Cost and Performance Baseline 

for Fossil Energy Plants

Volume 3 Executive Summary: 

Low Rank Coal and Natural Gas to 

Electricity

September 2011

DOE/NETL-2010/1399
Disclaimer

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

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

nor any of their employees, makes any warranty, express or implied, or assumes any 

legal liability or 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 3 EXECUTIVE SUMMARY: LOW RANK COAL AND 

NATURAL GAS TO ELECTRICITY

DOE/NETL-2010/1399

September 2011

NETL Contact:

James B. Black

Office of Program Planning & Analysis, Performance Division

National Energy Technology Laboratory

www.netl.doe.gov
This page intentionally left blank
NETL Viewpoint

Background

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

availability of ultra-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 study provides an accurate, independent 

assessment of the cost and performance for Integrated Gasification Combined Cycle (IGCC), 

Pulverized Coal (PC), Circulating Fluidized Bed Combustor (CFBC), and Natural Gas 

Combined Cycle (NGCC) plants with and without carbon dioxide (CO2) capture and 

sequestration operating at sites in Montana and North Dakota. The Montana coal plants use

Powder River Basin (PRB) coal and the minemouth North Dakota coal plants use North Dakota 

lignite (NDL) coals. 

Approach

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

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

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

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

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

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

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 for Fossil Energy Plants

VI

Table of Contents

TABLE OF CONTENTS ...........................................................................................................VI

LIST OF EXHIBITS..................................................................................................................VII

PREPARED BY .......................................................................................................................VIII

ACKNOWLEDGMENTS..........................................................................................................IX

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

PERFORMANCE..............................................................................................................................7

ENERGY EFFICIENCY..................................................................................................................7

WATER USE..............................................................................................................................10

COST RESULTS............................................................................................................................14

TOTAL OVERNIGHT COST..........................................................................................................14

COST OF ELECTRICITY..............................................................................................................18

COST OF CO2AVOIDED............................................................................................................23

FUEL COST SENSITIVITY ...........................................................................................................26

CAPACITY FACTOR SENSITIVITY ................................................................................................28

COMBINED NGCC CAPACITY FACTOR AND NATURAL GAS PRICE PARITY ..................................30

ENVIRONMENTAL PERFORMANCE...............................................................................................32

CO2EMISSIONS........................................................................................................................36

CO2 EMISSION PRICE IMPACT ..................................................................................................39

COMBINED CO2 EMISSION AND NATURAL GAS PRICE PARITY ....................................................41

REFERENCES.............................................................................................................................42
Cost and Performance Baseline for Fossil Energy Plants

VII

List of Exhibits

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

Exhibit ES-2 Results Summary for IGCC Cases........................................................................... 4

Exhibit ES-3 Results Summary for Combustion Cases................................................................. 5

Exhibit ES-4 Results Summary for NGCC Cases ......................................................................... 6

Exhibit ES-5 Net Plant Efficiency for Montana Site (HHV Basis)............................................... 8

Exhibit ES-6 Net Plant Efficiency for North Dakota Site (HHV Basis) ....................................... 9

Exhibit ES-7 Raw Water Withdrawal and Consumption for Montana Site ................................ 12

Exhibit ES-8 Raw Water Withdrawal and Consumption for North Dakota Site......................... 13

Exhibit ES-9 Plant Capital Costs for Montana Site..................................................................... 16

Exhibit ES-10 Plant Capital Costs for North Dakota Site ........................................................... 17

Exhibit ES-11 Economic Parameters Used to Calculate COE .................................................... 19

Exhibit ES-12 COE by Cost Component for Montana Site......................................................... 21

Exhibit ES-13 COE by Cost Component for North Dakota Site................................................. 22

Exhibit ES-14 First Year CO2 Avoided Costs for Montana Site................................................. 24

Exhibit ES-15 First Year CO2 Avoided Costs for North Dakota Site ......................................... 25

Exhibit ES-16 Sensitivity to Fuel Costs for Montana Site .......................................................... 27

Exhibit ES-17 Sensitivity to Fuel Costs for North Dakota Site................................................... 27

Exhibit ES-18 Sensitivity to Capacity Factor for Montana Site .................................................. 29

Exhibit ES-19 Sensitivity to Capacity Factor for North Dakota Site .......................................... 29

Exhibit ES-20 Non-Capture Sensitivity to NGCC CF and NG Price.......................................... 30

Exhibit ES-21 CCS Sensitivity to CO2 Capture NGCC CF and NG Price.................................. 31

Exhibit ES-22 CCS Sensitivity to Non-Capture NGCC CF and NG Price ................................. 31

Exhibit ES-23 Study Environmental Targets............................................................................... 32

Exhibit ES-24 Mercury Emissions Rates..................................................................................... 33

Exhibit ES-25 SO2, NOx, and Particulate Emission Rates for Montana Site.............................. 34

Exhibit ES-26 SO2, NOx, and Particulate Emission Rates for North Dakota Site ...................... 35

Exhibit ES-27 CO2 Emissions Normalized By Net Output for Montana Site............................. 37

Exhibit ES-28 CO2 Emissions Normalized By Net Output for North Dakota Site ..................... 38

Exhibit ES-29 Sensitivity to Carbon Emissions Price for Montana Site ..................................... 39

Exhibit ES-30 Sensitivity to Carbon Emissions Price for North Dakota Site ............................. 40

Exhibit ES-31 Lowest Cost Technology Parity Sensitivity to CO2 and NG Prices..................... 41
Cost and Performance Baseline for Fossil Energy Plants

VIII

PREPARED BY

Research and Development Solutions, LLC (RDS)

:

UPDATED BY

Energy Sector Planning and Analysis (ESPA)

:

Vincent H. Chou

Booz Allen Hamilton

Norma J. Kuehn

Booz Allen Hamilton

Lora L. Pinkerton

WorleyParsons Group, Inc.

Marc J. Turner

Booz Allen Hamilton

Elsy Varghese

WorleyParsons Group, Inc.

Mark C. Woods

Booz Allen Hamilton

DOE Contract # DE-FE0004001
Cost and Performance Baseline for Fossil Energy Plants

IX

Acknowledgments

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

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

under DOE NETL Contract Number DE-AM26-04NT41817; Subtask 41817-401.01.04. The 

report was updated by Booz Allen Hamilton Inc. under DOE NETL Contract Number DEFE0004001, Energy Sector Planning and Analysis.

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

NETL staff and other past contributors, particularly:

John Wimer, Director of Office of Program Planning and Analyses (OPPA)

Larry Rath, Director Performance Division - OPPA

James Black

Jared Ciferno

Kristin Gerdes

Eric Grol

Jeffrey Hoffmann

Michael Matuszewski

Wally Shelton

Erik Shuster

Gary Stiegel

William Summers

Jenny Tennant

John Haslebeck

formerly of Booz Allen Hamilton

Eric G. Lewis

formerly of Booz Allen Hamilton

Pamela Capicotto

formerly of Parsons Corporation

Michael Rutkowski

formerly of Parsons Corporation
Cost and Performance Baseline for Fossil Energy Plants

1

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

performance of Low-Rank Coal-Fired Power Systems, specifically integrated gasification 

combined cycle (IGCC), pulverized coal (PC) and circulating fluidized bed (CFB) plants plus 

natural gas combined cycle (NGCC) plants at different elevations, using a consistent technical 

and economic approach that accurately reflects current or near term market conditions. This 

Executive Summary covers all the technology types that make up the Low Rank Coal Study, 

which is Volume 3 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

Volume 3 was published in 3 sub volumes and this Executive Summary encompasses all three 

sub volumes:

• Volume 3a: IGCC Cases [1

• Volume 3b: Comubustion Cases [

]

2

• Volume 3c: NGCC Cases [

]

3

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

Exhibit ES-1 shows the 28 cases in this study, one for each technology configuration, using 

either PRB or lignite coal at one of two site conditions, with and without CO2 capture. This 

includes configurations for 12 oxygen-blown IGCC plants based on the Shell Coal Gasification 

Process (SCGP), Transport Integrated Gasification (TRIGTM) gasifier, Siemens Fuel Gasifier 

(SFG), and Conoco Phillips (CoP) E-GasTM gasifiers. Twelve combustion power plant 

configurations were analyzed including supercritical (SC) and ultra-supercritical (USC)

pulverized coal (PC) plants and SC CFB plants. NGCC cases were also analyzed at each site.
Cost and Performance Baseline for Fossil Energy Plants

2

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

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

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

the basis for cost estimating. Performance and process limits were based upon published reports, 

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

design/build utility projects, and 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 first year of capital expenditure (2007)

delivered costs used were $0.84/gigajoule (GJ) ($0.89/million British thermal unit [MMBtu]) for 

Powder River Basin (PRB) coal and $0.79/GJ ($0.83/MMBtu) for North Dakota Lignite (NDL), 

both on a higher heating value (HHV) basis and in June 2007 United States (US) dollars.

Exhibit ES-1 Case Descriptions

Case

Gasifier / 

Boiler Fuel Steam Cycle, psig/oF/oF Sulfur Removal CO2 Separation

S1A Shell SCGP PRB 1800/1050/1050 Sulfinol-M -

S1B Shell SCGP PRB 1800/1000/1000 Selexol Selexol 2nd stage

L1A Shell SCGP NDL 1800/1050/1050 Sulfinol-M -

L1B Shell SCGP NDL 1800/1000/1000 Selexol Selexol 2nd stage

S2A TRIGTM PRB 1800/1050/1050 Sulfinol-M -

S2B TRIGTM PRB 1800/1000/1000 Selexol Selexol 2nd stage

S3A Siemens SFG PRB 1800/1050/1050 Sulfinol-M -

S3B Siemens SFG PRB 1800/1000/1000 Selexol Selexol 2nd stage

L3A Siemens SFG NDL 1800/1050/1050 Sulfinol-M -

L3B Siemens SFG NDL 1800/1000/1000 Selexol Selexol 2nd stage

S4A CoP E-GasTM PRB 1800/1050/1050 MDEA -

S4B CoP E-GasTM PRB 1800/1000/1000 Selexol Selexol 2nd stage

S12A SC PC PRB 3500/1100/1100 Spray Dryer FGD -

S12B SC PC PRB 3500/1100/1100 Spray Dryer FGD Amine Absorber

L12A SC PC NDL 3500/1100/1100 Spray Dryer FGD -

L12B SC PC NDL 3500/1100/1100 Spray Dryer FGD Amine Absorber

S13A USC PC PRB 4000/1200/1200 Spray Dryer FGD -

S13B USC PC PRB 4000/1200/1200 Spray Dryer FGD Amine Absorber

L13A USC PC NDL 4000/1200/1200 Spray Dryer FGD -

L13B USCPC NDL 4000/1200/1200 Spray Dryer FGD Amine Absorber

S22A SC CFB PRB 3500/1100/1100 Spray Dryer FGD -

S22B SC CFB PRB 3500/1100/1100 In-bed Limestone Amine Absorber

L22A SC CFB NDL 3500/1100/1100 In-bed Limestone -

L22B SC CFB NDL 3500/1100/1100 In-bed Limestone Amine Absorber

S31A NGCC NG 2400/1050/1050 - -

S31B NGCC NG 2400/1050/1050 - Amine Absorber

L31A NGCC NG 2400/1050/1050 - -

L31B NGCC NG 2400/1050/1050 - Amine Absorber
Cost and Performance Baseline for Fossil Energy Plants

3

All plant configurations were evaluated based on installation at a greenfield site (Montana [MT], 

3400 ft elevation, for cases using PRB coal and North Dakota [ND], 1900 ft elevation, for cases 

using lignite). 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) was chosen to 

reflect the maximum availability demonstrated for the specific plant type, i.e., 80 percent for 

IGCC and 85 percent for PC and NGCC configurations. Since variations in fuel costs and other 

factors can influence dispatch order and CF, sensitivity of the cost of electricity (COE) to CF

was evaluated and is presented later in this Executive Summary in Exhibit ES-18 and 

Exhibit ES-19. Only the Shell and Siemens IGCC configurations are modeled at the North 

Dakota site with lignite coal, so averages and comparisons between the two sites in later 

discussions can have a different basis.

The nominal net plant output for this study is set at 550 megawatts (MW). The actual net output 

varies between technologies because the combustion turbines (CTs) in the IGCC and NGCC 

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

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

550 MW, but the IGCC cases have net outputs ranging from 445 (Case S3B) to 617 MW (Case 

L1A). The range in IGCC net output is caused by the higher auxiliary load incurred in the CO2

capture cases, primarily due to CO2 compression, and the need for extraction steam in the watergas shift (WGS) reactions, which reduces steam turbine output. Higher auxiliary load and 

extraction steam requirements can be accommodated in the PC cases (larger boiler and steam 

turbine) but not in the IGCC cases where it is impossible to maintain a constant net output from 

the steam cycle given the relatively fixed heat recovery from the CT. Likewise, the NGCC cases 

have a net output range of 435 (Case S31B) to 547 MW (Case L31A) because of the CT

constraint and the CO2 capture extraction steam and electrical auxiliaries.

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

IGCC cases, Exhibit ES-3 displays the results for the combustion cases, and Exhibit ES-4

displays the results for the NGCC cases. The results are discussed below in the following order:

• Performance (efficiency and raw water consumption)

• Cost (plant capital costs and COE)

• Environmental profile
Cost and Performance Baseline for Fossil Energy Plants

4

Exhibit ES-2 Results Summary for IGCC Cases

1 CF is 80% for IGCC cases

PERFORMANCE S1A L1A S1B L1B S2A S2B S3A L3A S3B L3B S4A S4B

CO2 Capture 0% 90% 0% 90% 0% 83% 0% 90% 0% 90% 0% 90%

Gross Power Output (kWe) 696,700 752,600 663,400 713,300 652,700 621,300 622,200 678,800 634,700 676,900 738,300 727,200

Auxiliary Power Requirement (kWe) 124,020 135,900 191,790 213,240 107,280 160,450 117,480 135,680 189,410 210,390 133,460 212,130

Net Power Output (kWe) 572,680 616,700 471,610 500,060 545,420 460,850 504,720 543,120 445,290 466,510 604,840 515,070

Coal Flowrate (lb/hr) 542,713 760,093 585,970 814,029 545,197 577,946 531,119 743,918 579,796 801,651 656,228 675,058

HHV Thermal Input (kWth) 1,362,134 1,474,011 1,470,704 1,578,608 1,368,368 1,450,564 1,333,034 1,442,644 1,455,207 1,554,603 1,647,041 1,694,303

Net Plant HHV Efficiency (%) 42.0% 41.8% 32.1% 31.7% 39.9% 31.8% 37.9% 37.6% 30.6% 30.0% 36.7% 30.4%

Net Plant HHV Heat Rate (Btu/kWh) 8,116 8,156 10,641 10,772 8,560 10,740 9,012 9,063 11,151 11,371 9,292 11,224

Raw Water Withdrawal (gpm/MWnet) 3.1 3.0 7.2 7.8 3.7 6.5 4.5 4.0 9.0 8.9 5.4 8.4

Process Water Discharge (gpm/MWnet) 0.8 0.8 1.4 1.6 0.8 1.0 1.1 1.1 1.6 1.7 1.1 1.5

Raw Water Consumption (gpm/MWnet) 2.3 2.2 5.9 6.2 2.9 5.5 3.4 2.9 7.4 7.2 4.3 6.9

CO2 Emissions (lb/MMBtu) 214 219 22 22 211 36 214 219 22 22 213 22

CO2 Emissions (lb/MWhgross) 1,426 1,461 165 170 1,507 287 1,563 1,585 172 175 1,620 174

CO2 Emissions (lb/MWhnet) 1,735 1,783 233 242 1,803 386 1,927 1,981 246 255 1,977 245

SO2 Emissions (lb/MMBtu) 0.0023 0.0023 0.0009 0.0010 0.0019 0.0009 0.0039 0.0021 0.0009 0.0010 0.0016 0.0009

SO2 Emissions (lb/MWhgross) 0.015 0.015 0.007 0.007 0.013 0.007 0.029 0.016 0.007 0.008 0.012 0.007

NOx Emissions (lb/MMBtu) 0.062 0.063 0.050 0.049 0.059 0.049 0.061 0.061 0.051 0.050 0.052 0.044

NOx Emissions (lb/MWhgross) 0.412 0.418 0.381 0.371 0.422 0.390 0.444 0.445 0.397 0.391 0.398 0.348

PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071

PM Emissions (lb/MWhgross) 0.047 0.047 0.054 0.054 0.051 0.057 0.052 0.051 0.056 0.056 0.054 0.056

Hg Emissions (lb/TBtu) 0.351 0.560 0.351 0.560 0.351 0.351 0.351 0.560 0.351 0.560 0.351 0.351

Hg Emissions (lb/MWhgross) 2.34E-06 3.74E-06 2.66E-06 4.23E-06 2.51E-06 2.80E-06 2.57E-06 4.06E-06 2.75E-06 4.39E-06 2.67E-06 2.79E-06

COST

Total Plant Cost (2007$/kW) 2,506 2,539 3,480 3,584 2,236 3,019 2,610 2,656 3,533 3,626 2,265 3,144

Total Overnight Cost (2007$/kW) 3,056 3,094 4,253 4,378 2,728 3,691 3,185 3,239 4,318 4,430 2,771 3,851

 Bare Erected Cost 1,914 1,941 2,610 2,692 1,692 2,228 2,006 2,044 2,654 2,730 1,737 2,357

 Home Office Expenses 177 179 242 250 157 207 186 189 247 254 162 221

 Project Contingency 343 349 486 502 305 421 359 367 493 508 306 431

 Process Contingency 72 69 142 141 83 164 60 56 139 135 60 135

 Owner's Costs 550 556 773 794 492 672 575 583 785 804 505 706

Total Overnight Cost (2007$x1,000) 1,750,189 1,908,200 2,005,883 2,189,363 1,488,063 1,701,132 1,607,607 1,759,016 1,922,741 2,066,464 1,675,790 1,983,369

Total As Spent Capital (2007$/kW) 3,484 3,527 4,849 4,991 3,110 4,208 3,631 3,692 4,922 5,050 3,159 4,390

COE (mills/kWh, 2007$)1 83.2 83.5 119.7 121.9 74.5 105.2 86.8 87.3 121.7 123.7 78.7 112.3

 CO 2 TS&M Costs 0.0 0.0 6.0 5.7 0.0 5.9 0.0 0.0 6.3 6.2 0.0 5.8

 Fuel Costs 7.2 6.7 9.5 8.9 7.6 9.5 8.0 7.5 9.9 9.4 8.3 10.0

 Variable Costs 8.0 8.2 10.6 11.1 6.8 8.8 8.2 8.4 10.6 11.1 8.3 10.9

 Fixed Costs 13.7 13.6 18.3 18.6 11.8 15.5 14.1 14.0 18.4 18.6 13.0 17.4

 Capital Costs 54.2 54.9 75.4 77.6 48.4 65.4 56.5 57.4 76.6 78.5 49.1 68.3

LCOE (mills/kWh, 2007$)1 105.4 105.8 151.8 154.5 94.5 133.3 110.0 110.7 154.3 156.9 99.8 142.4

Shell IGCC Cases TRIG IGCC Cases Siemens IGCC Cases CoP IGCC Cases
Cost and Performance Baseline for Fossil Energy Plants

5

Exhibit ES-3 Results Summary for Combustion Cases

1 CF is 85% for PC cases

PERFORMANCE S12A L12A S12B L12B S13A L13A S13B L13B S22A L22A S22B L22B

CO2 Capture 0% 0% 90% 90% 0% 0% 90% 90% 0% 0% 90% 90%

Gross Power Output (kWe) 582,700 584,700 673,000 683,900 581,500 583,200 665,400 675,200 578,400 578,700 664,000 672,900

Auxiliary Power Requirement (kWe) 32,660 34,640 122,940 133,850 31,430 33,170 115,320 125,170 28,330 28,670 113,990 122,820

Net Power Output (kWe) 550,040 550,060 550,060 550,050 550,070 550,030 550,080 550,030 550,070 550,030 550,010 550,080

Coal Flowrate (lb/hr) 566,042 755,859 811,486 1,110,668 549,326 731,085 764,212 1,043,879 563,307 745,997 801,270 1,095,812

HHV Thermal Input (kWth) 1,420,686 1,465,801 2,036,717 2,153,863 1,378,732 1,417,757 1,918,067 2,024,343 1,413,821 1,446,676 2,011,075 2,125,054

Net Plant HHV Efficiency (%) 38.7% 37.5% 27.0% 25.5% 39.9% 38.8% 28.7% 27.2% 38.9% 38.0% 27.3% 25.9%

Net Plant HHV Heat Rate (Btu/kWh) 8,813 9,093 12,634 13,361 8,552 8,795 11,898 12,558 8,770 8,975 12,476 13,182

Raw Water Withdrawal, gpm 2,649 2,683 7,642 7,817 2,578 2,597 7,117 7,261 2,393 2,379 7,762 7,996

Raw Water Consumption, gpm 2,093 2,125 5,527 5,456 2,035 2,056 5,141 5,060 1,839 1,828 5,713 5,704

CO2 Emissions (lb/MMBtu) 215 219 21 22 215 219 21 22 213 219 21 22

CO2 Emissions (lb/MWhgross) 1,786 1,877 222 236 1,737 1,820 211 225 1,775 1,865 220 236

CO2 Emissions (lb/MWhnet) 1,892 1,996 271 293 1,836 1,930 255 276 1,866 1,963 265 288

SO2 Emissions (lb/MMBtu) 0.119 0.132 0.002 0.002 0.119 0.132 0.002 0.002 0.102 0.113 0.002 0.002

SO2 Emissions (lb/MWhgross) 0.990 1.130 0.020 0.020 0.960 1.100 0.020 0.020 0.850 0.970 0.020 0.020

NOx Emissions (lb/MMBtu) 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070

NOx Emissions (lb/MWhgross) 0.582 0.599 0.723 0.752 0.566 0.581 0.689 0.716 0.584 0.597 0.723 0.754

PM Emissions (lb/MMBtu) 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013

PM Emissions (lb/MWhgross) 0.108 0.111 0.134 0.140 0.105 0.108 0.128 0.133 0.108 0.111 0.134 0.140

Hg Emissions (lb/TBtu) 0.597 1.121 0.597 1.121 0.597 1.121 0.597 1.121 0.302 0.482 0.302 0.482

Hg Emissions (lb/MWhgross) 4.96E-06 9.59E-06 6.16E-06 1.20E-05 4.83E-06 9.29E-06 5.87E-06 1.15E-05 2.52E-06 4.11E-06 3.12E-06 5.19E-06

COST

Total Plant Cost (2007$/kW) 1,033,301 1,122,438 1,797,852 1,958,416 1,084,716 1,185,901 1,827,095 1,973,559 1,062,836 1,123,412 1,812,415 1,943,572

Total Overnight Cost (2007$/kW) 2,293 2,489 3,987 4,341 2,405 2,628 4,049 4,372 2,357 2,490 4,018 4,307

 Bare Erected Cost 1,530 1,663 2,517 2,750 1,577 1,725 2,530 2,738 1,480 1,563 2,424 2,600

 Home Office Expenses 145 157 238 261 149 163 239 259 141 149 230 247

 Project Contingency 204 220 406 438 213 231 408 437 210 221 407 435

 Process Contingency 0 0 107 112 33 37 144 154 102 110 233 251

 Owner's Costs 414 448 718 781 433 472 727 783 425 448 722 773

Total Overnight Cost (2007$x1,000) 1,261,175 1,369,100 2,192,877 2,387,887 1,322,909 1,445,367 2,227,086 2,404,506 1,296,474 1,369,642 2,209,764 2,368,935

Total As Spent Capital (2007$/kW) 2,600 2,823 4,545 4,949 2,742 2,996 4,615 4,984 2,687 2,839 4,580 4,909

COE (mills/kWh, 2007$)1 57.8 62.2 107.5 116.4 62.2 67.3 107.7 115.4 61.5 64.6 108.0 115.2

 CO 2 TS&M Costs 0.0 0.0 6.0 6.2 0.0 0.0 5.8 6.0 0.0 0.0 5.9 6.1

 Fuel Costs 7.8 7.5 11.2 11.0 7.6 7.3 10.6 10.4 7.8 7.4 11.1 10.9

 Variable Costs 5.1 6.1 9.3 11.0 5.1 6.1 9.0 10.3 5.3 6.1 9.5 11.0

 Fixed Costs 9.0 9.7 14.5 15.7 9.3 10.1 14.7 15.8 9.1 9.5 14.5 15.4

 Capital Costs 35.9 39.0 66.5 72.4 40.1 43.9 67.6 73.0 39.3 41.6 67.0 71.9

LCOE (mills/kWh, 2007$)1 73.3 78.8 136.3 147.5 78.8 85.3 136.5 146.3 78.0 81.9 136.9 146.0

Supercritical Pulverized Coal Boiler Ultra-supercritical Pulverized Coal Boiler Supercritical CFB
Cost and Performance Baseline for Fossil Energy Plants

6

Exhibit ES-4 Results Summary for NGCC Cases

 1 CF is 85% 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

Fuel 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 1,084 1,148 3,107 3,309

Raw Water Consumption, gpm 841 890 2,321 2,468

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) 341,350 348,275 572,302 588,738

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 62 61

 Process Contingency 0 0 174 168

 Owner's Costs 151 145 291 281

Total Overnight Cost (2007$x1,000) 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
Cost and Performance Baseline for Fossil Energy Plants

7

PERFORMANCE

The net plant efficiency (HHV basis) for the Montana site cases is shown in

Energy Efficiency

Exhibit ES-5 and for 

the North Dakota site, in Exhibit ES-6. The primary conclusions that can be drawn are:

• The NGCC with no CO2 capture has the highest net efficiency of the technologies 

modeled in this study with an efficiency of 50.6 percent at the North Dakota site, slightly 

higher than the 50.5 percent efficiency at the higher elevation Montana site.

• The NGCC cases with CO2 capture results in the highest efficiency (43.0 percent for MT 

site, 42.9 percent for ND site) among all of the capture technologies.

• The trend for energy efficiency among the IGCC non-capture cases at the MT site is as 

follows: the dry-fed Shell gasifier (42.0 percent), the lower temperature dry fed TRIG 

gasifier (39.9 percent), the dry-fed Siemens gasifier without high temperature syngas 

coolers (37.9 percent), and the slurry-fed, two-stage CoP gasifier (36.7 percent).

• When CO2 capture is added to the IGCC cases, the efficiency of the different 

configurations begin to converge, as a larger portion of the auxiliaries is used for the 

common CO2 capture and compression processes. The gasifier attributes that contribute 

to a high efficiency, such as dry feed or high temperature heat recovery with no quench, 

are negated by the need for shift steam in capture cases. The Montana site cases range 

from 30.4 percent for CoP to 32.1 percent for Shell, with TRIG at 31.8 percent and 

Siemens at 30.6 percent overall net plant efficiency.

• The North Dakota site lignite IGCC cases have slightly lower efficiency than the MT 

(PRB) site counterparts, mainly due to the lower rank coal. The non-capture Shell case 

decreases from 42.0 to 41.8 percent efficiency, and the Siemens case decreases from 37.9 

to 37.6 percent efficiency. The CO2 capture Shell case decreases from 32.1 to 31.7 

percent efficiency, and the Siemens case decreases from 30.6 to 30.0 percent efficiency.

• SC PC without CO2 capture has an efficiency of 38.7 and 37.5 percent for the Montana 

and North Dakota cases, respectively. CFB with similar steam conditions follow the 

same trends, but are slightly more efficient at 38.9 and 38.0 percent efficiency, 

respectively. As steam conditions become more aggressive, the USC PC cases have even 

higher efficiencies of 39.9 and 38.8 percent, respectively.

• The relative efficiency penalty for adding CO2 capture to the IGCC cases is 21.2 percent 

on average, the relative penalty for combustion cases is 30.3 percent, and the relative 

penalty for NGCC is 15.1 percent.

• The addition of CO2 capture to the combustion cases has the highest relative efficiency 

penalties out of all the cases studied. This is primarily because the low partial pressure of 

CO2 in the flue gas (FG) from a combustion plant requires a chemical absorption process 

rather than physical absorption. For chemical absorption processes, the regeneration 

requirements are more energy intensive. The relative efficiency impact on a NGCC CO2

capture configuration is less because of the lower carbon intensity of natural gas relative 

to coal, which more than offsets the reduced driving force for CO2 separation due to the 

lower partial pressure of CO2 in the flue gas.
Cost and Performance Baseline for Fossil Energy Plants

8

Exhibit ES-5 Net Plant Efficiency for Montana Site (HHV Basis)

42.0%

32.1%

39.9%

31.8%

37.9%

30.6%

36.7%

30.4%

38.7%

27.0%

39.9%

28.7%

38.9%

27.3%

50.5%

42.9%

0%

10%

20%

30%

40%

50%

60%

Shell Shell 

w/CO2 

Capture

TRIG TRIG 

w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

CoP CoP 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB 

w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

Efficiency, % (HHV Basis)
Cost and Performance Baseline for Fossil Energy Plants

9

Exhibit ES-6 Net Plant Efficiency for North Dakota Site (HHV Basis)

41.8%

31.7%

39.7%

30.8%

37.5%

25.5%

38.8%

27.2%

38.0%

25.9%

50.6%

43.0%

0%

10%

20%

30%

40%

50%

60%

Shell Shell w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

Efficiency, % (HHV Basis)
Cost and Performance Baseline for Fossil Energy Plants

10

Three water metrics are presented for each technology in

Water Use

Exhibit ES-7 for the Montana site and 

Exhibit ES-8 for the North Dakota site: raw water withdrawal, process discharge, and raw water 

consumption. In each of these exhibits, the values are normalized by the net plant output. Raw 

water withdrawal is the difference between demand and internal recycle. Demand is the amount 

of water required to satisfy a particular process (cooling tower makeup, flue gas desulfurization

[FGD] makeup, etc.) and internal recycle is water available within the process. Raw water 

withdrawal is the water removed from the ground or diverted from a surface-water source for use 

in the plant. Raw water consumption is the portion of the raw water withdrawn that is 

evaporated, transpired, incorporated into products or otherwise not returned to the water source it 

was withdrawn from. Raw water consumption is the difference between withdrawal and process 

discharge, and it represents the overall impact of the process on the water source, which in this 

study is considered to be 50 percent from groundwater (wells) and 50 percent from a municipal 

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

located in the Western U.S. need to consider limited water supplies, a parallel wet/dry condenser

was chosen for all plant configurations. In a parallel cooling system half of the turbine exhaust 

steam is condensed in an air-cooled condenser and half in a water-cooled condenser. Other 

cooling loads, including the Econamine process, are satisfied using cooling water. Cooling water 

is provided by a mechanical draft, evaporative cooling tower. The primary conclusions that can 

be drawn are:

• In all cases the primary water consumer is cooling tower makeup, which ranges from 55

to 99 percent of the total raw water consumption.

• Among non-capture cases, NGCC requires the least amount of raw water withdrawal, 

followed by IGCC and combustion cases (which include all PC and CFB cases, which 

have similar performance profiles). The relative average normalized raw water 

consumption for the Montana site cases is 2.2:2.0:1.0 (PC:IGCC:NGCC) and 2.2:1.6:1.0 

for the North Dakota cases. The relative results are as expected given the higher steam 

turbine output in the PC cases, which results in higher condenser duties, higher cooling 

water flows, and ultimately higher cooling water makeup. The IGCC cases and the 

NGCC case have comparable steam turbine outputs, but IGCC requires additional water 

for coal slurry (CoP), syngas quench (Siemens), and slag handling (all cases). No slurry 

fed gasifiers were included in the North Dakota results.

• Among capture cases, raw water withdrawal requirements increase (relative to noncapture cases) more dramatically for the PC and NGCC cases than for IGCC cases 

because of the large cooling water demand of the Econamine process, which results in 

greater cooling water makeup requirements. The relative average normalized raw water 

consumption for the Montana site CO2 capture cases is 1.9:1.2:1.0 (PC:IGCC:NGCC) 

and 2.2:1.3:1.0 for the North Dakota cases.

• CO2 capture increases the average raw water consumption for all technologies, but the 

increase is lowest for the IGCC cases. The average normalized raw water consumption

for the IGCC cases increases by about 98 percent for the Montana cases and 161 percent 

for the North Dakota cases due primarily to the need for additional water in the syngas to 

accomplish the WGS reaction. With the addition of CO2 capture, PC normalized raw 

water consumption increases by 174 percent for the Montana cases and 170 percent for 
Cost and Performance Baseline for Fossil Energy Plants

11

the North Dakota cases. The NGCC cases’ water consumption increases by 

approximately 225 percent for both site locations. The large cooling water demand of the 

Econamine process drives this substantial increase for the PC and NGCC technologies.
Cost and Performance Baseline for Fossil Energy Plants

12

Exhibit ES-7 Raw Water Withdrawal and Consumption for Montana Site

3.1

7.2

3.7

6.5

4.5

9.0

5.4

8.4

4.8

13.9

4.7

12.9

4.4

14.1

2.1

7.1

2.3

5.9

2.9

5.5

3.4

7.4

4.3

6.9

3.8

10.0

3.7

9.3

3.3

10.4

1.6

5.3

0

2

4

6

8

10

12

14

16

Shell Shell 

w/CO2 

Capture

TRIG TRIG 

w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

CoP CoP 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB 

w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

Water, gpm/Mwnet

Raw Water Withdrawal

Process Water Discharge

Raw Water Consumption
Cost and Performance Baseline for Fossil Energy Plants

13

Exhibit ES-8 Raw Water Withdrawal and Consumption for North Dakota Site

3.0

7.8

4.0

8.9

4.9

14.2

4.7

13.2

4.3

14.5

2.1

7.1

2.2

6.2

2.9

7.2

3.9

9.9

3.7

9.2

3.3

10.4

1.6

5.3

0

2

4

6

8

10

12

14

16

Shell Shell w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

Water, gpm/Mwnet

Raw Water Withdrawal

Process Water Discharge

Raw Water Consumption
Cost and Performance Baseline for Fossil Energy Plants

14

COST RESULTS

The Total Overnight Cost (TOC) for each plant was calculated by adding owner’s costs to the 

Total Plant Cost (TPC). The 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). Escalation and interest on debt during the capital expenditure period were 

estimated and added to the TOC to provide the Total As-Spent Capital (TASC).

Total Overnight Cost

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

design engineering. 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 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:

• Gasifiers and Syngas Coolers – 15 percent on all IGCC cases – next-generation 

commercial offering and integration with the power island.

• Two Stage Selexol – 20 percent on all IGCC capture cases – lack of operating experience 

at commercial scale in IGCC service.

• Mercury Removal – 5 percent on all IGCC cases – minimal commercial scale experience 

in IGCC applications.

• CO2 Removal System – 20 percent on all PC/NGCC capture cases - post-combustion 

process unproven at commercial scale for power plant applications.

• Combustion Turbine-Generator (CTG) – 5 percent on all IGCC non-capture cases –

syngas firing and air separation unit (ASU) integration; 10 percent on all IGCC capture 

cases – high hydrogen firing. 

• Instrumentation and Controls – 5 percent on all IGCC accounts and 5 percent on the PC 

and NGCC capture cases – integration issues.

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

Exhibit ES-9 for the Montana site and Exhibit ES-10 for the North Dakota site. TOC is 

expressed in June 2007 dollars. TASC is expressed in mixed-year 2007 to 2011 year dollars for 

coal plants and 2007 to 2009 mixed-year dollars for NGCC. The following conclusions can be 

drawn:
Cost and Performance Baseline for Fossil Energy Plants

15

• Among the non-capture cases at the Montana site, NGCC has the lowest TOC at 

$817/kW followed by the combustion cases with an average cost of $2,352/kW and 

IGCC with an average cost of $2,935/kW. At the North Dakota site, NGCC has the 

lowest TOC at $782/kW (which is lower than at the Montana site due to increased 

output) followed by PC with an average cost of $2,536/kW and IGCC with an average 

cost of $3,166/kW, using the lower rank coal.

• Among the capture cases at the Montana site, NGCC has the lowest TOC of $1,607kW 

followed by PC with an average cost of $4,018/kW and IGCC with an average cost of 

$4,028/kW. At the North Dakota site, NGCC again has the lowest TOC, $1,548/kW, 

followed by PC with an average cost of $4,340/kW and IGCC with an average cost of 

$4,404/kW.

• The average non-capture IGCC cost is 25 percent greater than the average PC cost. The 

process contingency for the IGCC non-capture cases ranges from $56-83/kW, while there 

is minimal process contingency for the SC PC and NGCC non-capture cases. The 

differential between IGCC and PC is reduced to 22 percent when the IGCC process 

contingency is eliminated.

• The average CO2 capture IGCC cost is roughly equivalent to or slightly greater than the 

average PC cost. The process contingencies are universally higher for the more complex, 

less commercially mature CO2 capture processes and plant configurations: the IGCC 

capture cases process contingency ranges from $135-164/kW, the PC cases from $107-

154/kW, CFB cases $233-251/kW, and $168-174/kW for the NGCC cases.
Cost and Performance Baseline for Fossil Energy Plants

16

Exhibit ES-9 Plant Capital Costs for Montana Site

3,056

4,253

2,728

3,691

3,185

4,318

2,771

3,851

2,293

3,987

2,405

4,049

2,357

4,018

817

1,607

3,484

4,849

3,110

4,208

3,631

4,922

3,159

4,390

2,600

4,545

2,742

4,615

2,687

4,580

879

1,732

0

1,000

2,000

3,000

4,000

5,000

6,000

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

TOC

TASC

Shell Shell 

w/CO2 

Capture

TRIG TRIG 

w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

CoP CoP 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB 

w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

Capital Costs, $/kW

TASC Owner's Cost

Process Contingency Project Contingency

Home Office Expense Bare Erected Cost
Cost and Performance Baseline for Fossil Energy Plants

17

Exhibit ES-10 Plant Capital Costs for North Dakota Site

3,094

4,378

3,239

4,430

2,489

4,341

2,628

4,372

2,490

4,307

782

1,548

3,527

4,991

3,692

5,050

2,823

4,949

2,996

4,984

2,839

4,909

840

1,668

0

1,000

2,000

3,000

4,000

5,000

6,000

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

Shell Shell w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

Capital Costs, $/kW

TASC Owner's Cost

Process Contingency Project Contingency

Home Office Expense Bare Erected Cost
Cost and Performance Baseline for Fossil Energy Plants

18

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

4] 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-11

, 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 the simplified equation below.

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 ES-11 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

 

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 for Fossil Energy Plants

19

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

the length of the capital expenditure period (3 year or 5 year). All cases were assumed to be 

undertaken at investor owned utilities (IOUs). High risk projects are those in which commercial 

scale operating experience is limited. The IGCC and SC CFB cases (with and without CO2

capture) and the PC and NGCC cases with CO2 capture were considered to be high risk. The 

non-capture PC and NGCC cases were considered to be low risk. Coal based cases were 

assumed to have a 5 year capital expenditure period and natural gas cases a 3 year period. The 

current-dollar, 30-year levelized cost of electricity (LCOE) was also calculated and is in the 

results summary, but the primary metric used in the balance of this study is COE.

Exhibit ES-11 Economic Parameters Used to Calculate COE

High Risk

(5 year capital 

expenditure 

period)

Low Risk

(5 year capital 

expenditure 

period)

High Risk

(3 year capital 

expenditure 

period)

Low Risk

(3 year capital 

expenditure 

period)

First Year Capital 

Charge Factor 0.1243 0.1165 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 also be representative of January 2010 

costs.

The COE results are shown in Exhibit ES-12 for the Montana site cases and Exhibit ES-13 for 

the North Dakota site cases with the capital cost, fixed operating cost, variable operating cost,

and fuel cost shown individually. 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:

• In non-capture cases, at the Montana site, the combustion cases have the lowest COE 

(average 60.5 mills/kWh), followed by NGCC (64.4 mills/kWh) and IGCC (average 80.8

mills/kWh). At the North Dakota site, the SC PC plant has the lowest COE (61.5 

mills/kWh, all combustion cases average 64.7 mills/kWh), followed by NGCC (63.6 

mills/kWh) and IGCC (average 85.4 mills/kWh).

• In capture cases, at the Montana site, NGCC plants have the lowest COE (92.9 

mills/kWh), followed by the combustion cases (average 107.7 mills/kWh) and IGCC 

(average 114.7 mills/kWh), although the TRIG case (105.2 mills/kWh), with an 83% CO2

capture efficiency, is less expensive than the PC technologies. At the North Dakota site, 

NGCC plants have the lowest COE (91.4 mills/kWh), followed by the combustion cases

(average 115.6 mills/kWh) and IGCC (average 122.8 mills/kWh).
Cost and Performance Baseline for Fossil Energy Plants

20

• The capital cost component of COE is between 61 and 66 percent in all IGCC and PC 

cases. It represents only 18 percent of COE in the NGCC non-capture cases and 26 

percent in the CO2 capture cases mainly because NGCC cases use a cleaner and less 

carbon intensive but more expensive fuel.

• The fuel component of COE ranges from 7-14 percent for the PC and IGCC cases. The 

fuel component is 75 percent of the total in the NGCC non-capture cases and 61 percent 

in the CO2 capture cases.

• CO2 TS&M is estimated to add 3 to 6 mills/kWh to the COE, which is less than 6 percent 

of the total for all capture cases.
Cost and Performance Baseline for Fossil Energy Plants

21

Exhibit ES-12 COE by Cost Component for Montana Site

54

75

48

65

56

77

49

68

36

67

40

68

39

67

12

24

14

18

12

16

14

18

13

17

9

14

9

15

9

14

3

6

8

11

7

9

8

11

8

11

5

9

5

9

5

9

1

3

7

9

8

10

8

10

8

10

8

11

8

11

8

11

48

57

6

6

6

6

6 6 6

3

83

120

75

105

87

122

79

112

58

107

62

108

62

108

64

93

0

20

40

60

80

100

120

140

160

Shell Shell 

w/CO2 

Capture

TRIG TRIG 

w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

CoP CoP 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB 

w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

COE, mills/kWh (2007$)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs
Cost and Performance Baseline for Fossil Energy Plants

22

Exhibit ES-13 COE by Cost Component for North Dakota Site

55

78

57

79

39

72

44

73

42

72

11

23

14

19

14

19

10

16

10

16

10

15

3

6

8

11

8

11

6

11

6

10

6

11

1

3

7

9

7

9

8

11

7

10

7

11

48

57

6 6

6 6 6

3 83

122

87

124

62

116

67

115

65

115

64

91

0

20

40

60

80

100

120

140

160

Shell Shell w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

COE, mills/kWh (2007$)

CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs

Capital Costs
Cost and Performance Baseline for Fossil Energy Plants

23

The first year cost of CO2 avoided was calculated as illustrated in Equation ES-1:

Cost of CO2 Avoided

CO Emissions CO Emissions tons MWh

COE COE MWh

Avoided Cost

reference with removal

with removal reference

{ } /

{ } $ /

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-14 for the Montana site cases and 

Exhibit ES-15 for the North Dakota site cases for each of the technologies modeled. The 

avoided costs for each capture case are calculated using the analogous non-capture plant as the 

reference and again with SC PC without CO2 capture as the reference. The following 

conclusions can be drawn:

• CO2 avoided costs for IGCC plants, using analogous non-capture plants as reference, are 

substantially less than for PC and NGCC because the IGCC CO2 removal is 

accomplished prior to combustion and at elevated pressure using physical absorption. 

This metric can be considered an intrinsic property to the technology or configuration 

gauging the ease of configuring the technology to capture CO2.

• The CO2 avoided costs for NGCC plants, using analogous non-capture as reference, are 

high in part because the NGCC non-capture configuration already emits a very low 

amount of carbon. Consequently, the removal cost for NGCC plants is normalized by a 

smaller amount of CO2 being captured.

• CO2 avoided costs for NGCC plants without capture, using SC PC as reference, are 

substantially lower than all the other technologies. The inherently low carbon intensity of 

the fuel makes even the non-capture NGCC configuration emit almost 60% less CO2 than 

the reference SC PC plant, making it a cost effective option for reducing or offsetting 

smaller amounts of CO2 emissions. This metric can be used to assess the impact of 

building NGCC plants instead of coal plants.
Cost and Performance Baseline for Fossil Energy Plants

24

Exhibit ES-14 First Year CO2 Avoided Costs for Montana Site

54

48

46

44

68

63 64

89

82

69

86

73

68 67 68

13

43

0

10

20

30

40

50

60

70

80

90

100

Shell TRIG Siemens CoP SC PC USC PC CFB NGCC w/o CO2 

Capture

NGCC w/CO2 

Capture

First Year CO2 Avoided Cost, $/tonne (2007$)

Analogous Technology w/o Capture Reference

SC PC w/o Capture Reference
Cost and Performance Baseline for Fossil Energy Plants

25

Exhibit ES-15 First Year CO2 Avoided Costs for North Dakota Site

58

47

70

64

67

87

74

78

70

68 68

12

34

0

10

20

30

40

50

60

70

80

90

100

Shell Siemens SC PC USC PC CFB NGCC w/o CO2 

Capture

NGCC w/CO2 

Capture

First Year CO2 Avoided Cost, $/tonne (2007$)

Analogous Technology w/o Capture Reference

SC PC w/o Capture Reference
Cost and Performance Baseline for Fossil Energy Plants

26

The COE sensitivity to fuel cost for the Montana site cases is presented in 

Fuel Cost Sensitivity

Exhibit ES-16 and in 

Exhibit ES-17 for the North Dakota site cases. The solid line is the COE of NGCC as a function 

of natural gas cost, the higher green line representing the CO2 capture case and the lower blue 

line representing the non-capture case. For comparison, the lowest COE configuration was 

selected to represent each technology type: TRIG for PRB IGCC cases, Shell for Lignite IGCC 

cases, and SC PC for the PC cases. The points on the line represent the natural gas cost that 

would be required to make the COE of NGCC equal to the other technologies at a varied coal 

costs. For each coal type, associated with each site location, a range of coal price scenarios are 

plotted representing the base coal cost ± 25 percent. This translates to data points at [$0.67, 

$0.89, and $1.11/MMBtu] for the Montana PRB coal costs and [$0.62, $0.83, and 

$1.03/MMBtu] for the North Dakota lignite coal costs. As an example, at a PRB coal cost of 

$0.67/MMBtu (25% less than the base cost), the non-capture IGCC becomes competitive with

NGCC at a natural gas price of $7.69/MMBtu resulting in a COE of 102.8 mills/kWh.

At higher elevations, PC cases become more attractive, in part because there is no combustion 

turbine and thus no derate due to lower ambient pressures. For the non-capture scenario, the SC 

PC cases are the most cost competitive, requiring a natural gas price of $5.92/MMBtu for NGCC 

to generate power below the Montana PRB SC PC electricity cost of 57.8 mills/kWh assuming 

the base coal cost. For the lower elevation North Dakota site, NGCC becomes competitive at 

$6.36/MMBtu, resulting in a COE of 62.2 mills/kWh.

For the CO2 capture configurations using the base costs, NGCC is the lowest cost option due to 

the low capital cost component of the COE. For the CO2 capture configurations at the Montana 

site, the compact, high efficiency TRIG IGCC case results in a lower cost of electricity than the 

SC PC case, and beats the NGCC electrical generation cost when natural gas is above $7.97, 

compared to the base case PRB costs. The Montana PRB CO2 capture SC PC case requires a 

natural gas price of $8.23/MMBtu to be competitive with the NGCC CO2 capture case.
Cost and Performance Baseline for Fossil Energy Plants

27

Exhibit ES-16 Sensitivity to Fuel Costs for Montana Site

Exhibit ES-17 Sensitivity to Fuel Costs for North Dakota Site

0

20

40

60

80

100

120

140

160

0 2 4 6 8 10 12 14

COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu

NGCC

NGCC w/Cap

IGCC PRB

PC PRB

Baseline NG Price, 

$7.13/MMBtu

PRB Coal Costs

[$0.67, $0.89, $1.11/MMBtu]

0

20

40

60

80

100

120

140

160

0 2 4 6 8 10 12 14

COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu

NGCC

NGCC w/Cap

IGCC Lig

PC Lig

Baseline NG Price, 

$7.13/MMBtu

Lignite Coal Costs

[$0.62, $0.83, $1.03/MMBtu]
Cost and Performance Baseline for Fossil Energy Plants

28

The sensitivity of COE to CF is shown for the Montana site cases in 

Capacity Factor Sensitivity

Exhibit ES-18 and the North 

Dakota site cases in Exhibit ES-19. The CF is plotted from 30 to 90 percent. Select cases were 

chosen to represent the general characteristics of each technology type and configuration and to 

facilitate comparison between cases. The baseline CF is 80 percent for IGCC cases with no 

spare gasifier and is 85 percent for PC and NGCC cases. The curves for the IGCC cases assume 

that the CF could be extended to 90 percent with no spare gasifier. Similarly, the PC and NGCC 

curves assume that the CF could reach 90 percent with no additional capital equipment.

Technologies with high capital cost (PC and IGCC with CO2 capture) show a greater increase in 

COE with decreased CF. Conversely, NGCC with no CO2 capture is relatively flat because the 

COE is dominated by fuel costs, which decrease as the CF decreases. Conclusions that can be 

drawn from this sensitivity include:

• For the Montana site, at a CF below 70 percent, NGCC has the lowest COE out of the 

non-capture cases. Above this threshold, the TRIG IGCC configuration has the lowest 

COE.

• For the North Dakota site, at a CF below 85 percent, NGCC has the lowest COE out of 

the non-capture cases. Above this threshold, the SC PC configuration has the lowest 

COE.

• NGCC with CO2 capture is the most attractive CO2 capture option and can be even less 

expensive than some of the non-capture configurations, depending on the CF. At a CF 

below 40 percent, the NGCC CO2 capture cases become just as costly as the IGCC noncapture running at the base load (80 percent CF) further illustrating the relatively small 

impact of CF on NGCC COE.
Cost and Performance Baseline for Fossil Energy Plants

29

Exhibit ES-18 Sensitivity to Capacity Factor for Montana Site

Exhibit ES-19 Sensitivity to Capacity Factor for North Dakota Site

0

50

100

150

200

250

300

350

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

COE, mills/kWh (2007$)

Capacity Factor

Shell IGCC w/Capture

SC PC w/Capture

TRIG IGCC w/Capture

NGCC w/Capture

Shell IGCC

TRIG IGCC

NGCC

SC PC

0

50

100

150

200

250

300

350

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

COE, mills/kWh (2007$)

Capacity Factor

Shell IGCC w/Capture

SC PC w/Capture

NGCC w/Capture

Shell IGCC

NGCC 

SC PC 
Cost and Performance Baseline for Fossil Energy Plants

30

A plot combining the CF and fuel cost sensitivities for NGCC plants shows unique 

characteristics for this low capital cost, high fuel cost generating option, compared to the other 

options. Due to the high fuel cost, an NGCC plant may not be dispatched whenever the plant is 

available, which would lower the real world capacity factor. A parametric graph of the 

breakeven point for selected coal technologies show the required capacity factor and natural gas 

price, when the indicated coal technology (running at the baseline capacity factor) will have a 

lower COE than the analogous NGCC case at the same site location. A comparison of the noncapture cases is shown in 

Combined NGCC Capacity Factor and Natural Gas Price Parity

Exhibit ES-20. The CO2 capture cases are compared, using a 

$67/tonne CO2 emission price, to CO2 Capture NGCC in Exhibit ES-21 and to non-capture 

NGCC in Exhibit ES-22. This CO2 emission price shifts the COE breakeven lines up and to the 

left and corresponds to the breakeven point where the coal technologies have the lowest COE 

when adding CO2 capture rather than paying for uncontrolled emissions. An analysis on the 

effects of CO2 emissions prices are discussed in the CO2 Emissions section.

Exhibit ES-20 Non-Capture Sensitivity to NGCC CF and NG Price 

0

2

4

6

8

10

12

14

30% 40% 50% 60% 70% 80% 90%

Natural Gas Price, $/MMBtu

NGCC Capacity Factor

Shell Lignite

Shell PRB

TRIG PRB

Supercritical PC Lignite

Supercritical PC PRB

Coal Has 

Lowest COE

NGCC Has 

Lowest COE
Cost and Performance Baseline for Fossil Energy Plants

31

Exhibit ES-21 CCS Sensitivity to CO2 Capture NGCC CF and NG Price

with $67/tonne CO2Emission Price

Exhibit ES-22 CCS Sensitivity to Non-Capture NGCC CF and NG Price

with $67/tonne CO2Emission Price

0

2

4

6

8

10

12

14

30% 40% 50% 60% 70% 80% 90%

Natural Gas Price, $/MMBtu

NGCC Capacity Factor

Shell CCS Lignite

Shell CCS PRB

USC PC CCS Lignite

TRIG CCS PRB

USC PC CCS PRB

Coal CCS Has 

Lowest COE

NGCC Has 

Lowest COE

0

2

4

6

8

10

12

14

30% 40% 50% 60% 70% 80% 90%

Natural Gas Price, $/MMBtu

NGCC Capacity Factor

Shell CCS Lignite

Shell CCS PRB

USC PC CCS Lignite

TRIG CCS PRB

USC PC CCS PRB

Coal CCS Has 

Lowest COE

NGCC Has 

Lowest COE
Cost and Performance Baseline for Fossil Energy Plants

32

ENVIRONMENTAL PERFORMANCE

The environmental targets are based on presumed best available control technology (BACT) for 

each technology and are summarized in Exhibit ES-23. This study was conducted prior to the 

issuance of the EPA proposed rules “National Emission Standards for Hazardous Air Pollutants 

from Coal and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance 

for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small IndustrialCommercial-Institutional Steam Generating Units,” and consequently the emissions limits 

included in this proposed rule are not considered in this study. Emissions rates of mercury (Hg) 

are shown in Exhibit ES-24, for both sites, and emission rates of sulfur dioxide (SO2), nitrogen 

oxide (NOx), and particulate matter (PM) are shown graphically in Exhibit ES-25 and 

Exhibit ES-26.

Exhibit ES-23 Study Environmental Targets

Technology

Pollutant IGCC PC CFB NGCC

SO2 0.0128 lb/MMBtu 0.132 lb/MMBtu Negligible

NOx 15 ppmv (dry) @ 

15% O2

0.07 lb/MMBtu 2.5 ppmv (dry) @ 

15% O2

PM (Filterable) 0.0071 lb/MMBtu 0.013 lb/MMBtu Negligible

Hg (PRB) >90% capture 0.60 lb/TBtu 3.0 lb/TBtu N/A

Hg (Lignite) >90% capture 1.12 lb/TBtu 4.8 lb/TBtu N/A

The primary conclusions that can be drawn are:

• Low NOx burners (LNB) with overfire air and selective catalytic reduction in the PC 

cases and low bed temperature and selective non-catalytic reduction in the CFB cases 

achieve the 0.07 lb/MMBtu NOx emission limit. A NOx emissions limit of 15 ppmv was

achieved in the IGCC cases using LNBs and syngas dilution to the combustion turbine. 

NGCC emissions were limited using dry LNB and an SCR to achieve 2.5 ppmv. For 

these concentration based emissions limits, the resulting emissions on a lb/MMBtu basis 

for the coal-based systems vary slightly because of the variable coal feed rates and flue 

gas volumes generated among cases.

• A dry FGD with baghouse in PC cases and cyclones and a baghouse in the CFB cases 

were able to achieve the 0.013 lb/MMBtu PM emission limit. A combination of 

cyclones, candle filters, and scrubbers were assumed to achieve the IGCC particulate 

limit of 0.0071 lb/MMBtu.

• Sulfur emissions are uniformly low and vary with coal type and technology type. The 

AGR in the IGCC cases removes upwards of 99 percent of the sulfur as H2S, which is 

then recovered in the Claus plant as elemental sulfur. In-bed limestone injection in the 

CFB cases is assumed to have an SO2 removal efficiency of 94 percent while the spray 

dryer absorbers used in the PC cases is assumed to have a removal efficiency of 93 
Cost and Performance Baseline for Fossil Energy Plants

33

percent. While PRB and lignite coals have the similar sulfur content on an as-received 

basis, more lignite coal is required to generate the same amount of electricity because of 

its lower heating value. As a consequence, more SO2 is emitted at a constant capture 

efficiency in the lignite coal cases.

• In combustion-based CO2 capture cases the sulfur concentration is reduced even further 

to maintain the performance of the amine-based solvents through the use of a dry

polishing scrubber ahead of the absorber.

• Lignite coal inherently has higher concentrations of mercury (and lower heating value) 

than the PRB coal, so the lignite cases result in higher mercury emissions. Using 

activated carbon beds, the IGCC cases are able to achieve the environmental targets. For

combustion cases, mercury emissions are higher for lignite coal cases compared to the 

analogous PRB coal cases because there is no co-benefit capture with lignite coals while 

PRB coal cases achieve some co-benefit capture. Mercury emissions are lower for the 

CFB cases because of higher co-benefit capture in addition to the use of carbon injection.

Exhibit ES-24 Mercury Emissions Rates

0.351

0.597

0.302

0.560

1.121

0.482

0.000

0.200

0.400

0.600

0.800

1.000

1.200

IGCC PRB PC PRB CFB PRB NGCC MT IGCC Lig PC Lig CFB Lig NGCC ND

Emissions, lb/TBtu
Cost and Performance Baseline for Fossil Energy Plants

34

Exhibit ES-25 SO2, NOx, and Particulate Emission Rates for Montana Site

0.002 0.001 0.002 0.001

0.004

0.001 0.002 0.001

0.119

0.002

0.119

0.002

0.102

0.002

0.062

0.050

0.059

0.049

0.061

0.051 0.052

0.044

0.070 0.070 0.070 0.070 0.070 0.070

0.009 0.009 0.007 0.007 0.007 0.007 0.007 0.007 0.007 0.007

0.013 0.013 0.013 0.013 0.013 0.013

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

Shell Shell 

w/CO2 

Capture

TRIG TRIG 

w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

CoP CoP 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB 

w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

Emissions, lb/MMBtu

SO2

NOx

Particulate
Cost and Performance Baseline for Fossil Energy Plants

35

Exhibit ES-26 SO2, NOx, and Particulate Emission Rates for North Dakota Site

0.002 0.001 0.002 0.001

0.132

0.002

0.132

0.002

0.113

0.002

0.063

0.049

0.061

0.050

0.070 0.070 0.070 0.070 0.070 0.070

0.009 0.009 0.007 0.007 0.007 0.007

0.013 0.013 0.013 0.013 0.013 0.013

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

Shell Shell w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

Emissions, lb/MMBtu

SO2

NOx

Particulate
Cost and Performance Baseline for Fossil Energy Plants

36

CO2 emissions are not currently regulated. However, since there is increasing momentum for 

establishing carbon limits, it was an objective of this study to examine the relative amounts of 

CO2 capture achievable among the six technologies. CO2 emissions are presented in 

CO2 Emissions

Exhibit ES-27 and Exhibit ES-28 for the two sites, normalized by net output. In each results 

summary table emissions are reported on both a net and gross MWh basis. New Source 

Performance Standards (NSPS) contain emission limits for SO2 and NOx on a lb/(gross) MWh 

basis. However, since CO2 emissions are not currently regulated, the potential future emission 

limit basis is not known and CO2 emissions are presented in both ways. The following 

conclusions can be drawn:

• In cases with no CO2 capture, NGCC emits 56 percent less CO2 than the lowest PC case

and 54 percent less CO2 than the lowest IGCC case per unit of net output comparing each 

respective site. The NGCC CO2 emissions reflect the lower carbon intensity of natural 

gas relative to coal and the higher cycle efficiency of NGCC relative to IGCC and PC. 

Based on the fuel compositions used in this study, natural gas contains 41 lb 

carbon/MMBtu and the PRB and ND lignite coals contain 59 lb/MMBtu of heat input.

• The CO2 reduction goal in this study was a nominal 90 percent, which is achieved for all 

cases except the TRIG IGCC, which remove 83% of the CO2, in part due to the high cold 

gas efficiency and high methane concentration. The result is that the controlled CO2

emissions follow the same trend as the uncontrolled cases, i.e., the NGCC case emits less 

CO2 than the IGCC cases, which emit less than the PC cases.

• Among the non-capture coal cases the highest efficiency cases have the lowest emissions, 

after accounting for the carbon intensity of the fuels. The range of emissions rates for the 

CO2 capture cases is tightened after 90% of the carbon is captured and sequestered.
Cost and Performance Baseline for Fossil Energy Plants

37

Exhibit ES-27 CO2 Emissions Normalized By Net Output for Montana Site

1,735

233

1,803

386

1,927

246

1,977

245

1,892

271

1,836

255

1,866

265

799

94

0

500

1,000

1,500

2,000

2,500

Shell Shell 

w/CO2 

Capture

TRIG TRIG 

w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

CoP CoP 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB 

w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

CO2 Emissions, lb/net-MWh
Cost and Performance Baseline for Fossil Energy Plants

38

Exhibit ES-28 CO2 Emissions Normalized By Net Output for North Dakota Site

1,783

242

1,981

255

1,996

242

1,930

276

1,963

288

797

94

0

500

1,000

1,500

2,000

2,500

Shell Shell w/CO2 

Capture

Siemens Siemens 

w/CO2 

Capture

SC PC SC PC 

w/CO2 

Capture

USC PC USC PC 

w/CO2 

Capture

CFB CFB w/CO2 

Capture

NGCC NGCC 

w/CO2 

Capture

CO2 Emissions, lb/net-MWh
Cost and Performance Baseline for Fossil Energy Plants

39

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

examined in this study will become more expensive. The technologies without carbon capture 

will be impacted to a larger extent than those with carbon capture, and coal-based technologies 

will be impacted more than natural gas-based technologies. The most economical option for 

each technology is used for the COE sensitivity to carbon emissions price shown for the 

Montana site cases in 

CO2 Emission Price Impact

Exhibit ES-29 and for the North Dakota site cases in Exhibit ES-30. Thus,

the PC technology is represented by the SC PC cases and the IGCC technology is represented by 

the TRIG cases for the Montana site and the Shell cases for the North Dakota site.

The curves represent the base study design conditions, capacity factor, and fuel prices used for 

each technology; namely 80 percent capacity factor for IGCC plants and 85 percent for PC and 

NGCC plants, and $0.89/MMBtu for the PRB coal and $0.83/MMBtu for the lignite coal and 

$7.13/MMBtu for natural gas. Natural gas fuel prices are more volatile than coal and tend to 

fluctuate over a fairly large range. The dispatch-based capacity factor for NGCC plants is 

significantly less than 85 percent and would result in a higher COE as was shown in the capacity 

factor sensitivity.

Exhibit ES-29 Sensitivity to Carbon Emissions Price for Montana Site

0

20

40

60

80

100

120

140

160

180

0 10 20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

First Year CO2 Emission Price, $/tonne

Shell IGCC w/Capture

SC PC w/Capture

TRIG IGCC w/Capture

NGCC w/Capture

Shell IGCC

TRIG IGCC

NGCC

SC PC
Cost and Performance Baseline for Fossil Energy Plants

40

Exhibit ES-30 Sensitivity to Carbon Emissions Price for North Dakota Site

The intersection of the capture and non-capture curves for a given technology gives the cost of 

CO2 avoided for that technology. For example, the cost of CO2 avoided is $68/tonne for SC PC 

and $89/tonne for NGCC at the Montana site, and $70/tonne and $87/tonne for the North Dakota 

site. These values can be compared to those shown in Exhibit ES-14.

The following conclusions can be drawn from the carbon emissions price graph:

• At the baseline study conditions any cost applied to carbon emissions favors NGCC 

technology. While PC and NGCC with no capture start at essentially equivalent COEs, 

they diverge rapidly as the CO2 emission cost increases. The lower carbon intensity of 

natural gas relative to coal and the greater efficiency of the NGCC technology account 

for this effect.

• The SC PC and IGCC curves are nearly parallel indicating that the CO2 emission price 

impacts the two technologies nearly equally. As the CO2 emission price increases from 

zero, the two technologies gradually converge due to the slightly lower efficiency of SC 

PC relative to the IGCC.

• For the coal-based technologies, adding CO2 capture becomes the favored configuration

compared to SC PC with no capture at an emission price above approximately $70/tonne.

0

20

40

60

80

100

120

140

160

180

0 10 20 30 40 50 60 70 80 90 100

COE, mills/kWh (2007$)

First Year CO2 Emission Price, $/tonne

Shell w/Capture

SC PC w/Capture

NGCC w/Capture

Shell

NGCC 

SC PC 
Cost and Performance Baseline for Fossil Energy Plants

41

The relationship between technologies and CO2 emission pricing can also be considered in a 

“phase diagram” type plot as shown in 

Combined CO2 Emission and Natural Gas Price Parity

Exhibit ES-31. The lines in the plot represent cost parity 

between different pairs of technologies, combining the CO2 emissions price and natural gas price 

sensitivities to determine the lowest cost generating option at all combinations of these economic 

parameters. The darker lines represent the Montana site cases and the lighter lines represent the 

North Dakota site cases.

Exhibit ES-31 Lowest Cost Technology Parity Sensitivity to CO2 and NG Prices 

The lowest cost technology selection for the given CO2 emission and natural gas price follows 

the same trend for both the Montana and North Dakota site: NGCC dominates at low natural gas 

prices. The PC cases are the next attractive technology once natural gas prices exceed the 

colored horizontal lines. The black vertical lines demarcate the economic conditions where 

including CO2 capture to the base plant configuration results in the lowest overall COE. The 

slopes of the lines are a function of the relative CO2 intensities of the technologies as well as the 

natural gas cases sensitivity to fuel price.

When the parity charts are overlaid, it becomes apparent that the NGCC cases occupy a larger 

area as the lowest cost generating option at the North Dakota site, due in part to the reduced 

combustion turbine derate at lower elevation. The vertical black break even lines for the 

Montana site occur at slightly higher CO2 emissions prices compared to the North Dakota site.

0

2

4

6

8

10

12

14

0 10 20 30 40 50 60 70 80 90 100 110

Natural Gas Price, $/MMBtu

CO2 Emissions Price, $/tonne

SC PC has 

lowest COE

NGCC has 

lowest COE

USC PC w/Capture 

has lowest COE

NGCC w/Capture 

has lowest COE

North Dakota

Montana
Cost and Performance Baseline for Fossil Energy Plants

42

1 “Cost and Performance Baseline for Fossil Energy Plants, Volume 3a: Low Rank Coal to 

Electricity: IGCC Cases”, DOE/NETL-2010/1399, May 2011

REFERENCES

2 “Cost and Performance Baseline for Fossil Energy Plants, Volume 3b: Low Rank Coal to 

Electricity: Combustion Cases”, DOE/NETL-2011/1463, March 2011

3 “Cost and Performance Baseline for Fossil Energy Plants, Volume 3c: Natural Gas 

Combined Cycle at Elevation”, DOE/NETL-2010/1396, March 2011

4 NETL Power Systems Financial Model Version 5.0, December 2008 

User Guide available at: 

http://www.netl.doe.gov/business/solicitations/ssc2008/references/PSFM%20User%20G

uide.pdf