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

March 2011

DOE/NETL

- 201 1 / 1 463

## Disclaimer

This report was prepared as an account of work sponsored by an agency of the
United State s 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 responsibility for the accuracy, completeness, or usefulness of any informatio n, 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 nece ssarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government

o r any agency thereof.

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

COMBUSTION CASES

DOE/NETL

- 201 1 / 1 463

Final Report

March 2011

NETL Contact:

James B. Black

Office of Program Planning & Analysis, Pe rformance Division

National Energy Technology Laboratory

www.netl.doe.govThis page intentionally left blank

## NETL Viewpoint

Background

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

- clea n (―zero‖ emissions), abundant, low

- cost, domestic electricity and energy (including hydrogen) to fuel economic prosperity and strengthen energy security. A broad portfolio of technologies is being developed within the Clean Coal Program to accomplish thi s 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 te chnological progress of recent years has created a remarkable new opportunity for coal . Advances in technology are making it possible to generate power from fossil fuels with great improvements in the effi ciency of energy

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

- term impact of fossil energy use on the Earth’s climate. The objective of the Clean Coal RD&D Program is to build on these advances and bring these building blocks together into a

new, rev olutionary 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 performance for Pulverized Coal (PC) Combustion and Circulating Fluidized Bed (CFB) Combustion 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 this 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 projects, 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. T he 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 cont ent 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 and sequester greenhouse gases (GHGs). Improved efficiencies and reduced costs are requ ired 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 analysis provide a starting point from which to measure the progress
of RD&D achievements.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

I 

# Table of Contents

TABLE OF CONTENTS

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

................................ ................................ ................................ ................... III
PREPARED BY

................................ ................................ ................................ ....................... VIII
ACKNOWLEDGMENTS

................................ ................................ ................................ .......... IX
LIST OF ACRONYMS AND ABBREVIATIONS

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

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

................................ ................................ ................................ ..................... 4

Water Use

................................ ................................ ................................ ................................ . 4
Cost Results

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

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

................................ ................................ ................................ .............. 11
Overall Conclusions

................................ ................................ ................................ ............... 17

1. INTRODUCTION

................................ ................................ ................................ ................ 21
2. GENERAL EVALUATION B ASIS

................................ ................................ ................... 23
2.1 S ITE C HARACTERISTICS

................................ ................................ ................................ .. 23
2.2 C OAL C HARACTERISTICS

................................ ................................ ................................ 25
2.3 E NVIRONMENTAL T ARGETS

................................ ................................ ............................ 28
2.4 C APACITY F ACTOR

................................ ................................ ................................ ......... 31
2.5 R AW W ATER W ITHDRAWAL AND C ONSUMPTION

................................ ........................... 31
2.6 C OST E STIMATING M ETHODOLOGY

................................ ................................ ................ 32
2.6.1 Capital Co sts

................................ ................................ ................................ .............. 32
2.6.2 Operations and Maintenance Costs

................................ ................................ ........... 41
2.6.3 CO 2 Transport, Storage and Monitoring

................................ ................................ ... 42
2.6.4 Finance Structure, Discounted Cash Flow Analysis, and COE

................................ 45

3. COMBUSTION POWER PLA NT PROCESS DESCRIPTI ONS

................................ ... 53
3.1 C OMMON P ROCESS A REAS FOR A LL C OMBUSTION C ASES

................................ .............. 53
3.1.1 Coal and Sorbent Receiving and Storage

................................ ................................ .. 53
3.1.2 Steam Generator and A ncillaries

................................ ................................ ............... 54
3.1.3 Particulate Control

................................ ................................ ................................ .... 54
3.1.4 Carbon Dioxide Recovery Facility

................................ ................................ ............ 54
3.1.5 Power Generation

................................ ................................ ................................ ...... 58
3.1.6 Balance of Plant

................................ ................................ ................................ ......... 59
3.1.7 Accessory Electric Plant

................................ ................................ ............................ 63
3.1.8 Instrumentation and Control

................................ ................................ ...................... 63
3.2 C OMMON P ROCESS A REAS FOR PC C ASES O NLY

................................ ............................ 64
3.2.1 Steam Generator and Ancillaries

................................ ................................ ............... 64

3.2.2 NO
x Control System

................................ ................................ ................................ ... 65
3.2.3 Flue Gas Desulfurization

................................ ................................ ........................... 66
3.2.4 Mercury Removal

................................ ................................ ................................ ....... 67
3.3 C OMMON P ROCESS A REAS FOR CFB C ASES O NLY

................................ ......................... 68
3.3.1 Steam Generator and Ancillaries

................................ ................................ ............... 68
3.3.2 NO
x Control System

................................ ................................ ................................ ... 69
3.3.3 Mercury Removal

................................ ................................ ................................ ....... 69

4. PC CASES

................................ ................................ ................................ ............................ 71Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

II 4.1 SC & USC PC N ON

- C APTURE C ASES (PRB AND LIGNITE)

................................ ......... 71
4.1.1 Process Description

................................ ................................ ................................ ... 71
4.1.2 Key S

ystem Assumptions

................................ ................................ ............................ 82
4.1.3 Sparing Philosophy

................................ ................................ ................................ .... 83
4.1.4 Cases S12A, L12A, S13A, and L13A Performance Results

................................ ....... 83
4.1.5 PC Cases without CO 2 Capture Equipment Lists

................................ .................... 101
4.1.6 PC Cases without CO 2 Capture

– Cost Estimating

................................ ................. 113
4.2 SC & USC PC CO 2 C APTURE C ASES (PRB AND L IGNITE )

................................ ........... 142
4.2.1 Process Description

................................ ................................ ................................ . 142
4.2.2 Key System Assumptions

................................ ................................ .......................... 152
4.2.3 Sparing Philosophy

................................ ................................ ................................ .. 153
4.2.4 Cases S12B, L12B, S13B, and L13B Performance Results

................................ ..... 153
4.2.5 PC Cases with CO 2 Capture Equipment Lists

................................ ......................... 171
4.2.6 PC Cases with CO 2 Capture

– Cost Estimating

................................ ...................... 184

5. CIRCU LATING FLUIDIZED BED COMBUSTION CASES

................................ ...... 213
5.1 SC CFB N ON

- C APTURE C ASES (PRB AND L IGNITE )

................................ .................... 213
5.1.1 Process Description

................................ ................................ ................................ . 213
5.1.2 Key System Assumptions

................................ ................................ .......................... 220
5.1.3 Sparing Philosophy

................................ ................................ ................................ .. 221
5.1.4 Cases S22A and L 22A Performance Results

................................ ........................... 221
5.1.5 CFB Cases without CO 2 Capture Equipment Lists

................................ .................. 232
5.1.6 CFB Cases without CO 2 Capture

– Cost Estimat ing

................................ ............... 239
5.2 SC CFB CO 2 C APTURE C ASES (PRB AND L IGNITE )

................................ ..................... 254
5.2.1 Process Description

................................ ................................ ................................ . 254
5.2.2 Key System Assumptions

................................ ................................ .......................... 260
5.2.3 Sparing Philosophy

................................ ................................ ................................ .. 261

5.2.4 Cases S22B and L22B Performance Results

................................ ........................... 261
5.2.5 CFB Cases with CO 2 Capture Equipment Lists

................................ ....................... 272
5.2.6 CFB Cases with CO 2 Capture

– Cost Estimating

................................ .................... 279

6. SENSITIVITY TO BITUM INOUS BASELINE CASE 12A MEA SYSTEM

............. 295
6.1 B ASIS FOR S ENSITIVITY A NALYSIS

................................ ................................ ............... 295
6.2 P ERFORMANCE

................................ ................................ ................................ .............. 295
6.3 C OST E STIMATING

................................ ................................ ................................ ........ 301

7. SUMMARY

................................ ................................ ................................ ........................ 309
7.1 P ERFORMANCE

................................ ................................ ................................ .............. 309
7.2 C OST R ESULTS

................................ ................................ ................................ .............. 312
7.3 E NVIRONMENTAL P ERFORMANCE

................................ ................................ ................. 317
7.3.1 Emissions

................................ ................................ ................................ ................. 317
7.3.2 Water Usage

................................ ................................ ................................ ............. 321

8. REFERENCES

................................ ................................ ................................ ................... 325Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

III 

# List of Exhibits

Exhibit ES

- 1 Case Descriptions

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

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

................................ ................................ ................................ ................................ ................. 3
Exhibit ES

- 3 Net Plant Efficiency (HHV Basis)

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

- 4 Raw Water Withdrawal and Consumption

................................ .............................. 6
Exhibit E S

- 5 Plant Capital Costs

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

- 6 Economic Parameters Used to Calculate COE

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

- 7 COE by Cost Component

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

- 8 COE Sensitivity to Coal Cost

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

- 9 COE Sensitivity to Capacity Factor

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

- 10 First Year CO 2 Avoided Cost

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

- 11 Study Environmental Targets

................................ ................................ ............... 16
Exhib it ES

- 12 SO 2 , NOx and Particulate Emission Rates

................................ ........................... 18
Exhibit ES

- 13 Mercury Emission Rates

................................ ................................ ...................... 19
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 C haracteristics

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

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

................................ ................................ ................................ ........................ 26
Exhi bit 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,

Reconstruc ted, or Modified After February 28, 2005

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

- 7 NSPS Mercury Emission Limits

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

- 8 Environmental Target

................................ ................................ ............................... 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

................................ ........................... 38
Exhibit 2

- 12 TASC/TOC Factors

................................ ................................ ................................ 38
Exhibit 2

- 13 Owner’s Costs Included in TOC

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

- 14 CO 2 Pipeline Specification

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

- 15 Deep Saline Aquifer Specification

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

- 16 Global Economic Assumptions

................................ ................................ .............. 46
Exhibit 2

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

........ 47
Exhibit 2

- 18 Illustration of COE Solutions using DCF Analysis

................................ ................ 49
Exhibit 2

- 19 PC with CCS in Current 2007 Dollars

................................ ................................ .... 49
Exhibit 2

- 20 Capital Charge Factors for COE Equation

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

- 21 COE and LCOE Summary

................................ ................................ ...................... 51
Exhibit 3

- 1 Fluor Econamine FG Plus SM Typical Flow Diagram

................................ ............... 56
Exhibit 3

- 2 CO 2 Compressor Interstage Pressures

................................ ................................ ...... 58
Exhibit 4

- 1 Cases S12A, L12A, S13A, and L13A Process Flow Diagram

................................ . 73
Exhibit 4

- 2 Case S12A Stream Table

................................ ................................ .......................... 74
Exhibit 4

- 3 Case L12A Stream Table

................................ ................................ .......................... 76
Exhibit 4

- 4 Case S13A Stream Table

................................ ................................ .......................... 78Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

IV Exhibit 4

- 5 Case L13A Stre am Table

................................ ................................ .......................... 80
Exhibit 4

- 6 PC Cases without CO 2 Capture Study Configuration Matrix

................................ ... 82
Exhibit 4

- 7 PC Cases without CO 2 Capture Pl ant Performance Summary

................................ . 84
Exhibit 4

- 8 PC Cases without CO 2 Capture Air Emissions

................................ ......................... 85
Exhibit 4

- 9 Cases S12A and L12A Carbon Ba lance

................................ ................................ ... 86
Exhibit 4

- 10 Cases S13A and L13A Carbon Balance

................................ ................................ . 87
Exhibit 4

- 11 Cases S12A and L12A Sulfur Balance

................................ ................................ ... 87
Exhibit 4

- 12 Cases S13A and L13A Sulfur Balance

................................ ................................ ... 87
Exhibit 4

- 13 Case S12A Water Balance

................................ ................................ ...................... 88
Exhibit 4

- 14 Case L12A Water Balance

................................ ................................ ...................... 88
Exhibit 4

- 15 Case S13A Water Balance

................................ ................................ ...................... 88
Exhibit 4

- 16 Case L13A Water Ba lance

................................ ................................ ...................... 89
Exhibit 4

- 17 Case S12A Boiler and Gas Cleanup System Heat and Mass Balance Diagram

..... 91
Exhibit 4

- 18 Case S12A Power Bl ock System Heat and Mass Balance Diagram

...................... 92
Exhibit 4

- 19 Case L12A Boiler and Gas Cleanup System Heat and Mass Balance Diagram

..... 93
Exhibit 4

- 20 Case L12A Power Block System Heat and Mass Balance Diagram

...................... 94
Exhibit 4

- 21 Case S13A Boiler and Gas Cleanup System Heat and Mass Balance Diagram

..... 95
Exhibit 4

- 22 Case S13A Power Block System Heat and Mass Balance Diagram

...................... 96
Exhibit 4

- 23 Case L13A Boiler and Gas Cleanup System Heat and Mass Balance Di agram

..... 97
Exhibit 4

- 24 Case L13A Power Block System Heat and Mass Balance Diagram

...................... 98
Exhibit 4

- 25 Cases S12A and L12A Energy Ba lance (0°C [32°F] Reference)

........................... 99
Exhibit 4

- 26 Cases S13A and L13A Energy Balance (0°C [32°F] Reference)

......................... 100
Exhibit 4

- 27 Case S 12A TPC Summary

................................ ................................ .................... 114
Exhibit 4

- 28 Case S12A Total Plant Cost Details

................................ ................................ ..... 115
Exhibit 4

- 29 Case S12A Owner’s Costs

................................ ................................ .................... 119
Exhibit 4

- 30 Case S12A Initial and Annual O&M Costs

................................ .......................... 120
Exhibit 4

- 31 Case L12A Total Plant Cost Summary

................................ ................................ . 121
Exhibit 4

- 32 Case L12A Total Plant Cost Details

................................ ................................ ..... 122
Exhibit 4

- 33 Case L12A Owner’s Costs

................................ ................................ .................... 126
Exhibit 4

- 34 Case L12A Initial and Annual O&M Costs

................................ .......................... 127
Exhibit 4

- 35 Case S13A Total Plant Cost Summary

................................ ................................ . 128
Exhibit 4

- 36 Case S13A Total Plant Cost Details

................................ ................................ ..... 129
Exhibit 4

- 37 Case S13A Owner’s Costs

................................ ................................ .................... 133
Exhibit 4

- 38 Case S13A Initial and Annual O&M Cost s

................................ .......................... 134
Exhibit 4

- 39 Case L13A Total Plant Cost Summary

................................ ................................ . 135
Exhibit 4

- 40 Case L13A Total Plant Cost Details

................................ ................................ ..... 136
Exhibit 4

- 41 Case L13A Owner’s Costs

................................ ................................ .................... 140
Exhibit 4

- 42 Case L13A Initial and Annual O&M Costs

................................ .......................... 141
Exhibit 4

- 43 Cases S12B, L12B, S13B, and L13B Process Flow Diagram

.............................. 143
Exhibit 4

- 44 Case S12B Stream Table

................................ ................................ ...................... 144
Exhibit 4

- 45 Case L12B Stream Table

................................ ................................ ...................... 146
Exhibit 4

- 46 Case S13B Stream Table

................................ ................................ ...................... 148
Exhibit 4

- 47 Case L13B Stream Table

................................ ................................ ...................... 150
Exhibit 4

- 48 PC Cases with CO 2 Capture Study Configuration Matrix

................................ .... 152
Exhibit 4

- 49 PC Cases with CO 2 Capture Plant Performance Summary

................................ .. 154
Exhibit 4

- 50 PC Cases with CO 2 Capture Air Emissions

................................ .......................... 156Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

V Exhibit 4

- 51 Cases S12B and L12B Carbon Balance

................................ ................................ 157
Exhibit 4

- 52 Cases S13B and L13B Carbon Balance

................................ ................................ 157
Exhibit 4

- 53 Cases S12B and L12B Sulfur Balance

................................ ................................ . 158
Exhibit 4

- 54 Cases S13B and L13B Sulfur Balance

................................ ................................ . 158
Exhibit 4

- 55 Case S12B Water Balance

................................ ................................ .................... 159
Exhibit 4

- 56 Case L12B Water Balance

................................ ................................ .................... 159
Exhibit 4

- 57 Case S13B Water Balance

................................ ................................ .................... 159
Exhibit 4

- 58 Case L13B Water Balance

................................ ................................ .................... 160
Exhibit 4

- 59 Case S12B Boiler and Gas Cleanup System Heat and Mass Balance Diagram

... 161
Exhibit 4

- 60 Case S12B Power Block Sy stem Heat and Mass Balance Diagram

..................... 162
Exhibit 4

- 61 Case L12B Boiler and Gas Cleanup System Heat and Mass Balance Diagram

... 163

E xhibit 4

- 62 Case L12B Power Block System Heat and Mass Balance Diagram

.................... 164
Exhibit 4

- 63 Case S13B Boiler and Gas Cleanup System Heat and Mass Balance Diagram

... 165
Exhibit 4

- 64 Case S13B Power Block System Heat and Mass Balance Diagram

..................... 166
Exhibit 4

- 65 Case L13B Boiler and Gas Cleanup System Heat and Mass Balance Dia gram

... 167
Exhibit 4

- 66 Case L13B Power Block System Heat and Mass Balance Diagram

.................... 1 68
Exhibit 4

- 67 Cases S12B and L12B Energy B alance (0°C [32°F] Reference)

......................... 169
Exhibit 4

- 68 Cases S13B and L13B Energy Balance (0°C [32°F] Reference)

......................... 170
Exhibit 4

- 69 Case S12B Total Plant Cost Summary

................................ ................................ . 185
Exhibit 4

- 70 Case S12B Total Plant Cost Details

................................ ................................ ..... 186
Exhibit 4

- 71 Case S12B Owner’s Costs

................................ ................................ .................... 190
Exhibit 4

- 72 Case S12B Initial and Annual O&M Costs

................................ .......................... 191
Exhibit 4

- 73 Case L12B Total Plant Cost Summary

................................ ................................ . 192
Exhibit 4

- 74 Case L12B Total Plant Cost Details

................................ ................................ ..... 193
Exhibit 4

- 75 Case L12B Owner’s Costs

................................ ................................ .................... 197
Exhibit 4

- 76 Case L12B Initial and Annual O&M Costs

................................ .......................... 198
Exhibit 4

- 77 Case S13B Total Plant Cost Summary

................................ ................................ . 199
Exh ibit 4

- 78 Case S13B Total Plant Cost Details

................................ ................................ ..... 200
Exhibit 4

- 79 Case S13B Owner’s Costs

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

- 80 Case S13B Initial and Annual O&M Costs

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

- 81 Case L13B Total Plant Cost Summary

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

- 82 Case L13B Total Plant Cost Details

................................ ................................ ..... 207
Exhibit 4

- 83 Case L13B Owner’s Costs

................................ ................................ .................... 211
Exhibit 4

- 84 Case L13B Initial and Annual O&M Costs

................................ .......................... 212
Exhibit 5

- 1 Cases S22A and L22A Process Flow Diagram

................................ ...................... 215
Exhibit 5

- 2 Case S22A Stream Table

................................ ................................ ........................ 216
Exhibit 5

- 3 Case L22A Stream Table

................................ ................................ ........................ 218
Exhibit 5

- 4 CFB Cases without CO 2 Capture Study Configuration Matrix

.............................. 220
Exhibit 5

- 5 CFB Cases without CO 2 Capture Plant Performance Summary

............................. 222
Exhibit 5

- 6 CFB Cases without CO 2 Capture Air Emissions

................................ .................... 223
Exhi bit 5

- 7 Cases S22A and L22A Carbon Balance

................................ ................................ . 224
Exhibit 5

- 8 Cases S22A and L22A Sulfur Balance

................................ ................................ ... 224
Exhibit 5

- 9 Case S22A Water Balance

................................ ................................ ...................... 225
Exhibit 5

- 10 Case L22A Water Balance

................................ ................................ .................... 225
Exhibit 5

- 11 Case S22A Combustor and Gas Cleanup System Heat and Mass Ba lance Diagram

................................ ................................ ................................ ................................ ............. 227Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

VI Exhibit 5

- 12 Case S22A Power Block System Heat and Mass Balance Diagram

.................... 228
Exhibit 5

- 13 Case L22A Combustor and Gas Cleanup System Heat and Mass Balance Diagram

................................ ................................ ................................ ................................ ............. 229
Exhibit 5

- 14 Case L22A Power Block System Heat and Mass Balance Diagram

.................... 230
Exhibit 5

- 15 Cases S22A and L22A Energy Balance (0°C [32°F] Reference)

......................... 231
Exhibit 5

- 16 Case S22A Total Plant Cost Summary

................................ ................................ . 240
Exhibit 5

- 17 Case S22A Total Plant Cost Details

................................ ................................ ..... 241
Exhibit 5

- 18 Case S22A Owner’s Costs

................................ ................................ .................... 245
Exhibit 5

- 19 Case S22A I nitial and Annual O&M Costs

................................ .......................... 246
Exhibit 5

- 20 Case L22A Total Plant Cost Summary

................................ ................................ . 247
Exhibit 5

- 21 Case L22A Total Plant Cost De tails

................................ ................................ ..... 248
Exhibit 5

- 22 Case L22A Owner’s Costs

................................ ................................ .................... 252
Exhibit 5

- 23 Case L22A Initial and Annual O&M Costs

................................ .......................... 253
Exhibit 5

- 24 Cases S22B and L22B Process Flow Diagram

................................ ..................... 255
Exhibit 5

- 25 Case S22B Stream Table

................................ ................................ ...................... 256
Exhibit 5

- 26 Case L22B Stream Table

................................ ................................ ...................... 258
Exhibit 5

- 27 CFB Cases with CO 2 Capture Study Configuration Matrix

................................ . 260
Exhibit 5

- 28 CFB Cases with CO 2 Capture Plant Performance Summary

................................ 262
Exhibit 5

- 29 CFB Cases with CO 2 Capture Air Emissions

................................ ....................... 263
Exhibit 5

- 30 Cases S22B and L22B Carbon Balance

................................ ................................ 264
Exhibit 5

- 31 Cases S22B and L22B Sulfur Balance

................................ ................................ . 264
Exhibit 5

- 32 Case S22B Water Balance

................................ ................................ .................... 265
Exhibit 5

- 33 Case L22B Water Balance

................................ ................................ .................... 265
Exhibit 5

- 34 Case S22B Combustor and Gas Cleanup System Heat and Mass Balance Diagram

................................ ................................ ................................ ................................ ............. 267
Exhibit 5

- 35 Case S22B Power Block System Heat and Mass Balance Diagram

..................... 268
Exhibit 5

- 36 Case L22 B Combustor and Gas Cleanup System Heat and Mass Balance Diagram

................................ ................................ ................................ ................................ ............. 269
Exhibit 5

- 37 Case L22B Power Block System Heat and Mass Balance Diagram

.................... 270
Exhibit 5

- 38 Cases S22B and L22B Energy Balance (0°C [32°F] Reference)

......................... 271
Exhibit 5

- 39 Case S22B Total Plant Cost Summary

................................ ................................ . 280
Exhibit 5

- 40 Case S22B Total Plant Cost Details

................................ ................................ ..... 281
Exhibit 5

- 41 Case S22B Owner’s Costs

................................ ................................ .................... 285
Exhibit 5

- 42 Case S22B Initial and Annual O&M Costs

................................ .......................... 286
Exhibit 5

- 43 Case L22B Total Plant Cost Summary

................................ ................................ . 287
Exhibit 5

- 44 Case L22B Total Pl ant Cost Details

................................ ................................ ..... 288
Exhibit 5

- 45 Case L22B Owner’s Costs

................................ ................................ .................... 292
Exhibit 5

- 46 Case L22B Initial and Annual O&M Costs

................................ .......................... 293
Exhibit 6

- 1 Bituminous Baseline Case 12A MEA Sensitivity Process Flow Diagram

............. 297
Exhibit 6

- 2 Bituminous Baseline Case 12A Stream Tabl e, SC Unit with CO 2 Capture

........... 298
Exhibit 6

- 3 Bituminous Baseline Case 12A Plant Performance Summary

............................... 300
Exhibit 6

- 4 Bituminous Baseline Case 12A TPC Summary

................................ ..................... 302
Exhibit 6

- 5 Bituminous Baseline Case 12A Total Plant Cost Details

................................ ....... 303
Exhibit 6

- 6 Case S12A Owner’s Costs

................................ ................................ ...................... 307
Exhibit 6

- 7 Bituminous Baseline Case 12A Initial and Annual O&M Costs

............................ 308
Exhibit 7

- 1 Estimated Performance, Emissions, and Cost Results

................................ ............ 310Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

VII Exhibit 7

- 2 Net Plant Efficiency (HHV Basis)

................................ ................................ .......... 311
Exhibit 7

- 3 Total Overnight Cost

................................ ................................ .............................. 314
Exhibit 7

- 4 Cost of Electricity

................................ ................................ ................................ ... 315
Exhibit 7

- 5 Cost of CO 2 Avoided

................................ ................................ .............................. 316
Exhibit 7

- 6 Emissions Profile

................................ ................................ ................................ .... 318
Exhibit 7

- 7 Mercury Emissions

................................ ................................ ................................ . 319
Exhibit 7

- 8 CO 2 Emission

– lb/MWh

................................ ................................ ........................ 320
Exhibit 7

- 9 Normalized Water Usage

– Process Perspective

................................ .................... 322
Exhibit 7

- 10 Normalized Water Usage

– Environmental Perspective

................................ ....... 323Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

VIII 

### 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

Allison Kyle
Booz Allen Hamilton

Norm a J. Kuehn
Booz Allen Hamilton

Eric G. Lewis
Booz Allen Hamilton

Lora L. Pinkerton WorleyParsons

Vasant Shah
Booz Allen Hamilton

Elsy Varghese WorleyParsons

Mark C. Woods
Booz Allen Hamilton

Marc J. Turner
Booz Allen Hamilton

DOE Contract # DE

- FE0004 001Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

IX 

# 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 ; Subtas k 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 sta ff and other past contributors, particularly:

John Wimer, Director of Office of Program Planning & Analysis

Jeffrey Hoffmann

James Black

Michael Matuszewski

Robert James

Robert D. Brasington formerly of Parsons Corporation

The preparers also wish to ackno wledge the valuable input to this study provided by numerous technology suppliers

, but especially Denny McDonald and co

- workers at Babcock &Wilcox Power Generation Group, Inc. However, vendor participation does not in any way imply that the
vendor certifi es or endorses the results of this work.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

X LIST OF ACRONYMS AND ABBREVIATIONS

AACE Association for the Advancement of Cost Engineering

acfm Actual cubic feet per minute

AEO Annual Energy Outlook

BACT Best available control technology

BEC Bare erected cost

BF D Block flow diagram

BFW Boiler feed water

BLS Bureau of Labor Statistics

Btu British thermal unit

Btu/kWh British thermal unit per kilowatt hour

Btu/lb British thermal unit per pound

CAMR Clean Air Mercury Rule

CCF Capital Charge Factor

CDR Carbon Dioxide Recovery

CF Capacity factor

CFB Circulating Fluidized Bed

CL Closed

- loop

cm Centimeter

CO 2 Carbon dioxide

COE Cost of electricity

CS Carbon steel

CWP Circulating water pump

CWS C irculating water system

CWT Cold water temperature

DC Direct current

DCS Dis tributed control system

DOE Department of Energy

EAF Equivalent availability factor

EIA Energy Information Administration

EPA Environmental Protection Agency

EPC Engineer/Procure/Construct

EPCM Engineering/Procurement/Construction Management

ft/min Feet pe r minute

FD Forced draft

FGD Flue g as d esulfurization

FOAK First

- of

- a

- kind

FRP Fiberglass

- reinforced plastic

ft Foot, f

eet ft, w.g. Feet of water gauge

GADS Generating Availability Data System gal Gallon

GDP Gross domestic productCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

XI GJ Gigajoule

GJ/hr Gigajo ule per hour

gpm Gallons per minute h, hr Hour

H 2 Hydrogen

HAP Hazardous air pollutant Hg Mercury

HHV Higher heating value

HP High pressure

HSS Heat stable salts

HVAC Heating, ventilating, and air conditioning

HWT Hot water temperature

Hz Hertz

ICR Informa tion Collection Request

ID Induced draft

IEA International Energy Agency

IGCC Integrated gasification combined cycle

in Inches

IOU Investor

- owned utility

IP Intermediate pressure

ISO International Standards Organization

ITD Initial temperature difference

k g/GJ Kilogram per gigajoule kg/hr Kilogram per hour kJ/kg Kilojoules per kilogram

kPa Kilopascal absolute

kV Kilovolt

kW Kilowatt

kWe Kilowatts electric

kWt Kilowatts thermal

LAER Lowest Achievable Emission Rate

lb Pound

lb/hr Pounds per hour

lb/MMBtu Poun ds per million British thermal units

lb/MWh Pounds per megawatt hour

lb/TBtu Pounds per trillion British thermal units

LCOE Levelized cost of electricity

LF Fn Levelization factor for category n fixed operating cost

LF Vn Levelization factor for category n v ariable operating cost

LHV Lower heating value

LNB Low NOx burner

LP Low

- pressure lpm Liters per minuteCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

XII m Meters

m/min Meters per minute

m 3 /min Cubic meter per minute

md Millidarcy (a measure of permeability)

MCR Maximum continuous rate

MMBtu Million Briti sh thermal units (also shown as 10 6 Btu)

MMBtu/hr Million British thermal units (also shown as 10 6 Btu) per hour

MMscf Million standard cubic feet

MPa Megapascals

MVA Mega volt

- amps
MW Megawatts

MWe Megawatts electric

MWh Megawatt

- hour

N/A Not applicable

N AAQS National Ambient Air Quality Standards

NDL North Dakota Lignite

NEMS National Energy Modeling System

NERC North American Electric Reliability Council

NETL National Energy Technology Laboratory

NOAK N th

- of

- a

- kind

NOx Oxides of nitrogen

NSPS New Source Performance Standards

NSR New Source Review

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

OD Outside diameter

OFA Overfire a ir

OP/VWO Over pressure/valve wide open

PA Primary air

PC Pulverized c oal

PM Particulate matter

POTW Publicly Owned Treatment Works

ppm Parts per million

ppmv Parts per million volume

PRB Powder River Basin coal region

PSD Prevention of Significant Deterio ration psia Pounds per square inch absolute psig Pounds per square inch gage

PTFE Teflon (Polytetrafluoroethylene) Qty Quantity

RDS Research and Development Solutions, LLC

RH ReheaterCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

XIII SC Supercritical

scfm Standard cubic feet per minute

SCR Selective catal ytic reduction process or equipment

SDA Spray d ryer a bsorber

SO 2 Sulfur dioxide

SOx Oxides of sulfur

SNCR Selective non

- catalytic reduction process or equipment

SS Stainless steel

STG Steam turbine generator

tonne Metric t on (1000 kg)

TOC Total overnight cost
TPC Total plant cost tpd Tons per day tph Tons per hour

TS&M Transport, storage and monitoring

USC U ltra

- supercritical

WB Wet bulb

wt% Weight percentCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

1 EXECUTIVE SUMMARY

The objective of this report is to present an accurate, independent assessment of the c ost and

p erformance of L ow

- R ank C oal

- F ired P ower S ystems, specifically pulverized coal (PC) and circulating fluidized bed (CFB) plants, using a consistent technical and economic approach that accurately reflects current or near term market conditio ns. This document is Volume 3b 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 (Vario us Coal Ranks)

Volume 3: Low Rank Coal and Natural Gas to Electricity

Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture

T he cost and performance of the various fossil fuel

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

Capital and operating costs

Overall energy efficiency

Fuel prices

Cost of electricity (COE)

Availability

, reliability

, a nd 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 recent commer cial

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

Twelve combustion power plant configurations were analyzed as listed in Exhibit ES

- 1 . The list includes four PC cases, two super critical (SC) and two ultra

- supercritical (USC) , with and
without carbon dioxide ( CO 2 ) capture; and two CFB plants with and without CO 2 capture.

The methodology included performing steady

- state simulations of the various technologies using the Aspen Plus ® (Aspen) modeling software . The resulting mass and energy balance data from the Aspen model were used to size major pieces of equipment. These equipment sizes formed the basis for cost estimating. Performance and process limits were based upon publishe d reports, information obtained from vendors and users of the technology, performance data from design/build utility projects, and/or best engineering judgment. Capital and operating costs were estimated based on simulation results and through a combinati on of vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. Baseline fuel costs for this analysis were determined using data from the Energy Informa tion Administration’s (EIA) 2008 Annual Energy Outlook (AEO). The first year of capital expenditure ( 2007 )
delivered costs u sed are $0.84/ gigajoule ( GJ ) ($0.89 / million British thermal unit [ MMBtu ] ) forCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

2 Powder River Basin (PRB) coal and $0.79/GJ ($0.83 /MMBtu) for North Dakota L ignite (NDL)

, both on a higher heating va lue (HHV) basis and in June 2007 United States ( U.S. ) dollars.

Exhibit ES

- 1 Case Descriptions

Case Unit

Cycle Steam Cycle,

psig/ F/ F Boiler

Technology Coal NOx Control Sulfur

Removal 1 CO 2

Separation

S12A PC 3500/1100/1100 SC PC PRB LNB + SCR Spray Dry er FGD -

L12A PC 3500/1100/1100 SC PC Lignite LNB + SCR Spray Dry er FGD -

S12B PC 3500/1100/1100 SC PC PRB LNB + SCR Spray Dry er FGD Amine Absorber

L12B PC 3500/1100/1100 SC PC Lignite LNB + SCR Spray Dry er FGD Amine Absorb er

S13A PC 4000/1200/1200 USC PC PRB LNB + SCR Spray Dry er FGD -

L13A PC 4000/1200/1200 USC PC Lignite LNB + SCR Spray Dry er FGD -

S13B PC 4000/1200/1200 USC PC PRB LNB + SCR Spray Dry er FGD Amine Absorber

L13B PC 4000/1200/1200 USC PC Lignite LNB + SCR Spray Dry er FGD Amine Absorber

S22A CFB 3500/1100/1100 SC CFB PRB SNCR in

- bed
limestone -

L22A CFB 3500/1100/1100 SC CFB Lignite SNCR in

- bed
limestone -

S22B CFB 3500/1100/1100 SC CFB PRB SNCR in

- bed
limestone Amine Absorber

L22B CFB 3500/1100/1100 SC CFB Lignite SNCR in

- bed
limestone Amine Absorber

1 In CO 2 capture cases a polishing scrubber is used to reduce SO 2 concentrations to less than 10 ppmv prior to the CO 2 absorber.

All plant configurations were evaluated based on installation at a greenfiel d site (Montana for
PRB cases and North Dakota for NDL cases). Since these are state

- of

- the

- art plants, they will have higher efficiencies than the average power plant population. Consequently, these plants would be expected to be near the top of the dis patch list and the study capacity factor (CF) is chosen to reflect the maximum availability demonstrated for the specific plant type, i.e.

, 85 percent for both PC and CFB configurations. Since variations in fuel costs and other factors can influence dispa tch order and CF , sensitivity of COE to CF is evaluated and presented later in this Executive Summary ( Exhibit ES

- 9 ).

The nominal net plant output for this study was set at 550 megawatts ( MW ) . The boilers and
steam turbines in th e combustion cases are readily available in a wide range of capacities. Higher auxiliary load and extraction steam requirements in CO 2 capture cases are accommodated
in the PC and CFB cases by using larger boiler s and steam turbine s

.
Exhibit ES

- 2 shows the cost, performance, and environmental profile summary for all cases.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

3 Exhibit ES

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

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

- Low Rank, Volume 3b (Combustion Cases)

4 Energy Efficiency

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

- 3

. There are competing effects that impact efficiency: the more aggressive USC steam conditions increase efficiency relative to SC conditions ; poorer quality lignite coal decreases efficiency relative to PRB coal; and CFB technology increases efficiency relative to PC primarily because of the lower boiler exit temperature enable d by in

- bed limestone injection (eliminates acid dew point concerns). The primary conclusions that can be drawn are:

The USC PC with no CO 2 capture and PRB coal has the highest net efficiency of the technologies modeled in this study with an efficiency of 39.9 percent.

The USC PC case with CO 2 capture and PRB coal results in the highest efficiency (28.7 percent) among all of the capture technologies.

CO 2 capture results in an efficiency penalty of 11 to 12 absolute percent, relative to
the non

- capture ca se for all the technologies.

The relative efficiency penalty also varies over a narrow range, from 28 to 32 percent. The relative penalty is lowest for the USC PC cases and nearly equal for the SC PC
and SC CFB cases for both coal types

.

Water Use

Three w ater values are presented for each technology in Exhibit ES

- 4 : raw water withdrawal, process discharge, and raw water consumption. Each value is normalized by net output. Raw
water withdrawal is the difference between demand an d internal recycle. Demand is the amount of water required to satisfy a particular process (cooling tower makeup, f lue gas desulfurization [FGD] makeup, etc.) and internal recycle is water available within the process. Raw water
withdrawal is the water r emoved from the ground or diverted from a surface

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

source. 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 configur ations. 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

. The primary
conclusions that can be drawn are:

Among non

- capture cases the normalized water withdrawal and consumption of the USC PC cases are slightly less than the SC PC cases primarily because of the higher USC net efficiency. The same is true for both coal types.

Also among non

- capture cases the normalized withdrawal and consumption is lowest for SC CFB cases for both coal types. The CFB cases have reduced water demand because of using in

- bed limestone injection for SO 2 control in place of a spray dryer FGD system.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

5 Exhibit ES

- 3 Net Plant Efficiency (HHV Basis)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

6 Exhibit ES

- 4 Raw Water Withdrawal and ConsumptionCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

7 For CO 2 capture cases normalized w ate r withdrawal is on average 3 times greater than the analogous non

- capture case and normalized consumption is on average 2.7 times greater than the analogous non

- capture case. The CO 2 capture process, Econamine FG
Plus SM , requires a significant amount of cooling water that is provided by an evaporative cooling tower, resulting in greatly increased water demand.

Also for CO 2 capture cases normalized water consumption is nearly constant within each coal type because much of the water withdrawal is for the cooling tower makeup and 90 percent of the blowdown is returned t o the source as process discharge.

Cost Results

The Total Plant Cost (TPC) for each technology was determined through a combination of vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. TPC includes all equi pment (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, initia l 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 a nd 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 ap plied 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 equipm ent that would result from a detailed design. The contingencies represent costs that are expected to occur. Each bare erected cost (BEC) account was evaluated against the level of estimate detail and field experience to determine project contingency. Pr ocess contingency was added to cost
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:

Flu o r Econamine FG Plus SM (Econam ine ) CO 2 Removal System

– 20 percent on all
capture cases

- unproven technology at commercial scale in PC service.

USC Boiler and Steam Turbine

– 5 percent. A contingency of only 5 percent was used since the advanced material requirements for the steam tu rbine and boiler only impact a fraction of the equipment cost.

Instrumentation and Controls

– 5 percent on all accounts for CO 2 capture cases.

CFB Boiler

– 15 percent. A contingency of 15 percent was used since the boiler in this study is significantly l arger than any current CFB units

, which typically have a maximum capacity in the range of 300 to 350 MW per boiler. The Lagisza plant in Poland is a 460 MW SC CFB and started operation in the summer of 2009 [ 1 ]

. The CFB’s in this studyCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

8 have a gross outpu t ranging from 580

- 670 MW per boiler, making these cases truly
FOAK

.
The normalized components of TOC and overall TASC are shown for each plant configuration in
Exhibit ES

- 5 . The following conclusions can be drawn:

For the SC PC cases the TOC is higher for the NDL coal cases as compared to the P RB coal cases: approximately 8.7 percent for both the non

- capture and CO 2 capture case.

For the SC PC cases the TOC increase to add CO 2 capture is approximately 74 percent for both the PRB and NDL cases.

For the USC PC cases the TOC is also higher for the NDL coal cases as compared to the
PRB coal cases: approximately 9 percent for the non

- capture case and 8 percent for the
CO 2 capture case.

For the USC PC cases the TOC increase to add CO 2 capture is approximately 68 percent for the PRB case and 66 percent for the NDL case.
Following the same trend as the SC PC and USC PC cases, f or the SC CFB cases the TOC is higher for the NDL coal cases as compared to the PRB coal cases: approximately
5. 6 percent for the non

- capture case and 7. 2 percent for the CO 2 capture case. The NDL
cases have consistently higher TOC because of higher coal feed associated with lower boiler efficiency.

For the SC CFB cases the TOC increase to add CO 2 capture is approxi mately 70 percent for the PRB case and 73 percent for the NDL case.

Cost of Electricity

The 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, as suming 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 Power Systems Financial Model ( PS FM ) [ 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 equity over the entire economic analysis period (capital expen diture 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 Secti on 2.6.4

.

1 This nominal e scalation 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 Generation Indust ry 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 3b (Combustion Cases)

9 Exhibit ES

- 5 Plant Capital Costs

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

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

- Low Rank, Volume 3b (Combustion Cases)

10 The project financial structure varies depending on the type of project (high risk 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. The USC PC and CFB cases (with and without CO 2 c apture) and SC PC cases with CO 2 capture were considered to be high
risk and the non

- capture SC PC cases were considered to be low risk. All cases were assumed to have a 5 year capital expenditure period. The current

- dollar, 30

- year levelized cost of ele ctricity (LCOE) was also calculated and i s 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 of the report.

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 expecte d to be representative of January 2010 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 COE is dominated by capital charges in all cases. The capital cost component of COE comprises 62

- 6 3 percent in all four SC PC case s, 6 3

- 6 5 percent in all four USC PC cases, and 6 2

- 6 4 percent in all four CFB cases.

The fuel cost component is relatively minor in all cases, rep resenting 10

- 14 percent of the
COE costs in the PRB cases and 9

- 1 2 percent in the NDL cases.
For each coal type and CO 2 capture scenario, the COE is lowest for the more conventional technology (SC PC) compared to the more advanced technologies (USC PC and SC CFB). The only exception is for NDL coal with CO 2 capture where USC PC and SC CFB have a very slight cost b enefit because of the higher USC efficiency.

The TS&M component of COE in the CO 2 capture cases is 5

- 6 percent for both PRB and

NDL coal.

The COE is 5

- 8 percent lower in both the CO 2 capture and non

- capture PRB cases compared to the NDL coal cases because of higher efficiencies resulting in lower plant

costs.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

11 Exhibit ES

- 8 shows the COE sensitivity to coal costs. A ll c ases show a linear increase in COE
with an increase in coal prices. The slopes of the lines are relatively shall ow, as expected given the small fraction of total COE represented by fuel costs.

The sensitivity of COE to CF is shown in Exhibit ES

- 9

. The baseline CF is 85 percent for all

cases. The curves plotted in Exhibit ES

- 9 assume that CF could be extended to 90 percent with no additional capital equipment. The three lignite coal cases with CO 2 capture and the three
PRB coal cases with CO 2 capture fall nearly on the same line and are difficult to distinguish. All lines in the figure are nearly parallel indicating that a change in capacity factor affects all cases equally. This is a result of a nearly constant split between capital and fixed operating costs which are unaffected by CF, and variable operating cos ts and fuel costs which are affected.

Cost of CO 2 Avoided

The CO 2 emissions per megawatt

- hour ( MWh ) are about the same for each technology for a given coal type and site, and slightly higher for the NDL cases compared to the comparable PRB
cases. The firs t year cost of CO 2 avoided was calculated using the equation:

(ES

- 1)

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 for each of the CO 2 capture technologies modeled. The avoided costs for each capture case are calculated using the analogous non

- capture plant as the reference and again with SC PC without CO 2 capture as the
reference. The cost of CO 2 avoi ded for analogous plant designs averages $ 68.8 /ton ne ($62.4/ton) with a range of $ 67

- $ 70 /ton ne ($61

- $64/ton) for the SC PC cases, $ 63.7 /ton ne ($57.8/ton) with a range of $ 63

- $64 /ton ne ($57

- $58/ton) for the USC PC cases

, and $ 65.6 /ton ne ($59.5/ton) with a r ange of $ 64

- $67 /ton ne ($58

- $61/ton) for the CFB cases

. The CO 2 avoided
costs are lower for PRB coal than NDL , mainly because of the significant capital cost increase in
the NDL fuel cases resulting from lower plant efficiency . CO 2 avoided costs are also shown compared to the baseline SC PC plant (12 series cases) firing the same coal.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

12 Exhibit ES

- 7 COE by Cost ComponentCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

13 Exhibit ES

- 8 COE Sensitivity to Coal CostCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

14 Exhibit ES

- 9 COE Sensitivity to Capacity FactorCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

15 Exhibit ES

- 10 First Year CO 2 Avoided CostCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

16 Environmental Performance

The environmental targets are based on presumed best available control technology (BACT) for
each t echnology and are summarized in Exhibit ES

- 11 . The targets are identical for all pollutants except mercury, which is coal type and technology type dependent. Emission rates of sulfur dioxide ( SO 2 ), nitrogen oxide ( NOx ), and part iculate matter ( PM ) are shown graphically i n 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

Technology

Pollutant SC PC USC PC SC CFB

SO 2 0.132 lb/MMBtu 0.132 lb/MMBtu 0.132 lb/MMBtu

NOx 0.07 lb/MMBtu 0.07 lb/MMBtu 0.07 lb/MMBtu

PM (Filterable) 0.013 lb/MMBtu 0.013 lb/M MBtu 0.013 lb/MMBtu

Hg (PRB Coal) 0.60 lb/TBtu 0.60 lb/TBtu 3.0 lb/TBtu

Hg (Lignite Coal) 1.12 lb/TBtu 1.12 lb/TBtu 4.8 lb/TBtu

The primary conclusions that can be drawn are:

The NOx emissions are constant for all cases because a study assumption was th at low NOx burners with overfire air and selective catalytic reduction in the PC cases and low bed temperature and selective non

- catalytic reduction in the CFB cases could achieve the
0.07 lb/MMBtu emission limit. Similarly particulate emissions are consta nt because a study assumption was that a dry FGD with baghouse in PC cases and cyclones and a baghouse in the CFB cases could
achieve the 0.013 lb/MMBtu emission limit.

SO 2 emissions vary with coal type and technology type. In

- bed limestone injection in t he
CFB cases is assumed to have an SO 2 removal efficiency of 94 percent while the spray dryer absorbers used in the PC cases is assumed to have a removal efficiency of 93 percent. While PRB and lignite coals have the same sulfur content on an as

- received basis, more lignite coal is required to generate the same amount of electricity because of its lower heating value. As a consequence , more SO 2 is emitted at a constant capture efficiency in the lignite coal cases. In capture cases the SO 2 concentration is reduced to the equivalent of 10 ppmv through the use of a polishing scrubber ahead of the amine absorber. Mercury emissions are higher for lignite coal cases compared to the analogous technology PRB coal case because there is no co

- benefit capture observe d with lignite
coals while PRB coal cases achieve some co

- benefit capture. In addition, lignite coal has a higher Hg concentration and a lower heating value.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

17 Hg emissions are lower for the CFB cases because of the higher co

- benefit capture in
addition to the use of carbon injection.

Overall Conclusions

The increase in TOC to add CO 2 capture ranges from 66 to 74 percent.

The increase in COE to add CO 2 capture ranges from 7 1 to 87 percent.

COE for plants using PRB coal is 5

– 8 percent less than a similar pl ant using NDL

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

18 Exhibit ES

- 12 SO 2 , NOx and Particulate Emission RatesCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

19 Exhibit ES

- 13 Mercury Emission RatesCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

20 This page intentionally left blankCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

2 1 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 SC and USC PC R ankine c ycle p ower

p lants and SC CFB p ower p lants using low rank coals, in a consistent technical and economic
manner th at 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

T ypically four cases are modeled and analyzed for each technol ogy. Two cases use PRB subbituminous coal, with and without CO 2 capture, and two cases use NDL coal, with and
without CO 2 capture. The naming convention for the cases covered in this report is as follows:

First letter represents coal type: S = subbitumin ous (PRB) coal; L = NDL coal

Two digit number represents technology type: 12 = SC PC; 13 = USC PC; 22 = CFB

Final letter indicates CO 2 capture: A = no capture; B = capture

Volume 3b covers all the combustion process cases:

Case S12A

– This case is based on an SC PC plant without CO 2 capture. Rosebud PRB coal is the fuel and the plant is located in Montana.

Case S12B

– This case is the same as S12A except it includes CO 2 capture.

Case L12A

– This case is based on an SC PC plant without CO 2 capture

. NDL co al is the fuel, and the plant is located at a minemouth site in North Dakota.

Case L12B

– This case is the same as L12A except it includes CO 2 capture.

Case S13A

– This case is based on an USC PC plant without CO 2 capture. Rosebud PRB coal is the fuel, an d the plant is located in Montana.

Case S13B

– This case is the same as S13A except it includes CO 2 capture.

Case L13A

– This case is based on an USC PC plant without CO 2 capture

. NDL coal is the fuel, and the plant is located at a minemouth site in Nort h Dakota.

Case L13B

– This case is the same as L13A except it includes CO 2 capture.

Case S22A

– This case is based on an SC CFB plant without CO 2 capture. Rosebud PRB coal is
the fuel

, and the plant is located in Montana.

Case S22B

– This case is the same as S22A except it includes CO 2 capture.

Case L22A

– This case is based on an SC CFB plant without CO 2 capture

. NDL coal is the fuel, and the plant is located at a minemouth site in North Dakota.

Case L22B

– This case is the same as L22A except it includ es CO 2 capture.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

22 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.

Generating Unit Configurations

All twelve combus tion cases have a net output of 550 MW. The boiler and steam turbine industry’s ability to match unit size to a custom specification has been commercially demonstrated enabling a common net output comparison of the cases in this study. While the
CFB indu stry has not commercially demonstrated a unit as large in size as that needed for the cases in this study, it is assumed that such a design will be possible in the near future [ 3 ]

. The
coal feed rate was increased in the CO 2 capture cases to increase the gross steam turbine output and account for the higher auxiliary load, resulting in a constant net output.

The balance of this report is organized as follows:

Chapter 2 provides the basis for technical, environmental, and cost evaluations.

Chapter 3 descr ibes the systems common to all eight SC and USC PC cases and four SC
CFB cases.

Chapter 4 provides the detail ed results of the eight SC and USC PC cases.

Chapter 5 provides the detail ed results of the four SC CFB cases.

Chapter 6 describes the SC PC s ensit ivity to MEA s ystem p erformance and c ost (from the bituminous coal study)

Chapter 7 summarizes the results of the twelve combustion cases.

Chapter 8 contains the reference list.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion 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 provided the 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 c ost estimates. 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. Capital and operating

c osts were estimated by WorleyParsons based on simulation results and through a combination of vendor quotes and scaled estimates from previous design/build projects. Ultimately

, a COE was calculated for each of the cases and is reported as the economic fi gure

- 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 at a site 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 Am bient 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 Pres sure, 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 locati ons as shown in
Exhibit 2

- 3

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

24 Exhibit 2

- 3 Site Characteristics

Location Greenfield, Montana (PRB coal) or North Dakota (lignite)

Topography Level

Size, acres 300

Transportation R ail

Ash/Slag Disposal Off Site

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

Access Land locked , having access by rail 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 m (4,055 ft)

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 buildings are included to house the steam turbine and boiler. The following design parameters are considered site

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

Flood plain considerations

Existing soil/site conditions

Water discharges and reuse

Rainfall/snowfall criteria

Seismic design

Buildings/enclosures

Fire protection

Local code height requirements

Noise regulations

– Impact on si te and surrounding areaCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

25 2.2 COAL CHARACTERISTICS

The two design coals are a subbituminous PRB coal from Montana and lignite coal from North Dakota. The coal properties are from NETL’s Coal Quality Guidelines and are shown in
Exhibit 2

- 4 and Exhibit 2

- 5 [ 4 ]

. The Power Systems Financial Model (PSFM) was used to derive the first year capital charge factor for this study. 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 $0.7 8 /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 in a price of $13.42/tonne ($12.17/ton) [ 5 ]

. 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 on the average transportation rate for medium subbituminous coal from the western Montana region delivered to the mountain region [ 6 ]

. 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).

Note: 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 3b (Combustion Cases)

26 Exhibit 2

- 4 Montana Rosebud PRB, Area D, Western Ene rgy 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

Ph osphorous 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 Difference

2 Mercury value is the mean plus one standar d deviation using EPA’s ICR dataCost and Performance Baseline

- Low Rank, Volume 3b (Combustion 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 3b (Combustion Cases)

28 2.3 ENVIRONMENTAL TARGET S

The environmental targets for the study were considered on a tech nology

- 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 contr ol 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 2007 and shown in
Exhibit 2

- 6 . This re presents the minimum level of control that would be required for a new fossil energy plant [ 7 ].

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

- third of their potential output capacity to any utility power distribution system. In cases where 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 pound s 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 Modif ied After February 28, 2005

Pollutant 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 99.97

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 either 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 i n areas not meeting ambient air quality standards (non

- attainment areas). The Clean Air Act authorizes EPA to establish regulations to prevent significant deterioration of air quality due to emissions of any pollutant for which a national ambient air qual ity standard (NAAQS) has been promulgated. Environmental area designation varies by county and can be established only for a specific site
location. Based on the EPA Green Book Non

- attainment Area Map relatively few areas in the
Western U.S. are classifi ed as ―non

- attainment‖ so the plant site for this study was assumed to be
in an attainment area [ 8 ]

. In addition to federal regulations, state and local jurisdictions can impose even more stringent regulations on a new facility. However, since each new pl ant has unique environmentalCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

29 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 fr om new PC

- fired power plants. These rules were vacated by court action on February 8, 2008

, and the final resolution of these rules is unknown. Even though the rules are vacated, the CAMR emission limits are included for reference only. There were two

N SPS limits for mercury in combination with subbituminous coal, one for wet units and one for dry units. Wet units were defined as plants located in a county that receives more than 25 in ches ( in ) per year mean annual precipitation according to the U.S. De partment of Agriculture’s (USDA) most recent publicly available 30 year data, and dry units were plants located in a county receiving 25 in or less. The subbituminous coal plants in this study are located in the
state of Montana. Most of the PRB coal in Montana is located in areas that receive substantially less than 25 in of rainfall, and therefore the ―dry unit‖ designation is used for the NSPS limit [ 9

, 10 ]

. The vacated NSPS limits, based on gross output, are shown in Exhibit 2

- 7

.

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

L ignite 175 x 10 - 6 lb/MWh

Coal refuse 16 x 10 - 6 lb/MWh

IGCC 20 x 10 - 6 lb/MWh

The coal mercury concentration used for this study was determined from the EPA Information Collection Request (ICR) database. The ICR database has 137 records of Montana Roseb ud 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 concentration of 0.081 ppm (dry) and a standard devi ation 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 ppm (dry) for ND L [ 11 ]

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

Design Targets

The environmental targets for combustion cases were established using a presumed BACT and are the same for subbituminous and lignite coal, with the excep tion of mercury, as shown in
Exhibit 2

- 8

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

30 Exhibit 2

- 8 Environmental Target

Pollutants Environmental

Target NSPS Limit 1 Type of Technology

Filterable PM 0.013 lb/ MMBtu 0.015 lb/MMBtu Fabric Filter

SO 2 0.132 lb/MMBtu 1.4 lb/MWh (0.1 05 lb/MMBtu) Low

- Sulfur Fuel and Dry

FGD or Low

- Sulfur Fuel and

In

- bed Limestone Injection

N Ox 0.07 lb/MMBtu 1.0 lb/MWh (0.0 7 5 lb/MMBtu) LNB’s, OFA and SCR or

CFB with SNCR

Hg , Subbitu minous (PC only) 0.60 lb/TBtu (~ 5.0 x 10 - 6
lb/MWh) 97 x 10 - 6 lb/MWh 2

( 7

. 7 lb/TBtu) Co

- benefit capture, low coal

Hg content, and carbon injection

Hg , Lignite (PC only) 1.12 lb/TBtu (~ 9.6 x 10 - 6
lb/MWh) 175 x 10 - 6 lb/MWh 2

( 1 3

. 1 lb/TBtu) Low coal Hg conten t and

carbon injection

Hg , Subbituminous (CFB only) 3.0 lb/TBtu (~ 25 x 10 - 6
lb/MWh) 97 x 10 - 6 lb/MWh 2

( 7

. 8 lb/TBtu) Co

- benefit capture and low

coal Hg content [ 12

, 13 ]

Hg , Lignite(CFB only) 4.8 lb/TBtu (~ 41 x 10 - 6
lb/MWh) 175 x 10 - 6 lb/MWh 2

( 1 3

. 3 lb/TBt u) Co

- benefit capture and low

coal Hg content [ 12

, 13 ]

1 The values in parenthesis are calculated using the lowest efficiency plant heat rate for the applicable technology limit (CO 2 capture cases , PC or CFB as described).

2 CAMR limits were vacated on February 8, 2008 by court action.
The environmental target represents the maximum allowable emissions for any of the combustion cases. In some cases actual emissions are less than the target. For e xample, the CO 2 capture cases require a polishing scrubber to reduce sulfur dioxide ( SO 2 ) concentrations to less
than 10 parts per million volume ( ppmv ) . In those cases the SO 2 emissions are substantially less than the environmental target. The CFB cases utilize in

- bed limestone injection for SO 2 control
with a CO 2 capture efficiency of 94 percent. The spray dryer absorber (SDA) used in the
combustion cases has a CO 2 capture efficiency of 93 percent so the CFB cases have SO 2 emissions less than the envir onmental target. Deeper SO 2 reductions are possible in the CFB cases with the addition of a downstream spray dryer, but that option was not included in this study.

Carbon Dioxide

CO 2 is not currently regulated nationally . However, the possibility exist s 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 co mbustion cases that have CO 2 capture, the basis is a nominal post

- combustion 90 percent removal based on carbon input from the coal.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

31 The cost of CO 2 capture was calculated as an avoided cost as illustrated in the equation below. Analogous non

- capture tech nologies and SC non

- capture PC were chosen as separate reference
cases. The COE in the CO 2 capture cases includes TS&M as well as capture and compression.

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; therefore, CF and availability are equal. The availability for combustion cases was determined using the Generating Availability Data System (GADS) from the North Am erican Electric Reliability Council (NERC) [ 14 ]

. NERC defines an equivalent availability factor (EAF) as a measure of the plant CF assuming there is always a demand for the output. The EAF accounts for planned and scheduled derated
hours

, as well as season al derated hours. As such, the EAF matches this study’s definition of

CF

. The average EAF for coal

- fired plants in the 400

- 599 MW size range was 84.9 percent in 2004 and averaged 83.9 percent from 2000

- 2004. Given that many of the plants in this size ran ge are older, the EAF was rounded up to 85 percent and that value was used as the PC and CFB plant
CF

.
The addition of CO 2 capture was assumed not to impact the CF even without redundant pipelines, wells or subsurface infrastructure. This assumption was m ade 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.

2.5 RAW WATER WITHDRAWAL AND CONSU MPTION

A water balance was performed for each case on the major water co nsumers in the process. The total water demand for each major subsystem was determined. The internal recycle water
available from various sources was used to offset the water demand and determine the total water withdrawal. Discharge water stream quanti ties were estimated and subtracted from the water withdrawal to determine the water consumption from the environment required for the plant.

Fifty percent of the raw water withdrawal was assumed to be provided by a publicly owned treatment works (POTW) and 50 percent was provided 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 and flue gas desulfurization (FGD ) makeup.

The l argest 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 similar to the system being installed at the currently under construction 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 isCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

32 provided by a mechanical draft, evapo rative cooling tower, and all process blowdown streams were assumed to be treated and recycled to the cooling tower. The cooling tower blowdown was assumed to be treated and 90 percent returned to the water source with the balance sent to the ash ponds fo r evaporation. The design ambient wet bulb (WB) 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 makeup rate was determined using the following [ 15 ]:

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

- r ange 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 [ 16 ]. The ITD is the temperature difference between saturated steam at the steam turbine generator (ST G) 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 [ 17 ]

.
The wate r balances presented in subsequent sections include the water demand of the major water consumers within the process, the amount provided by internal recycle, the amount of raw water withdrawal by difference

, the amount of process water returned to the sou rce and the raw water consumption, again by difference.

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 cas h 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 y ears for coal plants (2007 to 201 2 ).

The BEC comprises the cost of process equipment, on

- site facilities and infrastructure that

suppo rt 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 overnight cost expressed in base

- year (2007 ) dollars.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

33 Exhibit 2

- 9 Capital Cost Levels and their Elements

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: detailed design, contractor permitting (i.e., those permits that individual contractors must obtain to perform their scopes of work, as opposed to project permitting, which is not included here), and project/ construction management costs. TPC is an overnight cost expressed in base

- year (2007) dollars.

The TOC comprises the TPC plus owner’s costs. TOC is an ―overnight‖ cost, expressed in base

year (2007) dollars and as such does not include escalation during construction or interest during
construction.

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 exp ressed in mixed, current

- year dollars over the capital expenditure period.

Cost Estimate Basis and Classification

The TPC and Operation and Maintenance (O&M) costs for each of the cases in the study were estimated by WorleyParsons us ing an in

- house databas e and conceptual estimating models. Costs were further calibrated using a combination of adjusted vendor

- furnished and actual cost data from recent design projects.

Recommended Practice 18R

- 97 of the Association for the Advancement of Cost Engineering

Int ernational (AACE) describes a Cost Estimate Classification System as applied in Engineering, Procurement and Construction for the process industries [ 18 ]

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

34 Most techno

- economic studies completed by NETL feature cost estimates intended for the purpose of a ―F easibility 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% P lant 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

The capital costs for each cost account were reviewed by comparing individual accounts across all cases to ensure an accurate representation of the relative cost differences between the cases and accounts. All capital costs are presented as ―overnight costs‖ expressed in June 2007 dollars. The dollar values have been held at June 2007 to allow direct comparison with earlier
results. Significant pricing fluctuations have occurred between June 2007 and March 2009. A retrospective look suggests that pricing for these commodities peaked in mid 2008 and generally declined during the latter parts of 2008 into 2009. B ased on published information, pr icing at the end of 2008 remains higher than June 2007 values.

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 allo cable components of a system or process, so they are included within the specific system account. (This would not be the case had a facility, area, or commodity account structure been chosen instead).

Non

- CO 2 Capture Plant Maturity

Non

- capture SC PC cas es are based on commercial offerings for a mature technology n th

- of

- a

kind (NOAK) cost. Thus, each of these cases reflects the expected cost for the next commercial
sale of this technolog y

.
Non

- capture USC PC cases are based on technologies that have not been proven and are consequently treated as FOAK with appropriate process contingencies applied.

Non

- capture CFB cases are based on available technologies that have not been proven at a scale equivalent to that required in this study and are consequently t reated as FOAK with appropriate process contingencies applied.

CO 2 Removal Plant Maturity

While the post

- combustion technology for the PC plants has been practiced at smaller scale, it has never been practiced at a scale equivalent to that required in thi s study. There are domestic
amine

- based CO 2 capture systems operating on coal

- derived flue gas at scales ranging from 150

- 800 tons per day ( TPD ) [ 19 ]

. The plants in this study will capture a n average 16,000 TPD of
CO 2 . Consequently the CO 2 capture cases are treated as FOAK.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

35 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 t ypically 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. As a result of current market conditions, EPC contractors appear more

r eluctant to assume that overall level of risk. The current trend appears to be a modified EPC approach where much of the risk remains with the Owner. Where Contractors are willing to accept the risk in EPC type lump

- sum arrangements, it is reflected in t he 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 antic ipated 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 high voltage side of the main power transformers. TS&M cost is not included in the reported capital cost or O&M costs, but is treated 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 equipmen t 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. This provides a basis for subsequent comparisons and easy modification when comparing between s pecific case

- by

- case variations.

Other key estimate considerations include the following:

Labor costs are based on Midwest, Merit Shop using factors from PAS, Inc [ 20 ]

. PAS presents information for eight separate regions. Volume 1 of this study used a gen eric 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 ra tes used in Volume 1 were maintained in this study. Costs 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.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

36 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 availability of skilled craft in the area at the time the projects proceed to construction.

The estimates are based on a greenfield site.

The site is considered to be Seismic Zone 1, relatively lev el, and free from hazardous materials, archeological artifacts, or excessive rock. Soil conditions are considered adequate for spread footing foundations. The soil bearing capability is assumed adequate such that piling is not needed to support the found ation loads.

Costs are limited to within the ―fence line,‖ terminating at the high voltage side of the main power transformers with the excep tion of costs included for TS&M, which are
treated as an addition to COE.

Engineering and Construction Management were estimated as a percent of BEC . These costs consist of all home office engineering and procurement services as well as field construction management costs. Site staffing generally includes a construction manager, resident engineer, scheduler, and pe rsonnel 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 received post

- 2007. All vendor quotes used to develop these estimates were adjusted to June 2007 dollars accounting for the price fluctuations. Adjustments of costs pre

- dating 2007
benefitted from a ve ndor 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

est imating models. The more recent economic down turn has resulted in a reduction of commodity prices such that many price indices have similar values in January 2010 compared to June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 and 532.9 in January 2010, and the Gross Domestic Product Chain

- type Price Index was 106.7 on July 1, 2007 and 110.0 on January 1, 2010. While these overall indices are nearly constant, it should be noted that the cost of individual equipment t ypes may still deviate from the June 2007 reference point.

Cross

- comparisons

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

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

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)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

37 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 include d 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 tho ugh 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 chang es in regulatory requirements 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 t o 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 show n in Exhibit 2

- 11 , AACE International Recommended Practice 16R

- 90 provides guidelines for estimating process contingency based on EPRI philosophy [ 21 ]

. Process contingencies have been applied to the estimates in this study as follo ws:

CO 2 Removal System (Econamine)

– 20 percent on all CO 2 capture cases

- unproven technology at commercial scale in PC service.

USC Boiler and Steam Turbine

– five percent. A contingency of only five percent was used since the advanced material requirem ents for the steam turbine and boiler only impact a fraction of the equipment.

Instrumentation and Controls

– five percent on all accounts for CO 2 capture cases.

CFB Boiler

– 15 percent. A contingency of 15 percent was used since the boiler in this study is significantly larger than any current SC CFB units

, which typically have aCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

38 maximum capacity in the range of 300 to 350 MW per boiler making these cases truly
FOAK

.
Exhibit 2

- 11 AACE Guidelines for Pro cess 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 comm ercially 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.

All contingencies included in the TPC, both project and process, represe nt costs that are expected to be spent in the developmen t and execution of the project.

Owner’s Costs

Exhibit 2

- 13 explains the estimation method for owner’s costs. With some exceptions, the estimation method follows guidelines i n Sections 12.4.7 to 12.4.12 of AACE International
Recommended Practice No. 16R

- 90 [ 21 ] . The Electric Power Research Institute’s ―Technical Assessment Guide (TAG®)

– Power Generation and Storage Technology Options‖ also has

g uidelines for estimating owner’s costs. The EPRI and AACE guidelines are very similar. In instances where they differ, this study has sometimes adopted the EPRI approach

. Interest during construction and escalation during construction are not included as owner’s 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 from the ratios given in Exhibit 2

- 12

.

Exhibit 2

- 12 TASC/TOC Factors

Finance Structure IOU High Risk IOU Low Risk

TASC/TOC 1. 140 1.1 34Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

39 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 no t 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 co nstruction. 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 Capi tal 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 ads orbents that are batch replacements such as WGS, COS, and SCR catalysts and
activated carbon.

AACE 16R

- 90 does not include an inventory cost for fuel, but EPRI TAG® does.

Land $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)

Financing Cost 2.7 % of TPC

This financing cost (not included by AACE 16R

- 90) covers the cost of securing financing, including fees and closing costs but not including interest during construction (or AFUDC). The ―rule of thumb‖ estimate (2.7% of TPC) is based on a 2008 pri vate communication with a capital services firm.

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% ofCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

40 Owner’s Cost Estimate Basis

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 loca l 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, and 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 3b (Combustion Cases)

41 2.6.2 Operations and Maintenance Costs

The production costs or operating costs and related mai ntenance 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 disposal

Co

- product or by

- product 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 variable O&M, which is proportional to power generation.

Op erating Labor

Operating labor cost was determined based on the number of operators required for each specific case. The average base labor rate used to determine annual cost is $34.65/ hour ( hr ) . The associated labor burden is estimated at 30 percent of t he 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 maintenance cost to initial capital cost. This represent s a weighted analysis in which the individual cost relationships were considered for each major plant component or section.

Administrative and Support Labor

Labor administration and overhead charges are assessed at a 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 operating hours.

Quantities for major consumables such a s 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 data.

The quantities for initial fills and daily consu mables 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 3b (Combustion Cases)

42 Initial fills of the consumables, fuels and chemicals, are different fr om 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 fly ash and bott om ash from the PC cases are considered a waste with a disposal cost of $17.89/tonne ($16.23/ton).

Co

- Products and By

- Products (Other than CO 2 )

By

- product quantities were also determined similarly to the consumables. However, due to the
variable marketa bility of these by

- products (bottom ash; fly ash co

- mingled with FGD products;
or CFB bed ash co

- mingled with FGD products) no credit was taken for potential saleable value.

It should be noted that by

- product credits and/or disposal costs could potenti ally be an additional determining factor in the choice of technology for some companies and in selecting some sites. A high local value of the product can establish whether or not added capital should be included in the plant costs to produce a particular co

- product. Ash is a potential by

- product in certain markets and would have potential marketability. However, as stated above, since in these cases the fly ash contains mercury from carbon injection and FGD byproducts, it was assumed to be a

waste mater ial rather than a saleable byproduct.

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
incr ement that was added to the plant COE.

CO 2 TS&M was modeled based on the following assumptions:

CO 2 is supplied to the pipeline at the plant fence line at a pressure of 15.3 MPa (2,215 psia). The CO 2 product gas composition varies in the cases presented, but is expected to meet the specification described in Exhibit 2

- 14 [ 22 ]

. A glycol 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 p ipeline to a geologic sequestration field for injection into a saline formation.

The CO 2 is transported and injected as a SC fluid in order to avoid two

- phase flow and achieve maximum efficiency [ 23 ]

. The pipeline is assumed to have an outlet pressure (abo ve the SC pressure) of 8

. 3 MPa (1, 200 psia) with no recompression along the way. Accordingly, CO 2 flow in the pipeline was modeled to determine the pipe diameter that results in a pressure drop of 6

. 9 MPa ( 1,0 00 psi) over an 80 km (50 mile) pipeline lengt h [ 24 ]

. (Although not explored in this study, the use of boost compressors and a smaller pipeline diameter could possibly reduce capital costs for sufficiently long pipelines.) The diameter of the injection pipe will be of sufficient size that frictional losses during injection are minimal and no booster compression is required at the well

- head in order to achieve an appropriate down

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

- Low Rank, Volume 3b (Combustion Cases)

43 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 C oncentration 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) [ 25 ]

. This is

co nsidered 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 [ 25 ]. The assumed aquifer
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 md (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 T S&M costs for a ― favorable ‖ sequestration project, and may vary signifi cantly based on variables such as terrain to be crossed by the pipeline, reservoir characteristics, and number of land owners from which sub

- surface rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics
found in t he literature, escalated to June 2007

- year dollars using appropriate price indices. These costs were then verified against values quoted by industrial sources where possible. Where regulatory uncertainty exists or costs are undefined, such as liability c osts and the acquisition of underground pore volume, analogous existing policies were used for representative cost
scenarios.

The following sub sections 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.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

44 In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur over a longer time period, up to 100 years. In these cases a capital fund is estab lished 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.

Pi peline 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 o f building a CO 2 pipeline, as noted in various studies [ 23

, 25

, 26 ]

. The University of California performed a regression analysis to generate cost curves from the O&GJ data: (1) Pi peline 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 [ 26 ]

. These cost curves were escalated to the June 2007 year dollar s 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 [ 25 ]

. This study ut ilized a similar basis for pipeline costs (O &GJ Pipeline cost data up to the year 2000) but added a CO 2 surge tank and pipeline control system to the project.

Transport O&M costs were assessed using metrics published in a second DOE/NETL sponsored
report entitled Economic Evaluation of CO 2 Stora ge and Sink Enhancement Options [ 23 ]

. This study was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the other studies mentioned above either (a) do not report operating costs, or (b) report them in absolute terms for one pipeline, as opposed to as a length

- or 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 [ 23 ]

. Th ese 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 injecting CO 2

. Pore Volume Acquisition cos ts 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 [ 27 ]

. 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 judgme nt‖ decisions to
be made

. In this study it was assumed that long

- term lease rights were acquired from the property owners in the projected CO 2 plume growth region for a nominal fee, and that an annual ―rent‖ was paid when the plume reached each individual acre of their property 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 r ent scenario.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

45 Liability Protection

Liability Protection addresses the fact that if damages are caused by injection and long

- term storage of CO 2 , the injecting party may bear financial liability. Several types of liability protection schem e s have been sug gested 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 [ 28 ]

. However, at 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 perpet uity (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) [ 29

, 30

, 31 ]

. In the case of Louisiana, a trust fund to taling five million 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 cost s 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 o n 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 com pared 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 f or Geologic Storage Projects report [ 32 ]

. In this scenario, operational monitoring of the CO 2 plume occurs over thirty years (during plant operation) and closure monitoring occurs for the following fifty years (for a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity survey, and periodic seismic survey ; EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after injection ceases.

2.6.4 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 (i nvestor

- owned utility (IOU) or independent power producer) and the assumed risk profile of the plant being assessed (low

- risk or high

- risk). For this study the owner/developer was assumed to be an IOU.
The SC non

- capture PC plants are categorized as low risk and all the CO 2 capture cases, USC plants, and CFB plants are categorized as high risk

. Exhibit 2

- 17 describes the low

- risk IOU and high

- risk IOU finance structures that were assumed for this study. These fi nance structures were recommended in a 2008 NETL report based on interviews with project developers/owners, financial organizations and law firms [ 33 ]

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

46 Exhibit 2

- 16 Global Economic Assumptions

Parameter Valu e
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 Constructio n Management ( owner assumes project risks for performance, schedule and cost)

Type of Debt Financing Non

- Recourse (collateral that secures debt is limited to the real assets of the project) Repayment Term of Debt 15 years Grace Period on Debt Repayment 0 years

Debt Reserve Fund None
ANALYSIS TIME PERIODS Capital Expenditure Period 5 Years Operational Period 30 years

Economic Analysis Period (used for IRROE) 35 Years (capital expenditure period plus operational period)
TREATMENT OF CAPITAL COSTS

Ca pital 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 parame ters

% 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 CO E (revenue), O&M Costs, and Fuel Costs (nominal annual rate) 3.0% 3

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.

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.)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

47 Exhibit 2

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

Type of Security % of Total Current (Nominal) Dollar
Cost Weighted

Curre nt (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

.

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 te rms 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 of 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 this 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.

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 perspective it is actually the ―p rice‖ 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 electricity.

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 Power 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.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

48 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 perce nt , 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 t han a real, basis 7 . ―Thirty

- years‖ refers to the 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 , provide d the stipulated return on equity over the entire 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 developmental 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 expenditure 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 and 2010 for natural gas plants in this study (see Volume 3c for cost and performance of NGCC plants)

. Note that, according to the Chemical Eng ineering Plant Cost Index, June

- 2007 dollars are nearly equivalent to January

- 2010 dollars.

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 pe riod, it is also the base year for the economic analysis. Accordingly, it is convenient to report the results of the economic analysis in
base

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

- year, current dollars over the capital ex penditure period.

Consistent with our nominal

- dollar discounted cash flow methodology, the COEs shown on
Exhibit 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 informa tion as in Exhibit 2

- 18 for a PC plant with CCS only on a constant 2007 dollar basis. With an assumed nominal COE escalation rate equal to the rate of inflation, the COE line now becomes horizontal and the LCOE dec reases at a rate of 3 percent

per year.

7 For this current

- dollar analysis, the LCOE is uniform in current dollars over the ana lysis 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 3b (Combustion Cases)

49 Exhibit 2

- 18 Illustration of COE Solutions using DCF Analysis

Exhibit 2

- 19 PC with CCS in Current 2007 DollarsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

50 E stimating 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 followin g simplified equation can 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 Char g e Factor (CCF) 0.1243 0.1165

All factors in the COE equation are expressed in base

- year dollars. The base year is the first year of capit al 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.

where:

COE = revenue received by the generator ($/MWh, equivalent to mills/kWh)

during the power plant’s first year of operation ( but expressed in base

y ear 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

8 Although TOC is used in the simplified COE equation, the CCF that multiplies it accounts for escalation during

const ruction and interest during construction (along with other factors related to the recovery of capital costs).Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

51 OC FIX = the sum of all fixed annual operating costs, expressed in b ase

- 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 megawa tt

- 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. Exhibit 2

- 21 presents this cost metric along with the COE es calated to the first year of operation (2010 for NGCC cases and 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 met hodology, the reader may generate either metric in the desired cost year basis.

Exhibit 2

- 21 COE and LCOE Summary

Case COE LCOE

Base

- Year First Operational

Year Base

- Year First Operational
Year

2007 $ 20 12 $ 2007$ 2012$

S 1 2A 57.80 67.00 73.27 84.93

S1 2 B 107.50 124.62 136.27 157.97

L12A 62.20 72.10 78.84 91.40

L12B 116.36 134.90 147.51 171.00

S13A 62.17 72.07 78.81 91.36

S13B 107.66 124.80 136.47 158.20

L13A 67.31 78.03 85.32 98.91

L13B 115.38 133.7 6 146.26 169.56

S22A 61.53 71.33 78.00 90.42

S22B 107.97 125.17 136.87 158.67

L22A 64.57 74.86 81.85 94.89

L22B 115.19 133.54 146.02 169.27Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

52 This page left intentionally blankCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

53 3. COMBUSTION POWER PLA NT PROCESS DESCRIPTI ONS

3.1 COMMON PROCESS AREAS FOR ALL CO MBUSTION CASES

The combustion cases have process areas that are common to each plant configuration such as coal receiving and storage, emissions control technologies, power generation, etc. As detailed descriptions of these process areas in each case sect ion would be burdensome and repetitious, they are presented in this section for general background information. The performance features of these sections are then presented in the case

- specific sections.

3.1.1 Coal and Sorbent Receiving and Storage

The functio n of the coal portion of the Coal and Sorbent Receiving and Storage system is to provide the equipment required for unloading, conveying, preparing, and storing the fuel delivered to the plant. The scope of the system is from the coal conveyor receiving h oppers up to the coal storage silos. The system is designed to support short

- term operation at maximum power output at the five percent over pressure/valves wide open (OP/VWO) condition (16 hours) and long

- term operation of 90 days or more at the maximum continuous rating (MCR).

The scope of the sorbent receiving and storage systems includes truck roadways, turnarounds, unloading hoppers, conveyors, and the day storage bin. The limestone system for the CFB cases also includes reclaim hoppers and feeders.

Operation Description

– The NDL plants are located at the minemouth and coal is delivered to the plant from the mine by conveyor into two receiving hoppers. Coal is delivered to the PRB plants by 100

- car unit trains comprised of 91 tonne (100 ton) rail ca rs. The unloading is done by a trestle dumper

, which unloads the coal into two receiving hoppers.

For both plant types, coal from each hopper is fed directly into a vibratory feeder. The 8
centimeter (cm) x 0 (3 ‖ x 0) coal from the feeder is discharged o nto 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 sep arator to remove tramp iron and then to the reclaim pile.

Coal from the reclaim pile is fed by two vibratory feeders, located under the pile, onto a belt conveyor, which transfers the coal to the coal surge bin located in the crusher tower. The coal is

r educed in size to 2.5 cm x 0 (1 ‖ x 0) by the coal crushers. The coal is then transferred by conveyor to the transfer tower. In the transfer tower the coal is routed to the tripper that loads
the coal into one of the six boiler silos.

For the PC cases, li me is delivered to the site using 23 tonne (25 ton) trucks and conveyed to storage. Lime is stored in a bulk storage lime silo. The lime is pneumatically conveyed to a day
bin.

For the CFB cases, l imestone is delivered to the site using 23 tonne (25 ton) trucks. The trucks empty into a below grade hopper where a feeder transfers the limestone to a conveyor for delivery to the storage pile. Limestone from the storage pile is transferred to a reclaim hopper and conveyed to a day bin.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

54 3.1.2 Steam Generator and Ancillaries

The steam generating boilers are described in Section 3.2.1 for the PC case and Section 3.3.1 for the CFB cases. The steam generator operates as follows:

F eedwater and Steam

For the SC and USC steam systems, feedwater ( FW ) enters the bottom header of the economizer and passes upward through the economizer tube bank, through stringer tubes that support the primary superheater, and discharges to the economizer outlet headers. From the ou tlet headers, water flows to the furnace hopper inlet headers via external downcomers. Water then flows upward through the furnace hopper and furnace wall tubes. From the furnace, water flows to the steam water separator. During low load operation (oper ation below the Benson point), the water from the separator is returned to the economizer inlet with the boiler recirculating pump. Operation at loads above the Benson point is once through.

Steam flows from the separator through the furnace roof to the c onvection pass enclosure walls, primary superheater, through the first stage of water attemperation, to the furnace platens. From the platens, the steam flows through the second stage of attemperation and then to the intermediate superheater. The steam t hen flows to the final superheater and on to the outlet pipe terminal. Two stages of spray attemperation are used to provide tight temperature control in all high temperature sections during rapid load changes.

Steam returning from the turbine passes thro ugh the primary reheater (RH) surface, then through crossover piping containing inter

- stage attemperation. The crossover piping feeds the steam to
the final RH banks and then out to the turbine. Inter

- stage attemperation is used to provide outlet
tempera ture control during load changes.

3.1.3 Particulate Control

A pulse

- jet baghouse with air to cloth ratio of 3.5 feet per minute ( ft/min ) is provided. The baghouse is provided with a spare compartment for off line cleaning to maintain the opacity at 10
percent o r less. The waste is pneumatically conveyed to a waste storage silo with a 3

- day storage capacity, which is in accordance with typical utility design. Flue gas exits the baghouse and enters the Induced Draft (ID) fan suction.

3.1.4 Carbon Dioxide Recovery Faci lity

A Carbon Dioxide Recovery (CDR) facility is used in Cases S12B, S13B, L12B, L13B, S22B

, and L22B to remove 90 percent of the CO 2 in the flue gas exiting the baghouse unit, purify it, and compress it to a SC condition. The CDR is comprised of the flue gas supply, SO 2 polishing,
CO 2 absorption, solvent stripping and reclaiming, and CO 2 compression and drying.

The CO 2 absorption/stripping/solvent reclaim process for the CO 2 capture cases is based on the
Fluor Econamine FG Plus SM technology [ 34

, 35 ]. A typi cal flowsheet is shown in Exhibit 3

- 1

. The Econamine FG Plus process uses a formulation of monoethanolamine (MEA) and a proprietary corrosion inhibitor to recover CO 2 from the flue gas. This process is designed t o recover high

- purity CO 2 from low

- pressure (LP) streams that contain O 2 , such as flue gas from
coal

- fired power plants, gas turbine exhaust gas, and other waste gases. The Econamine process used in this study differs from previous studies, including the 2004 IEA study [ 34 ], in the following ways:Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

55 The complexity of the control and operation of the plant is significantly decreased

Solvent consumption is decreased

Hard to dispose waste from the plant is greatly reduced

The above are achieved at the expense of a slightly higher steam requirement in the stripper reboiler (3,556 kJ/kg [1,530 Btu/lb] versus 3,242 kJ/kg [1,395 Btu/lb] used in the IEA study) [ 36 ]

. A recent Fluor publication [ 43 ] indicates that a reboiler steam duty of 1,270 Btu/lb CO 2 is possible with higher MEA concentration and im proved corrosion inhibitors. A sensitivity analysis was conducted to estimate the impact of the lower reboiler steam consumption on the COE. This sensitivity st udy is included in Section 6

.

SO 2 Polishing and FG Cooling and Supply

To minimize the accumulation of heat stable salts (HSS) , the incoming flue gas must have an
SO 2 concentration of 10 ppmv or less. The gas exiting the FGD s ystem passes through an SO 2 polishing step to achieve this objective. The polishing step consists of a non

- plugging, low

differential

- pressure, spray

- baffle

- type scrubber using a 20 weight percent ( wt% ) solution of sodium hydroxide (NaOH). A removal effi ciency of about 80 percent is necessary to reduce SO 2 emissions from the FGD outlet to 10 ppmv as required by the Econamine process. The polishing scrubber proposed for this application has been demonstrated in numerous industrial applications throughout the world and can achieve removal efficiencies of over 95 percent if necessary.

The polishing scrubber also serves as the flue gas cooling system. Cooling water from the PC/CFB plant is used to reduce the flue gas temperature to below the adiabatic satura tion temperature resulting in a reduction of the flue gas moisture content . Flue gas is cooled beyond
the CO 2 absorption process requirements to 32°C (90°F) to account for the subsequent temperature increase of about 17°C (30°F) in the flue gas blower. D ownstream from the Polishing Scrubber flue gas pressure is boosted in the Flue Gas Blowers by approximately 0.014 MPa (2 pounds per square inch [ psi ] ) to overcome pressure drop in the CO 2 absorber tower.

Circulating Water System

Cooling water is provided f rom the PC/CFB plant circulating water system (CWS) and returned to the plant cooling tower. The CDR facility requires a significant amount of cooling water for flue gas cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the lean solvent cooler, and CO 2 compression inter stage cooling.

CO 2 Absorption

The cooled flue gas enters the bottom of the CO 2 Absorber and flows up through the tower
countercurrent to a stream of le an MEA

- based solvent . Approximately 90 perc ent of the CO 2 in the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorber section and flows into the water wash section of the tower. The lean solvent enters the top of the
absorber section , absorbs the CO 2 from the flu e gas, and leaves the bottom of the absorber with
the absorbed CO 2

. The FG Plus process also includes solvent intercooling. The semi

- rich solvent is extracted from the column, cooled using cooling water, and returned to the absorber section just below th e extraction point. The CO 2 carrying capacity of the solvent is increased at lower temperature, which reduces the solvent circulation rate.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

56 Exhibit 3

- 1 Fluor Econamine FG Plus SM Typical Flow DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

57 Wat er Wash Section

The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The flue gas from the top of the CO 2 Absorption section is
contacted with a re

- circulating stream of water for the removal o f most of the lean solvent. The scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water stream from the bottom of the wash section is collected on a chimney tray. A p ortion of the water collected on the chimney tray spills over to the absorber section as water makeup for the amine with the remainder pu mped via the Wash Water Pump, cooled by the Wash Water Cooler, and recirculated to the top of the CO 2 Absorber.
The wa sh water level is maintained by wash water makeup

.

Rich/Lean Amine Heat Exchange System

The rich solvent from the bottom of the CO 2 Absorber is preheated by the lean solvent from the Solvent Stripper in the Lean/Rich Cross Exchanger. The heated rich solv ent is routed to the Solvent Stripper for removal of the absorbed CO 2 . The stripped solvent from the bottom of the Solvent Stripper is pumped via the Lean Solvent Pump to the Lean Solvent Cooler. A slipstream of the lean solvent is then sent through the Amine Filter Package to prevent buildup of contaminants in the solution. The filtered lean solvent is mixed with the remaining lean solvent
from the Lean Solvent Cooler and sent to the CO 2 Absorber, completing the circulating solvent
circuit.

Solvent Stri pper
The purpose of the Solvent Stripper is to separate the CO 2 from the rich solvent feed exiting the
bottom of the CO 2 Absorber. The rich solvent is collected on a chimney tray below the bottom packed section of the Stripper and routed to the Reboiler w here the rich solvent is heated by steam, stripping the CO 2 from the solution. Steam is provided from the crossover pipe between
the IP and LP sections of the steam turbine at 0.51 MPa (74 psia) and 292°C (557°F). The hot wet vapor from the top of the st ripper containing CO 2 , steam, and solvent vapor, is partially condensed in the Reflux Condenser by cross exchanging the hot wet vapor with cooling water. The partially condensed stream then flows to the Reflux Drum where the vapor and liquid are separated. The uncondensed CO 2 - rich gas is then delivered to the CO 2 product compressor . The condensed liquid from the Reflux Drum is pumped via the Reflux Pump where a portion of condensed overhead liquid is combined with the lean solvent entering the CO 2 Absorber

. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which aids in limiting the amount of solvent vapors entering the stripper overhead system.

Solvent Reclaimer

The low temperature reclaimer technology is a recent developmen t for the FG Plus technology. A small slipstream of the lean solvent is fed to the Solvent Reclaimer for the removal of high

boiling nonvolatile impurities including HSS, volatile acids and iron products from the circulating solvent solution. Reclaiming occurs in two steps, the first is an ion

- exchange process. There is a small amount of degradation products that cannot be removed via ion

- exchange, and a second atmospheric pressure reclaiming process is used to remove the degradation products. The
solve nt reclaimer system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned to the Solvent Stripper and the spent solvent is pumped via theCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

58 Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank for dispos al. The quantity of spent solvent is greatly reduced from the previously used thermal reclaimer systems.

Steam Condensate

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer
Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler Condensate Drum and returned to the steam cycle between BFW heaters 4 and 5 via the Solvent Reboiler Condensate Pumps.

Cor rosion Inhibitor System

A proprietary corrosion inhibitor is continuously injected into the CO 2 Absorber rich solvent
bottoms outlet line. This additive is to help control the rate of corrosion throughout the CO 2 recovery plant system.

Gas Compression and Drying System

In the compression section, the CO 2 is compressed to 15.3 MPa (2,215 psia) by a six

- stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable power distribution and discharge temperatures across th e various stages as shown in Exhibit 3

- 2

.

Exhibit 3

- 2 CO 2 Compressor Interstage Pressures

Stage Outlet Pressure,

MPa (psia)

1 0.35 (51)

2 0.77 (112)

3 1.69 (245)

4 3.71 (538)

5 8.16 (1,184)

6 15.3 (2,215)

Power consumption for this large compressor was estimated assuming a polytropic efficiency of 86 percent and mechanical efficiency of 98 percent for all stages . During compression to 15.3 MPa (2,215 psia) in the multiple

- s tage, intercooled compressor, the CO 2 stream is dehydrated to

a dew point of

- 40oC (

- 40°F) with triethylene glycol (TEG) . The virtually moisture

- free SC CO 2 stream is delivered to the plant battery limit as sequestration ready. CO 2 TS&M costs were estima ted and included in LCOE and COE using the methodology described in Section 2.6

.

3.1.5 Power Generation

Since there is no single consensus definition of USC conditions, a literature search was conducted to identify conditions to be u sed in this study. Main steam conditions of 24.1 MPa/593°C (3,500 psig/1,100°F) are used for SC PC and CFB cases and 27.6 MPa/649°C (4,000 psig/1,200°F) for USC PC cases in this study.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

59 Reasons for this decision include:

The SC steam conditions are consist ent with SC PC cases in Volume 1 of this study [ 37 ] Even without a precise definition for USC , these steam conditions would be categorized

as USC by all

The SC and USC steam conditions are sufficiently different to see a meaningful difference in plant effic iency

The steam turbine is designed for long

- term operation (90 days or more) at MCR with throttle control valves 95 percent open. It is also capable of a short

- term five percent OP/VWO condition (16 hours).

The steam turbine is a tandem compound type, co nsisting of HP

- intermediate pressure ( IP )

- two LP (double flow) sections enclosed in three casings, designed for condensing single reheat operation, and equipped with non

- automatic extractions and four

- flow exhaust. The turbine
drives a hydrogen cooled gen erator. The turbine has direct current ( DC ) motor

- operated lube oil pumps, and main lube oil pumps, which are driven off the turbine shaft [ 38 ]

. The exhaust pressure is 35.6 centimeter ( cm ) (1.4 in) Hg in the single pressure condenser. The condenser is

t wo

- shell, transverse, single pressure with divided waterbox for each shell.

Turbine bearings are lubricated by a closed

- loop (CL) , water

- cooled pressurized oil system. Turbine shafts are sealed against air in

- leakage or steam blowout using a labyrinth gla nd arrangement connected to a LP steam seal system. The generator stator is cooled with a CL water system consisting of circulating pumps, shell and tube or plate and frame type heat exchangers, filters, and deionizers, all skid

- mounted. The generator ro tor is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft.

Operation Description

The turbine stop valves, control valves, reheat stop valves, and intercept valves are controlled by
an electro

- hydraulic contro l system. Main steam from the boiler passes through the stop valves and control valves and enters the turbine at 24.1 MPa/593°C (3,500 psig/1,100°F) for the SC cases and 27.6 MPa/649°C (4,000 psig/1,200°F) for the USC cases. The steam initially enters
th e turbine near the middle of the HP span, flows through the turbine, and returns to the boiler for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 593°C (1,100°F) in the SC cases and 649°C (1,200°F) in the USC cases. After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the two LP sections. The steam divides into four paths and flows through the LP sections exhausting downward into the cond enser.
The turbine is designed to operate at constant inlet steam pressure over the entire load range.

3.1.6 Balance of Plant

The balance of plant components consist of the condensate, FW , main and reheat steam, extraction steam, ash handling, ducting and stac k, waste treatment

, and miscellaneous systems as
described below.

Condensate

The function of the condensate system is to pump condensate from both the air

- cooled and

water

- cooled condenser to the deaerator, through the LP FW heaters. Each system consists ofCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

60 two main condensers (one air

- cooled and one water

- cooled); two variable speed electric motor

driven vertical condensate pumps each sized for 50 percent capacity; four LP heaters; and one deaerator with storage tank.

Condensate is delivered to a common d ischarge header through two separate pump discharge lines, each with a check valve and a gate valve. A common minimum flow recirculation line discharging to the condenser is provided downstream of the gland steam condenser to maintain minimum flow require ments for the gland steam condenser and the condensate pumps.

LP FW heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the condenser neck. All remaining FW heaters are 100 percent capacity shell and U

- tube heat exchangers. Eac h LP FW heater is provided with inlet/outlet isolation valves and a full capacity bypass. LP FW heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the condenser. Pneumatic level control valves control norm al drain levels in the heaters. High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Pneumatic level control valves control dump line
flow.

Feedwater

The function of the FW system is to pump the FW from the deaerator storage tank through the
HP FW heaters to the economizer. One turbine

- driven BFW pump sized at 100 percent capacity is provided to pump FW through the HP FW heaters. One 25 percent motor

- driven BFW pump is provided fo r startup. The pumps are provided with inlet and outlet isolation valves, and individual minimum flow recirculation lines discharging back to the deaerator storage tank. The recirculation flow is controlled by automatic recirculation valves, which are a combination check valve in the main line and in the bypass, bypass control valve, and flow sensing element. The suction of the boiler feed pump is equipped with startup strainers, which are utilized during initial startup and following major outages or sy stem maintenance.

Each HP FW heater is provided with inlet/outlet isolation valves and a full capacity bypass. FW heater drains cascade down to the next lowest extraction pressure heater and finally discharge
into the deaerator. Pneumatic level control v alves control normal drain level in the heaters. High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Dump line flow is controlled by pneumatic level control
valves.

The deaerator is a horizontal, spray tray type with internal direct contact stainless steel (SS) vent condenser and storage tank. The boiler feed pump turbine is driven by main steam up to
60 percent plant load. Above 60 percent load, extraction from the IP turbine ex haust provides steam to the boiler feed pump steam turbine.

Main and Reheat Steam

The function of the main steam system is to convey main steam from the boiler superheater outlet to the HP turbine stop valves. The function of the reheat system is to conve y steam from
the HP turbine exhaust to the boiler RH and from the boiler RH outlet to the IP turbine stop
valves.

Main steam exits the boiler superheater through a motor

- operated stop/check valve and a motor

operated gate valve and is routed in a single li ne feeding the HP turbine. A branch line off the IPCost and Performance Baseline

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61 turbine exhaust feeds the BFW pump turbine during unit operation starting at approximately
60 percent load.

Cold reheat steam exits the HP turbine, flows through a motor

- operated isolation gate valve and a flow control valve, and enters the boiler RH . Hot reheat steam exits the boiler RH through a

motor

- operated gate valve and is routed to the IP turbine.

Extraction Steam

The function of the extraction steam system is to convey steam from turbine extrac tion points to
the FW heaters, deaerator, and CDR facility for CO 2 capture cases.

The turbine is protected from overspeed on turbine trip, from flash steam reverse flow from the heaters through the extraction piping to the turbine. This protection is prov ided by positive closing, balanced disc non

- return valves located in all extraction lines except the lines to the LP

FW heaters in the condenser neck. The extraction non

- return valves are located only in horizontal runs of piping and as close to the turbi ne as possible.

The turbine trip signal automatically trips the non

- return valves through relay dumps. The remote manual control for each heater level control system is used to release the non

- return valves to normal check valve service when required to r estart the system.

Circulating Water System

Exhaust steam from the steam turbine is split 50/50 to a surface condenser cooled with cooling
water and to an air

- cooled condenser using ambient air and forced convection. A decision to use a parallel wet/dry c ooling system was based primarily on the plans for the Xcel Energy Comanche 3 PC plant currently under construction, and the desire to reduce the plant water requirement.

The major impact of parallel cooling is a significant reduction in water requirement when compared to a wet cooling system. This impact is included in the water balance presented later in this report.

Because of the low ambient temperatures at the sites in this study, a condenser pressure of 4.81 kilopascal absolute ( kPa ) (0.698 psia) (c ondensing temperature of 32°C [90°F]) is used in the model as compared to 6.77 kPa (0.983 psia) (condensing temperature of 38°C [101°F]) used in Volume 1 of this report [ 37 ]

.
The CWS is a closed

- cycle cooling water system that rejects heat through a wet cooling tower and 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 CDR 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 intercoolers, oil coolers and other ancillary equipment and transfers that heat to the main circulating cooling water system in plate and fra me heat exchangers. The heat transferred to the circulating water in the surface condenser and other applications is removed by a mechanical draft cooling tower.

The system consists of two 50 percent capacity vertical CWPs , a mechanical draft evaporative cooling tower, and carbon steel (CS) cement

- lined interconnecting piping. The pumps are single

- stage vertical pumps. The piping system is equipped with isolation valves and all required expansion joints. The cooling tower is a multi

- cell wood frame coun terflow mechanical draft cooling tower.Cost and Performance Baseline

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62 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 fo r 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 remaining one

- half of the turbine exhaust steam.

Both cond ensers are equipped with an air extraction system to evacuate the condenser steam space for removal of non

- condensable gases during steam turbine operation and to rapidly reduce the condenser pressure from atmospheric pressure before unit startup and admis sion of steam to
the condenser.

Ash Handling System

The function of the ash handling system is to provide the equipment required for conveying, preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basis by the
boiler. The sc ope of the system is from the baghouse hoppers, air heater

, and economizer hopper collectors, and bottom ash hoppers to the dewatering bins (for bottom ash) and truck filling stations (for fly ash). The system is designed to support short

- term operation a t the
five percent OP/VWO condition (16 hours) and long

- term operation at the 100 percent guarantee point (90 days or more).

The fly ash collected in the baghouse and the air heaters is conveyed to the fly ash storage silo. A pneumatic transport system u sing low

- pressure air from a blower provides the transport mechanism for the fly ash. Fly ash is discharged through a wet unloader, which conditions the fly ash and conveys it through a telescopic unloading chute into a truck for disposal. Bottom ash

rem oval is handled by truck.

For systems that include an SDA FGD, ash collected in the baghouse includes particulates from the FGD that include unreacted lime. Sorbent utilization is increased by about 40 percent by slurrying and recycling a portion of the baghouse ash into the absorber with the virgin lime slurry.

Ash from the economizer hoppers and pyrites (rejected from the coal pulverizers in the PC cases) is conveyed using water to the economizer/pyrites transfer tank. This material is then sluiced on a periodic basis to the hydrobins.

Ducting and Stack

One stack is provided with a single fiberglass

- reinforced plastic (FRP) liner. The stack is constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate dispersion. Th e ID fans were sized large enough to allow for additional stack velocity to overcome the buoyancy losses resulting from colder than normal flue gas temperatures for the
CO 2 capture cases.

Waste Treatment/Miscellaneous Systems

An onsite water treatment faci lity treats all runoff, cleaning wastes, blowdown, and backwash to within the U.S. EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals. Waste treatment equipment is housed in a separate building. The waste treatment
system co nsists of a water collection basin, three raw waste pumps, an acid neutralization system, an oxidation system, flocculation, clarification/thickening, and sludge dewatering. TheCost and Performance Baseline

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63 water collection basin is a synthetic

- membrane

- lined earthen basin, which col lects rainfall runoff, maintenance cleaning wastes, and backwash flows.

The raw waste is pumped to the treatment system at a controlled rate by the raw waste pumps. The neutralization system neutralizes the acidic wastewater with hydrated lime in a two

- st age system, consisting of a lime storage silo/lime slurry makeup system, dry lime feeder, lime slurry tank, slurry tank mixer, and lime slurry feed pumps.

The oxidation system consists of an air compressor, which injects air through a sparger pipe into
the second

- stage neutralization tank. The flocculation tank is fiberglass with a variable speed agitator. A polymer dilution and feed system is also provided for flocculation. The clarifier is a plate

- type, with the sludge pumped to the dewatering system. The sludge is dewatered in filter presses and disposed offsite. Trucking and disposal costs are included in the cost estimate. The filtrate from the sludge dewatering is returned to the raw waste sump.

Miscellaneous systems consisting of fuel oil, servi ce air, instrument air, and service water are provided. A storage tank provides a supply of No. 2 fuel oil used for startup and for a small auxiliary boiler. Fuel oil is delivered by truck. All truck roadways and unloading stations inside
the fence area are provided.

Buildings and Structures

Foundations are provided for the support structures, pumps, tanks, and other plant components. The following buildings are included in the design basis:

 Steam turbine building  Fuel oil pump house  Guard house

 Boiler building  Coal crusher building  Runoff water pump house

 Administration and service building  Continuous emissions monitoring building  Industrial waste treatment building

 Makeup water and pretreatment building  Pump house and electrical equipment building  F GD system buildings

3.1.7 Accessory Electric Plant

The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transfor mer, required foundations, and standby equipment.

3.1.8 Instrumentation and Control

An integrated plant

- wide control and monitoring distributed control system ( DCS ) is provided. The DCS is a redundant microprocessor

- based, functionally distributed system. The control room houses an array of multiple video monitor and keyboard units. The monitor/keyboard units are the primary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all t he major plant equipment. The DCS is designed to provide 99.5 percent availability. The plant equipment and the DCS are designedCost and Performance Baseline

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64 for automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are implemented as su pervised manual, with operator selection of modular
automation routines available.

3.2 COMMON PROCESS AREAS FOR PC CASES ONLY

3.2.1 Steam Generator and Ancillaries

The steam generator for the super and USC plants is a once

- through, spiral

- wound, Benson

boiler, wall

- fired, balanced draft type unit with a water

- cooled dry bottom furnace. It includes a superheater, RH , economizer, and air heater.

It is assumed for the purposes of this study that the power plant is designed to be operated as a
base

- loaded unit but with some consideration for daily or weekly cycling, as can be cost effectively included in the base design.

The combustion systems for SC and USC steam conditions are equipped with low NOx burners ( LNBs ) and OFA.

Scope

The steam generator includes the followin g:

 Once

- through type
steam generator  Economizer  Low NOx Coal burners and light oil igniters/
warmup system

 Startup circuit, including integral
separators  Spray type desuperheater  OFA

 Water

- cooled furnace, dry bottom  Soot blower system  Forced draft (FD) fans

 Two

- stage superheater  Air preheaters ( Regenerative type)  Primary air (PA) fans

 R H  Coal feeders and pulverizers  ID fans

Air and Combustion Products

Combustion air from the FD fans is heated in regenerative type air preheaters, recovering h eat energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as secondary air. Air for conveying PC to the burners is supplied by the PA fans. This air is heated
in the regenerative type air preheaters to permit dr ying of the PC , and a portion of the air from the PA fans bypasses the air preheaters to be used for regulating the outlet coal/air temperature leaving the mills.

The PC and air mixture flows to the coal nozzles at various elevations of the furnace. The hot combustion products rise to the top of the boiler and pass through the superheater and RH sections. The gases then pass through the economizer and air preheater. The gases exit theCost and Performance Baseline

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65 steam generator at this point and flow to the Selective Catalytic Re duction (SCR) reactor, FGD system, fabric filter, ID fan, and stack.

Fuel Feed

The crushed coal is fed through feeders to each of the mills (pulverizers), where its size is reduced to approximately 72 percent passing 200 mesh with less than 0.5 percent rem aining on
50 mesh [ 39 ]

. The PC exits each mill via the coal piping and is distributed to the coal nozzles in the furnace walls using air supplied by the PA fans.

Ash Removal

The furnace bottom comprises several hoppers, with a clinker grinder under each ho pper. The hoppers are of welded steel construction, lined with refractory. The hopper design incorporates a

water

- filled seal trough around the upper periphery for cooling and sealing. Water and ash discharged from the hopper pass through the clinker gr inder to an ash sluice system for conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite disposal. The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to break up any c linkers that may form. From the clinker grinders the bottom ash is sluiced to hydrobins for dewatering and offsite removal by truck. The steam generator incorporates fly ash hoppers under the economizer outlet and air heater outlet.

Burners

A boiler of t his capacity employs approximately 24 to 36 coal nozzles arranged at multiple elevations. Each burner is designed as a low

- NOx configuration, with staging of the coal combustion to minimize NOx formation. In addition, OFA nozzles are provided to further stage combustion and thereby minimize NOx formation.

Oil

- fired pilot torches are provided for each coal burner for ignition, warm

- up and flame stabilization at startup and low loads.

Air Preheaters

Each steam generator is furnished with two vertical

- shaft, tri

- sector, regenerative type air preheaters with an assumed total air leakage of 5.5 percent. These units are driven by electric motors through gear reducers.

Soot Blowers

The soot

- blowing system utilizes an array of 50 to 150 retractable nozzles and la nces that clean the furnace walls and convection surfaces with jets of HP steam. The blowers are sequenced to provide an effective cleaning cycle depending on the coal quality and design of the furnace and
convection surfaces. Electric motors drive the s oot blowers through their cycles.

3.2.2 NO
x Control System

The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. Two
measures are taken to reduce the NOx. The first is a combination of LNBs and the introduction of staged OFA in the bo iler. The LNBs and OFA reduce the emissions to about 0.2 lb/MMBtu.

The second measure taken to reduce the NOx emissions is the installation of a SCR system prior to the air heater. SCR uses aqueous ammonia and a catalyst to reduce NOx to N 2 and water ( H 2 O ) . The SCR system consists of three subsystems: reactor vessel, ammonia storage andCost and Performance Baseline

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66 injection, and gas flow control. The SCR system is designed for 65 percent reduction with 2 ppmv ammonia slip at the end of the catalyst life. This, along with the L NBs , achieves the
emission limit of 0.07 lb/MMBtu.

The SCR capital costs are included with the boiler costs, as is the cost for the initial load of catalyst.

SNCR was considered for this application. However, with the installation of the LNBs and OFA
syst em, the boiler exhaust gas contains relatively small amounts of NOx, which makes removal of the quantity of NOx with SNCR to reach the emissions limit of 0.07 lb/MMBtu difficult. SNCR works better in applications that contain medium to high quantities of NOx and require removal efficiencies in the range of 40 to 60 percent. SCR, because of the catalyst used in the reaction, can achieve higher efficiencies with lower concentrations of NOx.

SCR Operation Description

The reactor vessel is designed to allow p roper retention time for the ammonia to contact the NOx in the boiler exhaust gas. Ammonia is injected into the gas immediately prior to entering the reactor vessel. The catalyst contained in the reactor vessel enhances the reaction between the
ammonia a nd the NOx in the gas. Catalysts consist of various active materials such as titanium dioxide, vanadium pentoxide, and tungsten trioxide. The operating range for vanadium/titanium

based catalysts is 260°C (500 F) to 455°C (850 F). The boiler is equipped with economizer bypass to provide flue gas to the reactors at the desired temperature during periods of low flow rate, such as low load operation. Also included with the reactor vessel is soot

- blowing equipment used for cleaning the catalyst.

The aqueous ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, dilution air skid, and injection grid.

The flue gas flow control consists of ductwork, dampers, and flow straightening devices required
to route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass and associated dampers for low load temperature control are also included.

3.2.3 Flue Gas Desulfurization

The FGD process uses a lime

- SDA system. The function of the FGD syste m is to scrub the boiler exhaust gases to remove the SO 2 prior to release to the environment, or entering the CDR facility. Sulfur removal efficiency is 93 percent in the FGD unit for all cases. The scope of the FGD system is from the outlet of the combu stion air preheater to the ID fan.

As discussed in Section 3.1.4 , the CDR unit includes a polishing scrubber to further reduce the flue gas SO 2 concentration from about 55 ppmv at the FGD exit to the required 10 ppmv prior to

t he CDR absorber.

Lime

- spray drying is a dry scrubbing process that is generally used for low

- sulfur coal [ 40 ]

. Flue gas is treated in an absorber by mixing the gas stream concurrently with atomized lime slurry droplets. The lime slurry is atomized thr ough rotary cup spray atomizers or through dual fluid nozzles. Water in the spray droplets evaporates, cooling the gas from the inlet temperature
of 149°C ( 300°F ) or higher to 71°C to 82°C ( 160°F to 180°F ) . The final temperature is maintained at approxim ately 17°C ( 30oF ) above the flue gas adiabatic saturation temperature by regulating the quantity of the slurry water. The droplets absorb SO 2 from the gas and react the
SO 2 with the lime in the slurry. The desulfurized flue gas, along with reaction produ cts,Cost and Performance Baseline

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67 unreacted lime, and the fly ash pass out of the dry scrubber to the baghouse. Sorbent utilization is increased by about 40 percent by slurrying and recycling a portion of the solid effluent collected in the baghouse into the absorber with the virgin lime slurry.

The system description is divided into three sections:

Lime Handling and Reagent Preparation
SO 2 Removal Particulate Control (described in Section 3.1.3 )

Lime Reagent Handling and Preparation

Lime is received by t ruck and conveyed to storage. Lime is stored in a 14

- day capacity bulk storage lime silo. The lime is pneumatically conveyed to a 16

- hour capacity day bin. The lime day bin and a gravimetric feeder supply the lime to a 150 percent slaking system. This will allow two shift operations for the unit operating continuously at 100 percent load. A conventional lime slaker with high

- efficiency grit removal and lime recovery system is used. Two 100 percent capacity slurry transfer pumps are used to provide hig h reliability to transfer the slurry to the slurry tank. The process makeup water is added to the slaker to produce 20 percent solids slurry. The slurry is diluted on line, if required, prior to injection into an absorber. The slurry is fed to the absor ber by a dedicated reagent feed pump (100 percent spare capacity provided).

SO 2 Removal

Two absorbers, each treating 50 percent of the flue gas, are provided to achieve 93 percent SO 2 removal efficiency in the absorber and baghouse. The absorber is a vert ical, open chamber with cocurrent contact between the flue gas and lime slurry. The slurry is injected into the tower at the top using a rotary atomizer to remove SO 2 . A spare rotary atomizer is provided. The hopper
in the bottom of the CS absorber also removes large particles that may drop in the absorber. The absorber will be operated at 30°F adiabatic approach to saturation temperature. In the past, a lower approach had been proposed. However, over the years, operational problems associated
with th e lower adiabatic approach to saturation temperature, due to wetting of the walls and large deposits in the absorber, were alleviated by designs with 17°C ( 30°F ) adiabatic approach to saturation temperature.

3.2.4 Mercury Removal

Mercury removal is based on a co al Hg content of 0.081 ppm (dry) for PRB coal and 0.116 ppm (dry) for ND L . The basis for the coal Hg concentration was discussed in Section 2.3 . The combination of pollution control technologies used in the PC plants, SCR, dr y FGD, and fabric filters, result in a range of estimated co

- benefit capture depending on the study source [ 12

, 41 ]

. Average values of 15 percent co

- benefit Hg reduction for the PRB coal and 0 percent co

- benefit
reduction for the ND L coal were assumed.

An injection system utilizing brominated carbon is included to reduce Hg emission by 90 percent beyond the co

- benefit capture levels. This requires an injection rate of 1.0 and 1.5 lb carbon/ million standard cubic feet ( MMscf ) flue gas for PRB and ND L coals, respectively.

The carbon injection system includes a carbon silo with a capacity to store a 30

- day supply of carbon. The silo houses the equipment to regulate and pneumatically convey the carbon to the flue gas duct.Cost and Performance Baseline

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68 3.3 COMMO N PROCESS AREAS FOR CFB CASES ONLY

3.3.1 Steam Generator and Ancillaries

The steam generator for the SC CFB plant is an atmospheric CFB boiler. It includes a superheater, RH , economizer, and air heater. It is assumed for the purposes of this study that the

pow er plant is designed to be operated as a base

- loaded unit but with some consideration for daily or weekly cycling, as can be cost effectively included in the base design.

Scope

The steam generator includes the following:

 CFB combustor  Economizer  FD Fan s

 Startup circuit, including integral cyclone separators  Air preheaters  PA Fans

 Coal feeders  Limestone feeders  ID Fans

 Backpass

Air, Coal, Limestone, and Combustion Products

Fluidizing combustion air enters the furnace through an air plenum and dis tribution nozzles with the balance injected through secondary air ports above the fluidizing grid. Combustion air from the PA and FD fans is heated in regenerative air preheaters, recovering heat energy from the exhaust gases exiting the boiler. The crus hed coal and limestone are fed to the furnace through the lower walls. The upward flow of solids decreases with increased furnace height as heavier particles recirculate back down the furnace, resulting in declining local density with increased
furnace he ight. Particle separators in the top of the furnace enclosure collect most of the solids that remain in the flue gas and return them to the furnace while passing the flue gas to the convection pass (backpass) of the heat transfer surfaces. The dense bed does not contain any in

bed tube bundle heating surfaces. Because the mass flow rate of the recycled solids is many times the mass flow rate of the incoming fuel and air and the combustion gas, the bed solids temperature remains relatively uniform through out the surface height. Thus the water cooled furnace walls provide adequate heat absorption to maintain a target bed temperature of ~871°C (1,600°F). The hot combustion products rise to the top of the boiler and pass through internal cyclones, then supe rheater, RH, and economizer sections that comprise the backpass. The gases then pass through the regenerative air preheater and flow to the fabric filter, ID fan, and stack or CDR system.

SO 2 Removal

When limestone is added to the fluidized bed, it underg oes calcination and then reacts with the
SO 2 in the flue gas to form calcium sulfate. SO 2 reductions of 90 to 95 percent are typical. The
coal

- fired CFB produces low levels of NOx by combusting the coal in the circulating bed, where temperatures are main tained at approximately 871°C (1,600°F). This low temperature minimizes the formation of NOx, while allowing the oxidation of carbon and the capture of sulfur by calcium to proceed to completion. Further NOx reduction is achieved with SNCR ammoniaCost and Performance Baseline

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69 inject ion. Addition of dry limestone to the bed, in appropriate particle sizes, provides the calcium carbonate for sulfur capture.

Ash Removal

Solids are collected in multi

- cyclone hoppers and recycled to the furnace. Excess solids are purged via the bed sol ids drain (with cooling) or the baghouse, and sent to the plant ash handling
system.

Air Preheaters

Each steam generator is furnished with two vertical

- shaft, tri

- sector, regenerative type air preheaters with an assumed total air leakage of 5.5 percent. T hese units are driven by electric motors through gear reducers.

3.3.2 NO
x Control System

The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. The coal

fired CFB produces low levels of NOx by combusting the coal in the circulating bed, where temperatures are maintained at approximately 871°C (1,600°F). This low temperature along with OFA minimizes the formation of NOx to approximately 0.13 lb NOx/MMBtu. Further NOx reduction is achieved with SNCR ammonia injection

, which achieves the emission limit of
0.07 lb/MMBtu.

SNCR uses aqueous ammonia to reduce NOx to N 2 and H 2 O. The SNCR system consists of ammonia storage and injection. The SNCR system is designed for 46 percent reduction with

2 ppmv ammonia slip

The SNCR capital costs are in cluded with the boiler costs. The aqueous ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, dilution air skid, and injection grid.

3.3.3 Mercury Removal

Mercury removal is based on a coal Hg content of 0.0 81 ppm (dry) for PRB coal and 0.116 ppm (dry) for ND L . The basis for the coal Hg concentration was discussed in Section 2.3 . The combination of pollution control technologies used in the CFB plants, in

- bed limestone injection

, SNCR, and fabric filters, result in an assumed 57 percent co

- benefit mercury removal for both coal types [ 12 ]

. This level of co

- benefit capture is sufficient to meet the mercury emissions targets, however since it is curren tly standard practice to also include carbon injection, carbon injection was also included.Cost and Performance Baseline

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70 This page intentionally left blankCost and Performance Baseline

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71 4. PC CASES

This section contains an evaluation of SC plant designs ( Cases S12A, S12B, L12A, and L12B )
and USC PC plants ( Cases S 13A, S13B, L13A, and L13B ) . All the designs have a nominal net output of 550 megawatts electric ( MWe ) . All four SC plants use a single reheat 24.1 MPa/593°C/593°C (3,500 psig/1,100°F/1,100°F) cycle. All four USC plants use a single reheat
27.6 MPa/649°C /649°C (4,000 psi/1,200°F/1,200°F ) cycle. Cases S12A and S12B are very similar in terms of process, equipment, scope, and arrangement, except that Case S12B employs
CO 2 absorption/regeneration and compression/transport systems. Cases L12A and L12B differ from Cases S12A and S12B only through the use of a different coal type ( NDL instead of PRB).
The same is true for the USC cases. Cases S13A and S13B are very similar in terms of process, equipment, scope, and arrangement, except that Case S13B employs C O 2 absorption/regeneration and compression/transport systems. Cases L13A and L13B differ from Cases S13A and S13B only through the use of a different coal type ( NDL instead of PRB).

Section 4.1 covers the four non

- carbon capture cases and Section 4.2 covers the four CO 2 capture cases coal. The sections are organized analogously as follows:

Process and System Description provides an overview of the technology operati on as applied to Cases S12A/L12A and S13A/L13A in Section 4.1.1 and S12B/L12B and
S13B/L13B in Section 4.2.1

. Key Assumptions is a summary of study and modeling assumptions relevant to Cases
S12A/L1 2A and S13A/L13A in Section 4.1.2 and S12B/L12B and S13B/L13B in
Section 4.2.2

. Sparing Philosophy is provided for Cases S12A/L12A and S13A/L13A in Section 4.1.3
and S12 B/L12B and S13B/L13B in Section 4.2.3

. Performance Results provide the main modeling results from Cases S12A/L12A and
S13A/L13A in Section 4.1.4 and S12B/L12B and S13B/L13B in Section 4.2.4 , including the performance summary, environmental performance, carbon balance, sulfur balance, water balance, mass and energy balance diagrams and mass and energy balance tables.

Equipment Lists provide an itemized list of major equipm ent for Cases S12A/L12A and
S13A/L13A in Section 4.1.5 and S12B/L12B and S13B/L13B in Section 4.2.5 with account codes that correspond to the cost accounts in the Cost Estimates section.

Cost Estima tes provide a summary of capital and operating costs for Cases S12A/L12A
and S13A/L13A in Section 4.1.6 and S12B/L12B and S13B/L13B in Section 4.2.6

.
If the information for the CO 2 capture cases is identical to that presented for the non

- capture cases, a reference is made to the earlier section rather than repeating the information.

4.1 SC & USC PC NON

- CAPTURE CASES (PRB A ND LIGNITE)

4.1.1 Process Description

In this section the SC and USC PC processes without CO 2 capture are described. Both the SC
and USC process descriptions follow the block flow diagram (BFD) in Exhibit 4

- 1 and stream
numbers reference the same exhibit. The tables in Exhibit 4

- 2 through Exhibit 4

- 5 provide process data for the numbered streams in the BFD.Cost and Performance Baseline

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72 Coal (stream 8) and PA (stream 4) are introduced into the boiler through the wall

- fired burners. Additional combustion air, including the OFA, is provided by the FD fans (stream 2). The boiler operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is
accounted for in stream 7.

Flue gas exits the boiler through the SCR reactor (stream 10) and is cooled to 143°C (290°F ) in the combustion air preheater (not shown) before passing to the spray

- dryer absorbers. The gases from the absorbers are sent to the baghouse to collect the waste products and the fly ash. Activated carbon is injected for additional mercury removal pr ior to the baghouse. Flue gas exits the baghouse and enters the ID fan suction (stream 15). The clean flue gas passes to the plant stack and is discharged to the atmosphere.Cost and Performance Baseline

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73 Exhibit 4

- 1 Cases S12A, L12 A, S13A, and L13A Process Flow DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

74 Exhibit 4

- 2 Case S12A Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

75 Exhibit 4

- 2 Case S12A Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

76 Exhibit 4

- 3 Case L12A Stream TableCost and Performance Baseline

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77 Exhibit 4

- 3 Case L12A Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

78 Exhibit 4

- 4 Case S13A Stream TableCost and Performance Baseline

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79 Exhibit 4

- 4 Case S13A Stream Table (Continued)Cost and Performance Baseline

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80 Exhibit 4

- 5 Case L13A Stream TableCost and Performance Baseline

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81 Exhibit 4

- 5 Case L13A Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

82 4.1.2 Key Syste m Assumptions

System assumptions for Cases S12A and L12A, SC PC without CO 2 capture, and Cases S13A and L13A, USC PC without CO 2 capture, are compiled in Exhibit 4

- 6

.
Exhibit 4

- 6 P C Cases without CO 2 Capture Study Configuration Matrix

Case S12A
w/o CO 2 Capture Case L12A

w/o CO 2 Capture Case S13A

w/o CO 2 Capture Case L13A

w/o CO 2 Capture
Steam Cycle, MPa/°C/°C (psig/°F/°F) 24.1/593/593 (3,500/1,100/1,100) 24.1/593/593

(3,500/ 1,100/1,100) 27.6/649/649

(4,000/1,200/1,200) 27.6/649/649

(4,000/1,200/1,200)

Coal Subbituminous Lignite Subbituminous Lignite

Carbon Conversion, % 100 100 100 100
Condenser pressure, mm Hg (in Hg) 36 (1.4) 36 (1.4) 36 (1.4) 36 (1.4)

Combustion Air Pr eheater Flue Gas Exit Temp, °C (oF) 143 (290) 143 (290) 143 (290) 143 (290)

Cooling water to condenser, °C (oF) 9 (48) 8 (4 7 ) 9 (48) 8 (47 )

Cooling water from condenser, °C (oF) 20 (68) 19 (6 7 ) 20 (68) 19 (6 7 )

FGD Outlet, °C (°F) 82 (180) 82 (180) 82 (1 80) 82 (180)

SO 2 Control SDA FGD SDA FGD SDA FGD SDA FGD
FGD Efficiency, % 1 93 93 93 93

NOx Control LNB w/OFA and
SCR LNB w/OFA and

SCR LNB w/OFA and

SCR LNB w/OFA and

SCR
SCR Efficiency, % 1 65 65 65 65
Ammonia Slip (end of catalyst life), ppmv 2 2 2 2

Particulate Control Fabric Filter Fabric Filter Fabric Filter Fabric Filter

Fabric Filter E fficiency, % 1 99.97 99.97 99.97 99.97
Ash Distribution, Fly/Bottom 80% / 20% 80% / 20% 80% / 20% 80% / 20%

Mercury Control Co

- benefit Capture
and Carbon inj ection Carbon injection Co

- benefit Capture
and Carbon injection Carbon injection

Mercury removal efficiency, % 1 90 plus 90 90 plus 90

CO 2 Control N/A N/A N/A N/A

CO 2 Capture, % 1 N/A N/A N/A N/A

CO 2 Sequestration N/A N/A N/A N/A

1 Equipment removal e fficiencies

Balance of Plant

– Cases S12A, L12A, S13A, and L13A

The balance of plant assumptions are common to all cases and were presented previously in
Section 3.1.6

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

83 4.1.3 Sparing Philosophy

Single trains are used throughout the design 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:

One dry

- bottom, wall

- fired PC SC or USC boi ler (1 x 100 percent)

Two SCR reactors (2 x 50 percent)

One lime spray dryer system with two absorbers (1 x 100 percent)

Two single

- stage, in

- line, multi

- compartment fabric filters (2 x 50 percent)

One steam turbine (1 x 100 percent)

4.1.4 Cases S12A, L12A, S13 A, and L13A Performance Results

The non

- capture SC PC plant using PRB coal produces a net output of 550 MWe at a net plant efficiency of 38.7 percent (HHV basis). The same plant configuration using lignite coal produces a net output of 550 MWe at a net pl ant efficiency of 37.5 percent (HHV basis). The

non

- capture USC PC plant using PRB coal produces a net output of 550 MWe at a net plant efficiency of 39.9 percent (HHV basis). The same plant configuration using lignite coal produces a net output of 550 M We at a net plant efficiency of 38.8 percent (HHV basis).

Overall performance for the four plants is summarized in Exhibit 4

- 7

, which includes auxiliary power requirements. The cooling water system, including the CWPs , cooling tower fan, and the
air

- cooled condenser, account for about 30 percent of the auxiliary load in all cases; and the PA

, FD and induced draft fans account for an additional 30 percent in all cases.

In all PC combustion cases boiler efficiencies are 85.8 perce nt for the PRB coal cases and 83.5
percent for the lignite cases. In each case the boiler heat loss is one percent of the heat input and carbon conversion is 100 percent.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

84 Exhibit 4

- 7 PC Cases without CO 2 C apture Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe) S12A L12A S13A L13A

Steam Turbine Power 582,700 584,700 581,500 583,200

AUXILIARY LOAD SUMMARY, kWe
Coal Handling and Conveying 510 600 500 580

Pulverizers 3,8 50 5,140 3,740 4,970
Lime Handling & Preparation 170 190 170 180
Ash Handling 8 5 0 1,270 830 1,230

PA Fans 2,480 2,440 2,4 1 0 2,360

FD Fans 1,460 1,440 1,420 1,390

ID Fans 6,720 6,890 6,520 6,660

SCR 10 20 10 10
Baghouse 120 180 120 170
Spray Dryer F GD 2,230 2,570 2,170 2,490

Steam Turbine Auxiliaries 400 400 400 400
Condensate Pumps 790 790 320 320

CWP 2,400 2,410 2,340 2,3 4 0
Ground Water Pumps 250 250 240 240
Cooling Tower Fans 1,570 1,480 1,530 1,430

Air

- Cooled Condenser Fans 5,020 4,730 4,88 0 4,560

Miscellaneous Balance of Plant 1 2,000 2,000 2,000 2,000

Transformer Loss 1,830 1,840 1,830 1,840

TOTAL AUXILIARIES, kWe 32,660 34,640 31,430 33,170

NET POWER, kWe 550,040 550,060 5 50,070 550,030

Plant Capacity Factor, % 85% 85% 85% 85%
Net Plant Efficiency, % (HHV) 38.7% 37.5% 39.9% 38.8%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,298 (8,813) 9,593

(9,093) 9,023

(8,552) 9,279

(8,795)

CONDENSER COOLING DUTY GJ/hr (10 6 Btu/hr) 2,235 (2,118) 2,243

(2,126) 2,174

(2,061) 2,167

(2,054)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 256,752 (566,042) 342,852

(755,859) 249,170

(549,326) 331,614

(731,085)
Thermal Input , kWt 2 1,420,686 1,465,801 1,378,732 1,417,757

Raw W ater Withd rawal, m 3 /min (gpm ) 10.0 (2,649) 10.2 (2,683) 9.8 (2,578) 9.8 (2,597) Raw Water Consumption, m 3 /min (gpm) 7.9 (2,093) 8.0 (2,125) 7.7 (2,035) 7.8 (2,056)

1 Includes plant control systems, lighting, HVAC and miscellaneous low voltage loads

2 Thermal input based on as

- received HHV of coal

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 Cases S12A, L12A, S13A, and L1 3A is presented in Exhibit 4

- 8

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

85 Exhibit 4

- 8 PC Cases without CO 2 Capture Air Emissions

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

S12A L12A S 13A L13A S12A L12A S13A L13A S12A L12A S13A L13A

SO 2 0.051

(0.119) 0.057

(0.132) 0.051

(0.119) 0.057

(0.132) 1,945

(2,144) 2,236

(2,465) 1,888

(2,081) 2,163

(2,384) 0.448

(0.99) 0.514

(1.13) 0.436

(0.96) 0.498

(1.10)

NO X 0.030

(0.070) 0.030

(0.070) 0.030

(0.070) 0.030

(0.070) 1,146

(1,263) 1,182

(1,303) 1,112

(1,226) 1,144

(1,261) 0.264

(0.582) 0.272

(0.599) 0.257

(0.567) 0.263

(0.581)

Particulates 0.006

(0.0130) 0.006

(0.0130) 0.006

(0.0130) 0.006

(0.0130) 213

(235) 220

(242) 207

(228) 212

(234) 0.049

( 0.108) 0.050

(0.111) 0.048

(0.105) 0.049

(0.108)

Hg 2.57E

- 7

(5.97E

- 7) 4.82E

- 7

(1.12E

- 6) 2.57E

- 7

(5.97E

- 7) 4.82E

- 7

(1.12E

- 6) 0.010

(0.011) 0.019

(0.021) 0.009

(0.010) 0.018

(0.020) 2.25E

- 6

(4.96E

- 6) 4.35E

- 6

(9.59E

- 6) 2.19E

- 6

(4.83E

- 6) 4.22E

- 6

(9.29E

- 6)

CO 2 92.3

(214.7) 94.4

(219.5) 92.3

(214.7) 94.4

(219.5) 3,514,375

(3,873,936) 3,707,311

(4,086,611) 3,410,593

(3,759,535) 3,585,786

(3,952,653) 810

(1,786) 852

(1,877) 788

(1,737) 826

(1,820)

CO 2 1 858 (1,892) 905

(1,996) 833

(1,836) 876

(1,930)

1 CO 2 emissions based on net power instead of gross powerCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

86 SO 2 emissions are controlled using a lime spray dryer FGD system that achieves a removal efficiency of 93 percent. The waste is collected in the baghouse. A portion of the waste is stored
in a rec ycle storage silo, which is then used to mix with lime slurry to increase the reagent
utilization.

NOx emissions are controlled to about 0.2 lb/MMBtu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 65 percent to 0.07 lb/MMBtu.

Particulate emissions are controlled using a pulse jet fabric filter

, which operates at an efficiency of 99.97 percent.

Co

- benefit capture and activated carbon injection result in greater than 90 percent reduction of mercury emissions for th e PRB coal. For the lignite coal, no co

- benefit capture is assumed, and carbon injection results in a total Hg capture of 90 percent.

CO 2 emissions represent the uncontrolled discharge from the process.

The carbon balances for the four non

- capture PC ca ses are shown in Exhibit 4

- 9 and
Exhibit 4

- 10

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. 100 percent carbon conversion is assumed since carbon conver sion for low rank PC plants is typically about 99.9 percent.

Carbon in the air is not neglected here since the model accounts for air components throughout. Carbon leaves the plant as CO 2 in the stack gas. The activated carbon injected for mercury

remova l is captured in the baghouse and removed with the ash.

Exhibit 4

- 9 Cases S12A and L12A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S12A L12A S12A L12A

Coal 128,551

(28 3

, 407 ) 135, 611

(298,970) Ash 42 (93) 65 (143)

Air (CO 2 ) 260 (574) 273 (601) Stack Gas 128,812 (28 3

, 981 ) 135,883

(299,571)

Activated
Carbon 42 (93) 65 (143)

Total 128,854

(284,074) 135,948

(299,715) Total 128,854 (284,074) 135,948

(299,715)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

87 Exhibit 4

- 10 Cases S13A and L13A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S13A L13A S13A L13A

Coal 124,755

(275,037) 131,166

(289,171) Ash 41 (91) 63 (139)

Air (CO 2 ) 253 (557) 263 (580) Stack Gas 125,008 (275,595) 131,429

(289,751)

Activated
Carbon 41 (91) 63 (139)

Total 125,049

(275,685) 131,492

(289,890) Total 125,049 (275,685) 131,492

(289,890)

Exhibit 4

- 11 and Exhibit 4

- 12 show the sulf ur balances for the four non

- capture PC cases. Sulfur input comes solely from the sulfur in the coal. Sulfur output is the sulfur combined with lime in the ash, and the sulfur emitted in the stack gas

.

Exhibit 4

- 11 Cases S12A and L12A Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S12A L12A S12A L12A

Coal 1,868 (4,118) 2,148 (4,735) Ash 1,737 (3,829) 1,997 (4,403)

Stack Gas 131 (288) 150 (331)

Total 1,868 (4,118) 2,148 (4,735 ) Total 1,868 (4,118) 2,148 (4,735)

Exhibit 4

- 12 Cases S13A and L13A Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S13A L13A S13A L13A

Coal 1,813 (3,996) 2,077 (4,580) Ash 1,686 (3 ,716) 1,932 (4,259)

Stack Gas 127 (280) 145 (321)

Total 1,813 (3,996) 2,077 (4,580) Total 1,813 (3,996) 2,077 (4,580)

Exhibit 4

- 13

, Exhibit 4

- 14

, Exhibit 4

- 15 , and Exhibit 4

- 16 show the overall water balances for the plants. Raw water withdrawal is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for

a par ticular process. Some water is recovered within the process 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 3b (Combustion Cases)

88 Exhibit 4

- 13 Case S12A Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /m in (gpm) Process

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

FGD Makeup 0.94 (248) 0 (0) 0.94 (248) 0 (0) 0.94 (248)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 9.4 (2,474) 0.27 (72) 9.1 (2,402) 2.1 (556) 6.98 (1, 845)

Total 10.3 (2,722) 0.27 (72) 10.0 (2,649) 2.1 (556) 7.92 (2,093)

Exhibit 4

- 14 Case L12A Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /mi n (gpm) Process

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

FGD Makeup 1.04 (274) 0 (0) 1.04 (274) 0 (0) 1.04 (274)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 9.4 (2,482) 0.28 (73) 9.1 (2,409) 2.11 (558) 7.01 (1, 851)

Total 10.4 (2,755) 0.28 (73) 10.2 (2,683) 2.11 (558) 8.04 (2,125)

Exhibit 4

- 15 Case S13A Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /mi n (gpm) Process

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

FGD Makeup 0.91 (240) 0 (0) 0.91 (240) 0 (0) 0.91 (240)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 9.1 (2,413) 0.29 (75) 8.8 (2,337) 2.05 (543) 6.79 (1, 795)

Total 10.0 (2,653) 0.29 (75) 9.8 (2,578) 2.05 (543) 7.70 (2,035)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

89 Exhibit 4

- 16 Case L13A Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /mi n (gpm) Process

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

FGD Makeup 1.01 (266) 0 (0) 1.01 (266) 0 (0) 1.01 (266)

BFW Makeup 0 ( 0 ) 0 (0) 0 ( 0 ) 0 (0) 0 ( 0 )
Cooling Tower Makeup 9.1 (2,406) 0.29 (75) 8.8 (2,330) 2.05 (541) 6.77 (1, 789)

Total 10.1 (2,672) 0.29 (75) 9.8 (2,597) 2.05 (541) 7.78 (2,056)

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 17 through
Exhibit 4

- 24 :
Boiler and flue gas cleanup

Steam and FW

Overall plant energy balances are provided in tabular form in Exhibit 4

- 25 and Exhibit 4

- 26 for
the four non

- capture cases. The power out is the steam tu rbine power after generator losses.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

90 This page intentionally left blankCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

91 Exhibit 4

- 17 Case S12A Boiler and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

92 Exhibit 4

- 18 Case S12A Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

93 Exhibit 4

- 19 Case L12A Boiler and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

94 Exhibit 4

- 20 Case L12A Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

95 Exhibit 4

- 21 Case S13A Boiler and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

96 Exhibit 4

- 22 Case S13A Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

97 Exhibit 4

- 23 Case L13A Boiler and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

98 Exhibit 4

- 24 Case L13A Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

99 Exhibit 4

- 25 Cases S12A and L12A Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total

S12A L12 A S12A L12A S12A L12A S12A L12A

Heat In, GJ/hr (MMBtu/hr)

Coal 5,114 (4,848) 5,277

(5,002) 2.6 (2.5) 3.1 (2.9) 5,117 (4,850) 5,280

(5,004)

Combustion Air 29.2 (27.6) 27.5 (26.1) 29.2 (27.6) 27.5 (26.0) Raw Water Makeup 14.4 (13.6) 11.6 (11.0) 14.4 (13.6) 11.6 (11.0)

Lime 0.02 (0.02) 0.01 (0.01) 0.02 (0.02) 0.01 (0.01) Auxiliary Power 118 (111) 125 (118) 118 (111) 125 (118)

Totals 5,114 (4,848) 5,277

(5,002) 46.2 (43.8) 42.2 (40.0) 118 (111) 125 (118) 5, 278 ( 5
, 003 ) 5,444

(5,160) Heat Out, GJ/hr (MMBtu/hr)

Bottom Ash 0.5 (0.4) 0.8 (0.7) 0.5 (0.4) 0.8 (0.7) Fly Ash + FGD Ash 1.6 (1.6) 2.4 (2.3) 1.6 (1.6) 2.4 (2.3)

Flue Gas 734 (696) 928 (879) 734 (696) 928 (879)

Condenser 2,235 (2,118) 2,243

(2,126) 2,235 (2,118 ) 2,243

(2,126) Cooling Tower
Blowdown 11.7 (11.1) 11.4 (10.8) 11.7 (11.1) 11.4 (10.8)

Process Losses* 197 (187) 154 (146) 197 (187) 154 (146)

Power 2,098 (1,988) 2,105

(1,995) 2,098

(1,988) 2,105

(1,995)

Totals 0 ( 0 ) 0 (0) 3,180 (3,015) 3, 339

(3,165) 2,098

(1,988) 2,105

(1,995) 5,278

(5,003) 5,444

(5,160) * Process losses including steam turbine, combustion reactions, and gas cooling are estimated to match the heat input to the plant.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

100 Exhibit 4

- 26 Cases S13A and L13A Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total

S13A L13A S13A L13A S13A L13A S13A L13A
Heat In, GJ/hr (MMBtu/hr)

Coal 4,963 (4,704) 5,104

(4,838) 2.6 (2.4) 3.0 (2.8) 4,966 (4,707) 5,107

(4,840)

C ombustion Air 28.3 (26.8) 26.6 (25.2) 28.3 (26.8) 26.5 (25.2) Raw Water Makeup 14.0 (13.3) 11.3 (10.7) 14.0 (13.3) 11.3 (10.7)

Lime 0.02 (0.01) 0.01 (0.01) 0.02 (0.01) 0.01 (0.01) Auxiliary Power 113 (107) 119 (113) 113 (107) 1 19 (113)

Totals 4,963 (4,704) 5,104

(4,838) 44.9

(42.5) 40.8

(38.7) 113

(107) 119

(113) 5,121

(4,854) 5,264

(4,989) Heat Out, GJ/hr (MMBtu/hr)

Bottom Ash 0.5 (0.4) 0.7 (0.7) 0.5 (0.4) 0.7 (0.7) Fly Ash + FGD Ash 1.6 (1.5) 2.3 (2.2) 1.6 (1.5 ) 2.3 (2.2)

Flue Gas 713 (676) 898 (851) 713 (676) 898 (851)

Condenser 2,174 (2,061) 2,167

(2,054) 2,174 (2,061) 2,167

(2,054) Cooling Tower
Blowdown 11.4 (10.8) 11.1 (10.5) 11.4 (10.8) 11.1 (10.5)

Process Losses 128 (121) 85 (80) 128 ( 121) 85 (80)

Power 2,093 (1,984) 2,100

(1,990) 2,093

(1,984) 2,100

(1,990)

Totals 0 (0) 0 (0 ) 3,028 ( 2,870 ) 3,165

(2,999) 2,093

(1,984) 2,100

(1,990) 5,12 1

(4,85 4 ) 5,264

(4,989) * Process losses including steam turbine, combustion reactions, and ga s cooling are estimated to match the heat input to the plant.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

101 4.1.5 PC Cases without CO 2 Capture Equipment Lists

Major equipment items for the SC PC and USC PC Cases with no CO 2 capture using PRB or lignite coal are shown in the following tables. The equipmen t lists are not meant to be comprehensive, but rather representative. The accounts used in the equipment list correspond to
the account numbers used in the cost estimates in Section 4.1.6 . In general, the design conditions
in clude 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 3b (Combustion Cases)

102 ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S1 3A Design

Condition L13A Design

Condition

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2(0) 181 tonne (200 ton) 181 tonne

(200 ton) 181 tonne

(200 ton) 181 tonne

(200 ton)

2 Feeder Belt 2(0) 572 tonne/hr (630 tph) 572 tonne/hr (630

tph) 572 tonne/hr (630

tph) 572 tonne/hr

(630 tph)

3 Conveyor No. 1 Belt 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph)

4 Transfer Tower No. 1 Enclosed 1(0) N/A N/A N/A N/A

5 Conveyor No. 2 Belt 1(0) 1,13 4 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph)

6 As

- Received Coal Sampling System Two

- stage 1(0) N/A N/A N/A N/A

7 Stacker/Reclaimer Traveling, linear 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph)

8 Reclaim Hopper N/A 2(1) 54 tonne (60 ton) 73 tonne (80 ton) 54 tonne (60 ton) 73 tonne (80 ton)

9 Feeder Vibratory 2(1) 209 tonne/hr (230 tph) 281 tonne/hr

(310 tph) 209 tonne/hr

(230 t ph) 272 tonne/hr

(300 tph)

10 Conveyor No. 3 Belt w/ tripper 1(0) 426 tonne/hr (470 tph) 562 tonne/hr

(620 tph) 408 tonne/hr

(450 tph) 544 tonne/hr

(600 tph)

11 Crusher Tower N/A 1(0) N/A N/A N/A N/A

12 Coal Surge Bin w/
Vent Filter Dual outlet 2(0) 209 tonne (230 ton) 281 tonne

(310 ton) 209 tonne

(230 ton) 272 tonne

(300 ton)

13 Crusher Impactor
reduction 2(0) 8cm x 0

- 3cm x 0 (3 ‖ x 0

- 1

- 1/4 ‖ x 0) 8cm x 0

- 3cm x 0

(3 ‖ x 0

- 1

- 1/4 ‖ x 0) 8cm x 0

- 3cm x 0

(3 ‖ x 0

- 1

- 1/4 ‖ x 0) 8cm x 0

- 3cm x 0

(3 ‖ x 0

- 1

- 1/4 ‖ x 0)

14 As

- Fired Coal Sampling System Swing hammer 1(0) N/A N/A N/A N/A

15 Conveyor No. 4 Belt w/tripper 1(0) 426 tonne/hr (470 tph) 562 tonne/hr

(620 tph) 408 tonne/hr

(450 tph) 544 tonne/hr

(600 tph)

16 Transfer Tower No. 2 Enclosed 1(0 ) N/A N/A N/A N/ACost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

103 Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S1 3A Design

Condition L13A Design

Condition

17 Conveyor No. 5 Belt w/ tripper 1(0) 426 tonne/hr (470 tph) 562 tonne/hr

(620 tph) 408 tonne/hr

(450 tph) 544 tonne/hr

(600 tph)

18 Coal Silo w/ Vent
Filter and Slide Gates Field erected 6(0) 454 tonne (500 ton) 635 tonne

(700 ton) 454 tonne

(500 ton) 635 tonne

(700 ton)

19 Lime Truck Unloading System N/A 1(0) 18 tonne/hr (20 tph) 18 tonne/hr

(20 tph) 18 tonne/hr

(20 tph) 18 tonne/hr

(20 tph)

20 Lime Bulk Storage
Silo w/Vent Filter Field erected 3(0) 454 tonne (500 ton) 544 tonne

( 600 ton) 454 tonne

(500 ton) 544 tonne

(600 ton)

21 Lime Live Storage Transport Pneumatic 1(0) 6 tonne/hr (7 tph) 7 tonne/hr (8 tph) 6 tonne/hr (7 tph) 7 tonne/hr (8 tph)

22 Limestone Day Bin w/ actuator 2(0) 54 tonne (60 ton) 64 tonne (70 ton) 45 tonne (50 ton) 54 tonne (60 ton)

23 Activated Carbon Storage Silo and Feeder System with
Vent Filter Shop assembled 1(0) Silo

- 36 tonne (40 ton)
Feeder

- 45 kg/hr (100 lb/hr) Silo

- 54 tonne

(60 ton)
Feeder

- 73 kg/hr (160 lb/hr) Silo

- 36 tonne

(40 ton)
Feede r

- 45 kg/hr (100 lb/hr) Silo

- 45 tonne

(50 ton)
Feeder

- 68 kg/hr (150 lb/hr)

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment

No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A De sign

Condition

1 Coal Feeder Gravimetric 6(0) 45 tonne/hr (50 tph) 64 tonne/hr

(70 tph) 45 tonne/hr

(50 tph) 64 tonne/hr

(70 tph)

2 Coal Pulverizer Ball type or equivalent 6(0) 45 tonne/hr (50 tph) 64 tonne/hr

(70 tph) 45 tonne/hr

(50 tph) 64 tonne/hr

(70 tph)

3 Lime Slaker N/A 1(1) 5 tonne/hr (6 tph) 6 tonne/hr (7 tph) 5 tonne/hr (6 tph) 6 tonne/hr (7 tph)

4 Lime Slurry Tank Field Erected 1(1) 276,337 liters (73,000 gal) 314,192 liters

(83,000 gal) 264,981 liters

(70,000 gal) 302,835 liters

(80,000 g al)

5 Lime Slurry Feed

Pumps Horizontal

centrifugal 1(1) 303 lpm @ 9m

H 2 O (80 gpm @
30 ft H 2 O) 341 lpm @ 9m

H 2 O (90 gpm @
30 ft H 2 O) 265 lpm @ 9m

H 2 O (70 gpm @
30 ft H 2 O) 303 lpm @ 9m

H 2 O (80 gpm @
30 ft H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

104 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEM S AND EQUIPMENT

Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

1 Demineralized Water Storage Tank Vertical, cylindrical,
outdoor 2(0) 1,086,413 liters (287,000 gal) 1,090,199 liters

(288,000 gal) 1,131,838 liters

(299,000 gal) 1,128,053 liters

(298,000 gal)

2 Condensate Pumps Vertical canned 1(1) 23,091 lpm @
213 m H 2 O (6,100 gpm @
700 ft H 2 O) 23,470 lpm @

213 m H 2 O (6,200 gpm @
700 ft H 2 O) 19,306 lpm @

91 m H 2 O (5,100 gpm @ 300 ft

H 2 O) 19,306 lpm @

91 m H 2 O (5,100 gpm @ 300 ft

H 2 O)

3 Deaerator and Storage
Tank Horizontal spray
type 2 (0) (USC) 1 (0) (SC) 1,809,834 kg/hr

(3,990,000 lb/hr),
5 min. tank 1,816,184 kg/hr

(4,004,000 lb/hr),
5 min. tank 1,881,501 kg/h r

(4,148,000 lb/hr),
5 min. Tank 1,880,140 kg/hr

(4,145,000 lb/hr),
5 min. tank

4 Boiler Feed

Pump/Turbine Barrel type, multi

stage, centrifugal 2 (2) (USC) 1 (1) (SC) 30,283 lpm @

3,444 m H 2 O (8,000 gpm @ 11,300 ft H 2 O) 30,662 lpm @

3,444 m H 2 O (8,100 gp m @ 11,300 ft H 2 O) 31,419 lpm @

3,871 m H 2 O (8,300 gpm @ 12,700 ft H 2 O) 31,419 lpm @

3,871 m H 2 O (8,300 gpm @ 12,700 ft H 2 O)

5 Startup Boiler Feed Pump, Electric Motor
Driven Barrel type, multi

stage, centrifugal 1(0) 9,085 lpm @ 3,444 m H 2 O (2,400 gpm @ 11,300 ft H 2 O) 9,085 lpm @

3,444 m H 2 O (2,400 gpm @ 11,300 ft H 2 O) 9,464 lpm @

3,871 m H 2 O (2,500 gpm @ 12,700 ft H 2 O) 9,464 lpm @

3,871 m H 2 O (2,500 gpm @ 12,700 ft H 2 O)

6 LP Feedwater Heater

1A/1B Horizontal U

- tube 2(0) 693,996 kg/hr (1,530,000 lb/hr) 6 93,996 kg/hr

(1,530,000 lb/hr) 571,526 kg/hr

(1,260,000 lb/hr) 571,526 kg/hr

(1,260,000 lb/hr)

7 LP Feedwater Heater

2A/2B Horizontal U

- tube 2(0) 693,996 kg/hr (1,530,000 lb/hr) 693,996 kg/hr

(1,530,000 lb/hr) 571,526 kg/hr

(1,260,000 lb/hr) 571,526 kg/hr

(1,260,000 lb/hr)

8 LP Feedwater Heater

3A/3B Horizontal U

- tube 2(0) 693,996 kg/hr (1,530,000 lb/hr) 693,996 kg/hr

(1,530,000 lb/hr) 571,526 kg/hr

(1,260,000 lb/hr) 571,526 kg/hr

(1,260,000 lb/hr)

9 LP Feedwater Heater
4A/4B Horizontal U

- tube 2(0) 693,9 96 kg/hr (1,530,000 lb/hr) 693,996 kg/hr

(1,530,000 lb/hr) 571,526 kg/hr

(1,260,000 lb/hr) 571,526 kg/hr

(1,260,000 lb/hr)

10 HP Feedwater Heater 6 Horizontal U

- tube 1(0) 1,809,834 kg/hr (3,990,000 lb/hr) 1,814,369 kg/hr

(4,000,000 lb/hr) 1,882,408 kg/hr

(4,150,000 lb/hr) 1,882,408 kg/hr

(4,150,000 lb/hr)

11 HP Feedwater Heater 7 Horizontal U

- tube 1(0) 1,809,834 kg/hr (3,990,000 lb/hr) 1,814,369 kg/hr

(4,000,000 lb/hr) 1,882,408 kg/hr

(4,150,000 lb/hr) 1,882,408 kg/hr

(4,150,000 lb/hr)

12 HP Feedwater he ater 8 Horizontal U

- tube 1(0) 1,809,834 kg/hr (3,990,000 lb/hr) 1,814,369 kg/hr

(4,000,000 lb/hr) 1,882,408 kg/hr

(4,150,000 lb/hr) 1,882,408 kg/hr

(4,150,000 lb/hr)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

105 Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

13 Auxiliary Boiler Shop fabricated,
water tube 1(0) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8

MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8

MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8

MPa, 343°C (40,000 lb/hr, 400 psig, 650°F)

14 Fuel Oil System No. 2 fuel oil for light off 1(0) 1,135,624 liter (300,000 gal) 1,135,624 liter

(300,000 gal) 1,135,624 liter

(300,000 gal) 1,135,624 liter

(300,000 gal)

15 Service Air

Compressors Flooded Screw 2(1) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7

MPa (1,000 scfm @ 100 p sig) 28 m 3 /min @ 0.7

MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7

MPa (1,000 scfm @ 100 psig)

16 Instrument Air Dryers Duplex, regenerative 2(1) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000

scfm) 28 m 3 /min (1,000

scfm) 28 m 3 /min (1,000

scfm)

17 Closed Cycle Co oling

Heat Exchangers Shell and tube 2(0) 53 GJ/hr (50 MMBtu/hr) each 53 GJ/hr (50

MMBtu/hr) each 53 GJ/hr (50

MMBtu/hr) each 53 GJ/hr (50

MMBtu/hr) each

18 Closed Cycle Cooling

Water Pumps Horizontal centrifugal 2(1) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 10 0 ft

H 2 O) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O)

19 Engine

- Driven Fire

Pump Vertical turbine, diesel engine 1(1) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O)

20 Fire Service Booster

Pump Two

- stage horizontal centrifugal 1(1) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O)

21 Raw Water Pumps Stainless steel, single
suction 2(1) 2,650 lpm @ 43

m H 2 O (700 gpm
@ 140 ft H 2 O) 2,650 lpm @ 43

m H 2 O (7 00 gpm
@ 140 ft H 2 O) 2,574 lpm @ 43

m H 2 O (680 gpm
@ 140 ft H 2 O) 2,574 lpm @ 43

m H 2 O (680 gpm
@ 140 ft H 2 O)

22 Ground Water Pumps Stainless steel, single
suction 2(1) 2,650 lpm @ 268

m H 2 O (700 gpm
@ 880 ft H 2 O) 2,650 lpm @ 268

m H 2 O (700 gpm
@ 880 ft H 2 O) 2,574 lpm @ 268

m H 2 O (680 gpm
@ 880 ft H 2 O) 2,574 lpm @ 268

m H 2 O (680 gpm
@ 880 ft H 2 O)

23 Filtered Water Pumps Stainless steel, single
suction 2(1) 303 lpm @ 49 m

H 2 O (80 gpm @
160 ft H 2 O) 303 lpm @ 49 m

H 2 O (80 gpm @
160 ft H 2 O) 303 lpm @ 49 m

H 2 O (80 gpm @
160 ft H 2 O) 303 lpm @ 49 m

H 2 O (80 gpm @
160 ft H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

106 Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

24 Filtered Water Tank Vertical, cylindrical 1(0) 299,048 liter (79,000 gal) 299,048 liter

(79,000 gal) 299,048 liter

(79,000 gal) 299,048 liter

(79,000 gal)

25 Makeup Water

Demineralizer Mul ti

- media filter, cartridge filter, RO membrane assembly,
electrodeionization
unit 1(1) 606 lpm (160 gpm) 606 lpm (160

gpm) 644 lpm (170

gpm) 644 lpm (170

gpm)

26 Liquid Waste

Treatment System -- 1(0) 10 years, 24

- hour

storm 10 years, 24

- hour

storm 10 year s, 24

- hour

storm 10 years, 24

- hour

storm

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design
Condition S13A Design
Condition L13A Design
Condition

1 Boiler Once

- thru,
wall

- fired,
low NO x burners,
overfire air 1(0) Supercritical, 1,809,834 kg/hr steam
@ 25.5
MPa/602°C/602°C (3,990,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) Supercritical, 1,814,369 kg/hr steam
@ 25.5
MPa/602°C/602°C (4,000,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) U ltra

- supercritical, 1,882,408 kg/hr steam
@ 29.0
MPa/657°C/657°C (4,150,000 lb/hr steam @ 4,200 psig/1,215°F/1,215°F) Ultra

- supercritical, 1,882,408 kg/hr steam
@ 29.0
MPa/657°C/657°C (4,150,000 lb/hr steam @ 4,200 psig/1,215°F/1,215°F)

2 Primary Air

Fan Centrifugal 2(0) 413,676 kg/hr, 6,162

m 3 /min @ 123 cm WG (912,000 lb/hr, 217, 600 acfm @ 48 in. WG) 432,727 kg/hr, 6,046

m 3 /min @ 123 cm WG (954,000 lb/hr, 213,500 acfm @ 48 in. WG) 400,976 kg/hr, 5,978

m 3 /min @ 123 cm WG (884,000 lb/hr, 211,100 acfm @ 48

i n. WG) 417,759 kg/hr, 5,836

m 3 /min @ 123 cm WG (921,000 lb/hr, 206,100 acfm @ 48 in. WG)

3 Forced Draft

Fan Centrifugal 2(0) 620,061 kg/hr, 9,243

m 3 /min @ 47 cm WG (1,367,000 lb/hr, 326,400 acfm @ 19 in. WG) 648,637 kg/hr, 9,070

m 3 /min @ 47 cm WG (1,430,0 00 lb/hr, 320,300 acfm @ 19 in. WG) 601,917 kg/hr, 8,968

m 3 /min @ 47 cm WG (1,327,000 lb/hr, 316,700 acfm @ 19 in. WG) 626,411 kg/hr, 8,756

m 3 /min @ 47 cm WG (1,381,000 lb/hr, 309,200 acfm @ 19 in. WG)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

107 Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design
Condition S13A Design
Condition L13A Design
Condition

4 Induced
Draft Fan Centrifugal 2(0) 1,210,638 kg/hr, 24,653 m 3 /min @ 82 cm WG (2,669,000 lb/hr, 870,600 acfm @ 32 in. WG) 1,302,264 kg/hr,

25,239 m 3 /min @ 82 cm WG (2,871,000 lb/hr, 891,300 acfm @ 32 in. WG) 1,174,351 kg/hr,

23,919 m 3 /min @ 82 cm WG (2,589,000 lb/hr, 844,700 acfm @ 32 in. WG) 1,257,812 kg/h r,

24,378 m 3 /min @ 82 cm WG (2,773,000 lb/hr, 860,900 acfm @ 32 in. WG)

5 SCR Reactor
Vessel Space for

spare layer 2(0) 2,422,183 kg/hr (5,340,000 lb/hr) 2,603,620 kg/hr (5,740,000 lb/hr) 2,349,608 kg/hr (5,180,000 lb/hr) 2,517,438 kg/hr (5,550,000 lb/hr)

6 SCR Catalyst -- 3(0)

-- -- -- --

7 Dilution Air
Blower Centrifugal 2(1) 40 m 3 /min @ 108 cm WG (1,400 acfm @ 42 in. WG) 42 m 3 /min @ 108 cm

WG (1,500 acfm @ 42 in. WG) 40 m 3 /min @ 108 cm

WG (1,400 acfm @ 42 in. WG) 40 m 3 /min @ 108 cm

WG (1,400 acfm @

42 in. WG)

8 Ammonia Storage Horizontal

tank 5(0) 45,425 liter (12,000 gal) 45,425 liter (12,000 gal) 41,640 liter (11,000 gal) 45,425 liter (12,000 gal)

9 Ammonia Feed Pump Centrifugal 2(1) 9 lpm @ 91 m H 2 O (2 gpm @ 300 ft H 2 O) 9 lpm @ 91 m H 2 O (2 gpm @ 3 00 ft H 2 O) 8 lpm @ 91 m H 2 O (2 gpm @ 300 ft H 2 O) 9 lpm @ 91 m H 2 O (2 gpm @ 300 ft H 2 O)

ACCOUNT 5 FLUE GAS CLEANUP

Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

1 Fabric Filter Single stage, high

- ratio with pulse

- jet online cleaning system,
air

- to

- cloth ratio

- 3.5 ft/min 2(0) 1,210,638 kg/hr (2,669,000 lb/hr) 99.9% efficiency 1,302,264 kg/hr

(2,871,000 lb/hr) 99.9% efficiency 1,174,351 kg/hr

(2,589,000 lb/hr)

9 9.9% efficiency 1,257,812 kg/hr

(2,773,000 lb/hr) 99.9% efficiency

2 Spray Dryer Co

- current open

spray 2(0) 26,420 m 3 /min (933,000 acfm) 27,128 m 3 /min

(958,000 acfm) 25,627 m 3 /min

(905,000 acfm) 26,221 m 3 /min

(926,000 acfm)

3 Atomizer Rotary 2(1) 151 lpm @ 64 m

H 2 O (40 gpm @
210 ft H 2 O) 189 lpm @ 64 m

H 2 O (50 gpm @
210 ft H 2 O) 151 lpm @ 64 m

H 2 O (40 gpm @
210 ft H 2 O) 189 lpm @ 64 m

H 2 O (50 gpm @
210 ft H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

108 Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

4 Spray Dryer Solids

Conveying --- 2(0)

--- --- --- ---

5 Carbon Injectors

--- 1(0) 45 kg/hr (100 lb/hr) 73 kg/hr (160

lb/hr) 45 kg/hr (100

lb/hr) 68 kg/hr (150

lb/hr)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES

N/A

ACCOUNT 7 HRSG, DUCTING & STACK

Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13 A Design

Condition L13A Design

Condition

1 Stack Reinforced
concrete with
FRP liner 1(0) 152 m (500 ft) high x 6.4 m (21 ft)
diameter 152 m (500 ft)

high x 6.5 m (21 ft)
diameter 152 m (500 ft)

high x 6.3 m (21 ft)
diameter 152 m (500 ft)

high x 6.4 m (21 ft)
diameter

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

1 Steam Turbine Commercially
available
advanced steam
turbine 1(0) 613 MW 24.1
MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 615 MW 24.1

MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 612 MW 27.6

MPa/649°C/649°C (4000 psig/ 1200°F/1200°F) 614 MW 27.6

MPa/649°C/649°C (4000 psig/ 1200°F/1200°F)

2 Steam Turbine
Generator Hydrogen cooled,

static excitation 1(0) 680 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 680 MVA @ 0.9

p.f., 24 kV, 60 Hz,

3

- phase 680 MVA @ 0.9

p.f., 24 kV, 60 Hz,

3

- phase 680 MVA @ 0.9

p.f., 24 kV, 60 Hz,

3

- phaseCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

109 Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

3 Surface Condenser Single pass,
divi ded waterbox including

vacuum pumps 1(0) 1,220 GJ/hr (1,160 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 1,230 GJ/hr (1,170

MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F) 1,190 GJ/hr (1,130

MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 1,190 GJ/hr (1,130

MMBtu/hr), Condensing temperature 32°C (9 0°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F)

4 Air

- cooled

Condenser --- 1(0) 1,220 GJ/hr (1,160 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 1,230 GJ/hr (1,170

MMBtu/hr), Condensing
temperat ure 32°C (90°F), Ambient temperature 4°C (40°F) 1,190 GJ/hr (1,130

MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 1,190 GJ/hr (1,130

MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 4°C (40°F)

ACCOUNT 9 COO LING WATER SYSTEM

Equipment
No. Description Type Operating Qty (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

1 Circulating Water Pumps Vertical, wet pit 2(1) 242,300 lpm @ 30

m (64,000 gpm @ 100 ft) 242,3 00 lpm @ 30

m (64,000 gpm @ 100 ft) 234,700 lpm @ 30

m (62,000 gpm @ 100 ft) 234,700 lpm @ 30

m (62,000 gpm @ 100 ft)

2 Cooling Tower Evaporative, mechanical draft,
multi

- cell 1(0) 3°C (37°F) wet bulb / 9°C (48°F)
CWT / 20°C (68°F) HWT / 1,340 GJ/hr (1,27 0 MMBtu/hr) heat duty 2°C (36°F) wet

bulb / 8°C (47°F)
CWT / 19°C (67°F) HWT / 1,350 GJ/hr (1,280 MMBtu/hr) heat duty 3°C (37°F) wet

bulb / 9°C (48°F)
CWT / 20°C (68°F) HWT / 1,308 GJ/hr (1,240 MMBtu/hr) heat duty 3°C (37°F) wet

bulb / 9°C (48°F)
CWT / 20° C (68°F) HWT / 1,308 GJ/hr (1,240 MMBtu/hr) heat dutyCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

110 ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment
No. Description Type Operating Qty. (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

1 Econ omizer Hopper (part of boiler scope of supply) -- 4(0)

-- -- -- --

2 Bottom Ash Hopper

(part of boiler scope of supply) -- 2(0)

-- -- -- --

3 Clinker Grinder

-- 1(1) 4.5 tonne/hr (5 tph) 7.3 tonne/hr

(8 tph) 4.5 tonne/hr

(5 tph) 7.3 tonne/hr (8

tph)

4 Pyrites Hopper (part

of pulverizer scope of supply included with boiler) -- 6(0)

-- -- -- --

5 Hydroejectors

-- 12(0)

-- -- -- --

6 Economizer /Pyrites

Transfer Tank -- 1(0)

-- -- -- --

7 Ash Sluice Pumps Vertical, wet pit 1(1) 189 lpm @ 17 m

H 2 O (50 gp m @
56 ft H 2 O) 303 lpm @ 17 m

H 2 O (80 gpm @
56 ft H 2 O) 189 lpm @ 17 m

H 2 O (50 gpm @
56 ft H 2 O) 303 lpm @ 17 m

H 2 O (80 gpm @
56 ft H 2 O)

8 Ash Seal Water

Pumps Vertical, wet pit 1(1) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O)

9 Hydrobins

-- 1(1) 189 lpm (50 gpm) 303 lpm (80 gpm) 189 lpm (50 gpm) 303 lpm (80 gpm)

10 Baghouse Hopper

(part of baghouse scope of supply) -- 24(0)

- - -- -- --

11 Air Heater Hopper

(part of boiler scope of supply) -- 10(0)

-- -- -- --

12 Air Blower

-- 1(1) 25 m 3 /min @ 0.2 MPa (880 scfm @ 24 psi) 36 m 3 /min @ 0.2

MPa (1,280 scfm @ 24 psi) 24 m 3 /min @ 0.2

MPa (850 scfm @ 24 psi) 35 m 3 /min @ 0.2

MPa (1,2 40 scfm @ 24 psi)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

111 Equipment
No. Description Type Operating Qty. (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

13 Fly Ash Silo Reinforced

concrete 2(0) 1,630 tonne (1,800 ton) 2,360 tonne

(2,600 ton) 1,540 tonne

(1,700 ton) 2,270 tonne

(2,500 ton)

14 Slide Gate Valves

-- 2(0)

-- -- -- -- 15 Unloader

-- 1(0)

-- -- -- --

16 Telescoping

Unloading Chute -- 1(0) 154 tonne/hr (170 tph) 227 tonne/hr

(250 tph) 145 tonne/hr

(160 tph) 218 tonne/hr

(240 tph)

17 Recycle Waste

Storage Silo Reinforced

concrete 2(0) 272 tonne (300 ton) 363 tonne

(400 ton) 272 tonne

(300 ton) 272 tonne (300

ton)

18 Recycle W aste

Conveyor -- 1(0) 36 tonne/hr (40 tph) 36 tonne/hr

(40 tph) 36 tonne/hr

(40 tph) 36 tonne/hr

(40 tph)

19 Recycle Slurry Mixer

-- 1(1) 984 lpm (260 gpm) 1,060 lpm

(280 gpm) 946 lpm

(250 gpm) 1,060 lpm

(280 gpm)

20 Recycle Waste

Slurry Tank -- 1(0) 60, 570 liters (16,000 gal) 64,350 liters

(17,000 gal) 56,780 liters

(15,000 gal) 64,350 liters

(17,000 gal)

21 Recycle Waste Pump

-- 1(1) 984 lpm (260 gpm) 1,060 lpm

(280 gpm) 946 lpm

(250 gpm) 1,060 lpm

(280 gpm)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipme nt
No. Description Type Operating Qty. (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

1 STG Transformer Oil

- filled 1(0) 24 kV/345 kV, 650 MVA, 3

- ph,

60 Hz 24 kV/345 kV,

650 MVA, 3

- ph,

60 Hz 24 kV/345 kV,

6 50 MVA, 3

- ph,

60 Hz 24 kV/345 kV,

650 MVA, 3

- ph,

60 Hz

2 Auxiliary

Transformer Oil

- filled 1(1) 24 kV/4.16 kV, 34 MVA, 3

- ph,

60 Hz 24 kV/4.16 kV,

36 MVA, 3

- ph,

60 Hz 24 kV/4.16 kV, 33

MVA, 3

- ph, 60

Hz 24 kV/4.16 kV, 35

MVA, 3

- ph, 60

Hz

3 Low Voltage

Trans former Dry ventilated 1(1) 4.16 kV/480 V, 5 MVA, 3

- ph, 60

Hz 4.16 kV/480 V, 5

MVA, 3

- ph, 60

Hz 4.16 kV/480 V, 5

MVA, 3

- ph, 60

Hz 4.16 kV/480 V, 5

MVA, 3

- ph, 60

Hz

4 STG Isolated Phase

Bus Duct and Tap

Bus Aluminum, self

cooled 1(0) 24 kV, 3

- ph, 60

Hz 24 k V, 3

- ph, 60

Hz 24 kV, 3

- ph, 60

Hz 24 kV, 3

- ph, 60

HzCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

112 Equipme nt
No. Description Type Operating Qty. (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

5 Medium Voltage

Switchgear Metal clad 1(1) 4.16 kV, 3

- ph, 60

Hz 4.16 kV, 3

- ph, 60

Hz 4.16 kV, 3

- ph, 60

Hz 4.16 kV, 3

- ph, 60

Hz

6 Low Voltage

Switchgear Metal enclosed 1(1) 480 V, 3

- ph, 60

Hz 480 V, 3

- ph, 60

Hz 480 V, 3

- ph, 60

Hz 480 V, 3

- ph, 60

Hz

7 Emergency Diesel

Generator Sized for

emergency shutdown 1(0) 750 kW, 480 V,
3

- ph, 60 Hz 750 kW, 480 V,

3

- ph, 60 Hz 750 kW, 480 V, 3

-

ph, 60 Hz 750 kW, 480 V, 3

-

ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONT ROL

Equipment
No. Description Type Operating Qty. (Spares) S12A Design

Condition L12A Design

Condition S13A Design

Condition L13A Design

Condition

1 DCS

- Main Control Monitor/keyboard, Operator printer, Engineering printer 1(0) Operator stations/printers and engineering stations/printers Operator

stations/printers and engineering stations/printers Operator

stations/printers and engineering stations/printers Operator

stations/printers and engineering stations/printers

2 DCS

- Processor Microprocessor
with redundant input/output 1(0) N/A N/A N/A N/A

3 DCS

- Data

Highway Fiber optic 1(0) Fully redundant, 25% spare Fully redundant,

25% spare Fully redundant,

25% spare Fully redundant,

25% spareCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

113 4.1.6 PC Cases without CO 2 Capture

– Cost Estimating

Costs Result s
The cost estimating methodology was described previously in Section 2.6 . The TPC summary organized by cost account, detailed breakdown of capital costs, owner’s costs, and initial and
annual O&M costs for the SC PC PRB case (S12A) are shown in Exhibit 4

- 27

, Exhibit 4

- 28

, Exhibit 4

- 29 , and Exhibit 4

- 30 respectively. The same data for the SC PC lignite cases (L12A)
are shown in Exhibit 4

- 31

, Exhibit 4

- 32

, Exhibit 4

- 33 , and Exhibit 4

- 34 ; the USC PC PRB case (S13A) are shown in Exhibit 4

- 35

, Exhibit 4

- 36

, Exhibit 4

- 37 , and Exhibit 4

- 38 , and the USC PC Lignite case (L13A) are shown in Exhibit 4

- 39

, Exhibit 4

- 40

, Exhibit 4

- 41 , and Exhibit 4

- 42

. The estimated TOC of the SC PC plant with no CO 2 capture using PRB coal is $2, 293 /kW and using lignite coal is $ 2,489 /kW. Project and process contingencies represent 8 .9 and 0 percent respective ly in both cases. The COE is 57.8 mills/kWh for the PRB case and 62.2 mills/kWh for the lignite case. The estimated TOC of the USC PC plant with no CO 2 capture using PRB coal is $2, 405 /kW and using lignite coal is $ 2,628 /kW. P roject and process contingencies represent
8 .9 and 1. 4 percent respectively in both cases. The COE is 62.2 mills/kWh for the PRB case and
67.3 mills/kWh for the lignite case.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

114 Exhibit 4

- 27 Case S12A TPC S ummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

115 Exhibit 4

- 28 Case S12A Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

116 Exhibit 4

- 28 Case S12A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

117 Exhibit 4

- 28 Case S12A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

118 Exhibit 4

- 28 Case S12A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

119 Exhibit 4

- 29 Case S12A Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

120 Exhibit 4

- 30 Case S12A Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

121 Exhibit 4

- 31 Case L12A Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

122 Exhibit 4

- 32 Case L12A Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

123 Exhibit 4

- 32 Case L12A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

124 Exhibit 4

- 32 Case L12A Total Plant Cost Details (Continued )Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

125 Exhibit 4

- 32 Case L12A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

126 Exhibit 4

- 33 Case L12A Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

127 Exhibit 4

- 34 Case L12A Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

128 Exhibit 4

- 35 Case S13A Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

129 Exhibit 4

- 36 Case S13A Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

130 Exhibit 4

- 36 Case S13A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

131 Exhibit 4

- 36 Case S13A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

132 Exhibit 4

- 36 Case S13A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

133 Exhibit 4

- 37 Case S13A Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

134 Exhibit 4

- 38 Case S13A Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

135 Exhibit 4

- 39 Case L13A Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

136 Exhibit 4

- 40 Case L13A Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

137 Exhibit 4

- 40 Case L13A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

138 Exhibit 4

- 40 Case L13A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

139 Exhibit 4

- 40 Case L13A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

140 Exhibit 4

- 41 Case L13A Owner’s C ostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

141 Exhibit 4

- 42 Case L13A Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

142 4.2 SC & USC PC CO 2 CAPTURE CASES (PRB A ND LIGNITE)

4.2.1 Process Description

In this section the SC and USC PC processes with CO 2 capture are described. The plant configurations are similar to the non

- capture cases presented in Section 4.1 with the major difference being the use of an Econamine system for CO 2 capture and subsequent compression of the captured CO 2 stream. Sinc e the CO 2 capture and compression process increases the auxiliary load on the plant, the coal feed rate is significantly increased and the overall efficiency is significantly reduced relative to the non

- capture cases. A process BFD for the four CO 2 captur e cases is shown in Exhibit 4

- 43 and stream tables for Cases S12B, L12B, S13B, and L13B are
shown in Exhibit 4

- 44 through Exhibit 4

- 47 . The CO 2 removal system is described in
Se ction 3.1.4

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

143 Exhibit 4

- 43 Cases S12B, L12B, S13B, and L13B Process Flow DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

144 Exhibit 4

- 44 Case S12B Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

145 Exhibit 4

- 44 Case S12B Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

146 Exhibit 4

- 45 Case L12B Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

147 Exhibit 4

- 45 Case L12B Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

148 Exhibit 4

- 46 Case S13B Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

149 Exhibit 4

- 46 Case S13B Stream (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

150 Exhibit 4

- 47 Cas e L13B Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

151 Exhibit 4

- 47 Cas e L13B Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

152 4.2.2 Key System Assumptions

System assumptions for Cases S12B and L12B, SC PC with CO 2 capture, and Cases S13B and L13B, USC PC with CO 2 capture , are compiled in Exhibit 4

- 48

.

Exhibit 4

- 48 PC Cases with CO 2 Capture Study Configuration Matrix

Case S12B
w/ CO 2 Capture Case L12B

w/CO 2 Capture Case S13B

w/ CO 2 Capture Ca se L13B

w/CO 2 Capture Steam Cycle, MPa/°C/°C (psig/°F/°F) 24.1/593/593 (3,500/1,100/1,100) 24.1/593/593

(3,500/1,100/1,100) 27.6/649/649

(4,000/1,200/1,200) 27.6/649/649

(4,000/1,200/1,200)

Coal Subbituminous Lignite Subbituminous Lignite

Carbon Conver sion, % 100 100 100 100 Condenser pressure, mm Hg (in Hg) 36 (1.4) 36 (1.4) 36 (1.4) 36 (1.4)

Combustion air preheater flue gas exit temp., °C (oF) 143 (290) 143 (290) 143 (290) 143 (290)

Cooling water to condenser, °C (oF) 9 (48) 8 (4 7 ) 9 (48) 8 (4 7 )

Cooling water from condenser, °C (oF) 20 (68) 19 (6 7 ) 20 (68) 19 (6 7 )

FGD Outlet, °C (°F) 82 (180) 82 (180) 82 (180) 82 (180)

SO 2 Control 2 Spray Dryer Absorption FGD & Polishing Scrubber Spray Dryer

Absorption FGD & Polishing Scrubber Spray Dryer

Absorpt ion FGD & Polishing Scrubber Spray Dryer

Absorption FGD & Polishing Scrubber SDA FGD Efficiency,

% 1 ,2,3 93 93 93 93

NOx Control LNB w/OFA and
SCR LNB w/OFA and

SCR LNB w/OFA and

SCR LNB w/OFA and

SCR SCR Efficiency, % 1 65 65 65 65 Ammonia Slip (end of catalyst life), ppmv 2 2 2 2

Particulate Control Fabric Filter Fabric Filter Fabric Filter Fabric Filter Fabric Filter efficiency, % 1 99.97 99.97 99.97 99.97 Ash Distribution, Fly/Bottom 80% / 20% 80% / 20% 80% / 20% 80% / 20%

Mercury Control Co

- benef it Capture & Carbon Injection Carbon Injection Co

- benefit Capture & Carbon Injection Carbon Injection

Mercury removal efficiency, % 1 90 plus 90 90 plus 90

CO 2 Control Econamine Econamine Econamine Econamine

CO 2 Capture, % 1 90 90 90 90

CO 2 Sequestration Off

- site Saline
Formation Off

- site Saline
Formation Off

- site Saline
Formation Off

- site Saline
Formation

1 Equipment removal efficiencies

2 An SO 2 polishing step is included to meet more stringent oxides of sulfur ( S O x ) content limits in the flue gas (< 10 ppmv) to reduce formation of amine HSS during the CO 2 absorption process

3 SO 2 exiting the post

- FGD polishing step is absorbed in the CO 2 capture process making stack emissions negligible

Balance of Plant

– Cases S12B, L12B, S13A, and L13B

The balance of plant assumptions are common to all cases and were presented previously in
Section 3.1.6

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

153 4.2.3 Sparing Philosophy

Single trains are used throughout the design 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:

One dry

- bottom, wall

- fired PC SC or USC boiler (1 x 100 percent)

Two SCR reactors (2 x 50 percent)

One lime spray dryer system with two absorbers (1 x 100 percent)

Two single

- stage, in

- line, multi

- compartment fabric filters (2 x 50 percent)

One steam turbine (1 x 100 percent)

Two parallel Econamine CO 2 absorption systems, with each system consisting of two absorbers, stripp ers, and ancillary equipment (2 x 50 percent)

4.2.4 Cases S12B, L12B, S13B, and L13B Performance Results

The CO 2 capture SC PC plant using PRB coal produces a net output of 550 MWe at a net plant efficiency of 27.0 percent (HHV basis). The same plant configur ation using lignite coal produces a net output of 550 MWe at a net plant efficiency of 25.5 percent (HHV basis).

The CO 2 capture USC PC plant using PRB coal produces a net output of 550 MWe at a net plant efficiency of 28.7 percent (HHV basis). The same plant configuration using lignite coal produces a net output of 550 MWe at a net plant efficiency of 27.2 percent (HHV basis).

Overall performance for the four plants is summarized in Exhibit 4

- 49

, which includes auxiliary

powe r requirements. The cooling water system, including the CWPs and cooling tower fan, and
the air

- cooled condenser account for about 15 percent of the auxiliary load in all cases, and the

PA , FD and induced draft fans account for an additional 12 percent. CO 2 compression accounts
for about 40 percent and the Econamine process about 19 percent of the auxiliary load in all

cases.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

154 Exhibit 4

- 49 PC Cases with CO 2 Capture Plant Performance Summary

POWER SUMMARY (G ross Power at Generator Terminals, kWe) S12B L12B S13B L13B

Steam Turbine Power 673,000 683,900 665,400 675,200

AUXILIARY LOAD SUMMARY, kWe
Coal Handling and Conveying 630 770 600 730

Pulverizers 5,520 7,550 5,200 7,100
Lime Handling & Preparation 240 280 230 260
Ash Handling 1,220 1,860 1,150 1,750

PA Fans 3,550 3,580 3,350 3,070

FD Fans 2,090 2,110 1,970 2,010

ID Fans 9,620 10,120 9,070 9,520

SCR 20 20 20 20
Baghouse 170 260 160 240
Spray Dryer FGD 3,200 3,780 3,020 3,550

Econamine Auxili aries 22,900 24,700 21,500 23,200

CO 2 Compression 49,000 52,930 46,110 49,750

Steam Turbine Auxiliaries 400 400 400 400
Condensate Pumps 550 540 210 210

CWP 9,140 10,200 8,540 9,510
Ground Water Pumps 690 710 640 660
Cooling Tower Fans 5,970 6,260 5, 570 5,840

Air

- Cooled Condenser Fans 3,680 3,370 3,270 2,990

Miscellaneous Balance of Plant 1 2,000 2,000 2,000 2,000

Transformer Loss 2,350 2,410 2,310 2,360

TOTAL AUXILIARIES, kWe 122,940 133,850 115,320 125,170

NET POWER, kWe 550,060 550,050 550,080 550,030

Plant CF , % 85% 85% 85% 85%
Net Plant Efficiency, % (HHV) 27.0% 25.5% 28.7% 27.2%

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 13,330 (12,634) 14,097

(13,361) 12,553

(11,898) 13,250

(12,55 8)

CONDENSER COOLING DUTY GJ/hr (10 6 Btu/hr) 1,636 (1,5 50 ) 1,598

(1,515) 1,459

(1,383) 1,415

(1,341)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 368,084 (81 1

, 486 ) 503,790

(1,110,668) 346,641

(764,212) 473,495

(1,043,879)
Thermal Input, kW t 2 2 ,036,717 2,153,863 1,918,067 2,024,343

Raw Water Withdrawal, m 3 /min (gpm) 28.9 (7,642) 29.6 (7,817) 26.9 (7,117) 27.5 (7,261) Raw Water Consumption, m 3 /min (gpm) 20.9 (5,527) 20.7 (5,456) 19.5 (5,141) 19.2 (5,060)

1 Includes plant control systems, light ing, HVAC

, and miscellaneous low voltage loads

2 Thermal input based on as

- received HHV of coalCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

155 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO 2, and PM were presented in
Section 2.3 . A summar y of the plant air emissions for Cases S12B, L12B, S13B, and L13B is presented in Exhibit 4

- 50

.

SO 2 emissions are controlled using a lime spray dryer FGD system that achieves a removal efficiency of 93 percent. The waste is colle cted in the baghouse. A portion of the waste is stored in a recycle storage silo, which is then used to mix with lime slurry to increase the reagent
utilization. The CO 2 capture system includes a SO 2 polishing unit that reduces SO 2 emission to a negligib le level.

NOx emissions are controlled to about 0.2 lb/10 6 Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 65 percent to 0.07 lb/10 6 Btu.

Particulate emissions are controlled using a pulse jet fabric filter

, which operates at an efficiency of 99.97 percent.

Co

- benefit capture and activated carbon injection result in greater than 90 percent reduction of mercury emissions for the PRB coal. For the lignite coal, no co

- benefit capture is assumed giving a total Hg capture of 90 percent.

Ninety percent of the CO 2 from the flue gas is captured in the Econamine system and compressed for sequestrationCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

156 Exhibit 4

- 50 PC Cases with CO 2 Capture Air Emissions

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

S12B L12B S13B L13B S12B L12B S13B L13B S12B L12B S13B L13B

SO 2 0.001

(0.002) 0.001

(0.002) 0.001

(0.002) 0.001

(0.002) 37 (40) 41 (45) 36 (40) 36 (40) 0.007 (0.020) 0.009

(0.020) 0.007

(0 .020) 0.007

(0.020)

NO X 0.030

(0.070) 0.030

(0.070) 0.030

(0.070) 0.030

(0.070) 1,643

(1,811) 1,738

(1,915) 1,547

(1,706) 1,633

(1,800) 0.328

(0.723) 0.341

(0.753) 0.313

(0.689) 0.325

(0.716)

Particulates 0.006

(0.0130) 0.006

(0.0130) 0.006

(0.0130) 0.00 6

(0.0130) 305

(336) 323

(356) 287

(317) 303

(334) 0.061

(0.134) 0.063

(0.140) 0.058

(0.128) 0.060

(0.133)

Hg 2.57E

- 7

(5.97E

- 7) 4.82E

- 7

(1.12E

- 6) 2.57E

- 7

(5.97E

- 7) 4.82E

- 7

(1.12E

- 6) 0.014

(0.015) 0.028

(0.031) 0.013

(0.015) 0.026

(0.029) 2.80E

- 6

(6.16E

- 6 ) 5.46E

- 6

(1.20E

- 5) 2.66E

- 6

(5.87E

- 6) 5.20E

- 6

(1.15E

- 5)

CO 2 9.2

(21.5) 9.4

(21.9) 9.2

(21.5) 9.4

(21.9) 503,823

(555,370) 544,753

(600,488) 474,474

(523,018) 512,997

(564,380) 101

(222) 107

(236) 96

(211) 102

(225)

CO 2 1 123 (271) 133

(293) 116

(25 5) 125

(276)

1 CO 2 emissions based on net power instead of gross powerCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

157 The carbon balances for the four CO 2 capture PC cases are shown in Exhibit 4

- 51 and
Exhibit 4

- 52 . The carbon input to the plant c onsists of carbon in the air in addition to carbon in the coal. Carbon leaves the plant as CO 2 in the stack gas and CO 2 product. 100 percent carbon conversion is assumed since carbon conversion for low rank PC plants is typically about 99.9
percent. The CO 2 capture efficiency is defined by the following fraction:

1

- [(Stack Gas Carbon

- Air Carbon)/(Total Carbon In

- Air Carbon)] or 1

- [(40,712

- 822)/(407,251

- 822)] * 100 = 90.2 percent (S12B)

1

- [(44,019

- 882)/(440,403

- 882)] * 100 = 90.2 percent (L12B)

1

- [(38,3 40

- 775)/(383,528

- 775)] * 100 = 90.2 percent (S13B)

1

- [(41,372

- 830)/(413,921

- 830)] * 100 = 90.2 percent (L13B)

Exhibit 4

- 51 Cases S12B and L12B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/h r)

S12B L12B S12B L12B

Coal 184,293

(406,296) 199,268

(439,310) Ash 61 (134) 96 (211)

Air (CO 2 ) 373 (822) 400 (882) Stack Gas 18,487 (40,756) 19,967

(44,019)

Activated
Carbon 61 (134) 96 (211) CO 2 Product 166,379 (366,802) 179,701

(396,172)

Total 18 4,726

(407,251) 199,763

(440,403) Total 184, 7 26 (407, 251 ) 199,763

(440,403)

Exhibit 4

- 52 Cases S13B and L13B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S13B L13B S13B L13B

Coal 173,557

(382,627) 187,285

(412,893) Ash 57 (126) 90 (198)

Air (CO 2 ) 352 (775) 377 (830) Stack Gas 17,391 (38,340) 18,766

(41,372)

Activated
Carbon 57 (126) 90 (198) CO 2 Product 156,517 (345,061) 168,895

(372,350)

Total 173,965

(383,528) 187,751

(413,921 ) Total 173,965 (383,528) 187,751

(413,921)

Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. The activated carbon injected for mercury removal is captured in the baghouse and
removed with the ash.

Exhibit 4

- 53 and Exhibit 4

- 54 show the sulfur balances for the four capture PC cases. Sulfur input comes solely from the sulfur in the coal. Sulfur output is the sulfur combined with lime inCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

158 the ash, the s ulfur from the polishing scrubber, and the SO 2 emitted in the stack gas. The sulfur exits the Econamine system in the form of sodium sulfite and HSS

.

Exhibit 4

- 53 Cases S12B and L12B Sulfur Balance

Sulfu r In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S12B L12B S12B L12B

Coal 2,678 (5,903) 3,156 (6,9 5 7) Ash 2,490 (5,490) 2,935 (6,470)
Polishing
Scrubber /
Econamine FG+ 185 (408) 218 (481)

Stack Gas 2 (5) 3 (6)

Total 2,678 (5,903) 3,156 (6,9 5 7) Total 2,678 (5,903) 3,156 (6,9 5 7)

Exhibit 4

- 54 Cases S13B and L13B Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S13B L13B S13B L13B

Coal 2,522 (5,559) 2,966 (6,593) Ash 2,345 (5, 170) 2,758 (6,081)
Polishing
Scrubber /
Econamine FG+ 174 (384) 205 (452)

Stack Gas 2 (5) 2 (5)

Total 2,522 (5,559) 2,966 (6,593) Total 2,522 (5,559) 2,966 (6,539)

Exhibit 4

- 55

, Exhibit 4

- 56

, Ex hibit 4

- 57 , and Exhibit 4

- 58 show the overall water balances for the plants. Raw water withdrawal is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand repres ents the total amount of water required for a particular process. Some water is recovered within the process and that water is re

- used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Some water is d ischarge 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 3b (Combustion Cases)

159 Exhibit 4

- 55 Case S12B Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /min (gpm) Process

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

Econamine 0.15 (40) 0 (0) 0.15 (40) 0 (0) 0.15 (40)

FGD Makeup 1.34 (355) 0 (0) 1.34 (355) 0 (0) 1.34 (355)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 35.6 (9,406) 8.17 (2,158) 27.4 (7,248) 8.01 (2,115) 19.43 (5,133)

Total 37.1 (9,800) 8.17 (2,158) 28.9 (7,642) 8.01 (2,115) 20.92 (5,527)

Exhibit 4

- 56 Cas e L12B Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /min (gpm) Process

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

Econamine 0.16 (43) 0 (0) 0.16 (43) 0 (0) 0.16 (43)

FGD Makeup 1.52 (402) 0 (0) 1.52 (402) 0 (0) 1.52 (402)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 39.7 (10,497) 11.8 (3,125) 27.9 (7,372) 8.9 (2,361) 19.0 (5,011)

Total 41.4 (10,941) 11.8 (3,125) 29.6 (7,817) 8.9 (2,361) 20.7 (5,456)

Ex hibit 4

- 57 Case S13B Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /min (gpm) Process

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

Econamine 0.14 (37) 0 (0) 0.14 (37) 0 (0) 0.14 (37)

FGD Makeup 1.27 (334) 0 (0) 1.27 (334) 0 (0) 1.27 (334)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 33.3 (8,786) 7.72 (2,041) 25.5 (6,745) 7.48 (1

, 976) 18.05 (4,769)

Total 34. 7 (9,157) 7.72 (2,041) 26.9 (7,117) 7.48 (1
, 976) 19.46 (5,141)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

160 Exhibit 4

- 58 Case L13B Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /min (gpm) Pr ocess

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

Econamine 0.15 (40) 0 (0) 0.15 (40) 0 (0) 0.15 (40)

FGD Makeup 1.43 (378) 0 (0) 1.43 (378) 0 (0) 1.43 (378)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 37.1 (9,78 8) 11.15 (2

, 945) 25.9 (6,843) 8.33 (2,201) 17.57 (4,642)

Total 38.6 (10,206) 11.15 (2,945) 27.5 (7,261) 8.33 (2,201) 19.15 (5,060)

Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 4

- 59 through
Exhibit 4

- 66 :
Boiler and flue gas cleanup

Steam and FW

Overall plant energy balances are provided in tabular form in Exhibit 4

- 67 for the two SC cases and in Exhibit 4

- 68 for the two USC cases. The sulfur exits the Econamine system in the form of
sodium sulfite and HSS , but is shown as SO 2 . The power out is the steam turbine power after generator losses.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

161 Exhibit 4

- 59 Case S12B Boiler and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

162 Exhibit 4

- 60 Case S12B Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

163 Exhibit 4

- 61 Case L12B Boiler and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

164 Exhibit 4

- 62 Case L12B Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

165 Exhibit 4

- 63 Case S13B Boiler and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

166 Exhibit 4

- 64 Case S13B Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

167 Exhibit 4

- 65 Case L13B Boiler and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

168 Exhibit 4

- 66 Case L13B Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

169 Exhibit 4

- 67 Cases S12B and L12B Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total

S12B L12B S12B L12B S12B L12B S12B L12B
Heat In, GJ/hr (MMBtu/hr)

Coal 7,332 (6,950) 7,754

(7,349) 3.8 (3.6) 4.5 (4.3) 7,336 (6,953) 7,758

(7,354)

Combustion Air 41.7 (39.6) 40.3 (38.2) 41.7 (39.6) 40.3 (38.2) Raw Water Makeup 40.3 (38.2) 33.0 (31.3) 40.3 (38.2) 33.0 (31.3)

Lime 0.02 (0.02) 0.02 (0.02) 0.02 (0.02) 0.02 (0.02) Auxiliary Power 443 (419) 482 (45 7) 443 (419) 482 (457)

Totals 7,332 (6,950) 7,754

(7,349) 85.8 (81.4) 77.8 (73.8) 443 (419) 482 (457) 7,861 (7,450) 8,314

(7,880) Heat Out, GJ/hr (MMBtu/hr)

Bottom Ash 0.7 (0.6) 1.1 (1.1) 0.7 (0.6) 1.1 (1.1) Fly Ash + FGD Ash 2.3 (2.2) 3.5 (3.3) 2.3 (2.2) 3.5 (3.3)

Flue Gas 234 (222) 241 (229) 234 (222) 241 (229)

Condenser 1,636 (1,550) 1,598

(1,515) 1,636 (1,550) 1,598

(1,515)

CO 2 - 129 (

- 123)

- 140 (

- 133)

- 129 (

- 123)

- 140 (

- 133) Cooling Tower Blowdown 44.6 (42.3) 48.4 (45. 9) 44.6 (42.3) 48.4 (45.9)

Econamine Losses 3,316 (3,143) 3,810

(3,611) 3,316 (3,143) 3,810

(3,611)

Process Losses 1 333.5 (316.1) 289.1

(274.0) 333.5 (316.1) 289.1

(274.0)

Power 2,423 (2,296) 2,462

(2,334) 2,423

(2,296) 2,462

(2,334)

Totals 0 ( 0 ) 0 ( 0 ) 5,438 (5,154) 5,852

(5,546) 2,423

(2,296) 2,462

(2,334) 7,861

(7,450) 8,314

(7,880)

1 Process losses including steam turbine, combustion reactions, and gas cooling are estimated to match the heat input to the pl ant.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

170 Exhibit 4

- 68 Cases S13B and L13B Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total

S13B L13B S13B L13B S13B L13B S13B L13B
Heat In, GJ/hr (MMBtu/hr)

Coal 6,905 (6,545) 7,288

(6,907) 3.5 (3.4) 4.2 (4. 0) 6,909 (6,548) 7,292

(6,911)

Combustion Air 39.4 (37.3) 38.0 (36.0) 39.4 (37.3) 38.0 (36.0) Raw Water Makeup 37.5 (35.6) 30.6 (29.0) 37.5 (35.6) 30.6 (29.0)

Lime 0.02 (0.02) 0.02 (0.02) 0.02 (0.02) 0.02 (0.02) Auxiliary Power 415 (3 93) 451 (427) 415 (393) 451 (427)

Totals 6,905 (6,545) 7,288

(6,907) 80.5 (76.3) 72.9 (69.1) 415 (393) 451 (427) 7,401 (7,014) 7,811

(7,404) Heat Out, GJ/hr (MMBtu/hr)

Bottom Ash 0.6 (0.6) 1.0 (1.0) 0.6 (0.6) 1.0 (1.0) Fly Ash + FGD Ash 2.2 (2.1) 3.3 (3.1) 2.2 (2.1) 3.3 (3.1)

Flue Gas 221 (209) 227 (215) 221 (209) 227 (215)

Condenser 1,459 (1,383) 1,415

(1,341) 1,459 (1,383) 1,415

(1,341)

CO 2 - 122 (

- 115)

- 131 (

- 125)

- 122 (

- 115)

- 131 (

- 125) Cooling Tower Blowdown 41.7 (39.5) 45. 1 (42.8) 41.7 (39.5) 45.1 (42.8)

Econamine Losses 3,122 (2,959) 3,580

(3,393) 3,122 (2,959) 3,580

(3,393)

Process Losses * 281.0 (266.3) 240.8

(228.3) 281.0 (266.3) 240.8

(228.3)

Power 2,395 (2,270) 2,431

(2,304) 2,395

(2,270) 2,431

(2,304)

Totals 0 ( 0 ) 0 ( 0 ) 5,005 (4,744) 5,380

(5,100) 2,395

(2,270) 2,431

(2,304) 7,401

(7,014) 7,811

(7,404)

* Process losses including steam turbine, combustion reactions, and gas cooling are estimated to match the heat input to the pl ant.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

171 4.2.5 PC Cases with CO 2 Capture Equipment Lists

Major equipment items for SC and USC PC with CO 2 capture and using PRB or lignite coal are shown in the following tables. The equipment lists are not meant to be comprehensive, but rather representative. The accounts used in the equipment list correspond to the account
numbers used in the cost estimates in Section 4.2.6 . 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 3b (Combustion Cases)

172 ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2(0 ) 181 tonne (200 ton) 181 tonne

(200 ton) 181 tonne

(200 ton) 181 tonne

(200 ton)

2 Feeder Belt 2(0) 572 tonne/hr (630 tph) 572 tonne/hr

(630 tph) 572 tonne/hr

(630 tph) 572 tonne/hr

(630 tph)

3 Conveyor No. 1 Belt 1(0) 1,134 tonne/hr (1,250 tph) 1,134 t onne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph)

4 Transfer Tower No. 1 Enclosed 1(0) N/A N/A N/A N/A

5 Conveyor No. 2 Belt 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,2 50 tph)

6 As

- Received Coal Sampling System Two

- stage 1(0) N/A N/A N/A N/A

7 Stacker/Reclaimer Traveling, linear 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph) 1,134 tonne/hr

(1,250 tph)

8 Reclaim Hopper N/A 2(1) 73 tonne (80 ton) 109 tonne (120 ton) 73 tonne (80 ton) 100 tonne (110 ton)

9 Feeder Vibratory 2(1) 308 tonne/hr (340 tph) 417 tonne/hr

(460 tph) 290 tonne/hr

(320 tph) 390 tonne/hr

(430 tph)

10 Conveyor No. 3 Belt w/ tripper 1(0) 608 tonne/hr (670 tph) 83 5 tonne/hr

(920 tph) 572 tonne/hr

(630 tph) 780 tonne/hr

(860 tph)

11 Crusher Tower N/A 1(0) N/A N/A N/A N/A

12 Coal Surge Bin w/
Vent Filter Dual outlet 2(0) 308 tonne (340 ton) 417 tonne

(460 ton) 290 tonne

(320 ton) 390 tonne

(430 ton)

13 Crusher Im pactor
reduction 2(0) 8cm x 0

- 3cm x 0 (3 ‖ x 0

- 1

- 1/4 ‖ x 0) 8cm x 0

- 3cm x 0

(3 ‖ x 0

- 1

- 1/4 ‖ x 0) 8cm x 0

- 3cm x 0

(3 ‖ x 0

- 1

- 1/4 ‖ x 0) 8cm x 0

- 3cm x 0

(3 ‖ x 0

- 1

- 1/4 ‖ x 0)

14 As

- Fired Coal Sampling System Swing hammer 1(1) N/A N/A N/A N/A

15 Co nveyor No. 4 Belt w/tripper 1(0) 608 tonne/hr (670 tph) 835 tonne/hr

(920 tph) 572 tonne/hr

(630 tph) 780 tonne/hr

(860 tph)

16 Transfer Tower No. 2 Enclosed 1(0) N/A N/A N/A N/ACost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

173 Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

17 Conveyor No. 5 Belt w/ tripper 1(0) 608 tonne/hr (670 tph) 835 tonne/hr

(920 tph) 572 tonne/hr

(630 tph) 780 tonne/hr

(860 tph)

18 Coal Silo w/ Vent
Filter and Slide Gates Field erected 6(0) 635 tonne (700 ton) 907 tonne

(1,000 ton) 635 tonne

(700 ton) 907 tonne

(1,000 ton)

19 Lime Truck Unloading System N/A 1(0) 27 tonne/h r (30 tph) 27 tonne/hr

(30 tph) 18 tonne/hr

(20 tph) 27 tonne/hr

(30 tph)

20 Lime Bulk Storage
Silo w/Vent Filter Field erected 3(0) 726 tonne (800 ton) 816 tonne

(900 ton) 635 tonne

(700 ton) 726 tonne

(800 ton)

21 Lime Live Storage Transport Pneumatic 1(0) 9 tonne/hr (10 tph) 11 tonne/hr

(12 tph) 9 tonne/hr

(10 tph) 10 tonne/hr

(11 tph)

22 Lime Day Bin w/ actuator 2(0) 73 tonne (80 ton) 91 tonne (100 ton) 73 tonne (80 ton) 82 tonne (90 ton)

23 Activated Carbon Storage Silo and Feeder System with

Ven t Filter Shop assembled 1(0) Silo

- 45 tonne (50 ton)
Feeder

- 68 kg/hr (150 lb/hr) Silo

- 73 tonne

(80 ton)
Feeder

- 104 kg/hr (230 lb/hr) Silo

- 45 tonne

(50 ton)
Feeder

- 64 kg/hr (140 lb/hr) Silo

- 73 tonne

(80 ton)
Feeder

- 100 kg/hr (220 lb/hr)

ACCO UNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 Coal Feeder Gravimetric 6(0) 64 tonne/hr (70 tph) 91 tonne/hr

(100 tph) 64 tonne/hr

(70 tph) 91 tonne/hr

(100 tph)

2 Coal Pulverizer Ball type or equivalent 6(0) 64 tonne/hr (70 tph) 91 tonne/hr

(100 tph) 64 tonne/hr

(70 tph) 91 tonne/hr

(100 tph)

3 Lime Slaker N/A 1(1) 8 tonne/hr (9 tph) 10 tonne/hr (11 tph) 8 tonne/h r (9 tph) 9 tonne/hr (10 tph)

4 Lime Slurry Tank Field Erected 1(1) 389,900 liters (103,000 gal) 458,038 liters

(121,000 gal) 367,188 liters

(97,000 gal) 431,540 liters

(114,000 gal)

5 Lime Slurry Feed Pumps Horizontal

centrifugal 1(1) 416 lpm @ 9m

H 2 O ( 110 gpm @
30 ft H 2 O) 492 lpm @ 9m

H 2 O (130 gpm @
30 ft H 2 O) 379 lpm @ 9m

H 2 O (100 gpm @
30 ft H 2 O) 454 lpm @ 9m

H 2 O (120 gpm @
30 ft H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

174 ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment
No. Description Type Operating Qty. (Spares) S 12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 Demineralized Water Storage Tank Vertical,

cylindrical,
outdoor 2(0) 1,536,877 liters (406,000 gal) 1,578,517 liters

(417,000 gal) 1,570,946 liters

(415,000 gal) 1,61 2,585 liters

(426,000 gal)

2 Condensate Pumps Vertical canned 1(1) 16,656 lpm @
213 m H 2 O (4,400 gpm @
700 ft H 2 O) 16,277 lpm @

213 m H 2 O (4,300 gpm @
700 ft H 2 O) 12,870 lpm @ 91

m H 2 O (3,400 gpm @ 300 ft

H 2 O) 12,492 lpm @ 91

m H 2 O (3,300 gpm @ 300 ft

H 2 O )

3 Deaerator and Storage Tank Horizontal spray

type 1(0) 2,556,450 kg/hr (5,636,000 lb/hr),
5 min. tank 2,629,021 kg/hr

(5,796,000 lb/hr),
5 min. tank 2,614,053 kg/hr

(5,763,000 lb/hr),
5 min. tank 2,683,545 kg/hr

(5,914,000 lb/hr),
5 min. tank

4 Boiler Feed Pump/Turbine Barrel type, multi

stage, centrifugal 1(1) 42,775 lpm @ 3,505 m H 2 O (11,300 gpm @ 11,500 ft H 2 O) 44,289 lpm @

3,505 m H 2 O (11,700 gpm @ 11,500 ft H 2 O) 43,911 lpm @

3,871 m H 2 O (11,600 gpm @ 12,700 ft H 2 O) 45,046 lpm @

3,871 m H 2 O (11,900 gpm @ 12,700 ft H 2 O)

5 Startup Boiler Feed Pump, Electric Motor
Driven Barrel type, multi

stage, centrifugal 1(0) 12,870 lpm @ 3,505 m H 2 O (3,400 gpm @ 11,500 ft H 2 O) 13,249 lpm @

3,505 m H 2 O (3,500 gpm @ 11,500 ft H 2 O) 13,249 lpm @

3,871 m H 2 O (3,500 gp m @ 12,700 ft H 2 O) 13,249 lpm @

3,871 m H 2 O (3,500 gpm @ 12,700 ft H 2 O)

6 LP Feedwater Heater
1A/1B Horizontal U

- tube 2(0) 494,416 kg/hr (1,090,000 lb/hr) 485,344 kg/hr

(1,070,000 lb/hr) 385,554 kg/hr

(850,000 lb/hr) 371,946 kg/hr

(820,000 lb/hr)

7 LP Fe edwater Heater
2A/2B Horizontal U

- tube 2(0) 494,416 kg/hr (1,090,000 lb/hr) 485,344 kg/hr

(1,070,000 lb/hr) 385,554 kg/hr

(850,000 lb/hr) 371,946 kg/hr

(820,000 lb/hr)

8 LP Feedwater Heater
3A/3B Horizontal U

- tube 2(0) 494,416 kg/hr (1,090,000 lb/hr) 485, 344 kg/hr

(1,070,000 lb/hr) 385,554 kg/hr

(850,000 lb/hr) 371,946 kg/hr

(820,000 lb/hr)

9 LP Feedwater Heater
4A/4B Horizontal U

- tube 2(0) 494,416 kg/hr (1,090,000 lb/hr) 485,344 kg/hr

(1,070,000 lb/hr) 385,554 kg/hr

(850,000 lb/hr) 371,946 kg/hr

(820,000 lb/hr)

10 HP Feedwater Heater

6 Horizontal U

- tube 1(0) 2,558,261 kg/hr (5,640,000 lb/hr) 2,630,836 kg/hr

(5,800,000 lb/hr) 2,612,692 kg/hr

(5,760,000 lb/hr) 2,680,731 kg/hr

(5,910,000 lb/hr)

11 HP Feedwater Heater

7 Horizontal U

- tube 1(0) 2,558,261 kg/h r (5,640,000 lb/hr) 2,630,836 kg/hr

(5,800,000 lb/hr) 2,612,692 kg/hr

(5,760,000 lb/hr) 2,680,731 kg/hr

(5,910,000 lb/hr)

12 HP Feedwater heater
8 Horizontal U

- tube 1(0) 2,558,261 kg/hr (5,640,000 lb/hr) 2,630,836 kg/hr

(5,800,000 lb/hr) 2,612,692 kg/hr

( 5,760,000 lb/hr) 2,680,731 kg/hr

(5,910,000 lb/hr)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

175 Equipment
No. Description Type Operating Qty. (Spares) S 12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

13 Auxiliary Boiler Shop fabricated,
water tube 1(0) 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8

MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8

MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8

MPa, 343°C (40,000 lb/hr, 400 psig, 650°F)

14 Fuel Oil System No. 2 fuel oil for light off 1(0) 1,135,624 liter (300,000 gal) 1,135,624 liter

(300,000 gal) 1,135,624 liter

(300,000 gal) 1,135,624 liter

(30 0,000 gal)

15 Service Air Compressors Flooded Screw 2(1) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7

MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7

MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7

MPa (1,000 scfm @ 100 psig)

16 Instrument Air Dry ers Duplex,

regenerative 2(1) 28 m 3 /min (1,000 scfm) 28 m 3 /min

(1,000 scfm) 28 m 3 /min

(1,000 scfm) 28 m 3 /min

(1,000 scfm)

17 Closed Cycle Cooling Heat Exchangers Shell and tube 2(0) 53 GJ/hr (50 MMBtu/hr)
each 53 GJ/hr

(50 MMBtu/hr)
each 53 GJ/hr

(50 MMB tu/hr)
each 53 GJ/hr

(50 MMBtu/hr)
each

18 Closed Cycle Cooling Water Pumps Horizontal

centrifugal 2(1) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O)

19 Engine

- Driven Fire Pump Vertical turbine,

diesel engine 1(1) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O)

20 Fire Service Booster Pump Two

- stage

horizontal centrifugal 1(1) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O) 2,650 lpm @ 64

m H 2 O (700 gpm @ 210 ft H 2 O)

21 Raw Water Pumps Stainless steel, single suction 2(1) 8,858 lpm @ 43

m H 2 O (2,340 gpm @ 140 ft

H 2 O) 19,003 lpm @ 43

m H 2 O (5,020 gpm @ 140 ft

H 2 O) 8,290 lpm @ 43

m H 2 O (2,190 gpm @ 140 ft

H 2 O) 8,858 lpm @ 43

m H 2 O (2,340 gpm @ 140 ft

H 2 O)

22 Ground Water Pumps Stainless steel, single suction 2(1) 2,953 lpm @ 268

m H 2 O (780 gpm
@ 880 ft H 2 O) 2,725 lpm @ 268

m H 2 O (720 gpm
@ 880 ft H 2 O) 2,763 lpm @ 268

m H 2 O (730 gpm
@ 880 ft H 2 O) 2,953 lpm @ 268

m H 2 O (780 gpm
@ 880 ft H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

176 Equipment
No. Description Type Operating Qty. (Spares) S 12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

23 Filtered Water Pumps Stainless steel, single suction 2(1) 492 lpm @ 49 m

H 2 O (130 gpm @
160 ft H 2 O) 530 lpm @ 49 m

H 2 O (140 gpm @
160 ft H 2 O) 530 lpm @ 49 m

H 2 O (140 gpm @
160 ft H 2 O) 530 lpm @ 49 m

H 2 O (140 gpm @
160 ft H 2 O)

24 Filtered Water Tank Vertical, cyli ndrical 1(0) 480,747 liter (127,000 gal) 499,674 liter

(132,000 gal) 499,674 liter

(132,000 gal) 518,601 liter

(137,000 gal)

25 Makeup Water
Demineralizer Multi

- media filter,

cartridge filter, RO
membrane assembly,
electrodeionization
unit 1(1) 1,022 lpm (270 gpm) 1,060 lpm

(280 gpm) 1,022 lpm

(270 gpm) 1,060 lpm

(280 gpm)

26 Liquid Waste Treatment System -- 1(0) 10 years,

24

- hour storm 10 years,

24

- hour storm 10 years,

24

- hour storm 10 years,

24

- hour storm

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment

No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design
Condition S13B Design
Condition L13B Design
Condition

1 Boiler Once thru,
wall

- fired,
low NOx burners,
overfire air 1(0) Supercritical, 2,558,261 kg/hr steam
@ 25.5
MPa/602°C/602°C (5,640,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) Supercritical, 2,630,836 kg/hr steam
@ 25.5
MPa/602°C/602°C (5,800,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) Ultra

- supercritical, 2,612,692 kg/hr steam
@ 29.0
MPa/657°C/657°C (5,760,000 lb/hr

steam @ 4,200 psig/1,215°F/1,215°F) Ultra

- supercritical, 2,680,731 kg/hr steam
@ 29.0
MPa/657°C/657°C (5,910,000 lb/hr steam @ 4,200 psig/1,215°F/1,215°F)

2 Primary Air

Fan Centrifugal 2(0) 591,938 kg/hr, 8,821

m 3 /min @ 123 cm WG (1,305,000 lb/hr, 311,400 acfm @ 48 in. WG) 635,029 kg/hr, 8,877

m 3 /min @ 123 cm WG (1,400,000 lb/hr, 313,500 acfm @ 48 in. WG) 557,919 kg/hr, 8,317

m 3 /min @ 123 cm WG (1,230,000 lb/hr, 293,700 acfm @ 48 in. WG) 597,835 kg/hr, 8,369

m 3 /min @ 112 cm WG (1,318,000 lb/hr, 295,100 acfm @ 44 in. WG)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

177 Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design
Condition S13B Design
Condition L13B Design
Condition

3 Forced Draft

Fan Centrifugal 2(0) 887,680 kg/hr, 13,230

m 3 /min @ 47 cm WG (1,957,000 lb/hr, 467,100 acfm @ 19 in. WG) 952,544 kg/hr, 13,317

m 3 /min @ 47 cm WG (2,100,000 lb/hr, 470,300 acfm @ 19 in. WG) 837,332 kg/hr, 12,474

m 3 /min @ 47 cm WG (1 ,846,000 lb/hr, 440,500 acfm @ 19 in. WG) 897,752 kg/hr, 12,536

m 3 /min @ 48 cm WG (1,977,000 lb/hr, 442,700 acfm @ 19 in. WG)

4 Induced
Draft Fan Centrifugal 2(0) 1,732,723 kg/hr, 35,288 m 3 /min @ 82 cm WG (3,820,000 lb/hr, 1,246,200 acfm @ 32 in. WG) 1,91 2,345 kg/hr,

37,061 m 3 /min @ 82 cm WG (4,216,000 lb/hr, 1,308,800 acfm @ 32 in. WG) 1,633,840 kg/hr,

33,275 m 3 /min @ 82 cm WG (3,602,000 lb/hr, 1,175,100 acfm @ 32 in. WG) 1,799,855 kg/hr,

34,878 m 3 /min @ 82 cm WG (3,968,000 lb/hr, 1,231,700 acfm
@ 32 in. WG)

5 SCR Reactor
Vessel Space for

spare layer 2(0) 3,465,446 kg/hr (7,640,000 lb/hr) 3,823,784 kg/hr (8,430,000 lb/hr) 3,265,865 kg/hr (7,200,000 lb/hr) 3,601,523 kg/hr (7,940,000 lb/hr)

6 SCR Catalyst -- 3(0)

-- -- -- --

7 Dilution Air
Blower Centrifu gal 2(1) 59 m 3 /min @ 108 cm WG (2,100 acfm @ 42 in. WG) 62 m 3 /min @ 108 cm

WG (2,200 acfm @ 42 in. WG) 54 m 3 /min @ 108 cm

WG (1,900 acfm @ 42 in. WG) 57 m 3 /min @ 108 cm

WG (2,000 acfm @ 42 in. WG)

8 Ammonia Storage Horizontal

tank 5(0) 64,352 liter (17,00 0 gal) 68,137 liter (18,000 gal) 60,567 liter (16,000 gal) 64,352 liter (17,000 gal)

9 Ammonia Feed Pump Centrifugal 2(1) 12 lpm @ 91 m H 2 O (3 gpm @ 300 ft

H 2 O) 13 lpm @ 91 m H 2 O

(3 gpm @ 300 ft

H 2 O) 12 lpm @ 91 m H 2 O

(3 gpm @ 300 ft

H 2 O) 12 lpm @ 91 m H 2 O

(3 gpm @ 300 ft

H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

178 ACCOUNT 5 FLUE GAS CLEANUP

Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 Fabric Filter Single stage, high

- ratio with pulse

- jet onlin e cleaning system,
air

- to

- cloth ratio

- 3.5 ft/min 2(0) 1,732,723 kg/hr (3,820,000 lb/hr) 99.9% efficiency 1,912,345 kg/hr

(4,216,000 lb/hr) 99.9% efficiency 1,633,840 kg/hr

(3,602,000 lb/hr) 99.9% efficiency 1,799,855 kg/hr

(3,968,000 lb/hr)
99.9% efficie ncy

2 Spray Dryer Co

- current open

spray 2(0) 37,831 m 3 /min (1,336,000 acfm) 39,842 m 3 /min

(1,407,000 acfm) 35,651 m 3 /min

(1,259,000 acfm) 37,492 m 3 /min

(1,324,000 acfm)

3 Atomizer Rotary 2(1) 227 lpm @ 64 m

H 2 O (60 gpm @
210 ft H 2 O) 265 lpm @ 64 m

H 2 O (7 0 gpm @
210 ft H 2 O) 227 lpm @ 64 m

H 2 O (60 gpm @
210 ft H 2 O) 265 lpm @ 64 m

H 2 O (70 gpm @
210 ft H 2 O)

4 Spray Dryer Solids Conveying --- 2(0)

--- --- --- ---

5 Carbon Injectors

--- 1(0) 68 kg/hr (150 lb/hr) 104 kg/hr

(230 lb/hr) 64 kg/hr

(140 lb/hr) 100 kg/hr

(220 lb/hr)

ACCOUNT 5B CARBON DIOXIDE RECOVERY

Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 Econamine FG Plus Amine

- based CO 2 capture technology 2(0) 1,732,723 kg/h (3,820,000 lb/h)
21.5 wt % CO 2 concentration 1,912,345 kg/h

(4,216,000 lb/h)
21.1 wt % CO 2 concentration 1,633,840 kg/h

(3,602,000 lb/h)
21.5 wt % CO 2 concentration 1,799,855 kg/h

(3,968,000 lb/h)
21.1 wt % CO 2 concentration

2 Econamin e Condensate Pump Centrifugal 1(1) 18,851 lpm @ 52

m H 2 O (4,980 gpm @ 170 ft

H 2 O) 20,366 lpm @ 52

m H 2 O (5,380 gpm @ 170 ft

H 2 O) 17,754 lpm @ 52

m H 2 O (4,690 gpm @ 170 ft

H 2 O) 19,154 lpm @ 52

m H 2 O (5,060 gpm @ 170 ft

H 2 O)

3 CO 2 Compressor Integrally gear ed,
multi

- stage centrifugal 2(0) 335,298 kg/h @
15.3 MPa (739,205 lb/h @ 2,215 psia) 362,560 kg/h @

15.3 MPa (799,309 lb/h @ 2,215 psia) 315,693 kg/h @

15.3 MPa (695,984 lb/h @ 2,215 psia) 340,699 kg/h @

15.3 MPa (751,114 lb/h @ 2,215 psia)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

179 ACCOUNT 6 COMB USTION TURBINE/ACCESSORIES

N/A

ACCOUNT 7 DUCTING & STACK

Equipment
No. Description Type Operating Qty. S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 Stack Reinforced
concrete with
FRP liner 1(0) 152 m (500 ft ) high x 6.1 m (20 ft)
diameter" 152 m (500 ft)

high x 6.1 m (20 ft)
diameter" 152 m (500 ft)

high x 5.9 m (19 ft)
diameter" 152 m (500 ft)

high x 5.9 m (19 ft)
diameter"

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment
No. Description Type Ope rating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 Steam Turbine Commercially
available
advanced steam
turbine 1(0) 709 MW 24.1
MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 720 MW 24.1

MPa/593°C/59 3°C (3500 psig/ 1100°F/1100°F) 701 MW 27.6

MPa/649°C/649°C (4000 psig/ 1200°F/1200°F) 711 MW 27.6

MPa/649°C/649°C (4000 psig/ 1200°F/1200°F)

2 Steam Turbine
Generator Hydrogen cooled,

static excitation 1(0) 790 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 800 MV A @ 0.9

p.f., 24 kV, 60 Hz,

3

- phase 780 MVA @ 0.9

p.f., 24 kV, 60 Hz,

3

- phase 790 MVA @ 0.9

p.f., 24 kV, 60 Hz,

3

- phase

3 Surface Condenser Single pass,
divided waterbox including vacuum

pumps 1(0) 900 GJ/hr (850 MMBtu/hr), Condensing temperature 32°C (90 °F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 880 GJ/hr

(830 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F) 800 GJ/hr

(760 MMBtu/hr), Condensing
temperatur e 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 770 GJ/hr

(730 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

180 Equipment
No. Description Type Ope rating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

4 Air

- cooled
Condenser --- 1(0) 900 GJ/hr (850 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 880 GJ/hr

(830 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 4°C (40°F) 800 GJ/hr

(760 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient
temp erature 6°C (42°F) 770 GJ/hr

(730 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 4°C (40°F)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

C ondition L13B Design

Condition

1 Circulating Water Pumps Vertical, wet pit 2(1) 916,100 lpm @
30 m (242,000 gpm @ 100 ft) 1,022,100 lpm @

30 m (270,000 gpm @ 100 ft) 855,500 lpm @

30 m (226,000 gpm @ 100 ft) 953,900 lpm @

30 m (253,000 gpm @ 100 ft)

2 Co oling Tower Evaporative, mechanical draft,
multi

- cell 1(0) 3°C (37°F) wet bulb / 9°C (48°F)
CWT / 20°C (68°F) HWT / 5,117 GJ/hr (4,850 MMBtu/hr) heat duty 2°C (36°F) wet

bulb / 8°C (47°F)
CWT / 19°C (67°F) HWT / 5,708 GJ/hr (5,410 MMBtu/hr) heat duty 3°C ( 37°F) wet

bulb / 9°C (48°F)
CWT / 20°C (68°F) HWT / 4,779 GJ/hr (4,530 MMBtu/hr) heat duty 2°C (36°F) wet

bulb / 8°C (47°F)
CWT / 19°C (67°F) HWT / 5,317 GJ/hr (5,040 MMBtu/hr) heat duty

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment

No. Des cription Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 Economizer Hopper (part of boiler scope of supply) -- 4(0)

-- -- -- --Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

181 Equipment
No. Des cription Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

2 Bottom Ash Hopper (part of boiler scope of supply) -- 2(0)

-- -- -- --

3 Clinker Grinder

-- 1(1) 6.4 tonne/hr (7 tph) 10.9 tonne/hr

(12 tph) 6.4 tonne/hr

(7 tph) 10.0 tonne/hr

(11 tph)

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- 6(0)

-- -- -- --

5 Hydroejectors

-- 12(0)

- - -- -- --

6 Economizer /Pyrites
Transfer Tank -- 1(0)

-- -- -- --

7 Ash Sluice Pumps Vertical, wet pit 1(1) 265 lpm @ 17 m

H 2 O (70 gpm @
56 ft H 2 O) 416 lpm @ 17 m

H 2 O (110 gpm @
56 ft H 2 O) 265 lpm @ 17 m

H 2 O (70 gpm @
56 ft H 2 O) 416 lpm @ 17 m

H 2 O (110 gpm @
56 ft H 2 O)

8 Ash Seal Water Pumps Vertical, wet pit 1(1) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O)

9 Hydrobins

-- 1(1) 265 lpm (70 gpm) 416 lpm (110 gpm) 265 lpm (70 gpm) 416 lpm (110 gpm)

10 Baghouse Hopper (part of baghouse scope of supply) -- 24(0)

-- -- -- --

11 Air Heater Hopper (part of boiler scope of supply) -- 10(0)

-- -- -- --

12 Air Blower

-- 1(0) 36 m 3 / min @ 0.2 MPa (1,260 scfm @ 24 psi) 54 m 3 /min @ 0.2

MPa (1,890 scfm @ 24 psi) 33 m 3 /min @ 0.2

MPa (1,180 scfm @ 24 psi) 50 m 3 /min @ 0.2

MPa (1,770 scfm @ 24 psi)

13 Fly Ash Silo Reinforced

concrete 2(0) 2,360 tonne (2,600 ton) 3,540 tonne

(3,900 ton) 2,18 0 tonne

(2,400 ton) 3,270 tonne

(3,600 ton)

14 Slide Gate Valves

-- 2(0)

-- -- -- -- 15 Unloader

-- 1(0)

-- -- -- --Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

182 Equipment
No. Des cription Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

16 Telescoping Unloading Chute -- 1(0) 218 tonne/hr (240 tph) 327 tonne/hr

(360 tph) 209 tonne/hr

(230 tph) 308 tonne/hr

(340 tph)

17 R ecycle Waste Storage Silo Reinforced

concrete 2(0) 454 tonne (500 ton) 454 tonne

(500 ton) 363 tonne

(400 ton) 454 tonne

(500 ton)

18 Recycle Waste Conveyor -- 1(0) 54 tonne/hr (60 tph) 54 tonne/hr

(60 tph) 45 tonne/hr

(50 tph) 54 tonne/hr

(60 tph)

19 Re cycle Slurry Mixer

-- 1(1) 1,401 lpm (370 gpm) 1,590 lpm

(420 gpm) 1,325 lpm

(350 gpm) 1,476 lpm

(390 gpm)

20 Recycle Waste Slurry
Tank -- 1(0) 83,280 liters (22,000 gal) 94,640 liters

(25,000 gal) 79,490 liters

(21,000 gal) 90,850 liters

(24,000 gal)

21 Recycle Waste Pump

-- 1(1) 1,401 lpm (370 gpm) 1,590 lpm

(420 gpm) 1,325 lpm

(350 gpm) 1,476 lpm

(390 gpm)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment

No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

1 STG Transformer Oil

- filled 1(0) 24 kV/345 kV, 650 MVA, 3

- ph,

60 Hz 24 kV/345 kV,

650 MVA, 3

- ph,

60 Hz 24 kV/345 kV,

650 MVA, 3

- ph,

60 Hz 24 kV/345 kV,

650 MVA, 3

- ph,

60 Hz

2 Auxiliary
Transformer Oil

- filled 1(1) 24 kV/4. 16 kV, 134 MVA, 3

- ph,
60 Hz 24 kV/4.16 kV,

146 MVA, 3

- ph,
60 Hz 24 kV/4.16 kV,

126 MVA, 3

- ph,
60 Hz 24 kV/4.16 kV,

137 MVA, 3

- ph,
60 Hz

3 Low Voltage
Transformer Dry ventilated 1(1) 4.16 kV/480 V, 20 MVA, 3

- ph,

60 Hz 4.16 kV/480 V,

22 MVA, 3

- ph,

60 Hz 4.1 6 kV/480 V, 19

MVA, 3

- ph, 60

Hz 4.16 kV/480 V, 20

MVA, 3

- ph, 60

Hz

4 STG Isolated Phase Bus Duct and Tap

Bus Aluminum, self

cooled 1(0) 24 kV, 3

- ph, 60

Hz 24 kV, 3

- ph, 60

Hz 24 kV, 3

- ph, 60

Hz 24 kV, 3

- ph, 60

Hz

5 Medium Voltage Switchgear Metal clad 1(1 ) 4.16 kV, 3

- ph, 60

Hz 4.16 kV, 3

- ph, 60

Hz 4.16 kV, 3

- ph, 60

Hz 4.16 kV, 3

- ph, 60

Hz

6 Low Voltage Switchgear Metal enclosed 1(1) 480 V, 3

- ph, 60

Hz 480 V, 3

- ph, 60

Hz 480 V, 3

- ph, 60

Hz 480 V, 3

- ph, 60

HzCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

183 Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Condition S13B Design

Condition L13B Design

Condition

7 Emergency Diesel
Generator Sized for

emergenc y shutdown 1(0) 750 kW, 480 V,
3

- ph, 60 Hz 750 kW, 480 V,

3

- ph, 60 Hz 750 kW, 480 V, 3

-

ph, 60 Hz 750 kW, 480 V, 3

-

ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment
No. Description Type Operating Qty. (Spares) S12B Design

Condition L12B Design

Con dition S13B Design

Condition L13B Design

Condition

1 DCS

- Main Control Monitor/keyboard, Operator printer, Engineering printer 1(0) Operator stations/printers and engineering stations/printers Operator

stations/printers and engineering stations/printers Operator

stations/printers and engineering stations/printers Operator

stations/printers and engineering stations/printers

2 DCS

- Processor Microprocessor
with redundant input/output 1(0) N/A N/A N/A N/A

3 DCS

- Data Highway Fiber optic 1(0) Fully redund ant, 25% spare Fully redundant,

25% spare Fully redundant,

25% spare Fully redundant,

25% spareCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

184 4.2.6 PC Cases with CO 2 Capture

– Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6 . The TPC summary organized by cost account, detailed breakdown of capital costs, owner’s costs, and initial and
annual O&M costs for the SC PC PRB case with CO 2 capture (S12B) are shown in Exhibit 4

- 69

, Exhibi t 4

- 70

, Exhibit 4

- 71 , and Exhibit 4

- 72 respectively. The same data for the SC PC lignite
case with CO 2 capture (L12B) are shown in Exhibit 4

- 73

, Exhibit 4

- 74

, Exhibit 4

- 75 , and
Exhibit 4

- 76 ; the USC PC PRB case with CO 2 capture (S13B) are shown in Exhibit 4

- 77

, Exhibit

4

- 78

, Exhibit 4

- 79 , and Exhibit 4

- 80 , and the USC PC Lignite case with CO 2 capture (L13B) are
shown in Exhibit 4

- 81

, Exhibit 4

- 82

, Exhibit 4

- 83 , and Exhibit 4

- 84

. The estimated TOC of the SC PC plant with CO 2 capture using PRB coal is $ 3,987 /kW and using lignite coal is $4,34 1 /kW. Project and process contingencies represent 1 0

. 2 and 2

. 6 percent respective ly in both cases. The COE is 107.5 mills/kWh for the PRB case and
116.4 mills/kWh for the lignite case. The estimated TOC of the USC PC plant with CO 2 capture using PRB coal is $ 4,049 /kW and using lignite coal is $ 4,372 /kW. Project and process contingencies represent 1 0

. 0 and 3

. 5 percent respective ly in both cases. The COE is
107.7 mills/kWh for the PRB case and 115.4 mills/kWh for the lignite case.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

185 Exhibit 4

- 69 Case S12B Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

186 Exhibi t 4

- 70 Case S12B Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

187 Exhibi t 4

- 70 Case S12B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

188 Exhibi t 4

- 70 Case S12B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

189 Exhibi t 4

- 70 Case S12B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

190 Exhibit 4

- 71 Case S12B Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

191 Exhibit 4

- 72 Case S12B Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

192 Exhibit 4

- 73 Case L12B Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

193 Exhibit 4

- 74 Case L12B Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

194 Exhibit 4

- 74 Case L12B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

195 Exhibit 4

- 74 Case L12B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

196 Exhibit 4

- 74 Case L12B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

197 Exhibit 4

- 75 Case L12B Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

198 Exhibit 4

- 76 Case L12B Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

199 Exhibit 4

- 77 Case S13B Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

200 Exhibit 4

- 78 Case S13B Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

201 Exhibit 4

- 78 Case S13B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

202 Exhibit 4

- 78 Case S13B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

203 Exhibit 4

- 78 Case S13B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

204 Exhibit 4

- 79 Case S13B Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

205 Exhibit 4

- 80 Case S13B Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

206 Exhibit 4

- 81 Case L13B T otal P lant C ost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

207 Exhibit 4

- 82 Case L13B Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

208 Exhibit 4

- 82 Case L13B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

209 Exhibit 4

- 82 Case L13B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

210 Exhibit 4

- 82 Case L13B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

211 Exhibit 4

- 83 Case L13B Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

212 Exhibit 4

- 84 Case L13B Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

213 5. CIRCULATING FLUIDIZE D BED COMBUSTION CAS ES

This section contains an evaluation of plant designs for Cases S22A, S22B, L22A, and L22B

, which are based on SC CFB plants. All the designs have a nominal net ou tput of 550 MWe. All four CFB plants use a single reheat 24.1 MPa/593°C/593°C (3,500 psig/1,100°F/1,100°F) cycle. Cases S22A and S22B are very similar in terms of process, equipment, scope, and arrangement, except that Case S22B employs CO 2 absorption/re generation and compression/transport systems. Cases L22A and L22B differ from Cases S22A and S22B only through the use of a different coal type ( NDL instead of PRB).

Section 5.1 covers the two non

- CO 2 capture cases and Sect ion 5.2 covers the two CO 2 capture cases. The sections are organized analogously to Section 4 as follows:

Process and System Description provides an overview of the technology operation as applied to Cases S22A and L22A in Section 5.1.1 and S22B and L22B in Section 5.2.1

. Key Assumptions is a summary of study and modeling assumptions relevant to Cases
S22A and L22A in Section 5.1.2 and S22B and L22B in Section 5.2.2

. Sparing Philosophy is provided for Cases S22A and L22A in Section 5.1.3 and S22B and
L22B Section 5.2.3

.
Performan ce Results provide the main modeling results from Cases S22A and L22A in
Section 5.1.4 and S22B and L22B in Section 5.2.4 , including the performance summary, environmental performance, carbon balanc e, sulfur balance, water balance, mass and energy balance diagrams

, and mass and energy balance tables.

Equipment Lists provide an itemized list of major equipment for Cases S22A and L22A
in Section 5.1.5 and S22B and L22B in S ection 5.2.5 with account codes that correspond
to the cost accounts in the Cost Estimates section.

Cost Estimates provide a summary of capital and operating costs for Cases S22A and
L22A in Section 5.1.6 and S22B and L22B in Section 5.2.6

.
If the information for the CO 2 capture cases is identical to that presented for the non

- capture cases, a reference is made to the earlier section rather than repeating the information.

5.1 SC CFB NON

- CAPTURE CASES (PRB A ND L IGNITE )

5.1.1 Process Description

In this section the SC CFB process without CO 2 capture is described. The SC process descriptions follow the BFD in Exhibit 5

- 1 and stream numbers reference the same exhibit. The
tables in Exhibit 5

- 2 and Exhibit 5

- 3 provide process data for the numbered streams in the BFD.

Coal (stream 8) and limestone (stream 9) are introduced into the combustor via pipes, and PA (stream 4) is introduced through bubble caps in a grid to fluidize the bed. Additional combustion air, including staged air for NOx and combustion control, is provided by the FD fans (stream 2). The combustor operates at a slight positive pressure so ai r leakage occurs in the solids collection/recycle zone, and the infiltration air is accounted for in stream 7. Ammonia is injected for additional NOx control using SNCR between the cyclone and the convective backpass.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

214 Flue gas exits the combustor (stream 11) and is cooled to 127°C (260°F) in the combustion air preheater (not shown) before passing to the baghouse to collect the waste products and the fly ash. Flue gas exits the baghouse and enters the ID fan suction (stream 1 4 ). The flue gas passes
to the plant stack and is discharged to the atmosphere.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

215 Exhibit 5

- 1 Cases S22A and L22A Process Flow DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

216 Exhibit 5

- 2 Case S22A Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

217 Exhibit 5

- 2 Case S22A Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

2 18 Exhibit 5

- 3 Case L22A Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

219 Exhibit 5

- 3 Case L22A Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

220 5.1.2 Key System Assumptions

System assumptions for Cases S22A and L22A, SC CFB without CO 2 capture, are compiled in
Exhibit 5

- 4

.
Exhibit 5

- 4 CFB Cases without CO 2 Capture Study Conf iguration Matrix

Case S22A
w/o CO 2 Capture Case L22A
w/o CO 2 Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 24.1/593/593 (3,500/1,100/1,100) 24.1/593/593 (3,500/1,100/1,100)

Coal Subbituminous Lignite

Carbon Conversion, % 98.6 99.1

Ca/S Mole Ratio 2.4 2.4
Condenser pressure, mm Hg (in Hg) 36 (1.4) 36 (1.4)

Combustion Air Preheater Flue Gas Exit Temp, °C (oF) 127 (260) 127 (260)

Cooling water to condenser, °C (oF) 9 (48) 8 (4 7 )
Cooling water from condenser, °C (oF) 20 (68) 19 (6 7 )

SO 2 Control in

- be d Limestone injection in

- bed Limestone injection

SO 2 Reduction Efficiency, % (A) 94 94

NOx Control Combustion temperature control
w/OFA and SNCR Combustion temperature control
w/OFA and SNCR
SNCR Efficiency, % 1 46 46
Ammonia Slip, ppmv 2 2

Particulat e Control Fabric Filter Fabric Filter
Fabric Filter efficiency, % 1 99.9 99.9
Ash Distribution, Fly/Bottom 70% / 30% 70% / 30%
Mercury Control Co

- benefit Capture Co

- benefit Capture
Mercury removal efficiency, % 1 57 57

CO 2 Control N/A N/A

CO 2 Capture , % 1 N/A N/A

CO 2 Sequestration N/A N/A

1 Equipment removal efficiencies

Balance of Plant

– Cases S22A and L22A

The balance of plant assumptions are common to all cases and were presented previously in
Section 3.1.6

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

221 5.1.3 Sparing Philosophy

Single trains are used throughout the design 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 subsy stems:

One SC CFB combustor (1 x 100 percent) with SNCR

Two single

- stage, in

- line, multi

- compartment fabric filters (2 x 50 percent)

One steam turbine (1 x 100 percent)

5.1.4 Cases S22A and L22A Performance Results

The non

- capture SC CFB plant using PRB coal pr oduces a net output of 550 MWe at a net plant efficiency of 38.9 percent (HHV basis). The same plant configuration using lignite coal produces a net output of 550 MWe at a net plant efficiency of 38.0 percent (HHV basis).

Overall performance for the two plants is summarized in Exhibit 5

- 5

, which includes auxiliary power requirements. The cooling water system, including the CWP s, cooling tower fan, and the
air

- cooled condenser, account for about 30 percent of the auxiliary load in all cases; and the PA

, FD and induced draft fans account for an additional 40 percent in all cases.

In the CFB cases boiler efficiencies are 85.7 percent for the PRB coal cases and 84.5 percent for the lignite cases. In each case the boiler heat loss i s 1 percent of the heat input and carbon conversion is 98.6 percent and 99.1 percent for PRB and lignite coal, respectively.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

222 Exhibit 5

- 5 CFB Cases without CO 2 Capture Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe) S22A L22A

Steam Turbine Power 578,400 578,700

AUXILIARY LOAD SUMMARY, kWe
Coal Handling and Conveying 500 600

Pulverizers / Crushers 120 160
Sorbent Handling & Reagent Preparation 80 90
Ash Handling 1,300 1,740

PA Fans 4,040 3,990

FD Fans 1,110 1,100

ID Fans 6,870 7,050

SNCR 10 20
Baghouse 150 200

Steam Turbine Auxiliaries 400 400
Condensate Pumps 780 790

CWP 2,390 2,380
Ground Water Pumps 220 220
Cooling Tower Fans 1,560 1,460

Air

- Cooled Condens er Fans 4,990 4,660

Miscellaneous Balance of Plant 1 2,000 2,000

Transformer Loss 1,810 1,810

TOTAL AUXILIARIES, kWe 28,330 28,670

NET POWER, kWe 550,070 550,030

Plant CF , % 85% 85%
Net Plant Efficiency, % (HHV) 38.9% 3 8.0%
Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,253 (8,770) 9,469 (8,975)

CONDENSER COOLING DUTY GJ/hr (10 6
Btu/hr) 2,225 (2,109) 2,211 (2,096)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 255,512 (563,307) 338,379 (745,997)
Thermal Input, kWt 2 1,4 1 3

, 821 1,446,676

Raw Water Withdrawal, m 3 /min (gpm) 9.1 (2,393) 9.0 (2,379) Raw Water Consumption, m 3 /min (gpm) 7.0 (1,839) 6.9 (1,828)

1 Includes plant control systems, lighting, HVAC

, and miscellaneous low voltage loads

2 Thermal input based on as

- rec eived HHV of coalCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

223 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 Cases S22A and L22A is presented in
Exhibit 5

- 6

.

Exhibit 5

- 6 CFB Cases without CO 2 Capture Air Emissions

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

S22A L22A S22A L22A S22A L22A

SO 2 0. 044

(0.102) 0.049

(0.113) 1,659

(1,829) 1,892

(2,086) 0.385

(0.85) 0.439

(0.97)

NO X 0.030

(0.070) 0.030

(0.070) 1,141

(1,257) 1,167

(1,286) 0.265

(0.584) 0.271

(0.597)

Particulates 0.006

(0.0130) 0.006

(0.0130) 212 (233) 217 (239) 0.049

(0.108) 0.050

(0. 111)

Hg 1.3E

- 7

(3.02E

- 7) 2.07E

- 7

(4.82E

- 7) 0.005

(0.005) 0.008

(0.009) 1.14E

- 6

(2.52E

- 6) 1.85E

- 6

(4. 11 E

- 6)

CO 2 91.5

(212.8) 94.0

(218.7) 3,464,762

(3,821,451) 3,645,843

(4,018,854) 805

(1,775) 846

(1,865)

CO 2 1 846 (1,866) 890

(1,963)

1 CO 2 emissio ns based on net power instead of gross power

SO 2 emissions are controlled using in

- bed limestone injection that achieves a removal efficiency of 94 percent. The waste is collected in the baghouse.

NOx emissions from CFB combustors are inherently low bec ause of the relatively low bed operating temperature of 1,600°F. NOx emissions are controlled to about 0.10

- 0.15 lb/MMBtu through the use of temperature controls, staging, and OFA. An SNCR unit then further reduces the NOx concentration by 46 percent to 0.07 lb/MMBtu.

Particulate emissions are controlled using a pulse jet fabric filter

, which operates at an efficiency of 99.9 percent.

Co

- benefit capture of mercury from a CFB with SNCR and a fabric filter is estimated to be 57 percent for either subbitumin ous or lignite coal [ 12 ]

. Mercury emissions can be reduced to approximately 25 percent of NSPS limits without the use of carbon injection, however carbon injection was included since it is currently the generally accepted pra ctice.

CO 2 emissions represent the uncontrolled discharge from the process.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

224 The carbon balances for the two non

- capture CFB cases are shown in Exhib it 5

- 7

. The carbon input to the plant consists of carbon in the air and limestone in addition to carbon in the coal. Carbon leaves the plant as CO 2 in the stack gas and unburned carbon in the ash

. The carbon conversion in the CFB is assumed to be 98.6 percent and 99.1 percent for PRB and lignite, respectively.

Exhib it 5

- 7 Cases S22A and L22A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S22A L22A S22A L22A

Coal 127,930

(282,037) 133,841

(295,069) Ash 2,935 (6,471) 2,570

(5,666)

Air (CO 2 ) 269 ( 593) 283 (623) Stack Gas 127,066 (280,133) 133,630

(294,604)

Limestone 1,756

(3,872) 2,005

(4,420)

Activated
Carbon 47 (103) 72 (158)

Total 130,002

(286,605) 136,200

(300,270) Total 130,002 (286,605) 136,200

(300,270)

Exhibit 5

- 8 shows the sulfur balances for the two non

- capture CFB cases. Sulfur input comes solely from the sulfur in the coal. Sulfur output is the sulfur combined with limestone in the ash, and the sulfur emitted in the stack gas.

Exhibit 5

- 8 Cases S22A and L22A Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S22A L22A S22A L22A

Coal 1,859 (4,098) 2,120 (4,673) Ash 1,747 (3,852) 1,992 (4,393)

Stack Gas 112 (246) 127 (280)

T otal 1,859 (4,098) 2,120 (4,673) Total 1,859 (4,098) 2,120 (4,673)

Exhibit 5

- 9 and Exhibit 5

- 10 show the overall water balances for the plants. Raw water withdrawal is obtained from groundwater (50 per cent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and that water is re

- used as internal recycle. Raw water
withdrawal is the dif

ference 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 3b (Combustion Cases)

225 Exhibit 5

- 9 Cas e S22A 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)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower

M akeup 9.3 (2,464) 0.27 (71) 9.1 (2,393) 2.10 (554) 6.96 (1,839)

Total 9.3 (2,464) 0.27 (71) 9.1 (2,393) 2.10 (554) 6.96 (1,839)

Exhibit 5

- 10 Case L22A Water Balance

Water Use Water

Demand,

m 3 /min (gpm) I nternal

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)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0) Cooling Tower Makeup 9.3 (2,450) 0.27 (71) 9.0 (2,379) 2.09 (551) 6.92 (1, 828)

Total 9.3 (2,450) 0.27 (71) 9.0 (2,379) 2.09 (551) 6.92 (1,828)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

226 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 5

- 11 through
Exhibit 5

- 14 :
Combustor and flue gas cleanup

Steam and FW

Overall plant energy balances are provided in tabular form in Exhibit 5

- 15 for the two CFB non

capture cases. The power out is the steam turbine power after generator losses.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

227 Exhibit 5

- 11 Case S22A Combustor and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

228 Exhibit 5

- 12 Case S22A Power Block System Heat and Mass Balance Diag ramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

229 Exhibit 5

- 13 Case L22A Combustor and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

230 Exhibit 5

- 14 Case L22A Power Block System Heat and Mass Balanc e DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

231 Exhibit 5

- 15 Cases S22A and L22A Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total

S22A L22A S22A L22A S22A L22A S22A L22A
Heat In, GJ/hr (MMBtu/hr)

Coal 5,090

(4,824 ) 5,208

(4,936) 2.6 (2.5) 3.0 (2.9) 5,092 (4,827) 5,211

(4,939)

Combustion Air 30.1 (28.5) 28.5 (27.0) 30.1 (28.5) 28.5 (27.0) Raw Water Makeup 12.6 (12.0) 10.0 (9.5) 12.6 (12.0) 10.0 (9.5)

Limestone 0.14 (0.13) 0.12 (0.12) 0.14 (0.13) 0.1 2 (0.12) Auxiliary Power 102 (97) 103 (98) 102 (97) 103 (98)

Totals 5,090

(4,824) 5,208

(4,936) 45.5 (43.1) 41.7 (39.5) 102 (97) 103 (98) 5,237 (4,964) 5,353

(5,074) Heat Out, GJ/hr (MMBtu/hr)

Bottom Ash 11.7 (11.0) 14.8 (14.0) 11.7 (11.0) 14.8 (14.0) Fly Ash + Sorbent 3.6 (3.5) 4.7 (4.4) 3.6 (3.5) 4.7 (4.4)

Flue Gas 691 (655) 874 (829) 691 (655) 874 (829)

Condenser 2,225 (2,109) 2,211

(2,096) 2,225 (2,109) 2,211

(2,096) Cooling Tower
Blowdown 11.7 (11.1) 11.3 (10.7) 11.7 (11 .1) 11.3 (10.7)

Process Losses* 212 (201) 153 (145) 212 (201) 153 (145)

Power 2,082 (1,974) 2,083

(1,975) 2,082

(1,974) 2,083

(1,975)

Totals 0 ( 0 ) 0 ( 0 ) 3,155 (2,990) 3,270

(3,099) 2,082

(1,974) 2,083

(1,975) 5,237

(4,964) 5,353

(5,074)

* Proce ss losses including steam turbine, combustion reactions, and gas cooling are estimated to match the heat input to the plant.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

232 5.1.5 CFB Cases without CO 2 Capture Equipment Lists

Major equipment items for the SC CFB Cases with no CO 2 capture using PRB or lignite coal are shown in the following tables. The equipment lists are not meant to be comprehensive, but rather representative. The accounts used in the equipment list correspond to the account
numbers used in the cost estimates in Section 5.1.6 . 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.

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment
No. Description Type Operating Qty. (Spa res) S22A Design

Condition L22A Design

Condition

1 Bottom Trestle Dumper and Receiving Hoppers N/A 2(0) 181 tonne (200 ton) 181 tonne

(200 ton)

2 Feeder Belt 2(0) 572 tonne/hr (630 tph) 572 tonne/hr (630

tph)

3 Conveyor No. 1 Belt 1(0) 1,134 tonne/hr (1 ,250 tph) 1,134 tonne/hr

(1,250 tph)

4 Transfer Tower No. 1 Enclosed 1(0) N/A N/A

5 Conveyor No. 2 Belt 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph)

6 As

- Received Coal Sampling System Two

- stage 1(0) N/A N/A

7 Stacker/Reclaimer Traveling, linear 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph)

8 Reclaim Hopper N/A 2(1) 54 tonne (60 ton) 73 tonne (80 ton)

9 Feeder Vibratory 2(1) 209 tonne/hr (230 tph) 281 tonne/hr

(310 tph)

10 Conveyor No. 3 Belt w/ tripper 1(0) 417 tonne/hr (46 0 tph) 553 tonne/hr

(610 tph)

11 Crusher Tower N/A 1(0) N/A N/A

12 Coal Surge Bin w/
Vent Filter Dual outlet 2(0) 209 tonne (230 ton) 281 tonne

(310 ton)

13 Crusher Impactor
reduction 2(0) 8cm x 0

- 3cm x 0 (3 x 0

- 3/4" x 0) 8cm x 0

- 3cm x 0

(3" x 0

- 3/4" x 0)

14 As

- Fired Coal Sampling System Swing hammer 1(0) N/A N/A

15 Conveyor No. 4 Belt w/tripper 1(0) 417 tonne/hr (460 tph) 553 tonne/hr

(610 tph)

16 Transfer Tower No. 2 Enclosed 1(0) N/A N/A

17 Conveyor No. 5 Belt w/ tripper 1(0) 426 tonne/hr (470 tph) 553 tonne/hr

(610 tph)

18 Coal Silo w/ Vent
Filter and Slide Gates Field erected 6(0) 454 tonne (500 ton) 635 tonne

(700 ton)

19 Limestone Truck Unloading Hopper N/A 1(0) 36 tonne/hr (40 tph) 36 tonne/hr

(40 tph)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

233 Equipment
No. Description Type Operating Qty. (Spa res) S22A Design

Condition L22A Design

Condition

20 Limestone Feeder Belt 1( 0) 73 tonne (80 ton) 82 tonne

(90 ton)

21 Limestone Conveyor

No. L1 Belt 1(0) 73 tonne (80 ton) 82 tonne

(90 ton)

22 Limestone Reclaim Hopper N/A 1(0) 18 tonne (20 ton) 18 tonne (20 ton)

23 Limestone Reclaim
Feeder Belt 1(0) 54 tonne (60 ton) 64 tonne ( 70 ton)

24 Limestone Conveyor

No. L2 Belt 1(0) 54 tonne (60 ton) 64 tonne (70 ton)

25 Limestone Day Bin w/ actuator 2(0) 227 tonne (250 ton) 263 tonne

(290 ton)

26 Activated Carbon Storage Silo and Feeder System with
Vent Filter Shop assembled 1(0) Silo

- 36 tonne (40 ton)
Feeder

- 50 kg/hr (110 lb/hr) Silo

- 54 tonne

(60 ton)
Feeder

- 77 kg/hr (170 lb/hr)

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment
No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design

Condition

1 Coal Feeder Gravimetric 6(0) 45 tonne/hr (50 tph) 64 tonne/hr

(70 tph)

2 Limestone Bin

Activator N/A 1(1) 19 tonne/hr (21 tph) 22 tonne/hr

(24 tph)

3 Limestone Weigh

Feeder N/A 1(1) 19 tonne/hr (21 tph) 22 tonne/hr

(24 tph)

4 Limestone Rod Mill

– Top size 1/16‖ Field Erected 1(1) 19 tonne/hr (21 tph) 22 tonne/hr

(24 tph)

5 Blower Horizontal centrifugal 1(1) 31 m 3 /min @
0.2 MPa (1,090 scfm @ 24 psi) 41 m 3 /min @

0.2 MPa (1,450 scfm @ 24 psi)

ACCOUNT 3 FW AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipme nt
No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design

Condition

1 Demineralized Water Storage
Tank Vertical, cylindrical,

outdoor 2(0) 1,067,486 liters (282,000 gal) 1,063,701 liters

(281,000 gal)

2 Condensate Pumps Vertical c anned 1(1) 23,091 lpm @
213 m H 2 O (6,100 gpm @
700 ft H 2 O) 23,091 lpm @

213 m H 2 O (6,100 gpm @
700 ft H 2 O)

3 Deaerator and Storage Tank Horizontal spray type 1(0) 1,774,000 kg/hr (3,911,000 lb/hr),
5 min. tank 1,771,732 kg/hr

(3,906,000 lb/hr),
5 min. tan kCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

234 Equipme nt
No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design

Condition

4 Boiler Feed

Pump/Turbine Barrel type, multi

- stage,

centrifugal 1(1) 29,905 lpm @ 3,475 m H 2 O (7,900 gpm @ 11,400 ft H 2 O) 29,905 lpm @

3,475 m H 2 O (7,900 gpm @ 11,400 ft H 2 O)

5 Startup Boiler Feed Pump,
Electric Motor
Driven Barrel type, multi

- stage,

centrifugal 1(0) 8,706 lpm @ 3,475 m H 2 O (2,300 gpm @ 11,400 ft H 2 O) 8,706 lpm @

3,475 m H 2 O (2,300 gpm @ 11,400 ft H 2 O)

6 LP Feedwater
Heater 1A/1B Horizontal U

- tube 2(0) 689,460 kg/hr (1,520,000 lb/hr) 689,460 kg/hr

(1,520,000 lb/hr)

7 LP Feedwater

Hea ter 2A/2B Horizontal U

- tube 2(0) 689,460 kg/hr (1,520,000 lb/hr) 689,460 kg/hr

(1,520,000 lb/hr)

8 LP Feedwater
Heater 3A/3B Horizontal U

- tube 2(0) 689,460 kg/hr (1,520,000 lb/hr) 689,460 kg/hr

(1,520,000 lb/hr)

9 LP Feedwater
Heater 4A/4B Horizontal U

- t ube 2(0) 689,460 kg/hr (1,520,000 lb/hr) 689,460 kg/hr

(1,520,000 lb/hr)

10 HP Feedwater

Heater 6 Horizontal U

- tube 1(0) 1,773,546 kg/hr (3,910,000 lb/hr) 1,773,546 kg/hr

(3,910,000 lb/hr)

11 HP Feedwater

Heater 7 Horizontal U

- tube 1(0) 1,773,546 kg/hr ( 3,910,000 lb/hr) 1,773,546 kg/hr

(3,910,000 lb/hr)

12 HP Feedwater

heater 8 Horizontal U

- tube 1(0) 1,773,546 kg/hr (3,910,000 lb/hr) 1,773,546 kg/hr

(3,910,000 lb/hr)

13 Auxiliary Boiler Shop fabricated, water
tube 1(0) 18,144 kg/hr, 2.8 MPa, 343°C (40,0 00 lb/hr, 400 psig, 650°F) 18,144 kg/hr, 2.8

MPa, 343°C (40,000 lb/hr, 400 psig, 650°F)

14 Fuel Oil System No. 2 fuel oil for light
off 1(0) 1,135,624 liter (300,000 gal) 1,135,624 liter

(300,000 gal)

15 Service Air

Compressors Flooded Screw 2(1) 28 m 3 /m in @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7

MPa (1,000 scfm @ 100 psig)

16 Instrument Air

Dryers Duplex, regenerative 2(1) 28 m 3 /min (1,000 scfm) 28 m 3 /min (1,000

scfm)

17 Closed Cycle

Cooling Heat Exchangers Shell and tube 2(0) 53 GJ/hr (50

MMB tu/hr) each 53 GJ/hr (50

MMBtu/hr) each

18 Closed Cycle

Cooling Water Pumps Horizontal centrifugal 2(1) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O)

19 Engine

- Driven

Fire Pump Vertical turbine, diesel

engi ne 1(1) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O)

20 Fire Service

Booster Pump Two

- stage horizontal

centrifugal 1(1) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

235 Equipme nt
No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design

Condition

21 Raw Water Pumps Stainless steel, single
suction 2(1) 2,612 lpm @ 18

m H 2 O (690 gpm
@ 60 ft H 2 O) 2,612 lpm @ 18

m H 2 O (690 gpm
@ 60 ft H 2 O)

22 Ground Water

Pumps Stainless steel, single

suction 2(1) 2,612 lpm @ 268

m H 2 O (690 gpm
@ 880 ft H 2 O) 2,612 lp m @ 268

m H 2 O (690 gpm
@ 880 ft H 2 O)

23 Filtered Water

Pumps Stainless steel, single

suction 2(1) 303 lpm @ 49 m

H 2 O (80 gpm @
160 ft H 2 O) 303 lpm @ 49 m

H 2 O (80 gpm @
160 ft H 2 O)

24 Filtered Water

Tank Vertical, cylindrical 1(0) 280,120 liter (74,000 ga l) 280,120 liter

(74,000 gal)

25 Makeup Water

Demineralizer Multi

- media filter,

cartridge filter, RO membrane assembly,
electrodeionization unit 1(1) 606 lpm (160 gpm) 606 lpm

(160 gpm)

26 Liquid Waste

Treatment System -- 1(0) 10 years,

24

- hour storm 10 years,

24

- hour storm

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment
No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design
Condition

1 Boiler Atm. Pressure

CFB,
Once

- thru Supercritical
Boiler with Air

Heater 1(0) 1,773,546 kg/hr stea m @ 25.5
MPa/602°C/602°C (3,910,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1,773,546 kg/hr steam
@ 25.5
MPa/602°C/602°C (3,910,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F)

2 Primary Air

Fan Centrifugal 2(0) 640,019 kg/hr, 9,534

m 3 /min @ 129 cm WG (1,4 11,000 lb/hr, 336,700 acfm @ 51 in. WG) 668,142 kg/hr, 9,339

m 3 /min @ 129 cm WG (1,473,000 lb/hr, 329,800 acfm @ 51 in. WG)

3 Forced
Draft Fan Centrifugal 2(0) 426,377 kg/hr, 6,357

m 3 /min @ 52 cm WG (940,000 lb/hr, 224,500 acfm @ 21 in. WG) 445,428 kg/hr, 6,224

m 3 /min @ 52 cm WG (982,000 lb/hr, 219,800 acfm @ 21 in. WG)

4 Induced
Draft Fan Centrifugal 2(0) 1,210,638 kg/hr, 27,037 m 3 /min @ 77 cm WG (2,669,000 lb/hr, 954,800 acfm @ 30 in. WG) 1,295,460 kg/hr, 27,555

m 3 /min @ 77 cm WG (2,856,000 lb/hr, 973,1 00 acfm @ 30 in. WG)

5 SNCR

Lance 1(1) 17 lpm (5 gpm) 17 lpm (5 gpm)

6 Dilution Air
Blower Centrifugal 2(1) 42 m 3 /min @ 108 cm WG (1,500 acfm @ 42 in. WG) 42 m 3 /min @ 108 cm

WG (1,500 acfm @ 42 in. WG)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

236 Equipment

No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design
Condition

7 Ammonia Storage Horizontal tank 5(0) 45,425 lite r (12,000 gal) 45,425 liter (12,000 gal)

8 Ammonia Feed Pump Centrifugal 2(1) 9 lpm @ 91 m H 2 O (2 gpm @ 300 ft H 2 O) 9 lpm @ 91 m H 2 O (2 gpm @ 300 ft H 2 O)

ACCOUNT 5 FLUE GAS CLEANUP

Equipment
No. Description Type Operating Qty. (Spares) S22A Design

Condit ion L22A Design

Condition

1 Fabric Filter Single stage, high

- ratio with pulse

-

jet online cleaning system, air

- to

cloth ratio

- 3.5 ft/min 2(0) 1,210,638 kg/hr (2,669,000 lb/hr) 99.9% efficiency 1,295,460 kg/hr

(2,856,000 lb/hr) 99.9% efficiency

2 Carbon Injectors

--- 1(0) 50 kg/hr (110 lb/hr) 77 kg/hr (170

lb/hr)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES

N/A

ACCOUNT 7 HRSG, DUCTING & STACK

Equipment
No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design
Condition

1 Stack Rei nforced
concrete with
FRP liner 1(0) 152 m (500 ft) high x 6.7 m (22 ft) diameter 152 m (500 ft) high x 6.8 m (22 ft) diameter

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment
No. Description Type Operating Qty. (Spares) S22A Design

Condition L 22A Design

Condition

1 Steam Turbine Commercially
available advanced
steam turbine 1(0) 609 MW 24.1
MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 609 MW 24.1

MPa/593°C/593°C (3500 psig/ 1100°F/1100°F)

2 Steam Turbine

Generator Hydrogen cooled,

static excita tion 1(0) 680 MVA @ 0.9 p.f., 24 kV, 60 Hz,

3

- phase 680 MVA @ 0.9

p.f., 24 kV, 60 Hz,

3

- phaseCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

237 Equipment

No. Description Type Operating Qty. (Spares) S22A Design

Condition L 22A Design

Condition

3 Surface
Condenser Single pass,

divided waterbox including vacuum

pumps 1(0) 1,220 GJ/hr (1,160 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water
tempe rature 9°C (48°F), Water temperature rise 11°C (20°F) 1,210 GJ/hr (1,150

MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F)

4 Air

- cooled
Condenser --- 1(0) 1,220 GJ/hr (1,160 MMBtu/hr),
Co ndensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 1,210 GJ/hr (1,150

MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 4°C (40°F)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment
No. Description Type Operating Qty. (Spares) S22A De sign

Condition L22A Design
Condition

1 Circulating Water Pumps Vertical, wet

pit 2(1) 238,500 lpm @ 30 m (63,000 gpm @ 100 ft) 238,500 lpm @ 30 m (63,000 gpm @ 100 ft)

2 Cooling Tower Evaporative,
mechanical draft, multi

cell 1(0) 3°C (37°F) wet bulb /
9 °C (48°F) CWT / 20°C (68°F) HWT / 1,340 GJ/hr (1,270 MMBtu/hr) heat duty 2°C (36°F) wet bulb /

8°C (47°F) CWT / 19°C (67°F) HWT / 1,329 GJ/hr (1,260 MMBtu/hr) heat duty

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

Equipment

No. Description Type Oper ating Qty. (Spares) S22A Design

Condition L22A Design

Condition

1 Economizer Hopper (part of boiler scope of supply) -- 4(0)

-- --

2 Bottom Ash Hopper (part

of boiler scope of supply) -- 2(0)

-- --

3 Clinker Grinder

-- 1(1) 14.5 tonne/hr (16 tph) 19.1 tonne/hr

(21 tph)

4 Pyrites Hopper (part of

pulverizer scope of supply included with boiler) -- 6(0)

-- --

5 Hydroejectors

-- 12(0)

-- --

6 Economizer /Pyrites

Transfer Tank -- 1(0)

-- --

7 Ash Sluice Pumps Vertical, wet pit 1(1) 568 lpm @ 17 m

H 2 O (15 0 gpm @
56 ft H 2 O) 757 lpm @ 17 m

H 2 O (200 gpm @
56 ft H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

238 Equipment
No. Description Type Oper ating Qty. (Spares) S22A Design

Condition L22A Design

Condition

8 Ash Seal Water Pumps Vertical, wet pit 1(1) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O)

9 Hydrobins

-- 1(1) 568 lpm (150 gpm) 757 lpm

(200 gpm)

10 Baghouse Hopper (part of

baghouse scope of supply) -- 24(0)

-- --

11 Air Heater Hopper (part

of boiler scope of supply) -- 10(0)

-- --

12 Air Blower

-- 1(1) 31 m 3 /min @ 0.2 MPa (1,090 scfm @ 24 psi) 41 m 3 /min @ 0.2

MPa (1,450 scfm @ 24 psi)

13 Fly Ash S ilo Reinforced

concrete 2(0) 1,996 tonne (2,200 ton) 2,722 tonne

(3,000 ton)

14 Slide Gate Valves

-- 2(0)

-- -- 15 Unloader

-- 1(0)

-- --

16 Telescoping Unloading

Chute -- 1(0) 191 tonne/hr (210 tph) 254 tonne/hr

(280 tph)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment
No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design

Condition

1 STG Transformer Oil

- filled 1(0) 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 650

MVA, 3

- ph, 60 Hz

2 Auxiliary

Transformer Oil

- filled 1(1) 24 k V/4.16 kV, 29 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 30

MVA, 3

- ph, 60 Hz

3 Low Voltage

Transformer Dry

ventilated 1(1) 4.16 kV/480 V, 4 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 4

MVA, 3

- ph, 60 Hz

4 STG Isolated

Phase Bus Duct and Tap Bus Aluminum,

self

- cooled 1(0) 24 kV , 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz

5 Medium Voltage

Switchgear Metal clad 1(1) 4.16 kV, 3

- ph, 60

Hz 4.16 kV, 3

- ph, 60 Hz

6 Low Voltage

Switchgear Metal

enclosed 1(1) 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz

7 Emergency

Diesel Generator Sized for

emergency sh utdown 1(0) 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

-

ph, 60 HzCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

239 ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment
No. Description Type Operating Qty. (Spares) S22A Design

Condition L22A Design

Condition

1 DCS

- Main
Control Monitor/keyboard,

Operator pr inter, Engineering printer 1(0) Operator stations/printers and engineering stations/printers Operator

stations/printers and engineering stations/printers

2 DCS

-

Processor Microprocessor with

redundant input/output 1(0) N/A N/A

3 DCS

- Data

Highway Fiber optic 1(0) Fully redundant, 25% spare Fully redundant,

25% spare

5.1.6 CFB Cases without CO 2 Capture

– Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6 . The TPC summary organized by cost account, detailed breakdown of capital costs, owner’s costs, and initial and
annual O&M costs for the CFB PRB case without CO 2 capture (S22A) are shown in Exhibit
5

- 16

, Exhibit 5

- 17

, Exhibit 5

- 18 , and Exhibit 5

- 19 respectively. The same data for the CFB lignite case without CO 2 capture (L22A) are shown in Exhibit 5

- 20

, Exhibit 5

- 21

, Exhibit 5

- 22

, and Exhibit 5

- 23

. The estimated TOC of the CFB plant without CO 2 capture using PRB coal is $ 2,357 /kW and using lignite coal is $ 2,490 /kW. Project and process contingencies represent 8

. 9 and 4

. 4 percent respective ly in both cases. The COE is 61.5 mills/kWh for the PRB case and 64.6 mills/kWh for the lignite case.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

240 Exhibit 5

- 16 Case S22A Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

241 Exhibit 5

- 17 Case S22A Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

242 Exhibit 5

- 17 Case S22A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

243 Exhibit 5

- 17 Case S22A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

244 Exhibit 5

- 17 Case S22A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

245 Exhibit 5

- 18 Case S22A Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

246 Exhibit 5

- 19 Case S22A Initi al and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

247 Exhibit 5

- 20 Case L22A Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

248 Exhibit 5

- 21 Case L22A Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

249 Exhibit 5

- 21 Case L22A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

250 Exhibit 5

- 21 Case L22A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

251 Exhibit 5

- 21 Case L22A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

252 Exhibit 5

- 22 Case L22A Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

253 Exhibit 5

- 23 Case L22A Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

254 5.2 SC CFB CO 2 CAPTURE CASES (PRB A ND LIGNITE)

5.2.1 Process Description

In this section the SC CFB processes with CO 2 capture are described. The plant configurations
are similar to the non

- capture cases presented in Section 5.1 with the major difference being the
use of an Econamine system for CO 2 capture and sub sequent compression of the captured CO 2 stream. Since the CO 2 capture and compression process increases the auxiliary load on the plant, the coal feed rate is significantly increased and the overall efficiency is significantly reduced
relative to the non

- capture cases. A process BFD for the two CO 2 capture cases is shown in
Exhibit 5

- 24 and stream tables for Cases S22B and L22B are shown in Exhibit 5

- 25 and
Exhibit 5

- 26 . The CO 2 removal system is described in Section 3.1.4

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

255 Exhibit 5

- 24 Cases S22B and L22B Process Flow DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

256 Exhibit 5

- 25 Case S2 2B Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

257 Exhibit 5

- 25 Case S2 2B Stream Table (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

258 Exhibit 5

- 26 Case L22B Stream TableCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

259 Exhibit 5

- 26 Case L22B Stream Table (Continued )Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

260 5.2.2 Key System Assumptions

System assumptions for Cases S22B and L22B, SC CFB with CO 2 capture, are compiled in
Exhibit 5

- 27

.

Exhibit 5

- 27 CFB Cases with CO 2 Capture Study Config uration Matrix

Case S22B
w/ CO 2 Capture Case L22B
w/CO 2 Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 24.1/593/593 (3,500/1,100/1,100) 24.1/593/593 (3,500/1,100/1,100)

Coal Subbituminous Lignite

Ca/S Mole Ratio 2.4 2.4 Condenser pressure, mm Hg (in H g) 36 (1.4) 36 (1.4) Combustion air preheater flue gas exit temp., °C (oF) 127 (260) 127 (260)

Cooling water to condenser, °C (oF) 9 (48) 8 (4 7 ) Cooling water from condenser, °C (oF) 20 (68) 19 (6 7 )

SO 2 Control 2, 3 in

- bed Limestone injection in

- bed Li mestone injection

SO 2 Reduction Efficiency, % 1 94 94

NOx Control Combustion temperature
control w/OFA and

SNCR Combustion temperature

control w/OFA and

SNCR
SNCR Efficiency, % 1 46 46
Ammonia Slip (end of catalyst life), ppmv 2 2

Particulate Control Fabric Filter Fabric Filter
Fabric Filter efficiency, % 1 99.9 99.9
Ash Distribution, Fly/Bottom 70% / 30% 70% / 30%
Mercury Control Co

- benefit Capture Co

- benefit Capture
Mercury removal efficiency, % 1 57 57

CO 2 Control Econamine Econamine

CO 2 Captu re, % 1 90 90

CO 2 Sequestration Off

- site Saline Formation Off

- site Saline Formation

1 Equipment removal efficiencies

2 An SO 2 polishing step is included to meet more stringent SOx content limits in the flue gas (< 10 ppmv) to reduce formation of amine HS S during the CO 2 absorption process

3 SO 2 exiting the post

- FGD polishing step is absorbed in the CO 2 capture process making stack emissions negligible

Balance of Plant

– Cases S22B and L22B

The balance of plant assumptions are common to all cases and were presented previously in
Section 3.1.6

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

261 5.2.3 Sparing Philosophy

Single trains are used throughout the design 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:

One SC CFB combustor (1 x 100 percent) with SNCR

Two single

- stage, in

- line, multi

- compartment fabric filters (2 x 50 percent)

One steam turbine (1 x 100 percent)

Two paralle l Econamine CO 2 absorption systems, with each system consisting of two absorbers, strippers, and ancillary equipment (2 x 50 percent)

5.2.4 Cases S22B and L22B Performance Results

The CO 2 capture SC CFB plant using PRB coal produces a net output of 550 MWe at a net plant efficiency of 27. 3 percent (HHV basis). The same plant configuration using lignite coal produces a net output of 550 MWe at a net plant efficiency of 2 5

. 9 percent (HHV basis).

Overall performance for the two plants is summarized in Exhibit 5

- 28

, which includes auxiliary power requirements. The cooling water system, including the CWPs and cooling tower fan, and
the air

- cooled condenser account for about 16 percent of the auxiliary load in all cases, and the

PA , FD and induced draft fans account for an additional 14 percent. CO 2 compression accounts
for about 42 percent and the Econamine process about 20 percent of the auxiliary load in all

cases.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

262 Exhibit 5

- 28 CFB Cases with CO 2 Capture Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe) S22B L22B

Steam Turbine Power 664,000 672,900

AUXILIARY LOAD SUMMARY, kWe
Coal Handling and Conveying 620 760

Pulverizers / Crushers 170 2 4 0

Sorbent Handling & Reagent Preparation 110 130
Ash Handling 1,850 2,550

PA Fans 5,760 5,880

FD Fans 1,590 1,620

ID Fans 9,080 9,630

SNCR 20 20
Baghouse 210 290

Econamine Auxiliaries 22,4 1 0 24,3 1 0

CO 2 Compression 47,960 52,090

Steam Turbine Auxiliaries 400 400
Condensate Pumps 560 530

CWP 8,850 9,900
Ground Water Pumps 700 720
Cooling Tower Fans 5,780 6,080

Air

- Cooled Condenser Fans 3,620 3,320

Miscellaneous Balance of Plant 1 2,000 2,000

Transformer Loss 2,300 2,350

TOTAL AUXILIARIES, kWe 113,990 122,820

NET POWER, kWe 550,010 550,080

Plant CF , % 85% 85%
Net Plant Efficiency, % (HHV) 27.3% 25.9%
Net Plant Heat Rate, kJ/kWh (Btu/kWh) 13,163 (12,476) 13,907 (13,182)

CONDENSER COOLING DUTY GJ/hr (10 6 Btu/hr) 1,614 (1 ,529) 1,574 (1,492)

CONSUMABLES

As

- Received Coal Feed, kg/hr (lb/hr) 363,450 (801,270) 497,052

(1,095,812)
Thermal Input, kW t 2 2,011,075 2,125,054

Raw Water Withdrawal, m 3 /min (gpm) 29.4 (7,762) 30.3 (7,996) Raw Water Consumption, m 3 /min (gpm) 21.6 (5,713) 21.6 (5,704)

1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

2 Thermal input based on as

- received HHV of coal

Environmental Performance

The environmental targets for emissions of Hg, NOx, SO 2, and PM were pres ented in
Section 2.3 . A summary of the plant air emissions for Cases S22B and L22B is presented in
Exhibit 5

- 29

.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

263 Exhibit 5

- 29 CFB Cases with CO 2 Captu re Air Emissions

kg/GJ (lb/10 6 Btu) Tonne/year (ton/year) 85% capacity factor kg/MWh (lb/MWh)

S22B L22B S22B L22B S22B L22B

SO 2 0.001

(0.002) 0.001

(0.002) 41 (45) 44 (48) 0.008 (0.020) 0.009

(0.020)

NO X 0.030

(0.070) 0.030

(0.070) 1,622

(1,788) 1,71 4

(1,890) 0.328

(0.723) 0.342

(0.754)

Particulates 0.006

(0.0130) 0.006

(0.0130) 301 (332) 318 (351) 0.061 (0.134) 0.064

(0.140)

Hg 1.30E

- 7

(3.02E

- 7) 2.07E

- 7

(4.82E

- 7) 0.007

(0.008) 0.012

(0.013) 1.41 E

- 6

(3.12E

- 6) 2.36E

- 6

(5.19E

- 6)

CO 2 9.1 (21.3) 9.4 (2 1.9) 493,129 (542,582) 535,549

(590,342) 100 (220) 107 (236)

CO 2 1 120 (265) 131 (288)

1 CO 2 emissions based on net power instead of gross power

SO 2 emissions are controlled using in

- bed limestone injection that achieves a removal efficiency of 94 pe rcent. The waste is collected in the baghouse. The CO 2 capture system includes a SO 2 polishing unit that reduces SO 2 emission to a negligible level.

NOx emissions from CFB combustors are inherently low because of the relatively low bed operating temper ature of 1,600°F NOx emissions are controlled to about 0.10

- 0.15 lb/MMBtu through the use of temperature controls, staging, and OFA. An SNCR unit then further reduces the NOx concentration by 46 percent to 0.07 lb/MMBtu.

Particulate emissions are controll ed using a pulse jet fabric filter

, which operates at an efficiency of 99.9 percent.

Co

- benefit capture of mercury from a CFB with SNCR and a fabric filter is estimated in an EPA report to be 57 percent for either subbituminous or lignite coal. Given the lack of mercury data on utility

- scale CFB’s, the EPA estimate is used for co

- benefit capture levels in all CFB cases. Mercury emissions can be reduced to approximately 25 percent of NSPS limits without the use of carbon injection, however carbon injection was included since it is currently the generally accepted practice.

Ninety percent of the CO 2 from the flue gas is captured in the Econamine system and compressed for sequestration.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

264 The carbon balances for the two CO 2 capture CFB cases are shown in Exhibit 5

- 30

. The carbon input to the plant consists of carbon in the air and limestone in addition to carbon in the coal. Carbon leaves the plant as CO 2 in the stack gas , unburned carbon in the ash and CO 2 product.
The carbon conv ersion in the CFB is assumed to be 98.6 percent and 99.1 percent for PRB and lignite respectively :
Percent Sequestered = (Carbon in Product for Sequestration)/ (Carbon in Coal + Carbon in
Limestone

- Carbon in Ash) or 358,628 / (401,181 + 5,505

– 9,202) * 100 = 90.2 percent (S22B) 389,478 / (433,434 + 6,468

– 8,299) * 100 = 90.2 percent (L22B)

Exhibit 5

- 30 Cases S22B and L22B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

S22B L22B S22B L22B

Coal 181,973

(401,181) 196,602

(433,434) Ash 4,174 (9,202) 3,764

(8,299)

Air (CO 2 ) 384 (846) 417 (918) Stack Gas 18,075 (39,848) 19,629

(43,275)

Limestone 2,497

(5,505) 2.934

(6,468) CO 2 Product 162,671 (358,628) 176,664

(389,478)

Activate d
Carbo n 66 (1 46 ) 106 (223)

Total 184,920

(407,678) 200,058

(441,053) Total 184,920 (407,678) 200,058

(441,053)

Exhibit 5

- 31 shows the sulfur balances for the two capture CFB cases. Sulfur input comes solely
from the sulfur in the coal. Sulfur output is the sulfur combined with lime in the ash, the SO 2 from the polishing scrubber, and the sulfur emitted in the stack gas. The sulfur exits the Econamine system in the form of sodium sulfite and HSS.

Exhibit 5

- 31 Cases S22B and L22B Sulfur Balance

Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr)

S22B L22B S22B L22B

Coal 2,644 (5,829) 3,114 (6,864) Ash 2,485 (5,479) 2,927 (6,452)
Polishing
Scrubber /
Econamine FG+ 156 (344) 1 84 (405)

Stack Gas 3 (6) 3 (6)

Total 2,644 (5,829) 3,114 (6,864) Total 2,644 (5,829) 3,114 (6,864)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

265 Exhibit 5

- 32 and Exhibit 5

- 33 shows the overall water balances for the plants. Raw water
withdra wal is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and that water is re

- used as internal r ecycle. 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.

Exhibit 5

- 32 Case S22B Water Balance

Water Use Water

Demand,

m 3 /min (gpm) Internal

Recycle,

m 3 /min (gpm) Raw Water

Withdrawal,

m 3 /min (gpm) Process

Water Discharge,

m 3 /min (gpm) Raw Water

Consumption,

m 3 /min (gpm)

Econamine 0.15 ( 39) 0 (0) 0.15 (39) 0 (0) 0.15 (39)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 34.5 (9,110) 5.25 (1,387) 29.2 (7,723) 7.76 (2,049) 21.48 (5,674)

Total 34.6 (9,148) 5.25 (1,387) 29.4 (7,762) 7.76 (2,049) 21.63 (5,713)

Exhibit 5

- 33 Case L22B 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)

Econa mine 0.16 (42) 0 (0) 0.16 (42) 0 (0) 0.16 (42)

BFW Makeup 0 (0) 0 (0) 0 (0) 0 (0) 0 (0)
Cooling Tower Makeup 38.6 (10,190) 8.47 (2,236) 30.1 (7,953) 8.67 (2,292) 21.43 (5,662)

Total 38.7 (10,232) 8.47 (2,236) 30.3 (7,996) 8.67 (2,292) 21.59 (5,704)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

266 He at and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 5

- 34 through
Exhibit 5

- 37 :
Combustor and flue gas cleanup

Steam and FW

Overall plant energy ba lances are provided in tabular form in Exhibit 5

- 38 for the two SC CFB cases. The sulfur exits the Econamine FG+ system in the form of sodium sulfite and HSS , but is
shown as SO 2 . The power out is the steam turbine power after g enerator losses.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

267 Exhibit 5

- 34 Case S22B Combustor and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

268 Exhibit 5

- 35 Case S22B Power Block System Heat a nd Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

269 Exhibit 5

- 36 Case L22B Combustor and Gas Cleanup System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

270 Exhibit 5

- 37 Case L22B Power Block System Heat and Mass Balance DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

271 Exhibit 5

- 38 Cases S22B and L22B Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total

S22B L22B S22B L22B S22B L22B S22B L22B
Heat In, GJ/hr (MMBtu/hr )

Coal 7,240 (6,862) 7,650

(7,251) 3.7 (3.5) 4.4 (4.2) 7,244 (6,866) 7,655

(7,255)

Combustion Air 43.0 (40.7 42.0 (39.8) 43.0 (40.7) 42.0 (39.8) Raw Water Makeup 40.9 (38.8) 33.7 (32.0) 40.9 (38.8) 33.7 (32.0)

Limestone 0.19 (0.18) 0.18 (0. 17) 0.19 (0.18) 0.18 (0.17) Auxiliary Power 410 (389) 442 (419) 410 (389) 442 (419)

Totals 7,240 (6,862) 7,650

(7,251) 87.8 (83.3) 80.4 (76.2) 410 (389) 442 (419) 7,738 (7,334) 8,173

(7,746) Heat Out, GJ/hr (MMBtu/hr)

Bottom Ash 16.6 (15.7) 21. 7 (20.6) 16.6 (15.7) 21.7 (20.6) Fly Ash + Sorbent 5.2 (4.9) 6.9 (6.5) 5.2 (4.9) 6.9 (6.5)

Flue Gas 244 (231) 254 (241) 244 (231) 254 (241)

Condenser 1,614 (1,529) 1,574

(1,492) 1,614 (1,529) 1,574

(1,492)

CO 2 - 127 (

- 120)

- 137 (

- 130)

- 127 (

- 120)

- 137 (

- 130) Cooling Tower Blowdown 43.2 (41.0) 47.0 (44.5) 43.2 (41.0) 47.0 (44.5)

Econamine Losses 3,196 (3,029) 3,686

(3,494) 3,196 (3,029) 3,686

(3,494)

Process Losses* 356.0 (337.4) 297.8

(282.3) 356.0 (337.4) 297.8

(282.3)

Power 2,390 (2,266) 2,422

(2,296) 2,390

(2,266) 2,422

(2,296)

Totals 0 ( 0 ) 0 ( 0 ) 5,348 (5,069) 5,750

(5,450) 2,390

(2,266) 2,422

(2,296) 7,738

(7,334) 8,173

(7,746) * Process losses including steam turbine, combustion reactions, and gas cooling are e stimated to match the heat input to the plant.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

272 5.2.5 CFB Cases with CO 2 Capture Equipment Lists

Major equipment items for SC CFB with CO 2 capture and using PRB or lignite coal are shown in the following tables. The equipment lists are not meant to be comprehe nsive, but rather representative. The accounts used in the equipment list correspond to the account numbers used
in the cost estimates in Section 5.2.6 . In general, the design conditions include a 10 percent contingency for f

lows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL AND SORBENT HANDLING

Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 Bottom Trestle Dumper and Receiving Hop pers N/A 2(0) 181 tonne (200 ton) 181 tonne

(200 ton)

2 Feeder Belt 2(0) 572 tonne/hr (630 tph) 572 tonne/hr

(630 tph)

3 Conveyor No. 1 Belt 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph)

4 Transfer Tower No. 1 Enclosed 1(0) N/A N/A

5 Conve yor No. 2 Belt 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph)

6 As

- Received Coal Sampling System Two

- stage 1(0) N/A N/A

7 Stacker/Reclaimer Traveling, linear 1(0) 1,134 tonne/hr (1,250 tph) 1,134 tonne/hr

(1,250 tph)

8 Reclaim Hopper N/A 2(1 ) 73 tonne (80 ton) 100 tonne (110 ton)

9 Feeder Vibratory 2(1) 299 tonne/hr (330 tph) 408 tonne/hr

(450 tph)

10 Conveyor No. 3 Belt w/ tripper 1(0) 599 tonne/hr (660 tph) 816 tonne/hr

(900 tph)

11 Crusher Tower N/A 1(0) N/A N/A

12 Coal Surge Bin w/

Ve nt Filter Dual outlet 2(0) 299 tonne (330 ton) 408 tonne

(450 ton)

13 Crusher Impactor
reduction 2(0) 8cm x 0

- 3cm x 0 (3 ‖ x 0

- 3/4"x 0) 8cm x 0

- 3cm x 0

(3 ‖ x 0

– 3/4"x 0)

14 As

- Fired Coal Sampling System Swing hammer 1(1) N/A N/A

15 Conveyor No. 4 Belt w/tripper 1(0) 599 tonne/hr (660 tph) 816 tonne/hr

(900 tph)

16 Transfer Tower No. 2 Enclosed 1(0) N/A N/A

17 Conveyor No. 5 Belt w/ tripper 1(0) 599 tonne/hr (660 tph) 816 tonne/hr

(900 tph)

18 Coal Silo w/ Vent
Filter and Slide Gates Field erec ted 6(0) 635 tonne (700 ton) 907 tonne

(1,000 ton)

19 Limestone Truck Unloading System N/A 1(0) 36 tonne/hr (40 tph) 36 tonne/hr

(40 tph)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

273 Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

20 Limestone Feeder Belt 1(0) 100 tonne (110 ton) 118 tonne

(130 ton)

21 Limestone Conveyor

No. L1 Belt 1(0) 100 to nne/hr (110 tph) 118 tonne/hr

(130 tph)

22 Limestone Reclaim Hopper N/A 1(0) 18 tonne (20 ton) 27 tonne (30 ton)

23 Limestone Reclaim
Feeder Belt 1(0) 82 tonne/hr (90 tph) 100 tonne/hr

(110 tph)

24 Limestone Conveyor

No. L2 Belt 1(0) 82 tonne/hr (90 tph ) 100 tonne/hr

(110 tph)

25 Limestone Day Bin w/ actuator 2(0) 327 tonne/hr (360 ton) 381 tonne/hr

(420 ton)

26 Activated Carbon

Storage Silo and Feeder System with
Vent Filter Shop assembled 1(0) Silo

- 54 tonne (60 ton)
Feeder

- 73 kg/hr (160 lb/hr) Si lo

- 82 tonne

(90 ton)
Feeder

- 118 kg/hr (260 lb/hr)

ACCOUNT 2 COAL AND SORBENT PREPARATION AND FEED

Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 Coal Feeder Gravimetric 6(0) 64 tonne/hr (70 tph) 9 1 tonne/hr

(100 tph)

2 Limestone Bin
Activator N/A 1(1) 27 tonne/hr (30 tph) 32 tonne/hr

(35 tph)

3 Limestone Weigh
Feeder N/A 1(1) 27 tonne/hr (30 tph) 32 tonne/hr

(35 tph)

4 Limestone Rod Mill

– Top size 1/16‖ Field Erected 1(1) 27 tonne/hr (30 tph) 3 2 tonne/hr

(35 tph)

5 Blower Horizontal centrifugal 1(1) 44 m 3 /min @
0.2 MPa (1,550 scfm @ 24 psi) 60 m 3 /min @

0.2 MPa (2,130 scfm @ 24 psi)

ACCOUNT 3 FW AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 Demineralized Water Storage
Tank Vertical, cylindrical,

outdoor 2(0) 1,510,379 liters (399,000 gal) 1,578,233 liters

(409,000 gal)

2 Condensate Pumps Vertical canned 1(1) 16,656 lpm @
213 m H 2 O (4,400 gpm @
700 f t H 2 O) 15,899 lpm @

213 m H 2 O (4,200 gpm @
700 ft H 2 O)

3 Deaerator and Storage Tank Horizontal spray

type 1(0) 2,516,077 kg/hr (5,547,000 lb/hr),
5 min. tank 2,578,219 kg/hr

(5,684,000 lb/hr),
5 min. tankCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

274 Equipment

No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

4 Boiler Feed Pump/Turbine Barrel type, multi

sta ge, centrifugal 1(1) 42,397 lpm @ 3,505 m H 2 O (11,200 gpm @ 11,500 ft H 2 O) 43,154 lpm @

3,505 m H 2 O (11,400 gpm @ 11,500 ft H 2 O)

5 Startup Boiler Feed Pump,
Electric Motor
Driven Barrel type, multi

stage, centrifugal 1(0) 12,492 lpm @ 3,505 m H 2 O (3,300 g pm @ 11,500 ft H 2 O) 12,870 lpm @

3,505 m H 2 O (3,400 gpm @ 11,500 ft H 2 O)

6 LP Feedwater
Heater 1A/1B Horizontal U

- tube 2(0) 489,880 kg/hr (1,080,000 lb/hr) 476,272 kg/hr

(1,050,000 lb/hr)

7 LP Feedwater
Heater 2A/2B Horizontal U

- tube 2(0) 489,880 kg/hr ( 1,080,000 lb/hr) 476,272 kg/hr

(1,050,000 lb/hr)

8 LP Feedwater

Heater 3A/3B Horizontal U

- tube 2(0) 489,880 kg/hr (1,080,000 lb/hr) 476,272 kg/hr

(1,050,000 lb/hr)

9 LP Feedwater
Heater 4A/4B Horizontal U

- tube 2(0) 489,880 kg/hr (1,080,000 lb/hr) 476,272 kg/hr

(1,050,000 lb/hr)

10 HP Feedwater

Heater 6 Horizontal U

- tube 1(0) 2,517,438 kg/hr (5,550,000 lb/hr) 2,576,405 kg/hr

(5,680,000 lb/hr)

11 HP Feedwater

Heater 7 Horizontal U

- tube 1(0) 2,517,438 kg/hr (5,550,000 lb/hr) 2,576,405 kg/hr

(5,680,000 lb/h r)

12 HP Feedwater
heater 8 Horizontal U

- tube 1(0) 2,517,438 kg/hr (5,550,000 lb/hr) 2,576,405 kg/hr

(5,680,000 lb/hr)

13 Auxiliary Boiler Shop fabricated,
water tube 1(0) 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)

14 Fuel Oil System No. 2 fuel oil for light off 1(0) 1,135,624 liter (300,000 gal) 1,135,624 liter

(300,000 gal)

15 Service Air Compressors Flooded Screw 2(1) 28 m 3 /min @ 0.7 MPa (1,000 scfm @ 100 psig) 28 m 3 /min @ 0.7

MPa (1,000 scfm @ 100 psig)

16 Instrument Air Dryers Duplex,

regenerative 2(1) 28 m 3 /min (1,000 scfm) 28 m 3 /min

(1,000 scfm)

17 Closed Cycle Cooling Heat Exchangers Shell and tube 2(0) 53 GJ/hr (50 MMBtu/hr)
each 53 GJ/hr

(50 MMBtu/hr)
each

18 Clos ed Cycle Cooling Water Pumps Horizontal

centrifugal 2(1) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O) 20,820 lpm @ 30

m H 2 O (5,500 gpm @ 100 ft

H 2 O)

19 Engine

- Driven Fire Pump Vertical turbine,

diesel engine 1(1) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O) 3,785 lpm @ 88

m H 2 O (1,000 gpm @ 290 ft

H 2 O)

20 Fire Service Booster Pump Two

- stage

horizontal centrifugal 1(1) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O) 2,650 lpm @ 64

m H 2 O (700 gpm
@ 210 ft H 2 O)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

275 Equipment

No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

21 Raw Water Pumps Stainless steel,

single suct ion 2(1) 8,934 lpm @ 18

m H 2 O (2,360 gpm @ 60 ft

H 2 O) 9,577 lpm @ 18

m H 2 O (2,530 gpm @ 60 ft

H 2 O)

22 Ground Water Pumps Stainless steel,

single suction 2(1) 2,990 lpm @ 268

m H 2 O (790 gpm
@ 880 ft H 2 O) 2,725 lpm @ 268

m H 2 O (720 gpm
@ 880 ft H 2 O)

23 Fil tered Water Pumps Stainless steel,

single suction 2(1) 492 lpm @ 49 m

H 2 O (130 gpm @
160 ft H 2 O) 530 lpm @ 49 m

H 2 O (140 gpm @
160 ft H 2 O)

24 Filtered Water
Tank Vertical, cylindrical 1(0) 480,747 liter (127,000 gal) 499,674 liter

(132,000 gal)

25 Makeup Water
Demineralizer Multi

- media filter,

cartridge filter, RO
membrane assembly,
electrodeionization
unit 1(1) 984 lpm (260 gpm) 1,022 lpm

(270 gpm)

26 Liquid Waste

Treatment System -- 1(0) 10 years,

24

- hour storm 10 years,

24

- hour storm

ACCOUNT 4 BOILER AND ACCESSORIES

Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design
Condition

1 Boiler Atm. Pressure CFB,
Once

- thru Supercritical
Boiler with
Air Heater 1(0) 2,517,438 kg/hr steam
@ 25.5
MPa/602°C/602°C (5,550,000 lb/ hr steam @ 3,700 psig/1,115°F/1,115°F) 2,576,405 kg/hr steam
@ 25.5
MPa/602°C/602°C (5,680,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F)

2 Primary Air

Fan Centrifugal 2(0) 911,721 kg/hr, 13,586

m 3 /min @ 129 cm WG (2,010,000 lb/hr, 479,800 acfm @ 51 in.

WG ) 980,213 kg/hr, 13,703

m 3 /min @ 129 cm WG (2,161,000 lb/hr, 483,900 acfm @ 51 in. WG)

3 Forced Draft

Fan Centrifugal 2(0) 607,814 kg/hr, 9,059

m 3 /min @ 52 cm WG (1,340,000 lb/hr, 319,900 acfm @ 21 in. WG) 653,627 kg/hr, 9,135

m 3 /min @ 52 cm WG (1,441,000 lb/hr, 322,600 acfm @ 21 in. WG)

4 Induced Draft

Fan Centrifugal 2(0) 1,724,105 kg/hr, 38,514 m 3 /min @ 71 cm WG (3,801,000 lb/hr, 1,360,100 acfm @ 28 in. WG) 1,901,006 kg/hr,

40,434 m 3 /min @ 71 cm WG (4,191,000 lb/hr, 1,427,900 acfm @ 28 in. WG)

5 SNCR Lance 1(1) 24 lpm (6 gpm) 25 lpm (7 gpm)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

276 Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design
Condition

6 Dilution Air
Blower Centrifugal 2(1) 57 m 3 /min @ 108 cm WG (2,000 acfm @ 42 in. WG) 59 m 3 /min @ 108 cm

WG (2,100 acfm @ 42 in. WG)

7 Ammonia

Storage Horizontal

tank 5(0) 64,352 liter (17,000 gal) 68,137 liter ( 18,000 gal)

8 Ammonia Feed Pump Centrifugal 2(1) 12 lpm @ 91 m H 2 O (3 gpm @ 300 ft H 2 O) 13 lpm @ 91 m H 2 O

(3 gpm @ 300 ft H 2 O)

ACCOUNT 5 FLUE GAS CLEANUP

Equipment

No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 Fabric Filter Single stage, high

ratio with pulse

-

jet online cleaning system, air

- to

- cloth
ratio

- 3.5 ft/min 2(0) 1,742,105 kg/hr (3,801,000 lb/hr) 99.9% efficiency 1,901,006 kg/hr

(4,191,000 lb/hr) 99.9% efficiency

2 Carbon Injectors

--- 1(0) 73 kg/hr (160 lb/hr) 118 kg/hr (260

lb/hr)

ACCOUNT 5B CARBON DIOXIDE RECOVERY

Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 Econamine FG Plus Amine

- based CO 2 capture technology 2(0) 1,742,105 kg/h (3,801,0 00 lb/h)
21.1 wt % CO 2 concentration 1,901,006 kg/h

(4,191,000 lb/h)
20.6 wt % CO 2 concentration

2 Econamine Condensate Pump Centrifugal 1(1) 18,397 lpm @ 52

m H 2 O (4,860 gpm @ 170 ft

H 2 O) 19,836 lpm @ 52

m H 2 O (5,240 gpm @ 170 ft

H 2 O)

3 CO 2 Compressor I ntegrally geared,
multi

- stage centrifugal 2(0) 327,062 kg/h @
15.3 MPa (721,048 lb/h @ 2,215 psia) 353,030 kg/h @

15.3 MPa (778,298 lb/h @ 2,215 psia)

ACCOUNT 6 COMBUSTION TURBINE/ACCESSORIES

N/ACost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

277 ACCOUNT 7 DUCTING & STACK

Equipment
No. Description Typ e Operating Qty. S22B Design

Condition L22B Design

Condition

1 Stack Reinforced
concrete with
FRP liner 1(0) 152 m (500 ft) high x 6.1 m (20 ft)
diameter" 152 m (500 ft)

high x 6.1 m (20 ft)
diameter"

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equ ipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 Steam Turbine Commercially
available
advanced steam
turbine 1(0) 699 MW 24.1
MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 707 MW 24.1

MPa/593°C/593°C (3500 psi g/ 1100°F/1100°F)

2 Steam Turbine
Generator Hydrogen cooled,

static excitation 1(0) 780 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3

- phase 790 MVA @ 0.9

p.f., 24 kV, 60 Hz,

3

- phase

3 Surface
Condenser Single pass,

divided waterbox including vacuum

pumps 1(0) 890 GJ/h r (840 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 9°C (48°F), Water temperature rise 11°C (20°F) 870 GJ/hr

(820 MMBtu/hr), Condensing temperature 32°C (90°F), Inlet water temperature 8°C (47°F), Water temperature rise 11°C (20°F )

4 Air

- cooled
Condenser --- 1(0) 890 GJ/hr (840 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 6°C (42°F) 870 GJ/hr

(820 MMBtu/hr), Condensing temperature 32°C (90°F), Ambient temperature 4°C (40°F)

ACCOUNT 9 COOLING WATER SYSTEM

Equ ipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design
Condition

1 Circulating Water Pumps Vertical, wet

pit 2(1) 885,800 lpm @ 30 m (234,000 gpm @ 100 ft) 988,000 lpm @ 30 m (261,000 gpm @ 100 ft)

2 Cooling

Tower Evaporati ve,

mechanical draft, multi

cell 1(0) 3°C (37°F) wet bulb / 9°C (48°F) CWT / 20°C (68°F) HWT / 4,948 GJ/hr (4,850 MMBtu/hr) heat duty 2°C (36°F) wet bulb /

8°C (47°F) CWT / 19°C (67°F) HWT / 5,497 GJ/hr (5,210 MMBtu/hr) heat dutyCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

278 ACCOUNT 10 ASH/SPENT SORB ENT RECOVERY AND HANDLING

Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 Economizer Hopper (part of boiler scope of supply) -- 4(0)

-- --

2 Bottom Ash Hopper (part of boiler scope of supply) -- 2(0)

- - --

3 Clinker Grinder

-- 1(1) 20.9 tonne/hr (23 tph) 28.1 tonne/hr

(31 tph)

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- 6(0)

-- --

5 Hydroejectors

-- 12(0)

-- --

6 Economizer /Pyrites
Transfer Tank -- 1(0)

-- --

7 As h Sluice Pumps Vertical, wet pit 1(1) 833 lpm @ 17 m

H 2 O (220 gpm @
56 ft H 2 O) 1,136 lpm @ 17

m H 2 O (300 gpm
@ 56 ft H 2 O)

8 Ash Seal Water Pumps Vertical, wet pit 1(1) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O) 7,571 lpm @ 9 m

H 2 O (2,000 gpm
@ 28 ft H 2 O)

9 Hydrobins

-- 1(1) 833 lpm (220 gpm) 1,136 lpm

(110 gpm)

10 Baghouse Hopper (part of baghouse scope of supply) -- 24(0)

-- --

11 Air Heater Hopper (part of boiler scope of supply) -- 10(0)

-- --

12 Air Blower

-- 1(0) 44 m 3 /min @ 0.2 MPa (1,550 scfm

@ 24 psi) 60 m 3 /min @ 0.2

MPa (2,130 scfm @ 24 psi)

13 Fly Ash Silo Reinforced

concrete 2(0) 2,900 tonne (3,200 ton) 3,990 tonne

(4,400 ton)

14 Slide Gate Valves

-- 2(0)

-- -- 15 Unloader

-- 1(0)

-- --

16 Telescoping Unloading
Chute -- 1(0) 272 tonne/hr (300 tph) 372 tonne/hr

(410 tph)

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment

No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 STG Transformer Oil

- filled 1(0) 24 kV/345 kV, 650 MVA, 3

- ph, 60 Hz 24 kV/345 kV, 65 0

MVA, 3

- ph, 60 Hz

2 Auxiliary
Transformer Oil

- filled 1(1) 24 kV/4.16 kV, 124 MVA, 3

- ph, 60 Hz 24 kV/4.16 kV, 133

MVA, 3

- ph, 60 Hz

3 Low Voltage
Transformer Dry ventilated 1(1) 4.16 kV/480 V, 19 MVA, 3

- ph, 60 Hz 4.16 kV/480 V, 20

MVA, 3

- ph, 60 HzCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

279 Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

4 STG Isolated Phase Bus Duct and Tap

Bus Aluminum,

self

- cooled 1(0) 24 kV, 3

- ph, 60 Hz 24 kV, 3

- ph, 60 Hz

5 Medium Voltage Switchgear Metal clad 1(1) 4.16 kV, 3

- ph, 60 Hz 4.16 kV, 3

- ph, 60

Hz

6 Low Voltage Switchgear Metal enclosed 1(1) 480 V, 3

- ph, 60 Hz 480 V, 3

- ph, 60 Hz

7 Emergency Diesel
Generator Sized for

emergency shutdown 1(0) 750 kW, 480 V, 3

- ph, 60 Hz 750 kW, 480 V, 3

-

ph, 60 Hz

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment
No. Description Type Operating Qty. (Spares) S22B Design

Condition L22B Design

Condition

1 DCS

- Main
Control Monitor/keyboard,

Operator printer, Engineering printer 1(0) Operator stations/printers and engineering stations/printers Operator

stations/printers and engineering stations/printers

2 DCS

- Processor Microprocessor with

redundant input/output 1(0) N/A N/A

3 DCS

- Data Highway Fiber optic 1(0) Fully redundant, 25% spare Fully redundant,

25% spare

5.2.6 CFB Cases with CO 2 Capture

– Cost Estimating

Costs Results

The cost estimating methodology was described previously in S ection 2.6 . The TPC summary organized by cost account, detailed breakdown of capital costs, owner’s costs, and initial and
annual O&M costs for the CFB PRB case with CO 2 capture (S22B) are shown in Exhibit 5

- 39

, Exhibit 5

- 40

, Exhibit 5

- 41 , and Exhibit 5

- 42 respectively. The same data for the CFB lignite
case with CO 2 capture (L22B) are shown in Exhibit 5

- 43

, Exhibit 5

- 44

, Exhibit 5

- 45 , and
Exhibit 5

- 46

. The estimated TOC of the CFB plant with CO 2 capture using PRB coal is $ 4,018 /kW and using lignite coal is $ 4,307 /kW. Project and process contingencies represent 1 0

. 1 and 5

. 8 percent respective ly in both cases. The COE is 108.0 mills/kWh for the PRB case and 115.2 mills/kWh for the lignite case.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

280 Exhibit 5

- 39 Case S22B Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

281 Exhibit 5

- 40 Case S22B Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

282 Exhibit 5

- 40 Case S22B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

283 Exhibit 5

- 40 Case S22B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

284 Exhibit 5

- 40 Case S22B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

285 Exhibit 5

- 41 Case S22B Owne r’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

286 Exhibit 5

- 42 Case S22B Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

287 Exhibit 5

- 43 Case L22B Total Plant Cost SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

288 Exhibit 5

- 44 Case L22B Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

289 Exhibit 5

- 44 Case L22B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

290 Exhibit 5

- 44 Case L22B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

291 Exhibit 5

- 44 Case L22B Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

292 Exhibit 5

- 45 Case L22B Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

293 Exhibit 5

- 46 Case L22B Initial and Annual O &M CostsCost and Performance Baseline

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294 This page intentionally left blankCost and Performance Baseline

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295 6. SENSITIVITY TO BITUMINOUS BASELINE CASE 12A MEA SYSTEM

Studies of PC plants with post combustion capture of CO 2 for the 20 10 NETL Bituminous and Low Rank Baselines Studies are based on a performance and cost estimate for an Econamine
CO 2 capture system provided by Fluor in 2005 [ 42 ]

. A recent Fluor publication [ 43 ] indicates that Fluor has improved the Econamine system. The improved system is able to achieve a reboiler steam requirement of 1,270 Btu/lb CO 2 as c ompared to the 1,530 Btu/lb CO 2 used in the baseline studies. Fluor also indicated concurrent reductions in auxiliary electrical power requirements and capital costs.

The Fluor publication [ 43 ] indicates the i mprovements in performance and cost are enabled by an improved solvent formulation with an MEA concentration greater than 30 percent and improved corrosion inhibitors. Fluor states that the improved solvent results in increased reaction rates enabling les s absorber packing and lower capital cost. Also, the higher solvent carrying capacity results in lower solvent circulation rates, lower steam requirements, and lower capital cost of solvent circulation equipment.

C ost and performance data on the improved system w ere unavailable directly from Fluor. Using
a commercial ac id gas removal software package, the CO 2 removal process was simulate d using higher MEA concentrations, but the confiden ce in the generated results and any associated equipment sizing or co sting changes were not adequate for use in this analysis. Therefore, a sensitivity analysis was performed using published data from Fluor and best engineering judgment to estimate the impact of an improved MEA CO 2 capture system on the performance
and cos t of a SC boiler firing bituminous coal. It is expected that the relative difference observed in the bituminous coal cases would be the same if applied to PRB or NDL coal cases.

6.1 BASIS FOR SENSITIVIT Y ANALYSIS

The sensitivity analysis was performed on Case 12 of the Bituminous Baseline Study. This case
used a SC PC plant burning bituminous (Illinois #6) coal at International Standards Organization ( ISO ) conditions. The sensitivity case was labeled Case 12A.

It was assumed, based on qualitative statements by Fluor, that the improved performance and reduced cost were achieved by increasing the MEA concentration from 30 wt% to 36 wt%. It
was further assumed that Econamine reboiler steam requirements, power requirements and capital cost were inversely proport ional to the increase in MEA concentration. The reboiler steam requirement and electrical auxiliary requirements were reduced by the ratio o f 30/36 = 0.83. The Econamine plant capital cost was scaled using two factors

– the first based on the
amount of C O 2 capture d to the 0.6 power and the second based on the ratio of the increased solvent concentration to the 0.7 power

. The Aspen model for Case 12 was modified for the reduced reboiler steam requirement and calculations were adjusted for the reduced aux iliary power requirement. Performance and cost estimates for Case 12A as compared to Case 12 are included in the following sections.

6.2 PERFORMANCE

The BFD , Stream Tables and Performance Summary for Case 12A are shown in Exhibit 6

- 1

, Exhibit 6

- 2 , and Exhibit 6

- 3 . The Performance Summary from Case 12 is also included inCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

296 Exhibit 6

- 3 for comparison. The net plant efficiency for Case 12A is 29.8% compared to 28.4%
for Case 12.

The auxiliary power for Case 12A is 104 MW compared to 113 MW for Case 12. Gross output was reduced for Case 12A by 9 MW to maintain a 550 MW net output for both cases. The
reduction in a uxiliary p ower results primarily from reduction s in the Econamine and CO 2 compressor auxiliaries with minor reductions in most other auxiliary loads resulting from a slightly smaller gross plant size.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

297 Exhibit 6

- 1 Bituminous Baseline Case 12A MEA Sen sitivity Process Flow DiagramCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

298 Exhibit 6

- 2 Bituminous Baseline Case 12A Stream Table, SC Unit with CO 2 CaptureCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

299 Exhibit 6

- 2 Bituminous Baseline Case 12A Stream Table, SC Unit with CO 2 Capture (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

300 Exhibit 6

- 3 Bituminous Baseline Case 12A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Bituminous Baseline Case 12 12A

Ste am Turbine Power 662,800 654,200
TOTAL (STEAM TURBINE) POWER, kWe 662,800 654,200
AUXILIARY LOAD SUMMARY, kWe Coal Handling and Conveying 510 500

Pulverizers 3,850 3,670 Sorbent Handling & Reagent Preparation 1,250 1,190 Ash Handling 740 700

PA Fa ns 1,800 1,720

FD Fans 2,300 2,190

ID Fans 11,120 10,610

SCR 70 60 Baghouse 100 90

Wet FGD 4,110 3,920

Econamine Auxiliaries 20,600 16,400

CO 2 Compression 44,890 42,840

Miscellaneous Balance of Plant 2,3 2,000 2,000

Steam Turbine Auxiliaries 400 40 0 Condensate Pumps 560 610

CWPs 10,100 9,390 Ground Water Pumps 920 850 Cooling Tower Fans 5,230 4,860

Transformer Losses 2,290 2,240
TOTAL AUXILIARIES, kWe 112,840 104,240
NET POWER, kWe 549,960 549 ,96 0 Net Plant Efficiency (HHV) 28.4 % 29.8 %

Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,663 (12

, 002 ) 12,085 (11,455)
CONDENSER COOLING DUTY, 10 6 kJ/h (10 6 Btu/h) 1,737 (1,646) 1,893 (1,794)

CONSUMABLES

As

- Received Coal Feed, kg/h (lb/h) 256,652 (565,820) 244,938 (539,995) Limestone Sorbent Feed, kg/h (lb/h) 25,966 (57,245) 24, 720 ( 54,497 ) Thermal Input, kWt 1 1,934,519 1,846,224 Raw Water Withdrawal, m 3 /min (gpm) 38.1 (10,071 ) 35.4 (9,350)
Raw Water Consumption, m 3 /min (gpm) 29.3 (7,733 ) 27.2 (7,177)

1. HHV of As Received Illinois No. 6 coal is 27, 135 kJ/kg (11,666 Btu/lb) 2. Boiler feed pumps are turbine driven 3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loadsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

301 6.3 COST ESTIMATING

The cost estimating methodology was described in Section 2.6 of this report

. Exhibit 6

- 4 shows
the TPC summary organized by cost account and Exhibit 6

- 5 shows a more detailed breakdown of the capital costs including the TOC and TASC

. Exhibit 6

- 7 shows the initial and annual
O&M costs.

The TPC was estimated using a factored cost method with Case 12 as the reference. Account
5B.1 was scaled based on CO 2 captured to the 0.6 power and additionally reduced by 12 percent as discussed previo usly to account for capital cost reductions resulting from the reduced solvent
circulation rate

. The estimated TOC for Case 12A is $3,364/kW. This represent s a reduction from Case 12 of 6
percent . Process contingency represents 2.6 percent of the TOC and project contingency represents 10.0 p ercent. The COE, including CO 2 TS&M costs of 5.3 mills/kWh, is 100.8
mills/kWh. This COE is 5 .5 % less than the Baseline Case 12 COE of 106.6 mills/kWh.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

302 Exhibit 6

- 4 Bituminous Baseline Case 12A TPC SummaryCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

30 3 Exhibit 6

- 5 Bituminous Baseline Case 12A Total Plant Cost DetailsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

304 Exhibit 6

- 5 Bituminous Baseline Case 12A Total Plant Cost Details ( Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

305 Exhibit 6

- 5 Bituminous Baseline Case 12A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

306 Exhibit 6

- 5 Bituminous Baseline Case 12A Total Plant Cost Details (Continued)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

307 Exhibit 6

- 6 Case S12A Owner’s CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

308 Exhibit 6

- 7 Bituminous Baseline Case 12A Initial and Annual O&M CostsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

309 7. SUMMARY

7.1 P ERFORMANCE

The nominal net plant output for this study is set at 550 MW. The boilers and steam turbines are readily available in a wide range of capacities. Higher auxiliary load and extraction steam requirements are accommodated in CO 2 capture cases using larger boilers and steam turbines.

The perform ance summaries for all cases are shown in Exhibit 7

- 1 . The efficiencies (based on HHV) are shown in Exhibit 7

- 2 . The primary conclusions regarding plant efficiencies that can
be drawn are:

The USC PC pl ant with no CO 2 capture and PRB coal has the highest net efficiency of the technologies modeled in this study with an efficiency of 39.9 percent. The combination of aggressive steam conditions and higher quality coal (relative to NDL) results in the highe st net efficiency.

The USC PC case with CO 2 capture and PRB coal results in the highest efficiency (28.7 percent) among all of the capture technologies. Similar to the non

- capture case, the aggressive steam conditions and higher quality coal are the prima ry reasons for the highest net efficiency.

The CO 2 capture results in an efficiency penalty of 11 to 12 absolute percent, relative to
the non

- capture case for all the technologies.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

310 Exhibit 7

- 1 Estimated Performance, Emissions, and Cost Results

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

- Low Rank, Volume 3b (Combustion Cases)

311 Exhibit 7

- 2 Net Plant Efficiency (HHV Basis)Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

312 7.2 COST RESULTS

The T OCs are shown in Exhibit 7

- 3 . Observations related to the TOCs include:

For the SC PC cases the TOC is higher for the NDL coal cases as compared to the P RB coal cases: approximately 8.7 percent for both the non

- capture and CO 2 ca pture case.

For the SC PC cases the TOC increase to add CO 2 capture is approximately 74 percent for both the PRB and NDL cases.

For the USC PC cases the TOC is also higher for the NDL coal cases as compared to the
PRB coal cases: approximately 9 percent f or the non

- capture case and 8 percent for the
CO 2 capture case.

For the USC PC cases the TOC increase to add CO 2 capture is approximately 68 percent for the PRB case and 66 percent for the NDL case.
Following the same trend as the SC PC and USC PC cases, f or the SC CFB cases the TOC is higher for the NDL coal cases as compared to the PRB coal cases: approximately
5. 6 percent for the non

- capture case and 7. 2 percent for the CO 2 capture case. The NDL
cases have consistently higher TOC because of higher coal feed associated with lower boiler efficiency.

For the SC CFB cases the TOC increase to add CO 2 capture is approximately 70 percent for the PRB case and 73 percent for the NDL case.

The COEs are shown in Exhibit 7

- 4

. The following observations can be made:

The COE is dominated by capital charges in all cases. The capital cost component of COE comprises 62

- 6 3 percent in all four SC PC cases, 6 3

- 6 5 percent in all four USC PC cases, and 6 2

- 6 4 percent in all four CFB cases.

The fuel c ost component is relatively minor in all cases, rep resenting 10

- 14 percent of the
COE costs in the PRB cases and 9

- 12 percent in the NDL cases.
For each coal type and CO 2 capture scenario, the COE is lowest for the more conventional technology (SC PC) comp ared to the more advanced technologies (USC PC and SC CFB). The only exception is for NDL coal with CO 2 capture where USC PC and SC CFB have a very slight cost benefit because of the higher USC efficiency.

The TS&M component of COE in the CO 2 capture case s is 5

- 6 percent for both PRB and

NDL coal.

The COE is 5

- 8 percent lower in both the CO 2 capture and non

- capture PRB cases compared to the NDL coal cases because of higher efficiencies resulting in lower plant

costs.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

313 The COE with CO 2 removal includes the c osts of capture and compression

, as well as TS&M costs. The resulting avoided costs are shown in Exhibit 7

- 5 for each of the CO 2 capture technologies modeled. The avoided costs for each capture case are calculated using the
anal ogous non

- capture plant as the reference and again with SC PC without CO 2 capture as the
reference. The cost of CO 2 avoided for analogous plant designs averages $ 68.8 /ton ne ($62.4/ton) with a range of $ 67

- $ 70 /ton ne ($61

- $64/ton) for the SC PC cases, $ 63.7 /ton ne ($57.8/ton) with a range of $ 63

- $64 /ton ne ($57

- $58/ton) for the USC PC cases

, and $ 65.6 /ton ne ($59.5/ton) with a range of $ 64

- $67 /ton ne ($58

- $61/ton) for the CFB cases

. The CO 2 avoided
costs are lower for PRB coal than NDL , mainly because of the si gnificant capital cost increase in
the NDL fuel cases resulting from lower plant efficiency . CO 2 avoided costs are also shown compared to the baseline SC PC plant (12 series cases) firing the same coal.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

314 Exhibit 7

- 3 Total Overnight CostCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

315 Exhibit 7

- 4 Cost of ElectricityCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

316 Exhibit 7

- 5 Cost of CO 2 AvoidedCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

317 7.3 ENVIRONMENTAL PERFOR MANCE

7.3.1 Emissions

The environmental targets were described in Section 2.3 . The emissions of SO 2 , NOx

, and PM
are shown in Exhibit 7

- 6 and mercury emissions are shown in Exhibit 7

- 7 . CO 2 emissions are shown on a lb/MWh basis (both gross and net) in Exhibit 7

- 8 . The following observations can
be made:

For the PC cases, emissions of SO 2 are controlled using a lime spray

- dryer system that achieves a removal efficiency of 93 percent and s atisfies the emissions target of 0.132
lb/MMBtu for the NDL cases

. The SO 2 emissions are lower for the PRB coal cases because the sulfur loading to the FGD system is less while the removal efficiency
remains the same

. For the CO 2 capture cases, SO 2 exiti ng the spray dryer is further reduced to 10 ppmv in the CDR facility polishing scrubber resulting in extremely low
emissions.

For the CFB cases, emissions of SO 2 are controlled using in

- bed limestone injection that achieves a removal efficiency of 94 perce nt and exceeds the emissions target of 0.132
lb/MMBtu. For the CO 2 capture cases, SO 2 exiting the baghouse is further reduced to 10 ppmv in the CDR facility polishing scrubber resulting in extremely low emissions.

Particulate emissions are controlled usin g a pulse jet fabric filter

, which removes over 99.9 percent of the particulates present in the flue gas

.
NOx emissions are the same for each PC case and controlled to about 0.2 lb/MMBtu using LNBs and OFA. An SCR unit further reduces the NOx concentratio n by 65 percent to 0.07 lb/MMBtu. For the CFB cases, combustion temperature controls and OFA are
used to limit NOx emissions to 0.13 lb/MMBtu, and an SNCR unit further reduces the NOx concentration by 46 percent to 0.07 lb/MMBtu.

For the PC cases, mercu ry emissions are constant for each coal type and significantly below the environmental targets. Emissions for PRB coal are less than NDL because of lower mercury in the coal and higher co

- benefit capture. All PC cases used carbon injection designed to re move 90 percent of the mercury in the flue gas. The emissions
shown in Exhibit 7

- 7 range from 0.6

- 1.2 lb/TBtu for the eight PC cases.

For the CFB cases, co

- benefit capture of mercury and carbon injection designed for 90
percent r emoval of mercury in the flue gas results in mercury emissions ranging from
0.3

- 0.48 lb/TBtu

.
CO 2 emissions

, normalized to both net and gross power output

, are shown in Exhibit 7

- 8

. The emissions follow a similar trend to the ove rall plant efficiency

. T he more efficient plants have lower emissions , and with identical CO 2 removal efficiencies, other than differences in normalized auxiliary power, the trends should mirror those seen in overall plant efficiency.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

318 Exhibit 7

- 6 Emissions ProfileCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

319 Exhibit 7

- 7 Mercury EmissionsCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

320 Exhibit 7

- 8 CO 2 Emission

– lb/MWhCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

321 7.3.2 Water Usage

Exhibit 7

- 9 shows water usage values from a process perspective. Water demand, internal recycle, and water withdrawal, all normalized by net output

, are shown. Water demand is the

gross water required by the process. Internal recycle is w ater obtained from the process that is recycled to partially supply the demand. Water withdrawal is the net water required to supply the demand for the process. Half of the withdrawal is obtained from a municipal water system
and half from wells. The fo llowing observations can be made:

For the non

- capture cases, the raw water withdrawal is similar for both fuels. There is minimal internal recycle so both the water demand and the water withdrawal are nearly equal in the PRB and NDL coal cases.

The use of the parallel wet/dry cooling system reduces water demand relative to an all wet cooling system. For the non

- capture PC cases, the reductions are approximately
6.8 m 3 /min (1,760 gpm) and 6.4 m 3 /min (1,700 gpm) for the SC and USC cases respectively

, result ing in a 46 percent reduction. For the non

- capture CFB cases, the reductions are approximately 6.6 m 3 /min (1,730 gpm) resulting in a 49 percent reduction.
For the PC CO 2 capture cases, the reductions are 4.8 m 3 /min (1,270 gpm) and 4.3 m 3 /min (1,130 gpm) resulting in only a 19 percent reduction. For the CFB CO 2 capture cases, the reductions are approximately 4.8 m 3 /min (1,250 gpm) resulting in a n 18 percent reduction. The water saving s are less in the CO 2 capture cases because a significant
amount of ext raction steam is used in the Econamine system and therefore not conde nsed
in the surface condenser.

The water demand is significantly greater for the CO 2 capture cases because of the significant cooling load required for the Econamine system. The Econamin e cooling load is provided by the wet cooling tower system and does not benefit from the dry cooling
system.

Exhibit 7

- 10 shows water usage values from an environmental perspective. Water withdrawal, discharge, and consumption ar e shown , all normalized by net output. Water discharge is water from the system that would be discharged to permitted outfalls or with the proper treatment could be used to reduce the water withdrawal. Water consumption is the net amount of water

extract ed from the environment.

For all cases, the discharge represents approximately 25 percent of the water withdrawal. This is because the cooling tower blowdown produces nearly all, if not all

, of the water discharge. The blowdown is calculated based on a c ooling tower cycles of concentration of 4. Since the cooling tower is the largest consumer of water

, the discharge as a percentage of water withdrawal is approximately equal to the inverse of cycles of
concentration.Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

322 Exhibit 7

- 9 Normalized Water Usage

– Process PerspectiveCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

323 Exhibit 7

- 10 Normalized Water Usage

– Environmental PerspectiveCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

324 This page intentionally left blankCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

325 8. REFERENCES

1 ―Foster Wheeler Announces Successful Start

- up of World’s Largest Circulating
Fluidized

- Bed Steam Generator at Lagisza Power Plant in Poland,‖ Foster Wheeler AG, News, July 7, 2009

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 Hotta, Arto, Kettunen, Ari and Utt, James, ―Milestones for CFB and OUT Technology: The 460 MWe Lagisza Supercritical Boiler Project Update,‖ CoalGen 2007, August 2007

4 C oal Specification s for Quality Guidelines, Revision 0, May 31, 2005

5 ― Annual Energy Outlook 200 8

, ‖ AEO Reference Case Table 1 12 , EIA, April 2008

6 Personal Communication between John Wimer (NETL) and Diane Kearney (EIA), AEO
2007 Reference Case National Energy Modeling Sy stem ( NEMS ) model forecasted
average cost s 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)

7 ― Protection of Environment. ‖ Code o f Federal Regulations Title 40

, PART 60

— S tandards 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; http://ecfr.gpoaccess.gov/cgi/t/text/text

idx?c=ecfr&sid=5239e4e3a1684997ba0d06797c26b6ae&rgn=div6&view=text&node=40
:6.0.1.1.1.10&idno=40

8 US EPA Green Book Nonattainment Area Map, http://www.epa.gov/oar/oaqps/greenbk/mapnpoll.html

9 Energ y Information Administration, The Demonstrated Reserve Base, U.S. Coal

Reserves: 1997, Update, February 1999, Figure 1, http://www.eia.doe.gov/cneaf/coal/reserves/ch apter1.html#chapter1a.html

10 Montana Annual Precipitation, U.S. Department of Agriculture, Natural Resources Conservation Service, http://www.ncgc.nrcs.usda.gov/products/datasets/images/climate/maps/mt.jpg

11 1999 Environmental Protection Agency Informatio n Collection Request Database with Coal Compositions for Over 37,000 Samples

12 Documentation for EPA Base Case 200 6 (V. 3

. 0 ) Using the Integrated Planning Model, EPA, November 2006

13 Mercury Emissions Control Technologies, www.netl.doe.gov/technologies/co alpower/ewr/mercury/control

- tech/PRBunit.htmlCost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

326 14 North American Electric Reliability Council website, http://www.nerc.com/~gads/

15 ― Cooling Tower Fundamentals

, ‖ ed

. John C. Hensley, 2 nd Edition, The Marley Cooling Tower Company, Mission, Kansas, 1985

16 Per sonal Correspondence with Frank Ortega, Product Manager

– Dry Cooling, Thermal Engineering / GEA Power Cooling, Inc., September 2008

17 ―EPA Technical Development Document for the Final Regulations Addressing Cooling
Water Intake Structures for New Facilit ies,‖ EPA

- 821

- R

- 01

- 036, November 2001

18 ―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

19 Herzog, Howard J., ―The Economics of CO 2 Separation and Capture,‖ MIT Energy Laboratory

20 ―Merit Shop Wage & Benefit Survey,‖ PAS, Inc., http://www.pas1.com/

21 ―Conducting Technical and Economic Evaluations

– 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

22 Economic Evaluation of CO 2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI , December 2002

23 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

24 Ciferno, Jared P. and McIlvried, How ard, ―CO 2 Flow Modeling and Pipe Diameter Determination,‖ February, 2003

25 Economic Evaluation of CO2 Storage and Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, December 2002

26 Parker, N., ―Using Natural Gas Transmission Pipeline Cos ts to Estimate Hydrogen Pipeline Costs,‖ Institute of Transportation Studies, University of California, Davis, CA,

2004.

27 Gresham, R. L., Apt, J., et. al, ― Implications of Compensating Property

- Owners fo r Geologic Sequestration of CO 2 ,‖ Department of Engi neering and Public Policy, Carnegie Mellon University, Pittsburgh, PA, 1999.

28 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

29 Sena te Bill No. 2095, 61st Legislative Assembly of North Dakota, January 6th, 2009

30 House Bill No. 661, Louisiana House of Representatives Regular Session, 2009Cost and Performance Baseline

- Low Rank, Volume 3b (Combustion Cases)

327 31 Enrolled Act No. 20 (Original House Bill No. 58), 60th Legislature of the State of Wyoming, Gene ral Session, 2009

32 Overview of Monitoring Requirements for Geologic Storage Projects. IEA Greenhouse
Gas R& D Programme, Report Number PH4/29, November 2004

33 ― Recommended Project Finance Structures for the Economic Analysis of Fossil

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