000 lb/hr) Design efficiency 90% 3 0

3 Syngas Scrubber Including Sour Water Stripper Vertical up flow 274,877 kg/hr (606,000 lb/hr) 292,567 kg/hr (645,000 lb/hr) 3 0

4 Raw Gas Coolers Shell and tube with condensate drain 385,554 kg/hr (850,000 lb/hr) 409,594 kg/hr (903,000 lb/hr) 8 0

5 Raw Gas Knockout Drum Vertical with mist eliminator 312,525 kg/hr, 35°C, 3.6 MPa (689,000 lb/hr, 95°F, 528 psia) 330,669 kg/hr, 35°C, 3.6 MPa (729,000 lb/hr, 95°F, 528 psia) 2 0

6 Synthesis Gas Reheater Shell and tube 73,482 kg/hr (162,000 lb/hr) 68,492 kg/hr (151,000 lb/hr) 2 0

7 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 412,315 kg/hr (909,000 lb/hr) syngas 438,624 kg/hr (967,000 lb/hr) syngas 2 0

8 ASU Main Air Compressor Centrifugal, multi

stage 5,239 m 3 

### /min @ 1.3 MPa (185,000 scfm

@ 190 psia) 5,833 m 3 

### /min @ 1.3 MPa (206,000 scfm

@ 190 psia) 2 0

9 Cold Box Vendor design 2,087 tonne/day (2,300 tpd) of 95% purity oxygen 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

351 

### Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 0 Oxygen Compressor Centrifugal, multi

stage 1,076 m 3 

### /min (38,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 1,189 m 3 

### /min (42,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 2 0

1 1 Primary Nitrogen Compressor Centrifugal, multi

stage 3,483 m 3 

### /min (123,000 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

12 Secondary Nitrogen Compressor Centrifugal, single

stage 481 m 3 

### /min (17,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 5.7 MPa (820 psia) 538 m 3 

### /min (19,000 scfm) Suction

- 2.6 MPa (380 psia) Discharge

- 5.7 MPa (820 psia) 2 0

13 Transport Nitrogen Boost Compressor Centrifugal, single

stage 402 m 3 

### /min (14,200 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 5.6 MPa (815 psia) 510 m 3 

### /min (18,000 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 5.6 MPa (815 psia) 2 0

14 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

stage 1,535 m 3 

### /min (54,200 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 3.2 MPa (469 psia) 1,668 m 3 

### /min (58,900 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 3.2 MPa (469 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

352 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed 312,525 kg/hr (689,000 lb/hr) 35°C (95°F) 3.6 MPa (523 psia) 330,669 kg/hr (729,000 lb/hr) 35°C (95°F) 3.6 MPa (523 psia) 2 0

2 Sulfur Plant Claus type 50 tonne/day (56 tpd) 60 tonne/day (66 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 385,554 kg/hr (850,000 lb/hr) 232°C (450°F) 4.0 MPa (580 psia) 409,594 kg/hr (903,000 lb/hr) 227°C (440°F) 4.0 MPa (580 psia) 4 0

4 Shift Reactor Heat Recovery Exchangers Shell and tube Exchanger 1: 189 GJ/hr (179 MMBtu/hr) Exchanger 1: 199 GJ/hr (188 MMBtu/hr) 4 0

5 Acid Gas Removal Plant Two

- stage Selexol 318,875 kg/hr (703,000 lb/hr) 35°C (94°F) 3.5 MPa (513 psia) 337,473 kg/hr (744,000 lb/hr) 35°C (94°F) 3.5 MPa (513 psia) 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 15,194 kg/hr (33,497 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 17,341 kg/hr (38,231 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 12,854 kg/hr (28,339 lb/hr) 13,945 kg/hr (30,743 lb/hr) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

353 

### ACCOUNT 5B CO 2 

### COMPRESSION

Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 CO 2 

### Compressor Integrally geared, multi

- stage centrifugal 1,070 m 3 

### /min @ 15.3 MPa (37,800 scfm @ 2,215 psia) 1,169 m 3 

### /min @ 15.3 MPa (41,300 scfm @ 2,215 psia) 4 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 215 MW 230 MW 2 0

2 Gas Turbine Generator TEWAC 240 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

ACCOUNT 7 HRSG, DUCTING AND STACK Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.7 m (2 0 ft) diameter 76 m (250 ft) high x 8.7 m (2 0 ft) diameter 2 0

2 Heat Recovery Steam Generator Drum, multi

pressure with economizer section and integral deaerator Main steam

- 177,845 kg/hr, 12.4 MPa/533°C

(392,082 lb/hr, 1,800 psig/992°F) Reheat steam

- 251,394 kg/hr, 3.1 MPa/533°C

(554,230 lb/hr, 452 psig/992°F) Main steam

- 185,876 kg/hr, 12.4 MPa/532°C

(409,786 lb/hr, 1,800 psig/990°F) Reheat steam

- 273,486 kg/hr, 3.1 MPa/532°C

(602,934 lb/hr, 452 psig/990°F) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

354 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Steam Turbine Commercially available 214 MW 12.4 MPa/533°C/533°C (1

, 800 psig/ 992°F/992°F) 232 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 240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided waterbox including vacuum
pumps 728 GJ/hr (690 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 791 GJ/hr (750 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F) 1 0

4 Air

- cooled Condenser --- 728 GJ/hr (690 MMBtu/hr), Condensing temperature

32°C (90°F), Ambient temperature 6°C (42°F) 791 GJ/hr (750 MMBtu/hr), Condensing temperature

32°C (90°F), Ambient temperature 4°C (40°F) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

355 

### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Circulating Water Pumps Vertical, wet pit 310,404 lpm @ 30 m (82,000 gpm @ 100 ft) 336,902 lpm @ 30 m (89,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) WB / 9°C (48°F) CWT / 20°C (68°F) HWT / 1730 GJ/hr (1640 MMBtu/hr) heat duty 2°C (36°F) WB / 8°C (47°F) CWT / 19°C (67°F) HWT / 1889 GJ/hr (1790 MMBtu/hr) heat duty 1 0

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 155,202 liters (41,000 gal) 257,408 liters (68,000 gal) 3 0
2 Slag Crusher Roll 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0
3 Slag Depressurizer Proprietary 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

4 Slag Receiving Tank Horizontal, weir 94,635 liters (25,000 gal) 155,202 liters (41,000 gal) 3 0

5 Black Water Overflow Tank Shop fabricated 41,640 liters (11,000 gal) 68,137 liters (18,000 gal) 3

6 Slag Conveyor Drag chain 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

7 Slag Separation Screen Vibrating 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

8 Coarse Slag Conveyor Belt/bucket 8 tonne/hr (9 tph) 14 tonne/hr (15 tph) 3 0

9 Fine Ash Settling Tank Vertical, gravity 132,489 liters (35,000 gal) 219,554 liters (58,000 gal) 3 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

356 

### Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H 2 

### O (10 gpm @ 46 ft H 2 

### O) 76 lpm @ 14 m H 2 

### O (20 gpm @ 46 ft H 2 

### O) 3 3

11 Grey Water Storage Tank Field erected 41,640 liters (11,000 gal) 68,137 liters (18,000 gal) 3 0

12 Grey Water Pumps Centrifugal 151 lpm @ 424 m H 2 

### O (40 gpm @ 1,390 ft H 2 

### O) 265 lpm @ 424 m H 2 

### O (70 gpm @ 1,390 ft H 2 

### O) 3 3

13 Slag Storage Bin Vertical, field erected 544 tonne (600 tons) 998 tonne (1,100 tons) 3 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 172 tonne/hr (190 tph) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

357 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 240 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, 240 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 260 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 81 MVA, 3

- ph, 60 Hz 345 kV/13.8 kV, 90 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 46 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 50 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 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

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 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

358 

### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type S3B Design Condition L3B Design Condition Operating Qty Spares

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 0

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

359 

### 3.4.11 Case S3B and L3B Cost Estimating

Costs Results The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 116 shows the TPC summary organized by cost account for the PRB coal case (S3B) and Exhibit 3

- 120 shows the same information for the NDL coal case (L3B). A more detailed breakdown of the capital costs is shown in Exhibit 3

- 117 for S3B and Exhibit 3

- 121 for L3B. Exhibit 3

- 118 and Exhibit 3

- 122 show the calculation and addition of owner’s costs to determine the TOC , used to calculate COE. Exhibit 3

- 119 shows the initial and annual O&M costs for Case S3B and Exhibit 3

- 123 shows the same information for Case L3B

.
The estimated T O C of the SFG with CO 2 

### capture using PRB coal is $ 4
, 31 8 /kW and using lignite coal is $ 4
, 43 0 /kW. Process contingency represents 3 percent, project contingency represents 1 2 percent , and owner’s costs represent 18 percent of TOC in both cases. The COE is 121.7 mills/kWh in the PRB case and 123.7 mills/kWh in the lignite case.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

36 0 

### Exhibit 3

- 116 Case S3B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S3B - Siemens 445 MW IGCC w/ CO2 Plant Size: 445.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $15,911 $2,957 $12,339 $0 $0 $31,206 $2,833 $0 $6,808 $40,846 $92

2 COAL & SORBENT PREP & FEED $119,959 $9,996 $20,467 $0 $0 $150,422 $13,050 $0 $32,694 $196,166 $441

3 FEEDWATER & MISC. BOP SYSTEMS $7,393 $5,413 $7,602 $0 $0 $20,407 $1,931 $0 $5,245 $27,583 $62

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemen $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $527 4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $184,152 $0 w/equip. $0 $0 $184,152 $17,850 $0 $20,200 $222,202 $499 4.4-4.9 Other Gasification Equipment $27,994 $12,820 $17,683 $0 $0 $58,497 $5,599 $0 $13,775 $77,871 $175 SUBTOTAL 4 $324,505 $12,820 $70,168 $0 $0 $407,493 $38,095 $24,727 $64,608 $534,921 $1,201

5A GAS CLEANUP & PIPING $84,233 $2,870 $71,635 $0 $0 $158,738 $15,335 $26,220 $40,227 $240,519 $540

5B CO2 COMPRESSION $18,605 $0 $10,561 $0 $0 $29,166 $2,807 $0 $6,395 $38,368 $86

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $291 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $296

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $31,401 $0 $4,465 $0 $0 $35,866 $3,410 $0 $3,928 $43,204 $97 7.2-7.9 SCR System, Ductwork and Stack $3,524 $2,513 $3,324 $0 $0 $9,361 $868 $0 $1,666 $11,895 $27 SUBTOTAL 7 $34,925 $2,513 $7,789 $0 $0 $45,227 $4,278 $0 $5,593 $55,098 $124

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,475 $0 $3,915 $0 $0 $27,390 $2,628 $0 $3,002 $33,019 $74 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $31,839 $802 $10,004 $0 $0 $42,645 $4,160 $0 $9,426 $56,231 $126 SUBTOTAL 8 $55,314 $802 $13,919 $0 $0 $70,035 $6,788 $0 $12,428 $89,251 $200

9 COOLING WATER SYSTEM $7,844 $7,697 $6,551 $0 $0 $22,092 $2,052 $0 $4,943 $29,087 $65

10 ASH/SPENT SORBENT HANDLING SYS $21,399 $1,472 $10,612 $0 $0 $33,483 $3,213 $0 $3,974 $40,669 $91

11 ACCESSORY ELECTRIC PLANT $30,719 $12,337 $23,901 $0 $0 $66,958 $5,760 $0 $13,849 $86,566 $194

12 INSTRUMENTATION & CONTROL $10,750 $1,978 $6,926 $0 $0 $19,653 $1,781 $983 $3,735 $26,152 $59

13 IMPROVEMENTS TO SITE $3,253 $1,917 $8,026 $0 $0 $13,196 $1,303 $0 $4,350 $18,849 $42

14 BUILDINGS & STRUCTURES $0 $6,276 $7,071 $0 $0 $13,347 $1,214 $0 $2,395 $16,957 $38

TOTAL COST $826,836 $69,854 $285,041 $0 $0 $1,181,731 $109,945 $61,790 $219,583 $1,573,049 $3,533 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

361 

### Exhibit 3

- 117 Case S3B Tot al Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S3B - Siemens 445 MW IGCC w/ CO2 Plant Size: 445.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,178 $0 $2,042 $0 $0 $6,220 $557 $0 $1,355 $8,133 $18 1.2 Coal Stackout & Reclaim $5,399 $0 $1,309 $0 $0 $6,708 $588 $0 $1,459 $8,755 $20 1.3 Coal Conveyors & Yd Crush $5,020 $0 $1,295 $0 $0 $6,315 $554 $0 $1,374 $8,243 $19
1.4 Other Coal Handling $1,313 $0 $300 $0 $0 $1,613 $141 $0 $351 $2,105 $5 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $2,957 $7,393 $0 $0 $10,350 $992 $0 $2,268 $13,610 $31 SUBTOTAL 1. $15,911 $2,957 $12,339 $0 $0 $31,206 $2,833 $0 $6,808 $40,846 $92
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $48,294 $2,901 $7,037 $0 $0 $58,232 $5,025 $0 $12,651 $75,909 $170 2.2 Prepared Coal Storage & Feed $2,076 $497 $326 $0 $0 $2,899 $248 $0 $629 $3,776 $8 2.3 Dry Coal Injection System $68,331 $793 $6,346 $0 $0 $75,470 $6,500 $0 $16,394 $98,364 $221 2.4 Misc.Coal Prep & Feed $1,258 $915 $2,745 $0 $0 $4,918 $452 $0 $1,074 $6,444 $14 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $4,889 $4,014 $0 $0 $8,903 $825 $0 $1,946 $11,674 $26 SUBTOTAL 2. $119,959 $9,996 $20,467 $0 $0 $150,422 $13,050 $0 $32,694 $196,166 $441 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $1,771 $3,041 $1,605 $0 $0 $6,417 $594 $0 $1,402 $8,413 $19 3.2 Water Makeup & Pretreating $553 $58 $309 $0 $0 $919 $88 $0 $302 $1,309 $3 3.3 Other Feedwater Subsystems $969 $327 $295 $0 $0 $1,591 $143 $0 $347 $2,080 $5 3.4 Service Water Systems $316 $651 $2,260 $0 $0 $3,227 $315 $0 $1,062 $4,604 $10 3.5 Other Boiler Plant Systems $1,697 $657 $1,629 $0 $0 $3,984 $378 $0 $872 $5,234 $12 3.6 FO Supply Sys & Nat Gas $286 $541 $504 $0 $0 $1,332 $128 $0 $292 $1,752 $4 3.7 Waste Treatment Equipment $772 $0 $471 $0 $0 $1,243 $121 $0 $409 $1,774 $4 3.8 Misc. Power Plant Equipment $1,029 $138 $529 $0 $0 $1,696 $164 $0 $558 $2,417 $5 SUBTOTAL 3. $7,393 $5,413 $7,602 $0 $0 $20,407 $1,931 $0 $5,245 $27,583 $62
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemen $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $527 4.2 Syngas Cooling w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $184,152 $0 w/equip. $0 $0 $184,152 $17,850 $0 $20,200 $222,202 $499
4.4 LT Heat Recovery & FG Saturation $27,994 $0 $10,642 $0 $0 $38,636 $3,771 $0 $8,481 $50,887 $114 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,670 $680 $0 $0 $2,350 $225 $0 $515 $3,090 $7 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $11,150 $6,362 $0 $0 $17,512 $1,603 $0 $4,779 $23,894 $54 SUBTOTAL 4. $324,505 $12,820 $70,168 $0 $0 $407,493 $38,095 $24,727 $64,608 $534,921 $1,201 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

362 

### Exhibit 3

- 117 Case S3B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S3B - Siemens 445 MW IGCC w/ CO2 Plant Size: 445.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $70,593 $0 $59,900 $0 $0 $130,492 $12,620 $26,098 $33,842 $203,053 $456 5A.2 Elemental Sulfur Plant $5,067 $1,010 $6,537 $0 $0 $12,614 $1,225 $0 $2,768 $16,607 $37 5A.3 Mercury Removal $1,384 $0 $1,054 $0 $0 $2,438 $235 $122 $559 $3,354 $8 5A.4 Shift Reactors $7,189 $0 $2,894 $0 $0 $10,082 $967 $0 $2,210 $13,259 $30 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.7 Fuel Gas Piping $0 $924 $647 $0 $0 $1,572 $146 $0 $344 $2,061 $5 5A.9 HGCU Foundations $0 $936 $604 $0 $0 $1,540 $141 $0 $504 $2,185 $5 SUBTOTAL 5A. $84,233 $2,870 $71,635 $0 $0 $158,738 $15,335 $26,220 $40,227 $240,519 $540 5B CO2 COMPRESSION 5B.1 CO2 Removal System w/5A.1 $0 w/5A.1 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $18,605 $0 $10,561 $0 $0 $29,166 $2,807 $0 $6,395 $38,368 $86 SUBTOTAL 5B. $18,605 $0 $10,561 $0 $0 $29,166 $2,807 $0 $6,395 $38,368 $86
6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $291 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $296
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $31,401 $0 $4,465 $0 $0 $35,866 $3,410 $0 $3,928 $43,204 $97 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,807 $1,322 $0 $0 $3,128 $275 $0 $681 $4,083 $9
7.4 Stack $3,524 $0 $1,324 $0 $0 $4,848 $464 $0 $531 $5,844 $13 7.9 HRSG,Duct & Stack Foundations $0 $706 $678 $0 $0 $1,384 $129 $0 $454 $1,967 $4 SUBTOTAL 7. $34,925 $2,513 $7,789 $0 $0 $45,227 $4,278 $0 $5,593 $55,098 $124 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,475 $0 $3,915 $0 $0 $27,390 $2,628 $0 $3,002 $33,019 $74 8.2 Turbine Plant Auxiliaries $162 $0 $371 $0 $0 $532 $52 $0 $58 $643 $1 8.3a Condenser & Auxiliaries $2,805 $0 $896 $0 $0 $3,701 $354 $0 $405 $4,460 $10 8.3b Air Cooled Condenser $25,704 $0 $5,153 $0 $0 $30,857 $3,086 $0 $6,788 $40,731 $91 8.4 Steam Piping $3,169 $0 $2,229 $0 $0 $5,398 $464 $0 $1,465 $7,327 $16 8.9 TG Foundations $0 $802 $1,356 $0 $0 $2,157 $205 $0 $709 $3,071 $7 SUBTOTAL 8. $55,314 $802 $13,919 $0 $0 $70,035 $6,788 $0 $12,428 $89,251 $200
9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,403 $0 $983 $0 $0 $6,386 $608 $0 $1,049 $8,043 $18 9.2 Circulating Water Pumps $1,405 $0 $90 $0 $0 $1,495 $126 $0 $243 $1,864 $4 9.3 Circ.Water System Auxiliaries $122 $0 $17 $0 $0 $140 $13 $0 $23 $176 $0 9.4 Circ.Water Piping $0 $5,107 $1,324 $0 $0 $6,430 $581 $0 $1,402 $8,414 $19 9.5 Make-up Water System $311 $0 $445 $0 $0 $756 $73 $0 $166 $994 $2 9.6 Component Cooling Water Sys $603 $721 $513 $0 $0 $1,837 $172 $0 $402 $2,411 $5 9.9 Circ.Water System Foundations $0 $1,870 $3,179 $0 $0 $5,049 $479 $0 $1,658 $7,185 $16 SUBTOTAL 9. $7,844 $7,697 $6,551 $0 $0 $22,092 $2,052 $0 $4,943 $29,087 $65 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

363 

### Exhibit 3

- 117 Case S3B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S3B - Siemens 445 MW IGCC w/ CO2 Plant Size: 445.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $18,925 $0 $9,333 $0 $0 $28,258 $2,715 $0 $3,097 $34,071 $77 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $561 $0 $610 $0 $0 $1,170 $114 $0 $193 $1,477 $3 10.7 Ash Transport & Feed Equipment $752 $0 $181 $0 $0 $933 $87 $0 $153 $1,173 $3 10.8 Misc. Ash Handling Equipment $1,161 $1,423 $425 $0 $0 $3,009 $286 $0 $494 $3,790 $9 10.9 Ash/Spent Sorbent Foundation $0 $50 $62 $0 $0 $112 $11 $0 $37 $159 $0 SUBTOTAL 10. $21,399 $1,472 $10,612 $0 $0 $33,483 $3,213 $0 $3,974 $40,669 $91
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $870 $0 $861 $0 $0 $1,731 $165 $0 $190 $2,086 $5 11.2 Station Service Equipment $4,634 $0 $418 $0 $0 $5,052 $466 $0 $552 $6,069 $14 11.3 Switchgear & Motor Control $8,568 $0 $1,558 $0 $0 $10,126 $939 $0 $1,660 $12,725 $29
11.4 Conduit & Cable Tray $0 $3,980 $13,130 $0 $0 $17,110 $1,655 $0 $4,691 $23,456 $53 11.5 Wire & Cable $0 $7,604 $4,996 $0 $0 $12,601 $915 $0 $3,379 $16,895 $38 11.6 Protective Equipment $0 $611 $2,225 $0 $0 $2,837 $277 $0 $467 $3,581 $8
11.7 Standby Equipment $218 $0 $213 $0 $0 $431 $41 $0 $71 $543 $1 11.8 Main Power Transformers $16,429 $0 $130 $0 $0 $16,559 $1,252 $0 $2,672 $20,483 $46 11.9 Electrical Foundations $0 $141 $371 $0 $0 $512 $49 $0 $168 $729 $2 SUBTOTAL 11. $30,719 $12,337 $23,901 $0 $0 $66,958 $5,760 $0 $13,849 $86,566 $194
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,061 $0 $709 $0 $0 $1,770 $168 $88 $304 $2,330 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $244 $0 $156 $0 $0 $400 $38 $20 $92 $550 $1 12.7 Computer & Accessories $5,661 $0 $181 $0 $0 $5,842 $536 $292 $667 $7,337 $16 12.8 Instrument Wiring & Tubing $0 $1,978 $4,043 $0 $0 $6,020 $511 $301 $1,708 $8,540 $19 12.9 Other I & C Equipment $3,784 $0 $1,837 $0 $0 $5,621 $529 $281 $965 $7,396 $17 SUBTOTAL 12. $10,750 $1,978 $6,926 $0 $0 $19,653 $1,781 $983 $3,735 $26,152 $59 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $102 $2,181 $0 $0 $2,283 $227 $0 $753 $3,263 $7 13.2 Site Improvements $0 $1,815 $2,412 $0 $0 $4,227 $417 $0 $1,393 $6,038 $14 13.3 Site Facilities $3,253 $0 $3,432 $0 $0 $6,685 $659 $0 $2,203 $9,548 $21 SUBTOTAL 13. $3,253 $1,917 $8,026 $0 $0 $13,196 $1,303 $0 $4,350 $18,849 $42
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,038 $2,903 $0 $0 $4,940 $455 $0 $809 $6,204 $14 14.3 Administration Building $0 $859 $623 $0 $0 $1,482 $132 $0 $242 $1,856 $4
14.4 Circulation Water Pumphouse $0 $158 $84 $0 $0 $241 $21 $0 $39 $302 $1 14.5 Water Treatment Buildings $0 $462 $451 $0 $0 $912 $82 $0 $149 $1,144 $3 14.6 Machine Shop $0 $440 $301 $0 $0 $740 $66 $0 $121 $927 $2
14.7 Warehouse $0 $710 $458 $0 $0 $1,168 $103 $0 $191 $1,462 $3 14.8 Other Buildings & Structures $0 $416 $324 $0 $0 $740 $66 $0 $161 $968 $2 14.9 Waste Treating Building & Str. $0 $930 $1,778 $0 $0 $2,708 $253 $0 $592 $3,553 $8 SUBTOTAL 14. $0 $6,276 $7,071 $0 $0 $13,347 $1,214 $0 $2,395 $16,957 $38

TOTAL COST $826,836 $69,854 $285,041 $0 $0 $1,181,731 $109,945 $61,790 $219,583 $1,573,049 $3,533 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

364 

### Exhibit 3

- 118 Case S3B Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $12,933 $29 1 Month Variable O&M $3,445 $8 25% of 1 Months Fuel Cost at 100% CF $805 $2 2% of TPC $31,461 $71 Total $48,644 $109

Inventory Capital 60 day supply of consumables at 100% CF $6,932 $16 0.5% of TPC (spare parts) $7,865 $18 Total $14,797 $33

Initial Cost for Catalyst and Chemicals $6,922 $16 Land $900 $2 Other Owner's Costs $235,957 $530 Financing Costs $42,472 $95

Total Owner's Costs $349,692 $785 Total Overnight Cost (TOC) $1,922,741 $4,318 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $2,191,925 $4,922Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

365 

### Exhibit 3

- 119 Case S3B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun) 2007 Case S3B - Siemens 445 MW IGCC w/ CO2 Heat Rate-net(Btu/kWh): 11,151 MWe-net: 445 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $14.178 Maintenance Labor Cost $14,379,765 $32.293 Administrative & Support Labor $5,173,318 $11.618 Property Taxes and Insurance $31,460,972 $70.653 TOTAL FIXED OPERATING COSTS $57,327,563 $128.742 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $27,449,429 $0.00880

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 2,898 1.08 $0 $915,331 $0.00029

Chemicals

MU & WT Chem.(lbs) 0 17,265 0.17 $0 $872,524 $0.00028 Carbon (Mercury Removal) (lb) 114,477 157 1.05 $120,220 $48,088 $0.00002 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,049 4.14 498.83 $3,017,654 $603,531 $0.00019 Selexol Solution (gal) 282,412 90 13.40 $3,783,824 $351,466 $0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.76 131.27 $0 $29,144 $0.00001 Subtotal Chemicals $6,921,697 $1,904,753 $0.00061

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 157 0.42 $0 $19,098 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 587 16.23 $0 $2,781,394 $0.00089 Subtotal Waste Disposal $0 $2,800,492 $0.00090

By-products & Emissions

Sulfur (tons) 0 50 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $6,921,697 $33,070,006 $0.01060

Fuel (ton) 0 6,958 15.22 $0 $30,914,533 $0.00991Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

366 

### Exhibit 3

- 120 Case L3B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L3B - Siemens 467 MW IGCC w/ CO2 Plant Size: 466.5 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $19,450 $3,614 $15,084 $0 $0 $38,148 $3,463 $0 $8,322 $49,933 $107

2 COAL & SORBENT PREP & FEED $145,819 $12,270 $24,711 $0 $0 $182,800 $15,856 $0 $39,731 $238,387 $511

3 FEEDWATER & MISC. BOP SYSTEMS $7,616 $5,584 $7,820 $0 $0 $21,020 $1,989 $0 $5,401 $28,409 $61

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $503 4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $198,687 $0 w/equip. $0 $0 $198,687 $19,259 $0 $21,795 $239,740 $514 4.4-4.9 Other Gasification Equipment $29,196 $14,523 $19,100 $0 $0 $62,820 $6,005 $0 $14,860 $83,686 $179 SUBTOTAL 4 $340,242 $14,523 $71,585 $0 $0 $426,350 $39,910 $24,727 $67,287 $558,274 $1,197

5A Gas Cleanup & Piping $87,936 $3,020 $75,000 $0 $0 $165,956 $16,033 $27,288 $42,026 $251,303 $539

5B CO 2 REMOVAL & COMPRESSION $19,885 $0 $11,288 $0 $0 $31,173 $3,000 $0 $6,835 $41,008 $88

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $278 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $283

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,635 $0 $4,640 $0 $0 $37,275 $3,544 $0 $4,082 $44,901 $96 7.2-7.9 Ductwork and Stack $3,526 $2,514 $3,326 $0 $0 $9,366 $869 $0 $1,667 $11,901 $26 SUBTOTAL 7 $36,161 $2,514 $7,966 $0 $0 $46,641 $4,413 $0 $5,749 $56,802 $122

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $24,841 $0 $4,166 $0 $0 $29,007 $2,783 $0 $3,179 $34,969 $75 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $33,661 $849 $10,539 $0 $0 $45,049 $4,396 $0 $9,950 $59,395 $127 SUBTOTAL 8 $58,502 $849 $14,705 $0 $0 $74,056 $7,179 $0 $13,129 $94,364 $202

9 COOLING WATER SYSTEM $8,311 $8,092 $6,895 $0 $0 $23,298 $2,164 $0 $5,209 $30,671 $66

10 ASH/SPENT SORBENT HANDLING SYS $29,325 $1,943 $14,539 $0 $0 $45,807 $4,395 $0 $5,422 $55,625 $119

11 ACCESSORY ELECTRIC PLANT $32,486 $12,985 $25,133 $0 $0 $70,604 $6,071 $0 $14,599 $91,274 $196

12 INSTRUMENTATION & CONTROL $10,955 $2,015 $7,059 $0 $0 $20,029 $1,815 $1,001 $3,807 $26,653 $57

13 IMPROVEMENTS TO SITE $3,354 $1,977 $8,275 $0 $0 $13,606 $1,343 $0 $4,485 $19,434 $42

14 BUILDINGS & STRUCTURES $0 $6,418 $7,268 $0 $0 $13,685 $1,245 $0 $2,455 $17,385 $37

TOTAL COST $892,068 $76,612 $304,802 $0 $0 $1,273,481 $118,383 $62,877 $236,794 $1,691,536 $3,626 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

367 

### Exhibit 3

- 121 Case L3B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L3B - Siemens 467 MW IGCC w/ CO2 Plant Size: 466.5 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $5,108 $0 $2,496 $0 $0 $7,604 $681 $0 $1,657 $9,942 $21 1.2 Coal Stackout & Reclaim $6,600 $0 $1,600 $0 $0 $8,201 $719 $0 $1,784 $10,703 $23 1.3 Coal Conveyors & Yd Crush $6,137 $0 $1,583 $0 $0 $7,720 $678 $0 $1,680 $10,077 $22
1.4 Other Coal Handling $1,606 $0 $366 $0 $0 $1,972 $173 $0 $429 $2,573 $6 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $3,614 $9,038 $0 $0 $12,652 $1,213 $0 $2,773 $16,638 $36 SUBTOTAL 1. $19,450 $3,614 $15,084 $0 $0 $38,148 $3,463 $0 $8,322 $49,933 $107
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $59,809 $3,593 $8,715 $0 $0 $72,116 $6,223 $0 $15,668 $94,007 $202 2.2 Prepared Coal Storage & Feed $2,833 $678 $444 $0 $0 $3,955 $338 $0 $859 $5,152 $11 2.3 Dry Coal Injection System $81,811 $949 $7,598 $0 $0 $90,358 $7,782 $0 $19,628 $117,768 $252 2.4 Misc.Coal Prep & Feed $1,367 $995 $2,983 $0 $0 $5,344 $491 $0 $1,167 $7,003 $15 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $6,055 $4,971 $0 $0 $11,026 $1,021 $0 $2,409 $14,457 $31 SUBTOTAL 2. $145,819 $12,270 $24,711 $0 $0 $182,800 $15,856 $0 $39,731 $238,387 $511 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 FeedwaterSystem $1,829 $3,141 $1,658 $0 $0 $6,627 $614 $0 $1,448 $8,689 $19 3.2 Water Makeup & Pretreating $566 $59 $316 $0 $0 $942 $90 $0 $309 $1,341 $3 3.3 Other Feedwater Subsystems $1,001 $338 $304 $0 $0 $1,643 $148 $0 $358 $2,149 $5 3.4 Service Water Systems $324 $667 $2,315 $0 $0 $3,306 $323 $0 $1,089 $4,717 $10 3.5 Other Boiler Plant Systems $1,738 $674 $1,669 $0 $0 $4,081 $387 $0 $894 $5,362 $11 3.6 FO Supply Sys & Nat Gas $298 $563 $525 $0 $0 $1,385 $133 $0 $304 $1,823 $4 3.7 Waste Treatment Equipment $791 $0 $483 $0 $0 $1,274 $124 $0 $419 $1,817 $4 3.8 Misc. Power Plant Equipment $1,069 $143 $549 $0 $0 $1,761 $170 $0 $579 $2,511 $5 SUBTOTAL 3. $7,616 $5,584 $7,820 $0 $0 $21,020 $1,989 $0 $5,401 $28,409 $61
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Siemens $112,359 $0 $52,484 $0 $0 $164,843 $14,646 $24,727 $30,632 $234,848 $503 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $198,687 $0 w/equip. $0 $0 $198,687 $19,259 $0 $21,795 $239,740 $514
4.4 LT Heat Recovery & FG Saturation $29,196 $0 $11,099 $0 $0 $40,295 $3,933 $0 $8,846 $53,073 $114 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,744 $710 $0 $0 $2,454 $235 $0 $538 $3,227 $7 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $12,779 $7,292 $0 $0 $20,071 $1,837 $0 $5,477 $27,385 $59 SUBTOTAL 4. $340,242 $14,523 $71,585 $0 $0 $426,350 $39,910 $24,727 $67,287 $558,274 $1,197 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

368 

### Exhibit 3

- 121 Case L3B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L3B - Siemens 467 MW IGCC w/ CO2 Plant Size: 466.5 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $73,469 $0 $62,340 $0 $0 $135,809 $13,134 $27,162 $35,221 $211,325 $453 5A.2 Elemental Sulfur Plant $5,695 $1,135 $7,347 $0 $0 $14,177 $1,377 $0 $3,111 $18,665 $40 5A.3 Mercury Removal $1,435 $0 $1,092 $0 $0 $2,527 $244 $126 $579 $3,476 $7 5A.4 Shift Reactors $7,337 $0 $2,953 $0 $0 $10,291 $987 $0 $2,255 $13,533 $29 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.7 Fuel Gas Piping $0 $937 $656 $0 $0 $1,593 $148 $0 $348 $2,089 $4 5A.9 HGCU Foundations $0 $949 $612 $0 $0 $1,560 $143 $0 $511 $2,215 $5 SUBTOTAL 5A. $87,936 $3,020 $75,000 $0 $0 $165,956 $16,033 $27,288 $42,026 $251,303 $539 5B CO2 COMPRESSION 5B.1 CO2 Removal System (w/5A.1) w/5A.1 $0 w/5A.1 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $19,885 $0 $11,288 $0 $0 $31,173 $3,000 $0 $6,835 $41,008 $88 SUBTOTAL 5B. $19,885 $0 $11,288 $0 $0 $31,173 $3,000 $0 $6,835 $41,008 $88
6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $278 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $283
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,635 $0 $4,640 $0 $0 $37,275 $3,544 $0 $4,082 $44,901 $96 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,808 $1,322 $0 $0 $3,130 $275 $0 $681 $4,086 $9
7.4 Stack $3,526 $0 $1,325 $0 $0 $4,851 $465 $0 $532 $5,847 $13 7.9 HRSG,Duct & Stack Foundations $0 $706 $679 $0 $0 $1,385 $129 $0 $454 $1,968 $4 SUBTOTAL 7. $36,161 $2,514 $7,966 $0 $0 $46,641 $4,413 $0 $5,749 $56,802 $122 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $24,841 $0 $4,166 $0 $0 $29,007 $2,783 $0 $3,179 $34,969 $75 8.2 Turbine Plant Auxiliaries $171 $0 $392 $0 $0 $563 $55 $0 $62 $680 $1 8.3a Condenser & Auxiliaries $2,973 $0 $950 $0 $0 $3,923 $375 $0 $430 $4,728 $10 8.3b Air Cooled Condenser $27,249 $0 $5,463 $0 $0 $32,711 $3,271 $0 $7,197 $43,179 $93 8.4 Steam Piping $3,268 $0 $2,299 $0 $0 $5,567 $478 $0 $1,511 $7,557 $16 8.9 TG Foundations $0 $849 $1,435 $0 $0 $2,284 $216 $0 $750 $3,250 $7 SUBTOTAL 8. $58,502 $849 $14,705 $0 $0 $74,056 $7,179 $0 $13,129 $94,364 $202
9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,744 $0 $1,045 $0 $0 $6,789 $646 $0 $1,115 $8,551 $18 9.2 Circulating Water Pumps $1,488 $0 $98 $0 $0 $1,586 $134 $0 $258 $1,977 $4 9.3 Circ.Water System Auxiliaries $129 $0 $18 $0 $0 $147 $14 $0 $24 $185 $0 9.4 Circ.Water Piping $0 $5,364 $1,391 $0 $0 $6,754 $610 $0 $1,473 $8,838 $19 9.5 Make-up Water System $318 $0 $454 $0 $0 $772 $74 $0 $169 $1,015 $2 9.6 Component Cooling Water Sys $633 $757 $539 $0 $0 $1,929 $181 $0 $422 $2,532 $5 9.9 Circ.Water System Foundations $0 $1,971 $3,350 $0 $0 $5,321 $504 $0 $1,748 $7,573 $16 SUBTOTAL 9. $8,311 $8,092 $6,895 $0 $0 $23,298 $2,164 $0 $5,209 $30,671 $66 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

369 

### Exhibit 3

- 121 Case L3B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case L3B - Siemens 467 MW IGCC w/ CO2 Plant Size: 466.5 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $26,061 $0 $12,852 $0 $0 $38,912 $3,739 $0 $4,265 $46,916 $101 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $740 $0 $805 $0 $0 $1,545 $150 $0 $254 $1,949 $4 10.7 Ash Transport & Feed Equipment $992 $0 $239 $0 $0 $1,232 $115 $0 $202 $1,548 $3 10.8 Misc. Ash Handling Equipment $1,532 $1,878 $561 $0 $0 $3,971 $378 $0 $652 $5,001 $11 10.9 Ash/Spent Sorbent Foundation $0 $65 $82 $0 $0 $148 $14 $0 $48 $210 $0 SUBTOTAL 10. $29,325 $1,943 $14,539 $0 $0 $45,807 $4,395 $0 $5,422 $55,625 $119
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $904 $0 $894 $0 $0 $1,797 $172 $0 $197 $2,166 $5 11.2 Station Service Equipment $4,879 $0 $440 $0 $0 $5,319 $490 $0 $581 $6,390 $14 11.3 Switchgear & Motor Control $9,020 $0 $1,640 $0 $0 $10,661 $989 $0 $1,747 $13,397 $29
11.4 Conduit & Cable Tray $0 $4,190 $13,823 $0 $0 $18,014 $1,742 $0 $4,939 $24,695 $53 11.5 Wire & Cable $0 $8,006 $5,260 $0 $0 $13,267 $964 $0 $3,558 $17,788 $38 11.6 Protective Equipment $0 $641 $2,332 $0 $0 $2,973 $290 $0 $490 $3,753 $8
11.7 Standby Equipment $225 $0 $219 $0 $0 $444 $42 $0 $73 $559 $1 11.8 Main Power Transformers $17,458 $0 $136 $0 $0 $17,594 $1,330 $0 $2,839 $21,763 $47 11.9 Electrical Foundations $0 $148 $388 $0 $0 $535 $51 $0 $176 $763 $2 SUBTOTAL 11. $32,486 $12,985 $25,133 $0 $0 $70,604 $6,071 $0 $14,599 $91,274 $196
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,081 $0 $722 $0 $0 $1,804 $171 $90 $310 $2,374 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $249 $0 $159 $0 $0 $408 $39 $20 $93 $560 $1 12.7 Computer & Accessories $5,769 $0 $185 $0 $0 $5,954 $546 $298 $680 $7,478 $16 12.8 Instrument Wiring & Tubing $0 $2,015 $4,120 $0 $0 $6,135 $520 $307 $1,741 $8,703 $19 12.9 Other I & C Equipment $3,856 $0 $1,873 $0 $0 $5,729 $539 $286 $983 $7,538 $16 SUBTOTAL 12. $10,955 $2,015 $7,059 $0 $0 $20,029 $1,815 $1,001 $3,807 $26,653 $57 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $105 $2,249 $0 $0 $2,354 $234 $0 $776 $3,364 $7 13.2 Site Improvements $0 $1,872 $2,487 $0 $0 $4,359 $430 $0 $1,437 $6,225 $13 13.3 Site Facilities $3,354 $0 $3,539 $0 $0 $6,893 $680 $0 $2,272 $9,844 $21 SUBTOTAL 13. $3,354 $1,977 $8,275 $0 $0 $13,606 $1,343 $0 $4,485 $19,434 $42
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,135 $3,042 $0 $0 $5,177 $476 $0 $848 $6,501 $14 14.3 Administration Building $0 $859 $623 $0 $0 $1,482 $132 $0 $242 $1,856 $4
14.4 Circulation Water Pumphouse $0 $161 $85 $0 $0 $247 $22 $0 $40 $308 $1 14.5 Water Treatment Buildings $0 $473 $462 $0 $0 $935 $84 $0 $153 $1,172 $3 14.6 Machine Shop $0 $440 $301 $0 $0 $740 $66 $0 $121 $927 $2
14.7 Warehouse $0 $710 $458 $0 $0 $1,168 $103 $0 $191 $1,462 $3 14.8 Other Buildings & Structures $0 $425 $331 $0 $0 $756 $68 $0 $165 $988 $2 14.9 Waste Treating Building & Str. $0 $950 $1,816 $0 $0 $2,766 $258 $0 $605 $3,629 $8 SUBTOTAL 14. $0 $6,418 $7,268 $0 $0 $13,685 $1,245 $0 $2,455 $17,385 $37

TOTAL COST $892,068 $76,612 $304,802 $0 $0 $1,273,481 $118,383 $62,877 $236,794 $1,691,536 $3,626 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

370 

### Exhibit 3

- 122 Case L3B Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $13,411 $29 1 Month Variable O&M $3,766 $8 25% of 1 Months Fuel Cost at 100% CF $799 $2 2% of TPC $33,831 $73 Total $51,807 $111

Inventory Capital 60 day supply of consumables at 100% CF $6,910 $15 0.5% of TPC (spare parts) $8,458 $18 Total $15,368 $33

Initial Cost for Catalyst and Chemicals $7,452 $16 Land $900 $2 Other Owner's Costs $253,730 $544 Financing Costs $45,671 $98

Total Owner's Costs $374,928 $804 Total Overnight Cost (TOC) $2,066,464 $4,430 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $2,355,769 $5,050Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

371 

### Exhibit 3

- 123 Case L3B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case L3B - Siemens 467 MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 11,371 MWe-net: 467 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $13.533 Maintenance Labor Cost $15,143,762 $32.462 Administrative & Support Labor $5,364,317 $11.499 Property Taxes and Insurance $33,830,718 $72.519 TOTAL FIXED OPERATING COSTS $60,652,304 $130.013 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $28,595,428 $0.00875

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 2,999 1.08 $0 $947,169 $0.00029

Chemicals

MU & WT Chem. (lb) 0 17,866 0.17 $0 $902,873 $0.00028 Carbon (Mercury Removal) (lb) 120,179 165 1.05 $126,208 $50,483 $0.00002 COS Catalyst (lb) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,395 4.38 498.83 $3,190,190 $638,038 $0.00020 Selexol Solution (gal) 308,653 98 13.40 $4,135,407 $384,552 $0.00012 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.89 131.27 $0 $34,196 $0.00001 Subtotal Chemicals $7,451,805 $2,010,143 $0.00061

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 165 0.42 $0 $20,050 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 968 16.23 $0 $4,585,247 $0.00140 Subtotal Waste Disposal $0 $4,605,296 $0.00141

By-products & Emissions

Sulfur (tons) 0 60 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,451,805 $36,158,036 $0.01106

Fuel (ton) 0 9,620 10.92 $0 $30,672,715 $0.00938Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

372 

### 3.5 COP E

- GAS TM IGCC CASES

This section contains an evaluation of plant designs for Cases S4A and S4B

, which are based on the E

- GasTM gasifier, developed by CoP. The non

- capture (A) and CO 2 

### capture (B) cases are very similar in terms of process, equipment, scope and arrangement, except that CO 2 

### capture cases includes SGS reactors, CO 2 

### absorption/regenerati on and compression/transport systems

.
Section 3.5.4 covers the results for the S4A non

- capture case using PRB coal and Section 3.5.8 covers the S4B CO 2 

### - capture case using PRB coal. The sections are organized analogously as follows:

**•** Process and System Description provides an overview of the specific technolog y’s operation.

**•** BF D and stream table display results for major processes and streams

**•** Performance Results provides the main modeling results, including the performance summary, environmental performance, carbon balance, sulfur balance, water balance, mass and energy balance diagrams

, and mass and energy balance tables.

**•** Equipment List provides an itemiz ed list of major equipment with account codes that correspond to the cost accounts in the Cost Estimates section.

**•** Cost Estimates provides a summary of capital and operating costs.

Process and System Description, Performance Results, Equipment List and Cost Estimates are repeated for Case S4B in Section 3.5.8 . If the information is identical to that presented for the

non

- capture cases, a reference is made to the ear lier section rather than repeating the information.

3.5.1 Gasifier Background

Development and Current Status

– The CoP E

- GasTM technology was first developed by Dow Chemical (the former principal stockholder of Destec Energy, which was bought by Global Energy, In c., the gasifier business that was later purchased by CoP ) who is a major producer of chemicals. They began coal gasification development work in 1976 with bench

- scale (2 kg/h r [4 lb/h r ]) reactor testing. Important fundamental data were obtained for conv ersion and yields with various coals and operating conditions. This work led to the construction of a pilot plant at Dow’s large chemical complex in Plaquemine, Louisiana. The pilot plant was designed for a capacity of 11 tonnes/day (12 tpd ) (dry lignite basis) and was principally operated with air as the oxidant. The plant also operated with oxygen at an increased capacity of 33 tonnes/day (36 tpd ) (dry lignite basis). This pilot plant operated from 1978 through 1983.

Following successful operation of the pilot plant, Dow built a larger 499 tonnes/day (550 tpd ) (dry lignite basis) gasifier at Plaquemine. In 1984, Dow Chemical and the U.S. Synthetic Fuels Corporation (SFC) announced a price guarantee contract

, which allowed the building of the first

com mercial

- scale Dow coal gasification unit. The Louisiana Gasification Technology, Inc. (LGTI) plant, sometimes called the Dow Syngas Project, was also located in the DowCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

373 

### Plaquemine chemical complex. The plant gasified about 1,451 tonnes/day (1,600 tpd ) (d ry basis) of subbituminous coal to generate 184 MW (gross) of combined

- cycle electricity utilizing a Westinghouse D

- Class CT

. . To ensure continuous power output to the petrochemical complex, a minimum of 20 percent of natural gas was co

- fired with the syn gas. LGTI was operated from 1987 through 1995.

In September 1991, DOE selected the Wabash River coal gasification repowering project, which used the Destec Energy process, for funding under the Clean Coal Technology Demonstration Program. The project wa s a joint venture of Destec and Public Service of Indiana (PSI Energy, Inc.). Its purpose was to repower a unit at PSI’s Wabash River station in West Terre Haute, Indiana to produce 265 MW of net power from local high

- sulfur bituminous coal. The design o f the project gasifier was based on the Destec LGTI gasifier. Experience gained in that project provided significant input to the design of the Wabash River coal gasification facility and eliminated much of the risk associated with scale

- up and process

va riables.

Gasifier Capacity

– The daily coal

- handling capacity of the E

GasTM gasifier operating at Plaquemine was in the range of 1,270 tonnes (1,400 tons) (moisture/ash

- free [MAF] basis) for bituminous coal to 1,497 tonnes (1,650 tons) for lignite. The dry gas production rate was 141,600 Nm 3 

### /h r (5 million scf/h r ) with an energy content of about 1,370 MMkJ/h r (1,300 MMBtu/h r ) (HHV). The daily coal

- handling capacity of the gasifier at Wabash River is about 1,6 80 tonnes (1,850 tons) (MAF basis) for high

- su lfur bituminous coal. The dry gas production rate is about 189,72 0 Nm 3 

### /h r (6.7 million scf/h r ) with an energy content of about 1,950 MMkJ/h r (1,850 MMBtu/h r ) (HHV). This size matches the CT , which is a GE 7FA.

Gasifier sizing for this study was limited, per CoP recommendation, to 130 percent of the Wabash gasifier, as the maximum scale

- up for a demonstrated commercial design resulting in a maximum gasifier throughput of around 4,000 tpd of as

- received coal, depending on the feedstock, resulting in 2 gasif ier trains for both cases.

Distinguishing Characteristics

- The CoP E

- GasTM gasifier is a slurry feed, entrained flow, slagging, two

- stage gasifier producing syngas at high pressures and high temperatures, which is quenched using a coal slurry, offering add itional operational flexibility and the ability to tune the gasifier for different applications. Slurry feed of the coal eliminates the need to dry the coal and simplifies the feed system for the coal. The gasifier portion of the reactor is refractory li ned, requiring periodic maintenance . The fire

- tube SGC used by E

- GasTM has a lower capital cost than a water

- tube design.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

374 

### Relative disadvantages of the CoP coal gasification technology are the relatively short refractory life and the high waste heat reco very (SGC) duty, as with the other entrained

- flow slagging gasifiers. These disadvantages result from high operating temperature although the syngas exits the gasifier at lower temperatures compared to dry feed gasifiers due to the slurry quench. The
upp er stage slurry quench helps to increase the calorific value of the resulting syngas and the gasifier CGE, which results in a quenched syngas that is higher in methane (CH 4 

### ) content than other dry feed gasifiers. Special gasifier tuning by the vendor can adjust the composition of the syngas to achieve the desired end application, be it power or chemicals production, optimized towards high efficiency or low methane for carbon removal. Although high efficiency is generally desired, the associated high metha ne content will require a tradeoff in order to capture 90 percent of the overall carbon since the AGR process does not capture the carbon from the methane in the syngas.

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 characteristics for use in the E

- GasTM coal gasification process. High ash levels increase the ratio of water to carbon in the coal in the feed slurr y, thereby increasing the oxygen requirements. Soluble salts affect the processing cost and amount of water blowdown required to avoid problems associated with excessive buildup of salts in the slurry water recycle loop.

An advantage of the CoP coal gasification technology is the current operating experience with subbituminous coal at full commercial scale at the Plaquemine plant and bituminous coal at the Wabash plant. Bituminous coals with lower inherent moisture improve the slurry concentration

an d reduce oxygen requirements. The two

- stage operation reduces the negative impact of low

rank coal use in slurry feed, entrained

- flow gasification. Low to moderate ash fusion

temperature coals are preferred for slagging gasifiers. Coals with high ash fu sion temperatures may require flux addition for optimal gasification operation.

3.5.2 Key System Assumptions

System assumptions for Cases S4A and S4B CoP E

- Gas TM IGCC using PRB coal, with and without CO 2 

### capture, are compiled in Exhibit 3

- 12 4

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

375 

### Exhibit 3

- 124 Case S4A and S4B Plant Study Configuration Matrix

Case S4A S4B Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O 2 

### :Coal Ratio, kg O 2 

### /kg dry coal 0. 907 0.91 7 Carbon Conversion, % 99.1 99.1 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

### (Btu/scf) 6, 027 ( 162 ) 5, 878 (15 8 )

Nominal Steam Cycle, MPa/°C/°C (psig/ **°** F/ **°** F) 12.4/566/566 (1,800/1,050/1,050) 12.4/538/538 (1,800/1,000/1,000) Condenser Pressure, mm Hg (in Hg) 36 (1.4) 36 (1.4)

Combustion Turbine 2x Advanced F Class (Nominal 232 MW output each, reduced by elevation considerations) 2x Advanced F Class (Nominal 232 MW output each, reduced by elevation considerations)

Gasifier Technology CoP E

- GasTM CoP E

- GasTM
Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Subbituminous Subbituminous Coal Slurry Solids Content, % 50 49 COS Hydrolysis Yes Yes (Part of WGS)

Water Gas Shift No Yes

H 2 

### S Separation MDEA Selexol (1 st 

### Stage)

Sulfur Removal, % 99. 9 99.8

CO 2 

### Separation None Selexol (2 nd 

### Stage)

CO 2 

### Removal, % N/A 90

Sulfur Recovery Claus Plant with Tail Gas Treatment / Elemental Sulfur Claus Plant with Tail Gas Treatment / Elemental Sulfur

Particulate Control Cyclone, Candle Filter, and AGR Absorber Cyclone, Candle Filter, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB) and N 2 

### Dilution MNQC (LNB) and N 2 

### DilutionCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

376 

### Balance of Plant

– All Cases The balance of plant assumptions are common to all cases and are presented in Exhibit 3

- 125

.

Exhibit 3

- 125 Balance of Plant Assumptions
Cooling water system Recirculating Wet Cooling Tower Fuel and Other storage Coal 30 days Slag 30 days Sulfur 30 days Sorbent 30 days Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt

Motors between 250 hp and 5,000 hp 4,160 volt
Motors above 5,000 hp 13,800 volt Steam and CT Generators 24,000 volt Grid Interconnection Voltage 345 kV Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW and 50 percent from groundwater, and is assumed to be in sufficient quantities to meet plant makeup requirements. Makeup for potable, process, and DI water is drawn from municipal sources

Process Wastewater Water associated with gasification activity and storm water that contacts equipment surfaces is collected and treated for discharge through a permitted discharge.

Sanitary Waste Disposal Design includes a packaged domestic sewage treatment plant with effluent discharged to the industrial wastewater treatment system. Sludge is hauled off site. Packaged plant was sized for 5.68 cubic meters per day (1,500 GPD )

Water Discharge Most of the process wastewater is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and disc harged.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

377 

### 3.5.3 Sparing Philosophy

The sparing philosophy for Cases S4A and S4B is provided below. Single trains are utilized throughout with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment.

The plant design consists of the following major subsystems:

**•** Two ASU s (2 x 50%).

**•** Two trains of coal drying and dry feed systems (2 x 50%).

**•** Two trains of gasification, including gasifier, SGC , cyclone, and barrier filter (2 x 50%).

**•** Two trains of syngas clean

- up process (2 x 50%).

**•** Two trains of MDEA acid gas removal in non

- capture cases and two trains of two

- stage Selexol in CO 2 

### capture cases (2 x 50%).

**•** One train of Claus

- based sulfur recovery (1 x 100%).

**•** Two CT /HRSG tandems (2 x 50%).

**•** One steam turbine (1 x 100%).

3.5.4 CoP E

- Gas TM IGCC Non

- Capture Case (S4A) Process Description

In this section the overall CoP E

- Gas TM gasification process for Case S4A is described. The system description follows the BFD in Exhibit 3

- 126 . The tables in Exhibit 3

- 127 provide process data for the numbered streams in the BFD for the PRB case (S4A). Coal Preparation and Feed Systems Coal receiving and handling is common to all cases and generally described in Section 3.1.1

. For the CoP E

- GasTM slurry fed gasifier, c oal from the coal silo is fed onto a conveyor by vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor that de livers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of about two hours 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 proce ss 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 trammel screen into the rod mill discharge tank, and then the slurry is pumped to the slurry storage tanks. The coal is prepared into a slurry with approximately 50 percent solids and is injected in both the oxidizing and reducing portions of the E

- G as TM gasifier, referred to as the full slurry quench, tuned by CoP to achieve high CGE

. 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 localCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

378 

### environmental r egulations. All of the tanks are equipped with vertical agitators to keep the coal slurry solids suspended. The equipment in the coal grinding and slurry preparation 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 polyethylene (HDPE).

Gasifier

The CoP E

- GasTM gasifier is a two

- stage, entrained

- flow, slurr y

- fed gasifier

. The coal is fed to the gasifier as in the full slurry quench configuration, maximizing CGE . The slurry feed and quench configuration removes the need for coal drying and also causes lower syngas exit temperatures compared to dry feed gasi fiers. Oxygen injection is scaled from the coal feed resulting in a gasifier exit temperature of around 1,900 o 

### F. Roughly 20 percent of the cleaned syngas is recycled to the gasifier to moderate the temperature and aid in transport. The predicted
raw gas composition and gasifier performance is based on published data and was refined with specific vendor quotes by adjusting the gasification reaction’s equilibrium approach temperatures.

The two parallel CoP E

- GasTM gasifiers operate at 4.2 MPa (6 15 psia) and process a total of 7,144 tonne/day (7,875 tpd) of as

- received PRB. The oxygen is used to gasify a portion of the slurry in the horizontal cylinder portion with two horizontally opposed burners. The highly exothermic gasification/oxidation reactions take place rapidly at high temperatures of 1,316 to 1,427°C (2,400 to 2,600 **°** F). The hot raw gas from the first stage enters the second (top) stage, which is a vertical cylinder perpendicular to the first stage. The remaining coal slurry is injected into this hot raw gas. The endothermic gasification/dev olatilization reaction in this stage reduces the final gas temperature to about 1,038°C (1,900 **°** F). Raw Gas Cooling/Particulate Removal High

- temperature heat recovery in each gasifier train is performed by raw gas coolers in three sections, a superheater, an evaporator, and an economizer, which lower the raw gas temperature from 1,038°C (1,900°F) to 337°C (638°F). After passing through the raw gas coolers, the syngas passes through a cyclone and a raw gas candle filter where a majority of the fine particl es are removed and returned to the gasifier using recycled syngas. The filter consists of an array of ceramic candle elements in a pressure vessel. Fines produced by the gasification system are recirculated to extinction. The ash that is not carried out with the gas forms slag and exits the gasifier in liquid form. The slag is solidified in a quench tank for disposal. Sour Water Stripper Water condensed during the cooling of the raw gas, along with all other sour water from the plant are sent to the so ur water stripper, which removes NH 3 

### , SO 2 

### , and other impurities from the waste stream. The sour gas stripper consists of a sour drum that accumulates sour water that flows to the sour stripper, which consists of a packed column with a steam

- heated reboile r. Sour gas is stripped from the liquid and sent to the SRU . Remaining water is sent to wastewater
treatment.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

379 

### COS Hydrolysis, Mercury Removal and AGR

H 2 

### S and COS are at significant concentrations, requiring removal for the power plant to achieve the low design level of SO 2 

### emissions. H 2 

### S is removed in an AGR process; however, because COS is not readily removed, it is first catalytically converted to H 2 

### S in a COS hydrolysis unit.

The cooled raw gas is fed to the COS hydrolysis reactor where the COS in th e sour gas is hydrolyzed with steam, over a catalyst bed, into H 2 

### S, which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the AGR process, it must be cooled to about 35 **°** C ( 95 **°** F). During this cooling through a series o f heat exchangers, part of the water vapor condenses. This water, which contains some NH 3 

### , is sent to the sour water stripper. The cooled syngas then passes through a carbon bed to remove 95 percent of the Hg.

Cool, particulate

- free synthesis gas enters the MDEA absorber unit at approximately 3.7 MPa (535 psia) and 35°C (95°F). This AGR system was ch osen to mimic the current Wabash CoP E

GasTM IGCC installation, as a proven commercial offering. In the absorber, H 2 

### S is preferentially removed from the fuel gas stream by contact with MDEA. The stripper acid gas stream, consisting of 7 percent H 2 

### S and 91 percent CO 2 

### , is sent to the Claus unit. The acid gas is combined with the sour water stripper off gas and introduced into the Claus plant burner section.

C laus Unit

The SRU is a Claus bypass type SRU utilizing oxygen instead of air. The Claus plant produces molten sulfur by converting approximately one third of the H 2 

### S in the feed to SO 2 

### , then reacting the H 2 

### S and SO 2 

### to sulfur and water. The combination of Claus technology and tail gas recycle results in an overall sulfur recovery exceeding 99 percent , producing 52 tonne/day (57 tpd) of sulfur

. Utilizing oxygen instead of air in the Claus plant reduces the overall co st of the sulfur recovery plant. Feed for each case consists of acid gas from both the acid gas cleanup unit and a vent stream from the sour water stripper in the gasifier section.

In the furnace waste heat boiler steam is generated. This steam is used t o satisfy all Claus process preheating and reheating requirements

, as well as to provide some steam to the medium

pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header.

Power Block Clean syngas exiting the MDEA absorber is reheated, diluted with nitrogen from the ASU, and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and a portion of the air requirements for the ASU. The exhaust gas exits the CT at 586°C (1, 087°F) and enters the HRSG where additional heat is recovered until the flue gas exits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam generated in the HRSG is used to power a steam turbine using a nominal 12.4 MPa/566°C/566 °C (1800 psig/1050°F/1050°F) steam cycle. Air Separation Unit

The ASU is de signed to produce approximately 5,212 tonne/day (5,746 tpd) of 95 mole percent O 2 

### for use in the gasifier and SRU . The plant is designed with two production trains. The airCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

380 

### compre ssor is powered by an electric motor. N itrogen is also recovered, compressed, and used as dilution in the CT combustor or as a coal transport fluid. Air extraction is taken from the CT compressor to reduce the size of the main air compressor.

Balance of Plant Balance of plant items were covered in Sections 3.1.12
, 3.1.13
, 3.1.14
, and 3.1.15

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

381 

### Exhibit 3

- 126 Case S4A Process Flow DiagramCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

382 

### Exhibit 3

- 127 Case S4A Stream Ta ble

1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0093 0.0094 0.0052 0.0319 0.0021 0.0360 0.0000 0.0000 0.0000 0.0114 0.0000 0.0082 0.0080 0.0080
CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0161 0.0000 0.0116 0.0113 0.0113
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3235 0.0000 0.2329 0.2264 0.2264
CO 2 0.0003 0.0003 0.0010 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2450 0.0000 0.1765 0.1717 0.1717
COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0001 0.0001 0.0000
H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2625 0.3080 0.0000 0.2217 0.2156 0.2156

H 2 O 0.0064 0.0104 0.0211 0.0000 0.0002 0.0000 0.0000 0.9973 0.6778 0.0833 0.0000 0.3381 0.3563 0.3562

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0031 0.0000 0.0022 0.0022 0.0022

N 2 0.7759 0.7722 0.9429 0.0178 0.9927 0.0140 0.0000 0.0000 0.0040 0.0048 0.0000 0.0035 0.0034 0.0034

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0027 0.0012 0.0048 0.0000 0.0053 0.0051 0.0051
O 2 0.2081 0.2077 0.0297 0.9503 0.0049 0.9500 0.0000 0.0000 0.0544 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 1.0000 0.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 26,378 6,059 10,801 97 14,950 6,641 0 8,671 19,040 1,582 0 31,402 30,031 30,031 V-L Flowrate (kg/hr) 762,198 174,817 302,410 3,137 419,453 214,047 0 156,182 278,273 36,401 0 678,578 645,989 645,989 Solids Flowrate (kg/hr) 0 0 0 0 0 0 297,660 0 175,569 0 25,712 0 0 0

Temperature (°C) 6 411 15 32 93 32 6 171 149 174 1,038 1,023 232 232 Pressure (MPa, abs) 0.09 1.43 0.11 0.86 2.65 0.86 0.09 5.10 5.10 5.52 4.24 4.24 4.07 4.00 Enthalpy (kJ/kg) A 15.26 441.49 33.48 26.67 92.33 26.59

--- 674.86

--- 394.70

--- 2,466.99 1,081.69 1,081.63 Density (kg/m 3 ) 1.1 7.2 1.3 11.0 24.4 11.0

--- 836.6

--- 34.2

--- 8.4 21.3 21.0 V-L Molecular Weight 28.895 28.854 27.999 32.181 28.056 32.229

--- 18.013

--- 23.005

--- 21.610 21.511 21.511

V-L Flowrate (lb mol /hr) 58,154 13,357 23,812 215 32,960 14,642 0 19,116 41,975 3,488 0 69,229 66,208 66,208 V-L Flowrate (lb/hr) 1,680,359 385,406 666,700 6,915 924,735 471,894 0 344,323 613,487 80,251 0 1,496,009 1,424,161 1,424,161 Solids Flowrate (lb/hr) 0 0 0 0 0 0 656,228 0 387,064 0 56,686 0 0 0

Temperature (°F) 42 771 58 90 199 90 42 340 300 345 1,900 1,873 450 450 Pressure (psia) 13.0 207.6 16.4 125.0 384.0 125.0 13.0 740.0 740.0 800.0 614.7 614.7 589.7 579.7 Enthalpy (Btu/lb) A 6.6 189.8 14.4 11.5 39.7 11.4

--- 290.1

--- 169.7

--- 1,060.6 465.0 465.0 Density (lb/ft 3 ) 0.070 0.451 0.083 0.687 1.522 0.688

--- 52.227

--- 2.133

--- 0.527 1.331 1.309 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

383 

### Exhibit 3

- 127 Case S4A Stream Table (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 V-L Mole Fraction

Ar 0.0124 0.0120 0.0037 0.0002 0.0000 0.0031 0.0126 0.0126 0.0093 0.0094 0.0094 0.0000 0.0000 0.0000 0.0000
CH 4 0.0176 0.0167 0.0000 0.0005 0.0000 0.0002 0.0175 0.0175 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 0.3541 0.3357 0.0057 0.0045 0.0000 0.0494 0.3529 0.3529 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.2686 0.2993 0.8515 0.9102 0.0000 0.6630 0.2676 0.2676 0.0003 0.1008 0.1008 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000
H 2 0.3371 0.3229 0.0670 0.0047 0.0000 0.0118 0.3394 0.3394 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0014 0.0015 0.0019 0.0029 0.0000 0.2142 0.0014 0.0014 0.0064 0.0642 0.0642 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0035 0.0034 0.0013 0.0682 0.0000 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0053 0.0086 0.0689 0.0088 0.0000 0.0573 0.0086 0.0086 0.7759 0.7238 0.7238 0.0000 0.0000 0.0000 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 0.0000 0.0000 0.0000
O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2081 0.1018 0.1018 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 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 0.0000 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) 19,206 20,274 1,068 1,000 0 1,285 19,274 19,274 100,835 122,337 122,337 40,099 22,058 22,058 44,671 V-L Flowrate (kg/hr) 451,111 493,753 42,642 42,828 0 46,542 450,925 450,925 2,913,623 3,609,183 3,609,183 722,401 397,375 397,375 804,761 Solids Flowrate (kg/hr) 0 0 0 0 2,163 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 35 33 38 51 174 232 51 196 6 594 131 566 32 32 33 Pressure (MPa, abs) 3.82 3.76 5.51 0.4 0.370 0.335 3.597 3.563 0.090 0.093 0.090 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A 34.80 30.60 -13.86 43.7

--- 508.895 58.933 268.577 15.260 745.200 233.099 3,513.669 2,304.786 2,304.786 139.823 Density (kg/m 3 ) 35.8 36.8 109.0 6.7

--- 2.9 31.6 21.2 1.1 0.4 0.8 34.9 0.04 0.04 995.0 V-L Molecular Weight 23.489 24.355 39.927 43

--- 36.231 23.396 23.396 28.895 29.502 29.502 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 42,341 44,696 2,354 2,204 0 2,832 42,491 42,491 222,302 269,707 269,707 88,404 48,629 48,629 98,483 V-L Flowrate (lb/hr) 994,530 1,088,539 94,008 94,420 0 102,608 994,119 994,119 6,423,439 7,956,887 7,956,887 1,592,622 876,061 876,061 1,774,195 Solids Flowrate (lb/hr) 0 0 0 0 4,769 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 95 92 100 124 345 450 124 385 42 1,100 268 1,050 90 90 92 Pressure (psia) 554.7 544.7 799.5 60.0 53.6 48.6 521.7 516.7 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A 15.0 13.2 -6.0 18.8

--- 218.8 25.3 115.5 6.6 320.4 100.2 1,510.6 990.9 990.9 60.1 Density (lb/ft 3 ) 2.234 2.298 6.807 0

--- 0.181 1.975 1.324 0.070 0.024 0.051 2.176 0.002 0.002 62.119Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

384 

### 3.5.5 Case S4A Performance Results

The non

- capture CoP E

- GasTM IGCC plant using PRB coal at the Montana site (elevation 3,400 ft) produces a net output of 605 MWe at a net plant efficiency of 36. 7 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3

- 128
, which includes auxiliary power requirements. The ASU accounts for approximately 78 percent of the total auxiliary load, distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU au xiliaries. The cooling water system, including the CWP s and cooling tower fan, and the air

- cooled condenser account for about 7 percent of the auxiliary load, and the BFW pumps account for an additional 3 percent. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

385 

### Exhibit 3

- 128 Case S4A Plant Performance Summary
POWER SUMMARY (Gross Power at Generator Terminals, kWe) S 4A

Gas Turbine Power 416,400 Steam Turbine Power 321,900 TOTAL POWER, kWe 738,300 AUXILIARY LOAD SUMMARY, kWe Coal Handling 550 Coal Milling 3,060 Sour Water Recycle Slurry Pump 290 Slag Handling 1,330 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 67,880 Oxygen Compressor 11,160 Nitrogen Compressors 23,850 Boiler Feedwater Pumps 4,370 Condensate Pump 260 Syngas Recycle Compressor 610 Circulating Water Pump 2,870 Ground Water Pumps 270 Cooling Tower Fans 1,870 Air Cooled Condenser Fans 3,880 Scrubber Pumps 10 Acid Gas Removal 1,320 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 2,520 Miscellaneous Balance of Plant 1 

### 3,000 Transformer Losses 2,010 TOTAL AUXILIARIES, kWe 133,460 NET POWER, kWe 604,840 Net Plant Efficiency, % (HHV) 36.7% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,803 (9,292) CONDENSER COOLING DUTY GJ/hr (10 6 

### Btu/hr) 1,720 (1,630) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 297,660 (656,228) Thermal Input, kWt 1,647,041 Raw Water Withdrawal , m 3 

### /min (gpm) 11.4 (3,023)
Raw Water Consumption , m 3 

### /min (gpm) 8. 86 (2,3 4 1)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

386 

### Environmental Performance The environmental targets for emissions of Hg, NOx, SO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for Case S4A is presented in Exhibit 3

- 129

.

Exhibit 3

- 129 Cases S4A Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.001 (0.002) 29 (32) 0.006 ( 0 .01 2 )

NO X 

### 0.022 (0.052) 934 (1,030) 0.180 ( 0 .398)

Particulates 0.003 (0.0071) 127 (140) 0.025 ( 0 .054) Hg 1.51E

- 7 (3.51E

- 7) 0.006 (0.007) 1.21E

- 6 (2.67E

- 6)

CO 2 

### gross 91.5 (212.8) 3,802,037 (4,191,028) 735 (1,620)

CO 2 

### net 897 (1,977)

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the MDEA AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 5 ppmv. This results in a concentration in t he flue gas of less than 1 ppmv. The H 2 

### S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated and recycled to the AGR to capture most of the remaining sulfur. Because the environmental target was set based on higher sulfur bituminous coal, the resulting SO 2 

### emissions with lower sulfur western coals are substantially less than the environmental target.

NO x emissions are limited to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ) by the use of low NOx burners and nitrogen dilution of the fuel gas . Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and destroyed in the Claus plant burner. This helps lower NO x levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable parti culate only.

Ninety five percent of the mercury is captured from the syngas by an activated carbon bed.

CO 2 

### emissions represent the uncontrolled discharge from the process.

The carbon balance for the two cases is shown in Exhibit 3

- 13 0

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the ash and as CO 2 

### in t he stack gas and ASU vent gas.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

387 

### Exhibit 3

- 130 Case S4A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 149,033 (328,561) Slag 1,341 (2,957)

Air (CO 2 

### ) 501 (1,105) Stack Gas 148,065 (326,427)

ASU Vent 128 (282)

Total 149,534 (329,666) Total 149,534 (329,666)

Exhibit 3

- 131 shows the sulfur balance for the non capture case. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted i n the stack gas. Sulfur in the ash is considered to be negligible

.

Exhibit 3

- 131 Case S4A Sulfur Balance
Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 2,165 (4,774) Elemental Sulfur 2,163 (4,769)

Stack Gas 2 (5)

Total 2,165 (4,774) Total 2,165 (4,774)

Exhibit 3

- 132 shows the overall water balance for the plant. 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, primarily as coal moisture from the drying process and syngas condensate, and that water is re

- used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Some water is discharged from the process to a permitted outfall. The difference between the withdrawal and discharge is the consumption.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

388 

### Exhibit 3

- 132 Case S4A 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) ,

S 4 A S4A S4A S4A S4A
Slag Handling 0.56 (147) 0.56 (147) 0 (0) 0 (0) 0 (0)
Slurry Water 2.61 (689) 2.30 (609) 0.30 (80) 0.00 (0) 0.30 (80)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0.08 (21)

- 0.08 (

- 21)
Condenser Makeup 0.17 (44) 0 (0) 0.17 (44) 0 (0) 0.17 (44)

BFW Makeup 0.17 (44) 0.17 (44)
Cooling Tower Makeup 11.14 (2,943) 0.17 (44) 10.97 (2,899) 2.51 (662) 8.47 (2,237)

BFW Blowdown 0.17 (44)

- 0.17 (

- 44)

Total 14.5 (3,823) 3.03 (800) 11.4 (3,023) 2.5 8 (6 83 ) 8. 86 (2,3 4 1)



### Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown f or the following subsystems in Exhibit 3

- 133 :

**•** Coal gasification and ASU

**•** Syngas cleanup

**•** Power block

An overall plant energy balance is provided in tabular form in Exhibit 3

- 134 based on 0°C (32°F) reference conditions. The power out is the combined CT and steam turbine power after generator losses.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

389 

### Exhibit 3

- 133 Case S4A Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

390 

### Exhibit 3

- 133 Case S4A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

391 

### Exhibit 3

- 133 Case S4A Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

392 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

393 

### Exhibit 3

- 134 Case S4A Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)
Coal 5,929 (5,620) 3.0 (2.9) 0 (0) 5,932 (5,623)

ASU Air 0 (0) 11.6 (11.0) 0 (0) 12 (11)

GT Air 0 (0) 44.5 (42.1) 0 (0) 44 (42)
Raw Water Makeup 0 (0) 15.9 (15.1) 0 (0) 16 (15)
Auxiliary Power 0 (0) 0 ( 0 ) 480 (455) 480 (455)

Totals 5,929 (5,620) 75.1 (71.1) 480 (455) 6,485 (6,146) Heat Out GJ/hr (MMBtu/hr)
ASU Intercoolers 0 (0) 273 (259) 0 (0) 273 (259)

ASU Vent 0 (0) 10.1 (9.6) 0 (0) 10 (10)
Slag 44 (42) 28.6 (27.1) 0 (0) 73 (69)

Sulfur 20 (19) 0.2 (0.2) 0 (0) 20 (19)
Cooling Tower Blowdown 0 (0) 14.0 (13.2) 0 (0) 14 (13)

HRSG Flue Gas 0 (0) 841 (797) 0 (0) 841 (797)

Condenser 0 (0) 1,724 (1,634) 0 (0) 1,724 (1,634)
Auxiliary Cooling Load 0 (0) 108 (102) 0 (0) 108 (102)

Generator Loss 0 (0) 0 (0) 40 (38) 40 (38)

Process Losses 0 (0) 724 (686) 0 (0) 724 (686)

Power 0 (0) 0 ( 0 ) 2,658 (2,519) 2,658 (2,519)

Totals 64 (61) 3,722 (3,528) 2,698 (2,558) 6,485 (6,146)

3.5.6 Case S4A Equipment Lists

Major equipment items for the COP TM gasifier with no CO 2 

### capture using PRB coal are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.5.7 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

394 

### ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne ( 200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As

- Received Coal Sampling System Two

- stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 64 tonne (70 ton) 2 1
9 Feeder Vibratory 245 tonne/hr (270 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 490 tonne/hr (540 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 245 tonne (270 ton) 2 0

13 Crusher Impactor reduction 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 1 1
15 Conveyor No. 4 Belt w/tripper 490 tonne/hr (540 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0
17 Conveyor No. 5 Belt w/ tripper 490 tonne/hr (540 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 1,089 tonne (1,200 ton) 3 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

395 

### ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty Spares

1 Feeder Vibratory 109 tonne/h r (120 tph) 3 0
2 Conveyor No. 6 Belt w/tripper 327 tonne/h r (360 tph) 1 0
3 Rod Mill Feed Hopper Dual Outlet 653 tonne (720 ton) 1 0
4 Weigh Feeder Belt 163 tonne/h r (180 tph) 2 0
5 Rod Mill Rotary 163 tonne/h r (180 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 515,729 liters (136,240 gal) 2 0

7 Slurry Water Pumps Centrifugal 2,877 lpm (760 gpm) 1 0

8 Rod Mill Discharge Tank with Agitator Field erected 254 tonne/h r (280 tph) 2 0

9 Slurry Recycle Pumps Centrifugal 469,773 liters (124,100 gal) 2 0
10 Rod Mill Product Pumps Centrifugal 3,785 lpm (1000 gpm) 2 0

11 Slurry Storage Tank with Agitator Field erected 2,818,640 liters (744,600 gal) 1 0

12 Slurry Recycle Pumps Centrifugal 7,949 lpm (2,100 gpm) 2 2
13 Slurry Product Pumps Positive displacement 3,785 lpm (1,000 gpm) 2 2Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

396 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 647,305 liters (171,000 gal) 2 0

2 Condensate Pumps Vertical canned 7,419 lpm @ 91 m H 2 

### O (1,960 gpm @ 300 ft H 2 

### O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 549,754 kg/hr (1,212,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2,309 lpm @ 27 m H 2 

### O (610 gpm @ 90 ft H 2 

### O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

- stage, centrifugal HP water: 7,003 lpm @ 1,890 m H 2 

### O ( 1,850 gpm @ 6,200 ft H 2 

### O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

- stage, centrifugal IP water: 114 lpm @ 223 m H 2 

### O ( 30 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) 1 0

8 Service Air Compressors Flooded Screw 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) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 224 GJ/hr (212 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 80,251 lpm @ 21 m H 2 

### O (21,200 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 1Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

397 

### Equipment No. Description Type Design Condition Operating Qty Spares
(1,000 gpm @ 350 ft H 2 

### O)

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 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 2,801 lpm @ 18 m H 2 

### O (740 gpm @ 60 ft H 2 

### O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,801 lpm @ 268 m H 2 

### O ( 740 gpm @ 880 ft H 2 

### O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 1,173 lpm @ 49 m H 2 

### O (310 gpm @ 160 ft H 2 

### O) 2 1

17 Filtered Water Tank Vertical, cylindrical 556,456 liter (147,000 gal) 2 0
18 Makeup Water Demineralizer Anion, cation, and mixed bed 189 lpm (50 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24

- hour storm 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

398 

### ACCOUNT 4 GASIFIER, ASU , AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type Design Condition Operating Qty Spares

1 Gasifier Pressurized two

- stage, slurry

- feed entrained bed 3,901 tonne/day, 4.2 MPa (4,300 tpd, 61 5 psia) 2 0

2 Synthesis Gas Cooler Fire

- tube boiler 373,307 kg/hr (823,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 373,307 kg/hr (823,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical up flow 373,307 kg/hr (823,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 355,163 kg/hr (783,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 248,569 kg/hr, 38°C, 3.9 MPa (548,000 lb/hr, 100°F, 565 psia) 2 0

8 Synthesis Gas Reheater Shell and tube 248,115 kg/hr (547,000 lb/hr) 2 0

9 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 373,307 kg/hr (823,000 lb/hr)
syngas 2 0

10 ASU Main Air Compressor Centrifugal, multi

- stage 5,720 m 3 

### /min @ 1.3 MPa (202,000 scfm @ 190 psia) 2 0

11 Cold Box Vendor design 2,812 tonne/day (3,100 tpd) of 95% purity oxygen 2 0

12 Oxygen Compressor Centrifugal, multi

- stage 1,444 m 3 

### /min (51,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

399 

### Equipment No. Description Type Design Condition Operating Qty Spares

13 Primary Nitrogen Compressor Centrifugal, multi

- stage 2,605 m 3 

### /min (92,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0

14 Secondary Nitrogen Compressor Centrifugal, single

- stage 651 m 3 

### /min (23,000 scfm) Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0

15 Extraction Air Heat Exchanger Gas

- to

- gas, vendor design 96,162 kg/hr, 411°C, 1.4 MPa (212,000 lb/hr, 771°F, 208 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

400 

### ACCOUNT 5 SYNGAS CLEANUP
Equipment No. Description Type Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed 248,115 kg/hr (547,000 lb/hr) 35°C (95°F) 3.8 MPa (555 psia) 2 0

2 Sulfur Plant Claus type 57 tonne/day (63 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 355,163 kg/hr (783,000 lb/hr) 232°C (450°F) 4.1 MPa (590 psia) 2 0

4 Acid Gas Removal Plant Sulfinol 271,702 kg/hr (599,000 lb/hr) 33°C (92°F) 3.8 MPa (545 psia) 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 46,542 kg/hr (102,608 lb/hr) 232°C (450°F) 0.3 MPa (48.6 psia) 1 0

6 Tail Gas Recycle Compressor Centrifugal 42,658 kg/hr (94,044 lb/hr) 1 0

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES Equipment No. Description Type Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 210 MW 2 0
2 Gas Turbine Generator TEWAC 230 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

401 

### ACCOUNT 7 HRSG, DUCTING AND STACK Equipment No. Description Type Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.4 m ( 19 ft) diameter 2 0

2 Heat Recovery Steam Generator Drum, multi

- pressure with economizer section and integral deaerator Main steam

- 397,321 kg/hr, 12.4 MPa/566°C (875,942 lb/hr, 1,800 psig/1,050°F) Reheat steam

- 390,352 kg/hr, 3.1 MPa/566°C (860,579 lb/hr, 452 psig/1,050°F) 2 0

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES Equipment No. Description Type Design Condition Operating Qty Spares

1 Steam Turbine Commercially available 339 MW 12.4 M Pa/566°C/566°C (1

, 800 psig/ 1
, 050 °F/1

, 050°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 380 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided waterbox including
vacuum pumps 50% steam flow @ design steam conditions 1 0

4 Air

- cooled Condenser --- 950 GJ/hr (900 MMBtu/hr), Inlet water temperature 09°C (48°F), Water temperature rise 11°C (20°F) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

402 

### ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty Spares

1 Circulating Water Pumps Vertical, wet pit 287,691 lpm @ 30 m (76,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) WB / 9°C ( 48°F) CWT / 20°C ( 68°F) HWT / 1
, 604 GJ/hr (1

, 520 MMBtu/hr) heat duty 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

403 

### ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment No. Description Type Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 268,764 liters (71,000 gal) 2 0
2 Slag Crusher Roll 15 tonne/hr (16 tph) 2 0
3 Slag Depressurizer Proprietary 15 tonne/hr (16 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 162,773 liters (43,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 71,923 liters (19,000 gal) 2 0

6 Slag Conveyor Drag chain 15 tonne/hr (16 tph) 2 0
7 Slag Separation Screen Vibrating 15 tonne/hr (16 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 15 tonne/hr (16 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 230,910 liters (61,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 76 lpm @ 14 m H 2 

### O (20 gpm @ 46 ft H 2 

### O) 2 2

11 Grey Water Storage Tank Field erected 71,923 liters ( 19,000 gal) 2 0

12 Grey Water Pumps Centrifugal 265 lpm @ 433 m H 2 

### O (70 gpm @ 1,420 ft H 2 

### O) 2 2

13 Slag Storage Bin Vertical, field erected 998 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 118 tonne/hr (130 tph) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

404 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Design Condition Operating Qty Spares

1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 230 MVA, 3

- ph, 60 Hz 2 0

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 380 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 57 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 32 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 5 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 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1
9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

405 

### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type Design Condition Operating Qty Spares

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 0

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

406 

### 3.5.7 Case S4 A Cost Estimating

Costs Results The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 135 shows the TPC summary organized by cost account for the Case S4A. A more detailed br eakdown of the capital costs is shown in Exhibit 3

- 136

. Exhibit 3

- 137 shows the calculation and addition of owner’s costs to determine the TOC , used to calculate COE. Exhibit 3

- 138 shows the initial and annual O&M costs for Case S4A.

The estimated T O C of the CoP E

- GasTM IGCC plant with no CO 2 

### capture using PRB coal is $2, 7 71 /kW. Process contingency represents 2 percent, project contingency represents 1 1 percent , and owner’s costs represent 18 percent of TOC . The COE is 78.7 mills/kWh.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

407 

### Exhibit 3

- 135 Case S4A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S4A - ConocoPhillips IGCC w/o CO2 Plant Size: 604.8 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $17,180 $3,193 $13,323 $0 $0 $33,696 $3,059 $0 $7,351 $44,106 $73

2 COAL & SORBENT PREP & FEED $29,627 $5,415 $17,900 $0 $0 $52,942 $4,753 $0 $11,539 $69,233 $114

3 FEEDWATER & MISC. BOP SYSTEMS $9,132 $8,032 $8,390 $0 $0 $25,554 $2,398 $0 $6,265 $34,218 $57

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $141,056 $0 $76,694 $0 $0 $217,750 $19,592 $30,569 $40,951 $308,862 $511 4.2 Syngas Cooling w/4.1 w/4.1 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $170,773 $0 w/equip. $0 $0 $170,773 $16,553 $0 $18,733 $206,059 $341 4.4-4.9 Other Gasification Equipment $21,702 $12,064 $14,900 $0 $0 $48,667 $4,645 $0 $11,574 $64,886 $107 SUBTOTAL 4 $333,532 $12,064 $91,594 $0 $0 $437,191 $40,790 $30,569 $71,257 $579,807 $959

5A GAS CLEANUP & PIPING $53,335 $2,999 $49,299 $0 $0 $105,634 $10,211 $91 $23,330 $139,266 $230

5B CO2 REMOVAL & COMPRESSION $0 $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 $0 $92,022 $8,724 $4,601 $10,535 $115,882 $192 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $196

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,203 $0 $4,721 $0 $0 $37,924 $3,606 $0 $4,153 $45,683 $76 7.2-7.9 Open, Ductwork and Stack $3,336 $2,378 $3,115 $0 $0 $8,829 $819 $0 $1,570 $11,217 $19 SUBTOTAL 7 $36,539 $2,378 $7,836 $0 $0 $46,753 $4,424 $0 $5,723 $56,900 $94

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $32,394 $0 $5,646 $0 $0 $38,040 $3,650 $0 $4,169 $45,859 $76 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $40,553 $1,120 $13,767 $0 $0 $55,441 $5,370 $0 $12,451 $73,262 $121 SUBTOTAL 8 $72,947 $1,120 $19,413 $0 $0 $93,480 $9,020 $0 $16,620 $119,121 $197

9 COOLING WATER SYSTEM $7,368 $7,303 $6,231 $0 $0 $20,903 $1,942 $0 $4,678 $27,522 $46

10 ASH/SPENT SORBENT HANDLING SYS $21,024 $1,598 $10,432 $0 $0 $33,053 $3,171 $0 $3,953 $40,177 $66

11 ACCESSORY ELECTRIC PLANT $28,690 $10,887 $21,639 $0 $0 $61,216 $5,261 $0 $12,523 $78,999 $131

12 INSTRUMENTATION & CONTROL $10,114 $1,861 $6,517 $0 $0 $18,492 $1,676 $925 $3,514 $24,607 $41

13 IMPROVEMENTS TO SITE $3,329 $1,962 $8,214 $0 $0 $13,505 $1,333 $0 $4,452 $19,290 $32

14 BUILDINGS & STRUCTURES $0 $6,804 $7,884 $0 $0 $14,688 $1,338 $0 $2,615 $18,641 $31

TOTAL COST $708,571 $66,423 $275,834 $0 $0 $1,050,827 $98,259 $36,187 $184,912 $1,370,185 $2,265 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

408 

### Exhibit 3

- 136 Case S4A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S4A - ConocoPhillips IGCC w/o CO2 Plant Size: 604.8 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,512 $0 $2,205 $0 $0 $6,716 $602 $0 $1,464 $8,782 $15 1.2 Coal Stackout & Reclaim $5,830 $0 $1,413 $0 $0 $7,243 $635 $0 $1,576 $9,454 $16 1.3 Coal Conveyors & Yd Crush $5,420 $0 $1,398 $0 $0 $6,819 $599 $0 $1,484 $8,901 $15
1.4 Other Coal Handling $1,418 $0 $324 $0 $0 $1,742 $152 $0 $379 $2,273 $4 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd. Foundations $0 $3,193 $7,983 $0 $0 $11,176 $1,071 $0 $2,449 $14,696 $24 SUBTOTAL 1. $17,180 $3,193 $13,323 $0 $0 $33,696 $3,059 $0 $7,351 $44,106 $73
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying (incl. w/2.3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,950 $467 $306 $0 $0 $2,723 $233 $0 $591 $3,546 $6 2.3 Slurry Prep & Feed $26,604 $0 $11,832 $0 $0 $38,436 $3,432 $0 $8,374 $50,241 $83 2.4 Misc.Coal Prep & Feed $1,072 $780 $2,340 $0 $0 $4,193 $385 $0 $916 $5,493 $9 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $4,168 $3,422 $0 $0 $7,590 $703 $0 $1,659 $9,952 $16 SUBTOTAL 2. $29,627 $5,415 $17,900 $0 $0 $52,942 $4,753 $0 $11,539 $69,233 $114 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $3,252 $5,584 $2,948 $0 $0 $11,784 $1,092 $0 $2,575 $15,451 $26 3.2 Water Makeup & Pretreating $450 $47 $251 $0 $0 $748 $71 $0 $246 $1,065 $2 3.3 Other Feedwater Subsystems $1,779 $601 $541 $0 $0 $2,921 $263 $0 $637 $3,821 $6 3.4 Service Water Systems $257 $530 $1,839 $0 $0 $2,626 $256 $0 $865 $3,747 $6 3.5 Other Boiler Plant Systems $1,381 $535 $1,326 $0 $0 $3,242 $307 $0 $710 $4,259 $7 3.6 FO Supply Sys & Nat Gas $313 $591 $552 $0 $0 $1,456 $140 $0 $319 $1,916 $3 3.7 Waste Treatment Equipment $629 $0 $383 $0 $0 $1,012 $99 $0 $333 $1,444 $2 3.8 Misc. Power Plant Equipment $1,072 $143 $550 $0 $0 $1,766 $171 $0 $581 $2,517 $4 SUBTOTAL 3. $9,132 $8,032 $8,390 $0 $0 $25,554 $2,398 $0 $6,265 $34,218 $57
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $141,056 $0 $76,694 $0 $0 $217,750 $19,592 $30,569 $40,951 $308,862 $511 4.2 Syngas Cooling w/4.1 w/4.1 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $170,773 $0 w/equip. $0 $0 $170,773 $16,553 $0 $18,733 $206,059 $341
4.4 LT Heat Recovery & FG Saturation $21,702 $0 $8,250 $0 $0 $29,952 $2,923 $0 $6,575 $39,451 $65 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,428 $581 $0 $0 $2,009 $193 $0 $440 $2,642 $4 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $10,636 $6,069 $0 $0 $16,705 $1,529 $0 $4,559 $22,793 $38 SUBTOTAL 4. $333,532 $12,064 $91,594 $0 $0 $437,191 $40,790 $30,569 $71,257 $579,807 $959 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

409 

### Exhibit 3

- 136 Case S4A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S4A - ConocoPhillips IGCC w/o CO2 Plant Size: 604.8 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $40,356 $0 $34,243 $0 $0 $74,599 $7,215 $0 $16,363 $98,176 $162 5A.2 Elemental Sulfur Plant $5,512 $1,098 $7,111 $0 $0 $13,721 $1,333 $0 $3,011 $18,064 $30 5A.3 Mercury Removal $1,039 $0 $790 $0 $0 $1,829 $177 $91 $419 $2,516 $4 5A.4 COS Hydrolysis $4,527 $0 $5,912 $0 $0 $10,440 $1,015 $0 $2,291 $13,746 $23 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,902 $320 $180 $0 $0 $2,402 $228 $0 $526 $3,156 $5 5A.7 Fuel Gas Piping $0 $785 $550 $0 $0 $1,335 $124 $0 $292 $1,751 $3 5A.9 HGCU Foundations $0 $795 $513 $0 $0 $1,308 $120 $0 $428 $1,857 $3 SUBTOTAL 5A. $53,335 $2,999 $49,299 $0 $0 $105,634 $10,211 $91 $23,330 $139,266 $230 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $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 $0 $92,022 $8,724 $4,601 $10,535 $115,882 $192 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $196
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,203 $0 $4,721 $0 $0 $37,924 $3,606 $0 $4,153 $45,683 $76 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,710 $1,220 $0 $0 $2,930 $257 $0 $637 $3,824 $6
7.4 Stack $3,336 $0 $1,253 $0 $0 $4,589 $440 $0 $503 $5,532 $9 7.9 HRSG,Duct & Stack Foundations $0 $668 $642 $0 $0 $1,310 $122 $0 $430 $1,862 $3 SUBTOTAL 7. $36,539 $2,378 $7,836 $0 $0 $46,753 $4,424 $0 $5,723 $56,900 $94 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $32,394 $0 $5,646 $0 $0 $38,040 $3,650 $0 $4,169 $45,859 $76 8.2 Turbine Plant Auxiliaries $218 $0 $499 $0 $0 $716 $70 $0 $79 $865 $1 8.3a Condenser & Auxiliaries $3,404 $0 $1,088 $0 $0 $4,492 $430 $0 $492 $5,414 $9 8.3b Air Cooled Condenser $31,198 $0 $6,255 $0 $0 $37,453 $3,745 $0 $8,240 $49,438 $82 8.4 Steam Piping $5,733 $0 $4,033 $0 $0 $9,766 $839 $0 $2,651 $13,256 $22 8.9 TG Foundations $0 $1,120 $1,893 $0 $0 $3,013 $286 $0 $990 $4,289 $7 SUBTOTAL 8. $72,947 $1,120 $19,413 $0 $0 $93,480 $9,020 $0 $16,620 $119,121 $197
9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,099 $0 $993 $0 $0 $6,092 $580 $0 $1,001 $7,673 $13 9.2 Circulating Water Pumps $1,320 $0 $82 $0 $0 $1,402 $118 $0 $228 $1,749 $3 9.3 Circ.Water System Auxiliaries $116 $0 $17 $0 $0 $133 $13 $0 $22 $167 $0 9.4 Circ.Water Piping $0 $4,840 $1,255 $0 $0 $6,095 $551 $0 $1,329 $7,975 $13 9.5 Make-up Water System $261 $0 $374 $0 $0 $635 $61 $0 $139 $835 $1 9.6 Component Cooling Water Sys $571 $683 $486 $0 $0 $1,741 $163 $0 $381 $2,285 $4 9.9 Circ.Water System Foundations $0 $1,779 $3,025 $0 $0 $4,804 $455 $0 $1,578 $6,838 $11 SUBTOTAL 9. $7,368 $7,303 $6,231 $0 $0 $20,903 $1,942 $0 $4,678 $27,522 $46 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

410 

### Exhibit 3

- 136 Case S4A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S4A - ConocoPhillips IGCC w/o CO2 Plant Size: 604.8 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $18,340 $0 $9,044 $0 $0 $27,384 $2,631 $0 $3,001 $33,016 $55 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $608 $0 $662 $0 $0 $1,270 $123 $0 $209 $1,602 $3 10.7 Ash Transport & Feed Equipment $816 $0 $197 $0 $0 $1,013 $94 $0 $166 $1,273 $2 10.8 Misc. Ash Handling Equipment $1,260 $1,544 $461 $0 $0 $3,265 $311 $0 $536 $4,112 $7 10.9 Ash/Spent Sorbent Foundation $0 $54 $68 $0 $0 $121 $11 $0 $40 $173 $0 SUBTOTAL 10. $21,024 $1,598 $10,432 $0 $0 $33,053 $3,171 $0 $3,953 $40,177 $66
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $951 $0 $940 $0 $0 $1,891 $181 $0 $207 $2,279 $4 11.2 Station Service Equipment $4,020 $0 $362 $0 $0 $4,383 $404 $0 $479 $5,265 $9 11.3 Switchgear & Motor Control $7,433 $0 $1,352 $0 $0 $8,784 $815 $0 $1,440 $11,039 $18
11.4 Conduit & Cable Tray $0 $3,453 $11,390 $0 $0 $14,843 $1,436 $0 $4,070 $20,348 $34 11.5 Wire & Cable $0 $6,597 $4,335 $0 $0 $10,931 $794 $0 $2,931 $14,657 $24 11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,154 $308 $0 $519 $3,981 $7
11.7 Standby Equipment $234 $0 $229 $0 $0 $463 $44 $0 $76 $583 $1 11.8 Main Power Transformers $16,052 $0 $145 $0 $0 $16,197 $1,225 $0 $2,613 $20,035 $33 11.9 Electrical Foundations $0 $157 $412 $0 $0 $569 $54 $0 $187 $811 $1 SUBTOTAL 11. $28,690 $10,887 $21,639 $0 $0 $61,216 $5,261 $0 $12,523 $78,999 $131
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $998 $0 $667 $0 $0 $1,665 $158 $83 $286 $2,192 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $229 $0 $147 $0 $0 $377 $36 $19 $86 $517 $1 12.7 Computer & Accessories $5,326 $0 $171 $0 $0 $5,497 $505 $275 $628 $6,904 $11 12.8 Instrument Wiring & Tubing $0 $1,861 $3,804 $0 $0 $5,664 $480 $283 $1,607 $8,035 $13 12.9 Other I & C Equipment $3,560 $0 $1,729 $0 $0 $5,289 $498 $264 $908 $6,959 $12 SUBTOTAL 12. $10,114 $1,861 $6,517 $0 $0 $18,492 $1,676 $925 $3,514 $24,607 $41 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $104 $2,232 $0 $0 $2,337 $232 $0 $771 $3,340 $6 13.2 Site Improvements $0 $1,858 $2,469 $0 $0 $4,326 $427 $0 $1,426 $6,179 $10 13.3 Site Facilities $3,329 $0 $3,513 $0 $0 $6,842 $675 $0 $2,255 $9,771 $16 SUBTOTAL 13. $3,329 $1,962 $8,214 $0 $0 $13,505 $1,333 $0 $4,452 $19,290 $32
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,682 $3,820 $0 $0 $6,502 $598 $0 $1,065 $8,165 $13 14.3 Administration Building $0 $842 $611 $0 $0 $1,453 $129 $0 $237 $1,819 $3
14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $254 $22 $0 $41 $317 $1 14.5 Water Treatment Buildings $0 $376 $367 $0 $0 $742 $67 $0 $121 $931 $2 14.6 Machine Shop $0 $431 $295 $0 $0 $726 $64 $0 $119 $909 $2
14.7 Warehouse $0 $696 $449 $0 $0 $1,145 $101 $0 $187 $1,433 $2 14.8 Other Buildings & Structures $0 $417 $324 $0 $0 $741 $66 $0 $161 $969 $2 14.9 Waste Treating Building & Str. $0 $931 $1,780 $0 $0 $2,712 $253 $0 $593 $3,557 $6 SUBTOTAL 14. $0 $6,804 $7,884 $0 $0 $14,688 $1,338 $0 $2,615 $18,641 $31

TOTAL COST $708,571 $66,423 $275,834 $0 $0 $1,050,827 $98,259 $36,187 $184,912 $1,370,185 $2,265 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

411 

### Exhibit 3

- 137 Case S4A Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $13,902 $23 1 Month Variable O&M $3,684 $6 25% of 1 Months Fuel Cost at 100% CF $911 $2 2% of TPC $27,404 $45 Total $45,902 $76

Inventory Capital 60 day supply of consumables at 100% CF $7,551 $12 0.5% of TPC (spare parts) $6,851 $11 Total $14,402 $24

Initial Cost for Catalyst and Chemicals $1,878 $3 Land $900 $1 Other Owner's Costs $205,528 $340 Financing Costs $36,995 $61

Total Owner's Costs $305,605 $505 Total Overnight Cost (TOC) $1,675,790 $2,771 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $1,910,400 $3,159Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

412 

### Exhibit 3

- 138 Case S4A Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun) 2007 Case S4A - ConocoPhillips IGCC w/o CO2 Heat Rate-net(Btu/kWh): 9,292 MWe-net: 605 Capacity Factor: (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $9.786 Maintenance Labor Cost $16,324,769 $26.990 Administrative & Support Labor $5,560,920 $9.194 Property Taxes and Insurance $27,403,700 $45.307 TOTAL FIXED OPERATING COSTS $55,208,302 $91.278 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $30,375,594 $0.00717

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 2,167.92 1.08 $0 $684,736 $0.00016

Chemicals

MU & WT Chem. (lb) 0 12,916 0.17 $0 $652,713 $0.00015 Carbon (Mercury Removal) (lb) 74,181 102 1.05 $77,902 $31,161 $0.00001 COS Catalyst (m3) 451 0.31 2,397.36 $1,080,271 $216,054 $0.00005 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 MDEA Solution (gal) 82,792 56 8.70 $720,105 $142,912 $0.00003 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.85 131.27 $0 $32,699 $0.00001 Subtotal Chemicals $1,878,278 $1,075,539 $0.00025

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 102 0.42 $0 $12,376 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 680 16.23 $0 $3,222,772 $0.00076 Subtotal Waste Disposal $0 $3,235,147 $0.00076

By-products & Emissions

Sulfur (tons) 0 57 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,878,278 $35,371,017 $0.00834

Fuel (ton) 0 7,875 15.22 $0 $34,989,859 $0.00825Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

413 

### 3.5.8 CoP E

- Gas TM IGCC CO 2 

### Capture Cases (S4B) Process Description

Case S4B is configured to produce electric power with CO 2 

### ca pture. The plant configuration is similar to Cases S4A with the major differences being the addition of WGS, the use of a two

stage Selexol AGR plant instead of MDEA and subsequent compression of the captured CO 2 

### stream. The gross power output is constrained by the capacity of the two CT s, and since the CO 2 

### capture and compression process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case S4A.

The process description for Case S4B is similar to Case S4A with several notable exceptions to

acc ommodate CO 2 

### capture. A BFD for the CO 2 

### capture case is shown in Exhibit 3

- 139 and stream tables are shown in Exhibit 3

- 140 . Instead of repeating the entire process description, only differences from Cases S4A are reported here. Coal Preparation and Feed Systems

Same as for Case S4A except for the coal is slurried to 49 percent solids for injection into the two stages of the gasifier.

Gasification The gasification process is similar to Case S4A except the coal feed (as

- re ceived) to the two gasifiers is 7,349 tonne/day (8,101 tpd) . For cases with a design target of 90 percent overall carbon capture, the gasifier can be tuned to minimize methane concentrations, which end up in the flue gas as the gas cleanup process does not capture the carbon in the form of methane. Varying s lurry concentration and different combinations of t wo stage slurry injection were considered based on vendor supplied gasifier performance

, guaranteeing a maximum methane concentration, with the tradeoff of lower CGE. This reduction in CGE is mainly due to the increased slurry water diluent, but for carbo n capture requiring WGS reaction, this slurry water replaces injected shift steam that would otherwise be extracted from the steam turbine. Raw Gas Cooling/Particulate Removal

No differences from Case S4A. Sour Water Stripper

No differences from Case S4A.

Sour Gas Shift The SGS process was described in Section 3.1.6

. The water concentration in the syngas is adjusted upstream of the shift reactors by the injection o f shift steam, extracted from the steam cycle. The hot syngas exiting the first stage of SGS is used to superheat steam. One more stage of SGS (for a total of two) results in approximately 97 percent overall conversion of CO to CO 2


### . The warm syngas from the second stage of SGS is cooled to preheat the syngas prior to the first stage of SGS. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second stage of SGS, the syngas is furt her cooled to 35°C (95°F) prior to the mercury removal beds. Mercury Removal and AGR Mercury removal is the same as in Case S4A.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

414 

### The AGR process in Case S4B is a two stage Selexol process where H 2 

### S is removed in the first stage and CO 2 

### in the second stage of absorption. The process results in three product streams, the clean syngas, a CO 2 

### - rich stream, and an acid gas feed to the Claus plant. The acid gas contains about 17 percent H 2 

### S and 68 percent CO 2 

### with the balance primarily H 2 

### . The CO 2 

### - rich stream i s discussed further in the CO 2 

### compression section.

CO 2 

### Compression and Dehydration

CO 2 

### from the AGR process is generated at two pressure levels. The LP stream is compressed from 0.12 MPa (17 psia) to 1.0 MPa (150 psia) and then combined with the HP stream. The combined stream is further compressed to a SC condition at 15.3 MPa (2215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

### stream is dehydrated to a dew point of

- 40oC (

- 40°F) using a thermal swing adsorptive dryer. The raw CO 2 

### stream from the Selexol process contains over 99 percent CO 2 

### . The dehyd rated 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 2.6

. Claus Un it The Claus plant is the same as Cases S4A except 53 tonne/day (59 tpd) of sulfur are produced.

Power Block Clean syngas from the AGR plant is reheated to 196°C (385°F). The conditioned syngas is diluted with nitrogen, and then enters the CT burner. The exhaust gas exits the CT at 561°C (1,042°F) and enters the HRSG where additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commerc ially available steam turbine using a nominal 12.4MPa/538°C/538°C (1

, 800 psig/1

, 000°F/1

, 000°F) steam cycle. There is no air integration between the CT and the ASU in the capture case.

ASU The same elevated pressure ASU is used as in Cases S4A except the o utput is 5,323 tonne/day (5,867 tpd) of 95 mole percent oxygen and 11,750 tonne/day (12,952 tpd) of nitrogen.

Balance of Plant Balance of plant items were covered in Sections 3.1.12
, 3.1.13
, 3.1.14 and 3.1.15

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

415 

### Exhibit 3

- 139 Case S4B Process Flow DiagramCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

416 

### Exhibit 3

- 140 Case S4B Stream Table

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction

Ar 0.0093 0.0058 0.0318 0.0022 0.0360 0.0000 0.0000 0.0000 0.0077 0.0000 0.0079 0.0077 0.0000 0.0067 0.0090
CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0068 0.0000 0.0069 0.0068 0.0000 0.0059 0.0079
CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2356 0.0000 0.2419 0.2356 0.0000 0.0027 0.0036
CO 2 0.0003 0.0012 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1536 0.0000 0.1577 0.1536 0.0000 0.3376 0.4498
COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0001 0.0001 0.0000 0.0000 0.0000
H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2625 0.2137 0.0000 0.2194 0.2137 0.0000 0.3901 0.5197

H 2 O 0.0064 0.0230 0.0000 0.0002 0.0000 0.0000 0.9993 0.6787 0.3744 0.0000 0.3577 0.3744 1.0000 0.2498 0.0016

H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0022 0.0021 0.0000 0.0019 0.0025

N 2 0.7759 0.9350 0.0178 0.9925 0.0140 0.0000 0.0000 0.0040 0.0050 0.0000 0.0051 0.0050 0.0000 0.0044 0.0058

NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0003 0.0011 0.0000 0.0011 0.0011 0.0000 0.0010 0.0000
O 2 0.2081 0.0350 0.9504 0.0051 0.9500 0.0000 0.0000 0.0544 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 0.0000
Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kg mol /hr) 33,471 9,121 49 17,449 6,832 0 8,919 19,585 2,404 0 33,454 31,944 4,593 36,538 27,421 V-L Flowrate (kg/hr) 967,149 255,486 1,588 489,579 220,189 0 160,664 286,258 50,937 0 711,541 676,731 82,753 759,484 595,271 Solids Flowrate (kg/hr) 0 0 0 0 0 306,201 0 180,607 0 26,450 0 0 0 0 0

Temperature (°C) 6 15 32 93 32 6 149 149 241 1,038 1,017 194 288 204 35 Pressure (MPa, abs) 0.09 0.11 0.86 2.65 0.86 0.09 5.10 5.10 5.52 4.24 4.24 4.00 4.14 3.79 3.62 Enthalpy (kJ/kg) A 15.26 33.66 26.67 92.32 26.59

--- 571.24

--- 1,140.59

--- 2,517.45 1,069.76 2,956.19 859.79 38.17 Density (kg/m 3 ) 1.1 1.3 11.0 24.4 11.0

--- 863.7

--- 28.2

--- 8.3 22.6 18.2 20.2 31.6 V-L Molecular Weight 28.895 28.011 32.181 28.058 32.229

--- 18.015

--- 21.185

--- 21.270 21.185 18.015 20.786 21.709

V-L Flowrate (lb mol /hr) 73,791 20,108 109 38,468 15,062 0 19,662 43,177 5,301 0 73,752 70,425 10,127 80,552 60,452 V-L Flowrate (lb/hr) 2,132,199 563,251 3,500 1,079,336 485,435 0 354,203 631,091 112,296 0 1,568,680 1,491,937 182,439 1,674,377 1,312,349 Solids Flowrate (lb/hr) 0 0 0 0 0 675,058 0 398,171 0 58,313 0 0 0 0 0

Temperature (°F) 42 59 90 199 90 42 300 300 465 1,900 1,863 382 550 400 95 Pressure (psia) 13.0 16.4 125.0 384.0 125.0 13.0 740.0 740.0 800.0 614.7 614.7 579.7 600.0 549.7 524.7 Enthalpy (Btu/lb) A 6.6 14.5 11.5 39.7 11.4

--- 245.6

--- 490.4

--- 1,082.3 459.9 1,270.9 369.6 16.4 Density (lb/ft 3 ) 0.070 0.084 0.687 1.522 0.688

--- 53.921

--- 1.761

--- 0.521 1.409 1.135 1.261 1.972 A - Reference conditions are 32.02 F & 0.089 PSIACost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

417 

### Exhibit 3

- 140 Case S4B Stream Table (Continued)

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 V-L Mole Fraction

Ar 0.0084 0.0090 0.0027 0.0000 0.0062 0.0002 0.0002 0.0154 0.0154 0.0093 0.0096 0.0096 0.0000 0.0000 0.0000 0.0000
CH 4 0.0000 0.0079 0.0042 0.0000 0.0014 0.0004 0.0004 0.0132 0.0132 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 0.0071 0.0036 0.0012 0.0000 0.0784 0.0001 0.0001 0.0063 0.0063 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
CO 2 0.7741 0.4498 0.6789 0.0000 0.4933 0.9929 0.9955 0.0603 0.0603 0.0003 0.0102 0.0102 0.0000 0.0000 0.0000 0.0000
COS 0.0000 0.0000 0.0001 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
H 2 0.1630 0.5197 0.1090 0.0000 0.0466 0.0039 0.0039 0.8937 0.8937 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H 2 O 0.0018 0.0016 0.0345 0.0000 0.3407 0.0025 0.0000 0.0001 0.0001 0.0064 0.1204 0.1204 1.0000 1.0000 1.0000 1.0000

H 2 S 0.0043 0.0025 0.1685 0.0000 0.0010 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N 2 0.0412 0.0058 0.0009 0.0000 0.0303 0.0000 0.0000 0.0110 0.0110 0.7759 0.7535 0.7535 0.0000 0.0000 0.0000 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 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 0.2081 0.1062 0.1062 0.0000 0.0000 0.0000 0.0000
SO 2 0.0000 0.0000 0.0000 0.0000 0.0019 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 0.0000 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) 367 27,421 419 0 500 11,456 11,427 15,913 15,913 100,835 127,035 127,035 32,906 22,438 22,438 49,951 V-L Flowrate (kg/hr) 13,301 595,271 15,361 0 15,704 501,429 500,903 91,783 91,783 2,913,623 3,494,984 3,494,984 592,804 404,228 404,228 899,885 Solids Flowrate (kg/hr) 0 0 0 2,223 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 38 35 48 176 138 16 72 31 196 6 561 130 533 32 32 33 Pressure (MPa, abs) 5.51 3.5 0.163 0.119 0.119 0.931 15.270 3.238 3.203 0.090 0.093 0.090 12.512 0.005 0.005 0.827 Enthalpy (kJ/kg) A -5.12 38.2 87.882

--- 644.216 5.951 -96.995 153.366 1,017.404 15.260 829.125 338.189 3,430.351 2,273.814 2,273.814 139.321 Density (kg/m 3 ) 93.2 31.0 2.3

--- 1.1 18.0 465.8 7.3 4.7 1.1 0.4 0.7 36.8 0.04 0.04 995.1 V-L Molecular Weight 36.268 22 36.699

--- 31.428 43.769 43.834 5.768 5.768 28.895 27.512 27.512 18.015 18.015 18.015 18.015

V-L Flowrate (lb mol /hr) 809 60,452 923 0 1,102 25,257 25,193 35,081 35,081 222,302 280,065 280,065 72,544 49,467 49,467 110,124 V-L Flowrate (lb/hr) 29,323 1,312,349 33,865 0 34,621 1,105,461 1,104,303 202,347 202,347 6,423,439 7,705,122 7,705,122 1,306,908 891,170 891,170 1,983,906 Solids Flowrate (lb/hr) 0 0 0 4,901 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 100 95 119 349 280 60 161 87 385 42 1,042 267 992 90 90 92 Pressure (psia) 799.5 514.7 23.7 17.3 17.3 135.0 2,214.7 469.6 464.6 13.0 13.5 13.0 1,814.7 0.7 0.7 120.0 Enthalpy (Btu/lb) A -2.2 16.4 37.8

--- 277.0 2.6 -41.7 65.9 437.4 6.6 356.5 145.4 1,474.8 977.6 977.6 59.9 Density (lb/ft 3 ) 5.816 1.935 0.141

--- 0.069 1.124 29.077 0.456 0.292 0.070 0.023 0.046 2.297 0.002 0.002 62.121Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

418 

### 3.5.9 Case S4B Performance Results

The Case S4B modeling assumptions were presented previously in Exhibit 3

- 124

.
The CoP E

- GasTM IGCC plant with CO 2 

### capture and using PRB coal at the Montana site (elevation 3,400 ft) produces a net output of 51 5 MWe at a net plant efficiency of 30. 4 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3

- 141
, which includes auxiliary power requirements. The ASU accounts for approximately 63 percent of the total auxiliary load, distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. CO 2 

### compression acc ounts for about 18 percent, and the AGR process about 10 percent of the auxiliary load. All other individual auxiliary loads are less than 3 percent of the total.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

419 

### Exhibit 3

- 141 Case S4B Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) S4B

Gas Turbine Power 429,000 Steam Turbine Power 298,200 TOTAL POWER, kWe 727,200 AUXILIARY LOAD SUMMARY, kWe Coal Handling 560 Coal Milling 3,150 Sour Water Recycle Slurry Pump 300 Slag Handling 1,370 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 86,130 Oxygen Compressor 11,480 Nitrogen Compressors 28,300 CO 2 

### Compressor 36,110 Boiler Feedwater Pumps 3,910 Condensate Pump 290 Syngas Recycle Compressor 1,040 Circulating Water Pump 3,400 Ground Water Pumps 360 Cooling Tower Fans 2,210 Air Cooled Condenser Fans 3,850 Scrubber Pumps 10 Acid Gas Removal 20,580 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 1,660 Miscellaneous Balance of Plant 1 

### 3,000 Transformer Losses 2,070 TOTAL AUXILIARIES, kWe 212,130 NET POWER, kWe 515,070 Net Plant Efficiency, % (HHV) 30.4% Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,842 (11,224) CONDENSER COOLING DUTY GJ/hr (10 6 

### Btu/hr) 1,720 (1,630) CONSUMABLES As

- Received Coal Feed, kg/hr (lb/hr) 306,201 (675,058) Thermal Input, kWt 1,694,303 Raw Water Withdrawal , m 3 

### /min (gpm) 15.1 (3,987)
Raw Water Consumption , m 3 

### /min (gpm) 12.1 (3,199)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

420 

### Environmental Performance The environmental targets for emissions of Hg, NOx , SO 2 

### , CO 2 

### , and PM were presented in Section 2.3 . A summary of the plant air emissions for Case S4B is presented in Exhibit 3

- 142

.

Exhibit 3

- 142 Case S4B Air Emissions

kg/GJ (lb/10 6 

### Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)

SO 2 

### 0.000 (0.001) 16 (17) 0.003 ( 0 .0 07 )

NO X 

### 0.019 (0.044) 804 (886) 0.158 ( 0 .348)

Particulates 0.003 (0.0071) 130 (144) 0.026 ( 0 .056) Hg 1.51E

- 7 (3.51E

- 7) 0.006 (0.007) 1.27E

- 6 (2.79E

- 6)

CO 2 

### gross 9.4 (21.9) 401,650 (442,743) 79 (174)

CO 2 

### net 111 (245)

The low level of SO 2 

### emissions is achieved by capture of the sulfur in the gas by the two

- stage Selexol AGR process. Just as in the non

- capture cases, the SO 2 

### emission are significantly less than the environmental targets of Section 2.3 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 2 ppmv. This results in a concentration in the flue gas of less than 0.3 ppmv. The H 2 

### S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The tail gas is hydrogenated and recycled to the gasifier.

NO x emissions are limited to 15 ppmvd (as NO 2 

### @ 15 percent O 2 

### ) by the use of low NOx burners and nitrogen dilution of the fuel gas . Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and subsequently destroyed in the Claus plant burner. This helps lower NO x levels as w ell.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter 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 mercury is captured from the syngas by an activated carbon bed.

Slightly greater than 92 percent of the CO 2 

### from the syngas is captured in the AGR system and compressed for sequestration.

The carbon balance for the plant is shown in Exhibit 3

- 143

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the carbon capture equation below, but it is not neglected in the balance since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the ash, CO 2 

### in the stack gas and ASU vent gas, and the captured CO 2 

### product

. The carbon capture efficiency is defined as the amount 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:Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

421 

### (Carbon in Product for Sequestration)/[(Carbon in the Coal)

- (Carbon in Slag)] or 90.0 percent

Exhibit 3

- 143 Case S4B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Coal 153,309 (337,988) Slag 1,380 (3,042)

Air (CO 2 

### ) 529 (1,166) Stack Gas 15,642 (34,484)

ASU Vent 132 (291)

CO 2 

### Product 136,684 (301,337)

Total 153,838 (339,154) Total 153,838 (339,154)

Exhibit 3

- 144 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack ga s , and sulfur that is co

- sequestered with the CO 2 

### product. Sulfur in the ash is considered negligible.

Exhibit 3

- 144 Case S4B Sulfur Balance
Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

Coal 2,227 (4,911) Elemental Sulfur 2,223 (4,901)
Stack Gas 1 (2)
CO 2 

### Product 3 (8)

Total 2,227 (4,911) Total 2,227 (4,911)

1 

### By difference
Exhibit 3

- 145 shows the overall water balance for the plant. 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, primarily from the coal drying process and as syngas condensate, and that water is re

used as internal recycle. Raw water makeup is the difference between water demand and in ternal recycle.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

422 

### Exhibit 3

- 145 Case S4B 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) ,

S4B S4B S4B S4B S4B
Slag Handling 0.57 (151) 0. 57 (151) 0 (0) 0 (0) 0 (0)

Slurry Water 2.68 (708) 2.1 (557) 0.57 (151) 0 (0) 0.57 (151)

SWS Blowdown 0 (0) 0 (0) 0 (0) 0.01 (2)

- 0.01 (

- 2)

Condenser Makeup 1.53 (403) 0 (0) 1.53 (403) 0 (0) 1.53 (403)

Shift Steam 1.38 (365) 1.38 (365)
BFW Makeup 0.14 (38) 0.14 (38)

Cooling Tower Makeup 13.22 (3,492) 0.2 (60) 12.99 (3,432) 2.97 (785) 10.02 (2,647)

BFW Blowdown 0.1 4 (38)

- 0.14 (

- 38)

SWS Blowdown 0. 08 (22)

- 0.08 (

- 22)

Total 18.0 (4,755) 2.91 (768) 15.1 (3,987) 2.98 (788) 12.11 (3,199)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

423 

### Heat and Mass Balance Diagrams Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3

- 146 :

**•** Coal gasification and ASU

**•** Syngas cleanup

**•** Power block An overall plant energy balance is provided in tabular form in Exhibit 3

- 147 based on 0°C (32°F) reference conditions

. The power out is the combined CT and steam turbine power after generator losses.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

424 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

425 

### Exhibit 3

- 146 Case S4 B Heat and Mass BalanceCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

426 

### Exhibit 3

- 146 Case S4B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

427 

### Exhibit 3

- 146 Case S4B Heat and Mass Balance (Continued)Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

428 

### This page intentionally left blankCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

429 

### Exhibit 3

- 147 Case S4B Energy Balance

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)
Coal 6,099 (5,781) 3.1 (3.0) 0 (0) 6,103 (5,784)

ASU Air 0 (0) 14.8 (14.0) 0 (0) 15 (14)

GT Air 0 (0) 44.5 (42.1) 0 (0) 44 (42)

Raw Water Makeup 0 (0) 21.0 (19.9) 0 (0) 21 (20)
Auxiliary Power 0 (0) 0 ( 0 ) 764 (724) 764 (724)

Totals 6,099 (5,781) 83.3 (79.0) 764 (724) 6,947 (6,584) Heat Out GJ/hr (MMBtu/hr)
ASU Intercoolers 0 (0) 342 (324) 0 (0) 342 (324)

ASU Vent 0 (0) 8.6 (8.2) 0 (0) 9 (8)
Slag 45 (43) 29.5 (27.9) 0 (0) 75 (71)

Sulfur 21 (20) 0.3 (0.2) 0 (0) 21 (20)

CO 2 

### 0 (0)

- 48.6 (

- 46.0) 0 (0)

- 49 (

- 46)

CO 2 

### Comp Intercoolers 0 (0) 176.2 (167.0) 0 (0) 176 (167)
Cooling Tower Blowdown 0 (0) 16.6 (15.7) 0 (0) 17 (16)

HRSG Flue Gas 0 (0) 1,182 (1,120) 0 (0) 1,182 (1,120)

Condenser 0 (0) 1,720 (1,631) 0 (0) 1,720 (1,631)
Auxiliary Cooling 0 (0) 132 (125) 0 (0) 132 (125)

Generator Loss 0 (0) 0 (0) 40 (38) 40 (38)

Process Losses 0 (0) 663 (629) 0 (0) 663 (629)

Power 0 (0) 0 ( 0 ) 2,618 (2,481) 2,618 (2,481)

Totals 66 (62) 4,223 (4,003) 2,658 (2,519) 6,947 (6,584)

3.5.10 Case S4B Equipment List

Major equipment items for the CoP E

- Gas TM gasifier with CO 2 

### capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section 3.5.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

430 

### ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 18 1 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0
6 As

- Received Coal Sampling System Two

- stage N/A 1 0
7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 64 tonne (70 ton) 2 1
9 Feeder Vibratory 254 tonne/hr (280 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 508 tonne/hr (560 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 254 tonne (280 ton) 2 0

13 Crusher Impactor reduction 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 1 1
15 Conveyor No. 4 Belt w/tripper 508 tonne/hr (560 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0
17 Conveyor No. 5 Belt w/ tripper 508 tonne/hr (560 tph) 1 0
18 Coal Silo w/ Vent Filter and Slide Gates Field erected 1,089 tonne (1,200 ton) 3 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

431 

### ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty Spares

1 Feeder Vibratory 109 tonne/h r (120 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 336 tonne/h r (370 tph) 1 0
3 Rod Mill Feed Hopper Dual Outlet 671 tonne (740 ton) 1 0

4 Weigh Feeder Belt 172 tonne/h r (190 tph) 2 0

5 Rod Mill Rotary 172 tonne/h r (190 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 530,530 liters (140,150 gal) 2 0

7 Slurry Water Pumps Centrifugal 2,953 lpm (780 gpm) 1 0
8 Trommel Screen Coarse 263 tonne/h r (290 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 483,250 liters (127,660 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 4,164 lpm (1100 gpm) 2 0

11 Slurry Storage Tank with Agitator Field erected 2,899,649 liters (766,000 gal) 1 0

12 Slurry Recycle Pumps Centrifugal 7,949 lpm (2,100 gpm) 2 2
13 Slurry Product Pumps Positive displacement 4,164 lpm (1,100 gpm) 2 2Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

432 

### ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Design Condition Operating Qty Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 560,241 liters (148,000 gal) 2 0

2 Condensate Pumps Vertical canned 8,290 lpm @ 91 m H 2 

### O (2,190 gpm @ 300 ft H 2 

### O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 573,341 kg/hr (1,264,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 2,158 lpm @ 27 m H 2 

### O (570 gpm @ 90 ft H 2 

### O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi

stage, centrifugal HP water: 5,754 lpm @ 1,890 m H 2 

### O ( 1,520 gpm @ 6,200 ft H 2 

### O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi

stage, centrifugal IP water: 189 lpm @ 223 m H 2 

### O ( 50 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) 1 0

8 Service Air Compressors Flooded Screw 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) 2 1

10 Closed Cycle Cooling Heat Exchangers Plate and frame 372 GJ/hr (353 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 133,625 lpm @ 21 m H 2 

### O (35,300 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) 1 1Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

433 

### Equipment No. Description Type Design Condition Operating Qty Spares

13 Fire Service Booster Pump Two

- stage horizontal centrifugal 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 3,785 lpm @ 18 m H 2 

### O (1,000 gpm @ 60 ft H 2 

### O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,536 lpm @ 268 m H 2 

### O ( 670 gpm @ 880 ft H 2 

### O) 2 1

16 Filtered Water Pumps Stainless steel, single suction 1,931 lpm @ 49 m H 2 

### O (510 gpm @ 160 ft H 2 

### O) 2 1

17 Filtered Water Tank Vertical, cylindrical 927,426 liter (245,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 908 lpm (240 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24

- hour storm 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

434 

### ACCOUNT 4 GASIFIER, ASU , AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type Design Condition Operating Qty Spares

1 Gasifier Pressurized two

- stage, slurry

- feed entrained bed 4,082 tonne/day, 4.2 MPa (4,500 tpd, 61 5 psia) 2 0

2 Synthesis Gas Cooler Fire

- tube boiler 391,450 kg/hr (863,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 391,450 kg/hr (863,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse

- jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical up flow 391,450 kg/hr (863,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 417,759 kg/hr (921,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 327,494 kg/hr, 35°C, 3.9 MPa (722,000 lb/hr, 95°F, 560 psia) 2 0

8 Synthesis Gas Reheater Shell and tube 50,349 kg/hr (111,000 lb/hr) 2 0

9 Flare Stack Self

- supporting, carbon steel, stainless steel top, pilot ignition 391,450 kg/hr (863,000 lb/hr)
syngas 2 0

10 ASU Main Air Compressor Centrifugal, multi

- stage 7,277 m 3 

### /min @ 1.3 MPa (257,000 scfm @ 190 psia) 2 0

11 Cold Box Vendor design 2,903 tonne/day ( 3,200 tpd) of 95% purity oxygen 2 0

12 Oxygen Compressor Centrifugal, multi

- stage 1,501 m 3 

### /min (53,000 scfm) Suction

- 0.9 MPa (130 psia) Discharge

- 5.1 MPa (740 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

435 

### Equipment No. Description Type Design Condition Operating Qty Spares

13 Primary Nitrogen Compressor Centrifugal, multi

- stage 3,115 m 3 

### /min (110,000 scfm) Suction

- 0.4 MPa (60 psia) Discharge

- 2.7 MPa (390 psia) 2 0

14 Secondary Nitrogen Compressor Centrifugal, single

- stage 680 m 3 

### /min (24,000 scfm) Suction

- 1.2 MPa (180 psia) Discharge

- 2.7 MPa (390 psia) 2 0

15 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single

- stage 1,750 m 3 

### /min (61,800 scfm) Suction

- 2.6 MPa (384 psia) Discharge

- 3.2 MPa (469 psia) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

436 

### ACCOUNT 5 SYNGAS CLEANUP

Equipment No. Description Type Design Condition Operating Qty Spares

1 Mercury Adsorber Sulfated carbon bed 327,494 kg/hr (722,000 lb/hr) 35°C (95°F) 3.6 MPa (525 psia) 2 0

2 Sulfur Plant Claus type 59 tonne/day ( 65 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 417,759 kg/hr (921,000 lb/hr) 232°C (450°F) 4.0 MPa (580 psia) 4 0

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 133 GJ/hr (126 MMBtu/hr) 4 0

5 Acid Gas Removal Plant Two

- stage Selexol 327,494 kg/hr (722,000 lb/hr) 35°C (95°F) 3.5 MPa (515 psia) 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 17,274 kg/hr (38,083 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 14,644 kg/hr (32,284 lb/hr) 1 0

ACCOUNT 5B CO 2 

### COMPRESSION

Equipment No. Description Type Design Condition Operating Qty Spares

1 CO 2 

### Compressor Integrally geared, multi

- stage centrifugal 1,240 m 3 

### /min @ 15.3 MPa ( 43,800 scfm @ 2,215 psia) 4 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

437 

### ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty Spares

1 Gas Turbine Advanced F class 215 MW 2 0

2 Gas Turbine Generator TEWAC 240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 2 0

ACCOUNT 7 HRSG, DUCTING AND STACK

Equipment No. Description Type Design Condition Operating Qty Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.7 m (1 9 ft) diameter 2 0

2 Heat Recovery Steam Generator Drum, multi

- pressure with economizer section and integral deaerator Main steam

- 326,042 kg/hr, 12.4 MPa/533°C ( 718,800 lb/hr, 1,800 psig/992°F) Reheat steam

- 384,422 kg/hr, 3.1 MPa/533°C (847,506 lb/hr, 452 psig/992°F) 2 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

438 

### ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty Spares

1 Steam Turbine Commercially available 314 MW 12.4 MPa/533°C/533°C (1

, 800 psig/ 992°F/992°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 350 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 1 0

3 Surface Condenser Single pass, divided waterbox including
vacuum pumps 950 GJ/hr (900 MMBtu/hr), Condensing temperature 32°C (90°F),

Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 1 0

4 Air

- cooled Condenser --- 950 GJ/hr (900 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 1 0

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty Spares

1 Circulating Water Pumps Vertical, wet pit 340,687 lpm @ 30 m (90,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative, mechanical draft, multi

- cell 3°C (37°F) WB / 9°C (48°F) CWT / 20°C (68°F) HWT / 1

, 899 GJ/hr

(1

, 800 MMBtu/hr) heat duty 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

439 

### ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment No. Description Type Design Condition Operating Qty Spares

1 Slag Quench Tank Water bath 276,335 liters ( 73,000 gal) 2 0
2 Slag Crusher Roll 15 tonne/hr (16 tph) 2 0
3 Slag Depressurizer Proprietary 15 tonne/hr (16 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 166,558 liters (44,000 gal) 2 0
5 Black Water Overflow Tank Shop fabricated 75,708 liters (20,000 gal) 2 0
6 Slag Conveyor Drag chain 15 tonne/hr (16 tph) 2 0
7 Slag Separation Screen Vibrating 15 tonne/hr (16 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 15 tonne/hr (16 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 238,481 liters (63,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 76 lpm @ 14 m H 2 

### O (20 gpm @ 46 ft H 2 

### O) 2 2

11 Grey Water Storage Tank Field erected 75,708 liters (20,000 gal) 2 0

12 Grey Water Pumps Centrifugal 265 lpm @ 433 m H 2 

### O (70 gpm @ 1,420 ft H 2 

### O) 2 2

13 Slag Storage Bin Vertical, field erected 1,089 tonne (1,200 tons) 2 0
14 Unloading Equipment Telescoping chute 118 tonne/hr (130 tph) 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

440 

### ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment No. Description Type Design Condition Operating Qty Spares

1 CTG Step

- up Transformer Oil

- filled 24 kV/345 kV, 240 MVA, 3

- ph, 60 Hz 2 0

2 STG Step

- up Transformer Oil

- filled 24 kV/345 kV, 340 MVA, 3

- ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil

- filled 345 kV/13.8 kV, 70 MVA, 3

- ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil

- filled 24 kV/4.16 kV, 94 MVA, 3

- ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 14 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 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self

- cooled 24 kV, 3

- ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3

- ph, 60 Hz 1 1
9 Low Voltage Switchgear Metal enclosed 480 V, 3

- ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3

- ph, 60 Hz 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

441 

### ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type Design Condition Operating Qty Spares

1 DCS

- Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS

- Processor Microprocessor with redundant input/output N/A 1 0

3 DCS

- Data Highway Fiber optic Fully redundant, 25% spare 1 0Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

442 

### 3.5.11 Case S4 B Cost Estimating

Costs Results The cost estimating methodology was described previously in Section 2.6

. Exhibit 3

- 148 shows the TPC summary organized by cost account with a more detailed breakdown of the capital costs shown in Exhibit 3

- 149

. Exhibit 3

- 150 shows the calculation and addition of owner’s costs to determine the TOC , used to calculate COE. Exhibit 3

- 151 shows the initial and annual O&M costs for Case S4B.

The estimated TO C of the CoP E

- GasTM IGCC plant with CO 2 

### capture using PRB coal is $3, 8 51 /kW. Process contingency represents 4 percent, project contingency represents 11 percent , and owner’s costs represent 18 percent of TOC . The COE is 112.3 mills/kWh.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

443 

### Exhibit 3

- 148 Case S4B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S4B - ConocoPhillips IGCC w/ CO2 Plant Size: 515.11 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $17,484 $3,249 $13,559 $0 $0 $34,292 $3,113 $0 $7,481 $44,886 $87

2 COAL & SORBENT PREP & FEED $30,185 $5,517 $18,237 $0 $0 $53,939 $4,842 $0 $11,756 $70,538 $137

3 FEEDWATER & MISC. BOP SYSTEMS $8,916 $7,230 $8,653 $0 $0 $24,800 $2,336 $0 $6,215 $33,351 $65

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $145,903 $0 $79,531 $0 $0 $225,434 $20,280 $31,720 $42,380 $319,815 $621 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $207,324 $0 w/equip. $0 $0 $207,324 $20,096 $0 $22,742 $250,162 $486 4.4-4.9 Other Gasification Equipment $24,306 $12,187 $15,965 $0 $0 $52,457 $5,014 $0 $12,419 $69,889 $136 SUBTOTAL 4 $377,533 $12,187 $95,496 $0 $0 $485,215 $45,390 $31,720 $77,541 $639,866 $1,242

5A GAS CLEANUP & PIPING $90,779 $3,037 $75,014 $0 $0 $168,830 $16,307 $27,123 $42,594 $254,854 $495

5B CO2 COMPRESSION $20,780 $0 $12,237 $0 $0 $33,018 $3,179 $0 $7,239 $43,436 $84

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $252 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $256

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $31,545 $0 $4,485 $0 $0 $36,031 $3,426 $0 $3,946 $43,402 $84 7.2-7.9 Open, Ductwork and Stack $3,418 $2,436 $3,191 $0 $0 $9,045 $839 $0 $1,608 $11,492 $22 SUBTOTAL 7 $34,963 $2,436 $7,677 $0 $0 $45,076 $4,264 $0 $5,554 $54,895 $107

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $30,702 $0 $5,308 $0 $0 $36,010 $3,455 $0 $3,947 $43,412 $84 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $39,331 $1,059 $12,929 $0 $0 $53,319 $5,181 $0 $11,889 $70,389 $137 SUBTOTAL 8 $70,034 $1,059 $18,237 $0 $0 $89,329 $8,637 $0 $15,835 $113,801 $221

9 COOLING WATER SYSTEM $8,342 $8,140 $6,985 $0 $0 $23,467 $2,180 $0 $5,242 $30,889 $60

10 ASH/SPENT SORBENT HANDLING SYS $21,401 $1,623 $10,619 $0 $0 $33,643 $3,228 $0 $4,023 $40,893 $79

11 ACCESSORY ELECTRIC PLANT $33,841 $13,137 $25,530 $0 $0 $72,507 $6,227 $0 $14,935 $93,669 $182

12 INSTRUMENTATION & CONTROL $11,248 $2,069 $7,247 $0 $0 $20,564 $1,864 $1,028 $3,908 $27,364 $53

13 IMPROVEMENTS TO SITE $3,470 $2,045 $8,562 $0 $0 $14,077 $1,390 $0 $4,640 $20,107 $39

14 BUILDINGS & STRUCTURES $0 $6,957 $7,977 $0 $0 $14,934 $1,360 $0 $2,664 $18,958 $37

TOTAL COST $821,003 $69,492 $323,505 $0 $0 $1,214,001 $113,822 $69,732 $221,967 $1,619,522 $3,144 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

444 

### Exhibit 3

- 149 Case S4B Total Plant Cost Summary Details

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S4B - ConocoPhillips IGCC w/ CO2 Plant Size: 515.11 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,591 $0 $2,244 $0 $0 $6,835 $612 $0 $1,490 $8,937 $17 1.2 Coal Stackout & Reclaim $5,933 $0 $1,438 $0 $0 $7,372 $646 $0 $1,604 $9,621 $19 1.3 Coal Conveyors & Yd Crush $5,516 $0 $1,423 $0 $0 $6,940 $609 $0 $1,510 $9,058 $18
1.4 Other Coal Handling $1,443 $0 $329 $0 $0 $1,773 $155 $0 $386 $2,313 $4 1.5 Sorbent Receive & Unload $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
1.7 Sorbent Conveyors $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 1.9 Coal & Sorbent Hnd.Foundations $0 $3,249 $8,124 $0 $0 $11,373 $1,090 $0 $2,493 $14,956 $29 SUBTOTAL 1. $17,484 $3,249 $13,559 $0 $0 $34,292 $3,113 $0 $7,481 $44,886 $87
2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying (incl. w/2.3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,987 $475 $312 $0 $0 $2,774 $237 $0 $602 $3,613 $7 2.3 Slurry Prep & Feed $27,106 $0 $12,055 $0 $0 $39,161 $3,496 $0 $8,531 $51,188 $99 2.4 Misc.Coal Prep & Feed $1,093 $795 $2,384 $0 $0 $4,272 $393 $0 $933 $5,597 $11 2.5 Sorbent Prep Equipment $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 2.7 Sorbent Injection System $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 2.9 Coal & Sorbent Feed Foundation $0 $4,247 $3,487 $0 $0 $7,733 $716 $0 $1,690 $10,140 $20 SUBTOTAL 2. $30,185 $5,517 $18,237 $0 $0 $53,939 $4,842 $0 $11,756 $70,538 $137 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,699 $4,635 $2,447 $0 $0 $9,780 $906 $0 $2,137 $12,823 $25 3.2 Water Makeup & Pretreating $548 $57 $306 $0 $0 $912 $87 $0 $300 $1,299 $3 3.3 Other Feedwater Subsystems $1,477 $499 $449 $0 $0 $2,425 $218 $0 $529 $3,171 $6 3.4 Service Water Systems $314 $646 $2,242 $0 $0 $3,202 $312 $0 $1,054 $4,569 $9 3.5 Other Boiler Plant Systems $1,684 $652 $1,617 $0 $0 $3,953 $375 $0 $866 $5,194 $10 3.6 FO Supply Sys & Nat Gas $313 $591 $552 $0 $0 $1,456 $140 $0 $319 $1,916 $4 3.7 Waste Treatment Equipment $766 $0 $468 $0 $0 $1,234 $120 $0 $406 $1,760 $3 3.8 Misc. Power Plant Equipment $1,115 $149 $573 $0 $0 $1,837 $177 $0 $604 $2,619 $5 SUBTOTAL 3. $8,916 $7,230 $8,653 $0 $0 $24,800 $2,336 $0 $6,215 $33,351 $65
4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $145,903 $0 $79,531 $0 $0 $225,434 $20,280 $31,720 $42,380 $319,815 $621 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $207,324 $0 w/equip. $0 $0 $207,324 $20,096 $0 $22,742 $250,162 $486
4.4 LT Heat Recovery & FG Saturation $24,306 $0 $9,240 $0 $0 $33,546 $3,274 $0 $7,364 $44,183 $86 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $1,399 $569 $0 $0 $1,968 $189 $0 $431 $2,588 $5 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $10,788 $6,155 $0 $0 $16,943 $1,551 $0 $4,623 $23,117 $45 SUBTOTAL 4. $377,533 $12,187 $95,496 $0 $0 $485,215 $45,390 $31,720 $77,541 $639,866 $1,242 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

445 

### Exhibit 3

- 149 Case S4B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S4B - ConocoPhillips IGCC w/ CO2 Plant Size: 515.11 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $73,047 $0 $61,982 $0 $0 $135,029 $13,059 $27,006 $35,019 $210,112 $408 5A.2 Elemental Sulfur Plant $5,613 $1,119 $7,241 $0 $0 $13,973 $1,357 $0 $3,066 $18,396 $36 5A.3 Mercury Removal $1,328 $0 $1,011 $0 $0 $2,339 $226 $117 $536 $3,218 $6 5A.4 Shift Reactors $8,762 $0 $3,527 $0 $0 $12,288 $1,178 $0 $2,693 $16,160 $31 5A.5 Particulate Removal w/4.1 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $2,030 $342 $192 $0 $0 $2,564 $243 $0 $561 $3,368 $7 5A.7 Fuel Gas Piping $0 $784 $549 $0 $0 $1,332 $124 $0 $291 $1,747 $3 5A.9 HGCU Foundations $0 $794 $512 $0 $0 $1,305 $120 $0 $428 $1,853 $4 SUBTOTAL 5A. $90,779 $3,037 $75,014 $0 $0 $168,830 $16,307 $27,123 $42,594 $254,854 $495 5B CO2 COMPRESSION 5B.1 CO2 Removal System w/ 5A.1 $0 w/ 5A.1 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $20,780 $0 $12,237 $0 $0 $33,018 $3,179 $0 $7,239 $43,436 $84 SUBTOTAL 5B. $20,780 $0 $12,237 $0 $0 $33,018 $3,179 $0 $7,239 $43,436 $84
6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,610 $9,348 $9,861 $11,782 $129,600 $252 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $256
7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $31,545 $0 $4,485 $0 $0 $36,031 $3,426 $0 $3,946 $43,402 $84 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,752 $1,250 $0 $0 $3,002 $263 $0 $653 $3,918 $8
7.4 Stack $3,418 $0 $1,284 $0 $0 $4,701 $450 $0 $515 $5,667 $11 7.9 HRSG,Duct & Stack Foundations $0 $685 $658 $0 $0 $1,342 $125 $0 $440 $1,907 $4 SUBTOTAL 7. $34,963 $2,436 $7,677 $0 $0 $45,076 $4,264 $0 $5,554 $54,895 $107 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $30,702 $0 $5,308 $0 $0 $36,010 $3,455 $0 $3,947 $43,412 $84 8.2 Turbine Plant Auxiliaries $213 $0 $489 $0 $0 $703 $69 $0 $77 $849 $2 8.3a Condenser & Auxiliaries $3,378 $0 $1,079 $0 $0 $4,457 $426 $0 $488 $5,372 $10 8.3b Air Cooled Condenser $30,958 $0 $6,207 $0 $0 $37,164 $3,716 $0 $8,176 $49,057 $95 8.4 Steam Piping $4,782 $0 $3,364 $0 $0 $8,146 $700 $0 $2,211 $11,057 $21 8.9 TG Foundations $0 $1,059 $1,790 $0 $0 $2,849 $270 $0 $936 $4,054 $8 SUBTOTAL 8. $70,034 $1,059 $18,237 $0 $0 $89,329 $8,637 $0 $15,835 $113,801 $221
9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,767 $0 $1,122 $0 $0 $6,889 $656 $0 $1,132 $8,677 $17 9.2 Circulating Water Pumps $1,500 $0 $99 $0 $0 $1,599 $135 $0 $260 $1,993 $4 9.3 Circ.Water System Auxiliaries $129 $0 $18 $0 $0 $148 $14 $0 $24 $186 $0 9.4 Circ.Water Piping $0 $5,400 $1,400 $0 $0 $6,800 $615 $0 $1,483 $8,897 $17 9.5 Make-up Water System $309 $0 $442 $0 $0 $751 $72 $0 $165 $988 $2 9.6 Component Cooling Water Sys $637 $762 $542 $0 $0 $1,942 $182 $0 $425 $2,549 $5 9.9 Circ.Water System Foundations $0 $1,977 $3,361 $0 $0 $5,339 $506 $0 $1,753 $7,598 $15 SUBTOTAL 9. $8,342 $8,140 $6,985 $0 $0 $23,467 $2,180 $0 $5,242 $30,889 $60 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

446 

### Exhibit 3

- 149 Case S4B Total Plant Cost Summary Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09 Project: Low Rank Western Coal Baseline Study

Case: Case S4B - ConocoPhillips IGCC w/ CO2 Plant Size: 515.11 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $18,675 $0 $9,209 $0 $0 $27,884 $2,679 $0 $3,056 $33,620 $65 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $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 10.4 High Temperature Ash Piping $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 10.6 Ash Storage Silos $618 $0 $672 $0 $0 $1,290 $125 $0 $212 $1,628 $3 10.7 Ash Transport & Feed Equipment $829 $0 $200 $0 $0 $1,029 $96 $0 $169 $1,293 $3 10.8 Misc. Ash Handling Equipment $1,280 $1,568 $469 $0 $0 $3,317 $316 $0 $545 $4,177 $8 10.9 Ash/Spent Sorbent Foundation $0 $55 $69 $0 $0 $123 $12 $0 $40 $175 $0 SUBTOTAL 10. $21,401 $1,623 $10,619 $0 $0 $33,643 $3,228 $0 $4,023 $40,893 $79
11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $942 $0 $932 $0 $0 $1,874 $179 $0 $205 $2,259 $4 11.2 Station Service Equipment $4,921 $0 $443 $0 $0 $5,365 $495 $0 $586 $6,445 $13 11.3 Switchgear & Motor Control $9,098 $0 $1,655 $0 $0 $10,752 $997 $0 $1,762 $13,512 $26
11.4 Conduit & Cable Tray $0 $4,226 $13,942 $0 $0 $18,168 $1,757 $0 $4,981 $24,907 $48 11.5 Wire & Cable $0 $8,075 $5,306 $0 $0 $13,381 $972 $0 $3,588 $17,941 $35 11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,154 $308 $0 $519 $3,981 $8
11.7 Standby Equipment $232 $0 $227 $0 $0 $459 $44 $0 $75 $579 $1 11.8 Main Power Transformers $18,647 $0 $143 $0 $0 $18,790 $1,421 $0 $3,032 $23,243 $45 11.9 Electrical Foundations $0 $155 $408 $0 $0 $563 $54 $0 $185 $802 $2 SUBTOTAL 11. $33,841 $13,137 $25,530 $0 $0 $72,507 $6,227 $0 $14,935 $93,669 $182
12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $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 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,110 $0 $741 $0 $0 $1,852 $175 $93 $318 $2,438 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $255 $0 $164 $0 $0 $419 $40 $21 $96 $575 $1 12.7 Computer & Accessories $5,923 $0 $190 $0 $0 $6,113 $561 $306 $698 $7,677 $15 12.8 Instrument Wiring & Tubing $0 $2,069 $4,230 $0 $0 $6,299 $534 $315 $1,787 $8,935 $17 12.9 Other I & C Equipment $3,959 $0 $1,923 $0 $0 $5,882 $553 $294 $1,009 $7,739 $15 SUBTOTAL 12. $11,248 $2,069 $7,247 $0 $0 $20,564 $1,864 $1,028 $3,908 $27,364 $53 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $109 $2,327 $0 $0 $2,436 $242 $0 $803 $3,481 $7 13.2 Site Improvements $0 $1,936 $2,573 $0 $0 $4,510 $445 $0 $1,486 $6,441 $13 13.3 Site Facilities $3,470 $0 $3,662 $0 $0 $7,132 $703 $0 $2,350 $10,185 $20 SUBTOTAL 13. $3,470 $2,045 $8,562 $0 $0 $14,077 $1,390 $0 $4,640 $20,107 $39
14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,560 $3,647 $0 $0 $6,208 $571 $0 $1,017 $7,796 $15 14.3 Administration Building $0 $923 $670 $0 $0 $1,593 $142 $0 $260 $1,995 $4
14.4 Circulation Water Pumphouse $0 $165 $87 $0 $0 $252 $22 $0 $41 $316 $1 14.5 Water Treatment Buildings $0 $458 $447 $0 $0 $905 $82 $0 $148 $1,135 $2 14.6 Machine Shop $0 $450 $308 $0 $0 $758 $67 $0 $124 $949 $2
14.7 Warehouse $0 $727 $469 $0 $0 $1,196 $106 $0 $195 $1,497 $3 14.8 Other Buildings & Structures $0 $435 $339 $0 $0 $774 $69 $0 $169 $1,012 $2 14.9 Waste Treating Building & Str. $0 $973 $1,860 $0 $0 $2,833 $264 $0 $619 $3,716 $7 SUBTOTAL 14. $0 $6,957 $7,977 $0 $0 $14,934 $1,360 $0 $2,664 $18,958 $37

TOTAL COST $821,003 $69,492 $323,505 $0 $0 $1,214,001 $113,822 $69,732 $221,967 $1,619,522 $3,144 TOTAL PLANT COST SUMMARYCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

447 

### Exhibit 3

- 150 Case S4B Owner’s Costs

Owner's Costs $x1000 $/kW Preproduction Costs 6 Months Fixed O&M $15,260 $30 1 Month Variable O&M $4,088 $8 25% of 1 Months Fuel Cost at 100% CF $937 $2 2% of TPC $32,390 $63 Total $52,676 $102

Inventory Capital 60 day supply of consumables at 100% CF $7,986 $16 0.5% of TPC (spare parts) $8,098 $16 Total $16,084 $31

Initial Cost for Catalyst and Chemicals $7,532 $15 Land $900 $2 Other Owner's Costs $242,928 $472 Financing Costs $43,727 $85

Total Owner's Costs $363,846 $706 Total Overnight Cost (TOC) $1,983,369 $3,851 TASC Multiplier 1.140 Total As-Spent Cost (TASC) $2,261,041 $4,390Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

448 

### Exhibit 3

- 151 Case S4B Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case S4B - ConocoPhillips IGCC w/ CO2 Heat Rate-net (Btu/kWh): 11,223 MWe-net: 515 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total

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-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $12.257 Maintenance Labor Cost $18,102,733 $35.143 Administrative & Support Labor $6,104,060 $11.850 Property Taxes and Insurance $32,390,449 $62.881 TOTAL FIXED OPERATING COSTS $62,910,750 $122.131 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $33,033,881 $0.00915

Consumables Consumption Unit Initial Initial /Day Cost Cost

Water (/1000 gallons) 0 2,867 1.08 $0 $905,553 $0.00025

Chemicals

MU & WT Chem. (lb) 0 17,081 0.17 $0 $863,203 $0.00024 Carbon (Mercury Removal) (lb) 116,627 160 1.05 $122,478 $48,991 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,257 4.29 498.83 $3,120,990 $624,198 $0.00017 Selexol Solution (gal) 320,048 102 13.40 $4,288,080 $397,550 $0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Aqueous Ammonia (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 0.87 131.27 $0 $33,524 $0.00001 Subtotal Chemicals $7,531,548 $1,967,466 $0.00055

Other

Supplemental Fuel (MBtu) 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 Catalyst (lb.) 0 160 0.42 $0 $19,457 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 700 16.23 $0 $3,315,235 $0.00092 Subtotal Waste Disposal $0 $3,334,692 $0.00092

By-products & Emissions

Sulfur (tons) 0 59 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,531,548 $39,241,592 $0.01087

Fuel (ton) 0 8,101 15.22 $0 $35,993,745 $0.00997Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

449 

### 3.6 IGCC CASE SUMMARY A summary of the results of the twelve IGCC plant configurations modeled in this study is presented in Exhibit 3

- 152

. The normalized components of TOC and overall TASC are shown for each plant configuration in Exhibit 3

- 153 . The TOC, which is used for COE calculations, is the TPC plus owner’s costs. The following conclusions can be drawn:

**•** The TOC is higher for the North Dakota elevation lignite coal cases as c ompared to the Montana elevation PRB coal cases by approximately 9 percent.

**•** The TOC increase to add CO 2 

### capture is approximately 3 8 percent.

The COE results are shown in Exhibit 3

- 154 with the capital cost, fixed operating cost, variable operating cost, and fuel cost shown separately. In the capture cases, the CO 2 

### TS&M costs are also shown as a separate bar segment. The following conclusions can be drawn:

**•** The COEs for the Shell and Siemens systems are higher than TRIGTM and CoP for both capture and non

- capture cases. Note that TRIGTM and CoP were only studied for PRB coal and TRIGTM with capture only achieved 83 percent carbon capture.

**•** TRIGTM is the only technolog y evalua ted that has not been demonstrated at commercial scale. For this reason, TRIGTM COEs are subject to a greater level of uncertainty than the other technologies in the gr oup.

**•** T he COE is dominated by capital charges in all cases. The capital cost component o f COE ranges from 61 to 66 percent for IGCC cases.

**•** The fuel cost component is relatively minor in all cases, ranging from 7 to 10 percent of the COE for IGCC cases.

**•** The CO 2 

### TS&M component adds approximately 5 percent to the COE.

**•** The COE increases by 40 t o 46% percent for IGCC plants when CO 2 

### capture is added.

**•** The COE is generally lower for Montana PRB cases compared to the North Dakota lignite cases.

Exhibit 3

- 155 shows the COE sensitivity to fuel costs. The solid lines are the COE of non

capture cases. The dotted lines are the capture cases. As expected, all cases show a linear decrease in COE with the decrease in coal prices. As the price for PRB coal decreases from $0.89 to $0/MMBtu, the average COE decreases from 81 to 73 mills/kWh for the non

- capture PRB cases and from 115 to 105 mills/kWh for the PRB capture cases

. As the price for ND lignite coal decreases from $0.8 3 to $0/MMBtu, the average COE decreases from 85 to 78 mills/kWh for the non

- capture lignite cases and from 123 to 113 mills/kWh for the lignite capture cases

.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

450 

### Exhibit 3

- 152 Estimated Performance and Cost Results for IGCC Cases

PERFORMANCE S1A L1A S1B L1B S2A S2B S3A L3A S3B L3B S4A S4B
CO 2 Capture No No Yes Yes No Yes No No Yes Yes No Yes Gross Power Output (kW e ) 696,700 752,600 663,400 713,300 652,700 621,300 622,200 678,800 634,700 676,900 738,300 727,200 Auxiliary Power Requirement (kW e ) 124,020 135,900 191,790 213,240 107,280 160,450 117,480 135,680 189,410 210,390 133,460 212,130 Net Power Output (kW e ) 572,680 616,700 471,610 500,060 545,420 460,850 504,720 543,120 445,290 466,510 604,840 515,070 Coal Flowrate (lb/hr) 542,713 760,093 585,970 814,029 545,197 577,946 531,119 743,918 579,796 801,651 656,228 675,058 HHV Thermal Input (kW th ) 1,362,134 1,474,011 1,470,704 1,578,608 1,368,368 1,450,564 1,333,034 1,442,644 1,455,207 1,554,603 1,647,041 1,694,303 Net Plant HHV Efficiency (%) 42.0% 41.8% 32.1% 31.7% 39.9% 31.8% 37.9% 37.6% 30.6% 30.0% 36.7% 30.4% Net Plant HHV Heat Rate (Btu/kWh) 8,116 8,156 10,641 10,772 8,560 10,740 9,012 9,063 11,151 11,371 9,292 11,224 Raw Water Withdrawal (gpm/MW net ) 3.1 3.0 7.2 7.8 3.7 6.5 4.5 4.0 9.0 8.9 5.4 8.4 Process Water Discharge (gpm/MW net ) 0.8 0.8 1.4 1.6 0.8 1.0 1.1 1.1 1.6 1.7 1.1 1.5 Raw Water Consumption (gpm/MW net ) 2.3 2.2 5.9 6.2 2.9 5.5 3.4 2.9 7.4 7.2 4.3 6.9
CO 2 Emissions (lb/MMBtu) 214 219 22 22 211 36 214 219 22 22 213 22
CO 2 Emissions (lb/MWh gross ) 1,426 1,461 165 170 1,507 287 1,563 1,585 172 175 1,620 174
CO 2 Emissions (lb/MWh net ) 1,735 1,783 233 242 1,803 386 1,927 1,981 246 255 1,977 245
SO 2 Emissions (lb/MMBtu) 0.0023 0.0023 0.0009 0.0010 0.0019 0.0009 0.0039 0.0021 0.0009 0.0010 0.0016 0.0009
SO 2 Emissions (lb/MWh gross ) 0.015 0.015 0.007 0.007 0.013 0.007 0.029 0.016 0.007 0.008 0.012 0.007 NOx Emissions (lb/MMBtu) 0.062 0.063 0.050 0.049 0.059 0.049 0.061 0.061 0.051 0.050 0.052 0.044 NOx Emissions (lb/MWh gross ) 0.412 0.418 0.381 0.371 0.422 0.390 0.444 0.445 0.397 0.391 0.398 0.348 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 PM Emissions (lb/MWh gross ) 0.047 0.047 0.054 0.054 0.051 0.057 0.052 0.051 0.056 0.056 0.054 0.056 Hg Emissions (lb/TBtu) 0.351 0.560 0.351 0.560 0.351 0.351 0.351 0.560 0.351 0.560 0.351 0.351 Hg Emissions (lb/MWh gross ) 2.34E-06 3.74E-06 2.66E-06 4.23E-06 2.51E-06 2.80E-06 2.57E-06 4.06E-06 2.75E-06 4.39E-06 2.67E-06 2.79E-06
COST Total Plant Cost (2007$/kW) 2,506 2,539 3,480 3,584 2,236 3,019 2,610 2,656 3,533 3,626 2,265 3,144 Total Overnight Cost (2007$/kW) 3,056 3,094 4,253 4,378 2,728 3,691 3,185 3,239 4,318 4,430 2,771 3,851
**Bare Erected Cost** 1,914 1,941 2,610 2,692 1,692 2,228 2,006 2,044 2,654 2,730 1,737 2,357 **Home Office Expenses** 177 179 242 250 157 207 186 189 247 254 162 221 **Project Contingency** 343 349 486 502 305 421 359 367 493 508 306 431 **Process Contingency** 72 69 142 141 83 164 60 56 139 135 60 135
**Owner's Costs** 550 556 773 794 492 672 575 583 785 804 505 706 Total Overnight Cost (2007$x1,000) 1,750,189 1,908,200 2,005,883 2,189,363 1,488,063 1,701,132 1,607,607 1,759,016 1,922,741 2,066,464 1,675,790 1,983,369 Total As Spent Capital (2007$/kW) 3,484 3,527 4,849 4,991 3,110 4,208 3,631 3,692 4,922 5,050 3,159 4,390 COE (mills/kWh, 2007$) 1 83.2 83.5 119.7 121.9 74.5 105.2 86.8 87.3 121.7 123.7 78.7 112.3
**CO 2**  **TS&M Costs** 0.0 0.0 6.0 5.7 0.0 5.9 0.0 0.0 6.3 6.2 0.0 5.8
**Fuel Costs** 7.2 6.7 9.5 8.9 7.6 9.5 8.0 7.5 9.9 9.4 8.3 10.0
**Variable Costs** 8.0 8.2 10.6 11.1 6.8 8.8 8.2 8.4 10.6 11.1 8.3 10.9
**Fixed Costs** 13.7 13.6 18.3 18.6 11.8 15.5 14.1 14.0 18.4 18.6 13.0 17.4 **Capital Costs** 54.2 54.9 75.4 77.6 48.4 65.4 56.5 57.4 76.6 78.5 49.1 68.3 LCOE (mills/kWh, 2007$) 1 105.4 105.8 151.8 154.5 94.5 133.3 110.0 110.7 154.3 156.9 99.8 142.4 Shell IGCC Cases TRIG IGCC Cases Siemens IGCC Cases CoP IGCC Cases

1 CF is 80% for IGCCCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

451 

### Exhibit 3

- 153 Plant Capital Costs

3,056 4,253

2,728 3,691

3,185 4,318

2,771 3,851

3,094 4,378

3,239 4,430

3,484 4,849

3,110 4,208

3,631 4,922

3,159 4,390

3,527 4,991

3,692 5,050

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/CapTOC or TASC ($/kW) TASC
Owner's Cost Process Contingency Project Contingency Home Office Expense
Bare Erected Cost North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

452 

### Exhibit 3

- 154 COE by Cost Component

54.2 75.4

48.4 65.4
56.5 76.6

49.1 68.3

54.9 77.6

57.4 78.5 13.7 18.3

11.8 15.5

14.1 18.4

13.0 17.4

13.6 18.6

14.0 18.6

8.0 10.6

6.8 8.8

8.2 10.6

8.3 10.9

8.2 11.1

8.4 11.1

7.2 9.5

7.6 9.5

8.0 9.9

8.3 10.0

6.7 8.9

7.5 9.4 6.0

5.9 6.3

5.8 5.7 6.2

83.2 119.7

74.5 105.2

86.8 121.7

78.7 112.3

83.5 121.9

87.3 123.7

0 20 40 60 80 100 120 140

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensCOE (2007 mills/kWh) CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital Costs North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

453 

### Exhibit 3

- 155 COE Sensitivity to Fuel Costs

0 20 40 60 80 100 120 140 160

0.0 0.5 1.0 1.5 2.0 2.5COE (2007 mills/kWh)

Coal Price ($/MMBtu) Siemens Lignite w/Capture Shell Lignite w/Capture

Siemens PRB w/Capture

Shell PRB w/Capture CoP PRB w/Capture

TRIG PRB w/Capture

Siemens Lignite

Siemens PRB

Shell Lignite

Shell PRB

CoP PRB

TRIG PRB Capacity Factor = 85% for all cases Study Coal Costs: Lignite = $0.83/MMBtu PRB = $0.89/MMBtuCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

454 

### The sensitivity of COE to CF is shown in Exhibit 3

- 156

. CF is equal to availability since it was assumed that the plants are able to operate at 100 percent capacity whenever power production is needed. The solid lines are the COE of non

- capture cases. The dotted lines are the capture

cases. All cases show a decrease in COE with the increase in CF. As the CF increases from 80 to 100 percent, the average COE decreases from 81 to 66 mills/kWh for the non

- capture PRB cases and from 115 to 94 mill s/kWh for the CO 2 

### capture PRB cases. The average COE decreases from 85 to 70 mills/kWh for the non

- capture lignite cases and from 123 to 100 mills/kWh for the lignite capture cases.

As presented in Section 2.6 the cost of CO 2 

### avoided was compared in two ways, relative to the analogous plant design and compared to a baseline SC PC plant utilizing the same coal. The results for the IGCC carbon capture cases are shown in Exhibit 3

- 157 . The cost of CO 2 

### avoided compared to the analogous non

- capture design averages $ 45 /ton, with a range of $ 40 /ton

– $ 53 /ton. The cost of CO 2 

### avoided, compared to the baseline SC PC non

- capture (A) design, was determined using results available in Exhibit 2

- 22 and averages $ 70 /ton, with a range of $ 63 /ton

- $ 77 /ton. The analogous CO 2 

### avoided costs are lower for the Montana PRB than the North Dakota lignite cases , mainly because of the capital cost increase in the lignite fuel cases

, as well as the additional cost for fuel. The cost of CO 2 

### avoided, compared t o the baseline SC PC plant, follows the same general trend as the COE for each of the cases, after accounting for the TRIGTM case only achieving 83 percent overall carbon removal. The comparison of the analogous Shell designs is affected by the change from a water quench in the CO 2 

### capture case to high temperature syngas heat recovery. This increase s efficiency when high water concentrations are not required for the WGS reaction , as is the case for non

- capture cases and also avoid s the expense of h igh temp erature heat exchangers, thus increasing the cost of avoiding carbon for the semi

- analogous Shell cases. Water demand, internal recycles, and raw water consumption, all normalized by net output, are presented in Exhibit 3

- 158 . The following observations can be made:

**•** The raw water usage is lower in the lignite coal cases because of its higher moisture content, and a significant amount of the coal moisture is recovered i n the drying process for dry feed cases and used as internal recycle. Thus, while the water demand is nearly equal in the Montana PRB and North Dakota lignite cases, the water usage is significantly lower when using lignite coal.

**•** The use of the parallel wet/dry cooling system reduces water demand by 36

- 47 percent in the non

- capture cases and by 24

- 30 percent in the CO 2 

### capture cases relative to using a purely wet cooling system. The water savings is less in the CO 2 

### capture cases because a significant amo unt of extraction steam is used in the shift reaction and therefore not condensed in the surface condenser.

**•** The water demand is significantly greater in the CO 2 

### capture cases because one

- half of the condenser load represents a smaller percentage of the tot al water requirements again due primarily to the high shift steam requirement.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

455 

### Exhibit 3

- 156 COE Sensitivity to Capacity Factor

0 50 100 150 200 250 300 350

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%COE (2007 mills/kWh)

Capacity Factor (%) Siemens Lignite w/Capture Shell Lignite w/Capture

Siemens PRB w/Capture
Shell PRB w/Capture CoP PRB w/Capture

TRIG PRB w/Capture

Siemens Lignite

Siemens PRB

Shell Lignite

Shell PRB

CoP PRB

TRIG PRB Study Capacity Factor is 80% for all casesCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

456 

### Exhibit 3

- 157 Cost of CO 2 

### Avoided in IGCC Cases

48.6

43.28 41.6 40.2 52.7

42.2 74.6

62.90 77.6

66.2 67.5 70.6

0 10 20 30 40 50 60 70 80 90 100

Shell PRB w/Capture TRIG PRB w/Capture Siemens PRB w/Capture CoP PRB w/Capture Shell Lignite w/Capture Siemens Lignite w/Capture

PRB LigniteFirst Year CO2Avoided Cost (2007$/ton) Avoided Cost (Analogous Technology w/o Capture Reference)
Avoided Cost (SC PC w/o Capture Reference)

North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

457 

### Exhibit 3

- 158 Normalized Water Usage in IGCC Cases

3.1 7.2

3.7 6.5

4.5 9.0

5.4 8.4

3.0 7.8

4.0 8.9

2.3 5.9

2.9 5.5

3.4 7.4

4.3 6.9

2.2 6.2

2.9 7.2

0 2 4 6 8 10 12 14

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensWater, gpm/MWnet Raw Water Withdrawal

Process Water Discharge

Raw Water Consumption North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

458 

### The environmental targets were described in Section 2.3 . The emissions of SO 2 

### , NOx
, and PM are shown in Exhibit 3

- 159 and mercury emissions are shown in Exhibit 3

- 160 . The following observations can be made:

**•** Emissions o f SO 2 

### are uniformly extremely low. The same environmental target was used as in the bituminous coal cases of Volume 1 of this study , and because the coal sulfur content is significantly lower in the design coals of this study, the resulting SO 2 

### emissions are also significantly lower.

**•** Particulate emissions are the same for each case because it was a study assumption that the combination of cyclones and candle filters would exactly meet the environmental target of 0.0071 lb/MMBtu.

**•** NOx emissions were assumed to be 15 ppmv at 15 percent oxygen in all cases. The resulting emissions on a lb/MMBtu basis vary slightly because of the variable coal feed rates and flue gas volumes generated among cases.

**•** Mercury emissions are constant for each coal type and significan tly below the NSPS limit of 20 x 10 - 6 

### lb/MWh for IGCC systems. The emissions shown in Exhibit 3

- 160 are equivalent to 3.7

– 4.4 x 10 - 6 

### lb/MWh for the four lignite cases (which have the higher Hg concentration of the two coal types) , or a minimum of 78 percent less than NSPS.Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

459 

### Exhibit 3

- 159 Emissions Profile for IGCC Cases

0.002 0.001 0.002 0.001 0.004

0.001 0.002 0.001 0.002 0.001 0.002 0.001 0.062

0.050 0.059

0.049 0.061

0.051 0.052

0.044 0.063

0.049 0.061

0.050

0.007

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensEmissions, lb/MMBtu SO2

NOx

Particulate North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

460 

### Exhibit 3

- 160 Mercury Emission for IGCC Cases

0.351 0.351 0.351 0.351 0.351 0.351 0.351 0.351 0.560 0.560 0.560 0.560

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80

S1A No Cap S1B W/Cap S2A No Cap S2B W/Cap S3A No Cap S3B W/Cap S4A No Cap S4B W/Cap L1A No Cap L1B W/Cap L3A No Cap L3B W/Cap

Shell TRIG Siemens CoP Shell SiemensMercury Emissions, lb/TBtu North Dakota Lignite Coal Elevation: 1,900 ft Montana Powder River Basin Coal Elevation: 3,400 ftCost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

461 

### 4. REFERENCES

1 Coal Specifications for Quality Guidelines, Revision 0, May 31, 2005

2 NETL Power Systems Financial M odel Version 5.0, December 2008

User Guide available at: http://www.netl.doe.gov/business/solicitations/ssc2008/references/PSFM%20User%20G uide.pdf

3 “Annual Energy Outlook 2008,” AEO Reference Case Table 112, EIA, April 2008

4 Personal Communication between John Wimer (NETL) and Diane Kearney (EIA), AEO 2007 Reference Case National Energy Modeling System (NEMS) model forecasted average costs of delivering (transport cost only) to electric utilities in 2010, as shown in the AEO 2007 data provided by the EIA to NETL on March 30, 2007. ( Source: aeo2007.d112106a)

5 “Protection of Environment.” Code of Federal Regulations Title 40, PART 60

— Standards of Performance for New Stationary Sources, Subpart Da

— Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978; Source: 72 FR 32722, June 13, 2007;

6 US EPA Green Book Nonattainment Area Map, http://www.epa.gov/oar/oaqps/greenbk/mapnpoll.html

7 1999 Environmental Protection Agency Information Collection Request Database with Coal Compositions for Over 37,000 Samples

8 CoalFleet User Design Basis Specification for Coal

- Based Integrated Gasifica tion Combined Cycle (IGCC) Power Plants: Version 4, EPRI, Palo Alto, CA: 2006. 1012227

9 Thomas, Greg, “Delivering the IGCC Solution,” GE Energy January 31, 2006

10 Morehead, Harry and Hannemann, Frank, “Siemens Technology Improvements Enhance IGCC Plant E conomics,” Gasification Technologies 2005, San Francisco, CA, October 2005

11 Telephone communication with David Denton, Eastman Chemical Co.

12 Higman, Christopher, DellaVilla, Sal, and Steele, Bob, “The Reliability of Integrated Gasification Combined Cyc le (IGCC) Power Generation Units,” Achema 2006, May 2006

13 “Evaluation of Alternative IGCC Plant Designs for High Availability and Near Zero Emissions: RAM Analysis and Impact of SCR,” EPRI, Palo Alto, CA, 2005, 1010461

14 Cooling Tower Fundamentals, ed. John C. Hensley, 2nd Edition, The Marley Cooling Tower Company, Mission, Kansas, 1985

15 Personal Correspondence with Frank Ortega, Product Manager

– Dry Cooling, Thermal Engineering / GEA Power Cooling, Inc., September 2008Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

462 

### 16 “EPA Technical Development Document for the Final Regulations Addressing Cooling Water Intake Structures for New Facilities,” EPA

- 821

- R

- 01

- 036, November 2001

17 “Cost Estimate Classification System

– As Applied in Engineering, Procurement, and Construction for the Process Industries; TCM Framework 7.3

– Cost Estimating and Budgeting,” AACE International Recommended Practice No. 18R

- 97, 2005

18 “Merit Shop Wage & Benefit Survey,” PAS, Inc., http://www.pas1.com/

19 “Conducting Technical and Economic Eva luations

– As Applied for the Process and Utility Industries; TCM Framework: 3.2

– Asset Planning, 3.3 Investment Decision Making, AACE International Recommended Practice 16R

- 90, 2003

20 Economic Evaluation of CO 2 

### Storage and Sink Enhancement Options, Tenne ssee Valley Authority, NETL and EPRI, December 2002

21 Smith, Lawrence A.
, Gupta, Neeraj, Sass, Bruce M. and Bubenik, Thomas A.,

“ Engineering and Economic Assessment of Carbon Dioxide Sequestration in Saline Formations

, ” Battelle Memorial Institute, 2001

22 Ciferno, Jared P. and McIlvried, Howard, “CO 2 

### Flow Modeling and Pipe Diameter Determination,” February, 2003

23 Economic Evaluation of CO 2 

### Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002

24 Parker, N., “ Using N atural Gas Transmission Pipeline Costs to E stimate Hydrogen Pipeline Costs,” Institute of Transportation Studies, University of California, Davis, CA, 2004.

25 Gresham, R. L., Apt, J., et. al, “ Implications of Compensating Property

- Owners fo r Geologic Seque stration of CO 2 

### ,” Department of Engineering and Public Policy, Carnegie Mellon University, Pittsburgh, PA, 1999.

26 Klass, A.B., Wilson, E.J., “Climate Change and Carbon Sequestration: Assessing a Liability Regime for Long

- Term Storage of Carbon Dioxide ,” 58 Emory Law Journal 103, 2008

27 Senate Bill No. 2095, 61 st Legislative Assembly of North Dakota, January 6 th 

### , 2009

28 House Bill No. 661, Louisiana House of Representatives Regular Session, 2009

29 Enrolled Act No. 20 (Original House Bill No. 58), 60 th Legislature of the State of Wyoming, General Session, 2009Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

463 

### 30 Overview of Monitoring Requirements for Geologic Storage Projects. IEA Greenhouse Gas R&D Programme, Report Number PH4/29, November 2004

31 “ Recommended Project Finance Structures for the Econom ic Analysis of Fossil

- Based Energy Projects ,” DOE/NETL

- 401/090808, September 2008

32 “ Cash Creek Incentives $150 Million ,” Evansville Courier & Press, 2008, http:/ /www.courierpress.com/news/2008/mar/28/cash

- creek

- incentives

- 150

- million/

33 “ No Customer for Controversial Energy Project ,” BusinessNorth.com, http://www.businessnorth.com/exclusives.asp?RI D=2934

34 “Summit Seeks Grant for Clean Coal Power Plant Near Penwell,” mywesttexas.com, September 26, 2009, http://www.mywesttexas.com/news/top_sto ries/article_85e0ec6c

c3ce

- 52b5

- a6cc

- ede89e9fc7d5.html

35 “Proposed Coal

- fired IGCC Power Plant Would Cost $5,500/kW,” Power

- Gen Worldwide, March 19, 2010, http://www.powergenworldwide.com/index/display/articledisplay/4210875418/articles/p

o wergenworldwide/coal

- generation/new

- projects/2010/03/mississippi

- power.html

36 Zuideveld, P.L., “Shell Coal Gasification Process Using Low Rank Coal,” Gasification Technologies Conference, San Francisco, CA, October 2005

37 Private Communication with Greg E . Johnson of Shell Development Corporation, February 5, 2007

38 “Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site,” EPRI, 1014510, October 2006

39 “CO 2 

### Capture in Low Rank Coal Power Plants,” Technical Study 2006/1, IE A Greenhouse Gas R&D Programme, January 2006

40 Pinkston, et al, “Orlando Gasification Project: Demonstration of a 285 MW Coal

- Based Transport Gasifier,” The 31 st 

### International Technical conference on Coal Utilization & Fuel Systems, May 21

- 25, 2006

41 Roge rs, Luke H., et al., “Power from PRB

– Four conceptual IGCC Plant Designs Using the Transport Gasifier,” presented at the Twenty

- Second annual International Pittsburgh Coal Conference, September 13, 2005

42 Eurlings, J. Th. G. M. and Ploeg, J.E.G., “Process Performance of the SCGP at Buggenum IGCC,” Gasification Technologies Conference, San Francisco, CA, October 1999

43 IGCC Puertollano: A Clean Coal Gasification Plant, ELCOGAS, 2001

44 Maurstad, Ola et al., “Impact of Coal Quality and Gasifier Technology on IGCC Performance”Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

464 

### 45 “Lignite

- Fired Power Plant with Optimized Plant Technology (BoA),” RWE Power

46 Pinkston, et al, “Orlando Gasification Project: Demonstration of a 285 MW Coal

- Based Transport Gasifier,” The 31 st 

### International Technical conference on Co al Utilization & Fuel Systems, May 21

- 25, 2006

47 Zuideveld, P.L., “Shell Coal Gasification Process Using Low Rank Coal,” Gasification Technologies Conference, San Francisco, CA, October 2005

48 “The HRL Coal Fired Power Station,” Friends of the Earth Melbo urne, http://www.melbourne.foe.org.au/?q=cc/fphrl , September 2010

49 “Clean Coal Technology for Brown Coal Power Generation: Construction of a 10 MW Demonstration Facility,” The Australian Coal Review, October 1996

50 Kakaras, Emm., et al , “Concept study for 700 o 

### C power plant: using poor quality brown coal with ultra supercritical PF boiler,” National Technical University of Athens, October 2006

51 “Feasibility Study for and Integrated Gasificatio n Combined Cycle Facility at a Texas Site,” EPRI with CPS Energy, Technical Update, October 2006

52 Larson, Eric D., et al, “Synthetic Fuel Production by Indirect Coal Liquefaction,” Energy for Sustainable Development, Volume VII, No. 4, December 2003

53 Universal Industrial Gases, Inc., http://www.uigi.com/cryodist.html

54 Jenkins, Steve, “Real

- World Experience with IGCC

– Lessons Learned in Design, Permitting, Operations and Maintenance,” URS Corporation, Au gust 17, 2005

55 Geosits, Robert F. and Schmoe, Lee A., “IGCC

– The Challenges of Integration, Proceedings of GT2005 ASME Turbo Expo 2005: Power for Land, Sea, and Air, Reno, NV, June 2005

56 Jaeger, Harry, “Plant Design Net Rated 644 MW and 38% HHV on Low Rank Coal,” Gas Turbine World, March

- April 2006

57 Personal communication, Ray Drnevich, Praxair, Inc., ray_drnevich@praxair.com

, November 2002

58 http://www.calgoncarbon.com/bulletins/Mercury_Removal_Gas_Stream s.htmn

59 http://www.calgoncarbon.com/bulletins/HGR

- P.htm

60 http://www.calgoncarbon.com/bulletins/TYPE_HGR.htm

61 “ Process Screening Study of Alternative Gas Treating and Sulfur Removal Systems for IGCC Power Plant Applications, ” EPRI AP

- 5505, December 1987

62 McIntush, Kenneth E. et al., “Status of the First Commercial Applications of CrystaSulf SM 

### : H 2 

### S Removal and Sulfur Recovery from Sour Gas in the Presence of Other Contaminants”Cost and Performance Baseline

– Low Rank, Volume 3a (IGCC Cases)

465 

### 63 CrystaSulf®, CrystaTech’s Breakthrough Sulfur Recovery Technology Removes S ulfur Economically without the Operating Problems of Water

- Based Systems, http://www.crystatech.com/pdf/directreat.pdf

64 “ Final Environmental Impact Statement for the Orlando Gasification Project,” DOE/EIS

0383, January 2007

65 DOE/NETL

- 2007/1281, “Cost and Performance Baseline for Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity, Final Report, Revision 1,” August 2007

66 “ Process Screening Analy sis of Alternative Gas Treating and Sulfur Removal for Gasification, ” Revised Final Report, December 2002, SFA Pacific for NETL

67 Brdar, R. Daniel, and Jones, Robert M. “ GE IGCC Technology and Experience with Advanced Gas Turbines, ” GER

- 4207, GE Power Syst ems, Schenectady, NY , 10/2000

68 GEI

- 41040G, “ Process Specification for Fuel Gases for Combustion in Heavy

- Duty Turbines, ” January 2002

69 GEK

- 4189, “ Design Considerations for Heated Gas Fuel ”

70 Pinkston, et al., “Orlando Gasification Project: Demonstration of a 285 MW Coal

- Based Transport Gasifier,” The 31 st 

### International Technical conference on Coal Utilization & Fuel Systems, May 21

- 25, 2006

71 Bonsu, et al., “Impact of CO 2 

### Capture on Transport Gasifier IGCC Power Plant,” The 31 st 

### International Technical Co nference on Coal Utilization & Fuel Systems, May 21

- 25, 2006