Cost and Performance Baseline for Fossil 

Energy Plants Supplement: Sensitivity to 

CO2 Capture Rate in Coal-Fired Power 

Plants

June 22, 2015

DOE/NETL-2015/1720

OFFICE OF FOSSIL ENERGY

National Energy 

Technology Laboratory
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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 Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

Author List:

Energy Sector Planning and Analysis (ESPA)

Vincent Chou, Arun K.S. Iyengar, Vasant Shah, and Mark Woods 

Booz Allen Hamilton, Inc.

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

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

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

under ESPA Task 341.03.01.

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

NETL staff, particularly:

Timothy Fout, General Engineer

Travis Shultz, Director, Performance Division

Kristin Gerdes, Director, Office of Program Performance and Benefits

DOE Contract Number DE-FE0004001
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

i

Table of Contents

Executive Summary.........................................................................................................................1

1 Introduction...................................................................................................................................5

2 Design Basis..................................................................................................................................6

2.1 Partial Capture Calculation........................................................................................................6

2.2 SC PC Partial Capture Design ...................................................................................................6

2.3 IGCC Partial Capture Design.....................................................................................................8

2.3.1 Water Gas Shift and COS Hydrolysis.....................................................................................8

2.3.2 CO2 Capture – Dual Stage Selexol .........................................................................................8

3 Results and Discussion .................................................................................................................9

4 Conclusion ..................................................................................................................................14

5 References...................................................................................................................................15

Appendix........................................................................................................................................16

Exhibits

Exhibit ES-1 Variation of COE, plant HHV efficiency, cost of CO2 captured, and CO2 capture 

rate with design emission levels for SC PC cases................................................................... 2

Exhibit ES-2 Variation of COE, plant HHV efficiency, cost of CO2 captured, and CO2 capture 

rate with design emission levels for IGCC cases.................................................................... 3

Exhibit ES-3 Summary of results ................................................................................................... 3

Exhibit 1-1 Bituminous Baseline SC PC schematic – modifications for partial capture cases...... 5

Exhibit 1-2 Bituminous Baseline IGCC schematic – modifications for partial capture cases ....... 6

Exhibit 2-1 Block flow diagram of the modified B12B process for partial capture....................... 7

Exhibit 2-2 Block flow diagram of the modified B5B process for partial capture......................... 9

Exhibit 3-1 Plant HHV Efficiency for SC PC plant at various levels of capture ......................... 10

Exhibit 3-2 Plant HHV Efficiency for IGCC plant at various levels of capture........................... 10

Exhibit 3-3 COE with T&S for SC PC plant at various levels of capture .................................... 11

Exhibit 3-4 COE with T&S for IGCC plant at various levels of capture ..................................... 11

Exhibit 3-5 Cost of captured and avoided CO2 for SC PC plant at various levels of capture ...... 12

Exhibit 3-6 Cost of captured and avoided CO2 for IGCC plant at various levels of capture ....... 12

Exhibit 3-7 Capture energy penalty (kWh/lb CO2) for IGCC plant at various levels of capture . 13

Exhibit A-1 PC cases performance summary ............................................................................... 16

Exhibit A-2 IGCC cases performance summary .......................................................................... 17

Exhibit A-3 PC cases cost summary............................................................................................. 18

Exhibit A-4 IGCC cases cost summary ........................................................................................ 19
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

ii

Acronyms and Abbreviations

AEO Annual Energy Outlook 

ASU Air separation unit 

BB Bituminous Baseline

BFD Block flow diagram

Btu British thermal units 

CCF Capital charge factor

CCS Carbon capture and sequestration 

CO Carbon monoxide

CO2 Carbon dioxide

COE Cost of electricity

COS Carbonyl sulfide

DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

ES Executive summary

ESPA Energy Sector Planning and Analysis 

FD Forced draft

FGD Flue gas desulfurization

GEE General Electric Energy 

GHG Greenhouse gas

Gpm Gallons per minute

h, hr Hour

HCl Hydrochloric acid 

Hg Mercury

HHV Higher heating value

HP High pressure

HRSG Heat recovery steam generator

ID Induced draft

IGCC Integrated gasification combined 

cycle 

IP Intermediate pressure

ISO International Standards Organization

kg Kilogram

kW, kWe Kilowatt electric

kWh Kilowatt-hour

lb Pound

lb/MMBtu Pounds per million British thermal 

units 

lb/MWh-gross Pounds per gross megawatt hour

lb/MWh-net Pounds per net megawatt hour

LP Low pressure

MMBtu Million British thermal units 

MW, MWe Megawatt electric

MWh Megawatt-hour

MWt Megawatt thermal

NETL National Energy Technology 

Laboratory

NOAK nth-of-a-kind

NOx Nitrogen oxide

O2 Oxygen

PA Primary air

PC Pulverized coal

PFD Process flow diagram

PM Particulate matter

psia Pound per square inch absolute 

QGESS Quality Guidelines for Energy 

System Studies 

R&D Research and development 

RD&D Research, development, and 

demonstration 

SC Supercritical

SC PC Supercritical pulverized coal

SCR Selective catalytic reduction process 

or equipment

SDA Spray dryer absorber 

SO2 Sulfur dioxide

SOx Oxides of sulfur

T&S Transport and storage

TBtu Trillion British thermal units

TOC Total overnight cost 

tonne Metric ton (1,000 kg)

TPC Total plant cost 

U.S. United States

WGS Water gas shift

°F Degrees Fahrenheit
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Executive Summary

The cost and performance of various plants designed to meet a range of carbon dioxide (CO2)

emissions are evaluated in this report by varying the CO2 capture rate. The base cases for these 

designs are the supercritical (SC) pulverized coal (PC) plant from the National Energy 

Technology Laboratory’s (NETL) report “Cost and Performance Baseline for Fossil Energy 

Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3” [1] and the 

General Electric Energy (GEE) integrated gasification combined cycle (IGCC) plant in NETL’s 

report, “Cost and Performance Baseline for Fossil Energy Plants, Volume 1b: Bituminous Coal

(IGCC) to Electricity, Revision 2 – Year Dollar Update.” [2] The chosen SC PC plants were 

based on the Case B12B, differing only in the addition of a bypass flow path that allows for an 

appropriate portion of the flue gas stream exiting the desulfurization step to be directed towards 

the stack, which reduces the amount CO2 captured in the Cansolv process. The chosen IGCC 

plants were based on the Case B5B, differing by bypassing (either partially or entirely) the water 

gas shift reactors and thereby reducing the amount of CO2 captured in the Selexol process. The 

major components of the underlying CO2 capture technology in the plants were preserved with 

minimal modifications to the overall processes. The SC PC cases include up-to-date cost and 

performance information from recent vendor quotes whereas the IGCC performance and cost are 

based upon the older quotes used for the Revision 2 report, with standard adjustments made to 

update the costs to 2011 dollars. 

The results of the study for the SC PC and IGCC plants are summarized in Exhibit ES-1 and 

Exhibit ES-2, respectively. The exhibits depict the variations of the computed plant higher 

heating value (HHV) efficiencies, costs of electricity (COE), and costs of CO2 captured with 

partial capture design CO2 emission levels. The overall CO2 capture rate is also shown in the 

exhibits. Exhibit ES-3 provides a tabular listing of salient results, including a comparison of the 

emissions on a net and gross output basis. The HHV efficiency of the plants expectedly 

increases with an increase in the allowable CO2 emission levels, varying from a value of 32.5 

percent for the SC PC plant with 90 percent CO2 capture to a value of 40.7 percent for the SC PC

plant with highest CO2 emission (no carbon capture). The HHV efficiency of the IGCC plants 

vary from a value of 32.6 percent for the IGCC plant with 90 percent CO2 capture to a value of 

39.0 percent for the IGCC plant with the highest CO2 emission (no carbon capture). The plant 

COE decreases with an increase in allowable CO2 emissions primarily due to the lower capital 

and operating costs for the reduced sizes of the capture systems and the reduced parasitic load of 

the CO2 capture equipment. For the SC PC plants, the COE for the plant featuring 90 percent 

CO2 capture is ~ 62 percent higher than the COE of the plant with no CO2 capture. For the 

IGCC plants, the COE for the plant featuring 90 percent CO2 capture is ~ 32 percent higher than 

the COE of the IGCC plant with no CO2 capture. The capture impact is smaller for the IGCC 

plants because the CO2 is at a higher concentration and pressure in the IGCC syngas than in the 

SC PC flue gas.

Actual average annual emissions from operating plants are likely to be higher than the design 

emissions rates shown due to start-up, shutdown, part-load operation, and performance 

degradation through maintenance cycles. Lower design emissions rates to ensure adequate 

margins may be required for compliance with future regulations; however, given that the slope of 

the variation of COE with CO2 emission levels is not steep for either SC PC or IGCC plants 

(except at low capture rates), designing for this margin does not have major cost implications. 
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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The cost of capture, equivalent to the minimum plant gate sales price (revenue) required to 

incentivize CO2 capture relative to a non-capture SC PC, is higher at lower capture rates 

primarily due to the associated economies of scale. Should such CO2 revenues be available, then 

the higher capture rate designs are a more cost effective method of CO2 abatement; however, the 

lower capture rate designs represent lower incremental costs than the plant with 90 percent 

capture. Deployment of lower capture rate plants enables demonstration, progressive scaling, 

and optimization of the CO2 capture system with lower absolute costs, while facilitating the 

smooth transition, from both economic and process perspectives, to subsequent plants with 

higher capture rates. 

The observations in this document are made with the caveat that the differences in costs between 

cases are less than the absolute accuracy of the capital cost estimates (estimated to be -15

percent/+30 percent); however, all cases were evaluated using a common set of technical and 

economic assumptions, which allowed meaningful comparisons among the cases. 

Exhibit ES-1 Variation of COE, plant HHV efficiency, cost of CO2 captured, and CO2 capture rate 

with design emission levels for SC PC cases

Source: NETL/Department of Energy (DOE)
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Exhibit ES-2 Variation of COE, plant HHV efficiency, cost of CO2 captured, and CO2 capture rate 

with design emission levels for IGCC cases

Source: NETL/DOE

Exhibit ES-3 Summary of results

Plant 

type

CO2 Emission Level CO2 Capture 

Rate

HHV 

Efficiency

*COE 

(excl. T&S)

**Cost of

Captured CO2

**Cost of 

Avoided CO2

lb/MWhgrosslb/MWhnet % % $/MWh $/tonne CO2 $/tonne CO2

SC PC

1,618 1,705 0 40.7 82.3 - -

1,400 1,498 16 39.2 97.8 123.9 178.7

1,300 1,400 22 38.6 101.4 105.3 152.6

1,200 1,302 29 38.0 104.8 94.2 137.4

1,100 1,201 35 37.4 108.1 86.7 127.2

1,050 1,151 39 37.1 109.7 83.7 123.2

1,000 1,100 42 36.8 111.3 81.2 119.7

900 997 48 36.3 114.4 76.9 114.0

700 786 60 35.1 121.2 72.0 107.5

500 570 72 34.1 127.2 67.4 101.4

183 214 90 32.5 133.2 58.2 89.4

IGCC

1,434 1,724 0 39.0 102.6 - -

1,100 1,356 22 38.5 109.3 154.7 182.4

900 1,129 37 37.4 114.2 105.7 134.8

152 206 90 32.6 135.4 63.2 91.7

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

consistent with Reference. [1] [2] [5]

**Cost of capture based on SC PC without capture (Case B12A)
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Special Considerations on Reported Costs

Capital Costs:

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

consistent with AACE Class 4 cost estimates (i.e., feasibility study) [3] [4] [5], based on the 

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

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

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

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

Costs of mature technologies and designs:

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

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

plants have dropped over time due to “learning by doing” and risk reduction benefits that result 

from serial deployments as well as from continuing R&D.

Costs of emerging technologies and designs:

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

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

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

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

is anticipated that initial deployments of the IGCC and capture plants may incur costs higher 

than those reflected within this report. 

Other factors:

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

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

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

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

captured by the reported cost uncertainty.

Future Cost Trends:

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

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

those estimated herein.
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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1 Introduction

The National Energy Technology Laboratory’s (NETL) Bituminous Baseline (BB) studies [1]

[2] have evaluated the performance and cost of fossil fuel-fired plants that are designed without

capture of the carbon contained in the inlet fuel, as well as plants with at least 90 percent carbon 

capture. The cost and performance of coal-based BB plants that are modified for lower levels of 

CO2 capture (partial capture designs) presented in this report are of general interest to NETL 

insofar that the cost and performance penalties may be mitigated. Specifically, plant designs 

with lower capture rates have the potential to enable demonstration, progressive scaling, and 

optimization of the CO2 capture system with lower absolute costs, while facilitating the smooth 

transition, from both economic and process perspectives, to subsequent plants with higher 

capture rates. 

The objective of this report is to evaluate the cost and performance of a BB supercritical (SC)

pulverized coal (PC) plant with capture (Case B12B) [1] and integrated gasification combined 

cycle (IGCC) plant with capture (Case B5B) [2], both modified to achieve various levels of 

partial capture. The partial capture cases presented in this report preserve the major components 

of the underlying carbon capture and sequestration (CCS) technology utilized in the 

corresponding BB plants with minimal modifications to the overall processes. 

In the SC PC cases, an appropriate portion of the flue gas stream exiting the desulfurization step 

is diverted, as shown in Exhibit 1-1, to the stack, bypassing the CO2 capture system, in order to 

evaluate systems with CO2 emissions ranging from ~ 1700 – 210 lb/MWh-net (zero to 90 percent 

capture). The amine-based Shell Cansolv system - designed to capture 90 percent of the CO2 in 

its inlet stream - is employed as the CO2 capture system, as in the B12B case. 

Exhibit 1-1 Bituminous Baseline SC PC schematic – modifications for partial capture cases

Source: NETL/Department of Energy (DOE)

In the IGCC cases, the reduction in the CO2 capture requirement also reduces the need to convert 

much of the carbon monoxide (CO) in the gasifier exit gas into CO2 via water gas shift (WGS) 

reactors for eventual capture in the dual stage Selexol process. Instead, the CO can be retained 

in the syngas and sent to the gas turbine for combustion and power generation. A simplified 

block flow diagram of the overall IGCC process is shown in Exhibit 1-2. A WGS bypass line 

including a carbonyl sulfide (COS) hydrolysis reactor has been added (in blue) to illustrate the 

CO2

Capture

CO2 Compression 

and Drying Flue Gas

Steam Generator

Particulate/

SOx/NOx/HCl/

Hg Clean-Up 

Steam Turbine

CO2

Steam

Air

Coal

Q

Pulverized coal

Combustor

Power

Captured 

CO2 Stream

CO2 Capture System 

Partial Bypass

To Stack

Residual Stream 

from CO2 Capture 

System
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

6

process modification for the partial capture cases that is used to evaluate systems with CO2

emissions ranging from ~ 1720 – 205 lb/MWh-net (zero to 90 percent capture). The key 

differences between the cases are reflected in the mole percentage of CO2 in the feed to the dual 

stage Selexol unit. These values range from ~16 mole percent for the 22 percent capture case to 

~40.6 mole percent for the 90 percent capture case (B5B). 

Exhibit 1-2 Bituminous Baseline IGCC schematic – modifications for partial capture cases

Source: NETL/DOE

2 Design Basis

The modified plants are assumed to be a generic Midwestern United States (U.S.) plant operating 

under ambient International Standards Organization (ISO) conditions with site and coal 

characteristics that are identical to the BB plants. [1] [2] The emission targets are assumed to be 

the same as in the BB studies, with the exception of the CO2 emission limit, which forms a 

parameter in the present investigation. 

2.1 Partial Capture Calculation

The percent of CO2 captured is estimated by using the model data and the following equation for 

each case: 

% CO2 capture = CO2 Captured / (CO2 Captured + CO2 Emissions * Plant Output)

For example, in BB Case B12B is as follows:

90% CO2 capture = 1,059,193 lb/hr / (1,059,193 lb/hr + 214 lb/MWh-net* 550 MW)

2.2 SC PC Partial Capture Design

The block flow diagram (BFD) of the modified SC PC system, shown in Exhibit 2-1, differs 

from the BFD of the base Case B12B only by the addition of the CO2 capture system bypass flue 

gas stream, downstream of the flue gas desulfurizer (FGD), which can be tuned to meet the 

desired CO2 emission level. The basis for the cost and performance of all partial capture cases is 

the previously mentioned Shell Cansolv amine-based system operating at 90 percent capture. No 

performance penalties were assessed due to the potential operation of the capture system at a 

scale smaller than its rated design point; accordingly, its auxiliary load was computed directly 

based on the CO2 product flow rate. A power law with an exponent of 0.6 was assumed to scale 

Water Gas 

Shift 

Reactor

CO2

Compression 

Flue Gas and Drying 

Heat Recovery 

Steam Generator

Quench and 

Syngas

Scrubber

Steam Turbine

CO2

Steam

O2

Coal

GEE Gasifier 

and Cooler

Power

WGS

Partial

Bypass

To Stack

Dual Stage 

Selexol

CO2

Capture

Combustion Turbine

COS 

Hydrolysis 

Reactor
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

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40 percent of the cost of the CO2 capture system based on the inlet gas volumetric flow to the 

process and the remaining 60 percent of the cost scaled based upon the captured CO2 mass flow 

rate in accordance with Quality Guidelines for Energy System Studies (QGESS) procedures. [6] 

The costs for controlling and monitoring the CO2 capture system bypass flow were assumed to 

be negligible. While partial bypass of the capture system results in slightly higher SO2 emissions 

than in Case B12B, the emission levels will be lower than the values for Case B12A (no CCS), 

which is tantamount to a special subset of the modified system where all the flue gas flow 

bypasses the CO2 capture system. 

The plants are evaluated at a rated net power of 550 MWe with an assumed capacity factor of 85 

percent. A high-risk financial structure resulting in a capital charge factor (CCF) of 0.124 is 

used to evaluate the costs of all cases with CO2 capture (non-capture case uses a conventional 

financial structure with a CCF of 0.116).1 All other process parameters and cost assumptions are 

identical to Case B12B.

Exhibit 2-1 Block flow diagram of the modified B12B process for partial capture

Source: NETL/DOE

 

1 In contrast, the Energy Information Administration (EIA) applies a cost of capital premium to non-capture coal plants in its Annual Energy 

Outlook (AEO) Reference Cases. Specifically, “to reflect the market reaction to potential future GHG regulation, a 3-percentage-point increase in 

the cost of capital for investments in new coal-fired power and coal-to-liquids plants without carbon capture and sequestration technology is 

assumed.” [5]

STACK GAS

STACK

CO2 CAPTURE

SYSTEM

32 31

33

22

23

CO2

PRODUCT

REBOILER

STEAM

REBOILER

CONDENSATE

PULVERIZED

COAL

BOILER

SCR

BAGHOUSE FGD

LIMESTONE GYPSUM

SLURRY

OXIDATION

AIR

MAKEUP

WATER

BOTTOM ASH

COAL FEED

INFILTRATION

AIR

1

4

8

7

9

14

FLY ASH

15 16

18 19

17 20

21

HP 

TURBINE

34

35

36

IP

TURBINE LP TURBINE

CONDENSER

38

FEEDWATER 

HEATER

SYSTEM

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

3

2

6

5

11

37

10

HYDRATED

LIME

12

13

ACTIVATED

CARBON

FD FANS

PA FANS

ID FAN

CO2 COMPRESSORS

BOILER

FEEDWATER

29 RECLAIMER

STEAM 30

RECLAIMER

CONDENSATE

DRYER

27

CO2 COMPRESSORS

28

25 26

24

VENT

DRYER STEAM

DRYER

CONDENSATE

39

40

CO2 CAPTURE SYSTEM 

BYPASS STREAM
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2.3 IGCC Partial Capture Design

The block flow diagram of the modified IGCC system, shown in Exhibit 2-2, differs from that of 

the BB Case B5B with 90 percent capture solely by the addition of a bypass around the WGS 

reactors. The bypass includes a COS hydrolysis reactor. Two partial capture cases were 

evaluated: one with a partial bypass of the WGS reactor and achieving 37 percent capture, and 

one with the WGS bypassed completely and achieving 22 percent capture.

The plants are evaluated with an assumed capacity factor of 80 percent. A high-risk financial 

structure resulting in a CCF of 0.124 is used to evaluate the costs of all IGCC cases. All other 

process parameters and cost assumptions are identical to Case B5B.

2.3.1 Water Gas Shift and COS Hydrolysis 

The 37 percent capture case, resulting in 1,129 lb/MWh-net or 900 lb/MWh-gross, requires only 

17 percent of the syngas to be sent to the WGS reactors. The 22 percent capture case, resulting 

in 1,356 lb/MWh-net or 1,100 lb/MWh-gross, can be processed without including WGS reactors,

so the entire gasifier exit stream is processed through a COS hydrolysis reactor instead. The 

reduced flow through the WGS reactor also reduces the amount of shift steam that needs to be 

extracted from the steam cycle from 285,687 lb/hr of 800 psia, 550°F steam for the reference 

90 percent capture case to 45,797 lb/hr in the 37 percent capture case, and zero in the 22 percent

capture case. This lower steam extraction requirement results in higher gross power output from 

the steam cycle for the partial capture cases. 

A power law with an exponent of 0.8 was assumed to scale the cost of the shift and COS 

hydrolysis reactors based on catalyst volume in accordance with QGESS procedures. [6] 

2.3.2 CO2 Capture – Dual Stage Selexol

The amount of hydrogen recovered from the syngas stream is dependent on the Selexol process 

design conditions. In the BB report, hydrogen recovery is 99.4 percent. The minimal hydrogen 

slip to the CO2 sequestration stream maximizes the overall plant efficiency. The BB case 

Selexol plant cost estimates are based on a plant designed to recover this high percentage of 

hydrogen.

The Selexol system is designed to capture 93 percent of the CO2 in the feed to the dual stage 

process for both of the cases that require some WGS. For the lowest capture case with no WGS, 

the system only needs to capture 78 percent of the CO2 in the feed to meet the proposed limit, so 

the cost estimates were modified to reflect the reduced capture requirement, while the 

performance continues to be scaled on the amount of CO2 captured.

Since the Selexol system has components for sulfur capture as well as CO2 capture, a combined 

approach to cost scaling was utilized. A power law with an exponent of 0.79 was assumed to 

scale 40 percent of the cost of the dual stage Selexol system based on the inlet gas volumetric 

flow to the process while a power law with an exponent of 0.61 was used to scale the remaining 

60 percent of the cost based upon the captured CO2 flow rate in accordance with QGESS 

procedures. [6]
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Exhibit 2-2 Block flow diagram of the modified B5B process for partial capture

Source: NETL/DOE

3 Results and Discussion

The performance and costs of both the SC PC and IGCC plants were evaluated for various partial 

capture cases. The higher heating value (HHV) efficiency of the plants expectedly decreases 

with an increase in the percent of CO2 capture and corresponding decrease in the allowable CO2

emission levels. This is illustrated in Exhibit 3-1 for the SC PC cases and in Exhibit 3-2 for the 

IGCC cases. Detailed performance and cost data is found in the Appendix to this report.

The variations of the cost of electricity (COE) for different design values of CO2 emissions are 

shown in Exhibit 3-3 and 3-4. The COE increases gradually as the capture rate increases. The 

costs of CO2 captured and avoided using the BB SC PC non-capture case (B12B) as the 

reference case are shown in Exhibits 3-5 and 3-6. The cost of captured CO2 represents the 

minimum CO2 plant gate sales price that will incentivize carbon capture in lieu of a defined 

reference non-capture plant. Similarly, the cost of avoided CO2 represents the minimum cost of,

or penalty on, CO2 emissions that will incentivize the carbon capture cases in lieu of a noncapture plant. For both the SC PC and the IGCC cases, the non-capture SC PC case (B12A) as 

the lowest cost non-capture coal case serves as the reference plant. As the figures indicate, the 

normalized capture and avoided costs decrease significantly as the capture rate increases due to 

the economies of scale and the increasing amount of CO2 captured or avoided.
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Exhibit 3-1 Plant HHV Efficiency for SC PC plant at various levels of capture

Source: NETL/DOE

Exhibit 3-2 Plant HHV Efficiency for IGCC plant at various levels of capture

Source: NETL/DOE
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Exhibit 3-3 COE with T&S for SC PC plant at various levels of capture

Note: Case without capture uses conventional financing. All others use high-risk financial assumptions.

Source: NETL/DOE

Exhibit 3-4 COE with T&S for IGCC plant at various levels of capture

Note: Case without capture uses conventional financing. All others use high-risk financial assumptions.

Source: NETL/DOE
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Exhibit 3-5 Cost of captured and avoided CO2 for SC PC plant at various levels of capture

Source: NETL/DOE

Exhibit 3-6 Cost of captured and avoided CO2 for IGCC plant at various levels of capture

Source: NETL/DOE
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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The energy penalty for adding CO2 capture was estimated using the following equation: 

Capture Energy Penalty =

� 1

HHHHHHHHHHHHHHHHHHHHHHHHHHHH−cccccccccccccc − 1HHHHHHHHHHHHHHHHHHHHHH � ∗ 1,000,000

(%Capture ∗ CO2 Emissions Factor in lb/MMBtu of fuel input)

Where:

CO2 Emissions Factor = 204 lb/MMBtu for bituminous coal

The capture energy penalties for the SC PC capture cases are nearly constant with a value of 

approximately 0.14 kWh/lb CO2. This is due to the use of the bypass around the CO2 capture 

system. All cases represent the use of a 90 percent efficient CO2 capture system with flue gas 

feed streams proportional to the desired overall CO2 capture rate.

The capture energy penalties for the three IGCC capture cases in this study are shown in 

Exhibit 3 and illustrate that the penalty increases significantly with increasing capture rates. The 

increasing capture penalty with higher rates of capture is due to the addition and intensification 

of unit operations at each level. The 22 percent capture case does not have WGS. The 37

percent capture case adds some WGS and, therefore, has a larger energy penalty. 90 percent

capture requires a larger amount of WGS and a higher capture rate in the Selexol unit and,

therefore, has the highest capture energy penalty.

Exhibit 3-7 Capture energy penalty (kWh/lb CO2) for IGCC plant at various levels of capture

Source: NETL/DOE
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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4 Conclusion

SC PC plants that meet a range of design CO2 emission levels were developed by modifying the 

SC PC plant with CCS (case B12B) through the introduction of flue gas bypass of the CO2

capture system. IGCC plants that meet a range of design CO2 emission levels were developed by 

modifying the IGCC plant with CCS (case B5B) through the introduction of syngas bypass of the 

WGS reactor to reduce the amount of CO2 in the stream to the capture system. For both the SC 

PC and IGCC plants, lower levels of CO2 capture result in a lower COE, primarily due to the 

lower capital and operating costs for the reduced sizes of the capture systems and the reduced 

parasitic load of the CO2 capture equipment. The cost of capture, equivalent to the minimum 

plant gate CO2 sales price (revenue) required to incentivize CO2 capture relative to a non-capture 

SC PC, is higher at lower capture rates primarily due to the associated economies of scale. 

Should such CO2 revenues be available, then the higher capture rate designs are a more cost 

effective method of CO2 abatement; however, the lower capture rate designs represent lower 

incremental costs than the plant with 90 percent capture. Deployment of lower capture rate 

plants enables demonstration, progressive scaling, and optimization of the CO2 capture system 

with lower absolute costs while facilitating the smooth transition, from both economic and 

process perspectives, to subsequent plants with higher capture rates. 
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

15

5 References

1. National Energy Technology Laboratory. Cost and Performance Baseline for Fossil Energy 

Plants; Cost and Performance Baseline for Fossil Energy Plants; Volume 1a: Bituminous Coal 

(PC) and Natural Gas to Electricity, Revision 3. Pittsburgh, Pa : U.S. Department of Energy, 

2015.

2. National Energy Technology Laboratory. Cost and Performance Baseline for Fossil Energy 

Plants; Volume 1b: Bituminous Coal (IGCC to Electricity, Revision 2 - Year Dollar Update. 

Pittsburgh, Pa : Department of Energy, In Press.

3. AACE International. Conducting Technical and Economic Evaluations – As Applied for the 

Process and Utility Industries; TCM Framework: 3.2 – Asset Planning, 3.3 Investment Decision 

Making. s.l. : AACE International, 2003. Recommended Practice 16R-90.

4. AACE International. Cost Estimate Classification System – As Applied in Engineering, 

Procurement, and Construction for the Process Industries; TCM Framework 7.3 – Cost 

Estimating and Budgeting. s.l. : AACE International, 2005. Recommended Practice No. 18R-97.

5. National Energy Technology Laboratory. Quality Guidelines for Energy System Studies: 

Cost Estimation Methodology for NETL Assessments of Power Plant Performance. Pittsburgh, 

Pa : U.S. Department of Energy, April 2011. DOE/NETL-2011/145.

6. National Energy Technology Laboratory. Quality Guidelines for Energy System Studies: 

Capital Cost Scaling Methodology. Pittsburgh, Pa : U.S. Department of Energy, January 2013. 

DOE/NETL-341/013113.

7. Energy Information Administration. Assumptions to AEO2014: Coal Market Module. 

[Online] 2014. [Cited: June 22, 2015.] 

http://www.eia.gov/forecasts/aeo/assumptions/pdf/coal.pdf.
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Appendix

Key Performance and Cost Summary Tables

Exhibit A-1 PC cases performance summary

Case 

B12A Partial Capture Cases Case B12B

CO2 Capture Rate 0% 16% 22% 29% 35% 39% 42% 48% 60% 72% 90%

Capacity Factor 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%

Gross Power Output (MWe) 580 589 592 597 600 603 605 609 618 626 642

Auxiliary Power Requirement (MWe) 30 38 42 46 50 53 55 59 68 77 91

Net Power Output (MWe) 550 550 550 550 550 550 550 550 550 550 550

Coal Flow rate (lb/hr) 395,053 410,912 417,178 423,717 430,079 433,533 436,873 443,675 457,667 471,919 495,578

HHV Thermal Input (kWt) 1,350,672 1,404,894 1,426,316 1,448,676 1,470,427 1,482,236 1,493,655 1,516,909 1,564,750 1,613,476 1,694,366

Net Plant HHV Efficiency (%) 40.7% 39.2% 38.6% 38.0% 37.4% 37.1% 36.8% 36.3% 35.1% 34.1% 32.5%

Net Plant HHV Heat Rate (Btu/kWh) 8,379 8,710 8,848 8,986 9,126 9,197 9,269 9,413 9,708 10,012 10,508

Raw Water Withdrawal, gpm 5,105 5,533 5,710 5,891 6,072 6,166 6,259 6,448 6,835 7,231 7,882

Process Water Discharge, gpm 1,059 1,174 1,222 1,271 1,321 1,346 1,372 1,423 1,528 1,636 1,813

Raw Water Consumption, gpm 4,045 4,359 4,488 4,620 4,751 4,820 4,888 5,025 5,307 5,595 6,069

CO2 Emissions (lb/MMBtu) 204 172 158 145 132 125 119 106 81 57 20

CO2 Emissions (lb/MWhgross) 1,618 1,400 1,300 1,200 1,100 1,050 1,000 900 700 500 183

CO2 Emissions (lb/MWhnet) 1,705 1,498 1,400 1,302 1,201 1,151 1,100 997 786 570 214

SO2 Emissions (lb/MMBtu) 0.085 0.070 0.064 0.058 0.051 0.048 0.045 0.040 0.028 0.017 0.000

SO2 Emissions (lb/MWhgross) 0.673 0.570 0.523 0.477 0.430 0.406 0.383 0.336 0.242 0.148 0.000

NOx Emissions (lb/MMBtu) 0.088 0.086 0.085 0.084 0.084 0.083 0.083 0.082 0.081 0.080 0.078

NOx Emissions (lb/MWhgross) 0.700 0.700 0.700 0.700 0.700 0.700 0.700 0.700 0.700 0.700 0.700

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

PM Emissions (lb/MWhgross) 0.090 0.090 0.090 0.090 0.090 0.090 0.090 0.090 0.090 0.090 0.090

Hg Emissions (lb/TBtu) 0.377 0.368 0.365 0.362 0.359 0.357 0.356 0.353 0.347 0.341 0.333

Hg Emissions (lb/MWhgross) 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Exhibit A-2 IGCC cases performance summary

Case B5A Partial Capture Case B5B

CO2 Capture Rate 0% 22% 37% 90%

Capacity Factor 80% 80% 80% 80%

Gross Power Output (MWe) 748 752 747 734

Auxiliary Power Requirement (MWe) 126 142 152 191

Net Power Output (MWe) 622 610 595 543

Coal Flow rate (lb/hr) 466,898 463,138 466,131 487,005

HHV Thermal Input (kWth) 1,596,309 1,583,454 1,593,685 1,665,056

Net Plant HHV Efficiency (%) 39.0% 38.5% 37.4% 32.6%

Net Plant HHV Heat Rate (Btu/kWh) 8,758 8,860 9,133 10,459

Raw Water Withdrawal, gpm 4,755 4,685 4,905 5,834

Process Water Discharge, gpm 984 968 994 1,080

Raw Water Consumption, gpm 3,771 3,717 3,911 4,754

CO2 Emissions (lb/MMBtu) 197 153 124 20

CO2 Emissions (lb/MWhgross) 1,434 1,100 900 152

CO2 Emissions (lb/MWhnet) 1,724 1,356 1,129 206

SO2 Emissions (lb/MMBtu) 0.001 0.002 0.002 0.002

SO2 Emissions (lb/MWhgross) 0.009 0.016 0.016 0.017

NOx Emissions (lb/MMBtu) 0.059 0.055 0.054 0.049

NOx Emissions (lb/MWhgross) 0.430 0.396 0.394 0.376

PM Emissions (lb/MMBtu) 0.007 0.007 0.007 0.007

PM Emissions (lb/MWhgross) 0.052 0.051 0.052 0.055

Hg Emissions (lb/TBtu) 0.412 0.417 0.412 0.388

Hg Emissions (lb/MWhgross) 3.00E-06 3.00E-06 3.00E-06 3.00E-06
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

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Exhibit A-3 PC cases cost summary

Case 

B12A Partial Capture Cases Case B12B

CO2 Capture Rate 0% 16% 22% 29% 35% 39% 42% 48% 60% 72% 90%

Total Plant Cost (2011$/kW) 2,026 2,467 2,586 2,695 2,798 2,847 2,896 2,990 3,204 3,384 3,524

Bare Erected Cost 1,646 1,955 2,040 2,117 2,190 2,225 2,260 2,327 2,481 2,610 2,716

Home Office Expenses 165 193 200 207 214 217 220 226 241 252 263

Project Contingency 216 279 297 312 327 334 341 355 386 411 430

Process Contingency 0 39 49 58 67 71 74 82 96 110 115

Total Overnight Cost (2011$MM) 1,379 1,674 1,753 1,826 1,894 1,928 1,960 2,023 2,167 2,287 2,384

Total Overnight Cost (2011$/kW) 2,507 3,042 3,187 3,320 3,445 3,505 3,565 3,680 3,940 4,160 4,333

Owner's Costs 480 575 601 625 647 658 669 689 736 776 809

Total As-Spent Capital (2011$/kW) 2,842 3,468 3,633 3,784 3,928 3,996 4,064 4,195 4,492 4,742 4,940

COE ($/MWh) (excluding T&S) 82.3 97.8 101.4 104.8 108.1 109.7 111.3 114.4 121.2 127.2 133.2

Capital Costs 39.0 50.7 53.1 55.3 57.4 58.4 59.4 61.3 65.6 69.3 72.2

Fixed Costs 9.6 11.5 11.9 12.3 12.7 12.9 13.1 13.4 14.2 14.9 15.4

Variable Costs 9.1 10.1 10.5 10.9 11.3 11.4 11.6 12.0 12.8 13.6 14.7

Fuel Costs 24.6 25.6 26.0 26.4 26.8 27.0 27.2 27.7 28.5 29.4 30.9

COE ($/MWh) (including T&S) 82.3 99.1 103.7 107.5 111.4 113.3 115.2 119.0 127.1 134.5 142.8

CO2 T&S Costs 0.0 1.4 2.0 2.6 3.3 3.6 3.9 4.6 5.9 7.3 9.6

COE Range Reflecting Capital Cost 

Accuracy*

COE ($/MWh) (excluding T&S) 

-15% TPC 75.8 90.7 94.6 98.3 101.9 103.6 105.4 108.8 116.2 123.0 130.8

COE ($/MWh) (excluding T&S) 

+ 30% TPC 95.3 115.9 121.0 125.8 130.5 132.7 134.9 139.3 148.9 157.6 166.8

CO2 Captured Cost (excluding T&S), 

$/tonne N/A 123.9 105.3 94.2 86.7 83.7 81.2 76.9 72 67.4 58.2

CO2 Avoided Cost (including T&S), 

$/tonne N/A 178.7 152.6 137.4 127.2 123.2 119.7 114 107.5 101.4 89.4

*The accuracy range is applied at the Total Plant Cost (TPC) level, which has a consequent impact on the fixed and variable O&M costs. [6]
Cost and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants

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Exhibit A-4 IGCC cases cost summary

Case B5A Partial Capture Case B5B

CO2 Capture Rate 0% 22% 37% 90%

Total Plant Cost (2011$/kW) 2,449 2,707 2,839 3,387

Bare Erected Cost 1,870 2,029 2,125 2,525

Home Office Expenses 187 203 213 253

Project Contingency 330 366 386 467

Process Contingency 61 109 115 143

Total Overnight Cost (2011$MM) 1,888 2,036 2,086 2,279

Total Overnight Cost (2011$/kW) 3,036 3,339 3,503 4,195

Owner's Costs 587 632 664 807

Total As-Spent Capital (2011$/kW) 3,461 3,807 3,994 4,782

COE ($/MWh) (excluding T&S) 102.6 109.3 114.2 135.4

Capital Costs 53.7 59.1 62.0 74.2

Fixed Costs 13.7 14.8 15.5 18.2

Variable Costs 9.4 9.4 9.9 12.2

Fuel Costs 25.7 26.0 26.8 30.7

COE ($/MWh) (including T&S) 102.6 111.2 117.5 144.7

CO2 T&S Costs 0.0 1.9 3.3 9.2

COE Range Reflecting Capital Cost Accuracy*

COE ($/MWh) (excluding T&S) -15% TPC 93.7 101.4 107.3 132.4

COE ($/MWh) (excluding T&S) + 30% TPC 120.3 130.8 138.1 169.2

CO2 Captured Cost (excluding T&S), $/tonne N/A 154.7 105.7 63.2

CO2 Avoided Cost (including T&S), $/tonne N/A 182.4 134.8 91.7

*The accuracy range is applied at the Total Plant Cost (TPC) level, which has a consequent impact on the fixed and variable O&M costs. [6]
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