Cost and Performance Baseline for 

Fossil Energy Plants

Volume 1a: Bituminous Coal (PC) and 

Natural Gas to Electricity

Revision 3

July 6, 2015

DOE/NETL-2015/1723

OFFICE OF FOSSIL ENERGY

National Energy 

Technology Laboratory
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference therein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The views 

and opinions of authors expressed therein do not necessarily state or reflect those of the United 

States Government or any agency thereof.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

Author List:

National Energy Technology Laboratory (NETL)

Tim Fout

General Engineer

Office of Program Performance & Benefits

Energy Sector Planning and Analysis (ESPA)

Alexander Zoelle, Dale Keairns, Marc Turner, Mark Woods, Norma Kuehn, 

Vasant Shah, Vincent Chou

Booz Allen Hamilton

Lora Pinkerton

WorleyParsons Group, Inc.

This report was prepared by Energy Sector Planning and Analysis (ESPA) for the United States 

Department of Energy (DOE), National Energy Technology Laboratory (NETL). This work was 

completed under DOE NETL Contract Number DE-FE0004001. This work was performed 

under ESPA Task 341.03, Activity 17.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

Acknowledgments

The authors wish to acknowledge the excellent guidance, contributions, and cooperation of the 

NETL staff, particularly:

Tim Fout, NETL Technical Monitor

Kristin Gerdes

Director of OPPB

Travis Shultz

Director, Performance Division of OPPB

John Wimer

Office Director of OCPR&D

James Black

Daniel Cicero

formerly of NETL

Jared Ciferno

Eric Grol

Jeffrey Hoffmann

Julianne Klara

Patrick Le

Michael Matuszewski

formerly of NETL

Sean Plasynski

Larry Rath

formerly of NETL

Walter Shelton

Gary Stiegel

formerly of NETL

William Summers

Thomas J. Tarka, P.E.

Maria Vargas

John L. Haslbeck

formerly of Booz Allen Hamilton

Eric G. Lewis

formerly of Booz Allen Hamilton

Pamela Capicotto

formerly of Parsons Corporation

Michael Rutkowski

formerly of Parsons Corporation

Ronald Schoff

formerly of Parsons Corporation

Thomas Buchanan

formerly of WorleyParsons Group, Inc.

James Simpson

WorleyParsons Group, Inc.

Elsy Varghese

formerly of WorleyParsons Group, Inc.

Vladimir Vaysman

WorleyParsons Group, Inc.

Richard Weinstein

WorleyParsons Group, Inc.

DOE Contract Number DE-FE0004001
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Table of Contents

Executive Summary.......................................................................................................................12

Results Analysis.............................................................................................................................15

Sensitivities....................................................................................................................................18

1 Introduction.................................................................................................................................22

2 General Evaluation Basis............................................................................................................25

2.1 Site Characteristics...................................................................................................................25

2.2 Coal Characteristics.................................................................................................................26

2.3 Natural Gas Characteristics......................................................................................................28

2.4 Environmental Targets.............................................................................................................29

2.4.1 PC..........................................................................................................................................30

2.4.2 NGCC ...................................................................................................................................31

2.4.3 Carbon Dioxide.....................................................................................................................32

2.5 Capacity Factor........................................................................................................................32

2.5.1 Capacity Factor Assumptions...............................................................................................32

2.5.2 Existing Plant Data ...............................................................................................................32

2.5.3 Capacity Factor for Coal Units without Carbon Capture .....................................................33

2.5.4 Capacity Factor for Natural Gas Combined Cycle (NGCC) Plants......................................36

2.5.5 Capacity Factor for Plants with Carbon Capture ..................................................................36

2.5.6 Perspective ............................................................................................................................37

2.6 Raw Water Withdrawal and Consumption ..............................................................................37

2.7 Cost Estimating Methodology .................................................................................................38

2.7.1 Capital Costs.........................................................................................................................39

2.7.2 Operation and Maintenance Costs........................................................................................42

2.7.3 CO2 Transport and Storage ...................................................................................................44

2.7.4 Cost of CO2 Captured and Avoided......................................................................................46

3 Pulverized Coal Rankine Cycle Plants .......................................................................................47

3.1 PC Common Process Areas.....................................................................................................47

3.1.1 Coal, Activated Carbon, and Sorbent Receiving and Storage ..............................................48

3.1.2 Steam Generator and Ancillaries..........................................................................................48

3.1.3 NOx Control System.............................................................................................................51

3.1.4 Activated Carbon Injection...................................................................................................52

3.1.5 Particulate Control ................................................................................................................52

3.1.6 Mercury Removal .................................................................................................................52

3.1.7 Flue Gas Desulfurization ......................................................................................................56

3.1.8 Carbon Dioxide Recovery Facility .......................................................................................59

3.1.9 Gas Compression and Drying System ..................................................................................61

3.1.10 Power Generation................................................................................................................62

3.1.11 Balance of Plant ..................................................................................................................63

3.1.12 Accessory Electric Plant .....................................................................................................67

3.1.13 Instrumentation and Control ...............................................................................................67

3.1.14 Performance Summary Metrics ..........................................................................................67

3.2 Subcritical PC Cases................................................................................................................68

3.2.1 Process Description...............................................................................................................68

3.2.2 Key System Assumptions.....................................................................................................73

3.2.3 Sparing Philosophy ...............................................................................................................74
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3.2.4 Case B11A Performance Results..........................................................................................75

3.2.5 Case B11A – Major Equipment List.....................................................................................81

3.2.6 Case B11A – Cost Estimating...............................................................................................86

3.2.7 Case B11B – PC Subcritical Unit with CO2 Capture ...........................................................92

3.2.8 Case B11B Performance Results..........................................................................................92

3.2.9 Case B11B – Major Equipment List...................................................................................103

3.2.10 Case B11B – Cost Estimating...........................................................................................108

3.3 Supercritical PC cases............................................................................................................115

3.3.1 Process Description.............................................................................................................115

3.3.2 Key System Assumptions...................................................................................................119

3.3.3 Sparing Philosophy .............................................................................................................120

3.3.4 Case B12A Performance Results........................................................................................120

3.3.5 Case B12A – Major Equipment List...................................................................................126

3.3.6 Case B12A – Costs Estimating Results..............................................................................131

3.3.7 Case B12B – Supercritical PC with CO2 Capture ..............................................................137

3.3.8 Case B12B Performance Results........................................................................................137

3.3.9 Case B12B – Major Equipment List...................................................................................148

3.3.10 Case B12B – Cost Estimating Basis.................................................................................154

3.4 PC Case Summary .................................................................................................................160

4 Natural Gas Combined Cycle Plants.........................................................................................167

4.1 NGCC Process Areas.............................................................................................................167

4.1.1 Natural Gas Supply System ................................................................................................167

4.1.2 Combustion Turbine ...........................................................................................................167

4.1.3 Heat Recovery Steam Generator.........................................................................................169

4.1.4 NOx Control System...........................................................................................................169

4.1.5 Carbon Dioxide Recovery Facility .....................................................................................170

4.1.6 Steam Turbine.....................................................................................................................170

4.1.7 Water and Steam Systems...................................................................................................171

4.1.8 Accessory Electric Plant .....................................................................................................172

4.1.9 Waste Treatment/Miscellaneous Systems...........................................................................172

4.1.10 Instrumentation and Control .............................................................................................172

4.1.11 Performance Summary Metrics ........................................................................................173

4.2 NGCC Cases..........................................................................................................................174

4.2.1 Process Description.............................................................................................................174

4.2.2 Key System Assumptions...................................................................................................176

4.2.3 Sparing Philosophy .............................................................................................................178

4.2.4 Case B31A Performance Results........................................................................................178

4.2.5 Case B31A – Major Equipment List...................................................................................185

4.2.6 Case B31A – Cost Estimating.............................................................................................188

4.2.7 Case B31B – NGCC with CO2 Capture..............................................................................192

4.2.8 Case B31B Performance Results........................................................................................193

4.2.9 Case B31B Major Equipment List......................................................................................201

4.2.10 Case B31B – Cost Estimating...........................................................................................204

4.3 NGCC Case Summary ...........................................................................................................209

5 Results Analysis........................................................................................................................215

5.1 Performance ...........................................................................................................................215
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5.1.1 Energy Efficiency ...............................................................................................................215

5.1.2 Environmental Emissions...................................................................................................216

5.1.3 Water Use............................................................................................................................216

5.2 Cost Results ...........................................................................................................................218

5.2.1 TOC and TASC...................................................................................................................218

5.2.2 COE.....................................................................................................................................219

5.2.3 CO2 Emission Price Impact ................................................................................................220

5.2.4 CO2 Sales Price Impact.......................................................................................................222

5.3 Sensitivities............................................................................................................................224

6 Revision Control.......................................................................................................................227

7 References.................................................................................................................................232
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibits

Exhibit ES-1 Case configuration summary.................................................................................. 12

Exhibit ES-2 Performance summary and environmental profiles ............................................... 15

Exhibit ES-3 Net plant efficiency (HHV basis)........................................................................... 16

Exhibit ES-4 Cost summary......................................................................................................... 17

Exhibit ES-5 COE by cost component*....................................................................................... 18

Exhibit ES-6 COE sensitivity to fuel costs.................................................................................. 19

Exhibit ES-7 Lowest cost technology options at various natural gas and CO2 sales prices........ 20

Exhibit 1-1 Case descriptions...................................................................................................... 24

Exhibit 2-1 Site characteristics .................................................................................................... 25

Exhibit 2-2 Site ambient conditions............................................................................................. 25

Exhibit 2-3 Design coal ............................................................................................................... 27

Exhibit 2-4 Probability distribution of mercury concentration in the Illinois No. 6 coal............ 28

Exhibit 2-5 Natural gas composition ........................................................................................... 28

Exhibit 2-6 MATS and NSPS emission limits for PM, HCl, SO2, NOx, and Hg........................ 29

Exhibit 2-7 Environmental targets for PC cases.......................................................................... 30

Exhibit 2-8 Environmental targets for NGCC cases.................................................................... 31

Exhibit 2-9 Coal plant availability and capacity factor data for units reporting in 2011............. 33

Exhibit 2-10 Coal plant availability and CF average data over the period 2007-2011................ 34

Exhibit 2-11 Number of coal units included in the 2011 data ..................................................... 34

Exhibit 2-12 Number of coal units reporting capacity factors greater than 80% ........................ 35

Exhibit 2-13 U. S. coal electricity power generation................................................................... 36

Exhibit 2-14 Capital cost levels and their elements..................................................................... 40

Exhibit 2-15 CO2 transport and storage costs.............................................................................. 46

Exhibit 3-1 Typical injection process flow diagram.................................................................... 55

Exhibit 3-2 Mercury removal across a fabric filter during a high-sulfur bituminous test ........... 56

Exhibit 3-3 Cansolv CO2 capture process typical flow diagram ................................................. 60

Exhibit 3-4 CO2 compressor interstage pressures........................................................................ 61

Exhibit 3-5 Case B11A block flow diagram, subcritical unit without CO2 capture .................... 70

Exhibit 3-6 Case B11A stream table, subcritical unit without capture........................................ 71

Exhibit 3-7 Subcritical PC plant study configuration matrix....................................................... 73

Exhibit 3-8 Balance of plant assumptions ................................................................................... 74

Exhibit 3-9 Case B11A plant performance summary.................................................................. 75

Exhibit 3-10 Case B11A plant power summary .......................................................................... 76

Exhibit 3-11 Case B11A air emissions........................................................................................ 76

Exhibit 3-12 Case B11A carbon balance ..................................................................................... 77

Exhibit 3-13 Case B11A sulfur balance....................................................................................... 77

Exhibit 3-14 Case B11A water balance ....................................................................................... 78

Exhibit 3-15 Case B11A heat and mass balance, subcritical PC boiler without CO2 capture..... 79

Exhibit 3-16 Case B11A heat and mass balance, subcritical steam cycle ................................... 80

Exhibit 3-17 Case B11A overall energy balance (0°C [32°F] reference).................................... 81

Exhibit 3-18 Case B11A total plant cost details.......................................................................... 87

Exhibit 3-19 Case B11A owner’s costs....................................................................................... 90

Exhibit 3-20 Case B11A initial and annual operating and maintenance costs............................ 91

Exhibit 3-21 Case B11A COE breakdown .................................................................................. 91

Exhibit 3-22 Case B11B block flow diagram, subcritical unit with CO2 capture ....................... 93
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Exhibit 3-23 Case B11B stream table, subcritical unit with capture ........................................... 94

Exhibit 3-24 Case B11B plant performance summary ................................................................ 97

Exhibit 3-25 Case B11B plant power summary .......................................................................... 98

Exhibit 3-26 Case B11B air emissions........................................................................................ 98

Exhibit 3-27 Case B11B carbon balance ..................................................................................... 99

Exhibit 3-28 Case B11B sulfur balance....................................................................................... 99

Exhibit 3-29 Case B11B water balance ..................................................................................... 100

Exhibit 3-30 Case B11B heat and mass balance, subcritical PC boiler with CO2 capture ........ 101

Exhibit 3-31 Case B11B heat and mass balance, subcritical steam cycle ................................. 102

Exhibit 3-32 Case B11B overall energy balance (0°C [32°F] reference).................................. 103

Exhibit 3-33 Case B11B total plant cost details........................................................................ 110

Exhibit 3-34 Case B11B owner’s costs ..................................................................................... 113

Exhibit 3-35 Case B11B initial and annual operating and maintenance costs .......................... 114

Exhibit 3-36 Case B11B COE breakdown................................................................................. 114

Exhibit 3-37 Case B12A block flow diagram, supercritical unit without CO2 capture............. 116

Exhibit 3-38 Case B12A stream table, supercritical unit without capture................................. 117

Exhibit 3-39 Supercritical PC plant study configuration matrix ............................................... 119

Exhibit 3-40 Case B12A plant performance summary.............................................................. 120

Exhibit 3-41 Case B12A plant power summary ........................................................................ 121

Exhibit 3-42 Case B12A air emissions...................................................................................... 121

Exhibit 3-43 Case B12A carbon balance ................................................................................... 122

Exhibit 3-44 Case B12A sulfur balance..................................................................................... 122

Exhibit 3-45 Case B12A water balance ..................................................................................... 123

Exhibit 3-46 Case B12A heat and mass balance, supercritical PC boiler without CO2 capture 124

Exhibit 3-47 Case B12A heat and mass balance, supercritical steam cycle.............................. 125

Exhibit 3-48 Case B12A overall energy balance (0°C [32°F] reference).................................. 126

Exhibit 3-49 Case B12A total plant cost details........................................................................ 132

Exhibit 3-50 Case B12A owner’s costs..................................................................................... 135

Exhibit 3-51 Case B12A initial and annual operating and maintenance costs.......................... 136

Exhibit 3-52 Case B12A COE breakdown ................................................................................ 136

Exhibit 3-53 Case B12B block flow diagram, supercritical unit with CO2 capture .................. 138

Exhibit 3-54 Case B12B stream table, supercritical unit with capture ...................................... 139

Exhibit 3-55 Case B12B plant performance summary .............................................................. 142

Exhibit 3-56 Case B12B plant power summary ........................................................................ 143

Exhibit 3-57 Case B12B air emissions...................................................................................... 143

Exhibit 3-58 Case B12B carbon balance ................................................................................... 144

Exhibit 3-59 Case B12B sulfur balance..................................................................................... 144

Exhibit 3-60 Case B12B water balance ..................................................................................... 145

Exhibit 3-61 Case B12B heat and mass balance, supercritical PC boiler with CO2 capture..... 146

Exhibit 3-62 Case B12B heat and mass balance, supercritical steam cycle .............................. 147

Exhibit 3-63 Case B12B overall energy balance (0°C [32°F] reference).................................. 148

Exhibit 3-64 Case B12B total plant cost details........................................................................ 155

Exhibit 3-65 Case B12B owner’s costs ..................................................................................... 158

Exhibit 3-66 Case B12B initial and annual operating and maintenance costs .......................... 159

Exhibit 3-67 Case B12B COE breakdown................................................................................. 159

Exhibit 3-68 Estimated performance and cost results for PC cases........................................... 160
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Exhibit 3-69 Plant capital cost for PC cases.............................................................................. 162

Exhibit 3-70 COE for PC cases ................................................................................................. 163

Exhibit 3-71 Sensitivity of COE to capacity factor for PC cases.............................................. 164

Exhibit 3-72 Sensitivity of COE to coal price for PC cases...................................................... 164

Exhibit 3-73 Cost of CO2 captured and avoided in PC cases.................................................... 165

Exhibit 3-74 Raw water withdrawal and consumption in PC cases .......................................... 166

Exhibit 4-1 Combustion turbine typical scope of supply........................................................... 168

Exhibit 4-2 Case B31A block flow diagram, NGCC without CO2 capture............................... 175

Exhibit 4-3 Case B31A stream table, NGCC without capture................................................... 176

Exhibit 4-4 NGCC plant study configuration matrix................................................................. 177

Exhibit 4-5 NGCC balance of plant assumptions...................................................................... 178

Exhibit 4-6 Case B31A plant performance summary................................................................ 179

Exhibit 4-7 Case B31A plant power summary .......................................................................... 179

Exhibit 4-8 Case B31A air emissions........................................................................................ 180

Exhibit 4-9 Case B31A carbon balance ..................................................................................... 180

Exhibit 4-10 Case B31A sulfur balance..................................................................................... 180

Exhibit 4-11 Case B31A water balance ..................................................................................... 181

Exhibit 4-12 Case B31A heat and mass balance, NGCC without CO2 capture ........................ 183

Exhibit 4-13 Case B31A overall energy balance (0°C [32°F] reference).................................. 185

Exhibit 4-14 Case B31A total plant cost details........................................................................ 189

Exhibit 4-15 Case B31A owner’s costs..................................................................................... 191

Exhibit 4-16 Case B31A initial and annual operating and maintenance costs.......................... 192

Exhibit 4-17 Case B31A COE breakdown ................................................................................ 192

Exhibit 4-18 Case B31B block flow diagram, NGCC with CO2 capture .................................. 193

Exhibit 4-19 Case B31B stream table, NGCC with capture...................................................... 194

Exhibit 4-20 Case B31B plant performance summary .............................................................. 196

Exhibit 4-21 Case B31B plant power summary ........................................................................ 196

Exhibit 4-22 Case B31B air emissions...................................................................................... 197

Exhibit 4-23 Case B31B carbon balance ................................................................................... 197

Exhibit 4-24 Case B31B sulfur balance..................................................................................... 198

Exhibit 4-25 Case B31B water balance ..................................................................................... 198

Exhibit 4-26 Case B31B heat and mass balance, NGCC with CO2 capture.............................. 199

Exhibit 4-27 Case B31B overall energy balance (0°C [32°F] reference).................................. 201

Exhibit 4-28 Case B31B total plant cost details........................................................................ 205

Exhibit 4-29 Case B31B owner’s costs ..................................................................................... 207

Exhibit 4-30 Case B31B initial and annual operating and maintenance costs .......................... 208

Exhibit 4-31 Case B31B COE breakdown................................................................................. 208

Exhibit 4-32 Estimated performance and cost results for NGCC cases .................................... 209

Exhibit 4-33 Plant capital cost for NGCC cases........................................................................ 210

Exhibit 4-34 COE of NGCC cases............................................................................................. 211

Exhibit 4-35 Sensitivity of COE to capacity factor in NGCC cases.......................................... 212

Exhibit 4-36 Sensitivity of COE to fuel price in NGCC cases.................................................. 212

Exhibit 4-37 First year cost of CO2 captured and avoided in NGCC cases............................... 213

Exhibit 4-38 Raw water withdrawal and consumption in NGCC cases.................................... 214

Exhibit 5-1 Performance summary and environmental profile for all cases .............................. 215

Exhibit 5-2 Net plant efficiency (HHV basis) ........................................................................... 216
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 5-3 Raw water withdrawal and consumption................................................................ 217

Exhibit 5-4 Cost summary for all cases...................................................................................... 218

Exhibit 5-5 Plant capital costs.................................................................................................... 219

Exhibit 5-6 COE by cost component ......................................................................................... 220

Exhibit 5-7 Impact of carbon emissions price on study technologies ....................................... 221

Exhibit 5-8 Lowest cost power generation options comparing NGCC and PC......................... 222

Exhibit 5-9 Impact of carbon sales price on study technologies ............................................... 223

Exhibit 5-10 Lowest cost power generation options comparing NGCC and coal..................... 224

Exhibit 5-11 COE sensitivity to fuel costs................................................................................. 225

Exhibit 5-12 COE sensitivity to capacity factor ........................................................................ 226

Exhibit 6-1 Record of revisions................................................................................................. 227
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Acronyms and Abbreviations

acfm Actual cubic feet per minute

ACI Activated carbon injection

AGR Acid gas removal

ANSI American National Standards

Institute

AR As received

Aspen Aspen Plus®

atm Atmosphere (14.696 psi) 

BACT Best available control technology

BAH Booz Allen Hamilton

BEC Bare erected cost

BFD Block flow diagram

BFW Boiler feedwater

Btu British thermal unit

Btu/hr British thermal units per hour

Btu/kWh British thermal units per kilowatt 

hour

Btu/lb British thermal units per pound

Btu/scf British thermal units per standard 

cubic foot

CCF Capital charge factor

CCS Carbon capture and storage

CDR Carbon dioxide recovery

cf Cubic feet

CF Capacity factor

cfm Cubic feet per minute

CFR Code of Federal Regulations

CGE Cold gas efficiency

CH4 Methane

CL Closed-loop

cm Centimeter

CO Carbon monoxide

CO2 Carbon dioxide

COE Cost of electricity

COS Carbonyl sulfide

CS Carbon steel

CT Combustion turbine

CTG Combustion turbine-generator

CWP Circulating water pump

CWS Circulating water system

CWT Cold water temperature

DCS Distributed control system

DI De-ionized

DLN Dry low NOx 

DOE Department of Energy

DSI Dry sorbent injection

EAF Equivalent availability factor

EIA Energy Information Administration

EMF Emission modification factors

EPA Environmental Protection Agency

EPC Engineer/Procure/Construct

EPRI Electric Power Research Institute

EOR Enhanced oil recovery 

ESPA Energy Sector Planning and Analysis

FD Forced draft

FE Fossil energy

FG Flue gas 

FGD Flue gas desulfurization

FOAK First-of-a-kind

FRP Fiberglass-reinforced plastic

ft Foot, Feet

ft, w.g. Feet of water gauge

FW Feedwater

GADS Generating Availability Data System

gal Gallon

gal/MWh Gallons per megawatt hour

GDP Gross domestic product

GEE General Electric Energy

GJ Gigajoule

GJ/hr Gigajoules per hour

gpd Gallons per day

gpm Gallons per minute

gr/100 scf grains per one hundred standard cubic 

feet

GRI Gas Research Institute

GWh Gigawatt-hour

h, hr Hour

H2 Hydrogen

H2O Water

H2S Hydrogen sulfide

H2SO4 Sulfuric acid

HCl Hydrochloric acid

Hg Mercury

HHV Higher heating value

hp Horsepower

HP High pressure

HRSG Heat recovery steam generator

HSS Heat stable salts

HV High voltage
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HVAC Heating, ventilating, and air 

conditioning

HWT Hot water temperature

Hz Hertz

ICR Information Collection Request

ID Induced draft

IEA International Energy Agency

IEEE Institute of Electrical and Electronics 

Engineers

IGCC Integrated gasification combined 

cycle

IGV Inlet guide vane

in. H2O Inch water

in. Hga Inch mercury (absolute pressure)

in. W.C. Inch water column

IOU Investor-owned utility

IP Intermediate pressure

IPM Integrated Planning Model

ISO International Organization for 

Standardization

kg/GJ Kilograms per gigajoule

kg/hr Kilograms per hour

kgmol Kilogram mole

kgmol/hr Kilogram moles per hour

kJ Kilojoule

kJ/hr Kilojoules per hour

kJ/kg Kilojoules per kilogram

km Kilometer 

KO Knockout

kPa Kilopascal 

kV Kilovolt

kW, kWe Kilowatt electric

kWh Kilowatt-hour

kWt Kilowatt thermal

LAER Lowest Achievable Emission Rate

lb Pound

lb/gal Pound per gallon 

lb/hr Pounds per hour

lb/ft2 Pounds per square foot

lb/MMBtu Pounds per million British thermal 

units

lbmol Pound mole

lbmol/hr Pound moles per hour

lb/MWh Pounds per megawatt hour

lb/TBtu Pounds per trillion British thermal 

units

LHV Lower heating value

LNB Low NOx burner

LP Low pressure

lpm Liters per minute

LV Low voltage

m Meter

m/min Meters per minute

m3

/min Cubic meters per minute

md Millidarcy (a measure of 

permeability)

MeOH Methanol

mi Mile

mpg Miles per gallon

M Thousand

Mbbl Thousand barrels

Mcf Thousand cubic feet

MAC Main air compressor

MAF Moisture and ash free

MATS Mercury and Air Toxics Standards

MCR Maximum continuous rate

MDEA Methyldiethanolamine

MEA Monoethanolamine

MHz Megahertz

MJ/Nm3 Megajoules per normal cubic meter

MM Million

MMBtu Million British thermal units 

MMBtu/hr Million British thermal units per hour

MMscf Million standard cubic feet

MMscfd Million standard cubic feet per day

MMscfy Million standard cubic feet per year

mole% Mole percent (percent by mole) 

MNQC Multi Nozzle Quiet Combustor

MPa Megapascal

MTG Methanol to gasoline

MVA Mega volt-amps

MW Megawatt

MWe Megawatt electric

MWh Megawatt-hour

MWt Megawatt thermal

N2 Nitrogen

N2O Nitrous oxide

N/A Not applicable

NAAQS National Ambient Air Quality 

Standards

NaOH Sodium hydroxide 

Neg. Negligible

NEMA National Electrical Manufacturers 

Association

NEMS National Energy Modeling System

NERC North American Electric Reliability 

Council
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NETL National Energy Technology 

Laboratory

NG Natural gas

NGCC Natural gas combined cycle

NH3 Ammonia

Nm3 Normal cubic meter

Nm3

/hr Normal cubic meter per hour 

NOAK Nth-of-a-kind

NOx Oxides of nitrogen

NSPS New Source Performance Standards

NSR New Source Review

O2 Oxygen

O&M Operation and maintenance

OD Outside diameter

OEM Original equipment manufacturers

OFA Overfire air

OPPA Office of Program Planning & 

Analysis

OP/VWO Over pressure/valve wide open

OSHA Occupational Safety and Health 

Administration 

PA Primary air

PC Pulverized coal

p.f. Power factor

PFD Process flow diagram

PM Particulate matter 

PM10 Particulate matter measuring 10 μm 

(micrometers) or less

PO Purchase order

POTW Publicly owned treatment works

ppm Parts per million 

ppmv Parts per million volume

ppmvd Parts per million volume, dry 

ppmw Parts per million weight

ppmwd Parts per million weight, dry

PAC Powdered activated carbon

PSD Prevention of significant deterioration

psi Pounds per square inch

psia Pound per square inch absolute

psid Pound per square inch differential

psig Pound per square inch gage

PSFM Power systems financial model

PTFE Teflon (Polytetrafluoroethylene)

PV Present value

QGESS Quality Guidelines for Energy 

System Studies

Qty Quantity

R&D Research and development

RD&D Research, Development, and 

Demonstration 

RH Reheater

RSP Required selling price

RTO Regional transmission 

operations/operator

SC Supercritical

SC PC Supercritical Pulverized Coal 

scf Standard cubic feet

scfd Standard cubic feet per day

scfh Standard cubic feet per hour

scfm Standard cubic feet per minute

Sch. Schedule

scmh Standard cubic meter per hour

SCR Selective catalytic reduction process 

or equipment

SG Specific gravity

SO2 Sulfur dioxide

SOx Oxides of sulfur

SNCR Selective non-catalytic reduction 

process or equipment

SS Stainless steel

SS Amine SS Specialty Amine 

st Short ton

STG Steam turbine generator

SubC PC Subcritical pulverized coal

SWS Sour water scrubber

Syngas Synthetic gas

T&D Transmission and distribution

TASC Total as-spent cost

TCR Total capital requirement

TEWAC Totally Enclosed Water-to-Air 

Cooled

tonne Metric ton (1,000 kg)

TOC Total overnight cost

TPC Total plant cost

tpd Ton per day

tph Tons per hour

TPI Total plant investment

T&S Transport and storage

U.S. United States

USC Ultra-supercritical

V Volt

VOC Volatile organic compound 

VO&M Variable operations and maintenance

V-L Vapor liquid portion of stream 

(excluding solids)

vol% Volume percent

WB Wet bulb
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

xi

wg Water gauge

WGCU Warm gas cleanup

WGS Water gas shift

wt% Weight percent

yr Year

ZnO Zinc oxide

ZnS Zinc sulfide

$/GJ Dollars per gigajoule

$/kW Dollars per kilowatt

$/MMBtu Dollars per million British thermal 

units

$M Millions of dollars

μS/cm micro Siemens per cm

°C Degrees Celsius

°F Degrees Fahrenheit

5-10s Fifty hour work weeks
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Executive Summary

This report presents the cost and performance results of pulverized coal (PC) and natural gas 

combined cycle (NGCC) plants, using a consistent technical and economic approach that reflects 

current market conditions. The primary value of this report lies not in the absolute accuracy of 

the capital cost estimates for the individual cases (estimated to be -15%/+30%), but in 

application of a consistent approach to allow meaningful comparisons of relative costs among 

the cases evaluated. 

This report is part of an update to Volume 1 of a four volume series, which consists of:

• 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

The cost and performance data have been updated for all PC and NGCC cases in this report, 

which constitutes Volume 1a. IGCC cases, previously integrated with the PC and NGCC cases 

in Revision 2a, will be incorporated separately into a Volume 1b. Section 6 has a revision 

control table listing the updates applied to this report. 

Six power plant configurations were analyzed in this report, including four PC cases – two 

subcritical and two supercritical (SC) (with and without CO2 capture); and two state-of-the-art 

2013 F-Class combustion turbine-based NGCC plants (with and without CO2 capture). While 

labeled as SC conditions, the SC steam cycle conditions utilized in this report are also generally 

representative of commercial plants characterized as ultra-supercritical (USC), particularly with 

respect to temperature (1100°F). Because efficiency is more sensitive to steam cycle temperature 

than pressure, the resulting performance is at or near that of top-performing commercially 

available USC PC plants. The Shell Cansolv CO2 capture system utilized in this report is an 

amine-based solvent system. A summary of the case configurations in the report is shown in 

Exhibit ES-1.

Exhibit ES-1 Case configuration summary

Case Unit 

Cycle

Steam Cycle, 

psig/°F/°F Combustion Turbine Boiler 

Technology

CO2

Separation

B11A PC 2400/1050/1050 N/A Subcritical 

PC N/A

B11B PC 2400/1050/1050 N/A Subcritical 

PC Cansolv

B12A PC 3500/1100/1100 N/A SC PC N/A

B12B PC 3500/1100/1100 N/A SC PC Cansolv

B31A NGCC 2400/1050/1050 2 x State-of-the-art 2013 F-Class HRSG N/A

B31B NGCC 2400/1050/1050 2 x State-of-the-art 2013 F-Class HRSG Cansolv

All plant configurations were evaluated based on installation at a greenfield site. Capacity 

factors (CF) are assumed to approximately equal availability at 85% for all configurations. 

Achieving such capacity factors would require that these plants be near the top of the dispatch 

list. 

The nominal net plant output for this study targets 550 megawatts (MW). The actual net output 

varies between technologies because the combustion turbines (CT) in the NGCC cases are 
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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manufactured in discrete sizes, but the boilers and steam turbines in the PC cases are readily 

available in a wide range of capacities. The result is that all of the PC cases have a net output of 

550 MW, but the NGCC cases have net outputs of 559 MW (with capture) and 630 MW (without 

capture). 

Environmental emission requirements are based on the mercury (Hg) and hydrochloric acid 

(HCl) limits, set by the March 2013 update to the Utility Mercury and Air Toxics Standards 

(MATS), and particulate matter (PM), sulfur dioxide (SO2), and nitrogen oxide (NOx) limits, set 

by the February 2013 update to the New Source Performance Standards (NSPS).

Mercury, SO2, NOx, and PM are actively controlled in all PC cases with dry sorbent injection 

(DSI) and activated carbon injection (ACI); wet flue gas desulfurization (FGD); low NOx 

burners (LNB) with overfire air (OFA) and selective catalytic reduction (SCR); and a baghouse, 

respectively. NOx is controlled in both NGCC cases with LNBs and an SCR.

All of the power plant configurations with carbon capture in this report are designed to achieve 

90 percent capture, resulting in atmospheric CO2 emissions at levels far below proposed EPA 

regulation.1

The methodology for developing the results presented in this report included performing steadystate simulations of the six power plant configurations using the Aspen Plus® (Aspen) process 

modeling software. The major plant equipment 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.

This revision reflects varying degrees of technology vendor input for updates to the pollution 

control equipment for PC plants, and the CO2 capture, CO2 compression, and steam turbine 

technology for PC and NGCC plants; however, the final assessment of performance and cost was 

determined independently and is not endorsed by the individual vendors.

The mass and energy balance data from the Aspen models were used to size major pieces of 

equipment. These equipment sizes formed the basis for the cost estimations. Capital and 

operating costs for the major equipment and plant sub-systems were estimated by WorleyParsons 

based on simulation results and through scaled estimates from previous design/build projects. 

Assumed fuel prices are $2.78/GJ ($2.94/MMBtu) for Illinois No. 6 coal and $5.81/GJ 

($6.13/MMBtu) for natural gas, both on a higher heating value (HHV) basis, delivered to the 

Midwest, and in 2011 United States (U.S.) dollars.2

The cost metric used in this study is the cost of electricity (COE), which is the revenue that must 

be received by the generator per net megawatt-hour produced to meet the desired internal rate of 

return on equity. The COE is assumed to escalate at a nominal annual rate equal to the general 

inflation rate, i.e., it remains constant or levelized in real terms over the operational period of the 

power plant. The cost of CO2 transport and storage (T&S) of $11 per tonne of CO2 is added to 

 

1 The Environmental Protection Agency (EPA) proposed a new source performance standard on April 13, 2012, for emissions of carbon dioxide 

for new fossil fuel-fired electric utility generating units. As of the publication of this report, the proposed regulation has been published in the 

Federal Register. (46) The limit set by the proposed regulation is 1,100 lb-CO2/MWh-gross. 

2 As specified in the Quality Guidelines for Energy System Studies (QGESS) document on “Fuel Prices for Selected Feedstocks in NETL Studies.”

(45)
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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the COE and represents a 62 km (100 mile) CO2 pipeline and storage in a deep saline formation 

in the Midwest.3 

The cost and performance of the various fossil fuel-based technologies will be important in 

determining which combination of technologies will be utilized to meet the demands of the 

power market in the future. 

Selection of new generation technologies will depend on many factors, including:

• Capital and operating costs

• Overall energy efficiency

• Fuel prices

• COE

• Availability, reliability, and environmental performance

• Current and future regulations governing air, water, and solid waste discharges from 

fossil-fueled power plants

• Market penetration of clean coal technologies that have matured and improved as a result 

of recent commercial-scale demonstrations under the Department of Energy’s (DOE)

Clean Coal and Carbon Management Program

 

3 Estimated using the FE/NETL CO2 Transport Cost Model and the FE/NETL CO2 Saline Storage Cost Model. Additional detail on development 

of these costs is available in the May 2014 revision of the QGESS document “Carbon Dioxide Transport and Storage Costs in NETL Studies.” (27)
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Results Analysis

Exhibit ES-2 shows the performance and environmental profile summary for all cases. A graph 

of the net plant efficiency (HHV basis) is provided in Exhibit ES-3.

Exhibit ES-2 Performance summary and environmental profiles

Pulverized Coal Boiler NGCC

PC Subcritical PC Supercritical State-of-the-art 2013 

F-Class

Case Name (Old Case Name)

A B11A (9) B11B (10) B12A (11) B12B (12) B31A (13) B31B (14)

PERFORMANCE

Gross Power Output (MWe) 581 644 580 642 641 601

Auxiliary Power Requirement (MWe) 31 94 30 91 11 42

Net Power Output (MWe) 550 550 550 550 630 559

Coal Flow rate (lb/hr) 412,005 516,170 395,053 495,578 N/A N/A

Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A 185,484 185,484

HHV Thermal Input (kWt) 1,408,630 1,764,768 1,350,672 1,694,366 1,223,032 1,223,032

Net Plant HHV Efficiency (%) 39.0% 31.2% 40.7% 32.5% 51.5% 45.7%

Net Plant HHV Heat Rate (Btu/kWh) 8,740 10,953 8,379 10,508 6,629 7,466

Raw Water Withdrawal, gpm 5,538 8,441 5,105 7,882 2,646 4,023

Process Water Discharge, gpm 1,137 1,920 1,059 1,813 595 999

Raw Water Consumption, gpm 4,401 6,521 4,045 6,069 2,051 3,024

CO2 Capture Rate (%) 0% 90% 0% 90% 0% 90%

CO2 Emissions (lb/MMBtu) 204 20 204 20 119 12

CO2 Emissions (lb/MWh-gross) 1,683 190 1,618 183 773 82

CO2 Emissions (lb/MWh-net) 1,779 223 1,705 214 786 89

SO2 Emissions (lb/MMBtu) 0.085 0.000 0.085 0.000 0.001 0.000

SO2 Emissions (lb/MWh-gross) 0.700 0.000 0.673 0.000 0.006 0.000

NOx Emissions (lb/MMBtu) 0.085 0.075 0.088 0.078 0.003 0.003

NOx Emissions (lb/MWh-gross) 0.700 0.700 0.700 0.700 0.020 0.022

PM Emissions (lb/MMBtu) 0.011 0.010 0.011 0.010 0.000 0.000

PM Emissions (lb/MWh-gross) 0.090 0.090 0.090 0.090 0.000 0.000

Hg Emissions (lb/TBtu) 0.363 0.321 0.377 0.333 0.000 0.000

Hg Emissions (lb/MWh-gross) 3.00E-06 3.00E-06 3.00E-06 3.00E-06 0.00E+00 0.00E+00

A Previous versions of this report used a different naming convention. The old case numbers are provided 

here, paired with the new case numbers for reference.

The primary conclusions that can be drawn are:

• The NGCC cases have the highest net efficiency of all the technologies, both without 

CO2 capture (51.5 percent) and with CO2 capture (45.7 percent). The next highest 

efficiency is the non-capture SC PC case, with an efficiency of 40.7 percent.

• For the PC cases, adding CO2 capture results in a relative efficiency penalty of 20 percent 

(8 percentage points).

• For the NGCC case, adding CO2 capture results in a relative efficiency penalty of 11

percent (6 percentage points). The NGCC penalty is less than the PC penalty because:

o Natural gas is less carbon intensive than coal (based on the fuel compositions 

used in this study, natural gas contains 32 lb carbon/MMBtu of heat input and 

coal contains 56 lb/MMBtu).

o The NGCC non-capture plant is more efficient, thus there is less total CO2 to 

capture and compress (NGCC non-capture CO2 emissions are approximately 54-
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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56 percent lower than the PC cases) when normalized to equivalent net power 

outputs.

o These effects are offset slightly by the lower concentration of CO2 in the NGCC 

flue gas (4% vs. 13% for PC). When normalized to CO2 captured, the energy 

penalty is 0.16 kWh and 0.13 kWh per lb of CO2 captured for NGCC and PC, 

respectively.

• Estimated emissions of Hg, PM, NOx, and SO2 are all at or below the applicable 

regulatory limits currently in effect.

Exhibit ES-3 Net plant efficiency (HHV basis)

Source: NETL

The cost results for all cases are provided in Exhibit ES-4. A graph of the COE is provided in 

Exhibit ES-5.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit ES-4 Cost summary

Pulverized Coal Boiler* NGCC*

PC Subcritical PC Supercritical State-of-the-art 2013 

F-Class

Case Name B11A B11B B12A B12B B31A B31B

COST

Total Plant Cost (2011$/kW) 1,960 3,467 2,026 3,524 685 1,481

Bare Erected Cost 1,582 2,665 1,646 2,716 561 1,117

Home Office Expenses 158 257 165 263 51 97

Project Contingency 220 427 216 430 73 193

Process Contingency 0 118 0 115 0 75

Total Overnight Cost (2011$MM) 1,336 2,346 1,379 2,384 528 1,008

Total Overnight Cost (2011$/kW) 2,429 4,267 2,507 4,333 838 1,804

Owner's Costs 469 800 480 809 154 323

Total As-Spent Cost (2011$/kW) 2,755 4,865 2,842 4,940 901 1,945

COE ($/MWh) (excluding T&S) 82.0 133.5 82.3 133.2 57.6 83.3

Capital Costs 37.8 71.0 39.0 72.2 11.8 26.9

Fixed Costs 9.3 15.1 9.6 15.4 3.4 6.6

Variable Costs 9.2 15.1 9.1 14.7 1.7 4.0

Fuel Costs 25.7 32.2 24.6 30.9 40.7 45.9

COE ($/MWh) (including T&S) 82.0 143.5 82.3 142.8 57.6 87.3

CO2 T&S Costs 0.0 10.0 0.0 9.6 0.0 4.0

CO2 Captured Cost (excluding T&S), 

$/tonne N/A 56.2 N/A 58.2 N/A 71.1

CO2 Avoided Cost (including T&S), 

$/tonne N/A 91.0 N/A 89.4 N/A 93.8

*Cases without capture use conventional financing; all others use high-risk financial asssumptions 

consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant 

Performance.” (1)

The primary conclusions that can be drawn are:

• Based on total overnight cost (TOC) in $/kW, NGCC capital costs are approximately 

34% and 42% of the PC capital costs for non-capture and capture cases, respectively. 

• Capital costs for subcritical and SC PC are essentially equivalent within the accuracy of 

this report for a constant power output. 

• The addition of CO2 capture increases the capital costs – normalized to an equivalent net 

power output – by 74% and 115% for PC and NGCC, respectively.

• NGCC plant COEs are 70% and 61% of the PC plant COEs, for non-capture and capture 

cases, respectively. 

• The difference between the SC PC and subcritical PC COEs is minor, given the level of 

accuracy of the study estimate.

• The capital cost component represents the largest portion of the COE in PC cases, 

ranging from 46-51 percent of the total COE. The capital cost in NGCC cases represents 

21-31 percent of the total COE.

• The fuel cost component represents the largest portion of the COE in NGCC cases, 

ranging from 53-71 percent of the total COE. The fuel cost in PC cases represents 22-31 

percent of the total COE.
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• CO2 T&S costs add between $4/MWh (NGCC) and $10/MWh (PC) to the COE, which is 

less than 7 percent of the total for all capture cases.

• The NGCC case incurs a smaller increase in COE by the addition of CO2 capture than PC 

cases (52 percent versus approximately 75 percent).

• Despite the higher net plant efficiency and lower increase in COE, both the costs of CO2

avoided and captured are higher for NGCC cases than PC cases (costs of CO2 avoided are 

essentially equivalent within the accuracy of this report with the NGCC case having a 3-5 

percent greater cost than the PC cases) due to the relatively lower concentration and 

amount of CO2 available for capture.

• In the event that future legislation assigns a cost to carbon emissions, all of the 

technologies examined in this report will become more expensive. The technologies 

without carbon capture will be impacted to a larger extent than those with carbon capture, 

and coal-based technologies will be impacted more than natural gas-based technologies.

Exhibit ES-5 COE by cost component*

Source: NETL

*Cases without capture use conventional financing; all others use high-risk financial asssumptions 

consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant 

Performance.” (1)

Sensitivities

Exhibit ES-6 shows the COE sensitivity to fuel costs for the SC PC and NGCC cases. The bands 

for the SC PC cases represent a variance of the coal price from $2.21 - $3.69/MMBtu (±25% of 

the study value $2.94/MMBtu). This highlights regions of competitiveness of NGCC with SCPC 

systems for cases with and without CCS as a function of delivered natural gas price. As an 

example, at a coal cost of $3/MMBtu, the COE of the non-capture SC PC case equals non-
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capture NGCC at a natural gas price of approximately $10.0/MMBtu. Similarly, the SC PC and 

NGCC cases with capture have equivalent COEs at a coal price of $3.0/MMBtu and a natural gas 

price of approximately $13.5/MMBtu.

Exhibit ES-6 COE sensitivity to fuel costs 

Source: NETL

Sale of the captured CO2 for utilization and storage in CO2 enhanced oil recovery (EOR) has the 

potential to provide a revenue stream to both the SC PC and NGCC capture plant configurations. 

The plant gate CO2 sales price will ultimately depend on a number of factors including plant 

location and crude oil prices. The impact of CO2 sales price and the implications on the 

competitiveness of the capture technologies can be considered in a “phase diagram” type plot, as 

shown in Exhibit ES-7. The lines in the plot represent COE parity between different pairs of 

technologies.

The plot demonstrates the following points:

• Non-capture plants are the low-cost option below a first-year CO2 price of $56/tonne 

($51/ton).

• NGCC is preferred when natural gas prices are below $10/MMBtu with a CO2

revenue below $56/tonne (and a capacity factor of 85 percent). The natural gas price 

that provides parity between the various NGCC and PC cases drops off at higher CO2

revenues reaching $6/MMBtu at approximately $100/tonne ($91/ton).

30

50

70

90

110

130

150

170

190

3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

COE with CO2 T&S, $/MWh (2011$)

Delivered Natural Gas Price, $/MMBtu

SCPC w/ CCS ($2.94/MMBtu coal)

SCPC w/o CCS ($2.94/MMBtu coal)

$2.21 -

$3.69 per 

MMBtu

$2.21 -

$3.69 per 

MMBtu
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Exhibit ES-7 Lowest cost technology options at various natural gas and CO2 sales prices

Source: NETL

Special Considerations on Reported Costs

Capital Costs:

The capital cost estimates documented in this report reflect an uncertainty range of -15%/+30%, 

consistent with AACE Class 4 cost estimates (i.e., feasibility study) (2) (3) (4), based on the level 

of engineering design performed. In all cases, the report intends to represent the next 

commercial offering and relies on vendor cost estimates for component technologies. It also 

applies process contingencies at the appropriate subsystem levels in an attempt to account for 

expected but undefined costs, which can be a challenge for emerging technologies.

Costs of mature technologies and designs:

The cost estimates for plant designs that only contain fully mature technologies, which have been 

widely deployed at commercial scale (e.g., PC and NGCC power plants without CO2 capture),

reflect nth-of-a-kind (NOAK) on the technology commercialization maturity spectrum. The 

costs of such plants have dropped over time due to “learning by doing” and risk reduction 

benefits that result from serial deployments as well as from continuing R&D.

Costs of emerging technologies and designs:

The cost estimates for plant designs that include technologies that are not yet fully mature (e.g., 

any plant with CO2 capture) use the same cost estimating methodology as the mature plant 

designs, which does not fully account for the unique cost premiums associated with the initial, 

complex integrations of emerging technologies in a commercial application. Thus, it is 
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anticipated that initial deployments of the capture plants may incur costs higher than those 

reflected within this report. 

Other factors:

Actual reported project costs for all of the plant types are also expected to deviate from the cost 

estimates in this report due to project- and site-specific considerations (e.g. contracting strategy, 

local labor costs, seismic conditions, water quality, financing parameters, local environmental 

concerns, weather delays, etc.) that may make construction more costly. Such variations are not 

captured by the reported cost uncertainty.

Future Cost Trends:

Continuing research, development, and demonstration (RD&D) is expected to result in designs 

that are more advanced than those assessed by this report, leading to costs that are lower than 

those estimated herein.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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1 Introduction

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

performance of pulverized coal (PC) and natural gas combined cycle (NGCC) plants, using a 

consistent technical and economic approach that reflects current market conditions. 

This report is part of an update to Volume 1 of the four volume series, which consists of:

• 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

The cost and performance data have been updated for all PC and NGCC cases in this report, 

which constitutes Volume 1a. IGCC cases, previously integrated with the PC and NGCC cases 

in Revision 2a, are incorporated separately into a Volume 1b. (5) Section 6 has a revision 

control table listing the updates applied to this report.

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, and environmental performance

• Current and future regulations governing air, water, and solid waste discharges from 

fossil-fueled power plants

• Market penetration of clean coal technologies that have matured and improved as a result 

of recent commercial-scale demonstrations under the Department of Energy’s (DOE)

Clean Coal and Carbon Management Program

Six power plant configurations were analyzed in this report, including four PC cases – two 

subcritical and two supercritical (SC) (with and without CO2 capture); and two state-of-the-art 

2013 F-Class combustion turbine-based NGCC plants (with and without CO2 capture). While 

labeled as SC conditions, the SC steam cycle conditions utilized in this report are also generally 

representative of commercial plants characterized as ultra-supercritical (USC), particularly with 

respect to temperature (1,100°F). Because efficiency is more sensitive to steam cycle 

temperature than pressure, the resulting performance is at or near that of top-performing 

commercially available USC PC plants. The Shell Cansolv CO2 capture system utilized in this 

report is an amine-based solvent system. A summary of the case configurations in the report is 

shown in Exhibit 1-1.

This revision reflects varying degrees of technology vendor input for updates to the pollution 

control equipment for PC plants, and the CO2 capture, CO2 compression, and steam turbine 

technology for PC and NGCC plants; however, the final assessment of performance and cost was 

determined independently and is not endorsed by the individual vendors.
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Generating Unit Configurations

A summary of plant configurations considered in this report is presented in Exhibit 1-1. 

Components for each plant configuration are described in more detail in the corresponding report 

sections for each case.

The NGCC cases have different gross and net power outputs because of the combustion turbine 

(CT) size constraint. The state-of-the-art 2013 F-class CT used to model the NGCC cases comes 

in a standard size of 211 MW when operated at conditions set by the International Standards 

Organization (ISO). Each case uses two CTs for a combined gross output of 422 MW. In the 

combined cycle a heat recovery steam generator (HRSG) extracts heat from the CT exhaust to 

power a steam turbine. 

The net output in the NGCC CO2 capture case is significantly reduced, compared to the noncapture case due to the high auxiliary power load and significant extraction steam requirement of 

the CO2 capture system.

While the two CTs provide 422 MW gross output in both NGCC cases, the overall combined 

cycle gross output ranges from 601 to 641 MW, which results in a range of net output from 559 

(Case B31B) to 630 MW (Case B31A). The natural gas feed rate is held constant in both cases 

at 84,134 kg/hr (185,484 kb/hr).

All four PC 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 PC cases in this report. The coal feed rate was increased 

in the CO2 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 describes the PC technologies modeled and presents the results for the four 

PC cases.

• Chapter 4 describes the NGCC technologies modeled and presents the results for the 

two NGCC cases.

• Chapter 5 provides a cross comparison of NGCC and PC cases

• Chapter 6 includes a record of report revisions.
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Exhibit 1-1 Case descriptions

Case

(Old Case NameA)

Unit 

Cycle

Steam Cycle, 

psig/°F/°F

Combustion 

Turbine

Boiler 

Technology Oxidant Sulfur Removal/Recovery PM Control NOx Control

CO2

SeparationB

B11A (9) PC 2400/1050/1050 N/A Subcritical PC Air Wet FGD/ Gypsum Baghouse

LNB w/OFA 

and SCR N/A

B11B (10) PC 2400/1050/1050 N/A Subcritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA 

and SCR Cansolv

B12A (11) PC 3500/1100/1100 N/A SC PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA 

and SCR N/A

B12B (12) PC 3500/1100/1100 N/A SC PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA 

and SCR Cansolv

B31A (13) NGCC 2400/1050/1050 2 x State-of-theart 2013 F-Class HRSG Air N/A N/A LNB and 

SCR N/A

B31B (14) NGCC 2400/1050/1050 2 x State-of-theart 2013 F-Class HRSG Air N/A N/A LNB and 

SCR Cansolv

APrevious versions of this report used a different naming convention. The old case numbers are provided here, paired with the new case numbers 

for reference.

BAll cases have a nominal 90 percent removal rate based on the total feedstock minus unburned carbon in ash (PC cases). The rate of CO2

capture from the flue gas in the Cansolv systems varies. An explanation for the difference is provided in Section 2.4.3. All cases sequester the 

CO2 offsite.
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2 General Evaluation Basis

For each of the plant configurations analyzed in this report an Aspen Plus® (Aspen) model was 

developed and used to generate material and energy balances, which were, in turn, used to 

provide a design basis for items in the major equipment list. The equipment list and material 

balances were used as the basis for generating the capital and operating cost estimates. 

Performance and process limits were based upon published reports, information obtained from 

vendors and users of the technology, performance data from design/build utility projects, and/or 

best engineering judgment. Capital and operating costs were estimated by WorleyParsons based 

on simulation results and through scaled estimates from previous design/build projects. 

Ultimately, a COE was calculated for each of the cases and is reported as the revenue 

requirement figure-of-merit.

The balance of this section discusses the design basis common to all technologies, as well as 

environmental targets and cost assumptions used in the study. Technology specific design 

criteria are covered in subsequent chapters.

2.1 Site Characteristics

All plants in this report are assumed to be located at a generic plant site in Midwestern U.S., with 

site characteristics and ambient conditions as presented in Exhibit 2-1 and Exhibit 2-2. The 

ambient conditions are the same as ISO conditions.

Exhibit 2-1 Site characteristics

Parameter Value

Location Greenfield, Midwestern U.S.

Topography Level

Size (Pulverized Coal), acres 300

Size (Natural Gas Combined Cycle), acres 100

Transportation Rail or Highway

Ash Disposal Off-Site

Water 50% Municipal and 50% Ground Water

Exhibit 2-2 Site ambient conditions

Parameter Value

Elevation, (ft) 0

Barometric Pressure, MPa (psia) 0.101 (14.696)

Average Ambient Dry Bulb Temperature, °C (°F) 15 (59)

Average Ambient Wet Bulb Temperature, °C (°F) 10.8 (51.5)

Design Ambient Relative Humidity, % 60

Cooling Water Temperature, °C (°F)A 15.6 (60)

Air composition based on published psychrometric data, mass %

N2 72.429

O2 25.352

Ar 1.761

H2O 0.382

CO2 0.076

Total 100.00

AThe cooling water temperature is the cooling tower cooling water exit temperature. 

This is set to 8.5°F above ambient wet bulb conditions in ISO cases.
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The land area for PC cases assumes that 30 acres are required for the plant proper and the 

balance provides a buffer of approximately 0.25 mi to the fence line. The extra land could also 

provide for a rail loop if required (rail loop not included in this analysis). In the NGCC cases it 

was assumed the plant proper occupies about 10 acres leaving a buffer of 0.15 mi to the plant 

fence line.

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

cases the boiler is also enclosed. The CTs in the NGCC cases are not enclosed.

The following design parameters are considered site-specific, and are not quantified for this 

report. Allowances for normal conditions and construction are included in the cost estimates.

• Flood plain considerations

• Existing soil/site conditions

• Water discharges and reuse

• Rainfall/snowfall criteria

• Seismic design

• Buildings/enclosures

• Local code height requirements

• Noise regulations – Impact on site and surrounding area

• Other localized environmental concerns

• Weather delays

2.2 Coal Characteristics

The design coal is Illinois No. 6 with characteristics presented in Exhibit 2-3. The coal 

properties are from the January 2012 revision of the Quality Guidelines for Energy System 

Studies (QGESS) document “Detailed Coal Specifications.” (6)

The Power Systems Financial Model (PSFM) was used to derive the capital charge factors (CCF) 

for this report. (7) The PSFM requires that all cost inputs have a consistent cost year basis. 

Because the capital and operating cost estimates are in June 2011 dollars, the fuel costs must also 

be in June 2011 dollars.

Assumed fuel price is $2.78/GJ ($2.94/MMBtu) for Illinois No. 6 coal, on a higher heating value 

(HHV) basis, delivered to the Midwest, and in 2011 United States (U.S.) dollars.4

 

4 As specified in the November 2012 QGESS document on “Fuel Prices for Selected Feedstocks in NETL Studies.” (45)
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Exhibit 2-3 Design coal

Rank Bituminous 

Seam Illinois No. 6 (Herrin)

Source Old Ben Mine

Proximate Analysis (weight %)A

As Received Dry

Moisture 11.12 0.00

Ash 9.70 10.91

Volatile Matter 34.99 39.37

Fixed Carbon 44.19 49.72

Total 100.00 100.00

Sulfur 2.51 2.82

HHV, kJ/kg (Btu/lb) 27,113 (11,666) 30,506 (13,126)

LHV, Btu/lb (Btu/lb) 26,151 (11,252) 29,544 (12,712)

Ultimate Analysis (weight %)

As Received Dry

Moisture 11.12 0.00

Carbon 63.75 71.72

Hydrogen 4.50 5.06

Nitrogen 1.25 1.41

Chlorine 0.29 0.33

Sulfur 2.51 2.82

Ash 9.70 10.91

OxygenB 6.88 7.75

Total 100.00 100.00

AThe proximate analysis assumes sulfur as volatile matter. BBy difference.

The mercury content of 34 samples of Illinois No. 6 coal has an arithmetic mean value of 

0.09 ppmwd with standard deviation of 0.06 based on coal samples shipped by Illinois mines. (8) 

Hence, as illustrated in Exhibit 2-4, there is a 50 percent probability that the mercury content in 

the Illinois No. 6 coal would not exceed 0.09 ppmwd. The coal mercury content for this report

was assumed to be 0.15 ppmwd for all PC cases, which corresponds to the mean plus one 

standard deviation and encompasses about 84 percent of the samples. It was further assumed 

that all of the coal Hg enters the gas phase and none leaves with the bottom ash (9).
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Exhibit 2-4 Probability distribution of mercury concentration in the Illinois No. 6 coal

Source: NETL

2.3 Natural Gas Characteristics

Natural gas is utilized as the fuel in Cases B31A and B31B (NGCC with and without CO2

capture), and its composition is presented in Exhibit 2-5. The natural gas properties are from the 

January 2012 revision of the QGESS document “Specification for Selected Feedstocks” (10)

with the addition of methanethiol (mercaptan). (11)

Assumed fuel price is $5.81/GJ ($6.13/MMBtu) for natural gas, on a higher heating value (HHV)

basis, delivered to the Midwest, and in 2011 United States (U.S.) dollars.5

Exhibit 2-5 Natural gas composition

Component Volume Percentage

Methane CH4 93.1

Ethane C2H6 3.2

Propane C3H8 0.7

n-Butane C4H10 0.4

Carbon Dioxide CO2 1.0

Nitrogen N2 1.6

MethanethiolA CH4S 5.75x10-6

Total 100.00

LHV HHV

kJ/kg (Btu/lb) 47,454 (20,410) 52,581 (22,600)

MJ/scm (Btu/scf) 34.71 (932) 38.46 (1,032)

AThe sulfur content of natural gas is primarily composed of added

Mercaptan (methanethiol, CH4S) with trace levels of H2S (11).

Note: Fuel composition is normalized and heating values are calculated 

 

5 As specified in the November 2012 QGESS document on “Fuel Prices for Selected Feedstocks in NETL Studies.” (45)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0.00 ppm Hg 0.05 ppm Hg 0.10 ppm Hg 0.15 ppm Hg 0.20 ppm Hg 0.25 ppm Hg 0.30 ppm Hg

Mercury Concentraion in Coal, ppm db

Probability Illinois #6 Sample Will Be At or Below Value

Arithmetic Mean = 0.09 ppm db

Standard Deviation = 0.06 ppm db
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2.4 Environmental Targets

Environmental targets were established for each of the technologies as follows:

• Mercury (Hg) and hydrochloric acid limits were set by the March 2013 update to the 

Utility Mercury and Air Toxics Standards (MATS) for PC technologies. (12), (13), (14)

• Particulate matter (PM), sulfur dioxide (SO2), and nitrogen oxide (NOx) limits were set 

by the February 2013 update to the New Source Performance Standards (NSPS) for PC

and NGCC technologies. (14), (15)

The regulations divide the coal types into low rank and non-low rank based on their heating 

value. Coals with a higher heating value (HHV) of greater than 8,300 Btu per pound (Btu/lb) on 

a moist, mineral-matter free basis are considered non-low rank. Therefore, Illinois No. 6 coal, 

with an HHV (moist, mineral-matter free) of 12,900 Btu/lb, is considered a non-low rank coal.

The emission limits imposed by MATS and NSPS that apply to each technology in this report are 

provided in Exhibit 2-6.

Exhibit 2-6 MATS and NSPS emission limits for PM, HCl, SO2, NOx, and Hg

PollutantA PC

(lb/MWh-gross)

NGCC

(lb/MWh-gross)

SO2 1.00 0.90

NOx 0.70 0.43

PM (Filterable) 0.09 N/A

Hg 3x10-6 N/A

HCl 0.010 N/A

ACO emissions may be considered in later revisions of this report, if necessary.

These new regulations apply to PC and NGCC technologies that begin construction after May 3, 

2011. Furthermore, these regulations state that (14), (16):

Fossil fuel is defined as natural gas, oil, coal, and any form of solid, liquid, or gaseous 

fuel derived from such material.

Electric utility steam generating units (EGU) are defined as a fossil fuel-fired combustion 

unit of more than 25 megawatts electric (MWe) that serves a generator that produces 

electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and 

supplies more than one-third of its potential electric output capacity and more than 25 

MWe output to any utility power distribution system for sale is considered an electric 

utility steam generating unit.

Fossil fuel-fired means an EGU that is capable of combusting more than 25 MW of fossil 

fuels. To be capable of combusting fossil fuels, an EGU would need to have these fuels 

allowed in its operating permit and have the appropriate fuel handling facilities on-site or 

otherwise available (e.g., coal handling equipment, including coal storage area, belts and 

conveyers, pulverizers, etc.; oil storage facilities).

Coal-fired electric utility steam generating units are defined as an EGU and meet the 

definition of “fossil fuel-fired,” which is that it burns coal for more than 10 percent of the 

average annual heat input during any three consecutive calendar years or for more than 

15 percent of the annual heat input during any one calendar year.
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Unit designed for low-rank virgin coal subcategory is defined as any coal-fired EGU that 

is designed to burn, and that is burning, non-agglomerating virgin coal having a calorific 

value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) that is 

constructed and operates at or near the mine that produces such coal.

Unit designed for coal ≥8,300 Btu/lb subcategory is defined as any coal-fired EGU that is 

not a coal-fired EGU in the “unit designed for low rank virgin coal” subcategory.

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 in areas not meeting ambient air quality standards (non-attainment areas). 

Environmental area designation varies by county and can be established only for a specific site 

location. Based on the EPA Green Book Non-attainment Area Map relatively few areas in the 

Midwestern U.S. are classified as “non-attainment,” so the plant site for this report was assumed 

to be in an attainment area. (15)

In addition to federal regulations, state and local jurisdictions can impose even more stringent 

regulations on a new facility. However, since each new plant has unique environmental 

requirements, it was necessary to apply some judgment in setting the environmental targets for 

this report.

2.4.1 PC

Exhibit 2-7 provides the emissions limits for PC plants as well as a brief summary of the control 

technology utilized to satisfy the limits.

Exhibit 2-7 Environmental targets for PC cases

Pollutant PC

(lb/MWh-gross) Control Technology

SO2 1.00 Wet limestone scrubber

NOx 0.70 Low NOx burners, overfire air and SCR

PM 

(Filterable) 0.09 Fabric filter

Hg 3x10-6 Co-benefit capture, dry sorbent injectionA, activated carbon 

injection

HCl 0.010 SO2 surrogateB

 ALimits SO3 levels and their detrimental effects on activated carbon injection (See Section 3.1.6)

ASO2 may be utilized as a surrogate for HCl measurement if the EGU utilizes wet FGD. (17)

It was assumed that low NOx burners (LNB) and staged overfire air (OFA) would limit NOx 

emissions to 0.5 lb/MMBtu and that selective catalytic reduction (SCR) technology would be 83-

85 percent efficient. By adjusting the ammonia flow rate in the SCR, the NOx emissions limit 

was able to be met exactly. 

The wet limestone scrubber was assumed to be 98 percent efficient, which results in SO2

emissions below the NSPS SO2 limit. Current technology allows wet flue gas desulfurization 
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(FGD) removal efficiencies in excess of 99 percent, but based on NSPS requirements, such high 

removal efficiency is not necessary.

The fabric filter was assumed to be capable of achieving an efficiency of greater than 99.9 

percent. As the required efficiency was approximately 99.9 percent for each case, the efficiency 

was varied in order to meet the PM emissions limit exactly.

The mercury removal efficiency required to meet the emission limit is approximately 97 percent 

in each case. It was assumed that the total mercury removal rate resulting from the combination 

of pollution control technologies used (SCR, dry sorbent injection (DSI), activated carbon 

injection (ACI), fabric filters, and FGD) would meet the limit exactly. DSI is required to limit 

the effects of SO3 on Hg capture due to the high sulfur content of the coal in this study. Section 

3.1.6 provides a detailed discussion regarding mercury removal and the various systems 

involved.

2.4.2 NGCC

Exhibit 2-8 provides the emissions limits for NGCC plants as well as a brief summary of the 

control technology utilized to satisfy the limits.

Exhibit 2-8 Environmental targets for NGCC cases

Pollutant

NGCC

(lb/MWh-gross) Control Technology

SO2 0.90 Low sulfur content fuel

NOx 0.43 Dry low NOx burners and SCR

PM (Filterable) N/A N/A

Hg N/A N/A

HCl N/A N/A

The NGCC cases were designed to achieve approximately 1.0 ppmvd NOx emissions

(referenced to 15 percent O2) through the use of a dry low NOx (DLN) burner in the CTG – the 

DLN burners are a low NOx design and reduce the emissions to about 9 ppmvd (18) (assumed to 

be approximately 98 percent NO and referenced to 15 percent O2) – and an SCR (19).

While a state-of-the-art 2013 F-class CT alone produces NOx emissions below the limit shown 

in Exhibit 2-8, an SCR was included to ensure the plant met the EPAs prevention of significant 

deterioration (PSD) program by installing the best available control technology (BACT). The 

SCR system is designed for 90 percent NO reduction while firing natural gas.

The total sulfur content of natural gas is typically limited by contract terms and industry practice

to between 0.25 and 1.00 gr/100 scf with the average total sulfur content being 0.34 gr/100 scf.

(11) For the purpose of this report, the natural gas was assumed to contain the average value of 

total sulfur of 0.34 gr/100 scf (4.71x10-4 lb-S/MMBtu). It was also assumed that the added 

mercaptan (CH4S) was the sole contributor of sulfur to the natural gas. The mercaptan 

concentration of the natural gas was provided in Exhibit 2-5 as 5.75x10-6 mol% (7.06x10-4 lbCH4S/MMBtu). 

If the natural gas contained 1.00 gr-S/100 scf, the SO2 emissions for the non-capture case would 

be 0.018 lb/MWh-gross. The CO2 capture system removes virtually all SO2 from the flue gas.

The pipeline natural gas was assumed to contain no particulate matter (PM), Hg, or HCl,

resulting in zero emissions.
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2.4.3 Carbon Dioxide

The EPA proposed a new source performance standard on April 13, 2012 for emissions of 

carbon dioxide for new fossil fuel-fired electric utility generating units. As of the publication of 

this report, the EPA is finalizing a rule that may set CO2 emissions limits below that of fossil 

fuel-fired electric utlity generation units without CO2 capture. 

The PC and NGCC cases both assume that all of the combusted carbon in the fuel is converted to 

CO2 in the flue gas. Carbon dioxide is also generated from limestone in the FGD system and 

added as activated carbon (for mercury removal). The CO2 capture plant design is for 90

percent capture of the CO2 exiting the FGD system, resulting in emissions of 180 - 190 lb/MWh 

gross and 82 lb/MWh gross for PC and NGCC plants, respectively.

2.5 Capacity Factor

2.5.1 Capacity Factor Assumptions

Availability is the percent of time during a specific period that a generating unit is capable of 

producing electricity. This report assumes that each new plant would be dispatched any time it is 

available and would be capable of generating the nameplate capacity when online. Therefore, 

the capacity factor (CF) and availability are equal. The operating period selected is also 

important. The calculations assume that the capacity factor and availability are constant over the 

life of the plant, but in actual operation may require that a plant have a higher peak availability to 

counter lower availability in the first several years of operation. 

2.5.2 Existing Plant Data

The North American Electric Reliability Council (NERC) Generating Availability Data System 

(20) (GADS) provides information on existing plants (e.g. Generating Analysis Reports, 

Generating Availability Reports, Generating Unit Statistical Brochure, Historical Availability 

Statistics). These data for coal plants (e.g. PC technology) include average availability and plant

capacity factor data, by fuel type and plant capacity.

The GADS database provides data on many plant operating characteristics. Three metrics are 

used in this report to evaluate existing plant availability and capacity factors (availability factor 

(AF), net capacity factor (NCF), and equivalent availability factor (EAF)). The metrics can be 

defined by the following equations.

NNNNNN = NNNNNN

PPPP ∗ � GG − CC

AAAA �

Where:

NAG – Net actual generation

PH – number of hours a unit was in the active state

GMC – Gross maximum capacity

CU – Capacity utilized for unit station service

Aux – Auxiliaries

= PPPP − (PPPPPP + + )

PPPP

Where:

POH – Planned outage hours
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FOH – Forced outage hours

MOH – Maintenance outage hours

EE = (PPPP − (PPPPPP + + )) − (EE EE + EE EE + EEEEEEEE )

PPPP

Where:

EUDH – Equivalent un-planned derated hours

EPDH – Equivalent planned derated hours

ESEDH – Equivalent seasonal derated hours

The EAF is essentially 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 seasonal derated 

hours. As such, the EAF matches this report’s definition of CF. 

2.5.3 Capacity Factor for Coal Units without Carbon Capture

Exhibit 2-9 presents GADS coal unit availability and capacity factor data for generating plants in 

2011. In order to provide perspective on these metrics over time, Exhibit 2-10 presents the same 

metrics averaged over the period 2007-2011. The number of generating units included in the 

2011 data is presented in Exhibit 2-11.

Exhibit 2-9 Coal plant availability and capacity factor data for units reporting in 2011

Source: NETL
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Exhibit 2-10 Coal plant availability and CF average data over the period 2007-2011

Source: NETL

Exhibit 2-11 Number of coal units included in the 2011 data

Source: NETL
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The baseline study net unit capacity is 550 MW. The average EAF for coal-fired plants in the 

400-599 MW size range was 83.7 percent in 2011 and averaged 81.8 percent from 2007-2011. 

The average net capacity factor for these units is less than 70 percent, which reflects the demand 

and how the plants were dispatched.

While the assumption for this report is that a unit will be dispatched when it is available, it is 

useful to have perspective on the ability of coal units to achieve high capacity factors. The 

Ventyx Velocity Suite (21) database provides data on individual unit performance. Exhibit 2-12

presents data on the number of units that achieved greater than 80 percent capacity factor in a 

given year for each year from 2000 through 2012. 

Exhibit 2-12 Number of coal units reporting capacity factors greater than 80% 

Source: NETL

The 2006-2007 peak in the number of units operating with a given capacity factor is related to 

the U.S. coal electricity demand. Exhibit 2-13 presents EIA data (22) on electricity generation 

that shows a peak in 2007.
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Exhibit 2-13 U. S. coal electricity power generation

Source: NETL

The GADS data show an average coal unit availability greater than 80 percent and the individual 

unit data from Ventyx Velocity show up to 162 coal units have operated in a given year with 

capacity factors greater than 85 percent. The current study costs are based on mature plant 

technology. Based on a review of the available data, an 85 percent capacity factor is selected for 

the PC coal units. 

2.5.4 Capacity Factor for Natural Gas Combined Cycle (NGCC) Plants

Similar data as used for PC plants were reviewed for natural gas combined cycle plants. The 

GADS database shows an average availability of 87.8 percent for 160 combined cycle plants in 

2011. The data over the last ten years show an availability of ~ 90 percent for each year. The 

average availability from 1980 to 1995 ranged from 80-90 percent. An 85 percent capacity 

factor is selected for NGCC plants.

2.5.5 Capacity Factor for Plants with Carbon Capture

The addition of carbon capture adds extra equipment to the power plant. Preliminary reliability 

analyses show small reductions in reliability if the reliability of the base plant components is 

kept constant. A solvent-based carbon capture technology is used in this report for both power 

plant configurations (PC and NGCC). The capture and CO2 compression technologies have 

commercial operating experience with demonstrated ability for high reliability. Given the use of 

commercial technology, albeit at smaller scale, the assumption is made that the capacity factors 

for a given plant with and without carbon capture are the same. Thus, the capacity factor for PC 

and NGCC plants with capture is 85 percent. 
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The DOE Energy Information Agency (EIA), in their Annual Energy Outlook 2013, projected a 

capacity factor of 85 percent for new advanced coal with capture and 87 percent for new 

advanced coal without capture. 

2.5.6 Perspective

Reported unit data and reported plant experience support the capability to achieve the selected 

availability factors for the plants. Important factors required to achieve these availability 

projections include a quality plant design that utilizes lessons learned from similar plant designs, 

a focus on life cycle costs, a smart predictive maintenance, a trained plant staff, and an economic 

demand for unit power. An illustration of lessons learned and the resulting high plant 

availability that can be obtained is reported by Richwine. (23) 

Plant availability is determined by the plant technology, the capital cost invested in the plant (e.g. 

what is the design approach with respect to minimizing scheduled and unplanned maintenance), 

the maintenance requirements and the ‘customer’ requirements for the electricity (e.g. customer 

costs due to a unit not being available). Since the unavailability cost will decrease with 

increasing unit availability and the maintenance and capital costs increase with increasing unit 

availability, there will be an optimum economic unit availability for a given application. The 

current study assumes that the plant design, plant maintenance, and electricity demand are 

consistent with the selected availability.

The existing plant data have not been analyzed with regard to the performance of individual 

plant availability over the life of the plant. As stated, this report assumes a constant availability 

of 85 percent for each year over the life of the plant. It is recognized that the availability of a 

given plant will vary over the life of the plant. As demonstrated by existing plant data, coal 

plants can be designed and operated with yearly availability ranging from 85-100 percent. It is 

assumed that the plants in this report will have yearly availability factors above and below the 

selected values with the effective or levelized availability for the life of the plant being the 

selected value. 

2.6 Raw Water Withdrawal and Consumption

A water balance was performed for each case on the major water consumers in the process. The 

total water demand for each subsystem was determined and internal recycle water available from 

various sources like boiler feedwater (BFW) blowdown and condensate from flue gas (in CO2

capture cases) was applied to offset the water demand. The difference between demand and 

recycle is raw water withdrawal. Raw water withdrawal is the water removed from the ground 

or diverted from a municipal source for use in the plant. Raw water consumption is also 

accounted for as the portion of the raw water withdrawn that is evaporated, transpired, 

incorporated into products, or otherwise not returned to the water source from which it was 

withdrawn.

Raw water makeup was assumed to be provided 50 percent by a publicly owned treatment works 

(POTW) and 50 percent from groundwater. Raw water withdrawal is defined as the water 

metered from a raw water source and used in the plant processes for any and all purposes, such 

as cooling tower makeup, BFW makeup, ash handling makeup, and FGD system makeup. The 

difference between withdrawal and process water returned to the source is consumption. 

Consumption represents the net impact of the process on the water source.
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BFW blowdown and a portion of the sour water stripper blowdown were assumed to be treated 

and recycled to the cooling tower. The cooling tower blowdown and the balance of the SWS 

blowdown streams were assumed to be treated and 90 percent returned to the water source with 

the balance sent to the ash ponds for evaporation.

The largest consumer of raw water in all cases is cooling tower makeup. It was assumed that all 

cases utilized a mechanical draft, evaporative cooling tower, and all process blowdown streams 

were assumed to be treated and recycled to the cooling tower. The design ambient wet bulb 

temperature of 11°C (51.5°F) (Exhibit 2-1 and Exhibit 2-2) was used to achieve a cooling water 

temperature of 16°C (60°F) using an approach of 5°C (8.5°F). The cooling water range was 

assumed to be 11°C (20°F). The cooling tower makeup rate was determined using the following

(24):

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

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

• Blowdown losses (BDL) were calculated as follows:

BB BB = EE

− 1

Where:

EL – Evaporative Losses

CC – Cycles of concentration

The cycles of concentration are a measure of water quality and a mid-range value of four (4) was 

chosen for this report.

The water balances presented in subsequent sections include the water demand of the major 

water consumers within the process, the amount provided by internal recycle, the amount of raw 

water withdrawal by difference, the amount of process water returned to the source, and the raw 

water consumption, again by difference.

2.7 Cost Estimating Methodology

Detailed information pertaining to topics such as contracting strategy, EPC contractor services, 

estimation of capital cost contingencies, owner’s costs, cost estimate scope, economic 

assumptions, finance structures, cost of electricity, etc. are available in the April 2011 revision of 

the QGESS document “Cost Estimation Methodology for NETL Assessment of Power Plant 

Performance.” (1) Select portions are repeated in this report for completeness.

Capital Costs:

The capital cost estimates documented in this report reflect an uncertainty range of -15%/+30%, 

consistent with AACE Class 4 cost estimates (i.e., feasibility study) (2) (3) (4), based on the level 

of engineering design performed. In all cases, the report intends to represent the next 

commercial offering, and relies on vendor cost estimates for component technologies. It also 

applies process contingencies at the appropriate subsystem levels in an attempt to account for 

expected but undefined costs (a challenge for emerging technologies).

Costs of mature technologies and designs:

The cost estimates for plant designs that only contain fully mature technologies, which have been 

widely deployed at commercial scale (e.g., PC and NGCC power plants without CO2 capture),
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reflect nth-of-a-kind (NOAK) on the technology commercialization maturity spectrum. The 

costs of such plants have dropped over time due to “learning by doing” and risk reduction 

benefits that result from serial deployments as well as from continuing R&D.

Costs of emerging technologies and designs:

The cost estimates for plant designs that include technologies that are not yet fully mature (e.g., 

any plant with CO2 capture) use the same cost estimating methodology as for the mature plant 

designs, which does not fully account for the unique cost premiums associated with the initial, 

complex integrations of emerging technologies in a commercial application. Thus, it is 

anticipated that initial deployments of the capture plants may incur costs higher than those 

reflected within this report. 

Other factors:

Actual reported project costs for all of the plant types are also expected to deviate from the cost 

estimates in this report due to project- and site-specific considerations (e.g. contracting strategy, 

local labor costs, seismic conditions, water quality, financing parameters, local environmental 

concerns, weather delays, etc.) that may make construction more costly. Such variations are not 

captured by the reported cost uncertainty.

Future Cost Trends:

Continuing research, development, and demonstration (RD&D) is expected to result in designs 

that are more advanced than those assessed by this report, leading to costs that are lower than 

those estimated herein.

2.7.1 Capital Costs

As illustrated in Exhibit 2-14, this report defines capital cost at five levels: BEC, EPCC, TPC, 

TOC, and TASC. BEC, EPCC, TPC, and TOC are “overnight” costs and are expressed in “baseyear” dollars. The base year is the first year of capital expenditure. TASC is expressed in 

mixed, current-year dollars over the entire capital expenditure period, which is assumed in most 

NETL studies to last five years for coal plants and three years for natural gas plants.

The Bare Erected Cost (BEC) comprises the cost of process equipment, on-site facilities and 

infrastructure that support the plant (e.g., shops, offices, labs, road), and the direct and indirect 

labor required for its construction and/or installation. The cost of EPC services and 

contingencies are not included in BEC. BEC is an overnight cost expressed in base-year dollars.

The Engineering, Procurement and Construction Cost (EPCC) comprises the BEC plus the cost 

of services provided by the engineering, procurement and construction (EPC) contractor. 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. EPCC is an overnight cost 

expressed in base-year dollars.

The Total Plant Cost (TPC) comprises the EPCC plus project and process contingencies. TPC is 

an overnight cost expressed in base-year dollars.

The Total Overnight Cost (TOC) comprises the TPC plus all other overnight costs, including 

owner’s costs. TOC is an “overnight” cost, expressed in base-year dollars and as such does not 

include escalation during construction or interest during construction. 
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The Total As-Spent Cost (TASC) is the sum of all capital expenditures as they are incurred 

during the capital expenditure period including their escalation. TASC also includes interest 

during construction. Accordingly, TASC is expressed in mixed, current-year dollars over the 

capital expenditure period.

Exhibit 2-14 Capital cost levels and their elements

Source: NETL

2.7.1.1 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 using an in-house database and conceptual estimating models. 

Costs were further calibrated using a combination of adjusted vendor-furnished and actual cost 

data from recent design projects.

2.7.1.2 System Code-of-Accounts 

The costs are grouped according to a process/system oriented code of accounts. This type of 

code-of-account structure has the advantage of grouping all reasonably allocable components of 

a system or process so they are included in the specific system account. (This would not be the 

case had a facility, area, or commodity account structure been chosen instead). 

2.7.1.3 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. 

T&S cost is not included in the reported capital cost or O&M costs, but is treated separately and 

added to the COE.

2.7.1.4 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 

process equipment

supporting facilities

direct and indirect 

labor

BEC

EPCC

TPC

TOC

TASC

EPC contractor services

process contingency

project contingency

pre-production costs

inventory capital

financing costs

other owner’s costs

escalation during capital expenditure period

interest on debt during capital expenditure period

Bare Erected Cost

Engineering, Procurement 

and Construction Cost

Total Plant Cost

Total Overnight Cost

Total As-Spent Cost

BEC, EPCC, TPC and TOC are 

all “overnight” costs 

expressed in base-year dollars.

TASC is expressed in mixedyear current dollars, spread 

over the capital expenditure 

period.
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and the respective models are maintained by WorleyParsons as part of a commercial power plant 

design base of experience for similar equipment in the company’s range of power and process 

projects. A reference bottom-up estimate for each major component provides the basis for the 

estimating models. 

Other key estimate considerations include the following:

• Labor costs are based on Midwest, Merit Shop. The estimating models are based on U.S. 

Gulf Coast and the labor has been factored to Midwest. The basis for the factors is the 

PAS, Inc. (PAS) “Merit Shop Wage & Benefit Survey,” which is published 

annually. Based on the data provided in PAS, WorleyParsons used the weighted average 

payroll plus fringe rate for a standard craft distribution as developed for the estimating 

models. PAS presents information for eight separate regions. For this report, Region 5 

(IL, IN, MI, MN, OH, and WI) was selected.

• The estimates are based on a competitive bidding environment, with adequate skilled 

craft labor available locally.

• Labor is based on a 50-hour work-week (5-10s). No additional incentives such as perdiem allowances or bonuses have been included to attract craft labor. 

• While not included at this time, labor incentives may ultimately be required to attract and 

retain skilled labor depending on the amount of competing work in the region, and the 

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 level, and free from hazardous 

materials, archeological artifacts, or excessive rock. Soil conditions are considered 

adequate for spread footing foundations. The soil bearing capability is assumed adequate 

such that piling is not needed to support the foundation loads. 

• Engineering and Construction Management are estimated at 8-10 percent of BEC. These 

costs consist of all home office engineering and procurement services as well as field 

construction management costs. Site staffing generally includes a construction manager, 

resident engineer, scheduler, and personnel for project controls, document control, 

materials management, site safety, and field inspection.

2.7.1.5 Price Fluctuations

During the course of this report, the prices of equipment and bulk materials fluctuated 

substantially. Some reference quotes pre-dated the 2011 year cost basis while others were 

received post-2011. All vendor quotes used to develop these estimates were adjusted to June 

2011 dollars accounting for the price fluctuations. Price indices, e.g. The Chemical Engineering 

Plant Cost Index (25) and the Gross Domestic Product Chain-type Price Index (26), were used as 

needed for these adjustments. While these overall indices are nearly constant, it should be noted 

that the cost of individual equipment types may still deviate from the June 2011 reference point.

2.7.1.6 Cross-comparisons 

In all technology comparison studies, the relative differences in costs are often more significant 

than the absolute level of TPC. This requires cross-account comparison between technologies to 

review the consistency of the direction of the costs. 
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In performing such a comparison, it is important to reference the technical parameters for each 

specific item, as these are the basis for establishing the costs. Scope or assumption differences 

can quickly explain any apparent anomalies.

2.7.1.6.1 Process Contingency

Process contingencies were applied to the estimates in this report as follows:

• Cansolv System – 20 percent on all PC/NGCC capture cases - post-combustion 

capture process unproven at commercial scale for power plant applications

• Instrumentation and Controls –5 percent on the PC and NGCC capture cases –

integration issues

2.7.1.7 Owner’s Costs

Two examples of what could be included in the “other” owner’s costs are rail spur and switch 

yard costs. Rail spur costs would only be applied to the PC cases; however, the switch yard costs 

would be included in all cases.

Switch yard costs are dependent on voltage, configuration, number of breakers, layout, and airinsulated vs. gas-insulated. As a rule of thumb, a 345 kV switchyard (air-insulated, ring bus) 

would cost roughly $850,000 per breaker.

On-site only rails (excludes long runs) would be expected to cost in the range of $850,000 to 

$950,000 per mi (relatively flat level terrain) plus the costs of any switches/turnouts 

(approximately $50,000 each) and road crossings (approximately $300 per lineal foot).

Additional details and explanation of owner’s costs are available in the April 2011 revision of 

the QGESS document “Cost Estimation Methodology for NETL Assessment of Power Plant 

Performance” (1).

2.7.2 Operation and Maintenance Costs

The production costs or operating costs and related maintenance expenses (O&M) pertain to 

those charges associated with operating and maintaining the power plants over their expected 

life. These costs include: 

• Operating labor

• Maintenance – material and labor

• Administrative and support labor

• Consumables

• Fuel

• Waste 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. Taxes and insurance 

are included as fixed O&M costs, totaling 2 percent of the TPC.
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2.7.2.1 Operating Labor

Operating labor cost was determined based on of the number of operators required for each 

specific case. The average base labor rate used to determine annual cost is $39.70/hour. The 

associated labor burden is estimated at 30 percent of the base labor rate.

2.7.2.2 Maintenance Material and Labor

Maintenance cost was evaluated on the basis of relationships of maintenance cost to initial 

capital cost. This represents a weighted analysis in which the individual cost relationships were 

considered for each major plant component or section.

2.7.2.3 Administrative and Support Labor

Labor administration and overhead charges are assessed at a rate of 25 percent of the burdened 

O&M labor.

2.7.2.4 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 as fuel and sorbent were taken from technology-specific 

heat and mass balance diagrams developed for each plant application. Other consumables were 

evaluated on the basis of the quantity required using reference data. 

The quantities for initial fills and daily consumables were calculated on a 100 percent operating 

capacity basis. The annual cost for the daily consumables was then adjusted to incorporate the 

annual plant operating basis, or CF. 

Initial fills of the consumables, fuels and chemicals, are different from the initial chemical 

loadings, which are included with the equipment pricing in the capital cost.

2.7.2.5 Waste Disposal

Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In 

this report fly ash and bottom ash from the PC cases are considered a waste with a disposal cost 

of $27.80/tonne ($25.11/ton). 

2.7.2.6 Co-Products and By-Products 

By-product quantities were also determined similarly to the consumables. However, due to the 

variable marketability of these by-products, specifically gypsum and sulfur, no credit was taken 

for their potential salable value.

It should be noted that by-product credits and/or disposal costs could potentially be an additional 

determining factor in the choice of technology for some companies and in selecting some sites. 

A 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; however, due to the activated carbon injection in the PC cases, the fly ash may not be 

marketable. As stated above, the ash is considered a waste in this report with a concomitant 

disposal cost.
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2.7.3 CO2 Transport and Storage

The cost of CO2 transport and storage (T&S) in a deep saline formation is estimated using the 

FE/NETL CO2 Transport Cost Model and the FE/NETL CO2 Saline Storage Cost Model. 

Additional detail on development of these costs is available in the May 2014 revision of the 

QGESS document “Carbon Dioxide Transport and Storage Costs in NETL Studies.” (27)

T&S costs are reported as first-year costs in $/tonne of CO2, increasing at a nominal rate of 3 

percent per year, consistent with the general inflation rate assumed in NETL’s energy systems 

studies. From the perspective of the CO2 source (e.g., a power plant or other energy conversion 

facility), these costs are treated as a disposal cost for each tonne of CO2 captured during the 

assumed 30-year operational period. From the pipeline and storage site’s perspective, this cost 

represents the first year break-even price they must charge across the 30-year operational period 

to cover all costs and provide the required internal rate of return on equity (IRROE). All costs 

are reported in 2011 dollars.

The Transport Cost Model provides cost estimates for the construction and operation of a 

dedicated pipeline for transporting CO2 from a CO2 source to a CO2 storage site. The pipeline is 

assumed to be buried in the shallow subsurface and the CO2 along the pipeline is assumed to be 

at the temperature of the surrounding soil, typically about 50 o

F. The CO2 entering the pipeline 

at the plant gate is assumed to be at a pressure of 2,200 psig and exiting the pipeline at the 

storage site at a pressure of 1,200 psig. At these pressures, CO2 is a liquid at temperatures from 

approximately -64°F to 88°F.

It is further assumed that the pipeline is 100 km long (62.1 mi) and transports 3.2 million tonnes 

of CO2 each year on average or approximately 8,770 tonnes per day on average. The pipeline is 

designed to operate at 80 percent of its maximum mass flow capacity, so the design maximum 

daily mass flow rate of CO2 is about 10,960 tonnes/day. The model determines the smallest 

standard diameter pipe that can transport this mass flow of CO2 the required distance without 

boosting the pressure. The model also determines the smallest standard diameter pipe that can 

transport this mass flow of CO2 the required distance assuming boost pumps are placed at equal 

intervals along the pipeline to boost the pressure from 1,200 psig to 2,200 psig. The model then 

determines which of these configurations (e.g., no boost pumps, one boost pump, two boost 

pumps, three boost pumps, etc.) is least expensive. The capital and operating costs used in the 

model were taken from the open literature. The capital costs for the pipeline are based on capital 

costs for natural gas pipelines reported in the Oil and Gas Journal with adjustments for the higher 

pressures used in CO2 pipelines.

The financial parameters used in the FE/NETL CO2 Transport Cost Model are:

• Debt to equity ratio: 50%/50%

• Nominal interest rate on debt: 4.5%/year

• Nominal IRROE: 12%

• Escalation rate: 3%

• Tax rate: 38%

• Project contingency factor of 15%

The FE/NETL CO2 Transport Cost Model determines the first year break-even price that needs 

to be charged to transport the CO2 in order to cover all costs including the minimum return on 

equity. The model uses a weighted average cost of capital methodology in determining the 
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break-even first year CO2 price. From the perspective of the CO2 source, the break-even price is 

also the minimum cost of transporting CO2. Transport costs are estimated to be $2.24/tonne in 

2011 dollars.

Storage costs are based on the FE/NETL CO2 Saline Storage Cost Model. This model provides 

detailed cost estimates for the injection and monitoring of CO2 under U.S. Environmental 

Protection Agency regulations for Class VI injection wells as well as monitoring and reporting 

requirements under Subpart RR of the Greenhouse Gas Reporting Rule. 

Inputs to the FE/NETL CO2 Saline Storage Cost Model that have a significant influence on cost 

include financial parameters, the timelines for the various stages of storage and important 

activities occurring in each stage. The financial parameters include:

• Debt to equity ratio: 45%/55%

• Nominal interest rate on debt: 5.5%/year

• Nominal IRROE: 12%

• Escalation rate: 3%

• Financial responsibility requirements for post-injection site care and site closure are met 

by pre-funding a modified trust fund over the period of injection operations

• Project contingency factor of 15% and process contingency factor of 20%

In the FE/NETL CO2 Saline Storage Cost Model, the sequestration process is divided into six 

stages. The timelines and important activities impacting costs for these stages are as follows:

• Regional evaluation and initial site selection: 1 year

• Site characterization: 3 years; four sites undergo site characterization with one successful 

site selected; pore space rights are leased

• Permitting: 2 years; drill, test and complete injection wells

• Operations: 30 years; installation of buildings, surface equipment, monitoring wells and 

other monitoring equipment; comply with permit requirements; fund modified trust fund 

to cover financial responsibility requirements for post-injection site care and site closure

• Post-injection site care and site closure: 50 years; continue monitoring, verification and 

accounting (MVA) per permit; costs are covered by storage site operator’s trust fund

• Long-term stewardship: (This stage is not explicitly included in the model.) The possible 

financial implication of long-term stewardship is included in the model as a statesponsored trust fund that the storage operator pays into during operations

Due to the variances in the geologic formations that make up saline formations across the U.S., 

region-specific storage and monitoring costs are developed to correspond to the plant locations 

used in NETL techno-economic studies of energy conversion facilities. Results from the 

FE/NETL CO2 Saline Storage Cost Model for storage and monitoring costs were aligned with 

the NETL studies by taking four generic plant locations and overlaying them with possible 

sequestration basins from the cost model resulting in the following pairings:

• Midwest plant location – Illinois Basin

• Texas plant location – East Texas Basin

• North Dakota plant location – Williston Basin

• Montana plant location – Powder River Basin
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CO2 storage supply-cost curves were developed for each of the four basins of interest with the 

resulting cost for each basin at 25 gigatonnes (Gt) of potential storage shown in Exhibit 2-15. 

Choosing this point on the supply-cost curves provides a conservative estimate of the storage 

cost since many decades, if not more than a century, will pass before 25 Gt of CO2 is stored in 

any of the four individual basins. For example, 25 Gt of storage would be sufficient for 125 GW 

of coal power with 90 percent CO2 capture operating over 30 years. 

The far right column of Exhibit 2-15 shows the total T&S costs used in NETL system studies for 

each plant location rounded to the nearest whole dollar. Only the $11/tonne value is used in this 

volume of the baseline study report since all cases are located in the Midwest.

Exhibit 2-15 CO2 transport and storage costs

Plant 

Location

Basin Transport

(2011 $/tonne)

Storage Cost at 25 Gt

(2011 $/tonne)

T&S Value for System 

StudiesA (2011$/tonne)

Midwest Illinois

2.24

8.69 11

Texas East Texas 8.83 11

North Dakota Williston 13.95 16

Montana Powder River 21.81 24

AThe sum of transport and storage costs is rounded to the nearest dollar

2.7.4 Cost of CO2 Captured and Avoided

The cost of captured CO2 represents the minimum CO2 plant gate sales price that will incentivize 

carbon capture in lieu of a defined reference non-capture plant. The cost of captured CO2 is 

calculated using the following formula:

CCCCCC oo 2 CCCCCC CCCCCC = ( CCCCCC − NNNNNN CCCCCC)

2 CCCCCC CCCCCC

The cost of CO2 avoided represents the minimum CO2 emissions price that will, when applied to 

both the capture and non-capture plant, incentivize carbon capture in lieu of a defined reference 

non-capture plant. The cost of CO2 avoided is calculated using the following formula:

CCCCCC oo 2 AA AA = ( CCCCCC wwwwwwh TT& − NNNNNN CCCCCC)

2 EEEE EE NNNNNN CCCCCC − 2 EEEE EE CCCCCC

where:

• CCS – the capture plant for which the cost of CO2 captured/avoided is being calculated

• Non-CCS – the reference non-capture plant, as described below

• COE – the cost of electricity, reported in $/MWh

o The CCS plant includes compression to 2,215 psia

o For CO2 Captured, the COE excludes transportation and storage (T&S) costs

o For CO2 Avoided, the COE includes T&S costs

• CO2 Captured – the rate of CO2 captured, reported in tonne/MWh

• CO2 Emissions – the rate of CO2 emitted out the stack, reported in tonne/MWh

For today’s greenfield coal with CCS plants, the reference non-capture plant used to calculate the 

cost of captured and avoided CO2 is a supercritical pulverized coal (SCPC) plant without 

capture. For a greenfield natural gas-based power system, the reference plant used to calculate 

the cost of captured and avoided CO2 is a non-capture natural gas-based plant.
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3 Pulverized Coal Rankine Cycle Plants 

Four PC fired Rankine cycle power plant configurations were evaluated and the results are 

presented in this section. Each design is based on a market-ready technology that is assumed to 

be commercially available in time for the plant startup date. All designs employ a one-on-one 

configuration comprised of a state-of-the art PC steam generator firing Illinois No. 6 coal and a 

steam turbine. 

The PC cases are evaluated with and without CO2 capture on a common 550 MWe net basis. 

The designs that include CO2 capture have a larger gross unit size to compensate for the higher 

auxiliary loads. The constant net output sizing basis is selected because it provides for a 

meaningful side-by-side comparison of the results. The boiler and steam turbine industry ability 

to match unit size to a custom specification has been commercially demonstrated enabling 

common net output comparison of the PC cases in this report. 

Steam conditions for the Rankine cycle cases were selected based on a survey of boiler and 

steam turbine original equipment manufacturers (OEM), who were asked for the most advanced 

steam conditions that they would guarantee for a commercial project in the US with subcritical 

and SC PC units rated at nominal 550 MWe net capacities and firing Illinois No. 6 coal. (28) 

Based on the OEM responses, the following single-reheat steam conditions were selected for the 

study:

 For subcritical cases (B11A and B11B) – 16.5 MPa/566°C/566°C 

(2,400 psig/1,050°F/1,050°F)

 For SC cases (B12A and B12B) – 24.1 MPa/593°C/593°C (3,500 psig/1,100°F/1,100°F)

Steam temperature selection for boilers depends upon fuel corrosiveness. Most of the contacted 

OEMs were of the opinion that the steam conditions in this range would be limited to low sulfur 

coal applications (such as PRB). Their primary concern is that elevated temperature operation 

while firing high sulfur coal (such as Illinois No. 6) would result in an exponential increase of 

the material wastage rates of the highest temperature portions of the superheater and reheater 

(RH) due to coal ash corrosion, requiring pressure parts replacement outages approximately 

every 10 or 15 years. This cost would offset the value of fuel savings and emissions reduction 

due to the higher efficiency. In addition, three of the most recently built SC units in North

America have steam cycles similar to this report’s design basis, namely James E. Rogers Energy 

Complex in North Carolina, which started operations in 2012 (27.0 MPa/568°C/579°C [3,922

psia/1,055°F/1,075°F]) and Prairie State Energy Campus units 1 and 2, which also started 

operation in 2012 (26.2 MPa/568°C/568°C [3,800 psig/1,055°F/1,055°F]).

The evaluation basis details, including site ambient conditions, fuel composition and the 

emissions control basis, are provided in Section 2 of this report.

3.1 PC Common Process Areas

The PC 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 section 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.
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3.1.1 Coal, Activated Carbon, and Sorbent Receiving and Storage

The function of the Coal Receiving and Storage system is to unload, convey, prepare, and store 

the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and 

coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage 

silos. The system is designed to support short-term operation at the 5 percent over 

pressure/valves wide open (OP/VWO) condition (16 hours) and long-term operation of 90 days 

or more at the maximum continuous rating (MCR).

The scope of the sorbent receiving and storage system includes truck roadways, turnarounds, 

unloading hoppers, conveyors and the day storage bin.

Operation Description - The coal is delivered to the site by 100-car unit trains comprised of 91 

tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the 

coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. 

The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors 

with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which 

transfer the coal to either the long-term storage pile or to the reclaim area. The conveyor passes 

under a magnetic plate separator to remove tramp iron and then to the reclaim pile.

Coal from the reclaim pile is fed by two vibratory feeders, located under the pile, onto a belt 

conveyor, which transfers the coal to the coal surge bin located in the crusher tower. The coal is 

reduced 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.

Limestone 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.

Non-halogenated powdered activated carbon (PAC) is delivered to the site using 18 tonne (20 

ton) trucks. The trucks pneumatically unload into a storage silo where a feeder hopper transfers 

the PAC to a screw feeder that conveys the PAC into the drop tube. PAC is fed through the drop 

tube directly into the eductor suction port. The carbon is transferred from the eductor suction 

port through the piping system and injected through a distribution of lances across the flue gas 

ductwork upstream of the baghouse.

Hydrated lime is delivered and distributed in a manner very similar to that of the PAC: the 

sorbent is contained in the main storage silo and fed to a weigh hopper for conveying through 

transport piping to the sorbent distribution manifold upstream of the air preheater. 

3.1.2 Steam Generator and Ancillaries

The steam generator for the subcritical PC plants is a drum-type, wall-fired, balanced draft, 

natural circulation, totally enclosed dry bottom furnace, with superheater, reheater, economizer 

and air preheater.

The steam generator for the SC 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, 

reheater, economizer, and air preheater.
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The combustion systems for both subcritical and SC steam conditions are equipped with LNBs 

and OFA. It is assumed for the purposes of this report that the power plant is designed for 

operation as a base-load unit but with some consideration for daily or weekly cycling.

3.1.2.1 Scope

The steam generator includes the following for both subcritical and SC PCs, except where 

otherwise indicated: 

 Drum-type evaporator 

(subcritical only)

 Economizer  OFA system

 Once-through type steam 

generator (SC only)

 Spray type desuperheater  Forced draft (FD) fans

 Startup circuit, including 

integral separators (SC 

only)

 Soot blower system  Primary air (PA) fans

 Water-cooled furnace, 

dry bottom

 Air preheaters 

(Ljungstrom type)

 Induced draft (ID) fans

 Two-stage superheater  Coal feeders and 

pulverizers

 Reheater (RH)  Low NOx Coal burners 

and light oil igniters/ 

warm-up system

The following subsections describe the operation of the steam generator.

3.1.2.2 Feedwater and Steam

For the subcritical steam system feedwater (FW) enters the economizer, recovers heat from the 

combustion gases exiting the steam generator, and then passes to the boiler drum, from where it 

is distributed to the water wall circuits enclosing the furnace. After passing through the lower 

and upper furnace circuits and steam drum in sequence, the steam passes through the convection 

enclosure circuits to the primary superheater and then to the secondary superheater.

The steam then exits the steam generator en route to the high pressure (HP) turbine. Steam from 

the HP turbine returns to the steam generator as cold reheat and returns to the intermediate 

pressure (IP) turbine as hot reheat. 

For the SC steam system FW enters the bottom header of the economizer and passes upward 

through the economizer tube bank, through stringer tubes, which support the primary 

superheater, and discharges to the economizer outlet headers. From the outlet headers, water 

flows to the furnace hopper inlet headers via external downcomers. Water then flows upward 

through the furnace hopper and furnace wall tubes. From the furnace, water flows to the steam 

water separator. During low load operation (operation below the 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 convection 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 then flows to the final superheater and on to the outlet pipe 
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terminal. Two stages of spray attemperation are used to provide tight temperature control in all 

high temperature sections during rapid load changes.

Steam returning from the turbine passes through the primary reheater surface, then through 

crossover piping containing inter-stage attemperation. The crossover piping feeds the steam to 

the final reheater banks and then out to the turbine. Inter-stage attemperation is used to provide 

outlet temperature control during load changes.

3.1.2.3 Air and Combustion Products

Combustion air from the FD fans is heated in Ljungstrom type air preheaters, recovering heat 

energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as 

secondary air. Air for conveying PC to the burners is supplied by the PA fans. This air is heated 

in the Ljungstrom type air preheaters to permit drying 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 reheater 

sections. The gases then pass through the economizer and air preheater. The gases exit the 

steam generator at this point and flow to the SCR reactor, dry sorbent injection (DSI) manifold, 

activated carbon injection (ACI) manifold, fabric filter, ID fan, FGD system, and stack.

3.1.2.4 Fuel Feed

The crushed Illinois No. 6 bituminous coal is fed through feeders to each of the mills 

(pulverizers), where its size is reduced to approximately 72 percent passing 200 mesh and less 

than 0.5 percent remaining on 50 mesh. (29) 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.

3.1.2.5 Ash Removal

The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. 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 grinder to an ash sluice system for 

conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite 

disposal. The description of the balance of the bottom ash handling system is presented in 

Section 3.1.11. The steam generator incorporates fly ash hoppers under the economizer outlet 

and air preheater outlet.

3.1.2.6 Burners

A boiler of this 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.
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3.1.2.7 Dry sorbent Injection

The hydrated lime injection manifold is located directly before the air preheaters. This SO3

control system is discussed in detail in Section 3.1.6.

3.1.2.8 Air Preheaters

Each steam generator is furnished with two vertical-shaft Ljungstrom regenerative type air 

preheaters. These units are driven by electric motors through gear reducers.

3.1.2.9 Soot Blowers

The soot-blowing system utilizes an array of 50 to 150 retractable nozzles and lances 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 soot blowers through their cycles.

3.1.3 NOx Control System

The plants are designed to achieve the environmental target of 0.70 lb/MWh-gross. Two 

measures are taken to reduce the NOx. The first is a combination of LNBs and the introduction 

of staged OFA in the boiler. The LNBs and OFA reduce the emissions to about 0.5 lb/MMBtu. 

The second measure taken to reduce the NOx emissions is the installation of an SCR system 

prior to the air heater. SCR uses ammonia and a catalyst to reduce NOx to N2 and H2O. The 

SCR system consists of three subsystems: reactor vessel, ammonia storage and injection, and 

gas flow control. The SCR system is designed for 83-85 percent reduction with 2 ppmv 

ammonia slip at the end of the catalyst life. 

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

catalyst.

Selective non-catalytic reduction (SNCR) was considered for this application. However, with 

the installation of the LNBs and OFA system, 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 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. Because of 

the catalyst used, SCR can achieve higher efficiencies with lower concentrations of NOx.

3.1.3.1 SCR Operation Description

The reactor vessel is designed to allow proper retention time for the ammonia to contact the NOx 

in the boiler exhaust gas. Ammonia is injected into the gas immediately prior to entering the 

reactor vessel. The catalyst contained in the reactor vessel enhances the reaction between the 

ammonia and 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/titaniumbased catalysts is 260°C (500°F) to 455°C (850°F). The boiler is equipped with an 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 ammonia storage and injection system consists of the unloading facilities, bulk storage tank, 

vaporizers, dilution air skid, and injection grid.
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The flue gas flow control consists of ductwork, dampers, and flow straightening devices required 

to route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass 

and associated dampers for low load temperature control are also included.

3.1.4 Activated Carbon Injection

The PAC injection manifold is located directly before the baghouse. (30) This system will be 

discussed in detail in Section 3.1.6.

3.1.5 Particulate Control

The fabric filter (or baghouse) consists of two separate single-stage, in-line, multi-compartment 

units. Each unit is of high (0.9-1.5 m/min [3-5 ft/min]) air-to-cloth ratio design with a pulse-jet 

on-line cleaning system. The ash is collected on the outside of the bags, which are supported by 

steel cages. The dust cake is removed by a pulse of compressed air. The bag material is 

polyphenylensulfide (PPS) with intrinsic Teflon Polytetrafluoroethylene (PTFE) coating. (31) 

The bags are rated for a continuous temperature of 180°C (356°F) and a peak temperature of 

210°C (410°F). Each compartment contains a number of gas passages with filter bags, and 

heated ash hoppers supported by a rigid steel casing. The fabric filter is provided with necessary 

control devices, inlet gas distribution devices, insulators, inlet and outlet nozzles, expansion 

joints, and other items as required.

The use of ACI and DSI increases the calcium content of the fly ash and adds an additional 

burden to the fabric filter. The addition of calcium is not expected to increase the leaching of 

trace metals from the fly ash significantly. The ACI and DSI systems increase the total amount 

of particulate matter by approximately 26 percent.

Fly ash from bituminous-fired plants (Class F fly ash) is sometimes sold for use as filler material 

in concrete mixtures. The use of Class F fly ash for concrete manufacture is not as common as 

the use of Class C fly ash (from high-calcium-containing coals); the latter is more valuable as a 

replacement for Portland cement in concrete mixtures. Class F fly ash must have a low unburned 

carbon content to be used in cement mixtures. The inclusion of activated carbon and hydrated 

lime (or, rather, the CaSO4 reaction product) will render the fly ash unsuitable for use in concrete 

mixtures.

3.1.6 Mercury Removal6

Mercury removal is partially achieved through flue gas reactions between mercury and available 

halogens and carbon.

Halogens in the coal, primarily chlorine, influence the fraction of oxidized mercury that is 

formed as the flue gas passes through the SCR and air preheater. Therefore, the overall mercury 

removal in control devices such as fabric filters and wet scrubbers is also influenced by halogens 

in the coal (concentrations of chlorine greater than 500 ppmv do not appear to have any 

additional impact on the rate of mercury oxidation (32)). 

The presence of an SCR can impact the amount of SO3 or H2SO4 that is present in the flue gas. 

Sulfuric acid can impact the ability of unburned carbon to adsorb mercury. Based on the 

 

6 Much of the text, descriptions, and images within this section were sourced, with permission, from a quote provided by ADA-ES to NETL, unless 

otherwise noted. The information relates to a mercury control system designed by ADA-ES. The quote also provided all images credited to them.
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assumptions and design bases of the PC cases in this study, the estimated SO3 concentration at 

the inlet of the air preheater, without mitigation, is 59 ppmvd. At these levels, low mercury 

removal is expected from either unburned carbon or added activated carbon. Therefore, dry

sorbent injection is included in the PC plant designs in order to reduce the SO3 levels to 

approximately 2 ppmvd, as discussed in Section 3.1.6.1.

The rate of mercury oxidation is also affected by the ammonia concentration. Since the SCR is 

operated more aggressively for nitrogen oxide (NOx) control, the ammonia levels increase and 

the fraction of oxidized mercury decreases. (33)

Unburned carbon can act as a catalyst to promote mercury oxidation as well as to adsorb 

mercury. In general, sufficient unburned carbon is present at plants firing bituminous coals such 

that one or both of these factors will have a significant influence on the overall mercury removal 

achieved in the system. (34)

The presence of unburned carbon and/or activated carbon on the fabric filter surface, in 

combination with relatively high levels of hydrogen halides (e.g. HCl) in the flue gas, is expected 

to result in high levels of oxidized mercury exiting the fabric filter. Oxidized mercury is water 

soluble and should be readily removed in the wet scrubber. Depending on the chemistry in the 

scrubber, some of the captured mercury may be reduced back to the relatively insoluble 

elemental form, which will then be re-emitted from the scrubber. The control systems employed 

in this study minimize the amount of mercury entering the scrubber, which reduces the risk of 

exceeding the emission limit. Even with low levels entering the scrubber, there is a risk of 

periodic spikes in mercury at the stack if mercury collected and concentrated in a recirculating 

scrubber is released. However, to a large extent, the periodic surges can be managed through 

careful operations and, because the regulations specify a 30- or 90-day averaging period, the 

impact of the surges on compliance can be minimized. 

EPA used a statistical method to calculate the Hg co-benefit capture from units using a “best 

demonstrated technology” approach, which for bituminous coals was considered to be a 

combination of a fabric filter and an FGD system. The statistical analysis resulted in a co-benefit 

capture estimate of 86.7 percent with an efficiency range of 83.8 to 98.8 percent. (35) EPA’s 

documentation for their Integrated Planning Model (IPM) provides mercury emission 

modification factors (EMF) based on 190 combinations of boiler types and control technologies. 

The EMF is simply one minus the removal efficiency. 

For PC boilers (as opposed to cyclones, stokers, fluidized beds, and ‘others’) with a fabric filter, 

SCR and wet FGD, the EMF is 0.1, which corresponds to a removal efficiency of 90 percent;

(36) the average reduction in total Hg emissions developed from EPA’s Information Collection 

Request (ICR) data on U.S. coal-fired boilers using bituminous coal, fabric filters, and wet FGD 

is 98 percent. (37) The referenced sources bound the co-benefit Hg capture for bituminous coal 

units employing SCR, a fabric filter, and a wet FGD system between 83.8 and 98 percent. It was 

assumed that the co-benefit potential of the equipment utilized in the PC cases of this report is 90 

percent, as it is near the mid-point of the previously mentioned range, and it also matches the 

value used by EPA in their IPM.

The potential co-benefit capture of the systems utilized in the PC cases does not satisfy the 

requirements of the mercury emission limit, therefore, a cost and performance estimate was 

obtained from ADA-ES, which stated that activated carbon injection (ACI) and dry sorbent 

injection (DSI) would be required. 
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Location of the DSI relative to the air preheater impacts the mercury removal efficiency of the 

ACI system. The mercury limit is assumed to be achievable with a DSI location downstream of 

the air preheater; however, the upstream location of the air preheater allows for a lower flue gas 

outlet temperature from the air preheater, which improves plant performance as well as increases 

the carbon efficiency by up to 25 percent.

3.1.6.1 Dry Sorbent Injection

Illinois No. 6 coal contains relatively high levels of sulfur (2.82 wt%). ADA-ES estimated that 

nominally 36 ppmvd of sulfur trioxide (SO3) will be present at the outlet of the air preheater 

resulting from coal combustion and oxidation across the SCR. 

SO3 can be detrimental to the effectiveness of both unburned carbon and activated carbon for 

mercury control, as evidenced by the results from a testing program conducted at the Mercury 

Research Center. The test using an ESP-configured system with an activated carbon injection 

rate of 10 lb/MMacf upstream of the air preheater, which showed that at SO3 levels above 20 

ppm, less than 50 percent mercury removal was achieved. At SO3 levels above 10 and 3 ppm, 

less than 70 and 80 percent mercury removal was achieved, respectively. (38)

Hydrated lime injection was selected for SO3 control and located upstream of the air preheater, 

which allows the air preheater to operate at a lower downstream flue gas temperature (290°F) 

and increases the overall plant efficiency compared to a system with no DSI or DSI downstream 

of the air preheater. Without SO3 mitigation, the downstream flue gas temperature must be 

maintained above the acid dew point temperature (approximately 337°F). 

Operation Description – The DSI and ACI injection systems are nearly identical, therefore, the 

description provided below pertains to both systems.

As shown in Exhibit 3-1, the DSI system is based on dilute-phase, pneumatic conveying of 

hydrated lime at a metered rate from a bulk storage silo to the flue gas ductwork where it mixes 

with the flue gas and reacts with the SO3 to form CaSO4, which is captured in the fabric filter. 

The hydrated lime is delivered in 40,000 lb batches by self-unloading pneumatic trucks. The 

hydrated lime is unloaded from the truck via an on-board compressor into the dry, welded-steel 

storage silo where the displaced air is vented through a silo vent filter. The hydrated lime level 

in the silo is measured by system instrumentation. A combination of compressed air fluidization 

valves and nozzles is used to pulse compressed air, promoting mass flow of the hydrated lime

out of the silo chisel-type cone.

Fluidized hydrated lime is then transferred from the silo by a rotary valve into the feeder hopper 

where it is temporarily stored until conveyed by the screw feeder into the drop tube. The speed 

of the screw feeder determines the feed rate into the drop tube. Hydrated lime is fed through the 

drop tube directly into the eductor suction port.

Motive air, provided by low-pressure blowers and fed into the eductors, produces a vacuum at 

the suction port. This helps draw the hydrated lime and air into the mixing zone directly 

downstream of the eductor discharge. The hydrated lime is transported through the piping 

system and is distributed to an array of injection lances specifically designed to disperse the 

hydrated lime across the cross section of the flue gas ductwork upstream of the air preheater.

The DSI system is monitored and controlled by the distributed control system (DCS) to adjust to 

varying demand.
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Exhibit 3-1 Typical injection process flow diagram

Source: Permission granted from ADA-ES

3.1.6.2 Activated Carbon Injection

ADA-ES conducted a mercury control trial using ACI and trona-based DSI on a unit with an 

installed fabric filter and high (greater than 20 ppm) levels of SO3 in the flue gas. For this test, 

the flue gas temperature was 380°F. Results from this test are presented in Exhibit 3-2 and 

indicate that high mercury removal can be achieved when alkaline materials are present with 

activated carbon on a bag surface (improved performance is expected at lower temperatures). 
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Exhibit 3-2 Mercury removal across a fabric filter during a high-sulfur bituminous test

Source: Permission granted from ADA-ES

In order to meet the mercury emission limit, PAC is injected at a rate of approximately 2.7

lb/MMacf in all PC cases.

Operation Description – The ACI system’s injection manifold is located directly upstream of 

the fabric filter and is otherwise identical to that of the DSI system and is described in Section 

3.1.6.1.

3.1.7 Flue Gas Desulfurization

The FGD system is a wet limestone forced oxidation positive pressure absorber non-reheat unit, 

with wet-stack, and gypsum production. The function of the FGD system is to scrub the boiler 

exhaust gases to remove the SO2 prior to release to the environment, or entering into the Carbon 

Dioxide Removal (CDR) facility. Sulfur removal efficiency is 98 percent in the FGD unit for all 

cases. For Cases B11B and B12B with CO2 capture, the SO2 content of the scrubbed gases must 

be further reduced to approximately 1 ppmv to minimize formation of amine heat stable salts 

(HSS) during the CO2 absorption process. The CDR unit includes a polishing scrubber to reduce 

the flue gas SO2 concentration from about 37 ppmv at the FGD exit to the required level prior to 

the CDR absorber. The scope of the FGD system is from the outlet of the ID fans to the stack 

inlet (Cases B11A and B12A) or to the CDR process inlet (Cases B11B and B12B). The system 

description is divided into three sections:

• Limestone Handling and Reagent Preparation

• FGD Scrubber

• Byproduct Dewatering

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8

Hg Removal (%)

Inj Concentration (lb/Mmacf)

380F, 10 to 20 ppm SO3

380F, Trona
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3.1.7.1 Limestone Handling and Reagent Preparation System

The function of the limestone reagent preparation system is to grind and slurry the limestone 

delivered to the plant. The scope of the system is from the day bin up to the limestone feed 

system. The system is designed to support continuous base load operation. 

Operation Description - Each day bin supplies a 100 percent capacity ball mill via a weigh 

feeder. The wet ball mill accepts the limestone and grinds the limestone to 90 to 95 percent 

passing 325 mesh (44 microns). Water is added at the inlet to the ball mill to create limestone 

slurry. The reduced limestone slurry is then discharged into a mill slurry tank. Mill recycle 

pumps, two per tank, pump the limestone water slurry to an assembly of hydrocyclones and 

distribution boxes. The slurry is classified into several streams, based on suspended solids 

content and size distribution.

The hydrocyclone underflow with oversized limestone is directed back to the mill for further 

grinding. The hydrocyclone overflow with correctly sized limestone is routed to a reagent 

storage tank. Reagent distribution pumps direct slurry from the tank to the absorber module.

3.1.7.2 FGD Scrubber

The flue gas exiting the air preheater section of the boiler passes through one of two parallel 

fabric filter units, then through the ID fans and into the one 100 percent capacity absorber 

module. The absorber module is designed to operate with counter-current flow of gas and 

reagent. Upon entering the bottom of the absorber vessel, the gas stream is subjected to an initial 

quenching spray of reagent. The gas flows upward through the spray zone, which provides 

enhanced contact between gas and reagent. Multiple spray elevations with header piping and 

nozzles maintain a consistent reagent concentration in the spray zone. Continuing upward, the 

reagent-laden gas passes through several levels of moisture separators. These consist of 

chevron-shaped vanes that direct the gas flow through several abrupt changes in direction, 

separating the entrained droplets of liquid by inertial effects. The scrubbed flue gas exits at the 

top of the absorber vessel and is routed to the plant stack or CDR process.

The scrubbing slurry falls to the lower portion of the absorber vessel, which contains a large 

inventory of liquid. Oxidation air is added to promote the oxidation of calcium sulfite contained 

in the slurry to calcium sulfate (gypsum). Multiple agitators operate continuously to prevent 

settling of solids and enhance mixture of the oxidation air and the slurry. Recirculation pumps 

recirculate the slurry from the lower portion of the absorber vessel to the spray level. Spare 

recirculation pumps are provided to ensure availability of the absorber.

The absorber chemical equilibrium is maintained by continuous makeup of fresh reagent, and 

blowdown of byproduct solids via the bleed pumps. A spare bleed pump is provided to ensure 

availability of the absorber. The byproduct solids are routed to the byproduct dewatering system. 

The circulating slurry is monitored for pH and density.

This FGD system is designed for wet stack operation. Scrubber bypass or reheat, which may be 

utilized at some older facilities to ensure the exhaust gas temperature is above the saturation 

temperature, is not employed in this reference plant design because new scrubbers have 

improved mist eliminator efficiency, and detailed flow modeling of the flue interior enables the 

placement of gutters and drains to intercept moisture that may be present and convey it to a 

drain. Consequently, raising the exhaust gas temperature above the FGD discharge temperature 

of 56°C (133°F) is not necessary.
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3.1.7.3 Byproduct Dewatering

The function of the byproduct dewatering system is to dewater the bleed slurry from the FGD 

absorber modules. The dewatering process selected for this plant is gypsum dewatering 

producing wallboard grade gypsum. The scope of the system is from the bleed pump discharge 

connections to the gypsum storage pile. 

Operation Description - The recirculating reagent in the FGD absorber vessel accumulates 

dissolved and suspended solids on a continuous basis as byproducts from the SO2 absorption 

process. Maintenance of the quality of the recirculating slurry requires that a portion be 

withdrawn and replaced by fresh reagent. This is accomplished on a continuous basis by the 

bleed pumps pulling off byproduct solids and the reagent distribution pumps supplying fresh 

reagent to the absorber. 

Gypsum (calcium sulfate) is produced by the injection of oxygen into the calcium sulfite 

produced in the absorber tower sump. The bleed from the absorber contains approximately 

20 wt% gypsum. The absorber slurry is pumped by an absorber bleed pump to a primary 

dewatering hydrocyclone cluster. The primary hydrocyclone performs two process functions. 

The first function is to dewater the slurry from 20 wt% to 50 wt% solids. The second function of 

the primary hydrocyclone is to perform a CaCO3 and CaSO4•2H2O separation. This process 

ensures a limestone stoichiometry in the absorber vessel of 1.10 and an overall limestone 

stoichiometry of 1.05. This system reduces the overall operating cost of the FGD system. The 

underflow from the hydrocyclone flows into the filter feed tank, from which it is pumped to a 

horizontal belt vacuum filter. Two 100 percent filter systems are provided for redundant 

capacity.

3.1.7.4 Hydrocyclones

The hydrocyclone is a simple and reliable device (no moving parts) designed to increase the 

slurry concentration in one step to approximately 50 wt%. This high slurry concentration is 

necessary to optimize operation of the vacuum belt filter.

The hydrocyclone feed enters tangentially and experiences centrifugal motion so that the heavy 

particles move toward the wall and flow out the bottom. Some of the lighter particles collect at 

the center of the cyclone and flow out the top. The underflow is thus concentrated from 20 wt% 

at the feed to 50 wt%.

Multiple hydrocyclones are used to process the bleed stream from the absorber. The 

hydrocyclones are configured in a cluster with a common feed header. The system has two 

hydrocyclone clusters, each with five 15 cm (6 inch) diameter units. Four cyclones are used to 

continuously process the bleed stream at design conditions, and one cyclone is spare.

Cyclone overflow and underflow are collected in separate launders. The overflow from the 

hydrocyclones still contains about 5 wt% solids, consisting of gypsum, fly ash, and limestone 

residues and is sent back to the absorber. The underflow of the hydrocyclones flows into the 

filter feed tank from where it is pumped to the horizontal belt vacuum filters.

3.1.7.5 Horizontal Vacuum Belt Filters

The secondary dewatering system consists of horizontal vacuum belt filters. The preconcentrated gypsum slurry (50 wt%) is pumped to an overflow pan through which the slurry 

flows onto the vacuum belt. As the vacuum is pulled, a layer of cake is formed. The cake is 
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dewatered to approximately 90 wt% solids as the belt travels to the discharge. At the discharge 

end of the filter, the filter cloth is turned over a roller where the solids are dislodged from the 

filter cloth. This cake falls through a chute onto the pile prior to the final byproduct uses. The 

required vacuum is provided by a vacuum pump. The filtrate is collected in a filtrate tank that 

provides surge volume for use of the filtrate in grinding the limestone. Filtrate that is not used 

for limestone slurry preparation is returned to the absorber.

3.1.8 Carbon Dioxide Recovery Facility7

A CDR facility is used, along with compressors and a dryer, in Cases B11B and B12B to remove 

90 percent of the CO2 in the flue gas exiting the FGD unit. The facility then purifies it and 

compresses it to a supercritical condition. The flue gas exiting the FGD unit contains about 

1 percent more CO2 than the raw flue gas because of the CO2 liberated from the limestone in the 

FGD absorber vessel. The CDR is comprised of the pre-scrubber, CO2 absorber, CO2 stripper, 

and absorbent purification unit. 

The CO2 recovery process for Cases B11B and B12B is based on data given by Shell Cansolv in 

2012. A typical flowsheet is shown in Exhibit 3-3. This process is designed to recover highpurity CO2 from low pressure (LP) streams that contain oxygen, such as flue gas from coal-fired 

power plants, CT exhaust gas, and other waste gases. 

3.1.8.1 Pre-scrubber Section

The flue gas from the FGD section is sent through a booster fan to drive the gas through 

downstream equipment starting with the pre-scrubber inlet cooling section. The cooler is 

operated as a direct contact cooler that saturates and sub-cools the flue gas. Saturation and subcooling are beneficial to the system as they improve the amine absorption capacity, thus reducing 

amine circulation rate. After the cooling section, the flue gas is scrubbed with caustic in the prescrubber sulfur polishing section. This step reduces the SO2 concentration entering the CO2

absorber column to 1 ppmv, and also reduces the NO2 concentration by 50 percent. 

3.1.8.2 CO2 Absorber Section

The Cansolv absorber is a single, rectangular, acid resistant, brick-lined concrete structure 

containing stainless-steel packing. 

There are four packing sections in the Cansolv absorber. The first three are used for CO2

absorption, and the final section is a water-wash section. This specific absorber geometry and 

design provides several cost advantages over more traditional column configurations while 

maintaining equivalent or elevated performance. The flue gas enters the absorber and flows 

counter-current to the Cansolv solvent. Approximately 90 percent of the inlet CO2 is absorbed 

into the lean solvent, and the remaining CO2 exits the main absorber section and enters the 

water-wash section of the absorber. Prior to entering the bottom packing section, hot amine is 

collected, removed, and pumped through a heat exchanger to provide intercooling and limit 

water losses. The cooled amine is then sent back to the absorber just above the final packing 

section. 

 

7 Much of the text and descriptions within this section were sourced, with permission, from data provided by Shell Cansolv to NETL, unless 

otherwise noted. The information relates to a CO2 removal system designed by Shell Cansolv. 
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Exhibit 3-3 Cansolv CO2 capture process typical flow diagram

Source: NETL

The water-wash section at the top of the absorber is used to remove volatiles or entrained amine 

from the flue gas, as well as to condense and retain water in the system. The wash water is 

removed from the bottom of the wash section, pumped through a heat exchanger, and is then reintroduced at the top of the wash section. This wash water is made up of recirculated wash water 

as well as water condensed from the flue gas. The flue gas treated in the water-wash section is 

then released to atmosphere. 

3.1.8.3 Amine Regeneration Section

The rich amine is collected at the bottom of the absorber and pumped through a rich/lean heat 

exchanger where heat from the lean amine is exchanged with the rich amine. The Cansolv 

rich/lean solvent heat exchanger is a stainless steel plate and frame type with a 5°C (9°F) 

approach temperature. Additional options for heat integration in the Cansolv system include a 

second heat exchanger after the rich/lean solvent heat exchanger where low-pressure steam 

condensate from the regenerator reboiler or intermediate-pressure steam condensate from the 

amine purification section may be used to further pre-heat the rich solvent. The rich amine 

continues and enters the stripper near the top of the column. The stripper is a stainless steel 

vessel using structured stainless steel packing. The regenerator reboiler uses low-pressure steam 

to produce water vapor that flows upwards, counter-current to the rich amine flowing 

downwards, and removes CO2 from the amine. The Cansolv regenerator reboiler is a stainless 

steel plate and frame type with a 3°C (5°F) approach temperature. Lean amine is collected in the 

stripper bottoms and flows to a flash vessel where water vapor is released. The water vapor is 

then recompressed and recycled to the bottom of the stripper to continue stripping CO2. The lean 

amine is then pumped through the same rich/lean heat exchanger to exchange heat from the lean 

amine to the rich amine and continues on to the lean amine tank. 

The water vapor and stripped CO2 flow up the stripper where they are contacted with recycled 

reflux to condense a portion of the vapor. The remaining gas continues to the condenser where it 

is partially condensed. The two-phase mixture then flows to a reflux accumulator where the CO2

product gas is separated and sent to the CO2 compressor at approximately 30 psia, and the 

remaining water is collected and returned to the stripper as reflux. 
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The flow of steam to the regenerator reboiler is proportional to the rich amine flow to the 

stripper; however, the flow of low-pressure steam is also dependent on the stripper top 

temperature. For the steady-state case described here, the low-pressure steam requirement for 

the reboiler only is calculated as approximately 1,100 Btu/lb CO2 for the Cansolv process, which 

is satisfied by extracting steam from the crossover pipe between the IP and LP sections of the 

steam turbine.

3.1.8.4 Amine Purification Section

The purpose of the amine purification section is to remove a portion of the HSS as well as ionic 

and non-ionic amine degradation products. The Cansolv amine purification process is performed 

in batch.

3.1.8.4.1 Ion Exchange

The HSS form due to residual amounts of NO2 and SO2 in the flue gas. The acids formed by the 

oxidative degradation of the amine, as well as through reactions with NO2 and SO2, neutralize a 

portion of the amine making it inactive to further CO2 absorption. Therefore, excess HSS are

removed via an ion exchange (resin bed contained within a column).

3.1.8.4.2 Thermal Reclaimer

The ionic and non-ionic amine degradation products are removed in the thermal reclaimer by 

distilling a slipstream – taken from the treated amine exiting the ion exchanger – under vacuum 

conditions to separate the water and amine. This process leaves the non-ionic degradation 

products in the bottom, which are pumped to a storage tank, diluted and cooled with process 

water, and then disposed. A portion of the condensed amine and water is returned to the

absorber column with the rest being sent to the lean amine tank.

3.1.9 Gas Compression and Drying System

The compression system was modeled based on vendor supplied data, similar in design to that 

presented in the Carbon Capture Simulation Initiative’s (CCSI) paper “Centrifugal Compressor 

Simulation User Manual.” (39) The design was assumed to be an 8-stage front-loaded 

centrifugal compressor with stage discharge pressures presented in Exhibit 3-4.

Exhibit 3-4 CO2 compressor interstage pressures

Stage Outlet Pressure, 

MPa (psia)

Stage Pressure 

Ratio

1 0.44 (64) 2.23

2 0.92 (133) 2.14

3 1.72 (250) 1.90

4 3.04 (441) 1.78

5 4.80 (696) 1.59

6 6.97 (1,011) 1.53

7 10.36 (1,502) 1.49

8 15.27 (2,215) 1.48

Power consumption for this large compressor was estimated assuming a polytropic efficiency of 

89 percent and a mechanical efficiency of 97 percent for the first 7 stages and a polytropic 

efficiency of 91 percent for the final stage. 
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Intercooling is included for each stage with the first three stages including water knockout. 

There is no aftercooler included in this design. 

A triethylene glycol (TEG) dehydration unit is included between stages 4 and 5, operating at 

3.03 MPa (439 psia), to reduce the moisture concentration of the CO2 stream to 300 ppmw. The 

dryer was designed based on a paper published by the Norwegian University of Science and 

Technology (NTNU) (40) titled “Conditioning of CO2 Coming from a CO2 Capture Process for 

Transport and Storage Purposes.”

In an absorption process, such as in a TEG dehydration unit, the gas containing water flows up 

through a column while the TEG flows downward. The solvent binds the water by physical 

absorption; water is more soluble in the solvent than in other components of the gas mixture. 

The dried gas exits at the top of the column, while the solvent rich in water exits at the bottom. 

After depressurization to around atmospheric pressure, the solvent is regenerated by heating it 

and passing it through a regeneration column where the water is boiled off. Depending on 

configuration a TEG unit can reduce water concentrations to below 10 ppm. (41)

Several alternatives to rejecting the heat of CO2 compression to cooling water were investigated 

in a separate study. (42) The first alternative consisted of using a portion of the heat to pre-heat 

BFW while the remaining heat was still rejected to cooling water. This configuration resulted in 

an increase in net plant efficiency of 0.3 percentage points (absolute). The second alternative 

modified the CO2 compression intercooling configuration to enable integration into a LiBr-H2O 

absorption refrigeration system, where water is the refrigerant. In the CO2 compression section, 

the single intercooler between each compression stage was replaced with one kettle reboiler and 

two counter-current shell and tube heat exchangers. The kettle reboiler acts as the generator that 

rejects heat from CO2 compression to the LiBr-H2O solution to enable the separation of the 

refrigerant from the brine solution. The second heat exchanger rejects heat to the cooling water. 

The evaporator heat exchanger acts as the refrigerator and cools the CO2 compression stream by 

vaporizing the refrigerant. Only five stages of CO2 compression were necessary for Approach 2. 

The compression ratios were increased from the reference cases to create a compressor outlet 

temperature of at least 93°C (200°F) to maintain a temperature gradient of 6°C (10°F) in the 

kettle reboiler. This configuration resulted in a net plant efficiency increase of 0.1 percentage 

points (absolute).

It was concluded that the small increase in efficiency did not justify the added cost and 

operational complexity of the two configurations and hence they were not incorporated into the 

base design.

3.1.10 Power Generation

The steam turbine is designed for long-term operation (90 days or more) at MCR with throttle 

control valves 95 percent open. It is also capable of a short-term 5 percent OP/VWO condition 

(16 hours).

For the subcritical cases, the steam turbine is a tandem compound type, consisting of HP-IP-two 

LP (double flow) sections enclosed in three casings, designed for condensing single reheat 

operation, and equipped with non-automatic extractions and four-flow exhaust. The turbine 

drives a hydrogen-cooled generator. The turbine has DC motor-operated lube oil pumps, and 

main lube oil pumps, which are driven off the turbine shaft. (43) The exhaust pressure is 50.8 
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cm (2 in) Hg in the single pressure condenser. There are seven extraction points. The condenser 

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

The steam-turbine generator systems for the SC plants are similar in design to the subcritical 

systems. The differences include steam cycle conditions and steam extractions points. The 

subcritical design has seven steam extraction points for both capture and non-capture cases, 

whereas the capture SC plant has only 6 extraction points and the non-capture SC plant has 8 

extraction points. The reason for the differences between the two SC plants (B12A and B12B) is 

discussed in Section 3.1.11.

Turbine bearings are lubricated by a closed-loop, water-cooled pressurized oil system. Turbine 

shafts are sealed against air in-leakage or steam blowout using a labyrinth gland arrangement 

connected to a 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 rotor 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 control system. Main steam from the 

boiler passes through the stop valves and control valves and enters the turbine at 16.5 

MPa/566°C (2,400 psig/1,050oF) for the subcritical cases and 24.1MPa /593°C (3,500

psig/1,100°F) for the SC cases. The steam initially enters the 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 566°C (1,050oF) 

in the subcritical cases and 593°C (1,100°F) in the SC 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 condenser. The last stages of the LP sections operate as condensing turbines with an exit 

liquid fraction ranging from 9.2 percent to 9.5 percent.

The turbine is designed to operate at constant inlet steam pressure over the entire load range.

3.1.11 Balance of Plant

The balance of plant components consist of the condensate, FW, main and reheat steam, 

extraction steam, ash handling, ducting and stack, waste treatment and miscellaneous systems as 

described below.

3.1.11.1 Condensate

The function of the condensate system is to pump condensate from the condenser hotwell to the 

deaerator and through the LP FW heaters. Each system consists of one main condenser; two 

variable speed electric motor-driven vertical condensate pumps each sized for 50 percent 

capacity; four LP heaters (two in Case B12B); and one deaerator with storage tank.

Condensate is delivered to a common discharge 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 requirements 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 
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exchangers. Each 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 normal drain levels 

in the heaters. High heater level dump lines discharging to the condenser are provided for each 

heater for turbine water induction protection. Pneumatic level control valves control dump line 

flow.

While Case B11B returns all process extraction steam (CO2 capture and drying requirements) 

condensate to the deaerator, the SC Case B12B requires this condensate to be returned after the 

condenser upstream of the condensate polisher. This is required as the SC cases do not have a 

blowdown stream. If the condensate was returned to the deaerator, there would be a buildup of 

contaminants. An impact of this design is that two of the LP FW heaters are not required in the 

SC capture case (B12B), as the condensate return increases the FW temperature above that 

which would be exiting the second LP FW heater.

3.1.11.2 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 for 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 system 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 valves 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 exhaust provides steam to the boiler feed pump 

steam turbine.

3.1.11.3 Main and Reheat Steam

The function of the main steam system is to convey main steam from the boiler superheater 

outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from 

the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine 

stop valves.

Main steam exits the boiler superheater through a motor-operated stop/check valve and a motoroperated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP 
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turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at 

approximately 60 percent load.

Cold reheat steam exits the HP turbine, flows through a motor-operated isolation gate valve and 

a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater 

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

3.1.11.4 Extraction Steam

The function of the extraction steam system is to convey steam from turbine extraction points 

through the following routes:

 From HP turbine extraction to heater 7 (and 8 in SC cases)

 From IP turbine extraction to heater 6 and the deaerator (heater 5)

 From LP turbine extraction to heaters 1, 2, 3, and 4

The turbine is protected from overspeed on turbine trip, from flash steam reverse flow from the 

heaters through the extraction piping to the turbine. This protection is provided by positive 

closing, balanced disc non-return valves located in all extraction lines except the lines to the LP 

FW heaters in the condenser neck. The extraction non-return valves are located only in 

horizontal runs of piping and as close to the turbine as possible.

The turbine trip signal automatically trips the non-return valves through relay dumps. The 

remote manual control for each heater level control system is used to release the non-return 

valves to normal check valve service when required to restart the system.

3.1.11.5 Circulating Water System

It is assumed that the plant is serviced by a public water facility and has access to groundwater 

for use as makeup cooling water with minimal pretreatment. All filtration and treatment of the 

circulating water are conducted on site. A mechanical draft, wood frame, counter-flow cooling 

tower is provided for the circulating water heat sink. Two 50 percent CWPs are provided. The 

circulating water system (CWS) provides cooling water to the condenser, the auxiliary cooling 

water system, and the CDR facility and CO2 compressors in capture cases.

The auxiliary cooling water system is a CL system. Plate and frame heat exchangers with 

circulating water as the cooling medium are provided. This system provides cooling water to the 

lube oil coolers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers, air 

release valves, instruments, controls, etc. are included for a complete operable system.

The CDR and CO2 compression systems in Cases B11B and B12B requires a substantial amount 

of cooling water that is provided by the PC plant CWS. The additional cooling loads imposed by 

the CDR and CO2 compressors are reflected in the significantly larger CWPs and cooling tower 

in those cases.

3.1.11.6 Ash Handling System

The function of the ash handling system is to provide the equipment required for conveying, 

preparing, storing, and disposing of the fly ash and bottom ash produced on a daily basis by the 

boiler, along with the hydrated lime and activated carbon injected for mercury control (discussed 

in Section 3.1.6). The scope of the system is from the baghouse hoppers, air heater and 

economizer hopper collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and 

truck filling stations (for fly ash). The system is designed to support short-term operation at the 
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5 percent OP/VWO condition (16 hours) and long-term operation at the 100 percent guarantee 

point (90 days or more). 

The fly ash collected in the baghouse and the air heaters is conveyed to the fly ash storage silo. 

A pneumatic transport system using LP 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. 

As mentioned in Section 3.1.5, the use of ACI and DSI increases the calcium content of the fly 

ash and adds an additional burden to the fabric filter. The addition of calcium is not expected to 

increase the leaching of trace metals from the fly ash significantly. The ACI and DSI systems 

increase the total amount of particulate matter by approximately 26 percent.

The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to 

break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to 

hydrobins for dewatering and offsite removal by truck.

Ash from the economizer hoppers and pyrites (rejected from the coal pulverizers) is conveyed 

using water to the economizer/pyrites transfer tank. This material is then sluiced on a periodic 

basis to the hydrobins.

3.1.11.7 Ducting and Stack

One stack is provided with a single fiberglass-reinforced plastic (FRP) liner. The stack is 

constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate 

dispersion.

3.1.11.8 Waste Treatment/Miscellaneous Systems

An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash. It 

is anticipated that the treated water will be suitable for discharge into existing systems and be 

within the EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals.

The waste treatment system is minimal and consists, primarily, of neutralization and oil/water 

separators (along with the associated pumps, piping, etc.). 

Miscellaneous systems consisting of fuel oil, service 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.

3.1.11.9 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:
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 Steam turbine building  Fuel oil pump house  Guard house

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

 Administration and 

service building

 Continuous emissions 

monitoring building

 Industrial waste treatment 

building

 Makeup water and 

pretreatment building

 Pump house and electrical 

equipment building

 FGD system buildings

3.1.12 Accessory Electric Plant

The accessory electric plant consists of switchgear and control equipment, generator equipment, 

station service equipment, conduit and cable trays, and wire and cable. It also includes the main 

power transformer, required foundations, and standby equipment.

3.1.13 Instrumentation and Control

An integrated plant-wide control and monitoring 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 the major plant equipment. The DCS is designed to 

provide 99.5 percent availability. The plant equipment and the DCS are designed for automatic 

response to load changes from minimum load to 100 percent. Startup and shutdown routines are 

implemented as supervised manual, with operator selection of modular automation routines 

available.

3.1.14 Performance Summary Metrics

This section details the methodologies of several metrics reported in the performance summaries 

of the PC cases.

Steam Generator Efficiency

The steam generator efficiency is equal to the amount of heat transferred in the boiler divided by 

the thermal input provided by the coal. This calculation is represented by the equation:

= BB

Where:

SGE – steam generator efficiency

BH – boiler thermal output

CH – coal thermal input

The heat transferred in the boiler is provided by the Aspen models, and the thermal input of the 

coal is the product of the coal feed rate and the heating value of the coal.

Steam Turbine Efficiency

The steam turbine efficiency is calculated by taking the steam turbine power produced and 

dividing it by the difference between the thermal input and thermal consumption. This 

calculation is represented by the equation:

SS = SS

( TT − )
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Where:

STE – steam turbine efficiency

STP – steam turbine power

TI – thermal input

TC – thermal consumption

The thermal input is considered to be the main steam.

The thermal consumption is only present in the capture cases. It is the enthalpy difference 

between the streams extracted for the capture and CO2 dryer systems and the condensate returned 

to the condenser (steam extraction – condensate return).

Steam Turbine Heat Rate

The steam turbine heat rate is calculated by taking the inverse of the steam turbine efficiency.

This calculation is represented by the equation:

SS SS = 1

SS ∗ 3,412

Where:

STHR – steam turbine heat rate, Btu/kWh

STE – steam turbine efficiency, fraction

3.2 Subcritical PC Cases 

This section contains an evaluation of plant designs for Cases B11A and B11B, which are based 

on a subcritical PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 

16.5 MPa/566°C/566°C (2,400 psig/1,050°F/1,050°F) cycle. The main difference between the 

two configurations is that Case B11B includes CO2 capture while Case B11A does not.

The balance of this section is organized as follows:

• Process and System Description provides an overview of the technology operation as 

applied to Case B11A. The systems that are common to all PC cases were covered in 

Section 3.1 and only features that are unique to Case B11A are discussed further in this 

section.

• Key Assumptions is a summary of study and modeling assumptions relevant to Cases 

B11A and B11B.

• Sparing Philosophy is provided for both Cases B11A and B11B.

• Performance Results provides the main modeling results from Case B11A, including the 

performance summary, environmental performance, carbon/sulfur balances, water 

balance, mass and energy balance diagrams and energy balance table.

• Equipment List provides an itemized list of major equipment for Case B11A with 

account codes that correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs for Case B11A.

• Process and System Description, Performance Results, Equipment List and Cost 

Estimates are discussed for Case B11B.

3.2.1 Process Description

In this section the subcritical PC process without CO2 capture is described. The system 

description follows the block flow diagram (BFD) in Exhibit 3-5 and stream numbers reference 
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the same Exhibit. The tables in Exhibit 3-6 provide process data for the numbered streams in the 

BFD.

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 1). 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. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD 

and PA fan outlet streams to the boiler exhaust.

Flue gas exits the boiler through the SCR reactor where ammonia is injected to reduce NOx 

compounds, followed by hydrated lime injection (stream 10) for the reduction of SO3. It then 

passes through the combustion air preheater (where the air preheater leakages are introduced) 

and is cooled to 143°C (289°F) (stream 11) before PAC is injected (stream 12) for mercury 

reduction. The flue gas then passes through a fabric filter for particulate removal (stream 15). 

An ID fan increases the flue gas temperature to 153°C (308°F) and provides the motive force for 

the flue gas (stream 16) to pass through the FGD unit. FGD inputs and outputs include makeup 

water (stream 18), oxidation air (stream 19), limestone slurry (stream 17) and product gypsum 

(stream 20). The clean, saturated flue gas exiting the FGD unit (stream 21) passes to the plant 

stack and is discharged to the atmosphere.
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Exhibit 3-5 Case B11A block flow diagram, subcritical unit without CO2 capture

Source: NETL

PULVERIZED

COAL

BOILER

SCR

BAGHOUSE FGD

LIMESTONE GYPSUM

SLURRY

OXIDATION

AIR

MAKEUP

WATER

BOTTOM ASH

COAL FEED

INFILTRATION

AIR

1

4

8

7

9

14

FLY ASH

15 16

18 19

17 20

21

HP 

TURBINE

22

23

24

IP

TURBINE LP TURBINE

CONDENSER

26

FEEDWATER 

HEATER

SYSTEM

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

3

2

6

5

11

25

10

HYDRATED

LIME

12

13

ACTIVATED

CARBON

STACK GAS

FD FANS

PA FANS

ID FAN

BOILER

FEEDWATER
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Exhibit 3-6 Case B11A stream table, subcritical unit without capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0000 0.0088 0.0000 0.0088 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.0000 0.1376 0.0000 0.1376 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0000 0.0831 0.0000 0.0831 0.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.0000 0.7345 0.0000 0.7345 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0000 0.0340 0.0000 0.0340 0.3333

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0020 0.0000 0.0020 0.6667

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 51,529 51,529 1,526 15,829 15,829 2,179 1,126 0 0 0 72,228 0 72,228 3

V-L Flowrate (kg/hr) 1,486,984 1,486,984 44,042 456,786 456,786 62,866 32,480 0 0 0 2,145,010 0 2,145,010 164

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 186,882 3,624 3,766 18,264 109 18,372 18,372

Temperature (°C) 15 19 19 15 25 25 15 15 149 27 143 27 143 143

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

Steam Table Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 0.00 0.00 0.00 --- ---

AspenPlus Enthalpy (kJ/kg)B -97.58 -93.45 -93.45 -97.58 -87.03 -87.03 -97.58 -2,114.05 97.18 -13,306.82 -2,399.51 3.40 -2,399.39 -2,632.02

Density (kg/m3) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- --- 0.9 --- 0.9 1.5

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- --- 29.698 --- 29.698 53.376

V-L Flowrate (lbmole/hr) 113,603 113,603 3,365 34,898 34,898 4,803 2,481 0 0 0 159,235 0 159,235 7

V-L Flowrate (lb/hr) 3,278,239 3,278,239 97,095 1,007,041 1,007,041 138,595 71,605 0 0 0 4,728,938 0 4,728,938 362

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 412,005 7,990 8,303 40,264 240 40,504 40,504

Temperature (°F) 59 66 66 59 78 78 59 59 300 80 289 80 289 289

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.4 14.7 14.4 14.7 14.4 14.4

Steam Table Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- --- ---

AspenPlus Enthalpy (Btu/lb)B -42.0 -40.2 -40.2 -42.0 -37.4 -37.4 -42.0 -908.9 41.8 -5,720.9 -1,031.6 1.5 -1,031.6 -1,131.6

Density (lb/ft3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- --- 0.053 --- 0.053 0.096

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
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Exhibit 3-6 Case B11A stream table, subcritical unit without capture (continued)

15 16 17 18 19 20 21 22 23 24 25 26

V-L Mole Fraction

Ar 0.0088 0.0088 0.0000 0.0000 0.0092 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1376 0.1376 0.0000 0.0000 0.0003 0.0001 0.1288 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0831 0.0831 1.0000 1.0000 0.0099 0.9999 0.1451 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.7345 0.7345 0.0000 0.0000 0.7732 0.0000 0.6854 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0340 0.0340 0.0000 0.0000 0.2074 0.0000 0.0325 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0020 0.0020 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 72,225 72,225 2,394 9,596 764 177 78,266 87,854 82,001 82,001 72,119 73,186

V-L Flowrate (kg/hr) 2,144,846 2,144,846 43,130 172,870 22,042 3,183 2,258,148 1,582,718 1,477,271 1,477,271 1,299,243 1,318,467

Solids Flowrate (kg/hr) 0 0 18,467 0 0 28,641 0 0 0 0 0 0

Temperature (°C) 143 153 15 27 167 56 56 593 355 566 38 39

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.31 0.10 0.10 16.65 4.28 4.19 0.01 2.04

Steam Table Enthalpy (kJ/kg) A 274.35 285.60 --- 111.65 184.48 --- 286.09 3,473.89 3,098.44 3,593.58 1,980.12 163.34

AspenPlus Enthalpy (kJ/kg)B -2,397.38 -2,386.13 -14,995.75 -15,964.53 56.67 -12,481.91 -2,940.30 -12,506.41 -12,881.86 -12,386.71 -14,000.17 -15,816.96

Density (kg/m3) 0.8 0.9 1,003.6 992.3 2.4 833.1 1.1 47.7 16.0 11.1 0.1 993.6

V-L Molecular Weight 29.697 29.697 18.015 18.015 28.857 18.018 28.852 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmole/hr) 159,229 159,229 5,278 21,155 1,684 389 172,548 193,685 180,781 180,781 158,995 161,348

V-L Flowrate (lb/hr) 4,728,575 4,728,575 95,086 381,114 48,595 7,018 4,978,363 3,489,296 3,256,825 3,256,825 2,864,341 2,906,721

Solids Flowrate (lb/hr) 0 0 40,712 0 0 63,142 0 0 0 0 0 0

Temperature (°F) 289 308 59 80 332 133 133 1,050 671 1,050 101 101

Pressure (psia) 14.2 15.2 15.0 15.7 45.0 14.7 14.7 2,414.7 620.5 608.1 1.0 295.5

Steam Table Enthalpy (Btu/lb)A 117.9 122.8 --- 48.0 79.3 --- 123.0 1,493.5 1,332.1 1,545.0 851.3 70.2

AspenPlus Enthalpy (Btu/lb)B -1,030.7 -1,025.9 -6,447.0 -6,863.5 24.4 -5,366.3 -1,264.1 -5,376.8 -5,538.2 -5,325.3 -6,019.0 -6,800.1

Density (lb/ft3) 0.052 0.055 62.650 61.950 0.153 52.011 0.067 2.975 1.000 0.692 0.004 62.028

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

73

3.2.2 Key System Assumptions

System assumptions for Cases B11A and B11B, subcritical PC with and without CO2 capture, 

are compiled in Exhibit 3-7.

Exhibit 3-7 Subcritical PC plant study configuration matrix

Case B11A 

w/o CO2 Capture 

Case B11B 

w/CO2 Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 16.5/566/566 

(2,400/1,050/1,050)

16.5/566/566 

(2,400/1,050/1,050)

Coal Illinois No. 6 Illinois No. 6

Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Boiler Efficiency, HHV % 89 89

Cooling water to condenser, °C (oF) 16 (60) 16 (60)

Cooling water from condenser, °C (oF) 27 (80) 27 (80)

Stack temperature, °C (°F) 56 (133) 42 (107)

SO2 Control Wet Limestone Forced 

Oxidation

Wet Limestone 

Forced Oxidation

FGD Efficiency, % (A) 98 98 (B, C)

NOx Control LNB w/OFA, SCR, and 

Polishing Scrubber

LNB w/OFA, SCR, and 

Polishing Scrubber

SCR Efficiency, % (A) 83 85

Ammonia Slip (end of catalyst life), 

ppmv

2 2

Particulate Control Fabric Filter Fabric Filter

Fabric Filter efficiency, % (A) 99.9 99.9

Ash Distribution, Fly/Bottom 80% / 20% 80% / 20%

SO3 Control DSI DSI

Mercury Control Co-benefit Capture and ACI Co-benefit Capture and ACI

CO2 Control N/A Cansolv

Overall Carbon Capture (A) N/A 90%

CO2 Sequestration N/A Off-site Saline Formation

ARemoval efficiencies are based on the flue gas content

BAn SO2 polishing step is included to meet more stringent SOx content limits in the flue gas (~1

ppmv) to reduce formation of amine HSS during the CO2 absorption process

CSO2 exiting the post-FGD polishing step is absorbed in the CO2 capture process making stack 

emissions negligible

3.2.2.1 Balance of Plant – Cases B11A and B11B

The balance of plant assumptions are common to all cases and are presented in Exhibit 3-8.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

74

Exhibit 3-8 Balance of plant assumptions

Parameter Value

Cooling system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Ash 30 days

Gypsum 30 days

Limestone 30 days

Hydrated lime 30 days

Activated carbon 30 days

Plant Distribution Voltage

Motors below 1 hp 110/220 V

Motors between 1 hp and 250 hp 480 V

Motors between 250 hp and 5,000 hp 4,160 V

Motors above 5,000 hp 13,800 V

Steam and CT generators 24,000 V

Grid Interconnection voltage 345 kV

Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW and 

50 percent from groundwater, and is assumed to be in 

sufficient quantities to meet plant makeup requirements.

Makeup for potable, process, and DI water is drawn from 

municipal sources.

Process Wastewater Storm water that contacts equipment surfaces is 

collected and treated for discharge through a permitted 

discharge.

Sanitary Waste Disposal Design includes a packaged domestic sewage treatment 

plant with effluent discharged to the industrial wastewater 

treatment system. Sludge is hauled off site. Packaged 

plant is sized for 5.68 cubic meters per day 

(1,500 gallons per day)

Water Discharge Most of the process wastewater is recycled to the cooling 

tower basin. Blowdown will be treated for chloride and 

metals, and discharged.

3.2.3 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 subcritical boiler (1 x 100%)

• Two SCR reactors (2 x 50%)

• One DSI system (1 x 100%)

• One ACI system (1 x 100%)

• Two single-stage, in-line, multi-compartment fabric filters (2 x 50%)

• One wet limestone forced oxidation positive pressure absorber (1 x 100%)

• One steam turbine (1 x 100%)

• For Case B11B only, one CO2 absorption system, consisting of an absorber, stripper, and 

ancillary equipment (1 x 100%) and two CO2 compression systems (2 x 50%)
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

75

3.2.4 Case B11A Performance Results

The plant produces a net output of 550 MWe at a net plant efficiency of 39.0 percent (HHV 

basis). Overall performance for the plant is summarized in Exhibit 3-9. Exhibit 3-10 provides a 

detailed breakdown of the auxiliary power requirements. 

Exhibit 3-9 Case B11A plant performance summary

Performance Summary

Total Gross Power, MWe 581

CO2 Capture/Removal Auxiliaries, kWe 0

CO2 Compression, kWe 0

Balance of Plant, kWe 31,153

Total Auxiliaries, MWe 31

Net Power, MWe 550

HHV Net Plant Efficiency (%) 39.0%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,221 (8,740)

LHV Net Plant Efficiency (%) 40.5%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,894 (8,430)

HHV Boiler Efficiency, % 89.1%

LHV Boiler Efficiency, % 92.4%

Steam Turbine Cycle Efficiency, % 46.3%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 7,774 (7,369)

Condenser Duty, GJ/hr (MMBtu/hr) 2,362 (2,239)

As-Received Coal Feed, kg/hr (lb/hr) 186,882 (412,005)

Limestone Sorbent Feed, kg/hr (lb/hr) 18,467 (40,712)

HHV Thermal Input, kWt 1,408,630

LHV Thermal Input, kWt 1,358,641

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.038 (10.1)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.030 (8.0)

Excess Air, % 20.9%
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

76

Exhibit 3-10 Case B11A plant power summary

Power Summary

Steam Turbine Power, MWe 581

Total Gross Power, MWe 581

Auxiliary Load Summary

Coal Handling and Conveying, kWe 440

Pulverizers, kWe 2,800

Sorbent Handling & Reagent Preparation, kWe 890

Ash Handling, kWe 650

Primary Air Fans, kWe 1,390

Forced Draft Fans, kWe 1,770

Induced Draft Fans, kWe 6,940

SCR, kWe 50

Activated Carbon Injection, kWe 23

Dry sorbent Injection, kWe 90

Baghouse, kWe 90

Wet FGD, kWe 2,950

CO2 Capture/Removal Auxiliaries, kWe 0

CO2 Compression, kWe 0

Miscellaneous Balance of PlantA,B, kWe 2,000

Steam Turbine Auxiliaries, kWe 400

Condensate Pumps, kWe 990

Circulating Water Pumps, kWe 4,850

Ground Water Pumps, kWe 500

Cooling Tower Fans, kWe 2,510

Transformer Losses, kWe 1,820

Total Auxiliaries, MWe 31

Net Power, MWe 550 ABoiler feed pumps are turbine driven

BIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.2.4.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section

2.4. A summary of the plant air emissions for Case B11A is presented in Exhibit 3-11. SO2

emissions are utilized as a surrogate for HCl emissions, therefore HCl is not reported.

Exhibit 3-11 Case B11A air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)

SO2 0.036 (0.085) 1,374 (1,514) 0.318 (0.700)

NOx 0.036 (0.085) 1,374 (1,514) 0.318 (0.700)

Particulate 0.005 (0.011) 177 (195) 0.041 (0.090)

Hg 1.56E-7 (3.63E-7) 0.006 (0.006) 1.36E-6 (3.00E-6)

CO2B 88 (204) 3,303,826 (3,641,844) 764 (1,683)

CO2C - - 807 (1,779)

mg/Nm3

Particulate ConcentrationD,E 14.66 ACalculations based on an 85 percent capacity factor BCO2 emissions based upon gross power

CCO2 emissions based on net power instead of gross power DConcentration of particles in the flue gas after the baghouse ENormal conditions given at 32°F and 14.696 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

77

SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a 

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. 

The wallboard grade material can potentially be marketed and sold, but since it is highly 

dependent on local market conditions, no byproduct credit was taken. The saturated flue gas

exiting the scrubber is vented through the plant stack.

NOx emissions are controlled to about 0.5 lb/MMBtu through the use of LNBs and OFA. An 

SCR unit then further reduces the NOx concentration by 83 percent to 0.08 lb/MMBtu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency 

of 99.9 percent.

The total reduction in mercury emission via the combined control equipment (SCR, ACI, fabric 

filter, DSI, and wet FGD) is 96.8 percent.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3-12. The carbon input to the plant consists 

of carbon in the coal, carbon in the air, PAC, and carbon in the limestone reagent used in the 

FGD absorber. Carbon in the air is not neglected here since the Aspen model accounts for air 

components throughout. Carbon leaves the plant mostly as CO2 through the stack, however, the 

PAC is captured in the fabric filter and some leaves as gypsum.

Exhibit 3-12 Case B11A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 119,128 (262,631) Stack Gas 121,094 (266,967)

Air (CO2) 272 (599) FGD Product 179 (394)

PAC 109 (240) Baghouse 109 (240)

FGD Reagent 1,874 (4,131) CO2 Product 0

CO2 Dryer Vent 0

CO2 Knockout 0

Total 121,382 (267,601) Total 121,382 (267,601)

Exhibit 3-13 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum, sulfur captured in 

the fabric filter via hydrated lime, and sulfur emitted in the stack gas.

Exhibit 3-13 Case B11A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 4,684 (10,327) FGD Product 4,526 (9,978)

Stack Gas 92 (204)

Polishing Scrubber and Solvent Reclaiming 0

Baghouse 66 (145)

Total 4,684 (10,327) Total 4,684 (10,327)

Exhibit 3-14 shows the water balance for Case B11A. 

Water demand represents the total amount of water required for a particular process. Some water 

is recovered within the process and is re-used as internal recycle. The difference between 

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water 
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

78

removed from the ground or diverted from a POTW for use in the plant and was assumed to be 

provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can 

be represented by the water metered from a raw water source and used in the plant processes for 

any and all purposes, such as FGD makeup, BFW makeup, and cooling tower makeup. The 

difference between water withdrawal and process water discharge is defined as water 

consumption and can be represented by the portion of the raw water withdrawn that is 

evaporated, transpired, incorporated into products or otherwise not returned to the water source 

from which it was withdrawn. Water consumption represents the net impact of the plant process 

on the water source.

Exhibit 3-14 Case B11A water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm) m3/min (gpm)

FGD Makeup 3.61 (952) – 3.61 (952) – 3.61 (952)

CO2 Drying – – – – –

Capture System 

Makeup – – – – –

Deaerator Vent – – – 0.05 (14) -0.05 (-14)

Condenser Makeup 0.32 (85) – 0.32 (85) – 0.32 (85)

 BFW Makeup 0.32 (85) – 0.32 (85) – 0.32 (85)

Cooling Tower 18.89 

(4,991)

1.86 

(491) 17.04 (4,500) 4.25 (1,123) 12.79 (3,378)

 FGD Dewatering – 1.86 

(491) -1.86 (-491) – -1.86 (-491)

 CO2 Capture 

Recovery – – – – –

 CO2 Compression KO – – – – –

 BFW Blowdown – 0.27 (71) -0.27 (-71) – -0.27 (-71)

Total 22.82 

(6,029)

1.86 

(491) 20.96 (5,538) 4.30 (1,137) 16.66 (4,401)

3.2.4.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the Case B11A PC boiler, the FGD unit, and 

steam cycle as shown in Exhibit 3-15 and Exhibit 3-16.

An overall plant energy balance is provided in tabular form in Exhibit 3-17. The power out is 

the steam turbine power prior to generator losses. The power at the generator terminals (shown 

in Exhibit 3-9) is calculated by multiplying the power out by a generator efficiency of 98.5

percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

79

Exhibit 3-15 Case B11A heat and mass balance, subcritical PC boiler without CO2 capture

Source: NETL

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

1 OF 2

BITUMINOUS BASELINE STUDY

CASE B11A

SUBCRITICAL PULVERIZED COAL

BOILER AND GAS CLEANUP SYSTEMS

DWG. NO.

BB-HMB-CS-B11A-PG-1

Pulverized

Coal

Boiler

Ammonia SCR

Infiltration Air

Air

Air

Coal

Bottom Ash

FGD

Fly Ash

Forced

Draft Fans

Primary 

Air Fans

412,005 W

59 T

15 P

78 T

16 P

18 H

66 T

15 P

15 H

3,489,296 W

1,050 T

2,415 P

1,494 H

3,256,825 W

1,050 T

608 P

1,545 H

1,007,041 W

59 T

15 P

13 H

3,278,239 W

59 T

15 P

13 H

71,605 W

59 T

15 P

13 H

4,769,202 W

289 T

14 P

117 H

7,990 W

300 T

14 P

40,866 W

289 T

14 P

3,256,825 W

671 T

621 P

1,332 H

3,489,296 W

486 T

2,536 P

471 H

5

4,978,373 W

133 T

15 P

123 H

1 2

4

7

9

4,728,575 W ID Fans

289 T

14 P

118 H

Gross Plant Power: 581 MWe

Auxiliary Load: 31 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 39.0%

Net Plant Heat Rate: 8,740 Btu/kWh

Oxidation 

Air

Make-Up 

Water

Limestone 

Slurry

Gypsum

18

17

14

4,728,575 W

308 T

15 P

123 H

135,798 W

59 T

15 P

423 H

48,595 W

332 T

45 P

79 H

381,124 W

80 T

16 P

48 H

70,160 W

133 T

15 P

1,499 H

Baghouse

3

6

8

15 16

19

21

22

23

24

DOE/NETL

SC PC PLANT

CASE B11A

Hydrated 

Lime

11

Single Reheat

Extraction from

HP Turbine

From Feedwater

Heaters

Single Reheat

To IP Turbine

Throttle Steam

To HP Turbine

8,303 W

80 T

15 P

10

Activated 

Carbon

12

13

240 W

80 T

15 P

Stack

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

4,769,442 W

289 T

14 P

117 H

20

Air

Coal/Ash

Slurry

Water

Steam

Lime/

Limestone/

Gypsum

Flue Gas

Activated 

Carbon

Ammonia
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

80

Exhibit 3-16 Case B11A heat and mass balance, subcritical steam cycle

Source: NETL

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

Water

Steam

PAGES

2 OF 2

DWG. NO.

BB-HMB-CS-B11A-PG-2

BITUMINOUS BASELINE STUDY

CASE B11A

SUBCRITICAL PULVERIZED COAL

POWER BLOCK SYSTEMS

LP Turbine Generator HP

Turbine

IP

Turbine

Condenser

Hot Well

Boiler Feed Pump 

Turbine Drives

Throttle

Steam

Condensate 

Pumps

3,489,296 W

1,050 T

2,415 P

1,494 H

182,562 W

887 T

336 P

1,466 H

232,471 W

669 T

596 P

1,332 H

3,256,825 W

671 T

621 P

1,332 H

131,872 W

694 T

164 P

1,373 H

131,872 W

126 T

2 P

1,085 H

2,236,743 W

101 T

1 P

1,009 H

2,906,721 W

101 T

1 P

69 H

2,906,721 W

101 T

296 P

70 H

2,906,721 W

155 T

284 P

124 H

495,726 W

111 T

1 P

79 H

360,720 W

165 T

5 P

133 H

2,906,721 W

290 T

251 P

259 H

415,033 W

381 T

198 P

354 H

2,906,721 W

262 T

261 P

231 H

232,471 W

440 T

382 P

419 H

3,489,296 W

430 T

2,642 P

410 H

Deaerator

Boiler Feed

Water Pumps

3,489,296 W

486 T

2,536 P

471 H

3,256,825 W

1,050 T

608 P

1,545 H

78,138 W

272 T

43 P

241 H

259,938 W

204 T

13 P

172 H

2,906,721 W

194 T

272 P

163 H

209,922 W

694 T

161 P

1,373 H

78,138 W

491 T

62 P

1,278 H

181,801 W

408 T

40 P

1,240 H

100,782 W

206 T

11 P

1,149 H

135,006 W

160 T

5 P

1,096 H

2,864,341 W

694 T

164 P

1,373 H

2,732,469 W

694 T

164 P

1,373 H

3,489,296 W

371 T

2,752 P

348 H 3,489,296 W

364 T

161 P

337 H

Gross Plant Power: 581 MWe

Auxiliary Load: 31 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 39.0%

Net Plant Heat Rate: 8,740 Btu/kWh

FWH 4 FWH 3 FWH 2 FWH 1 FWH 6 FWH 5

22

26

DOE/NETL

SC PC PLANT

CASE B11A

24

23

42,380 W

59 T

15 P

27 H

Blowdown

Vent

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

Single Reheat

Extraction

From Boiler

Single Reheat

Extraction to

Boiler

To Boiler

Steam Turbine

Makeup

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

25
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

81

Exhibit 3-17 Case B11A overall energy balance (0°C [32°F] reference)

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 5,071 (4,806) 4.2 (4.0) – 5,075 (4,810)

Air – 59.7 (56.6) – 59.7 (56.6)

Raw Water Makeup – 78.8 (74.7) – 78.8 (74.7)

Limestone – 0.40 (0.38) – 0.40 (0.38)

Auxiliary Power – – 112 (106) 112 (106)

TOTAL 5,071 (4,806) 143.2 (135.7) 112 (106) 5,326 (5,048)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash – 0.4 (0.4) – 0.4 (0.4)

Fly Ash + FGD Ash – 2.1 (2.0) – 2.1 (2.0)

Stack Gas – 646 (612) – 646 (612)

Sulfur – – – –

Motor Losses and Design 

Allowances – – 34 (33) 34 (33)

Condenser – 2,362 (2,239) – 2,362 (2,239)

Non-Condenser Cooling Tower 

Loads – 106 (100) – 106 (100)

CO2 – 0.0 (0.0) – 0.0 (0.0)

Cooling Tower Blowdown – 31.6 (29.9) – 31.6 (29.9)

CO2 Capture Losses – – – –

Ambient LossesA – 107.7 (102.0) – 107.7 (102.0)

Power – – 2,092 

(1,983) 2,092 (1,983)

TOTAL – 3,255 (3,085) 2,126 

(2,015) 5,382 (5,101)

Unaccounted EnergyB – -55 (-52) – -55 (-52)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the boiler, reheater, superheater, and transformers.

BBy difference

3.2.5 Case B11A – Major Equipment List

Major equipment items for the subcritical PC plant with no CO2 capture are shown in the 

following tables. The accounts used in the equipment list correspond to the account numbers 

used in the cost estimates in Section 3.2.6. 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 for Fossil Energy Plants Volume 1: Revision 3

82

Case B11A – Account 1: Coal and Sorbent Handling

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 180 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, 

linear 1,130 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 40 tonne (40 ton) 2 1

9 Feeder Vibratory 150 tonne/hr (170 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 310 tonne/hr (340 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 150 tonne (170 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 310 tonne/hr (340 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 310 tonne/hr (340 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide 

Gates Field erected 690 tonne (800 ton) 3 0

19 Activated Carbon Storage Silo and 

Feeder System

Shop 

assembled

Silo - 29 tonne (32 ton)

Feeder - 120 kg/hr

(260 lb/hr)

1 0

20 Hydrated Lime Storage Silo and 

Feeder System

Shop 

assembled

Silo - 200 tonne (220 ton)

Feeder –

4,140 kg/hr (9,130 lb/hr)

1 0

21 Limestone Truck Unloading Hopper N/A 30 tonne (40 ton) 1 0

22 Limestone Feeder Belt 80 tonne/hr (90 tph) 1 0

23 Limestone Conveyor No. L1 Belt 80 tonne/hr (90 tph) 1 0

24 Limestone Reclaim Hopper N/A 20 tonne (20 ton) 1 0

25 Limestone Reclaim Feeder Belt 60 tonne/hr (70 tph) 1 0

26 Limestone Conveyor No. L2 Belt 60 tonne/hr (70 tph) 1 0

27 Limestone Day Bin w/ actuator 240 tonne (270 ton) 2 0

Case B11A – Account 2: Coal and Sorbent Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Coal Feeder Gravimetric 30 tonne/hr (40 tph) 6 0

2 Coal Pulverizer Ball type or 

equivalent 30 tonne/hr (40 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 20 tonne/hr (22 tph) 1 1

4 Limestone Ball Mill Rotary 20 tonne/hr (22 tph) 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 77,200 liters (20,000 gal) 1 1

6 Limestone Mill Recycle 

Pumps Horizontal centrifugal 1,300 lpm @ 10m H2O (340 gpm @ 40 ft H2O) 1 1

7 Hydroclone Classifier 4 active cyclones in a 

5 cyclone bank

320 lpm (90 gpm)

per cyclone 1 1

8 Distribution Box 2-way N/A 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 439,000 liters (116,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 910 lpm @ 9m H2O 

(240 gpm @ 30 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

83

Case B11A – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor

1,271,000 liters 

(336,000 gal) 2 0

2 Condensate Pumps Vertical canned 24,300 lpm @ 300 m H2O 

(6,400 gpm @ 800 ft H2O) 1 1

3 Deaerator and Storage 

Tank Horizontal spray type

1,762,000 kg/hr 

(3,885,000 lb/hr), 

5 min. tank

1 0

4 Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

29,200 lpm @ 2,200 m H2O 

(7,700 gpm @ 7,200 ft H2O) 1 1

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

8,700 lpm @ 2,200 m H2O 

(2,300 gpm @ 7,200 ft H2O) 1 0

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 730,000 kg/hr (1,600,000 lb/hr) 2 0

7 LP Feedwater Heater 

2A/2B Horizontal U-tube 730,000 kg/hr (1,600,000 lb/hr) 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 730,000 kg/hr (1,600,000 lb/hr) 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 730,000 kg/hr (1,600,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1,740,000 kg/hr 

(3,840,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1,740,000 kg/hr 

(3,840,000 lb/hr) 1 0

12 Auxiliary Boiler Shop fabricated, water 

tube

20,000 kg/hr, 2.8 MPa, 

343°C (40,000 lb/hr, 400 

psig, 650°F)

1 0

13 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

14 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig) 2 1

15 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

16 Closed Cycle Cooling 

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

17 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,800 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

18 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O) 1 1

19 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O) 1 1

20 Raw Water Pumps Stainless steel, single 

suction

6,070 lpm @ 20 m H2O 

(1,600 gpm @ 60 ft H2O) 2 1

21 Ground Water Pumps Stainless steel, single 

suction

2,430 lpm @ 270 m H2O 

(640 gpm @ 880 ft H2O) 5 1

22 Filtered Water Pumps Stainless steel, single 

suction

1,920 lpm @ 50 m H2O 

(510 gpm @ 160 ft H2O) 2 1

23 Filtered Water Tank Vertical, cylindrical 1,839,000 liter (486,000 gal) 1 0

24 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

650 lpm (170 gpm) 1 1

25 Liquid Waste Treatment 

System -- 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Case B11A – Account 4: Boiler and Accessories

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Boiler

Subcritical, drum wall-fired, 

low NOx burners, overfire 

air

1,740,000 kg/hr steam 

@ 17.9 MPa/574°C/574°C 

(3,840,000 lb/hr steam 

@ 2,600 psig/1,065°F/1,065°F)

1 0

2 Primary Air Fan Centrifugal

251,000 kg/hr, 3,400 m3/min 

@ 123 cm WG 

(554,000 lb/hr, 121,100 acfm 

@ 48 in. WG)

2 0

3 Forced Draft

Fan Centrifugal

818,000 kg/hr, 11,200 m3/min 

@ 47 cm WG 

(1,803,000 lb/hr, 394,100 acfm 

@ 19 in. WG)

2 0

4 Induced Draft 

Fan Centrifugal

1,180,000 kg/hr, 23,400 m3/min 

@ 89 cm WG 

(2,601,000 lb/hr, 826,500 acfm 

@ 35 in. WG)

2 0

5 SCR Reactor 

Vessel Space for spare layer 2,360,000 kg/hr (5,200,000 lb/hr) 2 0

6 SCR Catalyst -- -- 3 0

7 Dilution Air 

Blower Centrifugal 130 m3/min @ 108 cm WG (4,600 acfm @ 42 in. WG) 2 1

8 Ammonia 

Storage Horizontal tank 142,000 liter (38,000 gal) 5 0

9 Ammonia Feed 

Pump Centrifugal 27 lpm @ 90 m H2O (7 gpm @ 300 ft H2O) 2 1

Case B11A – Account 5: Flue Gas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter

Single stage, high-ratio 

with pulse-jet online 

cleaning system

1,180,000 kg/hr (2,601,000 

lb/hr) 99.9% efficiency 2 0

2 Absorber Module Counter-current open 

spray

47,000 m3/min 

(1,661,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 164,000 lpm @ 65 m H2O 

(43,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal centrifugal 3,980 lpm (1,050 gpm) 

at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 80 m3/min @ 0.3 MPa 

(2,920 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units 

each

990 lpm (260 gpm) per 

cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 32 tonne/hr (35 tph) of 50 wt 

% slurry 2 1

9 Filtrate Water Return 

Pumps Horizontal centrifugal 610 lpm @ 13 m H2O (160 gpm @ 40 ft H2O) 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 400,000 lpm (100,000 gal) 1 0

11 Process Makeup 

Water Pumps Horizontal centrifugal 3,170 lpm @ 21 m H2O (840 gpm @ 70 ft H2O) 1 1

12 Activated Carbon 

Injectors --- 120 kg/hr (260 lb/hr) 1 0

13 Hydrated Lime 

Injectors --- 4,140 kg/hr (9,130 lb/hr) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Case B11A – Account 7: Ducting and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner

152 m (500 ft) high x

5.8 m (19 ft) diameter 1 0

Case B11A – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

612 MW

16.5 MPa/566°C/566°C (2400 psig/ 

1050°F/1050°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

680 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

2,600 GJ/hr (2,460 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

Case B11A – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 487,000 lpm @ 30 m(129,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2710 GJ/hr (2570 MMBtu/hr) heat duty

1 0

Case B11A – Account 10: Ash and Spent Sorbent Recovery and Handling

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of boiler scope 

of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of 

supply) -- -- 2 0

3 Clinker Grinder -- 4.0 tonne/hr (4.4 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of 

supply included with boiler) -- -- 6 0

5 Hydroejectors -- -- 12

6 Economizer /Pyrites Transfer Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, 

wet pit

160 lpm @ 17 m H2O 

(40 gpm @ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, 

wet pit

7,570 lpm @ 9 m H2O 

(2000 gpm @ 28 ft 

H2O)

1 1

9 Hydrobins -- 150 lpm (40 gpm) 1 1

10 Baghouse Hopper (part of baghouse 

scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of 

supply) -- -- 10 0

12 Air Blower -- 20 m3/min @ 0.2 MPa 

(650 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforce

d concrete 1,200 tonne (1,300 ton) 2 0

14 Slide Gate Valves -- -- 2 0

15 Unloader -- -- 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Equipmen

t No. Description Type Design Condition Operating Qty. Spares

16 Telescoping Unloading Chute -- 110 tonne/hr (130 tph) 1 0

Case B11A – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 

MVA, 3-ph, 60 Hz 1 0

2 High Voltage Transformer Oil-filled 345 kV/13.8 kV, 0 

MVA, 3-ph, 60 Hz 2 0

3 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 33 

MVA, 3-ph, 60 Hz 1 1

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 5 

MVA, 3-ph, 60 Hz 1 1

5 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

6 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

7 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

8 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B11A – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.2.6 Case B11A – Cost Estimating

The cost estimating methodology was described previously in Section 2.7. Exhibit 3-18 shows a 

detailed breakdown of the capital costs; Exhibit 3-19 shows the owner’s costs, along with the, 

TOC, and TASC; Exhibit 3-20 shows the initial and annual O&M costs; and Exhibit 3-21 shows 

the COE breakdown. 

The estimated TPC of the subcritical PC boiler with no CO2 capture is $1,960/kW. No process 

contingency is included in this case because all elements of the technology are commercially 

proven. The project contingency is 11.2 percent of the TPC. The COE is $82.1/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 3-18 Case B11A total plant cost details

Case: B11A – Subcritical PC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,103 $0 $1,849 $0 $5,952 $595 $0 $982 $7,529 $14

1.2 Coal Stackout & Reclaim $5,303 $0 $1,185 $0 $6,488 $649 $0 $1,071 $8,207 $15

1.3 Coal Conveyors $4,930 $0 $1,173 $0 $6,103 $610 $0 $1,007 $7,720 $14

1.4 Other Coal Handling $1,290 $0 $271 $0 $1,561 $156 $0 $258 $1,975 $4

1.5 Sorbent Receive & Unload $164 $0 $49 $0 $212 $21 $0 $35 $269 $0

1.6 Sorbent Stackout & Reclaim $2,644 $0 $478 $0 $3,122 $312 $0 $515 $3,949 $7

1.7 Sorbent Conveyors $943 $205 $228 $0 $1,376 $138 $0 $227 $1,741 $3

1.8 Other Sorbent Handling $570 $134 $295 $0 $999 $100 $0 $165 $1,263 $2

1.9 Coal & Sorbent Hnd. Foundations $0 $4,756 $6,270 $0 $11,026 $1,103 $0 $1,819 $13,948 $25

Subtotal $19,948 $5,095 $11,797 $0 $36,840 $3,684 $0 $6,079 $46,602 $85

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $2,351 $0 $452 $0 $2,803 $280 $0 $462 $3,545 $6

2.2 Coal Conveyor to Storage $6,019 $0 $1,296 $0 $7,315 $731 $0 $1,207 $9,253 $17

2.5 Sorbent Prep Equipment $4,491 $194 $920 $0 $5,605 $560 $0 $925 $7,090 $13

2.6 Sorbent Storage & Feed $541 $0 $204 $0 $745 $75 $0 $123 $943 $2

2.9 Coal & Sorbent Feed Foundation $0 $548 $481 $0 $1,029 $103 $0 $170 $1,301 $2

Subtotal $13,401 $742 $3,353 $0 $17,496 $1,750 $0 $2,887 $22,133 $40

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $18,097 $0 $6,235 $0 $24,332 $2,433 $0 $4,015 $30,780 $56

3.2 Water Makeup & Pretreating $5,536 $0 $1,751 $0 $7,288 $729 $0 $1,603 $9,620 $17

3.3 Other Feedwater Subsystems $6,083 $0 $2,497 $0 $8,581 $858 $0 $1,416 $10,855 $20

3.4 Service Water Systems $1,109 $0 $580 $0 $1,689 $169 $0 $372 $2,229 $4

3.5 Other Boiler Plant Systems $7,482 $0 $7,074 $0 $14,556 $1,456 $0 $2,402 $18,413 $33

3.6 FO Supply Sys & Nat Gas $327 $0 $382 $0 $709 $71 $0 $117 $897 $2

3.7 Waste Treatment Equipment $3,632 $0 $2,103 $0 $5,735 $573 $0 $1,262 $7,570 $14

3.8 Misc. Equip. (Cranes, Air Comp., 

Comm.)

$3,205 $0 $991 $0 $4,197 $420 $0 $923 $5,540 $10

Subtotal $45,472 $0 $21,614 $0 $67,086 $6,709 $0 $12,109 $85,903 $156

4 Boiler & Accessories

4.1 PC Boiler & Accessories $152,353 $0 $99,495 $0 $251,848 $25,185 $0 $27,703 $304,736 $554

4.2 SCR w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0

Subtotal $152,353 $0 $99,495 $0 $251,848 $25,185 $0 $27,703 $304,736 $554

5A Gas Cleanup & Piping

5A.1 Absorber Vessels & Accessories $69,501 $0 $14,860 $0 $84,361 $8,436 $0 $9,280 $102,077 $186

5A.2 Other FGD $3,627 $0 $4,082 $0 $7,709 $771 $0 $848 $9,328 $17
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Case: B11A – Subcritical PC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.3 Bag House & Accessories $19,695 $0 $12,414 $0 $32,109 $3,211 $0 $3,532 $38,852 $71

5A.4 Other Particulate Removal Materials $1,333 $0 $1,417 $0 $2,749 $275 $0 $302 $3,327 $6

5A.5 Gypsum Dewatering System $5,536 $0 $934 $0 $6,470 $647 $0 $712 $7,829 $14

5A.6 Mercury Removal System $4,205 $925 $4,135 $0 $9,265 $927 $0 $1,019 $11,211 $20

Subtotal $103,898 $925 $37,841 $0 $142,664 $14,266 $0 $15,693 $172,623 $314

7 HRSG, Ducting, & Stack

7.3 Ductwork $10,981 $0 $6,932 $0 $17,913 $1,791 $0 $2,956 $22,660 $41

7.4 Stack $10,920 $0 $6,346 $0 $17,267 $1,727 $0 $1,899 $20,893 $38

7.9 Duct & Stack Foundations $0 $1,190 $1,413 $0 $2,604 $260 $0 $573 $3,437 $6

Subtotal $21,902 $1,190 $14,692 $0 $37,784 $3,778 $0 $5,428 $46,990 $85

8 Steam Turbine Generator

8.1 Steam TG & Accessories $66,400 $0 $7,465 $0 $73,865 $7,387 $0 $8,125 $89,377 $163

8.2 Turbine Plant Auxiliaries $419 $0 $891 $0 $1,310 $131 $0 $144 $1,585 $3

8.3 Condenser & Auxiliaries $8,232 $0 $2,742 $0 $10,974 $1,097 $0 $1,207 $13,279 $24

8.4 Steam Piping $26,402 $0 $10,700 $0 $37,102 $3,710 $0 $6,122 $46,934 $85

8.9 TG Foundations $0 $1,249 $2,062 $0 $3,311 $331 $0 $728 $4,371 $8

Subtotal $101,453 $1,249 $23,861 $0 $126,563 $12,656 $0 $16,327 $155,546 $283

9 Cooling Water System

9.1 Cooling Towers $11,134 $0 $3,443 $0 $14,577 $1,458 $0 $1,604 $17,639 $32

9.2 Circulating Water Pumps $2,236 $0 $143 $0 $2,378 $238 $0 $262 $2,878 $5

9.3 Circ. Water System Auxiliaries $612 $0 $81 $0 $693 $69 $0 $76 $839 $2

9.4 Circ. Water Piping $0 $5,158 $4,671 $0 $9,829 $983 $0 $1,622 $12,434 $23

9.5 Make-up Water System $554 $0 $712 $0 $1,266 $127 $0 $209 $1,602 $3

9.6 Component Cooling Water Sys. $499 $0 $383 $0 $882 $88 $0 $146 $1,116 $2

9.9 Circ. Water Foundations & Structures $0 $2,726 $4,526 $0 $7,252 $725 $0 $1,595 $9,573 $17

Subtotal $15,035 $7,884 $13,960 $0 $36,879 $3,688 $0 $5,513 $46,080 $84

10 Ash & Spent Sorbent Handling Systems

10.6 Ash Storage Silos $796 $0 $2,435 $0 $3,231 $323 $0 $355 $3,909 $7

10.7 Ash Transport & Feed Equipment $5,286 $0 $5,240 $0 $10,526 $1,053 $0 $1,158 $12,736 $23

10.9 Ash/Spent Sorbent Foundation $0 $180 $221 $0 $401 $40 $0 $88 $529 $1

Subtotal $6,081 $180 $7,896 $0 $14,157 $1,416 $0 $1,601 $17,174 $31

11 Accessory Electric Plant

11.1 Generator Equipment $1,945 $0 $311 $0 $2,256 $226 $0 $186 $2,667 $5

11.2 Station Service Equipment $3,348 $0 $1,122 $0 $4,470 $447 $0 $369 $5,286 $10

11.3 Switchgear & Motor Control $3,843 $0 $668 $0 $4,510 $451 $0 $496 $5,457 $10

11.4 Conduit & Cable Tray $0 $2,635 $8,513 $0 $11,148 $1,115 $0 $1,839 $14,103 $26

11.5 Wire & Cable $0 $5,017 $8,969 $0 $13,986 $1,399 $0 $2,308 $17,692 $32

11.6 Protective Equipment $317 $0 $1,099 $0 $1,416 $142 $0 $156 $1,713 $3

11.7 Standby Equipment $1,499 $0 $35 $0 $1,534 $153 $0 $169 $1,856 $3

11.8 Main Power Transformers $9,846 $0 $206 $0 $10,052 $1,005 $0 $1,106 $12,163 $22

11.9 Electrical Foundations $0 $359 $914 $0 $1,274 $127 $0 $280 $1,681 $3

Subtotal $20,797 $8,012 $21,837 $0 $50,647 $5,065 $0 $6,909 $62,620 $114
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Case: B11A – Subcritical PC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

12 Instrumentation & Control

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $528 $0 $323 $0 $850 $85 $0 $140 $1,076 $2

12.7 Distributed Control Sys. Equipment $5,328 $0 $950 $0 $6,278 $628 $0 $691 $7,596 $14

12.8 Instrument Wiring & Tubing $3,213 $0 $5,846 $0 $9,059 $906 $0 $1,495 $11,459 $21

12.9 Other I & C Equipment $1,506 $0 $3,486 $0 $4,992 $499 $0 $549 $6,040 $11

Subtotal $10,574 $0 $10,605 $0 $21,179 $2,118 $0 $2,875 $26,171 $48

13 Improvements to Site

13.1 Site Preparation $0 $56 $1,196 $0 $1,252 $125 $0 $275 $1,653 $3

13.2 Site Improvements $0 $1,866 $2,465 $0 $4,331 $433 $0 $953 $5,717 $10

13.3 Site Facilities $3,344 $0 $3,508 $0 $6,851 $685 $0 $1,507 $9,044 $16

Subtotal $3,344 $1,922 $7,168 $0 $12,434 $1,243 $0 $2,736 $16,413 $30

14 Buildings & Structures

14.1 Boiler Building $0 $10,193 $8,958 $0 $19,151 $1,915 $0 $5,266 $26,332 $48

14.2 Turbine Building $0 $14,726 $13,715 $0 $28,442 $2,844 $0 $7,821 $39,107 $71

14.3 Administration Building $0 $703 $743 $0 $1,446 $145 $0 $398 $1,988 $4

14.4 Circulation Water Pumphouse $0 $201 $160 $0 $361 $36 $0 $99 $497 $1

14.5 Water Treatment Buildings $0 $691 $629 $0 $1,320 $132 $0 $363 $1,815 $3

14.6 Machine Shop $0 $470 $316 $0 $786 $79 $0 $216 $1,080 $2

14.7 Warehouse $0 $319 $319 $0 $638 $64 $0 $175 $877 $2

14.8 Other Buildings & Structures $0 $260 $221 $0 $482 $48 $0 $132 $662 $1

14.9 Waste Treating Building & Str. $0 $498 $1,511 $0 $2,010 $201 $0 $553 $2,763 $5

Subtotal $0 $28,061 $26,573 $0 $54,634 $5,463 $0 $15,024 $75,122 $137

Total $514,258 $55,260 $300,691 $0 $870,209 $87,021 $0 $120,883 $1,078,113 $1,960
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 3-19 Case B11A owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $8,261 $15

1 Month Maintenance Materials $1,013 $2

1 Month Non-fuel Consumables $2,245 $4

1 Month Waste Disposal $448 $1

25% of 1 Months Fuel Cost at 100% CF $2,577 $5

2% of TPC $21,562 $39

Total $36,106 $66

Inventory Capital

60 day supply of fuel and consumables at 100% CF $24,698 $45

0.5% of TPC (spare parts) $5,391 $10

Total $30,088 $55

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $161,717 $294

Financing Costs $29,109 $53

Total Overnight Costs (TOC) $1,336,034 $2,429

TASC Multiplier (IOU, low-risk, 35 year) 1.134

Total As-Spent Cost (TASC) $1,515,063 $2,755
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 3-20 Case B11A initial and annual operating and maintenance costs

Case: B11A – Subcritical PC w/o CO2 Cost Base: Jun 2011

Plant Size (MW,net): 550 Heat Rate-net (Btu/kWh): 8,740 Capacity Factor (%): 85

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 9.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 2.0 

Total: 14.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $6,329,450 $11.509

Maintenance Labor: $6,888,918 $12.527

Administrative & Support Labor: $3,304,592 $6.009

Property Taxes and Insurance: $21,562,266 $39.209

Total: $38,085,227 $69.254

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $10,333,377 $2.52347

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 3,987 $1.67 $0 $2,070,683 $0.50567

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 19,300 $0.27 $0 $1,603,749 $0.39164

Limestone (ton) 0 489 $33.48 $0 $5,074,576 $1.23924

Hydrated Lime (ton) 0 100 $155.00 $0 $4,791,509 $1.17011

Activated Carbon (ton) 0 3 $1,255.00 $0 $1,120,453 $0.27362

Ammonia (19% NH3, ton) 0 72 $330.00 $0 $7,327,095 $1.78932

SCR Catalyst (m3) 0 0.33 $8,938.80 $0 $908,626 $0.22189

Subtotal: $0 $22,896,691 $5.59150

Waste Disposal

Fly Ash (ton) 0 490 $25.11 $0 $3,816,576 $0.93203

Bottom Ash (ton) 0 96 $25.11 $0 $750,758 $0.18334

 Subtotal: $0 $4,567,334 $1.11537

By-Products

Gypsum (ton) 0 84 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $37,797,401 $9.23034

Fuel Cost

Illinois Number 6 (ton): 0 4,944 $68.54 $0 $105,133,037 $25.67409

Total: $0 $105,133,037 $25.67409

Exhibit 3-21 Case B11A COE breakdown

Component Value, $/MWh Percentage

Capital 37.8 46%

Fixed 9.3 11%

Variable 9.2 11%

Fuel 25.7 31%

Total (Excluding T&S) 82.1 N/A

CO2 T&S 0.0 0%

Total (Including T&S) 82.1 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

92

3.2.7 Case B11B – PC Subcritical Unit with CO2 Capture

The plant configuration for Case B11B, subcritical PC, is the same as Case B11A with the 

exception that the Cansolv system was used for the CDR facility. The nominal net output was 

maintained at 550 MW by increasing the boiler size and turbine/generator size to account for the 

greater auxiliary load imposed by the CDR facility and CO2 compressors. Unlike the NGCC

cases where gross output was fixed by the available size of the CTs, the PC cases utilize boilers 

and steam turbines that can be procured at nearly any desired output making it possible to 

maintain a constant net output.

The process description for Case B11B is essentially the same as Case B11A with one notable 

exception, the addition of CO2 capture and compression. A BFD and stream tables for Case 

B11B are shown in Exhibit 3-22 and Exhibit 3-23, respectively. Since the CDR facility process 

description was provided in Section 3.1.8, it is not repeated here.

3.2.8 Case B11B Performance Results

The Case B11B modeling assumptions were presented previously in Section 3.2.2.

The plant produces a net output of 550 MW at a net plant efficiency of 31.2 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 3-24; Exhibit 3-25 provides a 

detailed breakdown of the auxiliary power requirements. The CDR facility, including CO2

compression, accounts for over half of the auxiliary plant load. The CWS (CWPs and cooling

tower fan) accounts for over 13 percent of the auxiliary load, largely due to the high cooling 

water demand of the CDR facility and CO2 compressors.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

93

Exhibit 3-22 Case B11B block flow diagram, subcritical unit with CO2 capture

Source: NETL

STACK GAS

STACK

CANSOLV

32 31

33

22

23

CO2

PRODUCT

REBOILER

STEAM

REBOILER

CONDENSATE

PULVERIZED

COAL

BOILER

SCR

BAGHOUSE FGD

LIMESTONE GYPSUM

SLURRY

OXIDATION

AIR

MAKEUP

WATER

BOTTOM ASH

COAL FEED

INFILTRATION

AIR

1

4

8

7

9

14

FLY ASH

15 16

18 19

17 20

21

HP 

TURBINE

34

35

36

IP

TURBINE LP TURBINE

CONDENSER

38

FEEDWATER 

HEATER

SYSTEM

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

3

2

6

5

11

37

10

HYDRATED

LIME

12

13

ACTIVATED

CARBON

FD FANS

PA FANS

ID FAN

CO2 COMPRESSORS

BOILER

FEEDWATER

29 RECLAIMER

STEAM 30

RECLAIMER

CONDENSATE

DRYER

27

CO2 COMPRESSORS

28

25 26

24

VENT

DRYER STEAM

DRYER

CONDENSATE
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

94

Exhibit 3-23 Case B11B stream table, subcritical unit with capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0000 0.0088 0.0000 0.0088 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.0000 0.1376 0.0000 0.1376 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0000 0.0831 0.0000 0.0831 0.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.0000 0.7345 0.0000 0.7345 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0000 0.0340 0.0000 0.0340 0.3333

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0020 0.0000 0.0020 0.6667

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 64,558 64,558 1,912 19,831 19,831 2,729 1,410 0 0 0 90,489 0 90,489 4

V-L Flowrate (kg/hr) 1,862,938 1,862,938 55,177 572,275 572,275 78,760 40,691 0 0 0 2,687,332 0 2,687,332 206

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 234,131 4,541 4,719 22,881 136 23,017 23,017

Temperature (°C) 15 19 19 15 25 25 15 15 149 27 143 27 143 143

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

Steam Table Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 0.00 0.00 0.00 --- ---

AspenPlus Enthalpy (kJ/kg)B -97.58 -93.45 -93.45 -97.58 -87.03 -87.03 -97.58 -2,114.05 97.18 -13,306.82 -2,399.50 3.40 -2,399.38 -2,632.03

Density (kg/m3) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- --- 0.9 --- 0.9 1.5

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- --- 29.698 --- 29.698 53.376

V-L Flowrate (lbmole/hr) 142,325 142,325 4,215 43,721 43,721 6,017 3,109 0 0 0 199,495 0 199,495 9

V-L Flowrate (lb/hr) 4,107,075 4,107,075 121,644 1,261,650 1,261,650 173,636 89,709 0 0 0 5,924,552 0 5,924,552 454

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 516,170 10,010 10,403 50,444 300 50,745 50,745

Temperature (°F) 59 66 66 59 78 78 59 59 300 80 289 80 289 289

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.4 14.7 14.4 14.7 14.4 14.4

Steam Table Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- --- ---

AspenPlus Enthalpy (Btu/lb)B -42.0 -40.2 -40.2 -42.0 -37.4 -37.4 -42.0 -908.9 41.8 -5,720.9 -1,031.6 1.5 -1,031.5 -1,131.6

Density (lb/ft3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- --- 0.053 --- 0.053 0.096

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

95

Exhibit 3-23 Case B11B stream table, subcritical unit with capture (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28

V-L Mole Fraction

Ar 0.0088 0.0088 0.0000 0.0000 0.0092 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1376 0.1376 0.0000 0.0000 0.0003 0.0001 0.1288 0.9824 0.9977 0.0497 0.0000 0.0000 0.9993 0.9993

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0831 0.0831 1.0000 1.0000 0.0099 0.9999 0.1451 0.0176 0.0023 0.9503 1.0000 1.0000 0.0007 0.0007

N2 0.7345 0.7345 0.0000 0.0000 0.7732 0.0000 0.6854 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0340 0.0340 0.0000 0.0000 0.2074 0.0000 0.0325 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0020 0.0020 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 90,485 90,485 2,999 12,020 957 221 98,055 11,571 11,394 19 15 15 11,375 11,375

V-L Flowrate (kg/hr) 2,687,126 2,687,126 54,035 216,549 27,615 3,988 2,829,081 503,956 500,768 364 264 264 500,404 500,404

Solids Flowrate (kg/hr) 0 0 23,136 0 0 35,882 0 0 0 0 0 0 0 0

Temperature (°C) 143 153 15 27 167 56 56 29 29 29 476 203 29 40

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.31 0.10 0.10 0.20 3.03 3.03 2.42 1.70 2.89 15.27

Steam Table Enthalpy (kJ/kg) A 274.36 285.60 --- 111.65 184.48 --- 286.10 42.52 -6.01 137.83 3,408.95 863.91 -5.92 -205.59

AspenPlus Enthalpy (kJ/kg)B -2,397.37 -2,386.12 -14,995.75 -15,964.53 56.67 -12,481.91 -2,940.32 -8,972.02 -8,974.91 -15,229.20 -12,571.34 -15,116.38 -8,970.17 -9,169.84

Density (kg/m3) 0.8 0.9 1,003.6 992.3 2.4 833.2 1.1 3.5 63.3 374.4 7.1 861.8 59.9 789.2

V-L Molecular Weight 29.697 29.697 18.015 18.015 28.857 18.018 28.852 43.553 43.950 19.308 18.015 18.015 43.991 43.991

V-L Flowrate (lbmole/hr) 199,486 199,486 6,613 26,500 2,110 488 216,174 25,510 25,120 42 32 32 25,078 25,078

V-L Flowrate (lb/hr) 5,924,098 5,924,098 119,126 477,408 60,881 8,792 6,237,055 1,111,033 1,104,005 803 581 581 1,103,202 1,103,202

Solids Flowrate (lb/hr) 0 0 51,005 0 0 79,106 0 0 0 0 0 0 0 0

Temperature (°F) 289 308 59 80 332 133 133 85 85 85 888 397 85 104

Pressure (psia) 14.2 15.2 15.0 15.7 45.0 14.7 14.7 28.7 439.4 439.4 350.5 247.3 419.4 2,214.7

Steam Table Enthalpy (Btu/lb)A 118.0 122.8 --- 48.0 79.3 --- 123.0 18.3 -2.6 59.3 1,465.6 371.4 -2.5 -88.4

AspenPlus Enthalpy (Btu/lb)B -1,030.7 -1,025.8 -6,447.0 -6,863.5 24.4 -5,366.3 -1,264.1 -3,857.3 -3,858.5 -6,547.4 -5,404.7 -6,498.9 -3,856.5 -3,942.3

Density (lb/ft3) 0.052 0.055 62.650 61.950 0.153 52.013 0.067 0.216 3.953 23.375 0.446 53.800 3.737 49.267

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

96

Exhibit 3-23 Case B11B stream table, subcritical unit with capture (continued)

29 30 31 32 33 34 35 36 37 38

V-L Mole Fraction

Ar 0.0000 0.0000 0.0000 0.0000 0.0103 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0000 0.0000 0.0000 0.0000 0.0163 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 1.0000 1.0000 1.0000 0.0671 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.0000 0.0000 0.0000 0.0000 0.8652 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0410 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 87 87 29,214 29,214 77,673 110,081 102,661 102,661 61,864 63,201

V-L Flowrate (kg/hr) 1,561 1,561 526,301 526,300 2,166,238 1,983,144 1,849,458 1,849,458 1,114,489 1,138,575

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 355 215 266 151 41 566 355 566 38 39

Pressure (MPa, abs) 4.28 2.20 0.51 0.51 0.10 16.65 4.28 4.19 0.01 1.32

Steam Table Enthalpy (kJ/kg) A 3,098.44 921.65 2,994.07 635.95 151.94 3,473.89 3,098.44 3,593.58 1,976.98 162.43

AspenPlus Enthalpy (kJ/kg)B -12,881.86 -15,058.64 -12,986.23 -15,344.34 -794.66 -12,506.41 -12,881.86 -12,386.71 -14,003.31 -15,817.87

Density (kg/m3) 16.0 846.4 2.1 916.3 1.1 47.7 16.0 11.1 0.1 993.3

V-L Molecular Weight 18.015 18.015 18.015 18.015 27.889 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmole/hr) 191 191 64,406 64,406 171,241 242,688 226,328 226,328 136,386 139,333

V-L Flowrate (lb/hr) 3,441 3,441 1,160,294 1,160,293 4,775,737 4,372,084 4,077,357 4,077,357 2,457,027 2,510,129

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 671 419 512 304 107 1,050 671 1,050 101 101

Pressure (psia) 620.5 319.0 73.5 73.5 14.7 2,414.7 620.5 608.1 1.0 190.7

Steam Table Enthalpy (Btu/lb)A 1,332.1 396.2 1,287.2 273.4 65.3 1,493.5 1,332.1 1,545.0 850.0 69.8

AspenPlus Enthalpy (Btu/lb)B -5,538.2 -6,474.0 -5,583.1 -6,596.9 -341.6 -5,376.8 -5,538.2 -5,325.3 -6,020.3 -6,800.5

Density (lb/ft3) 1.000 52.840 0.129 57.202 0.068 2.975 1.000 0.692 0.004 62.010

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

97

Exhibit 3-24 Case B11B plant performance summary

Performance Summary

Total Gross Power, MWe 644

CO2 Capture/Removal Auxiliaries, kWe 16,600

CO2 Compression, kWe 36,560

Balance of Plant, kWe 41,161

Total Auxiliaries, MWe 94

Net Power, MWe 550

HHV Net Plant Efficiency (%) 31.2%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,556 (10,953)

LHV Net Plant Efficiency (%) 32.3%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,146 (10,565)

HHV Boiler Efficiency, % 89.1%

LHV Boiler Efficiency, % 92.4%

Steam Turbine Cycle Efficiency, % 52.5%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 6,854 (6,497)

Condenser Duty, GJ/hr (MMBtu/hr) 2,022 (1,916)

As-Received Coal Feed, kg/hr (lb/hr) 234,131 (516,170)

Limestone Sorbent Feed, kg/hr (lb/hr) 23,136 (51,005)

HHV Thermal Input, kWt 1,764,768

LHV Thermal Input, kWt 1,702,141

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.058 (15.4)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.045 (11.9)

Excess Air, % 20.9%
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

98

Exhibit 3-25 Case B11B plant power summary

Power Summary

Steam Turbine Power, MWe 644

Total Gross Power, MWe 644

Auxiliary Load Summary

Coal Handling and Conveying, kWe 490

Pulverizers, kWe 3,510

Sorbent Handling & Reagent Preparation, kWe 1,110

Ash Handling, kWe 820

Primary Air Fans, kWe 1,740

Forced Draft Fans, kWe 2,220

Induced Draft Fans, kWe 8,700

SCR, kWe 60

Activated Carbon Injection, kWe 28

Dry sorbent Injection, kWe 113

Baghouse, kWe 110

Wet FGD, kWe 3,700

CO2 Capture/Removal Auxiliaries, kWe 16,600

CO2 Compression, kWe 36,560

Miscellaneous Balance of PlantA,B, kWe 2,000

Steam Turbine Auxiliaries, kWe 400

Condensate Pumps, kWe 550

Circulating Water Pumps, kWe 8,210

Ground Water Pumps, kWe 760

Cooling Tower Fans, kWe 4,250

Transformer Losses, kWe 2,400

Total Auxiliaries, MWe 94

Net Power, MWe 550

ABoiler feed pumps are turbine driven

BIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.2.8.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case B11B is presented in Exhibit 3-26. SO2

emissions are utilized as a surrogate for HCl emissions, therefore HCl is not reported.

Exhibit 3-26 Case B11B air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)

SO2 0.000 (0.000) 0 (0) 0.000 (0.000)

NOx 0.032 (0.075) 1,523 (1,679) 0.318 (0.700)

Particulate 0.004 (0.010) 196 (216) 0.041 (0.090)

Hg 1.38E-7 (3.21E-7) 0.007 (0.007) 1.36E-6 (3.00E-6)

CO2B 9 (20) 413,912 (456,260) 86 (190)

CO2C - - 101 (223)

mg/Nm3

Particulate ConcentrationD,E 12.97

ACalculations based on an 85 percent capacity factor

BCO2 emissions based on gross power

CCO2 emissions based on net power instead of gross power DConcentration of particles in the flue gas after the baghouse

ENormal conditions given at 32°F and 14.696 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

99

SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a 

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. 

The wallboard grade material can potentially be marketed and sold, but since it is highly 

dependent on local market conditions, no byproduct credit was taken. The SO2 emissions are 

further reduced to 1 ppmv using a NaOH based polishing scrubber in the CDR facility. The 

remaining low concentration of SO2 is essentially completely removed in the CDR absorber 

vessel resulting in very low SO2 emissions.

NOx emissions are controlled to about 0.5 lb/MMBtu through the use of LNBs and OFA. An 

SCR unit then further reduces the NOx concentration by 85 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.

The total reduction in mercury emission via the combined control equipment (SCR, ACI, fabric 

filter, DSI, and wet FGD) is 97.2 percent.

Ninety percent of the CO2 in the flue gas is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 3-27. The carbon input to the plant consists 

of carbon in the coal, carbon in the air, PAC, and carbon in the limestone reagent used in the 

FGD absorber. Carbon leaves the plant mostly as CO2 through the stack, however, the PAC is 

captured in the fabric filter and some leaves as gypsum. The carbon capture efficiency is defined 

as one minus the amount of carbon in the stack gas relative to the total carbon in, represented by 

the following fraction: 

CCCCCCCC SSSS

( TT CCCCCCCC ) = �1 − � 33,446

335,258� ∗� 100 = 90.0%

Exhibit 3-27 Case B11B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 149,246 (329,031) Stack Gas 15,171 (33,446)

Air (CO2) 340 (751) FGD Product 224 (494)

PAC 136 (300) Baghouse 136 (300)

FGD Reagent 2,348 (5,175) CO2 Product 136,528 (300,992)

CO2 Dryer Vent 11 (25)

CO2 Knockout 0 (1)

Total 152,070 (335,258) Total 152,070 (335,258)

Exhibit 3-28 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum, sulfur emitted in

the stack gas, and sulfur removed in the polishing scrubber.

Exhibit 3-28 Case B11B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,868 (12,937) FGD Product 5,670 (12,500)

Stack Gas 0 (0)

Polishing Scrubber and Solvent Reclaiming 116 (255)

Baghouse 82 (182)

Total 5,868 (12,937) Total 5,868 (12,937)
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

100

Exhibit 3-29 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as was for Case B11A.

Exhibit 3-29 Case B11B water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

FGD Makeup 4.52 (1,193) – 4.52 (1,193) – 4.52 (1,193)

CO2 Drying – – – 0.01 (2) -0.01 (-2)

Capture System 

Makeup 0.02 (6) – 0.02 (6) – 0.02 (6)

Deaerator Vent – – – 0.07 (18) -0.07 (-18)

Condenser Makeup 0.40 (106) – 0.40 (106) – 0.40 (106)

 BFW Makeup 0.40 (106) – 0.40 (106) – 0.40 (106)

Cooling Tower 31.99 

(8,451) 4.98 (1,315) 27.01 (7,136) 7.19 (1,900) 19.82 (5,235)

 FGD Dewatering – 2.33 (615) -2.33 (-615) – -2.33 (-615)

 CO2 Capture 

 Recovery – 2.65 (700) -2.65 (-700) – -2.65 (-700)

 CO2 Compression 

 KO – 0.05 (14) -0.05 (-14) – -0.05 (-14)

 BFW Blowdown – 0.34 (89) -0.34 (-89) – -0.34 (-89)

Total 36.93 

(9,755) 4.98 (1,315) 31.95 (8,441) 7.27 (1,920) 24.68 (6,521)

3.2.8.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the Case B11B PC boiler, the FGD unit, CDR 

system and steam cycle in Exhibit 3-30 and Exhibit 3-31. An overall plant energy balance is 

provided in tabular form in Exhibit 3-32. 

The power out is the steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-24) is calculated by multiplying the power out by a generator 

efficiency of 98.5 percent. The capture process heat out stream represents heat rejected to 

cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser 

heat out stream. The CO2 compressor intercooler load is included in the capture process heat out 

stream.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

101

Exhibit 3-30 Case B11B heat and mass balance, subcritical PC boiler with CO2 capture

Source: NETL

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

1 OF 2

BITUMINOUS BASELINE STUDY

CASE B11B

SUBCRITICAL PULVERIZED COAL

BOILER AND GAS CLEANUP SYSTEMS

DWG. NO.

BB-HMB-CS-B11B-PG-1

Pulverized

Coal

Boiler

Ammonia SCR

Infiltration Air

Air

Air

Coal

Bottom Ash

FGD

Fly Ash

Forced

Draft Fans

Primary 

Air Fans

516,170 W

59 T

15 P

78 T

16 P

18 H

66 T

15 P

15 H

4,372,084 W

1,050 T

2,415 P

1,494 H

4,077,357 W

1,050 T

608 P

1,545 H

1,261,650 W

59 T

15 P

13 H

4,107,075 W

59 T

15 P

13 H

89,709 W

59 T

15 P

13 H

5,974,996 W

289 T

14 P

117 H

10,010 W

300 T

14 P

51,199 W

289 T

14 P

4,077,357 W

671 T

621 P

1,332 H

4,372,084 W

486 T

2,536 P

471 H

5

4,775,737 W

107 T

15 P

65 H

1 2

4

7

9

5,924,098 W ID Fans

289 T

14 P

118 H

Gross Plant Power: 644 MWe

Auxiliary Load: 94 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 31.2%

Net Plant Heat Rate: 10,953 Btu/kWh

Oxidation 

Air

Make-Up 

Water

Limestone 

Slurry

Gypsum

18

17

14

5,924,098 W

308 T

15 P

123 H

170,131 W

59 T

15 P

423 H

60,881 W

332 T

45 P

79 H

477,408 W

80 T

16 P

48 H

87,898 W

133 T

15 P

1,499 H

Baghouse

3

6

8

15 16

19

34

35

36

DOE/NETL

SC PC PLANT

CASE B11B

Hydrated 

Lime

11

Single Reheat

Extraction from

HP Turbine

From Feedwater

Heaters

Single Reheat

To IP Turbine

Throttle Steam

To HP Turbine

10,403 W

80 T

15 P

10

Activated 

Carbon

12

13

300 W

80 T

15 P

Cansolv

Stripper

Absorber

Flue Gas Acid Gas

1,111,033 W

85 T

29 P

18 H

22

33

6,237,055 W

133 T

15 P

123 H

Stack

21

1,103,202 W

104 T

2,215 P

-88 H

CO2

Product

CO2 Compression 

(Interstage Cooling) & 

Drying

7,028 W

85 T

62 P

66 H

KO-Water

Dryer 

Water

803 W

85 T

439 P

59 H

24

Dryer

28

23

27

1,103,202 W

85 T

419 P

-3 H

1,104,005 W

85 T

439 P

-3 H

5,975,297 W

289 T

14 P

117 H

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

20

Air

Coal/Ash

Slurry

Water

Steam

Lime/

Limestone/

Gypsum

Flue Gas

Activated 

Carbon

Ammonia

Carbon Dioxide
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

102

Exhibit 3-31 Case B11B heat and mass balance, subcritical steam cycle

Source: NETL

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

Water

Steam

PAGES

2 OF 2

DWG. NO.

BB-HMB-CS-B11B-PG-2

BITUMINOUS BASELINE STUDY

CASE B11B

SUBCRITICAL PULVERIZED COAL

POWER BLOCK SYSTEMS

LP Turbine Generator HP

Turbine

IP

Turbine

Condenser

Hot Well

Boiler Feed Pump 

Turbine Drives

Throttle

Steam

Condensate 

Pumps

4,372,084 W

1,050 T

2,415 P

1,494 H

431,232 W

887 T

336 P

1,466 H

291,286 W

669 T

596 P

1,332 H

4,077,357 W

671 T

621 P

1,332 H

218,704 W

512 T

74 P

1,287 H

218,704 W

126 T

2 P

1,071 H

1,808,607 W

101 T

1 P

1,006 H

2,510,129 W

101 T

1 P

69 H

2,510,129 W

101 T

191 P

70 H

2,510,129 W

155 T

183 P

124 H

429,716 W

111 T

1 P

79 H

312,590 W

165 T

5 P

133 H

2,510,129 W

290 T

162 P

259 H

722,518 W

321 T

90 P

291 H

2,510,129 W

262 T

169 P

231 H

291,286 W

440 T

382 P

419 H

4,372,084 W

430 T

2,642 P

410 H

Deaerator

Boiler Feed

Water Pumps

4,372,084 W

486 T

2,536 P

471 H

4,077,357 W

1,050 T

608 P

1,545 H

67,760 W

272 T

43 P

241 H

225,307 W

204 T

13 P

172 H

2,510,129 W

194 T

176 P

163 H

28,224 W

511 T

72 P

1,287 H

67,760 W

484 T

62 P

1,275 H

157,547 W

402 T

40 P

1,237 H

87,283 W

200 T

11 P

1,146 H

117,126 W

160 T

5 P

1,094 H

3,617,320 W

512 T

74 P

1,287 H

2,238,323 W

512 T

74 P

1,287 H

2,752 P

4,372,084 W

305 T

72 P

275 H

Gross Plant Power: 644 MWe

Auxiliary Load: 94 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 31.2%

Net Plant Heat Rate: 10,953 Btu/kWh

FWH 4 FWH 3 FWH 2 FWH 1 FWH 6 FWH 5

34

38

DOE/NETL

SC PC PLANT

CASE B11B

36

53,102 W

59 T

15 P

27 H

Blowdown

Vent

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

Single Reheat

Extraction

From Boiler

Single Reheat

Extraction to

Boiler

To Boiler

Steam Turbine

Makeup

35

Reclaimer 

Steam

29

581 W

888 T

351 P

1,466 H

Dryer

Steam

Reboiler

Steam

1,160,294 W

512 T

74 P

1,287 H

25

31

32

30

Reboiler

Condensate

Reclaimer

Condensate

26

Dryer 

Condensate

581 W

397 T

247 P

371 H

3,441 W

419 T

319 P

396 H

1,160,293 W

304 T

74 P

273 H

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

37

3,441 W

671 T

621 P

1,332 H
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

103

Exhibit 3-32 Case B11B overall energy balance (0°C [32°F] reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,353 

(6,022) 5.3 (5.0) – 6,358 (6,027)

Air – 74.8 (70.9) – 74.8 (70.9)

Raw Water Makeup – 120.1 (113.9) – 120.1 (113.9)

Limestone – 0.50 (0.48) – 0.50 (0.48)

Auxiliary Power – – 340 (322) 340 (322)

TOTAL 6,353 

(6,022) 200.8 (190.3) 340 (322) 6,894 (6,534)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash – 0.5 (0.5) – 0.5 (0.5)

Fly Ash + FGD Ash – 2.6 (2.5) – 2.6 (2.5)

Stack Gas – 329 (312) – 329 (312)

Sulfur 2.1 (2.0) 0.0 (0.0) – 2.2 (2.0)

Motor Losses and Design 

Allowances – – 44 (42) 44 (42)

Condenser – 2,022 (1,916) – 2,022 (1,916)

Non-Condenser Cooling 

Tower Loads – 106 (100) – 106 (100)

CO2 – -102.9 (-97.5) – -102.9 (-

97.5)

Cooling Tower Blowdown – 53.4 (50.7) – 53.4 (50.7)

CO2 Capture Losses – 2,050 (1,943) – 2,050 (1,943)

Ambient LossesA – 137.2 (130.0) – 137.2 (130.0)

Power – – 2,319 (2,198) 2,319 (2,198)

TOTAL 2.1 (2.0) 4,492 (4,358) 2,363 (2,240) 6,857 (6,599)

Unaccounted EnergyB – 36 (-66) – 36 (-66)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the boiler, reheater, superheater, and transformers.

BBy difference

3.2.9 Case B11B – Major Equipment List

Major equipment items for the subcritical PC plant with CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 3.2.10. 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.

Case B11B – Account 1: Coal and Sorbent Handling

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 180 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, 

linear 1,130 tonne/hr (1,250 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

104

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

8 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

9 Feeder Vibratory 190 tonne/hr (210 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 390 tonne/hr (430 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 190 tonne (210 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 390 tonne/hr (430 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 390 tonne/hr (430 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide 

Gates Field erected 860 tonne (900 ton) 3 0

19 Activated Carbon Storage Silo and 

Feeder System

Shop 

assembled

Silo - 36 tonne (40 ton)

Feeder - 150 kg/hr (330 

lb/hr)

1 0

20 Hydrated Lime Storage Silo and 

Feeder System

Shop 

assembled

Silo - 250 tonne (270 ton)

Feeder - 5,190 kg/hr 

(11,440 lb/hr)

1 0

21 Limestone Truck Unloading Hopper N/A 30 tonne (40 ton) 1 0

22 Limestone Feeder Belt 100 tonne/hr (110 tph) 1 0

23 Limestone Conveyor No. L1 Belt 100 tonne/hr (110 tph) 1 0

24 Limestone Reclaim Hopper N/A 20 tonne (20 ton) 1 0

25 Limestone Reclaim Feeder Belt 80 tonne/hr (80 tph) 1 0

26 Limestone Conveyor No. L2 Belt 80 tonne/hr (80 tph) 1 0

27 Limestone Day Bin w/ actuator 310 tonne (340 ton) 2 0

Case B11B – Account 2: Coal and Sorbent Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Coal Feeder Gravimetric 40 tonne/hr (50 tph) 6 0

2 Coal Pulverizer Ball type or 

equivalent 40 tonne/hr (50 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 25 tonne/hr (28 tph) 1 1

4 Limestone Ball Mill Rotary 25 tonne/hr (28 tph) 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 97,700 liters (26,000 gal) 1 1

6 Limestone Mill Recycle 

Pumps Horizontal centrifugal 1,620 lpm @ 10m H2O (430 gpm @ 40 ft H2O) 1 1

7 Hydroclone Classifier 4 active cyclones in a 

5 cyclone bank

410 lpm (110 gpm) per 

cyclone 1 1

8 Distribution Box 2-way N/A 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 550,000 liters (145,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1,150 lpm @ 9m H2O 

(300 gpm @ 30 ft H2O) 1 1

Case B11B – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor

1,592,000 liters (421,000 

gal) 2 0

2 Condensate Pumps Vertical canned 21,000 lpm @ 200 m H2O 

(5,600 gpm @ 500 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

105

Equipment 

No. Description Type Design Condition Operating Qty. Spares

3 Deaerator and Storage 

Tank Horizontal spray type

2,208,000 kg/hr 

(4,868,000 lb/hr), 

5 min. tank

1 0

4 Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

36,600 lpm @ 2,300 m H2O 

(9,700 gpm @ 7,500 ft H2O) 1 1

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

10,900 lpm @ 2,300 m H2O 

(2,900 gpm @ 7,500 ft H2O) 1 0

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 630,000 kg/hr (1,380,000 lb/hr) 2 0

7 LP Feedwater Heater 

2A/2B Horizontal U-tube 630,000 kg/hr (1,380,000 lb/hr) 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 630,000 kg/hr (1,380,000 lb/hr) 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 630,000 kg/hr (1,380,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 2,180,000 kg/hr 

(4,810,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 2,180,000 kg/hr 

(4,810,000 lb/hr) 1 0

12 Auxiliary Boiler Shop fabricated, water 

tube

20,000 kg/hr, 2.8 MPa, 

343°C (40,000 lb/hr, 400 

psig, 650°F)

1 0

13 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

14 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig) 2 1

15 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

16 Closed Cycle Cooling 

Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

17 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,800 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

18 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O) 1 1

19 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O) 1 1

20 Raw Water Pumps Stainless steel, single 

suction

9,170 lpm @ 20 m H2O 

(2,420 gpm @ 60 ft H2O) 2 1

21 Ground Water Pumps Stainless steel, single 

suction

3,670 lpm @ 270 m H2O 

(970 gpm @ 880 ft H2O) 5 1

22 Filtered Water Pumps Stainless steel, single 

suction

2,420 lpm @ 50 m H2O 

(640 gpm @ 160 ft H2O) 2 1

23 Filtered Water Tank Vertical, cylindrical 2,318,000 liter (612,000 gal) 1 0

24 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

830 lpm (220 gpm) 1 1

25 Liquid Waste Treatment 

System -- 10 years, 24-hour storm 1 0

Case B11B – Account 4: Boiler and Accessories

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Boiler

Subcritical, drum wall-fired, 

low NOx burners, overfire 

air

2,180,000 kg/hr steam 

@ 17.9 MPa/574°C/574°C 

(4,810,000 lb/hr steam 

@ 2,600 psig/1,065°F/1,065°F)

1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

106

Equipment 

No. Description Type Design Condition Operating Qty. Spares

2 Primary Air Fan Centrifugal

315,000 kg/hr, 4,300 m3/min 

@ 123 cm WG 

(694,000 lb/hr, 151,700 acfm 

@ 48 in. WG)

2 0

3 Forced Draft 

Fan Centrifugal

1,025,000 kg/hr, 14,000 m3/min 

@ 47 cm WG 

(2,259,000 lb/hr, 493,800 acfm 

@ 19 in. WG)

2 0

4 Induced Draft 

Fan Centrifugal

1,478,000 kg/hr, 29,300 m3/min 

@ 89 cm WG 

(3,258,000 lb/hr, 1,035,400 acfm 

@ 35 in. WG)

2 0

5 SCR Reactor 

Vessel Space for spare layer 2,960,000 kg/hr (6,520,000 lb/hr) 2 0

6 SCR Catalyst -- -- 3 0

7 Dilution Air 

Blower Centrifugal 170 m3/min @ 108 cm WG (5,800 acfm @ 42 in. WG) 2 1

8 Ammonia 

Storage Horizontal tank 182,000 liter (48,000 gal) 5 0

9 Ammonia Feed 

Pump Centrifugal 35 lpm @ 90 m H2O (9 gpm @ 300 ft H2O) 2 1

Case B11B – Account 5A: Flue Gas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter

Single stage, high-ratio 

with pulse-jet online 

cleaning system

1,478,000 kg/hr (3,259,000 

lb/hr) 99.9% efficiency 2 0

2 Absorber Module Counter-current open 

spray

59,000 m3/min 

(2,082,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 205,000 lpm @ 65 m H2O 

(54,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal centrifugal 4,990 lpm (1,320 gpm) 

at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 100 m3/min @ 0.3 MPa 

(3,660 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units 

each

1,250 lpm (330 gpm) per 

cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 39 tonne/hr (44 tph) of 50 wt 

% slurry 2 1

9 Filtrate Water Return 

Pumps Horizontal centrifugal 760 lpm @ 13 m H2O (200 gpm @ 40 ft H2O) 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 500,000 lpm (130,000 gal) 1 0

11 Process Makeup 

Water Pumps Horizontal centrifugal 3,980 lpm @ 21 m H2O (1,050 gpm @ 70 ft H2O) 1 1

12 Activated Carbon 

Injectors --- 150 kg/hr (330 lb/hr) 1 0

13 Hydrated Lime 

Injectors --- 5,190 kg/hr (11,440 lb/hr) 1 0

Case B11B – Account 5B: Carbon Dioxide Recovery

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Cansolv Amine-based CO2

capture technology

1,556,000 kg/hr (3,430,000 lb/hr) 

19.6 wt % CO2 concentration 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

107

Equipment 

No. Description Type Design Condition Operating Qty. Spares

2

Cansolv LP 

Condensate 

Pump

Centrifugal 10,788 lpm @ 1 m H2O 

(2,850 gpm @ 4 ft H2O) 1 1

3

Cansolv HP 

Condensate 

Pump

Centrifugal 10,782 lpm @ 1.1 m H2O 

(2,848 gpm @ 4 ft H2O) 1 1

4 CO2 Dryer Triethylene glycol

Inlet: 132.0 m3/min (4,655 acfm) @ 

3.0 MPa (439 psia) Outlet: 2.9 MPa 

(419 psia) Water Recovered: 364 

kg/hr (803 lb/hr)

1 0

5 CO2 Compressor

Integrally geared, 

multi-stage 

centrifugal

275,140 kg/hr @ 15.3 MPa 

(606,579 lb/hr @ 2,215 psia) 2 0

Case B11B – Account 7: Ducting and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner

152 m (500 ft) high x

5.6 m (19 ft) diameter 1 0

Case B11B – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

678 MW

16.5 MPa/566°C/566°C (2400 psig/ 

1050°F/1050°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

750 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

2,220 GJ/hr 

(2,110 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

Case B11B – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 824,000 lpm @ 30 m(218,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

4600 GJ/hr (4360 MMBtu/hr) heat duty

1 0

Case B11B – Account 10: Ash and Spent Sorbent Recovery and Handling

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of boiler scope 

of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of 

supply) -- -- 2 0

3 Clinker Grinder -- 5.0 tonne/hr (5.5 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of 

supply included with boiler) -- -- 6 0

5 Hydroejectors -- -- 12

6 Economizer /Pyrites Transfer Tank -- -- 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

108

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

7 Ash Sluice Pumps Vertical, 

wet pit

200 lpm @ 17 m H2O 

(50 gpm @ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, 

wet pit

7,570 lpm @ 9 m H2O 

(2000 gpm @ 28 ft 

H2O)

1 1

9 Hydrobins -- 190 lpm (50 gpm) 1 1

10 Baghouse Hopper (part of baghouse 

scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of 

supply) -- -- 10 0

12 Air Blower -- 20 m3/min @ 0.2 MPa 

(820 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforce

d concrete 1,500 tonne (1,700 ton) 2 0

14 Slide Gate Valves -- -- 2 0

15 Unloader -- -- 1 0

16 Telescoping Unloading Chute -- 140 tonne/hr (160 tph) 1 0

Case B11B – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 

MVA, 3-ph, 60 Hz 1 0

2 High Voltage Transformer Oil-filled 345 kV/13.8 kV, 20 

MVA, 3-ph, 60 Hz 2 0

3 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 102 

MVA, 3-ph, 60 Hz 1 1

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 15 

MVA, 3-ph, 60 Hz 1 1

5 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

6 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

7 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

8 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B11B – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.2.10 Case B11B – Cost Estimating

The cost estimating methodology was described previously in Section 2.7. Exhibit 3-33 shows a 

detailed breakdown of the capital costs; Exhibit 3-34 shows the owner’s costs, TOC, and TASC; 

Exhibit 3-35 shows the initial and annual O&M costs; and Exhibit 3-36 shows the COE 

breakdown. 
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

109

The estimated TPC of the subcritical PC boiler with CO2 capture is $3,467/kW. Process 

contingency represents 3.4 percent of the TPC and project contingency represents 12.3 percent. 

The COE, including CO2 T&S costs of $10.0/MWh, is $143.5/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

110

Exhibit 3-33 Case B11B total plant cost details

Case: B11B – Subcritical PC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,719 $0 $2,126 $0 $6,845 $684 $0 $1,129 $8,658 $16

1.2 Coal Stackout & Reclaim $6,098 $0 $1,363 $0 $7,461 $746 $0 $1,231 $9,438 $17

1.3 Coal Conveyors $5,670 $0 $1,348 $0 $7,018 $702 $0 $1,158 $8,878 $16

1.4 Other Coal Handling $1,483 $0 $312 $0 $1,795 $180 $0 $296 $2,271 $4

1.5 Sorbent Receive & Unload $189 $0 $56 $0 $245 $25 $0 $40 $310 $1

1.6 Sorbent Stackout & Reclaim $3,054 $0 $552 $0 $3,606 $361 $0 $595 $4,562 $8

1.7 Sorbent Conveyors $1,090 $237 $264 $0 $1,590 $159 $0 $262 $2,011 $4

1.8 Other Sorbent Handling $658 $155 $340 $0 $1,154 $115 $0 $190 $1,459 $3

1.9 Coal & Sorbent Hnd. Foundations $0 $5,469 $7,211 $0 $12,680 $1,268 $0 $2,092 $16,040 $29

Subtotal $22,962 $5,861 $13,572 $0 $42,395 $4,239 $0 $6,995 $53,629 $98

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $2,728 $0 $524 $0 $3,252 $325 $0 $537 $4,114 $7

2.2 Coal Conveyor to Storage $6,984 $0 $1,504 $0 $8,488 $849 $0 $1,401 $10,737 $20

2.5 Sorbent Prep Equipment $5,199 $225 $1,065 $0 $6,489 $649 $0 $1,071 $8,209 $15

2.6 Sorbent Storage & Feed $626 $0 $237 $0 $863 $86 $0 $142 $1,092 $2

2.9 Coal & Sorbent Feed Foundation $0 $635 $557 $0 $1,191 $119 $0 $197 $1,507 $3

Subtotal $15,538 $860 $3,886 $0 $20,284 $2,028 $0 $3,347 $25,659 $47

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $21,284 $0 $7,333 $0 $28,618 $2,862 $0 $4,722 $36,201 $66

3.2 Water Makeup & Pretreating $7,468 $0 $2,362 $0 $9,830 $983 $0 $2,163 $12,975 $24

3.3 Other Feedwater Subsystems $7,155 $0 $2,937 $0 $10,092 $1,009 $0 $1,665 $12,766 $23

3.4 Service Water Systems $1,496 $0 $783 $0 $2,278 $228 $0 $501 $3,007 $5

3.5 Other Boiler Plant Systems $8,860 $0 $8,377 $0 $17,236 $1,724 $0 $2,844 $21,804 $40

3.6 FO Supply Sys & Nat Gas $348 $0 $406 $0 $754 $75 $0 $124 $953 $2

3.7 Waste Treatment Equipment $4,899 $0 $2,836 $0 $7,735 $774 $0 $1,702 $10,210 $19

3.8 Misc. Equip. (Cranes, Air Comp., 

Comm.) $3,406 $0 $1,054 $0 $4,460 $446 $0 $981 $5,887 $11

Subtotal $54,915 $0 $26,088 $0 $81,002 $8,100 $0 $14,702 $103,805 $189

4 Boiler & Accessories

4.1 PC Boiler & Accessories $178,369 $0 $116,485 $0 $294,854 $29,485 $0 $32,434 $356,773 $649

4.2 SCR w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0

Subtotal $178,369 $0 $116,485 $0 $294,854 $29,485 $0 $32,434 $356,773 $649

5A Gas Cleanup & Piping

5A.1 Absorber Vessels & Accessories $81,951 $0 $17,522 $0 $99,473 $9,947 $0 $10,942 $120,362 $219

5A.2 Other FGD $4,277 $0 $4,813 $0 $9,090 $909 $0 $1,000 $10,999 $20
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Case: B11B – Subcritical PC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.3 Bag House & Accessories $23,533 $0 $14,833 $0 $38,366 $3,837 $0 $4,220 $46,423 $84

5A.4 Other Particulate Removal Materials $1,593 $0 $1,693 $0 $3,285 $329 $0 $361 $3,975 $7

5A.5 Gypsum Dewatering System $6,338 $0 $1,069 $0 $7,407 $741 $0 $815 $8,963 $16

5A.6 Mercury Removal System $4,817 $1,060 $4,736 $0 $10,613 $1,061 $0 $1,167 $12,842 $23

Subtotal $122,509 $1,060 $44,666 $0 $168,234 $16,823 $0 $18,506 $203,564 $370

5B CO2 Removal & Compression

5B.1 CO2 Removal System $172,746 $63,159 $134,933 $0 $370,838 $31,957 $63,914 $83,088 $549,796 $1,000

5B.2 CO2 Compression & Drying $51,118 $7,668 $16,831 $0 $75,616 $7,562 $0 $16,636 $99,813 $182

Subtotal $223,863 $70,827 $151,763 $0 $446,454 $39,518 $63,914 $99,723 $649,609 $1,182

7 HRSG, Ducting, & Stack

7.3 Ductwork $11,362 $0 $7,172 $0 $18,533 $1,853 $0 $3,058 $23,445 $43

7.4 Stack $10,271 $0 $5,969 $0 $16,240 $1,624 $0 $1,786 $19,651 $36

7.9 Duct & Stack Foundations $0 $1,120 $1,329 $0 $2,449 $245 $0 $539 $3,233 $6

Subtotal $21,633 $1,120 $14,470 $0 $37,223 $3,722 $0 $5,383 $46,329 $84

8 Steam Turbine Generator

8.1 Steam TG & Accessories $70,000 $0 $8,020 $0 $78,020 $7,802 $0 $8,582 $94,404 $172

8.2 Turbine Plant Auxiliaries $452 $0 $961 $0 $1,412 $141 $0 $155 $1,709 $3

8.3 Condenser & Auxiliaries $7,394 $0 $2,956 $0 $10,350 $1,035 $0 $1,138 $12,523 $23

8.4 Steam Piping $30,222 $0 $12,249 $0 $42,471 $4,247 $0 $7,008 $53,725 $98

8.9 TG Foundations $0 $1,346 $2,223 $0 $3,569 $357 $0 $785 $4,712 $9

Subtotal $108,067 $1,346 $26,408 $0 $135,822 $13,582 $0 $17,669 $167,073 $304

9 Cooling Water System

9.1 Cooling Towers $16,119 $0 $4,985 $0 $21,104 $2,110 $0 $2,321 $25,536 $46

9.2 Circulating Water Pumps $3,228 $0 $228 $0 $3,456 $346 $0 $380 $4,181 $8

9.3 Circ. Water System Auxiliaries $839 $0 $111 $0 $950 $95 $0 $104 $1,149 $2

9.4 Circ. Water Piping $0 $7,067 $6,400 $0 $13,466 $1,347 $0 $2,222 $17,035 $31

9.5 Make-up Water System $714 $0 $917 $0 $1,631 $163 $0 $269 $2,063 $4

9.6 Component Cooling Water Sys. $684 $0 $525 $0 $1,209 $121 $0 $199 $1,529 $3

9.9 Circ. Water Foundations & Structures $0 $3,743 $6,215 $0 $9,958 $996 $0 $2,191 $13,145 $24

Subtotal $21,583 $10,810 $19,381 $0 $51,774 $5,177 $0 $7,687 $64,638 $118

10 Ash & Spent Sorbent Handling Systems

10.6 Ash Storage Silos $902 $0 $2,759 $0 $3,661 $366 $0 $403 $4,430 $8

10.7 Ash Transport & Feed Equipment $5,990 $0 $5,938 $0 $11,928 $1,193 $0 $1,312 $14,433 $26

10.9 Ash/Spent Sorbent Foundation $0 $204 $251 $0 $454 $45 $0 $100 $600 $1

Subtotal $6,892 $204 $8,948 $0 $16,044 $1,604 $0 $1,815 $19,463 $35

11 Accessory Electric Plant

11.1 Generator Equipment $2,066 $0 $330 $0 $2,396 $240 $0 $198 $2,833 $5

11.2 Station Service Equipment $5,368 $0 $1,800 $0 $7,168 $717 $0 $591 $8,476 $15

11.3 Switchgear & Motor Control $6,161 $0 $1,070 $0 $7,232 $723 $0 $795 $8,750 $16

11.4 Conduit & Cable Tray $0 $4,225 $13,651 $0 $17,876 $1,788 $0 $2,950 $22,613 $41

11.5 Wire & Cable $0 $8,045 $14,381 $0 $22,426 $2,243 $0 $3,700 $28,369 $52

11.6 Protective Equipment $317 $0 $1,099 $0 $1,416 $142 $0 $156 $1,713 $3
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Case: B11B – Subcritical PC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11.7 Standby Equipment $1,574 $0 $37 $0 $1,611 $161 $0 $177 $1,949 $4

11.8 Main Power Transformers $12,712 $0 $221 $0 $12,933 $1,293 $0 $1,423 $15,649 $28

11.9 Electrical Foundations $0 $386 $983 $0 $1,369 $137 $0 $301 $1,807 $3

Subtotal $28,198 $12,656 $33,572 $0 $74,426 $7,443 $0 $10,291 $92,160 $168

12 Instrumentation & Control

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $608 $0 $371 $0 $979 $98 $49 $169 $1,295 $2

12.7 Distributed Control Sys. Equipment $6,134 $0 $1,094 $0 $7,228 $723 $361 $831 $9,143 $17

12.8 Instrument Wiring & Tubing $3,699 $0 $6,731 $0 $10,429 $1,043 $521 $1,799 $13,793 $25

12.9 Other I & C Equipment $1,733 $0 $4,013 $0 $5,747 $575 $287 $661 $7,270 $13

Subtotal $12,174 $0 $12,209 $0 $24,383 $2,438 $1,219 $3,460 $31,501 $57

13 Improvements to Site

13.1 Site Preparation $0 $62 $1,318 $0 $1,380 $138 $0 $304 $1,822 $3

13.2 Site Improvements $0 $2,057 $2,718 $0 $4,775 $478 $0 $1,051 $6,303 $11

13.3 Site Facilities $3,687 $0 $3,868 $0 $7,554 $755 $0 $1,662 $9,972 $18

Subtotal $3,687 $2,119 $7,904 $0 $13,710 $1,371 $0 $3,016 $18,097 $33

14 Buildings & Structures

14.1 Boiler Building $0 $10,735 $9,434 $0 $20,169 $2,017 $0 $3,328 $25,513 $46

14.2 Turbine Building $0 $15,664 $14,589 $0 $30,254 $3,025 $0 $4,992 $38,271 $70

14.3 Administration Building $0 $763 $807 $0 $1,570 $157 $0 $259 $1,986 $4

14.4 Circulation Water Pumphouse $0 $208 $165 $0 $374 $37 $0 $62 $473 $1

14.5 Water Treatment Buildings $0 $931 $849 $0 $1,780 $178 $0 $294 $2,252 $4

14.6 Machine Shop $0 $511 $343 $0 $853 $85 $0 $141 $1,080 $2

14.7 Warehouse $0 $346 $347 $0 $693 $69 $0 $114 $877 $2

14.8 Other Buildings & Structures $0 $283 $241 $0 $523 $52 $0 $86 $662 $1

14.9 Waste Treating Building & Str. $0 $541 $1,642 $0 $2,183 $218 $0 $360 $2,762 $5

Subtotal $0 $29,983 $28,416 $0 $58,399 $5,840 $0 $9,636 $73,875 $134

Total $820,390 $136,845 $507,769 $0 $1,465,004 $141,373 $65,133 $234,664 $1,906,174 $3,467
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Exhibit 3-34 Case B11B owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $11,919 $22

1 Month Maintenance Materials $1,719 $3

1 Month Non-fuel Consumables $3,776 $7

1 Month Waste Disposal $561 $1

25% of 1 Months Fuel Cost at 100% CF $3,228 $6

2% of TPC $38,123 $69

Total $59,326 $108

Inventory Capital

60 day supply of fuel and consumables at 100% CF $32,759 $60

0.5% of TPC (spare parts) $9,531 $17

Total $42,289 $77

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $285,926 $520

Financing Costs $51,467 $94

Total Overnight Costs (TOC) $2,346,083 $4,267

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,674,534 $4,865
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 3-35 Case B11B initial and annual operating and maintenance costs

Case: B11B – Subcritical PC w/o CO2 Cost Base: Jun 2011

Plant Size (MW,net): 550 Heat Rate-net (Btu/kWh): 10,953 Capacity Factor (%): 85

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 11.3 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 2.0 

Total: 16.3 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $7,384,208 $13.431

Maintenance Labor: $11,686,525 $21.257

Administrative & Support Labor: $4,767,683 $8.672

Property Taxes and Insurance: $38,123,487 $69.343

Total: $61,961,903 $112.703

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $17,529,787 $4.28219

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 6,077 $1.67 $0 $3,156,296 $0.77102

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 29,418 $0.27 $0 $2,444,559 $0.59716

Limestone (ton) 0 612 $33.48 $0 $6,357,560 $1.55303

Hydrated Lime (ton) 0 125 $155.00 $0 $6,002,945 $1.46640

Activated Carbon (ton) 0 4 $1,255.00 $0 $1,403,736 $0.34291

CO2 Capture System ChemicalsA Proprietary

Triethylene Glycol (gal) 0 407 $6.57 $0 $829,372 $0.20260

Ammonia (19% NH3, ton) 0 92 $330.00 $0 $9,376,827 $2.29058

SCR Catalyst (m3) 0 0.41 $8,938.80 $0 $1,138,354 $0.27808

Subtotal: $0 $38,511,747 $9.40767

Waste Disposal

Fly Ash (ton) 0 614 $25.11 $0 $4,781,508 $1.16803

Bottom Ash (ton) 0 121 $25.11 $0 $940,569 $0.22976

Amine Purification Unit Waste (ton) 0 21 $0.00 $0 $0 $0.00000

Thermal Reclaimer Unit Waste (ton) 0 2 $0.00 $0 $0 $0.00000

Prescrubber Blowdown Waste (ton) 0 46 $0.00 $0 $0 $0.00000

 Subtotal: $0 $5,722,077 $1.39779

By-Products

Gypsum (ton) 0 106 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $61,763,611 $15.08765

Fuel Cost

Illinois Number 6 (ton): 0 6,194 $68.54 $0 $131,713,383 $32.17501

Total: $0 $131,713,383 $32.17501

ACO2 Capture System Chemicals includes Ion Exchange Resin, NaOH, and Cansolv Solvent.

Exhibit 3-36 Case B11B COE breakdown

Component Value, $/MWh Percentage

Capital 71.1 50%

Fixed 15.1 11%

Variable 15.1 11%

Fuel 32.2 22%

Total (Excluding T&S) 133.5 N/A

CO2 T&S 10.0 7%

Total (Including T&S) 143.5 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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3.3 Supercritical PC cases

This section contains an evaluation of plant designs for Cases B12A and B12B, which are based 

on a SC PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 24.1 

MPa/593°C/593°C (3,500 psig/1,100°F/1,100°F) cycle. The only difference between the two 

plants is that Case B12B includes CO2 capture while Case B12A does not.

The balance of this section is organized in an analogous manner to the subcritical PC section:

• Process and System Description for Case B12A

• Key Assumptions for Cases B12A and B12B

• Sparing Philosophy for Cases B12A and B12B

• Performance Results for Case B12A

• Equipment List for Case B12A

• Cost Estimates for Case B12A

• Process and System Description, Performance Results, Equipment List and Cost 

Estimates for Case B12B

3.3.1 Process Description

In this section the SC PC process without CO2 capture is described. The system description is 

nearly identical to the subcritical PC case without CO2 capture but is repeated here for 

completeness. The description follows the BFD in Exhibit 3-37 and stream numbers reference 

the same Exhibit. The tables in Exhibit 3-38 provide process data for the numbered streams in 

the BFD.

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 1). 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. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD 

and PA fan outlet streams to the boiler exhaust.

Flue gas exits the boiler through the SCR reactor where hydrated lime is injected (stream 10) for 

the reduction of SO3. It then passes through the combustion air preheater (where the air 

preheater leakages are introduced) and is cooled to 143°C (289°F) (stream 11) before PAC is 

injected (stream 12) for mercury reduction. The flue gas then passes through a fabric filter for 

particulate removal (stream 15). An ID fan increases the flue gas temperature to 153°C (308°F) 

and provides the motive force for the flue gas (stream 16) to pass through the FGD unit. FGD 

inputs and outputs include makeup water (stream 18), oxidation air (stream 19), limestone slurry 

(stream 17) and product gypsum (stream 20). The clean, saturated flue gas exiting the FGD unit 

(stream 21) passes to the plant stack and is discharged to the atmosphere.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 3-37 Case B12A block flow diagram, supercritical unit without CO2 capture

Source: NETL

PULVERIZED

COAL

BOILER

SCR

BAGHOUSE FGD

LIMESTONE GYPSUM

SLURRY

OXIDATION

AIR

MAKEUP

WATER

BOTTOM ASH

COAL FEED

INFILTRATION

AIR

1

4

8

7

9

14

FLY ASH

15 16

18 19

17 20

21

HP 

TURBINE

22

23

24

IP

TURBINE LP TURBINE

CONDENSER

26

FEEDWATER 

HEATER

SYSTEM

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

3

2

6

5

11

25

10

HYDRATED

LIME

12

13

ACTIVATED

CARBON

STACK GAS

FD FANS

PA FANS

ID FAN

BOILER

FEEDWATER
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 3-38 Case B12A stream table, supercritical unit without capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0000 0.0088 0.0000 0.0088 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.0000 0.1376 0.0000 0.1376 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0000 0.0831 0.0000 0.0831 0.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.0000 0.7345 0.0000 0.7345 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0000 0.0340 0.0000 0.0340 0.3333

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0020 0.0000 0.0020 0.6667

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 49,410 49,410 1,463 15,178 15,178 2,089 1,079 0 0 0 69,258 0 69,258 3

V-L Flowrate (kg/hr) 1,425,833 1,425,833 42,230 438,001 438,001 60,280 31,143 0 0 0 2,056,795 0 2,056,795 158

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 179,193 3,475 3,611 17,512 104 17,616 17,616

Temperature (°C) 15 19 19 15 25 25 15 15 149 27 143 27 143 143

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

Steam Table Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- 0.00 0.00 0.00 --- ---

AspenPlus Enthalpy (kJ/kg)B -97.58 -93.45 -93.45 -97.58 -87.03 -87.03 -97.58 -2,114.05 97.18 -13,306.82 -2,399.46 3.40 -2,399.34 -2,632.07

Density (kg/m3) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- --- 0.9 --- 0.9 1.5

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- --- 29.698 --- 29.698 53.376

V-L Flowrate (lbmole/hr) 108,931 108,931 3,226 33,463 33,463 4,605 2,379 0 0 0 152,687 0 152,687 7

V-L Flowrate (lb/hr) 3,143,424 3,143,424 93,102 965,627 965,627 132,896 68,659 0 0 0 4,534,456 0 4,534,456 347

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 395,053 7,661 7,962 38,608 230 38,838 38,838

Temperature (°F) 59 66 66 59 78 78 59 59 300 80 289 80 289 289

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.4 14.7 14.4 14.7 14.4 14.4

Steam Table Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- --- ---

AspenPlus Enthalpy (Btu/lb)B -42.0 -40.2 -40.2 -42.0 -37.4 -37.4 -42.0 -908.9 41.8 -5,720.9 -1,031.6 1.5 -1,031.5 -1,131.6

Density (lb/ft3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- --- 0.053 --- 0.053 0.096

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 3-38 Case B12A stream table, supercritical unit without capture (continued)

15 16 17 18 19 20 21 22 23 24 25 26

V-L Mole Fraction

Ar 0.0088 0.0088 0.0000 0.0000 0.0092 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1376 0.1376 0.0000 0.0000 0.0003 0.0001 0.1288 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0831 0.0831 1.0000 1.0000 0.0099 0.9999 0.1451 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.7345 0.7345 0.0000 0.0000 0.7732 0.0000 0.6854 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0340 0.0340 0.0000 0.0000 0.2074 0.0000 0.0325 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0020 0.0020 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 69,255 69,255 2,296 9,201 732 169 75,048 88,629 74,095 74,095 66,938 67,115

V-L Flowrate (kg/hr) 2,056,637 2,056,637 41,356 165,764 21,135 3,052 2,165,283 1,596,685 1,334,839 1,334,839 1,205,905 1,209,098

Solids Flowrate (kg/hr) 0 0 17,707 0 0 27,462 0 0 0 0 0 0

Temperature (°C) 143 153 15 27 167 56 56 593 342 593 38 39

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.31 0.10 0.10 24.23 4.90 4.80 0.01 1.80

Steam Table Enthalpy (kJ/kg) A 274.35 285.60 --- 111.65 184.48 --- 286.10 3,477.96 3,049.83 3,652.36 1,978.90 163.04

AspenPlus Enthalpy (kJ/kg)B -2,397.32 -2,386.08 -14,995.75 -15,964.53 56.67 -12,481.91 -2,940.27 -12,502.33 -12,930.47 -12,327.94 -14,001.40 -15,817.25

Density (kg/m3) 0.8 0.9 1,003.6 992.3 2.4 833.1 1.1 69.2 19.2 12.3 0.1 993.5

V-L Molecular Weight 29.697 29.697 18.015 18.015 28.857 18.018 28.852 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmole/hr) 152,680 152,680 5,061 20,285 1,615 373 165,452 195,395 163,351 163,351 147,573 147,964

V-L Flowrate (lb/hr) 4,534,108 4,534,108 91,174 365,446 46,596 6,729 4,773,632 3,520,088 2,942,815 2,942,815 2,658,565 2,665,605

Solids Flowrate (lb/hr) 0 0 39,037 0 0 60,544 0 0 0 0 0 0

Temperature (°F) 289 308 59 80 332 133 133 1,100 648 1,100 101 101

Pressure (psia) 14.2 15.2 15.0 15.7 45.0 14.7 14.7 3,514.7 710.8 696.6 1.0 261.6

Steam Table Enthalpy (Btu/lb)A 118.0 122.8 --- 48.0 79.3 --- 123.0 1,495.3 1,311.2 1,570.2 850.8 70.1

AspenPlus Enthalpy (Btu/lb)B -1,030.7 -1,025.8 -6,447.0 -6,863.5 24.4 -5,366.3 -1,264.1 -5,375.0 -5,559.1 -5,300.1 -6,019.5 -6,800.2

Density (lb/ft3) 0.052 0.055 62.650 61.950 0.153 52.011 0.067 4.319 1.197 0.768 0.004 62.022

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

119

3.3.2 Key System Assumptions

System assumptions for Cases B12A and B12B, SC PC with and without CO2 capture, are 

compiled in Exhibit 3-39.

Exhibit 3-39 Supercritical PC plant study configuration matrix

Case B12A 

w/o CO2 Capture 

Case B12B 

w/CO2 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 Illinois No. 6 Illinois No. 6

Condenser pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Boiler Efficiency, HHV % 89 89

Cooling water to condenser, °C (oF) 16 (60) 16 (60)

Cooling water from condenser, °C (oF) 27 (80) 27 (80)

Stack temperature, °C (°F) 56 (133) 42 (107)

SO2 Control Wet Limestone Forced 

Oxidation

Wet Limestone 

Forced Oxidation

FGD Efficiency, % (A) 98 98 (B, C)

NOx Control LNB w/OFA, SCR, and 

Polishing Scrubber

LNB w/OFA, SCR, and 

Polishing Scrubber

SCR Efficiency, % (A) 83 85

Ammonia Slip (end of catalyst life), ppmv 2 2

Particulate Control Fabric Filter Fabric Filter

Fabric Filter efficiency, % (A) 99.9 99.9

Ash Distribution, Fly/Bottom 80% / 20% 80% / 20%

SO3 Control DSI DSI

Mercury Control Co-benefit Capture and 

ACI

Co-benefit Capture and 

ACI

CO2 Control N/A Cansolv

Overall Carbon Capture (A) N/A 90%

CO2 Sequestration N/A Off-site Saline 

Formation

ARemoval efficiencies are based on the flue gas content

BAn SO2 polishing step is included to meet more stringent SOx content limits in the flue gas (~1

ppmv) to reduce formation of amine HSS during the CO2 absorption process

CSO2 exiting the post-FGD polishing step is absorbed in the CO2 capture process making stack 

emissions negligible

3.3.2.1 Balance of Plant – Cases B12A and B12B

The balance of plant assumptions are common to all cases and were presented previously in 

Exhibit 3-8.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

120

3.3.3 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 boiler (1 x 100%)

• Two SCR reactors (2 x 50%)

• One DSI system (1 x 100%)

• One ACI system (1 x 100%)

• Two single-stage, in-line, multi-compartment fabric filters (2 x 50%)

• One wet limestone forced oxidation positive pressure absorber (1 x 100%)

• One steam turbine (1 x 100%)

• For Case B12B only, one CO2 absorption system, consisting of an absorber, stripper, and 

ancillary equipment (1 x 100%) and two CO2 compression systems (2 x 50%)

3.3.4 Case B12A Performance Results

The plant produces a net output of 550 MWe at a net plant efficiency of 40.7 percent (HHV 

basis). Overall performance for the plant is summarized in Exhibit 3-40; Exhibit 3-41 provides a 

detailed breakdown of the auxiliary power requirements.

Exhibit 3-40 Case B12A plant performance summary

Performance Summary

Total Gross Power, MWe 580

CO2 Capture/Removal Auxiliaries, kWe 0

CO2 Compression, kWe 0

Balance of Plant, kWe 29,688

Total Auxiliaries, MWe 30

Net Power, MWe 550

HHV Net Plant Efficiency (%) 40.7%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,841 (8,379)

LHV Net Plant Efficiency (%) 42.2%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,527 (8,082)

HHV Boiler Efficiency, % 89.1%

LHV Boiler Efficiency, % 92.4%

Steam Turbine Cycle Efficiency, % 48.2%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 7,473 (7,083)

Condenser Duty, GJ/hr (MMBtu/hr) 2,192 (2,078)

As-Received Coal Feed, kg/hr (lb/hr) 179,193 (395,053)

Limestone Sorbent Feed, kg/hr (lb/hr) 17,707 (39,037)

HHV Thermal Input, kWt 1,350,672

LHV Thermal Input, kWt 1,302,740

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.035 (9.3)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.028 (7.4)

Excess Air, % 20.9%
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

121

Exhibit 3-41 Case B12A plant power summary

Power Summary

Steam Turbine Power, MWe 580

Total Gross Power, MWe 580

Auxiliary Load Summary

Coal Handling and Conveying, kWe 430

Pulverizers, kWe 2,690

Sorbent Handling & Reagent Preparation, kWe 850

Ash Handling, kWe 620

Primary Air Fans, kWe 1,330

Forced Draft Fans, kWe 1,700

Induced Draft Fans, kWe 6,660

SCR, kWe 40

Activated Carbon Injection, kWe 22

Dry sorbent Injection, kWe 86

Baghouse, kWe 90

Wet FGD, kWe 2,830

CO2 Capture/Removal Auxiliaries, kWe 0

CO2 Compression, kWe 0

Miscellaneous Balance of PlantA,B, kWe 2,000

Steam Turbine Auxiliaries, kWe 400

Condensate Pumps, kWe 800

Circulating Water Pumps, kWe 4,520

Ground Water Pumps, kWe 460

Cooling Tower Fans, kWe 2,340

Transformer Losses, kWe 1,820

Total Auxiliaries, MWe 30

Net Power, MWe 550

ABoiler feed pumps are turbine driven

BIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.3.4.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case B12A is presented in Exhibit 3-42.

Exhibit 3-42 Case B12A air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)

SO2 0.036 (0.085) 1,317 (1,452) 0.305 (0.673)

NOx 0.038 (0.088) 1,371 (1,511) 0.318 (0.700)

Particulate 0.005 (0.011) 176 (194) 0.041 (0.090)

Hg 1.62E-7 (3.77E-7) 0.006 (0.006) 1.36E-6 (3.00E-6)

CO2B 87 (204) 3,167,890 (3,492,001) 734 (1,618)

CO2C - - 774 (1,705)

mg/Nm3

Particulate ConcentrationD,E 15.25

ACalculations based on an 85 percent capacity factor

BCO2 emissions based on gross power

CCO2 emissions based on net power instead of gross power DConcentration of particles in the flue gas after the baghouse

ENormal conditions given at 32°F and 14.696 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

122

SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a 

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. 

The wallboard grade material can potentially be marketed and sold, but since it is highly 

dependent on local market conditions, no byproduct credit was taken. The saturated flue gas

exiting the scrubber is vented through the plant stack.

NOx emissions are controlled to about 0.5 lb/MMBtu through the use of LNBs and OFA. An 

SCR unit then further reduces the NOx concentration by 83 percent to 0.09 lb/MMBtu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency 

of 99.9 percent.

The total reduction in mercury emission via the combined control equipment (SCR, ACI, fabric 

filter, DSI, and wet FGD) is 96.7 percent.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3-43. The carbon input to the plant consists 

of carbon in the coal, carbon in the air, PAC, and carbon in the limestone reagent used in the 

FGD. Carbon in the air is not neglected here since the Aspen model accounts for air components 

throughout. Carbon leaves the plant mostly as CO2 through the stack, however, the PAC is 

captured in the fabric filter and some leaves as gypsum.

Exhibit 3-43 Case B12A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 114,226 (251,825) Stack Gas 116,112 (255,983)

Air (CO2) 261 (574) FGD Product 171 (378)

PAC 104 (230) Baghouse 104 (230)

FGD Reagent 1,797 (3,961) CO2 Product 0

CO2 Dryer Vent 0

CO2 Knockout 0

Total 116,388 (256,591) Total 116,388 (256,591)

Exhibit 3-44 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum, sulfur captured in 

the fabric filter via hydrated lime, and sulfur emitted in the stack gas.

Exhibit 3-44 Case B12A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 4,491 (9,902) FGD Product 4,340 (9,567)

Stack Gas 89 (195)

Polishing Scrubber and Solvent Reclaiming 0

Baghouse 63 (139)

Total 4,491 (9,902) Total 4,491 (9,902)

Exhibit 3-45 shows the overall water balance for the plant. 

Water demand represents the total amount of water required for a particular process. Some water 

is recovered within the process and is re-used as internal recycle. The difference between 

demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water 
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

123

removed from the ground or diverted from a POTW for use in the plant and was assumed to be 

provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can 

be represented by the water metered from a raw water source and used in the plant processes for 

any and all purposes, such as FGD makeup, BFW makeup, and cooling tower makeup. The 

difference between water withdrawal and process water discharge is defined as water 

consumption and can be represented by the portion of the raw water withdrawn that is 

evaporated, transpired, incorporated into products or otherwise not returned to the water source 

from which it was withdrawn. Water consumption represents the net impact of the plant process 

on the water source balance.

Exhibit 3-45 Case B12A water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

FGD Makeup 3.46 (913) – 3.46 (913) – 3.46 (913)

CO2 Drying – – – – –

Capture System 

Makeup – – – – –

Deaerator Vent – – – 0.05 (14) -0.05 (-14)

Condenser Makeup 0.05 (14) – 0.05 (14) – 0.05 (14)

 BFW Makeup 0.05 (14) – 0.05 (14) – 0.05 (14)

Cooling Tower 17.59 

(4,648)

1.78 

(471) 15.81 (4,177) 3.96 (1,045) 11.86 (3,132)

 FGD Dewatering – 1.78 

(471) -1.78 (-471) – -1.78 (-471)

 CO2 Capture 

Recovery – – – – –

 CO2 Compression KO – – – – –

 BFW Blowdown – – – – –

Total 21.11 

(5,575)

1.78 

(471) 19.32 (5,105) 4.01 (1,059) 15.31 (4,045)

3.3.4.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the Case B12A PC boiler, the FGD unit and 

steam cycle in Exhibit 3-46 and Exhibit 3-47. 

An overall plant energy balance is provided in tabular form in Exhibit 3-48. The power out is 

the steam turbine power prior to generator losses. The power at the generator terminals (shown 

in Exhibit 3-40) is calculated by multiplying the power out by a generator efficiency of 98.5

percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

124

Exhibit 3-46 Case B12A heat and mass balance, supercritical PC boiler without CO2 capture

Source: NETL

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Coal/Ash

Slurry

Water

Steam

PAGES

1 OF 2

BITUMINOUS BASELINE STUDY

CASE B12A

SUBCRITICAL PULVERIZED COAL

BOILER AND GAS CLEANUP SYSTEMS

DWG. NO.

BB-HMB-CS-B12A-PG-1

Pulverized

Coal

Boiler

Ammonia SCR

Infiltration Air

Air

Air

Coal

Bottom Ash

FGD

Fly Ash

Forced

Draft Fans

Primary 

Air Fans

395,053 W

59 T

15 P

78 T

16 P

18 H

66 T

15 P

15 H

3,520,088 W

1,100 T

3,515 P

1,495 H

2,942,815 W

1,100 T

697 P

1,570 H

965,627 W

59 T

15 P

13 H

3,143,424 W

59 T

15 P

13 H

68,659 W

59 T

15 P

13 H

4,573,064 W

289 T

14 P

117 H

7,661 W

300 T

14 P

39,185 W

289 T

14 P

2,942,815 W

648 T

711 P

1,311 H

3,520,088 W

500 T

3,845 P

488 H

5

4,773,632 W

133 T

15 P

123 H

1 2

4

7

9

4,534,108 W ID Fans

289 T

14 P

118 H

Gross Plant Power: 580 MWe

Auxiliary Load: 30 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 40.7%

Net Plant Heat Rate: 8,379 Btu/kWh

Lime/

Limestone/

Gypsum

Flue Gas

Oxidation 

Air

Make-Up 

Water

Limestone 

Slurry

Gypsum

18

17

14

4,534,108 W

308 T

15 P

123 H

130,211 W

59 T

15 P

423 H

46,596 W

332 T

45 P

79 H

365,446 W

80 T

16 P

48 H

67,273 W

133 T

15 P

1,499 H

Baghouse

3

6

8

15 16

19

21

22

23

24

DOE/NETL

SC PC PLANT

CASE B12A

Hydrated 

Lime

11

Single Reheat

Extraction from

HP Turbine

From Feedwater

Heaters

Single Reheat

To IP Turbine

Throttle Steam

To HP Turbine

7,962 W

80 T

15 P

10

Activated 

Carbon

12

Activated 

Carbon

13

230 W

80 T

15 P

Stack

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

4,573,293 W

289 T

14 P

117 H

20

Ammonia
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

125

Exhibit 3-47 Case B12A heat and mass balance, supercritical steam cycle

Source: NETL

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

Water

Steam

PAGES

2 OF 2

DWG. NO.

BB-HMB-CS-B12A-PG-2

BITUMINOUS BASELINE STUDY

CASE B12A

SUBCRITICAL PULVERIZED COAL

POWER BLOCK SYSTEMS

LP Turbine Generator HP

Turbine

IP

Turbine

Condenser

Hot Well

Boiler Feed Pump 

Turbine Drives

Throttle

Steam

Condensate 

Pumps

3,520,088 W

1,100 T

3,515 P

1,495 H

163,399 W

861 T

298 P

1,453 H

317,057 W

645 T

682 P

1,311 H

2,942,815 W

648 T

711 P

1,311 H

218,567 W

653 T

135 P

1,353 H

218,567 W

126 T

2 P

1,083 H

1,968,852 W

101 T

1 P

1,010 H

2,665,605 W

101 T

1 P

69 H

2,665,605 W

101 T

262 P

70 H

2,665,605 W

141 T

251 P

110 H

471,146 W

111 T

1 P

79 H

380,391 W

151 T

4 P

119 H

2,665,605 W

298 T

222 P

268 H

740,671 W

369 T

170 P

341 H

2,665,605 W

219 T

231 P

187 H

577,272 W

429 T

339 P

406 H

3,520,088 W

419 T

4,005 P

399 H

Deaerator

Boiler Feed

Water Pumps

3,520,088 W

555 T

3,691 P

551 H

2,942,815 W

1,100 T

697 P

1,570 H

196,118 W

229 T

20 P

197 H

294,039 W

188 T

9 P

156 H

2,665,605 W

178 T

241 P

146 H

120,852 W

652 T

132 P

1,353 H

196,118 

W

519 T

70 P

1,291 H

97,921 W

281 T

18 P

1,183 H

86,352 W

183 T

8 P

1,128 H

90,754 W

146 T

3 P

1,077 H

2,658,565 W

653 T

135 P

1,353 H

2,439,998 W

653 T

135 P

1,353 H

4,172 P

3,520,088 W

349 T

132 P

320 H

Gross Plant Power: 580 MWe

Auxiliary Load: 30 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 40.7%

Net Plant Heat Rate: 8,379 Btu/kWh

FWH 4 FWH 3 FWH 2 FWH 1 FWH 6 FWH 5

22

26

DOE/NETL

SC PC PLANT

CASE B12A

24

23

7,040 W

59 T

15 P

27 H

Vent

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

Single Reheat

Extraction

From Boiler

Single Reheat

Extraction to

Boiler

To Boiler

Steam Turbine

Makeup

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

25

260,215 W

757 T

1,071 P

1,358 H

260,215 W

510 T

746 P

500 H

3,520,088 W

500 T

3,845 P

488 H FWH 7
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

126

Exhibit 3-48 Case B12A overall energy balance (0°C [32°F] reference)

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 4,862 (4,609) 4.1 (3.9) – 4,866 (4,613)

Air – 57.3 (54.3) – 57.3 (54.3)

Raw Water Makeup – 72.7 (68.9) – 72.7 (68.9)

Limestone – 0.38 (0.36) – 0.38 (0.36)

Auxiliary Power – – 107 (101) 107 (101)

TOTAL 4,862 (4,609) 134.4 (127.4) 107 (101) 5,104 (4,837)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash – 0.4 (0.3) – 0.4 (0.3)

Fly Ash + FGD Ash – 2.0 (1.9) – 2.0 (1.9)

Stack Gas – 619 (587) – 619 (587)

Sulfur – – – –

Motor Losses and Design 

Allowances – – 34 (32) 34 (32)

Condenser – 2,192 (2,078) – 2,192 (2,078)

Non-Condenser Cooling 

Tower Loads – 106 (100) – 106 (100)

CO2 – 0.0 (0.0) – 0.0 (0.0)

Cooling Tower Blowdown – 29.4 (27.9) – 29.4 (27.9)

CO2 Capture Losses – – – –

Ambient LossesA – 104.7 (99.2) – 104.7 (99.2)

Power – – 2,087 (1,978) 2,087 (1,978)

TOTAL – 3,054 (2,894) 2,121 (2,010) 5,175 (4,905)

Unaccounted EnergyB – -71 (-67) – -71 (-67)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the boiler, reheater, superheater, and transformers.

BBy difference

3.3.5 Case B12A – Major Equipment List 

Major equipment items for the SC PC plant with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the

cost estimates in Section 3.3.6. 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 for Fossil Energy Plants Volume 1: Revision 3

127

Case B12A – Account 1: Coal and Sorbent Handling

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 180 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, 

linear 1,130 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 40 tonne (40 ton) 2 1

9 Feeder Vibratory 150 tonne/hr (160 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 300 tonne/hr (330 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 150 tonne (160 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 300 tonne/hr (330 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 300 tonne/hr (330 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide 

Gates Field erected 660 tonne (700 ton) 3 0

19 Activated Carbon Storage Silo and 

Feeder System

Shop 

assembled

Silo - 28 tonne (30 ton)

Feeder - 110 kg/hr 

(250 lb/hr)

1 0

20 Hydrated Lime Storage Silo and 

Feeder System

Shop 

assembled

Silo - 190 tonne (210 ton)

Feeder - 3,970 kg/hr 

(8,760 lb/hr)

1 0

21 Limestone Truck Unloading Hopper N/A 30 tonne (40 ton) 1 0

22 Limestone Feeder Belt 70 tonne/hr (80 tph) 1 0

23 Limestone Conveyor No. L1 Belt 70 tonne/hr (80 tph) 1 0

24 Limestone Reclaim Hopper N/A 10 tonne (20 ton) 1 0

25 Limestone Reclaim Feeder Belt 60 tonne/hr (60 tph) 1 0

26 Limestone Conveyor No. L2 Belt 60 tonne/hr (60 tph) 1 0

27 Limestone Day Bin w/ actuator 230 tonne (260 ton) 2 0

Case B12A – Account 2: Coal and Sorbent Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Coal Feeder Gravimetric 30 tonne/hr (40 tph) 6 0

2 Coal Pulverizer Ball type or 

equivalent 30 tonne/hr (40 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 19 tonne/hr (21 tph) 1 1

4 Limestone Ball Mill Rotary 19 tonne/hr (21 tph) 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 75,000 liters (20,000 gal) 1 1

6 Limestone Mill Recycle 

Pumps Horizontal centrifugal 1,240 lpm @ 10m H2O (330 gpm @ 40 ft H2O) 1 1

7 Hydroclone Classifier 4 active cyclones in a 

5 cyclone bank

310 lpm (80 gpm) 

per cyclone 1 1

8 Distribution Box 2-way N/A 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 421,000 liters (111,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 880 lpm @ 9m H2O 

(230 gpm @ 30 ft H2O) 1 1
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Case B12A – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 211,000 liters (56,000 gal) 2 0

2 Condensate Pumps Vertical canned 22,300 lpm @ 200 m H2O 

(5,900 gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage 

Tank Horizontal spray type

1,760,000 kg/hr 

(3,880,000 lb/hr), 

5 min. tank

1 0

4 Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

29,500 lpm @ 3,400 m H2O 

(7,800 gpm @ 11,300 ft 

H2O)

1 1

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

8,800 lpm @ 3,400 m H2O 

(2,300 gpm @ 11,300 ft 

H2O)

1 0

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 670,000 kg/hr (1,470,000 lb/hr) 2 0

7 LP Feedwater Heater 

2A/2B Horizontal U-tube 670,000 kg/hr (1,470,000 lb/hr) 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 670,000 kg/hr (1,470,000 lb/hr) 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 670,000 kg/hr (1,470,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1,760,000 kg/hr 

(3,870,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 1,760,000 kg/hr 

(3,870,000 lb/hr) 1 0

12 HP Feedwater heater 8 Horizontal U-tube 1,760,000 kg/hr 

(3,870,000 lb/hr) 1 0

13 Auxiliary Boiler Shop fabricated, water 

tube

20,000 kg/hr, 2.8 MPa, 

343°C (40,000 lb/hr, 400 

psig, 650°F)

1 0

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

15 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig) 2 1

16 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

17 Closed Cycle Cooling 

Heat Exchangers

Shell and tube 53 GJ/hr (50 MMBtu/hr) 

each 2 0

18 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,800 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

19 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O) 1 1

20 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O) 1 1

21 Raw Water Pumps Stainless steel, single 

suction

5,670 lpm @ 20 m H2O 

(1,500 gpm @ 60 ft H2O) 2 1

22 Ground Water Pumps Stainless steel, single 

suction

2,270 lpm @ 270 m H2O 

(600 gpm @ 880 ft H2O) 5 1

23 Filtered Water Pumps Stainless steel, single 

suction

1,690 lpm @ 50 m H2O 

(450 gpm @ 160 ft H2O) 2 1

24 Filtered Water Tank Vertical, cylindrical 1,619,000 liter (428,000 gal) 1 0

25 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

330 lpm (90 gpm) 1 1

26 Liquid Waste Treatment 

System -- 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Case B12A – Account 4: Boiler and Accessories

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Boiler

Supercritical, drum, wallfired, low NOx burners, 

overfire air

1,760,000 kg/hr steam 

@ 25.5 MPa/602°C/602°C 

(3,870,000 lb/hr steam 

@ 3,700 psig/1,115°F/1,115°F)

1 0

2 Primary Air Fan Centrifugal

241,000 kg/hr, 3,300 m3/min 

@ 123 cm WG 

(531,000 lb/hr, 116,100 acfm 

@ 48 in. WG)

2 0

3 Forced Draft

Fan Centrifugal

784,000 kg/hr, 10,700 m3/min 

@ 47 cm WG 

(1,729,000 lb/hr, 377,900 acfm 

@ 19 in. WG)

2 0

4 Induced Draft 

Fan Centrifugal

1,131,000 kg/hr, 22,400 m3/min 

@ 89 cm WG 

(2,494,000 lb/hr, 792,500 acfm 

@ 35 in. WG)

2 0

5 SCR Reactor 

Vessel Space for spare layer 2,260,000 kg/hr (4,990,000 lb/hr) 2 0

6 SCR Catalyst -- -- 3 0

7 Dilution Air 

Blower Centrifugal 120 m3/min @ 108 cm WG (4,300 acfm @ 42 in. WG) 2 1

8 Ammonia 

Storage Horizontal tank 135,000 liter (36,000 gal) 5 0

9 Ammonia Feed 

Pump Centrifugal 26 lpm @ 90 m H2O (7 gpm @ 300 ft H2O) 2 1

Case B12A – Account 5: Flue Gas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter

Single stage, high-ratio 

with pulse-jet online 

cleaning system

1,131,000 kg/hr (2,494,000 

lb/hr) 99.9% efficiency 2 0

2 Absorber Module Counter-current open 

spray

45,000 m3/min 

(1,593,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 157,000 lpm @ 65 m H2O 

(41,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal centrifugal 3,820 lpm (1,010 gpm) 

at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 80 m3/min @ 0.3 MPa 

(2,800 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units 

each

960 lpm (250 gpm) per 

cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 30 tonne/hr (33 tph) of 50 wt 

% slurry 2 1

9 Filtrate Water Return 

Pumps Horizontal centrifugal 580 lpm @ 13 m H2O (150 gpm @ 40 ft H2O) 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 380,000 lpm (100,000 gal) 1 0

11 Process Makeup 

Water Pumps Horizontal centrifugal 3,040 lpm @ 21 m H2O (800 gpm @ 70 ft H2O) 1 1

12 Activated Carbon 

Injectors --- 110 kg/hr (250 lb/hr) 1 0

13 Hydrated Lime 

Injectors --- 3,970 kg/hr (8,760 lb/hr) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Case B12A – Account 7: Ducting and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner

152 m (500 ft) high x

5.7 m (19 ft) diameter 1 0

Case B12A – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

610 MW

24.1 MPa/593°C/593°C (3500 psig/ 

1100°F/1100°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

680 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

2,410 GJ/hr (2,290 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

Case B12A – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 453,000 lpm @ 30 m(120,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2530 GJ/hr (2400 MMBtu/hr) heat duty

1 0

Case B12A – Account 10: Ash and Spent Sorbent Recovery and Handling

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

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 -- 3.8 tonne/hr (4.2 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of 

supply included with boiler) -- -- 6 0

5 Hydroejectors -- -- 12

6 Economizer /Pyrites Transfer Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, 

wet pit

150 lpm @ 17 m H2O 

(40 gpm @ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, 

wet pit

7,570 lpm @ 9 m H2O 

(2000 gpm @ 28 ft 

H2O)

1 1

9 Hydrobins -- 150 lpm (40 gpm) 1 1

10 Baghouse Hopper (part of baghouse 

scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of 

supply) -- -- 10 0

12 Air Blower -- 20 m3/min @ 0.2 MPa 

(630 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforce

d concrete 1,200 tonne (1,300 ton) 2 0

14 Slide Gate Valves -- -- 2 0

15 Unloader -- -- 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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16 Telescoping Unloading Chute -- 110 tonne/hr (120 tph) 1 0

Case B12A – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 

MVA, 3-ph, 60 Hz 1 0

2 High Voltage Transformer Oil-filled 345 kV/13.8 kV, 0 

MVA, 3-ph, 60 Hz 2 0

3 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 31 

MVA, 3-ph, 60 Hz 1 1

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 5 

MVA, 3-ph, 60 Hz 1 1

5 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

6 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

7 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

8 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B12A – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.3.6 Case B12A – Costs Estimating Results

The cost estimating methodology was described previously in Section 2.7. Exhibit 3-49 shows a 

detailed breakdown of the capital costs; Exhibit 3-50 shows the owner’s costs, TOC, and TASC; 

Exhibit 3-51 shows the initial and annual O&M costs; and Exhibit 3-52 shows the COE 

breakdown. 

The estimated TPC of the SC PC boiler with no CO2 capture is $2,026/kW. No process 

contingency was included in this case because all elements of the technology are commercially 

proven. The project contingency is 10.7 percent of the TPC. The COE is $82.3/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

132

Exhibit 3-49 Case B12A total plant cost details

Case: B11A – Supercritical PC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $3,998 $0 $1,801 $0 $5,799 $580 $0 $957 $7,336 $13

1.2 Coal Stackout & Reclaim $5,167 $0 $1,155 $0 $6,321 $632 $0 $1,043 $7,996 $15

1.3 Coal Conveyors $4,804 $0 $1,142 $0 $5,946 $595 $0 $981 $7,522 $14

1.4 Other Coal Handling $1,257 $0 $264 $0 $1,521 $152 $0 $251 $1,924 $3

1.5 Sorbent Receive & Unload $159 $0 $47 $0 $207 $21 $0 $34 $262 $0

1.6 Sorbent Stackout & Reclaim $2,574 $0 $465 $0 $3,039 $304 $0 $501 $3,844 $7

1.7 Sorbent Conveyors $918 $199 $222 $0 $1,340 $134 $0 $221 $1,695 $3

1.8 Other Sorbent Handling $555 $131 $287 $0 $972 $97 $0 $160 $1,230 $2

1.9 Coal & Sorbent Hnd. Foundations $0 $4,633 $6,109 $0 $10,743 $1,074 $0 $1,773 $13,590 $25

Subtotal $19,431 $4,963 $11,493 $0 $35,888 $3,589 $0 $5,921 $45,398 $83

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $2,287 $0 $439 $0 $2,726 $273 $0 $450 $3,448 $6

2.2 Coal Conveyor to Storage $5,854 $0 $1,260 $0 $7,115 $711 $0 $1,174 $9,000 $16

2.5 Sorbent Prep Equipment $4,370 $189 $895 $0 $5,454 $545 $0 $900 $6,899 $13

2.6 Sorbent Storage & Feed $526 $0 $199 $0 $725 $73 $0 $120 $918 $2

2.9 Coal & Sorbent Feed Foundation $0 $533 $468 $0 $1,001 $100 $0 $165 $1,266 $2

Subtotal $13,037 $722 $3,262 $0 $17,021 $1,702 $0 $2,808 $21,531 $39

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $21,709 $0 $6,999 $0 $28,708 $2,871 $0 $4,737 $36,316 $66

3.2 Water Makeup & Pretreating $5,225 $0 $1,653 $0 $6,878 $688 $0 $1,513 $9,079 $17

3.3 Other Feedwater Subsystems $6,829 $0 $2,803 $0 $9,632 $963 $0 $1,589 $12,185 $22

3.4 Service Water Systems $1,046 $0 $548 $0 $1,594 $159 $0 $351 $2,104 $4

3.5 Other Boiler Plant Systems $8,284 $0 $7,832 $0 $16,116 $1,612 $0 $2,659 $20,387 $37

3.6 FO Supply Sys & Nat Gas $327 $0 $382 $0 $708 $71 $0 $117 $896 $2

3.7 Waste Treatment Equipment $3,428 $0 $1,985 $0 $5,413 $541 $0 $1,191 $7,145 $13

3.8 Misc. Equip. (Cranes, Air Comp., 

Comm.)

$3,201 $0 $990 $0 $4,191 $419 $0 $922 $5,532 $10

Subtotal $50,049 $0 $23,192 $0 $73,241 $7,324 $0 $13,079 $93,644 $170

4 Boiler & Accessories

4.1 PC Boiler & Accessories $179,905 $0 $102,509 $0 $282,414 $28,241 $0 $31,066 $341,722 $621

4.2 SCR w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0

Subtotal $179,905 $0 $102,509 $0 $282,414 $28,241 $0 $31,066 $341,722 $621

5A Gas Cleanup & Piping

5A.1 Absorber Vessels & Accessories $67,346 $0 $14,399 $0 $81,745 $8,175 $0 $8,992 $98,912 $180

5A.2 Other FGD $3,514 $0 $3,955 $0 $7,470 $747 $0 $822 $9,038 $16
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

133

Case: B11A – Supercritical PC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.3 Bag House & Accessories $19,040 $0 $12,001 $0 $31,041 $3,104 $0 $3,415 $37,560 $68

5A.4 Other Particulate Removal Materials $1,289 $0 $1,369 $0 $2,658 $266 $0 $292 $3,216 $6

5A.5 Gypsum Dewatering System $5,399 $0 $911 $0 $6,309 $631 $0 $694 $7,634 $14

5A.6 Mercury Removal System $4,093 $900 $4,024 $0 $9,018 $902 $0 $992 $10,911 $20

Subtotal $100,681 $900 $36,660 $0 $138,241 $13,824 $0 $15,207 $167,272 $304

7 HRSG, Ducting, & Stack

7.3 Ductwork $10,663 $0 $6,731 $0 $17,394 $1,739 $0 $2,870 $22,004 $40

7.4 Stack $10,604 $0 $6,162 $0 $16,766 $1,677 $0 $1,844 $20,287 $37

7.9 Duct & Stack Foundations $0 $1,156 $1,373 $0 $2,528 $253 $0 $556 $3,337 $6

Subtotal $21,267 $1,156 $14,266 $0 $36,689 $3,669 $0 $5,271 $45,629 $83

8 Steam Turbine Generator

8.1 Steam TG & Accessories $75,300 $0 $8,211 $0 $83,511 $8,351 $0 $9,186 $101,049 $184

8.2 Turbine Plant Auxiliaries $418 $0 $890 $0 $1,308 $131 $0 $144 $1,582 $3

8.3 Condenser & Auxiliaries $7,830 $0 $2,737 $0 $10,567 $1,057 $0 $1,162 $12,786 $23

8.4 Steam Piping $26,525 $0 $10,751 $0 $37,276 $3,728 $0 $6,151 $47,154 $86

8.9 TG Foundations $0 $1,247 $2,059 $0 $3,305 $331 $0 $727 $4,363 $8

Subtotal $110,073 $1,247 $24,647 $0 $135,967 $13,597 $0 $17,370 $166,934 $304

9 Cooling Water System

9.1 Cooling Towers $10,613 $0 $3,282 $0 $13,895 $1,390 $0 $1,529 $16,814 $31

9.2 Circulating Water Pumps $2,125 $0 $133 $0 $2,258 $226 $0 $248 $2,732 $5

9.3 Circ. Water System Auxiliaries $586 $0 $78 $0 $664 $66 $0 $73 $803 $1

9.4 Circ. Water Piping $0 $4,939 $4,473 $0 $9,412 $941 $0 $1,553 $11,906 $22

9.5 Make-up Water System $528 $0 $678 $0 $1,206 $121 $0 $199 $1,525 $3

9.6 Component Cooling Water Sys. $478 $0 $367 $0 $845 $84 $0 $139 $1,069 $2

9.9 Circ. Water Foundations & Structures $0 $2,616 $4,344 $0 $6,960 $696 $0 $1,531 $9,188 $17

Subtotal $14,330 $7,555 $13,355 $0 $35,240 $3,524 $0 $5,273 $44,037 $80

10 Ash & Spent Sorbent Handling Systems

10.6 Ash Storage Silos $777 $0 $2,379 $0 $3,156 $316 $0 $347 $3,819 $7

10.7 Ash Transport & Feed Equipment $5,164 $0 $5,119 $0 $10,283 $1,028 $0 $1,131 $12,443 $23

10.9 Ash/Spent Sorbent Foundation $0 $176 $216 $0 $392 $39 $0 $86 $517 $1

Subtotal $5,941 $176 $7,714 $0 $13,831 $1,383 $0 $1,564 $16,778 $31

11 Accessory Electric Plant

11.1 Generator Equipment $1,942 $0 $310 $0 $2,253 $225 $0 $186 $2,664 $5

11.2 Station Service Equipment $3,283 $0 $1,101 $0 $4,384 $438 $0 $362 $5,184 $9

11.3 Switchgear & Motor Control $3,769 $0 $655 $0 $4,423 $442 $0 $487 $5,352 $10

11.4 Conduit & Cable Tray $0 $2,584 $8,349 $0 $10,934 $1,093 $0 $1,804 $13,831 $25

11.5 Wire & Cable $0 $4,921 $8,796 $0 $13,717 $1,372 $0 $2,263 $17,352 $32

11.6 Protective Equipment $306 $0 $1,063 $0 $1,370 $137 $0 $151 $1,658 $3

11.7 Standby Equipment $1,497 $0 $35 $0 $1,532 $153 $0 $169 $1,854 $3

11.8 Main Power Transformers $9,846 $0 $206 $0 $10,052 $1,005 $0 $1,106 $12,163 $22

11.9 Electrical Foundations $0 $359 $913 $0 $1,271 $127 $0 $280 $1,678 $3

Subtotal $20,644 $7,864 $21,428 $0 $49,936 $4,994 $0 $6,806 $61,735 $112
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Case: B11A – Supercritical PC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

12 Instrumentation & Control

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $531 $0 $324 $0 $855 $86 $0 $141 $1,082 $2

12.7 Distributed Control Sys. Equipment $5,357 $0 $955 $0 $6,313 $631 $0 $694 $7,638 $14

12.8 Instrument Wiring & Tubing $3,230 $0 $5,878 $0 $9,109 $911 $0 $1,503 $11,522 $21

12.9 Other I & C Equipment $1,514 $0 $3,505 $0 $5,019 $502 $0 $552 $6,073 $11

Subtotal $10,632 $0 $10,663 $0 $21,296 $2,130 $0 $2,891 $26,316 $48

13 Improvements to Site

13.1 Site Preparation $0 $56 $1,194 $0 $1,250 $125 $0 $275 $1,651 $3

13.2 Site Improvements $0 $1,864 $2,462 $0 $4,326 $433 $0 $952 $5,710 $10

13.3 Site Facilities $3,340 $0 $3,504 $0 $6,843 $684 $0 $1,506 $9,033 $16

Subtotal $3,340 $1,920 $7,160 $0 $12,420 $1,242 $0 $2,732 $16,394 $30

14 Buildings & Structures

14.1 Boiler Building $0 $9,916 $8,714 $0 $18,629 $1,863 $0 $3,074 $23,566 $43

14.2 Turbine Building $0 $14,161 $13,189 $0 $27,349 $2,735 $0 $4,513 $34,597 $63

14.3 Administration Building $0 $702 $742 $0 $1,444 $144 $0 $238 $1,827 $3

14.4 Circulation Water Pumphouse $0 $201 $160 $0 $361 $36 $0 $60 $457 $1

14.5 Water Treatment Buildings $0 $652 $594 $0 $1,246 $125 $0 $206 $1,576 $3

14.6 Machine Shop $0 $470 $315 $0 $785 $79 $0 $130 $993 $2

14.7 Warehouse $0 $318 $319 $0 $637 $64 $0 $105 $806 $1

14.8 Other Buildings & Structures $0 $260 $221 $0 $481 $48 $0 $79 $609 $1

14.9 Waste Treating Building & Str. $0 $498 $1,510 $0 $2,008 $201 $0 $331 $2,540 $5

Subtotal $0 $27,177 $25,764 $0 $52,941 $5,294 $0 $8,735 $66,971 $122

Total $549,332 $53,681 $302,113 $0 $905,125 $90,513 $0 $118,723 $1,114,361 $2,026
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

135

Exhibit 3-50 Case B12A owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $8,509 $15

1 Month Maintenance Materials $1,071 $2

1 Month Non-fuel Consumables $2,133 $4

1 Month Waste Disposal $429 $1

25% of 1 Months Fuel Cost at 100% CF $2,471 $4

2% of TPC $22,287 $41

Total $36,901 $67

Inventory Capital

60 day supply of fuel and consumables at 100% CF $23,659 $43

0.5% of TPC (spare parts) $5,572 $10

Total $29,231 $53

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $167,154 $304

Financing Costs $30,088 $55

Total Overnight Costs (TOC) $1,378,634 $2,507

TASC Multiplier (IOU, low-risk, 35 year) 1.134

Total As-Spent Cost (TASC) $1,563,371 $2,842
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 3-51 Case B12A initial and annual operating and maintenance costs

Case: B12A – Supercritical PC w/o CO2 Cost Base: Jun 2011

Plant Size (MW,net): 550 Heat Rate-net (Btu/kWh): 8,379 Capacity Factor (%): 85

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 9.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 2.0 

Total: 14.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $6,329,450 $11.508

Maintenance Labor: $7,284,427 $13.244

Administrative & Support Labor: $3,403,469 $6.188

Property Taxes and Insurance: $22,287,220 $40.521

Total: $39,304,567 $71.461

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $10,926,640 $2.66803

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 3,675 $1.67 $0 $1,908,776 $0.46608

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 17,791 $0.27 $0 $1,478,352 $0.36098

Limestone (ton) 0 468 $33.48 $0 $4,865,781 $1.18811

Hydrated Lime (ton) 0 96 $155.00 $0 $4,594,464 $1.12186

Activated Carbon (ton) 0 3 $1,255.00 $0 $1,074,374 $0.26234

Ammonia (19% NH3, ton) 0 68 $330.00 $0 $6,967,794 $1.70137

SCR Catalyst (m3) 0 0.31 $8,938.80 $0 $871,258 $0.21274

Subtotal: $0 $21,760,800 $5.31349

Waste Disposal

Fly Ash (ton) 0 470 $25.11 $0 $3,659,558 $0.89358

Bottom Ash (ton) 0 92 $25.11 $0 $719,871 $0.17578

 Subtotal: $0 $4,379,428 $1.06936

By-Products

Gypsum (ton) 0 81 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $37,066,868 $9.05088

Fuel Cost

Illinois Number 6 (ton): 0 4,741 $68.54 $0 $100,807,335 $24.61483

Total: $0 $100,807,335 $24.61483

Exhibit 3-52 Case B12A COE breakdown

Component Value, $/MWh Percentage

Capital 39.0 47%

Fixed 9.6 12%

Variable 9.1 11%

Fuel 24.6 30%

Total (Excluding T&S) 82.3 N/A

CO2 T&S 0.0 0%

Total (Including T&S) 82.3 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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3.3.7 Case B12B – Supercritical PC with CO2 Capture

The plant configuration for Case B12B, SC PC, is the same as Case B12A with the exception 

that the Cansolv system was used for the CDR facility. The nominal net output is maintained at 

550 MW by increasing the boiler size and turbine/generator size to account for the greater 

auxiliary load imposed by the CDR facility and CO2 compressors. Unlike the NGCC cases 

where gross output was fixed by the available size of the CTs, the PC cases utilize boilers and 

steam turbines that can be procured at nearly any desired output making it possible to maintain a 

constant net output.

The process description for Case B12B is essentially the same as Case B12A with one notable 

exception, the addition of CO2 capture. A BFD and stream tables for Case B12B are shown in 

Exhibit 3-53 and Exhibit 3-54, respectively. Since the CDR facility process description was 

provided in Section 3.1.8, it is not repeated here.

3.3.8 Case B12B Performance Results

The Case B12B modeling assumptions were presented previously in Section 3.3.2.

The plant produces a net output of 550 MW at a net plant efficiency of 32.5 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 3-55; Exhibit 3-56 provides a 

detailed breakdown of the auxiliary power requirements. The CDR facility, including CO2

compression, accounts for over half of the auxiliary plant load. The CWS (CWPs and cooling 

tower fan) accounts for nearly 13 percent of the auxiliary load, largely due to the high cooling 

water demand of the CDR facility and CO2 compressors.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

138

Exhibit 3-53 Case B12B block flow diagram, supercritical unit with CO2 capture

Source: NETL

STACK GAS

STACK

CANSOLV

32 31

33

22

23

CO2

PRODUCT

REBOILER

STEAM

REBOILER

CONDENSATE

PULVERIZED

COAL

BOILER

SCR

BAGHOUSE FGD

LIMESTONE GYPSUM

SLURRY

OXIDATION

AIR

MAKEUP

WATER

BOTTOM ASH

COAL FEED

INFILTRATION

AIR

1

4

8

7

9

14

FLY ASH

15 16

18 19

17 20

21

HP 

TURBINE

34

35

36

IP

TURBINE LP TURBINE

CONDENSER

38

FEEDWATER 

HEATER

SYSTEM

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

3

2

6

5

11

37

10

HYDRATED

LIME

12

13

ACTIVATED

CARBON

FD FANS

PA FANS

ID FAN

CO2 COMPRESSORS

BOILER

FEEDWATER

29 RECLAIMER

STEAM 30

RECLAIMER

CONDENSATE

DRYER

27

CO2 COMPRESSORS

28

25 26

24

VENT

DRYER STEAM

DRYER

CONDENSATE
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

139

Exhibit 3-54 Case B12B stream table, supercritical unit with capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0000 0.0088 0.0000 0.0088 0.0000

CO2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.0000 0.1376 0.0000 0.1376 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0000 0.0831 0.0000 0.0831 0.0000

N2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.0000 0.7345 0.0000 0.7345 0.0000

O2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0000 0.0340 0.0000 0.0340 0.3333

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0020 0.0000 0.0020 0.6667

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 61,983 61,983 1,836 19,040 19,040 2,620 1,354 0 0 0 86,880 0 86,880 4

V-L Flowrate (kg/hr) 1,788,627 1,788,627 52,976 549,448 549,448 75,618 39,068 0 0 0 2,580,136 0 2,580,136 198

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 224,791 4,360 4,530 21,968 131 22,099 22,099

Temperature (°C) 15 19 19 15 25 25 15 15 149 27 143 27 143 143

Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

Steam Table Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23 --- --- --- --- --- --- ---

AspenPlus Enthalpy (kJ/kg)B -97.58 -93.45 -93.45 -97.58 -87.03 -87.03 -97.58 -2,114.05 97.18 -13,306.82 -2,399.49 3.40 -2,399.37 -2,632.04

Density (kg/m3) 1.2 1.2 1.2 1.2 1.3 1.3 1.2 --- --- --- 0.9 --- 0.9 1.5

V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857 --- --- --- 29.698 --- 29.698 53.376

V-L Flowrate (lbmole/hr) 136,648 136,648 4,047 41,977 41,977 5,777 2,985 0 0 0 191,537 0 191,537 8

V-L Flowrate (lb/hr) 3,943,248 3,943,248 116,791 1,211,325 1,211,325 166,710 86,130 0 0 0 5,688,226 0 5,688,226 436

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 495,578 9,611 9,988 48,432 288 48,720 48,720

Temperature (°F) 59 66 66 59 78 78 59 59 300 80 289 80 289 289

Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.4 14.7 14.4 14.7 14.4 14.4

Steam Table Enthalpy (Btu/lb)A 13.0 14.8 14.8 13.0 17.5 17.5 13.0 --- --- --- --- --- --- ---

AspenPlus Enthalpy (Btu/lb)B -42.0 -40.2 -40.2 -42.0 -37.4 -37.4 -42.0 -908.9 41.8 -5,720.9 -1,031.6 1.5 -1,031.5 -1,131.6

Density (lb/ft3) 0.076 0.078 0.078 0.076 0.081 0.081 0.076 --- --- --- 0.053 --- 0.053 0.096

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

140

Exhibit 3-54 Case B12B stream table, supercritical unit with capture (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28

V-L Mole Fraction

Ar 0.0088 0.0088 0.0000 0.0000 0.0092 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1376 0.1376 0.0000 0.0000 0.0003 0.0001 0.1288 0.9824 0.9977 0.0492 0.0000 0.0000 0.9993 0.9993

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0831 0.0831 1.0000 1.0000 0.0099 0.9999 0.1451 0.0176 0.0023 0.9508 1.0000 1.0000 0.0007 0.0007

N2 0.7345 0.7345 0.0000 0.0000 0.7732 0.0000 0.6854 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0340 0.0340 0.0000 0.0000 0.2074 0.0000 0.0325 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0020 0.0020 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 86,876 86,876 2,880 11,542 919 213 94,143 11,109 10,940 18 14 14 10,921 10,921

V-L Flowrate (kg/hr) 2,579,938 2,579,938 51,879 207,939 26,514 3,829 2,716,229 483,852 480,793 352 255 255 480,441 480,441

Solids Flowrate (kg/hr) 0 0 22,213 0 0 34,451 0 0 0 0 0 0 0 0

Temperature (°C) 143 153 15 27 167 56 56 29 29 29 461 203 29 40

Pressure (MPa, abs) 0.10 0.11 0.10 0.11 0.31 0.10 0.10 0.20 3.03 3.03 2.14 1.64 2.89 15.27

Steam Table Enthalpy (kJ/kg) A 274.36 285.60 --- 111.65 184.48 --- 286.10 42.52 -6.00 138.07 3,379.59 863.65 -5.93 -205.61

AspenPlus Enthalpy (kJ/kg)B -2,397.36 -2,386.11 -14,995.75 -15,964.53 56.67 -12,481.91 -2,940.30 -8,972.02 -8,974.94 -15,237.30 -12,600.71 -15,116.65 -8,970.17 -9,169.86

Density (kg/m3) 0.8 0.9 1,003.6 992.3 2.4 833.1 1.1 3.5 63.3 377.5 6.4 861.8 59.9 789.2

V-L Molecular Weight 29.697 29.697 18.015 18.015 28.857 18.018 28.852 43.553 43.950 19.294 18.015 18.015 43.991 43.991

V-L Flowrate (lbmole/hr) 191,529 191,529 6,349 25,447 2,026 468 207,551 24,492 24,118 40 31 31 24,078 24,078

V-L Flowrate (lb/hr) 5,687,790 5,687,790 114,374 458,428 58,452 8,441 5,988,260 1,066,711 1,059,968 776 563 563 1,059,192 1,059,192

Solids Flowrate (lb/hr) 0 0 48,970 0 0 75,950 0 0 0 0 0 0 0 0

Temperature (°F) 289 308 59 80 332 133 133 85 85 85 861 397 85 104

Pressure (psia) 14.2 15.2 15.0 15.7 45.0 14.7 14.7 28.7 439.4 439.4 310.1 237.4 419.4 2,214.7

Steam Table Enthalpy (Btu/lb)A 118.0 122.8 --- 48.0 79.3 --- 123.0 18.3 -2.6 59.4 1,453.0 371.3 -2.5 -88.4

AspenPlus Enthalpy (Btu/lb)B -1,030.7 -1,025.8 -6,447.0 -6,863.5 24.4 -5,366.3 -1,264.1 -3,857.3 -3,858.5 -6,550.9 -5,417.3 -6,499.0 -3,856.5 -3,942.3

Density (lb/ft3) 0.052 0.055 62.650 61.950 0.153 52.011 0.067 0.216 3.953 23.565 0.402 53.801 3.737 49.270

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

141

Exhibit 3-54 Case B12B stream table, supercritical unit with capture (continued)

29 30 31 32 33 34 35 36 37 38

V-L Mole Fraction

Ar 0.0000 0.0000 0.0000 0.0000 0.0103 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0000 0.0000 0.0000 0.0000 0.0163 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 1.0000 1.0000 1.0000 0.0671 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.0000 0.0000 0.0000 0.0000 0.8652 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0410 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 85 85 27,975 27,977 74,575 111,201 92,880 92,880 51,680 51,902

V-L Flowrate (kg/hr) 1,533 1,533 503,979 504,008 2,079,831 2,003,325 1,673,260 1,673,260 931,021 935,036

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 342 215 269 151 41 593 342 593 38 39

Pressure (MPa, abs) 4.90 2.11 0.51 0.49 0.10 24.23 4.90 4.80 0.01 1.37

Steam Table Enthalpy (kJ/kg) A 3,049.83 921.30 3,000.13 635.93 151.94 3,477.96 3,049.83 3,652.36 2,166.50 162.50

AspenPlus Enthalpy (kJ/kg)B -12,930.47 -15,058.99 -12,980.16 -15,344.37 -794.66 -12,502.33 -12,930.47 -12,327.94 -13,813.79 -15,817.80

Density (kg/m3) 19.2 846.4 2.1 916.3 1.1 69.2 19.2 12.3 0.1 993.3

V-L Molecular Weight 18.015 18.015 18.015 18.015 27.889 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmole/hr) 188 188 61,675 61,678 164,410 245,157 204,765 204,765 113,934 114,425

V-L Flowrate (lb/hr) 3,379 3,379 1,111,084 1,111,147 4,585,242 4,416,576 3,688,906 3,688,906 2,052,550 2,061,401

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 648 419 517 304 107 1,100 648 1,100 101 101

Pressure (psia) 710.8 306.2 73.5 70.6 14.7 3,514.7 710.8 696.6 1.0 198.7

Steam Table Enthalpy (Btu/lb)A 1,311.2 396.1 1,289.8 273.4 65.3 1,495.3 1,311.2 1,570.2 931.4 69.9

AspenPlus Enthalpy (Btu/lb)B -5,559.1 -6,474.2 -5,580.5 -6,596.9 -341.6 -5,375.0 -5,559.1 -5,300.1 -5,938.9 -6,800.4

Density (lb/ft3) 1.197 52.841 0.128 57.201 0.068 4.319 1.197 0.768 0.004 62.011

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

142

Exhibit 3-55 Case B12B plant performance summary

Performance Summary

Total Gross Power, MWe 642

CO2 Capture/Removal Auxiliaries, kWe 16,000

CO2 Compression, kWe 35,690

Balance of Plant, kWe 39,595

Total Auxiliaries, MWe 91

Net Power, MWe 550

HHV Net Plant Efficiency (%) 32.5%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,086 (10,508)

LHV Net Plant Efficiency (%) 33.7%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 10,693 (10,135)

HHV Boiler Efficiency, % 89.1%

LHV Boiler Efficiency, % 92.4%

Steam Turbine Cycle Efficiency, % 54.5%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 6,608 (6,263)

Condenser Duty, GJ/hr (MMBtu/hr) 1,867 (1,770)

As-Received Coal Feed, kg/hr (lb/hr) 224,791 (495,578)

Limestone Sorbent Feed, kg/hr (lb/hr) 22,213 (48,970)

HHV Thermal Input, kWt 1,694,366

LHV Thermal Input, kWt 1,634,237

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.054 (14.3)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.042 (11.0)

Excess Air, % 20.9%
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

143

Exhibit 3-56 Case B12B plant power summary

Power Summary

Steam Turbine Power, MWe 642

Total Gross Power, MWe 642

Auxiliary Load Summary

Coal Handling and Conveying, kWe 480

Pulverizers, kWe 3,370

Sorbent Handling & Reagent Preparation, kWe 1,070

Ash Handling, kWe 780

Primary Air Fans, kWe 1,670

Forced Draft Fans, kWe 2,130

Induced Draft Fans, kWe 8,350

SCR, kWe 60

Activated Carbon Injection, kW 27

Dry sorbent Injection, kW 108

Baghouse, kWe 110

Wet FGD, kWe 3,550

CO2 Capture/Removal Auxiliaries, kWe 16,000

CO2 Compression, kWe 35,690

Miscellaneous Balance of PlantA,B, kWe 2,000

Steam Turbine Auxiliaries, kWe 400

Condensate Pumps, kWe 640

Circulating Water Pumps, kWe 7,750

Ground Water Pumps, kWe 710

Cooling Tower Fans, kWe 4,010

Transformer Losses, kWe 2,380

Total Auxiliaries, MWe 91

Net Power, MWe 550

ABoiler feed pumps are turbine driven

BIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.3.8.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case B12B is presented in Exhibit 3-57. SO2

emissions are utilized as a surrogate for HCl emissions, therefore HCl is not reported.

Exhibit 3-57 Case B12B air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)

SO2 0.000 (0.000) 0 (0) 0.000 (0.000)

NOx 0.033 (0.078) 1,517 (1,672) 0.318 (0.700)

Particulate 0.004 (0.010) 195 (215) 0.041 (0.090)

Hg 1.43E-7 (3.33E-7) 0.006 (0.007) 1.36E-6 (3.00E-6)

CO2B 9 (20) 397,399 (438,058) 83 (183)

CO2C - - 97 (214)

mg/Nm3

Particulate ConcentrationD,E 13.45

ACalculations based on an 85 percent capacity factor

BCO2 emissions based on gross power

CCO2 emissions based on net power instead of gross power DConcentration of particles in the flue gas after the baghouse

ENormal conditions given at 32°F and 14.696 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

144

SO2 emissions are controlled using a wet limestone forced oxidation scrubber that achieves a 

removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. 

The wallboard grade material can potentially be marketed and sold, but since it is highly 

dependent on local market conditions, no byproduct credit was taken. The SO2 emissions are 

further reduced to 1 ppmv using a NaOH based polishing scrubber in the CDR facility. The 

remaining low concentration of SO2 is essentially completely removed in the CDR absorber 

vessel resulting in very low SO2 emissions.

NOx emissions are controlled to about 0.5 lb/MMBtu through the use of LNBs and OFA. An 

SCR unit then further reduces the NOx concentration by 85 percent to 0.08 lb/MMBtu.

Particulate emissions are controlled using a pulse jet fabric filter, which operates at an efficiency 

of 99.9 percent.

The total reduction in mercury emission via the combined control equipment (SCR, ACI, fabric 

filter, DSI, and wet FGD) is 97.1 percent.

Ninety (90) percent of the CO2 in the flue gas is removed in CDR facility.

The carbon input to the plant consists of carbon in the coal, carbon in the air, PAC, and carbon in 

the limestone reagent used in the FGD. Carbon leaves the plant mostly as CO2 through the stack, 

however, the PAC is captured in the fabric filter and some leaves as gypsum. The carbon 

capture efficiency is defined as one minus the amount of carbon in the stack gas relative to the 

total carbon in, represented by the following fraction: 

CCCCCCCC SSSS

( TT CCCCCCCC ) = �1 − � 32,112

321,883�� ∗ 100 = 90.0%

Exhibit 3-58 Case B12B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 143,292 (315,905) Stack Gas 14,566 (32,112)

Air (CO2) 327 (721) FGD Product 215 (474)

PAC 131 (288) Baghouse 131 (288)

FGD Reagent 2,254 (4,969) CO2 Product 131,081 (288,984)

CO2 Dryer Vent 11 (24)

CO2 Knockout 0 (1)

Total 146,004 (321,883) Total 146,004 (321,883)

Exhibit 3-59 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum, sulfur emitted in

the stack gas, and sulfur removed in the polishing scrubber.

Exhibit 3-59 Case B12B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,634 (12,421) FGD Product 5,444 (12,002)

Stack Gas 0 (0)

Polishing Scrubber and Solvent Reclaiming 111 (245)

Baghouse 79 (175)

Total 5,634 (12,421) Total 5,634 (12,421)
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145

Exhibit 3-60 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as for Case B12A.

Exhibit 3-60 Case B12B water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

FGD Makeup 4.34 (1,146) – 4.34 (1,146) – 4.34 (1,146)

CO2 Drying – – – 0.01 (2) -0.01 (-2)

Capture System 

Makeup 0.02 (5) – 0.02 (5) – 0.02 (5)

Deaerator Vent – – – 0.07 (18) -0.07 (-18)

Condenser Makeup 0.07 (18) – 0.07 (18) – 0.07 (18)

 BFW Makeup 0.07 (18) – 0.07 (18) – 0.07 (18)

Cooling Tower 30.19 

(7,976) 4.78 (1,262) 25.41 (6,714) 6.79 (1,794) 18.62 (4,920)

 FGD Dewatering – 2.24 (591) -2.24 (-591) – -2.24 (-591)

 CO2 Capture 

 Recovery – 2.54 (672) -2.54 (-672) – -2.54 (-672)

 CO2 Compression 

 KO – 0.05 (13) -0.05 (-13) – -0.05 (-13)

 BFW Blowdown – – – – –

Total 34.62 

(9,145) 4.78 (1,262) 29.84 (7,882) 6.86 (1,813) 22.97 (6,069)

3.3.8.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the Case B12B PC boiler, the FGD unit, CDR 

system, and steam cycle in Exhibit 3-61 and Exhibit 3-62. An overall plant energy balance is 

provided in tabular form in Exhibit 3-63. 

The power out is the steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-55) is calculated by multiplying the power out by a generator 

efficiency of 98.5 percent. The capture process heat out stream represents heat rejected to 

cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser 

heat out stream. The CO2 compressor intercooler load is included in the capture process heat out 

stream.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

146

Exhibit 3-61 Case B12B heat and mass balance, supercritical PC boiler with CO2 capture

Source: NETL

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Coal/Ash

Slurry

Water

Steam

PAGES

1 OF 2

BITUMINOUS BASELINE STUDY

CASE B12B

SUBCRITICAL PULVERIZED COAL

BOILER AND GAS CLEANUP SYSTEMS

DWG. NO.

BB-HMB-CS-B12B-PG-1

Pulverized

Coal

Boiler

Ammonia SCR

Infiltration Air

Air

Air

Coal

Bottom Ash

FGD

Fly Ash

Forced

Draft Fans

Primary 

Air Fans

495,578 W

59 T

15 P

78 T

16 P

18 H

66 T

15 P

15 H

4,416,576 W

1,100 T

3,515 P

1,495 H

3,688,906 W

1,100 T

697 P

1,570 H

1,211,325 W

59 T

15 P

13 H

3,943,248 W

59 T

15 P

13 H

86,130 W

59 T

15 P

13 H

5,736,658 W

289 T

14 P

117 H

9,611 W

300 T

14 P

49,156 W

289 T

14 P

3,688,906 W

648 T

711 P

1,311 H

4,416,576 W

555 T

3,691 P

551 H

5

4,585,242 W

107 T

15 P

65 H

1 2

4

7

9

5,687,790 W ID Fans

289 T

14 P

118 H

Gross Plant Power: 642 MWe

Auxiliary Load: 91 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 32.5%

Net Plant Heat Rate: 10,508 Btu/kWh

Lime/

Limestone/

Gypsum

Flue Gas

Oxidation 

Air

Make-Up 

Water

Limestone 

Slurry

Gypsum

18

17

14

5,687,790 W

308 T

15 P

123 H

163,344 W

59 T

15 P

423 H

58,452 W

332 T

45 P

79 H

458,428 W

80 T

16 P

48 H

84,392 W

133 T

15 P

1,499 H

Baghouse

3

6

8

15 16

19

34

35

36

DOE/NETL

SC PC PLANT

CASE B12B

Hydrated 

Lime

11

Single Reheat

Extraction from

HP Turbine

From Feedwater

Heaters

Single Reheat

To IP Turbine

Throttle Steam

To HP Turbine

9,988 W

80 T

15 P

10

Activated 

Carbon

12

Activated 

Carbon

13

288 W

80 T

15 P

Cansolv

Stripper

Absorber

Flue Gas Acid Gas

1,066,711 W

85 T

29 P

18 H

22

33

5,988,260 W

133 T

15 P

123 H

Stack

21

1,059,192 W

104 T

2,215 P

-88 H

CO2

Product

CO2 Compression 

(Interstage Cooling) & 

Drying

6,743 W

85 T

62 P

66 H

KO-Water

Dryer 

Water

776 W

85 T

439 P

59 H

24

Dryer

28

23

27

1,059,192 W

85 T

419 P

-3 H

1,059,968 W

85 T

439 P

-3 H

Carbon Dioxide

5,736,946 W

289 T

14 P

117 H

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

20

Ammonia
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

147

Exhibit 3-62 Case B12B heat and mass balance, supercritical steam cycle

Source: NETL

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

Water

Steam

PAGES

2 OF 2

DWG. NO.

BB-HMB-CS-B12B-PG-2

BITUMINOUS BASELINE STUDY

CASE B12B

SUBCRITICAL PULVERIZED COAL

POWER BLOCK SYSTEMS

LP Turbine Generator HP

Turbine

IP

Turbine

Condenser

Hot Well

Boiler Feed Pump 

Turbine Drives

Throttle

Steam

Condensate 

Pumps

4,416,576 W

1,100 T

3,515 P

1,495 H

341,791 W

861 T

298 P

1,453 H

397,804 W

645 T

682 P

1,311 H

3,688,906 W

648 T

711 P

1,311 H

336,231 W

517 T

74 P

1,290 H

336,231 W

126 T

2 P

1,073 H

1,508,246 W

101 T

1 P

1,008 H

2,061,401 W

101 T

1 P

69 H

3,176,490 W

173 T

176 P

142 H

208,074 W

183 T

8 P

151 H

3,176,490 W

241 T

162 P

210 H

1,066,082 W

324 T

94 P

294 H

3,176,490 W

193 T

169 P

161 H

724,291 W

429 T

339 P

406 H

4,416,576 W

419 T

4,005 P

399 H

Deaerator

Boiler Feed

Water Pumps

4,416,576 W

555 T

3,691 P

551 H

3,688,906 W

1,100 T

697 P

1,570 H

149,092 W

203 T

12 P

171 H

182,855 W

517 T

72 P

1,290 H

149,092 

W

344 T

28 P

1,211 H

58,981 W

199 T

11 P

1,146 H

3,163,697 W

517 T

74 P

1,290 H

1,716,320 W

517 T

74 P

1,290 H

4,172 P

4,416,576 W

305 T

72 P

275 H

Gross Plant Power: 642 MWe

Auxiliary Load: 91 MWe

Net Plant Power: 550 MWe

Net Plant Efficiency, HHV: 32.5%

Net Plant Heat Rate: 10,508 Btu/kWh

FWH 4 FWH 3 FWH 6 FWH 5

34

38

DOE/NETL

SC PC PLANT

CASE B12B

36

8,851 W

59 T

15 P

27 H

Vent

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

Single Reheat

Extraction

From Boiler

Single Reheat

Extraction to

Boiler

To Boiler

Steam Turbine

Makeup

35

Reclaimer 

Steam

29

563 W

861 T

310 P

1,453 H

Dryer

Steam

Reboiler

Steam

1,111,084 W

517 T

74 P

1,290 H

25 31

Reboiler

Condensate

Reclaimer

Condensate

Dryer 

Condensate

563 W

397 T

237 P

371 H

3,379 W

419 T

306 P

396 H

1,111,147 W

304 T

71 P

273 H

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

37

326,487 W

757 T

1,071 P

1,358 H

326,487 W

510 T

746 P

500 H

4,416,576 W

500 T

3,845 P

488 H FWH 6

3,379 W

648 T

711 P

1,311 H

30 26 32
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

148

Exhibit 3-63 Case B12B overall energy balance (0°C [32°F] reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Coal 6,100 

(5,781) 5.1 (4.8) – 6,105 (5,786)

Air – 71.9 (68.1) – 71.9 (68.1)

Raw Water Makeup – 112.2 (106.3) – 112.2 (106.3)

Limestone – 0.48 (0.46) – 0.48 (0.46)

Auxiliary Power – – 329 (311) 329 (311)

TOTAL 6,100 

(5,781) 189.6 (179.7) 329 (311) 6,618 (6,273)

Heat Out GJ/hr (MMBtu/hr)

Bottom Ash – 0.5 (0.4) – 0.5 (0.4)

Fly Ash + FGD Ash – 2.5 (2.4) – 2.5 (2.4)

Stack Gas – 316 (300) – 316 (300)

Sulfur 2.1 (1.9) 0.0 (0.0) – 2.1 (2.0)

Motor Losses and Design 

Allowances – – 44 (42) 44 (42)

Condenser – 1,867 (1,770) – 1,867 (1,770)

Non-Condenser Cooling 

Tower Loads – 106 (100) – 106 (100)

CO2 – -98.8 (-93.6) – -98.8 (-93.6)

Cooling Tower Blowdown – 50.4 (47.8) – 50.4 (47.8)

CO2 Capture Losses – 1,970 (1,868) – 1,970 (1,868)

Ambient LossesA – 133.5 (126.5) – 133.5 (126.5)

Power – – 2,309 (2,189) 2,309 (2,189)

TOTAL 2.1 (1.9) 4,347 (4,120) 2,353 (2,231) 6,703 (6,353)

Unaccounted EnergyB – -85 (-80) – -85 (-80)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the boiler, reheater, superheater, and transformers.

BBy difference

3.3.9 Case B12B – Major Equipment List

Major equipment items for the SC PC plant with CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 

estimates in Section 3.3.10. 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 for Fossil Energy Plants Volume 1: Revision 3

149

Case B12B – Account 1: Coal and Sorbent Handling

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 180 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Transfer Tower No. 1 Enclosed N/A 1 0

5 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, 

linear 1,130 tonne/hr (1,250 tph) 1 0

8 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

9 Feeder Vibratory 190 tonne/hr (200 tph) 2 1

10 Conveyor No. 3 Belt w/ tripper 370 tonne/hr (410 tph) 1 0

11 Crusher Tower N/A N/A 1 0

12 Coal Surge Bin w/ Vent Filter Dual outlet 190 tonne (200 ton) 2 0

13 Crusher Impactor 

reduction

8 cm x 0 - 3 cm x 0

(3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 370 tonne/hr (410 tph) 1 0

16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 370 tonne/hr (410 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide 

Gates Field erected 820 tonne (900 ton) 3 0

19 Activated Carbon Storage Silo and 

Feeder System

Shop 

assembled

Silo - 35 tonne (38 ton)

Feeder - 140 kg/hr (320 

lb/hr)

1 0

20 Hydrated Lime Storage Silo and 

Feeder System

Shop 

assembled

Silo - 240 tonne (260 ton)

Feeder - 4,980 kg/hr 

(10,990 lb/hr)

1 0

21 Limestone Truck Unloading Hopper N/A 30 tonne (40 ton) 1 0

22 Limestone Feeder Belt 90 tonne/hr (100 tph) 1 0

23 Limestone Conveyor No. L1 Belt 90 tonne/hr (100 tph) 1 0

24 Limestone Reclaim Hopper N/A 20 tonne (20 ton) 1 0

25 Limestone Reclaim Feeder Belt 70 tonne/hr (80 tph) 1 0

26 Limestone Conveyor No. L2 Belt 70 tonne/hr (80 tph) 1 0

27 Limestone Day Bin w/ actuator 290 tonne (320 ton) 2 0

Case B12B – Account 2: Coal and Sorbent Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Coal Feeder Gravimetric 40 tonne/hr (50 tph) 6 0

2 Coal Pulverizer Ball type or 

equivalent 40 tonne/hr (50 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 24 tonne/hr (27 tph) 1 1

4 Limestone Ball Mill Rotary 24 tonne/hr (27 tph) 1 1

5 Limestone Mill Slurry Tank 

with Agitator N/A 93,100 liters (25,000 gal) 1 1

6 Limestone Mill Recycle 

Pumps Horizontal centrifugal 1,570 lpm @ 10m H2O (410 gpm @ 40 ft H2O) 1 1

7 Hydroclone Classifier 4 active cyclones in a 

5 cyclone bank

390 lpm (100 gpm) 

per cyclone 1 1

8 Distribution Box 2-way N/A 1 1

9 Limestone Slurry Storage 

Tank with Agitator Field erected 528,000 liters (140,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1,100 lpm @ 9m H2O 

(290 gpm @ 30 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

150

Case B12B – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 265,000 liters (70,000 gal) 2 0

2 Condensate Pumps Vertical canned 17,300 lpm @ 200 m H2O 

(4,600 gpm @ 600 ft H2O) 1 1

3 Deaerator and Storage 

Tank Horizontal spray type

2,208,000 kg/hr 

(4,868,000 lb/hr), 

5 min. tank

1 0

4 Boiler Feed 

Pump/Turbine

Barrel type, multi-stage, 

centrifugal

37,000 lpm @ 3,500 m H2O 

(9,800 gpm @ 11,400 ft 

H2O)

1 1

5

Startup Boiler Feed 

Pump, Electric Motor 

Driven

Barrel type, multi-stage, 

centrifugal

11,000 lpm @ 3,500 m H2O 

(2,900 gpm @ 11,400 ft 

H2O)

1 0

6 LP Feedwater Heater 

1A/1B Horizontal U-tube 510,000 kg/hr (1,130,000 lb/hr) 2 0

7 LP Feedwater Heater 

2A/2B Horizontal U-tube 510,000 kg/hr (1,130,000 lb/hr) 2 0

8 LP Feedwater Heater 

3A/3B Horizontal U-tube 510,000 kg/hr (1,130,000 lb/hr) 2 0

9 LP Feedwater Heater 

4A/4B Horizontal U-tube 510,000 kg/hr (1,130,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 2,200,000 kg/hr 

(4,860,000 lb/hr) 1 0

11 HP Feedwater Heater 7 Horizontal U-tube 2,200,000 kg/hr 

(4,860,000 lb/hr) 1 0

12 HP Feedwater heater 8 Horizontal U-tube 2,200,000 kg/hr 

(4,860,000 lb/hr) 1 0

13 Auxiliary Boiler Shop fabricated, water 

tube

20,000 kg/hr, 2.8 MPa, 

343°C (40,000 lb/hr, 400 

psig, 650°F)

1 0

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

15 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa 

(1,000 scfm @ 100 psig) 2 1

16 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

17 Closed Cycle Cooling 

Heat Exchangers

Shell and tube 53 GJ/hr (50 MMBtu/hr) 

each 2 0

18 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 20,800 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

19 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 88 m H2O 

(1,000 gpm @ 290 ft H2O) 1 1

20 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 64 m H2O 

(700 gpm @ 210 ft H2O) 1 1

21 Raw Water Pumps Stainless steel, single 

suction

8,630 lpm @ 20 m H2O 

(2,280 gpm @ 60 ft H2O) 2 1

22 Ground Water Pumps Stainless steel, single 

suction

3,450 lpm @ 270 m H2O 

(910 gpm @ 880 ft H2O) 5 1

23 Filtered Water Pumps Stainless steel, single 

suction

2,080 lpm @ 50 m H2O 

(550 gpm @ 160 ft H2O) 2 1

24 Filtered Water Tank Vertical, cylindrical 1,999,000 liter (528,000 gal) 1 0

25 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly, 

electrodeionization unit

360 lpm (90 gpm) 1 1

26 Liquid Waste Treatment 

System -- 10 years, 24-hour storm 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

151

Case B12B – Account 4: Boiler and Accessories

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Boiler

Supercritical, drum, wallfired, low NOx burners, 

overfire air

2,200,000 kg/hr steam 

@ 25.5 MPa/602°C/602°C 

(4,860,000 lb/hr steam 

@ 3,700 psig/1,115°F/1,115°F)

1 0

2 Primary Air Fan Centrifugal

302,000 kg/hr, 4,100 m3/min 

@ 123 cm WG 

(666,000 lb/hr, 145,600 acfm 

@ 48 in. WG)

2 0

3 Forced Draft

Fan Centrifugal

984,000 kg/hr, 13,400 m3/min 

@ 47 cm WG 

(2,169,000 lb/hr, 474,100 acfm 

@ 19 in. WG)

2 0

4 Induced Draft 

Fan Centrifugal

1,419,000 kg/hr, 28,200 m3/min 

@ 89 cm WG 

(3,128,000 lb/hr, 994,100 acfm 

@ 35 in. WG)

2 0

5 SCR Reactor 

Vessel Space for spare layer 2,840,000 kg/hr (6,260,000 lb/hr) 2 0

6 SCR Catalyst -- -- 3 0

7 Dilution Air 

Blower Centrifugal 160 m3/min @ 108 cm WG (5,600 acfm @ 42 in. WG) 2 1

8 Ammonia 

Storage Horizontal tank 174,000 liter (46,000 gal) 5 0

9 Ammonia Feed 

Pump Centrifugal 33 lpm @ 90 m H2O (9 gpm @ 300 ft H2O) 2 1

Case B12B – Account 5A: Flue Gas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter

Single stage, high-ratio 

with pulse-jet online 

cleaning system

1,419,000 kg/hr (3,129,000 

lb/hr) 99.9% efficiency 2 0

2 Absorber Module Counter-current open 

spray

57,000 m3/min 

(1,999,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 197,000 lpm @ 65 m H2O 

(52,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal centrifugal 4,790 lpm (1,260 gpm) 

at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 100 m3/min @ 0.3 MPa 

(3,510 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units 

each

1,190 lpm (320 gpm) per 

cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 38 tonne/hr (42 tph) of 50 wt 

% slurry 2 1

9 Filtrate Water Return 

Pumps Horizontal centrifugal 730 lpm @ 13 m H2O (190 gpm @ 40 ft H2O) 1 1

10 Filtrate Water Return 

Storage Tank Vertical, lined 480,000 lpm (130,000 gal) 1 0

11 Process Makeup 

Water Pumps Horizontal centrifugal 3,820 lpm @ 21 m H2O (1,010 gpm @ 70 ft H2O) 1 1

12 Activated Carbon 

Injectors --- 140 kg/hr (320 lb/hr) 1 0

13 Hydrated Lime 

Injectors --- 4,980 kg/hr (10,990 lb/hr) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

152

Case B12B – Account 5B: Carbon Dioxide Recovery

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Cansolv Amine-based CO2

capture technology

1,494,000 kg/hr (3,294,000 lb/hr) 

19.6 wt % CO2 concentration 1 0

2

Cansolv LP 

Condensate 

Pump

Centrifugal 1,098 lpm @ 1 m H2O 

(290 gpm @ 4 ft H2O) 1 1

3

Cansolv HP 

Condensate 

Pump

Centrifugal 1,099 lpm @ 1.1 m H2O (290 gpm 

@ 4 ft H2O) 1 1

4 CO2 Dryer Triethylene glycol

Inlet: 127.0 m3/min (4,469 acfm) @ 

3.0 MPa (439 psia) Outlet: 2.9 MPa 

(419 psia) Water Recovered: 352 

kg/hr (776 lb/hr)

1 0

5 CO2 Compressor

Integrally geared, 

multi-stage 

centrifugal

264,163 kg/hr @ 15.3 MPa 

(582,381 lb/hr @ 2,215 psia) 2 0

Case B12B – Account 7: Ducting and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete 

with FRP liner

152 m (500 ft) high x

5.5 m (18 ft) diameter 1 0

Case B12B – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

675 MW

24.1 MPa/593°C/593°C (3500 psig/ 

1100°F/1100°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

750 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

2,050 GJ/hr 

(1,950 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

Case B12B – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 778,000 lpm @ 30 m(206,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

4340 GJ/hr (4110 MMBtu/hr) heat duty

1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

153

Case B12B – Account 10: Ash and Spent Sorbent Recovery and Handling

Equipmen

t No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of boiler scope 

of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of 

supply) -- -- 2 0

3 Clinker Grinder -- 4.8 tonne/hr (5.3 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of 

supply included with boiler) -- -- 6 0

5 Hydroejectors -- -- 12

6 Economizer /Pyrites Transfer Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, 

wet pit

190 lpm @ 17 m H2O 

(50 gpm @ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, 

wet pit

7,570 lpm @ 9 m H2O 

(2000 gpm @ 28 ft 

H2O)

1 1

9 Hydrobins -- 190 lpm (50 gpm) 1 1

10 Baghouse Hopper (part of baghouse 

scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of 

supply) -- -- 10 0

12 Air Blower -- 20 m3/min @ 0.2 MPa 

(790 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforce

d concrete 1,500 tonne (1,600 ton) 2 0

14 Slide Gate Valves -- -- 2 0

15 Unloader -- -- 1 0

16 Telescoping Unloading Chute -- 140 tonne/hr (150 tph) 1 0

Case B12B – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 

MVA, 3-ph, 60 Hz 1 0

2 High Voltage Transformer Oil-filled 345 kV/13.8 kV, 20 

MVA, 3-ph, 60 Hz 2 0

3 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 99 

MVA, 3-ph, 60 Hz 1 1

4 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 15 

MVA, 3-ph, 60 Hz 1 1

5 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

6 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

7 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

8 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B12B – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0
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3.3.10 Case B12B – Cost Estimating Basis

The cost estimating methodology was described previously in Section 2.7. Exhibit 3-64 shows a 

detailed breakdown of the capital costs; Exhibit 3-65 shows the owner’s costs, TOC, and TASC; 

Exhibit 3-66 shows the initial and annual O&M costs; and Exhibit 3-67 shows the COE 

breakdown. 

The estimated TPC of the SC PC boiler with CO2 capture is $3,524/kW. Process contingency 

represents 3.3 percent of the TPC and project contingency represents 12.2 percent. The COE, 

including CO2 T&S costs of $9.6/MWh, is $142.8/MWh.
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Exhibit 3-64 Case B12B total plant cost details

Case: B12B – Supercritical PC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,601 $0 $2,073 $0 $6,674 $667 $0 $1,101 $8,443 $15

1.2 Coal Stackout & Reclaim $5,946 $0 $1,329 $0 $7,275 $728 $0 $1,200 $9,203 $17

1.3 Coal Conveyors $5,529 $0 $1,315 $0 $6,843 $684 $0 $1,129 $8,657 $16

1.4 Other Coal Handling $1,446 $0 $304 $0 $1,751 $175 $0 $289 $2,215 $4

1.5 Sorbent Receive & Unload $184 $0 $55 $0 $239 $24 $0 $39 $302 $1

1.6 Sorbent Stackout & Reclaim $2,976 $0 $538 $0 $3,513 $351 $0 $580 $4,444 $8

1.7 Sorbent Conveyors $1,062 $231 $257 $0 $1,549 $155 $0 $256 $1,960 $4

1.8 Other Sorbent Handling $641 $151 $332 $0 $1,124 $112 $0 $185 $1,422 $3

1.9 Coal & Sorbent Hnd. Foundations $0 $5,333 $7,031 $0 $12,364 $1,236 $0 $2,040 $15,640 $28

Subtotal $22,386 $5,714 $13,233 $0 $41,333 $4,133 $0 $6,820 $52,286 $95

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $2,656 $0 $510 $0 $3,166 $317 $0 $522 $4,005 $7

2.2 Coal Conveyor to Storage $6,799 $0 $1,464 $0 $8,263 $826 $0 $1,363 $10,453 $19

2.5 Sorbent Prep Equipment $5,063 $219 $1,037 $0 $6,320 $632 $0 $1,043 $7,994 $15

2.6 Sorbent Storage & Feed $610 $0 $230 $0 $840 $84 $0 $139 $1,063 $2

2.9 Coal & Sorbent Feed Foundation $0 $618 $542 $0 $1,160 $116 $0 $191 $1,468 $3

Subtotal $15,128 $837 $3,784 $0 $19,749 $1,975 $0 $3,259 $24,983 $45

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $25,158 $0 $8,112 $0 $33,270 $3,327 $0 $5,489 $42,086 $76

3.2 Water Makeup & Pretreating $7,114 $0 $2,250 $0 $9,365 $936 $0 $2,060 $12,361 $22

3.3 Other Feedwater Subsystems $7,914 $0 $3,249 $0 $11,163 $1,116 $0 $1,842 $14,121 $26

3.4 Service Water Systems $1,425 $0 $746 $0 $2,170 $217 $0 $477 $2,865 $5

3.5 Other Boiler Plant Systems $9,820 $0 $9,284 $0 $19,103 $1,910 $0 $3,152 $24,166 $44

3.6 FO Supply Sys & Nat Gas $347 $0 $405 $0 $752 $75 $0 $124 $951 $2

3.7 Waste Treatment Equipment $4,667 $0 $2,702 $0 $7,369 $737 $0 $1,621 $9,727 $18

3.8 Misc. Equip. (Cranes, Air Comp., 

Comm.) $3,398 $0 $1,051 $0 $4,449 $445 $0 $979 $5,873 $11

Subtotal $59,843 $0 $27,798 $0 $87,641 $8,764 $0 $15,745 $112,150 $204

4 Boiler & Accessories

4.1 PC Boiler & Accessories $211,004 $0 $120,229 $0 $331,234 $33,123 $0 $36,436 $400,793 $728

4.2 SCR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0

Subtotal $211,004 $0 $120,229 $0 $331,234 $33,123 $0 $36,436 $400,793 $728

5A Gas Cleanup & Piping

5A.1 Absorber Vessels & Accessories $79,487 $0 $16,995 $0 $96,482 $9,648 $0 $10,613 $116,743 $212

5A.2 Other FGD $4,148 $0 $4,668 $0 $8,816 $882 $0 $970 $10,668 $19
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Case: B12B – Supercritical PC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.3 Bag House & Accessories $22,779 $0 $14,358 $0 $37,137 $3,714 $0 $4,085 $44,936 $82

5A.4 Other Particulate Removal Materials $1,542 $0 $1,638 $0 $3,180 $318 $0 $350 $3,848 $7

5A.5 Gypsum Dewatering System $6,185 $0 $1,043 $0 $7,229 $723 $0 $795 $8,747 $16

5A.6 Mercury Removal System $4,702 $1,034 $4,623 $0 $10,359 $1,036 $0 $1,139 $12,534 $23

Subtotal $118,843 $1,034 $43,325 $0 $163,202 $16,320 $0 $17,952 $197,475 $359

5B CO2 Removal & Compression

5B.1 CO2 Removal System $167,289 $61,389 $131,144 $0 $359,822 $31,060 $62,120 $80,756 $533,757 $970

5B.2 CO2 Compression & Drying $50,211 $7,532 $16,788 $0 $74,531 $7,453 $0 $16,397 $98,381 $179

Subtotal $217,500 $68,921 $147,932 $0 $434,354 $38,513 $62,120 $97,152 $632,139 $1,149

7 HRSG, Ducting, & Stack

7.3 Ductwork $11,042 $0 $6,970 $0 $18,013 $1,801 $0 $2,972 $22,786 $41

7.4 Stack $9,983 $0 $5,801 $0 $15,784 $1,578 $0 $1,736 $19,099 $35

7.9 Duct & Stack Foundations $0 $1,088 $1,292 $0 $2,380 $238 $0 $524 $3,142 $6

Subtotal $21,025 $1,088 $14,064 $0 $36,177 $3,618 $0 $5,232 $45,027 $82

8 Steam Turbine Generator

8.1 Steam TG & Accessories $79,100 $0 $8,815 $0 $87,915 $8,791 $0 $9,671 $106,377 $193

8.2 Turbine Plant Auxiliaries $450 $0 $958 $0 $1,408 $141 $0 $155 $1,704 $3

8.3 Condenser & Auxiliaries $6,997 $0 $2,374 $0 $9,370 $937 $0 $1,031 $11,338 $21

8.4 Steam Piping $30,410 $0 $12,325 $0 $42,735 $4,273 $0 $7,051 $54,060 $98

8.9 TG Foundations $0 $1,342 $2,217 $0 $3,559 $356 $0 $783 $4,698 $9

Subtotal $116,957 $1,342 $26,688 $0 $144,987 $14,499 $0 $18,690 $178,176 $324

9 Cooling Water System

9.1 Cooling Towers $15,466 $0 $4,783 $0 $20,250 $2,025 $0 $2,227 $24,502 $45

9.2 Circulating Water Pumps $3,102 $0 $228 $0 $3,330 $333 $0 $366 $4,030 $7

9.3 Circ. Water System Auxiliaries $811 $0 $107 $0 $918 $92 $0 $101 $1,111 $2

9.4 Circ. Water Piping $0 $6,831 $6,186 $0 $13,016 $1,302 $0 $2,148 $16,466 $30

9.5 Make-up Water System $685 $0 $880 $0 $1,565 $157 $0 $258 $1,980 $4

9.6 Component Cooling Water Sys. $661 $0 $507 $0 $1,168 $117 $0 $193 $1,478 $3

9.9 Circ. Water Foundations & Structures $0 $3,613 $5,999 $0 $9,612 $961 $0 $2,115 $12,688 $23

Subtotal $20,725 $10,443 $18,691 $0 $49,860 $4,986 $0 $7,408 $62,254 $113

10 Ash & Spent Sorbent Handling Systems

10.6 Ash Storage Silos $882 $0 $2,698 $0 $3,579 $358 $0 $394 $4,331 $8

10.7 Ash Transport & Feed Equipment $5,856 $0 $5,806 $0 $11,662 $1,166 $0 $1,283 $14,111 $26

10.9 Ash/Spent Sorbent Foundation $0 $199 $245 $0 $444 $44 $0 $98 $586 $1

Subtotal $6,738 $199 $8,748 $0 $15,685 $1,569 $0 $1,774 $19,028 $35

11 Accessory Electric Plant

11.1 Generator Equipment $2,061 $0 $329 $0 $2,390 $239 $0 $197 $2,826 $5

11.2 Station Service Equipment $5,290 $0 $1,773 $0 $7,063 $706 $0 $583 $8,352 $15

11.3 Switchgear & Motor Control $6,072 $0 $1,055 $0 $7,126 $713 $0 $784 $8,623 $16

11.4 Conduit & Cable Tray $0 $4,164 $13,452 $0 $17,616 $1,762 $0 $2,907 $22,284 $41

11.5 Wire & Cable $0 $7,928 $14,171 $0 $22,100 $2,210 $0 $3,646 $27,956 $51

11.6 Protective Equipment $306 $0 $1,063 $0 $1,370 $137 $0 $151 $1,658 $3
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Case: B12B – Supercritical PC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 550 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11.7 Standby Equipment $1,571 $0 $37 $0 $1,608 $161 $0 $177 $1,945 $4

11.8 Main Power Transformers $14,769 $0 $221 $0 $14,990 $1,499 $0 $1,649 $18,138 $33

11.9 Electrical Foundations $0 $385 $980 $0 $1,365 $136 $0 $300 $1,802 $3

Subtotal $30,069 $12,477 $33,082 $0 $75,628 $7,563 $0 $10,394 $93,584 $170

12 Instrumentation & Control

12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $611 $0 $373 $0 $984 $98 $49 $170 $1,301 $2

12.7 Distributed Control Sys. Equipment $6,164 $0 $1,099 $0 $7,263 $726 $363 $835 $9,188 $17

12.8 Instrument Wiring & Tubing $3,717 $0 $6,763 $0 $10,480 $1,048 $524 $1,808 $13,860 $25

12.9 Other I & C Equipment $1,742 $0 $4,033 $0 $5,775 $577 $289 $664 $7,305 $13

Subtotal $12,233 $0 $12,269 $0 $24,502 $2,450 $1,225 $3,477 $31,654 $58

13 Improvements to Site

13.1 Site Preparation $0 $62 $1,316 $0 $1,378 $138 $0 $303 $1,819 $3

13.2 Site Improvements $0 $2,053 $2,713 $0 $4,766 $477 $0 $1,049 $6,291 $11

13.3 Site Facilities $3,680 $0 $3,860 $0 $7,540 $754 $0 $1,659 $9,953 $18

Subtotal $3,680 $2,115 $7,889 $0 $13,684 $1,368 $0 $3,010 $18,063 $33

14 Buildings & Structures

14.1 Boiler Building $0 $10,432 $9,168 $0 $19,599 $1,960 $0 $3,234 $24,793 $45

14.2 Turbine Building $0 $15,048 $14,015 $0 $29,063 $2,906 $0 $4,795 $36,765 $67

14.3 Administration Building $0 $762 $806 $0 $1,568 $157 $0 $259 $1,984 $4

14.4 Circulation Water Pumphouse $0 $208 $165 $0 $373 $37 $0 $62 $472 $1

14.5 Water Treatment Buildings $0 $887 $808 $0 $1,696 $170 $0 $280 $2,145 $4

14.6 Machine Shop $0 $510 $342 $0 $852 $85 $0 $141 $1,078 $2

14.7 Warehouse $0 $346 $346 $0 $692 $69 $0 $114 $875 $2

14.8 Other Buildings & Structures $0 $282 $240 $0 $523 $52 $0 $86 $661 $1

14.9 Waste Treating Building & Str. $0 $541 $1,639 $0 $2,180 $218 $0 $360 $2,758 $5

Subtotal $0 $29,016 $27,530 $0 $56,547 $5,655 $0 $9,330 $71,531 $130

Total $856,131 $133,187 $505,263 $0 $1,494,582 $144,536 $63,345 $236,680 $1,939,143 $3,524
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Exhibit 3-65 Case B12B owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $12,156 $22

1 Month Maintenance Materials $1,774 $3

1 Month Non-fuel Consumables $3,605 $7

1 Month Waste Disposal $539 $1

25% of 1 Months Fuel Cost at 100% CF $3,099 $6

2% of TPC $38,783 $70

Total $59,957 $109

Inventory Capital

60 day supply of fuel and consumables at 100% CF $31,429 $57

0.5% of TPC (spare parts) $9,696 $18

Total $41,125 $75

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $900 $2

Other Owner's Costs $290,871 $529

Financing Costs $52,357 $95

Total Overnight Costs (TOC) $2,384,352 $4,333

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,718,161 $4,940
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Exhibit 3-66 Case B12B initial and annual operating and maintenance costs

Case: B12B – Supercritical PC w/o CO2 Cost Base: Jun 2011

Plant Size (MW,net): 550 Heat Rate-net (Btu/kWh): 10,508 Capacity Factor (%): 85

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 11.3 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 2.0 

Total: 16.3 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $7,384,208 $13.421

Maintenance Labor: $12,065,150 $21.928

Administrative & Support Labor: $4,862,340 $8.837

Property Taxes and Insurance: $38,782,850 $70.487

Total: $63,094,548 $114.673

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $18,097,725 $4.41742

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 5,675 $1.67 $0 $2,947,503 $0.71945

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 27,472 $0.27 $0 $2,282,848 $0.55721

Limestone (ton) 0 588 $33.48 $0 $6,103,937 $1.48989

Hydrated Lime (ton) 0 120 $155.00 $0 $5,763,495 $1.40679

Activated Carbon (ton) 0 3 $1,255.00 $0 $1,347,742 $0.32897

CO2 Capture System ChemicalsA Proprietary

Triethylene Glycol (gal) 0 394 $6.57 $0 $802,687 $0.19593

Ammonia (19% NH3, ton) 0 87 $330.00 $0 $8,943,423 $2.18297

SCR Catalyst (m3) 0 0.39 $8,938.80 $0 $1,092,946 $0.26677

Subtotal: $0 $36,775,427 $8.97641

Waste Disposal

Fly Ash (ton) 0 589 $25.11 $0 $4,590,762 $1.12055

Bottom Ash (ton) 0 116 $25.11 $0 $903,048 $0.22042

Amine Purification Unit Waste (ton) 0 20 $0.00 $0 $0 $0.00000

Thermal Reclaimer Unit Waste (ton) 0 2 $0.00 $0 $0 $0.00000

Prescrubber Blowdown Waste (ton) 0 45 $0.00 $0 $0 $0.00000

 Subtotal: $0 $5,493,809 $1.34097

By-Products

Gypsum (ton) 0 101 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $60,366,961 $14.73480

Fuel Cost

Illinois Number 6 (ton): 0 5,947 $68.54 $0 $126,458,921 $30.86699

Total: $0 $126,458,921 $30.86699

ACO2 Capture System Chemicals includes Ion Exchange Resin, NaOH, and Cansolv Solvent.

Exhibit 3-67 Case B12B COE breakdown

Component Value, $/MWh Percentage

Capital 72.2 51%

Fixed 15.4 11%

Variable 14.7 10%

Fuel 30.9 22%

Total (Excluding T&S) 133.2 N/A

CO2 T&S 9.6 7%

Total (Including T&S) 142.8 N/A
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3.4 PC Case Summary

The performance results of the four PC plant configurations are summarized in Exhibit 3-68.

Exhibit 3-68 Estimated performance and cost results for PC cases

Pulverized Coal Boiler

PC Subcritical PC Supercritical

Case B11A Case B11B Case B12A Case B12B

PERFORMANCE

Nominal CO2 Capture 0% 90% 0% 90%

Capacity Factor 85% 85% 85% 85%

Gross Power Output (MWe) 581 644 580 642

Auxiliary Power Requirement (MWe) 31 94 30 91

Net Power Output (MWe) 550 550 550 550

Coal Flow rate (lb/hr) 412,005 516,170 395,053 495,578

Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A

HHV Thermal Input (kWt) 1,408,630 1,764,768 1,350,672 1,694,366

Net Plant HHV Efficiency (%) 39.0% 31.2% 40.7% 32.5%

Net Plant HHV Heat Rate (Btu/kWh) 8,740 10,953 8,379 10,508

Raw Water Withdrawal, gpm 5,538 8,441 5,105 7,882

Process Water Discharge, gpm 1,137 1,920 1,059 1,813

Raw Water Consumption, gpm 4,401 6,521 4,045 6,069

CO2 Emissions (lb/MMBtu) 204 20 204 20

CO2 Emissions (lb/MWh-gross) 1,683 190 1,618 183

CO2 Emissions (lb/MWh-net) 1,779 223 1,705 214

SO2 Emissions (lb/MMBtu) 0.085 0.000 0.085 0.000

SO2 Emissions (lb/MWh-gross) 0.700 0.000 0.673 0.000

NOx Emissions (lb/MMBtu) 0.085 0.075 0.088 0.078

NOx Emissions (lb/MWh-gross) 0.700 0.700 0.700 0.700

PM Emissions (lb/MMBtu) 0.011 0.010 0.011 0.010

PM Emissions (lb/MWh-gross) 0.090 0.090 0.090 0.090

Hg Emissions (lb/TBtu) 0.363 0.321 0.377 0.333

Hg Emissions (lb/MWh-gross) 3.00E-06 3.00E-06 3.00E-06 3.00E-06

COST

Total Plant Cost (2011$/kW) 1,960 3,467 2,026 3,524

Bare Erected Cost 1,582 2,665 1,646 2,716

Home Office Expenses 158 257 165 263

Project Contingency 220 427 216 430

Process Contingency 0 118 0 115

Total Overnight Cost (2011$/MM) 1,336 2,346 1,379 2,384

Total Overnight Cost (2011$/kW) 2,429 4,267 2,507 4,333

Owner's Costs 469 800 480 809

Total As-Spent Cost (2011$/kW) 2,755 4,865 2,842 4,940

COE ($/MWh) (excluding T&S) 82.1 133.5 82.3 133.2

Capital Costs 37.8 71.1 39.0 72.2

Fixed Costs 9.3 15.1 9.6 15.4

Variable Costs 9.2 15.1 9.1 14.7

Fuel Costs 25.7 32.2 24.6 30.9

COE ($/MWh) (including T&S) 82.1 143.5 82.3 142.8

CO2 T&S Costs 0.0 10.0 0.0 9.6
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The following observations can be made regarding plant performance:

• The addition of CO2 capture and compression to the two PC cases results in an efficiency 

penalty of 7.8 absolute percent in the subcritical PC case and 8.2 absolute percent in the 

SC PC case. The efficiency is negatively impacted by the large auxiliary loads of the 

capture process and CO2 compression, as well as the large increase in cooling water 

requirement, which increases the CWP and cooling tower fan auxiliary loads. The 

auxiliary load increases by 63 MW in the subcritical PC case and by 62 MW in the SC 

PC case.

• Since the PC cases utilized a wet FGD system, SO2 emissions could be used as a 

surrogate for HCl (17). Provided the SO2 emissions limit is not exceeded, it can be 

assumed per the MATS regulation that the HCl emissions limit is also satisfied.

• The SO2 emissions for non-capture cases are nearly identical, with the subcritical PC 

emissions being higher than SC when normalized by gross output because of the lower 

efficiency. The CO2 capture process polishing scrubber and absorber vessel result in 

negligible SO2 emissions in CO2 capture cases.

• Uncontrolled CO2 emissions on a mass basis are greater for subcritical PC compared to 

SC because of the lower efficiency. The capture cases result in a 90 percent reduction of 

carbon for both subcritical and SC PC.

The components of TOC and overall TASC are shown for each PC case in Exhibit 3-69.
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Exhibit 3-69 Plant capital cost for PC cases

Source: NETL

The following observations about TOC can be made:

• The TOC of the non-capture SC PC case is approximately 3.2 percent greater than noncapture subcritical PC. The TOC of SC PC with CO2 capture is approximately 1.6 

percent greater than subcritical PC with CO2 capture.

• The TOC penalty for adding CO2 capture in the subcritical case is 76 percent and is 73

percent in the SC case. In addition to the high cost of the capture process, there is a 

significant increase in the cost of the cooling towers and CWPs in the CO2 capture cases 

because of the larger cooling water demand discussed previously. Also, the gross output 

of the two PC plants increases by 63 MW (subcritical) and 62 MW (SC) to maintain the 

net output at 550 MW. The increased gross output results in higher coal flow rate and 

consequently higher costs for all cost accounts in the estimate.

The COE is shown for the four PC cases in Exhibit 3-70 (including T&S in the capture cases). 
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Exhibit 3-70 COE for PC cases

Source: NETL

*Cases without capture use conventional financing; all others use high-risk financial asssumptions 

consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant 

Performance.” (1)

The following observations can be made:

• Capital costs represent the largest fraction of COE in all cases, but particularly so in the 

CO2 capture cases. Fuel cost is the second largest component of COE, and capital 

charges and fuel costs combined represent 72 to 77 percent of the total in all cases.

• In the non-capture cases, the slight increase in capital cost in the SC case is almost offset 

by the efficiency gain so that the COE for SC PC is only approximately 0.3 percent more 

than subcritical despite having more than a 3 percent greater TOC.

• In the CO2 capture cases, the increase in capital is even lower than in the non-capture 

case and is more than offset by the efficiency gain so that the COE for SC PC is 

approximately 0.2 percent lower than the subcritical case, despite having a TOC that is 

nearly 2 percent greater. The COE of the non-capture subcritical PC case and the noncapture SC PC case is well within the limits of the study accuracy. The same is true of 

the two CO2 capture cases.

The sensitivity of COE to capacity factor is shown in Exhibit 3-71. Implicit in the curves is the 

assumption that a capacity factor of greater than 85 percent can be achieved without the 

expenditure of additional capital. The subcritical and SC cases are nearly identical making it 

difficult to distinguish between the two lines. The COE increases slightly more rapidly at low 

CF because the relatively high capital component is spread over fewer kilowatt-hours of 

generation.
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Exhibit 3-71 Sensitivity of COE to capacity factor for PC cases

Source: NETL

COE is relatively insensitive to fuel costs for the PC cases, as shown in Exhibit 3-72. A tripling 

of coal price from $1-$3/MMBtu results in an approximate COE increase of about 26 percent in 

the non-capture cases and 18 percent in the CO2 capture cases.

Exhibit 3-72 Sensitivity of COE to coal price for PC cases

Source: NETL
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As presented in Section 2.7.4 the CO2 captured and avoided costs were calculated and the results 

for the PC CO2 capture cases – using SC PC as the non-capture reference case – are shown in 

Exhibit 3-73. The costs are nearly identical for the subcritical and SC PC cases.

Exhibit 3-73 Cost of CO2 captured and avoided in PC cases

Source: NETL

The normalized water withdrawal, process discharge and raw water consumption are shown 

in Exhibit 3-74 for each of the PC cases. 
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Exhibit 3-74 Raw water withdrawal and consumption in PC cases

Source: NETL

Raw water consumption for all cases is dominated by cooling tower makeup requirements, which 

accounts for about 81 percent of raw water in non-capture cases and 85 percent of raw water in 

CO2 capture cases. The amount of raw water consumption in the CO2 capture cases is greatly 

increased by the cooling water requirements of the capture process. Cooling water is required to:

o Reduce the flue gas temperature from 56°C (133°F) (FGD exit temperature) to 

30°C (86°F) (CO2 absorber operating temperature), which also requires 

condensing water from the flue gas that comes saturated from the FGD unit

o Remove the heat input by the stripping steam to cool the solvent

o Remove the heat input from the auxiliary electric loads

o Remove heat in the CO2 compressor intercoolers

In the CO2 capture cases, additional water is recovered from the flue gas as it is cooled to the 

absorber temperature. The condensate is treated and used as cooling tower makeup.
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4 Natural Gas Combined Cycle Plants

Two NGCC power plant configurations were evaluated and are presented in this section. Each 

design is based on a market-ready technology that is assumed to be commercially available in 

time to support start-up. Each design consists of two state-of-the-art 2013 F-class CTGs, two 

HRSGs, and one STG in a multi-shaft 2x2x1 configuration. 

The NGCC cases are evaluated with and without CO2 capture on a common thermal input basis. 

The NGCC designs that include CDR have a smaller plant net output resulting from the 

additional CDR facility and CO2 compressors auxiliary loads. The gross output of the NGCC 

cases was largely determined by the output of the commercially available CT. Hence, evaluation 

of the two NGCC designs on a common net output basis was not possible. 

The Rankine cycle portion of both designs uses a single reheat 16.5 MPa/566°C/566°C 

(2,400 psig/1,050°F/1,050°F) steam cycle. A more aggressive steam cycle was considered but 

not chosen because there are very few HRSGs in operation that would support such conditions.

(28)

4.1 NGCC Process Areas

The two NGCC cases are nearly identical in configuration with the exception that Case B31B 

includes CO2 capture while Case B31A does not. The process areas that are common to the two 

plant configurations are presented in this section.

4.1.1 Natural Gas Supply System

It was assumed that a natural gas main with adequate capacity is in close proximity (within 16 

km [10 mi]) to the site fence line and that a suitable right-of-way is available to install a branch 

line to the site. For the purposes of this report it was also assumed that the gas will be delivered 

to the plant custody transfer point at 3.0 MPa (435 psig) and 38°C (100oF), which matches the 

state-of-the-art 2013 F-class fuel system requirements. Hence, neither a pressure reducing 

station with gas preheating (to prevent moisture and hydrocarbon condensation), nor a fuel 

booster compressor is required.

As discussed in Section 2.4.2, it was assumed that the natural gas had an added mercaptan 

composition of 5.75x10-6 mol%. (11)

A new gas metering station is assumed to be added on the site, adjacent to the new CT. The 

meter may be of the rate-of-flow type, with input to the plant computer for summing and 

recording, or may be of the positive displacement type. In either case, a complete timeline 

record of gas consumption rates and cumulative consumption is provided.

4.1.2 Combustion Turbine

The combined cycle plant is based on two CTGs. The CTG is representative of the state-of-theart 2013 F-class turbines with an ISO base rating of 211 MW when firing natural gas (18). This 

machine is an axial flow, single spool, constant speed unit, with variable IGVs, and dry LNB 

combustion system.

Each CTG is provided with inlet air filtration systems, inlet silencers, lube and control oil 

systems including cooling, electric motor starting systems, acoustical enclosures including 
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heating and ventilation, control systems including supervisory, fire protection, and fuel systems. 

No back up fuel was envisioned for these cases.

The CTG is typically supplied in several fully shop-fabricated modules, complete with all 

mechanical, electrical, and control systems required for CTG operation. Site CTG installation 

involves module interconnection and linking CTG modules to the plant systems. The CTG 

package scope of supply for combined cycle application, while project specific, does not vary 

much from project-to-project. A typical scope of supply is presented in Exhibit 4-1.

Exhibit 4-1 Combustion turbine typical scope of supply

System System Scope

ENGINE 

ASSEMBLY

Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, 

Insulation Blankets, Platforms, Stairs and Ladders

Engine Assembly 

with Bedplate

Variable Inlet Guide Vane System, Compressor, Bleed System, Purge Air System, 

Bearing Seal Air System, Combustors, Dual Fuel Nozzles, Turbine Rotor Cooler

Walk-in acoustical 

enclosure HVAC, Lighting, and LP CO2 Fire Protection System

MECHANICAL 

PACKAGE

HVAC, Lighting, Air Compressor for Pneumatic System, LP CO2 Fire Protection 

System

Lubricating Oil 

System and 

Control Oil System

Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps, DC Emergency 

Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Filter, Oil Temperature and 

Pressure Control Valves, Oil Vapor Exhaust Fans and Demister, Oil Heaters, Oil 

Interconnect Piping (SS and CS), Oil System Instrumentation, Oil for Flushing and 

First Filling

ELECTRICAL 

PACKAGE

HVAC, Lighting, AC and DC Motor Control Centers, Generator Voltage Regulating 

Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, Battery 

Charger, Digital Control System with Local Control Panel (all control and 

monitoring functions as well as data logger and sequence of events recorder), 

Control System Valves and Instrumentation Communication link for interface with 

plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, LP 

CO2 Fire Protection System, Cable Tray and Conduit Provisions for Performance 

Testing including Test Ports, Thermowells, Instrumentation and DCS interface 

cards

INLET AND 

EXHAUST 

SYSTEMS

Inlet Duct Trash Screens, Inlet Duct and Silencers, Self-Cleaning Filters, Hoist 

System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct 

Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and 

Temperature Ports and Instrumentation

FUEL SYSTEMS

NG System Gas Valves Including Vent, Throttle and Trip Valves, Gas Filter/Separator, Gas 

Supply Instruments and Instrument Panel

STARTING 

SYSTEM

Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch 

Assembly, Starting Clutch, Torque Converter

GENERATOR

Static or Rotating Exciter (Excitation transformer to be included for a static 

system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge 

Capacitors, Neutral Cubicle with CT, Neutral Tie Bus, Grounding Transformer, and 

Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming 

Tank, Reservoir, Seal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, and 

Oil Mist Eliminator), Generator Auxiliaries Control Enclosure, Generator Breaker, 

Iso-Phase bus connecting generator and breaker, Grounding System Connectors

Generator Cooling 

Totally Enclosed Water-to-Air-Cooled (TEWAC) System (including circulation 

system, interconnecting piping and controls), or Hydrogen Cooling System 

(including H2 to Glycol and Glycol to Air heat exchangers, liquid level detector 

circulation system, interconnecting piping and controls)

MISCELLANEOUS

Interconnecting Pipe, Wire, Tubing and Cable Instrument Air System Including Air 

Dryer On Line and Off Line Water Wash System LP CO2 Storage Tank Drain 

System Drain Tanks Coupling, Coupling Cover and Associated Hardware
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Electrical generators are provided with the CT package. The generators are assumed to be 

24 kV, 3-phase, 60 Hz, constructed to meet American National Standards Institute (ANSI) and 

National Electrical Manufacturers Association (NEMA) standards for turbine-driven 

synchronous generators. The generator is TEWAC, complete with excitation system, cooling, 

and protective relaying.

4.1.3 Heat Recovery Steam Generator

The HRSG is configured with HP, IP, and LP steam drums, and superheater, reheater, and 

economizer sections. The HP drum is supplied with FW by the HP boiler feed pump to generate 

HP steam, which passes to the superheater section for heating to 566°C (1,050°F). The IP drum 

is supplied with FW by the IP boiler feed pump. The IP steam from the drum is superheated to 

482°C (900°F) and mixed the HP turbine exhaust before being reheated to 566°C (1,050oF). The 

combined flows are admitted into the IP section of the steam turbine. The LP drum provides 

steam to the LP turbine.

The economizer sections heat condensate and FW (in separate tube bundles). The HRSG tubes 

are typically comprised of bare surface and/or finned tubing or pipe material. The hightemperature portions are type P91 or P22 ferritic alloy material; the low-temperature portions 

(less than 399°C [750°F]) are carbon steel (CS). Each HRSG exhausts directly to the stack, 

which is fabricated from CS plate materials and lined with Type 409 SS. The stack for the 

NGCC cases is assumed to be 46 m (150 ft) high, and the cost is included in the HRSG account.

4.1.4 NOx Control System

Two measures are taken to reduce the NOx. The first is a DLN burner in the CTG. The DLN 

burners are a low NOx design and reduce the emissions to about 9 ppmvd (18) (assumed to be 

approximately 98 percent NO and referenced to 15 percent O2).

While a state-of-the-art 2013 F-class CT alone produces NOx emissions below the limits 

described in Section 2.4.2, an SCR was included as a second measure to ensure the plant met the 

EPA’s PSD program by installing the BACT.

A SCR uses ammonia and a catalyst to reduce NO to N2 and H2O. The SCR system consists of a 

reactor, and ammonia supply and storage system. The SCR system is designed for 90 percent 

reduction while firing natural gas (19). 

Operation Description - The SCR reactor is located in the flue gas path inside the HRSG 

between the HP and IP sections. The SCR reactor is equipped with one catalyst layer consisting 

of catalyst modules stacked in line on a supporting structural frame. The SCR reactor has space 

for installation of an additional layer. Ammonia is injected into the gas immediately prior to 

entering the SCR reactor. The ammonia injection grid is arranged into several sections, and 

consists of multiple pipes with nozzles. The ammonia flow rate into each injection grid section 

is controlled taking into account imbalances in the flue gas flow distribution across the HRSG. 

The catalyst contained in the reactor enhances the reaction between the ammonia and the NOx in 

the gas. The catalyst consists of various active materials such as titanium dioxide, vanadium 

pentoxide, and tungsten trioxide. The optimum inlet flue gas temperature range for the catalyst 

is 260°C (500°F) to 343°C (650°F). 

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, 

vaporizers, and dilution air skid.
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4.1.5 Carbon Dioxide Recovery Facility

A CDR facility is used in Case B31B to remove 90 percent of the CO2 in the flue gas exiting the 

HRSG, purify it, and compress it to a SC condition. It is assumed that all of the carbon in the 

natural gas is converted to CO2. The CDR is comprised of flue gas supply, CO2 absorption, 

solvent stripping and reclaiming, and CO2 compression and drying.

The CO2 absorption/stripping/solvent reclaimation process for Case B31B is based on the 

Cansolv system, previously described in Section 3.1.8, with the exception that no SO2 polishing 

step is required in the NGCC case, as the pipeline natural gas sulfur content produces a flue gas 

with an SO2 content below the concentration in the outlet of the polishing scrubber used in the 

PC cases. 

Any potential advantage that the natural gas case with CO2 capture would have over the coal 

cases with CO2 capture due to the significantly lower rate of chloride present in the feedstock 

(which forms HSS in the CO2 absorber) and SO2 and NOx gases in the flue gas (which 

contribute to amine degradation) is minimal as the prescrubber included in the coal cases 

removes the majority of these contaminants.

Due to the larger volumetric flow rate in the NGCC case compared to the PC cases (147 million 

ft3

/hr in Case B31B and 90 million ft3/hr in Case B12B) and the low CO2 concentration (4.9 

mol% in Case B31B and 12.9 mol% in Case B12B), the natural gas case requires a CO2 absorber 

over 1.5 times as large as the coal cases. However, as a result of the lower CO2 content, the CO2

stripper used in Case B31B is only 40 percent of the volume as the one used in Case B12B. 

4.1.6 Steam Turbine

The steam turbine consists of an HP section, an IP section, and a double-flow LP section, all 

connected to the generator by a common shaft. The HP and IP sections are contained in a single 

span, opposed-flow casing, with the double-flow LP section in a separate casing. 

Main steam from the boiler passes through the stop valves and control valves and enters the 

turbine at 16.5 MPa/566°C (2,400 psig/1,050°F). The steam initially enters the turbine near the 

middle of the HP span, flows through the turbine, and is combined with steam from the IP 

superheater before being returned to the HRSG for reheating. The reheat steam flows through 

the reheat stop valves and intercept valves and enters the IP section at 4.2 MPa/566°C 

(608 psia/1,050°F). After passing through the IP section, the steam enters a cross-over pipe, 

which transports the steam to the LP section. A branch line equipped with combined 

stop/intercept valves conveys LP steam from the HRSG LP drum to a tie-in at the cross-over 

line. The steam divides into two paths and flows through the LP sections exhausting downward 

into the condenser.

Turbine bearings are lubricated by a CL, water-cooled pressurized oil system. Turbine shafts are 

sealed against air in-leakage or steam blowout using a modern positive pressure variable 

clearance shaft sealing design arrangement connected to a LP steam seal system. The open-aircooled generator produces power at 24 kV. A static, transformer type exciter is provided. The 

STG is controlled by a triple-redundant microprocessor-based electro-hydraulic control system. 

The system provides digital control of the unit in accordance with programmed control 

algorithms, color monitor/operator interfacing, and datalink interfaces to the balance-of-plant 

DCS, and incorporates on-line repair capability.
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4.1.7 Water and Steam Systems

4.1.7.1 Condensate

The function of the condensate system is to pump condensate from the condenser hotwell to the 

deaerator, through the gland steam condenser; and the low-temperature economizer section in the 

HRSG.

The system consists of one main condenser; two 50 percent capacity, motor-driven vertical 

multistage condensate pumps (total of two pumps for the plant); one gland steam condenser; 

condenser air removal vacuum pumps, condensate polisher, and a low-temperature tube bundle 

in the HRSG.

Condensate is delivered to a common discharge 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 to maintain minimum flow requirements for the gland 

steam condenser and the condensate pumps.

4.1.7.2 Feedwater

The function of the feedwater (FW) system is to pump the various FW streams from the 

deaerator storage tank in the HRSG to the respective steam drums. One 100 percent capacity 

motor-driven feed pump is provided per each HRSG (total of two pumps for the plant). The FW 

pumps are equipped with an interstage takeoff to provide IP and LP FW. Each pump is provided 

with inlet and outlet isolation valves, outlet check valves, and individual minimum flow 

recirculation lines discharging back to the deaerator storage tank. The recirculation flow is 

controlled by pneumatic flow control valves. In addition, the suctions of the boiler feed pumps 

are equipped with startup strainers, which are utilized during initial startup and following major 

outages or system maintenance.

4.1.7.3 Steam System

Main, intermediate, and low pressure steam exits the HRSG superheater section through motoroperated stop/check valves and motor-operated gate valves. The main steam is routed to the HP 

turbine stop valve. The intermediate steam is combined with the HP turbine exhaust and is 

conveyed through a motor-operated isolation gate valve to the HRSG reheater and from the 

HRSG reheater outlet through a motor-operated gate valve to the IP turbines. The low pressure 

steam is combined with the IP turbine exhaust and is conveyed through a motor-operated 

isolation gate valve to the LP turbines. 

4.1.7.4 Circulating Water System

The function of the CWS is to supply cooling water to condense the main turbine exhaust steam, 

for the auxiliary cooling system, and for the CDR facility in Case B31B. The system consists of 

two 50 percent capacity vertical CWPs (total of two pumps for the plant), a mechanical draft 

evaporative cooling tower, and interconnecting piping. The condenser is a single pass, 

horizontal type with divided water boxes. There are two separate circulating water circuits in 

each box. One-half of the condenser can be removed from service for cleaning or plugging 

tubes. This can be done during normal operation at reduced load. 
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The auxiliary cooling system is a CL system. Plate and frame heat exchangers with circulating 

water as the cooling medium are provided. The system provides cooling water to the following 

systems:

1. CTG lube oil coolers

2. CTG air coolers

3. STG lube oil coolers

4. STG hydrogen coolers

5. Boiler feed water pumps 

6. Air compressors

7. Generator seal oil coolers (as applicable)

8. Sample room chillers

9. Blowdown coolers

10. Condensate extraction pump-motor coolers

The CDR system in Case B31B requires a substantial amount of cooling water that is provided 

by the NGCC plant CWS. The additional cooling load imposed by the CDR is reflected in the 

significantly larger CWPs and cooling tower in that case.

4.1.7.5 Buildings and Structures

Structures assumed for NGCC cases can be summarized as follows:

1. Generation Building housing the STG

2. CWP House

3. Administration / Office / Control Room / Maintenance Building 

4. Water Treatment Building

5. Fire Water Pump House

4.1.8 Accessory Electric Plant

The accessory electric plant consists of all switchgear and control equipment, generator 

equipment, station service equipment, conduit and cable trays, wire, and cable. It also includes 

the main transformer, required foundations, and standby equipment.

4.1.9 Waste Treatment/Miscellaneous Systems

An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash. It 

is anticipated that the treated water will be suitable for discharge into existing systems and be 

within the EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals.

The waste treatment system is minimal and consists, primarily, of neutralization and oil/water 

separators (along with the associated pumps, piping, etc.). 

Miscellaneous systems consisting of service air, instrument air, and service water are provided. 

All truck roadways and unloading stations inside the fence area are provided.

4.1.10 Instrumentation and Control

An integrated plant-wide DCS is provided. The DCS is a redundant microprocessor-based, 

functionally distributed system. The control room houses an array of video monitors and 

keyboard units. The monitor/keyboard units are the primary interface between the generating 
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process and operations personnel. The DCS incorporates plant monitoring and control functions 

for all the major plant equipment. The DCS is designed to provide 99.5 percent availability.

The plant equipment and the DCS are designed for automatic response to load changes from 

minimum load to 100 percent. Startup and shutdown routines are implemented as supervised 

manual procedures with operator selection of modular automation routines available.

4.1.11 Performance Summary Metrics

This section details the methods used to calculate several metrics reported in the performance 

summaries of the NGCC cases.

Combustion Turbine Efficiency

The combustion turbine efficiency is calculated by taking the CT power produced and dividing it 

by the thermal input to the turbines. This calculation is represented by the equation:

= TT

Where:

CTE – combustion turbine efficiency

CTP – combustion turbine power

TI – thermal input to turbines

The thermal input is calculated by taking the natural gas feed rate and multiplying it by the 

heating value of the natural gas and converting it to kWs.

Steam Turbine Efficiency

The steam turbine efficiency is calculated by taking the steam turbine power produced and 

dividing it by the difference between the thermal input and thermal consumption. This 

calculation is represented by the equation:

SS = SS

( TT − )

Where:

STE – steam turbine efficiency

STP – steam turbine power

TI – thermal input

TC – thermal consumption

The thermal input is calculated by taking the enthalpy of the flue gas to the HRSG and 

subtracting the enthalpy of the flue gas exiting the HRSG.

The thermal consumption is only present in the capture cases. It is the enthalpy difference 

between the streams extracted for the capture and CO2 dryer systems and the condensate returned 

to the condenser (steam extraction – condensate return).
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Steam Turbine Heat Rate

The steam turbine heat rate is calculated by taking the inverse of the steam turbine efficiency.

This calculation is represented by the equation:

SS SS = 1

SS ∗ 3,412

Where:

STHR – steam turbine heat rate, Btu/kWh

STE – steam turbine efficiency, fraction

4.2 NGCC Cases

This section contains an evaluation of plant designs for Cases B31A and B31B. The balance of 

this section is organized as follows:

• Process and System Description provides an overview of the technology operation as 

applied to Case B31A. The systems that are common to all NGCC cases were covered in 

Section 4.1 and only features that are unique to Case B31A are discussed further in this 

section.

• Key Assumptions is a summary of study and modeling assumptions relevant to Cases 

B31A and B31B.

• Sparing Philosophy is provided for both Cases B31A and B31B.

• Performance Results provides the main modeling results from Case B31A, including the 

performance summary, environmental performance, carbon balance, water balance, mass 

and energy balance diagrams, and energy balance table.

• Equipment List provides an itemized list of major equipment for Case B31A with 

account codes that correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates provides a summary of capital and operating costs for Case B31A.

• Process and System Description, Performance Results, Equipment List and Cost 

Estimates are reported for Case B31B.

4.2.1 Process Description

In this section the NGCC process without CO2 capture is described. The system description 

follows the BFD in Exhibit 4-2 and stream numbers reference the same exhibit. The tables in

Exhibit 4-3 provide process data for the numbered streams in the BFD. The BFD shows only 

one of the two CT/HRSG trains, but the flow rates in the stream table are the total for two 

systems.

Ambient air (stream 1) is supplied to an inlet filter and compressed before being combined with 

natural gas (stream 2) in the dry LNB, which is operated to control the rotor inlet temperature at 

1,359°C (2,479°F). The flue gas exits the turbine at 603°C (1,118°F) (stream 3) and passes into 

the HRSG. The HRSG generates both the main steam and reheat steam for the steam turbine. 

Flue gas exits the HRSG at 117°C (243°F) and passes to the plant stack.
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Exhibit 4-2 Case B31A block flow diagram, NGCC without CO2 capture

Source: NETL

1

HRSG

3

STACK

2

AIR

NATURAL

GAS

STEAM

TURBINE

5 6

CONDENSER

4

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.
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Exhibit 4-3 Case B31A stream table, NGCC without capture

1 2 3 4 5 6

Ar 0.0092 0.0000 0.0089 0.0089 0.0000 0.0000

CH4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000

CH4S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C2H6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000

C3H8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000

C4H10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0003 0.0100 0.0391 0.0391 0.0000 0.0000

H2O 0.0099 0.0000 0.0841 0.0841 1.0000 1.0000

N2 0.7732 0.0160 0.7442 0.7442 0.0000 0.0000

O2 0.2074 0.0000 0.1238 0.1238 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 125,541 4,855 130,538 130,538 24,398 32,637

V-L Flowrate (kg/hr) 3,622,750 84,134 3,706,884 3,706,884 439,533 587,969

Solids Flowrate (kg/hr) 0 0 0 0 0 0

Temperature (°C) 15 38 603 117 566 38

Pressure (MPa, abs) 0.10 3.10 0.10 0.10 16.65 0.01

Steam Table Enthalpy (kJ/kg) A 30.22 46.29 800.33 256.77 3,473.89 160.78

AspenPlus Enthalpy (kJ/kg)B -97.57 -4,462.93 -616.98 -1,160.55 -12,506.41 -15,819.51

Density (kg/m3) 1.2 22.2 0.4 0.9 47.7 992.8

V-L Molecular Weight 28.857 17.328 28.397 28.397 18.015 18.015

V-L Flowrate (lbmole/hr) 276,771 10,704 287,786 287,786 53,788 71,953

V-L Flowrate (lb/hr) 7,986,797 185,484 8,172,281 8,172,281 969,004 1,296,250

Solids Flowrate (lb/hr) 0 0 0 0 0 0

Temperature (°F) 59 100 1,118 243 1,050 101

Pressure (psia) 14.7 450.0 15.1 14.8 2,414.7 1.0

Steam Table Enthalpy (Btu/lb)A 13.0 19.9 344.1 110.4 1,493.5 69.1

AspenPlus Enthalpy (Btu/lb)B -41.9 -1,918.7 -265.3 -498.9 -5,376.8 -6,801.2

Density (lb/ft3) 0.076 1.384 0.025 0.056 2.975 61.977

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 

25°C and 1 atm.

4.2.2 Key System Assumptions

System assumptions for Cases B31A and B31B, NGCC with and without CO2 capture, are 

compiled in Exhibit 4-4.
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Exhibit 4-4 NGCC plant study configuration matrix

Case B31A 

w/o CO2 Capture 

Case B31B 

w/CO2 Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 16.5/566/566 

(2,400/1,050/1,050)

16.5/566/566 

(2,400/1,050/1,050)

Fuel Natural Gas Natural Gas

Fuel Pressure at Plant Battery Limit MPa (psia) 3.1 (450) 3.1 (450)

Condenser Pressure, mm Hg (in Hg) 50.8 (2) 50.8 (2)

Cooling Water to Condenser, °C (oF) 16 (60) 16 (60)

Cooling Water from Condenser, °C (oF) 27 (80) 27 (80)

Stack Temperature, °C (°F) 117 (243) 35 (95)

SO2 Control Low Sulfur Fuel Low Sulfur Fuel

NOx Control LNB and SCR LNB and SCR

SCR Efficiency, %A 90 90

Ammonia Slip (End of Catalyst Life), ppmv 10 10

Particulate Control N/A N/A

Mercury Control N/A N/A

CO2 Control N/A Cansolv

Overall Carbon CaptureA N/A 90%

CO2 Sequestration N/A Off-site Saline Formation

ARemoval efficiencies are based on the flue gas content

4.2.2.1 Balance of Plant – Cases B31A and B31B

The balance of plant assumptions are common to both NGCC cases and are presented in 

Exhibit 4-5.
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Exhibit 4-5 NGCC balance of plant assumptions

Parameter Value

Cooling System Recirculating Wet Cooling Tower

Fuel and Other Storage

Natural Gas Pipeline supply at 3.1 MPa (450 psia) and 38°C (100°F)

Plant Distribution Voltage

Motors below 1 hp 110/220 V

Motors between 1 hp and 250 hp 480 V

Motors between 250 hp and 5,000 

hp

4,160 V

Motors above 5,000 hp 13,800 V

Steam and CT generators 24,000 V

Grid Interconnection voltage 345 kV

Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW and 

50 percent from groundwater, and is assumed to be in 

sufficient quantities to meet plant makeup requirements.

Makeup for potable, process, and DI water is drawn from 

municipal sources.

Process Wastewater Storm water that contacts equipment surfaces is 

collected and treated for discharge through a permitted 

discharge.

Sanitary Waste Disposal Design includes a packaged domestic sewage treatment 

plant with effluent discharged to the industrial wastewater 

treatment system. Sludge is hauled off site. Packaged 

plant is sized for 5.68 m3/d (1,500 gpd)

Water Discharge Most of the process wastewater is recycled to the cooling 

tower basin. Blowdown is treated for chloride and 

metals, and discharged.

4.2.3 Sparing Philosophy

Dual trains are used to accommodate the size of commercial CTs. There is no redundancy other 

than normal sparing of rotating equipment. The plant design consists of the following major 

subsystems:

• Two state-of-the-art 2013 F-Class CTGs (2 x 50%)

• Two 3-pressure reheat HRSGs with self-supporting stacks and SCR systems (2 x 50%)

• One 3-pressure reheat, triple-admission STG (1 x 100%)

• For Case B31B only, one CO2 absorption systems, consisting of an absorber, stripper, 

and ancillary equipment (1 x 100%) and two CO2 compression systems (2 x 50%)

4.2.4 Case B31A Performance Results

The plant produces a net output of 630 MW at a net plant efficiency of 51.5 percent (HHV 

basis).

Overall plant performance is summarized in Exhibit 4-6; Exhibit 4-7 provides a detailed 

breakdown of the auxiliary power requirements.
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179

Exhibit 4-6 Case B31A plant performance summary

Performance Summary

Combustion Turbine Power, MWe 422

Steam Turbine Power, MWe 219

Total Gross Power, MWe 641

CO2 Capture/Removal Auxiliaries, kWe 0

CO2 Compression, kWe 0

Balance of Plant, kWe 11

Total Auxiliaries, MWe 11

Net Power, MWe 630

HHV Net Plant Efficiency (%) 51.5%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 6,994 (6,629)

HHV Combustion Turbine Efficiency, % 34.5%

LHV Net Plant Efficiency (%) 57.0%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 6,320 (5,990)

LHV Combustion Turbine Efficiency, % 38.1%

Steam Turbine Cycle Efficiency, % 39.1%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 9,201 (8,721)

Condenser Duty, GJ/hr (MMBtu/hr) 1,281 (1,215)

Natural Gas Feed Flow, kg/hr (lb/hr) 84,134 (185,483)

HHV Thermal Input, kWt 1,223,032

LHV Thermal Input, kWt 1,105,162

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.016 (4.2)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.012 (3.3)

Exhibit 4-7 Case B31A plant power summary

Power Summary

Combustion Turbine Power, MWe 422

Steam Turbine Power, MWe 219

Total Gross Power, MWe 641

Auxiliary Load Summary

Feedwater Pumps, kWe 3,550

SCR, kWe 2

CO2 Capture/Removal Auxiliaries, kWe 0

CO2 Compression, kWe 0

Miscellaneous Balance of PlantA, kWe 500

Combustion Turbine Auxiliaries, kWe 700

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 130

Circulating Water Pumps, kWe 2,570

Ground Water Pumps, kWe 240

Cooling Tower Fans, kWe 1,330

Transformer Losses, kWe 1,950

Total Auxiliaries, MWe 11

Net Power, MWe 630

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

4.2.4.1 Environmental Performance

The environmental targets for emissions of NOx, SO2, and PM were presented in Section 2.4. A 

summary of the plant air emissions for Case B31A is presented in Exhibit 4-8.
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180

Exhibit 4-8 Case B31A air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)

SO2 0.000 (0.001) 13 (15) 0.003 (0.006)

NOx 0.001 (0.003) 44 (49) 0.009 (0.020)

Particulate 0.000 (0.000) 0 (0) 0.000 (0.000)

Hg 0.00E+0 (0.00E+0) 0.000 (0.000) 0.00E+0 (0.00E+0)

CO2B 51 (119) 1,671,433 (1,842,440) 350 (773)

CO2C - - 357 (786)

ACalculations based on an 85 percent capacity factor

BCO2 emissions based on gross power

CCO2 emissions based on net power instead of gross power

For the purpose of this report, the natural gas was assumed to contain the average value of total 

sulfur of 0.34 gr/100 scf (4.71x10-4 lb-S/MMBtu). (11) It was also assumed that the added 

mercaptan (CH4S) was the sole contributor of sulfur to the natural gas. No sulfur capture 

systems were required.

The NGCC cases were designed to achieve approximately 1.0 ppmvd NOx emissions (at 15 

percent O2) through the use of a DLN burner in the CTG – the DLN burners reduce the 

emissions to about 9 ppmvd (at 15 percent O2) (18) – and an SCR – the SCR system is designed 

for 90 percent NO reduction (19).

The pipeline natural gas was assumed to contain no particulate matter (PM), Hg, or HCl,

resulting in zero emissions.

CO2 emissions are reduced relative to those produced by burning coal given the same power 

output because of the higher heat content of natural gas, the lower carbon intensity of gas relative 

to coal, and the higher overall efficiency of the NGCC plant relative to a coal-fired plant.

The carbon balance for the plant is shown in Exhibit 4-9. The carbon input to the plant consists 

of carbon in the natural gas and carbon as CO2 in the CT air. Carbon leaves the plant as CO2

through the stack.

Exhibit 4-9 Case B31A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Natural Gas 60,768 (133,971) Stack Gas 61,263 (135,061)

Air (CO2) 494 (1,090) CO2 Product 0 (0)

CO2 KO 0 (0)

CO2 Dryer Vent 0 (0)

Total 61,262 (135,061) Total 61,263 (135,061)

As shown in Exhibit 4-10, the sulfur content of the natural gas is insignificant. All sulfur in the 

natural gas is emitted in the stack gas.

Exhibit 4-10 Case B31A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Natural Gas 1 (2) Stack Gas 1 (2)

Polishing Scrubber/HSS 0 (0)

Total 1 (2) Total 1 (2)
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

181

Exhibit 4-11 shows the water balance for Case B31A. Water demand represents the total amount 

of water required for a particular process. Some water is recovered within the process and is reused as internal recycle. The difference between demand and recycle is raw water withdrawal. 

Raw water withdrawal is defined as the water removed from the ground or diverted from a 

surface-water source for use in the plant and was assumed to be provided 50 percent by a POTW 

and 50 percent from groundwater. Raw water withdrawal can be represented by the water 

metered from a raw water source and used in the plant processes for any and all purposes, such 

as condenser and cooling tower makeup. The difference between water withdrawal and process 

water discharge is defined as water consumption and can be represented by the portion of the raw 

water withdrawn that is evaporated, transpired, incorporated into products or otherwise not 

returned to the water source from which it was withdrawn. Water consumption represents the 

net impact of the plant process on the water source balance.

Exhibit 4-11 Case B31A water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process Water 

Discharge

Raw Water 

Consumption

m3/min (gpm) m3/min (gpm) m3/min (gpm) m3/min (gpm) m3/min (gpm)

CO2 Drying – – – – –

Capture System Makeup – – – – –

Condenser Makeup 0.10 (26) – 0.10 (26) – 0.10 (26)

 BFW Makeup 0.10 (26) – 0.10 (26) – 0.10 (26)

Cooling Tower 10.01 (2,646) 0.10 (26) 9.92 (2,620) 2.25 (595) 7.66 (2,025)

 CO2 Capture Recovery – – – – –

 CO2 Compression 

Recovery – – – – –

 BFW Blowdown – 0.10 (26) -0.10 (-26) – –

Total 10.11 (2,672) 0.10 (26) 10.01 (2,646) 2.25 (595) 7.76 (2,051)

4.2.4.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the NGCC in Exhibit 4-12. An overall plant 

energy balance is provided in tabular form in Exhibit 4-13. The power out is the combined CT 

and steam turbine power prior to generator losses. The power at the generator terminals (shown 

in Exhibit 4-6) is calculated by multiplying the power out by a combined generator efficiency of 

98.5 percent.
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Exhibit 4-12 Case B31A heat and mass balance, NGCC without CO2 capture

Source: NETL

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Nitrogen

Natural Gas

Water

Steam

PAGES

1 OF 1

NATURAL GAS COMBINED CYCLE PLANT

CASE B31A

2 X STATE-OF-THE-ART 2013 F-CLASS CT

2400/1050/1050

DWG. NO.

BB-HMB-CS-B31A-PG-1

Flue Gas

Gross Plant Power: 641 MWe

Auxiliary Load: 11 MWe

Net Plant Power: 630 MWe

Net Plant Efficiency, HHV: 51.5%

Net Plant Heat Rate: 6,629 Btu/kWh

DOE/NETL

NGCC PLANT

CASE B31A

Ambient

Air 1

7,986,797 W

59 T

15 P

13 H

State-of-the-art 2013 FClass Turbine

Natural 

185,483 W gas

100 T

450 P

20 H

2

8,172,280 W

243 T

15 P

110 H

Generator

Condensate 

Pumps

1,296,250 W

101 T

87 P

69 H

1,296,250 W

101 T

1 P

69 H

1,000 W

1,050 T

2,415 P

1,494 H

979,965 W

517 T

74 P

1,290 H

1,282,288 W

522 T

74 P

1,292 H

1,282,288 W

101 T

1 P

1,017 H

Hot Well

Condenser

Stack

Steam Turbine 

makeup

12,963 W

59 T

15 P

27 H

Air Inlet 

Filter

Gland Seal

Condenser

1,000 W

212 T

15 P

180 H

LP Turbine HP

Turbine

IP

Turbine

979,965 W

1,050 T

608 P

1,545 H

6

Preheater HP Economizer 2/ 

LP Superheater

IP Economizer/ 

HP Economizer 1

HP 

Evaporator

HP PreSuperheater/ 

IP Superheater

HP 

Superheater

/ Reheater

IP 

Evaporator

3

LP 

Evaporator

LP 

Economizer

305,377 W

300 T

84 P

270 H

12,082 W

301 T

707 P

272 H

978,792 W

306 T

3,010 P

282 H

1,296,250 W

253 T

80 P

222 H

HP 

Blowdown

Main Steam

969,004 W

1,050 T

2,415 P

1,494 H

5 IP 

Blowdown

Cold Reheat

Hot Reheat

IP Steam

LP Blowdown

11,961 W

900 T

621 P

1,462 H

968,004 W

673 T

621 P

1,333 H

302,323 W

537 T

74 P

1,300 HLP Steam

1,296,250 W

102 T

83 P

70 H

678 T 882 T

495 T 310 T 684 T 500 T

425 T

312 T

8,172,280 W

1,118 T

15 P

344 H

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

3,054 W

312 T

80 P

283 H 121 W

500 T

679 P

487 H

9,788 W

684 T

2,774 P

766 H

HP Pump

IP Pump

LP Pump

4
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185

Exhibit 4-13 Case B31A overall energy balance (0°C [32°F] reference)

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 4,403 (4,173) 2.9 (2.8) – 4,406 (4,176)

Air – 109.5 (103.8) – 109.5 (103.8)

Raw Water Makeup – 37.7 (35.7) – 37.7 (35.7)

Auxiliary Power – – 40 (38) 40 (38)

TOTAL 4,403 (4,173) 150.1 (142.3) 40 (38) 4,593 (4,353)

Heat Out GJ/hr (MMBtu/hr)

Stack Gas – 952 (902) – 952 (902)

Sulfur – – – –

Motor Losses and Design 

Allowances – – 41 (39) 41 (39)

Condenser – 1,281 (1,215) – 1,281 (1,215)

Non-Condenser Cooling Tower 

Loads – 26 (25) – 26 (25)

CO2 – – – –

Cooling Tower Blowdown – 16.7 (15.9) – 16.7 (15.9)

CO2 Capture Losses – – – –

Ambient LossesA – 34.6 (32.8) – 34.6 (32.8)

Power – – 2,306 

(2,186) 2,306 (2,186)

TOTAL – 2,311 (2,190) 2,347 

(2,225) 4,658 (4,415)

Unaccounted EnergyB – -65 (-62) – -65 (-62)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the combustor, reheater, superheater, and transformers.

BBy difference

4.2.5 Case B31A – Major Equipment List

Major equipment items for the NGCC plant with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 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.

Case B31A – Account 2: Fuel and Sorbent Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gas Pipeline

Underground, coated 

carbon steel, 

wrapped cathodic 

protection

70 m3/min @ 3.1 MPa

(2,456 acfm @ 450 psia)

39 cm (16 in) standard wall pipe

16 km 

(10 mi) 0

2 Gas Metering Station -- 70 m3/min (2,456 acfm) 1 0

Case B31A – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 776,000 liters (205,000 gal) 2 0

2 Condensate Pumps Vertical canned 5,430 lpm @ 70 m H2O

(1,430 gpm @ 240 ft H2O) 2 1
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186

Equipment 

No. Description Type Design Condition Operating Qty. Spares

3 Boiler Feedwater 

Pump

Horizontal, split case, 

multi-stage, centrifugal, 

with interstage bleed for 

IP and LP feedwater

HP water: 

4,100 lpm @ 2,500 m H2O 

(1,080 gpm @ 8,210 ft H2O)

IP water: 

050 lpm @ 540 m H2O 

(10 gpm @ 1,790 ft H2O)

LP water: 

1,280 lpm @ 14.0 m H2O 

(340 gpm @ 50 ft H2O)

2 1

4 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

5 Service Air 

Compressors Flooded Screw 13 m3/min @ 0.7 MPa(450 scfm @ 100 psig) 2 1

6 Instrument Air Dryers Duplex, regenerative 13 m3/min (450 scfm) 2 1

7 Closed Cycle Cooling 

Heat Exchangers Plate and frame 13 MMkJ/hr (13 MMBtu/hr) 2 0

8 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 5,200 lpm @ 20 m H2O(1,400 gpm @ 70 ft H2O) 2 1

9 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1

10 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

11 Raw Water Pumps Stainless steel, single 

suction

5,600 lpm @ 20 m H2O

(1,500 gpm @ 60 ft H2O) 2 1

12 Filtered Water Pumps Stainless steel, single 

suction

150 lpm @ 50 m H2O

(40 gpm @ 160 ft H2O) 2 1

13 Filtered Water Tank Vertical, cylindrical 145,000 liter (38,000 gal) 1 0

14 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly 

and electro-deionization 

unit

330 lpm (90 gpm) 1 0

15 Liquid Waste 

Treatment System 10 years, 24-hour storm 1 0

Case B31A – Account 6: Combustion Turbine and Accessories

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion

Turbine

State-of-the-art 2013 F-class

w/ dry low-NOx burner 210 MW 2 0

2

Combustion

Turbine 

Generator

TEWAC 230 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase 2 0

Case B31A – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

46 m (150 ft) high x

8.1 m (27 ft) diameter 2 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer section 

and integral deaerator

Main steam - 241,743 kg/hr, 

16.5 MPa/566°C 

(532,952 lb/hr, 2,400 

psig/1,050°F)

Reheat steam - 244,478 kg/hr, 

4.1 MPa/566°C 

(538,981 lb/hr, 593 

psig/1,050°F)

2 0
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187

Equipment 

No. Description Type Design Condition Operating Qty. Spares

3 SCR Reactor Space for spare layer 2,040,000 kg/hr (4,490,000 

lb/hr) 2 0

4 SCR Catalyst -- Space available for an 

additional catalyst layer 1 layer 0

5 Dilution Air Blowers Centrifugal 10 m3/min @ 108 cm WG

(190 scfm @ 42 in WG) 2 1

6 Ammonia Feed Pump Centrifugal 1.2 lpm @ 90 m H2O

(0.3 gpm @ 300 ft H2O) 2 1

7 Ammonia Storage 

Tank Horizontal tank 33,000 liter (9,000 gal) 1 0

Case B31A – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available 

advanced steam turbine

231 MW

16.5 MPa/566°C/566°C (2400 

psig/ 1050°F/1050°F)

1 0

2 Steam Turbine 

Generator

Hydrogen cooled, static 

excitation

260 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,410 GJ/hr (1,340 MMBtu/hr), 

Inlet water temperature 

16°C (60°F), 

Water temperature rise 

11°C (20°F)

1 0

4 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0

Case B31A – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 258,000 lpm @ 30 m(68,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

1440 GJ/hr (1360 MMBtu/hr) heat duty

1 0

Case B31A – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 230 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 250 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 0 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 10 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 2 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

188

Equipment 

No. Description Type Design Condition Operating Qty. Spares

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B31A – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

4.2.6 Case B31A – Cost Estimating

The cost estimating methodology was described previously in Section 2.7. Exhibit 4-14 shows a 

detailed breakdown of the capital costs; Exhibit 4-15 shows the owner’s costs, TOC, and TASC; 

Exhibit 4-16 shows the initial and annual O&M costs; and Exhibit 4-17 shows the COE 

breakdown. 

The estimated TPC of the NGCC with no CO2 capture is $685/kW. No process contingency was 

included in this case because all elements of the technology are commercially proven. The 

project contingency is 10.7 percent of TPC. The COE is $57.6/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

189

Exhibit 4-14 Case B31A total plant cost details

Case: B31A – 2x1 CT NGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 630 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,215 $3,329 $2,719 $0 $9,263 $834 $0 $1,515 $11,611 $18

3.2 Water Makeup & Pretreating $1,974 $204 $1,013 $0 $3,191 $287 $0 $696 $4,174 $7

3.3 Other Feedwater Subsystems $1,506 $498 $416 $0 $2,420 $218 $0 $396 $3,033 $5

3.4 Service Water Systems $238 $475 $1,531 $0 $2,245 $202 $0 $489 $2,937 $5

3.5 Other Boiler Plant Systems $1,606 $600 $1,380 $0 $3,586 $323 $0 $586 $4,496 $7

3.6 Natural Gas, incl. pipeline $17,706 $656 $567 $0 $18,929 $1,704 $0 $3,095 $23,728 $38

3.7 Waste Treatment Equipment $689 $0 $399 $0 $1,089 $98 $0 $237 $1,424 $2

3.8 Misc. Equip. (Cranes, Air Comp., 

Comm.)

$1,165 $156 $566 $0 $1,887 $170 $0 $411 $2,469 $4

Subtotal $28,101 $5,918 $8,592 $0 $42,611 $3,835 $0 $7,425 $53,871 $86

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,200 $0 $6,341 $0 $110,541 $9,949 $0 $12,049 $132,539 $211

6.9 Combustion Turbine Foundations $0 $879 $950 $0 $1,829 $165 $0 $399 $2,392 $4

Subtotal $104,200 $879 $7,291 $0 $112,370 $10,113 $0 $12,448 $134,931 $214

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $33,050 $0 $6,116 $0 $39,166 $3,525 $0 $4,269 $46,960 $75

7.2 SCR System $1,973 $829 $1,156 $0 $3,957 $356 $0 $647 $4,960 $8

7.9 HRSG, Duct & Stack Foundations $0 $551 $517 $0 $1,068 $96 $0 $233 $1,397 $2

Subtotal $35,023 $1,379 $7,788 $0 $44,190 $3,977 $0 $5,149 $53,316 $85

8 Steam Turbine Generator

8.1 Steam TG & Accessories $36,973 $0 $4,914 $0 $41,887 $3,770 $0 $4,566 $50,223 $80

8.2 Turbine Plant Auxiliaries $205 $0 $468 $0 $673 $61 $0 $73 $807 $1

8.3 Condenser & Auxiliaries $2,920 $0 $1,401 $0 $4,321 $389 $0 $471 $5,181 $8

8.4 Steam Piping $12,237 $0 $4,959 $0 $17,196 $1,548 $0 $2,812 $21,555 $34

8.9 TG Foundations $0 $968 $1,599 $0 $2,567 $231 $0 $560 $3,357 $5

Subtotal $52,335 $968 $13,341 $0 $66,644 $5,998 $0 $8,481 $81,123 $129

9 Cooling Water System

9.1 Cooling Towers $2,950 $0 $900 $0 $3,850 $347 $0 $420 $4,616 $7

9.2 Circulating Water Pumps $1,428 $0 $84 $0 $1,512 $136 $0 $165 $1,813 $3

9.3 Circ. Water System Auxiliaries $120 $0 $16 $0 $135 $12 $0 $15 $162 $0

9.4 Circ. Water Piping $0 $3,710 $840 $0 $4,550 $409 $0 $744 $5,703 $9

9.5 Make-up Water System $310 $0 $398 $0 $708 $64 $0 $116 $887 $1

9.6 Component Cooling Water Sys $239 $285 $183 $0 $707 $64 $0 $116 $886 $1

9.9 Circ. Water System Foundations $0 $1,678 $2,786 $0 $4,464 $402 $0 $973 $5,839 $9

Subtotal $5,046 $5,673 $5,207 $0 $15,926 $1,433 $0 $2,548 $19,907 $32

11 Accessory Electric Plant

11.1 Generator Equipment $5,327 $0 $3,151 $0 $8,477 $763 $0 $693 $9,933 $16

11.2 Station Service Equipment $1,527 $0 $131 $0 $1,659 $149 $0 $136 $1,944 $3

11.3 Switchgear & Motor Control $1,879 $0 $326 $0 $2,206 $199 $0 $240 $2,645 $4
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Case: B31A – 2x1 CT NGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 630 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11.4 Conduit & Cable Tray $0 $982 $2,830 $0 $3,812 $343 $0 $623 $4,778 $8

11.5 Wire & Cable $0 $3,156 $1,795 $0 $4,951 $446 $0 $809 $6,206 $10

11.6 Protective Equipment $0 $722 $2,506 $0 $3,228 $291 $0 $352 $3,871 $6

11.7 Standby Equipment $128 $0 $120 $0 $248 $22 $0 $27 $297 $0

11.8 Main Power Transformers $12,475 $0 $190 $0 $12,666 $1,140 $0 $1,381 $15,186 $24

11.9 Electrical Foundations $0 $164 $417 $0 $581 $52 $0 $127 $760 $1

Subtotal $21,337 $5,025 $11,466 $0 $37,828 $3,405 $0 $4,388 $45,621 $72

12 Instrumentation & Control

12.4 Other Major Component Control $900 $0 $573 $0 $1,473 $133 $0 $241 $1,846 $3

12.6 Control Boards, Panels & Racks $269 $0 $164 $0 $433 $39 $0 $71 $543 $1

12.7 Computer & Accessories $4,304 $0 $131 $0 $4,435 $399 $0 $483 $5,318 $8

12.8 Instrument Wiring & Tubing $0 $801 $1,417 $0 $2,217 $200 $0 $363 $2,779 $4

12.9 Other I & C Equipment $1,604 $0 $3,715 $0 $5,319 $479 $0 $580 $6,378 $10

Subtotal $7,077 $801 $6,000 $0 $13,878 $1,249 $0 $1,737 $16,864 $27

13 Improvements to Site

13.1 Site Preparation $0 $110 $2,335 $0 $2,445 $220 $0 $533 $3,198 $5

13.2 Site Improvements $0 $1,008 $1,331 $0 $2,339 $210 $0 $510 $3,059 $5

13.3 Site Facilities $2,057 $0 $2,158 $0 $4,215 $379 $0 $919 $5,514 $9

Subtotal $2,057 $1,117 $5,824 $0 $8,999 $810 $0 $1,962 $11,770 $19

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $303 $160 $0 $463 $42 $0 $76 $581 $1

14.2 Steam Turbine Building $0 $2,477 $3,295 $0 $5,772 $519 $0 $944 $7,235 $11

14.3 Administration Building $0 $568 $385 $0 $952 $86 $0 $156 $1,194 $2

14.4 Circulation Water Pumphouse $0 $190 $94 $0 $283 $26 $0 $46 $355 $1

14.5 Water Treatment Buildings $0 $419 $382 $0 $801 $72 $0 $131 $1,004 $2

14.6 Machine Shop $0 $493 $315 $0 $807 $73 $0 $132 $1,012 $2

14.7 Warehouse $0 $318 $192 $0 $510 $46 $0 $83 $639 $1

14.8 Other Buildings & Structures $0 $95 $69 $0 $165 $15 $0 $27 $206 $0

14.9 Waste Treating Building & Str. $0 $373 $665 $0 $1,038 $93 $0 $170 $1,301 $2

Subtotal $0 $5,235 $5,557 $0 $10,791 $971 $0 $1,764 $13,527 $21

Total $255,176 $26,995 $71,067 $0 $353,237 $31,791 $0 $45,902 $430,931 $685
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

191

Exhibit 4-15 Case B31A owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $3,632 $6

1 Month Maintenance Materials $522 $1

1 Month Non-fuel Consumables $242 $0

1 Month Waste Disposal $0 $0

25% of 1 Months Fuel Cost at 100% CF $4,679 $7

2% of TPC $8,619 $14

Total $17,695 $28

Inventory Capital

60 day supply of fuel and consumables at 100% CF $291 $0

0.5% of TPC (spare parts) $2,155 $3

Total $2,446 $4

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $300 $0

Other Owner's Costs $64,640 $103

Financing Costs $11,635 $18

Total Overnight Costs (TOC) $527,646 $838

TASC Multiplier (IOU, low-risk, 33 year) 1.075

Total As-Spent Cost (TASC) $567,219 $901
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

192

Exhibit 4-16 Case B31A initial and annual operating and maintenance costs

Case: B31A – 2x1 CT NGCC w/o CO2 Cost Base: Jun 2011

Plant Size (MW,net): 630 Heat Rate-net (Btu/kWh): 6,629 Capacity Factor (%): 85

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 1.0 

 Operating Labor Burden: 30.00 % of base Operator: 2.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 1.0 

Total: 5.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $2,260,518 $3.591

Maintenance Labor: $3,551,114 $5.641

Administrative & Support Labor: $1,452,908 $2.308

Property Taxes and Insurance: $8,618,615 $13.691

Total: $15,883,155 $25.230

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $5,326,671 $1.13636

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 1,905 $1.67 $0 $989,284 $0.21105

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 11,348 $0.27 $0 $943,019 $0.20118

SCR Catalyst (m3): w/equip. 0.08 $8,938.80 $0 $229,246 $0.04891

Ammonia (19% NH3, ton): 0 3.05 $330.00 $0 $311,902 $0.06654

Subtotal: $0 $2,473,451 $0.52767

Variable Operating Costs Total: $0 $7,800,123 $1.66404

Fuel Cost

Natural Gas (MMBtu): 0 100,384 $6.13 $0 $190,912,983 $40.72840

Total: $0 $190,912,983 $40.72840

Exhibit 4-17 Case B31A COE breakdown

Component Value, $/MWh Percentage

Capital 11.8 21%

Fixed 3.4 6%

Variable 1.7 3%

Fuel 40.7 71%

Total (Excluding T&S) 57.6 N/A

CO2 T&S 0.0 0%

Total (Including T&S) 57.6 N/A

4.2.7 Case B31B – NGCC with CO2 Capture

The plant configuration for Case B31B is the same as Case B31A with the exception that the 

CDR technology was added for CO2 capture. The nominal net output decreases to 559 MW 

because the CT designed output is fixed and the CDR facility significantly increases the auxiliary 

power load. Additionally, the CDR facility’s steam requirements reduces the power output of 

the steam turbine.

The process description for Case B31B is essentially the same as Case B31A with one notable 

exception, the addition of CO2 capture. A BFD and stream tables for Case B31B are shown in 
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

193

Exhibit 4-18 and Exhibit 4-19, respectively. Since the CDR facility process description was 

provided in Section 4.1.5, it is not repeated here.

4.2.8 Case B31B Performance Results

The Case B31B modeling assumptions were presented previously in Section 4.2.2.

The plant produces a net output of 559 MW at a net plant efficiency of 45.7 percent (HHV 

basis). Overall plant performance is summarized in Exhibit 4-20; Exhibit 4-21 provides a 

detailed breakdown of the auxiliary power requirements. The CDR facility, including CO2

compression, accounts for over 67 percent of the auxiliary plant load. The CWS (CWPs and 

cooling tower fan) accounts for nearly 16 percent of the auxiliary load, largely due to the high 

cooling water demand of the CDR facility.

Exhibit 4-18 Case B31B block flow diagram, NGCC with CO2 capture

Source: NETL

1 HRSG

3

AMINE

UNIT

STACK

4

15

16

6

12

5

2

AIR

NATURAL

GAS

REBOILER STEAM

REBOILER CONDENSATE

CO2

PRODUCT

STEAM

TURBINE

13 14

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

RECLAIMER STEAM

RECLAIMER CONDENSATE

17

18

7

CO2 COMPRESSORS

11 DRYER

CO2 COMPRESSORS

9 10

8

VENT

DRYER STEAM

DRYER

CONDENSATE
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

194

Exhibit 4-19 Case B31B stream table, NGCC with capture

1 2 3 4 5 6 7 8 9

V-L Mole Fraction

Ar 0.0092 0.0000 0.0089 0.0089 0.0096 0.0000 0.0000 0.0000 0.0000

CH4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CH4S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C2H6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C3H8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C4H10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0003 0.0100 0.0391 0.0391 0.0042 0.9824 0.9977 0.0503 0.0000

H2O 0.0099 0.0000 0.0841 0.0841 0.0468 0.0176 0.0023 0.9497 1.0000

N2 0.7732 0.0160 0.7442 0.7442 0.8054 0.0000 0.0000 0.0000 0.0000

O2 0.2074 0.0000 0.1238 0.1238 0.1340 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 125,541 4,855 130,538 130,538 120,611 4,673 4,601 8 7

V-L Flowrate (kg/hr) 3,622,750 84,134 3,706,884 3,706,884 3,408,725 203,504 202,217 148 121

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0

Temperature (°C) 15 38 603 117 35 29 29 29 356

Pressure (MPa, abs) 0.10 3.10 0.10 0.10 0.10 0.20 3.03 3.03 4.28

Steam Table Enthalpy (kJ/kg) A 30.22 46.29 800.33 255.91 110.58 42.52 -6.00 137.73 3,100.49

AspenPlus Enthalpy (kJ/kg)B -97.57 -4,462.93 -616.98 -1,161.40 -449.13 -8,972.02 -8,974.93 -15,221.43 -12,879.81

Density (kg/m3) 1.2 22.2 0.4 0.9 1.1 3.5 63.3 372.7 16.0

V-L Molecular Weight 28.857 17.328 28.397 28.397 28.262 43.553 43.950 19.322 18.015

V-L Flowrate (lbmole/hr) 276,771 10,704 287,786 287,786 265,902 10,301 10,144 17 15

V-L Flowrate (lb/hr) 7,986,797 185,484 8,172,281 8,172,281 7,514,952 448,649 445,812 327 267

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0

Temperature (°F) 59 100 1,118 242 95 85 85 85 673

Pressure (psia) 14.7 450.0 15.1 14.8 14.7 28.7 439.4 439.4 620.5

Steam Table Enthalpy (Btu/lb)A 13.0 19.9 344.1 110.0 47.5 18.3 -2.6 59.2 1,333.0

AspenPlus Enthalpy (Btu/lb)B -41.9 -1,918.7 -265.3 -499.3 -193.1 -3,857.3 -3,858.5 -6,544.0 -5,537.3

Density (lb/ft3) 0.076 1.384 0.025 0.056 0.070 0.216 3.953 23.269 0.998

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 

25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

195

Exhibit 4-19 Case B31B stream table, NGCC with capture (continued)

10 11 12 13 14 15 16 17 18

V-L Mole Fraction

Ar 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CH4S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C2H6 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C3H8 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

C4H10 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0000 0.9993 0.9993 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 1.0000 0.0007 0.0007 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 7 4,593 4,593 24,409 32,641 12,609 12,609 42 42

V-L Flowrate (kg/hr) 121 202,069 202,069 439,734 588,035 227,150 227,150 751 751

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0

Temperature (°C) 203 29 40 566 38 270 151 356 215

Pressure (MPa, abs) 1.64 2.89 15.27 16.65 0.01 0.51 0.49 4.28 2.11

Steam Table Enthalpy (kJ/kg)A 863.65 -5.93 -205.61 3,473.89 160.78 3,000.52 635.93 3,100.49 921.30

AspenPlus Enthalpy (kJ/kg)B -15,116.65 -8,970.17 -9,169.86 -12,506.41 -15,819.51 -12,979.77 -15,344.37 -12,879.81 -15,058.99

Density (kg/m3) 861.8 59.9 513.0 47.7 992.8 2.1 916.3 16.0 846.4

V-L Molecular Weight 18.015 43.991 43.991 18.015 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmole/hr) 15 10,127 10,127 53,813 71,961 27,797 27,797 92 92

V-L Flowrate (lb/hr) 267 445,486 445,486 969,448 1,296,395 500,779 500,779 1,656 1,656

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0

Temperature (°F) 397 85 104 1,050 101 517 304 673 419

Pressure (psia) 237.4 419.4 2,214.7 2,414.7 1.0 73.5 70.6 620.5 306.2

Steam Table Enthalpy (Btu/lb)A 371.3 -2.5 -88.4 1,493.5 69.1 1,290.0 273.4 1,333.0 396.1

AspenPlus Enthalpy (Btu/lb)B -6,499.0 -3,856.5 -3,942.3 -5,376.8 -6,801.2 -5,580.3 -6,596.9 -5,537.3 -6,474.2

Density (lb/ft3) 53.801 3.737 32.024 2.975 61.977 0.128 57.201 0.998 52.841

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 

25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

196

Exhibit 4-20 Case B31B plant performance summary

Performance Summary

Combustion Turbine Power, MWe 422

Steam Turbine Power, MWe 179

Total Gross Power, MWe 601

CO2 Capture/Removal Auxiliaries, kWe 13,000

CO2 Compression, kWe 15,010

Balance of Plant, kWe 13,722

Total Auxiliaries, MWe 42

Net Power, MWe 559

HHV Net Plant Efficiency (%) 45.7%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 7,877 (7,466)

HHV Combustion Turbine Efficiency, % 34.5%

LHV Net Plant Efficiency (%) 50.6%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 7,118 (6,746)

LHV Combustion Turbine Efficiency, % 38.1%

Steam Turbine Cycle Efficiency, % 43.5%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,269 (7,838)

Condenser Duty, GJ/hr (MMBtu/hr) 888 (842)

Natural Gas Feed Flow, kg/hr (lb/hr) 84,134 (185,483)

HHV Thermal Input, kWt 1,223,032

LHV Thermal Input, kWt 1,105,162

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.027 (7.2)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.020 (5.4)

Exhibit 4-21 Case B31B plant power summary

Power Summary

Combustion Turbine Power, MWe 422

Steam Turbine Power, MWe 179

Total Gross Power, MWe 601

Auxiliary Load Summary

Feedwater Pumps, kWe 3,550

SCR, kWe 2

CO2 Capture/Removal Auxiliaries, kWe 13,000

CO2 Compression, kWe 15,010

Miscellaneous Balance of PlantA, kWe 500

Combustion Turbine Auxiliaries, kWe 700

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 130

Circulating Water Pumps, kWe 4,310

Ground Water Pumps, kWe 360

Cooling Tower Fans, kWe 2,230

Transformer Losses, kWe 1,840

Total Auxiliaries, MWe 42

Net Power, MWe 559

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

4.2.8.1 Environmental Performance

The environmental targets for emissions of NOx, SO2, and PM were presented in Section 2.4. A 

summary of the plant air emissions for Case B31B is presented in Exhibit 4-22.
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197

Exhibit 4-22 Case B31B air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)

SO2 0.000 (0.000) 0 (0) 0.000 (0.000)

NOx 0.001 (0.003) 44 (49) 0.010 (0.022)

Particulate 0.000 (0.000) 0 (0) 0.000 (0.000)

Hg 0.00E+0 (0.00E+0) 0.000 (0.000) 0.00E+0 (0.00E+0)

CO2B 5 (12) 167,143 (184,244) 37 (82)

CO2C - - 40 (89)

ACalculations based on an 85 percent capacity factor

BCO2 emissions based on gross power

CCO2 emissions based on net power instead of gross power

For the purpose of this report, the natural gas was assumed to contain the average value of total 

sulfur of 0.34 gr/100 scf (4.71x10-4 lb-S/MMBtu). (11) It was also assumed that the added 

mercaptan (CH4S) was the sole contributor of sulfur to the natural gas. No sulfur capture 

systems were required.

The NGCC cases were designed to achieve approximately 1.0 ppmvd NOx emissions (at 15 

percent O2) through the use of a DLN burner in the CTG – the DLN burners reduce the 

emissions to about 9 ppmvd (at 15 percent O2) (18) – and an SCR – the SCR system is designed 

for 90 percent NO reduction (19).

The pipeline natural gas was assumed to contain no particulate matter (PM), Hg, or HCl,

resulting in zero emissions.

CO2 emissions are reduced relative to those produced by burning coal given the same power 

output because of the higher heat content of natural gas, the lower carbon intensity of gas relative 

to coal, and the higher overall efficiency of the NGCC plant relative to a coal-fired plant.

Ninety percent of the CO2 in the flue gas is removed in CDR facility.

The carbon balance for the plant is shown in Exhibit 4-23. The carbon input to the plant consists 

of carbon in the natural gas in addition to carbon in the CT air. Carbon leaves the plant as CO2

in the stack gas, the CO2 dryer’s vent, and the captured CO2 product. The carbon capture 

efficiency is defined as one minus the amount of carbon in the stack gas relative to the total 

carbon in, represented by the following fraction: 

CCCCCCCC SSSS

( TT CCCCCCCC ) = �1 − � 13,506

135,061�� ∗ 100 = 90.0%

Exhibit 4-23 Case B31B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Natural Gas 60,768 (133,971) Stack Gas 6,126 (13,506)

Air (CO2) 494 (1,090) CO2 Product 55,131 (121,544)

CO2 KO 0 (0)

CO2 Dryer Vent 5 (10)

Total 61,262 (135,061) Total 61,262 (135,061)
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

198

As shown in Exhibit 4-24, the sulfur content of the natural gas is insignificant, comprised 

entirely of mercaptan (CH4S) (used as an odorant). (11) All sulfur in the natural gas is removed 

in the polishing scrubber of the CDR system.

Exhibit 4-24 Case B31B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Natural Gas 1 (2) Stack Gas 0 (0)

Polishing Scrubber/HSS 1 (2)

Total 1 (2) Total 1 (2)

Exhibit 4-25 shows the overall water balance for the plant.

Exhibit 4-25 Case B31B water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

CO2 Drying – – – 0.00 (1) 0.00 (-1)

Capture System 

Makeup 0.02 (6) – 0.02 (6) – 0.02 (6)

Condenser Makeup 0.10 (26) – 0.10 (26) – 0.10 (26)

 BFW Makeup 0.10 (26) – 0.10 (26) – 0.10 (26)

Cooling Tower 16.81 

(4,440) 1.70 (449) 15.11 (3,991) 3.78 (998) 11.33 (2,992)

 CO2 Capture 

Recovery – 1.58 (417) -1.58 (-417) – –

 CO2 Compression 

Recovery – 0.02 (6) -0.02 (-6) – -0.02 (-6)

 BFW Blowdown – 0.10 (26) -0.10 (-26) – –

Total 16.93 

(4,472) 1.70 (449) 15.23 (4,023) 3.78 (999) 11.45 (3,024)

4.2.8.2 Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the NGCC in Exhibit 4-26. An overall plant 

energy balance is provided in tabular form in Exhibit 4-27.

The power out is the combined CT and steam turbine power prior to generator losses. The power 

at the generator terminals (shown in Exhibit 4-20) is calculated by multiplying the power out by 

a combined generator efficiency of 98.5 percent. The capture process heat out stream represents 

heat rejected to cooling water and ultimately to ambient via the cooling tower. The same is true 

of the condenser heat out stream. The CO2 compressor intercooler load is included in the capture

process heat out stream.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

199

Exhibit 4-26 Case B31B heat and mass balance, NGCC with CO2 capture

Source: NETL

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Nitrogen

Natural Gas

Carbon Dioxide

Water

Steam

PAGES

1 OF 1

NATURAL GAS COMBINED CYCLE PLANT

CASE B31B

2 X STATE-OF-THE-ART 2013 F-CLASS CT

2400/1050/1050

DWG. NO.

BB-HMB-CS-B31B-PG-1

Flue Gas

445,486 W

104 T

2,215 P

-88 H

CO2

Product

Ambient

Air 1

7,986,797 W

59 T

15 P

13 H

CO2 Compression 

(Interstage Cooling) & 

Drying

448,649 W

85 T

29 P

18 H

Knockout 

Water

208,676 W

216 T

15 P

803 H

Gross Plant Power: 601 MWe

Auxiliary Load: 42 MWe

Net Plant Power: 559 MWe

Net Plant Efficiency, HHV: 45.7%

Net Plant Heat Rate: 7,466 Btu/kWh

State-of-the-art 2013 FClass Turbine

Cansolv

Natural 

185,483 W gas

100 T

450 P

20 H

2

7,514,952 W

95 T

15 P

48 H

8,172,280 W

242 T

15 P

110 H

Generator

Condensate 

Pumps

1,296,395 W

101 T

87 P

69 H

1,296,395 W

101 T

1 P

69 H

1,000 W

1,050 T

2,415 P

1,494 H

978,472 W

517 T

74 P

1,290 H

779,729 W

525 T

74 P

1,294 H

Hot Well

Condenser

Stack

Condensate

From Reboiler

Steam Turbine 

makeup

12,964 W

59 T

15 P

27 H

Air Inlet 

Filter

Stripper

Absorber

Flue Gas Acid Gas

Blower

500,780 W

517 T

74 P

1,290 H

KO-Water

2,837 W

85 T

62 P

66 H

Gland Seal 

Condenser

1,000 W

212 T

15 P

180 H

LP Turbine

Steam to reboiler

HP

Turbine

IP

Turbine

6

15

500,780 W

304 T

71 P

273 H

14

Preheater HP Economizer 2/ 

LP Superheater

IP Economizer/ 

HP Economizer 1

HP 

Evaporator

HP PreSuperheater/ 

IP Superheater

HP 

Superheater

/ Reheater

IP 

Evaporator

3 LP 

Evaporator

LP 

Economizer

305,087 W

300 T

84 P

270 H

12,067 W

301 T

707 P

272 H

979,241 W

306 T

3,010 P

282 H

HP Pump

IP Pump

LP Pump

1,296,395 W

253 T

80 P

222 H

HP 

Blowdown

Main Steam

969,448 W

1,050 T

2,415 P

1,494 H

IP 

Blowdown

Cold Reheat

Hot Reheat

IP Steam

LP Blowdown

11,947 W

900 T

621 P

1,462 H

966,525 W

673 T

621 P

1,333 H

302,036 W

537 T

74 P

1,300 HLP Steam

DOE/NETL

NGCC PLANT

CASE B31B

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

5

Knockout Water

1,296,395 W

102 T

83 P

70 H

684 T 678 T 882 T

425 T

500 T

310 T

312 T

3,051 W

312 T

80 P

283 H

121 W

500 T

679 P

487 H

9,792 W

684 T

2,774 P

766 H

Condensate

From Dryer

Condensate

From Reclaimer

Reclaimer Steam

Dryer Steam

1,656 W

673 T

621 P

1,333 H

267 W

673 T

621 P

1,333 H

13

978,472 W

1,050 T

608 P

1,545 H

779,729 W

101 T

1 P

1,018 H

8,172,280 W

1,118 T

15 P

344 H

16

17

18

495 T

1,656 W

419 T

306 P

396 H

267 W

397 T

237 P

371 H

4

Vent

327 W

85 T

439 P

59 H

8

9

10

Dryer

12

7

11

445,486 W

85 T

419 P

-3 H

445,813 W

85 T

439 P

-3 H
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

201

Exhibit 4-27 Case B31B overall energy balance (0°C [32°F] reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 4,403 

(4,173)

2.9 (2.8) – 4,406 (4,176)

Air – 109.5 (103.8) – 109.5 (103.8)

Raw Water Makeup – 57.3 (54.3) – 57.3 (54.3)

Auxiliary Power – – 150 (142) 150 (142)

TOTAL 4,403 

(4,173)

169.7 (160.8) 150 (142) 4,723 (4,476)

Heat Out GJ/hr (MMBtu/hr)

Stack Gas – 377 (357) – 377 (357)

Sulfur 0 (0) 0.0 (0.0) – 0.0 (0.0)

Motor Losses and Design 

Allowances

– – 42 (40) 42 (40)

Condenser – 888 (842) – 888 (842)

Non-Condenser Cooling 

Tower Loads

– 26 (25) – 26 (25)

CO2 – -41.5 (-39.4) – -41.5 (-39.4)

Cooling Tower Blowdown – 28.1 (26.6) – 28.1 (26.6)

CO2 Capture Losses – 1,280 (1,213) – 1,280 (1,213)

Ambient LossesA – 37.4 (35.5) – 37.4 (35.5)

Power – – 2,163 (2,050) 2,163 (2,050)

TOTAL 0 (0) 2,595 (2,460) 2,205 (2,090) 4,800 (4,550)

Unaccounted EnergyB – -77 (-73) – -77 (-73)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the combustor, reheater, superheater, and transformers.

BBy difference

4.2.9 Case B31B Major Equipment List

Major equipment items for the NGCC plant with CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 

estimates in Section 4.2.10. 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.

Case B31B – Account 2: Fuel and Sorbent Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gas Pipeline

Underground, coated 

carbon steel, 

wrapped cathodic 

protection

70 m3/min @ 3.1 MPa

(2,456 acfm @ 450 psia)

39 cm (16 in) standard wall pipe

16 km (10 

mi) 0

2 Gas Metering Station -- 70 m3/min (2,456 acfm) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

202

Case B31B – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 776,000 liters (205,000 gal) 2 0

2 Condensate Pumps Vertical canned 5,430 lpm @ 70 m H2O

(1,430 gpm @ 240 ft H2O) 2 1

3 Boiler Feedwater 

Pump

Horizontal, split case, 

multi-stage, centrifugal, 

with interstage bleed for 

IP and LP feedwater

HP water: 

4,100 lpm @ 2,500 m H2O 

(1,080 gpm @ 8,210 ft H2O)

IP water: 

050 lpm @ 540 m H2O 

(10 gpm @ 1,790 ft H2O)

LP water: 

1,280 lpm @ 14.0 m H2O 

(340 gpm @ 50 ft H2O)

2 1

4 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

5 Service Air 

Compressors Flooded Screw 13 m3/min @ 0.7 MPa(450 scfm @ 100 psig) 2 1

6 Instrument Air Dryers Duplex, regenerative 13 m3/min (450 scfm) 2 1

7 Closed Cycle Cooling 

Heat Exchangers Plate and frame 13 MMkJ/hr (13 MMBtu/hr) 2 0

8 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 5,200 lpm @ 20 m H2O(1,400 gpm @ 70 ft H2O) 2 1

9 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1

10 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

11 Raw Water Pumps Stainless steel, single 

suction

8,500 lpm @ 20 m H2O

(2,200 gpm @ 60 ft H2O) 2 1

12 Filtered Water 

Pumps

Stainless steel, single 

suction

170 lpm @ 50 m H2O

(50 gpm @ 160 ft H2O) 2 1

13 Filtered Water Tank Vertical, cylindrical 164,000 liter (43,000 gal) 1 0

14 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly 

and electro-deionization 

unit

360 lpm (100 gpm) 1 0

15 Liquid Waste 

Treatment System N/A 10 years, 24-hour storm 1 0

Case B31B – Account 5B: Carbon Dioxide Recovery

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Cansolv Amine-based CO2

capture technology

4,078,000 kg/hr (8,990,000 lb/hr) 

6.1 wt % CO2 concentration 1 0

2 Cansolv LP 

Condensate Pump Centrifugal 492 lpm @ 1 m H2O (130 gpm @ 4 ft H2O) 1 1

3 Cansolv HP 

Condensate Pump Centrifugal 2 lpm @ 5 m H2O (1 gpm @ 15 ft H2O) 1 1

4 CO2 Dryer Triethylene glycol

Inlet: 53.0 m3/min (1,880 acfm) 

@ 3.0 MPa (439 psia) 

Outlet: 2.9 MPa (419 psia) 

Water Recovered: 148 kg/hr 

(327 lb/hr)

1 0
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203

Equipment 

No. Description Type Design Condition Operating Qty. Spares

5 CO2 Compressor

Integrally geared, 

multi-stage 

centrifugal

111,105 kg/hr @ 15.3 MPa 

(244,944 lb/hr @ 2,215 psia) 2 0

Case B31B – Account 6: Combustion Turbine and Accessories

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion

Turbine

State-of-the-art 2013 F-class

w/ dry low-NOx burner 210 MW 2 0

2

Combustion

Turbine 

Generator

TEWAC 230 MVA @ 0.9 p.f., 

24 kV, 60 Hz, 3-phase 2 0

Case B31B – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

46 m (150 ft) high x

7.0 m (23 ft) diameter 2 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer section 

and integral deaerator

Main steam - 241,854 kg/hr, 

16.5 MPa/566°C 

(533,197 lb/hr, 2,400 

psig/1,050°F)

Reheat steam - 244,105 kg/hr, 

4.1 MPa/566°C 

(538,160 lb/hr, 593 

psig/1,050°F)

2 0

3 SCR Reactor Space for spare layer 1,870,000 kg/hr 

(4,130,000 lb/hr) 2 0

4 SCR Catalyst -- Space available for an 

additional catalyst layer 1 layer 0

5 Dilution Air Blowers Centrifugal 10 m3/min @ 108 cm WG

(190 scfm @ 42 in WG) 2 1

6 Ammonia Feed Pump Centrifugal 1.2 lpm @ 90 m H2O

(0.3 gpm @ 300 ft H2O) 2 1

7 Ammonia Storage 

Tank Horizontal tank 33,000 liter (9,000 gal) 1 0

Case B31B – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available 

advanced steam turbine

189 MW

16.5 MPa/566°C/566°C (2400 

psig/ 1050°F/1050°F)

1 0

2 Steam Turbine 

Generator

Hydrogen cooled, static 

excitation

210 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase 1 0

3 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

980 GJ/hr (930 MMBtu/hr), 

Inlet water temperature 

16°C (60°F), 

Water temperature rise 

11°C (20°F)

1 0

4 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 0
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204

Case B31B – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 433,000 lpm @ 30 m(114,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2410 GJ/hr (2290 MMBtu/hr) heat duty

1 0

Case B31B – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 230 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 180 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 8 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 28 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B31B – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS -

Processor

Microprocessor with redundant 

input/output N/A 1 0

3 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

4.2.10 Case B31B – Cost Estimating

The cost estimating methodology was described previously in Section 2.7. Exhibit 4-28 shows a 

detailed breakdown of the capital costs; Exhibit 4-29 shows the owner’s costs, TOC, and TASC; 

Exhibit 4-30 shows the initial and annual O&M costs; and Exhibit 4-31 shows the COE 

breakdown. 

The estimated TPC of the NGCC with CO2 capture is $1,481/kW. Process contingency 

represents 5.0 percent of the TPC and project contingency represents 13.0 percent. The COE, 

including CO2 T&S costs of $4.0/MWh, is $87.3/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

205

Exhibit 4-28 Case B31B total plant cost details

Case: B31B – 2x1 CT NGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 559 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,216 $3,330 $2,720 $0 $9,266 $834 $0 $1,515 $11,615 $21

3.2 Water Makeup & Pretreating $2,587 $267 $1,328 $0 $4,182 $376 $0 $912 $5,470 $10

3.3 Other Feedwater Subsystems $1,507 $498 $416 $0 $2,421 $218 $0 $396 $3,034 $5

3.4 Service Water Systems $312 $623 $2,007 $0 $2,942 $265 $0 $641 $3,849 $7

3.5 Other Boiler Plant Systems $2,105 $786 $1,809 $0 $4,700 $423 $0 $768 $5,892 $11

3.6 Natural Gas, incl. pipeline $17,693 $631 $546 $0 $18,871 $1,698 $0 $3,085 $23,655 $42

3.7 Waste Treatment Equipment $904 $0 $523 $0 $1,427 $128 $0 $311 $1,866 $3

3.8 Misc. Equip. (Cranes, Air Comp., 

Comm.) $1,206 $161 $586 $0 $1,953 $176 $0 $426 $2,555 $5

Subtotal $29,530 $6,297 $9,935 $0 $45,762 $4,119 $0 $8,055 $57,936 $104

5B CO2 Removal & Compression

5B.1 CO2 Removal System $99,453 $41,537 $86,184 $0 $227,175 $18,462 $41,028 $52,926 $339,591 $608

5B.2 CO2 Compression & Drying $18,852 $2,828 $7,821 $0 $29,501 $2,655 $0 $6,431 $38,587 $69

Subtotal $118,305 $44,365 $94,006 $0 $256,676 $21,118 $41,028 $59,357 $378,178 $677

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,200 $0 $6,341 $0 $110,541 $9,949 $0 $12,049 $132,539 $237

6.9 Combustion Turbine Foundations $0 $879 $950 $0 $1,829 $165 $0 $399 $2,392 $4

Subtotal $104,200 $879 $7,291 $0 $112,370 $10,113 $0 $12,448 $134,931 $241

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $31,120 $0 $5,773 $0 $36,893 $3,320 $0 $4,021 $44,235 $79

7.2 SCR System $1,973 $829 $1,156 $0 $3,957 $356 $0 $647 $4,960 $9

7.9 HRSG, Duct & Stack Foundations $0 $442 $415 $0 $857 $77 $0 $187 $1,121 $2

Subtotal $33,093 $1,271 $7,344 $0 $41,707 $3,754 $0 $4,855 $50,316 $90

8 Steam Turbine Generator

8.1 Steam TG & Accessories $32,860 $0 $4,812 $0 $37,672 $3,390 $0 $4,106 $45,168 $81

8.2 Turbine Plant Auxiliaries $195 $0 $434 $0 $629 $57 $0 $69 $754 $1

8.3 Condenser & Auxiliaries $2,260 $0 $1,210 $0 $3,470 $312 $0 $378 $4,160 $7

8.4 Steam Piping $12,240 $0 $4,961 $0 $17,201 $1,548 $0 $2,812 $21,561 $39

8.9 TG Foundations $0 $836 $1,380 $0 $2,216 $199 $0 $483 $2,899 $5

Subtotal $47,555 $836 $12,796 $0 $61,188 $5,507 $0 $7,848 $74,543 $133

9 Cooling Water System

9.1 Cooling Towers $4,260 $0 $1,290 $0 $5,550 $500 $0 $605 $6,654 $12

9.2 Circulating Water Pumps $2,038 $0 $125 $0 $2,163 $195 $0 $236 $2,593 $5

9.3 Circ. Water System Auxiliaries $162 $0 $21 $0 $184 $17 $0 $20 $220 $0

9.4 Circ. Water Piping $0 $5,032 $1,139 $0 $6,171 $555 $0 $1,009 $7,735 $14

9.5 Make-up Water System $389 $0 $500 $0 $889 $80 $0 $145 $1,115 $2

9.6 Component Cooling Water Sys $324 $387 $248 $0 $959 $86 $0 $157 $1,202 $2

9.9 Circ. Water System Foundations $0 $2,294 $3,809 $0 $6,103 $549 $0 $1,330 $7,982 $14

Subtotal $7,173 $7,712 $7,133 $0 $22,018 $1,982 $0 $3,502 $27,502 $49
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

206

Case: B31B – 2x1 CT NGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 559 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11 Accessory Electric Plant

11.1 Generator Equipment $7,182 $0 $4,248 $0 $11,430 $1,029 $0 $934 $13,393 $24

11.2 Station Service Equipment $2,478 $0 $213 $0 $2,690 $242 $0 $220 $3,153 $6

11.3 Switchgear & Motor Control $3,049 $0 $530 $0 $3,578 $322 $0 $390 $4,290 $8

11.4 Conduit & Cable Tray $0 $1,593 $4,590 $0 $6,183 $556 $0 $1,011 $7,750 $14

11.5 Wire & Cable $0 $5,120 $2,911 $0 $8,031 $723 $0 $1,313 $10,067 $18

11.6 Protective Equipment $0 $713 $2,474 $0 $3,187 $287 $0 $347 $3,821 $7

11.7 Standby Equipment $125 $0 $116 $0 $241 $22 $0 $26 $288 $1

11.8 Main Power Transformers $13,433 $0 $182 $0 $13,615 $1,225 $0 $1,484 $16,324 $29

11.9 Electrical Foundations $0 $157 $399 $0 $556 $50 $0 $121 $727 $1

Subtotal $26,265 $7,583 $15,662 $0 $49,510 $4,456 $0 $5,847 $59,813 $107

12 Instrumentation & Control

12.4 Other Major Component Control $998 $0 $636 $0 $1,634 $147 $82 $279 $2,142 $4

12.6 Control Boards, Panels & Racks $298 $0 $182 $0 $481 $43 $24 $82 $630 $1

12.7 Computer & Accessories $4,775 $0 $146 $0 $4,921 $443 $246 $561 $6,170 $11

12.8 Instrument Wiring & Tubing $0 $888 $1,572 $0 $2,460 $221 $123 $421 $3,225 $6

12.9 Other I & C Equipment $1,780 $0 $4,121 $0 $5,901 $531 $295 $673 $7,400 $13

Subtotal $7,851 $888 $6,657 $0 $15,396 $1,386 $770 $2,016 $19,568 $35

13 Improvements to Site

13.1 Site Preparation $0 $112 $2,378 $0 $2,490 $224 $0 $543 $3,257 $6

13.2 Site Improvements $0 $1,026 $1,356 $0 $2,382 $214 $0 $519 $3,115 $6

13.3 Site Facilities $2,095 $0 $2,198 $0 $4,293 $386 $0 $936 $5,615 $10

Subtotal $2,095 $1,138 $5,931 $0 $9,164 $825 $0 $1,998 $11,987 $21

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $303 $160 $0 $463 $42 $0 $76 $581 $1

14.2 Steam Turbine Building $0 $2,195 $2,921 $0 $5,116 $460 $0 $836 $6,412 $11

14.3 Administration Building $0 $584 $395 $0 $979 $88 $0 $160 $1,227 $2

14.4 Circulation Water Pumphouse $0 $186 $92 $0 $277 $25 $0 $45 $348 $1

14.5 Water Treatment Buildings $0 $549 $500 $0 $1,049 $94 $0 $172 $1,315 $2

14.6 Machine Shop $0 $506 $324 $0 $830 $75 $0 $136 $1,040 $2

14.7 Warehouse $0 $327 $197 $0 $524 $47 $0 $86 $657 $1

14.8 Other Buildings & Structures $0 $98 $71 $0 $169 $15 $0 $28 $212 $0

14.9 Waste Treating Building & Str. $0 $383 $684 $0 $1,067 $96 $0 $174 $1,337 $2

Subtotal $0 $5,131 $5,344 $0 $10,475 $943 $0 $1,713 $13,130 $23

Total $376,068 $76,100 $172,100 $0 $624,267 $54,201 $41,798 $107,639 $827,904 $1,481
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

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Exhibit 4-29 Case B31B owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $5,405 $10

1 Month Maintenance Materials $851 $2

1 Month Non-fuel Consumables $767 $1

1 Month Waste Disposal $0 $0

25% of 1 Months Fuel Cost at 100% CF $4,679 $8

2% of TPC $16,558 $30

Total $28,260 $51

Inventory Capital

60 day supply of fuel and consumables at 100% CF $1,239 $2

0.5% of TPC (spare parts) $4,140 $7

Total $5,378 $10

Other Costs

Initial Cost for Catalyst and Chemicals $0 $0

Land $300 $1

Other Owner's Costs $124,186 $222

Financing Costs $22,353 $40

Total Overnight Costs (TOC) $1,008,381 $1,804

TASC Multiplier (IOU, high-risk, 33 year) 1.078

Total As-Spent Cost (TASC) $1,087,034 $1,945
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

208

Exhibit 4-30 Case B31B initial and annual operating and maintenance costs

Case: B31B – 2x1 CT NGCC w/ CO2 Cost Base: Jun 2011

Plant Size (MW,net): 559 Heat Rate-net (Btu/kWh): 7,466 Capacity Factor (%): 85

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 1.0 

 Operating Labor Burden: 30.00 % of base Operator: 3.3 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Techs, etc.: 1.0 

Total: 6.3 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $2,861,816 $5.120

Maintenance Labor: $5,785,827 $10.351

Administrative & Support Labor: $2,161,911 $3.868

Property Taxes and Insurance: $16,558,081 $29.623

Total: $27,367,635 $48.961

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $8,678,741 $2.08520

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 2,897 $1.67 $0 $1,504,337 $0.36144

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 17,257 $0.27 $0 $1,433,984 $0.34454

CO2 Capture System ChemicalsA Proprietary

SCR Catalyst (m3): w/equip. 0.08 $8,938.80 $0 $229,246 $0.05508

Triethylene Glycol (gal) 0 165 $6.57 $0 $337,099 $0.08099

Ammonia (19% NH3, ton): 0 3.05 $330.00 $0 $311,902 $0.07494

Subtotal: $0 $7,820,762 $1.87905

Waste Disposal

Amine Purification Unit Waste (ton) 0 4.01 $0.00 $0 $0 $0.00000

Thermal Reclaimer Unit Waste (ton) 0 0.37 $0.00 $0 $0 $0.00000

Prescrubber Blowdown Waste (ton) 0 0.00 $0.00 $0 $0 $0.00000

 Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $0 $16,499,502 $3.96425

Fuel Cost

Natural Gas (MMBtu): 0 100,384 $6.13 $0 $190,912,983 $45.86966

Total: $0 $190,912,983 $45.86966

ACO2 Capture System Chemicals includes Ion Exchange Resin, NaOH, and Cansolv Solvent.

Exhibit 4-31 Case B31B COE breakdown

Component Value, $/MWh Percentage

Capital 26.9 31%

Fixed 6.6 8%

Variable 4.0 5%

Fuel 45.9 53%

Total (Excluding T&S) 83.3 N/A

CO2 T&S 4.0 5%

Total (Including T&S) 87.3 N/A
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4.3 NGCC Case Summary

The performance results of the two NGCC plant configurations modeled in this report are 

summarized in Exhibit 4-32.

Exhibit 4-32 Estimated performance and cost results for NGCC cases

NGCC

State-of-the-art 2013 F-Class

Case B31A Case B31B

PERFORMANCE

Nominal CO2 Capture 0% 90%

Capacity Factor 85% 85%

Gross Power Output (MWe) 641 601

Auxiliary Power Requirement (MWe) 11 42

Net Power Output (MWe) 630 559

Coal Flow rate (lb/hr) N/A N/A

Natural Gas Flow rate (lb/hr) 185,484 185,484

HHV Thermal Input (kWt) 1,223,032 1,223,032

Net Plant HHV Efficiency (%) 51.5% 45.7%

Net Plant HHV Heat Rate (Btu/kWh) 6,629 7,466

Raw Water Withdrawal, gpm 2,646 4,023

Process Water Discharge, gpm 595 999

Raw Water Consumption, gpm 2,051 3,024

CO2 Emissions (lb/MMBtu) 119 12

CO2 Emissions (lb/MWh-gross) 773 82

CO2 Emissions (lb/MWh-net) 786 89

SO2 Emissions (lb/MMBtu) 0.001 0.000

SO2 Emissions (lb/MWh-gross) 0.006 0.000

NOx Emissions (lb/MMBtu) 0.003 0.003

NOx Emissions (lb/MWh-gross) 0.020 0.022

PM Emissions (lb/MMBtu) 0.000 0.000

PM Emissions (lb/MWh-gross) 0.000 0.000

Hg Emissions (lb/TBtu) 0.000 0.000

Hg Emissions (lb/MWh-gross) 0.00E-06 0.00E-06

COST

Total Plant Cost (2011$/kW) 685 1,481

Bare Erected Cost 561 1,117

Home Office Expenses 51 97

Project Contingency 73 193

Process Contingency 0 75

Total Overnight Cost (2011$/MM) 528 1,008

Total Overnight Cost (2011$/kW) 838 1,804

Owner's Costs 154 323

Total As-Spent Cost (2011$/kW) 901 1,945

COE ($/MWh) (excluding T&S) 57.6 83.3

Capital Costs 11.8 26.9

Fixed Costs 3.4 6.6

Variable Costs 1.7 4.0

Fuel Costs 40.7 45.9

COE ($/MWh) (including T&S) 57.6 87.3

CO2 T&S Costs 0.0 4.0
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The following observations can be made regarding plant performance with reference to 

Exhibit 4-32:

• The efficiency of the NGCC case with no CO2 capture is 51.5 percent (HHV basis). 

Gas Turbine World provides estimated performance for a state-of-the-art 2013 F-class 

turbine operated on natural gas in a combined cycle mode, and the reported efficiency 

is 58.0 percent (LHV basis). (44) Adjusting the result from this report to an LHV 

basis results in an efficiency of 57.0 percent.

• The efficiency penalty to add CO2 capture in the NGCC case is 5.8 absolute percent. 

The efficiency reduction is caused primarily by the auxiliary loads of the capture 

system and CO2 compression as well as the significantly increased cooling water 

requirement, which increases the auxiliary load of the CWPs and the cooling tower 

fan. CO2 capture results in a 31 MW increase in auxiliary load compared to the noncapture case.

The components of TOC and overall TASC are shown for the two NGCC cases in Exhibit 4-33. 

The addition of CO2 capture more than doubles the TOC cost of the NGCC plant. The process 

contingency included for the capture process totals $75/kW, which represents approximately 4 

percent of the TOC.

Exhibit 4-33 Plant capital cost for NGCC cases

Source: NETL

Exhibit 4-34 shows that at the study natural gas price, the fuel represents a significant fraction of 

the total. The fuel component of COE represents 71 percent of the total in the non-capture case 

and 53 percent of the total in the CO2 capture case. The CO2 T&S component of COE is only 5 

percent of the total in the CO2 capture case.
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Exhibit 4-34 COE of NGCC cases

Source: NETL

The sensitivity of NGCC COE to CF is shown in Exhibit 4-35. NGCC is relatively insensitive to 

CF but highly sensitive to fuel cost (as shown in Exhibit 4-36) because of the relatively small 

capital component. As the capacity factor drops, the decrease in net production is nearly offset 

by a corresponding decrease in fuel cost. A 33 percent increase in natural gas price (from $6.13

to $8.15/MMBtu) results in a COE increase of 23 percent in the non-capture case and 17 percent 

in the CO2 capture case. Because of the higher capital cost in the CO2 capture case, the impact 

of fuel price changes is slightly diminished.
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Exhibit 4-35 Sensitivity of COE to capacity factor in NGCC cases

Source: NETL

Exhibit 4-36 Sensitivity of COE to fuel price in NGCC cases

Source: NETL

The first year CO2 avoided and captured costs were calculated (the methodology and equations 

were provided in Section 2.7.4), and the results for the NGCC cases are presented in Exhibit 
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4-37. The cost of CO2 captured is $71/tonne ($65/ton) and the cost of CO2 avoided is $94/tonne 

($85/ton) using NGCC without CO2 capture as the reference. 

Exhibit 4-37 First year cost of CO2 captured and avoided in NGCC cases

Source: NETL

The normalized water withdrawal, process discharge and raw water consumption are shown in 

Exhibit 4-38. 
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Exhibit 4-38 Raw water withdrawal and consumption in NGCC cases

Source: NETL

The following observations can be made:

• Normalized water withdrawal increases 71 percent and normalized raw water 

consumption 66 percent in the CO2 capture case. The high cooling water demand of 

the capture process results in a large increase in cooling tower makeup requirements.

• Cooling tower makeup comprises approximately 99 percent of the raw water 

consumption in both NGCC cases. The only internal recycle stream in the noncapture case is the BFW blowdown, which is recycled to the cooling tower. In the 

CO2 capture cases, condensate is recovered from the flue gas as it is cooled to the 

absorber temperature of 30°C (86°F) and is also recycled to the cooling tower.
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5 Results Analysis

Summaries of the individual technologies were provided in Sections 3 and 4. This section 

provides the results of all technologies for cross-comparison.

5.1 Performance

Exhibit 5-1 provides a summary of the performance and environmental profile for all cases.

Exhibit 5-1 Performance summary and environmental profile for all cases

Pulverized Coal Boiler NGCC

PC Subcritical PC Supercritical State-of-the-art 2013 

F-Class

Case Name B11A B11B B12A B12B B31A B31B

PERFORMANCE

Gross Power Output (MWe) 581 644 580 642 641 601

Auxiliary Power Requirement (MWe) 31 94 30 91 11 42

Net Power Output (MWe) 550 550 550 550 630 559

Coal Flow rate (lb/hr) 412,005 516,170 395,053 495,578 N/A N/A

Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A 185,484 185,484

HHV Thermal Input (kWt) 1,408,630 1,764,768 1,350,672 1,694,366 1,223,032 1,223,032

Net Plant HHV Efficiency (%) 39.0% 31.2% 40.7% 32.5% 51.5% 45.7%

Net Plant HHV Heat Rate (Btu/kWh) 8,740 10,953 8,379 10,508 6,629 7,466

Raw Water Withdrawal, gpm 5,538 8,441 5,105 7,882 2,646 4,023

Process Water Discharge, gpm 1,137 1,920 1,059 1,813 595 999

Raw Water Consumption, gpm 4,401 6,521 4,045 6,069 2,051 3,024

CO2 Capture Rate, % 0 90 0 90 0 90

CO2 Emissions (lb/MMBtu) 204 20 204 20 119 12

CO2 Emissions (lb/MWh-gross) 1,683 190 1,618 183 773 82

CO2 Emissions (lb/MWh-net) 1,779 223 1,705 214 786 89

SO2 Emissions (lb/MMBtu) 0.085 0.000 0.085 0.000 0.001 0.000

SO2 Emissions (lb/MWh-gross) 0.700 0.000 0.673 0.000 0.006 0.000

NOx Emissions (lb/MMBtu) 0.085 0.075 0.088 0.078 0.003 0.003

NOx Emissions (lb/MWh-gross) 0.700 0.700 0.700 0.700 0.020 0.022

PM Emissions (lb/MMBtu) 0.011 0.010 0.011 0.010 0.000 0.000

PM Emissions (lb/MWh-gross) 0.090 0.090 0.090 0.090 0.000 0.000

Hg Emissions (lb/TBtu) 0.363 0.321 0.377 0.333 0.000 0.000

Hg Emissions (lb/MWh-gross) 3.00E-06 3.00E-06 3.00E-06 3.00E-06 0.00E+00 0.00E+00

5.1.1 Energy Efficiency

A graph of the net plant efficiency (HHV basis) is provided in Exhibit 5-2.

The primary conclusions that can be drawn are:

• The NGCC cases have the highest net efficiency of all the technologies, both without 

CO2 capture (51.5 percent) and with CO2 capture (45.7 percent). The next highest 

efficiency is the non-capture SC PC case, with an efficiency of 40.7 percent.

• For the PC cases, adding CO2 capture results in a relative efficiency penalty of 20 percent 

(8 percentage points).

• For the NGCC case, adding CO2 capture results in a relative efficiency penalty of 11

percent (6 percentage points). The NGCC penalty is less than the PC penalty because:
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o Natural gas is less carbon intensive than coal (based on the fuel compositions 

used in this study, natural gas contains 32 lb carbon/MMBtu of heat input and

coal contains 56 lb/MMBtu).

o The NGCC non-capture plant is more efficient, thus there is less total CO2 to 

capture and compress (NGCC non-capture CO2 emissions are approximately 54-

56 percent lower than the PC cases) when normalized to equivalent net power

outputs.

o These effects are offset slightly by the lower concentration of CO2 in the NGCC 

flue gas (4% vs. 13% for PC). When normalized to CO2 captured, the energy 

penalty is 0.16 kWh and 0.13 kWh per lb of CO2 captured for NGCC and PC, 

respectively.

Exhibit 5-2 Net plant efficiency (HHV basis)

Source: NETL

5.1.2 Environmental Emissions

Natural gas does not contain Hg, PM, or HCl, which makes its environmental profile more 

attractive compared to PC cases. In this report it was assumed that the only sulfur present in 

natural gas is from the addition of the odorant, mercaptan. This results in an SO2 emission rate 

below the regulatory limits without any further control.

Estimated emissions of Hg, PM, NOx, and SO2 are all at or below the applicable regulatory 

limits currently in effect for all cases (PC and NGCC)

5.1.3 Water Use

Three water values are presented for each technology in Exhibit 5-3: raw water withdrawal, 

process discharge, and raw water consumption. Each value is normalized by net output.
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Exhibit 5-3 Raw water withdrawal and consumption

Source: NETL

The primary conclusions that can be drawn are:

• NGCC has the lowest raw water consumption of all cases for both non-capture and 

CO2 capture cases with the relative normalized raw water consumption for the 

technologies being 2.2:1.0 (SCPC:NGCC). The relative results are expected given 

the higher steam turbine output in the PC cases, which results in higher condenser 

duties, higher cooling water flows, and, ultimately, higher cooling water makeup. 

• CO2 capture imposes a significant water demand on all technologies. The postcombustion capture technology has a significant cooling water demand that results in 

increased raw water consumption because of increased cooling tower blowdown and 

cooling tower evaporative losses. The normalized raw water consumption increases 

by 62 percent for the NGCC case, 50 percent for the SC PC case, and 48 percent for 

the subcritical PC case. The relative increases reflect the smaller non-capture water 

requirements that result from less power output generated by the steam turbine. 

Despite the lower relative water consumption increase for the PC cases, they still 

have the largest normalized raw water consumption of the capture technologies: 

2.0:1.0 (PC: NGCC). 
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5.2 Cost Results

Exhibit 5-4 provides a summary of the costs for all cases.

Exhibit 5-4 Cost summary for all cases

Pulverized Coal Boiler NGCC

PC Subcritical PC Supercritical State-of-the-art 2013 

F-Class

Case Name B11A B11B B12A B12B B31A B31B

COST

Total Plant Cost (2011$/kW) 1,960 3,467 2,026 3,524 685 1,481

Bare Erected Cost 1,582 2,665 1,646 2,716 561 1,117

Home Office Expenses 158 257 165 263 51 97

Project Contingency 220 427 216 430 73 193

Process Contingency 0 118 0 115 0 75

Total Overnight Cost (2011$/MM) 1,336 2,346 1,379 2,384 528 1,008

Total Overnight Cost (2011$/kW) 2,429 4,267 2,507 4,333 838 1,804

Owner's Costs 469 800 480 809 154 323

Total As-Spent Cost (2011$/kW) 2,755 4,865 2,842 4,940 901 1,945

COE ($/MWh) (excluding T&S) 82.1 133.5 82.3 133.2 57.6 83.3

Capital Costs 37.8 71.1 39.0 72.2 11.8 26.9

Fixed Costs 9.3 15.1 9.6 15.4 3.4 6.6

Variable Costs 9.2 15.1 9.1 14.7 1.7 4.0

Fuel Costs 25.7 32.2 24.6 30.9 40.7 45.9

COE ($/MWh) (including T&S) 82.1 143.5 82.3 142.8 57.6 87.3

CO2 T&S Costs 0.0 10.0 0.0 9.6 0.0 4.0

CO2 Captured Cost (excluding T&S), 

$/tonne N/A 56.2 N/A 58.2 N/A 71.1

CO2 Avoided Cost (including T&S), 

$/tonne N/A 91.0 N/A 89.4 N/A 93.8

*Cases without capture use conventional financing; all others use high-risk financial asssumptions 

consistent with NETL’s “QGESS: Cost Estimation Methodology for NETL Assessments of Power Plant 

Performance.” (1)

5.2.1 TOC and TASC

In Exhibit 5-5, the normalized components of TOC and overall TASC are shown for each 

technology.

The following conclusions can be drawn:

• Based on total overnight cost (TOC) in $/kW, NGCC capital costs are approximately 

34% and 42% of the PC capital costs for non-capture and capture cases, respectively. 

• The NGCC cost advantage over PC is partially enabled by the lack of emission

control equipment necessitated for the adherence to current regulations.

• The addition of CO2 capture technology significantly impacts all technologies. The 

TOC increases by 76 percent for subcritical PC, 73 percent for SC PC, and 115

percent for NGCC.
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Exhibit 5-5 Plant capital costs

Source: NETL

Note: TOC expressed in 2011 dollars. TASC expressed in 2011 to 2015 mixed-year dollars for PC and 

2011 to 2013 mixed-year dollars for NGCC

5.2.2 COE

A graph of the net plant efficiency (HHV basis) is provided in Exhibit 5-6.

The primary conclusions that can be drawn are:

• NGCC plant COEs are 70% and 61% of the PC plant COEs, for non-capture and capture 

cases, respectively. 

• The capital cost component represents the largest portion of the COE in PC cases, 

ranging from 46-51 percent of the total COE. The capital cost in NGCC cases represents 

21-31 percent of the total COE.

• The fuel cost component represents the largest portion of the COE in NGCC cases, 

ranging from 53-71 percent of the total COE. The fuel cost in PC cases represents 22-31 

percent of the total COE.

• CO2 T&S costs add between $4/MWh (NGCC) and $10/MWh (PC) to the COE, which is 

less than 7 percent of the total for all capture cases.

• While NGCC plants were impacted the most significantly by the addition of CO2 capture 

in terms of TOC, due to the small capital component of NGCC plants without CO2

capture (the cost of fuel is the most significant aspect of the COE for NGCC cases), the 

NGCC based plants incurred a smaller increase in COE than PC based plants (52 percent 

versus 74-75 percent).
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Exhibit 5-6 COE by cost component

Source: NETL

5.2.3 CO2 Emission Price Impact

In the event that future legislation assigns a cost to carbon emissions, all of the technologies 

examined in this report will become more expensive. The technologies without carbon capture 

will be impacted to a larger extent than those with carbon capture, and coal-based technologies 

will be impacted more than natural gas-based technologies.

The cost of CO2 avoided is shown in Exhibit 5-7 as the intersection of the CO2 capture PC case 

lines with the line for the SC PC non-capture case and the intersection of the NGCC CO2 capture 

case line with the line for the NGCC non-capture case. For example, the cost of CO2 avoided is 

$89.4/tonne ($81.1/ton) for SC PC and $93.8/tonne ($85.1/ton) for NGCC.

The curves in Exhibit 5-7 represent the study design conditions (capacity factor) and fuel prices 

used for each technology; namely an 85 percent capacity factor and $2.78/GJ ($2.94/MMBtu) for 

coal and $5.81/GJ ($6.13 /MMBtu) for natural gas.
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Exhibit 5-7 Impact of carbon emissions price on study technologies

Source: NETL

The following conclusions can be drawn from the carbon emissions price graph:

• The CO2 emission price impact on COE for the subcritical PC and SC PC cases is

indistinguishable for both the CO2 capture cases and the non-capture cases.

• At the baseline study conditions, non-capture SC PC diverges rapidly from noncapture NGCC as the CO2 emission cost increases. The lower carbon intensity of 

natural gas relative to coal and the greater efficiency of the NGCC technology 

account for this effect.

The impact of CO2 emissions price and natural gas price and the implications on the 

competitiveness of the capture technologies can also be considered in a “phase diagram” type 

plot, as shown in Exhibit 5-8. The lines in the plot represent cost parity between different pairs 

of technologies. 
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Exhibit 5-8 Lowest cost power generation options comparing NGCC and PC

Source: NETL

The plot demonstrates the following points:

• Non-capture plants are the low-cost option below a CO2 price of $78/tonne ($71/ton).

• NGCC is always preferred when natural gas prices are below $10/MMBtu (and a 

capacity factor of 85 percent).

• Coal plants are always preferred when natural gas prices are above $15/MMBtu.

5.2.4 CO2 Sales Price Impact

Sale of the captured CO2 for utilization and storage in CO2 enhanced oil recovery (EOR) has the 

potential to provide a revenue stream to both the SC PC and NGCC capture plant configurations. 

The plant gate CO2 sales price will ultimately depend on a number of factors including plant 

location and crude oil prices. The cost of CO2 captured represents the minimum CO2 plant gate 

sales price that will incentivize carbon capture in lieu of a defined reference non-capture plant. 

The cost of CO2 captured is shown in Exhibit 5-9 as the intersection of the CO2 capture PC case 

lines with the line for the SC PC non-capture case, and the intersection of the NGCC CO2

capture case line with the line for the NGCC non-capture case. For example, when looking at the 

exhibit, the cost of CO2 captured is $58/tonne ($53/ton) for SC PC and $71/tonne ($64/ton) for 

NGCC.

The curves in Exhibit 5-9 represent the study design conditions (capacity factor) and fuel prices 

used for each technology; namely 85 percent for PC and NGCC plants, and $2.78/GJ 

($2.94/MMBtu) for coal and $5.81/GJ ($6.13 /MMBtu) for natural gas.
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 Exhibit 5-9 Impact of carbon sales price on study technologies

Source: NETL

The following conclusions can be drawn from the carbon sales price graph:

• The CO2 sales price impact on COE for the subcritical PC and SC PC cases is

indistinguishable for both the CO2 capture cases and the non-capture cases.

• At the baseline study conditions, increasing the price of CO2 for EOR sales has a 

greater effect on PC than on NGCC. 

• At a CO2 sales price of $90/tonne, the cost of NGCC with CO2 capture is nearly equal 

to that of the subcritical PC and SC PC CO2 capture cases. 

Like technologies and CO2 emission pricing, the impact of CO2 sales price and natural gas price 

and the implications on the competitiveness of the capture technologies can also be considered in 

a “phase diagram” type plot, as shown in Exhibit 5-10. The lines in the plot represent COE

parity between different pairs of technologies. 
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Exhibit 5-10 Lowest cost power generation options comparing NGCC and coal

Source: NETL

The plot demonstrates the following points:

• Non-capture plants are the low-cost option below a first-year CO2 price of $56/tonne 

($51/ton).

• NGCC is preferred when natural gas prices are below $10/MMBtu with a CO2

revenue below $56/tonne (and a capacity factor of 85 percent). The natural gas price 

that provides parity between the various NGCC and PC cases drops off at higher CO2

revenues reaching $6/MMBtu at approximately $100/tonne ($91/ton).

5.3 Sensitivities

Exhibit 5-11 shows the COE sensitivity to fuel costs for the SC PC and NGCC cases. The bands 

for the SC PC cases represent a variance of the coal price from $2.21 - $3.69/MMBtu (±25% of 

the study value $2.94/MMBtu). This highlights regions of competitiveness of NGCC with SCPC 

systems for cases with and without CCS as a function of delivered natural gas price. As an 

example, at a coal cost of $3/MMBtu, the COE of the non-capture SC PC case equals noncapture NGCC at a natural gas price of approximately $10/MMBtu. Similarly, the SC PC and 

NGCC cases with capture have equivalent COEs at a coal price of $3/MMBtu and a natural gas 

price of approximately $13.5/MMBtu.
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Exhibit 5-11 COE sensitivity to fuel costs

Source: NETL

In Exhibit 5-12, the sensitivity of COE to CF is shown for all technologies. The subcritical and 

SC PC cases are nearly identical so that the curves are indistinguishable on the graph. The CF is 

plotted from 30 to 95 percent. The baseline CF is 85 percent for both PC and NGCC 

technologies. The curves plotted in Exhibit 5-12 for the PC and NGCC cases assume that the CF 

could be extended to 95 percent with no additional capital equipment.

Technologies with high capital cost (PC with CO2 capture) show a greater increase in COE with 

decreased CF. Conversely, NGCC with no CO2 capture is relatively flat because the COE is 

dominated by fuel charges, which decrease as the CF decreases. Conclusions that can be drawn 

from Exhibit 5-12 include:

• At any CF shown, NGCC has the lowest COE out of the non-capture cases. 

• The COE of NGCC with CO2 capture is the lowest of the capture technologies, and 

the advantage increases as the CF decreases. The relatively low capital cost 

component of NGCC accounts for the increased cost differential with decreased CF.

• At around a 60 percent CF, the COE of NGCC with CO2 capture crosses over with 

the COEs of both PC non-capture cases, with the NGCC case having a higher COE at 

increasing CFs.

30

50

70

90

110

130

150

170

190

3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

COE with CO2 T&S, $/MWh (2011$)

Delivered Natural Gas Price, $/MMBtu

SCPC w/ CCS ($2.94/MMBtu coal)

SCPC w/o CCS ($2.94/MMBtu coal)

$2.21 -

$3.69 per 

MMBtu

$2.21 -

$3.69 per 

MMBtu
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Exhibit 5-12 COE sensitivity to capacity factor

Source: NETL
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6 Revision Control

The initial issue of this report was published in May of 2007 and an updated revision was 

published in November of 2010. Subsequent to the re-issue date, updates have been made to 

various report sections. These modifications were made for clarification and aesthetic purposes 

as well as to update the report with more current performance and cost estimates and to bring all 

costs to a 2011 year dollar basis.

Exhibit 6-1 contains information added, changed, or deleted in successive revisions.

Exhibit 6-1 Record of revisions

Revision 

Number

Revision 

Date Description of Change Comments

1 8/23/07

Added disclaimer to 

Executive Summary and 

Introduction

Disclaimer involves clarification on extent of 

participation of technology vendors.

Removed reference to 

Cases 7 and 8 in Exhibits 

ES-1 and 1-1 since they no 

longer exist.

SNG cases moved to Volume 2 of this report as 

explained in the Executive Summary and Section 

1.

Added Section 2.8

Explains differences in IGCC TPC estimates in 

this report versus costs reported by other 

sources.

Added Exhibit ES-14

Mercury emissions are now shown in a separate 

exhibit from SO2, NOx and PM because of the 

different y-axis scale.

Corrected PC and NGCC 

CO2 capture case water 

balances

The capture process cooling water requirement 

for the PC and NGCC CO2 capture cases was 

overstated and has been revised.

Replaced Exhibits ES-4, 3-

121, 4-52 and 5-30

The old water usage figures were in gpm 

(absolute) and in the new figures the water 

numbers are normalized by net plant output.

Updated Selexol process 

description

Text was added to Section 3.1.5 to describe how 

H2 slip was handled in the models.

Revised PC and NGCC 

CO2 capture case energy 

balances (Exhibits 4-21, 4-

42 and 5-21)

The earlier version of the energy balances 

improperly accounted for the capture process 

heat losses. The heat removed from the capture

process is rejected to the cooling tower.

Corrected Exhibit 4-13 and 

Exhibit 4-27.

Sensible heat for combustion air in the two NGCC 

cases was for only one of the two combustion 

turbines – corrected to account for both turbines

2 10/27/10

Updated circulating water 

flow rate values in Section 

3.1.8.

Revision 1 changes to capture system cooling 

water flow rate were not made in the text in 

Section 3.1.8 (Circulating Water System).

Added Supplemental 

Chapter 6 “Effect of Higher 

Natural Gas Prices and 

Dispatch-Based Capacity 

Factors”

Added Supplemental 

Chapter 7 “Dry and Parallel 

Cooling”
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228

Revision 

Number

Revision 

Date Description of Change Comments

Added Supplemental 

Chapter 8 “GEE IGCC in 

Quench-Only Configuration 

with CO2 Capture” 

Added Supplemental 

Chapter 9 “Sensitivity to 

MEA System Performance 

and Cost Bituminous 

Baseline Case B12BA”

Updated Aspen models

Major Aspen model updates included:

• Converting FORTRAN code based steam 

cycles to Aspen blocks

• Using the Peng-Robinson property method in 

the Aspen gasifier section

• Modifying the AGR used in the IGCC cases 

to more closely represent commercially 

available technology

• Increasing the capture efficiency of the EGasTM plant with capture to achieve 90 

percent

• Correcting a steam condition error in the 

supercritical PC cases with capture

Updated case performance 

results

Major updates included:

• Revising the water balances to include 

withdrawal and consumption

• CAD-based HMB diagrams were replaced 

with Visio versions

Completed updating case 

economic results

Major updates included:

• Adding owner’s costs to the total plant costs 

to generate total overnight cost

• Updating fuel costs

• Revising the T&S methodology to include the 

July, 2007 Handy-Whitman Index, pore space 

acquisition costs, and liability costs

• Re-costing of cases based on the updated 

performance results

• Switching to COE as the primary cost metric 

(as opposed to levelized COE)

Updated report tables, 

figures and text to reflect 

the revision 2 changes

2a 9/19/2013

Section 2.7.1 was revised 

to clarify the text that 

explains the level of 

technology maturity 

reflected in the plant level 

cost estimates.
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229

Revision 

Number

Revision 

Date Description of Change Comments

3 7/6/2015

Volume 1 has been split 

into two sub volumes.

Major updates included:

• IGCC cases are reported in Volume 1b with a 

cost-only update (issued as an update to 

revision 2a)

• PC and NGCC cases are reported in Volume 

1a with a cost and performance update 

(issued as revision 3)

• Executive summary significantly revised and 

shortened

Results analysis section added

Separated Supplemental 

Chapter 6 “Effect of Higher 

Natural Gas Prices and 

Dispatch-Based Capacity 

Factors” into a stand alone 

report.

Separated Supplemental 

Chapter 7 “Impact of Dry 

and Parallel Cooling 

Systems on Cost and 

Performance of Fossil Fuel 

Power Plants” into a stand 

alone report.”

Removed Supplemental 

Chapter 9 “Sensitivity to 

MEA System Performance 

and Cost Bituminous 

Baseline Case 12A”

Updated the environmental 

targets to current limits 

published by the EPA and 

presented in Section 2.4

MATS and NSPS regulate SO2, NOx, Filterable 

PM, Hg, and HCl on a lb/MWh-gross basis.

Updated Section 2.5

covering Capacity Factors

Additional information has been included that 

supports the assumptions made regarding the 

capacity factors used for each technology type.

Removed portions of 

Section 2.7 concerning cost 

estimating methodology

Many QGESS documents have been published 

that detail information generic to a number of 

studies published by NETL. In an effort to reduce 

the size of this report, text provided in these 

QGESS documents has been removed and 

references have been inserted that provide the 

QGESS document title and revision notation.

Cost of CO2 Captured 

methodology and results 

have been added.

The Cost of CO2 avoided methodology has been 

moved from the executive summary and 

combined with the Cost of CO2 Captured 

methodology in Section 2.7.4.

Section 2.8 has been 

updated to reflect current 

information
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

230

Revision 

Number

Revision 

Date Description of Change Comments

The Combustion turbine

performance characteristics 

have been updated

The performance provided in this report reflects a 

state-of-the-art 2013 F-class combustion turbine 

for NGCC cases

Updated Natural Gas 

Composition Methanethiol was added to the composition

Improved the BFD 

depiction of the HRSGs in 

NGCC Case 

All cases have been 

updated to a new case 

naming convention.

Ex. Revision 2’s Case 9 is now Case B11A

Performance tables have 

been updated

Major updates include:

• Table is split into two sections

o Performance summary

o Plant power and auxiliary load 

breakdown

• PC

o Steam generator efficiency

o Excess air

o Steam turbine cycle efficiency and 

heat rate

o LHV basis efficiency and heat rate

• NGCC

o Combustion turbine efficiency

o Steam turbine efficiency and heat 

rate

o LHV basis efficiency and heat rate

Updated case performance 

results

Major updates included:

• Added particle concentration to emissions 

results

• Updated Energy Balance tables by adding 

Motor Losses and Design Allowances, NonCondenser cooling tower loads, and ambient 

losses
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

231

Revision 

Number

Revision 

Date Description of Change Comments

Updated Aspen models

Major Aspen model updates included:

• Updated steam turbine efficiency

• Incorporated exhaust losses into LP turbine 

efficiency

• Changed Capture system in NGCC and PC 

cases to Cansolv system

• Updated many pressure drops to percent of 

inlet

• Corrected temperature approaches

• Corrected pressure drops across various 

systems

• Converted to Aspen 8.2

• Converted to Hierarchy models

• Converted steam property method to 

SteamNBS

• Updated CO2 compression system to front 

loaded 8 stage design in NGCC and PC 

cases

• ACI and DSI systems were added to PC 

cases

• Boiler air preheater exit temperature was 

reduced to 300°F

• Excess O2 is controlled at the flue gas exiting 

the boiler at 2.7% dry

• Combustion turbine for NGCC cases was 

updated

• Added steam extraction for CO2 dryer

Completed updating case 

economic results

Major updates included:

• Updating to 2011 year dollars

• Updating the T&S costing methodology

• Updating the capital charge factors

• Updating fuel prices

• Re-costing of cases based on the updated 

performance results

• Updating cost estimates based on recently

obtained vendor quotes

Updated report tables, 

figures and text to reflect 

the revision 3 changes
Cost and Performance Baseline for Fossil Energy Plants Volume 1: Revision 3

232

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www.netl.doe.gov

Pittsburgh, PA • Morgantown, WV • Albany, OR • Sugar Land, TX • Anchorage, AK

(800) 553-7681

Tim Fout

Timothy.Fout@NETL.DOE.GOV

Mark Woods

Mark.Woods@CONTR.NETL.DOE.GOV