Coal-Fired Power Plants in the United States: 

Examination of the Costs of Retrofitting with 

CO2 Capture Technology, Revision 3 

January 4, 2011 

DOE/NETL- 402/102309 
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. 
COAL-FIRED POWER PLANTS IN THE UNITED 

STATES: EXAMINATION OF THE COSTS OF 

RETROFITTING WITH CO2 CAPTURE TECHNOLOGY 

DOE/NETL-402/102309 

January 4, 2011 

NETL Contact: 

Christopher Nichols 

Office of Strategic Energy Analysis and Planning 

National Energy Technology Laboratory 

www.netl.doe.gov 

 
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Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Table of Contents 

TABLE OF CONTENTS .............................................................................................................. i

LIST OF TABLES ........................................................................................................................ ii

ORIGINAL DOCUMENT .......................................................................................................... iv

ACKNOWLEDGMENTS .............................................................................................................v

LIST OF ACRONYMS AND ABBREVIATIONS ................................................................... vi

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

1. METHODOLOGY ................................................................................................................4

1.1 DATA SOURCES .................................................................................................................4

1.1.1 NETL Studies ...............................................................................................................4

1.2.2    Generating Unit Characteristics ..................................................................................5

1.1.3 Arial Imagery of Power Plant Sites .............................................................................5

1.2 SCREENING PROCESS ......................................................................................................13

1.3 UNIT-LEVEL COST ANALYSIS .........................................................................................14

1.3.1 SO2 Removal ..............................................................................................................17

1.3.2 NOx Removal .............................................................................................................17

1.3.3 Recirculating Cooling ................................................................................................18

1.3.4 Discounted Incremental Plant Units ..........................................................................19

1.3.5 Construction Difficulty Factors .................................................................................19

1.3.6 Total Investment CAPEX ...........................................................................................26

1.3.7 OPEX .........................................................................................................................27

1.3.8 Parasitic Load ............................................................................................................29

1.3.9 Levelized Cost of Electricity ......................................................................................30

1.3.10  Inclusion of Make-up Power ......................................................................................31

2. RESULTS .............................................................................................................................33

2.1 CAPEX RESULTS ...........................................................................................................33

2.2 BASE CASE (NO MAKE-UP POWER) ................................................................................34

2.3 MAKE-UP POWER CASE ..................................................................................................36

2.4 COMPARISON WITH CONESVILLE STUDY RESULTS .........................................................38

3. CONTINUING WORK .......................................................................................................39

APPENDIX A. EV SUITE DATA ELEMENTS ......................................................................40
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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List of Tables

Table ES-1. CO2 Capture Retrofit for U.S. Coal-fired Power Plants, Summary Capture Cost and 

LCOE results (based on 85% Capacity Factor) ...................................................................... 2

Table 2-1. Results from the Conesville Study and CCM............................................................. 38

Table 2-2. Key Input Parameters from the Conesville Study and CCM ..................................... 38

List of Figures

Figure ES-1. Cumulative Cost Curve, Retrofitting U.S. Coal Power Plants for CO2 Capture ....... 2

Figure 1-1. Example MS Terraserver Imagery ............................................................................... 6

Figure 1-2. Example Google Maps Imagery (color) on a Terraserver Image Base ........................ 6

Figure 1-3. Water Availability ........................................................................................................ 7

Figure 1-4. NatCarb Datasets .......................................................................................................... 8

Figure 1-5. USGS Oil and Gas Production Dataset ........................................................................ 9

Figure 1-6. NatCarb Sequestration Quality .................................................................................... 9

Figure 1-7. Forecast Regional Price and GHG Emissions for Power in 2020 under a GHG 

Emissions Reduction Scenario Emulating the Waxman-Markey Bill .................................. 11

Figure 1-8. Forecast Generation by Region in 2020 under a GHG Emissions Reduction Scenario 

Emulating the Waxman-Markey Bill and Carbon Loading by Generation Type. ................ 12

Figure 1-9. Results of the Screening Process ................................................................................ 14

Figure 1-10. Aerial imagery of the Coneseville plant ................................................................... 15

Figure 1-11. Let-Down Turbine Cost and Size Scaling ................................................................ 16

Figure 1-12. CO2 Separation and Compression Cost and Size Scaling ........................................ 16

Figure 1-13. CO2 Scrubber Cost and Size Scaling ....................................................................... 17

Figure 1-14. Current and Additional Recirculating Cooling Required to Retrofit All Units with 

90% CO2 Capture and Compression at the Conesville Plant ................................................ 19

Figure 1-15. Complete Plant Retrofit............................................................................................ 20

Figure 1-16. Example Showing 10 Percent Close-In Construction Difficulty and 10 Percent 

Landscape Construction Difficulty ....................................................................................... 22

Figure 1-17. Example Showing 30 Percent Close-In Construction Difficulty, 10 Percent 

Landscape Construction Difficulty ....................................................................................... 22

Figure 1-18. Example Showing 0 Percent Close-In Construction Difficulty, 0 Percent Landscape 

Construction Difficulty ......................................................................................................... 24

Figure 1-19. Example Showing 15 Percent Close-In Construction Difficulty, 0 Percent 

Landscape Construction Difficulty ....................................................................................... 24

Figure 1-20. Additional Land Requirements ................................................................................ 25

Figure 1-21. Assigned correction factors for space limitations .................................................... 25

Figure 1-22. Fixed OPEX Cost Function ...................................................................................... 28

Figure 1-23. Variable OPEX Cost Function ................................................................................. 28

Figure 1-24. Feedstock OPEX Cost Function............................................................................... 28

Figure 1-25. Parasitic Load Scaling for Carbon Capture Retrofit Components ........................... 29

Figure 1-26. LCOE Equation and Parameters from Conesville Study ......................................... 30

Figure 1-27. Captured and Mitigated Carbon Costs ..................................................................... 31
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 2-1. Nameplate Capacity as a Function of CO2 Capture CAPEX by Unit ........................ 33

Figure 2-2. Base Case, Cumulative U.S. Coal Generating Capacity versus Incremental LCOE for 

CO2 Capture Retrofit ............................................................................................................. 35

Figure 2-3. Base Case, Cumulative U.S. Coal Generating Capacity versus Retrofit CO2 Capture 

Cost ....................................................................................................................................... 35

Figure 2-4. Make-up Power Case, Cumulative U.S. Coal Generating Capacity versus Incremental 

LCOE for CO2 Capture Retrofit ........................................................................................... 37

Figure 2-5. Make-up Power Case, Cumulative U.S. Coal Generating Capacity versus Retrofit 

CO2 Capture Cost .................................................................................................................. 37

 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Original Document (January 2010) Prepared by: 

Research and Development Solutions, LLC (RDS) 

Jeffrey Eppink and Michael Marquis 

Enegis, LLC 

Revised Version (January 2011) Prepared by: 

Phil DiPietro and Chris Nichols, NETL and Michael Marquis, Enegis, LLC 

DOE Contract #DE-AC26-04NT41817 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

v 

Acknowledgments 

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

States Department of Energy’s National Energy Technology Laboratory. This work was 

completed under DOE NETL Contract Number DE-AC26-04NT41817, and performed under 

RDS Subtask 41817-402.01.01 

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

NETL staff, particularly: 

Philip DiPietro, NETL Technical Monitor 

Christopher Nichols, Office of Strategic Energy Analysis and Planning 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

vi 

LIST OF ACRONYMS AND ABBREVIATIONS

AEP American Electric Power 

Btu British Thermal Unit = 1055 Joules 

CAPEX Capital Expense 

CCM Carbon Capture Model 

CO2 Carbon Dioxide 

DOE Department of Energy 

EIA Energy Information Administration 

EV Energy Velocity 

EMM Electricity Market Modules 

FGD Flue Gas Desulfurization 

GIS Geographic Information Systems 

GW Gigawatt 

kW Kilowatt 

kWh Kilowatt hour 

LCOE Levelized Cost of Electricity 

MS Microsoft 

MW Megawatt 

MWh Megawatt hour 

NEMS National Energy Modeling System 

NETL National Energy Technology Laboratory 

NOx Nitrogen Oxide 

OPEX Operating Expense 

OSAP Office of Systems, Analyses and Planning 

Ppm Parts Per Million 

SO2 Sulfur Dioxide 

TDE Top Decile Average Efficiency 

Ton short ton = 2000 pounds 

Tonne metric ton = 1000 kilograms 

USGS United States Geological Surv
1 

EXECUTIVE SUMMARY

Retrofitting existing coal-fired power plants to capture CO2 is an important GHG mitigation 

option for the United States. Coal power plants are large point sources and account for roughly 

37% of total U.S. CO2 emissions. Also, retrofitting utilizes the base power plant and related 

infrastructure and so the cost and level of disruption could be less than other greenhouse gas 

mitigation options. 

NETL studied the 738 coal-fired generating units currently operating in the United States and 

estimated how much the capital cost and parasitic load for CO2 retrofit would vary from unit to 

unit. Site-specific characteristics such as base plant efficiency, whether or not the unit has a 

sulfur scrubber, the efficiency of the sulfur scrubber, how much water is available for the unit to 

use, and how much space is available for the CO2 capture and compression equipment were 

factored in to an estimate of CO2 capture cost at each generating unit. These 738 units are located 

at 282 power plant sites (some sites/plants have more than one unit). Plant-level characteristics 

were applied to all the units at a power plant site. 

All estimates were relative to the detailed study that NETL performed on AEP’s Conesville 

generating station. Year 2007 amine capture technology is assumed; 90% of CO2 in the flue gas 

is captured and the solvent requires 3.6 GJ regeneration energy per metric ton (mt) of CO2

captured. 

Figure ES-1 summarizes the results. The 738 generating units are ranked from least to highest 

cost of CO2 capture and unit-level cost of CO2 capture is graphed against cumulative capacity. 

The cost of CO2 capture in $/tonne (or $/mt) avoided is calculated from the cost of electricity 

(COE) and the CO2 emissions of the generating unit with and without CO2 capture as shown 

below. 

Cost of CO2 capture = [COEretrofit – COEbase] / [CO2/kWhretrofit, produced – CO2/kWhretrofit, emitted] {1} 

Figure ES-1 is interpreted as follows. Reading off the 75% capacity factor (CF) line, the 

Conesville generating plant has a cost of CO2 capture of $42/mt CO2 which places it at the 30% 

percentile. That is, 30% of the coal fired generating capacity has a CO2 captured cost less than 

$42/mt CO2. The other 70% of coal-fired capacity has a higher cost. Figure ES-1 shows an 

inflection in the curve where the cost of CO2 retrofits begin to increase more rapidly. This 

inflection occurs at a capture cost of 50 $/mt CO2 (or equivalently 70% of cumulative capacity). 

Figure ES-1 also shows that a 10 percentage point change in the assumed capacity factor of the 

generating units changes the cost of CO2 captured by roughly 5 $/mt CO2. 

Avoided cost, shown in equation {2} below, is an alternative evaluation metric. 

Cost of CO2 capture = [COEretrofit – COEbase] / [CO2/kWhbase, emitted – CO2/kWhretrofit, emitted] {2} 

The avoided cost calculation, unlike the capture cost above, includes charges for make-up power 

due to net power losses associated with CO2 capture and compression. A coal-fired generating 

unit with CO2 capture using amine-based scrubbing will lose roughly 30% of its generating 

capacity. The cost of buying spot power to “make up” the lost capacity and also the CO2

emissions associated with the purchased power are included in the COE and CO2/kWh for the 

retrofit unit. Table ES-1 below shows the results for cost of CO2 capture and avoided cost for the 

10th, 50th, and 90th percentiles. The avoided cost is $40 to $50 per mt CO2 higher, based on a 

median cost for make-up power of 7.6 cents/kWh. 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure ES-1. Cumulative Cost Curve, Retrofitting U.S. Coal Power Plants for CO2 Capture 

Table ES-1. CO2 Capture Retrofit for U.S. Coal-fired Power Plants, Summary Capture 

Cost and LCOE results (based on 85% Capacity Factor) 

Cost of CO2 capture 

($/mt CO2) 

Cost of CO2 avoided 

($/mt CO2)

1

 

10th percentile 34 73 

50th percentile 41 90 

90th percentile 57 107 

Future work includes (1) developing cost curves for cases with advanced CO2 capture and 

compression technology, (2) incorporating the possibility that the retrofits for CO2 capture 

include refurbishment to improve the heat rate of the base generating unit, and (3) including the 

 

1 Includes cost and GHG emissions for make-up power which varies by the region. Median cost value is 7.6 

cents/kWh (min/max 1.1/ 9.9). 

(282 Power Plants) 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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cost for CO2 transport and injection underground, taking into account the variation in pipeline 

distances and the injectivity of proximate sequestration repositories. 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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1. METHODOLOGY

The effort compiles relevant data and maps from a number of sources into a spreadsheet 

based model, the Carbon Capture Model, (CCM). The CCM links the databases and 

calculates capital expense (CAPEX), operating expense (OPEX), and parasitic load 

associated with retro-fitted carbon capture technology applied to the population of coalfired power plants in the United States. 

The methodology is described in the following sections: 

 1.1 Data Sources 

 1.2 Screening Process 

 1.3 Unit-level Cost Analysis 

All costs in this report are based on CO2 at the plant gate. The cost of compression and 

purification to pipeline conditions are included. Not included are the cost of pipeline 

construction, CO2 transport, and CO2 injection and storage in underground geologic 

formations. 

1.1 DATA SOURCES 

This section identifies the information sources used to populate the model. 

1.1.1 NETL Studies

Results from the following NETL studies were used. These reports can be found at 

http://www.netl.doe.gov/energy-analyses/refshelf/Default.aspx . The primary reference 

used is the Conesville study (listed first). The report provides the base value for the cost 

and parasitic load associated with implementing retrofit CO2capture at a typical coal-fired 

generating unit. 

 Carbon Dioxide Capture from Existing Coal-Fired Power Plants (Conesville 

Study) DOE/NETL-401/110907 November 2007 

 Cost and Performance Baseline for Fossil Energy Plants, (“Baseline Report”), 

DOE/NETL-2007/1281, Volume 1: Bituminous Coal and Natural Gas to 

Electricity, Final Report, Revision 1, August 2007 

 Pulverized Coal Oxycombustion Power Plants (Oxycombustion Report), NETL, 

Final Results, August 2007 

 Reduced Water Impacts Resulting from Deployment of Advanced Coal Power 

Technologies, (Water Impacts Report) NETL, Chris Nichols and Phil DiPietro, 

December 16, 2007 

 Water Requirements for Existing and Emerging Thermoelectric Plant 

Technologies, (Water Requirements Report) NETL Kristin Gerdes and 

Christopher Nichols, August 2008 (April 2009 Revision) 

 Roadmap for Bioenergy and Biobased Products in the US (Bioenergy Roadmap 

study), Biomass Research and Development Technical Advisory Committee, 

2009 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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1.2.2 Generating Unit Characteristics

The primary source of data on physical plant parameters such as unit nameplate capacity, 

heat-rate, and emissions was obtained from Ventyx Corporation’s Energy Velocity (EV) 

Suite, a compilation of energy industry and market databases. Appendix 1 provides a 

detailed description of the EV data elements that were used in the database. The database 

contains ten years of historical data. To provide a more valid representation of plant 

operations, the model uses ten-year average values for, heat rate, operations, and 

emissions data. EV data was joined to NETL’s Coal-fired Power Plant database 

(http://www.netl.doe.gov/energy-analyses/refshelf/PubDetails.aspx?Action=View&PubId=310) to provide steam 

pressure for the analysis. 

1.1.3 Arial Imagery of Power Plant Sites

The Microsoft TerraServer-USA Web site was used both as a primary source of power 

plant imagery and as a base map on which to georegister more recent or higher resolution 

imagery if available through Google Maps. The MS Terraserver imagery is available as 

an open-source Windows Mapping Service and as a seamless imagery layer within ESRI 

ArcGIS. Maps and images are supplied to Terraserver through Microsoft’s partnership 

with the U.S. Geological Survey. 

Figure 1-1 shows an example of available MS Terraserver imagery of Plant 1726 AES 

Somerset in Barker, New York. Of the 324 plants analyzed for this effort, 250 had 

satisfactory (best available) imagery obtained through MS Terraserver. 

Google Maps often provided the most recent, highest resolution imagery for sites in the 

project. Figure 2-1 presents an example of available Google Maps imagery from Plant 

2351, Gulf Power Co Christ Plant in Pensacola, Florida. Google Maps is not available as 

an open-source Windows Mapping Service, requiring screen capture and georegistration, 

processes which were performed for this project. Note the color, screen-captured Google 

Maps imagery georeferenced to the underlying, black and white Terraserver imagery. Of 

the plants analyzed for this project, 40 had the best available imagery through Google 

Maps. 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 1-1. Example MS Terraserver Imagery 

Figure 1-2. Example Google Maps Imagery (color) on a Terraserver Image Base 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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1.1.4 Water Availability 

Due to increased cooling loads associated with amine-based CO2 capture and 

compression, up to 100 percent increase, additional cooling water sources will be 

required upon retrofitting an existing unit. Depending on the current power plant 

cooling technology and location within the U.S., there is a potential for significant water 

constraints to meet additional capture and compression cooling needs. 

Data on the renewable water supply was provided by the U.S. Geological Survey 

(USGS), 1984, National Water Summary 1983—Hydrologic Events and Issues: U.S. 

Geological Survey Water-Supply Paper 2250. Renewable water supply is defined as the 

sum of precipitation and imports of water, minus the water not available for use through 

natural evaporation and exports. Renewable water supply is a simplified upper limit to 

the amount of water consumption that could occur in a region on a sustained basis. 

Figure 1-3 shows the USGS water availability data. 

The Bioenergy Roadmap study was used as a data source on the status of fresh water 

aquifers to further define those geographic areas with stressed or overpumped aquifers. 

Figure 1-3 shows these overpumped aquifers in relation to the USGS water availability 

data. These data were used to identify those plants in areas where further withdrawal 

from local aquifers is problematic. 

Figure 1-3. Water Availability 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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1.1.5 Potential CO2 Storage Repositories

GIS data on saline aquifers acceptable for carbon sequestration and the network of 

existing CO2 pipelines was obtained from NETL’s NatCarb website www.natcarb.org. 

Figure 1-4 shows these data. 

GIS data on existing oil and gas production was obtained from the USGS. A 

comprehensive, nation-wide GIS polygon set of oil and gas fields are not readily 

available. The USGS has published an oil and gas production map of the United States. 

This dataset consists of over one million 1⁄4 mile cells attributed with the presence of oil 

production, gas production, oil and gas production, or dry field. Figure 1-5 shows the 

USGS oil and gas data. 

Data were available from NatCarb on volumes of CO2 able to be sequestered in oil and 

gas fields and saline aquifers. These data were compiled to calculate a total sequestration 

capacity density map. Figure 1-6 shows sequestration quality in units of millions of 

tonnes CO2/ km2

. It should be noted that not all areas identified in the NatCarb and 

USGS sequestration opportunity datasets are shown as having sequestration capacity, 

which leads to differences between the two data sets. This source was used to evaluate 

storage space availability only, and not the costs associated with storage and 

measurement, monitoring and verification. 

Figure 1-4. NatCarb Datasets 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 1-5. USGS Oil and Gas Production Dataset 

Figure 1-6. NatCarb Sequestration Quality 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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1.1.6 Price Projections for Commodity Power 

Because the generation profile in a carbon-constrained world would significantly differ 

from the current power generation makeup, the CCM uses projections created by NETL 

to represent a likely generation profile following passage of the proposed WaxmanMarkey climate change legislation. 

“The American Clean Energy and Security Act of 2009”, sponsored by Congressmen 

Waxman of California and Markey of Massachusetts (Waxman-Markey) passed in the 

U.S. House in June, 2009. The Waxman-Markey bill addressed many issues related to 

climate change, but required a 17 percent reduction in greenhouse gas emissions, from 

2005 levels, by 2020, and an 83 percent reduction by 2050. The bill also required utilities 

to obtain 15 percent of their electricity from renewable sources, by 2020; and to 

demonstrate annual electricity savings from efficiency measures. 

Figure 1-7 shows the price for purchased power and the associated GHG emissions. 

There is a wide variation geographically so regional data from the NEMS Electricity 

Market Modules (EMM) were applied using GIS polygons. NETL ran NEMS using the 

EIA’s Waxman-Markey scenario to generate the average emissions rates and electricity 

prices by EMM region for the year 2020. Figure 1-8 shows assumed carbon loading that 

were inputs into the NEMS model and also regional generation results. 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 1-7. Forecast Regional Price and GHG Emissions for Power in 2020 under a 

GHG Emissions Reduction Scenario Emulating the Waxman-Markey Bill 

EMM Region Emissions rate 

(tonnes/MWh) 

Electricity price 

($/kWh) 

1 0.797 0.076 

2 0.605 0.079 

3 0.451 0.087 

4 0.493 0.067 

5 0.656 0.056 

6 0.301 0.099 

7 0.243 0.081 

8 0.438 0.011 

9 0.544 0.067 

10 0.826 0.076 

11 0.296 0.043 

12 0.712 0.082 

13 0.278 0.073 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 1-8. Forecast Generation by Region in 2020 under a GHG Emissions 

Reduction Scenario Emulating the Waxman-Markey Bill and Carbon Loading by 

Generation Type. 

0

100

200

300

400

500

600

700

800

900

1 2 3 4 5 6 7 8 9 10 11 12 13

Total Generation (10^9 KwH)

EMM

NETL 2020 Projected EMM Generation  By Type

Renewables

Pumped Storage

Nuclear

Petroleum

Natural Gas

Coal

Associated

Carbon Loading

(g/KwH)

  Coal 909                        

  Petroleum 821                        

  Natural Gas 465                        

  Nuclear 6                              

  Pumped Storage                            4

  Renewables                          ‐

Type
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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1.2 SCREENING PROCESS 

Prior to performing the cost analysis, a portion of the population of coal-fired power 

plants was screened out as being not amenable to CO2 capture retrofit. Plants excluded 

were those that: 

 are not currently operating 

 have a capacity less than 100 MW 

 have a 2008 reported heat rate greater than 12,500 Btu/kWh 

 do not have a defined CO2 repository within 25 miles. 

Figure 1-9 shows the screening criteria applied to the population of power plants. The 

left panel shows number of plants and the right panel shows generation capacity. Fifty 

percent of the operating power plants were excluded from the analysis, primarily 

consisting of smaller plants representing only 15% of the total generating capacity. 

The screening process was conducted at the plant level. A “power plant” is a parcel of 

land where coal is turned into power, and a single power plant may contain more than 

one generating unit. The capacity screen is based on the total capacity of all the 

generating units at a site. The idea being that one CO2 capture facility could serve all the 

units and thus obtain the needed economies of scale. The heat rate metric used as a 

screen is the average heat rate of all the units operating at a site. 

The current analysis considers neither the injectivity nor CO2 storage capacity, only 

the distance from a potential long term storage source to screen plants. A parallel 

task being conducted by NETL aims to develop information on the “quality” of 

sequestration targets. That data will be incorporated into subsequent versions of this 

analysis and will likely serve to exclude more power plants as not being near enough to 

large and permeable sequestration targets. 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 1-9. Results of the Screening Process 

1.3 UNIT-LEVEL COST ANALYSIS 

This section describes the analysis methodology used to make the unit-level adjustments to the 

cost and energy penalty associated with CO2 capture retrofit. The following is a list of 

adjustments. Each is described below. 

 Scale the let-down turbine and the CO2 separation and compression equipment relative to 

Conesville 

 Add sulfur scrubbing and polishing to 10 ppm 

 Reduce NOx to 0.07 lbs/mmBtu coal 

 Upgrade to re-circulating cooling or, in arid areas, upgrade to dry cooling 

 Add cost adjustment for units where the unit operations (boiler, steam turbine, etc.) are 

tightly spaced relative to Conesville (0-40% adjustment applied to CO2 scrubbers, CO2

absorbers, sulfur scrubbers, and sulfur polishers) 

 Add cost adjustment for generating units where the CO2 retrofit will require moving coal 

piles, parking lots, or other structures (0-40% adjustment applied to CO2 compression and 

cooling towers). This includes the cost of purchasing extra land where possible.

 Apply economies of scale discount for multiple units at the same plant (4% applied to all 

costs) 

The adjustments are relative to the design set forth in the Conesville Study. Figure 1-10 is an 

aerial view of the Conesville generating station with the CO2 capture and compression equipment 

drawn in consistent with the plot plan in the CO2 retrofit design document. Notice the large 

footprint for the CO2 compression facility and how far away it is from the CO2 absorber. 

0

200

400

600

800

1000

1200

0

100

200

300

400

500

600

Total Operating Above 100

MW

Below 12,500

Btu/kWh

W/in 25 miles

ofseq. target

Capacity, GW

Count of Plants

Count of Plants,

#

Capacity, GW
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 1-10. Aerial imagery of the Coneseville plant 

Scale Adjustments 

The Conesville Study examined four cases with CO2 capture percentages of 90, 70, 50 

and 30 percent. The study’s cases were achieved by limiting the amount of flue gas 

diverted to the CO2 absorbers—which allowed an imputed calculation of power plant size 

if the equipment for each of the cases was operative at 90 percent capacity. For example, 

scrubbing 50 percent of the CO2 from a 435.5 MW Conesville Unit 5 is the equivalent of 

scrubbing 90 percent of the CO2 from a 242 MW unit. Best fit lines were developed from 

the Coneville data points, Figures 1-11 and 1-12, and applied to estimate the capital cost 

of CO2 retrofit at each unit based on its starting nameplate generating capacity. Figure 1-

13 presents an estimated cost for the CO2 scrubber. This cost was not presented in the 

Conesville Study, but rather bundled with the compressor cost. The capture and 

compression costs were separated to properly apply the adjustments for close-in and 

landscape space availability. 

Plant 1497, AES Conesville, Coneville OH
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 1-11. Let-Down Turbine Cost and Size Scaling 

Figure 1-12. CO2 Separation and Compression Cost and Size Scaling 

y = 0.0004x + 0.799

R2 = 0.9979

0%

20%

40%

60%

80%

100%

120%

- 200 400 600 800 1,000 

Cost relative to Conesville 90% case

Original Capacity of System, MW

Let down turbine

y = 0.0017x + 0.2433

R2 = 0.9767

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

- 200 400 600 800 1,000 

Cost relative to Conesville 90% case

Original Capacity of System, MW

CO2 Compression and Separation
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

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Figure 1-13. CO2 Scrubber Cost and Size Scaling 

1.3.1 SO2 Removal

In plants without primary FGD systems, new construction costs of $230 per kilowatt 

capacity for the primary FGD system designed to remove 98 percent SO2, and a value of 

$94.60/ton2 for the additional sulfur removed by sulfur polishing down to 10 ppm were 

used. An example is Conesville’s 841.5 MW Unit 3, currently without primary FGD. 

At a cost of $105.5/kW, the Conesville Unit 3 FGD would cost $88.5 million for 

installation of FGD. 

In plants with current primary FGD systems, the current SO2 removal percentage was 

estimated using emissions and coal data from the EV datasets. The marginal SO2

removal needed to achieve 98 percent was calculated and the marginal additional removal 

requirement was prorated at a cost of $216 per kilowatt capacity. The sulfur polishing 

cost of $94.60/ton was then applied to the additional sulfur reduction to 10 ppm. Again, 

the Conesville report was used as the basis for scaling the various SO2 removal processes 

to each plant as necessary. A cost of $17.5 million, based on calibration with Conesville 

Unit 5, was used as a minimum cost of sulfur polishing. 

1.3.2 NOx Removal

Consistent with the post-combustion CO2 capture cases contained in the 2008 NETL 

Oxycombustion Report, and to be compliant with environmental requirements, the CCM 

requires NOx emissions to be at or below 0.07 lbs NOx/ million Btu for purposes of CO2

capture. NOx emissions data for each unit was compared to this target rate to determine 

 

2

 Estimated from Baseline Report. 

$‐

$10

$20

$30

$40

$50

$60

‐ 5,000 10,000 15,000 20,000 25,000

$ millions

Tons CO2

y = 3E‐12x3 ‐ 2E‐07x2 + 0.0054x + 3.0266
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

18 

the additional NOx scrubbing requirement. Using the unit’s total Btu value and an 

installation cost of $300/tonne NOx, a value for NOx scrubbing cost was calculated. 

1.3.3 Recirculating Cooling

The analysis is based on an assumption that all plants will be converted to recirculating 

cooling as part of the retrofit process. The exception is power plants that are located in 

arid areas. In those cases, a dry cooling system will be installed as a part of the retrofit 

process. The 2007 NETL Conesville Study did not address the issue of additional 

cooling capacity required by the CO2 retrofit. Current amine-based CO2 wet-scrubbing 

technology requires cooling to maintain the appropriate reactor temperatures. Multi-stage 

CO2 compression also requires cooling. Based on the Water Requirements Report, it was 

determined that a retrofitted unit would require 30 percent more recirculating cooling 

capacity than an unretrofitted unit. The total area (in square meters) of recirculating, 

induced draft cooling towers currently installed at the unretrofitted Conesville Unit 5 was 

digitized from the GIS imagery. This area was then increased by 30% to represent the 

area (and inferred required capacity) of the retrofitted Conesville Unit 5. This area was 

then divided by the total btu/hour generated at Conesville Unit 5 to arrive at a factor of 

required square meters of recirculating cooling per btu per hour. This methodology 

provided more required cooling at units operating at higher heat rates. This required area 

of retrofitted cooling is compared to the area of currently installed cooling towers (if 

present) to determine the area of additional cooling required. 

Using this ratio, polygons representing the estimated additional cooling for the Conesville 

plant were created. Figure 1-14 shows the current and additional recirculating cooling 

needed to retrofit all units at Conesville. 

Using a unit’s nameplate capacity, heat rate, an estimation of the heat generated per hour 

by a unit was calculated to determine a needed cooling area/Btu/hr for retrofitted units. A 

plant’s current cooling area was digitized in the GIS and used to calculate additional 

cooling area needed. 

The CAPEX cost of the additional recirculating cooling at the Conesville plant was 

identified as $2.85 million.3

 This value was compared to the total area of additional 

cooling to calculate a cost per square meter of recirculating cooling. This rate was used 

to estimate recirculating cooling costs at other plants. 

Consideration was also given to the fact that some plants may require dry cooling due to 

local water availability. Based on the Water Requirements Report, a factor of 3.5 times 

the cost of recirculating cooling was applied to those plants identified as needing dry 

cooling. 

Cooling costs were modified using the USGS water availability data (see Figure 1-3). 

Watersheds were assigned a water availability factor of 1 (minimum) to 3 (maximum) 

 

3

 Estimated from the Baseline Study CAPEX costs. 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

19 

relative to the water availability for Ohio (where the Conesville plant is located). By this 

methodology, cooling in plants in the driest areas (but where water is still available for 

recirculating cooling) will cost three times that of the cooling system at the Conesville 

plant. This factor was implemented and applied to water recirculating facility costs to 

account for additional cost of securing water for a plant (such as drilling wells). 

It was determined that a plant would require dry cooling if it was located in one of the 

two most-arid USGS watersheds, or if it was located within one of the areas designated as 

having an overpumped reservoir west of the Mississippi River (see Figure 1-3). 

Figure 1-14. Current and Additional Recirculating Cooling Required to Retrofit All 

Units with 90% CO2 Capture and Compression at the Conesville Plant 

1.3.4 Discounted Incremental Plant Units

A total CAPEX discount of 4 percent was given to plants with multiple units to account 

reduced engineering costs and economy of scale. The discount was determined by 

assuming a 50 percent reduction in engineering costs for the first successive unit at a site 

and was calculated based upon engineering costs in the Conesville Study relative to total 

investment costs. 

1.3.5 Construction Difficulty Factors

In analyzing the sampled plant sites it became apparent that some plants have less 

available space for equipment than others. Two construction cost factors were 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

20 

determined to accommodate this situation—a “close-in” cost of construction difficulty 

factor and a “landscape” cost of construction difficulty factor. A complete retrofit of 

Conesville Units 4, 5, and 6 was modeled using the Conesville Study as a guide. 

Conesville then served as a baseline for comparison of retrofit difficulty at other plants. 

Figure 1-15 shows the AEP Conesville plant retrofitted with carbon capture equipment on 

its three operating units. In this figure and the following figures, pink outlines represent 

additional CCS equipment, dark blue represents existing cooling and light blue new 

required cooling structures. 

Figure 1-15. Complete Plant Retrofit 

Close-in Construction. The letdown turbine, CO2 scrubbers and absorbers, as well as 

the primary and secondary FGD’s require construction in close proximity to the turbine 

and flue stack. The layout of some plants can easily accommodate these additional 

components. However, for plants where space is more crowded, an incremental factor 

was applied to account for anticipated difficulty in construction. These factors ranged 

from 0 (easily constructed) to 40 percent (difficult to construct). Plants with a zero factor 

are assumed to have a construction difficulty comparable to the Conesville baseline plant. 

This factor was added to one and used to scale costs. 

Landscape Construction. At the Conesville plant, as depicted in 5, designs were 

created to individually retrofit Units 4, 5, and 6 with all required components. However, 

it was assumed that CO2 compression and additional cooling facilities could be combined 

into larger plant (as opposed to unit) -servicing components. Note that, while some 

4

5

6
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

21 

adjustments and accommodations will need to be made, there are no large structures or 

other significant obstacles to overcome or work around with close-in construction at the 

Conesville site. The CO2 compression facility and additional cooling towers can be built 

in proximity to the plant, allowing more latitude for siting them. Still, these components 

are by far the largest and require significant open space at a plant. 

Using the Conesville plant as a baseline, each plant analyzed in the viable population was 

assigned close-in and landscape construction incremental difficulty factors ranging from 

0-40 percent. These values are based on professional judgment and represent general 

increases in costs due to engineering and construction difficulties. 

Figure 1-16 shows Plant 2315 Cherokee in Denver, Colorado, a plant assigned a 10 

percent close-in construction difficulty. The primary difficulty at this four-unit plant is 

the CO2 scrubbers. One scrubber interferes with a cooling tower and another interferes 

with other structures. The plant required no primary FGD, and appears to have sufficient 

recirculating cooling to accommodate retrofit, based on an analysis of cooling system 

data. The coal pile and a cooling tower must be moved, resulting in a 10 percent 

landscape construction difficulty. 

Figure 1-17 shows Plant 1651 Potomac River in Alexandria, Virginia, a plant assigned a 

30 percent close-in construction difficulty. Note that primary FGDs and CO2 scrubbers 

need to be constructed against the river, and the letdown turbines and CO2 absorbers may 

require moving the substation. This plant was also assigned a 10 percent landscape 

construction difficulty because of conflicts with the coal pile and the parking lot. 

Figure 1-18 shows Plant 1660 John Amos in Charleston West Virginia, which was not 

assigned additional construction difficulty. 

Figure 1-19 shows Plant 2346 Crystal River in Crystal River, Florida. It was assigned a 

15 percent close-in construction difficulty due to the southern CO2 scrubbers and letdown turbines. It was not assigned a landscape construction difficulty.
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

22 

Figure 1-16. Example Showing 10 Percent Close-In Construction Difficulty and 10 

Percent Landscape Construction Difficulty 

Figure 1-17. Example Showing 30 Percent Close-In Construction Difficulty, 10 

Percent Landscape Construction Difficulty 

In some cases, it may be cheaper to purchase more land rather than engineer around a 

crowded plant site, or a site may simply be too crowded such that additional land may be 

required to accommodate the retrofit facilities. This is particularly true for landscape 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

23 

construction components. Using the EV Land and Rights data as an analog for land 

value, and the estimated total plant acreage from the GIS, a dollar per acre value was 

estimated for additional land cost. Where Land and Rights data was not available, a 

value of $5,000/acre was used. It should be noted that the plant boundary can only be 

inferred from a best-judgment analysis of the available imagery. In some cases, the plant 

boundary is relatively clear, but typically assumptions must be made. Addition of a land 

records GIS database to the model could mitigate these assumptions and better quantify 

land value, but would require efforts beyond the scope of this project. 

Figure 1-20 shows Plant 1779 Warrick in Newburgh, Indiana. A parcel totaling 19.2 

acres was added to accommodate the landscape retrofit components. 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

24 

Figure 1-18. Example Showing 0 Percent Close-In Construction Difficulty, 0 Percent 

Landscape Construction Difficulty 

Figure 1-19. Example Showing 15 Percent Close-In Construction Difficulty, 0 

Percent Landscape Construction Difficulty 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

25 

Figure 1-20. Additional Land Requirements 

Figure 1-21 shows how many plants were assigned correction factors. More adjustments 

were made for close in space limitations than for landscape 

Figure 1-21. Assigned correction factors for space limitations 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

26 

1.3.6 Total Investment CAPEX

In the model, Total Investment CAPEX for a generating unit is determined as follows: 

CXTOT = [(CXLD +CX CS + CXSR + CXNO)*AFc* + (CXCC +CXCW)*AFL ]*AFMU + CXAL

CXLD = 0.004 * MW + 0.8 

CX CS = 3x10-12 * (MW)3 + 2x10-7 * (MW)2 + 0.0054 * (MW) + 3.03 

CXSR = CXSS+ CXSP 

CXSS = if FGD then (0.98 – Nss)*MW*216 $/kW, else MW*230 $/kW 

CXSP = (1-0.98)*MW*HR*(1/CLHC)*CLSU * 95 $/ton sulfur 

CXNO = if NOx < 0.07 then 0 else (NOX - .07) lbs/mmbtu *HR*MW*8760*CF*20 yrs*300 $/mtNOx 

CXCW = MW * [ if ARID then (if dry_cooling then 0 else MW * 98 $/kW) else (if recirc_cooling then 

0 else 28 $/kW) ] 

CXCC = 0.0017 * MW + 0.24 - CX CS 

where: 

MW = unit nameplate generating capacity, MW 

HR = unit heat rate, average achieved between 2000 and 2008, btu/kWh 

CXTOT = total capital expense for CO2 retrofit, MM$ 

CXLD = capital expense for the let down turbine, MM$ 

CX CS = capital expense for the CO2 capture and separation 

CXSR = capital expense for sulfur scrubber/upgrade to existing sulfur scrubber 

CXSS = capital expense for primary sulfur scrubber 

CXSP = capital expense for sulfur polishing 

CXNO = capital expense for NOx reduction/upgrade to existing NOx reduction 

CXCC = capital expense for CO2 compression 

CXCW = capital expense for cooling water upgrade 

CXAL = capital expense for additional land 

AFC = adjustment factor for tight spacing within the unit (close in) 

AFL = adjustment factor for tight spacing surrounding the unit (landscape) 

AFMU = adjustment factor (discount) for multiple generating units at a single plant 

Nss = efficiency of the scrubbing unit (SOx captured) 

NOX = NOx emissions, tons/yr 

CLHC = coal heat content, btu/lb 

CLSU = coal sulfur content, wt% 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

27 

1.3.7 OPEX

In the CCM, OPEX is calculated as the sum of Fixed (Labor) cost, Variable (chemical, 

waste, and maintenance) costs, and Feedstock cost. Figures 1-22, 1-23, and 1-24 show 

these costs as a function of the generation capacity of the power plant based on the 

scenarios in the Conesville Study. Note that the relationship between feedstock cost and 

nameplate, in Figure 1-26, does not fit a function well, but does show a general trend. 

This relationship is not completely understood. 

The Conesville Study gives OPEX as functions of total CO2 captured. For the 90% 

capture scenario, a retrofitted Conesville Unit 5 would capture approximately 3.3 million 

tons of CO2 per year and would require $2.6 M per year in fixed OPEX, $22.3 M per year 

in variable OPEX, and $1.1 M per year in feedstock OPEX.
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

28 

Figure 1-22. Fixed OPEX Cost Function 

Figure 1-23. Variable OPEX Cost Function 

Figure 1-24. Feedstock OPEX Cost Function 

y = 2.9701e-0.003x

R2 = 0.9597

$-

$0.50 

$1.00 

$1.50 

$2.00 

$2.50 

$3.00 

$3.50 

0 200 400 600 800 1000

$/tonne CO2

MWs

Fixed (Labor) OPEX 

y = 8.6317e-5E-04x

R2 = 0.9833

$-

$1.00 

$2.00 

$3.00 

$4.00 

$5.00 

$6.00 

$7.00 

$8.00 

$9.00 

$10.00 

0 200 400 600 800 1000

$/tonne CO2

MWs

Variable (chemicals, waste, maintenance) OPEX

y = 0.3398e0.0001x

R2 = 0.2984

$0.34 

$0.34 

$0.35 

$0.35 

$0.36 

$0.36 

$0.37 

$0.37 

$0.38 

$0.38 

$0.39 

$0.39 

0 200 400 600 800 1000

$/tonne CO2

MWs

Feedstock (natural gas) OPEX
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

29 

1.3.8 Parasitic Load

The total parasitic load of the carbon capture retrofit is equal to the sum of the parasitic 

loads of the newly installed NOx and SO2 control equipment, the additional cooling, the 

actual CO2 retrofit components, the parasitic heat used for amine regeneration and 

compression. Energy requirements for transportation, storage and monitoring were not 

included in this analysis. 

A parasitic loading function was developed based on the Conesville Study cases for the 

retrofit equipment. Figure 1-25 shows this as a function of nameplate capacity. 

Figure 1-25. Parasitic Load Scaling for Carbon Capture Retrofit Components 

The parasitic load factors associated with NOx, SO2 and additional cooling were 

developed based upon the Baseline Report. A factor of 0.0001 kW parasitic load/kW 

capacity was used for NOx equipment and a value of 0.0091 kW parasitic load/kW 

capacity was used for SO2 equipment. Additional cooling was determined to have a 

parasitic load of 0.033 kW parasitic load/kW capacity. A constant rate of 212.91 

kWh/tonne CO2 scrubbed was used for the parasitic steam rate for amine regeneration. 

These five components are summed and reported as total parasitic load in units of 

kWh/tonne CO2-captured. Make up power cost was calculated using the NETL projected 

2020 electric generation cost. 

y = 0.0645x + 184.45

R2 = 0.9606

-

50 

100 

150 

200 

250 

300 

- 200 400 600 800 1,000 

Parasitic Load (kW-h/tonne CO2

Original Capacity of System, MW

Parasitic Load Scaling
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

30 

1.3.9 Levelized Cost of Electricity

A levelized cost of electricity (LCOE) was calculated for each plant using methodology 

consistent with the Conesville Study. Figure 1-26 shows the LCOE equation from the 

Conesville Study. The equation levelizes the costs of capital, fixed and variable OM and 

feedstock over a levelization period and normalizes by the post-retrofit generation. The 

cost of make-up power associated with the retrofit parasitic load is calculated using the 

projected Waxman-Markey 2020 electric generation price. The CCM uses the same 

levelization period, capital charge factor, and levelization factors as the Conesville Study. 

For a 20-year levelization period, a capital charge factor of 0.175, a fixed and variable 

OM levelization factor of 1.1568, and a feedstock levelization factor or 1.1651 were 

used. 

Figure 1-26. LCOE Equation and Parameters from Conesville Study 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

31 

1.3.10 Inclusion of Make-up Power

The CCM also calculates carbon capture costs by tonne of captured carbon and tonne of 

avoided or mitigated carbon using the Conesville Study methodology. Figure 1-29 shows 

the captured and mitigated carbon cost equations from the Conesville Study.

The CO2 capture cost is a measure of levelized cost of retrofit per tonne of CO2 captured 

at the plant. Because the analysis assumes constant coal, the make-up power associated 

with the retrofit parasitic load must be generated by other plants. The CCM uses the 

NETL Waxman-Markey generation profile and average carbon loading values by 

generation type for the year 2020 to calculate the carbon loading associated with make-up 

power. 

The emissions associated with this make-up power generation reduce the actual tonnes of 

carbon avoided to the atmosphere. The actual tonnes mitigated are equal to the tonnes 

captured minus the tonnes reintroduced through make-up power generation.   

Figure 1-27. Captured and Mitigated (Avoided) Carbon Costs 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

32 

The LCOE equation, calculated for each generation unit, is adjusted as follows to account 

for make-up power. 

LCOEMU = (1-PL) * LCOEbase + PL * CostMU 

Where: 

LCOEMU - Levelized cost of electricity in the make up power case ($/MWh) 

LCOEbase - Levelized cost of electricity in the base case ($/MWh) 

CostMU - Cost of make-up power, $/MWh (NEMS results for 2020 under Waxman 

Markey scenario) 

PL - parasitic load, percent reduction in unit generating capacity going from no 

CO2 capture to CO2 capture 

The cost of CO2 capture is unaffected by the make-up power assumption, but the cost of 

CO2 avoided is impacted by the make-up power. 

CO2cp, MU = (1-PL) * CO2cp, base + PL* CO2MU 

Where: 

CO2 - Carbon dioxide emissions, metric tons CO2 / kWh 

PL - parasitic load, percent reduction in unit generating capacity going from no 

CO2 capture to CO2 capture

cp Capture Plant

MU Make up 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

33 

2. RESULTS

This section provides the analytical results of the analysis. It should be noted that all 

costs presented relative to carbon capture do not consider base plant costs and represent 

only costs associated with the retrofit. An Appendix presents a catalog of the plants 

analyzed, including site-specific imagery for carbon capture retrofits for individual plants 

in the viable population. 

2.1 CAPEX RESULTS 

CAPEX, OPEX, and parasitic costs were calculated for the population of viable plants for 

three scenarios with varied capacity factors of 65, 75, and 85 percent respectively. 

Results were calculated for two cases: (1) a carbon capture case, which does not consider 

carbon allowance nor the cost and carbon emissions associated make-up power, and (2) a 

carbon mitigation case, which models the effects of Waxman-Markey assumptions for 

make-up power costs and carbon emissions. 

Figure 2-1. Nameplate Capacity as a Function of CO2 Capture CAPEX by Unit shows 

CO2 capture CAPEX as a function of nameplate capacity for the 738 individual analyzed 

units. Note that large units demonstrate relatively low CAPEX rates (green oval), while 

smaller plants demonstrate high CAPEX variability (red oval). 

Figure 2-1. Nameplate Capacity as a Function of CO2 Capture CAPEX by Unit 

$5

$10

$15

$20

$25

0 500 1000 1500

CO2 Retrofit CAPEX ($/tonne)

Nameplate Capacity (MW)

282 GW (738 Units)
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

34 

2.2 BASE CASE (NO MAKE-UP POWER) 

This case determines the base LCOE and carbon capture costs. The LCOE was 

calculated without inclusion of make-up power. Levelized carbon capture costs were 

calculated without consideration of carbon emitted through generation of make-up power, 

and essentially represent CAPEX and OPEX costs associated with physically capturing 

carbon from the flue gases. 

In Figure 2-2. Base Case, Cumulative U.S. Coal Generating Capacity versus Incremental 

LCOE for CO2 Capture Retrofit, all the generating units are ranked from least to highest 

incremental cost of power required to “cover” the cost of CO2 capture. Figure 2-3 is a 

similar graphic that presents the cost of CO2 captured versus cumulative generating 

capacity. 

Figure 2-2 is interpreted as follows. Reading off the 75% capacity factor line, the 

Conesville generating plant has a cost of incremental cost of electricity of CO2 capture of 

$54/MWh which places it at the 20% percentile. That is, 20% of the coal fired generating 

capacity has an incremental cost of electricity less than $54/mt CO2. The other 70% of 

coal-fired capacity has a higher cost. Figure 2-2 shows that increasing the assumed 

capacity factor from 75% to 85% lowers the incremental cost of electricity by roughly 

$6/MWh. Lowering the assumed capacity factor to 65% increases the incremental COE 

by roughly $8/MWh. 

Figure 2-3 shows that roughly 70% of the generating capacity has an incremental cost of 

power of $70/MWh or less. After that the curve flattens out and the costs begin 

increasing more rapidly. By comparison the CO2 capture cost curves in Figure 2-3 are 

steeper. The explanation for this is partially seen in Figure 2-1 which shows a wide 

variation in CAPEX, the primary determinant of LCOE. The CO2 capture cost, however, 

is driven strongly by a unit’s efficiency which has a much lower variation across the fleet. 

A range of capacity factors was modeled (values of 65, 75, and 85 percent). 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

35 

Figure 2-2. Base Case, Cumulative U.S. Coal Generating Capacity versus 

Incremental LCOE for CO2 Capture Retrofit

Figure 2-3. Base Case, Cumulative U.S. Coal Generating Capacity versus Retrofit 

CO2 Capture Cost

(282 Power Plants) 

(282 Power Plants) 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

36 

2.3 MAKE-UP POWER CASE 

A coal-fired generating unit with CO2 capture using amine based scrubbing will lose 

roughly 30% of its generating capacity. An alternative analysis methodology will 

consider the cost and GHG emissions of make-up power. That is, the owning entity 

buys power – either via a contract or on the spot market, to “make-up” for the generation 

that is being consumed by the parasitic load of the CO2 capture plant. 

This case determines LCOE and carbon mitigation costs assuming NETL’s WaxmanMarkey (W-M) projections. LCOE was calculated including make-up power costs based 

on the cost of electricity in each unit’s EMM region. Levelized carbon mitigation costs 

were calculated with consideration of carbon emitted through generation of make-up 

power, and represents estimated costs associated with avoiding carbon emissions to the 

atmosphere. 

Figure 2-4 shows the incremental cost of electricity versus cumulative generating 

capacity for the make-up power case. The current cost of commodity power was not 

applied to the make-up power calculation, rather the forecasted cost under a GHG 

mitigation scenario. Specifically, the power costs contained in NEMS outputs for 2020 

under a Markey Waxman scenario was used. 

At the median cost, the curve in Figure 2-5 represents a horizontal shift of roughly 

$43/MWh compared to Figure 2-4. The slope of Figure 2-5 is shallower. The horizontal 

shift is higher for the high-cost generating units due to the spiraling effect of lower base 

plant efficiency. The shift is lower at the low cost region for the same reason. 

   
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

37 

Figure 2-4. Make-up Power Case, Cumulative U.S. Coal Generating Capacity versus 

Incremental LCOE for CO2 Capture Retrofit

Figure 2-5. Make-up Power Case, Cumulative U.S. Coal Generating Capacity versus 

Retrofit CO2 Capture Cost

(282 Power Plants) 

(282 Power Plants) 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

38 

2.4 COMPARISON WITH CONESVILLE STUDY RESULTS 

The results for incremental COE, capture cost, and mitigation cost for the Conesville 

generating unit are different in this study than in the source study developed by NELT 

and AEP, Table 2-1. Table 2-2-2 shows that the difference is explained by a higher 

CAPEX and OPEX, both due to the inclusion of additional cooling, emissions controls 

and auxiliary load requirements. The current study also assumes a higher price and 

regionally-based carbon emissions for make-up power, which contributes to the 

difference. 

Table 2-1. Results from the Conesville Study and CCM 

Table 2-2. Key Input Parameters from the Conesville Study and CCM 

 

Nameplate LCOE Capture Cost Mitigation Cost

(MW) ($/MWh) ($/tonne) ($/tonne)

Conesville Study 465.5 69 $ 59 $ 89 $ 

CCM 463.5 49 $ 38 $ 90 $ 

Delta 0.4% 29% 36% -1%

Conesville Unit 5

Nameplate Total Aux 

Load CO2 CAPEX Electricity 

Price

Make-up 

Power Cost

(MW) (MW) (10^6 $) ($/MWh) (10^6 $)

Conesville Study 465.5 130.5 400 $ 0.064 $ 21.2 $ 

CCM 463.5 148.9 456 $ 0.076 $ 27.3 $ 

Delta 0.4% -14% -14% -19% -29%

Conesville Unit 5
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

39 

3. CONTINUING WORK

NETL has conducted a stakeholder review of the first version of this version of the PC 

retrofit report and is working to refine and enhance the analysis. The following are 

priority objectives to be contained in a revised document, set to be posted in the Spring of 

2011. 

 Provide capability for the model to assess advanced retrofit technologies which 

reduce the costs and energy penalties for CO2 capture 

 Examine the potential synergy of refurbishing units with efficiency (heat rate) 

upgrades in conjunction with CO2 capture retrofits 

 Provide additional hard cost and performance data points by integrating results 

from current engineering-level retrofit studies currently in progress 

 Improve and refine data quality and calculations in the following manner: 

o Refine the viable population criteria to operate on unit rather than plant 

totals and averages 

o Incorporate base plant costs in the LCOE calculations 

o Perform a full twenty-year cost levelization using discrete electricity 

prices and generation profiles by EMM by year using NETL’s projections 

o Collect and integrate data on the timing of the installation of NOx and 

FGD equipment relative to efficiency drops 

 Further characterize viable sequestration opportunities by type and capacity 

 Incorporate costs for CO2 transportation and storage into output metrics 

 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

40 

APPENDIX A.  EV Suite Data Elements

The data tables can be located in the EV.mdb Access database. 

Units Table 

Data Item: Plant Name 

SOURCE: EIA 860, EIA 906, NERC 411, StatsCanada, CFE, Global Energy Primary Research 

DESCRIPTION: The most commonly used name for a power plant. A facility containing prime 

movers, electric generators, and auxiliary equipment for converting mechanical, chemical, and/or 

fission energy into electric energy. 

Data Item: Plant ID 

SOURCE: Global Energy 

DESCRIPTION: Unique Global Energy entity id corresponding to the plant name. 

Data Item: Unit 

DESCRIPTION: Any combination of physically connected generator(s), reactor(s), boiler(s), 

combustion turbine(s), or other prime mover(s) operated together to produce electric power. 

Data Item: Unit ID 

SOURCE: Global Energy 

DESCRIPTION: Global Energy entity id for the unit. 

Data Item: Unit Status 

SOURCE: Global Energy Primary Research 

DESCRIPTION: The current status of the generating unit 

Operating Categories: 

OP Operating Generator available to operate 

SB Standby Generator available for service but not normally 

 used, or on short term scheduled or forced outage 

 for less than 3 months 

OS Out of Service Generator on long term scheduled or forced outage 

 for more than 3 months 

RT Retirement Generator planned for retirement 

RS Restart Generator brought back online after being Retired or 

 Mothballed for more than 5 years 

SO Steam Only Generator was removed from electric generation service 

 and continues to operate solely as steam generator 

Planned Categories: 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

41 

FE Feasibility Planned new generator undergoing feasibility study 

PL Proposed New generator planned for installation 

AP App Pending Application(s) filed for permit(s), regulatory approval pending 

PM Permitted Two or more permits approved or contracts for 

 fuel or power have been received 

SP Site Prep The power plant site is being prepared for construction 

UC Under Const Planned generator under construction 

TS Testing Generator operating under test conditions, 

 not in commercial service 

Canceled Categories: 

CN Canceled Planned new generator canceled 

PP Postponed Planned new generator indefinitely postponed 

Cold Standby Category: 

SC Cold Standby Generator in deactivated status requiring more 

 than 6 months to reactivate 

Mothballed Category: 

MB Mothballed Generator taken out of service but not retired, 

 unit is able to come back online in future 

Retired Categories: 

RE Retired Generator no longer in service and not expected 

 to be returned to service 

CV Converted Generator was converted (refurbished) from stand- 

 alone status to combined-cycle configuration 

Data Item: Nameplate Capacity MW 

DESCRIPTION: The maximum rated output of a generator, prime mover, or other electric 

power production equipment under specific conditions designated by the manufacturer. Installed 

generator nameplate capacity is commonly expressed in megawatts (MW) and is usually 

indicated on a nameplate physically attached to the generator. 

INSTRUCTIONS: For EIA 860, 906 and NERC ES&D: For line 1, Maximum Generator 

Nameplate Capacity, report the highest value on the nameplate in megawatts rounded to the 

nearest tenth. 

Data Item: EV Fully Loaded Tested Heat Rate Btu/kWh 

SOURCE: Global Energy Intelligence 

DESCRIPTION: Energy Velocity has created a process to obtain the best fully loaded tested 

heat rate for a unit based on several different sources. These sources are detailed in the help for 

the EV Fully Loaded Tested Heat Rate Source field. 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

42 

At the onset of this project, Global Energy analysts used various resources to determine a low 

and high point for heat rates by Generator Availability Data System (GADS) category. By 

looking at heat rate data by GADS category a default heat rate was also determined. 

The process takes each thermal unit in the database and then moves down the list of sources 

looking to see if that unit has data for that source. If there are data for that unit for the first source 

(EV Research) and the data reported fall within the range determined for the GADS category of 

the unit, that heat rate would then be the value used for that unit in the EV Heat Rate item. If 

there is no EV Research data for that unit, the process will then look at the CEMS data to see if 

there is data for that unit. Again if there are data and the heat rate calculation is within the range 

that heat rate would be the value used for that unit in the EV Heat Rate item. The process follows 

down the list of sources and if there are no data to support a heat rate within the range at any of 

the sources, a default value will be used for the EV Heat Rate item. 

As new data are received or new information is found for a unit the EV Fully Loaded Tested 

Heat Rate value can change for that unit. 

Data Item: Prime Mover 

SOURCE: EIA 860, 906, NERC ES&D, CFE, StatsCan and Global Energy Primary Research 

DESCRIPTION: The engine, turbine, water wheel, or similar machine that drives an electric 

generator or a device that converts energy to electricity directly (photovoltaic solar and fuel 

cells). 

Data Item: Supercritical (Y/N) 

SOURCE: Global Energy Research 

DESCRIPTION: The terms supercritical and ultra-supercritical are derived from the definition 

of the temperature and pressure at which water vapor and liquid water are indistinguishable - 

known as the Critical Point. The Critical Point of water occurs at 705 degrees Fahrenheit under 

pressure of 3208 pounds per square inch (psia). At the Critical Point, the bubbling formation 

associated with boiling no longer occurs. Instead, with the addition of heat or increase in 

pressure the fluid experiences a continuous transition from water-like to steam-like 

characteristics. 

Pressure is said to be "supercritical" when the pressure exceeds 3208 psia. A conventional 

supercritical unit operates at a steam pressure of 3500 psi or higher and steam temperatures of 

1000 - 1050F. By contrast, a subcritical unit operates below the critical pressure, typically 2400 

psi at similar temperatures. 

By operating at elevated steam pressures and temperatures, the turbine cycle is more efficient. 

This reduces fuel consumption, and reduces emissions in the process. 

Data Item: SO2 Control Equipment (Y/N) 

SOURCE: U.S. EPA Clean Air Markets Division facility attributes and Global Energy Research 

DESCRIPTION: Indicates whether unit is known to have one or more SO2 control technologies 

in place 

Data Item: NOx Control Equipment (Y/N) 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

43 

SOURCE: U.S. EPA Clean Air Markets Division facility attributes and Global Energy Research 

DESCRIPTION: Indicates whether unit is known to have one or more NOx control technologies 

in place 

Data Item: SO2 Annual Rate lbs/mmBtu 

SOURCE: US EPA CEMS 

DESCRIPTION: SO2 emissions rate in lbs/mmBtu for the most recent complete calendar year of 

data available from the U.S. EPA CEMS database. (The EPA releases 4th quarter data in 

February of the following year.) 

hen aggregated this item will provide a weighted average value, weighted by Nameplate 

Capacity. 

IMPORTANT NOTE: Only units that report SO2 emissions will be included in this average. 

Data Item: NOX Summer Rate lbs/mmBtu 

SOURCE: US EPA CEMS 

DESCRIPTION: NOx emissions rate in lbs/mmBtu for the NOx season (May through 

September) of the most recent complete calendar year of data available from the U.S. EPA 

CEMS database. (The EPA releases 4th quarter data in February of the following year.) 

When aggregated, this item will provide a weighted average value, weighted by Nameplate 

Capacity. 

IMPORTANT NOTE: Only units that report NOx emissions will be included in this average. 

Data Item: CO2 Annual Rate lbs/mmBtu 

SOURCE: EPA 

DESCRIPTION: CO2 emissions rate in lbs/mmBtu for the most recent complete calendar year of 

data available from the U.S. EPA CEMS database. (The EPA releases 4th quarter data in 

February of the following year.) 

When aggregated, this item will provide a weighted average value, weighted by Nameplate 

Capacity. 

IMPORTANT NOTE: Only units that report CO2 emissions will be included in this average. 

Plant Generation and Production Table 

Data Item: Total mmBtus 

SOURCE: EIA 906, Ontario IESO, CEMS 

DESCRIPTION: Total consumption of the fuel specified, in millions of Btus. 

Note: this is the total quantity consumed for both electricity and, in the case of combined heat 

and power plants, process steam production. 

Data Item: Net Generation MWh 

SOURCE: EIA 906, Ontario IESO, CEMS 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

44 

DESCRIPTION: This is the monthly net generation as reported (in MWh) on the EIA 906 or 

Independent Electricity System Operator (Ontario) generator disclosure report. Combined heat 

and power facilities report gross generation for each prime mover whereas electric power plants 

report net generation. 

INSTRUCTIONS: EIA 906: Generation: column g. 

Report a single net generation value for all prime movers of a single type, regardless of the 

number of energy sources for that prime mover. For example, all generation from your steam 

turbines with multiple energy sources should be reported as one number under the primary 

energy source. 

All Plants Other Than Pumped Storage and Compressed Air Storage: When station use electrical 

demand exceeds the gross electrical output of the plant, a negative number should be reported for 

net generation. Indicate negative amounts by using a minus sign before the number. 

Hydro Pumped Storage and Compressed Air Energy Storage Plants: Report gross generation in 

column (f) and net generation (gross generation minus station use) in column (g). Report 

pumping energy in column (h) (energy source consumption). 

Note that during months when the storage facility is returning power to the grid, none of these 

values will typically be negative. If you need assistance with these new instructions for storage 

facilities, contact the survey manager. 

Data must be reported in megawatthours (MWh), rounded to whole numbers, no decimals. 

Enter zero when a plant has no generation for a prime mover. 

Combined Cycle Units: Report generation for the combustion turbine (CT) and the steam 

turbine (CA) separately. If multiple energy sources are used, report each energy source 

separately. Report supplemental firing fuels in duct burners and/or auxiliary boilers under steam 

turbine code (CA). 

CEMS (Continuous Emissions Monitoring System) Table 

Data Item: Sum Total CO2 Emissions tons (by ownership %) 

SOURCE: EPA 

DESCRIPTION: Total CO2 emissions for the year in tons. Emissions are broken out by 

ownership percentage of the unit. This query uses the current ownership of the units and does 

not reflect prior changes in ownership. When aggregated, this item will provide a sum value. 

Reported in Short Tons (i.e. US Tons). 

Data Item: Sum Total SO2 Emissions tons (by ownership %) 

SOURCE: EPA 

DESCRIPTION: Total SO2 emissions for the year in tons. Emissions are broken out by 

ownership percentage of the unit. This query uses the current ownership of the units and does 

not reflect prior changes in ownership. When aggregated, this item will provide a sum value. 

Data Item: Sum Total NOx Emissions tons (by ownership %) 

SOURCE: EPA 
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45 

DESCRIPTION: Total NOx emissions for the year in tons. Emissions are broken out by 

ownership percentage of the unit. This query uses the current ownership of the units and does 

not reflect prior changes in ownership. When aggregated, this item will provide a sum value. 

Data Item: Wtd Avg CO2 Emissions Rate lbs/MWh 

SOURCE: EPA, Global Energy Primary Research 

DESCRIPTION: Average CO2 emissions rate for the year in lbs/MWh. 

When aggregated, this item will provide a weighted average value, weighted by Net Generation. 

IMPORTANT NOTE: Only units that report CO2 emissions will be included in the average. 

Data Item: Wtd Avg SO2 Emissions Rate lbs/MWh 

SOURCE: EPA, Global Energy Primary Research 

DESCRIPTION: Average SO2 emissions rate for the year in lbs/MWh. 

When aggregated, this item will provide a weighted average value, weighted by Net Generation. 

IMPORTANT NOTE: Only units that report SO2 emissions will be included in the average. 

Data Item: Wtd Avg NOx Emissions Rate lbs/MWh 

SOURCE: EPA, Global Energy Primary Research 

DESCRIPTION: Average NOx emissions rate for the year in lbs/MWh. 

When aggregated, this item will provide a weighted average value, weighted by Net Generation. 

IMPORTANT NOTE: Only units that report NOX emissions will be included in the average. 

Plant Coal Transactions Table 

Data Item: Fuel Code Abbrev 

SOURCE: Global Energy Primary Research 

DESCRIPTION: 

FUELCODE DESCRIPTION 

ANT Anthracite Coal 

BC Beneficiated Coal 

BIT Bituminous Coal 

COK Coker bi-product 

COL Coal 

PC Petroleum Coke 

SC Coal Based Synfuel 

SUB Subbituminous Coal 

WC Waste Coal 

Data Item: Quantity (000s tons) 
Coal-Fired Power Plants: Costs of CO2 Capture Technology and Improvements in Efficiency 

46 

SOURCE: FERC 423 EIA 423 

DESCRIPTION: Quantity of fuel delivered during the report month. 

INSTRUCTIONS: Enter quantities in thousands of tons for coal, thousands of barrels for oil and 

other liquid fuels, and thousands of mmBtu (billions of British Thermal Units) for gas. For 

example, if 213,000 tons of coal are delivered during the reporting month, 

Report 213. Enter separate quantities for each type of fuel. To derive the quantity, group all fuels 

received within the month from the supplier for which the price was based upon a given or 

related set of laboratory analyses. Note: For quantities of fuel received from a given supplier 

during the month for which no laboratory analysis is made, report on the basis of the last 

previous laboratory analysis upon which price paid was determined for that supplier or on the 

basis of contract specifications or estimates, and specify in a footnote the basis used. 

Data Item: Sulfur % 

SOURCE: FERC 423 EIA 423 

DESCRIPTION: Sulfur content of fuel (except gas) in terms of percent sulfur by weight on an 

"as received" basis. 

INSTRUCTIONS: For all fuels except gas, enter sulfur content of fuel in terms of percent sulfur 

by weight. Show to the nearest 0.01%. 

Land Table 

Data Item: Land & Land Rights $ 

SOURCE: FERC Form 1, EIA 412, RUS 12 

DESCRIPTION: This is the $ expense for land and land rights for this plant.