Cost and Performance 

Baseline for Fossil Energy 

Plants

Volume 3c: Natural Gas 

Combined Cycle at Elevation

March 2011

DOE/NETL-2010/1396
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 3c: NATURAL GAS COMBINED CYCLE AT 

ELEVATION

DOE/NETL-2010/1396

Final Report

March 2011

NETL Contact:

James B. Black

Office of Program Planning & Analysis, Performance Division

National Energy Technology Laboratory

www.netl.doe.gov
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NETL Viewpoint

Background

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

availability of ultra-clean (“zero” emissions), abundant, low-cost, domestic electricity and energy 

(including hydrogen) to fuel economic prosperity and strengthen energy security. A broad 

portfolio of technologies is being developed within the Clean Coal Program to accomplish this 

objective. Ever increasing technological enhancements are in various stages of the research 

“pipeline,” and multiple paths are being pursued to create a portfolio of promising technologies 

for development, demonstration, and eventual deployment. The technological progress of recent 

years has created a remarkable new opportunity for coal. Advances in technology are making it 

possible to generate power from fossil fuels with great improvements in the efficiency of energy 

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

long-term impact of fossil energy use on the Earth’s climate. The objective of the Clean Coal 

RD&D Program is to build on these advances and bring these building blocks together into a 

new, revolutionary concept for future coal-based power and energy production.

Objective

To establish baseline performance and cost estimates for today’s fossil energy plants, it is 

necessary to look at the current state of technology. Such a baseline can be used to benchmark 

the progress of the Fossil Energy RD&D portfolio. This report documents an accurate, 

independent assessment of the cost and performance for Natural Gas Combined Cycle (NGCC) 

plants with and without carbon dioxide (CO2) capture and sequestration at two site elevations in 

Montana and North Dakota. The NGCC cases are a subset of a study that also includes 

Integrated Gasification Combined Cycle (IGCC) and combustion cases.

Approach

The power plant configurations analyzed in this study were modeled using the ASPEN Plus® 

(Aspen) modeling program. Performance and process limits were based upon published reports, 

information obtained from vendors and users of the technology, cost and performance data from 

design/build utility projects, and/or best engineering judgment. Capital and operating costs were 

estimated by WorleyParsons based on simulation results and through a combination of existing 

vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. 

Operation and maintenance (O&M) costs and the cost for transporting, storing, and monitoring 

(TS&M) carbon dioxide (CO2) in the cases with carbon capture were also estimated based on 

reference data and scaled estimates. The cost of electricity (COE) was determined for all plants

assuming investor-owned utility (IOU) financing. The initial results of this analysis were 

subjected to a significant peer review by industry experts, academia and government research 

and regulatory agencies. Based on the feedback from these experts, the report was updated both 

in terms of technical content and revised costs.

Fossil Energy RD&D aims at improving the performance and cost of clean coal power systems 

including the development of new approaches to capture and sequester greenhouse gases 

(GHGs). Improved efficiencies and reduced costs are required to improve the competitiveness of 

these systems in today’s market and regulatory environment as well as in a carbon constrained 

scenario. The results of this analysis provide a starting point from which to measure the progress 

of RD&D achievements.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

I

Table of Contents

TABLE OF CONTENTS ..............................................................................................................I

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

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

ACKNOWLEDGMENTS..........................................................................................................VI

LIST OF ACRONYMS AND ABBREVIATIONS.................................................................VII

EXECUTIVE SUMMARY ...........................................................................................................1

Energy Efficiency .....................................................................................................................4

Cost Results..............................................................................................................................5

Cost of Electricity ....................................................................................................................6

First Year Cost of CO2 Avoided ...............................................................................................9

1. INTRODUCTION................................................................................................................11

2. GENERAL EVALUATION BASIS ...................................................................................13

2.1 SITE CHARACTERISTICS ..................................................................................................13

2.2 NATURAL GAS CHARACTERISTICS..................................................................................15

2.3 ENVIRONMENTAL TARGETS ............................................................................................16

2.4 CAPACITY FACTOR .........................................................................................................17

2.5 RAW WATER WITHDRAWAL AND CONSUMPTION ...........................................................17

2.6 COST ESTIMATING METHODOLOGY ................................................................................18

2.6.1 Capital Costs..............................................................................................................19

2.6.2 Operations and Maintenance Costs...........................................................................27

2.6.3 CO2 Transport, Storage and Monitoring...................................................................28

2.6.4 Finance Structure, Discounted Cash Flow Analysis, and COE ................................32

3. NGCC POWER PLANT PROCESS DESCRIPTIONS...................................................41

3.1 NGCC COMMON PROCESS AREAS..................................................................................41

3.1.1 Natural Gas Supply System........................................................................................41

3.1.2 Combustion Turbine...................................................................................................41

3.1.3 Heat Recovery Steam Generator ...............................................................................43

3.1.4 NOx Control System...................................................................................................44

3.1.5 Carbon Dioxide Recovery Facility ............................................................................44

3.1.6 Steam Turbine ............................................................................................................49

3.1.7 Water and Steam Systems..........................................................................................50

3.1.8 Buildings and Structures............................................................................................51

3.1.9 Accessory Electric Plant............................................................................................52

3.1.10 Instrumentation and Control..................................................................................52

3.2 NGCC PROCESS DESCRIPTION .......................................................................................52

3.2.1 Key System Assumptions............................................................................................53

3.2.2 Sparing Philosophy....................................................................................................54

3.3 CASES S31A AND L31A PROCESS DESCRIPTION ............................................................55

3.3.1 Case S31A – Performance Results.............................................................................57

3.3.2 Case S31A – Major Equipment List...........................................................................64

3.3.3 Case S31A – Cost Estimating ....................................................................................70

3.3.4 Case L31A – Performance Results ............................................................................77

3.3.5 Case L31A – Major Equipment List ..........................................................................84
Cost and Performance Baseline - Volume 3c (NGCC Cases)

II

3.3.6 Case L31A – Cost Estimating ....................................................................................89

3.4 CASES S31B AND L31B PROCESS DESCRIPTION.............................................................96

3.4.1 Case S31B – Performance Results.............................................................................97

3.4.2 Case S31B – Major Equipment List.........................................................................106

3.4.3 Case S31B – Cost Estimating ..................................................................................112

3.4.4 Case L31B – Performance Results ..........................................................................119

3.4.5 Case L31B – Major Equipment List ........................................................................128

3.4.6 Case L31B – Cost Estimating ..................................................................................133

4. SUMMARY ........................................................................................................................141

5. REFERENCES...................................................................................................................149
Cost and Performance Baseline - Volume 3c (NGCC Cases)

III

List of Exhibits

Exhibit ES-1 Case Descriptions..................................................................................................... 2

Exhibit ES-2 Cost and Performance Summary and Environmental Profile for NGCC Cases...... 3

Exhibit ES-3 Net Plant Efficiency (HHV Basis)........................................................................... 4

Exhibit ES-4 Total Overnight Cost................................................................................................ 6

Exhibit ES-5 Economic Parameters Used to Calculate COE ........................................................ 7

Exhibit ES-6 COE by Cost Component......................................................................................... 8

Exhibit ES-7 COE Sensitivity to Fuel Costs.................................................................................. 9

Exhibit ES-8 COE Sensitivity to CF............................................................................................ 10

Exhibit ES-9 CO2 Avoided Costs................................................................................................ 10

Exhibit 2-1 Montana Site Ambient Conditions ........................................................................... 13

Exhibit 2-2 North Dakota Site Ambient Conditions.................................................................... 13

Exhibit 2-3 Site Characteristics ................................................................................................... 14

Exhibit 2-4 Natural Gas Composition.......................................................................................... 15

Exhibit 2-5 Environmental Targets for NGCC Cases.................................................................. 16

Exhibit 2-6 Capital Cost Levels and their Elements.................................................................... 19

Exhibit 2-7 Features of an AACE Class 4 Cost Estimate............................................................ 20

Exhibit 2-8 AACE Guidelines for Process Contingency............................................................. 24

Exhibit 2-9 Owner’s Costs Included in TOC................................................................................ 25

Exhibit 2-10 TASC/TOC Factors ................................................................................................ 27

Exhibit 2-11 CO2 Pipeline Specification ..................................................................................... 29

Exhibit 2-12 Deep Saline Aquifer Specification ......................................................................... 29

Exhibit 2-13 Global Economic Assumptions .............................................................................. 33

Exhibit 2-14 Financial Structure for Investor Owned Utility High and Low Risk Projects........ 34

Exhibit 2-15 Illustration of COE Solutions using DCF Analysis................................................ 36

Exhibit 2-16 PC with CCS in Current 2007 Dollars.................................................................... 37

Exhibit 2-17 Capital Charge Factors for COE Equation ............................................................. 38

Exhibit 2-18 COE and LCOE Summary...................................................................................... 39

Exhibit 2-19 Baseline SC PC Results for CO2 Cost Calculation................................................. 39

Exhibit 3-1 Combustion Turbine Typical Scope of Supply......................................................... 42

Exhibit 3-2 Fluor Econamine FG Plus Typical Flow Diagram ................................................... 46

Exhibit 3-3 CO2 Compressor Interstage Pressures ...................................................................... 49

Exhibit 3-4 NGCC Plant Study Configuration Matrix ................................................................ 53

Exhibit 3-5 NGCC Balance of Plant Assumptions...................................................................... 54

Exhibit 3-6 Cases S31A and L31A Process Flow Diagram, NGCC without CO2 Capture......... 56

Exhibit 3-7 Case S31A Stream Table, NGCC without CO2 Capture .......................................... 57

Exhibit 3-8 Case S31A Plant Performance Summary ................................................................. 58

Exhibit 3-9 Case S31A Air Emissions......................................................................................... 59

Exhibit 3-10 Cases S31A Carbon Balance .................................................................................. 60

Exhibit 3-11 Case S31A Water Balance...................................................................................... 60

Exhibit 3-12 Case S31A Heat and Mass Balance, NGCC without CO2 Capture ........................ 61

Exhibit 3-13 Case S31A Overall Energy Balance (0°C [32°F] Reference) ................................ 63

Exhibit 3-14 Case S31A Total Plant Cost Summary................................................................... 71

Exhibit 3-15 Case S31A Total Plant Cost Details....................................................................... 72
Cost and Performance Baseline - Volume 3c (NGCC Cases)

IV

Exhibit 3-16 Case S31A Owner’s Costs...................................................................................... 75

Exhibit 3-17 Case S31A Initial and Annual Operating and Maintenance Cost Summary .......... 76

Exhibit 3-18 Case L31A Stream Table, NGCC without CO2 Capture......................................... 77

Exhibit 3-19 Case L31A Plant Performance Summary ................................................................ 78

Exhibit 3-20 Case L31A Air Emissions....................................................................................... 79

Exhibit 3-21 Cases L31A Carbon Balance .................................................................................. 80

Exhibit 3-22 Case L31A Water Balance...................................................................................... 80

Exhibit 3-23 Case L31A Heat and Mass Balance, NGCC without CO2 Capture........................ 81

Exhibit 3-24 Case L31A Overall Energy Balance (0°C [32°F] Reference) ................................ 83

Exhibit 3-25 Case L31A Total Plant Cost Summary................................................................... 90

Exhibit 3-26 Case L31A Total Plant Cost Details....................................................................... 91

Exhibit 3-27 Case L31A Owner’s Costs...................................................................................... 94

Exhibit 3-28 Case L31A Initial and Annual Operating and Maintenance Cost Summary.......... 95

Exhibit 3-29 Cases S31B and L31B Process Flow Diagram, NGCC with CO2 Capture ............ 96

Exhibit 3-30 Case S31B Stream Table, NGCC with CO2 Capture ............................................. 98

Exhibit 3-31 Case S31B Plant Performance Summary................................................................ 99

Exhibit 3-32 Case S31B Air Emissions..................................................................................... 100

Exhibit 3-33 Cases S31B Carbon Balance................................................................................. 101

Exhibit 3-34 Case S31B Water Balance .................................................................................... 101

Exhibit 3-35 Case S31B Heat and Mass Balance, NGCC with CO2 Capture ........................... 103

Exhibit 3-36 Case S31B Overall Energy Balance (0°C [32°F] Reference)............................... 105

Exhibit 3-37 Case S31B Total Plant Cost Summary ................................................................. 113

Exhibit 3-38 Case S31B Total Plant Cost Details ..................................................................... 114

Exhibit 3-39 Case S31B Owner’s Costs.................................................................................... 117

Exhibit 3-40 Case S31B Initial and Annual Operating and Maintenance Cost Summary ........ 118

Exhibit 3-41 Case L31B Stream Table, NGCC without CO2 Capture ...................................... 120

Exhibit 3-42 Case L31B Plant Performance Summary ............................................................. 121

Exhibit 3-43 Case L31B Air Emissions..................................................................................... 122

Exhibit 3-44 Case L31B Carbon Balance.................................................................................. 123

Exhibit 3-45 Case L31B Water Balance.................................................................................... 123

Exhibit 3-46 Case L31B Heat and Mass Balance, NGCC without CO2 Capture ...................... 125

Exhibit 3-47 Case L31B Overall Energy Balance (0°C [32°F] Reference) .............................. 127

Exhibit 3-48 Case L31B Total Plant Cost Summary................................................................. 134

Exhibit 3-49 Case L31B Total Plant Cost Details..................................................................... 135

Exhibit 3-50 Case L31B Owner’s Costs.................................................................................... 138

Exhibit 3-51 Case L31B Initial and Annual Operating and Maintenance Cost Summary ........ 139

Exhibit 4-1 Performance and Cost Results for NGCC Cases.................................................... 141

Exhibit 4-2 Total Overnight Costs............................................................................................. 142

Exhibit 4-3 COE of NGCC Cases.............................................................................................. 143

Exhibit 4-4 Sensitivity of COE to Capacity Factor in NGCC Cases......................................... 144

Exhibit 4-5 Sensitivity of COE to Fuel Price in NGCC Cases.................................................. 144

Exhibit 4-6 CO2 Avoided Costs................................................................................................. 146

Exhibit 4-7 Water Usage in NGCC Costs.................................................................................. 147
Cost and Performance Baseline - Volume 3c (NGCC Cases)

V

PREPARED BY

Research and Development Solutions, LLC (RDS)

:

UPDATED BY

Energy Sector Planning and Analysis (ESPA)

:

Vincent H. Chou

Booz Allen Hamilton

John L. Haslbeck

Booz Allen Hamilton

Allison Kyle

Booz Allen Hamilton

Eric Lewis

Booz Allen Hamilton

Lora L. Pinkerton

WorleyParsons

Vasant Shah

Booz Allen Hamilton

Elsy Varghese

WorleyParsons

Mark C. Woods

Booz Allen Hamilton

DOE Contract # DE-FE0004001
Cost and Performance Baseline - Volume 3c (NGCC Cases)

VI

Acknowledgments

This report was initially prepared by Research and Development Solutions, LLC (RDS) for 

the United States Department of Energy’s (DOE) National Energy Technology Laboratory 

(NETL) under DOE NETL Contract Number DE-AM26-04NT41817; Subtask 41817-

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

Number DE-FE0004001, Energy Sector Planning and Analysis.

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

NETL staff, particularly:

John Wimer, Director of Office of Program Planning & Analysis

Wally Shelton

James Black

Jeff Hoffmann

Robert James
Cost and Performance Baseline - Volume 3c (NGCC Cases)

VII

AACE Association for the Advancement of Cost Engineering

LIST OF ACRONYMS AND ABBREVIATIONS

AC Alternating current

acfm Actual cubic feet per minute

AEO Annual Energy Outlook

Al Aluminum

ANSI American National Standards Institute

Aspen Aspen Plus®

BACT Best available control technology

BEC Bare erected cost

BFD Block flow diagram

BFW Boiler feed water

BLS Bureau of Labor Statistics

Btu British thermal unit

Btu/hr British thermal unit per hour

Btu/kWh British thermal unit per kilowatt hour

Btu/lb British thermal unit per pound

Btu/scf British thermal unit per standard cubic foot

CCF Capital charge factor

CDR Carbon dioxide recovery

CF Capacity factor

CFB Circulating fluidized bed

CL Closed-loop

cm Centimeter

CO2 Carbon dioxide

COE Cost of electricity

CS Carbon steel

CWP Circulating water pump

CT Combustion turbine

CTG Combustion turbine-generator

CWT Cold water temperature

DC Direct current

DCS Distributed control system

DI De-ionized

Dia. Diameter

DLN Dry low NOx

DOE Department of Energy

EAF Equivalent availability factor

EIA Energy Information Administration

EPA Environmental Protection Agency

EPC Engineer/procure/construct

EPCM Engineering/procurement/construction management
Cost and Performance Baseline - Volume 3c (NGCC Cases)

VIII

FEED Front-End Engineering Design

FW Feedwater

FOAK First-of-a-kind

ft Foot, feet

gal Gallon

GCV Gross calorific value

GDP Gross domestic product

GJ Gigajoule

GJ/hr Gigajoule per hour

gpm Gallons per minute

gr/100 scf grains per one hundred standard cubic feet

h, hr Hour

H2 Hydrogen

Hg Mercury

HHV Higher heating value

hp Horsepower

HP High pressure

HRSG Heat recovery steam generator

HSS Heat stable salts

HVAC Heating, ventilating, and air conditioning

HWT Hot water temperature

Hz Hertz

IEA International Energy Agency

IGCC Integrated gasification combined cycle

in Inches

IOU Investor-owned utility

IP Intermediate pressure

ISO International Standards Organization

kg/GJ Kilogram per gigajoule

kg/hr Kilogram per hour

kJ Kilojoules

kJ/kg Kilojoules per kilogram

km Kilometers

kV Kilovolt

kW Kilowatt

kWe Kilowatts electric

kWt Kilowatts thermal

LAER Lowest Achievable Emission Rate

CH4 Methane

lb Pound

lb/hr Pounds per hour

lb/MMBtu Pounds per million British thermal units

lb/MWh Pounds per megawatt hour
Cost and Performance Baseline - Volume 3c (NGCC Cases)

IX

LCOE Levelized cost of electricity

LHV Lower heating value

LNB Low NOx burner

LP Low pressure

lpm Liters per minute

m Meters

m3/min Cubic meter per minute

md Millidarcy (a measure of permeability)

MEA Monoethanolamine

Mills/kWh Tenths of a cent per kilowatt-hour

MJ/Nm3 Megajoule per normal cubic meter

MJ/scm Megajoule per standard cubic meter

MMBtu Million British thermal units (also shown as 106 Btu)

MMBtu/hr Million British thermal units (also shown as 106 Btu) per hour

MMkJ Million kilojoules (also shown as 106 kJ)

MMkJ/hr Million kilojoules (also shown as 106 kJ) per hour

MPa Megapascals

MVA Mega volt-amps

MW Megawatts

MWh Megawatt-hour

N/A Not applicable

NAAQS National Ambient Air Quality Standards

NEMA National Electrical Manufacturers Association

NERC North American Electric Reliability Council

NETL National Energy Technology Laboratory

NGCC Natural gas combined cycle

NH3 Ammonia

Nm3 Normal cubic meter

NO2 Nitrogen oxide

NOAK Nth-of-a-kind

NOx Oxides of nitrogen

NSPS New Source Performance Standards

NSR New Source Review

NDL site North Dakota Lignite Site

O2 Oxygen

O&M Operation and maintenance

OCFn Category n fixed operating cost for the initial year of operation

OCVn Category n variable operating cost for the initial year of operation

OSAP Office of Systems, Analyses and Planning

PC Pulverized coal

PM Particulate matter

POTW Publicly Owned Treatment Works

PO Purchase order
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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ppmv Parts per million volume

ppmvd Parts per million volume dry 

PRB Powder River Basin coal region

PSD Prevention of Significant Deterioration

psia Pounds per square inch absolute

psig Pounds per square inch gage

Qty Quantity

RDS Research and Development Solutions, LLC

RH Reheater

S Sulfur

SC Supercritical

scfm Standard cubic feet per minute

SCR Selective catalytic reduction process or equipment

SO2 Sulfur dioxide

SOx Oxides of sulfur

SS Stainless steel

STG Steam turbine generator

TCR Total capital requirement

TASC Total as-spent cost

TEWAC Totally Enclosed Water-to-Air Cooled

TiO2 Titanium dioxide

tonne Metric Ton (1000 kg)

TOC Total overnight cost

TPC Total plant cost

TPD Tons per day

tph Tons per hour

TS&M Transport, storage and monitoring

U.S. United States

USC Ultra-supercritical

yr Year

V2O5 Vanadium pentoxide

vol% Volume percent

WB Wet bulb

WO3 Tungsten trioxide

wt% Weight percent

$/MMBtu Dollars per million British thermal units

$/MMkJ Dollars per million kilojoule

$/MWh Dollars per megawatt hour

% Percent
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Cost and Performance Baseline - Volume 3c (NGCC Cases)

1

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

performance of electricity production from natural gas combined cycle (NGCC) power systems

using a consistent technical and economic approach that accurately reflects current market 

conditions for plants using commercially available technology. This document is Volume 3c of 

the Low Rank Coal Baseline Reports, which are part of a four volume series consisting of the 

following:

EXECUTIVE SUMMARY

• Volume 1: Bituminous Coal and Natural Gas to Electricity

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

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

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

The cost and performance of the various fossil fuel-based technologies will most likely 

determine which combination of technologies will be utilized to meet the demands of the power 

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

• Capital and operating costs

• Overall energy efficiency

• Fuel prices

• Cost of electricity (COE)

• Availability, reliability, and environmental performance

• Current and potential regulation of air, water, and solid waste discharges from fossilfueled 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 Programs

Four NGCC plant configurations were analyzed as listed in Exhibit ES-1. Two plants were 

located in Montana (with and without CO2 capture) and two in North Dakota (with and without 

CO2 capture). The plant locations are the same that were used to evaluate gasification and 

combustion based systems in Volumes 3a and 3b of this study. The Montana site corresponds to 

cases that used Powder River Basin (PRB) coal in the gasification and combustion reports while

the North Dakota site corresponds to the cases that used lignite coal. While the cases in this 

report all use natural gas, references to PRB and lignite coals are used to distinguish between the 

two plant locations with the primary difference being elevation. The Montana site elevation is 

1,036 meters (m) (3,400 feet [ft]) and the North Dakota site is 579 m (1,900 ft).

The methodology included performing steady-state simulations of the various technologies using 

the Aspen Plus® (Aspen) modeling program. The resulting mass and energy balance data from 

the Aspen model were used to size major pieces of equipment. These equipment sizes formed 

the basis for cost estimating. Performance and process limits were based upon published reports, 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

2

information obtained from vendors and users of the technology, performance data from 

design/build utility projects, and/or best engineering judgment. Capital and operating costs were 

estimated based on simulation results and through a combination of vendor quotes, scaled 

estimates from previous design/build projects, or a combination of the two. Baseline fuel costs 

for this analysis were determined using data from the Energy Information Administration’s 

(EIA) 2008 Annual Energy Outlook (AEO). The 2007 cost used for natural gas is $6.76/ million 

kilojoules (MMkJ) ($7.13/ million British thermal units [MMBtu]) on a higher heating value 

(HHV) basis and in June 2007 United States (U.S.) dollars.

Exhibit ES-1 Case Descriptions

Case Unit 

Cycle

Steam Cycle, 

psig/°F/°F

Boiler 

Technology Location CO2 Separation

S31A NGCC 2400/1050/1050 HRSG Montana -

S31B NGCC 2400/1050/1050 HRSG Montana Amine Absorber

L31A NGCC 2400/1050/1050 HRSG North Dakota -

L31B NGCC 2400/1050/1050 HRSG North Dakota Amine Absorber

All plant configurations were evaluated based on installation at a greenfield site (Montana or

North Dakota). To compare the plants on an equivalent basis, it was assumed that these plants 

would be dispatched any time they are available. The study capacity factor (CF), 85 percent,

was chosen to reflect the maximum availability for NGCC plants. Since variations in fuel costs 

and other factors can influence dispatch order and CF, sensitivity of levelized COE to CF was 

evaluated and is presented later in this Executive Summary (Exhibit ES-8).

The nominal net plant output for this study was set to approximately 500 megawatts (MW) to 

satisfy combustion turbine (CT) constraint as CTs are available in discrete sizes. The actual net 

output varies by site and carbon capture requirement. The heat recovery boilers and steam 

turbines in all cases are readily available in a wide range of capacities.

Exhibit ES-2 shows the cost, performance, and environmental profile summary for all cases

which are discussed below.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit ES-2 Cost and Performance Summary and Environmental Profile for NGCC 

Cases

PERFORMANCE Case S31A Case L31A Case S31B Case L31B

CO2 Capture 0% 0% 90% 90%

Gross Power Output (kWe) 522,100 557,000 470,000 501,600

Auxiliary Power Requirement (kWe) 9,690 10,020 34,940 36,960

Net Power Output (kWe) 512,410 546,980 435,060 464,640

Natural Gas Flowrate (lb/hr) 153,559 163,560 153,559 163,560

HHV Thermal Input (kWth) 1,014,787 1,080,880 1,014,787 1,080,880

Net Plant HHV Efficiency (%) 50.5% 50.6% 42.9% 43.0%

Net Plant HHV Heat Rate (Btu/kWh) 6,757 6,743 7,959 7,938

Raw Water Withdrawal (gpm/MWnet) 2.1 2.1 7.1 7.1

Process Water Discharge (gpm/MWnet) 0.5 0.5 1.8 1.8

Raw Water Consumption (gpm/MWnet) 1.6 1.6 5.3 5.3

CO2 Emissions (lb/MMBtu) 118 118 12 12

CO2 Emissions (lb/MWhgross) 784 783 87 87

CO2 Emissions (lb/MWhnet) 799 797 94 94

SO2 Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible

SO2 Emissions (lb/MWhgross) Negligible Negligible Negligible Negligible

NOx Emissions (lb/MMBtu) 0.009 0.009 0.009 0.009

NOx Emissions (lb/MWhgross) 0.060 0.060 0.067 0.066

PM Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible

PM Emissions (lb/MWhgross) Negligible Negligible Negligible Negligible

Hg Emissions (lb/TBtu) Negligible Negligible Negligible Negligible

Hg Emissions (lb/MWhgross) Negligible Negligible Negligible Negligible

COST

Total Plant Cost (2007$/kW) 666 637 1,315 1,267

Total Overnight Cost (2007$/kW) 817 782 1,607 1,548

 Bare Erected Cost 546 521 994 957

 Home Office Expenses 46 44 84 81

 Project Contingency 74 71 174 168

 Process Contingency 0 0 62 61

 Owner's Costs 151 145 291 281

Total Overnight Cost (2007$ x 1,000) 418,817 427,473 698,949 719,155

Total As Spent Capital (2007$/kW) 879 840 1,732 1,668

COE (mills/kWh, 2007$)1 64.4 63.6 92.9 91.4

 CO 2 TS&M Costs 0.0 0.0 3.4 3.3

 Fuel Costs 48.2 48.1 56.7 56.6

 Variable Costs 1.4 1.3 2.7 2.6

 Fixed Costs 3.4 3.2 6.1 5.9

 Capital Costs 11.5 11.0 24.0 23.1

LCOE (mills/kWh, 2007$)1 81.7 80.6 117.8 115.8

 NGCC with Advanced F Class

1 COE and Levelized COE are defined in Section 2.6
Cost and Performance Baseline - Volume 3c (NGCC Cases)

4

The net plant efficiency (HHV basis) for all four cases is shown in 

Energy Efficiency

Exhibit ES-3. The primary 

conclusions that can be drawn are:

• The CO2 capture results in an efficiency penalty of 7.6 absolute percent, relative to the 

non-capture case at both locations.

• The increase in elevation, going from the NDL to the Montana site, has minimal impact 

on efficiency but does cause a derate in the gas turbine compressor, reducing the net plant 

output by six percent for both CO2 capture and non-capture cases.

Exhibit ES-3 Net Plant Efficiency (HHV Basis)

50.5%

42.9%

50.6%

43.0%

0%

10%

20%

30%

40%

50%

60%

70%

NGCC PRB NGCC PRB w/ Capture NGCC Lig NGCC Lig w/ Capture

Efficieny, % (HHV Basis)

Montana Site

Elevation: 3,400 ft

North Dakota Site

Elevation: 1,900 ft
Cost and Performance Baseline - Volume 3c (NGCC Cases)

5

The Total Plant Cost (TPC) for each technology was determined through a combination of 

vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. 

TPC includes all equipment (complete with initial chemical and catalyst loadings), materials, 

labor (direct and indirect), engineering and construction management, and contingencies (process 

and project). Owner’s costs, including preproduction costs, inventory capital, initial cost for 

catalyst and chemicals, land, financing costs and other owner’s costs were added to TPC to 

generate total overnight cost (TOC). Property taxes and insurance were included in the fixed 

operating costs as an additional owner’s cost. Escalation and interest on debt during the capital 

expenditure period were estimated and added to the TOC to provide the Total As-Spent Cost 

(TASC).

Cost Results

The cost estimates carry an accuracy of -15/+30%, consistent with a “feasibility study” level of 

design engineering applied to the various cases in this study. The value of the study lies not in 

the absolute accuracy of the individual case results, but in the fact that all cases were evaluated 

under the same set of technical and economic assumptions. This consistency of approach allows 

meaningful relative comparisons among the cases evaluated. 

Project contingencies were added to the Engineering/Procurement/Construction Management 

(EPCM) capital accounts to cover project uncertainty and the cost of any additional equipment 

that would result from a detailed design. The contingencies represent costs that are expected to 

occur. Each bare erected cost (BEC) account was evaluated against the level of estimate detail 

and field experience to determine project contingency. Process contingency was added to cost 

account items that were deemed to be first-of-a-kind (FOAK) or posed significant risk due to 

lack of operating experience. The cost accounts that received a process contingency include:

• Fluor’s Econamine FG PlusSM (Econamine) CO2 Removal System – 20 percent on both

CO2 capture cases - unproven technology at commercial scale.

• Instrumentation and Controls – five percent on all accounts for CO2 capture cases.

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

Exhibit ES-4. The following conclusions can be drawn:

• Adding CO2 capture increases the normalized TOC by approximately 97 percent. The 

Econamine unit and CO2 compression train add significant capital cost, as well as project 

and process contingency.

• The normalized TOC for the plants located at the NDL site are 4 percent lower than the 

plants located at the Montana site. This trend is primarily because of the lower net output 

at the higher elevation of the Montana site.

• Adding Owner’s Costs to the TPC increases the cost of the non-capture plants by 

approximately 23 percent and the CO2 capture plants by 22 percent.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit ES-4 Total Overnight Cost

817

1,607

782

1,548

879

1,732

840

1,668

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

TOC TASC TOC TASC TOC TASC TOC TASC

NGCC NGCC w/ CO2 Capture NGCC NGCC w/ CO2 Capture

TOC and TASC ($/kW)

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost

North Dakota Site 

Elevation: 1,900 ft

Montana Site

Elevation: 3,400 ft

The cost metric used in this study is the COE, which is the revenue received by the generator per 

net megawatt-hour during the power plant’s first year of operation, assuming that the COE 

escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it 

remains constant in real terms over the operational period of the power plant. To calculate the 

COE, the Power Systems Financial Model (PSFM) [

Cost of Electricity

1] was used to determine a “base-year” 

(2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3

percent1

Exhibit ES-5

, provided the stipulated internal rate of return on equity over the entire economic

analysis period (capital expenditure period plus thirty years of operation). The first year capital 

charge factor (CCF) shown in , which was derived using the PSFM, can also be 

used to calculate COE using a simplified equation as detailed in Section 2.6.4.

 

1 This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S. 

Department of Labor’s Producer Price Index for Finished Goods. This index was used instead of the Producer Price 

Index for the Electric Power Generation Industry because the Electric Power Index only dates back to December 

2003 and the Producer Price Index is considered the “headline” index for all of the various Producer Price Indices.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

7

The project financial structure varies depending on the type of project (high risk or low risk). All 

cases were assumed to be undertaken at investor owned utilities (IOUs). High risk projects are 

those in which commercial scale operating experience is limited. Cases with CO2 capture were 

considered to be high risk. All NGCC cases were assumed to have a 3 year capital expenditure 

period. The current-dollar, 30-year levelized cost of electricity (LCOE) was also calculated and 

was shown in Exhibit ES-2, but the primary metric used in the balance of this study is COE. A 

more detailed discussion of the two metrics is provided in Section 2.6 of the report.

Exhibit ES-5 Economic Parameters Used to Calculate COE

High Risk

(3 year capital 

expenditure 

period)

Low Risk

(3 year capital 

expenditure 

period)

First Year Capital 

Charge Factor 0.1111 0.1048

Commodity prices fluctuate over time based on overall economic activity and general supply and 

demand curves. While the cost basis for this study is June 2007, many price indices had similar 

values in January 2010 compared to June 2007. For example, the Chemical Engineering Plant 

Cost Index was 532.7 in June 2007 and 532.9 in January 2010, and the Gross Domestic Product 

Chain-type Price Index was 106.7 on July 1, 2007 and 110.0 on January 1, 2010. Hence the June 

2007 dollar cost base used in this study is expected to be representative of January 2010 costs.

The COE results are shown in Exhibit ES-6 with the capital cost, fixed operating cost, variable 

operating cost, and fuel cost shown separately. In the capture cases, the CO2 Transport, Storage 

and Monitoring (TS&M) costs are also shown as a separate bar segment. The following 

conclusions can be drawn:

• The COE is dominated by fuel costs in all cases. The fuel cost component of COE 

comprises approximately 75 percent in both non-capture cases and 62 percent in both 

capture cases.

• The capital cost component is relatively minor in all cases, representing approximately 18

percent of the COE costs in the non-capture cases and 25 percent in the CO2 capture

cases.

• Adding CO2 removal more than doubles the capital cost component and increases the 

COE by approximately 44 percent for each location. 

• The TS&M component of COE in the CO2 capture cases is about 4 percent for both 

capture cases. 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit ES-6 COE by Cost Component

11.5

24.0

11.0

23.1 3.4

6.1

3.2

5.9

1.4

2.7

1.3

2.6

48.2

56.7

48.1

56.6

3.4 3.3

64.4

92.9

63.6

91.4

0

20

40

60

80

100

120

NGCC PRB NGCC PRB w/Capture NGCC Lig NGCC Lig w/Capture

COE (2007 mills/kWh)

CO2 TS&M Cost

Fuel Cost

Variable O&M Cost

Fixed O&M Cost

Capital Cost

Montana Site

Elevation: 3,400 ft

North Dakota Site

Elevation: 1,900 ft

Exhibit ES-7 shows the COE sensitivity to fuel cost. The top set of lines show the COE 

sensitivity of capture cases, and the bottom set of lines show the sensitivity of non-capture cases. 

As expected, all cases show a linear increase in COE with the increase in natural gas prices. 

The sensitivity of COE to CF is shown in Exhibit ES-8. The top set of lines is the COE of the 

capture cases. The bottom set of lines is the non-capture cases. All cases show an expected 

decrease in COE with the increase in CF.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit ES-7 COE Sensitivity to Fuel Costs 

0

20

40

60

80

100

120

140

160

0 2 4 6 8 10 12 14

COE (2007 mills/kWh)

Natural Gas Price, $/MMBtu

NGCC w/CO2 Capture Montana Site

NGCC w/CO2 Capture North Dakota Site

NGCC No Capture Montana Site

NGCC No Capture North Dakota Site

Capacity Factor = 85% for all cases

Study Natural Gas Cost: $7.13/MMBtu

The CO2 emissions per megawatt hour (MWh) in the non-capture cases are about the same for 

both sites. The first year cost of CO2 avoided was calculated as follows.

First Year Cost of CO2 Avoided

CO Emissions CO Emissions tons MWh

COE COE MWh

Avoided Cost

with removal

with removal w o removal

{ } /

{ } $/

2 2

/

−

− = (ES-1)

The COE with CO2 removal includes the costs of capture and compression, as well as TS&M 

costs. The resulting avoided costs are shown in Exhibit ES-9 for both sites. The avoided costs 

are calculated for the CO2 capture (B) case compared to results from each analogous non-capture 

plant (A) and compared to a baseline SC PC non-capture plant (SC PC A). The cost of CO2

avoided averages $88.0/tonne ($79.9/ton) compared to the analogous non-capture (A) design and 

$38.4/tonne ($34.8/ton) compared to the baseline SC PC non-capture (SC PC A) design.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit ES-8 COE Sensitivity to CF

0

20

40

60

80

100

120

140

160

180

0 10 20 30 40 50 60 70 80 90 100

COE (2007 mills/kWh)

Capacity Factor, %

NGCC w/CO2 Capture Montana Site

NGCC w/CO2 Capture North Dakota 

Site

NGCC No Capture Montana Site

NGCC No Capture North Dakota Site

Study Capacity Factor is 

85% for all cases

Exhibit ES-9 CO2 Avoided Costs

89.1

87.0

43.0

33.8

0

10

20

30

40

50

60

70

80

90

100

110

NGCC PRB w/Capture NGCC Lig w/Capture

First YEar CO2 Avoided Cost, (2007$/Tonne)

Avoided Cost (Analogous Technology w/o 

Capture Reference

Avoided Cost (SC PC w/o Capture 

Reference)

Montana Site

Elevation: 3,400 ft

North Dakota Site

Elevation: 1,900 ft
Cost and Performance Baseline - Volume 3c (NGCC Cases)

11

1.

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

performance of electricity production from natural gas combined cycle (NGCC) power systems 

in a consistent technical and economic manner that accurately reflects current market conditions 

for plants using commercially available technology. This document is Volume 3c of the Low 

Rank Coal Baseline Reports, which are part of a four volume series consisting of the following:

INTRODUCTION

• Volume 1: Bituminous Coal and Natural Gas to Electricity

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

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

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

Four NGCC power plant configurations were analyzed as listed in Exhibit ES-1. The list 

includes two locations corresponding to the Montana Powder River Basin (PRB) site and two 

locations corresponding to the North Dakota Lignite (NDL) site. The plant locations are the 

same that were used to evaluate gasification and combustion based systems in Volumes 3a and 

3b of this study. The Montana site corresponds to cases that used Powder River Basin (PRB)

coal in the gasification and combustion reports while the North Dakota site corresponds to the 

cases that used lignite coal. While the cases in this report all use natural gas, references to PRB 

and lignite coals are used to distinguish between the two plant locations with the primary 

difference being elevation. The Montana site elevation is 1,036 meters (m) (3,400 feet [ft]) and 

the North Dakota site is 579 m (1,900 ft). Both sites include cases with and without CO2

capture. 

The naming convention for the cases covered in this report is as follows:

• First letter represents location: S = PRB Montana; L = NDL location

• Two digit number represents technology type: 31 = NGCC

• Final letter indicates CO2 capture: A = no capture; B = capture

Volume 3c covers the four NGCC cases at the Montana and North Dakota sites:

Case S31A – This case is based on natural gas feed where the plant is located at the Montana

PRB site.

Case S31B – This case is the same as S31A except it includes CO2 capture.

Case L31A – This case is based on natural gas feed where the plant is located at the NDL site.

Case L31B – This case is the same as L31A except it includes CO2 capture.

Generating Unit Configurations

The nominal net plant output for this study is set to approximately 500 MW to satisfy CT

constraint as CTs are available in discrete sizes. The actual net output varies by site and CO2

capture requirement. The heat recovery boilers and steam turbines in all cases are readily 

available in a wide range of capacities. 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

12

The balance of this report is organized as follows:

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

• Chapter 3 describes the NGCC technologies modeled and presents the results for the four 

NGCC cases.

• Chapter 4 contains a summary of results.

• Chapter 5 contains the reference list.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

13

2. GENERAL EVALUATION BASIS

For each of the plant configurations in this study an Aspen model was developed and used to 

generate material and energy balances, which provided the design basis for items in the major 

equipment list. The equipment list and material balances were used as the basis for generating 

the capital and operating 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 a combination 

of vendor quotes and scaled estimates from previous design/build projects. Ultimately, a COE 

was calculated for each of the cases and is reported as the economic figure-of-merit.

The balance of this chapter documents the design basis, environmental targets, and cost 

assumptions used in the study.

2.1 SITE CHARACTERISTICS

The plants are located at two different generic plant sites, Montana PRB site and NDL site. The 

ambient conditions for the two sites are shown in Exhibit 2-1 and Exhibit 2-2.

Exhibit 2-1 Montana Site Ambient Conditions 

Elevation, m (ft) 1,036 (3,400)

Barometric Pressure, MPa (psia) 0.09 (13.0)

Design Ambient Temperature, Dry Bulb, °C (°F) 5.6 (42)

Design Ambient Temperature, Wet Bulb, °C (°F) 2.8 (37)

Design Ambient Relative Humidity, % 62

Exhibit 2-2 North Dakota Site Ambient Conditions 

Elevation, m (ft) 579 (1,900)

Barometric Pressure, MPa (psia) 0.10 (13.8)

Design Ambient Temperature, Dry Bulb, °C (°F) 4.4 (40)

Design Ambient Temperature, Wet Bulb, °C (°F) 2.2 (36)

Design Ambient Relative Humidity, % 68

The site characteristics are assumed to be the same for both plant locations, as shown in 

Exhibit 2-3.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit 2-3 Site Characteristics

Location Greenfield, Montana PRB site or NDL site

Topography Level

Size, acres 100

Transportation Rail

Ash/Slag Disposal N/A

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

Access Land locked, having access by rail and highway

CO2 Storage

Compressed to 15.3 MPa (2,215 psia), transported 80 

kilometers (km) (50 miles), and sequestered in a saline 

formation at a depth of 1,239 m (4,055 ft)

It was assumed that the plant proper occupies 10 acres providing a 0.15 mile buffer to the plant 

fence line for a total area of 100 acres.

In all cases it was assumed that buildings house the steam turbine and boiler. The following 

design parameters are considered site-specific, and are not quantified for this study. Allowances 

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

• Flood plain considerations

• Existing soil/site conditions

• Water discharges and reuse

• Rainfall/snowfall criteria

• Seismic design

• Buildings/enclosures

• Fire protection

• Local code height requirements

• Noise regulations – Impact on site and surrounding area
Cost and Performance Baseline - Volume 3c (NGCC Cases)

15

2.2 NATURAL GAS CHARACTERISTICS

Natural gas composition for all cases with and without CO2 capture is presented in Exhibit 2-4.

The fuel composition is normalized and heating values are calculated.

Exhibit 2-4 Natural Gas Composition

Component Vol %

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

Total 100.0

LHV HHV

kJ/kg 47,454 52,581

MJ/scm 34.71 38.46

Btu/lb 20,410 22,600

Btu/scf 932 1,032

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

levelization factors for this study. The PSFM requires that all cost inputs have a consistent cost 

year basis. Because the capital and operating cost estimates are in June 2007 dollars, the fuel 

costs must also be in June 2007 dollars.

The first year cost of natural gas used in this study is $6.76/MMkJ ($7.13/MMBtu) (2007 cost of 

natural gas in 2007 dollars). The cost was determined using the following information from the 

EIA’s 2008 AEO:

• The 2007 Mountain region delivered cost of natural gas to electric utilities in 2006 

dollars, $252/1000 m3 ($7.14/1000 ft3

), was obtained from the AEO 2008 reference case 

Table 108 and converted to an energy basis, $6.56/MMkJ ($6.92/MMBtu) [2

• The 2007 cost was escalated to 2007 dollars using the GDP chain-type price index from 

AEO 2008, resulting in a delivered 2007 price in 2007 dollars of $6.76/MMkJ 

($7.13/MMBtu) [

].

3].
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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2.3 ENVIRONMENTAL TARGETS

The environmental targets for the study were considered on a technology- and fuel-specific basis. 

In setting the environmental targets a number of factors were considered, including current 

emission regulations, regulation trends, and the status of current best available control 

technology (BACT).

Natural Gas Combustion Design Targets

BACT was applied to the NGCC cases and the resulting emissions compared to NSPS limits. 

The NGCC environmental targets were chosen based on reasonably obtainable limits given the 

control technologies employed and are presented in Exhibit 2-5.

Exhibit 2-5 Environmental Targets for NGCC Cases

Pollutant Environmental 

Target

40 CFR Part 60, 

Subpart KKKK 

Limits

Control 

Technology

NOx 2.5 ppmv @ 15% O2 15 ppmv @ 15% O2

Low NOx burners 

and SCR

SO2 Negligible 0.9 lb/MWh 

(0.135 lb/MMBtu)1

Low sulfur content 

fuel

Particulate Matter 

(Filterable) N/A N/A N/A

Mercury N/A N/A N/A 1 Assumes a heat rate of 6,690 Btu/kWh.

Published vendor literature indicates that 25 ppmv NOx at 15 percent oxygen (O2) is achievable 

using natural gas and dry low NOx (DLN) technology [4,5

For the purpose of this study, natural gas was assumed to contain a negligible amount of sulfur 

compounds, and therefore generate negligible sulfur emissions. The EPA defines pipeline 

natural gas as containing >70 percent CH4 by volume or having a gross calorific value (GCV) of 

between 35.4 and 40.9 megajoule per normal cubic meter (MJ/Nm3

) (950 and 1,100 Btu/scf) and 

having a total sulfur content of less than 13.7 milligrams per normal meter cubed (mg/Nm3) (0.6 

gr/100 scf [grains per one hundred standard cubic feet]) [

]. The application of SCR with 90 

percent efficiency further reduces NOx emissions to 2.5 ppmv, which was selected as the 

environmental target. 

6

The pipeline natural gas was assumed to contain no PM and no mercury resulting in no 

emissions of either.

]. Assuming a sulfur content equal to 

the EPA limit for pipeline natural gas, resulting SO2 emissions for the two non-capture NGCC 

cases in this study would be 9.7 metric ton (1000 kg) (tonnes)/year (yr) (10.7 tons/yr) at 85 

percent CF or 0.00073 kilogram per gigajoule (kg/GJ) (0.0017 lb/MMBtu). Thus, for the 

purpose of this study, SO2 emissions were considered negligible.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Carbon Dioxide

CO2 is not currently regulated nationally. However, the possibility exists that federal carbon 

limits will be imposed in the future and this study examines cases that include a reduction in CO2

emissions. CO2 emissions are reported on both a pound (lb)/(gross) MWh and lb/(net) MWh 

basis in each capture case emissions table.

For the cases in this report volume that have CO2 capture, the basis is a nominal post-combustion 

90 percent removal based on carbon input from the natural gas. It is assumed that all of the fuel 

carbon becomes CO2 in the CT flue gas.

The cost of CO2 capture was calculated as a first year avoided cost as illustrated in the equation 

below. Analogous non-capture technologies and SC non-capture PC were chosen as separate 

reference cases. The COE in the CO2 capture cases includes TS&M as well as capture and 

compression.

CO Emissions CO Emissions tons MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

2 − 2

− =

2.4 CAPACITY FACTOR

This study assumes that each new plant would be dispatched any time it is available and would 

be capable of generating maximum capacity when online; therefore, CF and availability are 

equal. The availability for NGCC cases was determined using the Generating Availability Data 

System (GADS) from the North American Electric Reliability Council (NERC) [7

NERC defines an equivalent availability factor (EAF) as a measure of the plant CF assuming 

there is always a demand for the output. The EAF accounts for planned and scheduled derated 

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

CF.

].

The average EAF for NGCC plants in the 400-599 MW size range was 84.7 percent in 2004 and 

averaged 82.7 percent from 2000-2004. The EAF was rounded up to 85 percent and that value 

was also used as the NGCC plant CF.

The addition of CO2 capture was assumed not to impact the CF even without redundant 

pipelines, wells or subsurface infrastructure. This assumption was made to enable a 

comparison based on the impact of capital and variable operating costs only. Any reduction in 

assumed CF would further increase the COE.

2.5 RAW WATER WITHDRAWAL AND CONSUMPTION

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

total water demand for each major subsystem was determined. The internal recycle water 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

18

available from various sources was used to offset the water demand and determine the total water 

withdrawal. Discharge water stream quantities were estimated and subtracted from the water 

withdrawal to determine the water consumption from the environment required for the plant.

Fifty percent of the raw water withdrawal was assumed to be provided by a publicly owned 

treatment works (POTW) and 50 percent was provided from groundwater. Raw water 

withdrawal is defined as the water metered from a raw water source and used in the plant 

processes for any and all purposes, such as cooling tower makeup and boiler feedwater (BFW) 

makeup.

The largest consumer of raw water in all cases is cooling tower makeup. Since plants located in 

the Western U.S. need to consider limited water supplies, a parallel wet/dry cooling tower was 

chosen for all plant configurations similar to the system installed at Xcel Energy’s Comanche 3 

PC plant. In a parallel cooling system half of the turbine exhaust steam is condensed in an aircooled condenser and half in a water-cooled condenser. The cooling water is provided by a 

mechanical draft, evaporative cooling tower, and all process blowdown streams were assumed to 

be treated and recycled to the cooling tower. The cooling tower blowdown was assumed to be 

treated and 90 percent returned to the water source with the balance sent to a pond for 

evaporation. The design ambient wet bulb temperature of 3°C (37°F) at the Montana site and 

2°C (36°F) at the NDL site (Exhibit 2-1 and Exhibit 2-2) was used to achieve a cooling water 

temperature of 9°C (48°F) and 8°C (47°F), respectively at the two sites using an approach of 6°C 

(11°F). The cooling water range was assumed to be 11°C (20°F). The cooling tower makeup 

rate was determined using the following [8

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

]:

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

• Blowdown losses = Evaporative Losses / (Cycles of Concentration - 1)

Where cycles of concentration are a measure of water quality, and a mid-range value of 4 

was chosen for this study.

Typical design conditions for air-cooled condensers include an initial temperature difference

(ITD) of 40-55°F [9]. The ITD is the temperature difference between saturated steam at the 

steam turbine generator (STG) exhaust and the inlet dry bulb cooling air temperature. The ITDs 

at the two locations in this study are 48 and 50°F. The fan power requirement is estimated at 3.5 

times the power required for a wet cooling tower with equivalent heat duty [10

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.

].

2.6 COST ESTIMATING METHODOLOGY

The estimating methodology for capital costs, operations and maintenance costs, and CO2 TS&M 

costs are described below. The finance structure, basis for the discounted cash flow analysis, and 

first-year COE cost calculations are also described.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

19

2.6.1

As illustrated in 

Capital Costs

Exhibit 2-6, this study reports capital cost at four levels: Bare Erected Cost 

(BEC), Total Plant Cost (TPC), Total Overnight Cost (TOC) and Total As-spent Capital (TASC). 

BEC, TPC and TOC are “overnight” costs and are expressed in “base-year” dollars. The base 

year is the first year of capital expenditure, which for this study is assumed to be 2007. TASC is 

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

assumed to last three years for natural gas plants (2007 to 2010).

Exhibit 2-6 Capital Cost Levels and their Elements

process equipment

supporting facilities

direct and indirect labor

BEC

TPC

TOC

TASC

EPC contractor services

process contingency

project contingency

preproduction costs

inventory capital

financing costs

other owner’s costs

escalation during capital expenditure period

interest on debt during capital expenditure period

Bare Erected Cost

Total Plant Cost

Total Overnight Cost

Total As-Spent Cost

BEC, TPC and TOC are all 

“overnight” costs expressed 

in base-year dollars.

TASC is expressed in mixed- year current dollars, spread 

over the capital expenditure 

period.

The BEC

The 

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 is not included in 

BEC. BEC is an overnight cost expressed in base-year (2007) dollars.

TPC comprises the BEC plus the cost of services provided by the engineering, procurement 

and construction (EPC) contractor and project and process contingencies. EPC services include: 

detailed design, contractor permitting (i.e., those permits that individual contractors must obtain 

to perform their scopes of work, as opposed to project permitting, which is not included here), 

and project/construction management costs. TPC is an overnight cost expressed in base-year 

(2007) dollars.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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The TOC

The 

comprises the TPC plus owner’s costs. TOC is an “overnight” cost, expressed in baseyear (2007) dollars and as such does not include escalation during construction or interest during 

construction. TOC is an overnight cost expressed in base-year (2007) dollars.

TASC

Cost Estimate Basis and Classification

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.

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.

Recommended Practice 18R-97 of the Association for the Advancement of Cost Engineering 

International (AACE) describes a Cost Estimate Classification System as applied in Engineering, 

Procurement and Construction for the process industries [11

Most techno-economic studies completed by NETL feature cost estimates intended for the 

purpose of a “Feasibility Study” (AACE Class 4). 

].

Exhibit 2-7 describes the characteristics of an 

AACE Class 4 Cost Estimate. Cost estimates in this study have an expected accuracy range of -

15%/+30%.

Exhibit 2-7 Features of an AACE Class 4 Cost Estimate

Project 

Definition Typical Engineering Completed Expected Accuracy

1 to 15%

Plant capacity, block schematics, indicated layout, 

process flow diagrams for main process systems, and 

preliminary engineered process and utility equipment 

lists

-15% to -30% on the low 

side, and +20% to +50% 

on the high side

The capital costs for each cost account were reviewed by comparing individual accounts across 

all cases to ensure an accurate representation of the relative cost differences between the cases 

and accounts. All capital costs are presented as “overnight costs” expressed in June 2007 

dollars. The dollar values have been held at June 2007 to allow direct comparison with earlier 

results. Significant pricing fluctuations have occurred between June 2007 and March 2009. A 

retrospective look suggests that pricing for these commodities peaked in mid 2008 and generally 

declined during the latter parts of 2008 into 2009. While some pricing is still currently declining, 

based on published information, pricing at the end of 2008 remains higher than June 2007 

values.

System Code-of-Accounts 

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

code-of-account structure has the advantage of grouping all reasonably allocable components of 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

21

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

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

Non-CO2 Capture Plant Maturity

Non-capture NGCC cases are based on commercial offerings for a mature technology nth-of-akind (NOAK) cost. Thus, each of these cases reflects the expected cost for the next commercial 

sale of each of this technology.

CO2 Removal Plant Maturity 

While the post-combustion technology used for the NGCC plants has been practiced at smaller 

scale, it has never been practiced at a scale equivalent to that required in this study. There were 

domestic amine-based CO2 capture systems operating on natural gas-derived flue gas at scales up 

to 1,200 tons per day (TPD) [12

Contracting Strategy 

]. The plants in this study will capture an average 4,600 TPD of 

CO2. Consequently the CO2 capture cases will be treated as FOAK. 

The estimates are based on an EPCM approach utilizing multiple subcontracts. This approach 

provides the Owner with greater control of the project, while minimizing, if not eliminating most 

of the risk premiums typically included in an Engineer/Procure/Construct (EPC) contract price. 

In a traditional lump sum EPC contract, the Contractor assumes all risk for performance, 

schedule, and cost. As a result of current market conditions, EPC contractors appear more 

reluctant to assume that overall level of risk. The current trend appears to be a modified EPC 

approach where much of the risk remains with the Owner. Where Contractors are willing to 

accept the risk in EPC type lump-sum arrangements, it is reflected in the project cost. In today’s 

market, Contractor premiums for accepting these risks, particularly performance risk, can be 

substantial and increase the overall project costs dramatically. 

The EPCM approach used as the basis for the estimates here is anticipated to be the most cost 

effective approach for the Owner. While the Owner retains the risks and absorbs higher project 

management costs, the risks become reduced with time, as there is better scope definition at the 

time of contract award(s).

Estimate Scope 

The estimates represent a complete power plant facility on a generic site. The plant boundary 

limit is defined as the total plant facility within the “fence line” including the water supply 

system, but terminating at the high voltage side of the main power transformers. TS&M cost is 

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

COE.

Capital Cost Assumptions

WorleyParsons developed the capital cost estimates for each plant using the company’s in-house 

database and conceptual estimating models for each of the specific technologies. This database 

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

design base of experience for similar equipment in the company’s range of power and process 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

22

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

estimating models. This provides a basis for subsequent comparisons and easy modification 

when comparing between specific case-by-case variations.

Other key estimate considerations include the following:

• Labor costs are based on Midwest, Merit Shop using factors from PAS, Inc [13

• The estimates are based on a competitive bidding environment, with adequate skilled 

craft labor available locally.

]. PAS 

presents information for eight separate regions. Volume 1 of this study used a generic 

Midwestern site, typical of Region 5 (IL, IN, MI, MN, OH, and WI). The weighted 

average rate for Region 8 (CO, MT, ND, SD, UT, and WY) is within less than one-half of 

one percent of that for Region 5. The difference is inconsequential so the same rates used 

in Volume 1 were maintained in this study. Costs would need to be re-evaluated for 

projects employing union labor. 

• Labor is based on a 50-hour work-week (5-10s). No additional incentives such as perdiems 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. 

• Costs are limited to within the “fence line,” terminating at the high voltage side of the 

main power transformers with the exception of costs included for TS&M, which are 

treated as an addition to COE.

• Engineering and Construction Management were estimated as a percent of BEC. These 

costs consist of all home office engineering and procurement services as well as field 

construction management costs. Site staffing generally includes a construction manager, 

resident engineer, scheduler, and personnel for project controls, document control, 

materials management, site safety, and field inspection.

Price Fluctuations

During the course of this study, the prices of equipment and bulk materials fluctuated quite 

substantially. Some reference quotes pre-dated the 2007 year cost basis while others were 

received post-2007. All vendor quotes used to develop these estimates were adjusted to June 

2007 dollars accounting for the price fluctuations. Adjustments of costs pre-dating 2007 

benefitted from a vendor survey of actual and projected pricing increases from 2004 through 

mid-2007 that WorleyParsons conducted for another project. The results of that survey were 

used to validate/recalibrate the corresponding escalation factors used in the conceptual 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

23

estimating models. The more recent economic down turn has resulted in a reduction of 

commodity prices such that many price indices have similar values in January 2010 compared to 

June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 

and 532.9 in January 2010, and the Gross Domestic Product Chain-type Price Index was 106.7 

on July 1, 2007 and 110.0 on January 1, 2010. While these overall indices are nearly constant, it 

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

reference point.

Cross-comparisons 

In all technology comparison studies, the relative differences in costs are often more important 

than the absolute level of TPC. This requires cross-account comparison between technologies to 

review the consistency of the direction of the costs. 

Exclusions

The capital cost estimate includes all anticipated costs for equipment and materials, installation 

labor, professional services (Engineering and Construction Management), and contingency. The 

following items are excluded from the capital costs:

• All taxes, with the exception of payroll and property taxes (property taxes are included 

with the fixed O&M costs)

• Site specific considerations – including, but not limited to, seismic zone, accessibility, 

local regulatory requirements, excessive rock, piles, laydown space, etc. 

• Labor incentives in excess of 5-10s

• Additional premiums associated with an EPC contracting approach

Contingency

Process and project contingencies are included in estimates to account for unknown costs that are 

omitted or unforeseen due to a lack of complete project definition and engineering. 

Contingencies are added because experience has shown that such costs are likely, and expected, 

to be incurred even though they cannot be explicitly determined at the time the estimate is 

prepared. 

Capital cost contingencies do not cover uncertainties or risks associated with

• scope changes

• changes in labor availability or productivity

• delays in equipment deliveries

• changes in regulatory requirements

• unexpected cost escalation

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

Project Contingency

AACE 16R-90 states that project contingency for a “budget-type” estimate (AACE Class 4 or 5) 

should be 15 to 30 percent of the sum of BEC, EPC fees and process contingency. This was 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

24

used as a general guideline, but some project contingency values outside of this range occur 

based on WorleyParsons’ in-house experience. 

Process Contingency

Process contingency is intended to compensate for uncertainty in cost estimates caused by 

performance uncertainties associated with the development status of a technology. Process 

contingencies are applied to each plant section based on its current technology status.

As shown in Exhibit 2-8, AACE International Recommended Practice 16R-90 provides 

guidelines for estimating process contingency based on EPRI philosophy [14

Process contingencies have been applied to the estimates in this study as follows:

].

• CO2 Removal System (Econamine) – 20 percent on all CO2 capture cases - unproven 

technology at commercial scale in NGCC service.

• Instrumentation and Controls – five percent on all accounts for CO2 capture cases.

Exhibit 2-8 AACE Guidelines for Process Contingency

Technology Status

Process Contingency

(% of Associated Process Capital)

New concept with limited data 40+

Concept with bench-scale data 30-70

Small pilot plant data 20-35

Full-sized modules have been operated 5-20

Process is used commercially 0-10

Process contingency is typically not applied to costs that are set equal to a research goal or 

programmatic target since these values presume to reflect the total cost.

All contingencies included in the TPC, both project and process, represent costs that are expected 

to be spent in the development and execution of the project.

Owner’s Costs

Exhibit 2-9 explains the estimation method for owner’s costs. With some exceptions, the 

estimation method follows guidelines in Sections 12.4.7 to 12.4.12 of AACE International 

Recommended Practice No. 16R-90 [14]. The Electric Power Research Institute’s “Technical 

Assessment Guide (TAG®) – Power Generation and Storage Technology Options” also has 

guidelines for estimating owner’s costs. The EPRI and AACE guidelines are very similar. In 

instances where they differ, this study has sometimes adopted the EPRI approach.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

25

Exhibit 2-9 Owner’s Costs Included in TOC

Owner’s Cost Estimate Basis

Prepaid Royalties Any technology royalties are assumed to be included in the associated equipment cost, and thus are not included as an 

owner’s cost.

Preproduction (StartUp) Costs

• 6 months operating labor

• 1 month maintenance materials at full capacity

• 1 month non-fuel consumables at full capacity

• 1 month waste disposal 

• 25% of one month’s fuel cost at full capacity

• 2% of TPC

Compared to AACE 16R-90, this includes additional costs for operating labor (6 months versus 1 month) to cover the 

cost of training the plant operators, including their participation in startup, and involving them occasionally during the 

design and construction. AACE 16R-90 and EPRI TAG® differ on the amount of fuel cost to include; this estimate 

follows EPRI.

Working Capital Although inventory capital (see below) is accounted for, no additional costs are included for working capital.

Inventory Capital

• 0.5% of TPC for spare parts

• 60 day supply (at full capacity) of fuel. Not applicable for natural gas.

• 60 day supply (at full capacity) of non-fuel consumables (e.g., chemicals and catalysts) that are stored on site. Does 

not include catalysts and adsorbents that are batch replacements such as WGS, COS, and SCR catalysts and 

activated carbon.

AACE 16R-90 does not include an inventory cost for fuel, but EPRI TAG® does.

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

Financing Cost

• 2.7% of TPC

This financing cost (not included by AACE 16R-90) covers the cost of securing financing, including fees and closing 

costs but not including interest during construction (or AFUDC). The “rule of thumb” estimate (2.7% of TPC) is based 

on a 2008 private communication with a capital services firm.

Other Owner’s Costs • 15% of TPC

This additional lumped cost is not included by AACE 16R-90 or EPRI TAG®. The “rule of thumb” estimate (15% of 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

26

Owner’s Cost Estimate Basis

TPC) is based on a 2009 private communication with WorleyParsons. Significant deviation from this value is possible 

as it is very site and owner specific. The lumped cost includes:

- Preliminary feasibility studies, including a Front-End Engineering Design (FEED) study

- Economic development (costs for incentivizing local collaboration and support)

- Construction and/or improvement of roads and/or railroad spurs outside of site boundary

- Legal fees

- Permitting costs

- Owner’s engineering (staff paid by owner to give third-party advice and to help the owner oversee/evaluate the work 

of the EPC contractor and other contractors)

- Owner’s contingency (Sometimes called “management reserve”, these are funds to cover costs relating to delayed 

startup, fluctuations in equipment costs, unplanned labor incentives in excess of a five-day/ten-hour-per-day work 

week. Owner’s contingency is NOT a part of project contingency.)

This lumped cost does NOT include:

- EPC Risk Premiums (Costs estimates are based on an Engineering Procurement Construction Management approach 

utilizing multiple subcontracts, in which the owner assumes project risks for performance, schedule and cost)

- Transmission interconnection: the cost of interconnecting with power transmission infrastructure beyond the plant 

busbar.

- Taxes on capital costs: all capital costs are assumed to be exempt from state and local taxes.

- Unusual site improvements: normal costs associated with improvements to the plant site are included in the bare 

erected cost, assuming that the site is level and requires no environmental remediation. Unusual costs associated 

with the following design parameters are excluded: flood plain considerations, existing soil/site conditions, water 

discharges and reuse, rainfall/snowfall criteria, seismic design, buildings/enclosures, fire protection, local code 

height 

requirements, noise regulations.

Initial Cost for 

Catalysts and 

Chemicals

• All initial fills not included in BEC

Taxes & Insurance • 2% of TPC (Fixed O&M Cost)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

27

Interest during construction and escalation during construction are not included as owner’s costs 

but are factored into the COE and are included in TASC. These costs vary based on the capital 

expenditure period and the financing scenario. Ratios of TASC/TOC determined from the PSFM 

are used to account for escalation and interest during construction. Given TOC, TASC can be 

determined from the ratios given in Exhibit 2-10.

Exhibit 2-10 TASC/TOC Factors

Finance Structure IOU High Risk IOU Low Risk

TASC/TOC 1.078 1.075

2.6.2

The production costs or operating costs and related maintenance expenses (O&M) pertain to 

those charges associated with O&M the power plants over their expected life. These costs 

include: 

Operations and Maintenance Costs

• Operating labor

• Maintenance – material and labor

• Administrative and support labor

• Consumables

• Fuel

• Waste disposal

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. 

Operating Labor

Operating labor cost was determined based on the number of operators required for each specific 

case. The average base labor rate used to determine annual cost is $34.65/hour (hr). The 

associated labor burden is estimated at 30 percent of the base labor rate. Taxes and insurance are 

included as fixed O&M costs totaling 2 percent of the TPC.

Maintenance Material and Labor

Maintenance cost was evaluated on the basis of relationships of 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.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

28

Administrative and Support Labor

Labor administration and overhead charges are assessed at a rate of 25 percent of the burdened 

O&M labor.

Consumables

The cost of consumables, including fuel, was determined on the basis of individual rates of 

consumption, the unit cost of each specific consumable commodity, and the plant annual 

operating hours. 

Quantities for major consumables such as fuel were taken from technology-specific heat and 

mass balance diagrams developed for each plant application. Other consumables were evaluated 

on the basis of the quantity required using reference 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 (such as reactor catalyst), which are included with the equipment pricing in the capital 

cost.

Waste Disposal

No wastes are generated in NGCC cases that require disposal. 

Co-Products and By-Products (Other than CO2)

No co-products or by-products (other than CO2 in the capture cases) are generated in NGCC 

cases.

2.6.3

For those cases that feature carbon sequestration, the capital and operating costs for CO2 TS&M 

were independently estimated by NETL. Those costs were converted to a TS&M COE

increment that was added to the plant COE.

CO2 Transport, Storage and Monitoring

CO2 TS&M was modeled based on the following assumptions:

• CO2 is supplied to the pipeline at the plant fence line at a pressure of 15.3 MPa (2,215 

psia). The CO2 product gas composition varies in the cases presented, but is expected to 

meet the specification described in Exhibit 2-11 [15

• The CO2 is transported 80 km (50 miles) via pipeline to a geologic sequestration field for 

injection into a saline formation.

]. A glycol dryer located near the 

mid-point of the compression train is used to meet the moisture specification.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

29

Exhibit 2-11 CO2 Pipeline Specification

Parameter Units Parameter Value

Inlet Pressure MPa (psia) 15.3 (2,215)

Outlet Pressure MPa (psia) 10.4 (1,515)

Inlet Temperature °C (°F) 35 (95)

N2 Concentration ppmv < 300

O2 Concentration ppmv < 40

Ar Concentration ppmv < 10

H2O Concentration ppmv < 150

• The CO2 is transported and injected as a SC fluid in order to avoid two-phase flow and 

achieve maximum efficiency [16]. The pipeline is assumed to have an outlet pressure 

(above the SC pressure) of 8.3 MPa (1,200 psia) with no recompression along the way. 

Accordingly, CO2 flow in the pipeline was modeled to determine the pipe diameter that 

results in a pressure drop of 6.9 MPa (1,000 psi) over an 80 km (50 mile) pipeline length

[17

• The saline formation is at a depth of 1,236 m (4,055 ft) and has a permeability of 22 

millidarcy (md) (22 μm2) and formation pressure of 8.4 MPa (1,220 psig) [

]. (Although not explored in this study, the use of boost compressors and a smaller 

pipeline diameter could possibly reduce capital costs for sufficiently long pipelines.) The 

diameter of the injection pipe will be of sufficient size that frictional losses during 

injection are minimal and no booster compression is required at the well-head in order to 

achieve an appropriate down-hole pressure, with hydrostatic head making up the 

difference between the injection and reservoir pressure.

15]. This is 

considered an average storage site and requires roughly one injection well for each 9,360 

tonnes (10,320 short tons) of CO2 injected per day [15]. The assumed aquifer 

characteristics are tabulated in Exhibit 2-12.

Exhibit 2-12 Deep Saline Aquifer Specification

Parameter Units Base Case

Pressure MPa (psi) 8.4 (1,220)

Thickness m (ft) 161 (530)

Depth m (ft) 1,236 (4,055)

Permeability md (μm2) 22 (22)

Pipeline Distance Km (miles) 80 (50)

Injection Rate per Well Tonne (ton) CO2/day 9,360 (10,320)

The cost metrics utilized in this study provide a best estimate of TS&M costs for a “typical” 

sequestration project, and may vary significantly based on variables such as terrain to be crossed 

by the pipeline, reservoir characteristics, and number of land owners from which sub-surface 

rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

30

found in the literature, escalated to June 2007-year dollars using appropriate price indices. These 

costs were then verified against values quoted by industrial sources where possible. Where 

regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of 

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

scenarios.

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

TS&M Capital Costs

TS&M capital costs include both a 20 percent process contingency and 30 percent project 

contingency. 

In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur 

over a longer time period, up to 100 years. In these cases a capital fund is established based on 

the net present value of the cost outlay, and this fund is then levelized similar to the other costs.

Transport Costs

CO2 transport costs are broken down into three categories: pipeline costs, related capital 

expenditures, and O&M costs.

Pipeline costs are derived from data published in the Oil and Gas Journal’s (O&GJ) annual 

Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs 

from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO2

pipeline, as noted in various studies [15, 16, 18

18

]. The University of California performed a 

regression analysis to generate cost curves from the O&GJ data: (1) Pipeline Materials, (2) 

Direct Labor, (3) Indirect Costs, and (4) Right-of-way acquisition, with each represented as a 

function of pipeline length and diameter [ ]. These cost curves were escalated to the June 2007 

year dollars used in this study.

Related capital expenditures were based on the findings of a previous study funded by 

DOE/NETL, Carbon Dioxide Sequestration in Saline Formations – Engineering and Economic 

Assessment [16]. This study utilized a similar basis for pipeline costs (O&GJ Pipeline cost data 

up to the year 2000) but added a CO2 surge tank and pipeline control system to the project. 

Transport O&M costs were assessed using metrics published in a second DOE/NETL sponsored 

report entitled Economic Evaluation of CO2 Storage and Sink Enhancement Options [15]. This 

study was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the 

other studies mentioned above either (a) do not report operating costs, or (b) report them in 

absolute terms for one pipeline, as opposed to as a length- or diameter-based metric. 

Storage Costs

Storage costs were divided into five categories: (1) Site Screening and Evaluation, (2) Injection 

Wells, (3) Injection Equipment, (4) O&M Costs, and (5) Pore Volume Acquisition. With the 

exception of Pore Volume Acquisition, all of the costs were obtained from Economic Evaluation 

of CO2 Storage and Sink Enhancement Options [15]. These costs include all of the costs 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

31

associated with determining, developing, and maintaining a CO2 storage location, including site 

evaluation, well drilling, and the capital equipment required for distributing and injecting CO2.

Pore Volume Acquisition costs are the costs associated with acquiring rights to use the subsurface volume where the CO2 will be stored, i.e., the pore space in the geologic formation. 

These costs were based on recent research by Carnegie Mellon University, which examined 

existing sub-surface rights acquisition as it pertains to natural gas storage [19

Liability Protection

]. The regulatory 

uncertainty in this area combined with unknowns regarding the number and type (private or 

government) of property owners, require a number of “best engineering judgment” decisions to 

be made. In this study it was assumed that long-term lease rights were acquired from the 

property owners in the projected CO2 plume growth region for a nominal fee, and that an annual 

“rent” was paid when the plume reached each individual acre of their property for a period of up 

to 100 years from the injection start date. The present value of the life cycle pore volume costs 

are assessed at a 10 percent discount rate and a capital fund is set up to pay for these costs over 

the 100 year rent scenario.

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

storage of CO2, the injecting party may bear financial liability. Several types of liability 

protection schemes have been suggested for CO2 storage, including Bonding, Insurance, and 

Federal Compensation Systems combined with either tort law (as with the Trans-Alaska Pipeline 

Fund), or with damage caps and preemption, as is used for nuclear energy under the Price 

Anderson Act [20]. However, at present, a specific liability regime has yet to be dictated either 

at a Federal or (to our knowledge) State level. However, certain state governments have enacted 

legislation which assigns liability to the injecting party, either in perpetuity (Wyoming) or until 

ten years after the cessation of injection operations, pending reservoir integrity certification, at 

which time liability is turned over to the state (North Dakota and Louisiana) [21, 22, 23

Liability costs assume that a bond must be purchased before injection operations are permitted in 

order to establish the ability and good will of an injector to address damages where they are 

deemed liable. A figure of five million dollars was used for the bond based on the Louisiana 

fund level. This bond level may be conservatively high, in that the Louisiana fund covers both 

liability and monitoring, but that fund also pertains to a certified reservoir where injection 

operations have ceased, having a reduced risk compared to active operations. The bond cost was 

not escalated.

]. In the 

case of Louisiana, a trust fund totaling five million dollars is established over the first ten years 

(120 months) of injection operations for each injector. This fund is then used by the state for 

CO2 monitoring and, in the event of an at-fault incident, damage payments. 

Monitoring Costs

Monitoring costs were evaluated based on the methodology set forth in the International Energy 

Agency (IEA) Greenhouse Gas (GHG) R&D Programme’s Overview of Monitoring Projects for 

Geologic Storage Projects report [24]. In this scenario, operational monitoring of the CO2 plume 

occurs over 30 years (during plant operation) and closure monitoring occurs for the following 

fifty years (for a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

32

survey, and periodic seismic survey; EM and gravity surveys are ongoing while seismic survey 

occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 

60, 70, and 80 after injection ceases.

2.6.4

The global economic assumptions are listed in 

Finance Structure, Discounted Cash Flow Analysis, and COE

Exhibit 2-13.

Finance structures were chosen based on the assumed type of developer/owner (investor-owned 

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

assessed (low-risk or high-risk). For this study the owner/developer was assumed to be an IOU. 

The NGCC non-capture plants are categorized as low risk and the CO2 capture cases are 

categorized as high risk. Exhibit 2-14 describes the low-risk IOU and high-risk IOU finance 

structures that were assumed for this study. These finance structures were recommended in a 

2008 NETL report based on interviews with project developers/owners, financial organizations 

and law firms [25].
Cost and Performance Baseline - Volume 3c (NGCC Cases)

33

Exhibit 2-13 Global Economic Assumptions

Parameter Value

TAXES

Income Tax Rate 38% (Effective 34% Federal, 6% State)

Capital Depreciation 20 years, 150% declining balance

Investment Tax Credit 0%

Tax Holiday 0 years

CONTRACTING AND FINANCING TERMS

Contracting Strategy

Engineering Procurement Construction 

Management (owner assumes project risks for 

performance, schedule and cost)

Type of Debt Financing Non-Recourse (collateral that secures debt is 

limited to the real assets of the project)

Repayment Term of Debt 15 years

Grace Period on Debt Repayment 0 years

Debt Reserve Fund None

ANALYSIS TIME PERIODS

Capital Expenditure Period Coal Plants: 5 Years

Operational Period 30 years

Economic Analysis Period (used for IRROE) 35 Years (capital expenditure period plus 

operational period)

TREATMENT OF CAPITAL COSTS

Capital Cost Escalation During Capital 

Expenditure Period (nominal annual rate) 3.6%2

Distribution of Total Overnight Capital over the 

Capital Expenditure Period (before escalation) 5-Year Period: 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters

% of Total Overnight Capital that is Depreciated

100% (this assumption introduces a very small 

error even if a substantial amount of TOC is 

actually non-depreciable)

ESCALATION OF OPERATING REVENUES AND COSTS

Escalation of COE (revenue), O&M Costs, and 

Fuel Costs (nominal annual rate) 3.0%3 COE, O&M, Fuel

 

2 A nominal average annual rate of 3.6 percent is assumed for escalation of capital costs during construction. This 

rate is equivalent to the nominal average annual escalation rate for process plant construction costs between 1947 

and 2008 according to the Chemical Engineering Plant Cost Index.

3 An average annual inflation rate of 3.0 percent is assumed. This rate is equivalent to the average annual escalation 

rate between 1947 and 2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the socalled "headline" index of the various Producer Price Indices. (The Producer Price Index for the Electric Power 

Generation Industry may be more applicable, but that data does not provide a long-term historical perspective since 

it only dates back to December 2003.)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

34

Exhibit 2-14 Financial Structure for Investor Owned Utility High and Low Risk Projects

Type of 

Security % of Total

Current 

(Nominal) Dollar 

Cost

Weighted 

Current 

(Nominal) Cost

After Tax 

Weighted Cost of 

Capital

Low Risk

Debt 50 4.5% 2.25%

Equity 50 12% 6%

Total 8.25% 7.39%

High Risk

Debt 45 5.5% 2.475%

Equity 55 12% 6.6%

Total 9.075% 8.13%

DCF Analysis and Cost of Electricity

The NETL Power Systems Financial Model (PSFM) is a nominal-dollar4 (current dollar) 

discounted cash flow (DCF) analysis tool. As explained below, the PSFM was used to calculate 

COE5

Exhibit 2-15

in two ways: a COE and a levelized COE (LCOE). To illustrate how the two are related, 

COE solutions are shown in for a generic pulverized coal (PC) power plant and a 

generic natural gas combined cycle (NGCC) power plant, each with carbon capture and 

sequestration installed.

• The COE is the revenue received by the generator per net megawatt-hour during the power 

plant’s first year of operation, assuming that the COE escalates thereafter at a nominal 

annual rate equal to the general inflation rate, i.e., that it remains constant in real terms over 

the operational period of the power plant. To calculate the COE, the PSFM was used to 

determine a “base-year” (2007) COE that, when escalated at an assumed nominal annual 

general inflation rate of 3 percent6

 

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

the interplay between depreciation and inflation.

, provided the stipulated internal rate of return on equity 

over the entire economic analysis period (capital expenditure period plus thirty years of 

operation). The COE solutions are shown as curved lines in the upper portion of 

5 For this calculation, “cost of electricity” is somewhat of a misnomer because from the power plant’s perspective it 

is actually the “price” received for the electricity generated to achieve the stated IRROE. However, since the price 

paid for generation is ultimately charged to the end user, from the customer’s perspective it is part of the cost of 

electricity.

6 This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S. 

Department of Labor’s Producer Price Index for Finished Goods. This index was used instead of the Producer Price 

Index for the Electric Power Generation Industry because the Electric Power Index only dates back to December 

2003 and the Producer Price Index is considered the “headline” index for all of the various Producer Price Indices.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

35

Exhibit 2-15 for a PC power plant and a NGCC power plant. Since this analysis assumes that 

COE increases over the economic analysis period at the nominal annual general inflation 

rate, it remains constant in real terms and the first-year COE is equivalent to the base-year 

COE when expressed in base-year (2007) dollars. 

• The LEVELIZED COE is the revenue received by the generator per net megawatt-hour 

during the power plant’s first year of operation, assuming that the COE escalates thereafter 

at a nominal annual rate of 0 percent, i.e., that it remains constant in nominal terms over the 

operational period of the power plant. This study reports LCOE on a current-dollar basis 

over thirty years. “Current dollar” refers to the fact that levelization is done on a nominal, 

rather than a real, basis7

Exhibit 2-15

. “Thirty-years” refers to the length of the operational period 

assumed for the economic analysis. To calculate the LCOE, the PSFM was used to calculate 

a base-year COE that, when escalated at a nominal annual rate of 0 percent, provided the 

stipulated return on equity over the entire economic analysis period. For the example PC and 

NGCC power plant cases, the LCOE solutions are shown as dashed lines in the upper portion 

of .

Exhibit 2-15 also illustrates the relationship between COE and the assumed developmental and 

operational timelines for the power plants. As shown in the lower portion of Exhibit 2-15, the 

capital expenditure period is assumed to start in 2007 for all cases in this report. All capital costs 

included in this analysis, including project development and construction costs, are assumed to 

be incurred during the capital expenditure period. Coal-fueled plants are assumed to have a 

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

capital expenditure period of three years. Since both types of plants begin expending capital in 

the base year (2007), this means that the analysis assumes that they begin operating in different 

years: 2012 for coal plants and 2010 for natural gas plants in this study. Note that, according to 

the Chemical Engineering Plant Cost Index, June-2007 dollars are nearly equivalent to January2010 dollars.

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

operation for both coal and natural gas plants.

Since 2007 is the first year of the capital expenditure period, it is also the base year for the 

economic analysis. Accordingly, it is convenient to report the results of the economic analysis in 

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

dollars over the capital expenditure period.

 

7 For this current-dollar analysis, the LCOE is uniform in current dollars over the analysis period. In contrast, a 

constant-dollar analysis would yield an LCOE that is uniform in constant dollars over the analysis period.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

36

Exhibit 2-15 Illustration of COE Solutions using DCF Analysis

Consistent with our nominal-dollar discounted cash flow methodology, the COEs shown on

Exhibit 2-15 are expressed in current dollars. However, they can also be expressed in constant, 

base year dollars (June 2007) as shown in Exhibit 2-16 by adjusting them with the assumed 

nominal annual general inflation rate (3 percent).

Exhibit 2-16 illustrates the same information as in Exhibit 2-15 for a PC plant with CCS only on 

a constant 2007 dollar basis. With an assumed nominal COE escalation rate equal to the rate of 

inflation, the COE line now becomes horizontal and the LCOE decreases at a rate of 3 percent

per year.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

37

Exhibit 2-16 PC with CCS in Current 2007 Dollars

Estimating COE with Capital Charge Factors

For scenarios that adhere to the global economic assumptions listed in Exhibit 2-13 and utilize 

one of the finance structures listed in Exhibit 2-14, the following simplified equation can be used 

to estimate COE as a function of TOC8

Exhibit 2-17

, fixed O&M, variable O&M (including fuel), capacity 

factor and net output. The equation requires the application of one of the capital charge factors 

(CCF) listed in . These CCFs are valid only for the global economic assumptions 

listed in Exhibit 2-13, the stated finance structure, and the stated capital expenditure period. 

 

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

construction and interest during construction (along with other factors related to the recovery of capital costs). 
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38

Exhibit 2-17 Capital Charge Factors for COE Equation

Capital Expenditure Period Three Years

Finance Structure High Risk IOU Low Risk IOU

Capital Charge Factor (CCF) 0.111 0.105

All factors in the COE equation are expressed in base-year dollars. The base year is the first year 

of capital expenditure, which for this study is assumed to be 2007. As shown in Exhibit 2-13, all 

factors (COE, O&M and fuel) are assumed to escalate at a nominal annual general inflation rate 

of 3.0 percent. Accordingly, all first-year costs (COE and O&M) are equivalent to base-year 

costs when expressed in base-year (2007) dollars.

where:

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

during the power plant’s first year of operation (but expressed in baseyear dollars), assuming that the COE escalates thereafter at a nominal 

annual rate equal to the general inflation rate, i.e., that it remains constant 

in real terms over the operational period of the power plant.

CCF = capital charge factor taken from Exhibit 2-17 that matches the applicable 

finance structure and capital expenditure period

TOC = total overnight capital, expressed in base-year dollars

OCFIX = the sum of all fixed annual operating costs, expressed in base-year dollars

OCVAR = the sum of all variable annual operating costs, including fuel at 100

percent capacity factor, expressed in base-year dollars

CF = plant capacity factor, assumed to be constant over the operational period

MWH = annual net megawatt-hours of power generated at 100 percent capacity 

factor

The primary cost metric in this study is the COE, which is the base-year cost presented in baseyear dollars. Exhibit 2-18 presents this cost metric along with the COE escalated to the first year 

of operation using the average annual inflation rate of 3 percent. Similarly, the LCOE is 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

39

presented in both base-year dollars and first year of operation dollars. Using a similar 

methodology, the reader may generate either metric in the desired cost year basis.

Exhibit 2-18 COE and LCOE Summary

Case

COE (mills/kWh) LCOE (mills/kWh)

Base-Year First Operational 

Year Base-Year First Operational Year

2007$ 2010$ 2007$ 2010$

S31A 64.42 74.58 81.66 89.24

S31B 92.91 107.55 117.77 128.69

L31A 63.58 73.60 80.59 88.07

L31B 91.36 105.76 115.81 126.54

First Year CO2 Avoided Cost with Supercritical PC Reference

The cost of CO2 removal was calculated in two ways: the cost of CO2 avoided compared to the 

analogous non-capture design and the cost of CO2 avoided compared to a baseline supercritical 

(SC) PC plant at the same site location as the NGCC plant, using the equation below. The 

baseline SC PC plant is a 550 MW (net) plant with the results presented in Exhibit 2-19, and in 

Volume 3b of this study. The cost of electricity in the CO2 capture cases includes TS&M as well 

as capture and compression.

Exhibit 2-19 Baseline SC PC Results for CO2 Cost Calculation

Montana

(S12A)

North Dakota

(L12A)

Net Output (MW) 550 550

COE (2007 mills/kWh) 57.80 62.20

Emissions (lb/MWhnet) 1,892 1,996

CO Emissions CO Emissions tons MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

2 − 2

− =
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3. NGCC POWER PLANT PROCESS DESCRIPTIONS

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. 

Each design consists of two advanced F class combustion turbine generators (CTG), two HRSGs

and one STG in a multi-shaft 2x2x1 configuration. 

The NGCC cases are evaluated with and without carbon capture on a common thermal input 

basis for each site condition. The NGCC designs that include carbon dioxide recovery (CDR)

have a smaller plant net output resulting from the additional CDR facility auxiliary loads. Like 

in IGCC cases, the sizes of the NGCC designs were determined by the output of the 

commercially available CT. Hence, evaluation of the 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 

(2400 psig/1050°F/1050°F) steam cycle.

3.1 NGCC COMMON PROCESS AREAS

The four NGCC cases are nearly identical in configuration. With the exception of cases S31B 

and L31B, which include a CDR facility, the following process descriptions are common to all 

cases.

3.1.1 Natural Gas Supply System

It was assumed that a natural gas main with adequate capacity is in close proximity (within 16 

km [10 miles]) 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 study 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 advanced 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 are required. 

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 time-line 

record of gas consumption rates and cumulative consumption is provided.

3.1.2 Combustion Turbine

The combined cycle plant is based on two CTGs. The CTG is representative of the advanced F 

Class turbines with an ISO base rating of 184,400 kW when firing natural gas at International 

Standards Organization (ISO) conditions [26]. As elevation increases, the output is reduced due 

to the lower air density, resulting in less mass flow through the turbine for a given volumetric 

flow or rotational velocity. This machine is an axial flow, single spool, constant speed unit, with 

variable inlet guide vanes and dry LNB combustion system.
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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 

heating and ventilation; control systems including supervisory, fire protection, and fuel systems. 

No back up fuel was envisioned for this project.

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 3-1.

Exhibit 3-1 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

Heating, ventilating, and air conditioning (HVAC), Lighting, 

and Low Pressure (LP) CO2 Fire Protection System

MECHANICAL 

PACKAGE

HVAC and Lighting, Air Compressor for Pneumatic System, 

LP CO2 Fire Protection System

Lubricating Oil 

System and Control 

Oil System

Lube Oil Reservoir, Accumulators, 2x100% alternating current 

(AC) Driven Oil Pumps, direct current (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 and 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 Distributed control 

system (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
Cost and Performance Baseline - Volume 3c (NGCC Cases)

43

System System Scope

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

N. GAS FUEL 

SYSTEMS

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 (H2)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

The generators would typically be provided with the CT package. The generators are assumed to 

be 24 kilovolt (kV), 3-phase, 60 hertz (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.

3.1.3 Heat Recovery Steam Generator

The heat recovery steam generator (HRSG) is configured with high pressure (HP), intermediate 

pressure (IP), and LP steam drums, and superheater, reheater (RH), and economizer sections. 

The HP drum is supplied with feedwater (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 
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44

with FW from an interstage bleed on the HP boiler feed pump. The IP steam from the drum is 

superheated to 566°C (1,050°F) and mixed with hot reheat steam from the reheat section at 

566°C (1,050oF). The combined flows are admitted into the IP section of the steam turbine. The 

LP drum provides steam to the integral deaerator, and also 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 

(< 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 stainless steel (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.

3.1.4 NOx Control System

This reference plant is designed to achieve 2.5 parts per million volume dry (ppmvd) NOx 

emissions (expressed as nitrogen oxide (NO2) and referenced to 15 percent O2). Two measures 

are taken to reduce the NOx. The first is a dry LNB in the CTG. The dry LNB burners are a low 

NOx design and reduce the emissions to about 25 ppmvd (referenced to 15 percent O2) [27

The second measure taken to reduce the NOx emissions was the installation of a SCR system. 

SCR uses ammonia (NH3) and a catalyst to reduce NOx to N2 and H2O. The SCR system 

consists of reactor, and (NH3) supply and storage system. The SCR system is designed for 

90 percent reduction while firing natural gas. This along with the dry LNB achieves the 

emission limit of 2.5 ppmvd (referenced to 15 percent O2).

].

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. 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 (TiO2), vanadium 

pentoxide (V2O5), and tungsten trioxide (WO3). 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.

3.1.5 Carbon Dioxide Recovery Facility

A CDR facility is used in Cases S31B and L31B to remove 90 percent of the CO2 in the flue gas 

exiting the HRSG, dry it, and compress it to a SC condition. It is assumed that all of the carbon 
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45

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 reclaim process for the CO2 capture cases is based on the 

Fluor Econamine FG PlusSM technology [28,29]. A typical flowsheet is shown in Exhibit 3-2.

The Econamine FG Plus process uses a formulation of monoethanolamine (MEA) and a 

proprietary corrosion inhibitor to recover CO2 from the flue gas. This process is designed to 

recover high-purity CO2 from LP streams that contain O2, such as flue gas from coal-fired power 

plants, gas turbine exhaust gas, and other waste gases. The Econamine process used in this study 

differs from previous studies, including the 2003 IEA study [30

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

], in the following ways:

• Solvent consumption is decreased

• Hard to dispose waste from the plant is eliminated

The above are achieved at the expense of a slightly higher steam requirement in the stripper 

(3,693 kJ/kg [1,589 Btu/lb] versus 3,242 kJ/kg [1,395 Btu/lb] used in the IEA study) [31].
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Exhibit 3-2 Fluor Econamine FG Plus Typical Flow Diagram

PC

Flue Gas

to Ambient

Absorber Section

Makeup 

Wash Water

Cooling 

Water

Flue Gas

Excess Water

CWS

LP Steam

Condensate

Waste to 

Disposal

Stripper

Cooling 

Water

Cooling 

Water

Soda Ash 

Injection

Solvent 

Storage Tank

Make Up

Solvent 

Lean Solvent 

Lean Solvent 

Solvent Cross

Heat Exchanger

Reboiler

Reclaimer

Rich Solvent 

Rich Solvent 

Direct Contact 

Cooler (DCC) 

and Polishing 

Scrubber

Wash Water 

Filter

DCC

Circulating 

Water Filter

Blower

Condenser

Product CO2

Overhead 

Accumulator

Cooling 

Water

Semi-Rich Solvent

Water Wash 

Section

CWR

Corrosion 

Inhibitor
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Flue Gas Cooling and Supply 

The function of the flue gas cooling and supply system is to transport flue gases from the HRSG 

to the CO2 absorption tower, and condition flue gas pressure, temperature, and moisture content 

so it meets the requirements of the Econamine process. Temperature and hence moisture content 

of the flue gas exiting the HRSG is reduced in the Direct Contact Flue Gas Cooler, where flue 

gas is cooled using cooling water. 

The water condensed from the flue gas is collected in the bottom of the Direct Contact Flue Gas 

Cooler section and re-circulated to the top of the Direct Contact Flue Gas Cooler section via the 

Flue Gas Circulation Water Cooler, which rejects heat to the plant circulating water system. 

Level in the Direct Contact Flue Gas Cooler is controlled by directing the excess water to the 

cooling water return line. In the Direct Contact Flue Gas Cooler, flue gas is cooled beyond the 

CO2 absorption process requirements to 33°C (91°F) to account for the subsequent flue gas 

temperature increase of 14°C (25°F) in the flue gas blower. Downstream from the Direct 

Contact Flue Gas Cooler, flue gas pressure is boosted in the flue gas blowers by approximately 

0.014 MPa (2 pound per square inch [psi]) to overcome pressure drop in the CO2 absorber tower.

Circulating Water System

Cooling water is provided from the NGCC plant circulating water system and returned to the 

NGCC plant cooling tower. The CDR facility requires a significant amount of cooling water for 

flue gas cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer 

cooling, lean solvent cooler, and CO2 compression interstage cooling.

CO2 Absorption 

The cooled flue gas enters the bottom of the CO2 Absorber and flows up through the tower 

countercurrent to a stream of lean MEA-based solvent. Approximately 90 percent of the CO2 in 

the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorber section 

and flows into the water wash section of the tower. The lean solvent enters the top of the 

absorber, absorbs the CO2 from the flue gases, and leaves the bottom of the absorber with the 

absorbed CO2. The FG Plus process also includes solvent intercooling. The semi-rich solvent is 

extracted from the column, cooled using cooling water, and returned to the absorber section just 

below the extraction point. The CO2 carrying capacity of the solvent is increased at lower 

temperature, which reduces the solvent circulation rate.

Water Wash Section

The purpose of the Water Wash section is to minimize solvent losses due to mechanical 

entrainment and evaporation. The flue gas from the top of the CO2 Absorption section is 

contacted with a re-circulating stream of water for the removal of most of the lean solvent. The 

scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to 

the atmosphere via the vent stack. The water stream from the bottom of the wash section is 

collected on a chimney tray. A portion of the water collected on the chimney tray spills over to 

the absorber section as water makeup for the amine with the remainder pumped via the Wash 
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Water Pump, cooled by the Wash Water Cooler, and recirculated to the top of the CO2 Absorber. 

The wash water level is maintained by wash water makeup. 

Rich/Lean Amine Heat Exchange System

The rich solvent from the bottom of the CO2 Absorber is preheated by the lean solvent from the 

Solvent Stripper in the Lean/Rich Cross Exchanger. The heated rich solvent is routed to the 

Solvent Stripper for removal of the absorbed CO2. The stripped solvent from the bottom of the 

Solvent Stripper is pumped via the Lean Solvent Pump to the Lean Solvent Cooler. A slipstream 

of the lean solvent is then sent through the Amine Filter Package to prevent buildup of 

contaminants in the solution. The filtered lean solvent is mixed with the remaining lean solvent 

from the Lean Solvent Cooler and sent to the CO2 Absorber, completing the circulating solvent 

circuit.

Solvent Stripper

The purpose of the Solvent Stripper is to separate the CO2 from the rich solvent feed exiting the 

bottom of the CO2 Absorber. The rich solvent is collected on a chimney tray below the bottom 

packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the 

rich solvent is heated by steam, stripping the CO2 from the solution. Steam is provided from the 

crossover pipe between the IP and LP sections of the steam turbine and is 0.51 MPa (74 psia) 

and 152°C (306°F). The hot wet vapor from the top of the stripper containing CO2, steam, and 

solvent vapor, is partially condensed in the Solvent Stripper Condenser by cross exchanging the 

hot wet vapor with cooling water. The partially condensed stream then flows to the Solvent 

Stripper Reflux Drum where the vapor and liquid are separated. The uncondensed CO2-rich gas 

is then delivered to the CO2 product compressor. The condensed liquid from the Solvent 

Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a portion of 

condensed overhead liquid is used as make-up water for the Water Wash section of the CO2

Absorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which 

aids in limiting the amount of solvent vapors entering the stripper overhead system.

Solvent Stripper Reclaimer 

A small slipstream of the lean solvent from the Solvent Stripper bottoms is fed to the Solvent 

Stripper Reclaimer for the removal of high-boiling nonvolatile impurities (HSS), volatile acids, 

and iron products from the circulating solvent solution. The solvent bound in the HSS is 

recovered by reaction with caustic and heating with steam. The solvent reclaimer system 

reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned 

to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to 

the Solvent Reclaimer Drain Tank.

Steam Condensate

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer 

Condensate Drum and level controlled to the Solvent Reboiler Condensate Drum. Steam 

condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler 

Condensate Drum and returned to the steam cycle just downstream of the deaerator via the 

Solvent Reboiler Condensate Pumps.
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49

Corrosion Inhibitor System

A proprietary corrosion inhibitor is continuously injected into the CO2 Absorber rich solvent 

bottoms outlet line, the Solvent Stripper bottoms outlet line, and the Solvent Stripper top tray. 

This constant injection is to help control the rate of corrosion throughout the CO2 recovery plant 

system.

Gas Compression and Drying System

In the compression section, the CO2 is compressed to 15.3 MPa (2,215 psia) by a six-stage 

centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable 

power distribution and discharge temperatures across the various stages as shown in Exhibit 3-3.

Exhibit 3-3 CO2 Compressor Interstage Pressures

Stage Outlet Pressure, 

MPa (psia)

1 0.36 (52)

2 0.78 (113)

3 1.71 (248)

4 3.76 (545)

5 8.27 (1,200)

6 15.3 (2,215)

Power consumption for this large compressor was estimated assuming a polytropic efficiency of 

86 percent and a mechanical efficiency of 98 percent for all stages. During compression to 15.3 

MPa (2,215 psia) in the multiple-stage, intercooled compressor, the CO2 stream is dehydrated to 

a dewpoint of -40oC (-40°F) with triethylene glycol. The virtually moisture-free SC CO2 stream 

is delivered to the plant battery limit as sequestration ready. CO2 TS&M costs were estimated 

and included in LCOE and COE using the methodology described in Section 2.6.

3.1.6 Steam Turbine

The steam turbine consists of an HP section, an IP section, and one double-flow LP section, all 

connected to the generator by a common shaft. The HP and IP sections are contained in a single 

span, opposed-flow casing, with the double-flow LP section 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 (2400 psig/1050°F). The steam initially enters the turbine near the 

middle of the HP span, flows through the turbine, and returns to the HRSG for reheating. The 

reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 

2.5 MPa/564°C (360 psia/1047°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 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

50

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 closed-loop (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 low-pressure steam 

seal system. The generator is a hydrogen-cooled synchronous type, generating power at 24 kV. 

A static, transformer type exciter is provided. The generator is cooled with a hydrogen gas 

recirculation system using fans mounted on the generator rotor shaft. The 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.

3.1.7 Water and Steam Systems

Condensate

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

water-cooled condenser to the deaerator, through the gland steam condenser and the lowtemperature economizer section in the HRSG.

Feedwater

The function of the FW system is to pump the various FW streams from the deaerator storage 

tank in the HRSG to the respective steam drums. 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.

Steam System

The steam system is comprised of main, reheat, intermediate, and LP steam systems. The 

function of the main steam system is to convey main steam from the HRSG superheater outlet to 

the HP turbine stop valves. The function of the reheat system is to convey steam from the HP 

turbine exhaust to the HRSG RH and from the HRSG RH outlet to the turbine reheat stop valves.

Main steam exits the HRSG superheater through a motor-operated stop/check valve and a motoroperated gate valve, and is routed to the HP turbine.

Cold reheat steam exits the HP turbine, and flows through a motor-operated isolation gate valve 

to the HRSG RH. Hot reheat steam exits at the HRSG RH through a motor-operated gate valve 

and is routed to the IP turbines. 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

51

Circulating Water System

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

water and to an air-cooled condenser using ambient air and forced convection. A decision to use 

a parallel wet/dry cooling system was based primarily on the Xcel Energy Comanche 3 PC plant, 

and the desire to reduce the plant water requirement.

The major impact of parallel cooling is a significant reduction in water requirement when 

compared to a wet cooling system. This impact is included in the water balance presented later 

in this report.

Because of the low ambient temperatures at the sites in this study, a condenser pressure of 4.81 

kilopascal absolute (kPa) (0.698 psia) (condensing temperature of 32°C [90°F]) is used in the 

model as compared to 6.77 kPa (0.983 psia) (condensing temperature of 38°C [101°F]) used in 

Volume 1 of this report.

The CWS is a closed-cycle cooling water system that rejects heat through a wet cooling tower 

and supplies cooling water to the surface condenser to condense one-half of the main turbine 

exhaust steam. The system also supplies cooling water to the CDR plant as required, and to the 

auxiliary cooling system. The auxiliary cooling system is a CL process that utilizes a higher 

quality water to remove heat from compressor intercoolers, oil coolers and other ancillary 

equipment and transfers that heat to the main circulating cooling water system in plate and frame 

heat exchangers. The heat transferred to the circulating water in the surface condenser and other 

applications is removed by a mechanical draft cooling tower.

The system consists of two 50 percent capacity vertical CWPs, a mechanical draft evaporative 

cooling tower, and carbon steel (CS) cement-lined interconnecting piping. The pumps are 

single-stage vertical pumps. The piping system is equipped with butterfly isolation valves and 

all required expansion joints. The cooling tower is a multi-cell wood frame counterflow 

mechanical draft cooling tower.

The surface condenser is a single-pass, horizontal type with divided water boxes. There are two 

separate circulating water circuits in each box. One-half of the condenser can be removed from 

service for cleaning or for plugging tubes. This can be done during normal operation at reduced 

load. The air-cooled condenser utilizes ambient air and forced convection across tube bundles to 

condense the balance of the turbine exhaust steam.

Both condensers are equipped with an air extraction system to evacuate the condenser steam 

space for removal of non-condensable gases during steam turbine operation and to rapidly reduce 

the condenser pressure from atmospheric pressure before unit startup and admission of steam to 

the condenser.

3.1.8 Buildings and Structures

Structures assumed for NGCC cases can be summarized as follows:

1. Generation Building housing the STG
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52

2. CWP House

3. Administration / Office / Control Room / Maintenance Building 

4. Water Treatment Building

5. Fire Water Pump House

3.1.9 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.

3.1.10 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 

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.

3.2 NGCC PROCESS DESCRIPTION

This section contains an evaluation of plant designs for each of the four cases. All cases use a 

single reheat 16.5 MPa/566°C/566°C (2400 psig/1050°F/1050°F) cycle. Cases S31A and L31A 

as well as S31B and L31B differ from each other by ambient conditions, carbon capture, and 

hence the amount of natural gas feed to maintain the CT loading to the discrete value provided 

by the manufacturer.

The balance of Section 3.2 is organized as follows:

• Key Assumptions provides a summary of study and modeling assumptions relevant to all 

cases.

• Sparing Philosophy is provided for all cases.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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3.2.1 Key System Assumptions

System assumptions for NGCC with and without CO2 capture are compiled in Exhibit 3-4.

Exhibit 3-4 NGCC Plant Study Configuration Matrix

Cases S31A/L31A

w/o CO2 Capture 

Cases S31B/L31B

w/CO2 Capture

Steam Cycle, MPa/°C/°C (psig/°F/°F) 16.5/566/566 

(2400/1050/1050)

16.5/566/566 

(2400/1050/1050)

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) 36.0 (1.4) 36.0 (1.4)

Cooling Water to Condenser, °C (oF) 9 (48)/8 (47) 9 (48)/8 (47)

Cooling Water from Condenser, °C (oF) 20 (68)/19 (67) 20 (68)/19 (67)

Stack Temperature, °C (°F) 102 (215)/102 (216) 29 (85)

SO2 Control Low Sulfur Fuel Low Sulfur Fuel

NOx Control LNB and SCR LNB and SCR

SCR Efficiency, %1 90 90

Ammonia Slip (End of Catalyst Life), 

ppmv

10 10

Particulate Control N/A N/A

Hg Control N/A N/A

CO2 Control N/A Econamine

CO2 Capture, %1 N/A 90.7

CO2 Sequestration N/A Off-site Saline 

Formation 1 Removal efficiencies are based on the flue gas content

Balance of Plant 

The balance of plant assumptions are common to all NGCC cases and are presented in 

Exhibit 3-5.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit 3-5 NGCC Balance of Plant Assumptions

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 Horsepower (hp) 110/220 volt

Motors between 1 hp and 250 hp 480 volt

Motors between 250 hp and 

5,000 hp

4,160 volt

Motors above 5,000 hp 13,800 volt

Steam and GT generators 24,000 volt

Grid Interconnection voltage 345 kV

Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW 

and 50 percent from groundwater, and is assumed to 

be in sufficient quantities to meet plant makeup 

requirements.

Makeup for potable, process, and de-ionized (DI) 

water is drawn from municipal sources.

Process Wastewater 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 is treated for 

chloride and metals, and discharged.

3.2.2 Sparing Philosophy

Dual trains are used to accommodate the size of commercial gas turbines. There is no 

redundancy other than normal sparing of rotating equipment. The plant design consists of the 

following major subsystems:

• Two advanced F class CTGs (2 x 50%)
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• 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%)

• Two trains of Econamine CO2 capture (2 x 50%) (Capture cases)

3.3 CASES S31A AND L31A PROCESS DESCRIPTION

In this section the NGCC process without CO2 capture is described. The system description 

follows the block flow diagrams (BFD) in Exhibit 3-6.

The stream numbers in the following description reference the BFD in Exhibit 3-6. The tables in

Exhibit 3-7 and Exhibit 3-18, for cases S31A and L31A respectively, provide process data for 

the numbered streams in the BFD. The BFD shows only one of the two CT/HRSG 

combinations, but the flow rates in the stream table are the total for two systems.

Ambient air (stream 1) and natural gas (stream 2) are combined in the dry LNB, which is 

operated to control the rotor inlet temperature at 1371°C (2500°F). The flue gas exits the turbine 

around 628°C (1163°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 102°C (215°F) 

and passes to the plant stack.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit 3-6 Cases S31A and L31A Process Flow Diagram, NGCC without CO2 Capture

The balance of Section 3.3 is organized as follows:

• Performance Results - provides the main modeling results including the performance 

summary, environmental performance, water balance, mass and energy balance diagrams,

and energy balance table.

• Major Equipment List - provides an itemized list of major equipment with account codes 

that correspond to the cost accounts in the Cost Estimating section.

• Cost Estimating - provides a summary of capital and operating costs.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

57

3.3.1 Case S31A – Performance Results

The plant produces a net output of 512 MW at a net plant efficiency of 50.5 percent (HHV 

basis).

Major stream flows are shown in Exhibit 3-7 and overall plant performance is summarized in 

Exhibit 3-8, which includes auxiliary power requirements.

Exhibit 3-7 Case S31A Stream Table, NGCC without CO2 Capture

1 2 3 4 5 6 7 8

V-L Mole Fraction

Ar 0.0093 0.0000 0.0089 0.0089 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

C2H6 0.0000 0.0320 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

C4H10 0.0000 0.0040 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

CO2 0.0003 0.0100 0.0413 0.0413 0.0000 0.0000 0.0000 0.0000

H2O 0.0064 0.0000 0.0849 0.0849 1.0000 1.0000 1.0000 1.0000

N2 0.7759 0.0160 0.7451 0.7451 0.0000 0.0000 0.0000 0.0000

O2 0.2081 0.0000 0.1198 0.1198 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 98,174 4,020 102,311 102,311 19,410 12,552 12,552 25,662

V-L Flowrate (kg/hr) 2,836,748 69,653 2,906,401 2,906,401 349,679 226,125 226,125 462,303

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0

Temperature (°C) 6 38 628 102 566 32 32 32

Pressure (MPa, abs) 0.09 3.10 0.09 0.09 16.65 0.005 0.005 0.90

Enthalpy (kJ/kg)A 15.26 46.30 832.10 241.77 3,472.36 2,360.91 2,360.91 135.69

Density (kg/m3) 1.1 22.2 0.4 0.8 47.7 0.04 0.04 995.4

V-L Molecular Weight 28.895 17.328 28.408 28.408 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 216,437 8,862 225,556 225,556 42,792 27,672 27,672 56,574

V-L Flowrate (lb/hr) 6,253,958 153,559 6,407,517 6,407,517 770,911 498,521 498,521 1,019,203

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0

Temperature (°F) 42 100 1,163 215 1,050 90 90 90

Pressure (psia) 13.0 450.0 13.5 13.0 2,414.7 0.7 0.7 130.0

Enthalpy (Btu/lb)A 6.6 19.9 357.7 103.9 1,492.8 1,015.0 1,015.0 58.3

Density (lb/ft3) 0.070 1.384 0.022 0.051 2.977 0.002 0.002 62.141

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit 3-8 Case S31A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 335,300

Steam Turbine Power 186,800

TOTAL POWER, kWe 522,100

AUXILIARY LOAD SUMMARY, kWe

Condensate Pumps 150

Boiler Feedwater Pumps 2,450

Circulating Water Pump 1,060

Ground Water Pumps 100

Cooling Tower Fans 700

Air Cooled Condenser Fan 2,330

SCR 10

Gas Turbine Auxiliaries 700

Steam Turbine Auxiliaries 100

Miscellaneous Balance of Plant1 500

Transformer Losses 1,590

TOTAL AUXILIARIES, kWe 9,690

NET POWER, kWe 512,410

Net Plant Efficiency (HHV) 50.5%

Net Plant Efficiency (LHV) 56.0%

Net Plant Heat Rate (HHV), kJ/kWhr (Btu/kWhr) 7,130 (6,757)

Net Plant Heat Rate (LHV), kJ/kWhr (Btu/kWhr) 6,428 (6,093)

CONDENSER COOLING DUTY, 106 kJ/h (106 Btu/h) 1,023 (970)

CONSUMABLES

Natural Gas Feed Flow, kg/hr (lb/hr) 69,653 (153,559)

Thermal Input (HHV), kWth 1,014,787

Thermal Input (LHV) , kWth 914,961

Raw Water Withdrawal, m3/min (gpm) 4.1 (1,084)

Raw Water Consumption, m3/min (gpm) 3.2 (841) 1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline - Volume 3c (NGCC Cases)

59

Environmental Performance

The environmental targets for emissions of NOx, SO2, and PM were presented in Section 2.3. A 

summary of the plant air emissions for Case S31A is presented in Exhibit 3-9.

Exhibit 3-9 Case S31A Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 Negligible Negligible Negligible

NOx 0.004 (0.009) 106 (117) 0.027 (0.060)

Particulates Negligible Negligible Negligible

Hg Negligible Negligible Negligible

CO2 50.8 (118.3) 1,383,150 

(1,524,662) 356 (784)

CO2

1 363 (799)

1 CO2 emissions based on net power instead of gross power

The operation of the modern, state-of-the-art gas turbine fueled by natural gas, coupled to a 

HRSG, results in very low levels of NOx emissions and negligible levels of SO2, particulate, and 

Hg emissions. As noted in Section 2.3, if the fuel contains the maximum amount of sulfur 

compounds allowed in pipeline natural gas, the NGCC SO2 emissions would be 9.7 tonnes/yr 

(10.7 tons/yr) at 85 percent CF, or 0.00073 kg/GJ (0.0017 lb/MMBtu).

The low level of NOx production (2.5 ppmvd at 15 percent O2) is achieved by utilizing a dry 

LNB coupled with an SCR system.

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 is shown in Exhibit 3-10. The carbon input to the plant consists of carbon in 

the air in addition to carbon in the natural gas. One hundred percent carbon conversion is 

assumed since carbon conversion for NGCC plants is typically about 99.9 percent.

Carbon in the air is not neglected here since the model accounts for air components throughout. 

Carbon leaves the plant as CO2 in the stack gas.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit 3-10 Cases S31A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Natural Gas 50,310 (110,914) Stack Gas 50,696 (111,766)

Air (CO2) 387 (852)

Total 50,696 (111,766) Total 50,696 (111,766)

Exhibit 3-11 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, 

such as BFW blowdown, 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 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 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 3-11 Case S31A Water Balance

Water Use

Water 

Demand, 

m3/min 

(gpm)

Internal 

Recycle, 

m3/min 

(gpm)

Raw Water 

Withdrawal, 

m3/min (gpm)

Process 

Water 

Discharge, 

m3/min 

(gpm)

Raw Water 

Consumption, 

m3/min (gpm)

Condenser Makeup 0.08 (20) 0 (0) 0.08 (20) 0 (0) 0.08 (20)

 BFW Makeup 0.08 (20) 0 (0) 0.08 (20)

Cooling Tower 4.11 (1,084) 0.08 (20) 4.03 (1,064) 0.92 (244) 3.10 (820)

 BFW Blowdown 0 (0) 0.08 (20) -0.08 (-20)

Total 4.18 (1,105) 0.08 (20) 4.11 (1,084) 0.92 (244) 3.18 (841)

Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the NGCC in Exhibit 3-12.

An overall plant energy balance is provided in tabular form in Exhibit 3-13. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-8) is calculated by multiplying the power out by a combined 

generator efficiency of 98.4 percent.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Exhibit 3-12 Case S31A Heat and Mass Balance, NGCC without CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

T TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Nitrogen

Natural Gas

Carbon Dioxide

Water

Steam

PAGES

1 OF 1

NATURAL GAS COMBINED CYCLE PLANT

CASE S31A

2 X ADVANCED F-CLASS GT

2400/1050/1050

DWG. NO.

LROF-HMB-CS-S31A-PG-1

Flue Gas

AMBIENT

AIR

1 6,253,958 W

42.0 T

13.0 P

6.5 H

Gross Plant Power: 522 MWe

Auxiliary Load: 10 MWe

Net Plant Power: 512 MWe

Net Plant Efficiency, HHV: 50.5%

ADVANCED Net Plant Heat Rate: 6,757 Btu/kWh

F CLASS

GAS TURBINES

COMBUSTOR

NATURAL

GAS 153,559 W

100.0 T

450.0 P

19.9 H

2

6,407,517 W

215.5 T

13.0 P

103.9 H

6,407,517 W

1,163.2 T

13.5 P

357.7 H

GENERATOR

CONDENSATE

PUMPS

8,801 W

1,302 W

90.0 T

130.0 P

58.3 H

1,019,203 W

89.9 T

0.7 P

57.9 H

1,400 W

581.0 T

75.0 P

1,321.3 H

913,182 W

641.1 T

75.0 P

1,351.0 H

997,042 W

632.3 T

75.0 P

1,346.6 H

498,521 W

89.9 T

0.7 P

1,015.0 H

6 7

498,521 W

89.9 T

0.7 P

1,015.0 H

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

STACK

4

8

STEAM TURBINE

MAKEUP

10,192 W

42.0 T

13.0 P

10.1 H

AIR INLET

FILTER

3

HP PUMP

1,019,203 W

253.0 T

100.0 P

221.9 H

BLOWDOWN

84,707 W

300.1 T

95.0 P

269.4 H

155,798 W

300.7 T

400.0 P

270.7 H

778,698 W

305.3 T

2,540.0 P

279.3 H 10,192 W

GLAND SEAL

CONDENSER

1,400 W

212.0 T

14.7 P

179.9 H

LP TURBINE

89.9 T

0.7 P

1,015.0 H

9,569 W

1,019,203 W

92.9 T

120.0 P

61.2 H

Three Pressure 

Heat Recovery 

Steam Generator 

(HRSG)

743,251 W

1,055.0 T

360.0 P

1,553.4 H

A

A

154,240 W

1,055.0 T

360.0 P

1,553.4 H

HOT REHEAT

COLD

REHEAT

743,251 W

588.0 T

390.0 P

1,300.7 H

STEAM SEAL

REGULATOR

83,860 W

537.0 T

80.0 P

1,299.1 H

16,993 W

970.1 T

1,850.0 P

1,459.8 H

HP

TURBINE

IP

TURBINE

766,391 W

2,654 W

1,050.0 T

2,414.7 P

1,492.8 H

914,484 W

MAIN STEAM

770,911 W

1,050.0 T

2,414.7 P

1,492.8 H

5

10,969 W

866 W

IP

STEAM

IP PUMP

LP PUMP

DOE/NETL

SC PC PLANT

CASE S31A
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63

Exhibit 3-13 Case S31A Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 3,653 (3,463) 0.9 (0.9) 3,654 (3,463)

GT Air 43.3 (41.0) 43 (41)

Raw Water Withdrawal 5.7 (5.4) 6 (5)

Auxiliary Power 35 (33) 35 (33)

Totals 3,653 (3,463) 49.9 (47.3) 35 (33) 3,738 (3,543)

Heat Out GJ/hr (MMBtu/hr)

Cooling Tower BD 5.1 (4.9) 5 (5)

Stack Gas 703 (666) 703 (666)

Condenser 1,019 (966) 1,019 (966)

Process Losses1 131 (124) 131 (124)

Power 1,880 (1,781) 1,880 (1,781)

Totals 0 (0) 1,858 (1,761) 1,880 (1,781) 3,738 (3,543) 1

 Process Losses are calculated by difference and reflect various turbine and other heat and work losses not modeled 

in Aspen.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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3.3.2 Case S31A – 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 3.3.3. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

N/A

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

609,456 liters

(161,000 gal) 2 (0)

2 Condensate Pumps Vertical canned

4,278 lpm @ 110 m 

H2O

(1,130 gpm @ 360 

ft H2O)

2 (1)

3 Boiler Feedwater 

Pump

Horizontal, split 

case, multi-stage, 

centrifugal, with 

interstage bleed for 

IP and LP feedwater

HP water: 3,255 

lpm @ 2,103 m 

H2O (860 gpm @ 

6,900 ft H2O)

2 (1) IP water: 644 lpm 

@ 283 m H2O (170 

gpm @ 930 ft H2O)

LP water: 341 lpm 

@ 24.4 m H2O (90 

gpm @ 80 ft H2O)

4 Auxiliary Boiler Shop fabricated, 

water tube

18,144 kg/hr, 2.8 

MPa, 343°C

(40,000 lb/hr, 400 

psig, 650°F)

1 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

65

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

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

5,300 lpm @ 21 m 

H2O

(1,400 gpm @ 70 ft 

H2O)

2 (1)

9 Engine-Driven Fire 

Pump

Vertical turbine, 

diesel engine

3,785 lpm @ 107 m 

H2O

(1,000 gpm @ 350 

ft H2O)

1 (1)

10 Fire Service 

Booster Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m 

H2O

(700 gpm @ 250 ft 

H2O)

1 (1)

11 Raw Water Pumps Stainless steel, single 

suction

2,271 lpm @ 18 m 

H2O

(600 gpm @ 60 ft 

H2O)

2 (1)

12 Filtered Water 

Pumps

Stainless steel, single 

suction

151 lpm @ 49 m 

H2O

(40 gpm @ 160 ft 

H2O)

2 (1)

13 Filtered Water 

Tank Vertical, cylindrical 143,847 liter (38,000 gal) 1 (0)

14 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly 

and electrodeionization unit

341 lpm (90 gpm) 1 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

66

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

15 Gas Pipeline

Underground, coated 

carbon steel, 

wrapped cathodic 

protection

58 m3/min @ 3.1 

MPa (2,033 acfm @ 

450 psia) 

41 cm (16 in) 

standard wall pipe

16 km (0)

16 Gas Metering 

Station -- 58 m3

/min (2,033 

acfm) 1 (0)

17 Liquid Waste 

Treatment System

10 years, 24-hour 

storm

1 (0)

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES 

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/A

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

1 Gas Turbine Advanced F class w/ 

dry low-NOx burner 170 MW 2 (0)

2 Gas Turbine 

Generator TEWAC

190 MVA @ 0.9 

p.f., 24 kV, 60 Hz, 

3-phase

2 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

67

ACCOUNT 7 WASTE HEAT BOILER, 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

7.5 m (25 ft) diameter 2 (0)

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer 

section and 

integral deaerator

Main steam - 192,324 

kg/hr, 16.5 MPa/566°C 

(424,001 lb/hr, 2,400 

psig/1,050°F) 2 (0) Reheat steam - 223,903 

kg/hr, 2.4 MPa/566°C

(493,620 lb/hr, 345 

psig/1,050°F)

3 SCR Reactor Space for spare 

layer

1,596,647 kg/h (3,520,000 

lb/h) 2 (0)

4 SCR Catalyst -- Space available for an 

additional catalyst layer 1 layer (0)

5 Dilution Air 

Blowers Centrifugal 10 m3

/min @ 107 cm WG

(350 scfm @ 42 in WG) 2 (1)

6 Ammonia Feed 

Pump Centrifugal 3.8 lpm @ 91 m H2O

(1 gpm @ 300 ft H2O) 2 (1)

7 Ammonia 

Storage Tank Horizontal tank 60,567 liter (16,000 gal) 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition

Operating 

Qty. 

(Spares)

1 Steam Turbine

Tandem 

compound, HP, 

IP, and two-flow 

LP turbines

197 MW 

16.5 MPa/566°C/566°C 

(2,400 psig/ 

1050°F/1050°F)

1 (0)

2 Steam Turbine 

Generator

Hydrogen 

cooled, static 

excitation

220 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

68

Equipment 

No. Description Type Design Condition

Operating 

Qty. 

(Spares)

4 Surface 

Condenser

Single pass, 

divided waterbox 

including 

vacuum pumps

560 MMkJ/hr, (530 

MMBtu/hr), Inlet water 

temperature 9°C (48°F), 

Water temperature rise 

11°C (20°F)

1 (0)

5 Air-cooled 

Condenser ---

560 GJ/hr (530 

MMBtu/hr), Condensing 

temperature 32°C (90°F), 

Ambient temperature 6°C 

(42°F)

1 (0)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

1 Circulating 

Water Pumps Vertical, wet pit 105,992 lpm @ 30.5 m(28,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

3°C (37°F) wet bulb / 9°C 

(48°F) CWT / 20°C 

(68°F) HWT 1,149 

MMkJ/hr (1,090 

MMBtu/hr) heat load

1 (0)

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty. 

(Spares)

1 CTG Transformer Oil-filled 24 kV/345 kV, 190 MVA, 

3-ph, 60 Hz 2 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

69

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty. 

(Spares)

2 STG Transformer Oil-filled 24 kV/345 kV, 210 MVA, 

3-ph, 60 Hz 1 (0)

3 Auxiliary 

Transformer Oil-filled 24 kV/4.16 kV, 09 MVA, 3-ph, 60 Hz 1 (1)

4 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 1 MVA, 3-ph, 60 Hz 1 (1)

5

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 

self-cooled 24 kV, 3-ph, 60 Hz 2 (0)

6

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 

self-cooled 24 kV, 3-ph, 60 Hz 1 (0)

7 Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 (1)

8 Low Voltage 

Switchgear

Metal 

enclosed 480 V, 3-ph, 60 Hz 1 (1)

9 Emergency Diesel 

Generator

Sized for 

emergency 

shutdown

750 kW, 480 V, 3-ph, 60 Hz 1 (0)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty 

(Spares)

1 DCS - Main 

Control

Monitor/keyboard, 

Operator printer, 

Engineering 

printer

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)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

70

3.3.3 Case S31A – Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-14 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-15 shows a more 

detailed breakdown of the capital costs. Exhibit 3-16 itemizes the owner’s costs and 

Exhibit 3-17 shows the initial and annual O&M costs.

The estimated TOC of the NGCC with no CO2 capture is $817/kW. No process contingency was 

included in this case because all elements of the technology are commercially proven. The 

project contingency is 9.1 percent of TOC. The COE is 64.4 mills/kWh.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

71

Exhibit 3-14 Case S31A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S31A - 1x512 MWnet 2x1 7FB NGCC

Plant Size: 512.4 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& FeeProcess Project $ $/kW

 1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS $20,716 $3,813 $4,914 $0 $0 $29,442 $2,480 $0 $5,018 $36,941 $72

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,295 $0 $4,804 $0 $0 $80,099 $6,800 $0 $8,690 $95,589 $187

6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4

SUBTOTAL 6 $75,295 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,491 $190

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $87

7.2-7.9 SCR System, Ductwork and Stack $1,006 $851 $978 $0 $0 $2,835 $241 $0 $505 $3,582 $7

SUBTOTAL 7 $33,964 $851 $5,257 $0 $0 $40,071 $3,412 $0 $4,546 $48,029 $94

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $22,586 $0 $3,614 $0 $0 $26,200 $2,251 $0 $2,845 $31,297 $61

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $27,599 $753 $8,980 $0 $0 $37,331 $3,509 $0 $7,451 $48,290 $94

SUBTOTAL 8 $50,185 $753 $12,594 $0 $0 $63,531 $5,760 $0 $10,296 $79,587 $155

 9 COOLING WATER SYSTEM $4,569 $3,118 $3,227 $0 $0 $10,914 $912 $0 $1,693 $13,519 $26

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $16,014 $3,593 $8,565 $0 $0 $28,172 $2,160 $0 $3,223 $33,555 $65

12 INSTRUMENTATION & CONTROL $5,631 $578 $4,679 $0 $0 $10,888 $907 $0 $1,352 $13,147 $26

13 IMPROVEMENTS TO SITE $1,659 $901 $4,414 $0 $0 $6,974 $617 $0 $1,518 $9,109 $18

14 BUILDINGS & STRUCTURES $0 $3,885 $4,135 $0 $0 $8,020 $652 $0 $1,301 $9,973 $19

 

TOTAL COST $208,031 $18,210 $53,333 $0 $0 $279,574 $23,822 $0 $37,954 $341,350 $666

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline - Volume 3c (NGCC Cases)

72

Exhibit 3-15 Case S31A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S31A - 1x512 MWnet 2x1 7FB NGCC

Plant Size: 512.4 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& FeeProcess Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,247 $2,315 $1,904 $0 $0 $6,466 $533 $0 $1,050 $8,049 $16

3.2 Water Makeup & Pretreating $843 $88 $440 $0 $0 $1,371 $117 $0 $298 $1,786 $3

3.3 Other Feedwater Subsystems $1,025 $346 $291 $0 $0 $1,662 $134 $0 $269 $2,065 $4

3.4 Service Water Systems $100 $205 $666 $0 $0 $970 $85 $0 $211 $1,266 $2

3.5 Other Boiler Plant Systems $668 $259 $600 $0 $0 $1,527 $130 $0 $249 $1,906 $4

3.6 Natural Gas, incl. pipeline $14,655 $482 $420 $0 $0 $15,557 $1,319 $0 $2,531 $19,407 $38

3.7 Waste Treatment Equipment $304 $0 $173 $0 $0 $478 $42 $0 $104 $623 $1

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $874 $117 $419 $0 $0 $1,410 $122 $0 $306 $1,838 $4

SUBTOTAL 3. $20,716 $3,813 $4,914 $0 $0 $29,442 $2,480 $0 $5,018 $36,941 $72

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline - Volume 3c (NGCC Cases)

73

Exhibit 3-15 Case S31A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S31A - 1x512 MWnet 2x1 7FB NGCC

Plant Size: 512.4 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& FeeProcess Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,295 $0 $4,804 $0 $0 $80,099 $6,800 $0 $8,690 $95,589 $187

6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4

SUBTOTAL 6. $75,295 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,491 $190

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $87

7.2 SCR System $1,006 $422 $593 $0 $0 $2,022 $174 $0 $329 $2,525 $5

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2

SUBTOTAL 7. $33,964 $851 $5,257 $0 $0 $40,071 $3,412 $0 $4,546 $48,029 $94

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $22,586 $0 $3,614 $0 $0 $26,200 $2,251 $0 $2,845 $31,297 $61

8.2 Turbine Plant Auxiliaries $152 $0 $348 $0 $0 $500 $44 $0 $54 $598 $1

8.3a Condenser & Auxiliaries $2,332 $0 $696 $0 $0 $3,028 $259 $0 $329 $3,616 $7

8.3b Air Cooled Condenser $21,369 $0 $4,284 $0 $0 $25,654 $2,565 $0 $5,644 $33,863 $66

8.4 Steam Piping $3,746 $0 $2,463 $0 $0 $6,208 $476 $0 $1,003 $7,687 $15

8.9 TG Foundations $0 $753 $1,189 $0 $0 $1,941 $165 $0 $421 $2,527 $5

SUBTOTAL 8. $50,185 $753 $12,594 $0 $0 $63,531 $5,760 $0 $10,296 $79,587 $155

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $3,592 $0 $459 $0 $0 $4,052 $345 $0 $440 $4,836 $9

9.2 Circulating Water Pumps $662 $0 $29 $0 $0 $691 $52 $0 $74 $817 $2

9.3 Circ.Water System Auxiliaries $58 $0 $8 $0 $0 $66 $6 $0 $7 $79 $0

9.4 Circ.Water Piping $0 $1,700 $412 $0 $0 $2,112 $171 $0 $342 $2,625 $5

9.5 Make-up Water System $143 $0 $191 $0 $0 $335 $29 $0 $55 $418 $1

9.6 Component Cooling Water Sys $113 $135 $90 $0 $0 $338 $28 $0 $55 $421 $1

9.9 Circ.Water System Foundations $0 $1,283 $2,038 $0 $0 $3,320 $281 $0 $720 $4,322 $8

SUBTOTAL 9. $4,569 $3,118 $3,227 $0 $0 $10,914 $912 $0 $1,693 $13,519 $26

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline - Volume 3c (NGCC Cases)

74

Exhibit 3-15 Case S31A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case S31A - 1x512 MWnet 2x1 7FB NGCC

Plant Size: 512.4 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& FeeProcess Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $3,886 $0 $2,335 $0 $0 $6,221 $527 $0 $506 $7,254 $14

11.2 Station Service Equipment $1,192 $0 $100 $0 $0 $1,292 $107 $0 $105 $1,504 $3

11.3 Switchgear & Motor Control $1,469 $0 $250 $0 $0 $1,718 $143 $0 $186 $2,047 $4

11.4 Conduit & Cable Tray $0 $702 $2,164 $0 $0 $2,865 $248 $0 $467 $3,580 $7

11.5 Wire & Cable $0 $2,235 $1,372 $0 $0 $3,607 $232 $0 $576 $4,415 $9

11.6 Protective Equipment $0 $533 $1,814 $0 $0 $2,347 $205 $0 $255 $2,808 $5

11.7 Standby Equipment $99 $0 $91 $0 $0 $190 $16 $0 $21 $227 $0

11.8 Main Power Transformers $9,368 $0 $138 $0 $0 $9,506 $645 $0 $1,015 $11,166 $22

11.9 Electrical Foundations $0 $123 $302 $0 $0 $425 $36 $0 $92 $554 $1

SUBTOTAL 11. $16,014 $3,593 $8,565 $0 $0 $28,172 $2,160 $0 $3,223 $33,555 $65

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $716 $0 $447 $0 $0 $1,163 $98 $0 $189 $1,451 $3

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $214 $0 $128 $0 $0 $342 $29 $0 $56 $427 $1

12.7 Computer & Accessories $3,425 $0 $102 $0 $0 $3,527 $290 $0 $382 $4,199 $8

12.8 Instrument Wiring & Tubing $0 $578 $1,105 $0 $0 $1,683 $127 $0 $271 $2,081 $4

12.9 Other I & C Equipment $1,277 $0 $2,897 $0 $0 $4,173 $363 $0 $454 $4,990 $10

SUBTOTAL 12. $5,631 $578 $4,679 $0 $0 $10,888 $907 $0 $1,352 $13,147 $26

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $89 $1,770 $0 $0 $1,858 $165 $0 $405 $2,428 $5

13.2 Site Improvements $0 $812 $1,009 $0 $0 $1,821 $161 $0 $396 $2,379 $5

13.3 Site Facilities $1,659 $0 $1,636 $0 $0 $3,294 $291 $0 $717 $4,302 $8

SUBTOTAL 13. $1,659 $901 $4,414 $0 $0 $6,974 $617 $0 $1,518 $9,109 $18

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1

14.2 Steam Turbine Building $0 $1,879 $2,502 $0 $0 $4,381 $360 $0 $711 $5,452 $11

14.3 Administration Building $0 $443 $300 $0 $0 $743 $59 $0 $120 $923 $2

14.4 Circulation Water Pumphouse $0 $148 $73 $0 $0 $221 $17 $0 $36 $274 $1

14.5 Water Treatment Buildings $0 $182 $166 $0 $0 $348 $28 $0 $56 $432 $1

14.6 Machine Shop $0 $384 $246 $0 $0 $630 $50 $0 $102 $782 $2

14.7 Warehouse $0 $248 $150 $0 $0 $398 $31 $0 $64 $494 $1

14.8 Other Buildings & Structures $0 $74 $54 $0 $0 $128 $10 $0 $21 $159 $0

14.9 Waste Treating Building & Str. $0 $291 $519 $0 $0 $810 $67 $0 $132 $1,009 $2

SUBTOTAL 14. $0 $3,885 $4,135 $0 $0 $8,020 $652 $0 $1,301 $9,973 $19

TOTAL COST $208,031 $18,210 $53,333 $0 $0 $279,574 $23,822 $0 $37,954 $341,350 $666

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline - Volume 3c (NGCC Cases)

75

Exhibit 3-16 Case S31A Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $3,038 $6

1 Month Variable O&M $508 $1

25% of 1 Months Fuel Cost at 100% CF $4,505 $9

2% of TPC $6,827 $13

Total $14,878 $29

Inventory Capital

60 day supply of consumables at 100% CF $164 $0

0.5% of TPC (spare parts) $1,707 $3

Total $1,871 $4

 Initial Cost for Catalyst and Chemicals $0 $0

Land $300 $1

Other Owner's Costs $51,202 $100

Financing Costs $9,216 $18

Total Owner's Costs $77,468 $151

Total Overnight Cost (TOC) $418,817 $817

TASC Multiplier 1.075

Total As-Spent Cost (TASC) $450,229 $879
Cost and Performance Baseline - Volume 3c (NGCC Cases)

76

Exhibit 3-17 Case S31A Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case S31A - 1x512 MWnet 2x1 7FB NGCC Heat Rate-net (Btu/kWh): 6,757

MWe-net: 512

 Capacity Factor (%): 85

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 1.0 1.0

 Operator 2.0 2.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 1.0 1.0

 TOTAL-O.J.'s 5.0 5.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $1,972,971 $3.850

Maintenance Labor Cost $2,888,333 $5.637

Administrative & Support Labor $1,215,326 $2.372

Property Taxes and Insurance $6,826,992 $13.323

TOTAL FIXED OPERATING COSTS $12,903,622 $25.182

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $4,332,499 $0.00114

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0.00 780.48 1.08 $0 $261,921 $0.00007

Chemicals

MU & WT Chem. (lbs) 0.00 4649.87 0.17 $0 $249,672 $0.00007

MEA Solvent (ton) 0.00 0.00 2249.89 $0 $0 $0.00000

Activated Carbon (lb) 0.00 0.00 1.05 $0 $0 $0.00000

Corrosion Inhibitor 0.00 0.00 0.00 $0 $0 $0.00000

SCR Catalyst (m3) w/equip. 0.06 5775.94 $0 $116,099 $0.00003

Ammonia (19% NH3) ton 0.00 5.45 129.80 $0 $219,434 $0.00006

Subtotal Chemicals $0 $585,205 $0.00015

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000

Gases, N2 etc.(/100scf) 0.00 0.00 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Waste Disposal $0 $0 $0.00000

By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $5,179,625 $0.00136

Fuel (MMBtu) 0 83,097 7.13 $0 $183,795,700 $0.04817
Cost and Performance Baseline - Volume 3c (NGCC Cases)

77

3.3.4 Case L31A – Performance Results

The plant produces a net output of 547 MW at a net plant efficiency of 50.6 percent (HHV 

basis). 

Major stream flows are described in Exhibit 3-18 and overall plant performance is summarized 

in Exhibit 3-19, which includes auxiliary power requirements.

Exhibit 3-18 Case L31A Stream Table, NGCC without CO2 Capture

1 2 3 4 5 6 7 8

V-L Mole Fraction

Ar 0.0093 0.0000 0.0089 0.0089 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

C2H6 0.0000 0.0320 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

C4H10 0.0000 0.0040 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

CO2 0.0003 0.0100 0.0413 0.0413 0.0000 0.0000 0.0000 0.0000

H2O 0.0064 0.0000 0.0851 0.0851 1.0000 1.0000 1.0000 1.0000

N2 0.7759 0.0160 0.7451 0.7451 0.0000 0.0000 0.0000 0.0000

O2 0.2081 0.0000 0.1196 0.1196 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

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmol/hr) 104,424 4,282 108,830 108,830 20,569 13,340 13,340 27,253

V-L Flowrate (kg/hr) 3,017,333 74,190 3,091,523 3,091,523 370,555 240,318 240,318 490,976

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0

Temperature (°C) 4 38 628 102 566 32 32 32

Pressure (MPa, abs) 0.10 3.10 0.10 0.10 16.65 0.005 0.005 0.90

Enthalpy (kJ/kg)A 14.12 46.30 831.54 242.05 3,472.36 2,360.98 2,360.98 135.69

Density (kg/m3) 1.2 22.2 0.4 0.9 47.7 0.04 0.04 995.4

V-L Molecular Weight 28.895 17.328 28.407 28.407 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 230,215 9,439 239,928 239,928 45,347 29,409 29,409 60,083

V-L Flowrate (lb/hr) 6,652,082 163,560 6,815,642 6,815,642 816,935 529,812 529,812 1,082,416

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0

Temperature (°F) 40 100 1,162 216 1,050 90 90 90

Pressure (psia) 13.8 450.0 14.3 13.8 2,414.7 0.7 0.7 130.0

Enthalpy (Btu/lb)A 6.1 19.9 357.5 104.1 1,492.8 1,015.0 1,015.0 58.3

Density (lb/ft3) 0.074 1.384 0.023 0.054 2.977 0.002 0.002 62.141

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline - Volume 3c (NGCC Cases)

78

Exhibit 3-19 Case L31A Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 358,600

Steam Turbine Power 198,400

TOTAL POWER, kWe 557,000

AUXILIARY LOAD SUMMARY, kWe

Condensate Pumps 160

Boiler Feedwater Pumps 2,600

Circulating Water Pump 1,120

Ground Water Pumps 100

Cooling Tower Fans 700

Air Cooled Condenser Fan 2,340

SCR 10

Gas Turbine Auxiliaries 700

Steam Turbine Auxiliaries 100

Miscellaneous Balance of Plant1 500

Transformer Losses 1,690

TOTAL AUXILIARIES, kWe 10,020

NET POWER, kWe 546,980

Net Plant Efficiency (HHV) 50.6%

Net Plant Efficiency (LHV) 56.1%

Net Plant Heat Rate (HHV), kJ/kWhr (Btu/kWhr) 7,114 (6,743)

Net Plant Heat Rate (LHV), kJ/kWhr (Btu/kWhr) 6,414 (6,079)

CONDENSER COOLING DUTY, 106 kJ/h (106 Btu/h) 1,087 (1,030)

CONSUMABLES

Natural Gas Feed Flow, kg/hr (lb/hr) 74,190 (163,560)

Thermal Input (HHV), kWth 1,080,880

Thermal Input (LHV) , kWth 974,553

Raw Water Withdrawal, m3/min (gpm) 4.3 (1,148)

Raw Water Consumption, m3/min (gpm) 3.4 (890) 1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

79

Environmental Performance

The environmental targets for emissions of NOx, SO2, and PM were presented in Section 2.3. A 

summary of the plant air emissions for Case L31A is presented in Exhibit 3-20.

Exhibit 3-20 Case L31A Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 Negligible Negligible Negligible

NOx 0.004 (0.009) 113 (124) 0.027 (0.060)

Particulates Negligible Negligible Negligible

Hg Negligible Negligible Negligible

CO2 50.8 (118.3) 1,473,220 

(1,623,947) 355 (783)

CO2

1 362 (797)

1 CO2 emissions based on net power instead of gross power

The operation of the modern, state-of-the-art gas turbine fueled by natural gas, coupled to a 

HRSG, results in very low levels of NOx emissions and negligible levels of SO2, particulate, and 

Hg emissions. 

The low level of NOx production (2.5 ppmvd at 15 percent O2) is achieved by utilizing a dry 

LNB coupled with an SCR system.

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 is shown in Exhibit 3-21. The carbon input to the plant consists of carbon in 

the air in addition to carbon in the natural gas. One hundred percent carbon conversion is 

assumed since carbon conversion for NGCC plants is typically about 99.9 percent.

Carbon in the air is not neglected here since the model accounts for air components throughout. 

Carbon leaves the plant as CO2 in the stack gas.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

80

Exhibit 3-21 Cases L31A Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Natural 

Gas

53,586 

(118,138) Stack Gas 53,998 (119,044)

Air (CO2) 411 (907)

Total 53,998 

(119,044) Total 53,998 (119,044)

Exhibit 3-22 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as was for Case S31A.

Exhibit 3-22 Case L31A Water Balance

Water Use

Water 

Demand, 

m3/min 

(gpm)

Internal 

Recycle, 

m3/min 

(gpm)

Raw Water 

Withdrawal, 

m3/min 

(gpm)

Process 

Water 

Discharge, 

m3/min 

(gpm)

Raw Water 

Consumption, 

m3/min (gpm)

Condenser Makeup 0.08 (22) 0 (0) 0.08 (22) 0 (0) 0.08 (22)

 BFW Makeup 0.08 (22) 0 (0) 0.08 (22)

Cooling Tower 4.35 (1,148) 0.08 (22) 4.27 (1,127) 0.98 (258) 3.29 (868)

 BFW Blowdown 0 (0) 0.08 (22) -0.08 (-22)

Total 4.43 (1,170) 0.08 (22) 4.35 (1,148) 0.98 (258) 3.37 (890)

Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the NGCC in Exhibit 3-23.

An overall plant energy balance is provided in tabular form in Exhibit 3-24. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-19) is calculated by multiplying the power out by a combined 

generator efficiency of 98.4 percent.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

81

Exhibit 3-23 Case L31A Heat and Mass Balance, NGCC without CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

T TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Nitrogen

Natural Gas

Carbon Dioxide

Water

Steam

PAGES

1 OF 1

NATURAL GAS COMBINED CYCLE PLANT

CASE L31A

2 X ADVANCED F-CLASS GT

2400/1050/1050

DWG. NO.

LROF-HMB-CS-L31A-PG-1

Flue Gas

AMBIENT

AIR

1 6,652,082 W

40.0 T

13.8 P

6.0 H

Gross Plant Power: 557 MWe

Auxiliary Load: 10 MWe

Net Plant Power: 547 MWe

Net Plant Efficiency, HHV: 50.6%

ADVANCED Net Plant Heat Rate: 6,743 Btu/kWh

F CLASS

GAS TURBINES

COMBUSTOR

NATURAL

GAS 163,560 W

100.0 T

450.0 P

19.9 H

2

6,815,642 W

215.7 T

13.8 P

104.0 H

6,815,642 W

1,162.0 T

14.3 P

357.4 H

GENERATOR

CONDENSATE

PUMPS

8,801 W

1,302 W

90.0 T

130.0 P

58.3 H

1,082,416 W

89.9 T

0.7 P

57.9 H

1,400 W

581.0 T

75.0 P

1,321.3 H

970,326 W

641.3 T

75.0 P

1,351.1 H

1,059,623 W

632.4 T

75.0 P

1,346.7 H

529,812 W

89.9 T

0.7 P

1,015.0 H

6 7

529,812 W

89.9 T

0.7 P

1,015.0 H

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

STACK

4

8

STEAM TURBINE

MAKEUP

10,824 W

40.0 T

13.8 P

8.1 H

AIR INLET

FILTER

3

HP PUMP

1,082,416 W

253.0 T

100.0 P

221.9 H

BLOWDOWN

90,199 W

300.1 T

95.0 P

269.4 H

167,030 W

300.7 T

400.0 P

270.7 H

825,187 W

305.3 T

2,540.0 P

279.3 H 10,824 W

GLAND SEAL

CONDENSER

1,400 W

212.0 T

14.7 P

179.9 H

LP TURBINE

89.9 T

0.7 P

1,015.0 H

9,569 W

1,082,416 W

92.8 T

120.0 P

61.0 H

Three Pressure 

Heat Recovery 

Steam Generator 

(HRSG)

789,275 W

1,055.0 T

360.0 P

1,553.4 H

A

A

165,360 W

1,055.0 T

360.0 P

1,553.4 H

HOT REHEAT

COLD

REHEAT

789,275 W

588.0 T

390.0 P

1,300.6 H

STEAM SEAL

REGULATOR

89,297 W

537.0 T

80.0 P

1,299.1 H

16,993 W

970.1 T

1,850.0 P

1,459.8 H

HP

TURBINE

IP

TURBINE

812,415 W

2,654 W

1,050.0 T

2,414.7 P

1,492.8 H

971,628 W

MAIN STEAM

816,935 W

1,050.0 T

2,414.7 P

1,492.8 H

5

10,969 W

866 W

IP

STEAM

IP PUMP

LP PUMP

DOE/NETL

SC PC PLANT

CASE L31A
Cost and Performance Baseline - Volume 3c (NGCC Cases)

82

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Cost and Performance Baseline - Volume 3c (NGCC Cases)

83

Exhibit 3-24 Case L31A Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 3,891 (3,688) 0.8 (0.7) 3,892 (3,689)

GT Air 42.6 (40.4) 43 (40)

Raw Water 

Withdrawal 4.8 (4.6) 5 (5)

Auxiliary Power 36 (34) 36 (34)

Totals 3,891 (3,688) 48.2 (45.7) 36 (34) 3,975 (3,768)

Heat Out GJ/hr (MMBtu/hr)

Cooling Tower 

Blowdown 5.3 (5.0) 5 (5)

Stack Gas 748 (709) 748 (709)

Condenser 1,083 (1,026) 1,083 (1,026)

Process Losses1 134 (127) 134 (127)

Power 2,005 (1,901) 2,005 (1,901)

Totals 0 (0) 1,970 (1,867) 2,005 (1,901) 3,975 (3,768) 1

 Process Losses are calculated by difference and reflect various turbine and other heat and work losses not 

modeled in Aspen.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

84

3.3.5 Case L31A – 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 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.

ACCOUNT 1 FUEL HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

N/A

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition Operating Qty (Spares)

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor

647,310 liters (171,000 

gal) 2 (0)

2 Condensate Pumps Vertical canned

4,543 lpm @ 110 m H2O

(1,200 gpm @ 360 ft 

H2O)

2 (1)

3 Boiler Feedwater Pump

Horizontal, split case, 

multi-stage, centrifugal, 

with interstage bleed for 

IP and LP feedwater

HP water: 3,445 lpm @ 

2,103 m H2O (910 gpm 

@ 6,900 ft H2O)

2 (1)

IP water: 681 lpm @ 283 

m H2O (180 gpm @ 930 

ft H2O)

LP water: 379 lpm @ 

24.4 m H2O (100 gpm @ 

80 ft H2O)

4 Auxiliary Boiler Shop fabricated, water

tube

18,144 kg/h, 2.8 MPa, 

343°C

(40,000 lb/h, 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 5,300 lpm @ 21 m H2O

(1,400 gpm @ 70 ft H2O) 2 (1)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

85

Equipment 

No. Description Type Design Condition Operating Qty (Spares)

9 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 107 m H2O

(1,000 gpm @ 350 ft 

H2O)

1 (1)

10 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft H2O) 1 (1)

11 Raw Water Pumps Stainless steel, single 

suction

2,650 lpm @ 18 m H2O

(700 gpm @ 60 ft H2O) 2 (1)

12 Filtered Water Pumps Stainless steel, single 

suction

151 lpm @ 49 m H2O

(40 gpm @ 160 ft H2O) 2 (1)

13 Filtered Water Tank Vertical, cylindrical 143,847 liter (38,000 gal) 1 (0)

14 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly and 

electro-deionization unit

341 lpm (90 gpm) 1 (0)

15 Gas Pipeline

Underground, coated 

carbon steel, wrapped 

cathodic protection

61 m3

/min @ 3.1 MPa

(2,166 acfm @ 450 psia)

41 cm (16 in) standard 

wall pipe

16 km (0)

16 Gas Metering Station -- 61 m3/min (2,166 acfm) 1 (0)

17 Liquid Waste 

Treatment System 10 years, 24-hour storm 1 (0)

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES 

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/A

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty (Spares)

1 Gas Turbine Advanced F class w/ dry 

low-NOx burner 180 MW 2 (0)

2 Gas Turbine 

Generator TEWAC 200 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 2 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

86

ACCOUNT 7 WASTE HEAT BOILER, 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

7.5 m (25 ft) diameter 2 (0)

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer 

section and integral 

deaerator

Main steam - 203,806 kg/h, 16.5 

MPa/566°C (449,314 lb/h, 2,400 

psig/1,050°F) 2 (0) Reheat steam - 238,159 kg/h, 

2.4 MPa/566°C (525,049 lb/h, 

345 psig/1,050°F)

3 SCR Reactor Space for spare layer 1,700,973 kg/h (3,750,000 lb/h) 2 (0)

4 SCR Catalyst -- Space available for an additional 

catalyst layer 1 layer (0)

5 Dilution Air 

Blowers Centrifugal 10 m3

/min @ 107 cm WG

(370 scfm @ 42 in WG) 2 (1)

6 Ammonia Feed 

Pump Centrifugal 3.8 lpm @ 91 m H2O

(1 gpm @ 300 ft H2O) 2 (1)

7 Ammonia Storage 

Tank Horizontal tank 64,353 liter (17,000 gal) 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty (Spares)

1 Steam Turbine

Tandem compound, 

HP, IP, and two-flow 

LP turbines

209 MW 16.5 MPa/566°C/566°C 

(2,400 psig/ 1050°F/1050°F) 1 (0)

2 Steam Turbine 

Generator

Hydrogen cooled, static 

excitation

230 MVA @ 0.9 p.f., 24 kV, 60 

Hz, 3-phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam 

conditions 2 (0)

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

590 MMkJ/hr (560 MMBtu/hr), 

Inlet water temperature 8°C 

(47°F), Water temperature rise 

11°C (20°F)

1 (0)

5 Air-cooled 

Condenser ---

590 GJ/hr (560 MMBtu/hr), 

Condensing temperature 32°C 

(90°F), Ambient temperature 4°C 

(40°F)

1 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

87

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition Operating Qty (Spares)

1 Circulating Water 

Pumps Vertical, wet pit 113,563 lpm @ 30.5 m

(30,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

2°C (36°F) wet bulb / 8°C (47°F) 

CWT / 19°C (67°F) HWT 1,219 

MMkJ/hr (1,156 MMBtu/hr) heat 

load

1 (0)

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type L12A Design Condition Operating Qty (Spares)

1 CTG Transformer Oil-filled 24 kV/345 kV, 200 MVA, 

3-ph, 60 Hz 2 (0)

2 STG Transformer Oil-filled 24 kV/345 kV, 220 MVA, 

3-ph, 60 Hz 1 (0)

3 Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 09 MVA, 3-ph, 60 

Hz 1 (1)

4 Low Voltage

Transformer Dry ventilated 4.16 kV/480 V, 1 MVA, 

3-ph, 60 Hz 1 (1)

5 CTG Isolated Phase 

Bus Duct and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 (0)

6 STG Isolated Phase 

Bus Duct and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 (0)

7 Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 (1)

8 Low Voltage 

Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 (1)

9 Emergency Diesel 

Generator

Sized for 

emergency 

shutdown

750 kW, 480 V, 3-ph, 60 Hz 1 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

88

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type L12A Design Condition Operating Qty (Spares)

1 DCS - Main Control

Monitor/keyboard, 

Operator printer, 

Engineering printer

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)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

89

3.3.6 Case L31A – Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-25 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-26 shows a more 

detailed breakdown of the capital costs. Exhibit 3-27 itemizes the owner’s costs and 

Exhibit 3-28 shows the initial and annual O&M costs.

The estimated TOC of the NGCC with no CO2 capture is $782/kW. No process contingency was 

included in this case because all elements of the technology are commercially proven. The 

project contingency is 9.1 percent of TOC. The COE is 63.6 mills/kWh.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

90

Exhibit 3-25 Case L31A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L31A - 1x547 MWnet 2x1 7FB NGCC

Plant Size: 547.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& FeeProcess Project $ $/kW

 1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS $20,979 $3,972 $5,118 $0 $0 $30,069 $2,533 $0 $5,129 $37,732 $69

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $175

6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $3

SUBTOTAL 6 $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $178

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $81

7.2-7.9 SCR System, Ductwork and Stack $1,138 $906 $1,056 $0 $0 $3,100 $264 $0 $549 $3,913 $7

SUBTOTAL 7 $34,096 $906 $5,335 $0 $0 $40,337 $3,434 $0 $4,589 $48,361 $88

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,537 $0 $3,793 $0 $0 $27,329 $2,349 $0 $2,968 $32,646 $60

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $28,692 $786 $9,346 $0 $0 $38,825 $3,649 $0 $7,748 $50,222 $92

SUBTOTAL 8 $52,229 $786 $13,139 $0 $0 $66,154 $5,997 $0 $10,716 $82,868 $152

 9 COOLING WATER SYSTEM $4,765 $3,241 $3,350 $0 $0 $11,356 $949 $0 $1,760 $14,065 $26

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $16,538 $3,697 $8,860 $0 $0 $29,096 $2,231 $0 $3,326 $34,653 $63

12 INSTRUMENTATION & CONTROL $5,758 $591 $4,785 $0 $0 $11,134 $927 $0 $1,382 $13,443 $25

13 IMPROVEMENTS TO SITE $1,710 $929 $4,552 $0 $0 $7,191 $636 $0 $1,566 $9,393 $17

14 BUILDINGS & STRUCTURES $0 $3,996 $4,263 $0 $0 $8,259 $671 $0 $1,340 $10,270 $19

 

TOTAL COST $211,369 $18,839 $54,950 $0 $0 $285,158 $24,302 $0 $38,816 $348,275 $637

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline - Volume 3c (NGCC Cases)

91

Exhibit 3-26 Case L31A Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L31A - 1x547 MWnet 2x1 7FB NGCC

Plant Size: 547.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& FeeProcess Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,343 $2,414 $1,985 $0 $0 $6,742 $556 $0 $1,095 $8,392 $15

3.2 Water Makeup & Pretreating $878 $92 $459 $0 $0 $1,429 $122 $0 $310 $1,860 $3

3.3 Other Feedwater Subsystems $1,068 $361 $304 $0 $0 $1,733 $139 $0 $281 $2,153 $4

3.4 Service Water Systems $104 $214 $693 $0 $0 $1,011 $88 $0 $220 $1,319 $2

3.5 Other Boiler Plant Systems $696 $270 $625 $0 $0 $1,591 $135 $0 $259 $1,985 $4

3.6 Natural Gas, incl. pipeline $14,665 $501 $436 $0 $0 $15,602 $1,322 $0 $2,539 $19,463 $36

3.7 Waste Treatment Equipment $317 $0 $181 $0 $0 $498 $43 $0 $108 $649 $1

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $908 $121 $436 $0 $0 $1,465 $127 $0 $318 $1,909 $3

SUBTOTAL 3. $20,979 $3,972 $5,118 $0 $0 $30,069 $2,533 $0 $5,129 $37,732 $69

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline - Volume 3c (NGCC Cases)

92

Exhibit 3-26 Case L31A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L31A - 1x547 MWnet 2x1 7FB NGCC

Plant Size: 547.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& FeeProcess Project $ $/kW

 5A GAS CLEANUP & PIPING

5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $175

6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $3

SUBTOTAL 6. $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $178

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $81

7.2 SCR System $1,138 $478 $671 $0 $0 $2,288 $197 $0 $373 $2,857 $5

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2

SUBTOTAL 7. $34,096 $906 $5,335 $0 $0 $40,337 $3,434 $0 $4,589 $48,361 $88

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $23,537 $0 $3,793 $0 $0 $27,329 $2,349 $0 $2,968 $32,646 $60

8.2 Turbine Plant Auxiliaries $159 $0 $363 $0 $0 $522 $46 $0 $57 $625 $1

8.3a Condenser & Auxiliaries $2,423 $0 $724 $0 $0 $3,147 $270 $0 $342 $3,758 $7

8.3b Air Cooled Condenser $22,209 $0 $4,453 $0 $0 $26,662 $2,666 $0 $5,866 $35,193 $64

8.4 Steam Piping $3,901 $0 $2,565 $0 $0 $6,466 $495 $0 $1,044 $8,005 $15

8.9 TG Foundations $0 $786 $1,242 $0 $0 $2,029 $172 $0 $440 $2,641 $5

SUBTOTAL 8. $52,229 $786 $13,139 $0 $0 $66,154 $5,997 $0 $10,716 $82,868 $152

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $3,743 $0 $479 $0 $0 $4,222 $359 $0 $458 $5,039 $9

9.2 Circulating Water Pumps $695 $0 $31 $0 $0 $726 $55 $0 $78 $859 $2

9.3 Circ.Water System Auxiliaries $61 $0 $8 $0 $0 $69 $6 $0 $7 $82 $0

9.4 Circ.Water Piping $0 $1,772 $429 $0 $0 $2,201 $178 $0 $357 $2,736 $5

9.5 Make-up Water System $148 $0 $198 $0 $0 $346 $30 $0 $56 $433 $1

9.6 Component Cooling Water Sys $118 $141 $94 $0 $0 $352 $30 $0 $57 $439 $1

9.9 Circ.Water System Foundations $0 $1,329 $2,111 $0 $0 $3,440 $292 $0 $746 $4,477 $8

SUBTOTAL 9. $4,765 $3,241 $3,350 $0 $0 $11,356 $949 $0 $1,760 $14,065 $26

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline - Volume 3c (NGCC Cases)

93

Exhibit 3-26 Case L31A Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-09

Project: Low Rank Western Coal Baseline Study

Case: Case L31A - 1x547 MWnet 2x1 7FB NGCC

Plant Size: 547.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& FeeProcess Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $4,036 $0 $2,425 $0 $0 $6,461 $547 $0 $526 $7,534 $14

11.2 Station Service Equipment $1,222 $0 $103 $0 $0 $1,325 $109 $0 $108 $1,541 $3

11.3 Switchgear & Motor Control $1,506 $0 $256 $0 $0 $1,762 $146 $0 $191 $2,099 $4

11.4 Conduit & Cable Tray $0 $719 $2,218 $0 $0 $2,937 $254 $0 $479 $3,670 $7

11.5 Wire & Cable $0 $2,291 $1,407 $0 $0 $3,698 $238 $0 $590 $4,526 $8

11.6 Protective Equipment $0 $558 $1,898 $0 $0 $2,456 $215 $0 $267 $2,938 $5

11.7 Standby Equipment $102 $0 $93 $0 $0 $196 $17 $0 $21 $234 $0

11.8 Main Power Transformers $9,672 $0 $144 $0 $0 $9,817 $666 $0 $1,048 $11,531 $21

11.9 Electrical Foundations $0 $129 $316 $0 $0 $445 $38 $0 $97 $580 $1

SUBTOTAL 11. $16,538 $3,697 $8,860 $0 $0 $29,096 $2,231 $0 $3,326 $34,653 $63

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $732 $0 $457 $0 $0 $1,189 $101 $0 $193 $1,483 $3

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $219 $0 $131 $0 $0 $350 $30 $0 $57 $436 $1

12.7 Computer & Accessories $3,502 $0 $105 $0 $0 $3,607 $297 $0 $390 $4,293 $8

12.8 Instrument Wiring & Tubing $0 $591 $1,130 $0 $0 $1,721 $130 $0 $278 $2,128 $4

12.9 Other I & C Equipment $1,305 $0 $2,962 $0 $0 $4,268 $371 $0 $464 $5,102 $9

SUBTOTAL 12. $5,758 $591 $4,785 $0 $0 $11,134 $927 $0 $1,382 $13,443 $25

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $91 $1,825 $0 $0 $1,916 $170 $0 $417 $2,504 $5

13.2 Site Improvements $0 $838 $1,040 $0 $0 $1,878 $166 $0 $409 $2,453 $4

13.3 Site Facilities $1,710 $0 $1,687 $0 $0 $3,397 $300 $0 $739 $4,436 $8

SUBTOTAL 13. $1,710 $929 $4,552 $0 $0 $7,191 $636 $0 $1,566 $9,393 $17

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1

14.2 Steam Turbine Building $0 $1,948 $2,594 $0 $0 $4,542 $373 $0 $737 $5,652 $10

14.3 Administration Building $0 $452 $307 $0 $0 $759 $60 $0 $123 $943 $2

14.4 Circulation Water Pumphouse $0 $151 $75 $0 $0 $226 $18 $0 $37 $280 $1

14.5 Water Treatment Buildings $0 $190 $173 $0 $0 $362 $29 $0 $59 $450 $1

14.6 Machine Shop $0 $393 $251 $0 $0 $644 $51 $0 $104 $799 $1

14.7 Warehouse $0 $254 $153 $0 $0 $406 $32 $0 $66 $504 $1

14.8 Other Buildings & Structures $0 $76 $55 $0 $0 $131 $10 $0 $21 $163 $0

14.9 Waste Treating Building & Str. $0 $297 $531 $0 $0 $828 $69 $0 $134 $1,031 $2

SUBTOTAL 14. $0 $3,996 $4,263 $0 $0 $8,259 $671 $0 $1,340 $10,270 $19

TOTAL COST $211,369 $18,839 $54,950 $0 $0 $285,158 $24,302 $0 $38,816 $348,275 $637

TOTAL PLANT COST SUMMARY
Cost and Performance Baseline - Volume 3c (NGCC Cases)

94

Exhibit 3-27 Case L31A Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $3,056 $6

1 Month Variable O&M $517 $1

25% of 1 Months Fuel Cost at 100% CF $4,799 $9

2% of TPC $6,966 $13

Total $15,337 $28

Inventory Capital

60 day supply of consumables at 100% CF $174 $0

0.5% of TPC (spare parts) $1,741 $3

Total $1,915 $4

 Initial Cost for Catalyst and Chemicals $0 $0

Land $300 $1

Other Owner's Costs $52,241 $96

Financing Costs $9,403 $17

Total Owner's Costs $79,197 $145

Total Overnight Cost (TOC) $427,473 $782

TASC Multiplier 1.075

Total As-Spent Cost (TASC) $459,533 $840
Cost and Performance Baseline - Volume 3c (NGCC Cases)

95

Exhibit 3-28 Case L31A Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case L31A - 1x547 MWnet 2x1 7FB NGCC Heat Rate-net (Btu/kWh): 6,743

MWe-net: 547

 Capacity Factor (%): 85

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 1.0 1.0

 Operator 2.0 2.0

 Foreman 1.0 1.0

 Lab Tech's, etc. 1.0 1.0

 TOTAL-O.J.'s 5.0 5.0

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $1,972,971 $3.607

Maintenance Labor Cost $2,916,909 $5.333

Administrative & Support Labor $1,222,470 $2.235

Property Taxes and Insurance $6,965,508 $12.734

TOTAL FIXED OPERATING COSTS $13,077,858 $23.909

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $4,375,364 $0.00107

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0.00 826.56 1.08 $0 $277,385 $0.00007

Chemicals

MU & WT Chem. (lbs) 0.00 4924.41 0.17 $0 $264,413 $0.00006

MEA Solvent (ton) 0.00 0.00 2249.89 $0 $0 $0.00000

Activated Carbon (lb) 0.00 0.00 1.05 $0 $0 $0.00000

Corrosion Inhibitor 0.00 0.00 0.00 $0 $0 $0.00000

SCR Catalyst (m3) w/equip. 0.07 5775.94 $0 $123,497 $0.00003

Ammonia (19% NH3) ton 0.00 5.80 129.80 $0 $233,416 $0.00006

Subtotal Chemicals $0 $621,326 $0.00015

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000

Gases, N2 etc.(/100scf) 0.00 0.00 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Waste Disposal $0 $0 $0.00000

By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $5,274,074 $0.00129

Fuel (MMBtu) 0 88,519 7.13 $0 $195,789,067 $0.04807
Cost and Performance Baseline - Volume 3c (NGCC Cases)

96

3.4 CASES S31B AND L31B PROCESS DESCRIPTION

The plant configuration for these cases is the same as cases S31A and L31A with the exception 

being the Econamine FG Plus CDR technology was added for CO2 capture. The nominal net 

output decreases because the CT fixes the output and the CDR facility significantly increases the 

auxiliary power load.

A BFD is shown in Exhibit 3-29. Flue gas from the heat recovery system is processed in the 

Econamine system before exiting the stack. Since the CDR facility process description was 

provided in Section 3.1.5, it is not repeated here.

The tables in Exhibit 3-30 and Exhibit 3-41, for cases S31B and L31B respectively, provide 

process data for the numbered streams in the BFD. The BFD shows only one of the two 

CT/HRSG combinations, but the flow rates in the stream table are the total for two systems.

Exhibit 3-29 Cases S31B and L31B Process Flow Diagram, NGCC with CO2 Capture
Cost and Performance Baseline - Volume 3c (NGCC Cases)

97

The balance of Section 3.4 is organized as follows:

• Performance Results - provides the main modeling results including the performance 

summary, environmental performance, water balance, mass and energy balance diagrams,

and energy balance table.

• Major Equipment List - provides an itemized list of major equipment with account codes 

that correspond to the cost accounts in the Cost Estimating section.

• Cost Estimating - provides a summary of capital and operating costs.

3.4.1 Case S31B – Performance Results

The plant produces a net output of 435 MW at a net plant efficiency of 42.9 percent (HHV 

basis). 

Major stream flows are described in Exhibit 3-30 and overall plant performance is summarized 

in Exhibit 3-31, which includes auxiliary power requirements.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

98

Exhibit 3-30 Case S31B Stream Table, NGCC with CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13

V-L Mole Fraction

Ar 0.0093 0.0000 0.0089 0.0089 0.0098 0.0000 0.0000 0.0000 0.0000 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 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 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 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 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0003 0.0100 0.0413 0.0413 0.0045 0.9893 1.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0064 0.0000 0.0849 0.0849 0.0385 0.0107 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.7759 0.0160 0.7451 0.7451 0.8161 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2081 0.0000 0.1198 0.1198 0.1312 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 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

V-L Flowrate (kgmol/hr) 98,174 4,020 102,311 102,311 93,416 3,840 3,799 16,400 16,400 19,410 5,646 5,646 11,850

V-L Flowrate (kg/hr) 2,836,748 69,653 2,906,401 2,906,401 2,647,417 167,925 167,182 295,457 295,457 349,679 101,713 101,713 213,479

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 6 38 628 142 30 21 51 152 151 566 32 32 32

Pressure (MPa, abs) 0.09 3.10 0.09 0.09 0.09 0.16 15.27 0.51 0.49 16.65 0.005 0.005 0.90

Enthalpy (kJ/kg)A 15.26 46.30 832.10 284.57 91.45 26.65 -164.90 2,746.79 635.72 3,472.36 2,354.18 2,354.18 135.69

Density (kg/m3) 1.1 22.2 0.4 0.7 1.0 2.9 653.5 2.7 915.8 47.7 0.04 0.04 995.4

V-L Molecular Weight 28.895 17.328 28.408 28.408 28.340 43.731 44.010 18.015 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 216,437 8,862 225,556 225,556 205,947 8,466 8,375 36,157 36,157 42,792 12,447 12,447 26,124

V-L Flowrate (lb/hr) 6,253,958 153,559 6,407,517 6,407,517 5,836,555 370,210 368,573 651,371 651,371 770,911 224,240 224,240 470,640

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 42 100 1,163 288 85 69 124 306 304 1,050 90 90 90

Pressure (psia) 13.0 450.0 13.5 13.0 13.0 23.5 2,214.7 73.5 71.0 2,414.7 0.7 0.7 130.0

Enthalpy (Btu/lb)A 6.6 19.9 357.7 122.3 39.3 11.5 -70.9 1,180.9 273.3 1,492.8 1,012.1 1,012.1 58.3

Density (lb/ft3) 0.070 1.384 0.022 0.046 0.063 0.183 40.800 0.169 57.172 2.977 0.002 0.002 62.141

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline - Volume 3c (NGCC Cases)

99

Exhibit 3-31 Case S31B Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 335,300

Steam Turbine Power 134,700

TOTAL POWER, kWe 470,000

AUXILIARY LOAD SUMMARY, kWe

Condensate Pumps 70

Boiler Feedwater Pumps 2,440

Amine System Auxiliaries 8,800

CO2 Compression 13,950

Circulating Water Pump 3,400

Ground Water Pumps 280

Cooling Tower Fans 2,210

Air Cooled Condenser Fan 1,040

SCR 10

Gas Turbine Auxiliaries 700

Steam Turbine Auxiliaries 100

Miscellaneous Balance of Plant1 500

Transformer Losses 1,440

TOTAL AUXILIARIES, kWe 34,940

NET POWER, kWe 435,060

Net Plant Efficiency (HHV) 42.9%

Net Plant Efficiency (LHV) 47.5%

Net Plant Heat Rate (HHV), kJ/kWhr (Btu/kWhr) 8,397 (7,959)

Net Plant Heat Rate (LHV), kJ/kWhr (Btu/kWhr) 7,571 (7,176)

CONDENSER COOLING DUTY, 106 kJ/h (106 Btu/h) 464 (440)

CONSUMABLES

Natural Gas Feed Flow, kg/hr (lb/hr) 69,653 (153,559)

Thermal Input (HHV), kWth 1,014,787

Thermal Input (LHV) , kWth 914,961

Raw Water Withdrawal, m3/min (gpm) 11.8 (3,107)

Raw Water Consumption, m3/min (gpm) 8.8 (2,315) 1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline - Volume 3c (NGCC Cases)

100

Environmental Performance

The environmental targets for emissions of NOx, SO2, and PM were presented in Section 2.3. A 

summary of the plant air emissions for Case S31B is presented in Exhibit 3-32.

Exhibit 3-32 Case S31B Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 Negligible Negligible Negligible

NOx 0.004 (0.009) 106 (117) 0.030 (0.067)

Particulates Negligible Negligible Negligible

Hg Negligible Negligible Negligible

CO2 5.1 (11.8) 138,315 (152,466) 40 (87)

CO2

1 43 (94)

1 CO2 emissions based on net power instead of gross power

The operation of the modern, state-of-the-art gas turbine fueled by natural gas, coupled to a 

HRSG, results in very low levels of NOx emissions and negligible levels of SO2, particulate, and 

Hg emissions. As noted in Section 2.3, if the fuel contains the maximum amount of sulfur 

compounds allowed in pipeline natural gas, the NGCC SO2 emissions would be 9.7 tonnes/yr 

(10.7 tons/yr) at 85 percent CF, or 0.00073 kg/GJ (0.0017 lb/MMBtu).

The low level of NOx production (2.5 ppmvd at 15 percent O2) is achieved by utilizing a dry 

LNB coupled with an SCR system.

The carbon balance is shown in Exhibit 3-33. The carbon input to the plant consists of carbon in 

the air in addition to carbon in the natural gas. One hundred percent carbon conversion is 

assumed since carbon conversion for NGCC plants is typically about 99.9 percent.

Carbon in the air is not neglected here since the model accounts for air components throughout. 

Carbon leaves the plant as CO2 in the stack gas. 90.7 percent of carbon is separated in the MEA

process, compressed and sent to sequestration, reducing CO2 emissions to 94 lb/net-MWh. The 

carbon capture efficiency is defined as the amount of carbon in the CO2 product stream relative 

to the amount of carbon in the natural gas, represented by the following fraction:

(Carbon in CO2 Product)/(Carbon in the Natural Gas)*100 or

100,590/(110,914) *100 or

90.7 percent
Cost and Performance Baseline - Volume 3c (NGCC Cases)

101

Exhibit 3-33 Cases S31B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Natural Gas 50,310 (110,914) Stack Gas 5,070 (11,177)

Air (CO2) 387 (852) CO2 Product 45,627 (100,590)

Total 50,696 (111,766) Total 50,696 (111,766)

Exhibit 3-34 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, 

such as BFW blowdown, 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 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 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 3-34 Case S31B Water Balance

Water Use

Water 

Demand, 

m3/min (gpm)

Internal 

Recycle, 

m3/min (gpm)

Raw Water 

Withdrawal, 

m3/min 

(gpm)

Process 

Water 

Discharge, 

m3/min 

(gpm)

Raw Water 

Consumption, 

m3/min (gpm)

Econamine 0.04 (11) 0 (0) 0.04 (11) 0 (0) 0.04 (11)

Condenser Makeup 0.08 (20) 0 (0) 0.08 (20) 0 (0) 0.08 (20)

 BFW Makeup 0.08 (20) 0 (0) 0.08 (20)

Cooling Tower 13.23 (3,494) 1.61 (425) 11.62 (3,069) 2.97 (786) 8.64 (2,283)

 BFW Blowdown 0 (0) 0.08 (20) -0.08 (-20)

 Flue Gas Condensate 0 (0) 1.51 (398) -1.51 (-398)

 CO2 Product Condensate 0 (0) 0.03 (7) -0.03 (-7)

Total 13.35 (3,526) 1.61 (425) 11.74 (3,100) 2.97 (786) 8.76 (2,315)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

102

Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the NGCC in Exhibit 3-35.

An overall plant energy balance is provided in tabular form in Exhibit 3-36. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-31) is calculated by multiplying the power out by a combined 

generator efficiency of 98.4 percent.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

103

Exhibit 3-35 Case S31B Heat and Mass Balance, NGCC with CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

T TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Nitrogen

Natural Gas

Carbon Dioxide

Water

Steam

PAGES

1 OF 1

NATURAL GAS COMBINED CYCLE PLANT

CASE S31B

2 X ADVANCED F-CLASS GT

2400/1050/1050

DWG. NO.

LROF-HMB-CS-S31B-PG-1

Flue Gas

368,573 W

123.8 T

2,214.7 P

CO2

PRODUCT

AMBIENT

AIR

1 6,253,958 W

42.0 T

13.0 P

6.5 H

CO2 COMPRESSION 

(INTERSTAGE COOLING) 

& DRYING

370,210 W

69.0 T

23.5 P

11.5 H

KNOCKOUT 

WATER

198,938 W

85.2 T

13.0 P

8.7 H

Gross Plant Power: 470 MWe

Auxiliary Load: 35 MWe

Net Plant Power: 435 MWe

Net Plant Efficiency, HHV: 42.9%

ADVANCED Net Plant Heat Rate: 7,959 Btu/kWh

F CLASS

GAS TURBINES

COMBUSTOR

NATURAL

GAS 153,559 W

100.0 T

450.0 P

19.9 H

2

5,836,555 W

85.2 T

13.0 P

39.2 H

6,407,517 W

287.9 T

13.0 P

122.3 H

6,407,517 W

1,163.2 T

13.5 P

357.7 H

GENERATOR

CONDENSATE

PUMPS

8,801 W

1,302 W

90.0 T

130.0 P

58.3 H

470,640 W

89.9 T

0.7 P

57.9 H

5

1,400 W

581.0 T

75.0 P

1,321.3 H

913,182 W

641.1 T

75.0 P

1,351.0 H

448,479 W

621.5 T

75.0 P

1,341.3 H

224,240 W

89.9 T

0.7 P

1,012.1 H

11 12

224,240 W

89.9 T

0.7 P

1,012.1 H

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

STACK

4

REBOILER CONDENSATE

13

CONDENSATE

PUMPS

STEAM TURBINE

MAKEUP

10,192 W

42.0 T

13.0 P

10.1 H

DOE/NETL

SC PC PLANT

CASE S31B

AIR INLET

FILTER

3

HP PUMP

470,640 W

253.0 T

100.0 P

221.9 H

BLOWDOWN

84,707 W

300.1 T

95.0 P

269.4 H

155,798 W

300.7 T

400.0 P

270.7 H

778,698 W

305.3 T

2,540.0 P

279.3 H 10,192 W

STRIPPER

ABSORBER FLUE GAS ACID GAS

ECONAMINE FG+

BLOWER

548,563 W

641.1 T

75.0 P

1,351.0 H

WATER

1,638 W

100.0 T

14.7 P

GLAND SEAL

CONDENSER

1,400 W

212.0 T

14.7 P

179.9 H

LP TURBINE

STEAM TO REBOILER

651,371 W

306.2 T

73.5 P

1,180.9 H

89.9 T

0.7 P

1,012.1 H

9,569 W

470,640 W

96.3 T

120.0 P

64.5 H

Three Pressure 

Heat Recovery 

Steam Generator 

(HRSG)

743,251 W

1,055.0 T

360.0 P

1,553.4 H

A

A

154,240 W

1,055.0 T

360.0 P

1,553.4 H

HOT REHEAT

COLD

REHEAT

743,251 W

588.0 T

390.0 P

1,300.7 H

STEAM SEAL

REGULATOR

83,860 W

537.0 T

80.0 P

1,299.1 H

16,993 W

970.1 T

1,850.0 P

1,459.8 H

HP

TURBINE

IP

TURBINE

766,391 W

2,654 W

1,050.0 T

2,414.7 P

1,492.8 H

914,484 W

MAIN STEAM

770,911 W

1,050.0 T

2,414.7 P

1,492.8 H

6

7

8

9

10

10,969 W

866 W

IP

STEAM

548,563 W

303.9 T

73.5 P

273.3 H

IP PUMP

LP PUMP

651,371 W

303.9 T

71.0 P

273.3 H
Cost and Performance Baseline - Volume 3c (NGCC Cases)

104

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Cost and Performance Baseline - Volume 3c (NGCC Cases)

105

Exhibit 3-36 Case S31B Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 3,653 (3,463) 0.9 (0.9) 3,654 (3,463)

GT Air 43.3 (41.0) 43 (41)

Raw Water Withdrawal 16.4 (15.5) 16 (16)

Auxiliary Power 126 (119) 126 (119)

Totals 3,653 (3,463) 60.6 (57.4) 126 (119) 3,840 (3,639)

Heat Out GJ/hr (MMBtu/hr)

CO2 -27.6 (-26.1) -28 (-26)

Cooling Tower 

Blowdown 16.6 (15.7) 17 (16)

Econamine Losses 891.3 (844.8) 891 (845)

CO2 Compression 

Intercooling 77.9 (73.9) 78 (74)

Stack Gas 242 (229) 242 (229)

Condenser 464 (440) 464 (440)

Process Losses1 483 (458) 483 (458)

Power 1,692 (1,604) 1,692 (1,604)

Totals 0 (0) 2,148 (2,036) 1,692 (1,604) 3,840 (3,639) 1

 Process Losses are calculated by difference and reflect various turbine and other heat and work losses not modeled 

in Aspen.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

106

3.4.2 Case S31B – 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 3.4.3. In general, the design conditions include a 10 percent contingency for 

flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

N/A

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

609,456 liters

(161,000 gal) 2 (0)

2 Condensate Pumps Vertical canned

1,968 lpm @ 110 m 

H2O

(520 gpm @ 6,900 

ft H2O)

2 (1)

3 Boiler Feedwater 

Pump

Horizontal, split 

case, multi-stage, 

centrifugal, with 

interstage bleed for 

IP and LP feedwater

HP water: 3,255 

lpm @ 2,103 m 

H2O (860 gpm @ 

6,900 ft H2O)

2 (1) IP water: 644 lpm 

@ 283 m H2O (170 

gpm @ 930 ft H2O)

LP water: 341 lpm 

@ 24.4 m H2O (90 

gpm @ 80 ft H2O)

4 Auxiliary Boiler Shop fabricated, 

water tube

18,144 kg/hr, 2.8 

MPa, 343°C

(40,000 lb/hr, 400 

psig, 650°F)

1 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

107

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

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

5,300 lpm @ 21 m 

H2O

(1,400 gpm @ 70 ft 

H2O)

2 (1)

9 Engine-Driven Fire 

Pump

Vertical turbine, 

diesel engine

3,785 lpm @ 107 m 

H2O

(1,000 gpm @ 350 

ft H2O)

1 (1)

10 Fire Service 

Booster Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m 

H2O

(700 gpm @ 250 ft 

H2O)

1 (1)

11 Raw Water Pumps Stainless steel, single 

suction

6,435 lpm @ 18 m 

H2O

(1,700 gpm @ 60 ft 

H2O)

2 (1)

12 Filtered Water 

Pumps

Stainless steel, single 

suction

151 lpm @ 49 m 

H2O

(40 gpm @ 160 ft 

H2O)

2 (1)

13 Filtered Water 

Tank Vertical, cylindrical 143,847 liter (38,000 gal) 1 (0)

14 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly 

and electrodeionization unit

341 lpm (90 gpm) 1 (0)

15 Gas Pipeline

Underground, coated 

carbon steel, 

wrapped cathodic 

protection

58 m3/min @ 3.1 

MPa (2,033 acfm @ 

450 psia) 

41 cm (16 in) 

standard wall pipe

16 km (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

108

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

16 Gas Metering 

Station -- 58 m3

/min (2,033 

acfm) 1 (0)

17 Liquid Waste 

Treatment System

10 years, 24-hour 

storm 1 (0)

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES 

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/A

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment 

No. Description Type Design Condition Operating Qty (Spares)

1 Gas Turbine Advanced F class w/ dry 

low-NOx burner 170 MW 2 (0)

2 Gas Turbine 

Generator

TEWAC 190 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 2 (0)

ACCOUNT 7 WASTE HEAT BOILER, 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

6.5 m (21 ft) diameter

2 (0)

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer 

section and 

integral deaerator

Main steam - 192,324 

kg/hr, 16.5 MPa/566°C 

(424,001 lb/hr, 2,400 

psig/1,050°F) 2 (0) Reheat steam - 223,903 

kg/hr, 2.4 MPa/566°C

(493,620 lb/hr, 345 

psig/1,050°F)

3 SCR Reactor Space for spare 

layer

1,456,033 kg/h (3,210,000 

lb/h) 2 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

109

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

4 SCR Catalyst -- Space available for an 

additional catalyst layer 1 layer (0)

5 Dilution Air 

Blowers Centrifugal 10 m3

/min @ 107 cm WG

(350 scfm @ 42 in WG) 2 (1)

6 Ammonia Feed 

Pump Centrifugal 3.8 lpm @ 91 m H2O

(1 gpm @ 300 ft H2O) 2 (1)

7 Ammonia 

Storage Tank Horizontal tank 60,567 liter (16,000 gal) 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

1 Steam Turbine

Tandem 

compound, HP, 

IP, and two-flow 

LP turbines

142 MW 16.5 

MPa/566°C/566°C (2,400 

psig/ 1050°F/1050°F)

1 (0)

2 Steam Turbine 

Generator

Hydrogen 

cooled, static 

excitation

160 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design 

steam conditions 2 (0)

4 Surface 

Condenser

Single pass, 

divided waterbox 

including 

vacuum pumps

250 MMkJ/hr, (240 

MMBtu/hr), Inlet H2O 

temperature 9°C (48°F), 

H2O temperature rise 11°C 

(20°F)

1 (0)

5 Air-cooled 

Condenser ---

250 GJ/hr (240 

MMBtu/hr), Condensing 

temperature 32°C (90°F), 

Ambient temperature 6°C 

(42°F)

1 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

110

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition

Operating 

Qty 

(Spares)

1 Circulating 

Water Pumps Vertical, wet pit 340,690 lpm @ 30.5 m

(90,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

3°C (37°F) wet bulb / 9°C 

(48°F) CWT / 20°C 

(68°F) HWT 539 

MMkJ/hr (511 MMBtu/hr) 

heat load

1 (0)

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty 

(Spares)

1 CTG Transformer Oil-filled 24 kV/345 kV, 190 MVA, 

3-ph, 60 Hz 2 (0)

2 STG Transformer Oil-filled 24 kV/345 kV, 130 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 (1)

4 Medium Voltage 

Transformer Oil-filled 24 kV/4.16 kV, 22 MVA, 

3-ph, 60 Hz 1 (1)

5 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 3 MVA, 

3-ph, 60 Hz 1 (1)

6

CTG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 

self-cooled 24 kV, 3-ph, 60 Hz 2 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

111

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty 

(Spares)

7

STG Isolated 

Phase Bus Duct 

and Tap Bus

Aluminum, 

self-cooled 24 kV, 3-ph, 60 Hz 1 (0)

8 Medium Voltage 

Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 (1)

9 Low Voltage 

Switchgear

Metal 

enclosed 480 V, 3-ph, 60 Hz 1 (1)

10 Emergency Diesel 

Generator

Sized for 

emergency 

shutdown

750 kW, 480 V, 3-ph, 60 Hz 1 (0)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty 

(Spares)

1 DCS - Main 

Control

Monitor/keyboard, 

Operator printer, 

Engineering 

printer

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)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

112

3.4.3 Case S31B – Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-37 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-38 shows a more 

detailed breakdown of the capital costs. Exhibit 3-39 itemizes the owner’s costs and 

Exhibit 3-40 shows the initial and annual O&M costs.

The estimated TOC of the NGCC with CO2 capture is $1,607/kW. Process contingency accounts 

for 3.9 percent of the TOC. The project contingency is 10.9 percent of TOC. The COE, 

including CO2 TS&M costs of 3.4 mills/kWh, is 92.9 mills/kWh.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

113

Exhibit 3-37 Case S31B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-19

Project: Low Rank Western Coal Baseline Study

Case: Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 435.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS $22,829 $4,396 $6,973 $0 $0 $34,198 $2,888 $0 $5,963 $43,049 $99

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $115,518 $0 $35,189 $0 $0 $150,707 $12,909 $26,586 $38,040 $228,242 $525

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,295 $0 $4,804 $0 $0 $80,099 $6,800 $0 $8,690 $95,589 $220

6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4

SUBTOTAL 6 $75,295 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,491 $224

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $102

7.2-7.9 SCR System, Ductwork and Stack $1,006 $851 $978 $0 $0 $2,835 $241 $0 $505 $3,582 $8

SUBTOTAL 7 $33,963 $851 $5,257 $0 $0 $40,071 $3,412 $0 $4,546 $48,029 $110

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $17,924 $0 $3,200 $0 $0 $21,124 $1,816 $0 $2,294 $25,234 $58

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $17,489 $593 $6,554 $0 $0 $24,636 $2,265 $0 $4,811 $31,712 $73

SUBTOTAL 8 $35,413 $593 $9,754 $0 $0 $45,760 $4,081 $0 $7,105 $56,946 $131

 9 COOLING WATER SYSTEM $7,217 $5,431 $4,875 $0 $0 $17,523 $1,456 $0 $2,686 $21,664 $50

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $19,399 $5,344 $11,597 $0 $0 $36,341 $2,798 $0 $4,235 $43,373 $100

12 INSTRUMENTATION & CONTROL $6,097 $626 $5,066 $0 $0 $11,789 $982 $589 $1,531 $14,891 $34

13 IMPROVEMENTS TO SITE $1,657 $900 $4,409 $0 $0 $6,966 $616 $0 $1,516 $9,098 $21

14 BUILDINGS & STRUCTURES $0 $3,767 $3,888 $0 $0 $7,656 $621 $0 $1,242 $9,519 $22

 

TOTAL COST $317,388 $22,627 $92,556 $0 $0 $432,571 $36,686 $27,175 $75,870 $572,302 $1,315

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

114

Exhibit 3-38 Case S31B Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-19

Project: Low Rank Western Coal Baseline Study

Case: Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 435.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,247 $2,315 $1,904 $0 $0 $6,466 $533 $0 $1,050 $8,049 $19

3.2 Water Makeup & Pretreating $1,776 $186 $928 $0 $0 $2,889 $246 $0 $627 $3,763 $9

3.3 Other Feedwater Subsystems $1,025 $346 $291 $0 $0 $1,662 $134 $0 $269 $2,065 $5

3.4 Service Water Systems $210 $432 $1,402 $0 $0 $2,044 $179 $0 $445 $2,668 $6

3.5 Other Boiler Plant Systems $1,408 $546 $1,264 $0 $0 $3,218 $273 $0 $524 $4,015 $9

3.6 Natural Gas, incl. pipeline $14,640 $453 $395 $0 $0 $15,488 $1,313 $0 $2,520 $19,320 $44

3.7 Waste Treatment Equipment $641 $0 $365 $0 $0 $1,006 $88 $0 $219 $1,313 $3

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $883 $118 $424 $0 $0 $1,424 $123 $0 $309 $1,857 $4

SUBTOTAL 3. $22,829 $4,396 $6,973 $0 $0 $34,198 $2,888 $0 $5,963 $43,049 $99

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

115

Exhibit 3-38 Case S31B Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-19

Project: Low Rank Western Coal Baseline Study

Case: Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 435.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING

5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $101,984 $0 $30,944 $0 $0 $132,928 $11,386 $26,586 $34,180 $205,079 $471

5B.2 CO2 Compression & Drying $13,534 $0 $4,246 $0 $0 $17,779 $1,523 $0 $3,861 $23,163 $53

SUBTOTAL 5. $115,518 $0 $35,189 $0 $0 $150,707 $12,909 $26,586 $38,040 $228,242 $525

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,295 $0 $4,804 $0 $0 $80,099 $6,800 $0 $8,690 $95,589 $220

6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4

SUBTOTAL 6. $75,295 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,491 $224

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $102

7.2 SCR System $1,006 $422 $593 $0 $0 $2,022 $174 $0 $329 $2,525 $6

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2

SUBTOTAL 7. $33,963 $851 $5,257 $0 $0 $40,071 $3,412 $0 $4,546 $48,029 $110

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $17,924 $0 $3,200 $0 $0 $21,124 $1,816 $0 $2,294 $25,234 $58

8.2 Turbine Plant Auxiliaries $131 $0 $294 $0 $0 $426 $37 $0 $46 $510 $1

8.3 Condenser & Auxiliaries $1,339 $0 $400 $0 $0 $1,739 $149 $0 $189 $2,077 $5

8.3b Air Cooled Condenser $12,273 $0 $2,461 $0 $0 $14,733 $1,473 $0 $3,241 $19,448 $45

8.4 Steam Piping $3,746 $0 $2,463 $0 $0 $6,208 $476 $0 $1,003 $7,687 $18

8.9 TG Foundations $0 $593 $936 $0 $0 $1,529 $130 $0 $332 $1,990 $5

SUBTOTAL 8. $35,413 $593 $9,754 $0 $0 $45,760 $4,081 $0 $7,105 $56,946 $131

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,103 $0 $653 $0 $0 $5,756 $490 $0 $625 $6,871 $16

9.2 Circulating Water Pumps $1,500 $0 $83 $0 $0 $1,583 $119 $0 $170 $1,872 $4

9.3 Circ.Water System Auxiliaries $117 $0 $16 $0 $0 $133 $11 $0 $14 $159 $0

9.4 Circ.Water Piping $0 $3,426 $830 $0 $0 $4,256 $344 $0 $690 $5,290 $12

9.5 Make-up Water System $269 $0 $359 $0 $0 $628 $54 $0 $102 $784 $2

9.6 Component Cooling Water Sys $227 $272 $181 $0 $0 $681 $57 $0 $111 $848 $2

9.9 Circ.Water System Foundations $0 $1,733 $2,753 $0 $0 $4,486 $380 $0 $973 $5,840 $13

SUBTOTAL 9. $7,217 $5,431 $4,875 $0 $0 $17,523 $1,456 $0 $2,686 $21,664 $50

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

116

Exhibit 3-38 Case S31B Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-19

Project: Low Rank Western Coal Baseline Study

Case: Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 435.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $5,116 $0 $3,074 $0 $0 $8,190 $694 $0 $666 $9,550 $22

11.2 Station Service Equipment $1,906 $0 $161 $0 $0 $2,066 $171 $0 $168 $2,405 $6

11.3 Switchgear & Motor Control $2,349 $0 $399 $0 $0 $2,748 $228 $0 $298 $3,274 $8

11.4 Conduit & Cable Tray $0 $1,122 $3,460 $0 $0 $4,583 $397 $0 $747 $5,726 $13

11.5 Wire & Cable $0 $3,574 $2,195 $0 $0 $5,769 $372 $0 $921 $7,062 $16

11.6 Protective Equipment $0 $533 $1,814 $0 $0 $2,347 $205 $0 $255 $2,808 $6

11.7 Standby Equipment $94 $0 $86 $0 $0 $181 $15 $0 $20 $216 $0

11.8 Main Power Transformers $9,934 $0 $128 $0 $0 $10,062 $683 $0 $1,074 $11,819 $27

11.9 Electrical Foundations $0 $114 $281 $0 $0 $395 $34 $0 $86 $515 $1

SUBTOTAL 11. $19,399 $5,344 $11,597 $0 $0 $36,341 $2,798 $0 $4,235 $43,373 $100

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $775 $0 $484 $0 $0 $1,259 $107 $63 $214 $1,643 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $232 $0 $139 $0 $0 $370 $31 $19 $63 $483 $1

12.7 Computer & Accessories $3,708 $0 $111 $0 $0 $3,819 $314 $191 $432 $4,756 $11

12.8 Instrument Wiring & Tubing $0 $626 $1,196 $0 $0 $1,822 $137 $91 $308 $2,358 $5

12.9 Other I & C Equipment $1,382 $0 $3,136 $0 $0 $4,519 $393 $226 $514 $5,651 $13

SUBTOTAL 12. $6,097 $626 $5,066 $0 $0 $11,789 $982 $589 $1,531 $14,891 $34

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $89 $1,768 $0 $0 $1,856 $165 $0 $404 $2,425 $6

13.2 Site Improvements $0 $811 $1,008 $0 $0 $1,819 $161 $0 $396 $2,376 $5

13.3 Site Facilities $1,657 $0 $1,634 $0 $0 $3,291 $291 $0 $716 $4,297 $10

SUBTOTAL 13. $1,657 $900 $4,409 $0 $0 $6,966 $616 $0 $1,516 $9,098 $21

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1

14.2 Steam Turbine Building $0 $1,544 $2,056 $0 $0 $3,600 $296 $0 $584 $4,480 $10

14.3 Administration Building $0 $449 $305 $0 $0 $754 $60 $0 $122 $936 $2

14.4 Circulation Water Pumphouse $0 $143 $71 $0 $0 $214 $17 $0 $35 $265 $1

14.5 Water Treatment Buildings $0 $383 $350 $0 $0 $733 $59 $0 $119 $911 $2

14.6 Machine Shop $0 $390 $249 $0 $0 $639 $51 $0 $103 $793 $2

14.7 Warehouse $0 $252 $152 $0 $0 $404 $32 $0 $65 $501 $1

14.8 Other Buildings & Structures $0 $75 $55 $0 $0 $130 $10 $0 $21 $162 $0

14.9 Waste Treating Building & Str. $0 $295 $527 $0 $0 $822 $68 $0 $133 $1,023 $2

SUBTOTAL 14. $0 $3,767 $3,888 $0 $0 $7,656 $621 $0 $1,242 $9,519 $22

TOTAL COST $317,388 $22,627 $92,556 $0 $0 $432,571 $36,686 $27,175 $75,870 $572,302 $1,315

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

117

Exhibit 3-39 Case S31B Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $4,197 $10

1 Month Variable O&M $844 $2

25% of 1 Months Fuel Cost at 100% CF $4,505 $10

2% of TPC $11,446 $26

Total $20,992 $48

Inventory Capital

60 day supply of consumables at 100% CF $441 $1

0.5% of TPC (spare parts) $2,862 $7

Total $3,303 $8

 Initial Cost for Catalyst and Chemicals $755 $2

Land $300 $1

Other Owner's Costs $85,845 $197

Financing Costs $15,452 $36

Total Owner's Costs $126,647 $291

Total Overnight Cost (TOC) $698,949 $1,607

TASC Multiplier 1.078

Total As-Spent Cost (TASC) $753,467 $1,732
Cost and Performance Baseline - Volume 3c (NGCC Cases)

118

Exhibit 3-40 Case S31B Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case S31B - 1x435 MWnet 2x1 7FB NGCC w/ CO2 Capture Heat Rate-net (Btu/kWh): 7,959

MWe-net: 435

 Capacity Factor (%): 85

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 1.0 1.0

 Operator 3.3 3.3

 Foreman 1.0 1.0

 Lab Tech's, etc. 1.0 1.0

 TOTAL-O.J.'s 6.3 6.3

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $2,497,781 $5.741

Maintenance Labor Cost $4,216,800 $9.692

Administrative & Support Labor $1,678,645 $3.858

Property Taxes and Insurance $11,446,039 $26.309

TOTAL FIXED OPERATING COSTS $19,839,265 $45.601

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $6,325,200 $0.00195

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0.00 2,229.12 1.08 $0 $748,070 $0.00023

Chemicals

MU & WT Chem.(lbs) 0.00 13,280.45 0.17 $0 $713,086 $0.00022

MEA Solvent (ton) 316.29 0.44 2,249.89 $711,622 $310,049 $0.00010

Activated Carbon (lb) 0.00 530.59 1.05 $0 $172,875 $0.00005

Corrosion Inhibitor 0.00 0.00 0.00 $43,332 $2,063 $0.00000

SCR Catalyst (m3) w/equip. 0.06 5,775.94 $0 $116,099 $0.00004

Ammonia (19% NH3) (ton) 0.00 5.45 129.80 $0 $219,434 $0.00007

Subtotal Chemicals $754,953 $1,533,607 $0.00047

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000

Gases,N2 etc. (/100scf) 0.00 0.00 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Waste Disposal $0 $0 $0.00000

By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $754,953 $8,606,876 $0.00266

Fuel (MMBtu) 0 83,103 7.13 $0 $183,810,997 $0.05674
Cost and Performance Baseline - Volume 3c (NGCC Cases)

119

3.4.4 Case L31B – Performance Results

The plant produces a net output of 465 MW at a net plant efficiency of 43.0 percent (HHV 

basis). 

Major stream flows are described in Exhibit 3-41 and overall plant performance is summarized 

in Exhibit 3-42 which includes auxiliary power requirements.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

120

Exhibit 3-41 Case L31B Stream Table, NGCC without CO2 Capture

1 2 3 4 5 6 7 8 9 10 11 12 13

V-L Mole Fraction

Ar 0.0093 0.0000 0.0089 0.0089 0.0098 0.0000 0.0000 0.0000 0.0000 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 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 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 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 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0003 0.0100 0.0413 0.0413 0.0045 0.9893 1.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0064 0.0000 0.0851 0.0851 0.0362 0.0107 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

N2 0.7759 0.0160 0.7451 0.7451 0.8181 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.2081 0.0000 0.1196 0.1196 0.1314 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 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

V-L Flowrate (kgmol/hr) 104,424 4,282 108,830 108,830 99,118 4,090 4,046 17,468 17,468 20,569 5,985 5,985 12,543

V-L Flowrate (kg/hr) 3,017,333 74,190 3,091,523 3,091,523 2,811,389 178,860 178,068 314,689 314,689 370,555 107,817 107,817 225,973

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°C) 4 38 628 142 30 21 51 152 151 566 32 32 32

Pressure (MPa, abs) 0.10 3.10 0.10 0.10 0.10 0.16 15.27 0.51 0.49 16.65 0.005 0.005 0.90

Enthalpy (kJ/kg)A 14.12 46.30 831.54 284.90 87.73 26.65 -164.90 2,746.79 635.72 3,472.36 2,354.20 2,354.20 135.69

Density (kg/m3) 1.2 22.2 0.4 0.8 1.1 2.9 653.5 2.7 915.8 47.7 0.04 0.04 995.4

V-L Molecular Weight 28.895 17.328 28.407 28.407 28.364 43.731 44.010 18.015 18.015 18.015 18.015 18.015 18.015

V-L Flowrate (lbmol/hr) 230,215 9,439 239,928 239,928 218,518 9,017 8,920 38,510 38,510 45,347 13,194 13,194 27,653

V-L Flowrate (lb/hr) 6,652,082 163,560 6,815,642 6,815,642 6,198,051 394,318 392,574 693,772 693,772 816,935 237,696 237,696 498,185

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0 0 0

Temperature (°F) 40 100 1,162 288 85 69 124 306 304 1,050 90 90 90

Pressure (psia) 13.8 450.0 14.3 13.8 13.8 23.5 2,214.7 73.5 71.0 2,414.7 0.7 0.7 130.0

Enthalpy (Btu/lb)A 6.1 19.9 357.5 122.5 37.7 11.5 -70.9 1,180.9 273.3 1,492.8 1,012.1 1,012.1 58.3

Density (lb/ft3) 0.074 1.384 0.023 0.049 0.067 0.183 40.800 0.169 57.172 2.977 0.002 0.002 62.141

A - Reference conditions are 32.02 F & 0.089 PSIA
Cost and Performance Baseline - Volume 3c (NGCC Cases)

121

Exhibit 3-42 Case L31B Plant Performance Summary

POWER SUMMARY (Gross Power at Generator Terminals, kWe)

Gas Turbine Power 358,600

Steam Turbine Power 143,000

TOTAL POWER, kWe 501,600

AUXILIARY LOAD SUMMARY, kWe

Condensate Pumps 70

Boiler Feedwater Pumps 2,580

Amine System Auxiliaries 9,400

CO2 Compression 14,860

Circulating Water Pump 3,640

Ground Water Pumps 300

Cooling Tower Fans 2,230

Air Cooled Condenser Fan 1,040

SCR 10

Gas Turbine Auxiliaries 700

Steam Turbine Auxiliaries 100

Miscellaneous Balance of Plant1 500

Transformer Losses 1,530

TOTAL AUXILIARIES, kWe 36,960

NET POWER, kWe 464,640

Net Plant Efficiency (HHV) 43.0%

Net Plant Efficiency (LHV) 47.7%

Net Plant Heat Rate (HHV), kJ/kWhr (Btu/kWhr) 8,375 (7,938)

Net Plant Heat Rate (LHV), kJ/kWhr (Btu/kWhr) 7,551 (7,157)

CONDENSER COOLING DUTY, 106 kJ/h (106 Btu/h) 496 (470)

CONSUMABLES

Natural Gas Feed Flow, kg/hr (lb/hr) 74,190 (163,560)

Thermal Input (HHV), kWth 1,080,880

Thermal Input (LHV) , kWth 974,553

Raw Water Withdrawal, m3/min (gpm) 12.5 (3,309)

Raw Water Consumption, m3/min (gpm) 9.3 (2,461) 1 Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline - Volume 3c (NGCC Cases)

122

Environmental Performance

The environmental targets for emissions of NOx, SO2, and PM were presented in Section 2.3. A 

summary of the plant air emissions for Case L31B is presented in Exhibit 3-43.

Exhibit 3-43 Case L31B Air Emissions

kg/GJ

(lb/106 Btu)

Tonne/year

(ton/year) 

85% CF

kg/MWh

(lb/MWh)

SO2 Negligible Negligible Negligible

NOx 0.004 (0.009) 113 (124) 0.030 (0.066)

Particulates Negligible Negligible Negligible

Hg Negligible Negligible Negligible

CO2 5.1 (11.8) 147,322 (162,395) 39 (87)

CO2

1 43 (94)

1 CO2 emissions based on net power instead of gross power

The operation of the modern, state-of-the-art gas turbine fueled by natural gas, coupled to a 

HRSG, results in very low levels of NOx emissions and negligible levels of SO2, particulate, and 

Hg emissions.

The low level of NOx production (2.5 ppmvd at 15 percent O2) is achieved by utilizing a dry 

LNB coupled with an SCR system.

The carbon balance is shown in Exhibit 3-44. The carbon input to the plant consists of carbon in 

the air in addition to carbon in the natural gas. One hundred percent carbon conversion is 

assumed since carbon conversion for NGCC plants is typically about 99.9 percent.

Carbon in the air is not neglected here since the model accounts for air components throughout. 

Carbon leaves the plant as CO2 in the stack gas. 90.7 percent of carbon is separated in the MEA 

process, compressed and sent to sequestration, reducing CO2 emissions to 94 lb/MWh of net 

power. The carbon capture efficiency is defined as the amount of carbon in the CO2 product 

stream relative to the amount of carbon in the natural gas, represented by the following fraction:

(Carbon in CO2 Product)/(Carbon in the Natural Gas)*100 or

107,140/(118,138) *100 or

90.7 percent
Cost and Performance Baseline - Volume 3c (NGCC Cases)

123

Exhibit 3-44 Case L31B Carbon Balance

Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr)

Natural Gas 53,586 (118,138) Stack Gas 5,400 (11,904)

Air (CO2) 411 (907) CO2 Product 48,598 (107,140)

Total 53,998 (119,044) Total 53,998 (119,044)

Exhibit 3-45 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as was for Case S31B.

Exhibit 3-45 Case L31B Water Balance

Water Use

Water 

Demand, 

m3/min (gpm)

Internal 

Recycle, 

m3/min (gpm)

Raw Water 

Withdrawal, 

m3/min 

(gpm)

Process 

Water 

Discharge, 

m3/min 

(gpm)

Raw Water 

Consumption, 

m3/min (gpm)

Econamine 0.04 (12) 0 (0) 0.04 (12) 0 (0) 0.04 (12)

Condenser Makeup 0.08 (22) 0 (0) 0.08 (22) 0 (0) 0.08 (22)

 BFW Makeup 0.08 (22) 0 (0) 0.08 (22)

Cooling Tower 14.16 (3,740) 1.79 (472) 12.37 (3,269) 3.18 (841) 9.19 (2,427)

 BFW Blowdown 0 (0) 0.08 (22) -0.08 (-22)

 Flue Gas Condensate 0 (0) 1.68 (443) -1.68 (-443)

 CO2 Product Condensate 0 (0) 0.03 (7) -0.03 (-7)

Total 14.28 (3,773) 1.79 (472) 12.50 (3,302) 3.18 (841) 9.31 (2,461)

Heat and Mass Balance Diagrams

A heat and mass balance diagram is shown for the NGCC in Exhibit 3-46.

An overall plant energy balance is provided in tabular form in Exhibit 3-47. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-42) is calculated by multiplying the power out by a combined 

generator efficiency of 98.4 percent.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

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Cost and Performance Baseline - Volume 3c (NGCC Cases)

125

Exhibit 3-46 Case L31B Heat and Mass Balance, NGCC without CO2 Capture

NOTES:

1. ENTHALPY REFERENCE POINT IS NATURAL STATE

AT 32 °F AND 0.08865 PSIA

HEAT AND MATERIAL FLOW DIAGRAM

PLANT PERFORMANCE SUMMARY

LEGEND

P ABSOLUTE PRESSURE, PSIA

T TEMPERATURE, °F

W FLOWRATE, LBM/HR

H ENTHALPY, BTU/LBM

MWE POWER, MEGAWATTS ELECTRICAL

Air

Nitrogen

Natural Gas

Carbon Dioxide

Water

Steam

PAGES

1 OF 1

NATURAL GAS COMBINED CYCLE PLANT

CASE L31B

2 X ADVANCED F-CLASS GT

2400/1050/1050

DWG. NO.

LROF-HMB-CS-L31B-PG-1

Flue Gas

392,574 W

123.8 T

2,214.7 P

CO2

PRODUCT

AMBIENT

AIR

1 6,652,082 W

40.0 T

13.8 P

6.0 H

CO2 COMPRESSION 

(INTERSTAGE COOLING) 

& DRYING

394,318 W

69.0 T

23.5 P

11.5 H

KNOCKOUT 

WATER

221,341 W

85.2 T

13.8 P

8.6 H

Gross Plant Power: 502 MWe

Auxiliary Load: 37 MWe

Net Plant Power: 465 MWe

Net Plant Efficiency, HHV: 43.0%

ADVANCED Net Plant Heat Rate: 7,938 Btu/kWh

F CLASS

GAS TURBINES

COMBUSTOR

NATURAL

GAS 163,560 W

100.0 T

450.0 P

19.9 H

2

6,198,051 W

85.2 T

13.8 P

37.6 H

6,815,642 W

288.2 T

13.8 P

122.4 H

6,815,642 W

1,162.0 T

14.3 P

357.4 H

GENERATOR

CONDENSATE

PUMPS

8,801 W

1,302 W

90.0 T

130.0 P

58.3 H

498,185 W

89.9 T

0.7 P

57.9 H

5

1,400 W

581.0 T

75.0 P

1,321.3 H

970,326 W

641.3 T

75.0 P

1,351.1 H

475,392 W

621.5 T

75.0 P

1,341.3 H

237,696 W

89.9 T

0.7 P

1,012.1 H

11 12

237,696 W

89.9 T

0.7 P

1,012.1 H

HOT WELL

AIR-COOLED 

CONDENSER CONDENSER

STACK

4

REBOILER CONDENSATE

13

CONDENSATE

PUMPS

STEAM TURBINE

MAKEUP

10,824 W

40.0 T

13.8 P

8.1 H

AIR INLET

FILTER

3

HP PUMP

498,185 W

253.0 T

100.0 P

221.9 H

BLOWDOWN

90,199 W

300.1 T

95.0 P

269.4 H

167,030 W

300.7 T

400.0 P

270.7 H

825,187 W

305.3 T

2,540.0 P

279.3 H 10,824 W

STRIPPER

ABSORBER FLUE GAS ACID GAS

ECONAMINE FG+

BLOWER

584,232 W

641.3 T

75.0 P

1,351.1 H

WATER

1,745 W

100.0 T

14.7 P

GLAND SEAL

CONDENSER

1,400 W

212.0 T

14.7 P

179.9 H

LP TURBINE

STEAM TO REBOILER

693,772 W

306.2 T

73.5 P

1,180.9 H

89.9 T

0.7 P

1,012.1 H

9,569 W

498,185 W

95.9 T

120.0 P

64.2 H

Three Pressure 

Heat Recovery 

Steam Generator 

(HRSG)

789,275 W

1,055.0 T

360.0 P

1,553.4 H

A

A

165,360 W

1,055.0 T

360.0 P

1,553.4 H

HOT REHEAT

COLD

REHEAT

789,275 W

588.0 T

390.0 P

1,300.6 H

STEAM SEAL

REGULATOR

89,297 W

537.0 T

80.0 P

1,299.1 H

16,993 W

970.1 T

1,850.0 P

1,459.8 H

HP

TURBINE

IP

TURBINE

812,415 W

2,654 W

1,050.0 T

2,414.7 P

1,492.8 H

971,628 W

MAIN STEAM

816,935 W

1,050.0 T

2,414.7 P

1,492.8 H

6

7

8

9

10

10,969 W

866 W

IP

STEAM

584,232 W

303.9 T

73.5 P

273.3 H

IP PUMP

LP PUMP

693,772 W

303.9 T

71.0 P

273.3 H

DOE/NETL

SC PC PLANT

CASE L31B
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127

Exhibit 3-47 Case L31B Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + 

Latent Power Total

Heat In GJ/hr (MMBtu/hr)

Natural Gas 3,891 (3,688) 0.8 (0.7) 3,892 (3,689)

GT Air 42.6 (40.4) 43 (40)

Raw Water Withdrawal 13.9 (13.2) 14 (13)

Auxiliary Power 133 (126) 133 (126)

Totals 3,891 (3,688) 57.3 (54.3) 133 (126) 4,082 (3,869)

Heat Out GJ/hr (MMBtu/hr)

CO2 -29.4 (-27.8) -29 (-28)

Cooling Tower 

Blowdown 17.2 (16.3) 17 (16)

Econamine Losses 960.6 (910.5) 961 (911)

CO2 Compression 

Intercooling 83.0 (78.7) 83 (79)

Stack Gas 247 (234) 247 (234)

Condenser 491 (465) 491 (465)

Process Losses1 506 (480) 506 (480)

Power 1,806 (1,712) 1,806 (1,712)

Totals 0 (0) 2,276 (2,157) 1,806 (1,712) 4,082 (3,869) 1 Process Losses are calculated by difference and reflect various turbine and other heat and work losses not modeled 

in Aspen.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

128

3.4.5 Case L31B – 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 3.4.6. In general, the design conditions include a 10 percent contingency for 

flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 FUEL HANDLING

N/A

ACCOUNT 2 FUEL AND SORBENT PREPARATION AND FEED

N/A

ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND 

EQUIPMENT

Equipment 

No. Description Type Design Condition

Operating 

Qty

(Spares)

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor

647,310 liters (171,000 

gal) 2 (0)

2 Condensate Pumps Vertical canned

2,082 lpm @ 110 m 

H2O

(550 gpm @ 360 ft 

H2O)

2 (1)

3 Boiler Feedwater 

Pump

Horizontal, split case, 

multi-stage, centrifugal, 

with interstage bleed for 

IP and LP feedwater

HP water: 3,445 lpm @ 

2,103 m H2O (910 gpm 

@ 6,900 ft H2O)

2 (1)

IP water: 681 lpm @ 

283 m H2O (180 gpm 

@ 930 ft H2O)

LP water: 379 lpm @ 

24.4 m H2O (100 gpm 

@ 80 ft H2O)

4 Auxiliary Boiler Shop fabricated, water 

tube

18,144 kg/h, 2.8 MPa, 

343°C

(40,000 lb/h, 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

5,300 lpm @ 21 m H2O

(1,400 gpm @ 70 ft 

H2O)

2 (1)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

129

Equipment 

No. Description Type Design Condition

Operating 

Qty

(Spares)

9 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 107 m 

H2O

(1,000 gpm @ 350 ft 

H2O)

1 (1)

10 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 76 m H2O

(700 gpm @ 250 ft 

H2O)

1 (1)

11 Raw Water Pumps Stainless steel, single 

suction

6,814 lpm @ 18 m H2O

(1,800 gpm @ 60 ft 

H2O)

2 (1)

12 Filtered Water Pumps Stainless steel, single 

suction

151 lpm @ 49 m H2O

(40 gpm @ 160 ft H2O) 2 (1)

13 Filtered Water Tank Vertical, cylindrical 143,847 liter (38,000 

gal) 1 (0)

14 Makeup Water 

Demineralizer

Multi-media filter, 

cartridge filter, RO 

membrane assembly and 

electro-deionization unit

341 lpm (90 gpm) 1 (0)

15 Gas Pipeline

Underground, coated 

carbon steel, wrapped 

cathodic protection

61 m3/min @ 3.1 MPa

(2,166 acfm @ 450 

psia)

41 cm (16 in) standard 

wall pipe

16 km (0)

16 Gas Metering Station -- 61 m3

/min (2,166 

acfm) 1 (0)

17 Liquid Waste 

Treatment System 10 years, 24-hour storm 1 (0)

ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES 

N/A

ACCOUNT 5 FLUE GAS CLEANUP

N/A
Cost and Performance Baseline - Volume 3c (NGCC Cases)

130

ACCOUNT 6 COMBUSTION TURBINE GENERATORS AND AUXILIARIES

Equipment 

No. Description Type Design Condition

Operating 

Qty

(Spares)

1 Gas Turbine Advanced F class w/ dry 

low-NOx burner 180 MW 2 (0)

2 Gas Turbine 

Generator TEWAC 200 MVA @ 0.9 p.f., 24 

kV, 60 Hz, 3-phase 2 (0)

ACCOUNT 7 WASTE HEAT BOILER, 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

6.5 m (21 ft) diameter 2 (0)

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer section 

and integral 

deaerator

Main steam - 203,806 kg/h, 16.5 

MPa/566°C (449,314 lb/h, 

2,400 psig/1,050°F) 2 (0) Reheat steam - 238,159 kg/h, 

2.4 MPa/566°C (525,049 lb/h, 

345 psig/1,050°F)

3 SCR Reactor Space for spare layer 1,546,752 kg/h (3,410,000 lb/h) 2 (0)

4 SCR Catalyst -- Space available for an additional 

catalyst layer 1 layer (0)

5 Dilution Air 

Blowers Centrifugal 10 m3

/min @ 107 cm WG

(370 scfm @ 42 in WG) 2 (1)

6 Ammonia Feed 

Pump Centrifugal 3.8 lpm @ 91 m H2O

(1 gpm @ 300 ft H2O) 2 (1)

7 Ammonia Storage 

Tank Horizontal tank 64,353 liter (17,000 gal) 1 (0)

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

Equipment 

No. Description Type Design Condition

Operating 

Qty

(Spares)

1 Steam Turbine

Tandem compound, 

HP, IP, and twoflow LP turbines

151 MW 16.5 

MPa/566°C/566°C (2,400 psig/ 

1050°F/1050°F)

1 (0)

2 Steam Turbine 

Generator

Hydrogen cooled, 

static excitation

170 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 1 (0)

3 Steam Bypass One per HRSG 50% steam flow @ design steam 

conditions 2 (0)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

131

Equipment 

No. Description Type Design Condition

Operating 

Qty

(Spares)

4 Surface Condenser

Single pass, divided 

waterbox including 

vacuum pumps

270 MMkJ/hr, (260 MMBtu/hr), 

Inlet water temperature 8°C 

(47°F), Water temperature rise 

11°C (20°F)

1 (0)

5 Air-cooled 

Condenser --

270 GJ/hr (260 MMBtu/hr), 

Condensing temperature 32°C 

(90°F), Ambient temperature 

4°C (40°F)

1 (0)

ACCOUNT 9 COOLING WATER SYSTEM

Equipment 

No. Description Type Design Condition

Operating 

Qty

(Spares)

1 Circulating Water 

Pumps Vertical, wet pit 363,402 lpm @ 30.5 m

(96,000 gpm @ 100 ft) 2 (1)

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

2°C (36°F) wet bulb / 8°C 

(47°F) CWT / 19°C (67°F) 

HWT 569 MMkJ/hr (540 

MMBtu/hr) heat load

1 (0)

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING

N/A

ACCOUNT 11 ACCESSORY ELECTRIC PLANT

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty

(Spares)

1 CTG Transformer Oil-filled 24 kV/345 kV, 200 MVA, 

3-ph, 60 Hz 2 (0)

2 STG Transformer Oil-filled 24 kV/345 kV, 140 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 1 (1)

4 Medium Voltage 

Transformer Oil-filled 24 kV/4.16 kV, 23 MVA, 3-ph, 60 Hz 1 (1)

5 Low Voltage 

Transformer Dry ventilated 4.16 kV/480 V, 3 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)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

132

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty

(Spares)

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)

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment 

No. Description Type L12A Design Condition

Operating 

Qty

(Spares)

1 DCS - Main Control

Monitor/keyboard, 

Operator printer, 

Engineering printer

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)
Cost and Performance Baseline - Volume 3c (NGCC Cases)

133

3.4.6 Case L31B – Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-48 shows 

the total plant capital cost summary organized by cost account and Exhibit 3-49 shows a more 

detailed breakdown of the capital costs. Exhibit 3-50 itemizes the owner’s costs and 

Exhibit 3-51 shows the initial and annual O&M costs.

The estimated TOC of the NGCC with CO2 capture is $1,548/kW. Process contingency accounts 

for 3.9 percent of the TOC. The project contingency is 10.9 percent of TOC. The COE, 

including CO2 TS&M costs of 3.3 mills/kWh, is 91.4 mills/kWh.
Cost and Performance Baseline - Volume 3c (NGCC Cases)

134

Exhibit 3-48 Case L31B Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-19

Project: Low Rank Western Coal Baseline Study

Case: Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 464.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS $23,198 $4,585 $7,280 $0 $0 $35,063 $2,961 $0 $6,122 $44,146 $95

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $119,974 $0 $36,547 $0 $0 $156,521 $13,407 $27,611 $39,508 $237,047 $510

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $206

6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4

SUBTOTAL 6 $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $210

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $96

7.2-7.9 SCR System, Ductwork and Stack $1,138 $906 $1,056 $0 $0 $3,100 $264 $0 $549 $3,913 $8

SUBTOTAL 7 $34,096 $906 $5,335 $0 $0 $40,337 $3,434 $0 $4,589 $48,361 $104

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $18,712 $0 $3,357 $0 $0 $22,068 $1,897 $0 $2,397 $26,362 $57

8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $18,435 $619 $6,876 $0 $0 $25,930 $2,386 $0 $5,067 $33,382 $72

SUBTOTAL 8 $37,147 $619 $10,232 $0 $0 $47,998 $4,283 $0 $7,464 $59,744 $129

 9 COOLING WATER SYSTEM $7,556 $5,648 $5,090 $0 $0 $18,293 $1,520 $0 $2,801 $22,614 $49

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $20,098 $5,521 $12,017 $0 $0 $37,636 $2,898 $0 $4,383 $44,917 $97

12 INSTRUMENTATION & CONTROL $6,236 $640 $5,181 $0 $0 $12,057 $1,004 $603 $1,566 $15,230 $33

13 IMPROVEMENTS TO SITE $1,709 $928 $4,547 $0 $0 $7,184 $636 $0 $1,564 $9,384 $20

14 BUILDINGS & STRUCTURES $0 $3,876 $4,009 $0 $0 $7,885 $640 $0 $1,279 $9,804 $21

 

TOTAL COST $325,306 $23,444 $95,786 $0 $0 $444,536 $37,706 $28,214 $78,282 $588,738 $1,267

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

135

Exhibit 3-49 Case L31B Total Plant Cost Details

Client: USDOE/NETL Report Date: 2009-Oct-19

Project: Low Rank Western Coal Baseline Study

Case: Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 464.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

 1 COAL & SORBENT HANDLING

1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 2 COAL & SORBENT PREP & FEED

2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 3 FEEDWATER & MISC. BOP SYSTEMS

3.1 Feedwater System $2,343 $2,414 $1,985 $0 $0 $6,742 $556 $0 $1,095 $8,392 $18

3.2 Water Makeup & Pretreating $1,858 $194 $970 $0 $0 $3,022 $258 $0 $656 $3,935 $8

3.3 Other Feedwater Subsystems $1,068 $361 $304 $0 $0 $1,733 $139 $0 $281 $2,153 $5

3.4 Service Water Systems $220 $452 $1,467 $0 $0 $2,138 $187 $0 $465 $2,790 $6

3.5 Other Boiler Plant Systems $1,473 $571 $1,322 $0 $0 $3,366 $286 $0 $548 $4,199 $9

3.6 Natural Gas, incl. pipeline $14,649 $471 $410 $0 $0 $15,530 $1,316 $0 $2,527 $19,373 $42

3.7 Waste Treatment Equipment $670 $0 $382 $0 $0 $1,053 $92 $0 $229 $1,373 $3

3.8 Misc. Equip.(cranes,AirComp.,Comm.) $917 $123 $440 $0 $0 $1,480 $128 $0 $322 $1,930 $4

SUBTOTAL 3. $23,198 $4,585 $7,280 $0 $0 $35,063 $2,961 $0 $6,122 $44,146 $95

 4 GASIFIER & ACCESSORIES

4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

136

Exhibit 3-49 Case L31B Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-19

Project: Low Rank Western Coal Baseline Study

Case: Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 464.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING

5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION

5B.1 CO2 Removal System $105,919 $0 $32,137 $0 $0 $138,056 $11,825 $27,611 $35,498 $212,990 $458

5B.2 CO2 Compression & Drying $14,056 $0 $4,409 $0 $0 $18,465 $1,582 $0 $4,009 $24,057 $52

SUBTOTAL 5. $119,974 $0 $36,547 $0 $0 $156,521 $13,407 $27,611 $39,508 $237,047 $510

 6 COMBUSTION TURBINE/ACCESSORIES

6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $206

6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4

SUBTOTAL 6. $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $210

 7 HRSG, DUCTING & STACK

7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $96

7.2 SCR System $1,138 $478 $671 $0 $0 $2,288 $197 $0 $373 $2,857 $6

7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2

SUBTOTAL 7. $34,096 $906 $5,335 $0 $0 $40,337 $3,434 $0 $4,589 $48,361 $104

 8 STEAM TURBINE GENERATOR 

8.1 Steam TG & Accessories $18,712 $0 $3,357 $0 $0 $22,068 $1,897 $0 $2,397 $26,362 $57

8.2 Turbine Plant Auxiliaries $137 $0 $308 $0 $0 $445 $39 $0 $48 $532 $1

8.3 Condenser & Auxiliaries $1,416 $0 $423 $0 $0 $1,839 $158 $0 $200 $2,196 $5

8.3b Air Cooled Condenser $12,980 $0 $2,602 $0 $0 $15,583 $1,558 $0 $3,428 $20,569 $44

8.4 Steam Piping $3,901 $0 $2,565 $0 $0 $6,466 $495 $0 $1,044 $8,005 $17

8.9 TG Foundations $0 $619 $978 $0 $0 $1,597 $135 $0 $347 $2,079 $4

SUBTOTAL 8. $37,147 $619 $10,232 $0 $0 $47,998 $4,283 $0 $7,464 $59,744 $129

 9 COOLING WATER SYSTEM

9.1 Cooling Towers $5,349 $0 $684 $0 $0 $6,033 $514 $0 $655 $7,201 $15

9.2 Circulating Water Pumps $1,569 $0 $99 $0 $0 $1,668 $126 $0 $179 $1,973 $4

9.3 Circ.Water System Auxiliaries $122 $0 $16 $0 $0 $138 $12 $0 $15 $165 $0

9.4 Circ.Water Piping $0 $3,561 $863 $0 $0 $4,424 $358 $0 $717 $5,499 $12

9.5 Make-up Water System $279 $0 $373 $0 $0 $652 $56 $0 $106 $815 $2

9.6 Component Cooling Water Sys $236 $283 $188 $0 $0 $707 $59 $0 $115 $882 $2

9.9 Circ.Water System Foundations $0 $1,804 $2,867 $0 $0 $4,671 $396 $0 $1,013 $6,080 $13

SUBTOTAL 9. $7,556 $5,648 $5,090 $0 $0 $18,293 $1,520 $0 $2,801 $22,614 $49

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline - Volume 3c (NGCC Cases)

137

Exhibit 3-49 Case L31B Total Plant Cost Details (Continued)

Client: USDOE/NETL Report Date: 2009-Oct-19

Project: Low Rank Western Coal Baseline Study

Case: Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture

Plant Size: 464.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST

No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

10 ASH/SPENT SORBENT HANDLING SYS

10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT

11.1 Generator Equipment $5,314 $0 $3,193 $0 $0 $8,507 $721 $0 $692 $9,920 $21

11.2 Station Service Equipment $1,965 $0 $166 $0 $0 $2,131 $176 $0 $173 $2,480 $5

11.3 Switchgear & Motor Control $2,422 $0 $412 $0 $0 $2,834 $235 $0 $307 $3,376 $7

11.4 Conduit & Cable Tray $0 $1,157 $3,569 $0 $0 $4,726 $409 $0 $770 $5,905 $13

11.5 Wire & Cable $0 $3,686 $2,263 $0 $0 $5,949 $383 $0 $950 $7,282 $16

11.6 Protective Equipment $0 $558 $1,898 $0 $0 $2,456 $215 $0 $267 $2,938 $6

11.7 Standby Equipment $97 $0 $89 $0 $0 $186 $16 $0 $20 $222 $0

11.8 Main Power Transformers $10,298 $0 $134 $0 $0 $10,432 $708 $0 $1,114 $12,254 $26

11.9 Electrical Foundations $0 $120 $294 $0 $0 $414 $35 $0 $90 $539 $1

SUBTOTAL 11. $20,098 $5,521 $12,017 $0 $0 $37,636 $2,898 $0 $4,383 $44,917 $97

12 INSTRUMENTATION & CONTROL

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $793 $0 $495 $0 $0 $1,288 $109 $64 $219 $1,680 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards,Panels & Racks $237 $0 $142 $0 $0 $379 $32 $19 $64 $494 $1

12.7 Computer & Accessories $3,792 $0 $113 $0 $0 $3,906 $321 $195 $442 $4,864 $10

12.8 Instrument Wiring & Tubing $0 $640 $1,223 $0 $0 $1,864 $140 $93 $315 $2,412 $5

12.9 Other I & C Equipment $1,414 $0 $3,208 $0 $0 $4,622 $401 $231 $525 $5,779 $12

SUBTOTAL 12. $6,236 $640 $5,181 $0 $0 $12,057 $1,004 $603 $1,566 $15,230 $33

13 IMPROVEMENTS TO SITE

13.1 Site Preparation $0 $91 $1,823 $0 $0 $1,914 $170 $0 $417 $2,501 $5

13.2 Site Improvements $0 $837 $1,039 $0 $0 $1,876 $166 $0 $408 $2,451 $5

13.3 Site Facilities $1,709 $0 $1,685 $0 $0 $3,394 $300 $0 $739 $4,432 $10

SUBTOTAL 13. $1,709 $928 $4,547 $0 $0 $7,184 $636 $0 $1,564 $9,384 $20

14 BUILDINGS & STRUCTURES

14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1

14.2 Steam Turbine Building $0 $1,601 $2,131 $0 $0 $3,732 $307 $0 $606 $4,644 $10

14.3 Administration Building $0 $459 $311 $0 $0 $770 $61 $0 $125 $956 $2

14.4 Circulation Water Pumphouse $0 $146 $72 $0 $0 $218 $17 $0 $35 $271 $1

14.5 Water Treatment Buildings $0 $401 $366 $0 $0 $766 $62 $0 $124 $953 $2

14.6 Machine Shop $0 $398 $255 $0 $0 $653 $52 $0 $106 $810 $2

14.7 Warehouse $0 $257 $155 $0 $0 $412 $33 $0 $67 $512 $1

14.8 Other Buildings & Structures $0 $77 $56 $0 $0 $133 $11 $0 $22 $165 $0

14.9 Waste Treating Building & Str. $0 $301 $538 $0 $0 $839 $70 $0 $136 $1,046 $2

SUBTOTAL 14. $0 $3,876 $4,009 $0 $0 $7,885 $640 $0 $1,279 $9,804 $21

TOTAL COST $325,306 $23,444 $95,786 $0 $0 $444,536 $37,706 $28,214 $78,282 $588,738 $1,267

TOTAL PLANT COST SUMMARY 
Cost and Performance Baseline, Volume 3c (NGCC Cases)

138

Exhibit 3-50 Case L31B Owner’s Costs

Owner's Costs $x1000 $/kW

Preproduction Costs

6 Months Fixed O&M $4,249 $9

1 Month Variable O&M $871 $2

25% of 1 Months Fuel Cost at 100% CF $4,799 $10

2% of TPC $11,775 $25

Total $21,693 $47

Inventory Capital

60 day supply of consumables at 100% CF $470 $1

0.5% of TPC (spare parts) $2,944 $6

Total $3,414 $7

 Initial Cost for Catalyst and Chemicals $804 $2

Land $300 $1

Other Owner's Costs $88,311 $190

Financing Costs $15,896 $34

Total Owner's Costs $130,417 $281

Total Overnight Cost (TOC) $719,155 $1,548

TASC Multiplier 1.078

Total As-Spent Cost (TASC) $775,249 $1,668
Cost and Performance Baseline, Volume 3c (NGCC Cases)

139

Exhibit 3-51 Case L31B Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007

Case L31B - 1x465 MWnet 2x1 7FB NGCC w/ CO2 Capture Heat Rate-net (Btu/kWh): 7,938

MWe-net: 465

 Capacity Factor (%): 85

OPERATING & MAINTENANCE LABOR

Operating Labor

 Operating Labor Rate(base): 34.65 $/hour

 Operating Labor Burden: 30.00 % of base

 Labor O-H Charge Rate: 25.00 % of labor

Total

 Skilled Operator 1.0 1.0

 Operator 3.3 3.3

 Foreman 1.0 1.0

 Lab Tech's, etc. 1.0 1.0

 TOTAL-O.J.'s 6.3 6.3

Annual Cost Annual Unit Cost

$ $/kW-net

Annual Operating Labor Cost $2,497,781 $5.376

Maintenance Labor Cost $4,300,603 $9.256

Administrative & Support Labor $1,699,596 $3.658

Property Taxes and Insurance $11,774,756 $25.342

TOTAL FIXED OPERATING COSTS $20,272,736 $43.631

VARIABLE OPERATING COSTS

$/kWh-net

Maintenance Material Cost $6,450,905 $0.00186

Consumables Consumption Unit Initial

 Initial /Day Cost Cost

Water (/1000 gallons) 0.00 2,374.56 1.08 $0 $796,878 $0.00023

Chemicals

MU & WT Chem.(lbs) 0.00 14,146.94 0.17 $0 $759,611 $0.00022

MEA Solvent (ton) 336.89 0.47 2,249.89 $757,962 $330,240 $0.00010

Activated Carbon (lb) 0.00 565.14 1.05 $0 $184,133 $0.00005

Corrosion Inhibitor 0.00 0.00 0.00 $46,153 $2,198 $0.00000

SCR Catalyst (m3) w/equip. 0.07 5,775.94 $0 $123,497 $0.00004

Ammonia (19% NH3) (ton) 0.00 5.80 129.80 $0 $233,416 $0.00007

Subtotal Chemicals $804,115 $1,633,094 $0.00047

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000

Gases,N2 etc. (/100scf) 0.00 0.00 0.00 $0 $0 $0.00000

L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Other $0 $0 $0.00000

Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal Waste Disposal $0 $0 $0.00000

By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000

Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $804,115 $8,880,877 $0.00257

Fuel (MMBtu) 0 88,519 7.13 $0 $195,790,457 $0.05659
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4. SUMMARY

The performance results of the four NGCC plant configurations modeled in this study are 

summarized in Exhibit 4-1.

Exhibit 4-1 Performance and Cost Results for NGCC Cases

PERFORMANCE Case S31A Case L31A Case S31B Case L31B

CO2 Capture 0% 0% 90% 90%

Gross Power Output (kWe) 522,100 557,000 470,000 501,600

Auxiliary Power Requirement (kWe) 9,690 10,020 34,940 36,960

Net Power Output (kWe) 512,410 546,980 435,060 464,640

Natural Gas Flowrate (lb/hr) 153,559 163,560 153,559 163,560

HHV Thermal Input (kWth) 1,014,787 1,080,880 1,014,787 1,080,880

Net Plant HHV Efficiency (%) 50.5% 50.6% 42.9% 43.0%

Net Plant HHV Heat Rate (Btu/kWh) 6,757 6,743 7,959 7,938

Raw Water Withdrawal (gpm/MWnet) 2.1 2.1 7.1 7.1

Process Water Discharge (gpm/MWnet) 0.5 0.5 1.8 1.8

Raw Water Consumption (gpm/MWnet) 1.6 1.6 5.3 5.3

CO2 Emissions (lb/MMBtu) 118 118 12 12

CO2 Emissions (lb/MWhgross) 784 783 87 87

CO2 Emissions (lb/MWhnet) 799 797 94 94

SO2 Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible

SO2 Emissions (lb/MWhgross) Negligible Negligible Negligible Negligible

NOx Emissions (lb/MMBtu) 0.009 0.009 0.009 0.009

NOx Emissions (lb/MWhgross) 0.060 0.060 0.067 0.066

PM Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible

PM Emissions (lb/MWhgross) Negligible Negligible Negligible Negligible

Hg Emissions (lb/TBtu) Negligible Negligible Negligible Negligible

Hg Emissions (lb/MWhgross) Negligible Negligible Negligible Negligible

COST

Total Plant Cost (2007$/kW) 666 637 1,315 1,267

Total Overnight Cost (2007$/kW) 817 782 1,607 1,548

 Bare Erected Cost 546 521 994 957

 Home Office Expenses 46 44 84 81

 Project Contingency 74 71 174 168

 Process Contingency 0 0 62 61

 Owner's Costs 151 145 291 281

Total Overnight Cost (2007$ x 1,000) 418,817 427,473 698,949 719,155

Total As Spent Capital (2007$/kW) 879 840 1,732 1,668

COE (mills/kWh, 2007$)1 64.4 63.6 92.9 91.4

 CO 2 TS&M Costs 0.0 0.0 3.4 3.3

 Fuel Costs 48.2 48.1 56.7 56.6

 Variable Costs 1.4 1.3 2.7 2.6

 Fixed Costs 3.4 3.2 6.1 5.9

 Capital Costs 11.5 11.0 24.0 23.1

LCOE (mills/kWh, 2007$)1 81.7 80.6 117.8 115.8

 NGCC with Advanced F Class

1 COE and Levelized COE are defined in Section 2.6.
Cost and Performance Baseline, Volume 3c (NGCC Cases)

142

The TOC for each of the four NGCC cases is shown in Exhibit 4-2. The TOC of the NDL site 

non-capture case, $782/kW, is the lowest of the four NGCC cases. The TOC of the non-capture 

NGCC plant at the Montana site is $817/kW, or approximately four percent greater. Addition of 

CO2 capture nearly doubles the TOC at each location. The process contingency included for the 

Econamine process averages $60/kW for the capture cases, which represents approximately 8

percent of the incremental cost due to the addition of CO2 capture and 4 percent of the total

TOC.

The COE for NGCC plants is heavily dependent on the price of natural gas as shown in 

Exhibit 4-3. The fuel component of COE represents 75 percent of the total in the non-capture 

cases and 62 percent of the total in the CO2 capture case. 

Exhibit 4-2 Total Overnight Costs

817

1,607

782

1,548

879

1,732

840

1,668

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

TOC TASC TOC TASC TOC TASC TOC TASC

NGCC NGCC w/ CO2 Capture NGCC NGCC w/ CO2 Capture

TOC and TASC ($/kW)

TASC

Owner's Cost

Process Contingency

Project Contingency

Home Office Expense

Bare Erected Cost

North Dakota Site 

Elevation: 1,900 ft

Montana Site

Elevation: 3,400 ft
Cost and Performance Baseline, Volume 3c (NGCC Cases)

143

Exhibit 4-3 COE of NGCC Cases

11.5

24.0

11.0

23.1 3.4

6.1

3.2

5.9

1.4

2.7

1.3

2.6

48.2

56.7

48.1

56.6

3.4 3.3

64.4

92.9

63.6

91.4

0

20

40

60

80

100

120

NGCC PRB NGCC PRB w/Capture NGCC Lig NGCC Lig w/Capture

COE (2007 mills/kWh)

CO2 TS&M Cost

Fuel Cost

Variable O&M Cost

Fixed O&M Cost

Capital Cost

Montana Site

Elevation: 3,400 ft

North Dakota Site

Elevation: 1,900 ft

Because the NGCC COE has a relatively small capital component, it is less sensitive to CF

changes than it is to changes in fuel prices. The sensitivity of NGCC to CF is shown in 

Exhibit 4-4 while the sensitivity of NGCC to natural gas price is shown in Exhibit 4-5. A 50 

percent reduction in CF (80 percent to 40 percent) results in approximately a 24 percent increase 

in COE for the non-capture cases and a 37 percent increase for the capture cases. The capture 

cases are more capital intensive and are more sensitive to changes in the CF.

Increasing the price of natural gas 50 percent (from $7.13 to $10.70/MMBtu) results in a COE

increase of 38 percent in the non-capture cases and 32 percent in the CO2 capture cases. Because

the fuel costs are a smaller proportion of the total COE in the CO2 capture cases, the impact of 

fuel price variations is less for those cases.
Cost and Performance Baseline, Volume 3c (NGCC Cases)

144

Exhibit 4-4 Sensitivity of COE to Capacity Factor in NGCC Cases

0

20

40

60

80

100

120

140

160

180

0 10 20 30 40 50 60 70 80 90 100

COE (2007 mills/kWh)

Capacity Factor, %

NGCC w/CO2 Capture Montana Site

NGCC w/CO2 Capture North Dakota 

Site

NGCC No Capture Montana Site

NGCC No Capture North Dakota Site

Study Capacity Factor is 

85% for all cases

Exhibit 4-5 Sensitivity of COE to Fuel Price in NGCC Cases

0

20

40

60

80

100

120

140

160

0 2 4 6 8 10 12 14

COE (2007 mills/kWh)

Natural Gas Price, $/MMBtu

NGCC w/CO2 Capture Montana Site

NGCC w/CO2 Capture North Dakota Site

NGCC No Capture Montana Site

NGCC No Capture North Dakota Site

Capacity Factor = 85% for all cases

Study Natural Gas Cost: $7.13/MMBtu
Cost and Performance Baseline, Volume 3c (NGCC Cases)

145

The following observations can be made regarding plant performance with reference to 

Exhibit 4-1:

The efficiency for cases S31A and L31A are 50.5 and 50.6 percent (HHV basis), respectively. 

Gas Turbine World provides estimated performance for an advanced F class turbine operated on 

natural gas in a combined cycle mode, and the reported efficiency is 57.5 percent (LHV basis)

[32

• The increase in elevation, going from the NDL to the Montana site, has minimal impact 

on efficiency but does cause a derate in the gas turbine compressor, reducing the net plant 

output by six percent for both CO2 capture and non-capture cases. As the air becomes 

less dense at higher elevations, the maximum volumetric capacity of the compressor 

results in less mass flow through the combustion turbine.

]. Adjusting the results from this study to an LHV basis results in efficiencies of 56.0 and 

56.1 percent for cases S31A and L31A, respectively. A portion of the efficiency difference can 

be attributed to the higher condenser pressure used in this study relative to the Gas Turbine 

World reference case.

• The efficiency penalty to add CO2 capture in the NGCC cases is 7.6 percentage points (a 

relative reduction of 15 percent). The efficiency reduction is caused primarily by the 

auxiliary loads of the Econamine 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 25 and 27 MW increase in 

auxiliary load compared to the Montana and ND site non-capture cases, respectively. 

Additionally, the extraction steam required to regenerate the Econamine solvent results in 

a reduction of steam turbine output of over 50 MW at both site locations.

• A study assumption is that the natural gas contains no PM or Hg, resulting in negligible 

emissions of both.

• This study also assumes that the natural gas contains no sulfur compounds, resulting in

negligible emissions of SO2. As noted previously in the report, if the natural gas 

contained the maximum allowable amount of sulfur per EPA’s pipeline natural gas 

specification, the resulting SO2 emissions would be 9.7 tonnes/yr (10.7 tons/yr) at 85 

percent CF, or 0.00073 kg/GJ (0.0017 lb/MMBtu).

• NOx emissions are similar for the two non-capture NGCC cases on a mass basis. This is 

a result of the fixed output from the gas turbine (25 ppmv at 15 percent O2) and the fixed 

efficiency of the SCR (90 percent). The capture cases have slightly higher NOx 

emissions because they are normalized by a smaller gross power output.

As presented in Section 2.6 the cost of CO2 avoided was compared in two ways, relative to the 

analogous plant design and compared to a baseline SC PC plant. The cost of CO2 avoided, shown 

in Exhibit 4-6, averages $88.0/tonne ($79.9/ton) compared to the analogous non-capture (A) 

design and $38.4/tonne ($34.8/ton) compared to the baseline SC PC non-capture (SC PC A) 

design. NGCC plants have low carbon emissions, even before capturing CO2, so the cost of CO2

avoided compared to a baseline SC PC plant is very low. The cost of avoiding CO2 compared to 

the analogous non-capture NGCC case shows costs comparable to the addition of a typical post 

combustion CO2 capture process.
Cost and Performance Baseline, Volume 3c (NGCC Cases)

146

Exhibit 4-6 CO2 Avoided Costs

89.1

87.0

43.0

33.8

0

10

20

30

40

50

60

70

80

90

100

110

NGCC PRB w/Capture NGCC Lig w/Capture

First YEar CO2 Avoided Cost, (2007$/Tonne)

Avoided Cost (Analogous Technology w/o 

Capture Reference

Avoided Cost (SC PC w/o Capture 

Reference)

Montana Site

Elevation: 3,400 ft

North Dakota Site

Elevation: 1,900 ft

The normalized water withdrawal, process discharge and raw water consumption are shown in 

Exhibit 4-7 for each case. The following observations can be made:

• Normalized water withdrawal and normalized raw water consumption more than triple 

when CO2 capture technology is added. The high cooling water demand of the 

Econamine process results in a large increase in cooling tower makeup requirements.

• The use of the parallel wet/dry cooling system reduces water demand relative to an all 

wet cooling tower system. For the non-capture cases, the reductions are approximately 

3.1 m3

/min (820 gpm) resulting in a 49 percent reduction. For the CO2 capture cases, the 

reductions are 2.1 m3/min (370 gpm) resulting in a 14 percent reduction. The water 

savings is less in the CO2 capture cases because a significant amount of extraction steam 

is used in the Econamine system and therefore not condensed in the surface condenser. 

• Cooling tower makeup comprises over 97 percent of the raw water consumption in each 

case. The only internal recycle stream in the non-capture 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 32°C (89°F) as well as 

from the CO2 product stream during compression. These streams are also recycled to the 

cooling tower.
Cost and Performance Baseline, Volume 3c (NGCC Cases)

147

Exhibit 4-7 Water Usage in NGCC Costs

2.1 2.1

7.1 7.1

0.5 0.5

1.8 1.8

1.6 1.6

5.3 5.3

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

NGCC PRB NGCC Lig NGCC PRB w/ Capture NGCC Lig w/ Capture

Water Usage, gpm/MWhnet

Raw Water Withdrawal

Process Water Discharge

Raw Water Consumption
Cost and Performance Baseline, Volume 3c (NGCC Cases)

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149

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Cost and Performance Baseline, Volume 3c (NGCC Cases)

150

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151

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